EPA-450/3-76-016-b
May 1976
THE IMPACT OF LEAD
ADDITIVE REGULATIONS
ON THE PETROLEUM REFINING
INDUSTRY: VOLUME II -
DETAILED STUDY RESULTS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
-------
Fourth, it was assumed that unleaded gasoline would be manufactured
at about 92 Research Octane Number (and at an 84 Motor Octane Number
minimum), instead of the mandated 91 RON, to provide a margin of safety.
Some investigators contend that this is a cost of doing business not
ascribable to the lead regulations.
Finally, ADL has taken a relatively pessimistic view of the costs
of upgrading existing catalytic reformers. The conclusion was based on
extensive industry contact. Although EPA does not totally agree with
this conclusion, we support ADL's decision.
In light of the above, the reader is cautioned to view the final
results of the report in the context of the assumptions that were made.
References
1. EPA-230/3-76-004, Economic Impact Of EPA's Regulations on the
Petroleum Refining Industry, April 1976.
2. Draft Report, The Economic Impact of Environmental Regulations
on the Petroleum Industry - Phase II Study, Battelle Columbus
Laboratories for the American Petroleum Institute, June 11, 1976.
-------
EPA COMMENT
"The Impact of Lead Additive Regulations
on the Petroleum Refining Industry"
EPA-450/3-76-016-a
May 1976
In 1974, the Environmental Protection Agency commissioned Arthur D.
Little, Inc. to mathematically model the petroleum refining industry in
the United States and to predict up to 1985 the impacts on the industry
of the entry into the market of unleaded gasoline and the phase-down of
total lead use in the gasoline pool. When the study was initiated,
Arthur D. Little was given certain baseline assumptions by EPA. These
assumptions, which included projections of crude slate, crude supply,
product demand, growth rates and gasoline pool characteristics, were
made based on the information available at that time. Because of
uncertainties with regard to such fundamental questions as future motor
vehicle design, emission standards, petroleum supplies and demands, and
other factors, the assumptions made for this study generally reflected a
somewhat conservative view.
The Environmental Petroleum Agency strongly believes that this
study by Arthur D. Little represents a significant step forward in
analyses of the refining industry. However, in reviewing the final
report, EPA identified certain aspects of the report which should be
further clarified to ensure proper interpretation.
First, for the purposes of this study, it was assumed that essentially
all gasoline would be the unleaded grade in 1985. Although factors such
as average car life and off-highway gasoline use indicate some leaded
gasoline will still be required in 1985, there is much uncertainty
surrounding this issue, and the conservative decision was made to assume
all unleaded gasoline in 1985.
Second, an average product demand growth rate of two percent per
year through 1985 was assumed. This does not completely coincide with
some opinions concerning improved engine efficiencies in the future.
However, the decision was made again on the side of conservatism.
Third, ADI used 1975 dollars in their calculations, whereas other
recent studies ' have generally used 1974 dollars. ADL s assumption
yields final investment figures 10 to 15 percent higher than the others.
-------
EPA-450/3-76-016-b
THE IMPACT OF LEAD
ADDITIVE REGULATIONS
ON THE PETROLEUM REFINING
INDUSTRY: VOLUME II -
DETAILED STUDY RESULTS
by
Arthur D. Little, Inc.
Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-1332, Task Order No. 7
EPA Task Officer: Richard K. Burr
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 2771 1
Mav 1976
-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD35) , Research Triangle Park, North Carolina
27711; or, for a fee, from the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by Arthur
D. Little, Inc. , Cambridge, Massachusetts 02140, in fulfillment of Contract
No. 68-02-1332, Task Order No. 7. The contents of this report are reproduced
herein as received from Arthur D. Little, Inc. The opinions, findings,
and conclusions expressed are those of the author and not necessarily
those of the Environmental Protection Agency. Mention of company or
product names is not to be considered as an endorsement by the Environmen-
tal Protection Agency.
Publication No. EPA-450/3-76-016-b
11
-------
ABSTRACT
The report assesses the impact on the U. S. petroleum refining industry
of two EPA regulations promulgated to control the level of lead additives
in motor gasoline. The first of these regulations requires the avail-
ability of low octane, unleaded gasoline for vehicles equipped with lead
sensitive catalytic converters. For health reasons, the second regulation
requires a gradual phase-down of the lead content of the total gasoline
pool (including higher octane gasoline to satisfy the remaining higher
compression ratio engines). The report assumes essentially a 100 percent
need for unleaded gasoline by 1985. Computer models representative of
specific refineries in six geographical regions of the U. S. were
developed as the basis for determining the impact on the existing refining
industry. New refinery construction during the period under analysis
(1975-1985) was considered by development of separate computer models
rather than expansion of existing refineries. These models were utilized
to assess investment and energy requirements to meet each lead regulation.
A sensitivity study was made of the impact on the refining industry of
manufacturing a higher octane unleaded gasoline than currently mandated.
Other sensitivity studies evaluated the effects of a higher demand for
unleaded gasoline than now forecast and of variations in the type of
imported crude oil available in the future for domestic refining.
iii
-------
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
-------
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-19
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.t 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-l7
-------
TABLE OF CONTENTS - Volume II (cont.)
APPENDIX H
TECHNICAL DOCUMENTATION
Page
A. CRUDE OIL PROPERTIES . H-l
B. PROCESS DATA H-2
C. GASOLINE BLENDING QUALITIES H-5
D. SULFUR DISTRIBUTION H-5
E. OPERATING COSTS H-6
F. CAPITAL INVESTMENTS H-6
APPENDIX I
MODEL CALIBRATION
A. BASIC DATA FOR CALIBRATION 1-1
1. Refinery Input/Output 1-1
2. Processing Configurations 1-10
3. Product Data 1-18
4. Calibration Economic Data 1-21
B. CALIBRATION RESULTS FOR CLUSTER MODELS 1-22
APPENDIX J
STUDY RESULTS
A. MASS AND SULFUR BALANCE J-l
1. Crude-Specific Streams J-2
2. Cluster Specific. Streams J-3
3. Miscellaneous Streams J-4
vi
-------
TABLE OF CONTENTS - Volume II (cont.)
APPENDIX K
CONVERSION FACTORS AND NOMENCLATURE
vii
-------
VOLUME II
LIST OF TABLES
APPENDIX A Page
TABLE A-l. Bureau of Mines Receipts of Crude by Origin 1973 A~3
TABLE A-2. ADL Model Crude Slates and Sulfur Contents
for 1973 A~4
TABLE A-3. Model Crude Slates - Small Midcontinent A-5
TABLE A-4. Model Crude Slates - Large Midwest . .. A-7
TABLE A-5. Model Crude Slates - Texas Gulf A-8
TABLE A-6. Model Crude Slates - East Coast A-9
TABLE A-7. Model Crude Slates - West Coast A-ll
TABLE A-8. Model Crude Slates - Louisiana Gulf A-12
TABLE A-9. Scale Up of Model Crude Slates, Scenario A A-14
TABLE A-10. Total Crude Run to Grass Roots Refineries A-15
TABLE A-ll. Distribution of Sweet and Sour Crude Run A-16
APPENDIX B
TABLE B-l. Projections of Major Product Demand in Total U.S.
Assumed in Making Model Runs B-3
TABLE B-2. A Comparison of Projected "Simulated" Demand
for Major Products with Results of Detailed Forecast .... B-5
TABLE B-3. A Comparison of Projected Total Petroleum Product
Demand in "Simulated" Demand Case With Detailed
Forecast B-6
TABLE B-4. Projection of U.S. Primary Energy Supplies
with Oil as the Balancing Fuel B-9
TABLE B-5.
Forecast of U.S. Product Demand . B-ll
viii
-------
APPENDIX C
TABLE C-l. Product Specifications, Gasoline C-2
TABLE C-2. Other Product Specifications C-4
APPENDIX D
TABLE D-l. Refinery Fuel Sulfur Regulations by State D-4
TABLE D-2. Refinery Fuel Sulfur Regulations by PAD D-5
TABLE D-3. Refinery Fuel Sulfur Regulations Applicable to
Individual Refineries in Cluster Models D-7
TABLE D-4. Base Level of Cluster Refinery Fuel
Sulfur Content Used in Model Runs D-9
. APPENDIX E
TABLE E-l. Catalytic Reforming Capacity Availability E-4
TABLE E-2. Catalytic Reformer Investment for Capacity
Utilization and Severity Upgrading E-6
TABLE E-3. Costs of Additional Reformer Capacity E-7
TABLE E-4. Cost of Severity Upgrading E-9
TABLE E-5. Hydrocracking Capacity Availability E-ll
TABLE E-6. Hydrocracking Investment for Capacity Utilization,
New Capacity, and Severity Flexibility E-12
TABLE E-7. Costs of Additional Hydrocracking Capacity E-13
TABLE E-8. Cost of Hydrocracker Severity Flexibility E-15
TABLE E-9. Alkylation and Isomerization Capacity Availability E-17
TABLE E-10. Utilization of Existing Alkylation Capacity E-18
TABLE E-ll. Isomerization Investment for Capacity Utilization
and Once Through Upgrading E-20
TABLE E-12. Costs of Additional Isomerization Capacity E-21
TABLE E-13. Cost of Once Through Isomerization Upgrading E-23
ix
-------
APPENDIX F
Page
TABLE F-l.
TABLE F-2.
TABLE F-3.
TABLE F-4.
TABLE F-5.
TABLE F-6.
TABLE F-7.
TABLE F-8.
TABLE F-9.
TABLE F-10.
TABLE F-ll.
TABLE F-12.
TABLE F-13.
TABLE F-14.
TABLE F-15.
Texas Gulf Cluster Processing Configuration F-6
Louisiana Gulf Cluster Processing Configuration
Large Midwest Cluster Process Configuration
Small Midcontinent Cluster Processing Configuration
East Coast Cluster Processing Configuration
West Coast Cluster Processing Configuration
F-7
F-8
F-9
F-10
F-ll
Summary of Major Refinery Processing Units F-12
F-14
Comparison of Product Output of East Coast
Cluster to PAD District I, 1973
Comparison of Product Output of Midcontinent Clusters
to PAD District II, 1973 F-15
Comparison of Product Output of Gulf Coast Clusters
to PAD District III, 1973 F-16
Comparison of Product Output of West Coast Cluster
to PAD District V, 1973 F-17
Comparison of Crude Input of East Coast Cluster
to PAD District 1, 1973
F-l 8
Comparison of Crude Input to Midcontinent Cluster
to PAD District II, 1973 F-19
Comparison of Crude Input of Gulf Coast Clusters
to PAD District III, 1973 F-20
Comparison of Crude Input to West Coast Cluster
PAD District V, 1973 F-21
-------
APPENDIX G Page
TABLE G-l. ADL Model Input/Outturn Data for Calibration - 1973 G-2
TABLE G-2. Comparison of 1973 B.O.M. Data and Scale Up of 1973
Calibration Input/Outturn G-3
TABLE G-3. L.P. Model Input/Outturns 1977 G-7
TABLE G-4. L.P. Model Input/Outturns 1980 G-8
TABLE G-5. L.P. Model Input/Outturns - 1985 G-9
TABLE G-6. Scale Up Input/Outturns 1977 G-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 tt-22
xi
-------
APPENDIX H - (Cont.)
Page
TABLE H-14. Stream Qualities - Foreign Crudes and Natural
Gasoline H-25
TABLE H-15. Stream Qualities - Miscellaneous Streams H-28
TABLE H-16. Stream Qualities - Variable Sulfur Streams H-30
TABLE H-17. Sulfur Distribution - Coker and Visbreaker H-31
TABLE H-18. Sulfur Distribution - Catalytic Cracking H-32
TABLE H-19. Alternate Yield Data - High and Low Severity Reforming
of SR Naphtha H-33
TABLE H-20. Alternate Yield Data - High and Low Pressure Reforming
of Conversion Naphtha H-36
TABLE H-21. Operating Cost Consumptions - Reforming H-37
TABLE H-22. Operating Cost Consumptions - Catalytic Cracking H-38
TABLE H-23. Operating Cost Consumptions - Hydrocracking H-39
TABLE H-24. Operating Cost Consumptions - Desulfurization H-40
TABLE H-25. Operating Cost Consumptions - Miscellaneous Process
Units . . H-41
TABLE H-26. Operating Costs Coefficients H-42
TABLE H-27. Process Unit Capital Investment Estimates H-43
TABLE H-28. Offsite and Other Associated Costs of Refineries Used
in Estimating Cost of Grassroots Refineries H-44
APPENDIX I
TABLE 1-1. Bureau of Mines Refinery Input/Output Data for
Cluster Models: 1973 1-2
TABLE 1-2. Bureau of Mines Receipts of Crude by Origin 1973 1-3
TABLE 1-3. Bureau of Mines Refinery Fuel Consumption for
Cluster Models 1973 1-4
xii
-------
APPENDIX I - (cont.)
Page
TABLE 1-4. Bureau of Mines Refinery Fuel Consumption for Cluster
Models 1973 1-5
TABLE 1-5. ADL Model Input/Outturn Data for Calibration 1-7
TABLE 1-6. Conversion of BOM Input/Outturn Data to ADL Model
Format 1-8
TABLE 1-7. ADL Model Crude Slates and Sulfur Contents for
Refinery Clusters 1-11
TABLE 1-8. Texas Gulf Cluster Processing Configuration 1-12
TABLE 1-9. Louisiana Gulf Cluster Processing Configuration 1-13
TABLE 1-10. Large Midwest Cluster Process Configuration 1-14.
TABLE 1-11. Small Midcontinent Cluster Processing Configuration 1-15-
TABLE 1-12. West Coast Cluster Model Processing Configuration 1-16
TABLE 1-13. East Coast Cluster Processing Configuration 1-17
TABLE 1-14. Cluster Model Gasoline Production and Properties
1973 1-19
TABLE 1-15. Key Product Specifications 1-20
TABLE 1-16. Cluster Model Processing Data - 1973 1-23
TABLE 1-17. Louisiana Gulf Cluster Model 1-32
TABLE 1-18. Texas Gulf Cluster Model 1-33
TABLE 1-19. Large Midwest Cluster Model 1-34
TABLE 1-20. Small Midcontinent Cluster Model 1-35
TABLE 1-21. West Coast Cluster Model 1-36
TABLE 1-22. East Coast Cluster Model 1-37
TABLE 1-2.3. Louisiana Gulf Calibration 1-39
TABLE 1-24. Texas Gulf Calibration 1-40
TABLE 1-25. Small Midcontinent Calibration 1-41
xiii
-------
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 the Manufacture of Lead-Free
Gasoline - 1977 J-5
TABLE J-2. Economic Penalty for the Manufacture of Lead-Free
Gasoline - 1980 J-6
TABLE J-3. Economic Penalty for the Manufacture of Lead-Free
Gasoline - 1985 J-7
TABLE J-4. Economic Penalty for the Introduction of Lead
Phasedown - 1977 J-8
TABLE J-5. Economic Penalty for Introduction of Lead Phasedown -
1980 J-9
TABLE J-6. Energy Penalty for the Manufacture of Lead-Free
Gasoline - 1977 . . . . J-10
TABLE J-7. Energy Penalty for the Manufacture of Lead-Free
Gasoline - 1980 J-ll
TABLE J-8. Energy Penalty for the Manufacture of Lead-Free
Gasoline - 1985 J-12
TABLE J-9. Energy Penalty for the Introduction of Lead Phasedown -
1977 , J-13
TABLE J-10. Energy Penalty for the Introduction of Lead Phasedown -
1980 J-14
TABLE J-ll. Capital Investment Requirements
for Lead Regulations . J-15
TABLE J-12. Operating Costs Required to Meet Lead Regulations J-16
TABLE J-13. Basis for Cluster Capital Investment Requirements J-17
TABLE J-14. L.P. Model Results - Capital Investment Requirements
and Operating Costs -r East Coast J-18
xiv
-------
APPENDIX J - (cont.)
Page
TABLE J-15. L.P. Model Results - Capital Investment Requirements
and Operating Costs - East Coast J-19
TABLE J-16. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Large Midwest J-20
s
TABLE J-17. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Large Midwest J-21
TABLE J-18. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-22
TABLE J-19. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-23
TABLE J-20. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-24
TABLE J-21. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-25
TABLE J-22. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Texas Gulf J-26
TABLE J-23. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Texas Gulf J-27
TABLE J-24. L.P. Model Results - Capital Investment Requirements
and Operating Costs - West Coast J-28
TABLE J-25. L.P. Model Results - Capital Investment Requirements
and Operating Costs - West Coast J-29
TABLE J-26. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
East of Rockies J-30
TABLE J-27. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
West of Rockies J-31
TABLE.J-28. L.P. Model Results - Fixed Inputs and Outputs -
East Coast J-32
TABLE J-29. L.P. Model Results - Fixed Inputs and Outputs -
Large Midwest J-33
xv
-------
APPENDIX J - (cont.)
Page
TABLE J-30. L.P. Model Results - Fixed Inputs and Outputs -
Small Midcontinent J-34
TABLE J-31. L.P. Model Results - Fixed Inputs and Outputs -
Louisiana Gulf J-35
TABLE J-32. L.P. Model Results - Fixed Inputs and Outputs -
Texas Gulf J-36
TABLE J-33. L.P. Model Results - Fixed Inputs and Outputs -
West Coast J-37
TABLE J-34. L.P. Model Results - Inputs and Fixed Outputs -
Grassroots Refineries J-38
TABLE-J-35. L.P. Model Results - Processing and Variable Outputs -
East Coast Cluster '. J-39 '
TABLE J-36. L.P. Model Results - Processing and'Variable Outputs -
Large Midwest J-40
TABLE J-37. L.P. Model Results - Processing and Variable Outputs -
Small Midcontinent Cluster J-41
TABLE J-38. L.P. Model Results - Processing and Variable Outputs -
Louisiana Gulf Cluster J-42
TABLE J-39. L.P. Model Results - Processing and Variable Outputs -
Texas Gulf Cluster J-43
TABLE J-40. L.P. Model Results - Processing and Variable Outputs -
West Coast Cluster J-44
TABLE J-41. L.P. Model Results - Processing and Variable Outputs -
Grassroots Refineries, 1985 J-45
TABLE J-42. L.P. Model Results - Gasoline Blending - East Coast ... J-46
TABLE J-43. L.P. Model Results - Gasoline Blending - East Coast ... J-47
TABLE J-44. L.P. Model Results - Gasoline Blending -
Large Midwest . J-48
TABLE J-45. L.P. Model Results - Gasoline Blending -
Large Midwest J-49
xvi
-------
APPENDIX J - (cont.)
Page
TABLE J-46. L.P. Model Results - Gasoline Blending -
Small Midcontinent J-50
TABLE J-A7. L.P. Model Results - Gasoline Blending -
Small Midcontinent J-51
TABLE J-48. L.P. Model Results - Gasoline Blending -
Louisiana Gulf J-52
TABLE J-49. L.P. Model Results - Gasoline Blending -
Louisiana Gulf J-53
TABLE J-50. L.P. Model Results - Gasoline Blending -
Texas Gulf J-54
TABLE J-51. L.P. Model Results - Gasoline Blending -
Texas Gulf J-55
TABLE J-52. L..P. Model Results - Gasoline Blending -
West Coast J-56
TABLE J-53. L.P. Model Results - Gasoline Blending -
West Coast J-57
TABLE J-54. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries - East Coast Sweet Crude J-58
TABLE J-55. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - East Coast Sweet Crude J-59
TABLE J-56. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries - East Coast Sour Crude J-60
TABLE J-57. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - East Coast Sour Crude J-61
TABLE J-58. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - West Coast - Alaskan North SI. J-62
TABLE J-59.. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - West Coast - Alaskan North SI. J-63
TABLE J-60. L.P. Model Results - Residual Fuel Oil Sulfur
Levels - 1977 J-64
xvi i
-------
APPENDIX J - (cont.)
Page
TABLE J-61. L.P. Model Results - Residual Fuel Oil Sulfur
Levels - 1980 J-65
TABLE J-62. L.P. Model Results - Residual Fuel Oil Sulfur
Levels - 1985 J-66
TABLE J-63. L.P. Model Results - Refinery Fuel Sulfur
Levels - 1977 J-67
TABLE J-64. L.P. Model Results - Refinery Fuel Sulfur
Levels - 1980 J-68
TABLE J-65. L.P. Model Results - Refinery Fuel Sulfur
Levels - 1985 J-69
TABLE J-66. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985, Scenario B/C - Stream Values -
Gas Oil 375-650°F J-73
TABLE J-67. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985 B/C - Desulfurization of
Light Gas Oil J-74
TABLE J-68. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985, Scenario B/C - Feed Sulfur Levels ... J-75
TABLE J-69. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Stream Qualities -
Cluster Specific Streams J-76
TABLE J-70. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985, Scenario B/C - Stream Qualities -
Cluster Specific Streams J-77
TABLE J-71. Specific Gravities and Densities for the Miscellaneous
Streams J-78
TABLE J-72. Mass and Sulfur Balance - Texas Gulf Cluster 1985,
Scenario B/C J-79
XVlll
-------
APPENDIX K
TABLE K-l.
TABLE K-2.
TABLE K-3.
TABLE K-4.
TABLE K-5.
TABLE K-6.
Weight Conversions
Volume Conversions
Page
K-l
K-2
Gravity, Weight and Volume Conversions for Petroleum
Products K-3
Representative Weights of Petroleum Products
Heating Values of Crude Petroleum and Petroleum
Products
Nomenclature
K-4
K-5
K-6
xix
-------
VOLUME II
LIST OF FIGURES
APPENDIX F
FIGURE F-l. Geographic Regions Considered in Development of
Cluster Models F-3
APPENDIX I
FIGURE 1-1. Louisiana Gulf Cluster Model Calibration 1-25
FIGURE 1-2. Texas Gulf Cluster Model Calibration 1-26
FIGURE 1-3. Small Midcontinent Cluster Model Calibration 1-27
FIGURE 1^4. Large Midwest Cluster Model Calibration 1-28
FIGURE 1-5. West Coast Cluster Model Calibration 1-29
FIGURE 1-6. East Coast Cluster Model Calibration 1-30
APPENDIX J
FIGURE J-l. East of Rockies Grassroots 1985 - Scenario A J-70
FIGURE J-2. West of Rockies Grassroots 1985 - Scenario A J-71
FIGURE J-3. Texas Gulf Cluster 1985 Sulfur and Material Balance J-72
xx
-------
APPENDIX A
CRUDE SLATES
-------
TABLE OF CONTENTS
APPENDIX A - CRUDE SLATES
Page
A. METHODOLOGY A"1
B. MODEL CRUDE SLATES A-2
C. CRUDE MIX FOR TOTAL U. S A-10
LIST OF TABLES
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 A
CRUDE SLATES
The general objective in selecting crude slates for each cluster model
was to simulate as closely as possible the average future mixture of crudes
which would be run in each refining area represented by the cluster models.
Specifically, the crude slates were chosen to simulate as closely as
possible the average domestic/foreign mix, sulfur content, API gravity,
and other key properties of future crude slates for these refining areas.
A. METHODOLOGY
The basis for forecasting future crude mixes in each cluster model was
the Bureau of Mines data on actual crude inputs in 1973 for the six refinery
clusters. tSee Table A-l.) For future years, the actual mixes in each cluster
model were modified in accordance with changes in availability of certain
crudes and the addition of major new crude sources (e.g., Alaskan North
Slope). The only limitation on the future crude slates was to restrict the
number of different crudes used to a manageable level.
The Bureau of Mines data for 1973 shown in Table A-l indicates the origin
of domestic crude inputs by state and foreign crude receipts by country of
origin. For the purposes of forecasting model crude slates, certain repre-
sentative crudes have been chosen to represent crude inputs of a similar
quality. Specifically,
Louisiana crude was used for Louisiana and low-sulfur Texas
crudes;
Oklahoma crude was used for light, sweet crudes produced in the
Mivlccntinenf;
* West Texas was used for high sulfur crudes from both Texas and
New Mexico;
A-l
-------
Wilmington and Ventura crudes were used for heavy and light
Californian crudes, respectively;
Nigerian Forcados was used for heavy African crudes;
Algerian Hassi Messaoud was used for light African crudes;
Arabian Light was considered representative of average Middle
East crudes;
Minas crude represented southeast Asian crude imports; and
Tia Juana Medium was assumed to typify Venezuelan export crudes.
Table A-2 indicates the actual crude slates assumed for 1973 for each cluster
model based on the representative crude methodology just discussed. Table A-2
also includes a comparison of the average, sulfur content of the assumed model
crude slates given in the table with industry average sulfur content
obtained by the EPA from individual company data. As shown, the sulfur con-
tents of the model crude slates check quite closely with actual reported
data.
B. MODEL CRUDE SLATES
In projecting crude slates for the cluster models (see Tables A-3 -
A-8), specific assumptions have been made regarding crude requirements and
availability for each cluster model. These assumptions have been made to
simulate the average crude inputs which will prevail in the refining areas
represented-by the cluster models. The specific crude supply conditions and
assumptions for each refining area are as follows:
Small Midcontinent: The cluster model simulating the typical small
Midcontinent refiner shows that on average the small Midcontinent
refiner currently runs a large proportion of various Texas, Louisiana,
and Oklahoma crudes (82%) and small amounts of Canadian (18%). In
general, it has been forecast that in the future there will be decreasing
amounts of domestic crudes (particularly lower sulfur Louisiana crudes)
available to the small Midcontinent refiner and, as a result, he will
find himself turning increasingly .towards foreign crude sources. (See
Table A-3.) It has been assumed that Canadian crude will be rapidly
withdrawn from these refiners and that the future foreign crude require-
ments will be a 50/50 mixture of relatively high sulfur Middle Eastern
crudes and low sulfur African crudes. There is already evidence of thi.s
A-2
-------
Table A-1. BUREAU OF MINES RECEIPTS OF CRUDE BY ORIGIN 1973
(MB/CD)
Crude source
Domestic crudes
State of orgin:
Alabama
Alaska
California
Colorado
Florida
Illinois
Kansas
Louisiana
Oklahoma
Mississippi
Montana
Nebraska
New Mexico
Texas
Utah
Wyoming
Total domestic
Foreign crudes
Country of origin:
Algeria
Angola
Canada
Ecuador
Indonesia
Iran
Iraq
Libya
Mexico
Nigeria
Qatar
Saudi Arabia
Sumatra
Trinidad
Tunisia
United Arab Emirates
Venezuela
Total foreign crudes
Louisiana
Gulf
50
185,654
2,395
40,502
228,601
161
214
827
910
189
546
263
3,110
Texas
Gulf
5,231
12,051
18,306
1,601
281,252
318,441
3,869
3,666
50
489
10,213
15,732
7,257
41,276
Small
Midcontinent
459
63
18,906
2,259
21,931
85
370
4,686
1,022
49,781
10,744
10,744
Large
Midwest
3,398
9,090
836
19,354
10,643
241
836
32,673
48,805
10,818
136,694
26,022
238
4,291
30,551
West
Coast
12,146
89,254
' 678
4,321
106,399
7,019
5,970
515
2
27,056
24,712
3,927
1,295
70,4.46
East
Coast
2,594
3,346
275
37,800
44,015
25,248
1,165
3,905
16,121
29,430
6,036
1,772
3,733
5,676
61,334
154,430
A-3
-------
Table A-2. ADL MODEL CRUDE SLATES AND SULFUR CONTENTS FOR 1973
(MB/CD)
Crude type
Domestic
Louisiana
West Texas Sour
Oklahoma
Calif. Wilmington
Calif. Ventura
Subtotal
Foreign
\ Nigerian
(Arabian Light
Venezuelan
Algerian
Mixed Canadian
Indonesian
Subtotal
Total
Sulfur Content
(% weight)
Model average
Industry average3
Louisiana Gulf
Volume
197.2
25.0
-
-
222.2
-
-
-
0
222.2
%
88.7
11.3
-
-
100.0
:
-
-
-
-
0
100.0
0.331
0.40
Texas Gulf
Volume
157.2
137.1
-
-
294.3
12.7
17.4
7.0
-
-
-
37.1
331.4
%
47.4
41.4
-
-
88.8
3.8
5.3
2.1
-
-
-
11.2
".00.0
0.765
0.72
Small Midcontinent
Volume
4.2
7.2
33.9
-
-
45.3
-
9.8
- .
9.8
55.1
%
7.6
13.1
61.5
-
-
82.2
17.8
-
17.8
100.0
0.367
0.37
Large Midwest
Volume
8.7
102.4
1.7
-
118.3
12.3
15.0
-
27.3
145.6
%
6.0
70.3
4.9
-
-
81.2
8.5
10.3
-
18.8
100.0
1.130
1.17
West Coast
Volume
58.0
21.4
79.4
48.6
11.0
16.2
75.8
155.2
%
37.4
13.8
51.2
31.3
7.1
10.4
48.8
100.0
1.251
1.30
East Coast
Volume
28.9
14.4
_
-
-
43.3
30.4
14.2
59.6
40.5
-
144.7
188.0
%
15.4
7.6
-
-
23.0
16.2
7.6
31.7
21.5
-
-
77.0
100.0
0.789
0.73
>
Reference-transmitted to ADL by EPA on 1/22/75
-------
Table A-3. MODEL CRUDE SLATES-SMALL MIDCONTINENT
(MB/CD)
Domestic
West Texas Sour
Louisiana
Oklahoma
Subtotal
Foreign
Canadian
Saudi Arabian Light
Algerian Hassi Messaoud
Subtotal
Total
1977
Volume
6.6
3.3
32.9
42.8
4.8
3.7
3.7
12.2
55.0
Percent
12.0
6.0
59.8
77.8
8.8
6.7
6.7
22.2
100.0
1980
Volume
6.0
1.6
31.8
39.4
7.8
7.8
15.6
55.0
Percent
10.9
2.9
57.8
71.6
14.2
14.2
28.4
100.0
1985
Volume
5.5
30.7
36.2
9.4
9.4
18.8
55.0
Percent
10.0
55.8
65.8
17.1
17.1
34.2
100.0
-------
trend towards increasing use of foreign crudes in the two new
crude pipelines under construction from the Texas Gulf Coast to
Gushing, Oklahoma. Both Texoma and Seaway pipelines were designed
to transport foreign crudes to refineries in the Midcontinent.
Large Midwest: Like the small Midcontinent refiners, the large Midwest
refiners have typically run a high percentage of domestic crudes (81%)
with smaller volumes of Canadian and Middle Eastern crudes. In the
future, it is expected that domestic crudes (again, particularly the
sweeter Louisiana crudes) will decline in importance and be replaced by
foreign crudes (See Table A-4.) Domestic oil policy in Canada will cause
Canadian exports to large Midwest refiners to decline vapidly, so that by 1980
no Canadian crudes are likely to be run in Midwest refineries. The
demise of Canadian exports to the area will force refiners to rely
increasingly on Middle Eastern crudes. Since large Midwest refineries
£-
were built to handle high sulfur domestic crudes, it is forecast that
higher-sulfur Middle Eastern sources (typified by Saudi.Arabian Light)
will become increasingly important to the area's refineries. As in the
case of the small Midcontinent refineries, the trend towards increased
reliance on foreign crude supplies is evidenced by the expansion of
the region's only direct, non-Canadian, foreign crude lineCapline
from the Louisiana Gulf.
Texas Gulf: Refiners in the Texas Gulf have run almost 90% domestic
crude (48% Louisiana and 42% West Texas Sour). The remaining
10-11% of crude supplies have come from a combination of Middle Eastern,
African, and Venezuelan sources. In the future, it is forecast that
the crude supply pattern in this region will not change significantly,
as decreasing supplies of domestic crudes are reserved for use by
refiners in the Gulf area. (See Table A-5 .)
East Coast: Historically, typical refineries in this area have run a
very high proportion of foreign crude (77% in the cluster model in 1973).
As domestic crude supplies decline in the future, it is forecast that East
Coast refiners will rely entirely upon foreign crude sources. (See Table A-6 .)
Because of the severe sulfur restrictions on the East Coast, it is
projected that there will be significant imports of Algerian and Nigerian
type crudes (representing some 38% of total crude oil to the East Coast
A-6
-------
Table A-4. MODEL CRUDE SLATES-LARGE MIDWEST
(MB/CD)
Domestic
West Texas Sour
Louisiana
Oklahoma
Subtotal
Foreign
Canadian
Saudi Arabian Light
Subtotal
Total
1977
Volume
93.4
4.3
6.9
104.6
7.4
31.4
38.8
143.4
Percent
65.1
3.0
4.8
72.9
5.2
21.9
27.1
100.0
1980
Volume
86.2
6.6
92.8
50.6
50.6
143.4
Percent
60.1
4.6
64.7
35.3
35.3
100.0
1985
Volume
79.0
6.3
85.3
58.1
58.1
143.4
Percent
55.1
_
4.4
59.5
40.5
40.5
100.0
-------
>
oo
Table A-5. MODEL CRUDE SLATES-TEXAS GULF
(MB/CD)
Domestic
West Texas Sour
Louisiana
Subtotal
Foreign
Saudi Arabian Light
Nigerian Forcados
Tia Juana Medium
Subtotal
Total
1977
Volume
136.0
155.7
291.7
17.4
12.5
6.9
36.8
328.5
Percent
41.4
47.4
88.8
5.3
3.8
2.1
11.2
100.0
1980
Volume
136.0
155.7
291.7
17.4
12.5
6.9
36.8
328.5
Percent
41.4
47.4
88.8
5.3
3.8
2.1
11.2
100.0
1985
Volume
136.0
155.7
291.7
17.4
12.5
6.9
36.8
328.5
Percent
41.4
47.4
88.8
5.3
3.8
2.1
11.2
100.0
-------
>
Table A-6. MODEL CRUDE SLATES-EAST COAST
(MB/CD)
Domestic
Subtotal
Foreign
Saudi Arabian Light
Algerian Hassi Messaoud
Nigerian Forcados
Tia Juana Medium
Subtotal
Total
1977
Volume
. -
-
70.7
40.8
34.0
52.4
197.9
197.9
Percent
-
-
35.7
20.6
17.2
26.5
100.0
100.0
1980
Volume
-
-
80.5
38.8
36.0
42.6
197.9
197.9
Percent
-
-
40.7
19.6
18.2
21.5
100.0
100.0
1985
Volume
-
-
90.4
36.8
38.0
32.7
197.9
197.9
Percent
-
45.7
18.6
19.2
16.5
100.0
100.0
-------
cluster model in 1977-':1985) , with the remainder supplied by Middle
Eastern and Venezuelan crudes.
West Coast: The refineries comprising this cluster model currently
run an almost 50/50 mixture of domestic Californian crudes and foreign
crudes. The predominenc domestic crude is presently typified by Cali-
fornia Wilmington (a heavy crude). While the West Coast refineries
modeled currently consume Middle Eastern, Indonesian, and Canadian
crudes, the Middle Eastern crudes account for nearly twice as much as
the Canadian and Indonesian inputs combined. In the future it is forecast
that volumes of local California crudes will remain at present levels,
but foreign crudes will be entirely backed out by Alaskan North Slope
volumes beginning in 1980. (See Table A-7 .)
Louisiana Gulf: As simulated in the cluster model, refineries along
the Louisiana Gulf presently operate exclusively on domestic crudes. Of
these domestic crudes, about 88% are sweet and the remainder sour. Due
to the fact that these Louisiana refineries are ideally located to
process offshore and southern Louisiana crude production, it is forecast
that there will be no change in the crude slate for the typical refiner
on the Louisiana Gulf. (See Table A-&.)
Grassroots Refineries: The crude slates for the grassroots refineries
were based on balancing the total crude supply to the U.S.A. on an East
of the Rockies and West of the Rockies basis.
East of the Rockies; Grassroots refineries on the East Coast are
projected to run a mixture of three types of foreign crudes. Two-
thirds of the crude input will be composed of Middle Eastern crudes
typified by Saudi Arabian Light; the remaining one-third will
be made up of a 50/50 mixture of crudes like Algerian Hassi Messaoud
and Nigerian Forcados.
West of the Rockies: Because of the huge volumes of Alaskan North
Slope crude expected to be available on the West Coast, it was
assumed that grassroots refineries in that part of. the country
would run exclusively Alaskan North Slope crudes.
f.. CRUDE MIX FOR TOTAL U.S.
In order to assess the implications for the total U.S. crude slate of
our assumptions regarding crude inputs to cluster models and grassroots
A-10
-------
Table A-7. MODEL CRUDE SLATES-WEST COAST
(MB/CD)
Domestic
California Wilmington
California Ventura
Alaskan North Slope
Subtotal
Foreign
Canadian
Saudi Arabian Light
Indonesian Minas
Subtotal
Total
1977
Volume
65.7
21.7
87.4
5.6
54.8
16.4
76.8
164.2
Percent
40.0
13.2
53.2
3.4
33.4
10.0
46.8
100.0
1980
Volume
65.7
21.7
76.8
164.2
-
164.2
Percent
40.0
13.2
46.8
100.0
-
-
100.0
1985
Volume
65.7
21.7
76.8
164.2
-
-
164.2
Percent
40.0
13.2
46.8
100.0
-
-
100.0
-------
>
Table A-8. MODEL CRUDE SLATES-LOUISIANA GULF
(MB/CD)
Domestic
Louisiana Sweet
West Texas Sour
Subtotal
Foreign
Subtotal
Total
1977
Volume
192.3
25.7
218.0
218.0
Percent
88.2
11.8
100.0
100.0
1980
Volume
192.3
25.7
218.0
218.0
Percent
88.2
11.8
100.0
-
100.0
1985
Volume
192.3
25.7
218.0
_
218.0
Percent
88.2
11.8
100.0
-
100.0
-------
refineries, we have scaled up the volume of inputs consistent with the
amount of refining capacity represented by each cluster or type of grass-
roots refinery. Table A-9 shows the results of the scale up exercise using
the crude oil required in Scenario A. For the cluster models the scaled
up crude slates in 1980 and 1985 are constant between scenarios. Crude
inputs to the grassroots models were allowed to vary between scenarios to
balance required gasoline production. Table A-10 shows the scaled up crude
inputs to the grassroots models for 1980 and 1985.
In general, there is expected to be an increasing reliance on foreign
crudes in 1980 and 1985 as a result of declines in crude production in the
"Lower 48." Even with 1.6 million B/CD of Alaskan North Slope crude
consumed in 1985, the decline in production from existing reserves is not
offset. Among the foreign imports, the Middle Eastern crudes typified by
Saudi Arabian Light are expected to provide by far the largest share, with
Nigerian, Algerian, and Venezuelan type crudes accounting for about half
of the volume of Middle Eastern crudes.
The scale up crude slate detailed in Table A-9 indicates that the pro-
portions of sweet and sour crude within the total crude slate will not
change substantially over the next decade (see also Table A-ll). Over the
next five years there will be a rise in the volume of sour crudes processed
in U.S. refineries as a result of insufficient worldwide production of low
sulfur crudes to offset declining U.S. production of sweet crudes. However,
this increase in average sulfur content is not expected to cause processing
constraints, since domestic and Caribbean downstream processing capacity is
forecast to be sufficient to allow refiners to meet sulfur constraints even
with a higher average sulfur content in their crude inputs.
In the longer-term, the sweet/sour balance will be preserved despite
declines in production from existing domestic sources as a result of an
increased availability of sweet crudes on the world market. It is pro-
jected that not only will significant volumes of new low-sulfur crude pro-
duction become available (e.g., the. North Sea production and increased
Chinese exports), but output from current low-sulfur sources, such as
Indonesia will increase. While it is possible that somp of the crude
from new low-sulfur production sources will be shipped to the U.S., it is
A-13
-------
Table A-9. SCALE UP OF MODEL CRUDE SLATES, SCENARIO A
(MB/CD)
Crude type
Domestic
Louisiana
West Texas Sour
Oklahoma
California
North Slope
Other
Subtotal
Foreign
Arabian Light
Nigerian
Algerian
Venezuelan
Canadian
Indonesian
Other
Subtotal
Total
1980
Cluster
models
3,253.2
3,368.0
640.0
1,057.8
930.5
-
9,249.5
1,850.5
412.3
422.2
400.2
-
3.085.2
12,334.7
Atypical
-
-
-
-
698.1
698.1
-
-
-
-
-
-
698.1
Grass
Roots
-
-
396.1
-
396.1
852.2
210.1
210.1
-
-
1,272.7
1,668.8
Total
Volume
3,253.2
3,368.0
640.0
1,057.8
1,326.6
698.1
10,343.7
2,703.0
622.4
632.3
400.2
-
4.357.9
14,701.6
%
22.1
22.9
4.4
7.2
9.0
4.8
70.4
18.4
4.2
4.3
2.7
-
29.6
100.0
1985
Cluster
models
3,226.2
3,229.0
616.8
1,062.3
934.5
-
9,068.8
2,088.0
427.4
434.1
324.9
-
3.274.4
12.343.2
Atypical
335.1
335.1
62.7
162.7
62.7
100.0
-
388.1
723.'
Grass
Roots
645.8
-
645.8
1,985.6
489.3
489.3
-
2,964.2
3,610.0
Total
Volume
3,226.2
3,229.0
616.8
1,062.3
1,580.3
335.1
10,049.7
4,136.3
1 ,079.4
986.1
424.9
-
6,626.7
16,676.4
%
19.3
19.4
3.7
6.4
9.5
2.0
60.3
24.8
6.5
5.9
2.5
-
39.7
100.0
-------
Table A-10. TOTAL CRUDE RUN TO GRASS ROOTS REFINERIES
(MB/CD)
Year/Grass Roots Region
1980
West of Rockies
East of Rockies
Total
1985
West of Rockies
East of Rockies
Total
Scenario
A
396.1
1,272.7
1,668.8
645.8
2,964.2
3,610.0
B
405.2
1,323.7
1,728.9
a
C
412.7
1,370.8
1,783.5
672.6
3,192.9
3.865.5
D
419.9
1,391.4
1,811.3
703.3
3,240.9
3,944.2
E
420.7
1,451.5
1,872.2
702.5
3,506.2
4,208.7
F
b
687.8
3,240.3
3,928.1
a. Scenarios B and C are identical in 1985.
b. Scenario F not analyzed in 1980.
A-15
-------
Table A-11. DISTRIBUTION OF SWEET AND SOUR CRUDE RUN
(Percent of total crude run)
Domestic
Louisiana
West Texas Sour
Oklahoma
California
North Slope
Subtotal
Foreign
Nigerian Forcados
Saudi Arabian Light
Venezuelan
Algerian Hassi Messaoud
Canadian
Indonesian
Subtotal
Otherb
Total
1973
Sour
-
26.1
-
7.3
-
33.4
-
8.4
6.0
-
3.3
-
17.7
51.1
Sweet3
36.1
-
3.7
-
-
39.8
3.9
-
-
3.7
-
1.5
9.1
48.9
1980
Sour
-
22.9
-
7.2
9.0
39.1
-
18.4
2.7
-
-
21.1
60.2
Sweet3
22.1
4.4
-
26.5
4.2
-
-
4.3
-
8.5
35.0
Otherb
-
-
-
-
-
-
-
4.8
4.8
1985
Sour
19.4
-
6.4
9.5
35.3
-
24.8
2.5
-
27.3
_
62.6
Sweet3
19.3
3.7
-
23.0
6.5
-
5.9
-
12.4
35.4
Otherb
-
_
-
-
2.0
2.0
>
a"Sweet" crude is defined as crude with a sulfur content less than 0.5%. "Sour" crude includes all crudes with sulfur contents greater than 0.5%.
h"
Other" refers to crudes which have not been defined by source and whose sulfur content is therefore unknown.
-------
more likely that low-sulfur crudes from new sources will displace low-
sulfur material from existing sources in traditional sulfur-sensitive
markets. For example, Chinese crude will likely go to Japanese markets
where it will displace some of the lower-sulfur Middle Eastern and Indonesian
imports. Similarly, North Sea production will be consumed in Europe,
freeing up some of the sweet African crudes for delivery to the U.S.
A-17
-------
APPENDIX B
U.S. SUPPLY/DEMAND PROJECTIONS
-------
TABLE OF CONTENTS
APPENDIX B - U.S. SUPPLY/DEMAND PROJECTIONS
Page
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
LIST OF TABLES
TABLE B-l. Projections of Major Product Demand in Total U.S.
Assumed in Making Model Runs B-3
TABLE B-2. A Comparison of Projected "Simulated" Demand for
Major Products with Results of Detailed Forecast.. B-5
TABLE B-3. A Comparison of Projected Total Petroleum Product
Demand in "Simulated" Demand Case with Detailed
Forecast B-6
TABLE B-4. Projection of U.S. Primary Energy Supplies
with Oil as the Balancing Fuel B-9
TABLE B-5. Forecast of U.S. Product Demand B-ll
-------
APPENDIX B
U.S. SUPPLY/DEMAND PROJECTIONS
A. DEMAND ASSUMPTIONS FOR MODEL RUNS
In the current study the demand forecast for the United States was
obtained by two different approaches. To ease the process of relating
the demand forecast with the scale up of the cluster model approach
(Appendix G), one simplistic forecasting approach was utilized which led
to a demand growth rate of 2% per annum for all petroleum products.
However, to. ensure that the study results were not unduly influenced
by this simplistic approach, parametric runs were undertaken to include
the effect of a more sophisticated forecasting technique. Each of these
forecasting techniques is described in detail below.
The primary reason for forecasting demand was to highlight the dif-
?'*.
ferences in requirements for grassroots capacity among the six scenarios.
Therefore, the actual demand forecast was thought to be of relatively
little importance in comparison to the relative differences inherent in
the scenarios. Because of the minor importance attached to the absolute
projected demand levels, a very simplistic forecasting approach was
initially utilized. As will be discussed below, the initial simplistic
approach resulted in an overall demand forecast which was well within the
range later derived by more elaborate forecasting techniques.
This appendix discusses petroleum product demand only for the U.S. as
a whole. To arrive at scaled up product outturns which must be met by the
simulated refining industry, imports of petroleum products (assumed to
be constant at 1973 actual levels throughout the period of analysis) and
outturns from atypical refineries must be subtracted from overall U.S.
demand.
B-l
-------
From the base year, 1973, product demand was forecast to realize zero
growth over 1974 and 1975 and average 2% per annum thereafter. In late
1975, it is evident that demand over 1974-1975 will, indeed, show zero
or, in some areas, negative growth relative to 1973 demand. Beyond
1975, public projections of oil demand growth range between 1% and 3.5%,
depending upon key assumptions regarding oil prices, consumer price
sensitivity, conservation incentives, the availability of alternative
energy forms, and U.S. government policy. The estimate of 2% average
annual growth was selected as a consensus figure, reflecting the generally
slower than historical growth trend which has resulted from higher oil
prices, but assuming some optimism regarding the future ecmomic growth
of the country.
The methodology initially utilized involved three simplifying assump-
tions: (1) demand for all products was assumed to grow at one uniform
rate (2% per annum from 1975 to 1985); (2) demand growth would occur
in equal increments throughout the forecast period; and (3) imports of
products would remain constant in volume and type throughout the forecast
period.
Table B-l shows the demand levels for major products which result
from an application of the simplified forecasting methodology. It should
be noted that these projections were based not on actual 1973 demand, but
on a "simulated" demand slate derived by adding the 1973 imports and out-
turn from atypical refineries to the scaled up yield of each of the cluster
models. Since the scale up of 1973 for all products was based on the
factors required to have gasoline yields for individual refining areas
equivalent to 1973 Bureau of Mines statistics on gasoline outturn in each
area, products other than gasoline were not necessarily scaled up to
actual consumption figures. The reason for using a "simulated" demand
slate as a projection base rather than an actual historical one was that
the use of actual data would have resulted in a demand forecast in future
years which, by comparison with our projected scaled up cluster outturns,
would have accentuated the initial 1973 differences in scaled up cluster
outturn and actual demand statistics. Because the differences in projected
B-2
-------
Table B-1. PROJECTIONS OF MAJOR PRODUCT DEMAND IN TOTAL U.S.
ASSUMED IN MAKING MODEL RUNS
(MB/CD)
Gasoline
Jet fuel & kerosene
Distillate fuel oil
Residual fuel oil
Total-major products
1973
Base year
"Simulated Demand"
6,706
1,177
3,550
2,809
14,271
1973
Base year
Actual Demand*
6,719
1,275
3,092
2,822
13,908
1977
6,977
1,225
3,693
2,922
14,817
1980
7,404
1,299
3,920
3,101
15,724
1985
8,174
1,432
4,328
3,424
17,358
'Bureau of Mines.
B-3
-------
demand and scaled up cluster outturn are used to set the quality and yield
structure of grassroots refineries, it is important that small differ-
ences between actual statistics and our scale ups in 1973 not be magnified
over the forecast period.
Table B-2 shows a comparison of the forecast of "simulated" demand
for major products and the range of demand projections resulting from our
more detailed forecast. As indicated, the projection of total "simulated"
demand falls within the range of demand forecast by the more elaborate
methods which will be described below. However, although there is overall
agreement on total demand, there are discrepancies within individual
products as a result of: (1) differences in base year smarting points
(see Table B-l); (2) the assumption of constant average annual growth;
and (3) the lack of differential product growth. The differences in
base year statistics result from the methods used in scaling up cluster
output to regional refinery yields. As described above, one scale up
factor (based on the premise of equating gasoline outturns to actual
gasoline yields) for all products inevitably resulted in the deviation of
some "simulated" product demands from actual reported consumption. The
assumption of common growth rate for all products not only reinforced
the initial inconsistencies resulting from the scale up procedure but
permitted no oscillation in product growth rates. In general, the
detailed forecast described below shows product growth (particularly,
fuel oils) resuming a moderate growth through the late 1970's and then
dropping off in the 1980's as more efficient conservation practices
become feasible, more non-oil energy is available and the national
economy grows more slowly and with less energy input.
Comparing the total simulated product demand with the demand fore-
cast described below also shows that the results of the simplified
approach fall within the range projected in the detailed forecast.
Table B-3 Compares the total product demands forecast in the simplified
and detailed forecasts. Several important assumptions should be noted.
Firstly, the LPG demand forecast in the "simulated" demand reflects only
the demand for refinery-produced LPG, not LPG extracted at natural gas
B-4
-------
Table B-2. A COMPARISON OF PROJECTED "SIMULATED" DEMAND FOR
MAJOR PRODUCTS WITH RESULTS OF DETAILED FORECAST
(MB/CD)
Gasoline
Jet fuel & kerosene
Distillate fuel oil
Residual fuel oil
Major products total
1977
"Simulated"
6,977
1,225
3,693
2,922
14,817
Forecast
High
7,370
1,320
3,420
3,140
15,250
Low
7,190
1,300
3,040
2,790
14,320
1980
"Simulated"
7.404
1,299
3,920
3,101
15,724
Forecast
High
8,160
1,470
3,870
\
4,030
17,530
Low
7,520
1,390
3,110
3,240
15,260
1985
"Simulated"
8,174
1,432
4,328
3,424
17,358
Forecast
High
9,010
1,790
4,270
3,020
18,090
Low
7,520
1,600
3,400
2,750
15,270
-------
Table B-3. A COMPARISON OF PROJECTED TOTAL PETROLEUM PRODUCT DEMAND
IN "SIMULATED" DEMAND CASE WITH DETAILED FORECAST
(MB/CD)
Gasoline
LPG (excl. products at gas
processing plants)
Jet fuel & kerosene
Distillate fuel oil
Residual fuel oil
Lubes, waxes & coke
Asphalt
Other
Total
1977
"Simulated"
6,977
513
1,225
3,693
2,922
422
354
504
16,610
Memo:
LPG production at gas processing plants
Estimated refinery fuel & losses
Total forecast petroleum consumption
Forecast
High
7.370
480
1,320
3,420
3,140
450
530
1,040
17,750
720
1,430
19,900
Low
7,190
460
1,300
3,040
2,790
420
520
1,010
16,730
680
1,410
18,820
1980
"Simulated"
7,404
545
1,299
3,920
3,101
448
408
538
17,663
." ^recast
High
8,160
540
1,470
3,870
4,030
490
590
1,100
20,250
800
1,620
22,670
Low
7,520
500
1,390
3,110
3,240
470
550
1,080
17,860
750
1,530
20,140
1985
"Simulated"
8,174
603
1,432
4,328
3,424
496
452
597
19,506
Forecast
High
9,010
590
1,790
4,270
3,020
540
660
1,360
21,240
890
1,780
23,910
Low
7,520
560
1,600
3,400
2,750
520
610
1,310
18,270
820
1,690
20,780
cd
I
-------
liquids plants. In recent years approximately 65-70% of all LPG
originated from natural gas liquids processing, with the remainder
supplied from refineries and imports. In the future, the volume of
natural gas liquids and the LPG yield from these liquids are expected
to decline, so we have assumed in our 1985 projection that only 60%
of the LPG will be produced at natural gas processing plants. A
second factor to keep in mind in comparing forecasts is that the
simplified forecast does not include projections of refinery fuel and
losses. Thus, the simplified forecast should not be read as a forecast
of total U.S. oil requirements.
B. DETAILED U.S. PRODUCT DEMAND FORECAST
Prior to 1973 forecasting oil demand in the U.S. was a fairly
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. Oil consumption was
largely unaffected in 1973, but beginning in 1974, oil demand actually
dropped an estimated 3.8%.
Looking to the future there is a great deal of uncertainty surround-
ing the level and growth of oil demand. Contrary to historical trends.
oil demand is not expected to resume a rapid and steady upward climb.
However, the extent to which U.S. demand will turn upward and the timing
of the upswing are still very uncertain. In order to bound this uncer-
tainty, Arthur D. Little, Inc., has developed a range of estimates of
total energy and oil demand which we feel effectively defines the limits
within which future energy demand will probably fall. The methodology
underlying the forecast, as well as the forecast itself, is discussed
below.
1. Methodology
To forecast future oil consumption it is necessary to evaluate the
supplies and demand for all primary energy forms (coal, natural gas,
B-7
-------
hydroelectric, nuclear and oil). Two basic sets of assumptions were used
in order to develop a definitive range of energy supply/demand balances:
High Case: Economic growth is assumed to be somewhat slower than historic
rates, but high enough to permit a rising standard of living. Higher
energy prices aloneand not government actionare assumed to result in
consumer energy conservation. Likewise, higher energy prices are the
impetus for the development of domestic energy resources.*
Low Case: Economic and total energy growth fall further off historic
rates as a result of both strong government action and higher energy
prices. Government action in the form of conservation incentives,
selective taxes on oil, import tariffs, etc., is taken to enhance the
effects of higher prices in dampening demand and stimulating the develop-
ment of domestic resources.
The methodology used for deriving oil demand in both cases involved
projecting the availability of non-oil energy forms and contrasting
these supply estimates with projections of demand consistent with the
high and low scenarios. In all cases, oil was assumed to be the balancing
fuel in matching the supply and demand estimates. Our forecast of non-
oil energy supplies, expressed in quadrillions of Btu's.is given in
Table B-4.
Table B-4 shows-our projection that total U.S. energy demand will
grow at an average of 2.9-3.3% per annum over the period 1972-1980 and
between 2.7-4.0% per annum during the first half of the following decade.
Oil demand is forecast to grow at between 2.4-3.4% between 1972-1980,
and at about 1% in the 1980-85 period.
There are several important features of the primary energy forecast
given in Table B-4. Coal production and consumption which have actually
declined in recent years are expected to be rejuvenated as a result of
higher energy prices, emphasis on exploiting domestic energy resources,
*
This case currently appears to be too optimistic regarding future
economic growth and the sensitivity of consumers to rises in energy
prices. However, we feel that it does represent the bounding limit on
the high side.
B-8
-------
Table B-4. PROJECTION OF U.S. PRIMARY ENERGY SUPPLIES
WITH OIL AS THE BALANCING FUEL
(Quadrillions of Btu's)
Coal
Natural gas
Hydro
Nuclear
Non-conventional
Oil
Total
1972
12.3
25.1
2.8
0.6
-
32.5
73.3
1980
High
19.6
23.9
3.2
5.8
0.1
42.5
95.1
Low
19.8
23.9
3.2
5.8
0.1
39.2
92.0
1985
High
23.6
24.7
3.3
.17.5
0.2
44.7
114.0
Low
21.5
24.7
3.2
14.7
0.2
40.9
105.2
Source: U.S. Bureau of Mines and Arthur D. Little, Inc., estimates.
B-9
-------
and production of secondary energy forms from coal. It is expected that
it will take the coal industry several years to gear up for higher pro-
duction levels, but beyond 1980, production capacity will no longer be
such a severe limitation on coal consumption. Natural gas is expected
to be supply-constrained throughout the forecast period, as production
from "Lower 48" resources continues to decline (despite increased off-
shore activity) 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 a 25-30 fold
increase over the forecast period. Non-conventional energy forms,
such as solar, wind and solid waste, are not expected to play a signi-
ficant role during the time frame of this forecast, due to the time
required to commercialize and disseminate the technologies involved.
As described above, oil was assumed to be the balancing fuel
between the forecast demand for total energy and the projected availa-
bility of non-oil energy forms. As such, oil was regarded as being
a premium quality fuel, to be increasingly devoted to uses where its
liquid, clean-burning properties would command a premium price. Coal,
and later nuclear power, were assumed to take over the non-premium oil
uses, such as fuel for industrial and utility boilers.
The demand for energy was developed by breaking down total energy
consumption into demand by various end-use sectors (e.g., transportation,
industry, 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 of the high and low cases.
The modification of historic growth rates took into account our expecta-
tions of the impact of consumer conservation, government policy, energy
prices, and macro-economic conditions.
The breakdown of oil demand by product, shown in Table B-5, was
accomplished by examining the oil consumption patterns of specific
end-use sectors. For example, in the transportation sector, the oil
demand is a mixture of gasoline, jet fuel, LPG, residual fuel oil, and
distillate idiesel ) . To project future oil consumption patterns in the
B-10
-------
Table B-5. FORECAST OF U.S. PRODUCT DEMAND
(MMB/CD)
LPG & refinery gas
Naphtha & others
Gasoline
Kero & jet fuel
Distillate fuel oil
Residual fuel oil
Lubes/waxes, & coke
Asphalt
Refinery fuel & losses
Total
1975
1.49
0.49
6.56
1.17
2.70
2.52
0.41
0.47
1.28
17.09
1977
High
1.68
0.56
7.37
1.32
3.42
3.14
0.45
0.53
1.43
19.90
Low
1.62
0.53
7.19
1.30
3.04
2.79
0.42
0.52
1.41
18.82
1980
High
1.84
0.60
8.16
1.47
3.87
4.03
0.49
0.59
1.62
22.67
Low
1.75
0.58
7.52
1.39
3.11
3.24
0.47
0.55
1.53
20.14
1985
High
2.03
0.81
9.01
1.79
4.27
3.02
0.54
0.66
1.78
23.91
Low
1.93
0.76
7.52
1.60
3.40
2.75
0.52
0.61
1.69
20.78
B-ll
-------
transportation sector, separate forecasts were developed for automotive,
rail, marine and air transport and the fuels were projected accordingly,
taking into account any efficiency improvements.
2. Product Forecast
Table B-5 presents our forecast of the range of U.S. demand for
petroleum products. This forecast was developed by splitting the total
oil demand by end-use sector down into appropriate products and correcting
for any changes in consumption patterns.
There are several significant factors to notice about the forecast in
Table B-5. Gasoline, which grew at an average annual rate of 5.3%
between 1965 and 1972, will grow much more slowly, even in the high demand
case. Under the assumptions of the high demand case, gasoline will
continue to grow at a modest rate through 1980 (averaging 4.4% per annum),
and thereafter growth will be slower (2.0% per annum, 1980-1985) as
smaller-engined, more efficient cars penetrate the car population. In the
low demand case, we expect gasoline demand to be dampened earlier, with
higher gasoline prices, more efficient cars, and, perhaps, government
policy combining to keep growth to an average of 2.8% per annum in the
1975-1980 period. In the low demand case, gasoline .will actually show no
growth over 1980-1985, as the rate of introduction of more efficient
cars into the car population offsets the increases in size of the total
car population and any increases in average annual mileage travelled.
Jet fuel and kerosene combined are expected to have an average
annual growth rate of between 3.5 and 4.8% between 1975 and 1980, and
range between 2.9 and 4.0% during the last five years of the forecast
period. These forecast growth rates.are considerably below the historic
growth rates for jet fuel (which averaged just over 6.0% per annum
between 1965 and 1972), although kerosene for other uses has historically
shown a declining growth trend.
Demand for both distillate and: residual fuel oils is expected to grow
rapidly until 1980, largely as a result of decreased availability of
B-12
-------
natural gas and the inability of coal to immediately offset curtailed
volumes of natural gas. Beyond 1980, as increased availability of coal
and nuclear, and possibly volumes of Alaskan gas, decrease the burden
on fuel oils, growth in demand for fuel oil will drop off dramatically.
Thus, in the high demand case, demand for distillate fuel oil is projected
to grow rapidly at an average of 7.5% per annum between 1975 and 1980,
and then decrease dramatically to an average annual rate of 2.0% during
the early 1980's. Low case assumptions result in a distillate demand
growth of about 3.0% in the 1975-1980 period, declining to 1.8% between
1980 and 1985. Residual fuel oil demand in the high demand case will
increase very rapidly through the remainder of the 1970's (averaging
just under 10% per annum), and then fall off absolutely in the early 1980's.
Similarly, in the low demand case, residual fuel oil consumption is
projected to grow at an average annual rate of about 5% between 1975 and
1980, and decrease absolutely at a rapid pace in the 1980-1985 period.
Demand for naphtha and other petrochemical feed stocks is expected to
be another area of rapid growth. In the first five years of the forecast,
growth in feed stock demand is expected on average to be moderate
(averaging between 3.5 and 4.1% per annum) as a result of the recessionary
macro-economic conditions in the early years, but rapid growth (between
5.6 and 6.2% per annum) is expected to resume in the early 1980's.
The demand for LPG shown in Table B-5 represents total demand
regardless of product source. LPG is presently derived approximately
70% from natural gas processing plants, 22% from refineries, and 8%
from imports. In the future, with domestic natural gas production
projected to decline (as well as become leaner in natural gas liquids),
and Canadian import levels uncertain, there may be pressure on refineries
to increase production of LPG, and we anticipate a high level of interest
in major LPG import projects.
In summary, total product demand is expected to resume moderate growth
through the remainder of the 1970's and then slow to an average of 1% or
less iii the early 1980's, as conservation (price-induced and/or mandated)
and slower rates of national economic growth combine to depress demand
below historic levels.
B-13
-------
APPENDIX C
PRODUCT SPECIFICATIONS
-------
TABLE OF CONTENTS
APPENDIX C - PRODUCT SPECIFICATIONS
LIST OF TABLES
Page
TABLE C-l. Product Specifications, Gasoline C-2
TABLE C-2. Other Product Specifications C-4
-------
APPENDIX C
PRODUCT SPECIFICATIONS
Specifications for motor gasolines are presented in Table C-l.
Volatility specifications, i.e., Reid vapor pressure and distillation
temperatures, were primarily based upon reviewing Bureau of Mines data
for summer and winter gasolines. Also, a comprehensive analysis of
gasoline volatility is presented in the API study on unleaded gasoline.
In practice, the only distillation specification that exhibited a
significant influence on blending flexibility was the maximum percent
evaporated at 150°F. Several models, particularly the Texas Gulf, which
processed a relatively high percentage of natural gasoline, were impacted
by this volatility requirement.
Gasoline distillation end-point specifications are controlled
implicitly. For straight-run naphtha the maximum end-point of feed to
catalytic reforming is 400°F. For catalytic cracking, the yields and
product properties are based on a gasoline/distillate cut point of 400°F
in the catalytic cracking fractionation system.
Leaded octane specifications for each cluster model were set
identical to the values supplied by the EPA representing actual 1973 oper-
ations for the aggregate of the specific refineries comprising each cluster
model. The leaded octane requirements for grassroots refining was de-
termined by an average of the cluster models.
The minimum octane requirements for unleaded gasoline were specified
at 92/84 research/motor, respectively. Although statutory regulations re-
quire only a minimum 91/83 product, indications are that marginally higher
octanes are required to provide some allowance for blending tolerances.
Specific parametric studies were addressed to manufacturing unleaded grades
at higher octane specifications.
C-l
-------
Table C 1. PRODUCT SPECIFICATIONS, GASOLINE
Cluster model
Premium
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
East of Rockies Grassroots
West of Rockies Grassroots
Regular
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
East of Rockies Grassroots
West of Rockies Grassroots
Unleaded
Louisiana Gulf
Texas Gulf
All Others
Maximum Reid
vapor pressure
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
10.5
% Evaporated at 150°F
Minimum Maximum
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
28.0
30.0
28.0
28.0
28.0
28.0
28.0
30.0
30.0
30.0
3C.C
30.0
30.0
30.0
32.0
30.0
% Evaporated at 21 0°F
Minimum Maximum
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
54.0
Minimum leaded
research octane
number
100.5
99.2
98.9
99.8
99.5
99.3
99.8
99.3
94.1
94.0
92.2
93.6
93.8
93.4
93.9
93.4
92.0
92.0
92.0
Minimum leaded
motor octane
number
92.5
92.6
94.0
92.2
92.0
90.2
92.7
90.2
86.1
86.2
86.1
86.6
86.8
84.5
86.4
84.5
84.0
84.0
84.0
o
I
-------
Other product specifications are presented in Table C-2. The basic
philosophy was to adopt only those key specifications necessary to measure
the impacts being evaluated in this study. For example, there are
approximately 20 different specifications on commercial jet fuel, each of
which is critical to satisfactory performance. Yet only several key ones
are required for use in an aggregate model of this type. It is only
meaningful to consider product specifications for which specific processing
adjustments are required which affect unit costs. Those specifications
that are met by segregated blending, while they require careful planning in
the individual refineries, are not relevant to this level of simulation.
For example, the smoke-point specification for jet fuel must be met
on all products supplied. However, in the East of Rockies system, there
are ample supplies of good quality blend stocks such that no special
processing or additives are needed. On the other hand, in the West Coast
one of the reasons for the widespread installation of hydrocracking is due
to the relatively high product demands for jet fuel and the relatively poor
smoke-point of product produced from indigenous crudes. Thus, we do
specify that the smoke-point requirement be met by the model for the West
Coast. Although no sulfur specification was used in the model for jet
fuel, the model is structured such that only desulfurized components can
be routed to jet fuel blending with the exception of the Louisiana cluster
model which processes low sulfur crudes.
The initial end-point distillation requirements for jet fuel (as well
as for other products) are met by the model structural control of
fractionating cut points, which allow only "specification" components to be
made available for blending.
Distillate fuel oil sulfur specifications vary from cluster model to
cluster model. They were adjusted during the calibration phase to achieve
a reasonable utilization of existing desulfurization facilities and the
specifications thus determined were then used for the simulation at future
years. Diesel fuels are included in the general distillate fuel category.
Although they require various cetane number specifications in the market-
place, they are met by blending and thus need not -be considered in this
analysis.
C-3
-------
Table C-2. OTHER PRODUCT SPECIFICATIONS
Cluster Model
Jet fuel
West Coast and West of Rockies Grass Roots
All others
Kerosene
All clusters
Distillate fuel oil
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
East of Rockies Grass Roots
West of Rockies Grass Roots
Residual fuel oil
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
East of Rockies Grass Roots
Scenario A
Scenario C
Scenario D
Scenario E
Scenario F
West of Rockies Grass Roots
Scenario A
Scenario C
Scenario D
Scenario E
Scenario F
Minimum specific
gravity
0.797
0.797
0.797
Maximum sulfur
level - % wt
'
0.1
0.1
0.2
0.2
0.1
0.17
0.14
0.1
0.1
2.0
1.5
1.5
1.5
1.5
1.0
1.78
1.97
2.45
2.40
2.12
1.47
1.63
1.38
1.38
1.16
Minimum smoke
point mm
20X)
Viscosity - Refutas @ 122°F
Minimum Maximum
_ .
28.0
28.0
28.0
24.0
28.0
28.0
28.0
28.0
28.0
28.0
28.0'
28.0
28.0
28.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
37.0
n
-------
A similar philosophy was used for residual fuel oil, the critical
specifications for which are presented in Table C-2. The variability
in sulfur content reflects the sulfur content of products from each
2 3
geographical area, ' as discussed in Volume I, Section II.
The sulfur content of the refinery fuel oil system is discussed in
detail in Appendix D.
C-5
-------
References
1. U.S. Motor Gasoline Economics, Volume 1, Manufacture of Unleaded
Gasoline, American Petroleum Institute, 1967.
2. U.S. Dept. of Interior, Bureau of Mines, Petroleum Products Survey,
Burner Fuel Oils (1974).
3. U.S. Dept. of Interior, Bureau of Mines, "Availability of Heavy Fuel
Oils by Sulfur Level", December (1973).
C-6
-------
APPENDIX D
BASE LEVEL OF CLUSTER REFINERY FUEL SULFUR CONTENT
-------
TABLE OF CONTENTS
APPENDIX D - BASE LEVEL OF CLUSTER REFINERY FUEL SULFUR CONTENT
Page
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
LIST OF TABLES
TABLE D-l. Refinery Fuel Sulfur Regulations by State D-4
TABLE D-2. Refinery Fuel Sulfur Regulations by PAD D-5
TABLE D-3. Refinery Fuel Sulfur Regulations Applicable to
Individual Refineries in Cluster Models D-7
TABLE D-4. Base Level of Cluster Refinery Fuel
Sulfur Content Used in Model Runs D-9
-------
APPENDIX D
BASE LEVEL OF CLUSTER REFINERY FUEL SULFUR CONTENT
U.S. refinery fuel sulfur oxide (SO ) emission levels are currently
X
controlled primarily by state regulations on fuel sulfur content or on
ground level concentrations of sulfur dioxide (SO-). Since the control
of refinery fuel SO emissions will place an important constraint on the
X
modeling of the refinery operations, the allowable refinery fuel sulfur
content under current or immediately anticipated regulations"had to be de-
termined for each cluster model. This is complicated by the regional
modeling approach since emission regulations are typically established on a
state-by-state basis. This appendix describes the methodology used in
calculating emission regulations for each cluster model, beginning with the
determination of state regulations and then translating these into equiva-
lent cluster regulations.
Specific regulations on sulfur content of fuels were promulgated not as
a means of controling fuel sulfur content itself but as one of the control
techniques for the ambient air quality standards on SO . Thus, not all states
X
have established explicit standards on fuel sulfur content. While the Federal
government has promulgated the National Ambient Air Quality Standards (NAAQS)
for SO , these regulations represent minimum standards to be achieved. As a
X
result, air quality regulations and, indirectly, fuel sulfur regulations,
vary from state to state and often within a state. Since actual implementa-
tion of NAAQS is the responsibility of state governments, the means by which
regulations are expressed also varies between and within states. For ex-
ample, some states regulate SO emissions by determining the maximum allow-
X
able fuel sulfur content for achievement of the particular SO standards,
while other S5tates express standards only in terms of ambient air or ground
level SO^ concentrations. In the latter case, allowable S0_ concentrations
D-l
-------
at the stack have to be determined by dispersion models reflecting local
meteorological conditions. For consistent use in the ADL refinery model,
this stack concentration was then translated into an equivalent refinery
fuel sulfur content, and, in some cases, it was necessary to contact re-
finers or EPA regional offices where these calculations were available.
A final complicating factor is that these regulations also vary accord-
ing to the size of the combustion units. This made it necessary to identify
the location of refineries within each state and to make simplifying assump-
tions about the size of refinery combustion units.
A. METHODOLOGY OF CALCULATIONS
1. Fuel Oil Sulfur Content by State
The National Sumnary of State Implementation Plan Reviews (Volume II),
published in July, 1975, by the EPA, was used as the primary source of state
regulations on fuel sulfur levels. For those states with fuel sulfur
regulations varying by Air Quality Control Region (AQCR), each refinery
in that state was identified as to its location in an AQCR. The state
regulation was then calculated as the average sulfur regulation of the
AQCR's containing refineries, weighted by 1973 crude refining capacity of
each AQCR.
Reasonable assumptions were required for those states that did not
have explicit fuel oil sulfur regulations. In Texas, the ground level SO
concentration regulation may require a maximum liquid fuel sulfur content
of 0.7-0.9% wt. for compliance, according to one refiner's modeling of
operations. Similarly, in California, the ground level S0« concentration
translates into fuel sulfur limits of 0.5% wt. Although Louisiana has
promulgated a maximum fuel sulfur level of 3.6% wt., ground level concen-.
tration standards are, in fact, controling and refiners in some AQCR's
limit fuel burned to 0.7-0.9% wt. S. Current regulations in Ohio and
Illinois are uncertain at present and, after consultation with local AQCR
authorities, were assumed to be 1.0% wt. S.
2. Combustion Unit Size
State regulations for existing and new sources are reported in the
above publication by size of combustion unit (heat inputs of 10, 100, 250,
or 1000 million Btu/hour), by type of fuel burned, and by air quality
D-2
-------
control region. Regulations applicable to refineries were taken as those
pertaining to residual fuel-fired units with heat inputs of less than 1000
million Btu/hour. Where they differed among the 10, 100 and 250 million
Btu/hour units, an arithmetic average of the three was used. If the reg-
ulations were explicit only for a 1000 million Btu/hour unit, this was
assumed to apply.
B. RESULTS
Table D-l shows existing and new source fuel sulfur regulations by state
which were calculated using the above methodology.
Refinery fuel sulfur level standards by Petroleum Administration for
Defense (PAD) districts were then calculated as the weighted average of state
regulations comprising each PAD, with crude throughput of each state used
as weighting factors. Refinery crude throughput by state is available in the
Bureau of Mines 1973 Annual Petroleum Statement. However, for some PAD
districts, crude throughput for several states is reported together; where
this occurred a weighted average sulfur standard for those states was de-
termined using 1973 state refining capacities as weighting factors.
Table D-2 shows calculated PAD regulations for existing and new sources.
Also shown is the state within each PAD with the most and least stringent
sulfur regulation. Those states or portions of states for which sulfur
standards could not be determined (Western Pennsylvania, Missouri, Oklahoma
for existing sources, and Arkansas) were eliminated from the determination
of weighted average PAD regulations.
As discussed in Appendix F, specific clusters of refineries were
selected to represent typical refineries in each PAD district, to be scaled
up to represent the U.S. petroleum industry. For comparison to the average
Sulfur standards applying to 1000 million Btu/hr heat input units are
more applicable to large steam generating units such as electric utilities,
In.addition, Federal New Source Performance Standards (NSPS) technically
apply only to fossil-fuel fired steam generators with heat inputs greater
than 250 million Btu/hr. The occasional use of these standards for de-
termining regulations pertaining to refineries was necessitated by lack
of suitable alternative information, but it is felt the resulting cluster
regulation is nevertheless representative.
D-3
-------
Table D-1. REFINERY FUEL SULFUR REGULATIONS BY STATE
PAD
1
II
III
V
State
New Jersey
Delaware, Maryland
Virginia, Georgia, Florida
New York
Pennsylvania-East
West Virginia
Total .
Ohio
Indiana
Illinois
Kentucky, Tennessee
Michigan
Minnesota, Wisconsin
N. Dakota
Oklahoma
Kansas
Total
Texas
Louisiana
Mississippi
Alabama
New Mexico
Total
California
Other States3
Total
1973 Refinery crude
throughput (MB/D)
596.885
128.301
.57.764
100.496
543.641
13.718
1,440.805
500.315
491.614
1,031.118
175.148
122.885
193.252
49.101
447.162
373.266
3,383.861
3,209.112
1,462.088
256.033
31.559
46.389
5,005.181
1,577.197
398.173
1,975.370
a. PAD V "Other States:"
Washington
Oregon
Arizona
Alaska
Hawaii
Calculated regulation - % wt. S
Existing source
0.3
0.93
2.45
2.2
0.3
2.7
1.0
3.63
1.0
2.05
1.16
1.83
2.7
b
2.8
0.9
0.9
2.2
2.54
0.9
0.5
1.88
2.14
1.4
0.9
0.5
2.0
New source
0.3
0.93
2.44
2.2
0.3
2.0
1.0
3.63
1.0
1.60
1.16
1.83
2.7
0.3
0.7
0.7
0.7
2.2
2.54
0.9
0.5
1.87
2.14
1.4
0.7
0.5
2.0
b. Various maximum ambient concentration limits.
D-4
-------
Table D-2. REFINERY FUEL SULFUR REGULATIONS BY PAD
PAD
1
II
III
V
Existing sources % wt. S
Most
restrictive (state)
0.3 (New Jersey)
(Pennsylvania)
1.0 (Ohio)
(Illinois)
0.9 (Texas)
(Louisiana)
(New Mexico)
0.5 (California)
(Alaska)
Least
restrictive (state)
2.83 (Georgia)
3.63 (Indiana)
2.54 (Alabama)
2.14 (Washington)
PAD weighted
average
0.60
1.82
0.98
0.78
New sources % wt. S
Most
restrictive (state)
0.3 (New Jersey)
(Pennsylvania)
0.3 (Oklahoma)
0.7 (Texas)
(Louisiana)
0.5 (California)
(Alaska)
Least
restrictive (state)
2.83 (Georgia)
3.63 (Indiana)
2.54 (Alabama)
2.14 (Washington)
PAD weighted
average
0.59
1.37
0.79
0.78
-------
PAD fuel sulfur regulations of Table D-2, the regulations applicable to
each of the individual refineries in the clusters are shown in Table D-3.
Because of the AQCR's in which these particular refineries are located, the
regulations for these refineries are generally more restrictive than the
average regulations for the PAD district as a whole.
C. CLUSTER MODEL REFINERY FUEL SPECIFICATION
From Tables D-l, D-2 and D-3, the existing fuel sulfur regulations
(to be applied to the sulfur level of the refinery fuel system) for the
cluster models must be selected. As noted above, however, there is a
conflict between the regulations pertaining to the specific refineries
simulated in the cluster models and the average of the PAD district. This
makes the selection of representative refinery fuel sulfur regulations
difficult.
On the one hand, if the stringent regulations typical of the specific
cluster refineries (Table D-3) are selected to represent the existing
maximum refinery fuel sulfur levels in the cluster models, then the computer
simulation would indicate that little additional investment would be re-
quired to meet future regulations. Since the average PAD district fuel
sulfur regulation (Table D-2) is much higher than these most stringent
regulations, it is likely that the cost of future sulfur regulations de-
termined by such computer models would understate the actual costs incurred
by the industry.
On the other hand', . if existing maximum sulfur levels of the refinery
fuel system were selected equal to the average PAD district regulations
(Table D-2), then the sulfur balances in the cluster models will not match
those of the actual refineries being simulated (Appendix F), for these
refineries .are operated to match the regulations of Table D-3. For some
clusters, such as the Texas Gulf Coast, there was such a small fraction of
residual oil in the fuel system in 1973 that this inconsistency is unimpor-
tant. For the East Coast cluster, however, the inconsistency is significant
(compare Table D-2 and D-3). ' '
Since it is felt that understatement of the cost of future regulations
is a far more serious error when the industry model is to provide input to
environmental policy decisions, the current cluster model fuel regulations
D-6
-------
Table D-3. REFINERY FUEL SULFUR REGULATIONS APPLICABLE
TO INDIVIDUAL REFINERIES IN CLUSTER MODELS
Cluster
East Coast
Small
Midcontinent
Large Midwest
Texas Gulf
Louisiana Gulf
West Coast
Refinery and location
ARCO-Philadelphia, Pa.
Sun-Marcus Hook, Pa.
Exxon-Linden, N.J.
Skelly-EI Dorado, Kansas
Gulf-Toledo, Ohio
Champlin-Enid, Oklahoma
Mobil-Joliet, III.
Union- Lemont, III.
ARCO-E. Chicago, III.
Exxon-Baytown, Texas
Gulf-Pt. Arthur, Texas
Mobil-Beaumont, Texas
Gulf-Alliance, La.
Shell-Norco, La.
Citgo-Lake Charles, La.
Mobil-Torrance, Ca.
Arco-Carson, Ca.
Socal-EI Segundo, Ca.
Fuel regulations % wt. S
Existing source
0.3
0.3
0.3
2.8
1.0
a
1.0
1.0
1.0
0.9
0.9
0.9
0.9
0.9
0.9
0.5
0.5
0.5
New source
0.3
0.3
0.3
0.7
1.0
0.3
1.0
1.0
1.0
0.7
0.7
0.7
0.7
0.7
0.7
0.5
0.5
0.5
a. Various maximum ambient concentration limits.
n-7
-------
were assumed to be those of the PAD district and not of the refineries
simulated by the cluster model. The allowable refinery fuel sulfur content
assumed in the cluster models is summarized in Table D-4. The East Coast
cluster entry is taken as the PAD I regulation of Table D-2. The Small
Midcontinent and Large Midwest entries were taken as the average PAD II
regulation for existing and new sources of Table D-2 (recall the uncertainty
for the Ohio and Illinois entries of Table D-l, making more precise assess-
ments unwarranted). The Texas and Louisiana entries were taken directly
from Table D-l, and agree well with Table D-2. The West Coast cluster entry
is near that of Table D-2, weighted downward by the California entry of
Table D-l.
Furthermore, since most existing refineries must meet these regulations
on a stack-by-stack basis (not averaged over total gaseous and liquid fuel
systems), these sulfur specifications were used to limit the sulfur level
of the liquid fuel system (e.g., residual fuel oil) in the existing cluster
refineries. For the grassroots refineries, which would likely have one
large stack, these sulfur specifications were applied to the average sulfur
levels of liquid and..gaseous fuels.
D-8
-------
Table D-4. BASE LEVEL OF CLUSTER REFINERY FUEL
SULFUR CONTENT USED IN MODEL RUNS
Refinery cluster
East Coast
Small Midcontinent
Large Midwest
Texas Gulf
Louisiana Gulf
West Coast
Maximum allowable sulfur level
in refinery fuel system, wt. %
0.6
1.5
1.5
0.9
0.9
0.7
I) 9
-------
APPENDIX E
CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY
UPGRADING AND UTILIZATION OF CAPACITY ALREADY CONSTRUCTED
-------
TABLE OF CONTENTS
APPENDIX E - CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY
IIP GRADING AND UTILIZATION OF CAPACITY ALREADY CONSTRUCTED
Page
A. CATALYTIC REFORMING E-2
B. HYDROCRACKING E-8
C. ALKYLATION E-16
D. ISOMERIZATION E-19
LIST OF JTABLES^
TABLE E-l. Catalytic Reforming Capacity Availability -. . . E-4
TABLE E-2. Catalytic Reformer Investment for Capacity
Utilization and Severity Upgrading E-6
TABLE E-3. Costs of Additional Reformer Capacity E-7
TABLE E-4. Cost of Severity Upgrading E-9
TABLE E-5. Hydrocracking Capacity Availability E-ll
TABLE E-6. Hydrocracking Investment for Capacity Utilization,
New Capacity, and Severity Flexibility E-12
TABLE E-7. Costs of Additional Hydrocracking Capacity E-13
TABLE E-8. Cost of Hydrocracker Severity Flexibility E-15
TABLE E-9. Alkylation and Isomerization Capacity Availability .. E-17
TABLE E-10. Utilization of Existing Alkylation Capacity E-18
TABLE E-ll. Isomerization Investment for Capacity Utilization
and Once Through Upgrading E-20
TABLE E-12. Costs of Additional Isomerization Capacity E-21
TABLE E-13. Cost of Once Through Isomerization Upgrading : E-23
-------
APPENDIX E
CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY UPGRADING
MD UTILIZATION OF CAPACITY ALREADY CONSTRUCTED
In order to meet the environmental regulations under study, it is
often required to utilize existing process unit capacity or to upgrade the
process unit severity beyond that required without the proposed regulation.
Hence, in the evaluation of investment penalties associated with the regu-
lations, costs must be assessed for (1) the value of the existing facilities
which have been utilized and (2) the added expense of upgrading these
facilities to meet these regulations.
For example, for the lead regulations, existing catalytic reformer
capacity must be utilized to make increasing amounts of unleaded and
low lead gasolines. This capacity could be otherwise utilized to produce
increasing quantities of leaded gasoline were it not for the lead regula-
tions. Hence, a value must be placed on this excess reformer capacity, and
a cost assessed due to lead removal if the capacity utilization exceeds the
case without the lead regulations. This cost assessment for existing
facilities is well-known in economic theory, and the value of such facili-
ties is obtained from an evaluation of their "opportunity cost" or
"alternative value".
The production of unleaded gasoline will require that existing re-
formers be operated at 100 RON severity, even though the existing re-
formers may have been designed to operate only at 90 RON severity. Hence,
a capital outlay may be required to upgrade the severity capability of such
reformers to 100 RON.
The present appendix provides the methodology used in assessing the
capital investment penalties for existing capacity utilization and severity
upgrading, as well as the results of this calculation for the example
E-l
-------
clusters of existing refineries. Additional costs of promulgated lead
regulations and other possible regulations are incurred in new grassroots
refineries, which are summarized in Appendices H and J. Finally, the
investments required in these individual clusters are multiplied by scale
up factors (Appendix G) to reflect the industry-wide costs, the results of
which are tabulated in Appendix J.
From an examination of the unit throughput/severity results of
Appendix J, only four refinery units vary sufficiently to warrant invest-
ment evaluations for capacity utilization and severity upgrading. These
are catalytic reforming, hydrocracking, isomerization and alkylation.
Other units, such as fluid catalytic cracking, did not undergo sufficient
change in unit intake or severity between scenarios to jus :ify such
calculations.
A. CATALYTIC REFORMING
Calibration runs for each of the clusters were performed, as discussed
in Appendix I, comparing the reformer throughput required by the cluster
model with that obtained from industry data. Also summarized in Appendix
I was the comparison of these figures with the stream-day capacity reported
in the Oil and Gas Journal.
In Table E-l are summarized the results of this comparison for each
cluster. The model output provided the catalytic reformer intake of high
severity (>95 RON) and low severity (< 95 RON) operation required to meet
pool octane for each cluster (Appendix I). It also provided the BTX
reformer throughout required to meet the 1973 demand for BTX from each
cluster.
The existing reformer calendar day capacity in Table E-l was obtained
by multiplying the Oil and Gas Journal stream day capacity (Appendix I)
by 85%. This figure represents limitations such as:
Scheduled or extraordinary refinery turnarounds and maintenance.
Limitations on secondary processing capacity which can limit
meeting product specifications.
Variations in crude slates since nominal capacity is based on a
design crude and would be higher or lower depending on the gravity
E-2
-------
of the actual crude run.
Forced outages due to fires or strikes.
Crude supply restrictions, particularly those refineries tied to
local crudes.
Regional and logistical constraints.
Imbalances between individual product output and market demand.
Discussions with industry sources indicated that about three-fourths
of total reforming capacity is capable of only low severity operation (high
pressure units). The BTX capacity is conservatively taken to be equal to
that of the 1973 calibration run, with the remaining capacity available
for motor gasoline production. Hence, for the East Coast, Large Midwest
and Louisiana Gulf clusters, the existing low severity capacity available
was calculated as three-fourths of total reforming capacity, and total high
severity capacity was obtained by difference. High severity capacity
available for gasoline production in these three clusters was determined
as total high severity capacity less 1973 BTX capacity. Applying this same
methodology to the Small Midcontinent, Texas Gulf, and West Coast clusters
would result in total high severity capacity less than that required for
BTX production. Therefore, for these clusters it was assumed that no high
severity capacity existed for gasoline production. If total calibration
throughput requirements exceeded the adjusted Oil and Gas Journal capacity,
the former figure was taken as the capacity limitation.
It is recognized that the zero high severity capacity for motor
gasoline production indicated in Table E-l is not true in reality. However,
the assumptions about the amount of existing high and low severity capacity
affect only the assignment of penalties to severity upgrading versus utili-
zation of existing capacity. Total capital requirements are not affected,
so no further refinement of high severity capacity availability was under-
taken.
Next, 'the cost of upgrading the catalytic reformer severity and the
value of existing facilities had to be assessed. After discussions with
process licensors, it was determined that the cost of upgrading a catalytic
reformer to be capable of 100 RON operation (furnace costs and pressure
E-3
-------
Table E-1. CATALYTIC REFORMING CAPACITY AVAILABILITY
(MB/CD)
1973 Calibration throughput
High severity mogas
Low severity mogas
BTX
Spare capacity
Subtotal
Existing capacity, 1973
High severity mogas
Low severity mogas
BTX
Subtotal
Cluster model
East
Coast
7.0
29.0
3.5
2.4
41.9
7.0
31.4
3.5
41.9
Large
Midwest
0
25.3
2.3
0.2
27.8
4.6
20.9
2.3
27.8
Small
Midcont
0
10.2
4.3
0
14.5
0
8.9
4.3
13.2
Louisiana
Gulf
0
28.3
0
6.1
34.4
8.6
25.8
0
34.4
Texas
Gulf
0
50.4
20.3
0
70.7
0
49.7
20.3
70.0
West
Coast
0
21.0
16.3
0
37.3
0
20.5
16.3
36.8
m
i
-------
alteration) would approximate that of the initial investment of the low
severity unit. This investment will certainly vary from site-to-site;
hence, this upgrading cost is assumed to be equivalent, but all investment
penalties will be reported with this item explicitly identified so that it
may be adjusted easily if improved cost data becomes available. Note,
however, that only 75% of the units potentially need upgrading.
The value of the existing facilities, to be used in the assessment
of the cost of utilization of existing capacity, is more difficult to
identify, since it depends upon the value of alternate use of these
facilities. Fortunately, the total investment penalty is not heavily
dependent upon the value placed on these existing facilities. If the value
is taken equal to cost of installation of a low severity unit, the cost of
utilization is only 7% of the severity upgrading cost for catalytic reform-
ing.
The investment penalties for each of these items is summarized in
Table E-2, along with the cost of installation of new, low-pressure
reformers for comparison.
An example calculation of the cost of capacity utilization for the Large
Midwest cluster is shown in Table E-3, for Scenarios A and C. The reformer
tnroughput required to meet the gasoline demand and the quality specifications
is obtained from the computer output (Appendix J). For Scenario A, few
changes take place between 1977 and 1985; for Scenario C, the amount of
high-severity reforming increases due to lead regulations, and the total
reforming capacity increases due to yield losses. As noted in Table E-3,
subtracting the throughput of the prior time period from the throughput
requirement allows a break-down between spare capacity utilization and new
reformer capacity requirements. After adjusting the stream day investments
of Table E-2 to a calendar day basis, the total capacity-related costs can
be determined. Note that the cost of spare capacity utilitization is quite
low, making the precise "opportunity cost" assessed for this utilization
immaterial.
The cumulative onsite cost for Scenario C is $3.37 million for this
cluster, while that for Scenario A is $1.40 million. The penalty for lead
regulations is thus $1.97 million. This penalty was further increased by
E-5
-------
Table E-2. CATALYTIC REFORMER INVESTMENT FOR CAPACITY
UTILIZATION AND SEVERITY UPGRADING
Existing capacity value
Severity upgrading cost
New capacity cost
Small Midcontinent cluster
Standard unit,
MB/SD
10
10
10
Investment,
S/B/SD
1,135
1,135
1,450
All other clusters
Standard unit,
MB/SD
25
25
25
Investment,
$/B/SD
655
655
760
E-6
-------
m
i
Table E-3. COSTS OF ADDITIONAL REFORMER CAPACITY
Large Midwest Cluster
Reformer throughput required (MB/CD)
High severity
Low severity
Subtotal
Less existing thruput (MB/CD)
Subtotal (MB/CD)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Cost of spare capacity0 ($MM)
Cost of new capacityd ($MM)
Total capacity cost ($MM)
Cumulative total capacity cost ($MM)
Scenario A
1977
4.4
20.7
25.1
25.3a
0
-
0
0
0
0
0
1980
3.7
20.8
24.5
25.3a
0
-
0
0
0
0
0
1985
3.9
23.0
26.9
25.3a
1.6
0.2
1.4
0.15
1.25
1.40
1.40
Scenario C
1977
17.7
9.6
27.3
25.3a
2.0
0.2
1.8
0.15
1.61
1.76
1.76
1980
26.7
0
26.7
27.3b
0
0
0
0
0
1.76
1985
29.1
0
29.1
27.3b
1.8
0
1.8
0
1.61
1.61
3.37
1973 calibration thruput. Table E-1
Total capacity available after 1977
cThruputx (655/0.85)
dThruput x (760/0.85)
-------
40% to allow for offsite costs and working capital, leading to $2.76 million.
It should be noted that the investment penalties indicated in Appendix J of
"The Impact of Lead Additive Regulations On The Petroleum Refining Industry,
Volume II" were calculated on a Scenario B versus Scenario A, and Scenario
C versus Scenario B basis. The Scenario C versus A comparison in this
appendix is intended only for illustrative purposes. Furthermore, in
Appendix J, investments for individual units are reported for onsite costs
only, prior to adjustment to a calendar-day basis. The sum of unit onsite
costs is first increased by 40% to allow for offsite costs and working
capital and then adjusted for stream day investments.
An example calculation of the cost of severity upgrading for the Large
Midwest cluster is shown in Table E-4 for Scenarios A and C. The high
severity reformer throughput required to meet gasoline demand and quality
specifications is identical to that shown in Table E-3. The high severity
capacity available was reported in Table E-l for 1973. Subtraction of the
capacity from the throughput requirements and allowing for new high severity
capacity constructed from Table E-3 provides the anount of severity up-
grading required. After correcting the stream day investments of Table E-2
to a calendar day basis, the cost of severity upgrading can be determined.
The cumulative on-site cost for severity upgrading in Scenario C
becomes $16.11 million for the Large Midwest cluster. Subtracting the
upgrading cost for Scenario A (zero in this case) , the penalty for lead
regulations becomes $16.1 million. Increasing this cost by 40% to allow
for offsites and working capital, the total penalty for severity upgrading
becomes $22.6 million.
Combining the results of Tables E-3 and E-4, the total reformer related
capital investment penalty for Scenario C versus Scenario A becomes $25.4
million. To obtain the contribution of the Large Mic'west cluster to the
U.S. refining industry requires further multiplication of this penalty by
the scale-up factor of Appendix G.
B. HYDROCRACKING .
The methodology used to assess investment costs for utilization of
spare capacity and alterations in severity of operations for hydrocracking
is similar to that used for reforming. Again, calibration results indicated
E-8
-------
I
o
Table E-4. COST OF SEVERITY UPGRADING
Large Midwest Cluster
High severity reformer thruput required (MB/CD)
Less high severity capacity available (MB/CD)
Subtotal
Less new capacity construction (MB/CD)
Severity upgrading required (MB/CD)
Cost of severity upgrading f ($MM)
Cumulative cost of severity upgrading ($MM)
Scenario A
1977
4.4
4.6a
0
0
0
0
0
1980
3.7
4.6a
0
0
0
0
0
1985
3.9
4.6a
0
0
0
0
0
Scenario C
1977
17.7
4.6a
13.1
1.8d
11.3
8.71
8.71
1980
26.7
17.7b
9.0
0
9.0
6.94
15.65
1985
29.1
26.7C
2.4
1.8e
0.6
0.46
16.11
1973 Existing capacity (Table E-1)
Total capacity available after 1977
cTotal capacity available after 1980
New capacity built in 1977 (Table E-3)
eNew capacity built in 1985 (Table E-3)
fThruput x (655/0.85)
-------
the hydrocracking capacity and severity required to meet 1973 product
demands and specifications. Table E-5 shows the results taken from computer
outputs of calibration runs. All clusters except the Large Midwest and
Small Midcontinent contained hydrocracker units in 1973. For the
Louisiana Gulf and West Coast clusters, calibration hydrocracker utilization
was at medium severity only, while the Texas Gulf'cluster ran at high
severity and the East Coast cluster required both.high and medium severity
operations. The existing capacity shown in Table E-5 is the Oil and Gas
Journal stream day capacity (Appendix I) multiplied by 85%. Because
published information does not provide a breakdown of existing hydrocracking
capacity by level of severity, it was assumed for purposes of calculating
investment penalties that actual 1973 hydrocracking severities paralleled
the results obtained in calibration. Hence, for example, .he existing
18.1 MB/CD hydrocrac1. ing capacity for the Texas Gulf cluster was assumed
to be designed for high severity operations since calibration results in-
dicated a requirement of 14.7 MB/CD high severity hydrocracking in order to
meet the 1973 product demand slate. Table E-5 also shows spare capacity
available as the difference between total existing capacity in 1973 and
total calibration throughput.
As discussed in the preceeding section on catalytic reforming, an
implicit opportunity cost for utilization of spare capacity specifically
for meeting promulgated or potential EPA regulations trust be incorporated
in addition to explicit investment costs for new capacity and for severity
changes. The charge for existing capacity has been taken as the investment
cost required for new capacity. The cost of changing severity levels, which
is 20% of new grassroots investment, represents alterations to provide the
flexibility to vary severity of operations as required to meet product
demand. Table E-6 shows the investment penalties associated with utili-
zation of spare capacity (i.e., investment costs for new hydrocracking
capacity of high and medium severity) and severity flexibility.
A calculation of investment penalties for capacity utilization in the
Texas Gulf cluster for Scenarios A and C is provided in Table E-7. Tn
this example, the cost for utilization of existing capacity is the $1270/B
stream-day investment for high severity hydrocracking (Table E-6), adjusted
to a calendar day basis, since all existing capacity in the Texas Gulf
E-10
-------
Table E-5. HYDROCRACKING CAPACITY AVAILABILITY
(MB/CD)
1973 Calibration throughput
High severity
Medium severity
Total
Existing capacity, 1973
High severity
Medium severity
Total
Spare capacity available
Cluster model
East
Coast
6.2
1.3
7.5
7.2
1.3
8.5
1.0
Large
Midwest
-
-
:
-
-
Small
Midcontinent
-
-
:
-
-
Louisiana
Gulf
6.6
6.6
8.1
8.1
1.5
Texas
Gulf
14.7
14.7
18.1
18.1
3.4
West
Coast
22.1
22.1
23.6
23.6
1.5
-------
Table E-6. HYDROCRACKING INVESTMENT FOR CAPACITY UTILIZATION,
NEW CAPACITY, AND SEVERITY FLEXIBILITY
Existing and new capacity cost
High severity
Medium severity
Cost of severity flexibility
Standard unit, MB/SD
30
30
30
Investment, '$/B/SD
1270
1090
240
E-12
-------
I
Lo
Table E-7. COSTS OF ADDITIONAL HYDROCRACKING CAPACITY
Texas Gulf Cluster
Hydrocracker throughput required (MB/CD)
High severity
Medium severity
Subtotal
Less existing throughput (MB/CD)
. Subtotal (MB/CD)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Cost of spare capacity0 ($MM)
Cost of new capacity d ($MM)
Total capacity cost ($MM)
Cumulative total capacity cost ($MM)
Scenario A
1977
13.2
6.3
19.5
14.7a
4.8
3.4
1.4
5.08
1.80
6.88
6.88
1980
19.0
0.3
19.3
19.5b
0
0
-
0
0
0
6.88
1985
13.4
14.7
28.1
19.5b
8.6
0
8.6
0
1 1 .03
11.03
17.91
Scenario C
1977
5.7
14.2
19.9
14.7a
5.2
3.4
1.8
5.08
2.31
7.39
7.39
1980
6.7
13.1
19.8
19.9b
0
0
- '
0
0
0
7.39
1985
3.1
17.5
20.6
19.9b
0.7
0
0.7
0
0.90
0.90
8.29
1973 Calibration throughput. Table E-5
Total capacity available after 1977
throughput x (1270/0.85)
throughput x (1090/0.85)
-------
cluster is at high severity (Table E-5). New capacity investment is that
for medium severity hydrocracking from Table E-6. In 1977, both scenarios
show capacity requirements that exceed the spare capacity available. Thus,
the penalty for Scenario C regulations is represented by the difference in
cost of new hydrocracker capacity of $0.51 million ($2.31 million for
Scenario C less $1.80 million for Scenario A). In 1980, required throughput
for both scenarios is slightly less than the total capacity available after
1977 and hence no penalty is incurred. By 1985, Scenario A required $11
million of new hydrocracker capacity versus less than $1 million for
Scenario C. Total cumulative onsite cost for Scenario A is $17.91 million
while that for Scenario C is $8.29 million, thus showing a net onsite
investment credit of $9.62 million for lead regulations. This credit is
increased by 40% to account for working capital and offsitf costs for a
total credit of $12.47 million.
Table E-8 provides an example of the calculation of penalties for
flexibility in hydrocracker operating severity for the Texas Gulf cluster,
Scenarios A and C. In 1977, Sceanrio A requires 6.3 MB/CD of hydrocracking
at medium severity as shown in Table E-7. Since exis-ting capacity is all
at high severity (see Table E-5), throughput requirements at medium
severity must be charged with the cost of alterations to provide severity
flexibility. New capacity construction of 1.4 MB/CD is subtracted from the
medium severity throughput required, as new grassroots investment is assumed
to be installed at the appropriate severity level. Additional severity
flexibility needed is thus 4.9 MB/CD. After 1977 medium severity capacity
available is the sum of new capacity construction and severity flexibility
provided in 1977.
Similarly, for Scenario C medium severity hydrocracker throughput
requirements are those reported in Table E-7, while capacity available is
that shown in Table E-5 for 1977 and the capacity installed or upgraded in
previous periods for 1980 and 1985. The cost of severity flexibility is
the stream day investment from Table E-6, adjusted to a calendar day basis.
Cumulative onsite costs for providing flexibility in hydrocracking
severity is $4.23 million in Scenario C cornpa rc-d to $1.38 million in
Scenario A. The cumulative onsite severity change penalty for lead
regulations in the Texas Gulf cluster is thus $2.85 million, which when
E-14
-------
n
i
Table E 8. COST OF HYDROCRACKER SEVERITY FLEXIBILITY
Texas Gulf Cluster
Medium severity hydroct acker throughput
required (MB/CD)
Less medium severity capacity available (MB/CD)
Total
Less new capacity construction (MB/CD)
Severity flexibility required (MB/CD)
Cost of severity flexibility6 ($MM)
Cumulative cost of severity flexibility ($MM)
1977
6.3
Oa
6.3
1.4C
4.9
1.38
1.38
Scenario A
1980
0.3
6.3b
0
0
0
0
1.38
1985
14.7
6.3b
8.4
8.6d
0
0
1.38
1977
14.2
a
14.2
1.8C
12.4
3.50
3.50
Scenario C
1980
13.1
14.2b
0
0
0
0
3.50
1985
17.5
14.2b
3.3
0.7d
2.6
0.73
4.23
a1973 Existing capacity, Table E-5
Total capacity available after 1977
GNew capacity built in 1977. Table E-7
New capacity built in 1985, Table E-7
eThroughput x (240/0.85)
-------
increased by 40% for working capital and offsite costs, results in a total
flexibility penalty of $3.99 million.
The total cumulative penalty or credit, including new capacity invest-
ment, the charge for utilization of existing capacity, and costs of provid-
ing severity flexibility, is obtained by adding the results of Tables E-7
and E-8. The result is a total hydrocracker investment credit of $9.5
million for lead regulations in the Texas Gulf cluster. The credit to the
total U.S. refining industry is found by multiplying this credit by the
appropriate scale-up factor in Appendix G.
C. ALKYLATION
Calibration results for utilization of alkylation capacity are compared
with existing calendar day capacity in the upper half of T..ble E-9. All but
the Louisiana Gulf ar.J West Coast clusters show calibration requirements
exceeding the calculated existing capacity. The penalty for utilization of
spare capacity has been taken as the investment cost for new alkylation
capacity as shown below:
Investment For
Standard Unit, MB/SD New Capacity, $/B/SD
Small Midcontinent Cluster 5 2250
All Other Clusters 10 1400
A sample calculation of investment penalties for utilization of exist-
ing alkylation capacity is shown for the Louisiana Gulf, Scenarios A and C,
in Table E-10; no new capacity is required in this case. Alkylation through
put required in Scenario A is less than existing calibration throughput for
all years and hence there is no cost for use of spare capacity. In 1980,
Scenario C requires 0.2 MB/CD of spare capacity which is charged at the
stream-day investment cost of $1400/8 given above and adjusted to a calendar
day basis. In 1985, Scenario C, existing throughput represents total capa-
city available after 1980. Spare capacity available for utilization in 1985
has been reduced by the spare capacity used (and hence charged 'off) in 1980.
.Since no new capacity is required in Scenario C, the cumulative spare capa-
city investment penalty of $.99 million represents total onsite penalties.
Including working capital and offsite costs at 40% of onsite investment, the
total alkylation-related penalty for lead regulations is $1.39 million for
E-16
-------
Table E-9. ALKYLATION AND ISOMERiZATION CAPACITY AVAILABILITY
(MB/CD)
Alkylation
1973 Calibration throughput
Existing capacity3
.Spare capacity available
Isomerization
1973 Calibration throughput
Existing capacity-once
through3
Spare capacity available
Cluster model
East
Coast
8.0
7.1
-
Large
Midwest
12.0
11.4
-
Small
Midcont.
4.9
4.5
_
1.5
1.5
Louisiana
Gulf
17.5
20.4
2.9
_
-
Texas
Gulf
17.8
17.7
2.0
2.0
West
Coast
5.5
6.6
1.1
_
-
a85% of Oil and Gas Journal stream day capacity
-------
Table E-10. UTILIZATION OF EXISTING ALKYLATION CAPACITY
Louisiana Gulf Cluster
rn
I
Alkylation throughput required (MB/CD)
Less existing throughput (MB/CD)
Subtotal (MB/CD)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Cost of spare capacityd ($MM)
Cumulative cost of spare capacity ($MM)
Scenario A
1977
16.9
17.5a
0
-
-
0
0
1980
16.9
17.5a
0
-
-
0
0
1985
16.6
17.5a
0
-
-
0
0
Scenario C
1977
17.4
17.5a
0
-
0
0
1980
17.7
17.5
0.2
2.9
0
0.33
0.33
1985
18.1
17.7b
0.4
2.7C
0
0.66
0.99
1973 Calibration throughput, Table E-9
Total capacity available after 1980
cSpare capacity available after 1980
throughput x (1400/0.85)
-------
the Louisiana Gulf cluster. This figure, multiplied by the appropriate
scale-up factor in Appendix G, is the contribution to the total penalty to
the U.S. refining industry represented by the Louisiana Gulf cluster.
D. ISOMERIZATION
As shown in the lower half of Table E-9, only two clustersthe Small
Midcontinent and the Texas Gulf clustershad existing isomerization capa-
city, although calibration results showed no isomerization throughput re-
quirements. Grassroots investment for recycle isomerization is twice the
cost of new once through capacity, as shown in Table E-ll. All existing
capacity is assumed to be once through. The investment for upgrading once
through to recycle isomerization and the charge for utilitzation of existing
capacity are both equal to initial investment for once through isomerization.
Table E-12 shows the calculation of investment penalties for utili-
zation of isomerization capacity for Scenarios A and C in the Texas Gulf
cluster. Scenario A did not require isomerization in any of the three years.
In 1977, Scenario C required 2.6 MB/CD of total isomerization capacity, thus
uf-n->'-7-ing all 2.0 MR/CD of spare capacity in this year. The cost of using
spare capacity is the $620/B stream day investment for use of existing once
through capacity from Table E-ll, multiplied by the 2.0 MB/CD throughput
and adjusted to a calendar day basis. The 0.6 MB/CD of new recycle
capacity is multiplied by the investment figure in Table E-ll for new
recycle capacity, for a cost of $.88 million. In 1980, the existing through-
put is that available after 1977 (2.6 MB/CD). Since all spare capacity
was utilized and charged in 1977, additional requirements must come from
construction of new capacity, which in this case is all recycle isomerization.
Scenario C in 1985 requires both new once through and new recycle capacity.
New once through capacity required is determined by subtracting the 0.3
MB/CD once through capacity in 1980 from the 7.0 MB/CD once through through-
put required in 1985. The cost of new once through isomerization, $4.89
million, is then found by multiplying the required new capacity (6.7
MB/CD) times the stream day investment cost for new once through isomeri-
zation given in Table E-ll and adjusted to a calendar day basis. The cost
for new recycle isomerization, $3.21 million, is calculated in a similar
manner.
E-19
-------
Table E-11. ISOMERIZATION INVESTMENT FOR CAPACITY-UTILIZATION
AND ONCE THROUGH UPGRADING
Existing and new capacity
once through
- recycle
Once through upgrading
Small Midcontinent cluster
Standard unit,
MB/SD
5
5
5
Investment
S/B/SD
1,000
2,000
1.000
All other clusters
Standard unit,
MB/SD
10
10
10
Investment
$/B/SD
620
1,240
620
E-20
-------
Table E-12. COSTS OF ADDITIONAL ISOMERIZATIOIM CAPACITY
Texas Gulf Cluster
m
i
''1973 Calibration throughput, Table E-9
Total capacity available after 1977
cTotal capacity available after 1980
dThroughput x (620/0.85)
eThroughput x (1240/0.85)
Isomerization throughput required (MB/CD)
once through
recycle
Subtotal
Less existing throughput (MB/CD)
Subtotal (MB/CD)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Total
- once through
recycle
Cost of spare capacity ($MM)
Cost of new capacity ($MM)
- once through
- recycle6
Total capacity cost ($MM)
Cumulative total capacity cost ($MM)
Scenario A
1977
0
0
0
oa
0
2.0
0
0
__
-
-
-
0
0
1980
0
0
0
oa
0
2.0
0
0
-
-
-
0
0
1985
0
0
0
oa
0
2.0
0
0
-
-
-
0
0
Scenario C
1977
0.3
2.3
2.6
Oa
2.6
2.0
0.6
-
0.6
1.46
-
0.88
2.34
2.34
1980
0.3
6.1
6.4
2.6b
3.8
-
3.8
-
3.8
-
-
5.54
5.54
7.88
1985
7.0
8.3
15.3
6.4C
8.9
-
8.9
6.7
2.2
-
4.89
3.21
8.10
15.98
-------
Cumulative onsite cost for use of existing isomerization capacity and
construction of new capacity for Scenario C versus A is $15.98 million.
Increasing this onsite investment by 40% for offsite costs and working
capital gives an isomerization penalty of $22.37 million for lead regulations
in the Texas Gulf cluster.
Investment penalties for upgrading once through to recycle isomerization
are given in Table E-13 for Scenarios A and C of the Texas Gulf cluster.
Scenario A did not use isomerization and thus has a cumulative cost of zero.
Recycle isomerization throughput required in Scenario C is taken from Table
E-12. Since existing capacity is assumed to be once through isomerization
only (Table E-9), there is no recycle capacity available in 1977. Total
throughput requirements of 2.3 MB/CD less 0.6 MB/CD new recycle capacity
built in 1977 show 1.7 MB/CD of once through isomerization that must be
upgraded. This figure is multiplied by the stream-day investment in Table
E-ll for once through upgrading and adjusted to a calendar day basis for a
cost of $1.24 million. No further once through upgrading is required in
1980 and 1985 so the cumulative onsite investment penalty for Scenario
C is $1.24 million. Including working capital and offsite costs at 40%
of onsite investment, the penalty for upgrading becomes $1.74 million.
Combining the results of additional capacity utilization from Table
E-12 and once through upgrading from Table E-13 gives a total isomerization
investment penalty for Scenario C versus A of $24.1 million. Multiplying
by the scale up factors of Appendix G gives the contribution to the U.S.
industry of the Texas Gulf cluster penalty.
E-22
-------
i
r-o
U)
Table E-13. COST OF ONCE THROUGH ISOMERIZATION UPGRADING
Texas Gulf Cluster
Recycle isomerization throughput required (MB/CD)
Less recycle capacity available (MB/CD)
Total
Less new recycle capacity construction (MB/CD)
Once through upgrading required (MB/CD)
Cost of once through upgrading9 ($MM)
Cumulative cost of upgrading ($MM)
1977
0
0
0
0
0
0
Scenario A
1980
0
0
0
0
0
0
1985
0
0
0
0
0
0
1977
2.3
Oa
2.3
0.6d
1.7
1.24
1.24
Scenario C
1980
6.1
2.3b
3.8
3.8e
0
0
1.24
1985
8.3
6.1C
2.2
2.2f
0
0
1.24
;'1973 Existing capacity. Table E-9
Total recycle capacity available after 1977
Total recycle capacity available after 1980
New capacity built in 1977, Table E-12
eNew capacity built in 1980, Table E-12
New capacity built in 1985, Table E-12
throughput x (620/0,85)
-------
APPENDIX F
DEVELOPMENT OF CLUSTER MODELS
-------
TABLE OF CONTENTS
APPENDIX F - DEVELOPMENT OF CLUSTER MODELS
Page
A. SELECTION OF CLUSTER MODELS F-2
B. COMPARISON OF CLUSTER MODEL TO PAD DISTRICT F-5
LIST OF TABLES
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-ll
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 I, 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
-------
APPENDIX F - (con't)
TABLE F-15. Comparison of Crude Input to West Coast
Cluster PAD District V, 1973 F-21
LIST OF FIGURES
FIGURE F-l. Geographic Regions Considered in Development
of Cluster Models F-3
ii
-------
APPENDIX F
DEVELOPMENT OF CLUSTER MODELS
The U.S. refining industry is composed of nearly 300 individual re-
fineries scattered throughout the country; each is characterized by a
unique capacity, processing configuration, and product distribution, often
varying significantly from refinery-to-refinery. In developing a refining
model for the industry, one could attempt to aggregate all these refineries
into a single composite refinery model. Of necessity, such an approach
would require averaging the U.S. crude slate, processing sequence and unit
size, and product distribution in this single refinery model. Furthermore,
since the entire industry is simulated as a single composite refinery, the
model would exhibit a higher degree of flexibility in processing configura-
tions and in selective crude/product blending options than the industry
could achieve in practice. For these reasons, the single composite re-
finery model was not used in these studies. On the other hand, it is
impractical to attempt a simulation of the U.S. refining industry by the
creation of nearly 300 individual computer models, one representing each
individual refinery.
Since there are logical regional groupings of major refineries with
similar crude supply patterns, processing configurations, and product
outputs, a cluster model approach was developed for this study. In this
approach, the existing U.S. refining industry was simulated by a relatively
small number of cluster refinery models. The results of these individual
cluster model studies were composited by using appropriate scale (or
weighting) factors to provide a representation of the U.S. refining industry.
To overcome the disadvantages of the single composite model approach,
it is necessary that each cluster model crude slate, processing configuration
and product outputs closely approximate the specific refineries which the cluster
F-.1
-------
model is intended to represent. As discussed below, this was achieved by select-
ing six geographic regions in the United States having refineries with
similar characteristics, and creating one cluster model .for each region.
Hence, a total of six cluster models was used as an appropriate balance be-
tween one single composite refiner}7 model and nearly 300 individual refinery
models.
Furthermore, it is important that each of these cluster refinery models
represent, as closely as possible, a realistic mode of operation of the
actual refineries being simulated. Specifically, processing units should be
of normal commercial size and the plants should be allowed normal flexibility
in regard to raw material selection and product mix.
Also, to allow verification of these objectives, each cluster model
should be calibrated rgainst historical operating data of the refinery being
simulated. Since operating data is confidential for any given refinery, it
was agreed that input/output data, energy consumptions, and plant operating
data be supplied from government and industry as an aggregate of three
specific refineries selected to comprise each cluster model. By using
three, it would be impossible to determine competitive proprietary data for
any single refinery.
The initial task in this program was the identification of the regions
used to represent the U.S. industry and the selection of the specific three
individual refineries which would .make up each cluster model. An ad hoc
industry task force comprised of API and NPRA representatives played a major
role in this effort.
A. SELECTION OF CLUSTER MODELS
The selection of the geographic regions to be simulated in the cluster
models required definition of several guidelines, sumirariz^d below.
PAD Districts I and V (Figure F-l) have sufficient crude capacity of
common characteristics that they can be simulated by one cluster model for
each district.
PAD District III, which represents about 40% of the U.S. total refining
capacity, was simulated by two models because of its overall importance and
because two types of refining configurations were identified. The Louisiana
r_2
-------
PETROLEUM ADMINISTRATION FOR DEFENSE (PAD) DISTRICTS
f -
(Incl. Alaska
and Hawaii)
( "£>.
I
/ CALIF \
BUREAU OF MINES REFINING DISTRICTS
TEXAS
GULF COAST
Source: Bureau of Mines.
Figure F-l. GEOGRAPHEC REGIONS CONSIDERED IN DEVELOPMENT OF CLUSTER MODELS,
F-3
-------
Gulf Coast district of Figure F-l (or about 1/3 of the total Gulf) can be
characterized by a single source sweet crude slate, a high percentage of
catalytic cracking, a low percentage of catalytic reforming, and product
outputs emphasizing both major energy products and specialties. The Texas
Gulf Coast district can be typified by higher sulfur and more varied crude
slates, less catalytic cracking, more reforming, and heavy involvement
in petrochemicals, lubes, and other specialty operations.
PAD District II, representing about 28% of domestic capacity, was also
characterized by two refineries. Although its total crude capacity is some-
what less than the Gulf, two separate models with quite distinct character-
istics could be identified to simulate the region. One was a large (100+
MB/CD) Midwest cluster model simulating the Indiana/Illino:?s/Kentucky
district and processing high sulfur crudes. The other was a moderate size
(50-100 MB/CD) cluster model simulating the Midcontinent (Oklahoma/Kansas/
Missouri) operation which is characterized by lower sulfur crudes and very
low production levels of residual products.
PAD District IV (Rocky Mountains, see Figure F-l) represented too
little refining capacity (<5% of total) to be included as a specific cluster
model.
A list of U.S. refineries was prepared representing refineries suitable
for the aggregation program outlined above. The final identification of
the specific refineries comprising each cluster was jointly agreed upon by
the contractor, EPA, and the ad hoc industry task force. The final selec-
tion is indicated below:
Texas Gulf (PAD III) Louisiana Gulf (PAD III)
Exxon - Baytown, Texas Gulf Oil - Alliance, LA
Gulf Oil - Port Arthur, Texas Shell Oil - Norco, LA
Mobil - Beaumont, Texas Cities Service - Lake Charles, LA
Small Midcontinent (PAD II) Large Midwest (PAD II)
Skelly - El Dorado, Kansas Mobil - Joliet, Illinois
Gulf Oil - Toledo, Ohio Union - Lemont, Illinois
Champlin - Enid, Oklahoma Arco - East Chicago, Illinois
F-4
-------
East Coast (PAD I) West Coast (PAD V)
Arco - Philadelphia, PA Mobil - Torrance, California
Sun Oil - Marcus Hook, PA Arco - Carson, California
Exxon - Linden, New Jersey Socal - El Segundo, California
B. COMPARISON OF -CLUSTER MODEL TO PAD DISTRICT
The major factor in the original selection of the three refineries com-
prising each cluster was the processing configuration. Tables F-l to F-6
provide detailed processing information for the three selected refineries in
each cluster for January 1, 1973, and January 1, 1974, as presented in the
Oil and Gas Journal annual refining surveys. Table F-7 compares the key
processing configuration for each cluster refinery to the corresponding PAD
total. In PAD III the Texas and Louisiana Gulf refineries bracket the PAD
average for coking and hydrocracking. They are slightly low on reforming
and high on catalytic cracking and alkylation. Since the clusters are in-
tended to represent large refiners that produce high yields of gasoline
rather than small specialty plants maximizing asphalt and/or lubes, this
is to be expected. In PAD II, the coking and catalytic reforming capacity
for the cluster models bracket the PAD average. Catalytic cracking is high
for this PAD region; however, since the cluster refineries contain no hydro-
cracking, the composite of cracking conversion operations checks well against
the PAD average.
In PAD I, the East Coast cluster contained no coking, although it did
possess a higher percentage of catalytic cracking and hydrocracking than the
PAD average. It was considered useful to have at least one cluster model
that did not contain coking, as this is characteristic of many U.S. plants.
The West Coast cluster refineries also exhibited slightly greater process
unit intakes than the PAD average with the exception of alkylation.
Once the specific refineries comprising each cluster were identified,
cluster input/output data for the year 1973 was requested from the Bureau
of Mines (BOM). This information was then tabulated and compared to the
average of the BOM data for the entire PAD district to determine if the
specific crude slates and product output patterns for the cluster refineries
were representative of the PAD average.
F-5
-------
Table F-1. TEXAS GULF CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity, B/CD
Vacuum dist.
Thermal
Visb.
-Fluid coke
Delayed coke
Other
Catalytic cracking
Catalytic reforming
Hydrocracking
- Dist.
Residual
- Lubes
Other
Hydro! ining
t ivy gas oil
F^esid. visb..
Cut teed & cycle
Pistillate
- Other '
Hyilrotreat
Rel orm feed
Naphtha
Olof/Arom sat
S H. Distill.
l.uhos
Other dist.
Othur
Alk vlrttion
Aiotn/lsom
h 1 X
- HDA
Cvclohox
C4 t-eed
C5 Feed
CS/C6 Feed
Llll»!S
Asphalt
Coko tons/day
Unit capacity,8 1974
Exxon
Bay town,
Texas
400,000
420,000
180,000
124,000
88,000
20,000 .
48,000
9O.OOO
15.OOO
41,000
109,000
a.sooc
26.0OO
1
2li,000
12,000
Gulf
Port Arthur,
Texas
312,100
319,000
147,400
30,000
1 20.0OO
65,000
15,000
65,000
65,000
1,200
13,900
20,000
2,700
2,500
7,200
13,200
1,390
Mobil
Beaumont,
Texas
325,000
335,000
103,000
33,000
95,000
94,000
297000
83,000
42.OOO
16,500
8,800
100
1,200
1974
Average
345,700
358,000
143.467
21,000
113,000
82,333
21,333
16,000
21,667
79,333
5,000
400
18.30O
50,333
2.833
20.833
900
833
2,400
15,667
4.033
863
Unit capacity,3 1973
Exxon
Baytown,
Texas
350,000
365,000
1 50,000
135,000
88,000
20,000
53,000
90,000
32,000
39,500
84.000
8.50C
26,000
25,000
12,000
Gulf
Port Arthur,
Texas
312,100
319,000
147,400
30,000
120.JOO
65,000
15,000
65.OOO
65,000
1.2OO
13,900
20.000
2,700
2,500
7,200
13,200
1,390
Mobil
Beaumont,
Texas
335,000
350,000
103.000
12,000
33,000
95,000
94,000
29,000
83,000
42,000
16.500
8,800
100
1.200
1973
Average
332,367
344,667
133,467
4,000
21,000
116,667
82,333
21,333
17.667
21.667
79,333
10,667
400
17,800
42,000
2,833
20,833
900
833
2,400
15.667
4,033
863
Unit capacity, 8'
1973/
1974
Average
339,034
351.333
138,467
2,000
21,000
114.834
82,333
21.333 "~
16,834
21,667
79.333
7,833
400
18,050
46,167
2.833
2O.833
. 900
833
2,400
15.667
4,033
863
%
Crude
39.4
0.6
- -
6.0
32.7
23.4
6.1
4.8
6.2
22.6
2.2
0.1
5.1
13.1
0.8
5.9
0.3
0.2
0.7
4.4
1.1
-
unless otherwise noted.
in dustui model.
Hcti'ienre: Oil and Gas Journal, April 2, 1973.
^11 and Gas Journal, April 1, 1974.
-------
Table F-2. LOUISIANA GULF CLUSTER PROCESSING CONFIGURATION
Unit type
Crudii capacity, B/CD
Vacuum di»t.
Thermal
- Visb.
Fluid coke
Delayed coke
Other
Catalytic cracking
Catalytic reforming
Hyclrocracking
-Gist.
Residual
-Lubes
Other
Hyclrofining
Residual
Hvy gas oil
- Resid. visb.
-Cat feed 81 cycle
Distillate
-Other
Hycliotreat
Reform li-ed
Nuphtha
Olef/Arom sat
S.R. Distill.
Lubes
Other dist.
Other
Alkylatlon
Aioni/lsom
BTX
-HDA
Cyclohex
-C4 Feed
C5 Feed
C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity.8 1974
Gulf
Alliance.
La.
180.400
186,000
55,000
16,000
78,000
37,500
16.000
22.0OO
41,000
28,400
11.100
5,400
840
Shell
Norco,
La.
240,000
250,000
90,000
18.000
95,000
41,500
28,000
25,000
26.OOO
1 4, 1 00
6,000
90O
Citgo
L. Chas..
La.
268.000
N.R.
60,000
28,000
125,000
46,000
6,000
30,000
46.0OO
14.000
35,300
7.000
1.000
1974
Average
229.467
68,333
20,667
99,333
41,667
9,333
2.000
23.667
7,333
29,000
8,667
4,667
25,933
3.700
1.800
2,333
2,000
913
Unit capacity,3 1973
Gulf
Alliance,
La.
1 74,000
180.000
54,000
16,000
75,000
37.500
16,000
22,000
41,000
28,400
11,100
5,400
. 840
Shell
Norco,
La.
240,000
250,000
90,000
17.00O
85,000
43,000
29.400
25.000
26,000
14,100
6,000
900
Citgo
L. Chas.,
La.
240.000
245,000
78,000
25,000
112,500
39,000
6.000
16,300
11,200
24,000
26,000
10,000
895
1973
Average
218,000
225.OOO
74,000
19.333
90.833
39.833
9,800
2,000
13,667
7,333
19,100
12,400
8,000
22,833
3,700
1,800
3,333
2,000
878
Unit capacity, a>
1973/
1974
Average
223,734
71.167
20,000
95,000
40,750
9,566
1,000
1,000
18,667
7,333
24,050
10,534
2,333
4,000
24,383
3,700
1,800
2.833
2.000
896
%
CHitfo
30.8
8.7
41.1
17.6
4.1
0.4
0.4
8.1
3.2
1O.4
4.6
1.0
1.7'
10.6
1.6
0.8
1.2
0.9
B'SO unless otherwise noted.
bUsed in cluster model.
Reference: Oil and Gas Journal. April 2, 1973.
Oil and Gas Journal, April 1. 1974.
-------
Table F-3. LARGE MIDWEST CLUSTER PROCESS CONFIGURATION
Unit type
Crude capacity, B/CD
Vacuum dist.
Thermal
Gas oil
-Visb
Fluid coke
Delayed coke
-Other
Catalytic crack! -g
Catalytic reforming
Hydrofining
Hvy gas oil
Resid. visb.
Cat feed & cycle
-Distillate
-Other
Hydrotreat
Reform feed
- Naphtha
Olef/Arom sat
-S.R. Distill:
Lubes
-Other dist.
-Other
Alkylation
Arom/lsom
-BTX
-HDA " .
Cyclohex
C4 Feed
C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke -tons/day
Unit capacity,8 1974
Mobil
Joliet.
Illinois
1 75,000
186,000
82,000
28,000
66,000
46,200
69,000
67,000
22,000
1,700
Union
Lemont,
Illinois
152,000
N.R.
55,000
19,500
52,000
32,000
32,000
2,700
4,500
7,000
34,500
2,500C
12,800
3,300
2,000
1,000
Arco
E. Chic.,
Illinois
126.000
140.000
70,000
48,000
20,000
25,000
20,000
2,000
6,000
1 0,400
1974
Average
151,000
69,000
15,833
55,333
32,733
31,333
~" 39,667
1,567
1,500
2,333
11,500
833
13,600
1,100
4,133
900
Unit capacity,8 1973
Mobil
Joliet,
Illinois
160,000
164,000
72,500
28,000
66.000
46,200
53,000
54,000
18,000
^
1,700
Union
Lemont,
Illinois
140.000
N.R.
55.000
19,000
50,000
32,000
32,000
2,000
5,300
7,OOO
37,000
16,000
3,200
1,OoC
Arco
E. Chic.,
Illinois
135,000
140,000
70,000
48,000
20,000
25,000
20,000
2,000
6,000
10,400
1973
Average
145,000
65,833
6,333
9,333
54,667
32,733
8,333
asTobb"
1,333
1,767
2.333
18,000
12,333
13,333
1,067
3,467
900
Unit capacity, 8*
1973/
1974
Average
148,000
67,417
3,167
12,583
55,000
32,733
19,833
37,334
1,450
1,634
2.333
14,750
6,583
13.467
1.084
3,800
900
Crude
43.4
2.0
10.1
35.4
21.1
12.7
24.0
.9
1.1
1.5
12.9
4.2
8.6
.7
2.4
i
cc
B/SD unless otherwise noted.
Used for cluster model.
Benzene concentrate.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table F-4. SMALL MIDCONTINENT CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity, B/CD
Vacuum dist.
Thermal
-Visb.
Fluid coka
Delayed coke
-Other
Catalytic cracking
Catalytic reforming
Hydrofining
Hvy gas oil
Resid. visb.
Cat feed & cycle
Distillate
-Other
Hydrotreat
Reform feed
Naphtha
- Olef/Arom sat
S.R. Distill.
- Lubes
-Other dist.
Other
Alkylation
Arom/lsom
-BTX
-HDA
-Cyclohex
C4 Feed
-C5 Feed
- C5/C6 Feed
Lubes
Asphalt
Coke-tons/day
Unit capacity,8 1974
Skally
El
Dorado,
Kan.
73,700
75,000
23,000
9,800
30,000
21,500
23,000
4,300
6,000
1,400
500
Gulf
Toledo,
Ohio
50,300
51,000
12.500
20.000
11,000
5,000
1 1 ,000
5,500
2,000
Champlin
Enid,
Okla.
49,500
52.000
18,000
3,700
19,500
15,000
20.400
4,500
6,000
1,100
1.400
165
1974
Average
57,833
59,333
17,833
4,500
23.167
15,833
1,667
18,133
1,433
5.333
467
2,000
367
1,133
222
Unit capacity,3 1973
Skelly
El
Dorado,
Kan.
67.000
70,000
23,000
9.800
30,000
20,000
23,000
4,300
6,000
1,400
''
3,000
500
Gulf
Toledo,
Ohio
48.800
50.000
12,300
18,500
1 0,500
5.00O
10,500
5,100
2,000
Champlin
Enid,
Okla.
48,000
50,000
24,000
4,000
19,000
15.000
15,000
5,000°
4,400
5,000
1,200
2,000
158
1973
Average
54,600
56,667
19.767
4,600
22,500
15,167
1,667
16.167
1,433
1,667
5,167
467
1,667
400
2,333
219
Unit capacity, 8'
1973/
1974
Average
56,217
58,000
18.800
4,550
22,834
15,500
1,667
17,150
1,433
I
834
5,250
467
1.834
384
1.733
221
%
Crude
32.4
7.8
39.4
26.7
2.9
"29.6"
2.5
1.4
9.1
0.8
3.2
0.7
3.0
B/SD Unless otherwise noted.
Used for cluster model.
Isom feed.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table F-5. EAST COAST CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity. B/CD
Vacuum dist.
Thermal
-Visb.
Fluid coke
Delayed coke
- Other
Catalytic cracking
Catalytic reforming
Hydrocracking
-Dist.
Residual
Lu bes
Other
Hydrofining
Hvy gas oil
Resid. visb.
-Cat feed & cycle
Distillate
-Other
Hydrotreat
-Reform feed
-Naphtha
-Olef/Arom sat
-S.R. Distill
Lubes
-Other dist.
-Other
Alkylation
Arom/lsom
BTX
HDA
Cyclohex
C4 Feed
C5 Food
C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity,8 1974
Arco
Phil.,
Pa.
185,000
195,000
57.000
60,000
30.000
32,000
41,000
,
54,000
19,500
Sun
Marcus
Hook, Pa.
165,000
180,000
48,000
75,000
45,000
35,000
10,000
c
1 0,000
12,000
5,300
1 7,000
12,000
Exxon
Linden,
N.J.
275,000
286.000
143,000
120,000
42,000
50,000
42,000
14,000
39,000
8.500
46,000
1974
Average
208,333
220,333
82,667
65.000
49.000
10.000
27.333
13,667
43,667
4,667
3,333
13,000
3,333
6,833
1,767
5,667
25,833
Unit capacity,8 1973
Arco
Phil.,
Pa.
160,000
165,000
83,000
36,000
60,000
30,000
34,000
53,000
7,000
17,000
Sun
Marcus
Hook, Pa.
163.000
180,000
48,000
75,000
43,000
35,000
10,000
16.000C
12.000
5,300
17,000
12,000
Exxon
Linden,
N.J.
255,000
268,000
140.000
1 25.000
46,000
50,000
46,000
14,000
37,000
10,700
46.000
1973
Average
192.667
204,333
90.333
78,667
49,667
10,000
16,667
11,333
44,667
4,667
3,333
12.333
5.333
9,900
1,767
5,667
25.000
Unit capacity.
1973/
1974
Average
200,500
212,333
86,500
71,834
49,334
10,000
22,000
12,500
44,167
4,667
3,333
12,667
4,333
8,367
~ ~T.767~~
5,667
25,416
%
Crude
40.7
33.8
23.2
4.7
10.4
5.9
20.8
2.2
1.6
6.0
2.0
3.9
__ _
2.7
12.0
T)
I
' B/SD unless otherwise noted.
Used for cluster model.
cFurnace oil.
Reference: Oil and Gas Journal. April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table F-6. WEST COAST CLUSTER PROCESSING CONFIGURATION
Unit type
Cm-It) i:npocltv
Vacuum dltt.
Thermal
Gas oil
-Visb.
Fluid coke
Delayed coke
Other
Catalytic cracking
Catalytic reforming
Hydrocracking
-Dist.
Residual
-Lubes
Other
Hydrofining
Hvy gas oil
-Resid. visb.
-Cat feed & cycle
Distillate
Other
Hydrotreat
- Reform feed
Naphtha
-Olef/Arom sat
-S.R. Distill.
-Lubes
Other dlst.
-Other
Alkylation
Arom/lsom
-BTX
-HDA
Cyclohex
-C4 Feed
-C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke-tons/day
Unit capacity,3 1974
Mobil
Torrance,
Calif.
123.500
130.000
95.0OO
16.000
46,640
56,000
36.000
18,000
23,000
15.000
25,000
10.500
2.800
Arco
Carson,
Calif.
165.000
1 73,000
93.OOO
12,500
42,000
30,000
57,000
34,000
19,700
18,000
34,000
1 8.0OO
7,200
2,490
1,800
Socal
El Segundo,
Calif.
230,000
N.R.
1 03,000
54.000
43.500
60,000
49,000
40,000
12.OOO
18,000C
5.900
1,500
8.300
2,200
1974
Average
172.833
97,000
4,167
19,333
43,547
52,167
43,333
28,900
6,000
32,333
6,000
5,000
4,000
8,333
6,000
7,867
830
500
2,767
2,267
Unit capacity,8 1973
Mobil
Torrance,
Calif
123,500
130,000
95,000
16,000
46,640
56,000
36,000
18,000
23,000
1 5,000
23,000
10,500
2,800
Arco
Carson,
Calif
165.00O
173.000
93.00O
23,000
37,000
25,500
57,000
32,000
177000
18,000
32.000
18,000
7,200
2,490
1.650
Socal
El Segundo,
Calif.
N.R.
220,000
103.000
50,000
40,000
62,000
45,000
40,000
12,000
18,000
5,400
1,500
8,300
2,200
1973
Average
174,333
97,000
7,667
17,667
40,713
51,000
43,333
26,667
6,000
31,667
11,000
4,000
7,667
6,000
7,700
1,330
2,767
2,217
Unit capacity, a'b
1973/
1974
Average
97,000
5,917
18,500
42.130
51.584
43.333
27.784
6,000
32,000
3.000
8.000
4.000
8,000
6,000
7,784
1,080
250
2,767
2,242
%
Crude
54.5
3.3
10.4
23.7
29.0
24.3
15.6
3.4
18.0
1.7
4.5
2.2
4.5
3.4
4.4
0.7
0.1
1.6
B/SD unless otherwise noted.
Used for cluster model.
cJet fuel.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal. April 1, 1974.
-------
Table F-7. SUMMARY OF MAJOR REFINERY PROCESSING UNITS
(percentage of crude capacity)
Processing unit
Catalytic reforming
Catalytic cracking
Hydrocracking
Alkylation
Delayed coking
Texas
Gulf
cluster
23
33
6
6
6
La.
Gulf
cluster
18
41
4
11
9
PAD III
average
24
31
5
6
8
Large
Midwest
cluster
21
35
0
9
10
Small
Mid-
continent
cluster
27
39
0
g
8
PAD II
average
22
34
4
7
g
East Coast
cluster
23
34
5
4
0
PAD!
average
21
33
3
4
7
West Coast
cluster
24
29
16
4
24
PADV
avtragt
23
24
15
5
20
I
I-1
10
-------
Tables F-8 through F-ll provide the comparison of product outputs. In
general, the cluster refineries exhibited higher yields of gasoline and
distillate fuel oil (except for East Coast) and lower yields of residual
fuel oil (except for West Coast) than the corresponding PAD averages. How-
ever, in no cases were the deviations deemed to be of sufficient magnitude
to change the cluster make-up.
Tables F-12 through F-15 provide the comparison of the crude slate for
each cluster with the crude slate for the PAD district. PAD Districts II
and III showed excellent agreement. There were variations in PAD I, however
the varying crudes were of equivalent quality. For example, the subtotal
of African crudes (light, low sulfur) checked very well and the combined
subtotals of Middle East and South American crudes (heavy, high sulfur)
also showed excellent agreement. Thus, the major discrepency was the re-
placement of mixed Canadian crude with domestic supplies (primarily from
Texas) which should not appreciably change average crude quality.
In PAD V, Canadian crude is replaced by approximately equal quantities
of Middle East and Far East crudes (low sulfur) in the cluster model which,
again does not reflect a major change in crude quality.
F-13
-------
Table F-8. COMPARISON OF PRODUCT OUTPUT OF EAST COAST CLUSTER TO
P.A.D. DISTRICT 1,1973
Outputs
Gasoline total
Jet fuel
Naphtha- type
Kerosene-type
Ethane
LPG
For fuel use
For chemical use
Kerosene
Distillate fuef
Residual fuel
Petrochemical feedstocks
Still gas
Naphtha - 400°
Other
Special naphthas
Lube oil, total
Wax
Coke (marketable)
Asphalt
Road oil
Total
Total P.A.D. I
MBPY
272,932
2,726
11,918
58
14,364
6,394
7,009
147,003
52,258
942
4,932
768
391
12,081
1,433
13,627
36,416
706
585,958
% of Total
46.58
.47
2.03
.01
2.45
1.09
1.20
25.09
8.92
.16
.84
.13
.07
2.06
.24
2.33
6.21
.12
100.00
East Coast cluster
MBPY
114,904
1,730
5,956
58
7,369
4,524
3,711
49,818
14,053
883
1,485
29
13
5,074
333
0
19,856
0
229,796
% of Total
50.0
.75
2.59
.03
3.21
1.97
1.61
21.68
6.12
.38
.65
.01
.01
2.21
.14
0
8.64
0
100.0
F-14
-------
I able f 9. COMPARISON OF PRODUCT OUTPUT OF MIDCONTINENT CLUSTERS TO
PlA.D. DISTRICT II, 1973
Outputs
Gasoline total
Jet fuel
Naphtha- type
Kerosene-type
Ethane
LPG
For fuel use
For chemical use
Kerosene
Distillate fuel
Residual fuel
Petrochemical feedstocks
Still gas
Naphtha - 400°
Other
Special naphthas
Lube oil, total
Wax
Coke (marketable)
Asphalt
Road oil
Total
P.A.D. II
MBPY
728,246
11,937
50,788
520
25,323
4,248
19,887
297,796
71,120
2,671
6,572
2,857
6,106
10,725
1,194
38,873
57,637
4,104
1,340,605
% of Total
54.32
.89
3.79
.04
1.89
.32
1.48
22.21
5.31
.20
.49
.21
.46
.80
.09
2.90
4.30
.31
100.01
Small Midcontinent cluster
MBPY
40,991
472
9.11
520
1,586
653
38
17,374
252
70
1,535
185
7
370
0
1,430
1,976
0
68,370
% of Total
59.95
.69
1.33
.76
2.32
.96
.06
25.41
.37
.10
2.25
.27
.01
.54
0
2.09
2.89
0
100.0
Large Midwest cluster
MBPY
89,467
143
2,297
0
3,489
0
1,813
44,678
8,094
0
1,025
0
2,248
0
0
4,024
2,013
2,154
161,445
% of Total
55.42
.09
1.42
0
2.16
0
1.12
27.67
5.01
0
.63
0
1.39
0
0
2.49
1.25
1.33
99.98
-------
Table F-10. COMPARISON OF PRODUCT OUTPUT OF GULF COAST CLUSTERS TO
P.A.D. DISTRICT III. 1973
Ti
I
Outputs
Gasoline total
Jet fuel
Naphtha-type
Kerosene- type
Ethane
LPG
For fuel use
For chemical use
Kerosene
Distillate fuel
Residual fuel
Petrochemical feedstocks
Still gas
Naphtha - 400°
Other
Special naphthas
Lube oil, total
Wax
Coke (marketable)
Asphalt
Road oil
Total
Total P.A.D. III
MBPY
979,079
27,693
114,173
8,108
35,507
23,219
49,003
439,979
88,455
7,773
40,298
56,170
21,010
40,099
3,082
42.436
41,433
64
2,017,581
% of Total
48.53
1.37
5.66
.40
1.76
1.15
2.43
21.81
4.38
.39
2.00
2.78
1.04
1.99
.15
2.10
2.05
.003
99.993
Louisiana Gulf cluster
MBPY
130,086
807
20,295
687
8,644
2,623
6,021
69,914
5,856
0
42
3,464
0
0
0
4,512
1,701
. 0
254,652
% of Total
51.08
.32
7.97
.27
3.39
1.03
2.36
27.45
2.30
0
.02
1.36
0
0
0
1.77
.67
0
99.99
Texas Gulf cluster
MBPY
181,351
3,009
25,115
1,266
5,428
4,350
8,429
88,491
17,170
776
6,623
2,684
7,231
17.502
550
4,380
1,536
0
375,891
% of Total
48.25
.80
6.68
.34
1.44
1.16
2.24
23.54
4.57
.21
1.76
.71
1.92
4.66
.15
1.17
.41
0
100.01
-------
Table F-11. COMPARISON OF PRODUCT OUTPUT OF WEST COAST CLUSTER TO
P.A.D. DISTRICT V, 1973
Outputs
Gasoline total
Jet fuel
Naphtha-type
Kerosene- type
Ethane
LPG
For fuel use
For chemical use
Kerosene
Distillate fuel
Residual fuel
Petrochemical feedstocks
Still gas
Naphtha - 400°
Other
Special naphthas
Lube oil, total
Wax
Coke (marketable)
Asphalt
Road oil
Total
Total P.A.D. V
MBPY
335,285
20,148
66,202
508
12,202
4,139
1,319
102,599
132,900
881
5,352
3,132
5,241
5,450
961
33,371
22,013
1,682
753,385
% of Total
44.50
2.67
8.79
.07
1.62
.55
.18
13.62
17.64
.12
.71
.42
.70
.72
.13
4.43
2.92
.22
100.01
West Coast cluster
MBPY
74,667
3,594
21,059
508
4,386
1,523
184
23,891
33,457
0
4,271
358
1,300
381
0
10,486
2,199
16
182,280
% of Total
40.96
1.97
11.55
.28
2.41
.84
.10
13.11
18.35
0
2.34
.20
.71
.21
0
5.75
1.21
.01
100.00
F-17
-------
Table F-12. COMPARISON OF CRUDE INPUT OF EAST COAST CLUSTER
TO P.A.D. DISTRICT I, 1973
Crude receipts from:
P.A.D. I
P.A.D. II
P.A.D. Ill
Louisiana
Texas and others
P.A.D. IV
Total domestic
Africa
Algeria
Angola
Egypt
Libya
Nigeria
Tunisia
Subtotal Africa
Middle East
Iran
Iraq
Israel
Kuwait
Qatar
Saudi Arabia
United Arab Emirates
Subtotal Middle East
South America
Bolivia
Colombia
Ecuador
Mexico
Trinidad
Venezuela
Subtotal S. America
Far East
Indonesia
Malaysia
Subtotal Far East
Canada
Total foreign
Total crude
Total P.A.D. I
MBPY
16,100
12,277
14,002
43,318
-
85,697
37,289
13,884
5,074
26,350
119,281
4,030
205,908
47,496
343
12,665
38,153
12,977
111,634
484
377
4,454
96,736
102,051
2,532
-
2,532
43,949
466,074
551,771
% of Total
2.92
2.23
2.54
7.85
-
15.53
6.76
2.52
.92
4.78
21.62
.73
37.32
8.61
.06
2.30
6.91
2.35
20.23
.09
,07
.81
17.53
18.50
.46
-
.46
7.97
84.47
100.00
East Coast cluster
MBPY
2,594
3,346
38,075
-
44,015
25,248
-
16,121
29,430
3,733
74,532
3,905
6,036
5,676
15,617
_
1,772
61,344
63,116
1,165
-
1,165
154,430
198,445
% of Total
1.31
1.69
19.19
-
22.18
12.72
-
8.12
14.83
1.88
37.56
1.97
3.04
2.86
7.87
.89
30.91
31.81
.59 ,
-
.59
77.82
100.00
F-18
-------
Table F-13. COMPARISON OF CRUDE INPUT TO MID CONTINENT CLUSTER TO
P.A.D. DISTRICT II, 1973
Crude receipts from:
P.A.D. I
P.A.D. II
P.A.D. Ill
Louisiana
Texas and others
P.A.D. IV
Total domestic
Africa
Algeria
Angola
Egypt
Libya
Nigeria
Tunisia
Subtotal Africa
Middle East
Iran
Iraq
Israel
Kuwait
Qatar
Saudi Arabia
United Arab Emirates
Subtotal Middle East
South America
Bolivia
Colombia
Ecuador
Mexico
Trinidad
Venezuela
Subtotal S. America
Far East
Indonesia
Malaysia
Subtotal Far East
Cjr.jda
Totjl foreign
Tot.il crude
Total P.A.D. II
MBPY
337,673
183,950
391,308
100,160
1,013,091
1,438
-
222
5,546
4618
-
11,824
6,709
653
17,509
639
25,510
596
238
4,077
1,050
5,961
_
-
-
217,073
260,368
1,273,159
% of Total
26.52
14.44
30.73
7.87
79.55
.1.1
-
.02
.44
.36
-
.93
.53
.05
1.37
.05
2.00
.05
.02
.32
.08
.47
_
-
.
17.05
20.45
100.00
Small Midcontinent cluster
MBPY
40,985
2,259
5,056
1,481
49,781
-
-
-
-
-
-
.
_
-
-
10,744
10,744
60.525
% of Total
67.72
3.73
8.35
2.45
82.25
-
-
_
_
_
_
-
- '
17.75
17.75
100.00
Large Midwest cluster
MBPY
21,405
19,354
81,478
14,457
136,694
_
238
238
_
_
_
4,291
4,291
% of Total
12.80
11.57
48.72
8.64
81.73
_
.14
\14
_
_
_
_
2.57
2.57
i
_
_
_
-
_
-
26,022
30,551
167,245
_
_
-
_
15.56
18.27
100.00
F-19
-------
TaMe F-14. COMPARISON OF CRUDE INPUT OF GULF COAST CLUSTERS TO P.A.D.
District 111.1973
Crude Receipts From:
P.A.D. 1
P.A.D. II
P.A.D. Ill
Louisiana
Texas and others
P.A.D. IV
P.A.D. V
California
Other states
Total domestic
Africa
Algeria
Angola
Egypt
Libya
Nigeria
Tunisia
Subtotal Africa
Middle East
Iran
Iraq
Israel
Kuwait
Qatar
Saudi Arabia
United Arab Emirates
Subtotal Middle East
South America
Bolivia
Colombia
Ecuador
Mexico
Trinidad
Venezuela
Subtotal S. America
Far East
Indonesia
Malaysia
Subtotal Far East
Canada
Total foreign
Total crude
Total P.A.D. Ill
MBPY
_
-
629,470
1,037,412
-
-
1,666,882
4,892
3,869
-
16,689
39,788
2,511
67,479
11,041
671
309
340
910
28,345
958
42,574
295
566
489
13,208
19,108
33,666
1,665
-
1,665
145,654
1,812,536
% of Total
_
-
34.73
57.24
-
-
91.96
.27
.21
-
.92
2.20
.14
3.74
.61
.04
.02
.02
.05
1.56
.05
2.35
.02
.03
.03
.73
1.05
1.86
.09
-
.09
''
8.04
100.00
Louisiana Gulf cluster
MBPY
_
2,395
185,654
40,552
-
-
228,601
-
-
214
827
-
1,041
-
_
910
546
1,456
_
189
263
452
161
-
161
3,110
229,316
% of Total
_
1.03
80.13
17.50
-
-
98.66
'
.09
.36
-
.45
-
_
_
.39
.24
.63
_
_
_
.08
.11
.20
.07
-
.07
1.33
99.99
Texas Gulf cluster
MBPY
_
-
18,306
281,252
-
-
299,558
3,869
50
10,213
-
14,132
3,666
_
_
15,732
-
19,398
_
_
489
7,257
7,746
_
-
-
_
41,276
340,834
% of Total
_
-
5.37
82.52
-
-
87.89
1.14
.01
3.00
-
4.15
1.08
_
_
4.62
-
5.70
_
_
_
.14
_
2.13
2.27
-
-
_
12.11
100.00
F-20
-------
Table F-15. COMPARISON OF CRUDE INPUT TO WEST COAST CLUSTER
P.A.D. DISTRICT V, 1973
Crude receipts from:
P.A.D. 1
P.A.D. II
P.A.D. Ill
Louisiana
Texas and others
P.A.D. IV
P.A.D. V
California
Other States
Total domestic
Africa
Algeria
Angola
Egypt
Libya
Nigeria
Tunisia
Subtotal Africa
Middle East
Iran
Iraq
Israel
Kuwait
Qatar
Saudi Arabia
United Arab Emirates
Subtotal Middle East
South America
Bolivia
Colombia
Ecuador
Mexico
Trinidad
Venezuela
Subtotal S. America
Far East
Indonesia
Malaysia
Subtotal Far East
Canada
Total foreign
Total crude
Total P.A.D. V
MBPY
_
-
10,795
386,805
26,597
424,197
-
-
13,744
1,020
1,698
1,100
84,518
11,190
113,270
8,848
25,190
68,858
234
69,092
88.216
295,768
719,965
% of Total
_
-
1.50
53.73
3.69
58.92
-
-
1.91
.14
.24
.15
11.74
1.55
15.73
1.23
3.50
9.56
.03
9.60
12.25
41.08
100.00
West Coast cluster
MBPY
-
4,321
89,254
12,146
105,721
-
-
5,920
515
2
27,056
3,927
37,420
1,295
8,314
24,712
24,712
'
70,446
176,167
% of Total
_
-
2.45
50.66
6.89
60.01
-
-
3.36
.29
0
15.36
2.23
21.24
.74
4.72
14.03
14.03
-
39.99
100.00
F 21
-------
APPENDIX G
SCALE UP OF CLUSTER RESULTS -
DERIVATION OF PRODUCT DEMANDS FOR GRASS ROOTS REFINERIES
-------
TABLE OF CONTENTS
APPENDIX G - SCALE UP OF CLUSTER RESULTS -
DERIVATION OF PRODUCT DEMANDS FOR GRASS ROOTS REFINERIES
Page
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. 1.985 Scale Up G-12
3. 1980 Scale Up G-15
E. SCALE UP OF CAPITAL INVESTMENTS G-17
LIST OF TABLES
TABLE G-l. ADL Model Input/Outturn Data for Calibration -
1973 G-2
TABLE G-2. Comparison of 1973 B.O.M. Data and Scale Up of 1973
Calibration Input/Outturn G-3
TABLE G-3. L.P. Model Input/Outturns 1977 G-7
TABLE G-4. L.P. Model Input/Outturns 1980 G-8
TABLE G-5. L.P. Model Input/Outturns 1985 G-9
TABLE G-6. Scale Up Input/Outturns 1977 G-ll
TABLE G-7. Atypical Refinery Intake/Outturn Summary G-13
TABLE G-8. Scale Up Input/Output - 1985 G~14
TABLE G-9. Scale Up Input/Output - 1980 G-16
-------
APPENDIX G
SCALE UP OF CLUSTER RESULTS -
DERIVATION OF PRODUCT DEMANDS FOR GRASS ROOTS REFINERIES
A. INTRODUCTION
Appendix F explained how the U.S. refining industry has been simulated
by the study of six cluster models, each cluster representing three exist-
ing refineries in different regions of the U.S.A. This appendix discusses
the method of scale up of the results obtained from the cluster model analysis
to represent an aggregate of the total U.S. refining industry. It also
describes how the demands for the grassroots refineries were determined.
B. 1973 CALIBRATION SCALE UP
Each cluster model was considered to represent either part of or a
complete PAD, with the exception of PAD IV which was not represented by a
specific cluster model. The input/output data used in the calibration runs
(Appendix I) was then scaled up by making the gasoline production in the
cluster model equal to the total gasoline production for each PAD as de-
fined in the BOM annual data for 1973.
PAD II is represented by two cluster models; it has been assumed
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 BOM Louisiana Gulf refining district and the Texas
Gulf cluster represents the balance of District III.
Table G-l gives the input/output data used in the model calibration
runs. These data were then scaled up and are compared with the BOM data
in Table G-2. For example, for the East Coast cluster a scale up factor
G-l
-------
Table G-1. ADL MODEL INPUT/OUTTURN DATA FOR CALIBRATION - 1973
MB/CD
Product Outturns
Refinery gas/ethane (FOE)
LPG-fuel
LPG-petrochemicals
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke
Cat cracker feed
Cat reformer feed
Total outturns
Inputs
Isobutane
Normal butane
Natural gasoline
Natural gas (FOE)
Cat cracker feed
Cat reformer feed
Crude oil
Domestic
Foreign
Total crude
Total inputs
Louisiana
Gulf
0.32
5.97
2.40
118.79
0.78
18.53
5.50
67.80
5.35
1.55
4.12
2.161
1.164
234.435
6.1C
5.97
4.28
5.40
-
222.200
-
222.200
243.95
Texas
Gulf
.84
4.96
3.97
165.62
8.80
6.05
23.49
7.70
83.27
16.49
15.68
1.40
4.00
2.00
4.955
349.225
2.13
?.C5
16.00
13.447
-
294.270
37.130
331.400
365.027
Large
Midwest
-
3.19
81.70
2.16
0.94
2.12
1.66
40.80
7.39
3.81
3.68
147.45
3.70
0.93
0.24
1.215
.654
118.265
27.280
145.545
152.284
Small
Midcontinent
0.54
1.45
0.60
37.44
0.35
1.40
0.92
0.04
16.04
0.34
0.23
1.81
1.31
62.47
0.94
0.31
5.50
2.046
.436
.235
45.319
9.800
55.119
64.586
East
Coast
0.86
6.73
4.13
104.93
1.28
1.36
5.76
3.39
45.52
4.94
12.83
18.13
209.86
0.35
1.76
5.84
2.50
11.10
5.98
43.290
144.685
187.975
215.505
West
Coast
0.46
3.99
1.30
67.77
3.81
3.90
19.89
0.17
22.15
0.35
30.55
2.02
9.58
165.94
0.50
0.16
1.30
6.39
3.597
1.937
79.381
75.816
155.197
169.081
o
1
N>
-------
TABLE G-2. COMPARISON OF 1973 B.O.M. DATA AND SCALE UP OF 1973 CALIBRATION INPUT/OUTTURN
{MB/CO)
Intakes
Domestic crude
Imported crude
Subtotal
Isobutane
Normal butane
Subtotal
Natural gasoline
Plant condensate
Unfinished oils
Total
Purch. natural gas (FOE)
Outturns
Gas/ethane FOE
LPG-fuel
LPG-petrochemicals
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke-market
11 f '«hnH 'I
Total
Crude capacity (MB/CD)
990%
Scale up factor
PADI
B.O.M.
data
237.3
1.264.1
1,501.4
-
_
.8
.4
5.8
108.2
1.616.6
140
2.7
39.4
17.5
747.8
7.0
13.5
34.1
19.2
404.9
37.0
143.2
101.7
15.3
I-.S83.3
1.673.52
1.506.17
A/T
-
-
100.0
-
_
-
-
-
100.0
-
-
-
-
-
-
-.
50.0
-
50.0
-
-
100.0
Cluster
model
scaled up
308.5
1,031.2
1,339.7
2.5
12.5
15.0
41.6
-
121.7
1.518.0
17.8
6.1
48.0
29.4
747.8
9.1
9.7
41.1
24.2
324.4
35.2
91.4
129.2
-
1,495.6
_
-
7.127
PAD II
Ok la., Kans., etc.
B.O.M.
data
893.3
28.2
921.5
-
-
32.3
32.7
.1
-
986.6
37.6
2.1
19.2
4.0
543.5
15.0
6.0
32.0
5.7
236.4
16.4
21.1
44.5
14.9
965.3
1 .000.44
900.40
A/T
-
-
60.0
-
-
-
-
--
-
60.0
-
-
-
-
-
10.0
-
5.0
5.0
-
-
20.0
20.0
-
60.0
_
-
Cluster
model
scaled up
657.9
142.3
800.2
13.6
4.5
18.1
79.8
-
9.7
907.8
29.7
7.8 .
21.0
8.7
543.5
5.1
20.3
13.4
.6
232.9
4.9
3.3
26.3
19.0
906.8
_
-
14.517
Balance PAD
B.O.M.
data
1.880.9
682.5
2,563.4
-
-
40.9
20.7
66.9
5.1
2.697.0
19.8
5.8
50.2
7.6
1,461.7
27.9
12.0
113.7
48.8
587.3
16.3
173.7
124.6
36.6
2,656.2
2.888.972
2,600.07
A/T
-
-
40.0
-
-
-
-
-
-
40.0
-
-
-
-
-
-
~
10.0
10.0
-
-
10.0
10.0
-
40.0
_
-
Cluster
model
scaled up
2.101.5
484.7
2,586.2
65.7
. -
65.7
16.5
-
33.2
2.701.6
4.3
-
56.7
-
1.451.7
38.4
16.7
37.7
29.5
725.0
131.3
67.7
65.4
2,620.1
_
-
X 17.769
Total PAD
B.O.M.
data
2,774.2
710.7
3,484.9
-
-
73.2
53.4
67.0
5.1
3,683.6
57.4
7.9
69.4
11.6
1,995.2
42.9
18.0
145.7
54.5
823.7
32.7
194.8
169.1
51.5
3,621.5
3,889.412
3.500.47
A/T
-
-
100.0
-
-
-
-
-
-
100.0
-
-
-
-
-
10.0
-.
15.0
15.0
-
-
30.0
30.0
-
100.0
_
-
Cluster
model
scaled up
2,759.4
627.0
3,386.4
79.3
4.5
83.8
96.3
-
42.9
3.609.4
34.0
7.8
77.7
8.7
1,996.2
43.5
37.0
51.1
30.1
957.9
4.9
134.6
94.0
84.4
3,526.9
_
-
PAD III
L.A. Gulf
B.O.M.
data
1.617.2
46.2
1,633.4
-
-
54.4
66.2
4.4
41.2
1.829.6
57.2
3.6
38.9
19.0
907.7
17.6
1.3
140.2
55.0
481.0
24.2
65.1
40.4
16.9
1,810.9
1,893.05
1,703.75
A/T
-
-
20.0
-
-
-
-
-
-
20.0
-
-
-
-
-
5.0
-
-
5.0
-
-
-
10.0
-
20.0
-
Cluster
model
scaled up
1.697.8
-
1,697.8
46.6
45.6
92.2
32.7
-
-
1.822.7
41.3
2.4
45.6
18.3
907.7
6.0
-
141.6
42.0
518.1
-
40.9
11.8
31.5
1,791.3
_
-
7.641
Balance PAD
B.O.M.
data
3,038.7
351.9
3.390.6
-
-
62.2
291.2
41.2
-
3.785.2
264.8
27.6
58.4
44.6
1.774,7
100,7
109.1
187.8
79.3
878.4
94.1
177.3
73.3
32.4
3.699.5
4.039.876
3,635.89
A/T
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
_
-
Cluster
model
scaled up
3.153.1
397.8
3,550.9
22.8
22.0
44.8
171.4
-
-
3.767.1
144.1
9.0
53.1
42.5
1,774.7
94.3
64.8
251.7
82.5
892.2
176.7
168.0
15.0
42.9
3,741.9
_
-
10.715
Total PAD
B.O.M.
data
4.655.9
393.1
5,054.0
-
-
1166
357.4
45.6
41.2
5.614.8
322.0
31.2
97.3
63.6
2.682.4
118.3
110.4
328.0
134.3
1.359.4
118.3
242.4
113.7
49.3
5.510.4
5.932.926
5,339.63
A/T
-
-
20.0
-
-
-
-
-
-
20.0
-
-
-
-
-
5.0
-
-
5.0
-
-
-
10.0
-
20.0
_
Cluster
model
scaled U0
4.850.9
397.8
5,248.7
69.4
67.6
137.0
204.1
-
-
5,589.8
185.4
11.4
98.7
60.8
2.682.4
100.3
64.8
393.3
124.5
1.410.3
176.7
208.9
26.8
74.4
5,533.2
_
-
i
-------
TABLE G 2 (Continued) COMPARISON OF 1973 B.O.M. DATA AND SCALE UP OF 1973 CALIBRATION INPUT/OUTTURN
(MB/CD)
o
I
Intakes
Outturn
Gas/e
LPG-
LPG-i
Gasol
Naph
BTX
estic crude
>rted crude
btotal
jtane
nal butane
btotal
ral gasoline
lensate
nished oils
nal
i. natural gas (FOE)
i
sthane-FOE
-fuel
-petrochemicals
line
itha
uel
sene
Hate fuel oil
; stocks
^ual fuel oil
lalt
3-market
nished oils
3 till
Opacity (MB/CD)
PAD IV
b.o M
A/T
371.0
44.1
415.1
-
-
9.4
4.6
27.7
.2
457.0
11.9
.4
6.0
.2
228.2
8.0
.1
14.5
6.0
115.1
1.3
27.0
30.5
3.9
-
441.2
PAD 1 IV
Tolnl
Ollll.lt.,
model
scaled up
7,918.8
2,056.0
9,974.8
151.2
84.6
235.8
342.0
-
64.7
10,617.3
237.2
25.3
224.4
98.9
5,425.4
152.9
111.5
485.5
178.8
2,692.6
216.8
434.9
250.0
158.8
-
10,455.8
50B.7?1
455.15
Total
A/T
-
635.1
9.4
4.6
27.7
.2
677.0
11.9
.4
6.0
.2
228.2
23.0
1
. i
29.5
26.0
165.1
1.3
107.0
70.5
3.9
-
661.2
_
Subtotal
-
10,609.9
--
245.2
346.6
27.7
64.9
11,294.3
249.1
25.7
230.4
99. 1
5,653.6
175.9
111.6
515.0
204.8
2,857.7
218.1
541.9
320.5
162.7
-
11,117.0
Total
B.O.M.
8,038.4
2,417.0
10,455.4
200.0
415.8
146.1
88.4
11,305.7
405.3
42.2
212.2
92.9
5,6536
176.2
142.0
522.3
214.0
2,703.1
189.3
607.4
415.0
120.0
11,090.2
12,001.579
10,801.42
j factor
PADV
B.O.M.
data
1,166.9
808.4
1,975.3
19.8
23.4
9.8
37.0
2,065.3
61.6
3.0
33.4
11.3
918.6
58.5
14.7
192.4
3.6
289.7
17.6
364.1
64.9
65.4
-
2,037.2
2,218.737
1,996.86
Cluster
model
scaled up
1,076.0
1,027.7
2,103.7
6.8
2.2
9.0
17.6
-
75.0
2,205.3
86.6
6.2
54.1
17.6
918.6
51.6
52.9
269.6
2.3
300.2
4.7
414.1
27.4
129.9
2,249.2
_
13.555
... I
Total U.S.
Total
cluster
model
scaled up
8,994.8
3,083.7
12,078.5
158.0
86.8
244.8
359.6
-
139.7
12,822.6
323.8
31.5
278.5
116.5
6,344.0
204.5
164.4
755.1
181.1
2,992.8
221.5
849.0
277.4
288.7
-
12,705.0
Total
A/T
-
635.1
-
-
9.4
4.6
27.7
.2
677.0
11.9
.4
6.0
.2
228.2
23.0
.1
29.5
26.0
165.1
1.3
107.0
70.5
3.9
-
661.2
i
t
Subtotal
-
12,713.6
-
-
254.2
364.2
27.7
139.9
13,499.6
335.7
31.9
284.5
116.7
6,572.2
227.5
164.5
784.6
207.1
3,157.9
222.8
956.0
347.9
292.6
-
13,366.2
_
Total
B.O.M.
9,205.3
3,225.4
12,430.7
-
-
219.8
439.2
155.9
125.4
13,371.0
466.9
45.2
245.6
104.2
6,572.2
234.7
156.7
714.7
217.6
2,992.8
206.9
971.5
479.9
185.4
-
13,127.4
14,220.316
12,798.23
'jti
3?-:
>:
-------
of 7.127 has been used since this is the ratio of the gasoline production
of District I to the gasoline production of the East Coast cluster. Table
G-2 also contains a middle column entitled "A/I", which stands for atypical
configuration. This column is an estimate of the effect of those refineries
which do not produce as much motor gasoline on the total output of each
district (except PAD IV). By adding the inputs and outputs from these
atypical refineries to the scaled up cluster model inputs and outputs,
the total cluster model simulation is obtained, which should be comparable
to the BOM data. The basis for determining the volume and product mix of
the atypical refineries in each region is now discussed.
For PAD I, total product outturns from the cluster model were
1,495.6 MB/CD, while the BOM data indicated 1,583.3; therefore 100 MB/CD
has been accounted for via the A/T configuration. The choice of 50 MB/CD
as distillate fuel oil and 50 MB/CD as residual fuel oil was made because
these products were in short supply from the cluster model; also, the
atypical refineries in PAD I produce heavy products predominantly, it should
be noted that the crude supply is equal to the products (i.e. no processing
loss or gain). However, since the A/T crude intake has only a minor effect
on crude slate, this is not important.
In PAD II, which is represented by two cluster models, the addition
of 60 MB/CD A/T configuration for the Small Midcontinent and 40 MB/CD for
the Large Midwest brought the product outturns from the cluster models
close to the BOM statistics.
In PAD III, only a nominal 20 MB/CD of A/T configuration was used to
balance the entire district. PAD IV is not simulated by a cluster model
and therefore the basic BOM data is by definition equal to the A/T con-
figuration needed to balance the district.
The model simulation for PAD's I-IV is obtained by combining the total
cluster model output with the total A/T (including PAD IV), for comparison
with the BOM data for Districts I-IV. Of course, as shown in Table G-2, the
gasoline productions are equal. Other products check quite well with the
cluster models being approximately. 150 MB/CD high on distillate fuel and
slightly more than 300 MB/CD low on total residual products (residual fuel,
plus asphalt, plus coke). Total product outturns differed by less than
G-5
-------
30 MB/CD and total intakes by about 10 MB/CD. The scaled up model runs
were about 150 MB/CD high on crude and 50 MB/CD on butanes, but these
were offset by natural gasoline and condensate.
The scale up for PAD V is presented next. After scaling up the
gasoline the results show a greater production of other products (primarily
jet fuel, residual fuel oil and coke) than the BOM data. Thus, it was
concluded that no A/T configuration would be added for this region.
C. DERIVATION OF MODEL FIXED INPUTS AND OUTPUTS FOR FUTURE YEARS
The crude oils and other fixed inputs used in the model runs for the
years 1977, 1980 and 1985 were based on the inputs used in the calibration
runs with certain modifications, as shown in Tables G-3, G-4, and G-5.
The choice of crude oil types has already been discussed in Appendix A.
The amount of crude oil processed was kept constant in all three future
years studied, to simulate no expansion of these refineries (expansion was
included in the grassroots models).
Butanes and natural gasoline inputs were reduced from the calibration
levels to reflect a gradual reduction in availability of these materials.
The volumes used in the calibration runs were reduced by 10% in 1977, 20%
in 1980 and 30% in 1985.
Natural gas purchased by the cluster model refineries was completely
phased out by 1985 to reflect our forecast of the declining production of
natural gas. In 1977, 75% of the volumes purchased in the calibration
runs were used and in 1980 the volumes purchased were 50% of those in
calibration.
Product demands with the exception of LPG and gasoline, were fixed,
based on the demands used in the calibration run. The actual demands
used in the cluster model runs for future years were the calibration
demands ratioed up or down based on the total fixed input to the cluster
model (crude oil, butanes, natural gasoline, natural gas and unfinished
oil).. For example, the total inputs to the Texas Gulf cluster model in
the calibration run amounted to 365,027 barrels per calendar day (331,400 of
crude oil, 4,180 of butanes, 16,000 of natural gasoline and 13,447 of
natural gas). In the 1985 model runs the total inputs to the Texas Gulf
G-6
-------
Table G-3. L.P. MODEL INPUT/OUTTURNS 1977
(MB/CD)
Fixed intakes
Domestic crude
Imported crude
Subtotal
Isobutane
Normal butane
Natural gasoline
Natural gas (FOE)
Unfinished oils
Total
Fixed outturns
Gas/ethane (FOE)
LPG - petrochem.
Naphtha
BTX
Jet fuel
Kerosene
Distillate
Lube stocks
Resid. fuel oil
Asphalt
Coke
Unfinished oils
Total
Variable outturns
Scenario Product
A Gasoline
LPG
B Gasoline
LPG
C Gasoline
LPG
D Gasoline
LPG
E Gasoline
LPG
F Gasoline
LPG
East Coast
197.917
197.917
0.315
1.584
5.840
1.875
17.080
224.611
0.896
4.303
1.333
1.417
6.001
3.532
47.431
5.147
13.368
18.891
-
102.319
110.972
4.634
110.424
4.402
109.109
5.579
110.236
5.246
109.771 .
5.883
108.987
5.140
Large
Midwest.
104.575
38.875
143.450
3.330
0.837
0.180
1.869
149.666
-
-
2.122
0.924
2.083
1.631
40.090
7.261
3.744
3.616
-
61.471
79.463
2.716
79.398
2.793
79.295
3.121
78.838
3.407
78.862
3.392
77.040
3.415
Small
Midcontinent
42.744
12.197
54.941
0.846
0.279
4.950
1.535
0.671
63.222
0.528
0.587
0.343
1.370
0.900
0.039
15.698
0.333
0.225
1.771
1.282
-
23.076
36.922
1.320
36.889
1.331
36.732
1.454
36.618
1.601
36.579
1.648
35.541
1.552
Louisiana
Gulf
217.993
-
217.993
5.490
5.373
3.852
4.050
-
236.758
0.311
2.329
0.757
-
17.984
5.338
65.801
5.192
1.504
3.999
3.198
106.413
119.104
3.223
119.328
2.843
118.346
3.588
118.308
3.623
118.369
3.483
116.558
3.831
Texas
Gulf
291.633
36.782
328.415
1.917
1.845
14.400
10.085
-
356.662
0.821
3.879
.8.598
5.911
22.952
7.524
81.363
16.112
15.321
1.368
3.908
6.796
174.553
164.006
5.263
163.300
5.849
161.267
7.303
161.267
7.303
161.267
7.303
161.288
6.919
West
Coast
87.349
76.840
164.189
0.450
0.144
1.170
4.793
5.534
176.280
0.480
1.357
3.978
4.072
20.765
0.177
23.125
0.365
31.894
2.109
10.002
-
98.324
71.380
3.458
71.208
3.623
69.634
4.033
69.631
4.035
69.627
4.038
69.609
3.997
C-7
-------
Table G-4. L.P. MODEL INPUT/OUTTURNS 1980
(MB/CD)
Fixed intakes
Domestic crude
Imported crude
Subtotal
liobutane
Normal butane
Natural gasoline
Natural gas (FOE)
Unfinished oils
Total
Fixed outturns
Gas/ethane (FOE)
LPG-petrochem.
Naphtha
BTX
Jet Fuel
Kerosene
Distillate
Lube stocks
Resid. fuel oil
Asphalt
Coke
Unfinished oils
Total
Variable outturns
Scenario
A
B
C
D
E
Product
Gasoline
LPG
Gasoline
LPG
Gasoline
LPG
Gasoline
LPG
Gasoline
LPG
East
Coast
197.910
197.910
0.280
1.400
5.840
1.250
17.080
223.760
0.892
^.286
1.328
1.411
5.978
3.518
47.249
5.127
13.317
18.818
-
101.924
111.524
3.954
109.817
4.910
108.723
5.561
109.435
5.568
108.862
6.543
Large
Midwest
92.812
50.638
143.450
2.960
0.744
0.120
1.869
149.143
-
-
2.115
0.920
2.076
1.625
39.948
7.236
3.730
3.603
61.253
78.635
2.807
78.070
3.498
77.425
3.999
77.024
4.060
76.906
4.100
Small
Midcontinent
39.447
15.494
54.941
0.752
0.248
4.400
1.023
0.671
62.035
0.518
0.576
C.336
1.344
0.883
0.038
15.400
0.326
0.221
1.738
1.258
22.638
36.219
1.261
35.874
1.569
35.472
1.948
35.437
1.981
35.302
1.957
Louisiana
Gulf
217.993
-
217.993
4.880
4.776
3.424
2.700
-
233.773
0.307
2.300
0.747
-
17.757
5.271
64.972
-
5.127
1.485
3.948
3.198
105.112
118.130
2.8r>5
117.446
3.324
116.110
4.315
115.505
4.541
114.842
4.768
Texas
Gulf
291.633
36.782
328.415
1.704
1.640
12.800
6.724
-
351.283
0.808
3.820
8.468
5.822
22.604
7.410
80.131
15.868
15.089
1.347
3.849
6.693
171.909
161.364
5.268
159.451
6.950
158.202
7.516
158.062
7.600
157.874
7.615
West
Coast
164.190
164.190
0.400
0.128
1.040
3.195
5.534
174.487
0.475
1.343
3.936
4.029
20.548
0.176
22.883
0.362
31.561
2.087
9.897
97.297
71.735
2.989
70.973
3.732
70.398
3.016
69.814
3.723
69.707
3.740
G-8
-------
Table G-5. L.P. MODEL INPUT/OUTTURNS-1985
(MB/CD)
Fixed Intakes
Domestic crude
Imported crude
Subtotal
Isobutane
Normal butane
Natural gasoline
Unfinished oils
Total
Fixed outturns
Gas/ethane (FOE)
LPG-petrochem.
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke market
Unfinished oils
Total
Variable outturns
Scenario Product
A Gasoline
LPG
B/C Gasoline
LPG
D Gasoline
LPG
E Gasoline
LPG
F Gasoline
LPG
East Coast
-
197.915
197.915
.245
1.232
5.840
17.080
222.312
.887
4.260
1.320
1.403
5.941
3.497
46.954
5.096
13.234
18.700
-
101.292
110.785
3.981
106.915
6.119
107.116
6.460
104.981
9.221
107.447
5.592
Large
Midwest
85.353
58.097
143.450
2.590
.651
1.869
148.560
2.107
.917
2.068
1.619
39.790
-
7.207
3.716
3.589
-
61.013
78.570
2.683
76.615
4.063
75.028
4.542
74.078
5.423
74.830
4.236
Small
Midcontinent
36.151
18.790
54.941
.658
.217
3.850
.671
60.337
.504
.560
.327
1 .307
.859
.037
14.973
.317
.215
1.690
1.223
-
22.012
35.174
1.366
34.016
1.720
33.045
1.689
33.033
1.655
32.775
1.622
Louisiana
Gulf
217.993
-
217.993
4.700
4.179
3.000
-
229.872
.301
2.257
.734
17.427
5.173
63.763
5.032
1.458
3.870
3.198
103.213
116.277
2.878
112.488
5.082
111.981
5.669
102.790
14.309
113.770
0.910
Texas
Gulf
291.633
36.782
328.415
1.491
1.435
11.200
-
342.541
.788
3.725
8.258
5.677
22.043
7.226
78.141
15.474
14.714
1.314
3.754
6.527
167.641
157.251
5.392
152.330
8.014
152.720
7.860
142.134
15.997
152.850
7.667
West
Coast
164.190
-
164.190
.350
.112
.910
5.534
171.096
.470
1.331
3.900
3.993
20.364
.174
22.678
.358
31.279
2.068
7.790
94.405
71.613
_
70.290
0.044
68.171
3.288
68.350
3.054
69.730
-
-------
cluster model totaled 342,541 barrels per calendar day (328,415 of crude
oil, 2,926 of butanes and 11,200 of natural gasoline). The product demands
for the Texas Gulf cluster for 1985 were derived by multiplying the cali-
bration run demands by a factor of 0.9384 (the ratio of total input in 1985
to the total input in the calibration run).
Also listed in Tables G-3, G-4 and G-5 are the variable outturns
of LPG and gasoline that were produced in each scenario studied.
D. SCALE UP OF RESULTS FOR FUTURE YEARS
The model results for the study years of 1977, 1980 and 1985 were
scaled up using the atypical concept derived from the calibration results.
In 1977, scale up factors were derived as in the calibration scale up,
using total gasoline demand. In 1980 and 1985 the scale up factors used,
however, were based on total crude run in each cluster and the effective
crude oil distillation capacity for the region simulated by that cluster.
The scale up factors used were calculated by making the crude run in each
region equal to the effective crude oil distillation capacity for that region.
Effective crude oil distillation capacity was defined as 90% of the 1973
calendar day rated capacity, which is similar to historical capacity
utilization. This capacity is shown for each region in Table G-2.
1. 1977 Scale Up
The scale up of results for 1977 was based on meeting the gasoline
demand for the total U.S. from scaled up cluster model gasoline productions,
atypicals and imports only. Since crude capacity utilization was less than
90%, grassroots refineries were not needed in 1977.
This scale up method results in a different scale up factor for each
scenario, since the cluster models produce different gasoline volumes in
each scenario and each scenario is scaled up to the s&me total U.S. demand
for gasoline. Therefore, in 1977 the penalties for meeting the proposed
regulations will be based on the loss of other products in addition to
additional crude runs required while continuing to produce the same
gasoline volume. Table G-3 gives the fixed inputs and outputs for the 1977
cluster runs and the variable gasoline and LPG productions for each
scenario. Table G-6 gives the scaled up fixed inputs, fixed outputs and
LPG for each scenario when producing the same volume of gasoline.
G-10
-------
Table G 6 SCALE UP INPUT/OUTTURNS 1977
Scenario
A
B
C
D
E
F
Input/outturn
Fixed input
Fixed output
LPG
Fixed input
Fixed output
LPG
Fixed input
Fixed output
LPG
Fixed input
Fixed output
LPG
Fixed input
Fixed output
LPG
Fixed input
Fixed output
LPG
East Coast
Factor
7.649
7.666
7.713
7.715
7.720
7.766
MB/CD
1,718.0
782.6
35.4
1,721.9
784.4
33.7
1,732.4
789.2
43.0
1,732.9
789.4
40.8
1,734.0
789.9
40.8
1,744.3
794.6
39.9
Large Midwest
Factor
18.217
18.258
18.369
18.376
18.387
18.450
MB/CD
2,726.5
1,119.8
49.5
2,732.6
1,122.3
51.0
2,749.2
1,129.2
57.3
2,750.3
1,129.6
62.6
2,751.9
1,130.3
62.6
2,761.3
1,134.1
58.7
Small Midcont.
Factor
16.417
16.454
16.609
16.615
16.625
16.725
MB/CD
1,037.9
378.8
21.7
1,040.3
379.7
21.9
1,050.1
383.3
24.1
1,050.4
383.4
26.6
1,051.1
383.6
27.4
1,057.4
385.9
26.0
Louisiana Gulf
Factor
7.856
7.874
7.921
7.924
7.929
7.977
MB/CO
1,856.0
836.0
25.3
1,864.2
837.9
22.4
1,875.4
842.9
28.4
1,876.1
843.2
28.7
1,877.3
843.7
27.6
1,888.6
848.9
30.6
Texas Gulf
Factor
11.127
11.152
11.220
11.224
11.231
11.299
MB/CD
3,968.6
1,942.3
58.6
3,977.5
1,946.6
65.2
4,001.7
1,958.5
81.9
4,003.2
1,959.2
82.0
4,005.7
1,960.4
82.0
4,029.9
1,972.3
78.2
West Coast
Factor
13.392
13.423
13.727
13.728
13.729
13.732
MB/CD
2,360.7
1,316.8
46.3
2,366.2
1,319.8
48.6
2,419.8
1,349.7
55.4
2.420.0
1,349.8
55.4
2,420.1
1,349.9
55.4
2,420.7
1,350.2
54.9
-------
In evaluating the penalties associated with any regulation, the
fixed inputs and outputs have both been considered as crude oil.
Product imports into the U.S.A. have been assumed to continue at
similar levels as experienced in 1973 in all the study years. Table G-7
gives the assumptions of atypical refinery inputs and outputs for 1977,
1980 and 1985. The atypical refinery data for PAD IV were based on the
assumption that total crude (plus condensate) was 90% of the rated calendar
day capacity for this district. Product outputs were then ratioed on the
basis of total output in each year compared with the calibration results.
The data for atypical refineries for the remaining PAD districts were based
on a 2% per annum escalation of the 1973 volumes, but assuming zero growth
from 1973 to 1975,
2. 1985 Scale Up
The cluster model input /output data for Scenarios A, B/C, D, E aitd F
is given in Table G-5. All input data and output data for each cluster
are the same for all scenarios with the exception of gasoline and LPG which
were allowed to vary from scenario to scenario.
The scale up of the cluster results is given in Table G-8. For
example, for the East Coast cluster, the amount of crude run in the L.P.
model was 197.915 MB/CD. The effective crude oil distillation capacity
for this region was 1506.17 MB/CD and therefore a scale up factor of 7.610
was used (the ratio of effective capacity over model crude run). The
atypical and import volumes are then added to the scaled up cluster volumes
to give total supply of products. These are then compared with the forecast
demand for the major product groups (Gasoline, Jet Fuel, Kerosene,
Distillate Heating Oil and Residual Fuel Oil) in order to derive the demand
for grassroots refining. For example, in Table G-8 tae total supply of
jet fuel from existing refineries in Districts I-IV in 1985 is 634,600
barrels per calendar day. The forecasted demand for all refineries
(existing plus additional capacity built by 1985) is 780,.000 barrels per
calendar day. Therefore, the jet fuel production required of the grass-
roots refineries in Districts I-IV was set at 145,400 barrels per calendar
day. The grassroots productions of kerosene, distillate fuel oil and
residual fuel oil were determined in a similar manner. The grassroots
G-12
-------
Table G-7. ATYPICAL REFINERY INTAKE/OUTTURN SUMMARY
(MB/CD)
Crude (+cond.)
C4's
Natural gasoline
Unfinished
Natural gas (FOE)
Total
Gas
LPG-fuel
LPG-petrochemical
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate
Lubes
Residual
Asphalt
Coke
Total
1973
PAD IV
442.8
9.4
4.6
0.2
11.9
468.9
0.4
6.0
0.2
228.2
8.0
0.1
14.5
6.0
115.1
1.3
27.0
30.5
3.9
441.2
Other3
220.0
-
-
-
-
220.0
-
-
-
. -
15.0
-
15.0
20.0
50.0
-
80.0
40.0
-
220.0
1977
PAD IV
455.2
8.5
4.2
0.2
8.9
477.0
0.4
6.1
0.2
232.1
8.1
0.1
14.8
6.1
117.1
1.3
27.5
31.0
4.0
448.8
Other3
228.9
-
-
-
-
228.9
-
-
-
-
15.6
-
15.6
20.8
52.1
-
83.2
51.6
-
228.9
1980
PAD IV
455.2
7.9
4.1
0.2
6.0
473.4
0.4
6.1
0.2
230.4
8.1
0.1
14.6
6.1
116.2
1.3
27.2
30.8
3.9
445.4
Other3
242.9
-
-
-
-
242.9
-
-
, -
- -
16.6
-
16.6
22.1
55.2
-
88.3
44.1
-
242.9
1985
PAD IV
455.2
7.0
3.6
0.2
.0
466.0
0.4
6.0
0.2
226.8
8.0
0.1
14.4
6.0
114.4
1.3
26.8
30.3
3.9
438.6
Other3
268.2
-
-
-
-
268.2
. -
-
-
-
18.3
-
18.3
24.4
61.0
-
97.5
48.8
-
268.3
aTotalof PADS 1,11, III and V.
G-13
-------
Table G-8. SCALE UP INPUT/OUTPUT - 1985
(MB/CO)
Fined intakes
Domestic crude
Imported crude
Subtotal
liobutane
Normal butane
Subtotal
Natural gasoline
Unfinished oils
Total
Fixed outturns
Gas/ethane-FOE
(.PC-petrochemicals
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke-market
Unfinished oils
Total
Variable outturns
Scenario Product
A Gasoline
LPG-fuel
AM products
B/C Gasoline
LPG-fuel
All products
O Gasoline
LPG-fuel
All products
E Gasoline
LPGfuel
All products
F Gasoline
LPG fuel
All products
Scale up factor
PAD Districts I-IV
East
Coast
-
1,506.1
1,506. t
1.9
9.4
11.3
44.4
130.0
1.691.8
6.8
32.4
10.0
10.7
45.2
26.6
357.3
38.8
100.7
142.3
-
770.8
843.1
30.3
1.644.2
813.6
46.6
1,631.0
815.2
49.2
1.635.2
798.9
70.2
1 .639.9
817.7
42.6
1.631.1
7.610
Large
Midwest
1,547.0
1.053.0
2.6000
46.9
-
46.9
11.8
33.9
2.692.6
_
-
38.2
16.6
37.5
29.3
721.2
_
130.6
67.4
65.1
1.105.9
1,420.1
49.9
2,575.9
1.388.6
73.6
2.568.1
1.359.9
82.3
2.548.1
1.342.7
98.3
2.546.9
1.356.3
76.8
2,539.0
18.125
Small
Midcont.
592.4
307.9
900.3
10.8
3.6
14.4
63.1
11.0
988.8
8.3
9.2
5.4
21.4
14.1
.6
245.4
5.2
3.5
27.7
20.0
360.8
576.4
22.4
969.6
557.5
28.2
946.5
541.5
27.7
9300
541.3
27.1
929.2
537.1
26.6
924.5
16.388
Louis.
Gulf
1,703.8
-
1,703.8
36.7
32.7
69.4
23.4
-
1,796.6
2.4
17.6
5.7
-
136.2
40.4
498.4
-
39.3
11.4
30.2
25 0
806.6
908.8
22.5
1.737.9
879.2
39.7
1,725.5
875.2
44.3
1.726.1
803.4
111.8
1,721.8
889.2
7.1
1,702.9
7.816
Texas
Guff
3,228.7
407.2
3.635.9
16.5
15.9
32.4
124.0
-
3,792.3
8.7
41.2
91.4
62.9
244.0
80.0
865.1
171.3
162.9
14.5
41.6
72 3
1.855.9
1 .740.9
59.7
3.656.5
1.686.4
88.7
3,631.0
1 ,690.8
87.0
3,633.7
1.573.6
177.1
3.606.6
1.692.2
840
3.633.0
11.071
Subtotal
I-IV
7.071.9
3.274.2
10.346.1
112.8
61.6
174.4
266.7
77.6
10.864.8
26.2
100.4
150.7
111.6
477.0
176.9
2.687.4
215.3
437.0
263.3
156.9
4,802.7
5.489.3
184.8
10.476.8
5.325.3
276.8
10,404.8
5.282.6
790.5
10.375.8
5.059.9
484.5
10.347.1
5.292.5
:".s n
10.333.2
-
A/T
723.4
7.0
3.6
.2
734.2
.4
.2
26.3
.1
32.7
30.4
175.4
1.3
124.3
79 1
3.9
;;4.i
226.8
6.0
706.9
226.8
6.0
706.9
226.8
60
706.9
226.8
6.0
706.9
226.8
6.0
706.9
-
Major
product
imports
124.9
2.2
381.0
1.797.7
2,305.8
130.2
2.436.0
130.2
2.436.0
130.2
2.436.0
130.2
2.436.0
130.:
2.436.0
-
Total
intake/
supply
11,069.5
181.4
270.3
77.8
11.599.0
26.6
100.6
177.0
111.7
634.6
209.5
3,243.8
216.6
2,359.0
342.4
160.8
7,582.6
5.846.3
190.8
13,619.7
5.682.3
282.8
13.547.7
5.639.6
296.5
13.518.7
5.416.9
490.5
13,490.0
5.C.13.5
244.0
13.476.1
-
Major
product
demand
780.0
252.3
3.948.0
2,852.0
7.832.3
7,050.3
7.050.3
7,050.3
7.050.3
7.060.3
-
Grass
Roots
required .
outturn
145.4
42.8
704.2
493.0
1,385.4
1,204.0
1.3680
1.410.7
1 .633.4
1.400.8
-
PAD District V
Cluster
scale up
1.996.9
_
1.996.9
4.3
1.4
5.7
11.1
67.3
2.081.0
5.7
16.2
47.4
48.6
247.7
2.1
27S.8
4.4
380.4
25.2
94.7
1,148.2
871.0
2.019.2
854.9
0.5
2.003.6
829.1
40.0
2,01 7.3
831.3
37.1
2.016.6
848.1
-
1,996.3
12.162
Major
product
imports
58.4
11.2
55.0
124.6
3.4
126.V-
3.4
128.T
3.4
128.0
3.4
128.0
3.4
128.0
-
Total
supply
5.7
16.2
47.4
48.6
306.1
2.1
287.0
4.4
435.4
25.2
94.7
1,272.8
874.4
-
2,147.2
858.3
0.5
2.131.6
832.5
40.0
2.145.3
834.7
37.1
2.144.6
851.5
_
2,124.3
-
Major
product
demand
399.8
379.6
571.8
1.351.2
1,123.9
2,475.1
1,123.9
2.475.1
1.123.9
2.475.1
1,123.9
2,475.1
1,123.9
2,475.1
-'
Grass
Roots
required
outturn
93.7
92.6
136.4
322.7
249.5
572.2
265.6
588.3
291.4
571.8
289.2
611.9
272.4
595.1
-
Total U.S.
Cluster
scale up
+t
A/T
13.066.4
187.1
281.4
145.1
13,680.0
32.3
116.8
224.4
160.3
757.4
209.4
3,138.6
221.0
941.7
367.6
255.5
6.425.0
6.587.1
190.8
13.202.9
6,407.0
283.3
13,115.3
6,338.5
336.5
13,100.0
6,118.0
527.6
13,070.6
6.367.4
244.0
13,036.4
-
Major
product
imports
183.3
2.2
392.2
1.852.7
2.430.4
133.6
2.564.0
133.6
2.564.0
133.6
2.564.0
133.6
2.564.0
133.6
2,564.0
-
Total
supply
32.3
116.8
224.4
160.3
940.7
211.6
3.530.8
221.0
2.794.4
367.6
255.5
8.855.4
6,720.7
190.8
15,766.9
6.540.6
283.3
15.679.3
6,472.1
336.5
15,664.0
6.251.6
527.6
15.634.6
6.501.0
244.0
15.600.4
-
Ma for
product
demand
1,179.8
252.3
4.327.6
3,423.8
9,183.5
8.174.2
8.174.2
8,174.2
8.174.2
8.174.2
-..
Oral
Roots
required
outturn
239.1
42.8
796.8
629.4
1,708.1
1.453.5
1.633.6
1.702.1
1.922.6
1.673.2
-
-------
production of gasoline varied from scenario to scenario because of the
effects of the proposed regulations but was also determined the same way.
The results of the scale up exercise indicated that 15 "new refineries"
(these can be new plants or additions to existing ones) with a capacity of
approximately 200,000 barrels per calendar day will be required to meet
East of the Rockies product demands by 1985. Three "new refineries" will
be required to meet West of the Rockies product demands by 1985. In
determining the L.P. model inputs for the grassroots cases, the grass-
roots volumes shown in Table G-8 were therefore divided by 15 for the East
of the Rockies model and by 3 for the West of the Rockies model.
The forecast product demand was derived by using a "simulated" product
demand pattern obtained by using the scaled up 1973 calibration output for
each cluster model combined with the atypicals and the 1973 imports (see
Appendix B). This was done to prevent minor discontinuities being
leveraged to result in unreasonable grassroots requirements.
This method of determining the demand for grassroots refining does
not consider the increased demand for specialty products and therefore the
total demand shown for grassroots refining in 1985 will be deficient by
the increased demand for specialty products. By comparison with Appendix B,
the simulated 1985 product demands are 92% of our forecast of total product
demand. The results for the grassroots refinery model runs have therefore
been scaled up by a further factor of 1.087 (1 divided by .92) to reflect
the need to meet total product demand.
3. 1980 Scale Up
The scale up for 1980 was done in an identical pattern to that for
1985. The scale up results are shown in Table G-9. The results showed
that 6 to 7 new grassroots refineries of approximately 200 MB/CD would be
required to meet the product demand of PAD I-IV by 1980, included in the
total of 15 refineries by 1985 discussed above. Again, these "new
refineries" include both major expansions of existing refineries and grass-
roots refineries.
Two new refineries would be required to meet PAD V product demands by
1980, included in the total of 3 refineries by 1985 discussed above.
G-15
-------
TABLE G-9. SCALE UP INPUT/OUTPUT - 1980
(MB/CD)
Fhwd firtrtn
Domeillc trude
Imported crude
Subtotal
Isobutane
Normal butane
Subtotal
Natural gasoline
Natural gas (FOE)
Unfinished oils
Total
Fixed outturns
Gas/ethane (FOE)
LPG-pet roc hem teals
Naphtha
BTX
Jet Fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke-market
Unfinished oils
Total
Variable outturns
Scenario Product
A Gasoline
LPG-fuel
All products
B Gasoline
LPG-fuel
All products
C Gasoline
LPG-fuel
All products
D Gasoline
LPG-fuel
All products
E Gasoline
LPG-fuel
Scale up factor
PAD DISTRICTS 1 IV
East
Coast
--
1.506.1
1.506.1
2.1
10.7.
12.8
44.4
9.5
130.0
. 1.702.8
6.8
32.6
10.1
10:7
45.5
26.8
359.6
39.0
10113
143.2
-
.-
775.6
848.7
30.1
1 .654.4
835.7
37.4
1.648.7
827.4
42.3
1.645.3
832.8
42.4
1.650.8
828.4
49.8
1 653 8
7.610
Large
1.682.2
917.8
2.600.0
53.7
-
53.7
13.5
2.2
33.9
2,703.3
_
-
38.3
16.7
37.6
29.5
724.1
_
131.2
67.6
65.3
-
1,110.3
1,425.3
50.9
2,586.5
1,4150
63.4
2,588.7
1,403.3
72.5
2.586.1
1,396.1
73.6
2,580.0
1,393.9
74.3
2 578 5
18.125
Small
Midcont.
646.4
253.9
900.3
12.3
4.1
16.4
72.1
16.8
11.0
1.016.6
8.5
9.4
5.5
22.0
14.5
0.6
252.4
5.3
3.6
28.5
20.6
-
370.9
593.6
20.7
930.2
587.9
25.7
984.5
581.3
31.9
984.1
580.7
32.D
984.1
B78.5
32.1
981 5
16.388
Louis.
Gulf
1,703.8
-
1,703.8
38.1
37.3
75.4
26.8
21.1
-
1.827.1
2.4
18.0
6.8
_
138.8
41.2
507.8
_
40.1
11.6
30.9
25.0
821.6
923.3
27.3
1,767.2
918.0
26.0
1,765.6
907.5
33.7
1 .762.8
902.8
35.5
1.759.9
897.6
37.3
1 756 5
7.816
Texas
Gulf
3,228.7
407.2
3,635.9
18.9
18.2
37.1
141.7
74.4
-
3.889.1
8.9
42.3
93.7
64.5
250.2
82.0
887.1
175.7
167.1
14.9
42.6
74.1
1,903.1
1 ,786.5
58.3
3.747.9
1,765.3
76.9
3,745.3
1,751.6
83.2
3,737.8
1 .749.9
84.1
3,737.1
1,747.8
84.3
3 735 2
11.071
Subtotal
1 IV
7,261.2
3,084.9
10.346.1
125.1
70.3
195.4
298.5
124.0
174.9
11,138.9
26.6
102.3
153.4
113.9
486.6
180.1
2.731.0
220.0
443.3
265.8
159.4
99.1
4 981 .5
^.577.4
182.3
10.741.2
5.521.9
229.4
10,732.8
5.471.0
263.6
10.716.1
5.462.3
268.1
10-11.9
5.446.2
277.8
10 705 5
A/T
698.1
7.9
4.1
6.0
0.2
716.3
0.4
0.2
24.7
0.1
31.2
28.2
171.4
1.3
115.5
74.9
3.9
-
451.8
230.4
61
688.3
230.4
6.1
688.3
230.4
6.1
688.3
230.4
6.1
688.3
230.4
6.1
688 3
Major
iroduct
imports
124.9
2.2
381.0
1.797.7
2,305.8
130.2
2.436.0
130.2
2.436.0
130.2
2.436.0
130.2
2,436.0
130.2
2 436 0
Total
intake/
supply
11,044.2
203.3
302.6
130.0
175.1
11.855.2
27.0
102.5
178.1
114.0
642.7
210.5
3.283.4
221.3
2.356.5
340.7
163.3
99.1
7,739.1
5.938.0
188.4
13,865.5
5,882.5
235.5
13.857.1
5.831.6
269.7
13,840.4
5,822.9
274.2
13,836.2
5,806.8
283.9
138298
I
Major
product
demand
706.5
228.5
3.575.8
2.583.1
7.O93.9
6,385.7
6.385.7
6.385.7
6,385.7
6,385.7
Grass
roots
required
outturn
63.8
18.0
292.4
226.6
600.8
447.7
503.2
554.1
562.8
578.9
PAD DISTRICT V
Cluster
scale-up
1,988.3
-
1,988.3
4.8
1.6
6.4
12.6
38.7
67.0
2,113.0
5.8
16.3
47.7
48.8
248.8
2.1
277.1
4.4
382.2
25.3
119.9
-
1.178.4
868.7
36.2
2,083.3
859.5
45.2
2,083.1
852.5
36.5
2,067.4
845.4
45.1
2.068.9
844.2
45.3
20679
12.110
Major
product
imports
58.4
_
11.2
55.0
124.6
3.4
128.0
3.4
128.0
3.4
128.0
3.4
128.0
3.4
128.0
Total
supply
5.8
16.3
47.7
48.8
307.2
2.1
288.3
4.4
437.2
25.3
119.9
-
1,303.0
8721
36.2
".-'1.3
862.9
45.2
2,21.. 1
855.9
36.5
2.195.4
848.8
45.1
2,196.9
847.6
45.3
2.1959
Major
product
demand
362.1
343.8
517.9
1,223.8
1,018.0
1.018.0
1,018.0
1,018.0
1,018.0
Grass
roots
required
outturn
54.9
55.5
80.7
191.1
145.9
155.1
162.1
169.2
170.4
TOTAL U.S..
Cluster
scale-up
+
A/T
13,032.5
209.7
315.2
168.7
242.1
13,968.2
32.8
118.8
225.8
162.8
766.6
210.4
3,179.5
225.7
941.0
366.0
283.2
99.1
6.61 1 .7
6.676.5
224.6
13.512.8
6,61 1 .8
280.7
13.504.2
6,553.9
306.2
13.471.8
6.538.1
319.3
13,469.1
6,520.8
329.2
13,461.7
Major
product
imports
183.3
2.2
392.2
1.852.7
2,430.4
133.6
2.564.0
133.6
2.564.0
133.6
2.564.0
133.6
2.564.0
133.6
2,564.0
Total
supply
32.8
118.8
225.8
162.8
949.9
212.6
3.571.7
225.7
2,793.7
366.0
283.2
99.1
9.042.1
6.810.1
224.6
16.076.8
6.745.4
280.7
16.068.2
6.687.5
306.2
16.035.8
6,671.7
319.3
16,033.1
6.654.4
329.2
16.025.7
Major
iroduct
demand
1.068.6
228.5
3,919.6
3,101.0
8,317.7
7.403.7
7,403.7
7.403.7
7.403.7
7.403.7
Grass roots
required
outturn
118.7
18.0
347.9
307.3
791.9
593,6
658.3
716.2
732.0
749.3
-------
E. SCALE UP OF CAPITAL INVESTMENTS
The scale up factors derived in the first part of this Appendix have
been used to scale up all the L.P. model results except the capital
investment requirements. In determining the capital investment requirements
on an aggregate U.S. basis it was fait that the requirements of the small
to medium refiner (refineries with capacities below 75,000 barrels per day)
would not be adequately reflected if the scale up factors derived in the
first part of this Appendix were applied to the cluster model capital invest-
ment requirements.
The only cluster model which represented the small to medium refiner
was the Small Midcontinent model. Based on the derived scale up factors the
investments resulting from this model would carry a weighting factor of 21%
of the total scaled up cluster model investments. In fact, refineries with
capacities less than 75,000 barrels per day represent some 30% of the total
U.S. refining capacity. To correct for the fact that the straightforward
scale up method would not fully account for the small refiners and based on
an aggregate of the study results obtained, the total cluster model invest-
ments (this does not include the grassroots model investment) were scaled
up by a further 17%.
This factor of 17% was derived by calculating the investment require-
ments associated with a particular regulation for each of the cluster models
on a dollar per barrel per day basis. Then, the total capital investment
penalty for the regulation was calculated by multiplying the dollar per
barrel capital requirement of the Small Midcontinent model by the capacity
of refineries in PAD I, for example, with a refinery capacity below 75,000
BPD. To this figure was added the dollar per barrel capital requirement for
the East Coast model multiplied by the capacity of refineries in PAD I with
individual refinery capacities above 75,000 BPD. When this procedure was
repeated for all PAD's, the total U.S. capital investment was found to be
17% above that obtained by a direct use of the scale up factors derived
earlier in this Appendix. When this procedure was used for the regulations
considered in the three companion reports, these deviations were found to
range from 15% to 21%. Therefore, a constant value of 17% was used for all
the regulations studied.
C-17
-------
APPENDIX H
TECHNICAL DOCUMENTATION
-------
TABLE OF CONTENTS
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
LIST OF TABLES
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
TABLE H-14. Stream Qualities - Foreign Crudes and Natural
Gasoline H-25
TABLE H-15. Stream Qualities - Miscellaneous Streams H-28
i
-------
APPENDIX H - (con't)
Page
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 Cost 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
ii
-------
APPENDIX H
TECHNICAL DOCUMENTATION
This appendix provides basic yields, blending properties, operating
costs and investment data which comprise the ADL Refinery Modeling System.
Over the past several years ADL has accumulated and continually updated a
data bank containing crude assays & other relevant data for refinery
simulation purposes. The sources for this basic data-are many and varied,
including technical literature, data received from clients for specific
projects, and internally developed information. Much of the basic gasoline
blending data was derived from an update of "U.S. Motor Gasoline Economics,
Volume 1, Manufacture of Unleaded Gasoline" published June 1, 1967 by
the American Petroleum Institute. In general, the simulation data presently
represents a consensus of individual data elements from different sources
which have been blended and in some cases modified based on our technical/
economic experience in this field.
A. CRUDE OIL PROPERTIES
Table H-l provides distillation yield data and selected product in-
spections for the various crude oils (and natural gasoline) used in this
study. For most of the crude oils, more than one crude assay was available
and the yields presented reflect a composite of the information available.
As can be seen in the table, the crude oil assay is divided into individual
light hydrocarbons through butanes (methane and ethane are combined to-
gether and presented as fuel oil equivalent barrels (FOE)*). Straight-run
naphtha is divided into four boiling fractions the lightest of which
(C5-160°F) can be isomerized or routed directly to motor gasoline blending.
*An FOE barrel is equivalent to 6.3 x 10 BTU gross heating value.
H-l
-------
The light naphtha fraction (160-200°F) can be reformed or blended to
gasoline. The medium naphtha fraction (200-340°F) must be reformed.
The heavy naphtha fraction (340-375°F) can be either reformed or blended
to middle distillate products.
Straight-run atmospheric gas oil is divided into two fractions - a
375-500°F product with suitable volatility characteristics for blending
to aviation turbine fuel and a 500-650°F heating/diesel oil component.
Atmospheric bottoms (650°+) is usually processed in a vacuum distillation
unit operating at an equivalent cut point of approximately 1,050°F.
Key properties for each crude oil fraction specifically used in the
model runs are shown in TablesH-13 andH-14. Other i/ropeities of these
fractions are a."1 so important in product blending, which were met by allowing
only suitable boiling range fractions to be blended into these products.
B. PROCESS DATA
Tables H-2 and H-3 provide basic yield dar.a for the catalytic reforming
simulations in the model. Product inspections are reported in Table H-15.
As noted previously, three different straight-run boiling fractions ca.i be
charged to reforming. Unit yields are provided for three severity levels
of operation - 90, 95, and 100 clear research octane number (RON) on the
C5 + reformate product.
The yields simulate bi-metallic catalyst operation at moderate (30C-
400 psig) reactor pressure. The hydrogen yield shewn in the table and i sed
in the model is the effective hydrogen production available for hydro-
treating purposes. This value is approximately 2/3 the stochiometric yield
of pure hydrogen and accounts for different operating factors for reforming
vs. various hydrotreaters, required purge volume and other inefficiencies
in refinery hydrogen usage. The stochiometric hydrogen not made available
for hydrotreating purposes is included with the ethane/methane stream to
refinery fuel.
Table H-2 presents reforming yield data for straight-run naphthas
while Table H-3 presents yield data for catalytic reforming of naphthas
H-2
-------
supplied from various conversion processes. Two heavy hydrocracked naphthas
are identified: one derived from straight-run gas oils (atmospheric or
vacuum) feeds and a second produced from cracked gas oil feedstocks (i.e.
catalytic cracking, coking, etc.) which produces a higher ring content
reformer feedstock. Other potential feeds to catalytic reforming are
medium coker naphtha and heavy catalytic cracked gasoline both of which are
hydrotreated.
Item Nos. 4, 10, 38, 40, and 43 in the Technical Documentation Reference
List provides process yield data on catalytic reforming. The ADL simulation
model data is not derived from any specific reference source and the referenced
articles are only noted to indicate the range of industry information avail-
able and that the selected ADL model data is representative of published
plant experience.
The yield data of Table H-2 are a simplified representation of reformer
operation, but do provide for ease of computer simulation. Because the
reformer simulation is critical to the present study, extensive computer
check runs were made with alternate yield data of Tables H-19 and H-20,
which represent improved reformer simulation. Check runs were conducted
on the Texas Gulf cluster model, which represents a major contribution to the
U.S. gasoline production. From these studies, it was concluded that the yields
of Table H-2 and H-3 were quite adequate in the present simulation studies.
Table H-4 provides yield data for catalytic cracking. Four different
yield structures are displayed for catalytic cracking - at low and high
severity operation, and for raw and hydrotreated feed. By utilizing a
weighted average of the data, operating severity for untreated feed can range
from 65-85% volume conversion, while that for hydrotreated feed can range from
72.5-95%. There are variations in C3/C4 olefin, isobutane, and gasoline
yields between cluster models, primarily to balance historical alkylation
operating levels. These catalytic cracking yields are based on operation
with zeolite catalysts. Item Nos. 5, 14, 15, 17, 38, 42, 43, 44, 46, and
47 in the Technical Documentation Reference List provide process yield
data for catalytic cracking.
H-3
-------
Hydrocracking yields are presented in Table H-5 for two severity
levels of operation - one producing maximum gasoline, and a low severity
operation producing approximately 60% jet fuel product. Yields from three
different feedstocks are shown for hydrocracking: atmospheric gas oil,
vacuum gas oil, and cracked gas oils (from catalytic cracking, coking, etc.).
Item Nos. 1, 3, 38, 43, and 45 in the Technical Documentation Reference
List provide process yield data for hydrocracking.
Table H-6 provides delayed coking yields for processing vacuum bottoms
feedstocks or heavy cycle oil from catalytic cracking. Variations exist
in gas oil and coke yields between cluster models to reflect the differing
crude slates for these models. Item Nos. 34, 36, 39, and 43 in the
Technical Documentation Reference List provide process yield data for
delayed coking.
Table H-8 provides yield data for hydrotreating operations while
selected product properties are shown in Table H-12. Vacuum and atmospheric
bottoms hydrotreating is allowed only in .the two grassroots models as it is
anticipated that this process will not be commo.ily installed in existing
plants. (See Appendix F) Therefore, data is provided for only two crudes -
Arabian Light for the East Coast and Alaskan North Slope for the West Coast.
Hydrotreating of Arabian Light atmospheric bottoms is shown producing 1%
and .5% sulfur product, and for vacuum bottoms 1% and .6 % sulfur. Alaskan
North Slope atmospheric bottoms may be desulfurized to .5% and vacuum
bottoms to .6%.
Table H-9 provides data on miscellaneous refinery process units,
including isomerization, alkylation, and aromatics extraction. Two operating
modes are available for isomerization, once-through and recycle. The alkylation
unit is assumed to charge a mixed C^/C, olefin stream containing about 1/3
C., olefins and 2/3 C, olefins. Aromatics extractions charging a reformate
produced from light naphtha (100-200°F) feedstock produces a 50/50 mix of
BTX/raffinate. The product mix declines to 25/75 when a heavier reformer
feedstock is used. Item Nos. 2, 6, 11, 13, 19, 38, and 43 in the Technical
Documentation Reference List provide process yield data for the above
miscellaneous refinery process units.
H-4
-------
Tables H-10 and H-ll provide hydrogen consumption data for hydrotreating
and hydrocracking. There are two hydrogen purity systems in the model. A
"normal purity" system of approximately 80% hydrogen purity is supplied
by catalytic reforming and is suitable for all hydrotreating use. (Only
about 2/3 of the stochiometric hydrogen produced by reforming is available
for hydrotreating use as noted in the reforming discussion in this section.)
Purification of this system for upgrading is not allowed in the model. A
"high purity" hydrogen system is required for hydrocracking use which must
be supplied by a synthetic hydrogen plant charging either natural gas or
naphtha feedstock. Hydrogen consumption for straight-run distillate and
residual streams is crude specific, varying with the properties of the
respective crude'fractions. Item Nos. 28, 29, 38, and 43 in the Technical
Documentation Reference List provide process yield data for hydrogen con-
sumption.
C. GASOLINE BLENDING QUALITIES
Tables H-13 through H-16 provide gasoline blending properties for
Reid Vapor Pressure (RVP), octanes, and sulfur contents. The original
source of much of the RVP and octane data was from the referenced API
study noted in the first paragraph in this section. In general, ADL took
the respective octane numbers for each non-straight-run component quoted
in the study and adjusted for blending bonuses by combining those for
premium and regular gasoline in a 1/3-2/3 ratio. The octane numbers thus
derived were submitted to an API/NPRA task force as well as to other industry
sources for review. Many verbal and written comments were received and the
numbers used in this study reflect the consensus of these comments. Item
Nos. 7, 8, 9, 16, and 41 in the Technical Documentation Reference List provide
industry comments on the gasoline blending octane numbers.
D. SULFUR DISTRIBUTION
The distribution of sulfur in the product streams for several units
is presented in Tables H-17 and H-18. Item Nos. 12, 18, 37, and 39 in
the Technical Documentation Reference List provide process yield data for
sulfur distribution.
H-5
-------
E. OPERATING COSTS
Tables H-21 through H-26 provide detailed unit consumptions and cost
coefficients of the individual elements that comprise refinery operating
costs. These include maintanence, labor, purchased catalysts and chemicals,
(including royalties) purchased electricity, steam, cooling water, and
refinery fuel. The unit consumptions are provided per barrel of intake
for each refinery process, except alkylation, which is per barrel of
alkylate.
Refinery steam requirements are balanced by a steam generating facility
which consumes additional refinery fuel. Cooling water requirements can
be purchased or supplied by a central refinery cooling tower. Unit con-
sumptions for crude and products handling are provided per barrel of total
crude oil charged to the refinery, and reflect operating costs associated
with receiving and storing crude oil, and blending, storage and loading of
finished products.
F. CAPITAL INVESTMENTS
Estimating investments for onsite and offs.Lte process units currently
is difficult because of the recent rapid rate of inflation and the long
time it takes to build a large, complete petroleum refinery. Nevertheless,
investment estimates were necessary and have been determined using data
from literature sources, from engineering contractors, and from internal
cost files.
In order to minimize the impact of estimates of inflationary factors
over the next decade, all investments used in the model were 1975 costs,
i.e. all materials and labor were costed on a first quarter, 1975 basis.
This is equivalent to a hypothetical case in which a refinery is designed,
equipment ordered, and constructed all within the year 1975. In Volume I
of the report, these costs are also reported for an assumed level of cost
escalation to more nearly reflect the actual costs that will be incurred
for the scenarios under evaluation, assumed to be 20%, 17%, 15%, 10%, 10%,
10.?;, 9%, 9%, 8%, 8%, 8% for the years 1975-1985.
H-6
-------
Onsite capital investments were estimated by the unit costs of Table
H-27. Variation of the unit investments with unit capacity utilized
the standard curves such as (reported by Nelson. Item Nos. 20, 21, 22,
27, 30, 31, 32,33, and 35 in the Technical Documentation Reference List
provide typical capital investment numbers.
In assessing refinery costs, units were costed individually using
the data of Table H-27. In addition, costs of capacity utilization and
severity upgrading were assessed, as discussed in Appendix E. Offsite
and working capital requirements for the cluster models were taken to be a
constant 40% of onsite costs. Offsite costs and working capital requirements
for the grassroots models were obtained by the Nelson complexity factor
approach, discussed in detail in Item Nos. 23, 24, 25, and 26 in the Technical
Documentation Reference .List. With this approach, working capital was taken
to be 70% of total onsite capital investment. In the cases considered, off-
sites and associated costs (including working capital) varied from 200-
300% of onsite costs.
In assessing the economic penalties associated with a regulation, a
capital-related penalty was taken to be 25%/year of the total capital invest-
ment. This capital charge, used for both cluster and grassroots models,
provides for return on invested capital, and is equivalent to roughly 12%
rate of return on an after tax, discounted cash flow basis. A discussion
of capital costs for small refiners appears in Appendix G.
H-7
-------
Table H-1. CRUDE AND NATURAL GASOLINE YIELDS;
CRUDE PROPERTIES
Yield, Volume %
Methane/ethane (FOE)
Propane
Isobutane
Normal butane
Straight-run naphtha:
C5-160°F
Light 1 60-200° F
Medium 200-340°F
Heavy 340-375° F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
. Vacuum overhead 650-1050°F
\ Vacuum bottoms 1050°F+
Crude properties
Gravity (°API )
< % Weight sulfur
Domestic crudes
Louisiana
-
.20
.40
.70
4.09
2.99
. 13.05
3.47
17.50
19.50
32.50
5 PC
36.2
.22
West
Texas
Sour
.04
.50
.40
1.30
5.70
3.80
15.50
3.30
13.39
14.11
29.60
12.30
33.4
1.63
Oklahoma
-
.48
.46
2.18
7.70
4.76
16.66
3.93
13.76
11.77
2C.04
10.25
40.2
.212 1
California
Wilmington
.002
.093
.095
.318
2.09
2.47
7.64
1.50
9.29
11.96
38.54
26.00
19.6
1.28
California
Ventura
.005
.400
.295
1.069
5.72
3.25
14.26
3.34
11.54
12.53
32.08
15.50
29.7
1.66
Alaskan
North
Slope
.06
.28
.13
.49
3.53
2.57
9.25
2.69
12.43
15.50
29.49
23.52
27.5
.96
Foreign crudes
Nigerian
Forcados
.04
.04
.51
.79
2.70
3.40
11.70
2.80
18.10
20.60
30.40
8.50
29.4
.21
Arabian
Light
-
.17
.17
1.06
4.85
3.27
14.93
3.95
13.39
15.01
29.50
13.70
34.5
1.7
Venezuelan
Tia Juana
.01
.59
.27
.45
3.89
2.20
9.09
2.52
10.30
12.70
32.80
25.00
26.3
1.61
Algerian
Hassi
Messaoud
.04
1.21
.53
3.27
8.29
5.00
21.19
5.02
15.78
11.92
22.71
4.99
44.7
.13
Mixed
Canadian
.05
1.13
.49
1.98
6.60
3.89
16.50
3.51
14.40
15.20
25.60
10.60
39.0
.55
Indonesian
Minas
.003
.139
.141
.379
1.70
1.60
9.10
2.60
10.70
15.00
41.00
18.00
35.3
.07
Natural
gasoline
-
-
4.71
7.58
62.02
13.99
11.70
-
-
-
-
-
. -
-------
Table H-2. YIELD DATA
Reforming of SR Naphtha
90 RON Severity
Stream8
Light feed (160-200°)
Hvdrogen (MSCF)b
Ethane/ methane (FOE)
Propane
Isobutane
Normal butane
90 Reformate
Medium feed (200-340°)
' Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Refoimate
Domestic crudes
Louisiana
.546
.0526
.0437
.0192
.0336
.8449
.660
.0496
.0291
.0111
.0218
.8808
.660
.0496
.0291
.0111
.0218
.8808
West Texas
Sour
.660
.0496
.0291
.0111
.0218
.8808
.748
.0515
.0069
.001
.0061
.9284
.748 "
.0515
.0069
.001
.0061
.9284
Oklahoma
.680 '
.0496
.0267
.0097
.0199
.8888
.660
.0496
.0291
.0111
.0218
.8808
.660
.0496
.0291
.0111
.0218
.8808
Calif.
Wilmington
.748
.0515
.0069
.001
.0061
.9284
.852
.0496
.0065
-
.0033
.9576
.852
.0496
.0065
.0001
.0032
.9576
Calif.
Ventura
.680
.0496
.0267
.0097
.0199
.8888
.790
.0507
.0067
.0006
.005
.9401
.790
.0507
.0067
.0006
.005
.9401
Alaskan
North Slope
.44-2
.0564
.0622
.0296
.0486
.7993
.790
.0507
.0067
.0006
.005
.9401
.790
.0507
.0067
.0006
.005
.9401
Foreign crudes
Nigerian
Forcados
'.719
.0495
.0220
.007
.016
.9049
.852
.0496
.0065
-
.0033
.9576
.852
.0496
.0065
.0001
.0032
.9576
Arabian
Light
.349
.0602
.0819
.0405
.0640
.7552
.442
.0564
.0669
.0318
.0487
.7993
.442
.0494
.0669
.0318
.0487
.7993
Venezuelan
Tia
Juana
.660
.0496
.0291
.0111
.0218
.8808
.704
.0506
.018
.006
.014
.9046
.704
.0506
. .018
.006
.014
.9046
Algerian
Hassi
Massaoud
.546
.0526
.0437
.0192
.0336
.8449
.660
.0496
.0291
.0111
.0218
:8808
.660
.0496
.0291
.0111
.0218
.8808
Mixed
Canadian
.704
.0495
.0238
.008
.0175
.8989
.790
.0507
.0067
.0006
.005
.9401
.790
.0507
.0067,
.0006
.005
.9401
Indonesian
Minas
.442
.0564
.0622
.0296
.0486
.7993
.442
.0564
.0622
.0296
.0486
.7993
.442
.0564
.0622
.0296
.0486
.7993
Natural
Gasoline
.546
.0526
.0437
.0192
.0336
.8449
.660
.0496
.0291
.0111
.0218
.8808
aLV fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydrotreating.
-------
Table H-2 (continued). YIELD DATA
Reforming of SR Naphtha
95 RON Seyerity_
Stream9
Light feed (160-200 I
Hydrou.M> (MSCF)b
Ethane/methane (FOE)
Propane .
Isobutane
Normal butane
95 Reformate
Medium feed (200-340°)
Hydroqen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
Heavy feed (340-375°)
Hydiocim (MSCF]b'
Ethane/methane (FOE)
Propanp
Isobutane
Normal butane
95 Reformate
Domestic crudes
Louisiana
.5') 6
.OGG
.064
.027
.043
.80
.660
.0656
.0441
.0161
.0288
.8428
.ceo
West Texas
Sour
.660
.0656
.0441
.0161
.0288
.8428
.748
.0675
.0219
.004
.0131
.8904
7-;3
.0656 .0675
.0441
.0161
.0288
.8428
.071!)
00-i
.OKU
.8904
Oklahoma
.680
.0656
.0405
.0141
.0263
.8505
.660
.0656
.0441
.0161
.0288
.8428
.660
.0056
044 1
.OIGI
.0288
.8428
Calif.
Wilmington
.748
.0675
.0219
.004
.0131
.8904
.852
.0656
.0099
-
.0044
.9103
.852
.OGGG
.oo'iy
.0044
.91(33
Calif.
Ventura
.680
.0656
.0405
.0141
.0263
.8505
.790
.0667
.0171
.0024
.0096
.9008
700
.0667
.0171
.0024
.0006
.5)008
Alaskan
North Slope
.442
.0654
.0819
.0368
.0557
.7613
.790
.0667
.0171
.0024
.0090
.90 Of)
.790
.0667
.0171
.0024
.009C,
.900!!
Foreign crudes
Nigerian
Forcados
.719
.0655
.0333
.0102
.0212
.8659
.852
.0656
.0099
--
.0044
.9163
.85?
.0656
.0099
-
.0044 '
9163
Arabian
Light
.349
.0646
.0983
.0457
.0673
.7262
.442
.0654
.0819
.0368
.0557
.7613
.442
.0654
.081!)
.0368
.0557
.7613
Venezuelan
Tia
Juana
.660
.0656
.0441
.0161
.0288
.8428
.704
.0666
.033
.01
.021
.8066
.704
.0666
.033
.01
.021
.8666
Algerian
Hassi
Messaoud
.546
.066
.064
.027
.043
.80
.660
.0656
.0441
.0161
.0288
.8428
.660
.0656
.0441
.0161
.0288
.8428
Mixed
Canadian
.704
.0655
.036
.0117
.0231
.8601
.790
.0667
.0171
.0024
.0096
.9008
.790
.0667
.0171
.0024
.0096
.9008
Indonesian
Minas
.442
.0654
.0819
.0368
.0557
.7613
.442
.0654
.0819
.0368
.0557
.7613
.442
.0654
.0819
.0368
.0557
.7613
Natural
Gasoline
.546
.066
.064
.027
.043
.80
.660
.0656
.0441
.0161
.0288
.8428
LV fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydiotieating.
-------
Table H-2 (continued). YIELD DATA
Reforming of SR Naphtha
100 ROM Severity
Stream"
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Norma! butane
100 Reformats
Medium feed (200-340°)
Hydiogen (MSCF)b
Ethane/methane (FOE)
Piopanc
Isoluilane
Normal butane
100 Refoimate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isohutane
Normal butane
100 Reformate
Domestic crqdai
Louisiana
.596
.080
.090
.035
.054
.745
.7520
.0815
.0715
.0245
.0404
.7848
,7520
.0815
0715
.0245
.0404
.7848
West Texas
Sour
.754
.0814
.0715
.0245
.0404
.7848
.838
.0813
.0508
.0129
.0253
.8292
.838
.0813
.0508
.0129
.0253
.8292
Oklahoma
.759
.0813
.0681
.0226
.038
.792
.7520
.0815
.0715
.0246
.0404
.7848
.7520
.0815
.0715
.0245
.0404
.7848
Calif.
Wilmington
.838
.0813
.0508
.0129
.0253
.8292
.910
.082
.0397
.0065
.017
.8533
.910
.082
.0397
.0065
.017
.8533
Calif.
Ventura
.759
.Q8 13
.Q681
.0226
.Q380
.7920*
.867
.0816
.0464
.0103
.0220
.8388
.B6-1
.0816
.0464
.0103
.0220
.8388
Alalkjn
North Slope
.487
.0788
.1066
.0444
.0662
.7089
.867
.0816
.0464
.0103
.022
.8388
.867
.0816
.0464
.0103
.02?
.8388
Foreign crudes
Nigerian
Forcados
.772
.0809
.0614
.0189
.0331
.8064
.910
082
.0397
.0065
017
H533
910
082
.0397
.0065
017
Arabian
Light
.394
.0784
.1218
.0530
.0773
.6762
.487
.0788
.1066
.0444
.0662
.7089
487
.0788
.1066
.0444
0662
.8533 | .7089
Venezuelan
Tia
Juana
.754
.0814
.0715
.0245
.0404
.7848
.795
.0814
.0612
.0187
.0329
.807
.795
.0814
.0612
.0187
.0329
.807
Algerian
Hassi
Messaoud
.596
.080
.090
.035
.054
.745
.7520
.0815
.0715
.0245
.0404
.7848
.7520
.0815
.0715
.0245
.0404
.7848
Mixed
Canadian
.767
.0811
.0639
.0203
.0349
.8010
.867
.0816
.0464
.0103
.0220
.8388
.867
.0816
.0464
.0103
.0220
.8388
Indonesian
Minas
.487
.0788
.1066
.0444
.0662
.7089
.487
.0788
1066
.0444
.0662
.7089
.487
.0788
.1066
.0444
.0662
.7089
Natural
Gasoline
.596
.080
.090
.035
.054
.745
.7520
.0815
.0715
.0245
.0404
.7848
3LV fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydrotreating.
-------
Table H-3. YIELD DATA
Reforming of Conversion Naphtha
Stream8
90 RON Severity
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformate
95 RON Severity
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
100 RON Severity
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
100 Reformate
Heavy hydrocracked naphtha
Straight run Cracked
gas oil feedc gas oil feed
.720
.0495
.0220
.007
.016
.9049
.720
.0655
.0333
.0102
.0212
.8659
.774
.0808
.0614
.0189
.0331
.8064
.852
.0496
.0065
-
.0033
.9573
.852
.0656
.0099
-
.0044
.9163
.910
.082
.0397
.0065
.017
.8533
Medium
coker
naphtha
.660
.0496
.0291
.0111
.0218
.8808
.660
.0656
.0441
.0161
.0288
.8428
.753
.0814
.0715
.0245
.0404
.7848
Heavy
cat.
naphtha
.660
.0496
.0291
.0111
.0218
.8808
.660
.0656
.0441
.0161
.0288
.8428
.753
.0814
.0715
.0245
.0404
.7848
aLV fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydrotreating.
clncludes atmospheric gas oils and vacuum overhead.
H-12
-------
Table H-4. YIELD DATA
Catalytic Cracking
(LV fraction on f(ed)
Stream
C.,/C4 Olefins
Propane
Isobutane
Normal butane
Cat. gasoline (C
Light cycle oil
Heavy cycle oil
C.,/C4 Olefins
Propane
Isobutane
Normal butane
Cat. gasoline 1C
Light cycle oil
Heavy cycle oil
050° F feed
ne (FOE)
s
IB
(C, to430°F)
1
>il
0°Ffeed
ne(FOE)
s
e
Cs to 430" F >
1
il
Low sev cat cracking
Louisiana
025
123
.018
046
008
.52
27
.08
.018
.147
.020
07
.012
.57
212
063
^ .
Texas
.025
128
.013
.046
.008
.52
.27
08
.018
.137
.020
.07
.012
.58
212
.063
Large
Midw.
.025
.099
.016
.069
.008
.52
.27
.08
.018
.137
.020
.07
.012
.58
.212
.063
Small
Midc.
.025
.128
.013
.066
.008
.50
.27
.08
.018
.137
.020
.08
.012
.57
.212
063
L . ...
East
Coast
.025
.098
.013
.051
.008
.538
.27
.08
.018
.137
020
07
.012
.58
.212
.063
West
Coast
.025
.098
.013
.051
.008
.538
.27
.08
.018
.137
.020
.07
.012
East
Grassroots
.025
.128
.013
.046
.008
.52
.27
.08
.018
.137
.020
.07
.012
.58 .58
.212 .212
063 .063
West
Grassroots
High sev cat cracking
Louisiana
.025 .048
.128
.013
.178
.03
.046 ' .09
.008 ' .022
.52 : .60
.27 ' .10
.08
.018
137
.020
.07
.012
58
212
.063
.05
a
Texas
.048
.178
.03
.09
.022
.60
.10
.05
a
Large
Midw.
.048
.159
.033
.103
022
.60
.10
.05
a
Small
Midc.
.048
.178
.03
.11
.022
.58
.17
.05
a
East
Coast
.048
178
.03
.09
.022
.60
.10
.05
a
West
Coast
.048
178
.03
.09
.022
.60
10
.05
a
East
Grassroots
.048
.178
.03
.09
.022
.60
.10
.05
.033
.191
.043
.128
.031
West
Grassroots
.048
178
.03
.09
.022
.60
10
.05
.03 i
91
043
128
.031
.669 ' .669
033
017
033
017
aHigh severity catalytic cracking of hydrotreated feed is not used in the cluster models.
-------
Table H-5. YIELD DATA
Hydrocracking
(LV fraction on feed)
Stream
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
Light gasoline
Heavy naphtha
Jet fuel
High severity
Heavy
G.O.
.004
.054
.144
.060
.364
.660
Vacuum
G.O.
.0057
.0768
.1520
.0630
.382
.692
Cracked
G.O.
.005
.067
.117
.052
.317
.780
Medium severity
Heavy
G.O.
.003
.040
.080
.045
.220
.252
.600
Vacuum
G.O.
.004
.050
.084
.048
.231
.265
.630
Cracked
G.O.
.003
.045
.070
.040
.200
.312
.610
H-14
-------
Table H-6. YIELD DATA
Coking
(LV fraction on feed)
Stream
Methane/ethane (FOE)
Propane
C^/C^ Olefins
Isobutane
Normal butane
Light coker naphtha
Meci. coker naphtha
Coker gas oil
Coke
Vacuum bottoms feed
Louisiana
.095
.02
.039
.008
.022
.105
.187
.410
.261
Texas
.095
.001
.039
.008
.022
.105
.187
.413
.258
Large
Midw.
.095
.02
.039
.008
.022
.105
.187
.381
.290
Small
Midc.
.095
.001
.039
.008
.022
.105
.187
.308
.363
West
Coast
.095
.001
.039
.008
.022
.105
.187
.428
.243
West
Grassroots
.095
.001
.039
.008
.022
.105
.187
.428
.243
Heavy cycle oil feed
Louisiana
.0743
.0007
.030
.006
.017
.080
.142
.594
.1275
Texas
.0743
.0007
.030
.006
.017
.080
.142
.5932
.1283
Large
Midw.
.0743
.015
.030
.006
.017
.080
.142
.560
.1615
Small
Midc.
.0743
.0007
.030
.006
.017
.080
.142
.560
.1615
West
Coast
.0743
.0007
.030
.006
.017
.080
.142
.560
.1615
West
Grassroots
.0743
.0007
.030
.006
.017
.080
.142
.560
.1615
I
M
VJ1
-------
Table H-7. YIELD DATA
Visbreaking
(LV fraction on feed)
Stream
1 050° F+ feed
Methane/ethane (FOE)
Propane
Isobutane
Normal butane
C3/C4 Olefins
Visbreaker naphtha
Visbreaker gas oil
Tar
West Coast cluster3
.0168
.0002
.002
.005
.005
.110
.4020
.4900
aVisbreaking not used in any other cluster or grassroots
model.
H-16
-------
Table H-8. YIELD DATA
Desulfurization
(LV Fraction on feed)
Stream
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
Naphtha
Desulfurized product
Light gasoline
Heavy gasoline
SR
naph
1.0
SR
gas
oil
.001
.001
.001
.008
.990
Coker
naph.
1.01
Vacuum
OVHD
.001
.001
.002
.002
.01
.995
Light
cycle
oil
.001
.001
.001
.008
.990
Cat
naph
.672
.336
Atm.
bottoms
to 0.5%
North
Slope
.0020
.0024
.0016
.0016
.0089
1 .0051
Atm.
bottoms
to
1.0%
Arab
Light
.0030
.0030
.0020
.0020
.0070
.9934
Atm.
bottoms
to
0.5%
Arab
Light
.0031
.0046
.0025
.0025
.0150
.9966
Vac.
bottoms
to
0.6%
North
Slope
.0041
.0041
.0028
.0028
.0160
1.008
Vac.
bottoms
to
1.0%
Arab
Light
.0041
.0041
.0028
.0028
.0160
1.008
Vac.
bottoms
to
0.6%
Arab
Light
.0049
.0072
.0039
.0039
.0145
1.022
-------
Table H-9. YIELD DATA
Miscellaneous Process Units
Stream3
Ethane/methane (FOE)
Isomerate
Alkylate
BTX aromatics
Raffinate .
Hydrogen (MSCF/Bbls)
Sulfur
Sulfur oxides
Isomerization
Single Recycle
0.023
0.965
0.036
0.945
Alkylation
C3/C4 Olefinsb
1.77
Aromatics extraction
1 60-200° F 200-340° F
feed feed
0.5
0.5
0.25
0.75
Hydrogen from
natural gas (FOE)
feed
23.9
Sulfur recovery
95% 99.95%
(Wgt fraction (Wgt fraction
on feed) on feed)
0.894
0.094
0.941
0.009
I
I
00
aLV fraction on feed unless otherwise noted.
Isobutane consumption 1.19 per unit volume Cj/C4 olefin feed.
-------
Table H-10. HYDROGEN CONSUMPTION DATA
Desulfurization of Crude-specific Streams
(MSCF/Bbl feed)
Stream
Normal purity hydrogen
SB naphtha
Light gas oil
Heavy gas oil
Vacuum overhead
High purity hydrogen
Atmospheric bottoms
to 1.0% sulfur
to .5% sulfur
Vacuum bottoms
to 1.0% sulfur
to .6% sulfur
Domestic crudes
Louisiana
.105
.140
.150
.300
West
Texas
Sour
.105
.190
.250
.300
Oklahoma
.105
.140
.150
.300
California
Wilmington
.105
.140
.150
.300
California
Ventura
.105
.140
.150
.300
Alaskan
North
Slope
.105
.140
.150
.300
.330
.860
Foreign crudes
Mixed
Canadian
.105
.170
.250
.300
Arabian
Light
.105
.170
.250
.300
.530
.600
.860
1.060
Nigerian
Forcados
.105
-a-
a
.300
Algerian
Hassi
Messaoud
.105
.150
-a-
.300
Venezuelan
Tia Juana
.105
.170
.250
.300
Indonesian
Minas
.105
.140
.150
.300
ac
i
Not desulfurized.
-------
Table H-11. HYDROGEN CONSUMPTION DATA
Hydrocracking and Desulfurization of Model-Specific Streams
(MSCF/Bbl feed)
Stream
Normal purity hydrogen
Light cycle oil
Coker naphthas
Cat. gasoline
High purity hydrogen
High sev hydrocracking
Heavy gas oil feed
Vacuum gas oil feed
Cracked gas oil feed
Medium sev hydrocrackina
Heavy gas oil feed
Vacuum gas oil feed
Cracked oil gas feed
Louisiana
.220
.600
.600
1.90
2.45
3.10
1.70
7.83
2.70
Texas
.220
.600
.600
1.95
2.50
3.15
1.75
1.88
2.75
Small
Midc.
.220
.600
.600
1.90
2.45
3.10
1.70
1.83
2.70
Large
Midwest
.220
.600
.600
1.95
2.50
3.15
1.75
1.88
2.75
West Coast
.220
.600
.600
1.95
2.50
3.15
1.75
1.88
2.75
East Coast
.220
i .600
.600
1.95
2.50
3.15
1.75
1.88
2.75
West
Grassroots
.220
.600
.600
1.95
2.50
3.15
1.75
1.88
2.75
East
Grassroots
-sour
.220
.600
.600
1.95
2.50
3.15
1.75
1.88
2.75
East
Grassroots
-sweet
.220
.600
.600
1.90
2.45
3.10
1.70
1.83
2.70
I
ro
O
-------
Table H-12. SULFUR REMOVAL
Levels in Desulfurization
Stream
Effluent Stream
sulfur, %'
a
Comment
Isomerization feed
C5 to 160°F
Reformer feed
Light SR naphtha (160-200°F)
Medium SR naphtha (200-340°F)
Heavy SR naphtha (340-375° F)
Heavy hydrocrackate
Heavy cat. naphtha
Coker naphtha
Cat. feed
Vacuum overhead
Heavy atomospheric gas oil
Coker gas oil
Other streams
Light atmospheric gas oil
Heavy atmospheric gas oil
Cat. cycle oil
Atmospheric bottoms
Alaskan North Slope
- Arabian Light
Vacuum bottoms
Alaskan North Slope
Arabian Light
1 PPM
1 PPM
1 PPM
1 PPM
1 PPM
1 PPM
1 PPM
0.2
0.2
0,2
l% feed sulfur
5% feed sulfur
15% feed sulfur
0.5
1.6/0.5
0.6
1.0/0.6
Level required for isomeri-
zation feed.
Level required for reformer
feed.
Desulfurization to 0.2% wt.S
or 85% feed sulfur removal
(whichever is lower).
Two processes (correspond-
ing to the two sulfur levels
listed) exist in model.
Two processes (correspond-
ing to the two sulfur levels
listed) exist in model.
= Percent, unless otherise noted.
H-21
-------
Table H-13. STREAM QUALITIES
Domestic Crudes
Stream
Louisiana
Full r.iruie naphtha
Cb to VOO°F
C5 to-160°F
light 160-200° F
Medium 200-340°F
Heavy 340-375°F
o
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1050 F
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
West Texas Sour
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
Atmospheric gas oil 375-650 F
Light gas oil 375-500° F
Heavy gas oil 500-650 r
o
Atmospheric bottoms 650 F +
Vacuum overhead 650-1050 f
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
Specific
gravity
.7511
.693
.668
.727
.762
.816
.837
.8220
.8504
.9108
.8974
.9881
.65
.64
.7587
.691
.664
.732
.793
.794
.8440
.8251
.8633
.9467
.9167
1.0187
65
.64
Sulfur
content,
% weight
.0072
.0021
.0002
.0045
.0093
.0089
.0649
.0362
.0901
.4175
.3221
.9207
.0001
.0001
.1496
.0364
.0288
.0466
.1610
.3790
.9i46
.5787
1.2187
2.2145
1.8513
3.0018
.0001
.0001
Viscosity^
4.53
15.18
9.04
20.68
31.74
28.75
49.14
4.53
14.44
8.32
20.26
35.09
28.51
50.92
Smoke
point,
mm.
22.5
20.0
22.0
18.0
Gasoline blending qualities
R.V.P.
8.1
11.0
4.1
11.5
12.0
8.9
11.5
5.0
12.0
12.5
RON
Clear
70.8
73.0
67.8
82.1
90.0
67.8
72.1
61.4
81.0
89.0
0.5 cc
78.2
80.6
75.3
88.0
94.0
77.0
79.8
72.5
86.9
93.0
3.0 cc
88.8
91.0
85.8
96.0
99.9
89.3
90.5
87.5
95.0
98.9
MON
Clear
68.5
71.2
64.8
82.8
86.8
58.6
65.7
48.0
79.0
85.0
0.5 cc
76.8
79.6
73.0
87.8
92.5
67.2
74.3
59.0
83.9
90.5
3.0 cc
88.2
90.8
84.6
94.3
100.2
84.8
86.2
82.7
91.0
98.0
Mid-fill blend number,
% distilled at
150°F
41.0
91.3
0.0
93.0
95.0
51.0
91.3
0.0
93.0
95.0
210°F
95.0
100.0
99.0
105.0
100.0
98.0
100.0
99.0
100.0
100.0
a:
i
rsj
N3
! Refutiis hli'ndmg values tor viscosity '" centistokes (9)122 F.
-------
Table H-13 (continued). STREAM QUALITIES
Domestic Crudes
Stream
Oklahoma
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650° F
o
Atmospheric bottoms 650 F+
Vacuum overhead 650-1050°F
Vacuum bottoms 1050 F +
Once through isomerate
Recycle isomerate
California Wilmington
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
Q
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
Vacuum bottoms 1050°F+
Once through isomerate
Recycle isomerate
Specific
gravity
.7315
.665
.643
.701
.763
.809
.838
.825
.854
.9080
.8970
.9380
.65
.64
.763
.689
.643
.728
.794
.832
.881
.860
.898
.9929
.966
1.033
.637
.635
Sulfur
content,
% weight
.0074
.0022
.0002
.0051
.0105
.0090
.0912
.0572
.1296
.3306
.2327
.5883
.0001
.0001
.0472
.0098
.0100
.0097
.0446
.1543
.6867
.3823
.9124
1.6557
1.3126
2.1311
.0001
.0001
Viscosity3
4.53
15.18
9.04
20.68
31.74
28.75
49.14
3.71
19.0
11.78
24.89
44.4
33.84
58.34
Smoke
point,
mm.
_
22.9
16.3
Gasoline blending qualities
R.V.P.
10.2
14.2
3.7
14.7
15.2
6.4
10.5
2.9
11.0
11.5
RON
Clear
70.3
70.7
69.7
80.3
88.7
83.1
85.9
80.7
89.0
93.1
0.5 cc
77.5
78.4
76.4
86.0
92.5
87.8
90.2
85.8
94.1
97.0
3.0 cc
87.7
88.9
85.8
93.7
98.1
94.6
96.5
93.0
101.4
103.3
MON
Clear
69.6
69.7
69.4
81.8
86.4
79.7
82.3
77.5
87.5
89.1
0.5 cc
76.3
77.0
75.4
85.8
91.5
84.8
87.4
82.7
91.3
94.2
3.0 cc
85.9
87.0
84.1
91.8
98.4
92.1
94.3
90.2
96.8
101.6
Mid-fill blend number,
% distilled at
150"f=
41.0
91.3
0.0
93.0
95.0
41.0
91.3
0.0
93.0
95.0
2lO°f
95.0
100.0
99.0
105.0
100.0
95.0
100.0
99.0
105.0
100.0
5C
ro
Rpfutas blending v.ilues lor viscosity in centistokes 122 F.
-------
Table H-13 (continued). STREAM QUALITIES
Domestic Crudes
Stream
California Ventura
Full range naphtha
C5 to 200°F
C5 to 160° F
Light 1 60-200° F
Medium 200-340°F
Heavy 340°-375°F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
Alaskan North Slope
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
o
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650° f-
o
Atmospheric bottoms 650 F ^
-Desulf to .5% wgt sulfur
Vacuum overhead 650-1 050°F
Vacuum bottoms 1050 F^
Desulf to .6% wgt sulfur
Once through isomerate
Recycle isomerate
Specific
gravity
.7471
.6824
.6429
.7519
.7746
.8034
.8521
.8392
.8640
.9676
.9350
1.035
.6399
.6379
.7518
.6801
.6526
.7179
.7807
.8151
.8601
.3349
.8803
.9581
.937
.9281
.9957
.945
.645
.64
Sulfur
content,
% weight
.1006
. .0209
.0200
.0224
.1019
.2769
.7334
.2797
1.1393
2.4672
1.5411
4.1959
.0001
.0001
.0177
.0147
.0105
.0199
.0160
.0291
.32U1
.1615
.4547
1.5310
.5000
1.1029
2.0313
.6000
.0001
.0001
Viscosity3
3.25
11.4
7.09
14.9
37.39
31.9
48.76
1.7
12.5
8.3
15.9
39.4
36.5
33.2
47.3
43.0
Smoke
point.
mm.
24.1
19.0
21.85
17.9
Gasoline blending qualities
R.V.P.
8.9
11.9
3.6
12.4
12.9
7.0
8.7
4.7
9.2
9.7
RON
Clear
78.8
80.4
76.0
86.7
92.3
72.2
75.5
67.7
83.6
90.6
0.5 cc
85.2
86.5
83.0
92.7
96.5
78.0
81.0
74.0
87.8
93.7
3.0 cc
94.0
94.7
92.8
101.0
102.9
86.4
89.0
82.8
93.8
98.2
MON
Clear
74.8
76.2
72.3
85.6
87.8
70.3
73.6
65.8
84.3
87.3
0.5 cc
81.5
82.7
79.5
89.7
93.2
76.5
79.6
72.4
87.7
92.2
3.0 cc
91.0
91.8
89.6
95.5
100.7
85.5
88.1
81.9
92.7
98.9
Mid-fill blend number,
% distilled at
150°F
41.0
91.3
0.0
9.3.0
95.0
41.0
91.3
0.0
93.0
95.0
210°F
95.0
100.0
99.0
105.0
100.0
95.0
100.0
99.0
100.0
100.0
I
r-o
Refutiis hli'nding values for viscosity in cnntistokes &>^22 F.
-------
Table H-14. STREAM QUALITIES
Foreign Crudes and Natural Gasoline
Stream
Nigerian Forcados
Full range naphtha
C5 to 200° F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
Vacuum bottoms 1050 F +
Once through isomerate
Recycle isomerate
Arabian Light
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160- 200° F
Medium 200-340°F
Heavy 340-375° F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
-Desulf. to 1.0% sulfur
--Desulf. to .5% sulfur
Vacuum overhead 650-1050 F
Vacuum bottoms 1050 F+
-Desulf. to 1.0% sulfur
-Desulf. to .6% sulfur
Once through isomerate
Recycle isomerate
Specific
gravity
.762
.702
.670
.727
.780
.816
.874
.854
.891
.954
.942
.998
.667
.665
.7335
.669
.657
.686
.7554
.797
.8278
.8072
.8463
.9484
.920
.9117
.9154
1.0195
.9567
.9478
.654
.652
Sulfur
content,
% weight
.0072
.0001
.0001
.0001
.0053
.0281
.1452
.0790
.2015
.3845
.3125
.6265
.0001
.0001
.0292
.0231
.0220
.0247
.0266
.0487
.6849
.2203
1.0807
3.0820
1.000
.5000
2.3215
4.5530
1.000
.6000
.0001
.0001
Viscosity
4.53
14.14
9.38
18.15
35.00
31.25
47.65
4.53
11.786
7.09
15.98
34.31
32.0
30.86
28.51
46.79
46.79
46.79
Smoke
point,
mm.
22.5
21.0
27.0
23.0
Gasoline blending qualities
R.V.P.
8.1
1i.O
5.8
11.5
12.0
9.0
11.0
6.0
11.5
12.0
RON
Clear
77.1
81.0
74.0
87.0
92.5
60.5
66.0
52.3
78.0
87.0
0.5 cc
81.8
86.0
78.7
92.5
96.3
69.0
74.0
58.5
83.6
93.0
3.0 cc
89.0
92.8
86.0
100.0
102.2
80.8
85.6
73.7
91.5
97.0
MON
Clear
73.5
77.0
70.7
86.0
88.0
59.4
64.5
51.8
78.2
84.5
0.5 cc
79.0
82.5
76.3
89.3
93.0
67.0
71.9
57.9
81.8
89.2
3.0 cc
87.0
90.0
84.6
Mfd-f III blend number,
% distlliad at
150°F
41.0
91.3
0.0
i
94.2
99.8
78.7
82.2
73.5
87.1
96.0
93.0
95.0
53.5
91.3
0.0
93.0
95.0
210°F
95.0
100.0
99.0
105.0
100.0
100.0
100.0
99.0
105.0
100.0
I
ro
ui
Q
iiiis blending values for viscosity in centistokes @>122 F.
-------
Table H-14. (continued). STREAM QUALITIES
Foreign Crudes and Natural Gasoline
Stream
Venazualan Tia Juana
Full range naphtha
C5 to 200°F
C5 to 1609F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
Vacuum bottoms 1050°F+
Once through isomerate
Recycle isomerate
Algerian Hassi Messaoud
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375° F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Q
Atmospheric bottoms 650 F+
Vacuum overhead 650-1050°F
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
Specific
gravity
.7362
.682
.659
.723
.7628
.7708
.8473
.826
.865
.966
.922
1 .0236
.65
.64
.738
.678
.657
.716
.764
.788
.834
.3.0
.866
.910
.892
.990
.654
.652
Sulfur
content.
% weight
.0190
.0078
.0046
.0129
.0238
.0261
.4599
.1900
.6690
2.1999
1.6292
2.8743
.0001
.0001
.0070
.0021
.0002
.0051
.0091
.0092
.?449
.0201
.0756
.3502
.2249
.8655
.0001
.0001
Viscosity3
3.25
11.4
7.09
14.9
39.07
29.73
51.32
1.76
9.38
3.25
17.51
30.48
26.97
46.49
Smoke
point,
mm.
25.0
21.0
22.0
24.0
Gasoline blending qualities
R.V.P.
10.6
14.0
4.6
14.5
15.0
8.2
9.9
5.4
10.4
10.9
RON
Clear
67.2
70.3
61.7
80.1
88.5
65.0
68.7
b8.9
79.2
87.9
0.5 cc
/6.0
"'S.S
69.7
86.6
93.0
73.0
76.5
65.0
84.9
91.9
3.0 cc
88.0
90.7
83.2
95.3
99.3
84.2
87.5
78.7
92.7
97.6
MON
Clear
67.2
70.3
61.7
82.2
86.5
61.5
66.8
52.7
79.8
85.4
0.5 cc
76.4
79.3
71.0
87.7
92.5
70.8
74.9
60.7
' 84.5
90.7
3.0 cc
88.7
91.4
83.9
95.2
100.5
83.6
86.3
79.1
91.1
98.0
Mid-fill blend number,
% distilled H
150°F
75.0
91.3
0.0
93.0
95.0
57.0
91.3
0.0
93.0
95.0
210°F
100.0
100.0
99.0
105.0
100.0
100.0
100.0
99.0
105.0
100.0
a
i
"Hetut-is bl01'dini) values for viscosity in cemistokes <9>122 F.
-------
Table H-14. (continued). STREAM QUALITIES
Foreign Crudes and Natural Gasoline
Stream
Mixed Canadian
Full range naphtha
C5 to 200° F
C5tp160°F
Light 1 60-200° F
Medium 200-340°F
Heavy 340-375°F
o
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
Indonesian Minas
Full range naphtha
C5 to 200°F
C5 to 160°F
Light 160-200°F
Medium 200-340°F
Heavy 340-375°F
Atmospheric gas oil 375-650 F
Light gas oil 375-500°F
Heavy gas oil 500-650°F
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
o
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
Natural gasoline
C5 to 200°F
C5 to 160° F
Light 160-200°F
Medium 200-340°F
Once through isomerate
Recycle isomerate
Specific
gravity
.7386
.6845
.6643
.7187
.7619
.7911
.8405
.8239
.8562
.9349
.915
1.020
.65
.64
.7400
.6690
.650
.6892
.7521
.7877
.8134
.80
.823
.8886
.864
.9433
.647
.645
.672
.643
.727
.762
.637
.630
Sulfur
content,
% weight
.0543
.0422
.0406
.0448
.0529
.0917
.3102
.1720
.4362
.8636
.7121
1 .4303
.0001
.0001
.0092
.0013
.0002
.0024
.0115
.0101
.0255
.0120
.0349
.1051
.0890
.1387
.0001
.0001
.0020
.0010
.0045
.0093
.0001
.0001
Viscosity3
4.53
15.18
9.04
20.68
31.74
28.75
49.14
2.0
11.43
6.7
14.8
33.2
29.17
42.4.
Smoke
point,
mm.
28.8
25.6
31.3
27.5
,
Gasoline blending qualities
R.V.P.
11.7
15.5
5.5
16.0
16.5
9.4
10.6
8.13
11.1
11.6
10.8
12.0
4.1
12.5
13.0
RON
Clear
75.3
76.5
73.3
84.3
91.0
63.7
67.5
59.7
78.6
87.4
78.9
79.5
67.8
86.2
92.0
0.5 cc
79.8
80.7
78.0
87.7
93.7
72.7
76.2
69.2
84.7
91.7
84.0
84.6
75.3
92.4
96.3
3.0 cc
86.3
87.2
84.8
92.5
97.5
85.1
88.0
82.0
93.1
97.7
93.5
94.1
85.8
100.8
102.8
MON
Clear
73.9
74.8
72.4
84.9
87.6
60.2
61.8
58.5
76.8
83.2
77.8
78.3
64.8
86.5
88.3
0.5 cc
77.6
78.5
76.2
86.5
91.4
71.0
73.0
68.5
83.5
90.0
81.7
81.9
73.0
89.6
93.1
3.0 cc
83.3
84.2
81.8
89.1
96.9
85.6
88.0
83.0
92.6
98.8
89.9
90.0
84.6
94.2
99.8
Mid-fill bland number,
% distilled at
150°F
41.0
91.3
0.0
93.0
95.0
41.0
91.3
0.0
93.0
95.0
53.5
91.3
0.0
93.0
95.0
210>
95.0
100.0
99.0
105.0
100.0
95.0
100.0
99.0
105.0
100.0
105.0
100.0
99.0
105.0
100.0
I
N3
Retinas blending values for viscosity in centistokes @122 F.
-------
Table H-15. STREAM QUALITIES
Miscellaneous Streams
Stream
Chemical compounds8
Propane
Isobutane
Normal butane
Process streams
90 Sev. reformate
Light SR feed
Medium SR feed
Heavy SR feed
Hydrocracked naphtha feed
Coker naphtha feed
Cat. naphtha feed
95 Sev. Reformate
Light SR feed
Medium SR feed
Heavy SR feed
Hydrocracked naphtha feed
Coker naphtha feed
Cat. naphtha feed
100 Sev. reformate
Light SR feed
Medium SR teed
Heavy SR feed
Hydrocracked naphtha f ^ou
Coker naphtha feed
Cat. naphtha feed
Specific
gravity
.508
.563
.584
.78
.79
.79
.79
.79
.79
.79
.80
.80
.80
.80
.80
.80
.81
.81
.81
.81
.31
Sulfur
content,
% weight
rtegl.
negl.
negl.
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.UJ01
.0001
Smoke
point
R.V.P.
76.0
59.0
9.0
5.3
1.3
6.4
4.3
4.3
9.2
5.5
1.5
6.7
4.5
4.5
9.5
5.8
1.8
7.0
4.8
4.8
Gasoline blending qualities
RON
Clear
100.5
92.0
90.5
90.5
90.5
90.5
90.5
90.5
95.3
95.3
95.3
95.3
95.3
3o.3
99.8
3rf.8
99.8
99.8
99.8
99.8
0.5 cc
104.4
96.5
93.7
93.7
93.7
93.7
93.7
93.7
97.2
97.2
97.2
97.2
97.2
97.2
101.8
101.8
101.8
101.8
101.8
101.8
3.0 cc
109.0
103.2
97.8
97.8
97.8
97.8
97.8
97.8
100.2
100.2
100.2
100.2
100.2
100.2
102.9
102.9
102.9
102.9
102.9
102.9
MOM
Clear
95.8
89.0
80.1
80.1
80.1
80.1
80.1
80.1
82.1
82.1
82.1
82.1
82.1
82.1
86.0
86.0
86.0
86.0
86.0
86.0
I
0.5 cc
101.3
94.4
82.9
82.9
82.9
82.9
82.9
82.9
84.7
84.7
84.7
84.7
84.7
84.7
88.0
88.0
88.0
88.0
88.0
88.0
3.0 cc
106.3
102.0
87.1
87.1
87.1
87.1
87.1
87.1
88.5
88.5
88.5
88.5
88.5
88.5
91.0
91.0
91.0
91.0
91.0
91.0
Mid-fill blend number,
% distilled at
150°F
115.0
115.0
12.2
2.6
-.7
4.2
3.0
3.0
13.5
3.6
-.5
6.6
3.6
3.6
17.0
6.5
2.4
9.7
6.5
6.5
210°F
110.0
110.0
93.1
17.4
.5
22.0
17.8
17.8
94.5
18.5
1.0
24.5
18.5
18.5
96.2
20.2
2.7
26.2
20.2
20.2
KJ
OO
-------
Table H 15. (continued). STREAM QUALITIES
Miscellaneous Streams
Stream
Process Stream* (continued)
Light hydrocrackate
Heavy hydrocrackate
SR gas oil feed
Cracked gas oil feed
Hydrocracked jet fuel
Desulfurized cat. gasoline
Light
Heavy
Alkylate
BTX raffinate
Light SR feed (160-200°F)
Medium SR feed (200-340°F)
Specific
gravity
.68
.76
.76
.812
.705
.793
.699
.692
.777
Sulfur
content,
% weight
.0001
.0004
.0004
.0004
.0003
.0004
.0004
.0001
.0001
Smoke
point,
mm.
30.0
15.0
26.0
Gasoline blending qualities
R.V.P.
13.1
11.0
.5
3.5
4.2
1.6
RON
Clear
85.6
78.0
56.0
95.0
61.6
87.1
0.5 cc
90.6
83.4
65.0
98.6
70.6
91.4
3.0 cc
97.3
93.1
83.2
105.4
83.4
96.4
MON
Clear
82.4
77.0
58.0
89.8
62.6
78.2
0.5 cc
88.9
81.6
65.0
95.3
67.1
81.0
3.0 cc
98.1
90.7
79.2
103.9
83.6
88.5
lUlirl fill hlanrl MllrMha*
IVIIO-TIII Dienu numoorf
% distilled at
150°F
78.0
40.0
-20.0
1.5
2.0
0.0
210°F
100.0
90.4
- 8.0
29.3
77.0
0.0
I
K)
^ell-defined chemical compounds whose qualities are constant.
Streams whose qualities are a function of the processing unit rather than the feed stream (with the exception of reformate whose specific gravity varies with feed
gravity).
-------
Table H-16. STREAM QUALITIES
Variable Sulfur Streams3
Stream
Cat. cracked gasolines
Low sev, raw feed
High sev, raw feed
Low sev, treated feed
High sev, treated feed
Light cycle oil
Heavy cycle oil .
Cat. feed - desulfurized
Light coker naphtha
Desulfurized
Medium coker naphtha
Desulfurized
Coker gas oil
Coke
Visbreaker gasoline
Visbruaker flas oil
Visbieaker tar
Specific
gravity
.753
.757
.755
.758
.8956
.9448
varies
.677
.677
.765
.761
.844
-
.735
.837
.910
Viscosity
16.46
22.55
28.75
16.48
16.46
22.10
..
Gasoline blending qualities
R.V.P.
6.2
6.2
6.2
6.2
16.2
15.0
1.2
3.3
RON
Clear
92.0
93.0
93.0
93.0
78.0
77.0
55.0
62.3
0.5 cc
94.8
95.8
95.8
95.8
83.3
82.3
SC.'i
6>122°F.
-------
Table H-17. SULFUR DISTRIBUTION
Coker and Visbreaker
(% feed sulfur)
Unit
Coker- 1 050° F+ feed
H2S
Light gasoline
Heavy gasoline
Gas oil
Coke
Total
Visbreaker - 1050°F+ feed
H2S
Gasoline
Gas oil
Tar
Total
Sulfur distribution
34.4
1.2
3.4
30.3
30.7
100.0%
10.0
.8
29.2
60.0
100.0%
H-31
-------
Table H-18. SULFUR DISTRIBUTION
Catalytic Cracking
(% feed sulfur)
Case/feed
Casel - all crude VOH's
Case 2
Crude independent VOH
Crude dependent
Louisiana VOH
West Texas Sour VOH
Oklahoma VOH
Calif. Wilmington VOH
Calif. Ventura VOH
Alaskan North Slope
VOH
Nigerian Forcados
VOH
Arabian Light VOH
Venezuelan Tia Juana
VOH
Algerian Hassi Messaoud
VOH
Mixed Canadian VOH
Indonesian Minas VOH
Process
conversion,
% LV feed3
65
72.5
85
95
72.5
65
85
65
85
65
85
65
85
65
85
65
85
65
85
65
85
65
85
65
85
65
85
65
85
Output Stream
H2S
40.0
44.0
50.0
52.0
20.0
41.7
48.7
38.1
45.1
41.7
48.7
55.4
62.4
55.4
62.4
49.2
56.2
41.7
48.7
41.7
48.7
38.1
45.1
41.7
48.7
41.7
48.7
48.8
55.8 .
Gasoline
6.0
6.5
7.0
7.5
3.5
5.0
4.0
4.1
3.1
5.0
4.0
10.1
9.1
10.1
9.1
7.6
6.6
5.0
4.0
4.4
3.4
4.1
3.1
5.0
4.0
5.0
4.0
7.4
6.4
Light cycle
oil
33.0
30.0
21.0
19.5
34.5
18.0
13.8
31.0
26.8
18.0
13.8
23.7
19.5
23.7
19.5
20.5
16.3
Heavy cycle
oil
15.0
13.5
14.0
13.0
33.5
30.5
26.3
23.5
19.3
30.5
26.3
9.8
5.6
9.8
5.6
19.5
15.3
18.0 30.5
13.3
24.1
19.9
31.0
26.8
18.0
13.8
18.0
13.8
13.9
9.7
26.3
20.3
16.1
23.5
19.3
30.5
26.3
30.5
26.3
12.4
8.2
Cokeb
6.0
6.0
8.0
8.0
8.5
4.8
7.2
3.3
5.7
4.8
7.2
1.0
3.4
1.0
3.4
3.2
5.6
4.8
7.2
9.5
11.9
3.3
5.7
4.8
7.2
4.8
7.2
17.5
19.9
Total
100.0%
100.0%
100.0%
100.0%
1 00.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
Conversion levels vary as follows: untreated feed, low severity (65%) and high severity (85%); treated feed, low severity (72.5%) and
high severity (95%).
Equivalent to SO production.
H-32
-------
Table H-19. ALTERNATE YIELD DATA
High and Low Severity Reforming of SR Naphtha
90 RON Severity
Stream3
Light feed (160-200°)
Hydrogen
-------
Table H-19 (continued). ALTERNATE YIELD DATA
High and Low severity Reforming of SR Naphtha
95 RON Severity
Stream8
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
Medium feed (200-340°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
High prersure (450 psi)
Louisiana
.84
.0488
.077
.0334
.0494
.76
1,06
.0275
.0375
.0172
.0243
.847
1.095
.0228
.o29
.0138
.01R8
.868
West Texas
Sour
.825
.0525
.0845
.0365
.0542
.745
1.02
.0325
.0468
.0208
.0302
.825
1.06
.0275
.038
.0174
.0245
.847
Nigerian
Forcados
1.095
.0228
.029
.0134
.0188
.868
1.085
.0247
.0322
.0152
.021
.86
1.13
.019
.0225
.0112
.0148
.886
Arabian
Light
.445
.0847
.146
.063
.0927
.624
.72
.0614
.1014
.0437
.0645
.712
.935
.043
.0651
.0284
.0419
.783
Venezualan
Tia Juana
.89
.0467
.0727
.0316
.0467
.768
.985
.0372
.055
.0241
.0354
.806
1.02
.0325
.0468
.0208
.0303
.825
Low pressure (225 psi)
Louisiana
1.255
.0286
.0498
.0206
.0301
.806
1.36
.0128
.0231
.0097
.014
.877
1.37
.0103
.0168
.0075
.0105
.894
West Texas
Sour
1.215
.0328
.054
.0227
.0333
.794
1.35
.0155
.0298
.0122
.0175
.858
1.36
.013
.0233
.0098
.0142
.C76
Nigerian
Forcados
1.37
.0103
.0168
.0075
.0105
.894
1.366
.0110
.0185
.0079
.0115
.8915
1.375
.0085
.012
.0057
.0085
.909
Arabian
Light
.860
.0735
.0885
.0413
.0628
.6960
1.127
.0430
.0626
.0275
.0407
.7690
1.310
.0221
.0433
.0172
.0251
.8240
Venezualan
Tia Juana
1.275
.0262
.0475
.0193
.0283
.812
1.33
.0186
.0365
.0146
.0212
.841
1.35
.0155
.0298
.0122
.0175
.858
LV Fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydrotreating.
-------
Table H-20. ALTERNATE YIELD DATA
High and Low Pressure Reforming of Conversion Naphtha
Stream3
90 RON Severity
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformate
95 RON Severity
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
100 RON Severity
Hydrogen (MSCF)b
High pressure (450 psi)
Heavy hydrocracked
naphtha
Straight run
gas oil feed0
1.05
.0147
.0175
.0083
.0105
.9050
1.095
.0228
.029
.0138
.0188
.8680
1.17
Ethane/methane (FOE) 1 .037
Propane ! .i>47
Isobutane
Normal butane
100 Reformate
.0206
Cracked gas
oil feed
1 .045
.0165
.0203
.0095
.012
.898
1.085
.0247
.0322
.0152
.021
.86
1.13
.0385
.0505
.02°
.03 .032
.8210
.813
Medium
Coker naphtha
1.02
.0185
.025
.0114
.0158
.8860
1.06
.0275
.0375
.0172
.0243
.8470
1.105
.0406
.Ooti
.0245
.0357
.8020
Heavy
Cat. naphtha
1.02
.0185
.025
.0114
.0158
.8860
1.06
.0275
.0375
.0172
.0243
.8470
1.105
.0406
.056
.0245
.0357
.8020
Low pressure (225 psi)
Heavy hydrocracked
naphtha
Straight run
gas oil feed0
1.2^
.002
.0035
.001
.0025
.933
1.37
. .0103
.0168
.0075
.0105
.894
1.48
.0175
.037
.0140
.022
.851
Cracked gas
oil feed
1.255
.0028
.0049
.0020
.0030
19310
1.366
.0110
.0185
.0079
.0115
.8915
1.479
.0185
.0382
.0148
.0229
.8480
Medium
Coker naphtha
1.24
.0055
.0098
.0043
.0064
.917
1.36
.0128
.0231
.0097
.014
.877
1.475
.0211
.042
.0142
.0243
.835
Heavy
Cat. naphtha
1.24
.0055
.0098
.0043
.0064
.917
1.36
.0128
.0231
.0097
.014
.877
1 .475
.0211
.042
.0142
.0243
.835
LV Fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydrotreating.
Includes atmospheric gas oils and vacuum overhead.
-------
Table H-19 (continued). ALTERNATE YIELD DATA
High and Low Severity Reforming of SR Naphtha
100 RON Severity
Stream
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
100 Reformate
Medium feed (200-340°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
100 Reformate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
100 Refoimate
High pressure (450 psi)
Louisiana
.89
.0577
.097
.0424
.0621
.716
1.105
.0406
.056
.0245
.0357
.802
1.17
.037
.047
.0206
.03
.821
West Texas
Sour
.85
.0608
.1045
.0455
.0667
.702
1.06
.0447
.0658
.0288
.0422
.781
1.105
.0408
.0564
.0247
.036
.801
Nigerian
F oread os
1.17
.037
.047
.0206
.03
.821
1.13
.0385
.0505
.022
.032
.813
1.185
.0342
.0401
.0174
.025
.835
Arabian
Light
.447
.0877
.166
.0726
.1055
.588
.74
.0683
.1215
.0530
.0773
.671
.965
.053
.0856
.0374
.0547
.738
Venezuelan
Tia Juana
.92
.056
.0928
.0405
.0594
.723
1.02
.0482
.0743
.0326
.0477
.762
1.06
.0446
.0658
.0288
.0422
.781
Low pressure (225 psi)
Louisiana
1.39
.0394
.063
.026
.0383
.761
1.475
.0211
.042
.0142
.0243
.835
1.48
.0175
.037
.014
.022
.851
West Texas
Sour
1.355
.044
.0661
.0282
.0418
.75
1.47
.0242
.0475
.0181
.0264
.817
1.475
.0212
.0422
.0163
.0245
.834
Nigerian
Forcados
1.48
.0175
.037
.0140
.022
.851
1.479
.0185
.0382
.0148
.0229
.8480
1.480
.0153
.0329
.0129
.021
.864
Arabian
Light
1.030
.0881
.0930
.0485
.0781
.6600
1.273
.0550
.0729
.0333
.0511
.7270
1.445
.0325
.0579
.0227
.0328
.7790
Venezuelan
Tia Juana
1.41
.0368
.061
.0248
.0363
.767
1.46
.0285
.0526
.0203
.0293
.798
1.47
.0242
.0475
.0181
.0264
.817
LV Fraction on feed unless otherwise noted.
Effective hydrogen yield available for hydrotreating.
-------
Table H-21. OPERATING COST CONSUMPTIONS
Reforming
(per Bbl intake)
90 Severity
Maintenance (S)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
95 Severity
Maintenance (S)
Labor (shift positions)
Catalyst and chemicals (S)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
100 Severity
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
Straight-run
naphtha
Clusters
.06
.0001
.04
3.0
.001
.6
.05
.062
.0001
.06
3.2
.001
.7
.05
.064
.0001
.10
3.5
.001
.8
.05
G.R.a
.06
.0001
.04
3.0
.001
.45
.05
.062
.0001
.06
3.2
.001
.5
.05
.064
.0001
.10
3.5
.001
.55
.05
Heavy hydrocracked naphtha
Straight-run
gas oil feed
Clusters
.06
.0001
.04
3.0
.001
.6
.05
.062
.0001
.06
3.2
.001
.7
.05
.064
.0001
.10
3.5
.001
.8
.05
G.R.a
.06
.0001
.04
3.0
.001
.45
.05
.062
.0001
.06
3.2
.001
.5
.05
.064
.0001
.10
3.5
.001
.55
.05
Cracked gas oil
feed
Clusters
.06
.0001
.04
3.0
.001
.6
.05
.062
.0001
.06
3.2
.001
.7
.05
.064
.0001
.10
3.5
.001
.8
.05
G.R.a
.06
.0001
.04
3.0
.001
.45
.05
.062
.0001
.06
3.2
.001
.5 .
.05
.064
.0001
.10
3.5
.001
.55
.05
Medium coker
naphtha
Clusters
.06
.0001
.04
3.0
.001
.6
.05
.062
.0001
.06
3.2
.001
.7
.05
.064
.0001
.10
3.5
.001
.8
.05
G.R.a
.06
.0001
.04
3.0
.001
.45
.05
.062
.0001
.06
3.2
.001
.5
.05
.064
.0001
.10
3.5
.001
.55
.05
Heavy
Cat. naphtha
Clusters
.06
.0001
.04
3.0
.001
.6
.05
.062
.0001
.06
3.2
.001
.7
.05
.064
.0001
.10
3.5
.001
.8
.05
G.R.a
.06
.0001
.04
3.0
.001
.45
.05
.062
.0001
.06
3.2
.001
.5
.05
.064
.0001
.10
3.5
.001
.55
.05
I
J
Grassroots.
-------
Table H 22. OPERATING COST CONSUMPTIONS
Catalytic Cracking
(per Bbl intake)
Maintenance (S)
Labor (shift positions)
Catalyst & chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
Hydrotreated feed
Low severity
Clusters
.049
.00015
.04
2.0
.001
1.0
.024
Grassroots
.049
.00015
.04
2.0
.001
.8
.024
High severity3
Grassroots
.051
.00015
.08
2.4
.001
1.0
.048
Raw feed
Low severity
Clusters
.049
.00015
.04
2.0
.001
1.0
.02
Grassroots
.049
.00015
.04
2.0
.001
.8
.02
High severity
Clusters
.051
.00015
.08
2.4
.001
1.2
.04
Grassroots
.051
.00015
.08
2.4
.001
1.0
.04
aHigh severity catalytic cracking of hydrotreated feed is not used in the cl'jstei models.
-------
Table H-25. OPERATING COST CONSUMPTIONS
Miscellaneous Process Units8
(per Bbl intake)
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
Make-up water
Sulfur recovery units
95%
Recovery
.56
.028
6.0
80.0
4.0
.4
2.4
99.95%
Recovery
1.06
.028
7.6
346.0
3.93
.48
2.9
Isomerization
Once thru
.03
.0002
.085
2.4
.01
.3
.03
Recycle
.06
.0002
.12
4.8
.01
.3
.03
H Manufacture
Clusters
0.032
0.00014
0.005
0.17
0.001
0.1
0.031
Grassroots
0.032
0.00014
0.005
0.17
0.001
0.1
0.031
0.011
ffi
I
.(S
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
Coking
.086
.0002
.002
1.5
.03
.6
.03
Visbreaking
.0231
.0002
.0021
1.0
.02
.5
.03
Alkylationd
.094
.0003
.2
3.7
.03
2.0
.1
Aromatics
extraction
.05
.004
.132
2.0
.4
.4
.005
Atmospheric
distillation
.008
.00002
.001
.25
.023
.5
.01
Vacuum
distillation
.009
.00005
.002
.20
.03
.20
.01
Crude and
products
handling
.032
.00008
.001
1.0
.02
.2
.01
'' All models.
11 Consumption per ton of sulfur recovered. Includes associated costs required to achieve specified recovery level.
c Consumption per MSCF of hydrogen product.
Consumption per Bbl product.
-------
Table H-26. OPERATING COSTS COEFFICIENTS
Regional Supply Cost per Unit Coefficient
($ per unit)
Louisiana Gulf
Texas Gulf
West Coast
Large Midwest
Small Midcontinent
East Coast
West Grassroots
East Grassroots
Maintenance
1.32
1.32
1.32
1.39
1.39
1.44
1.38
1.38
Labor
(shift positions)
473.0
473.0
473.0
473.0
473.0
520.3
500.0
500.0
Electricity
(KWH)
.0144
.0144
.018
.018
.018
.0215
.02
.02
Catalyst and
chemicals
1.1
1.1
1.1
1.1
1.1
1.21
1.15
1.15
Cooling
water3
(M gallons)
.044
.044
.044
.044
.044
.048
Make-up
water6
(M gallons)
.35
.35
I
*^
NJ
aCluster models purchase cooling water.
Grassroots models generate cooling water in a cooling tower which consumes purchased make-up water to
compensate for evaporation iosses.
-------
Table H-27. PROCESS UNIT CAPITAL INVESTMENT ESTIMATES
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 (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
estimate
S/B/SD
165
185
925
800
1400
620
1240
1400
235
320
230
250
370
775
1500
930
230a
260a
25000
50000
aS/MSCF/SD
I1-43
-------
Table H-28. OFFSITE AND OTHER ASSOCIATED COSTS OF REFINERIES USED IN ESTIMATING COST OF
GRASSROOTS REFINERIES
1st Quarter 1975 Basis
(% onsite cost)
Typfe of cost
Mainly complexity-related offsites, %
Includes utilities, piping, blending.
product handling, buildings, roads, site
preparation, safety and fire.
Other offsites, %
Includes tankage, ecology and land
Offsites-subtotal %
Associated costs
Chemicals and catalysts
Marine or equivalent facilities
Working capital
/"V + Krt V
utner
Includes training, spares.
telephone, autos, domestic water.
cafeteria and recreation.
Associated subtotal %
Refinery complexity
3
138.0
87.0
225.0
6.0
20.0
116.0
4
103.0
67.0
170.0
5.0
15.5
110.5
5
88.9
59.0
147.9
4.5
12.8
107.3
6
- -
74.7
51.0
125.7
4.0
10.0
/u.u
*>n n ---
/U.U
104.0
7
70.4
48.0
118.4
3.8
8.8
102.6
8
64.9
44.2
109.1
3.5
7.8
101.3
9
61.7
42.0
103.7
3.3
6.8
100.1
10
57.4
39.0
96.4
3.0
5.8
^
98.8
-------
Technical Documentation Reference List
1. Alcocak, L., et al. , "BP Hydi.ocrac.ks for Middistillates",
Oil and Gas Journal July, 1974, pp. 102-110.
2. Anderson, R.F., "Changes Keep HF Alkylation Up-To-Date".Oil and Gas Journal,
February, 1974, pp. 78-81.
3. "BP Adds Hydrocracking To It's Lavera Refinery", Petroleum & Petrochemical
International, November, 1973, pp. 66-69.
4. Bernstein, J-L- Dauber, "Flexibility and Capability of Powerforming Are .
Extended", Oil and Gas Journal, September, 1968, pp. 163-167.
5. Blazek, James, "Zeolitic Catalyst Prooved On Natural Stock", Oil and Gas
Journal, November, 1971, pp. 66-73.
6. Bour, George, C.P. Schwoerer, G.F. Asselin, "Penex Unit Peps Up SR Gasoline",
Oil and Gas Journal, October, 1970, pp. 57-61.
7." Dupont, (letter from), to Mr. Marshall Nicols, Re: NPC study on factors
affecting U.S. petroleum refining, October, 1974.
8. Dupont, (letter from), to Mr. W.A. Johnson, Re: Motor octane blending
values for. reformate, February, 1975.
9. Ethyl Corporation, (letter from), to Gilbert H. Wood, Re: Simulation studies
for E.P.A., gasoline component blending values, December, 1974.
10. Gould, G.D., C.S. McCoy, "Rheniforming Scores High In Commercial Runs",
Oil and Gas Journal, November, 1970, pp. 49-53.
11. Hainsselin, M.H., M.F, Symoniak, G.R. Cann, "Strategy of Isomerization,"
Hydrocarbon Processing, April, 1975, pp. 62-H - 62-T.
12. Ruling, G.P., et al., "Feed-Sulfur Distribution in FCC Product",
Oil and Gas Journal, May, 1975, pp. 73-79.
13. "Hysomer May Ease Lead Elimination", Oil and Gas Journal, March, 1971,
pp. 44-45.
14. Jones, H.B., "Modern Cat Cracking for Smaller Refineries", Oil and Gas Journal,
December, 1969, pp. 50-53.
15. Magee, et al., "Catalyst's Developments in Catalytic Cracking"
Oil and Gas Journal, July, 1973, pp. 48-54.
16. Marathon Oil Company, (letter from), to Mr. Marshall W. Nicols,
Re: Comments as to ADL's octane data and gasoline blending, September, 1974,
17. Murphy, J.P., M.R. Smith, C.H. Vienes, "Hydrocracking Vs. Cat Cracking for
Gas Oils in Today's Refinery", Oil and Gas Journal, June, 1970, pp. 108-112.
H-45
-------
18. "NPRA Panel", Hydrocarbon Processing, March, 1971, pp. 96-98.
19. "NPRA Panel", Oil and Gas Journal, February, 1971, p. 63.
20. Nelson, W.L., "Costs of Alkylation and Viscosity-Breaking Plants are Updated",
Oil and Gas Journal, April, 1974, pp. 74-75.
21. , "Cost of Catalytic-Cracking Plants", Oil and Gas Journal,
April, 1974, pp. 66-67.
22. > "Cost Examination for Coking Plants", Oil and Gas Journal,
April, 1974, pp. 118-119.
23 } "Cost of Refineries - Part 1: Offsite Facilities", Oil and Journal,
July, 1974, pp. 114-116.
24. , "Cost of Refineries - Part 2: Process-Unit Costs", Oil and Gas Journal,
July, 1974, p. 87
25.-- , "Cost of Refineries - Part 3: Off-Sites Breakup", Oil and Gas Journal,
July, 1974, pp. 60-61.
26. , "Cost of Refineries - Part 4: Storage, Environment, Land",
Oil and Gas Journal, July, 1974, pp. 160-162.
27. , "Hydrocracking, Hydrogen-Manufacture Costs", Oil and Gas Journal,
March, 1974, pp. 120-124.
28. > "Hydrogen Consumption In Treating", Oil and Gas Journal,
January, 1972, p. 67.
29. , "How Much Hydrogen Is Consumed in Treating", Oil and Gas Journal,
December, 1970, pp.
30. > "A Look at Catalytic Reforming", Oil and Gas Journal, April, 1974,
pp.
31. , "A Look At Sulfur-Recovery Costs", Oil and Gas Journal,
March, 1974, pp. 120-123.
32. ," A Look at Vacuum-Distillation Costs", Oil and Gas Journal,
March, 1974. p. 100.
33. , "Plant Costs For Processing Hydrogen", Oil and Gas Journal,
March, 1974, pp. 111-112.
34. ,."What Are Coking Yields", Oil and Gas Journal, January, 1974, p. 70.
35. , "What's Happening To Refinery-Construction Costs?", Olj^ and Gas Journal,
February, 1974, pp. 70-71.
36. 'Petroleum Coke Takes On New Luster", Oil and Gas Journal, September, 1970,
pp. 73-76.
H-46
-------
37. Production of Low Sulfur Gasoline, Contract// 68-02-1308, Task 10,
Phases 1, 2, 3, can be obtained by writing to M.W. Kellogg Company,
1300 Tree Greanway Plaza Kast, Houston, Texas, 77046.
38. "1974 Refining Process Handbook", Hydrocarbon Processing, September, 1974,
pp. 107-113, 116-119, 128-131, 207-208, 211-213.
39. Rose, K.E., "Delayed Coking - What You Should Know", Hydrocarbon Processing,
- July, 1971, pp. 85-92.
40. Stockey, A. Nelson, Richard F. Bauman, "Cyclic Powerforming Ups Octane",
Hydrocarbon Processing, May 1971, pp. 106-110.
41. Texaco, (letter from), to Mr. George Holzman, Re: Gasoline blending data
used by Arthur D. Little for various lead studies for the E.P.A.,
November, 1974.
42. "Two New Intermediate Activity Catalysts Developed", Oil and Gas Journal,
October, 1971, pp. 82-83.
43. U.S. Motor Gasoline Economics, Volume 1, Manufacture of Unleaded Gasoline,
American Petroleum Institute,1967.
44. Wachtel, S.J., et al., "Atlantic Richfields Lab Unit Apes Fluid Catalytic
Cracker", Oil and Gas Journal, April, 1972, pp. 104-107.
45. Ward, J.W., A.D. Reichle, J. Sosnowski, "Catalyst Advance Open Doors for
Hydrocracking", Oil and Gas Journal, May, 1973, pp. 69-73.
46. Whillington, E.L., Murphy, I.H. Lutz, "Striking Advances Show Up In
Modern FCC Design", Oil and Gas Journal, October, 1972, pp. 49-54.
47. white, Paul, J., "How Cracker Feed Influences Yield", Hydrocarbon Processing,
May, 1968, pp. 103-108.
H-47
-------
APPENDIX I
MODEL CALIBRATION
-------
TABLE OF CONTENTS
APPENDIX I - MODEL CALIBRATION
Page
A. BASIC DATA FOR CALIBRATION !_!
1. Refinery Input/Output j^
2. Processing Configurations I-IQ
3. Product Data 1-18
4. Calibration Economic Data 1-21
B. CALIBRATION RESULTS FOR CLUSTER MODELS 1-22
LIST OF TABLES
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
TABLE 1-4. Bureau of Mines Refinery Fuel Consumption for
Cluster Models 1973 ................................ 1-5
TABLE 1-5. ADL Model Input/Outturn Data for Calibration ....... 1-7
TABLE 1-6. Conversion of BOM Input/Outturn Data to ADL
Model Format ....................................... 1-8
TABLE 1-7. ADL Model Crude Slates and Sulfur Contents for
Refinery Clusters .................................. l-li
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
-------
LIST OF TABLES - (cont.)
Paee
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 - Calibration Results ... 1-32
TABLE 1-18. Texas Gulf Cluster Model - Calibration Results 1-33
TABLE 1-19. Large Midwest Cluster Model - Calibration Lesults .... 1-34
TABLE 1-20. Small .Midcontinent Cluster Model - Calibration
Results 1-35
TABLE 1-21. West Coast Cluster Model - Calibration Results 1-36
TABLE 1-22. East Coast Cluster Model - Calibration Results 1-37
TABLE 1-23. Louisiana Gulf Calibration - Gasoline Blending
Summary 1-39
TABLE 1-24. Texas Gulf Calibration - Gasoline Blending
Summary 1-40
TABLE 1-25. Small Midcontinent Calibration - Gasoline Blending
Summary 1-41
TABLE 1-26. Large Midwest Calibration - Gasoline Blending
Summary 1-42
TABLE 1-27. West Coast Calibration - Gasoline Blending Summary ... 1-43
TABLE 1-28. East Coast Calibration - Gasoline Blending Summary ... 1-44
LIST OF FIGURES
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
ii
-------
LIST OF FIGURES - (cont.)
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
iii
-------
APPENDIX I
MODEL CALIBRATION
Upon completion of the development of the cluster refinery modeling
concept, which is discussed in Appendix F, an extensive calibration effort
was undertaken by Arthur D. Little (ADL) with the assistance of the Bureau
of Mines (BOM), Environmental Protection Agency (EPA), and an ad hoc
industry task force coordinated by the American Petroleum Institute (API)
and National Petroleum Refiners Association (NPRA).
A. BASIC DATA FOR CALIBRATION
1. Refinery Input/Output
Every refiner in the United States provides monthly statistics to the
BOM concerning refinery inputs, production and a summary of fuel consumed
for all purposes. The BOM accumulates and summarizes this data on a monthly
and annual basis, and publishes aggregate statistics by PAD district, BOM
refining district, and in some cases by state.
For this project, the BOM supplied EPA with 1973 annual data for the
aggregate of the three specific refineries comprising each individual cluster
model (see Appendix F). This data as received from the BOM is presented in
Tables 1-1, 1-2, and 1-3.
Table 1-1 contains the refinery input/output data for the year 1973 in
the standard BOM reporting format.
Table 1-2 provides a breakdown of refinery crude receipts by origin,
by individual state for domestic crudes, and by country for foreign sources.
Tables 1-3 and 1-4 provide statistics on fuel consumed for all purposes in
the cluster model refineries for the year 1973.
1-1
-------
Table 1-1. BUREAU OF MINES REFINERY IN:'ir /OUTPUT DATA FOR CLUSTER MODELS: 1973
1. Crude oil (including lease condensate)
a. Domestic
b. Foreign
2. Products of natural gas processing plants
a. Propane
b. Isobutane
c. Normal butane
d. Other butanes
e. Butane-propane mixtures
f. Natural gasoline and ispoentane
g. Plant condensate
3. Other hydrocarbons and hydrogen
consumed as raw materials
4. Unfinished oils
5. Gasoline
a. Motor
b. Aviation
6. Special naphthas (solvents)
7. Jet fuel
a. Naphtha-type
b. Kerosine-type
8. Kerosine (including range oil)
9. Distillate fuel oil
10. Residual fuel oil
11. Lubracating oils
a. Bright stock
b. Neutral
c. Other
12. Asphalt
13. Wax
a. Microcrystalline
b. Crystalline-fully refined
c. Crystalline-other
14. Petroleum coke
a. Marketable
b. Catalyst
15. Road oil
16. Still gas
3. Petrochemical Itvdstock use
b. Refinery g.is
17. Ethane ami/or ethylene -
Petrochemical feedstock use
18. Propane and/or propylene
a. Petiochemical feedstock use
b. Other use
19. Butane and'or butylene
a. Petrochemical 'eestock use
b. Other use
20. Butane-propane mixtures
a. Petrochemical feedstock list:
1'. Otlir" use
?1. Isobuumt' IC.J 'Vlrnditimiciil feed-
stock use
22. Nnplttda-lcss than 40U1 end point
petrochemical feedstock use
23. Other oils over 400 end point -
petrochemical feedstock use
24. Other finished products
25 Overage (input) or shortage (output)
26. Total
Louisiana Gulf
Input
238,199
3.112
2.109
6.685
5,875
664
4,683
-
-
3.561
10.823
275.711
Output
7,202
1 30,006
80
-
807
20,295
6,021
69.914
5,856
-
(12)
-
1,701
-
-
-
4.512
1,880
-
-
10,463
687
2,262
8,644
333
-
28
-
-
42
3,464
1,447
79
275,711
Texas Gulf
Input
317,931
40,662
-
2,334
2,246
-
13,849
16,092
31
4.626
,
9.789
407.560
Output
12,242
178,081
Small Midcontinent
Input
49,999
10,733
-
1,028
340
-
4,798
1,226
1,499
3,270
7,231 :
3,009 :
25,115
8,429
88,491
17,170
1.470
3,500
12,532
1,536 '
30
236
284
4,380
4,972
-
776 j
11.657
1,266
3,719
4.156
631
1,272
-
_
-
6,623
2,684
1.740
1,058
407,560
2,887
72.510
Output
765
40,991
-
7
472
911
38
17,374
252 '
111
84
175
1,976
-
-
_
1,430
1,184
_
70
1,974
520
653
1,578
_
8
_
1
-
1.535
185
84
132
72,510
Large Midwest
Input
128,062
30,247
4,050
-
-
-
108
915
-
S.BI1
5.650
174,543
Output
3,464
89,467
-
2.248
143
2,297
1.813
44,678
8.094
-
-
2.013
-
-
-
4,024
3.301
2.154
-
5,860
-
-
3,483
_
6
_
_
1.025
-
427
46
174,543
West Coast
Input
106.057
69,597
2
570
93
124
47
1,422
.-
935
8,257
1 1 ,229
198.333
Output
2,198
72,734
1,933
1,300
3,594
21,059
184
23,891
33,457 '
64
165
152
2,199
-
-
-
10,486
2,630
16
-
10,254
508
1,131
1,658
_
1,646
289
1,082
103
4,271
358
611
360
198,333
East Coast
Input
47.340
157,890
-
383
1,927
-
63
206
432
25,033a
731 \
6,965*:
240.970
Output
114,904
-
13
1,730
5,956
3,711
49,818
14.053
323
' 1.488
3.263
19,856
44
289
-
-
2,528
-
882
7,433
58
3,083
7,369
1,441
-
_
-
-
1,485
29
1,213
-
240,970
Includes the following unfirjshcd oils:'alkylation feed, 293; reformer feed, 3,824; cat. cracker feed, 12,496: slack wax, 692; slop oil, 340; mineral oil, 395; hydrogen, 13; polymerization feed, 651; toluene, 524; alkylate, 105;
Mid naphtha, 5,700 for a total of 25,033.
-------
Table 1-2. BUREAU OF MINES RECEIPTS OF CRUDE BY ORIGIN 1973
(Mbbls)
Domestic crudes
State of origin:
Alabama
Alaska
California.
Colorado
Florida
Illinois
Kansas
Louisiana
Oklahoma
Mississippi
Montana
Nebraska
New Mexico
Texas
Utah
Wyoming
Total domestic crudes
Foreign crudes
Country of origin:
Algeria
Angola
Canada
Ecuador
Indonesia
Iran
Iraq
Libya
Mexico
Nigeria
Qatar
Saudi Arabia
Sumatra
Trinidad
Tunisia
United Arab Emirates
Venezuela
Total foreign crudes
Total crude
Louisiana
Gulf
50
185,654
2,395
40,502
228,601
161
214
827
910
189
546
263
3,110
231,711
Texas
Gulf
5,231
12,051
18,306
1,601
281,252
318,441
3,869
3,666
50
489
10,213
15,732
7.257
41,276
359,717
Small
Midcontinent
459
63
18,906
2,259
21,931
85
370
4,686
1,022
49,781
10,744
10,744
60,525
Large
Midwest
3,398
9,090
836
19,354
10,643
241
836
32,673
48,805
10,818
136,694
26,022
238
4,291
30,551
167,245
West
Coast
12,146
89,254
678
4,321
106,399
7,019
5,920
515
2
27,056
24,712
3,927
1,295
70,446
176,845
East
Coast
2,594
3,346
275
37,800
44,015
25,248
1,165
3,905
16,121
29,430
6,036
1,772
3,733
5,676
61,344
154,430
198,445
1-3
-------
Table 1-3. BUREAU OF MINES REFINERY FUEL CONSUMPTION FOR CLUSTER MODELS 1973a
Commodity
A. Fuel (purchased and produced at refinery):
1) Crude oil used as fuel
2) Fuel oils:
a) Distillate-type
b) Residual-type (incl. acid sludge)
3) Liquified petroleum gases
4) Natural gas
5) Still gas
6) Petroleum coke:
a) Marketable
b) Catalyst
7) Coal
B. Electrical energy:
1) Purchased
2) Generated
3) Sold
C. Steam:
1) Purchased
2) Sold
Unit of
measureb
Bbls
Bbls
Bbls
Bbls
MCF
MCF
Short tons
Short tons
Short tons
MKWH
MKWH
MKWH
MLbs
MLbs
Louisiana
Gulf
330,495
1,207,201
1,549,390
37,183,993
65,393,750
375,934
-
657,644
5,627
560,743
28,017
Texas
Gulf
-
345,882
127,940
201,687,751
72,856,250
994,400
-
687,585
502,218
8,631
-
Small
ixlidcontinent
198
598,458
35,797
14,116,609
12,337,500
236,800
-
310,680
-
Large
Midwest
-
2,741,952
134,196
1,677,499
36,625,000
660,200
-
803,985
118,820
-
West
Coast
209,461
570,702
1,079,793
23,388,789
64,087,500
526,000
-
1,381,360
87,984
East
Coast
4,996,043
16,015,802
48,125.000
59,846
395,000
1,449,291
46,460
84,068
6,316,090
38,302
alncluues consumption for three refineries for the calendar year 1973.
See table 1-4 for FOE conversion factors.
-------
Table 1-4. BUREAU OF MINES REFINERY FUEL
CONSUMPTION FOR CLUSTER MODELS 19738
(Bbls FOE)
Commodity
A. Fuel (purchased and produced at refinery):
( 1 ) Crude oil used as fuel
(2) Fuel oils:
a) Distillate-type
b) Residual-type (incl. acid sludge)
(3) Liquified petroleum gases
(4) Natural gas
(5) Still gas
(6) Petroleum coke:
a) Marketable
b) Catalyst
(7) Coal
B. Electrical energy:
(1) Purchased
(2) Generated
(3) Sold
Conversion
factor, FOE
bbl per unit"
-
.9246 per bbl
.9979 per bbl
.6367 per bbl
. 1683 per MCF
. 1638 per MCF
<4. 7810 per short ton
-
(
1 1.6475 per MKWH
/
Louisiana
Gulf
305,576
1,204,666
986,497
6,258,066
10,711,496
1,797,340
-
1,083,468
9,270
Texas
Gulf
.
319,802
-
81,459
33,944,049
11,933,853
4,754,226
-
1,132,796
827,404
14,220
Small
Midcontinent
-
183
597,201
22,792
2,375,825
2,020,883
1,132,141
-
511,845
-
Large
Midwest
-
2,736,194
85,443
282,323
5,999,175
3,156,416
-
1,324,565
195,756
West
Coast
-
193,668
575,491
687,504
3,936,333
10,497,532
2,514,806
-
2,275,791
East
Coast
-
4,985,551
-
2,695,459
7,882,875
286,124
1,888,495
-
2,387,707
76,543
138,502
a Includes consumption for three refineries for the year 1973.
One FOE (fuel oil equivalent) barrel contains 6.3 x 106 BTU's (gross heating value).
-------
Several revisions were made to the data as originally transmitted by
the BOM in preparing Table 1-1. These changes resulted from discussions
between the EPA and individual refiners and revised information was trans-
mitted to ADL. Data presented in Table 1-1 represents the revised version.
One of the refineries included in the East Coast cluster model shut down
a catalytic cracking/alkylation complex during the calendar year 1973 and
started up a new hydrocracker and associated operations. Therefore, it was
considered that the use of annual statistics for this refinery in 1973 would
not provide meaningful information. Accordingly, this particular plant
provided specific refinery input/output data to the EPA covering that portion
of the year when operations were relatively consistent. The J.1PA extrapolated
these results to a calendar year basis which were then incorporated with the
1973 annual operating data supplied by the other companies to obtain the
revised input/output data for this cluster model, and presented in Table 1-1.
Note that this cluster model also provided an extensive breakdown of unfin-
ished oil intake which represents a substantial portion of the raw material
consumed in this cluster.
The product blending and input streams used in the ADL refinery simula-
tion model system do not correspond exactly to the format used in the Bureau
of Mines reports. Accordingly, it was necessary to make some adjustments to
the basic Bureau of Mines data to meet the requirements of the ADL model.
The transformation of this data is summarized in Table 1-5, with the metho-
dology outlined in Table 1-6. In comparing the data in Table 1-1 with
Table 1-5, it must be remembered that the BOM presents annual aggregate
statistics for the total of three plants while the information in Table I-!.
is presented in MB/CD for the "average" single refinery operation represent--
ing the cluster. In undertaking the calibration effort, all product demands
and non-crude inputs to the model were fixed. The n.odel was then allowed to
vary crude intake as needed to balance refinery product (and internal fuel)
demands.
1-6
-------
Table 1-5. ADL MODEL INPUT/OUTTURN DATA FOR CALIBRATION
(MB/CD)a
i
j
Specified product outturns
Refinery gas/ethane (FOE)
LPG-fuel
LPG-petrochemicals
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke
Cat. cracker feed
Cat. reformer feed
Specified inputs
Isobutane
Normal butane
Natural gasoline
Max natural gas (FOE)
Cat. cracker feed
Cat. reformer feed
Louisiana
Gulf
0.32
5.97
2.40
1 18.79
0.78
18.53
5.50
67.80
5.35
1.55
4.12
2.161
1.164
6.10
5.97
4.28
5.40
Texas
Gulf
.84
4.96
3.97
165.62
8.80
6.05
23.49
7.70
83.27
16.49
15.68
1.40
4.00
2.00
4.955
2.13
2.05
16.00
29.24
Large
Midwest
_
3.19
81.70
2.16
0.94
2.12
1.66
40.80
7.39
3.81
3.68
3.70
0.93
0.24
1.215
.654
Small
Midcontinent
0.54
1.45
0.60
37.44
0.35
1.40
0.92
0.04
16.04
0.34
0.23
1.81
1.31
0.94
0.31
5.50
2.046
.436
.235
East
Coast
0.86
6.73
4.13
104.93
1.28
1.36
5.76
3.39
45.52
4.94
12.83
18.13
-
0.35
1.76
5.84
2.50
11.10
5.98
West
Coast
0.46
3.99
1.30
67.77
3.81
3.90
19.89
0.17
22.15
0.35
30.55
2.02
9.58
0.50
0.16
1.30
6.39
3.597
1.937
aObtained by dividing BOM data by 365 days/year and 3 refineries per cluster.
-------
Table 1-6. CONVERSION OF BOM INPUT/OUTTURN DATA
TO ADL MODEL FORMAT
ADL product/input category
(as shown in Table 1-5)
Bureau of Mines category
(as shown in Table 1-1)
Refinery gas/ethane (FOE)
LPG - fuel
LPG-petrochemicals
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke
Cat cracker feed
Cat reformer feed
Isobutane
Normal butane
Natural gasoline
16(a) + 17 (converted to FOE basis)
18(b) + 19(b)+20(b)-2(a)
18(a) + 19(a)+20(a)
5(a) + 5(b)
6+ 80% of 7(a)
22
20%.of 7(a)+7(b)
8
9 + 23
11(a.b,c) + 13(a,b,c)
10
12 + 15
14(a)
65% of 4 (net of input/production)
35% of 4 (net of input/production)
2(b)
2(c)
2(f)+2lg)
-------
Table 1-6 presents the procedure for converting the BOM data as shown
in Table 1-1 to the ADL format in Table 1-5. For the Small Midcontinent,
East Coast, and West Coast cluster models, the ethane and/or ethylene pro-
duction shown in line 17 of the BOM data was not converted to an FOE basis.
For the West. Coast cluster model, the total gasoline outturn used for the
calibration model was 67.77 MB/CD although the correct number should have
been 68.19. Isobutane and normal butane for Louisiana and isobutane for
the West Coast were entered as 6.10/5.97/.50, respectively, instead of the
correct figures 6.40/5.67/.60. In addition, LPG to petrochemicals in the
West Coast was entered as 1.30 rather than the correct 1.39. Since it was
felt that the calibration would not significantly be improved by correcting
these items, no further adjustments were made.
The following assumptions were used in constructing Table 1-6. Naphtha
jet fuel production (BOM category 7 (a)) was assumed to consist of 80%
naphtha and 20% kerosene. Category 22 (Naphtha-less than 400°F end point-
petrochemical feedstock use) was considered to be 100% mixed aromatics
referred to as BTX. Discussions with some individual oil companies indicated
that for most companies this is a reasonable assumption. However, for
certain companies this category represents a mixed reformate stream prior
to extraction. Category 23 (other oilsover 400° end point-petrochemical
feedstock use) was added to distillate fuel oil production.
Unfinished oils were considered to consist of 65% catalytic cracker
feed and 35% catalytic reformer feed, except in the Texas Gulf cluster.
Discussions with members of the API/NPRA Task Force indicated this to be
a reasonable representation for this category. In the Texas Gulf cluster
the percentage of catalytic cracker feed in unfinished oils was adjusted
to 29% to improve calibration.
Discrepancies were noted in the mode of reporting BOM statistics from
company-to-company. Refinery residual fuel production (BOM category 10
in Table 1-1) was usually reported as the net production from the refinery.
However, some companies also included in this total any internal residual
fuel consumption (category A., 2b), as is shown in Table 1-3. Table 1-3
also provides purchased natural gas consumption in category A.4. Most
companies report natural gas in this category for fuel use only. However,
1-9
-------
some companies with hydrogen generating facilities include natural gas for
this purpose within this BOM category. The above company-to-company
variations obviously limit the degree of calibration possible with the
cluster models.
Table 1-7 reports the crude slate used for each cluster model to
simulate the reported BOM data. The objective was to simulate average
domestic/foreign mix, sulfur content, API gravity, and other key proper-
ties as closely as possible, while still keeping the number of crudes to
a manageable level. Table 1-7 also contains a comparison between the
average sulfur content of the model crude slates compared with the industry
data obtained from the individual companies and averagf d by the EPA.
The follouii g general methodology was used to develop the model crude
slates. Louisiana crude was used to simulate Louisiana and low sulfur
Texas crudes. Oklahoma crude was used to represent light, sweet crudes
from the Midcontinent. West Texas sour was used to simulate high sulfur
crudes from Texas and New Mexico. Wilmingion and Ventura were used to
simulate heavy and light California crudes respectively. Nigerian Forcados
was used to represent heavy African crudes while Algerian Hassi Messaoud
was used to simulate light African crudes. Arabian Light represented
average Middle East production and Tia Juana Medivm was used to simulate
Venezuelan crude.
2. Processing Configurations
The annual refinery surveys published in the Oil and Gas Journal were
used as the basic reference source for determining cluster model processing
configurations. Since operations for the calendar year 1973 were to be
simulated, unit capacities were tabulated for January 1, 1973 and
January 1, 1974, and an arithmetic average of these was used as the
capacity available for the calendar year 1973. Tables 1-8 through 1-13
provide the basic processing data for each of the refineries comprising
the respective cluster models. Each table provides 1973 and 1974 capacity
data and the arithmetic average for the cluster of each, as well as the
final capacity limits used in the calibration effort. It should he noted
that the Oil and Gas Journal processing unit capacity data is presented
in barrels per stream day; these figures were used directly for the
1-10
-------
Table 1-7. ADL MODEL CRUDE SLATES AND SULFUR CONTENTS FOR REFINERY CLUSTERS
Crude charge
% total volume
Domestic crudes
Louisiana
West Texas Sour
Oklahoma
California Wilmington
California Ventura
Subtotal domestic crudes
Foreign crudes
Nigerian Forcados
Arabian Light
Venezuelan
Tia Juana
Algerian
Hassi Messaoud
Mixed Canadian
Indonesian
Minas
Subtotal foreign crude
Total crude - %
Sulfur content % weight
Model average3
Industry average6
Louisiana
Gulf
88.7
11.3
100.0
0.0
100.0
.331
.4
Texas
Gulf
47.4
41.4
88.8
3.8
5.3
2.1
11.2
100.0
.765
.72
Small
Midcontinent
7.6
13.1
61.5
82.2
17.8
17.8
100.0
.367
.37
Large
Midwest
6.0
70.3
4.9
81.2
8.5
10.3
18.8
100.0
1.130
1.17
West
Coast
37.4
13.8
51.2
31.3
7.1
10.4
48.8
100.0
1.251
1.30
East
Coast
15.4
7.6
23.0
16.2
7.6
31.7
21.5
77.0
100.0
.789
.73
Based on weighted average of sulfur content of crudes in model runs (Appendix H).
Reference - transmitted to ADL by EPA on 1-22-75.
-------
Table 1-8. TEXAS GULF CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity, Bbls/CD
Vacuum dist.
Thermal
-Visb.
Delayed coke
Catalytic cracking
Catalytic reforming
Hvdrocracking
-Dist.
Residual
Hydrofining
Hvy gas oil
Resid, visb.
-Cat feed & cycle
-Distillate
Hydrotreat
-Reform feed
-Naphtha
-Olef/arom sat
-S.R. distill.
-Lubes
-Other dist.
-Other
Alkylation
Arom/isom
-BTX
-HDA
Cyclohex
-C4 Feed
-C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke-tons/day
Unit capacity9. 1974
Exxon
Baytown,
Texas
400.000
420,000
180,000
1 24,000
88.000
20,000
48,000
90,000
15,000
41,000
109,000
8,500C
26,000
25,000
1 2,000
Gulf
Port Arthur,
Texas
312.100
319,000
147,400
30,000
120,000
65,000
15,000
65,000
65,000
1,200
13,900
20,000
2,700
2,500
7,200
13,200
1,390
Mobil
Beaumont,
Texas
325,000
335,000
103,000
33,000
95,000
94,000
29,000
83,000
42,000
16,500
8.800
100
1.200
1974
Average
345,700
358,000
143,467
21,000
113,000
82,333
21,333
16,000
21,667
79,333
5,000
400
18.300
50,333
2,833
20,833
900
833
2,400
15,667
4,033
863
Unit capacity8, 1973
Exxon
Baytown,
Texas
350,000
365,000
150,000
135,000
88,000
20,000
53,000
90,000
32,000
39,500
84,000
8,500
26,000
25,000
12,000
Gulf
Port Arthur,
Texas
312,100
319,000
147,400
30,000
120,000
65,000
15,000
65,000
65,000
1,200
13,900
20,000
2,700
2,500
7,200
13,200
1,390
Mobil
Beaumont.
Texas
335,000
350,000
103,000
12,000
OC.OOO
95,000
94,000
29,000
83.000
42,000
16,500
8,800
100
1,200
1973
Average
332,367
344,667
133,467
4,000
21,000
116,667
82,333
21,333
17,667
21,667
79,333
10,667
400
17,800
42,000
2,833
20,833
900
833
2,400
15,667
4,033
863
Unit c?oacitya'
1973/
1974
Average
339,034
351,333
138,467
2,000
21 ,000
1 14,834
82,333
21.333
16,834
21,667
79,333
7,833
400
18,050
46,167
2,833
20,833
900
833
2,400
15,667
4,033
863
%
Crude
cap.
39.4
0.6
6.0
32.7
23.4
6.1
4.8
6.2
22.6
2.2
0.1
5.1
13.1
0.8
5.9
0.3
0.2
0.7
4.4
1.1
Model
limit
MB/SO
114.8
82.3
21.3
38.5
18.1
46.2
20.8
2.4
Bl)ls/SD unless otherwise noted.
Used for cluster model.
c - i
Solvents.
Reference: Oil and Gas Jou'-~l, April 2. 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table 1-9. LOUISIANA GULF CLUSTER PROCESSING CONFIGURATION
*
Unit type
Crude capacity, Bbls/CO
Vacuum dist.
Thermal
-Visb.
-Delayed coke
Catalytic cracking
Catalytic reforming
Hydrocracking
-Dist.
Residual
Hydrofining
-Residual
-Hvy gas oil
Resid. visb.
-Cat feed & cycle
-Distillate
Hydrotreat
-Reform feed
-Naphtha
Olef/arpm sat
-S.R. distill.
Lubes
Other dist.
-Other
Alkylation
Amm/isom
- BTX
-HDA
Cyclohex
-C4 Feed
-C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity,3 1974
Gulf
Alliance,
La.
180.400
186.000
55,000
16,000
78,000
37,500
16,000
22,000
41,000
28,400
11,100
5,400
840
Shell
Norco,
La.
240,000
250,000
90,000
18,000
95,000
41,500
28,000
25,000
26,000
14,100
6,000
900
Citgo
L. Chas.,
La.
268.000
N.R.
60.000
28.000
125.000
46.000
6.000
30.000
46,000
14.000
35,300
7,000
1,000
1974
Average
229,467
68,333
20,667
99,333
41,667
9,333
2,000
23,667
7,333
29,000
8,667
4,667
25,933
3,700
1,800
2,333
2,000
913
Unit capacity.8 1973
Gulf
Alliance,
La.
174,000
180,000
54,000
16,000
75,000
37,500
16,000
22.000
41,000
28,400
11,100
5,400
840
Shell
Norco,
La.
240,000
250,000
90,000
17,000
85,000
43,000
29,400
25,000
26,000
14,100
*
6,000
900
Citgo
L. Chas.,
La.
240.000
245,000
78,000
25,000
112,500
39,000
6.000
16,300
11,200
24,000
26,000
10,000
895
1973
Average
218,000
225,000
74,000
19,333
90,833
39,833
9,800
2.000
13,667
7,333
19,100
12,400
8,000
22,833
3,700
1,800
3,333
2,000
878
Unit capacity8'
1973/
1974
Average
223,734
71.167
20,000
95,000
40,750
9,566
1.000
1^000
18,667
7,333
24,050
10,534
2,333
4,000
24,383
3,700
1,800
2,833
2,000
896
%
Crude
cap.
30.8
8.7
41.1
17.6
4.1
0.4
0.4
8.1
3.2
10.4
4.6
1.0
1.7
10.6
1.6
0.8
1.2
0.9
Model
limit
MB/SO
95.0
40.5
9.5
29.0
7.3
24.0
I
h-
OJ
Bbls/SD unless otherwise noted.
Used in clustui model.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table 1-10. LARGE MIDWEST CLUSTER PROCESS CONFIGURATION
Unit type
Crude capacity. Bbls/CO
Vacuum dist.
Thermal
-Gas oil
-Visb.
-Delayed coke
Catalytic cracking
Catalytic reforming
Hydrofining
Hvy gas oil
Resid. visb.
-Cat feed & cycle
-Distillate
Hydrotreat
Reform feed
Naphtha
Olef/arom sat
-S.R. distill.
-Lubes
-Other dist.
-Other
Alkylation
Arom/isom
-BTX
-HDA
-Cyclohex
-C4 Feed
-C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke-tons/day
Unit capacity8, 1974
Mobil
Joliet.
III.
175.000
186,000
82,000
28,000
66,000
46.200
69,000
67,000
22,000
1,700
Union
Lament,
III.
152,000
N.R.
55,000
19,500
52,000
32,000
32,000
2,700
4,500
7,000
34,500
2,500°
12,800
3.300
2,000
1,000
Arco
E. Chic.,
III.
126,000
140,000
70,000
48,000
20,000
25,000
20,000
2,000
6.000
10,400
1974
Average
151,000
69,000
15,833
55,333
32,733
31,333
39,667
1,567
1,500
2,333
11,500
833
13,600
i,100
,
4,133
900
Unit capacity8, 1973
Mobil
Joliet,
III.
160,000
164,000
72,500
28,000
66,000
46,200
53,000
54,000
18,000
1,700
Union
Lament,
III.
140,000
N.R.
55,000
19,000
50,000
32,000
32,000
2,000
5,300
7,000
37,000
16,000
3,200
1,000
Arco
E. Chic.,
III.
135,000
140,000
.'0,000
48,000
20,000
25,000
20,000
2,000
6,000
10,400
1973
Average
145,000
65,833
6,333
9,333
54,667
32,733
8,333
35,000
1,333
1,767
2,333
18,000
12,333
13,333
1,067
3,467
900
Unit capacity8'
1973/
1974
Average
148.000
67,417
3,167
12,583
55,000
32,733
19,833
37,334
1,450
1,634
2,333
14,750
6,583
13,467
1,084
3,800
900
%
Crude
cap.
43.4
2.0
10.1
35.4
21.1
12.7
24.0
.9
1.1
1.5
12.9
4.2
8.6
.7
2.4
Model
limit
MB/SO
55.0
32.7
22.7
20.0
13.5
Bbls/SD unless otherwise noted.
Used for cluster model.
C8enzene concentrate.
Reference: Oil and Gas Jcur:.tl, ,".fit\\ 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table 1-11. SMALL MIDCONTINENT CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity. Bbls/CD
Vacuum dist.
Thermal
-Visb.
Delayed coke
Catalytic cracking
Catalytic reforming
Hydrofining
-Hvy gas oil
Resid. visb.
-Cat feed & cycle
-Distillate
Hydrotreat
Reform feed
Naphtha
-Olef/arom sat
-S.R. distill.
-Lubes
Other dist.
-Other
Alkylation
Arom/isom
- BTX
-HDA
Cyclohex
-C4 Feed
-C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke-tons/day
Unit capacity8, 1974
Skelly
El
Dorado,
Kan.
73,700
75,000
23.000
9,800
30,000
21.500
23,000
4.300
6,000
1,400
500
Gulf
Toledo,
Ohio
50,300
51,000
12,500
20,000
11,000
5,000
11,000
5,500
2,000
Champlin
Enid,
Ok la.
49,500
52,000
18,000
3,700
19,500
15,000
20,400
4,500
6,000
1,100
1,400
165
1974
Average
57,833
59,333
17,833
4,500
23,167
15,833
1,667
18,133
1,433
5,333
467
2,000
367
1,133
222
Unit capacity8, 1973
*e,,y
Dorado,
Kan
67,000
70,000
23,000
9,800
30,000
20,000
23,000
4,300
6,000 .
1,400
f
3,000
500
Gulf
Toledo,
Ohio
48,800
50,000
12,300
18,500
10,500
5,000
10,500
5,100
2,000
Champlin
Enid,
Ok la.
48,000
50,000
24,000
4.000
19.000
15,000
15,000
5,000°
4,400
5,000
1,200
2,000
158
1973
Average
54,600
56,667
19,767
4,600
22.500
15.167
1.667
16,167
1,433
1,667
5,167
467
1,667
400
2,333
219
Unit capacity '
1973/
1974
Average
56.217
58,000
18.800
4,550
22.834
15.500
1.667
17,150
1,433
834
5,250
467
1,834
384
1,733
221
%
Crude
cap.
32.4
7.8
39.4
26.7
2.9
*"
29.6
2.5
1.4
9.1
0.8
3.2
0.7
3.0
Modal
limit
MB/SO
22.8 '
15.5
1.7
5.3
1.8
Bhls/SD unless otherwise' noted.
Used lor cluster model.
Isoni feed.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table 1-12. WEST COAST CLUSTER MODEL PROCESSING CONFIGURATION
Unit typo
Crude capacity, Bbls/CD
Vacuum dist.
Thermal
-Gas oil
-Visb.
Delayed coke
Catalytic cracking
Catalytic reforming
Hydrocracking
-Dist.
Residual
Hydrofining
Hvy gas oil
Resid. visb.
-Cat feed & cycle
-Distillate
Hydrotreat
Reform feed
Naphtha
Olef/arom sat
-S.R. distill.
-Lubes
Other dist.
-Other
Alkylation
Arom/isom
BTX
-HDA
-Cyclohex
~C4 Feed
-C5 Feed
-C5/C6 Feed.
Lubes
Asphalt
Coke tons/day
Unit capacity8, 1974
Mobil
Torranca,
Calif.
123.500
130.000
95.000
16,000
46,640
56.000
36,000
18.000
23,000
15,000
25.000
10,500
2,800
Arco
Carton,
Calif.
165,000
173,000
93,000
12,500
42,000
30,000
57,000
34,000
19,700
18.000
34,000
18,000
7,200
2,490
1,800
Socal
El Seguiido,
Calif.
230.000
N.R.
103,000
54,000
43.500
60,000
49.000
40,000
12,000
18,000C
5,900
1,500
8,300
2,200
1974
Average
172,833
97.000
4,167
19,333
43,647
52,167
43,333
28,900
6,000
32,333
6,000
5,000
4,000
8,333
6,000
7,Gd7
830
500
2,767
2,267
Unit capacity8, 1973
Mobil
Torrance,
Calif.
123,500
130,000
95,000
16,000
46,640
56,000
36,000
18,000
23,000
15,000
23.000
10,500
2,800
Arco
Carson,
Calif.
165,000
1 73,000
93,000
23,000
37,000
25,500
57,000
32,000
,
17,000
18,000
32,000
18,000
7,200
~ 2,490
1,650
Socal
El Segundo,
Calif.
N.R.
220,000
100.000
50,000
40,000
62,000
"45,000
40,000
12,000
18,000
5,400
1,500
8,300
2,200
1973
Average
174,333
97,000
7,667
17,667
40.713
51,000
43,333
26,667
6,000
31,667
11,000
4,000
7,667
6,000
7,700
1,330
2,767
2,217
Unit capacity3
1973/
1974
Average
97,000
5,917
18,500
42,130
51,584
43,333
27,784
6,000
32,000
3,000
8,000
4,000
8,000
6,000
7,784
1,080
250
2,767
2,242
%
Crude
cap.
54.5
3.3
10.4
23.7
29.0
24.3
15.6
3.4
18.0
1.7
4.5
2.2
4.5
3.4
4.4
0.7
0.1
1.0
Model
limit
MB/SD
51.6
43.3
27.8
27.0
8.0
7.8
''Sub'SU unless otherwise noted.
bUsod tor cluster model
cji:t fuel.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table 1-13. EAST COAST CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity. Bbls/CD
Vacuum dist.
Thermal
-Visb.
-Delayed coke
Catalytic cracking
Catalytic reforming
Hydrocracking
-Dist.
- Other
Hydrofining
Hvy gas oil
Resid. visb.
-Cat feed & cycle
Distillate
Hycirotreat
Reform feed
-Naphtha
Olef /arom sat
--S.R. distill.
-Lubes
Other dist.
-Other
Alkylation
Arom/isom
-BTX
-HDA
Cyclohex
-C4 Feed
- C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity3, 1974
Arco
Phil.,
Pa.
185,000
195,000
57,000
60,000
30,000
32,000
41,000
54,000
19,500
Sun
Marcus
Hook, Pa.
165,000
180,000
48.000
75,000
45,000
35,000
10,000
10,000°
12,000
5,300
17,000
12,000
Exxon
Linden,
N.J.
275,000
286,000
143,000
120,000
42,000
50,000
42,000
14,000
39,000
8,500
46,000
1974
Average
208,333
220,333
82,667
65,000
49,000
10,000
27,333
13,667
43,667
4,667
3,333
13,000
3,333
6,833
1,767
5,667
25,833
Unit capacity8, 1973
Arco
Phil.,
Pa.
160,000
165,000
83,000
36,000
60,000
30,000
34,000
53,000
7,000
17,000
Sun
Marcus
Hook, Pa.
163,000
180,000
48,000
75,000
43,000
35.000
10,000
16,000C
12,000
5,300
17,000
12,000
Exxon
Linden,
N.J.
255,000
268,000
140.000
125.000
46,000
50,000
46,000
14,000
37.000
10,700
46,000
1973
Average
192,667
204,333
90,333
78,667
49,667
10,000
16,667
11,333
44,667
4,667
3,333
12,333
5,333
9,900
1,767
5,667
25,000
Unit capacity3
1973/
1974
Average
200,500
212.333
86.500
71,834
49,334
10,000
22,000
12,500
44,167
4,667
3,333
12,667
4,333
8,367
1,767
5,66 X.
25,416
%
Crude
cap.
40.7
33.8
23.2
4.7
10.4
5.9
20.8
2.2
1.6
6.0
2.0
3.9
.8
2.7
12.0
Model
limit
MB/SD
71.8
49.3
10.0
34.5
17.0
8.4
Bbls/SD unless otherwise noted.
b
Used lor cluster model.
Furnace oil.
Reference:
Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
calibration effort, since it was not known if any operating units were,
in fact, shut- down for maintenance during 1973. When this processing
configuration capacity data was used for computer runs for 1977, 1980,
and 1985, appropriate stream-day-factors were applied.
A stream day capacity limit for a conversion processing unit such as
catalytic cracking or reforming is only meaningful at a given operating
severity level. The maximum feed rate that a unit can process will
increase as severity declines. The Oil and Gas Journal capacity data
was assumed to be applicable at 65% volume conversion for catalytic
cracking and 95 RON for catalytic reforming. Feed capacity adjustments
for severity were used in the calibration runs.
Since the Oi". and Gas Journal does not provide capacity data on
hydrogen manufacture or sulfur recovery facilities, no limits on these
operations were imposed in the calibration runs.
3. Product Data
As part of this project, EPA obtained from each individual oil company
the average gasoline grade distribution for calendar year 1973 and asso-
ciated octane levels/lead additions for each grade, shown in Table 1-14.
Also shown in Table 1-14 are total gasoline volumes and average sulfur
contents as supplied by the individual companies and compiled by the EPA.
In some cases, the gasoline volumes deviated from the information received
from the BOM - for the Texas Gulf Coast and West Coast, the industry pro-
duction data was about 3 MB/CD below BOM statistics. For these cases,
the BOM data was used in the calibration effort.
Table 1-15 provides other key product specifications used in the
calibration runs. Distillate fuel sulfur specifications were allowed to
vary from model to model in an effort to achieve icasonable utilization
of existing desulfurization capacity. Since U. S. refiners did not
desulfurize residual stocks in 1973, sulfur specifications were relatively
"loose" for this product. After discussions with several oil companies,
it was felt that LPG for petrochemicals feedstock use would be met by a
fixed blend of 80% mixed C/C, olefins, 16% propane and 2% each of i.so
3 4
and normal butane.
1-18
-------
Table 1-14. CLUSTER MODEL GASOLINE PRODUCTION AND PROPERTIES - 1973
a,b
Gasoline volume
MBPY
MB/CD
Sulfur content, %
Pool octanes
Clear RON
Leaded RON
Clear MON
Leaded MON
Lead g/gal
rade distribution and octane
Premium, %
Premium, octane
Leaded RON
Clear RON
Leaded MON
Clear MON
Lead g/gal
Regular, %
Regular, octane
Leaded RON
Clear RON
Leaded MON
Clear MON
Lead g/gal
Low lead, %
Low lead, octane
Leaded RON
Clear RON
Leaded MON
Clear MON
Lead g/gal
Unleaded, %
Unleaded, octane
RON
MON
Texas Gulf
59,360
162.6
.041
88.2
95.5
79.7
88.3
2.09
28.46
99.5
92.9
92.0
83.2
2.43
60.68
93.8
85.5
86.8
77.3
2.22
10.86
93.7
91.7
86.3
83.4
0.44
-
Louisiana Gulf
43,335
118.8
.044
88.95
81.63
1.77
34.54
99.8
92.2
1.99
58.05
93.6
86.6
1.81
7.42
94.3
85.7
0.5
-
East Coast
38,301
104.9
.023
87.8
80.0
1.82
28.8
100.5
92.5
2.27
64.9
94.1
86.1
1.76
6.3
96.6
86.8
0.4
-
_
Small
Midcontinent
13,663
37.4
.034
86.1
80.0
1.58
20.67
98.9
90.4
94.0
80.0
2.30
75.70
92.2
84.7
86.1
78.6
1.44
3.63
91.0
88.7
86.0
79.6
0.36
-
'
Large Midwest
81.7
.082
87.9
79.6
1.74
20.2
99.2
92.6
1.99
79.6
94.0
86.2
1.68
0.2
94.6
88.0
0.3
-
West Coast
23,904
65.5
.07
90.4
81.5
1.94
53.57
99.3
90.2
2.6
45.07
93.4
84.5
1.21
0.78
94.0
85.1
0.3
0.58
92.0
82.7
dRi>ference: transmitted to ADL by EPA on 1-22-75
"No entry indicates data not reported.
-------
Table 1-15. KEY PRODUCT SPECIFICATIONS
Product Specifications
Motor gasoline Maximum vapor pressure (RVP)
Maximum lead addition (g/gal)
Kerosene Maximum sulfur (% Wt)
Maximum gravity (°API)
Jet fuel Maximum sulfur (% Wt)
Maximum gravity (°API)
Minimum smoke point (mm)
Residual fuel oil Maximum viscosity (Refutas @ 122°F)
Maximum sulfur (% Wt)
Distillate fuel oil Maximum sulfur (% Wt)
All
clusters
10.5
3.17
0.1
46.0
0.1
46.0
20.0
38.0
Texas?
Gulf
.78
.17
La.
Gulf
.75
.17
Large
Midwest
.78
.30
Small
Midcohtinent
.78
.30
East
Coast
.78
.10
West
Coast
1.90
.17
to
o
Volatility specifications for this cluster used as shown in Table C-1.
-------
4_. Calibration Economic _Data
As was stated previously, for the calibration runs each individual
product demand was fixed as well as non-crude inputs. For each cluster
model, one important crude, a reference crude, was allowed to vary to
balance product demands and internal fuel requirements. Other crude inputs
were fixed.
The reference crudes used were:
Cluster Model Reference Crude
Louisiana Gulf Louisiana
Texas Gulf West Texas Sour
Large Midwest West Texas Sour
Small Midcontinent Oklahoma
East Coast Tia Juana
West Coast Wilmington
The reference crude was assumed to cost $4.00/bbl. for all models
except the East Coast, which used $4.25/bbl.
Maximum natural gas availability was established for each cluster
model based on the BOM data presented in Table 1-3 under category A-4.
In some cases, this value was increased somewhat to account for natural
gas consumed in hydrogen manufacture. The model could purchase up to the
specified maximum at the prices indicated as follows:
Maximum Natural Price
Gas Availability $ per bbl.
Cluster Model MB/CD (FOE) (FOE)
Louisiana 5.4 1.89
Texas Gulf 29.24 1.89
Large Midwest .24 2.52
.Small Midcontinent 2.046 1.89
East Coast . 2.50 3.15
West Coast 6.39 1.89
T-21
-------
Full refinery operating coses were used for the optimization of the
calibration runs. Unit costs for all models included purchased electricity
at 1.2c per KWH, cooling water at 4c per 1,000 gal., and $430.00 per daily
shift position for operating labor. Capital charge (annualized capital
recovery rate) for the existing capacity in the cluster model was reduced
to l/10th the normal level (25%) which would be assessed to hew plant
construction. (This resulted in a 2.5% per year annual charge of the
plant capital value in 1973 dollars.)
In theory, the day-to-day optimization and operation of any manu-
facturing facilities should consider the capital charges associated with
existing plant investments as "sunk" capital, and thus not be a factor
for influencing OTerating decisions. However, there can be tax savings
associated with early tax write-offs of existing facilities and the land
area occupied by refinery processing units undoubtedly has value. Thus,
we feel a relatively nominal 10% of full capital charge to be a reasonable
approach in the optimization of existing faciliuies.
B. CALIBRATION RESULTS FOR CLUSTER MODELS
There are four main areas in which one can compare the degree of
calibration for the cluster models. These are:
Overall Refinery Material Balance (i.e., volume of the crude
intake required to balance specified product demands and internal
fuel requirements)
Refinery Energy Consumption
Processing Configuration, Throughputs and Operating Severities
Key Product Properties (i.e., gasoline clear pool octanes, lead
levels, etc.)
As noted previously in this Appendix, the EPA obtained specific
operating data from each individual refinery within each cluster model,
and EPA averaged the industry statistics which were then transmitted to
ADL. Table 1-16 presents this data as received from the EPA.
Refinery flow diagrams resulting from the calibration runs arc shown
in Figures 1-1 through 1-6.
1-22
-------
Table 1-16. CLUSTER MODEL PROCESSING DATA" - 1973
Unit
Crude distillation
Atmospheric
MB/CD
MB/SO
Vacuum
MB/CD
MB/SD
Thermal Operations
Delayed coker
MB/CD
MB/SD
Catalytic Cracker
MB/CD
MB/SD
Conversion
Catalytic reformer
MB/CD
MB/SD
Seventy. RON clear
Hydrocracker
MB/CD
MB/SD
Alkylation
MB/CD
MB/SD
Texas Gulf
Unit
Capac-
ity
331.4
351.3
129.2
138.4
19.3
20.5
100.4
114.8
73.8
82.3
14.7
21.3
17.8
20.8
%
Uti-
lized
94.3
93.3
94.2
87.5
89.6
69.0
85.6
Opera-
tion
73.6
94.8
Louisiana Gulf
Unit
Capac-
ity
216.8
232.2
66.1
71.2
19.1
20.5
90.0
95.1
30.2
36.9
6.3
9.6
17.7
21.1
%
Uti-
lized
93.4
92.9
93.0
94.6
81.7
66.2
83.8
Opera-
tion
70.0
92.3
Small Midcontinent
Unit
Capa-
ity
56.6
57.8
18.5
19.2
4.6
4.6
20.2
23.0
11.7
13.8
5.0
5.3
%
Uti-
lized
97.8
96.4
100.0
88.1
85.0
95.6
Opera-
tion
76.5
85.8
Large Midwest
Unit
Capac-
ity
145.5
156.3
58.3
67.4
13.6
15.8
51.2
55.5
27.8
32.7
>
11.4
12.9
%
Uti-
lized
93.1
86.4
85.9
92.3
84.8
^
87.9
Opera-
tion
74.9
90.7
East Coast
Unit
Capac-
ity
186.5
207.3
78.1
90.8
73.1
76.5
36.3
43.4
7.4
10.0
6.9
9.2
%
Uti-
lized
90.0
86.0
95.6
83.7
74.0
75.0
Opera-
tion
71.6
93.4
West Coast
Unit
Capac-
ity
162.0.
177.6
84.1
97.0
38.4
42.1
44.5
51.6
34.7
43.0
23.2
27.8
5.6
7.8
%
Uti
lized
91.2
86.7
Op«r«
tlOll
!
91.2
86.2
80.7
83.4
71.5
61.6
95.9
-------
Table I 16 (continued). CLUSTER MODEL PROCESSING DATA3 - 1973
Unit
Aromatic*
Cg isomerization
MB/CD
MB/SO
Benzene (HDA)
MB/CD
MB/SD
BTX reformer
MB/CD
MB/SD
UDEX
' MB/CD
MB/SD
Texas Gulf
Unit
Capac-
ity
2.36
2.40
0.83
0.90
%
Uti-
lized
98.6
92.5
Opera-
tion
Louisiana Gulf
Unit
Capac-
ity
1.5
1.8
2.7
3.7
%
Uti
lized
85.2
73.0
Opera-
tion
Small Midcontinent
Unit
Capa-
ity
1.4
1.8
1.6
1.8
0.30
0.47
I
%
Uti-
lized
76.6
88.9
64.9
Opera-
tion
Large Midwest
Unit
Capac-
ity
%
Uti-
lized
Opera-
tion
East Coast
Unit
Capac-
ity
4.4
6.1
4.5
5.0
%
Uti-
lized
73.0
90.0
Opera-
tion
West Coast
Unit
Capac-
ity
%
Uti-
lized
Opera-
tion
Reference transmitted to ADL by LPA on 1-25-75.
a. MB/CD daui supplied by industry to EPA.
-------
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-------
Tables 1-17 through 1-22 provide key calibration results concerning
the first three, of the above four, comparison areas, for each of the
cluster models. For example, Table 1-18 provides the information for
the Texas Gulf cluster. The first element in this table reports the
total crude intake for the calendar year 1973 from the BOM data, industry
data, and the ADL model run. The BOM crude input data (converted to
MB/CD) was obt/ained from Table 1-1 by adding categories l(a) + l(b),
subtracting category 24 (the ADL model did not manufacture "other" finished
products since they could not be discretely identified), plus BOM category 3
(whenever information was reported in this category). The industry data as
compiled by the EPA reflects some non-crude material being charged to
atmospheric distillation units, but in general, checks reasonably well
with BOM statistics.
Next, in Table 1-18, is a comparison of refinery energy consumption".
The BOM data for purchased natural gas is obtained from Table. 1-3 assuming
1,000 BTU's per SCF heating value. The Texas Gulf cluster model is the
only one that did not use all the available natural gas. Since total
refinery fuel usage for this category represented 12.1% of crude intake
(exclusive of purchased electricity and catalytic cracking catalyst coke),
this cluster is not typical when compared to the rest of the U. S. Since
the Texas Gulf Coast refineries have extensive specialty (i.e., lube
processing) and petrochemicals operations which are not simulated by the
ADL refinery model, we felt that it was not required that a close calibra-
tion be achieved on total refinery fuel usage and purchased natural gas.
On an FOE basis, the difference in refinery fuel consumption (13.6 MB/CD)
is similar to the difference in purchased natural gas (15.8 MB/CD), indi-
cating that internal fuel generation and consumption is in balance.
Electricity consumption (purchased and internally generated) is also shown
in the energy consumption category.
Finally, in Table 1-18, is shown a comparison entitled "Processing
Summary" presenting the various intakes/severities of the model run
results with data reported by industry and capacity data obtained from
the Oil and Gas Journal. We do not know if all the data reported by
industry on catalytic reforming severity (RON) includes those reformers
1-31
-------
Table 1-17. LOUISIANA GULF CLUSTER MODEL
Calibration Results
(MB/CD)a
Material balances
Total crude intake
Energy consumption
Purchased natural gas (FOE)
Total fuel consumption (FOE)b
Electricity MKWH/CD
Processing summary
Catalytic reforming intake
severity RON
Catalytic cracking" intake
conversion % vol.
Alkylation production
Hydrocracking intake
Coking intake
Oil and Gas
capacity MB/SD
40.5
95.0
24.0
9.5
20.0
BOM
data
219.8
5.4
17.2
606
Industry
data
216.8
32.9
92.3
90.0
70.0
17.7
6.3
19.1
Model
run
222.2
5.4
17.0
744
28.3
90.0
82.2
69.6
17.5
6.6
15.8
a MB/CD unless otherwise noted.
Excludes catalyst coke.
1-32
-------
Table 1-18. TEXAS GULF CLUSTER MODEL
Calibration Results
(MB/CD)a
Material balances
Total crude intake
Energy consumption
Purchased natural gas
(FOE)
Total fuel consumption (FOE)b
Electricity MKWH/CD
Processing summary
Catalytic reforming
Catalytic cracking
Alkylation
Hydrocracking
Coking
Isornerization
intake
severity RON
intake
conversion % vol.
production
intake
intake
intake
Oil and Gas
capacity MB/SD
82.3
114.8
20.8
21.3
21.0
2.4
BOM
data
325.9
29.2
40.2
1078
Industry
data
331.4
73.8
94.8
100.4
78.6
17.8
14.7
19.3
2.4
Model
run
331.4
13.4
26.6
1300
70.6
90.0
92.7
68.1
17.8
14.7
17.3
0.0
a-(MB/CD) unless otherwise noted.
Excludes catalyst coke.
T-33
-------
Table 1-19. LARGE MIDWEST CLUSTER MODEL
Calibration Results
(MB/CD)a
Material balances
Total crude intake
Energy consumption
Purchased natural gas (FOE)
Total fuel consumption (FOE)*5
Electricity MKWH/CD
Processing summary
Catalytic reforming intake
severity RON
Catalytic cracking intake
conversion % vol.
Alkylation production
Coking intake
Oil and Gas
capacity MB/SD
32.7
55.0
13.4
15.8
BOM
data
146.1
.2
8.1
843
Industry
data
145.5
27.8
90.7
51.2
74.9
11.4
13.6
Model
run
145.5
.2
8.4
545
27.6
90.0
48.7
74.3
12.0
, 14.1
a MB/CD unless otherwise noted.
Excludes catalyst coke.
1-34
-------
Table 1-20. SMALL MIDCONTINENT CLUSTER MODEL
Calibration Results
(MB/CD)a
Material balances
Total crude intake
Energy consumption
Purchased natural gas (FOE)
Total fuel consumption (FOE)b
Electricity MKWH/CD
Processing summary
Catalytic reforming
Catalytic cracking
Alkylation
Coking
Isomerization
intake
severity RON
intake
conversion % vol.
production
intake
intake
Oil and Gas
capacity MB/SO
15.5
22.8
5.3
4.6
1.8
BOM
data
56.1
2.0
4.4
284
Industry
data
56.6
-
13.3
85.8
20.2
76.5
5.0
4.6
1.4
Model
run
55.1
2.0
4.7
213
14.5
91.4
19.5
77.3
4.9
4.3
-
3 MB/CD unlesss otherwise noted.
Excludes catalyst coke.
I.-'3 5
-------
Table 1-21. WEST COAST CLUSTER MODEL
Calibration Results
(MB/CD)a
Material balances
Total crude intake
Energy consumption
Purchased natural gas (FOE)
Total fuel consumption (FOE)b
Electricity MKWH/CD
Processing summary
Catalytic reforming intake
severity RON
Catalytic cracking intake
conversion % vol.
Alkylation production
Hydrocracking intake
Coking intake
Oil and Gas
capacity MB/SD
43.3
51.6
7.8
27.8
42.1
BOM
data
159.6
3.4
14.0
1262
Industry
data
162.0
-
34.7
95.9
44.5
61.6
5.6
23.2
38.4
Model
run
155.2
6.4
14.8
768
37.3
92.6
35.0
61.0
5.5
22.1
39.4
aiMB/CD unless otherwise noted.
Excludes catalyst coke.
1-36
-------
Table 1-22. EAST COAST CLUSTER MODEL
Calibration Results
(MB/CD)a
Material balances
Total crude intake
Energy consumption
Purchased natural gas (FOE)
Total fuel consumption (FOE)b
Electricity MKWH/CD
Processing summary
Catalytic reforming intake
severity RON
Catalytic cracking intake
conversion % vol.
Alkylation production
Hydrocracking intake
Oil and Gas
capacity MB/SD
49.3
-
71.8
8.4
10.0
BOM
data
187.4
2.3
13.9
1365
Industry
data
186.5
-
-
40.7
93.4
73.1
71.6
6.9
7.4
Model
run
188.0
2.5
12.6
712
39.5
95.4
72.4
67.5
8.0
7.5
aMB/CD unless otherwise noted.
Excludes catalyst coke
[-37
-------
operating primarily for BTX production. The reported ADL reforming
severity is for motor gasoline blending use only.
The West Coast and East Coast cluster model runs (Tables 1-21 and
1-22) consumed more natural gas than was indicated to be available by
the BOM data. In these cases we increased the allowable maximum above
BOM statistics to account for hydrogen plant feedstock use. The Louisiana
and Texas model runs consumed more electricity than indicated by BOM data
while the other four consumed less.
The Large Midwest cluster (Table 1-19) contains two refineries built
since 1970. Since these refineries are among the most modern in the U. S.
it is expected that their fuel efficiency will be much greater than the
U. S. average. It was decided to reduce the average unit fuel consumptions
outlined in Appendix H to 80% of the usual levels to improve calibration.
After this adjustment was made, the refinery material balance and energy
consumption checked quite well against BOM data; this adjustment was main-
tained for all future runs.
Tables 1-23 through 1-28 present gasoline blending summaries for each
cluster model which include a comparison of gasoline average sulfur content,
clear pool octanes, and lead additions with industry data. For example,
4
Table 1-24 contains the gasoline blending summary for the Texas Gulf.
Included in the table is a tabulation of each blending component and the
respective volumes routed to premium, regular and low lead gasolines.
The sulfur content (PPM) is shown for each blending component and the
average for the pool was calculated to be 524 PPM compared with the re-
ported industry data of 410 PPM. The model run required 1.99 grams per
gallon of lead addition compared to the industry data of 2.09.
In general, all cluster model results checked well against industry
data in regard to pool octanes and lead addition. Sulfur contents also
checked quite well with the exception of the Louisiana Gulf Coast and
East Coast. For the Louisiana Gulf Coast the industry reported an average
of 440 PPM which appears to us to be unreasonably high considering the
average sulfur content of the crude slate to this cluster model. Con-
versely, the industry reported East Coast value of 230 PPM appears to
be low by a factor of 2-3.
1-38
-------
Table 1-23. LOUISIANA GULF CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
90 RON reformate
Cat cracker gasoline
Normal butane
Alkylate
Straight run
Light hydrocrackate
Coker gasoline
Desulf. coker gasoline
Natural gasoline
Total pool
Gasoline pool qualities
Sulfur, PPM
RON clear
MON clear
Lead addition gm/gal
Gasoline blend components, MB/CD
Premium
-
21.34
4.14
15.56
-
-
-
-
-
41.04
Regular
21.40
19.46
4.95
1.13
13.65
1.62
1.66
1.83
3.25
68.95
Low lead
3.78
3.48
.77
.76
-
-
-
-
-
8.79
Total pool
25.18
44.28
9.86
17.45
13.65
1.62
1.66
1.83
3.25
118.78
Component stream
sulfur, PPM
1
676
1
3
72
1
2359
4
20
Gasoline pool qualities
Model run
295
88.0
81.2
1.83
Industry data
440
89.0
81.6
1.77
-------
Table 1-24. TEXAS GULF CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
90 RON reformats
Cat cracker gasoline
Normal butane
Alkylate
Straight run
Light hydrocrackate
Coker gasoline
Desulf. coker gasoline
Natural gasoline
BTX raffinate
Total pool
Gasoline pool qualities
Sulfur, PPM
RON clear
MON clear
Lead addition gm/gal
Gasoline blend components, MB/CD
Premium
3.08
20.80
4.26
14.01
.34
1.69
-
-
2.95
-
47.13
Regular
43.00
17.79
5.81
-
14.30
-
1.72
.10
8.11
9.66
100.49
Low lead
-
10.76
-
3.81
-
3.43
-
-
-
-
18.00
Total pool
46.08
49.35
10.07
17.82
14.64
5.12
1.72
.10
11.06
9.66
165.62
Component stream
sulfur, PPM
1
1462
1
3
160
1
4161
4
16
1
Gasoline pool qualities
Model run
524
88.1
79.9
1.99
Industry data
410
88.2
79.7
2.09
I
-p-
o
-------
Table 1-25. SMALL MIDCONTINENT CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
90 RON reform ate
100 RON reformate
Cat cracker gasoline
Normal butane
Isobutane
Alkylate
Straight run
Coker gasoline
Natural gasoline
BTX raffinate
Total pool
Gasoline pool qualities
Sulfur, PPM
RON clear
MON clear
Lead addition gm/gal
Gasoline blend components, MB/CD
Premium
3.74
.64
-
2.51
.86
-
-
-
7.75
Regular
8.08
.74
6.97
1.96
-
2.34
2.93
.42
3.26
1.64
28.34
Low lead
_
.55
-
.04
.01
.06
-
-
.70
-
1.36
Total pool
8.08
1.29
10.71
2.64
.01
4.91
3.79
.42
3.96
1.64
37.45
Component stream
sulfur, PPM
1
1
738
1
1
3
103
1886
20
1
Gasoline pool qualities
Model run
243
87.1
81.2
1.41
Industry data
340
86.1
80.0
1.58
-------
Table 1-26. LARGE MIDWEST CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
90 RON reformate
Cat cracker gasoline
Normal butane
Alkylate
Straight run
Coker gasoline
Natural gasoline
BTX raffinate
Total pool
Gasoline pool qualities
Sulfur, PPM
RON clear
MON clear
Lead addition gm/gal
Gasoline blend components, MB/CD
Premium
_
8.57
1.66
6.27
-
-.
-
-
16.50
Regular
23.09
18.51
5.17
5.67
9.54
1.40
.71
.94
65.03
Low lead
.08
.02
.07
-
-
-
-
.17
Total pool
23.09
27.16
6.85
12.01
9.54
1.40
.71
.94
81.70
*
Component stream
sulfur, PPM
1
2265
1
1
284
4896
20
1
Gasoline pool qualities
Model run
843
88.5
81.2
1.38
Industry data
820
87.9
79.6
1.74
I
.£-
-------
Table 1-27. WEST COAST CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
100 RON reformate
95 RON reformate
90 RON reformate
Cat cracker gasoline
Normal butane
Alkylate
Straight run
Light hydrocrackate
Coker gasoline
Natural gasoline
BTX raffinate
Total pool
Gasoline pool qualities
Sulfur, PPM
RON clear
MON clear
Lead addition gm/gal
Gasoline blend components, MB/CD
Premium
11.08
-
14.49
3.10
5.53
-
2.32
-
-
-
36.52
Regular
_
-
11.07
4.06
.97
-
5.60
2.59
4.14
.81
1.49
30.73
Low lead
.25
-
-
-
.01
-
.07
.20
-
-
-
.53
Total pool
.25
11.08
11.07
18.55
4.08
5.53
5.67
5.11
4.14
.81
1.49
67.78
Component stream
sulfur, PPM
1
1
1
2047
1
3
203
1
4613
20
1
Gasoline pool qualities
Model run
860
89.0
80.3
2.11
Industry data
700
90.4
81.5
1.94
I
.£>
LO
-------
Table 1-28. EAST COAST CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component Stream
100 RON reformate
95 RON reformate
90 RON reformate
Cat cracker gasoline
Normal butane
Alkylate.
Straight run
Light hydrocrackate
Natural gasoline
BTX raffinate
Total pool
Gasoline pool qualities
Sulfur, PPM
RON clear
MON clear
Lead addition gm/gal
Gasoline blend components, MB/CD
Premium
13.87
-
-
5.39
2.97
7.98
-
-
-
-
30.21
Regular
11.24
34.23
4.33
-
10.72
1.77
4.44
1.36
68.09
Low lead
1.00
4.61
-
.55
-
-
.45
-
-
6.61
Total pool
14.87
4.61
11.24
39.62
7.85
7.98
10.72
2.22
4.44
1.36
104.91
Component stream
sulfur, PPM
1
1
1
1447
1
3
79
1
20
1
Gasoline pool qualities
Model run
556
89.5
81.8
1.60
Industry data
230
87.8
80.0
1.82
I
*-
.c-
-------
In order to improve the octane calibration, the basic gasoline blending
values shown in Table H-12 in Appendix H were modified somewhat for most
cluster models. For the Louisiana Gulf, the Large Midwest, Small
Midcontinent and East Coast all leaded research octanes were lowered
0.5 units and leaded motor octane numbers were increased 1.0 units. The
leaded motor octane numbers only were increased by 0.2 units for the Texas
Gulf Coast and no octanes were changed for the West Coast.
1-45
-------
APPENDIX J
STUDY RESULTS
-------
TABLE OF CONTENTS
APPENDIX J - STUDY RESULTS
A. MASS AND SULFUR BALANCE J-l
1. Crude-Specific Streams J-2
2. Cluster Specific. Streams J-3
3. Miscellaneous Streams J-4
LIST OF TABLES
TABLE J-l. Economic Penalty for the Manufacture of Lead-Free
Gasoline - 1977 J-5
TABLE J-2. Economic Penalty for the Manufacture of Lead-Free
Gasoline - 1980 J-6
TABLE J-3. Economic Penalty for the Manufacture of Lead-Free
Gasoline - 1985 J-7
TABLE J-4. Economic Penalty for the Introduction of Lead
Phasedown - 1977 J-8
TABLE J-5. Economic Penalty for Introduction of Lead Phasedown -
1980 J-9
TABLE J-6. Energy Penalty for the Manufacture of Lead-Free
Gasoline - 1977 J-10
TABLE J-7. Energy Penalty for the Manufacture of Lead-Free
Gasoline - 1980 J-ll
TABLE J-8. Energy Penalty for the Manufacture of Lead-Free
Gasoline - 1985 J-12
TABLE J-9. Energy Penalty for the Introduction of Lead Phasedown -
1977 , J-13
TABLE J-10. Energy Penalty for the Introduction of Lead Phasedown -
1980 J-14
TABLE J-ll. Capital Investment Requirements
for Lead Regulations J-15
TABLE J-12. Operating Costs Required to Meet Lead Regulations J-16
-------
LIST OF TABLES - (cont.)
Page
TABLE J-13. Basis for Cluster Capital Investment Requirements J-17
TABLE J-14. L.P. Model Results - Capital Investment Requirements
and Operating Costs - East Coast J-18
TABLE J-15. L.P. Model Results - Capital Investment Requirements
and Operating Costs - East Coast J-19
TABLE J-16. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Large Midwest J-20
TABLE J-17. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Large Midwest J-21
TABLE J-18. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-22
TABLE J-19. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-23
TABLE J-20. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-24
TABLE J-21. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Louisiana Gulf . . . J-25
TABLE J-22. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Texas Gulf J-26
TABLE J-23. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Texas Gulf '. . J-27
TABLE J-24. L.P. Model Results - Capital Investment Requirements
and Operating Costs - West Coast J-28
TABLE J-25. L.P. Model Results - Capital Investment Requirements
and Operating Costs - West Coast J-29
TABLE J-26. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
East of Rockies J-30
TABLE J-27. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
West of Rockies '... J-31
TABLE J-28. L.P. Model Results - Fixed Inputs and Outputs -
East Coast J-32
TABLE J-29. L.P. Model Results - Fixed Inputs and Outputs -
Large Midwest J-33
ii
-------
LIST OF TABLES - (cont.)
Page
TABLE J-30. L.P. Model Results - Fixed Inputs and Outputs -
Small Mldcontinent J-34
TABLE J-31. L.P. Model Results - Fixed Inputs and Outputs -
Louisiana Gulf J-35
TABLE J-32. L.P. Model Results - Fixed Inputs and Outputs -
Texas Gulf J-36
TABLE J-33. L.P. Model Results - Fixed Inputs and Outputs -
West Coast J-37
TABLE J-34. L.P. Model Results - Inputs and Fixed Outputs -
Grassroots Refineries J-38
TABLE J-35. L.P. Model Results - Processing and Variable-Outputs -
East Coast Cluster J-39
TABLE J-36. L.P. Model Results - Processing and Variable Outputs -
Large Midwest J-40
TABLE J-37. L.P. Model Results - Processing and Variable Outputs -
Small Midcontinent Cluster J-41
TABLE J-38. L.P. Model Results - Processing and Variable Outputs -
Louisiana Gulf Cluster J-42
TABLE J-39. L.P. Model Results - Processing and Variable Outputs -
Texas Gulf Cluster J-43
TABLE J-40. L.P. Model Results - Processing and Variable Outputs -
West Coast Cluster J-44
TABLE J-41. L.P. Model Results - Processing and Variable Outputs -
Grassroots Refineries, 1985 J-45
TABLE J-42. L.P. Model Results - Gasoline Blending - East Coast ... J-46
TABLE J-43. L.P. Model Results - Gasoline Blending - East Coast ... J-47
TABLE J-44. L.P. Model Results - Gasoline Blending -
Large Midwest J-48
TABLE J-45. L.P. Model Results - Gasoline Blending -
Large Midwest J-49
iii
-------
LIST OF TABLES - (cont.)
Page
TABLE J-46. L.P. Model Results - Gasoline Blending -
Small Midcontinent J-50
TABLE J-47. L.P. Model Results - Gasoline Blending -
Small Midcontinent ; . . . . J-51
TABLE J-48. L.P. Model Results - Gasoline Blending -
Louisiana Gulf J-52
TABLE J-49. L.P. Model Results - Gasoline Blending -
Louisiana Gulf J-53
TABLE J-50. L.P. Model Results - Gasoline Blending -
Texas Gulf J-54
TABLE J-51. L.P. Model Results - Gasoline Blending -
Texas Gulf J-55
TABLE J-52. L.P. Model Results - Gasoline Blending -
West Coast J-56
TABLE J-53. L.P. Model Results - Gasoline Blending -
West Coas t J-5 7
TABLE J-54. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries - East Coast Sweet Crude J-58
TABLE J-55. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - East Coast Sweet Crude J-59
TABLE J-56. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries - East Coast Sour Crude J-60
TABLE J-57. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - East Coast Sour Crude J-61
TABLE J-58. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - West Coast - Alaskan North SI. J-62
TABLE J-59. L.P. Model Results Summary - Gasoline Blending
Grassroots Refineries - West Coast - Alaskan North SI. J-63
TABLE J-60. L.P. Model Results - Residual Fuel Oil Sulfur
Levels - 1977 J-64
iv
-------
LIST OF TABLES - (cont.)
Page
TABLE J-61. L.P. Model Results - Residual Fuel Oil Sulfur
Levels - 1980 J-65
TABLE J-62. L.P. Model Results - Residual Fuel Oil Sulfur
Levels - 1985 J-66
TABLE J-63. L.P. Model Results - Refinery Fuel Sulfur
Levels - 1977 J-67
TABLE J-64. L.P. Model Results - Refinery Fuel Sulfur
Levels - 1980 J-68
TABLE J-65. L.P. Model Results - Refinery Fuel Sulfur
Levels - 1985 J-69
TABLE J-66. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985, Scenario B/C - Stream Values -
Gas Oil 375-650°F J-73
TABLE J-67. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf. 1985 B/C - Desulfurization of
Light Gas Oil J-74
TABLE J-68. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985, Scenario B/C - Feed Sulfur Levels ... J-75
TABLE J-69. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Stream Qualities - ,
Cluster Specific Streams J-76
TABLE J-70. Sample Calculations for Mass and Sulfur Balance -
Texas Gulf 1985, Scenario B/C - Stream Qualities -
Cluster Specific Streams J-77
TABLE J-71. Specific Gravities and Densities for the Miscellaneous
Streams J-78
TABLE J-72. Mass and Sulfar Balance - Texas Gulf Cluster 1985,
Scenario B/C J-79
-------
LIST OF FIGURES
Page
FIGURE J-l. East of Rockies Grassroots 1985 - Scenario A J-70
FIGURE J-2. West of Rockies Grassroots 1985 - Scenario A J-71
FIGURE J-3. Texas Gulf Cluster 1985 Sulfur and Material Balance J-72
VI
-------
APPENDIX J
STUDY RESULTS
This appendix gives a. detailed summary of the results of this study.
Tables J-l through J-1Q give the economic and energy penalties for the
total U.S. refining industry for the manufacture of unleaded gasoline and
the introduction of lead phasedown. These have been calculated by scaling
up the LP model results using the scale up factors derived in Appendix G.
The scaled up capital investment requirements and operating costs used in
evaluating the economic penalties are given in Tables J-ll and J-12. Table
J-13 provides existing capacity and calibration utilization of capacity for
reforming, hydrocracking, alkylation and isomerization. These figures were
used as the basis for determining capital requirements, as discussed in
Appendix E.
The LP model results are given in Tables J-14 through J-65. Capital
investments and operating costs for the LP model runs are given in Tables
J-14 through J-27. Crude slates and other inputs, product outputs, and
process unit throughput and severities are given in Tables J-28 through
J-41. Gasoline blends are given in Tables J-42 through J-59. The volumes
of refinery fuel consumed and the amount of residual fuel oil produced,
together with their sulfur levels are given in Tables J-60 through J-65.
Figures J-l and J-2 show the refinery process configurations and stream
flows for Scenario A in the East of Rockies and West of Rockies Grassroots,
respectively.
A. MASS AND SULFUR BALANCE
The computer model operates on a volumetric basis, and each process
unit yield structure was carefully checked to ensure that the volumetric
process outturns were reliable. The sulfur content of each stream was
entered in Ibs./barrel, and was similarly checked and mass balanced for
J-l
-------
specific feedstocks. At the completion of the study, it was deemed to be
desirable to illustrate the method of checking overall mass balances and
sulfur balances, for the benefit of interested parties. Hence, sample ,
calculations are provided herein to illustrate this procedure.
To complete these sample calculations, specific gravities were
assumed for every stream in the refinery simulation. Using the stream
flow rates from the computer output and the assumed gravities, the weight
balances shown in Table J-72 was constructed. Because of the time
which would be required to refine these assumed gravities, the input
and output streams do not balance precisely; hence, the results illustrate
the method of calculation, but are not indicative of the actual mass bal-
ances in the simulation.
Figure J-3 and Table J-72 detail the hydrocarbon and sulfur flows by
individual process units for the Texas Gulf cluster, with numbered arrows
on the flowsheet corresponding to stream numbers and stream names listed
on the tables. Table J-72 gives volume, mass, and sulfur flows for Scen-
ario B/C. Refinery streams of C, and lighter, as well as gases, such as
H9S and SO , are grouped in verticle output arrows on the flowsheet and in
^ X
streams labeled "light ends" on the tables.
Following is a discussion of the methodology used in the Texas Gulf
mass and sulfur balance for 1985, Scenario B/C.
1. Crude-Specific Streams
Stream values for crude-specific streams are calculated from infor-
mation on process intakes (Tables J-35 through J-41) , yield on crude or
process yields, hydrogen consumption, sulfur removal in desulfurization
and stream qualities (Appendix H).
For example, arrow //5 on Figure J-3 represents the aggregated flow
of gas oils 375-650°F for the crudes charged to the atmospheric distilla-
tion tower. The unaggregated values for each crude's gas oil is calcu-
lated and summed in Table J-66. The crude volume or charge (column 1)
multiplied by the yield on crude (column 2) gives the stream volume
(column 5). The stream volume multiplied by the stream density gives the
hydrocarbon weight for that stream. Sulfur content (column 4) divided by
J-2
-------
100 and multiplied by the hydrocarbon weight yields the sulfur weight
(column 7). Sulfur in PPM (parts per million) is derived from the hydro-
carbon and sulfur weights as shown. Stream values for other crude-spec-
ific streams are calculated in a similar manner with the exception of
reformate whose qualities for light, medium and heavy straight-run naphtha
are given in Appendix H.
Desulfurization of crude-specific streams requires additional infor-
mation on hydrogen consumption and the level of sulfur removal. For exam-
ple, desulfurization of light gas oil requires 190 SCF of hydrogen per
barrel of intake and converts 99% of the feed sulfur into H_S, leaving the
remaining 1% in the liquid output stream (see Table J-67).
Isomerization takes in desulfurized C_ to 160°F for all crudes except
Nigerian, whose undesulfurized stream is at the required 1 PPM sulfur
level.
2. Cluster-Specific Streams
Cluster-specific streams, output streams of the catalytic cracker,
coker and visbreaker, have constant specific gravities (with the exception
of desulfurized FCC feed) and sulfur contents which vary according to the
feed sulfur level (i.e., with the crude slate and cluster). The feed sul-
fur to each process unit is distributed among the products according to
the percentages given in Appendix H. Because the actual feed to these
units cannot be known-until after the LP solution has been reached, an
estimate of each unit's feed is made prior to LP optimization in order to
set output stream sulfur contents. Catalytic cracker feed is assumed to
be vacuum overhead (650-1050°F) and coker/visbreaker feed is assumed to be
vacuum bottoms (1050°F+). Each crude is assumed to be represented by a
factor equal to its percentage of the crude slate times its yield of the
specified feed stream. The hydrocracker has one cluster-specific stream,
H?S, which accumulates all feed sulfur not contained in the unit's liquid
output streams. Feed to the hydrocracker is assumed to be heavy gas oil
(500-650°F). Table J-68 shows assumed feed sulfur levels for the catalytic
cracker, visbreaker/coker and hydrocracker. Table J-69 distributes this
feed sulfur among the process output streams and lists the stream qualities
and output of H_S and SO .
2 x
J-3
-------
The cluster models allow greater flexibiity in feed streams to the
conversion units than the assumed feeds discussed above. Each unit takes
in hydrocarbons within the specified boiling range yet is not limited to
either a fixed ratio of crudes in straight-run streams nor to straight-run
streams alone. This feed flexibility and the necessity of assuming feed
sulfur in order to set product sulfur levels is a potential source of error
in the sulfur balance around each conversion unit.
3. Miscellaneous Streams
Miscellaneous streams are handled in a manner similar to the crude-
specific streams, using yield data and stream qualities.
Densities used for refinery gas, BTX, olefins, coke and hydrogen are
shown in Table J-71.
J-4
-------
Table J-1. ECONOMIC PENALTY FOR THE MANUFACTURE OF LEAD-FREE GASOLINE3 - 1977
Scenario B Versus Scenario A
Basis
Cumulative capital investment
required millions $
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Penalities
Thousands dollars per day
Capital charge (25%)a
Operating costs
Crude oil @$12.5/B
LPG @ $8.75/B
Sulfur @$10/ton
Total penalty
Lead free gasoline volume
MB/CD
Penalty $/B of lead-free
gasoline3
Penalty d/G of lead-free
gasoline3
East
Coast
-
4.7
(1.6)
(58)
59
14
-
263
Large
Midwest
-
1.3
1.4
(33)
16
(12)
-
.
465
Small
Midcontinent
29.1
0.6
0.2
20
(7)
8
(2)
-
194
Louisiana
Gulf
2.0
(3.0)
(22)
25
26
290
Texas
Gulf
131.2
8.8
6.7
90
(66)
110
(59)
566
^
East of
Rockies
Grassroots
-
-
-
-
-
Subtotal
PAD I-IV
160.3
17.4
3.7
110
(186)
218
(33)
-
109
1778
0.06
0.15
West
Coast
52.9
2.5
2.3
36
(36)
31
(20)
-
344
West of
Rockies
Grassroots
-
-
-
-
-
Subtotal
PAD V
52.9
2.5
2.3
36
(36)
31
(20)
-
11
344
0.03
0.08
Total
U.S. A.
213.2
19.9
6.0
146
(222)
249
(53)
-
120
2122
0.06
0.13
C-,
I
aBased on cumulative capital investment
-------
Table J-2. ECONOMIC PENALTY FOR THE MANUFACTURE OF LEAD-FREE GASOLINE8 - 1980
Scenario B Versus Scenario A
Basis
Cumulative capital investment
required millions $
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Penalties
Thousands dollars per day
Capital charge (25%)a
Operating costs
Crude oil @$12.5/B
LPG @ $8.75/B
Sulfur @$10/ton
Total penalty
Lead-free gasoline volume
MB/CD
Penalty $/B of lead-free
gasoline3
Penalty
-------
Table J-3. ECONOMIC PENALTY FOR THE MANUFACTURE OF LEAD-FREE GASOLINE8 - 1985
Scenario B/C Versus Scenario A
Basis
Cumulative capital investment
required millions $
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Penalties
Thousands dollars per day
Capital charge (25%)a
Operating costs
Crude oil @ $12.5/8
LPG @ $8.75/6
Sulfur @$10/ton
Total penalty
Gasoline volume MB/CD
Penalty $/B of gasoline'1
Penalty
-------
Table J-4. ECONOMIC PENALTY FOR THE INTRODUCTION OF LEAD PHASEDOWN3 -
Scenario C Versus Scenario B
1977
Basis
Cumulative capital investment
squired millions $
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Penalties
Thousands dollars per day
Capital charge (25%)a
Operating costs
Crude oil @$12.5/B
LPG @ $8.75/B
Sulfur @$10/ton
Total penalty
Total gasoline volume MB/CD
Penalty $/B of total gasoline3
Penalty d/G of total gasoline3
East
Coast
129.1
11.2
9.6
88
(2)
140
(84)
-
848
Large
Midwest
315.9
2.0
6.0
216
(4)
25
(53)
-
1446
Small
Midcontinent
44.7
2.8
2.0
31
(2)
35
(18)
-
606
Louisiana
Gulf
88.7
8.5
6.0
61
(26)
106
(53)
-
935
Texas
Gulf
647.2
25.5
17.3
443
1
319
(151)
-
1820
East of
Rockies
Grassroots
' -
-
-
-
-
Subtotal
PAD I-IV
122F.6
50.0
40.9
839
(33)
625
(359)
-
1072
5655
0.19
0.45
West
Coast
131.8
23.7
6.8
90
(51)
296
(60)
-
956
West of
Rockies
Grassroots
-
-
-
-
-
-
-
Subtotal
PAD V
Total
U.S.A.
131.8 j 1357.4
23.7
6.8
90
(51)
296
(60)
-
275
956
0.29
0.68
73.7
47.7
929
(84)
921
(419)
1347
6611
0.20
0.49
I
oo
aBased on cumulative capital investment.
-------
Table J-5. ECONOMIC PENALTY FOR INTRODUCTION OF LEAD PHASEDOWN3 - 1980
Scenario C Versus Scenario B
u,
I
VO
Basis
Cumulative capital investment
required millions $
Additional crude oil processed
Mb/CD
Additional LPG produced
MB/CD
Penalties
Thousands dollars per day
Capital charge (25%)a
Operating costs
Crude oil @ $12.5/8
LPG @ $8.75/B
Sulfur @ $10/ton
Total penalty
Total gasoline volume
MB/CD
Penalty $/B of total
gasoline3
Penalty UG of total
gasoline9
East
Coast
174.3
4.9
119
(16)
_
(43)
-
827
Large
Midwest
208.3
9.1
143
(9)
(80)
-
1403
Small
Midcontinent
196.0
6.2
134
3
(54)
-
581
Louisiana
Gulf
239.4
7.7
164
(5)
_
(67)
-
908
Texas
Gulf
355.4
-
6.3
243
(22)
(55)
-
1751
East of
Rockies
Grassroots
374.0
47.1
256
(8)
589
-
555
Subtotal
PAD I-IV
1547.4
47.1
34.2
1059
(57)
589
(299)
-
1292
6025
0.21
0.51
West
Coast
105.3
-
(8.7)
72
(17)
76
-
852
West of
Rockies
Grassroots
43.5
7.5
30
(5)
94
163
Subtotal
PAD V
148.8
7.5
(8.7)
102
(22)
94
76
250
1015
0.25
0.59
Total
U.S.A.
1696.2
54.6
25.5
1161
(79)
683
(223)
1542
7040
0.22
0.52
aBased on cumulative capital investment.
-------
Table J-6. ENERGY PENALTY FOR THE MANUFACTURE OF LEAD-FREE GASOLINE - 1977
Scenario B Versus Scenario A
Basis
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Additional purchased power
required MKWH/CD
Energy penalties
109 BTU/CD
Crude oil
LPG
Purchased power
Total penalty 109 BTU/CD
Thousands barrels of fuel oil
equivalent per calendar day
East
Coast
4.7
(1.6)
(209)
26
6
(2)
Large
Midwest
1.3
1.4
58
7
(6)
1
Small
Midcontinent
0.6
0.2
40
3
(1)
-
Louisiana
Gulf
2.0
(3.0)
38
11
12
-
Texas
Gulf
8.8
6.7
200
49
(27)
2
West
Coast
2.5
2.3
67
14
(9)
1
Total
U.S.A.
19.9
6.0
194
110
(25)
2
87
13.8
L-,
I
-------
Table J-7. ENERGY PENALTY FOR THE MANUFACTURE
Scenario B Versus Scenario
OF LEAD-FREE GASOLINE - 1980
A
Basis
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Additional purchased power
required MKWH/CD
Energy penalties
109 BTU/CD
Crude oil
LPG
Purchased power '
Total penalty 109 BTU/CD
Thousands barrels of fuel oil
equivalent per calendar day
East
Coast
7.3
(137)
(29)
(1)
Large
Midwest
12.5
254
(50)
2
i
Small
Midcontinent
5.0
115
(20)
1
Louisiana
Gulf
-
3.7
109
(15)
1
Texas
Gulf
-
18.6
587
(75)
6
East of
Rockies
Grassroots
51.1
-
558
286
6
Subtotal
PAD I-IV
51.1
47.1
1486
286
(189)
15
112
17.8
West
Coast
-
9.0
109
(36)
1
West of
Rockies
Grassroots
9.0
-
9
50
-
Subtotal
PAD V
9.0
9.0
118
50
(36)
1
15
2.4
Total
U.S.A.
60.1
56.1
1604
336
(225)
16
127
20.2
-------
Table J-8. ENERGY PENALTY FOR THE MANUFACTURE OF LEAD-FREE GASOLINE - 1985
Scenario B/C Versus Scenario Aa
Basis
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Additional purchased power
required.MKWH/CD
Energy penalties
109 BTU/CD
Crude oil
LPG
Purchased power
Total penalty 109 BTU/CD
Thousands, barrels of fuel oil
equivalent per calendar day
East
Coast
-
16.3
442
(66)
5
Large
Midwest
23.7
1541
(95)
15
Small
Midcontinent
5.8
705
(23)
7
Louisiana
Gulf
17.2
727
(69)
7
Texas
Gulf
29.0
664
(116)
7
East of
Rockies
Grassroots
228.7
2500
1280
25
Subtotal
PAD I-IV
228.7
92.0
6579
1280
(369)
66
977
155.1
West
Coast
_
0.5
742
_
(2)
7
West of
Rockies
Grassroots
26.8
26
150
-
Subtotal
PAD V
26.8
0.5
768
150
(2)
7
155
24.6
Total
U.S.A.
255.5
92.5
7347
1430
(371)
73
1132
179.7
I
f_J
NJ
aln 1985 Scenarios B and C identical.
-------
Table J-9. ENERGY PENALTY FOR THE INTRODUCTION OF LEAD PHASEDOWN - 1977
Scenario C Versus Scenario B
Basis
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Additional purchased power
required MKWH/CD
Energy penalties
109 BTU/CD
Crude oil
LPG
Purchased power
Total penalty 109 BTU/CD
Thousands barrels of fuel oil
equivalent per calendar day
East
Coast
11.2
9.6
182
63
(38)
2
Large
Midwest
2.0
6.0
189
11
(24)
2
Small
Midcontinent
2.8
2.0
100
16
(8)
1
Louisiana
Gulf
8.5
6.0
218
48
(24)
2
Texas
Gulf
25.5
17.3
651
143
(69)
7
West
Coast
23.7
6.8
436
132
(27)
4
Total
U.S.A.
73.7
47.7
1776
413
(190)
18
241
38.3
I
I>
00
-------
Table J 10. ENERGY PENALTY FOR THE INTRODUCTION OF LEAD PHASEDOWN - 1980
Scenario C Versus Scenario B
I
I'
-p*
Basis
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Additional purchased power
required MKWH/CD
Energy penalties
109 BTU/CD
Crude oil
LPG
Purchased power
Total penalty 109 BTU/CD
Thousands barrels of fuel oil
equivalent per calendar day
East
Coast
-
4.9
206
_
(20)
2
Large
Midwest
9.1
181
(36)
2
Small
Midcontinent
6.2
147
(25)
1
Louisiana
Gulf
_
7.7
219
(31)
2
Texas
Gulf
6.3
476
(25)
5
East of
Rockies
Grassroots
47.1
515
264
-
5
Subtotal
PAD I-IV
47.1
34.2
1744
264
(137)
17
144
22.9
West
Coast
(8.7)
182
35
2
West of
Rockies
Grassroots
7.5
7
42
-
Subtotal
PAD V
7.5
(8.7)
189
42
35
2
79
12.5
Total
U.S.A.
54.6
25.5
1933
306
(102)
19
223
35.4
-------
Table J-11. CAPITAL INVESTMENT REQUIREMENTS FOR LEAD REGULATIONS
Million $1st QUARTER 1975
Cluster
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
West Grassroots
East Grassroots
Totals
Scenario B versus A
Cluster investment
1977
-
-
1.5
-
9.9
3.2
1980
6.2
16.5
9.1
2.6
36.9
5.3
1985
44.0
28.5
17.2
50.9
23.6
26.5
Total
50.2
45.0
27.8
53.5
70.4
35.0
Scaled up investment
1977
-
-
29.1
-
131.2
52.9
213.2
1980
54.5
351.4
174.7
23.8
482.2
77.5
47.1
405.7
1.616.9
1985
394.3
607.0
330.2
465.3
308.7
388.4
88.8
1,265.0
3,847.7
Total
448.8
958.4
534.0
489.1
922.1
518.8
135.9
1,670.7
5,677.8
Scenario C versus B
Cluster investment
1977
14.3
14.7
2.3
9.7
49.4
8.3
1980
5.0
(5.0)
7.9
16.5
(22.2)
( 1.7)
1985
(19.3)
( 9.7)
(10.2)
(26.2)
(27.2)
( 6.6)
Total
0
0
0
0
0
0
Scaled up investment
1977
129.1
315.9
44.7
88.7
647.2
131.8
1.357.4
1980
45.2
(107.6)
151.3
150.7
(291.8)
( 26.5)
43.5
374.0
338.8
1985
( 174.3)
( 208.3)
( 196.0)
( 239.4)
( 355.4)
( 105.3)
( 43.5)
( 374.0)
(1.696.2)
Total
0
0
0
0
0
0
0
0
0
-------
Table J 12. OPERATING COSTS REQUIRED TO MEET LEAD REGULATIONS
Thousands $ Per Day
Cluster
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
West Grassroots
East Grassroots
Total
Scenario B versus A
Cluster operating cost
1977
(7.5)
(1.8)
(0.4)
(2.8)
(5.9)
(2.6)
1980
( 8.8)
( 3.3)
( 0.1)
( 8.8)
(10.0)
( 5.1)
1985
(12.8)
( 5.1)
( 0.3)
(10.4)
(18.3)
( 6.8)
(11.5)
( 5.2)
Scaled up operating cost
1977
( 57.8)
( 33.1)
( 6.6)
( 21.9)
( 66.2)
( 35.7)
(218.4)
1980
( 67.0)
( 59.8)
( 1.6)
( 68.8)
(110.7)
( 61.8)
( 18.0)
( 29.0)
(426.2)
1985
( 97.4)
( 92.4)
( 4.9)
( 81.3)
(202.6)
( 82.7)
( 34.5)
( 78.5)
(671.9)
Scenario C versus B
Cluster operating
cost
1977
(0.2)
(0.2)
(0.1)
(3.3)
0.1
(3.7)
1980
(2.1)
(0.5)
0.2
(0.7)
(2.0)
(1.4)
Scaled up operating
cost
1977
( 1-6)
( 3.6)
( 1.7)
(25.8)
1.1
(50.8)
(82.4)
1980
(15.9)
( 9.1)
3.2
( 5.5)
(22.2)
(16.9)
( 5.0)
( 7.6)
(79.0)
-------
Table J-13. BASIS FOR CLUSTER CAPITAL INVESTMENT REQUIREMENTS
Existing Capacity Versus Calibration Run Requirement
Process'(MB/CD)
Reforming
Existing capacity for BTX
Existing capacity for mogas - high severity
low severity
1973 Calibration utilization high severity
- low severity
Spare capacity available
Hydrocracking
Existing capacity high severity
medium severity
1973 Calibration utilization high
medium
Spare capacity available
Alkylation
Existing capacity
1973 Calibration utilization
Spare capacity available
Isomerization .
Existing capacity - once through
1973 Calibration utilization
Spare capacity available
East
Coast
3.5
7.0
31.4
7.0
29.0
2.4
7.2
1.3
6.2
1.3
1.0
7.1
8.0
-
Large
Midwest
2.3
4.6
20.9
-
25.3
0.2
-
-
-
11.4
12.0
-
Small
Midcont.
4.3
8.9
-
10.2
-
-
-
-
-
-
4.5
4.9
-
1.5
1.5
Louisiana
Gulf
8.6
25.8
28.3
6.1
-
8.1
6.6
1.5
20.4
17.5
2.9
-
Texas
Gulf
20.3
49.7
50.4
18.1
14.7
3.4
17.7
17.8
-
2.0
2.0
West
Coast
16.3
20.5
21.0
-
23.6
22.1
1.5
6.6
5.5
1.1
-
C-,
I
-------
Table J 14. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: East Coast
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: existing capacity
new capacity
Hydrocracking: existing capacity
new capacity
Alkylation: existing capacity
new capacity
Hydrogen manufacture: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Purchased steam
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: A
1977
1.6
3.6
1.1
5.3
2.1
2.3
16.0
6.4
22.4
26.4
5.7
1980
_
'-
_
-
-
5.7
17.0 : 16.9
15.2 : 15.2
27.3 27.3
52.8
20.9
14.5
153.4
52.8
22.7
14.4
155.0
1985
_
0.1
_
-
0.1
-
0.1
0.1
Total
1.6
3.6
1.1
5.4
_
2.1
2.3
16.1
6.4
22.5
26.5
5.7 !
16.8
15.1
27.3 ;
52.8
25.8
14.3 j
157.8
J-18
-------
Table J 15. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
Cluster: East Coast
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: existing capacity
severity upgrade
new capacity
Hydrocracking: existing capacity
new capacity
Isomurization: once through upgrading
new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Purchased stream
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: B
1977
1.6
4.6
1.1
0.5
_
_
3.5
-
11.3
4.5
15.8
18.6
5.7
16.4
15.3
26.8
52.6
13.9
15.2
145.9
1980
7.0
0.1
_
0.4
0.8
0.2
8.5
3.4
11.9
14.0
5.7
16.5
15.6
27.7
52.9
11.4
16.4
146.2
1985
12.6
0.3
0.3
8.8
2.5
2.3
26.8
10.7
37.5
44.1
5.7
18.0
16.6
30.8
53.S
-
20.1
145.0
Total
1.6
19.6
4.6
1.1
0.9
0.3
9.2
6.8
2.5
46.6
18.6
65.2
76.7
Scenario: C
1977
1.6
11.9
4.5
1.1
0.7
0.1
4.8
-
24.7
9.9
34.6
40.7
5.7
16.8
15.9
28.3
53.1
8.6
17.3
145.7
1980
1.8
0.1
2.1
1.7
1.1
6.8
2.7
9.5
11.2
5.7
17.1
16.2
29.1
53.3
4.3
18.4
144.1
1985
6.0
0.1
1.9
5.3
0.4
1.4
15.1
6.0
21.1
24.8
5.7
18.0
16.6
30.8
53.8
20.1
145.0
Total
1.6
19.7
4.5
1.1
0.9
1.9
7.5
6.9
2.5
46.6
18.6
65.2
76.7
I
M
VD
-------
Table J-16. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Large Midwest
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: existing capacity
new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: A
1977
_
-
-
9.7
11.3
20.1
38.0
11.5
10.0
100.6
1980
_
-
9.8
11.5
20.1
38.0
12.9
10.4
102.7
1985
0.1
1.1
1.2
0.5
1.7
2.0
9.9
11.3
20.1
38.0
14.7
9.7
103.7
Total
0.1
1.1
1.2
0.5
1.7
2.0
J-20
-------
Table J-17. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
Cluster: Large Midwest
Capital investments (million dollars)
(1stQ 1975 Basis)
Reforming: existing capacity
severity upgrade
new capacity
Isomerization: new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
. : _
Scenario: B
1977
_
-
-
-
-
-
-
_
-
9.7
11.3
20.1
38.0
9.6
10.1
98.8
1980
0.1
9.4
0.5
-
-
-
10.0
4.0
14.0
16.5
10.1
11.7
21.3
38.3
6.5
11.5
99.4
1985
_
4.3
2.3
8.7
-
2.2
17.5
7.0
24.5
28.8
11.1
12.0
23.3
38.9
13.3
98.6
Total
0.1
13.7
2.8
8.7
-
2.2
27.5
11.0
38.5
45.3
Scenario: C
1977
0.1
7.4
1.4
-
-
-
8.9
3.6
12.5
14.7
9.8
11.3
21.1
38.3
7.8
10.3
98.6
1980
_
5.9
-
-
1.1
-
7,0
2.8
9.8
11.5
10.3
11.9
21.9
38.5
3.8
12.5
98.9
1985
0.4
1.4
8.7
-
2.2
12.7
5.0
17.7
20.8
11.1
12.0
23.3
38.9
13.3
98.6
Total
0.1
13.7
2.8
8.7
1.1
2.2
28.6
11.4
40.0
47.0
I
NJ
-------
Table J 18. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Small Midcontinent
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: severity upgrade
new capacity
Alkylation: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: A
1977
0.9
0.2
1.1
0.4
1.5
1.8
3.8
4.4
7.6
20.8
4.2
4.6
45.4
1980
-
_
-
3.8
4.4
7.6
20.8
4.5
4.6
45.7
1985
4.3
-
4.3
1.7
6.0
7.0
3.6
4.3
7.6
20.8
5.4
4.8
46.5
Total
4.3
0.9
0.2
5.4
2.1
7.5
8.8
J-22
-------
Table J-19. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
C-i
I
NJ
OJ
Cluster: Small Midcontinent
Capital investments (million dollars)
(1stQ 1975 Basis)
Reforming: severity upgrade
new capacity
Isomerization: existing capacity'
new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: B
1977
1.2
_
0.6
0.2
-
2.0
0.8
2.8
3.3
3.8
4.4
7.7
20.8
3.6
4.7
45.0
1980
4.2
-
0.1
1.2
-
-
5.5
2.2
7.7
9.1
3.9
4.5
8.3
21.0
2.8
5.1
45.6
1985
5.9
0.3
1.4
4.6
0.9
1.6
14.7
5.9
20.6
24.2
4.'4
4.7
9.6
21>.4
6.1
\
46.2
Total
10.1
1.5
1.5
6.4
1.1
1.6
22.2
8.9
31.1
36.6
Scenario: C
1977
2.2
_
1.0
0.2
-
3.4
1.4
4.8
5.6
3.9
4.5
7.9
20.9
2.9
4.8
44.9
1980
7.9
-
2.2
0.2
-
10.3
4.1
14.4
17.0
4.1
4.5
9.1
21.2
1.4
5.5
45.8
1985
1.6
-
1.4
3.2
0.7
1.6
8.5
3.4
11.9
14.0
4.4
4.7
9.6
21.4
_
6.1
46.2
Total
9.5
2.2
1.4
6.4
1.1
1.6
22.2
8.9
31.1
36.6
-------
TaWe J-20. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Louisiana Gulf
Capital investments (million dollars)
(1st Q 1975 Basis)
Hydrocracking: existing capacity
new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: A
1977
1.6
0.7
2.3
0.9
3.2
3.8
11.2
16.1
27.7
43.4
20.9
11.7
131.0
1980
_
-
-
11.3
16.2
27.7
43.4
21.8
11.9
132.3
1985
-
-
11.1
16.1
27.7
43.4
22.5
11.8
132.6
Total
1.6
0.7
2.3
0.9
3.2
3.8
J-24
-------
Table J 21. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
I
K3
Cluster: Louisiana Gulf
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: existing capacity
severity upgrade
new capacity
Hydrocracking: existing capacity
new capacity
Isomerization: new capacity
Alkylation: existing capacity
Light naphtha desulfurization: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: B
1977
_
-
-
1.6
0.7
-
-
-
2.3
0.9
3.2
3.8
11.2
16.2
27.7
43.4
17.9
11.8
128.2
1980
1.0
0.6
-
-
-
-
1.6
0.6
2.2
2.6
11.6
16.4
27.9
43.4
11.5
12.7
123.5
1985
3.0
16.3
0.8
7.3
0.8
2.6
30.8
12.3
43.1
50.7
12.3
17.3
31.5
44.5
16.6
122.2
Total
4.0
16.9
0.8
1.6
0.7
7.3
0.8
2.6
34.7
13.8
48.5
57.1
Scenario: C
1977
1.3
4.5
-
1.6
0.8
-
-
-
8.2
3.3
11.5
13.5
11.6
16,5
28.4
43.6
11.7
13.1
124.9
1980
0.9
10.6
-
-
0.1
-
11.6
4.6
16.2
19.1
12.0
16.9
29.7
44.0
5.7
14.5
122.8
1985
1.8
1.8
0.8
7:3
0.7
2.6
15.0
6.0
21.0
24.7
12.3
17.3
31.5
44.5
16.6
122.2
Total
4.0
16.9
0.8
1.6
0.8
7.3
0.8
2.6
34.8
13.9
48.7
57.3
-------
Table J 22. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Texas Gulf
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: severity upgrade
new capacity
Hydrocracking: existing capacity
severity change
new capacity
Hydrogen manufacture: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: A
1977
1.6
4.3
1.2
1.5
0.7
9.3
3.7
13.0
15.3
18.8
23.2
43.3
113.7
34.2
21.1
254.3
1980
_
_
-
-
-
-
18.6
22.7
43.3
113.7
35.7
20.5
254.5
1985
_
0.6
-
9.4
5.7
15.7
6.3
22.0
25.9
19.3
22.4
43.3
113.7
34.9
21.2
254.8
Total
1.6
0.6
4.3
1.2
10.9
6.4
25.0
10.0
35.0
41.2
J-26
-------
Table J-23. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
I
t-O
I
Cluster: Texas Gulf
Capital investments (million dollars)
. (1st Q 1975 Basis)
Reforming:
severity upgrade
new capacity
Hydrocracking: existing capacity
severity change
new capacity
Isomerization: existing capacity
once through upgrading
new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: B
1977
9.4
-
4.3
0.3
1.3
-
-
-
15.3
6.1
21.4
25.2
19.0
23.4
44.0
113.9
26.0
22.1
248.4
1980
16.3
2.9
1.5
0.4
1.1
0.2
-
-
,, 22.4
9.0
31.4
36.9
19.4
23.8
46.6
114.6
16.0
24.1
244.5
1985
7.3
0.5
1.8
1.0
0.1
13.1
1.8
4.3
29.9
12.0
41.9
49.2
20.2
24.2
48.3
115.1
28.7
236.5
Total
33.0
3.4
4.3
3.6
2.7
1.2
0.2
13.1
1.8
4.3
67.6
27.1
94.7
111.3
Scenario: C
1977
30.7
0.8
4.3
3.0
2.0
1.2
1.1
0.7
1.3
0.2
45.3
18.1
63.4
74.6
19.7
24.4
47.5
114.9
15.9
26.1
248.5
1980
1.3
1.7
_
-
_
-
4.7
-
1.2
8.9
3.6
12.5
14.7
20.0
24.4
48.5
115.2
7.8
26.6
242.5
1985
Total
i
t
1.0 33.0
0.9 ; 3.4
1 4.3
0.6 ; 3.6
0.8 ; 2.8
1-2
6.9
0.6
2.8
13.6
5.4
19.0
22.3
20.2
1.1
12.3
1.9
4.2
67.8
27.1
94.9
111.6
24.2
48.3
115.1
_
28.7
236.5
-------
Table J-24. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: West Coast
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: new capacity
Hydrocracking: existing capacity
new capacity
Alkylation: existing capacity
new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: A
1977
0.8
1.6
4.1
1.5
8.0
3.2
11.2
13.2
15.2
12.3
27.5
70.4
16.2
13.1
154.7
1980
-
_
0.1
1.1
1.2
0.5
1.7
2.0
15.3
12.7
27.5
70.4
12.8
13.2
151.9
1985
-
_
-
_
-
-
_
-
15.0
11.8
27.5
70.4
14.3
13.6
152.6
Total
0.8
1.6
4.1
1.6
1.1
9.2
3.7
12.9
15.2
J-28
-------
Table J 25. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
t_l
ISJ
- .. ;-,; v
Cluster: West Coast
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: severity upgrade
new capacity
Hydrocracking: existing capacity
new capacity
Isomerizatibn: new capacity
Alkylation: existing capacity
new capacity
Light naphtha desulfurization: new capacity
Subtotals
Offsites and working capital at 40%
Subtotals
Totals (adjusted for stream day)
Operating costs (thousands of dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario: B
1977
2.0
0.8
1.6
4.1
-
1.4
-
-
9.9
4.0
13.9
16.4
15.3
12.4
27.7
70.4
12.9
13.4
152.1
1980
2.9
-
_
-
-
0.1
1.4
-
4.4
1.8
6.2
7.3
15.4
12.9
28.0
70.6
6.0
13.9
146.8
1985
8.9
0.1
4.8
0.8
1.6
16.2
6.4
22.6
26.6
16.2
12.5
29.6
71.0
-
16.5
145.8
Total
13.8
0.9
1.6
4.1
4.8
1.5
2.2
1.6
30.5
12.2
42.7
50.3
Scenario: C
1977
5.2
0.8
1.6
4.1
-
1.5
1.8
-
15.0
6.0
21.0
24.7
15.5
12.1
28.2
70.6
6.9
15.1
148.4
1980
3.4
_
-
_
.-
3.4
1.4
4.8
5.6
15.7
12.3
28.4
70.6
3.5
14.9
145.4
1985
Total
i
i
!
5.2 13.8
0.1 | 0.9
_
4.8
_
0.4
1.6
12.1
4.8
16.9
19.9
16.2
12.5
29.6
71.0
-
16.5
145.8
1.6
4.1
4.8
1.5
2.2
1.6
30.5
12.2
42.7
50.2
-------
Table J-26. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Grassroots Refinery East of Rockies
Total capital investments (million dollars)
(1st Q 1975 basis)
Operating costs (thousands dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Totals
Scenario A
sweet
544.5
13.3
3.3
20.7
20.5
24.4
7.5
89.7
sour
698.1
19.9
4.2
26.9
32.0
24.8
16.0
123.8
Scenario C
sweet
651.3
16.4
4.1
28.2
22.7
-
13.4
84.8
sour
798.4
23.0
4.9
34.0
34.1
-
22.4
118.4
J-30
-------
Table J-27. L.P. MODEL RESULTS - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Grassroots Refinery West of Rockies
Total capital investments (million dollars)
(1st Q 1975 Basis)
Operating costs (thousand dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Tetra ethyl lead
Catalysts and chemicals
Total
Scenario A
722.8
23.0
4.6
30.1
32.5
19.3
16.2
125.7
Scenario C
764.5
23.1
5.1
33.0
33.4
-
19.6
114.2
J-31
-------
Table J-28. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: East Coast
Inputs
Tia Juana Medium crude oil
Saudi Arabian Light crude oil
Nigerian Forcados crude oil
Algerian Hassi Messoud crude oil
Isobutanes
Normal butanes
Natural gas (purchased refinery fuel)
Natural gasoline
Intermediate product transfer-cat feed
Intermediate product transfer-reformer
feed
Total
Outputs
Naphtha
Jet Fuel
Kerosine
Number 2 heating oil
Residual fuel oil
Lubes
Asphalt
BTX
Refinery gas
Olefin sales to petrochemicals
Total
Year
1977
52.448
70.656
34.042
40.771
0.315
1 .584
1.875
5.840
11.100
5.980
224.611
1.333
6.001
3.532
47.431
13.36B
5.147
18.891
1.417
0.896
4.303
102.319
1980
42.550
80.550
36.020
38.790
0.280
1.400
1.250
5.840
11.100
5.980
223.760
1.328
5.978
3.518
47.249
13.317
5.127
18.818
1.411
0.892
4.286
101.924
1985
32.656
90.447
38.000
36.812
0.245
1.232
-
5.840
11.100
5.980
222.312
1.320
5.941
3.497
46.954
13.234
5.096
18.700
1.403
0.887
4.260
101.292
J-32
-------
Table J-29. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: Large Midwest
Inputs
West Texas Sour crude oil
South Louisiana Mix crude oil
Oklahoma crude oil
Canadian interprovincial mix crude oil
Saudi Arabian Light crude oil
Isobutanes
Natural gas (purchased refinery fuel)
Natural gasoline
Intermediate product transfer-cat feed
Intermediate product transfer-reformer
feed
Total
Outputs
Naphtha
Jet fuel
Kerosine
Number 2 heating oil
Residual fuel oil
Asphalt
Coke
BTX
Total.
Year
1977
93.386
4.303
6.886
7.459
31.416
3.330
0.180
0.837
1.215
0.654
149.666
2.122
2.083
1.631
40.090
7.261
3.744
3.616
0.924
61.471
1980
86.213
6.599
50.638
2.960
0.120
0.744
1.215
0.654
149.143
2.115
2.076
1.625
39.948
7.236
3.730
3.603
0.920
61.253
1985
79.041
6.312
-
58.097
2.590
0.651
1.215
0.654
148.560
2.107
2.068
1.619
39.790
7.207
3.716
3.589
0.917
61.013
J-33
-------
Table J 30. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: Small Midcontinent
Inputs
West Texas Sour crude oil
South Louisiana Mix crude oil
Oklahoma crude oil
Canadian Interprovincial Mix crude oil
Saudi Arabian Light crude oil
Algerian Hassi Messoud crude oil
Isobutanes
Normal butanes
Natural gas (purchased refinery fuel)
Natural gasoline
Intermediate product transfer-cat feed
Intermediate product transfer-reformer feed
Total
Outputs
Naphtha
Jet fuel
Kerosene
Number 2 heating oil
Residual fuel oil
Lubes
Asphalt
Coke
BTX ,
Refinery gas
Olefin sales to petrochemicals
Total
Year
1977
6.593
3.296
32.855
4.835
3.681
3.681
0.846
0.279
1.535
4.950
0.436
0.235
63.222
0.343
0.900
0.039
15.698
0.225
0.333
1.771
1.282
1.370
0.528
0.587
23.076
1980
6.043
1.648
31.756
-
7.747
7.747
0.752
0.248
1.023
4.400
0.436
0.235
62.035
0.336
0.883
0.038
15.400
0.221
0.326
1.738
1.258
1.344
0.518
0.576
22.638
1985
5.494
-
30.657
'-
9.395
9.395
0.658
0.217
-
3.850
0.436
0.235
60.337
0.327
0.859
0.037
14.973
0.215
0.317
1.690
1.223
1.307
0.504
0.560
22.012
J-34
-------
Table J 31. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: Louisiana Gulf
Inputs
West Texas Sour crude oil
South Louisiana Mix crude oil
Isobutanes
Normal butanes
Natural gas (purchased refinery fuel)
Natural gasoline
Total
Outputs
Naphtha
Jet fuel
Kerosine
Number 2 heating oil
Residual fuel oil
Asphalt
Coke
Refinery gas
Olefin sales to petrochemicals
Intermediate product transfer-cat feed
Intermediate product transfer-reformer
feed
Total
Year
1977
25.723
192.270
5.490
5.373
4.050
3.852
236.758
0.757
17.984
5.338
65.801
5.192
1.504
3.999
0.311
2.329
2.078
1.120
106.413
1980
25.723
192.270
4.880
4.776
2.700
3.424
233.773
0.747
17.757
5.271
64.972
- 5.127
1.485
- 3.948
0.307
2.300
2.078
1.120
105.112
1985
25.723
192.270
4.700
4.179
-
3.000
229.872
0.734
17.427
5.173
63.763
5.032
1.458
3.870
0.301
2.257
2.078
1.120
103.213
J-35
-------
Table J-32. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: Texas Gulf
Inputs
West Texas Sour crude oil
South Louisiana Mix crude oil
Tia Juana Medium crude oil
Saudi Arabian Light crude oil
Nigerian Forcados crude oil
1 so butanes
Normal butanes
Natural gas (purchased refinery fuel)
Natural gasoline
Total
Outputs
Naphtha
Jet fuel
Kerosene
Number 2 heating oil
Residual fuel oil
Lubes
Asphalt
Coke
BTX
Refinery gas
Olefin sales to petrochemicals
Intermediate product transfer-cat feed
Intermediate product transfer-reformer feed
Total
Year
1977
135.964
155.669
6.897
17.405
12.480
1.917
1.845
10.085
14.400
356.662
8.598
22.952
7.524
81.363
15.321
16.112
1.368
3.908
5.911
0.821
3.879
1.954
4.842
174.553
1980
135.964
155.669
6.897
17.405
12.480
1.704
1.640
6.724
12.800
351.283
8.468
22.604
7.410
80.131
15.089
15.868
1.347
3.849
5.822
0.808
3.820
1.925
4.768
171.909
1985
i
135.964
155.669
6.897
17.405
12.480
1.491
1.435
-
11.200
342.541
8.258
22.043
7.226
78.141
14.714
15.474
1.314
3.754
5.677
0.788
3.725
1.877
4.650
167.641
J-36
-------
Table J-33. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: West Coasi
Inputs
California Ventura crude oil
California Wilmington crude oil
Alaskan North Slope crude oil
Canadian Interprovincial Mix crude oil
Saudi Arabian Light crude oil
Indonesian Minas crude oil
Isobutanes
Normal butanes
Natural gas (purchased refinery fuel)
Natural gasoline
Intermediate product transfer-cat feed
Intermediate product transfer-reformer
feed
Total
Outputs
Naphtha
Jet fuel
Kerosine
Number 2 heating oil
Residual fuel oil
Lubes
Asphalt
Coke - low sulfur
BTX
Refinery gas
Olefin sales to petrochemicals
Total
Year
1977
21.673
65.676
-
5.580
54.840
16.420
0.450
0.144
4.793
1.170
3.597
1.937
176.280
3.978
20.765
0.177
23.125
31.894
0.365
2.109
10.002
4.072
0.480
1.357
98.324
1980
21.673
65.676
76.841
-
-
-
0.400
0.128
3.195
1.040
3.597
1.937
174.487
3.936
20.548
0.176
22.883
31.561
0.362
2.087 -
9.897
4.029
0.475
1.343
97.297
1985
21.673
65.676
76.841
-
-
-
0.350
0.112
-
0.910
3.597
1.937
171.096
3.900
20.364
0.174
22.678
31.279
0.358
2.068
7.790
3.993
0.470
1.331
94.405
J-37
-------
Table J-34. L.P. MODEL RESULTS: - INPUTS AND FIXED OUTPUTS
Grassroots Refineries
(MB/CD)
Inputs
Scenario
A
C
Fixed outputs
Jet fuel
Kerosine
Number 2 heating oil
Residual fuel oil
Total
East of Rockies
Sour crude refinery
Arabian Light
crude oil
182.677
196.978
Sweet crude refinery
Nigerian Algerian
crude oil crude oil
90.033
96.768
East of Rockies
9.700
2.900
46.900
32.900
92.400
90.033
96.768
West of Rockies
Alaska North Slope
crude oil
198.048
206.277
West of Rockies
31.200
30.900
45.500
107.600
J-3G
-------
Table J 35. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
East Coast Cluster
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion vol %
Hydrocracking
High severity
Medium severity
Total
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Hydrogen manufacture (MMSCF/CD)
Desulfurization
Light naphtha (isom. feed)
Medium naphtha (ref. feed)
Cat cracker cycle oil
Straight run distillate
Total
Scenario A
1977
110.972
4.634
112
52
47.1
43.6
90.0
55.2
55.2
80.4
8.2
5.2
13.4
-
-
9.5
32.9
36.1
3.4
18.0
57.5
1980
111.524
3.954
111
52
47.0
43.5
90.0
58.2
58.2
78.3
3.9
9.5
13.4
-
-
9.5
29.9 ,
37.9
5.3
12.4
55.6
1985
110.785
3.981
109
54
47.0
43.5
90.1
56.8
56.8
79.1
4.1
9.4
13.5
-
-
9.5
30.6
37.7
4.5
10.6
52.8
Scenario B
1977
110.424
4.402
103
50
47.9
44.4
92.3
53.4
53.4
84.4
9.0
9.0
-
-
10.5
25.7
37.6
0.7
20.2
58.5
1980
109.817
4.910
104
51
45.8
42.3
95.6
58.5
58.5
81.9
6.7
2.3
9.0
0.6
0.6
11.1
24.6
0.6
36.3
2.4
15.3
54.6
1985
106.915
6.119
114
59
46.5
43.0
100.0
62.2
62.2
83.6
1.4
8.0
9.4
0.1
7.6
7.7
12.9
20.7
7.7
36.5
4.1
12.9
61.2
Scenario C
1977
109.109
5.579
104
51
47.8
44.3
97.0
55.6
55.6
85.0
5.4
3.8
9.2
0.2
0.2
11.4
24.2
0.2
38.1
0.1
19.7
58.1
1980
108.723
5.561
106
54
45.8
42.3
98.0
60.5
60.5
84.1
4.2
5.1
9.3
3.2
0.2
3.4
12.6
22.7
3.4
35.8
2.3
13.7
55.2
1985
106.915
6.119
114
59
46.5
43.0
100.0
62.2
62.2
83.6
1.4
8.0
9.4
0.1
7.6
7.7
12.9
20.7
7.7
36.5
4.1
12.9
61.2
-------
Table J-36. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Large Midwest
I
J>
o
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion vol %
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Coking
Hydrogen manufacturing (MMSCF/CD)
Desulfurization
Light naphtha (isom. feed)
Medium naphtha (ref. feed)
Medium coker naphtha (ruf. feed)
Cat cracker cycle oil
Straight run distillate
Total
Scenario A
1977
79.463
2.716
154
62
27.3
25.0
91.7
51.8
51.8
70.8
-
-
11.6
14.1
-
-
22.5
2.5
10.7
22.4
58.1
1980
78.635
2.807
174
70
26.8
24.5
91.5
51.6
51.6
72.4
-
-
12.0
14.0
-
-
22.0
2.5
10.7
26.1
61.3
1985
78.570
2.683
176
69
29.2
26.9
91.4
52.2
52.2
67.5
-
-
10.8
14.1
-
26.7
2.5
13.0
23.6
65.8
Scenario B
1977
79.398
2.793
154
62
27.4
25.1
92.4
51.8
51.8
70.8
-
11.6
14.1
-
22.6
2.5
10.7
22.4
58.2
1980
78.070
3.498
174
70
28.4
26.1
97.5
51.6
51.6
72.4
-
12.0
14.0
-
22.7
2.5
10.7
25.8
61.7
1985
76.615
4.063
174
73
31.4
29.1
100.0
51.6
51.6
72.4
7.0
7.0
12.0
14.0
-
7.0
28.8
2.5
10.7
23.8
72.8
Scenario C
1977
79.295
3.121
156
61
29.6
27.3
96.5
52.4
52.4
66.6
-
10.6
14.3
-
19.0
2.5
13.4
24.8
59.7
1980
77.425
3.999
174
71
29.0
26.7
100.0
51.2
51.2
75.6
_
-
12.8
13.9
-
21.8
2.5
9.2
26.4
59.9
1985
76.615
4.063
174
73
31.4
29. i
100.0
51.6
_
51.6
72.4
7.0
7.0
12.0
14. n
-
7.0
28. B
2.5
10.7
23.8
72.8
-------
Table J 37. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Small Midcontinent Cluster
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion vol %
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Coking
Desulfurization
Light naphtha (isom. feed)
Medium naphtha (ref. feed)
Medium coker naphtha (ref. feed)
Cat cracker cycle oil
Straight run distillate
Total
Scenario A
1977
36.922
1.320
14
21
13.9
9.6
90.0
17.7
17.7
85.0
-
-
-
5.0
4.0
14.0
0.7
1.1
15.8
1980
36.219
1.261
15
21
13.7
9.4
90.0
17.7
17.7
85.0
-
-
-
5.0
4.0
13.8
0.7
0.2
0.8
15.5
1985
35.174
1.366
17
25
11.0
6.7
90.0
17.6
17.6
85.0
-
-
-
5.0
3.9
11.0
0.7
2.0
-
13.7
Scenario B
1977
36.889
1.331
14
21
14.0
9.7
90.0
17.7
17.7
85.0
0.3
0.3
5.0
4.0
0.3
14.1
0.7
1.1
16.2
1980
35.874
1.569
16
22
13.5
9.2
96.9
17.7
17.7
85.0
0.1
0.9
1.0
5.0
4.0
1.0
13.5
0.7
0.3
0.8
16.3
1985
34.016
1.720
19
24
14.2
9.9
100.0
18.9
-
18.9
85.0
1.4
3.2
4.6
5.4
3.4
4.6
13.5
0.6
2.4
-
21.1
Scenario C
1977
36.732
1.454
14
21
14.7
10.4
90.7
17.7
17.7
85.0
-
0.5
0.5
5.0
4.0
0.5
14.0
0.7
1.2
16.4
1980
35.472
1.948
16
22
14.0
9.7
98.7
17.9
17.9
85.0
-
1.6
1.6
5.1
4.0
1.6
13.3
0.7
0.3
0.8
16.7
19
34
1
19
24
14
9
100.
18
-.
18
85
1
3
4
P,
^
4
1:
0
2
-
21
1.720
-------
Table J 38. L.I' MODEL UESULTS PROCESSING AND VARIABLE OUTPUTS
Louisiana Gulf Cluster
I
.IN
ho
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total .
Conversion vol %
Hydrocracking
High severity
Medium severity
Total
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Coking
Hydrogen manufacturing (MMSCF/CD)
Desulfurization
Light naphtha (isom. feed)
Medium naphtha (ref. feud)
Medium coker naphtha (ref. feed)
Cat cracker feed
Straight inn distillate
Total
Scenario A
1977
119.104
3.223
57
18
27.2
27.2
90.0
68.1
16.1
84.2
66.4
_
8.8
8.8
_
_
-
16.9
18.6
23.9
_
24.4
3.2
16.1
2.6
46.3
1980
118.130
2.855
60
22
27.0
27.0
90.0
55.9
26.3
82.2
67.4
0.1
8.8
8.9
_
._
-
16.9
18.3
21.0
_
24.4
3.1
26.3
2.6
56.4
1985
116.277
2.878
60
23
28.2
28.2
90.0
54.0
26.3
80.3
67.7
0.3
8.5
8.8
_
_
-
16.6
17.9
20.0
_
24.3
3.1
26.4
2.7
56.5
Scenario B
1977
119.328
2.843
57
18
27.5
27.5
90.0
68.2
16.4
84.6
66.4
8.8
8.8
_
_
-
17.0
18.6
23.9
_
24.4
3.2
16.4
2.6
46.6
1980
117.446
3.324
59
22
29.8
29.8
93.2
59.2
24.4
83.6
67.2
_
8.8
8.8
_
_
-
17.2
18.3
21.8
_
24.4
3.2
24.5
2.6
54.7
1985
112.488
5.082
60
24
35.5
35.5
100.0
53.9
26.3
80.2
71.6
_
8.8
8.8
4.7
3.5
8.2
18.1
17.6
17.5
8.2
30.0
3.1
26.4
2.7
70.4
Scenario C
1977
118.346
3.588
58
18
30.3
30.3
95.1
68.3
17.9
86.2
66.6
_
8.8
8.8
'
_
17.4
18.7
23.9
...
24.3
3.2
18.0
2.6
48.1
1980
116.110
4.315
61
22
31.7
31.7
100.0
59.4
26.3
85.7
67.3
8.8
8.8
_
-
17.7
18.4
21.8
25.8
3.2
26.4
2.6
58.0
1985
112.488
5.082
60
24
35.5
35.5
100.0
53.9
26.3
80.2
71.6
_
8.3
8.8
4.7
3.5
8.2
18.1
17.6
17.5
8..?
30.0
3.1
26.4
2.7
70.4
-------
Table J-39. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Texas Gulf Cluster
I
^
OJ
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion vol %
Hydrocracking
High severity
Medium severity
Total
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Coking
Hydrogen Manufacture (MMSCF/CD)
Desulfurization
Light naphtha (isom. feed)
Medium naphtha (ref. feed)
Medium coker naphtha (ref. feed)
Cat cracker cycle oil
Straight run distillate
Total
Scenario A
1977
164.006
5.263
187
72
65.8
45.1
90.5
98.1
98.1
65.0
13.2
6.3
19.5
-
15.0
19.1
44.9
43.0
3.2
26.4
6.6
79.2
1980
161.364
5.268
179
86
68.2
48.1
90.1
90.5
90.5
65.1
19.0
0.3
19.3
-
14.7
18.5
47.9
43.1
3.1
24.3
6.9
77.4
1985
157.251
5.392
177
79
70.4
51.2
91.2
85.0
85.0
65.0
13.4
14.7
28.1
-
14.7
18.0
69.7
42.7
3.1
9.6
5.6
61.0
Scenario B
1977
163.300
5.849
183
72
69.4
49.5
92.9
94.2
94.2
65.0
16.8
2.5
19.3
-
16.6
18.9
46.7
42.8
3.2
25.3
7.0
78.3
1980
159.451
6.950
182
87
72.6
54.2
97.9
92.8
92.8
65.1
10.7
9.0
19.7
1.4
0.4
2.8
16.8
18.6
43.6
2.8
47.6
3.2
24.9
7.0
85.5
1985
152.330
8.014
173
92
72.2
54.9
100.0
80.6
80.6
79.2
3.1
17.5
20.6
7.0
8.3
15.3
19.1
16.9
40.7
15.3
50.0
3.0
11.9
7.1
87.3
Scenario C
1977
161.267
7.303
186
74
71.3
51.4
99.3
95.7
95.7
68.2
5.7
14.2
19.9
0.3
2.3
2.6
18.7
18.8
41.0
2.6
49.6
3.2
23.2
6.1
84.7
1980
158.202
7.516
183
90
72.4
53.7
99.7
93.4
93.4
68.9
6.7
13.1
19.8
0.3
6.1
6.4
18.5
18.4
41.5
6.4
49.4
3.1
22.0
6.5
87.4
193S
152.330
8.014
173
92
72.2
54.9
100.0
80.6
-.
80.6
79.2
3.1
17.5
20.6
7.0
83
153
19 1
1 6 3
40.'
15.3
50.0
3.0
11.9
7.1
87.3
-------
Table J-40. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
West Coast Cluster
Variable output .
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion vol %
Hydrocracking
High severity
Medium severity
Total
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Coking
Hydrogen manufacture (MMSCF/CD)
Desulfurization
Light naphtha (isom. feed)
Medium naphtha (ref. feed)
Medium coker naphtha (ref. feed)
Cat cracker cycle oil
Straight run distillate
Total
Scenario A
1977
71.380
3.458
211
50
37.9
22.1
92.0
29.0
29.0
65.0
27.4
27.4
_
-
6.5
41.9
51.5
25.7
7.7
7.8
14.9
56.1
1980
71.735
2.989
187
55
35.1
19.3
92.0
34,5
_
34.5
65.0
27.5
27.5
-
7.4
41.7
51.7
20.1
7.7
7.8
14.8
50.4
1985
71.613
_
168
45
33.1
17.3
91.5
37.3
_
37.3
65.0
27.4
27.4
-
6.8
33.1
51.5
20.6
6.1
7.8
13.7
48.2
Scenario B
1977
71.208
3.623
211
50
37.9
22.1
92.5
29.3
_
29.3
65.0
27.4
27.4
6.5
42.0
51.5
_
25.6
7.7
7.9
14.9
56.1
1980
70.973
3.732
187
55
36.0
20.2
94.2
34.9
_
34.9
65.0
27.4
27.4
_
7.6
41.7
51.5
_
15.0
7.7
7.8
20.8
51.3
1985
70.290
0.044
171
47
38.0
22.2
100.0
38.2
38.2
68.6
27.4
27.4
2.5
2.6
5.1
7.9
33.0
51.5
5.1
24.7
6.1
7.8
14.9
58.6
Scenario C
1977
69.634
4.033
198
46
38.0
22.2
93.8
28.1
28.1
75.4
_
27.4
27.4
_
-
7.9
41.8
51.5
.._
26.5
7.7
3.6
14.9
52.7
1980
70.398
3.016
178
42
36.2
20.4
96.9
37.3
_
37.3
65.0
_
27.4
27.4
_
_
-
7.4
41.7
51.7
21.7
7.7
7.8
14.9
52.1
198!
70.2
0.0
171
47
38.0
22.2
100.0
38.2
38.2
68.6
_
27.4
27.4
2.5
2.6
5.1
7.9
33.0
51.5
5.5
24.7
6.1
7.P
14.9
58.6
t-i
I
-------
Table J-41. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Grassroots Refineries, 1985
i
JS
Ul
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion vol %
Hydrocracking
High severity
Medium severity
Total
Isomerization of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Coking
Hydrogen manufacture (MMSCF/CD)
Desulfurization
Full range naphtha
Medium coker naphtha
Cat cracker cycle oil
Straight run distillate
Vacuum bottoms
Total
Scenario A
East of Rockies
sour sweet
80.3
_
296
99
35.0
35.0
90.1
30.3
_
30.3
75.8
1.6
23.6
25.2
_
_
-
8.3
59.6
49.6
_
3.8
18.2
17.6
89.2
80.3
10
25
41.9
41.9
90.1
20.0
_
20.0
65.0
2.5
13.7
16.2
_
_
-
4.5
30.5
54.1
_
1.1
55.2
West of
Rockies
83.2
__
149
52
37.5
37.5
90.0
21.5
21.5
85.0
5.4
37.6
43.0
_
_
-
6.8
1.1
81.2
36.0
0.2
2.2
23.6
17.3
79.3
. Scenario B
East of Rockies
sour sweet
91.2
311
118
44.4
44.4
96.3
40.3
_
40.3
85.0
4.8
17.8
22.6
9.8
9.8
12.7
52.8
53.5
_
22.4
17.9
93.8
91.2
12
30
53.2
53.2
97.4
35.8
_
35.8
65.0
4.9
9.2
14.1
0.2
8.1
8.3
8.1
26.8
58.2
_
_
4.0
62.2
West of
Rockies
88.5
141
55
42.4
42.4
99.4
30.5
30.5
85.0
6.9
32.4
39.3
4.9
4.9
9.9
4.6
78.0
37.4
0.8
_
34.3
8.9
81.4
Scenario C
East of Rockies
sour sweet
91.2
311
118
44.4
44.4
96.3
40.3
40.3
85.0
4.8
17.8
22.6
9.8
9.8
12.7
_
52.8
53.5
22.4
17.9
93.8
91.2
12
30
53.2
53.2
97.4
35.8
35.8
65.0
4.9
9.2
14.1
0.2
8.1
8.3
8.1
_
26.8
58.2
4.0
62.2
West o
Rocki
88.5
141
55
42.4
42.4
99.4
30.5
_
30.5
850
6.9
32.4
39.3
4 9
4.9
9.9
4.6
780
37.4
0.8
_
34.3
8.9
81 4
-------
Table J-42. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: East Coast
Scenarios
Premium Pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Straight-run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Natural gasoline
Straight run
Total
Year
1977 1980 1985
A
92.7
83.5
29.96
3.00
686
8.0
0.4
59.4
23.0
9.2
-
-
100.0
85.5
77.6
72.13
2.20
187
2.0
7.0
50.4
-
16.5
1.8
17.6
4.7
-
100.0
Q
92.7
83.3
16.56
3.00
568
9.1
7.8
54.3
24.3
-
-
4.5
100.0
85.8
77.3
59.63
1.93
424
2.4
7.2
32.2
38.4
-
-
-
19.8
100.0
C A
B ' C
A
1 i i i
! i
94.9 , 92.7 | 92.4 96.6
86.3
16.37
1.53
304
10.9
-
17.6
28.8
41.7
-
1.0
-
100.0
87.7
79.0
58.92
1.32
438
2.4
7.1
19.0
6.8
41.0
5.2
-
-
- .
18.5
100.0
83.6 i 82.8 , 87.8
36.80
3.00
4.39
3.00
448 714
1
8.8
21.4
40.9
23.5
5.4
-
-
100.0
85.4
77.5
71.37
2.24
373
2.0
6.8
40.3
26.2
2.0
-
5.0
17.7
100.0
6.3
4.35
0.97
2
8.0
64.5
22.3
6.9
100.0
83.9
75.9
40.64
3.00
46.3
41.5
4.2
-
100.0
88.4
79.5
40.22
1.17
350 . 492
3.5
7.1
40.1
_
1.0
7.4
20.2
2.8
1
24.0 44.7
I 6.4
25.3
100.0
17.5
100.0
92.8
83.8
44.31
3.00
722
7.7
3.0
61.2
20.2
7.9
-
100.0
84.5
77.0
64.26
2.71
170
2.2
7.3
55.9
9.1
_
5.8
19.7
100.0
J-46
-------
Table J43. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: East Coast
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CO
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline (untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Natural gasoline
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
A
92.0
84.0
8.86
459
-
8.2
22.6
30.2
29.5
-
-
9.5
100.0
88.0
79.7
110.97
2.24
343
1977
B
92.0
84.0
34.23
3
7.5
24.4
8.7
19.1
-
18.9
9.1
-
12.3
100.0
88.8
80.3
1 1 0.42
1.49
315
C
93.8
84.0
33.82
136
6.9
2.7
50.3
13.2
4.6
7.7
-
12.4
2.2
100.0
90.7
81.6
109.11
0.94
324
Ye
A
92.0
84.0
3.35
5
7.2
11.0
37.7
-
25.2
0.6
-
18.3
100.0
88.0
' 79.7
111.52
2.42
387
ar
1980
B
93.5
84.0
64.79
369
7.8
28.9
34.0
15.6
4.3
0.9
6.5
2.0
100.0
89.9
81.0
109.82
1.23
376
C
93.5
84.0
64.15
317
-
7.4
34.9
28.3
12.9
3.9
4.8
6.6
1.2
100.0
91.7
82.5
108.72
0.47
369
19
A
92.0
84.0
2.22
5
6.6
46.5
25.1
-
-
21.8
100.0
88.0
79.7
110.79
2.77
387
85
B-C
93.8
84.0
106 9
394
0.1
7.3
-
30.9
34.6
12.1
2.1
6.8
3.9
2.2
100.0
93.8
84.0
106.91
-
394
-------
Table J-44. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Large Midwest
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Coker gasoline
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Coker gasoline
Natural gasoline
Straight run
Total
Year
1977
A
90.2
81.2
12.71
2.48
610
9.7
1.8
44.5
31.8
-
12.2
100.0
87.7
78.9
60.39
1.29
750
1.5
3.9
31.0
-
33.5
12.5
2.3
0.3
15.0
100.0
B
93.7
84.7
3.97
1.54
669
8.9
-
53.9
37.2
-
-
100.0
85.9
77.3
50.02
1.71
573
1.8
2.9
34.2
-
25.3
10.5
2.8
1.3
21.2
100.0
C
94.6
85.5
3.96
1.20
394
7.3
21.0
28.9
37.6
-
5.2
100.0
87.1
78.3
49.97
1.40
853
1.8
4.4
17.0
4.6
36.0
14.1
2.8
-
19.3
100.0
1980
A
93.5
84.6
17.30
1.61
698
10.2
10.1
9.9
37.3
31.8
-
0.7
100.0
86.8
77.8
59.98
1.61
773
1.6
2.8
28.4
-
35.6
11.0
2.3
0.7
17.6
100.0
B
90.3
81.1
0.78
2.49
709
6.4
-
49.0
28.8
-
15.8
100.0
84.9
76.3
30.45
1.98
475
3.0
0.2
16.8
0.4
9.6
30.8
9.3
-
-
29.9
100.0
C
91.8
82.6
0.77
2.05
645
6.2
5.6
45.4
30.0
-
12.8
100.0
88.1
79.0
30.20
1.15
889
2.0
1.5
13.5
43.2
16.6
-
-
23.2
100.0
1985
A
92.6
83.6
22.79
1.84
677
10.5
10.6
10.0
32.7
31.4
1.6
3.2
100.0
86.4
77.4
54.21
1.81
872
1.7
1.9
33.2
-
36.2
6.7
1.9
0.7
17.7
100.0
J-48
-------
Table J-45. L.P. MODEL RESULTS - GASOLINE BLENDING
c-,
I
-fs
Cluster: Large Midwest
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
100 RON reformats
Cat cracker gasoline (untreated feed)
Alkylate
Isomerized light naphtha
Coker gasoline
Natural gasoline
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Year
1977
A
95.8
84.0
6.36
428
6.4
49.6
36.5
-
-
7.5
-
100.0
88.7
79.7
79.46
1.38
702
B
94.3
84.0
25.41
959
8.9
19.4
52.6
19.1
-
-
100.0
89.0
79.8
79.40
1.15
701
C
94.9
84.0
25.37
572
8.5
44.5
33.5
8.0
2.5
3.0
100.0
90.0
80.5
79.30
0.94
738
1980
A
95.8
84.0
2.36
469
7.2
49.3
37.0
6.5
-
100.0
88.5
79.5
78.64
1.56
747
B
94.1
84.0
46.84
920
8.5
28.0
39.7
19.0
-
2.9
1.2
0.7
100.0
90.5
81.0
78.07
0.80
744
C
94.4
84.0
46.46
605
8.2
36.0
33.1
16.2
3.0
1.2
2.3
100.0
91.9
82.0
77.43
0.47
716
1985
A
95.9
84.0
1.57
498
6.7
48.3
38.4
-
-
6.6
100.0
88.4
79.3
78.57
1.78
808
B/C
94.0
84.0
76.61
746
5.6
29.5
37.1
15.6
8.7
1.8
0.6
1.1
100.0
94.0
84.0
76.61
-
746
-------
Table J-46. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Small Midcontinent
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Coker gasoline
Natural gasoline
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinates
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Coker gasoline
Natural gasoline
Straight run
Total
Year
1977
A
90.9
82.6
5.91
2.18
261 .
-
9.0
-
45.7
33.6
1.3
-
10.4
100.0
85.9
78.7
28.06
1.33
154
7.6
7.3
30.2
-
22.0
7.5
3.7
10.5
11.2
100.0
B
90.61
82.3
1.84
2.23
263
6.7
43.5
34.4
1.6
-
13.8
100.0
84.7
77.6
23.24
1.68
132
8.9
7.2
36.8
-
16.8
2.8
4.7
9.4
13.4
100.0
c
90.5
82.3
1.84
2.25
220
11.7
9.6
35.6
31.7
-
11.4
100.0
86.0
78.8
23.14
1.31
136
8.3
7.0
36.9
-
18.2
4.6
1.7
11.5
11.8
100.0
1980
A
91.2
82.8
7.97
2.14
318
8.7
-
-
48.2
32.9
-
10.2
100.0
85.8
78.6
27.16
1.36
173
7.6
7.3
30.1
-
21.9
7.6
4.0
10.4
11.1
100.0
B
89.E
81.3
0.36
3.00
223
25.0
10.3
33.8
19.8
-
-
11.1
100.0
82.1
75.3
13.99
2.32
184
15.9
6.8
29.7
16.3
-
7.9
23.4
100.0
C
91.3
83.2
0.35
2.05
304
8.6
48.9
30.2
-
5.0
7.3
100.0
85.9
78.9
13.83
1.15
268
17.8
7.6
7.5
30.5
14.5
2.8
1.1
18.2
100.0
1985
A
95.0
86.7
10.20
0.92
2
11.4
18.7
27.8
-
41.8
0.3
-
100.0
81.7
75.4
24.27
2.27
565
7.8
5.9
0.8
1.0
41.2
3.1
4.3
11.4
24.5
100.0
J-50
-------
Table J-47. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Small Midcontinent
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
BTX raffinates
Butanes
100 RON reformate
Cat cracker gasoline (untreated feed)
Alkylate
Isomerized light naphtha
Coker gasoline
Natural gasoline
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Year
1977
A
92.0
84.0
2.95
254
6.8
47.3
31.6
14.3
100.0
87.2
79.7
36.92
1.36
179
B
92.0
84.0
11.80
257
8.2
47.1
31.6
2.5
9.6
1.0
100.0
87.3
79.9
36.89
1.17
179
C
92.3
84.0
11.75
255
8.0
4.2
45.9
28.6
4.3
6.3
2.7
100.0
88.3
80.6
36.73
0.94
178
1980
A
92.0
84.0
1.09
286
6.1
1.6
45.7
30.5
16.1
100.0
87.2
79.7
36.22
1.49
208
B
92.3
84.0
21.52
226
8.1
14.8
36.5
23.0
4.2
-
13.4
100.0
88.3
80.6
35.87
0.93
210
C
92.8
84.0
21.29
173
7.4
29.2
28.1
13.9
7.3
-
14.1
100.0
90.1
82.0
35.47
0.47
211
1985
A
97.3
84.0
0.70
399
63.6
36.4
-
-
-
100.0
85.9
78.8
35.17
1.83
398
8/C
92.8
84.0
34.02
237
5.3
7.5
22.4
32.1
15.8
12.8
1.0
3.1
100.0
92.8
84.0
34.02
237
-------
Table J-48. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Louisiana Gulf
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
100 RON reformate
Cat cracker gasoline
(untreated feed)
Cat cracker gasoline
(desulfurized feed)
Alkylate
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Cat cracker gasoline
(desulfurized feed)
Alkylate
Light hydrocrackate
Coker gasoline
Natural gasoline
Straight run
Total
Year
1977
A
93.4
84.7
29.78
1.76
176
10.1
21.6
30.7
37.6
-
100.0
85.6
77.5
80.98
1.80
269
7.5
30.1
29.7
.
3.8
2.2
6.2
3.6
16.9
100.0
B
93.5
84.0
15.51
1.98
52
9.6
1.4
60.1
28.9
-
100.0
84.9
76.6
66.81
2.09
447
6.6
4.5
.
52.8
1.9
2.6
7.0
4.3
20.3
100.0
C
96^77
87.05
15.38
0.74
8
10.2
47.2
-
9.4
33.2
-
100.0
86.3
78.3
66.28
1.51
332
6.8
20.3
36.6
-
5.9
2.7
2.7
4.4
20.6
100.0
1980
A
93.5
84.7
36.62
1.74
119
10.0
12.5
40.9
36.6
-
100.0
85.5
77.4
79.15
1.82
265
7.5
30.5
29.3
-
3.5
2.4
6.2
3.3
17.3
100.0
B
90.5
80.5
3.52
3.00
83
9.5
-
58.6
22.9
9.0
100.0
83.9
76.0
44.63
2.21
489
5.7
53.6
-
5.0
5.8
29.9
100.0
C
97.5
87.6
3.48
0.52
2
6.5
56.0
-
37.5
-
100.0
87.4
79.0
44.12
1.20
124
5.9
18.4
-
33.5
6.4
4.2
4.0
27.6
100.0
1985
A
93.4
84.6
44.19
1.79
145
10.0
16.6
37.2
36.2
-
100.0
85.2
77.1
69.77
1.93
261
7.0
34.2
27.6
2.8
5.3
3.3
19.8
100.0
J-52
-------
Table J-49. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Louisiana Gulf
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Coker gasoline
Natural gasoline
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Year
1977
A
93.0
84.0
8.34
414
9.8
58.4
31.8
100.0
88.1
79.8
119.10
1.66
256
B
92.0
84.0
36.99
2
10.8
58.7
_
-
-
30.3
-
0.2
100.0
88.2
79.9
119.33
1.43
258
C
94.0
84.0
36.69
230
9.4
13.4
30.6
23.8
22.8
100.0
90.0
81.2
118.35
0.94
258
1980
A
93.0
84.0
2.36
414
9.8
58.4
-
31.8
-
100.0
88.1
79.8
118.13
1.76
223
B
93.2
84.0
69.30
82
9.6
26.2
10.8
10.0
17.1
23.6
2.7
-
100.0
89.6
80.9
117.45
0.93
237
C
93.8
84.0
68.51
313
9.1
22.0
45.1
0.2
19.8
-
-
3.8
100.0
91.8
82.2
116.11
0.47
232
1985
A
92.0
84.0
2.33
21
13.4
55.9
2.8
-
27.9
-
-
-
100.0
88.5
80.1
116.28
1.84
216
B/C
93.6
84.0
112.49
217
7.4
-
24.9
24.8
14.6
16.1
1.8
6.9
1.5
2.0
100.0
93.6
84.0
112.49
-
217
I
Ln
U)
-------
Table J-50. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Texas Gulf
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinates
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alky I ate
Light hydrocrackate
Coker gasoline
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Isomerized light naphtha
Coker gasoline
Natural gasoline
Straight run
Total
Year
1977
A
91.9
83.5
41.00
2.03
619
-
7.0
10.1
52.0
27.9
-
-
3.0
100.0
85.9
78.0
111.53
2.16
347
9.1
7.3
35.1
22.9
1.3
-
3.0
9.8
11.5
100.0
B
91.1
83.0
21.23
2.16
602
-
8.9
-
50.3
31.2
-
-
9.6
100.0
86.0
77.8
91.45
2.20
391
10.4
6.6
35.5
24.3
0.8
2.0
7.2
13.2
100.0
c
91.5
83.5
20.96
2.02
293
14.0
8.8
37.3
25.7
13.5
-
0.7
100.0
90.1
80.8
90.32
1.20
624
3.1
6.6
3.5
9.1
47.9
14.7
1.4
-
13.7
100.0
1980
A
92.2
83.8
50.02
1.99
625
6.8
-
-
52.4
26.8
13.9
-
0.1
100.0
85.6
77.7
108.11
2.22
295
9.1
7.1
39.5
18.2
0.6
3.6
-
9.0
12.9
100.0
B
91.1
82.9
4.78
2.16
596
6.5
49.6
31.1
-
-
12.8
100.0
85.9
77.3
60.59
2.35
612
14.0
5.6
16.9
40.4
4.9
.
2.9
-
15.3
100.0
c
90.7
82.5
4.75
2.29
770
8.1
-
42.8
35.3
5.8
8.0
100.0
89.1
81.0
60.12
1.06
633
7.7
6.7
2.3
44.5
22.4
2.5
13.9
100.0
1985
A
92.1
83.6
59.76
2.03
640
7.6
2.1
9.2
0.5
41.8
24.6
12.8
1.4
100.0
85.7
77.7
94.35
2.23
391
9.9
6.0
39.8
19.9
1.8
8.6
14.0
100.0
J-54
-------
Table J-51. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Texas Gulf
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
100 RONreformate
Cat cracker gasoline (untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Coker gasoline
Natural gasoline
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Year
1977
A
92.7
84.0
11.48
408
5.2
16.9
36.6
17.9
20.5
-
-
-
2.9
100.0
87.9
79.8
164.01
1.98
419
B
92.6
84.0
50.62
369
6.2
22.2
31.8
18.3
13.8
7.0
0.7
100.0
88.7
80.4
163.30
1.51
412
C
93.2
84.0
49.99
44
6.3
60.4
-
5.3
5.0
1.1
21.9
-
100.0
91.2
82.1
161.27
0.94
401
1980
A
92.7
84.0
3.23
285
6.2
16.8
35.1
20.4
11.1
-
-
-
10.4
100.0
87.8
79.7
161.36
2.10
397
B
93.1
84.0
94.08
261
7.5
37.0
22.8
13.1
6.5
1.8
8.4
2.9
100.0
90.3
81.4
159.45
0.96
404
C
93.9
84.0
93.33
216
6.7
45.1
22.8
3.6
6.0
6.4
9.4
-
100.0
92.0
82.8
158.20
0.47
387
1985
A
94.7
84.0
3.15
197
5.8
59.8
13.4
-
-
10.3
10.7
100.0
88.3
80.1
157.25
2.11
482
8/C
93.24
84.0
152.33
309
2.1
7.2
29.0
30.6
12.5
3.4
9.5
1.1
4.6
-
100.0
93.2
84.0
152.33
_
309
Ul
Ui
-------
Table J-52. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: West Coast
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinates
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Natural gasoline
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinates
Butanes
90 RON reformate
95 RON reformate
Cat cracker gasoline
(untreated feed)
Light hydrocrackate
Coker gasoline
Natural gasoline
Straight run
Total
Year
1977
A
90.3
82.4
31.41
2.77
950
1.0
6.4
0.1
-
49.8
19.8
15.7
2.3
4:9
100.0
84.3
76.8
37.11
1.82
430
13.4
6.1
43.8
14.0
-
3.8
11.7
-
7.2
100.0
B
90.6
82.1
15.67
3.00
184
3.5
9.3
58.7
10.1
18.4
-
-
-
100.0
82.1
75.0
29.91
2.54
1,466
15.8
4.1
47.7
3.6
14.5
2.4
11.9
100.0
c
92.7
83.5
15.32
1.63
1,328
6.4
0.6
50.1
24.4
-
-
11.5
100.0
85.9
78.1
29.25
1.38
768
29.0
7.7
22.4
20.0
8.7
4.1
-
8.1
100.0
1980
A
93.3
83.6
31.56
1.76
928
9.7
16.5
-
50.4
23.4
-
-
-
100.0
84.5
77.7
37.30
1.77
578
4.1
3.4
39.7
7.3
16.9
11.5
1.7
15.4
100.0
B
91.0
81.8
3.55
3.00
1,247
-
6.1
67.1
7.8
19.0
-
-
100.0
83.7
76.1
22.00
2.11
1,650
6.3
3.3
46.8
19.6
2.4
21.6
100.0
C
91.8
82.6
3.52
2.26
1,744
6.1
61.9
20.8
-
-
11.2
100.0
87.0
79.0
21.82
1.15
558
32.3
8.4
23.1
15.0
3.7
3.1
14.4
100.0
1985
A
92.2
83.1
35.81
2.22
1,353
-
7.0
11.4
49.1
1.8.4
14.1
-
-
100.0
85.1
77.7
34.37
1.64
479
26.3
6.6
31.3
7.2
3.3
10.0
2.0
13.3
100.0
J-56
-------
Table J-53. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: West Coast
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline (untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Coker gasoline
Natural gasoline
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Year
1977
A
92.0
84.0
2.86
74
5.2
_
44.4
-
9.0
-
-
-
-
41.4
100.0
87.2
79.6
71.38
2.17
645
B
92.0
84.0
25.63
12
6.6
27.6
24.0
-
14.3
20.5
-
7.0
100.0
87.5
79.8
71.21
1.73
661
C
92.1
84.0
25.07
171
0.9
7.2
22.0
_
24.1
5.7
16.4
15.1
-
3.5
5.1
100.0
89.6
81.4
69.63
0.94
673
1980
A
92.0
84.0
2.87
47
3.8
_
10.7
32.8
-
-
1.9
-
50.8
100.0
88.7
80.5
71.74
1.69
711
B
92.8
84.0
45.42
252
7.6
24.4
_
22.4
13.6
16.1
12.4
-
0.3
3.2
100.0
89.9
81.4
70.97
0.80
735
C
93.2
84.0
45.06
884
1.1
7.2
2.1
_
24.8
32.4
14.8
14.0
0.3
3.3
100.0
91.2
82.4
70.40
0.47
826
1985
A
92.0
84.0
1.43
14
7.4
27.6
23.0
_
17.8
11.6
12.6
100.0
88.8
80.5
71.61
1.90
907
B/C
93.3
84.0
70.29
779
8.2
7.3
_
26.2
29.9
11.3
9.0
7.0
1.1
100.0
93.3
84.0
70.29
_
779
C-l
Ui
-------
Table J-54. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: Grassroots Refineries
East Coast Sweet Crude
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformats
95 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Straight run
Total
91.5
82.6
28.10
3.00
124
8.5
29.9
37.1
14.9
9.4
0.2
100.0
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
95 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Straight run
Total
83.1
75.6
50.59
2.92
1
6.6
57.2
2.0
34.2
100.0
J-58
-------
Table J-55. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: Grassroots Refineries
Scenarios
Lead free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naptha
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
East Coast sweet crude
A
92.0
84.0
1.61
1
4.6
42.9
-
20.9
26.7
-
4.9
100.0
86.2
78.2
80.30
2.89
44
B/C
93.7
84.0
91.20
70
6.7
14.7
33.7
20.4
8.9
4.3
8.6
2.7
100.0
93.7
84.0
91.20
70
J-59
-------
Table J 56. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: Grassroots Refineries
East Coast sour crude
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
Cat cracker gasoline
(untreated feed)
Alky I ate
Light hydrocrackate
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
Cat cracker gasoline
(untreated feed) .
Alky late
Light hydrocrackate
Straight run
Total
90.5
82.9
28.10
3.00
639
6.3
23.3
25.7
25.4
16.7
2.6
100.0
82.6
75.2
50.59
3.00
320
6.5
42.3
19.5
1.8
1.6
28.3
100.0
J-60
-------
Table J-57. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Ouster: Grassroots Refineries
Scenarios
Lead free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerized light naphtha
Total
Total gasoline pool
Reser ^h octane clear
IVotor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
East Coast sour crude
A
92.0
84.0
1.61
1
4.7
31.2
-
21.0
15.7
27.4
100.0
85.6
78.1
80.30
2.94
426
B/C
93.3
84.0
91.20
433
6.1
14.9
22.1
26.6
13.9
, 6.2
10.2
100.0
93.3
84.0
91.20
433
J-61
-------
Table J-58. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Ouster: Grassroots Refineries
West Coast - Alaskan North Slope
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Straight run
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
Cat cracker gasoline
(untreated feed)
Light hydrocrackate
Coker gasoline
Straight run
Total
90.4
82.3
41.60
2.97
409
8.3
30.1
26.4
15.9
14.4
4.9
100.0
85.8
78.6
39.94
1.51
80
5.3
53.5
4.7
10.5
0.2
25.8
100.0
J-62
-------
Table J-59. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: Grassroots Refineries
Scenarios
Lead free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alky I ate
Light hydrocrackate
Isomerized light naphtha
Coker gasoline
Straight run
Total
Total gasolL.rf pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
West Coast - Alaskan
North Slope crude
A
92.0
84.0
1.66
1
6.6
36.5
17.2
-
12.7
27.0
-
100.0
88.2
80.6
83.20
2.21
243
B/C
93.2
84.0
88.50
331
6.3
2.6
37.0
20.7
11.2
11.1
5.4
0.5
5.2
100.0
93.2
84.0
88.50
_
331
J-63
-------
Table J-60. L.P. MODEL RESULTS: - RESIDUAL FUEL OIL SULFUR LEVELS - 1977
Scenario
A
B
C
Cluster
East
Coast
MB/CD
13.37
13.37
13.37
WT%S
2.0
2.0
2.0
Large
Midwest
MB/CD
7.26
7.26
7.26
WT % S
0.47
0.46
0.48
Small
Midcont.
MB/CD
0.23
0.23
0.23
WT%S
0.33
0.33
0.33
Louisiana
Gulf
MB/CD
5.19
5.19
5.19
WT % S
0.60
0.60
0.60
Texas
Gulf
MB/CD
15.321
15.321
15.321
WT%S
1.50
1.49
1.43
West
Coast
MB/CD
31.89
31.89
31.89
WT % S
0.26
0.25
0.12
C-H
I
-------
Table J-61. L.P. MODEL RESULTS: - RESIDUAL FUEL SULFUR LEVELS - 1980
c_
I
01
Ui
Scenario
A
B
C
Cluster
East
Coast
MB/CD
13.32
13.32
13.32
WT % S
2.0
2.0
2.0
Large
Midwest
MB/CD
7.24
7.24
7.24
WT%S
0.77
0.76
0.67
Small
Midcont.
MB/CD
0.22
0.22
0.22
i/VT % S
0.42
0.42
0.42
Louisiana
Gulf
MB/CD
5.13
5.13
5.13
WT%S
0.60
0.60
0.60
Texas
Gulf
MB/CD
15.089
15.089
15.089
WT%S
1.30
1.25
1.17
West
Coast
MB/CD
31.56
31.56
31.56
WT % S
0.53
0.53
0.67
-------
c_
3V
Table J-62. L.P. MODEL RESULTS: - RESIDUAL FUEL OIL SULFUR LEVELS - 1985
Scenario
A
C
Cluster
East
Coast
MB/CD
13.234
13.234
WT
%S
1.8
1.8
Large
Midwest
MB/CD
7.21
7.21
WT
%S
.82
.98
Small
Midcont.
MB/CD
0.215
0.215
WT
%S
.98
.33
Louisiana
Gulf
MB/CD
5.032
5.032
WT
%S
.61
.61
Texas
Gulf
MB/CD
14.714
14.714
WT
%S
1.80
1.22
West
Coast
MB/CD
31.28
31.28
WT
%S
.75
.69
East of Rockies
Grassroots
Sweet Crude Sour Crude
MB/CD
32.9
32.9
WT
%S
0.35
0.41
MB/CD
32.9
32.9
WT
%S
1.78
1.97
West of Rockies
Grassroots
MB/CD
45.5
45.5
WT
%S
1.47
1.63
-------
Table J-63. L.P. MODEL RESULTS: - REFINERY FUEL SULFUR LEVELS - 1977
Scenario
A
B
C
Cluster
East
Coast
MB/CD
14.37
14.22
14.46
WT % S
0.6
0.6
0.6
Large
Midwest
MB/CD
10.15
10.16
10.09
WT%S
1.5
1.5
1.5
Small
Midcont.
MB/CD
4.74
4.75
4.80
WT % S
1.3
1.3
1.3
Louisiana
Gulf
MB/CD
15.37
15.41
15.68
WT%S
0.4
0.3
0.2
Texas
Gulf
MB/CD
25.70,
25.94
26.62
WT%S
0.9
0.9
0.9
West
Coast
MB/CD I WT%S
15.89 0.7
15.91 0.7
I
16.63 0.7
-------
C-,
00
Table J-64. L.P. MODEL RESULTS: - REFINERY FUEL SULFUR LEVELS - 1980
Scenario
A
B
C
Cluster
East
Coast
MB/CD
14.11
14.14
14.59
WT%S
0.6
0.6
0.6
Large
Midwest
MB/CD
10.42
10.51
10.69
WT%S
1.5
1.5
1.5
Small
Midcont.
MB/CD
4.71
4.77
4.85
WT%S
1.5
1.5
1.5
Louisiana
Gulf
MB/CD
15.36
15.57
15.84
WT%S
0.4
0.4
0.3
Texas
Gulf
MB/CD
25.49
25.94
26.60
WT%S
0.9
0.9
0.9
West
Coast
MB/CD : WT%S
16.03 0.7
16.11 0.7
16.46 j 0.7
I
-------
Table J-65. L.P. MODEL RESULTS: - REFINERY FUEL SULFUR LEVELS - 1985
Scenario
A
C
Cluster
East
Coast
MB/CD
14.01
14.81
WT
%S
0.6
0.6
Large
Midwest
MB/CD
10.33
10.98
WT
%S
1.5
1.5
Small
Midcont.
MB/CD
4.54
5.05
WT
%S
1.5
1.4
Louisiana
Gulf
MB/CD
15.31
16.55
WT
%S
0.4
0.4
Texas
Gulf
MB/CD
25.87
27.07
WT
%S
0.9
0.9
West
Coast
MB/CD
15.79
16.57
r WT
%S
0.7
0.7
East of Rockies
Grassroots
Sweet Crude Sour Crude
MB/CD
11.43
13.60
WT
%S
0.6
0.5
MB/CD
15.46
17.82
WT
%S
1.0
1.0
West of Rockies
Grassroots
MB/CD
16.91
18.24
WT
%S
0.7
0.7
I
c^
VO
-------
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ZI.7O HEAVY GAS OIL 30O -aSO'F HEAVY C.A-= OIL 3.54
118.16(^^^1 DCSOLFUR\teO WEAVY GAS, OIL 17.98
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^>-
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^ POOU
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-*-, ., 9.7O iPT FUFl.
>.
' 59.SO t*5>TlU.AT6 Z.9O KEROS6ME
i
-
I _ DISTILLATION ' Jgj CRACKER *" *^I>IPU l| -
7S.92. TOWER 3
-------
\-Z.\G, Cs TO ZOO°F
IO4.'
4.Z9 SOX FROM FCC _
I5.TI SOX ^SUI-F
35.
14.9.OS Ei.EMEMT^U SULFUR
(TOMS)
55. ES SOX.
(TOMS)
OF
(MB/CD)
JP\^^o^5-l
-------
zz
TEXAb GULF CLUSTER 1985 SULFUR i MATERIAL BALANCE
JPII13T5-I
Figure J-3
-------
C-,
-vl
u>
Table J-66. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985, Scenario B/C
Stream Values-Gas Oil 375-650° F
Gas oil /Crude charge
Louisiana
West Texas Sour
Nigerian Forcados
Arabian Light
Venezuelan Tia Juana
Total
Values for stream #5
gas oil 375-650°F
(1)
Crude
volume.
MB/CD8
155.669
135.964
12.480
17.405
6.897
328.415
(2)
Yield on
crude.
volume %b
37.0
27.5
38.7
28.4
23.0
N.A.
(3)
Specific
gravity0
0.837
0.8440
0.874
0.8278
0.8473
0.8409
(4)
Sulfur
content.
% weight6
0.0649
0.9146
0.1452
0.6849
0.4599
0.4028
(5)
(1)x(2)
100
Stream
volume.
MB/CD
57.598
37.390
4.830
4.943
1.586
106.347
106.347
(6)
(5) x (3) x 349.776
Hydrocarbon weight.
Mlbs/CD
16,862.535
11,037.937
1,476.551
1,430.873
470.035
31,277.931
31,277.931
(7)
(4) x (6)
100
Sulfur weight.
Mlbs/CD
10.944
100.953
2.144
9.800
2.162
126.003
126.003
(8)
(7) x 106
(6)
Sulfur
content,
PPM
649
9,146
1,452
6,849
4,600
4,028d
4,028
aTable J-32.
b
Table H-1, sum of light and heavy gas oil yields.
cTables H-13and H-14.
d.
Average
-------
Table J-67. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Guff 1985 B/C
Desulfurization of Light Gas Oil
Stream
number
35
36
37
. Stream name
DMurfurization of light gas oil
Intake
Texas light gas oil
Normal purity hydrogen, MSCF/CD
Output
C3
iC4
nC4 o
C5 to 160 F
H2S
Subtotal - light ends and H2S
Desulfurized light gas oil
(1)
Process
coefficients*
1.000
0.190
0.001
0.001
0.001
0.008
N.A.
0.990
(2)
<1)x7j080b
Volume,
MB/CD
7.080
1.345
0.007
0.007
0.007
0.057
N.A.
0.078
7.009
(3)
Specific
gravity'
0.8251
N.A.
0.508
0.563
0.584
0.664
N.A.
0.815
(4)
Sulfur.
%wgt.c
0.5787
0.0
negl.
negl.
negl.
0.0288
N.A.
(5)
(2>x(3>x349.776
Hydrocarbon
weight.
Mlbs/CD
2.043.289
7.2708
1.244
1.378
1.430
19.937
12.440f
36.429
1.998.038
(61
(4) x (5)
100
Intake sulfur
weight.
Mlbs/CD
11.824
0.000
<7)
Output
sulfur
distribution.
percent
0.0
0.0
0.0
0.0
99.0
99.0
1.0
(8)
Output sulfur
weight.
Mlbs/CD
0.000
0.000
0.000
0.000
11.708
11.708
0.117
(9)
Sulfur
content,
PPM
5,786
0
0
0
0
0
N.A.
N.A.
58.
<-t
C-
"Tables H-8 and H-10.
Intake volume for undesulfurized light gas oil; MB/CO unless otherwise noted.
Tables H-13 through H-15.
dTableH-12.
Height of hydrogen assumed to be 5.405 Ib/MSCF.
Sulfur in H^S (column 8) times the weight ratio of HjS/sulfur (1.0625).
-------
Table J-68. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985, Scenario B/C
Feed Sulfur Levels
Process/ Feed
unit / stream
Catalytic cracker
Vacuum overhead feed
Louisiana
- West Texas Sour
Nigerian Forcados
Arabian Light
- Venezuelan Tia Juana
Total VOH feed
Coker/Visbreaker
Vacuum bottoms 1050°F+
- Louisiana
- West Texas Sour
Nigerian Forcados
Arabian Light
Venezuelan Tie Juana
Total bottoms faad
Hydroeracfcar
Heavy gas oil 500-650° F feed
-- Louisiana
West Texas Sour
Nigerian Forcados
- Arabian Light
Venezuelan Tia Juana
Total HGO faed
m
%
crude
charge8
47.4
41.4
3.8
S.3
2.1
100.0
47.4
41.4
3.8
5.3
2.1
100.0
47.4
41.4
3.8
5.3
2.1
100.0
(2)
Yield on
crude,
volume %
32.50
29.60
30.40
29.50
32.80
N.A.
5.60
12.30
8.50
13.70
25.00
N.A.
19.50
14.11
20.60
15.01
12.70
N.A.
(3)
(Dx (2)
100
Feed.
MB/CD
15.405
12.254
1.155
1.564
0.689
31.067
2.654
5.092
0.323
0.726
0.525
9.320
9.243
5.842
0.783
0.780
' 0.2^7
16.915
(4)
Specific
gravity0
0.8974
0.9167
0.942
0.9154
0.922
0.9081
0.9881
1.0187
0.998
1.0195
1.0236
1.0096
0.8504
0.8633
0.891
0.8463
0.865
0.8568
(5)
Sulfur
content
% weight0
0.3221
1.8513
0.3125
2.3215
1.6292
1.0614
0.9207
3.0018
0.6265
4.5530
2.8743
2.4651
0.0901
1.2187
0.2015
1.0807
0.6690
0.5426
(6)
(3) x (4) x 349.776 x (5)
100
Feed sulfur
Mlbs/CD
15.575
72.740
1.189
11.624
3.619
104.747
8.445
54.464
0.706
11.787
5.403
80.805
2.477
21.499
0.492
2.495
0.540
27.503
(7)
(d)
Feed sulfur,
Ibs/bblfeed
0.501
2.342
0.038
0.374
0.117
3.372
0.906
5.844
0.075
1.265
0.580
8.670
0.146
1.271
0.029
0.148
0.032
1.626
aTable A-5. Volume for each crude as a percent of total crude charge.
bTableH-1.
cTables H-13and H-14.
Crude-specific feed sulfur (column 6) divided by total feed to unit (column 3).
-------
Table J-69. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985, Scenario B/C
Stream Qualities Cluster Specific Streams
-V; '
Process / Output
unit / stream
Catalytic cracker
65 conversion6
Cat. naphtha
Light cycle oil
Heavy cycle oil
H2S
SOX
Total Cat 65 conversion
85 conversion
Cat. naphtha
Light cycle oil
Heavy cycle oil
H2S
SOX
Total Cat 85 conversion
Crude-specific sulfur distribution (1)
Sulfur content, Ibs/bbl feed"
Louisiana
VOH
0.025
0.090
0.153
0.209
0.024
0.501
0.020
0.069
0.132
0.244
0.036
0501
Texas
VOH
0.096
0.726
0.551
0.892
0.077
2.342
0.073
0.628
0.452
1.056
0.133
2.342
Nigerian
VOH
0.002
0.007
0.011
0.016
0.002
0.038
0.002
0.005
0.010
0.018
0.003
0.038
Arabian
VOH
0.016
0.090
0.076
0.156
0.036
0.374
0.013
0.074
0.060
0.182
0.045
0.374
Venezuelan
VOH
0.045
0.005
0.036
0.027
0.004
0.117
0.053
0.004
0.031
0.022
0.007
0.117
Total
VOH
0.184
0.918
0.827
1.300
0.143
3.372
0.161
0.780
0.685
1.522
0.224
3.372
(2)
Stream
volume.
LV fraction
onfeedb
0.52
0.27
0.08
N.A.
N.A.
N.A.
0.60
0.10
0.05
N.A.
N.A.
N.A.
(3)
(1)^(2)
Sulfur
content,
lbs/bblc
0.354
3.400
10.338
N.A.
N.A.
N.A.
0.268
7.800
13.700
N.A.
N.A.
N.A.
(4)
GBJOOIII
weight
Ibs/bbl
feed11
N.A.
N.A.
N.A.
1.381
0.286
N.A.
N.A.
N.A.
N.A.
1.817
0.448
N.A.
(-1
Crude-specific feed sulfur (Table J-68, column 7) times output stream sulfur as a percent of crude-specific feed sulfur (Table H-18, case 2).
''Table H-4.
cSulfur content, PPM, calculated by methodology shown on Table J-66. Specific gravities of streams found on Table H-16.
Gaseous sulfur content (column 1) times weight ratio of gaseous stream/sulfur.
H2S/sulfur weight ratio = 1.0625; SOx/sulfur content = 2.000.
e
Low conversion, untreated feed.
High conversion, untreated feed.
-------
Table J-70. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985, Scenario B/C
Stream Qualities - Cluster-Specific Streams
Process/Streama
Catalytic cracker
72.5 conversion^
Cat. naphtha
Light cycle oil
Heavy cycle oil
H2S
SOX
Total cat 72.5 conversion
Coker
Vacuum bottoms feed
Light coker naphtha
Medium coker naphtha
Coker gas oil
Coke
H2S
Total coker - bottoms feed
Heavy cycle oil feed*1
Light coker naphtha
Medium coker naphtha
Coker gas oil
Coke
H2S
Total coker cycle oil feed
Hydrocracker
Heavy gas oil feed
Output streams
H2S
Total hydrocracker - HGO
Vacuum overhead feed
Output streams
H2S
Total hydrocracker - VOH
Light cycle oil feed"
Output streams
H2S
Total hydrocracker LCO
(1)
Total feed
sulfur
Ibs/bbl feedb
0.337
0.337
0.337
0.337
0.337
0.337
8.670
8.670
8.670
8.670
8.670
8.670
10.338
10.338
10.338
10.338
10.338
10.338
1.626
1.626
1.626
3.372
3.372
3.372
3.400
3.400
3.400
(2)
Stream
sulfur.
Xfeadc
3.5
34.5
33.5
20.0
8.5
100.0
1.2
3.4
30.3
30.7
34.4
100.0
1.2
3.4
30.3
30.7
34.4
100.0
o.o'
100.0
100.0
0.0'
100.0
100.0
0.0'
100.0
100.0
(3)
(1)x (2)
100
Output
sulfur.
Ibs/bbl feed
0.012
0.116
0.113
0.067
0.029
0.337
0.104
0.295
2.627
2.662
2.982
8.670
0.124
0.351
3.133
3.174
3.556
10.338
0.000'
1.626
1.626
0.000'
3.372
3.372
0.000'
3.400
3.400
(4)
Stream
volume.
LV fraction
on feed"
0.58
0.212
0.063
N.A.
N.A.
N.A.
0.105
0.187
0.413
0.258
N.A.
N.A.
0.080
0.142
0.5932
0.1283
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
(5)
(3) -^ (4)
Sulfur
content.
Ibs/bbl8
0.021
0.547
1.794
N.A.
N.A.
N.A.
0.990
1.578
6.361
10.318
N.A.
N.A.
1.550
2.472
5.282
24.739
N.A.
N.A.
0.000'
N.A.
0.000
0.000'
N.A.
0.000
0.000'
N.A.
0.000
(6)
(f)
Gaseous
weight.
Ibs/bbl
feed
N.A.
N.A.
N.A.
0.071
0.058
0.129
N.A.
N.A.
N.A.
N.A.
3.168
3 .'168
N.A.
N.A.
N.A.
N.A.
3.778
3.778
N.A.
1.728
1.728
N.A.
3.583
3.583
N.A.
3.613
3.613
3Other cat cracker conversions on Table J-69. Visbreaking not used in Texas Gulf cluster.
bTable J-68 (column 7).
cTables H-17 and H-18 (case 2).
dTable H-4 through H-7.
eSulfur content, PPM, calculated by methodology shown on Table J-66. Specific gravities of streams found on Table H-16.
Gaseous output sulfur (column 3) times weight ratio of gaseous stream/sulfur.
H2S/$ulfur weight ratio - 1.0625, SOx/sulfur weight ratio = 2.000.
9Low conversion, hydrotreated feed (sulfur level is 10% of untreated feed). High (95) conversion, hydrotreated feed not used
in Texas Gulf.
65 conversion catalytic cracker output (Table J-69).
'Negligible sulfur content (approximately 1 PPM).
J-77
-------
Table J-71. SPECIFIC GRAVITIES AND DENSITIES FOR
MISCELLANEOUS STREAMS
Stream
Refinery gas (FOE)
BTX
Mixed olefins
Coke
Hydrogen
Spgr
0.9714
0.872
0.550
1.100
Lbs/MSCF
5.405
J-78
-------
Table J-72. MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985. Scenario B/C
Stream
number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Process/Stream name
Purchased butanes
Atmospheric distillation tower
Intake
Crude charge
Output
Light ends
Full range naphtha
Gas oil 375 to 650° F
Bottoms 650° F+
Naphtha splitter
Intake
Purchased natural gasoline
Full range naphtha
Output
Light ends
Cs to 200° F
200 to 340° F
340 to 375° F
Cs to 200° splitter
Intake
Cs to 200°F
Output
Cs to 160°F
160 to 200° F
Desulfurization of isomerization feed
Intake
Cs to 160°F
Normal purity hydrogen
Output
H2S
C5 to 160°F desulfurized
Process intake
Volume,
MB/CD"
2.926
328.415
11.200
80.070
33.952
14.900
1.564
Hydrocarbons
weight,
Mlbs/CD
586.637
97,946.709
2,634.901
21,134.135
8,156.225
3,601.199
8.454
Sulfur
weight,
Mlbs/CD
0.293
751.830
0.076
16.162
1.258
0.577
0.000
Sulfur
content,
PPM
499.
7,676.
29.
764.
154.
160.
0
Process output
Volume,
MB/CD"
5.627
83.708
106.347
132.642
1.376
33.952
45.375
10.564
21.864
12.088
N.A.
14.900
Hydrocarbons
weight,
Mlbs/CD
1.124.336
22,068.196
31,277.931
43,221.001
1 277.400
8,156.236
12,328.216
2,976.906
I
I
i
I
5,037.023
3,080.919
0.582
3,467.882
Sulfur
weight,
Mlbs/CD
0.000
16.435
126.003
609.392
0.000
1.258
10.062
4.921
0.551
0.701
0.548
0.004
Sulfur
content
PPM
0
744.
4,028.
14,099.
0
154.
816.
1,653.
109.
227.
N.A.
1.
C-,
I
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Ouster 1985, Scenario B/C
Stream
number
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Process/Stream name
Isomerization
Intake
C5 to 160°F desulfurized
Output
Light ends
. I some rate
Naphtha product from desulfurization
Cs to 160° from LGO desulfurization
Reformer feed to transfer
SR naphtha
Desulfurization SR naphtha
Intake
SR naphtha 160 to 375° F
Normal purity hydrogen
Output
H2S
Desulfurized SR naphtha
Catalytic reforming
Intake
SR naphtha (desulf. and undesulf.)
Heavy hydrocrackate
Medium coker naphtha
Total intake
Output
Light ends
Reformate
Aromatic* extraction
Intake
100 sev. reformate
Output
Raffinate
BTX
Process intake
Volume,
MB/CD8
15.230
0.317
4.650
61.683
6.478
62.463
6.793
2.980
72.236
13.470
Hydrocarbons
weight,
Mlbs/CD
3,545.238
75.285
1,239.361
16,626.918
35.016
16,839.077
1 ,805.542
793.215
19,437.834
3,782.611
Sulfur
weight,
Mlbs/CD
0.004
0.016
0.115
13.534
0.000
0.018
0.007
0.003
0.028
0.004
Sulfur
content,
PPM
1.
212.
92.
813.
0
1.
4.
4.
1.
1.
Process output
Volume,
MB/CD8
0.482
14.493
0.317
4.650
N.A.
61.683
14.952
57.614
7.795
5.675
Hydrocarbons
weight,
Mlbs/CD
163.902
3,265.166
75.285
1,239.361
14.435
16,626.918
2,837.415
16,290.655
1,980.780
1,731.480
Sulfur
weight,
Mlbs/CD
0.000
0.003
0.016
0.115
13.585
0.019
0.001
0.019
0.002
0.000
Sulfur
content,
PPM
0
1.
212.
92.
N.A.
1.
0.
1.
1.
0
00
O
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985. Scenario B/C
Stream
number
32
33
34
35
36
37
21
38
39
40
41
42
43
44
45
Process/Stream name
Gas oil splitter
Intake
Gasoil375to650°F
Output
Light gas oil 375 to 500°F
Heavy gas oil 500 to 650° F
Desulfurize light gas oil
Intake
Light gas oil 375 to 500°F
Normal purity hydrogen
Output
Light ends and H2S
Desulfurized light gas oil
C5 to 160° naphtha
Hydrocracker
Intake
Hydrocarbon feed
High purity hydrogen
Total intake
Output
Light ends and H2S
Light hydrocrackate
Hydrocracked jet fuel
Heavy hydrocrackate
Vacuum distillation tower
Intake
Bottoms 650° +F
Output
Vacuum Overhead
Bottoms 1050° + F
Process intake
Volume,
MB/CD8
59.210
7.080
1.354
20.646
40.725
116.440
Hydrocarbons
weight,
Mlbs/CD
17,415.680
2,043.289
7.270
6,621.258
220.134
6,841.392
38,059.579
Sulfur
weight,
Mlbs/CD
115.823
1 1 .824
0.000
68.634
0.000
68.634
587.862
Sulfur
content,
PPM
6,650.
5,786.
0
10,366.
0
10,032
15,445.
Process output
Volume,
MB/CD"
28.484
30.726
0.078
7.009
.317
4.182
5.235
11.050
6.793
88.206
28.234
Hydrocarbons
weight,
Mlbs/CD
8,198.376
9,226.711
36.429
1,998.038
75.285
890.978
1,244.852
3,138.540
1,805.542
28,069.637
9,988.223
Sulfur
weight ,
Mlbs/CD
33.001
82.872
1 i.708
0.117
0.016
67.581
0.002
0.011
0.007
330.035
257.865
Sulfur
content,
PPM
4,029.
8,981.
N.A.
58.
212.
N.A.
0
3.
3.
11,757.
25,816.
I
00
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario B/C
Stream
number
46
47
48
49
50
51
53
54
55
56
57
58
59
Process/Stream name
Gas oil feedstock
Cat. feed to transfer
Desulfurization for lubes
Input
Hydrocarbon feed
Hydrogen
Output
Light ends and H2S
Desulfurized product for lubes
Catalytic cracker
Input
Output
Light ends, H2S and sulfur in SOX
Mixed olefins
Cat. naphtha
Light cycle oil
Heavy cycle oil
Alkylation
Input
Isobutane
.Mixed olefins
Output
Alkylate
Process intake
Volume,
MB/CD"
98.050
1.880
16.580
80.633
12.821
10.780
Hydrocarbons
weight,
Mbs/CD
30,586.753
586.469
5,178.623
26.919
25,150.105
2,524.683
2,073.821
Sulfur
weight,
Mlbs/CD
411.399
7.888
59.650
0.000
274.295
0.001
0.000
Sulfur
content,
PPM
13,449.
13,449.
11,519.
0
10,906
0
0
Process output
Volume,
MB/CD3
0.264
16.517
12.997
13.163
46.525
12.072
4.731
19.080
Hydrocarbons
weight,
Mlbs/CD
114.998
5,087.446
3,149.495
2,532.256
12,301.881
3,781.817
1.563.756
4,664.612
Sulfur
weight,
Mlbs/CD
50.378
5.566
137.729
0.000
10.430
55.696
64.804
0.019
Sulfur
cofitfttit,
PPM
N.A.
1,092.
N.A.
0
847.
14,728.
41,441.
0
I
oo
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario B/C
Stream
number
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
Process/Stream name
Desulfurization of light cycle oil
Input
Light cycle oil
Normal purity hydrogen
Output
Light ends and H2S
Desulfurized light cycle oil
Coker
Input
Output
Light ends and H2S
Mixed olefins
Light coker naphtha
Medium coker naphtha
Coker gas oil
Coke
Desulfurization of Coker Naphtha
Input
Medium coker naphtha
Normal purity hydrogen
Output
H2S
Desulfurized medium coker naphtha
Refinery Fuel System
Input (FOE)
Bottoms 650° +F
Gases C4 and lighter
Output
Sulfur in SOX
Refinery fuel (FOE)
Process intake
Volume,
MB/CD"
11.850
16.900
2.95
16.420
10.670
Hydrocarbons
weight,
Mlbs/CD
3,712.124
14.092
5,901.070
789.357
: 9.568
5,550.302
1,177.801
Sulfur
weight.
Mlbs/CD
55.573
0.000
151.456
4.629
0.000
62.467
0.000
Sulfur
content,
PPM
14,970.
0
25,666.
5,864.
0
11,255.
0
Process output
Volume,
MB/CD8
0.131
11.731
4.416
0.616
1.657
2.950
7.820
3.754
N.A.
2.980
N.A.
27.090
Hydrocarbons
weight,
Mlbs/CD
92.790
3,675.003
1,122.711
118.503
392.375
789.357
2,308.549
1,444.365
4.915
793.215
62.467
6,728.100
Sulfur
weight,
Mlbs/CD
47.295
8.251
46.355
0.000
1.633
4.628
49.507
38.549
4.626
0.003
62.467
62.467
Sulfur
content,
PPM
N.A.
2,245.
N.A.
0
4,162.
5,863.
21,445.
26,689.
N.A.
4.
N.A.
9,284.
C-,
oo
u>
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Ouster 1985, Scenario B/C
StiMffl
number
77
78
79
80
81
82
83
84
85
86
Process/Stream name
Hydrogen manufacturing
Input
Methane/ethane (FOE)
Output
High purity hydrogen
Sulfur recovery
Input
H2S
Output
Elemental sulfur
Sulfur in SOX
Blending of refinery gas
Composition
Methane/ethane
Blend totals
Blending of LPG
Composition
Propane
Blend totals
Blending of unleaded gasoline
Composition
Liquid
Isomerate
Reformate
Light hydrocrackate
Cat. naphtha
Light coker naphtha
Raffinate
Natural gasoline
Alkylates
Gaseous
Butanes
Blend totals
Process intake
Volume,
MB/CD"
1.702
N.A.
0.788
8.014
14.493
44.144
5.235
46.525
1.657
3.175
6.981
19.080
11.040
Hydrocarbons
weight,
Mlbs/CD
544.251
387.384
267.578
1,423.938
3,265.166
12,508.044
1,244.852
12,301.881
392.375
863.946
1,562.352
4,664.612
2,253.082
Sulfur
weight,
Mlbs/CD
0.000
364.597
0.000
0.000
0.003
0.015
0.002
10.430
1.633
0.001
0.016
0.019
0.000
Sulfur
content
PPM
0
N.A.
0
0
1.
1.
0
847.
4,164.
1.
10.
4.
0
Process intake
Volume,
MB/CD"
40.72
N.A.
N.A.
0.788
8.014
152.330
Hydrocarbons
weight,
Mlbs/CD
220.108
346.342
18.255
267.578
1,423.938
39,056.31
Sulfur
weight.
Mlbs/CD
0.000
346.342
18.255
0.000
0.000
12.118
Sulfur
content,
PPM
0
N.A.
N.A.
0
0
309.
oo
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario B/C
Stream
number
87
88
89
do
91
92
93
Process/Stream name
Blending of BTX
Composition
BTX
Blend totals
Blending of naphtha
Composition
SR naphtha
Raffinate
Blend totals
Blending of distillates
Composition
Heavy naphtha 340 to 375° F
Gas oil 375 to 650°F
Light gas oil
Desulfurized light gas oil
Hydrocracked jet fuel
Heavy gas oil
Light cycle oil
Desulfurized light cycle oil
Blend totals
Jet fuel
Kerosene
Distillate fuel oil
Blending of olefins
Composition
Mixed olefins
Light ends
Blend totals
Process intake
Volume,
MB/CD8
5.677
3.638
4.620
0.814
47.138
21.404
7.009
11.050
8.055
0.222
11.731
2.980
0.745
Hydrocarbons
weight,
Mlbs/CD
1,731.480
932.853
1,116.834
228.249
13,862.697
6,155.087
1,998.095
3,138.540
2,396.789
68.905
3,675.003
573.283
135.790
Sulfur
weight,
Mlbs/CD
0.000
0.273
0.000
0.048
10.183
21.177
0.117
0.011
2.159
0.120
8.251
0.000
0.000
Sulfur
content,
PPM
0
292.
0
210.
734.
3,440.
58.
3.
900.
1,741.
2,245.
0
0
Process output
Volume,
MB/CD8
5.677
8.258
22.043
7.226
78.141
3.725
Hydrocarbons
weight,
Mlbs/CD
1,731.480
2,049.680
6,289.908
2,067.487
23,177.402
709.073
Sulfur
weight,
Mlbs/CD
0.000
0.273
0.827
2.168
39.071
0.000
Sulfur
content,
PPM
0
133.
131.
1,048.
1,685.
0
I
00
Ui
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-72.(continued). MASS AND SULFUR BALANCE
Texas Gulf Ouster 1985, Scenario B/C
Stream
number
94
95
96
97
Process/Stream name
Blending of residual fuel oil
Composition
Heavy naphtha 340 to 375° F
Bottoms 650° + F
Bottoms 1050° + F
Blend totals
Blending of lubes
Composition
Desulfurized feed
Blend totals
Blending of asphalt
Composition
Bottoms 1050° + F
Blend totals
Blending of coke
Composition
Coke
Blend totals
Process intake
Volume,
MB/CD*
0.111
10.379
4.224
15.474
1.314
3.754
Hydrocarbons
weight,
Mlbj/CD
31.681
3,307.285
1,505.082
4,766.188
468.560
1,444.365
Sulfur
weight.
Mbs/CD
0.003
13.834
45.180
5.205
21.334
38.550
Sulfur
content,
DOUI
rrm
95.
4,183.
30,018.
1,092.
45,531.
26,689.
Process output
Volume,
MB/CD*
14.714
15.474
1.314
3.754
Hydrocarbons
weight,
Mlbs/CD
4,844.048
4,766.188
468.560
1,444.365
Sulfur
weight,
Mlbs/CD
59.017
5.205
21.334
38.550
Sulfur
content
PPM
12,183.
1,092.
45,531.
26,689.
I
00
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
APPENDIX K
CONVERSION FACTORS AND NOMENCLATURE
-------
F CONTENTS
APPENDIX K - CONVERSION FACTORS AND NOMENCLATURE
LIST OF TABLES
TABLE K-l. Weight Conversions K-l
TABLE Kr-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
-------
Table K-1. WEIGHT CONVERSIONS
Unit
Equivalent value
One short ton
One metric ton
One long ton
One cubic centimeter lead
2,000 pounds
2,204.6 pounds
2,240.0 pounds
1.06 grams lead
K-1
-------
Table K-2. VOLUME CONVERSIONS
Unit
Equivalent value
One imperial gallon
One liter
One U.S. barrel
One cubic meter
One cubic foot
1.201 U.S. gallons
0.264 U.S. gallons
42.000 U.S. gallons
264.173 U.S. gallons
7.481 U.S. gallons
K 2
-------
Table K-3. GRAVITY, WEIGHT AND VOLUME CONVERSIONS FOR
PETROLEUM PRODUCTS
(All measurements at 60 Deg F)
Gravity,
degrees
API
0
10
15
18
20
22
24
26
28
30
32
34
36
38
40
42
44
46
48
50
55
60
65
70
75
80
85
90
95
100
Specific
gravity
1.0760
1 .0000
0.9659
0.9465
0.9340
0.9218
0.9100
0.8984
0.8871
0.8762
0.8654
0.8550
0.8448
0.8348
0.8251
0.8155
0.8063
0.7972
0.7883
0.7796
0.7587
0.7389
0.7201
0.7022
0.6852
0.6690
0.6536
0.6388
0.6247
0.6112
Gallons
per
pound
0.1116
0.1201
0.1243
0.1269
0.1286
0.1303
OJ320
0.1337
0.1354
0.1371
0.1388
0.1405
0.1422
0.1439
0.1456
0.1473
0.1490
0.1507
0.1524
0.1541
0.1583
0.1626
0.1668
0.1711
0.1753
0.1796
0.1838
0.1881
0.1924
0.1966
Pounds
per
gallon
8.962
8.328
8.044
7.882
7.778
7.676
7.578
7.481
7.387
7.296
7.206
7.119
7.034
6.951
6.870
6.790
6.713
6.637
6.563
6.490
6.316
6.151
5.994
5.845
5.703
5.568
5.440
5.316
5.199
5.086
Pounds
per
barrel
376.40
349.78
337.85
331.04
326.68
322.39
318.28
314.20
310.25
306.43
302.65
299.00
295.43
291.94
288.54
285.18
281.95
278.75
275,65
272.58
265.27
258.34
251.75
245.49
239.53
233.86
228.48
223.27
218.36
213.61
Barrels
per
short
ton
5.31
5.72
5.92
6.04
6.12
6.20
6.28
6.36
6.45
6.53
6.61
6.69
6.77
6.85
6.93
7.01
7.09
7.17
7.26
7.34
7.54
7.74
7.94
8.15
8.35
8.55
8.75
8.96
9.16
9.36
Barrels
per
metric
ton
5.86
6.30
6.52
6.66
6.75
6.84
6.93
7.02
7.10
7.19
7.28
7.37
7.46
7.55
7.64
7.73
7.82
7.91
8.00
8.09
8.31
8.53
8.76
8.98
9.20
9.43
9.65
9.87
10.10
10.32
Barrels
per
long
ton
5.95
6.40
6.63
6.77
6.86
6.95
7.04
7.13
7.22
7.31
7.40
7.49
7.58
7.67
7.76
7.85
7.94
8.04
8.13
8.22
8.44
8.67
8.90
9.12
9.35
9.58
9.80
10.03
10.26
10.49
K 3
-------
Table K-4. REPRESENTATIVE WEIGHTS3 OF PETROLEUM PRODUCTS
Product
Asphalt
Coke
Crude petroleum (domestic)
Crude petroleum (foreign)
Distillate fuel oil
Gasoline and naphtha
Kerosine
Liquefied petroleum gas
Lubricating oil
Residual fuel oil
Wax
Gallons
per
pound
0.116
0.105
0.142
0.133
0.138
0.162
0.148
0.221
0.133
0.127
0.150
Pounds
per
gallon
8.60
9.54
7.03
7.50
7.24
6.17
6.75
4.52
7.50
7.88
6.68
Pounds
per
barrel
361
401
295
315
304
259
284
190
315
331
280
Barrels
per
short
ton
5.54
4.99
6.77
6.35
6.58
7.72
7.05
10.53
6.35
6.04
7.13
Barrels
per
metric
ton
Barrels
per
long
ton
I
6.11
5.50
7.46
7.00
7.25
8.51
7.78
11.60
7.00
6.66
7.86
6.21
5.59
7.58
7.11
7.37
8.65
7.90
11.79
7.11
6.77
7.99
Approximate or representative figures to be used only for rough estimating. When API or
specific gravity is known, Table K-3 should be used.
K 4
-------
Table K-5. HEATING VALUES OF CRUDE PETROLEUM AND PETROLEUM PRODUCTS
Item
Crude petroleum
Petroleum products, average
Dry natural gas
Still gas
Fuel oil equivalent barrel
Natural gasoline
Liquefied gases
Gasoline
Special naphtha
Jet fuel, naphtha-type
Jet fuel, kerosine-type
Kerosine
Distillate fuel oil
Residual fuel oil
Lubricants
Waxes
Petroleum coke
Asphalt
Gross heating value3
5,599,100
5,517,000
1,021 Btu/cu.ft.
6,000,000
6,250,000
4,620,000
4,011,000
5,248,000
5,248,000
5,355,000
5,670,000
5,670,000
5,825,000
6,287,000
6,065,000
5,537,000
6,024,000
6,636,000
aAII units in Btu/bbl except as noted
K-5
-------
Table K-6. NOMENCLATURE
B/SD
Bbls/SD
BTU
cc/gal
cc/USG
FOE
g/gal
gm/gal
LV
MB
Mbbls
MB/CCT
MB/SD
MBPY
MKWH
MKWH/CD
Mlbs
MMB
MMB/CO
MMBPY
MSCF
MMSCF
PPM
SCF
$/B/SD
$MM
Barrels per stream day
British Thermal Unit
Cubic centimeters per U.S. gallon
Fuel oil equivalent
Grams per gallon
Liquid volume
Thousands of barrels
Thousands of barrels per calendar day
Thousands of barrels per stream day
Thousands of barrels per year
Thousands of kilowatt hours
Thousands of kilowatt hours per calendar day
Thousands of pounds.
Millions of barrels
Millions of barrels per calendar day
Millions of barrels per year
Thousands of standard cubic feet
Millions of standard cubic feet
Parts per million
Standard cubic feet
Dollars per barrel per stream day
Millions of dollars
K-6
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EFA-450/3-76-016b
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
The Impact of Lead Additives Regulations on the
Petroleum Refining Industry
Volume II - Detailed Study Results
5. REPORT DATE
May 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
N. Godley, S. G. Johnson, W. A. Johnson,
J. R. Kittrell, T. G. Pollitt
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Incorporated
Acorn Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-1332
Task No. 7
12. SPONSORING AGENCY NAME AND ADDRESS
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final Report
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report assesses the impact on the U. S. petroleum refining industry of two
EPA regulations promulgated to control the level of lead additives in motor
gasoline. The first of these regulations requires the availability of low octane,
unleaded gasoline for vehicles equipped with lead sensitive catalytic converters.
For health reasons, the second regulation requires a gradual phase-down of the
lead content of the total gasoline pool (including higher octane gasoline to
satisfy the remaining higher compression ratio engines.) The report assumes
essentially a 100 percent need for unleaded gasoline by 1985. Computer models
representative of specific refineries in six geographical regions of the U. S.
were developed as the basis for determining the impact on the existing refining
industry. New refinery construction during the period under analysis (1975-1985)
was considered by development of separate computer models rather than expansion
of existing refineries. These models were utilized to assess investment and
energy requirements to meet each lead regulation. A sensitivity study was made
of the impact on the refining industry of manufacturing a higher octane unleaded
gasoline than currently mandated. Other sensitivity studies evaluated the effects
of a higher demand for unleaded gasoline than now forecast and of variations in the
type of imported crude oil available in the future for domestic refining.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Gasoline
Gasoline Engine
Tetraethy Lead
Octane Number
Refineries
Unleaded Gasoline
Lead Phase-Down
Motor Gasoline Additives
Catalytic Converter
13, 08
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report/
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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