CORPORATION
SUMMARY REPORT
FOR
A SCREENING STUDY TO DETERMINE THE
EMISSION REDUCTION POTENTIAL NSPS
WOULD HAVE ON TRANSFER OPERATIONS
INVOLVING CRUDE OIL, JET FUELS
AND AVIATION GASOLINE
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RC Project No. 200-045-55
EPA Project No. 68-02-1319, Task 55
SUMMARY REPORT
FOR
A SCREENING STUDY TO DETERMINE THE
EMISSION REDUCTION POTENTIAL NSPS
WOULD HAVE OK TRANSFER OPERATIONS
INVOLVING CRUDE OIL, JET FUELS
AND AVIATION GASOLINE
Presented to:
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park
North Carolina 27711
Attention: Mr. C. F. Kleeberg
23 July 1976
Prepared by:
William C. Thomas
Staff Engineer
8500 Shoal Creek Blvd./P.O. Box 9948/Austin, Texas 787667(512)454-4797
I
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ABSTRACT
The purpose of this report is to provide the Environmental
Protection Agency with information on the hydrocarbon emission
reduction potential that new source performance standards (NSPS)
would have on segments of the petroleum transfer industry. In
this study transfer operations involving crude oil, kerosine jet
fuel, naphtha jet fuel, and aviation gasoline are investigated.
The emission reduction potential that NSPS would have on each of
these petroleum transfer segments by 1985 is determined by use of
the EPA developed calculational procedure known as Model IV.
The following information is included in this report:
1) Definition of each of the transfer segments, the
current throughput of each segment, and the
projected throughput of the transfer operation in
1985.
2) Identification of the emission sources associated
with each transfer operation and emission esti-
mates for each source.
3) Identification of the best available emission
control techniques.
4) Identification of the various state emission
regulations applicable to each emission source.
5) Description of the method by which the industry
modifies or modernizes its facilities.
6) Estimation of the emission reduction potential
that NSPS would have on each petroleum transfer
industry segment by 1985.
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TABLE OF CONTENTS
Page
1.0 INTRODUCTION. 1 ... 1
2.0 SUMMARY 5
3.0 RECOMMENDATIONS 12
4.0 INDUSTRY STATISTICS 14
4.1 Crude Oil Transfer Industry Segment. ... 14
4.1.1 Baseline Year Statistics - Crude Oil 14
4.1.2 Projected Industry Size in 1985 -
Crude Oil 19
4.2 Kerosine-Based Jet Fuel Transfer Industry
Segment 25
4.2.1 Baseline Year Statistics - Kerosine
Jet Fuel 25
4.2.2 Projected Industry Size in 1985 -
Kerosine Jet Fuel 31
4.3 Naphtha-Based Jet Fuel Transfer Industry
Segment 42
4.3.1 Baseline Year Statistics - Naphtha
Jet Fuel 42
4.3.2 Projected Industry Size in 1985 -
Naphtha Jet Fuel 44
4.4 Aviation Gasoline Transfer Industry
Segment 50
4.4.1 Baseline Year Statistics - Aviation
Gasoline 50
4.4.2 Projected Industry Size in 1985 -
Aviation Gasoline 53
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TABLE OF CONTENTS (Cont.)
Page
5.0 BASELINE YEAR EMISSIONS 59
5.1 Hydrocarbon Emission Sources . 59.
5.1.1 Tank Filling Operations 60
5.1.2 Storage Facilities 61
5.1.3 Pump Seals and Valves 68
5.2 Emission Factors for Important Sources ... 71
5.2.1 Crude Oil Production Facilities ... 73
5.2.2 Tank Loading 74
5.2.3 Storage Facilities 78
5.2.4 Pumps and Valves 84
5.3 Summary of Transfer Emissions 85
6.0 APPLICABLE BEST SYSTEMS OF EMISSION REDUCTION . . 90
6.1 Loading Operations 90
6.1.1 Vapor Collection Systems. ...... 91
6.1.2 Vapor Recovery Units 95
6.1.3 Efficiency of Vapor Recovery Units. . 99
6.2 Storage Facilities 104
6.3 Pump and Valve Emission Controls 105
6.4 Summary of Emissions Using Best Available
Control Systems 107
7.0 CURRENT STATE HYDROCARBON EMISSION REGULATIONS. . 113
8.0 FACILITY MODIFICATION AND MODERNIZATION 126
9.0 ESTIMATED EMISSION REDUCTION 128
9.1 Model IV . 128
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TABLE OF CONTENTS (Cont.)
Page
9.2 Model IV Results 132
9.2.1 Crude Oil Transfer Segment 132
9.2.2 Kerosine Jet Fuel Segment 134
9.2.3 Naphtha Jet Fuel Transfer Segment . 140
9.2.4 Aviation Gasoline Transfer Segment. 143
10.0 FUGITIVE EMISSIONS FROM PUMP SEALS AND VALVES . 148
APPENDIX A FLOATING ROOF STANDING STORAGE AND
FIXED ROOF TANK BREATHING LOSSES
APPENDIX B MODEL IV CALCULATIONS
APPENDIX C BIBLIOGRAPHY
IV
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LIST OF TABLES
TABLE NO.
Table 2-1
Table 2-2
Table 2-3
Table 2-4
Table 4-1
Table 4-2
Table 4-3
Table 4-4
Table 4-5
Table 4-6
Table 4-7
Table 4-8
Table 4-9
Table 4-10
Table 4-11
Table 4-12
TITLE
National Emission Reduction by 1985* - Crude
Oil Transfer
National Emission Reduction by 1985* -
Kerosine Jet Fuel Transfer
National Emission Reduction by 1985* -
Naphtha Jet Fuel Transfer
National Emission Reduction by 1985* -
Aviation Gasoline Transfer
Crude Oil Statistics
1974 Domestic Crude Production of Major
Oil Companies
1985 Projections of Domestic Crude Oil
Production and Imports
Historical Crude Oil Data
Refinery Receipts of Crude Oil by Method
of Transportation
Summary of 1985 Refinery Receipts of Crude
1972 Petroleum Bulk Facilities by Size
and Storage Capacity of Jet Fuels
Major Air Traffic Hubs in U.S. in 1974
Kerosine Jet Fuel Statistics for 1966-75
Pipeline and Tanker /Barge Transport of
Kerosine Jet Fuel
Kerosine Jet Fuel Usage
Naphtha Jet Fuel Statistics for 1966-75
PAGE
8
9
10
11
17
18
20
22
23
26
32
33
34
38
40
45
Table 4-13
1972 Petroleum Bulk Facilities by Size and
Storage Capacity of Aviation Gasoline
52
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LIST OF TABLES (Cont.)
TABLE NO.
Table 4-14
Table.5-1
Table 5-2
Table 5-3
Table 5-4
Table 5-5
Table 5-6
Table 5-7
Table 5-8
Table 5-9
Table 5-10
Table 6-1
Table 6-2
Table 6-3
Table 6-4
TITLE PAGE
1966-74 Aviation Gasoline Statistics 54
Parameters for Emission Calculations 72
Estimated Hydrocarbon Emissions from Crude
Oil Production 75
S Factors for Equation 5-1 77
Emission Factors for Loading Petroleum
Liquids 79
Fixed Roof and Underground Storage Emission
Factors 81
Underground Tank Filling Losses 83
Emission Rates from Crude Oil Transfer Based
on an Example Throughput of 159 m3/Day
(1000 bbl/Day) 86
Emission Rates from Kerosine-Based Jet Fuel
Transfer Based on an Example Throughput of
159 rnVday (1000 bbl/day) 87
Emission Rates from Naphtha-Based Jet Fuel
Transfer Based on an Example Throughput of
159 mVday (1000 bbl/Day) 88
Emission Rates from Aviation Gasoline
Transfer Based on an Example Throughput
of 159 m3/day (1000 bbl/Day) 89
Vapor-Air Mixture Compositions Used in
Equilibrium Calculations 101
Summary of Equilibrium Calculations 101
Vapor Recovery Efficiencies for Refrigera-
tion Type Vapor Recovery Units 103
Effectiveness of Mechanical and Packed
Pump Seals on Various Types of Hydrocarbons 106
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LIST OF TABLES (Cont.)
TABLE NO.
TITLE
Table 6-5 Achievable Emission Rates from Crude Oil
Transfer Based on an Example Throughput of
159 ra3/Day (1000 bbl/Day)
Table 6-6 Achievable Emission Rates from Kerosine
Based on an Example Throughput of 159 m3/
Day (1000 bbl/Day)
Table 6-7 Achievable Emission Rates from Naphtha-
Based Jet Fuel Transfer Based on an
Example Throughput of 159 m3/Day (1000
bbl/Day)
Table 6-8 Achievable Emission Rates from Aviation
Gasoline Transfer Based on an Example
Throughput of 159 m3/Day (1000 bbl/Day)
Table 7-1 Summary of State Hydrocarbon Emission
Regulations
Table 7-2 Comparison of Best Available Control System
and Current Control Emission Levels* -
Crude Oil Transfer Segment
Table 7-3 Comparison of Best Available Control System
and Current Control Emission Levels* -
Kerosine Jet Fuel Transfer Segment
Table 7-4 Comparison of Best Available Control System
and Current Control Emission Levels* -
Naphtha Jet Fuel Transfer, Segment
Table 7-5 Comparison of Best Available Control System
and Current Control Emission Levels* -
Aviation Gasoline Transfer Segment
Table 9-1 Summary of Input/Output Variables for Model
IV Crude Oil Transfer
Table 9-2 National Emission Reduction by 1985*
Crude Oil Transfer
t
Table 9-3 Summary of Input/Output Variables for
Model IV Kerosine Jet Fuel Transfer
PAGE
108
109
110
111
114
122
123
124
125
133
135
136
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LIST OF TABLES (Cont.)
TABLE NO.
Table 9-4
table 9-5
Table 9-6
Table 9-7
Table 9-8
Table 10-1
TITLE
National Emission Reduction by 1985* -
Kerosine Jet Fuel Transfer
Summary of Input/Output Variables for
Model IV Naphtha Jet Fuel Transfer
National Emission Reduction by 1985* -
Naphtha Jet Fuel Transfer
Summary of Input/Output Variables for Model
IV Aviation Gasoline Transfer
National Emission Reduction by 1985* -
Aviation Gasoline Transfer
Hydrocarbon Emissions from Crude Oil and
Aviation Fuels Transfer in 1975
PAGE
139
141
144
145
147
150
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LIST OF FIGURES
FIGURE NO.
Figure 4-1
Figure 4-2
Figure 4-3
Figure 4-4
Figure 4-5
Figure 4-6
Figure 4-7
Figure 4-8
Figure 4-9
Figure 4-10
Figure 4-11
Figure 4-12
Figure 4-13
Figure 4-14
Figure 5-1
Figure 5-2
Figure 5-3
Figure 5-4
TITLE
Crude Oil Transfer Industry in 1975
Refinery Receipts of Crude Oil By Mode of
Transportation
Projected Crude Oil Transfer Industry in
1985
1975 Kerosine-Based Jet Fuel Transfer
Industry
Indicated Demand for Kerosine Jet Fuel
Projected Kerosine-Based Jet Fuel Transfer
Industry in 1985
1975 Naphtha-Based Jet Fuel Transfer
Industry
Indicated Demand for Naphtha Jet Fuel
Pipeline and Tanker/Barge Transport of
Naphtha Jet Fuel
Projected Naphtha-Based Jet Fuel Transfer
Industry in 1985
1975 Aviation Gasoline Transfer Industry
Indicated Demand for Aviation Gasoline
Pipeline and Tanker/Barge Transport of
Aviation Gasoline
Projected Aviation Transfer Industry in 1985
Fixed Roof Storage Tank
Double Deck Floating Roof Storage Tank
(Non-Metallic Seals)
«.
Covered Floating Roof Storage Tank
Lifter Roof Storage Tank (Wet Seal)
PAGE
15
24
27
28
36
41
43
47
48
49
51
55
57
58
62
63
64
66
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LIST OF FIGURES (Cont.)
FIGURE NO. TITLE PAGE
Figure 5-5 Flexible Diaphragm Tank (Integral Unit) 67
Figure 5-6 Packed Seal 69
Figure 5-7 Mechanical Seal 70
Figure 5-8 Turnover Factor (KN) for Fixed Roof Tanks 80
Figure 6-1 Top Loading Arm Equipped with a Vapor
Recovery Nozzle 92
Figure 6-2 Detail of a Vapor Recovery Nozzle 93
Figure 6-3 Bottom Loading Vapor Recovery 94
Figure 6-4 Schematic of a Terminal Vapor Recovery Unit 97
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1.0 INTRODUCTION
Section 111 of the Clean Air Act charges the Administrator
of the Environmental Protection Agency (EPA) with the responsi-
bility of establishing Federal standards of performance for new
stationary sources which may significantly contribute to air
pollution. These new source performance standards (NSPS) are to
reflect the degree of emission limitation achievable through
application of the best demonstrated control methods considering
cost. In order to achieve, in a time effective manner, the
greatest emission reduction from the promulgation of NSPS, EPA
is preparing a list of industries, prioritized according to the
impact NSPS would have on each industry's emissions. As part of
the preparation of this prioritized list, EPA contracted Radian Cor-
poration (EPA Contract No. 68-02-1319 Task 55) to perform a screening
study to determine the emission reduction potential NSPS would
have on transfer operations involving crude oil, jet fuels and
aviation gasoline. This report presents the results of this
screening study.
Scope of Work
The purpose of this study is to determine the hydrocarbon
emission reduction potential NSPS would have on the crude oil, jet
fuel and aviation gasoline segments of the U.S. petroleum transfer
industry. The movement of crude oil from domestic oil wells and
importers to refineries is accomplished via a complex network in-
volving tank farms and bulk terminals connected by overland and
water transportation systems. Similarly, the distribution of re-
fined petroleum products from refineries to end users requires a
network of intermediate storage and transfer points connected by
overland and water transportation systems.
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At the present time, federal NSPS have been promulgated
for storage vessels for petroleum liquids. These regulations
affect storage vessels with capacities greater than 151,000 liters
(40,000 gallons) that contain petroleum liquids with vapor pressures,
as stored, equal to or greater than 78 mmHg (1.5 psia). Specifically
excluded from these NSPS are storage vessels for crude oil or
lease condensate located at drilling and production sites prior
to custody transfer. Since portions of the storage facilities
found in the petroleum transfer industry are regulated by the above
NSPS, they will not be included in the emission calculations of this
study. In addition, refinery storage of crude oil and products
is specifically excluded from the scope of work of this study.
For the storage vessels which are not regulated by the
existing federal NSPS, only hydrocarbon emissions resulting
from filling and withdrawal of liquid are considered in the
analysis portion of this study. Breathing or standing storage
losses are considered to be an indirect result of transfer opera-
tions and are discussed in Appendix A.
Approach
In order to evaluate the emission reduction potential
NSPS would have on an industry, EPA developed a calculational
procedure called Model IV. The execution of Model IV entails
the use of two sets of conditions to estimate an industry's
emissions ten years from a baseline year. (In this study 1975
is the baseline year and 1985 is the calculational year.) The
first emission calculation is made by assuming emissions in 1985
will be controlled to the level required by the baseline year
regulations. The second calculation of 1985 emissions assumes that
after the baseline year, all new emission sources will be required
to utilize the best available emission control techniques. The
difference between the two estimates is the emission reduction
potential of NSPS.
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The execution of Model IV requires the following in-
formation:
1) a description of the industry and its present and
projected throughput,
2) identification of the industry's emission sources and
emission estimates for each source,
3) identification of the best available emission control
technique for each emission source,
4) the various state emission regulations applicable to
each emission source in the industry, and
5) the method by which the industry modifies or moder-
nizes its facilities.
The structure of this report is arranged to present this material
in a logical and organized manner. Section 4.0 provides a brief
discussion of the operations that comprise each of the four transfer
industry segments, identifies the historical and baseline year
throughput of each operation and makes projections of each operation's
throughput in 1985. Emission factors for each emission source are
developed in Section 5.0 while Section 6.0 identifies the best
available control techniques for each source and develops emission
factors based on the application of these techniques. Section 7.0
summarizes the various state hydrocarbon emission regulations and
compares the emission levels required by state regulations to the
emission levels attainable with best available control techniques.
The methods used to modify and modernize facilities are identified
in Section 8.0.
Section 9.0 summarizes the input/output variables used
in executing Model IV and presents the emission reduction potential
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calculated for each transfer industry segment. Section 2.0 is
a summary of the important parts of this report while Section
3.0 contains recommendations for areas requiring additional study,
Section 10.0 discusses the potential importance of pump seal and
valve leaks to the emission levels of the crude oil and aviation
fuels transfer industry segments.
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2.0 SUMMARY
The emission reduction potential of NSPS for the crude
oil, kerosine-based jet fuel, naphtha-based jet fuel and aviation
gasoline segments of the petroleum transfer industry were estimated.
Hydrocarbon emission sources found in these transfer segments in-
clude tank truck and rail car loading operations, tanker and barge
loading operations, aircraft refueling operations, intermediate
storage tanks, consumer storage tanks and process pumps and valves.
Emission factors for the above point sources are
calculated from American Petroleum Institute (API) correlations
(AM-039, AM-085), crude oil production emissions (MS-001), under-
ground storage tank emission data (CH-159) and fugitive emission
data for refinery operations °(DA-069, AT-040). For tank truck,
rail car, tanker and barge loading operations and fixed roof
storage tanks, vapor collection and recovery systems are utilized
as the best available emission control system while the vapor
balance method of filling is utilized as the best available control
system for underground tank storage facilities. No technique
is presently available for controlling aircraft refueling emissions.
The results of calculations using Model IV are summarized
in Tables 2-1 through 2-4. Based on the data from Table 2-1, by 1986
the emission reduction for the crude oil transfer segment is esti-
mated to be 15 x 106kg/yr (17 x 103tons/yr) or approximately 87o
of the emission level if NSPS are not promulgated in 1975. Over
70% of the total emission reduction or 10.6 x 106kg/yr (11.7 x
103tons/yr) is estimated to result from control of tanker/barge
loading operations. The major portion of the new tanker/barge
loading facilities are estimated to be located on Alaska's.
south shore.
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Table 2-2 is a summary of the results of emission re-
duction calculations for the kerosine jet fuel transfer industry
segment. The emission reduction potential, 189 x 103kg/yr (208
tons/yr), is approximately 32% of the emissions estimated to
occur if only baseline year regulations are in effect in 1985.
The major contributor to the emission reduction is fixed roof
tank losses, which accounted for 5870 of the total emission
reduction.
The data of Tables 2-3 and 2-4 show that NSPS will
not reduce emissions from the naphtha jet fuel or aviation gaso-
line transfer segments. The reason for the lack of any emission
reduction is the projected decline in domestic demand for these
two aviation fuels. Because of this decline no new emission
sources to which NSPS would apply are projected for the 1975-
1985 time frame.
The data of Tables 2-1 through 2-4 do not include pump
seal and valve emissions except for crude oil production facili-
ties. The crude production pump seal and valve emissions are
estimated because emission data were available for these sources
in-production service. The importance of these type emissions is
illustrated by the fact that of the 193 x 106kg/yr (213 x 103tons/
yr) of crude oil transfer related hydrocarbon emissions estimated
to occur in 1985, about 87% or 168 x 105kg/yr (185 x 103tons/yr)
will be from pump seal and valve leaks.
To illustrate what the relative importance of fugitive
emissions may be compared to the other emissions, estimates are
made of the number of pump units (which consist of one pump and
six valves) required in each transfer segment for these fugitive
emissions to equal the emissions from all other sources within the
transfer segment. Emission factors for pump seals and valves
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in refinery service (DA-069, AT-040) are used to make these
calculations, with the results of these calculations shown below.
Transfer Industry Number of Pump Units
Crude Oil 934,000 (86,000*)
Kerosine Jet Fuel 4,000
Naphtha Jet Fuel 109,000
Aviation Gasoline 49,000
*Based on excluding production pump seal and valve
emissions from the total crude oil emissions.
From these calculations, it is obvious that fugitive
emissions may potentially represent a significant portion of the
total emissions from the petroleum transfer industry.
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TABLE 2-1
I
00
Emissions Source
1. Crude Oil Production
Storage Tanks
Pump Seals
Pipeline Valves
Production Subtotal
2. Truck/Rail Loading
3. Tanker/Barge Loading
INDUSTRY TOTAL
Vapor
Vapor
Vapor
NATIONAL EMISSION REDUCTION BY 1985*
CRUDE OIL TRANSFER
Emission Rate with
Best Available System,
Control Techniques 10skg/yr(103tons/yr)
Collection and Recovery 4.3 (4.7)
145 (160)
23.1 (25.4)
172 (190)
Collection and Recovery 2.33 (2.57)
Collection and Recovery 3.20 (3.52)
178 (196)
Emission Rate Under
1975 Controls,
108kg/yr(103tons/yr)
7.5 (8.3)
145 (160)
23.1 (25.4)
176 (194)
3.53 (3.89)
13.8 (15.2)
193 (213)
Emission Reduction,
106kg/yr(103tons/yr)
3.2
0
0
3.2
1.20
10.6
15
(3.6)
(4)
(1.32)
(11.7)
(17)
*As Per Model IV evaluation (10 years)
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TABLE 2-2
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vO
Emission Source
1. Truck/Rail Loading _
2. Tanker/Barge Loading
3. Fixed Roof Tanks
4. Underground Tanks
5. Aircraft Refueling
INDUSTRY TOTAL
Vapor
Vapor
Vapor
Vapor
NATIONAL EMISSION REDUCTION BY 1985*
KEROSINE JET FUEL TRANSFER
Emission Race with
Best Available System,
Control Technique 10Jkg/yr(tons/yr)
Collection and Recovery 35.3 (38.9)
Collection and Recovery 2.7 (3.0)
Collection and Recovery 93 (103)
Balance System 55.7 (61.3)
NA 214 (236)
401 (442)
Emission Rate Under
1975 Controls,
10Jkg/yr (tons/yr)
63.3 (69.7)
3.6 (4.0)
203 (224)
106 (117)
214 (236)
590 (650)
Emission
Reduction!
103kg/yr(tons/yr)
28.0 (30.8)
0.9 (1.0)
110 (122)
50.3 (55.7)
0
189 (208)
As per Model IV evaluation (10 years)
NA - none available
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TABLE 2-3
Emission Source
I. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Tanks
I
1 i 4. Underground Tanks
O
1 5. Aircraft Refueling
NATIONAL EMISSION REDUCTION BY
NAPHTHA JET FUEL TRANSFER
Emission Rate With
Best Available System
Control Technique 106kg/yr(103tons/yr)
** 2.12 (2.33)
** 0.06 (0.07)
** 1.61 (1.77)
** 0.42 (0.46)
**-NA 2.27 (2.5)
1985*
Emission Rate Under
, 1975 Controls,
106kg/yr(103tons/yr)
2.12 (2.33)
0.06 (0.07)
1.61 (1.77)
0.42 (0.46)
2.27 (2.5)
Emission Reduction,
106kg/yr(103tons/yr)
0
0
0
0
0
INDUSTRY TOTAL
6.48 (7.14)
6.48 (7.14)
As per Model IV evaluation (10 years)
**
No new sources to which controls can be applied
NA - none available
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TABLE 2-4
NATIONAL EMISSION REDUCTION BY 1985*
AVIATION
GASOLINE TRANSFER
Emission Rate With
1.
2.
3.
It.
5.
Emission Source
Truck/Rail Loading
Tanker/Barge Loading
Fixed Roof Tanks
Underground Tanks
Aircraft Refueling
Best Available System,
Control Technique 103kg/yr(tons/yr)
** 903
** 34
** 187
** 684
**-NA 735
(994)
.3 (37.8)
(206)
(753)
(809)
Emission Rate Under
1975 Controls,
10'kg/yr(tons/yr)
903 (994)
34.3 (37.8)
187 (206)
684 (753)
735 (809)
Emission Reduction,
103k*s/yr(tons/yr)
0
0
0
0
0
INDUSTRY TOTAL
2,543 (2800)
2.543 (2800)
As per Model IV evaluation (10 years)
**
No new sources to which controls can be applied
NA-none available
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3.0 RECOMMENDATIONS
The recommendations contained in this section pertain
to the availability of up-to-date hydrocarbon emission data for
the various emission sources in the petroleum transfer industry.
During the course of this study, several areas were identified
wherein little or no emission data existed or the data that were
available were a result of studies performed 15 to 20 years ago.
The following recommendations summarize the areas in which further
studies should be initiated:
1) More comprehensive emission data for emissions
from crude oil production operations should be
obtained. The crude oil production emission
data used in this study were taken from a study
performed in 1968 in a specific production area
of California (MS-001). No description of the
types or conditions of the facilities was given
with the emission data. Since crude production
emissions are estimated to be over 90% of the
crude oil transfer segment's total emissions
(as defined in this study), the importance of
accurate production emission data is evident.
Test data should be gathered for a variety of
production facility configurations and operating
conditions. These data could then possibly be
correlated with various equipment and operating
parameters to provide an accurate emission es-
timate technique.
2) Tests to determine emission rates from sources
such as pump seals, valves, flanges, etc.,
should be performed. The best data for these
fugitive losses are based on refinery data taken
in the 1950's. Whether these data accurately
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reflect state-of-the-art control technology
and are applicable to nonrefinery service
should be ascertained. Correlations should
be developed to relate fugitive emission rates
to flow rates through the piece of equipment
and to the vapor pressure of the product
handled.
3) More test data related to emissions from tanker
and barge loading operations are needed. The
American Petroleum Institute has developed
correlations for estimating these emissions,
but their work was based on a very limited amount
of data that was taken in the 1950's (AM-085).
A broader sampling of loading operations under
a variety of conditions will provide for a
better understanding of the emissions from these
sources and the factors that affect them.
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4.0 INDUSTRY STATISTICS
In order to utilize Model IV to estimate the emission
reduction potential NSPS will have on an industry, the industry
must first be defined and its throughput identified. Then
historical data or industry growth projections must be examined
to determine the industry's future size. In the following sections
pertinent statistics are presented for each industry segment and
'the growth rates of these segments are estimated. The crude oil
transfer segment is discussed in Section 4.1 while Sections
4.2-4.4 describe the kerosLne-based jet fuel, naphtha-based
jet fuel and aviation gasoline segments respectively. Other
information of interest such as the size distribution of facilities
and the major companies involved in the transfer industry are
also included in these sections.
4-1 Crude Oil Transfer Industry Segment
Crude oil is transported to refineries by pipelines,
tank trucks, rail cars, barges and tankers. The transport of
crude oil from domestic wells and importers to U. S. refineries
is schematically shown in Figure 4-1. The flow rates shown are
for the baseline year of 1975.
4.1.1 Baseline Year Statistics - Crude Oil
Total domestic production of crude oil and lease
condensate in 1975 amounted to 485xl.06ra3 (3.05xl09 bbl). Approxi-
mately 1670 of this production was from offshore wells. Imports of
crude oil in 1975 totaled 238xl06m3(1.SOxlO9 bbl)(US-421).
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DOMESTIC
ONSHORE
PRODUCTION
406
DOMESTIC
OFFSHORE
PRODUCTION
i
M
Cn
I
80
FIELD
PROCESSING
AND STORAGE
12.9
TRUCK/RAIL
393
345
PIPELINE
PIPELINE
48
48
FIELD
PROCESSING
AND STORAGE
TANKER/BARGE
80
PIPELINE
35
65
IMPORTS
PIPELINE
204
30
PIPELINE
174
TANKER/BARGE
FIGURE 4-1
CRUDE OIL TRANSFER INDUSTRY IN 1975
(flows are 10 6m3)
48
REFINERY
STORAGE
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RADIAN
CORPORATION
Pipelines are the most important mode of transportation
of domestic crude oil with over 87%> of the refineries' 1975 re-
ceipts, 425 x 106m3(2.67 x 109 bbl), being supplied by this
method. Tanker and barge operations accounted for 48 x 106m3
(302 x 106 bbl) or 10% of the domestic crude oil received at
refineries. The remaining 370 of domestic production was supplied
by tank trucks and rail cars (US-421).
Imported crude oil is primarily supplied to refineries
by tankers and barges. About 73% of 1975's crude imports, 174 x
106m3(1.09 x 109 bbl), were received in this manner. Pipelines
account for the transfer of the other 27% of crude imports to
refineries (US-421).
Distribution of Production Facilities
The number of producing oil wells for the baseline year
has not yet been reported. At the end of 1974, the U. S. had
approximately 498,000 wells in production (US-420). Since this
total represents very little change from the approximately 497,000
wells in 1973, it is assumed that approximately 500,000 wells
were in operation at the end of 1975. The number of producing
oil wells in each state as of 13 December 1974 are listed in
Table 4-1 (US-420). Also given in Table 4-1 is a breakdown of
1975 crude oil production by states (US-421). The states of
Texas, Louisiana and California, and the areas off their shores
accounted for about 7270 of 1975 production.
Major Companies
Domestic crude oil production is largely performed by
major oil companies. A listing of major oil companies and their
domestic crude production for 1974 is given in Table 4-2 (NA-303).
This production represented almost 80% of the 1974 U. S. total,
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TABLE 4-1
CRUDE OIL STATISTICS
APPROXIMATE NUMBER OF
PRODUCING OIL WELLS ON
STATE 1975 PRODUCTION**, 103m3 13 DECEMBER 1974
Alabama 2,142 582
Alaska 11,094 199
Arizona 101 25
Arkansas 2,606 7,235
California 51,225 40,479
Colorado 6,030 2,174
Florida 6,658 136
Illinois 4,147 23,630
Indiana 737 4,376*
Kansas 9,398 41,755*
Kentucky 1,201 14,127
Louisiana 104,214 27,973*
Michigan 3,882 4,201
Missouri 11 157
Mississippi 7,407 2,254
Montana 5,222 3,103
Nebraska 972 1,127
Nevada 18 9
New Mexico 15,064 13,304
New York 142 5,475*
North Dakota 3,250 1,488*
Ohio 1,861 16,658
Oklahoma 25,936 71,797
Pennsylvania 622 32,095
South Dakota 77 31
Tennessee 122 154
Texas 194,220 159,702
Utah 6,292 1,076*
Virginia 3
West Virginia 394 13,650*
Wyoming 20,231 8,656*
TOTAL 485,276 497,631
* Estimated by the Bureau of Mines, all other number of producing oil
wells furnished by State agencies.
** Includes lease condensate and off-shore production
Source: Production data - US-421
Well data - US-420
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TABLE 4-2
1974 DOMESTIC CRUDE PRODUCTION OF MAJOR OIL COMPANIES
COMPANY
1974 DOMESTIC PRODUCTION,
m3/day
Amerada Hess Corp.
American Petrofina, Inc.
Apco Oil Co.
Ashland Oil, Inc.
Atlantic Richfield Co.
Cities Services Oil Co.
Clark Oil and Ref. Co.
Continental Oil Co.
Diamond Shamrock Oil and
Gas Co.
Exxon Corp.
Getty Oil Corp.
Gulf Oil Corp.
Kerr-McGee Corp.
Marathon Oil Co.
Mobil Oil Corp.
Murphy Oil Corp.
Pasco Inc.
Phillips Petroleum Co.
Shell Oil Co.
Skelly Oil Co.
Standard Oil Co. of Calif.
Standard Oil Co. (Ind.)
Standard Oil Co. (Ohio)
Sun Oil Co.
Tenneco Corp.
Texaco, Inc.
Union Oil Co. of Calif.
TOTAL
15,712
3,180
924
3,668*
60,913
33,756
201
34,662
2,966
141,510
47,748
75,732
4,974
27,672
66,780**
2,487
2,393
40,656
93,174
12,627
65,680
85,701
4,714
42,228
13,798
128,313***
42,676
1,054,845
* Includes condensate only
** Gross crude production
***Gross crude production: includes interests in nonsubsidiary
companies
Source: NA-303
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with eight companies, Atlantic Richfield, Co., Exxon Corp., Gulf
Oil Corp., Mobil Oil Corp., Shell Oil Co., Standard Oil Co. of
Calif., Standard Oil Co. (Ind.) and Texaco Inc., accounting for
over 50% of the total.
4.1.2 Projected Industry Size in 1985 - Crude Oil
Production and Imports
The use of historical data alone to predict future
growth rates for the crude oil transfer industry might have been
valid prior to the Fall of 1973 and the oil embargo. This event
and the imported crude oil price rises associated with it now
make projections ten years into the future extremely unreliable.
The future of domestic crude oil production, crude imports and
domestic demand for crude oil are now more dependent on oil
exporting nations' pricing decisions, federal regulations and
consumer conservation than on factors such as domestic economic
growth.
Following the oil embargo, numerous forecasts of U. S.
crude oil production, imports and domestic demand were made.
These forecasts were based on various economic and political
assumptions. Since these projections take into account more factors
than could be considered within the limits of this study, an effort
was made to obtain several of the more recent projections and use
their estimates of what the crude oil industry will be in 1985.
Table 4-3 lists some of these projections.
For the purpose of this study, the median Stanford
Research Institute (SRI) domestic crude oil production estimate,
1.86 x 106m3/day (11.7 x 106 bbl/day), is selected (ST-381).
Domestic crude oil. demand is assumed to grow approximately 3%
per year, indicating that demand in 1985 will be 2.67 x 106m3/day
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TABLE 4-3
1985 PROJECTIONS OF DOMESTIC CRUDE OIL PRODUCTION AND IMPORTS
SOURCE OF PROJECTION DOMESTIC PRODUCTION CRUDE IMPORTS
1. Shell Chemical Co. 1,600 870
2. Bankers Trust Co. 2,100 1,200
3. National Petroleum Council NA 1,300
4. Project Independence, Update 1,900 800-950
5. Stanford Research Institute 1,900 730
Units: 103m3/day
Notes: Stanford Research Institute data shown are median values, with low
and high ranges of 1,400 - 2,200 and 330 - 1,400 for domestic
production and imports, respectively.
Sources: Projection #1: RE-149
Projection #2: EN-431
Projection #3: NA-261
Projection #4: PR-124
Projection #5: ST-381
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(16.8 x 106 bbl/day). Therefore, the difference between domestic
demand and production must be supplied by imports. This calcu-
lation shows crude imports in 1985 as 0.81 x 10*in3/day (5.1 x 106
bbl/day), which is in line with both the SRI projection and other
projections.
Of the total domestic production in 1985, approximately
0.87 x 106m3/day (5.5 x 106 bbl/day) is projected to be from
sources not in production in 1975. This figure is calculated by
assuming that the existing production in 1975 will decline at a
rate of 370 per year, as it did over the period 1971-75. (Table
4-4 lists historical crude oil data for 1966-75). Of the 0.87 x
10s m3/day (5.5 x 106 bbl/day) of new production, 0.32 x 106m3/
day (2.0 x 106 bbl/day) is assumed to be Alaskan production.
Transportation
The amounts of crude oil received at refineries by
pipeline, tanker/barge and truck/rail for 1966-75 are listed in
Table 4-5. These data are plotted in Figure 4-2 as percent of
total refinery receipts in order to ascertain whether there is
any trend in the method of transporting crude oil. An analysis
of the data shows no significant trend in the transportation of
domestic crude oil, with each mode of transportation accounting
for a fairly constant percentage of domestic production from
1966 through 1975. Therefore, 1975's percentages (87.5% by pipeline,
9.97o by tanker/barge and 2.67o by truck/rail) are used in calculating
the quantities of domestic crude transported by each mode in 1985.
The 0.32 x 106m3/day (2.0 x 106 bbl/day) of new Alaskan production
are not included in the above percentages. It is assumed that
this crude will be piped to Alaska's south shore and then shipped
by tankers to west coast refineries.
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TABLE 4-4
HISTORICAL CRUDE OIL DATA
CRUDE OIL TOTAL NEW*
YEAR TOTAL DOMESTIC PRODUCTION* IMPORTS SUPPLY OF CRUDE OIL
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1,319
1,401
1,446
1,469
1,532
1,505
1,501
1,464
1,394
1,330
195
179
205
224
210
267
352
516
553
653
1,514
1,580
1,651
1,693
1,742
1,772
1,853
1,980
1,947
1,983
Units: m3/day
*Includes lease condensate
Source: 1966-74 data - AM-132
1975 data - US-421
-22-
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TABLE 4-5
REFINERY RECEIPTS OF CRUDE OIL BY METHOD OF TRANSPORTATION
DOMESTIC CRUDE FOREIGN CRUDE
YEAR PIPELINE TANKERS & BARGES TANK CARS & TRUCKS PIPELINE TANKERS & BARGES
1966 1,072 218 18 55 140
1967 1,122 243 20 64 116
1968 1,172 246 21 73 132
1969 1,207 238 21 87 137
1970 1,237 266 19 103 106
i 1971 1,235 257 18 113 154
ro
V3 1972 1,288 197 23 138 213
1973 1,265 174 25 178 338
1974 1,200 149 32 161 390
1975* 1,164 131 35 177 476
Units: 103m3/day
*1975 data includes an estimate by Radian for the month of October
Source: 1966-1974 data - AM-132
1975 data - U.S. Bureau of Mines Monthly Petroleum Statements for 1975.
-------
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I
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90 _
80
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CO
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c
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60
50
30
20
10
0
-₯=
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Transportation of crude imports shows a distinct trend
with the percentage of tanker and barge receipts increasing and
pipeline receipts declining. This trend can be almost solely
accounted for by the Canadian Government's decision to terminate
crude exports to the U. S. By 1985, Canada will be exporting no
crude and hence, the pipeline transport of imported crude will be
relegated to the portion of imports brought in by tankers and
routed into pipelines for delivery to inland refineries. In
1975, 1578 of the crude imported by tankers was subsequently de-
livered to inland refineries by pipelines. This same percentage
is assumed to apply in 1985. Table 4-6 summarizes the amounts
of crude estimated to be transported by pipeline, tanker/barge and
truck/rail in 1985.
Based on the above projections and considerations, the
flow of crude oil within the U. S. in 1985 is schematically shown
in Figure 4-3.
4.2 Kerosine-Based Jet Fuel Transfer Industry Segment
Kerosine-based jet fuel is transported from refineries
by pipelines, tankers, barges, tank truck and rail cars. Petro-
leum bulk terminals and bulk stations serve as intermediate storage
and distribution centers. The transport of kerosine jet fuel
from refineries and importers to end users is schematically shown
in Figure 4-4. The flow rates shown are for the baseline year
of 1975.
4.2.1 Baseline Year Statistics - Kerosine Jet Fuel
Demand
Domestic refineries produced 40.1 x 106m3(252 x 106 bbl)
of kerosine-based jet fuel in 1975, while imports amounted to
-25-
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TABLE 4-6
SUMMARY OF 1985 REFINERY RECEIPTS OF CRUDE OIL
i
co
cr>
Received By
Pipeline
Tanker/Barge
Truck/Rail
TOTAL
Domestic Crude*
492
55
15
562
New Alaskan Crude
117
Total Domestic Crude Imported Crude
117
492
172
15
679
44
252
296
Units: 106 m3
*Excludes new Alaskan Crude
-------
TOTAL
DOMESTIC
PRODUCTION
679
FIELD
PROCESSING
AND STORAGE
15
TRUCK/RAIL
664
492
PIPELINE
fo
IMPORTS
172
296
TANKER
172
TANKER/BARGE
PIPELINE
REFINERY
STORAGE
FIGURE 4-3
PROJECTED CRUDE OIL TRANSFER INDUSTRY IN 1985
(flows are 10bm3)
-------
IMPORTS
EXPORTS
ro
oo
i
ADDITION
TO STOCKS
CONSUMER
STORAGE
17,067
TRUCK
28,883
END
USERS
PIPELINE
FIGURE 4-4
1975 KEROSINE-BASED JET FUEL TRANSFER INDUSTRY
(flows are 103m3)
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CORPORATION
6.07 x 105m3(38.2 x 106 bbl). Since stocks of kerosine jet fuel
in 1975 increased by 199 x 103m3(1.25 x 105 bbl) and 97.0 x 103m3
(610 x 103bbl) were exported, the indicated domestic demand was
45.9 x ie6m3(289 x 10e bbl) (US-421).
In 1974 (the latest year for which data are available),
over 90% of the kerosine jet fuel consumed was for commercial use
and almost all of this was for aircraft fuel. The military used
almost 870 of the total kerosine jet fuel consumed while the re-
maining 270 was used for non-aviation purposes (US-419). These
percentages are assumed to be the same in 1975.
Transportation
The U. S. Bureau of Mines reported that in 1975, 35.9
x 106m3(226 x 106 bbl) of kerosine jet fuel were turned into pipe-
lines and 6.2 x 106m (39 x 106 bbl) were loaded on tankers and
barges for transport between Petroleum Administration for Defense
(PAD) districts (US-421). Since the quantity transported via
pipelines and tanker/barge is greater than the amount produced by
domestic refineries, it is evident that a portion of the imported
kerosine jet fuel is included in the pipeline and/or tanker/barge
transport data. Because the military normally receive their
kerosine jet fuel by truck, it is assumed that sales to the mili-
tary are transported by truck/rail directly from the refinery.
Military usage in 1975 is estimated to be 3.5 x 106m3 (22 x 10s
bbl). Therefore, the amount of kerosine jet fuel turned into
.pipelines directly from refineries is calculated to be 30.1 x
106m3 (189 x 106 bbl) by subtracting the amounts imported, used
by the military and transported by tanker/barge from indicated
domestic demand.
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Petroleum bulk terminals and stations normally deliver
their products by tank trucks. However, most major airports have
direct pipeline connections (dedicated pipelines) to these bulk
facilities for delivery of kerosine jet fuel (VA-129). Since
the Bureau of Mines figure for pipeline transportation is 35.9 x
106m3 (226 x 106 bbl) but only 30.1 x 106m3 (189 x. 105 bbl) were
turned into pipelines directly from refineries, 5.7 x 106m3 (36
x 106 bbl) of imports are assumed to be turned in dedicated pipe-
lines at bulk facilities. The remaining quantity of kerosine jet
fuel imports and the amount received by bulk facilities by tanker/
barge, 6.5 x 106m3(41 x 106 bbl), is delivered by tank trucks.
Due to the large quantities of kerosine jet fuel used
by the major airports, an underground pipeline system is employed
for delivering jet fuel from the airport storage tanks to the
terminal gates (EL-104). In 1974, 68% of the total U. S. revenue
passenger enplanements occurred at these major airports (US-418).
Therefore, it is assumed that in 1975 approximately 687o of the
commerical usage of kerosine jet fuel or 29.3 x 106m3 (184 x 106
bbl) was delivered by pipeline to the airport terminal gates.
Kerosine jet fuel not delivered by pipeline is transported by small
tank trucks. Therefore, in 1975 the amount of kerosine jet fuel
transported from airport storage to airport terminals by trucks
is assumed to be 16.6 x 106m3 (104 x 106 bbl).
Bulk Terminals and Stations
The U. S. Department of Commerce's Bureau of Census
reported that in 1972, 23,367 petroleum bulk stations and 1,925
petroleum bulk terminals were in operation (US-417). This was
a decrease from the 26,338 bulk stations and 2,701 bulk terminals
reported in operation in 1967 (US-031). A breakdown of petroleum
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bulk facilities in 1972 by size and storage capacity of jet fuels
(both kerosine-based and naphtha-based) is given in Table 4-7.
Airports
There were approximately 11,100 airports on record
with the Federal Aviation Administration on December 31, 1974,
(US-418). If an airport's refueling requirements are proportional
to the number of revenue passenger enplanements, then in 1974 almost
68% of the total airline consumption of kerosine jet fuel occurred
at the 25 major air traffic hubs listed in Table 4-8. Approximately
one-half of these major airport centers contract Allied Aviation
to operate their refueling operations (DE-202).
4.2.2 Projected Industry Size in 1985 - Kerosine Jet Fuel
Historical Demand
Refinery production, import, export, and indicated
demand data for kerosine jet fuel are listed in Table 4-9 for
the years 1966-75. Large increases in indicated domestic demand
are shown for the late 1960's, with smaller increases for the
1970's. This trend can be at least partially accounted for by
realizing that in the late 1960's, the commercial airlines were
still in the process of converting from propeller-driven air-
craft (which use aviation gasoline) to jet-propelled planes (which
use kerosine jet fuel). By 1970, this conversion to jet aircraft
was essentially completed. Demand growth after 1970 reflects ex-
pansion of airline traffic. The decline in kerosine jet fuel con-
sumption in 1974 is probably entirely attributable to the severe
recession of that year.
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TABLE 4-7
1972 PETROLEUM BULK FACILITIES BY
SIZE AND STORAGE CAPACITY OF JET FUELS
TOTAL FACILITY
STORAGE CAPACITY
NUMBER OF KEROSINE AND NAPHTHA-BASED
FACILITIES JET FUEL STORAGE CAPACITY, 103m 3
Less than 159 m3
159 m3 to 235 m3
238 m3 to 314 m3
318 m3 to 394 m3
398 m3 to 791 m3
795 m3 to 3,971 m3
3,975 m3 to 7,946 m3
7,950 m3 to 23,846 m3
23,850 m3 to 79,496 m3
79,500 m3 or more
5,309 1
6,379 2
5,072 2
2,431 l
2,929 2
1,395 21
339 50
687 364
579 1,034
172 1,827
U.S. TOTAL
25,929
3,303
Source: US-417
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TABLE 4-8
MAJOR AIR TRAFFIC HUBS IN U.S. IN 1974
% OF TOTAL REVENUE PASSENGER
AIR TRAFFIC HUB ENPLANEMENTS
Atlanta, Ga. 6.36
Boston, Mass. 2.50
Chicago, 111. 8.32
Cleveland, Ohio 1.41
Dallas/Ft. Worth, Texas 3.63
Denver, Col. 2.69
Detroit and Ann Arbor, Mich. 1.94
Honolulu, Hawaii 2.14
Houston, Texas 1.46
Kansas City, Mo. 1.07
Las Vegas, Nev. 1.36
Los Angeles, Cal. 4.69
Miami/Ft. Lauderdale, Fla. 3.26
Minneapolis/St. Paul, Minn. 1.64
Newark, N.J. 1.63
New Orleans, La. 1.09
New York, N.Y. 6.98
Philadelphia, Penn. 1.76
Phoenix, Arizona 1.01
Pittsburgh, Penn. 1.81
St. Louis, Mo. 1.78
San Francisco/Oakland, Cal. 3.25
Seattle/Tacoma, Wash. 1.43
Tampa/St. Petersburg, Fla. 1.19
Washington, D.C. 3.31
TOTAL . 67.71
Source: US-418
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TABLE 4-9
KEROSINE JET FUEL STATISTICS FOR 1966-75
i
U)
YEAR
Production
Imports
Exports
Indicated Domestic Demand
Turned into Pipelines
Tanker/Barge Transport
Between PAD's
1966
20.0
3.0
<0.1
22.7
9.9
4.6
1967
26.0
4.3
<0.1
30.1
15.2
5.3
1968
30.8
4.3
<0.1
35.4
20.4
6.0
1969
34.5
5.0
40.3
24.5
6.3
1970
34.6
7.3
41.7
26.2
5.2
1971
34.9
8.7
<0.1
43.6
29.0
5.3
1972
37.1
9.4
<0.1
46.7
33.4
6.0
1973
39.4
10.2
0.1
48.9
37.3
5.5
1974
37.2
7.8
0.1
44.7
34.2
5.1
1975
40.1
6.1
0.1
45.9
35.9
6.2
Units: 106m3
Source: U.S. Bureau of Mines Mineral Yearbooks and Monthly Petroleum Statements
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The validity of Model IV for predicting the emission
reduction potential of NSPS is dependent on accurate projections
of industry growth within the time period from 1975 to 1985. The
two suggested methods of calculating growth are based on historical
data. If an industry is experiencing a positive growth, these
methods result in a prediction of a constant yearly throughput
growth (simple growth rate) or an increasing yearly throughput
growth (compound growth rate). However, an analysis of historical
data for the kerosine jet fuel industry indicate that neither of
these methods would predict growth that would conform to the
historical growth pattern.
Figure 4-5 is a plot of the indicated domestic demand
for kerosine jet fuel for the years 1966-75. With the exception
of 1974, the kerosine jet fuel demand-time relationship can be
expressed as a logarithmic function. The deviation in 1974, as
previously mentioned, is due to the cutback of air traffic during
the recession of 1974. A least squares fit of the 1966-73 data to
the equation
Indicated Demand = A£nT = B (4-1)
where A and B are constants and T is the number of years from
1965 gives the solid line shown on Figure 4-5. This equation,
with A equal to 12.5 x 10s and B equal to 22.1 x 106 m3 (139 x
106 bbl), gives good agreement with the actual data.
Projected Demand
Three alternatives for extrapolation of the historical
data to 1985 are shown in Figure 4-5. First, Equation 4-1 with
the derived constants can be used to calculate the 1985 industry
capacity. This method neglects the effects of the recession in
-35-
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CO
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w
w
68 .
64 _
60 .
56 .
52 .
CO
1 48
£ 44
Q
&
a
H
Q
H
H
CO
W
40
36
32
Q
H 28
<
CJ
M
g 24
20
CASE 3
CASE 1
-A CASE 2
'66 '68 '70 '72 '74 '76 '78 '80 '82 '84 '86
YEAR
FIGURE 4-5
INDICATED DEMAND FOR KEROSINE JET FUEL
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1974 and gives 1985 domestic demand as 59.5 x 106 m3 (374 x 106
bbl) (see Case 1 on Figure 4-5). The second alternative is to
use the same form of Equation 4-1, but reduce B by 4.93 x
106 m3(31.0 x 106 bbl) to account for the effects of the recession
in 1974. This method calculates domestic demand for kerosine jet
fuel in 1985 as 54.6 x 106 m3 (343 x 106 bbl) (see Case 2 on Figure
4-5). The third alternative is to assume a simple growth rate
from 1975 to 1985 based on the approximately simple growth
exhibited by the data for 1969-73 . This method discounts the
large growth rate of the late 1960's attributable to conversion
by the airlines from propeller to jet aircraft. Based on this
method, 1985 indicated demand will be 67.4 x 106 m3 (424 x 106 bbl)
(see Case 3 in Figure 4-5). The third method is selected for use
in this study.
Imports of kerosine jet fuel in 1985 are assumed to be
8.9xl06m3(56xl06 bbl) or 13.2% of indicated domestic demand, which
is the same percentage of domestic demand supplied by imports in
1975.
Historical Transportation Data
The amount of kerosine jet fuel transported by tankers
and barges between PAD districts and turned into pipelines is
given in Table 4-9 for the years 1966-75. These data show an
increasing share of the total domestic demand being handled by
pipelines while the share handled by tankers and barges has
experienced a slight decline.
Projected Transportation Data
The amounts of kerosine jet fuel turned into pipelines
and transported by tankers and barges between PAD districts in
1985 can, in part, be projected from historical data. The per-
cent of total indicated domestic demand transported by the above
two methods for the years 1966-75 are shown in Table 4-10. The
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TABLE 4-10
PIPELINE AND TANKER/BARGE TRANSPORT OF KEROSINE JET FUEL
AMOUNT TRANSPORTED AS % OF DOMESTIC DEMAND
YEAR VIA PIPELINE _ VIA TANKER/ BARGE
1966 43.5 ' 20.5
1967 50.4 17.5
1968 57.6 17.0
1969 60.9 15.7
1970 62.9 12.5
1971 66.5 12.1
1972 71.4 12.8
1973 76.3 11.3
1974 76.4 11.4
1975 78.1 13.5
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data for pipeline transport appear to follow an increasing log-
arithmic function similar to the pattern shown for indicated
domestic demand. A least squares fit of Equation 4-1 for the
1966-73 pipeline transport data gives A as 14.9 and B as 41.4.
Thus, in 1985, pipelines are projected to transport 86.170 or
58 x 106m3(365 x 10s bbl) of the indicated domestic demand.
Tanker and barge transport between PAD districts as a
percent of indicated demand has shown a slight decrease since
1966. If the data for 1966 and 1975 are used to calculate a
compound growth rate, in 1985 tankers and barges will handle
approximately 8.5% of the indicated domestic demand or 5.7 x
106 m3 (36 x 106 bbl).
In order to determine the quantity of kerosine jet
fuel turned into pipelines from domestic refineries, it is
necessary to estimate the military demand for this fuel. Histori-
cal data for military use show an erratic pattern for 1971-74. (See
Table 4-11) Therefore, it is assumed that the amount of kerosine
jet fuel required by the military and transported by truck/rail
directly from refineries is equal to the amount used by the mili-
tary in 1975, 3.5 x 106 to3 (22 x 106 bbl).
N
The delivery of kerosine jet fuel from consumer storage
to aircraft is assumed to be proportioned between truck and
pipeline transportation as it was in 1975. Therefore, 6870 of
commercial usage or 43.4 x 106m3 (273 x 106 bbl) is piped and
the remaining 32% plus all military usage, 24.0 x 106m3(151 x
106 bbl), is trucked.
Based on the above projections and considerations, the
flow of kerosine jet fuel in 1985 is schematically shown in Figure
4-6. Due to the small amounts of kerosine jet fuel exported, no
estimate of exports-is made for 1985.
-39-
-------
TABLE 4-11
KEROSINE JET FUEL USAGE
YEAR 1966 1967 1968 1969 1970 1971 1972 1973 1974
Commercial Use* NA NA NA NA NA 108 114 118 110
Military Use** 6.7 7.3 7.8 8.1 8.4 11.0 10.2 11.1 9.6
i
g Non-Aviation Use NA NA NA NA NA NA 3.8 2.7 2.2
i
* Includes airlines, factory and general aviation use
**Includes all military consumption except JP-4 (naphtha jet fuel). Excludes direct
imports by military.
NA - Not available.
Units: 103 m3/day
Source: AM-132, US-419
-------
5.729
TANKER/BARGE
58.503
49,276
PIPELINE
PIPELINE
3,498
TRUCK/RAIL
p-
h->
I
CONSUMER
STORAGE
23,947
TRUCK
END
USERS
43,453
PIPELINE l
FIGURE 4-6
PROJECTED KEROSINE-BASED JET FUEL TRANSFER INDUSTRY IN 1985
(flows are 103m3)
-------
CORPORATION
4.3 Naphtha-Based Jet Fuel Transfer Industry Segment
Naphtha-based jet fuel like kerosine jet fuel is trans-
ported from refineries by pipelines, tankers, barges, tank trucks
and rail cars, with petroleum bulk terminals and bulk stations
serving as intermediate storage and distribution centers. The
transport of naphtha jet fuel from refineries and importers to end
users is schematically shown in Figure 4-7. The flow rates shown
are for the baseline year of 1975.
4.3.1 Baseline Year Statistics - Naphtha Jet Fuel
Production of naphtha jet fuel in 1975 amounted to
10.4 x lO^m3 (65.6 x 106 bbl) while imports totaled 1.64 x 105m3
(10.3 x 106 bbl) and stocks were reduced by 48.8 x 103m3 (307 x
103 bbl). Since no naphtha jet fuel was exported in 1975, the
indicated domestic demand was 12.1 x 10sm3 (76.3 x 106 bbl) (US- 421)
Tanker and barge transport of naphtha jet fuel between
PAD districts totaled 1.54 x 106m3.(9.72 x 106 bbl) in 1975, with
5.41 x 106 m3 (34.0 x 10s bbl) turned into pipelines (US-421).
Since military bases use large quantities of naphtha jet fuel, it
is assumed that they receive most of their fuel through dedicated
pipelines. Therefore, the amount of fuel received by dedicated
pipelines is assumed equal to the amount turned into pipelines
directly from refineries. All movement of naphtha jet fuel from
consumer storage to aircraft is by small tank trucks.
The latest statistics on petroleum bulk terminal and bulk
station storage capacity are given in terms of total jet fuel
storage (both naphtha- and kerosine-based). Total jet fuel storage
capacity at these facilities amounted to 3.30 x 106m3 (20.8 x
106 bbl) in 1972 as shown in Table 4-7 (US-417). In 1974 (the
-42-
-------
I
-p>
U)
IMPORTS
1,644
MARINE
TERMINAL
1.545
TANKER/BARGE
in
49
5,412
PIPELINE
BULK
TERMINALS
AND
STATIONS
3.525
TRUCK/RAIL
DRAWDOWN
FROM STOCKS
3.189
TRUCK
5,412
PIPELINE
CONSUMER
STORAGE
12.126
TRUCK
.END
USERS
FIGURE 4-7
1975 NAPHTHA-BASED JET FUEL TRANSFER INDUSTRY
(flows are 103m3)
-------
RADIAN
CORPORATION
latest year for which data are available), military uses accounted
for almost 8770 of the total domestic demand for naphtha jet fuel.
The other 13% was utilized in the commercial sector (US-419).
These same percentages are used to represent the usage of naphtha
jet fuel in the commercial and military sectors during 1975.
4.3.2 Projected Industry Size in 1985 - Naphtha Jet Fuel
Historical Demand Data
Production, import, export, and indicated domestic
demand data for naphtha jet fuel are contained in Table 4-12 for
the years 1966-75. These data show that the indicated domestic
demand for naphtha jet fuel decreased by about 257o from 1966 to
1975. The decline in the naphtha jet fuel industry in the late
1960's and 1970's can probably be accounted for by the decreased
military activity associated with the ending of the Vietnamese
conflict and a general cutback in military activity in the 1970's.
Projected Demand Data
The historical indicated domestic demand data of Table
4-12 were analyzed by performing a least squares fit to an
exponential equation of the following form:
BT
Demand = Ae or &n(Demand) = £nA + BT (4-2)
where A and B are constants and T is defined as the number of
years from 1966. The resulting equation, based on 1966-75 data
is
Capacity (in 105 m3) = 18.6xe("°'046xT) .
-44-
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TABLE 4-12
NAPHTHA JET FUEL STATISTICS FOR 1966-75
Year
Production
Imports
Exports
Indicated
Domestic Trade
Turned into
Pipelines
Tanker/Barge
Transport Between
PAD's
1966
14.2
2.0
0.2
16.2
3.7
2.9
1967
17.4
0.9
0.3
17.7
3.8
4.5
1968
19.3
1.1
0.3
20.1
4.2
3.5
1969
16.6
0.8
0.3
17.2
4.4
3.7
1970
13.4
1.1
0.3
14.4
3.9
2.3
1971
13.6
1.8
0.2
15.1
4.0
2.6
1972
12.2
1.9
0.1
14.1
2.9
2.0
1973
10.5
2.1
0.1
12.6
2.4
1.5
1974
11.3
1.6
<0.1
12.9
5.3
1.6
1975
10.4
1.6
-
12.1
5.4
1.5
Units: 106m3
Source: U.S. Bureau of Mines Mineral Yearbooks and Monthly Petroleum Statements
-------
CORPORATION
For the year 1985 when T = 19, the indicated domestic demand is
predicted to be 7.63 x 106m3 (48.0 x 10s bbl). This naphtha jet
fuel demand projection is shown in Figure 4-8.
Imports of naphtha jet fuel in 1985 are assumed to be
1.01 x 106m3 (6.3 x 106 bbl) or 13.2% of indicated demand, which
is the percent of demand that imports provided in 1975.
Transportation Data
A breakdown of the amount of naphtha jet fuel turned
into pipelines and transported by tankers and barges between PAD
districts is also listed in Table 4-12. These data show an erratic
pattern in pipeline and tanker/barge transport over the 1966-75 time
frame.
Figure 4-9 is a plot of the percent of indicated demand
for naphtha jet fuel turned into pipelines and transported between
PAD.districts by tankers and barges. It is evident from Figure 4-9
that no pattern or trend is present in these data and hence no
accurate projections can be made for what amounts of naphtha jet
fuel will be transported by these two modes in 1985. Therefore,
1985 pipeline and tanker/barge transportation percentages are
assumed equal to the 1975 percentages of 44.6% and 12.4% respectively.
These values indicate that in 1985, 3.40 x 10sm3 (21.4 x 105 bbl)
of naphtha jet fuel will be transported by pipeline with 0.95 x 106
tn? (6.0 x 106 bbl) handled by tankers and barges. Therefore, truck/
rail transport direct from refineries is equal to 2.15 x 106m3
(13.5 x 106 bbl).
Based on the above projections and considerations, the
flow of naphtha jet fuel in 1985 is schematically shown in Figure
4-10. Due to the small amount of naphtha jet fuel exported, no
estimate of exports is made for 1985.
-46-
-------
23 _,
21 -
H 19
w ±y
-)
17 .
5!
a
pi
o
13 _
w
o
u
M
H
O
o
o
w
'66 '68 '70 '72 '74 '76 '78 '80 '82 '84 '86
YEAR
FIGURE 4-8
INDICATED DEMAND FOR NAPHTHA JET FUEL
-------
50_
40.
:CATED DEMAND
CO
o
1
f 1
H
h 20.
o
^
10
O -PIPELINE DATA
A -TANKER/BARGE DATA O
O
0 0
A 0
o
o o A o
o
A A A
A
A
A A A
I I I I
T I-
'66 '67 '68 '69 '70 '71 '72 '73 '74 '75
YEAR
FIGURE 4-9
PIPELINE AND TANKER/BARGE TRANSPORT OF NAPHTHA JET FUEL
-48-
-------
IMPORTS
1,007
VO
I
REFINERY
STORAGE
6,623
MARINE
TERMINAL
J
is-
1
946
TANKER/BARGE
3,403
PIPELINE }
BULK
TERMINALS
AND
STATIONS
2,274
1,953
TRUCK
3,403
PIPELINE
TKUUK./KAJ.II
CONSUMER
STORAGE
7,630 END
TRUCK - USERS
FIGURE 4-10
PROJECTED NAPHTHA-BASED JET FUEL TRANSFER INDUSTRY IN 1985
(flows are 10dmJ)
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CORPORATION
4.4 Aviation Gasoline Transfer Industry Segment
Aviation gasoline like jet fuel is transported from
refineries by pipelines, tankers, barges, tank trucks and rail
cars, with petroleum bulk terminals and bulk stations serving
as intermediate storage and distribution centers. The transport
of aviation gasoline from refineries to end users is schematically
shown in Figure 4-^11. The flow rates shown are for the baseline
year of 1975.
4.4.1 Baseline Year Statistics - Aviation Gasoline
In 1975 refineries produced 2.18 x 106m3 (13.7 x 106
bbl) of aviation gasoline and withdrew 71.1 x 103m3 (447 x 103
bbl) from stocks. No aviation gasoline was imported, but 16.8 x 103
m3 (106 x 103 bbl) were exported. Thus, the indicated domestic
demand was 2.24 x 106m3 (14.1 x 10s bbl)(US-421).
In 1975, tankers and barges were used to transport 523
x 103m3 (3.29 x 106 bbl) of aviation gasoline between PAD districts,
while 610 x 103m3 (3.84 x 106 bbl) were turned into pipelines
(US-421). All of the aviation gasoline was moved from consumer
storage tanks to aircraft by small tank trucks.
The latest petroleum bulk terminal and station sales
storage data for aviation gasoline is for 1972. In that year,
the 1,925 petroleum bulk terminals in operation as reported by
the Bureau of the Census had sales of 1.51 x 106m3 (9.50 x 106bbl)
of aviation gasoline and a total of 490 x 103m (3.08 x 106 bbl)
of storage while the 23,367 petroleum bulk stations had sales of
684 x 103 (4.30 x 10s-bbl) and a total of 83.2 x 103m3 (523 x 103
bbl) of storage (US-417). Table 4-13 shows the number of bulk
facilities in 1972 broken down by their total storage capacity and
their aviation gasoline storage capacity.
-50-
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EXPORTS
17
I
01
MARINE
TERMINAL
2164
71
DRAW DOWN
FROM STOCKS
523
TANKER/
BARGE
610
PIPELINE
121
TRUCK/RAIL
BULK
TERMINAL
413
TRUCK/RAIL
568
TRUCK/RAIL
1254
TRUCK
568
TRUCK
CONSUMER
STORAGE
2.235
TRUCK
END
USERS
FIGURE 4-11
1975 AVIATION GASOLINE TRANSFER INDUSTRY
(flows are 103m3)
-------
RADIAN
CORPORATION
TABLE 4-13
1972 PETROLEUM BULK FACILITIES BY SIZE AND STORAGE
CAPACITY OF AVIATION GASOLINE
Total Facility Number of Aviation Gasoline Storage
Storage Capacity Facilities Capacity, 103m3
less than 159m3 5,309 4.2
159m3 to 235m3 6,379 6.6
238m3 to 314m3
318m3 to 394m3
398m3 to 791m3
795m3 to 3,971m3
3,975m3 to 7,946m3
7,950m3 to 23,846m3
23,850m3 to 79,496m3
79,500m3 or more
25,292 572.8
Source: US-417.
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CORPORATION
In 1974 there were approximately 11,100 airports in
the U. S., with the twenty-five major airport centers (see Table
4-8) accounting for almost 6870 of the revenue passenger enplane-
ments (US-418). Therefore, the remaining airports consist of
small or medium size facilities where a large majority of general
aviation flying originates. Since aviation gasoline is the fuel
normally used by general aviation aircraft, the end user segment
of the aviation gasoline industry is widespread among many small
facilities.
4.4.2 Projected Industry Size in 1985 - Aviation Gasoline
Historical Demand
Table 4-14 contains production, import, export, and
indicated domestic demand data for aviation gasoline for the
period 1966-75. An analysis of this data shows that the demand
for aviation gasoline decreased over 637o from 1966 to 1975, with
a rapid decline shown in the late 1960's and a more gradual
decline in the 1970's. The rapid decline of the late 1960's is
probably attributable to the phasing-out of propeller-driven
aircraft by the major airlines.
Projected Demand
While the aviation gasoline demand data show a
continual decline from 1966 to 1975 (see Figure 4-12), the decline
from 1970 to 1975 appears to conform to an exponential relation-
ship expressed as
BT
Demand = Ae or £n(Demand) = &nA + BT
where A and B are constants and T is defined as the number of
years from 1970.
-53-
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TABLE 4-14
1966-74 AVIATION GASOLINE STATISTICS
Ul
-f>
i
Year
Production
Imports
Exports
Indicated
Domestic Trade
Turned into
Pipelines
Tanker /Barge
Transport Between
PAD's
1966
6.56
-
0.53
6.11
1.77
1.72
1967
5.89
-
0.64
5.2
1.49
1.59
1968
5.02
-
0.29
4.87
1.17
1.13
1969
4.21
-
0.28
4.06
0.90
0.96
1970
3.13
-
0.14
3.16
0.73
0.66
1971
2.93
-
0.20
2.84
0.73
0.80
1972
2.70
-
0.04
2.69
0.64
0.74
1973
2.61
-
0.03
2.63
0.64
0.63
1974
2.53
-
0.02
2.58
0.72
0.56
1975
2.18
-
0.02
2.24
0.61
0.52
Units: 106m3
Source: U.S. Bureau of Mines' Mineral Yearbooks and Monthly Petroleum Statements
-------
5 .
a
-------
CORPORATION
Based on a least squares fit of the 1970-75 data to
the above equation, A=3.10 and B= -0.0591. This calculated curve
is represented by the solid line on Figure 4-12. In 1985 when
T=15, the indicated domestic demand is calculated as 1.28 x 106m3
(8.04 x 106 bbl).
Transportation
Table 4-14 also shows the amounts of aviation gaso-
line turned in pipelines and transported between PAD district
by tankers and barges for the years 1966-75. These data are
plotted in Figure 4-13 as percent of indicated demand. Since
there is no consistent trend over the 1966-75 time period, 1975 per-
centages will be used for 1985. Therefore, for 1985 pipeline trans-
port is assumed to handle 27.27, of the aviation gasoline while
tanker/barge operations are assumed to handle 23.370.
In 1972, bulk terminal and bulk station sales of
aviation gasoline were 56.17» and 25.4% of the indicated domestic
demand respectively. These same percentages are assumed to apply
in 1985, indicating that at that time bulk terminal sales will be
717 x 103m3 (4.51 x 106 bbl) and bulk station sales will be 325
x 103m3(2.04 x 106 bbl).
Based on the above projections and considerations,
the aviation gasoline transfer industry in 1985 can be schemati-
cally shown by Figure 4-14. Due to the small amounts of aviation
gasoline exported, no estimate is made for exports in 1985.
-56-
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35
30
O
A
§
o
o
a
o
w
a
o
s-s
25
20
15
O
A
O - PIPELINE DATA
A - TANKER/BARGE DATA
'66 '67 '68 '69 '70 '71 '72 '73 '74 '75
YEAR
FIGURE 4-13
PIPELINE AND TANKER/BARGE TRANSPORT OF AVIATION GASOLINE
-57-
-------
MARINE
TERMINAL
298
1.278
i
Ul
oo
TANKER/
BARGE
348
PIPELINE
71
TRUCK/RAIL
325
BULK
TERMINAL
236
TRUCK/RAIL
TRUCK/RAIL
BULK
STATION
717
TRUCK
325
TRUCK
CONSUMER
STORAGE
1.278
TRUCK
END
'USERS
FIGURE 4-14
PROJECTED AVIATION TRANSFER INDUSTRY IN 1985
(flows are 103m3)
-------
CORPORATION
5.0 BASELINE YEAR EMISSIONS
Hydrocarbon emissions can occur at any point in a
transfer network where crude oil or petroleum products are moved
from one vessel to another or anywhere equipment parts do not form
perfect seals. These emissions are normally termed vapor dis-
placement or filling losses and fugitive leaks respectively. It
is necessary to identify these emission sources in the transfer
network prior to calculating the quantities of hydrocarbons emitted
from each industry segment.
The four industry segments examined in this study have
many of the same types of emission sources. Therefore, Section 5.1
provides a general description of the emission points in all the
segments and discusses the factors that affect emission rates.
Section 5.2 details the parameters necessary for estimating the
emissions from each point source and develops emission factors for
the four industry segments. Emissions for each transfer segment
are summarized in Section 5.3 based on an example throughput of
159 m3/day (1000 bbl/day) for each emission point.
5.1 Hydrocarbon Emission Sources
Sources of hydrocarbon emissions resulting from
handling petroleum liquids include:
1) Tank filling operations
2) Storage facilities
3) Pump seals and valves
These emission sources are discussed in detail in the following
sections.
.-59-
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CORPORATION
5.1.1 Tank Filling Operations
As petroleum liquids are loaded into tank trucks,
marine vessels, rail cars and aircraft fuel tanks, hydrocarbon
vapors are displaced. Unless equipment is provided to collect
and dispose of these displaced vapors, they will result in at-
mospheric emissions. The quantity of emissions is dependent on
the method of transfer, quantity of product dispensed, dis-
pensed liquid vapor pressure and previous service of the tank.
Loading losses occur as hydrocarbon vapors residing
in empty tanks are displaced to the atmosphere by the liquid
being loaded. The hydrocarbon vapors displaced from the tanks
are a composite of hydrocarbon vapors formed in the empty tank
by evaporation of residual product from its previous service and
hydrocarbon vapors generated in the tank as the new product is
being loaded. The amount of hydrocarbons lost during the loading
operation is therefore a function of the methods of unloading and
filling being used.
From an emission standpoint, filling procedures fall
into two basic categories - splash loading or submerged surface
loading. 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
liquid is discharged within a few inches of the tank bottom.
There is a marked decrease in turbulence resulting in a reduction
of losses by evaporation and entrained droplets.
The previous service .of the tank determines the hydro-
carbon content of the contained vapors prior to loading. Factors
such as vapor pressure of the previous cargo, type of unloading
-60-
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RADIAN
CORPORATION
method used and whether or not the tank space was freed of hydro-
carbon vapors after unloading will affect the. concentration of
hydrocarbons in the tank's vapor space.
5.1.2 Storage Facilities
Types of Storage Tanks
There are five basic types of storage tanks used by
the petroleum industry. 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 5-1). Today, fixed roof tanks are
normally equipped with pressure/vacuum valves set at only a few
inches of HaO to contain minor vapor volume expansion.
Floating roof tanks are cylindrical steel tanks similar
to fixed roof tanks (Figure 5-2). 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 floating
roofs, designed to deal with the buoyancy problems caused by snow
and rain (Figure 5-3). 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.
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CORPORATION
PRESSURE-VACUUM
'VENT
NOZZLE
GAUGE HATCH -
FIGURE 5-1. FIXED ROOF STORAGE TANK
-62-
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RADIAN
CORPORATION
ROOF SEAL
(NON-METALLIC)
WEATHER SHIELD-
NOZZLE
FIGURE 5-2. DOUBLE DECK FLOATING ROOF STORAGE TANK (NON-METALLIC SEALS)
-63-
-------
RADIAN
CORPORATION
AIR SCOOPS.
NOZZLE
FIGURE 5-3. COVERED FLOATING ROOF STORAGE TANK
-64-
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RADIAN
CORPORATION
There are two basic types of variable vapor space
tanks. These are shown in Figures 5-4 and 5-5. 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 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 14 atia (210 psia) .
Another type of storage vessel commonly used by the
end use sector is the underground tank. This type of tankage is
essentially identical to fixed roof tanks except for the vessel
being located completely underground.
Mechanism of Storage Loss
Evaporation loss is the natural process whereby a liquid
is converted to a vapor which subsequently is lost to the atmos-
phere. 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.
Some factors which influence evaporation loss include:
1) stored liquid physical characteristics
2) dimensions of storage vessel
3) condition of tank
4) daily temperature and pressure changes
5) tank throughput
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CORPORATION
-PRESSURE-VACUUM
VENT
ROOF SEAL
(LIQUID IN
THROUGH)
NOZZLE
FIGURE 5-4. LIFTER ROOF STORAGE TANK (WET SEAL)
-66-
-------
CORPORATION
PRESSURE
VACUUM VENTS
NOZZLE.
FIGURE 5-5. FLEXIBLE DIAPHRAGM TANK (INTEGRAL UNIT)
-67-
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CORPORATION
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 saturation 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. Underground tanks experience filling and
emptying losses, but normally have negligible breathing losses
due to the small diurnal temperature changes experienced by the
stored liquid.
5.1.3 Pump Seals and Valves
Pumps required to move liquids can leak at the point of
contact between the moving shaft and the stationary casing. If
volatile, the leaked liquid will evaporate to the atmosphere. The
two types of seals commonly used in the petroleum industry are
packed seals (Figure 5-6) and mechanical seals (Figure 5-7).
Packed seals effect a seal around the moving shaft by forcing a
fibrous packing between the shaft and casing wall. Mechanical
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.
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RADIAN
CORPORATION
.FIGURE 5-6
Packed Seal
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CORPORATION
High-pressure tone
Rotating shaft
Rotating cellar
Backing spreader
c-JJ^Cup packing
Set screw
Seat stop
-Graphite rina
(stationary}
Lcw-pressuro mne
Casino
Springs
Lock washer
FIGURE 5-7
Mechanical Seal
-70-
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RADIAN
CORPORATION
Under the influences of heat, pressure, vibration,
friction, and corrosion, valves generally develop.leaks. The
hydrocarbon emissions from these leaks depend on both the
volatility of the product and the temperature and pressure of
the system.
5.2 Emission Factors for Important Sources
Parameters for Emission Calculations
For the most part, actual hydrocarbon emission data
for transfer operations involving crude oil, jet fuels and avia-
tion gasoline are not available. Therefore, it is necessary to
use correlations to estimate emission rates from these operations.
The equations used in calculating these estimates require several
parameters related to'the physical characteristics of the petroleum
liquid, such as the liquid vapor pressure under transfer condi-
tions and the molecular weight of the vapor.
The parameters required in the emission calculations
for each emission source are listed in Table 5-1. Obviously,
these numbers will not be correct for every transfer operation
involving crude oil, jet fuels or aviation gasoline. Instead,
they are meant to represent the average situation.
Emission Sources
Hydrocarbon emission sources in the crude oil and
aviation fuels transfer industry segments include 1) oil field
production facilities, 2) tank truck and rail car loading operations,
3) tanker and barge loading operations, 4) aircraft refueling
operations, 5) intermediate storage tanks, 6) consumer storage
tanks and 7) process pumps and valves. The first source is ob-
viously found only in the crude oil transfer segment while the
fourth source is present only in the aviation fuels segment.
-71-
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TABLE 5-1
Crude Oil
I
10 Kerosine Jet Fuel
Naphtha Jet Fuel
Aviation Gasoline
PARAMETERS FOR
Average Temperature of
Liquid during Transfer
Operation, °C (°F)
15.5(60)
15.5(60)
15.5(60)
15.5(60)
EMISSION CALCULATIONS
Vapor Pressure of Liquid at
Average Temperature,
mmHg(psia)
145 (2.8)
0.44 (0.0085)
67 (1.3)
150 (2.9)
Molecular Weight of
Vapor at Average Liquid
Temperatures
50
130
80
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Some of the intermediate and end use storage tanks
are floating roof tanks which exhibit only standing storage losses.
These emissions are not directly caused by the transfer of petro-
leum liquids. Similarly, breathing losses from fixed roof tanks
are not directly related to transfer operations. However, these
two types of losses are indirectly related to the transfer of
petroleum liquids since if the transfer operation were not present
there would be no need for storage. Therefore, while standing
storage and breathing losses are not included in the emission
analysis of this report, a discussion of these emissions is
included in Appendix A.
5.2.1 Crude Oil Production Facilities
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.
Because crude oil is produced in association with gases
and water (usually in the form of brine), it must be treated to
separate the crude oil from the other components. These operations
may occur in the oil field, at a central gathering station or in
the refinery. After being processed for water and gas removal,
the crude oil is stored in welded tanks of high-strength steel.
These are usually vertical tanks with fixed roofs. The' point of
custody transfer is normally defined as the withdrawal of the crude
oil from the field storage tanks pursuant to entering a main trans-
mission pipeline, a central gathering station pipeline or being
loaded into tank trucks and rail cars.
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Offshore production operations are very similar to onshore
operations with the main difference being that offshore facilities
tend to minimize the amount of field storage due to space limitations
Offshore production is normally transported to the mainland via
pipelines although small quantities are shipped ashore via barges
and tankers.
Emissions
Hydrocarbon emission sources at crude oil production
facilities include pump seals, valves and storage tanks. Emission
data for these sources are extremely limited. The only source of
information obtained from the literature and industry contacts that
could be correlated to production rates is a study performed by the
MSA Research Corporation in 1972. Their study was based on data
taken for a specific area in California in 1968. The MSA study
does not describe what types of operations or equipment were being
utilized in the tested oil fields. These emission data, which are
based on production of 2.94 x 106m3 (18.5 x 106 bbl) of crude oil
in 1968, are shown in Table 5-2.
5.2.2 Tank Loading
The mechanism by which hydrocarbon emissions are pro-
duced during the loading of tank trucks, rail cars, tankers and
barges and the refueling of aircraft is identical. Therefore,
these emission sources and their emission rates can be addressed
together.
The American Petroleum Institute (API) has developed
correlations for estimating hydrocarbon emissions from loading
operations (AM-085). These correlations can be expressed in the
form of a theoretically derived equation which uses a saturation
factor to account for various unloading and loading methods. The
equation is given by:
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TABLE 5-2
ESTIMATED HYDROCARBON EMISSIONS FROM CRUDE
OIL PRODUCTION
Hydrocarbon Emissions
Point Source Kg/Day Kg/103m3
Storage Tanks 88 11
Wastewater Separators* 177 22
Pump Seals 1720 214
Compressor Seals* 88 11
Relief Valves* 177 22
Pipeline Valves 274 34
*These sources are not considered part of the transfer
segment as defined for this study.
Source: MS-001
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12.46 S£N (5-1)
where L = loading loss, lb/103 gal. of liquid loaded
Li
M = molecular weight of vapors, Ib/lb-mole
P = true vapor pressure of liquid loaded, psia
T = bulk temperature of liquid loaded, °R
S = a saturation factor.
Table 5-3 lists recommended values for S based on various loading
and lonloading methods.
The value of S for submerged loading of marine vessels
(0.2) is less than the value for submerged loading of tank trucks
and rail cars (0.6) due mainly to the greater depth of tanks on
marine vessels. During loading operations a blanket of saturated
hydrocarbon vapors is formed above the liquid surface. This blanket
is approximately 1-2 meters (-3-6 feet) deep. Above the blanket,
the hydrocarbon content of the vapor space is normally far from the
saturation value. Therefore when loading occurs and the tank's
vapors are expelled, the total amount of hydrocarbons emitted is
dependent upon the relative volumes of the blanket and initial
space above the blanket. For tank trucks and rail cars the
blanket volume is greater than the volume of unsaturated vapor,
while for marine vessels the volume of unsaturated vapors is 2-7
times the blanket volume.
Equation 5-1 can be used with the data of Table 5-1 and
the appropriate saturation factors from Table 5-3 to calculate
hydrocarbon emission factors for loading operations. In this study
an S factor of 0.6 is used for determining emissions from tank
truck and rail car loading since almost all of these vehicles are
now submerge loaded. The hydrocarbon concentration in the vapor
space of aircraft fuel tanks is normally in equilibrium with the
aviation fuel. Therefore, an S factor of 1.0 is used in calculating
aircraft refueling emissions.
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TABLE 5-3
S FACTORS FOR EQUATION 5-1
Tank Trucks and Tank Cars S
submerged loading of a purged compartment1 0.50
splash loading of a purged compartment1 1.45
submerged loading - normal service 0.60
splash loading - normal service 1.45
submerged loading - balance service2 1.0
splash loading - balance service2 1.0
Marine Vessels
submerged loading 0.20
1. On occasions the cargo compartment will be purged of vapors
because it has been cleaned or previously used to convey
non-volatile hydrocarbon liquids.
2. These factors apply where the cargo carrier's previous delivery
was to a facility practicing the balance method of vapor control
on bulk fuel deliveries, and the cargo carrier is returning with
a load of saturated vapors.
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The calculated emission factors for loading operations
are shown in Table 5-4 along with the parameters used in the cal-
culations .
5.2.3 Storage Facilities
Fixed Roof Tank Working Losses
Working losses from fixed roof tanks can be estimated
from correlations developed by the American Petroleum Institute
(AM-039). The equation form of these correlations can be modified
to make it applicable to the storage of any organic liquid. The
modified equation is
Lw = 0.024 (M)(P)(KN)(KC) (5-2)
where Ly = fixed roof working loss (lb/103 gallon throughput)
M = Molecular weight of vapor in the storage tank (Ib/lb-mole)
P = Vapor pressure of liquid at storage temperature (psia)
K^ = Turnover factor (dimensionless)
K = Crude oil factor (dimensionless)
L»
K is 0.75 for crude oil storage and is 1.00 for storage of all
other liquids. K is obtained from Figure 5-8.
Equation 5-2 can be used with the data of Table 5-1 and
the appropriate K,, and KC values to calculate fixed roof working
losses. Figure 5-3 indicates that for less than 36 turnovers
per year, KN is 1.0. Since all fixed roof storage under considera-
tion in this study have less than 36 turnovers per year, ^ is
taken as 1.0 in all working loss calculations. Oil field storage
losses are not addressed in this section but are included in
Section 5.3.1. Table 5-5 lists the calculated emission factors
for fixed roof working losses.
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TABLE 5-4
VO
I
3.
4.
Liquid
Emission Source Temperature,°R
Crude Oil
Truck/Rail Loading 520
Tanker/Barge Loading 520
Kerosine Jet Fuel ;
Truck/Rail Loading 520
Tanker/Barge Loading 520
Aircraft Refueling 520
Naphtha Jet Fuel
Truck/Rail Loading 520
Tanker/Barge Loading 520
Aircraft Refueling 520
Aviation Gasoline
Truck/Rail Loading 520
Tanker/Barge Loading 520
Aircraft Refueling 520
IION FACTORS FOR LOADING PETROLEUM LIQUIDS
Liquid Vapor Molecular Weight S Calculated Em
Pressure, psia of Vapor Factor lb/103 gal loaded
2.8
2.8
0.0085
0.0085
0.0085
1.3
1.3
1.3
2.9
2.9
2.9 .
50
50
130
130
130
80
80
80
69
69
69
0.6
0.2
0.6
0.2
1.0
0.6
0.2
1.0
0.6
0.2
1.0
2.01
0.671
0.0159
0.00530
0.0265
1.50
0.498
2.49
2.88
0.959
4.79
Kg/m3 loaded
0.241
0.0804
0.00190
0.000635
0.00317
0.180
0.0597
0.298
0.345
0.115
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cf
o
1.0
0.8
0.6
£ 0.4
>
o
9- 0.2
NOTE: FOR 36 TURNOVERS PER
YEAR OR LESS. KM "1.0
100
200
300
400
TURNOVERS PER YEAR
ANNUAL THROUGHPUT
TANK CAPACITY
FIGURE 5-8 TURNOVER FACTOR
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TABLE 5-5
i
00
FIXED ROOF AND UNDERGROUND STORAGE EMISSION FACTORS
Emission Source and Liquid Stored
'ixed Roof Tank Working Loss
Kerosine Jet Fuel
Naphtha Jet Fuel
Aviation Gasoline
Inderground Storage Filling Loss
Kerosine Jet Fuel
Naphtha Jet Fuel
Aviation Gasoline
fnderground Storage Withdrawal Loss
Kerosine Jet Fuel
Naphtha Jet Fuel
Aviation Gasoline
Storage
Temper a ture,°F
60
60
60
60
60
60
60
60
60
Liquid Vapor
Pressure at
Storage Temperature,
psia
0.0085
1.3
2.9
0.0085
1.3
2.9
0.0085
1.3
2.9
Molecular Weight
of Vapor
130
80
69
130
80
69
130
80
69
Emission
lb/10d gal
Throughput
0.0265
2.50
4.80
0.0370
3.48
4.26
neg.
0.0404
0.197
Factors
Kg/m3
Throughput
0.00317
0.300
0.575
0.00444
0.418
0.510
neg.
0.00484
0.0236
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Underground Tank Losses
Emissions from underground storage tanks include filling
losses and withdrawal losses. Emission data for filling losses
are reported for storage of motor gasoline in the Los Angeles
area (CH-159) . These data are shown in Table 5-6. Filling losses
resulting from loading petroleum liquids other than motor gasoline
can be calculated by ratioing vapor molecular weights and vapor
pressures of motor gasoline and the stored liquid. For this study,
the vapor molecular weight of motor gasoline is taken as 66 kg/kg-
mole and its vapor pressure as 269 mmHg (5.2 psia) . The calculated
emission factors for filling underground tanks are shown in Table
5-5. Splashfilling is assumed at jet fuels storage facilities
while submerged filling is assumed at aviation gasoline storage
facilities.
Withdrawal losses from underground tanks result from
inbreathing of air during the withdrawal of stored liquid, with
the volume of air being approximately equal to the volume of
liquid dispensed. This air then causes vaporization of hydro-
carbons with the resulting vapor volume being greater than the
inhaled air. Until a pressure balance with the atmosphere is
achieved, vapors are exhaled from the tank. A theoretical deriva-
tion, based on exhaling air saturated with hydrocarbons, for under-
ground tank withdrawal losses is given by Equation 5-3.
L - x P x « (5-3)
where P = Partial pressure of exhaled hydrocarbons in psia
divided by 14.7
M = Molecular weight of the hydrocarbon vapors
K = a constant. 2.83, to convert L to lb/103 gal dispensed
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TABLE 5-6
UNDERGROUND TANK FILLING LOSSES
(CH-159)
Method of Filling Filling Loss, kg/ci3
Splash 1.38
Submerged 0.87
Vapor Return-open vent line 0.10
Vapor Re turn-closed vent line O.,0
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In practice, the value of L is found to be one-sixth of what is
predicted by Equation 5-3. This is due to diffusion limitations
within the tank and the presence of subsaturated vapors within
the tank prior to withdrawal of liquid. Therefore, Equation 5-3
may be rewritten as
T - ( P W P v M v v r* />
-L* ~~ IT n J X r X ?r X rn f}-£i.i
IX I/
where FD is a diffusion and dilution factor equal to one-sixth.
The results of applying Equation 5-4 to the data of Table 5-1
gives the emission factors for underground storage withdrawal
losses shown in Table 5-5.
5.2.4 Pumps and Valves
Estimates of hydrocarbon emissions resulting from leaks
from pump seals and valves cannot be made with any reasonable
degree of accuracy due to two factors.
1) The best emission rate data available were
taken in 1958 for pumps and valves in refinery
service. The volatility of the liquids handled
by these pieces of equipment varied over the
entire range encountered in a refinery. In
addition, whether the emission data gathered
accurately reflects present day state-of-the-art
technology must also be questioned.
2) The number of pumps and valves present in the
transportation network is almost impossible
to estimate. Pumps and valves are found at
every transfer point and pump station in the
system. Multiple pump arrangements and the
variations in equipment configurations at
each location further complicate the task
of estimating fugitive leaks.
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As a result of these factors, no attempt is made in
this section to quantify pump seal and valve emissions. Instead,
a special discussion of fugitive leaks is included as Section 10.0.
5.3 Summary of Transfer Emissions
The emission factors developed in Section 5.2 can be used
in conjunction with throughput data to estimate hydrocarbon emis-
sion rates from the various point sources within the transfer
industry. Tables 5-7 through 5-10 summarize these emission factors
and give emission rates for each source based on an example through-
put of 159 m3/day (1000 gal/day).
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TABLE 5-7
EMISSION RATES FROM CRUDE OIL TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 m3/DAY (1000 bbl/Day)
EMISSION SOURCE EMISSION FACTOR. Kg/m3 THROUGHPUT HYDROCARBON EMISSIONS, Kg/Day
1. Crude Oil Production
Pump Seals 0.214 34.0
Pipeline Valves 0.034 5.4
Storage Tanks 0.011 1.7
2. Crude Oil Transportation
' Truck/Rail Loading 0.241 38.3
T Tanker/Barge Loading 0.0804 12.8
Pump Seals and Valves *
* This information cannot be accurately quantified. See Section 10.0 for a discussion of pump
seal and valve emissions.
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TABLE 5-8
EMISSION RATES FROM KEROSINE-BASED JET FUEL TRANSFER
BASED ON AN EXAMPLE THROUGHPUT OF 159 m3/day (1000 bbl/day)
EMISSION SOURCE
EMISSION FACTOR, Kg/m3 THROUGHPUT
HYDROCARBON EMISSIONS, Kg/Day
i
oo
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Storage Tanks
4. Underground Storage Tanks
Filling
Withdrawal
5. Aircraft Refueling
6. Pumps and Valves
0.00190
0.000635
0.00317
0.00444
Neg.
0.00317
0.30
0.10
0.50
0.71
Neg.
0.50
*
*This information cannot be accurately quantified. See Section 10.0 for a discussion of pump
seal and valve emissions.
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TABLE 5-9
EMISSION RATES FROM NAPHTHA-BASED JET FUEL TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 m3/day (1000 bbl/Day)
EMISSION SOURCE EMISSION FACTOR. Kg/m3 THROUGHPUT HYDROCARBON EMISSIONS. Kg/DAY
1. Truck/Rail Loading 0.180 28.6
2. Tanker/Barge Loading 0.0597 * 9.5
3. Fixed Roof Storage Tanks 0.300 47.7
4. Underground Storage Tanks
Filling 0.418 66.5
Withdrawal 0.00484 0.8
i
oo 5. Aircraft Refueling 0.298 47.4
1 6. Pumps and Valves *
* This information cannot be accurately quantified. See Section 10.0 for a discussion of pump
and valve emissions.
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TABLE 5-10
EMISSION RATES FROM AVIATION GASOLINE TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 m3/DAY (1000 bbl/Day)
EMISSION SOURCE EMISSION FACTOR, Kg/m3 THROUGHPUT HYDROCARBON EMISSIONS. Kg/DAY
54.9
18.3
91.4
81.1
3.8
91.3
*
1
oo
VO
1
1.
2.
3.
4.
5.
6.
Truck/Rail Loading
Tanker/Barge Loading
Fixed Roof Storage Tanks
Underground Storage Tanks
Filling
Withdrawal
Aircraft Refueling
Pumps and Valves
0.345
0.115
0.575
0.510
0.0236
0.574
* This information cannot be accurately quantified. See Section 10.0 for a discussion of
pump and valve emissions.
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6.0 APPLICABLE BEST SYSTEMS OF EMISSION REDUCTION
The use of Model IV to estimate the emission reduction
potential of NSPS for an industry is based on requiring the appli-
cation of the best available emission control systems to new emission
sources. The sources of emissions in the crude oil and aviation
fuels transfer industry segments as described in Section 5.0 are
1) loading operations, 2) storage facilities and 3) pumps and valves.
In this section the best available emission control systems are
identified for these emission sources. For loading operations,
the best available control systems are vapor collection and recovery
systems. These same type systems can be utilized to control storage
emissions, although the use of floating roof tanks in place of
fixed roof tanks and vapor balance loading techniques for under-
ground storage tanks are other alternatives. Pump and valve emissions
may be reduced by 1) use of mechanical seals or double seals and
2) good maintenance practices.
The following sections discuss loading operation and
storage facility emission controls and the reduction of pump seal
and valve emissions.
6.1 Loading Operations
The best available system for controlling hydrocarbon
emissions from transport loading operations is 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. While in theory aircraft refueling operations can be
controlled by vapor collection and recovery systems, the intricate
arrangement and non-uniformity of vents on aircraft fuel tanks make
vapor collection nearly impossible. Therefore, at this time no emis-
sion control methods are available for aircraft refueling operations.
The number and location of vapor collection and recovery
systems presently installed on crude oil and aviation fuels loading
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operations are not readily available. However, based on talks with
a limited number of representatives of the petroleum industry,
approximately 17% of the loading facilities have a vapor control
system (ST-407, HE-187, GR-235). The following sections discuss
the vapor collection and recovery systems available for controlling
loading emissions.
6.1.1 Vapor Collection Systems
Loading Equipment
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 6-1).
The loading arm consists of a splash or submerged loading nozzle
(Figure 6-2) fitted with a head which seals tightly against the
hatch opening. 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 6-3 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.
Collection Efficiency
The vapor containment efficiency of bottom loading
equipment approaches 100 percent on a tightly sealed transport
vehicle. When properly operating, the system remains sealed through-
out the loading operation. Dry break couplings are used on the dis-
pensing lines and check valves are used on the vapor return lines to
minimize spills and vapor escape during hook-ups and disconnects.
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VAPOR
GASOLINE
VAPOR RECOVERY
NOZZLE
MISCELLANEOUS PARTS
ITEM
1
2
3
4
5
6
7
8
9
10
11
PART NO.
3420-F-30
2775*
3420-F-40
H-5936
D-e37-M
H-5633-RP
H-S905-M
H-5905-M
H-M18-
C-1067-A
C-2479-M
DESCRIPTION
Swivel Joint, 3"
Boom
Swivel Joint. 4"
Swivel Joint 3"
Handle
Hose
Elbow
Cord Crip
Collar Sub-Assembly
Link
Gasket
QTY.
1
1
1
1
1
1
1
2
2
2
1
ITEM
12
13
14
15
16
17
IS
PART NO.
H-4190-M
D-835-M
3630-30
H-4189-W
H-5952
3340-FO-40
710
C-555-A
417-FKA-4"
3476-F-10
DESCRIPTION
Gasket, 4"
Upper Kindle & Pipe
Swivel Joint. 3"
Gasket, 3" :
Swivel Joint Sub-Assembly, 4"
Swivel Joint Only
4x27/8 Nipple Only
4" Flange Only
Loading Valve
Swivel Joint, 4"
QTY.
6
Figure 6-1. TOP LOADING ARM EQUIPPED WITH A VAPOR RECOVERY NOZZLE
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DUMP PASSAGE
UP/DOWN"
CONTROL VALVE
HANDLE
DUMP PASSAGE
FLOATING COLLAR
SEAL
LEVEL SENSOR
VAPOR RETURN
ADAPTOR
Figure 6-2. DETAIL OF A VAPOR RECOVERY NOZZLE
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Gasoline Dispensing Line
Vapor Return Line
Figure 6-3. BOTTOM LOADING VAPOR RECOVERY
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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 transport vehicle. Therefore,
bottom loading is used in this study as the best available loading
method.
6.1.2 Vapor Recovery Units
Vapor recovery units are manifolded into a vapor
collection system for either conversion of the hydrocarbon 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 loading operations.
The main processing operations employed by vapor recovery
systems are compression, refrigeration, absorption 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) Compress ion-Refrigeration-Condensation (CRC)
3) Refrigeration
4) Flame Oxidation
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All of the above systems are capable of achieving 90%
reduction of hydrocarbon emissions. These systems are rather
complex, however, and thus a proper maintenance schedule must be
maintained to assure proper operation. Reliability has generally
been reported as good when proper maintenance has been performed.
Figure 6-4 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 recovery
system (CRA) is based on the absorption of hydrocarbon vapors under
pressure with chilled recovered product 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 entering the absorber. In the
absorber, the cooled, comoressed vapors are contacted by chilled
recovered product drawn from product storage and are absorbed.
Hydrocarbon-free air is vented from the top of the absorber and
recovered product enriched with light ends is withdrawn from the
bottom of the absorber and returned to the storage tanks. The
operating conditions in the absorber vary with the manufacturer,
and range from -23°C (-10°F) to ambient temperature and from 4 atm
(45 psig) to 15 atm (210 psig).
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 com-
pression and refrigeration. Incoming vapors are first contacted
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PARKER VAPOR
RECOVERY SYSTEM
FLOW DIAGRAM
ABSORBER
COMPRESSOR
AFTERCOOLER
MODULE
L
AAAAAAAAAAAAAAJI
AAAAAAAAAAAAAA II T&EFR1GERATOR
MODULE
ft
AAAAAAAAAAAAAAA
SATURATOR-FLASH
VAPOR
SAVER
CONNECTION
VENT
CAS
A A A A A A A A A A "' J Vj
Figure 6-4. SCHEMATIC OF A TERMINAL VAPOR RECOVERY UNIT
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with recovered product in a saturator, and are saturated beyond
the flammability 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 storage tanks. Essentially hydrocarbon-free
air is vented from the top of the condenser. Operating conditions
vary with the manufacturer, with temperatures ranging from -23°F
(-10°F) to -1°C (30°F) and pressures ranging from 6.7 atm
(85 psig) to 28 atm (410 psig).
Refrigeration Systems
One of the most recently developed vapor recovery systems
is the straight refrigeration system, based on the condensation of
hydrocarbon vapors by refrigeration at atmospheric pressure. Vapors
displaced from the transport vehicle enter a horizontal fin-tube
condenser where they are cooled to -73°C (-100°F) and condensed.
Because the vapors are treated on demand no vapor holder is
required. Condensate is withdrawn from the condenser bottom
and hydrocarbon-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 maintain the stored
brine solution between -76°C (-105°F) and -87°C (-125°F).
Flame Oxidation Systems
One of the simplest vapor control systems for loading
operations is the flame oxidation system. This system controls
hydrocarbon emissions by combusting hydrocarbon vapors as opposed
to recovering them as a liquid product. Vapors from the transport
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vehicle 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 flammability
limit. When the vapor holder reaches its capacity the vapors
are released to the oxidizer, after mixing with a properly
metered air stream and combusted to carbon dioxide and water.
6.1.3 Efficiency of Vapor Recovery Units
The efficiency of a vapor recovery unit, defined as volume
percent reduction of hydrocarbons, is dependent upon four factors:
1) the unit's operating temperature,
2) the unit's operating pressure,
3) the hydrocarbon concentration of the inlet vapor-
air mixture, and
4) the hydrocarbon composition of the inlet vapor-
air mixture.
The CRA, CRC, and refrigeration type units have been shown to
operate very nearly at equilibrium. Thus, the hydrocarbon con-
centration of the exit vapors from these units is fixed for a
given operating temperature and pressure and inlet hydrocarbon
composition regardless of the inlet hydrocarbon concentration
(BU-169).
Computer Simulation
Equilibrium calculations were performed for the above
three systems using typical operating conditions listed below:
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RADIAN
CORPORATION
Operating Operating
System Temperature Pressure
Refrigeration -73-°C (100°F) Ambient
CRA 0 4.4 atm (65 psia)
CRC -4°C (25°F) 29 atm (440 psia)
In these calculations, the inlet hydrocarbon concentrations were
15 and 40 volume percent and the hydrocarbon composition was that
of a typical motor gasoline (Table 6-1). Table 6-2 shows the
results of the equilibrium calculations. Butanes are the major
hydrocarbon constituent of the exit vapors, with no hexane or
heavier compounds present (BU-169).
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RADIAN
CORPORATION
TABLE 6-1
VAPOR-AIR MIXTURE COMPOSITIONS
USED IN EQUILIBRIUM CALCULATIONS
Component
Air
(\
C5
C6
C7
Hydrocarbon Concentration
157. HC 40% HC
85.0%
7 . 57,
4.9%
1.7%
0.9%
60.0%
20.0%
13.2%
4.4%
2.4%
TABLE 6-2
SUMMARY OF EQUILIBRIUM CALCULATIONS
Hydrocarbon Outlet HC
Concentration Concentration % 1
System Type (%)
Refrigeration 15
40
CRC 15
40
CRA 15
40
0.9
0.9
2.5
2.6
2.5
2.5
94.0
98.0
83.0
93.5
83.0
94.0
1 Based on Volume 70 Recovery
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RADIAN
CORPORATION
Based on the above considerations, the limit of hydro-
carbon reduction achievable with a vapor recovery system (re-
frigeration type) is an exit vapor concentration of 0.9 volume
70. However, this limit is contingent upon the presence of
butane in the inlet vapors. If no butane or lighter compounds
are present, the exit vapor hydrocarbon concentration could be
reduced a further 90% to ~10070. Conversely, if propane or
lighter compounds are present in the inlet vapors, the exit
hydrocarbon concentration will be greater than 0.9 volume 70.
The use of flame oxidation to handle collected hydro-
carbon vapors would give emission reduction efficiencies
nominally equal to refrigeration type recovery units. Care
must be exercised in operating these units to maintain the proper
air/hydrocarbon mixture to insure complete combustion. Because
of the fairly equal effectiveness of the refrigeration and
oxidation systems, the refrigeration system is chosen for use
in this study.
Recovery Efficiency
The hydrocarbon concentrations of saturated vapors
from crude oil and aviation fuels are given in Table 6-3.
Based on these numbers, the efficiency of a refrigeration type
vapor recovery unit operating at -73°C (-100°F) and atmospheric
pressure can be calculated. For the crude oil vapors, the
exit stream is assumed to be 1.3 volume 7o hydrocarbons to account
for the presence of some propane in the inlet stream. For
kerosine jet fuel, no pentane or lighter compounds are present
in the inlet vapor-air mixture so the exit stream hydrocarbon
concentration is essentially nil. Table 6-3 lists the calculated
recovery efficiencies based on volume 70 and weight 70 recovery.
Since all vapors collected from loading operations and tank
-102-
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CORPORATION
TABLE 6-3
VAPOR RECOVERY EFFICIENCIES FOR REFRIGERATION
TYPE VAPOR RECOVERY UNITS
Source of Vapors
Saturated Vapor Recovery Efficiency
Hydrocarbon Based On
Concentration. Vol 7, Vol 7,Wt~I
Crude Oil
35.4
96.3
96.8
Kerosine Jet Fuel
Naphtha Jet Fuel
Aviation Gasoline
0.058
8.8
19.7
100
89.8
95.4
100
92.6
96.2
-103-
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CORPORATION
fillings are not saturated, the weight % efficiencies given in
Table 6-3 should be reduced slightly. Therefore, the efficiency
used in this study for recovery of vapors will be 9570 for crude
oil and aviation gasoline, 100% for kerosine jet fuel and 1070
for naphtha jet fuel.
6.2 Storage Facilities
Fixed Roof Tanks
When product is added to a fixed roof tank, an approxi-
mately equivalent volume of vapor is displaced from the tank.
Unless contained and disposed of, these expelled vapors become
atmospheric emissions. Because the method by which fixed roof
tank filling or working losses occur is essentially the same as
for loading operations, vapor recovery systems can be used to
control fixed roof tank losses by manifolding the tank vent lines
into a vapor recovery unit.
A second consideration in using vapor recovery systems
to control fixed roof tank emissions is the ability to integrate
the storage control system into loading control systems. Ex-
pansion of loading facilities will probably be accompanied by
an expansion of storage facilities. Since these new loading
operations are assumed to utilize a vapor recovery system for
emission control, the emissions from the associated new storage
tanks could be directed to the loading system vapor recovery unit.
Therefore, vapor recovery systems on fixed roof tanks are considered
in this study as the best available control methods for new above-
ground storage facilities. The discussion of vapor recovery units
contained in Sections 6.1.2 and 6.1.3 is directly applicable to
the recovery of emissions from fixed roof tanks.
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RADIAN
CORPORATION
Underground Tanks
Underground tanks are used for storage at locations
where the daily volume of petroleum liquid dispensed is relatively
small. These type tanks receive their fuels from tank trucks
loaded at bulk facilities (bulk terminals and stations or refineries)
Since new underground tanks will probably receive their fuels from
expanded bulk facilities, i.e., new sources, the tank trucks are
assumed to be equipped for bottom loading and unloading. Trucks
equipped in this manner are also capable of practicing the vapor
balance method of filling underground tanks. In this filling
method, the vapors expelled from the underground tank are directed
to the tank truck instead of being vented. This method of filling
has the advantage of returning nearly saturated vapors to the
bulk facility, which in turn makes the bulk facility's vapor
recovery system more efficient (Section 6.1.3 discusses the ef-
ficiency of vapor recovery units). Therefore, vapor balance
filling methods are used in this study as the best available con-
trol method for new underground storage tanks. The emission rates
from underground tanks using vapor balance filling methods can
be estimated from data contained in a study performed by the Los
Angeles County Air Pollution Control District (CH-159).
6.3 Pump and Valve Emission Controls
Pump Seals
Pump seals inherently leak and there is no practical
method for eliminating hydrocarbon emissions from these sources.
The two types of seals commonly used in the petroleum industry
are packed seals and mechanical seals. Average hydrocarbon losses
for both types of seals on centrifugal and reciprocating pumps
and compressors are tabulated in Table 6-4 (DA-069). A study of
Los Angeles County refineries found centrifugal pumps with packed
-105-
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TABLE 6-4
EFFECTIVENESS OF MECHANICAL AND PACKED
PUMP SEALS ON VARIOUS TYPES OF HYDROCARBONS
Type
Hydrocarbon
Being Pumped,
Avg Hydrocarbon
Loss Per
Inspected Seal,
Leak Incidence
Small Leaks,'
of Total
I
M
O
I
Large Leaks,
of Total
Seal Type
Mechanical
Average
Packed
Average
Packed
Average
Pump Type
Centrifugal
Centrifugal
Reciprocating
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
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
Inspected
19
18
19
19
20
32
12
22
31
24
9
20
Inspected
21
5
4
13
37
34
4
23
42
10
0
13
Small leaks lose less than 1 pound of hydrocarbon per day.
Source: DA-069
-------
RADIAN
CORPORATION
seals lost 2.2 kg (4.8 Ibs) of hydrocarbons/day-seal, centrifugal
pumps with mechanical seals lost 1.4 kg (3.2 Ibs) of hydrocarbons/
day-seal and reciprocal pumps with packed seals lost 2.4 kg (5.4 Ibs)
of hydrocarbons/day-seal. Therefore a 337o reduction in hydrocarbon
emissions from centrifugal pumps may be effected by installing mechan-
ical seals in place of packed seals. There are no alternatives to
using packed seals on reciprocating pumps. Dual sets of mechanical
seals may also be installed with provisions to vent the volatile
vapor 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.
Valves
Hydrocarbon emissions originating from product leaks
at valves can only be controlled by regular inspection and prompt
maintenance of valve packing boxes. Tests of numerous valves
indicate average hydrocarbon emissions of 0.2 kg (0.5 lb)/day-
valve for service with materials having vapor pressures above
1 atm (15 psia), and emissions of 0.02 kg (0.05 Ib)/day-valve
for service with materials having vapor pressures below 1 atm
(15 psia) (AT-040). Because of its dependence on the nature of
the products handled, the degree of maintenance, and the characteris-
tics of the equipment, the emissions reduction that can realistically
be expected from controlling valves cannot be defined with any
degree of accuracy.
6.4 Summary of Emissions Using Best Available Control Systems
The emission levels achieveable by the emission control
systems discussed in this chapter are shown in Tables 6-5 through
6-8. Emission factors for each source and the emission control
system employed are listed in this table. Emission rates are given
-107-
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TABLE 6-5
ACHIEVABLE EMISSION RATES FROM CRUDE OIL TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 m3/DAY (1000 bbl/DAY)
o
oo
i
EMISSION SOURCE
1. Crude Oil Production
Pump Seals
Pipeline Valves
Storage Tanks
2. Crude Oil Transportation
Truck/Rail Loading
Tanker/Barge Loading
Pump Seals and Valves
CONTROL TECHNIQUE
NA
NA
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
EMISSION FACTOR,
kg/m3 THROUGHPUT
0.214
0.034
0.00055
0.0120
0.00402
HYDROCARBON EMISSIONS,
kg/DAY
34.0
5.4
0.1
1.9
0.6
A
This information cannot be accurately quantified. See Section 10.0 for a discussion of pump
seal and valve emissions.
-------
TABLE 6-6
ACHIEVABLE EMISSION RATES FROM KEROSINE BASED JET FUEL TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 mVDAY (1000 bbl/DAY)
i
o
EMISSION SOURCE
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Storage Tanks
4. Underground Storage Tanks
Filling
Withdrawal
5. Aircraft Refueling
6. Pumps and Valves
CONTROL TECHNIQUE
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Balance System
NA
EMISSION FACTOR,
kg/m3 THROUGHPUT
negligible
negligible
negligible
0.00031
negligible
0.00317
HYDROCARBON EMISSIONS,
kg/DAY
negligible
negligible
negligible
0.05
negligible
0.50
This information cannot be accurately quantified. See Section 10.0 for a discussion of
pump and valve emissions.
-------
TABLE 6-7
ACHIEVABLE EMISSION RATES FROM NAPHTHA-BASED JET FUEL TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 m3/DAY (1000 bbl/DAY)
EMISSION SOURCE
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Storage Tanks
4. Underground Storage Tanks
Filling
o
i
Withdrawal
5. Aircraft Refueling
6. Pumps and Valves
CONTROL TECHNIQUE
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Balance System
NA
EMISSION FACTOR,
kg/m3 THROUGHPUT
0.0180
0.00597
0.0300
0.0290
0.00484
0.298
HYDROCARBON EMISSIONS,
kg/DAY
2.9
0.9
4.8
4.6
0.8
47.4
*
This information cannot be accurately quantified. See Section 10.0 for a discussion of pump
seal and valve emissions.
-------
TABLE 6-8
ACHIEVABLE EMISSION RATES FROM AVIATION GASOLINE TRANSFER BASED ON
AN EXAMPLE THROUGHPUT OF 159 m3/DAY (1000 bbl/DAY)
EMISSION SOURCE
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Storage Tanks
4. Underground Storage Tanks
Filling
Withdrawal
5. Aircraft Refueling
6. Pumps and Valves
CONTROL TECHNIQUE
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Balance System
NA
EMISSION FACTOR,
kg/m3 THROUGHPUT
0.0287
0.00575
0.0287
0.0559
0.0236
0.574
HYDROCARBON EMISSIONS,
kg/DAY
4.6
0.9
4.6
8.9
3.8
91.3
*
This information cannot be accurately quantified. See Section 10.0 for a discussion of
pump and valve emissions.
-------
RADIAN
CORPORATION
for an example throughput of 159 m3/day (1000 bbl/day). For
tank truck and rail car loading operations, the S factor of Equation
5-1 used in calculating the emission factor for aviation gasoline
is assumed to be 1.0 to indicate that these transport vehicles
deliver to tanks utilizing vapor balance systems and hence return
with saturated vapors.
-112-
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CORPORATION
7.0 CURRENT STATE HYDROCARBON EMISSION REGULATIONS
In order to define a baseline-year hydrocarbon emission
level for an industry, state regulations must be examined to
determine to what extent hydrocarbon emissions must be controlled.
This section summarizes the state hydrocarbon emission regulations
applicable to the storage and loading of petroleum liquids.
These regulations are not uniform and vary from no
regulations at all, to regulations only for specific air quality
control regions (AQCR), to regulations for all areas within a
state. In addition the scope of these regulations may also vary.
State regulations may apply to all existing sources, only to
existing sources in designated regions, or only to new sources.
Moreover, due to the current interest in controlling hydrocarbon
emissions, promulgation of new regulations and/or revision of
existing regulations by state legislatures is occurring at a
rapid pace.
State Regulations Summary
Table 7-1 is a summary of the latest state regulations
as reported in the Environmental Reporter - State Air Laws. This
table shows that twenty-seven states and the District of Columbia
have regulations that control, to some extent, hydrocarbon emissions
from storage tanks, while nineteen states and the District of
Columbia have regulations that control loading operations. Only
New Mexico and Colorado have regulations that apply to oil field
storage tanks. Rhode Island's regulations are representative of
the more stringent state regulations that have been promulgated.
As applied to the crude oil and aviation fuels transfer industry
segments, Rhode Island's regulations require the following:
-113-
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TABLE 7-1
Existing New
State Sources Sources
Alabama x
X
X
X
Alaska
Arkansas
Arizona x
X
'x
California
Colorado x
x
X
Connecticut x
x
(1,000* (250*
gal) gal)
Washington,
D.C. x
x
X X .
(2,000 ' (250
gal) gal)
SUMMARY
Tank Size
60, 000* gal
60,000* gal
1,000* gal
1,000* gal
65,000* gal
65,000* gal
Any
40,000* gal
40,000* gal
.. 550* gal
40,000* gal
40,000* gal
40,000* gal
40,000* gal
OF STATE HYDROCARBON EMISSION REGULATIONS
Stored Liquid
Vapor Pressure
1.5-11.0 psla
11.0* psia
1.5* psla
1.5* psla
2.0-12.0 psla
12.0* psla
Any
. 1.5-11.0 psla
11.0* psla
1.5* psla
1.5-11.0 psla
11.0* psla
1.5* psla
1.5-11.0 psla
11.0* psla
1.5* psla
Existing Ke»
Storage Regulations Sources Sources,
Pressure, vapor recovery, floating x
roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Permanent submerged fill pipe
Permanent or portable submerged fill
pipe
None Listed
None Listed
Pressure tank, floating roof or x
approved equivalent
Pressure tank or approved equivalent
Submerged fill pipe or approved
equivalent
*
Pressure tank, floating roof, vapor x
recovery or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Submerged fill pipe and vapor recovery
sufficient to restrict emissions to
1.15 lb/101 gal loaded «
Pressure tank, vapor recovery, float- x
Ing roof or approved equivalent
Pressure tank, vapor recovery, or
approved equivalent
Permanent submerged fill pipe, vapor
recovery or pressure tank
Pressure tank, vapor recovery, float- x
Ing roof -or approved equivalent
Pressure tank, vapor recovery or ap-
proved equivalent
Submerged fill pipe and 90 wt X ef-
ficient vapor recovery
Loading Regulations
Loading 50,000* gal/day
of 1.5* psla liquid re-
quires vapor recovery or
liquid must be 95Z sub-
merge filled.
None Listed
None Listed
Loading of 1.} psla
liquid must use sub-
merged filling
*
Loading 1.5 psla liquid
requires vapor collection
and disposal. Exceptions
for certain situations.
Loading of 10,000* gal/day
of 1.5* psla liquid Into
200* gal truck/rail tanks
must use vapor collection
and disposal or equivalent
Loading 1.5 psla liquid
must use vapor collection
and disposal with 90 wt Z
control or approved equiv-
alent
-------
TABLE 7-1. SUMMARY OF STATE HYDROCARBON EMISSION REGULATIONS (CONTINUED)
State
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Existing New
Sources Sources
X X
X X
X X
X
X
X
X
X
X X
(Priority A
areas)
x x
(Priority A
areas)
x
X
X
X X
(Priority' I
areas)
x x
(Priority I
areas)
x x
(Priority I
areas)
Tank Site
40,000* gal
40,000* gal
250* gal
40,000* gal
40,000* gal
40.000* gal
40,000 gal
250* gal
40,000* gal
4,
40,000 gai
4.
250 gal
4.
ga
40,000* gal
40,000* gal
.1.
40,000 gal
500-40,000
gal
Stored Liquid
Vapor Pressure
1.5-11.0 psla
11.0* psla
1.5* psla
1.5-11.0 pala
11.0* psia
2.5-12.5 psla
g 70°P
12.5 psla
@ 70°P
2.5-12.0 psla
4.
12.0 psia
4.
2.5 pala
3n_ 11 ft nnla
. U 1 J. U pB la
13.0* psla
1.5-11.1 psia
+.
11.1 psla
4.
1.5 psia
Existing
Storage Regulations Sources
None Listed
None Listed
None Listed
Pressure tank, vapor recovery, float-
Ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Permanent submerged fill pipe or
vapor recovery
Pressure tank, vapor recovery, float-
Ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Pressure tank, vapor recovery, float- x
Ing roof or approved equivalent-
Pressure tank, vapor recovery or
approved equivalent
Permanent submerged fill pipe, vapor
recovery or approved equivalent
Pressure tank, vapor recovery, float- x
Ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Submerged fill pipe or vapor recovery
None Listed
Ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Pressure tank, vapor recovery, float-
Ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Permanent submerged fill pipe or vapor
recovery
New
Sources Loading Regulations
None Listed
None Listed
None Listed
None Listed
None Listed
Loading 40,000* gal/day
can emit only 8 Ib hydro-
carbons/hr unless sub-
merged filling or equiv-
alent is used.
Loading 40,000* gal/day of
2.5+ psla liquid requires
vapor recovery or sub-
merged filling
None Listed
None Listed
x Loading 20,000 gal/day re-
quires 90 wt Z control of
emissions
-------
TABLE 7-1. SUMMARY OF STATE HYDROCARBON EMISSION REGULATIONS (CONTINUED)
Existing New
State Sources Sources
Louisiana x .
x
X
Maine
Maryland
Massachusetts
Michigan
Minnesota x
x
x
Mississippi
Montana x
x
Nebraska
Nevada . x
x
X
New Hampshire
New Jersey x
x
X
Tank Site
40.000* gal
40,000* gal
250* gal
65,000* gal
65,000* gal
250* gal
65,000* gal
65,000* gal
40,000* gal
40,000* gal
any
2,000* gal
10,000* gal
1,000* gal
Stored Liquid
Vapor Pressure
1.5-11.0 psla
11. 0* paia
2.5-12.5 psla
12.5* psla
4* psla RVP
2.5-13.0 psla
13.0* psia
1.5-11 psla
11* psla
1.5* psla
0.02* psia
13.0* psla
Existing
Storage Regulations Sources
Pressure tank, vapor recovery, float-
Ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Permanent submerged fill pipe, vapor
recovery or approved equivalent
None Listed
None Listed
None Listed
None Listed
Pressure tank, vapor recovery, float-
Ing roof or approved equivalent.
Pressure tank, vapor recovery or
approved equivalent
Permanent Submerged fill pipe or vapor
recovery
None Listed
Pressure tank, vapor recovery, float-
Ing roof or approved equivalent
Pressure tank, vapor recovery or ap-
proved equivalent
None Listed
Pressure tank, vapor recovery, float- x
ing roof or approved equivalent
Pressure tank, vapor recovery or
approved equivalent
Submerged fill pipe or approved equiva-
lent
None Listed
Tank must be painted white x
Table used to calculate emmlsslon con-
trol required
Vapor recovery with 90X efficiency
New
Sources Loading Regulations
x Loading 20,000* gal /day of
1.5+ psla liquid into 200+
gal truck/rail tank must
use 95Z submerged fill or
vapor collection and dis-
posal
None Listed
None Listed
None Listed
None Listed
None Listed
None Listed
None Listed
None Listed
Loading of 1.5 psia
liquids must use sub-
merged fill pipe or
approved equivalent
None Listed
Loading 0.02 psia liquid
into 2,000+ gal tank must
use submerged fill pipe or
approved equivalent
-------
TABLE 7-1. SUMMARY OF STATE HYDROCARBON EMISSION REGULATIONS (CONTINUED)
Existing New Scored Liquid
State Sources Sources Tank Size Vapor Pressure
New Mexico x 20,000+ gal
x 65,000 gal 1.5-11.0 psia
(refineries)
Storage Regulations
Submerged fill pipe or approved
equivalent
Pressure tank, vapor recovery,
floating roof or approved
equivalent
Existing
Sources
Hew
Sources
Loading Regulations
x Loading of 1.5 psla RVP
(refineries) liquids must use vapor
collection and disposal
X
(refineries)
New York
North Carolina x
North Dakota x
x
X
Ohio x x
(Priority I
area)
x x
(Priority 1
area)
x x
(Priority I
area)
Oklahoma x
x
X
65,000* gal
50,000* gal
50,000* gal
65,000* gal
65,000* gal
1,000* gal
65,000* gal
65,000* gal
500* gal
40.000* gal
40,000* gal
250* gal
11.0* psla
1.5-11.0 pala
11.0* psla
1.5-12.0 psla
% 12.0* psla
1.5* psia
1.5-12.5 psla
12.5* psla
1.5* psla
1.5-11 psla
11.0* psia
1.5* psla .
Pressure tank, vapor recovery or
approved equivalent
None Listed
Pressure tank, vapor recovery, x
floating roof or approved
equivalent
Pressure tank, vapor recovery- or
approved equivalent
Pressure tank, vapor recovery, . x
floating roof or approved
equivalent
Pressure tank, vapor recovery or
approved equivalent
Submerged fill pipe or vapor
recovery
Pressure tank, vapor recovery, x x
floating roof or approved (Priority I
equivalent area}
Pressure tank, vapor recovery or
approved equivalent '
Submerged fill pipe or vapor
recovery
Pressure tank, vapor recovery. x
floating roof or approved
equivalent
Pressure tank, vapor recovery or
approved- equivalent x
Permanent Submerged fill pipe or
vapor recovery
None Listed
Loading 20,000* gal/day of
1.5+ psia liquid must use
submerged loading or ap-
proved equivalent
Loading 20,003 gal/day of
1.5+ psla liquid oust use
submerbed loading or ap-
proved equivalent
Loading 40,000* gal/day of
1.5+ psla liquid must use
vapor collection and dis-
posal or approved equiva-
lent
Loading 40.000* gal/day of
1.5+ psla liquid must use
bottom loading or vapor
collection and disposal
Loading less than 40,000
gal/day of 1.5+ psi liquid
Into 200+ gal truck/rail
tanks oust use submerged
filling
-------
TABLE 7-1. SUMMARY OF HYDROCARBON EMISSION REGULATIONS (CONTINUED)
oo
i
State
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Existing New
Sources Sources
x
x
x
(specific
areas
only)
x
(specific
areas
only)
x
x
X
t
X
(specific
areas
only)
x
(specific
areas
only)
x
(specific
areas
only)
x
x
Stored Liquid
Tank Size Vapor Pressure
40, 000* gal 1.5-11.1 psla
40,000* gal 11.1* psla
40,000* gal 1.5-11.0 psla
40,000* gal 11.0* psia
40,000* gal 1.5-11.0 psla
40,000* gal 11.0* psla
250-40,000 1.5* psia
gal
25,000* gal 1.5-11.0 psla
25.000* gal- 11.0* psla
1,000* gal 1.5*
any 1.5-11.1 psla
any 11.1 psia
Storage Regulations
Pressure tank, vapor recovery,
floating roof or approved
equivalent
Pressure tank, vapor recovery
or approved equivalent
Pressure tank, vapor recovery,
floating roof or approved
equivalent
Pressure tank, vapor recovery or
approved equivalent
Pressure tank, vapor recovery,
floating roof or approved
equivalent
Pressure tank, vapor recovery
or approved equivalent
Permanent submerged fill pipe or
approved equivalent
Hone Listed
None Listed
None Listed
Pressure tank, vapor recovery,
floating roof or approved
equivalent
Pressure tank, vapor recovery or
approved equivalent
Permanent submerged fill pipe or
vapor recovery
Pressure tank, vapor recovery,
floating roof or approved
equivalent
Pressure tank, vapor recovery or
approved equivalent
Existing New
Sources Sources Loading Regulations
None Listed
x Loading 20,000 gal/day of
1.5+ psla liquid Into 200+
gal truck/rail tanks oust
use vapor collection and
disposal
x Loading 40,000* gal/day of
1.5+ psla liquid must use
submerge loading, vapor
recovery or approved
equivalent
None Listed
None Listed
None Listed
x Loading 20,000* gal/day of
(specific 1.5+ psia liquid mist use
areas vapor recovery
only)
None Listed
-------
TABLE 7-1. SUMMARY OF HYDROCARBON EMISSION REGULATIONS (CONTINUED)
State
Virginia
Vermont
West Virginia
Washington
Wisconsin
Existing Hew
Sources Sources
X
(AQCR 7
only)
X
(AQCR 7
only)
X
X
Stored Liquid
Tank Size Vapor Pressure Storage Regulations
40,000 gal 1.5-11.1 psia Pressure tank, vapor recovery,
floating roof or approved
equivalent
+ +
40,000 gal 11.1 psia Pressure tank, vapor recovery
or approved equivalent
None Listed
None Listed
None Listed
40,000 gal 1.5-11.1 psia Pressure tank, vapor recovery.
floating roof or approved
equivalent
40,000 gal 11.1 psia Pressure tank, vapor recovery
or approved equivalent
Existing New
Sources Sources Loading Regulations
x Loading 20,000 gal/day of
(AQCR 7 1.5+ psia liquid must use
only) vapor collection and dis-
posal or approved equiv-
alent
None Listed
None Listed
None Listed
None Listed
* California hydrocarbon emissions are regulated by regional agencies; there are no state regulations.
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CORPORATION
1) Aviation gasoline and crude oil storage tanks
with capacities of 152,000 liters (40,000
gallons) or greater are to be pressure tanks or
floating-roof tanks, or are to be equipped
with a vapor recovery system.
2) Aviation gasoline and crude oil tanks with
capacities of 946 liters (250 gallons) to
152,000 liters (40,000 gallons) must have
permanent submerged fill pipes or an approved
equivalent.
3) Loading facilities that dispense 152,000 liters/
day (40,000 gallons/day) or greater of petroleum
liquids with vapor pressures of 77.9 mmHg (1.5
psia) or greater must use submerged loading
methods, vapor recovery systems or an approved
equivalent for loading aviation gasoline or
crude oil.
Rhode Island's regulations do not apply to jet fuel storage and
loading since the vapor pressures of these liquids are below
77 mmHg (1.5 psia), or to crude oil production storage tanks.
Comparison of Emission Levels
In order to compare the emission levels achievable
with the best available emission control systems to the emission
levels required by state regulations, emission factors are devel-
oped for each emission source in the crude oil and aviation fuels
network based on Rhode Island's regulations. For the purpose of
these calculations, vapor recovery systems are used for storage
tanks. Submerged filling procedures are assumed for the loading
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of tank trucks, rail cars and marine vessels. Comparisons of
point source emission rates using current controls and using best
available controls are presented in Tables 7-2 through 7-5. An
example throughput of 159 m3/day (1000 bbl/day) was used for these
calculations. The best available control technique and emission
reduction achievable for each source are also included in these
tables.
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TABLE 7-2
COMPARISON OF BEST AVAILABLE CONTROL SYSTEM AND CURRENT CONTROL EMISSION LEVELS*
CRUDE OIL TRANSFER SEGMENT
I
M
NJ
I
Emission Source
1. Crude Oil Production
Pump Seals
Pipeline Valves
Storage Tanks
2. Crude Oil Transportation
Truck/Rail Loading
Tanker/Barge Loading
Pump Seals and Valves
Control Technique
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
Hydrocarbon Emission Rate
with Best Systems. Kg/day
3A.O
5.A
0.1
1.9
0.6
**
Current Control Emission
Level*** Kg/day Reduction, ke/dav
34.0
5.A
1.7
38.3
12.8
**
0.0
0.0
1.6
36.A
12.2
**
*Based on an example throughput of 159 m'/day (1000 bbl/day)
**This information cannot be accurately quantified. See Section 10.0 for a discussion of pump and valve emissions.
***Based on Rhode Island's regulations being applied nationwide.
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TABLE 7-3
I
I-1
N5
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
Fixed Roof Storage Tanks
Underground Storag
Filling
Withdrawal
Aircraft Refueling
3.
4.
5.
6. Pumps and Valves
COMPARISON OF BEST AVAILABLE CONTROL SYSTEM AND CURRENT CONTROL EMISSION LEVELS*
KEROSINB JET FUEL TRANSFER SEGMENT
>g
Tanks
; Tanks
Control Technique
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Balance System
NA
Hydrocarbon Emission Rate
with Best Systems, Kg/day
negligible
negligible
negligible
0.05
negligible
0.50
**
Current Control
Level***, Kg/day
0.30
0.10
0.50
0.71
negligible
0.50
**
Emission
Reduction, kg/day
0.30
0.10
0.50
0.66
0.0
**
*Based on an example throughput of 159 m3/day (1000 bbl/day)
**This information cannot be accurately quantified. See Section 10.0 for a discussion of pump and valve emissions.
***Based on Rhode Island's regulations being applied nationwide
NA - None available
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TABLE 7-4
COMPARISON OF BEST AVAILABLE CONTROL SYSTEM AND CURRENT CONTROL EMISSION LEVELS*
l
M
tsi
-P-
1.
2.
3.
it.
5.
6.
Emission Source
Truck/Rail Loading
Tanker /Barge Loading
Fixed Roof Storage Tanks
Underground Storage Tanks
Filling
Withdrawal
Aircraft Refueling
Pumps and Valves
NAPHTHA JET FUEL TRANSFER SEGMENT
Hydrocarbon Emission Rate
Control Technique with Best Systems, Kg/day
Vapor Collection and Recovery 2.9
Vapor Collection and Recovery 0.9
Vapor Collection and Recovery 4.8
Vapor Balance System
4.6
0.8
NA 47.4
**
Current Control
Level***, Kg/day
28.6
9.5
47.7
66.5
0.8
47.4
**
Emission
Reduction, kg/day
25.7
8.6
42.9
61.9
0.0
0.0
**
*Based on an example throughput of 159 m3/day (1000 bbl/day)
**Thls information cannot be accurately quantified. See Section 10-Qfor a discussion of pump and valve emissions.
***Based on Rhode Island's regulations being applied nationwide.
NA - None available
-------
TABT.E 7-5
^COMPARISON OF BEST AVAILABLE CONTROL SYSTEM AND CURRENT CONTROL EMISSION LEVELS*
AVIATION GASOLINE TRANSFER SEGMENT
Ui
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Storage Tanks
4. Underground Storage Tanks'
Filling
Withdrawal
5. Aircraft Refueling
6. Pumps and Valves
Control Technique
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Collection and Recovery
Vapor Balance System
NA
Hydrocarbon Emission Rat£ Current Control
with Best Systems, Kg/day 'Level***. Kg/day
Emission
Reduction, kg/day
4.6
0.9
4.6
54.9
18.3
4.6
50.3
17.4
0.0
8.9
3.8
91.3
**
81.9
3.8
91.3 '
**
73.0
0.0
0.0
**
*Based on an example throughput of 159 m3/day (1000 bbI/day)
**This information cannot be accurately quantified. See Section 10D for a discussion of pump and valve emissions.
***Based on Rhode Island's regulations being applied nationwide.
NA - None available
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CORPORATION
8.0 FACILITY MODIFICATION AND MODERNIZATION
NSPS apply to existing facilities that are modified,
modernized or reconstructed such that an increased mass rate of
emissions results. Therefore, it is necessary to identify how
the petroleum transfer industry undergoes modification and modern-
ization and what effect these changes have on the hydrocarbon
emission rates from modified or modernized facilities.
Modification and modernization in the crude oil
and aviation fuels transfer industry segments normally consist
of adding additional facilities or replacing worn out or faulty
equipment. Since there are no processing or treating operations,
there is no concern with conversion or production efficiency as
is found in industrial plants. Instead, the concern in a trans-
fer industry is the minimization of product losses. For this
reason, modification or modernization that does not increase
throughput rarely results in increased emissions but normally
produces an emission level less than or equal to the prior level.
However, the expansion of a transfer industry's
throughput normally does result in increased emissions. As
evidenced by the emission factors developed in Sections 5.0-7.0,
the emission rates from each emission source in a transfer net-
work are directly dependent upon throughput. For example, a
doubling of throughput at a bulk terminal loading rack will
result in a doubling of loading emissions if the same type of
loading methods are employed for the added capacity.
The methods of expanding a transfer network are very
straightforward. In terms of storage facilities, additional
storage tanks are constructed and new loading arms are installed.
To increase the amount of liquid moved by tank truck, rail car or
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CORPORATION
marine vessels, additional trucks, cars or ships are purchased and
put into service. New wells are drilled to increase crude oil
production. (Secondary and tertiary recovery techniques can be
used to increase a declining oil well's production, but the
increased recovery rate will not equal the well's peak primary
recovery rate). Therefore, the increased emissions from an
expansion of throughput can be quantified by merely applying the
appropriate emission factor from Section 5.0 or 6.0 to the new
flow.
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CORPORATION
9.0 ESTIMATED EMISSION REDUCTION
In order to evaluate the emission reduction potential
NSPS would have on the various segments of the petroleum transfer
industry, an EPA developed calculational procedure known as
Model IV was used. In this section Model IV is described and the
results of the calculations for each segment of the petroleum
transfer industry are presented.
9.1 Model IV
The execution of Model IV entails the use of two sets
of conditions to estimate an industry's emissions ten years from
a baseline year. (In this study 1975 is the baseline year and
1985 is the calculational year.) The first emission calculation
is made by assuming emissions in 1985 will be controlled to the
level required by the baseline year regulations. The second
calculation of 1985 emissions assumes that after the baseline
year, all new emission sources will be required to utilize the
best available emission control techniques. The difference between
the two estimates is the emission reduction potential of NSPS.
In order to use Model IV, the following information is
needed:
1) a description of the industry and its
throughput or capacity,
2) identification of the industry's emission
sources and emission estimates for each source,
3) identification of the best available control
techniques for each emission source,
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4) the state emission regulations applicable
to each emission source, and
5) the methods by which facilities are modified
or modernized,
A brief mathematical description of Model IV is given below:
The following definitions are required to derive
Model IV in mathematical terms:
j-^S. year = baseline year (in this study 1975
is the jO. year)
iHl year = future year for which the emission reduction
potential of NSPS is to be calculated (for
this study 1985 is the i year)
TS - total emissions in the i year under j
year regulations
TM = total emissions in the i year under NSPS
^t_
which have been promulgated in the j year
t?V\
A1 = j year throughput, 106m3
tVi
B' = i-^- year throughput from construction and
modification to replace obsolete facilities,
106m3
C' = i year throughput from construction and
.th
modification to increase throughput above j
year, 106m3
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CORPORATION
construction and modification rate to
replace obsolete facilities, decimal
fraction of j year throughput
PC,= construction and modification rate to
increase industry throughput, decimal
fraction of j year throughput
Eg = allowable emissions under j year
regulations, kg/106n3 throughput
allowable emissions under NSPS, kg/106m3
throughput
Using the above definitions, the emission reduction potential
of NSPS would be Tg-TN. TN and Tg can be calculated by the
following equations.
TN = ES(A'-B') + EN(B'+C')
Tg - ES(A'+C') = EgCA'-B1) + EgCB'+C1)
Therefore, TC-TM can be calculated as
O IN
TS-TN = ES(B'+C') + EN(B'+G')
= (ES+EN)(B'+C')
Depending on whether the future growth of an industry is assumed
to be compound or simple, the following formulas can be used
to calculate B1 and C1.
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If compound growth is assumed,
B' = A1 [(1+Pg,)1 - 1]
C1 = A1 [(l+Pc,)i - 1]
If simple growth is assumed,
B' = AiPfi,
C1 = AiPfi,
where i = elapsed time in years from the jth year. Curve fitting
historical data is a third method of calculating B1 and C1.
This method is used in this study whenever possible.
Appendix B contains the calculations used in executing
Model IV. Most of the information required to perform these
calculations is contained in Sections 4.0 - 8.0. Additional
information on the types of storage tanks in the transfer segments
and their throughput is presented with the calculations. The
results of the Model IV calculations for the crude oil, kerosine-
based jet fuel, naphtha-based jet fuel and aviation gasoline
transfer segments are presented and discussed in Section 9.2.
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9.2 Model IV Results
In this section each of the petroleum transfer segments
is discussed in terms of the specific input variables necessary
to execute Model IV and the calculated emission reduction potential.
9.2.1 Crude Oil Transfer Segment
Input Variables
The data required to execute Model IV for the crude
oil transfer industry segment are summarized in Table 9-1. The
crude oil production factors are based on a projected domestic
crude production rate of 1.86 x 106m3/day (11.7 x 106 bbl/day)
in 1985 (ST-381) and the assumption that old production
(production from wells in existence in 1975) will decline at an
annual rate of 3% over the 1975 to 1985 time period. The
crude oil production emission factor, E , is based on data pre-
s
sented in (MS-001). In calculating EN, a 95 wt % efficient
vapor collection and recovery system is assumed to be applied
to oil field storage emissions.
Historical data show that the amount of domestic
crude oil transported by truck/rail and tanker/barge is a fairly
constant percent of domestic production. Therefore, the 1975
percentages are applied to the predicted domestic production for
1985 to estimate the throughput for the various modes of trans-
portation at that time. The tanker/barge loading throughput in
1985 that is a result of construction and modification to replace
obsolete facilities (factor B1) is calculated from IRS depreciation
guidelines (CO-424).
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TABLE 9-1
SUMMARY OF
INPUT/OUTPUT VARIABLES FOR MODEL IV
CRUDE OIL TRANSFER
Emission Factor,
kg/ 106 m * throughput
Emission
:rude Oil
'ruck/RaiJ
Source
Production
L Loading
'anker/Barge Loading
. Es
259,000
241,000
80,400
EH
249,000
12,000
4,020
Growth Rates, '
Decimal/yr
V p
-0.03
*
0.0312
C1
*
*
*
Throughput,
lO'mVyr
A1 B' C'
485 124 194
12'.8 3.41 1.84
47.8 14.9 124
Emlss Ions ,
10'kg/yr
TA Tg TN
126 176 173
3.08 ' 3.53 2.33
3.84 13.8 3.20
Emission
Reduction,
103kg/yr
VTN
3
1.20
10.6
TOTALS 133 193 178 14.8
*Growth rate Is calculated by method other than use of P , or P ,
C B
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RADIAN
CORPORATION
The value of B" for truck/rail loading is calculated
by subtracting the estimated quantity of old production transported
by this mode in 1985 from the quantity of crude transported via
truck/rail in 1975. No allowance in the value of B1 is made for
equipment becoming obsolete since crude oil truck/rail loading
racks are located near the oil fields and have useful lifetimes
greater than the production lifetime of the oil reservoir. Thus,
there is no need to replace equipment. Emission factors for base-
line year controls, Eg, and best available controls, EN are
calculated from API correlations.
Emission Reduction Potential
Table 9-2 is a summary of the emissions from and
the emission reduction potential of NSPS for the crude oil
transfer industry segment. From the data of this table, the
emission reduction is approximately 8% of the baseline year
controls emission level. Over 707o of the total emission reduction
or 10.6 x 106kg/yr (11.7 x 103tons/yr), is estimated to result
from control of tanker/barge loading operations. The major
portion of the new tanker/barge loading facilities will be located
on Alaska's south shore.
9.2.2 Kerosine Jet Fuel Segment
Input Variables
The variables required to execute Model IV for the
kerosine jet fuel transfer industry segment are summarized in
Table 9-3. The amount of kerosine jet fuel loaded into tankers
and barges is calculated as a percent of indicated demand.
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TABLE 9-2
Ln
NATIONAL EMISSION REDUCTION BY 1985*
CRUDE OIL TRANSFER
Emission Rate with
1.
2.
3.
Emissions Source
Crude Oil Production
Storage Tanks
Pump Seals
Pipeline Valves
Production Subtotal
Truck/Rail Loading
Tanker/Barge Loading
INDUSTRY TOTAL
Best Available System,
Control Techniques 106kg/yr(103tons/yr)
Vapor Collection and Recovery 4.3
145
23.1
172
Vapor Collection and Recovery 2.33
Vapor Collection and Recovery 3.20
178
(4.7)
(160)
(25.4)
(190)
(2.57)
(3.52)
(196)
Emission Rate Under
1975 Controls,
106kg/yr(103tons/yr)
7.5
145
23.1
176
3.53
13.8
193
(8.3)
(160)
(25.4)
(194)
(3.89)
(15.2)
(213)
Emission Reduction,
106kg/yr(103tons/yr
3.2
0
0
3.2
1.20
10.6
15
(3.6)
(4)
(1.32)
(11.7)
(17)
*As Per Model IV evaluation (10 years)
-------
TABLE 9-3
SUMMARY OF INPUT/OUTPUT VARIABLES
FOR MODEL IV
KEROSINB JET FUEL TRANSFER
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
1 3. Fixed Roof Tanks
l_i
^ 4. Underground Tanks
5. Aircraft Refueling
Emission Factor,
kg/106m3 throughput
ES EN
1,900 0
635 0
3,170 . 0
4,440 310
3,170 3,170
Growth Rates, Throughput,
Declmal/yr 106mJ/yr
V PC' A'
0.0312 * 27.1
0.0312 * 6.2
0.0312 * 42.4
0.0312 * 17.0
0 0.0468 45.9
B1 C1
8.5 6.2
1.9 -0.471
13.2 21.5
5.3 6.9
0 21.5
Emlss ions,
103kg/yr
TA
51.5
3.9
134
75.5
146
Ts TN
63.3 35.3
3.6 2.7
203 93
106 55.7
214 214
Emission
Reduction,
10'kg/yr
T -T
S N
28,0
0.9
110
50.3
0
TOTALS
411
590
401
189
*Growth rate Is calculated by method other than use of P_,
' \j
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RADIAN
CORPORATION
Historical data show that this percentage has decreased at a
compound rate of 0.0454 from 1966 to 1975. Extrapolating this
to 1985 indicates tanker/barge loadings will decline by about
5 percentage points to 8.5% of indicated demand. Thus, although
demand for kerosine jet fuel increases from 1975 to 1985, the
amount loaded into tankers/barges is estimated to decrease by
0.471 x 106m3 (2.96 x 106bbl).
The amount of truck/rail transport of kerosine jet
fuel in 1985 is estimated from a complex interrelationship of
pipeline transport, tanker/barge transport and military and
commercial usage. Based on the discussion in Section 4.2.2 and
Figure 4-6, truck/rail loading of kerosine jet fuel is estimated
to increase by 6.2 x 106m3 (39 x 10s bbl) from 1975 to 1985.
Because of the low vapor pressure of kerosine jet
fuel, all bulk terminal and station storage of this fuel is assumed
to be in fixed roof tanks. From Figure 4-6, the amount of kerosine
jet fuel handled by bulk facilities in 1985 is estimated to be
21.5 x 106m3 (135 x 106 bbl). Therefore, the fixed roof tank
throughput of kerosine jet fuel in 1985 is assumed equal to this
number.
Major airports which require large quantities of kerosine
jet fuel normally store their jet fuel in floating roof tanks to
protect the fuel from contamination by water and dirt. Smaller
airports and the military do not use large quantities of kerosine
jet fuel and hence cannot economically justify the installation
of large floating roof tanks. These end users store kerosine
jet fuel in underground tanks. In 1985, 20.4 x 106m3 (129 x 106
bbl) of kerosine jet fuel or 327» of the total commercial usage
(US-418) is estimated to be used by small airports and 3.5 x
106m3 (22 .x 106 bbl) is estimated to be the military usage. There-
fore, the underground tank throughput of kerosine jet fuel in
1985 is estimated to be 23.9 x 106m3 (150 x 106 bbl).
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CORPORATION
Aircraft refueling throughput is calculated by
assuming a simple growth rate in indicated demand from 1975 to
1985 equal to the growth exhibited from 1969 to 1973. At this
assumed growth rate (4.68% of 1975's demand per year), the
indicated demand in 1985 is 67.4 x 106m3(424 x 106bbl). This
value is used for aircraft refueling throughput.
The values of C', throughput from construction and
modification to increase throughput above 1975's level, for the
various point sources are calculated by subtracting 1975's
throughput from 1985's throughput. The throughput due to con-
struction and modification to replace obsolete facilities is esti-
mated from IRS depreciation guideline information (CO-424).
Emission factors for truck/rail and tanker/barge
loading and fixed roof storage tanks are calculated from API
correlations (AM-085, AM-039) while underground storage tank
emission factors are derived from a study performed by the Los
Angeles County Air Pollution Control District (CH-159). Vapor
recovery and collection systems with 100% recovery efficiencies
are applied to truck/rail loadings, tanker/barge loadings and
fixed roof tanks to estimate emission factors with best available
controls. Underground tanks are controlled by use of vapor
balance unloading techniques.
Emission Reduction Potential
Table 9-4 is a summary of the results of Model IVs
calculations for the kerosine jet fuel segment of the transfer
industry. The emission reduction potential, 189 x 103m3/yr
(208 tons/yr), is approximately 3270 of the emissions estimated to
occur if only baseline year regulations are in effect in 1985.
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TABLE 9-4
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Tanks
4. Underground Tanks
5. Aircraft Refueling
INDUSTRY TOTAL
Vapor
Vapor
Vapor
Vapor
NATIONAL EMISSION REDUCTION BY 1985*
KEROSINB JET FUEL TRANSFER
Emission Rate with
Best Available System,
Control Technique 103kg/yr(tons/yr)
Collection and Recovery 35.3 (38.9)
Collection and Recovery 2.7 (3.0)
Collection and Recovery 93 (103)
Balance System 55.7 (61.3)
NA 214 (236)
401 (442)
Emission Rate Under
1975 Controls,
103kg/yr (tons/yr)
63.3 (69.7)
3.6 (4.0)
203 (224)
106 (117)
214 (236)
590 (650)
Emission
Reduction!
10*kg/yr(tons/yr)
28.0 (30.8)
0.9 (1.0)
110 (122)
50.3 (55.7)
0
189 (208)
As per Model IV evaluation (10 years)
NA - none available
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RADIAN
CORPORATION
The major contributor to the emission reduction is fixed roof
tanks losses, which account for 5870 of the total emission reduction.
9-2-3 Naphtha Jet Fuel Transfer Segment
Input .Variables
The variables required to execute Model IV for the
naphtha jet fuel transfer industry segment are summarized in
Table 9-5. Indicated domestic demand for naphtha jet fuel is
estimated by extrapolating historical demand data to 1985. This
calculation shows demand will decrease from 12.1 x 106m3 (76.1 x
106 bbl) in 1975 to 7.63 x 106m3 (48.0 x 106 bbl) in 1985. The
difference in these two values, -4.47 x 106m3 (-28.1 x 106 bbl)
is used as C1 for aircraft refueling.
Tanker and barge loadings of naphtha jet fuel in
1985 are assumed to be equal to the same percent of indicated
demand as existed in 1975. Since demand is estimated to decline,
tanker/barge loadings will also decline. Therefore, C1 for
tanker/barge loading is calculated to be -0.59.
Based on the discussion of Section 4.3.2 and
Figure 4-10, truck/fail loadings are estimated to decline by
7.0 x 106 m3(44.0 x 106 bbl) from 1975's total. This decline
is directly related to the decline in demand for naphtha jet
fuel.
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TABLE 9-5
SUMMARY
Of INPUT/OUTPUT VARIABLES FOR MODEL IV
' NAPHTHA JET FUEL TRANSFER
Emission Factor,
kg/106ms throughput
ES
180,000
59/700
300,000
423,000
298.000
EN
18,000
5,970
30,000
33,800
298.000
Growth Rates,
Decimal/ yr
0
0
0
0
0
PB' P
.0312
.0312
.0312
.0312
i
C
*
*
*
*
*
A1
18.
1.
8.
1.
12.
Throughput
lO'mVyr
B'
8 NA
54 NA
60 NA
57 NA
1 0
C1
-7.0
-0.59
-3.24
-0.578
-4.47
TA
3.38
0.09
2.58
0.66
3.61
Emissions,
106kg/yr
Ts
2.12
0.06
1.61
. 0.42
2.27
TN
2.12
0.06
1.61
0.42
2.27
Emission
Reductlon(
10'kg/yr
VTN
0
0
0
0
0
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
t_i 3. Fixed Roof Tanks
.£>
*""" 4. Underground Tanks
5. Aircraft Refueling
TOTAL 10.3 6.48 6.48
Growth rate Is calculated by method other than use of P_,
\j
NA - not applicable due to negative growth
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CORPORATION
Due to the relatively low vapor pressure of naphtha
jet fuel, bulk terminal and station storage of this fuel is assumed
to be in fixed roof tanks. From Figure 4-10, in 1985 bulk facilities
are estimated to handle 5.36 x 106m3 (33.7 x 106bbl) of this jet
fuel which is 3.24 x 106m3 (20.4 x 10s bbl) less than bulk facilities
handled in 1975. Therefore, C1 for fixed roof tanks is -3.24. Since
commercial use of naphtha jet fuel is relatively small, commercial
users normally store naphtha jet fuel in underground tanks. In
1985 commercial usage of naphtha jet fuel is estimated to be 0.992 x
106m3 (6.24 x 106 bbl) which is 0.578 x 106m3 (3.64 x 106bbl) less
than 1975's commercial use. Hence, C1 for underground tanks is
-0.578.
The values of B', the throughput from construction
and modification to replace obsolete equipment, for the loading
and storage operations are calculated form IRS depreciation
guideline data (CO-424). The resultant figures, when added to
the values of C1, are negative. This indicates that the rate of
obsolescence is less than the rate of decline of the naphtha jet
fuel segment.
The baseline year emission factors are based on API
correlations except for the underground storage tank emission
factor which is derived from a study performed by the Los Angeles
County Air Pollution Control District (CH-159). Truck/rail loading,
tanker/barge loading and fixed roof tanks are assumed to employ
vapor collection and recovery systems (90% efficient) as the best
available controls while underground tanks are assumed to use the
vapor balance loading technique.
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' Estimated Emission Reduction
The values of C' for all operations in the naphtha jet
fuel transfer industry segment are negative, which reflects the
projected decline in the use of naphtha jet fuel. In addition,
from an economic viewpoint, obsolete equipment is normally not
replaced when an industry is experiencing a decline. Therefore, no
new sources are estimated to exist in 1985 to which NSPS could be
applied and the calculated emission reduction potential for the
naphtha jet fuel transfer industry is zero. Table 9-6 summarizes
the estimated emission level in 1985.
9.2.4 Aviation Gasoline Transfer Segment
Input Variables
Table 9-7 lists the variables required to execute
Model IV for the aviation gasoline transfer industry segment.
Historical indicated demand data for 1970-75 is extrapolated
to obtain an estimated demand of 1.28 x 106m3 (8.04 x 106 bbl) for
1985. This value is 0.96 x 106m3 (6.04 x 106 bbl) less than demand
in 1975. Thus, C1 for aircraft refueling is -0.96.
Tanker and barge loading of aviation gasoline is
assumed to be 23.370 of demand (as in 1975), implying C1 for
tanker/barge loading is -0.225. From the discussion in Section
4,4.2 and Figure 4-14, truck/rail loading is estimated to be 2.21
x 106m3 (13.9 x 106bbl) less in 1985 than in 1975. C' for truck/rail
loading is therefore -2.21.
The amount of aviation gasoline handled by bulk
stations is assumed to be stored in fixed roof tanks. Bulk
station sales are assumed to be 25.4% of demand based on 1972
Census Bureau data (US-412). Applying this percentage to 1985
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TABLE 9-6
NATIONAL EMISSION REDUCTION BY 1985*
1
M
-P-
1
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Tanks
4 . Underground Tanks
5. Aircraft Refueling
NAPHTHA JET FUEL TRANSFER
Emission Rate With
Best Available System,
Control Technique 106kg/yr(10Jtons/yr)
** 2.12 (2.33)
** 0.06 (0.07)
** 1.61 (1.77)
** 0.42 (0.46)
**-NA 2.27 (2.5)
Emission Rate Under
1975 Controls,
106kg/yr(103tons/yr)
2.12 (2.33)
0.06 (0.07)
1.61 (1.77)
0.42 (0.46)
2.27 (2.5)
Emission Reduction,
10skg/yr(103tons/yr)
0
0
0
0
0
INDUSTRY TOTAL
6.48 (7.14)
6.48 (7.14)
As per Model IV evaluation (10 years)
**
No new sources to which controls can be applied
NA - none available
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TABLE 9-7
Emission Source
1. Truck/Rail Loading
2. Tanker/Barge Loading
3. Fixed Roof Tanks
4. Underground Tanks
5. Aircraft Refueling
TOTALS
*Growch rate is calculated by method other than use of P ,
c
NA - not applicable due to negative growth
SUMMARY OF INPUT/OUTPUT
VARIABLES FOR M3DEL IV
AVIATION GASOLINE TRANSFER
Emission Factor,
kg/106m3 throughput
Es
345,000
115,000
575,000
534,000
574,000
EN
28,700
5,750
28,700
79,500
574,000
Growth Rates,
Deciraal/yr
PB' PC'
0.0312 *
0.0312 *
0.0312 *
0.0312 *
0 *
Throughput,
lO'mVyr
A1
5.16
0.523
0.569
2.24
2.24
B1
NA
NA
NA
NA
0
C1
-2.21
-0.225
-0.244
-0.96
-0.96
TA
1780
60
327
1200
1290
Emissions
103kg/yr
Ts
903
34.3
187
684
735
t
TN
903
34.3
187
684
735
Emission
Reduction,
103kg/yr
T -T1
S 1N
0
0
0
0
0
4660 2543 2543
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demand shows that fixed roof storage throughput decreased 0.244
x 106m3 (1.53 x 106 bbl) from 1975 to 1985, implying C' = -0.244.
Throughput for underground tanks is assumed to be equivalent to
the indicated domestic demand. Therefore, C1 for underground tanks
is -0.96.
The values of B' for the various portions of the
aviation gasoline transfer segment are calculated from IRS
depreciation guidelines data (CO-424). When these values of
B1 are added to the values of C1 the resultant sums are negative
indicating that the rate of obsolescence is less than the rate of
decline of the aviation gasoline segment.
The baseline year emission factors are based on
API correlations except for the underground storage tank emission
factor which is derived from a study performed by the Los Angeles
County Air Pollution Control District (CH-159). Truck/rail loading,
tanker/barge loading and fixed roof tanks are assumed to employ
vapor collection and recovery systems (95% efficient) as the best
available controls while underground tanks are assumed to use the
vapor balance loading technique.
Estimated Emission Reduction
The values of C' for all operations in the aviation
gasoline transfer industry segment are negative, which reflects
the projected decline in the use of aviation gasoline. In addition,
from an economic viewpoint, obsolete equipment is normally not
replaced when an industry is experiencing a decline. Therefore,
no new sources are estimated to exist in 1985 to which NSPS could
be applied and the calculated emission reduction- potential for the
aviation gasoline transfer industry is zero. Table 9-8 summarizes
the estimated emission level in 1985.
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TABLE 9-8
NATIONAL EMISSION REDUCTION BY 1985*
1.
2.
3.
4.
5.
Emission Source
Truck/Rail Loading
Tanker/Barge Loading
Fixed Roof Tanks
Underground Tanks
Aircraft Refueling
AVIATION GASOLINE TRANSFER
Emission Rate With
Best Available System,
Control Technique 103kg/yr(tons/yr)
** 903 (994)
** 34.3 (37.8)
** 187 (206)
** 684 (753)
**-NA 735 (809)
Emission Rate Under
1975 Controls,
103kg/yr(tons/yr)
903 (994)
34.3 (37.8)
187 (206)
684 (753)
735 (809)
Emission Reduction,
103kR/vr(tons/yr)
0
0
0
0
0
INDUSTRY TOTAL
2,543 (2800)
2,543 (2800)
As per Model IV evaluation (10 years)
**
No new sources to which controls can be applied
NA-none available
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CORPORATION
10.0 FUGITIVE EMISSIONS FROM PUMP SEALS AND VALVES
Potentially fugitive emission sources may be the biggest
factor in the amount of hydrocarbons emitted from petroleum trans-
fer operations. Although fugitive emissions from individual sources
may be very small the total losses may be significant due to the
prevalence of fugitive emission sources.
In the petroleum transfer industry, fugitive sources
include pump seals and pipeline valves. The actual emissions
from these sources in the crude oil and aviation fuels transfer
segments cannot be accurately calculated due to the unknown num-
ber of pumps and valves existing in the transfer segments. For this
reason, fugitive emissions were not included in the Model IV
calculations. In this section some estimates and comparisons
are made in order to provide some indication of what the importance
of fugitive emissions may be relative to the other emissions from
the transfer operations.
From Section 6.2, pump seal and valve emission factors
applicable to the transfer industry are
Emission Factor, kg(lb)/day-seal or valve
Source Aviation Fuels Crude Oil
Centrifugal pumps with packed seals 0.18 (0.4) 2.7 (5.9)
Centrifugal pumps with mechanical seals 0.14 (0.3) 0.27 (0.6)
Reciprocal pumps with packed seals 0.05 (0.1) 1.8 (4.0)
Pipeline valves 0.02 (0.05) 0.02 (0.05)
To illustrate a conservative estimate of fugitive
emissions, the emission factor for centrifugal pumps with mechani-
cal seals is used. The assumption that each pump has six valves
associated with it is also made. Therefore, each pump unit in
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the crude oil segment will emit 0.39 kg (0,86 lb)/day and each
pump unit in the aviation fuels segments will emit 0.26 kg (0.57
lb)/day. Table 10-1 lists the 1975 total emissions from each of
the transfer industry segments under consideration in this study
as calculated per Model IV.
A calculation is made for each transfer segment to
determine the number of pump units that must be present in order
to have fugitive emissions equal the total emissions from other
sources. The results of these calculations are as follows:
Transfer Segment Number of Pump Units
Crude Oil 934,000 (86,000*)
Kerosine Jet Fuel 4,000
Naphtha Jet Fuel 109,000
Aviation Gasoline 49,000
''The number in parenthesis is based on excluding production pump
seal and valve emissions from the total crude emissions.
The above data indicate that if approximately 4,000
pump units exist in the kerosine jet fuel transfer segment, then
fugitive emissions are .equal to all other emissions in the kerosine
jet fuel segment in 1975.
Approximately 49,000 pump units are required in the
aviation gasoline transfer segment to make fugitive emissions
equal to all other aviation gasoline transfer emissions in 1975.
This number of pump units is not an unreasonable estimate of
what actually exists and may easily be a low estimate.
Almost 110,000 pump units must be present in the naphtha
jet fuel transfer segment for fugitive emissions to equal all
other emissions in 1975. Since this number is not an unreasonable
estimate of the number of pump units present, fugitive leaks can
be a very, significant emission source.
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TABLE 10-1
HYDROCARBON EMISSIONS FROM CRUDE OIL AND
AVIATION FUELS TRANSFER IN 1975
Industry Segment Emissions, 106kg (103tons)
Crude Oil* 133 (146)
Kerosine Jet Fuel 0.411 (0.453)
Naphtha Jet Fuel 10.3 (11.3)
Aviation Gasoline 4.66 (5.13)
*If production pump seal and valve emissions are excluded, the
crude oil segment's emissions are 12.3 x 106kg (13.5 x 103tons)
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The potential importance of fugitive emissions is also
emphasized by the fact that of 133 x 106 kg/yr of crude oil
transfer related emissions that occurred in 1975, an estimated
120.7 x 106 kg/yr are from production pump seal and valve leaks.
If these losses are omitted from the emission total only 86,000
pump units would be required to equal all the other hydrocarbon
emissions resulting from crude oil transfer.
From these results, it is evident that in regard to
hydrocarbon emissions from the petroleum transfer industry, the
area of fugitive losses requires further study. A rigorous in-
vestigation of fugitive emissions is particularly required in
order to accurately determine the impact of fugitive losses
compared to other emissions and to assess the degree to which these
losses may be controlled.
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APPENDIX A
FLOATING ROOF STANDING STORAGE
AND FIXED ROOF TANK BREATHING LOSSES
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1.0 FLOATING ROOF AND FIXED ROOF BREATHING LOSSES
While floating-roof tank standing storage losses and
fixed-roof tank breathing losses are not a direct result of the
transfer of petroleum liquids, these losses would not necessarily
occur if the transfer industry were not present. In order to pro-
vide some indication of what the importance of these storage losses
may be to the other emissions from the petroleum transfer industry,
this appendix contains an estimate of standing storage and breath-
ing losses.
Storage Locations
Estimates are not made for crude oil storage tanks since
it is assumed that these tanks are large enough (<40,000 gals) to
be regulated by existing NSPS. The small field storage tanks are
not regulated, but their breathing losses are assumed to be
included in the emission factor used in calculating oil field
storage emissions. Fixed-roof tanks are used to store kerosine
and naphtha jet fuels at bulk terminals and bulk stations. However,
only the amounts of kerosine and naphtha jet fuels delivered from
these facilities by tank trucks are assumed to be stored in fixed-
roof tanks that exhibit breathing losses. Although jet fuels
delivered through dedicated pipelines enter fixed roof "dropout"
tanks for quality inspection prior to entering the dedicated
pipeline, the residence time in these "dropout" tanks is assumed
to be short enough to make breathing losses negligible. All
military storage of naphtha jet fuel and all major airport storage
of kerosine jet fuel is assumed to be in floating-roof tanks.
Large storage tanks containing aviation gasoline are regulated by
existing federal NSPS. Therefore, only breathing losses from
small fixed-roof, tanks (<40,000 gals) are estimated. These small
tanks are found at bulk stations.
A-l
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Method of Emissions Estimate
Floating-roof standing storage and fixed-roof breathing
losses can be estimated from API correlations (AM-107, AM-087) .
These correlations can be expressed as :
i4P7_p °-7(D)1-5(Vw)°-7(Kt;)(Ks)(K)(Kc) (A-l)
p
=(0. 000221) (M)I-68(D)1-73(H)0>51(AT)°-5(Fp)(C)(Kc)
rT2r^Ipl0-
(A-2)
where
L = Floating-roof standing-storage loss (Ib/day)
O
1» = Fixed roof breathing loss (Ib/day)
M = Molecular weight of vapor in storage tank (Ib/lb-mole)
P = True vapor pressure at bulk liquid conditions (psia)
D = Tank diameter (ft)
V = Average wind velocity (Mi/hr)
vv
K = Tank type factor
K = Seal factor
o
K = Paint factor
P
K = Crude oil factor
c
H = Average vapor space height (ft)
AT = Average daily ambient temperature change (°F)
F = Paint factor
P
C = Adjustment factor for small .diameter tanks
Assumptions
In order to use Equations A-l and A-2, the above variables
must be defined. The values of M and P are found in Table 5-1 of
the main text. Tank diameters are assumed to be 90 ft (50,000 bbl
tanks) for kerosine and naphtha jet fuel tanks and 19 ft (40,000
gal tanks) for aviation gasoline tanks .
A-2
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Since the condition of a storage tank can significantly
affect the tank's losses, two values of the following variables
are shown in order to calculate worst and best case emission
levels. These factors are taken from API bulletins (AM-107,
AM-087).
Variable Best Case Worst Case
Kt 0,045 0.14
K 1.0 1.33
s
K 0.9 1.0
F 1.0 1.58
Additionally, AT is assumed to be 15°F and V to be 10 mi/hr.
w/
For jet fuel storage tanks H is assumed to be 25 ft and C is
1.0, while H is assumed to be 9 ft for aviation gasoline storage
tanks and C is 0.83.
The amount of storage that a facility has must also be
known in order to calculate breathing and standing storage losses.
Therefore, storage capacity equivalent to thirty days' throughput
is assumed for all storage tanks except for floating-roof tanks
at airports. Since these airport tanks receive kerosine jet fuel
by dedicated pipelines and hence have an essentially uninterrupt-
able source of supply, they do not need as much storage capacity.
Thus, the equivalent of five days' throughput is used for airport
floating-roof storage capacity (DE-202).
A-3
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Results
The results of the emission calculations for standing
storage and breathing losses are summarized in Table A-l. If
these emissions are added to the baseline year controls emission
levels in 1985, as estimated in Section 9.0, the standing storage
and breathing losses would represent the following percent of
total emissions.
Best Case Worst Case
Kerosine Jet Fuel 15% 257,
Naphtha Jet Fuel 12% 25%
Aviation Gasoline 10% 14%
A-4
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TABLE A-l
ESTIMATED STANDING STORAGE AND BREATHING LOSSES*
Liquid Stored
Type Tank
Estimated Storage
Capacity, 10 bbl
Emission Factor,
Ib/day- 103bbl capacity
Best Case Worst Case
Emissions,
103Kg/yr (tons/yr)
Best Case Worst Case
Kerosine Jet Fuel Floating
Roof
Kerosine Jet Fuel Fixed Roof
3740
3030
0.0225
0.174
0.103
0.274
14 ( 15) 64 ( 70)
87 ( 96) 138 ( 152)
Naphtha Jet Fuel Floating
Roof
Naphtha Jet Fuel Fixed Roof
3430
1010
0.499
3.48
2.29
5.50
284 (312) 1300 (1430)
582 (641) 917 (1010)
Aviation Gasoline Fixed Roof
168
9.91
14.9
276 (304) 415 ( 457)
* Based on projected transfer industry size in 1985
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CORPORATION
APPENDIX B
MODEL IV CALCULATIONS
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Computation Sheet for EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of A"
Prepared By: William C. Thomas
Crude Oil:
Tables 4-4 and 4-5 of the main text give the following
information on crude oil:
1975 Domestic Production - 485xl06m3(3,052xl06bbl)
1975 Truck/Rail Loading - 12.8xl06m3(80,5xl06bbl)
1975 Tanker/Barge Loading - 47.8xl05m3(301xl06bbl)
1975 Pipeline Transport - 489xl06m3(3,078xl06bbl)
Pipeline transport emissions occur as leaks from pump seals and
valves. These emissions cannot be accurately quantified, but are
discussed in Section 10.0. Storage of crude oil after leaving the,
oil field is assumed to be in tanks >152,000 liters (40,000 gal).
Since federal NSPS already regulate this storage, emissions from
these sources are not included in this study.
From the above data, the A' factors are:
A' = 485
prod
A'r =12.8
UT/R
A' =47.8
B-l
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Computation Sheet for EPA Contract No. 68-02-1319, Task 55
/
Subject: Calculation of A" (cont.)
Prepared By: William C. Thomas
Kerosine Jet Fuel:
Table 4-9 and Figure 4-4 of the main text give the
following information for kerosine jet fuel:
1975 imports - 6.lx!06m3(38xl06bbl)
1975 indicated domestic demand - 45.9xl06m3(289x 106bbl)
1975 truck/rail loading - 27.Ixl06m3(170xl06bbl)
1975 tanker/barge loading - 6.2xl06m3(39xl06bbl)
1975 nonairport pipeline transport - 35.9x106m3(226x106bbl)
1975 airport pipeline transport - 28.9xl06m3(182xl06bbl)
Therefore,
A' = 45.9 - A'
KDemand
A' = 27.1
KT/R
A' = 6.2
KT/B
From Figure 4-4 of the main text, 42.4xl06m3(267xl06bbl) is
handled by bulk facilities. This quantity is stored in fixed roof
tanks. The amount transported from consumer storage to end users
by truck is assumed to be stored in underground tanks while the
amount moved by pipeline is stored in floating roof tanks
(EL-104.VA-129). For kerosine jet fuel, naphtha jet fuel and
B-2
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Computation Sheet for EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of A" (cont.)
Prepared By: William C. Thomas
Kerosine Jet Fuel (cont.)
aviation gasoline, standing storage losses from floating roof
tanks and breathing losses from fixed roof tanks are not included
in the emission calculations but are discussed in Appendix A.
Thus,
A' = 42.4
*TRT
A' - 17.0
Naphtha Jet Fuel:
Table 4-12 and Figure 4-7 of the main text give the
following information for naphtha jet fuel:
1975 Imports - 1.6xl06m3(10xl06bbl)
1975 Indicated Domestic Demand - 12.1x106m3(76.3x106bbl)
1975 Tanker/Barge Loading - 1.54xl06m3(9.7xl06bbl)
1975 Pipeline Transport - 5.41xl06m3(34.0xl06bbl)
1975 Truck/Rail Loading - 18.8xl06m3(118xl06bbl)
Thus ,
A' = 12 1 = A'
N ' N
1NDemand INAR
A' =18.8
NT/R
A\T = 1.54
B-3
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CORPORATION
Computation Sheet for EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of A" (cont.)
Prepared By: William C. Thomas
Naphtha Jet Fuel (cont.)
All naphtha jet fuel handled by bulk facilities is assumed to be
stored in fixed roof tanks. From Figure 4-7 of the main text,
bulk facility sales in 1975 were 8.60xl06m3(54.Ixl06bbl).
Thus,
A' =8.60
1NFRT
In 1974 military uses accounted for 87% of the total
domestic demand for naphtha jet fuel (US-419 Table 27). It is
assumed that all military storage is in floating roof tanks while
commercial storage is in underground tanks. Assuming that the
percentage breakdown in 1974 is applicable to 1975, then
A' = 0.13xA- = 1.57
1NUT ^Demand
Aviation Gasoline:
Table 4-14 and Figure 4-11 in the main text give the
following information on aviation gasoline:
1975 Indicated Domestic Demand - 2.24xl06m3(14.Ixl06bbl)
1975 Tanker/Barge Loading - 0.523xl06m3(3.29xl06bbl)
1975 Pipeline Transport - 0.610xl06m3(3.84xl06bbl)
1975 Truck/Rail Loading - 5.16xl06m3(32.4xl06bbl)
B-4
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of A"(cont.) _
Prepared By: William C. Thomas _ _ _
Aviation Gasoline (cont.)
Thus,
A' 2.24 = A'
^Demand °AR
A' = 5.16
A' = 0.523
GT/B
Storage at bulk terminals is assumed to be in tanks large enough
in capacity to fall under federal NSPS. Bulk station storage is
assumed to be small fixed roof tanks, while consumer storage is
underground tanks. Using the data from Figure 4-11 of the main
text gives :
A' = 0.569
A'r = 2.24
GUT
B-5
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C"
Prepared By: William C. Thomas
Crude Oil:
Based on a projection from (ST-381) domestic crude oil
production is assumed to be 679xl06m3(4,270xl06bbl) in 1985.
Thus,
C' = 679-485 = 194
prod
Existing production in 1975 is assumed to decline at the rate
experienced over the 1971-75 period. From Table 4-4 of the main
text,
1971 production = 549xl06m3(3,360x106bbl)
1975 production = 485xl06m3(3,050xl06bbl)
Thus,
B' - A'
prod Cprod L - -prod'
= 485 1
= 485(0.262)
B' = 124
prod
B-6
H
J
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C" (cont.)
Prepared By: William C. Thomas
Crude Oil (cont.)
Of the 318x106m3(2,000x106bbl) of new crude production
in 1985, 116x106m3(730x106bbl) is assumed to be Alaskan crude
transported by tanker from Alaska's south shore to the West Coast.
The other 202xl06m3(1,270xl06bbl) of production is assumed to be
transported to refineries via pipelines, tankers/barges and trucks/
rails in the same percentages exhibited over the 1966-75 time period.
Figure 4-2 in the main text shows that in 1975 87.570 of domestic
crude production was transported by pipeline, 9.970 by tanker/barge
and 2.6% by truck/rail. Thus, the values of B' and C' for tanker/
barge loading and truck/rail loading are calculated as follows:
Old production in 1985 = 361xl06m3(2,270xl06bbl)
T/R loading - 0.026x361 = 9.39
T/B loading - 0.099x361 =35.7
New production in 1985 = 318-116 = 202x106m3(1,270xl06bbl)
T/R loading - 0.026x202 =5.25
T/B loading - 0.099x202 =20.0
1975 T/R loading =12.8
1975 T/B loading =47.8
B-7
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C" (cont.)
Prepared By. William C. Thomas
Crude Oil (cont.)
B' = 12.8-9.39 = 3.41
LT/R
C' = 9.39+5.25-12.8 =1.84
T/R
C' = 35.7+20.0+116-47.8 =124
CT/B
Since truck/rail loading facilities are located at the oil fields,
their useful life time is normally greater than the productive
lifetime of the oil reservoir. Therefore, no replacement of T/R
loading facilities due to obsolescence occurs. However, tanker/
barge loading occurs at marine terminals where equipment replace-
ment does occur. From (CO-424 p. 415) the IRS depreciation guide-
line for petroleum marketing equipment is 16 yrs,@ twice this value
P'» - 1 » 0.0312
CT/B 2xT6-
B'r = 47.8x10x0.0312 = 14.9
LT/B
Kerosine Jet Fuel:
From the discussion in Section 4.2.2 and Figure 4-5
of the main text, the simple growth rate of indicated demand for
kerosine jet fuel is
B-8
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Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C' (cont.)
William C. Thomas
Prepared By:
Kerosine Jet Fuel (cont.)
P r- - 48.9-40.3 = 0.0468 = P r.
KDemand 4x45'9 KAR
C' - 45.9x10x0.0468 » 21.5 = C\
^Demand AR
B'K =0 since no controls exist for aircraft refueling
emissions
The percent of indicated demand transported by tanker/barge has
shown a negative growth from 1966 to 1975. Using a compound growth
correlation gives
Ryr- =/13.5\ -1 = -0.0454
'<>« y I oA d I
KT/B \20-5/
%C'R =13.5 Kl-0.0454)lo-i]
= -5.02
Therefore, total % of demand by T/B is 13.5-5.02 = 8.5%
C' = (45.9+21.5)xO.085-6.2 = -0.471
B-9
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C' (cont.) _
Prepared By: William C. Thomas _ _
Kerosine Jet Fuel (cont.)
Emission control equipment on T/B loading would be installed at
the marine terminal. From (CO-424 p. 415) the IRS depreciation
guideline for petroleum marketing equipment is 16 yrs.
@ twice this value P ' = _ L_ = 0.0312
Therefore,
B' = 6.2x10x0.0312 =1.9
From the discussion in Section 4.2.2 and Figure 4-6 of the main
text, the amount of kerosine jet fuel loaded into trucks/rails in
1985 is 33.3x106m3(209x106bbl). Thus
C'v = 33.3-27.1 - 6.2
*T/R
From (CO-424 p. 415) the IRS depreciation guideline for
petroleum marketing equipment is 16 yrs.
@ twice this value
P,. = 1 = 0.0312
2xT6~
B-10
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Sub j act : Calculation of Bx and C" (cont.) _
Prepared By: William C. Thomas _
Kerosine Jet Fuel (cont.)
Therefore,
B' - 27.1x10x0.0312 = 8.5
From Figure 4-6 of the main text, bulk facilities are estimated
to handle 63. 9xl06m3 (402xl06bbl) in 1985. This is assumed to be
stored in fixed roof tanks. 23. 9x10 6m3 (150x10 6bbl) is shown to
be transported from consumer storage to end users by trucks. This
amount is assumed to be stored in underground tanks. Thus
= 63.9-42.4 = 21.5
C'K = 23.9-17.0 = 6.9
From (CO-424 p. 415) the IRS depreciation guideline for petroleum
marketing equipment is 16 yrs.
@ twice this value
P ' = I = 0.0312
KFRT 2x16
P ' = 0.0312
JT
B-ll
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C" (cont.)
Prepared By: William C. Thomas
Kerosine Jet Fuel (cont.)
Therefore,
B\r = 42.4x10x0.0312 = 13.2
KFRT . . .
B' = 17.0x10x0.0312 =5.30
KUT
Naphtha Jet Fuel
From the discussion in Section 4.3.2 and Figure 4-8, the
indicated demand for naphtha jet fuel in 1985 is 7.63xl06in3
(48.0xl06 bbl).. This is calculated by performing a least squares
fit to historical demand data and using the resultant equation to
calculate the demand in 1985. Thus,
C' = 7.63-12.1 = -4.47 = C'
"Demand AR
B'TT = 0 since no controls exist for aircraft refueling
AR
emissions
Figure 4-9 of the main text shows historical pipeline and tanker/
barge transport data as a percent of indicated demand. Since there
is no discernable trend in these data, 1975's percentage are used
for 1985.
B-12
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RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319.. Task 55
Subject:: _ Calculation of B" and C' (cont.) _
Prepared By: William C. Thomas _ _
Naphtha Jet Fuel (cont.)
Thus ,
% pipeline transport = 44.6%
% tanker /barge transport =12.4%
C'..' = 7.63x0.124-1.54 = -0.59
NT/B
From Figure 4-10 of the main text, truck/rail loading
in 1985 is 11. 8x10 6m3 (74. 6x10 6bbl) . Therefore
C' = 11.8-13.8 = -7.0
From (CO-424 p. 415) the IRS depreciation guideline for petroleum
marketing equipment is 16 yrs .
(§ twice this value,
P -? - _ L. = 0-0312
X/B ^
B ' = 1.54x10x0.0312 = 0.480
NT/B
B-13
-------
R ADBAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B' and C' (cont.)
Prepared By: William C. Thomas _
Naphtha Jet Fuel (cont.)
P «' = _ 1 = 0.0312
X/R ***
B\T = 18.8x10x0.0312 = 5.86
NT/R
In a declining industry, obsolete equipment is normally
not replaced. Since
B' + C' = 0.48+(0.59) = -0.11 < 0
NT/B LT/B
and B, - + C\T = 5.86+(-7.0) = -1.14 < 0
NSPS will have no effect on. the T/R and T/B loading aspects of the
naphtha jet fuel transfer industry.
From Figure 4-10 of the main text, bulk facilities will handle
5. 36x10 6m3 (33. 7x10 6 bbl) of naphtha jet fuel in 1985. Assuming
this amount is stored in fixed roof tanks,
C' = 5.36-8.60 = -3.24
Military use of naphtha jet fuel is assumed to be the same percent
of indicated demand as was assumed for 1975, 87%. Thus, if the
remaining 1370 of commercial use is stored in underground tanks.
B-14
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C' (cont.)
Prepared By: William C. Thomas ,__.
Naphtha Jet Fuel fcont.)
C' - 0.13x7.63-1.57 = -0.578
UT
Since the demand for naphtha jet fuel is declining, if the rate
at which tanks become obsolete is not greater than the decline
in demand then NSPS will have no effect on storage emissions.
From (CO-424 p. 415) the IRS depreciation guideline for petroleum
marketing equipment is 16 yrs.
@ twice this value
P.. = 1 = 0.0312
NFRT 2xl6
B\T =8.60x10x0.0312 = 2.68
INFRT
P . = 1 = 0.0312
BNUT IxTF
B' = 1.57x10x0.0312 = 0.490
B-15
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B" and C" (cont.)
Prepared By: William C. Thomas
Naphtha Jet Fuel (cont.)
Since
B' + C'M = 2.68+(-3.24) = -0.56 < 0
1NFRT
r + C'M * 0.490+(-0.578) = -0.088 < 0
UT UT
NSPS will have no effect on storage emissions.
Aviation Gasoline:
From the discussion of Section 4.4.2 and Figure 4-12 of
the main text, the indicated domestic demand for aviation gasoline
is estimated to be 1.28x10frm3(8.04xl06bbl) in 1985. This value
is obtained by curve fitting the 1970-75 demand data and extra-
polating the result to 1985. Thus
C'r =1.28-2.24 = -0.96 = C'
^Demand ^AR
B',, = 0 since no controls exist for aircraft
AR
refueling emissions
B-16
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319 ,. Task 55
Subject: Calculation of B" and C' (cont.) _ _
Prepared By: William C. Thomas _ .
Aviation Gasoline (cont.):
In 1975, tanker/barge loading was 23.370 of demand and
pipeline transport was 27.270 of demand. Using these same per-
centages in 1985 gives
C' = 0.233x1.28-0.523 = -0.225
From Figure 4-14 of the main text, the amount of aviation gaso-
line transported by truck/rail is 2. 95xl06m3 (18 . 6xl06bbl) . Thus,
C' = 2.95-5.16 = -2.21
Storage of aviation gasoline at bulk terminals is assumed to be
in tanks large enough in capacity to be regulated by existing
federal NSPS. Bulk station storage is assumed to be small
fixed roof tanks while consumer storage is underground tanks.
Using the data from Figure 4-14 of the main text,
C' = 0.325-0/569 = -0.244
GFRT
C' = 1.28-2.24 = -0.96
GUT
B-17
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of B' and C' (cont.)
Prepared By: William C. Thomas
Aviation Gasoline (cont.)
From (CO-424 p. 415) the IRS depreciation guideline for petroleum
marketing equipment is 16 yrs.
@ twice this value
P , - P , » P = P , = _L = 0.0312
° r "" r " r o-,i il
GT/R GFRT GUT 2xl6
Thus,
B%, = 0.523x10x0.0312 = 0.163
= 5.16x10.0.0312 = 1.61
B' = 0.569x10x0.0312 = 0.178
GFRT
B' = 2.24x10x0.0312 = 0.699
GUT
In a declining industry, obsolete equipment is normally not
replaced if the rate of decline is greater than the rate at
which the equipment becomes obsolete. Thus, since for T/B and
T/R loading and FRT and UT storage the values of B'G+C' are
< 0, NSPS will have no effect on the emission levels from these
operations.
B-18
-------
RADIAM
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319,. Task 55
Subject: Calculation of Eg
Prepared By: William C. Thomas
Crude Oil Production:
From (MS-001) the following emission factors for crude
oil production facilities are used:
Storage Tanks - 11 Kg/103m3 production
Pump Seals - 214 Kg/103m3 production
Pipeline Valves - 34 Kg/103m3 production
Thus, the emission factor for production is 259 Kg/103m3 production
E0 = 259,000
C
prod
Loading Operations:
Emission factors .for truck/rail and'tanker/barge loading
and aircraft refueling can be calculated from the following equation:
LT - 12.46 SPM
L T
This equation is based on emission data reported in (AM-085).
For T/R loading S = 0.6, for T/B loading S = 0.2 and for aircraft
refueling S = 1.0. Table 5-4 of the main text shows the values
of S, P, M and T used in the emission factor calculation. The
results of these calculation give:
B-19
-------
RAB23AN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject:
Calculation of Eq(cont.)
Prepared By: William C. Thomas
Loading Operations (cont.)
Crude Oil:
241,000 E
Kerosine Jet Fuel:
= 80,400
1,900 Eg = 635 Eg
K
3,170
AR
.Naphtha Jet Fuel:
Ec = 180,000 EQ
M
NT/R. .
59,700 E,, = 298,000
N
AR
Aviation Gasoline:
E0 = 345,000 E
On
GT/R
= 115,000 Ec = 574,000
O
Storage Facilities :
Emission factors for fixed roof working losses can be
calculated from the following equation:
= 0.024xMxPxKNxKc
B-20
-------
RADBAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of ES (cont.)
Prepared By: William C. Thomas
Storage Facilities (cont);
where M = vapor molecular weight
P = liquid vapor pressure at storage temperatures, psia
IxN = 1.0 for tank turnovers < 36/yr.
KC = 0.75 for crude oil storage; KC = 1.00 for all other
liquids
The above equation was derived from information presented in (AM-039^
Table 5-5 of the main text lists the values of 1^ calculated for the
storage of aviation fuels.
Emission factors for underground tank filling losses can be cal-
culated from data reported in (CH-159) for motor gasoline storage.
This report gives emissions as:
Type of Fill Emissions Kg/m3 .throughput
Splash 1.38
Submerged 0.874
Vapor Balance - Open Vent 0.0958
Vapor Balance - Closed Vent 0.0
By dividing these factors by the vapor molecular weight and vapor
pressure of gasoline (66 and 5.2 psia) and then multiplying by
the dispensed liquid vapor molecular weight and vapor pressure,
the appropriate new emission factors can be obtained.
B-21
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Eg (cont.)
Prepared By: William C. Thomas
Storage Facilities (cont.)':
Underground tank withdrawal losses can be estimated by use of an
emission factor calculated from the following equation:
L =/ P \x P x M x
V1"1/
!s
K
In this equation:
P = liquid vapor pressure in psia divided by 14.7
M = vapor molecular weight
K = conversion factor to- convert L to T7T3~^T v - o at
1UJ gal, K. = L. oj
Fn - experimentally confirmed diffusion factor
to account for subsaturation of exhaled vapors
FD =1/6
L = withdrawal loss, lb/103 gal dispensed
Table 5-5 of the main text lists the emission factors calculated
for the three types of storage losses. These factors are summarized
as follows:
B-22
-------
RADIAN
CORPORATION
Computation Sheet for EPA Contract No. 68-02-1319, Task 55
Subiect- Calculations of Eg (cont.)
Prepared by: William C. Thomas
Storage. Facilities (cont.):
Kerosine Jet Fuel:
Es = 3,170 Eg = 4,440 Eg = neg Eg = 4,440
KFRT KUTF KUTW KUT
Naphtha Jet Fuel:
Ec - 300,000 E0 - 418,000 E0 = 4,840 Ec = 423,000
bN bN N K
INFRT UTF UTW UT
Aviation Gasoline:
Ec = 575,000 E0 = 510,000 E0 - 23,600 E0 = 534,000
Of, b,-, Op Op
°UTF UTW ^UT
B-23
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of EN
Prepared By: William C. Thomas
Vapor collection and vapor recovery via a refrigeration
type system is used in this study as the best available control
technique for fixed roof working losses and truck/rail and tanker/
barge loading losses. Based on the information presented in
Section 6.0 of the main text, the following emission reductions
are achievable with vapor collection and recovery.
Kerosine Jet Fuel Vapors - 100 wt7»
Naphtha Jet Fuel Vapors - 90 wt%
Crude Oil Vapors - 95 wt%
Aviation Gasoline Vapors - 95 wt7o
These factors can be applied to the appropriate Eg to obtain £.
For truck/rail loading of aviation gasoline the S factor for
calculating the uncontrolled emission factor is assumed to b'e
1.0 instead of 0.6 to account for the fact that these tank trucks
and rail cars will deliver to tanks that practice the vapor
balance method _of loading and hence return with a saturated air-
Based on the preceding discussion, the following summarizes the
calculated E ' s
Crude Oil:
EN = Eg x 0.05 = 12,000 E = EQ x 0.05 = 4,020
r r "r> &n
^T/R LT/R CT/B CT/B
Eq = 214,000+34,000+0.05x11,000 = 249,000
C
prod
B-24
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of EN _ ___
Prepared By: William C. Thomas _ _ _
Kerosine Jet Fuel:
EM =EC x 0.0 = 0.0 EM = 0.0 x E_ =0.0
Tf V
^T/R ^T/B
EM = 0.0 x Ec =0.0
Naphtha Jet Fuel:
EM = Ec x 0.1 = 18,000 EM = Ec x 0.1 = 5,970
\T M TVT TJ
NT/R NT/R NT/B NT/B
E,, - E0 x 0.1 = 30,000
N N
1 FRT 1NFRT
Aviation Gasoline:
EN = Eg x 0.05 x ^ = 28,700 EN = Eg x 0.05 = 5,750
GT/R GT/R ' GT/B GT/B
EM = Ec x 0.05 = 28,700
B-25
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject; Calculation of.E^ (cont.) _
Prepared By: William C. Thomas _
From (CH-159) the underground tank filling loss for motor gasoline
is 0.0958 Kg/m3 throughput. By ratioing vapor molecular weights
and vapor pressures in the same manner used to calculate E<,'s,
the following values of EN are derived:
Kerosine Jet Fuel:
E = 310 E -Es - negligible E = 310
Naphtha Jet Fuel:
EM - 29,000 EM = E- = 4,840 EM = 33,800
\t vr W M
NUTF NUTW UTW WUT
Aviation Gasoline:
EN = 55,900 EN = ES = 23,600 EN = 79,500
GUTF GUTW GUTW GUT
For aircraft refueling emissions, no practical means of control
is available. Therefore,
EN = E = 3,170 EN = Eq = 298,000
KAR KAR NAR NAR
= Eg = 574,000
3AR GAR
B-26
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN
Prepared By: William C. Thomas
The following table summarizes the factors developed in the
preceding pages.
Emission Source
Crude Oil
Production
T/R Loading
T/B Loading
A',
106
485
12
47
m3
.8
.8
B',
106ffi3
124
3.41
14.9
cr,
106m3
194
1.84
124
Es
Kg/106m3
259,000
241,000
80,400
EN,
Kg/106m3
249,000
12,000
4,020
Kerosine Jet Fuel
T/R Loading 27.1 8.5 6.2 1,900 0.0
T/B Loading 6.2 1.9 -0.471 635 0.0
' Fixed Roof Tanks 42.4 13.2 21.5 3,170 0.0
Underground Tanks 17.0 5.30 6.9 4,440 .310
Aircraft Refueling 45.9 0 21.5 3,170 3,170
Naphtha Jet Fuel
T/R Loading 18.8 NA -7.0 180,000 18,000
T/B Loading 1.54 NA -0.59 59,700 5,970
Fixed Roof Tanks 8.60 NA -3.24 300,000 30,000
Underground Tanks 1.57 NA -0.578 423,000 33,800
Aircraft Refueling 12.1 0 -4.47 298,000 298,000
B-27
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Emission Source A', B', C', Eg EN
106m3 106m3 106m3 Kg/106m3 Kg/106m3
Aviation Gasoline
T/R Loading 5.16 NA -2.21 345,000 28,700
T/B Loading 0.523 NA -0.225 115,000 5,750
Fixed Roof Tanks 0.569 NA -0.244 575,000 28,700
Underground Tanks 2.24 NA -0.96 534,000 79,500
Aircraft Refueling 2.24 0 -0.96 574,000 574,000
The general formula, derived in Section 9.1 of the main text, for
Tg-T., is given as follows:
VTN - 'W (B'+ c'>
However, the use of the formulas
TS = Eg (A'+ C') and
TN = Eg (A--B')+EN(B-+C-)
will give a more informative analysis of the emission reduction
potential of NSPS by presenting what the magnitude of emissions
are in 1985.
B-28
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subjecti Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Crude Oil;
Tc = 259,000x(485+194)
C
prod
Tc » 176xl06Kg
C
prod
TM = 259,OOOx(485-124)+249,000(124+194)
C
prod
TM = 173xl06Kg
C
prod
T-. - TT, = (176-173)xl06
C C
prod prod
- 3x106Kg Crude Oil Production
TS = 241,000(12.8+1.84)
CT/R
Tc = 3.53xl06Kg
TM = 241,000(12.8-3.41)+12,000(3.41+1.84)
B-29
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Crude Oil (cont.);
TN = 2.33xl06Kg
CT/R
CT/R CT/R
(3.53-2.33)xl06Kg
= 1.20x106Kg Truck/rail loading of crude
Ts = 80,400x(47.8+124)
r«, = 13.8xl06Kg
c
LT/B
T = 80,400(47.8-14.9)+4,020(14.9+124)
TN = 3.20x106Kg
= (13.8-3.2)xl06
= 10.6xl06Kg Tanker/barge loading of
crude
B-30
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tq-TN (cont.) _
Prepared By: William C. Thomas _
Kerosine Jet
= 1,900(27.1+6.2)
KT/R
- 63.3xl03Kg
KT/R
T. = 1,900(27. 1-8. 5)+0. 0(8. 5+6. 2)
NTT
KT/R
= 35.3xl03Kg
= (63.3-35.3)xl0
28.0xl03Kg Truck/rail loading of
kerosine jet fuel
Ts = 635(6.2-0.471)
KT/B
T = 3.6xl03Kg
KT/B
= 635(6.2-1.9)+0.0(1.43+0)
KT/B
B-31
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Calculation of Tc-TM(cont.)
Subject:
Prepared By: William C. Thomas
Kerosine Jet Fuel (cont.):
= 2.7xl03Kg
'B
Tq - TM = (3.6-2.7)xl03
«Jtr IN-,,.
*T/B
= 0.9xl03Kg Tanker/barge loading of
kerosine jet fuel
= 3,170(42.4+21.5)
TS = 203x103Kg
KFRT
TN = 3,170(42.4-13.2)+0.0(13.2+21.5)
KFRT
= 93x103Kg
= (203-93)xl03
= 110x10 3Kg Fixed Roof Tanks Working
Losses
KFRT
B-32
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Ts~TN(cont.)
William C. Thomas
Prepared By:
Kerosine Jet Fuel (cont.):
Ts = 4,440(17.0+6.9)
KUT
Tc = 106x1O3Kg
"
TN = 4,440(17.0-5.3)+310(5.30+6.9)
KUT
T = 55.7xl03Kg
, - TN = (106-55.7)xl03
KUT KUT
= 50.3xl03Kg Undergroiond Storage Tank
Losses
B-33
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319. Task 55
Subject: Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Kerosine Jet Fuel (cont.):
Tg <= 3,170(45.9+21.5)
KAR
Tc = 214x103Kg
KAR
TM = 3,170(45.9-0)+3,170(0+21.5)
N-lf
KAR
TM = 214xl03Kg
v
KAR
Tc - TM = 214-214
^v "v
KAR KAR
= 0 Kg Aircraft refueling
Naphtha Jet Fuel:
The naphtha jet fuel transfer industry is projected to
experience a negative growth. Model IV's calculational framework
is not suited to accurately express Tg and TN when an industry
is declining. Therefore the following equations are used to
calculate TS and TN.
B-34
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN (cont.) _
Prepared By: William C. Thomas _
Naphtha Jet Fuel (cont.):
TN = Tg = ES(A'+O where C" < 0
The above equation is valid only when C' < 0 and |C'|-B' > 0
TM = TQ = 180,000(18.8-7.0)
1ST 1ST
iNT/R 1NT/R
= 2.12xl06Kg
TS - TN =0 truck/rail loading of naphtha jet
NT/R NT/R fuel
TM = TQ = 59,700(1.54-0.59)
= 56.7xl03Kg
TQ - TJJ =0 tanker /barge loading of naphtha jet
NT/B NT/B fuel
TM - TQ = 300,000(8.60-3.24)
N N
1NFRT INFRT
= 1.61xl06Kg
T<, - TM =0 Fixed roof storage tank working
N N
WFRT 1NFRT losses
B-35
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN (cont.) _
Prepared By: William C. Thomas _
Naphtha Jet Fuel (cont.):
TM = T0 - 423,000(1.57-0.578)
N N
WUT LNyT
= 420x10 3Kg
Tc - T., =0 Underground storage tank losses
N N
INUT UT
Tc = 298,000(12.1-4.47)
N
W
= 2.27xl06Kg
TM = 298,000(12.1-0)4-298,000(0-4.47)
w
WAR
- 2.27xl06Kg
Tc - T.T = (2.27-2.27)xl06
N N
LNAR W
= 0 aircraft refueling
Aviation Gasoline:
The aviation gasoline transfer industry is projected to
experience a negative growth. Model IV 's calculational framework
is not suited to accurately express T^ and T., when an industry is
declining. Therefore, the following equations are used to calculate
T and T.
B-36
-------
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Aviation Gasoline (cont.):
TN = Ts = ES(A'+C') where C' < 0
This equation is valid only when C' < 0 and |CJ-B' > 0
From the information in Section 7.0 of the main text,
the states of CT, PA, VA, KY, OH, WI, TX, NM, and CO and
Washington, DC have emission regulations that would require vapor
recovery systems for loading aviation gasoline into tank trucks
and rail cars. In 1972, the areas affected by these regulations
handled 15.970 of the total bulk facilities' sales of aviation
gasoline (US-417). Therefore, this same percentage is assumed
to apply to the bulk terminal and stations and refinery truck/
rail loadings in 1985. To account for this in the calculation of
Tg and TN, a hybrid Eg is calculated
1975 total T/R loading - 5.16
1975 refinery and bulk facilities T/R loading - 4.03
1975 loading with vapor recovery - 0.159x4.03 = 0.641
E0 - 0.641 x 28,700 -1- 4.52 x 345,000 = 306,000
S 5.16 37T6"
TM = Tc = 306,000(5.16-2.21)
= 903x10 3Kg
B-37
-------
RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319. Task 55
Subject: Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Aviation Gasoline (cont.):
- TN =0 truck/rail loading of aviation
-T/R GT/R gasoline
115,000(0.523-0.225)
34.3xl03Kg
- T.. =0 Tanker/barge loading of aviation
GT/B GT/B gasoline
- TQ » 575,000(0.569-0.244)
°p
UFRT
= 187x103Kg
Tf, - TTT =0 Fixed roof tank working losses
o /* . IN y-i
TM = Tc = 534,000(2.24-0.96)
JN^-i /^
= 684x103Kg
TS - TN =0 Underground storage tank losses
B-38
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of Tg-TN (cont.)
Prepared By: William C. Thomas
Aviation Gasoline (cont.):
T0 = 574,000(2.24-0.96)
GAR
Tc = 735x103Kg
GAR
TN = 574,000(2.24-0)+574,000(0+(-0.96))
* p
GAR
TM = 735x103Kg
V1
GAR
GAR GAR
= (735-735)xl03
= 0 Aircraft refueling
B-39
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject:
Prepared By:
Calculation of Tg-TN (cont.)
William C. Thomas
The following table summarizes the T<,-TN calculations .
Emission Source
Crude Oil
Production
T/R Loading
T/B Loading
TOTAL
TQ, Kg
176xl06
3.53x106
13.8x106
193x106
TN, Kg (TS-TN), Kg
173xl06
2.33x106
3.20x106
178x106
3x106
1.20x106
10.6x106
14.8x106
Kerosine Jet Fuel
T/R Loading
T/B Loading
Fixed Roof Tanks
Underground Tanks
Aircraft Refueling
TOTAL
Naphtha Jet Fuel
Aviation Gasoline
63. 3x10 3
3. 6x10 3
203x10 3
106x10 3
214x10 3
590x10 3
35. 3x10 3
2. 7x10 3
9 3x10 3
55. 7x10 3
2 14x10 3
401x10 3
28. 0x10 3
0.9xl03
110x10 3
50. 3x10 3
--
189x10 3
0
0
B-40
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RADIAN
CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of TA _
Prepared By: William C. Thomas _
TA
Therefore, using the values of A" and Eg listed on pages B-27
and B-28,
Crude Oil:
TA - 485x259,000 = 126xl06Kg
G
prod
TA - 12.8x241,000 = 3.08xl06Kg
T. = 47.8x80,400 = 3.84xl06Kg
Kerosine Jet Fuel:
TA = 27.1x1,900 = 51.5xl03Kg
TA = 6.2x635 = 3.9xl03Kg
B-41
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject- Calculation of T. (cont.)
Prepared By: William C. Thomas
Kerosine Jet Fuel (cont.):
TA = 42.4x3,170 = 134x103Kg
KFRT
T - 17.0x4,440 = 75.5xl03Kg
TA = 45.9x3,170 = 146x103Kg
KAR
Naphtha Jet Fuel:
TA = 18.8x180,000 = 3.38xl06Kg
NT/R
T. = 1.54x59,700 = 0.09x105Kg
"
TA = 8.60x300,000 = 2.58xl06Kg
N
1NFRT
TA = 1.57x423,000 = 0.66xl06Kg
N
1NUT
TA = 12.1x298,000 = 3.61xl06Kg
N
W
B-42
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CORPORATION
Computation Sheet For EPA Contract No. 68-02-1319, Task 55
Subject: Calculation of TA (cont.)
Prepared By: William C. Thomas
Aviation Gasoline:
TA = 5.16x345,000 = 1.78x106Kg
p
GT/R -
TA - 0.523x115,000 = 0.06x106Kg
GT/B
TA = 0.569x575,000 = 0.33x106Kg
T. = 2.24x534,000 = 1. 20x10 6Kg
= 2.24x574,000 = 1. 29x10 6Kg
GUT
B-43
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CORPORATION
APPENDIX C
BIBLIOGRAPHY
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BIBLIOGRAPHY
AM-039 American Petroleum Inst., Div. of Refining, Petrochemical
Evaporation Loss from Storage Tanks, API Bull. 2523,
N.Y., 1969.
AM-085 American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss from Tank Cars, Tank Trucks, and Marine
Vessels, Bull. 2514, Washington, D.C., 1959.
AM-087 American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss from Fixed-Roof Tanks, Bull. 2518,
Washington, D.C., 1962.
AM-107 American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss from Floating-Roof Tanks. Bull. 2517,
Washington, D.C., 1962.
AM-132 American Petroleum Institute, Statistics Dept., Annual
Statistical Review, Petroleum Industry Statistics, 1965-
1974, Washington, D.C., May 1975.
AT-040 Atmospheric Emissions from Petroleum Refineries, A
Guide for Measurement and Control, PHS No. 763,
Washington, D.C., Public Health Service, 1960.
BU-169 Burklin, Clinton E., et al., Study of Vapor Control
Methods for Gasoline Marketing Operations, 2 vols.,
Radian Project No. 200-045-087, EPA Contract No. 68-02-
1319, Task 7, EPA 450/3-75.046 a,b, Austin, TX., Radian
Corporation, May 1975.
CH-159 Chass, Robert L., et. al., "Emissions from Underground
Gasoline Storage Tanks", J. APCA 13_ (11), 524 (1963).
C-l
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CO-424 Commerce Clearing House Editorial Staff, 1976 U.S. Master
Tax Guide. 59th edition, Chicago, 111.. Commerce Clearing
House, Inc., 1975.
DA-069 Danielson, John A., comp. and ed., Air Pollution
Engineering Manual, 2nd ed., AP-40. Research Triangle
Pk., N.C., EPA, Office of Air & Water Programs, 1973.
DE-202 Devine, Matt, Private Communication, Allied Fueling,
March 17, 1976.
EL-104 Elliot, George, Private Communication, Allied Fueling,
May 11, 1976.
GR-235 Grundy, E. T., Private Communication, Gulf Oil Company,
April 6, 1976.
HE-187 Henderson, Cliff, Private Communication, Amoco Oil Co.,
Marketing Division, April 7, 1976.
HO-244 Hopper, Thomas G. and William A. Marrone, Impact o_f New
Source Performances Standards on 1985 National Emissions
from Stationary Sources, Volume I, Final Report, Main Text
and Appendices I through III. Contract No. 68-02-1382,
Task No. 3, Wethersfeld, Conn., TRC, The Research Cor-
poration of New England, Oct. 1975.
MS-001 MSA Research Corp., Hydrocarbon Pollutant Systems Study, -
Vol. !_, Stationary Sources, Effects and Control, PB-
219-073, APTD 1499, Evans City, PA., 1972.
NA-303 National Petroleum News, Fact Book, Mid-May 1975, NY,
McGraw-Hill. 1975.
C-2
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ST-381 Stanford Research Institute, Western Regional Energy
Development Study: Economics, Tools, draft report,
Contract No. EQ5AC007, EQ5AC008, SRI Project 4000, Menlo
Pk., CA., Dec., 1975.
ST-407 Stoddard, Bryon, Private Communication, Shell Oil Co.,
Marketing Engineering Division, April 6, 1976.
US-C31 U.S. Dept. of Commerce, Bureau of the Census, 1967 Census
p_f Business. Vol. Ill, Wholesale Trade Subject Reports,
Washington, GPO, 1971.
US-417 U.S. Dept. of Commerce, Bureau of Census, 1972 Census p_f
Wholesale Trade, Petroleum Bulk Stations and Terminals,
WC72-S-2, Washington, D.C., October, 1975.
US-418 U.S. Dept. of Transportation, Federal Aviation Admin.,
FAA Statistical Handbook of Aviation, Calendar Year 1974.
Washington, D.C., GPO, 1975.
US-419 U.S. Dept. of Interior, Bureau of Mines, Division of
Fuels Data, Crude Petroleum, Petroleum Products and
Natural Gas Liquids, March 1975, Mineral Industry Surveys,
Petroleum Statement, Monthly, Washington, D.C., July 1975.
US-420 U.S. Dept. of Interior, Bureau of Mines, Division of
Fuels Data, Crude Petroleum, Petroleum Products, and
Natural Gas Liquids, April 1975, Minerals Industry
Surveys, Petroleum Statement, Monthly, Washington, D.C.,
August, 1975.
C-3
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US-421 U.S. Dept. of Interior, Bureau of Mines, Division of
Fuels Data, Crude Petroleum, Petroleum Products, and
Natural Gas Liquids, Dec. 1975, Mineral Industry Surveys,
Petroleum Statement, Monthly, Washington, D.C., April 1976,
VA-129 Van Cleave, K.W., Private Communications, Allied Aviation,
March 16, 1976.
C-4
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