EPA 340/1-77-005
APRIL 1977
Stationary Source Enforcement Series
INSPECTION MANUAL FOR ENFORCEMENT OF
NEW SOURCE PERFORMANCE STANDARDS
VOLATILE HYDROCARBON STORAGE
TANKS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
Office of General Enforcement
Washington, D.C. 20460
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INSPECTION MANUAL FOR THE
ENFORCEMENT OF NEW SOURCE
PERFORMANCE STANDARDS:
VOLATILE HYDROCARBON STORAGE
Contract No. 68-01-3156
Task Order No.19
EPA Project Officer
Mark Antell
Prepared for
UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY
Division of Stationary Source Enforcement
Washington, D.C.
-------
This report was furnished to the United States Environmental
Protection Agency by The Ben Holt Co., Pasadena, California,
in fulfillment of Contract No. 68-02-1090 and by Pacific
Environmental Services, Inc., Santa Monica, California in ful-
fillment of Contract No. 68-01-3156. The contents of this
report are reproduced herein as received 'from the contractor.
The opinions, findings, and conclusions expressed are those
of the author and not necessarily those of the Environmental
Protection Agency.
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TABLE OF CONTENTS
Page
LIST OF FIGURES vi
LIST OF TABLES vi
1.0 INTRODUCTION 1-1
2.0 STATE IMPLEMENTATION PLANS (SIP) AND NEW SOURCE 2-1
PERFORMANCE STANDARDS (NSPS)
2.1 Existing Sources - SIP 2-1
2.1.1 Summary of Typical SIP Regulations 2-1
2.2 Summary of New Source Performance Standards 2-1
2.2.1 Equipment Specifications 2-2
2.2.1.1 Equipment for Storage of Liquids 2-2
of Intermediate Volatility
2.2.1.2 Equipment for Storage of Liquids 2-2
of High Volatility
2.2.2 Record Keeping and Reporting 2-3
2.2.2.1 Information to be Filed 2-3
2.2.2.2 Notifications Regarding Initial 2-3
Start-up
2.2.2.3 Records Regarding Start-up, Shut- 2-4
down and Malfunction
2.2.2.4 Quarterly Reports 2-4
2.3 Applicability of Standards 2-4
2.3.1 Determination of Vapor Pressure 2-4
2.3.2 Computational Estimates of Emissions 2-6
3.0 PROCESS DESCRIPTION, ATMOSPHERIC EMISSIONS AND EMISSION 3-1
CONTROL METHODS
3.1 Process Description 3-1
3.1.1 Cone Roof Tanks 3-1
3.1.2 Floating Roof Tanks 3-2
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TABLE OF CONTENTS (continued)
Page
3.1.2.1 Single Floating Roof 3-6
3.1.2.1.1 Pan-Type 3-6
3.1.2.1.2 Pontoon 3-10
3.1.2.1.3 Double-Deck 3-10
3.1.2.2 Covered Floating Roof 3-10
3.1.2.2.1 Pan-Type 3-11
3.1.2.2.2 Pontoon 3-11
3.1.2.2.3 Double-Deck 3-11
3.1.2.2.4 Rigid Polyurethane 3-12
3.1.2.2.5 Floating Fabric Covers 3-12
3.1.3 Variable Vapor Space Tanks 3-13
3.1.3.1 Lifter-Roof Tanks 3-13
3.1.3.2 Internally Modified Fixed-Roof Tanks 3-13
3.2 Atmospheric Emissions 3-13
3.3 Emission Control Methods 3-15
3.3.1 Conservation Vents 3-15
3.3.2 Floating Roofs 3-15
3.3.3 Flares 3-16
3.3.4 Recovery to Fuel Gas 3-16
3.3.5 Vapor Recovery Systems 3-16
4.0 PROCESS AND CONTROL DEVICE INSTRUMENTATION 4-1
4.1 Process Instrumentation 4-1
4.2 Control Device Instrumentation 4-1
5.0 START-UP/MALFUNCTIONS/SHUTDOWN 5-1
6.0 INSPECTION PROCEDURES 6-1
6.1 Conduct of Inspection 6-1
6.1.1 Formal Procedure 6-1
6.1.2 Overall Inspection Process 6-2
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TABLE OF CONTENTS (continued)
Page
6.1.3 Safety Equipment and Procedures 6-3
6.1.4 Frequency of Inspections 6-5
6.2 Inspection Checklist 6-5
6.3 Inspection Follow-up Procedures 6-7
7.0 PERFORMANCE TEST 7-1
7.1 Process Operating Conditions 7-1
7.2 Process Observations 7-1
7.3 Equipment Observations 7-2
7.3.1 Emission Monitoring 7-2
Appendix
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LIST OF FIGURES
Figure Page
2.1 Vapor Pressures of Gasolines and Finished 2-8
Petroleum Products
2.2 Working Loss of Gasoline from Fixed-Roof Tanks 2-9
2.3 Breathing Loss of Gasoline from Fixed-Roof Tanks 2-10
2.4 Calculation of Emission Factor, Lf, for 2-11
Standing Storage Evaporation Emissions from
Floating-Roof Tanks
3.1 Schematic View of Typical Floating Deck 3-3
3.2 Schematic of a Metallic Seal 3-4
3.3 Metallic Seal Situated in a Double-Deck Floating 3-4
Roof
3.4 Metallic Seal Equipped with Secondary Seals to 3-5
Stop Vapor Losses due to High Winds on Riveted
Tanks
3.5 Schematic of a Nonmetallic Seal 3-7
3.6 Liquid-Filled Nonmetallic Tube Seal 3-7
3.7 Air-Inflated Nonmetallic Tube Seal 3-8
3.8 Foam-Filled Nonmetallic Tube Seal 3-9
3.9 Vapor Recovery System for Storage Tanks 3-17
3.10 High Pressure Absorber Unit 3-18
6.1 Tank Inspection Checklist 6-4
LIST OF TABLES
Table Page
2.1 Volatility Classes of Petroleum Liquids, as 2-5
Related to New Source Performance Standards
for Storage Facilities
2.2 Standing Storage Evaporation Emissions from 2-11
Floating-Roof Tanks
V 1
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1.0 INTRODUCTION
Pursuant to Section 111 of the Clean Air Act (42 USC 1857
et. seq.), the Administrator of the Environmental Protection
Agency (EPA) promulgated standards for performance of new and
modified storage vessels for petroleum liquids. These proposed
standards were issued in the Federal Register of June 11, 1973,
and final standards (40 CFR 60.112) became effective on February
28, 1974. These standards were amended on December 16, 1975.
The standards apply to all sources whose construction or modifi-
cation commenced after June 11, 1973, subject to the exceptions
outlined in Section 2.2 of this report. Appendix I summarizes
the applicable regulations as of February 27, 1976.
Enforcement of these standards may be delegated by the EPA
to individual state agencies for all sources except those owned by
the U.S. Government. Each state must first, however, develop a
program which includes inspection procedures for verifying compli-
ance with the standards, and EPA must approve the program.
The purpose of this document is to provide guidelines for
the appropriate enforcement agency in the development of inspec-
tion programs for petroleum liquid storage vessels which are
covered by New Source Performance Standards (NSPS). Included are
sections which explain the process, the regulations, control
techniques and the responsibilities of the enforcement agency
personnel.
1-1
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2.0 STATE IMPLEMENTATION PLANS (SIP) AND NEW
SOURCE PERFORMANCE STANDARDS (NSPS)
2.1 EXISTING SOURCES - SIP
SIP regulations applying to hydrocarbon storage are gener-
ally expressed in terms of required control devices and precautions
rather than in terms of emission limitations. This same approach
is utilized in the New Source Performance Standards for petroleum
storage.
2.1.1 Summary of Typical SIP Regulations
A majority of the states have petroleum storage regulations
in their final SIP's. Typically, a SIP regulation will be worded
in the following manner: "No person shall place, store or hold
in any stationary tank, of more than 40,000 gallons capacity, any
volatile organic compounds unless such tank is a pressure tank
capable of maintaining working pressures at all times to prevent
vapor or gas loss to the atmosphere, or is designed and equipped
with one of the following vapor loss control devices: floating
roof, vapor recovery system, or other equipment or means of equal
efficiency for purposes of air pollution control as approved by
the Agency." The most common difference between regulations in
various states is the specification of a different minimum tank
capacity covered by the regulation.
The "cut-off" vapor pressure limits which provide the basis
for selection of a particular system of storage (e.g., floating
roof, vapor recovery system) in NSP standards (see Table 2.1, Sec-
tion 2.3.1) are essentially the same values as for most SIP regula-
tions.
2.2 SUMMARY OF NEW SOURCE PERFORMANCE STANDARDS
Performance standards for new storage vessels for petroleum
liquids apply only to vessels of more than 151,412 liters (40,000
gallons) capacity with the following exceptions:
• Pressure vessels which are designed to operate in excess
of 776 mm Hg (15 psig) without emissions to the atmosphere
except under emergency conditions.
• Subsurface caverns or porous rock reservoirs.
2-1
-------
• Underground tanks if the total volume of petroleum
liquids added to and taken from a tank annually does
not exceed twice the volume of the tank.
e Tanks storing materials having a true vapor pressure,
as stored, of less than or equal to 26 mm Hg (0.5 psia).
« Storage vessels for petroleum or condensate stored,
processed, and/or treated at a drilling and production
facility prior to custody transfer.
e Tanks with a capacity of less than 246,000 liters (65,000
gallons) upon which construction or modification began
between June 11, 1973 and February 27, 1974. The pro-
posed NSP standards presented June 11, 1973 had a
minimum regulated capacity of 246,000 liters. The
adopted rules which appeared on February 27, 1974 had
a minimum regulated capacity of 151,412 liters.
These standards are stated in terms of equipment specifica-
tions, in which the type of equipment specified is related to the
true vapor pressure of the liquid to be stored. Compliance will
be determined by inspection of equipment and records of material
stored and of temperatures within the stored liquids.
2.2.1 Equipment Specifications
2.2.1.1 Equipment for Storage of Liquids of Intermediate Volatility
Liquids having a true vapor pressure equal to or greater
than 78 mm Hg (1.5 psia) but not greater than 570 mm Hg (11.1 psia)
must be stored in vessels equipped with a floating roof or a vapor
recovery system or an equivalent control system. A floating roof
may be a double-deck, or flexible single-deck, pontoon-type cover
which rests upon and is supported by the stored liquid.
2.2.1.2 Equipment for Storage of Liquids of High Volatility
Liquids having true vapor pressure in excess of 570 mm Hg
(11.1 psia) must be stored in vessels equipped with vapor recovery
systems or equivalent vapor control systems, A vapor recovery
system includes a system of collecting vapors and gases so as to
prevent their emission to the atmosphere (see pp. 110-112 of
Reference 8).
2-2
-------
2.2.2 Record Keeping
The owner or operator of a new volatile hydrocarbon storage
facility will be required to maintain daily records and monthly
summaries, and to retain such records and summaries for two years.
2.2.2.1 Information to be Filed
Information required by these regulations for each storage
vessel on a daily basis includes the type of petroleum liquid
stored, the typical Reid vapor pressure of the petroleum liquid
stored, the dates during which the tank is storing materials and
the periods the tank is empty. Monthly summaries of average
temperatures and true vapor pressures of the liquids must be
maintained for any vessels which contain petroleum liquids in the
following two categories.
• If the true vapor pressure, as stored, is greater than
26 mm Hg (0.5 psia) but less than 78 mm Hg (1.5 psia)
and the storage vessel is not equipped with a floating
roof, vapor recovery system or equivalent.
• If the true vapor pressure, as stored, is greater than
470 mm Hg (9.1 psia) and the storage vessel is not
equipped with a vapor recovery system or equivalent.
The average monthly storage temperature is an arithmetic average
calculated for each calendar month, from bulk liquid storage
temperatures determined at least once every seven days. The true
vapor pressure at each bulk liquid temperature is to be determined
in accordance with American Petroleum Institute Bulletin 2517,
"Evaporation Loss from Floating Roof Tanks."
2.2.2.2 Notifications Regarding Initial Start-Up
The owner or operator of any new facility for volatile
hydrocarbon storage is required to furnish to the Administrator
of the Environmental Protection Agency written notifications of
anticipated initial start-up date and actual start-up date of the
new facility. The notification of the anticipated start-up date
must be postmarked no more than sixty (60) days nor less than thirty
(30) days prior to that date; notification of actual start-up must
be postmarked within fifteen (15) days after its occurrence.
2-3
-------
2.2.2.3 Records Regarding Start-Up, Shutdown and Malfunction
Records regarding start-up, shutdown, or malfunction of the
facility must be maintained for a period of two years following
each occurrence. A similar period of maintenance is required for
the records regarding operation of the facility, as described
above (Section 2.2.2).
Records should include the nature and cause of any malfunc-
tion, together with a notation as to corrective action and any
measures undertaken to prevent recurrence.
In this connection, "start-up" refers to a renewed operation
of the facility at any time; "shutdown" means the cessation of
operations of the facility; and "malfunction" is defined as any
sudden, unavoidable failure of air pollution control equipment, or
of the storage vessel itself, to operate in a normal manner. Pre-
ventable failures, such as may be caused by poor maintenance or
careless operation or by equipment breakdown due to such causes,
are not included in this definition.
2.2.2.4 Quarterly Reports
Quarterly reports are to be filed on the 15th day following
the end of each calendar quarter. These reports should include
the monthly summaries from the monitoring of operations, as well
as the records of start-up, shutdown, and malfunction during the
calendar quarter. Details should be furnished as to causes of
malfunctions and corrective measures applied.
2.3 APPLICABILITY OF STANDARDS
2.3.1 Determination of Vapor Pressure
Both equipment specifications and monitoring requirements
are keyed to the volatility of the petroleum liquids to be stored
in the new volatile hydrocarbon storage facility. This, in effect,
divides petroleum into five volatility classes, as shown in
Table 2.1.
Because the vapor pressure of a volatile hydrocarbon depends
upon its temperature, some petroleum liquids may belong to one
volatility class in cool weather, and to another, higher volatility
class in warm weather. In such cases, ambiguity arises regarding
which set of regulations is appropriate, or whether different
procedures should be followed with any given liquid when its vola-
tility class changes due to a change in the temperature.
2-4
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Table 2.1
VOLATILITY CLASSES OF PETROLEUM LIQUIDS
AS RELATED TO NEW SOURCE PERFROMANCE STANDARDS
FOR STORAGE FACILITIES
ro
en
Volatil
Class
I
II
III
IV
V
* F.R.
V.R.
ity True vapor Type of control
pressure, range required*
0 to 26mm Hg None
(0 to 0.50 psia)
26 to 78mm Hg None
(0.50 to 1.50 psia)
78 to 470mm Hg F.R. or V.R.
(1.50 to 9.1 psia)
470 to 570mm Hg F.R. or V.R.
(9.1 to 11.1 psia)
Above 570mm Hg V.R.
(above 11.1 psia)
= Floating Roof
= Vapor Recovery System
Maintain file
for type of
petroleum liquid
stored, typical
Reid vapor press.
and dates of
storage
no
yes
yes
yes
yes
Record keeping for
average monthly
storage temp.
and true vapor
pressure
no
yes
no
yes
no
-------
In such cases, the proper course of action is to require
the storage of any given liquid to be performed in a vessel of
the type required for the highest volatility class expected of
that liquid while it is in storage. Also, tn avoid infractions
of the record keeping requirements, records should be maintained
at all times on any liquid which could at any time move into a
volatility class for which reporting is required, as shown in
Table 2.1.
For record keeping purposes, the true vapor pressure (the
vapor pressure at storage temperature) of a stored liquid is used.
This pressure can be determined by procedures specified in Ameri-
can Petroleum Institute Bulletin 2517, "Evaporation Loss from
Floating Roof Tanks." For storage vessel planning purposes, if
the Reid vapor pressure [the vapor pressure at 37.8°C (100°F)] is
known, the true vapor pressure at any expected temperature (of the
bulk liquid) can be estimated from the nomograph shown in Figure
2.1. Thus, if the maximum expected temperature can be estimated,
the highest volatility class can be determined from the estimated
true vapor pressure at that temperature.
2.3.2 Computational Estimates of Emissions
Although the Administrator has determined that equipment
specification is the most acceptable approach to standards of
performance for storage vessels, the regulations do allow for the
use of equivalent technology, provided the same degree of emission
control can be demonstrated.
One method of demonstrating emission control is a calcula-
tion procedure developed by the American Petroleum Institute for
the estimation of product losses. Factors entering the computa-
tion include average wind velocity, average ambient diurnal
temperature change, product physical characteristics, tank size
and mechanical conditions, and volume throughput. Figures 2.2
and 2.3 show nomographs taken from API Publication 4080, for
estimating losses of gasoline from fixed-roof tanks.
Emission losses from a fixed-roof tank consist of losses
due to the movement of material into and out of a tank (working
losses) and losses resulting from standing storage (breathing
2-6
-------
losses). Figure 2.2 provides a means to calculate working losses.
In Step 1, draw a line through the number of tank turnovers per
year and the true vapor pressure (calculated from Figure 2.1)
through the pivot. In Step 2, connect the throughput in barrels
with the pivot intersection and extend that line until it inter-
sects the scale identifying gasoline working losses in barrels.
Figure 2.3 provides a means for calculating breathing losses.
The method requires five steps.
1) After finding the average atmospheric temperature change
in degrees Fahrenheit on the diagonal scale in the upper
right, move vertically upward to the corresponding paint
factor.
2) From the point on the paint factor scale move horizontally
to the right to the corresponding tank outage (height)
value.
3) Move vertically downward to the corresponding true vapor
pressure (calculable with knowledge of the Reid vapor
pressure, the storage temperature and Figure 2.1).
4) From this point move horizontally to the left to the
tank diameter.
5) From this point move vertically downward to the value
for breathing losses in barrels per year.
It may also be necessary to calculate emissions from a float-
ing roof tank for comparison. Emissions from a floating roof tank
consist of losses due to standing storage and liquid withdrawal.
The standing storage emission is a function of a series of factors
which include (1) type of product stored, (2) Reid vapor pressure,
(3) average storage temperature, (4) type of shell construction,
(5) tank diameter, (6) color of tank paint, (7,) type of floating
roof, (8) type and condition of seal, and (9) average wind velocity
in area.
The equations used in this method were developed by API
between 1952 and 1957 and were based on an intensive study of
available data from the petroleum industry. Up until the last
few years, these equations were used throughout the industry as
the best method of calculating tank emissions. Recently, a great
deal of testing has been performed to restudy the mechanisms which
are responsible for the evaporative emissions. There is good rea-
son to believe that the API equations will be revised to reflect
the new testing. One important preliminary result of the new work
has indicated that wind is the most important factor in determining
the emission level. The amount of seal gap is also a significant
factor, but stopping wind impacts with a good double seal may be
more effective than totally eliminating the gap.
2-7
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Figure 2.1 VAPOR PRESSURES OF GASOLINES AND FINISHED PETROLEUM PRODUCTS
2-8
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Figure 2,2 WORKING LOSS OF GASOLINE FROM FIXED-ROOF TANKS
2-9
-------
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23 30 33 40 30 40 70 60 90 100 123 130
H - l
it
-*-t 1—t—»—1 1—h-
-i 1—*-t-t-
-» trt « K to (
Figure 2.3 BREATHING LOSS OF GASOLINE FROM FIXED-ROOF TANKS
8 Z Breathing loss in Berrelt per Year, LT
-------
Table 2.2 STANDING STORAGE EVAPORATION EMISSIONS FROM FLOATING-ROOF TANKS:
Ly (LOSS IN bbl/yr) = Lf (LOSS FACTOR FROM FIGURE 2.4) TIMES MULTIPLYING FACTOR
(FROM THIS TABLE) (AP-40, Page 633.)
factors
apply to
h
Gasoline
Crude oil
-in: — ; — : — .
Welded tanki
Pan or pontoon roof
Single or double seal
Modern
Tank
paint0
L«
grey
1.0
0.75
White
O.°0
0.68
Old"
Tank
paint
Lt
grey
1. 33
!.0
White
1.40
0.90
Riveted tanks
Pan roof
Single teal
Modern
Tank
paint
Li
grey
3.2
I.*
White
2.9
i.i
Old*
Tank
paint
Lt
grey
4.2
3. 1
While
3.8
2.8
Double seal
Modern
Tank
paint
Lt
grey
2.8
I. 1
White
2. 5
1.9
Old"
Tank
paint
Lt
grry
3.8
2.8
White
3.4
2.5
Pontoon roof
Single seal
Modern
Tank
paint
Lt
grey
2.8
2. 1
White
2.5
1.9
Old"
Tank
paint
. Lt
grey
3.8
2.8
White
3. 4
2.5
Double seal
Modern
Tank
paint
Lt
grey
2.5
1.9
White
2. 2
1.7
Old*
Tank
paint
Lt
Hrey
3. 3
2. 5
White
3.0
2.2
"Aluminum paint is considered light grey in loss estimation.
//I/I///
FOR AVERAGE HIND VELOCITY
REFER TO API BULLETIN
2513, EVAPORATION LOSS IN
THE PETROLEUM INDUSTRY-
CAUSES AND CONTROL, OR
LOCAL IEATHER BUREAU DATA
/I / I/ /i / i / i/ i/
30 4050 60 70 BO 90 100 ItO 1ZO 130 1*0 ISO
FOR TANKS LARGER THAN 150 It
DIAMETER. MULTIPLY LOSS FOR
ISO-ft-DIAMETER TANK BY RATIO
8 7654
TRUE VAPOR PRESSURE,PIia
3 2 1
100 ZOO 300 400 500 600 700 BOO 900 1000
LOSS FACTOR, L,
(MULTIPLY BY VALUE FROM TABLE TO OBTAIN ADJUSTED LOSS)
Figure 2.4 CALCULATION OF EMISSION FACTOR, Lf, FOR STANDING STORAGE EVAPORATION
EMISSIONS FROM FLOATING-ROOF TANKS (AP-40, page 633.)
2-11
-------
With values for these parameters and Table 2.1 and Figure
2.4, the standing losses from a floating roof tank can be estimated.
The process involves five steps.
1) After establishing the true vapor pressure in psia for
the liquid stored using the Reid vapor pressure, the
storage temperature and Figure 2.1, find the correspond-
ing value on the scale in the lower left hand corner of
Figure 2.4.
2) From this point move vertically upward to the corres-
ponding average wind velocity measured in miles per hour.
3) From this point move horizontally to the right, past the
zero line, to the corresponding tank diameter.
4) Move vertically downward to the corresponding loss
factor, Lf.
5) Once Lf has been determined, consult Table 2.2 to estab-
lish the adjusted loss value based upon type of tank,
type of roof, type of seal and its condition, paint color,
and product type.
Such computations could be useful in support of an argument
that emissions of hydrocarbons from an installation under particular
conditions were not excessive. However, compliance with NSP stan-
dards cannot be established through this approach, since the stan-
dards are not given in terms of actual emission rates.
2-12
-------
REFERENCES FOR CHAPTER 2
1. Duncan, L. J., "Analysis of Final State Implementation
Plans - Rules and Regulations," Environmental Protection
Agency, Office of Air Programs, Research Triangle Park,
N.C., Publication Number APTD - 1334, July 1972.
2. Federal Register, Vol. 36, December 23, 1971.
3. Federal Register, Vol. 38, No. Ill, June 11, 1973.
MT'
4. Federal Register, Vol. 38, No. 198, page 28564, October
15, 1973.
5. Federal Register, Vol. 39, No. 47, page 9307, March 8, 1974.
6. Federal Register, Vol. 39, No. 75, page 13776, April 17, 1974.
7. Federal Register, Vol. 39, No. 116, page 20794, June 14, 1974.
8. "Field Surveillance and Enforcement Guide of Petroleum Refin-
eries (Final Draft)," prepared by The Ben Holt Co., Pasadena,
California , for Environmental Protective Agency, Research
Triangle Park, N.C., July 1973.
9. Air Pollution Engineering Manual, Second Edition. Publica-
tion Number AP-40, May 1973.
2-13
-------
3.0 PROCESS DESCRIPTION, ATMOSPHERIC EMISSIONS
AND EMISSION CONTROL METHODS
3.1 PROCESS DESCRIPTION
Four types of tanks predominate in the storage of petroleum
liquids: Cone (or fixed) roof, floating roof, pressure and vari-
able vapor space tanks. Cone roof tanks are generally simple
cylindrical steel vessels with conical steel roofs. They are
normally designed to withstand only a few inches of water pressure
or vacuum in the enclosed vapor space. From an air pollution
standpoint, they are thus only suitable for storing low vapor
pressure materials unless equipped with vapor recovery devices.
Floating roof tanks are similar to cone roof tanks except
that they are fitted with a deck or roof that floats on the sur-
face of the stored liquid. A sliding seal is provided at the tank
wall, and the tank may have a cone roof in addition or may rely
solely on the floating deck for a roof. Such tanks limit hydro-
carbon losses because the roof floats upon the product and the
air space in contact with the volatile stock is almost completely
eliminated.
Pressure tanks are designed to contain substantial pressure
and are frequently made in the form of spheresor cylindrical "bullets."
They are normally designed to contain the stored material without
venting except in emergencies. Since pressure tanks are much more
expensive to construct than cone or floating roof tanks, their use
is usually restricted to the storage of high vapor pressure materials
such as butane. Nonventing pressure tanks are not subject to NSPS.
Pressure tanks that vent can be considered as a special form of fixed
roof tank and will not be treated separately.
Variable vapor space or conservation tanks are equipped with
expandable vapor reservoirs to accommodate vapor volume fluctuations
attributable to temperature and barometric pressure changes. Vari-
able 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.
3,1,1 Cone Roof Tanks
Cone roof tanks are normally cylindrical, constructed of
welded steel plate, with a welded steel floor. The tank walls are
self-supporting and normally a ladder is provided for access to
the roof. Near the base of the tank wall, flanged cleanout doors,
3-1
-------
entry manways, water drains, firewater connections and product
lines are attached. The tanks are usually surrounded by firewalls
which would contain any product spill. The construction o? this
firewall is subject to the provisions of the Spill Prevention
Control and Countermeasure (SPCC) Plans. The tank has a welded
steel plate roof which is attached to the upper rim of the tank
walls. The roof is supported by a welded steel structure in larger
tanks. There is generally a manway in the roof for access, a con-
nection for the tank level indicator, a small hatch for sampling
and hand gauging, and a conservation vent. The conservation vent
is a relief type valve which allows a small pressure or vacuum to
build in the tank before it opens to the atmosphere. It is usually
set at 2 oz/sq. in. This helps minimize vapor losses due to breath-
ing effects. Some fixed roof tanks have gas blanketing systems which
are used to keep a positive pressure on the inside of the tank in
order to prevent oxygen from entering. The gas can be natural gas,
refinery gas, or an inert gas such as nitrogen. Fixed roof tanks
are also associated with vapor recovery systems. These systems
collect all excess vapors and dispose of them in an environmentally
acceptable manner.
3.1.2 Floating Roof Tanks
The principle used in floating roof tanks is the elimination
of vapor spaces. This is accomplished by floating a rigid deck or
roof on the surface of the stored liquid. The roof then rises and
falls according to the depth of stored liquid. The roof is equipped
with a sliding seal at the tank wall so that the liquid is com-
pletely covered. No additional roof is required, however, many
tanks are equipped with a standard fixed roof that covers the
floating roof.
Sliding seals are an important feature of all floating roofs.
The ideal seal would be vapor tight, long lasting and require little
maintenance. However, some clearance between seal and tank wall is
necessary for roof movement. Seals are situated at the rim of the
roof, at support columns and at all points where tank appurtenances
pass through the roof (see Figure 3-1). Two basic types of seals
are commonly used today; the metallic and the nonmetallic seal.
The conventional metallic seal generally consists of vertical metal
plates or shoes connected by braces or pantograph (electrical)
devices to the floating roof. The shoes are suspended in such a
way that they are forced outward against the inner tank wall. An
impervious fabric bridges the area between the tops of the shoes
contacting the tank wall and the circumference of the floating
roof. The fabric is often protected by a metal cover (see Figures
3-2 through 3-4). Riveted tanks, as opposed to welded structures,
3-2
-------
GAUGE
HATCH
ANTI-
ROTATION
CABLE
GROUND
CABLE
GAUGING
UNIT
PERIPHERAL
SEAL
PRESSURE-VAC
VENT
COLUMN
NEGOTIATOR
AIR SCOOP
OVERFLOW
FLAT SHEET
SURFACE
SURFACE
SUPPORT RIB
PONTOON
MANWAY
FILL LINE
WITH DIFFUSER
SUPPORT LEG
Figure 3.1 SCHEMATIC VIEW OF TYPICAL FLOATING DECK
(FROM ALTECH INDUSTRIES, INC,, ALLENTOWN, PENNSYLVANIA,
TECHNICAL LITERATURE)
3-3
-------
Tank
Shell'
Secondary Seal Optional
Primary Fabric Seal
(Location varies according
to manufacturer)
Metallic Seal
Seal supports not shown.
Floating
Roof
Figure 3.2 SCHEMATIC OF A METALLIC SEAL
(A.P.I. PUBLICATION NO. 2517)
HEXUM CLOSUkt
FIEXUHE
UPPER INSL'LATOft
LOWER INSULATOR
?ANTACRAPH HANGER —
SEALING WNO
Figure 3.3 METALLIC SEAL SITUATED IN A DOUBLE-DECK FLOATING ROOF
(CHICAGO BRIDGE AND IRON CO., CHICAGO, ILL,)
3-4
-------
EXPANSION JOINT FABRIC
-rrj.^
SECONDARY SEAl
FABRIC
SOLE PLATE
SCALING RING
FLEXURE
STANDARD HORTON
SEALING RING
WITH
PANTAGRAPH
HANGERS
SOLE PlATt
Figure 3.4 METALLIC SEAL EQUIPPED WITH SECONDARY
SEALS TO STOP VAPOR LOSSES DUE TO HIGH WINDS
ON RIVETED TANKS (CHICAGO BRIDGE AND
IRON CO., CHICAGO, ILL.)
3-5
-------
pose a special problem at the gap between seal and tank wall. Rivet
heads may extend from the wall by as much as an inch at the bottom
of the tank where the walls are thickest. Therefore, the spaces
between the rivet heads create gaps. Also, the rivets can tear seal
fabrics. To resist tearing, seal fabrics must be thick and tough,
and hence may not be flexible enough to conform to the irregularities
of the tank wall.
The nonmetallic seal is usually made of a hollow flexible
plastic or fabric tube filled with plastic foam, liquid or com-
pressed air (see Figures 3-5 through 3-8). The pneumatic, inflated
seal is provided with uniform air pressure by means of a small
expansion chamber and control valves. The sides of the tube remain
in contact with the roof and inner shell. The liquid-filled tube
holds a ribbed scuff band against the tank wall. The ribbed band
acts as a series of wiper blades as well as a closure. All tubes
are protected by some type of weather covering. Column and guide
cable seals are usually close fitting flexible plastic sheets.
The sheets cover holes cut in the floating roof and are sealed at
the edges of the holes by resting on plastic or metal rims fitted
around the holes. The sheet is sometimes allowed to slide horizon-
tally on the rim to provide for vertical misalignment of the column.
Floating roofs are taken as the standard of effective emis-
sion control for storage tanks. Their effectiveness depends on the
material stored and the total throughput. Significant reductions
over emissions generated using a fixed roof tank are achieved with
floating roof tanks.
3.1.2.1 Single Floating Roof
Where single floating roofs are employed the roof is exposed
to the weather. Provisions must be made for draining off rain
water and for snow removal, and the sliding seal usually requires
protection from dirt. Maintenance costs are normally higher than
for covered floating roofs. In general, single floating roofs are
not recommended for aviation fuels, particularly where rain or
snowfall are heavy.
3.1.2.1.1 Pan-Type
The pan-type was the first floating roof developed. This
consists of a flat metal plate with a vertical rim and sufficient
stiffening braces to maintain rigidity. The plate is sloped down-
ward toward the center where a drain is provided for rainwater.
Since the roof floats up and down with the liquid level, a flexible
drain connection must be removed manually as necessary to prevent
sinking the roof. Metallic seals are commonly used with pan-type
floaters. The roof is equipped with automatic vents for pressure
and vacuum release, adjustable legs to limit low level travel, man-
ways, gauge hatch, and a roller footed ladder that adjusts to the
roof level.
3-6
-------
Tank ,
Shell
W.olh.r Shl.ld
Scat Containing
liquid, Cat, or
Rtiilienl Maltrial
;/•- Floating
Roof
Note: Seal supports not shown.
Figure 3..5 SCHEMATIC OF A NONMETALLIC SEAL
(A.P.I. PUBLICATION NO. 2517)
WEATHER SHIELD -
SEALING BAND
SEALING LIQUID-
NORMAL
PRODUCT LEVEL
TANK SHELL -
ADAPTABLE
SEAL SUPPORT
- R'M BAND
TOP DECK
BOTTOM DECK
Figure 3.6 LIQUID-FILLED NONMETALLIC TUBE SEAL
(CHICAGO BRIDGE AND IRON CO., CHICAGO, ILL.)
3-7
-------
WEATHER SHIELD— ;
SEAL CURTAIN
Figure 3.7 AIR INFLATED NONMETALLIC TUBE SEAL
(CHICAGO BRIDGE AND IRON CO., CHICAGO, ILL.)
3-8
-------
WEATHER SHIELD
HANGER BAR
CURTAIN SEAL
SEAL ENVELOPE
SEAL SUPPORT
RING
RESILIENT
URETHANE FOAM'
Figure 3.8 FOAM-FILLED NONMETALLIC TUBE SEAL
(CHICAGO BRIDGE AND IRON CO., CHICAGO, ILL.)
3-9
-------
Although simple and relatively inexpensive, the pan-type is
now seldom used as a single roof. Tilting, holes, and heavy snow
or rain loads have caused a significant number of these roofs to
sink. Also, the single metal plate in contact with the liquid
readily conducts solar heat with resulting high vaporization losses.
Applications of pan-type floaters is limited today to internal
floating roof tanks.
3.1.2.1.2 Pontoon
In order to overcome the problem of sinking and improve
emission control efficiency, the pan-type roof was modified by the
addition of pontoon sections to the top of the deck. The added
expense of the pontoons is generally felt to be justified by the
better stability achieved. The installation of a center drain with
hinged or flexible connections can aid in roof draining and help
reduce the sinking problem. Nonmetallic seals are generally used
on pontoon roofs. All other accessories used with pontoon roofs
are the same as those used with pan-type roofs.
Although the problem of roof stability is solved by the use
of pontoons, the high vaporization losses resulting from solar
heating are not noticeably reduced over those for the pan-type roof.
3.1.2.1.3 Double-Deck
Extending the pontoon sections to completely cover the roof
results in a new design, the double-deck roof. The added expense
of this design is generally considered to be justified by the added
rigidity and by the insulation provided by the dead air space be-
tween the upper and lower deck plates. The compartmented dead air
space is usually over one foot deep and provides enough insulation
to significantly reduce vapor losses from solar boiling. The space
may contain a mixture of air and organics, primarily methane. The
upper deck is sloped to a centrally located drain, the rain water is re-
moved through a flexible hose or drain pipe. The bottom deck is domed
upwards to trap any vapor entrained with incoming liquid or formed in
storage. Nonmetallic seals are commonly found on this type of roof.
Accessories are similar to those used with pan-type or pontoon roofs.
3.1.2.2 Covered Floating Roof
The American Petroleum Institute has designated the term
"covered floating roof" to describe a fixed roof tank with a steel
pan-type floating roof inside. The term "internal floating cover"
has been chosen by the API to describe covers constructed of ma-
terials other than steel, such as aluminum and urethane foam.
Floating roofs and covers can be installed inside fixed roof tanks.
3-10
-------
Since the fixed roof protects the floating roof from the
weather, no provision is required for rainwater removal. Main-
tenance is reduced since the internals, particularly the seal, are
protected and the product is less likely to be contaminated by dirt
or water. The rolling stairway is eliminated, but antirotational
guides are added to maintain alignment between fixed roof and float-
ing roof openings. If the tank has support columns they must pene-
trate the float, and the opening must be sealed. Practical column
seals have been devised, but they add to the installed and mainte-
nance costs. Also, the space between the roofs must be vented to
prevent the possible formation of a flammable and therefore explo-
sive mixture. Hooded vents provide adequate ventilation for above-
ground tanks, but underground tanks may present a special problem.
A possible solution is the use of blowers. Underground steel tanks
with horizontal stiffening rings at the wall cannot be sealed with
the usual seal rings. A satisfactorily smooth vertical surface can
probably be supplied by filling the space between stiffening rings
with Gunite or steel plates, but no existing installations of this
sort are known.
The conversion of existing fixed roof tanks to covered floaters
is standard practice in the industry. In fact, the cost of conversion
is usually less than the cost of converting the tank to a single roof
floating roof tank.
3.1.2.2.1 Pan-Type
Although pan-type roofs are no longer considered suitable for
single roof tanks, they are used as internal floating roofs. They
are cost competitive with other types of internal floating covers
when they are installed as part of a new tank. They can also be
added to existing tanks, but at a cost that is somewhat higher than
for some of the newer covers such as those made from rigid poly-
urethane.
3.1.2.2.2 Pontoon
Since covered floating roofs are protected from the elements,
the added cost of pontoons does not appear to be justified.
3.1,2.2.3 Double-Deck
Double-deck floats are more expensive than pontoons, and the
added cost does not appear to be justified.
3-11
-------
3.1.2.2.4 Rigid Polyurethane
Rigid polyurethane foam floating covers are a recent innova-
tion, and several different styles of covers are now being offered
by various companies. The number of installations and their service
record is sufficient reason to consider them to be an established
system, but there has not been enough service time to establish the
superiority of one style over another.
One of the first styles to appear on the market used a poly-
urethane core with a laminated aluminum sheet covering. Difficulty
was experienced when the solvent being stored in the tank attacked
the adhesive used and loosened the aluminum sheeting. A new method
of bonding the sheet to the core has been developed that is said to
overcome this problem.
Most of the polyurethane covers being offered are covered
with fiberglass. The resin for bonding the glass must be chosen
with regard to the material being stored; however, it is now pos-
sible to provide a resin that has shown to be satisfactory for use
with gasoline and turbine fuels.
One type of cover is assembled from fiberglass covered poly-
urethane foam planks. The finished assembly weighs only about one
pound per square foot, but has sufficient strength to permit main-
tenance and inspection personnel to walk on the cover while standing
on its legs with the tank dry. Closed cell foam is used so that even
if the cover is punctured it will not sink or become saturated by the
stored liquid. Column seals, manways and other accessories are easily
installed by cutting an opening in the deck and cementing an appropri-
ate fitting in place. Column seals can be designed for abnormal ver-
tical misalignment in excess of four to six inches by increasing the
diameter of the deck opening. The wiper is attached to a section of
board that is free to slide horizontally across the seal between the
board and the opening. A temporary two foot by eight foot hole must
be cut in existing tanks to permit installation of this type of roof,
but the installation labor and time is about half that for a pan-type
deck.
3.1.2.2.5 Floating Fabric Covers
Flexible coated fabric covers have been in use for a number
of years, particularly in Europe. Urethane coated nylon with an
inflatable tubular float of the same material around the circumfer-
ence is one type. Other covers are only suitable for use in small
diameter tanks, and, therefore, are not of use in the tanks under
consideration.
3-12
-------
3.1.3 Variable Vapor Space Tanks
Variable vapor space (also called conservation) tanks consist
basically of two different types: lifter-roof tanks and tanks with
internal flexible diaphragms or internal plastic floating blankets.
3.1.3.1 Lifter-Roof Tanks
The lifter-roof, commonly called a gas holder, is used for
low-pressure gaseous products or for high-volatility liquids. This
type of vessel can be employed as a vapor surge tank when manifolded
to vapor spaces of fixed roof tanks. The lifter-roof tank has 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 dry seal consisting of a gastight flexible fabric, or a
liquid seal. The sealing liquid can be fuel oil, kerosene, or water.
Water should not be employed as a sealing liquid where there is dan-
ger of freezing.
The physical weight of the roof itself floating on vapor main-
tains a slight positive pressure in the lifter-roof tank. When
the roof has reached its maximum height, the vapor is vented to pre-
vent overpressure and damage to tank.
3.1.3.2 Internally-Modified Fixed-Roof Tanks
The second type of conservation tank consists of fixed-roof
tanks equipped with internal flexible diaphragms or internal plastic
floating blankets. The internal coated fabric diaphragm is flexible
and rises and falls to balance changes in vapor volume. Normal
operating pressure is 1/2 ounce per square inch, which is approx-
imately one-eighth the operating pressure possible with most gas
holders. Two basic types of diaphragm tanks are the integrated
tank, which stores both liquid and vapor, and the separate tank
which stores only vapor.
3.2 ATMOSPHERIC EMISSIONS
Hydrocarbon emissions from storage tanks arise from breathing
loss, working loss, standing storage loss, end spills, and leaks.
With proper operating and maintenance practices, spills and leaks
should not be significant except for accidents or emergencies.
Breathing losses occur when the vapors contained in a tank expand
because of changes in temperature or atmospheric pressure. Diurnal
temperature variations can lead to significant hydrocarbon emissions.
The amount of loss is a function of the volume of vapor space in the
tank, changes in liquid level and temperature, changes in atmospheric
3-13
-------
pressure, the venting pressure of the tank, and the vapor pressure
of the stored material.
Working losses occur when tanks are filled; the incoming
liquid displacing the vapor from the tank. The amount of loss is
a function of the volume of liquid transferred, the temperature,
and the vapor pressure of the stored material. Splash or above sur-
face loading can result in significantly higher losses than subsur-
face or submerged loading. Floating roof tanks theroetically have
no significant working losses.
Floating roof tanks are subject ot reduced breathing and work-
ing losses due to the nature of the tank operations. Different causes
of emissions are associated with a floating-roof tank. These causes
are known as standing (wicking) and withdrawal evaporation losses
(wetting). Wicking emissions are caused by the capillary flow of
the liquid between the outer side of the sealing ring and the inner
side of the tank wall. The wetting emission results when the float-
ing roof moves toward the bottom of the tank during emptying and
leaves the inner tank shell covered with a film of liquid, which
evaporates when exposed to the atmosphere. Procedures for estimating
losses from hydrocarbon storage, with examples, are presented in the
following publications, available from the American Petroleum Insti-
tute, Publications and Distribution Section, 1801 K Street, N.W.,
Washington, D.C. 20006. Use of these equations should be carefully
considered. The equations are based upon measurements performed on
older tanks storing gasoline and crude oil. Estimating emissions
from modern tanks storing other petroleum liquids based upon these
equations does not have a measured statistical basis and may provide
misleading values. (See Section 2.3.2)
BULLETIN TITLE
2512 Tentative Methods of Measuring Evaporation Loss from
Petroleum Tanks and Transportation Equipment (1957)
2513 Evaporation Loss in Petroleum Industry - Causes and
Control (1959)
2514 Evaporation Loss from Tank Cars, Tank Trucks and
Marine Vessels (1959)
2515 Use of Plastic Foam to Reduce Evaporation Loss (1961)
2516 Evaporation Loss from Low Pressure Tanks (1962)
3-14
-------
BULLETIN TITLE
2517 Evaporation Loss from Floating Roof Tanks (1962)
2518 Evaporation Loss from Fixed Roof Tanks (1962)
2519 Use of Internal Floating Covers for Fixed Roof Tanks
to Reduce Evaporation Loss (1962)
2520 Use of Variable Vapor Space to Reduce Evaporation
Loss (1964)
4062 Investigation of Passenger Refueling Losses APRAC
Project CAPE-9-68 Coordinating Research Council
4080 Recommended Procedures for Estimating Evaporation
and Handling Losses
3.3 EMISSION CONTROL METHODS
3.3.1 Conservation Ve_nts_
Adequate emission control for the storage of low vapor pres-
sure hydrocarbons(<1.5 psia TVP) can be obtained by equipping cone
roof tanks with conservation vents. A conservation vent is a form
of pressure and vacuum relief valve that provides a large gas flow
area with a differential pressure setting of a few inches of water.
The seal is provided by gasketed metal plates held in place over an
opening by a system of levers and adjustable weights. The use of a
conservation vent reduces the amount of breathing losses by venting
only when the set pressure differential is exceeded.
3.3.2 Floating Roofs
Floating roofs may be used for the storage of hydrocarbons
with true vapor pressures (TVP) at storage conditions of 11.1 psia
or less. The use of a floating roof eliminates any vapor space in
storage vessel and this significantly reduces breathing and working
losses. To be successful, the floating roof must be equipped with an
adequate and well maintained roof-to-wall sliding seal. Gauge hatches
and other openings must also be provided with seals. Deterioration of
the condition of these seals can significantly affect the degree of
control achievable from a floating roof. Therefore, the type of seal
being installed should be carefully reviewed for its maintenance and
reliability history.
3-15
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The floating roof tank is generally accepted as the standard
for adequate control for storing hydrocarbons such as gasoline, when
the TVP at storage conditions is 11.1 psia or less. In some cases,
cooling systems, such as circulation through water-cooled heat ex-
changers, are used to lower the hydrocarbon TVP so as to permit
storage in floating roof tanks.
3.3.3 Flares
Flares may sometimes be used for the control of hydrocarbon
emissions from storage tanks. Since the hydrocarbon is burned, the
practice is wasteful and the installation must be carefully designed
to avoid the hazards of fire and explosion. For these reasons the
use of flares is generally limited to small, remotely located
installations.
3.3.4 Recovery to Fuel Gas
Petroleum refineries utilize fuel gas systems to collect
overhead gasses generated from various processing units and dis-
tribute it to heaters and other users. Cone roof storage tanks
can be connected to the fuel gas system in such a way that fuel gas
is used to blanket the tanks and any vented vapor is put back into
the fuel gas system. Figure 3.9 is a sketch of such a system.
Fuel gas is admitted to the storage system through a pressure regu-
lating valve as required. Excess pressure is relieved through a
second pressure regulating valve and the vented vapor is compressed
and sent to the fuel gas system.
Such a system is reliant on a -functioning compressor at all
times. The compressor forces the blanketing fuel gas into the tanks
and draws off the vented vapors. A malfunction of the compressor
could result in the venting of gases generated during this period
to the atmosphere. Serious consideration should be given to the
type of compressor used, the reliability history of this unit, and
what provisions for standby capabilities are being made.
3.3.5 Vapor Recovery Systems
There are a number of different recovery system designs now
in use. Those that are commonly used which can meet the NSPS employ
compression, absorption, refrigeration, or a combination of these
steps to recover the hydrocarbon. One such system, shown in Figure
3.10, uses gasoline as an absorbent to recover the hydrocarbon.
The vapor vented from gasoline storage tanks is largely a mixture
of air and butane. The vapor is saturated with gasoline to ensure
that the vapor composition is above the flammable limit. The satu-
rated vapor is accumulated in a variable vapor space gas holder and
3-16
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CO
I
sr0***G,& TX/VXC
Figure 3.9 VAPOR RECOVERY SYSTEM FOR STQRAGE TANKS
-------
CO
I
00
Figure 3.10 HIGH PRESSURE ABSORBER UNIT
-------
is compressed and fed to the absorber where it is brought into con-
tact with gasoline pumped from storage. The gasoline absorbs the
hydrocarbon from the mixed vapor and the air is vented. The gaso-
line from the absorber is reduced in pressure in the flash separator
and stripper, and, still containing most of the absorbed butane, is
returned to storage. Vapor balance lines between tanks are frequently
used to reduce the load handled by the recovery system.
For more detail on the design of emission control equipment,
refer to "Air Pollution Engineering Manual (Second Edition)," John
A. Danielson, available from the Government Printing Office as
EP 4.9:40-2 and "A Study of Vapor Control Methods for Gasoline
Marketing Operations," 2 Volumes, prepared by Radian Corporation,
available from the Government Printing Office as EPA-450/3-75-046-a.
3-19
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4.0 PROCESS AND CONTROL DEVICE INSTRUMENTATION
4.1 PROCESS INSTRUMENTATION
Storage tanks are frequently equipped with level gauges and
temperature indicators. Sometimes provision is made for remote
reading at a control house. Vapor pressure of the stored material
is usually determined by manual sampling and testing in the control
laboratory.
4.2 CONTROL DEVICE INSTRUMENTATION
Recovery to fuel gas systems normally have pressure gauges
indicating fuel gas supply pressure, tank header pressure, compres-
sor inlet vacuum, and compressor discharge pressure. The tank
header pressure should be less than the set pressure of the conser-
vation vent, since otherwise the tanks will vent to the atmosphere.
If the compressor cannot maintain a vacuum at the inlet, the com-
pressor is probably undersized or malfunctioning.
Vapor recovery system instrumentation should include devices
for reading absorber pressure, the temperature of the gasoline to
the absorber, the flow rate of the gasoline to the absorber,
and the flow rate of the vapor through the compressor. These values
should be checked against design values.
4-1
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5.0 START-UP/MALFUNCTIONS/SHUTDOWN
Tanks require periodic cleaning and occasional repair, but
will probably only be taken out of service for such purposes once
every few years. When a tank is taken out of service, the petroleum
liquid is first completely drained out. The empty tank is then in-
jected with low pressure steam for approximately 24 hours to elim-
inate hydrocarbons still present. The steam is vented to the atmo-
sphere causing emission of hydrocarbons. Once the hydrocarbon level
of the tank atmosphere has been reduced to below the low explosi-
bility limit, air eductors are attached, usually to the bottom man-
hole. Plant air is circulated through the tank and exits through
the open upper manhole. The air cools the tank and ventilates the
internal atmosphere to a level which is tolerable for the workers.
Any hydrocarbons remaining after the steaming cycle would escape
during this airing out process.
Normal care to avoid spills and following good maintenance
procedures should be sufficient to avoid significant emissions.
The seals on conservation vents, gauge hatches, and floating roof
wall seals should be inspected regularly to avoid malfunction.
Recovery to fuel gas and vapor recovery systems do not pre-
sent any particular problems from the point of view of pollutant
emissions. The most common malfunctions are failure of pressure
control valves and compressor and pump breakdowns, and the affected
tanks will vent to the atmosphere if the control system is not
operating. A good inspection and maintenance program will prevent
most such malfunctions.
5-1
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6.0 INSPECTION PROCEDURES
An air pollution inspection consists of entering a facility
to determine if the equipment or processes meet the standard and
comply with the rules and regulations of the air pollution control
agency. The inspection process also includes a spot-check of
selected records maintained by the operator. The Inspecting Offi-
cer (10) must observe, in a qualitative manner, the items associated
with atmospheric emissions - volatile hydrocarbon storage tanks in the
present case. Condition and type of equipment, procedure for filling
and emptying the tanks, and general housekeeping all influence the
emission rate. Tank design is a major factor that must be reviewed
at the time the construction permit or operating permit applications
are evaluated.
The importance of plant inspection as a field operations
activity that provides for the systematic detection and observation
of emission sources cannot be overemphasized. The whole process of
inspection follows certain rules and guidelines which are discussed
briefly in the following sections.
6.1 CONDUCT OF INSPECTION
There are four important components in the conduct of inspec-
tion of volatile hydrocarbon storage tanks:
• Formal procedure (e.g., use of credentials, ask to see
appropriate official).
• Overall inspection process (e.g., review of process and
records).
• Safety precautions and procedures.
• Frequency of inspection.
Description of the above four components follows.
6.1.1 Formal Procedure
Prior to the actual on-site inspection, the 10 should inves-
tigate and familiarize himself with any available data on plant
operations. In preparation for the inspection, the official should
obtain the following data:
• Information for each major storage tank (capacity greater
than 40,000 gallons), including material stored, operating
conditions and normal filling and emptying schedules. Much
6-1
-------
of this information may be entered in forms such as those
shown in Figure 6.1 for easier reference.
• Plot plans showing disposition of all major units of the
facility including the locations of all petroleum liquid
storage tanks.
• Business and ownership data including names of responsible
management personnel.
At the time of inspection, the 10 must have with him the cre-
dentials showing his identity as an official of an air pollution
control agency. He should arrange an interview with the management
of the facility. The interview with plant managers and equipment
operators can verify data gathered and clarify and any misunderstanding
with regard to the information reviewed prior to the inspection.
6.1.2 Overall Inspection Process
Some inspections, especially initial ones, are comprehensive,
designed to gather information on all the equipment and processes
of the facility. Others are conducted for specific purposes such as:
• Obtaining information relating to violations.
• Gathering evidence relating to violations.
• Checking permit or compliance plan status of equipment.
• Investigating complaints.
• Following up on previous inspection.
• Obtaining emissions information by source testing.
• Evaluating compliance with SPCC spill regulations and
other regulations.
An initial inspection lays the groundwork for evaluating
potential emissions of hydrocarbons from tanks and for assessing
the relative magnitude of pollution control problems requiring
correction, reinspection, or further attention.
The initial inspection has two phases: a plant survey and
a physical inspection of the equipment and processes. After this
inspection is complete, routine surveillance continues.
6-2
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Periodic reinspections are scheduled and occasional special
purpose inspections (unscheduled) may be required. During the
initial survey, the inspector examines the possible effects of
emissions on property, persons and vegetation adjacent to the
source; he may also collect samples or specimens that exhibit
possible pollution-related damage. Sensory observations (odor
detection) in case of excess hydrocarbon vapor discharge from
vapor controlled tankage are also made.
Sources like storage tanks are so similar that standard
inventory forms are used to report them (see Figure 6.1). These
inventory forms record the type of tank, vapor control, function,
dimensions, product stored, Reid vapor pressure, storage tempera-
ture, etc., of each tank to determine compliance with rules. The
NSP Standards for storage tanks are stated in terms of equipment
specifications (e.g., type of tank and vapor recovery system).
The details have already been given in Section 2.2, where the
records related to tanks which must be maintained were also dis-
cussed (Section 2.2.3.2). The inspector must also review these
records kept by the operator.
An aid to the 10 is the information incorporated in appli-
cations to operate the equipment. The permit status of the equip-
ment should be routinely checked to detect any changes in equipment
or process that might invalidate an existing permit or conflict with
the variance conditions.
Similarly, alteration of equipment is frequently detected by
discrepancies in the equipment description (size of the tank for
example) or by changes noted on engineering applications in the
permit file.
6.1.3 Safety Equipment and Procedures
All facilities have standard safety procedures for employees
and visitors. These procedures also concern the 10. The 10 is
accompanied to the unit or units to be inspected by the air pollu-
tion representative within the plant or by such other informed
plant personnel as he might indicate.
Personal protection is necessary in many of the industrial
locations (including storage tanks for hydrocarbons) that an Inspec-
tion Officer may be required to visit.
The 10 should wear a head covering while in a plant, preferably
a hard safety hat. He should wear rubber gloves and goggles when
necessary. In the event of fire in the area of inspection, the 10
6-3
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AREA GRID NO.
FIRM NAME
M.R.NO.
TEL.
ZONE
ADDRESS OF PREMISES_
NATURE OF BUSINESS
CITY
POSTAL ZONE
RESPONSIBLE PERSON TO CONTACT
TITLE
INSPECTION REPORT
TANK GROUP NO.
INSPECTOR'S NAME
. DATE
19
Reinspection Record on Back of Sheet
Tank No.
Height
Diam.
Type
Gen.
Cond.
Product
Stored
RVP
Product
Storage
Temp.
Service
Vapor
Control
Permit
Status
Rules
Affected
Remarks
Codes and Standard Terminology
Type: C-Fixed Roof; F-Floating Roof; P-Pressure; O-Open Top; S-Spheroid; H-Horizontal; U-Underground.
Condition: G-Good; P-Poor; B-Bad
Service: Rundown; Storage; Blending or Mixing
Control: N-None; PVV-Conservation Vents; F-Floating Roof (SS-Single Seal; DS-Double Seal); V. R. -Vapor Recovery;
V. D. -Vapor Disposal; V. B. -Vapor Balance.
Figure 6.1 TANK INSPECTION CHECKLIST
-------
must leave immediately, and remain outside the area until the "All
Out" signal is sounded. He should use the buddy system when taking
a sample or gauging a tank of volatile or gaseous hydrocarbons. The
10 should be accompanied by another person and two persons should
remain together until the job is completed. Before sampling a tank,
he must make certain that all equipment is in workable order. He
must not smoke or carry cigarette lighters which may ignite when
dropped within a dangerous area such as an oil refinery. He should
use only approved flashlights in oil refineries.
6.1.4 Frequency of Inspections
Because of the complexity of many of the industries under
consideration, unit processes must be inspected systematically and
regularly. The frequency of reinspection of storage tanks is based
upon the findings during the initial inspection and the recommenda-
tions of the 10 and his supervisor. These recommendations obviously
depend on whether or not the "good" maintenance practices from the
pollution standpoint are being followed by the operator. Further,
the frequency would depend on the overall inspection load of the
control agency for the whole district. The reinspections are sched-
uled so that they can be completed within a month. The number of
reinspections assigned per district is based on the estimate that
all required inspections can be completed within one year.
The Inspection Officer may have occasion to inspect the tanks
out-of-schedule because of complaints or violations. In these cases,
he does not make a formal inventory reinspection, but uses the copy
of the previous inventory record (equipment list) from his files as
a check on status of the permit, compliance, or other situation.
6.2 INSPECTION CHECKLIST
Data obtained during an inspection can be summarized on forms
similar to the one shown in Figure 6.1. These forms also serve as a
record of inspection. During the inspection, data on these forms
will be completed and verified. In addition to the parameters speci-
fically mentioned in Figure 6.1, there are other factors which should
be considered for incorporation into a complete checklist.
1) In the event that the inspected facility has underground
tanks, what is the material throughput of each tank?
2) As a check to determine the applicability of NSPS, the 10
should obtain the dates of construction start, completion,
and initial service for each tank which has a questionable
status.
6-5
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3) For vapor control systems:
a) Manufacturer
b) Description of the type of system
c) Capacity
d) Estimation of efficiency. The 10 should ask if any source
tests have been conducted to determine a measured effeciency.
4) The 10 may also want to climb the floating roof tanks to de-
termine the liquid level with relation to the tank height. From
this vantage point, the officer will also be in position to
examine seal gaps and seal conditions. Materials used to mea-
sure seal gaps can vary in sophistication from the use of sized
aluminum dowels and a ruler to a single calibrated adjustable
expansion device. Careful note of the liquid level will aid
the inspector in evaluating how much of a variance in seal gaps
can be attributed to a tank being out-of-round. As the liquid
level in the tank increases, distortions in the tank diameter
also increase. While on the tank roof, the inspector may wish
to use an explosimeter (JW meter) to check for leaky seals.
These devices can also be used to document visual observations
of large seal gaps.
5) Compliance schedule data if necessary.
6) Individuals contacted
7) Tank capacity
8) Shell construction (riveted or welded)
9) Submerged fill (yes or no)
10) Roof Color
11) Shell Color
12) Paint condition:
a) Amount of chipping and flaking visible
b) The date of the last painting of the tank
13) Molecular weight and liquid density of material stored.
14) Average vapor space volume
15) Storage temperature (average and maximum)
16) Average ambient temperature
6-6
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17) Average wind velocity
18) Hydrocarbon emission rate
6.3 INSPECTION FOLLOW-UP PROCEDURES
Upon completion of the on-site inspection, an inspection
report should be written. This report should include data obtained
for each tank such as liquid level, temperature, and apparent odors.
Other equipment attached to the tank such as mixers or heaters should
also be noted. Finally, a statement should be made which indicates
approval of the tank's control system or notes any conditions which
may necessitate further action such as reinspection or denial of
permit to operate.
If an inspection indicates that a source is not operating
in compliance with applicable regulations, the 10 should follow
established Agency procedures regarding notice of violation, request
for source test, and related matters.
He checks to ensure that permits have been granted for all
applicable processes and equipment and their modifications. For
any later public complaints, he determines cause of complaint,
records pertinent data, issuing violation notices if appropriate,
and ascertaining adequacy of plans for prevention of future inci-
dents. He periodically reviews emergency procedure plans. He
makes sure that all shutdown procedures are being implemented during
periods of process curtailment. He coordinates with other agencies
participating in pollution reduction effort. As a part of inspec-
tion follow-up procedures, he also checks to see that engineering,
procurement, installation, and testing of equipment is proceeding
according to the approved plan.
In the case of incident and complaint investigations, court
actions, and variance board activity, the 10 will require the data
collected during his previous inspection visits to the facility.
For example, the point of emission of excessive odors may be traced
from an incident described in an operator's log or from an odor
survey record.
6-7
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REFERENCES FOR CHAPTER 6
1. Weisburd, M. I., "Air Pollution Control Field Operations
Manual, a Guide for Inspecting and Enforcement," Department
of Health, Education and Welfare, Public Health Service,
Division of Air Pollution, Washington, D.C., Publication
No. 937, 1962.
2. Brandt, C. S., and W. W. Heck, "Effects of Air Pollutants on
Vegetation," in "Air Pollution," Vol. 1, Stern, A. C, (Ed.),
Academic Press, New York, 1968=
3. "Guide for Compiling a Comprehensive Emission Control Inven-
tory (Revised)," Environmental Protection Agency, Research
Triangle Park, N. C., Publication No. APTD - 1135, March
1973.
4. "Field Surveillance and Enforcement Guide for Petroleum
Refineries (Final Draft)," prepared by The Ben Holt Co.,
Pasadena, California for Environmental Protection Agency,
Research Triangle Park, N. C., July 1973.
6-8
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7.0 PERFORMANCE TEST
7.1 PROCESS OPERATING CONDITIONS
To comply with NSPS, it is not necessary for source testing
to be conducted on petroleum liquid vessels, however, certain design
features must be inspected to determine that adequate provision has
been made for minimization of hydrocarbon emissions to the atmosphere.
Petroleum liquids are classified for storage purposes according
to their vapor pressures. Inspectors must determine that the follow-
ing conditions are met:
• Vessels used to store petroleum liquids having true vapor
pressures between 78 mm Hg (1.5 psia) and 570 mm Hg (11.1
psia) must be of the "floating roof" design or be equipped
with a vapor recovery system or equivalent.
• Vessels used to store petroleum liquids having a true vapor
pressure in excess of 570 mm Hg (11.1 psia) must be equipped
with a vapor recovery system or equivalent vapor reclaiming
system.
7.2 PROCESS OBSERVATIONS
Processes related to petroleum liquid vessels are basically
two: storage and working (filling and draining). Emissions from
storage of such liquids result from "breathing" losses caused by
thermal expansion and contraction of the liquid and its container,
while the working losses result from the transfer of bulk liquid
to and from the vessel. Process observations of these operations
during an inspection are very limited. During loading and unloading
operations, however, the inspector should attempt to uncover any
leakage problems.
There are several means easily available to the 10 which
will aid him in determining whether or not a leak exists. The
presence of an odor may indicate escaping gas, as well as hissing
sounds and heat plumes. Stains on paint surfaces could indicate
a leak in the tank wall. The 10 can be prepared to verify any
suspicions by having access to gas testing equipment such as explo-
simeters and by carrying soap or other bubbling solutions which could
be applied to a suspected leak.
During the course of the process observation, actual sampling
and analysis of the tank contents should be made to verify that the
material being handled is being stored in an acceptable manner. If
at all possible, the seal gaps at various liquid heights should be
7-1
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measured to determine how much of the gapping, if any, can be attributed
to tank out-of-round conditions.
7.3 EQUIPMENT OBSERVATIONS
While no defined provisions exist for emission testing of storage
vessels for petroleum liquids, inspectors should check the existing
storage facilities to make sure they are being properly used and in good
repair.
If the true vapor pressure of the liquid being stored or worked
is between 78 mm Hg and 570 mm Hg (1.5 psia and 11.1 psia), the storage
vessel must be of the "floating roof" design or be equipped with a vapor
recovery system or an equivalent. In cases where the liquid being stored
or worked has a true vapor pressure in excess of 570 mm Hg (11.1 psia),
the vessel must be equipped with a vapor recovery system or equivalent
vapor reclaiming system.
Tanks and vessels used to store petroleum liquids with true vapor
pressure 78 mm Hg (1.5 psia) and greater should be painted and maintained
such that excessive temperature and vapor pressure increases are pre-
vented. Paint should be continuous and of a heat-reflective nature.
Check all seals on the floating roof (usually these are of a rubberized
fabric type) for continuity and to make sure no deterioration or wear
has caused seals to develop holes or gaps. Many times these seals will
have a metal shield to protect seal from sharp objects; these shields
should be checked for completeness and to make sure that they are not
deformed so as to interfere with the function of the seal. All gauging
and sampling devices should be checked to make certain that seals are
effective at all times except when sampling and gauging is taking place.
The anti-rotational stabilizers should be inspected to ensure
proper operation. Water drainage ducts should be examined for the
presence of oil.
7.3.1 Emission Monitoring
No provisions for instrumental monitoring of hydrocarbon vapors
are established. Certain records must be maintained, however, which
can be used to determine emissions for a particular period of time,
should the need arise. Such records must be kept on file at least two
(2) full calendar years.
The records required to be maintained are the bulk petroleum
liquid temperature and true vapor pressure of petroleum liquid at bulk
liquid temperature. Monthly summaries should be kept of the following
information: type of petroleum liquid being handled, true vapor pres-
sure and bulk liquid temperature. If Reid vapor pressures are maintained,
they should have been determined according to ASTM method D-323-58. True
vapor pressure may be obtained from the Reid vapor pressure if the storage
temperature of the material is known (see Figure 2.1 of this manual).
7-2
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• REFERENCES FOR CHAPTER 7
1. Federal Register, Vol. 36, December 23, 1971.
2. Federal Register, Vol. 38, No. Ill, June 11, 1973.
3. "Field Surveillance and Enforcement Guide for Petroleum
Refineries (Final Draft)," prepared by the Ben Holt Co.,
Pasadena, California for Environmental Protection Agency,
Research Triangle Park, N. C., July, 1973.
7-3
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APPENDIX
-------
Subpart J—Standards, of Performance far
Petroleum Rafineries 5
§ 60.300 Applicability and desig-nalion
of affected facility.
The provisions of this subpart are ap-
plicable to the following affected- facil-
ities in petroleum refineries: Fluid cata-
lytic cracking unit .catalyst regenerators.
fluid catalytic cracking unit incinerator-
waste heat boilers, and fuel gas Combus-
tion devices.
§ 60.101 Definitions.
As u=ed in this subpart, all terms not
defined herein shall have the maaning
given them in the Act and in subpart A.
(a) "Petroleum refinery" means any
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel
oils, lubricants, or other products
through distiHation of petroleum- or
through redistillation, cracking or re-
forming of unfinished petroleum
derivatives.
(b) "Petroleum" means the crude oil
removed from the earth and the oils de-
rived from tar sands, shale, and coal.
(c) "Process gas" means any gas gen-
erated 'by a petroleum refinery process
unit, except fuel gas and process upset
gas s.3 defined in this section.
(d) "Fuel gas" means any gas which
is generated by a petroleum refinery
process unit and which is combusted, in-
cluding- any gaseous mixture of natural
cas and fuel gas which is combusted.
Col "Proce-ss upset gas" means anv KRS
Esneraied by a petroleum refinery process
unit as a result of start-up, shut-down,
upset or malfunction.
Cf) "Refinery process unit" means any
segment of the petroleum refinery in
which a specific processing operation, is
conducted
-(•C) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers and flares used to corn-
bust fuel gas, but does not include fluid
coking unit and fluid catalytic cracking
unit incinerator-waste heat boilers or fa-
cilities in which gases are combusted to
producs sulfur or sulfuric acid.
(h) "Coke bum-off" means the coke
removed from the surface of the fluid
catalytic cracking unit catalyst by com-
bustion in the catalyst regenerator. The
rate of coke burn-off is calculated by the
formula specified in § 60.106.
§ 60.102 Standard
matter.
for
particulaie
(a) On and alter the date on which
the performance test required to be con-
ducted by § 80.8 is completed, no owner
or operator subject to Ui> provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from any
iluid catalytic cracking unit catalyst re-
generator or from any fluid catalytic
cracking unit incinerator-waste heat
boiler:
(1) Paniculate matter in excess of
1.0 ks/1000 kg o.o lb/1000 Ib) of coke
bum-off in the catalyst regenerator.
(2) Gases exhibiting 30 percent opac-
ity or greater, except_for 3 minutes in
any 1 hour. IB
(b) la those instances in -which aux-
iliary liquid or solid fossil fuels are
burned in the fluid catalytic cracking
unit incinerator-waste heat boiler, par-
ticular matter in excess of that permit-
ted by paragraph (a)(l) of this section
may be emitted to the atmosphere, ex-
cept that the incremental rate of partic-
ulate emissions shall not exceed 0.18 g/
million cal (0.10 Ib/million Btu) of heat
input attributable to such liquid or solid
- fuel.
§ 60,103 Standard for carlxm monoxide,
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from the
fluid catalytic cracking unit catalyst
regenerator any gases which contain car-
bon monoxide in excess of 0.050 percent
by volume.
§ 60.104 Standard for sulfur dioxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no own-
er or operator subject to the provisions of
this subpart shall bum in any fuel gas
combustion device any fuel gas which
contains H;S in excess of 230 mg/dscm
(0.10 gr/dscf), except as provided In
bustion of process upset gas in a flare.
or the combustion in a flare of process
gas or fuel gas which is released to the
flare as a result of relief valve leakage, is
exempt from this paragraph.
(b) The ovraar or operator may elect
to treat the gases resulting from the com-
bustion of fuel gas in a manner which
limits the release of SO.- to the atmos-
phere if it is'shown ic the satisfaction
of the Administrator that this prevents
SOa emissions as effectively as compli-
ance with the requirements of paragraph
(a) of this section.
§ 60.105 Emission monitoring.^
(ai Continuous monitoring systems
shall be installed, calibrated, maintained,
and operated by the owner of operator as
follows:
(1) A continuous monitoring system
for the measurement of the opacity of
emissions discharged into the atmosphere
from the fluid catalytic cracking unit cat-
alyst regenerator. The continuous moni-
toring system shall be spanned at 60, 70,
or 80 percent opacity.
(2) [Reserved]
(3) A continuous monitoring system
for the measurement of sulfur dioxide in
the gases discharged into the atmosphere
from the combustion of fuel gases (ex-
cept where a continuous monitoring sys-
tem for the measurement of hydrogen
sulfide is installed under paragraph (a)
(4) of this section). The pollutant gas
used to prepare calibration gas mixtures
under paragraph 2.1, Performance Speci-
fication 2 ar.d for calibration checks' un-
der 5 6o:i3(d) to this part, shall be sul-
fur dioxide (SO.). The span shall be-set
at 100 ppm. For conducting monitoring
system perforrhar.ee evaluations under
§ 60.13(c), Reference Method 6 shall be
used.
(4) [Reserved]
(b) [Reserved]
(c) The av^raga coke bum-off rate
(thousands of k.llogram/nr) arid hdunTbf
operation for any fluid catalytic crack-
ing unit catalyse regenerator subject to
§ 60.102 or 60.1C3 shall be recorded daily.
(d) For -any fluid catalytic cracking
unit catalyst regenerator which is subject
to § 60.102 and which utilises an inciner-
ator-waste heat boiler to combust the
exhaust gases from the catalyst regen-
erator, the owner or operator shall re-
cord daily the rate of combustion of
liquid or solid- fossil fuels (liters/hr or
kilograms/hr) r:nd the hours of opera-
tion during which liquid or solid fossil
fuels are combusted in the incinerator-
waste heat boiler.
(e) For the purpose of reports under
I 60.7(0)', periods of excess emissions that
shall be reported are defined as follows:
(1) [Reserved]
(2) ^Reserved]
(3) [Reservsd]
(4) Any six-hour period during which
the average emissions (arithmetic aver-
age of sb: contiguous one-hour periods)
of sulfur dioxide as measured by a con-
tinuous monitoring system exceed the
st^-Pci^rd uriripr 5 60.104-
§ 60.306 Teas ;a«s!ioJ» .in<3
(a) For the purpose of determining
compliance with § 60.102(a) (1), the fol-
lowing reference methods and calcula-
tion procedures shall be used:
(1) For ga&es released to the ataos-
phera from the.fluid catalytic cracking
unit caUuyst regenerator:
(i) Method 5 for the concentration of
participate matter and moisture con-
tent,
(iii Mathod 1 for sample and velocity
traverses, and
(iii) Method 2 for velocity and volu-
metric SOT? raie.
(2) For Me-Miod 5, the sampling time
for each run siisil be at least 60 minutes
s,nd the sampling rate shall be at least
O.Ola dscm/dia (0.53 dscf/mtn), except
that shorter sa-i'cpling tixnes may be ap-
proved by Lhs Administrator when proc-
ess variables or other factors. preclude
sampling for at least 60 minutes.
.(3) For exhaust gases from Kia fluid
catalytic cracking unit catalyst regenera-
tor prior to iih-;. emission control system:
the intejrrateij. sample techniques ~o'
Method 3 and Method 4 for gas analysis
and moisture content, r'espsctively;
Method I for velocity traverses; and
Method.2 for velocity and volumetric flow
rate.
(4) Coke bura-o2 rate shall be deter-
mined by ta.
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B.-O.SSW2 Q»j (%COrf %CO)+2.088 QRA-O.OW4 Qjw
S.-0.015«Q»i(70COi+%CO)+0.1303QiU-O.OOe2(Jsi
ftOi CMeMo Unit.)
^roke bum-flit rate, ke/br (English units: Ib/hr).
0.29*;!»nietnc uriiis material balance ftwior divided by 100,
O.OlSo-Enji'Jsh units diiwlal balance !;«U>r divided by 1, Ib-raio/ur-ft'.
Qai-ftuld -»ul/tlo cracking uni: catalyst regenerator eibaust eu flow rat* belon ooterlDj the tmtatfoa
control system, as determined by method 2, dicm/min (Etx'Jjh unlU: daef/mln).
%CO.<-p«rc«n: 1ra.-Soo &oude by voluraa, dry baaa, M 'JsUrminxl by M*tboil 3.
% CO ™p«rceflt carbon xsonoiide by volume, dry btv*ia, 2.1 dytermloed by ^Utbod 3.
% Oi«perc«ui oxygen by volume. dry basis, aa determined by Mittbod 3.
a.CM—netric units mauirial balAcce factor divided by 100, kx-rnlji/br-m'.
O.lOtn-EniiUsh units material baUac* ticlor dlvldtd by 100, Ib-mla/br-ft1.
Qa»-air rat* to Suid catalytic crackine unit cauiyat regenerates, aa determined trota Hold eauiytlit crackinf
unit control room InstrumenUUun, dscmj'mln (KngUsb unlU: dx^'min).
0.09&*— neir.c unlu material balanon (actor diTid«d by 100, kg-niln/hr-iaV
O.O«:-EnsUih utiiu material bilmiw fulor dlvld«d by 100, lb-mJn/Hi-,'a
(5) Particulate emissions shall be determined by the following equation:
Rs-(80X10-«}Q«vC, (Melric TJnita)
B»-(8.S7X10->)Q»iC. (English Units)
b«rs:
Bs-pwncuUU soiisioQ nu«, kg/hr CEaiUih uniU: Ib/br).
«OX10-«— metric unit! contirsloo lactor, min-kR/hr.ra«.
8-57XtO-'=Ef.glisfi uniu convMiion factor, mln-lb/br-^r.
Qav-»o',nn;jtric Coir role o( pis<« diachau-yed Into th» atsiocpberg born tio fluid cat&lytia cracklog nnlt
cataiv3i n>senarTiur foUuvicg the emission control 5751*01, as determined by Method 2, dacmMila
(Eniiuih urJtj. dscl/min). -
d—parttcnlau ntnission concentrntloa discharged into lh» almoapoera, SA determined by Method 5,
• mg/daua (Erjjluh unlta:
(6) For each run, emissions expressed in kg/1000 kg (English units: lb/1000 Ib)
of coke burn-oft In the catalyst regenerator shall be determined by the following
equation:
- (Metric or English Units)
(d) Method 6 shall be used for de-
termining concentration of SO, in de-
termining compliance with § 60.104(b).
except that H*S concentration of the fuel
gas may be determined Instead. Method
1 shall be used for velocity traverses and
Method 2 for determining velocity and
volumetric flow rate. The sampling site
for determining SO. concentration by
Method 6 chall be the same as for
determining volumetric flow rate by
Method 2. The sampling point In trie"
duct for determining SO* concentration
by Method 6 shall be at the centrold of
th* cross section if the cross sectional
area is less than 5 m' (54 ft1) or at a
point no closer to the walls than 1 m
ar'.i:u!.ite emission rate, kg/1000 kg (English units: lb/1000 Ib) ol coke burn-off In the ftuid catalytic e
ii;s unit cut^ly^; regenerator.
tutor, kj! to 1000 kjf (Enelish units: Ib to ICOOlb).
JRe-purticuiiW "mission rale. k;/!lr (Eng)isl) uuu: Ib/br).
fi.-coij boru-oQ rate, kg/br (En^Lsh uniu: Ib/br).
(7) In those instances in which auxiliary liquid or solid fossil fuels are burned
in an incinerator-waste heat boiler, the rate of participate matter emissions per-
mitced under 5 60.102(b) must be determined. Auxiliary fuel heat input, expressed
in millions of cal/hr (English units: Millions of Btu/hr) shall be calculated for*
each run by fuel flow rate measurement and analysis of the liquid or solid auxiliary
fossil fuels.' For each run, the rate of participate emissions permitted under
5 60.102(b) shall be calculated from the following equation:
°'T H
(Metric Units)
where:
S.=-1.0|0''°H (English Unlta)
«•
l!ow3W» partlculitn emission raU, fegAOOO kg (English units: ibACCO Ib) ol coke bum-on la the
2'jld catalytic cracking unit catalyst regenerator.
1.0-smijsioP standard, 1.0 kg/1000 kg (Engusb units: 1.0 lb/1000 Ib) ol coke bura-oa ID the Odd catalytic
cracking unit catalyst r«geD*rator.
O.l^^Tnp.tric units nKztipum allowable Incremontal rate of particular emJ55lons, g/milllon CAl.
0.1'J=>£nglisb uui'j m
-------
Subpart K—Standrr^F. of Performance for
Storage Vessels for Petroiaum Liquids5
§60.130 Apj>IicK.bi!i!Y and dnsScnittion
of aff'ie'od facility.
61) Except as provided in § 6G.110(b),
ir.e affected facility to which tnia sub-
part applies is each storage vessel for
petroleum liquids which has a storage
capacity greater than 151,412 liters
<40,000 gallons).
(b) This suhpan. does not apply to
storage vessels for i!vs=cani« petroleum
or condensate stored, processed, and/or
treat-ed at a drilling and production
facility prior to custody transfer.8
§60.111 Definitions.
As used in this .••->bpart, all terms not
defined herein shsU have the meaning
piven them in the Aci and in subpart A
of this part.
(a) "Storage vcs&ei" means any tank,
reservoir, or container used for the
storage of petrolc-.1.;,-. liquids, but does
not Include:
(1) Pressure vesrels which are designed
k> operate in excci:. of 15 pounds per
square inch gauge without emissions to
the atmosphere except under emergency
conditions,
(2) Subsurface caverns or porous rock
reservoirs, or
(3) Unoersroui-vi tanks if the total
•.••Uirne of petroleum liquids added to
i».i4 taken from a i.arik annually does
not exceed twice the •volume of the tank.
(b) "Petroleum liquids" means petro-
leum, condensate, and any finished or
intenned."'v;e products manufactured In
a petroleum rennei-y but does not mean
Number 2 through Number 6 fuel oils
iis specified In A.S.T.M. D396-69, gas
Airblne fuel olis Numbers 2-GT through
4-GT aa specified In /..S.TJU. D2880-71,
or diesel fuel oils Numbers 2-D and 4-D
as specifies? in A.S.T.M. D&75-88.8
(cJ "Petroleum refinery" means any
facility enpaged in producing gasolme,
kerosene, distillate fuel oil:;, residual fuel
••..Is, lubricants, or other products through
distillation of petroleum or through
redistillation, cracking, or reforming of
nnfinisl-.e-"! petroleum derivatives.
(d) "Petroleum" means the crude oil
removed from the earth and the oils
derived from tar s.' ..-els, shale, arid coa-3.8
^e) "Hydrocarbon" means any organic
compound consisting predominantly of
carbon and hydrogen 6
(f) "Condensate" means hydrocarbon
liquid separated from natural ga- which
condenses due to chr nges in the tem-
perature i.nd/or pi~e.--.i-ij.re and remains
.liquid at standard r.ondltions.
(g) "Custody transfer" means the
transfer of produced petroleum and/or
condensate, after processing and/or
treaties in the producina' operations,
from, storage tanks or automatic trans-
fer JaciliUe.'i to pipelines or any other
forms of transportation. 8
(h; "Drilling and production facility"
means all drilling and servicing equip-
ment, wells, flow linns, separators, equip-
ment, gathering lines, and auxiliary non-
. transportation-related equipment used
in the production of petroleum but docs
not include natural gasoline plants. 8
(i) "True vapor pressure" means the
equilibrium partijj pressure exerted by
a petroleum liquk; as determined In ac-
cordp-nce with methods described in
American Petroleum Institute Bulletin
2517, Evaporation Loss from Floating
Roof Tanks. 1062. ' •
(j) "Floating roof" means a storage
vessel cover consisting of a double deck,
pontoon single deck, internal floating
cover or covered floating roof, which rests
upon and is supported by the petroleum
liquid being contained, and is equipped
with a closure seal or seals to close the
space between the root" edge and tank
wall.
(k) "Vapor recovery system" means a
vapor gathering system capable of col-
lecting all hydrocarbon vapors and gases
discharged from the storage vessel and
a vapor disposal system capable of proc-
essing such hydrocarbon vapors and
gR,se.s so as to prevent their, emission to
the atmosphere.
(1) "Reid vapor pressure" is the abso-
lute vapor pressure of volatile crude oil
and volatile non-viscous petroleum
liquids, ex-cept.liquified petroleum gases,
as determined by ASTM-D-323-58 (re-
approved 19S3),
§ 60.112 Standard for hydrocarbono.
(a) The of-ner or operator of anyjstor-
age vessel to which this subpari applies
shall store petroleum Uguids its -follows:
<1) If the true vapor pressure of the
petroleum liquid, ts stored, is equal to
or greater than 73 mm Hg (1.5 psia) but
not greater than 570 mm Pig (11.i1 psia),
th-; storage vessel shall be equipped with
a floating roof, a vapor recovery system,
or their equivalents.
.(2) If the true vapor pressure of the
petroleum liquid as stored is greater than
570 mm Hg (11.1 psia), the storage ves-
sel shall be equipped with a vapor re-
covery system or its equivalent.
§ 60.113 Monitoring of operations.
(a). 7~he owner or operator of any
storage vessel to which this subpart ap-
plies shall for each such storage vessel
maintain a file of each type of petroleum
liquid stored, 01 the typical Held vapor
pressure of each type of petroleum liquid
stored, and of the dates of storage. Dates
on which the storage vessel is empty shall
be shown.
(b) The owner or operator of any stor-
age vessel to which this subpart applies
shall lor each such storage vessel deter-
mine and record the average monthly
storage temperature and true vapor pres-
sure of the petroleum liquid stored at
such temperature if:
(1) The petroleum liquid has a true
vapor pressure, as stored, greater than
26 mm Hg (0.5 psia) but less than 78 mm
Hg (1.5 psia) and Is stored in a storage
vessel other than one equipped with a
floating roof, a vapor recovery system
or their equivalents; or
• (2) The petroleum liquid has a iiu
vapor, pressure, as stored, greater tha.
470 mm Hg (9.1 psia) and Is stored i
a storage vessel other than one equlppe
with a vapor recovery •system or It
equivalent. i
(c) The average monthly storage tern
perature is an arithmetic average cal
culated for each calendar month, or por
tion thereof If storage is for less than .
month, from bulk liquid storage tern
perafcures determined at least one
every ~7 days.
(d) The true vapor pressure shall b
determined by the procedures in AF
Bulletin 2517. This procedure is de
pendent upon determination of tr,
storage temperature and the Reid vapc
pressure, which requires sampling of tr,
petroleum liquids in the storage vessel.-
Unless the Administrator requires i
specific cases that the stored petroleur.
liquid be sampled, the true vapor pres
sure may be determined by using th
average monthly storage temperatur
and the typical Reid vapor .pressure. Fo'
those liquids for which certified specif!
cations limiting the Reid vapor pressur
exist, that Reid vapor pressure may I:
used. For other liquids, supporting ana
lytical data must be made available o?
request to the Administrator when typl
cal Reid vapor pressure Is used.
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TECHNICAL, REPORT DATA
. .7-v /•<:,:..' {,:±ir.!c:iv!:i u». tlis n\ ±•/••,•: baj'ore compiling)
3. RECIPIENT'S ACCeSSIOiVNO.
EPA 340/1-77-005
i ..H AM- S'J5TiT!_ =
Inspection Manual for the Enforcement of New Source
Performance Standards: Volatile Hydrocarbon Storage
5. PERFORMING ORGANIZATION CODE
5, REPORT DATE
October. 1976
7. AUTHOR. 31
3. PERFORMING ORGANIZATION REPORT NO.
3 PERFORMING ORGANIZATION NAME ANO ADDRESS
j Pacific Environmental Services, Inc.
j 1930 14th Street
! Santa Monica, California 90404
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-01-3156, T.O. #19
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Division of Stationary Source Enforcement
Washington, D.C.
13. TYPE Or REPORT AND PERIOD COVERED
Final Report
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
Prepared by Anker V. Sims of The Ben Holt Company,
Revised by George Umlauf of Pacific Environrrental Services, Inc.
IS. ABSTRACT
The purpose of this document is to assist air pollution agencies in the enforcement of
Federal new source performance standards (NSPS) for volatile organic storage tanks.
The manual actually serves a twofold purpose in that it outlines the requirements of
the regulations and also describes methods for conducting inspections of tanks to verify
their compliance with these requirements.
The NSPS regulations are applicable to storage tanks of 40,000 gals capacity or greater
storing organic material of greater than 0.5 psia true vapor pressure. The standards
are written in terms of the type of roof required and the type of records to be kept
on file based upon the volatility of the material stored. The various types of tanks
are described in the manual so that the inspection officer can recognize which tanks
are affected by the standards during an on-site inspection. A checklist is included to
be used to gather tank data, and procedures are outlined which allow the inspector to
monitor and verify proper performance test conditions.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
POL Storage
Vapor Pressure
Standards
b.lDENTIFIERS/OPEN ENDED TERMS C. CO3ATI 1 idd/GrOUp
New Source Performance
Standards
Inspection Procedures
Volatile Organic Storage
Performance Testing
1308/0703
0704
1407
-T.. -.: j7>?i = j7!O-. STATEV.iM
Release Unlimited
£?A Form 2J20-1 (9-73)
•19. 'JFCUrllTY CLASS (Tili\ Report)
JJn classified
20~S::CURITY CLASS (Tills pj^v)
Unclassified
21. NO. Or PAGES
56 .
22 PRICE
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