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.
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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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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
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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
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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 -
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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
-------
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
-------
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
-------
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
-------
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
-------
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
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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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