EPA-600/2-76-161b
June 1976
Environmental Protection Technology Series
IMPACT OF SOX EMISSIONS CONTROL ON
PETROLEUM REFINING INilSTRY
Volume I
Detailed Study Results
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
-------
EPA-600/2-76-161b
June 1976
IMPACT OF SOX EMISSIONS CONTROL
ON PETROLEUM REFINING INDUSTRY
VOLUME H. DETAILED STUDY RESULTS
by
James R. Kittrell and Nigel Godley
Arthur D. Little, Inc.
20 Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-1332, Task 1
ROAPNo. 21ADC-030
Program Element No. 1AB013
EPA Task Officer: Max Samfield
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
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
ILL
-------
TABLE OF CONTENTS - Volume II (cent.)
APPENDIX E
CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY
UPGRADING AND UTILIZATION OF CAPACITY ALREA"V CONSTRUCTED
A. CATALYTIC REFORMING E"2
B. HYDROCRACKING E"
E-16
C. ALKYLATION
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. DERIVATION OF MODEL FIXED INPUTS AND OUTPUTS FOR FUTURE YEARS . G-6
D. SCALE UP OF RESULTS FOR FUTURE YEARS G-10
1. 1977 Scale Up G_10
2. 1985 Scale Up G_12
3. 1980 Scale Up G-15
E. SCALE UP OF CAPITAL INVESTMENTS G_17
-------
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
A. 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
-------
TABLE OF CONTENTS - Volume II (cont.)
APPENDIX K
CONVERSION FACTORS AND NOMENCLATURE
APPENDIX L
ALTERNATE FOR REFINERY SO CONTROL STUDY
" " " ---- - - .- - ~ ~~ . . i 11 j^
FLUE GAS DESULFURIZATION TECHNOLOGY
Page
A. BACKGROUND [[[ L-l
1. Commercial and Near Commercial Technologies .............. L-l
2. Initial Process Selection ................................ L-3
B. DETAILED EVALUATION OF SELECTION PROCESSES . , .................. L-5
1 . Basis [[[ L-5
a. Technical Assumptions ............................... L-5
b. Economic Assumptions ................................ L-9
2 . Chiyoda ---- . ............................................. L-12
a. Process Description ................................. L-12
b. Process Reliability ................................. L-15
c. Application to Refinery SO Control ............. .... L-16
X
d. Capital and Operating Requirements .................. L-l 7
3. Dual Alkali and Wet Lime Scrubbing ................. L-23
a. Process Description ................. , 0_
........... JL> Z. j
b. Process Reliability ..................
L 26
c. Application to Refinery SO Control
x
d. Capital and Operating Requirements
.......... L 28
e. Wet Lime Scrubbing ............
-------
TABLE OF CONTENTS - Volume II (cont.)
APPENDIX L (cont.)
Page
(1) Process Description L-33
(2) Prpcess Reliability L-34
(3) Applicability to Refinery SO Control L-36
X
4. Magnesia Scrubbing L-38
a. Process Description L-38
(1) SO Absorption L-40
(2) Slurry Processing L-42
(3) Dewatering L-45
(4) Drying; L-46
(5) Calcining L-46
(6) Slurry Makeup L-48
(7) Sulfuric Acid Production L-48
b. Process Reliability L-50
c. Application to Refinery SO Control L-54
X
d. Capital and Operating Requirements L-57
5. Shell/UOP L-62
a. Process Description L-62
b. Process Reliability L-68
c. Application to Refinery SO Control L-71
X
d. Capital and Operating Requirements L-74
6. Wellman-Lord L-80
a. Process Description L-80
(1) Gas Pretreatment L-81
vii
-------
(cant.)
APPENDIX.L (cont.)
r a^c
... L-84
(2) SO Absorption
... L-86
(3) Absorbent Regeneration
T Rft
(4) System Purge & Makeup
L-91
b. Process Reliability
c. Applicability to Refinery SO Control L~
X
d. Capital and Operating Requirements L-96
(1) Scrubber System L-96
(2) Regeneration System L-99
C. OFF-LINE COMPARATIVE ECONOMIC ANALYSIS L-101
D. CONTROL OF SULFUR PLANT EMISSIONS L-110
1. Alternatives L-110
2. Economics , L-113
3. Claus Tail-Gas-Cleanup Processes L-114
E. INTEGRATION OF S02 REMOVAL PROCESSES L-116
1. Davy Powergas Process L-116
2. Process Requirements L-ITft
viii
-------
VOLUME II
LIST OF TABLES
APPENDIX A
TABLE A-l. Bureau of Mines Receipts of Crude by Origin 1973 A~3
TABLE A-2. ADL Model Crude Slates and Sulfur Contents
for 1973 A~4
TABLE A-3. Model Crude Slates - Small Midcontinent A-5
TABLE A-4. Model Crude Slates - Large Midwest A-7
TABLE A-5. Model Crude Slates - Texas Gulf A-8
TABLE A-6. Model Crude Slates - East Coast A-9
TABLE A-7. Model Crude Slates - West Coast A-ll
1 A
TABLE A-8. Model Crude Slates - Louisiana Gulf A-12
i
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
tx
-------
APPENDIX C
TABLE C-l. Product Specifications, Gasoline c~2
C-4
TABLE C-2. Other Product Specifications
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. Alkylatton and Isomerization Capacity Availability E-17
TABLE E-10. Utilization of Existing Alkylation Capacity E_jo
TABLE E-ll. Isomerization Investment for Capacity Utilization
and Once Through Upgrading ».»/»
».......... E^0
TABLE E-12. Costs of Additional Isomerization Capacity
TABLE E-13. Cost of Once Through Isomerization Upgrading
-------
APPENDIX F
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 v- 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~1:L
TABLE F-7. Summary of Major Refinery Processing Units F~12
TABLE F-8. Comparison of Product Output of East Coast
Cluster to PAD DiftrCict 1, 1973 - F~14
TABLE F-9. Comparison of Product Output of Midcontinent Clusters
to PAD District II, 1973 F-15
TABLE F-10. Comparison of Product Output of Gulf Coast Clusters
to PAD District III, 1973 F-16
TABLE F-ll. Comparison of Product Output of West Coast Cluster
to PAD District V, 1973 F-l7
TABLE F-12. Comparison of Crude Input of East Coast Cluster
to PAD District 1, 1973 F-18
TABLE F-13. Comparison of Crude Input to Midcontinent Cluster
to PAD District II, 1973 , F-19
TABLE F-14. Comparison of Crude Input of Gulf Coast Clusters
to PAD District III, 1973 F-20
TABLE F-15. Comparison of Crude Input to West Coast Cluster
PAD District V, 1973 F-21
xi
-------
APPENDIX G Pag
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 ...............................
TABLE G-3. L.P. Model Input /Out turns 1977
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~1;L
TABLE G-7. Atypical Refinery Intake/Outturn Summary ................ G-13
TABLE G-8. Scale Up Input/Output - 1985 ............................ G-1*
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 Da ta-Hyd roc racking ................................ H-1A
TABLE H-6. Yield Data-Coking ....................................... H_15
TABLE H-7. Yield Data-Visbreaking .................................. H_16
TABLE H-8. Yield Data -Desulfurizat ion .............................. H_17
TABLE H-9. Yield Data-Miscellaneous Process Units ................. H-18
TABLE H-10. Hydrogen Consumption Data - Desulfurization of Crude-
Specific Streams ................... U1n
....... ............ H iy
TABLE H-ll. Hydrogen Consumption Data - Hydrocracking and
Desulfurization of Model-Specific Streams u on
TABLE H-12 . Sulfur Removal ...........................
* ..... *** ............. H 21
TABLE H-13. Stream Qualities - Domestic Crudes
*"** ...... «.. H 22
xli
-------
APPENDIX H - (coat.)
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
f 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
xiii
-------
APPENDIX I - (ront.)
Page
TABLE 1-4. Bureau of Mines Refinery Fuel Consumption for Cluster ^ ^
Models 1973
. 1-7
TABLE 1-5. ADL Model Input/Outturn Data for Calibration
TABLE 1-6. Conversion of BOM Input/Outturn Data to ADL Model ^ ^
TABLE 1-7.
TABLE 1-8.
TABLE 1-9.
TABLE 1-10.
TABLE 1-11.
TABLE 1-12.
TABLE 1-13.
TABLE 1-14.
TABLE 1-15.
TABLE 1-16.
TABLE 1-17.
TABLE 1-18.
TABLE 1-19.
TABLE 1-20.
TABLE 1-21.
TABLE 1-22.
TABLE 1-23.
TABLE 1-24.
TABLE 1-25.
Format
ADL Model Crude Slates and Sulfur Contents for
Refinery Clusters
Texas Gulf Cluster Processing Configuration
Louisiana Gulf Cluster Processing Configuration
Large Midwest Cluster Process Configuration
Small Midcontinent Cluster Processing Configuration
West Coast Cluster Model Processing Configuration
Cluster Model Gasoline Production and Properties
1973
Key Product Specifications
Cluster Model Processing Data - 1973
Louisiana Gulf Cluster Model
Texas Gulf Cluster Model
Large Midwest Cluster Model
Small Midcontinent Cluster Model .
West Coast Cluster Model
East Coast Cluster Model
Louisiana Gulf Calibration
Texas Gulf Calibration
Small Midcontinent Calibration
1-11
1-12
1-13
1-14
1-15
1-16
1-17
1-19
1-20
1-23
1-32
1-33
1-34
1-35
1-36
1-37
1-39
1-40
1-41
xiv
-------
APPENDIX I - cont.)
Page
TABLE 1-26. Large Midwest Calibration 1-42
TABLE 1-27. West Coast Calibration 1-43
TABLE 1-28. East Coast Calibration 1-44
APPENDIX J
TABLE J-l. Economic Penalty for Reducing Refinery SO Emissions -
1977 ? J-5
TABLE J-2. Economic Penalty for Reducing Refinery SO Emissions -
1985 * J-6
TABLE J-3. Energy Penalty for Reducing Refinery SO Emissions -
1977 ? J-7
TABLE J-4. Energy Penalty for Reducing Refinery SO Emissions -
1985 ? J-8
TABLE J-5. Capital Investment Requirements to Reduce Refinery
SO Emission Levels J-9
x
TABLE J-6. Operating Costs Required to Reduce Refinery SO
Emission Levels J-10
TABLE J-7. Basis for Cluster Capital Investment Requirements J-ll
TABLE J-8. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - East Coast J-12
TABLE J-9. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Large Midwest J-13
TABLE J-10. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-14
TABLE J-ll. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-15
TABLE J-12. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Texas Gulf J-16
TABLE J-13. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - West Coast J-17
TABLE J-14. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Grassroots Refinery
East of Rockies J-l8
XV
-------
APPENDIX J (cont.)
TABLE j-15. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery - ......... ^^
West of Rockies ......................................
TABLE J-16. L.P. Model Results - Fixed Inputs and Outputs -
East Coast ............................................
TABLE J-17. L.P. Model Results - Fixed Inputs and Outputs -
Large Midwest ......................................... J~21
TABLE J-18. L.P. Model Results - Fixed Inputs and Outputs -
Small Midcontinent .................................... J~22
TABLE J-19. L.P. Model Results - Fixed Inputs and Outputs -
Louisiana Gulf ........................................ J-23
TABLE J-20. L.P. Model Results - Fixed Inputs and Outputs -
Texas Gulf ............................................ J-24
TABLE J-21. L.P. Model Results - Fixed Inputs and Outputs -
West Coast ............................................ J-25
TABLE J-22. L.P. Model Results - Inputs and Fixed Outputs
Grassroots Refineries ................................. J-26
TABLE J-23. L.P. Model Results - Processing and Variable Outputs
East Coast Cluster .................................... J-27
TABLE J-24. L.P. Model Results - Processing and Variable Outputs -
Large Midwest Cluster ................................. J-28
TABLE J-25. L.P. Model Results - Processing and Variable Outputs
Small Midcontinent Cluster ............................ J-29
TABLE J-26. L.P. Model Results - Processing and Variable Outputs -
Louisiana Gulf Cluster
TABLE J-27. L.P. Model Results - Processing and Variable Outputs -
Texas Gulf Cluster
TABLE J-28. L.P. Model Results - Processing and Variable Outputs -
West Coast Cluster ................. T _
.......................... J-32
TABLE J-29. L.P. Model Results - Processing and Variable Outputs
Grassroots Refineries, 1985 ..................
.............. J~33
TABLE J-30. L.P. Model Results Summary - Gasoline Blending
East Coast ..........................
................. J-34
xvi
-------
APPENDIX J - (cont.)
Page
TABLE J-31. L.P. Model Results - Gasoline Blending - East Coast ____ J-35
TABLE J-32. L.P. Model Results - Gasoline Blending - Large Midwest . J-36
TABLE J-33. L.P. Model Results - Gasoline Blending - Large Midwest . J-37
TABLE J-34. L.P. Model Results Summary - Gasoline Blending -
Small Midcontinent ..................................... J-38
TABLE J-35. L.P. Model Results - Gasoline Blending -
Small Midcontinent ..................................... J-39
TABLE J-36, L.P. Model Results Summary - Gasoline Blending -
Louisiana Gulf ......................................... J-40
TABLE J-37. L.P. Model Results - Gasoline Blending - Louisiana Gulf J-41
TABLE J-38. L.P. Model Results Summary - Gasoline Blending -
Texas Gulf ............................................. J-42
TABLE J-39. L.P. Model Results Summary - Gasoline Blending -
Texas Gulf ............................................. J-43
TABLE J-4D. L.P. Model Results Summary - Gasoline Blending -
West Coast ......... .................................... J-44
TABLE J-41. L.P. Model Results - Gasoline Blending - West Coast ---- J-45
TABLE J-42. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries ................................... J-46
TABLE J-43. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries .................................. J-47
TABLE J-44. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1977 [[[ J-48
TABLE J-45. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1985 [[[ J-49
TABLE J-46. L.P. Model Results - Refinery Fuel Sulfur Levels -
1977 ............................. .................. J-50
TABLE J-47. L.P. Model Results - Refinery Fuel Sulfur Levels -
-------
APPENDIX J - (cont.)
TABLE J-48. Sample Calculations for Mass and Sulfur Balance Page
Texas Gulf 1985, Scenario B/C - Stream Values -
Gas Oil 375-650°F J~53
TABLE J-49. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 B/C - Desulfurization of
Light Gas Oil J~54
TABLE J-50. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Feed Sulfur Levels ... J-55
TABLE J-51. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Stream Qualities -
Cluster-Specific Streams J-56
TABLE J-52. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 Scenario B/C - Stream Qualities -
Cluster-Specific Streams J-57
TABLE J-53. Specific Gravities for Miscellaneous Streams J-58
TABLE J-54. Mass and Sulfur Balance - Texas Gulf Cluster 1985 '
Scenario B/C J-59
TABLE J-55. Mass and Sulfur Balance - Texas Gulf Cluster 1985
Scenario F J-67
APPENDIX K
TABLE K-l, Weight Conversions
"»*«»..»»», K*~l
TABLE K-2 Volume Conversions
K-2
Table K-3. Gravity, Weight and Volume Conversions for Petroleum
Products
K-3
TABLE K-4. Representative Weights of Petroleum Products
TABLE K-5. Heating Values of Crude Petroleum and Petroleum
Products
K-5
TABLE K-6. Nomenclature
K-6
xviii
-------
APPENDIX L
Page
TABLE L-l. Development Status of Significant SC>2 Control
Processes L-2
TABLE L-2. Major Sources of SOX Emissions in Refineries L-6
TABLE L-3. Refinery Sulfur Emission Sources L-7
TABLE L-4. Unit Costs Applied in Off-Line Economics L-ll
TABLE L-5. Chiyoda Thoroughbred 101 Process Estimated Capital Cost
and Operating Requirements - Gas Side L-18
TABLE L-6. Chiyoda Thoroughbred 101 Process Estimated Capital Cost
and Operating Requirements - Liquor Side L-21
TABLE L-7. Dual Alkali Process Estimated Capital Cost and Operating
Requirements - Gas Side L-29
TABLE L-8. Dual Alkali Process Estimated Capital and Operating
Costs - Liquor Side L-31
TABLE L-9. Capital and Operating Requirements - Magnesium Oxide
Scrubbing System L-58
TABLE L-10. Capital and Operating Requirements - Magnesium Oxide
Regeneration System L-59
TABLE L-ll. Capital and Operating Cost Estimate - Shell Flue Gas
Desulfurization Acceptor System L-75
TABLE L-12. Capital and Operating Cost Estimate - Shell Flue Gas
Desulfurization Regeneration/Reduction Section L-77
TABLE L-13. Capital and Operating Cost Estimates - Wellman-Lord
Scrubbing System L-92
TABLE L-14. Capital and Operating Cost Estimates - Wellman-Lord
Regeneration System L-97
TABLE L-15. Flue Gas Desulfurization Processes Off-Line
Comparative Economic L-102
TABLE L-16. Exxon R and E FCC Scrubbing System Capital and
Operating Requirements L-109
TABLE L-17. Beavon Tail-Gas-Cleanup Process Typical Investment
and Operating Requirements L-115
xix
-------
APPENDIX L (cont.)
Page
TABLE L-18. Flue Gas Desulfurlzation Process Economics -
Capital Requirements L-119
TABLE L-19. Refinery Flue Gas Desulfurization Process
Operating Requirements ' L-120
XX
-------
VOLUME II
LIST OF FIGURES
APPENDIX F
Page
FIGURE F-l. Geographic Regions Considered in Development of
Cluster Models F-3
APPENDIX I
FIGURE 1-1. Louisiana Gulf Cluster Model Calibration 1-25
FIGURE 1-2. Texas Gulf Cluster Model Calibration 1-26
FIGURE 1-3. Small Midcontinent Cluster Model Calibration 1-27
FIGURE 1-4. Large Midwest Cluster Model Calibration 1-28
FIGURE 1-5. West Coast Cluster Model Calibration 1-29
FIGURE 1-6. East Coast Cluster Model Calibration 1-30
APPENDIX J
FIGURE J-l. Texas Gulf Cluster 1985 Sulfur and Material Balance J-52
APPENDIX L
FIGURE L-l. Process Flow Diagram, Chiyoda Thoroughbred 101 '. L-13
FIGURE L-2. Chiyoda Engineering, Capital Investment
Scrubbing Section L-20
FIGURE L-3. Chiyoda Engineering, Capital Investment
Regeneration Section L-22
FIGURE L-4. Dual Alkali System L-24
FIGURE L-5. Double Alkali, Capital Investment - Scrubbing Section ... L-30
FIGURE L-6. Double Alkali, Capital Investment - Regeneration
Section L-32
FIGURE L-7. Dual Alkali Scrubbing With Lime Regeneration L-35
xxi
-------
APPENDIX L (cont.) Page
FIGURE L-8. Flow Diagram - Magnesia Slurry Scrubbing-Regeneration L~41
FIGURE L-9. MagOx (Chemico) Capital Investment - Scrubbing Section L-60
FIGURE L-10. MagOx (Chemico) Capital Investment - Regeneration Section .. L-61
FIGURE L-ll. Simplified Process Flow Scheme of SFGD L~65
FIGURE L-12. Simplified Flow Scheme of SFGD Demonstration Unit for
Coal Fired Utility Boiler at Tampa Electric, Florida L-73
FIGURE L-13. Shell/UOP, Capital Investment - Acceptor Section L~76
FIGURE L-14. Shell/UOP, Capital Investment - Regeneration Section L-79
FIGURE L-15. Schematic Flowsheet - Wellman-Lord Process L-82
FIGURE L-16. Davy Power Gas, Capital Investment - Scrubbing Section L-98
FIGURE L-17. Davy Power Gas, Capital Investment - Regeneration Section .. L-100
FIGURE L-18. Typical Flow Diagram - Exxon FCC Caustic Scrubbing System .. L-107
FIGURE L-19. Glaus Tail Gas Cleanup - Scheme I and II L-lll
FIGURE L-20. Conceptual Refinery SOX Control System Based on
Wellman-Lord Process L-117
xxii
-------
APPENDIX A
CRUDE SLATES
A-i
-------
TABLE OF CONTENTS
.......... A-l
A. METHODOLOGY ....................................
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
A-ii
-------
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. ^See 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
Midcontinenf;
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
F.nst 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-
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 decreasmg
amounts of domestic crudes (particularly lower sulfur Louisiana crudes)
availahlp 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
rrudos and low sulfur African crudes. There is already evidence of this
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
Mid continent
459
63
18,906
2,259
21,931
85
370
4,686
1,022
49,781
10,744
10,744
L
Mid
3
g
19
1C
32
48
1C
136
2
t
3(
rge
/est
OQQ
ocru
090
836
354
R.A1
Q*K>
241
836
673
805
818
o lo
694
022
238
291
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
70,446
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
100.0
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 East Coast
Volume
-
-
58.0
21.4
79.4
-
48.6
-
-
11.0
16.2
75.8
155.2
% Volume
t
- ! 28.9
- > 14.4
_
37.4
13.8
51.2
-
31.3
-
-
7.1
10.4
48.8
100.0
1.251
1.30
-
-
43.3
20.4
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
aReference-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
5.8
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 -apidly, 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.)
.«L«1 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 suoplies decline in the future, it ls forecast that Fast
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 Nigeria
tvpe crudes (representing some 38% of total crude oil to the East Coast
A-6
.an
-------
>
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
-------
>
00
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
i
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
1OO.O
-------
cluster model in 1977-1985), with the remainder supplied by
Eastern and Venezuelan crudes.
West Coast: The refineries comprising this cluster model currently
run an almost 50/50 mixture of domestic California crudes and foreign
crudes. The predominent domestic crude is presently typified by
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-8.)
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 f/rassroots refineries in that part of the country
would run exclusively Alaskan North Slope crudes.
('. CRUPK MIX FOR TOTAL U.S.
In order to assess the implications for the total U.S. crude slate of
,ur assumptions regarding crude inputs to cluster models and grassroots
A-10
-------
>
I
Table A-7. MODE L 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
-------
H-
ro
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 some 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
Atypical
I
3,253.2 '
3,368.0
640.0 j
1,057.8
930.5
9,249.5
1.850.5
412.3
422.2
400.2
-
-
-
3,085.2
12,334.7
-
-
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
722.2
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
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
Sweet8
36.1
-
3.7
-
-
39.8
3.9
-
-
3.7
-
1.5
9.1
48.9
\i
-------
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
B-i
-------
TABLE OF CONTENTS
APPENDIX B - U.S. SUPPLY/DEMAND PROJECTIONS
Page
A. DEMAND ASSUMPTIONS FOR MODEL RUNS B~1
B. DETAILED U.S. PRODUCT DEMAND FORECAST B~7
I. 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 f6r
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
B-ii
-------
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 ecmorale 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 starting points
(see Table B-l) ; (?) 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
-
T ^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
Hi9h
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
a)
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
Pu1C!!'u HoWGVer> We feCl that U d°es 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
Tbtaf
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 (diesel). 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,"
r.iking 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 in 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
C-i
-------
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
C-ii
-------
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
^^M^^^^-MHI^^^^riaOWV
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
^^^^^^^^^Vl^tftaBHta^H
28.0
30.0
28.0
28.0
28.0
28.0
28.0
30.0
30.0
30.0
30.0
30.0
30.0
30.0
32.0
30.0
% Evaporated at 210°F
Minimum Maximum
r
42.0
42.0
42.0
4ZO
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
42.0
^^^^^^^ . mm ^^^M
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
n
i
N)
-------
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
Clutter 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
20.0
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
o
P"
-------
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
D-i
-------
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
i
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-8
D-ii
-------
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,
X
while other states express standards only in terms of ambient air or ground
level S0_ concentrations. In the latter case, allowable SO,, 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 Summary 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 S0?
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
I
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
22
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 lirjiits.
D-4
-------
Table D-2. REFINERY FUEL SULFUR REGULATIONS BY PAD
1
PAD
1
H
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
o
1
Ln
-------
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 indus'try 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- Bay town, 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.
D-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.
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
. t . .
Maximum allowable sulfur level
in refinery fuel system, wt. %
0.6
1.5
1.5
0.9
0.9
0.7
D-8
-------
APPENDIX E
CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY
UPGRADING AND UTILIZATION OF CAPACITY ALREADY CONSTRUCTED
E-i
-------
TABLE OF CONTENTS
APPENDIX E - CAPITAL.J[NVESTnfflNT_FOR_P.ROCESS 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
M^I_PJLJABLE1
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
E-ii
-------
APPENDIX E
CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY UPGRADING
AN?_ 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 justify 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)
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
-------
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
throughput 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,
$/B/SD
1,135
1,135
1,450
All other clusters
Standard unit,
MB/SD
25
25
25
Investment,
$/B/SD
655
655
760
E-6
-------
PI
I
Table E-3. COSTS OF ADDITIONAL REFORMER CAPACITY
Large Midwest Cluster
81973 calibration thruput Table E-1
bTotal capacity available after 1977
cThruput x (655/0.85)
dThruput x (760/0.85)
Reformer throughput required (MB/CD)
High severity
Low severity
Subtotal
Less existing thru put (MB/CD)
Subtotal (MB/CD)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Cost of spare capacity0 ($MM)
Cost of new capacityd (SWIM)
Total capacity cost (SMM)
Cumulative total capacity cost (SWIM)
Scenario A
1977
4.4
20.7
25.1
25.3*
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
-------
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 den and 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 amount 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 $25.4
million. To obtain the contribution of the Large Midwest cluster to the
U.S. refining industry requires further multiplication of this penalty by
the scale-up factor of Appendix G.
B. HYDROCRACKING
The methodology used to assess investment costs for utilization of
spare capacity and alterations in severity of operations for hydrocracking
is similar to that used for reforming. Again, calibration results indicated
E-8
-------
i
o
Table E-4. COST OF SEVERITY UPGRADING
Large Midwest Cluster
High severity reformer thruput required (MB/CD)
Less high severity capacity available (MB/CD)
Subtotal
Less new capacity construction (MB/CD)
Severity upgrading required (MB/CD)
Cost of severity upgrading f ($MM)
Cumulative cost of severity upgrading (SMM)
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
4.6?
0
0
0
0
0
Scenario C
1977
17.7
4.6a
13.1
1.8"
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
a1973 Existing capacity (Table E-1)
Total capacity available after 1977
'Total capacity available after 1980
dNew 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 hydrbcracking
capacity by level of severity, it was assumed for purposes of calculating
investment penalties that actual 1973 hydrocracking severities paralleled
the results obtained fn calibration. Hence, for example, 'he existing
18.1 MB/CD hydrocracl Lng 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 n,ust 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. In
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
*k
6.6
6.6
8.1 J
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/SO
30
30
30
Investment, $/B/SD
1270
1090
240
E-12
-------
Table -7. COSTS OF ADDITIONAL HYDROCRACKING CAPACITY
Texas Gulf Cluster
Hydrocracker throughput required (MB/CD)
High severity
Medium severity
Subtotal
Less existing throughput (MB/CD)
Subtotal (MB/CD)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Cost of spare capacity0 ($MM)
Cost of new capacity** ($MM)
Total capacity cost ($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
11.03
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
w
H1
CO
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 offsite costs for a
total credit of $13.47 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 existing 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 compared to $1.38 million in
Scenario A. The cumulative onsite severity change penalty for lead
regulations in the Texas Gulf cluster is thus $2.85 million, which when
E-14
-------
Table E-8. COST OF HYDROCRACKER SEVERITY FLEXIBILITY
Texas Gulf Cluster
Medium severity hydrocracker throughput
required (MB/CD)
Less medium severity capacity available (MB/CD)
Total
Less new capacity construction (MB/CD)
Severity flexibility required (MB/CD)
Cost of severity flexibility6 ($MM)
Cumulative cost of severity flexibility ($MM)
Scenario A
1977
6.3
O8
6.3
1.4C
4.9
1.38
1.38
1980
0.3
6.3b
0
0
0
0
1.38
1985
14.7
6.3b
8.4
8.6d
0
0
1.38
Scenario C
1977
14.2
_ a
14.2
1.8°
12.4
3.50
3.50
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
w
M
Ln
a1973 Existing capacity. Table E-5
faTotal capacity available after 1977
°New capacity built in 1977, Table E-7
dNew capacity built in 1985, Table E-7
throughput 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.tble E-9. All but
the Louisiana Gulf ard 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/B 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 alltylation-related penalty for lead regulations is $1.39 million for
E-16
-------
Table E-9. ALKYLATION AND ISOMERIZATION CAPACITY AVAILABILITY
(MB/CD)
Alkytation
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
-
en
a85% of Oil and Gas Journal stream day capacity
-------
I
t-1
oo
Tabte E-10. UTILIZATION OF EXISTING ALKYLATION CAPACITY
Louisiana Gulf Cluster
1973 Calibration throughput, Tabte E-9
bTotal capacity available after 1980
°Spare capacity available after 1980
dThroughput x (1400/0.85)
^^ . - ________[__ nni-nn nrnmmmn I, L -
Alkylation throughput required (MB/CD)
Less existing throughput (MB/CD)
Subtotal (MB/CO)
Less spare capacity (MB/CD)
New capacity required (MB/CO)
Cost of spare capacityd (SMM)
Cumulative cost of spare capacity (SMM)
Scenario A
1977
^^^^^^^
16.9
17.58
0
-
-
0
0
1980
16.9
17.53
0
-
-
0
0
1985
16.6
17.5a
0
-
-
0
0
Scenario C
1977
17.4
17.5a
0
-
"w -
0
0
V
1980
MI mmm*»mi*mvmi*mm**mm***~- "^
17.7
17.5
0.2
2.9
0
0.33
0.33
1985
18.1
17.7b
0.4
2.7°
0
0.66
o.gg
-------
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
utilizing all 2.0 MB/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
$/B/SD
1,000
2,000
1.000
All other clusters
Standard unit,
MB/SD
10
10
10
Investment
$/B/SD
620
1,240
620
E-20
-------
w
I
S3
Table E-12. COSTS OF ADDITIONAL ISOMERIZATION CAPACITY
Texas Gulf Cluster
a1973 Calibration throughput. Table E-9
bTotal capacity available after 1977
cTotal capacity available after 1980
dThroughput x (620/0.85)
e Throughput x (1240/0.85)
Isomerization throughput required (MB/CD)
once through
recycle
Subtotal
Less existing throughput (MB/CD)
Subtotal (MB/CO)
Less spare capacity (MB/CD)
New capacity required (MB/CD)
Total
once through
recycle
Cost of spare capacity01 ($MM)
Cost of new capacity ($MM)
once throughd
recycle6
Total capacity cost (SMM)
Cumulative total capacity cost (SMM)
Scenario A
1977
0
0
0
o8
0
2.0
0
0
.
0
0
1980
0
0
0
o8
0
2.0
0
0
0
0
1985
0
0
0
o8
0
2.0
0
0
0
0
Scenario C
1977
0.3
2.3
2.6
O3
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
6.4°
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 $24.1 million. Multiplying
by the scale up factors of Appendix G gives the contribution to the U.S.
industry of the Texas Gulf cluster penalty.
E-22
-------
w
to
OJ
Table E-13. COST OF ONCE THROUGH ISOMERIZATION UPGRADING
Texas Gulf Cluster
Recycle isomerization throughput required (MB/CD)
Less recycle capacity available (MB/CD)
Total
Less new recycle capacity construction (MB/CD)
Once through upgrading required (MB/CD)
Cost of once through upgrading9 (SMM)
Cumulative cost of upgrading ($MM)
Scenario A
1977
0
0
0
0
0
0
1980
0
0
0
0
0
0
1985
0
0
0
0
0
0
Scenario C
1977
2.3
Oa
2.3
0.6"
1.7
1.24
1.24
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
bTotal recycle capacity available after 1977
cTotal recycle capacity available after 1980
dNew capacity built in 1977, Table E-12
eNeyv capacity built in 1980, Table E-12
fNew capacity built in 1985, Table E-12
throughput x (620/0.85)
-------
APPENDIX F
DEVELOPMENT OF CLUSTER MODELS
F-i
-------
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 I, 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-l3. 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
F-ii
-------
APPENDIX F - (con't)
Page
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
F-iii
-------
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 refinery 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, summarized 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
F-2
-------
PETROLEUM ADMINISTRATION FOR DEFENSE (PAD) DISTRICTS
(Incl. Alaska
and Hawaii)
BUREAU OF MINES REFINING DISTRICTS
LOUISIANA
GULF COAST
TEXAS
GULF COAST
Source: Bureau of Mines,
Figure F-l. GEOGRAPHIC 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 sojne-
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/Illinois/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 top
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
Champlln - 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 PAp 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
Hydrofining
Hwy 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
Exxon
Baytown.
Texas
400,000
420.000
180,000
124,000
88,OOO
20,000
48,000
90.00O
15,000
41 ,OOO
109.000
8,500
26.0OO
25,000
12,000
Gulf
Port Arthur,
Texas
312,100
319,000
147,400
30,000
120,000
65,000
15.OOO
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 capacity,8 1973
Exxon
Baytown,
Texas
350,000
365,000
150,000
135,000
88,000
20,000
53,000
90,000
32,000
39.5OO
84,000
8,500
26,000
25,000
12,000
Gulf
Port Arthur,
Texas
312,100
319,000
147,400
30,000
12O.OOO
65,000
i 5,000
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
33,000
95,000
94.0OO
29,000
83.0OO
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
17.8OO
42,000
2,833
20,833
900 "~"
833
2,400
1 5,667
4,033
863
Unit capacity. **
1973/
1974
Average
339,034
351,333
138,467
2.0OO
21,000
114,834
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
1 5,667
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
-03
0.2
0.7
4.4
1.1
aB/SD unless otherwise noted.
bUsed in cluster model.
cSolvents.
Reference: Oil and Gas Journal, April 2,
Oil and Gas Journal, April 1,
1973.
1974.
-------
Table F-2. LOUISIANA GULF CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity, B/CD
Vacuum di«t-
Thermal
-Visb.
Fluid coke
-Delayed coke
Other
Catalytic cracking
Catalytic reforming
Hydrocracking
-Dist.
- Residual
-Lubes
-Other
Hydrofining
-Residual
Hvy gas oil
Resid. visb.
Cat feed & cycle
- Distillate
Other
Hydrotreat
Reform feed
-Naphtha
Olef/Arom sat
-S.R. Distill.
-Lubes
Other dist.
Other
Alky'lation
Arom/lsom
-BTX
-HDA
Cyclohex
- C4 Feed
-C5 Feed
C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity," 1974
Gulf
Alliance,
La.
180,400
186,000
55,000
16,000
78,000
37,5OO
16,000
22,000
41,000
28,400
11,100
5,400
840
Shall
Norca,
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. Chat,,
La.
268,000
N.R.
60.000
28,000
125.000
46,000
6,000"
30,000
46.OOO
14,000
35,300
"
7,000
1,000
1974
Average
229.467
68,333
20,667
99,333
41,667
9,333
2,000
23JB67
7,333
29,000
8,667
4,667
25,933
3.7OO
1,800
2,333
2,000
913
Unit capacity ,a 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
Ti.ioo"
5,400
840
Shell
Norco,
La.
240,000
250,000
90,000
17,000
85.000
43,000
29,400
25,000
26.OOO
14,100
6,000
900
Citgo
L. Chas.,
La.
240,000
245.OOO
78,000
25.000
112,500
39.0OO
6,000
16.3OO
11.2OO
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
s
13,667
7,333
19,100
12,400
8.000
22,833
3.70O
1.800
3,333
2,000
878
Unit capacity, **
1973/
1974
Average
223,734
71,167
20,000
95,000
40,750
9,566 ""
1,000
1,000
18,667
7,333
m
24,050
10,534
2,333
4,000
24,383
3.7OO
1,800 .
2,833
2,000
896
%
Crude
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
Tl
aB/SD unless otherwise noted.
bUsed in cluster model.
Reference: Oil and Gas Journal. April 2, 1973.
Oil and Gas Journal, Aprill, 1974.
-------
Table F-3. LARGE MIDWEST CLUSTER PROCESS CONFIGURATION
Unit type
Crude capacity, B/CD
Vacuum din.
Thermal
-Gas oil
-Vlsb
-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
-C4Feed
-C5 Feed
-C5/C6 Feed
Lubes
Asphalt
Coke tons/day
" -""
Unit capacity,8 1974
Mobil
JolMt,
Illinois
175.0OO
186,000
82,000
28,000
66,000
46,200
69.000
67,000
22,000
1,700
Union
Lemon t.
Illinois
152.000
N.R.
55,000
19,500
52.000
32,000
32,000
2,700
4,500
7.0OO
34,500
2,500°
12,800
3,300
2,OOO
1,000
Arco
E. Chic.,
Illinois
126,000
140.000
70.0OO
"
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
1,100
4,133
900
Unit capacity,8 1973
Mobil
Joliet,
Illinois
160,000
164,000
72.5OO
'
28,000
66,000
46,200
53.OOO
54.0OO
18,000
1,700
Union
Lemon t.
Illinois
1 4O.OOO
N.R.
55.0OO
19,000
50.0OO
32,000
32,000
2,000
5.3OO
7,000
37.OOO
16,000
3,200
1,OCO
Arco
E. Chic..
Illinois
135,000
140,000
70,000
.
48,000
2O.OOO
25,000
20,006
2.00O
6,000
10,400
1973
Average
145.000
65,833
6,333
9,333
54,667
32,733
8,333
35,OOO
1,333
1,767
2.333
18,000
12,333
13.333
1,067
3,467
900
- -
Unit capacity, **
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
oo
B/SD unless otherwise noted.
Used for cluster model.
GBenzene 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 coke
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/l som
-BTX
-HDA
Cyclohex
-C4 Feed
-C5 Feed
-CS/C6 Feed
Lubes
Asphalt
Coke-ton s/day
Unit capacity* 1974
Skelly
HI
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
20.00O
11,000
5,000
11,000
5,500
2,000
Champlin
~Emd,
Okla.
49,500
52,000
18,000
3,700
19,500
15,000
20,400
4,500
6,000
1,100
1,400
165
1*74
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.8 1973
Skelly
El
Dorado.
Kan.
67,000
70,000
23,000
9,800
30,000
20,000
23.OOO
4,300
6,000
1.400
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,
Okla.
48,000
50,000
24,000
4,000
19,000
1 5.OOO
15.000
5,000C
4,400
5,OOO
1,200
2.OOO
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, a
-------
I
I
o
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
-Lubes
-Other
Hydrofining
Hvy gas oil
Resid. visb.
Cat feed & cycle
-Distillate
-Other
Hydro'treat
Reform feed
-Naphtha
Olef/Arom sat
-S.R. Distill
Lubes
Other dist.
Other
Alkylation
Arom/lsom
BTX
-HDA
-Cyclohex
C4 Feed
C5 Faed
-C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity,3 1974
Area
Phil.,
Pa.
185,000
1 95.OOO
57.000
60,000
30.0OO
32,000
41.OOO
54,000
19,500
Sun
Marcus
Hook, Pa.
165,000
180.000
48.000
75,000
45,000
35,000
10.OOO
10,000°
12,000
5,300
17,000
12,000
Exxon
Linden,
NJ.
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
65.0OO
49.0OO
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,9 1973
Arco
Phil.,
Pa.
160,000
165,000
83,000
36.0OO
60,OOO
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.OOO
10,000
16,OOOC
12.OOO
5,300
17,000
12,000
Exxon
Linden,
NJ.
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 capacity, **b
1973/
1974
Average
2O0.5OO
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
5,667
25,416
%
Crude
40.7
33.8
23.2
4.7
10.4
6.9
20.8
2.2
1.6
6.0
2.0
3.9
.8
2.7
12.0
aB/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
Crude capacity
Vacuum dl»t.
Thermal
Gas oil
-Visb.
Fluid coke
Delayed coke
-Other
Catalytic cracking
Catalytic reforming
Hydrocracking
-Oist.
Residual
-Lubes
-Other
Hydrofining
Hvy gas oil
-Resid. vi»b.
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
Torrance,
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
Area
Canon,
Calif.
165,000
173,000
93,000
12.500
42,000
30,000
57.000
34,000
19,700
18,000
34,OOO
1 8.0OO
7,200
2,490
1,800
Socal
ElSegundo,
Calif.
230,000
N.R.
103,000
54.0OO
43,500
60,000
49,000
40,000
12,000
18,000°
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
1 23,500
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
173.000
93,000
23.000
37.00O
25,500
57,000
32.000
1 7.0OO
18,000
32,000
18,000
,
7,200
2,490
1,650
Socal
ElSegundo,
Calif.
N.R.
220,000
103.000
50,000
40,000
62,000
45,OOO
40,000
12.OOO
1 8,OOO
5.4OO
1,500
8,300
2,200
1973
Average
174,333
97.0OO
7,667
17,667
40,713
51,000
43,333
26,667
6,000
31,667
11,OOO
4,000
7,667
6,000
7,700
1,330
2,767
2,217
Unit capacity, 8*b
19737
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
aB/SD unless otherwise noted.
bUsed for cluster model.
cjet fuel.
Reference: Oil and Gas Journal. April 2,
Oil and Gas Journal, April 1,
1973.
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
9
8
PAD II
average
22
34
4
7
9
East Coast
cluster
23
34
5
4
0
PAD!
average
21
33
3
4
7
West Coast
cluster
24
29
16
4
24
PADV
average
23
24
15
5
20
n
i
to
-------
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
f
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. 1
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
1 14,904
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
-------
Table F 9. COMPARISON OF PRODUCT OUTPUT OF MIDCONTINENT CLUSTERS TO
P.A.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 duster
MBPY
40,991
472
911
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
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 - 40(f
Other
Special naphthas
Lube oil, total
Wax
Coke (marketable)
Asphalt
Road oil
Total
f iinr
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.P. 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
1 .70
.72
i '13i
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. 1
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. 1
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
0
.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
Canada
Total foreign
Total 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
1,273,459
% of Total
26.52
14.44
30.73
7.87
79.55
.11
-
.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
-
-
-
26,022
30,551
167,245
% of Total
12.80
11.57
48.72
8.64
81.73
-
-
.14
-
.14
-
-
-
2.57
2.57
-
-
-
15.56
18.27
100.00
F-19
-------
Ta»» F-14. COMPARISON OF CRUDE INPUT OF GULF COAST CLUSTERS TO P.A.D.
District III, 1973
Crude Receipts From:
P.A.D. I
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. III
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. I
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
G-i
-------
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. 1985 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
G-ii
-------
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 ±8 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
I so butane
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
6.10
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
2.C5
16.00
13.447
-
-
294.270
37.130
331.400
365.027
Large
Midwest
if
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
NJ
-------
TABLE G-2. COMPARISON OF 1973 B.OJM. DATA AND SCALE UP OF 1973 CALIBRATION INPUT/OUTTURN
(MB/CDI
Intake!
Domestic crudg
Imported crude
Subtotal
Itobutane
Normal butane
Subtotal
Natural gasoline
Plant condensate
Unfinished oils
Total
Purch. natural gas 1FOE
Outturn*
Gat/ethane FOE
LPG-fuel
LPG-petrochemicalt
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke-market
Unfinished oils
Total
Crude capacity (MB/CD)
090%
Scale up factor
PAD!
B.OJM.
data
i
1
A/T
237.3 j -
1,264.1
1.501.4
-
-
.8
.4
5.8
108 2
1.616.6
14.0
2.7
39.4
17.5
747.8
7.0
13.S
34.1
19.2
404.9
37.0
143.2
101.7
15.3
_
1,583.3
1,673.52
1.506.17
-
100.0
-
-
-
-
-
Cluster
model
scaled up
308.5
1.031.2
1,339.7
2.5
12.5
15.0
41.6
-
; 121 7
100.0
-
-
-
-
-
-
-
-
50.0
-
50.0
-
-
-
100.0
_
-
1318.0
17.8
6.1
46.0
29.4
747.8
9.1
9.7
41.1
242
324.4
35.2
91.4
129.2
-
-
1.495.6
-
-
7.127
PAD II
Okla., Kara., etc.
B.O.M.
data
S93.3
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
4.5
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
seeled 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
1
Balance PAD
B.O.M.
data
1,880.9
682.5
2.563.4
-
-
40.9
20.7
66.9
5 1
2397.0
19.8
5.8
50.2
7.6
1,451.7
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
-
-
17.769
Total PAD
B.O.M.
data
2,774.2
710.7
3,484.9
-
-
73.2
53.4
67.0
c 1
3,683.6
57.4
7.9
69.4
11.6
1595.2
42.9
18.0
A/T
-
-
100.0
-
-
_
-
-
100.0
_
-
-
-
10.0
-
145.7 i 15.0
64.5
823.7
32.7
1943
169.1
51.5
4.5
3.621.5
3,889.412
3.500.47
ts.o
-
-
30.0
30.0
-
-
100.0
-
-
Cluster
model
scaled up
2.759.4
627.0
3.386.4
79.3
4.5
B3.8
96.3
-
439
3.609.4
34.0
7.8
77.7
8.7
1,995.2
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.GUH
B.O.M.
data
1,617.2
46.2
1.633.4
-
-
54.4
66.2
4.4
41 9
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
-
-
duster
model
scaled up
1,697.8
1.697.8
46.6
45.6
92.2
32.7
_
1.822.7
41.3
2.4
4S.6
18.3
907.7
6.0
-
141.6
42.0
518.1
-
40.9
11.8
31.5
25.4
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
A/T
-
-
-
-
-
_
-
-
_
-
_
58.4 ! -
44.6
1,774.7 i -
100.7 ! -
109.1
187.8
79.3
878.4
94.1
177.3
73.3
32.4
61.8
3.699.5
4,039.876
3,635 8<»
-
-
-
-
-
-
-
-
-
-
-
-
Cluster
model
seated 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
74.5
3,741.9
-
-
10.715
Total PAD
B.O.M.
data
4,655.9
393.1
5,054.0
-
-
1166
357.4
45.6
all ")
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
61.8
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
99.9
5,533.2
-
Q
CO
-------
TABLE G 2 (Continued) COMPARISON OF 1973 B.O.M. DATA AND SCALE UP OF 1973 CALIBRATION INPUT/OUTTURN
(MB/CD)
Intakes
Domestic crude
1 mported crude
Subtotal
1 so butane
Normal butane
Subtotal
Natural gasoline
Condensate
Unfinished oils
Total
Purch. natural gas (FOE)
Outturn
Gas/ethane-FOE
LPG-fuel
LPG-petrochemicals
Gasoline
Naphtha
BTX
Jet fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke-market
Unfinished oils
Total
Crude Capacity (MB/CD)
@90%
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
505.721
455.15
PAD I-IV
total
Dlimloi
modal
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
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
;1 1,294.3
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
5,653.6
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
Scale up 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
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
AST
-
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
-
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
12,798.28
-------
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/T", 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 100 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 crade 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
G-7
-------
Table G-4. L.P. MODEL INPUT/OUTTURNS 1980
(MB/CD)
Fixed intakes
Domestic crude
Imported crude
Subtotal
loobutane
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.
fuet 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
0.336
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
2.855
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
f,
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
"
G-9
-------
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 lip,
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 same 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.
i
G-10
-------
Table G-6 SCALE UP INPUT/OUTTURNS 1977
Scenario
A
B
C
0
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/CO
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/CD
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 Gutf
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 and 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 the 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
residua] 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
Other0
268.2
-
-
-
-
268.2
-
-
-
-
18.3
-
18.3
24.4
61.0
-
97.5
48.8
-
268.3
aTotalof PADS I, II, III and V.
G-13
-------
Table 6-8. SCALE UP INPUT/OUTPUT - 1985
Fixed intakes
Domestic crude
Imported crude
Subtotal
Isobutane
Normal butane
Subtotal
Natural gasoline
Unfinished oils
Total
Fixed outturns
Gas/ethane-FOE
LPG-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
All products
B/C Gasoline
LPG-fuel
All products
D Gasoline
LPG-fuel
All products
E Gasoline
LPG-fuel
All products
F Gasoline
LPG-fuel
All products
Scale up factor
East
Coast
_
1.B06.1
1,506.1
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
1.63B.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
2,600.0
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.B
576.4
22.4
959.6
557.5
28.2
946.5
541.5
27.7
930.0
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
PAD Districts I-IV
Texas
Gulf
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
M.9
3,633.0
11.O71
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
290.5
10,375.8
5,059.9
484.5
10.347.1
5,292.5
238.0
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
474 1
226.8
6.0
706.9
226.8
6.0
706.9
226.8
6.0
706.9
226.8
60
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
5,643.5
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
7,050.3
~
Grass
Roots
required .
outturn
145.4
42.8
704.2
493.0
1,385.4
1.204.0
1,368.0
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
275.8
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
12B.V,
3.4
128..1
3.4
128.0
3.4
128.0
3.4
128.0
~~
Total
supply
6.7
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
/
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
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
+,
A/T
13,066.4
187.1
281.4
145.1
13.680.0
32.3
116.8
224.4
160.3
757.4
2P9A
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
323
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
15.6346
6,501 .0
244.0
15,600.4
~
Major
product
demand
1.179.8
262.3
4.327.6
3,423.8
9,183.5
8,174.2
8.174.2
8,174.2
8.174.2
8.1 74.2
Grass
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 prod"CL
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
-------
(MB/CD)
Find intakes
Domestic crude
Imported crude
Subtotal
Isobutane
Normal butane
Subtotal
Natural gasoline
Natural gu (FOE)
Unfinhhed oils
Total
Fixed outturn!
Gas/ethane (FOE)
LPG-petrochemicali
Naphtha
BTX
Jet Fuel
Kerosene
Distillate fuel oil
Lube stocks
Residual fuel oil
Asphalt
Coke-market
Unfinished oils
Total
Variable outturns
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
All products
1 Scale up factor
PAD DISTRICTS I-IV
EM
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
4S.5
26.8
359.6
39.0
101.3
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
mi
Urge
Midwest
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
1,415.0
63.4
2,688.7
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
J
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
98S.2
587.9
25.7
984.5
581.3
31.9
984.1
580.7
32.5
984.1
578.5
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
22.3
1,767.2
9.18.0
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
Subtq.«l
I-IV
7,261.2
3.084.9
0.346.1
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
5.677.4
182.3
10.741.2
5,521.9
229.4
10,732.8
5.471.
263.6
10,716.
5,462.
268.
10.""11.
5,446.2
277.8
10,705.5
r
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
115.6
74.9
3.9
-
451.8
230.4
6.1
688.3
230.4
6.1
688.3
230.4
6.1
688.3
230.4
6.1
688.3
230.4
6.
688.
^^»^^^
Major
oduct
mports
124.9
2.2
381.0
,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.S
235.5
13.857.1
5^31.6
269.7
13^40.4
5322.9
274.2
13336.2
5.806.8
283.9
13329.8
1 1
4
Major
product
demand
706.5
228.5
3.575.8
2.583.1
7.093.9
6,385.7
6.385.7
6.385.7
6.385.7
6.385.7
j
Gnus
roots
equirrt
outturn
PAD DISTRICT V
Cluster
scale-up
1,988.3
-
1,988.3
4.8
1.6
6.4
12.6
38.7
67.0
i
63.8
18.0
292.4
226.6
600.8
447.7
503.2
564.1
562.8
578.9
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
863.7
36.2
2,083.3
859.5
45.2
2,083.1
852.5
36.5
2,067.4
845.4
2.068.9
844.2
45.3
2.067.9
12.110
Major
product
mports
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
53
16.3
47.7
48.8
307.2
2.1
288.3
4.4
437.2
25.3
119.9
1,303.0
872.1
36.2
V1 1-3
862.9
45.2
2,2i:.
855.9
36.
2.195.4
848.
Ati
2,196.
847.
46.
2,195.
Major
otfuct
lemand
362.1
3433
517.9
1.2233
1,018.
1.018
1,018
1.018
1.018
^^^^^^^M
Grasi
roots
required
outturn
54.9
55.5
80.7
191.1
145.9
155.1
162.1
169.2
170.4
^ ^^^^^^^^ "
TOTAL US.
Cluster
scale-up
+
A/T
3,032.5
209.7
315.2
168.7
242.1
3,968.2
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
6,611.7
6.676.5
224.6
13.512.8
6.611.8
280.7
13.504.2
6.553.9
306.2
13.4715
6,538.1
3193
13.469.1
6.520.8
329.2
13.461.7
Major
iroouct
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
6310.1
224.6
16.076.8
6.745.4
280.7
16,068.2
6.687.5
306.
16.035.8
6.671.
319.
16,033.
6,654.
329.
16.025.
Major
oduct
mend
068.6
228.5
,919.6
,101.0
B.317.7
7.403.7
7.403.7
7.403.7
7,403.7
7.403.7
rass roots
raquirad
outturn
118.7
18.0
347.9
307.3
791.9
593,6
658.3
71 6 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 felt 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.
G-17
-------
APPENDIX H
TECHNICAL DOCUMENTATION
H-i
-------
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-.!S
H-ii
-------
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
H-iii
-------
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
(C.5-160°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 aJ 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 ti-2 and H-3 provide basic yield data 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 can 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 (300-
400 psig) reactor pressure. The hydrogen yield shewn in the table and ised
in the model is the effective hydrogen production available for hydro-
treating purposes. This value is approximately 2/3 the stpchiometric 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 napht.has
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 11-3 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 Documertation 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 commonly 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, onre-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
aIkylate.
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 offsite 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
i Heavy 340-376° F
> Light gas oil 375-500°F
Heavy gas oil 500-650° F
Vacuum overhead 650-1 060° F
Vacuum bottoms 1050°F+
Gravity (°API)
% Weight sulfur
Domestic crudes
Louisiana
-
.20
.40
.70
4.09
2.99
. 13.05
3.47
17.50
19.50
32.50
5.60
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
28.04
10.25
40.2
.212 >
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
.00%
.400
.295
1.069
5.72
3.26
14.26
3.34
11.54
12.53
32.08
15.50
29.7
1.56
Alaskan
>i .
raonn
Slope
.06
.28
.13
.49
3.S3
2.57
9.25
2.69
12.43
15.50
29.49
23.52
27.5
.96
' -^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^l ! 1 ,,^^^m~ H
Foreign crudes
Nigerian
FOTCBOOS
.04
.04
.51
.79
2.70
3.40
11.70
2.80
18.10
20.60
30.40
850
29.4
.21
Arabian
Light
-
.17
.17
1.06
4.8S
3.27
14.93
3.95
13.39
15.01
29.50
13.70
34.5
1.7
Venezuelan
TiaJuana
.01
.59
.27
.45
3.89
2.20
9.09
2.52
10.30
12.70
32.80
25.00
26.3
151
Algerian
Hassi
.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
Min*>
.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
-
-
-
-
. -
a
00
-------
Table H-2. YIELD DATA
Reforming of SR Naphtha
90 BON Severity
Stream*
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
4 90 Reformate
> Medium feed (200-340°)
' Hydrogen (MSCF)b
Ethane/ methane 1FOE)
Propane
Isobutane
Normal butane
90 Reformate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformate
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
OBOO
CKrOO
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
.442
.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.
bEffective hydrogen yield available for hydrotreating.
-------
Table H-2 (continued). YIELD DATA
Reforming of SR Naphtha
95 RON Severity
Stream"
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformats
Medium feed (200-340°)
Hydrogen (MSCF)b
j Ethane/methane (FOE)
Propane
4
> Isobutane
Normal butane
95 Reformate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformate
Domestic crudes
Louisiana
.546
.066
.064
.027
.043
.80
.660
.0656
.0441
.0161
.0288
.8428
.660
.0656
.0441
.0161
.0288
.8428
West Texas
Sour
.660
.0656
.0441
.0161
.0288
.8428
.748
.0675
.0219
.004
.0131
.8904
.7-;s
.0675
.0219
.004
.0131
.8904
Oklahoma
.680
.0656
.0405
.0141
.0263
.8505
.660
.0656
.0441
.0161
.0288
.8428
.660
.0656
.0441
Calif.
Wilmington
.748
.0675
.0219.
.004
.0131
.8904
.852
.0656
.0099
-
.0044
.9163
.852
.0656
.0099
.0161
.0288 .0044
.8428
.9163
Calif.
Ventura
.680
.0656
.0405
.0141
.0263
.8505
.790
.0667
.0171
.0024
.0096
.9008
790
.0667
.0171
.0024
.0096
.9008
Alaskan
North Slope
.442
.0654
.0819
.0368
.0557
.7613
.790
.0667
.0171
.0024
.0096
.9008
.790
.0667
.0171
.0024
.0096
.9008
Foreign crudes
Nigerian
Forcados
.719
.0655
.0333
.0102
.0212
.8659
.852
.0656
.0099
-
.0044
.9163
.852
.0656
.0099
-
.0044
.9163
Arabian
Light
.349
.0646
.0983
.0457
.0673
.7262
.442
.0654
.0819
.0368
.0557
.7613
.442
.0654
.0819
.0368
.0557
.7613
Venezuelan
Ta
Juana
.660
.0656
.0441
.0161
.0288
.8428
.704
.0666
.033
.01
.021
.8666
.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
aLV fraction on feed unless otherwise noted.
bEffective hydrogen yield available for hydrotreating.
-------
Table H-2 (continued). YIELD DATA
Reforming of SR Naphtha
100 RON Severity
Stream9
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
i Propane
Isobutane
J 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 Reformate
Domestic crudes
Louisiana
.596
.080
.090
.035
.054
.745
.7520
.0815
West Texas
Sour
.754
.0814
.0715
.0245
.0404
.7848
.838
.0813
.0715 .0508
.0245 i .0129
.0404 i .0253
.7848
.7520
.0815
.0715
.0245
.0404
.7848
.8292
.838
.0813
.0508
.0129
.0253
.8292
Oklahoma
.759
.0813
.0681
.0226
.038
.792
.7520
.0815
.0715
.0245
.0404
.7848
.7520
.0815
.0715
.0245
.0404
.7848
Calif.
WH nun yton
.838
.0813
.0508
.0129
.0253
.8292
.910
.082
.0397
.0065
.017
.8533
.910
.082
.0397
.0065
.017
.8533
Calif.
Ventura
.759
.0813
.0681
.0226
.0380
.7920
.867
.0816
.0464
.0103
.0220
.8388
.86-1
.0816
.0464
.0103
.0220
.8388
Alaskan
North Slope
.487
.0788
.1066
.0444
.0662
.7089
.867
.0816
.0464
.0103
.022
.8388
.867
.0816
.0464
.0103
.022
.8388
Foreign crudes
Nigerian
Forcadoi
.772
.0809
.0614
.0189
.0331
.8064
.910
082
.0397
.0065
017
8533
.910
082
.0397
.0065
Arabian
Light
-
.394
.0784
.1218
.0530
.0773
.6762
.487
.0788
.1066
.0444
.0662
.7089
487
.0788
.1066
.0444
017 ! 0662
.8533 i .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
aLV fraction on feed unless otherwise noted.
bEffective hydrogen yield available for hydrotreating.
-------
Table H-3. YIELD DATA
Reforming of Conversion Naphtha
Stream*
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.
Includes atmospheric gas oils and vacuum overhead.
H-12
-------
Table H-4. YIELD DATA
Catalytic Cracking
(LV fraction on feed)
Stream
Untreated 650-1 050° F feed
Methane/ethane (FOE)
C3/C4 Olefins
Propane
Isobutane
Normal butane
Cat. gasoline (C5 to 430° F
Light cycle oil
Heavy cycle oil
Treated 650-1050°F feed
Methane/ethane (FOE)
C3/C4 Olefins
Propane
Isobutane
Normal butane
Cat. gasoline (Cs to 430° F
Light cycle oil
Heavy cycle oil
Low sev cat cracking
Louisiana
.025
123
.018
.046
.008
.52
.27
.08
.018
.147
.020
.07
012
.57
212
Texas
.025
.128
.013
.046
.008
.52
.27
08
.018
.137
.020
.07
.012
.58
.212
063 ' .063
Large
MiiliM
minw.
.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
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
.58
.212
.063
East
Grassroots
.025
.128
.013
.046
.008
.52
.27
.08
.018
.137
.020
.07
.012
.58
.212
.063
West
Grassroots
.025
.128
.013
.046
.008
.52
.27
.08
.018
137
.020
.07
.012
.58
.212
.063
. High sev cat cracking
Louisiana
.048
.178
.03
.09
.022
.60
.10
.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
.O3'i
'91
043
128
.031
.669 i .669
033 033
017
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
.2.00
.312
.610
H-14
-------
Table H-6. YIELD DATA
Coking
(LV fraction on feed}
Stream
Methane/ethane (FOE)
Propane
C3/C4 Olefins
Isobutane
Normal butane
Light coker naphtha
Med. 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
.O743
.0007
.030
.006
.017
.080
.142
.560
.1615
5C
I
M
Ln
-------
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
-------
TcbteH-8. YIELD DATA
Dcwlfuriation
(LV Fraction on fted)
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
'
Vacuui*
OVHO
.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
BS
-------
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
160-200°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
oo
aLV fraction on feed unless otherwise noted.
^Isobutane consumption 1.19 per unit volume C3/C4 olefin feed.
-------
Table H-10. HYDROGEN CONSUMPTION DATA
Desulfurization of Crude-specific Streams
(MSCF/Bbl feed)
Stream
Normal purity hydrogen
SR 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
a
i
M
VO
aNot 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 hydrocracking
' Heavy gas oil feed
Vacuum gas oil feed
Cracked oil gas feed
Louisiana
.220
.600
.600
1.90
2.45
3.10
1.70
i.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
.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
ac
i
to
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 ojl
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
1PPM
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
1.0/0.5
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 etherise noted.
H-21
-------
Table H-13. STREAM QUALITIES
Domestic Crudes
Stream
Louisiana
Full range naphtha
C5 to 200° F
Q
C5 to 160 F
Light 16O-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 650-1050 F
Vacuum bottoms 1050°F+
Once through isomerate
Recycle isomerate
West Texas Sour
Full range naphtha
C5 to 200°F
C5to160°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° r
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° 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
.9146
.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 ec
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
ac
i
N)
NJ
Q
3Refutas blending values for viscosity in centistokes @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
Atmospheric bottoms 650 F+
Vacuum overhead 650-1 050° F
Vacuum bottoms 1050°F+
Once through isomerate
Recycle isomerate
California Wilmington
Full range naphtha
C5 to 200° F
C5to 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-i-
Vacuum overhead 650-1 050°F
Vacuum bottoms 1 050°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
Viscosity8
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
210°F
95.0
100.0
99.0
105.0
100.0
95.0
100.0
99.0
105.0
100.0
EC
NJ
U>
3 Refutas blending values for viscosity in centistokes @122 F.
-------
Table H-13 (continued). STREAM QUALITIES
Domestic Crudes
Stream
California Ventura
Full range naphtha
C5 to 200° f
C5to160°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 650-1050°F
Vacuum bottoms 1050 F+
Once through isomerate
Recycle isomerate
Alaskan North Slope
Full range naphtha
C5 to 200°F
C5to 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 .5% wgt sulfur
Vacuum overhead 650-1050° 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
.93SO
1.035
.6399
.6379
.7518
.6801
.6526
.7179
.7807
.8151
.8601
.8349
.8803
.9581
.937
.9281
.9957
.945
.645
.64
Sulfur
content,
n weiQnt
.1006
.0209
.0200
.0224
.1019
.2769
.7334
.2797
1.1393
2.4672
1.5411
4.1959
.0001
.0001
.0177
.0147
.0105
.0199
.0160
.0291
.3281
.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
WON
Clear
745
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
Mid-fill blend number.
% distilled at
150°F
41.0
91.3
0.0
95.5 93.0
100.7
85.5
88.1
81.9
92.7
98.9
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
a
N3
C-
!Refutas blending values for viscosity in centistokes @122 F.
-------
Table H-14. STREAM QUALITIES
Foreign Crudes and Natural Gasoline
Stream
Nigerian Forcados
Full range naphtha
C5 to 200°F
A
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
r.o
5.3
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
WON
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
3.0 cc
87.0
90.0
84.6
89.3
93.0
67.0
71.9
57.9
81.8
89.2
94.2
99.8
78.7
82.2
73.5
87.1
96.0
Mid-fill blend number.
% distilled at
150°F 1 210°F
41.0
91.3
0.0
93.0
95.0
53.5
91.3
0.0
93.0
95.0
95.0
100.0
99.0
105.0
100.0
100.0
100.0
99.0
105.0
100.0
EC
N5
Ul
Q
3 Refutas blending values for viscosity in centistokes @122 F.
-------
Table H-14. (continued). STREAM QUALITIES
Foreign Crudes and Natural Gasoline
Stream
Venezuelan Tia Juana
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
Algerian Ham 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
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
.810
.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
.0449
.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 Mending 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
58.9
79.2
87.9
0.5 cc
76.0
"3.8
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 flt
150°F
75.0
91.3
0.0
210°F
100.0
100.0
99.0
I
93.0
95.0
57.0
91.3
0.0
93.0
95.0
105.0
100.0
100.0
100.0
99.0
105.0
100.0
Q
£ Refutas blinding values for viscosity in centistokes @122 F.
-------
Table H-14. (continued). STREAM QUALITIES
Foreign Crudes and Natural Gasoline
Stream
Mixed Canadian
Full range naphtha
C5 to 200° F
C5to 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 1 050 F+
Once through isomerate
Recycle isomerate
Indonesian Minas
Full range naphtha
C5 to 200°F
rt
C5 to 160 F
Q
Light 160-200 F
Medium 200-340°F
Heavy 340-375°F
Atmospheric gas oil 37 5-650° 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
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
Viscosity9
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 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
53.5
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
105.0
100.0
105.0
100.0
99.0
105.0
100.0
a
to
3Refutas blending values for viscosity in centistokes @122 F.
-------
Table H-15. STREAM QUALITIES
Miscellaneous Streams
Strom
Chemical compounds*
Propane
Isobutane
Normal butane
Process streams'*
90 Sev. reformats
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 feed
Heavy SR feed
Hydrocracked naphtha f ica
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
.81
Sulfur
content,
% weight
negl.
negl.
negl.
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
.0001
Smoke
point
Gasoline blending qualities
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
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
33.3
99.8
99.8
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
MON
Clear
95.8
89.0
80.1
80.
80.
80.
80.
80.
82.
82.
82.
82.
82.
82.
86.0
86.0
86.0
86.0
86.0
86.0
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
83.0
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
X
N>
00
-------
Table H-15. (continued). STREAM QUALITIES
Miscellaneous Streams
Stream
Proca* Streams (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)
i .11 ^>«^
A -»
Specific
gravity
.68
.76
.76
.812
.705
.793
.699
.692
.777
Sulfur
content,
% weight
.0001
.0004
.0004
.0004
.0003
.0004
.0004
.0001
.0001
Smoke
B-EjiTa^*
point,
turn.
30.0
15.0
26.0
..I .... .- --i. .. ...... i .... ... -. .. .... . . ... .. ., .... ... . - .1 '-
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
M>«4 fill Klanrl imiiih^i
iV*KJ-TIIi 016*10 nUIIIUVr,
% 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
a
to
vo
^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 Streams8
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
Visbreaker gas oil
Visbreaker tar
Specific
gravity
.753
.757
.755
.758
.8956
.9448
varies
.677
.677
.765
.761
.844
-
.735
.837
.910
Viscosity"3
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
60.1
66-C
3.0 cc
98.8
99.8
99.8
99.8
90.7
89.7
67.7
71.4
MON
Clear
80.0
80.5
80.5
80.5
71.2
72.2
52.2
56.6
0.5 cc
82.2
82.7
82.7
82.7
74.8
75.8
56.9
59.1
3.0 cc
85.3
85.8
85.8
85.8
79.9
80.9
63.9
62.6
Hnid'Tiil bi0nci oumbsr
% distilled at
150°F
17.0
17.0
17.0
17.0
62.5
62.5
-10.0
3.0
210°F
46.7
46.7
46.7
46.7
99.0
99.0
1.0
18.0
X
I
u>
o
8Streams whose specific gravity and viscosity are unit-dependent yet whose sulfur content varies with the feed sulfur. See tables H-17 and H-18 and Appendix J.
for the percentage distribution of feed sulfur among output streams and a discussion of the usage of these percentages.
Refutas blending values for viscosity in centistokes@122°T:.
-------
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
Case 1 - 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
Venezualan 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
18.0
13.3
24.1
19.9
31.0
26.8
18.0
13.8
18.0
13.8
13.9
9.7
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
30.5
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%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
ioo.o%
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
Stream8
L Dittoed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformats
Medium feed (200-340°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformats
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
90 Reformate
High pressure (450 psi)
Louisiana
.87
.0383
.0812
.0266
.0392
.798
1.02
.0185
.025
.0114
.0158
.886
1.05
.0147
.0175
.0083
.0105
.905
West Texas
Sour
.797
.0425
.0678
.0295
.0436
.783
.985
.0225
.0333
.0147
.0213
.864
1.02
.0185
.0253
.0115
.016
.885
Nigerian
Forcados
I.05
.0147
.0175
.0083
.0105
.905
1.045
.0165
.0203
.0095
.012
.898
1.085
.0119
.0114
.0058
.0066
.922
Arabian
Light
.435
.0779
.124
.0538
.0799
.666
.69
.052
.083
.0361
.0535
.752
.9
.0315
.0508
.022
.0322
.822
Venezualan
Tia Juana
.86
.0358
.0574
.025
.0366
.807
.95
.0265
.0408
.018
.0262
.845
.985
.0225
.0333
.0147
.0213
.864
Low pressure (225 psi)
Louisiana
1.12
.0227
.0382
.0166
.0235
.844
1.24
.0055
.0098
.0043
.0064
.917
1.26
.002
.0035
.001
.0025
.933
West Texas
Sour
1.08
.0262
.043
.0188
.0262
.833
1.225
.0095
.017
.0072
.0107
.897
1.24
.0057
.0101
.0043
.0065
.916
Nigerian
Forcados
1.26
.002
.0035
.001
.0025
.933
1.255
.0028
.0049
.0020
.0030
.9310
1.27
.0003
.0008
.0002
.0004
.948
Arabian
Light
.687
.0560
.0854
.0374
.0490
.7320
.983
.0337
.0537
.0235
.0320
.8075
1.180
.0175
.0307
.0133
.0193
.8620
Venezualan
Tia Juana
1.14
.0208
.0355
.0154
.022
.851
1.205
.0134
.0235
.0102
.015
.88
1.225
.0095
.017
.0072
.0107
.897
EC
u>
u>
al_V Fraction on feed unless otherwise noted.
^Effective hydrogen yield available for hydrotreating.
-------
Table H-19 (continued). ALTERNATE YIELD DATA
High and Low severity Reforming of SR Naphtha
95 RON Severity
Stream*
Light feed (160-200°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
95 Reformats
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 pressure (450 psi)
Louisiana
.84
.0488
.077
.0334
.0494
.76
1.06
.0275
.0375
.0172
.0243
.847
1.095
.0228
.029
.0138
.0188
.868
West Texas
Sour
.825
.0525
.0845
.0365
.0542
.745
1.02
.0325
.0468
.0208
.0302
£25
1.06
.0275
.038
.0174
.0245
.847
Nigerian
F oread os
1.095
,0228
.029
.0134
.0188
.868
1.085
.0247
.0322
.0152
.021
.86
17T3
.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
Venezuelan
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
.276
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
Venezuelan
Tia Juana
1.275
.0262
.0475
.0193
.0283
.812
1.33
.0186
.0365
.0146
.0212
.841
1.35
.0155
.0298
.0122
.0175
.858
UJ
aLV Fraction on feed unless otherwise noted.
bEffective hydrogen yield available for hydrotreating.
-------
Table H-19 (continued). ALTERNATE YIELD DATA
High and Low Severity Reforming of SR Naphtha
100 RON Severity
Stream8
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
1 00 Reformate
Heavy feed (340-375°)
Hydrogen (MSCF)b
Ethane/methane (FOE)
Propane
Isobutane
Normal butane
100 Reformate
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
f
u>
U1
aLV 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
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 (FOEl
Propane
Isobutane
Normal butane
100 Reformate
High pressure (450 psi)
Heavy hydrocracked
naphtha
Strait run
gas oil feed**
1.05
.0147
.0175
.0083
.0105
.9050
1.095
.0228
.029
.0138
.0188
.8680
1.17
.037
.047
.0206
.03
.8210
Cracked gas
oil feed
1.045
.0165
.0203
.0095
.012
398
1.085
.0247
.0322
.0152
.021
.86
1.13
.0385
.0505
.021
.032
.813
Medium
Coker naphtha
1.02
.0185
.025
.0114
.0158
.8860
1.06
.0275
.0375
.0172
.0243
.8470
1.105
.0406
.056
.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
.9310
1.366
.0110
.0185
.0079
.0115
3915
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
335
Heavy
Cat. naphtha
1.24
.0055
.0098
.0043
.0064
.917
1.36
.0128
.0231
.0097
.014
.877
1.475
.0211
.042
.0142
.0243
.835
33
aLV Fraction on feed unless otherwise noted.
bEffective hydrogen yield available for hydrotreating.
°lncludes atmospheric gas oils and vacuum overhead.
-------
Table H-21. OPERATING COST CONSUMPTIONS
Reforming
(per Bbi intake)
90 Severity
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
95 Severity
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
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
J5
.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.8
.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
UJ
Grassroots.
-------
Table H-22. OPERATING COST CONSUMPTIONS
Catalytic Cracking
(per Bbl intake)
Maintenance {$)
Labor (shift positions)
Catalyst & chemicals ($)
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
I
Srf^i
os
aHigh severity catalytic cracking of hydrotreated feed is not used in the cluster models.
-------
Table H 23. OPERATING COST CONSUMPTIONS
Hydrocracking
(Per Bbl intake)
High severity hydrocracking
Maintenance (S)
Labor (shift
positions)
Catalyst &
chemicals ($)
Electricity
(KWH)
Steam (Mlbs)
Cooling water
(Mgal)
Refinery Fuel
(FOE)
Heavy gas oil feed
Clusters
.075
.00008
.10
10:0
.015
.7
.03
East
Grassroots
(sour crude)
.079
.00008
.105
10.0
.015
.5
.03
West and
East
Grassroots
(sweet crude)
.075
.00008
.10
10.0
.015
.5
.03
Vacuum gas oil feed
Clusters
.075
.00008
.10
10.0
.015
^
.03
East
Grassroots
(sour crude)
.079
.00008
.105
10.0
.015
.5
.03
West and
East
Grassroots
(sweet crude)
.075
.00008
.10
10.0
.015
.5
.03
Cracked gas oil feed
Clusters
.075
.00008
.10
10.0
.015
.7
.03
East
Grassroots
(sour crude)
.079
.00008
.126
10.0
.015
.5
.03
West and
East
Grassroots
(sweet crude)
.075
.00008
.10
10.0
.015
.5
.03
Medium severity hydrocracking
All gas oil feeds
Clusters
.077
.00008
.10
9.0
.0145
.68
.028
Grassroots
.077
.00008
.10
9.0
.0145
.48
.028
HJ
-------
Table H-24. OPERATING COST CONSUMPTIONS
Desulfurization3
(per Bbl intake)
Maintenance ($)
Labor (shift positions)
Catalyst + Chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
SR
Naphtha
.014
.0001
.013
1.0
.01
.3
.01
Light*
heavy
gas oil
.022
.00013
.015
1.2
.01
.4
.01
Vacuum
overhead
.025
.00008
.02
1.5
.01
.4
.01
Cat
naphtha
.014
.0001
.015
1.0
.01
.3
.01
Light*
medium
coker
naphtha
.014
.0001
.015
1.0
.01
.3
.01
Light
cycle
oil
.023
.00013
.017
1.3
.01
.4
.01
Atm Btms
to .5%
North
Slope
.048
.000075
.063
4.7
.01
.14
.012
Atin Btnts
to1%
Arabian
Light
.05
.000075
.065
6.2
.01
.17
.013
Atm Btms
to .5%
Arabian
Light
.054
.000075
.085
6.3
.01
.18
.013
Vac Btms
to .6%
North
Slope
.07
.0002
.13
8.7
.02
.22
.012
Vac Btms
to1%
Arabian
Light
.07
.0002
.13
8.7
.02
.22
.012
Vac Btms
to .6%
Arabian
Light
.076
.0002
.17
9.5
.02
.25
.012
aAII cluster and grass roots models.
-------
Table H-25. OPERATING COST CONSUMPTIONS
Miscellaneous Process Units3
(per Bbl intake)
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
Make-up water
Sulfur recovery units
95%
Recovery
.56
.028
6.0
80.0
4.0
.4
2.4
99.95%
Recovery
1.06
.028
7.6
346.0
3.93
.48
2.9
Isomerization
Once thru
.03
.0002
.085
2.4
.01
.3
.03
Recycle
.06
.0002
.12
4.8
.01
.3
.03
H Manufacture
Clusters
0.032
0.00014
0.005
0.17
0.001
0.1
0.031
Grassroots
0.032
0.00014
0.005
0.17
0.001
0.1
0.031
0.011
BC
Maintenance ($)
Labor (shift positions)
Catalyst and chemicals ($)
Electricity (KWH)
Steam (Mlbs)
Cooling water (Mgal)
Refinery fuel (FOE)
Coking
.086
.0002
.002
1.5
.03
.6
.03
Visbreaking
.0231
.0002
.0021
1.0
.02
.5
.03
Alkylation
.094
.0003
.2
3.7
.03
2.0
.1
Aromatics
extraction
.05
.004
.132
2.0
.4
.4
.005
Atmospheric
distillation
.008
.00002
.001
.25
.023
.5
.01
Vacuum
distillation
.009
.00005
.002
.20
.03
.20
.01
Crude and
products
handling
.032
.00008
.001
1.0
.02
.2
.01
a All models.
bConsumption per ton of sulfur recovered. Includes associated costs required to achieve specified recovery level.
cConsumption per MSCF of hydrogen product.
^Consumption per Bbl product.
-------
Table H-26. OPERATING COSTS COEFFICIENTS
Regional Supply Cost per Unit Coefficient
($ 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
waterb
(M gallons)
.35
.35
EC
**
NJ
aCluster models purchase cooling water.
bGrassroots models generate cooling water in a cooling tower which consumes purchased make-up water to
compensate for evaporation losses.
-------
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
Hyclrocracking (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
2608
25000
50000
a$/MSCF/SD
11-43
-------
Table H-28. OFFSITE AND OTHER ASSOCIATED COSTS OF REFINERIES USED IN ESTIMATING COST OF
GRASSROOTS REFINERIES
1st Quarter 1975 Basis
(% onsite cost)
Type 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-subtotai %
Associated costs
Chemicals and catalysts
Marine or equivalent facilities
Working capital
Other
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
f\r\ ft
" ZU.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 Hydrocracks for Middistillates",
Oil and Gas Journal July, 1974, pp. 102-110.
2. Anderson, R.F., "Changes Keep HF Alkylation Up-To-Date".0il and Gas Journal.
February, 1974, pp. 78-81.
3. "BP Adds Hydrocracklng 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
Jjournal, 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. HainsseHn, 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. "Hysotner 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: Off site 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 afe 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?", Oil 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. _Frpduct_ion oj Low . SM_lfur__qasoJ.ine, Contract// 68-02-1308, Task 10,
Phases 1, 2 , 3, can be obtained by writing to M.W. Kellogg Company,
1300 Tree Greanway Plaza East, Houston, Texas, 77046.
38. "1974 Refining Process Handbook", Hydrocarbon Processing, September, 1974,
pp. 107- 1.13, 116-119, 1.28-131, 26~7-208, 2ll-213.
39. Rose, K.K., "Delayed Coking - What You Should Know", Hydrocarbon Processing ,
.hi.ly, 1.971, pp. 85-92.
40. Stockey, A. Nelson, Richard F. Bauman, "Cyclic Powerforming Ups Octane",
, 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. ~~
^ ' H: S- Motor Gasoline E c onomi.cs, Volume 1, Manufacture of Unleaded Gasoline ,
American Petroleum Institute ,1967.
44. Waphtel, 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. Reichie, 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
I-i
-------
A. BASIC DATA FOR CALIBRATION
1. Refinery Input/Output
2. Processing Configurations
3. Product Data
I18
4. Calibration Economic Data
B . CALIBRATION RESULTS FOR CLUSTER MODELS
I_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 ....................................... J-8
TABLE 1-7. ADL Model Crude Slates and Sulfur Contents for
Refinery Clusters
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
I-ii
-------
LIST OF TABLES - (cont.)
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 Insults .... 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
I-iii
-------
LIST OF FIGURES - (cont.)
Page
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
I-iv
-------
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 INHT /OUTPUT DATA FOR CLUSTER MODELS: 1973
Mbils)
1. Crude oil (including lease condensatel
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
1 1 . 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
a. Petrochemical feedstock use
b. Refinery gas
17. Ethane and/or ethylene-
Petrochemical feedstock use
18. Propane and/or propylene
a. Petrochemical feedstock use
b. Other use
19. Butane and/or butylene
a. Petrochemical feestock use
b. Other use
" 20. 'Butane-propane mixtures
a. Petrochemical feedstock use
b. Other use
21. Isobutane IC4 - Petrochemical feed-
stock use
22. Naphtha-less than 400° 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
Louisia
Input
238,199
3.112
2.109
6.685
5,875
664
4.683
-
_
3.561
10,823
275,71 1
na Gulf
Output
7.202
130,006
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 Small Midcantinent
Input flutniit Innn* An*mit
317,931
40.662
_
2.334
2,246
_
_
13,849
16,092
31
4,626
9,789
407,660
49,999
10,733
1.028
340
_
4,798
1.226
12,242
178.081
_.
1,499
3.270
7.231
3,009 i
25,115
8,429
88,491
17,170
1.470
3,500
12.532 !
1.536 ;
30 ;
236
284
4.380 I
4.972
-
776
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
765
40,991
_
7
472
911
38
17,374
252
111
84
175
1.878 '
_
_
_
1.430
1.184
-
70
1.974
520
653
1.578
-
8
-
1
1,535
185
84
132
72.510
Large Midwest
Inruif flu******
128,062
30,247
4,050
108
915
_
E,ol1
5,650
174,543
3,464
89,467
_
2.248
143
2,297
1,813
44,678
8,094
_
-
-
2,013
_
_
4,024
3,301
2.154
_
6,860
_
-
3.483
-
6
-
-
1,025
-
427
46
174,543
West Coast
Input
106,057
69,597
2
570
93
47
1,422
'
935
8,257
11.229
198,333
wuipui
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
1- n -
nput
47,340
157,890
383
1 957
1 ,*Ht I
63
one
*wD
432
25.0338
731
6,965
240,970
uutput
114,904
13
1.730
5,956
3,711
49318
14.053
323
1,488
3,263
19,856
44
289
_
_
2.528
_
883
7,433
58
3,083
7,369
1,441
_
_
_
_
1,485
29
1,213
240,970
"Includes the following unfinished oils: alkylation feed, 293; reformer feed, 3324; cat. cracker feed, 12,496; slack wax, 692; slop oil, 340; mineral oil. 395; hydrogen, 13; polymerization feed. 651; toluen,., 524; alkylan, 106;
and 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
T.-3
-------
Table 1-3. BUREAU OF MINES REFINERY FUEL CONSUMPTION FOR CLUSTER MODELS 1973"
Commodity
A. Fuel (purchased and produced at refinery):
1 } Crude oil used as fuel
2) Fuel oils:
a) Distiltete-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
uriidcontinent
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
576,702
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
I
IS
alncludes consumption for three refineries for the calendar year 1973.
bSee table I-4 for FOE conversion factors.
-------
Table 1-4. BUREAU OF MINES REFINERY FUEL
CONSUMPTION FOR CLUSTER MODELS 1973s
(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. 78 10 per short ton
-
) 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
I
u>
a Includes consumption for three refineries for the year 1973.
bOne 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 KPA 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-l»
is presented in MB/CD for the "average" single refinery operation represent-
ing the cluster. In undertaking the calibration efcort, all product demands
and non-crude inputs to the model were fixed. The model 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
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
1T8.79
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%of7(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) + 2(g)
1-8
-------
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 averaged by che 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. Wilmington 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 Medium 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 be 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 average*5
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
aBased on weighted average of sulfur content of crudes in model runs (Appendix H).
bReference - transmitted to ADL by EPA on 1-22-75.
-------
N>
Table 1-8. TEXAS GULF CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity, Bbls/CD
Vacuum dist.
Thermal
-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
Exxon
B&ytown,
Texas
400,000
420.000
180,000
124,000
88,000
20,000
48,000
90,000
15,000
41,000
109,000
8,500C
26,000
Arom/isom !
-BTX
-HDA i
Cyclohex
-C4 Feed
-C5Feed
C5/C6 Feed
Lubes
Asphalt
Coke tons/day
25,000
12,000
Unit capacity8, 1974
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
3C,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
H^B^^^^^^^ ^^^^^^^^^^^
a K
Unit c?oacrty ~
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
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
p^M^~^B^^q^^^a*^HH»
Model
limit
MB/SO
114.8
82.3
21.3
38.5
18.1
46.2
20.8
2.4
aBbls/SD unless otherwise noted.
Used for clu^er model.
cSolvents.
Reference: Oil and Gas Jour":!, April 2, 1973.
Oil and Gas Journal, April 1,1974.
-------
Table 1-9. LOUISIANA GULF CLUSTER PROCESSING CONFIGURATION
Unit type
Crude capacity, Bbls/CD
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 /arom sat
-S.R. distill.
- Lubes
Other dist.
Other
Alkylation
Arom/isom
-BTX
-HDA
Cyclohex
-C4Feed
-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
Noreo.
La.
240,000
250,000
90,000
18,000
95.000
41,500
28,000
25.000
26.000
14,100
6,000
900
Cftop
LChas.,
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.QOO
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
1300
3,333
2,000
878
Unit capacity3'*
19737
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
Bbls/SD unless otherwise noted.
Used in cluster model.
Reference: OH and Gas Journal, April 2, 1973.
Oil and Gas Journal, April 1, 1974.
-------
Table 1-10. LARGE MIDWEST CLUSTER PROCESS CONFIGURATION
Unit lypa
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
-C4Feed
-CSFeed
-C5/C6 Feed
Lubes
Asphalt
Coke tons/day
Mobil
Joliet.
III.
175,000
186,000
82,000
28,000
66,000
46,200
69,000
67,000
22,000
1,700
Unit opacity*, 1974
Union
Lemorrt,
III.
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.,
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
Lemont,
III.
140,000
N.R.
55,000
~19.~600
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
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
35,000
1,333
1,767
2,333
18,000
12,333
13,333
1,067
3,467
900
Unit capacity"'1*
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/SD
55.0
32.7
22.7
20.0
13.5
M
I
aBbls/SD unless otherwise noted.
btlsed for cluster model.
cBenzene concentrate.
Reference: Oil and Gas Jourr.zl, Apr ii 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 capacity*, 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
97,833
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 capacity9, 1973
SkeHy
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
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
5,000C
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 capacity3'6
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
Model
limit
MB/SO
22.8
15.5
1.7
5.3
1.8
aBbls/SD unless otherwise noted.
bUsed for cluster model.
clsom 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 typa
Crude capacity. Bblt/CO
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
-C4Feed
-CSFeed
-CS/C6 Feed
Lubes
Asphalt
Coke tons/day
Unit capacity*, 1974
Mobil
Torrance,
Calif.
123.500
130.000
95.000
16.000
46.640
56,000
36.000
18,000
23,000
15.000
25.000
Aroo
Canon.
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
10,500 ! 7,200
2.800
2,490
1,800
Socal
ElSagundo.
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
7,867
830
500
2,767
2,267
Unit capacity", 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
Areo
Canon,
Calif.
165,000
173,000
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
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"'1"
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
1.6
_
Model
limit
MB/SO
51.6
43.3
27.8
27.0
8.0
7.8
aBbls/SD unless otherwise noted.
bUsed for cluster model
cJet fuel.
Reference: Oil and Gas Journal, April 2, 1973.
Oil and Gas Journal. April 1, 1974.
-------
Table 1-13. EAST COAST CLUSTE R PROCESSING CONFIGURATION
Unit typo
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
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 capacity3. 1974
Area
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
f%
10,000C
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 capacitya/b
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
5,667
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
aBbls/SD unless otherwise noted.
bUsed for cluster model.
cFurnace 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 OiL 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 runst
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 reasonable 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^/CA olefins, 16% propane and 2% each of iso
and normal butane.
1-18
-------
Table 1-14. CLUSTER MODEL GASOLINE PRODUCTION AND PROPERTIES -
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
W
60.0
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
MJdcontinent
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
I
H»
vo
aReference: transmitted to ADL by EPA on 1-22-75
bNo entry indicates data not reported.
-------
Table 1-15. KEY PRODUCT SPECIF (CATIONS
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
Midcontinent
.78
.30
East
Coast
.78
.10
West
Coast
1.90
.17
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
1-21
-------
Full refinery operating costs were used for the optimization of the
calibration runs. Unit costs for all models included purchased electricity
at l.*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 new 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 operating 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 facilities.
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 interna1.
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 are shown
in Figures 1-1 through 1-6.
1-22
-------
Table 1-16. CLUSTER MODEL PROCESSING DATA8 - 1973
IMIt
Crude distillation
Atmospheric
MB/CD
MB/SO
Vacuum
MB/CD
MB/SD
Thermal Operations
Delayed coker
MB/CD
MB/SO
Catalytic Cracker
MB/CD
MB/SD
Conversion
Catalytic reformer
MB/CO
MB/SO
Severity, 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
91.2
86.2
80.7
83.4
71.5
Opera-
tion
61.6
95.9
to
-------
Table 1-16 (continued). CLUSTER MODEL PROCESSING DATA8 - 1973
Unit
Aromatic*
Cg isomerization
MB/CO
MB/SO
Benzene (HOA)
MB/CD
MB/SO
BTX reformer
MB/CD
MB/SD
UOEX
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
%
Utl-
lizad
85.2
73.0
Opera-
tion
Small Midcontinent
Unit
Cap*
ity
1.4
1.8
I
I
1.6
1.8
0.30
0.47
II
%
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
X
Uti-
lized
73.0
90.0
Opera-
tion
West Coast
Unit
Capac-
ity
%
Uti-
lized
Opera-
tion
Reference: transmitted to AOL by EPA on 1-25-75.
a. MB/CD data supplied by industry to EPA.
-------
I
N5
PURO4NSCO
CO&OUHK.
OS TO ZOO*F
At. O3 PREMIUM ,._
WORWAT& 25.*
18.53 JET FUEL
6S Hi^ocRRXMia
&7.6O DISDUATB
ATMO&. BOTTON^S .34.
VACUUM OVHO
<&5O-RKT\OM
(MB/CD) JPlOO>7S-l
Figure 1-1
-------
(9.O9 Cs TO \
TO PETROCHEM\CAL*
l&.feS RESIDUAL FUEL 01U
DESULPORI7.ED VOH
VAC. BOTTOMS 17.M,
1. 4O A5PHA.LT
M6CXCOKER
NAPHTHA
4,OO (2O.OTONS) COKE
ZZO.45 ELEMENTAL SUtRJR
19.63 SOX PROM FC.C
2.13 PURCHASED IC4
Ai-KVUATION
2O.I7 &OX%>ULFU« RECOVCRV
t*
62.71 &OK7VRFIMERY FUtL
Z.OS PORCHAS«> MC4. ^
13.45
SOX
TEXAS GULF CLUSTER MODEL CALIBRAT\ON
(MB/CD) JP> \o775-t
Figure 1-2
- 01,08,09
-------
REFORMER P66O FROM TRANS* CR
CAT. PESO PUOM
Figure 1-3
-------
16.SO PREMIUM
U&HT
-------
3.99 UPQ»
REFMIRV 6*E> TO
I
to
VO
WEST CQASTCLUSTER MODEL CALIBRATION
(MB/CD)
JPI 10*75-2.
Figure 1-5
-------
I
U>
O
VACUUM OVHO
10*0*^ -
II.IO FROM
TRANSFER.
.35
.74
tl.lO
8.T& SCKfteLPUR RKOMMY
EAST CO^VT CLUSTER MODEL CALIBRATION
CM6/CD).
JPIIOS75-Z
Figure 1-
160G&-OI ,06,09
-------
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 obtained 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)0
Electricity MKWH/CD
Processing summary
Catalytic reforming
Catalytic cracking-
Alkylation
Hydrocracking
Coking
intake
severity RON
intake
conversion % vol.
production
intake
intake
Oil and Gas
capacity MB/SO
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)3
Material balances
Total crude intake
Energy consumption
Purchased natural gas (FOE)
Tptal fuel consumption (FOE)D
Electricity MKWH/CD
Processing summary
Catalytic reforming
Catalytic cracking
Alkylation
Hydrocracking
Coking
Isomerization
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
ai(MB/CD) unless otherwise noted.
Excludes catalyst coke.
1-33
-------
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)D
Electricity MKWH/CD
Processing summary
Catalytic reforming.
Catalytic cracking
Alkylation
Coking
intake
severity RON
intake
conversion % vol.
production
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
8 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 intake
severity RON
Catalytic cracking intake
conversion % vol.
Alkylation production
Coking intake
Isomerization intake
Oil and Gas
capacity MB/SD
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
-
a MB/CD unlesss otherwise noted.
"Excludes catalyst coke.
1-35
-------
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
Catalytic cracking-
Alkylation
Hydrocracking
Coking
intake
severity RON
intake
conversion % vol.
production
intake
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)'3
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
3MB/CD unless otherwise noted.
^Excludes catalyst coke
1-37
-------
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,
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 n 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
Oesulf. 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
I
UJ
-------
Table 1-24. TEXAS GULF CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
90 RON reformate
Cat cracker gasoline
Normal butane
Atkylate
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
4N
o
-------
Table 1-25. SMALL MIDCONTINENT CALIBRATION
Gasoline Blending Summary
Stream/Quality
Component stream
90 RON reformate
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 Mend 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
Alky late
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 component!, MB/CO
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
ro
-------
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
*>
u»
-------
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
WON clear
Lead addition gm/gal
Gasoline Mend 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
dh _ _
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
-------
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 chanced for the West Coast.
1-45
-------
APPENDIX J
STUDY RESULTS
J-i
-------
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 Reducing Refinery SO Emissions -
1977 .................................... ? ............... J-5
TABLE J-2. Economic Penalty for Reducing Refinery SO Emissions -
1985 ................................ , . . .x ............... J-6
TABLE J-3. Energy Penalty for Reducing Refinery SO Emissions -
1977 .................................. ? ................. J-7
TABLE J-4. Energy Penalty for Reducing Refinery SO Emissions -
1985 .................................. ? ................. J-8
TABLE J-5. Capital Investment Requirements to Reduce Refinery
SO Emission Levels ..................................... J-9
x
TABLE J-6. Operating Costs Required to Reduce Refinery SO
Emission Levels .............................. x .......... J-10
TABLE J-7. Basis for Cluster Capital Investment Requirements ....... J-ll
TABLE J-8. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - East Coast ........................ J-12
TABLE J-9. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Large Midwest ..................... J-13
TABLE J-10. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Small Midcontinent ................ J-14
TABLE J-ll. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Louisiana Gulf .................... J-15
TABLE J-12. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Texas Gulf ........................ _
TABLE J-13. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - West Coast
J-ii
-------
LIST OF TABLES - (cont.)
Page
TABLE J-14. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
East of Rockies J~18
TABLE ,1-15. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
West of Rockies J~19
TABLE J-16. L.P. Model Results - Fixed Inputs and Outputs -
East Coast J-20
TABLE J-17. L.P. Model Results - Fixed Inputs and Outputs -
Large Midwest J-21
TABLE J-18. L.P. Model Results - Fixed Inputs and Outputs -
Small Midcontinent J-22
TABLE J-19. L.P. Model Results - Fixed Inputs and Outputs -
Louisiana Gulf J-23
TABLE J-20. L.P. Model Results - Fixed Inputs and Outputs -
Texas Gulf J-24
TABLE J-21. L.P. Model Results - Fixed Inputs and Outputs -
West Coast J-25
TABLE J-22. L.P. Model Results - Inputs and Fixed Outputs
Grassroots Refineries J-26
TABLE J-23. L.P. Model Results - Processing and Variable Outputs
East Coast Cluster J-27
TABLE J-24. L.P. Model Results - Processing and Variable Outputs -
Large Midwest Cluster J-28
TABLE J-25. L.P. Model Results - Processing and Variable Outputs
Small Midcontinent Cluster j-29
TABLE J-26. L.P. Model Results - Processing and Variable Outputs -
Louisiana Gulf Cluster j-30
TABLE J-27. L.P. Model Results - Processing and Variable Outputs -
Texas Gulf Cluster J-31
TABLE J-28. L.P. Model Results - Processing and Variable Outputs -
West Coast Cluster J-32
TABLE J-29. L.P. Model Results - Processing and Variable Outputs -
Grassroots Refineries, 1985 J-33
TABLE J-30. L.P. Model Results Summary - Gasoline Blending -
East Coast J-34
J-iii
-------
LIST OF TABLES - (cont.)
Page
TABLE J-31. L.P. Model Results - Gasoline Blending - East Coast J-35
TABLE J-32. L.P. Model Results - Gasoline Blending - Large Midwest . J-36
TABLE J-33. L.P. Model Results - Gasoline Blending - Large Midwest . J-37
TABLE J-34. L.P. Model Results Summary - Gasoline Blending -
Small Midcontinent J-38
TABLE J-35. L.P. Model Results - Gasoline Blending -
Small Midcontinent J-39
TABLE J-36. L.P. Model Results Summary - Gasoline Blending -
Louisiana Gulf J-40
TABLE J-37. L.P. Model Results - Gasoline Blending - Louisiana Gulf J-41
TABLE J-38. L.P. Model Results Summary - Gasoline Blending -
Texas Gulf J-42
TABLE J-39. L.P. Model Results Summary - Gasoline Blending -
Texas Gulf J-43
TABLE J-40. L.P. Model Results Summary - Gasoline Blending -
West Coast J-44
TABLE J-41. L.P. Model Results - Gasoline Blending - West Coast .... J-45
TABLE J-42. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries J-46
TABLE J-43. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries J-47
TABLE J-44. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1977 J-48
TABLE J-45. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1985 J-49
TABLE J-46. L.P. Model Results - Refinery Fuel Sulfur Levels -
1977 J-50
TABLE J-47. L.P. Model Results - Refinery Fuel Sulfur Levels -
1985 J-51
J-iv
-------
LIST OF TABLES - (cont.)
TABLE J-48. Sample Calculations for Mass and Sulfur Balance Page
Texas Gulf 1985, Scenario B/C - Stream Values -
Gas Oil 375-650°F J-53
TABLE J-49. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 B/C - Desulfurization of
Light Gas Oil J-54
TABLE J-50. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Feed Sulfur Levels ... J-55
TABLE J-51. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Stream Qualities -
Cluster-Specific Streams J-56
s
TABLE J-52. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 Scenario B/C - Stream Qualities -
Cluster-Specific Streams ..., J-57
TABLE J-53. Specific Gravities for Miscellaneous Streams J-58
TABLE J-54. Mass and Sulfur Balance - Texas Gulf Cluster 1985
Scenario B/C J-59
TABLE J-55. Mass and Sulfur Balance - Texas Gulf Cluster 1985
Scenario F J-67
LIST OF FIGURES
FIGURE J-l. Texas Gulf Cluster 1985 Sulfur and Material Balance
J-52
J-v
-------
APPENDIX J
STUDY RESULTS
This appendix gives a detailed summary of the results of this study.
Tables J-l through J-4 give the economic and energy penalties for the
total U.S. refining industry for the reduction of refinery sulfur oxides
emissions. 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 econ-
omic penalties are given in Tables J-5 and J-6. Table J-7 provides exis-
ting capacity and calibration utilization of capacity for reforming, hydro-
cracking, 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-8 through J-47. Capital
investments and operating costs for the LP model runs are given in Tables
J-8 through J-15. Crude slates and other Inputs, product outputs, and
process unit throughput and severities are given in Tables J-16 through
J-29. Gasoline blends are given in Tables J-30 through J-43. The volumes
of refinery fuel consumed and the amount of residual fuel oil produced,
together with their sulfur levels are given in Tables J-44 through J-47.
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
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.
J-l
-------
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 Tables J-54 and J-55 were 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 illus-
trate the method of calculation, but are not indicative of the actual mass
balances in the simulation.
Figure J-l and Tables J-54 and J-55 detail the hydrocarbon and sulfur
flows by individual process units for the Texas Gulf cluster, with num-
bered arrows on the flowsheet corresponding to stream numbers and stream
names listed on the tables. Table J-54 gives volume, mass, and sulfur
flows for Scenario B/C and Table J-55 for Scenario F. Refinery streams of
C. and lighter, as well as gases, such as H_S and SO , are grouped in
*f £ 3C
verticle output arrows on the flowsheet and in 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-23 through J-29), yield on crude or
process yields, hydrogen consumption, sulfur removal in desulfurization
and stream qualities (Appendix H).
For example, arrow #5 on Figure J-l 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-48. 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
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-speci-
fic streams are calculated in a similar manner with the exception of
J-2
-------
refornate 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 Csee Table J-49).
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-50 shows assumed feed sulfur levels for the cataly-
tic cracker, visbreaker/coker and hydrocracker. Table J-51 distributes
this feed sulfur among the process output streams and lists the stream
qualities and output of H,S and SO .
£* X
The cluster models allow greater flexibility 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
J-3
-------
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 similiar 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-53.
J-4
-------
Table J-1. ECONOMIC PENALTY FOR REDUCING REFINERY SOx EMISSIONS3 - 1977
Scenario F Versus Scenario C
Basis
Cumulative capital investment
required millions $
Additional crude oil processed
MB/CO
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 @ $1 0/ton
Total penalty
Total products MB/CO
Penalty $/B of total
products3
Penalty 4/G of total
products3
East
Coast
397.1
1.0
(3.4)
272
65
13
30
(6)
1685
Large
Midwest
1016.7
5.0
1.4
696
140
63
(12)
(3)
2630
Small
Midcontinent
414.9
22.3
2.6
284
30
279
(23)
(1)
1026
Louisiana
Gulf
304.3
15.9
2.5
208
31
199
(22)
(1)
1820
Texas
Gulf
598.8
_
(4.3)
410
73
38
(5)
3873
East of
Rockies
Grassroots
_
_
-
_
-
-
Subtot&l
PAD)- IV
2731.8
44.2
-
1870
339
554
11
(16)
2758
11034
0.25
0.60
West
Coast
388.8
0.4
.
(0.5)
266
54
5
4
(3)
2361
West of
Rockies
Grassroots
-
-
Subtotal
PAOV
388.8
0.4
(0.5)
266
54
5
4
(3)
326
2361
0.14
0.33
Total
U.S.A.
3120.6
44.6
(1.7)
2136
393
559
15
(19)
3084
13395
0.23
0.55
Based on cumulative capital investment.
-------
Table J-2. ECONOMIC PENALTY FOR REDUCING REFINERY SOx EMISSIONS' - 1985
Scenario F Versus Scenario C
Basis
Cumulative capital investment
required millions $
Additional crude oil processed
MB/CD
Additional LPG produced
MB/CD
Penalties
Thousands dollars par day
Capital charge (25%)a
Operating costs
Crude oil @ $12.5/8
LPG @ $8.75/B
Sulfur @$10/ton
Total penalty
Total products MB/CD
Penalty $/B of total
products
Penalty
-------
Table J-3. ENERGY PENALTY FOR REDUCING REFINERY SOX EMISSIONS - 1977
Scenario F Versus Scenario C
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
1.0
<3.4)
1292
6
14
13
Large
Midwest
5.0
1.4
1594
28
(5)
16
Small
Midcontinent
22.3
2.6
443
125
(10)
4
Louisiana
Gulf
15.9
2.5
524
89
(10)
5
Texas
Gulf
_
(4.3)
1294
_
17
13
West
Coast
0.4
(0.5)
1199
2
2
12
Total
U.S. A.
44.6
(1.7)
6346
250
8
63
321
51.0
-------
Table J-4. ENERGY PENALTY FOR REDUCING REFINERY SOX EMISSIONS - 1985
Scenario F Versus Scenario C
Basis
Additional crude oil processed
MB/CO
Additional LPG produced
MB/CO
Additional purchased power
required MKWH/CD
109 BTU/CO
Crude oil
LPG
Purchased power
Total penalty 109 BTU/CD
Thousands barrels of fuel oil
equivalent per calendar day
East
Coast
(4.0)
1134
16
11
Large
Midwest
3.2
1831
(13)
18
Small
Mideontinent
(1.6)
442
_
6
4
Louisiana
Gulf
_
(32.6)
484
_
131
5
Texas
Gulf
(3.8)
1783
_
15
18
East of
Rockies
Grassroots
47.4
2217
265
23
Subtotal
PAD 1- IV
47.4
(38.8)
7891
265
155
79
499
79.2
West
Coast
(0.5)
900
_
2
9
West of
Rockies
Grassroots
15.2
-
1324
85
-
13
Subtotal
PADV
15.2
(0.5)
2224
85
2
22
109
17.3
Total
U.S. A.
62.6
(39.3)
10115
350
157
101
608
96.5
I
CD
-------
Table J-5. CAPITAL INVESTMENT REQUIREMENTS TO REDUCE REFINERY SOX EMISSION LEVELS
Million $ 1st Quarter 1975
Cluster
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
West Grassroots
East Grassroots
Total
Scenario F versus C
Cluster investment
1977
43.7
47.1
21.2
32.6
45.3
24.2
1985
4.3
(2.3)
(3.5)
0.8
20.3
2.2
Total
48.0
44.8
17.7
33.4
65.6
26.4
Scaled up investment
1977
397.1
1,016.7
414.9
304.3
598.8
388.8
-
-
3,120.6
1985
38.3
(48.8)
(67.2)
7.4
262.9
31.4
274.9
873.9
1,372.8
Total
435.4
967.9
347.7
311.7
861.7
420.2
274.9
873.9
4,493.4
Sox emission levels 1985
Short tons per day
Cluster levels
before after
control control
59
73
24
24
92
47
55
89
14
14
6
3
35
13
19
16
Scaled up levels
before after percent
control control reduction
449
1,323
393
188
1,019
572
165
1,335
5,444
107
254
98
23
387
158
57
240
1,324
76
81
75
88
62
72
65
82
76
-------
Table J 6. OPERATING COSTS REQUIRED TO REDUCE REFINERY
SOX EMISSION LEVELS
(thousands $ per day)
Cluster
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
West Grassroots
East Grassroots
Total
Scenario F versus C
Cluster operating cost
1977 1985
8.4
7.6
1.8
3.9
6.5
3.9
8.1
6.3
1.5
4.8
8.7
4.1
22.1
8.2
Scaled up operating cost
1977 1985
64.8
139.6
29.9
30.9
72.9
53.5
391.6
61.6
114.2
24.6
37.5
96.3
49.9
66.3
123.0
573.4
J-10
-------
Table J-7. 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
-
-------
Table J-8. LP. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
Cluster: East Coast
Capital investments (million dollars)
(1st CM 975 Basis)
Reforming: existing capacity
severity upgrade
new capacity
Hydrocracking: existing capacity
new capacity
Isomerization: once through upgrading
new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Cat cracker feed desulfurization: new capacity
Sulfur recovery
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: 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
^ _^ ^^ - - - -
Scenario: F
1977
1.6
12.9
4.5
1.1
1.7
1.2
1.4
0.3
21.9
4.6
51.2
20.5
71.7
84.4
5.7
20.2
16.8
31.4
54.0
8.6
17.4
154.1
1985
6.9
-
_
10.4
2.1
3.0
2.1
24.5
9.8
34.3
40.3
5.7
21.2
17.3
34.2
54.8
19.9
153.1
Total
1.6
19.8
4.5
1.1
1.7
_
11.6
3.5
3.3
24.0
4.6
75.7
30.3
106.0
124.7
C-l
I
-------
Table J-9. LP. 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
Cat cracker feed desulfurization: new capacity
Hydrogen manufacture: new capacity
Sulfur recovery
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: 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
Scenario: F
1977
0.1
13.7
0.7
-
15.3
3.3
4.4
37.5
15.0
52.5
61.8
11.4
11.7
24.5
39.3
7.6
11.7
106.2
1985
5.1
9.3
-
2.4
0.2
0.4
0.8
18.2
7.3
25.5
30.0
12.9
12.1
26.4
39.8
13.7
104.9
Total
0.1
13.7
5.8
9.3
-
2.4
15.5
3.7
5.2
55.7
22.3
78.0
91.8
I
H-
U>
-------
Table J-10. LP. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
Cluster: Small Midcontinent
Capital investments (million dollars)
(1stQ 1975 Basis)
Reforming: severity upgrade
new capacity
Isomerization: existing capacity
once through upgrading
new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Cat cracker feed desulfurization: new capacity
Sulfur recovery
Subtotals
Off sites 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
r ' !.- -^, . . -, - r mi _ir
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
. . , I.,
Scenario: F
1977
1.8
2.0
i
0.9
0.9
9.6
1.1
16.3
6.5
22.8
26.8
4.3
4.4
9.4
21.3
2.8
4.5
46.7
1985
8.3
0.1
0.6
5.3
-
1.5
0.6
0.3
16.7
6.7
23.4
27.5
4.9
4.7
10.8
21.7
5.6
47.7
Total
10.1
2.1
1.5
0.9
5.3
-
1.5
10.2
1.4
33.0
13.2
46.2
54.3
I
M
J^
-------
Table J 11. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
c_
I
M
Ui
Clutter : Louisiana Gulf
Capital investments (million dollars)
(1st Q 1975 Basis)
Reforming: existing capacity
severity upgrade
new capacity
Hydrocracking: existing capacity
severity change
new capacity
Isomerization: new capacity
Alkylation: existing capacity
Light naphtha desulfurization: new capacity
Cat cracker feed desulfurization: new capacity
Sulfur recovery
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: 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
Scenario: F
1977
4.0
2.6
2.0
1.6
1.2
0.5
-
-
_
14.7
1.8
28.4
11.4
39.8
46.8
12.5
16.5
30.7
44.3
11.5
13.4
128.9
1985
14.3
1.4
-
0.2
5.8
-
2.5
2.8
0.1
27.1
10.8
37.9
44.6
13.2
17.8
33.9
45.2
16.9
127.0
Total
4.0
16.9
3.4
1.6
1.2
0.7
5.8
2.5
17.5
1.9
55.5
22.2
77.7
91.4
-------
Table J-12. 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
Isomerization: existing capacity
once through upgrading
new capacity
Alkylation: new capacity
Light naphtha desulfurization: new capacity
Cat cracker feed desulfurization: new capacity
Sulfur recovery
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: 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
1.0
0.9
_
0.6
0.8
_
6.9
0.6
2.8
13.6
5.4
19.0
22.3
20.2
24.2
48.3
115.1
28.7
236.5
Scenario: F
Total
33.0
3.4
4.3
3.6
2.8
1.2
1.1
12.3
1.9
4.2
67.8
27.1
94.9
111.6
1977
23.6
-
1.1
3.7
-
1.2
1.1
2.6
0.4
0.7
32.6
5.8
72.8
29.1
101.9
119.9
21.3
24.9
50.7
115.8
15.9
26.4
255.0
1985
9.4
2.7
3.2
0.6
2.3
12.8
-
3.8
34.8
13.9
48.7
57.3
22.5
24.8
52.9
116.5
28.5
245.2
Total
33.0
2.7
4.3
4.3
2.3
1.2
1.1
15.4
0.4
4.5
32.6
5.8
107.6
43.0
150.6
177.2
M
O^
-------
Table J-13. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS AND OPERATING COSTS
Cluster: West Coast
Capital investments (million dollars)
(IstQ 1975 Basis)
Reforming: severity upgrade
new capacity
Hydrocracking: existing capacity
new capacity
Isomerization: new capacity
Alkylation: existing capacity
new capacity
Light naphtha desulfurization: new capacity
Cat cracker feed desulfurization: new capacity
Sulfur recovery
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: 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
5.2
0.1
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
Total
13.8
0.9
1.6
4.1
4.8
1.5
2.2
1.6
-
30.5
12.2
42.7
50.2
Scenario: F
1977
5.0
1.5
1.6
4.1
-
1.5
1.1
9.4
5.5
29.7
11.9
41.6
48.9
17.1
12.3
29.6
71.0
6.9
15.4
152.3
1985
7.5
4.3
1.1
1.4
2.6
16.9
6.7
23.6
27.8
17.5
12.8
31.2
71.5
16.9
149.9
Total
12.5
1.5
1.6
4.1
4.3
1.5
2.2
1.4
12.0
5.5
46.6
18.6
65.2
76.7
I
M
-vl
-------
Table J-14. L.P. MODEL RESULTS: - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
Cluster: Grassroots Refinery East of Rockies
Total capital investment (million dollars)
(1stQ 1975 basis)
Operating costs (thousands dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Catalysts and chemicals
Total
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
Scenario F
sweet
678.5
17.1
4.3
30.1
23.3
13.8
88.6
sour
865.2
26.7
5.2
38.7
35.5
22.7
128.8
J-18
-------
Table J-15. L.P. MODEL RESULTS - CAPITAL INVESTMENT REQUIREMENTS
AND OPERATING COSTS
duster: Grassroots Refinery - West of Rockies
Total capital investment (million dollars)
dstQ 1975 basis)
Operating costs (thousands dollars per day)
Electricity
Cooling water
Maintenance
Manpower
Catalysts and chemicals
Total
Scenario C
764.5
23.1
5.1
33.0
33.4
19.6
114.2
Scenario F
848.8
31.3
5.6
39.0
35.1
25.3
136.3
J-19
-------
Table J-16. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Clutter: 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
13.368
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-20
-------
Table J-17. 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-21
-------
Table J-18. LP. 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-22
-------
Table J-19. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Clutter: 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-23
-------
Table J-20. |_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
Iso 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
|
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-24
-------
Table J-21. L.P. MODEL RESULTS - FIXED INPUTS AND OUTPUTS
(MB/CD)
Cluster: West Coast
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-25
-------
Table J-22. L.P. MODEL RESULTS: - INPUTS AND FIXED OUTPUTS
Grassroots Refineries
(MB/CD)
Inputs
Scenario
C
F
Fixed outputs
Jet fuel
Kerosine
Number 2 heating oil
Residual fuel oil
Total
East of Rockies
Sour crude refinery
Arabian Light
crude oil
196.978
199.822
Sweet crude refinery
Nigerian Algerian
crude oil crude oil
96.768
98.291
East of Rockies
9.700
2.900
46.900
32.900
92.400
96.768
98.291
West" of Rockies
Alaska North Slope
crude oil
.
206.277
210.944
West of Rockies
31.200
30.900
45.500
107.600
J-26
-------
Table J-23. 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
Cat cracker feed
Straight run distillate
Total
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
Scenario F
1977
108.987
5.140
185
13
47.8
44.3
97.3
62.2
62.2
72.5
4.1
6.1
10.2
0.1
0.9
1.0
9.0
24.2
1.0
38.2
-
62.5
31.4
133.1
1985
107.447
5.592
185
14
46.6
43.1
100.0
68.1
68.1
72.5
0.1
9.4
9.5
2.2
8.2
10.4
10.5
17.9
10.4
41.7
-
68.5
17.4
138.0
J-27
-------
Table J-24. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Large Midwest Clutter
~
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
Atkylation (product basis)
Coking
Hydrogen manufacturing (MMSCF/CD)
Desulfurization
Light naphtha (isom. feed)
: Medium naphtha (ref. feed)
Medium coker naphtha (ref. feed)
Cat cracker cycle oil
Cat cracker feed
Straight run distillate
Total
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
29.1
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 F
1977
77.040
3.415
174
13
28.7
26.4
100.0
43.6
43.6
72.5
_
-
11.4
-
14.2
_
28.1
2.3
_
43.8
20.1
94.3
1985
74.830
4.236
204
14
35.4
33.1
100.0
41.4
41.4
72.5
_
7.5
7.5
10.9
-
15.4
7.5
34.2
2.3
44.4
24.0
112.4
J-28
-------
Table J-25. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Small Midcontinent Clutter
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
Cat cracker feed
Straight run distillate
Total
" INI'- .!..,! .. -_.lll..» .Ill, _ I.I. |l ^
Scenario C
1977
36.732
1.454
14
21
14.7
10.4
90.7
17.7
17.7
85
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
1.6
1.6
5.1
4.0
1.6
13.3
0.7
0.3
-
0.8
16.7
1985
34.016
1.720
19
24
14.2
9.9
100
18.9
18.9
85
1.4
3.2
4.6
5.4
3.4
4.6
13.5
0.6
2.4
-
21.1
LUIIL _ J Ili Illl 1 _L / II
Scenario F
1977
35.541
1.552
21
5
14.6
10.3
92.6
18.1
18.1
72.5
-
0.9
0.9
3.8
4.2
0.9
13.9
0.7
18.2
-
33.7
1985
32.775
1.622
27
6
14.9
10.6
100.0
19.2
19.2
72.5
1.9
2.9
4.8
4.1
4.0
4.8
14.2
0.7
19.3
-
39.0
J-29
-------
Table J-26. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Louisiana Gulf Cluster
LO
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 %
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 feed
Straight run distillate
Total
-
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
.
8.8
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
m**m~~*i*~~mmmmmmmmmm~m**mmmm*mi**~^^mmmm
Scenario F
1977
116.558
3.831
71
2
37.2
37.2
94.1
68.1
68.1
72.5
5.1
3.5
8.6
15.3
15.5
18.8
29.9
2.9
68.4
4.9
106.1
1985
113.770
0.910
71
2
39.1
39.1
100.0
76.0
76.0
72.5
8.8
8.8
6.5
1.4
7.9
17.3
15.2
16.2
7.9
33.9
2.8
76.4
7.3
128.3
-------
Table J-27. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Texas Gulf Cluster
Variable output
Gasoline MB/CD
LPG MB/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing MB/CD
Reforming
Tetal
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
Cat cracker feed
Straight run distillate
Total
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
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 F
1977
161.288
6.919
233
25
68.1
48.2
98.2
93.2
93.2
72.5
-
15.6
15.6
0.3
3.8
4.1
18.1
15.2
29.3
4.1
50.4
2.8
93.2
6.9
157.8
1985
152.850
7.667
229
35
71.3
53.9
100.0
87.0
87.0
72.5
20.2
20.2
3.4
12.6
16.0
16.8
14.6
38.0
16.0
50.8
2.7
87.5
6.5
163.4
J-31
-------
Table J-28. 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
Cat cracker feed
Straight run distillate
Total
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
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 F
1977
69.609
3.997
221
10
38.8
23.0
96.3
26.7
26.7
72.9
i
_
27.4
27.4
_
_
-
7.4
4.1.2
51.5
_
25.2
7.7
26.8
14.9
74.6
1985
69.730
187
13
36.9
21.1
100.0
_
33.9
33.9
65.0
27.4
27.4
1.9
2.5
4.4
8.2
32.1
51.5
4.4
23.6
6.0
34.1
14.9
83.0
J-32
-------
Table J-29. L.P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
Grassroots Refineries, 1985
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
l-iigh severity
Medium severity
Total
Isomerization of light naphtha
Once through
Recycle
Total
Aklylation (product basis)
Coking
Hydrogen manufacture (MMSCF/CD)
Desulfurlzation
Full range naphtha
Medium coker naphtha
Cat cracker feed
Straight run distillate
Vacuum bottoms
Total
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 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 F
East of Rockies
-sour -sweet
93.4
365
22
47.8
47.8
96.8
42.5
42.5
72.5
10.3
16.2
26.5
10.4
10.4
10.3
-
64.9
54.2
-
42.7
23.0
15.4
135.3
93.4
__
18
12
52.1
52.1
97.2
35.2
35.2
72.5
5.3
4.7
10.0
1.7
8.3
10.0
8.5
-
19.4
59.4
-
35.4
6.8
101.6
West of
Rockies
90.8
207
19
43.6
43.6
99.8
27.2
27.2
95.0
14.8
42.2
57.0
2.1
-
2.1
9.5
4.3
111.3
38.8
0.8
27.3
18.2
26.3
111.4
J-33
-------
Table J-30. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: East Coast
Scenario
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)
Cat cracker gasoline (desulfurized feed)
Alky late
Light hydrocrackate
Isomerized light naphtha
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)
Cat cracker gasoline (desulfurized feed)
Alkylate
Straight run
Total
Year: 1977
C
94.9
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
F
95.3
85.9
16.35
1.70
46
10.6
26.8
29.6
32.5
0.5
100.0
87.9
79.1
58.85
1.27
84
2.4
6.8
18.2
2.3
_
46.7
6.2
17.4
100.0
J-34
-------
Table J-31. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: East Coast
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
BTX raffinate
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alky late
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
Year
1977
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
F
94.1
84.0
33.79
19
6.0
57.4
11.2
-
8.0
2.5
12.4
2.5
100.0
90.9
81.7
108.99
0.94
58
1985
C
93.8
84.0
106.91
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
F
93.9
84.0
107.45
57
0.1
7.2
_
30.9
36.8
9.8
2.0
9.1
3.9
0.2
100.0
93.9
84.0
107.45
-
57
J-35
-------
Table J-32. 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
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alky I ate
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)
Cat cracker gasoline (desulfurized feed)
Alkylate
Coker Gasoline
Straight run
Total
Year: 1977
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
F
94.7
85.8
3.85
1.19
48
10.1
19.9
30.7
37.9
1.4
100.0
87.2
78.3
48.54
1.40
237
1.9
2.6
__
20.5
_
28.9
17.9
6.2
22.0
100.0
J-36
-------
Table J-33. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Large Midwest
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alky late
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
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
F
95.6
84.0
24.65
60
8.5
42.8
40.8
5.3
-
-
2.6
100.0
90.3
80.5
77.04
0.94
171
1985
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
F
94.0
84.0
74.83
148
6.0
34.6
32.1
14.6
9.6
1.7
0.5
0.9
100.0
94.0
84.0
74.83
-
148
J-37
-------
Table J-34. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: Small Midoontinent
Scenarios
Premium pool
Research octane clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raff inate
Butanes
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alkylate
Coker Gasoline
Straight run
Total
Regular pool
Research octance clear
Motor octane clear
Volume MB/CD
Lead CC/USG
Sulfur PPM
Composition LV%
BTX raffinates
Butanes
90 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alkylate
Coker gasoline
Natural gasoline
Straight run
Total
Year: 1977
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
F
91.0
82.9
1.78
2.12
81
2.5
6.2
45.3
31.5
1.7
12.8
100.0
86.0
78.8
22.39
1.32
61
10.5
6.4
29.1
22.4
4.8
1.7
13.2
11.9
100.0
J-38
-------
Table J-35. 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 raffinate
Butanes
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized 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
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
F
92.9
84.0
11.37
49
8.3
17.1
-
39.6
19.2
7.7
5.3
2.8
100.0
88.4
80.6
35.54
0.94
58
1985
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
F
93.1
84.0
32.78
65
5.9
7.1
24.6
-
33.4
12.6
14.0
1.2
1.2
100.0
93.1
84.0
32.78
-
65
J-39
-------
Table J-36. L.P. MODEL RESULTS SUMMARY - 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 (desulfurized feed)
Alkylate
Total
Regular pool
Research octane clear
Motor octane clear
Volume MB/CO
Lead CC/USG
Sulfur PPM
Composition LV%
Butanes
90 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alkylate
Light hydrocrackate
Coker gasoline
Natural gasoline
Straight run
Total
Year: 1977
C
96.77
87.1
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
F
i
97.2
87.4
15.15
0.60
,- 4
10.2
53.7
"3.2
32.9
100.0
86.1
78.1
65.27
1.54
90
7.1
30.0
27.5
3.0
4.2
2.5
4.1
21.6
100.0
J-40
-------
Table J-37. L.P. MODEL RESULTS - GASOLINE BLENDING
Cluster: Louisiana
Scenarios
Lead-free pool
Research octane clear
Motor octane clear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized 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
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
F
94.0
84.0
36.14
76
9.3
10.9
55.9
23.2
-
-
-
0.7
\ -
100.0
90.0
81.1
116.56
0.94
74
1985
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
F
93.6
84.0
113.77
84
7.6
27.1
37.7
15.2
1.8
6.7
1.4
2.0
0.5
100.0
93.6
84.0
113.77
-
84
J-41
-------
Table J-38. L.P. MODEL RESULTS SUMMARY 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 raffinate
Butanes
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alkylate
Light hy drocrackate
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)
Cat cracker gasoline (desulfurized feed)
Alkylate
Coker gasoline
Straight run
Total
Year: 1977
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
F
91.4
83.1
20.97
2.24
35
14.6
8.8
42.1
21.3
12.4
.8
100.0
90.2
80.9
90.32
1.16
122
3.1
7.5
5.6
6.4
_
47.6
15.1
1.8
12.9
100.0
J-42
-------
Table J-39. L.P. MODEL RESULTS SUMMARY - 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 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alky late
Light hydrocrackate
Isomerised 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
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
F
93.3
84.0
50.00
8
6.3
57.6
4.4
-
2.0
7.8
-
21.9
100.0
91.3
82.1
161.29
0.94
75
1985
c
93.2
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
F
93.5
84.0
152.85
65
2.1
6.9
28.3
33.0
11.0
3.1
10.0
1.0
4.6
100.0
93.5
84.0
152.85
65
J-43
-------
Table J-40. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
Cluster: West Coast
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%
BTX raffinate
Butanes
90 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Light hydrocrackate
Coker gasoline
Straight run
Total
Year: 1977
C
92.7
83.5
15.32
1.63
1328
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
F
92.7
83.4
15.31
1.64
108
6.2
57.7
24.4
11.7
100.0
85.9
78.1
29.24
1.38
192
30.3
7.8
22.0
19.1
8.6
3.4
8.8
100.0
J-44
-------
Table J-41. 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
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized 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
- . .
Year
1977
C
92.1
84.0
25.07
171
.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
F
92.3
84.0
25.06
17
7.4
23.9
26.2
4.2
14.6
15.2
3.5
5.0
100.0
89.7
81.4
69.61
0.94
111
1985
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
F
93.2
84.0
69.73
47
10.4
7.5
25.0
28.1
11.7
9.1
6.1
-
2.1
100.0
93.2
84.0
69.73
47
J-45
-------
Table J-42. L.P. MODEL RESULTS SUMMARY - GASOLINE BLENDING
CH
Cluster: Grassroots Refineries
Scenarios
Lead free pool
Research octane clear
Motor octane dear
Volume MB/CD
Sulfur PPM
Composition LV%
Butanes
90 RON reformats
100 RON reformate
Cat cracker gasoline (untreated feed)
Cat cracker gasoline (desulfurized feed)
Alkylate
Light hydrocrackate
Isomerised light naphtha
Straight run
Total
East Coast
sweet crude
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
F
93.7
84.0
93.40
7
6.9
15.0
31.5
21.7
9.1
3.1
10.2
2.5
100.0
East Coast
sour crude
C
93.3
84.0
91.20
433
6.1
14.9
22.1
26.6
-
13.9
6.2
10.2
100.0
F
93.5
84.0
93.40
40
5.5
13.0
25.6
-
26.4
11.0
7.9
10.6
_
100.0
-------
Table J-43. L.P. MOPEL 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)
Cat cracker gasoline (desulfurized feed)
Alky I ate
Light hydrocrackate
Isomerised light naphtha
Coker gasoline
Straight run
Total
West Coast - Alaskan
North Slope crude
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
F
93.3
84.0
90.80
31
4.7
0.7
38.7
-
20.0
10.4
16.6
2.2
0.5
6.2
100.0
J-47
-------
f-,
I
Table J-44. L.P. MODEL RESULTS: - RESIDUAL FUEL OIL SULFUR LEVELS - 1977
Scenario
C
F
Cluster
East
Coast
MB/CD
13.37
13.37
WT%S
2.0
1.3
Large
Midwest
MB/CD
7.26
7.26
WT%S
0.48
0.94
Small
Midcont
MB/CD
0.23
0.23
WT%S
0.33
0.23
Louisiana
Gulf
MB/CD
5.19
5.19
WT%S
0.60
0.11
Texas
Gulf
MB/CO
15.321
15.321
WT%S
1.43
1.29
West
Coast
MB/CD
31.89
31.89
WT%S
0.12
0.43
00
-------
Table J-45. L.P. MODEL RESULTS: - RESIDUAL FUEL OIL SULFUR LEVELS - 1985
Scenario
C
F
Cluster
East
Coast
MB/CD
13.234
13.234
WT
%S
1.8
1.03
Large
Midwest
MB/CD
7.21
7.21
WT
%S
.98
1.13
Small
Midcont
MB/CD
0.215
0.215
WT
%S
.33
.45
Louisiana
Gulf
MB/CD
5.032
5.032
WT
%S
.61
.30
Texas
Gulf
MB/CO
14.714
14.714
WT
%S
1.22
1.42
West
Coast
MB/CD
31.28
31.28
WT
%S
.69
.87
East of Rockies
Grassroots
Sweet Crude Sour Crude
MB/CD
32.9
32.9
WT
%S
0.41
0.36
MB/CD
32.9
32.9
WT
%S
1.97
2.12
West of Rockies
Grassroots
MB/CD
45.5
45.5
WT
%S
1.63
1.16
*>
vo
-------
Table J-46. LP. MODEL RESULTS: - REFINERY FUEL SULFUR LEVELS - 1977
Scenario
C
F
Cluster
East
Coast
MB/CD
14.46
14.96
WT%S
0.6
0.3
Large
Midwest
MB/CD
10.09
10.97
WT%S
1.5
0.5
Small
Midcont.
MB/CD
4.80
4.68
WT%S
1.3
0.5
Louisiana
Gulf
MB/CD
15.68
16.21
WT%S
0.2
<0.1
Texas
Gulf
MB/CD
26.62
26.87
WT%S
0.9
0.5
West
Coast
MB/CD
16.63
16.86
WT%S
0.7
0.3
I
In
O
-------
TaWe J-47. L.P. MODEL RESULTS: - REFINERY FUEL SULFUR LEVELS - 1985
Scenario
C
F
- _-,,- . . -i. ' - in- - " - "
Cluster
East
Coast
MB/CD
14.81
15.11
WT
%S
0.6
0.3
Large
Midwest
MB/CD
10.98
12.00
WT
%S
1.5
0.5
Small
Midcont
MB/CD
5.05
4.96
WT
%S
1.4
0.5
Louisiana
Gulf
MB/CO
16.55
17,07
WT
%S
0.4
<0.1
Texas
Gulf
MB/CD
27.07
27.20
WT
%S
0.9
0.5
West
Coast
MB/CD
16.57
16.93
WT
%S
0.7
0.3
East of Rockies
Grassroots
Sweet Crude Sour Crude
MB/CD
13.60
13.90
WT
%S
0.5
0.4
MB/CD
17.82
18.63
WT
%S
1.0
0.4
West of Rockies
Grassroots
MB/CD
18.24
20.82
WT
%S
0.7
0.3
Ci
-------
22
l^i
N)
TEX Aft GULF. CLUSTER 1985 SULFUR *- MATERIAL BALANCE
OPIIISTB-I
Figure J-l
-------
Table J-48. 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/CD*
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.
% weight0
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,
MJos/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,
MJbs/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
4.028"
4,028
C-,
I
m
LO
*Table J-20.
^"able H-1, sum of light and heavy gas oil yields.
Table* H-13 and H-14.
Average
-------
Table J-49. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985 B/C
Desulfurization of Light Gas Oil
Stream
number
35
36
37
Stream name
Dwlfurizttion of light gn oil
Intake
Texas light gas oil
Normal purity hydrogen, MSCF/CD
Output
C3
iC4
"C4 o
Cs to 160 F
H2S
Subtotal - light ends and H2S
Desulfurized light gas oil
(1)
Proces
coefficients*
1.000
0.190
0.001
0.001
0.001
0.008
N.A.
0.990
(2)
(1>x7J080b
Volume,
MB/CO
7.080
1.345
0.007
0.007
0.007
0.057
N.A.
0.078
7.009
(3)
Specific
gra«tye
0.8251
N.A.
0.508
0.563
0.584
0.664
N.A.
0.815
(4)
Sulfur,
%wgt.e
0.5787
0.0
negl.
negl.
negl.
0.0288
N.A.
(5)
(2)x|3bi349.776
Hydrocarbon
weight.
MRfas/CD
2,043.289
7,270*
1.244
1.378
1.430
19.937
12.440f
36.429
1.998.038
(6)
(4) x (5)
100
Intake sulfur
weight.
MHbs/CD
11.824
0.000
(7)
Output
sulfur
distribution.
percent
0.0
0.0
0.0
0.0
99.0
99.0
1.0
I
(8)
Output sulfur
weight.
Mlbs/CD
0.000
0.000
0.000
0.000
11.708
11.708
0.117
(9)
SuHui
content.
j"M"Hj
rrfn
5,786
0
0
0
0
0
N.A.
N.A.
58.
Ul
tables H-8 and H-10.
blntake volume for undesulfurized light gas oil; MB/CO unless otherwise noted.
'Tables H-13 through H-15.
dTaWeH-12.
"Weight of hydrogen assumed to be 5.405 Ib/MSCF.
fSulfur in HjS (column 8) times the weight ratio of H2S/suMur (1.0625).
-------
Table J-5O. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985, Scenario B/C
Feed Sulfur Levels
ProceM/Faad
unit / stream
Catalytic cracker
Vacuum overhead feed
Louisiana
West Texas Sour
Nigerian Forcados
Arabian Light
Venezuelan Tia Juana
Total VOH feed
Coker/Vabreaker
Vacuum bottoms 1050°F+
Louisiana
West Texas Sour
Nigerian Forcados
Arabian Light
Venezuelan Tia Juana
Total bottoms feed
Hydrocracfcer
Heavy gas oil 500-650° F feed
Louisiana
West Texas Sour
Nigerian Forcados
Arabian Light
Venezuelan Tia Juana
Total HGO feed
(1)
%
crude
d*.'
47.4
41.4
3.8
5.3
2.1
109.0
47.4
41.4
3.8
5.3
Z1
100.0
47.4
41.4
3.8
5.3
2.1
100.0
(21
YMdon
crude,
volume V>
32.50
29.60
30.40
29.50
32.80
N.A.
5.60
12.30
a 50
13.70
25.00
N.A.
19.50
14.11
20.60
15.01
12.70
N.A.
(3)
(1) x (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
0.267
16.915
(4)
Specific
gravity6
0.8974
0.9167
0.942
0.9154
0.922
OJM61
0.9881
1.0187
0.998
1.0195
1.0236
1.0096
0.8504
0.8633
0.891
0.8463
0.865
0.8568
(51
Sulfur
contwit,
% weight0
a3221
1.8513
0.3125
2.3215
1.6292
1.0614
a9207
3.0018
0.6265
4.5530
2.8743
2.4S51
a 0901
1.2187
0.2015
1.0807
0.6690
(L5426
(6)
(3) x (4) x 349.776 x 6)
100
Feed sulfur
Mfcs/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,
Ibt/bbifeed
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
t-l
-------
Table J-51. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985. Scenario B/C
Stream Qualities Cluster Specific Streams
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 ( j j
Sulfur content, Ibs/bbl feed"
Louisiana
VOH
0.025
0.090
0.153
0.209
0.024
0501
0.020
0.069
0.132
0.244
0.036
0301
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
O827
1.300
0.143
3.372
0.161
0.780
0.685
1.522
0.224
3.372
<2>
volume.
LV fraction
on feed*1
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
^__^^*^^^^
cufiuni*
M/bM*
0.354
3.400
10.338
N.A.
N.A.
N.A.
tt 268
7.800
13.700
N.A.
N.A.
N.A.
(4)
Height
fcc/bbl
feed11
N.A.
N.A.
N.A.
1.381
0.286
N.A.
N.A.
N.A.
N.A.
1.617
0.448
N.A.
Ui
"Crude-specific feed sulfur (Table J-50, column 7) times output stream sulfur as a percent of crude-specific feed sulfur (Table H-18, case 2).
''Table H-4.
°Sulfur content, PPM, calculated by methodology shown on Table J-48. Specific gravities of streams found on Table H-16.
dGaseous sulfur content (column 1) times weight ratio of gaseous stream/sulfur.
H2S/sulfur weight ratio = 1.0625; SOx/sulfur content = 2.000.
*Low conversion, untreated feed.
High conversion, untreated feed.
-------
Table J-52. SAMPLE CALCULATIONS FOR MASS AND SULFUR BALANCE
Texas Gulf 1985, Scenario B/C
Stream Qualities - Cluster-Specific Streams
StrMm
volume,
LV fraction
on feed"
Total Ieed
sulfur
Ibt/bbl faed4*
Catalytic cracker
72.6 convenient
Cat. naphtha
Light cycla oil
Haavy cycla oil
HjS
SOx
Total eat 72.8 eonvanlon
Cokar
Vacuum bottomt faad
Light colcar naphtha
Medium cokar naphtha
Cokar gat oil
Coka
H2S
Total ookar bottomt faad
H»»W cycle oil feed"
Light cokar naphtha
Medium cokar naphtha
Cokar gat oil
Coka
H2S
Total coker - cycle oil faad
Hydrocr acker
Heavy gat oil faad
Output ttraamt
H2S
Total hydrocracker - HGO
Vacuum overhead feed
Output ttraamt
H2S
Total hydroerackar - VOH
Light cycle oil feed"
Output ttraami
H2S
Total hydrooraeker - LCD
0.337
0.337
0.337
0.337
0.337
0.337
8.870
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
3.6
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
0.0'
100.0
100.0
0.0'
100.0
100.0
0.0'
100.0
100.0
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
0.0001
1.626
1.626
0.000'
3.372
3.372
o.ooo1
3.400
3.400
0.68
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
0.6932
0.1283
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
0.021
0.647
1.794
N.A.
N.A.
N.A.
0.990
1.578
6.361
10.318
N.A.
N.A.
1.560
2.472
5.282
24.739
N.A.
N.A.
0.000'
N.A.
0.000
0.0001
N.A.
0.000
o.ooo1
N.A.
0.000
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
aOther cat cracker conversion* on Table J-51. Vl»breaklng not used in Texas Gulf cluster.
bTable J-50.(column 7).
°Tablat H-17 and H-18 (cata 2).
dTabla H-4 through H-7.
'Sulfur content, PPM, calculated by methodology thown on Table J-48. Specific gravities of itreamt found on Table H-16.
'Oataout output tulfur (column 3) timet weight ratio of gateout stream/tulfur.
H2S/tulfur weight ratio - 1.0625, SOx/tulfur weight ratio - 2.000.
8Lowconver»ion, hydrotreetad feed (tulfur level it 10% of untreated feed). High (95) convertion, hydrotreated feed not used
In Texat Gulf.
h85 convartion catalytic cracker output (Table J-51).
'Negligible sulfur content (approximately 1 PPM).
J-57
-------
Table J-53. 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-58
-------
Table J-54. MASS AND SULFUR BALANCE
Texas Gulf Ouster 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
C5 to 200°F
200 to 340° F
340to375°F
Cs to 200° splitter
Intake
Cs to 200°F
Output
Cs to 160°F
160 to 200°F
Desutfurization of isomerization feed
Intake
Cj 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.
Mbs/CD
586.637
97,946.709
2,634.901
21,134.135
8,156.225
3.601.199
8.454
Sulfur
weight,
Mbs/CD
0.293
751.830
0.076
16.162
1.258
0.577
0.000
Sulfur
content,
DOfcJ
rfwi
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
Ll> Mrl*n«r
Hydrocarbons
weight,
Mbs/CD
1.124.336
22,068.196
31,277.931
43,221.001
277.400
8.156.236
12,328.216
2,970.906
5,037.023
3,080.919
0.582
3,467.882
Sulfur
weight,
Mbs/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
DOAA
IVTCI
0
744.
4,028.
14.099.
0
154.
816.
1.653.
109.
227.
N.A.
1.
(-4
Ui
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gulf duster 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
Cs to 160°F desulfurized
Output
Light ends
Isomerate
Naphtha product from desulfurization
C5 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
Aromatics extraction
Intake
1 00 sev. reformate
Output
Raffinate
BTX
' _ . _ . _ . _ i
Process intake
Volume,
MB/CD"
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
»_
16^39.077
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.
....i. , . .-,.... ... i . . i
Process output
Volume,
MB/CD*
0.482
14.493
0.317
4.650
N.A.
61.683
14.952
57.614
7.795
5.675
L J m
Hydrocarbons
weight.
Mbs/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
ON
O
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gulf Ouster 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
Dasutfurize light gas oil
Intake
Light gas oil 375 to 500° F
Normal purity hydrogen
Output
Light ends and H2S
Desulfurized light gas oil
Cg 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/CO*
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,
Mite/CD
115.823
11.824
0.000
68.634
0.000
68.634
587.862
Sulfur
content,
DOU
rrWI
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
rfyOrOCTffPUm
WBtytt,
Mbs/CO
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,
Mbs/CD
33.001
82.872
11.708
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.
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gurf duster 1986. 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
DMutfurizatkm for lubes
Input
Hydrocarbon feed
Hydrogen
Output
Light ends and HjS
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
Alkyfation
Input
Isobutane
Mixed otefins
Output
Alkylate
Process intake
Volume,
MB/CD*
98.050
1.880
16.580
80.633
12.821
10.780
Hydrocarbons
weight
Mlbs/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/CD*
0.264
16.517
12.997
13.163
46.525
12.072
4.731
19.080
.. . j_
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
content,
DfMJ
fVWl
N.A.
1J092.
N.A.
0
847.
14.728.
41.441.
0
e-i
I
ON
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gulf Ouster 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
Desurfurization of light cyde 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
OesuHurization of Coker Naphtha
Input
Medium coker naphtha
Normal purity hydrogen
Output
H2S
Oesulfurized 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,
Mbs/CD
3,712.124
14.092
5,901.070
789.357
9.568
5,550.302
1.177.801
Sulfur
WWylt,
Mbs/CD
55.573
0.000
151.456
4.629
0.000
62.467
0.000
Sulfur
content,
PPM
14,970.
0
25,666.
5,364.
0
11.255.
0
Process output
Volume,
MB/CD*
0.131
11.731
4.416
0.616
1.657
2.950
7.820
3.754
N.A.
2.980
N.A.
27.090
weight,
Mbs/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,
Mbf/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.
(-1
I
aM8/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gulf Ouster 1985, Scenario B/C
Stream
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,
Mite/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,
Mbs/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/CO"
40.72
N.A.
N.A.
0.788
8.014
152.330
Hydrocarbons
weight.
Mbs/CD
220.108
346.342
18.255
267.578
1,423.938
39,056.31
Sulfur
K^^^U^^fe A
WVfyll,
Mite/CD
0.000
346.342
18.255
0.000
0.000
12.118
Sulfur
content,
PPM
0
N.A.
N.A.
0
0
309.
C-,
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario B/C
Stream
number
87
88
89
90
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 otefins
Composition
Mixed olefins
Light ends
Blend totals
Process intake
Volume,
MB/CD*
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
UlLJ«l>J)LMIululLUm«
Hydrocarbons
weight,
Wbs/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,
Mbs/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/CD*
5.677
8.258
22.043
7.226
78.141
3.725
Hydrocarbons
weight.
Mbs/CD
1,731.480
2,049.680
6,289.908
2,067.487
23,177.402
-%
709.073
Sulfur
weight,
Mbs/CD
0.000
0.273
0.827
2.168
39.071
0.000
Sulfur
content,
PPM
0
133.
131.
1,048.
1,685.
0
c_
o^
in
JMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-54.(continued). MASS AND SULFUR BALANCE
Texas Gulf Clutter 1965. 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 1 050° + F
Blend totals
Blending of coke
Composition
Coke
Blend totals
Process intake
Volume.
MB/CO*
O.tlf
10.378
4.224
15.474
1.314
3.754
Hydrocarbons
weight,
Mbs/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,
nftmm
rrvn
95.
4,183.
30,018.
1.092.
45,531.
26,689.
Process output
Volume.
MB/CD*
14.714
15.474
1.314
3.754
1^ ! II III B>4uUU
HyoTOcarDuiD
weight,
Mbs/CD
4,844.048
4,766.188
468.560
1,444.365
Sulfur
weight,
Mbs/CD
59.017
5.205
21.334
38.550
Sulfur
content.
PPM
12.183.
1,092.
45,531.
26,689.
C-i
I
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas {FOE MB/CD).
-------
Table J-55. MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Proem/stream name
Purchased butanes
Atmospheric Distillation
Intake
Crude charge
Output
Light ends
Full range naphtha
Ga* oil 375 to 650° F
Bottoms 650°+F
Naphtha splitter
Intake
Purchased natural gasoline
Full range naphtha
Output
Light ends
C5 to 200° F
200 to 340°F
340 to 375°F
C$ to 200° F splitter
Intake
C5 to 200° F
Output
C5 to 160°F
160 to 200°F
DesuHurization of isomerizatton feed
Intake
C5 to 160°F
Normal purity hydrogen
Output
H2S
C5 to 160 F desulfurized
Process intake
Volume."
MB/CO
2.926
328.415
11.200
80.050
33.045
15.660
1.644
Hydrocarbon
weight,
Mlbs/CD
586.637
97,946.709
2,634.901
21,233.742
8,104.170
3,708.665
8.886
Sulfur
weight,
Mlbs/CD
0.293
751.830
.076
16.236
1.257
0.619
0.000
Sulfur
content,
PPM
499.
7,676.
29.
764.
155.
166.
0.
Process output
Volume,3
MB/CD
5.627
83.708
106.347
132.642
1.377
33.946
45.364
10.561
21.684
12.046
N.A.
15.660
nydrocsfoon
i neiirahl
ww^n,
Mlbs/CD
1,124.336
22.068.196
31,277.931
43,221.001
277.401
8,154.832
12,325.287
2,976.073
4,936.723
3,070.121
0.622
3,642.508
Sulfur
i inTnili
Mioigni,
Mlbs/CD
0.000
16.435
126.003
609.392
0.000
1.258
10.061
4.921
0.549
0.700
0.586
0.005
Sulfur
content,
BBaU
rrm
0.
744.
4,028.
14,099.
0.
154.
816.
1,653.
111.
228.
N.A.
1.
C-H
ON
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-55. (continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Process/stream name
Isomerization
Intake
Cg to 160°F desulfurized
Output
Light ends
Isomerate
Naphtha product from desuifurization
Reformer feed to transfer
SR naphtha
Desuifurization of 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
Aromatics extraction
Intake
lOOsev. reformate
Output
Raffinate
BTX
Process intake
Volume,8
MB/CD
16.000
0.052
4.650
62.410
6.582
61.403
5.360
2.750
69.513
13.504
Hydrocarbon
weight,
Mlbs/CD
4,074.715
12.031
1,239.361
16,836.012
35.578
1 7,040.361
1,424.657
731.993
19,197.011
3,793.598
Sulfur
weight,
Mlbs/CD
0.005
0.003
0.115
13.552
0.000
0.018
0.005
0.003
0.026
0.004
Sulfur
content,
PPM
1.
249.
92.
804.
0.
1.
4.
4.
1.
1.
Process output
Volume,*
MB/CD
.535
15.187
0.052
4.650
N.A.
62.410
16.258
56.839
7.827
5.677
Hydrocarbon
n »!>
wwyiiL,
Mlbs/CD
177.009
3,417.954
1Z031
1,239.361
13.800
16,836.012
3,127.796
16,451.301
1,990.253
1,731.480
Sulfur
weight,
Mlbs/CD
0.000
0.004
0.003
_
0.115
12.988
.018
0.001
0.019
0.002
0.000
Sulfur
content,
PPM
0.
1.
249.
92.
N.A.
1.
0.
1.
1.
0.
00
aMB/CD except for hydrogen IMMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-55. (continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Process/stream name
Gas oil splitter
Intake
Gas oil 375 to 650°F
Output
Light gas oil 375 to 500°F
Heavy gas oil 500 to 650°F
Desulfurization of light gas oil
Intake
Light gas oil 375 to 500° F
Normal purity hydrogen
Output
Light ends and H2S
Desulfurized light gas oil
Hydrocrackar
Intake
Hydrocarbon feed
High purity hydrogen
Total intake
Output
Light ends and H2S
Light hydrocrackate
Hydrocracked jet fuel
Heavy hydrocrackate
Vacuum distillation tower
Input
Bottoms 650° +F
Output
Vacuum overhead
Bottoms 1050°+F
Gas oil feedstock
Process intake
Volume,3
MB/CD
59.540
6.470
1.229
20.200
37.996
117.240
104.890
Hydrocarbon
weight,
Mlbs/CD
17,583.471
1,867.243
6.645
6.392.135
205.384
6,597.519
37,677.285
32,739.498
Sulfur
weight,
Mlbs/CD
117.135
10.805
0.000
67.956
0.000
67.956
588.926
389.387
Sulfur
content,
DDU
mm
6,661.
5,786.
0.
10,631.
0.
10,300.
15,630.
11,893.
Procoa output
Volume,8
MB/CD
28.614
30.926
N.A.
6.405
N.A.
4.669
12.733
5.356
88.890
28.351
-
Hydrocarbon
wuiuhl,
Mbs/CD
8,260.803
9,322.812
33.806
1,825.942
1,012.792
1,110.510
3,616.402
1,461.252
28,314.305
10,028.877
Sulfur
WMytt,
Mlbs/CD
33.312
83.848
10.703
0.107
67.451
0.001
0.003
0.005
330.823
258.239
Sulfur
content,
nokJ
rrrn
4,032.
8,993.
N.A.
58.
N.A.
0.
0.
3.
11.683.
25,749.
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-55. (continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
47
48
49
50
52
53
54
55
56
57
58
59
60
61/62
63
64
65
66
67
68
69
Process/stream name
Cat. feed to transfer
Desutfurization of cat. feed
Input
Undesulfurized cat. feed
Hydrogen
Output
Light ends and H2S
Oesulfurized cat feed
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
Desulfurization of light cycle oil
Input
Output
Coker
Input
Output
Light ends and H2S
Mixed olefins
Light coker naphtha
Medium coker naphtha
Coker gas oil
Coke
Process intake
Volume,3
MB/CD
1.880
103.023
30.907
87.004
11.312
5.522
0.000
14.550
Hydrocarbon
weight,
Mlbs/CD
586.790
32,152.708
167.065
26,807.427
2,310.752
1,062.209
0.000
5,185.064
Sulfur
weight,
Mlbs/CD
6.979
382.408
0.000
29.330
0.001
0.000
0.000
132.090
Sulfur
content,
PPM
11.893.
11,893.
0.
1,094.
1.
0.
0.
Process output
Volume,3
MB/CO
N.A.
102.508
N.A.
11.924
50.497
18.451
5.483
.
16.834
0.000
25,475.
N.A.
.567
1.528
2.721
6.009
3.754
Hydrocarbon
weight,
Mlbs/CD
880.726
31,573.739
2,265.940
2,293.900
13,335.298
5,779.941
1,811.956
4,115.795
0.000
1,204.262
109.155
361.757
728.055
1,774.011
1,444.362
Sulfur
weight,
Mlbs/CD
Sulfur
content,
PPM
325.018 N.A.
34.545
8.422
1,094.
N.A.
0.000 0.
1.010 75.
10.111 1,749.
9.826 5,422.
I
0.017
0.000
43.193
0.000
1.506
4.269
38.045
38.550
4.
0.
N.A.
0.
4,163.
5,863.
21,445.
26,689.
^J
o
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-55. (continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
70
71
72
73
74
75
76
77
78
79
80
81
82
83
Process/stream name
Desurfurization 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 (04 and lighter)
Output
Sulfur in SOX
Refinery fuel (FOE)
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 (FOE)
Normal butane
Blend totals (FOE)
Blending of LPG
Composition
Propane
Blend totals
Process intake
Volume,8
MB/CO
2.721
1.633
18.590
8.610
1.588
N.A.
0.790
7.670
Hydrocarbon
weight,
Mlbs/CD
728.055
8.824
5,950.004
1 ,029.097
539.599
486.936
256.147
1,362.853
Sulfur
weight,
Mlbs/CD
4.269
0.000
35.131
0.000
0.000
458.293
0.000
0.000
Sulfur
content,
PPM
5,863.
0.
5,902.
0.
0.
N.A.
0.
0.
Process output
Volume,3
MB/CO
N.A.
2.748
N.A.
27.200
37.996
N.A.
N.A,.
0.790
7.670
Hydrocarbon
weight,
Mlbs/CD
4.533
731.488
35.121
6,979.101
205.383
458.077
0.504
256.147
1,362.853
Sulfur
weight,
Mlbs/CD
4.266
0.003
35.121
35.121
0.000
458.077
0.252
-
0.000
0.000
Sulfur
content,
.PPM
N.A.
4.
N.A.
5,032.
0.
N.A.
N.A.
0.
0.
C-,
I
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
{continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
Process/stream name
Process intake
Volume,3
MB/CD
Blending of unleaded gasoline ;
84
Composition
Liquid
(sornerate
15.187
! Reformate 43.330
85
86
87
88
89
Light hydrocrackate 4.669
Cat. naphtha
Light coker naphtha
Raffinate
50.497
1.528
3.224
Natural gasoline 6.983
Alky late
Gaseous
Butanes
Blend totals
Blending of BTX
Composition
BTX
Blend totals
Blending of naphtha
16.834
10.598
5.677
Composition
SR naphtha 3.660
Raffinate ; 4.600
Blend totals
Blending of distillates
Composition
! Heavy naphtha 340 to 375° F 0.155
90
91
92
Gas oil 375 to 650 F i 46.810
Light gas oil 375 to 500° F 22.140
Desulfurized light gas oil 6.405
Hydrocracked jet fuel 12.733
Heavy gas oil 0-716
Light cycle oil 18.451
Blend totals
Jet fuel
Kerosene j
Distillate fuel oil
Hydrocarbon
weight,
Mlbs/CD
Sulfur
weight,
Mlbs/CD
i
3,417.954
12,557.703
1,110.510
13,335.298
361.757
876.314
1,572.596
0.004
0.015
0.001
1.010
1.506
0.001
0.016
4,115.795 0.017
2,153.220
1,731.480
939.012
1,113.939
43.197
13,704.213
6,392.557
1,825.942
3,616.402
212.974
5,779.941
0,003
0.000
0.275
0.001
0.021
8.894
22.504
0.107
0.003
0.192
10.111
Sulfur
content,
PPM
Process output
Volume,3
MB/CD
Hydrocarbon ; Sulfur Sulfur
weight, . weight, content,
Mlbs/CD Mlbs/CD PPM
.
1.
1.
0.
75.
4,163.
1.
10.
4.
1.
. T
0.
2.
1.
i
1
152.850 39,601.147 2.573 65.
i
5.677 1,731.480
8.260
486.
2,459.
3,520.
58.
0.
901.
1,749.
22.043
7.226
78.141
i
2,052.951
0.000 0.
;
0.276 134.
1
--
6,282.969
2,087.194
23,204.734
0.613 97.
2.168 1,038.
39.071 1,683.
c,
I
^4
r-o
3MB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
Table J-55. (continued). MASS AND SULFUR BALANCE
Texas Gulf Cluster 1985, Scenario F
Stream
number
93
94
95
96
97
Process/stream name
Blending of olef ins
Composition
Mixed olef ins
Light ends
Process intake
Volume,8
MB/CO
2.980
0.745
Blend totals
Blending of residual fuel oil
Composition
Bottoms 650 +F
Bottoms 1 050°+F
Heavy cycle oil
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
2.860
6.371
5.483
15.474
1.314
3.754
Hydrocarbon
weight,
Mtbs/CD
573.283
135.790
911.127
2,213.643
1,811.956
4,766.188
468.560
1,444.362
Sulfur
weight,
Mlbs/CD
0.000
0.000
3.810
56.942
9.826
5.215
21.334
38.550
Sulfur
content,
PPM
0.
0.
4,183.
25,716.
5,422.
1,094.
45,530.
26,689.
Process output
Volume,9
MB/CO
3.725
14.714
15.474
1.314
3.754
Hydrocarbon
weight,
Mlbs/CD
709.073
4,980.883
4,766.188
468.560
1,444.362
Sulfur
weight,
Mlbs/CD
0.000
70.578
5.215
21.334
38.550
Sulfur
content,
PPM
0.
14,169.
1,094.
45,530.
26.689.
c_
-J
u>
aMB/CD except for hydrogen (MMSCF/CD) and refinery gas (FOE MB/CD).
-------
APPENDIX K
CONVERSION FACTORS AND NOMENCLATURE
K-i
-------
TAl^Ltf OF CONTENTS
__Jl.JcMyM^I_OLN__FACTO_RS^J\.ND NOMENCLATURE
LIST OF TABLES
Page
TABLE K-l. Weight Conversions K-l
TABLE K-2. Volume Conversions K-2
TABLE K-3. Gravity, Weight and Volume Conversions for
Petroleum Products K-3
TABLE K-4. Representative Weights of Petroleum Products K-4
TABLE K-5. Heating Values of Crude Petroleum and
Petroleum Products K-5
TABLE K-6.
Nomenclature K-6
K-ii
-------
Table K-1. WEIGHT CONVERSIONS
Unit
One short ton
One metric ton
One long ton
One cubic centimeter lead
Equivalent value
2,000 pounds
2,204.6 pounds
2,240.0 pounds
1.06 grams lead
K-1
-------
Table K-2. VOLUME CONVERSIONS
Unit
One imperial gallon
One liter
One U.S. barrel
One cubic meter
One cubic foot
Equivalent value
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'COIMVERSIONS 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
/O
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
0.1320
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
-------
Table K-4. REPRESENTATIVE WEIGHTS8 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
6.11
5.50
7.46
7.00
7.25
8.51
7.78
11.60
7.00
6.66
7.86
Barrels
per
long
ton
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 ijas
Fuel oil i.'quivalent barrel
Natural gasoline
Li(|ueficd 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 value
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/CD
MB/SD
MBPY
MKWH
MKWH/CD
Mlbs
MMB
MMB/CD
MMBPY
MSCF
MMSCF
PPM
SCF
$/B/SD
$MM
Barrels per stream day
British Thermal Unit
Cubic centimeters per U.S. gallon
t
Fuel oil equivalent
i
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
-------
APPENDIX L
ALTERNATE FOR REFINERY S0__ CONTROL STUDY
x
FLUE GAS DESULFURIZATION TECHNOLOGY
L-i
-------
TABLE OF CONTENTS
APPENDIX L - ALTERNATE FOR REFINERY S0y CONTROL STUDY
FLUE GAS DESULFURIZATION TECHNOLOGY
A. BACKGROUND L-l
1. Commercial and Near Commercial Technologies I1
2. Initial Process Selection 13
B. DETAILED EVALUATION OF SELECTION PROCESSES L-5
1. Basis L-5
a. Technical Assumptions .. 15
b. Economic Assumptions 19
2. Chiyoda L~12
a. Process Description L-12
b. Process Reliability L""15
c. Application to Refinery SO Control 11.6
Jv
d. Capital and Operating Requirements 117
3. Dual Alkali and Wet Lime Scrubbing L~23
a. Process Description * L-23
b. Process Reliability L~26
c. Application to Refinery SO Control L-27
X
d. Capital and Operating Requirements 1-28
e. Wet Lime Scrubbing L~33
I 13
(1) Process Description
(2) Prpcess Reliability L~34
(3) Applicability to Refinery S0x Control L-36
L-ii
-------
TABLE OF CONTENTS - (cont.)
Page
4. Magnesia Scrubbing L-38
a. Process Description L-38
(1) SO Absorption - L-40
(2) Slurry Processing L-42
(3) Dewatering L-45
(4) Drying L-46
(5) Calcining L-46
(6) Slurry Makeup L-48
(7) Sulfuric Acid Production L-48
b. Process Reliability L-50
c. Application to Refinery SO Control L-54
A
d. Capital and Operating Requirements L-57
5. Shell/UOP L-62
a. Process Description L-62
b. Process Reliability L-68
c. Application to Refinery SO Control L-71
X
d. Capital and Operating Requirements L-74
6. Wellman-Lord L-80
a. Process Description L-80
(1) Gas Pretreatment L-81
(2) SO Absorption L-84
(3) Absorbent Regeneration L-86
(4) System Purge & Makeup L-88
b. Process Reliability L-91
L-iii
-------
TABLE OF CONTENTS - (cont.)
c. Applicability to Refinery SO Control L-94
x
d. Capital and Operating Requirements L-96
(1) Scrubber System L-96
(2) Regeneration System L-99
C. OFF-LINE COMPARATIVE ECONOMIC ANALYSIS , L-101
D. CONTROL OF SULFUR PLANT EMISSIONS L-110
1. Alternatives L-110
2. Economics L-113
3. Glaus Tail-Gas-Cleanup Processes L-114
E. INTEGRATION OF SO REMOVAL PROCESSES L-116
1. Davy Powergas Process , L-116
2. Process Requirements L-118
L-iv
-------
LIST OF TABLES
TAIH.K l.-l.
TABLE L-2.
TABLE L-3.
TABLE L-4.
TABLE L-5.
TABLE L-6.
TABLE L-7,
TABLE L-8.
TABLE L-9-
TABLE L-10.
TABLE L-ll.
TABLE L-12.
TABLE L-13.
TABLE L-14.
TABLE L-15.
TABLE L-16.
TABLE L-17.
Development Status of Significant S02 Control
Processes L-2
Major Sources of SOX Emissions in Refineries L-6
Refinery Sulfur Emission Sources L-7
Unit Costs Applied in Off-Line Economics L-ll
Chiyoda Thoroughbred 101 Process Estimated Capital Cost
and Operating Requirements - Gas Side L-18
Chiyoda Thoroughbred 101 Process Estimated Capital Cost
and Operating Requirements _T Liquor Side L-21
DuaJ Alkali Process Estimated Capital Cost and Operating
Requirements - Gas Side L-29
Dual Alkali Process Estimated Capital and Operating
Costs - Liquor Side ^ L-31
_i
Capital and Operating Requirements - Magnesium Oxide
Scrubbing System L-58
Capital and Operating Requirements - Magnesium Oxide
Regeneration System L-59
i
Capital and Operating Cost Estimate - Shell Flue Gas
Desulfurization Acceptor System '. L-75
Capital and Operating Cost Estimate - Shell Flue Gas
Desulfurization Regeneration/Reduction Section L-77
Capital and Operating Cost Estimates - Wellman-Lord
Scrubbing System L-92
Capital and Operating Cost Estimates - Wellman-Lord
Regeneration System L-97
Flue Gas Desulfurization Processes Off-Line
Comparative Economic L-102
Exxon R and E FCC Scrubbing System Capital and
Operating Requirements L-109
Beavon Tail-Gas-Cleanup Process Typical Investment
and Operating Requirements L-115
L-v
-------
LIST OF TABLES - (cont.)
Page
TABLE L-18. Flue Gas Desulfurization Process Economics -
Capital Requirements L-119
TABLE L-19. Refinery Flue Gas Desulfurization Process
Operating Requirements , L-120
LIST OF FIGURES
FIGURE L-l. Process Flow Diagram, Chiyoda Thoroughbred 101 L-13
FIGURE L-2. Chiyoda Engineering, Capital Investment
Scrubbing Section L-20
FIGURE L-3. Chiyoda Engineering, Capital Investment
Regeneration Section L-22
FIGURE L-4. Dual Alkali System L-24
FIGURE L-5. Double Alkali, Capital Investment - Scrubbing Section ... L-30
!r »
FIGURE L-6. Double Alkali, Capital Investment - Regeneration
Section L-32
FIGURE L-7. Dual Alkali Scrubbing With Lime Regeneration L-35
FIGURE L-8. Flow Diagram - Magnesia Slurry Scrubbing-Regeneration L-41
FIGURE L-9. MagOx (Chemico) Capital Investment - Scrubbing Section ... L-60
FIGURE L-10. MagOx (Chemico) Capital Investment - Regeneration Section L-61
FIGURE L-ll. Simplified Process Flow Scheme of SFGD L-65
FIGURE L-12. Simplified Flow Scheme of SFGD Demonstration Unit for
Coal Fired Utility Boiler at Tampa Electric, Florida L-73
FIGURE L-13. Shell/UOP, Capital Investment - Acceptor Section L-76
FIGURE L-14. Shell/UOP, Capital Investment - Regeneration Section L-79
FIGURE L-15. Schematic Flowsheet - Wellman-Lord Process L-82
FIGURE L-16. Davy Power Gas, Capital Investment - Scrubbing Section ... L-98
L-vi
-------
LIST OF FIGURES - (cont.)
Page
FIGURE L-17. Davy Power Gas, Capital Investment - Regeneration Section .. L-100
FIGURE L-18. Typical Flow Diagram - Exxon FCC Caustic Scrubbing System .. L-107
FIGURE L-19. Glaus Tail Gas Cleanup - Scheme I and II L-lll
FIGURE L-20. Conceptual Refinery SOX Control System Based on
Wellman-Lord Process L-117
L-vii
-------
APPENDIX L
ALTERNATE FOR REFINERY SO CONTROL STUDY
FLUE GAS DESULFURIZATJLON TECHNOLOGY
A. BACKGROUND
1. COMMERCIAL AND NEAR COMMERCIAL TECHNOLOGIES
With the passage of the Clean Air Act of 1970, considerable effort has
been expended by the government and private .industry to develop reliable and
economical methods for removing S02 from the flue gases leaving stationary
combustion sources. Many techniques for chemically or physically capturing
the SO- have been studied and considerable effort is being expended to develop
commercially demonstrated processes. The number of S0~ removal processes currently
under development is indeed large. However, it is the intent of this study to
identify processes which will be commercially proven and available by 1980.
Ideally, this would mean the process would have been installed and operated on
at least 100 megawatts prior to this date. A list of the significant SO control
processes which have a reasonable chance of meeting these criteria is presented
in Table L-l. Included in the table is the current development status of each
process and an estimate of the earliest date for commercial availability. In
L-l
-------
TABLE L-l
DEVELOPMENT STATUS OF SIGNIFICANT SC>2 CONTROL PROCESSES
As of Mid-1974
PROCESS
Waste Salts
Limestone Injection
and Scrubbing
Direct Limestone
Scrubbing
Direct Lime Scrubbing
Sodium Solution
Scrubbing
REACTANT OR SORBENT PRODUCT
Limestone
Limestone
Lime
Soda ash, caustic
soda, trona
CURRENT STATUS
Earliest
Commercial
Availability
430-Mw plant in op-
eration
Several plants in op-
eration
156-Mw plant opera-
ting in Japan
250-Mw plant under
construction
1974
1974
Double Alkali
Chiyoda
Concentrated S02
Chemico Mag-Ox
Stone & Webster/Ionics
Wellman-Powergas
Esso/B&W
UOP/Shell
TVA
FW/Bergbau-Forschung
Direct Acid Processes
Monsanto Cat-Ox
Bergbau-Forschung
Elemental Sulfur
UOP Sulfoxel
Atomics International
Westvaco Char
Consolidation Coal
Bureau of Mines
Citrate
Stauffer Chemical
Lime (or limestone),
soda ash
Weak Acid
Magnesium oxide
slurry
Sodium hydroxide
solution
Sodium sulfite
solution
Unknown dry ad-
sorbent
Copper oxide/alumina
Ammonia
Dry Char
Gypsum
10-15% S02
100% S02
100% S02
S02/H2S04
S02
S02
40%
S02/H2S04
25-Mw plant planned 1975
350-Mw plant under 1974
contract
150-Mw plant in op- 1975
eration
75-Mw plantplanned 1978
115-Mw plant under 1974
construction
Ready for demonstra- 1979
tion unit
40-Mw commercial plant 1974
operating
Pilot plant operating 1979
35-Mw operating 1976
Catalytic-oxidation 80% H2S04 110-Mw plant operating 1975
Wet Char 20% H2S04 Bench-scale 1976
Unknown
Molten alkali car-
bonates
Char catalyst
Potassium formate
Citrate Solution
Sodium phosphate
Sulfur Pilot-scale operating 197°
problems
H2S/Sulfur Pilot plant operating 197V
Sulfur Pilot-scale operating 197V
H2S/Sulfur Pilot-scale operating 197U
Sulfur Ready for demonstration 1979
unit
Sulfur Pilot operation 1979
completed
L-2
-------
some cases, the process is presently considered commercialized on oil fired
sources. From this list of processes, five candidates were selected for de-
tailed evaluation.
2. INITIAL PROCESS SELECTION
The five processes selected for detailed' technical and economic
evaluation include:
1. Chiyoda Thoroughbred 101
2. Double Alkali Scrubbing
3. Magnesia Scrubbing
4. Shell Flue Gas Desulfurization
5. Wellman Lord/Davy Powergas Soda Scrubbing
Basic considerations in this selection were the method of sulfur removal,
degree of commercialization and form of by-product sulfur.
An attempt was made to cover a variety of S02 removal methods while still
*
retaining those processes with a high degree of commercialization. For example,
the Chiyoda process absorbent is weak sulfuric acid. Double alkali and Wellman-
Lord utilize the sulfite/bisulfite system in different concentration modes. MagOx
is a regenerably slurry scrubbing process and, finally, the Shell process represents
a dry adsorption process.
In regard to degree of commercialization, all of the above processes have
L-3
-------
either commercial plants in operation or U.S. demonstration plants planned.
Of the five, Chiyoda and Davy Powergas have the most commercial systems operating.
Sulfur product forms represented include throw-away waste salts, con-
centrated acid and elemental sulfur.
L-4
-------
B. DETAILED EVALUATION OF SELECTION PROCESSES
1. BASIS
a^ Technical Assumptions
The scope of this study involves the comparison of in process feed and flue
gas desulfurization for controlling sulfur emissions from "typical" petroleum
refineries. In order to accomplish this objective in a generalized way, certain
assumptions were required to facilitate the development of flue gas desulfurization
economics. These assumptions and the identification of major sulfur emission
sources are presented below.
The major sources of refinery SO emissions are shown in Table L-2
along with typical gas conditions for these sources. A detailed breakdown of
these major sources together with approximate volumetric flow rates is presented
in Table L-3 for the typical refinery locations being studied. These flow rates
were determined xrom the fuel requirements for the various refinery units
assuming a gallon of fuel oil generates 2000 scf of flue gas.
L-5
-------
TABLE L-2
MAJOR SOURCES OF SOx EMISSIONS
IN REFINERIES
1. Sulfur Plant Tail Gas
2. Fluidized Catalytic Cracker Catalyst Regeneration
3. Boiler Plant Stacks
4. Numerous Process Furnace Stacks
Typical Gas Conditions
For
SOx Emission Source
FCC Regeneration Gas
Source
SOx Concentration, ppmv
Temperature, °F
Pressure, PSIA
Dust Loading, gr/scfd
Approximate Analysis, Mol
H2
N2
°2
CO
CO.,
H20
Glaus Plant
Tail Gas
12,000-20,000
350
18-20
%
3
57
1
10
26
Before
CO Boiler
140-3300(1)
1000-1200
16-28
0.1-1.4
70
2
8
10
10
After Boiler & Furnace
CO Boiler
110-2500(2)
500-800
14.7
0.02-1.0
72
4
11
13
Stacks
1600-2200
450-600
- 14.7
0.1
78
3
11
8
(1) SO concentration can be 10-60% of tot.l SOx.
(2) Approximately 30% dilution by additional flue gases.
L-6
-------
TABLE L-3
REFINERY SULFUR EMISSION SOURCES
Geographical Location
Refinery intake, MB/D
STATIONARY SOURCES
Atmospheric Distillation
Vacuum Distillation
Naphtha Desulfurization
Distillate Desulfurization
VGO Desulfurization
Residum Desulfurization
Catalytic Reforming
Catalytic Cracking
Hydrocracking
Alkylation
Coking
H2 Reformer
Steam Boilers
FLUID CATALYTIC CRACKER
Gulf Coast East Coast West Coast Mid. Cont.
Regenerator Gas
Sulfur Plant
(1)
250 150 100 75
Approximate Volumetric Flows, Mscfm (wet)
43.7
17.7
6.0
146.0
52.7
17.7
35.3
29.3
8.7
204.3
70.0
, 43,. 7
52.7
35.0
73.0
253.3
87.7
35.0
10.3
20.3
17.7
13.0
102.0
46.7
1.7.7
35.0
14.0
29.3 :
166.0
58.3
23.3
' 7.3
11.7
8.7
8.7
58.3
29.3
17.7
' 29.3
14.0
29.3
105.7
Tailgas before Incineration
96.0
18.2
64.0
18.2
40.0
9.1
43.7
29.3
29.3
10.3
70.0
40.0
1.2
(1) Before CO boiler; after CO boiler volume is 30% greater than figures shown.
L-7
-------
Specific assumptions made for developing the off-line economics are:
Typical stack gas conditions
Temperature, °F 475
Stack pressure, in. wg. 0
Sulfur, ppm 2200
Dust Loading, gr/scf 0.1 max
Moisture, mol % 9
Molecular weight (wet) 28.5
Base scrubber system capital investment cost based on 100,000 scfm
treatment volume and 90% removal of S0_.
$
Base regeneration system capital investment cost estimates based on
200 moles/hr SO. recovered equivalent to 77 tons/day of sulfur.
t (
50°F of flue gas reheat required for "wet" processes.
Existing refinery sulfur control assumed to include amine scrubbing
unit for sour gas recovery and two-stage Glaus unit with incineration.
FCC regenerator off-gas assumed to have particulate control system
and CO boiler.
Sulfur content of fuel to boilers and fired heaters assumed at 4.5 wt %.
Plot area available for required flue gas desulfurization equipment.
Flue gas ducting uneconomical for distances in excess of 2500 feet.
L-8
-------
SO- concentration in FCC regenerator flue gas after CO boiler assumed
to be similar to that encountered with fossil fuel sources.
Regeneration of spent absorbent and sulfur recovery system assumed
to be centrally located.
This last assumption was made to realize the economies of scale of one
large regeneration system as opposed to each scrubbing location having its own
regeneration system. However, there are some offsetting costs associated with
i
this concept since regenerated and spent absorbent must be transferred to and
from the central system. This requires extra piping and controls. Consequently,
an allowance for interfacing the stationary source scrubbers with the central
regeneration system was included in the capital investment estimates.
b_. Economic Assumptions
The development of capital investment requirements included the following
items:
Other direct costs including site preparation, buildings and
service facilities at 10% of process directs.
Engineering and contractor's fee at 22% of total direct costs.
Owner's indirects including interest during construction, startup and
modifications at 15% of total direct plus engineering costs.
U-9
-------
For the preparation of the off-line economic analysis, various unit
costs were assumed. These unit costs are summarized in Table L-4. The unit
costs incorporated in the refining model, although not exactly these values,
are generally in agreement.
For the off-line comparison, maintenance was assumed at 4% of total
installed cost (TIC). Fixed cost, including depreciation, return on investment,
federal and local taxes and insurance were estimated at 20% of TIC.
L-10
-------
TABLE L-4
UNIT COSTS APPLIED
IN OFF-LINE ECONOMICS
Power, kwh
Fuel (Low Sulfur), 106 Btu
Steam (High Sulfur Fuel), M Ibs
Reducing Gas (Hydrogen), Mscf
Water
Process, M gal
Cooling, M gal
BFW, M gal
Chemicals
Lime, Ton CaO
Limestone, Ton
Magnesium Oxide, Ton
Soda Ash, Ton
Purge Treatment, M gal
C3)
Waste Disposal, Ton '
Labor (FCOP), y
(2)
$/UNIT
0.015
1.25
1.25
0.70
0.40
0.05
0.80
22
19
119
50
1.00
5
65,000
(1) Less fuel credit.
(2) Davy Powergas Process.
(3) Double alkali.
(4) Full coverage operating position.
L-ll
-------
2. CHIYQDA
a. Process Description
The Chiyoda Thoroughbred 101 process for control of SO emissions consists
^^
of absorbing the sulfur oxides from flue gases in a dilute (2-3%) solution of
sulfuric acid. The rich absorbent is then oxidized to produce sulfuric acid
from the sulfurous acid present. A portion of the sulfuric acid stream is
then reacted with limestone to produce a gypsum by-product.
A schematic process flow sheet for the Chiyoda process is shown in
Figure L-l. The flue gas enters a prescrubber where it is cooled to its
adiabatic saturation temperature by contacting with the recirculated water.
!
Most of the dust entering the prescrubber is removed upon contact with the
liquid which is filtered to remove the solid particles before being returned
to the prescrubber. The flue gas then passes to a rectangular, packed absorber
where the sulfur oxides are removed from the gas by a dilute sulfuric acid
liquor stream.
Much of the sulfurous acid formed by the absorption of S0~ in the aqueous
acid stream is oxidized to sulfuric acid in the presence of the ferric oxide
L-12
-------
FIGURE L-l
PROCESS FLOW DIAGRAM
CHIYODA THOROUGHBRED 101
L-l 3
-------
catalyst and the residual oxygen in the flue gas. The chemical reactions
taking place in the liquid phase in the absorber are:
2FeS04
The absorber effluent liquor passes to an oxidizer column which is a
tray tower designed to contact makeup air with the liquor to oxidize any remaining
sulfurous acid by the same reactions.
Some of the dilute sulfuric acid is then sent to a crystallizer where
it is reacted with limestone to produce gypsum by the equation:
CaC0
3 24
The gypsum slurry is then centrifuged and the wet gypsum product is removed
from the system. The centrate, or mother liquor, is then blended with the
remainder of the dilute sulfuric acid stream to redissolve any trace insoluble
calcium compounds before returning to the absorber system.
L-14
-------
A small purge stream of liquor may be required to keep solubles levels
in the system to a minimum. The rate of this purge stream is determined by
the rate at which these solubles may enter the system via particulate matter
in the flue gas stream or corrosion of the system materials.
kj Process Reliability
The Chiyoda Thoroughbred 101 process is commercially proven.' There are
presently 12 licensing agreements for the process in Japan, including -five plaints
which are commissioned and operating satisfactorily. The others are at various
stages of planning and construction. Of the five operating plants, two are on
oil-fired boilers, two are on Glaus sulfur plant tail gases and the other on a
combination of oil-fired boiler;,and Glaus sulfur plant tail gas. At present,
all the Chiyoda licensees are in Japan; consequently, the process has not been
commercially demonstrated in the United States. A demonstration plant with a
capacity equivalent to 23 megawatts is under construction and will be in operation
in Florida in the fall of 1974 to prove the applicability of the process to U.S.
L-15
-------
coals. The system will be operating on a utility boiler of Gulf Power Company.
c. Application to Refinery S0y Control
SO removal of up to 95% is possible with the Chiyoda Thoroughbred 101
process. Particulate removal to very low levels is also possible with the
liquid to gas ratios used in the prescrubber and absorber. High dust loadings
in the feed gas, however, have the undesirable effect of increasing the
possibility of pluggage in the packed absorber and increasing solubles levels
in the circulating liquor and consequently the,impurity level in the by-product
gypsum. Chiyoda therefore recommends that an electrostatic precipitator be
used for dust loadings in excess of one grain per standard cubic foot. Although
most refinery gases which must be treated for SO removal have relatively low
X
dust loadings which can approach one grain per standard cubic foot and higher.
Since, for the purposes of this study, electrostatic precipitators are assumed to
be installed downstream of the FCC regenerator regardless of which desulfurization
process is used, the Chiyoda process carries no economic penalty for requiring
a relatively low dust loading.
L-16
-------
The SO,, content of the flu-id catalytic cracker regeneration gases
should pose no problem for the Chiyoda process. The absorption of S0_ rather
than S02 is actually preferable as the next process step is to oxidize SO-
«
completely to SO- .
ch Capital and Operating Requirements
The capital cost for the gas treating portion of the Chiyoda process
is shown in TableL-5 for a gas handling capacity of 100,000 scfm (wet). For
the development of these costs, it was assumed that the scrubbing system would
be retrofitted to an existing stack and that there is sufficient area to locate
the scrubber so that no unusual structural problems would be encountered.
The estimated annual operating requirements for the same gas handling
equipment are also shown in Table L-5. For the gas scrubbing system there is
little or no difference in capital or operating costs for various SO removal
A
efficiencies in the range of 75-95%. Therefore, within the accuracy of these
estimates, they can be considered appropriate for any removal efficiency in
this range.
L-17
-------
TABLE L-5
CHIYODA THOROUGHBRED 101 PROCESS
ESTIMATED CAPITAL COST AND OPERATING REQUIREMENTS
Gas Side100,000 SCFM
S02 Removal Efficiency 90%
Capital Investment ($M)
Scrubber System 750
Fans, Duct Work and Stack 270
Flue Gas Reheater 60
Process Direct Cost
Other Directs @ 10%
Total Direct Cost
Engineering and Contractor's Fee @ 22%
Subtotal 1,449
Owner's Indirects @ 15% 217
Total Investment 1,666
Operating Requirements
Annual Usage ($M>
Utilities
Electric Power 7.7 x 10 kwh 116
Fuel (Reheat) 138 x 109 Btu 173
Water 60 x 10 gal 50
Total Utilities 339
L-18
-------
Figure L-2 shows how the capital costs developed in Table L_5 for the
base case of 100,000 scfm are extended to the range 30,000 to 200,000 scfm.
Table L-6 shows the development of the capital costs and operating
requirements for the liquor side of the Chiyoda process for a liquor capacity
equivalent to an SO removal rate of 200 Ib-moles/hour. Figure L-3 shows the
X
extension of the capital cost data in Table L-6 to the range of 75 to 200 Ib-moles/hr.
The value of by-product gypsum in the U.S. is probably less than in Japan
because gypsum from natural sources is relatively plentiful and generally con-
sidered superior for plasterboard and Portland cement. However, since there
are potential markets for the synthetic gypsum, it cannot really be considered
a waste salt and the full penalty of landfill cost is also not appropriate.
Consequently, it was assumed the gypsum would be available to any seeker willing
to pay the hauling cost. Therefore, no product credit nor disposal cost was
assigned.
The power costs associated with operating a gypsum production system are
relatively insignificant when compared with the requirements for the gas side.
L-19
-------
6.0 -r
5.0--
vO
o
4.0
c
-------
TABLE L-6
CHIYODA THOROUGHBRED 101 PROCESS
ESTIMATED CAPITAL COST AND OPERATING REQUIREMENTS
Liquor Side200 Ib-mole/hr. SO Removal
Capital Investment ($M)
Material Storage and Feed System
Oxidation and Liquor Handling
Crystallization and Solids Removal
Interfacing Cost
Process Directs
Other Directs @ 10%
Total Directs
Engineering and Contractor's Fee @ 22%
Subtotal
Owner's Indirects @ 15%
Total Investment 12,500
Operating Requirements
Annual Usage ($M)
Labor 3 Shift Positions 195
Utilities
Electric Power $0.015/kwh 20 x 10 kwh
Limestone 86,SOOT 30
Catalyst 15,400 Ib
L-21
-------
25
vO
o
20
c
0)
*J
to
15 -
10 -
100
200
300
400
Capacity, Mols/Hr of SO Removed
FIGURE L-3
CHIYODA ENGINEERING, CAPITAL INVESTMENT
REGENERATION SECTION
L-22
-------
Therefore, no electric power figure is shown in the liquor side operating
costs.
The labor costs associated with operating the gas handling system are
minimal and are usually considered an extension of the boiler operation.
Therefore, operating labor costs are shown only for the operation of the gypsum
production system.
3. DUAL ALKALI AND WET LIME SCRUBBING
The economics for dual alkali and lime scrubbing systems are quite
similar. Therefore, capital and operating cost estimates were developed for
only the dual alkali process and are presented in that section as being
approximately typical (total cost basis) for both types of systems. A discussion
of lime scrubbing is presented in a separate section.
_a_- Process Description
In the dual alkali scrubbing process shown schematically in Figure L-4,
a mixture of sodium hydroxide and sodium sulfite is used to absorb S07 in the
L-23
-------
r
Vacuum \ Waste
Filter I Calcium
Salts
Ca(OH),
FIGURE L-4 DUAL ALKALI SYSTEM
-------
scrubber system according to the equations:
2NaOH + S02 -» Na2S03 4- H20
Na2S03 + S02 + H20 -» 2NaHS03
The absorber effluent is reacted with lime in a controlled environment to
precipitate calcium sulfite and regenerate the sodium value (as sulfite)
which is recycled to the absorber. Some oxidation of sodium sulfite to
sodium sulf ate does occur in the absorber by the equation:
Na2S03 + 1/2 02 -»- Na2S04
and the lime must also.be reacted with sodium sulf ate to produce calcium
sulf ate and active sodium hydroxide. The regeneration equations are:
Ca(OH)2 -> CaSO_ + 2NaOH
NaHS03 + Ca(OH)2 * CaS03 + NaOH
Na2SO, + Ca(OH)2 -> CaSO^ + 2NaOH
The solid calcium sulf ite/sulf ate salts are concentrated in the thickener
and dewatered on a vacuum filter to produce a waste cake containing 30 to 40%
moisture. The process requires a makeup stream of sodium carbonate (or sodium
hydroxide) to replace the sodium value lost in the wet solid waste.
L-25
-------
b. Process Reliability
The technology of sodium scrubbing to remove SO from flue gases has
Xi
been commercially demonstrated on once-through scrubbing systems. However,
regenerating the spent sodium back to an active species for reuse in Che
scrubber system introduces two problems which are not encountered in the
once-through sodium scrubbing scheme. These are: preventing the return of
both soluble and insoluble calcium salts to the scrubber .system in order to
minimize the potential scaling; and regenerating sodium sulfate (which,has
been formed in the scrubber circuit by absorption of SO. or by oxidation of
the sodium sulfite). If the sodium sulfate is not regenerated then it must
be purged from the system resulting in a liquid waste stream and higher sodium
makeup requirements.
These problems have largely been overcome on the pilot plant scale by
various researchers using different modes of operation. However, the proces.0
has not as yet been commercially demonstrated in the United States. Two dual
alkali systems are scheduled for startup in 1974.
L-26
-------
c. Application to Refinery SO Control
^^^"'^"*'^^*^"^^"""^"^^^"^"~
The dual alkali scrubbing process is quite suitable for operation on
refinery flue gases. S02 removal in excess of 95% can be achieved with
capital and operating costs not much higher than for significantly lower
removal efficiencies.
The relatively low dust loadings in refinery flue gases can be readily
handled by the dual alkali system. Even the fluid catalytic cracker regeneration
gases, which have a dust loading of about one grain per standard cubic foot,
are relatively lightly loaded when compared with coal-fired boilers for which
many dual alkali systems have been proposed. Particulate matter, about 99% of
which can be removed from the flue gas in the scrubber system, remains in the
liquor as a slurry and is ultimately removed from the system by the vacuum
filter as a component in the waste sludge.
The presence of SO- in the fluid catalytic cracker regeneration gases
increases the concentration of SO * in the circulating scrubbing solution upon
absorption, thus aggravating the problem of sulfate regeneration described in
the next section. L-27
-------
d. Capital and Operating Requirements
The capital cost for the gas treating portion of the dual alkali system
is shown in Table L-7 for a gas handling capacity of 100,000 scfm (wet). For
the development of these costs, it was assumed that the scrubbing system would
be retrofitted to an existing stack and that there is sufficient area to locate
the scrubber so that no unusual structural problems would be encountered. The
estimated annual operating requirements for the flue gas treatment system are
also shown in Table L-7 There is little or no difference in capital or
operating costs for various SO removal efficiencies in the range 75-95%. There-
fore, these estimated operating requirements can be considered appropriate for
any removal efficiency in this range.
Figure L-5 shows how the capital costs developed in Table L-7 for the
base case of 100,000 scfm are extended to the range 30,000 to 200,000 scfm.
Table1'"8 shows the development of the capital costs and operating
requirements for the liquor side of the dual alkali system for a liquor capacity
equivalent to an SO removal rate of 200 Ib-moles/hr. Figure L-6 shows the
extension of the capital cost data in Table L-8 to the range of 75 to 200 Ib-moles/hr.
L-28
-------
TABLE L-7
DUAL ALKALI PROCESS
ESTIMATED CAPITAL COST AND OPERATING REQUIREMENTS
Gas Side--100,000 SCFM
SO Removal Efficiency 90%
A
Capital Investment ($M)
Scrubber System
Fans, Duct Work, and Stack
Flue Gas Reheater
Process Direct Cost
Other Directs @ 10%
Total Direct Cost
Engineering and Contractor's Fee @ 22%
Subtotal
Owner's Indirects @ 15%
Total Investment 1,358
Operating Requirements
Unit Cost Annual Usage ($M)
Utilities
Electric Power $.015/kwh 2.8 x 106 kwh 42,000
Fuel (Reheat) $1.25/106Btu 50 x 109 Btu 63,000
Water $ .80/103gal 60 x 106 gal 50,000
Total Utilities 155,000
L-29
-------
5.0
NO
o
f-l
4.0
C
§
4-1
tn
3.0 --
2.0 --
1.0
100
200
Capacity, Mscfm
FIGURE L-5
DOUBLE ALKALI, CAPITAL INVESTMENT
SCRUBBING SECTION
L-30
-------
TABLE L-8
DUAL ALKALI PROCESS
ESTIMATED CAPITAL AND OPERATING COSTS
Liquor Side200 Ib-mole/hr S0? Removal
Capital Cost ($M)
Material Storage and Feed Systems
Regeneration System
Sludge Thickening and Filtration
Interfacing Cost
Process Directs
Other Directs @ 10%
Total Directs
Engineering and Contractor's Fee @ 22%
Subtotal
Owner's Indirects @ 15%
Total Investment
1,700
470
770
300
3,240
324
3,564
784
4,348
652
5,000
Operating Usages
Labor
Utilities
Elec. Pwr.
Soda Ash
Lime
Waste Disposal
Unit Cost
Annual Usage
$65,000/Shift Pos. 2 Shift Pos.
,6
$0.015/kwh
$50/Ton
$22/Ton
$5/Ton
1.6 x 10 kwh
2,650 Tons
69,700 Tons
231,000 Tons
($M)
130
24
100
1,533
1,160
L-31
-------
vO
o
c
II
E
9.0 --
8.0 --
7.0
6.0
5.0
4.0
3.0
2.0 ~-
1.0
100 200 300
Capacity, Mols/Hr of SO- Removed
FIGURE L-6
DOUBLE ALKALI, CAPITAL INVESTMENT
REGENERATION SECTION
400
L-32
-------
The power costs associated with operating a regeneration system are
relatively insignificant when compared with the requirements for the gas side.
Therefore, no electric power figure is shown in the liquor side operating
costs.
The labor costs associated with operating the gas handling system are
minimal and are usually considered an extension of the boiler operation. Therefore,
only operating labor is shown for the operation of the regeneration system.
Maintenance costs (at 4% of capital cost) are shown for both the gas and
liquor handling systems.
e> Wet Lime Scrubbing
(1) Process Description
In the wet lime scrubbing process, a lime slurry is contacted with the
flue gases in scrubbing equipment similar to that used in the dual alkali process
to form calcium sulfite by the following reaction:
Ca(OH)2 + S0£ -» CaS03 + H20
The scrubber bottom slurry passes to a sludge dewatering system which consists
of a thickener and vacuum filter. Lime is added to the clarified water which in
L-33
-------
turn is recycled to the scrubber system. A schematic flow diagram of this
process is shown in Figure L-7.
Either lime or limestone may be used for SO,, scrubbing. Although the
materials cost for limestone is less than for lime, there is a combination of
technical advantages to using lime. The reactivity of natural limestone is
variable and unpredictable depending on where it is mined. Furthermore, smaller
stoichiometric quantities of lime are required for given SO removal requirements,
^^
For the purposes of this study, the use of lime only is considered.
(2) Process Reliability
The major question regarding theoperability of lime scrubbing systems
is the potential for scaling and plugging as a result of deposition of solids
on the surfaces of the scrubber due either to sticking of slurry solids or
crystallization of calcium sulfite or sulfate during the reaction of lime with
sox.
A second, but less important, problem is the erosion of process equip-
ment and piping which results from the circulation of slurry materials.
L-34
-------
I
Scrubb«d
Gas
Flue
Gas
By-Passl
I
Flue
Gas
Feed
t-1
CO
Ul
H2O-
Scrubber
1
Feed
Scrubber
Scrubber
Effluent
!-
f
1
Mixing
Tank
<
i
\
R
c,
Reactor
System
1
Make-up
Na2C03
Thickener
Vacuum \ Waste
Filter ] Calcium
Salts
|H2°
T
Holding
Tank
FIGURE L-7 DUAL ALKALI SCRUBBING WITH LIME REGENERATION
-------
Until recently no concensus had been reached regarding the optimal
operating mode for lime/limestone systems as the problems of scaling, plugging
and erosion always arose. However, since April 1973 the SO control system
(lime scrubbing) at Louisville Gas and Electric's Paddy's Run Station No. 6
in Kentucky has been operating satisfactorily with SO removal at about 90%
Jv
and no evidence of scaling, plugging or erosion. The plant operated for
periods up to twelve days. Of the several lime/limestone systems which have
been operated, Paddy's Run appears to offer the most encouragement for the
potential long-range operation of a wet lime scrubbing system.
(3) Applicability to Refinery SO Control
~^^"1 "~ ^^
Despite some claims of up to 98% SO- removal capability with lime
scrubbing, the ability to maintain such high removal rates for extended period
of operation has not been demonstrated and is still questionable.
Since the scrubber system is designed to handle a slurry, dust loads
characteristic oi refinery flue gases including fluid catalytic cracker
regeneration gas would be expected to pose no problem. These solids would be
removed from the system along with the by-product waste sludge.
L-36
-------
The major question regarding the operability of lime scrubbing systems
is the potential for scaling and plugging of the scrubber system. The process
has been piloted by many people and there has been no concensus as to the
optimum operation.
It is anticipated that in a refinery, several gas treating units
4f
(scrubbers) will be located near the emissions sources and the sulfur-rich
liquor would be piped to a common liquor handling or treatment facility. Since
slurries must be transported'between the gas-treatment and liquor handling
systems to and from the scrubbers, a serious turndown problem arises. The
solids must be maintained in suspension by keeping a minimum velocity in
slurry pipelines. However, when several scrubbers are down, the flow through the
header will decrease below this minimum. Therefore, an additional flow, must
be circulated and another pipeline must be provided to carry the extra flow
back to the liquor system. This results in extra power consumption for pumping
and additional capital investment for installation of long pipelines. Further-
more, the main headers must be larger than would otherwise be necessary because
they must carry the recirculating slurry in addition to the primary flow.
L-37
-------
SO, in the fluid catalytic cracker regeneration gases will result in
a waste solid relatively rich in calcium sulfate which is no less environmentally
acceptable. Process-wise, higher sulfate levels in the scrubber circuit are
of no concern.
4. MAGNESIA SCRUBBING
a. Process Description
The MagOx process, developed by Chemical Construction Company and Basic
Chemicals, removes sulfur oxides from flue gases by scrubbing with a recirculating
slurry consisting of magnesia crystals and some insoluble particulates. Better
than 90% removal efficiency of S02 has been demonstrated at Boston Edison using
(8)
this process. The major by-product of the magnesium oxide scrubbing process
is a dilute (12-16%) S0? gas stream which is usually converted into sulfuric acid.
The overall process is divided into the following operations:
1. S0_ absorption
2. Slurry processing
a. Contamination control
b. Hydrate conversion
3. Dewatering
L-38
-------
4. Drying
5. Calcining
6. Slurry makeup
7. Sulfuric acid production
The manufacture of sulfuric acid is well known technology; therefore, this
process is not described in detail. It is, however, included in the process
<
i i
flow diagram.
The process chemistry for Steps 1, 4 and 5 above is given below.
Absorption
Main Reactions
MgO + S02 + 3H20 -
MgO + S02 4- 6H2
-------
Drying
Main Reactions
3H90 * MgSO + 3H00
-» L j L
MgS03-6H20 £ MgS03 + 6H20
MgS04'7H20 A MgS04 + 7H20
Side Reaction
MgS03 + 1/2 02 £ MgS04
Regeneration
MgSO.- + MgO + S02
MgS04 + 1/2 C + MgO + 1/2 C02 + S02
(1) S02 Absorption
The flue gas enters the venturi absorber as shown in Figure I..-8. There
it is contacted counter-currently with the recycled slurry containing magnesium
oxide (MgO), magnesium sulfite (MgSO-) and magnesium sulfate (MgSO,). The slurry
also contains particulates. As shown in the process chemistry, sulfur dioxide
is absorbed into the slurry by magnesium oxide to form magnesium sulfite and some
L-40
-------
Figure JS Fl<>w Diagram-
Magnesia Slurry Scrubbing-Regeneration
-------
magnesium bisulfite. To a lesser degree, other reactions occur between the
flue gas and the magnesium compounds in the recycled slurry, including reactions
producing magnesium sulfate.
(2) Slurry Processing
The slurry processing operation can be subdivided into two stages:
contamination control and hydrate conversion.
Contamination Control
When this process is applied to oil-fired sources which generate a
low particulate flue gas (0.0228 gr/scfd was measured at the Boston Edison
(8)
pilot plant based on #6 fuel oil) , separate particulate removal is not
required. On coal-fired sources, separate particulate scrubber and ash pond
or electrostatic precipitators are employed to reduce the particulate loading
before the flue gas enters the absorber. Even with oil-fired systems, there
will be some buildup of insoluble particulates and soluble contaminant in. the
system. Some means of purging the system of these solids must be provided.
With oil firing, the buildup of insolubles is small since there are unavoidable
losses of both particulates and magnesium solids in the process of drying, cal-
L-42
-------
cining and conveying solids within the plant.
However, because of the regenerative and cyclic nature of the magnesium
oxide scrubbing process, it is necessary to minimize the amount of contaminants
which build up in the sulfur dioxide scrubbing loop.
Both soluble and insoluble impurities build up in the sulfur dioxide
scrubber loop. Soluble impurities enter the system in the makeup water,
principally, and to a lesser degree with makeup MgO. The major soluble con-
taminants expected are calcium oxide (CaO), sulfate ion (SO, ) and chloride
ion (Cl~).
The major source of insoluble contaminants is fly ash. For flue gas
from oil-fired units, the rate of fly ash addition is low. Even so, the fly
ash mass rate of addition to the scrubber loop is greater than the addition
rate of soluble contaminants by a factor of about 200 for oil-fired sources.
One method of contamination control is to react a purge stream from the
recirculating slurry with sulfur dioxide in a solubilizing tank. Here the magnesium
i
compounds of sulfite and sulfate would be solubilized followed by filtration to
remove fly ash as a cake. The magnesium compounds in the filtrate can be
L-43
-------
precipitated by adding MgO to the filtrate in a separate reaction vessel. By
filtration, the magnesium solids can be recovered and returned to the system,
with the contaminated filtrate discarded to an evaporation pond.
Hydrate Conversion
Reported pilot plant data for MgO slurry scrubbing indicate that
MgSO -3H_0 can be obtained from the hexahydrate by thermal conversion. In
J £*
the process flow diagram, the particular sequence of size screening, thermal
conversion, dewatering and drying was chosen because:
1. Crystals of the hexahydrate require more heat for drying than
crystals of the trihydrate.
2. Trihydrate crystals are smaller than hexahydrate crystals and
are more difficult to dewater.
3. Net heat savings can result from thermally converting crystals
in a thickened slurry before drying. Thickened slurries have
the fastest conversion rates and require less sensible heat.
L-44
-------
Returning to Figure L-8, a bleed stream of the absorbent slurry is with-
drawn for regeneration of magnesium sulfite and magnesium sulfate to magnesium
- \ !.
ojd.de. To separate the larger magnesium sulfate hexahydrate crystals in a
thickened slurry, wet screens are utilized, The return stream to the scrubber
loop consists of a dilute slurry containing the smaller crystals. These smaller
crystals can serve as nuclei fpr further crystal growth in the scrubber loop.
A thickened slurry of about 40% solids from the wet screens is fed to a thermal
conversion tank where heat £s sidded to conyerif JlgSO -6H 0 to MgSO -3HLO.
(3j Dewatering
The slurry stream from the thermal conversion tank containing the
hydrated magnesium crystals, both as a slurry and as a saturated solution, is
discharged to a continuous centrifuge. There, partial dewatering produces a
cake containing a mixture of crystals of MgS03'3H2Q, MgS03-6H20, MgS04'7H20 and
unreacted MgO. Hovever, during the thermal conversion treatment, most of the
sulfite crystals convert to the trihydrate form. The clear, saturated, centrate
liquor is returned to the main recireulating slurry line. The solids cake,
containing about 15% water, is conveyed to a fluid bed dryer.
L-45
-------
lit! Drying
In a separate combustion chamber, fuel oil is burned with a minimum of
excess air and fed to a fluid bed dryer. By direct contact the drying gas
vaporizes both the bound moisture (water of hydration) and the remaining free.
moisture in the solids feed under non-oxidizing conditions to give an essentially
anhydrous solids product (less than 3% moisture). About one-third of the total
exhaust, gas from the dryer is recycled to the combustion chamber to minimize
heat losses and to increase the superficial gas velocity in the dryer.
The flue gas from the dryer contains particles of magnesium and fly ash
which must be removed before being sent to the stack. For the exhaust temper:tui
of 400°F, a cyclone and bag filter combination can be used to return these
crystals co the dryer product conveyor. The cleaned dryer flue gas is combined
with the outlet flue gas from the SO- absorber.
JjJ? Calcining
The crystals from the dryer are fed via conveyor to a fluid bed calciner
where chey ar^ contacted with a hot flue gas to regenerated MgO, The flue ga,
is generated by direct combustion of fuel oil with 5% excess air MgS00 is
L-46
-------
converted directly to MgO, and MgSO, is converted to MgO by feeding coke to the
calciner along with the dried crystal feed. Typically, calciner feed crystals
contain 5-10% MgSO,, the remainder being essentially all MgSO,..
Off-gas from the calciner contains 12-16% SCL by volume which is
liberated from MgO regeneration. The S0_-rich flue gas from the calciner is
sent to the sulfuric acid plant where 98% H-SO, is made. (Production of 98%
concentrated sulfuric acid was chosen for this process.)
the flue gas contains a significant amount of magnesium crystals which
must be collected. However, due to the high flue gas exit temperature of 1600°F,
a bag filter cannot be used without first cooling the flue gas. Therefore, a
T
hot cyclone is used primarily on the flue gas followed by a heat recovery unit
which lowers the flue gas temperature to 700°F. If instead the flue gas
temperature is lowered to the proper operating range for a bag filter of 425-500°F
at the heat recovery unit, there would be a chance of sulfuric acid mist con-
densation in the bag filter. Although this is only a remote chance, air is added
between the waste heat boiler and the bag filter to reduce the flue gas temperature
from 700°F to a temperature suitable for bag filter operation.
L-47
-------
Slurry Makeup
The regenerated MgO crystals from the calciner are conveyed to a-makeup
tank where they are re-slurried along with fresh MgO makeup crystals which are
added to replace miscellaneous magnesium losses throughout the system. A bleed
stream of recycle slurry from the venturi scrubber loop is used as liquor in
the makeup tank and the new slurry is returned to the absorption system.
(J) _ Sulfuric Acid Production
Most of the more recent sulfuric acid plant designs utilize the contact
process in which the following sequence takes place:
a. The generation of a sulfur-dioxide-rich gas from an appropriate
raw material.
b. Cooling, purification and drying of the gas.
c. Reheating of the gas to the proper temperature for conversion
to sulfur trioxide (SO,).
d. Catalytic oxidation of SO- to SO.,.
e. Cooling of the SO--containing gas.
f. Production of sulfuric acid by absorption of SO in concentrated
sulfuric acid.
The hot fJue gas from the calciner is fed to the sulfuric acid plant after
cleansing by the bag filter. Utilizing a bag filter to clean the flue gas instead
of a wet scrubber is referred to as a "dry" system in the sulfuric acid production
process. One advantage of the dry system is that it cleans the calciner off-gas
L-48
-------
without lowering its temperature. This reduces the amount of reheat necessary
to increase the flue gas temperature to 830°F as required by the converter in
the sulfuric acid process. A second advantage is that the moisture content of
the feed gas must be below the mole ratio of 1.11, HLOiSC^ required to make 98%
H-SO,. If the water content of the gas is below 4.4 wt. % (which corresponds to
the proper ratio of tLO to SO- for this flue gas), additional water can be added
at the sulfuric acid plant to insure the proper ratio. In a "dry" system this
is possible; in a "wet" system a more difficult water removal step would have to
be implemented in the sulfuric acid plant.
Air must be bled into an S02-containing flue gas stream before being fed
to a sulfuric acid unit to obtain an O-iSO- mole ratio of 1.4. This addition
t
lowers the S0? percent in the gas stream but it is necessary to obtain efficient
conversion of S02 to S0~. On this basis, the percent S02 in the flue gas from
the calciner is roughly 10% lower than the percent SO in the off-gas from a
conventional sulfur burner used to generate feed gas for the sulfuric acid process.
L-49
-------
Another problem that sulfuric acid plants must be concerned with is their
gaseous sulfur pollutants emitted into the atmosphere. EPA emission standards
for sulfuric acid plants allow a maximum of 4.0 lbs-|S02/ton and 0.15 i^SO.mist
per ton H2S04 emissions. This translates to a minimum of 99.7% required con-
version of inlet S02 to H^SO, in the sulfuric acid plant. By recycling tail
( i
gas from the sulfuric acid plant to the stack gas entering the venturi absorber,
i
an overall efficiency of the sulfuric acid process greater than 99.7% can be
obtained.
b. Process Reliability
Good operating results from actual tests that have been performed on the
magnesium oxide scrubbing process are minimal. To date, no commercial units have
been built utilizing this process, although large-scale demonstration units at
both utility plant and industrial sites have been operated. Our concensus, based
on available data, is that:
The process is feasible.
There are many variations of the process, giving it the flexibility
required to meet a wide variety of commercial needs.
L-50
-------
All of the bugs' have not been worked out for any of these processes.
The processes that have been attempted on a demonstration scale have
not incorporated the best possible technolpgy for some of the operations
characterizing the overall process.
The economics of this process depend on the ability to utilize a
dilute (12-16%) byproduct gas stream of sulfur dioxide.
More demonstration tests are being conducted to develop basic design
data and operating experience.
Development work on the magnesium oxide slurry scrubbing process has been
performed by Chemico-Basic companies and the Babcock & Wilcox Company in the
United States, Russia and Japan. In addition, the Grillo-Werke Company of the
United States has tested the magnesium oxide-manganese dioxide slurry scrubbing
variation of the process.
Although data are not available for filtration of hexahydrate crystals,
vendors indicate that a moisture content of 10-20% could be expected compared
with about 5% moisture after centrifugation.
In the venturi scrubbing and recycle loop section of this process, suitable
demonstrations have been made at a corresponding high degree of reliability.
Design provisions have to be made to prevent problems of corrosion and erosion
L-51
-------
associated with low pH slurry scrubbing. Also, spare pumps can be provided to
circumvent shutdowns and minimize problems due to possible slurry settling in
the lines. Proper wash facilities can be provided for slurry lines.
The slurry treatment process mentioned previously has not been demonstrated
in its entirety, although experts generally agree that this arrangement is
feasible. Chemico-Basic has shown satisfactory performance in centri-fuging
a magnesium sulfite hexahydrate slurry at their 150 megawatt demonstration
unit at the Boston Edison Company. Similar tests 'for the trihydrate crystals
have not been performed.
Pilot plant results have not been obtained for thermal conversion of
magnesium sulfite hexahydrate crystals to the trihydrate form. Kinetics indicate
that conversion should go rapidly and completely under proper conditions.
One area of slurry treatment that is lacking in data is treatment of a
bleed stream from the absorber loop for contamination control. The nature of
this problem and possible solutions have been described earlier in this section.
This could be a critical area for some variations of the magnesium scrubbing
process utilizing a high fly ash loading or a mineral-rich makeup water stream.
L-52
-------
Chemico-Basic has demonstrated rotary dryer performance where the feed
material was predominantly a magnesium sulfite hexahydrate cake. The dryer
product contained 3% moisture when operated within a temperature range of
600-800°F.7 Reports indicate considerable difficulties associated with the
co-current, rotary dryer operation. One type of problem is associated with the
excessive dust entrainment from the system. This problem was primarily due to
poor control of gas velocity through the dryer. The more serious problem
associated with the rotary dryer involved agglomeration of dryer feed cake and
insufficient drying within these masses. Downtime in the dryer was significant,
causing the dryer to be the bottleneck in the process. It has been suggested
that either a countercurrent dryer or a fluid bed dryer be utilized. The key
to making this process work would be to produce a uniform centrifuge cake with
low water content; to introduce the feed in a discrete, steady manner; to maintain
good control of the superficial gas velocity through the fluid bed; and to
incorporate a hignly efficient dust removal system.
L-53
-------
As in the drying operation, Chemico has also demonstrated rotary calciner
operation. Nearly complete conversion was obtained between 1600-2000°F with the
i
addition of coke. ^" It should be mentioned, however, that problems were
/
i
initially encountered in calcining the product magnesium oxide at excessive
temperatures. The product was burned and rendered inactive. Satisfactory
performance has been demonstrated in Japan with fluid bed calciners. These
results were obtained at 1800°F without the addition of reducing coke. The
process (e.g., lower temperatures) should proceed even better with the addition
of coke.
<-' Application to Refinery SO Control
jL
There are few special provisions associated with the magnesium oxide
slurry scrubbing process that would be necessary for its adaptation to a refinery.
The amenability of this process to a refinery can be considered under three
categories:
a) Space Requirement of Process
b) Degree of Centralization of Process
c) Process Dependence on Flue Gas Composition
L-54
-------
At a refinery site there may be many sources of sizeable flue gas
emissions in need of sulfur controls. If it is impractical, infeasible or
impossible to duct two or more of these outlet flues to a common scrubber unit,
separate scrubbers would have to be installed at each flue gas source.
The amount of space required for the regeneration section of the magnesium
process would depend on the degree to which this process is centralized. If each
scrubber within the refinery has its own slurry treatment and calcination unit,
this case would represent the maximum space requirement. If one centralized
slurry treatment system, drying and calcination unit is utilized, this would
represent the best case with the minimum space requirement for this process.
The applicability of this process to a refinery would depend on the
refinery's ability to utilize the dilute sulfur dioxide byproduct gas stream.
The refinery would either have to be capable of selling the sulfur dioxide in the
gas stream to a neighboring plant producing a sulfur product, or it would have
to build its own sulfuric acid, elemental sulfur, or sulfur dioxide manufacturing
plant. The remaining alternative would be for the refinery to truck the dried
magnesium sulfite/sulfate crystals to a nearby sulfur-utilizing plant. A calcination
L-55
-------
unit for the liberation of the sulfur dioxide in a flue gas stream could be built
at this plant. Regenerated magnesium oxide crystals could then be trucked back
to the refinery for addition to the venturi scrubbers which would conceivably be
spread out over the refinery.
The applicability of the magnesium scrubbing process to a refinery will
also depend on the level of sulfur dioxide and particulates in the inlet flue gas.
There are no data to indicate that varied sulfur dioxide levels in the inlet flue
would be difficult to remove by magnesium oxide slurry scrubbing. If, however,
a high particulate loading exists in the inlet flue, as it would in the flue gas
from a coal-fired boiler or from a fluidized catalytic cracker unit (FCC),
then a separate particulate removal device would be necessary upstream of the
sulfur dioxide venturi absorber. Either an electrostatic precipitator or a
separate particulate scrubber (preferable) could be installed to remove the
particulates. If a wet scrubber is used, an ash pond would be necessary for the
particulate that is removed from the flue gas. If this were not feasible, it
would be necessary to provide for disposal of the fly ash.
L-56
-------
The potentially high concentrations of SO in FCC catalyst regenerator
gas would result in higher magnesium sulfate concentrations in the circulating
slurry. This is less of a problem with the magnesium system, since magnesium
sulfate can be regenerated to magnesium oxide as previously explained.
cL Capital and Operating Requirements
Estimated capital investment and operating requirements for the
Mag-Ox process are given in Tables L-9 and L-10. The first table presents
the costs associated with the scrubber section of the process and the second
table contains costs for the combined regeneration section and sulfuric acid
plant. Investment as a function of capacity for scrubbing and regeneration
is presented in Figures L-9 and L-10.
The operating requirements in Table L-9 do not take account of provisions
for slurry treatment for contamination control or for any specific type of
particulate removal devices. (Some particulates are removed by the venturi
absorber.) In addition, it is assumed that regeneration occurs on-site.
Fuel requirements are based on 50°F of flue gas reheat. This is in
addition to the temperature rise due to compression of the flue gas through
the induced draft fan downstream of the scrubber, and the temperature rise
due to dryer off-gas addition to the scrubber flue gas.
L-57
-------
TABLE L-9
CAPITAL & OPERATING REQUIREMENTS
Magnesium Oxide Scrubbing System
Basis 100,000 scfm Flue Gas
2,200 ppm SO
90% SO. Removal
8,000 Operating Hours/Year
Estimated Capital Investment
Scrubber System
Fan, Duct Work and Stack
Gas Reheat System
Process Directs
Other Directs @ 10%
Total Directs
Engineering and Contractor's Fee @ 22%
Subtotal
Owner's Indirects @ 15%
Total Investment
Annual Operating Requirements
Labor
Utilities:
Fuel
Usage
4 Man Years
1029 BTU/M scf
Unit Cost
Annual
Cost(SM)
Process Wtr 68x10 gal/yr/105scfm
Povar
Total Utilities
6.25 kw/M scfm
$16,000/man yr 64.0
$1.25/MM BTU
$0.40/M gal
$0.015/kwh
63.0
27.2
75.0
165.2
L-58
-------
TABLE L-10
CAPITAL & OPERATING REQUIREMENTS
Magnesium Oxide Regeneration System
Basis: 200 // Moles SO Treated/Hr
(240 Ton/Day of 98% HS0)
Estimated Capital Investment
, MgO Regeneration (Dewatering, Drying & Calcining)
Sulfuric Acid Plant (Contact Unit & Storage)
Purge Treatment System
Allowance for Interfacing
Process Directs
Other Directs
Total Directs
Engineering and Contractor's Fee @ 22%
Subtotal
Owner's Indirect @ 15%
Total Investment Cost
8395
Annual Operating Requirements
H2S04 Plant + Regeneration
System Variable Costs:
Usaee
Labor 12 Man Years
Utilities:
Fuel 47.5 gal/T acid
Water-Boiler Feed 181 gal/T acid
-Cooling
-Process
Power
Total Utilities
MgO
Coke
Catalyst
Unit Cost
Annual
Cost($M)
$16,000/ManYr 192.00
17.7 Mgal/T acid
4.2 gal/T acid
50 kwh/T acid
8.62 T/103T acid
6.06 T/103T acid
3.78 gal/103T acid
$1.25/MMBtu
$0.;80/Mgal
$0.05/Mgal
$0.40/Mgal
$0.015/kwh
$120/T
$ 30/T
$6.62/gal
647.42
11.30
69.32
0.13
58.75
786.92
81.03
14.24
1.96
(1) As 100%
L-59
-------
5.0--
4.0
(A
V
3.0 --
2.0 --
1.0
100
Capacity, Mscfm
FIGURE L-9
MAGOX (CHEMICO) CAPITAL INVESTMENT
SCRUBBING SECTION
200
L-60
-------
\o
o
(0
V
>
c
14.0
13.0
12.0 --
11.0 ._
10.0 --
9.0 --
8.0 --
7.0
6.0 -
5.0 -
4.0 -
3.0
100
200
300
400
Capacity, Mols/Hr of'SO,, Removed
FIGURE L-10
MAGOX (CHEMICO) CAPITAL 1IWESTMENT
REGENERATION SECTION
L-61
-------
j, SHELL/UOP
a. Process Description
The Shell flue gas desulfurization process is based on the reactivity of
sulfur oxides with CuO. Fixed bed reactors containing a dry acceptor consisting
of CuO-on-alumina are utilized for S0_ adsorbtion. In situ 'regeneration by
reducing gas is carried out at approximately the same temperature as S0_
capture. The process was developed by Shell International Petroleum Mij at
The Hague, Netherlands, and is licensed through Universal Oil Products Company.
The principal reaction between SO- in the flue gas and the copper activated
alumina adsorbent is:
SO- + 1/2 0. + CuO -> CuSO.
2. L k
The bulk of the accepted sulfur is released from the copper sulfate in the form
of S02 upon regeneration with reducing agents such as hydrogen or carbon monoxide.
With hydrogen, the overall regeneration reaction is
+ 2H + Cu + SO+ 2H0.
L-62
-------
In addition, any unreacted CuO is reduced to copper. Some Cu?S is also formed.
During the initial stages of the acceptance period, the Cu produced during
5*.
regeneration is oxidized according to the following reaction:
Cu + 1/2 02 -* CuO.
In addition, the Cu«S present in the regenerated acceptor will oxidize as follows:
Cu0S + 2-1/2 Cu0 -» CuO + CuSO.
i 2 4
'. >
which will give the acceptor a based load of sulfur.
These oxidation reactions are exothermic and cause a considerable amount
of heat to be released during the initial stages of the acceptance period.
This results in a temperature peak which quickly travels through the reactor.
The temperature peak is held below a predetermined level to protect the acceptor
against a gradual loss of activity resulting from the growth of copper crystallites
and possibly recrystallization of the active alumina. This is achieved by careful
choice of the acceptor's copper content and of the reactor operating conditions.
Some of the more important process requirements are:
Reactor inlet temperature between 700-800°F.
L-63
-------
Oxidizing conditions at the emission point to reactivate
the regenerated acceptor.
A source of reducing gas, preferably hydrogen.
Process advantages include:
No loss of thermal buoyancy in the treated gas.
No waste products since the process is dry and SO^ is
recovered as elemental sulfur.
Minimum process water requirements.
Low operating labor.
A simplified process flow schematic is shown in Figure L-ll. Flue gas frpm
the boiler passes through a rotary-type heat exchanger and is preheated by
exchange with treated gas from the on-stream acceptor. Additional preheat is
supplied by an indirectly fired trim heater, which supplies about 60°F of preheat.
The 750°F flue gas passes vertically upwards through the on-stream reactor. The
reactor internals are of "parallel passage1* design with the acceptor contained
between layers of wire gauze with spaces provided between packages for flue gas
flow. With this design, the flue gas flows along the surface of the acceptor
L-64
-------
TREATED
FLUE GAS
OPEN
BYPASS
FLUE GAS
TO REACTORS
REGENERATION GAS
ABSORBER
OFF-GAS
ACCEPTANCE TIME: 170 MIN.
BOILER
FEED WATER
EXCESS
STRIPPED
WATER
SOjTO
CLAUS UNIT
REGENERATION
OFF-GAS,400°C
re L-li Simplified process flow schcrr.e of SFGD
-------
packages and not through the acceptor material; thus plugging of the acceptor
by participates is avoided. The gas residence time in the thermal passages
is about one-third of a second.
For convenience in fabrication and handling, a number of layers of
acceptor packages appropriately spaced are placed 'in a container to form a
module. A given reactor contains several such modules depending on the through-
put and SO2 removal requirements.
The sulfur dioxide will be accepted until the loading of the acceptor
has proceeded to the point where the remaining unloaded acceptor at the exit
end of the reactor has become too small to insure complete S0~ removal. At
this point, S0» will start to slip through. When the cumulative slip of the
SO. reaches a value of 10% of the inlet concentration, purification of the gas
input stream will have dropped to 90% and generation of the reactor is required.
To regenerate the spent reactors, the flue gas stream is diverted to the
freshly regenerated reactor and reducing gas is simultaneously admitted to the
spent reactor. The switching of reactors is performed automatically with the
L-66
-------
use of sequential control valves, thereby reducing labor requirements. The
regeneration off-gas consisting of SCL, H-O and diluent leaves the reactor
and passes through a waste heat boiler before entering the quench column.
In the quench column, the regeneration gas is cooled and saturated before
entering the S0_ adsorber. In the adsorber, the regeneration gas is scrubbed
with water to remove SO^ before being vented, possibly to a fuel gas system.
The water is removed from the adsorber and steam stripped to obtain concentrated
S0_. The stripped water is returned to the top of the adsorber. The concen-
trated S0_ from the stripper can be sent to a contact unit to produce concen-
trated sulfuric acid or to a direct reduction process (Glaus unit) to produce
elemental sulfur.
In addition to the S02 product, the process has two other effluents.
One of these is the stripped regeneration off-gases which are vented or can be
returned to the boiler for recovery of combustion heat. The other stream is
excess stripped water produced during regeneration which contains some dissolved
SO . This purge stream can be sent to the boiler feed water treatment system
to reduce raw water requirements. -
-------
j^ Process Reliability
Shell began development work on the SFGD process about ten years ago.
In order to prove the feasibility of the parallel passage reactor concept, a
demonstration unit was erected in 1967 in the Shell refinery at Pernis, The
Netherlands. The Pernis unit handled 600 scfm of flue gas containing 0.1-0.3
volume percent S02. The flue gas was isokinetically sampled from the main flue
gas duct of a furnace fired with high sulfur fuel oil. A total of about 20,000
hours of testing was accomplished on this unit. The results of these tests
convinced Shell that an acceptor based on a reinforced alumina support will
have stable activity in excess of 8000 cycles or about 1-1/2 years of service
life. The Pernis unit is still being used from time to time to test improved
versions of the Cu-on-alumina acceptor.
After four years of successful operation of the Pernis unit, a decision
was made to erect a full-scale unit at the Yokkaichi refinery of Showa Yokkaichi
Sekiyu (SYS), Japan. The SFGD unit for SYS is designed to effect 90% desulfurizatiou
L-68
-------
on 80,000 scfm (about 40 Mw), which is the combined flow of flue gas from an
oil-fired boiler and tail gas from a Claus unit, the aggregate flow containing
2500 ppm SCL* This unit was started up in the summer of 1973 and since then
has only treated flue gas from the boiler since operation of the Claus unit
has been discontinued for reasons not associated with the SFGD process. Based
on limited information, the process availability appears to have been satisfactory.
As indicated in the process flow schematic, the reactor beds are auto-
matically cycled from acceptor mode to regeneration mode by the use of sequential
timers and motor-activated butterfly valves. To prevent leakage of reducing gas
into the on-line reactor, special large, tight shut-off flue gas valves are
required. In addition, pressure surges caused by reactor switching can influence
boiler operation and are therefore undesirable. The effect of these surges is
minimized by the use of an "open bypass" which continuously recycles a small
(14)
quantity of treated flue gas. According to recent papers given at the AIChE
National Meeting in Tulsa, operations at SYS have confirmed the operability of
the sequential switching and bypass system.
L-69
-------
In using a fixed bed reactor for treatment of flue gas, one must
consider the potential plugging problem associated with gas-borne fly ash.
With the operation of the full-scale unit in Japan, this concern has been
removed for oil-fired sources, which generate particulate in the range of
0.02-0.12 gr/scf of flue gas. Furthermore, UOP indicate that a conservative
design figure for allowable, inlet dust loading of 0.1 grains/scf.
In regard to applying SFGD to coal-fired boilers, a dummy parallel
passage reactor was tested on a coal-fired boiler in The Netherlands to deter-
mine resistance to fouling by the unfiltered flue gas. No deposits were ob-
served during a five-day duration run. Currently, tests on a coal-fired boiler
are being performed at Tampa Electric with a single reactor containing a CuO
acceptor. The unit is pracessing a slipstream from TECO's Big Bend Unit No. 1.
The capacity of the unit is approximately three megawatts and is designed for a
cycle time of 60 minutes to achieve 90% desulfurization. The objective of these
tests is to demonstrate the applicability of this process to coal-fired sources.
L-70
-------
±. Application to Refinery SO Control
""' "" """" " "" " A "
The SFGD process is particularly suited for SO control in a refinery
«»
t
because:
It produces a concentrated S02 gas stream which can be combined
with the hydrogen sulfide from the amine unit and treated in a
conventional Claus sulfur plant.
The operation of the system is highly automated and labor
requirements are minimal.
The adsorbent accepts SO- and SO- equally well? consequently
the system can be applied to the fluid catalytic cracker
regenerator with no operating cost penalty.
As mentioned in an earlier section, the inlet temperature to the fixed
bed reactor must be about 750°F. A refinery furnace or process heater designed
to achieve reasonable thermal efficiency will normally have stack temperatures
in the range of 400-500°F. Consequently, in a retrofit situation, preheating of
the gas is required before entering the reactors. In order to minimize fuel
requirements, a rotating heat exchanger (Ljunjstrom) is utilized to recover the
heat in the treated gas by exchange with the incoming gas. A typical example of
L-71
-------
(15)
this arrangement is shown in Figure L-12. According to UOP , the inclusion
i i
of a heat exchange system increases the overall capital investment by about 15%.
In the refinery situation, supplying the required reducing gas is less
difficult than for a utility boiler since hydrogen must be produced for other
units within the refinery. Consequently, the cost of obtaining hydrogen can be
assumed as incremental capital and operating cost for a reforming unit.
A refinery complex contains an atmospheric crude separation unit, numerous
processing units and usually a central boiler facility, all of which contain
stationary emission sources. In applying the Shell process to a typical refinery
layout, it was assumed that several fixed bed acceptors would be located within
the refinery to accept flue gas from several nearby emission sources.
The alternative of placing individual reactors on each source becomes prohibitively
expensive since the major capital investment for this process is in the acceptor
section. The reducing gas is heated in a central location and distributed to
the various acceptors. Regeneration gas from the acceptors is treated in a
central absorption/stripping unit and the concentrated sulfur dioxide stream
L-72
-------
-vj
REGENERATION
GAS
FLUE GAS
FROM OUCT
UP/DOWNSTREAM
PHECIPITATOR
AIR
FIGURE L-12
SIMPLIFIED FLOW SCHEME OP SFGD DEMONSTRATION UNIT
FOR COAL1 FIRED UTILITY BOILER! ATiTAMPA ELECTRIC, FLORIDA
-------
leaving the stripper is combined with the sour gas stream from the amine unit
and processed in a conventional Claus unit.
iL Capital and Operating Requirements
i ,
Typical capital investment costs for the acceptor section of a Shell flue
i
gas desulfurization unit are shown in Table L-ll. The estimated costs are based
on a treatment capacity of 200,000 scfm and an SO- removal efficiency of 90%.
Because the 'major portion of the capital investment for this process is associated
with the acceptor system, a larger basic module size was used. This approach
results in a savings in capital investment which more than pays for the additional
duct work necessary for collection of the flue gas. Furthermore, the cost of a
rotary-type heat exchanger was included to reduce annual fuel consumption required
for preheat of the flue gases. Figure L-13 presents the capital costs for systems
ranging in size from 30,000 scfm to 200,000 scfm.
Generalized costs for an S0? recovery and reduction unit were developed and
are shown in Table L-12. The cost estimates are based on an S0~ recovery rate of
200 Ib-mols/hr or approximately 25,000 tons of elemental sulfur per year. In
L-74
-------
TABLE L-ll
CAPITAL & OPERATING COST ESTIMATE
Shell Flue Gas Desulfurization
Acceptor System
Basis: 200,000 scfm
90% S02 Removal
Capital Investment ($M)
Acceptor Section (Incl. Ton and Stacks)
Rotary Heat Exchanger (Pre-heater)
Gas Collection Ducts
Process Directs
Other Directs @ 10%
Total Directs
Engineering and Contractor's Fee @ 22%
Subtotal
Owner's Indirects @ 15%
Total Investment
Annual Operating Requirements
Category
Unit Cost
Quantity
3100
500
200
3800
380
4180
920
5100
765
5865
Annual Cost($M)
$0.015/kwh
Labor
Utilities
Power
Fuel
Total Utilities
Catalyst and Chemicals $29/Ton of S
9.6x10 kwh
$1.25/10 BTU 114.4x10 BTU
25,600 Ton
144
143
287
715
L-75
-------
C
0)
4J
tn
c
M
11.0 __
10.0 --
9-0 --
8.0 --
7.0 --
6.0 --
5.0 --
4.0 "
3.0
100
200
300
Capacity, Mscfm
FIGURE L-13
SHELLAJOP , CAPITAL INVESTMENT
ACCEPTOR SECTION
400
L-76
-------
TABLE L-12
CAPITAL & OPERATING COST ESTIMATE
Shell Flue Gas Desulfurization
Regeneration/Reduction Section
Basis: 200 # Moles/Hr of SO,, Treated
(1)
Capital Investment
S0» Recovery Section
Allowance for Interfacing
Process Directs
Other Directs @ 10%
Total Directs '
Engineering and Contractors Fee @ 22%
Turn Key Glaus Plant
Subtotal
Owner's Indirects @ 15%
Total Investment
Annual Operating Requirements
Category Unit Cost
Labor
H- Reducing Gas
Utilities
Power
BFW
Cooling Water
Steam
Total Utilities
Glaus Aunt Variable Cost $12.50/T of S
$65,000/Shift Pos.
$0.70/M scf
$0.015/kwh
$0.80/M gal
$0.05/M gal
$1.25/M Ibs
(2)
Quantity
1.5
1.75xl05M scf
5.35xl06 kwh
7500 M gal
S.OxlO4 M gal
7.17xl05 M Ib
25,600
2790
300
3090
309
3399
748
1500
5647
848
6495
Annual
Cost($M)
98
1225
80
6
4
930
330
(1) 76.8 Tons of Sulfur/Day
(2) Full Coverage Operating Position
L-77
-------
developing the capital investment costs, it was assumed that a central SO-
recovery system would be located in the vicinity of the refinery sulfur plant
(Glaus unit). This requires a main regeneration gas header to and from the
various acceptor reactors within the refinery complex. An allowance for inter-
facing the SO- recovery system with the acceptors has been included to account
for this extra piping.
The concentrated SO- produced in the recovery section is combined with
a portion of the refinery sour gas (H2S) to obtain the proper stoichiometric
ratio required for reduction to elemental sulfur in a conventional Claus unit.
Included in the cost estimate is the investment required for a 77 ton/day sulfur
plant including tail gas cleanup.
Estimated annual operating requirements for the recovery/reduction system
are also presented in Table L12 . As can be seen, reducing gas and stripping
steam represent the major utility items. Included with the operating requirements
is a composite cost figure for the Claus plant variable costs shown in Figure L-1A.
L-78
-------
vO
O
C
HI
11.0 J_
10.0
9.0 --
8.0 --
S 7.0 4-
-------
6. WELLMAN-LORD
a. Process Description
The Wellman-Lord process is a sodium solution scrubbing system based upon
a sulfite/bisulfite/S02 cycle. Sodium sulfite acts as the SCK absorbent
and the spent sulfite liquor is thermally regenerated producing an S02-rich gas
which can be further processed to either sulfuric acid or elemental sulfur.
The overall system operation can be generally characterized by the following
two reactions:
Absorption: S02 + Na^O, + H2<) * 2NaHSO_
Regeneration: 2NaHSO_ > Na0SO, + SO.t + H.O
3 A 2 3 2 2
The Wellman-Lord technology takes advantage of the relative solubilities
and equilibrium S02 vapor pressures of the two sodium salts. Sodium bisulfite
has almost twice the solubility of sodium sulfite in the temperature range of
the process. It is, therefore, possible to feed a solution to the absorption
tower which is nearly saturated in sodium sulfite, since the solution composi-
tion is shifted in the direction of increasing solubility as SO- is absorbed.
L-80
-------
This same solubility effect aids, in a reverse fashion, in the regeneration
I
section. As SO^ is evolved from the concentrated solution of sodium bisulfite,
the sulfite salt is formed and rapidly reaches its solubility limit. The
resultant precipitation of sodium sulfite helps to drive the regeneration
reaction to the desired degree of completion with a minimum heat requirement.
Figure!-15 shows a flow schematic of the general process configuration
for the Wellman-Lord SO- recovery system. In most applications there will be
four processing steps in the recovery systemflue gas pretreatment, SO- absorption,
absorbent regeneration, and purge treatment.
(1) Gas Pretreatment
The S0? absorber is usually designed to receive a saturated flue gas at
100~150°F which is free from particulate. Since the system operation is very
sensitive to the buildup of contaminants, fly ash and other impurities in the
gas must be removed or destroyed prior to contacting the SO,, absorbent liquor.
In the case of coal-fired boiler applications, pretreatment would involve fly
\
ash removal using a high efficiency electrostatic precipitator followed by
L-81
-------
Low
Paniculate
Flue Gas
H-.O
Makeup *
r4
oo
N3
Gas
Pre-Cooling
Purge
to
Treatment
SO2
Absorber
R cheater
Surge
Tank
Surge
Tank
^. Scrubbed
Flue Gas
H20 Na2C03
I
H,0
Soda
Ash
Makeup
Dissolving
Tank
s
T
E
A
M
I
Cooling H20
Evaporator/
Crystal! izer
Purge
Treatment
To
Discharge
FIGURE L -15 SCHEMATIC FLOWSHEET - WELLMAN-LORD PROCESS
-------
wet scrubbing to saturate the gas. The prescrubber not only cools the gas,
but also ensures continued operation in the event of a failure of the electro-
static precipitator. In addition, it removes some small amount of fly ash
(depending upon the particulate load and size distribution) as well as soluble
fly ash components which could build up as impurities in the absorbent solution.
The wet scrubber most commonly specified is a low pressure drop venturi
(AP = 4-6" HLO) . No absorbent is added to this cooling system, only fresh
f
makeup water at a rate equivalent to the rate of water evaporation plus the
liquor bleed rate. This liquor bleed, which is usually small (on the order
of 50 gpm for a 400 MW system) can be returned to the prescrubber if it is
relatively free from impurities. Otherwise, it must be neutralized (the bleed
liquor pH is 1.5-2.0) and treated to meet local water pollution codes i-f it
is to be discharged. The bleed rate is determined by the level of insoluble
solids (<5 wt %) and the calcium concentration (to prevent CaSO^ precipitation).
For applications to Glaus plant tail gases it may be necessary to incinerate
the gas to destroy H^S, COS and CS2 prior to S02 absorption. This incineration
L-83
-------
step is always followed by gas cooling via saturation with water. In other
applications, such as oil-fired boilers, flue gas pretreatment may not be
required because the flue gases are relatively "clean". However, provisions
are usually made for gas prescrubbing prior to SO- absorption. This reduces
the possibility of local precipitation of sulfite salts in the scrubbera
precipitation which could occur relatively easily if SO- inlet levels were to
i
drop suddenly (this would decrease the amount of bisulfite formed, while
water evaporation rates remain unchanged). In these applications (and even
in some applications where pretreatment is used) in-line filters in the spent
liquor stream are used to maintain insoluble contaminants at low levels.
(2) S02 Absorption
Following the prescrubber the gas passes through a de-entrainment separator
and a mist eliminator to minimize the mixing of prescrubbing liquor with
absorbent solution. The S02-rich gas is then contacted in a counter-current
absorption tower with a concentrated solution of sodium sulfite and bisulfite
(generally sodium concentrations are on the order of 6.0M Na ). In the
L-84
-------
absorber, sodium sulfite is reacted with SO to form sodium bisulfite:
S02 + Na2S03 + H20 £ 2NaHSO
Sodium sulfate, which is nonregenerable, is also formed in the absorber both
by the oxidation of sodium sulfite and be reaction of sodium sulfite and sulfur
trioxide from the flue gas:
Na2S02 + 1/2 02 * Na2S04
2Na.,SO, + SO- + H_0 -> NaHSO- 4- Na0SO.
i J 32 3 24
The resultant sulfate levels are controlled at a level of about 5 wt. % in
the absorber feed stream by maintaining a. continuous system purge.
The absorber itself is a multi-stage contacting device, such as a tray
tower, with from three to six stages depending upon the required S02 removal.
Liquor is recycled around each stage separately because the feed solution
rate is generally not sufficient to adequately wet the trays (or packing).
The largest absorption unit being will handle the flue gas from a 150-200 MW
boiler.
Spent liquor bled from the recirculation leg on the bottom stage is
L-85
-------
discharged to a surge tank and then pumped to the regeneration system. Consider-
able surge capacity is provided for the absorbent feed as well as the spent
liquor. This surge capacity ensures smooth operation during periods of
fluctuating gas conditions and also provides for temporary shutdowns of the
regeneration section.
(3) Absorbent Regeneration
The regeneration system basically consists of a conventional forced-
circulation evaporator/crystallizer operated at a high internal recirculation
rate. The evaporator can be designed to use low pressure steam (such as
exhaust steam which might otherwise be discharged) although it is preferable
i
to use high pressure steam; and the evaporator can also be either a single
stage or multi-effect design (multi-effect is the usual type). A multi-effect
configuration improves performance and can considerably reduce steam consumption.
Multi-effect evaporators are used in the Japanese systems, however, in the
United States, m'tlti-effect evaporators require a considerably higher capital
investment, so single effect evaporators are usually specified for small
systems (less than about 150 MW). The largest evaporator now being designed
L-86
-------
is about 20 feet in diameter.
The primary reaction occurring in the regeneration system involves the
conversion of sodium bisulfite to gaseous S02 and sodium sulfite, some of which
precipitates as crystalline sodium sulfite:
2NaHS03 ->- Na2S034- + S02* + HjO
There are, however, side reactions which produce byproducts which contaminate
the liquor. These byproducts consist primarily of sodium sulfate, but also
include some thiosulfate, thionate, and possibly elemental sulfur. It is
not known whether the exact mechanism and kinetics of these side reactions
is well defined, however, at least enough data has been compiled to guide
the system design to reduce these undesirable byproducts.
*
The vapor leaving the evaporator is subjected to one or more stages of
partial condensation to remove water. Existing plants are operating on both
air and water-cooled condensers. To some extent, the degree of dewatering
can be adjusted to provide any quality of S02 gas which is required for
further processing (less than 10% water is easily achieved). The water obtained
L-87
-------
from this condensation is recycled to a dissolution tank and combined with the
regenerated absorbent liquor.
(4) System Purge & Makeup
A continuous system purge must be maintained to prevent a buildup of
contaminants in the system liquor. Possible contaminant sources include not
only all byproduct formation in the system (Na-SO,, Na2S20_, S, etc.) but
also all soluble and insoluble contaminants picked up from the flue gas and
process makeup water. The most significant contaminant is sulfate. Since
sulfate cannot be thermally regenerated it must be purged from the system
in some type of bleed stream. This purge also removes other contaminants
from the system, however the purge rate will normally be determined by the
amount of sulfate formed. The effect of this purge requirement will be directly
translated into process economicsin the capital investment for the purge
treatment facility arid the operating costs associated with the makeup sodium
and purge disposal. Because these costs can be substantial and because process
acceptability may be evaluated in terms of lost sodium value and waste dis-
L-88
-------
posability, a considerable process development effort has been expended in
determining the various factors governing the rates of sulfate formation and
developing methods for minimizing both sulfate formation and the attendant
sodium losses in the required purge.
The majority of the sulfate is formed in the absorption system both from
sulfite oxidation and from absorption of sulfur trioxide. To some degree
the high solution concentrations used in the Wellman-Lord system tend to
i
reduce the sulfite oxidation because oxygen solubility is greatly reduced at
high solution concentrations. However, work is being directed toward further
reducing oxidation by introducing anti-oxidants into the system.
In systems now in operation the purge stream is taken from the regenerated
absorbent solution. This liquor must be treated to meet local water pollution
codes which as a minimum would include neutralization and oxidation to eliminate
COD. An alternative purge treatment approach which is under development in-
volves crystallizing Glauber's salt from the regenerated liquor followed by
filtration and drying to produce a relatively pure solid sulfate byproduct
L-89
-------
(about 90% Na^SO, by weight). This purge treatment system will be incorporated
into the NIPSCO installation that is now under construction.
In most cases the purge has amounted to about 10% of the absorbed sulfur
value (the reported range in operating plants has been 5-20%), but it is
expected that anti-oxidants will reduce this by 50%. Caustic or soda ash
must be added to replace the sodium value lost in this purge stream. A purge
containing 10% of the absorbed sulfur value tied up as sodium salts corresponds
to a sodium makeup equivalent to 0.25 Ibs. NaOH or 0.33 Ibs. NaCO_ per Ib. S
absorbed (0.14 Ibs. NaOH or 0.18 Ibs. Na2CO_ per Ib. SO- recovered).
A research effort is currently being funded to develop a more sophisticated
purge treatment (sulfate regeneration) system; however, no commercial approaches
have yet been demonstrated. Most of this work is being conducted in Sweden.
As previously described, they are now treating the absorption system
purge to produce solid, relatively pure sodium sulfate. The treatment and
disposal of the purge from the gas prescrubbers has depended upon the particular
type of application and system site. Where it cannot be mixed with sluiced
L-90
-------
ash, it must be neutralized and clarified and disposed of in an environ-
mentally acceptable manner. Depending upon local water pollution codes,
this could involve to be a troublesome and expensive treatment process.
jb. Process Reliability
The Wellman-Lord process is a fully developed SO control system for
certain applications as evidenced by the number of commercial installations
now in operation in the United States and Japan. In addition to the installations
currently operating, shown in Table L-13, there are about a dozen systems
either in the planning stage or presently under construction. To date most
applications of this technology have been to either sulfuric acid or Glaus plants
and almost all have involved the conversion of the recovered SO- to sulfuric
acid. There are, however, two systems in operation on oil-fired boilers in
Japan and a retrofit system at Northern Indiana Public Service Company's (NIPSCO)
coal-fired power plant in Gary, Indiana is due to start up in mid-1975. In
addition, Davy Power Gas has recently been awarded the contract for a system
on the San Juan plant of Public Service of New Mexico. The NIPSCO system
L-91
-------
TABLE L-LJ
CAPITAL & OPERATING COST ESTIMATES
WELLMAN-LORD SCRUBBING SYSTEM
Basis: 100,000 scfm flue gas
2,200 ppm S02
90% SO2 removal
8000 operating hours/year
CAPITAL COST ESTIMATES (Installed)
Scrubber System
Fan, Ductwork, and Stack
Gas Reheat System
Process Direct Cost
Other Directs @ 10%
Total Directs
Engineering & Fees (@ 22% TIC)
Subtotal
Owner's Indirects @ 15%
Total Investment
ANNUAL OPERATING COST ESTIMATES (Full Load)
Usage Unit Cost
Labor
Utilities
Fuel
Steam
Process Water
Power
Total Utilities
Purge Treatment
50 x 10 Btu $1.25/MM Btu
80 x 10 gal
40c/Mgal
3.9 x 10 kwh 1.5c/kwh
20 x 10 gal $1.00/Mgal
Annual
Cost ($M)
63
32
59
154
20
L-92
-------
will incorporate an SC>2 reduction process developed by the Allied Chemical
Company for the production of elemental sulfur from the recovered SO .
&t
The reliability of the Davy Power Gas/Wellman-Lord technology is indicated
by the operating records of the installation at the Chuba plant of the Japan
Synthetic Rubber Company. This system has operated from June, 1971 to March,
1973 with an on-stream factor of 97%, and from May 9, 1972 to March 1, 1973
with an on-stream factor of 100%. These stream factors refer to the scrubber
circuit operation. Over this period the system has also achieved better than
90% SO- removal and has converted the recovered SO- to high quality sulfuric
acid.
The major concern with the process operation has been the removal of
contaminants and purge treatment and disposal, see attached.
Although difficulties in the evaporator/crystallizer operation have been
few, the scrubber system operation is still protected by the considerable surge
capacity (up to four days). This capacity also allows for continued absorp-
tion system operation during periods of routine system maintenance and when
L-93
-------
in-line suspended solids filters (if used) are being cleaned or replaced. The
surge capacity also allows for the installation of a reasonable regeneration
system size. The scrubber system itself requires no specia|, bacjc-up provi-
sions since this is well-developed and proven operation whiqh f}pes not involve
slurry handling.
c_. Applicability to Refinery SO Control
^%i
The Wellman-Lord technology has several features that make it an attrac-
tive system for application to refinery SO emissions control problems.
JC
Specifically, these process features include:
high SO- removal capability (>95%);
low-scale potential in the scrubber system;
ability to separate the scrubber system operation from
the regeneration section, which allows the use of a centrally
located regeneration facility serving a number of different
scrubbers;
generation of an SO- rich gas as the recovery system product
that can be further processed in.a Glaus-type facility at the
refinery; and
high scrubber system stream factors due to the inclusion of
surge capacity to cover regeneration system down time.
L-94
-------
The Wellman-Lord process, though, also suffers from a number of inherent system
limitations and potential operational disadvantages some of which may prove
to be significant in a refinery application, these are:
sensitivity of the system operation to the buildup of
contaminantsthis could be a major problem in scrubbing
off-gases containing high SO and 0 levels or particulate
loadings, conditions which may exist in the fluid cat-cracker
flue gas (the Wellman-Lord system may not be a viable scrubber
system for the fluid cat-cracker due to the potentially high
SO levels).
the high saturation temperature of the recirculating liquid
may require heat tracing of lines, particularly where the
regeneration system is located some distance from the scrubbers;
the scrubbed gas must be reheated to prevent plume formation;
a
and
the necessity of handling and disposing of a sizeable
waste stream of soluble salts.
In general the Wellman-Lord process appears to be an appropriate control system
for application lo almost all refinery S02 emissions control problems. How
ever, consideration must be given to the manner in which the system purge
would be handled. There is also some uncertainty, regarding the suitability
L-95
-------
of the process for scrubbing the off-gases from the fluid cat-cracker units.
The applicability to these units must be evaluated on an individual basis taking
into consideration specific flue gas conditions, particularly S0_ concentrations
and particulate removal provisions.
d_.Capital and Operating Requirements
Scrubber System
Generalized costs have been estimated for installing and operating an S09
absorption system utilizing the Wellman-Lord technology. Table L-14 lists
the capital investment (on an installed module basis) and operating cost break-
down for a unit treating 100,000 scfm of flue gas. Figure L-16 provides correl-
ations of capital costs for systems ranging in size from 30,000 scfm to 200,000
scfm.
In developing these costs it has been assumed that gas precooling would
be accomplished in a separate tower and that the unit is designed for 90% SO
removal (there is only a slight cost advantagt for lower removal efficiencies).
It has also been assumed that the scrubber system would be erected at ground
L-96
-------
TABLE L-14
CAPITAL & OPERATING COST ESTIMATES
WELLMAN-LORD REGENERATION SYSTEM
Basis: 200 # mols SO treated/hour
CAPITAL COST ESTIMATES (installed)
Cost ($M)
Evaporator/Crystallizer Section $ 5,700
Purge Treatment System i 300
Allowance for Scrubber/Regeneration Interfacing 800
Process Direct Cost $ 7,800
Other Directs @ 10% 780
Total Directs $ 8,580
Engineering and Fees (@ 22% TIC) 1,888
Turnkey Claus Plant 1,500
Subtotal $ 11,968
Owner's Indirects <§ 15% 1.795
Total Investment $ 13,763
ANNUAL OPERATING COST ESTIMATES (at capacity)
Annual
Usage Unit Cost Cost ($M)
Regeneration System Variable Costs:
Labor 3.25 Shift Pos. $65,000/ShiftYr 211
Utilities
Fuel
Steam 900xl06lbs steam $1.25/Mlbs 1125
Water-Cooling 6.5xl09gal(circ) 5c/Mgal circ 325
Process Ixl06gal 40c/Mgal ^ 0
Power 9.0xl06kwh 1.5c/kwh 135
Total Utilities 1585
Soda Ash 5400 tons $50/ton 270
Waste Disposal (90%Na2S04) 700 tons Assumed =0 0
20
Operating Supplies
Claus Plant Variable Costs 33°
L-97
-------
5.0--
4.0
LJ
c
0)
4J
to
-------
level and that there would be reasonable access to the scrubber site. Gas
reheat would be by direct fired heaters. The purge treatment cost is for treat-
ing the acidic effluent from the precooler.
(2) Regeneration System
Cost estimates have been prepared for the thermal regeneration system
on an installed module basis.
The regeneration system would be a centrally located facility capable
treating the effluent from all the refinery scrubbers. Table L-14
provides the costs for a system to recover 200 Ib. moles/hf. SO..
Figure L-17 shows capital and operating costs as a function of system
size.
It has been assumed that the purge treatment section would be
similar to that for the NIPSCO installation and would produce a
fairly pure Na_SO,. Allowance has also been provided for
scrubber and regeneration system interfacing. This includes heated
surge tanks with a one day storage based upon regeneration
system capacity and a piping (heat traced) and control system.
It has been assumed that the recovered S02 would be compressed
and sent to a centralized Glaus plant. The regeneration system
cost-- include the S02-rich gas compressors, but not the duct
work.
L-99
-------
25 -
20
i
u
(A
15
10 ..
100
200
300
400
Capacity, Mols/Hr of SO- Removed
FIGURE L-17
DAVY POWER GAS, CAPITAL INVESTMENT
REGENERATION SECTION
L-100
-------
.C. OFF-LINE COMPARATIVE ECONOMIC ANALYSIS
As part of the process evaluation, annual operating costs for each of
the five processes were developed. This economic evaluation was performed without
the use of the refinery LP model and is hence referred to as an off-line analysis.
However, to make the exercise meaningful, a basis was selected that would approximate
the actual application to refinery sources. This was accomplished by determining
capital investment requirements for each process based on six gas treatment systems
i
of 100,000 scfm each and a central regeneration system with a capacity to handle
the combined SO. removed by the six scrubbers or acceptors. The sulfur removal
rate for this model is equivalent to 77 tons/day of elemental sulfur. This is
nearly equivalent to the degree of removal required to attain 90% desulfurization
of the flue gas from a 150 BPD refinery.
The results of this annual cost comparison are summarized in Table L-15.
For those processes which generate concentrated S02 as the primary product, the
investment required to convert S02 to a more convenient final product has been
included.
L-101
-------
TABLE L-15
FLUE GAS DESULFURIZATION PROCESSES
t-1
Basis: 90% Sulfur removal from flue gas.
77 T/D Sulfur recovered.
Capital Investment. $M^ '
Final Product
Gas Treatment Section
Regeneration Section
SO£ Reduction
TOTAL INSTALLED COST (TIC)
$/Kw (Estimate)
$/Kw (Typical)
(2)
(3)
OFF-LINE
ue gas .
Chiyoda
Gypsum
9,990
12,500
_ _
22,490
83
2,163
1,642
195
899
4,498
9,397
COMPARATIVE ECONOMIC
Dual Alkali
Calcium Sulfite
8,150
5,000
13,150
49
26-47
798"
1,660
133
1,160
526
2,630
__
6,907
MagOx
Acid
7,090
6,700
1,700
15,490
57
36-66
1,777
110
192
620
3,098
-
5,797
Shell/UOP
Sulfur
17,590
5,000
1,500
24,090
89
(65)
1,880
1,900
100
964
4,818
330
9,992
Davy Powergas
Wellman Lord
Sulfur
6,950
12,250
1.500
20,700
77
40-68
Operating Cost, $M
Utilities
Raw Material & Chemicals
Operating Labor
Waste Disposal
Maintenance (4% of TIC)
Fixed Charges (20% of TIC)
Glaus Plant Operating Cost
TOTAL ANNUAL COST
"(1)Mid-1974.
(2) EPA presentation on Status of Flue Gas Pesulfurization Technology - National Power Plant Hearings.
(3) Including Add-on Process.
2,510
290
211
120
828
4,140
330
8,429
-------
For example, the cost of a sulfuric acid plant is included for the MagOx process
and the investment for additional Glaus plant capacity is abided for the Shell/UOP
and Davy Powergas processes.
The dollar per kilowatt equivalent of these estimates is shown in the
table and are compared with typical values from other sources. 2' The estimates
of this study are understandably in the high end of the range due to the complexity
of interfacing this technology with typical refinery operations.
The annual operating costs for each process are also developed in Table L-15.
Variable and semi-variable costs such as utilities, operating labor, catalyst and
chemicals, and waste disposal are based on the individual process operating require-
ments presented in Section B. Maintenance and fixed charges are also included at
4% and 20% of total installed cost respectively. An important assumption made in
determining the operating costs was that salable products such as gypsum, sulfuric
acid, calcium sulfite and sulfur have zero market value and zero disposal costs.
The zero product value assumption was made due to the prevailing uncertainties
regarding the market for these products. However, it is conceivable that a firm
L-103
-------
might; pay freight rates to obtain this material, thus alleviating a disposal
problem for the producers. In the case of a throw-away process, disposal costs
were set at $5/ton.
Based on this evaluation, the processes fell into two operating cost
ranges. In the low range are the dual alkali and MagOx processes. Chiyoda,
Davy Powergas and Shell occupy the high end of the spectrum. The most notice-
able difference between the members of these two tiers is the degree of com-
mercial application, which is undoubtedly reflected in the estimated annual
cost. In general, annual costs tend to increase as processes near full com-
mercialization .
The Wellman-Lord/Davy Powergas soda scrubbing process was selected to
typify the economics associated with flue gas desulfurization in the refinery
LP model. The reason for selecting this process is that it has been commer-
cially applied in refineries in the United States and Japan and consequently
the operating costs should be realistic. Furthermore, these costs are
competitive with other processes exhibiting the same or similar degree of
commercialization (i.e., Shell/UOP and Chiyoda). Finally, the process is
L-104
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compatible with existing refinery sulfur recovery processes which would make
it attractive to refineries.
The one disadvantage with the process is that it may be unsuitable for
application to the FCC catalyst regenerator due to possible high sulfur
trioxide levels in the gas leaving the catalyst regenerator. Operating prob-
lems can be anticipated for processes based on the sodium sulfite/bisulfite
system in this service. The main concern is a high rate of sulf ate formation
which would require a large system purge. This problem is diminished when
a co-boiler is added to the system. This is due to a shift in the SCK/SO.
equilibrium concentrations at temperatures existing in the combustion zone.
The SO- levels leaving the co-boiler are not much greater than those
encountered in typical flue gases from fossil fuel combustion sources. .Con-
sequently, the W-L process, with prescrubbers for particulate control, could
(12)
be applied to the FCC.
The MagOx process is an example of an emerging technology which appears
environmentally and economically attractive. In the off-line evaluation, the
overall economics were most attractive. However, these figures have more
L-105
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uncertainty than some of the other processes since the process has not operated
continuously for any appreciable length of time. Hence, operating require-
ments are not as well defined. One of the major attractions of the process
is that magnesium sulfate can be regenerated to recover the active magnesium.
Hence, sulfate formation in the system is not a major concern. In addition,
secondary emissions from the process are minimal. This process should evolve
into a desirable candidate for flue gas desulfurization.
After completing this detailed assessment of FGD processes, it was
learned that Exxon Research and Engineering has successfully applied caustic
(NaOH) scrubbing technology to FCC regenerators for controlling particulate
and SOX emissions. The process flow schematic for this system shown in
Figure L-18 is a standard, once-through arrangement frequently used with non-
regenerable systems. A Jet Scrubber is employed to affect vapor-liquid con-
tact and provide pumping capacity thereby eliminating the need for a fan.
The scrubbing solution is the motivating fluid for the Jet Scrubber. A bleed
stream is withdrawn from the circulating loop and delivered to a clarifier
for removal of particulates. Solids and sulfur in the form of sodium sulfate
L-106
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V
FIGURE L-18
TYPICAL FLOW DIAGRAM
EXXON FCC CAUSTIC SCRUBBING SYSTEM
-------
are purged from the system in the thickened underflow. The clarified liquids
with fresh caustic are returned to the scrubber.
Capital and operating requirements for the Exxon system are summarized
in Table L-16 The economics of this process were not available in time for
comparison with Wellman-Lord to determine which process has the lowest
overall cost,
L-108
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TABLE L-16
EXXON R AND E FCC SCRUBBING SYSTEM
CAPITAL AND OPERATING REQUIREMENTS
Capacity, MScfm 55 125
Inlet Conditions
Par ticulates , gr/Scf (dry) 0.1 0.1
, PPMV 1,000 1,000
Removal Efficiencies, %
Particulates 78 78
90 90
Capital Investment, $MM
USGC; 1974 1-7 2.7
Utilities
Makeup Water, gpm 85 20°
Electric Power, kw 15° 325
Fuelgas (10° reheat), MMBtu/hr 0.7 1.7
Caustic (26° Be), gpm 6-* 14'6
Sludge Generation Rate, gpm °-75
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£. ' CONTROL OF SULFUR PLANT EMISSIONS
1. ALTERNATIVES
The Claus sulfur plant tail gas from a typical three-stage converter
(22)
contains between 7,000-12,000 ppmv of sulfur compounds. ' Control of this
source is necessary to achieve the required overall reduction in refinery
emissions. In this study, two alternate routes were considered for treatment
first
of the Claus plant tail gas. The/scheme, shown in Figure L-19,utilizes the same
stack gas desulfurization technology ascribed to the other process units within
; /
the refinery. This approach involves the installation of a scrubber on the stack
of the Claus plant incinerator. The spent absorbent is sent to the central SO-
recovery system required for the other flue gas scrubbing units. The recovered
sulfur value is recycled to the Claus plant along with the S02 removed from other
sources. Scheme 2 assumes the installation of one of the available add-on [recesses
such as the Beavon/Stretford or Pritchard Cleanair to the Claus unit to treat the
L-110
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2.05 T/D
Sour Gas, lU
t-1
>
'
^
315 T/D
«^_
95.5 T/D
Cone.
C(\
O\Jn
>
Fvf«f"lnff Claus
Plant
NPU m AH*?
Plant
SO, Recovery
System
y S
7-
/
£
1 T
i
/ Scr
/^ / \ ^^
i ^L, Y"
Incinerator A. ^ ]
V ^X J
\o ^/
^^* ' r*^
18.5 T/D
J' V
^_ . _ _
^
^
Solution to and
{ rrom otner scrubbers.
/D
/ w
Basis: 95% Removal In Claus Plant
90% Removal in Scrubber
99.5% Removal of Fresh Feed
390 T/D
CLAUS TAIL GAS CLEANUP
SCHEME I
FIGURE L-19
-------
Sour Gas,
315 T/D
ISJ
Existing Glaus
Plant
77 T/D
Cone.
SO,
17.6 T/D
Add-On
Process
New Glaus
Plant
Add-On
Process
S02 Recovery
System
2.06 T/D
n
!
r
Solution to and
from scrubbers.
77 T/D
Basis: 95% Removal in Glaus Plant
90% Removal in Add-On
99.5% Removal of Feed
390 T/D
GLAUS TAIL GAS CLEANUP
SCHEME II
-------
tail gas. The gas leaving the add-on process is further incinerated to oxidize
the remaining H2S to sulfur dioxide.
2. ECONOMICS
The capital investment associated with Scheme I includes the cost of a
scrubber system and incremental costs on the regeneration system and an incremental
cost on the new sulfur plant to handle the recycle. The capital investment required
for Scheme 2 is primarily the cost of the Claus add-on plant.
The economics of these two routes are summarized below:
Scheme 1 Scheme 2
Flue Gas Treatment Claus Add-On Process
Capital Investment, $M . 2000 2100
Annual Operating Costs, $M 1180 650
The flue gas treatment costs for Scheme 1 are based on the figures developed
in this report for the Wellman Lord process. The economics of the add-on process
are based on available information in the published literature.
Based on this generalized evaluation, it appears that the Claus add-on process
route has the more favorable economics. Consequently, we selected Scheme 2 for our
sulfur control assessment study.
L-113
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3. GLAUS TAIL-GAS-CLEANUP PROCESSES
A number of add-on processes are commercially available for treatment
of Glaus tail-gas. Some of the more advanced technologies include the fol-
lowing:
Process Supplier
Beavon/Stretford Ralph M. Parsons
CleanAir Pritchard Co.
Sulfreen IFP
SCOT Shell
Of these, the Sulfreen process has the lowest sulfur removal capability, which
is about 80-85%. The other processes all guarantee sulfur emissions less than
250 ppmv, or an overall recovery of better than 99.9 percent for the combi-
nation Claus plant/Tail-gas Cleanup System.
In our refinery SOX control evaluation, we use the economics associated
with the Beavon/Stretford process as typical of the cost for reducing sulfur
emissions from Claus plants. The operating requirements for this process are
shown in Table L-17.
L-114
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TABLE L-17
BEAVON TAIL-GAS-CLEANUP PROCESS
TYPICAL INVESTMENT AND OPERATING REQUIREMENTS
Basis: 110 STPD Sulfur
Capital Investment, $MM (1st Quarter 1975)
Scale Factor
Operating Requirements
Electric Power, kwh
Steam, Mlbs (50 psig)
Fuelgas, 106 Btu
BFW, Mgal
Labor, Oper/Shift
Per Short
Ton of Sulfur
$2.75
0.4
284
0.14
4.36
0.13
1/2
L-115
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E. INTEGRATION OF SO REMOVAL PROCESSES
This section describes in a general way how the selected process might
be integrated into a typical refinery complex.
l- DAVY POWERGAS PROCESS
A conceputal refinery SO control system based on the Davy Powergas
> i
process is presented in Figure L-20. Basically, individual flue gas scrubbers
i
are installed on the various refinery units including the FCC, and the spent
adsorbent from each scrubber is sent to a central regeneration S02/recovery
system with the regenerated adsorbent returning to the scrubbers. The re-
covered SO- stream containing about 95% SO- is sent to a Claus sulfur plant.
The concentrated sulfur dioxide from the central regeneration recovery
system is combined with the sour gas from the amine unit to form the feed
for the sulfur plant. A new sulfur plant is also required since the capacity
of the existing unit is likely to be insufficient to handle all of the SO2
recovered from the stationary sources. The combined tail-gas from both sul-
fur plants is subjected to a tail gas cleanup step, employing add-on process
technology as discussed in Section D.
L-116
-------
(r-1
FIGURE L-20
CONCEPTUAL REFINERY SO CONTROL SYSTEM
BASED ON WELLMAN-LORD PROCESS
-------
2. PROCESS REQUIREMENTS
The capital investment/capacity relationships associated with refinery
flue gas desulfurization are shown in Table L-18 for the process programmed
into the refinery model. The investment costs are consistent with the first
quarter 1975 basis used in the model. The investment cost equation for the
regeneration/recovery section does not include the cost of the additional
Glaus unit. This was excluded since sulfur plant economics are handled
separately in the refinery LP model.
Process operating requirements for the F6D processes are presented in
Table L-19. The operating requirements are presented in terms of consumption
per unit of treatment volume or weight of sulfur produced.
In applying flue gas scrubbing in a cost effective manner, scrubber
sizing must be considered. For sources with a treatment volume of less than
30 Mscfm, it is more economical to combine the flue gas with that of a nearby
source and take a (vantage of economies of scal<>. However, for large sources
such as the atmospheric crude heater or the boiler facility, scrubber avail-
ability becomes a major consideration. Consequently, for emission sources in
L-118
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TABLE L-18
FLUE GAS DESULFURIZATION PROCESS ECONOMICS
CAPITAL REQUIREMENTS
GAS TREATMENT
Capital Investment (Mid 1975)
Process
Capacity, Mscfm
Total system cost, $M
Size factor
CD
ABSORBENT REGENERATION/S00 RECOVERY
J .""' ' --'" ""-- ' ^
Capital Investment (Mid-1975)
Basis: 200 Ib mols SO /hr treated
Process
Total system cost, $M
Size Factor
(1) Includes acid plant.
(2) Excludes Glaus plant.
(3) 76.8 T/D of Sulfur.
(3)
Davy Powergas
Wellman Lord
100
1275
[Mscfm/100]
0.7
Davy Powergas
Wellman Lord
15,125
(2)
C
Ib mols S0,,/hr\
200 I
0,7
L-H9
-------
TABLE L-19
REFINERY FLUE GAS DESULFURIZATION
PROCESS OPERATING REQUIREMENTS
PROCESS:
Scrubber Section
Electric Power, kwh/Mscf
Fuel, Btu/Mscf
Process Water, Mgal/Mscf
Purge Treatment, $/Mscf
Davy Powergas
Wellman-Lord
0.0813
1040
0.00170
0.00042
Regeneration Section
Utilities
Steam, Mlbs/T of S
Electric Power, kwh/T of S
Process Water, Mgal/T of S
Cooling Water, Mgal/T of S
Raw Materials
Soda Ash, $/T of S
Waste Salts, T/T of S
S02 to Claus Plant T/T of Product
Sulfur Product
35
352
0.039
254
10.50
0.27
2.0
Cone. SO,
L-120
-------
excess of 100,000 scfm, two 60% scrubbers should be considered. In summary,
recommended scrubber utilization is as follows:
Flue Gas Treatment
Volume, Mscfm
<30
30-100
100-250
Number of Scrubber
Systems Required
Combined with another small source
1
2
L-121
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REFERENCES
1. National Public Hearings on Power Plant Compliance with Sulfur Oxide
Air Pollution Regulations. U.S. Environmental Protection Agency,
January 1974.
t
2. "An Introduction to Stack Gas Cleaning Technology," A.V. Slack, Technical
Conference on Sulfur in Utility Fuels: The Growing Dilemma, October 25-26, 1972.
3. "Japan Tries Three Stack-Gas Desulfurization Routes," The Oil and Gas Journal,
July 24, 1972, pp. 36-41.
4. New Flue Gas Desulfurization Process, Hideo Idemura, June 20, 1973.
5. The Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process. Chiyoda
Chemical Engineering & Construction Co., Ltd., 1973.
6. Summary Report on U.S. Requirements for Desulfurization, Battelle Columbus
Laboratories, November 22, 1972.
7. "Conceptual Design and Cost Study, Sulfur Oxide Removal from Power Plant
Stack Gas, Magnesia ScrubbingRegeneration: Production of Concentrated
Sulfuric Acid," G. G. McGlamery, R. L. Torstrick, J. P. Simpson, J. F. Phillips, Jr
all of TVA, Muscle Shoals, Alabama, 372 pages, Office of Research and Monitoring,
U.S. EPA-R2-73-244, May 1973, Washington, D.C.
8. "Operational Performance of the Chemico Basis Magnesium Oxide Systems at the
Boston Edison Company," Part I, George R. Koehler, Chemical Construction Corp.,
New York, N.Y., Flue Gas Desulfurization Symposium, New Orleans, Louisiana,
May 14-17, 1973, 25 pages.
9. "Operational Performance of the Chemico Magnesium Oxide System at the Boston
Edison Company," Part II, Christopher P. Quigley, Boston Edison Company,
Boston, Massachusetts, Flue Gas Desulfurization Symposium, New Orleans, Louisiana,
May 14-17, 1973, 12 pages.
10. "Some General Economic Considerations of Flue Gas Scrubbing for Utilities,"
John K. Burchard, Garty T. Rochelle, William R. Schofield, John 0. Smith,
Technical Conference on "Sulfur in Utility Fuels: The Growing Dilemma,"
sponsored by Electrical World. October 25-26, 1972, pp. 91-124.
11. "Control of Sulfur Oxides in Stack Gases; Magnesium Base S02 Recovery Prc ^ess:
A Prototype Installation at Boston Edison Company and Essex Chemical Company,"
I. S. Shah, C. P. Quigley, Symposium No. 39E, Seventieth National Meeting,
Atlantic City, N.J., August 29-September 1, 1971, AIChE, New York, N.Y., 30 pages.
L-122
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REFERENCES (Continued)
12. "Refinery Catalytic Cracker Regenerator SOX Control," T. Ctvrtnicek,
T. W. Hughes, C. M. Moscowitz, D. L. Zanders, Contract No. 68-02-1320,
Task No. 1, Phase I, EPA Control Systems Laboratory, Chemical Processes
Section, Research Triangle Park, North Carolina, September 1973, 161 pages.
13. Conversation with M. A. Maxwell, EPA Project Director for Boston Edison/EPA
Mag-Ox Study.
14. "Shell Flue Gas Desulfurization Process Demonstration on Oil and Coal-Fired
Boilers," AIChE National Meeting, Tulsa, Oklahoma, March 1974.
15. "New Tool Combats S02 Emissions," R. E. Conser, R. F. Anderson, Oil and Gas
Journal. October 29, 1973.
16. "Dry Process for S02 Removal Due Test," Oil and Gas Journal. August 21, 1972.
17. Control of Sulfur Oxide Pollution from Power Plants. F. T. Princiotta and
N. Kaplan, EPA Control Systems Divisions Report, October 1971.
18. Economics of Flue Gas Desulfurization, G. T, Rochelle, presented at the Flue
Gas Desulfurization Symposium, New Orleans, Louisiana, May 14-17, 1973.
19. Discussions with C. B. Earl, Davy Powergas, Lakeland, Florida.
20. Discussions with R. Christnan, Federal EPA Project Officer, Research Triangle
Park, North Carolina.
21. The Wellman-Lord SOo Recovery Process. B. H. Potter and C. B. Earl, presented
at 1973 Gas Conditioning Conference.
!
22. "Environment Needs Guide Refinery Sulfur Recovery," H.S. Bryant, Oil and
Gas Journal, March 26, 1973.
L-123
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TECHNICAL REPORT DATA
(I lease read fnuruclions on the reverse lie/are completing)
1. HLPOHT NO
EPA-600/2-76-161b
2.
4. TITLE ANDSUBTITLE T , ,--,,-. .-,
Impact of SOx Emissions Control on
Petroleum Refining Industry
Volume U. Detailed Study Results
3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
June 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
James R. Kittrell and Nigel Godley
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Inc.
20 Acorn Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADC-030
11. CONTRACT/GRANT NO.
68-02-1332, Taskl
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 9/73-5/76
14. SPONSORING AGENCY CODE
EPA-ORD
is. SUPPLEMENTARY NOTES IERL-RTP Task Officer for this report is Max Samfield, Mail
Drop 62, (919) 549-8411, Ext 2547.
16. ABSTRACT
The report gives results of an assessment of the impact on the U.S. petro-
leum refining industry of a possible EPA regulation limiting the level of gaseous
refinery sulfur oxide (SOx) emissions. Computer models representing specific refi-
neries in six geographical regions of the U.S. were developed as the basis for deter--
mining the impact on the existing refining industry. New refinery construction during
the period under analysis (1975-1985) was also considered by development of computer
models representing new grassroots refineries. Control of refinery SOx emissions
from both existing and new refineries was defined for the purposes of this study by
maximum sulfur levels on refinery fuel and on fluid catalytic cracking unit feedstock
and by increased sulfur recovery in the Claus plant. The computer models thus
constrained were utilized to assess investment and energy requirements to meet the
possible regulation and the incremental cost to manufacture all refinery products as
a result of the regulation. Parametric studies evaluated the impact of variations in
the types of imported crude oils available for future domestic refining and the projec-
ted sulfur level of residual fuel oil manufactured in the U.S.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Sulfur Oxides
Petroleum Industry
Petroleum Refining
Refineries
atalytic Cracking
b.lDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Refinery Fuel
Claus Plant
cos AT I Field/Group
13B
07B
05C
13H
131
07A
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
458
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
L-124
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