THE M. W. KELLOGG COMPANY
     A Division of Pullman Incorporated
     ALTERNATIVE CONTROL STRATEGIES TO REDUCE

     PETROLEUM REFINERY SO2 EMISSIONS RESULTING

                FROM FUEL COMBUSTION
                     PREPARED FOR

           OFFICE OF RESEARCH AND DEVELOPMENT

           U.S. ENVIRONMENTAL PROTECTION AGENCY

                  WASHINGTON, D.C. 20460
              CONTRACT NO. 68-02-1308 (TASK 33)
                    JANUARY 31, 1975
                RESEARCH & ENGINEERING DEVELOPMENT

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  ALTERNATIVE CONTROL STRATEGIES  TO  REDUCE
PETROLEUM REFINERY S02 EMISSIONS  RESULTING
          FROM FUEL COMBUSTION
                   by

I.H. Lutz, N.S. Al-Haj-Ali, and  B.P.  Castiglioni

          THE M.W. KELLOGG COMPANY
     RESEARCH & ENGINEERING DEVELOPMENT
          HOUSTON, TEXAS  77046


    CONTRACT NO. 68-02-1308  (TASK 33)


  EPA TASK OFFICER:  CHARLES B.  SFDMAN
       CONTROL SYSTEMS LABORATORY
   NATIONAL ENVIRONMENTAL RESEARCH  CENTER
    RESEARCH TRIANGLE PARK, N.C. 27711


             Prepared for
   OFFICE OF RESEARCH AND DEVELOPMENT
  U.S. ENVIRONMENTAL PROTECTION  AGENCY
          WASHINGTON, D.C. 20460


         January 31, 1975

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                                NOTICE
          The attached document is a DRAFT CONTRACTOR'S REPORT.  It
includes technical information and recommendations submitted by the
Contractor to the United States Environmental Protection Agency ("EPA")
regarding the subject industry.  It is being distributed for review and
comment only.  The report is not an official EPA publication and it has
not been reviewed by the Agency.

          The report, including the recommendations, will be undergoing
extensive review by EPA, Federal and State agencies, public interest
organizations, and other interested groups and parsons during the coming
weeks.  The report and in particular the contractor's recommended standards
of performance are subject to change in any and all respects.

          The regulations to be published by EPA under Section 111 of the
Clean Air Act of 1970 will be based to a large extent on the report and the
comments received on it.  However, EPA will also consider additional
pertinent technical and economic information v?hich is developed in the
course of review of this report by the public and within EPA.  Upon completion
of the review process, and prior to final promulgation of regulations, an
EPA report will be issued setting forth EPA's conclusions concerning the
subject industry and standards of performance for new stationary sources
applicable to such industry.  Judgments necessary to promulgation of
regulations under Section 111 of the Act, of course, remain the responsi-
bility of EPA.  Subject to these limitations, EPA is making this draft
contractor's report available in order to encourage the widest possible
participation of interested persons in the decision making process at the
earliest possible time.

          The report shall have standing in any EPA proceeding or court
proceeding only to the extent that it represents the views of the Contractor
who studied the subject industry and prepared the information and recommendation.
It cannot be cited, referenced, or represented in any respect in any such
proceedings as a statement of EPA's views regarding the subject industry.
                                 ii

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                      Table of Contents

                                                         Page No,
    List of  Figures                                         iv
    List of  Tables                                           v
1.  Introduction                                              1
2.  Summary                                                   3
3-  Prediction of Refinery SO,, Emissions for the Year 1980    5
    A. Crude Slate                                            5
    B. Average Refinery Configuration                         5
    C. Products and SO  Emissions                            10
    D. Specific Schemes Projected for Processing Mid-East    16
       Crudes
4-  Schemes for Reducing Refinery S0_ Emissions              24
    A. Cat. Cracker Feed Desulfurization                     24
       1.  Cost                                               24
       2.  Supplemental Benefits                              25
    B. Reduction in Fuel Requirements                        25
    C. Use of Low Sulfur Fuel  in The Refinery                27
    D. Stack Gas Scrubbing                                   30
    E. Evaluation of Alternative Methods for Reducing        36
       Emissions
5-  Trends - Present to 1985                                 38
6-  Conclusions                                              48
7-  References                                               50
                        111

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                     List of Fiqures
Figure No.                  Description                  Page No.

    1.      Average Flow Sheet for Processing                11
            Mid-East Crude
    2.      Average Flow Sheet for Processing                12
            Non-Mid-East Crude
    3.      Block Flow Diagram for Case I                    18
    4.      Block Flow Diagram for Case II                   20
    5.      Block Flow Diagram for Case III                  21
    6.      Approximate Stack Gas Scrubbing Cost             33
            vs. Capacity
    7.      Domestic Demand for Heavy Fuel Oil               42
    8.      Production and Imports of Residual               44
            Fuel Oil
    9.      Residual Fuel Oil Consumption By End             45
            Use
                       IV

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                       List of Tables
Table No.                   Descriptiori                  Page  No,

   1         Capacities of Process Units  in  1973  and         7
             in 1980
   2         Fuel Requirements - Mid-East Crude              8
             Refineries
   3         Fuel Requirements - Non-Mid-East Crude         9
             Refineries
   4         Sulfur Dioxide Emissions  - Mid-East            13
             Crude Refineries
   5         Sulfur Dioxide Emissions, -  Non-Mid-East      14
             Crude ProcessihgvRefineries  with Various
             Refinery Fuels
   6-        SOx Emissions from New  Refinery  Expansions      23
   7         Hydrodesulfurization Economic Summary           29
   8         Average  Sulfur Content  of  Some Residual         31
             Fuel  Oils
   9         Fuel  Oil sulfur Level Regulations               32
  10         Approximate Economics of Stack Gas Scrubbing    35
  11-a       Energy Outlook -  1974                           39
  11-b       Energy Outlook Forecast  -  1980                  40
  11-c       Energy Outlook Forecast  -  1985                  41

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1.   Introduction

         This report covers work performed under contract
    No. 68-02-1308 for the Environmental Protection Agency
    (EPA), Emission Standards and Engineering Division,
    OAQPS, Task No. 33.

         The purpose of this task is to study alternative
    control strategies to reduce petroleum refinery SO
    emissions resulting from fuel combustion.  The scope
    of this study dictated that an average of the subject
    facilities be assumed.  Detailed designs and cost
    estimates were not prepared for a specific installation;
    rather a general case was used.

         United States' refineries are divided into two
    groups, those processing Mid-East high sulfur crudes
    and those processing the balance of the crudes.  The
    general, refining schemes for Mid-East crude differ
    principally in the method of processing residual.  These
    are:

         I.  Coking
        II.  Residual desulfurization.
       III.  Deasphalting followed by partial oxidation of
             deasphalted bottoms.

         Sulfur dioxide emissions of the refineries are cal-
    culated based on firing four alternative fuels:

         1.  Refinery gas plus required natural gas.
         2.  Fuel oil plus refinery gas.
         3.  Desulfurized distillate plus refinery gas.
         4.  Desulfurized residual plus refinery gas.

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     Emission control strategies are discussed, particu-
larly the relative economics of flue gas scrubbing com-
pared to residual desulfurization.

     An attempt is made to forecast the future trend in
demand for heavy fuel oils in the U.S. market and a
look is given to stack gas scrubbing for sulfur level
reduction.

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  2.  Summary

          The purpose of this report is to predict refinery
      emissions for 1980 by sources to study the feasibility
      of reducing these emissions.  As a result of this study,
      the steps which would have the most impact on reducing
      emissions were found to be:

          1.  Cat cracker feed desulfurization.
          2.  Use of low sulfur content refinery fuels.
          3.  Improved sulfur plant efficiency.
          4.  Improved refinery fuel economy.
          5.  Flue gas scrubbing.

          In this study the projected crude runs for 1980
      were estimated by assuming that the 1980 refinery
      capacity and configuration would be the capacity in
      existence at the start of 1974 plus contracted ex-
      pansions.  Mid-East crude runs were estimated to be 1973
      Mid-East crude runs (783,000 barrels per stream day* (bpsd))
      plus all the crude capacity increase resulting from announced
      expansions, or a total of 2,560,000 bpsd.  The Mid-East
      crude mix and the mix of other crudes was assumed to
      be the same as for 1972.  Total non-Mid-East crude
      runs for 1980 were estimated at 14,622,000 bpsd.

          With the projected average refinery operating on
      either Mid-East or other crudes and using low sulfur
      fuels the SO--SO., emissions from cat cracker regenerator
      flue gas will constitute over 60% of the total SO
                                                       X
      emissions, assuming 96% sulfur plant efficiency.  Usir.g
      a sulfur plant efficiency of 99%, the percentage in-
      creases to over 80%.
* A stream day is 24 hours and refers only to the. days when the
  plant is actually operating.  If the plant operates 365 days
  per year,  calendar days and stream days are identical.

-------
    Facilities to desulfurize the feed of 10% of the
existing cat cracker capacity have been installed on the
basis of (1) the improved cat cracking yields and (2)
savings obtained in product desulfurization facilities.
With total 1980 cat cracking capacity estimated at
4,660 mbpsd and total projected cat feed desulfurization
facilities estimated at 684 mbpsd to desulfurize the remain-
ing cat feed would require an investment of about one
billion dollars, assuming that 25,000 bpsd units on
the average are built.  If only those refineries
processing Mid-East crude installed hydrodesulfurization
facilities, the investment would be reduced to $260
million, and almost half of the SO  emissions from cat
                                  X
crackers would be eliminated.

    Improved sulfur plant efficiencies are now required
by legislation in most states.  With tail gas clean-up,
sulfur plants and sulfuric acid plant emissions should
not be important contributors to SO  emissions.

    In many refineries, fuel consumption can be reduced
significantly by improving thermal efficiency.  This
reduces air and usually water pollution; this step can
often be justified with present fuel prices.

    Flue gas scrubbing to permit burning of high sulfur
fuel shows greatest promise where very low value fuel,
such as high sulfur coke, is available and where one
scrubber might service various process units.

    Use of low sulfur distillates or desulfurized
bottoms for fuel to allow sale of refinery gas should
prove attractive.

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3.   Prediction of Refinery SO  Emissions for the Year 1980

    A.   Crude Slate

        The 1980 crude slate was determined by assuming
    that the increase in refinery capacity would be supplied
    totally by Mid-East crude.  It was assumed that the
    proportions of Mid-East crudes in the Mid-East mix
    would be the same in 1980 as in 1973.

        The average non-Mid-East crude charge was determined
    from statistics for average crude runs  (1).  The
    values for 1972 were used since these were the latest
    figures that did not have the distorting effects of
    the oil embargo crisis.  From these data, it was
    estimated that the average Mid-East crude and non-
    Mid-East crude would have 1.7% and 0.7% sulfur
    respectively.

                                 °API         WT%S
         Mid-East Crudes         33.8          1.7
         Other Crudes            34.6          0.7
        ' Total Crudes            34.0          0.8

    B.  Average Refinery Configuration - 1980

        To determine the average refinery configuration
    for 1980, the total 1973 refining capacity, by units
    was extracted from the Oil & Gas Journal  (2).  To
    this was added the refinery construction announced
    through September  , 1974  (3).  Since the lead time
    from announcement  to oil  flow is 3-4 years, these
    expansions will not be completed until 1977-1978 which
    gives a good approximation of refining capacity in

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1980.  Using our best judgement, we eliminated announced
construction that had small probability of occurring.
The remainder gave the approximate total 1980 refining
capacity.

     The refineries most likely to process Mid-East crude
were estimated from our knowledge of the industry-inquiries
received, and general background information developed
from past experience in the refining industry.  The
high sulfur crudes were processed through these refineries
according to the total capacities of the various types of
units comprising these refineries.  Since the total
capacity of these refineries was greater than the total
Mid-East crude imports, the refineries processed non-
Mid-East crudes also.  The rest of the refineries pro-
cessed only non-Mid-East crudes, according to the capacities
of the types of units.

     Configurations for those refineries processing Mid-
East crudes and those refineries not processing Mid-East
crudes are shown in Tables 1, 2, and 3.  On the basis of
percent of crude charged, the refineries processing Mid-
East crude have more vacuum capacity, more hydrotreating
capacity, and essentially all of the residual hydrode-
sulfurization (hydrotreating) capacity.

     Almost all of the new refinery expansions announced
are for Mid-East crudes.  Adding to the total Mid-East
crude processed in 1973 the total indicated by refinery
expansions, we estimate that a total of 2.56 million barrels
of Mid-East crude will be processed in 1980.  The re-
fineries processing this crude will have a total capacity
of 4.632 million barrels per day in 1980.

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                          TABLE 1
     Capacities of Process Units in 1973 and in 1980
Process Unit
Volume Percent of Crude Capacity
1973
Ref .
Crude Distillation 100.0
Vacuum Distillation
Catalytic Cracking
Catalytic Reforming
Cat Reforming Feed
Hydrotreat
Cat Cracking Feed
Hydrotreat
Residuum Hydrotreat
Distillate Hydrotreat
Hydrocracking
Coking
Alkylation
Visbreaking
Lube
35.6
31.0
22.6
17.4
3.4
0.1
19.2
5.8
5.0
5.7
1.5
1.6

1980

All Mid East Non-Mid East
Ref. Crude Crude
Ref. Ref.
100.0
33.0
27.1
21.2
16.6
4.0
0.8
21.8
5.1
5.2
5.0
1.3
1.4
100.0
39.2
24.7
23.2
21.6
3.5
2.8
29.0
6.9
5.9
4.2
0.3
1.8
100.0
30.8
28.1
20.5
14.7
4.2
0.1
19.2
4.3
5.0
5.3
1.7
1.3

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                          TABLE 2

                       Fuel Requirements
                   Mid East Crude Refineries
                                  Capacity      Fuel Consumption
   Unit                            MBPSD            MM Btu/Hr


   Crude                            4,632*           19,250

   Vacuum                           1,810             3,020

   Alkylation                         195

   Catalytic Reformer               1,086            15,800

   Catalytic Cracker                1,144**           1,765

   Coker                              273             2,960

   Visbreaker                          14                99

   Thermal Cracking                    56             1,635

   Naphtha Hydrodesulfurizers       1,004             1,590

   Kerosene/Diesel & Other
   Hydrodesulfurizers               1,338             4,450

   Gas Oil Hydrodesulfurizer          163**             591

   Residuum Hydrodesulfurizer         131               437

   Hydrocracking                      318             2,980

   Asphalt (PDA)                       55               161
   Sub Total      '                                   54,738

   Add 5% for Misc.  Units                             2,737
   Sub Total                                         57,475

   Utility Plant                                     13,535

   Total                                             71,070
 * Mid-East crude included in the charge to these refineries is
   2,560,000 bpsd.


** To desulfurize all of the feed to the cat cracker would require
   981,000 bpsd of new gas oil HDS capacity.  To desulfurize only
   the high sulfur gas oils  would require  500,000  bpsd  capacity.

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                           TABLE 3

                     Fuel Requirements
Non-Mid East Crude
Unit
Crude
Vacuum
Alkylation
Catalytic Reformer
Catalytic Cracker
Coker
Visbreaker
Thermal Cracker
Naphtha Hydrodesulfurizers
Kerosene/Diesel & Other
Hydrodesulfurizers
Gas Oil Hydrodesulfurizer
Residuum
Hydrocracking
Asphalt (PDA)
Other Cracking
Sub Total
Add 5% for Misc. Units
Sub Total
Utility Plant
Refineries
Capacity
MBPSD
12,550*
3,866
668
2,568
3,517
626
207
142
1,857
2,403
521
11
558
289
159


Fuel Consumption
MM Btu/Hr
52,200
6,450
-
37,400
5,430
6,800
1,465
4,140
2,940
8,000
1,890
37
5,240
844
1,490
134,326
6,717
141,043
33,216
  Total                                              174,259
* The refineries processing Mid-East crude also process
  3,072,000 bpsd of other crudes.  See Table 2.

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     The average flow sheet for processing Mid-East crude
in 1980 is projected to be as shown in Figure 1.  This
flow sheet includes essentially all of the residual fuel
hydrodesulfurization announced.  Also, hydrotreating ca-
pacity available in the refineries which will orocess
Mid-East crudes was selectively used for processing the
high sulfur Mid-East fractions.

     The average flow sheet for processing non-Mid-East
crudes in 1980 is shown in Figure 2.  Some of the crudes
are low enough in sulfur that the distillates derived
therefrom may be sold without hydrodesulfurization.
C.  Products and SO  Emissions

     As indicated in tables 4 and 5, the major sources
of SO  emissions in the average refinery are:
     X

     1.  Catalytic Cracking Coke Burn
     2.  Refinery Fuel
     3.  Sulfur Plant Tail Gas
     If low sulfur fuel is burned in the refinery, the
major source of refinery pollution is the flue gas from
the regenerator of the catalytic cracking unit.  In the
regenerator, the coke deposited on the catalyst when the
charge is cracked is burned to reactivate the catalyst and
to produce the heat for the process.  The flue gas pro-
duced is at a high temperature (1150-1400°F); power is
often generated by expanding the flue gas and the heat
is recovered and used for steam generation.

     Referring to Figure 1, it will be noted that the cat
cracker coke from processing the total Mid-East crude
(2.56/ MMbpsd)  will contain approximately 25,000 #/hr of
                      10

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THE  M. W. KELLOGG  COMPANY
            o dhition of PULLMAN INCORPORATED

-------
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     800
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                              TABLE 4

                      Sulfur Dioxide Emissions
                                                (1)
                      Mid East Crude Refineries
                      With Various Refinery Fuels

                                             S in         % of
                             MM#/Hr        Flue Gas      Sulfur
                             Burned  Wt%S    M#/Hr      Emissions
Cat Cracker Coke Other Crudes  0 .3 (2) 3 . 8     11.5          23
Cat Cracker Coke Mid East      0.4(3) 6.4     25.0          50
Fuel
   Refinery Gas                0.7   Nil     Nil          Nil
   Natural Gas                 2.5   Nil     Nil          Nil
Sulfur Plant Tail Gas
   With 96% Sulfur Recovery                  13.4          27
Total                                        49.9        "100.0

Cat Cracker Coke - Total       0.7   5.3     36.5          29
Fuel
   Refinery Gas                0.7   Nil     Nil          Nil
   No. 6 Fuel                  3.3   2.36    77.9          61
Sulfur Plant Tail Gas                        13.4          10j	
Total                                       127.8         100.0

Cat Cracker Coke - Total       0.7   5.3     36.5          69
Fuel
   Refinery Gas                0.7   Nil     Nil
   Distillates                 3.1   0.1      3.1
Sulfur Plant Tail Gas                        13.4
Total                                        52.2

Cat Cracker Coke - Total       0.7   5.3     36.5          61
Fuel
   Refinery Gas                0.4   Nil     Nil          Nil
   0.3% Resid                  3.2   0.3      9.4          16
Sulfur Plant Tail Gas                        13.4          23
Total                                        5975"         100.0
 (1)  These figures are for the total crude processed in these
     refineries, Mid-East plus others.

 (2)  From other crudes.
 (3)  From Mid-East crudes.
                                13

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        TABLE 5




Sulfur Dioxide Emissions
Non-Mid East Crude Processing Refineries




Cat Cracker Coke
Fuel
Refinery Gas
Natural Gas
Sulfur Plant Tail
With 96% Sulfur
Total
Cat Cracker Coke
Fuel
Refinery Gas
No. 6 Fuel
Sulfur Plant Tail
Total
Cat Cracker Coke
Fuel
Refinery Gas
Distillates
Sulfur Plant Tail
Total
Cat Cracker Coke
Fuel
Refinery Gas
0.3% S Resid
Sulfur Plant Tail
Total
With Various

MM#/Hr
Burned
2.0

1.6
4.9
Gas
Recovery

2.0

1.6
6.0
Gas

2.0

1.6
5.7
Gas

2.0

0.2
7.4
Gas

Refinery

Fuels
S in
Flue Gas
Wt%S
3.84

Nil
Nil



3.84

Nil
1.0


3.84

Nil
0.1


3.84

Nil
0.3


M#/Hr
77.2

Nil
Nil

17.8
95 0
y -j • \J
77.2

Nil
60 .0
17.8
BsTo
77.2

Nil
5.7
17.8
100.7
77.2

Nil
22.2
17.8
117.2

% of
Sulfur
Emissions
81

Nil
Nil

19
100
50

Nil
39
11
TOO"
77

Nil
6
17
roir
66

Nil
19
15
TW
           14

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sulfur.  It is estimated that all of the non-Mid-East
crude processed (14.62 MMbpsd) will produce cat cracker
coke containing 84,000 #/hr of sulfur.

     When the coke is burned the sulfur is converted
to S0_ and SO., which appear  in the flue gas.  The
ratio of S0? to SO^ depends primarily on the amount
of oxygen in the flue gas.  For Thermofor Catalytic
Cracking (TCC) units containing 7-8% oxygen in the flue
gas, the percent of sulfur appearing as SO, can he as
high as 40%.  For fluid cat crackers  (FCC) having a CO
boiler, the percent of sulfur appearing as SO- in the
boiler effluent will be on the order of 1%.  For units
with high temperature regeneration, the percentage will
increase to the range of 5-10%.  SO., is a more serious
health problem than S02•

     If the total fuel to the refinery consists of
natural gas plus desulfurized refinery gas, SO  emis-
sions from fuel combustion will be almost negligible.
However, if high sulfur fuel is used to supplement
available refinery gas, the SO  emissions from fuel
can exceed those from the cat cracker.  If desulfurized
distillates are used for refinery fuel, the contribution
of fuel to the total SO  emissions will be small.
                       X

     The sulfur plant tail gas can be a major contri-
buter to the refinery SO  emissions.  Sulfur plants are
                        X
utilized in refineries to remove H,,S from sour gas
streams by converting the H_S to liquid sulfur.  The re-
                           £t
action occurs in two steps or stages.  The first stage
produces S0_.  Since the overall conversion from H_S
to sulfur is never 100% completed, relatively large
Quantities of SO., remain in the sulfur-plant tail
"~               2.
                       15

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gas.  A sulfur plant achieves about 96% conversion.
Hence, about 4% of the sulfur in the feed exits in the
tail gas as SO2.   Flue gas can be cleaned up by processes
such as the Scot, Beavon, IFF and others.  These flue
gas desulfurization processes will increase sulfur re-
covery above 99%.

     Some refineries are undoubtedly still burning, with
no sulfur recovery, small amounts of H?S in their process
furnaces and boilers.  No figure is shown for this source
of pollution.

     A small source of pollution is caused by periodic
regeneration of hydrodesulfurization catalysts and clean-
ing of furnace tubes.  The coke in the catalysts
and on the furnace tubes is periodically burned off.
During the decoking operation the sulfur in the coke is
converted to SO-.  Both these operations occur for only
a very small part of the operating time and are not a
significant source of S0_ pollution.

     Some refiners regenerate the spent sulfuric acid
from their sulfuric acid alkylation units.  These units
should receive the same consideration as chemical plants
producing sulfuric acid.  The overall contribution to
the refinery air pollution problem from these regeneration
units is small.
D.  Specific Schemes Projected for Processing Mid-East
    Crudes
     Based on inquiries M. W. Kellogg has received to
bid on new refineries, several refinery configurations
were developed to show the effect of processing on
sulfur emissions.  Most of these projected refineries
are about 250,000 bpsd.  Hence, these refinery schemes
were based on a 250,000 bpsd crude charge.  The refinery

                     16

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  configurations  differ primarly in residual processing.
  The  residual  processing schemes considered are:

       Case  I.  Coking.
      Case  II.  Residual desulfurization.
    Case III.  Deasphalting of vacuum bottoms followed by
               partial oxidation of deasphalted residual.

       Flowsheets for these configurations are shown in
  figures 3,  4  and 5.  The flowsheets are  based on the
  following  assumptions:

       1.  The  catalytic cracker is a riser cracker using
           zeolite catalyst operating at 75% conversion.
       2.  The  catalytic reformer produces 95 research
           octane clear gasoline.
       3.  The  coking unit is a delayed coking unit.
       4.  The  hydrogen consumption of the hydrodesulfur-
           ization units is based on commercial data.   This
           includes the hydrogen dissolved in the  liquid
           product and the hydrogen in the purge gas as well
           as the chemical hydrogen.  Eighty five  percent of
           the  sulfur in the cat feed and  89% of the sulfur
           in the residuum are removed.

  Case I

       The  delayed coking route represented by this case  is
  the  processing  route chosen by almost all the high sulfur
  crude expansion projects actually being  constructed.
  Figure 3  is a block flow diagram for Case I and  presents
  the  yields and  properties of the intermediate and final
  product streams.  This figure shows a processing scheme
  in which  mercaptans are extracted from the light gasoline,*
  naphtha is hydrotreated and reformed and mid-distillates

* In many cases,  the light gasoline is hydrotreated along
  with cat  feed for sulfur removal.
                     17

-------
NO.           DESCRIPTION
                                    TE     IV    CHECKED
                                                             .Q5?.*.T.'j?j-i.
-------
  are  hydrotreated.   The  vacuum residuum is  sent to the
  coker and the vacuum gas oil and heavy coker gas oil are
  fed  to the catalytic cracking unit.   Propylenes and bu-
  tylenes from the  catalytic cracking  unit are alkylated.
  A variation of this case is to hydrodesulfurize the cat
  feed.  This is indicated by the dotted box labeled HDS.
  High sulfur coke  produced in this process  has limited
  uses and a very low value.

  Case II
       Figure 4 is a block flow diagram for Case II showing
  the yields  and properties of intermidiate and final pro-
  duct streams.  The atmospheric bottoms are hydrodesul-
  furized and then distilled in an atmospheric and a vacuum
  unit.  The  vacuum bottoms become low sulfur fuel.*  By
  increasing  the amount of low sulfur cat cycle oil or
  other distillates included in the residual fuel pool,
  the fuel oil pool sulfur content may be decreased;
  this degradation of distillates to residual fuel in-
  creases the cost of the residual fuel.  Butylenes and
  propylenes  are alkylated.  Cat gasoline is split, the
  light fraction is sent to a mercaptan extraction unit
  and the heavy fraction sent to hydrotreating and re-
  forming.

  Case III

       Figure 5 is a block flow diagram for Case III and
  shows a fuels refinery processing scheme.  Light gas-
  oline and naphtha are desulfurized in one hydrotreat-
  er while the kerosene through gas oils are desulfurized
  in other hydrotreaters.  The vacuum tower bottoms are
  deasphalted.  Deasphalted oil is hydrodesulfurized to-

* The low sulfur vacuum bottoms may be processed in a de-
  layed coking unit to produce electrode grade coke.
                         19

-------
DCSCItrTION
               I   'ON oNiMvaa     B
                                             THE  M. W. KELLOGG COMPANY
                                             	o divitlon of PUUMAN INCORPORATED	
                                                            JOI NUM1E>
                                                                       P4/I7-D
                                                                          DRAWING NUMIEI

-------
                                                               Sz-r I? tr-  Hd   I
                                                               yx                4
        -       .
C-fOO - 
-------
gather with some of the vacuum gas oil and the pitch
is converted to low Btu gas in a partial oxidation unit.
The balance of the vacuum gas oil is hydrocracked.
     In Table 6, the SO  emissions from the three re-
fining schemes are indicated.  Cases II and III address
themselves directly to the problems of SO  emissions
and sulfur contents of heavy fuel oils.  No emission pro-
blems would be expected from these schemes.  In Case I,
problems will be experienced with SO  emissions and the
                                    X
sulfur content of gasolines unless cat feed desulfuriza-
tion facilities are installed.  Also, in Case I, a large
amount of high sulfur coke is produced.  To avoi,d air
pollution problems, this coke would have to be burned
in facilities equipped with flue gas scrubbers, used in
partial oxidation facilities, or sold.
                   22

-------
                                                            Table 6
                                         SO  Emissions  from New Refinery Expansions
                                         Basis:   250,000  BPSD  of Avg.  Mid-East Crude
SOURCE
                                      CASE I
                                                                                                                         CASE III
Cat Cracker Coke
Fuel
Gas
Delayed coke
Sulfur Plant (4)
Total
Cat Cracker Coke
Fuel
Gas
Lou Sulfur Re sid
Sulfur Plant (4)
Total
M#/HR WT %
Fuel S
49.8 6.6
63.6 NIL
220.0 7.4

49.8 6.6

187.0(1) NIL
HOIIE
" "
S in F.G.
it AIR
3,300
NIL
16,300
130
19,730
3,290

MIL
-
1,280
4,570
% of
S0x
16
NIL
78
6
100
72

NIL
-
28
100.0
M*/HR WT %
Fuel S
42,600 0.9
195,000(1> NIL

42,600 0.9

47,600 NIL
264,000 0.9

s in F.G.
«/HR
390
NIL
1860
2250
390

NIL
1630
1860
3880
% of
—X-
17
NIL
83
100.0
10

SIIL
42
48
100
HH/HR
Fuel
NONE
14,900
450,000

NONE

14,900
190,000
-
WT % S in F.G.
S fl/HR
_ _
NIL NIL
(3) _
1860
1860
-

NIL NIL
0.3<2) 570
1860
2430
% of
SO

NIL
100
0

NIL
23
7_7_
100
  (1)   Refinery Gas £ Natural Gas
  (2)   Assume refinery fuel oil treated to 0.3% S.
  (3)   Low Btu Gas
  (4)   96% Recovery with tail gas clean-up Sulfur Recovery 99% +.

-------
4.  Schemes for Reducing Refinery SO  Emissions
      "  '                   —        X      •"" —
    A.   Cat Cracker Feed Desulfurization
        1.  Cost
             The problem of SO  in cat cracker flue gas often can
                              X
        be solved economically by hydrodesulfurizing the feed to
        the unit.  Hydrogenating the feed can achieve an 80% re-
        duction in SO  emissions.  Currently, about 10% of the
                     X
        cat crackers in the U. S. desulfurize their feed pri-
        marily for the economic incentive of improved yields.
             The total cost of desulfurizing cat feed must be
        worked out for a specific refinery.  Basically desulfuri-
        zation reduces the aromatic content of the feed as well
        as the sulfur content.  For constant coke burning capa-
        city, more of the feed can be converted to gasoline at
        the expense of cycle oil and fractionator bottoms.  A
        25,000 bpsd hydrodesulfurization unit required an onsite
        investment of $6.7 million in 1973; with a differential
        of $1.50/bbl in favor of gasoline, the gross profit from
        the unit would be about $3 million/yr.  The inflation
        from mid 1973 to the third quarter of 1974 has been over
        60%, and the differential between No. 2 heater oil and
        gasoline is still about $1.50/bbl.  Until costs and
        prices stabilize, it will be difficult to develop firm
        economics.  Literature references are numerous (32, 33, 34,
        35, 36, 37, 38).

             Few of the announced expansions for running Mid-East
        crude include provision for desulfurizing the cat feed.
        To desulfurize only the half million bbls of Mid East cat
        feed for which no provision has been made in the announced
        expansions would require an investment of about $130 mil-
        lion (mid 1973 basis).  See Table 2.
                                24

-------
    2.   Supplemental Benefits
         A supplemental benefit of cat feed desulfurization
    in addition to improved yields and reduction in SO_
    emissions is a reduction in the sulfur content of the
    gasoline pool.  In the processing scheme of Figure 1,
    the sulfur content of the total gasoline pool could be
    reduced from 0.04% sulfur to 0.01% sulfur.
         Referring to Figure 1, the low sulfur content of
    the gasoline pool could be obtained by the following:

         a.  Cutting cat reformer feed front end at 145°F.
         b.  Mercaptan extraction of the light IBP-145°F
             cut, or including this cut in hydrotreater
             charge.
         c.  Hydrotreating and reforming cat heavy naphtha.
         d.  Mercaptan extraction of light cat gasoline.
         e.  Hydrotreating coker and visbreaker gasolines.
         f.  Desulfurizing the total cat feed.

B.  Reduction in Fuel Requirements

     The energy required to operate a modern refinery is
equivalent to 4-8% of the energy in the crude charge.(13)
This is a huge amount of energy considering the total 1980 crude
throughput of over 17 million bpsd, an increase in ef-
fiency of 15 percent would correspond to a decrease in fuel
consumption of 100,000-200,000 bpsd and a corresponding re-
duction in sulfur emissions from fuel.

     There are a number of ways in which efficiencies in a
refinery can be increased.  One of the simplest ways is to
reduce excess air in the refinery furnaces.  This can be
accomplished by monitoring the percent oxygen in the flue
gas.  One large corporation made a study of more than 50
furnaces and found that some were being operated with as

                         25

-------
much as 200% excess air  (13).  They calculated that if
all the furnaces in their survey were run with 20%
excess air the annual fuel savings would be equivalent
to 1.2 million barrels per year.  The reduction in
sulfur dioxide emissions would vary with the type of
fuel, its source and whether it had been desulfurized.
In some cases, it could result in significant re-
ductions.  Another source of furnace inefficiency is
air leakage.  This can be minimized by replacing worn
gaskets on header boxes and cover plates, and sealing
cracks in surfaces.

    In furnaces operating with high stack temperature,
furnace efficiency can be improved by installing ad-
ditional heat transfer surface in the convection
sections.  Either more tubes can be added or bare sur-
face tubes can be replaced with extended surface tubes.
Air preheaters can be used to increase furnace efficiency
by reducing flue gas temperature and increasing combus-
tion air temperature.

    Another method of reducing  refinery fuels consump-
tion and thereby reducing sulfur emissions is to optimize
heat recovery from refinery streams.  Many product
streams and reflux stream are water cooled.  Some of this
heat can be recovered by preheating feed streams and
reducing furnace requirements.  One study on a 200,000
bpsd refinery indicated that the crude charge temperature
to the furnace could be increased from 457°F to 495°F
by redesigning the crude preheat train to utilize
maximum exchange of reflux  (5).  This represents a fuel
savings of approximately 70 MMBtu/hr.

    Use of hydraulic turbines and turboexpanders to drive
                      26

-------
pumps and compressors also saves on fuel consumption.
Many high pressure gas and liquid streams are reduced
by control valves.  Recovery of this energy through
turbine drivers saves steam which is generated by
burning fuel.  Waste heat boilers can be utilized to
recover heat from streams and to generate plant steam
thereby reducing boiler fuel consumption and sulfur
emissions.

    Use of fanless air coolers is suggested as another
means of reducing energy consumption.  Some air cooler
experts maintain that a fanless air cooler can be designed
to give two thirds of the cooling duty achieved by a
conventional air cooler (4).

    Other methods of increasing refinery efficiency by
lowering fuel consumption include the use of the heat
pump principle on distillation towers (compression
of overhead vapors and condensation of same in reboil
heat); and generation of low pressure steam by conden-
sing overhead vapors.

C.  Use of Low Sulfur Content Fuels

    In tables 4 and 5 the reductions in emissions possible
from use of low sulfur fuels were indicated.  The low
sulfur fuels available, or which can be made available,
are as follows:

    1.  Desulfurized refinery gas.
    2.  Desulfurized distillates.
    3.  Desulfurized residuals.
    4.  Low Btu gas from partial oxidation.

    Low sulfur fuels are considerably more expensive
                      27

-------
than high sulfur fuels.  In table  7, the cost of de-
sulfurizing high sulfur atmospheric bottoms to produce
a fuel oil with 0.3% wt sulfur is developed.  In a
50,000 bpsd unit, the cost is estimated at $2.76/bbl,
corresponding to  44C/MMBtu.  Since this size unit
would employ reactors of maximum size, little reduct-
ion in cost would result from larger units.  However,
the desulfurization cost in a  unit one-fourth this
size would increase to GSC/MMBtu.

    While the current shortage of cheap natural gas
and projected requirements for low sulfur fuels tend
to increase costs, some recuperation of this increased
cost could result from sale of refinery gas.  Sale of
refinery gas and burning of low sulfur residuals, or
even low sulfur coal, in the refinery is a 100% ef-
ficient way of converting these fuels to gas with little
investment.  The substitution of desulfurized distillates
for refinery gas will have no significant impact on
emissions.

    Desulfurized distillates have value to the refiner
considerably above high sulfur visbreaker bottoms, cat
fractionator bottoms, vacuum bottoms, etc.  If EPA
standards prohibit the burning of high sulfur fuel in
the refinery, it would, in general, not be practical for
a refiner to install residual desulfurization facilities
for only his fuel.  The possible exception is cat
fractionator bottoms which might be desulfurized for
refinery fuel at a much lower cost than residual; it
contains no metals which deactivate hydrodesulfurization
catalysts.

    Most refiners will have to purchase low sulfur
                       28

-------
             Table 7
Hydrodesulfurization Economic Summary
End of 1973 Basis
Investment
Process Units
Off Sites
Working Capital
Approx. Royalties

Units Units/D

Feed Cost
Atmos. Resid-High S Bbl 50,000
Product Credits
Sulfur ST 320
C1~C4' FOE Bbl 65°
C5+Naphtha Bbl 1,400
Raw Materials
Cost of 0.3%
Sulfur Fuel Oil Bbl 49,300
Direct Operating Costs
Labor & Super. Manhours 317
Hydrogen Plant - 48 MM SCF/D
Naphtha Bbl 1,400
FOE Bbl 2,900
Utilities
Fuel, FOE Bbl 1,622
BFW M Gal 60
Power - Generated
Cat & Chem.
Misc. Operating Expenses
Maint., 4% ISBL, 2% OSBL
Insurance & Property Tax, 2% ISBL +
Capital Charges
Interest on Working Capital @ 10%
Depreciation - 10% ISBL, 5% OSBL






$/Unit


9.00

4.5
10.50
10.50


8.66

7.00

10.50
10.50

10.50
0.20




OSBL



Return on Total Investment - 15% Before Tax
Total Cost, Low S Resid 49,300
11.76

$67.0 MM
$10.5 MM
$ 6.0 MM
$ 3.0 MM
$86.5 MM
$/D 330 D/Yr
	 M$/Yr

450,000

1,440
6,825
14,700


427,035 140,920

2,220 810

14,700 4,851
30,450 10,049

17,040 5,623
12 4

3,500
350
2,790
1,550

600
7,225
12,975
579,536 191,247
                 29

-------
residual fuel or burn distillates to meet SO  emission
                                            X
requirements.  With present prices of low sulfur
residual and distillates; however, economics probably
dictate the burning of distillates.

    Partial oxidation, particularly coupled with power
recovery could prove attractive in large installations.
Basically, the high sulfur residual is burned with a
limited amount of air to produce H2S and reducing gas.
The H^S is removed, and the low Btu gas is used for
power generation and fuel.

D.  Stack Gas Scrubbing

    Sulfur content of residual fuel oils depends largely
on the origin of the crude.  Table 8 shows the average
sulfur content of residual fuel oils obtained from five
different crudes.  Comparing these sulfur contents with
state regulations (table 9) shows that some form of
desulfurization will have to be performed.  One approach
to solve the sulfur oxide problem is use of stack gas
scrubbing.  Many scrubbing processes are presently being
brought into commercial operation.  Among these are:
the citrate process, the modified lime/limestone process,
the Wellman-Lord process, the Cat-Ox process, the Stauffer
process, the Shell process, and PuraSive S process, and
many others.  The cost of stack-gas cleaning for most of
these processes is competitive.

    Figure 6 shows the approximate cost of stack-gas scrub-
bing  in C/MMBtu as a function of refinery size indicated
by the annual fuel consumption in the refinery.  These
costs were calculated on the basis of a cost estimation
model developed by MWK and presented to EPA in Task 7
report  (33).
                       30

-------
      Table 8  - Average Sulfur Content of Some
                  Residual Fuel Oils
                               Avg.  % Sulfur in
Crude Origin                   700+ °F End Point

  Canadian                          1.5
  Californian                       1.9
  West Texas                        2.0
  Venezuelan                        2.2
  Middle Eastern                    3.7
      Source:  Oil & Gas Journal, Sept. 17, 1973, p.  69.
                         31

-------
               Table 9 - Fuel Oil Sulfur level
                         Regulations
Maryland

     No.
     No.
     No.
2 (proposed-Effective 7/1/75)
4, 5 & 6 (Current)
4, 5 & 6 (Proposed-Effective 7/1/75)
Massachusetts
     No. 2
     No. 4, 5 & 6
       Boston Area
       Rest of State

New Jersey  (Ex Rural Southern Counties)
     No.
     No.
2
4,
5 & 6
NeW York City
     No. 2
     No. 4, 5 & 6

Nassau, Rockland and Westchester

     No. 4, 5 & 6

Proposed by New York State

  New York City plus Suffolk
  Nassau, Rockland & Westchester

     No. 2 (Effective 10/1/74)
     No. 4, 5 & 6  (Effective 10/1/73)
                                       Weight %

                                        0.3
                                        1.0
                                        0.5
                                           0.3

                                           0.5
                                           1.0
0.2
0.3
                                           0.2
                                           0.3
                                           0.37
                                           0.1
                                           0.3
Source:  Chemical Engineering Progress, June 1973, p. 42.
                         32

-------
                              Figure  6
         Approximate  Stack  Gas Scrubbing  Cost  vs.  Capacity
                                     •   Stack  Gas %  2,000  PPM  Sulfur
                                     •   WeiIman-Lord/Al1ied  Scrubber
                                     t   End  of 1973   -   Gulf Coast
                                     t   Refer  to  text for  Cost Basis
400

300


200
100
 90
 80
 70
 60
 50

 40

 30
in
o
  20
  10
                               i   i _ I
                                 '  I
     _L
                                                             J—I
                               5   6   7  8  9  10
                                             20
30
40  50 60
                         Size  -  10
                                  12
                             BTU/YR
                                 33

-------
     As the size of the refinery increases, the cost of
scrubbing the gas decreases and the process becomes super-
ior to hydrodesulfurization.  A breakdown of the econo-
mics is presented in table 10.

     It should be kept in mind that Kellogg's cost esti-
mation model for stack gas scrubbing was designed for an
assumed average of the existing facilities and thus can
not be used as a specific cost estimation tool.

     In a grass roots refinery consideration can be given
to scrubbing all the refinery flue gases in one large
scrubber.  This would reduce the scrubber cost per unit
(Btu, cubic ft) of flue gas.  It would also permit the
use of high sulfur residual oil as fuel to the refinery
furnaces.  A 250,000 bpsd refinery could burn 10,000-
20,000 bpsd of residual fuel.

     The present high demand for sulfur in the U.S. as
well as the World's market is expected to continue
through the next period, mainly because 50 percent of
the U.S. sulfur consumption is used for providing
fertilizers which have been in short supplies for the
past few years  (28).  In 1973, sulfur consumption in
the U.S., as well as in the world, has risen 6.1 percent
and is expected to continue this increase for the next
ten years (29).  The amount of sulfur produced from
sulfur recovery processes was 63 percent higher in 1973
than it was in 1968 (28).  High sulfur prices, comnared
with the very conservative $5/ton used in this study, is
another factor that would increase the competitiveness
of the scrubbing processes which yield sulfur as a by-
product.  Presently, sulfur prices range from a low of
$21/ton up to a high of $50/ton depending on quality
(29).
                        34

-------
                         Table 10

       Approximate Economics of Stack Gas Scrubbing
(Wellman-Lord/Allied Scrubber - Gulf Coast - End of 1973)

                              Refinery Size  -  1012 Btu/yr
                                         30          60.9
Total Plant Investment
      (M$)                   9,060     26,550     40,600

Annual Raw Materials
 Less Credits (M$)             444      2,662      5,404

Annual Labor & Supervision     470        470        470
Total Annual Cost
 (M$/yr)                     3,079      9,531     15,713

 C/MMBtu                       61.6      31.8        25.8
                          35

-------
E.  Evaluation of Alternate Methods for Reducing
    Emissions

    As previously discussed, there are many alternate
methods for reducing refinery SO  emissions.  For many
                                X
refineries, the most attractive step will be cat feed
desulfurization.  This will often pay out from improved
yields and savings in requirements for distillate de-
sulfurization; in most refineries it is the most economic
route to low sulfur gasolines.  Steps for reducing fuel
requirements will pay out with fuel savings in many
cases.  After these steps have been taken, a decision
will probably have to be made if flue gas desulfurization
or burning of low sulfur fuels will be the most attractive.

    As shown in Figure 6, flue gas scrubbing for the
flue gas resulting from burning 4000 MMBtu/hr of 3.5%
sulfur fuel would cost 32C/MMBtu.  The 4000 MMBtu/hr
of fuel corresponds roughly to the fuel requirements
for a 250,000 bpsd refinery.  If the furnaces could
be arranged so that the added ductwork could be paid
out with  3C/MMBtu of revenue, about one million dollars
per year, it would pay the refiner to install flue gas
scrubbing as long as the cost of high sulfur fuel was
35C/MMBtu less than low sulfur fuel.

    Low sulfur fuel costs considerably in excess of
35
-------
must be sold for a give away price, conversion of
atmospheric bottoms is attractive.  The liquid fuel
burned in a refinery is usually a low value pitch of
much less value than atmospheric bottoms.  The de-
sulfurized fuel of Table 6, since it is now low in
metals, could be converted by catalytic cracking to
yield over 100% (by volume) of products in the LPG
to heater oil range.

    In an existing refinery, each refiner must
develop his alternate use value for his high sulfur
liquid fuel, or coke.  This must be compared with the
cost of low sulfur fuel.  Since the cost of high
sulfur fuel can approach zero for high sulfur coke, and
the price of low sulfur liquid fuel approaches dis-
tillate price, there appears to be a large number of re-
fineries where flue gas scrubbing will be economically
attractive.
                       37

-------
5.    Trends - Present to 1985

        The World's energy picture has changed drastically
     during the past year.  The sharp increase in oil prices
     is the main cause for this change.  Future forecasts
     for energy needs which were made a year ago are now
     obsolete becuase of this sudden change, and new
     forecasts may face the same end if the energy scene
     remains instable.

        Four independent forecasts for future energy needs
     are shown in Table 11:  two of which are old (before
     the change), and the other two are new (after the
     change).  All four predict that fossil fuels will
     remain the main source of energy for the coming decade.
     However; they differ in the proportional distribution
     of the individual components.  The old forecasts pre-
     dicted that oil and natural gas will constitute 67-68
     percent of the energy demand in 1980 and 65-66 percent
     of the demand in 1985.  In contrast, the new forecasts
     predict that 69-71 percent of the demand in 1980 will
     be met by oil and gas which will constitute only 53-61
     percent of the demand in 1985.  Both forecasts, old and
     new, agree on the declining importance of oil and gas.
     The new forecasts, however; predict that the role of
     oil and gas will be declining at a rate three times
     faster than the old predictions,  if the new gover-
     ments  programs to curb the oil imports pass through
     legislation,  the new predictions will most likely re-
     present  the future energy market.   Between now and
     1980,  coal,  especially low sulfur coal, will take up
     the slack left by oil and gas.   Nuclear fuels will
     probably have a more prominent role in the period
     1980-1985.
                                       A

         Figure  7 - shows the domestic demand for residual
     fuel oil (RFO),  asphalt and coke since 1964.   It is
                             38

-------
                                          Table 11-a -  Energy Outlook  -  1974
                              NEW FORECASTS
                                                                              OLD  FORECASTS
Energy Source
Domestic Crude

Imported Crude
Natural Gas
Total Oil & Gas
Coal
Nuclear Fuel
W.B. Bryant
Shell Oil
Q Btu/yr
(1015 Btu)*
24

16
23
63
15
3
1
Co.
% of
Demand
28

19
27
74
17
3
A Leading Research W.D. Trammell
Institute Fluor Corp.
Q Btu/yr
CIO15 Btu)
22

11
23
56
13
-
% of Q Btu/yr
Demand (1015 Btu)
31
{36
16
33 27
80 63
18 16
4
% of
Demand

{40

30
70
18
4
J.L. Reed
Office of Oil & Gas
Q Btu/yr
(1015 Btu)

{37

27
64
15
3
% of
Demairi

{43

32
75
18
3
Assuming 1 barrel =6.5 MMBtu

-------
                             Table 11-b- Energy Outlook Forecast  for  1980
                                 NEW FORECASTS
                 W.B. Bryant
                  Shell Oil Co.	
Energy Source   Q Btu/yr       % of
               (1015 Btu)*    Demand
                                          A Leading Research
                                               Institute
                                            Q Btu/yr
                                            (1015 Btu)
                       % of
                      Demand
                                                                                 OLD  FORECASTS
                                 W.D. Trammell
                                   Fluor Corp.
                    Q Btu/yr
                    (1015 Btu)
 % of
Demand
    J.L. Reed
Office of Oil & Gas_
               % of
              Demand
                                                                                           Q Btu/yr
                                                                                          (1015 Btu)
Domestic Crude

Imported Crude
Natural Gas

Total Oil & Gas
Coal
Nuclear Fuel
                      24
22
23
                                                           28
                                                                       {42
                                               {38
                                              {42
                       {38
32
20
76
22
7
29
18
69
20
6
7
29
59
16
8
8
35
71
20
10

33
75
20
12

30
68
18
11

32
74
19
13

29
67
17
12
*  Assuming 1 barrel -- 6.5 MMBtu

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                                 Table 11-c-  Energy Outlook Forecast for  1935
                                  HEW FORECASTS
                                                                                 OLD  FORECASTS
Energy Source
Domestic Crude

Imported Crude
Natural Gas
Total Oil & Gas
Coal
Nuclear Fuel
W.B. Bryant1
Shell Oil Co
Q Btu/yr
(1015 Btul*
21

27
21
69
26
22
A Leading Research
Institute
% of
Demand
16

21
16
53
20
17
Q Btu/yr
(1.015 Btu)
20

6
32
58
20
15
% of
Demand
21

6
34
61
21
16
W.D. Trammell
Fluor Corp.
Q Btu/yr % of
(1C15 Btu) Demand

(46 (35

39 30
84 65
22 17
20 15
J.L. Reed
Office of Oil & Gas
Q Btu/yr % of
(1015 Btu) Demand

M8 {36

40 30
88 66
23 17
22 16
Assuming 1 barrel = 6.5 MI-IBtu
1.   Chemical Engineering Progress - Aug. 1974, p. 8
2.   October 1974
3.   Chemical Engineering Progress - April 1973, p. 69
4.   Chemical Engineering Progress - Nov. 1973, p. 73

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                                  Figure  7

              Domestic Demand  for  Heavy  Fuels  Projected  Through  1985
   2000
CD
en
-o
c:
1C
   1000
    900
    800
    700
    600
    500

    400

    300
    200
0
a
100
 90
 80
 70
 60
 50

 40

 30


 20
                                              Res'
                                                  R.F.O. < 2% S
                                                  R.F.O. < 1% S
                                                  R.F.O. < 0.5% S
                                                         Coke.
                                             Mar
     10
                                       I
                                         I
I
 I
       64    66    68    70     72     74     76     78
                                   Calendar Year
                                                     80
            82
84   86
                                     42

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expected that the high demand for RFO which existed in
1972-73 will continue to increase at a relatively lower
rate:  Demand will probably increase because of the
continued growth of the energy needs to keep up with
the growing economy of the United States.  The
rate of increase will be lower than it had been for
the following reasons:  (1) the current policy of the
U.S. government to slow down the growth of energy
from 4.5% per year to 2% per year (26), (2) the prices
of residual fuel oil have risen sharply in the previous
period and resulting high cost will contribute to a
slow down on its demand as a result of competition
from low sulfur coal, (3)  desulfurization methods
are being investigated vigorously at the present time
which will help the marketability of high sulfur
coal, (4) the availability of virgin low sulfur fuel
oil is limited since 80 percent of the world's oil
has a high sulfur content  (27).

    Figure 8 shows the roles of imports and domestic
production of residual fuel oil.  Since 1970, the sharp
decline in production of residual fuel oil in the U.S
refineries had stopped.  This resulted in a simultaneous
decrease of the continuing dominence of imports.
Whether this reverse of trends will continue or not
will be largely dependent on the profitability
of producing RFO compared to that of producing gasoline.
 If  the  government  imports  policy become a  reality,  this
 trend will  most  likely  continue.

     As  can be seen  from Figure 9, the main  portion of
 residual  fuel oil  is  being consumed by electric utilities.
 Their share has  been  increasing in the past  few years
 on  behalf of the other  consumers.  This trend will  pro-
 bably stop  and may even reverse itself when  cheaper coal

                         43

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                                             Figure 8

                                  Production and Imports of RFO
                           [Bureau of Mines Data-Petroleum Statements]
     70
                            Imports
     60
to
E
CD
Q

O
U_
o:

4-
o
50
     40
     30
                          Product!on
       64      66      68      70      72      74      76

                                          Calendar Year
                                                          78
80
82
84
86

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        60
                                                Figure 9

                              Consumption  of Residual  Fuel  Oil By End Use

                                    [Annual  Statistical  Reviews-API]
Ul
     c
     rO
     
-------
takes its prominent role in the near future.  The
amount of residual fuel oil used for heating and
for industrial use will probably increase as natural
gas supplies become more limited and as natural
gas is shifted more to production of chemicals.

     Demand for asphalt and coke is not expected to
change drastically.  The steady slow increase in this
demand, as shown in Figure 7, would probably stav on
the same order of magnitude although the first half
of 74 showed a slight decrease from the same oeriod
of 1973 (30).   Coke gasification to produce low Btu
gas for refinery use might have a slight impact on
coke demand.  Since 1964, approximately 95% percent of
the domistic demand for asphalt has been produced in
the U.S. (30).  This will probably remain the case
for the coming ten years.  Approximately/ 75 percent
of this asphalt is used for paving purposes and 18
percent for roofing (30).

     The production of low Btu gas from heavy fuels is
being investigated by many companies.  Most of the
information is confidential.  Tv/o studies were reported
in Chemical Engineering - July 22, 1974.  The investi-
gations were those of U.S. government agencies.  The
capital investment for producing 235 billion Btu per
day of low Btu gas from coal was found to be 165-210
$million.  The cost of production is estimated to be
110-125 £/MMBtu.  A recent study conducted by MWK for
EPA (34) indicated that stack gas scrubbing may be far
cheaper than the production of low Btu gas from coal
to supply fuel for a 1000 MW new conventional power
plant.  Based on that study it was shown that the cost
                     46

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of producing low Btu gas varies almost linearly with
coal cost.  At a coal price of $5/ton, it would probably
cost 72C/MMBut as compared to 199
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6.   Conclusions
    Based on the results of this study, it can be concluded
    that:

    1.  Stack gas scrubbing could be economical in large
        installations burning high sulfur-fuels that clean-
        up flue gas from several sources in the refinery.
        This system has the potential to reduce sulfur emis-
        sions in a refinery to meet current air pollution
        standards.

    2.  Desulfurization of cat cracker feed has proven
        economical on the basis of improved cat cracker
        yields and gasoline quality and savings in light
        cycle oil desulfurization.  Future requirements for
        low sulfur gasoline makes this route more attractive.
        Assuming low sulfur fuel and sulfur plant tail gas
        clean up, addition of cat feed hydrotreating can
        reduce refinery sulfur emissions by about 80%.

    3.  Refineries with high sulfur residual oil and no
        flue gas scrubber raust sell their residual oil to
        users that have flue gas scrubbers to avoid vio-
        lating air pollution standards.

    4.  Improved refinery energy efficiency, sulfur-plant
        tail gas clean up and burning low sulfur refinery
        fuels will reduce sulfur-oxide emissions.

    5.  Fossil fuels will continue to dominate the energy
        market in this century.  But coal will have a more
        prominent role in the next ten years.
                           48

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6.   Technology is available to go to any level of sulfur
    emissions standards but the costs of doing so incre-
    ases exponentially, as lower levels are achieved.
    The cost to benefit ratio must be kept in mind when
    proposals are made to lower SO   emission levels.
                     49

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 References

„!.  American Petroleum Institute Annual Statistical
     Review, U.S.  Petroleum Statistics 1956-1972,  April 1973.
 2.  Annual Refining Survey, 0. & G.  J.  72,  No.  13,  82-103,
     (April 1, 1974) .
 3.  World Wide Construction, O. & G. J., 72,  No.  40,
     84-93, (Oct.  7,  1974) .
 4.  Doyle, P.T. & Benkly,  G.J., Hydrocarbon Processing,
     52^ No. 7, 81-86  (July, 1973).
 5.  Firth, J.F. et.  al., Ibid, 89-91.
 6.  Mai, A., Ibid, 109-112.
 7.  Brown, L.C. et.  al., Ibid, 115-116.
 8.  Reed, Robert D.,  Ibid, 119-121.
 9.  Robertson, J.C.,  Chem. Eng. 82,  No. 2,  104-111  (Jan.
     21, 1973).
10.  Fleming, J.B., Lambrix, J.R., Smith, M.R.,  Ibid,  112-122
11.  Braun, S.S.,  Hydrocarbon Processing, 52,  No.  5, 81-85
     (May, 1973) .
12.  Woodard, A.M., Ibid, 106-108.
13.  Cherrington,  D.C.,  and Michelson, H.D., 0.  &  G.
     Journal, 72^  No.  35, 59-68 (September 2,  1974).
14.  Hayden, J.E., and Lewis, W.H.,  API  Preprint,  No.
     28-73, Wednesday,  May 16, 1974.
15.  Brown, C.L. and Kraus, M., API  Preprint,  No.  30-73,
     May 16, 1973.
16.  Hildebrand, R.E.,  et.al., Japan Petroleum Institute,
     October 23-24, 1973.
17.  Hildebrand, R.E.  and Taylor H.,  Jr., Technical  Session
     of S. Texas Section of AIChE, Nov.  2, 1973.
18.  Production of Low Sulfur Gasolines  Task 10, Phase
     2. Contract No.  68-02-1308 by M.W.  Kellogg
19.  Atmospheric Residue Processing Study, RDO-2472-04 by
     M.W. Kellogg.
20.  Guide to Refinery Operating Costs by W.L. Nelson.
                        50

-------
 References (cont'd.)

21.  Clean Fuels Refinery for Columbia Gas,  Job 5905  by
     M.W. Kellogg.
22.  Synthesis Gas Production Tech.  Report for Union
     Carbide,  Job 5012 by M.W. Kellogg
23.  1000 STPSD NH3 Pet. Using Texaco Part OX, RDO-3373-01B.
24.  Conn, A.L., CEP 69^ No. 12, 56-61 (Dec.,  1973).
25.  Shell Oil Partial Oxid. Design Manual,  pg. 7.
26.  Platt's Oilgram,  October 18, 1974, p. 3 & 5.
27.  Chemical Engineering Progress,  August,  1974.
28.  Chemical Week, March 20, 1974,  p. 23.
29.  Chemical Marketing Report, "Chemical Profile  -
     Sulfur" September 23, 1974.
30.  Bureau of Mines - Department of the Interior:
     1) Petroleum Statements
     2) Availability of Fuel Oils by Sulfur Levels
     3) Minerals Yearbooks
31.  Monroe, E.S., 0.  & G. J., 64, No. 48, 66-69,  (Nov.
     28, 1966).
32   Ritter, Ronald. E., et. al., O. & G. J.,  72,  No. 41,
     99-110 (Oct. 14,  1974).
33.  Evaluation of R&D Investment Alternatives For  SO
                                                     X
     Air Pollution Control Processes, EPA 650/2-74-098,
     Task 7 report M.W. Kellogg.
34.  Comparison of Flue Gas Desulfurization, Coal Lique-
     faction and Coal  Gasification,  M.W.  Kellogg RDO  4118r34.
                       51

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