EPA-450/3-76-039
August 1976
REVISION
OF EVAPORATIVE
HYDROCARBON
EMISSION FACTORS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-76-039
REVISION
OF EVAPORATIVE
HYDROCARBON
EMISSION FACTORS
by
C.E. Burklin and R.L. Honerkamp
Radian Corporation
8500 Shoal Creek Blvd.
P.O. Box 9948
Austin, Texas 78766
Contract No. 68-02-1889
(Radian No. 100-086-01)
EPA Project Officer: Charles C. Masser
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1976
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD-35) , Research Triangle Park, North Carolina
27711; or, for a fee, from the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by
Radian Corporation, 8500 Shoal Creek Blvd. .P.O. Box 9948, Austin,
Texas 78766, in fulfillment of Contract No. 68-02-1889 (Radian No. 100-
086-01) . The contents of this report are reproduced herein as received
from Radian Corporation. The opinions, findings, and conclusions ex-
pressed are those of the author and not necessarily those of the Environ-
mental Protection Agency. Mention of company or product names is not
to be considered as an endorsement by the Environmental Protection
Agency.
Publication No. EPA-450/3-76-039
ii
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ABSTRACT
The increased use of EPA Document AP-42 entitled
Compilation of Air Pollutant Emission Factors and EPA's National
Emission Data System (NEDS) have brought to light several
inadequacies in the information contained in these sources per-
taining to evaporative hydrocarbon losses from the petroleum
industry. This report presents the work performed by Radian in
EPA study 68-02-1889 to update and revise the information pre-
sently contained in the National Emissions Data System and the
EPA Document AP-42 Compilation of Air Pollutant Emission Factors
related to evaporative hydrocarbon emissions from the petroleum
industry. As defined for this program, the petroleum industry
comprises production, transportation, storage, refining, and
marketing operations for petroleum crude oil and petroleum products
The methodologies used to make these revisions are also presented.
A discussion of the merits of conducting source testing and an
outline of a source test program for evaporative emission sources
when further source testing is warranted is included in the last
section of this report.
in
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TABLE OF CONTENTS
Paj
1.0 INTRODUCTION . 1
2.0 REVISIONS TO AP-42 2
2.1 Storage Losses 2
2.1.1 Hydrocarbon Properties 2
2.1.2 Clarification of Storage Losses 4
2.1.3 Revisions to Loss Correlations . 5
2.1.4 Revised Emission Factors for
Storage Losses 7
2.2 Transportation and Marketing Losses . . 8
2.2.1 Clarification of Transportation
and Marketing Losses 8
2.2.2 Revisions to Loss Correlations . 8
2.3 Refinery Losses 11
2.4 Production Losses ... . 12
2.5 Crude Oil RVP's ...... 13
3.0 REVIEW OF SOURCE CLASSIFICATION CODES ... 14
4.0 TEST PLAN DEVELOPMENT 16
4.1 Storage - Bulk 16
4.2 Storage - Service Stations ...... 20
4.3 Loading - Bulk 20
4.4 Loading - Service Station 22
4.5 Natural Gas and Crude Oil Production . 23
4.6 Refinery - Fugitive 25
4.7 Refinery - Process 26
4.8 Transportation 26
4.9 Vapor Characteristics 27
IV
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TABLE OF CONTENTS. (Cont.)
Page
ATTACHMENT A: .STORAGE LOSSES 29
ATTACHMENT•B: TRANSPORTATION AND LOADING LOSSES 57
ATTACHMENT C: REFINERY LOSSES .... 77
ATTACHMENT D: PRODUCTION LOSSES 83
ATTACHMENT E: SOURCE CLASSIFICATION CODES 109
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LIST OF TABLES
TABLE 4.0-1 Characterization of Evaporative
Hydrocarbons by Industry 17
TABLE 4.0-2 Characterization of Evaporative
Hydrocarbons by Source 18
VI
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1.0 INTRODUCTION
The increased use of EPA Document AP-42 entitled
Compilation of Air Pollutant Emission Factors and EPA's National
Emission Data System (NEDS) have brought to light several
inadequacies in the information contained in these sources per-
taining to evaporative hydrocarbon losses from the petroleum
industry.
Radian Corporation was contracted by EPA to upgrade and
refine the information presently contained in AP-42 and the NEDS,
related to evaporative hydrocarbon emission from the petroleum
industry. As defined for this program, the petroleum industry
comprises production, transportation, storage, refining, and
marketing operations for petroleum crude oil and petroleum products
Specific items reviewed by Radian include:
the vapor properties of hydrocarbon fuels,
the definitions for terms and equations,
the utility of equations and their units, and
the comprehensiveness of correlations and factors.
Radian was also contracted as part of this study to develop a test
plan for conducting source testing where further testing is war-
ranted.
This report presents the work performed by Radian in
EPA study 68-02-1889 to update and revise the information pre-
sently contained in the National Emissions Data System and the
EPA Document AP-42 Compilation of Air Pollutant Emission Factors
related to evaporative hydrocarbon emissions from the petroleum
industry. The methodologies used to make these revisions are
also presented. A discussion of the. merits of conducting source
testing and an outline of a source test program for evaporative
emission sources when further source testing is warranted, is
included in the last section of this report.
1
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2.0 REVISIONS TO AP-42
Radian's revisions to the evaporative loss section of
EPA document AP-42 entitled Compilation of Air Pollutant Emission
Factors, and the methodologies used in making these.revisions are
presented in this section. AP-42 is an EPA document which discusses
sources of air emissions, available control technologies, and
emission rates. The portions of AP-42 which were revised in this
study are those pertaining to evaporative hydrocarbon losses from
the petroleum industry. Evaporative losses from petroleum storage
and transportation are currently presented in Sections 4.3 and 4.4
respectively of Supplement No. 1 to AP-42. Evaporation losses
from petroleum refining are currently presented in Section 9.1 of
AP-42. No emissions are currently presented in AP-42 for evapora-
tive emissions from petroleum production operations.
2.1 Storage Losses
The revised Section 4.3 of AP-42 pertaining to storage
losses is presented in Attachment A. These revisions include
improved data on the properties of hydrocarbon liquids and their
vapors, restructured equations for calculating losses from petrol-
eum storage, expanded descriptions of petroleum storage losses
and of the use of the loss equations, and revised emission factors.
2.1.1 Hydrocarbon Properties
The physical properties of crude oil and petroleum fuels
presented in Section 4.3 and 4.4 of AP-42 were found to be defi-
cient and partially incorrect. The following problems were
identified with the data on the physical properties of hydro-
' carbon fuels:
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(1) Molecular weights for the vapors of
petroleum fuels xvere too low.
(2) Incomplete data were given on the density of
petroleum liquids.
(3) Incomplete data were given on the density of
condensed vapors from petroleum fuels.
(4) No direct correlations were given for
vapor pressure vs.temperature for either
petroleum fuels, .petroleum products, or
various crude oils.
In the revised Section 4.3 on storage losses, Radian
added Figures 4.3-8 and 4.3-9 which present nomographs for the
calculation of true vapor pressures for crude oil and gasolines.
These nomographs are taken from API Bulletin 2513 on Evaporation
Loss in the Petroleum Industry. The temperature and RVP of a
crude oil or gasoline can be used to obtain the true vapor
pressure of the liquid using these nomographs.
Radian also developed Table 4.3-3 which presents the
densities of petroleum liquids, the molecular weights and liquid
densities of the vapors from petroleum liquids, and the vapor
pressures of petroleum liquids at seven commonly encountered
temperatures. This information was primarily obtained from API
bulletin 2513 and from NACA Technical Note 3276 on Properties
of Aircraft Fuels. The vapor pressure data developed for fueis
were compared with data collected by EPA and were found to agree
quite well.
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2.1.2 Clarification of Storage Losses
The descriptions and explanations presented in Section
4.3 on storage losses were expanded where necessary to clarify
sources of storage losses and the proper application of correla-
tions for calculating storage losses. In several instances it-
was not clear in the description of variables for an equation
whether the molecular weight input required by the equation was
that of the vapor or of the liquid. Because properties for the
vapors of fuels differ significantly from the properties of the
fuels themselves, the terms used in the storage loss correlations
were defined more clearly.
Variables used in the storage loss equations and their
units were also changed to conform to convention and to standard-
ize the variables used among all of the evaporative loss equations.
The units used;in the revised storage loss correlations were those
units expected to be most convenient for persons employing AP-42.
Radian expanded the scope of AP-42 by including the
API correlation for calculating withdrawal losses from floating
roof tanks storing gasoline.
An example calculation was included in the revised
storage loss section to demonstrate the proper method of applying
the storage loss equations. It is hoped that better understanding
of how to apply the storage loss equations will lead to increased
use of the equations over the use of the less accurate storage loss
factors.
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2.1.3 Revisions to Loss Correlations
The correlations currently used in AP-42 for calculating
storage losses are based on API studies. Each of these equations
is designed for calculating hydrocarbon emissions from gasoline
storage. Emissions from the storage of crude oil and other petrol-
eum products are calculated using the gasoline specific equations
and by multiplying the results from that equation by an adjustment
equation. The adjustment equation developed by API is presented
in API Bulletin 2523 and is of the form;
_ /0.08M\
= \ d /
LG
where
L = liquid volume of vapors lost (bbl)
M = molecular weight of vapors lost
d = liquid density of vapors lost (Ib/gal)
L-, = liquid volume of vapors lost as
calculated by the gasoline specific
equation (bbl)
It should be noted that r^ for gasoline is roughly 0.08, and the
constant 0.08 is used in the adjustment equation to cancel the
M
value of -T for gasoline out of the gasoline specific equation.
Radian combined the adjustment equation with the gasoline
specific loss equations to form a single universal equation. As
an example, the fixed roof tank breathing loss equation for gaso-
line storage is of the form:
= 0.024
14.7-F
0.68
D H 'AT - F CK
P
where L,, = -fixed roof breathing loss for gasoline (bbl/yr)
G
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P = True vapor pressure of liquid at bulk liquid temperature (psia)
D = Tank diameter (ft)
H = Average vapor space height (ft)
AT = Average diurnal temperature change (°F)
F = Paint factor
P
C = Adjustment factor for small diameter tanks
K = Adjustment factor for crude oil storage
Application of the adjustment .aquation yields,
... 0-68
P I
'j. 7-P D H AT F C K
or;
L.- 0.00192 §
Multiplying the equation by 42d fIb-yr ] the units of the
equation become pounds per day and;
r -.0-68
I P I 1-73 0-51 0-
~*M [14.7-Pj . ' D H AT
0-68
5 0
L - 2.21x10 M I14.7-PI . D H — Fp C Kc
The above equation is universally applicable to gasoline
storage, crude oil storage, and the storage of all other petroleum
products with vapor pressures in the range of gasoline vapor
pressures. When this equation is applied to the storage of gaso-
line with a ft ratio of 0.08 it yields the exact same value as the
preceding gasoling specific equation.
The other gasoline specific equations for storage
losses presented in AP-42 were restructured in a similar manner
to yield single universal equations which are applicable to the
storage of gasoline, crude oil, and petroleum products.
6
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The API only recommends the use of these storage loss
equations for cases in which the stored petroleum liquids exhibit
vapor pressures in the same range as gasolines. However, in the
absence of any correlations developed specifically for naphthas,
kerosenes, or fuel oils it is recommended that the API storage
loss equations also be used for the storage of these heavier fuels.
2.1.4 Revised Emission Factors for Storage Losses
Section 4.3 of AP-42 contains a table of emission factors
for estimating emissions from petroleum liquid storage when suffi-
cient information is not available for using the more accurate
storage loss correlations. The emission factors for crude oil,
JP-4, jet kerosene, and distillate were based on 50,000 bbl storage
tanks. All other factors were based on 67,000 bbl storage tanks.
Because tank size has a significant impact on storage emissions
and because fuels are often stored in tanks larger than 100,000 bbl,
a second set of factors was added to the storage loss factor table
which are based on storage tanks with a capacity of 250,000 bbl.
The second set of factors was added for crude oil and petroleum fuels
storage only, as petrochemicals are primarily stored in the smaller
tanks.
In addition to adding a set of factors based on larger
storage tanks, each factor in the storage loss factor table was
recalculated using the revised physical properties for petroleum
liquids. Several factors were changed significantly.
The emission factors for storage losses are based upon
typical systems and conditions. Radian emphasized in the revisions
to AP-42 that these emission factors should only be used in the
absence of sufficient parameters for using the more accurate
emission correlations.
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2.2 Transportation and Marketing Losses
The revised Section 4.4 of AP-42 on Transportation and
Marketing Losses in the petroleum industry is presented in Attach-
ment B. The major revisions to the transportation and marketing
section centered around increased discussion of emission sources
and simplification of the emission correlations.
2.2.1 Clarification of Transportation and Marketing Losses
The revised transportation and marketing loss section of
AP-42 has a much expanded discussion on sources of hydrocarbon
emissions, the mechanism by which these emissions are generated,
and available emission control technology for hydrocarbon emission
sources. Several figures were added to the descriptions for
further clarification.
2.2.2 Revisions to Loss Correlations
Three problems surfaced when Radian investigated the
emission rate correlations presented in Supplement No. 1 to
AP-42 for evaporative hydrocarbon emissions from petroleum loading
operations. Equations 1, 2, and 3 (reprinted below) were found
to be specific for hydrocarbon blends with vapors exhibiting mole-
cular weights in the same region as the molecular weight of
gasoline vapors.
69.600 YPW
ut (690-4M)T . (1)
69,600 PW
Lsub = ^~*~^ (69°-4M)T (2)
1 02x106W
sp (690-4M)T
14.7-YP , (3)
14.7-0.95P
-1
-------
wherei .
U = unloading loss (lb/103gal)
L , = submerged loading loss (lb/103 gal)
L = splash loading loss (lb/103gal)
sp
Y = degree of saturation
P = true vapor pressure (psia)
W = liquid density (Ib/gal)
T = temperature of liquid (°R)
M = molecular weight
The emission rate U L , or L calculated by equations (1),
U i S LlD f ^r
(2), and (3) approaches infinity as the molecular weight (M) of
the vapor approaches 172. API information also indicates that the
term 1 was developed from gasoline test data only.
690-4M
A second problem which surfaced when investigating
equations (1), (2), and (3) is that each equation requires the
input of a value for Y, the residual vapor's fractional approach
to saturation. Residual vapors are those vapors remaining in the
empty cargo tank from the previous delivery. Radian felt that
most people resorting to the use of emission correlations will
not have sufficient test data to supply a value for Y.
Finally, equations 4, 5 and 6 correlate mass emission rates
with product density (W) and ignore the impact of temperature.
U = 0.07 PW (unloading ships) (4)
o
L = 0.08 PW (loading ships) (5)
o
R =0.1 PW (intransit loss on ships) (6)
S
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Where P = true vapor pressure (psia)
W = transported liquid density (Ib/gal)
U L R = emission rate (lb/103gal)
s, s, s
The Ideal Gas law states that emission rates (on a weight basis)
should be proportional to vapor molecular weight instead of
liquid density and that emission rates should also be inversely
proportional to temperature.
In an effort to simplify the calculation of loading
emissions, equations 1 through 5 were restructured into a single
equation based on the Ideal Gas law.
LT - 12.46 SPM
L —j-
Where L, ^Loading loss (lb/103gal)
J_i
P = True vapor pressure of the loaded hydrocarbon (psia).
M = Molecular weight of the vapors (Ib/lb-mole)
T = Temperature of the liquid (°R).
S = Saturation factor.
The saturation factor (S) corrects for the fact that various
loading methods result in the stratification of hydrocarbon vapors
and in the expulsion of subsaturated vapors. A table of S factors
was generated from API Bulletin 2514 on Evaporation Loss from
Tank Cars, Tank Trucks, and Marine Vessels.
This equation based on the Ideal Gas law and on an S
factor applies to loading losses from crude oil, gasoline, and
petroleum products into truck, rail car, barge, and marine vessel
modes of transportation.
10
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The Ideal Gas law equation was not recommended for the cal-
culation of hydrocarbon emissions from the marine loading of gaso-
line in light of the new marine operation emission factors recently
released by the API. The API factors are more accurate than
current information on S factors for marine loading of gasoline.
The Ideal Gas law equation however is still recommended for the
calculation of hydrocarbon emissions from the marine loading of
crude oil and petroleum products other than gasoline.
Equation 6 of AP-42 pertaining to marine intransit losses
was not restructured because sufficient information was not avail-
able for developing a value for the intransit loss S factor.
2.3 Refinery Losses
The revised Section 9.1 of AP-42 pertaining to Refinery
Losses is presented in Attachment C. Revisions to the refinery
loss section are limited to evaporative hydrocarbon emissions.
Radian removed the evaporative hydrocarbon emission factors from
Table 9.1-1 and formed them into a separate evaporative emission
table (Table 9.1-2).
In an attempt to make the emission factors more useful,
they are reported in several sets of units. For example, revised
emission factors for evaporative emissions from process drains
and waste water separators are given in the units of lbs/103
gallons of waste water and in the units of lbs/103bbl of refinery
capacity. Revised pump seal leak rates are reported in Ibs/day -
seal and in lbs/103bbl refinery capacity. Table 9.1-2 also
presents a separate set of evaporative emission factors for con-
trolled emission sources.
11
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Revisions to emission factors for sources other than
evaporative emission sources were not within the scope of this
program. This program also did not include revisions to the text
of the refinery loss section of AP-42.
2.4 Production Losses
Section 9.3 concerning Evaporative Emissions from the
petroleum production industry is a new section to AP-42 and not a
revision to an existing section. To date, production emissions have
not been covered in AP-42. The production loss section discusses
in length the operations, emission sources, and available control
technology for the petroleum production industry. As defined
for Section 9.3, the petroleum production industry encompasses
exploration, site preparation, drilling, crude oil processing,
natural gas processing, and secondary or tertiary recovery.
While composing Section 9.3 it became apparent that very
little definitive data is available on the emissions from the
petroleum production industry. Although potentially very helpful
as a description of the petroleum production industry and its
evaporative emission sources, Section 9.3 is very weak in emission
factors and correlations. Consequently, it may be premature to
include a section on petroleum production emissions in AP-42 at
this time.
12
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2.5 Crude Oil RVP's
It had been suggested at the onset of this program that
Radian incorporate a table into either Section 4.3 or Section 4.4
of AP-42 which listed the RVP's of the major crude oils of the
world. After further study it was decided not to include such a
table on crude oil RVP's for several reasons.
Currently there are in excess of fifty major crude oils
imported into the United States. It is unlikely that many users
of AP-42 will have information of sufficient detail to identify
the specific crude oils about which he is concerned.
In those cases where the user of AP-42 does have informa-
tion on the specific crude oils handled, it is also likely that
he has access tro crude oil assays performed by the refinery on the
delivered crude oil. The physical properties reported in these
assays are much more accurate than a table of well head assays
because the volatility of crude oils is heavily dependent upon
a very small quantity of light ends which have a tendency to
weather significantly during transportation and handling.
13
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3.0 'REVIEW OF SOURCE CLASSIFICATION CODES
Source Classification Codes (SCC) were developed for the new
evaporative emission factors and revised for the existing evapora-
tive emission factors associated with the petroleum industy. A
table of the revised codes is presented in Attachment E. The
format and structure used in these revisions is identical to
that appearing in the EPA publication NEDS Source Classification
Codes, Appendix D of Supplement No. 5 (AP-42).
Symbols in the far right hand column of the Source Classi-
fication Code tables indicate the action taken to revise each code.
These symbols represent the following actions:
Symbol Action
* No changes were made to the existing EPA SCC.
+ No changes were made to the newly added TACB
(Texas Air Control Board) SCC.
1 Both the source title and.emission factor were
changed for an existing EPA SCC.
2 Both the source title and emission factor were
changed for a newly added TACB SCC.
3 A new SCC was added.
4 Only the emission factor was changed for an
existing EPA SCC.
5 Only the emission factor was changed for a newly
added TACB SCC.
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Although emission factors were developed for the storage
of gasolines with three different vapor pressures, source classi-
fication codes were only assigned to the factors for the 10 RVP
gasoline. The small increase in accuracy afforded by including
emission factors for three gasolines and the infrequent demand
for the factors for 7 RVP and 13 RVP gasolines did not justify
the complexity resulting in the SCC system by including all three
gasolines. Jet fuel in the existing SCO's was redefined as JP-4
and kerosene was redefined as jet kerosene.
No source classifications codes were assigned to petrol-
eum production emissions because of their incompleteness. Neither
were source classification codes assigned to refinery emission
factors. It is anticipated that the refinery section of AP-42
will shortly undergo complete revision and it will be most efficient
to revise all of the source classification codes for refinery emis-
sions at one time.
15
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4.0 TEST PLAN DEVELOPMENT
The increased use of EPA Document AP-42 entitled
Compilation of Air Pollutant Emission Factors and EPA's National
Emission Data System (NEDS) have brought to light several
inadequacies in the information contained in these sources per-
taining to evaporative hydrocarbon losses from the petroleum
industry. Many emission factors in AP-42 work well when applied
to a large cross section of sources but are inaccurate when applied
to individual emission sources.
This section discusses the adequacy of the evaporative
hydrocarbon emission factors currently contained in AP-42 and its
Supplements. A discussion is also included on what would be
involved in testing these sources. Tables 4.0-1 and 4.0-2 present
a breakdown of the contribution of evaporative emission sources
to the national hydrocarbon emission level. Table 4.0-2 also
summarizes the adequacy of existing emission factors for these
sources and the complexity of a sampling program to update these
factors. ., • •
4.1 Storage - Bulk
The bulk storage of crude petroleum and petroleum
products is the largest source of hydrocarbon emissions in the
petroleum industry. Bulk storage operations contribute an esti-
mated 7.470 of the nation's total hydrocarbon emissions. Even
after the full application of best available emission control
technology, storage emissions are expected to remain a very signi-
ficant, if not the most significant, hydrocarbon emission source
in the petroleum industry. The major contributor to hydrocarbon
16
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TABLE 4.0-1
CHARACTERIZATION OF EVAPORATIVE HYDROCARBONS
BY INDUSTRY
Industry
Natural Gas Production
Crude Oil Production
Crude Transportation
Refining
Gasoline Marketing
Refinery Product Marketing
TOTAL
Evaporative
Hydrocarbon
Emissions
(103 Ton/Year)
544
346
538
2101
1440
257
5226
Percent of
National
Hydrocarbon
Emissions
2.1
1.4
2.1
8.3
5.7
1.0
20.6
Sources
MSA Research Corporation, Hydrocarbon Pollutant Systems Study, Vol. 1
Stationary Sources, Effects and Control.PB-219-073, APTD 1499.
Evans City, PA., 1972.
Burklin, C.E., et al., Control of Hydrocarbon Emissions from
Petroleum Liquids. Contract No. 68-02-1319, Task 12, EPA
600/2-75-042.PB 246 650/ST. Austin, Texas, Radian Corporation,
Sept. 1975.
17
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TABLE 4.0-2
CHARACTERIZATION OF EVAPORATIVE HYDROCARBONS BY SOURCE
Evaporative Percent of
Hydrocarbon National Emission
Emissions Hydrocarbon Factor
Source (10 3 Ton/Yr) Emissions Accuracy
Storage - bulk
- service
s t.a t ion
Loading - bulk
- service
station
Natural Gas Production
Crude Oil Production
Refinery - fugitive
- process
Transportation
TOTAL
1890
48
426
872
544
344
857
243
NA
5224
7.4
0.2
1.7
3.4
2.1
1.4
3.4
1.0
NA
uncertain
adequate
not adequate
not adequate
very poor
very poor
not adequate
uncertain
uncertain
Involvement
of
Sampling
Program
very involved
not necessary
standard
involved
very involved
very involved
very involved
standard
standard
NA - data not available
Sources
MSA Research Corporati
Effects and Control.
Burklin, C.E. , et al. ,
on, Hydrocarbon
PB-219-073, APTD
Pollutant Systems Study, Vol. 1.
1499.
Control of Hydrocarbon
68-02-1319, Task 12, EPA 600/2-75-042. PB 246
Evans City, PA. , 1972.
Emissions from Petroleum
Stationary Sources
Liquids . Contract No
> 650/ST. Austin, Texas, Radian Corporation,
Sept. 1975
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emissions from bulk storage operations is the bulk storage of
gasoline both at refineries and in the gasoline marketing system.
The primary sources of hydrocarbon emission factors for
bulk storage operations are the correlations derived by the Evapora-
tive Loss Committee of API between 1959 and 1962. These correla-
tions are based on testing results assembled by API from the
petroleum industry. The reported accuracy of these correlations
at the time of their development was estimated at + 2570 overall.
There have been many significant developments made in recent
years on storage tank design, especially in the area of seals
for floating-roof tanks. It is likely that the API emission -
factor correlations do not adequately predict the hydrocarbon
emissions from floating-roof tanks. Recent test results also
indicate that API storage emission correlations do not adequately
deal with petroleum liquids having low vapor press-ures. Currently
available floating-roof tank withdrawal loss correlations are
limited to the use of gasoline storage only.
Because the accuracy of storage loss equations is unknown,
it may be advisable to first conduct a screening study to identify •
areas where source testing is required. The screening study would
review the basis for the present API storage loss equations and
attempt to verify these equations by spot testing.
If a comprehensive sampling program is indicated by the
screening study, elaborate testing procedures will have to be
developed. Fixed-roof tank emission testing will be relatively
straight forward. Care must be taken to record all applicable
parameters. The hydrocarbon emission rate can be obtained by
monitoring the vapors exiting the pressure/vacuum vent.
19
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Measuring the hydrocarbon emission rate from floating-
roof tanks is much more difficult. It is impossible to test
floating-roof tank emissions by enclosing the tank because of its
large size and the importance that wind velocity has on the
emission rate. Floating-roof hydrocarbon emission testing will
likely involve either ambient hydrocarbon sampling in the proxi-
mity of the tank and back calculating emission rates using diffusion
modeling techniques or scale up of emission test results on small
tanks. Several measurements must be taken around each tank and
numerous tanks must be sampled to account for the effects of wind
speed, tank size, seal type, fuel RVP, and temperature.
^-^ Storage - Service Stations
Existing emission factors for the storage of gasoline
in underground service station tanks are adequate for the charac-
terization of service station storage losses. The emission
factors presented in AP-42 were developed in recent source testing
programs on representative service station equipment. In addition,
evaporation losses from service station storage tanks are small,
contributing an estimated 0.2% of the nation's total hydrocarbon
emissions. Even on the local level, service station storage
losses are relatively small compared to vehicle refueling losses
and bulk delivery losses.
4. 3 Loading - Bulk
The bulk loading of crude petroleum and refined petroleum
products into tank trucks, railcars, and marine vessels contrib-
utes an estimated 1.770 of the national hydrocarbon emissions.
These loading losses are primarily attributable to gasoline loading
operations within the gasoline marketing industry. Loading losses
are even more significant on the local level because of the large
quantities loaded at high loading rates on individual loading
20
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sites. Marine terminals load as much as 400 thousand gallons of
gasoline per hour.
The correlations used today to calculate loading losses
are largely based on loading loss correlations developed by the
American Petroleum Institute in 1959. At that time they were
estimated by API to have an overall accuracy of + 3570. Since
the development of loading loss correlation, there have not been
dramatic changes in loading equipment. However, loading rates
have increased and loading nozzles have been modified. Loading
emission controls have also been improved. These design changes
may have altered the applicability of the API loading loss corre-
lations to current loading operations.
The API emission work concentrated on gasoline and crude
oil loading operations into railcars and tank trucks. The corre-
lations API developed have not been demonstrated to be accurate for
the. calculations of losses from the loading of other petroleum pro-
ducts or for the loading of gasoline and crude oil at nonstandard
conditions. Marine and barge loading loss correlations were also
inadequate, however API is currently in the process of revising
these correlations.
Recent gasoline loading loss data for tank trucks has
been collected in conjunction.with studies to define the hydro-
carbon emissions associated with the gasoline marketing industry.
However, it appears that not enough parameters were measured to
allow the development of a universal correlation for tank truck
and railcar loading of crude oil and refined petroleum products.
Testing procedures for tank truck loading emissions have
been developed in conjuncution with new source performance studies
conducted on the gasoline marketing industry. These testing
procedures are sufficient for the development of truck loading
emission factors. Testing procedures for marine loading operations
are similar to those for tank truck and railcar loading operations.
21
-------
However, testing marine loading operations is more difficult
because of the large flow rates and emission rates involved. A
much larger scale of sampling equipment is required.
4.4 Loading - Service Station
Loading emissions at service stations include hydrocarbon
emissions generated by the bulk drop of gasoline into the under-
ground service station storage tank and the hydrocarbon emissions
generated by refueling automobiles. Service station loading losses
are estimated to contribute 3.470 of the national hydrocarbon
emissions. Service station loading emissions are also significant
when considered on the local level. The average service station
emits an estimated 20 pounds of hydrocarbons per day at ground
level. The hydrocarbon emission problem from service stations
*
is further complicated by the high concentration of service stations
in the average urban area.
Extensive source testing conducted in the past five
years has resulted in the development of emission factors which
adequately yield the hydrocarbon emission rate from national
service station operations. These emission factors are most
accurate when applied to a large cross section of service stations.
Their accuracy may be a problem, however, when applied to indi-
vidual sources. Scott Environmental Technology, Inc. developed a
three-parameter correlation to calculate vehicle refueling
emissions. Although the values predicted by the Scott correlation
have been questioned, a correlation of this type is required to
accurately calculate emissions from individual service stations or
from service station operations conducted in a particular season or
portion of the country. Sufficient test data may have been
collected in recent studies to develop multi-parameter correlations
for service station operations without the need for additional
testing.
22
-------
Adequate emission factors do not exist for service
stations applying emission controls. Service station emission
controls are currently a developing technology under a continued
state of change. Biannual testing may be required to provide adequate
up-to-date emission factors for controlled service station operations.
4. 5 Natural Gas and Crude Oil Production
Although generally located in remote areas, the natural
gas and crude oil production industry is a significant emission
source. Collectively, emissions from the natural gas and crude
oil production industry are estimated to represent 3.5% of the
national hydrocarbon emissions.
Emission factors for the gas and oil production industry
are not adequate. The primary source of emission factors for
natural gas production operations is a Processes Research, Inc.
report which based its emission estimates on the assumptions that:
1) all unaccounted natural gas is lost to the atmosphere, 2) twenty
percent of the vented and flared gas is emitted without burning,
and 3) emitted hydrocarbons have a density of 0.1 pounds per cubic
foot. Thesa assumptions require verification. Crude oil produc-
tion emissions are largely based on a L967 study conducted on
crude oil production facilities in Monterey County by the Monterey-
Santa Cruz County Unified APCD.
A broader study is required to verify the applicability
of these emission factors to production facilities in all locations.
The Santa Cruz study also did not include all of the hydrocarbon
emission sources associated with production facilities. In addi-
tion there are no emission factors available for offshore pro-
duction facilities. The uniqueness of offshore productions makes
it inadvisable to apply onshore production emission factors to
offshore operations.
23
-------
Emission factors for production operations may need to
be developed on two levels. On the first level, production
emission factors would be developed which represent the average
facility and which will be meaningful when applied to a large
cross section of production facilities. These emission factors
will be applicable to region-wide or state-wide emission inventories
Because no production facility is average and because the
range of production processing schemes is so great, average emission
factors have no meaning for individual production facilities.
A second set of equipment and process emission factors would be
required for dealing with individual production facilities. If
simple flow schemes are available for a production facility,
emission factors for each piece of equipment can be assembled to
yield an overall emission factor for that particular production
facility.
A testing program for production facilities will be very
involved. Although testing of direct process emissions will be
straightforward, a large portion of the emissions from production
operations are attributable to fugitive emission sources. Test
procedures for fugitive emission sources will have to be developed.
Both the development and implementation of fugitive emission source
testing is a very involved process.
The development of emission factors for offshore pro-
duction facilities must be a separate study. Emissions from
offshore production facilities are expected to be unique. Most
offshore production facilities are newer installations employing
advanced processing and control technology. In addition, good
housekeeping and maintenance practices are routinely employed as
a safety measure. Fugitive leaks and spills present a great fire
hazard to the high density of processing equipment on offshore
production platforms.
24
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4.6 Refinery - Fugitive
Fugitive emissions account for the major portion of
hydrocarbon emissions from petroleum refining operations. It has
been estimated that the fugitive hydrocarbon emissions from
refinery operations contribute 3.4% of the nation's total hydro-
carbon emissions.
The adequacy of current fugitive emission factors for
refinery operations is unknown. These refinery emission factors
were developed in the late 1950's in a survey of Los Angeles
refineries. However, since the 1950's there have been many
developments in processing and control technology for refineries. .
These developments have significantly changed the basis upon which
the original refinery emission factors were derived."
The. sampling of a petroleum refinery is a very involved
task. Refineries are enormous processing complexes consisting
of numerous fugitive emission sources. The task of establishing
representative emission factors is further complicated by the wide
variety of processing flow schemes used in petroleum refineries.
Petroleum refineries range from simple topping facilities designed
to separate crude oil into its basic natural components to a fully
integrated gasoline and petrochemical refinery designed to alter
the composition of crude oil constituents to maximize the produc-
tion of gasoline and petrochemicals.
A suggested form for the fugitive emission factors for
petroleum refineries is pounds/source-throughput and pounds/unit-
throughput. For example fugitive emissions from pipeline valves
on the atmospheric still might be expressed in units of pounds/valve-
day and pounds/103bbl of atmospheric still throughput. The ability
to account for the fugitive emissions from each unit according to
unit size allows the calculation of fugitive emission rates Which
25
-------
will be more accurate on the individual refinery level. It will
remain impossible to account for variations in fugitive emissions
due to variations in maintenance and housekeeping practices
between refineries.
4.7 Refinery - Process
Although not as large as fugitive refinery emissions,
process refinery emissions are a significant source of atmospheric
hydrocarbons. It is estimated that process emissions account for
170 of the total national hydrocarbon emissions .
The adequacy of current emission factors for refinery
process emissions is unknown. Most of the available process
emission factors were originally developed in the late 1950's in
a survey of Los Angeles refineries. Since that time some of these
emission factors, have been updated by the American Petroleum
Institute and by the EPA. Because of the error uncertainty in
process emission factors, screening tests should be conducted to
identify sources for which detailed testing is warranted.
Process emission sources are generally fewer in number
than fugitive emission sources and are much more easily identified.
The sampling of process emission sources is much less involved
than the sampling of fugitive emission sources.
4.8 Transportation
Very little data is available on the evaporative hydro-
carbon emissions from transportation operations. The significance
of these emissions has not been verified. Ship and barge intransit
losses are probably significant owing to their consolidated large
volume. Although dispersed in smaller cargoes, truck and rail
26
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intransit losses may also be significant. The testing of ship
and barge transportation emissions would involve traveling with
the vessel for a complete voyage. The vent lines on ships and
barges are thought to be accessible. The sampling of tank trucks
and rail tank cars is more difficult because of the limited space
available for sampling equipment and lack of utilities.
4.9 Vapor Characteristics
Additional testing of vapor characteristics for common
petroleum crude oils and refinery products is also warranted.
Some testing has been conducted by API, however, the tests were
conducted for different purposes and not all of the important para-
meters were tested. EPA has also conducted vapor pressure analysis
for standard fuels, but these tests did not include sufficient data
points in the ambient temperature range. In addition, more infor-
Tiation must be collected on the molecular weights and condensed
vapor densities of petroleum product vapors. These tests should
include statistical analyses to select representative petroleum
liquids. They should also focus on collecting the data in the full
range of normal operating conditions.
27
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ATTACHMENT A
STORAGE LOSSES
29
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4.3 STORAGE OF PETROLEUM LIQUIDS
Fundamentally, the petroleum industry consists of three
operations: (1) petroleum production and transportation, (2)
petroleum refining, and (3) transportation and marketing of
finished petroleum products. All three operations require some
type of storage for petroleum liquids. Storage tanks for both
crude and finished products can be sources of evaporative emissions
Figure 4.3-1 presents a schematic of the petroleum industry and
its points of emissions from storage operations.
4.3.1 Process Description
Four basic tank designs are used for petroleum storage
vessels: fixed roof, floating roof (open type and covered type),
variable vapor space, and pressure (low and high).
Fixed Roof Tanks3
The minimum accepted standard for storage of vol-atile
liquids is the fixed roof tank (Figure 4,3-2). It is usually
the least expensive tank design to construct. Fixed roof tanks
basically consist of a cylindrical steel shell topped by a coned
roof having a minimum slope of 3/4 inches in 12 inches. Fixed
roof tanks are generally equipped with a pressure/vacuum vent
designed to contain minor vapor volume changes. For large fixed
roof tanks, the recommended maximum operating pressure/vacuum
is +0.03 psig/-0.03 psig (+2.1 g/cm2/-2.1 g/cm2).
Floating Roof Tanks5
Floating roof tanks reduce evaporative storage losses
by minimizing vapor spaces. The tank consists of a welded or
riveted cylindrical steel wall, equipped with a deck or roof
30
-------
u>
m
5
"B
3
**
o
3
l/J
O
e
•n
O
a
OIL FIELD
CRUDE
STORAGE
TANKS
CRUDE OIL PRODUCTION
1
PRODUCT
STORAGE
TANKS
REFINERY
MARKETING
TERMINAL
STORAGE
TANKS
TANK TRUCK , .
TANK CAR
PETROCHEMICALS
1
BULK
PLANT
STORAGE
TANKS
TANK TRUCK
1
COMMERCIAL
ACCOUNTS'
STORAGE
TANKS
SERVICE
STATIONS
AUTOMOBILES
AND
OTHER MOTOR
VEHICLES
Figure 4.3-1. Flowsheet of petroleum production, refining, and distribution systems.
(Sources of organic evaporative emissions are indicated by vertical arrows).
-------
PRESSURE-VACUUM
VENT
00
K)
NOZZLE -
GAUGE HATCH
MANHOLE -.
LIQUID LEVEL
MANHOLE —
FIGURE 4.3-2. FIXED ROOF STORAGE TANK
-------
which is free to float on the surface of the stored liquid. The
roof then rises and falls according to the depth of stored liquid.
To insure that the liquid surface is completely covered, the
roof is equipped with a sliding seal which fits against the
tank wall. Sliding seals are also provided at support columns
and at all other points where tank appurtenances pass through
the floating roof.
Until recent years, the most commonly used floating
roof tank was the conventional open-type tank. The open-type
floating roof tank exposes the roof deck to the weather; pro-
visions must be made for rain water drainage, snow removal, and
sliding seal dirt protection. Floating roof decks are of three
general types: pan, pontoon, and double deck. The pan-type
roof consists of flat metal plate with a vertical rim and
sufficient stiffening braces to maintain rigidity (Figure 4.3-3).
The single metal plate roof in contact with the liquid readily
conducts solar heat, resulting in higher vaporization losses than
other floating roof decks. The roof is equipped with automatic
vents for pressure and vacuum release. The pontoon roof is a
pan-type floating roof with pontoon sections added to the top of
the deck around the rim. The pontoons are arranged to provide
floating stability under heavy loads of water and snow. Evapora-
tion losses due to solar heating are about the same as for pan-
type roofs. Pressure/vacuum vents are required on pontoon roof
tanks. The double deck roof is similar to a pan-type floating
roof, but consists of a hollow double deck covering the entire
surface of the roof, (Figure 4.3-4). The double deck adds
rigidity, and the dead air space between the upper and lower
deck provides significant insulation from solar heating. Pressure/
vacuum vents are also required.
The covered-type floating roof tank is essentially a
fixed-roof tank with a floating roof deck inside the tank
33
-------
NOZZLE
ROOF SEAL (METALLIC SHOO
FIGURE 4.3-3. RAM-TYPE FLOATING ROOF STORAGE TANK (METALLIC SEALS)
ROOF SEAL
. (NON-METALLIC)
WEATHER SMELD-
NOZZLE
FIGURE 4.3-4. DOUBLE DECK FLOATING ROOF STORAGE TANK (NON-METALLIC SEALS*
AIR SCOOPS •
NOZZLE
FIGURE 4.3-5. COVERED FLOATING ROOF STORAGE TANK
34
-------
(Figure 4.3-5). The American Petroleum Institute has designated
the term "covered floating " roof to describe a fixed roof tank
with an internal steel pan-type floating roof. The term "internal
floating cover" has been chosen by the API to describe internal
covers constructed of materials other than steel. Floating roofs
and covers can be installed inside existing fixed roof tanks. The
fixed roof protects the floating roof from the weather, and no
provision is necessary for rain or snow removal, or for seal protection,
Antirotational guides must be provided to maintain roof alignment,
and the space between the fixed and floating roofs must be vented
to prevent the possible formation of a flammable mixture.
Variable Vapor Space Tanks"
Variable vapor space tanks are equipped with expandable
vapor reservoirs to accommodate vapor volume fluctuations attrib-
utable to temperature and barometric pressure changes. Variable
vapor space tanks are sometimes used independently, however, a
variable vapor space tank is normally connected to the vapor
spaces of one or more fixed roof tanks. The two most common types
of variable vapor space tanks are lifter roof tanks and flexible
diaphragm tanks.
Lifter roof tanks have a telescoping roof that fits
loosely around the outside of the main tank wall. The space
between the roof and the wall is closed by either a wet seal which
consists of a trough filled with liquid, or a dry seal which employs
a flexible coated fabric in place of the trough (Figure 4.3-6).
Flexible diaphragm tanks utilize flexible membranes to
provide the expandable volume. They may be separate gasholder
type units, or intergral units mounted atop fixed roof tanks
(Figure 4.3-7).
35
-------
-PRESSUflE-VACULM
VENT
NOZZLE
FIGURE 4.3-6. LIFTER ROOF STORAGE TANK (WET SEAL)
PRESSURE
VACUUM VENTS
NOZZLE
FIGURE 4.3-7. FLEXIBLE DIAPHRAGM TANK (INTEGRAL UNIT)
36
-------
Pressure Tanks6
Pressure tanks are designed to withstand relatively
large pressure variations without incurring a' loss. They are
generally used for storage of high volatility stocks, and they
are constructed in many sizes and shapes, depending on the
operating range. The noded spheroid and noded hemispheroid shapes
are generally used as low pressure tanks (17 to 30 psia or 12 to
21 Mg/m2), while the horizontal cylinder and spheroid shapes are
generally used as high pressure tanks (up to 265 psia or 186 Mg/m2)
4.3.2 Emissions and Controls
There are six sources of emissions from petroleum liquids
in storage: fixed roof breathing losses, fixed roof working losses,
floating roof standing storage losses, floating roof withdrawal
losses, variable vapor space filling losses, and pressure tank
losses.2
Fixed roof breathing losses consist of vapor expelled
from a tank because of the thermal expansion of existing vapors,
vapor expansion caused by barometric pressure changes, and/or
an increase in the amount of vapor due to added vaporization in
the absence of a liquid-level change.
Fixed roof working losses consist of vapor expelled
from a tank as a result of filling or emptying operations. Filling
loss is the result of vapor displacement by the input of liquid.
Emptying loss is the expulsion of vapors subsequent to product
withdrawal, and is attributable to vapor growth as the newly
inhaled air is saturated with hydrocarbons.
37
-------
Floating roof standing storage losses result from causes
other than breathing or change in liquid level. The largest
potential source of this loss is attributable to an improper fit
of the seal and shoe to the shell, which exposes some liquid sur-
face to the atmosphere. A small amount of vapor may escape between
the flexible membrane seal and the roof.
Floating roof withdrawal losses result from evaporation
of stock which wets the tank wall as the roof descends during
emptying operations. This loss is small in comparison to other
types of losses.
Variable vapor space filling losses result when vapor
is displaced by the liquid input during filling operations. Since
the variable vapor space tank has an expandable vapor storage
capacity, this loss is not as large as the filling loss associated
with fixed roof tanks. Loss of vapor occurs only when the vapor
storage capacity of the tank is exceeded.
Pressure tank losses occur when the pressure inside the
tank exceeds the design pressure of the tank, which results in
relief vent opening. This happens only when the tank is filled
improperly, or when abnormal vapor expansion occurs. These are
not regularly occurring events, and pressure tanks are not a
significant source of loss under normal operating conditions.
The total amount of evaporation loss from storage tanks
depends upon the rate of loss and the period of time involved.
Factors affecting the rate of loss include:
1) True vapor pressure of the liquid stored,
2) Temperature changes in the tank,
3) Height of the vapor space (tank outage),
4) Tank diameter,
38
-------
5) Schedule of tank filling and emptying,
6) Mechanical condition of tank and seals ,
7) Type of tank and type of paint applied to
outer surface .
The American Petroleum Institute has developed empirical formulae,
based on field testing, that correlate evaporative losses with
the above factors and other specific storage factors.
Fixed Roof Tanks1.3
Fixed roof breathing losses can be estimated from:
1 '
TZTTT p c
[p ~1 ' 1-73 o-si o.so
TZTT D H AT F C K (1)
where: Lfi = Fixed roof breathing loss (Ib/day) .
.M = Molecular weight of vapor in storage tank
(Ib/lb mole); see Table 4.3-3.
P = True vapor pressure at bulk liquid conditions
(psia) ; see Figures 4.3-8, 4.3-9, or Table 4.3-3.
D = Tank diameter (ft) .
H = Average vapor space height, including roof
volume correction (ft) ; see note (1) .
AT = Average ambient temperature change from day to night
(°F) .
F = Paint factor (dimensionless) ; see Table 4.3-1.
C = Adjustment factor for. small diameter tanks
(dimensionless); see Figure 4.3-10.
K = Crude oil factor (dimensionless) ; see note (2) .
Note: (1) The vapor space in a cone roof is equivalent
in volume to a cylinder which has the same base
diameter as the cone and is one-third the
height of the cone.
39
-------
(2) KC = (0.65) for crude oil, Kc=(1.0) for gasoline
and all other liquids.
API reports that calculated breathing loss from equation (1) may
deviate -in the order of ±10 percent from actual breathing loss.
Fixed roof working losses can be estimated from:
• • L.T = 2.40 x 10-2 M P KM K (2)
W IN C
where Ly = Fixed roof working loss (lb/103 gal. throughput).
M = Molecular weight of vapor in storage tank
(Ib/lb mole); see Table 4.3-3.
P = True vapor pressure at bulk liquid conditions
(psia); see Figures 4.3-8, 4.3-9, or Table 4.3-3.
K«t = Turnover factor (dimensionless); see Figure 4.3-11.
K = Crude oil factor (dimensionless); see note.
Note: K = (0.84) for crude oil, K = (1.0) for gasoline
C C
and all other liquids.
API reports that special tank operating conditions may result in
actual losses which are significantly more, or less than the esti-
mates provided by equation (2).
The API only recommends the use of these storage loss
equations for cases in which the stored petroleum liquids exhibit
vapor pressures in the same range as gasolines. However, in the
absence of any correlation developed specifically for naphthas,
kerosenes, and fuel oils it is recommended that these storage
loss equations also be used for the storage of these heavier fuels.
The method most commonly used to control emissions from
fixed roof tanks is a vapor recovery system which collects emissions
from the storage vessels and converts them to liquid product.
40
-------
To recover vapor, one or a combination of four methods may be used
vapor/liquid absorption, vapor compression, vapor cooling, and
vapor/solid adsorption. Overall control efficiencies of vapor
recovery systems vary from 90 to 95 percent, depending on the
method used, the design of the unit, the composition of vapors
recovered, and the mechanical condition of the system.
Emissions from fixed roof tanks can also be controlled
by the addition of an internal floating cover or covered floating
roof to the existing fixed roof tank. API reports that this can
result in an average loss reduction of 90 percent of the total
evaporation loss sustained from a fixed roof tank.7
Evaporative emissions can be minimized by reducing tank
heat input with water sprays, mechanical cooling, underground
storage, tank insulation, and optimum scheduling of tank turnovers
Floating Roof Tanks1*5
Floating roof standing storage losses can be estimated
from:
o. 7
- 3
L = 9.21x10 M
p
14.7-P
D < Vw' Kt Ks Kp Kc
where: LS = Floating roof standing storage loss (Ib/day).
M = Molecular weight of vapor in storage tank
(Ib/lb mole); see Table 4.3-3.
P = True vapor pressure at bulk liquid conditions
(psia); see Figures 4.3-8, 4.3-9, or Table 4.3-3.
D = Tank diameter (ft); see note (1).
V = Average wind velocity (mi/hr) ; see note (2).
Wr
K = Tank type factor (dimensionless); see Table 4.3-2.
K = Seal factor (dimensionless); see Table 4.3-2.
s
K = Paint factor (dimensionless); see Table 4.3-2.
K = Crude oil factor (dimensionless); see note (3).
c
41
-------
Note: (1) For D>150, use D/T5T) instead of D.
(2) API correlation was derived for minimum wind
velocity of 4 mph. If YW <4 mph use V =4mph.
(3) Kc=(0.84) for crude oil, Kc=(1.0) for all
other liquids.
API reports that standing storage losses from gasoline
and crude oil storage calculated from equation (3) will not deviate
from the actual losses by more than ±25 percent for tanks in good
condition under normal operation. However, losses may exceed the
calculated amount for seals in poor condition. Although the API
only recommends the use of these correlations for petroleum liquids
exhibiting vapor pressures in the range of gasoline and crude
oils, in the absence of better correlations, these correlations
are also recommended with caution for use with heavier naphthas,
kerosenes, and fuel oils.
API has developed a correlation based on laboratory data
for calculating floating roof withdrawal loss for gasoline storage.6
Floating roof withdrawal loss for gasoline can be estimated from:
JiiA^z (4)
where: r = Floating roof gasoline withdrawal loss
(lb/103 gal throughput).
d = Density of stored liquid at bulk liquid conditions
(Ib/gal); see Table 4.3-3.
C~ = Tank construction factor (dimensionless) ;
r
see note.
D = Tank diameter (ft).
Note: Cp=(0.02) for steel tanks, CF=(1.0) for gunite
lined tanks.
-------
Equation C4) was derived from gasoline data and its applicability
to other stored liquids is uncertain. No estimate of accuracy of
equation (4) has been given,
API has not presented any correlations that specifically
pertain to internal floating covers or covered floating roofs.
Currently, API recommends the use of equations C3) and C4) with a
wind speed of 4 mph for calculating the losses from internal
floating covers and covered floating roofs.
Evaporative emissions from floating roof tanks can be
minimized by reducing tank heat input.
Variable Vapor Space Systems 1>U
Variable vapor space system filling losses can be
estimated from:
= C2. 40x10-2) ,M P
CM-CO.25 V2 N)
(5)
VT
where: Ly = Variable vapor space filling loss
-------
The accuracy of equation (5) is not documented, however,
API reports that special tank operating conditions may result in
actual losses which are significantly different from the estimates
provided by equation (5). It should also be noted that although
not developed for use with heavier petroleum liquids such as kero-
senes and fuel oils, equation (5) is recommended for use with
heavier petroleum liquids in the absence of better data.
. Evaporative emissions from variable vapor space tanks are
negligible and can be minimized by optimum scheduling of tank turn-
overs and by reducing tank heat input. Vapor recovery systems can
be used with variable vapor space systems to collect and recover
filling losses.
Vapor recovery systems capture hydrocarbon vapors dis-
placed during filling operations and recover the hydrocarbon vapors
by the use of refrigeration, absorption, adsorption, and/or com-
pression. Control efficiencies range from 90 percent to 98 percent
depending on the nature of the vapors and the applicable air quality
regulations in force.
Pressure Tanks
Pressure tanks incur vapor losses when excessive internal
pressures result in relief valve venting. In some pressure tanks
vapor venting is a design characteristic and the vented vapors must
be routed to a vapor recovery system. However, for most pressure
tanks vapor venting is not a normal occurrence and the tanks can
be considered closed systems, Fugitive losses are also associated
with pressure tanks and their equipment, but with proper system
maintenance they are insignificant. Correlations do not exist for
estimating vapor losses from pressure tanks.
-------
Emission Factors
Equations (1) through (5) can be used to estimate
evaporative losses, provided the respective parameters are known.
For those cases where such parameters are unknown, Table 4.3-4
provides emission factors for the typical systems and conditions.
It should be emphasized that these emission factors are rough
estimates at best for storage of liquids other than gasoline and
crude oil, and for storage conditions other than the ones they
are based upon. In areas where storage sources contribute a
substantial portion of the total evaporative emissions or where
they are major factor affecting the air quality, it is advisable
to obtain the necessary parameters and to calculate emission
estimates using equations (1) through (5).
Sample Calculation
Breathing losses from a fixed roof storage tank would
be calculated as follows, using equation (1).
Design basis
tank capacity - 100,000 bbl
tank diameter - 125 ft.
tank height - 46 ft.
average diurnal temperature change - 15 F
gasoline RVP - 9 psia
gasoline temperature - 70°F
specular aluminum painted tank
roof slope is 0.1 ft/ft
Fixed roof tank breathing loss equation
_0 • 6 8
T p H 1-73 0-51 0-50
Lfi = 2.21 x io"MT2rfT D H AT F C KC
-------
where
M = Molecular wt of gasoline vapors (see Table 4.3-3)=66.
P = true vapor of gasoline (see Figure 4.3-8)=5.6 psia
D = tank diameter = 125 ft.
AT = average diurnal temperature change = 15°F
F = paint factor (see Table 4.3-1) =1.20
C = tank diameter adjustment factor (see Figure 4.3-10)=1.0.
K = crude oil factor (see note for equation (1)=1.0.
H = average vapor space height. For a tank which is filled
completely and emptied, the average liquid level is
% the tank rim height, or 23 ft. The effective cone
height is 1/3 of the cone height. The roof slope is
0.1 ft/ft and the tank radius is 62.5 ft. Effective
cone height = (62.5 ft) (0.1 ft/ft) (1/3)=2.08 ft.
H = average vapor space height = 23 ft + 2 ft = 25 ft.
Therefore:
r 5.6 v
LB - 2.21 x 1.0-' (66) J14.7-5.6 J (125) '-73 (25)°-51 (15)°-50 (1. 2) (1. 0) (1.0)
LB = 1068 Ibs/day
-------
TABLE 4.3-1
PAINT FACTORS FOR FIXED ROOF TANKS3
— • ' "— • • •• — •'
Tank Color
Roof
White
Aluminum (specular)
White
Aluminum (specular)
White
Aluminum (diffuse)
White
Light gray
Medium gray
Shell
White
White
Aluminum (specular)
Aluminum (specular)
Aluminum (diffuse)
Aluminum (diffuse)
Gray
Light gray
Medium gray
Paint Factors (F )
P
Paint Condition
Good
1.00
1.04
1.16
1.20
1.30
1.39
1.30
•1.33
1.46
Poor
1.15
1.18
1.24
1.29
1.38
1.46
1.38
1.44*
1.58*
*Estimated from the ratios of the seven preceding paint factors.
-------
TABLE 4.3-2
TANK, TYPE, SEAL, AND PAINT FACTORS FOR
FLOATING ROOF TANKS3
Tank Type
Seal Type
Welded tank with pan or pontoon
roof, single or double seal. 0.045
Riveted tank with pontoon roof,
double seal. 0.11
Riveted tank with pontoon roof,
single seal. 0.13
Riveted tank with pan roof,
double seal. 0.13
Riveted tank with pan roof,
single seal. 0.14
Tight fitting (typical of modern
metallic and non-metallic seals) 1.00
Loose fitting (typical of seals
built prior to 1942).
Paint Color of Shell and Roof
Light gray or aluminum
White
1.33
1.0
0.9
-------
TABLE 4.3-3
PHYSICAL PROPERTIES OF HYDROCARBONS
Hydrocarbon
Fuels
Gasoline RVP 13
Gasoline RVP 10
Gasoline RVP 7
Crude Oil RVP 5
Jet Naphtha (JP-4)
Jet Kerosene
Distillate Fuel No. 2
Residual Oil No. 6
Petrochemicals
Acetone
Acrylonitrlle
Benzene
Carbon Disulflde
Carbon tetrachloride
Chloroform
Cyclohexane
1, 2 - Dichlorethane
Ethylacetate
Ethyl alcohol
Isopropyl alcohol
Methyl alcohol
Methylene chloride
Methyl-ethyl-ketone
Methyl-methacrylate
1, 1, 1 - Trlchloroethane
Trichloroethylene
Toluene
Vlnylacetate
Vapor
Molecular
Weight
@ 60°F
62
66
68
50
80
130
130
190
58
53
78
76
154
119
84
99
88
46
60
32
85
72
100
133
131
92
86
Product
Density (d)
Ib/gal @ 60°F
5.6
5.6
5.6
7.1
6.4
7.0
7.1
7.9
6.6
6.8
7.4
10.6
13.4
12.5
6.5
10.5
7.6
6.6
6.6
6.6
11. 1
6.7
7.9
11.2
12.3
7.3
7.8
Condensed
Vapor
Density (w)
Ib/gal @ 60°F
4.9
5.1
5.2
4.5
5.4
6,1
6.1
6.4
6.6
6.8
7.4
10.6
13.4
12.5
6.5
10.5
7.6
6.6
6.6
6.6
11.1
6.7
7.9
11.2
12.3
7.3
7.8
40°
4.7
3.4
2.3
1.8
0.8
0.0041
0.0031
0.00002
1.7
0.8
0.6
3.0
0.8
1.5
0.7
0.6
0.6
0.2
0.2
0.7
3.1
0.7
0.1
0.9
0.5
0.2
0.7
50°F
5.7
4.2
2.9
2.3
1.0
0. 0060
0.0045
0.00003
2.2
1.0
0.9
3.9
1.1
1.9
0.9
0.8
0.8
0.4
J.3
1.0
4.3
0.9
0.2
1.2
0.7
0.2
1.0
1 » 8
Vapor Pressure in psla at:
60°F 70°F 80°F
6.9
5.2
3.5
2.8
1.3
0.0085
0.0074
0.00004
2.9
1.4
1.2
4.8
1.4
2-5
1.2
1.0
1.1
0.6
0.5
1.4
5.4
1.2
0.3
1.6
0.9
0.3
1.3
8.3
6.2
4.3
3.4
1.6
0.011
0.0090
0.00006
3.7
1.8
1.5
6.0
1.8
3.2
1.6
1.4
1.5
0.9
0.7
2.0
6.8
1.5
0.5
2.0
1.2
0.4
1.7
9.9
7.4
5.2
4.0
1.9
0.015
0.012
0.00009
4.7
2.4
2.0
7.4
2.3
4.1
2.1
1.7
1.9
1.2
0.9
2.6
8.7
2.1
0.8
2.6
1.5
0.6
2.3
90°F
11.7
8.3
6.2
4.8
2.4
0.021
0.016
0.00013
5.9
3.1
2.6
9.2
3.0
5.2
2.6
2.2
2.5
1.7
1.3
3.5
10.3
2.7
1.1
3.3
2.0
0.8
3.1
100" F
13.8
10.5
7.4
5.7
2.7
0.029
0.022
0.00019
7.3
4.0
3.3
11.2
3.8
6.3
3.2
2.8
3.2
2.3
1.8
4.5
13.3
3.3
1.4
4.2
2.6
1.0
4.0
-------
TABLE 4.3-4
EVAPORATIVE EMISSION FACTORS FOR
Pi.
Fill1
1.
2.
1.
4.
5.
6.
7.
R.
Km
9.
in.
II.
12.
II.
14.
15.
Ih.
IV 1
17.
IR.
19.
20.
21 .
22.
2).
24.
25.
26.
27.
28.
29.
)0.
11.
32.
33.
34.
15.
.duel Stored
•|H - 67, (HKI hhl tank*
Cnnollnc RVf 1 1
Cn.sultnc RW 10
C.inolliip RVP 7
Crude oil RVP 5
.let n.iphtli.i (JP-4)
.lei kerosene
DlHt llt.ite fuel no. 2
ReNltlil.il till lift. 6
IN - 25n.(HM) hhl tnnkn
C.isollne RVI> 13
C.iMollne RVP 10
C.1i:.il III.- RVI' 7
Crude oil RVI' 5
Jet naphtha (JP-4)
.let kerns fnc
1)1 Ml Ill.-ile fuel tin. 2
Keril.ln.it furl no. 6
mn> HOOF
flreathlni> I.ORR
""New tank"' "Sid Link"
Condition* Conditions
Ib/day- Kg/dny- Ih/tlay- Kg/d.iy-
10' gal 10' liter 10* gal 10' liter
O.)0
0.2)
0.16
.0.064
0.086
0.0041
0.0019
O.OOOI6
0.22
0.17
0.12
0.046
0.062
O.INI1I
0.0028
n. 00012
O.016
0.078
0.019
0.0077
o.nio
0.00052
0.00047
O.OH0019
0.026
0.020
0.014
0.0055
0.00/4
0.0017
o.nnni4
0.000014
0.14
O.26
0.18
0.073
0.098
0.0049
0.0044
O.OOOI8
0.25
0.19
0.1)
0.052
0.071
0.00)5
0.0012
0. 00014
0. 04 1
0.031
0.022
O.OOB8
O.OIt
O.OO059
0.0(1053
0.000022
0.010
0.021
0.016
0.0062
0.0085
O.IHMI42
0.0(1018
O.IKKH1I7
TANK!)
STORAGE TANKS ' • *•'•*• !
FLOATING ROOF TANKS
Working
LORB
ih/lo1' g'al " ~Kg/in'r liter
throughput throughput
10.0
8.2
5.7
2.8
2.5
0.027
0.0?)
O.OOOI8
10.0
8.2
5.7
2.8
2.5
0.027
Q.02)
0.00018
1.2
0.99
0.68
0.34
0.30
0.00)2
0.0028
O.OOO022
1.2
O.99
0.68
0.34
0.30
0.00)2
0.0028
0.000022
Standing Storage I.OSB
~'~ "New" Tank" " "~ "l»Yd~ Tnnk" Will
Condi t lima Condition!! U
fhTday- Kg/d'ay- Ih/day- Kg7day-~ lb/101 gal
in' gal in' liter IO* gal 10* liter throughput
0.044
0.013
0.021
0.012
0.012
0.00054
0.00049
0.000018
0.025
0.019
0.011
0.0077
O.OO68
0.000)1
0.00(128
0.000010
n.nor>2
0.0040
0.0028
0.0014
0.0014
0.000065
0.000058
0.0000022
0.0010
0.002)
0.0016
0.0092
O.OOO82
0.0000)7
0.0000)4
o. 0000012
0.10
0.078
0.055
0.028
0.028
0.0011
O.Oflll
0.000041
0.057
O.044
0.011
0.018
0.016
O.OOO74
O.OOO68
0.000024
0.012 0.02)
0.0094 0.02)
0.0066 0.02)
0.0034
0.0034
0.00016
0.00014
0.0000052
0.0068 0.013
0.0053 0.01)
0.00)7 0.013
0.0022
0.0019
O.OOH089
O.OOO082
0.001)0029
VARIABLE VAPOR SPACE
TANKS
I0.5OO hhl
nlrnwal Filling
In/in' liter "Ih7i0r gal
throughput througlijMil
0.0028 9.6
0.0028 7.7
O.OO28 5.4
Ntit used
2.)
0.025
0.022
0.00017
O.OOI5 Not used
0.0015 N..I iiRed
O.OOI5 Not lined
Nttt uRcd
Nut used
Not lined
Not MHI'll
Nttl iiRed
Kg/Fir liter
throughput
1.2
.O..9)
0.65
Not lined
0.28
0.0(110
n.no?r.
O.OOOO2D
N.»l used
Nfll IWCll
Not URcd
Not llxcd
Nol lined
Ni.l lined
N..I lise.l
N..I used
r... lM-«lf.ilH - 67.0OO hhl tanka
Are! one
AcryltHillrlle
Benzene
Carhttn dlRiilflde
C.irhun tet rachlor Ide
Clilurnforta
Cycloliexane
1 , 2-Dlchloreth.ine
F.thyl acetate
Klliyl alcohol
Isopropyl alcohol
Hethyl alcohol
Helhylcne chloride
Helhyl-etliyl-kctone
Hetliyl •ethacrylate
I.I.I -Tr Ichloroethane
Tr Icliloroethylene
Toluene
Vinyl acetate
0.12
O.O6O
0.079
0.24
0.17
0.21
0.085
0.087
0.081
0.028
0.011
0.0)6
0.31
0.07)
0.0)8
0.17
0.11
0.0)5
0.092
0.014
0.0072
0.0094
0.029
0.021
0.025
0.010
0.010
0.010
0.0014
o.ooia
0.0044
0.017
0.0087
0.0046
0.020
0.011
0.0042
O.OII
0.14
0.068
0.090
0.28
0.20
0.24
0.096
0.10
0.095
0.0)2
0.0)6
0.042
0. )5
0.083
0.043
0.19
0.12
0.040
0. 10
0.016
0.0082
O.OII
0.011
0.024
0.029
0.012
0.012
O.OII
0.0018
0.0043
0.0050
0.042
0.0099
0.0052
O.023
O.014
0.0048
0.01)
4.0
1.8
2.2
8.8
5.2
7.1
2.4
2.4
2.)
0.66
0.72
1.1
11.0
Z.I
0.72
5.1
2.8
0.66
2.7
0.48
0.21
0.27
I.I
0.62
0.86
0.29
0.28
0.28
0.079
O.O86
O.I)
1.3
0.25
0.086
0.61
0.34
0.079
0.12
0.017
0.0084
O.OII
0.015
0.024
0.010
0.012
0.012
0.012
0.0019
O.004)
0.0051
O.O44
0.010
0.0051
0.02)
0.015
0.0048
0.01)
0.0020
0.0010
0.0011
0.0042
0.0029
o. on its
0.0014
O.OOI4
0.0014
0.00046
0.00052
O.OO06I
0.0051
0.0012
O.OO06I
0.0028
o.ooia
0.00058
0. no its
0.019
0.020
0.026
0.081
0.056
0.071
0.028
0.029
0.027
0.0091
0.010
0.012
0.10
0.024
0.012
0.055
0.015
0.011
0.010
0.0047
0.0024
O.Oflll
O.O099
O.OO69
0.0085
0.0034
O.O034
0.00)1
0.0011
0.0012
0.0014
0.012
O.O029
0.0015
0.0066
0.0042
0.0014
0.00)7
1.8
1.7
2.1
8.2
4.8
6.7
2.)
2.2
2.2
0.62
0.68
"l.O
10.0
1.9
0.68
4.8
2.6
0.62
2.5
(1.45
(1.211
0.25
0.'»8
0.58
0.80
0.27
0.27
O.26
0.074
0.082
0.12
1.2
6.21
0.082
0.58
0.11
0.074
O.10.
F.»lRRlnn fnctorn KiNf^d on thr following pMrmMnteriv:
Aiiiblrnt condl t lonn :
Slor.ip.p ti^tipcriiturr: 6O°F (I5.6nc).
pnlly jmhlcnt toviperAtnre chnnge: 15 F (8.1 C).
Wind velocity: 10 al/hr (4.5 a/Rer).
Typlritl. fixed roof tankR!
(hitnge: 50 percent of Link height.
Ttirnovcrn per year (N): 1O for crude; 1) for
all other liquid*.
fnlnt fnr.tor (F ): New tnnk-uhlte palnt-I.OO;
P Old l»uk-w1iltp/nliK.lnin. palnt-1.14.
For 67.OOO hhl tnnk.ige (10.7 > 10 liter)
llrlght: 48 ft (14.h.)
Dlfliieter: IIO ft (11.5i>)
For 250.000 bhl tnnlcip.r (19.7 K in* liter)
lli'lr.lil - '.'• II (ll.'iinl
Diameter: 200 ft (60.8m)
RwlRRlon factorR hiined on the following paraBrterfi:
Typlr.il flout Ing roof l«nkR!
Flint factor (K >: New tnnk-whlte |">lnl-O.09O;
P Old tnnkrwhlte/aliuilniiB pnlnl-0.95.
Se.il factor (K ): New tnnk-nndern Reals-I.OO;
* Old t«nk-5O percent old cealn-l.14.
Tank type factor (Kt): New tank-weltfed-0.045;
• •Id litok-'ill p.-rcrol rlveted'O.OoH.
Typical v.irlahle Rpace Link:
Dimeter: 50 ft (I5.2ti)
llelglil : 10 ft (9.1.)
Cnpnclty: IO.50nhl>l (1.67 « IO liter)
Turnowera per year (N): 6
VO|IMM> eKp.inRloH capacity: one fourth of llqnld
capacity • 2<>25 hhl (0.42 x 10 I).
-------
UJ
I-
o
z
c
UJ
OL
*>
O
UJ
K
0)
o
a.
in
3
— C.20
— 0.30
— 0.4O
0.30
0.60
0.70
0.80
0.9O
1.00
1.30
2.00
2.30
3.00
3.30
4.0O
— 5.00
E- 7.00
r- a.oo
,1 0
K
-------
UJ
t-
o
z
(T
I
in
cr
UJ
0.
V)
O
1
LJ
cr
tc
a.
e
o
a.
UJ
9
10
I I
12
13
14-
IS
UJ
C
m
tr
a.
ec
o
a.
,— 2
-3
4
5
— 10
15
140 —a
. -3
3
130 —=
.20-1
I 10 -=
—*
I 00 —1
UJ
"1 5
90 -3 §
-3 •*•
80
-I £
20
* s
70 -g °
E 5
60 —5 S
J 5
g K
50 -| £
= S
-— UJ
=• h-
•|
30 -|
20 -i
10 —=
0 -
FIGURE 4.3-9. VAPOR PRESSURES OF CRUDE OIL
52
-------
1.00
o
u.
K
UJ
2
CO
AD
bo
o
en
o
A.
o
to
o
10 20 30
TANK DIAMETER IN FEET
FIGURE 4.3-10. ADJUSTMENT FACTOR (C) FOR SMALL DIAMETER TANKS
a
o
h-
O
1.0
0.8
0.6
g 0.4
>
O
2- 0.2
NOTE: FOR 36 TURNOVERS PER
YEAR OR LESS. KN -1.0
100
200 300 400
TURNOVERS PER YEAR "
ANNUAL THROUGHPUT
TANK CAPACITY
FIGURE 4.3-11. TURNOVER FACTOR (KN) FOR FIXED ROOF TANKS
53
-------
REFERENCES
SECTION 4.3
1. American Petroleum Inst., Div. of Refining, Petrochemical
Evaporation Loss From Storage Tanks, API Bull. 2523, N.Y.,
. 1969.
2. American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss In The Petroleum Industry, Causes and Control,
API Bull. 2513, Washington, D.C. 1959.
3. American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss From Fixed-Roof Tanks, Bull. 2518,
Washington, D.C., 1962.
4. American Fetroleum Inst., Evaporation Loss Committee,
Use Of Variable Vapor-Space Systems To Reduce Evaporation Loss,
loss, Bull. 2520, N.Y., N.Y., 1964.
5. American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss From Floating-roof Tanks, Bull. 2517,
Washington, D.C., 1962.
6. American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss From Low-Pressure Tanks, Bull. 2516,
Washington, D.C., 1962.
7. American Petroleum Inst., Evaporation Loss Committee,
Use Of Internal Floating Covers For Fixed-Roof Tanks To
Reduce Evaporation Loss, Bull. 2519, Washington, D.C., 1962.
8. Barnett, Henry C., et al., Properties Of Aircraft Fuels,
NACATN 3276, Cleveland, Ohio, Lewis Flight Propulsion Lab.
August, 1956.
-------
. REFERENCES
SECTION 4.3
Continued
9. Bridgeman, Oscar C, and Elizabeth W. Aldrich, Some Phases
Of The Problem Of Evaluating Evaporation Losses From Petroleum
Products By Means Of Vapor Volume Measurements. Report 128855R,
Bartlesville, Oklahoma, Phillips Petroleum Company, undated.
10. Environmental Protection Agency, Compilation Of Air
Pollutant Emission Factors, 2nd ed. with supplements, AP-42,
Research Triangle Park, N.C,, 1973,
55
-------
ATTACHMENT B
TRANSPORTATION AND LOADING LOSSES
57
-------
4.4 TRANSPORTATION AND MARKETING OF PETROLEUM LIQUIDS
4.4.1 Process Description
As Figure 4.4-1 indicates, the transportation and mar-
keting of petroleum liquids involves many distinct operations,
each of which represents a potential source of hydrocarbon evap-
oration loss. Crude oil is transported from production operations
to the refinery via tankers, barges, tank cars, tank trucks, and
pipelines. In the.same manner refined petroleum products are
conveyed to fuel marketing terminals and petrochemical industries
by tankers, barges, tank cars, tank trucks, and pipelines. From
the fuel marketing terminals the fuels are delivered via tank
trucks to service stations, commercial accounts, and local bulk
storage plants. The final destination for gasoline is normally
a motor vehicle gasoline tank. A similar distribution path may
also be developed for fuel oils and other petroleum products.
4.4.2 Emissions and Controls
Evaporative hydrocarbon emissions from the transportation
and marketing of petroleum liquids may be separated into four cat-
egories, depending on the storage equipment and mode of transpor-
tation used:
1. Large storage tanks: Breathing, working,
and standing storage losses,
2. Marine vessels, tank cars, and tank trucks:
Loading and transit losses,
3. Service stations: Bulk fuel drop losses and
underground tank breathing losses, and,
4. Motor vehicle tanks: Refueling losses.
58
-------
ID
CJ
"B
3
**
o'
3
O
00
o
c
PRODUCT
STORAGE
TANKS
CRUDE OIL PRODUCTION
MARKETING
TERMINAL
STORAGE
TANKS
TANK TRUCK , ,
TANK CAR
PETROCHEMICALS
BULK
PLANT
STORAGE
TANKS
TANK TRUCK
1
COMMERCIAL
ACCOUNTS'
STORAGE
TANKS
SERVICE
STATIONS
AUTOMOBILES
AND
OTHER MOTOR
VEHICLES
Figure 4.4-1. Flowsheet of petroleum production, refining, and distribution systems.
(Sources of organic evaporative emissions are indicated by vertical arrows).
-------
(In addition, evaporates and exhaust emissions are also associated
with motor vehicle operation. These topics are discussed in
Chapter 3).
Large Storage Tanks
Losses from storage tanks have been thoroughly discussed
in Section 4.3
Marine Vessels, Tank Cars, Tank Trucks
Loading losses are the primary source of evaporative
hydrocarbon emissions from marine vessel, tank car, and tank truck
operations. Loading losses occur as hydrocarbon vapors residing
in empty cargo tanks are displaced to the atmosphere by the liquid
being loaded into the cargo tanks. The hydrocarbon vapors dis-
placed from the cargo tanks are a composite of (1) hydrocarbon
vapors formed in the empty tank by evaporation of residual
product from previous hauls and (2) hydrocarbon vapors generated
in the tank as the new product is being loaded. The quantity of
hydrocarbon losses from loading operations is, therefore, a function
of the following parameters:
• Physical and chemical characteristics of the previous
cargo,
• Method of unloading the previous cargo,
• Operations during the transport of the empty carrier
to the loading terminal,
• Method of loading the new cargo, and
• Physical and chemical characteristics of the new cargo.
The two basic methods of loading cargo carriers are
presented in Figures 4,4-2, 4,4-3, and 4.4-4. In the splash
loading method, the fill pipe dispensing the cargo is only
60
-------
-FIL pipe
VAPOR
ATCH COVER
CARGO TANK
FIGURE 4.4-a SPLASH LOADING METHOD
VAPOR EMISSIONS
FILL PIPE
HATCH COVER
CARGO TANK
FIGURE 4.4-3 SUBMERGED FILL PIPE
VAPOR VENT
TO RECOVERY
OR ATMOSPHERE
HATCH CLOSED
\
\
VAPORS
FIGURE 4.4-4 BOTTOM LOADING
CARGO TANK
I FILL PIPE
61
-------
partially lowered into the cargo tank. Significant turbulence
and vapor-liquid contacting occurs during the splash loading
operation, resulting in high levels of vapor generation and loss.
If the turbulence is high enough, liquid droplets will be
entrained in the vented vapors.
A second method of loading is submerged loading. The
two types of submerged loading are the submerged fill pipe method
and the bottom loading method. In the submerged fill pipe method,
the fill pipe descends almost to the bottom of the cargo tank.
In the bottom loading method, the fill pipe enters the cargo tank
from the bottom. During the major portion of both forms of sub-
merged loading methods, the fill pipe opening is positioned below
the liquid level. The submerged loading method significantly reduces
liquid turbulence and vapor-liquid contacting, thereby resulting in
much lower hydrocarbon losses than encountered during splash loading
methods.
The history of a cargo carrier is just as important
a factor in loading losses as the method of loading. Hydrocarbon
emissions are generally lowest from a clean cargo carrier whose
cargo tanks are free from vapors prior to loading. Clean cargo
tanks normally result from either carrying a non-volatile liquid
such as heavy fuel oils in the previous haul, or from cleaning or
venting the empty cargo tank prior to loading operations. A fully
ballasted tanker compartment will also be relatively free from
hydrocarbon vapors.
In normal dedicated service, a cargo carrier is dedicated
to the transport of only one product and does not clean or vent its
tanks between trips. An empty cargo tank in normal dedicated
service will retain a low but significant concentration of vapors
which were generated by evaporation of residual product on the
tank surfaces. These residual vapors are expelled along with newly
generated vapors during the subsequent loading operation.
62
-------
A third type of cargo carrier is one in dedicated
balance service. Cargo carriers in dedicated balance service
pick up vapors displaced during unloading operations and trans-
port these vapors in the empty cargo tanks back to the loading
terminal. Figure 4.4-5 shows a tank truck in dedicated vapor
balance service unloading gasoline to an underground service
station tank and filling up with displaced gasoline vapors to be
.returned to the truck loading terminal. The vapors in an empty
cargo carrier in dedicated balance service are normally saturated
with hydrocarbons.
Emissions from loading hydrocarbon liquids can be esti-
mated (within 30 percent) using the following expression:
, 10 ,,- SPM
L, = 12.46 —rrr-
J-J i.
(1)
where:
LL = loading loss, lb/103 gal of liquid loaded.
M = molecular weight of vapors, Ib/lb-mole (see Table 4.3-3).
P = true vapor pressure of liquid loaded, psia (see
Figures 4.3-8 and 4.3-9, and Table 4.3-3).
T = bulk temperature of liquid loaded, °R.
S = a saturation factor (see Table 4.4-1).
The saturation factor (S) represents the expelled vapor's frac-
tional approach to saturation and accounts for the variations
observed in emission rates from the different unloading and load-
ing methods. Table 4.4-1 lists suggested saturation factors (S).
The API has recently developed a separate set of factors
for calculating the hydrocarbon emission rate from loading gasoline
onto marine tankers and barges. These factors are presented in
Table 4.4-2 and should be used instead of equation (1) for gasoline
loading operations at marine terminals.
63
-------
VAPOR VENT LINE
MANIFOLD FOR RETURNING VAPORS
TRUCK STORAGE\
COMPARTMENTS
f\ .\
j\\\\\\\\\\\\\/'r/'fi'
UNDERGROUND
STORAGE
i* TANK
FIGURE 4.4-5 TANKTRUCK UNLOADING INTO AN UNDERGROUND
SERVICE STATION STORAGE TANK. TANKTRUCK
IS PRACTICING " VAPOR BALANCE " FORM OF
VAPOR CONTROL.
-------
TABLE 4.4-1
S FACTORS FOR CALCULATING LOADING LOSSES1
Tank Trucks and Tank Cars _S
submerged loading of a clean cargo tank 0.50
splash loading of a clean cargo tank 1.45
submerged loading - normal dedicated
service 0.60
splash loading - normal dedicated
service 1.45
submerged loading - dedicated, vapor
balance service 1.0
splash loading - dedicated, vapor balance
service 1.0
Marine Vessels*
submerged loading 0.20
*To be used for products other than gasoline.
Use factors from Table 4.4-2 for marine loading of gasoline
65
-------
An additional emission source associated with marine
vessel, tank car, and tank truck operations is transit losses.
During the transportation of petroleum liquids small quantities
of hydrocarbon vapors are expelled from cargo tanks due to tem-
perature and barometric pressure changes. The most significant
transit loss is from tanker and barge operations and can be cal-
culated using equation (2).l
LT = 0.1 PW (2)
where:
LT = transit loss, lb/week-103 gal transported.
P = true vapor pressure of the transported liquid,
psia (see Figures 4.3-8 and 4.3-9, and Table 4.3-3).
W = density of the condensed vapors, Ib/gal (see Table 4.3-3).
In the absence of specific inputs for equations (1) and (2)
typical evaporative hydrocarbon emissions from loading operations
are presented in Table 4.4-2. It should be noted that
although the crude oil used to calculate the emission values
presented in Table 4.4-2 has an RVP of 5, the RVP of crude oils
can range over two orders of magnitude. In areas where loading
and transportation sources are a major factor affecting the air
quality, it is advisable to obtain the necessary parameters
and to calculate emission estimates from equations (1) and (2).
Control measures for reducing loading emissions include
the application of alternate loading methods producing lower
emissions, and the application of vapor recovery equipment. Vapor
recovery equipment captures hydrocarbon vapors displaced during
loading operations and recovers the hydrocarbon vapors by the use of
refrigeration, absorption, adsorption, and/or compression. Figure
4.4-6 demonstrates the recovery of gasoline vapors from tank trucks
66
-------
TABLE 4.4-2
ORGANIC COMPOUND EVAPORATIVE EMISSION FACTORS FOR UNCONTROLLED PETROLEUM
TRANSPORTATION AND' MARKETING SOURCES
PRODUCT
EMISSION SOURCES
Tank cars/trucks
submerged load ing- normal service
lb/103 gal transferred
Kg/103 liter transferred
splash loading-normal service
lb/103 gal transferred
Kg/103 liter transferred
submerged loading-balance service
3 gal transferred
lb/10
Kg/103
liter transferred
splash loading-balance service
lb/103 gal transferred
Kg/103 liter transferred
Marine Vessels
loading- general
lb/103 gal transferred
Kg/103 liter transferred
loading-cle.in ships
lb/103 gal transferred
Kg/103 liter transferred
loading-dirty ships
lb/103 gal transferred
Kg/103 liter transferred
loading-clean barges
lb/103 gal transferred
Kg/103 liter transferred
loading-dirty barges
lb/103 gal transferred
Kg/103 liter transferred
transit
lb/week-103 gal transported
. Kg/week- 103 liter transported
Jet ""
Crude Naphtha Jet Distillate Residual
Gasoline Oil (JP-4) Kerosene Oil Oil
No. 2 JJo J>
5
0.6
12
1.4
8
1.0
8
1.0
1.3
0.16
1
\
2.5
0.30
1.2
0.14
3.8
0.46
, 3
: 0.4
3
C.4
7
0.8
5
0.6
5
0.6
1.0
0.1
1
0.1
1.5
0.18
4
0.5
2.5
0.3
2.5
0.3
0.5
0.06
0.7
0.08
0.02
0.002
0.04
0.005
*
*
0.02
0.001
0.02
0.002
0.01
0.001
0.03
0.004
*
*
0.005
0.0006
0.005
0.0006
0.0001
0.00001
0.0003
0.00004
*
*
0.00004
5xlO~ 6
3x10" 5
! 4xlO~6
i
1. Emission factors are calculated for a dispensed fuel temperature of 60°F.
2. The example gasoline has an RVP of 10 psia.
3. The example crude oil has an RVP of 5 psia.
A Not normally used. 67
-------
VAPOR RETURN LINE
co
TRUCK V
STORAGE x
COMPART-
MENTS
VAPOR FREE
AIR VENTED
TO
ATMOSPHERE
VAPOR
RECOVERY
UNIT
PRODUCT FROM
LOADING TERMINAL
STORAGE TANK
FIGURE 4.4-6 TANKTRUCK LOADING WITH VAPOR RECOVERY
-------
during loading operation at bulk terminals. Control efficiencies
range from 90 percent to 98 percent depending on the nature of the
vapors and the applicable air quality regulations in force.2
Emissions from controlled loading operations can be
calculated by multiplying the uncontrolled emission rate calculated
in equations (1) and (2) by the control efficiency term:
|l - efficiency
Sample Calculation
Loading losses from a gasoline tank truck in dedicated
balance service and practicing vapor recovery would be calculated
as follows using equation (1) .
Design basis :
Tank truck volume is 8000 gallons
Gasoline RVP is 9 psia
Dispensing temperature is 80°F
Vapor recovery efficiency is 95%
Loading loss equation:
T , 0 ., SPM .,,
LL = 12.46 -jr- (1-
where :
S = saturation factor (see Table 4.4-1) =1.0
P = true vapor pressure of gasoline (see Figure 4.3-8) = 5.6 psia
M = Molecular weight of gasoline vapors (see Table 4. 3-3) =66
T = temperature of gasoline = 540°R
eff = the control efficiency = 95%
69
-------
T - 19 Lf> d.0)(5.6)(66) n 95
LL ' 12'46 - - (1-
= 0.43 lbs/103 gal
Total .loading losses are
(0.43 Ib/103gal)(8.0xl03 gal) = 3.4 Ibs of hydrocarbon
Service Stations
Another major source of evaporative hydrocarbon emis-
sions is the filling of underground gasoline storage tanks at
service stations. Normally, gasoline is delivered to service
stations in large (8000 gallon) tank trucks. Emissions are
generated when hydrocarbon vapors in the underground storage tank
are displaced to the atmosphere by the gasoline being loaded into
the tank. As with other loading losses, the quantity of the
service station tank loading loss depends on several variables
including the size and length of the fill pipe( the method of
filling, the tank configuration, and the gasoline temperature,
vapor pressure, and composition. An average hydrocarbon emission
rate for submerged filling is 7.3 lbs/103 gallons of transferred
gasoline and for splash filling is 11.5 lbs/103 gallons of trans-
ferred gasoline.2
Emissions from underground tank filling operations at
service stations can be reduced by the use of the vapor balance
system (Figure 4.4-5). The vapor balance system employs a vapor
return hose which returns gasoline vapors displaced from the
underground tank to the tank truck storage compartments being
emptied. The control efficiency of the balance system ranges
from 93 to 100 percent. Hydrocarbon emissions from underground
70
-------
tank filling operations at a service station employing the vapor
balance system and submerged filling are not expected to exceed
0.3 lbs/103 gallons of transferred gasoline.
A second source of hydrocarbon emissions from service
stations is underground tank breathing. Breathing losses occur
daily and are attributed to temperature changes, barometric pres-
sure changes, and gasoline evaporation. The type of service
station operation also has a large impact on breathing losses.
An. average breathing emission rate is 1 lb/103 gallons through-
put. 2
Motor Vehicle Refueling
An additional source of evaporative hydrocarbon emissions
at service stations is vehicle refueling operations. Vehicle
refueling emissions are attributable to vapors displaced from the
automobile tank by dispensed gasoline and to spillage. The
quantity of displaced vapors is dependent on gasoline temperature,
auto tank temperature, gasoline RVP, and dispensing rates. Although
several correlations have been developed to estimate losses due to
displaced vapors, significant controversy exists concerning these
correlations. It is estimated that the hydrocarbon emissions due
to vapors displaced during vehicle refueling averages 9 lbs/103
gallons of dispensed gasoline.2
The quantity of spillage loss is a function of the
type of service station, vehicle tank configuration, operator
technique, and operation discomfort indices. An overall average
spillage loss is 0.7 lb/103 gallons of dispensed gasoline.1*
Control methods for vehicle refueling emissions are
based on conveying the vapors displaced from the vehicle fuel tank
71
-------
to the underground storage tank vapor space through the use
of a special hose and nozzle (Figure 4.4-7). In the "balance"
vapor control system the vapors are conveyed by natural pressure
differentials established during refueling. In "vacuum assist"
vapor control systems the conveyance of vapors from the auto fuel
tank to the underground fuel tank is assisted by a vacuum pump.
The overall control efficiency of vapor control systems for
vehicle refueling emissions is estimated to be 88 to 92 percent.2
72
-------
TABLE 4.4-3
HYDROCARBON EMISSIONS FROM GASOLINE SERVICE STATION OPERATIONS
Emission Rate
Emission Source lb/103 gal throughput kg/103 liter throughput
Filling Underground Tank
Submerged filling 7.3 0.88
Splash filling 11.5 1.38
Balanced submerged filling 0.3 0.04
Underground Tank Breathing 1 0.12
Vehicle Refueling Operations
Displacement losses
(uncontrolled) 9 1.08
Displacement losses 0.9 0.11
(controlled)
Spillage 0.7 0.084
73
-------
FIGURE 4.4-7
AUTOMOBILE REFUELING VAPOR-RECOVERY SYSTEM
SERVICE
STATION
PUMP
RETURNED VAPORS
U DISPENSED GASOLINE
-------
REFERENCES
SECTION 4.4
1. American Petroleum Inst., Evaporation Loss Committee,
Evaporation Loss From Tank Cars, Tank Trucks. And Marine
Vessels, Bull. 2514, Washington, B.C. 1959.
2. Burklin, Clinton E., et al. Study Of Vapor Control Methods
For Gasoline Marketing Operations, 2 vols., Austin, Texas,
Radian Corporation, May 1975.
3. Scott Research Laboratories, Inc., Investigation Of
Passenger Car Refueling Losses, Final Report, 2nd year
program, CPA 22-69-69. APRAC Project No. Cape 9-68.
4. Scott Research Laboratories, Inc., Mathematical Expressions
Relating Evaporative Emissions From Motor Vehicles To
Gasoline Volatility, summary report, API Publication 4077,
Plumsteadville, Pennsylvania, March 1971.
75
-------
ATTACHMENT C
REFINERY LOSSES
77
-------
Table 9.1-1. EMISSION FACTORS FOR PETROLEUM REFINERY PROCESSES
EMISSION FACTOR RATING: A
, Type of Process
Boilers and process heaters
lb/103 bbl oil burned
kg/103 liters oil burned
lb/103 ft3 gas burned
kg/10 m3 gas burned
Fluid catalytic cracking
e
j units
i
Uncontrolled
lb/103 bbl fresh feed
kg/103 liters fresh feed
Electrostatic precipitator
and CO boiler
lb/103 bbl fresh feed
kg/10 liters fresh feed
Particulates
840
2.4
0.02
0.32
242
(93 to 340)
0.695
(0.267 to 0.976)
44.7
(12.5 to 61.0)
0.128
(0.036 to 0.175)
Sulfur
oxides
(S02)
6,720Sb
19. 2S
28d
32s
493
(313 to 525)
1.413
(0.898 to 1.505)
493
(313 to 525)
1.413
(0.898 to 1.505)
Carbon
monoxide
NegC
Neg
Neg
Neg
13,700
39.2
Neg
Neg
Hydro-
carbons
140
0.4
0,03
0.48
220
0.630
220
0.630
Nitrogen
oxides
(N02)
2,900
8.3
0.23
3.7
71.0
(31.1 to 145.0)
0.204
(0.107 to 0.416)
71.0
(37.1 to 145.0)
0.204
(0.107 to 0.416)
Alde-
hydes
25
0.071
0.003
0.048
19
0.054
19
0.054
Ammonia
Neg
Neg
Neg
Neg
54
0.155
54
0.155
CO
-------
Sulfur Nitrogen
oxides Carbon Hydro- oxides Aide-
Type of process Particulates (S02) monoxide carbons (N02) hydes Ammonia
Moving-bed catalytic
a
cracking units
lb/103 bbl fresh
feed
kg/103 liters fresh
feed
g
Fluid coking units
Uncontrolled
lb/103 bbl fresh feed
kg/103 liters fresh feed
Electosr.atic precipitator
lb/103 bbl fresh feed
•g kg/103 liters fresh feed
Compressor internal combustion
a
engines
lb/103 ft3 gas burned
kg/103 m3 gas burned
17
0.049
523
1.50
6.85
0.0196
Neg
Neg
60
0.171
NAh
NA
NA
NA
2s
32s
3,800
10.8
Neg
Neg
Ncg
Neg
Neg
Neg
87
0.250
Neg
Neg
Ncg
Neg
1.2
19.3
5
0.014
Neg
Neg
Ncg
Neg
0.9
14.4
12
0.034
-
Neg
Neg
iJcg
Neg
0.1
1.61
.
6
0.017
Neg
Neg
Nc-
Neg
0.2
3.2
Reference 1.
bS = Fuel oil sulfur content (weight percent): factors based on 100 percent combustion of sulfur to S02 and assumed
density of 336 Ib/bbl (0.96 kg/liter).
°Neglibigle emission.
ds = refinery gas sulfur content (lb/100 f t"*): factors based on 100 percent combustion of sulfur to S02.
References 1 through 6.
Numbers in parenthesis indicate range of values observed.
a
^Reference 3.
-------
Table 9,1-2. EMISSION FACTORS FOR PETROLEUM REFINERY EVAPORATIVE SOURCES
EMISSION FACTOR RATING A
Process Type
Uncontrolled
Emissions
Controlled
Emissions
Method of Control
Slowdown Systems
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
Process Drains & Wastewater
Separators
lb/103 gal wastewater
kg/103 liters wastewater
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
300
0.86
5
0.60
200
0.57
5
0.014
0.2
0.024
10
0 029
Vapor recovery system
or flaring.
Vapor recovery systems
and/or separator covers.
Vacuum Jets
lb/103 bbl of vacuum charge
kg/103 liters of vacuum charge
lb/103 bbl of refinery capacity
kg/10 liters of refinery capacity
130
0.37
60
0.17
Neg
Neg
Neg
Neg
Fume burner, waste heat
boiler, vapor recovery,
change to vacuum pumps,
surface condenser.
Cooling Towers
lb/106 gal cooling water
lb/106 liters cooling water
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
6
0.72
18
0.051
3
0.36
10
0.029
Good housekeeping and
maintenance.
Pipeline Valves and Flanges
Ib/day-valve
kg/day-valve
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
0.15
0.068
28
0.080
NA
NA
NA
NA
Good housekeeping and
maintenance.
80
-------
Table 9.1-2 (continued)
Process Type
Uncontrolled
Emissions
Controlled
Emissions
Method of Control
Vessel Relief Valves
Ib/day-valve
kg/day-valve
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
2.4
1.1
11
0.031
Neg-
Neg
Neg
Neg
Rupture discs up stream
of relief valve.
Pump Seals
Ib/day-seal
kg/day-seal
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
5
2.3
17
0.049
3
1.4
10
0.029
Mechanical seals, dual
seals, purged seals.
Compressor Seals
Ib/day-seal
kg/day-seal
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
9
4.1
5
0.014
NA
NA
NA
NA
Mechanical seals, dual
seals, purged seals.
Asphalt Blowing
Ib/Ton of asphalt
kg/MT of asphalt
60
30
Neg
Neg
Scrubbing, incineration.
Blind Changing
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
0.3
0.001
Neg
Neg
Line flushing, use of
"line" blinds, blind
insulation w/gate valves
Sampling
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
2.3
0.007
Neg
Neg
Avoid excessive sample
purge, flush sample
purge to sump.
81
-------
Table 9.1-2 (continued)
Process Type
Uncontrolled
Emissions
Controlled
Emissions
Method of Control
Other
lb/103 bbl refinery capacity
kg/103 liters refinery capacity
7
0.020
NA
NA
Good Housekeeping and
maintenance.
NA Emission factors for these sources are not available.
References:
Atmospheric Emissions from Petroleum Refineries.
A Guide for Measurement
and Control. PHS No. 763. Washington, D.C., Public Health Service, 1960.
Burklin, C.E., et al., Control of Hydrocarbon Emissions from Petroleum
Liquids. Contract No. 68-02-1319, Task 12, EPA 600/2-75-052. PB 246 65Q/ST.
Austin, Texas, Radian Corporation, Sept. 1975.
82
-------
ATTACHMENT D
PRODUCTION LOSSES
83
-------
9.3 OIL AND GAS PRODUCTION
The oil and gas production industry is involved in
locating and retrieving oil and gas from underground formations
and preparing the well streams for use by consumers or refiners.
Production activities begin with exploration and end with storage
or sales.
The oil and gas production industry comprises five
segments:
1) Exploration and Site Preparation - This
segment includes those operations necessary
for selection and preparation of a drilling
site.
2) Drilling - The drilling segment is comprised
of all operations involved in digging a well
and preparing it for production.
3) Crude Processing - Several process modules
are described for preparing crude for
refinery use.
4) Natural Gas Processing - This segment includes
widely used processes for preparing natural
gas for sales.
5) Secondary or Tertiary Recovery - Methods for
stimulating well production are included in
this segment.
-------
Figure 9.3-1 is a schematic representation of the industry
segments and their interrelationships.
An attempt has been made to present processing steps
and their emissions in sequence. The problem encountered in the
crude processing and natural gas processing segments is the
diversity of the operations involved. The sequences of processing
steps are not at all the same from place to place; moreover, some
processes may be absent and additional processes present to deal
with the local conditions and composition of the production.
Production process descriptions are further complicated because
oil wells often produce significant quantities of natural gas and
conversely some gas wells produce significant quantities of crude
oils. This emission section cannot be considered an all-encom-
passing survey, but only a summary of the evaporative hydrocarbon
emissions associated with some of the most commonly used methods
in domestic oil and gas production.
9.3.1 Exploration and Site Preparation
The objective of oil exploration procedures is defining
and describing geological structures which are often associated
with oil accumulation in the earth's crust. Geological surveys
of the surface are made using aerial photographs, satellite photo-
graphs, and mappings of surface outcrops. Offshore geological
surveys include mapping of the ocean bottom using acoustic sounding
methods. Subsurface geological surveys are made by seismic and
gravimetric methods which yield indications of the depth and
nature of subsurface rock.
Site preparation activities include those operations
necessary, to prepare the drilling site and "rig-up" the equipment.
The operations are necessarily different for onshore and offshore
85
-------
00
ffi
EXPLORATION
AND SITE
PREPARATION
DRILLING
CRUDE
PROCESSING
SECONDARY
OR TERTIARY
RECOVERY
NATURAL GAS
PROCESSING
FIGURE 9.3-1. THE OIL AND GAS PRODUCTION INDUSTRY
-------
locations, and will be dictated somewhat by local conditions.
For land operations earth-moving machinery clears, grades, and
levels the site. Earthen pits are dug for circulating fluids and
wastes, and access roads are built and surfaced. Water wells are
dug, and .the drilling rig and associated machinery are installed.
Preparations for offshore drilling differ widely because of the
many types of rigs available. The .drilling rigs may be floating
or fixed in place on the ocean floor. In all cases the pumps,
pipelines, and machinery must be installed and in the case of
submersible rigs, the platform must be settled firmly on the
bottom.
No significant sources of evaporative hydrocarbon emis-
sions are associated with exploration and site preparation seg-
gents of the oil and gas production industry. There is a very
minimal danger of hydrocarbon emissions due to a blowout during
core drilling operations when a shallow pocket of high pressure
oil or gas is encountered.
9.3.2 Drilling
Drilling is the process of actually cutting through the
earth's crust to form a well and is accomplished by rotating and
hoisting operations performed at the derrick. The cutting and
grinding through the earth's surface is accomplished by rotating
the drill string with the required weight on the drill bit
affixed to the end of the drill string. Additional lengths of
drill pipe are attached as the drilling proceeds. When a worn
drill bit has to be replaced, the entire string of pipe must be
hoisted. The pipe lengths are removed as the string is slowly
raised until the drill bit is brought to the surface and changed
out. The new bit and the drill string are slowly lowered, and
the lengths of pipe are replaced until the bottom is reached,
at which time rotation begins again. The drill bit is designed
87
-------
to break, dislodge, and fragment formation material. A drilling
fluid (rnud) is circulated down to the drill bit through the string
for the purpose of transporting formation cuttings to the surface
for disposal.
Hydrocarbon emissions associated with drilling operations
are attributable to oil and gas brought to the surface with drilling
.mud. Oil brought to the surface is separated and generally dis-
posed of in open pits or pumped into barges for onshore disposal.
Excess oil based muds are treated in the same manner. At any
point that the oil is open to the air, atmospheric emissions re-
sult. Hydrocarbon gas brought to the surface with drilling fluid
is separated from the mud and may be vented or flared at a safe
distance from the drilling operations. The magnitude of hydro-
carbon emissions released from production operations is dependent
on product volatility, method of handling and concentration of
hydrpcarbons returning with the mud. Estimates of these emissions
are not available.
9.3.3 Crude Oil Production
The crude oil production industry is involved in
locating and retrieving oil from underground formations and pre-
paring the well streams for use by refiners. Crude oil production
can be divided into four major steps: (1) extraction, (2) well
production gathering, (3) field processing, and (4) storage or
sales. These four major steps are applicable to onshore and
offshore production operations.
Extraction involves bringing the oil to the surface
by natural flow, gas lifting, or pumping. The production from
each well is then sent to a complex gathering system to combine
all of the production or to separate the individual well pro-
auctions. Field processing removes water and/or solids and/or
88
-------
gas from the produced oil. Storage at the production site or
sale of the crude oil via pipeline, truck, rail, barge, or tanker
marks the end of production activities. Figure 9.3-2 gives a
schematic flow diagram of the crude oil production industry. All
phases of crude oil production involve potential sources of
evaporative hydrocarbon emissions.
Extraction
In natural flow production the bottom hole oil reservoir
pressure is sufficient to overcome gravity and pressure drop,
and the produced oil flows into the gathering system without
energy input. Gas lifting is accomplished by injecting gas into
the downhole production tubing at various depths in order to
assist oil flow to the surface.. Most producing oil wells require
pumping by mechanical lifting methods using subsurface pumps.
The most commonly used pump is the reciprocating sucker rod pump.
Electric or hydraulic bo.ttomhole centrifugal pumps may also be
used.
The primary source of emissions from extraction operations
is the evaporation of crude oil which leaks from reciprocating
pump rod seals at the wellhead. This source is absent from natural
flow and gas lift operations. Fugitive emissions may occur in
gas lifting or gas injection operations if leaks develop in the
gas compression and piping system. Emissions from extraction
operations can be minimized by proper maintenance of operating
equipment and the use of double pump seals.
Well Production Gathering
The produced crude oil enters the production gathering
system at the wellhead. The production from wells in the same
area is collected and transported to the crude processing units
89
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OIL WELLS
CRUDE-
°™DEE
EMULSION
PRODUCTION
GATHERING
SYSTEM
EMULSION
BREAKING
VO
O
WASTE WATER
DISPOSAL
r
I
I
QAS
WATER
KNOCK-OUT
CRUDE
OIL
1
TO.GAS
TREATING
GAS-OIL
SEPARATION
I
I »
CRUDE
OIL
WASTE WATER
SEPARATION
STORAGE
AND SALES
FIGURE 9.3-2. FLOWSHEET OF PETROLEUM PRODUCTION OPERATIONS.
(SOURCES OF EVAPORATIVE HYDROCARBON
EMISSIONS ARE INDICATED BY VERTICAL ARROWS).
-------
by a system of pipes, valves, fittings, pumps, and meters.
The gathering system may be small if the processing units are
small and serve a few localized wells. Large processing units
which serve many wells in decentralized areas require more ex-
tensive gathering systems. Offshore production gathering systems
may transport crude to centrally located offshore processing
platforms, or to onshore processing facilities.
Evaporative emissions from the production gathering
system are the result of crude oil leaks from valves, fittings,
and pumps. The magnitude of these emissions may vary greatly
from one facility to another depending on the number of equipment
pieces, the physical properties of the crude oil being gathered,
and the efficiency of equipment maintenance. Emissions can be
reduced by regular maintenance of equipment, relief valve venting
to vapor recovery or flare, and conversion of pump seals to
mechanical or double seals.
Field Processing
Before crude oil is sent to a refinery, it is processed
to remove water, solids, and gas if they are produced with the
crude oil. Field processing units vary in size, depending on the
number of wells and production rates in the area that the pro-
cessing unit is located. The sequence of processing steps varies
from one production facility to another, and some processes may
be absent or additional processes present, depending on the local
conditions and the composition of the production. Offshore pro-
duction may be processed at offshore platform processing units,
or it may be piped from the wellhead to onshore processing units.
91
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Water Removal - Produced crude oil nearly always
contains water, usually as an oily brine or emulsion, and most of
this water must be removed before the crude oil is sent to a re-
finery. The composition of the production determines the sequence
and types of processing used to reduce brine content to about
two weight percent.
"Free water knock-out" - Water that is produced with
crude oil may be in the form of an immiscible brine. Free water
knock-out is the settling out of this water in a large tank
usually equipped with baffles to minimize turbulence and mixing.
Suspended solids can also be removed in this processing step.
The rate of throughput is determined by the settling character-
istics of the produced free water. These units usually operate
at ambient temperatures and atmospheric pressure, although free
water knock-out in conjunction with gas separation or heat treat-
ing will operate at varying conditions. The input is well pro-
duction, and yields are determined by the composition of the
production. The output is oil or emulsion, gas, oily brine,
and removed solids.
"Emulsion breaking" - The relative amounts of free
water and emulsion determine whether free water knock-out or
emulsion breaking is the upstream process. Emulsion breaking
consists of destabilization of the film between the oil and water
droplets, coalescence of the oil droplets, and gravitational
separation of the oil and water phases. The four methods used
in dehydrating emulsions are heating, chemical destabilization,
electrical coalescense, and gravitational settling.
92
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Heater treaters are commonly used for emulsion breaking.
They are usually direct fired, although indirect fired heater
treaters are also available. The brine-oil emulsion is destabili-
zed by the application of heat. Heater treaters are normally
operated at 210°F (99°C) under varying pressures, with a residence
time of about twenty minutes. These conditions may change if the
heater treater is also a gas separator (three phase separator).
The input is brine-oil emulsion and separated oil, gas, oily
brine, and solids are the output.
Chemical destabilization causes emulsions to break up
by altering the chemical compositions at the interfacial film
and by the effects of surface-active agents. Separation can be
enhanced by addition of heat and is completed in some type of
gravity settler.
Electrical dehydrators consist of a preheater to reduce
the viscosity of the crude, followed by exposure of the crude
to a high-voltage alternating electrical field. When the polar
water molecules in the emulsion turn to follow the lines of the
electrical field, the molecules coalesce and form droplets which
fall out by the force of gravity. Electrical dehydrators may
operate at varying temperatures and pressures, with a residence
time of about twenty minutes. The input is brine-oil emulsion
and the output is separated oil, gas, and oily brine.
Gravitational settling can be used to break unstable
emulsions. This is similar to free water knock-out, except that
the emulsion requires a longer residence time to achieve separa-
tion. Gravitational settling is usually done in a wash tank
which has three parts: (1) a bulk separator for free gas,
(2) a bulk separator for free water, and (3) a quiescent tank
for settling of suspended solids and water droplets. Operating
conditions, inputs, yields and outputs are essentially the same
as those for free water knock-out.
93
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Oil-Gas Separation - Crude oil contains some amount of
entrained and dissolved gases, and this amount varies from very
low gas-oil ratios to gas-oil ratios that are so high that the
well is classified as a gas well with entrained oil. Separation
of gases from the oil is usually accomplished at the production
site. Nonsolution gases can be separated by settling, agitating,
heating, or adding chemicals. The shape of separators is deter-
mined by the gas-oil ratio. For high gas-oil ratios horizontal
cylindrical separators are used, and for low gas-oil ratios
vertical cyclindrical separators are used. Spherical separators
are used for intermediate gas-oil ratios. In two-phase separators
only oil and gas are separated, while three-phase units separate
oil, gas, and water. The type of internal equipment used to achieve
separation is dependent on the composition of the production. When
wellhead pressure is very high, a stage separation procedure may
be used in which a series of separators are operated to perform
two or .more flash vaporizations at sequentially reduced pressures.
The rate of throughput is determined by the charac-
teristics of the production. Residence times of one to three
minutes are generally adequate, but difficult separations may
require five to twenty minutes. The operating temperature and
pressure of separators will generally begin with the wellhead
temperature and pressure and will drop step-wise to ambient
conditions. Inputs are gas-oil or gas-oil-water mixtures, and
yields are determined by the gas-oil 'ratio and operating con-
ditions. Outputs are gas, oil, and in the case of three-phase
separators, water. The crude product is sent to storage or sales,
and the gas produced is sent to a gas processing plant, or in
remote areas it may be vented, re-injected, or flared.
-------
Waste Water Disposal - The oily brine from the knock-out
tanks, dehydrators, and three-phase separators must be further
treated before being discharged as wastewater or reinjected into a
waterflooding or disposal well. The flotation cell type waste-
water treater is a commonly used primary water treating facility.
Other wastewater treatment methods include sedimentation followed
by aeration, aerated lagoons, or evaporation ponds. Most waste-
water treaters operate at ambient conditions, but some flotation
cells may have a gas solution tank that operates at 2-3 atmospheres
of pressure. Flotation cells have skimmers that recover the oil
and scrapers which remove settled solids. Aerated lagoons and
evaporation ponds dispose of waste brine and oil by solar
evaporation.
Emissions and Controls - Field processing units require
a system of pipes, fittings, pumps, compressors, and valves to
.transport the processed fluids. Leaks in this system are a
potential source of evaporative hydrocarbon emissions. Water re-
moval units can emit hydrocarbons if they are not vapor tight
vessels, especially if heater treaters are used, since the added
heat increases the vapor pressure of the crude oil. Gas-oil
separators are usually connected to gas recovery systems and
should not be a major source of hydrocarbon emissions. In remote
areas or where it is uneconomical to send the gas to a recovery
system, the gas may be flared or vented. Flotation cells can
emit hydrocarbons from evaporation of the oil that floats to the
surface. Wastewater.lagoons and evaporation ponds will evaporate
any oil that is discharged with the wastewater. In remote
locations the oil that floats to the surface of the evaporation
ponds may be burned.
95
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Evaporative hydrocarbon emissions from field processing
units can be reduced with proper maintenance of equipment., and
(1) rupture discs and vapor recovery or flares for relief valves,
(2) mechanical or double seals for pumps and compressors, and
(3) floating covers or sealed vapor recovery systems for waste-
water separators.
Storage and Sales
Evaporative emissions and emission factors for crude
oil in storage are presented in Section 4.3. Section 4.4 presents
emissions and emission factors for crude oil in transportation
and marketing operations.
Emission Factors
Evaporative emissions from crude oil production opera-
tions may vary significantly from one location to another. There
is not sufficient field test data available on oil production
operations to allow accurate estimation of emission factors for
all types of production facilities. The Monterey-Santa Cruz
County Unified Air Pollution Control District has published data
for emissions from production operations in Monterey County,
California. "Air Pollution in Monterey and Santa Cruz Counties"
present emission data based on 18.5x106 bbl of crude oil pro-
duction in 1967. Table 9.3-1 gives emission factors based on
the data in the Monterey County study.
In the Monterey County survey, emissions from pump
seals were found to average 75 lb/103 bbl of crude production.3
In a 1958 survey of Los Angeles area refineries the average em-
ission rate for pump seals was 17 lb/103 bbl of refinery capacity.
This data indicates that although an emission factor of 75 lb/103
bbl of crude production may be representative of an average
96
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TABU!.
ESTIMATED CRUDE OIL PRODUCTION
EMISSION FACTORS
Point Source Emission Factor1
(lb/103 bbl crude production)
Compressor seals 4
Relief valves 8
Waste water separators 8
Pipeline valves 12
Pumps 75
i
Based on 18.5x106 bbl/year crude production in Monterey County,
California in 1967 . Reference 7.
97
-------
production facility in 1967, the evaporative emissions from pump
seals in production operations may be as low as 17 lb/103 bbl of
crude throughput with the application of newer technology and
proper maintenance scheduling. The Monterey County data shows
a total evaporative emission rate from crude oil production
operations of 107 lb/103 bbl of crude production.7 This emission
rate does riot include evaporative emissions from storage facilities
Crude oil production facilities can vary from older
fields where production rates may be too low to economically
support regular maintenance of obsolete equipment, to new fields
where modern equipment with emission control devices and regular
maintenance are used. Many crude oil production units are
similar to petroleum refinery units. Section 9.1 on refinery
emissions lists emission factors for evaporative sources
in petroleum refining. These emission factors may be used to
estimate emissions from crude oil production operations for
similar unit operations, such as pipeline valves, etc. Emission
factors are given for individual operations in units of lb/valve
day, etc. A detailed flow diagram of the production operations
is required in order to make accurate emission estimates from
this basis.
9.3.4 Natural Gas Processing
The natural gas processing segment of the oil and gas
production industry is involved in the preparation of natural
gas for sales. Natural gas as obtained from the gas well may
contain impurities, including water vapor, carbon dioxide,
suflur compounds, and hydrocarbon liquids. These impurities
must be removed in order for natural gas to meet the quality
regulations for pipeline sales.
98
-------
The processes used to meet these sales requirements
are presented in this section. Although the processing steps
are presented sequentially in Figure 9.3-3, they are by no means
intended to be in a prescribed order. Variations in sequences,
operating conditions, and physical locations occur throughout
the industry with local production conditions and geographical
locations dictating the particular processing methods.
Liquid Hydrocarbon Recovery
From the gas well, natural gas may first be routed to
a liquid hydrocarbon recovery unit for the removal of readily
separable water and hydrocarbon liquids. High levels of water
vapor and hydrocarbon liquids in natural gas present the potential
hazards of condensation ani freezing, which may interrupt the.trans-
portation of gas to the gas plant. The removal of entrained
water and hydrocarbon liquid droplets is effected by the use of
mist eliminators and knockout chambers. If additional pretreat-
ment is necessary, there are four major types of liquid recovery
processes which may be used singly or in combination to effect the
necessary separation; adsorption, absorption, refrigeration, and
compression. One of the newer technologies involves the use of a
turboexpander to expand the natural gas through a turbine compressor
from which it exhausts at extremely low temperatures; most of
the gas except methane is condensed. These liquid recovery
technologies are discussed in detail under the section on product
separation. Water separated in the liquid hydrocarbon recovery
unit is sent to disposal, and hydrocarbon condensates are sent to
the product separation unit for further separation into salable
products.
99
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O
O
OCHYDHATION
-^ QIC DISPOSAL]
f "^^Sl 'O SA
AL!
IPO
SIORACr
~~^\l 10 s«i r.r, I
~~s^ I OR fitriurnYJ
FIGURE 9.3-3 GAS PROCESSING FLOW DIAGRAM
-------
Acid Gas Removal
The acid gas removal unit is designed to remove hydrogen
sulfide from hydrocarbon gases by absorption in an aqueous, re-
generative sorbent. Amine-based sorbents are the most commonly
used. Within the acid gas removal unit, the natural gas feed is
contacted with the amine sorbent in an absorption column to
selectively absorb H2S from the natural gas. Other gaseous
species which will also be absorbed if present include: carbon
dioxide, nitrogen, mercaptans, and some hydrocarbons. Absorbed
gases are steam stripped or distilled from the amine sorbent in
a regeneration step. The products are a "sweet" natural gas and
a concentrated hydrogen sulfide stream. Hydrogen sulfide is
normally routed to a sulfur recovery plant for recovery of its
sulfur content. However, if a sulfur recovery plant is not
available, the hydrogen sulfide is flared to produce less toxic
sulfur oxides.
Sulfur Recovery
The sulfur recovery unit converts hydrogen sulfide to
elemental sulfur by the Glaus process. The Glaus process involves
the combustion of 1/3 of the hydrogen sulfide feed to sulfur di-
oxide, followed by the catalytic .conversion of the remaining hydro-
gen sulfide and sulfur dioxide to elemental sulfur and water. The
elemental sulfur is marketed, and the water is routed to disposal.
Dehydration
The dehydration unit removes water vapor from natural
gas so that it will meet market specifications. The most common
dehydration process used in natural gas production is based upon
the absorption of water from natural gas into a di- or tri-ethylene
glycol sorbent. The glycol sorbent is regenerated by distilling
101
-------
off the water. Other dehydration processes frequently used in- .
elude adsorption with molecular sieves and dessicants, absorption
with hygroscopic materials, and condensation using refrigeration.
Product Separation
Purified natural gas laden with hydrocarbon liquids, and
petroleum condensates separated from the well head gas are pro-
cessed in a product separation unit for the recovery of valuable
hydrocarbon liquids. The products from the product separation
unit include: 1) pipeline gas which is almost pure methane,
2) ethane, 3) propane, 4) butane, and 5) natural gasoline, which
is a blend of all hydrocarbons heavier than butane.
There are several different methods used to achieve
product separation. Commonly used processes involve absorption,
refigerated absorption, refigeration, compression, and/or adsorption
In an absorption process the wet field gas is contacted .
with an absorber oil in a packed or bubble tray column. Propane
and heavier hydrocarbons are absorbed by the oil, while most -of
the ethane and methane pass through the absorber. The enriched
absorber oil is then taken to a stripper where the absorbed pro-
pane and heavier compounds are stripped from the oil.
The natural gas feed to a refrigerated absorption pro-
cess must be dehydrated to a minus 40°C dew point prior to enter-
ing the unit. All hydrocarbons except methane are absorbed by
absorber oil operating at this temperature. These absorbed hydro-
carbons and the oil are passed through a series of fractionation
columns from which ethane, propane, and heavier hydrocarbons are
removed as product streams.
102
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In .refrigeration, a cryogenic process, the natural gas
is passed through a heat exchanger where it is cooled to minus
37°C. Condensed hydrocarbons are removed in a gas-liquid sep-
arator. The gas from the separator is cooled to minus 93°C and
passed through a second separator where more condensed liquids
drop out. The liquids from the two separators are fed into a
series of distillation columns where methane, ethane, propane,
butanes, natural gasoline, and other products are recovered.
A compression process uses two stages of compression,
each followed by cooling and gas-liquid separation, to produce
a wet natural gas product and natural gasoline. This is not a
widely used process.
The adsorption processes consist of two or more beds
of activated carbon. The beds are used alternatively, with one
or more beds on stream while the others are being regenerated.
The activated carbon adsorbs all hydrocarbons except methane.
The bed is regenerated by means of heat and steam, which remove
the adsorbed hydrocarbons as a vapor. This vapor is then con-
densed permitting the water to be separated from the liquid hydro-
carbons. The resulting hydrocarbon product is fed to a fraction-
ation process where the various components are separated.
Product Storage
The products from the gas processing operations are
routed to intermediate storage facilities to await transportation
to refineries, petrochemical plants, and domestic consumers.
Pressure tanks are used to store ethane, propane, and butane.
Floating roof tanks and fixed roof tanks are normally used to
store natural gasoline. The design and functions of tankage
facilities are. discussed in detail in Chapter 4.3. Natural gas
103
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is not normally stored at gas processing facilities, but compressed
and transferred directly into distribution pipelines.
Emissions
The only direct process-source of hydrocarbon emissions
from natural gas processing is the water vapor stream vented from
a glycol dehydration unit. Small quantities of glycol are distil-
led from the dehydration process in conjunction with the water
distillation step and appear in the vented water vapor. The
estimated level of glycol loss from a dehydration unit is 0.1
gal/106 SCF of natural gas treated (13.4 liter/106 Nm3).9
Fugitive emissions from numerous leaks and spills are
collectively the largest source of hydrocarbon emissions from gas
processing plants. Sources of fugitive emissions include control
valves, relief vales, spills, pipe fittings, pump seals, and com-
pressor seals. Because the rate of fugitive emissions is dependent
on processing schemes, housekeeping practices, and maintenance
practices, they vary greatly from facility to facility and are
difficult to determine. Estimates for the level of fugitive
emissions from the standard natural gas processing plant range
from 150 to 200 lbs/106 SCF of natural gas processed (2400 to
3200 Kg/106 Nm3).5.9
Many of the fugitive emission sources composing a
natural gas processing unit are analogous to fugitive emission
sources found in the refinery. In a survey of Los Angeles area
refineries the average leak rate for a control valve in gaseous
service was 0.49 Ibs/day-valve. In the same refinery survey
hydrocarbon leaks from pressure relief valves on operating units
averaged 2.9 Ibs/day-valve, while single and dual pressure relief
valves on storage vessels average 0.32 Ibs/day-valve and 1.24
Ibs/day-valve, respectively. In another refinery survey of seals
in gaseous service emissions from mechanical seals on centrifugal
104
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pumps averaged 9.2 Ibs/day-seal; emissions from pa.cked seals on
centrifugal pumps averaged 10.3 Ibs/day-seal; and emissions from
packed seals on reciprocating pumps averaged 16.1 Ibs/day-seal.
Estimates of fugitive emission rates from other gas processing
units which are analogous to refinery processing units can be
obtained from Section 9.1 on refinery emission sources.3
9-3.5 Secondary and Tertiary Recovery
When a producing well decreases its production, it is
often stimulated by using secondary and tertiary recovery techniques
The problems causing loss of production fall into three major
areas. One major problem, loss of formation pressure, is solved
by displacement processes. Displacement processes involve the
injection of water or gas under high pressure into the formation
to maintain formation pressure. A second problem, low permeability
of the formation, occurs when the formation is packed so tightly
that the oil cannot flow through it. This is corrected by acid
treatment in carbonate rock formations or by formation
fracturing with pressurized fluids in sandstone formations. The
third major problem occurs when the oil is too viscous to flow
easily. This problem is corrected by thermal treatment which
increases production by heating the oil via processes such as
steam injection, hot water injection, and in-situ combustion.
Secondary and tertiary recovery techniques do not
significantly increase the fugitive hydrocarbon emissions gen-
erated by standard oil and gas production operations.
9.3.6 Offshore Facilities
Offshore production and processing operations are very
similar in principle, to their onshore counterparts. However,
these facilities tend to be newer installations employing better
105
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processing and emission control technology. In addition,
because fugitive leaks and spills present a great fire hazard to
the high density of processing equipment on off-shore production
platforms, good housekeeping and maintenance practices are
routinely employed as a safety measure.
106
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REFERENCES
SECTION 9.2
1. Cavanaugh, E.G., et al., Atmospheric Environmental Problem
Definition of Facilities For Extraction, On-site Processing,
and Transportation of Fuel Resources, Contract No. 68-02-
1319, Task 19., Austin, Texas, Radian Corporation, July 1975.
2. Chilingar, George V. and Carrol M. Beeson, Surface
Operations in Petroleum Production, N.Y., American Elsevier,
1969.
3. Danielson, John A., comp. and ed., Air Pollution Engineering
Manual, 2nd ed., AP-40. Research Triangle Park, N.C., EPA
Office of Air & Water Programs, 1973.
4. Environmental Conservation, Washington D.C., National
Petroleum Council, 1972.
5. Frick, Thomas C. and R. William Taylor, eds., Petroleum
Production Handbook, 2 vols., N.Y., McGraw-Hill, 1962.
6. Monsanto Research Corp., Overview Matrix, Contract No.
68-02-1874, Dayton, Ohio, July 1975.
7. MSA Research Corp., Hydrocarbon Pollutant Systems Study,
Vol. 1, Stationary Sources, Effects and Control, PB-219-073,
APTD 1499, Evans City, PA., 1972.
8. Petroleum Extension Service, Univ. of Texas, Treating Oil
Field Emulsions, 3rd ed., Austin, Texas, 1974.
9. Processes Research, Inc., Industrial Planning & Research,
Screening Report, Crude Oil and Natural Gas Production Pro-
cesses, Final Report, Contract No. 68-02-0242, Cincinnati,
Ohio, 1972.
107
-------
REFERENCES
SECTION 9.2
Continued
10. Reid, G. W., et al. , Brine Disposal Treatment Practices
Relating to the Oil Production Industry, Program 14020
FVW, EPA 660/2-74-037, Norman, Oklahoma, Univ. Oklahoma
Research Inst., 1974.
108
-------
ATTACHMENT E
SOURCE CLASSIFICATION CODES
109
-------
REVISED SCC LISTINGS
Fixed Roof
4-03-001-01
4-03-001-02
4-03-001-03
4-03-001-04
4-03-001-05
4-03-001-06
4-03-001-07
4-03-001-08
4-03-001-09
4-03-001-10
4-03-001-11
4-03-001-12
4-03-001-13
4-03-001-14
4-03-001-15
4-03-001-16
4-03-001-17
4-03-001-18
4-03-001-19
4-03-001-20
4-03-001-21
4-03-001-22
4-03-001-23
4-02-001-24
4-02-001-25
Source
Breath-Gasoline < 100,000 bbl
Breath-Crude < 100,000 bbl
Working-Gasoline
Working-Crude
Breath-JP-4 < 100,000 bbl
Breath-Jet Kero < 100,000 bbl
Breath-Dist No. 2 < 100,000 bbl
Breath-Benzene
Breath-Cyclohexane
Breath-Cyclopentane
Breath-Heptane
Breath-Hexane
Brea th-1sooc tane
Breath-Isopentane
Brea tli-Pen tane
Breath-Toluene
Breath-Naphtha
Breath-Reformate
Breath-Alkylate
Breath-Gas Oil
Breath-Resid No. 2<100,000 bbl
Breath-LPG
Breath-Gasoline > 100,000 bbl
Breath-Crude > 100,000 bbl
Breath-JP-4 > 100,000 bbl
Part
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
S0x
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
84.0
23.4
8.2
2.8
31.4
1.6
1.4
28.8
31.0
58.4
11.3
32.1
13.9
142-0
94.9
12.8
0.06
62.1
16.8
22.6
CO
0
0
0
0
0
0
• 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Units Actioi
1000 gal. storage capacity 1
1000 gal. storage capacity 1
1000 gal. throughput 4
1000 gal. throughput 4
1000 gal. storage capacity 1
1
n n n n -I
n n n n ^
" " " " 4
n n ii n *
n n n n *
M ti ii n *
n n n ii *
n n M ii *
It It II 1! ^
M II II It ^
II It II II i
II II II II i
II II II II I
II II II It i
II It II II O
II II II II i
II II II II O
II II II II O
II It It II •)
-------
REVISED SCC LISTINGS
Fixed Roof (cont.)
Source
4-03-001-26
4-03-001-27
4-03-001-28
4-03-001-50
4-03-001-51
4-03-001-52
4-03-001-53
4-03-001-54
4-03-001-55
4-03-001-56
4-03-001-57
4-03-001-58
4-03-001-59
4-03-001-60
4-03-001-61
4-03-001-62
4-03-00J-63
4-03-001-64
4-03-001-65
4-03-001-66
4-03-001-67
4-03-001-98
4-03-001-99
Breath-Jet Kero > 100,000 bbl
Breath-Dist No. 2 > 100,000 bbl
Breath-Resid No. 6 > 100,000 bbl
Working-JP-4 .
Working-Jet Kero
Working-Dist No>. 2
Working-Benzene
Working-Cyclohex
Working-Cyclopent
Working-Heptane
Working-Hexane
Working-Isooctane
Working-Isopent
Working-Pentane
Working-Toluene
Working-Naphtha
Working-Reformats
Working-Alkylate
Working-Gas Oil
Working-Resid No. 6
Working-LPG
Breath Specify
Working Specify
Part
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
SO
0
0
0
0
0
0
0
0
0
0
0
0 •
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
1.1
0.10
0.005
2.5
0.027
0.023
2.2
2.4
6.40
1.20
3.60
1.50
15.7
10.6
0.66
0.0002
CO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Units
1000 gal." storage capacity
1000 gal. throughput
Action
3
3
3
1
1
4
4
4
A
A
A
A
A
4
1000 gal. storage capacity
1000 gal. throughput
A
*
-------
REVISED SCC LISTINGS
Floating Roof
4-03-002-01
4-03-002-02
4-03-002-03
A-03-002-04
4-03-002-05
4-03-002-06
4-03-002-07
4-03-002-08
4-03-002-09
4-03-002-10
4-03-002-11
4-03-002-12
4-03-002-13
4-03-002-14
4-03-002-15
4-03-002-16
4-03-002-17
4-03-002-18
4-03-002-19
4-03-002-20
Working-Crude
Standing STG-
Standing STG-
Standing STG-
Standing STG-Benzene
Standing STG-Cyclohex
Standing STG-Cyclopen
Standing STG-Heptane
Standing STG-Hexane
Standing STG-Isooct
Standing STG-Isopen
Standing STG-Pentane
Standing STG-Toluene
Standing STG-Naphtha
Standing STG-Reforma
Standing STG-Alkylate
Standing STG-Gas Oil
mrce Part
soline <100,000 bbl 0
2 <100,000 bbl 0
ade <100,000 bbl 0
0
4 <300,000 bbl 0
: Kero <100,000 bbl 0
it No. 2 <100,000 bbl 0
izene 0
:lohex 0
:lopen 0
>tane 0
cane 0
>octane 0
>pentane 0
itane 0
.uene 0
»htha 0
:ormate 0
Lylate 0
i Oil 0
S0x
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
12.0
0.023
4.38
4.38
0.197
0.179
4.02
4.38
8.76
1.64
4.75
2.01
20.8
13.9
1.75
CO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Units Action
1000 gal storage capacity 1
1000 gal throughput 1
1000 gal storage capacity 1
1000 gal throughput *
1000 gal storage capacity 1
n ii ii ii -I
"1
n n n n ^
n n n n i
n n n n %
II II II It £
II II II II £
II It II II £
II II II II £
II II II II £
II II II II A
II II II II _|_
It II II II 1
II II II II 1
II II II II 1
-------
REVISED SCC LISTINGS
Floating Roof Cont. Source Part
4-03-002-21
4-03-002-22
4-03-002-23
4-03-002-24
4-03-002-25
4-03-002-26
4-03-002-27
Standing STG-Resid No. 6
<100,000 bbl
Standing STG-Gasoline
>100,000 bbl
Working-Gasolene >100,000 bbl
Standing STC-Crude >100,000 bbl
Standing STG-JP-4 >100,000 bbl
Standing STG-Jet Kero >100,000 bbl
Standing STG-Dist. No. 2
0
0
0
0
0
0
0
SO
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
HC
0.007
6.94
0.013
2.08
2.48
0.113
0.102
CO Units
0 1000 gal storage capacity
A " 'I "
0 1000 gal throughput
0 1000 gal storage capacity
0 " " "
n II II II
0 " "
Action
2
3
3
3
3
3
3
- 4-03-002-28
>100,000 bbl
Standing STG-Resid No. 6
> 100, 000 bbl
0
0.004
0
4-OJ-002-99 Standing STG-Capacity
-------
REVISED SCC LISTINGS Continued
Variable Vapor Space
4-03-003-02
4-03-003-03
4-03-003-04
4-03-003-05
4-03-003-06
4-03-003-07
4-03-003-08
4-03-003-09
4-03-003-10
4-03-003-11
4-03-003-12
4-03-003-13
4-03-003-14
4-03-003-15
Source
Working-Gasoline
Working-JP-4
Working-Jet Kero
Working-Dist. No. 2
Working-Benzene
Working-Cyclohex
Working-Cyclopent
Working-Heptane
Working-Hexane
Working-Isooctane
Working-Isopentane
Working-Pentane
Working-Toluene
Working-Resid No. 6
Part.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
so
— x
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
7.7
2.3
0.025
0.022
2.1
2.3
7.2
1.4
4.0
1.7
17.8
12.0
0.62
0.0002
CO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Units
1000 gal throughput
Action
4
1
1
4
4
4
*
4
3
4-03-003-99
Working-Specify
0
-------
REVISED SCC LISTINGS Continued
Fixed Roof Breathing .
(Petrochemical)
4-04-001-04
4-04-001-06
4-04-001-14
4-04-001-15
4-04-001-19
4-04-001-26
4-04-001-28
4-04-001-39
4-04-001-42
Source
Breath-Acetone
B reath- Aery lonit rile
Breath-Carbon Tetra-
chloride
Breath-Chloroform
B reath- 1 ,2-Dichloro-
ethane
Breath-Ethylacetate
Breath- Ethylalcohol
Breath-Menthyl Alcohol
Breath-Methylene
Part.
0
0
0
0
0
0
0
0
0
sox
0
o
0
0
0
0
0
0
0
N0x
0
0
0
0
0
0
0
0
0
HC
43.8
21.9
62.1
76.7
31.8
30.3
10.2
13.1
113
CO
0
0
0
0
0
0
0
0
0
Units Activity
1000 gal storage capacity 5
It II II II c
II II II It c
II II It II r
II II II II c
II II II II C
It It It II c
II II II II c
II II II II c
4-04-001-43
4-04-001-44
4-04-001-50
4-04-001-55
4-04-001-56
4-04-001-58
Chloride
Breath-Methyl Ethyl 0 0
Ketone
3reath-Methyl- 0 0
methaerylate
Breath-Isopropyl- 0 0
alcohol
Breath-1,1, 1 Trichloro- 0 0
ethane
Breath-Trichloroethylene 0 0
Breath-Vinyl Acetate 0 0
0
0
26.6
13.9
11.3
62.1
40.2
33.6
II II
II II II
II II tl
II II It
0
0
II II
5
5
-------
REVISED SCC LISTINGS Continued
Fixed Roof Working
(Petrochemical)
4-04-005-04
4-04-005-06
4-04-005-14
4-04-005-15
4-04-005-19
4-04-005-26
4-04-005-28
4-04-005-39
4-04-005-42
4-04-005-43
4-04-005-44
4-04-005-50
. 4-04-005-55
4-04-005-56
4-04-005-58
Sources Part.
Working- Ace tone
Working-Acrylonitrile
Working-Carbon tetra-
chloride
Working-Chloroform
Working- 1,2-Dichloro-
ethane
Working- Eth lace tate
Working-Ethylalcohol
Working- Me thy lalcohol
Working-Methylene Chloride
Working-Methyl Ethyl
Ketone
Working-Me thy line th-
acrylate
Workingrlsopropyl Alcohol
Working-1 , 1 , 1-Trichloro-
ethane
Working-Trichlbroethylene
Working-Vinyl Acetate
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
S0x
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
4.0
1.8
5.2
7.1
2.4
2.3
0.66
1.1
11.0
2.1
0.72
0.72
5.1
2.8
2.7
CO Units
0 1000 gal throughput
o
0 " " "
n i» ii ii
n ii ii ii
r\ II II II
0 ii •• ••
0 " " . "
0
Q II II II
Q II II II
0 " " "
Q II II II
f\ II It II
n ii' • it ii
Activity
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
-------
REVISED SCC LISTINGS
Floating Roof Standing
(Petrochemical) Source
4-04-010-04
4-04-010-06
4-04-010-14
4-04-010-15
4-04-010-19
4-04-010-26
4-04-010-28
4-04-010-39
4-04-010-42
4-04-010-43
4-04-010-44
4-04-010-50
4-04-010-55
4-04-010-56
4-04-010-58
Variable Vapor
4-04-011-01
4-04-011-02
4-04-011-03
4-04-011-04
4-04-011-05
4-04-011-06
4-04-011-07
4-04-011-08
4-04-011-09
Standing-Acetone
St and ing-Aery lonit rile
Standing-Carbon Tetrachloride
Standing-Chloroform
Standing- 1 . 2-Dichloroethane
Standing-Ethy lacetate
Standing-Ethyl Alcohol
Standing-Methyl Alcohol
Standing-Methylene Chloride
Standing-Methyl Ethyl Ketone
Standing-Me thy Imethacry late
Standing-Isopropyl Alcohol
Standing-1, 1, 1-Trichloroethane
Standing-Trichloroethylene
Standing-Vinyl Acetate
Space (Petrochemical)
Working- Ace tone
Working-Aery lonitrile
Working-Carbon Tetrachloride
Working-Chloroform
Working-1, 2-Dichloroethane
Wor k ing- E thy lacetate
Working-Ethyl Alcohol
Working-Methyl Alcohol
Working-Methylene Chloride
Tart
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
SOx
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO*
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
6.2
3.1
8.8
11.0
4.4
4.4
1.4
1.9
16.1
3.7
1.9
1.6
8.4
5.5
4.7
3.8
1.7
4.8
6.7
2.2
2.2
0.62
1.0
10.0
Ct
0
0
0
0
6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Un it:
1000 gal. storage capacity
M II
1000 gal. throughput
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
3
3
3
3
3
3
3
3
3
-------
REVISED SCC LISTINGS
Floating Roof Standing
Petrochemical (cont.)
Source
4-04-011-10'
4-04-011-11
.4-04-011-12
4-04-011-13
4-04-011-14
4-04-011-15
Working-Methyl Ethyl Ketone
Working-Methylmethacrylate
Working-Isopropyl Alcohol
Working-1,1,1-Trichloroethane
Working-Trichloroethane
Working-Vinyl Acetate
Part
0
0
0
0
0
0
SO
— • — X
0
0
0
0
0
0
NO
0
0
0
0
0
0
HC
1.9
0.68
0.68
4.8
2.6
2.5
CO
0
0
0
0
0
0
Units
1000 gal. throughput
Action
3
3
3
3
3
3
oo
-------
REVISED SCO LISTINGS
Tank Cars/Trucks -
Loading
Source
4-06-001-01
4-06-001-02
4-06-001-03
4-06-001-04
4-06-001-05
4-06-001-06
4-06-001-25
4-06-001-26
4-06-001-27
4-06-001-28
4-06-001-29
4-06-001-30
4-06-001-50
4-06-001-51
4-06-001-52
4-06-001-53
4-06-001-54
4-06-001-55
4-06-001-75
4-06-001-76
4-06-001-77
Submerged-Normal Gasoline
Submerged-Normal Crude
Submerged-Normal JP-4
Submerged-Normal Jet Kero
Submerged-Normal Dist No. 2
Submerged-Normal Resid No. 6
Splash-Normal Gasoline
Splash-Normal Crude
Splash-Normal JP-4
Splash-Normal Jet Kero
Splash-Normal Dist No. 2
Splash-Normal Resid No. 6
Submerged-Balance Gasoline
Submerged-Balance Crude
Submerged-Balance JP-4
Submerged-Balance Jet Kero
Submerged Balance Dist No. 2
Submerged-Balance Resid No. 6
Splash-Balance Gasoline
Splash-Balance Crude
Splash-Balance JP-4
Part
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
S0x
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
5
3
1.5
0.02
0.01
0 . 0001
12
7
4
0.04
0.03
0.0003
8
5
2.5
0.03
0.02
0.0002
8
5
2.5
CO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Units
1000 gal. transferred
Action
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
-------
REVISED SCC USTFNGS
Tank Cars/Trucks -
Loading (cont.)
Source
4-06-0001-78
4-06-001-79
4-06-001-80
Splash-Balance Jet Kero
Splash-Balance Dist No. 2
Splash-Balance Resid No. 6
Part S0x N0x HC CO
00 0 0.03 0
0 0 0 0.02 0
0 0 0 0.0002 0
1000 gal. transferred
Act Lor.
3
3
3
4-06-001-99 Other-Specify
Delete all other 4-06-001 Classifications
ISJ
O
-------
REVISED SCC LISTINGS Continued
Marine Vessels
4-06-002-01
4-06-002-02
4-06-002-03
4-06-002-04
4-06-002-05
4-06-002-06
4-06-002-07
4-06-002-08
4-06-002-09
4-06-002-25
4-06-002-26
4-06-002-27
4-06-002-28
4-06-002-29
4-06-002-30
Sources
Loading Clean Ships-Gasoline
Loading Dirty Ships-Gasoline
Loading Clean Barges-
Gasoline
Loading Dirty Barges-
Gasoline
Loading General-Crude
Loading General- JP-4
Loading General-Jet Kero
Loading General-Dist. No. 2
Loading General-Resid No. 6
Transit Gasoline
Transit Crude
Transit-JP-4
Trans it- Jet Kero
Transit-Dist. No. 2
Transit-Resid No. 6
Part.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
SO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
HC
1.3.
2.5
1.2
3.8
1.0
0.5
0.02
0.005
0.00004
3
1
0.7
0.02
0.005
0.00003
CO Units
0 1000 gal transferred
0 " " "
Q II II II
0 " " "
0 " " "
Q II II II
0 " " "
Q II II II
0 " " "
0 " " "
0 " " "
Q II II II
Q II II II
Q II It II
0 " " "
Activity
3
3
3
3
3
3
3
3
3
3
3
3
3
' 3
3
4-06-002-99
Other Specity
1000 gal transferred
Delete all other 4-06-002
-------
REVISED SCC LISTINGS Continued
Underground Gasoline
Storage
4-06-003-01
4-06-005-02
4-06-003-03
4-06-003-04
4-06-003-05
4-06-003-99
Fill Vehicle Gas Tank
4-06-004-01
4-06-004-02
4-06-004-99
Source
Splash Loading
Sub Load-Uncont.
Sub Load-Opn Sys.
Sub Load-Cls Sys.
Unloading
Specify
Vapor Disp. Loss
Liq. Spill Loss
Other Specity
Part. S0v NOV HC
. •• X ' • Js ~—
No Change
CO
0
0
0
0
0
0
0
0
0
9.0
0.7
0
0
0
Units
1000 gallons pumped
Activity
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
.EPA-450/3-76-039
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Revision of Evaporative Hydrocarbon Emission Factors
5. REPORT DATE
August 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C. E. Burklin and R. L. Honerkamo
8. PERFORMING ORGANIZATION REPORT NO.
100-086-01
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Blvd.
P. 0. Box 9°48
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-1889
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Duality Planninq and Standards
Monitoring and Data Analysis'Division
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final Report
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The increased use of EPA Document AP-42 entitled Compilation of Air Pollutant
Emission Factors and EPA's National Emission Data System (NEDS) have brought to
light a need to improve the emission factors pertaining to evaporative hydrocarbon
losses from the petroleum industry. As defined for this nrogram, the petroleum
industry comprises production, transportation, storage, refining, and marketing
operations for petroleum crude oil and petroleum products.
This report presents the work performed to update and revise the information
presently contained in the EPA Document AP-42 Compilation of Air Pollutant Emission
Factors related to- evaporative hydrocarbon emissions from We petroleum industry.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Source Classification Codes
Emissions
HC
RVP
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
134
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
123
-------
|