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

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                                        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

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                                 Volume  II


                                 APPENDIX A

                               CRUDE  SLATES
                                                                     Page

A.   METHODOLOGY	   A-l

B.   MODEL CRUDE SLATES	   A-2

C.   CRUDE MIX FOR TOTAL U.S.  	   A-10



                                APPENDIX B

                      U.S.  SUPPLY/DEMAND PROJECTIONS


A.   DEMAND ASSUMPTIONS FOR MODEL RUNS	   B-l
                                   ',,
B.   DETAILED U.S. PRODUCT  DEMAND FORECAST	   B-7

     1.   Methodology	   B-7

     2.   Product Forecast	 	   B-12


                               APPENDIX  C

                          PRODUCT SPECIFICATIONS



                               APPENDIX  D

             BASE LEVEL OF  CLUSTER REFINERY FUEL SULFUR CONTENT



A.   METHODOLOGY OF CALCULATIONS	   D-2

     1.   Fuel Oil Sulfur Content by  State  	   D-2

     2.   Combustion Unit Size	   D-2

B.   RESULTS	   D-3

C.   CLUSTER MODEL REFINERY FUEL SPECIFICATION	   D-6
                                     ILL

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                   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

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                    TABLE OF CONTENTS  -  Volume II  (cont.)


                                APPENDIX H

                          TECHNICAL DOCUMENTATION
                                                                      Page


A.   CRUDE OIL PROPERTIES .'	   H-l

B.   PROCESS DATA  	,	   H-2


C.   GASOLINE BLENDING QUALITIES  	   H-5


D.   SULFUR DISTRIBUTION  	   H-5

E.   OPERATING COSTS  	   H-6

F.   CAPITAL INVESTMENTS  	   H-6



                                APPENDIX I

                             MODEL CALIBRATION



A.   BASIC DATA  FOR CALIBRATION 	   1-1

     1.   Refinery  Input/Output 	   1-1


     2.   Processing  Configurations	   1-10

     3.   Product Data 	   1-18

     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

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                     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 ............

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              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

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                                                 (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

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                                 VOLUME II

                              LIST OF TABLES


                                APPENDIX A

TABLE A-l.   Bureau of Mines Receipts of Crude by Origin 1973	   A~3

TABLE A-2.   ADL Model Crude Slates and Sulfur Contents
             for 1973	   A~4

TABLE A-3.   Model Crude Slates - Small Midcontinent 	   A-5

TABLE A-4.   Model Crude Slates - Large Midwest	   A-7

TABLE A-5.   Model Crude Slates - Texas Gulf	   A-8

TABLE A-6.   Model Crude Slates - East Coast	   A-9

TABLE A-7.   Model Crude Slates - West Coast	   A-ll
     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

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                                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  	

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                                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

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                                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

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                            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

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                            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

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                            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

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                             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

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                             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

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                                 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

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                                   VOLUME  II

                                LIST OF FIGURES


                                   APPENDIX F
                                                                           Page
FIGURE  F-l.    Geographic  Regions  Considered in  Development of
               Cluster Models  	    F-3


                                   APPENDIX I

FIGURE  1-1.    Louisiana Gulf  Cluster Model Calibration  	    1-25

FIGURE  1-2.    Texas  Gulf  Cluster  Model Calibration  	    1-26

FIGURE  1-3.    Small  Midcontinent  Cluster  Model  Calibration 	    1-27

FIGURE  1-4.    Large  Midwest Cluster Model Calibration 	    1-28

FIGURE  1-5.    West Coast  Cluster  Model Calibration  	    1-29

FIGURE  1-6.    East Coast  Cluster  Model Calibration  	    1-30


                                   APPENDIX J

FIGURE  J-l.    Texas  Gulf  Cluster  1985  Sulfur  and Material Balance  	    J-52


                                   APPENDIX L

FIGURE  L-l.    Process Flow Diagram, Chiyoda Thoroughbred 101 '.	    L-13

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

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 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

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                                 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 line—Capline—
 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

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                                    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

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          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

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                               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 alone—and not government action—are 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

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                       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

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                                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

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 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

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        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

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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

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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

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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

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 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

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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

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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

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                                   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 clusters—the Small
Midcontinent and the Texas Gulf clusters—had  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  	
                                      	••	  I—18

       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 oils—over 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  	  I—1
     2.   Initial Process Selection  	  1—3
B.   DETAILED EVALUATION OF SELECTION PROCESSES  	  L-5
     1.   Basis 	  L-5
          a.   Technical Assumptions ..	  1—5
          b.   Economic Assumptions  	  1—9
     2.   Chiyoda		  L~12
          a.   Process  Description	  L-12
          b.   Process  Reliability 	  L""15
          c.   Application to Refinery SO  Control 	  1—1.6
                                          Jv
          d.   Capital  and Operating Requirements 	  1—17
      3.   Dual Alkali and Wet Lime Scrubbing	  L~23
          a.   Process  Description 	*	  L-23
          b.   Process  Reliability 	  L~26
           c.    Application to Refinery SO  Control 	  L-27
                                          X
           d.    Capital and Operating Requirements 	  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

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                           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

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                           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

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                             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

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                                   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

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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

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                                  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

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  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 Side—100,000 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 Side—200 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 Side—200 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 L—12 .  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

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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 system—flue 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

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                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

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 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 scrubber—a


 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

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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

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 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

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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

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 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 economics—in 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

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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

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 (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

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 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

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                              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

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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

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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

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 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
             contaminants—this 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

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 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

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                             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

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      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

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      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

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.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

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                                                     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

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 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
                                 L-109

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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

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            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

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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

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(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

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                               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

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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 Scrubbing—Regeneration:  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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