EPA-600/2-75-042
September 1975
Environmental Protection Technology Series
CONTROL OF
HYDROCARBON EMISSIONS FROM
PETROLEUM LIQUIDS
industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, N.C, 27711
-------
EPA-600/2-75-042
CONTROL OF
HYDROCARBON EMISSIONS
FROM PETROLEUM LIQUIDS
by
C.E.Burklin, E.C.Cavanaugh, J. C. Dicker man,
S. R. Fernandas, and G. C. Wilkins
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
Contract No. 68-02-1319, Task 12
ROAPNo. 21BJV-034
Program Element No. 1NB458
EPA Project Officer: L.Lorenzi, Jr.
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
September 1975
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Develop"me|it,
U.S. Environmental Protection Agency, have been grouped "Sin^to
five series. These five broad categories were establishedjlto
facilitate further development and application of environmental
technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in
related fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY STUDIES 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 U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency, nor
does mention of trade names or commercial products constitute endorse-
ment or recommendation for use.
This document is available to the public through the National
Technical Information Service, Springfield, Virginia 22161.
11
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ABSTRACT
The petroleum industry has been identified as a large
source of hydrocarbon emissions by virtue of the large volumes of
volatile hydrocarbons involved in the myriad of operations com-
prising the industry. This report is a state-of-the-art review
on the availability and application of technology for the control
of hydrocarbon emissions to the atmosphere from facilities for
the production, refining, and marketing of liquid petroleum
fuels. The scope of this study includes (1) the identification
i«
of major hydrocarbon emission sources within the petroleum
industry and the quantity of their emissions, (2) a review of
existing hydrocarbon emission control technology and the current
extent of its application by the petroleum industry, and (3) the
identification of hydrocarbon emission sources within the petro-
leum industry for which control techniques are either not avail-
able or else not widely applied.
This final report is submitted in fulfillment of Task
12 of contract 68-02-1319 under the sponsorship of the Office
of Research and Development, Environmental Protection Agency.
111
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TABLE OF CONTENTS
Page
1.0 SUMMARY 1
1.1 Project Objective, 1
1.2 Methodology 1
1.3 Results. . . . .' 2
1.4 Conclusions 5
1.5 Recommendations 6
(,
2.0 THE INDUSTRY 8
3.0 CRUDE OIL PRODUCTION 14
3.1 Domestic Oil Fields 14
3.1.1 Operations 14
3.1.2 Products 16
3.1.3 Storage and Handling 18
3.1.4 Emissions 20
3.2 Domestic Offshore 23
3.2.1 Operations 23
3.2.2 Products 24
3.2.3 Storage and Transport to Mainland 24
3.2.4 Emissions 26
3.3 Emission Controls 26
4.0 CRUDE OIL TRANSPORT 28
4.1 Domestic Oil Fields and Refineries 28
4.1.1 Pipelines. . 28
4.1.2 Domestic Tanker Transport 29
4.1.3 Other Transport Methods 30
4.2 Imported Crude 32
4.3 Intermediate Storage, Processing, and
Handling 34
4.4 Emissions 34
IV
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TABLE OF CONTENTS (Cont.)
Page
4.5 Emission Controls 40
5.0 PETROLEUM REFINERIES 41
5.1 The Industry 41
5.1.1 Statistics 41
!
5.1.2 Refining Processes 44
5.1.3 Refinery Products 54
5.1.4 Auxiliary Processes 56
5.2 Hydrocarbon Emission Sources 61
5.2.1 Combustion Sources 62
5.2.2 Storage and Loading Sources 65
5.2.3 Process Sources 75
5.2.4 Fugitive Sources 86
5.3 Hydrocarbon Emission Controls 92
5.3.1 Combustion Source Controls 92
5.3.2 Storage and Loading Controls 93
5.3.3 Process Source Controls 98
5.3.4 Fugitive Source Controls 103
6.0 GASOLINE MARKETING 106
6.1 The Industry 106
6.1.1 Quantity of Products 106
6.1.2 Nature of Products 110
6.2 The Gasoline Marketing Network 115
6.2.1 Bulk Terminals 119
6,2.2 Bulk Stations. '. 121
\
6.2.3 Service Stations 123
6.3 Industry Trends 126
6.3.1 U.S. Gasoline Consumption 126
6.3.2 Gasoline Marketing Facilities 132
v
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TABLE OF CONTENTS (Cont.)
Page
6.4 Emissions 138
6.4.1 Quantity of Hydrocarbon Emissions 138
6.4.1.1 Bulk Terminals 140
6.4.1.2 Bulk Stations 147
6.4.1.3 Service Stations 148
6.4.1.4 Aviation Gasoline Hydrocarbon Emissions 151
6.4.2 Adverse Effects of Hydrocarbon Emissions 153
6.4.2.1 Effects on Human Health 153
6.4.2.2 Effects on Vegetation 155
6.4.2.3 Materials Damage 156
6.4.2.4 Other Effects 156
6.4.3 Seasonal Characteristics of Emissions 156
6.5 Emission Control Technology 159
6.5.1 Bulk Terminals 159
6.5.1.1 Storage Tank Controls. 159
6.5.1.2 Loading Rack Vapor Controls 160
6.5.1.3 Vapor Recovery Units 165
6.5.2 Service Stations 169
6.5.2.1 Stage I Control Technology 170
6.5.2.2 Stage II Control Technology 171
6.5.3 Bulk Stations 182
6.5.3.1 Vapor Balance 182
6.5.3.2 Vapor Recovery Systems 183
6.5.3.3 Operating Reliability 185
7.0 JET FUEL MARKETING 186
7.1 The Industry 186
7.1.1 Jet Fuel Description 186
7.1.2 Uses 187
7.2 Product Distribution and Storage 187
7.2.1 Transport 187
7.2.2 Storage 187
VI
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TABLE OF CONTENTS (Cont.)
Page
7.3 Emissions and Controls 189
8.0 DISTILLATE AND DIESEL FUEL MARKETING 192
8.1 The Industry 192
8.1.1 Distillate Fuel Oils 192
8.1.3 Use 193
8.2 Product Distribution and Storage 195
8.2.1 Distribution 195
8.2.2 Storage . . 195
8.3 Emissions 195
9.0 RESIDUAL FUELS 198
9.1 The Industry 198
9.1.1 Product Description 198
9.1.2 Uses 199
9.1.3 Domestic Production ..... 201
9.2 Distribution 201
9.2.1 Storage 201
9.2.2 Transportation 202
9.3 Emissions 202
10.0 NATURAL GAS LIQUIDS 203
10.1 The Industry 203
10.2 Gas Plants 204
10.3 Product Distribution and Storage 209
10.4 Emissions 209
10.5 Emission Controls 210
11.0 LIQUEFIED PETROLEUM GASES 211
11.1 Sources and Quantities 211
11.2 Recovery of LPG from Refineries . 211
vii
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TABLE OF CONTENTS (Cont.)
Page
11.3 Distribution, Storage and Handling 213
11.4 Emissions 214
11.5 Emission Controls 214
12.0 PETROCHEMICAL FEEDSTOCKS 215
12.1 Methane 215
12.2 Ethane-Ethylene 216
12.3 Propane-Propylene 217
12.4 Butane-Butylenes 217
12.5 Aromatics 218
12.6 Emissions 218
13.0 STATUS OF CONTROL TECHNOLOGY 219
13.1 Existing Control Technology . 219
13.2 Current Application of Control Technology . . . 220
13.3 Gaps in Control Technology 225
REFERENCES 226
UNIT CONVERSIONS 230
Vlll
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LIST OF TABLES
Page
TABLE 1.3-1 Summary of Controlled and Uncontrolled
Hydrocarbon Emissions From The Petroleum
Industry 3
TABLE 2,0-1 Petroleum Industry Supply and Disposition
of Products - 1973 9
TABLE 2.0-2 Petroleum Products - 1973 : . . . 10
TABLE 3.1-1 Estimated Hydrocarbon Emissions From Crude
Oil Production, Monterey County - 1967. ... 22
TABLE 4.1-1 Tanker and Barge .Movements of Crude Oil ... 31
TABLE 4.2-1 Crude Oil Imports 32
TABLE 4.4-1 Splash-Loading-Loss Tests for Tank Cars
(Crude Oil) 38
TABLE 4.4-2 Subsurface-Loading-Loss Tests for Tank Cars
(Crude Oil) 39
TABLE 5.1-1 Refinery Size Distribution - 1971 42
TABLE 5.1-2 Distribution of Refinery Locations (1974) . . 43
TABLE 5.1-3 Petroleum Product Rate - 1973 55
TABLE 5.2-1 Heat Demand of Some Typical Refining Units. . 63
TABLE 5.2-2 Hydrocarbon Emissions from Refinery Boilers
and Heaters 64
TABLE 5.2-3 Nature of Product Storage at Refineries ... 71
TABLE 5.2-4 Hydrocarbon Emission Factors for Petroleum
Storage 73
TABLE 5.2-5 Hydrocarbon Emissions from Petroleum Product
Loading 77
TABLE 5.2-6 Modes of Product Transportation from
Refineries (1973) 78
TABLE 5.2-7 Effectiveness of Mechanical and Packed Pump
Seals on Various Types of Hydrocarbons.... 89
TABLE 6.1-1 Gasoline Refining and Marketing Facilities. . 107
TABLE 6.1-2 Motor Gasoline Survey, Summer 1973 Average
Data for Brands in Each District 112
IX
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LIST OF TABLES (Cont.)
TABLE 6.1-3 Motor Gasoline Survey, Winter 1971-72
Average Data for Brands in Each District. . 113
TABLE 6.2-1 U.S. Bulk Storage Capacity by Tank Size . . 120
TABLE 6.3-1 Gasoline Consumption By State 129
TABLE 6.3-2 Average Fuel Consumption 1969-1973 133
TABLE 6.3-3 Number of Gasoline Service Stations and
Sales Volume 137
TABLE 6.4-1 Predicted Hydrocarbon Emissions from U.S.
Bulk Terminal Sources 145
TABLE 6.4-2 Case Comparison of Predicted Hydrocarbon
Emissions from U.S. Bulk Terminals 146
TABLE 6.4-3 Predicted Hydrocarbon Emissions from U.S.
Bulk Stations 149
TABLE 6.4-4 Predicted Hydrocarbon Emissions from U.S.
Service Stations 152
TABLE 6.4-5 Predicted Hydrocarbon Emissions from
Aviation Gasoline 154
TABLE 7.1-1 Jet Fuel Consumption (1973) 188
TABLE 7.2-1 Hydrocarbon Emission Factors for Jet Fuels
Marketing 190
TABLE 8.1-1 Properties of Distillate Fuels 192
TABLE 8.1-2 U.S. Distillate Fuel Oil Domestic Demand
By Uses 194
TABLE 8.3-1 Hydrocarbon Emission Factors for Distillate
Fuels 196
TABLE 9.1-1 U.S. Residual Fuel Oil Domestic Demand By
Uses 200
TABLE 13.1-1 Summary of Controlled and Uncontrolled
Hydrocarbon Emissions from the Petroleum
Industry 221
x
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LIST OF FIGURES
Page
FIGURE 2.0-1 Production, Transport, and Use of Crude
Oil and Petroleum Products-1973 11
FIGURE 3.1-1 Production of Natural Gas and Natural Gas
Products 19
FIGURE 4.2-1 Marine Tanker 33
FIGURE 4.3-1 Transportation of Crude Oil, 1973 35
FIGURE 5.1-1 Typical Fully Integrated Gasoline Refinery . 45
FIGURE 5.2-1 Standard Fixed Roof Tank 67
FIGURE 5.2-2 Floating Roof Tank - (double deck type). . . 67
FIGURE 5.2-3 Internal Floating Cover Tank 68
FIGURE 5.2-4 Lifter Roof Tank 68
FIGURE 5.2-5 Flexible Diaphragm Tank 69
FIGURE 5.2-6 Loading Losses from Marine Vessels, Tank Cars
and Tank Trucks 76
FIGURE 5.2-7 Typical Moving-Bed Catalytic Cracking Unit . 79
FIGURE 5.2-8 Typical Fluidized Bed Catalytic Cracking
Unit 79
FIGURE 5.2-9 Typical Steam Ejector - Barometric
Condenser 81
FIGURE 5.2-10 Flow Diagram of Asphalt Blowing Process. . . 83
FIGURE 5.2-11 Modern Oil-Water Separator 85
FIGURE 5.2-12 Packed Seal 87
FIGURE 5.2-13 Mechanical Seal 87
FIGURE 5.2-14 Pressure Relief Valve 90
FIGURE 5.3-1 Integrated Vapor Gathering System 94
FIGURE 5.3-2 Top Loading Arm Equipped With A Vapor
Recovery Nozzle 96
FIGURE 5.3-3 Bottom Loading Vapor Recovery 97
FIGURE 6.1-1 Vapor Pressures of Gasolines Ill
FIGURE 6.1-2 Map Showing Locations and Numbers of Samples
for the National Motor Gasoline Survey,
Summer 1973 114
XI
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LIST OF FIGURES (Cont.)
FIGURE 6.1-3 Motor Gasoline Volatility Trends 116
FIGURE 6.2-1 The Gasoline Marketing Distribution System
in the United States 117
FIGURE 6.2-2 Vapor and Liquid Flow in a Typical Bulk
Terminal 122
FIGURE 6.2-3 Vapor and Liquid Flow in a Typical Bulk
Plant 124
FIGURE 6.2-4 Vapor and Liquid Flow in a Typical Service
Station 127
FIGURE 6.3-1 U.S. Gasoline Consumption 128
FIGURE 6.3-2 Marketing Trends at Gasoline Service
Stations 135
FIGURE 6.4-1 Gasoline Flow Through the Marketing Network . 141
FIGURE 6.4-2 Hourly Oxidant Measurements, Azusa, Los
Angeles, and San Diego, California - 1972 . . 157
FIGURE 6.4-3 Hourly Oxidant Measurements, Bakersfield
and Stockton, California, and Denver,
Colorado - 1972 158
FIGURE 6.5-1 Top Loading Arm Equipped With A Vapor
Recovery Nozzle 161
FIGURE 6.5-2 Detail of a Vapor Recovery Nozzle 162
FIGURE 6.5-3 Bottom Loading Vapor Recovery 164
FIGURE 6.5-4 Schematic of a Terminal Vapor Recovery Unit . 167
FIGURE 6.5-5 Stage I Vapor Recovery Equipment 172
FIGURE 6.5-6 Diagram of a Vapor Balance System 176
FIGURE 6.5-7 Low Pressure Tank Emissions Vs Tank
Operating Pressure Range 184
FIGURE 10.2-1 Absorption Plant With LPG - Natural Gasoline
Splitter 206
FIGURE 10.2-2 Refrigerated Absorption Process Using
Chilled Glycol as Absorbent 207
XII
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LIST OF FIGURES (Cont,)
Page
FIGURE 10.2-3 Adsorption Process 208
FIGURE 11.1-1 Disposition of LPG for 1973 212
Xlll
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1.0 SUMMARY
1.1 Project Objective
The petroleum industry has been identified as a
large source of hydrocarbon emissions by virtue of the large'
volumes of gases and volatile petroleum liquids involved in
the many processing and handling steps comprising the industry.
The Environmental Protection Agency has contracted
with Radian Corporation to develop a state-of-the-art review
on availability and application of technology for the control
of hydrocarbon emissions from facilities for production, re-
fining, and marketing of liquid petroleum fuels.
1.2 Methodology
Radian Corporation developed a three phase study for
achieving these objectives. In the first phase, Radian reviewed
the various operations in the petroleum industry and identified
the major sources of hydrocarbon emissions. Emission quantities
were also defined where possible.
The second phase involved identifying existing control
technology applicable to these emission sources and the degree
of emission control obtainable. The extent of application of
the existing control technology was included.
The third phase involved identification of hydrocarbon
emission sources within the petroleum industry for which control
techniques are either not available or else not widely applied.
-------
For convenience, Radian divided the petroleum industry
into ten operating areas including all phases of oil and gas
production, petroleum refining, and petroleum products marketing.
For each area the processes involved in that area were identi-
fied. Other information included were the nature of the products,
feed and product throughput rates, and growth trends within the
industry. Major hydrocarbon emission sources within each area
were determined and related to specific processes. Typical emis-
sion rates were quantified where available. Finally, for each
area the control technology applicable to the hydrocarbon emis-
sion sources within that area was identified. Control efficien-
cies, and information on the current extent of technology ap-
plication were obtained where such information was available
for the various control techniques.
1.3 Results
The results of the information obtained in this study
are summarized in Table 1.3-1. The major hydrocarbon emission
sources identified for each area of the petroleum industry are
given on the table. Also shown are average emission factors for
the uncontrolled emission sources, for average .emission sources
based on current degrees of control, and for emission sources
fully applying the latest control technology. For maximum
estimating accuracy, emission sources were broken down into
the smallest divisions for which data were available.
The efficiency of control techniques and the current
extent of their application can be obtained by comparing this
set of emission factors. The right-hand column of Table 1.3-1
lists comments on control technology applicable to each emission
source. For a comparison of the relative impacts of each hydro-
carbon emission source, the industry throughput and production
-2-
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TABLE 1.3-1
SUMMARY OF CONTROLLED AND UNCONTROLLED HYDROCARBON EMISSIONS FHOM THE PETKOt.EUM INDUSTRY
ll.itural Gas Production
ami Processing
vented nat. gas
fugitive nat. |>as leaks
1
Crude Oil Production
ttlorajje
waslewatcr .separator
pump seals
compressor seals
relief valves
pipeline valves
Crude Transportation
storage
rail & truck loading
imirlnu loading
Refinery Operations
boilers & heaters
compressor engines
storage
loading operations
FCC unit
TCC unit
vacuum jets
blowdown
ajpluilc blowing
process drains & waste-
wattr separators
purap seals
compressor seals
pressure relief valves-
cool tn|> tower
pipeline valves & flanges
blind changing
sampling
oilier
I'tMildii'-il Fuc-lu
Natural Gas Liquids
Liquefied Petroleum
T.ases
1973
Throughput
Rate
65.9xlO*SCF/day
6S.9xlO*SCF/day
9.2xlO'hpd
9.2xlO'bpd
9.2xlO*bpd
9.2xlO'bpd
9.2xlO'bpd
9.2xlO'bpd
_
12.4xlO*hpd
0.2xlOM>pd
l.lxlO'bpd
12.4xlO«bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
4.03xlOlbpd
0.38xlO'hpd
12.AxlOlbpd
12./ixlO'bpd
0.65xlO'bpd
12.4xlO'bpd
I2.4xl0'bpd
12./,xl04bpd
12.4xl04bpd
12./.xlO'bpd
12.4xlO'bpd
12.AxlO'bpd
12.AxlO'bpd
la.AxlO'-bpd
2.8 xlO'bpd
l.73xlO'bpd
l.AlxlO«bpd
Emission Factors
Uncontrolled
HA,
NA
MA
NA
NA
MA
NA
NA
660 lbs/10'bbl
540 lbs/10'bbl
11D
UD
1200 lbs/10'bbl
32 lbs/10'bbl..
220 lba/10M.bl'1
87 lbs/10'bl>Tfi
57 lbs/10'bbl
325 lbs/10'l.bl
60 Ibs/ton
asphalt
200 lbs/10'bbl
UD
UD
11 lbs/10'bbl
UD
UD
UD
UD
UD
ncg
NA
NA
Current
Controls
20 lbs/10*SCI-
190 lhs/10'SCI
/. lba/10'l.b
8 lbs/10M>bl
74 Ibs/lOMib
4 lbs/ll)'bb)
8 lbtt/10'bb
12 lbs/10'bbl
256 Ibs/IO'bbl
198 lbs/10'hbl
96 lbu/10'bbl
10 lbs/10«bbl
16 lbo/in>|,bl
'<70 lbs/10'bbl
32 lbs/10»bbl
NA
NA
=•57 lbo/10'bbl
160 lbs/10'bbl
NA
105 lbs/10'bbl
17 lba/10'bbl
S lbs/IO*hbl
11 lbs/10'bbl
UD
28 lbs/10'bb]
0.3 lbs/10'bbl
2.3 lbs/10'bbl
7 lbs/10'bbl
NA
HA
Completely
Controlled
IIA
NA
NA
NA
HA
NA
NA
NA
136 lbs/10'bbl
90 lbu/10'bbl
96 lbs/10'bbl
III)
UD
250 lhs/10'bbl
5 lba/10'bbl
"<-'i;
ncg
neg
5 lbs/10'bbl
neg
10 lbu/10'bbl
III)
III)
ueg
01
10 lba/10'bbl
UD
UD
UD
UD
ncg
NA
HA
Estimated
1973
Emissions
(tons/day)
659
6261
6920 total
17
36
339
17
36
53
598 total
1587
20
53
loCQ total
62
99
29 U
198
111
4
353
992
neg
651
105
31
68
62
174
2
14
43
5BB3~ cotul
Comment on
Control Device Applied
vapor recovery
housekeeping, maintenance
floating roofa
cover
mechanical seals
mechanical seals
rupture discs, vapor
recovery
maintenance
floating roofs
bottom loading
bottom loading already in
use
housekeeping
floating roofs
vapor recovery
CO boiler
CO holler
surface condenser, mechait-
icnl pump
vapor recovery
incineration, scrubbing
cover
mechanical seals
mechanical seals
rupture discs, vapor
recovery
hauHi-kccp 1 Hi-
housekeeping . maintenance
housekeeping, purging
housekeeping
housekeeping, maintenance
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TABLE 1.3-1 - SUMMARY OF CONTROLLED AND UNCONTROLLED HYDROCARBON EMISSIONS FROM THE PETROLEUM INDUSTRY (Cont.)
Page 2
I
-P-
I
Gasoline Marketing
bulk terminal
storage
loading
bulk station
storage
loading
service station
filling underground tk.
filling automobile
storage
aviation gasoline
a tor age
loading
Jet Fuel Marketing
Jet Naphtha
storage-breathing
storage- fill ing
rail/truck loading
marine loading
Jet Kerosene
storage- breathing
storage- filling
rail/truck loading
marine loading
Diesel & Distillates
storage-breathing
storage-filling
truck/rail loading
marine loading
1973
Throughput
Rate
6.7xlO'bpd
6.7xlO'bpd
l.lxlO'bpd
l.lxlO'bpd
6.1xlO'bpd
6.1xlO'bpd
6.1xlO'bpd
45xlO'bpd
45xlO'bpd
=6.7xl06bbl
217xl01bpd
149xlO'bpd
27xlO'bpd
12.4xiO'bbl
833xlO'bpd
90xlOsbpd
lOOxlO'bpd
=218xlO'bbl
3.08xlO'bpd
.79xlO'bpd
. 30x10* bpd
Emission Factors
'Uncontrolled
600 lbs/10'bbl
520 lbs/10'bbl
600 lbs/10'bbl
520 lbs/10'bbl
11.5 lba/10'gal
11.0 lbs/10'gnl
1.0 lba/10'gal
600 lbs/10'bbl
520 lbs/10'bbl
0.074 Ibs/d-lO^
gal
2.4 lbs/10'gal
1.8 lbs/10'gal
NA
K
0.038 lbs/d-10**
gal
1.0 lbs/10'gal
0.88 lbs/10'gal
NA
0.038 lbs/d-10^
gal
1.0 lbs/10'gal
0.93 lbs/10?gal
NA
Current
Controls
HA
HA
=600 lbs/10'
bhl
=520 lbs/10'
bbl
• 9.4 lbs/10'
gal
11. 0 lba/10'
gal
«1.0 lbs/10'
gal
600 Ibu/lO'bbl
520 Ibe/lO'bbl
NA
NA
NA
0.60 lbs/103
gal
©
=0.038 Ibs/d-
10JRal
=1.0 lbs/10'
gal
=0.88 lbs/10'
gal
0.27 lbs/10J
gal
=0.038 lbs/d-G
10'gal
1.0 lbs/10\al
0.93 lbs/10Y
gal
0.29 lbs/10*
gal
Completely
Controlled
30 lbs/10'bbl
17 lbs/10'bbl
30 lbo/10'bb]
17 lbs/10'bbl
0.37 lbs/10»
gal
1.10 lbs/10'
gal
neg
30 lba/10'bbl
17 lba/10'bbl
0.02 Ibs/d-lO*
gal
neg
0.91 lbs/10'
gal
0.60 lbs/10'
gal
s>
0.009 Ibs/d-
10'gal
neg
0.45 lbs/105
gal
0.27 lbs/10'
gal
0.009 lbs/d-®
10'gal
neg
0.48 Ib3/10$
gal
0.29 lbs/101
gal
Estimated
1973
Emissions
(tons/day)
101
57
330
286
1204
1409
128
-
14
12
3541 total
10
11
6
0
10
17
2
1
~5T total
174
65
15
2
255 total
Comment on
Control Device Applied
floating roofs
bottom loading, vapor
recovery
floating roofs
bottom loading, vapor
recovery
submerged fill, vapor
balance
vapor recovery, vapor
balance
vapor recovery
submerged fill, vapor
balance
vapor recovery
floating roofs
floating roofs
bottom loading
bottom loading already In
use
floating roofs
floating roofs
bottom loading
bottom loading already In
use
floating roofs
floating roofs
bottom loading
bottom loading already
in use
® units in lb/10'bbl of cat cracker capacity
® units in lb/10'bbl of storage capacity
® Emission factors for existing cooling towers were too variant to average. However emissions from recently constructed
cooling towers are down to 10 lb/10'bbl
NA - data not available
UD - emissions from this source were undefinable
neg- emissions are negligible
-------
rates for 1973, with the estimated emission rates for that year,
are also included. In addition, these throughput and production
rates can be combined with the controlled emission factors to
gage overall impacts of various control technologies.
1.4 Conclusions
The data indicate that there are three areas of the
petroleum industry which generate large volumes of hydrocarbon
emissions. Estimated emissions for the natural gas production
and processing industry based on 1973 production rates were 6900
tons of hydrocarbons per day. Refinery operations contributed
an estimated 5900 tons of hydrocarbons per day. Gasoline mar-
keting operations contributed an estimated 3800 tons of hydro-
carbons per day. For perspective, 1970 national hydrocarbon
emissions totaled 90,000 tons per day and the total industrial
contribution was 26,000 tons per day. It should be noted that
while emissions from natural gas production and processing are
quite large, they consist largely of methane, a photochemically
non-reactive hydrocarbon.
The results indicate that emission control technology
is generally well developed for every major hydrocarbon emission'
source in the petroleum industry.
The data presented in Table 1.3-1 also indicate that
in nearly all areas of the petroleum industry, existing control
technology has not been fully applied. The greatest progress
towards full application of control technology has been made in
those areas exhibiting economic incentives for control or in areas
governed by emission regulations. Typical examples are volatile
product storage where the petroleum industry is installing
floating roofs for product conservation reasons, and gasoline
marketing emission controls which have been applied in part because
of emission regulations.
-5-
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1.5 Recommendat ions
Although this study did not uncover any specific areas
of the petroleum industry that demand development of new control
technology, it did point out two areas where further development
may be required. These areas are floating roof tanks and the
service station portion of gasoline marketing.
The emission factors for completely controlled storage
tanks indicate that the hydrocarbon emissions from storage tanks
equipped with floating roofs will still be sizeable. For some
locations with specific hydrocarbon problems, it may be necessary
to improve floating roof seals or to develop other forms of
emission control.
Although the technology for controlling hydrocarbon
emissions from automobile refueling is well developed there
remain several problems. Nozzle manufacturers have had dif-
ficulties designing a dispensing nozzle which consistently
effects a good seal at the nozzle-fillneck interface. Problems
have also arisen with the dependability and control efficiency
of service station vapor recovery units.
In addition this study has pointed out some areas
where very little is known about specific emission sources, their
emission levels, and the efficiency of applicable control tech-
nology. By virtue of the significant quantities of emissions
from the following such areas in the petroleum industry, further
emissions investigation and testing appear needed in these areas:
Oil and gas production - including wells,
gathering stations, brine disposal, and gas
plants.
-o-
-------
Transport of crude liquids to refineries -
including storage,loading, unloading,and
intransport emissions from crude oil, lease
condensate, and natural gas liquids.
Much of the available data on refinery emissions and
the efficiency of their control is based on refinery studies
conducted in the late 1950fs and early 1960's. There exists the
need to verify the applicability of these studies to current
refinery emission sources and present day control techniques.
The impact of hydrocarbon emissions on health, air
quality, and the environment vary greatly among hydrocarbon
species. Many of the hydrocarbons emitted by the petroleum
industry are low molecular weight, straight chain paraffins which
are believed to be relatively non-reactive and non-hazardous.
More information on the nature and impact of hydrocarbon emissions
from petroleum industry sources is needed with respect to
hazardous and photochemically reactive compounds; certainly
where such data are needed for support of hydrocarbon emissions
policies.
-------
2.0 THE INDUSTRY
Definition
The petroleum industry encompasses a wide range of
operations between the well and the point of product consumption.
The first phase of the industry is production. Production
includes locating and drilling oil wells, pumping and pretreat-
ing the crude oil, recovering gas condensate, and shipping these
raw products to the refinery or to the consumer. The second
phase, refining, extends through the separation, treating, and
conversion of crude to finished salable products. The third and
last phase of the petroleum industry is marketing, which involves
the distribution and sale of finished petroleum products. These
operations, their hydrocarbon emissions, and available controls
for these emissions are discussed in this report.
Size
Data used in this report is based on 1973 figures. This
is the latest year for which a complete set of statistics on
the petroleum industry are available. In 1973 crude oil and lease
condensate production averaged 9.2 million barrels per day,
natural gas plant liquids production averaged 1.7 million barrels
per day, and natural gas production averaged 65.9 billion SCF
per day. The United States also imported 3.2 million barrels of
crude per day in addition to 2.7 million barrels of finished
products per day. Daily refining rates in 1973 averaged 12.4
million barrels per day. Domestic demand for refined products
and natural gas liquids in 1973 averaged 17.3 million barrels
per day. These statistics are expanded in Tables 2.0-1 and 2.0-2,
and in Figure 2.0-1.
-8-
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TABLE 2.0-1
PETROLEUM INDUSTRY
SUPPLY AND DISPOSITION OF PRODUCTS - 1973
(DAILY AVERAGES IN THOUSANDS OF BARRELS PER DAY)
SUPPLY
Production
Crude and lease condensate 9,187
Natural gas plant liquids 1,738
Imports
Natural gasoline and plant condensate 103
Crude oil 3,244
Unfinished oils 137
Refined products 2,718
Other HC and hydrogen input 29
Unaccounted for crude oil 24
Processing gain • 453
TOTAL SUPPLY 17,633
CHANGE IN STOCKS -135
OF ALL OILS 17>498
.DISTRIBUTION OF PRODUCTS
Exports
Crude oil 2
Refined products 229
Crude losses 13
Domestic use 17,254
TOTAL DISPOSITION 17,498
Source: API, Annual Statistical Review, Petroleum Industry
Statistics, 1964-1973. (AM-099)
-9-
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TABLE 2.0-2
O
i
PETROLEUM PRODUCTS -
1973
(DAILY AVERAGES IN THOUSANDS OF BARRELS PER DAY)
Product
Total Casoline
Mot ox-
Aviation
Kerosine
Jet Fuel -
Naptha type
Jet fuel - -..
Kerosine type
Distillate
Fuel oil
Residual
Fuel Oil
Lubricants
Other
NCL
LRC
Includes special
U.S.
Production
6580
6535
45
220
181
679
2822
2 Transfer
971
17 Transfer
188
1854
1738 ^
375 '
nnpthas. wax.
Imports
132
132
..*
2
36
167
380
1827
6
37
234
coke, asphalt,
Total
lieu
Supply
6712
6667
45
222
217
846
3204
2815
194
1891
2347
road oil.
Change
in
Stocks Exports
-11 5
-10 4
.
+6
-2 2
+10 3
+115 9
-5 25 .
-3 35
-17 123
+41 . 27
fitill gas.
Domestic
Use
6718
6673
45
216
217
833
3080
2795
162
1785
1448
(831 Used
at refinery)
Total
Demand
6723
6677
45
216
219
836
3089
2820
197
1908
2347
petrochemical feedstocks, miscellaneous.
Source i API. Annual Statistical Review. Petroleum Industry Statistics.
1964-1973. (AM-099)
-------
FIGURE 2.0-1
PRODUCTION. TRANSPORT. AND USE OF CRUDE OIL AND PETROLEUM PRODUCTS-1973
(UNLESS OTHERWISE SPECIFIED . ALL FIGURES ARE DAILV AVERAGES IN THOUSANDS OF 42 GALLON BARRELS).
DOMESTIC PRODUCTION
NATURAL GAS I2.Q64 MtLUON CO. FT./DAV
AT 14.73 P.S.t.A.
-IMPORTS
CASING MEAD
GAS
CRUDE OIL AMD 9167
LEASE COKDEHSATE
PRIMARILY
8v
PIPELINE
TANKER/BARGE
OFFSHORE PRODUCTION
1586
CRUDE OIL
3244
UNFINISHED OILS
137
NATURAL GASOLINE
AND
PLANT CONOEHSATC
109
REFINED PRODUCTS
27IS
PRIMARILY 0V
TAMKER/OARGE
UAftlNE TERMINALS
PIPELINE 7959
T ANK CARS/TRUCKS 159 '
EXPORTS 27
. po SALES! W/'to e'ses |
iRCFIHERir USE
UOTOR GASOLINE 631
TOTAL GASOLINE
«S6C
REFINERV
PROCesStNG fACILIHES. FEED.
INTERMEDIATE. AND PRODUCT
S FORAGE
UPORTS 132
54 SPECIAL NAPTHAS.COKE.
WAX.ASPHALT. ROAD OIL.
STILL GA3.PCTROCKEMICAL
FECDSTOCKS.OTHER
NOlCi
NUUBLNS FOH TANK CAR /TRUCK TRANSPORTATION WERE CALCULATED FROM OTHER
MODE OF TRANSPORTATION FIGURES.
SOURCE* (AH-Otf)| (M-154)
-------
Growth Trends
The high growth trends established by the petroleum
industry in the late 1960's and early 1970's have been inter-
rupted and are still fluctuating. Although predicting the future
at this time is a difficult task, it appears that for the near
future U.S. crude production will be declining 2% to 370 yearly
while domestic petroleum demands and refining capacity will be
increasing 2% to 3%. At this point, it is apparent that increased
imports will be required. If more domestic refineries are added,
the amount of imported crude oil can be increased; otherwise
the increase will be as refined products processed outside the
country. Only a few grass roots refineries have been completed
in the last five years and there is no indication that the rate
of adding new domestic refinery capacity will increase under
current economic and political circumstances.
Emissions
The petroleum industry, because of the nature of its
products, represents a very large potential source of hydrocarbon
emissions. Hydrocarbon emissions are generated wherever volatile
hydrocarbons contact the atmosphere. Sources of hydrocarbon
emissions include storage tanks, loading operations, wastewater
systems, catalyst regenerators, valve and fitting leaks, and
emergency venting. Estimated hydrocarbon emissions for the
petroleum industry in 1973 were 9100 tons/day for production
and transportation of oil and gas, 5900 ton/day for petroleum
refining, and 3900 tons/day for petroleum product marketing,
making an industry total of 18,900 tons/day.
-12-
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By way of comparison, nation-wide hydrocarbon emissions
from transportation sources in 1970 averaged 53,400 tons/day,
while hydrocarbon emissions from the petroleum industry totaled
21,300 tons/day. Total 1970 hydrocarbon emissions from all sources
amounted to 95,600 tons/day (CA-102). Although petroleum in-
dustry emissions represent a large fraction (22%) of the nation's
total hydrocarbon emissions, these hydrocarbons are composed
largely of methane and other photochemically non-reactive
hydrocarbons.
-13-
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3.0 CRUDE OIL AND. NATURAL GAS PRODUCTION
«
3.1 • Domestic Oil Fields
3.1.1 Operations
In a producing oil well, there are three methods of
bringing the oil to the surface: natural flow, gas lifting
(injection of gas into the flowing column), and pumping. Most
producing wells are operated by mechanical lifting methods using
subsurface pumps of either a plunger or centrifugal type.
The production from each well is then sent to a complex
gathering system which consists of pipes, valves, and fittings
necessary to combine all of the production or to separate the
individual well productions in the case of varying qualities.
There are, in addition, test separators and tanks for testing
the oil quality.
Separation-Water
Because crude oil is produced in association with gases
and water (usually in the form of brine), it must then be treated
to separate the crude oil from the other components. Dehydration
or separation of oil from water is accomplished in two stages.
Water which freely settles is drained at the wellhead or from
the tanks at the gathering station to complete the first stage.
Often water remains in the crude oil in the form of an emulsion
which must be broken to remove the water. When this is the
case, the emulsion moves to a dehydration plant. Emulsion-
breaking is accomplished by adding a chemical destabilizer and/
or heating in a heater treater. The emulsion may be broken
-14-
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electrically by passing it between high voltage electrodes , or
a combination of these methods may be used. The brine removed
from the oil may be pumped into an open pond, treated, and used
for repressuring or returned to an abandoned formation for
disposal.
Separation-Gases
Separation of gases from the oil is often accomplished
in the field at the gathering station. Vertical, horizontal,
and spherical separators have specific advantages and may be
used alone or in series. The oil from the separators is trans-
ferred to the field storage tanks. The gas from the separators
may be transported to sales, transported to a natural gasoline
plant, reinjected into the producing formation to maintain
pressure, or (especially in remote areas) flared or vented.
The wet gas produced with crude oil is normally rich
in recoverable hydrocarbon liquids. This hydrocarbon mixture
is transported to a gas processing plant to separate the com-
ponents. Alternatively, the wet gas may be shipped directly to
a refinery for treatment. The dry gas obtained at the gas
processing plant is shipped via pipeline to natural gas sales.
The natural gas liquids obtained are stored in pressure tanks to
await transportation to the refinery or are piped directly to
fuel sales. The natural gasoline produced goes to the refinery
for blending and for production of other chemicals.
Variations in the production sequence are found
throughout the industry. Any step in the process may occur in
the field, at the gathering station, or in the refinery. Local
circumstances dictate specific procedures for individual
production.
-15-
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Secondary Recovery
To maintain production after reservoir pressures have
dropped, secondary recovery methods are implemented. There are
three general methods in use: waterflooding, gas injection, and
thermal methods. In 1967, an estimated 33% of the oil production
in the United States was by waterflooding. It has been further
projected that by 1980 fifty percent of U.S. oil production will
be by waterflooding (CH-182). Waterflooding consists of injection
of water into the formation under pressure via injection well.
Production water may be used, but it must first be treated to
prevent corrosion and chemical deposition from occurring in pipes.
or machinery. Detergents are sometimes added to the water.
In the use of gas injection, gas is injected under high
pressure via the injection wells to displace the crude out into
the production well. The gas supply is often production gas.
Thermal methods of recovery include steam injection,
hot water injection, or partial combustion. The increased
temperature of the reservoir causes a reduction in viscosity
and an increase in volume which results in increased oil recovery.
3.1.2 Products
There were 497,378 producing oil wells in the United
States in 1973 which produced a daily average of 9.2 million
barrels of crude oil (AM-099). Crude oil production results in
three main hydrocarbon products: crude oil, dry natural gas,
and natural gas liquids.
-16-
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Crude Oil
Crude oil is composed chiefly of saturated hydrocarbons
together with small amounts of organic compounds containing sulfur,
nitrogen, and oxygen. A typical domestic crude oil contains
83-877. carbon, 11-147. hydrogen, 0.05-2% sulfur, 0.1-27. nitrogen
and 0-27o oxygen (CH-182). Crude oils vary widely in appearance
and consistency. They range from yellowish brown, mobile liquids
to black, viscous semisolids depending on the molecular types and
sizes of hydrocarbons present. Paraffin base crude oils contain
mainly saturated straight-chain hydrocarbons; naphthene base
crudes contain mostly saturated ring-type molecules; mixed base
crude contain both straight-chain and cyclic saturated hydrocar-
bons and some aromatics.
Natural Gas
Natural gas is about 9570 saturated hydrocarbons. The
principal hydrocarbon is methane. Also present, in decreasing
proportions, are ethane, propane, butanes, pentanes, hexanes,
and heptanes. The remaining 57» is usually nitrogen, carbon
dioxide, and sometimes hydrogen sulfide. After being processed
to remove the natural gas liquids, the natural gas becomes dry
natural gas and consists chiefly of methane. The heavier hydro-
carbons are separated and/or liquefied to become ethane, natural
gas liquids and natural gasoline.
In 1973 there were 763 gas-processing plants in operation
which had a total capacity of 74.6 billion cubic feet per day
and an average throughput of 55.6 billion cubic feet per day
(FA-080). The average daily natural gas production for 1973 was
65.9 billion cubic feet per day with 12.9 billion cubic feet per
day produced from oil wells (AM-099). These gas plants produced
a daily average of 1.5 million barrels of natural gas liquids
-17-
-------
and ethane and 151,000 barrels of debutanized natural gasoline
(FA-080). Figure 3.1-1 illustrates the quantities of natural
gas and natural gas products produced in 1973 on a daily average
basis.
3.1.3 Storage and Handling
Crude oil is stored in welded tanks of high strength
steel. These are usually vertical tanks with fixed or floating
roofs. MSA estimated that in 1968 the storage capacity outside
of refineries amount to 304 million barrels (MS-001). This
figure includes field storage and storage at all points in the
transportation of crude from the field to the refinery.
The natural gas liquids produced with the crude are
handled as liquids and are stored in high pressure vessels,
either horizontal cylinders or spheres. The liquids may also be
stored under pressure in caverns in the earth's crust. Alterna-
tively these products may be handled at lower pressures by reduc-
ing operating temperatures. Using this handling method the
chilled liquids may be stored in lighter, insulated vessels above
ground, or in frozen earth pits.
Natural gas may be stored underground in former pro-
duction areas or in natural geological formations. The American
Gas Association reports a capacity for storage of over six
trillion cubic feet of natural gas in underground reservoirs
(UN-016). . Natural gas may also be cooled until it is liquid at
which time it can be handled in appropriately insulated vessels
lined with aluminum or stainless steel; however, this is a rel-
atively expensive means of storage and handling, and has been
used on a limited basis. Tankage may be above or below ground.
-18-
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Dry Natural Gas
Natural Gas
66.0 billion
cubic feet
763 Domestic
Gas Processing
Plants
NGL and Ethane
1.5 million barrels
Debutanized Gasoline
151,000 barrels
FIGURE 3.1-1
Production of Natural Gas and Natural Gas Products
(Daily Averages for 1973)
-19-
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3.1.4 Emissions
The evaporative losses in production of crude oil
result in emission of saturated hydrocarbons (the least photo-
chemically reactive of the hydrocarbons), usually low molecular
weight gases, which are associated with the crude oil.
In isolated areas where it may not be necessary or
feasible to control emissions to the atmosphere, and where there
may be no use for the gases separated from the crude or no
economical method of transportation to a gas processing plant,
the gases produced may be flared or even vented. An estimate
for the quantities of hydrocarbons vented to the atmosphere
was originally made by Processes Research, Inc., using data
from the 1968 Minerals Yearbook. This estimate was revised by
Radian using data from the 1972 Minerals Yearbook. The 1972
data shows 25 billion cubic feet of gas vented or flared and 45
billion cubic feet unaccounted for. The following assumptions
were made in calculation of emissions.
(l) All unaccounted gas is lost to the
atmosphere.
(2} Twenty percent of the vented and
flared gas is emitted without burning.
(.3) The emitted hydrocarbons have a
density of 0.1 pound per cubic foot.
These figures lead to an estimated emission of 50 billion cubic
feet per year lost to the atmosphere. This converts to 6,800
tons per day (PR-052).
-20-
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There is a further emission potential in the storage
tanks where the crude and natural gas liquids await transporta-
tion to the refinery. Light gases which have remained with the
crude may be discharged to the atmosphere from a storage tank
as a result of temperature changes, filling operations, and
volatilization.
Field processes have a potential for emitting hydro-
carbons to the atmosphere also. Oily brines produced with the
crude oil are often pumped into open pits or tanks where oil
collected on the top is skimmed off, or it may be left to
evaporate if there is no use for the water recovered. Also,
heat added in breaking of emulsions in the heater treaters has
the potential for increasing hydrocarbon emissions because of
the increased vapor pressure of the heated crude.
Pumps used in lifting the crude to the surface and
for pumping the crude to the storage tanks are also sources of
hydrocarbon emissions. The opening in the cylinder through
which the connecting rod actuates the piston is the major
potential source of contaminants from a reciprocating pump.
Leakage occurs in centrifugal pumps where the drive shaft
passes through the impeller casing.
Table 3.1-1 is from the MSA Study on Hydrocarbon
Pollutants (MS-001). It lists production emissions for a
specific area in California in 1968 with a total production of
18.5 million barrels of crude oil. These data emphasize the
importance of emissions from pumps.
The MSA Study further estimated total hydrocarbon
emissions from domestic crude oil production for 1968 as 220,000
tons/year.
-21-
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TABLE 3.1-1
ESTIMATED HYDROCARBON EMISSIONS FROM CRUDE
OIL PRODUCTION, MONTEREY COUNTY
1967
(Crude production of 18.5 million barrels per year)
Hydrocarbon Emissions
Point Source
Storage Tanks
Wastewater Separators
Pump Seals
Compressor Seals
Relief Valves
Pipeline Valves
Tons/Day
0.1
0.2
1.9
0.1
0.2
0.3
lb/103bbl
3.9
7.9
75.0
3.9
7.9
11.8
-22-
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3.2 Domestic Offshore
3.2.1 Operations
Offshore production operations are very similar to
onshore operations with the added complications of space limita-
tions, larger expenditures, and the generally hostile environ-
ment surrounding the fixed or floating platforms on which the
work must be done. Offshore oil is brought to the surface by
natural flow, gas lift, or pumping with subsurface pumps.
Processing
The crude is commonly sent to a central production
platform via pipeline for processing in generally the same
manner as onshore oil. Delivery to shore for processing is
also a possibility, but the usual practice is the separation
of gas and water from the oil on offshore installations. The
water from the separators must then be cleaned before release
to the ocean. If it is treated offshore to remove hydrocarbons,
the oil must be stored in an already limited space. Because of
confined operating conditions, the oily water may be delivered
onshore for treatment at a conventional cleaning and dehydrating
plant before release to the ocean. The gas is collected and
dehydrated if there is a market for it. If the production is
far removed from processing facilities, however, the gas is
often vented or flared.
Secondary Recovery
Producing wells offshore are subject to the same
secondary recovery methods as onshore wells. Secondary re-
covery offshore is more difficult because of the limitations
on size and weight of compression and pumping equipment. If
-23-
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necessary, the compression equipment c'an be installed on separate
platforms to provide the services needed. In addition, direct-
fired heating vessels must be avoided offshore for safety reasons;
nonflammable heat transfer fluids are commonly used.
Controls and Safety
The same process steps are made offshore as on-
shore with the added general complication of the precarious
positions of the men and machinery. These adversities necessitate
elaborate control systems of safety valves and cut-off equip-
ment integrated into the production equipment to handle the
eventualities of mechanical failure or damage due to storms or
shipping accidents. These control systems are often operated
from onshore facilities or by remote control from other plat-
form installations.
3.2.2 Products
The products from offshore installations are the
same as those produced onshore: crude oil, natural gas, and
natural gas liquids. The average daily production from off-
shore wells was 1.6 million barrels in 1973, or 17% of domestic
production. These numbers should undergo a steady growth as
exploration and production operations move further offshore.
3.2.3 Storage .'and Transport to Mainland
A great deal of reliance is placed on pipeline
deliveries of offshore oil to onshore installations. Barges
may be used for transport, but pipelines have the advantage of
minimizing storage on offshore structures.
-24-
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Offshore storage is used to a lesser extent in a
few of the far-removed operations. As development proceeds
farther from shore, more offshore storage will be utilized.
The storage facilities vary in capacity from 10,000 barrels to
one million barrels with a capacity of ten days of production
an accepted minimum (EN-043). The storage facilities are
classified in terms of their location in relation to the water
level: elevated, floating, semisubmerged, submerged, and
combination.
Elevated storage is located on a platform above the
surface of the water, frequently on the same platform with
production facilities. On deck storage in the Gulf of Mexico
is usually limited to 10,000 barrels (EN-043).
Floating storage facilities consist of barges, tankers,
and tanks having high positive buoyancy. Aside from regular
barges and tankers used for storage purposes, barges built
specifically for storage with capacities as high as 880,000
barrels of crude and with oil treating facilities on board are
also being used.
Semisubmerged tanks, used in protected waters, are
tanks moored in place which have a low positive buoyancy. Sub-
merged storage tanks may be moored below wave action near the
bottom, or they may have a negative buoyancy and be supported
on the bottom. This type of storage tank is frequently equipped
with above water structures for production support.
Combination storage facilities have their main storage
facility submerged. The elevated tank normally has 10-30 per-
cent of the submerged capacity and its primary purpose is to
replace the subsurface ballast needed to maintain a negative
buoyancy.
-25-
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The offshore storage facilities may also serve as
marine terminals for tankers whose sizes preclude their docking
in conventional harbors. The oil is transported from the storage
facilities to shore by pipeline, barge, or tanker to be stored
before it is transferred to the refinery.
3.2.4 Emissions
The emissions to the atmosphere from offshore opera-
tions are generally comparable to those from onshore production
presented in Table 3.1-1. These consist of saturated hydrocarbons,
usually in the lower molecular weight range. The emissions come
from venting excess associated gas and from evaporative losses
in water treatment facilities, pumps, and storage tanks. In
addition, there exists a higher potential for accidents, and,
therefore, an increased possibility of spillage in offshore
operations because of wave action, storms, and shipping mishaps.
As in onshore production of crude, the greatest
emissions may be in remote areas where control or recovery of
emissions may not be feasible or economical.
3.3 Emission Controls
Because the hydrocarbon emission sources found in crude
oil production are very similar to those found in refining opera-
tions, the emission control measures outlined in Section 5.3 on
refinery controls are directly applicable to the control of pro-
duction emissions. The control efficiencies reported for re-
finery sources should also be directly applicable.
-26-
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In brief, existing control technology for production
emissions consist of the following:
Storage Facilities
floating roof tanks or internal floating covers
vapor recovery units
Wastewater Separators
seal from atmosphere
vent to vapor recovery
floating covers
Pump and Compressor Seals
convert packed seals to mechanical seals
install double seals
Relief Valves
upstream rupture discs
vent to vapor recovery or flare
Pipeline Valves
regular maintenance of stuffing boxes
Heaters and Compressor Engines
carburetion adjustments
Miscellaneous Losses
regular maintenance
good housekeeping
-27-
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4'.0 CRUDE OIL TRANSPORT
4.1 Domestic Oil Fields and Refineries
4.1.1 Pipelines
The most important mode of transporting petroleum
overland is the pipeline. The basic function of trunk pipelines
in domestic oil fields is that of transporting crude oil from
field storage to refinery storage. In 1973 a daily average of
8.0 million barrels of domestic crude moved to refineries
through pipelines. This figure represented 8770 of domestic
production for that year (AM-Q99).
The first crude oil pipeline was built in 1865 in
Pennsylvania. Since then the pipeline network has grown to
thousands of miles. Pipelines have been enlarged from two inches
in diameter lines carrying crude very short distances to lines
of several feet in diameter which transfer multiple products
hundreds of miles.
Pipeline Construction
Pipelines are constructed predominantly of special
high strength steel but may be constructed of aluminum or plastic,
The lengths of pipe are welded together one length at a time.
Careful attention;,is given to the quality of weld at the joints.
The welds are inspected not only visually, but also radiograph-
ically to detect any weaknesses. Valves and pumps are installed
along the pipeline to control the flow of crude. Low viscosity
oils, are generally pumped through the lines with centrifugal
pumps, while higher viscosity oils are pumped with positive
displacement pumps, usually high speed, multistage reciprocating
types.
-28-
-------
Before the pipelines are buried, they are wrapped
with a protective coating to prevent corrosion of the outside
of the pipe. The pipe may also be equipped with cathodic pro-
tection. Internal corrosion is a problem only in those lines
carrying crudes containing sulfides.
Nearly all of the existent pipelines are laid below
grade. Subsurface installation protects them from weather and
from accidental damage by earth-moving equipment. Offshore
pipelines', are laid in trenches on the floor of the sea to guard
against damage by wave action, storms, and shipping accidents.
Pipeline Operations
A dispatcher coordinates operations of the pumping
stations and storage tanks to move oil through the lines on
schedule. The dispatching orders govern starting and stopping
of units, pressure changes, valve regulation, tankage utilization,
and oil sampling from a central, remote location. A good com-
munication system is essential, and computer controlled operations
are now common.
4.1.2 Domestic Tanker Transport
Although the United States pipeline system is extensive,
it is sometimes necessary and economical to transport crude by
barge or tanker to refineries in certain parts of the country.
Many refineries are located on navigable waters and operate
docks for receiving or shipping oil by tanker or barge. Tankers
of many sizes transport crude oil and products in coastal
traffic and over inland waterways. The United States has 12,000
miles (EN-045) of. coastline and 25,000 miles (AM-155) of naviga-
ble inland waterways, and, therefore, offers a large potential
for domestic traffic by water.
-29-
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Tanker and barge movements of crude oil for several
recent years are shown in Table 4.1-1 in daily averages of thou-
sands of barrels. Crude transported by water is usually moved
by pipeline from the point of production to the point of water
shipment.
The tankers involved in these short trips are small
"handy-tankers" which can maneuver well in restricted areas such
as docks and loading facilities. These versatile vessels have
an average capacity of 35,000 deadweight tons (DWT).
The barges used for transport of crude oil are called
tank barges. They are designed to carry liquid products in
bulk and are powered by towboats or tugboats.
4.1.3 Other Transport Methods
Other forms of crude transport are railway tank cars
and tank trucks. These are less commonly used methods, but they
are necessities in some areas. The daily average of crude
transported to the refineries by tank car and tank truck in
1973 was 159,000 barrels, or about 270 of the domestic production.
Tanks mounted on truck bodies or rail cars are constructed of
mild steel or aluminum. They are usually fitted with openings
for filling on top and discharge openings on the bottom. They
may also be fitted with heating coils and pumps for discharging
highly viscous crudes. The tanks are generally cylindrical in
shape and are as large as state highway departments and railroads
will allow. Loading and unloading is accomplished through flex-
ible hoses to and from loading racks at the storage facilities.
-30-
-------
TABLE 4.1-1
TANKER AND BARGE MOVEMENTS OF CRUDE OIL
(in thousand barrels per day)
(AM-099)
Gulf Coast to East Coast
Gulf Coast to Mid-West
Gulf Coast to West Coast
1971
565
50
--
1972
292
50
2
1973
155
28
--
-31-
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4.2
Imported Crude
Imports of crude oil for 1973 averaged 3.2 million
barrels per day. This figure constituted a 46 percent increase
of crude imports over 1972 figures. Table 4.2-1 provides an
illustration of the rate of growth of crude imports over the
past years.
TABLE 4.2-1
CRUDE OIL IMPORTS
(in thousands of barrels per day)
(AM-099)
1968
1290
1969
1409
1970
1324
1971
1680
1972
2216
1973
3244
1974*
3500
1975**
3830
Preliminary
January
- - Tanker Capacities
A large percentage of the imports must, of necessity,
be transported over the ocean in marine tankers. As more and
more oil has been transported from the lesser developed countries
to the highly industrialized nations, the world tanker fleet
has grown in numbers and in capacity. In 1950 tankers totalled
25.3 million deadweight tons (DWT); by 1972 tanker tonnage
came to 183.2 million DWT. The average size tanker increased
in the same time period, growing from 12,000 DWT to 58,000 DWT.
The largest tanker in use in 1950 was under 25,000 DWT, but in
1972 the largest tanker in use was in excess of 300,000 DWT,
and vessels of 540,000 DWT were under construction (PR-074).
-32-
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The increasing emphasis on large carriers results from the
favorable economics of carrying large loads on long trips.
Tankers are large vessels especially constructed to
carry products in bulk. They differ from other vessels in their
method of handling and storing their cargo. The cargo is pumped
aboard by shore pumps through pipelines connected to the
internal piping of the tanker and is stored in the cargo holds,
separated by bulkheads into a series of tanks. The cargo is
discharged by the reverse process, with the ship's pumps furnish-
ing the power to move the cargo through pipelines into storage
tanks ashore. The loading and unloading time is kept to a
minimum. Figure 4.2-1 is a diagram of a typical tanker and its
cargo disposition,
Cargo tank
FIGURE 4.2-1
Marine Tanker
The existing United States ports are unable to ac-
commodate the large "supertankers." This fact has necessitated
loading and unloading at offshore anchorages. The oil may be
loaded and unloaded via submarine pipeline to the shore. It
may also be handled in an offshore storage facility with later
transport to shore by smaller tankers and barges.
-33-
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4.3 Intermediate Storage, Processing, and Handling
Crude oil is handled in a virtually closed system
except for points of transfer. Crude is supplied to refineries
through a transportation system which includes tank farms, bulk
terminals, and other storage points connected by overland and
water transportation systems. Figure 4.3-1 illustrates the
relative sizes of systems involved in transporting crude oil
to refineries.
4.4 Emissions
The hydrocarbons emitted in transferring crude to the
refinery are mostly low molecular weight saturated hydrocarbons.
If the oil transportation system is open to the atmosphere at
any point, dissolved light gases will be lost.
Storage
As in every other phase of production, storage tanks
are potential sources of emission. An MSA Research Corporation
study on hydrocarbon pollutants included an estimated 470,000
tons of hydrocarbon emissions from crude storage tanks outside
of the refinery for the year 1968. This amounted to about 3.1
million barrels for the year, or 8,600 barrels per day (MS-001).
This is roughly 0,1 percent of the domestic crude oil production,
For comparison the hydrocarbon emissions from crude storage
within the refinery were estimated as 2.2 million barrels for
the same year.
-34-
-------
I
co
Ul
DOMESTIC PRODUCTION
9.2
Pipeline - 7.95
Rail and Tank Car - 0.16
Barge and Tanker - 1.09
IMPORTS
3.2
Pipeline
- 1.1
Marine Tanker _
2.1
ONSHORE
STORAGE
Pipeline
Tanker or
fc*^
te»
— *^_
FIGURE 4.3-1
Transportation of Crude Oil, 1973
(Rates in millions of barrels per day)
REFINERY
STORAGE
-------
Pipelines
Pipelines are subject to losses caused by corrosion
damage or accidents. Spills account for only a small percentage
of the quantity of products carried, but the volume of products
carried is very large. Data from Environmental Conservation
(EN-043) for 1968 showed that of 6.5 billion barrels of
petroleum products carried, six thousandths of one percent was
spilled. This amounted to 390,000 barrels of petroleum and
products spilled.
Data for 1970 show that 90 percent of pipeline failures
occur within the line pipe itself. The major cause of line
failure is corrosion, which accounted for 42.8 percent of the
mishaps, while another 20.2 percent was caused by outside forces,
such as earth moving equipment (EN-043). Of the pipeline failures
reported in 1970, 62.2 percent involved crude oil pipelines
(EN-043).
There are other sources of emissions in pipeline
systems such as valves, pumps, flanges, and other fittings. 'Even
small leaks in the many fittings and pumping equipment may result '
in sizable emissions because of the large volumes transported
through the pipeline network.
Tank Cars and Tank Trucks
Most evaporation from tank cars and tank trucks occurs
during loading operations. The tanks are usually filled from
the top by either subsurface loading or splash loading methods.
Subsurface loading is accomplished by extending the loading line
to the bottom of the container in order to discharge the product
below the surface of the liquid soon after the start of the
operation. This method eliminates much of the evaporation loss
-36-
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due to spraying the crude through the air space. Splash loading
is accomplished by a short loading pipe which allows the product
to fall through the tank vapor space thereby increasing the hydro-
carbon concentration vapor space. When the tanker is filled, the
liquid displaces the vapors inside the compartment to the atmos-
phere; consequently, the concentration of hydrocarbons in the
vapor space becomes important.
These displaced vapors contain a mixture of hydrocarbons
and air, the concentration of hydrocarbons depending on the type
of oil being loaded, the method of loading, and ambient temperature
and pressure. Tables 4.4-1 and 4.4-2 contain data from loading
tests conducted to determine losses encountered in the two types
of loading (AM-085). Comparison of the tables shows a trend
toward larger losses due to splash loading. The average vapor
saturation for subsurface loading is 6,4370 resulting in an
average loss of 0.03%. The average vapor saturation for splash
loading is 24.2% resulting in an average loss of 0.1870. Assuming
7570 of the tanks are loaded by the subsurface method and 25?0
are loaded by the splash method, and using the average volume of
crude transported in this method per day, the emissions from
this source were calculated to be an average of 110 barrels per day,
Marine Facilities
Evaporation losses from marine vessels occur during
all phases of the .transportation cycle. In loading operations,
marine tankers are filled from the bottom through fill pipes
which are integral parts of the carriers. This method of load-
ing creates the least amount of turbulence and results in the
least amount of vaporization. An equation has been published
by API (based on a relatively small amount of data) which can
be used to find a rough estimate of loading emissions: Percent
loss is equal to about 0.008 times TVP (true vapor pressure)
-37-
-------
TABLE 4.4-1
SPLASH-LOADING-LOSS TESTS FOR TANK CARS (CRUDE OIL)
Loading Condition!)
i
LO
CO
Daily
Mean
Tempera-
Test Geographical ture
No. Location (DegF) Month
1 Midland, Texas
2 Midland. Texas
3 Midland. Texas
4 M idland, Texas
5 Midland, Texas
6 Midland, Texas
7 Midland, Texas
8 Midland, Texas
9 Midland, Texas
10 Midland, Texas
11 Midland, Texas
12 Midland. Texas
13 Jefferson, Texas
14 Jefferson, Texas
15 Jefferson, Texas
16 Jefferson, Texas
17 Jefferson, Texas
IK Jefferson, Texas
63
63
63
63
63
63
63
63
63
63
63
63
79
79
79
79
79
79
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
June
June
June
June
June
June
Spout
Location
(Inches Vapor
Weather Below Saturation
Condition Hatch) (Per Cent)
Clear —
Cloudy —
Clear —
Clear —
Cloudy —
Cloudy —
Cloudy —
Cloudy —
Clear —
Cloudy —
Night —
Night —
Clear _
Clear ~
Clear —
Clear _
• Clear —
Clear —
5.0
113.0*
61.3
14.2
13.6
3.4
26.5
19.5
15.0
18.4
15.1
12.1
11.2
22.6
24.2
31.0
30.0
0
/ __"^
DCJJ r*
56
55
60
58
48
49
50
51
59
51
52
51
80
84
83
81
92
92
Stock
.A-
RVI'1
5.5
5.5
5.5
5.5
7.5
7.5
7.5
7.5
7.5
7.5
7.5
7.5
7.2
7.2
7.2
7.2
2.7
2.7
]
1
TV1» '
2.8
2.8
3.0
• 2.9
3.8
3.9
4.0
4.0
4.7
4.0
4.1
4.0
6.3
6.8
6.7
6.4
2.5
2.5
Fill Kate
(Gallons
per Load Loss
Minute) (Gallons) (Per Cent)
176
215
203
206
196
280
172
148
300
256
188
271
168
137
172
142
—
153
8,097
10,214
8,106
10,073
8,213
10,090
8,078
8,106
8,063
10,205
8,155
8,105
8.081
8,192
8,237
10,214
8,077
8.128
0.14
0.16
0.12
0.21
0.25
0.32
0.23
0.26
0.17
0.22
0.25
0.17
0.15
0.14
0.20
0.15
0.06
0.06
Test Method
Vapor analysis *• *
Vapor analysis *• *
Vapor analysis *• •
Vapor analysis *• *
Vapor analysis fc- '
Vapor analysis u- *
Vapor analysis *• *
Vapor analysis *• "
Vapor analysis v *
Vapor analysis k- *
Vapor analysis *• '
Vapor analysis k- '
Vapor analysis *• *
Vapor analysis *• '
Vapor analysis ki '
Vapor analysis b- •
Vapor analysis b> *
Vapor analysis *• •
* Theoretically could not exceed 100 per cent.
Vapor-analyst* method via
Insufficient Information
Temperature of the crude
alr*balance
to detemlne
stock being
technique
extent of
loaded.
. Vapor saaplea aaplrated
trow dome
Interaction between oxygen (02) ami
of cur;
hydrogen
air content determined
aulf Ide
(HjS) and the
by Orsat analyala.
error
reaulting therefrom.
Held Vapor Pressure.
True Vapor Pressure.
-------
TABLE 4.4-2
SUBSURFACE-LOADING-LOSS TESTS FOR TANK CARS (CRUDE OIL)
Test
No.
1
2
3
4
5
6
7
8
9
Geographical
Location
Midland, Texas
Midland, Texas
Midland, Texas
Midland, Texas
Midland, Texas
Midland, Texas
Midland, Texas
Midland, Texas
Midland, Texas
Daily
Mean
Tempera-
ture
(DegF)
63
63
63
63
63
63
63
63
63
Month
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
Feb.
.Feb.
Weather
Condition
Clear
Cloudy
Clear
Cloudy
Cloudy
Cloudy
Clear
Night
Night
Vapor '
Saturation
(PerCent)
8.9
2.6
2.5
3.5
5.7
0
19.5
4.8
10.4
DegF'
56
55
58
48
49
50
51
51
52
LWUUlUg
Stock
OlUCn.
RVP"
5.5
5.5
5.5
7.5
7.5
7.5
7.5
7.5
7.5
iwUiiutiiuu.:
TVP"
2.8
2.8
2.9
3.8
3.9
4.0
4.0
4.0
4.i
1
Fill Rate
(Gallons
per
Minute)
181
176
171
217
240
195
160
200
203
Load
(Gallons)
10,100
8,104
6,475
10,203
8,126
9,912
6,374
7,975
10,175
Loss
(PerCent)
0.03
0.01
0.03
0.01
0.02
0.05
0.05
0.07
0.02
Test Method
Vapor analysis *• b
Vapor analysis •• b
Vapor analysis '• "
Vapor analysis "• b
Vapor analysis *• b
Vapor analysis *• b
Vapor analysis *• b
Vapor analysis *• b
Vapor analysis *' b
• Vapor-analysis method via air-balance technique. Vapor samples aspirated from dome of car; air content determined by Orsat analysis.
b Insufficient Information to determine extent of Interaction between oxygen (Oj) and hydrogen aulflde (HjS) and the error resulting thersfro
Temperature of the crude stock being loaded.
Held Vapor Pressure.
True Vapor Pressure.
-------
(AM-085). Using an average true vapor pressure for crude of
4.00 psia (AM-085), the loss would be about 0.032 percent of
the domestic crude transported by barge or tanker or about
349 barrels per day emitted as loading losses. As the data
for unloading losses and transit losses were sparse, estimates
for these have not been developed (AM-085).
4.5 Emission Controls
Many of the hydrocarbon emission sources outlined above
are very similar in nature to the hydrocarbon emission sources
found in refinery operations. For this reason, the refinery
emission control measures detailed in section 5.3 should be
directly applicable to crude transportation emission sources.
Loading losses are best controlled by converting to bottom loading
and by installing vapor recovery units to process the displaced
vapors. Pipeline valve, flange, and fitting leaks can be
minimized by regular maintenance of packed seals and gaskets.
Converting from packed seals to mechanical seals in addition to
installing double seals will reduce compressor and pump leaks.
Hydrocarbon emissions unique to the transportation
industry and not found in refineries are in-route evaporation
losses. However, these emissions and those from storage tank
are similar. If control is required on rail car and tank
truck emissions, partial control can be effected by equipping the
tanks with pressure/vacuum valves which retain minor vapor
expansions and contractions. Barge and tanker emission controls
consist of venting vapor expansions to an on-board vapor recovery
system which reliquefies the vapors by refrigeration, compression,
absorption, and/or adsorption. Pressure/vacuum valves can also
be applied to barge and tanker storage for minimizing the quantity
of vapors processed in the vapor recovery unit.
-40-
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5.0 PETROLEUM REFINERIES
Petroleum refining is the third largest industry in the
United States and represents a potential hydrocarbon emission
problem by virtue of the large quantities of petroleum liquids
refined and the intricacy of the refining process. This section
defines the refining industry, sources of hydrocarbon emissions
within refineries, and control methods applicable to refinery
hydrocarbon emissions.
5.1 The Industry
5.1.1 Statistics
Generally each petroleum refinery is a unique hybrid
whose design is determined by the local market demands and the
characteristics of the crude being processed. However, refiner-
ies normally can be classified into one of the following five
basic refinery types.
Topping - primary operation is separation of
crude into its major fractions but may include
some hydrotreating.
Topping and Cracking - operations not only
include crude separation but also include
conversion and cracking processes for
maximization of gasoline product.
Topping, Cracking and Petrochemical - some
petrochemical processing is performed in
addition to cracking, conversion, and topping
operations.
-41-
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Integrated - lube oil, wax, and asphalt
processing is integrated into topping,
cracking and conversion processing.
Integrated and Petrochemical - petro-
chemical manufacturing is combined with
the refining operations of an integrated
refinery.
Approximately 28% of the refineries in the U.S. are
topping and cracking refineries, 20% are topping, cracking, and
petrochemical refineries, and 2070 are integrated refineries.
As of January 1, 1974, there were 247 operating
petroleum refineries in the U.S. with a total crude capacity of
14,200,000 b/d (AN-089). Individual refinery capacities range
from 1,000 b/d to 445,000 b/d. The ten largest refineries
comprise over 257* of the nation's capacity (EN-043) . Table
5.1-1 presents a distribution of the refinery sizes for 1971
(EN-043). There is a trend with time toward larger and fewer
refineries.
TABLE 5.1-1
REFINERY SIZE DISTRIBUTION - 1971
% of Total % of Total
Refinery Capacity Refineries Refining Capacity
<70,000 b/cd 75.9 28.4
70,000-200,000 b/cd 19.0 41.6
>200,000 b/cd 5.1 30.0
Many larger refinery complexes are situated adjacent
to petrochemical complexes to facilitate exchange of products
and by-products. This trend is also encouraged by municipalities
granting tax incentives for locating in industrial parks. In
-42-
-------
1967 over 50% of the nation's refining capacity was located in
100 large metropolitan areas (FO-001). Table 5.1-2 presents
the national refinery distribution by states in 1974 (AN-089).
The highest concentrations of refineries are along the Gulf Coast,
the West Coast, the midwest, and the Philadelphia-New Jersey area.
Refineries located hear large metropolitan areas and petrochemical
complexes pose significant hydrocarbon emissions problems.
TABLE 5.1-2
DISTRIBUTION OF REFINERY LOCATIONS (1974)
70 of National
State Refining Capacity (b/cd) Capacity
Texas 3,733,000 26
California 1,809,000 13 } 51%
Louisiana 1,667,000 12
Illinois 1,152,000 8
Pennsylvania 690,000 5
New Jersey 619,000 4
Ohio 572,000 4
Indiana 551,000 4 35%
Oklahoma 481,000 3
Kansas 402,000 3
Washington 347,000 2
Mississippi 290,000 2
Although the uncertainties of government action
and the economy make trend predicting difficult, refinery
production trends are expected to reflect the national goals of
self sufficiency, resourcefulness, and conservation. The high
yearly production increases of 57«, in the late 60's and early
70's may never be seen again. Current estimates are that yearly
production increases for the next few years are expected to re-
main at approximately 27,-3% (AN-089),
-43-
-------
5.1.2 Refining Processes
It is difficult to characterize the refining processes
applied by a so called "typical" refinery because of the wide
variety of refining schemes and processes available to the re-
finer. Because of the emphasis today on gasoline, a fully
integrated gasoline refinery will be used in the example of a
typical refinery. This section contains a brief description of
the commonly used refinery process units. Their relationship in
the overall refining scheme is shown in Figure 5.1-1 (RA-
119), the flow scheme of a fully integrated gasoline refinery
designed to maximize the production of motor gasoline.
Atmospheric and Vacuum Distillation
Crude petroleum is a mixture of many different hydro-
carbon compounds. These compounds are distinguished by their
hydrocarbon type and by their normal boiling temperatures. The
hydrocarbon types include paraffins , olefins , naphthenes , and
aromatics, and the normal boiling temperatures encompass a range
that exceeds 1000°F for most crudes. In crude oil refining the
first processing step is the physical separation of the crude
oil into these fractions of specific boiling temperature range.
This separation is performed in the atmospheric distillation
unit and in the vacuum distillation unit.
Within the atmospheric distillation process, desalted
crude is first charged to a direct-fired furnace where sufficient
heat is supplied to achieve partial vaporization of the crude
petroleum. Next both the liquid and vaporized portions are
charged at atmospheric pressure to the atmospheric fractionator.
The crude charge is separated into several petroleum fractions
within the atmospheric fractionator. A naphtha and lighter stream
is taken at the tower overhead and several liquid side-stream
-44-
-------
IV.H,1» (U»
i:
ar>*r«OM rtw>
aizc
•*"*
'if
I10MC0
iZATKJM
uwtr
.dUMU'lFQ
04TftL*fC _.
_ZL.
Tufiu
-ZZD
1
u
Radian Corporation
An si in. To««a
uneu mtr
tiniui
r
FIGURE 5.1-1
Typical Fully Integrated Gasoline Refinery
-------
fractions are withdrawn from the fractionator at different ele-
vations within the tower. These side-stream fractions are
stripped of residual light ends and then charged to hydrotreating
processes. From the fractionator bottom is drawn the heaviest
petroleum fraction (reduced crude) which is the charge to the
vacuum distillation unit.
Vacuum distillation receives its name from the sub-
atmospheric operating pressure of the fractionation tower(s)
employed. The purpose of vacuum distillation is to separate
heavy petroleum distillates from reduced crude (atmospheric
distillation tower bottoms). Vacuum fractionation with steam
stripping is employed to avoid excessive temperatures that
would be encountered in producing these heavy distillates by
atmospheric fractionation.
In the vacuum distillation process reduced crude is
first heated in a direct-fired furnace to a predetermined tempera-
ture of approximately 730-770°F. The hot oil is then charged to
the vacuum unit for separation of distillates from the charge
stock. Vacuum residuum is recovered as the fractionator's
bottoms product. Vacuum fractionators are maintained at ap-
proximately 100 mm Hg absolute pressure by either steam ejectors
or mechanical vacuum pumps.
Hydrocarbon emission sources associated with distilla-
tion units include vacuum jets with barometric condensers,
process heaters, and fugitive sources.
Gas Treating and Light Ends Recovery
Light ends from atmospheric distillation and other
refinery units contain a variety of acid gas species as well as
-46-
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light hydrocarbons. These acid gas species consist primarily
of hydrogen sulfide, but also include mercaptans, carbonyl
sulfides, and carbon disulfide. Acid gases are formed during
refinery operations from sulfur contained in the crude oil.
Acid gases are generally removed from the light ends
stream in a gas treating unit by absorption with an aqueous
regenerative sorbent. A number of gas treatment processes are
available, and they are distinguished primarily by the regenera-
tive sorbent employed. Amine-based sorbents are most commonly
used, however.
Within the gas treatment process, impure refinery light
ends are charged to an absorption tower for vapor-liquid mass
transfer with the amine solution. H2S is absorbed by the amine
solution in a reversible reaction. Purified refinery gas is
yielded as the absorption tower overhead product. This gas may
be further processed in light end recovery processes, or it may
be charged as a raw material to other refinery or petrochemical
processes. Sorbent rich in H2S from the absorption tower bottoms
is charged to a reactivator for regeneration. Here, the absorp-
tion reaction is shifted and H2S is stripped from the sorbent.
Concentrated acid gas removed in the reactivator is normally
charged to a sulfur plant for recovery of the contaminated
sulfur. Lean sorbent from the reactivator bottoms is recycled
to the absorption tower to complete the cycle.
Sweetened light ends from the gas treating plant are
subsequently processed in the light ends recovery unit. Light
ends recovery involves the separation of refinery gases into
individual component streams. The separation is normally
accomplished by absorption and/or distillation.
-47-
-------
The methane through propane fractions can be used as
refinery fuel, sold as products, or used as feedstock for
ethylene units. The butane fraction can be sold as product,
blended into motor gasoline, or routed to alkylation units.
Hydrocarbon emissions from gas treating and light ends
recovery are primarily attributable to fugitive leaks of the
highly volatile light ends.
Conversion Processes - Alkylation, Reforming,
Isomerization
There are three conversion processes normally applied
in gasoline refineries for converting low octane products to
high octane products. These are alkylation, reforming, and
isomerization.
Alkylation is the process whereby an olefin (propylene,
butylene, etc.) and an isoparaffin (normally iso-butane) are
catalytically reacted or combined to produce a high octane
component known as alkylate for gasoline blending. The two
major types of alkylation processes for refinery application
utilize liquid catalyst of either sulfuric acid (thSCK) or hydro-
fluoric acid (HF). The mechanism of alkylation is essentially
the same for both processes; however, they differ somewhat in the
process flow scheme. Both processes are being built in new
and existing refineries.
In the alkylation unit, olefin and isoparaffin feed-
stocks are mixed with the liquid catalyst in a reaction vessel.
The alkylation reaction takes place at modest pressures and
temperatures. After reaction the alkylate and catalyst phases
are separated in a settler. The catalyst is recycled to the
reactor.
-48-
-------
Isomerization units are used to increase the octane
rating of pentane and hexane fractions by catalytically re-
arranging the normal paraffins into isoparaffins. The feedstocks
to isomerization units are desulfurized and dehydrated straight
chain pentane and hexane fractions normally from the naphtha HDS
unit. The product from isomerization is a low sensitivity gaso-
line blending stock consisting of up to 75% isomers and having
a clear research octane number of 80 to 85.
In the isomerization unit desulfurized, dehydrated
C5-C6 feedstock is mixed with hydrogen, heated to reaction
temperature, and mixed with HC1.. This mixture passes over a
catalyst in a hydrogenation reactor where benzene and olefins
are hydrogenated, and then passes on to the isomerization reac-
tor. In the isomerization reactor the feed contacts a chlori-
nated platinum-aluminum-oxide catalyst which isomerizes the
C5-C6 normal paraffins into Cs-Ce isoparaffins. Effluent from .
the isomerization reactor is cooled and passed to a high pres-
sure separator where recycle hydrogen is withdrawn. Separator
liquid passes to a stripper column where it is stripped of re-
cycle H.C1, and then passes through a neutralization vessel. The
neutralized product is routed to gasoline blending.
Cat a ly tic reforming processes convert low octane
naphthas into high octane naphthas by catalytically rearranging
naphthenes and paraffins, forming benzene, toluene, and xylene.
The high octane aromatic products are used in gasoline blending
and as feedstocks to aromatic plants.
Within the catalytic reformer the naphtha feedstock
from the naphtha HDS unit is first mixed with hydrogen under
pressure and heated in a series of heat exchangers to reaction
temperature. The mixture then passes through a series of fur-
naces and fixed bed catalytic reactors. In the catalytic
-49-
-------
reactors, the paraffins and naphthenes are dehydrogenated to form
higher octane aromatics with some hydrocracking reactions occur-
ring to convert higher boiling paraffins to lower boiling higher
octane material. Reactor effluent, after passing through a
bank of heat exchangers, enters into a separator where a hydro-
gen-rich gas is withdrawn and recycled. Liquid from the separa-
tor is taken to a fractionator and split into a light ends stream
containing Ci-C4 and into a reformate stream containing the
»
aromatics, paraffins, and naphthenes. The reformate product is
routed to gasoline blending.
In many refineries a liquid-liquid aromatic extraction
unit is incorporated within the catalytic reforming unit. The
aromatic extraction unit separates the reformate stream into a
raffinate stream containing the non-aromatics and an extract
stream containing 95% aromatics.
Hydrocarbon emissions from conversion processes can be
attributed to process heaters, fugitive emissions from the units
under pressure, and fixed bed catalyst regeneration.
Hydrodesulfurization Units
Hydrodesulfurization is becoming widely practiced in
modern refineries for the desulfurization and denitrification of.
naphtha, distillate, and residual feedstocks. The demand for low
sulfur products in conjunction with the susceptibility of some
catalysts to sulfur and nitrogen poisoning necessitates the
removal of sulfur and nitrogen from naphtha, distillate, and
residual feedstocks. Normally petroleum fractions are treated
separately because of the varying sulfur limits placed on various
fuels and because of the wide range of catalysts and reactor con-
ditions required to treat the various petroleum fractions.
-50-
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Within the hydrodesulfurization unit, feedstocks from
the atmospheric and vacuum distillation columns are mixed with
fresh and recirculating hydrogen and heated to reaction tempera-
ture. The mixture then passes into a fixed-bed reactor where it
contacts a non-noble metal catalyst. In the reactor, organic
sulfur and nitrogen complexes are broken and hydrogenated to
form H2S and NH3. Depending on the severity of the reactor
conditions, there will also be some cracking of the feedstock
into lighter fractions. Reactor effluent is cooled and then
split in a series of flash drums into a recycle hydro-
gen stream, a sour light ends stream and a desulfurized product
stream. The sour light ends are routed to the gas treating unit.
Desulfurized product is sent to product storage or provides a
feedstock for downstream processing units.
Because of the high temperatures and pressures required
in desulfurization processes, leaks of volatile hydrocarbon are
prevalent, and maintenance is difficult. In addition to fugitive
sources, hydrocarbon emissions are also attributable to inter-
mittent catalyst regeneration and to handling of oily condensates
from the steam strippers.
Cracking
The purpose of cracking is to convert heavy distillate
oils into petroleum fractions of lower boiling range and of cor-
respondingly lower molecular weight. Feedstocks to the process
are typically gas oils which may or may not have been desulfurized.
Cracking performed in a hydrogen atmosphere with a fixed bed is
termed "hydrocracking" and cracking performed without hydrogen
addition and with a moving or fluidized bed is termed "catalytic
cracking."
In catalytic cracking, preheated feedstock is contacted
with the catalyst in either a fluidized bed or a moving bed
-51-
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reactor. Catalytic cracking occurs in the reactor. The syn-
crude product is withdrawn from the reactor and separated
in a fractionation tower. Spent catalyst coated with coke and
other impurities is continuously withdrawn from the reactor and
charged to the regenerator. Regeneration is achieved by con-
trolled combustion of the coke that has accumulated on the cata-
lyst. Recycle of the hot regenerated catalyst to the reactor
completes the catalyst loop.
In the hydrocracking process the feedstock is first
mixed with hydrogen and recycle unconverted product. The mixture
is heated, then contacted with catalyst in a fixed bed reactor '
at a specified hydrogen partial pressure. Reactor design may be
either one or two stage. • Within the reactor the feedstock is
catalytically cracked and hydrogenated, forming primarily satu-
rated isoparaffins and naphthenes, plus some aromatics. The
hydrocrackate product from the reactors is fed to a series of
separators and fractionators for separation into a recycle
hydrogen stream, desired product streams, and a recycle un-
converted product stream. The hydrocracking catalysts must be
regenerated regularly to remove coke and impurities. The re-
generation is achieved by controlled combustion in a batch opera-
tion.
Hydrocarbon emissions from cracking operations are
primarily generated in the catalyst regenerators. Other sources
of emissions include process heaters, handling of oily conden-
sates, and fugitive sources.
Alternative Vacuum Resid Processes
There are several alternative vacuum resid processes
open to the refiner which are used in place of or in conjunc-
tion with resid hydrodesulfurization. The selection of these
-52-
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processes is dependent on both refinery needs and market demands,
but the list basically includes solvent deasphalting, coking,
partial oxidation, and asphalt stills.
In solvent deasphalting, a solvent such as pentane or
propane is used to extract heavy oil fractions from asphalt
in vacuum resids. The deasphalted oil is suitable for heavy
fuel oil or feedstock to lube processing.
Asphalts and coke from solvent deasphalting can be fed
to partial oxidation units where they are partially oxidized in
the presence of steam and oxygen to yield hydrogen, low Btu fuel
gas and hydrocarbons.
The coking process severely cracks vacuum tower bottoms
in a thermal cracker to produce coke, a light naphtha, and light
ends. The naphtha fraction is routed to gasoline blending and
the light ends is treated in the gas treating plant.
High quality asphalt is produced from vacuum tower
bottoms by processing in asphalt stills. Within the asphalt
still, air is blown through the vacuum tower bottoms at an
elevated temperature, stripping off lighter hydrocarbon frac-
tions and dehydrogenating the remaining fractions. The de-
hydrogenating reaction yields water and a highly polymerized
asphalt.
Because of the generally low volatility of the
products handled in vacuum resid processes, fugitive emissions
are not a serious problem. The largest potential hydrocarbom emis-
sion sources are asphalt air-blowing and coker off gas.
-53-
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Lube Processing
Lube processing units for the refining of vacuum dis-
tillation cuts into lube oils, waxes, and greases are included
in several refineries. Because the demand for lube products is
very small in comparison to the demand for liquid fuels, refiners
tend to consolidate their lube processing units into only a few
refineries. Lube processing units consist primarily of lube
hydrotreating, solvent extraction, and grease manufacturing.
Hydrocarbon emissions from lube processing are generally
attributed to air-blowing and fugitive losses of refining sol-
vents .
5.1.3 Refinery Products
National average production rates of major refining
products are presented in Table 5.1-3. Generally, however,
national production rates fluctuate seasonally by several
percentage points depending upon seasonal demands. Gasoline
production is highest during the summer vacation months and
fuel oil production is highest during the cold winter months.
In relating the products in Table 5.1-3 to Figure 5.1-1,
motor gasoline, aviation gasoline, and jet naphthas are pro-
duced in the gasoline blending unit while kerosenes and diesel
fuels are included in the distillate fuels stream. Lubricants
and other miscellaneous products are unique to each refinery and
are therefore omitted from the "typical gasoline refinery"
depicted in Figure 5.1-1.
Although the national ratio of gasoline production
to fuel oil production was 4870 to 27 °/0, the ratio of refinery
-54-
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TABLE 5.1-3
PETROLEUM PRODUCT RATE - 1973
(Daily Average Production in Thousands of Barrels)
Product
Motor Gasoline
Aviation Gasoline
Kerosine
Jet Naphtha
Jet Kerosine
Distillate Fuel Oil
Residual Fuel Oil
Lubricants
LPG (C2, C3, and CO
Other (special naphthas,
wax, coke, asphalt, road
oil, still gas, petrochem-
ical feedstocks)
TOTAL
Production
6,535
45
220
181
679
2,822
971
188
375
1,854
13,870
47
2
1
5
20
7
1
3
13
99
-55-
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products is quite variable among refineries depending on the
composition of the crude and the processing objectives of the
refinery. Products from refineries dedicated to maximizing
gasoline may consist of 7070 gasoline and 257o fuel oil. On the
other hand, products from a refinery dedicated to fuel oil
production may consist of only 25% gasoline and up to 70% fuel oil,
5.1.4 Auxiliary Processes
There are several important auxiliary processing units
which are included in most refineries but: which are not con-
sidered part of the refining process. These units are employed
for such functions as the treatment of waste streams, the supply
of plant utilities, and the handling of products. Auxiliary
units are important as potential sources of emissions and are
described here in general terms.
Crude Desalting
The first unit in an oil refinery is normally a crude
desalting unit which removes inorganic salts and brines from the
incoming crude. If not removed, these inorganic salts can cause:
(1) fouling of process equipment; (2) equipment corrosion due
to the formation of HC1; and (3) catalyst poisoning by metal-
lic salts.
In a typical electrostatic crude desalting unit the
unrefined crude oil is heated to give it suitable fluid proper-
ties. Then fresh water is added to dissolve and absorb impuri-
ties from the crude. To assure intimate mixing between the
crude and the fresh water, an emulsion is formed by passing the
two through an emulsifier. Next the water-oil emulsion passes
into a treating vessel where a high voltage field demulsifies the
-56-
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oil and water mixture. The impurities from the crude oiloare
removed in the water effluent and the clean desalted crude oil
is ready for subsequent refining.
Chemical crude desalting is a little used alternative
to electrostatic crude desalting, and employs coalescing agents
instead of a high voltage field to demulsify the aqueous and
organic phases.
Crude desalting units are generally not considered
a significant hydrocarbon emission source. However, in addition
to fugitive emissions there potentially are hydrocarbon emissions
from handling oily aqueous wastes.
Sulfur Recovery Plant and Tail Gas Treatment
Sulfur recovery involves conversion of the hydrogen
sulfide (H2S) in acid gases into elemental sulfur. The con-
centrated acid gas streams charged to the recovery plant are
from (1) the refinery gas treating plant and from (2) the sour
water stripper.
The Claus process is the most widely accepted sulfur
recovery system in the refining industry. In the process con-
centrated acid gas is first combusted with a sub-stoichiometric
air supply to S, S02 and H20. Additional sulfur recovery is
obtained in a series of catalytic reactors where SOa formed in
combustion reacts with remaining H2S to form sulfur and H20.
The number of reactors determines the degree of conversion.
Unconverted acid gas leaves in the tail gas stream and is often
treated in a tail gas treatment unit before release to the
atmosphere.
-57-
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Treatment of sulfur plant tail gas serves to reduce
atmospheric emissions and is expected to become a standard
refinery process as air quality requirements become more strin-
gent. Seven processes employing varying principles are presently
operating or are installed in processing plants. At the moment
it is difficult to determine which of the processes will prove
most effective. The charge to these processes is tail gas
directly from the Glaus unit. In addition to reducing atmospheric
emissions, some candidate treatment processes recover a salable
product such as sulfur, sulfuric acid, etc.
Normally there are no significant hydrocarbon emissions
associated with the sulfur recovery unit or the tail gas treatment
plant.
Hydrogen Plant
Hydrogen is consumed in many refinery processes in-
cluding hydrodesulfurization, hydrocracking, isomerization, and
others. Catalytic reforming yields hydrogen for refinery con-
sumption; however, an additional source is often required to meet
a refinery's hydrogen demand. The hydrogen plant serves to fill
the gap between a refinery's hydrogen supply and demand.
Hydrogen plants utilize steam-hydrocarbon reforming
to produce hydrogen. In a typical steam-hydrocarbon reforming
process, hydrocarbons (which may range from methane to residual
oils) and steam are catalytically reacted in a high-temperature
reactor to form hydrogen and carbon monoxide. The high tempera-
ture is maintained by direct heating. These reaction products
are cooled by quenching and carbon monoxide further reacts with
water to form hydrogen and carbon dioxide. Carbon dioxide is
removed from the hydrogen in an amine absorption unit and carbon
monoxide is methanated by reaction with hydrogen.
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Oily condensates, fugitive sources, and fired heaters
are potential hydrocarbon emission sources associated with
hydrogen production.
Blending and Storage
Refinery blending operations involve the mixing of
various components to achieve a product of desired characteris-
tics. The most common blending operation in petroleum refining
involves the final step in gasoline manufacturing. Gasoline
components such as cat gasoline, reformate, alkylate, isonerate,
butane, lead, dye,'etc., are mixed in a proportion to meet gaso-
line marketing specifications. Blending is commonly accomplished
in a mixing manifold.
Storage capacity is required at refineries for the
blended products as well as for liquid feedstocks, intermediate
products and other finished products. Storage capacities vary
among refineries but generally range from one to two months
for feedstocks and products. Normally included in storage
facilities are loading and unloading facilities. Although a
majority of the feedstocks and products are transported by pipe-
line, some material is transported by tank trucks, rail tank
cars, and marine vessels. Loading facilities are made up of
loading arms, hoses, couplings and nozzles for the taking up
and dispensing of petroleum liquids.
Blending and storage operations potentially represent
the largest single source of hydrocarbon emissions from re-
fineries .
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Sour Water Stripper
Sour water stripping units are used in refineries to
remove hydrogen sulfide and ammonia from sour waste waters. The
two product gas streams from the stripping unit are 99+% pure
hydrogen sulfide and ammonia, and the water effluent contains
only trace amounts of hydrogen sulfide and ammonia.
In a typical sour water treatment unit degassed sour
water feed is passed through a feed heater into a reboiler
stripper column where hydrogen sulfide is stripped overhead
while water and ammonia flow out the column bottoms. The hydro-
gen sulfide overhead is high purity and directly suitable as
sulfur plant feed. The hydrogen sulfide stripper bottoms are
fed into a second reboiler stripper column which produces a
clean water bottoms and an ammonia overhead product. After fur-
ther processing to remove small amounts of hydrogen sulfide and
water the ammonia product is salable as anhydrous liquid ammonia.
Since sour water stripping units are enclosed systems,
hydrocarbon emissions are limited to very minor fugitive leaks.
Waste Water Treatment Plant
The purpose of a waste water treatment plant is to up-
grade the quality of water effluents so that they can be safely
returned to the environment, or reused within the refinery. The
design of waste water treatment is complicated by the diverse range
of refinery pollutants, including oil, phenols, sulfides, dissolved
solids, suspended solids, toxic chemicals, and BOD-b.earing
materials. The four basic phases of waste water treatment are
inplant pretreatment, primary treatment, secondary treatment,
and tertiary treatment.
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Although most of the oil entering with the waste water
is removed by API separators, residual hydrocarbons remain dissolved
in the waste water. Due to the high air-water contact occurring
in waste treatment processes, these dissolved hydrocarbons are
emitted to the atmosphere.
Utility Steam Boilers
Refineries generally include a steam plant to supply
their utility steam requirements. Conventional boilers are em-
ployed and normally fired with either refinery fuel gas, vacuum
resid, or one of the product fuel oils. Utility steam demands
for a refinery are approximately 40 Ibs/bbl at pressures ranging
from 150 to 600 psig.
Hydrocarbon emissions resulting from incomplete fuel
combustion are common in boiler flue gases.
5.2 Hydrocarbon Emission Sources
Hydrocarbon emissions vary greatly from one petroleum
refinery to another depending on such factors as capacity, age,
crude type, processing complexity, application of control mea-
sures, and degree of maintenance (EN-043). National surveys in
1968 indicated that refinery hydrocarbon emissions totaled 1.7 x
106 tons/year. Tha ratio of hydrocarbon emissions to refinery
feed, ranged from 0.07 wt% to 0.87 wt% on an individual refinery
bcsis and averaged 0.1 wt70 across the country (MS-001) .
Because refineries are a complex collection of inte-
grated processing units, the pinpointing of individual hydrocarbon
emission sources would be an extensive task. This section attempts
to characterize and where possible to quantify the hydrocarbon
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emissions from major sources within a typical refinery. These
emission sources are grouped into combustion sources, tankage and
loading sources, process sources, and fugitive sources.
5.2.1 Combustion Sources
A typical petroleum refinery has several major com-
bustion sources which include process heaters, boilers and
compressor engines. Hydrocarbons are emitted from these
sources due to incomplete fuel combustion. Sources such as
flares and flue gas incinerators are treated as control devices
and discussed in Section 5.3 on emission controls.
Process Heaters
Process heaters are used extensively in refining
operations to heat and thermally crack feed streams prior to
separation and treating processes. They are the largest combus-
tion source of hydrocarbon emissions in refineries. Table 5.2-1
summarizes the heater demand of some typical refining units
(RA-119). The total process heater demand for a modern
refinery is approximately 270 x 106 Btu/1000 bbl of refinery
feed (RA-119). However, the process heater demand for older,
less efficient refineries may reach 600 x 106 Btu/1000 bbl of
refinery feed (MS-001).
The fuel to process heaters can be any one of several
hydrocarbon streams in the refinery, but is generally either
residual fuel oil, refinery fuel gas, or a combination of the
two. A refinery survey in California reported the process
heater emissions listed in Table 5.2-2 (AT-040). The heating
values of these fuels are included (EN-071).
-62-
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TABLE 5.2-1
HEAT DEMAND OF SOME TYPICAL REFINING UNITS
SOURCE
Heaters and Furnaces
Heat Demand
(103 Btu/bbl of unit feed)
distillation unit
naphtha HDS unit
distillate KDS unit
gas oil HDS unit
residual HDS unit
isotnerization unit
reformer
reformate extraction
catalytic cracking
hydrogen plant
alkylation unit
100
25
55
55
64
68.4
258
190
154
166
244
Total for modem refinery
265 103Btu/bbl refinery
feed
-63-
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TABLE 5.2-2
HYDROCARBON EMISSIONS FROM
REFINERY BOILERS AND HEATERS
Fuel Hydrocarbon Emissions Heating Value
Refinery fuel gas 0.03 lb/103scf 1050 Btu/scf
Distillate fuel oil 140 lb/103bbl 5.9 x 106Btu/bbl
Residual fuel oil 140 lb/103bbl 6.3 x 105Btu/bbl
Refineries in the future may elect to fuel process heaters with
unrefined vacuum resid, a low grade of fuel which can produce
slightly greater hydrocarbon emissions than refined fuel oils.
Boilers
Most refineries include steam boilers in their process-
ing units to supply their process and utility steam requirements
Major sources utilizing steam are light ends strippers, vacuum
steam ejectors, process stream exchangers, and reactors. The
steam demand for a typical gasoline refinery is approximately
40 x 103lb/103bbl of refinery feed. This equates to a boiler
size of 53 x 106btu/103bbl of refinery feed.
As with process heaters, refinery boilers are fueled
with the most available fuel source, generally refinery fuel gas
or residual fuel oil. Hydrocarbon emissions from refinery
boilers were found in a refinery survey to be the same as hydro-
carbon emissions from process heaters (AT-040). These emissions
are reported in Table 5.2-2.
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Refinery boilers are often partially fueled with cata-
lytic cracker regenerator flue gas as a means of controlling
carbon monoxide in the regenerator flue gas, in addition to re-
covering the heating value of carbon monoxide. When this is
done, the hydrocarbon emission contribution of the boiler fuel
is not expected to change significantly.
Compressor Engines
Many older refineries use internal combustion engines
fired with refinery fuel gas to run high pressure compressors
because refinery fuel gas has traditionally been a cheap, abundant
source of energy. Examples of refining units operating at high
pressures include the hydrodesulfurization, iscmerization, re-
forming, and hydrocracking units. Hydrocarbon emissions from
internal combustion engines fired with refinery fuel gas are
approximately 1.2 lbs/103 scf fuel (MS-001). A survey of hydro-
carbon emissions from compressor engines at refineries in 1968
indicated that the national average emissions from compressor
engines were 16 lbs/103 bbl refinery feed (MS-001).
5.2.2 Storage and Loading Sources
The high volatility of feedstocks, intermediates, and
products stored and loaded in refinery tank farms makes them
one of the largest potential hydrocarbon emission sources in the
refining industry. Because most products and feedstocks are
transported by pipeline, storage losses are greater than loading
losses.
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Types of Storage Tanks
There are five basic types of storage tanks used by
refineries. These include fixed roof, floating roof, internal
floating cover, variable space, and pressure. The application of
these tanks largely depends on the volatility of the stored
liquid.
The fixed roof tank is the least expensive and the most
common type of tank used. It is a cylindrical steel tank with
a conical steel roof (Figure 5.2-1). Today fixed roof tanks are
normally equipped with pressure/vacuum valves set at only a few
inches of H20 to contain minor vapor volume expansion.
Floating roof tanks are cylindrical steel tanks simi-
lar to fixed roof tanks (Figure 5.2-2). However, instead of a
fixed roof, they are equipped with a sliding roof, designed to
float on the surface of the product. A sliding seal attached
to the roof seals the annular space between the roof and vessel
wall from product evaporation. Floating roof tanks eliminate
the vapor space of fixed roof tanks.
Internal floating covers are a modification of float-
ing roofs, designed to deal with the buoyancy problems caused
by snow and rain (Figure 5.2-3). They are essentially fixed
roof tanks equipped with an internal floating cover similar to
a floating roof. . Internal floating covers contain sliding
seals to seal the annular space between the cover and the vessel
wall from evaporation.
There are two basic types of variable vapor space
tanks. These are shown in Figures 5.2-4 and 5.2-5. The lifter
roof tank has a telescopic roof, free to travel up and down as
the vapor space expands and contracts. A second type is the
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FIGURE 5.2-1
Standard Fixed Roof Tank
FIGURE 5.2-2
Floating Roof Tank - (double deck type)
-67-
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FIGURE 5.2-3
Internal Floating Cover Tank
FIGURE 5.2-4
Lifter Roof Tank
-68-
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Flexible diaphragm
FIGURE 5.2-5
Flexible Diaphragm Tank
-69-
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diaphragm tank equipped with an internal flexible diaphragm
to cope with vapor volume changes.
Pressure tanks are used to store highly volatile
products. These tanks come in a very wide range of shapes and
are designed to eliminate evaporation emissions by storing the
product under high pressures. Pressure tanks are commonly de-
signed for pressures up to 200 psig.
Fixed roof, floating roof, and internal floating
cover tanks are the most common tanks in refinery service.
These tanks range in size from 20,000 to 160,000 bbl and
average 70,000 bbl (MS-001).
Nature of Product Storage
Table 5.2-3 indicates the vapor pressures (EN-043),
volumes (MS-001), and types of storage tanks used for several
major refinery products. Federal emission regulations currently
require hydrocarbon products with true vapor pressures (under
storage temperatures) ranging from 1.5 to 11.1 psia be stored in
floating roof tanks or their equivalent. Normally internal
floating covers are considered equivalent to floating roof
tanks.
Mechanism of Storage Losses
Evaporation loss is the natural process whereby a
liquid is converted to a vapor which subsequently is lost to the
atmosphere. Evaporation occurs whenever a volatile hydrocarbon
is in contact with a vapor space or the atmosphere. There are
six basic kinds of evaporation loss from petroleum storage:
breathing, standing storage, filling, emptying, wetting, and
boiling.
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TABLE 5.2-3
Product
NATURE OF PRODUCT STORAGE AT REFINERIES
True Vapor
Pressure
psia @ 60°F
Types of Storage Tanks
Qty. Stored
1968
(106bbl)
Fuel Gas
Propane 105
Butane 26
Motor Gasoline 4-6
Aviation Gasoline 2.5-3
Jet Naphtha 1.1
Jet Kerosene <0.1
Kerosene <0.1
No. 2 Distillate <0.1
No. 6 Residual <0.1
Crude Oil 2
Cryogenic - Pressurized
Pressurized
Pressurized
Vapor Saver, Fixed Roof,
Floating Roof
Vapor Saver, Fixed Roof,
Floating Roof
Vapor Saver, Fixed Roof,
Floating Roof
Fixed Roof
Fixed Roof
Fixed Roof
Fixed Roof
Vapor Saver, Fixed Roof,
Floating Roof
204
14
18
31
46
346
137
-71-
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Breathing losses occur when vapors are expelled from a
storage tank because of temperature and/or barometric pressure
changes. Standing storage losses are those resulting from leaks
around hatches, relief valves, and floating roof or floating
cover seals. Filling losses occur when vapors are displaced to the
atmosphere as a result of tank filling. Vapor expansion subsequent
to product withdrawal is termed emptying loss and is due to satu-
ration of newly inhaled air. Wetting losses are attributed to
the vaporization of liquid from wetted tank walls exposed when a
floating roof or floating cover is lowered by liquid withdrawal.
Boiling losses occur when vapors boil off stored liquid.
The major source of hydrocarbon emissions from fixed
roof tanks are breathing and filling losses, while the major
source of emissions from floating roofs and internal floating
covers is standing storage losses. Depending on auxiliary vapor
recovery equipment, vapor saver tanks may or may not be subject
to filling losses.
Quantification of Storage Emissions
Storage emissions at refineries depend on several major
factors, including liquid vapor pressure, diurnal temperature
changes, schedule of tank fillings and emptyings, solar radiation
absorption of tank, and mechanical condition of the tank, seals,
and fittings. The American Petroleum Institute and other groups
have developed extensive formulas for calculating tank emissions
including the above parameters. However, due to the variability
in location, tank design, and operation of refineries
the definition of a characteristic refinery for purposes of
calculation does not seem warranted. Emission factors developed
for the simplification of estimation of tankage emissions are
available as presented in Table 5.2-4 (EN-071).
-72-
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TABLE 5.2-4
HYDROCARBON EMISSION FACTORS
Floating Roof Standing
Storage Emissions
Liquids
Crude Oil
Gasoline
Jet Naphtha
Kerosene
Distillate Fuels
New Tank
lbs/day-103gal
0.
0.
0.
0.
0.
029
033
012
0052
0052
Old Tank
lbs/day-103gal
0.
0.
0.
0.
0.
071 '
088
029
012
012
FOR PETROLEUM
Fixed
STORAGE
Roof Storage Tank
Breathing Losses
New Tank
lbs/day-103gal
0.
0.
0.
0.
0.
15
22
069
036
036
Old Tank
lbs/day-103gal
0.
0.
0.
0.
0.
17
25
079
041
041
Filling
Losses
lbs/103gal
throughput
7.3
9.0
2.4
1.0
1.0
Variable
Vapor
Space Tank
Filling
Losses*
lbs/103gal
throughput
_.
10.2
2.3
1.0
1.0
Based on no auxiliary vapor recovery equipment.
-------
Application of tankage emission factors indicates that
average tankage emissions from a refinery generally range from
100 to 1000 pounds per thousand barrels of crude processed de-
pending on type of storage used (AT-040, MS-001). In 1968 ap-
proximately 757o of the storage tanks at refineries were equipped
with floating roofs. Based on this degree of control, national
hydrocarbon emissions from the petroleum refining industry in
1968 were estimated at 3.2 x 105ton/year from crude storage,
4.2 x 10ston/year from gasoline storage, and 2.0 x 105ton/year
for the balance of the product storage (MS-001). These emissions
are equivalent to 470 Ib of hydrocarbons/103bbl of refinery feed.
Loading Losses
A second source of hydrocarbon emissions in refinery
tank farms occurs at the loading racks. As volatile products are
loaded into tank trucks, marine vessels, and rail cars, gasoline
vapors in the tanks are displaced to the atmosphere. The quantity
of these emissions is dependent on the method of dispensing,
quantity of product dispensed, product vapor pressure, and pre-
vious service of the transport vehicle.
The greatest determinant in the total emissions generated
in product loading is the method of dispensing. In splash loading
the liquid is discharged by a short spout into the upper part of
the tank. The resultant free fall not only increases evaporation
but may result in a fine mist of liquid droplets.
In submerged surface and bottom loading the product is
discharged within a few inches of the tank bottom. There is a
marked decrease in turbulence, therefore losses by evaporation
and entrained droplets are correspondingly reduced.
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The hydrocarbon emissions generated from product loading
operations at the refinery can be calculated from either the
curves shown in Figure 5.2-6 (AM-055) or from Table 5.2-5 (EN-071)
The curves in Figure 5.2-6 report hydrocarbon emissions from
splash loading and submerged loading as a function of true vapor
pressure and in the units of volume percent of the product loaded.
Table 5.2-5 reports hydrocarbon emissions in pounds of hydrocar-
bons per thousand gallons of product loaded. The total quantity
of refinery products loaded daily into rail cars, tank trucks,
barges and tankers for the year 1973 are reported in Table 5.2-6
(AM-099). These tables and figures indicate that gasoline load-
ing was by far the largest hydrocarbon emission source in re-
finery loading operations. For 1968 gasoline uncontrolled load-
ing losses at the refinery were estimated at 63,000 tons/year,
or approximately 32 lbs/103 bbl of refinery feed (MS-001).
5.2.3 Process Sources
A substantial portion of the hydrocarbon emissions from
petroleum refineries can be attributed to individual refining
processes or to individual auxiliary processes. These sources
include catalyst regenerators, barometric condensers, blowdown
systems, waste water separators, air blowing, and cooling towers.
Because process emission sources are identifiable, their emis-
sions are more accurately quantified and more easily controlled.
Catalytic Cracker Regenerators
An integral part of a catalytic cracking unit is the
catalyst regenerator (Figures 5.2-7 and 5.2-8) where coke that is
formed on the catalyst surface during cracking is burned off.
Because the combustion rate is controlled by limiting the air to
the regenerator, there is only partial oxidation, leaving many
-75-
-------
FIGURE 5.2-6
LOADING LOSSES FROM MARINE VESSELS, TANK CARS AND TANK TRUCKS
0.5
O
.J
Lu
O
0.4
0.3
CO
O
_J
o
0.2
o O.I
Q.
LJ
0.0
0 I 23456789
TRUE VAPOR PRESSURE (TVP), PSIA
-76-
-------
TABLE 5.2-5
Emission Source
Rail Cars
Splash Loading
Submerged Loading
HYDROCARBON EMISSIONS FROM
PETROLEUM PRODUCT LOADING
Product Losses (lbs/103gal)
Crude Jet
Gasoline Oil Naphtha Kerosene Distillate Oil
12.4
4.1
10.6
4.0
1.8
0.91
0.88
0.45
0.93
0.48
Tank Trucks
Splash Loading 12.4
Submerged Loading 4.1
10.6 1.8 0.88
4.0 0.91 0.45
0.93
0.48
Marine Vessels
2.9
2.6
0.60 0.27
0.29
-77-
-------
TABLE 5.2-6
MODES OF PRODUCT TRANSPORTATION
FROM REFINERIES (1973)
Pipeline Tanker/Barge Rail/Trucks
(IQ^bbl/d) (103bbl/d) (103bbl/d)
Motor Gasoline 4809 649 1215
Aviation Gasoline 11 11 23
Lubricants 0 50 112
Residual Fuel Oils 0 64 2731
Distillate Fuel Oils 1992 297 791
Jet Kerosene 643 100 90
Jet Naphtha 41 27 149
Kerosene 128 44 44
-78-
-------
Ven»
Surge
Separator
P'oducti
n
->
Rfgtrerolld
Cotalvst
Airlifl or
Elevator
Fraclionolino,
Tower
_^W«t Gas to Poly, or
""^"" Alky lotion Units
—^Crocked Gasoline
Pull Oil
Oil Reeyelt
-5^-Hgflvy Fu«l OH
FIGURE 5.2-7
Typical Moving-Bed Catalytic Cracking Uni
Flue GOJ
Regenerator
Gas to Poly.
or Al'-Recyc!e Gas Oil
>^Heovy Fuel Oil
Cos Oil Charge
FIGURE 5.2-8
Typical Fluidized Bed Catalytic Cracking Unit
-79-
-------
unburned hydrocarbons in the regenerator flue gas. Catalytic
cracker regenerators operate continuously.
Regenerator flue gas contains from 100 to 1500 ppm of
hydrocarbons (EN-043) depending on characteristics of the charge
and the type of catalytic cracker. Hydrocarbon emissions from
fluidized bed catalytic cracker regenerators (FCC) average 220
lbs/1000 bbl charge and hydrocarbon emissions from moving bed
catalytic cracker regenerators (TCC) average 87 lbs/1000 bbl
charge (AM-055). In 1968 the estimated hydrocarbon emissions
from FCC regenerators were 143,000 tons/year and from TCC
regenerators were 10,000 tons/year (MS-001).
Catalysts used in other process units are regenerated
by combustion, generating hydrocarbon emissions similar to those
from regenerating cracking catalysts. However these catalysts
need only be regenerated once or twice a year resulting in negli-
gible emissions.
Vacuum Jet - Barometric Condensers
Most refineries operate some processing equipment at
less than atmospheric pressures. The vacuum distillation column
is the most common of these processes operating at a vacuum.
Steam driven vacuum jets or ejectors coupled with a barometric
condenser are frequently used in refineries to produce and
maintain vacuums (Figure 5.2-9). Light hydrocarbons which do not
condense in the barometric condenser are discharged to the
atmosphere.
Studies indicate that the hydrocarbon emissions from
barometric condensers on vacuum distillation columns are
approximately 130 lbs/1000 bbl of charge to the vacuum
distillation column (LA-129). Because the charge to vacuum
-80-
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STEAM INLET
WATER
SUCTION
r»
\
I
•STEAM INLET
\
DISCHARGE
BAROMETRIC CONDENSER
WATER AND CONDENSED
HYDROCARBONS OUTLET
FIGURE 5.2-9
Typical Steam Ejector - Barometric Condenser
-81-
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distillation columns is 40% to 50% of the crude charge to the
refinery, the hydrocarbon emission factor for barometric con-
densers becomes 50 to 65 lbs/1000 bbl refinery capacity.
Slowdown Systems
One of the essentials of refinery operations is the
periodic maintenance and repair of equipment. This involves
purging equipment of hydrocarbons. The hydrocarbons purged
during shutdowns and startups are often manifolded to blowdown
systems for recovery, flaring, or safe venting to the atmosphere.
Emergency venting in the event of upsets in operations is also
manifolded to the blowdown system.
Studies on hydrocarbon emissions from uncontrolled
blowdown systems indicate that they range from 300 to 350 Ib
of hydrocarbons per 1000 bbl of refinery feed, varying with fre-
quency of shutdowns and upsets (AT-040).
Air Blowing
Air blowing of petroleum products is today confined
largely to the manufacture of asphalt, although air is occasionally
blown through heavier petroleum products for the purpose of re-
moving moisture. Figure 5.2-10 depicts the flow diagram of a
typical asphalt air-blowing process. The use of air blowing
for the purpose of agitation, formerly quite common, is today
practically non-existent.
Hydrocarbon emissions are generated as the air blown
through the asphalt entrains light hydrocarbons and hydrocarbon
aerosols. The quantity of light hydrocarbons stripped by the
air is a function of the amount of air used, the volatility of
the asphalt, and the process temperature. Available data on
-82-
-------
3ESIOUAI
Oil
STEAK
BLANKET ,.
AIR
OATES
—•ST
AIR 3Lfl'»N
ASPHALT
Off MS TO
INCINERATOR
EfRUENT TO
COVESE3 OIL-HATER
SEPARATOH
HEATER
(RECYCLE)
BLC1ING STILL
KNOCKOUT DRUM
FIGURE 5.2-10
Flow Diagram of Asphalt Blowing Process
-83-
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asphalt air blowing indicate that hydrocarbon emissions amount
to 27o-4% by weight of asphalt charge (AM-055). This may be
expressed as 40 to 80 Ibs per ton of charge. Because asphalt
production is limited, the overall national emissions from
asphalt blowing are minor.
Process Drains and Waste Water Separators
Some equipment and a number of operations in oil re-
fineries allow hydrocarbons to reach drains and eventually the
waste water separators. These include blind changing, sampling,
turnarounds, leaks, and spills. In addition, much of the water
routed to the drains is already contaminated with hydrocarbons,
including water from processing, pump seal cooling, and flush-
ing. Drains generally flow to an API separator for gravity
separation of the oil and water prior to treatment in the waste
water treatment plant (Figure 5.2-11).
If the drains and waste water separator are uncovered,
hydrocarbons can evaporate to the atmosphere. Important factors
in the quantity of hydrocarbon emissions generated are oil con-
centration, volatility, temperature, and agitation. Uncontrolled
emissions from this source approach 200 Ibs of hydrocarbons/1000
bbl of refinery feed (AT-040).
Cooling Towers
Petroleum refineries use large quantities of water for
cooling. Before the water can be reused, the heat absorbed in
passing through process heat exchangers must be removed. This
cooling is usually accomplished by allowing the water to cascade
through a cooling tower where evaporation removes the sensible
heat from the water.
-84-
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HAN
OIL-UTES
TIANSVCUt OPENINGS
flt»»HOH
lECS
FIGURE 5.2-11
Modern Oil-Water Separator
-35-
-------
Hydrocarbon emissions are generated at the cooling tower
when hydrocarbons leaked into the cooling water system by heat
exchangers, evaporate to the atmosphere. A survey of Los Angeles
County refineries reported that hydrocarbon emissions from cool-
ing towers range from 5 Ibs to 500 lbs/day-103gpm of cooling
water circulated (DA-069).
5.2.4 Fugitive Sources
One of the largest yet hardest to control category of
hydrocarbon emissions from petroleum refineries is fugitive
sources. Fugitive sources are those sources which are not
attributable to particular refining processes or auxiliary pro-
cesses, but which are scattered throughout the refinery. Fugi-
tive losses from individual sources are generally small, but
become significant because of their prevalence. Fugitive sources
include pump seals, relief valves, pipeline valves, sampling,
blind changing, etc.
Pump and Compressor Seals
Pumps and compressors required to move liquids and gases
in the refinery can leak product at the point of contact between
the moving shaft and the stationary casing. If volatile, the
leaked product will evaporate to the atmosphere. The two types
of seals commonly used in the petroleum industry are packed
seals (Figure 5.2-12) and mechanical seals (Figure 5.2-13).
Packed seals affect a seal around the moving shaft by forcing a
fibrous packing between the shaft and casing wall. Mechancial
seals consist of two plates situated perpendicular to the shaft
and forced tightly together. One plate is attached to the shaft
and one is attached to the casing.
-86-
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TU(
IMC
,
MODUCT
flOOUCT
FIGURE 5.2-12
Packed Seal
High-pressure zone
Rotating shaft
Rotating collar—'x^—
-Graphite ring
(stationary)
Springs
•Packing spreader
U-Cup packing
Set screw
Seal s top
Low-pressure zone
\
Cosing
Lock washer
FIGURE 5.2-13
Mechanical Seal
-87-
-------
Average hydrocarbon losses for both types of seals on
centrifugal and reciprocating pumps and compressors are tabulated
in Table 5.2-7 (DA-069). A study of Los Angeles County refineries
found centrifugal pumps with packed seals lost 4.8 Ibs of hydro-
carbons/day-seal, centrifugal pumps with mechanical seals lost 3.2
Ibs of hydrocarbons/day-seal, reciprocal pumps with packed seals
lost 5.4 Ibs of hydrocarbons/day-seal, and compressors lost 8.5
Ibs of hydrocarbons/day-seal. On an overall refinery basis these
hydrocarbon emissions amount to 17 lb/1000 bbl refinery feed for
pumps and 5 lb/1000 bbl refinery feed for compressors (AT-040).
Pressure Relief Valves
For safety and equipment protection, high pressure
vessels are commonly equipped with relief valves to vent exces-
sive pressures. Figure 5.2-14 shows a standard pressure relief
valve.
Corrosion may cause pressure relief valves to reseat
improperly after blowoff, creating a potential source for hydro-
carbon leaks and emissions. Surveys indicate average hydrocarbon
leaks for relief valves on process vessels average 2.9 Ib/day-
valve and for relief valves on pressure storage tanks average
0.6 lb/day-valve. The overall quantity of hydrocarbons leaked
from refinery relief valves is 2.4 Ib/day-valve which equates
to 11 lb/103bbl refinery feed (AT-040).
Pipeline Valves and Flanges
Under the influences of heat, pressure, vibration,
friction, and corrosion, valves and flanges generally develop
leaks. The hydrocarbon emissions from these leaks depend on
both the volatility of the product and the leak rate.
-88-
-------
TABLE 5.2-7
EFFECTIVENESS OF MECHANICAL AND PACKED
PUMP SEALS ON VARIOUS TYPES OF HYDROCARBONS
Seal type
Mechanical
Avg
Packed
Avg
Packed
Avg
Pump type
Centrifugal
Centrifugal
Reciprocating
^
Type
hydrocarbon
being pumped,
Ib Reid
> 26
5 to 26
0.5 to 5
> 0. 5
> 26
5 to 26
0.5 to 5
> 0. 5
26
5 to 26
0.5 to 5
> 0.5
Avg hydrocarbon
loss per
inspected seal,
Ib/day
9.2
0.6
0.3
3.2
10.3
5.9
0.4
4.8
16.6
4.0
0. 1
5.4
Leak incidence
Small leaks, a
To of total
inspected
19
18
19
19
20
32
12
22
31
24
9
20
Large leaks,
% of total
inspected
21
5
4
13
37
34
4
23
42
10
0
13
aSmall leaks lose less than 1 pound of hydrocarbon per day.
-89-
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SPRING
FROM PRESSURE VESSEl
TO VENT
LINE
FIGURE 5.2-14
Pressure Relief Valve
-90-
-------
Tests of numerous valves indicate average hydrocarbon
emissions of 0.5 Ib/day-valve for service with materials having
vapor pressures above 15 psia, and emissions of 0.05 Ib/day-
valve for service with materials having vapor pressures below
15 psia. The overall average leakage is 0.15 Ib/day-valve which
is equivalent to 28 lbs/103bbl of refinery feed (AT-040).
Pipeline Blind Changing
Refinery operations frequently require that a pipeline
be used for more than one product. To prevent leakage and
contamination of a particular product, other product-connecting
or product-feeding lines are customarily "blinded off". "Blind-
ing" a line involves inserting a flat solid plate between two
flanges of a pipe connection. In inserting or withdrawing a
blind, spillage of product in the pipeline can occur. The mag-
nitude of hydrocarbon emissions from the spillage is a function of
the spilled liquid's vapor pressure, type of ground surface,
distance to nearest drain, and amount of liquid spilled.
Hydrocarbon emissions from blind changing vary greatly
in quantity from zero to several pounds per blind. A two month
log of emissions from blind changing by Los Angeles refineries
indicated average hydrocarbon emissions of 0.29 lb/103bbl of
refinery feed (AT-040).
Purging Sampling Lines
The operation of process units is constantly checked
throughout the refinery by routine analysis of feedstocks and
products. To obtain representative samples for these analysis,
sampling lines must be purged, resulting in possible hydrocarbon
vapor emissions.
-91-
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Hydrocarbon emissions from excessive purging of sampling
lines can amount to 50-100 lbs/103bbl of refinery feed (LA-129)
but generally average 2.3 lbs/103bbl of refinery feed (AT-040).
Others
In every refinery there are several unaccountable hydro-
carbon emission sources as well as hydrocarbon emission sources
which are not common to all refineries, such as asphalt blowing,
coke processing, and lube processing. It has been estimated
that this category of emissions amounts to 7 Ibs of hydrocarbons/
103bbl of refinery feed (AT-040).
5.3 Hydrocarbon Emission Controls
Because hydrocarbons are the products of refineries, there
is an obvious economic incentive to minimize their loss. The
control of hydrocarbon emissions from petroleum refineries prin-
cipally centers around three methods: process changes, installa-
tion of control equipment, and improved housekeeping. This sec-
tion itemizes control measures available for the emission sources
discussed in the previous section. Where available, control ef-
ficiencies are also given, however, it is very difficult to assign
efficiencies to controls which are based upon housekeeping and
maintenance.
5.3.1 Combustion Source Controls
Hydrocarbon emissions from process heaters and steam
boilers can be minimized by adjusting the fuel to air ratio for
optimum fuel combustion. To insure optimum combustion condi-
tions are maintained, some refineries have installed oxygen
analyzers and smoke alarms on heater and boiler stacks (WA-086).
-92-
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Internal combustion engines used to drive older com-
pressors have inherently high hydrocarbon emissions. The major
means of controlling hydrocarbon emissions from this source is
by carburetion adjustments similar to those applied to automobile
engines for emission control. Economic considerations coupled
with increased concern for emission reductions is inducing
refineries to phase out the use of internal combustion engines.
5.3.2 Storage and Loading Controls
Tankage Controls
The most common form of emission control applied to
large storage tanks is the installation of floating roofs or
internal floating covers (Figures 5.2-2 and 5.2-3). A physical
description of these devices was given in Section 5.2.2. Float-
ing roofs and internal floating covers eliminate breathing and
filling emissions by eliminating the vapor space that exists in
fixed roof tanks. The application of floating roofs or internal
floating covers on all storage of liquids having true vapor
pressures ranging from 1.5 psia to 11 psia, would reduce refinery
emissions from approximately 1200 Ibs to 250 lbs/103bbl of re-
finery feed (MS-001).
Another emission control available for refinery tankage
is the manifolding of fixed roof tanks into a vapor saver or a
variable vapor space tank (Figures 5.2-4 and 5.2-5).. Vapor
expansions in excess of the vapor storage capacity would be
vented to a vapor recovery unit where the vapors are liquefied
and returned to storage. This flow arrangement is shown in
Figure 5.3-1. The efficiency of such a system is dependent on
the efficiency of the vapor recovery unit. Because of the high
-93-
-------
r\
!
VAPOR RECOVERY
PROCESSING UNIT
u u
0=0
r
>
GASOLINE
STORAGE
GASOLINE
STORAGE
TRUCK-TRAILER RACK
EQUIPMENT LOADING EQUIP. LOADING
. RUMP
DROPOUT £ SATURATOR TANK
FIGURE 5.3-1
Integrated Vapor Gathering System
-------
cost of vapor recovery units their application normally can be
justified only in recovery of the more volatile products,
Loading Rack Controls
Hydrocarbon emissions from transport loading operations
are generally controlled by the use of a vapor collection device
manifolded into a vapor recovery unit. The transport vehicle
may be a tank truck, rail car, barge, or marine vessel.
The type of vapor collection system installed depends
on how the transport vehicle is loaded. If the unit is top
loaded, vapors are recovered through a top loading arm (Figure
5.3-2). Product is loaded through a central channel in the nozzle,
Displaced vapors from the compartment being loaded flow into an
annular vapor space surrounding the central channel and in turn
flow into a hose leading to a vapor recovery system.
If the transport is bottom loaded, the equipment needed
to recover the vapor is considerably less complicated. Vapor and
liquid lines are independent of each other with resultant sim-
plification of design. Figure 5.3-3 shows a typical installation.
Product is dispensed into the bottom of the transport and dis-
placed vapors are collected from the tank vents and returned to
a vapor recovery unit.
Bottom loading vapor recovery has many advantages over
top loading vapor recovery. Bottom loading generates much less
vapor, generates almost no mist and is safer from a static
electricity point of view.
The vapor collection efficiency of loading controls is
in excess of 9570. However the overall emission reduction is
-95-
-------
MISCELLANEOUS PARTS
ITEM
1
2
3
4
5
6
7
8
9
10
11
PART HO.
3420-F-30
2775*
3420-F-40
H-S936
D-S37-M
H-5898-RP
H-S90S-M
H-5905-M
H-SSI8-
C-1667-A
C-2479^
OESCRIPT10H
Swivel Joint, 3"
Boom
Swivel Joint, 4"
Swivel Joint 3"
Handle
Hose
Elbow
Coid Grip
Collat Sub-Assembly
Link
Gasket
QTY.
2
2
2
1
ITEM
12
13
14
15
16
17
18
PART NO.
H-4190-M
D-636-M
3630-30
H-4189-M
H-5952
3840-FCMO
710
C-555-A
417-FKA-4"
3476-F-40
DESCRIPTION
Gasket, 4"
Upper Kindle & Pipe
Swivel Joint, 3"
Gasket, 3"
Swivel Joint Sub-Assembly, 4"
Swivel Joint Only
4x2 7,8 Nipple Only
4" Flange Only
Loading Valve
Swivel Joint, 4"
QTY.
6
1
1
1
FIGURE 5.3-2
Top Loading Arm Equipped With A Vapor Recovery Nozzle
-96-
-------
I
VO
FIGURE 5.3.3
Bottom Loading Vapor Recovery
-------
also dependent on the efficiency of the vapor recovery unit. A
9070 efficient vapor recovery unit would make a loading control
system 85% efficient and lower the hydrocarbon emissions from
loading operations to 5 lbs/103 bbl refinery feed.
Vapor Recovery Units
Vapor recovery units are manifolded into the vapor
collection systems of tankage and loading operations for the
reliquefaction of hydrocarbon vapors into product. Figure 5.3-1
shows an integrated vapor collection system with a vapor recovery
unit. Vapor recovery units liquefy hydrocarbon vapors by several
principles which include compression, refrigeration, absorption,
and adsorption. They also can employ a combination of these
principles. The efficiency of vapor recovery units typically
ranges from 9070 to 97% depending upon the composition and con-
centration of the hydrocarbon vapors processed.
5.3.3 Process Source Controls
Catalytic Cracker Regenerators
There are two major control measures applicable to the
reduction of hydrocarbon emissions in the flue gas of catalytic
cracker regenerators. The first of these is incineration in a
carbon monoxide waste-heat boiler. By incinerating regenerator
flue gas in CO waste-heat boilers, the hydrocarbon emissions
are reduced to a negligible amount and valuable thermal energy
is recovered from the flue gas.
A second control measure applicable to the flue gas
from TCC catalytic cracker regenerators as well as the flue
gas from regenerating operations for other catalysts is incinera-
tion in a heater fire box or smoke plume burner. These regenerators
-98-
-------
produce significantly less flue gas than FCC regenerators and
may not justify a CO boiler. Catalysts in this category may in-
clude reformer, isomerization, and hydrocracking catalysts.
Hydrocarbon emissions in regenerator flue gas are reduced to
negligible quantities by incineration in heater fire-boxes and
smoke plume burners.
Although neither CO boilers nor other forms of regenera-
tor flue gas incineration are extensively used today, they are
becoming standard equipment in new refineries and expansions
of existing units. This is a result of both energy conservation
and increased concern for air quality.
Vacuum Jets - Barometric Condensers
Hydrocarbon emissions from barometric condensers on
vacuum jets are attributable to both the venting of non-
condensable hydrocarbons as well as to the evaporation of hydro-
carbons from the oily barometric condensates.
Three measures for minimizing oily condensate generation
are mechanical vacuum pumps, lean oil absorption, and surface
condensers. While mechanical vacuum pumps have little effect on
the quantity of non-condensable hydrocarbons generated, they
do eliminate the generation of oily steam condensate. The inser-
tion of a lean oil absorption unit between the vacuum tower and
the first stage vacuum jet helps to minimize the quantities of
both non-condensables and oily condensate (AM-055). The rich
oil effluent is reused as charge stock and not regenerated. Sur-
face condensers in place of barometric condensers minimize oily
condensates but have little effect on the quantity of non-
condensables (AT-040).
-99-
-------
Because there are no means to completely eliminate the
generation of non-condensable vapors from vacuum pumps or steam
ejectors, these emissions must be controlled by either vapor
incinerators or vapor recovery units. Vapor incinerators combust
the vapors by catalytic or direct flame methods. Vapor recovery
units on the other hand recover the hydrocarbon vapors and return
them to processing streams.
The maximum degree of control attainable for the hydro-
carbon vapors from vacuum jets equipped with barometric condensers
is effectively 100% (AT-040). Currently however, controls for
vacuum units are not widely applied in the petroleum industry.
Slowdown Systems
Slowdown emissions can be effectively controlled by vent-
ing into an integrated vapor-liquid recovery system. All units
and equipment subject to shutdowns, upsets, emergency venting,
and purging are manifolded into a multi-pressure collection
system. Discharges into the collection system are segregated
according to their operating pressures. A series of flash drums
and condensers arranged in descending pressures separates the
blowdown into vapor pressure cuts. These recovered gaseous
and liquid cuts can be either flared and/or re-refined.
Fully integrated blowdown recovery systems can reduce
refinery blowdown emissions to 5 Ibs of hydrocarbon/103bbl of
refinery feed (AT-040). Because most refineries are currently
applying some degree of blowdown system control the average
refinery emissions from blowdown systems range from 120 Ibs to
200 Ibs of hydrocarbons/103bbl of refinery feed (MS-001, AT-040).
-100-
-------
Air Blowing
Control of the hydrocarbon vapors and aerosols generated
by air blowing of asphalts is normally accomplished by one of two
methods.
1) Scrubbing of vapors with water.
2) Incineration of vapors in an afterburner
or firebox,
A disadvantage of controlling asphalt blowing exhaust
gases by water scrubbing is the high volume ratio of water to
exhaust gas required to scrub the noncondensable gases of pungent
odor. This ratio is reported as 100 gal per 1000 scf (AM-055).
When an adequate water supply is not available or where
handling condensate may result in hydrocarbon emissions, incinera-
tion of the vapors by direct flame contact may be used. Incinera-
tion and scrubbing systems have also been combined to achieve
maximum control.
On a refinery basis, the hydrocarbon emissions from a
controlled asphalt blowing unit are negligible (AT-040).
Process Drains and Waste Water Separators
Control measures for reducing the evaporative hydro-
carbon emissions from process drains and waste water separators
center around 1) reducing the quantity of hydrocarbons evaporated
and 2) enclosing the waste water systems.
The quantity of hydrocarbons evaporated can first be
reduced by minimizing through good housekeeping the volume of
-101-
-------
oil leaked to the waste water systems. Lowering the temperature
of the waste water will also reduce hydrocarbon evaporation
(AM-055).
Measures for enclosing waste water systems include
manhole covers, catch basin liquid seals, and fixed or floating
roofs for API separators. The potential also exists for some
form of vapor disposal or vapor recovery device in conjunction
with fixed roofs on API separators (EL-033).
Studies of Los Angeles County refineries indicate that
hydrocarbon emissions from controlled waste water systems are as
low as 10 lbs/103bbl of refinery feed (AT-040). On a nationwide
basis and accounting for the existing degree of control, it is
estimated that hydrocarbon emissions from waste water systems
in 1972 averaged 105 lbs/103bbl refinery feed (MS-001).
Cooling Towers
The control of hydrocarbon emissions from cooling towers
is best effected at the point where hydrocarbon contaminants
enter the cooling water. Hence, systems of detection of contamina-
tion in water, proper maintenance, speedy repair of leaks, and
good housekeeping programs in general are necessary to minimize
the air pollution occurring at the cooling tower. In addition,
water that has been used in direct contact condensers should be
eliminated from cooling towers. Greater use of air cooling will
also control hydrocarbon emissions by reducing the size of the
cooling water system (DA-069).
Refineries practicing good housekeeping in Los Angeles
County have succeeded in reducing their cooling tower emissions
to approximately 10 lbs/103bbl refinery feed (AT-040, AM-055).
-102-
-------
5.3.4 Fugitive Source Controls
Although inconspicuous, fugitive hydrocarbon emission
sources are generally significant because of their abundance.
Regular maintenance and good housekeeping are the major control
measures for minimizing fugitive hydrocarbon emissions.
Pumps and Compressor Seals
Pump and compressor seals inherently leak and there are
no practical means for eliminating hydrocarbon emissions from
these sources. As brought out in section 5.2.4 on fugitive
emissions, the emissions from centrifugal pumps with mechanical
seals average 3.2 Ibs/day-seal and from centrifugal pumps with
packed seals average 4.8 Ibs/day-seal. Therefore a 33% reduction
in hydrocarbon emissions from centrifugal pumps may be effected
by installing mechanical seals in place of packed seals. There
are no alternatives to using packed seals on reciprocating pumps.
Dual sets of seals may also be installed with provisions to vent
the volatile vapors that leak past the first seal, into a vapor
recovery system.
Without a doubt, frequent inspection and maintenance
of seals are very important measures for the minimization of
pump and compressor leaks.
Pressure Relief Valves
Hydrocarbon emissions from pressure relief valves are
sometimes controlled by manifolding to a vapor control device
or a blowdown system (DA-069). For valves where it is not
desirable, because of convenience or safety aspects, to discharge
into a closed system, frangible blanks called rupture discs can
-103-
-------
be installed before the valve. Rupture discs serve to prevent
the pressure relief valve from leaking as well as protect the
valve seat from corrosive environments (WA-086).
The hydrocarbon emissions from relief valves controlled
by rupture discs or blowdown systems are negligible.
Pipeline Valves and Flanges
Hydrocarbon emissions originating from product leaks at
valves and flanges can only be controlled by regular inspection
and prompt maintenance of valve packing boxes and flange gaskets.
Because of its dependence on the nature of the products handled,
the degree of maintenance, and the characteristics of the equip-
ment, the emissions reduction from controlling valves and flanges
is undefinable.
Pipeline Blend Changing
Emissions from the changing of blinds can be minimized
by pumping out the pipeline and then flushing the line with water
before breaking the flange. Slight vacuums can be maintained in
the pipeline for the case of highly volatile hydrocarbons. Spill-
age can also be minimized by the use of special "line" blinds
in place of the common "slip" blinds. A survey of Los Angeles
County refineries indicated that spillage from line blinds was
40% of the spillage for slip blinds. In addition combinations
of line blinds in conjunction with gate valves allow changing
of line blinds while the pipeline is under pressure (DA-069).
-104-
-------
Purging Sampling Lines
One means for controlling the hydrocarbon emissions
generated by purging sampling lines is the installation of
drains and flushing facilities at each sample point. Conscious
efforts to avoid excessive sampling in addition to flushing
sample purges into the drain have a significant impact on the
hydrocarbon emissions from sampling operations.
Miscellaneous Emissions
There are several other fugitive emission sources which
are collectively significant but not common to all refineries
and not easily identifiable. The control of these sources is
basically centered around regular inspection, proper maintenance,
and good housekeeping. The efficiency of these control measures
is dependent on the degree to which they are performed and the
nature of the emission sources.
-105-
-------
6.0 GASOLINE MARKETING
6.1 The Industry
The gasoline marketing industry is defined as that
industry concerned with the transfer and storage of gasoline.
This definition includes all transfer and storage operations
that occur in transporting gasoline products from petroleum
refineries to the consumer. These operations represent a signi-
ficant part of the petroleum industry.
6.1.1 Quantity of Products
In 1967, over 80 billion gallons per year of motor
gasoline were distributed through 2,700 marketing terminals
and over 36,000 bulk stations. By 1973 annual U. S. consumption
had grown to over 106 billion gallons, about 70 percent of
which was sold to passenger cars at 212,000 retail service
stations. The remaining 30 billion gallons were sold to
industrial, commercial, and rural customers or to passenger
cars at nonservice station outlets. The combined wholesale and
retail segments of the gasoline marketing industry employ over
700,000 people.
In 1973, 6.7 million barrels per day of motor gasoline
were produced. Table 6.1-1 specifies the number of refineries
and the volume of gasoline produced in each state. Outputs
from these refineries, plus some imported -refined products,
are the sources of supply to the domestic gasoline marketing
network. In addition to motor gasoline, U. S. refineries pro-
duced 45,000 barrels per day of aviation gasoline in 1973,
which is less than one percent of motor gasoline production.
-106-
-------
TABLE 6.1-1
GASOLINE REFINING AND MARKETING FACILITIES
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
D.C.
( Florida
^ Georgia
~-j Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky •
Louisiana
Haine
Maryland
Massachusetts
Michigan
Minnesota
Refineries
1973
4
2
1
4
37
3
0
1
0
. 1
2
1
0
12
7
0
10
4
20
0
2
0
6
3
Gasoline «
Output (b/d)1
1973
1,200
16,700
1.009,479
30.550
73 , 400
. .
11,680
592,950
219,095
190,271
59.400
788,330
57,320
69,910
2
Bulk Stations
1967
449
29
213
526
1.154
72
34
4
546
610
12
366
1,448
993
1,481
841
492
464
142
129
112
1,055
1,282
Terminal;
1967
52
50
17
24
125
60
10
3
79
63
30
23
85
74
49
26
.. 44
58
34'
58
49
87
43
Bulk Stations
_2 and Terminals
6 ~
1967''
501
79
230
550
1.279
452
132
44
7
625
673
42
389
1.533
1,067
1,530
867
536
522
176
187
161
1,142
1,325
V
1972J
518
88
219
535
1,166
366
120
43
7
558
656
32
317
1,324
#65
1,202
663
417
569
163
172
157
1,023
1,012
Service Stations
19 724
4,510
241
2.357
3 . 144
19,153
3.170
2,798
557
318
9,199
6.730'
480
1,193
10.211
6.235
4.484
3.609
3.921
3.921
1.224
3,012
4,698
8.919
4.585
-------
TABLE 6.1-1 (Cont.)
o
CD
GASOLINE REFINING
State
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
N. Carolina
N. Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
S. Carolina
S. Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
W. Virginia
AND MARKETING
Refineries
1973
5
1
8
1
0
0
5
6
2
0
2
7
12
1
11
1
0
0
0
43
6
0
1
6
3
FACILITIES
Gasoline •>
Output (b/d)1
1973
161,400
38.400
68,326
2,200
237,970
18,350
42,100
. '
22,000 •
292.090
253,417
330,435
.1 — •
• .,
14,000
1.795.075
53,400
24,000
161,770
5,650
Bulk Stations
Bulk Stations
1967
448
1,028
589
89
69
147
•230
481
732
634
905
589
504
603
27
368
531
439
1,841
164
61
447
579
160
Terminals
J95T
35
55
19
12
7
89
17
282
114
14'
118
25
28
156
17
46
16
53
118
11
11
87
94
29
and Terminals Service Stations
1967*
483
1,083
413
608
101
76
236
247
763
846
648
1,023
614
532
759
44
414
547
492
1,959
175
72
534
673
189
19723*
427
839
356
471
90
70
218
246
672
771
556
784
594
434
662
36
378
491
439
2,211
155
60
473
541
162
19724
2
6
1
2
5
1
11
6
11
4
2
11
3
1
5
17
1
4
3
2
,725
.280
.190
,265
798
888
,768
.831
.359
,946
910
.723
.153
.828
.256
901
.720
,171
,157
.118
.504
596
,648
.945
.156
-------
TABLE 6.1-1 (Cont.)
GASOLINE REFINING AND MARKETING FACILITIES
State
Wisconsin
Wyoming
Ref ineries
1973
1
9
Output (b/d)1
1973
14,100
67,140
o
Bulk Stations
1967
1.222
2
Terminals
1967
71
Bulk Stations
• and Terminals
19672 19723*
1.293 1.042
192 161
Service Stations
19724
5.182
772
TOTAL •
252
6.722.108
26.338
2.701
29.039 25.531
226.459
o
vo
Source:
API Annual Statistical Review. Petroleum Industry Statistics. 1964-73. p. 33.(AM-099)
21967 Census of Business. Vol. .3. Wholesale Subject Reports. (US-031)
3
1972 Census of Business. Wholesale Trade. Area Statistics.
1972 Census ojf Business, Retail Trade, Area Statistics
-------
6.1.2 Nature of Products
Motor gasolines are blends of petroleum distillates
carefully combined to yield the proper volatility and com-
bustion characteristics for good engine performance. Their
compositions are complex and vary greatly with the sources of
crude oil from which they were distilled and with the types of
conversion processes to which they have been subjected. Gaso-
line compositions also vary greatly because the temperatures
and altitudes at which gasolines are used vary, and the gaso-
line blends must be altered to ensure proper fuel volatility
and car performance at each locale and for each season.
Gasoline is often characterized by Reid Vapor
Pressure (RVP), a technique developed as a means of express-
ing the vapor pressure or volatility of petroleum fractions.
This is an extensively used parameter in the study of hydro-
carbon emissions from gasoline marketing facilities. Figure
6.1-1 (DA-004) correlates Reid Vapor Pressure with true vapor
as a function of temperature. In the absence of distillation
data, the value of S (the slope of the ASTM distillation curve
at 107o evaporation) may be estimated as three for motor gaso-
lines. Seasonal and locational variations, in Reid Vapor
Pressures and several other gasoline characteristics for both
premium and regular grades are presented in Table 6.1-2
(SH-137) and Table 6.1-3 (SH-138). Districts to which these
tables refer are shown in Figure 6.1-2 (SH-137).
Improved refinery processing technology and more
natural gas liquids production have increased the availability
-110-
-------
uj
H
o
to
X
u
z •
u
cc
D
cr
tf
UJ
0.
!ft
O
Z
D
O
0.
z
u
Z
"™* 3 L» 5
— 3.0 - * ,L/f w
•• 1 Ufi 1 QC
JHlj I/ 6 D
"•" ' ' Lfir x tii
«• *' /i 1 1 \/\ *&
- ' • • . W\]f 8 o.
™" " l \ \Jf V 9
~~ 4'° x\v/y I0 o
~ iKi// ' ' °"
"" " MiinL/i 1 2 ^
iwV/ l3
— V\J\/^ 14 ^
— S.O M/i/1 ^
^ ^rtlM
"" ^lUi 1
_ . vri
^. 1
— 6.0
— .
b^.
mm
— 7.0
120 -z
100-r
90 -E
80 -E
—
JH
^
_
70-^
™ ™
,—
^•»
••
60-^
5
—
^'^
50 -E
™
•w
" * *
, —
40 -z
—
r —
*.
^
30-E
S = SLOPE OF THE ASTM DISTILLATION CURVE AT d
1 10 PER CENT EVAPORATED
— 8.0 DEG F AT 15 PER CENT MINUS DEC F
- 10
~ 9.0
= • =
AT 5 PER CENT 20-4
"""
™
IN THE ABSENCE OF DISTILLATION DATA THE FOLLOW- ,n -
ING AVERAGE VALUES OF S MAY BE
— 10.0
MOTOR GASOLINE
AVIATION GASOLINE
— 11.0 LIGHT NAPHTHA (9-14 LB
NAPHTHA (2-8 LB RVP)
— 12.0
— 13.0
— 14.0
USED : :
—
3 ~
2 =
RVP) 3.5 0-^
K
IU
I
Z
Ul
a
i
^
u.'
tf)
Ul
UJ
-------
TABLE 6.1-2
MOTOR GASOLINE SURVEY. SUMMER 1973 AVERAGE DATA FOR
BRANDS IN EACH DISTRICT
PREMIUM-PRICE CASOLINC
DISTRICT NO.
AND NAMC
1 NORTHEAST
2 MiO-ATLANTiC COAST
3 SOUTHEAST
4 APPALACHIAN
5 MICHIGAN
6 NORTH ILLINOIS
7 CENTRAL MISSISSIPPI
6 ICHCA MISSISSIPPI
9 NliHTH PLAINS
10 CENTRAL PLAINS
11 SOUTH PLAINS
12 SUUTH TEXAS
13 SOUTH KO'JSTAtN STATES
1« NCRTM MOUNTAIN STATES
15 PACIFIC NORTHWEST
16 NORTH CALIFORNIA
17 SCUTH. CAl_lrOlN!A
NO. Or
BRANDS
13
17
18
17
U
14
21
19
1*
12
20
15
16
11
9
11
11
SAM-
PLES
58
21*
193
164
10«
41
lo9
147
52
93
133
94
243
137
59
70
91
AVERAGE
Oft.»
ASTM
0287
API
<0.0
59.5
6Q.2
61,4
63.2
«3.3
62.8
do. 5
65.1
65.0
63.3
6Q.8
61.9
64.1
St. 8
57.4
58.2
61.7
suir,
ASTM
0126*
HT *
0.030
.024
.02ft
.019
.024
.028
.021
.034
.040
.035
.024
.019
.025
.034
.008
.011
.034
.026
OUM»
ASTM
cm
HO
0
1
0
1
1
PHOS.
ASTM
03231
Q/flAL
„
0.014
• 003
.004
.001
.003
.000
•»
»
• ooo
.004
.000
.005
• 001
• oot
•flOl
.003
IEAO.
ASTM
0526
C/CAL
2.39
2.43
2.51
2.27
2.31
2.30
2.35
2.59
2.52
2.23
2.69
2.65
2.47
2.24
2.35
2.07
li«!_
2.42
P_£I_ANE Nun £J _
RES.
AST).
C2J«9
99.8
«9.a
99.8
99.5
99.4
99.4
99.3
99. «
99.0
98.9
99.2
99.6
98.1
99.Q
99.1
99. J
_99,L_
99.3
HOT,
ASTM
02700
91.8
91.7
92.0
9J.9
92.1
92.5
92.1
91,9
93.3
91.9
92.5
92.0
91.0
91.8
91.7
91.6
?1.;2_
9J.9
fi*M
•«•!•
2
95.8
»5.7
95.9
95.7
95.8
96.0
95.8
95.8
96.2
95.4
95. 9
95.6
94.6
95.4
95.4
95.5
iliSL
95.6
RVP.
ASTM
0323
IB
10. 1
9.8
9.5
10.3
10.2
10.2
9.4
9.2
9.5
8.8
9.0
.0
.7
.6
1 .2
.7
j.0
.5
20V/L
ASTM
0439
r
133
135
136
132
132
132
tV
138
136
139
139
13S
1«2
136
132
144
>M
137
DISTlLLAttOH. ASTM 086
TEMPERATURE, F (CORRECTED TO 760 HM
iep
69
90
92
89
90
SO
90
89
69
92
91
91
94
87
86
93
9?
90
PERCENT EVAPqRATEO
5 10 20 30 50 70 90 95
100 115 139 166 219 261 327 363
105 119 142 168 219 264 330 36}
106 119 143 169 218 243 32S 362
103 117 141 167 21) 258 32) 314
104 119 143 171 210 250 319 356
103 118 144 170 210 244 320 363
107 120 147 172 212 249 321 36;
106 122 146 171 217 260 331 363
106 121 149 174 209 239 314 358
110 124 147 169 211 2»5 320 365
H8J
EP
4C2
4Q8
435
411
»04
407
40«
«10
3;9
«10
106 123 148 172 215 252 327 365 «C«
1C8 122 144 167 215 258 329 358 4C0
113 128 ISO 173 216 240 336 375 4t4
107 121 147 173 213 247 324 36; 40«
104 116 141 164 212 255 313 341
383
112 131 157 182 225 265 327 356 «03
110_126 150_17!_Z19 J63 32' 36Q 4D3
J07 121 146 171 215 255 325 36i 405
RES LOSS
X 1
1.2 .9
1.1 .r
1.6 .«
1.0 2.2
.9 .
.9 .
.9
1.0 .
1.1 .
1.0 .
1.0 .
1.0 .
.9 .
.9 .0
t.O .0
t.O 1.7
_Ufi_t^6_
1.0 1^7
SAMPLES 2.031
REGULAR-PRICE GASOLINE
DISTRICT NO.
AND NAME
1 NORTHEAST
2 MiO-ATLANTiC COAST
3 SOUTHEAST
4 APPALACHIAN*
5 MICHIGAN
6 NORTH ILLINOIS
7 CENTRAL MISSISSIPPI
8 LCHER MISSISSIPPI
9 NORTH PLAINS
10 CENTRAL PLAINS
it SOUTH PLAINS
12 SOUTH TEXAS
13 SOUTH MOUNTAIN STATES
14 fcCSTH MOUNTAIN STATES
15 PACIFIC NORTHHEST
14 NORTH CALIFORNIA
17 SOUTH CALIFORNIA
AV
NO. Or
BRANDS
12
17
18
17
13
14
20
19
12
12
20
15
16
13
9
11
n
SAM-
PLES
52
209
200
171
1S8
64
107
121
45
83
135
as
232
129
59
72
92
ERASE
OR..
ASTM
0267
API
60.7
60.1
60.2
60.6
59.7
59.6
59.7
60.7
60.6
M.7
61.4
6Q.8
6Q. 2
6Q.9
61.1
58.7
sa.s
Tit'. 3
SULF.
ASTM
01266
MT X
0.040
.037
.037
.037
.047
.048
.039
.044
.050
.045
.033
.032
.042
.050
.017
.033
.046
.040
GUM.
ASTM
0361
MQ
0
1
0
1
2
2
1
0
0
1
1
1
2
1
2
1
. 1
1
PHOS.
ASTM
03231
0/SAL
.
0.007
•
.015
.007
• 001
• 003
•
•
•
• 000
• 004
• 000
• 004
• 000
• 001
• oov
• 004
LEAD,
ASTM
D526
G/GAL
2.21
2.16
2.33
2.12
1.85
1.91
1.86
2.54
2.06
1.83
2.31
2.35
1.92
1.76
2.08
1.53
1 .40
2.01
OCTANE NUMBER
RES.
ASTH
0269'
94.2
94.1
94.1
93.9
94. (
94.1
93.9
93.9
92.7
92.6
93.0
93.6
92.4
93.3
93.0
93.6
93.3
9-3;5"
MOT,
ASTM
02700
87.0
86.7
86.9
66.3
66.2
66.3
86.3
86.8
65.2
65.3
66.3
86.6
85.2
45. 3
86.6
85.2
85.2
16.1
R*M
• •»
2
90.6
90.4
90.5
90.1
90.2
90.2
90.1
90.4
69.0
89.0
89.7
90.2
BS.8
89.3
69.8
69.4
69.3
89.8
RVF.
ASTM
0323
LB
9.8
9.
9.
9.
10.
9.
9,
» •
•
•
6.
9.
10.
8.
8.
9.
20V/L
ASTM
0439
r
132
134
136
133
133
133
136
137
132
139
138
133
J42
135
133
141
JJ9
13^
DISTILLATION. ASTM CS6
TEMPERATURE. F (CORRECTED TO 760 hx HG)
IBP
88
91
92
69
89
92
89
91
90
95
92
93
96
68
90
95
93
91
TAkPLES 2.017
PERCENT EVAPCSATEO
5 10 20 30 50 70 90 95
Ep
102 US 136 156 209 267 340 372 410
107 119 140 161 211 270 347 384
4?n
108 121 142 163 213 273 350 383 «2C
105 116 139 161 209 265 342 38|
1C4 118 140 163 213 267 344 379
422
421
105 118 140 163 212 264 343 382 424
106 119 142 167 217 271 349 386 421
110 122 142 163 209 265 3
-------
TABLE 6.1-3
MOTOR GASOLINE SURVEY. WINTER 1971-72 AVERAGE DATA
FOR BRANDS IN EACH DISTRICT
PREMIUM-PRICE GASOLINE
DISTRICT NO.
AND NAME
1 NORTHEAST
2 MID-ATLANTIC COAST
9 SOUTHEAST
4 APPALACHIAN
5 MICHIGAN
6 NORTH ILLINOIS
7 CENTRAL MISSISSIPPI
6 LOslR MISSISSIPPI
9 NORTH PLAINS
10 CENTRAL PLAINS
it SOUTH PLAINS
12 SPUTH TEXAS
13 SOUTH MOUNTAIN STATES
14 NOPTH MOUNTAIN STATES
15 PACIFIC NORTHWEST
16 NORTH CALIFORNIA
17 SOUTH CALIFORNIA
NO. or
BRANDS
15
IV
20
20
ir
14
21
20
15
21
20
16
16
14
10
11
11
SAM-
PLES
82
267
203
186
106
62
130
135
51
155
140
89
263
112
61
70
94
1 - AVERAGE
OR.,
ASTH
D2B7
API
61.5
61.5
61.5
63.1
63.8
64.3
62.1
62.0
67.7
64.0
63.9
62.0
63.1
66.3
64.0
59.6
56.4
fc?.«
SULF,
ASTH
01266
Mt S
0.021
.024
.016
.021
.017
.026
.024
.029
.041
.032
.026
.0)5
.027
.047
.012
.016
.041
.026
r.UH,
ASTH
t>38i
MG
1
1
1
1
1
1
•
1
•
1
1
1
2
1
1
1
1
1
LEAP*
ASTM
D52*
G/GAL
2.46
2.37
2.5*
2.2ft
2.27
?.?«
2.51
2.ft«
2.3"
2.3"
2.5*
2.5*
2.43
2.24
2.14
2.5?
2.71
2. 43
OCTANT NUHPFR
RES*
ASTH
D2699
100.3
100.4
100.2
100.1
99.6
99.6
99.9
100. 1
99.1
99.6.
99.6
100.0
99.4
99.7
99.9
99.9
100.0
99.8
HOT/
ASTH
02700
92.1
92.4
92.4
92.6
92.6
97.6
92.6
92.3
92.7
92.1
92.9
92.3
91.3
91.7
92.0
92.0
9] .6
92, 3~
fi + M
2
96.2
96.4
96.3
96.5
96.2
96.?
V6.3
96.2
95.9
96.0
96.3
96.2
94.9
95.7
96.0
96.0
95.9
96. 1
RVP.
ASTH
0323
LB
12.7
13.0
11.6
12.9
12.6
12.7
12.5
12.0
12.0
11.4
11.9
11.4
11.3
12.9
12.0
11.4
10.7
12,1
DISTILLATION. ASTH 066
TEMPERATURE* F (CORRECTED to 760 MM
IBP
BO
no
«3
82
M
ra
fll
ft A
62
113
05
(14
86
64
65
87
66
S3
SAMPLES 2*226
PERCINT tVAHOHAIlO
5 10 20 30 50 70 90 95
90 104 124 149 206 257 319 346
91 103 125 151 209 257 323 351
97 107 130 155 207 254 325 353
93 104 126 154 P07 252 319 351
91 104 128 156 2JO 250 320 355
91 107 130 155 210 250 323 354
92 106 132 159 216 259 3?7 358
99 110 132 159 706 25J 322 355
97 113 139 166 209 2«3 31» 34ft
97 1(2 135 160 2|0 250 320 354
99 1|2 136 163 2|3 255 326 363
98 109 131 153 203 250 316 3«5
99 113 137 162 212 256 329 3ft«
95 108 134 162 2)0 244 316 356
96 106 128 152 2C2 2«6 308 338
96 111 136 162 2|1 257 3?2 349
102 117 141 167 216 263 325 356
95 {09 132 158 209 25J 3?1 35J
Her
EP
390
394
397
395
400
400
401
400
3V6
403
406
391
405
3V3
363
39ft
405
3«a
RES LOSS
X X
1.0 2.9
.9 2.9
1.1 2.2
.9 J.2
.9 3.1
.a j.9
.9 2.4
1.1 1.9
.7 2.0
.9 .7
1.0 .8
1.0 .9
1.0 ..7
.9 .3
1.0 2.3
,9 2.6
1 .0 2.1
.9 2.4
REGULAR-PRICE GASOLINE
DISTRICT NO.
AND NAME
1 NORTHEAST
2 MID-ATLANTIC COAST
) SOUTHEAST
4 APPALACHIAN
5 MICHIGAN
6 NORTH ILLINOIS
7 CENTRAL MISSISSIPPI
A LOnER MISSISSIPPI
9 NORTH PLAINS
10 CENTRAL PLAINS
11 SOUTH PLAINS
12 SOUTH TF.XIS
13 SOUTH MOUNTAIN STATES
14 NORTH MOUNTAIN STATE!
15 PACIFIC KPSTHHEST
16 NORTH CALIFORNIA
17 SOUTH CALIFORNIA
NO. OF
BRANDS
15
21
19
24
17
14
20
19
13
21
20
16
16
14
10
11
It
SAM-
PIES
75
277
203
190
115
81
126
131
45
147
134
64
255
137
61
71
92
... . . „, Av-Mi(.r - —..
GR.*
ASTM
0267
API
63.1
62.3
62.1
62.6
62.8
63.3
62.9
63.0
63.3
63.1
63.6
63.6
63.0
62.7
63.9
61.2
60.1
6?77
SULF*
ASTH
01266
XT *
0.039
.039
.043
.034
.033
.056
.036
.039
.066
.045
.041
.027
.043
.062
.024
.031
.095
,044
CUK*
ASTM
D361
MG
1
1
1
1
1
2
•
1
m
i
i
2
2
2
i
1
1
i
LEA"*
AST"
D52*
G/GAL
1.89
1.69
2.1A
1.90
1,7?
1.63
2.01
2.13
1.49
1.93
2.17
2.4ft
1 .6?
1.3«
2.03
1.77
1 .5"
__HCJLA,
RLS*
ASTH
02699
95.2
94.9
94.6
94.8
94.6
94.4
94 .4
94.3
92.4
93.4
93.3
94.4
92.3
93.8
93.4
93.9
03.6
1^68 f94.0
*t Nl'HRFR
MOT*
ASTH
02700
67.5
67.1
66.9
67.1
66.7
66.9
66.9
86.7
84.5
66.4
86.5
87.0
65.6
86.2
07.1
66.0
85.5
86.5
R + M
2
91.4
91.0
90.8
91.0
90.8
90.7
90.7
RVP*
ASTH
D373
LB
12.6
12.6
11.4
12.9
13.0
13.1
12.6
90.5 12.1
86.5
69.9
89.9
90.7
69.0
90.0
90.3
90.0
89.7
12.2
11. 5
11.9
11. 1
11.2
12.9
12.3
tl.l
10.9
90.31 12.1
DISTILLATION. ASTH DB6
TEMPERATURE* F (CORRECTED TO 760 MM
IBP
60
01
83
82
81
A3
62
64
»1
84
85
67
67
64
62
87
68
84
SAMPLES 2*224
PEHCINT EVAPORATED
5 10 20 30 50 70 90 95
93 104 124 146 1«6 257 336 367
92 104 125 148 199 260 340 370
98 109 129 151 199 255 337 369
93 103 124 146 196 256 337 370
90 101 122 146 199 257 337 370
91 104 123 145 196 256 335 367
92 106 126 147 |«9 257 343 376
98 109 127 149 195 252 336 3A9
95 108 129 152 201 260 345 367
99 111 131 152 199 254 332 366
98 110 129 150 200 25i 333 374
99 111 130 150 195 2«6 325 356
100 113 134 155 201 254 338 374
95 106 126 150 199 254 333 371
95 106 125 148 196 2«7 334 373
99 113 135 157 204 256 327 358
101 116 137 159 204 263 3«2 373
96 108 128 153 199 255 336 369
HG)
£P
401
406
405
411
410
406
414
410
414
406
413
3V8
414
4C4
406
401
411
4C6
RES LOSS
X X
1.0 2.5
1.0 2.7
1.1 1.9
1 .0 2.8
.9 2.9
. 2.5
. 2.1
i. .7
.5
.6
.1 .6
.2 .5
.0 .6
.0 2.7
,0 2.2
.9 2.2
.0 2.2
.0 2.1
-------
FIGURE 6.1-2 MAP SHOWING LOCATIONS AND NUMBERS OF SAMPLES FOR THE NATIONAL
MOTOR GASOLINE SURVEY, SUMMER 1973
-------
of low-boiling blending stocks, which has resulted in increased
volatility of motor gasoline. The increase in gasoline volatility
has greatly improved engine performance characteristics. The
increased volatility has, however, made modifications to the
fuel systems of vehicles necessary to prevent vapor lock and
it has also increased evaporative losses. Figure 6.1-3 shows
the trend toward more volatile motor gasolines from 1946-1970.
Aviation gasoline is also composed of blends of
petroleum distillates which are combined under carefully control-
led conditions to yield the proper volatility and combustion
characteristics for reliable airplane engine performance. Quality
control in aviation gasoline is more critical than in motor
gasoline, since engine failure is a more serious problem. The
main quality control parameters are volatility, freezing point,
heat of combustion, and oxygen stability.
6.2 The Gasoline Marketing Network
Figure 6.2-1 shows the basic flow of motor gasoline
from refinery storage to the vehicle refueling stations in
the U.S. marketing network. The flow of aviation gasoline
generally follows this pattern only to the terminal from which
it is transported to an airport for final distribution. In
some cases, however, aviation gasoline may be transported
directly to the airport from the refinery through pipelines.
Gasoline is transported from refinery storage to
terminals by pipelines, tankers and barges, or rail tank cars.
In 1973, pipelines transported over 70% of the gasoline shipped
to bulk terminals.
-115-
-------
13.0
12.0
11.0
10.0
9.0
1 8.0
S 7.0
£ 0'
o
o.
13.0
1 12-°
* 11.0
10.0
9.0
8.0
7.0
,<•,
Winter
Summer
Winter
1945
'50
'55
'60
Premium Grade
Regular Grade
'65
70
FIGURE 6.1-3
Motor Gasoline Volatility Trends
Sourca: U.S. Bureau of Mines. "Petroleum Products Survey," Mineral Industry Surveys (June 1971).
-116-
-------
REFINERY STORAGE
SHIP, RAIL, BARGE
BULK TERMINALS
TANK TRUCK
PIPELINE
SERVICE STATION
AUTOMOBILES, TRUCKS
BULK PLANTS
FIGURE 6.2-1
The Gasoline Marketing Distribution System
In The United States
-117-
-------
Bulk stations are intermediate distribution points
in the marketing network. Gasoline from 8,000-gallon terminal
transports is unloaded into storage tanks at the bulk stations,
then reloaded into smaller tank trucks, usually in the
2,000-gallon category, for distribution to service stations
and to commercial and rural users. In many areas, gasoline
is delivered directly from terminals to service stations.
Table 6.1-1 lists the number of wholesale marketing facilities
in each state. Gasoline is unloaded into underground storage
tanks at the more than 300,000 domestic service stations and
other gasoline retail outlets.* Table 6.1-1 lists the number of
service stations in each state. Sizes of service stations
vary widely, from 5,000 to 500,000 gallons per month of gasoline
dispensed. Average service station size is about 30,000
gallons per month. Other gasoline retail outlets range from
2,000-3,000 gallons per month to as much as 150,000 gallons
per month.
Sizes, numbers, and operations of marketing terminals,
bulk plants and service stations are described in more detail
in the following sections. The main sources of hydrocarbon
emissions from these facilities will be briefly mentioned.
Later sections will address emissions in a more detailed manner.
*A service station is defined as a retail outlet with more than
507o of its dollar value coming from the sale and service of
petroleum products. Retail outlets not meeting this definition
are grouped together as "other gasoline retail outlets" or
"nonservice station" outlets.
-118-
-------
6.2.1 Bulk Terminals
The primary distribution facility in the gasoline
marketing network is the bulk terminal. Gasoline products
arrive at the bulk terminal by pipeline and are stored in large
above-ground storage tanks. From these storage tanks the
gasoline is loaded into tank trucks and transported to smaller
bulk loading stations and to service stations. One million
gallons of gasoline may pass through one of the larger bulk
terminals daily.
Statistics from the 1967 Census of Business show
that there were 2,701 terminals in that year. Total national
liquid storage capacity of motor gasoline at terminals was
6.2 billion gallons with an average capacity of 2.3 million
gallons per terminal (US-031).
Generally, the gasoline storage tanks are large
enough that they are subject to regulations requiring that
they be equipped with floating roofs. Hydrocarbon emissions
from tanks of this design are limited to vapors escaping past
the wall seals and to gasoline evaporating from the wetted
walls as the liquid level is lowered. These minor hydrocarbon
emissions are generally less than 0.3 gallons/1,000 gallons
handled (DU-001). Table 6.2-1 contains a compilation of the
nation's bulk storage capacities as a function of tank size
(US-031).
Hydrocarbon emissions from the tank truck loading
racks are potentially much greater than those from the storage
tanks at bulk terminals. As the empty tank trucks are filled,
the hydrocarbons in the vapor space are displaced to the atmo-
sphere, unless vapor collection facilities have been provided.
-119-
-------
TABLE 6.2-1
U.S. BULK STORAGE CAPACITY BY TANK SIZE
(US-031)
Storage Capacity
Tank Size (10y gal)
Less than 42,000 gallons 95,975
42,000 - 62,000 gallons 242,837
63,000 - 83,000 gallons 249,542
84,000'- 104,000 gallons 137,078
105,000 - 209,000 gallons 214,148
210,000 - 1,049,000 gallons 186,960
1,050,000 - 2,099,000 gallons 221,792
2,100,000 - 6,299,000 gallons 1,386,821
6,300,000 - 20,999,000 gallons 2,357,165
Greater than 21,000,000 gallons 2,120,770
-120-
-------
The quantity of hydrocarbons contained in the displaced vapors is
dependent on the Reid Vapor Pressure, temperature, method of tank
filling, and the conditions under which the truck was previously
loaded. Emission factors have been developed to estimate the
quantity of hydrocarbon emissions from loading operations. Figure
6.2-2 is a schematic drawing of liquid and vapor flow through a
typical bulk terminal.
6.2.2 Bulk Stations
Bulk loading stations are secondary distribution
facilities which receive gasoline from bulk terminals by large
tank trucks, store the gasoline in somewhat smaller above-
ground storage tanks, and subsequently dispense the gasoline
via smaller tank trucks to local farms, businesses, and service
stations. The 1967 Census of Business indicates that there
were 26,338 bulk stations in that year. Liquid storage capacity
of gasoline at bulk stations was 1.0 billion gallons with an
average capacity of 40,000 gallons per bulk station (US-031).
Hydrocarbon emissions in bulk stations are generated
from the storage tanks and from the tank truck loading operations.
Emission factors mentioned previously for the loading of tank
trucks at bulk terminals also apply to the hydrocarbon emissions
generated during the loading of gasoline at bulk loading stations.
Because the storage tanks are often horizontal and
cannot be fitted with floating roofs, or because they are
below the size at which floating roof regulations apply, the
storage tanks at bulk loading stations are generally uncon-
trolled and are thus a significant source of hydrocarbon emissions.
The emissions from bulk station storage tanks may be di-
vided into two categories: breathing losses and working losses. Breath
ing losses are associated with the thermal expansion and contraction
-121-
-------
Pipeline Gasoline
to Storage
Storage Tank(s)
Loading Vapors
to Recovery Unit
1
n
Terminal
o o
o
oad-
Gasoline to
Loading
Rack
^
| Storage Vapors to
, Recovery Unit
Vent Gas
T
Vapor
Recovery
Unit
Recovered
Gasoline
t
In terminals using floating roof tanks, vapor lines from storage tanks
to the vapor recovery unit are not required for the control of storage
tank vapor losses.
FIGURE 6.2-2
Vapor and Liquid Flow in a Typical Bulk Terminal
-------
of the vapor space resulting from the daily temperature cycle.
Working losses are associated with changes in the liquid level
of the tank. Although the magnitude of these hydrocarbon
emissions is dependent on numerous factors including tank param-
eters, Reid Vapor Pressure and weather conditions, they can be
estimated by applying appropriate emission factors. Figure
6.2-3 is a schematic drawing showing vapor and liquid flow through
a typical bulk plant.
6/2.3 Service Stations
In 1973 there were 218,000 service stations (NA-168).
A gasoline service station is defined by the U. S. Department
of Commerce as a retail outlet with more than 50% of its dollar
volume coming from the sale and service of petroleum products.
As described in the following section on marketing trends, the
total number of gasoline service stations is undergoing rapid x
change. A survey conducted in May and June 1974, by Audits and
Surveys Inc., a New York, firm reveals that in 1974 there are
196,000 U. S. service stations, a total which is down 9.170
from their 1973 survey figure of 216,000 (AU-020).
Detailed breakdowns of service station sizes as
functions of sales volumes are difficult to obtain due to the
reluctance of oil companies to make this information public.
In 1973, average monthly service station throughput was 30,800
gallons per month according to an estimate by Lundberg Survey
Inc. (LU-044).
An EPA analysis of service station sales statistics
from the 1967 Census of Business reveals the following totals
for the number of stations in various size categories (MA-314).
-123-
-------
Vapor, to Recovery Unit*
Vent Gas
Vapor
Recovery
Unit
Vapor Displaced* j
to Transport
Terminal
J Transport
O Q
Storage
rank(s)
jlecpvered Gasoline
: j •*• Vapor Return
. to Storage
rank
Iruck
Gasoline to
Storage
Gasoline
to Truck
D O
•jt
Vapor emissions 'from bulk plants may potentially be controlled
by vapor displacement, in which case the recovery unit would
be eliminated.
FIGURE 6.2-3
Vapor and Liquid Flow in a Typical Bulk Plant
-------
Service Station Sizes Number Stations
Gallons/Year Sold ' in 1967
Less than 150,000 • 54,100
150,000-200,000 17,100
200,000-250,000 21,200
250,000-300,000 25,500
Larger than 300,000 98,100
216,000
Service stations are the final facility in the
gasoline marketing network. At the stations, gasoline is
received by tank truck, stored in underground tanks, and dis-
pensed to automobile fuel tanks. Unless a vapor collection
system is provided, hydrocarbons in the storage tank vapor
space are displaced as the tank is filled with gasoline from
the tank truck. The quantity of these emissions is dependent
on filling rate, filling method, Reid Vapor Pressure, and the
system temperature.
Breathing losses from the underground gasoline storage
tanks are another source of hydrocarbon emissions. The losses
from underground service gasoline storage tanks has been esti-
mated at 1 lb/1,000 gallons throughput (CA-155). Because the
tanks are underground, breathing losses due to diurnal tempera-
ture effects are minimized.
Automobile refueling is the final source of hydro-
carbon emissions from gasoline marketing operations. As with
the filling of tank trucks or underground storage tanks, the
hydrocarbon emissions are generated from gasoline vapors
which are displaced as the fuel tank is filled. As previously
mentioned, the quantity of these hydrocarbon emissions is de-
pendent on the temperature and the Reid Vapor Pressure of the
fuel. The uncontrolled emissions have, however, been estimated
-125-
-------
to be about 11 Ibs/1,000 gallons of gasoline throughput. Figure
6.2-4 is a schematic drawing of vapor and liquid flow through a
typical service station.
6.3 Industry Trends
6.3.1 U. S. Gasoline Consumption
In 1973, U. S. consumption of gasoline was 106 billion
gallons, a 4.7 percent increase over 1972 consumption. As in-
dicated in Figure 6.3-1, the number of gallons of gasoline con-
sumed annually between 1968 and 1973 has increased steadily
with an average annual increase of 5.2%. This increase may be
attributed to two factors: (1) an increase in the number of
vehicles on the road, and (2) a gradual increase in the number
of miles traveled per vehicle combined with an accompanying
decrease in the number of miles achieved per gallon through
1973 model automobiles.
America, a mobile society, has become increasingly
more dependent on the automobile as a means of transportation
in the last two decades, This trend is demonstrated by the
steady growth in annual consumption of energy by automobiles
as compared with a comparable decrease in energy consumption
by public transportation (CI-005). Current statistics reflect
that eight out of ten American household own at least one car
and three out of ten own two cars (FO-027).
Roughly 13 million new drivers have been registered
and 17 million motor vehicles have been added to U. S. roads
since 1969. A state-by-state breakdown of these figures as
compared with gasoline consumption is given in Table 6.3-1.
-126-
-------
ND
~-J
I
T
Underground Tank
.*- Vent Line
Displaced Vapors
to Tank Truck |
Terminal
Transport or
Tank Truck
*~ ~7
o o o
Gasoline to
Storage "*"
\
Gasoline
Dispenser
_
Dispensed
Gasoline ->•
to Vehicle
Underground
Storage
f Tank
-
t
1
0 0
FIGURE 6.2-4
Vapor and Liquid Flow in a Typical Service Station
-------
(0
c
o
r-l
r-4
fl
60
U-l
O
(0
C
O
110
105
100
95
90
85
.80
FIGURE 6.3-1
U.S. GASOLINE CONSUMPTION
1968 1969 1970 1971 1972 1973 1974
SOURCE: NPN Mid-Ma^ Factbook. 1968-74.
-128-
-------
TABLE 6.3-1
GASOLINE CONSUMPTION BY STATE
STATE
ALABAMA
ALASKA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
CONNECTICUT
DELAWARE
DISTRICT OF
COLUMBIA
FLORIDA
GEORGIA
HAWAII
IDAHO
ILLINOIS
INDIANA
IOWA
KANSAS
KENTUCKY
LOUISIANA
POPULATION
1972
3,510,000
325,000
1,945,000
1,978,000
20,468,000
2,357,000
3,082,000
565,000
748,000
7,259,000
4,720,000
809,000
756,000
11,251,000
5,244,000
2,883,000
2,257,000
3,299,000
3,693,000
REGISTERED MOTOR
1972
2,227,293
148,756
1,301,870
1,070,295
12,852,228
1,679,702
1,860,385
322,971
259,492
4,835,986
2,959,454
447,409
549,834
5,643,853
2,908,543
1,917,075
1,691,501
1,967,620
1,942,263
1973
(estimated)
2,363,000
161,000
1,418,000
1,096,000
13,445,000
1,805,000
1,939,000
341,000
252,000
5,131,000
3,157,000
473,000
596,000
5,867,000
2,959,000
1,985,000
1,818,000
2,106,000
2,069,000
VEHICLES2
7o Increase
6.1
8.2
8.9
2.4
4.6
7.5
4.2
5.6
-2.9
6.1
6.7
5.7
8.4
4.0
1.7
3.5
7.5
7.0
6.5
GASOLINE CONSUMPTION2
Add
1972
1,811,609
122,639
1,105,586
1,175,865
10,128,458
1,300,450
1,336,043
292,733
243,253
3,956,142
2,688,489
267,245
463,143
4,852,112
2,767,014
1,673,848
1,450,625
1,633,516
1,704,022
000 gal.
1973
1,901,914
135,754
1,211,826
1,124,473
10,425,236
1,362,836
1,359,316
308,648
259,339
4,379,689
3,082,334
276,736
481,714
5,063,378
2,867,475
1,821,011
1,433,253
1,760,172
1,793,721
"L Increase
5.0
10.7 .
9.6
4.6
2.9
4.8
1.7
5.4
6.6
10.7
14.6
3.6
4.0
4.4
3.6
8.8
-1.2
7.8
5.3
-------
TABLE 6.3-1 (Cont.)
LO
O
GASOLINE CONSUMPTION BY STATE .
POPULATION1 . REGISTERED MOTOR VEHICLES2
STATED
MAINE
MARYLAND
MASSACHUSETTS
MICHIGAN
MINNESOTA
MISSISSIPPI
MISSOURI
MONTANA
NEBRASKA
NEVADA
NEW HAMPSHIRE
NEW JERSEY
NEW MEXICO
NEW YORK
N. CAROLINA
N. DAKOTA
OHIO
OKLAHOMA
OREGON
1972
1,029,000
4,056,000
5,787,000
9,082,000
3,860,000
2,250,000
4,753,000
719,000
1,525,000
527,000
771,000
7,367,000
1,065,000
18,366,000
5,214,000
632,000
10,739,000
2,634,000
2,182,000
1972
564,782
2,130,458
2,821,596
5,010,537
2,368,127
1,249,152
2,618,164
584,116
1,080,885
399,046
436,158
3,858,631
710,765
7,006,452
3,219,776
463,622
6,224,278
1,887,210
1,496,115
1973
(estimated)
582,000
2,272,000
2,944,000
5,187,000
2,499,000
1,313,000
2,719,000
652,000
1,141,000
428,000
468,000
4,094,000
758,000
7,113,000
3,456,000
489,000
6,359,000
1,978,000
1,619,000
GASOLINE CONSUMPTION2
Add 000 fial.
% Increase
3.0
6.6
4.3
3.5
5.5
5.1
3.9
11.6
5.6
7.3
7.3
6.1
6.6
1.5
7.3
5.5
2.2
4.8
8.2
1972
525,300
1,785,969
2,290,313
4,585,129
2,109,913
1,204,810
2,667,902
457,792
917,215
374,164
393,322
3,188,965
660,638
6,056,144
2,767,481
429,682
4,982,198
1,666,744
1,198,744
1973
543,737
1,852,382
2,360,033
4,774,714
2,155,860
1,237,932
2,742,295
474,804
936,994
390,979
405,147
3,266,842
702,265
6,318,982
2,874,027
436,977
5,286,197
1,729,329
1,247,483
% Increase
3.5
3.7
3.0
4.1
2.2
2.7
2.8
3.7
2.2
4.5
3.0
2.4
6.3
4.3
3.8
1.7
6.1
3.8
4.1
-------
TABLE 6.3-1 (Cont.)
u>
GASOLINE CONSUMPTION BY STATE
POPULATION1 REGISTERED MOTOR
STATE
PENNSYLVANIA
RHODE ISLAND
S. CAROLINA
S. DAKOTA
TENNESSEE
TEXAS
UTAH
VERMONT
VIRGINIA
WASHINGTON
W. VIRGINIA
WISCONSIN
WYOMING
U.S. TOTAL
SOURCES: l
1972
11,926,000
968,000
2,665,000
679,000
4,031,000
11,649,000
1,126,000
462,000
4,764,000
3,443,000
1,781,000
4,520,000
345,000
208,232,000
Statistical
1972
6,311,330
536,284
1,497,389
462,613
2,293,635
7,315,711
740,507
261,295
2,602,773
2,242,060
873,606
2,378,836
273,608
118,506,048
Abstract of the
1973
. (estimated)
6,655,000
566,000
1,608,000
484,000
2,439,000
7,708,000
789,000
273,000
2,815,000
2,379,000
919,000
2,500,000
291,000
124,478,000
U.S., Table 13
VEHICLES2
GASOLINE CONSUMPTION2
Add
% Increase 1972
5.4
5.5 ,
7.4
4.6
6.3
5.4
6.5
4.5
8.2
6.1
5.2
5.1
6.4
5.0
4,811,065
413,405
1,412,207
470,521
2,129,984
7,093,777
689,017
243,508
2,409,315
1,648,222
736,772
2,212,202
288,912
101,685,524'
, "Population- S tate s :
000 gal.
1973 '
4,874,664
415,762
1,478,414
. 479,785
2,296,340
7,497,154
706,166
246,285
2,611,693
1,730,908
778,359
2,155,014
309,244
106,474,172
1960-1972".
'L Increase
1.3
.6
4.7
2.0
7.8
5.7
2.5
1.1
8.4
5.0
5.6
2.7
7.0
4.7
NPN Mid_-Ma£ Factbook. 1974. (NA-168).
-------
In addition to increased dependence on the automobile,
gasoline demand has been affected by a loss of fuel economy in
recent years. In 1963 the average passenger car got 14.4 miles
per gallon; in 1973 this figure was estimated to be 13.3 miles
per gallon (NA-168). This decrease in fuel efficiency has been
attributed to the increased weight of automobiles, the increased
prevalence of accessory items such as air conditioning, power
steering, automatic transmissions, and emission control devices
on post-1970 model cars. The use of the catalytic converter
as an emission control device will affect the number of miles
per gallon. It is expected that future cars will be equipped
with catalytic converters. It will not yet be possible to assess
the impact of catalytic converters on overall gasoline consump-
tion, however. Future fuel economy measures would include an
increased production of lighter cars and cars with smaller engines
The increase in the average number of gallons con-
sumed by passenger cars between 1969 and 1973 is indicated in
Table 6.3-2. An increase in the average number of miles traveled
is also shown. Fuel efficiency for cargo vehicles has remained
relatively constant.
6.3.2 Gasoline Marketing Facilities
Bulk Terminals and Bulk Stations
Although 1972 Census of Business figures are not yet
available, state totals published to date indicate that gasoline
was being distributed in 1972 through fewer bulk stations and
terminals than in 1967 (see Table 6.1-1). Direct contact with
-132-
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TABLE 6.3-2
AVERAGE FUEL CONSUMPTION 1969-1973
AVERAGE MILES TRAVELED/ AVERAGE FUEL CON -
VEHICLE SUMPTION/VEHICLE
Passenger Cars All Vehicles Passenger Cars All Vehicles
1969
1970
1971
1972
1973
9,782 9,969
9,978 10,076
10,121 10,198
10,184 10,370
10,184 10,370
SOURCE: U.S. Dept.
Statistics
718
735
746
755
766
821
830
838
859
864
AVERAGE MILES/
GALLON OF FUEL
Passenger Cars All Vehicles
13.6
13.6
13.6
13.5
13.3
12.15
12.14
12.16
12.07
12.07
of Transportation, Federal Highway Administration, Highway
, 1969-72; 1973 - NPN Mid-May Factbook, 1974. (NA-168) , and
Radian estimates.
-------
oil companies and industry associations has confirmed this
preliminary assessment and indicated that the reduction is
primarily in the number of bulk stations. These contacts have
indicated that there is a current trend toward phasing out bulk
stations for economic reasons. More gasoline deliveries xvill be
made directly from terminals with large tank trucks; less from
the disappearing bulk stations with small trucks. Storage
volumes will be added at terminals to compensate for bulk
station reductions. The decrease in number of bulk stations
will not necessarily have a major impact on overall marketing
operations, however.
Again, without the benefit of complete 1972 statistics,
it is presumed that the combined sales volume at bulk stations
and terminals has increased at a rate commensurate with the
steady increase in gasoline consumption.
Service Stations
Two trends are evident when looking at gasoline market-
ing operations at service stations during the last five years:
(1) retail sales have increased
(2) the total number of service stations
has decreased
These trends are charted in Figure 6.3-2.
National Petroleum News has documented the decline
in service station construction. In 1973, the average oil
company closed 750 stations and opened 97 (NA-168). The 1974
survey by Audits and Surveys Inc., confirms the continuation of
-134-
-------
o
o
wo
Or-4
H
>p
co
!3
O
H
CO
230
225
220
215
210
205
80
75
70
65
60
55
50
45
1968 1969 1970 1971 1972 1973 1974
•— Retail Sales
— No. of Stations
FIGURE 6.3-2
Marketing Trends at Gasoline Service Stations
O
CO
CQ
Source: NPN Mid-Ma^ Factbook, 1974 (NA-168)
-135-
-------
this trend in 1974 as previously mentioned. A review of selected
major and independent oil company 1973 annual reports reinforces
this picture. Operational policy for all companies reviewed
included a program of closing those stations considered econom-
ically marginal. New construction programs are underway, however,
to meet intensive growth demands.
Accompanying the decline in the number of service
stations has been an increase in throughput per station to
accommodate the increased volume of gasoline consumption nation-
ally. As indicated in Table 6.3-3, passenger car gasoline sales
have increased from 58.1 billion gallons in 1968 to an estimated
75.8 billion gallons per year in 1974. Service station dollar
sales show an accompanying increase during this period.
-136-
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TABLE 6.3-3
NUMBER OF GASOLINE SERVICE STATIONS AND SALES VOLUME
Year
1968
1969
1970
1971
1972
1973
19742
Source
1968 - 1974
Annual Nat ' 1 Passenger Average Passenger Car 7o Increase
Car Sales Sales/Station Total Sales In Sales
Stations (Millions of Gallons) (Gallons/Month) (Billions of Dollars) (Dollars)
219,100
222,000
222,000.
220,000
220,000
218,000
212,000
: NPN Mid-May
58,127 22,100
62,047 23,300
65,297 24,500
68,821 26,100
73,121 27,700
75,842 29,000
75,842 29,800
Factbook, 1974 (NA-168) .
24.5
25.9 5.7
28.0 8.1
29.2 4.3
31.0 6.2
34.4 11.0
37.5 9.0
Gasoline service stations are defined as retail outlets with 507. or more
of dollar volume coming from sale and service of petroleum products.
1974 figures are NPH estimates.
-------
6.4 Emissions
•
The gasoline marketing industry contributes hydro-
carbon compounds to the atmosphere through the mechanism of
evaporation during the many handling processes involved in
transferring gasoline from the refinery to the automobile. In
studying these evaporation losses it is important to assess the
nature and magnitude of the problems associated with hydrocarbon
emissions. Although the hydrocarbons from gasoline marketing
do not contribute directly to smog and its adverse effects,
several of the hydrocarbons do undergo reactions to form
products which do produce undesirable smog. This section
reviews the quantity of atmospheric hydrocarbons contributed
by the gasoline marketing industry, the direct and indirect
adverse effects of such hydrocarbon emissions, and the seasonal
.characteristics of these contributions.
6.4.1 Quantity of Hydrocarbon Emissions
In bulk terminal, bulk plant, or service station
operations, the vapors displaced by the liquid during tank fills
contains hydrocarbons which are emitted to the atmosphere.
The quantities of these emissions are variable, depending on
such factors as the Reid Vapor Pressure of the gasoline, the
method of loading, the temperatures of the vapors, and the ef-
fects of geographical and meteorological conditions.
There are two basic categories of emissions which
will be discussed for each facility of the marketing network;
uncontrolled and controlled emissions. The term uncontrolled
emissions will be used to refer only to the worst predicted
case for each facility. There may be several cases comparing
controlled emissions for each facility, however, due to the
-138-
-------
variety of operations .at each facility which affect the quantity
of hydrocarbon emissions and which may be controlled.
Emission factors* published by the Office of Air and
Water Programs, U.S.E.P.A., July 1973, are used in the estimation
of hydrocarbon emissions from gasoline marketing. Because these
factors are based on throughputs of gasoline, flow rates through
the gasoline marketing network had to be defined for calculational
purposes. The bases of throughput definitions are as follows:
(1) Gasoline from Refineries to Terminals -•
Total domestic gasoline usage from
Table 2.0-2 was used with the assumption
that all gasoline was distributed
through a terminal.
(2) Gasoline from Terminals toBulk Stations -
\ •
The ratio of bulk storage to terminal
storage capacity (0.16) as reported in the
1967 Census of Business (US-031) was
used to determine the amount of gasoline
going to bulk stations.
(3) Gasoline from Terminals to Service Stations -
The difference between total flow to
terminals and gasoline flow to bulk
stations was defined as the gasoline flow
to service stations,
(4) Gasoline Distributed from Service Stations
and Bulk Stations
Data from the Bureau of Public Roads,
U.S. Department of Transportation
-139-
-------
(US-143) was used. It was assumed that all
fuel consumed by passenger cars, motor-
cycles, and single unit trucks was
distributed through service stations while
the remainder was distributed through
bulk stations.
These definitions resulted in gasoline flow rates through each
marketing facility as depicted in Figure 6.4-1.
6.4.1.1 Bulk Terminals
Emission Sources
The main bulk terminal emission sources are storage
tanks and loading operations. Emissions from each of these
sources will be considered separately,
Storage Tank Losses
Two basic types of tanks are used in terminals:
fixed roof tanks and floating roof tanks. Each of these basic
tank designs may, however, have several modifications associated
with it.
Fixed Roof Tanks
Fixed roof tanks are subject to both breathing and
working losses. Breathing losses are associated with expansion
and contraction of the vapor space resulting from the daily
temperature cycle. Working losses are associated with changes
in the liquid levels in the tanks.
-140-
-------
From Refinery
Storage
6718
Bulk
Terminals
5605
Service
Stations
467
6072
45
Airport
Distributior
1068
.2.
Bulk
Stations
601
FIGURE 6.4-1
Gasoline Flow Through the Marketing Network
(All flows in 103bbl/day)
-141-
-------
Floating Roof Tanks
Emissions from floating roof tanks come primarily
from two sources: standing storage losses and wetting losses.
Standing storage losses result from the improper fit of the seal
and shoe to the tank shell and are the principal source of
emissions of floating roof tanks. Wetting losses occur when a
wetted tank wall is exposed to the atmosphere, but these are
generally negligible.
Loading Operation Losses
During the loading operation vapor in the transport
truck is displaced into the atmosphere as it is being filled
from terminal storage. The amount of emissions generated is
dependent primarily upon the type of loading operation.
There are two basic methods of filling transport tanks:
top loading and bottom loading. The top loading procedure can
be done with splash fill or submerged fill. With splash loading,
gasoline is discharged into the upper part of the tank compart-
ment through a short spout which never dips below the surface of
the liquid. The free fall of the gasoline droplets promotes
evaporation and may even result in liquid entrainment of some
gasoline droplets in the expelled vapors.
With subsurface or submerged loading, gasoline is
discharged into the tank compartment below the surface of liquid
in the tank. This is accomplished for top loading operations
by the use of a long spout or fixed pipe extending internally
from the top tank entry to the bottom of the compartment. With
direct bottom loading, transfer piping is connected directly to
the tank bottom. This method achieves the same effect as sub-
merged top loading while providing other advantages such as
-142-
-------
ease of loading operations and safety. Consequently, many
terminals have already been converted to bottom loading.
It should be noted that hydrocarbon emission levels
from loading operations are partly influenced by the transports
previous operation. If low volatility products were transported
previously, or the transport was purged of hydrocarbon vapor
prior to loading, the hydrocarbon emissions from gasoline loading
may be significantly lower.
Emission Factors
The following emission factors were used to estimate
hydrocarbon losses from bulk terminals (EN-071).
Storage Losses
Predicted Loss
Tank Type (Ib/day per 1000 gal capacity)
Fixed Roof
1. Breathing Losses
New Tanks 0.22
Old Tanks 0.25
2. Working Losses 9.0 Ib per 1000 gal throughput
Floating Roof
New Tanks 0.033
Old Tanks 0.088
Loading Losses
Predicted Loss
Type Loading (Ib per 1000 gal transferred)
Splash Loading 12.4
Submerged Loading 4.1
-143-
-------
Predicted Emissions
The following hydrocarbon emissions from U.S. bulk ter-
minals are predicted using the gasoline throughputs and storage
capacities as previously defined (6.7 million barrels per day
throughput with storage capacity of 148 million barrels).
The worst case, or total uncontrolled hydrocarbon emis-
sions from U.S. bulk terminals results in expected emissions of
1.37 million tons/yr of hydrocarbons. This hypothetical case
constitutes one for which all terminals would employ old fixed
roof tanks and splash filling operations. The best control
case, assuming no secondary vapor recovery facilities, results in
calculated hydrocarbon emissions of 0.25 million tons/yr. This
case represents a situation in which all U.S. bulk terminals
employ new floating roof tanks and submerged filling operating.
Further control of hydrocarbon emissions is possible
with the installation of secondary vapor recovery units. There
are several units commercially available today which are claimed
to achieve 9070 control of all collected hydrocarbon vapors.
*
These units, depending on their size, are used in re-
covering vapors from either storage or loading operations or both.
Generally, however, they are now being used to control emissions
from loading operations. Floating roof tanks are in wide use in
marketing terminals today, and these do not normally require
secondary recovery.
Table 6.4-1 presents a comparison of the expected emis-
sions from each type of storage tank and loading operation. Table
6.4-2 presents a summary of expected emissions for eight different
cases of tankage and loading operations of U.S. bulk terminals, with
uncontrolled emissions ranging from the worst case to the best case
(described above). Included on the table also are the predicted
emissions where vapor recovery units are added to capture emissions
during loading operations.
-144-
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TABLE 6.4-1
PREDICTED HYDROCARBON EMISSIONS FROM
U.S. BULK TERMINAL SOURCES*
Emission Emissions
Source (tons/year)
(1) Fixed Roof Tanks
Old Tanks 7.4 x 10s
New Tanks 7.1 x 10s
(2) Floating Roof Tanks
Old Tanks 9.98 x 10"
New Tanks 3.73 x 10*
(3) Splash Loading Operations 6.34 x 10s
(4) Submerged Loading Operations 2.09 x 105
*Basis of Calculations
148 million barrel storage capacity
6.7 million barrel/day throughput
-145-
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TABLE 6.4-2
CASE COMPARISON OF PREDICTED HYDROCARBON EMISSIONS FROM U.S. BULK TERMINALS
Predicted Percent Reduction Predicted' ' Percent Reduction^ '
Emissions Of Uncontrolled Emissions Of Uncontrolled
Terminal Operating Conditions (LQ6 tons/yr) Emissions (L06tons/yr) Emissions
Case I - Uncontrolled
Old fixed roof tanks & 1.37 - 0.80 42
splash loading
Case II
New fixed roof tanks & 1.34 2 0.77 44
splash loading
Case III
Old fixed roof tanks & 0.95 31 0.76 45
submerged loading
Case IV
New fixed roof tanks & 0.92 33 0.73 47
submerged loading
Case V
Old floating roof tanks 0.73 47 0.16 88
& splash loading
Case VI
New floating roof tanks & 0.67 51 0.10 93
splash loading
Case VII
Old floating roof tanks & 0.31 77 0.12 91
submerged loading
Case VIII
New floating roof tanks & 0.25 82 0.06 96
submerged loading
(1) Emissions assume a 9070 efficient vapor recovery unit installed to capture loading emissions.
(2) Based on emissions calculated by assumption (1).
(3) Percent reduction is referred to predicted emissions for Case I,without a vapor recovery unit
-------
6.4.1.2 Bulk Stations
Emission Sources
Hydrocarbon emissions from bulk plants are also
generated from storage tanks and from tank truck loading opera-
tions. Because storage tanks typically found at bulk plants
s
are relatively small, the use of floating roof tanks is not
common. In many cases horizontal tanks which cannot be fitted
with floating roofs are used, and in others the tanks are not large
enough to be subject to regulations. Therefore, only fixed
roof tanks will be considered in the compilation of emissions
from bulk plants.
As in terminal operations, both splash and submerged
loading operations are used in bulk stations. Loading losses
were estimated for each type of operation.
Emission Factors
The same emission factors used to estimate storage
and loading losses for terminals are also applicable to bulk
station operations.
Predicted Emissions
Hydrocarbon emissions from U.S. bulk stations are pre-
dicted using the gasoline throughputs and storage capacities
as previously defined (1.1 million barrels per day throughput
with storage capacity of 24 million barrels).
-147-
-------
The worst hypothetical case (total uncontrolled hydro-
carbon emissions) for U.S. bulk stations results in calculated
emissions of 220 thousand tons/year of hydrocarbons. This case
constitutes one for which all terminals employ old fixed roof
tanks and splash filling operations. The best control case, as-
suming no recovery of displaced vapors, results in expected
hydrocarbon emissions of 145 thousand tons/year. This case
represents a situation in which all bulk stations employ new fixed
roof tanks and submerged filling operations,
Further control of hydrocarbon emissions from bulk
stations may be accomplished with the installation of a vapor
recovery system. It is likely that any vapor recovery system
designed for a bulk station will be designed to recovery emissions
from both storage and loading operations as there are generally
no existing controls on these storage operations. It is also
feasible that a properly designed, simple displacement system
will provide effective control of hydrocarbon emissions from
bulk stations. Hydrocarbon emissions controls, other than through
the use of submerged filling, are generally not practiced in
U.S. bulk stations today.
Table 6.4-3 presents a summary of expected emissions
»
for the different cases of tankage and loading operations of
U.S. bulk stations.
6.4.1.3 Service Stations
Emission Sources
Emissions of hydrocarbons at service stations come
from loading losses from underground tanks, refueling losses
from vehicle tanks, and breathing losses from the underground
tank vent.
-148-
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TABLE 6.4-3
PREDICTED HYDROCARBON EMISSIONS FROM U.S. BULK STATIONS
vo
i
Bulk Station Operating
Conditions
Case I - Uncontrolled
Old fixed roof tanks
splash loading
Case II
New fixed roof tanks
splash loading
Case III
Old fixed roof tanks
submerged loading
Case IV
New fixed roof tanks
submerged loading
Predicted
Emissions
(103 tons/yr)
(3)
Percent Reduction
Of Uncontrolled
Emissions
CD
Predicted
Emissions
(103tons/yr)
Percent Reduction
Of Uncontrolled
Emissions
220
213
152
145
31
34
22.0
21.3
15.2
14.5
90
90
93
93
(1) Calculations assume a vapor recovery system which controls 90% of all emissions.
(2) Based on emissions calculated by assumption (1).
(3) Percent reduction is referred to predicted emissions for Case I without a vapor recovery
unit.
-------
Losses consist of: (1) displaced vapors from the under-
ground tank that occur during refilling, (2) vapors displaced
from vehicle tanks during refueling, and (3) underground tank
breathing resulting from changes in vapor and liquid temperature.
Emission Factors
Emission factors developed for service stations are
as follows (EN-071):
(1) Underground Tank Filling:
Splash Filling: 11,5 lb/1000 gal transferred
Submerged Filling: 7.3 lb/1000 gal transferred
(2) Vehicle Refueling: 11 lb/1000 gal dispensed
(3) Underground Tank Breathing: 1 lb/1000 gal
throughput
Predicted Emissions
The following hydrocarbon emissions from U.S. service
stations are predicted using the gasoline throughput of 6.07
million barrels per day as defined in Figure 6.4-1.
Underground tank filling operations represent the only
variable in predicting service station emissions. Maximum
emissions of 1.09 million tons/year would be expected for
service stations employing splash filling operations while
emissions of 0.90 million tons/year would be expected for service
stations using submerged filling operations.
-150-
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Further controls of service station emissions are
practiced in some areas of the U.S. today. Hydrocarbon
emission controls on underground tank fillings have been con-
sistently measured to reduce those emissions by 957o. The
installation of a vapor recovery system can be used to reduce
vehicle refueling emissions up to 907o and virtually eliminate
underground tank breathing losses.
Vapor recovery systems in use today are of two basic
types: vacuum assist and vapor balance. Vehicle refueling
emission reductions are estimated to be 80% for a vapor balance
system and 9070 for a vacuum assist system. Both of these
efficiencies are based on applying 1974 technology. A detailed
discussion of emission control technology is presented in
section 6.5 of this report. Table 6.4-4 presents a summary of
predicted hydrocarbon emissions from U.S. service stations which
indicates the relative effects of applying different hydrocarbon
emission controls.
6.4.1.4 Aviation Gasoline Hydrocarbon Emissions
Hydrocarbon emissions from aviation gasoline will be
much lower than from motor gasoline due primarily to the relatively
small quantity of aviation gasoline consumed in the U.S. Emissions
from aviation gasoline will be localized and found predominately
around airports.
Emissions from storage tanks for this source were
predicted by applying the storage loss emission factors for
motor gasoline to the assumed storage capacity of aviation
gasoline. It was reported in 1972 by the MSA Research Corpora-
tion (MS-001) that there were 19.8 million barrels of storage
capacity across the United States for aviation gasoline. This
figure was used as the basis of calculation.
-151-
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TABLE 6.4-4
PREDICTED HYDROCARBON EMISSIONS FROM U.S. SERVICE STATIONS
Case I - No Control
• Splash filling of underground tank
. No vehicle refueling controls
Case II
• Submerged filling of under-
ground tank
• No vehicle refueling controls
Case III
• Underground tank emission controls
-• No vehicle refueling controls
Case IV
• Underground tank emission controls
• Vapor balance vehicle refueling
control
Predicted
Emissions
(10s tons/yr)
1.09
0.90
Percent
Reduction of
Uncontrolled
Emissions
(1)
(1)
0.53
0.12
17
51
89
Case V
Underground tank emission controls^ '
Vacuum assist vehicle refueling
(3)
control
0.07
94
(1) Underground tank controls (Stage I controls) are assumed
to be installed in conjunction with submerged filling
operations only. Control efficiency is assumed to be 95%
of the submerged filling losses.
(2) Vapor balance control of vehicle refueling emissions is
assumed to provide control of 80% of those losses.
(3) Vacuum assist control of vehicle refueling emissions is
assumed to provide control of 90% of those losses. This
further assumes, of course, that the control unit is
operating properly.
-152-
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Loading losses for aviation gasoline handling were
estimated by multiplying the loading losses previously pre-
dicted for motor gasoline by the ratio of average daily through-
puts of aviation to motor gasolines. Table 6.4-5 presents a.
summary of the predicted aviation gasoline hydrocarbon emissions
6.4.2 Adverse Effects of Hydrocarbon Emissions
Very few hydrocarbons in the atmosphere exist in con-
centrations that directly affect the environment; however,
many hydrocarbons termed "reactive" participate to various
degrees in photochemical reactions to form photochemical
oxidants which do have adverse effects on plants, animals, and
materials. The hydrocarbons contained in gasoline vapor are
reported to be composed of 42% to 65% reactive hydrocarbons
(MS-001, TR-042). Presented here are some of the direct and
indirect effects produced by hydrocarbons such as those found
in gasoline vapor.
6.4.2.1 Effects on Human Health
Effects on human health are of paramount importance
in any consideration of air pollutants. However, the wide
variety of compounds in photochemical smog effectively prevent
singling out specific compounds as contributors to specific
adverse effects. There is little conclusive evidence that
hydrocarbons as emitted to the air in existing levels have
direct adverse effects on the health of the general public.
The documented health effects are limited to eye, respiratory
irritation, and aggravation of chronic respiratory ailments
due to exposure to photochemical oxidants which are the result
of subjecting hydrocarbons to the photochemical reaction.
-153-
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TABLE 6.4-5
PREDICTED HYDROCARBON EMISSIONS FROM AVIATION GASOLINE
Conditions of Handling
Case I - Uncontrolled
Old fixed roof tanks
Splash loading
Case II
New fixed roof tanks
Splash loading
Case III
Old fixed roof tanks
Submerged loading
Case IV
New fixed roof tanks
Submerged loading
Case V
Old floating roof tanks
Splash loading
Case VI
New floating roof tanks
Splash loading
Case VII
Old floating roof tanks
Submerged loading
Case VIII
New floating roof tanks
Submerged loading
Predicted
Emissions
CLQ3 tons/yr)
45.4
40.8
42.5
37.9
17.7
9.3
14.8
6.4.
Percent Reduction
Of Uncontrolled
Emissions
10
16
61
80
67
86
-154-
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The major contributors to eye and respiratory irri-
tation are aldehydes, organic peroxides, peroxynitrates, and
ozone. Peroxyacetylnitrate (PAN) was found to induce
increased oxygen uptake under stressful exercise.
Studies in Los Angeles have found that prolonged exposure
of guinea pigs to ambient Los Angeles air increased
pulmonary airflow rates. There is also wide spread
concern over the potentially carcinogenic effects of long
term human exposure to the airborne polycyclic aromatic
hydrocarbons.
In summer, although ambient hydrocarbons do not directly
effect human health, their derivaties from the photochemical
reaction, in atmospheric concentrations, cause eye and res-
piratory irritation, and aggravation of chronic respiratory ail-
ments (TR-042).
6.4.2.2 Effects on Vegetation
Of the primary hydrocarbon air pollutants, ethylene
is the only one producing significant damage at atmospheric
concentrations. Oxidants resulting from the photochemical
reaction produce the greatest amount of vegetation damage.
This damage is primarily in the form of growth supression. It
is difficult to assess vegetation damage due to air pollution
but estimates of pollution vegetation damage in California
were $100 million annually and for the nation $500 million
annually (TR-042).
-155-
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6.4.2.3 Materials Damage
Materials damage by atmospheric hydrocarbons and
their oxidant derivatives is not well documented. Photo-
chemical oxidants cause cracking and loss of elasticity in
rubber and plastics, the formation of resistive coatings on
electrical contacts, and discoloration and deterioration of
architectural coatings. The San Francisco Bay Area estimated
their materials damage due to hydrocarbons and photochemical
oxidants to be $15 million annually (TR-042).
6.4.2.4 Other Effects
In addition to effects on health, vegetation, and
materials, hydrocarbon and photochemical oxidant pollutants can
be visually offensive and contribute to offensive odors.
Offensive odors are a nuisance and can result in property
depreciation and degradation of the general quality of life.
6-4.3 Seasonal Characteristics of Emissions
The ambient level of photochemical oxidants is lowest
in the winter season. This coincides with the season
when the efficiency of the vapor balance recovery system is
the lowest. Photochemical reaction rates are lowest during
the winter months when solar radiation is at a minimum
and the ambient temperatures are low. Figures 6.4-2 and
6.4-3 present the frequency that ambient standards were
surpassed at several sampling locations (EN-182).
At all sampling locations the ambient photochemical
oxidant standard was not surpassed in the months of January
and December, and for several of the sampling locations the
-156-
-------
240
220
I 200
*S
en
C
o
•i-i
w
w
01
o
c
•H
W
03
QJ
Pi
4-J
c
cd
T)
•H
X
O
FIGURE 6.4-2 HOURLY
OXIDANT MEASUREMENTS,
AZUSA, LOS ANGELES, AND
SAN DIEGO, CALIFORNIA -
1972
J
*\ J
Months
J
-------
FIGURE 6.4-3 HOURLY
OXIDANT MEASUREMENTS,
BAKERSFIELD AND STOCKTON,
CALIFORNIA, AND DENVER,
COLORADO - 1972
M J J
Months
-------
standard was not surpassed in the months of January, February,
November and December. During these months the average tempera-
tures were in the low 50's or lower.
Photochemical oxidant production is greatest in the
warm summer season when ultraviolet radiation is at its peak.
Figures 6.4-2 and 6.4-3 reflect this trend, indicating June,
July, and August to be the months when this problem is most
acute.
6.5 Emission Control Technology
6.5.1 Bulk Terminals
The emission control technology designed for bulk ter-
minals is the most highly developed and has been in use for some
time. Certain regions have for many years had regulations
requiring emission controls and have thus encouraged the develop-
ment of bulk terminal emission control technology. The petroleum
industry has also viewed terminal emission control technology as
an economical means of conservating valuable fuel products.
This section provides brief descriptions of the control measures
available for bulk terminal emissions.
6.5.1.1 Storage Tank Controls
Gasoline storage tanks at bulk terminals are generally
of the size which are regulated for hydrocarbon vapor emissions.
Most terminals, therefore, have some type of hydrocarbon emis-
sion controls on their storage tanks. Emission control tech-
nology applicable to storage tank hydrocarbon emissions is dis-
cussed in Section 5.3.2 of this report.
-159-
-------
6.5.1.2 Loading Rack Vapor Controls
A second source of emissions from bulk terminals occurs
at the tank truck loading rack. As the truck is loaded, gasoline
vapors in the tank, unless contained, are displaced to the
atmosphere. The quantity of hydrocarbons in these emissions
is dependent on the previous drop made by the truck, the method
of gasoline loading, and climatic conditions. Loading rack
vapor control equipment attempts to capture these emissions
from the truck and transfer them to a vapor recovery unit.
Description
The type of vapor collection system at the truck
rack depends on how the truck is loaded. If the truck is top
loaded, vapors are recovered through a top loading arm (Figure
6.'5-1). Top loading arms consist of a splash or submerged loading
nozzle (Figure 6.5-2) fitted with a head which seals tightly
against the hatch opening. Gasoline is loaded through a central
channel in the nozzle. Displaced" vapors flow into an annular
vapor space surrounding the central channel and in turn flow
into a hose leading to a vapor recovery system. Since the vapor
line is incapable of handling liquid overflows a safety shut-
off is usually included in the nozzle. Some of the advantages
of top loading vapor collection are:
minimal modifications required for
existing top loading trucks
inexpensive conversion of existing top
loading racks for vapor recovery
adaptability to existing top loading
independent carriers.
-160-
-------
MISCELLANEOUS PARTS
ITEM
1
2
3
4
5
6
7
8
9
10
11
PART NO.
3420-F-30
2775 •
3420-F-50
H-5936
D-e37-M
H-5S93-RP
H-5905-M
H-S905-M
H-S318-
C-1G67-A
C-2479-f.l
DESCRIPTION
Swivel Joint, 3"
Boom
Swivel Joint, 4"
Swivel Joint 3"
Handle
Hose
Elbow
Coid Clip
Collat Sub-Assembly
Link
Gasket
QTY.
1
2
2
2
1
ITEM
12
13
14
15
16
17
18
PART NO.
H-4190-M
D-33S-M
3630-30
H-4189-M
H-5952
3840-FO-<0
710
C-555-A
417-FKA-4"
3476-F-40
DESCRIPTION
Gasket, 4"
Upper Handle & Pipe
Swivel Joint, 3"
Gasket, 3"
Swivel Joint Sub-Assembly, 4"
Swivel Joint Only
4x278 Nipple Only
4" Flange Only
Loading Valve
Swivel Joint, 4"
QTY.
6
FIGURE 6.5-1
Top Loading Arm Equipped With A Vapor Recovery Nozzle
-161-
-------
DUMP PASSAGE
"UP/DOWN"
CONTROL VALVE
HANDLE
DUMP PASSAGE
FLOATING COLLAR
SEAL
LEVEL SENSOR
VAPOR RETURN
ADAPTOR
FIGURE 6.5-2
Detail of a Vapor Recovery Nozzle
-162-
-------
If the truck is bottom loaded the equipment
needed to recover the vapor is considerably less complicated.
Vapor and liquid lines are independent of each other with
resultant simplification of design. Figure 6.5-3 shows a
typical installation. The vents on top of the trucks are mani-
folded together and a single vapor vent line is brought from the
truck near the bottom loading fueling connections. One or
both of the truck turnover rails are usually used as the vapor
manifold. Vapor collection and gasoline dispensing lines are
flexible hoses and/or swing type arms connected to quick acting
couplings on the truck,
Bottom loading vapor recovery has many advantages
over top loading vapor recovery. The operator does not have to
walk on top of the truck. Bottom loading generates much less
vapor, generates almost no mist, and is safer from a static
electricity point of view. Because of the capacity to simul-
taneous load several compartments, bottom loading allows faster
loading. In addition, a truck equipped to pick up vapors at
the service station is equipped for bottom loading.
Efficiencies
Although difficult to quantify, the vapor collection
efficiency for top loading is lower than for bottom loading.
Vapors escape from the hatch opening during insertion and
removal of the top loading nozzle. There are also losses due
to spills as the loading arm is raised from the truck.
-163-
-------
FIGURE 6.5-3
Bottom Loading Vapor Recovery
-164-
-------
The vapor containment efficiency of bottom loading
equipment approaches 100 percent on a tightly sealed truck.
When properly operating, the system remains sealed throughout the
loading operation. Dry break couplings are used on the gasoline
dispensing lines and check valves are used on the vapor return
lines to minimize spills and vapor escape during hook-ups and
disconnects.
6.5.1.3 Vapor Recovery Units
Vapor recovery units are manifolded into the vapor
collection system at bulk terminals for either conversion of the
gasoline vapors into liquid product or for disposal of the
vapors through such processes as combustion or adsorption.
There are several vapor recovery units which are commercially
available today that have demonstrated high efficiencies in
recovering hydrocarbon vapors from operating bulk terminals.
The main processing operations employed by vapor
recovery systems are compression, refrigeration, absorption,
adsorption, and oxidation. A vapor recovery system may use one
or several of these operations to achieve effective hydrocarbon
control.
Vapor recovery units are generally classified as to
their principle of operation. The most widely used vapor
recovery units today, are of the following types:
(1) Compression-Refrigeration-Absorption (CRA)
(2) Compression-Refrigeration-Condensation (CRC)
(3) Refrigeration
-165-
-------
(4) Lean Oil Absorption
(5) Flame Oxidation
Each of these systems will be discussed in this section.
All of the above systems are capable of achieving
907o reduction of hydrocarbon emissions. These systems are
rather complex, however, and thus a proper maintenance schedule
must be maintained to assure of proper operations. Reliability
has generally been reported as good when proper maintenance has
been performed. Figure 6,5-4 is a schematic of a vapor recovery
unit which depicts some of the complex equipment associated with
these systems.
Compression-Refrigeration-Absorption (CRA) Systems
The compression-refrigeration-absorption vapor re-
covery system (CRA) is based on the absorption of gasoline
vapors under pressure with chilled gasoline from storage. The
primary unit in CRA systems is the absorber with the remaining
components serving to condition the vapor and liquid entering the
absorber, improve absorber efficiency, reduce thermal losses,
and/or improve system safety. Incoming vapors are first passed
through a saturator where they are saturated with fuel. The
saturated vapors are then compressed and cooled prior to enter-
ing the absorber. In the absorber the cooled, compressed
vapors are contacted by chilled gasoline drawn from product
storage and are absorbed. Hydrocarbon-free air is vented from
the top of the absorber and gasoline enriched with light ends is
withdrawn from the bottom of the absorber and returned to the fuel
storage tanks. The operating conditions in the absorber vary
with the manufacturer, and range from -10°F to ambient temperature
and from 45 psig to 210 psig.
-166-
-------
ABSORBER
COMPRESSOR
AFTERCOOLER
MODULE
A A A AA A A A A A A A A A
EFRIGERATOR
A A AAAAAAAA A A A A
A A A A 7\ A A A /V A A A A A A
• HEAT
EXCHANGER
SATURATOR-FLASH
SEPARATOR
r>
AAAAAAAAAA —
VAPOR
SAVER
CONNECTION
FIGURE 6.5-4
Schematic of a Terminal Vapor Recovery Unit
-------
Compression-Refrigeration-Condensation (CRC) Systems
Compression-Refrigeration-Condensation vapor recovery
systems (CRC) were the first type utilized by the petroleum
industry. They are based on the condensation of hydrocarbon
vapors by compression and refrigeration. Incoming vapors are
first contacted with recovered product in a saturator, and
are saturated beyond the flamability range. The saturated vapors
are then compressed in a two stage compressor with an inter-
cooler. Condensate is withdrawn from the inter-cooler prior to
second stage compression. The compressed vapors are passed through
a condenser where they are cooled, condensed, and returned along
with condensate from the inter-cooler to the gasoline storage
tank. Essentially hydrocarbon-free air is vented from the top
of the condenser. Operating conditions vary with the manufacturer,
with temperatures ranging from -10°F to 30°F and pressures
ranging from 85 psig to 410 psig.
Refrigeration Systems
One of the most recently developed vapor recovery systems
is the straight refrigeration system, based on the condensation
of gasoline vapors by refrigeration at atmospheric pressure.
Vapors displaced from the terminal enter a horizontal fin-tube
condenser where they are cooled to -100°F and condensed. Be-
cause vapors are treated on demand no vapor holder is required.
Condensate is withdrawn from the condenser bottom and hydro-
carbon-free air is vented from the condenser top. Cooling
for the condenser coils is supplied by a methyl chloride brine
solution circulated from a cold brine storage reservoir. A
two-stage refrigeration unit is used to refrigerate the stored
brine solution to between -105°F and -125°F.
-168-
-------
Lean Oil Absorption Systems
The lean oil absorption (LOA) vapor recovery system is
based on the absorption of gasoline vapors into lean gasoline
stripped of light ends. Gasoline vapors from the terminal are
displaced through a packed absorber column where they are
absorbed by cascading lean gasoline (termed sponge oil or lean
oil) at atmospheric temperature and pressure. Stripped air is
vented from the top of the absorber column. The enriched
gasoline is returned to storage. Lean gasoline for the absorber
is generated by heating gasoline from the storage tanks and
evaporating off the light ends. The separated light ends are
compressed, condensed, and returned to storage, and the lean
gasoline is stored separately for use in the absorption column.
Flame Oxidation Systems
One of the simplest vapor control systems for bulk
terminals is the flame oxidation system. This system controls
hydrocarbon emissions by combusting gasoline vapors as opposed
to recovering them as a liquid product. Gasoline vapors from
the terminal are displaced to a vapor holder as they are
generated. A hydrocarbon analyzer system adds propane to the
vapor holder when necessary to maintain the hydrocarbon/air
ratio above its flamability limit. When the vapor holder
reaches its capacity the gasoline vapors are released to the
oxidizer, after mixing with a properly metered air stream and
combusted to carbon dioxide and water.
6.5.2 Service Stations
The main sources of hydrocarbon emissions from service
stations are the underground tank refilling and vehicle refueling
operations. Considerable experience has recently been obtained
-169-
-------
with emission controls for both sources. Emission control of
underground tank filling operations has been designated as
Stage I controls and control of vehicle refueling operations
has been designated as Stage II controls. Emission control
technology, for both stages of control will be discussed in
this section.
6.5.2.1 Stage I Control Technology
Emissions resulting from underground tank filling
vary with the method of tank loading operations, i.e., splash or
submerged loading. Underground storage tanks should be equipped
with submerged fill pipes that extend to within six inches of the
bottom of the underground tank to provide minimum emissions.
Substantial test data exists which indicate that
957o of the displaced vapors can be recovered by simply returning
the displaced vapors to the tank truck. These data indicate
that a well-designed vapor balance or displacement system will
provide efficient control of underground tank refilling vapors
with the use of emission control technology and equipment
commercially available today.
A well designed vapor balance system used to control
emissions from refilling underground tanks should employ the
following equipment:
(1) A fill pipe which extends to within
6" of the bottom of the underground
tank
-170-
-------
(2) Vapor return hoses and connector of
3" or greater nominal size
(3) The storage tank vent to atmosphere
should be equipped with either an
orifice of 1/2-3/4 inch inside diameter
or a pressure-vacuum vent valve
Figure 6.5-5 is a schematic sketch of a well designed
vapor displacement system for recovery of underground storage
tank vapors. The system depicted employs a concentric or
coaxial vapor-liquid connector.
6.5.2.2 Stage II Control Technology
Stage II controls refer to control during vehicle
refueling. It is in this area where much disagreement
remains on the effectiveness of different means of
emission control. Most of the controversy centers on
the relative advantages/disadvantages of two basic types
of emission control systems: vapor displacement and
vacuum assist.
Cons t'd'ef at ions -Vapor Balance Systems
The vapor displacement, or vapor balance, system
operates by simply transferring vapors to the underground
tank where they are stored until final transfer to a tank
truck. Pressure created in the vehicle tank and vacuum
created in the underground tank are the principal agents
of vapor transfer. The main pieces of equipment associated
with a vapor balance system are a specially designed nozzle
which is designed to form a vapor tight seal at the fill
neck interface, a flexible hose, and an underground piping
system to transport the vapors to the underground storage
-171-
-------
to
3" Vapor Return Line
1. Dry-break connection for vapor return connection
at the terminal.
2. Coaxial Fitting.
3. Drop Tube.
4. Dry-break connection on vapor return line.
5. PV valve or orifice on underground tank vent.
6. Coaxial fill adaptor on underground tank 4" riser
7. Manhole.
FIGURE 6.5-5
Stage I Vapor Recovery Equipment
-------
tank. The underground storage tank vent line can either be
open to the atmosphere or equipped with a P-V value to aid in
retaining a vacuum in the underground tank.
Source testing of vapor balance systems conducted by
EPA and several major oil companies has indicated that these
systems are capable of recovering between 80-90% of the hydro-
carbon emissions resulting from vehicle refueling operations.
The majority of uncollected hydrocarbon losses result from
leaks at the nozzle-fill neck interface, if the problem of
leakage around this interface can be solved, the vapor balance
system will then become a highly efficient and extremely re-
liable method of recovering vehicle refueling vapors.
There are a multitude of vehicle fill neck con-
figurations and sizes found in vehicles on the road today. It
is highly unlikely, therefore, that a single nozzle will"be
developed to provide leak free seals on all vehicles. One means
of ensuring a tight seal could, however, be through development
of fill neck adapters which have been standardized for fill
necks on all vehicles. Agreement of automobile manufacturers
to supply standardized fill necks with all cars would, of
course, greatly simplify implementation of this plan.
Due to its simplicity, costs for a balance system
will be relatively low and operating reliability will be high.
Costs are expected to be about $5,000 for installation in an
existing service station and $2,500 for installation in a new
station.
Considerations-Vacuum Assist Systems
Designs of commercially available vacuum assist
systems vary widely. All do, however, employ a blower or
vaccum pump and a secondary recovery device. The vacuum, pump
-173-
-------
creates a negative pressure in the vehicle fill neck
which "pulls" hydrocarbon vapors either directly to the
secondary unit or to the underground tank with the excess
vapors going to a secondary unit. The amount of vapor
collected by this type system is greater than the amount
that would be displaced by the balance system filling
operations.
The main processing operations employed by secondary
control devices are compression, refrigeration, adsorption, con-
densation, and oxidation. One secondary control device may use
one or several of these operations to achieve the necessary
control. The equipment associated with these type systems is
generally complex, expensive, and subject to mechanical failure,
Equipment associated with a balance system on the other
hand is simple, less expensive, contains no moving parts
(except for the nozzle) and is thus not subject to opera-
tional downtimes.
Efficiencies of secondary vapor recovery systems are
reported to be at least 90%. This efficiency should be
achievable if the equipment is well maintained.
Potential problems with these systems result from
the use of a vacuum pump to assist the transfer of gasoline
vapors from a vehicle tank to an underground storage tank.
If there is a high vacuum and a good seal at the nozzle-fill
neck interface, vapor "pull-out" will occur and gasoline vapors
will be lost which would have ordinarily remained in equili-
brium with the gasoline in the vehicle tank. A situation may
also exist where there is a high vacuum and a poor seal at
the nozzle fill neck interface. In this case, fresh air will
be pulled in the leak thus creating a potentially explosive
-174-
-------
mixture in the underground piping network. Proper pressure
control of these systems is essential.
Due to their complexity, vacuum assist vapor recovery
%
systems will be more costly than the simpler vapor balance
systems. Costs for complete installation of these systems have
been estimated to be in the $10,000-$15,000 range.
Descriptions of each of these vapor recovery systems
will be provided in this section.
System Description-Vapor Balance
The major components of a vapor balance system are
a vapor recovery nozzle, a flexible hose, and underground piping.
The function of the vapor recovery nozzle is to effect a leak
free seal at the fill pipe interface. When the seal is made,
all vapors displaced from the vehicle tank will flow through
a vapor passage in the nozzle.
The function of the flexible hose is to provide a
means of transferring the displaced vapors from the nozzle to
the underground pipe. The hose is connected to the outlet of
the nozzle vapor passage and to the inlet of the underground
pipe which provides a path of vapor flow to the underground tank.
Experience with these systems has indicated that a flexible
hose size of at least 3/4" and an underground pipe size of
at least 2" are necessary to prevent excessive system pressure
drops. Furthermore, experience has shown that a slope of
1/8 - 1/4" per foot will provide a sufficient gradient for any
condensed vapors to flow to the underground tank. Figure
6.5-6 shows a diagram of a vapor balance system with manifolded
vent lines.
-175-
-------
VENT
NO LEAD
FIGURE 6.5-6
Diagram of a Vapor Balance System
-------
The major differences in vapor balance systems are
found in designs of nozzles, piping configurations, and under-
ground tank vent line controls. Some systems return the dis-
placed vapors to individual tanks while others manifold them
together. Pressure-vacuum valves can be used to control breathing
of the underground tank. In addition, they have the capability
of taking advantage of the vacuum developed in the underground
tank upon vehicle refueling which aids in providing a driving
force for the transport of vapors from the fuel tank to the
underground storage tank,
System Descriptions-Vacuum Assist
Compression-Refrigeration-Condensation
The major pieces of equipment associated with a
compression-refrigeration-condensation (CRC) vapor recovery
system are:
vapor recovery nozzle,
flexible hose,
vacuum pumps,
underground piping system,
vapor holder,
two stage compressor, and
refrigeration heat exchanger.
-177-
-------
One commercially available system operates by pump-
ing the collected vapors through a bed of liquid con-
tained within a surge tank where the vapors become
saturated. The purpose of the surge tank is to en-
sure that the vapors are saturated before they are
compressed and to even out large volume surges which
may occur during bulk drops. The saturated vapors
from the vapor holder, or surge tank, are compressed
and cooled in a two-stage, high-pressure refrigeration
unit. The condensed gasoline is returned to the under-
ground storage tank and the non-condensed vapors are
vented.
A carbon canister can be used in this system in
place of the vapor holder and saturator. When the canister
is used, all excess vapors pass through it and the hydro-
carbons are adsorbed while essentially hydrocarbon free
air exists. The carbon is regenerated by heat assisted
vacuum stripping and the recovered vapors are condensed
in the CRC unit.
Oxidation
There are two types of oxidation systems used to
eliminate hydrocarbon emissions. They are defined as
catalytic oxidation and thermal oxidation processes.
Both employ the same basic equipment: vapor recovery
nozzles, vacuum blowers, piping systems, excess vapor
holders, and an oxidation unit. Both expandable blad-
der tanks and carbon canisters have been used for
vapor holders.
-178-
-------
For regeneration of carbon bed vapor holders, a
vacuum blower pulls air through the canister in a
reverse direction, purging the adsorbed hydrocarbons.
The regeneration gases are then passed to the oxidation
units. Both the catalytic and thermal units add air
to the hydrocarbon stream in a controlled amount to
support combustion. After adsorbed hydrocarbons have
been removed, the fuel/air mix passing to the oxida-
tion units becomes leaner. The catalytic unit auto-
matically shuts off when the temperature drops below a
certain level (say 1100°F) and the thermal oxidation'unit is
automatically shut off, when combustion is no longer
supported.
Refrigeration-Adsorption
Commercially available refrigeration vapor recovery
systems are designed to process the excess vapors from
the underground tank. When the system pressure reaches
a designated level (say 3" H20) the refrigeration unit
is activated and vapors are passed across the low tempera-
ture cooling coils. This causes some of the excess
vapors to be condensed, reducing the volume of un-
condensed vapors. Condensed product and contracted
vapors are returned to the underground tank.
Under extreme conditions, when large quantities
of excess air are suddenly introduced into the system,
the system pressure may rise above 3.0" HaO operating
level. When the pressure reaches a maximum of seven
inches of water excess vapors are vented through a carbon
canister which may be regenerated off-line after the
system pressure is lowered to its normal operating level.
-179-
-------
Gasoline Engine
Hydrocarbon vapors are collected from the dispensing
nozzle by a vacuum blower and discharged into a vapor
manifold. The major portion of the collected vapors
are returned to the underground tank dispensing the
gasoline. Excess vapors are conveyed either to an
activated carbon bed or to the carburetor of a one
cylinder, four-cycle engine. The engine and blower
are automatically started when the gasoline dispenser
j
is activated. Excess vapors generated at rates greater
than the engine can consume bypass the engine and are
stored on the carbon bed. The engine is connected to
a load blower which simply serves as a sink for energy
output.
When the nozzle and blower are cut off the engine
continues to operate on hydrocarbons purged from the
carbon bed by reversed air flow. When the carbon bed
is fully regenerated the engine cuts off from lack of
fuel. A special carburetor maintains the fuel air
ratio constant. The engine is equipped with a catalytic
muffler to oxidize any trace quantities of hydrocarbons
or carbon monoxide in the exhaust,
Systems Under Development
Several additional recovery units for use in vacuum
assist systems are under development. Prototypes of
these systems are being tested and commercial units are
likely to be in production by 1976. In this section,
each of these basic types of systems will be described.
-180-
-------
Compression-Absorption-Adsprption
This system operates by compression of hydrocarbon
vapors to 22.5 psia and passing them through an absorp-
tion column where they are contacted with 0°F gasoline.
Air and unabsorbed hydrocarbons are subsequently vented
through a carbon bed cooled by heat exchange with cold
gasoline. The carbon bed is vacuum regenerated, with
recycling of the desorbed hydrocarbons through the
absorption unit.
Compression-Refrigeration ••Condensation
A CRC system under development offers a new
recovery technique. It separates and bottles
collected propane and butane products. The collected
hydrocarbon vapors are first cooled to 60°F in an
exchanger where pentanes and heavier fractions
are condensed and returned to the underground product
storage tanks. Uncondensed vapors are next compressed
to 125 psig and again cooled to 60°F where propanes
and butanes are condensed and bottled for sale. The
small quantities of methane and ethane; remaining in the
vapor stream are.adsorbed in a carbon bed and purified .
air is vented from-the bed.
Open Refrigeration
This system is in design stage only. Hydrocarbon
vapors generated during refueling are vacuum collected
and returned to the underground product storage tank
through a common vapor manifold. Excess vapors are
displaced through a refrigeration-condenser unit
-181-
-------
and cooled to -85°F. The hydrocarbon components of the
vapor are condensed out and returned to product storage.
Adsorption-Absorption
This system is basically an on-site regeneration
carbon adsorption system. Vacuum assist is used to return
the collected hydrocarbon vapors to the underground
storage tank. Excess vapors are vented through a carbon
canister where the hydrocarbon vapors are adsorbed.
Regeneration is accomplished by vacuum stripping the
off-service carbon canister. The recovered hydrocarbons
are returned to the underground storage tank (premium
grade) and absorbed into the liquid fuel.
6.5.3 Bulk Stations
Very few studies have been conducted on bulk station
emission controls ; however, research on service station and
terminal control techniques is largely applicable to bulk
stations. The two primary emission sources at bulk stations
are transfer operations and tankage. Emissions from transfer
operations are attributed to vapors displaced during the
filling of bulk station storage tanks and the filling of
delivery trucks. Tankage emissions are attributed to diurnal
breathing losses. The two basic approaches to controlling
these emission sources is straight vapor balance and vapor
balance in conjunction with vapor recovery systems.
6.5.3.1 Vapor Balance
The control of transfer losses from bulk stations
centers mainly around vapor balance and bottom loading.
-182-
-------
Converting to bottom loading and reducing transfer rates will
tend to reduce the generation of gasoline vapors. In section
6.5.2.1 (Stage I controls) it is reported that vapor balance
systems at service stations achieve an average emission
reduction efficiency of 95%. The same efficiency should be
possible when applying that system to bulk station transfer
losses.
Bulk station storage tanks are usually truck portable
horizontal or vertical tanks. It is uneconomical to install
variable volume vapor storage or floating covers on these
tanks to control breathing losses. One economical solution
to breathing losses is the installation of pressure-vacuum (p/v)
vents on the tanks. Figure 6.5-7 (NI-027) indicates that tank-
age breathing losses can be virtually eliminated by using a
p/v vent with a 40 oz/in2 (2.5 psig) pressure setting and a
reduction of 70% can be achieved by using a p/v vent with a
16 oz/in2 (1 psig) pressure setting. Since API tankage is
already stressed for higher working pressures than these,
additional tankage costs would not be incurred.
6.5.3.2 Vapor Recovery Systems
If the efficiency of the balance system proves
insufficient, bulk stations can be equipped with vapor re-
covery systems. The vapor recovery systems would be installed
in conjunction with balance system piping to process only the
excess vapors which the balance system fails to control.
Large bulk stations would employ one of the terminal-size vapor
recovery systems outlined in section 6.5.1, for terminals,
and a small bulk station would employ one of the service
station-size vapor secondary recovery systems outlined in
section 6.5.2.2.
-183-
-------
«
h
^
u
ff
i i t i ( i
t I I I ! I I I I .1 I .1 I I I I !.._'. I ! I I I I I I t
I I I I I I I I i I I I I I II I
FIGURE 6.5-7
Low Pressure Tank Emissions Vs Tank Operating Pressure Range
-184-
-------
6.5.3.3 Operating Reliability
The operating reliability of the balance system is
very high. It is simple with very few parts to fail. Vapor
recovery systems on the other hand are constructed of com-
plex equipment and are therefore more subject to failures.
Considering the sophistication of vapor recovery equipment,
the lack of motivation at bulk stations to maintain non-
profitable equipment, and the fact that bulk stations are often
situated in areas remote to repair services, the vapor
balance portion is significantly more acceptable than the
secondary recovery portion of the systems described above.
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7.0 JET FUEL MARKETING
7.1 The Industry
Ninety-five percent of the jet fuels produced in the
nation's refineries is used in U.S. airline or military air-
craft. The facilities for manufacturing, transporting and
storing these fuels and hydrocarbon emissions associated with
these facilities are discussed in this section.
7.1.1 Jet Fuel Description
Basically the jet turbine can operate on any clean
burning fuel. Kerosene is a suitable fuel and is widely used.
Distillates with wider boiling ranges are also used, however.
The first jet fuel, JP-1, was introduced during World War II.
Since then the development of jet fuel market has been rapid
and continuous,
Naphtha-type jet fuel with a lower vapor pressure
was developed in the early 50's. This fuel is a blend of 25-
357o kerosene and 65-7570 gasoline components. Another jet fuel,
a 140°F flash point kerosene, was originally mixed with aviation
gasoline, but is now used unblended.
Jet fuel is essentially kerosene-boiling range material
with critical specifications of freeze point, flash point, and
smoke point. The flash point is controlled by the amount of
naphtha blended into the jet fuel. Naphtha tends to lower the
pour point and in most instances maximum naphtha (up to flash
point restrictions) is used. Hydrocrackers can be used to
produce high-quality kerosene blend stocks by isomerizing the
paraffins (lowers the freeze point) and by saturating the aro-
matics (raises the smoke point) (DO-070).
-186-
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7.1.2 Uses
Data for 1973 show that approximately 957» of all jet
fuel consumed in the U.S. was for airline or military use. Table
7.1-1 lists demands by uses of jet fuels in the U.S. (AM-099).
The demand for kerosene-type jet fuel for 1973 was 303
million barrels, while the demand for naphtha-type jet fuel was
80 million barrels. These figures show an increase in the demand
for kerosene-type fuel and a decrease in the demand for naphtha-
type fuel when compared to 1972 figures (293 million barrels and
88 million barrels, respectively).
7.2 Product Distribution and Storage
7.2.1 Transport
Of the 381 million barrels of jet fuel consumed in the
United States in 1972, 48 million barrels were transported by
barge and tanker (AM-099), while 229 million barrels were
transported by pipeline (US-144). According to this data 95
million barrels of jet fuel was transported by some other means,
such as railroad tank car or tank truck, with some 9 million
barrels left unaccounted for (AM-099),
7.2.2 Storage
Non-refinery storage capacities for jet fuels in 1968
(with a throughput of 349 million barrels) amounted to 17.4
million barrels (MS-001). As the 1973 throughput exceeds the
1968 figure by 10%, it is assumed that storage capacities have
increased accordingly, although 1973 capacities are at present
unavailable. Within the marketing system, j^t fuels are stored
-187-
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TABLE 7.1-1
JET FUEL CONSUMPTION (1973)
Consumption
Product Use 103bbl/year
Airliner 267,545
Military 96,725
General Aviation 8,760
Non-Aviation 6,935
Factory 3,285
TOTAL 383,250
-188-
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at bulk stations and bulk terminals. Petroleum bulk stations
are defined generally as those having capacities less than 2
million gallons and receiving their supply by truck or rail
transport. Bulk terminals generally handle large throughputs
and are supplied primarily by pipeline, tanker, or barge.
Storage capacities for naphtha-type jet fuels amounted
to 6.1 million barrels in 1968, while those for kerosene-type
jet fuels amounted to 11.3 x million barrels (MS-001).
7.3 Emissions and Controls
Table 7.2-1 reports hydrocarbon emission factors for
the storage and loading of jet fuels. These factors were
compiled by EPA from various sources (EN-071).
The MSA Research Corporation calculated hydrocarbon
emissions from jet fuels using 1968 storage capacities.
Based on their calculations, the marketing of naphtha-type
jet fuels was found to be responsible for approximately 10,500
tons/year of hydrocarbon emissions while the marketing of
kerosene-type jet fuels was responsible for the emission of
approximately 3,300 tons/year. MSA assumed in their calculations
that 75% of bulk storage was equipped with floating roofs.
Traditionally, only jet naphthas have been volatile
enough to justify emission controls. Hydrocarbon emission sources
in the jet fuels marketing industry are very similar to the
hydrocarbon emission sources found in refinery storage operations
and in the gasoline marketing industry. For this reason, the
emission control measures presented in sections 5.3 and 6.5.1
on refineries and gasoline marketing should be directly appli-
cable to the jet fuel marketing industry,
-189-
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TABLE 7.2-1
HYDROCARBON EMISSION FACTORS FOR JET FUELS MARKETING
Emission Factors
Source Jet Naphtha Jet Kerosene
Floating Roof Storage
Standing Emission (Ibs/day 103gal) 0.020 0.009
Fixed Roof Storage
Breathing Emissions (Ibs/day 103gal) 0.074 0.038
Filling Emissions (lbs/103gal through- 2.4 1.0
put
Filling Losses
Rail Car & Tank Truck
splash loading (lbs/103gal) 1.8 0.88
submerged loading (lbs/103gal) 0.91 0.45
Marine Vessels
loading (lbs/103gal) 0.60 0.27
Source: (EN-071)
-190-
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In brief, storage losses can be controlled by con-
verting to floating-roof tanks or by venting excess vapor from
fixed roof tanks to a vapor recovery system. Loading and un-
loading emissions can be controlled by venting the displaced
vapors to a vapor recovery unit.
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8.0 DISTILLATE AND DIESEL FUEL MARKETING
8.1 The Industry
Approximately 3.0 million barrels per day of refined
products in the distillate fuel oils range are used for heating
and for diesel power in the nation. The facilities for distri-
bution and storage of these fuels and hydrocarbon emissions asso-
ciated with these facilities are described in the following pages.
8.1.1 Distillate Fuel Oils
Distillate fuel oil refers to those petroleum products
boiling in the 350° to 650°F range. This includes Numbers 1, 2,
and 4 fuel oils. Diesel fuels are also included in this fraction.
Grade No. 2 fuel oil is the designation given to the heating or
furnace oil most commonly used for domestic and small commercial
space heating and is the fuel oil generally referred to as dis-
tillate fuel. Domestic heating oil is generally a clean product
with a low sulfur and ash content and no asphaltic matter. As
a result, distillate fuels form no sediment in storage and have
less tendency to form ash or carbon deposits on burning. These
properties, combined with viscosities much lower than residual
fuels, make it easier to achieve clean and trouble-free combustion,
Diesel fuel is similar to distillate fuel. It is often
referred to by ASTM grade numbers 1-D and 2-D, as it is marketed
as burner fuel and grades 1 and 2. Some typical specifications
for fuel oil and diesel fuels are listed in Table 8.1-1 (DO-070).
TABLE 8.1-1
PROPERTIES OF DISTILLATE FUELS
Property No. 2 Fuel Oil Diesel Fuel
Flash, °F (min.) 140 145 to 155
Pour Point, °F (max.) -5 -10 to +10
Sulfur, wt% (max.) 0.5 0.5
Cetane Number (min.) 40.0 52.0
-192-
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Diesel fuel is burned in the compression ignition
engine rather than in a fuel burner. As a result, ignition
quality becomes an important characteristic. This ignition
quality is expressed as a cetane number which may be improved
(raised) by the removal of aromatics or by the inclusion of ad-
ditives to initiate the combustion process. Paraffinic fuels
are better suited for diesel use because of lower self-ignition
temperatures.
Both distillates and diesel fuels contain organic
sulfur compounds which may cause low-temperature corrosion due
to the condensation of acid combustion products and water on
boiler-tubes and cylinder walls. Although corrosion can be
effectively counteracted by the use of additives in the lubri-
cating oil of diesel engines, there is a definite trend towards
lower sulfur contents in distillate fuel oils. Sulfur content
can be reduced by desulfurization, and restrictions in parts of
the country have been placed on the maximum allowable sulfur
content to as little as 0.5. wt% (DO-0.70) .
8.1.3 Use
Forty-eight percent of the 1.1 billion barrels of
distillate fuel oil consumed in the U.S. in 1973 was used as
heating oil. Twenty-four percent of the total was used as
diesel fuel. Table 8.1-2 shows a breakdown of distillate fuel
oil demands by uses in 1973.
-193-
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TABLE 8.1-2
U.S. DISTILLATE FUEL OIL DOMESTIC DEMAND BY USES
(Daily averages in thousands of 42 gallon barrels)
1973
Heating Oils:
No. 1
Automatic Burners 91
Other Heating 40
No. 2 1,222
No. 4 115
Total 1,468
Industrial . " 184
Oil Company Fuel 41
Electric Utility Company .... 2141
Railroads 282
Vessel Bunkering 73
Military Use 54
Diesel Type
On Highway 594
Off Highway 155
Total. 749
All Other 15
Total 3.0801
1Includes 69,000 barrels per day of distillate fuel used by steam
electric plants. Also included are 17,000 barrels per day of
kerosene-type jet fuel used by electric-utility companies.
-194-
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8.2 Product Distribution and Storage
8.2.1 Distribution
«
Transportation data for 1972 show, that of the. 1.06
billion barrels of distillate fuel oil used in the U.S., 138
million barrels were moved by tanker and barge (AM-099) and 657
million barrels were moved by pipeline (US-144). The remaining
268 million barrels were transported by means of railroad tank
car and tank truck. Pipeline movement figures are not available
for 1973, but of the 1.1 billion barrels consumed 108 million
barrels were moved by tanker and barge (AM-099).
8.2.2 Storage
Storage'capacities in the marketing system for dis-
tillate fuel oil in 1968 (with a throughput of 872 million
barrels) amounted to 169 million barrels (MS-001). In 1973
throughput exceeded the 1968 figure by 29 percent. It is
assumed storage capacities have been increased accordingly.
8-3 Emissions
Hydrocarbon emissions from the marketing of distillate
and diesel fuels primarily originate from storage tank evapor-
ation and from tank truck and rail car loading. Table 8.3-1
lists some average emission factors for marketing operations
of distillate and diesel fuel (EN-071). Calculations by MSA
Research Corporation estimate that the hydrocarbon emissions
from distillate and diesel storage outside of refineries in
the year 1968 totaled 50,000 tons/year (MS-001). Because of
the low volatility of diesel and distillate fuels, their loading
emissions in 1973 were approximately 5,000 tons/year.
-195-
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TABLE 8.3-1
HYDROCARBON EMISSION FACTORS FOR DISTILLATE FUELS
Source Emissions
Floating Roof Storage
Standing Emissions (Ibs/day 103gal) 0.009
Fixed Roof Storage
Breathing Emissions (Ibs/day 103gal) 0.038
Filling Emissions (lbs/103 gal) 1.0
throughput
Filling Losses
Rail Car & Tank Truck
Splash loading (lbs/103gal) 0.93
Submerged loading (lbs/103gal) 0.48
Marine Vessels
Loading (lbs/103gal) 0.29
-196-
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Emission controls have not been applied to diesel
and distillate fuels marketing because of their relatively
low volatility and hydrocarbon emission rate.
-197-
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9.0 RESIDUAL FUELS
9.1 _. The Industry
In 1973, some 2.8 million barrels per day of residual
oils were used to generate steam, to fire industrial boilers
and furnaces, and as fuel for marine vessels. This heavy,
"left over" material from refining processes, although more
difficult to .handle and fire than lighter fuels, has become a
very important source of energy in the power, marine, and indus-
trial areas.
9.1.1 Product Description
Residual fuel oils are generally defined as residues
from the distillation of crude oils, having a boiling point of
650°F or greater. In addition to these "straight-run" oils,
there are fuels of the residual type produced from the various
refinery cracking processes. Residual oil is not considered
a choice among the fossil fuels. It is composed of the heaviest
parts of the crude and contains asphaltic matter, asphaltenes,
sulfur, and small amounts of metals. The presence of asphaltic
matter can result in the deposition of material which can
cause the clogging of strainers, preheaters or burners.
On combustion, part of the sulfur in residual oil may
contribute to undesirable boiler-tube deposits. The remainder
of the sulfur is either converted into sulfuric acid, a corrosive
chemical, or oxides of sulfur, which escape into the atmosphere.
Similarly, metals, such as sodium and vanadium, which are found
in small amounts in residual oils, can cause fireside tube deposits
in boilers, corrosion, and fly-ash air contamination. Some of the
sodium can be removed by water washing and centrifugation, but
at this time there is no commercially feasible way to remove
metals such as vanadium from residual oils (EN-043).
-198-
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Residual fuel oils are by their nature heavy, viscous,
difficult to vaporize, and often difficult to burn quickly
under "cold" conditions. In order to reduce viscosity, such
fuels are generally burned in equipment which permits relatively
steady operation at high fire-box temperatures. Since residual
fuels are difficult to vaporize they are atomized in special
burners to insure complete and efficient combustion. The more
viscous oils must be heated before entering the burners so that
they can be atomized.
Residual fuels are normally graded by viscosity, which
is an important characteristic in relation to their use. Other
properties which may be important, depending upon the application
of the fuel, are calorific value, sulfur content and ash.
Sulfur content has been limited by government regulation to
1 wt7o in certain areas of the country. Upgrading of the poorer
quality fuels can be accomplished through coking, solvent
deasphalting, residual hydrocracking, and desulfurizing.
9.1.2 Uses
Residual fuel oils can be defined as Number 5 and
Number 6 heating (burner) oils, heavy diesel, heavy industrial,
and heavy marine (Bunker "C") fuel oils. Fuel oil terminology
is not sharply defined. For example, Bunker C fuel is a heavy
fuel oil that generally corresponds to Grade 6 fuel oil, and
heating oils and burner fuel oils terms are often used synony-
mous ly.
Typically, residual fuels are used to provide steam
and heat for industry and large buildings, to generate electricity,
and to power ships, There is a tendency to describe the fuel
-199-
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TABLE 9,1-1
I
NJ
O
O
I
Total
U.S. RESIDUAL FUEL OIL DOMESTIC DEMAND BY USES
(DAILY AVERAGES IN THOUSANDS OF 42 GALLON BARRELS)
1964 1965 1966 1967 1968 1969 1970 1971
1972
1.515 1.608 1,716 1,786 1,826
1.978
1973
Heating Oils:
No. 5
No. 6
Total
Industrial1
Oil Company Fuel . .
Electric Utility Co. . .
Railroads
Vessel Bunkering . . .
Military Use . ...
All Other1
94
251
345
429
118
267
14
227
97
18
99
329
428
385
94
315
1 1
202
111
62
106
353
""459
387
96
378
10
202
115
69
114
368
482
361
104
434
15
221
I 1 1
58
105
371
476
371
107
505
12
239
96
20
109
379
488
366
100
679
9
229
87
20
117
392
509
383
105
856
6
246
79
20
107
392
499
373
89
1,019
4
216
80
16
112
410
~522
389
121
3
213
67
24
107
408
515
412
139
l,396b
3
252
53
25
2.204 2.296 2.529a 2,795'
1 Includes adjustments to allow total of uses shown to equal total domestic demand.
a Excludes approximately 36,000 barrels per day of distillate fuel oil used by steam-electric plants. This use svas shown
as residual fuel oil in prior years.
b Excludes approximately 69,000 barrels per day of distillate fuel oil used by steam-electric plants.
Source: Bureau of Mines, Sales vjFuel Oil and Kerosine, Annual.
-------
according to its use. Thus, fuel oils loaded into ships' bunkers
are called bunker fuels oils; fuels used for steam raising are
called underboiler fuels; and fuels employed in industry are called
industrial fuel oils. A breakdown of U.S. residual fuel oil
demands over the past decade by uses is shown in Table 9.1-1.
9.1.3 Domestic Production
The steady increase in the use of catalytic cracking
in refineries following World War II had the effect of decreasing
the percentage yield of residual fuels as well as changing their
makeup. As more high-boiling materials were charged to catalytic
cracking, the remaining oil sold as residual fuel became
heavier and heavier. Previous common industry practice was to
blend these heavy stocks with lighter distillates to reduce their
viscosities to a salable level for fuels. After the war, re-
fining processes in the United States continued to become more
efficient in producing the more profitable products. Residual
fuel oils account for 7.6 percent of average petroleum pro-
duction and refining yields on a national basis (EN-043). In
1973, 971 thousand barrels per day of residual oils were pro-
duced in domestic refineries while another 1,827 thousand
barrels per day were imported (AM-099). U.S. refineries have
continued to reduce the yield of residual fuels; however, if
the current residual shortages and higher prices prevail, this
trend could be slowed down or even reversed.
9.2 Distribution
9.2.1 Storage
Fixed-roof tanks operated at atmospheric pressure are
predominantly used in the storage of residual fuel oils. These
fuels have low volatilities and evaporation, breathing, and
working losses are minimal. Resid fuels are heated throughout
storage and transportation operations to maintain manageable
viscosities.
-201-
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9.2.2 Transportation
»
Residual fuel oil can be transported by tanker, barge,
pipeline, tank truck, or railroad tank car. Of the 2.8 million
barrels per day of residual oil consumed in the U.S. in 1973',
1.8 million were imported; and thus, the majority of residual
fuels are handled by tanker and barge. Furthermore, in 1973,
44,000 barrels per day of residual oils were transported by tanker
and barge from the Gulf Coast to the East Coast and 24,000 barrels
per day were transported from the Gulf Coast to the Mid-west via
the Mississippi River (AM-099).
The use of the insulated pipeline as a means of trans-
porting residual fuel oil is new in the U.S. Residual fuel,
with a pour point of 110°F or above, must be heated to permit
movement by normal pipeline operations. Several new insulated
lines are now in the planning or construction stages. These
lines will serve the fuel needs of major public utility gen-
erating plants in the eastern states.
9.3 Emissions
The possibility of substantial hydrocarbon atmospheric
emissions from residual fuel oils during storage or transportation
is minimal. Number 6 residual fuel oil has a negligible vapor
pressure, i.e., less than 0.1 psia, and as a result emission
factors for this fuel are generally omitted from pollution studies
-202-
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10.0 NATURAL GAS LIQUIDS
10.1 The Industry
Natural gas liquids are hydrocarbon mixtures which are
gaseous in underground reservoirs but which are separated and
recovered in liquid form by condensation, absorption, and ad-
sorption processes in natural gas plants or petroleum refineries.
Natural gas is composed principally of methane, but
also present in decreasing proportions are ethane, propane,
butanes, pentanes, hexanes, heptanes, and octanes. Those hydro-
carbons which are liquid at atmospheric pressure are recovered
from natural gas as "natural gasoline." This fraction consists
primarily of butanes, pentanes, and heavier saturated hydrocarbons.
Of the gaseous hydrocarbons which do not condense at
atmospheric pressure, methane cannot be liquefied under pressure
at ambient temperature, but propane and butanes can be. This
C3 and Ct, fraction is commonly known as liquefied petroleum
gas (LPG).
The average domestic production of natural gas liquids
(including ethane) from gas processing plants for 1973 was 72.5
million gallons or 1.73 million barrels per day from a total of
763 gas processing plants (FA-080).
The natural gasoline fraction is delivered to the
refinery for further processing or for blending with other
gasoline stocks. The LPG fraction may be sold at the gasoline
plant for fuel, or it may be transported to refineries or chemical
plants for use as petrochemical feedstocks.
-203-
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10.2 Gas Plants
The removal of the condensable hydrocarbons from gas
streams is conducted in the field at small processing stations
or at large natural gas processing plants which process the bulk
of the gas. The gas plants often separate the hydrocarbon
components, but the recovered liquids may be sent to the refinery
for further separation. The processing facilities, whether in
the field or at the plant, consist of four components: feed
preparation, gas 'compression, liquid recovery, and fractionation.
The three major types of recovery are used singly or in combina-
tions to effect the necessary separation.
Adsorption
Adsorption units are generally small, handling gas
volumes ranging from one to 20 million cubic feet per day. The
adsorption towers are filled with activated alumina or charcoal
which adsorbs the heavier hydrocarbons. After the material has
been saturated with hydrocarbons, heated gas or steam is passed
through the bed to desorb the hydrocarbons which are then con-
densed and ultimately fractionated. This process produces a
relatively low yield of natural gas liquids and is usually used
where the main concern is producing dry natural gas rather than
maximizing natural gas liquids recovery. About 12 percent of
the existing natural gas plants use adsorption processes (PR-052).
Absorption
In the absorption process the gas passes through an
absorber unit where absorber oil removes the propane and heavier
components. The gas stream is contacted with a controlled amount
of oil countercurrently in either a packed or bubble tray column.
-204-
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The oil extracts the absorbable hydrocarbons allowing the methane
and ethane to pass up through the tower in the gaseous phase..
The enriched absorber oil is then sent to a stripper where
individual products are separated under controlled temperature
and pressure conditions. About 164 plants in the United States
use absorption processes (PR-052).
Refrigeration
Refrigeration processes involve decreasing the temper-
ature of the gas to promote condensation of the heavier hydro-
carbons. The condensate is then fed to distillation columns
where the separate products are recovered. About 130 domestic
plants use refrigeration processes (PR-052).
Combinations of the above three basic methods are often
used to increase recovery of the liquefiable hydrocarbons.
Notably, 448 plants use combined refrigeration-absorption methods
(PR-052). In all of the processing methods, the dry natural gas
goes to pipeline sales, the LPG goes to sales or to the refinery,
and the natural gasoline goes to the refinery for further process-
ing or blending. There were 763 gas processing plants in the
United States in 1973 with an average total throughput of 55.6
billion cubic feet per day (FA-080).
Figures 10.2-1, 10.2-2, and 10.2-3 are flow diagrams
of some of the common gas treatment processes. Figure 10.2-1
illustrates an absorption process which incorporates an LPG-
natural gasoline splitter, Figure 10.2-2 is a refrigerated
absorber using chilled glycol as the absorbent. This system is
a more complex one and includes separation of the natural gas
liquids. The production includes lean natural gas, ethane, propane,
and small quantities of butane and heavier molecules. Figure
-205-
-------
RESIDUE GAS
RECVCLE GAS
RAW GAS
FROM FIELD
ABSORBER
STABILIZER
ABSORBER OIL
STRIPPER
SPLITTER
LPG
CH4.
ETHANE.
N2.
C02.
H2S
PROPANE
—*~
BUTANE
C4
LEAN OIL
HEAVIER
NATURAL
GASOLINE
FIGURE 10.2 - I
ABSORPTION PLANT
WITH LPG - NATURAL GASOLINE SPLITTER
(PR-C52)
-206-
-------
I
CO
O
100 F
4 STEAM -f
GLYCOL
NATURAL
GASOLINE
C4 & HEAVIER
TO SALES
•%*•!
W^
CH-OIL
EMATHANIZER
o: Q
U>
j
X"
^
FIGURE 10.2-2
REFRIGERATED ABSORPTION PROCESS
USING CHILLED GLYCOL AS ABSORBENT
(PR-052)
-------
fO
o
oo
s^
\
)
/
v^
t
NATURAL GAS
(FROM FIELD)
rr
C j D
D C
^•N
A B
7
/ ALUMINA OR
( CHARCOAL
\ PACKING
f/
C j D
D j C
ADSORBERS
h-
1
x*-^
\
}
/
*^_
1
1
^
/
/
v
\
.-X
(TO P.PEL.NE) ETHANE,
CONDENSER . N Co2
/][ SEPARATOR
j j LIQUIDS 0
S^
i ,
WATER
FIGURE 10.2 - 3
ADSORPTION PROCESS
(PR-052)
NOTE:
ADSORBER A ON LINE: ADSORBER B REGENERATING.
-------
10.2-3 is an adsorption process which incorporates two packed
columns: one on line while the other is regenerating.
10.3 Product Distribution and Storage
The natural gasoline fraction resulting from natural
gas processing is stored in conventional steel tanks prior to
shipment to the refineries. The mode of transportation is
usually pipeline, but tank trucks, tank cars, barges and tankers
are also used. The LPG fraction requires special handling.
It is conveniently handled in the liquid form, but exists at
atmospheric temperature and pressure in the gaseous state.
It must be stored in heavy-walled, high-pressure vessels prior to
being shipped in high pressure pipelines, tank trucks, rail
cars, barges, or tankers. It may also be stored in under-
•
ground formations. Refrigeration is also used in the handling the
LPG fraction. With this method, the cooled liquid is stored in
insulated tanks and transported in refrigerated vessels.
10.4 Emissions
The hydrocarbon emissions from natural gas processing
plants result from evaporative losses of the low molecular
weight, saturated hydrocarbons. The losses occur from storage
tank breathing and filling, and from leaks in pumps, valves,
compressors, and other machinery. The natural gas processing
plants are essentially miniature refineries, but have a lower
air pollution potential because of simpler process schemes and
lower thermal requirements (ZA-041).
-209-
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10.5 Emission Controls
Emission sources in natural gas processing plants are
similar to those found in refineries. The emission control
measures outlined for refinery emission sources in Section 5.3
are directly applicable. This includes control measures available
and the effects of pump and compressor seal leaks, pipeline valve
and flange leaks, and loading and storage emissions. Gasoline
handling emissions and their control are also applicable. These
are discussed in detail in Section 6.0.
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11.0 LIQUEFIED PETROLEUM GASES
11.1 Sources and Quantities
Liquid petroleum gas comes from two sources: natural
gas processing plants and refineries. Bureau of Mines data shows
total production of LPG for 1973 to be 466 million barrels
(US-156). Of this, 339 million barrels were contributed by
gas plants while 127 million barrels were produced by refineries.
The LPG from refineries, which is sometimes called liquid re-
finery gas (LRG), differs from LPG from gas plants in that it
may contain some olefins. Before this LRG can be shipped to fuel
sales, it must be passed through a polymerization unit to re-
duce the concentration of olefins which will tend to form a
gummy residue in pipes and vessels. In addition to the LPG
produced domestically, the United States imported 48 million
barrels in 1973. Figure 11.1-1 represents the production and
disposition of LPG in the United States for 1973 (US-156).
11.2 Recovery of LPG from Refineries
Crude oil stored at atmospheric pressure contains
very little propane and butane. The gas streams from thermal
and catalytic cracking, reforming, and coking units, however,
contain appreciable quantities of propane, propylene, butanes, and
butylenes. These components are extracted and separated by
conventional absorption, adsorption, condensation, and frac-
tionation processes. The LPG is treated to remove hydrogen
sulfide and moisture before being delivered to commercial sales.
The olefins are nominally used as petrochemical feedstocks.
-211-
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Gas Plants
339
Refineries
127
Domestic Production
466
N5
to
I
Exports
10
-*>
Storage
4-15 (gain)
Domestic Use
489
FIGURE 11.1-1
Disposition of LPG for 1973
(Rates in millions of barrels per year)
Refinery Fuel
80
LPG For Chemical and
Fuel Use
281
LRG For Fuel
90
LRG For
Chemical Use
38
-------
11.3 Distribution, Storage and Handling
LPG is stored and shipped as a liquid and used as a gas;
it must be kept under a moderate pressure. Consequently,
storage and transfer tanks must have a design pressure of about
250 psig.
LPG can be stored at the necessary points along the
distribution chain in underground formations or aboveground
in horizontal cylindrical or spherical pressure tanks. Spheres
in the 5000 to 10,000 barrel range are common, with some as large
as 20,000 barrels. Horizontal cylindrical tanks are usually of
30,000 gallon capacity, although some are 60,000 gallons or
larger. Most of the storage is at the point of production.
The distribution pattern of LPG has changed from local
distribution in small containers to distribution in bulk in
large vessels by road, rail, or sea. In North America, rail
tank cars have capacities of up to 80 tons (50,000 gallons).
Tank truck capacities are in the 20 ton category. LPG is
similarly transported at sea in large pressure vessels. Pipe-
lines are commonly used in North America to move LPG over long
distances from refineries and gas wells to major industrial and
utility users.
Transfer from tank cars or tank trucks is through a
closed system of high pressure lines by means of a liquid pump,
gas compressor, or gas pressure. Connections are made by flexible
hoses or pipes. If a pump is used, liquid is pumped from the
transport tank into storage, the pressures being equalized
through the connections. If a compressor is used, vapor is
taken from the storage container and discharged into the vapor
space of the tank car or truck, creating a pressure differential
-213-
-------
between the two which forces liquid into the storage container.
Gas under pressure may be used to increase the tank car pressure
and force liquid to flow to the storage tank.
An alternative to handling LPG under high pressure is
handling it at reduced temperatures. At the lower operating
pressures, it can be stored and transported in lighter, in-
sulated tanks. The refrigerated LPG may be stored in underground
pits or in depleted formations to await transport, It may
also be shipped in ocean-going tankers more easily and more
economically than in pressure vessels. The economic incentive
has caused the method of distribution by sea to change drastically
from the use of pressure vessels carrying several hundred tons
to refrigerated vessels carrying ten thousand tons or more,
11.4 Emi s s ions
Emissions from LPG consist of evaporative losses of
propane and butane, low molecular weight saturated hydrocarbons.
At any point that the system is open to atmospheric temperature
and pressure, emissions will result. However, since LPG must
be stored and handled under pressure it is seldom exposed to
the atmosphere except through fugitive leaks. Refinery produced
gas will, in addition, add emissions of propylene and butylenes,
photochemically reactive hydrocarbons.
11.5 Emission Controls
Because hydrocarbon emissions from LPG marketing
operations are predominantly due to fugitive losses, emission
controls consist of good housekeeping practices and regular
maintenance of potential leak sources, i.e. valves, fittings,
and seals.
-214-
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12.0 PETROCHEMICAL FEEDSTOCKS
The petrochemical industry has become an important,
integral part of the oil industry. Measured by volume of feed
and products, the petrochemical industry represents a relatively
small part of the total petroleum industry; however, these
products are valued much higher per unit weight than average
oil products. The United States' production of petrochemical
feedstocks in 1973 was in excess of 326 million barrels. The
main feedstocks for the industry are hydrocarbons present in natural
gas and other hydrocarbons produced in refinery operations,
such as olefins, aromatics, and higher molecular-weight paraffins.
The petrochemical industry is very complex, involving thousands
of products and intermediates for other industries. This dis-
cussion, while limited to a few basic feedstocks and their
ultimate uses, is intended to illustrate the variety of chemicals
derived from petroleum based stocks.
12.1 Methane
Methane from natural gas is used in several important
processes. Ammonia is produced by reforming or oxidation of
methane to yield hydrogen which is catalytically reacted with
nitrogen from the atmosphere to yield ammonia, primarily for use
in fertilizers.
Methyl alcohol is another important methane-derived
petrochemical. Methane is converted to a synthesis gas mixture
of hydrogen and carbon monoxide which is then used in the
manufacture of methyl alcohol, higher alcohols, and synthetic
\
gasoline.
-215-
-------
Acetylene, made by controlled oxidation of natural gas,
is used to make vinyl chloride, acrylonitnile, neoprene rubbers,.
acetaldehyde, acetic acid, perchloroethylene, and trichloroethylene
Hydrogen cyanide formed by passing methane and ammonia over a
catalyst is used in the manufacture of acrylonitrile and adi-
ponitrile for the synthetic fiber industry. Chlorinated solvents
are produced by reacting methane with chlorine, the product
depending on the number of chlorine atoms attached to the molecule.
Methane reacted with sulfur gives carbon disulfide for use in
rayon manufacture. Controlled combustion of methane produces
carbon black for use in inks and in tire manufacture.
12.2 Ethane-Ethylene
Ethylene, which is used as a feedstock for a large
number of products, is produced primarily from pyrolysis of
ethane and propane, although in recent years, heavier cracking
stocks such as naphtha and gas oil, are becoming more widely used.
Polyethylene and ethylene oxide are the major ethylene-based
products. Ethylene glycol for antifreeze, ethanolamines,
acrylonitrile, and di- and tri-ethylene glycol are derived from
ethylene oxide.
Ethyl alcohol made by hydration or hydrolysis of
ethyl sulfa'tes is a principal industrial solvent. It can be
further processed to acetaldehyde which can then be oxidized to
acetic acid and acetic anhydride.
Ethyl benzene, made by the reaction of ethylene and
benzene is dehydrogenated to form styrene which is used in
production of synthetic rubber and polystyrene. Ethyl chloride,
made by the addition of hydrogen chloride to ethylene is further
used to manufacture tetraethyl lead. Ethylene dichloride is
produced by catalytically reacting ethylene and chlorine and is
used to make vinyl chloride, polyvinyl chloride, and ethylene
diamine.
-216-
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12.3 Propane-Propylene
The hydrocarbon components of LPG and LRG (liquid re-
finery gas) serve as important feedstocks for the petrochemical
industry. Propane can be oxidized to give methyl alcohol, formal-
dehyde, acetaldehyde, and acetone. Isopropyl alcohol, which is
made by hydration of propylene, is used for solvents, deicing
additives, antifreeze, rubbing alcohols, and as feedstock for the
production of acetone. Low weight polymers of propylene are used
in synthetic detergents.
Propylene oxide, made by the chlorohydrination of
propylene, is hydrated to both propylene glycol and dipropylene
glycol used in the manufacture of polyurethane foams. Chlorina-
tion of propylene yields allylchloride which is used in the manu-
facture of glycerine "and epoxy resins and also yields propylene
dichloride. Direct oxidation of propylene gives acrolein.
Alkylation of propylene and benzene yields cumene which is
used in the production of phenol, acetone, and methyl styrene.
The increasingly important polypropylene is made by polymerization
of propylene.
12.4 Butane-Butylenes
Catalytic dehydrogenation of butane yields butylenes
and butadienes. Oxidation of butane yields acetic acid, acetalde-
hyde, methyl alcohol, propionic acid, butyric acid, n-propyl
alcohol, n-butyl alcohol, and isobutyl alcohol. Butylenes,
recovered to a large extent from refinery gases are used in
making butadiene and isobutylenes for synthetic rubber manu-
facture, secondary butyl alcohol and methyl ethyl ketone.
7-
-------
12.5 Aromatics
The main aromatics recovered from reforming operations
are benzene, toluene and the xylenes. This group of compounds
is an important source of chemical intermediates. Benzene
alkylated with ethylene gives ethyl benzene from which styrene
is obtained by dehydrogenation. Phenol, an important interme-
diate in the manufacture of synthetic resins, nylon, herbicides,
and disinfectants, is also made from benzene. Toluene is used
as a solvent and in the manufacture of trinitrotoluene and poly-
urethane. The three xylene isomers are oxidized to phthalic acids,
used in the synthetic fiber industry.
12.6 Emissions
Emissions from producing and handling petrochemical
feedstocks contain a relatively high percentage of reactive and
toxic hydrocarbon compounds such as the olefins and the aromatics
in addition to saturated hydrocarbons of a very unreactive nature.
The emissions from production of petrochemical feedstocks at
refineries are part of the total refinery losses discussed
in Section 5.0. The high economic value of petrochemical
feedstocks has been an incentive for the petroleum industry
to minimize their loss to the atmosphere.
-218-
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13.0 STATUS OF CONTROL TECHNOLOGY
This section contains a review of the existing control
technology applicable to hydrocarbon emission sources, areas
where this control technology remains to be applied, and areas
where further technology development is required.
13.1 Existing Control Technology
To summarize, the status of existing control measures
for hydrocarbon emissions from the petroleum industry are as
follows:
Storage and loading losses - fixed roof tanks
can be replaced with floating roof tanks,
products can be bottom loaded, and excess
vapors from loading operations and tankage
can be processed in vapor recovery units.
Wastewater systems - systems can be enclosed,
and vapors purged from the systems can be
combusted or recovered in a vapor recovery
unit.
Pump and compressor seals - packed seals can be
replaced with mechanical seals, and double
seals can be installed. Regular maintenance
and good housekeeping are also important
control measures.
Relief valves - rupture discs can be placed upstream
ot the relief valve, or the valve can be
vented to a blowdown system.
Catalyst regeneration - regeneration off gas can
be combusted in either a CO boiler or an
incinerator.
Vacuum jets and_barometric condensers - replace
vacuum jets with mechanical pumps, barometric
condensers with surface condensers, and
vent non-condensable gases to a vapor recovery
or a vapor disposal unit.
-219-
-------
Slowdown systems - can be designed for recycling
condensable hydrocarbons and processing non-
condensables in vapor disposal or vapor re-
covery units.
Asphalt blowing - off gases can be incinerated
and/or water scrubbed.
Pipeline valves and flanges,and miscellaneous
fugitive losses - improved housekeeping and
regular maintenance are the best control
measures.
Service station bulk fuel drops - vapor dis-
placement from the underground tank to the
unloading tank truck. Pressure-vacuum
valves on the tank vent.
Automobile refueling - in cases where good
nozzle fits are possible, displaced
vapors from the automobile tank can be
routed to the underground tank. Vacuum
units coupled with vapor recovery units
are also available to control gasoline
vapors displaced during automobile re-
fueling.
Good housekeeping practices and regular maintenance play a very
important role in all hydrocarbon emission control measures,
especially for the control of fugitive emissions.
Table 13.1-1 summarizes the major hydrocarbon emission
sources identified for each area of the petroleum industry.
Table 13.1-1 also presents average emission factors for the un-
controlled emission source, for the average emission source based
on current degrees of control, and for a fully controlled emission
source.
13.2 Current Application of Control Technology
Good indicators of the degree of emission control
currently being applied to hydrocarbon emission sources in the
-220-
-------
TABLE 13.1-1
SUMMARY OF CONTROLLED AND UNCONTROLLED HYDROCARBON EMISSIONS,FROM THE PETROLEUM INDUSTRY
I
tsj
N3
Natural Gas Production
and Processing
vented nat. gas
fugitive nat. gas leaks
Crude Oil Production
storage
wastewater separator
punp seals
compressor seals
relief valves
pipeline valves
Crude Transportation
storage
rail & truck loading
marine loading
Refinery Operations
boilers & heaters
compressor engines
storage
loading operations
FCC unit
TCC unit
vacuum jets
blcwdown
asphalt blowing
process drains & waste-
water separators
punp seals
compressor seals
pressure relief valves '
cooling tower
pipeline valves & flanges
blind changing
sampling
other
Residual Fuels
Natural Cas Liquids
Liquefied Petroleum
Gases
1973
Throughput
Rate
65.9xlO'SCF/day
65.9xlO*SCF/day
9.2xlO*bpd
9.2xlO'bpd
9.2xlO°bpd
9.2xlO'bpd
g^xlO'bpd
9.2xlO'bpd
12.4xlO*bpd
0.2xlO'bpd
l.lxlO'bpd
12.4xlO*bpd
12.4xlOf'bpd
12.4xlO'bpd
12.4xlO'bpd
4.03xlO''bpd
a.38xlO'bpd
12.4xlO'-bpd
12.4xl06bpd
0.65xlO*bpd
12.4xlO*bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
12.4xlO'bpd
2.8 xlO'bpd
1.73xlO'bpd
1.41xlO*bpd
Emission Factors
Uncontrolled
NA
NA .
NA
NA
NA
NA
NA
NA
660 lbs/10'bbl
540 lbs/10'bbl
UD
UD
1200 lbs/10Jbbl
32 lbs/103bbV
220 lba/10'bbC
87 lbs/K>3bb$
57 lbs/10'bbl
325 lbs/103bbl
60 Ibs/ton
aophalt
200 lbs/10'bbl
UD
UD
11 lbs/10'bbl
UD
UD
UD
UD
UD
neg
NA
NA
Current
Controls
20 lbs/10'SCF
190 lbs/10'SCF
4 lbB/10'bbl
8 lbs/10'bbl
74 lbs/10'bbl
4 lbs/10'bbl
8 lbs/10'bbl,
12 lbs/103bbl
256 Ibs/lO'bbl
198 lbs/10'bbl
96 lbs/10'bbl
10 Ibs/lO'bbl
16 lbs/103bbl
470 lbs/103bbl
32 lbs/10'bbl
NA
NA
=57 lbs/10'bbl
160 lbs/103bbl
NA
105 lbs/10'bbl
17 lbs/103bbl
5 lbs/103bbl
11 lbs/103bbl
UD
28 lbs/103bbl
0.3 lbs/10'bbl
2.3 lbs/103bbl
7 lbs/10Jbbl
NA
NA
Completely
Controlled .
•*
NA
NA
NA
NA
NA
NA
NA
NA
136 lbs/10'bbl
90 lbs/103bbl
96 lbs/10'bbl
UD
UD
250 lbs/10'bbl
5 lbs/10'bbl
neg
neg
neg
5 lbs/103bbl
neg
10 lbs/10'bbl
UD
UD
neg
ffl
10 lbs/10'bbl
UD
UD
UD
UD
neg
NA
NA
Estimated
1973
* Emissions
(tons /day)
659
6261
WFZU total
17
36
339
17
36
53
591 total
1587
20
53
T6TTO" total
62
99
2914
198
111
4
353
992
neg
651
105
31
68
62
174
2
14
43
5B83 total
Comae nt on
Control Device Applied
vapor recovery
housekeeping, maintenance
floating roofs
cover
mechanical seals
mechanical seals
rupture discs, vapor
recovery
maintenance
floating roofs
bottom loading
bottom loading already in
use
housekeeping
floating roofs
vapor recovery
CO boiler
CO boiler
surface condenser, mechan-
ical purap
vapor recovery
incineration, scrubbing
cover
mechanical seals
mechanical seals
rupture discs, vapor
recovery
housekeeping
housekeeping, maintenance
housekeeping, purging
housekeeping
housekeeping, maintenance
-------
TABLE 13.1-1 - SUMMARY OF CONTROLLED AND UNCONTROLLED HYDROCARBON EMISSIONS FROM THE PETROLEUM INDUSTRY (Cent.)
Page 2
to
hO
t-0
I
Gasoline Marketing
bulk terminal
storage
loading
bulk station
storage
loading
service station
filling underground tk.
filling automobile
storage
aviation gasoline
storage
loading
Jet Fuel Marketing
Jet Naphtha
storage-breathing
storage-filling
rail/truck loading
marine loading
Jet Kerosene
storage -breath ing
storage-filling
rail/truck loading
marine loading
Diesel 6, Distillates
storage-breathing
storage-filling
truck/rail loading
marine loading
1973
Throughput
Rate
6.7xlO'bpd
6.7xlO'bpd
l.lxlO'bpd
l.lxlO'bpd
6.1xlO'bpd
6.1xlO'bpd
6.1xlO'bpd
45xl03bpd
45xlO'bpd
*6.7xlO'bbl
217xl03bpd
149xl01bpd
27xl03bpd
12.4xlO'bbl
833xlO'bpd
90xl03bpd
100xl03bpd
*218xlO'bbl
3.08xlO*bpd
.79xlO*bpd
.SOxlo'bpd
Emission Factors
Uncontrolled
600 lbs/10'bbl
520 lbs/103bbl
600 lbs/103bbl
520 lbs/103bbl
11.5 lbs/103gal
11.0 lbs/10'gal
1.0 lbs/103gal
600 lbs/10'bbl
520 lbs/103bbl
0.074 Ibs/d-lO32
gal
2.4 lbs/10'gal
1.8 lbs/103gal
NA
ff
0.038 lbs/d-10*2
gal
1.0 lbs/103gal
0.88 lbs/103gal
NA
0.038 lbs/d-103®
gal
1.0 lbs/103gal
0.93 lbs/10?gal
NA
Current
Controls
NA
NA
=600 lbs/10J
bbl
=520 lbs/103
bbl
= 9.4 lbs/103
gal
= 11.0 lba/10*
gal
=1.0 lbs/103
gal
600 Ib3/103bbl
520 lbs/10'bbl
NA
NA
NA
0.60 lbs/103
f,al
©
-0.038 Ibs/d-
10 3 gal
=1.0 lbs/103
gal
=0.88 lbs/10'
gal
0.27 lbs/103
gal
=0.038 Ibs/d®
103gal
1.0 lbs/10^gal
0.93 lbs/10*
gal
0.29 lbs/103
gal
Completely
Controlled
30 lbs/103bbl
17 lbs/10Jbbl
30 lbs/103bbl
17 lbs/103bbl
0.37 lbs/103
gal
1.10 lbs/10*
gal
neg
30 lba/103bbl
17 lbs/103bbl
0.02 lbs/d-103
gal
neg
0.91 lbs/103
gal
0.60 lbs/103
gal
3
0.009 Ibs/d-
10'gal
neg
0.45 lbs/103
gal
0.27 lbs/103
gal
0.009 lbs/d-®
103gal
neg
0.48 lbs/103
gal
0.29 lbs/101
gal
Estimated
1973
Emissions
(tons /day)
101
57
330
286
1204
1409
328
14
12
3541 total
10
11
6
0
10
17
2
1
57 total
174
65
15
2
7T6~ total
Comment on
Control Device Applied
floating roofs
bottom loading, vapor
r.ccovery
floating roofs
bottom loading, vapor
recovery
submerged fill, vapor
balance
vapor recovery, vapor
balance
vapor recovery
submerged fill, vapor
balance
vapor recovery
floating roofs
floating roofs
bottom loading
bottom loading already in
use
floating roofs
floating roofs
bottom loading
bottom loading already in
use
floating roofs
floating roofs
bottom loading
bottom loading already
in use
® units in lb/10'bbl of cat cracker capacity
© units in lb/103bbl of storage capacity
® Emission factors for existing cooling towers were too variant to average. However emissions from recently constructed
cooling towers are down to 10 lb/103bbl
NA - data not available
UD - emissions from this source were undefinable
neg- emissions are negligible
-------
petroleum industry are the "Current Control" emissions factors
presented in Table 13.1-1. The overall impact of applying
current control technology can be studied using the 1973
throughput rates.
The data presented in Table 13.1-1 also indicate that
in nearly all areas of the petroleum industry, existing control
technology has not been fully applied.
Natural gas production and processing is a major area
where the potential exists for significant hydrocarbon emissions
reductions. High pressures, presence of corrosive hydrogen
sulfide and moisture, volatility of the products, and remoteness
of the installations are factors which tend to increase hydro-
carbon losses from natural gas production and processing. Repair
and replacement of old and faulty equipment as well as good
housekeeping are major control measures. Normally vented hydro-
carbons can be routed to vapor recovery units. It should also be
noted, however, that while the hydrocarbon emissions from natural
gas operations are high, they are primarily methane, a non-
reactive hydrocarbon.
The high storage emissions occurring throughout the
petroleum industry are expected to decline as a greater number
of storage tanks are equipped to comply with current regulations
requiring floating roofs or vapor recovery.
Current emissions from vacuum jets equipped with baro-
metric condensers can be reduced to negligible levels by con-
verting to mechanical vacuum pumps, surface condensers, and by
venting non-condensable vapors to the blowdown system.
-223-
-------
There remain a sizable number of only partially con-
trolled blowdown systems. Application of existing hydrocarbon
recycle and vapor recovery technology to these systems will
greatly reduce refinery emissions.
One other group of significant hydrocarbon emission
sources in refineries for which there exists control technology
are process drains, wastewater systems, and wastewater separators.
Emissions for these sources can be reduced through minimizing the
contamination of water with oil and by enclosing all wastewater
systems. Manhole covers can be installed. There are now fixed
roofs and floating roofs for API oil-wastewater separators. In
some cases it may also be practical to vent enclosed wastewater
systems and separators to vapor recovery units,
The high hydrocarbon emissions from gasoline marketing
operations are expected to drop greatly as vapor recovery
systems are added to service stations and bulk terminals to
comply with new or pending regulations. Other reductions would
be realized with the addition of recovery systems at bulk
stations. At present, emission control regulations for bulk
stations are not defined, however.
The greatest progress towards full application of
control technology has been made in those areas exhibiting economic
incentives for control or in those areas governed by emission
regulations. Typical examples are volatile product storage where
the petroleum industry is installing floating roofs for product
conservation reasons, and gasoline marketing controls which were
induced in part by emission regulations.
-224-
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13.3 Gaps in Control Technology
Review of the "Completely Controlled" emission factors
indicate there is control technology available for all major
hydrocarbon emission areas within the petroleum industry. However,
two areas where further development may be required are floating
roof tanks and the service station portion of gasoline marketing.
The emission factors for completely controlled storage
tanks indicate that the hydrocarbon emissions from storage tanks
equipped with floating roofs will still be sizeable. For some
locations with specific hydrocarbon problems, it may be neces-
sary to improve floating roof seals or to develop other forms of
emission control.
Although the technology for controlling hydrocarbon
emissions from refueling automobiles is well developed there
remain several problems. Nozzle manufacturers have had dif-
ficulties designing a dispensing nozzle which consistently effects
a good seal at the nozzle-fillneck interface. Problems have
also arisen with the dependability and control efficiency of
service station vapor recovery units.
-225-
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Environmental Control, Hydr pc arbon Emi s s i on s F r om
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CI-005 Citizen's Advisory Committee on Environmental Quality,
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EN-182 Environmental Protection Agency, Emission Standards
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FA-080 Farrar, Gerald L., "Gas Capacity Is Up; Throughput,
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FO-027 Ford Foundation, Energy Policy Project, Exploring
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LA-129 Laster, L. L., Atmospheric Emissions From The Petroleum
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2-73-017, Control Systems Lab., EPA, Research Triangle
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REFERENCES (Cont.)
LU-044 Lundberg Survey, Inc., "Service Station Throughput.
Average Monthly Sales of Gasoline Per Station, 1973-
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1974).
MA-314 Maxwell, Robert, "Private Communication," EPA, Mobile
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MS-001 MSA Research Corp., Hydrocarbon Pollutant Systems Study,
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APTD-1499, PB 218 073, Evans City, PA (1972).
NA-168 National Petroleum News, Fact Book. Mid-May 1974,
McGraw-Hill, NY (1974).
NI-027 Nichols, Richard A., Control of Evaporation Losses in
Gasoline Marketing Operations,Parker-Hannifin,Irvine,
CA.
PR-052 Processes Research, Inc., Industrial Planning and
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02-0242, Cincinnati, Ohio (1972).
PR-074 Pross, T. W. , "Marine Transportation-State-Of-The-Art,"
Presented at the Intersociety Conference on Trans-
portation, Denver, Colorado, September 1973, New York,
ASME (1973).
RA-119 Radian Corporation, A Program to Investigate Various
Factors in Refinery Siting, 2 Vols., Final Report with
map inserts, Austin,. TX (1974) .
SH-137 Shelton, Ella Mae, Motor Gasolines. Winter 1971-72,
Petroleum Products Survey No.75, Bureau of Mines,
Washington, B.C.
SH-138 Shelton, Ella Mae, Motor Gasolines, Summer 1973,
Petroleum Products Survey No. 83, Bureau of Mines,
Washington, D.C.
TR-042 TRW, Inc., Transportation and Environmental Operations,
Photochemical Oxidant Control Strategy Development
For Critical Texas Air Quality Control Regions, Con-
tract No. 68-02-0048, Redondo Beach, CA (1973).
UN-016 "Underground Gas Storage Tops 6 Trillion," Oil Gas
Journal, Vol. 1, (July 1974).
-228-
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REFERENCES (Cont.)
US-031 U.S. Department of Commerce, Bureau of the Census,
1967 Census of Business, Vol. Ill'Wholesale Trade
Subject Reports, Washington (197IT.
US-143 U.S. Department of Transportation, Bureau of Public
Roads, High Statistics. 1972, Washington, D.C. (1973),
US-144 U.S. Bureau of Mines, Minerals Yearbook 1972, Vol. 1,
Metals, Minerals, and Fuels, Washington, D.C. (1974T.
US-156 U.S. Bureau of Mines, Crude Petroleum, Petroleum
Products, and Natural Gas Liquids, Monthly Petroleum
Statement, December 1973, Washington, D.C. (1973).
WA-086 Walters, R. M., "How An Urban Refinery Meets Air
Pollution Requirements," CEP 68 (11), 85 (1972).
ZA-041 Zaffarano, Richard F., Natural Gas Liquids: A Review
of Their Role in the Petroleum Industry, I.C. 8441,
Bureau of Mines, Washington, D.C.(1970).
-229-
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UNIT CONVERSIONS
To Convert From
Ib
bbl
lb/103 bbl
scf
ton
gal
lb/103 gal
Ib/ton
Btu/bbl
ton
Btu
To
kg
1
kg/103l
Nm3
MT
1
kg/103l
kg/MT
kcal/1-
kcal
Multiply By
0.454 '
159.0
.002855
0.0283
0.9072
3.785
0.1199
0.5004
1.585
907.2
0.252
-230-
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/2-7 5-042
3. RECIPIENT'S ACCESSION'NO.
4. TITLE AND SUBTITLE
Control of Hydrocarbon Emissions from
Petroleum Liquids
5. REPORT DATE
September 1975
6. PERFORMING ORGANIZATION CODE
7.AUTHORis)C.E.Burklin, E.G. Cavanaugh, J. C. Dicker-
man, S.R.Fernandes, and G. C.Wilkins
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard
P.O. Box 9948
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
1NB458; ROAP 21BJV-034
11. CONTRACT/GRANT NO.
68-02-1319, Task 12
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final: 7/74-9/75
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT.
The report is a state-of-the-art review of the availability and application
of technology for the control of hydrocarbon emissions to the atmosphere from
facilities for the production, refining, and marketing of liquid petroleum fuels. The
review includes: (1) identification of major hydrocarbon emission sources within the
petroleum industry and the quantity of such source emissions, (2) review of existing
hydrocarbon emission control technology and the extent of its application by the
petroleum industry, and (3) identification of hydrocarbon emission sources within
the petroleum industry for which control techniques are neither available nor widely
applied.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution
Control Equipment
Hydrocarbons
Petroleum Industry
Petroleum Refining
Refineries
Air Pollution Control
Stationary Sources
Hydrocarbon Emission
Control
13 B
14B
07C
13H
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report I
Unclassified
21. NO. OF PAGES
231
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
-231-
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