EPA-650/2-74-130
JULY 1974
Environmental Protection Technology Series
!i$;5S|6$$i$^
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EPA-650/2-74-130
PRODUCTION
OF LOW-SULFUR GASOLINE
by
W. F. Hoot
M. W. Kellogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
Contract No. 68-02-1308
ROAP No. 21ADE
Program Element No. 1AB013
EPA Project Officer: John B. Moran
Special Studies Staff
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
July 1974
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U. S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOC1OECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
11
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CONTENTS
Page
LIST OF FIGURES vi
LIST OF TABLES vii
PART 1. PRODUCTION OF LOW-SULFUR GASOLINES (PHASE 1) ... 1
1. INTRODUCTION 3
2. SUMMARY 5
3. DISCUSSION 7
GENERAL REFINERY SITUATIONS 7
U.S. PRODUCTION OF PETROLEUM PRODUCTS 9
UNLEADED GASOLINE 13
PHASE-DOWN OF LEAD IN GASOLINE 15
OCTANES OF TOTAL U.S. GASOLINES 16
SULFUR IN GASOLINE BLENDING COMPONENTS .... 18
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE
WITHOUT NEW FACILITIES 21
4. DESULFURIZATION OF GASOLINE 23
CASE 1: TYPICAL "A" REFINERY 23
CASE 2: "A" REFINERY WITH HYDRODESULFURIZATION
OF CATALYTIC CRACKER FEED, LIGHT VIRGIN
COKER GASOLINE 26
CASE 3: "A" REFINERY WITH HYDRODESULFURI-
ZATION OF LIGHT VIRGIN, LIGHT COKER AND
CATALYTICALLY CRACKED GASOLINES 35
SULFUR DISTRIBUTION 42
APPENDIX A. COSTS 45
APPENDIX B. OIL EQUIVALENT OF UTILITIES 47
APPENDIX C . SOURCES OF INFORMATION 47
PART 2. PRODUCTION OF LOW-SULFUR GASOLINE (PHASE 2) .... 51
1. INTRODUCTION 53
2. SUMMARY 55
3. EPA REGULATIONS ON GASOLINES 57
111
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Page
UNLEADED GASOLINE 57
PHASE-DOWN OF LEAD IN GASOLINE 57
4. PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE
IN PRESENT U.S. REFINERIES 59
DEFINITION OF "A" TYPICAL U.S. REFINERY 59
"A" TYPICAL U.S. REFINERY (CASE 1) 59
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE
IN PRESENT FACILITIES 59
5. DESULFURIZATION OF GASOLINE 75
CASE 2: "A" REFINERY WITH HYDRODESULFURIZA-
TION OF CATALYTIC CRACKER FEED AND LIGHT
GASOLINES 75
Investment to Produce Low-sulfur Gasoline in the
United States - Case 2 83
Potential Gasoline Production in Case 2 Lead
Phase-down 84
CASE 3: "A" REFINERY WITH HYDRODESULFURIZA-
TION OF CATALYTICALLY CRACKED AND LIGHT
GASOLINES 86
SULFUR DISTRIBUTION 95
APPENDIX A. GENERAL SITUATIONS OF REFINERIES
IN THE UNITED STATES 97
APPENDIX B. U.S. PRODUCTION OF PETROLEUM
PRODUCTS 101
APPENDIX C. COSTS 109
APPENDIX D. OIL EQUIVALENT OF UTILITIES Ill
APPENDIX E. SOURCES OF INFORMATION 113
PART 3. PRODUCTION OF LOW-SULFUR GASOLINES IN
CALIFORNIA REFINERIES 115
1. INTRODUCTION 117
2. SUMMARY 119
3. PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE
IN PRESENT CALIFORNIA REFINERIES 121
CRUDE OILS RUN IN CALIFORNIA REFINERIES .... 121
AVERAGE OF CALIFORNIA REFINERIES - CASE 1 ... 121
IV
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Page
SALES OF PREMIUM AND NO-LEAD GASOLINE IN
CALIFORNIA 125
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE
IN PRESENT CALIFORNIA REFINERIES 134
4. DESULFURIZATION OF GASOLINE 137
GENERAL 137
CASE 2: AVERAGE CALIFORNIA REFINERY WITH
HYDRODESULFURIZATION OF CATALYTIC
CRACKER FEED AND LIGHT GASOLINES 137
CASE 3: AVERAGE CALIFORNIA REFINERY WITH
HYDRODESULFURIZATION OF CATALYTIC
CRACKED GASOLINE AND LIGHT GASOLINES 138
SULFUR DISTRIBUTION IN REFINERY PRODUCTS
AND EMISSIONS 146
DISCUSSION 146
APPENDIX A. SURVEY OF REFINERIES IN CALIFORNIA . . 152
APPENDIX B. SOURCES OF INFORMATION 157
TECHNICAL REPORT DATA AND ABSTRACT 158
v
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LIST OF FIGURES
Figure Page
1-1 Typical ASTM Distillations of Petroleum Products 8
1-2 Projected Percent of Sales of Premium and No-Lead Gasolines . 14
1-3 Octane of Total U.S. Gasoline Pool in 1972 17
1-4 Case 1: Typical "A" Refinery 24
1-5 Case 2: "A" Refinery with Hydrodesulfurization of
Catalytic Cracker Feed, Light Virgin Gasoline
and Light Coker Gasoline 28
1-6 Case 3: "A" Refinery with Hydrodesulfurization of
Light Virgin, Light Coker and FCC Gasolines 36
2-1 "A" Typical U.S. Refinery (Case 1) 62
2-2 Octanes of Total Gasoline Pool 67
2-3 Projected Percent of Sales of Premium and No-Lead Gasolines . 72
2-4 "A" Typical U.S. Refinery with Hydrodesulfurization of Cat
Cracker feed and Light Gasolines 76
2-5 "A" Typical U.S. Refinery with Hydrodesulfurization of Cat
Cracked and Light Gasolines 88
A-l Typical ASTM Distillations of Petroleum Products 99
B-l Octane of Total U.S. Gasoline Pool in 1972 107
3-1 Flow Scheme for Average of California Refineries 126
3-2 Octanes of Total Gasoline Pool 132
3-3 Projected Percent of Sales of Premiums and No-Lead
Gasolines in California 133
VI
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LIST OF TABLLS
Table Page
1-1 U.S. Production of Petroleum Products
in 1972 10
1-2 U.S. Demand for Mid-distillate by Use
in 1973 11
1-3 Typical Properties of Petroleum Products 12
1-4 Sulfur in Light Virgin Gasolines 19
1-5 Sulfur in Gasoline Blending Components 20
1-6 Potential Gasoline Production with Lead
Phase-down 22
1-7 Comparison of Products
(1972 U.S. Production, Case 1, Case 2
and Case 3) 30
1-8 Costs for Gasoline Desulfurization - Case 2 31
1-9 Investment for Process Units - Case 2 32
1-10 Comparison of Yields - Case 1 and Case 2 33
1-11 Utilities and Catalyst Replacement - Case 2 34
1-12 Cost for Gasoline Desulfurization - Case 3 38
1-13 Investment for Process Units - Case 3 39
1-14 Comparison of Yields - Case 1 and Case 3 40
1-15 Utilities and Catalyst Replacement -Case 3 41
1-16 Sulfur Distribution 43
2-1 Comparison of Process Units in Case 1 with
U.S. Average 64
2-2 Comparison of Products and Yields - 1972
U.S. Production vs. Typical Refineries 65
2-3 Sulfur in Gasoline Blending Components 69
2-4 Sulfur in Light Virgin Gasolines 70
2-5 Potential Gasoline Production in Case 1 with
Lead Phase-Down 73
2-6 Cost for Gasoline Desulfurization - Case 2 79
2-7 Investment for Desulfurization Facilities-
Case 2 80
2-8 Comparison of Yields - Case 1 and Case 2 81
2-9 Utilities and Catalyst Replacement - Case 2 82
2-10 Potential Gasoline in Case 2 with Lead Phase-
Down 85
vii
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2-11 Octane Debit for Case 3 90
2-12 Cost for Gasoline Desulfurization - Case 3 91
2-13 Investment for Desulfurization Facilities -
Case 3 92
2-14 Comparison of Yields - Case 1 and Case 3 93
2-15 Utilities and Catalyst Replacement - Case 3 94
2-16 Sulfur Distribution 96
B-l Crude Capacities of U.S. Refineries in 1973 102
B-2 Capacity of Process Units in United States
in 1973 103
B-3 U.S. Refinery Products in 1971 104
B-4 U.S. Demand for Mid-Distillates by Use in 1973. . . 105
B-5 Typical Properties of Petroleum Products 106
3-1 Crude Oils for District 5 122
3-2 Selected Crude Mix 123
3-3 Processing Units in California Refineries 124
3-4 Capacities of Process Units in Case 1 Compared
with California Refineries 128
3-5 Comparison of Products and Yields - West Coast
Production, Case 1, Case 2, and Case 3 129
3-6 Overall Refinery Material Balance - Case 1 130
3-7 Gasoline Pool - Case 1 ' 131
3-8 Potential Gasoline Production in Case 1 with Lead
Phase-Down 135
3-9 Overall Refinery Material Balance - Case 2 139
3-10 Gasoline Pool - Case 2 140
3-11 Investment for Desulfurization Facilities - Case 2 . . 141
3-12 Potential Gasoline Production in Case 2 with Lead
Phase-down 142
3-13 Overall Refinery Material Balance -Case 3 144
3-14 Gasoline Pool - Case 3 145
3-15 Investment for Desulfurization - Case 3 147
3-16 Costs for Gasoline Desulfurization - Cases 2 and 3 . . 148
3-17 Sulfur Distribution in Refinery Products and
Emissions 149
3-18 Refinery Runs - PAD District 5 (West Coast) 150
3-19 Average Properties of Product Sales in Southern
California 151
viii
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PART 1
PRODUCTION OF LOW-SULFUR GASOLINES
(PHASE 1)
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CHAPTER 1
INTRODUCTION
This part of the report covers work which was performed under Contract No.
68-02-1308, Environmental Protection Agency, Office of Research and Moni-
toring, Task No. 10, Phase 1.
The crude mix used in Phase I resulted in capacities of the reformer,
catalytic cracker and alkylation units which do not match the average U.S.
refinery capacities. Future work planned for Phase II will modify the
Phase 1 study in order to match the average U.S. production capacities of
these units.
Future work planned for Phase III will be based on crudes and refinery
capacities typical of the Los Angeles area.
Catalytic converters are to be installed in the exhaust systems of new cars
starting with the 1975 model year. The use of catalytic converters is in-
tended to control carbon monoxide and hydrocarbon emissions. However, the
catalysts convert sulfur in the gasoline into sulfuric acid mists in the exhaust.
The purpose of this study is to determine the impact on oil refineries to
produce unleaded, low-sulfur gasolines and also to desulfurize all gasolines
produced for United States sales.
Prior to installation of additional desulfunzation process units, unleaded,
low-sulfur gasolines would have to be blended from existing low-sulfur
gasoline blending .stocks.
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CHAPTER 2
SUMMARY
Automotive exhausts are to have catalytic mufflers for pollution control
starting with the 1975 models. However, the catalysts convert the sulfur
in gasoline into sulfunc acid mists in the exhaust.
This study indicates that the "typical" United States refinery can produce
no-lead, low-sulfur gasoline blended from normal butane, alkylate and re-
formate. The predicted sales percent of no-lead and premium gasolines
can be met for 1975 and 1976 with the total gasoline production meeting
the EPA phase-down of lead antiknock additives. New desulfurization and
octane upgrading facilities would have to be onstream by 1977 to produce
the required sales percent of both no-lead, low-sulfur gasoline and premium
gasoline.
The total gasolines could be made low sulfur by hydrodesulfurization of
the gas oil feedstock to catalytic cracking and hydrodesulfurization of the
light virgin and light thermal gasolines. Economics indicate that this scheme
would add 0. 74 cents per gallon to the cost of gasoline production.
An alternate case considers hydrodesulfurization of the catalytically cracked
gasoline rather than the feedstock to the catalytic cracker. Economics in-
dicate that use of this scheme to produce low-sulfur gasoline would add
0. 95 cents per gallon to the cost of gasoline production. This cost includes
a penalty of 0. 33 cents per gallon debited to the lower octane resulting
from partial hydrogenation of olefins in the FCC gasoline.
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CHAPTER 3
DISCUSSION
GKNKKAL UKKINKHY SITUATIONS
No two crude oils or two refineries are the same. Furthermore.
no two refineries will produce and have the same product demand.
Depending upon the crude properties and rehnery process capabili-
ties, different refineries are Beared to the following categories or
combinations thereof:
Productions of gasolines, mid-distillates and residual oil.
Petrochemical production.
Lubricant production.
Asphalt production.
In crude topping and vacuum operations, crude oils can be distilled
into fractions with true boiling cut points approximately as follows:
Butanes and lighter components to gas recovery.
Pentanes to 200° I light gasoline for blending to gasoline
or isomerization ol the pcntaneb and hcxanes to upgrade the
octane number.
200 °F - 350° !• naphtha for reformer leedstock to upgrade
the octane number or produce aromatics.
350 °1 - 500° 1- kerosine for production of aviation jet turbine
fuel and kerosine or for blending to diesel fuel or No. 2 fuel oil.
600°I - l.OOOT gas oil feedstock to catalytic cracking,
thermal cracking or hydrocrackmg.
Heavier than 1,000 °F residuum for blending No. 6 fuel oil
or to asphalt or produced as feedstock for visbreaking, de-
layed coking, fluid coking or solvent deasphalting.
Typical ASTM distillations of refined products to sales are shown in
Figure 1-1. Gasolines distill in the range of 80° F to 400° F, kerosine
and jet luel (kerosme-type) distill in the range of 340° F to 530° F, and
diesel fuel and No. 2 luel oil distill in the range of 350 °F to 650° F.
-------
§
r^
o
U.S. BUREAU MINES
PETROLEUM PRODUCTS SURVEYS
80
loo"
•VOL % DISTILLED
Figure 1-1. Typical ASTM distillations of petroleum products
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U.S. PRODUCTION OK PETROLEUM PRODUCTS
United States refineries produce petroleum products in relation to
the market demands for quantities and properties.. Each refinery
bases its operations on market demands, and availability oi crudes
within the limitations of its refinerv process units and the flexibility
of operating conditions.
Table 1-1 shows the U.S. production of petroleum products in 1972.
Table 1-2 shows the U.S. demand of mid-distillates by use in 1973.
The term "mid-distillates" refers to the distillates boiling between
gasoline and No. 6 fuel oil and comprises the kerosine, aviation
jet fuel, diesel fuels and No. 2 heating oil. Kerosine, aviation jet
fuel and No. 1-D diesel fuel are produced from the distillates boiling
between 350° I- and 500° I' true boiling cut points. No. 2 heating
oil and No. 2-D diesel fuel are blends of essentially 50 percent
of the 350° F to 500° I~ fraction with 50 percent of the 500° 1 to
600 °F fraction.
Table 1-3 shows typical properties of the petroleum products sold
in the United States m 1972 and 1973.
It appears that the crude oils to supply needs in the Lnited States
above the domestic production will be supplied by the Persian Gulf
countries. These crude oils have high sulfur contents and yield
more residual fuel oil.
Therefore, it is expected that the sulfur content in the products
will increase in the future unless additional desulfurization units
are installed.
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Table 1-1. U.S. PRODUCTION OF PETROLEUM PRODUCTS IN 1972
Production
Gasoline from Crude
Natural Gas Liquids to Gasoline
Gasoline Content of Naphtha-type
.let Fuel
Kerosine
Kerosme-type Jet J-'uel
Kerosine Content of Naphtha-
type Jet l-uel
Distillate Fuel Oil
Residual Fuel Oil
Lubricants
Losses
Unaccounted
Crude Huns to Stills Plus
Natural Gas Liquids to
Gasoline
Refinery Input
Crude Runs to Stills
Natural Gas Liquids to Gasoline
Million Barrels
Yield,
2.014
305
38
2.357
80
233
38
351
964
293
65
5
552
4,587
Million Barrels
4,282
305
47.0
7.1
0.9
55.0
1.9
5.4
0.9
8.2
22. 6
6.8
1.5
0. 1
12.9
107.1
Input. %*
100.0
7. 1
4,587
107.1
:Volume percent on crude input
10
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Table 1-2. U.S. DEMAND FOR MID-DISTILLATES BY USE IN 1973
Million Barrels
Kerosine 80 6. 1
Kerosine-type Jet Fuel 233 17.6
Kerosine Content of Naphtha-type Jet Fuel 38 2.9
No. 1 Range Oil 15 1.1
^^^™"^~ j^^nr ^5^^^^^
ODO £1.1
Diesel P~uel Used on Highways 164 12.4
Industrial Uses 50 3.8
Oil Company Fuel 14 1.1
Railroads 86 6. 5
Vessel Bunkering 21 1.6
Military Uses 17 1.3
"Z6TT
Heating Oil 509 38.5
Gas and Electric Company Public
Utility Power Plants 35 2.6
Miscellaneous and Unaccounted 60 4.5
Total Mid-distillates 1,322 100.0
11
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1'able 1-3. TYPICAL PROPERTIES OF PETROLEUM PRODUCTS
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-------
UNLEADED GASOLINE
The Environmental Protection Agency has issued regulations
(Jan. 10, 1973) on unleaded gasoline (minimum 91 research octane)
to be supplied starting in July, 1974.
Unleaded gasoline to be used in automobiles equipped with catalytic
converters is to be generally available in United States.
General Motors announced plans to equip all its 1975 models with
converters, compared to about 60 percent for Ford. Thus about
80 percent of the 1975 automobiles will have catalytic converters.
Figure 1-2 shows predicted future sales percent of unleaded and
premium gasolines.
13
-------
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/NO-
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PREMIUM GASOLINE
SALES
/
/
PREMIU::
GASOLINE
RECOMMENDED
FOR CARS
OS ROAD
xV
x/x
\
1965
1970
1975
1980
1985
1S90
YEAP
Figure 1-2. Projected percent of sales of premium and no-lead gasolines.
14
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PHASE-DOWN OF LEAD IN GASOLINE
The Environmental Protection Agency has ordered a phased reduction
of lead antiknock additives in gasoline (Federal Register, Dec. 6, 1973).
These regulations restrict the average lead content in all grades of
gasoline (including unleaded gasoline) produced by any refinery as
follows:
Lead Content
January 1 Grams per Gallon
1975 1.7
1976 1.4
1977 1.0
1978 0.8
1979 0.5
15
-------
OCTANES OF TOTAL U. S. GASOLINES
The 1972 properties of the total U.S. gasoline pool were estimated
from U.S. Bureau of Mines surveys and Ethyl Corporation sales
data as follows:
Research Octane 97.5
Motor Octane 90. 0
Lead, g/gal. 2.24
Sulfur, wt% 0.031
The response of lead content in the total U. S. gasoline pool was
estimated from the lead response of various premium and regular
gasoline blends. Figure 1-3 shows the research and motor octanes
of the total U. S. gasoline pool in 1972 as a function of lead content.
16
-------
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-------
SULl-'UR IN GASOLINE BLENDING COMPONENTS
The sulfur contents of various light straight gasolines are shown in
Table 1-4, and the sulfur contents in miscellaneous samples of other
gasoline blending components are shown in Table 1-5.
The sulfur content is variable and depends upon the crude source for
catalytically cracked gasoline, light straight-run gasoline, natural
gasoline and coker or thermal gasoline.
Reformate and alky late can be considered sulfur-free. The bi-
metallic reformer catalyst requires that the feed naphtha be de-
sulfurized to less than 1.0 ppm sulfur. The feedstocks to alkylation
are desulfurized or essentially sulfur-free. In alkylation, the
hydrofluoric acid catalyst or sulfuric acid catalyst quantitatively
removes sulfur.
Therefore, production of sulfur-free gasoline generally will require
the desulfurization of the thermally cracked gasoline, catalytically
cracked gasoline and light straight-run gasoline.
Desulfurization of the gas oil feedstock to catalytic cracking will
produce catalytically cracked gasoline with low sulfur content.
18
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Table 1-4. SULFUR IN LIGHT VIRGIN GASOLINES*
Sulfur, WT %
Crude Source In Light Gasoline*
East Texas 0. 01
West Texas Intermediate Sweet 0.038
Ellenberger (Texas) 0.01
West Texas (0. 31 wt % sulfur in crude) 0. 01
West Texas Sour 0. 15
Oklahoma City 0.011
Tinsley (Mississippi) 0.006
Corning (Ohio) 0. 060
South Louisiana 0.006
Kuwait 0.006
Light Arabian (Saudi Arabia) 0.02
Light Iranian (Iran) 0.01
:=C5 - ZOU^F TBP
19
-------
Table 1-5. SULFUR IN GASOLINE BLENDING COMPONENTS
Gasoline Blending Components^ Sulfur. WT %
Catalytically Cracked Gasoline 0. 055
0.036
0.034
0.07
0.327
0.039
0.175
Alkylate 0.001
0.008
0.002
0.003
Catalytic Reformate 0.001
0.007
0.013
0.006
0.002
Coker Gasoline 0. 089
0.19
1.43
0.59
Natural Gasoline 0. 008
0.010
0.027
* Analyses of miscellaneous samples
20
-------
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE WITHOUT NEW FACILITIES
The time to plan, finance and construct refining facilities to upgrade
gasoline blending components requires two to three years from the
date of a firm decision to proceed.
During the period until the additional gasoline upgrade facilities are
onstream, the no-lead, low-sulfur gasolines will have to be blended
from low-sulfur components which can be produced in the present
refining facilities.
The potential production of gasolines with the EPA phase-down of
lead is shown in Table 1-6. Alkylate and reformate are the_high-
octane components and are components in both the unleaded and
premium gasolines. The gasoline blends shown in Table 1-6 are
based on the yields and properties from "A" Refinery (Case 1).
The unleaded gasoline would be sulfur-free, since the blend consists
of normal butane, alkylate and reformate. Comparison of the re-
sults in Table 1-6 with the projected percent of sales indicates that
the present day refineries could produce the required sales percent
of unleaded and premium gasolines in 1975 and 1976. New desulfuri-
zation and new octane upgrading facilities would have to be onstream
by 1977 to produce the required sales percent of both no-lead, low-
sulfur gasoline and premium gasoline.
21
-------
Table 1-6. POTENTIAL GASOLINE PRODUCTION
WITH LEAD PHASE-DOWN (1)
Year
Lead Content, g/gal.
Allowed by El
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline, vol %
Unleaded (92 RON)
Premium (100 RON)
Regular (94 ROM
Unleaded Gasoline, vol %
N-Butane
Alkylate
Reformate
Premium Gasoline, vol %
N- Butane
Alkylate
Reformate
FCC Gasoline
Regular Gasoline, vol %
N-Butane
Light Virgin Gasoline
Light Coker Gasoline
FCC Gasoline
Alkylate
Reformate
1972 1975 1976 1977 1978 1979
4.2(2)
2.2
2.4
1.9
—
37
63
1.7
1.3
2.5
1.2
18
26
56
14.2
39.5
46.3
14.2
39.5
46.3
•"
7.3
14.4
2.0
76.3
1.4
1.3
3.0
1.4
30
21
49
14.2
39.5
46.3
11.9
25. 5
29.4
33. 2
7.3
16.6
2.4
73.8
1.0
0.7
3.0
1.3
40
6
54
14.2
39.5
46.3
11.9
25. 5
29.4
33.2
7.3
16.6
2.4
73.8
0.8
0.7
-
1. 2
44
(3)
56
14.2
39.5
46.3
None
7.3
14.4
2.0
76.3
0.5
0.65(3)
-
0.65
(3)
(3)
100
None
None
10.3
8.1
1.2
43.1
17.1
20.2
(l)Based on gasoline yields and properties from "A" Refinery (Case 1).
Unloaded gasoline to be low-sulfur.
(2)Prior to KPA regulation.
(3)EPA regulation on lead content precludes production of unleaded and
premium gasolines if total gasoline pool requirements are to be met.
22
-------
CHAPTER 4
DESULFURIZATION OF GASOLINE
CASE 1: TYPICAL "A" REFINERY
As a basis of comparison, a "typical" United States refinery and
crude mix were selected to produce about the same distribution and
properties of yasolmes. mid-distillates and No. 6 fuel oil (Bunker
C ) as the tnited States production in 1972.
The refinery feedstock was considered to be a 32 API crude oil
containing 0. 51 weight percent sulfur. For calculations, the crude
mix was considered to be 90 percent South Louisiana and 10 percent
Kuwait.
The refinery process units selected were as follows:
Crude and Vacuum Distillation
Catalytic Reformer with Hydrogen Pretreat Section
Fluid Catalytic Cracker with Vapor Recovery
Delayed Coker
Alkylation
Sulfur Recovery.
Figure 1-4 is a block flow diagram showing the yields and properties
of the intermediate and finaf product streams. C'ase 1 is based on
100.000 barrels per calendar day (BPCD) of crude oil. Thus, the
volume percent yields based on crude oil may be obtained by
dividing the BPCD flows by 1,000. The sulfur from the crude oil
is shown distributed in the product streams, recovered sulfur and
emissions to the atmosphere.
Table 1-7 shows a comparison of the product yields and product pro-
perties for Case 1 with the 1972 U. S. production. The distribution
of yields in Case 1 shows more gasolines and mid-distillates. This
may be explained by the 13.4 percent unaccounted in the 1972 U.S.
production. The properties ot the products show general agreement
between Case 1 and the 1972 L.S. production.
23
-------
/. IM/Mf
-r)
w wfc
Jtfffif
on «c. ("•«•
•«•«?» -j
•
,,.IUW
tr
I.IU */>
$
—T»
I!
M "ft
fu.ifftA
I! $
5 3; f,y.
DfLAICD COKCR
it in
If J W
some
QM T*na.
"9^1^^ 3>Mf
•"tla'l** iiusreafff
eavr
tm*
1 III tfCO
lt.1V> •»
Figure 1-4. Case 1:
24
-------
tr*p t i fine 900
~" *"
"/ft
. fr.t
lututAie
—*
ystur
MffLAT/Ofi/
mroA teeovfAV
itiir-j?tf ».; w« Hiaoffr
tSf I « /fo*6 fl 7 f*»fltt /**.!
oerMtf ****** «.ur
CuMl lf-0 fi-"
/ >«» 7>A f * 7 VJ /•
f3.li/t ti,
rrf 4*
ton
' 7 •,..
TVTMt *» • umujan
/ *atfi'*r Atj,r
(Mlfl. fft L fut
irrr*.g*ee iv
«r. t/> */*
tiff i,.
»/.<
f/./
f » »
(7.7
,
-------
CASE 2: "A" REFINERY WITH HYDRODESULFURIZATION OF CATALYTIC
CRACKER FEED, LIGHT VIRGIN GASOLINE AND LIGHT COKER GASOLINE
In order to calculate the costs of producing sulfur-free gasoline,
hydrodesulfurization of the gas oil feedstock to catalytic cracking and
hydrodesulfurization of the light virgin and light coker gasolines were
considered. In Case 1, the sulfur content in the light virgin gasoline
would be 0. 004 weight percent. The light virgin gasolines listed in
Table 1-4 show higher sulfur content. Therefore, hydrodesulfurization
of light virgin gasoline should be included in the "typical" refinery
for cost purposes.
The refinery process units in Case 2 would be the same as in Case 1
with the following additions:
Gas Oil Hydrodesulfurization
Light Gasoline Hydrodesulfurization
New Capacity for Amine Treating and Sulfur Recovery.
Figure 1-5 is a block flow diagram of Case 2 showing the yields and
properties of the intermediate and final product streams. The
yields and product properties also are listed in Table 1-7.
For gas oil desulfurization. the calculations are based on 80 percent
sulfur removal with a hydrogen consumption of 42 standard cubic
feet per pound sulfur removed (3. 5 mols hydrogen consumed per mol
sulfur removed). Above 85 percent sulfur removal, the hydrogen
consumption increases due to saturation of polyaromatics and hydro-
cracking.
In Case 2, the hydrogen produced in the reformer would be more
than adequate to supply the refinery needs.
The sulfur content would be 0. 008 weight percent in the total gasolines.
Economics for producing low-sulfur gasoline in Case 2 are summarized
in Table 1-8. Based on payout of the investment for the desulfurization
units in five years (20 percent rate of return), the total added costs
(above Case 1) would be about 0.74 cents per gallon of low-sulfur gasoline.
The economic basis is presented in the Appendix.
Table 1-9 shows the estimated investment for the desulfurization
facilities in Case 2. Table 1-10 shows a comparison of yields in Case 1
and Case 2. Table 1-11 shows the estimated utilities and catalyst re-
placement cost in Case 2.
26
-------
The apparent liquid gain in products over charges for Case 2 is 379
BPCD above Case 1. However, the utilities for the desulfurization
facilities would require 584 BPCD of fuel equivalent. Thus, Case 2
would show a net loss of 205 BPCD in comparison to Case 1.
27
-------
nri. ea. e*winnr*r (r.e-r.).
*rio MtH Mfttuar f/A AT u* '
Figure 1-5. "A" refinery with hydrodesulfurization of cata-;
28
-------
/amir/ 1*0 sf AT i*af
*"""
lytic cracker feed, light virgin gasoline, and light coker gasoline.
29
-------
Table 1-7. COMPARISON OF PRODUCTS
1972 Cas Case 2 CaseJ
^
U.S Production
Total Gasolines
~~Y7eld. ~voT%* 550 58.8 59.6 591
"API 61 7 64 2 64.3 64.8
Sulfur. wt% 0031 0033 0.008 0007
Octanes:
Research Clear 90.0 89.6 88.0
Research +3 ct 987 99.1 97.8
Motor Clear 829 82.5 821
Motor +3 cc 92.5 92.9 93.0
Research +2.24 g/gal. 97 5 97.7 97 8 96 7
Motor +2 24 g/gal 90.0 91.4 91.4 91.8
Reid Vapor Pressure 107 110 110 1 1 .0
Middle Distillates
Yield. vol%*~~ 30.8 37.6 37.3 376
Kerosine and Kerosine-type Jet Fuel
Yield, vol%* 8.5 8.4 8.4 8.4
"API 423 41.0 41.0 41.0
Sulfur. wt% 0.066 0041 0.041 0.041
Diesel Fuel
Yieldr^bl %* 8 2 8.4 8.4 8 4
°API 365 37.3 37.3 37.3
Sulfur, wt% 0.21 019 0.19 0.19
No 2 Furnace Oil
"Yield", ™T%*"~ 127 20.8 20.5 20.8
"API 35 1 30.5 31.0 305
Sulfur, wt% 0.22 0.31 Oil 0.31
No. 6 Fuel Oil
Yield, vol %* 68 78 7.8 7.8
"API 110 100 106 100
Sulfur. wt% 1.6 15 1.1 1.5
Viscosity, Furol at 122°F 170 200 200 200
Carbon Residue, wt % 9.3 7 5 7.5 7.5
Miscellaneous Yield, vol %*
Lubricants I 5
Delayed Coke (wt'^) ") 2.6 2.6 2.6
Gas to Fuel (FOE.) ( 13.4 3.7 3.4 3.5
Unaccounted and Losses
YTdd~as~volume percent of crude input
30
-------
Table 1-8. COSTS FOR GASOLINE DESULRJRIZATION - CASE 2*
Investment for Desulfurization Facilities
Years to Payout
$13.0 million
5.0
Cash Flow (13.0/5.0)
Depreciation
Net Profit
Income Tax
Gross Margin
Operating Costs:
Depreciation
Operating Manpower
Utilities
Catalyst Replacement
Interest
Maintenance
Local Taxes and Insurance
Debit for Products
(Case 1 - Case 2)
Credit for Lower Butane Charges
Total Operating Costs
Total Added Cost for Low-sulfur
Gasoline
Million Dollars
per Year
2.60
0.87
1.73
1.73
3.46
0.87
0.22
1.40
0.28
0.65
0.46
0.20
0.18
(-0.94)
$/CD
3.32
3,840
760
480
(-2,570)
6.78 18,580
(0. 74 cents per gallon)
'Compared to Case 1
31
-------
Table 1-9. INVESTMENT FOR PROCESS UNITS - CASE 2
Process Unit
Light Gasoline Hydrodesulfurizer
Gas Oil Hydrodesulfurizer
Sulfur Recovery (Claus Plant)
Onsite Subtotal
Offsite at 30 percent of Onsite
Total Investment
Capacity
5. 700 BPSD
45.000 BPSD
Two 20 TPD Units
Investment. *
Million Dollars
2.6
6.5
0.9
10.0
3.0
13.0
'"Investment includes paid-up royalty (if applicable) plus initial charge for
catalyst.
32
-------
Table 1-10. COMPARISON OF YIELDS - CASE 1 AND CASE 2
BPCD
CHARGES
Crude Oil
Isobutane
N-Butane
Total Charges
PRODUCTS
Fuel Gas, F. O. E.
Propane
Gasolines
Mid-distillates
Sulfur
No. 6 Fuel Oil
Delayed Coke
Total Product (Excluding
Sulfur and Coke)
Apparent Gain (Products - Charges)
CASE 1
100.000
3.864
4.065
107.929
3,664
2,047
58. 873
37.592
(21 TPD)
7.784
(393 TPD)
CASE 2
100.000
3.478
3,984
107.462
3,167
2.028
59. 574
37.302
(40 TPD)
7.801
(393 TPD)
DIFFERENCE
(-386)
(-81)
(-467)
(-497)
(-19)
f701
(-290)
-
+ 17
-
109.960
2,031
109,872
2.410
(-88)
+ 379
33
-------
Table 1-11. UTILITIES AND CATALYST REPLACEMENT - CASE 2
Process Unit
Light Gasoline
Hydrodesulfurization
Gas Oil
Hydrodesulfurization
Sulfur
Recovery
One 20
TPD Plant
Total
Consumption of Utilities:
Electricity, kw 280
Fuel, MM Btu/hr 23.7
Cooling Water, gpm 380
Boiler Feedwater. Ib/hr
Steam Consumed. Ib/hr
Steam Generated, Ib/hr
Net Steam Consumed, Ib/hr
Cost of Utilities, S/CD
Catalyst Replacement Cost, S/CD 20
Fuel Equivalent of Utilities,
BPCD (F.OE.)
2.250
24.4
2,400
58,000
5,250
5,000
740
40 2.570
1.5 49.6
2,780
5,250
58,000
5,000
53,000
3,840
760
584
34
-------
CASE 3: "A" REFINERY WITH HYDRODESUoFURIZATION OF LIGHT VIRGIN,
LIGHT COKER AND CATALYTICALLY CRACKED GASOLINES
Case 3 considers the costs to produce sulfur-free gasoline by hydro-
desulfurization of the catalytically cracked gasoline rather than the
feedstock to the catalytic cracker.
The refinery process units in Case 3 would be the same as in Case 1
with the following additions:
FCC Gasoline Hydrodesulfurization
Light Gasoline Hydrodesulfunzalion.
Figure 1-6 is a block flow diagram of Case 3 showing the yields and
properties of the intermediate and final product streams. The yields
and product properties also are listed in Table 1-7.
Sulfur removal from the KCC gasoline was selected to yield about
the same sulfur content in the total gasolines as in Case 2.
In Case 3, the sulfur removal would be 75 percent from the FCC
gasoline. At this desulfurization severity, 42 percent of the olefins
in FCC gasoline would be hydrogenated, which would result in de-
creased research octane.
Economics for producing low-sulfur gasoline in Case 3 are shown in
Table 1-12. Based on payout of the investment for the desulfurization
units in five years (20 percent rate of return), the total added costs
(above Case 1) would be 0.95 cents per gallon of low-sulfur gasoline.
The costs include a penalty of 0. 33 cents per gallon debited to the
lower octanes which result from partial hydrogenation of olefins in
the FCC gasoline.
Table 1-13 shows the estimated investment for the desulfurization
facilities in Case 3. Table 1-14 shows a comparison of yields in
Case 1 and Case 2. Table 1-15 shows the estimated utilities and
catalyst replacement.
The apparent gain (difference between products and charges) for
Case 3 would be 38 BPCD above the apparent gam for Case 1. The
utilities for the desullurization facilities would required 594 BPCD
of equivalent fuel oil. Thus Case 3 would result in a net loss of
556 BPCD compared to Case 1.
35
-------
' Hi W7% JIMO */»
j 4k/u*e £M6f* Mr Drvr a*n*v6 fur Atfrt
i fir MUtr nuttr xr * / **i Of* m Aurfn
rirn. MM. fjirtvAtt*r iff r)
V &t>M,»e etrMtr*
fL /> M«'/r
^f/lf Ml Mr &-** 111 *r*t gr~/i
.
\** xr/o
ftuumi t it€ ret
t »tf Mfn» -> it. rr i
Prut "!•** ,'*,•.. ar ri,f fr ,fr V
l.lftltO •/*
to «L%
w. Ai ft
'. ft
!
s* Hot
evftt.
1AI *M" ». f* 7
if < M~" If. F> J
watz,A
HrraM**.
o H-l'fff
(i'f- ttrr)
I I
«•»•. • ir wrft jfr •/»
,
ttltt
., r-rjt
;».wr j
tf»'.ii» */#
tuLfvt ft
!.'«
*',tln K^KP
*JW*
.Fff&LJtaiune
WSW
v
f,4 Otto*
pet-Ayto count
.
JfJ «KW MM/IUX
iwar
1 1*1 Bpro
if tm */r
Figure 1-6. Case 3: "A" refinery with hydrodesulfurization
36
-------
///*J «/«*0
* *f J t
/-** «*>tf */W
-
1* * fi*f +l€* f 7 tf
ft / .** «• J*« fff
^iryta
*" *•' SSi'n't. Si","' Z*7
CUM
f i •« m
•-*r tf/>5a/tr
if II* OffO t9 f W
, if r>a •/» «
rr'/v
tax 111 «<*« la H,l
Mtfc t,./ *••>* ?At r» ;
•XS^
T 5-Sr
•tr nor *M*f .
ite in mat-
tint"''»f
/.til rfc
11
fiff*r "" "' *'.
/nic ft/ ***** i>* r» »
•*»•*'
I ff f^T f.
• 1*9 * »
of light virgin, light coker and FCC gasolines.
37
-------
Table 1-12. COST FOR GASOLINE DESULFURIZATION - CASE 3*
Investment for Desulfurization Facilities
Years to Payout
$9.0 million
5.0
Cash Flow (9.0/5.0)
Depreciation
Net Profit
Income Tax
Gross Margin
Operating Costs:
Depreciation
Operating Manpower
Utilities
Catalyst Replacement
Interest
Maintenance
Local Taxes and Insurance
Debit for Lower Octane Gasoline
Credit for Lower Butane Charged
Credit for Products
Total Operating Costs
Total Added Cost for Low-sulfur
Gasoline
Million Dollars
per year
1.80
0.60
1.20
1.20
2.40
0.60
0.22
1.43
0.04
0.45
0.36
0. 14
3.02
(-0.04)
(-0.03)
$/CD
6.19
3.920
100
8,280
(-120)
(-90)
8.59 23.530
(0. 95 cents per gallon)
-Compared to Case 1
38
-------
Table 1 ,13.. INVESTMENT -FOR P-ROGESS jUNITS CASE 3
Investment, :;'
Process Unit Capacity Million Dollars
.Light--Gasoline Hydirodesuif;uri,z?r- 57, 000 BPSD 2.6
FCC Gasolin«-,|iy
-------
Table 1-14. COMPARISON OF YIELDS - CASE 1 AND CASE 3
BPCD
CHARGES
Crude Oil
Isobutane
N-Butane
Total Charges
PRODUCTS
Fuel Gas. F. O. E.
Propane LPG
Gasolines
Mid-Distillates
Sulfur
No. 6 Fuel Oil
Delayed Coke
Total Product (Excluding
Sulfur and Coke)
CASE 1
100.000
3.864
4,065
107.020
3.664
2.047
58.873
37.592
(21 TPD)
7.784
(393 TPD)
109.960
CASE 3
100.000
3.864
4.043
107.907
3.431
2.047
59.122
37.592
(23 TPD)
7.784
(393 TPD)
109.976
DIFFERENCE
(-233)
+ 249
(+16)
Apparent Gain (Products - Charges) 2.031
2.069
+ 38
40
-------
Table 1-15. UTILITIES AND CATALYST REPLACEMENT - CASE 3
Process Unit Light Gasoline FCC Gasoline Total
Hydrodesulfunzation Hydrodesulfurization
Consumption of Utilities
Electricity, kw 280 1.320 1,600
Fuel, MM Btu/hr 23.7 111.1 134.8
Cooling Water, gpm 380 1,770 2,150
Cost of Utilities, S/CD 3,920
Catalyst Replacement Cost, S/CD 20 80 100
Fuel Equivalent of Utilities, 594
BPCD (F.O.E.)
41
-------
SULFUR DISTRIBUTION
Table 1-16 shows the sulfur distribution in the products and atmospheric
emission as pounds per hour sulfur and as the percent of the sulfur
in the crude charge.
The sulfur in gasoline is only a small fraction of the sulfur in the crude
oil charge. The final combustion of the products used as fuel in-
cluding gasolines, mid-distillates and Bunker "C" results in emissions
of sulfur oxides to the atmosphere. The sulfur in delayed coke may be
emitted to the atmosphere or be combined in metallurgical slag, de-
pending upon the use of the delayed coke.
Table 1-16 shows that the recovered elemental sulfur would be 27.6
percent of the sulfur in the crude oil in a "typical" refinery (Case 1)
and 52. 3 percent of the sulfur in the crude oil in Case 2.
42
-------
Table 1-16. SULFUR DISTRIBUTION
Sulfur Content. LB/HR Case 1 Case 2 Case 3
Crude Oil 6,443 6,443 6,443
Products:
Gasoline 205 49 47
Mid-distillates 1,046 534 1,046
Bunker "C" 1.708 1,235 1,708
Delayed Coke 897 897 897
Recovered Elemental Sulfur 1,776 3,372 1,928
Emitted as SO2 to Atmosphere 811 356 817
Total 6,443 6,443 6,443
Sulfur Distribution, %-': Case 1 Case 2 Case 3
Products:
Gasoline 3.2 0.8 0.7
Mid-distillates 16.2 8.3 16.2
Bunker "C" 26.5 19.2 26.5
Delayed Coke 13.9 13.9 13.9
Recovered Elemental Sulfur 27.6 52.3 30.0
Emitted as SO2 to Atmosphere 12. 6 5. 5 12.7
100.0 100.0 100.0
Sulfur distribution as percent ot sulfur in crude charges.
43
-------
APPENDIX A.
COSTS'
1. All costs and capital are based on January, 1974 levels.
2. Capital related charges
Straight-line depreciation for 15 year life.
Interest at 10 percent per year. This is equivalent to
5 percent per year over the average payout period.
Maintenance: onsite, 4 percent; offsite, 2 percent.
Local taxes and insurance: 1.5 percent.
Payout on investment: 5 years after taxes.
3. U.S. income plus state corporation taxes at 50 percent of
gross profit.
4. Incremental utility costs
Fuel: $1.00 per million Btu net heat value. This is
equivalent to $5.50 per barrel of 32° API crude
oil.
Electricity: $ Per KWH
Fuel cost 0. 010
Other charges 0. 006
0.016
Steam: $1.40 per 1,000 pounds corresponding to the
fuel cost of $1.00 per million Btu.
Cooling water: SO. 02 per 1,000 gallons circulation.
Treated boiler feedwater: SO. 05 per 1,000 pounds.
5. Operating manpower costs
Average costs for stillman and operators at $6. 00 per
hour plus 30 percent fringe benefits. Sixty percent
overhead on operating manpower is added to allow
for supervision, laboratory, technical service and
instrument services.
45
-------
5. Operating manpower costs (Contd.)
Manpower Cost
Per Shift Position $/HR % $/YR
Rate 6.00 52.600
Fringe Benefits 30 15.800
Overhead 60 41,000
Total 109,400
6. Product prices
Incremental product yields were priced at the same price
as crude oil ($5.50 per barrel).
7. Royalties
Gas oil hydrodesulfurization:
Paid-up royalty $10.00 per BPCD feed rate.
Naphtha hydrodesulfurization:
Royalty-free. Royalty costs would be included in
catalyst costs or nominal know-how fee.
8. Hydrogen make-up
Assumed to be available in the reformer make-gas for
for hydrodesulfurization units.
9. Gasoline octane
Incremental gasoline octane priced at 2.0 cents per 6 octane
difference between premium and regular gasolines at the
1972 lead level of 2.24 grams per gallon. This price is
equivalent to 0.333 cents per gallon per research octane
number.
46
-------
APPENDIX B.
OIL EQUIVALENT OF UTILITIES
1. Fuel
Net heat value at 6.1 million Btu per barrel fuel oil
equivalent.
2. Electricity
Net heat to generate electricity is assumed to be 10, 000
Btu per kilowatt-hour. This requires 0.04 BPCD F.O. E.
per kilowatt-hour.
3. Steam
Net heat to generate steam is assumed to be 1, 370 Btu
per pound of steam. This requires 5.4 BPCD F.O.E. per
1. 000 pounds per hour of steam.
47
-------
APPENDIX C.
SOURCES OF INFORMATION
American Petroleum Institute
"Annual Statistical Review, U. S. Petroleum
Industry Statistics, 1972 "
U. S. Bureau of Mines, Mineral Industry Surveys
"Motor Gasolines, Summer 1972"
"Motor Gasolines, Winter 1972-1973"
"Aviation Turbine Fuels, 1972"
"Diesel Fuels, 1973"
"Burner Fuel Oils. 1973"
U. S. Federal Register
Enviromental Protection Agency
Part 80. Regulations of Fuels and Fuel Additives
Vol. 38, No. 6 - Jan. 10. 1973
Vol. 38, No. 234 - Dec. 6, 1973
Ethyl Corporation
"Yearly Report of Gasoline Sales by States, 1972"
Gulf Oil Corporation
"32.3° API Gravity South Louisiana Crude Oil (Ostrica Mix)"
"Kuwait Crude Oil Handbook"
49
-------
PART 2
PRODUCTION OF LOW-SULFUR GASOLINES
(PHASE 2)
51
-------
CHAPTER 1
INTRODUCTION
This part of the report covers work which was performed under Con-
tract No. 68-02-1308 for the Environmental Protection Agency,
(EPA) Office of Research and Monitoring, Task No. 10, Phase
2.
Automobile manufacturers indicate that some automobiles
will have catalytic mufflers for pollution control starting
with the 1975 model year. To avoid poisoning of the catalyst,
no-lead gasoline is required. The catalytic mufflers reduce
emissions of carbon monoxide and hydrocarbons; however, the
catalysts convert sulfur in the gasoline into sulfuric acid
mist in the exhaust.
The purpose of this work is to determine the impact of
producing low-sulfur gasolines on the refineries in the
United States. To show the impact on U.S. refineries it
was decided to select a "typical" refinery as a basis such
that plant capacity, capacities of individual process units,
yields of products, and properties of products about matches
the average of the total U.S. refineries. Desulfurization
facilities were then added to this refinery, using two pro-
cess schemes, to produce low-sulfur gasolines.
The results presented herein supersede the results pre-
sented in the Phase I study.
53
-------
CHAPTER 2
SUMMARY
This study shows how a "typical" U.S. refinery can pro-
duce no-lead, low-sulfur gasoline and by installing new
hydrodesulfurization facilities produce the low sulfur gaso-
lines to include the no-lead, premium and regular gasolines.
Results of this study indicate that no-lead, low-sulfur
gasoline would have to be blended from normal butane, alky-
late, and reformate in the existing "typical" United States
refineries. Beyond 1975, the predicted demand of no-lead
(low-sulfur) and premium gasolines could not be met with
the EPA limits on lead anti-knocks in the total gasoline
pools.
Total gasolines could be made low sulfur by hydrodesul-
furization of the gas oil feedstock to catalytic cracking
and by hydrodesulfurization of the light virgin and light
coker (or thermal) gasolines. Economics for this scheme
(Case 2) show that the costs for producing gasoline would
be increased depending upon refinery size approximately as
follows:
Refinery Crude Desulfurization
Capacity, BPCD Costs, Cents Per Gallon
16,000 1.59
44,000 1.01
100,000 0.67
An alternate case considers hydrodesulfurization of the
catalytically cracked gasoline rather than the feedstock
to the catalytic cracker. Economics indicate that this
scheme (Case 3) to produce low-sulfur gasoline would add
about 0.82 cents per gallon to the cost of gasoline pro-
55
-------
duction for a IOC, 000 BPCD refinery. This cost includes
a penalty c.f. 0.3 cents per gallon of gasoline debited to
the lower octane resulting from partial hydrogenation of
olefins in the FCC gasoline. , vl..
If new facilities were installed to desulfurize all the
*•»
U.S. gasolines by desulfurizing light virgin and themal
gasolines and desulfurizing the cat cracker feedstock, it
would require an investment of about 2.0 billion dollars
by U.S. refiners based on January, 1974 costs.
Based on the gasoline yields and properties in Case 2
for low-sulfur gasolines, no-lead, premium and regular
gasolines could be blended in the predicted sales volumes
and the total gasoline pool could meet the EPA regulations
in lead phase-down until 1979. Octane up-grading would be
require i*. *979 to meet the limit of 0.5 grams of lead
per gallon.
"A" Typical U.S. Refinery is shown as Case 1 and con-
forms to the following criteria:
• Median capacity of crude charges to U.S. refineries
• Capacities of process units within the refinery
about matches the average percent of crude input
as the total U.S. refineries.
• The crude charge produces about the average per-
cent yields and properties of products as the
total U.S. refineries.
56
-------
CHAPTER 3
EPA REGULATIONS ON GASOLINES
UNLEADED GASOLINE
Regulations by the Environmental Protection Agency
(EPA) to limit the emissions of carbon monoxide and hydro-
carbons require most future automobiles to have catalytic
mufflers.
General Motors announced plans to equip all its 1975
models with converters, compared to about 60 percent for
Ford. Thus about 80 percent of the 1975 automobiles will
have catalytic converters.
Unleaded gasoline to be used in automobiles equipped
with catalytic converters is to be generally available
in the United States at major service stations.
The EPA has issued regulations (January 10, 1973)
on unleaded gasoline (minimum 91 research octane) to
be supplied starting in July, 1974.
PHASE-DOWN OF LEAD IN GASOLINE
The EPA has ordered a phase reduction of lead anti-
knock additives in gasoline (Federal Register, Dec. 6,
1973). These regulations restrict the average lead
content in all grades of gasoline (including unleaded
gasoline) produced by any refinery as follows:
Lead Content
January 1 Grams per Gallon
1975 1.7
1976 1.4
1977 1.0
1978 0.8
1979 0.5
57
-------
CHAPTER 4
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN PRESENT
U.S. REFINERIES
DEFINITION OF "A" TYPICAL U.S. REFINERY
The purpose of this study is to determine the impact
of producing low-sulfur gasolines by the refineries in
the United States.
"A" Typical U.S. Refiner can be used to show the pro-
duction of no-lead, low-sulfur in the present U.S. re-
fineries and then develop the added costs to produce
gasolines by installing new hydrodesulfurization facil-
ities.
For this purpose, "A" Typical U.S. Refinery and the
crude charge should conform to the following criteria:
• Median capacity of crude charges to U.S. refineries
• Capacities of process units within the refinery
matches about the average percentage of crude in-
put as the total U.S. refineries
• The crude charge produces about the average per-
cent yields and properties of products as the
total U.S. refineries
_«
CASE 1: "A" TYPICAL U.S. REFINERY
The refinery process units selected for Case 1 were
as follows:
• Crude and Vacuum Distillation
• Catalytic Reformer with Hydrogen Pretreat Section
• Fluid Catalytic Cracker with Vapor Recovery
• Delayed Coker
59
-------
• Alkylation
• Sulfur Recovery
For calculations, the refinery feedstock was con-
sidered to be a 38.4° API mixture of Texas-Louisiana
crude oils containing 0.5 weight percent sulfur.
Figure 2-1 is a block flow diagram showing the yields
and properties of intermediate and final product streams,
Case 1 is based on 100,000 barrels per calender day
(BPCD) of crude oil. Thus, the volume percent yields
based on crude oil may be obtained by dividing the BPCD
flows by 1,000. The vapor pressures and octanes of the
gasoline component streams are shown in Figure 2-1. The
sulfur in the crude oil is shown distributed in the
product streams, recovered sulfur, and emissions to the
atmosphere.
To simplify the work, the following conditions were
assumed:
• Production of alkylate was set at 5.8 volume per-
cent on crude input by taking propylene to LPG.
• Reformer would produce reformate with 95 research
octane clear.
• Catalytic cracker would operate at 75% conversion
with yields corresponding to riser cracking using
zeolite catalyst.
• Unfinished asphalt would be produced from vacuum
tar.
• Production of lubricants and waxes were not con-
sidered as these account for only 1.8 volume per-
cent on crude input.
60
-------
• Special naphthas and the benzene-toluene-xylenes
aromatics were considered to be part of reformate
and would be accounted in the total gasolines.
Comparisons o.f the results in Case 1 with the aver-
ages for the U.S. refineries from statistics are as
follows:
• Table 2-1 - Comparison of Process Units in Case 1
with the U.S. Average
• Table 2-2 - Comparison of Products and Yields -
1972 U.S. Production vs. Typical Refineries.
• Figure 2-2 - Octane of Total Gasoline Pool - Typical
Refineries
The median quantity of crude refined in the United
States in 1973 was processed in refineries with a median
capacity of about 100,000 barrels per stream day (BPSO)
of crude oil. Capacities of refineries are usually
expressed in barrels per stream or operating day
(BPSD) whereas accounting of the annual production is
on a barrels per calendar day (BPCD) which considers
the down time.
These comparisons show that refinery and crude oil
in Case 1 may be considered to be "A" Typical U.S. Refin-
ery by conforming to the criteria stated previously in
this chapter.
Further imports of foreign crudes with lower "API
gravities, higher sulfur content, and higher metals
content than domestic crudes will result in a somewhat
different distribution of products with higher sulfur
61
-------
TYPICAL U S RETIIbWl
pacity off procaaa unit* , .
cruda input aa tha total I S rafining capacity
Capacity off procaia unlta *a about avaraga parcantMe of
' - - - - • 'in 1<7I
Product yialdi ara about avaraoa parentage of cruda input
aa total U S production in 1971 and 1972
Propartiaa of producta aza alaoat t/plcal of awraoa
U B production in 1972 and 1971
2 Boiling rangaa *ra trua boiling cut pointa
1 Mt haat »lua at 6 1 Billion Btu par barral fui : oil
aquivalant (FOE)
I GASOLINE OCTANES
BOHC RESEARCH OCTAUE CLUD
KOI • Ice RESEARCH OCTANE PLUS JCC T E L /Gal
MOW MOTOR OCTANE CLEM
•W1 • Ice MOTOR OCTAU PLLI ice T E L /C.I
i RVP REID VAPOR PRLSSLRt. PSI AT OUT
Sulfur contani
(I/HI
iai ahgun aa UT* and LOJIWI per linj-
cjda fc Vacuua bnit
100 000 BPCO
3b 4 'API
1.213.3701/H
Sulfur 0 9 ktl
60141/H
Mil of Cruda. tro»
Taxaa and Louiaiana
I.ff24 BPCD
11,720 I/H
Vac Tar 11.000 • 'PI
11,912 BPCD
14 S 'API
162.6401/11
Sulfur 1 9 Htl
3.0MI/U
Light GaaollnalCj-200*P)
l.itO BPCD 75'API li,4CO I/H
Sulfur 0 010 tftt 91/H i
>VP 7 i I«MC 69 I
MO»C C7.I
BOKtICC 17 I
MOII.JCC II 1
•aphtha H80-17o'ri
19.941 BPCD S1.7*AP1 222
Sulffur 0 042 «• 041/H
Haroaina H70-»00'ri
2,031
•aphtha (200-170*PI
20,794 BPCD
211,190 I/H
Sulfur 112I/H
21,9901/H
Hydrogan Pratraat
BaforMr
Gaa to Rial
21.110 I/H
Nat Haat valua
• tlB 7 Mil Btu/il
2.414 BPCD P. E
Sulfur ISI/H
Debut, Ovarnaad
• 12,3501/H
Sulfur 471/u
bulfur 0 12 mt 194 I/H
tttaaal H08-400TI '\
I I
12.317 BPCD 1CAPI 1S1.MOI/H
Sulfur 0 24 Wtt 1S9I/B
Gaa Oil (CM-l.OOO'P)
11.717 BPCO
21 2 -API
409.910 I/H
Sulfur 0 9> ni-i
2,272 I/H f
Light Gaaolina (Cs-JOOTI
S14 BPCD 71'AH
9.1IOI/H
Sulfur 0 11 Mtl 171/H
RVP 7 9 aONC S2 I
BOX3CC 90 1
mK 70 1 HOD* Ice 77 2
Haphtka (JOO-170T)
111 BPCD »*API
9.UDI/-I
Sulfur 0.9 Htl III/H
14,491 BPCD
2S.1*API
144,920 I/H
Sulfur 0 99 Ull
2.<19 I/H
S.S19 BPCD
B6.310 t/H
Sulfur 691
22,110 I/H
Bulfur IMI/H
Fluid Catalytic
Cracking Unit
1791 Convaralonl
Gaa Oil I1TO-BP)
2.7M BPCD 29.VAPI
14.9901/H
Sulfur 1.09 Htl
M7I/I
C< t Lightac
• .I2D l/ll
Bulfur 4BO I/H
9,192 BPCD
T1.1JOI/H
Salfur 1.19M/H
oalayad Cokor
I ^
U.IOOI/B
202 Short Tona/Day
Sulffur 2 •« *tl
114 I/H
1,220 BPCD
45,490 I/B
Sulfur «t I/H
Dacant Oil
(«50«TI
1,729 BPCD
2 2-API
2i,610 I/H
Sulfur 1 II kt«
4»9 I/H
Gaaoline
Llghtar
304.190 I/H
Sulfur
•^ 1.912 I/H
Light Cyela Oil
(410-tlO*PI
t.191 BPCD
21 2'API
91.I90I/H
Sulfur 0 79 Wtt
iMI/B
179 BPCD
9.020 I/H
Sulfur II I/B
Figure 2-1. "A" typical
-------
Furchaaod
N-Buiano
3.964 BPCD
33. BOO t/ll
C4*Re forma ta
RVP 2 4 ROSC 9S 0 RON»Jcc 100 6
HONC 65 & MGN*3CC 91 I
Purchaied
Isobutano
432
BKD
Cj> Alkylale
5.800 BPCD 72 5BAPI S8.610I/H
RVP 3 3 RONC 94 6 RONOcc 105 6
By-Product Oil *ONC 93 5 HONOcc 107 6
Total Caiolina Pool
•>
98.306 BPCD 62 2 -API
620,550 I/H
Sulfur 0 031 ut« 191 I/H
RVP 11 0
RoHUCll «""'
Cl«.r 89 7 •» '
•lee T E L If J '14
•2 24 9/9.1 97 2 »° 3
100.980 I/H
Sulfur 0 12 wtl
8.217 BPCD
1 I
1
-^—
»PCD
C3' 1.75J
C3 1.75S
3,509
'8,390 I/H
*s~
JJ9.450 I/H
Sulfur 1,992 I/H
. H, conau.ed 7-«0 BPCD
« 0 39 It SCF/B — ll ' "API
4 100 BPCI>l80l/H f *] »1 ««0 I/H
3,300 BPCD < L
ilO I/H Sulfur 181 I/H / l,j,,
BPCD |BPCD
67.610 I/H >•"» "'CD
1C 2"^$ Claui Plant
C41 2.B66 i"^^"*1^1™*
TtflT J Sulfur B8I/H
Vapor Recovery
JAnine Treatimj uaaco ruei
11 S40 */H ' §,JJ;j «•"•«••' !•*
1 411 1 m Btu/H
| Sulfur >.«»»'« FOE
1.669 I/H
20 Ton/Day
FCC GalollM ICS-410'F)
20,<91 BPCD 58 9 'API 221.910 I/H Sulfur 16SI/H
RVP 7 2 RONC 91 5 RON. Ice 97 1
MONC BO 6 HON. Ice 86 B
2.400 '.200 BfC.
BiCD 36 5'APl
100,5113 .
118 I/H
a^n No 2 Furnace Oi
BPCD ^
li 021 BPCD 12 B' "
201.030 I/H
Sulfur 0 28 wtl 4 • •
No 6 Fuel Oil
Bunkor "C'
5 121 BPCD
10 1'API
77 120 I/H
S 'fur 1 B2 wtl
1.401 I.'H
vncoilly I'O Puiol SCO al 122 r
A^uidlt runfi^iahedl
3.100 BfCD
il 5 '»P1
41 BOO < li
r.ullu 1 ' ^ti DJJ I/H
U.S. refinery (Case 1),
63
-------
Table 2-1. COMPARISON OF PROCESS UNITS IN CASE 1
WITH THE U.S. AVERAGE
Vol. % of Crude Capacity
U.S. Refineries
Process Units in 1973 Case 1
Crude Distillation 100.0 100.0
Vacuum Distillation 36.8 37.8*
Cokers (Delayed and Fluid) 6.4 5.2
Catalytic Cracking 32.3 34.5
Naphtha Hydrodesulfurization 20.0 20.8
Catalytic Reformer 23.4 20.8
Mid-Distillate Hydrodesulfurization 7.9 7.4
Alkylation 5.8 5.8
* At 670°F TBP cut point in crude oil.
-------
Table 2-2. COMPARISON OF PRODUCTS AND YIELDS,
1972 U.S. PRODUCTION VERSUS TYPICAL REFINERIES
1972 U.S.
Total Gasolines Production Case 1 Case 2 Case 3
Yield, vol%
°API
Sulfur, wt%
Research Clear
Research + 3cc TEL
Research + 2.24 g. lead/gal
Motor Clear
Motor + 3cc TEL
Motor + 2.24 g. lead/gal
Reid Vapor Pressure
Kerosine and Kerosine-Type Jet
Yield, vol%
°API
Sulfur, wt%
Diesel Fuel
Yield, vol%
°API
Sulfur, wt%
No. 2 Furnace Oil
Yield, vol%
°API
Sulfur, wt%
No. 6 Fuel Oil
Yield, vol%
°API
Sulfur, wt%
Viscosity, Furol at 122°F
Asphalt, vol% (5.5 bbl=l short.
Coke, vol% (5 bbl=l short ton)
58.2
61.7
0.031
97.5
90.0
10.7
Fuel
8.5
42.3
0.066
8.2
36.5
0.21
14.4
35.1
0.22
6.8
11.0
1.6
170
ton) 3. 8
1.5
58.3
62.0
0.031
89.7
98.3
97.2
82.3
91.4
90.3
11.0
8.5
42.0
0.12
8.2
36.5
0.15
16.0
32.8
0.28
5.3
10.9
1.8
170
3.1
1.0
58.7
62.1
0.006
89.3
98.9
97.8
82.2
92.2
91.1
11.0
8.5
42.0
0.12
8.2
36.5
0.13
15.7
33.1
0.14
5.5
12.6
1.3
170
3.1
1.0
58.5
62.6
0.006
88.0
98.5
81.7
92.3
11.0
8.5
42.0
0.12
8.2
36.5
0.15
16.0
32.8
0.28
5.3
10.9
1.8
170
3.1
1.0
65
-------
Table 2-2. (continued) COMPARISON OF PRODUCTS AND YIELDS,
1972 U.S. PRODUCTION VS. TYPICAL REFINERIES
1972 U.S.
Production Case 1 Case 2 Case 3
Liquefied Petroleum Gas (LPG),vol% 1.9 3.4 3.7 3.4
Still Gas to Fuel, vol% 3.8 4.1 3.9 3.9
Other Products, vol% None None None
Lubricants 1.6
Wax (1 bbl-280 Ib.) 0.2
Road Oil 0.2
Miscellaneous 0.3
Notes:
1. Yields are volume percent on crude input.
2. Where 1972 yields were not available, they were
estimated from 1971 products. Petrochemical
feedstocks (aromatics) and special naphthas added
into total gasoline production.
66
-------
LEAD ALKYL ANTIKNOCK SUSCEPTIBILI1 V CHART
115 i
no
105
100
03
S
3
Z
111
o
_l
2.0 <
O
tt
IS W
o
c/i
100
- 80
70
a
UJ
00
3
Z
UJ
O
•z
I
err
O
LL
a
^J
a.
75 *
Ob 1.0 1.4 20 2.5 3.0 4.0 5.0 6.0
ANTIKNOCK CONTENT, CRAMS METALLIC LEAD PER GALLON
• *l«nt to ! .0, i t. J.O
-------
content than shown in Case 1.
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN PRE-
SENT FACILITIES
The time to plan, finance and construct refining
facilities to upgrade gasoline blending components re-
quires two to three years from the date of a firm de-
cision to proceed. During the period until the additional
gasoline-upgrade facilities are onstream, the no-lead,
low-sulfur gasolines will have to be blended from low-
sulfur components which can be produced in the present
refining facilities.
Sulfur contents of various gasoline blending com-
ponents can be shown by the analyses of various samples
in Tables 2-3 and 2-4. The sulfur content is variable
and depends upon the crude source for catalytically
cracked gasoline, light straight-run gasoline, natural
gasoline and coker or thermal gasoline.
Reformate and alkylate can be considered sulfur-free.
The bi metallic reformer catalysts require that the
feed naphtha be desulfurized to less than 1.0 ppm sulfur.
The feedstocks to alkylation are desulfurized or essentially
sulfur-free. In alkylation, the hydrofluoric acid cata-
lyst or sulfuric acid catalyst quantitatively removes
any residual sulfur.
Production of sulfur-free gasolines generally will
require the desulfurization of thermally cracked gasoline,
catalytically cracked gasoline, and light straight-run
gasoline. However, until new desulfurization facilities
are installed, the requirements for no-lead, low-sulfur
68
-------
Table 2-3. SULFUR IN GASOLINE BLENDING COMPONENTS
Gasoline Blending Components* Sulfur, WT%
Catalytically Cracked Gasoline 0.055
0.036
0.034
0.07
0.327
0.039
0.175
Alkylate 0.001
0.008
0,002
0.003
Catalytic Reformate 0.001
0.007
0.013
0.006
0.002
Coker Gasoline 0.089
0.19
1.43
0.59
Natural Gasoline 0.008
0.010
0.027
^Analyses of miscellaneous samples
69
-------
Table 2-4. SULFUR IN LIGHT VIRGIN GASOLINES*
Sulfur, WT%
Crude Source In Light Gasoline*
East Texas 0.01
West Texas Intermediate Sweet 0.038
Ellenberger (Texas) 0.01
West Texas (0.31 wt% sulfur in crude) 0.01
West Texas Sour 0.15
Oklahoma City 0.011
Tinsley (Mississippi) 0.006
Corning (Ohio) 0.006
South Louisiana 0.006
Kuwait 0.006
Light Arabian (Saudi Arabia) 0.02
'..ight Iranian (Iran) 0.01
- 200°F TBP
70
-------
gasolines will have to be blended from low-sulfur blend
stocks, such as n-butane, reformate and aIkylate.
Starting in July, 1974 the no-lead gasoline will
have to be available for the 1975 automobiles equipped
with catalytic mufflers. Gasoline blending components
presently available will be used to blend the no-lead,
premium, and regular gasolines. In future years as
more automobiles in service have catalytic mufflers
and the pre-1971 automobiles are increasingly junked,
more no-lead gasoline and less premium gasoline will be
required to satisfy automobile needs. The 1971 and
later automobiles without catalytic mufflers can use
regular gasoline.
Figure 2-3 shows a projected percent of sales of
premium and no-lead gasolines.
The potential production of no-lead, low-sulfur
gasoline together with premium and regular gasolines
was calculated attempting to meet the EPA regulations
on lead phase-down using the blending components pro-
duced in Case 1. These results (Table 2-5) indicate that
the projected percent of gasoline sales can be produced
through 1975. In 1976 and later years the EPA limit
on lead content would be exceeded. In 1977 and later
years the production of no-lead, low-sulfur and premium
gasolines would be less than the projected percent of
sales, i
71
-------
U)
w
w
o
w
w
100 - -
90 . .
80 - •
g 70 +
U)
60 - -
50 . .
40 - -
30 . :
20 - -
13 ..
PREMIUM GASOLINE
SALES
/
/
PREMIUM
GASOLINE
RECOMMENDED
FOR CARS
ON ROAD
.
/
X /
/
/NO-
LEAD GASOLINE
1965
1970
1975
—h
1980
H
1985
1990
YEAR
Figure 2-3. Projected percent of sales of premium and no-lead gasolines.
72
-------
Table 2-5. POTENTIAL GASOLINE PRODUCTION IN CASE
WITH LEAD PHASE-DOWN
Year
Lead Content, g./gal
Allowed by EPA
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline, vol%
No-Lead, Low Sulfur
Premium (100 RON)
Regular (94 RON)
No-Lead Gasolinef vol%
N-Butane
Alkylate
Re formate
Premium Gasoline/ vol%
N-Butane
Alkylate
Reformate
FCC Gasoline
Regular Gasoline, vol%
N-Butane
Light Virgin Gasoline
Light Coker Gasoline
FCC Gasoline
Alkylate
Reformate
Gasoline Octanes
No-Lead, Research
1 Motor
Premium, Research
Motor
Regular, Research
Motor
Comment - See Note
1972 1975 1976 1977 1978
1979
4.2
(2)
37
63
1.7
1.6
1.8
2.0
18
23
59
15
22
63
15
22
63
8
25
2
59
1
5
1.4
1.55
2.6
2.1
30
16
54
15
22
63
13
15
44
28
8
27
2
57
1
5
40
9
51
15
22
63
12
12
35
41
7
29
2
61
45 45
None None
55 55
15
22
63
7
27
2
64
15
22
63
None None
7
27
2
64
99
92
94
86
.7
.2
.0
.4
94
87
100
94
94
86
.7
.9
.2
.8
.2
.3
94
87
100
93
94
87
.7
.9
.2
.3
.2
.0
94
87
100
92
94
86
.7
.9
.2
.6
.2
.3
94
87
94
86
.7
.9
.2
.2
94
87
94
86
.7
.9
.2
.2
3.
4.
5.
6.
73
-------
Notes on Table 2-5:
(1) Potential gasoline blends are based on the gasoline
yields and properties from "A" Typical U.S. Refinery
(Case 1). The no-lead, low-sulfur gasoline would be
blended from normal butane, alkylate, and reformate.
(2) Legal limit was 4.2 grams lead content per gallon prior
to EPA regulations.
(3) Predicated sales demand of premium gasoline and no-lead,
low-sulfur gasoline precludes meeting the EPA limit on
lead content in 1976.
(4) Predicated sales demand of no-lead, low-sulfur gasoline
reduces the production of premium gasoline below pre-
dicted sales demand. Lead content in total gasoline
pool exceeds EPA regulation in 1977.
(5) In 1978 and 1979, the octanes of the gasoline components
limits the production of no-lead, low-sulfur gasoline
below predicted sales demand. The production of no-lead,
low-sulfur gasoline precludes the production of premium
gasoline. The lead content in the total gasoline pool
exceeds the EPA regulation in 1978 and 1979.
74
-------
CHAPTER 5
DESULBURIZATION OF GASOLINE
CASE 2: "A" REFINERY WITH HYDRODESULFURIZATION OF
CATALYTIC CRACKER FEED AND LIGHT GASOLINES
In order to calculate the costs of producing
low-sulfur gasolines, hydrodesulfurization of the
gas oil feedstock to catalytic cracking and hydro-
desulfurization of the light virgin and light coker
gasolines were considered.
In Case 1, the sulfur content in the light
virgin gasoline is 0.01 wt.%. However, hydrode-
sulfurization of light virgin gasoline should be
included for the "typical" refinery for cost pur-
poses because some of these gasolines, as shown in
Table IV, have high sulfur contents.
In Case 2, the refinery process units would be
same as in Case 1 of "A" Typical U.S. Refinery with
the following additions:
• Gas Oil Hydrodesulfurization
• Light Gasoline Hydrodesulfurization
• New Capacity for Amine Treating and Sulfur
Recovery
Figure 2-4.is a block flow diagram of Case 2 show-
ing the yields and properties of the intermediate
and final product streams. The yields and product
properties are listed in Table 2-2 together with the
average U.S. production.
75
-------
H,S 1} I/H
SOlfur 21 I,
C« 1,924 B?« 15.HO I/H
CRUDL h VACUUM UNIT
103.030 UPCD
11 I 'API
1.213.110 I/H
Sulfur 0.5 vtl
6,314 I/H
HiK of Crudci Froia
T«xai and Louiii«»
Vac T«r (1.009+
11,112 BPCU
II j 'API
1.2.6«0 I/H
Sulfur 1 I vll
3,096 I/H
Light Gnalini (C^-203'ri
i.660 BPCD 75 'nPI 8S.I63 I/I!
Sulfur 0 31 vtl 9 I/H
RVP 7 i RONC 49 ] RON • lee «7 t
HOMC t7 I ION • Ice 85 1
5,174 BP1.D
7t I 'Ml
9H4J l/ll
LI3HT GASOLINE
HVDROULSULFURIIATION I
Nuphtht I203-370TI
23,734 BPCD
211.530 I/H
Sulfur 112 I/H
Uohtlui (200 170*r 19,311 BPCD 5] 7 'API 222,330 I/H
Sulfur 0 042 vtl 84 I/H I
SO I/H
0.23 KM SCF/U
G» to Tual 22.980 I/H
,N>t Hilt Vllut
Sullur 85 I/H
HYDROGEN
1 REFORMER
PqETREAT I
;a r
Xiroiim (170-500*P) 11,887 BPCD II 'API lgl.970 I/H
Sulfur 0 12 wtl 191 I/H I
I I
Dillll OOO-600'F) 12,317 BPCU 36 *,
111,(20 l/ri
Bulfur 0 21 wtl
359 I/H
CM Oil (600-1,OOOTI
31,757 1PCD
2B 2 'API
439,930 l/ll
Sulfur J 55 vtt
2,272 l/ll
Light Glioliiu (Cj-200'r)
514 BPCD 73 "API
5,180 ./H
Sulfur 0 31 vtl 17 I/H
RVP 7,5 RONC 12 t
ROH • 3cc 90 3
HONC 70 1 HON • 3ce 77 2
5,192 BPCD
73,310 I/H
Sulfur 1,396 I/H
Naphtha (200-370'F)
811 BPCD 12 'API
9,560 I/H
Sulfur 3 1 vtl II ./H
34,493 BPCD
21 1 'API
444,920 I/H
Sulfur 0 59 vtl
2,(19 I/H
COMUMd
2 11 N.1 SCF/D
2
520 I/H
2,9(0 I/H
Sulfur 2,138 l/ri
FCC PMdsuek I
Hydrod«ulfurl»tion I
{801 Sulfur Ramoval) I
33,162 BPCD
r
Coka Burned
18,710 I/H
Sulfur 78 I/H
FLUID CATALYTIC
CRACKING UNI-
(751 lonnrilonl
DELAYED COKER
Dll 1373-LP)
C SPCD 29 7 -API
.940 I/H
ur 1 01 vtl
3(7 I/H
C4 k Lighter
6,820 I/H
Sulfur 410 I/H
434,933 I/H
Sulfur 0 12 vtl
531 I/H
Cok. 16,100 I/H
— 202 Short Tom/Diy
••••^ Sulfur 2 86 vtt
4B4 I/H
Decint oil (650T)
1.69< BPCD 1 4 -API
21,530 I/H
Sulfur 0 12 vtl
107 I/H
1.220 BPCD
Figure 2-4. "A" typical U.S. refinery with hydrodesulfuriza-
76
-------
5«1 4 IB Btu/ll
2.127 BUD r I I
Ucbut 'n/erhead
12.J50 >/H
bulfur 47 i/ll
Gasoline I Liuhter
lOl.loO f/H ^
K Sulfur 19( •/»
Light Cycle Oil
l410-o53'F)
G.774 BPCD
24 t 'API
89,500 I/H
Sulfur 0 17 vti
150 I/H
i_,ht -ab^l.ne
,-tf 7 t HOC S3 ! RON • Ice 91 9
'OIC 4- 8 nil, • lee 16 B
Sulfur 3 J92 *t« J 'H
'-s * Roforoato
PVP 2 4 SONC 95 ] 4 BH.D 14 '«P1 195.653 '/H
Purclueed l.l.l J-CD 27,783 I/H
BPCD
c] '•"' '-4 7-"°' 1 "'"SuSed1
29.710 1/B n<:4 2l"4 %i3.IJ! I/H L^^JJL"
V Cl 1,301 ^^*^
x » * 4 BPCD 1
< 50 I/ll
Purchased
n -Butane
1.599 BPCD
10, (99 I/ll
BPCD
C]- 1,849
c' MK
N-ButaA«
2,590 BPCD 22,383 I/H
Cj • Alkylate
5,890 BPCD 71 9 *AP1 11,810 I/H
RVP 1 1 RONC 94 7 RON • ICC 105 7
Oil HONC 94 6 R01 • Ice 137 7
•API
2,903 BPCD
H, Conauoed
. HNC 80 5 ION • le
Sulfur 0 3i7 utl 16 I/H
Claul Plant
Stack Gal
r— — eellllV Sulfur 149 I/H
CWERY "«^ G" » ^"
Net Heat Value
102 0 MM Btu/ll
1,581 BPCD r 0 E
—^^ SULFUR
2,114 I/H
14 Tone/Day
293 I/H
C 97 2
c 86 4
(67 BFiD 30 'API 7.5B3 I/H
RVP 1 RON 61 RON • Ice 82
NON 62 KOV • Ice Bl
(15 DFX.D
NO 6 Fuel Oil
5,529 BPCD
Total GafCline ^oo'
58,670 DPCD 62 4 'API ^^^
(21,700 I/H
Sulfur 0 006 wtl IB I/H
RVP 11 0
OCTANE RESEARCH F i,r>,
CLEAR 99 1 92 2
• :cc 98 9 il 2
• 2 24 g/gal 97.8 Jl
Keroaine
8,500 BPCD 42 M 1
103,980 I/H
Sulfur 3 12 wtl 1*, i,ll
2,990 BPCD
2'100 Dieiel Fun'
BPCD B.20G BP'.U
s 16 5 -API
' 103,620 'il
115 i/H
5,000
BPCD
NO 2 FUPJIACL OIL
15, (61 SP.b
11 1 'API
196,210 • il
Sulfur 0 14 vt
271 I/H
12 6
79.110 I/H
Sulfur 1 25 utl 987 I/H
viacoatty 170 Furol Sec at 122"F
Alphalt (unfiniahed)
1,100 BPCD
' 14 5 "API
11,803 I/H
S.l.'ur 1 0 «tl B14 I/
tion of cal. cracker feed and light gasolines.
77
-------
For desulfurization of the gas oil, the calcu-
lations are based on 80 percent sulfur removal with
a hydrogen consumption of 42 standard cubic feet
per pound sulfur removed (3.5 moIs hydrogen consumed
per mol sulfur removed). Above 85 percent sulfur
removal, the hydrogen consumption increases due to
saturation of polyaromatics and hydrocracking.
In Case 2, the hydrogen produced in the refocmer
would be more than adequate to supply the refinery
needs. The sulfur content would be 0.008 weight
percent in the total gasolines.
Economics for producing low-sulfur gasoline
in Case 2 are summarized in Table 2-6 and estimated
investments for the desulfurization facilities are
shown in Table 2-7. The economic basis is presented
in the Appendix. The investment for the desulfuri-
zation facilities is assumed to pay out in five
years (20 percent rate of return.)
The total added costs to produce low-sulfur
gasolines (above Case 1) depends upon refinery size
as follows:
Added Costs to
Refinery Capacity, Produce Low-Sulfur
BPCD Gasoline, Cents Per Gallon
16,000 1.59
44,000 1.01
100,000 0.67
Table 2-8 shows a comparison of yields in
Case 1 and Case 2. Table 2-9 shows the estimated
78
-------
Table 2-6. COSTS FOR GASOLINE DESULFURIZATION - CASE 2*
Refinery Capacity, BPCD
Investment for Desulfurization Facilities, Million Dollars
Years to Payout
Million Dollars Per Year:
Cash flow
Depreciation
Net Profit
Income Tax
Gross Margin
Operating Costs:
Depreciation
Operating Manpower
Utilities
Catalyst Replacement
Interest
Maintenance
Local Taxes and Insurance
Credit for Added Products
Credit for Lower Butane Charges
Total Operating Costs
100,000
11.1
5.0
44,000
7.5
5.0
16,000
4.4
5.0
2.22
0.74
1.48
1.48
2.96
1.50
0.50
1.00
1.00
2.00
0.88
0 .29
0.59
0.59
1.18
0.74
0.32
2.09
0.23
0.56
0.36
0.15
-1.00
-0.34
3.11
0.50
0.32
0.92
0.10
0.38
0.26
0.11
-0.44
-0.15
2.00
0 .29
0.22
0.33
0.04
0.22
0.16
0.06
-0.16
-0.05
TTTT
Total Added Costs for Low-Sulfur Gasolines:
Million Dollars Per Year (Gross Margin + Operating Costs) 6.07 4.00
Cents Per Gallon Gasoline 0.67 1.01
2.29
1.59
* Compared to Case 1
-------
CO
o
Table 2-7. INVESTMENT FOR DESULFURIZATION FACILITIES
100,000 BPCD
44,000 BPCD
16,000 BPCD
Light Gasoline Hydrodesulfurizer
Hydrodesulfurizer for FCC Feedstock
Sulfur Recovery (Claus Plant)
Onsite Subtotal
Offsite
Total Investment
Unit
Capacity
4,700 BPSD
35,000 BPSD
15 Ton/ Day
Invest.*
MM$
2.8
5.6
0.3
8.7
2.4
11.1
Unit
Capacity
4,300 BPSD
16,000 BPSD
7 Ton/Day
Invest
MM$
2.0
3.6
0.2
5.8
1-7
7.5
.* Unit
Capacity
1,600
6,000
None
Invest.*
MM$
1.3
2.1
—
3.4
1.0
4.4
* Investment include paid-up royalty (if applicable) plus initial charge for catalyst.
-------
Table 2-8. COMPARISON OF YIELDS - CASE 1 AND CASE 2
BPCD
Charges
Crude Oil
Isobutane
N-Butane
Total Charges
Case 1
100,000
863
3,964
104,827
Case 2
100,000
1,103
3,599
104,702
Difference
(Case 2-Case 1)
240
-365
-125
Products
Fuel Gas, F.O.E.
LPG (Propane-Propylene)
Gasolines
Kerosine
Diesel Fuel
No. 2 Furnace Oil
No. 6 Fuel Oil
Delayed Coke (5 Bbl = 1 Ton)
Asphalt
Sulfur
4,060
3,391
58,306
8,500
8,200
16,023
5,324
1,008
3,100
3,908
3,698
58,670
8,500
8,200
15,663
5,529
1,008
3,100
-152
307
364
-360
205
(20 tons/day)(34 tons/day) (14 tons/day)
Total Products (Excluding Sulfur) 107,912
108,276
364
Apparent Gain
(Products Minus Charges)
3,085
3,574
489
81
-------
Table 2-9. UTILITIES AND CATALYST REPLACEMENT - CASE 2*
Process Unit
Capacity
Light Gasoline FCC Feed
Hydro- Hydro- Sulfur
Desulfurization Desulfurization Recovery Total
9,700 BPSD
36,000 BPSD 15 TPD
Consumption of Utilities:
Electricity, KW
Fuel, MM Btu/ni
Cooling Water, GPM
Boiler Feedwater, Ib/hr
Steam Consumed, Ib/hr
Steam Generated, Ib/hr
Wash Water, GPM
Cost of Utilities, $/CD
Catalyst Replacement, $/CD
240
24
400
10
40
1,800
126
1,260
1,100
1,100
40
620
30
1
3,940
4,000
3,800
2,070
151
5,600
5,100
4,900
50
5,720
660
Fuel Equivalent of
Utilities, BPCD (F.O.E.)
650
*Utilities and catalyst replacement are incremental above those
in Case 1.
82
-------
utilities and catalyst replacement cost in Case 2.
The apparent liquid gain in products over
charges for Case 2 is 489 BPCD above Case 1. How-
ever, the utilities for the desulfurization facilities
would require 650 BPCD of fuel equivalent. Thus,
Case 2 would show a net loss of 161 BPCD in compari-
son to Case 1.
Investment to Produce Low-sulfur Gasolines in the
United States - Case 2
Based on the process scheme shown in Case 2,
a crude oil throughput at 15 million barrels per
day in 1978, and investment for the new desulfuri-
zation facilities at January, 1974 costs, the total
investment would add about 2.03 billion dollars to
U.S. refinery facilities. This investment would be
portioned depending upon refinery size as follows:
Range of Refinery % of Investment,
Crude Capacity, BPSD Crude Capacity Million Dollars
0 to 25,000 7.5 310
25,000 to 75,000 20.4 520
75,000 and larger 72.1 1,200
100.0 2,030
This investment applies to the typical U.S.
refineries and could be higher depending upon
future imports of high sulfur crude oils. Increased
imports of high sulfur crude oils would require de-
sulfurization at increased severities for streams
presently being desulfurized and installation of de-
sulfurization facilities for other refinery streams.
83
-------
In this event hydrogen for the refinery needs may
not be sufficiently available from the reformer and
new hydrogen production facilities may be required.
Potential Gasoline Production in Case 2 with Lead
Phase-Down
The potential production of no-lead, premium,
and regular gasolines was calculated attempting to
meet the EPA regulations on lead phase-down using
the blending components produced in Case 2. All
the gasolines would be low-sulfur. These results
(Table 2-10) indicate that the projected percent of
gasoline sales and EPA regulations on lead phase-
down can be met through 1978. In 1979, octane up-
grading would be required to meet the EPA regulations
on lead content.
84
-------
Table 2-10. POTENTIAL GASOLINE PRODUCTION IN CASE 2
WITH LEAD PHASE-DOWN
(1)
1976
1977
1978
1979
(2)
Year
Lead Content, g/gal
Allowed by EPA
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline, vol%
No-Lead (92 RON)
Premium (100 RON)
Regular (94 RON)
No-Lead Gasoline, vol%
N-Butane
Alkylate
Reformate
FCC Gasoline
Light Gasoline
Premium Gasoline, vol%
N-Butane
Alkylate
Reformate
FCC Gasoline
Light Gasoline
Regular Gasoline, vol%
N-Butane
Alkylate
Reformate
FCC Gasoline
Light Gasoline
HDS Gasoline
Gasoline Octanes
No-Lead,Research
Motor
Premium, Research
Motor
Regular, Research
Motor
(1) Potential gasoline blends are based on the gasoline yields
and properties from Case 2, "A" Typical U.S. Refinery with
Hydrodesulfurization of Cat Cracker Feed, Light Virgin
Gasoline and Light Coker Gasoline".
(2) In 1979, lead content of total gasoline pool would exceed
EPA regulation.
1.4
1.1
1.8
1.5
30
18
52
11
11
33
40
5
12
36
19
33
10
—
29
32
27
2
92.2
84.3
100.2
95.6
94.2
87.2
1.0
1.0
1.8
1.7
40
14
46
11
11
33
40
5
12
36
19
33
10
1
27
30
30
2
92.2
84.3
100.2
95.6
94.2
87.5
0.8
0.8
1.8
1.4
49
9
42
11
11
33
40
5
12
36
19
33
10
3
25
28
31
3
92.2
84.3
100.2
96.5
94.2
87.8
0.5
0.8
1.8
1:9
\
57
5
38
11
11
33
40
5
12
36
19
33
10
4
23
26
34
3
92.2
84.3
100.2
96.5
94.2
88.3
85
-------
CASE 3
"A" REFINERY WITH HYDRODESULFURIZATION OF CATALYT-
ICALLY CRACKED AND LIGHT GASOLINES (CASE 3)
Case 3 considers the cost to produce low-sulfur
gasolines by hydrodesulfurization of the catalyti-
cally cracked gasoline rather than the feedstock to
the catalytic cracker.
The refinery process units in Case 3 would be
the same as in Case 1 with the following additions:
• FCC Gasoline Hydrodesulfurization
• Light Gasoline Hydrodesulfurization
Figure 2-5 is a block flow diagram of Case 3 show-
ing the yields and properties of the intermediate
and final product streams. The yields and product
properties are compared with those for the U.S.
average and Cases 1 and 2 in Table 2-2.
Sulfur removal from the FCC gasoline of about
80 percent was selected since this yields about the
same sulfur content in the total gasolines as in
Case 2. At this desulfurization severity, 45 per-
cent of the FCC gasoline would be hydrogenated,
which would result in decreased research octane.
The octane debit and other results are summarized
as follows:
• Table 2-11 - Octane Debit
• Table 2-12 - Economics of Producing Low-Sulfur
Gasoline
86
-------
• Table 2-13 - Investment for Desulfunzation
Facilities
• Table 2-14 - Comparison of Yields, Case 1 versus
and Case 3
• Table 2-15 - Utilities and Catalyst Replacement
Requirements
The apparent gain (difference between products
and charges, Table 2-14 for Case 3 would be 6 BPCD
above the apparent gain for Case 1. However, the
utilities for the desulfurization facilities
would require 501 BPCD of equivalent fuel oil
(Tab]0 XV). Thus Case 3 would result in a net loss
of 495 BPCD compared to Case 1.
Economics as shown in Table 2-12 indicate that
the total added costs (above Case 1) would be 0.82
cents per gallon to produce low sulfur gasolines.
i'nebc costs include the penalty of 0.30 cents per
gallon of gasoline debited to the lower octanes
which result from partial hydrogenation of olefins
in the FCC gasoline.
87
-------
2S 11 '.it/U
I/JI
I t.jhi CanolL
(L - 'JOT)
9,f74 UPUi
74 1 AIM
M 64) • /!!
ll.b 30 I/ll
Sulfur 24 I/ll
1 , >i4 Ui'CU
15,7*0 l/ll
LHUDL I VALLUM UMT
LXLLL OIL
»-
lOJ,000 riPCD
J8 4 -API
1,21J.370 l/ll
Suitor 0 5 wtt
6,014 i/ll
MIX or C.IIUDLS FROII
TJXAb ANL. LOUIblAJA
U J12 dPL
14 O 'API
,
Sulfu- 1 9 wt%
I lyhl «.,is»il mi! |L, -200TI
b.f.lfl 111 'i u /) */ll
67 H MON t Ice. BJ 1
Korea
13,88
SuHu
ru. ( pil-SQO'F)
U11.U 4J 'API 1 1.4. 170 i/ll
0 12 wit 194 I/ll
(joo-r.ia*t}
12 11 ilPLIl Ju "Al'f I*l,b2u 4/H '
buliur .) 24 WL« 15'J l/ll
( ab ULl (OOU-1 ,MO"l )
jl , 717 UPIE)
23 2 *AI'[
40 J 930 I/ll
Sulfur 3 5S wtt
2,272 I/ll
1 itjht CiAstiJ irf ( r 200'H
514 III'LU 73»API '
5,180 i/H
bJlfur U 1J wtt 17 l/ll
RVP 7 j PONL 32 b
RO1 • Kc. 'fO J
MCJX. 70 1 WN • )cc 77 2
'» 1 f2 UPCD
7] iSJ i/M
Sulfur I 3'J,
2U,7'*4 IlI'LU
2 11, VI') l/ll
iiulfur U2 l/ll
22,160 l/ll
* %l 'leai Valu*
/,241 OP( U i >•
'ullur HS l/ll
23,090 l/ll
IX IIUL Ovo 1
12,100 i/ll
.ulfui 47 4/11
• IfLtOKMI K
851 UPU) j2*Al'l
9.J60 •/!>
Sulfur 0 i wl* 4ri
14,41 ) Ul'I I)
28 J "API
444 't?H l/ll
Sulfur U rH i
^,h)4 I/H
(,js 0] | ( J70-LI')
2,7 1., HI' LI) 29 7 'AIM
34,970 I/H
bul fur 1 Orj vi\
L i I iqhur
f, 7820 l/ll
bullur 4HO I/
^lfc '
^^^02
COKI
IQU */IL
ilior L luns/Luy
bulfur 2 flfi utl
484 l/ll
I
llf-ltiliL (II I (G'»0''l )
j-S II PL I» 2 2 'API
CIO l/ll
bulfur 1 88 wtt
499 l/ll
3,220 liPCU
45,490 I/M
Sulfur 866 I/H
Sulfur 38 l/ll
1.0 b Pud i .1
Bunker "i"
O.J24 bPtPJ
> 10 «> -AIM
77,120 l/ll
bulfur 1 82 wi,
1 403 l/ll
i 1 u
al l^J'l
Abfii.ilt iUn 11
J.I33 UPCn
14 5 -API
4J BOO I'll
SuMur I i ,i
Figure 2-5. A typical U.S. refinery with hydrodesulfurization
88
-------
1 lylit (as
t in UPC
PVI> 7 6
Su 1 1 u r )
L - Rt
16,1.54 [
HVl" 2 4
r—
BPU>
V T'"!
(. . L , 756
3 ,"jT9
28.311 i/H
ol mi
II 74 >i VIM 01,663 I/ll
KONL u'J 1 RIM • Jt.c RJ j
MONC IP 7 H HUN • ILL fab H
Purchased
N-Butane
1,979 UPID
13,9)3 I/H
PLU 44'Al'I H'j.SSO I/ll
HOW. Sj u IION • 3CL 100 6
rtuic as "i j>oi • ict 91 i BreD
Purchaaud p(. ™" ^j 1,804
IsoDutanc 9. .fcn .... 3 ] 391
116 1 BP1.0 ) "•"' ''"
^ cio I/H /
" ^^ 1 I >.-uutano l
1 J 2.223 BPCU IB, ISO I/ll
f l.« Alkyldti
1 MVP 3 3 KONL 94 6 RON - 3cc 105 6
1 HONC. 93 5 ION • ]CC 107 6
t^.^^^a^lfaV By-ProdutL oil Burned
^^^ 5 BPCU
19*AP1
70 I/ll
T01AL GASOLINE POOL
58,520 BPCD 62 6 V.P1
621,470 i/ll
Sulfur 0 006 wit 18 i/il
«VP 11 0
CKTA.t PtSEARCII 10 r ,'
Clear BR 0 81 7
•3cc »8 5 12 !
XLROSIliC
8,500 BKD I2*API
100,980 i/ll
Sulfur 0 12 ut« IU • II
I^'^^f
aK.a°-\\ /2.900 BPCD
/I ^
x~ H conaurcd 1 1
7,400 BPCD l»5> Sulfur Romoval) i 7|<00 BPCD f i
T J 93.140 l/ll 1 I,-,,,
-— J 110 I/H Sulfur 183 I/ll Sulfur 0 072 vtl 4 lupCD
1,100 BPlV] «' •/« [ p
1- 3.210 BPC.D
nL. 2,103 f 67 6ia ''H ^ claua Plant
C 1 2,866 ' .—•••> stack Caa
TT4T ^ Sulfur 96 I/H
AHINE TREAT IliC ^
j ?'i™ ;'!,'„. .... "»> G...K.I
I Nat Hoat Valua
310,610 i/ll [ 413 3 KM Btu/H
t^___«a«lBjJ>> 1.S2S BPCD FOE
Sulfur
1,814 I/H
H.S 140 ,/H " T°"""y
SOlfur 129 I/H
H, Coniuned
4*07 MM
930 •/»
FCC GAS
L, -430
20 401
58 9 'A
221,910
Sulfur
t
r i
OLINC 1 1 DESULFURIZCO FCC GASOLINE *
BPCU nc RASOLINE Sulfur 0 016 wtl 36 I/H
PI HYDROUESUL'URIZATION
I/H (781 Sulfur Removal
165 I/H ssi olefin Retention)
UILSLI -ULI
j.«» Si2?0.^"
0 L" 1 JO, 560 i/ll
148 •/!!
5,000
BPCD
f MO 2 FURNACL OH
16,023 BPCD 32 B •„, 1
201,010 I/H
of cat cracked'and light gasolines.
89
-------
Table 2-11. OCTANE DEBIT FOR CASE 3*
Octane at 0.5 g/gal
Case 1
Research 93.1
Motor 85.9
Research + Motor 89.5
2
Case 3
Research 92.2
Motor 85.9
Research + Motor 89.1
2
Research Octane Penalty =93.1-92.2= 0.9 Octane
. / $0.02 /58y520 Bbls / 42 Gal/
/ 6 Octane,Gal/ Day 7 Bbl l~
Octane Debit = 0.9 Octane. / $0.02 /58y520 Bbls / 42 Gal/ 365 Days
Year
= $2.69 million/year
or 0.30 cents per gallon of gasoline.
*Compared to Case 1
90
-------
Table 2-12. COST FOR GASOLINE DESULFURIZATION - CASE 3*
Refinery Capacity 100*000 BPCD
Investment for Desulfurization Facilities $8.3 million
Years to Payout 5
Million Dollars Per Year:
Cash Flow 1.66
Depreciation 0.55
Net Profit 1.11
Income Tax 1.11
Gross Margin 2.22
Operating Costs:
Depreciation 0.55
Operating Manpower 0.22
Utilities 0.91
Catalyst Replacement 0.04
Interest 0.42
Maintenance 0.29
Local Taxes and Insurance 0.01
Credit for Added Products -0.06
Cost for Added Butane 0. 04
Debit for Lower Octane 2.69
Total Operating Costs 5.11
Total Added Cost for Low-Sulfur Gasolines
(Gross Margin + Operating Costs) 7.33
Cents Per Gallon Gasoline 0.82
*Compared to Case 1
-------
Table 2-13. INVESTMENT FOR DESULFURIZATION FACILITIES - CASE 3
Investment *
Capacity Million Dollars
Refinery 100,000 BPCD
Light Gasoline Hydrodesulfurizer Unit 9,700 BPSD 2.8
FCC Gasoline Hydrodesulfurizer Unit 21,600 BPSD 3.6
Onsite Subtotal 6.4
Offsite 1.9
Total Investment 8.3
92
-------
Table 2-14.' COMPARISON OF YIELDS - CASE 1 AND CASE 3
Charges
Crude Oil
Isobutane
N-Butane
Total Charges
Case 1
100,000
863
3,964
BPCD
Case 3 Difference
(Case 3-Case 1)
100,000
863
3,979
104,827 104,842
15
15
Products
Fuel Gas, F.O.E.
LPG (Propane-Propylene)
Gasolines
Kerosine
Diesel Fuel
No. 2 Furnace Oil
No. 6 Fuel Oil
Delayed Coke (5 Bbl = 1 Ton)
Asphalt
Sulfur
4,060
3,391
58,306
8,500
8,200
16,023
5,324
1,008
3,100
3,867
3,391
58,520
8,500
8,200
16,023
5,324
1,008
3,100
-193
214
(20 ton/day) (22 ton/day)(2 ton/day)
Total Products (Excluding Sulfur)
107,912
Apparent Gain (Products Minus Charges) 3,085
107,933
3,091
21
93
-------
Table 2-15. UTILITIES AND CATALYST REPLACEMENT - CASE 3*
Process Unit
Capacity
Light Gasoline
Hydro-
Desulfurization
9,700 BPSD
Light Gasoline
Hydro-
Desulfurization Total
21,600 BPSD
Consumption of Utilities:
Electricity, KW
Fuel, MM Btu/H
Cooling Water, GPM
Wash Water, GPM
240
24
400
10
1,070
90
1,430
30
1,310
114
1,830
40
Cost of Utilities, $/CD
Catalyst Replacement, $CD
40
70
2,490
110
Fuel Equivalent of
Utilities, BPCD (F.O.E.)
501
'Utilities and catalyst replacement are incremental above those
in Case 1.
94
-------
SULFUR DISTRIBUTION
The sulfur contained in the crude oil to the refinery
is distributed in the products, recovered as elemental
sulfur, and emitted as SO- to atmosphere as shown in
Table 2-16 for all three cases studied.
Sulfur contained in the gasoline is only a small
fraction of the sulfur in the crude oil. Sulfur in the
products used as fuels eventually will be emitted as
sulfur oxides to the atmosphere as products of combus-
tion unless stack gas scrubbing or other types of
controls are used. The sulfur in delayed coke may be
emitted as sulfur oxides to the atmosphere or be com-
bined in metallurgical slag, depending upon the use
of the delayed coke.
From the values tabulated in Table 2-16, it is seen
that hydrodesulfurization of the gas oil feedstock to
catalytic cracking (Case 2) results in:
• gasoline with the same sulfur content as Case 3
but lower than Case 1
• diesel fuel, No. 2 furnace oil and Banker "C" with
lower sulfur than either Case 1 or 3
• increased recovery of elemental sulfur
95
-------
Table 2-16. SULFUR DISTRIBUTION
Sulfur Content, Lb/hr Case 1 Case 2 Case 3
Crude Oil
Products :
Gasoline
Kerosine
Diesel Fuel
No. 2 Furnace Oil
Bunker C
Asphalt
Delayed Coke
Recovered as Elemental Sulfur
Emitted as SO 7 to Atmosphere
Total
Sulfur Distribution, %*
Gasoline
Kerosine
Diesel Fuel
No. 2 Furnace Oil
Bunker C
Asphalt
Delayed Coke
Recovered as Elemental Sulfur
Emitted as SO 2 to Atmosphere
6,014
191
119
148
554
1,403
834
484
1,669
612
6,014
3.2
2.0
2.5
9.2
23.3
13.9
8.0
27.7
10.2
6,014
38
119
135
271
987
834
484
2,834
312
6,614
0.6
2.0
2.2
4.5
16.4
13.9
8.0
47.2
5.2
6,014
38
119
148
554
1,403
834
484
1,814
620
6,014
0.6
2.0
2.5
9.2
23.3
13.9
8.0
30.2
10.3
Total 100.0 100.0 100.0
*As percent of sulfur in crude oil
96
-------
APPENDIX A
GENERAL SITUATIONS OF REFINERIES IN THE UNITED STATES
No two crude oils or two refineries are the same.
Furthermore, no two refineries will produce and have the
same product demand. Depending upon the crude properties
and refinery process capabilities, different refineries
are geared to the following categories or combinations
thereof:
• Production of gasolines, mid-distillates and residual
oil
• Petrochemical production
• Lubricant production
• Asphalt production
United States refineries produce petroleum products in
relation to the market demands for quantities and properties.
Each refinery bases its operations on market demands and
availability of crudes within the limitations of its refinery
process units and the flexibility of operating conditions.
In crude topping and vacuum operations, crude oils can
be distilled into fractions with true boiling cut points
approximately as follows:
• Butanes and lighter components to gas recovery
• Pentanes to 200°F light gasoline for blending to
gasoline or isomerization of the pentanes and hexanes
to upgrade the octane number
• 200°F - 370°F naphtha for reformer feedstock to up-
grade the octane number or produce aromatics
97
-------
• 600°F - 1,000°F gas oil feedstock to catalytic crack-
ing, thermal cracking or hydrocracking
• Heavier than 1,000°F residuum for blending No. 6
fuel oil or to asphalt or produced as feedstock for
visbrcaking, delayed coking, fluid coking or solvent
deasphalting
Tyipcal ASTM distillations of refined products to sales
are shown in Figure A-l. Gasolines distill in the range of ,
80°F to 400°F, kerosine and jet fuel (kerosine-type) distill
in the range of 340°F to 530°F and diesel fuel and No. 2 .fuel
oil distill in the range of 350°F to 650°F. The term "mid-
distillates" refers to the distillates boiling between
gasoline and No. 6 fuel oil and comprises the kerosine,
aviation jet fuel, diesel fuels and No. 2 heating oil. Kero-
sine, aviation jet fuel and No. 1-D diesel fuel are produced
from the distillates boiling between 370°F and 500°F true
boiling cut points. No. 2 heating oil and No. 2-D diesel
fuel are blends of essentially 50 percent of the 370°F to
500°F fraction with 50 percent of the 500°F to 600°F fraction,
98
-------
DATA SOURCE: U.S. BUREAU MINES
PETROLEUM PRODUCTS SURVEYS
h 2 • 40TT
-—f—
% DISTILLED
Figure A-l. Typical ASTM Distillations
of Petroleum Products.
-------
APPENDIX B
U.S. PRODUCTION OF PETROLEUM PRODUCTS
Table B-l shows the range of crude capacities in U. S.
refineries in 1973. Refineries larger than 25,000 BPSD
have 92.5% of the U.S. crude capacity. The median quantity
of crude is processed in U.S. refineries of about 100,000
BPSD crude capacity.
Table B-2 shows the charge capacity of U. S. refineries
in 1973 by types of processing units.
Table B-3 shows the production U. S. refinery products
in 1971. Table B-4 shows the U. S. demand for mid-distillates
by use in 1973.
Table B-5 shows typical properties of the petroleum
products sold in the United States in 1972 and 1973.
The 1972 properties of the total U.S. gasoline pool were
estimated from U.S. Bureau of Mines surveys and Ethyl Corp-
oration sales data as follows:
Research Octane 97.5
Motor Octane 90.0
Lead, g/gal. 2.24
Sulfur, wt% 0.031
The response of lead content in the total U.S. gasoline
pool was estimated from the lead response of various premium
and regular gasoline blends. Figure B-l shows the research
and motor octanes of the total U.S. gasoline pool in 1972
as a function of lead content.
101
-------
Table B-l. CRUDE CAPACITIES OF U.S. REFINERIES IN 1973
Number- % of
Range of Crude of Crude Capacity,BPSD U.S. Crude
Capacities, BPSD Refineries Total Average Capacity
0-10,000 76 340,000 4,500 2.4
10,000-25,000 43 702,000 16,000 5.1
25,000-75,000 64 2,826,000 44,000 20.4
75,000-125,000 31 3,033,000 98,000 21.9
125,000-200,000 15 2,298,000 153,000 16.5
200,000-300,000 8 2,145,000 268,000 15.4
Larger Than 300,000 7_ 2,546,000 364,000 18.3
244 13,890,000 100.0
Total
Refineries Larger
Than 25,000 BPSD 125 12,848,000 103,000 92.5
102
-------
Table B-2. CAPACITY OF PROCESS UNITS IN UNITED STATES IN 1973
Process Unit
Crude Distillation
Vacuum Distillation
Delayed Cokers
Fluid Cokers
Visbreakers
Hydrogen Desulfurization:
Naphtha
Mid-Distillates
FCC Feedstock
Heavy Gas Oil
Reduced Crude
Cat Crackers (Fresh Feed)
Hydrocrackers
Cat Reformers
Alkylation (Sulfuric Acid)
Alkylation (Hydrofluoric Acid)
Aromatics (Benzene-Toluene-Xylenes)
Isomerization
Butane
Pentane
Pentane-Hexane
LuJ- as
Asphalt
C. ke
Charge
Capacity, BPSD
13,890,000
5,150,700
776,900
118,200
237,300
188,500
49,600
34,100
37,500
221,900
644,300
Vol. % of
Crude Capacity
100.0
36.8
6.4
2,798,800
1,109,700
279,800
184,000
19,500
4,512,600
865,100
3,278,100
531,300
280,600
20.0
7.9
2.0
1.3
0.14
32.3
6.2
23.4
3.8J
2.0J
1.3
0.35
0.24
0.27
1.6
4.6-
5.8
(42,700 ton/day) (0.00305 tons
coke per barrel
crude)
103
-------
Table B-3. U. S. REFINERY PRODUCTS IN 1971
Refinery Input
Crude Runs to Still
Natural Gas Liquids
Refinery Production
Motor Gasoline
Aviation Gasoline
Naphtha in Naphtha-Type Jet Fuel
Special Naphthas
Petrochemical Feedstocks
Total Gasoline-Naphtha
Ethane-Ethylene
Liquefied Petroleum Gas (LPG)
Propane-Propylene
03-04 Mix
Total Light Components
Kerosine
Kerosine-Type Jet Fuel
Kerosine in Nahptha-Type Jet Fuel
Total Kerosine
Distillate Fuel Oil
Residual Fuel Oil
Hsphalt (5.5 bbl = 1 short ton)
Road Oil
To'.al Residual Oil
Lubr .cants
Wax (1 bbl = 280 Ib)
Coke (5 bbl = 1 short ton)
Mis"- -llcreous Products
~ti '^s to Fuel
'-* -o lei
-o l el
'co uel
-Counted Yield
" i.fference (Accounted Minus Input)
Million
4,088
359
4,447
Million
2,179
18
43
28
111
9
32
12
3
87
219
42
275
157
9
65
7
157
Barrels
Barrels
2,379
56
348
911
441
72
62
14
5
14
3
179
4,462
15
Input
100.
8.
108.
Yield
53.3
0.4
1.1
0.7
2.7
0.2
0.8
0.3
0.1
2.1
5.4
1.0
6.7
3.8
0.2
1.6
0.2
3.8
0.1
0.3
0.1
, %*
0
8
8
, %*
58.2
~~T74
8.5
22.3
10.8
1.8
1.5
0.3
4.3
109.1
0.3
*Volume percent on crude input
104
-------
Table B-4. U.S. DEMAND FOR MID-DISTILLATES BY USE IN 1973
Kerosine
Kerosine-type Jet Fuel
Kerosine Content of Naphtha-type Jet Fuel
No. 1 Range Oil
Diesel Fuel Used on Highways
Industrial Uses
Oil Company Fuel
Railroads
Vessel Bunkering
Military Uses
Heating Oil
Gas and Electric Company Public
Utility Power Plants
Million Barrels %
80
233
38
15
~T66~
164
50
14
86
21
17
352
509
35
6.1
17.6
2.9
1.1
12.4
3.8
1.1
6.5
1.6
1.3
38.5
2.6
2T77
2677
54?
11.1
Miscellaneous and Unaccounted
60
4.5
Total Mid-distillates
1,322
100.0
105
-------
Table B- 5.
.L PROPERTIES OF PETROLEUM PRODUCTS
i
U.S. Bureau Min*. . >nr
Gravity. °API
Distillation, ASTM, °F
IBP
10%
30
so
70
90*
EP
Sulfur, wt %
Aniline Point, °F
Cctanc Number
Viscosity. CS at 100°F
Viscosity. Furol at 1 22°F
Carbon Residue, wt %
Lead, g/gal.
Octane Number:
Research
Motor
(Research + Motory2
Reid Vapor Pressure
Tola) Gasoline:
Sales. %
Sulfur, wt %
Research Octane
Motor Octane
(Research * MotorV2
Lead.sypl.
Reid Vapor Pressure
i
. RErui. **
H
JL_ ._
'• -
60.5
1
1 ' 1 1
92,
122; I.
163 '
208. T
262
339 ,
411
0.042
i
2.04
)
94.1 '
86.4
: 3.3
9.2
38
0.0:
97.<
90.C
1 93.J
, j ! 2.3<
rn
• i
1 i
• •
GASOLINF
Summer
1972
60.7
t
i 1
91
123
172
217
257
; 324
401
0.026
]
1
2.52
99.8
92.2
96.0
9.3
62
2
1 1
; .
j i
i i
1 i
1 • !
REGULAR
GASOLINE
Winter
1972-73
62.5
i ;
84 •
108 !
150 ' 1
200
257
334
405
0.038
(
1
1.80
93.9
86.4
90.2
12.2
37
0.0:
97.!
90.
93.1
, 2.U
1 1 •
-i ,
I
PREMIUM
GASOLINE
Winter
1972-73
63.0
84
109
158
209
251
352
397
0.023
2.34
99.6
92.2
95.9
12.1
63
!9
!
1
[
TOTAL
GASOLINE
POOL
Average
1972
61.7
0.031
97.5
90.0
93.8
2.24
10.7
KEROSINE
1973
42.3
1
341
378
428
485
525
0.067
146
1.66
JET A-l
FUEL
1972
42.4
362
405
464
0.065
140
DIESEL
FUEL
/ TRUCKS- \
^TRACTORS/
1972
.'6.5
375
427
495
573
618
021
147
4D.6
2.71
NO. 2
FURNACT
OIL
1973
35.1
' 367
425
504
580
635
0.22
2.71
NO. 6
!'! I •
1973
11.0
1.60
170
9.3
-------
L-.AO A'K(L ANTIKNOCK SUSCtPTIBJLtTr CHART
10
x
X
I t '
115
TOTAL U.S. GA
LEAD, g
RESEARC
MOTOR 0
SULFUR,
(
T 1
SOLINE POOL IN 1972
/gal. 2.24 '
H OCTANE 97.5
CTANE 90.0
WT% 0.031
' 1 :j ! .|. J
• - - • -
,-• • -
. . . .
. . .
._._u..
;•]
110
— 100
10J
: V 20 25 3.0
ANT;r.;«0< K CONTENf '.;»AMS Mf TALuC tEAO PER GALLON
Figure B-l. Octane of Total U.S. Gasoline Pool in 1972.
40 53
60
0 -J
-»
f
7
,00
8(J
r
33
3
Z
U
O
z
I
o
i
o^
Q.
107
-------
APPENDIX C
COSTS
All costs and capital are based on January, 1974
levels.
Capital related charges
Straight-line depreciation for 15 year life
Interest at 10 percent per year. This is equivalent
to 5 percent per year over the average payout period.
Maintenance: onsite, 4 percent; offsite, 2 percent
Local taxes and insurance: 1.5 percent
Payout on investment: 5 years after taxes
U.S. income plus state corporation taxes at 50 per-
cent of gross profit.
Incremental utility costs for new facilities
Fuel: $1.40 per million Btu net heat value. This
is equivalent to $7.50 per barrel of 38°API
crude oil.
Electricity: $ Per KWH
Fuel cost 0.014
Other charges 0.006
0.020
Steam:
$1.90 per 1,000 pounds corresponding to the
fuel cost of $1.40 per million Btu.
Cooling Water:
$0.20 per 1,000 gallons circulation
Treated boiler feedwater:
$0.05 per 1,000 pounds
Operating manpower costs
Average costs for stillman and operators at $6.00
per hour plus 30 percent fringe benefits. Sixty
percent overhead on operating manpower is added to
allow for supervision, laboratory, technical service
109
-------
and instrument services.
Manpower Cost
Per Shift Position $/HR %^ $/YR
Rate 6.00 52,600
Fringe Benefits 30 15,800
Overhead 60 41,000
TOTAL 109,400
6. Product prices
Incremental product yields were priced at the same
price as crude oil ($7.50 per barrel).
7. Royalties
Gas oil hydrodesulfurization:
Paid-up royalty $10.00 per BPCD feed rate
Naphtha hydrodesulfurization:
Royalty-free. Royalty costs would be included in
catalyst costs or nominal know-how fee.
8. Hydrogen make-up
Assumed to be available in the reformer make-gas for
hydrodesulfurization units.
9. Gasoline octane
Incremental gasoline octane priced at 2.0 cents per
6 octane difference between premium and regular
gasolines at the 1972 lead level of 2.24 grams
per gallon. This price is equivalent to 0.333 cents
per gallon per research octane number.
110
-------
APPENDIX D
OIL EQUIVALENT OF UTILITIES
Fuel
Net heat value at 6.1 million Btu per barrel fuel
oil equivalent. (F.O.E.)
Electricity
Net heat to generate electricity is assumed to be
10,000 Btu per kilowatt-hour. This requires 0.04
BPCD F.O.E. per kilowatt-hour.
Steam
Net heat to generate steam is assumed to be 1,370
Btu per pound of steam. This requires 5.4 BPCD
F.O.E. per 1,000 pounds per hour of steam.
Ill
-------
APPENDIX E
SOURCES OF INFORMATION
American Petroleum Institute
"Annual Statistical Review, U.S. Petroleum
Industry Statistics, 1972"
U.S. Bureau of Mines, Mineral Industyr Surveys
"Motor Gasolines, Summer 1972"
"Motor Gasolines, Winter 1972-1973"
"Aviation Turbine Fuels, 1972"
"Diesel Fuels, 1973"
"Burner Fuel Oils, 1973"
"Crude Petroleum, Petroleum Products, and Natural-
Gas-Liquids; 1971 (Final Summary)"
U.S. Federal Register
Environmental Protection Agency
Part 80. Regulations of Fuels and Fuel Additives
Vol. 38, No. 6 - Jan. 10, 1973
Vol. 38, No. 234 - Dec. 6, 1973
Ethyl Corporation
"Yearly Report of Gasoline Sales by States, 1972"
Oil and Gas Journal (Petroleum Publishing Company)
"1973-74 Worldwide Refining and Gas Processing
Directory"
113
-------
PART 3
PRODUCTION OF LOW-SULFUR
GASOLINES IN CALIFORNIA REFINERIES
115
-------
CHAPTER 1
INTRODUCTION
This part of the report covers work which was performed under Contract
68-02-1308 for the Environmental Protection Agency (EPA), Office of
Research and Monitoring, Task 10, Phase 3.
The purpose of this work is to determine the impact of producing low-sulfur
gasolines on the refineries supplying California and the Los Angeles area.
Refineries in the Los Angeles area account for 56% of the crude capacity in
California. For this work, the basic refinery was considered to have process
units with capacities based on percent of crude input to be the average of
refineries within California charging a crude mix with the average composi-
tion of crudes now being processed in California. Desulfurization facilities
were then added to this basic refinery, using two processing schemes, to
produce low-sulfur gasolines.
Refineries in California process crude mixes averaging 53% domestic crudes
and 47% foreign crudes. The California crude oils are heavy crudes with
high sulfur content. As the results of the heavy high sulfur charge stocks
and the market demands in California, these refineries have more residual
oil processing, more hydrogen treating of products, and more hydrocracking
of gas oils than the "typical refineries in the United States.
In order to show the maximum costs for producing low-sulfur gasolines, it
was assumed that new facilities would be necessary to provide the incremen-
tal hydrogen, remove hydrogen sulfide and recover sulfur.
Part 2 of this report (Phase 2) presented a similar study based on a
"typical" U. S. refinery and crude oil mix. The Phase 3 work supple-
ments the Phase 2 report.
117
-------
CHAPTER 2
SUMMARY
This study shows how a model of the average refineries in California can
produce no-lead, low-sulfur gasoline and by installing new hydrodesulfuri-
zation facilities can produce low-sulfur gasolines to include the no-lead,
premium, and regular gasolines.
Results of this study show that the existing large California refineries can
produce no-lead, low-sulfur gasoline at the projected percent of gasolines
sales through 1979, blended from normal butane, light hydrocrackate, re-
formate, and alkylate. Beyond 1976. the predicted demand of no-lead and
premium gasolines could not be met with EPA limits on lead anti-knock in
the total gasoline pool.
Total gasolines can be made low-sulfur by hydrodesulfurization of the gas
oil feedstock to catalytic cracking and by hydrodesulfurization of the light
virgin gasoline and light thermally cracked gasolines. Economics for this
scheme (Case 2) show that the costs** for producing low-sulfur gasoline
would add 1.1 cents per gallon to the costs of manufacturing the present gaso-
lines in refineries of 100,000 barrels per calender day (bpcd) capacities.
An alternate case considers hydrodesulfurization of the catalytically cracked
gasoline rather than the feedstock to the catalytic cracker. Economics in-
dicate that this scheme (Case 3) to produce low-sulfur gasoline would add
about 1. 0 cent per gallon to the present cost** of manufacturing gasolines
in refineries of 100, 000 bpcd capacities.
In California, there are eleven refineries which are larger than 75,000 bpsd. *
The crude capacities for these eleven refineries total 1, 402, 000 bpsd which
is 78% of the total crude capacity of all refineries in California. If new
facilities were installed to produce low sulfur gasolines in these eleven re-
fineries by desulfurizing the light virgin gasoline, light thermal gasolines,
and catalytic cracker feedstock (Case 2), an investment of about 250 million
dollars would be required based on May, 1974 costs.
Based on the gasoline yields and properties in Case 2 for low-sulfur gaso-
lines, the predicted sales ratios of no-lead, premium, and regular gaso-
lines could be blended and meet the EPA regulations on lead phase-down for
1975 and 1976. Additional processing for octane up-grading would be re-
quired starting in 1977 to meet the EPA regulations on further lead phase-
down.
* bpsd - Barrels per stream day
bpcd - Barrels per calander day
**Costs include 5 years payout on investment (20% rate of return) after
taxes.
119
-------
CHAPTER 3
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN
PRESENT CALIFORNIA REFINERIES
CRUDE OILS RUN IN CALIFORNIA REFINERIES
At present, California refineries process about 53% domestic
crudes and 47% imported crudes. Table 3-1 shows the origins of
crudes processed in District 5 which includes California. The Cali-
fornia crude oils are typically heavy and high sulfur crudes. The
Middle East are also typically high sulfur crudes. Therefore, 'the
average mixture of crudes processed in California refineries is
heavier and has higher sulfur content than the crudes processed in
the average U.S. refinery.
Table 3-2 lists the crude mix selected for this study. This crude mix
would be 28°API. 1. 27 wt% sulfur, and 4.1 wt% Conradson carbon.
When the Alyeska pipeline begins delivering North Slope crude oil in
1977, this crude will probably be processed by the West Coast refin-
eries and reduce their imports of foreign crude oils.
Addition of Alaskan North Slope crude oil to the West Coast crude mix
will not materially effect the crude mix as the North Slope crude is
26°API, 1.1 wt% sulfur, and 6. 0 wt% Conradson carbon.
AVERAGE OF CALIFORNIA REFINERIES - CASE 1
As the results of processing heavy crude oils with high sulfur contents
and sales demands, the California refineries have more residual oil
processing, more hydrogen treating of products, and more hydro-
cracking of gas oils than the "typical" refineries in the United States.
Table 3-3 shows the capacities of processing units in California re-
fineries. *
The refinery process units selected for Case 1 for an "Average of
California Refineries" were as follows:
- Crude and Vacuum Distillation
- Catalytic Reformer with Hydrogen Pretreat Section
- Fluid Catalytic Cracker with Vapor Recovery
- Catalytic Hydrocracker
- Jet Fuel Hydrotreater
- Diesel Hydrotreater
- Alkylation
- Delayed Coker
- Visbreaker
- Solvent Deasphalting
- Amine Treating and Sulfur Recovery
121
-------
Table 3-1. CRUDE OILS FOR DISTRICT 5
THOUSAND BARRELS VOL% OF
PER DAY TOTAL
Domestic Crudes:
California
Alaska
Four-corners Pipeline
Rail From Utah
910
190
30
15
1,145
42.2
8.8
1.4
0.7
53. 1
Foreign Crudes:
Canada
Venezuela
Ecuador. Peru
Middle East
Indonesia
250
20
70
470
200
1.010
11.6
0.9
3.2
21.9
9.3
46.9
Total Crude Oils
2.155
100.0
'rron,: Oil & Gas .Journal, March 18. 1974
122
-------
Table 3-2. SELECTED CRUDE MIX
THOUSAND BARRELS
PER DAY
California:
M id way - Sun s et
Huntington Beach
Wilmington
Alaska
Canada
Middle East (Arabian)
Indonesia (Minas)
Total
910
190
250
470
200
2.020
VOL% OF
TOTAL
13
7
25
9
13
23
10
100
123
-------
Table 3-3. PROCESSING UNITS IN CALIFORNIA REFINERIES
PROCESS UNIT
Crude Distillation
Vacuum
Catalytic Cracking
Catalytic Hydrocracking
Thermal Cracking Gas Oil
Catalytic Reforming
Hydrotreating:
Naphtha
Mid-Distillate
Other
Delayed Coking
Fluid Coking
Visbreaking
. , -ylation, HF
Sulfuric Acid
Aromatics, BTX
Isomerization, C$
C5&C6
Asphi It
Solvent Deasphalting
FEED CAPACITY
BPSD
Los Angeles
Area
996.000
509. 500
284. 500
134,200
23.000
245.700
234.000
149.000
210.000
86. 000
1 5. 800
33.600
4,000
5.000
13.000
-
47.100
Total
California
1.785.200
930.000
473. 500
312.100
32, 500
463.700
425.400
202.800
64. 000
252. 500
71,000
95,600
15.800
73.000
5.500
9.700
13,000
23.800
96,400
45.000
FEED CAPACITY
VOL% ON CRUDE CAPACITY
Los Angeles
Area
100.0
51.2
28.6
13.5
2.3
24.7
23.5
15.0
21.1
8.7
1.6
3.4
0.4
0.5
1.3
-
4.7
Total
California
100.0
52.1
26.5
17.5
1.8
26.0
23.8
11.4
3.6
14.1
4.0
5.4
0.9
4.1
0.3
0.5
0.7
1.3
5.4
2.5
124
-------
Figure 3-1 shows the flow scheme for this "Average of California
Refineries".
To calculate the refinery yields, the following conditions were
assumed:
- Crude input to basic California refinery (Case 1) would be
100.000 bpcd crude oil.
- Catalytic cracker would operate at 75% conversion with yields
corresponding to riser cracker with zeolite catalysts.
- Production of alkylate was set at 5.0 vol% on crude input by
taking propylene to LPG.
- Reformer severity would produce 95 research octane clear.
- Unfinished asphalt would be produced from vacuum residuum and
asphalt from solvent deasphalting.
- Production of lubricants and waxes were not considered as these
account for only 0. 9 vol% on crude input.
- Special naphthas and the benzene - toluene - xylenes aromatics
were considered to be part of reformate and would be accounted
in the total gasolines.
Capacities of the process units required to process the streams from
the selected crude mix in Case 1 are compared in Table 3-4 with the
average of California refineries based on percent of crude input.
Product yields and properties in Case 1 are compared in Table 3-5
with products produced in California refineries.
The comparisons in Table 3-4 and Table 3-5 show that refinery
model and crude mix used in Case 1 may be considered an average
of the California refineries.
For Case 1, the overall material balance is shown in Table 3-6 and
the gasoline pool is shown in Table 3-7.
The volumetric blended octanes shown in Table 3-7 were corrected
for sensitivities, olefin content and aromatic content. The correc-
ted octanes are shown in Figure 3-2.
SALES OF PREMIUM AND NO-LEAD GASOLINES IN CALIFORNIA
During the period 1953 to 1972, the premium gasoline sales as per-
cent of total gasoline sales in California has been 16 to 20% higher
than the average for the United States.
Figure 3-3 shows a projected percent of sales of premium gasoline
and no-lead gasoline in California. It was assumed that the premium
gasoline would be 25% of sales in 1977. The sales requirements for
premium gasoline will continue to decrease as the pre-1971 high
125
-------
IZ
Figure 3-1. Flow schemes for
-------
®-
h
*c*afs f*r~e>f.
average of California refineries.
127
-------
Table 3-4. CAPACITIES OF PROCESS UNITS IN CASE 1
COMPARED WITH CALIFORNIA REFINERIES
PROCESS UNITS
VOL% OF CRUDE CAPACITY
Crude Distillation
Vacuum Distillation
Catalytic Cracking
Catalytic Hydrocracking
Thermal Cracking Gas Oil
Catalytic Reforming
Hydrotreating:
Naphtha
Mid-Distillate
Other
Delayed Coking
Fluid Coking
Visbreaking
Alkjlation, HF
Sulfuric Acid
A romatics, BTX Production
omerization. C$
C5&C6
Lube Production
Asphalt Production
Solvent Deasphalting
Average of California
Refineries in 1973
100.0
52.1
26.5
17.5
1.8
26.0
23.8
11.4
3.6
14.1
4.0
5.4
0.9
4.1
0.3
0.5
0.7
1.3
5.4
2.5
Case 1
100.0
51.5*
24.4
17.1
-
24.0
15.8
11.4
-
12.3
-
3.7
5.0
_
-
-
_
2.2
1.7
--A+ b?0° F TBP cut point in crude oil
128
-------
Table 3-5. COMPARISON OF PRODUCTS AND YIELDS
Basis: Yields are Vol% on crude input and for West Coast (PAD District
5) for January 1972-September, 1973. Properties of products are
from 1973 sales in California.
TOTAL GASOLINES
Yield, Vol % on Crude Input
°API
Sulfur, wt%
Lead Anti-knock, Grams Per Gal.
Research Octane
Motor Octane
Reid Vapor Pressure
JET FUEL AND KEROSINE
Yield, Vol% on Crude Input
°API
Sulfur, wt%
Aniline Point, ° F
DIESEL AND NO. 2 FURNACE OIL
Yield, Vol% on Crude Input
°API
Sulfur, wt%
Cetane Index
NO. 6 FUEL OIL
Yield, Vol% on Crude Input
°API
Sulfur, wt%
Carbon Residue, wt%
OTHER PRODUCTS
Yield, Vol% on Crude Input:
Coke (5 bbl = 1 Short Ton)
Asphalt and Road Oil
Still Gas to Fuel
Liquefied Refinery Gas
Lube Oil, Wax. & Miscellaneous
APPARENT PROCESSING GAIN
Vol% on Crude Input
LPG INPUT
West Coast
Production
51.0
58.5
0.046
2.1
97.2
89.0
10.0
11.0
42.9
0.045
143
13.7
35.0
0.27
50.0
17.4
11.0
1.5
11.2
Case 1 Case 2 Case 3
Vol% on Crude Input
4.5
3.3
4.7
2.5
1.2
6.4
1.0
55.5
61.5
0.053
2.1
97.1
89.6
10.0
11.6
39.0
0.049.
139
14.8
35.7
0.26
48.8
14.6
10.8
2.4
9.1
3.1
2.2
3.8
2.9
None
55.5
62.6
0.006
2.1
97.4
90.4
10.0
11.6
39.0
0.049
139
14.8
35.6
0.26
48.8
14.6
11.3
1.7
9.1
3.1
2.2
3.7
3.3
None
55.5
61.6
0.006
2.1
96.0
90.8
10.0
11.6
39.0
0.049
139
14.8
35.7
0.26
48.8
14.6
10.8
2.4
9.1
3.1
2.2
3.8
2.9
None
6.4
1.2
7.0
0.8
6.4
1.2
129
-------
Table 3-6. OVERALL REFINERY MATERIAL BALANCE - CASE 1
INPUT BPCD #/H SULFUR CONTENT, #/H
Crude Oil 100.00 1.292.720 16.377
Purchased N-Butane 1,204 10,250
H? Plant: Nat. Gas-FOE 848 10.020
Water 22.550
Total Input 102.052 1.335.540
OUTPUT
Gas to Fuel - FOE 3,769 46,210 182
H2S to Sulfur Recovery - 7,030 6.613
LPG 2,874 21,360
Gasolines 55,519 592.760 315
Alkylation By-product Oil 6 80
Jet Fuel & Kerosine 11.582 140.060 68
Diesel & Distillate Fuel Oil 14.787 182,400 472
No. 6 Fuel Oil 14,629 212,010 5.167
Asphalt 2,200 33,540 1.017
Delayed Coke (5 bbl = 1 Short
Ton) 3,100 51,660 1.723
Catalytic Cracker Coke
Burned - 20.450 820
CO2 From H2 Plant - 27. 560
TH3 From Hydrocracker - 420 -
Total 108,466 1,335,540 16.377
Apparent Gain 6,414
130
-------
Table 3-7. GASOLINE POOL - CASE I
TBPBOIlINf, RANC.t "1
VOL FRACTION
BPCD
"API (SP CR )
LB/H
REID VAPOR PRESSURE
OCTANE
RESEARCH CLtAR
RESEARCH* 3 cc
MOTOR CLEAR
MOTOR* 3 cc
OLEFINS VOL 9
AROMATICS. VOL It
SULFUR. Wit
LB/H
ISOBUTAM
0003
158
10 5626)
1290
82 5
1026
1042
976
1030
--
—
N-BUTANE
007S
4137
(0584)
35.210
591
938
1016
903
1004
_ _
—
LJCHT
VIRGIN
GASOLINE
C5-200
0108
5990
740
60060
90
700
882
682
866
._
3
0019
II
LIGHT
COKER
GASOLINt
Cs-200
0017
927
697
9.490
67
81 1
883
677
755
17
4
049
47
LIGHT
VISBREAKLK
GASOUNk
Cs-200
0002
IIS
750
1 ISO
6!
81
88
68
76
37
4
004
s
RHFORMATE
C^EP
0359
19.970
480
229340
35
940
1000
848
907
10
34
_ .
—
ALKYLATE
Cs-EP
0090
5.000
716
50.740
31
941
105 1
930
1070
—
—
CAT
CRACkED
GASOLINfc
C's-410
0263
I4.60S
572
159620
67
91 2
982
822
872
17
34
0158
252
LIGHT
HYDRO-
CRACKATE
Cj :OU
0081
4481
765
44410
1:0
82 R
•»«•!>
82 5
496
.
i
—
HDS
GASOLINE
Ls-400
0002
136
610
I4SO
70
63
84
63
85
_
-
--
TOT\L
1000
55519
615
592760
100
401
484
WO
9:0
; <
:i i
0053
315
-------
IIS
110
105
100
u
CD
90
°-5 1-0 1.5 2.0 2.5 S.O
ANTIKNOCK CONTENT, GRAMS METALLIC LEAD PER GALLON
Figure 3-2. Octanes of Total Gasoline Pool
— N<
3TE:
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132
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Figure 3-3. Projected Percent of Sales of Premium
and No-Lead Gasoline in California
f
t
4
f
/
»
j
/
f-
f
/
j
191
133
-------
compression cars are junked. The projected sales percent of
no-lead gasoline is assumed to follow the projected sales of new cars
which require no-lead gasolines.
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN PRESENT
CALIFORNIA REFINERIES ~~
The time to plan, finance, and construct refining facilities to up-
grade gasoline blending components requires about three years
from the date of a firm decision to proceed. During the period un-
til the additional gasoline-upgrade facilities are onstream, the no-
lead, low-sulfur gasolines will have to be blended from low-sulfur
components which can be produced in the present refining facilities.
In the California refineries, the present low-sulfur gasoline compon-
ents are normal butane, reformate, light hydrocrackate and alky late.
The potential production of no-lead, low-sulfur gasoline together
with premium and regular gasoline were calculated attempting to
meet the EPA regulations on lead phase-down using the blending
components produced in Case 1. The results '(Table 3-8) indicate
that the projected percent of gasoline sales can be met in 1975 and
and 1976. In 1977 and later years, the EPA limit on lead content
would be exceeded.
No-lead gasoline and premium gasoline utilize the same gasoline
blending components such as reformate and light hydrocrackate or
alkylate. Regular gasoline will contain the lower-octane blending
components which cannot be utilized in no-lead or premium gasoline
blends. Therefore if the projected sales demand for no-lead or pre-
mium gasoline significantly increased from the projected sales,
shortages of premium and no-lead gasoline may occur.
In 1977 and later years, octane up-grading will become necessary
to meet the EPA regulations on lead phase-down. In 1977, it may be
possible to increase the reformer severity. In the later years, new
octane up-grading facilities will need to be installed. The processes
for octane up-grading include isomerization of normal pentane and
hexanes and reforming of heavy catalytic cracked naphtha.
In producing no-lead, low-sulfur gasoline. Table 3-8 shows that the
sulfur contents by 1979 in the premium and regular gasolines will
be about twice the present sulfur levels. In 1979, regular gasoline
and premium gasoline would respectively contain 0.11 and 0.07 wt%
sulfur.
134
-------
Table 3-8. POTENTIAL GASOLINE PRODUCTION. JN CASE 1
WITH LEAD PHASE-DOWN
Year 1972 1975 1976 1977 1978 1979
Lead Content, Grams/Gal
Allowed by EPA 4. 2(2) 1.7 1.4 1.0 0.8 0.5
Total Gasoline Pool 2.12 1.56 1.07 1.01 1.03 0.93
Premium Gasoline 2.65 2.91 2.00 2.07 2.75 3.00
Regular Gasoline 1.32 0.92 0.92 1.07 1.17 1.36
Potential Gasoline. Vol%
No-Lead, Low-Sulfur
(92 RON) - 11 20 29 38 47
Premium (99.5 RON) 54 37 31 25 19 13
Regular (93.5 RON) 46 52 49 46 43 40
No-Lead Gasoline, Vol%
N-Butane 9 9 999
Light Hydrocrackate - 18 18 18 18 17
Reformate - 73 73 73 73 70
Alkylate - - 4
Premium Gasoline, Vol%
N-Butane 989 999
Alkylate 17 20 29 22 22 21
Reformate 40 33 26 31 31 24
FCC Gasoline 25 23 21 26 31 46
Light Hydrocrackate 9 16 15 12 7
Regular Gasoline, Vol%
N-Butane 676 655
Isobutane 0.5 0.5 0.5 0.5 0.5 0.5
Light Coker & VB
Gasoline 444 455
Reformate 31 30 27 15 5
FCC Gasoline 28 34 40 43 48 51
Light Hydrocrackate 7 - - -
^ight Virgin Gasoline 23 21 22 23 25 27
HDS Gasoline 0. 5 0.5 0.5 0.5 0.5 0.5
Alkylate - 3 - 8 11 11
135
-------
Table 3-8 (continued). POTENTIAL GASOLINE PRODUCTION IN CASE 1
(1)
WITH LEAD PHASE-DOWN
Year 1972 1975 1976 1977 1978 1979
Gasoline Octanes
No-Lead, Research - 92.4 92.4 92.4 92.4 92.5
Motor - 85.0 85.0 85.0 85.0 85.2
Premium, Research 99.6 99.5 99.5 99.5 99.5 99.5
Motor 92.4 93.5 96.8 95.2 92.6 91.7
Regular. Research 93.9 93.5 93.5 93.5 93.5 93.5
Motor 86.3 85.5 84.9 85.7 85.8 85.9
Sulfur. Wt%
No-Lead, Low-Sulfur - -
Premium 0.033 0.037 0.034 0.043 0.050 0.074
Regular 0.058 0.076 0.087 0.094 0.104 0.112
Comment - See Note (3) (3) (3)
NOTES:
(1) Gasoline blends are calculated at 10 pounds Reid vapor pressure using the
gasoline components with the yields and properties from Case 1 for the
Average" of California refineries.
(2) Legal limit was 4. 2 grams lead content per gallon prior to EPA regulations.
(3) In 1977, 1978 and 1979, the lead content in the total gasolines would exceed
r> EPA limits on lead content. Additional octane upgrading refining facili-
ties will be required to meet the EPA limits on lead content.
136
-------
CHAPTER 4
DESULFURIZATION OF GASOLINES
GENERAL
In order to calculate the costs of producing low-sulfur gasolines, the
"Average of California Refineries" was taken as the basic refinery
and then low-sulfur gasoline produced by two types of process addi-
tions:
- Hydrodesulfurization of catalytic cracker feedstock and hydrode-
sulfurization of the light virgin, light coker. and light visbreaker
gasolines (Case 2).
- Hydrodesulfurization of catalytic cracker gasoline and hydrode-
sulfurization of the light gasolines (Case 3).
In this study, the costs were purposely made on the conservative
(i.e. higher capital) side as follows:
- Investments included new units to provide the incremental capa-
cities for hydrogen, amine treating and sulfur recovery. In Case
3, these units are small and may not be required.
- In Case 2, the catalytic cracker conversion was kept at 75% as in
Case 1. Depending upon the whether the refinery catalytic cracker
severity is coke limited or gas limited, it may be practical in Case
2 to increase the catalytic cracker conversion to make this case
more attractive.
In Case 3, the octane of the catalytic cracked gasoline would be lower
after hydrotreating due to partial olefin saturation. Economics deb-
ited the lower octane by penalizing the production of premium gaso-
line using the price differential between premium and regular gaso-
lines. If additional octane up-grading were necessary the costs
would further penalize Case 3.
CASE 2: AVERAGE CALIFORNIA REFINERY WITH HYDRODESULFURIZATION
OF CATALYTIC CRACKER FEED AND LIGHT GASOLINES
In Case 2, the crude oil and refinery process units would be the same
as Case 1 of the "Average of California Refineries" with the following
additions:
- Hydrodesulfurization of catalytic cracker feedstock.
- Light gasoline hydrodesulfurization.
- New units for incremental needs for hydrogen, amine treating,
and sulfur recovery.
The flow scheme for "Average of California Refineries" shows the
added hydrodesulfurization unit. The yields and product properties
are listed in Table 3-5 together with, the information for the West Coast
production and Case 1. For Case 2. the overall material balance
137
-------
is shown in Table 3-9 and the gasoline pool is shown in Table 3-10
The sulfur content of the total gasolines would be 0.006 weight percent.
The incremental investment to product low-sulfur gasolines is esti-
mated to be 18.7 million dollars (Table 3-11) in Case 2 for a 100,000
bpcd refinery.
In California, there are eleven refineries which are larger than
75,000 bpsd. The crude capacities of these eleven refineries total
1,402,000 bpsd which is 78% of the total crude capacity of all re-
fineries in California. If new facilities were installed to produce
low-sulfur gasolines in these eleven refineries by desulfurizing light
virgin gasoline, light thermal gasolines, and catalytic cracker feed-
stock (Case 2), an investment of about 250 million would be required
based on May, 1974 costs.
Economics show that this desulfurization scheme would add 1.1 cents
per gallon to the costs of producing gasoline (Table 3-16).
The potential production of no-lead, premium and regular gasolines
were calculated attempting to meet the EPA regulations on lead
phase-down using the blending components produced in Case 2. All
the gasolines would be low-sulfur. The results (Table 3-12) indi-
cate that the projected percent of gasoline saies can be met in 1976.
In 1977 and later years, the EPA limit on lead content would be ex-
ceeded.
Results in Table 3-16 for Case 2 and in Table 3-8 for Case 1 indi-
cate that refiners should start planning installation of new octane
up-grading facilities or that EPA should relax the lead phase-
down regulations to about the 1.4 grams per gallon for 1976 and
later years.
CASE 3: AVERAGE CALIFORNIA REFINERY WITH HYDRODESULFURIZATION
OF CATALYTIC CRACKED GASOLINE AND LIGHT GASOLINES
In Case 3, the crude oil and refinery process units would be the same
as Case 1 of the "Average of California Refineries" with the follow-
ing additions:
- Hydrodesulfurization of catalytic cracked gasoline.
- Light gasoline hydrodesulfurization.
- New units for incremental needs for hydrogen, amine treating,
and sulfur recovery.
138
-------
Table 3-9. OVERALL REFINERY MATERIAL BALANCE - CASE 2
INPUT BPCD #/H SULFUR CONTENT, #/H
Crude Oil 100.000 1,292,720 16.377
Purchased N-Butane 796 6.770
H2 Plant: Nat. Gas-FOE 1,076 12,720
Water 28,620
Total 101.872 1.340.830 16.377
OUTPUT
Gas to Fuel - FOE 3.746 46,120 183
Ho S to Sulfur Recovery 9,670 9,100
LPG 3,335 24,860
Gasoline 55.536 589.860 36
Alkylation 5 70
Jet Fuel & Kerosine 11,582 140,060 68
Diesel & Distillate Fuel Oil 14.821 182.860 473
No. 6 Fuel Oil 14.587 210.660 3,673
Asphalt 2.200 33.540 1.017
Delayed Coke (5 bbl=l Short
Ton) 3,100 51,660 1,723
Catalytic Cracker Coke
Burned 16.070 104
CO 2 From H2 Plant 34. 980
NH 3 From Hydrocracker 420
Total 108,912 1,340,830 16.377
Apparent Gain 7. 040
139
-------
Table 3-10. GASOLINE POOL - CASE 2
TBP BOILING RANGE »F
VOL FRACTION
BFCD
°API (SP CR )
LB/H
RbID VAPOR PRESSURE
OCTANE
RESEARCH CLEAR
RESEARCH * 3 ce
MOTOR CLEAR
MOTOR * 3 cc
OLEFINS.VOL%
AROMATICS VOL%
SULFUR. WT«
LB/H
ISOBUTANE
0006
316
(0 5626)
2 MO
825
1026
1042
976
1030
—
—
—
N-BUTANE
0068
3.793
(0 584)
32280
501
938
1016
903
1004
—
HDS
LIGHT
GASOLINE
Cs-200
0127
7,040
736
70750
87
687
883
671
870
31
0.004
3
REFORMATS
CS-EP
03S9
19.970
480
229340
35
940
1000
848
907
10
34
ALKYLUE
CsEP
OOW
5000
^^4
SO 800
3:
943
IOS4
9J3
1013
_
--
-
CAT
CRACKED
GASOLINE
Cj-430
0264
14678
586
156940
7 1
91 9
992
81 0
883
156
32
002
33
UGH1
HYDRO-
CRACKATE
C5200
0081
4481
765
44410
12.0
828
968
825
996
2
—
—
HDS
GASOUVES
CjEP
0005
258
61 :
:7bO
TO
6.'
84
6'
85
__
—
-
TOTAL
1000
55.536
626
589860
100
S93
986
825
925
45
21 3
0006
36
-------
Table 3-11. INVESTMENT FOR DESULFURIZATION FACILITIES - CASE 2
FACILITY
CAPACITY
Refinery Size 100,000 BPCD
Light Gasoline Hydrodesulfurizer 7.400 BPSD
Catalytic Cracker Feed
Hydrodesulfurizer
Amine H- S Removal
Sulfur Recovery (Glaus Plant)
Hydrogen Plant
Onsite
Offsite (at 30% of Onsite)
Total Investment
25. 700 BPSD
Amine Circulation
193 GPM
INVESTMENT. *
MILLION DOLLARS
3.2
6.2
30 Short Tons/Day
8.3 MM SCF/D
1.0
0.5
3.5
14.4
4.3
18.7
Investment includes paid-up royalties (if applicable) plus
initial charges of catalysts. Investment at May, 1974 levels.
141
-------
Table 3-12. POTENTIAL GASOLINE PRODUCTION IN CASE 2
WITH LEAD PHASE-DOWN^1)
Year 1976 1977 1978 1979
Lead Content, Grams/Gal
Allowed By EPA 1.4 1.0 0.8 0.5
Total Gasoline Pool 1.24 1.03 0.93 0.76
Premium Gasoline 2.41 2.28 2.38 1.87
Regular Gasoline 1.00 1.00 1.11 1.28
Potential Gasoline. Vol%
No-Lead, Low-Sulfur (92 RON) 20 29 38 47
Premium (99.5 RON) 31 25 19 13
Regular (93.5 RON) 49 46 43 40
No-Lead Gasoline, Vol%
N-Butane 8999
Light Hydrocrackate 13 18 18 17
Reformate 38 73 73 72
FCC Gasoline 28 - - 2
Alkylate 13
Premium Gasoline, Vol%
N-Butane 8799
Alkylate 12 22 22 35
Reformate 41 15 29 16
FCC Gasoline 30 44 33 40
Light Hydrocrackate 9 12 7
Regular Gasoline, Vol%
N-Butane 5543
obutane 1111
< OS Light Gasoline 26 28 30 32
R 'formate 32 24 6
A kylate 5 8 11 10
Catalytic Cracked Gasoline 24 33 47 53
flight Hydrocrackate 6
.IDS Gasoline 1111
142
-------
Table 3-12 (continued). POTENTIAL GASOLINE PRODUCTION IN CASE 2
WITH LEAD PHASE-DOWN
Year
Gasoline Octanes
No-Lead, Research
Motor
Premium, Research
Motor
Regular, Research
Motor
Sulfur, Wt%
No-Lead, Low-Sulfur
Premium
Regular
Comments - See Note
1976
1977
1978
1979
92.3
84.6
99.5
91.5
93.5
86.7
92.4
85.1
99.5
92.2
93.5
86.3
92.4
85.1
99.5
92.5
93.5
86.5
92. 5
85.1
99.5
92.9
93.5
85.8
0.006
0.006
0.006
0.000
0.010
0.008
(2)
0.000
0.007
0.011
(2)
0.000
0.009
0.013
(2)
NOTES:
(1) Gasoline blends are calculated at 10 pounds Reid vapor pressure
using the gasoline components in Case 2.
(2) In 1977, 1978 and 1979, the lead content in the total gasolines
would exceed the EPA limits on lead content. Additional octane
upgrading refining facilities will be required to meet the EPA
limits on lead content.
143
-------
Table 3-13. OVERALL REFINERY MATERIAL BALANCE - CASE 3
INPUT BPCD #/H SULFUR CONTENT. #/H
Crude Oil 100.000 1,292.720 16,377
Purchased N-Butane 1,176 10,010
H2 Plant: Nat. Gas- FOE 929 10,980
Water ___"__ 24,710 __!_
Total 102, 105~ 1.338,420 16,377
OUTPUT
Gas to Fuel-FOE 3,769 46,210 182
H98 to Sulfur Recovery - 7,320 6,892
LPG 2,874 21,360
Gasoline 55,533 592,710 36
Alkylation By-Product Oil 6 80
Jet Fuel &. Kerosine 11.582 140.060 68
Diesel & Distillate Fuel Oil 14,787 182,400 472
No. 6 Fuel Oil 14,629 212.010 5.167
Asphalt 2,200 33.540 1,017
Delayed Coke (5 bbl= 1 Short
Ton) 3.100 51,660 1,723
Catalytic Cracker Coke
Burned - 20,450 820
CO2 From H2 Plant - 30,200
NT From Hydrocracker - 420 - ^
Total 108,480 1,338,420 16,377
Apparent Gain 6,375
144
-------
Table 3-14. GASOLINE POOL - CASE 3
TBPBOIUSGRANf.h °F
VOL FRACTION
BPCD
"API ISP GR )
LB'H
RbID VAPOR PRESSIRL
OCTANE
RESEARCH CLEAR
RESEARCH « 3 cc
MOIOR CLEAR
MOTOR + 3 cc
OLEFINS.VOLK
AROMATICS.VOL9
SULFITR WT»
LB.H
ISOBLTANE
0003
158
(0 5626)
1 290
825
1026
104 2
••76
1030
,
-
_ .
-
VBLTANE
0074
4 109
(0 584)
34970
59 1
938
101 6
903
1004
. _
-
HDS
LIGHT
GASOLINE
C5 200
0127
7040
736
70750
87
687
883
671
870
31
0004
3
RE FORMATE
Cs-EP
0359
19970
480
229 340
35
940
1000
848
907
10
34
-
ALKYLATb
CSEP
0090
5000
716
50746
.1 1
941
105 1
910
1070
--
—
IIDS
CAT
CRACKED
GASOLINE
C5430
0264
14.634
574
159760
6 7
876
940
783
893
77
34
0021
3'
LIGHT
HYDRO-
CRACKATE
Cs-200
0081
4481
765
44.410
120
828
968
825
996
2
—
HDS
GASOLINE
Cs-400
0002
136
610
1450
70
63
84
63
85
—
. _
—
TOTAL
1000
55533
61 b
592710
100
8814
972.1
81 79
9279
24
217
0006
36
-------
The yields and product properties for Case 3 are listed in Table 3-5
together with the information for the West Coast production and
Cases 1 and 2.
In removing sulfur from catalytic cracked gasoline, 87% desulfuri-
zation was selected since this yields about the same sulfur content
in the total gasolines as in Case 2 (0.006 wt% sulfur). At this
desulfurization severity, 55% of the olefins in the catalytic cracked
gasolines would be hydrogenated and lower the octane. In the eco-
nomics, the lower octane shows a penalty of 0.1 cent per gallon
of gasoline for 0.3 octane (Research/2+ Motor/ 2) difference at 1.0
gram lead per gallon.
In Case 3. the incremental investment to produce low-sulfur gaso-
lines is estimated to be 13.5 million dollars (Table 3-15) for a
100,000 bpcd refinery. Economics show that this desulfurization
scheme would add 1.0 cents per gallon to the costs of producing
gasoline (Table 3-16).
SULFUR DISTRIBUTION IN REFINERY PRODUCTS AND EMISSIONS
Sulfur contained in the crude oil to the refinery is distributed in the
products, recovered as elemental sulfur, and emitted as SQ2 to the
atmosphere as shown in Table 3-17.
In Case 1. the sulfur in the crude oil is distributed 37. 8% to re-
sidual fuel oil and asphalt. 38.0% recovered as elemental sulfur
and 8. 5% emitted as SGfc to the atomosphere. By desulfurizing the
catalytic cracker feedstock in Case 2, the recovery of elemental
sulfur can be increased to 52.3% and the emission decreased to
5.1%.
DISCUSSION
This study was based on a refinery model which represents an
average of the refineries in California. However, each refinery
in California may be distinctly different from this refinery model
in both the process units, crude mix charged, operating conditions
and products. Each refinery bases its operations on market de-
mands, availability of crudes, limitations of process units, and
flexibility of operating conditions. If it becomes mandatory to
produce only low-sulfur gasolines, each California refinery should
prepare their own economics as to which process scheme best suits
its refinery or refineries.
It is believed that desulfurization of the catalytic cracker feed will
generally be the most attractive.
146
-------
Table 3-15. INVESTMENT FOR DESULFURIZATION - CASE 3
FACILITY CAPACITY INVESTMENT. *
MILLION DOLLARS
Refinery Size 100,000 BPCD
Light Gasoline Hydrodesulfurizer 7,400 BPSD 3.2
FCC Gasoline Hydrodesulfurizer 15,400 BPSD 4.4
Amine H2S Removal Amine Circulation
19GPM 0.3
Sulfur Recovery (Claus Plant) 3. 5 Short Tons/Day 0.1
Hydrogen Plant 4.0 MM SCF/D 2.4
Onsite 10.4
Offsite (at 30% of Onsite) 3.1
# Investment includes paid-up royalties (if applicable) plus
initial charges of catalysts.
Total Investment 13. 5
147
-------
Table 3-16. COSTS FOR GASOLINE DESULFURIZATION*
Case 2
Refinery Capacity, BPCD 100.000 100.000
Investment for Gasoline Desulfurization.
Million Dollars 18.7 13.5
Years to Payout 5 5
Return, Percent Per Year 20 20
Million Dollars Per Year:
Cash Flow 3.74 2.70
Depreciation 1.05 0.90
Income After Tax 2.69 1.80
Income Tax at 48% 2.48 1.66
Tax Base 5.17 3.46
Operating Costs:
Depreciation 1.05 0.90
Operating Manpower 0.33 0.33
Utilities 3.10 1.45
Catalyst Replacement 0.14 0.04
Interest 0.94 0.68
Maintenance 0.66 0.48
Local Taxes & Insurance 0.28 0.20
Incremental Product Credits -2.28 0.15
Debit for Lower Gasoline
Octane - 0.85
Total Operating Costs 4.22 5.08
Total added Costs for Gasoline Desulfurization:
Million Dollars Per Year (Tax Base + Oper.
Costs) 9.39 8.54
Cents Per Gallon Gasoline 1.10 1.00
In remental costs above Case 1.
148
-------
Table 3-17. SULFUR DISTRIBUTION IN REFINERY PRODUCTS AND EMISSIONS
SULFUR DISTRIBUTION, % *
Case 1 Case 2 Case 3
Gasoline 1.9 0.2 0.2
Jet Fuel & Kerosine 0.4 0.4 0.4
Diesel & Distillate Fuel Oil 2.9 2.9 2.9
No. 6 Fuel Oil 31.6 22.4 31.6
Asphalt 6.2 6.2 6.2
Delayed Coke 10.5 10.5 10.5
Recovered as Elemental Sulfur 38.0 52.3 39.6
Emitted as SO2 to Atmosphere 8. 5 5.1 8.6
Total 100.0 100.0 100.0
As percent of sulfur in crude oil.
149
-------
Table 3-18. REFINERY RUNS - PAD DISTRICT 5 (WEST COAST)
Basis: Bu Mines Statistics for January. 1972 through September. 1973.
INPUT
Crude Oil - Total
U.S.
Foreign
Natural Gas Liquids - Total
LPG
Nat. Gas.
Total Input
OUTPUT
Gasoline (1)
Liquefied Refinery Gas (2)
Jet Fuel and Kerosine (3)
Diesel and Distillate Fuel Oil
Residual Fuel Oil
Lube Oil and Wax
Coke (5 bbls = 1 short ton)
Asphalt and Road Oil
Still Gas to Fuel
Miscellaneous
T. d Output
Processing Gain
MILLION BARRELS
1.222
757
465
35
12
23
1,257
623
30
134
167
213
11
55
40
58
4
1.335
78
VOL% ON
CRUDE INPUT
100.0
61.9
38.1
2.9
1.0
1.9
102.9
51.0
2.5
11.0
13.7
17.4
0.9
4.5
3.3
4.7
0.3
109.3
6.4
NOTES:
( ' Includes motor gasolines, aviation gasolines, petrochemical
f -istocks (aromatics) and special naphthas.
' In ludes ethylene-ethane and liquefied refinery gas for fuel
an i chemical uses.
J) Includes jet fuel (kerosine type) and 50% of naphtha-type
J fuel.
150
-------
Table 3-19. AVERAGE PROPERTIES OF PRODUCT
SALES IN SOUTHERN CALIFORNIA
REGULAR
GASOLINE
BUREAU MINIS SURVEY WINTER
GRAVITY "API
ASTM DISTILLATION »F
IBP
10.
30
50
70
909
EP
SULFUR. WT*
ANILINE POINT, °F
CETANE NUMBER (INDEX)
SMOKE PONT. MIN
VISCOSITY. CS AT IOO°F
VISCOSITY, FUROL AT I22°F
CARBON RESIDUE. WT %
LEAD.g/gil
OCTANE NUMBER
RESEARCH
MOTOR
(RESEARCH + MOTORj/2
REID VAPOR PRESSURE
SALES, %
1972 1973
592
87
113
159
209
269
346
412
00*9
124
938
852
895
II 1
37
PREMIUM
GASOLINE
WINTER
I97M973
584
86
IIS
167
2I9
264
324
403
0042
264
999
916
958
110
63
REGULAR
GASOLINE
SUMMER
1973
585
93
124
166
212
270
342
412
0046
140
933
852
893
89
42
PREMIUM
GASOLINE
SUMMER
1973
582
92
126
173
21V
263
327
409
0034
265
99 1
91 2
952
90
58
AVERAGE
TOTAL JET A
GASOLINE KEROSINE FUEL
1173 I913
585 417 429
339 331
370 369
.
412 415
— —
469 473
516 512
0 046 0 073 0 045
138 143
233
212
972
890
931
100
DIESEL
FUEL
(TRUCKS-
TRACTORS)
1973
353
395
453
—
520
—
600
643
032
149
473(507)
295
NO 2
FURNACE
OIL
1973
345
388
446
519
--
602
647
022
146
(490)
320
NO 6
FUEL
OIL
1973
110
1 50
159
II 2
-------
APPENDIX A
SURVEY OF REFINERIES
IN CALIFORNIA
153
-------
CALIFORNIA
CeettW) "d ' • 'je«
Atlantic Rkdrfield C_.-Canon ....
Beacon Oil Co — Hanford
Champlln Petroleum Co.— Wilmington
Carson Oil Co. (Leased from Golden
Eagle Refining Co.)— Torranc* .
Douglas Oil Co. of California-
Santa Maria
Edgington Oil Co.-iong Beach
Edgington Oxnard Relinery— Oxnard
Exxon Co.— Benitia
Fletcher Oil 4 Refining Co.— Carson
Golden Bear Division, Witco Chemical
Cor?.— Oildale
Gulf Oil Co —Santa Fe Sprints
(Cam County Refinery Inc.—
BakersfieM
Unday-THtiard Oil Co.— South Bate
Macmillan Ring-free Oil Co. Inc.—
Signal Hill
Mchawk Petroleum Corp. Inc. —
Bakersfield
Newhall Refining Co. Inc.— Newhall
Phillips Petroleum Co.— Avon
Powerint Oil Co.— Santa Fe Sprints
San Joaquin Retiring Co.— Oildale ,
Sequoia Refining Corp.— Hercules . .
Standard Oil Co. of California—
Richmond
Sunland Refining Corp.— Bakersfield
Texaco Inc.— Wilmington!
Toscopetro Corp. — Bakersfield
Union Oil Co. of California!—
1 M lno«I#t
Wart Co«t Oil Co.— Oildili
Total** .
f
, — Crete capacity — .
a/c< i/sd
165,000
12.000
28.750
6,900
35.000
8.200
15.000
NR
86.000
15.200
9.350
49.800
12.000
5.000
10.000
123.500
17.000
MR
110.000
28.500
17.000
27,000
100,000
86.000
NR
NR
NR
8.500
UOO
77.000
26,500
104,000
95,000
12,700
1.714.900
173,000
12.100
30.000
7.000
36.000
8.500
16.000
2.500
95.000
16.000
9.500
52.000
13.500
5JOO
10.000
130.000
17.500
6.500
NR
30,000
18,000
28,300
103,000
88.000
26,000
220,000
190,000
NR
NR
NR
27,000
107,000
99,000
13,000
1796.700
V«c . H
93,000
18.600
21.000
7.500
47.000
9.500
21.900
5.000
3.000
95,000
3.000
74.500
14.000
7,000
5,900
56.600
60,000
103.000
150,000
17.000
83,000
38,500
•2,000
936000
Ciatietapai
lenul eav ^— Cat cncUif — .
•23,000
•37,000
•25,500
'500
>2,750
•9,650
>23.000
'13.800
'16.000
M6.640
"42,000
•30.000
•9,000
•50.000
•48.000
>6.000
•20,000
M2.500
456.640
'57,000
'46.000
'13.500
'56,000
"47.000
'10.000
'46,000
'35,000
(40,000
•40,000
'28.000
'10.000
M5.000
476,600
8.000
9,300
300
None
NR
1.000
40.000
5,000
15,000
15.000
NR
2.000
7.000
126.000
^Cat* Cathy*.- Catty**- Cattodra-
raftmUev cnetl* rtfiaiai treatiaj
'32.000
'1.650
*MOO
•24.000
•4,000
'19.000
0,000
'17.500
'18,500
"2,500
'32.500
'6,300
'15.800
>25,000
*21,000
'5.000
'15,000
"47,000
•69,000
'1.000
'35.000
'12.500
•29.000
•26.000
472.650
'17.000
'24.000
•1,000
'11,000
'18,000
'22.000
•2.200
'2,900
'18.000
'45,000
'68.000
'20.000
. '12.000
'21.000
'30.000
314.300
'18,000 '32,000
'18.000
»7.000 '6,400
•22.500 "21,000
•18,500
'4.000
'12.000
'3 $00
'23000
'15.000
•23,000
'2500
•34.500
"8,000 '7.000
'S.OOO*
'15.400
•50,000 '16,000
•6,100
•15,000
til, 000
HI.OOO
>30.000
•33.000
11,000
'5.000
'40.000
•12,000
'18,,000f
'44.000
•3,200
'33.000
ic (Vyi
'37,000
•33,000
'21,000
•9.000
14,000
105.500 651,800
Alkyla- Aromatla-
ttM ttwMrlztt*M Uki*
'7.200 '2.490
•13.000
'12.000 .'.'".'. '..'.'...
4,000
•3,000 ...
'10,500
'10.500 «2,700 1.670
•2^00
'6,600 4,500
'8,600 '3,800
'5,400 '1,500
'8,500 '1,500 10,000
•2,000
'4.400 '1.200
11 (UYl
'1.000
3,600
89400 28^90 23.770
Asphalt
14,000
5.800
5,000
3.200
4,000
1,200
1,600
5,000
3,360
10,400
1.100
8,300
11,000
10,000
6,150
2,000
92,110
Coke
(I/O
1.650
575
900
2.800
'i.206
1,800
2,200
1,650
180
1,850
14.955
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LEGEND
Processes in table are
Identified by numbers
Cat Hydrorefining
1. Residual desulfurizing
2. Heavy gas-oil desulfurizing
3. Residual visbreaking
4. Cat cracker and cycle stock
feed pretreatment
5. Middle distillate
6. Other
Cat Hydrotreating
1. Pretreating cat-reformer feeds
2. Naphtha desulfurizing
3. Naphtha olefin or aromatics
saturation
4. Straight-run distillate
5. Lube oil "polishing"
6. Other distillates
7. Other
Aromatics/Isomerization
1. BTX
2. Hydrodealkylation
3. Cyclohexane
4. C4 feed
5. C5 feed
6. C5 and C( feed
Cat Reforming
Semiregenerative:
1. Conventional catalyst
2. Bimetallic catalyst
Cyclic:
3. Conventional catalyst
4. Bimetallic catalyst
Other:
5. Conventional
6. Bimetallic
Cat Hydrocracking
1. Distillate upgrading
2. Residual upgrading
3. Lube-oil manufacturing
4. Other
Thermal Process
1. Gas-oil cracking
2. Visbreaking
3. Fluid coking
4. Delayed coking
5. Other
Alkylation
1. Sulfuric acid
2. Hydrofluoric acid
Cat Cracking
1. Fluid
2. Thermofor
3. Houdriflow
NR—Not reported
•Diesel and jet. fGasoline. iTurbine fuel. SJet Wll figures are calendar day. Stream-day figures not reported. ITurbine aromatics saturation. "State totals include figures concerted to itreanvdw or
calendar-day basis. Cat cracking recycle total includes figures not reported (with recycle estimated at 30% of fresh feed). * w * «"•*•* *
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APPENDIX B
SOURCES OF INFORMATION
American Petroleum Institute
"Annual Statistical Review. U. S. Petroleum Industry Statistics,
1956-1972". (April, 1973).
U. S. Bureau of Mines, Mineral Industry Surveys
"Crude Petroleum. Petroleum Products, and Natural-Gas-Liquids:"
January - December. 1973 and Final Summary, 1972
Motor Gasolines. Winter 1972-1973 and Summer 1973
Aviation Turbine Fuels, 1973
Diesel Fuel Oils. 1973
Bunker Fuel Oils. 1973
Ethyl Corporation
"Yearly Report of Gasoline Sales by States - 1972"
Oil and Gas Journal (Petroleum Publishing Company)
"1973-74 Worldwide Refining and Gas Processing Directory"
"Forecast Review - Here's Where the Big Reserves Are In U. S."
January 28. 1974
"Where District 5 Now Gets Crude, Products"
March 18. 1974
157
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TECHNICAL REPORT DATA
(Pleat reed laXntction* on the reverse before completing}
1 REPORT NO
EPA-650/2-74-130
2.
3. RECIPIENT'S ACCESSION-NO.
TITLE AND SUBTITLE
PRODUCTION OF LOW-SULFUR GASOLINE
6 REPORT DATE
July 1974
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
W. F. HOOt
B. PERFORMING ORGANIZATION REPORT NO.
9 PERFORMING ORGANISATION NAME AND ADDRESS
M. W. Kelfogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
10. PROGRAM ELEMENT NO.
1AB013
11. CONTRACT/GRANT NO.
68-02-1303
12 SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
National Environmental Research Center
Research Triangle Park, N.C. 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final Contract 11/72 - 6/74
14. SPONSORING AGENCY CODE
15 SUPPLEMENTARY NOTES
Project Officer - John B. Moran
16 ABSTRACT
Catalytic converters are to be installed in the exhaust systems of new cars starting
with the 1975 model year. The use of catalytic converters is intended to control
carbon monoxide and hydrocarbon emissions. However, the catalysts convert some of
the sulfur in gasoline into sulfuric acid mist in the exhaust. The purpose of this
study was to determine the impact on oil refineries to produce unleaded, low-sulfur
gasolines and also to desulfurize all gasolines produced for United States sales.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS C. COS AT I Field/Group
catalytic converters
desulfurization
oil refineries
no-lead gasoline
nonleaded gasoline
unleaded gasoline
catalysts
gasoline
sulfur
catalysts
refineries
8 DISTRIBUTION STATEMENT
release unlimited - copies available from
NTIS
19. SECURITY CLASS ITHI3 Report)
unclassified
21. NO. OF PAGES
±. 150
20. SECURITY CLASS (Thispage)
unclassified
22. PRICE
EPA Form 2220-1 (9-73)
158
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