EPA 340/1-77-006
APRIL 1977
Stationary Source Enforcement Series
INSPECTION MANUAL FOR ENFORCEMENT OF
NEW SOURCE PERFORMANCE STANDARDS
CATALYTIC CRACKING
REGENERATORS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
Office of General Enforcement
Washington, D.C. 20460
-------
INSPECTION MANUAL FOR THE
ENFORCEMENT OF NEW SOURCE
PERFORMANCE STANDARDS:
FLUID CATALYTIC CRACKING REGENERATORS
Contract No. 68-01-3156
Task Order No. 19
EPA Project Officer
Mark Ante!1
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 fulfillment of Contract 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.
-------
TABLE OF CONTENTS
Page
LIST OF FIGURES vl
1.0 INTRODUCTION 1-1
2.0 STATE IMPLEMENTATION PLANS (SIP) AND
NEW SOURCE PERFORMANCE STANDARDS (NSPS) 2-1
2.1 Existing Sources - SIP 2-1
2.1.1 Summary of Typical Emission Limitation 2-1
2.1.1.1 Particulate Matter 2-1
2.1.1.2 Carbon Monoxide 2-2
2.2 Summary of New Source Performance Standards 2-3
2.2.1 Emission Standards 2-3
2.2.1.1 Particulate Matter 2-3
2.2.1.2 Opacity 2-5
2.2.1.3 Carbon Monoxide 2-5
2.2.2 Performance Testing 2-5
2.2.2.1 Initial Performance Test 2-5
2.2.2.2 Subsequent Performance Tests 2-6
2.2.3 Monitoring Equipment 2-6
2.2.4 Recordkeeping and Reporting 2-6
2.2.4.1 Notifications Regarding
Construction, Reconstruction
and Modifications 2-6
2.2.4.2 Notifications Regarding
Initial Startup 2-7
2.2.4.3 Records Regarding Startup, Shut-
down, and Malfunction 2-7
2.2 A A Records Regarding Performance
Testing 2-7
2.2.4.5 Quarterly Reports 2-8
2.2.4.6 Notification of Monitoring
Commencement 2-8
2.2.4.7 Daily Recording 2-8
iii
-------
TABLE OF CONTENTS (continued)
Page
2.3 Applicability of Standards 2-8
2.3.1 Participate Matter Emission Standard 2-9
2.3.2 Opacity Standard 2-10
2.3.3 CO Standard 2-10
3.0 PROCESS DESCRIPTION, ATMOSPHERIC EMISSIONS AND EMISSION
CONTROL METHODS 3-1
3.1 Process Description 3-1
3.2 Atmospheric Emissions 3-4
3.3 Emission Control Methods 3-5
4.0 PROCESS AND CONTROL DEVICE INSTRUMENTATION 4-1
4.1 Process Instrumentation 4-1
4.2 Control Device Instrumentation 4-1
5.0 STARTUP/MALFUNCTIONS/SHUTDOWN 5-1
5.1 Startup 5-1
5.2 Malfunction 5-1
5.3 Shutdown 5-2
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
6.1.3 Safety Equipment and Procedures 6-3
6.1.4 Frequency of Inspections 6-4
6.2 Inspection Checklist 6-4
6.3 Inspection Follow-up Procedures 6-10
7.0 PERFORMANCE TEST 7-1
7.1 Process Operating Conditions 7-1
7.2 Process Observations 7-2
IV
-------
TABLE OF CONTENTS (continued)
7.3 Emission Test Observations
7.3.1 Traversing (EPA Method No. 1)
7.3.2 Stack or Duct Gas Velocity Determination
(EPA Method No. 2)
7.3.3 Gas Analysis (EPA Method No. 3)
7.3.4 Moisture (EPA Method No. 4)
7.3.5 Particulate Matter (EPA Method No. 5)
7.3.6 Carbon Monoxide (EPA Method No. 10)
7.3.7 Emission Monitoring
Page
7-3
7-3
7-3
7-5
7-5
7-6
7-8
7-8
APPENDICES
Appendix 1
Appendix 2
Appendix 3
New Source Performance Standards for Fluid
Catalytic Cracking Regenerators
Proposed Revision to the Opacity Standard
for New Fluid Catalytic Cracking Regenerators
Estimation of the Exit Gas Volume LQ.RF)
leaving the Fluid Catalytic Cracking Unit
Regenerator
-------
LIST OF FIGURES
Figure Page
3.1 Fluid Catalytic Cracking Unit 3-2
3.2 CO Boiler and Precipitator 3-6
-------
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 particulate, carbon monoxide, and opacity standards for
performance of new and modified Fluid Catalytic Cracking Regenera-
tors. These proposed standards were issued in the Federal Register
of June 11, 1973, and final standards (40 CFR 60.102, 40 CFR 60.103)
became effective on February 28, 1974. The standards apply to all
sources whose construction or modification commenced after June 11,
1973.
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 of inspection procedures for verifying compliance with
the standards, and EPA must approve the program.
The primary purpose of this document is to provide guide-
lines for the appropriate enforcement agency in the development
of inspection programs for Fluid Catalytic Cracking Regenerators
which are covered by New-Source Performance Standards (NSPS). A
large portion of the material presented, however, discusses the
catalytic cracking process in general and may prove useful in
improving procedures used to inspect existing regenerators. Included
are sections which explain the process, the regulations, control
techniques and the responsibilities of the enforcement agency personnel
1-1
-------
2.0 STATE IMPLEMENTATION PLANS (SIP) AND NEW SOURCE
PERFORMANCE STANDARDS (NSPS)
The following sections 2.1 and 2.2 describe the various SIP
requirements and the NSPS as related to Catalytic Cracking Regenera-
tors.
2.1 EXISTING SOURCES - SIP
An analysis of rules and regulations of final State Implemen-
tation Plansi shows regulations for particulate and CO emissions,
applicable to existing Catalytic Cracking Regenerators.
2.1.1 Summary of Typical Emission Limitation
2.1.1.1 Particulate Matter
A number of SIP regulations for various states exist related
to particulate emissions. Some of the regulations apply to all
stationary sources including refineries, while others are applicable
only to petroleum refining operations. Typical examples of the
former regulations (all stationary sources) are:
• Los Angeles APCD - limits emissions of solid particulate
matter from any source to a maximum of 30 Ibs/hr (Rule 54).
• Illinois - the allowable particulate emission rate shall
not exceed 100 Ibs (45 kg) per hour as determined by:
E = 4.10 (P)0-67 for P<30 tons/hour
E = 55 (P)0'11 -40 for 304,800 tons/hour
where E = Allowable Emission Rate in Ibs/hour
and P = Catalyst recycle rate including the amount
of fresh catalyst added in tons/hour.
2-1
-------
An example of a regulation which specifically applies to
particulate emissions from the Catalytic Cracking Regeneration
process is included in the SIP for the Commonwealth of Pennsyl-
vania. The regulation states that these sources shall not permit
the emission of particulate matter in excess of the rate calculated
as follows:
A = 0.76 (E)°-42, where:
A = Allowable emission in Ibs/hr
E = Emission index = F x W Ibs/hr
F = 40 Ibs/ton of liquid feed
W = Production or charging rate in tons of liquid feed per
hour.
2.1.1.2 Carbon Monoxide
The various regulations pertaining to CO emissions include
some which apply to all stationary sources including refineries,
and others which are applicable only to petroleum refining CO
emissions. Three typical examples of the former (all stationary
sources) follow:
• Los Angeles APCD - limits emission of CO from all stationary
sources except I.C. engines to 0.2% by volume.
• Louisiana - no emissions of CO from any installation which
will cause ambient air quality standards to exceed 9 ppm
(max. 8-hour concentration), 35 ppm (max. 1-hour concen-
tration).
• Maryland - no emission of CO from any installation which,
without emission control measures, would discharge CO at
500 pounds per day and at a concentration exceeding 12%
by volume, unless burned at 1,300°F (720°C) or more for 0.3
seconds or longer in a direct flame afterburner, or equivalent
device.
Examples of state regulations for CO emissions applicable
specifically to petroleum refineries (including Catalytic Cracking
Regenerators) are:
• Illinois - limit emission of CO to 100 ppm corrected to
50% excess air.
2-2
-------
• Oklahoma - emissions reduced by use of complete secondary
combustion of waste gas generated. Removal of 93% or more
of CO generated will be considered complete secondary com-
bustion.
2.2 SUMMARY OF NEW SOURCE PERFORMANCE STANDARDS
Performance standards for new Fluid Cracking Catalyst Regene-
rators require that the particulate loading of effluent gases from
the regenerator not exceed a specified level, that the opacity of
any plume issuing from the regenerator not exceed a specified level
and that the concentration of carbon monoxide in the effluent gas
not exceed a specified level. The regulations were published in
the March 8, 1974 Federal Register (39 FR 9315). Since that time
there have been periodic updates. The regulations as of February
27, 1976 appear as Appendix I.
These standards included both the maximum emission limits
for the specified pollutants and the standards for monitoring the
emissions from the fluid catalytic cracking process.
2.2.1 Emission Standards
Levels of particulate loading, opacity, and carbon monoxide
concentration of the effluent gases are outlined in following sec-
tions. These levels are not to be exceeded during performance
testing.
2.2.1.1 Particulate Matter
The NSP Standard for particulate loading prohibits the emission
from a Fluid Catalytic Cracking Unit in excess of 1.0 kg/1,000 kg
(1.0 lb/1,000 Ib) of coke burnoff in the catalyst regenerator.
The coke burnoff rate shall be determined by the following formula
[paragraph 60.106 (a)(4)]:
RC = 0.2982 QRE (%C02 + «CO) + 2.088 Q^ - 0.0994 QRE (
for Metric Units, or
Rc = 0.0186 QRE (%C02 + %CO) + 0.1303 QRA - 0.0062 QRE (
for English Units, where:
2-3
-------
R = Coke burn-off rate, kg/hr (English units: Ib/hr)
0.2982 = Metric units material balance factor divided by 100,
kg-min/hr-cubic m
0.0186 = English units material balance factor divided by 100,
Ib-min/hr-cubic m
QRF = Fluid catalytic cracking unit catalyst regenerator
exhaust gas flow rate before entering the emission
control system, as determined by Method 2, dscm/min
(English units: dscf/min)
%C02 = Percent carbon dioxide by volume, dry basis, as
determined by Method 3
%CO = Percent carbon monoxide by volume, dry basis, as
determined by Method 3
%09 = Percent oxygen by volume, dry basis, as determined
^ by Method 3
2.088 = Metric units material balance factor divided by 100,
kg-min/hr-cubic m
0.1303 = English units material balance factor divided by
100, Ib-min/hr-cubic ft
Qnn = Air rate to fluid catalytic cracking unit catalyst
regenerator, as determined from fluid catalytic
cracking unit control room instrumentation, dscm/min
(English units: dscf/min)
0.0994 = Metric units material balance factor divided by 100,
kg-min/hr-cubic m
0.0062 = English units material balance factor divided by 100,
Ib-min/hr-cubic ft
In those instances in which auxiliary liquid or solid fossil
fuels are burned in the fluid catalytic cracking unit incinerator-
waste heat boiler, particular matter in excess of that permitted
above may be emitted to the atmosphere, except that the incremental
rate of particulate emissions shall not exceed 0.18 g/million cal
(0.10 Ib/million BTU) of heat input attributable to such liquid or
solid fuel.
2-4
-------
Participate matter, for the purposes of this regulation,
is defined^as that collected in the front half (nozzle, probe,
and filter) of the Method 5 train. Condensible organic matter
is defined as that collected in the back half (impingers) of
the train.
2.2.1.2 Opaci ty
The NSP Standard states that gases exhibiting thirty (30)
percent opacity or greater shall not be emitted from a Fluid
Catalytic Cracking Regenerator, except for three minutes in any
one hour. Where the presence of recombined water is the only
reason for this failure to meet the requirements of this standard,
such failure shall not be a violation of the standard.
New proposed NSP Standards were presented in the Federal
Register, Volume 41, No. 169 - Monday, August 30, 1976 (see Appen-
dix 2). The proposed revision would change the opacity standard
from thirty (30) percent, except for three minutes in any one
hour, to twenty-five (25) percent, except for two six-minute
average opacity readings in any one hour.
A continuous monitoring system is required for the measurement of
the opacity of emissions discharged into the atmosphere from the fluid
catalytic cracking unit catalyst regenerator. The continuous moni-
toring system shall be spanned at 60, 70, or 80 percent opacity.
2.2.1.3 Carbon Monoxide
The NSP Standard for carbon monoxide is 0.050% by volume on
a dry basis (500 parts per million, or 570 milligrams per normal
cubic meter).
2.2.2 Performance Testing
Demonstration that the standards are being met is accomplished
only by performance testing. The owner or operator of a new or
modified Catalytic Cracking Regenerator is required to conduct
performance tests within a specified period after startup and there-
after from time to time as may be specified by the EPA.
2.2.2.1 Initial Performance Test
The initial test of performance of a new facility must be
conducted within 60 days after the facility is first operated at
its maximum intended rate of operation, but not later than 180 days
after initial start-up of such facility. Thirty days must be allowed
for prior notice to the EPA, to allow the Agency to designate an
observer to witness the test.
2-5
-------
Each performance must be conducted in accordance with the
instructions set forth in the regulations (Appendix I), which are
discussed in more detail in Section 7 of this Manual. Necessary
modifications in the details of the test methods may be made, if
approved in advance by the EPA. A written report of the test
must be furnished to the EPA.
2.2.2.2 Subsequent Performance Tests
Subsequent to the initial test, further performance tests may
be required from time to time at the discretion of EPA. Alterna-
tively, the Agency may decide to conduct performance tests. For
this purpose the owner or operator is required to provide testing
facilities, including necessary utilities, sampling ports, safe
sampling platforms, and safe access to the sampling platform.
Performance testing subsequent to the initial test is most
likely to be required when records indicate a relatively high
frequency of occurrence of emission levels near, at, or above the
NSPS levels.
2.2.3 Monitoring Equipment
The NSP Standards (40 CFR 60.105) require that the owner or
operator of a new or modified Catalytic Cracking Regenerator will
install, calibrate, maintain and operate monitoring instruments
for the unit's effluent gases. A photoelectric or other type
smoke detector and recorder will continuously monitor and record
the opacity of the effluent gases discharged into the atmosphere
from the unit.
2.2.4 Recordkeeping and Reporting
The owner or operator of any Catalytic Cracking Regenerator
is required to maintain certain records, to furnish certain reports
and to notify EPA of certain plans and occurrences, as listed below:
2.2.4.1 Notifications Regarding Construction, Reconstruction and
Modifications
The owner or operator is required to notify EPA of the date
construction of an affected facility is commenced no later than
30 days after such date. A notification is also required for any
physical or operational change to an existing facility which may
increase the emission rate of any air pollutant to which a standard
applies. This notice shall be postmarked 60 days or as soon as
practicable before the change is commenced and shall include infor-
mation describing the precise nature of the change, present and
2-6
-------
proposed emission control systems, productive capacity of the
facility before and after the change, and the expected completion
date of the change.
2.2.4.2 Notifications Regarding Initial Startup
The owner or operator is required to notify EPA of the antici-
pated date of initial startup of the facility not more than 60 days
nor less than 30 days in advance of the anticipated date. He is
also required to notify EPA of the date of actual occurrence of
initial startup within 15 days after that date. In this connection,
"startup" refers to the operation of the facility for any purpose.
2.2.4.3 Records Regarding Startup, Shutdown, and Malfunction
The owner or operator is required to record the occurrence
and duration of any startup, shutdown, or malfunction in operation
of the Catalytic Cracking Regenerator and to retain the record for
at least two years thereafter.
The record should also include the nature and cause of any
malfunction, together with a notation as to corrective action and
any measures undertaken to prevent recurrence of the malfunction.
In this connection, "startup" refers to a renewed operation
of the facility for any purpose; and "malfunction" is defined as
any sudden, unavoidable failure of air pollution control equipment
or of the Regenerator itself to operate in a normal manner. Pre-
ventable failures, such as those which may have been caused by
poor maintenance or careless operation, or by equipment breakdown
due to such causes, are not included in this definition.
2.2.4.4 Records Regarding Performance Testing
The owner or operator is required to make available to the
EPA, in order to facilitate conduct of performance tests by 'the
Agency, any records necessary to determine whether performance of
the Regenerator is representative performance at the time of the
test. Production rate and hours of operation for any Fluid Catalytic
Cracking Unit Regenerator shall be recorded daily. A file of all
measurements required by CO and particulate emissions regulations
shall be maintained by the owner or operator. Appropriate measure-
ments shall be reduced if necessary to the units of the applicable
standard daily, and summarized monthly. The record of any such
measurement(s) and summary shall be retained for at least two years
following the date of such measurements and summaries. These records
should also be made available during inspections of the facility.
2-7
-------
2.2.4.5 Quarterly Reports
Quarterly reports are to be filed on the fifteenth day follow-
ing the end of each calendar quarter. These reports must include
the records of excessive emissions during the calendar quarter in
terms of date, time of commencement, and time of completion for
each period of excessive emissions, as evidenced by records of
monitoring equipment or other observations. The quarterly reports
must also include the records of startup, shutdown, and malfunction
during the calendar quarter, with details as to the causes of
malfunctions and corrective measures applied.
2.2.4.6 Notification of Monitoring Commencement
A notification is required of the data upon which
demonstration of the continuous monitoring system perfor-
mance commences.
2.2.4.7 Daily Recording
The average coke burn-off rate (thousands of kilogram/hour)
and hours of operation for any Fluid catalytic Cracking Unit
catalyst regenerator shall be recorded daily.
2.3 APPLICABILITY OF STANDARDS
The applicability of the NSP standards includes all new or
modified Fluid Catalytic Cracking Regenerator units and all unit
incinerator-waste heat boilers. A new or modified source is one
on which construction or modification commenced after June 11,
1973, subject to the following definitions (40 CFR 60.2):
"Modification" means any physical change in, or change in
the methods of operation of, an affected facility which
increases the amount of any air pollutant (to which a standard
applies) emitted by such facility or which results in the
emission of any air pollutant (to which a standard applies)
not previously emitted, except that:
(a) Routine maintenance, repair and replacement shall not
be considered physical changes, and
(b) The following shall not be considered in themselves
to be a change in the method of operation:
2-8
-------
(i) An increase in the production rate, if such
increase does not exceed the operating
design capacity of the affected facility;
(ii) An increase in hours of operation;
•ft .
(iii) Use of an alternative fuel or raw material n
if, prior to June 11, 1973, the affected :
facility was designed to accommodate such
alternative use.
(iv) The addition or use of any system or device
whose primary function is the reduction of
air pollutants, except when an emission
control system is removed or is replaced by
a system determined to be less environmentally
beneficial.
(v) The relocation or change in ownership of an
existing facility.
"Commenced" means that an owner or operator has undertaken a
continuous program of construction or modification or that
an owner or operator has entered into a binding agreement or
contractual obligation to undertake and complete, within a
reasonable time, a continuous program of construction or
modification.
2.3.1 Particulate Matter Emission Standard
The performance standard for emission of particulate matter,
applicable to new Regenerators, is 1.0 kg /I,000 kg (1.0 lb/1,000 Ib)
of coke burn-off; no owner or operator is permitted to cause dis-
charge of effluent gases whose particulate emission exceeds this
value. However, the actual particulate loading of the effluent
gases will not be known during routine operation of the facility.
A determination as to whether the facility is or is not in compliance
with this regulation may be based only on the results of performance
tests conducted in the manner prescribed in Section 60.106 (see
Appendix I).
Paragraph 60.106(a) (Appendix I) specifies that EPA Method 5
be used for determining the concentration of particulate matter
and the moisture content. For Method 5, the sampling time shall
be at least 60 minutes and the sampling rate shall be at least
0.015 dscm/min (0.53 dscf/min), except that shorter sampling times
may be approved when process variables or other factors preclude
sampling for at least 60 minutes.
2-9
-------
When the production rate is nonuniform as will frequently be
the case, it may be difficult to determine what would be the normal
maximum production rate referred to during the period alloted for
the test. The normal maximum production rate will be determined
in this case by the unit operator. However, the operator will
have to show the reasonableness of this rate based on design capa-
cities of the unit including fresh feed rate, catalyst recirculation
rate and coke burnoff rate.
2.3.2 Opacity Standard
The performance standard is 30% opacity, not to be exceeded
for more than three minutes of any one hour. Where the presence
of uncombined water is the only reason for failure to meet the
requirements, such failure would not be considered a violation.
For determining initial compliance, this observation can only be
made during an established performance test. Following the per-
formance test, opacity observations can be made from time to time
to determine if the unit appears to be maintaining its compliance
status.
Revisions to this rule have been proposed but not promulgated
and appear as Appendix 2.
2.3.3 Carbon Monoxide Standard
The standard was described in Section 2.2.1.3 (0.050% by
volume). For the purpose of determining compliance with this
performance standard, the integrated sample technique of Method 10
shall be used. The sample shall be extracted at a rate propor-
tional to the gas velocity at a sampling port near the centroid
of the duct. The sampling time shall not be less than 60 minutes.
2-10
-------
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.
2-11
-------
3.0 . PROCESS DESCRIPTION, ATMOSPHERIC EMISSIONS
AND EMISSION CONTROL METHODS
«
3.1 PROCESS DESCRIPTION
The principal use of the fluid catalytic cracking (FCC) process
is to convert gas oil feed stocks to high quality gasoline. Heavier
liquid products and gas are also produced, along with coke which is
deposited on the catalyst. In order to reuse the catalyst the coke
is removed by burning.
A flowsheet for a typical FCC unit is shown in Figure 3.1.
This specific unit employs a riser reactor, a process variation
that has become popular in recent years. Variations in equipment
arrangements and process details are common, but the major elements
are similar and the regenerator effluent control problems are the
same.
Powdered catalyst, both regenerated and as addition (make-up)
with the appearance of fine sand, is fluidized in combination with
vaporized feed and steam added to the lower part of the riser re-
actor. The mixed feed, steam, and catalyst reacts and flows upward
into the cyclone vessel where the catalyst is disengaged from the-
vapor mixture. Multistage cyclones (usually two), located within
the cyclone vessel, are used to remove catalyst from the reactor
effluent vapors. The reactor effluent (catalytically cracked gas
oils) then flows to a section of the refinery devoted to product
recovery and fractionation.
The catalyst captured in the cyclone vessel is laden with coke
(carbon) which will seriously affect the activity level of the cata-
lyst unless it is removed. In order to recover this "spent" catalyst,
the fluid catalytic cracking unit has a regeneration process. The
captured spent catalyst from the cyclone vessel is brought into con-
tact with steam in the stripper to absorb hydrocarbon. The stripped
spent catalyst then flows to the regenerator. In the regenerator,
compressed air is fed to the chamber through the bottom of the vessel.
The air contacts the hot catalyst at approximately 533°C (1,100°F)
causing combustion of the coke. In the standard regeneration process,
neither the structure of the vessel nor the catalyst used is hearty
enough to withstand a high enough temperature to ensure complete
combustion of the carbon to carbon dioxide (C02)« As a consequence,
the gases generated in the vessel are characterized by large quantities
of carbon monoxide (CO) and the captured catalyst leaving the vessel
retains a small amount of the coke causing a deterioration of the
catalyst activity level.
3-1
-------
t
Flue Gas
Stack
Cyclone Vessel
Stripper
Precipitator
Reactor
'Effluent
\
i
i
lel-jL StriPPin9
i/
Steam
Fractionator
Riser Reactor
Steam
Upper Feed Injection
Recycle
Lower Feed
Injection
Vapor to
Gas Compressor
( ;
Raw Gasoline
Lt. Cycle
Gas Oil
Hvy. Cycle
Gas Oil
Figure 3.1 FLUID CATALYTIC CRACKING UNIT
-------
The regenerated catalyst and the burned off coke (as CO and C02)
along with other combustion contaminants rise to the top of the regen-
erator vessel where multiple stages of internal cyclones separate all
but a small amount of the catalyst fines from the flue gas. In some
units additional external (tertiary) cyclones are also used. Comple-
tion of the combustion of CO to C02 in the flue gas can be performed
downstream of the regeneration in a CO (often termed waste heat) boil-
er. In the CO boiler, auxiliary fuel is used to maintain combustion
and stabilize the operation, and useful heat is recovered in the form
of steam. The flue gas from the CO boiler is passed through an electro-
static precipitator for removal of the remaining catalyst fines and
leaves the unit through the stack. In some units the precipitator is
located upstream of the CO boiler.
A turbine is sometimes inserted ahead of the CO boiler to re-
cover power available from the pressure drop which exists between
the regenerator vessel exit and the final exhaust stack. In such
cases an additional stage of cyclones, exterior to the regenerator,
is used to remove catalyst fine that would otherwise damage the turbine.
The external cyclones do not effect complete particulate collection so
a precipitator is still required for final particulate control.
One advancement in the FCC regeneration process termed hot re-
generation has been developed by Universal Oil Products (UOP). The
process allows for complete combustion of carbon monoxide to carbon
dioxide within the regenerator chamber and can be applied to both
new and existing units. Hot regeneration requires an operating temp-
erature of about 732QC (1,350°F) which means existing FCC units will
require structural modifications in the form of a refractory lining
of the interior of the regenerator vessel in order to withstand the
higher temperature. Hot regeneration also requires the use of a special
catalyst developed specifically for the process which is durable enough
to withstand the temperature without losing activity levels.
A more recent improvement of the standard FCC operation is a
process which accomplishes complete combustion in the regenerator of
existing units without requiring a higher operating temperature.
The process, developed by American Oil Company (AMOCO), is called
Ultracat. Ultracat is the result of a detailed study of the total
FCC operation and involves the application of design modifications
and special control techniques to both the reactor and regenerator.
Ultracat reactor operations improve conversion efficiency to gaso-
line and reduce the amount of carbon deposited on the catalyst.
This allows an existing regenerator to accomplish complete combus-
tion without necessitating higher operating temperatures and the
associated major structural modifications.
3-3
-------
3.2 ATMOSPHERIC EMISSIONS
The most significant source of atmospheric emissions from a
FCC regenerator is the exhaust stack. In addition to the large quan-
tities of carbon monoxide and particulate emissions discussed earlier,
significant quantities of sulfur oxides (generated during combustion
due to the large sulfur contents which characterize this form of coke),
nitrogen oxides and hydrocarbons are emitted. Smaller amounts of ammonia,
aldehydes and cyanide are also present. The handling of catalyst both
into the system and out of the collection equipment can pose a fugitive
dust problem. New Source Performance Standards (NSPS) have been estab-
lished for carbon monoxide and particulates.
As was discussed in the previous section, the amounts of the various
pollutants entering the control devices are influenced by the design and
operating factors in the FCC unit. For instance, the amounts of sulfur
oxides increases with feed rate, sulfur content of the feed, and conversion
level. The amount of carbon monoxide increases with the amount of coke
produced, which increases with feed rate and conversion level and is also
influenced by catalyst type. Particulate loading varies with the type of
catalyst and increases with catalyst circulation rate and the rate of
regeneration air. These rates are, in turn, a function of the feed rate
and conversion level.
Another factor which may affect particulate emissions is the length
of time since last turnaround. Turnaround is a standard refinery practice
which involves the complete shutdown of the FCC unit for maintenance and
catalyst replacement. The practice occurs approximately every two years
with the exact time varying greatly between refiners depending on the type
of process employed. One of the prime factors which dictates turnaround is
a gradual trend toward lower conversion efficiencies of the feedstocks due
to decreased catalyst activity. Despite the fact that new catalyst is
constantly added to the operation to stimulate high activity levels, with
time an unavoidable general aging of the catalyst takes place. In addition
to an accumulation of coke deposits on the catalyst caused by the inability
of the regenerator to perform at one-hundred percent efficiency, the catalytic
binder begins to deteriorate, breaking down the particle and accelerating the
formation of fines. Because the efficiency of the internal cyclones is less
for the smaller particles, as their numbers increase, fines begin to appear
in the recirculated stream and the exhaust stream in higher rates.
Once this combined effect reaches a certain point, a turnaround is
performed. Source test reports on FCC units do not record the elapsed time
since last t-urnaround meaning that to date there are no statistical means
available to attempt to quantify any correlation between length of time of
operation and particulate emission increases.
3-4
-------
3.3 EMISSION CONTROL METHODS
Carbon monoxide and participate emissions are commonly controlled
by the devices shown in Figure 3.2. Carbon monoxide is converted to
carbon dioxide in the CO boiler and participates are removed in the
electrostatic precipitator. In some units the precipitator is located
upstream of the CO boiler.
Flue gas leaves the regenerator and enters the control system
through an orifice chamber, used to reduce pressure without creating
noise or valve wear. The flue gas, along with the air supplied by a
compressor and fuel gas, is then fed to the combustion chamber of the
CO boiler. The sensible heat of the flue gas, as well as the heat of
combustion of,the carbon monoxide and fuel gas, is recovered by pro-
ducing steam using conventional steam boiler practices. Exit gas from
the CO boiler is passed through electrostatic precipitators for removal
of particulates and then through the stack for dispersal to the
atmosphere.
A two port slide valve is provided ahead of the CO boiler to per-
mit the bypassing of regenerator flue gas in case maintenance or emer-
gency repairs of the boiler are required. The precipitator collection
chambers can be multiple units installed in parallel so that a unit can
be taken out of service for repair without interrupting operations.
3-5
-------
/-OCrt TlOfJ
Figure 3. 2
*•••»
• — i — i —
l i
1 ' !
' \
8
(
— •• 1
THE B£N KOU CO.
Z . O. .Boiler and
Drecipitator
— . 1 — | — • — i . — .. l...i
i i ; I — -
I"'1
!
-------
4.0 PROCESS AND CONTROL DEVICE INSTRUMENTATION
4.1 PROCESS INSTRUMENTATION
The process instruments of particular importance from the stand-
point of NSPS are the hydrocarbon feed flow rate recorder-controller
and the regenerator air flow rate recorder-controller. Performance
tests are normally to be made while the unit is operating at or above
the maximum expected production rate, based on the feed rate. For a
given combination of feed rate, feed stock, catalyst and conversion
level there is an expected rate of coke formation. The air required
for burning this coke is supplied to the regenerator by a compressor
under flow rate control and the air rate is directly related to the re-
generator flue gas rate. Flue gas rate influences catalyst carryover,
gas velocities in the cyclones and precipitator and residence time in
the CO boiler. Other instruments measuring variables such as reactor
and regenerator temperature and pressure and product gasoline flow
rate can be checked against design values to establish that the unit
is operating normally.
The NSPS regulation for allowable particulate matter from a
regenerator is calculated as a direct percentage of thevcoke burn-
off rate. The control room of a FCC unit does not normally have
a continuous readout of the burnoff rate. In isolated cases, control
rooms will be tied to a computer (such as an 1800 IBM) and capable
of an instantaneous value. The majority of the time, however, it
will be necessary to determine the coke burnoff rate by use of the
equation discussed in Section 2.2.1.1. The equation solution requires
values for five variables: (1) QRE, the FCC exhaust flow rate; (2)
QRA, the air rate to the FCC regenerator; (3) percent C02» (4) percent
CO; and (5) percent 02. Normal process instrumentation will include
the air blower rate to the regenerator (QRA) on a continuous basis;
a gas chromotograph readout of the exhaust stack with the percentages
of C02, CO, and 02 on a dry basis; the process operating temperature
will be on a continuous readout but may not be easy to obtain and
document due to the highly confidential nature of this value.
4.2 CONTROL DEVICE INSTRUMENTATION
The NSPS as applied to FCC units requires a continuous moni-
4-1
-------
toring system for the measurement of the opacity of emissions. The
continuous monitoring system shall be spanned at 60, 70, or 80 percent
opacity.
The opacity meters in gerieral use are of the photoelectric type.
A light source is mounted on one side of the stack and the beam passes
through the flue gas and strikes the photoelectric cell mounted on the
opposite side. The signal from the photoelectric cell is continuously
recorded.
The reader should be aware of the fact that a revision of the
NSPS opacity requirement has been proposed in the Federal Register,
Volume 41, No. 169 - Monday, August 30, 1976 (see Appendix 2).
While there are no longer NSPS requirements for the monitoring
of carbon monoxide from a FCC regenerator, the enforcement agency
should be aware of devices capable of quantifying CO emissions. Experts
in the catalytic cracking field tend to agree that a relationship can
be drawn between the percent combustion accomplished in the regenerator
and the temperature and oxygen (02) content. However, after checking
with sources in both government and industry, it seems apparent that an
accurate confirmation of this possibility in the form of equations or a
graphic representation (nomograph) is not currently available. A large
part of the problem is associated with the lack of a 'typical1 set of
process operating parameters from which to draw a correlation which
can be applied to any unit.
In the conventional FCC operation, the carbon monoxide exiting
the regenerator is destroyed in a CO boiler. Instruments have been
developed which are suitable for use in continuously monitoring and
recording directly the carbon monoxide concentration of a flue gas.
At this time, these devices are not considered to be as reliable and
trouble-free as the combination of an oxygen meter and temperature
recorder. Incinerating carbon monoxide in the presence of excess air
for a suitable length of time at a suitable temperature (for instance
0.3 seconds at 1,300°F) has been found to reduce the concentration
satisfactorily. Therefore, the combination of an oxygen meter and
temperature recorder probe is mounted in the firebox of the CO boiler
and the oxygen meter sample is taken from the exit gas duct.
Other control device instrumentation includes combustion controls
for the CO boiler, and electrical current and rapper controls for the
precipitator. The combustion controls may include a BTU computer,
used to match fuel gas flow with CO boiler air and regenerator flue
gas rates.
In some precipitators a spark counter is used to measure the
rate at which arcing occurs, and the voltage is automatically
4-2
-------
controlled to maintain the desired spark rate. A low but definite
spark rate is associated with maximum effective corona discharge,
and high collection efficiency.
Mechanical rappers are used to dislodge the catalyst fines
from the precipitator collector plates. Proper timing and sequencing
of rapper operation is needed to meet the current limitation of opacity
greater than 30% in any one hour.
Particulate matter has a tendency to collect on the CO boiler
tubes reducing the heat transfer and therefore steam generating
capabilities. To alleviate this problem, the boiler is "soot blown"
to remove this collected material. Soot blowing consists of injecting
pressurized air or steam across the tubes which loosens any accumulated
carbon and transports it downstream to either an electrostatic precipi-
tator or the exit stack. During soot blowing, it is not uncommon for
the maximum opacity limitation to be exceeded. Therefore, it is
important to time the blowing cycle so that it can be accomplished
within the time limitations of the NSPS opacity regulation.
4-3
-------
5.0 STARTUP/MALFUNCTIONS/SHUTDOWN
5.1 STARTUP
It is considered normal for an FCC unit to operate without shut-
down for at least two years, so that startups are infrequent. A
startup can be expected to take one or two days from a cold start
to full operation, with a period of operation at reduced feed rates.
Emissions during the startup period should not exceed the standards
unless a malfunction occurs. The unit operator is also required by
regulation to "use maintenance and operating procedures designed
to minimize emissions" during startup, shutdown and malfuction.
5.2 MALFUNCTION
Malfunctions in the reactor and fractionation sections of an
FCC unit may lead to shutdowns or operation at reduced feed rates,
but do not usually result in increased emissions from the regener-
ator section.
Regenerator and control device malfunctions that may affect
emissions include the following:
• Cyclone damage
• CO boiler failure
• Precipitator wire breakage
• Rapper failure
• High voltage supply failure
Regenerator cyclones are subject to severe erosion by the
abrasive catalyst. If the cyclones are sufficiently worn, they
fail to separate the catalyst from the flue gas and large amounts
of catalyst are carried into the CO boiler and precipitator. Cat-
alyst losses may become so large that the unit must be shut down
for economic reasons, but smaller losses can overload the precip-
itator. The entire FCC unit must be shut down if cyclone repair
is required.
CO boilers are very reliable and usually can be expected to
operate continuously for the two-year period between turnarounds.
A bypass is provided, however, so that the boiler can be taken
out of service temporarily for either minor repairs or for periodic
5-1
-------
safety inspections. Repairs would include burner replacement, the re-
pairs of feed water pumps and the repair of air blowers. Carbon mon-
oxide standards are exceeded while the boiler is out of service
so such periods must be limited.
Discharge electrodes in electrostatic precipitators frequently
take the form of wires, weighted at the bottom and hung vertically
between collector plates. Breakage of these wires is a common cause
of lost efficiency, and broken wires may need replacing every few
months.
If the precipitator has several parallel trains, wire replace-
ment can be accomplished by taking one section of the precipitator
at a time out of service, so that the unit can continue to function.
If the precipitator in question has only one train, the options
are fewer. Therefore, electrostatic precipitator installations with
more than one train should be encouraged.
If a rapper or its control fails to operate, the corresponding
collector plates will become clogged and collection efficiency will
suffer. Rapper repairs should not be required more than once or
twice between turnarounds.
Interruption of the high voltage supply stops precipitator
operation and particulate removal will cease. High voltage is
normally supplied by parallel units serving the corresponding
collection sections, so that repairs are usually possible without
taking the entire precipitator unit out of service.
5.3 SHUTDOWNS
Shutdowns, or turnarounds, are normally planned well in ad-
vance and generally occur about once every two years, although
some units have shown the capability of going over six years with-
out a turnaround. All major maintenance is scheduled for these
periods and only a serious emergency will justify an unplanned
shutdown. Planned shutdowns should not result in exceeding NSPS
regulations.
5-2
-------
REFERENCE FOR CHAPTER 5
1. Federal Register, Vol. 38, No. 198, October 15, 1973.
5-3
-------
6.0 INSPECTION PROCEDURES
An air pollution inspection consists of entering a refinery
to determine if the equipment or processes under investigation 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 records maintained by the operator. The Inspection
Officer (10) must observe, in a qualitative manner, the items as-
sociated with atmospheric emissions. The condition and type of
equipment, and general housekeeping all influence the emission rate.
Equipment design is a major factor that must be reviewed at the time
the construction permit or operating permit applications are evalu-
ated.
The importance of plant inspection as a field operations activ-
ity 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 conduction of an
inspection of a given equipment or process.
• 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
6.1.1 Formal Procedure
Prior to the actual on site inspection, the 10 should investi-
gate any available data on plant operations. In preparation for the
inspection the official should obtain the following data:
• Information for each major source (from an air pollution
point of view) including process descriptions, and esti-
mated flow rates, flow diagrams, estimates of emissions,
applicability of standards, and previous related enforcement
actions.
6-1
-------
• Plot plans showing disposition of all major units at
the facility including the location of the FCC unit.
• Business and ownership data including names of respon-
sible 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 refinery. The interview with refinery managers and equipment
operators can verify data gathered and clarify 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 equipment and processes in
question at the refinery. Others are conducted for specific purposes
such as:
• Obtaining information relating to violations
• Gathering evidence relating to violations
0 Checking permit or compliance plan status of
equipment
• Investigating complaints
• Following up on a previous inspection
• Obtaining emissions information by source testing
An initial inspection lays the groundwork for evaluating poten-
tial emissions of pollutants from the FCC regenerator and for asses-
sing the relative magnitude of pollution control problems requiring
correction, reinspection, or further attention.
The initial inspection has two phases: an initial general
survey and a physical inspection of the specific equipment and pro-
cesses. After this inspection is complete, routine surveillance
continues. 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 detec-
tion) are also made.
6-2
-------
The NSPS regulations for the FCC Regenerator have been presented
in Chapter 2. The specific details are given in Section 2.2, including
the various records related to the process which must be maintained.
The inspector should also review the records kept by the operator
and the readouts available in the control room. The procedure necessary
to determine the allowable particulates rate from the coke burnoff rate
has already been discussed. The Inspection Officer can expect to find
the air blower rate to the regenerator (QR^) on a continuous readout in
the control room. While QRE (the exhaust gas flow rate) is not directly
available, (see Appendix 3), the percent CO, C02» and Op on a dry basis
leaving the regenerator are read by .a gas chromatograpn on a contin-
uous basis and available in the control room. This gas chromatograjafe
also reads hydrogen, which is all assumed to leave as water. By calcu-
lating the hydrogen readout as water, an estimate can be made of the
moisture content. The inspector should be warned that refinery person-
nel consider many of the operating values associated with an FCC unit
to be proprietary in nature and that special care should-be given to
receiving the necessary clearance for the recording of information.
An additional aid to the 10 is the information incorporated in
applications to operate the equipment. The permit status of the
equipment should be routinely checked to detect any changes in equip-
ment or process that might invalidate an existing permit or conflict
with variance conditions.
Similarly, alteration of equipment is frequently detected by dis-
crepancies in the equipment description or by changes noted on engineer-
ing applications in the permit file.
6.1.3 Safety Equipment and Procedures
All refineries have standard safety procedures for employees and
visitors. These procedures also concern the 10. The 10 is accom-
panied to the unit or units to be inspected by the air pollution repre-
sentative within the plant or by such other informed refinery person-
nel as he might indicate.
Personnel protection is necessary in many of the industrial loca-
tions that an officer may be required to visit.
The 10 should wear a hard safety hat head covering while in
a plant. He should wear rubber gloves and goggles when necessary.
In the event of fire in the area of inspection, the 10 must leave
immediately, and remain outside the area until the "All Out" signal
is sounded. For safety, the 10 should be accompanied by another
person and the two individuals should remain together until the
job is completed. He must not smoke or carry cigarette lighters
which may ignite when dropped within an oil refinery. He should
use only approved flashlights in oil refineries.
6-3
-------
6.1.4 Frequency of Inspections
Because of the complexity of the petroleum industry and the
FCC unit in particular, the unit must be inspected systematically
and regularly. The frequency of reinspection is based upon the
findings during the initial inspection and the recommendations of
the 10 and his supervisor. These recommendations obviously depend
on whether or not "good" maintenance practices from the pollution
standpoint are 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 scheduled 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 process
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 necessary for NSPS compliance determination obtained
during an inspection can be summarized on forms similar to the
one shown on the following pages. These forms also serve as a
record of inspection.
A possible problem the Inspection Officer should always be aware
of in the data gathering process is confidentiality of information.
Many of the FCC operation parameters desired by the 10 can be expected
to be considered confidential by the source. The 10 should inform the
concerned party that under the provision of the Clean Air Act he has
the right to request whatever information he considers to be necessary
for his investigation but that he is bound by law to honor the confi-
dential nature of business information as defined in the Code of Federal
Register, Title 40, Chapter 1, pages 36902-36924, appearing Wednesday,
September 1, 1976.
During the inspection, the 10 should attempt to gain a feel for the
refiner's commitment to the use of "good" maintenance procedures. Check-
ing to ensure that proper procedures are being followed can prove difficult
for the regenerator vessel itself. Just as operational parameters differ
with each unit, the maintenance necessary to keep each unit operating
properly also varies. There are, however, several conditions the 10 can
check to determine whether proper maintenance is being performed on the
electrostatic precipitator (ESP) and the opacity monitoring device.
6-4
-------
The most common problem associated with an ESP is the loss of the
weights which are attached to the end of the electrode. The loose
electrode wires then have a tendency to wrap themselves around each
other and short out sections of the system. To reduce the frequency
of this occurence, the internal sections of the ESP should be visually
inspected at least once a month. The 10 can check to be sure that this
is being done by asking to see the maintenance log.
Opacity meters require a great deal of routine blower filter
maintenance in order to operate properly. The operator should keep a log
showing the history of the filter maintenance. If this log is not
kept or the 10 has any other reason to suspect that the meter is
operating improperly, he should ask the operator to perform a zero
check and a span check. Each of these tests can be performed almost
instantaneously. The zero test uses a retroreflector to simulate zero
opacity in the stack and indicates if the meter has any zero drift.
The span check utilizes a series of optical density setters to simu-
late specific stack opacities.
6-5
-------
INSPECTION CHECK LIST FOR
CATALYTIC CRACKING REGENERATORS
FACILITY IDENTIFICATION
Facility Name
Facility Address
Mailing Address
Telephone Number
Date of Last Inspection
Responsible Person to
Contact
Persons Contacted at Plant
Site
Inspectors
Source Code Number
OPACITY OBSERVATIONS
Emission Source
Average percent equivalent opacity from Method 9 obser-
vation
Reading ranged from to % opacity
*
Minutes in any one hour of 30% or greater opacity
Compliance status with opacity regulation
n
This value may change to 25% under the proposed new regulations
(see Appendix 2).
6-6
-------
FLUID CATALYTIC CRACKING UNIT AND REGENERATOR
(A) Input to cracking unit (e.g. gas oil
feed stock etc.) Barrel/day
(B) Catalyst recycle rate Tons/min
(C) Catalyst makeup rate Tons/hour
(D) Coke burnoff rate Pounds/hour
(1) In the event that the coke burnoff rate is not
directly known, the 10 must obtain the following
information:
(a) the controlled air rate to the fluid
catalytic cracking unit catalyst regen-
erator dscm/min
(b) volume percent CO on a dry basis leav-
ing the regenerator %
(c) volume percent C02 on a dry basis leav-
ing the regenerator %
(d) volume percent 0~ on a dry basis leav-
ing the regenerator %
(e) fluid catalytic cracking unit catalyst
regenerator exhaust gas flow rate before
entering the emission control system
(if known) dscm/min
(E) Hours of operation hours/day
(F) Has a source test been conducted on the unit recently which
regulatory agencies are not aware of?
If so, the 10 should attempt to obtain a copy of this test.
"*;"?;
CO BOILER (AFTERBURNER)
(A) Temperature of gas entering CO
boiler °C
(B) Flow rate of gas entering CO boiler M /second
6-7
-------
(C) Combustion temperature in CO boiler
(D) Auxiliary fuel(s) used
(1) Heat value of fuel(s)
(2) Quantity of fuel(s) used
PARTICULATE POLLUTION CONTROL EQUIPMENT
(A) Number of stages of internal cyclones in the regen-
erator
(B) External Pollution Control Equipment
(1) Cyclone separators, type
Evidence of corrosion and wear
Estimated collection efficiency
Pressure drop
Inlet temperature
(2) Electrostatic precipitators (ESP), type
Evidence of corrosion and wear
Voltage measurements and regula-
tion
Electrodes broken?
Condition of collection plates and
tubes
Alignment of plates _
Condition of rapping mechanism _
Rapper timing _
Sparking rate _
(3) Scrubber, type
Evidence of corrosion and wear
6-8
-------
Pressure drop
Effluent disposal system
Estimated collection efficiency
RECORDS OF OPERATION
Quality of records (circle one) Good Fair Poor
Regulations regarding recordkeeping being followed? (See
Section 2.2 regulations)
Opacity
Startup, shutdown,
and malfunction
Performance testing
OPERATIONAL ASPECTS
(a) Plant operating within specified
limits? Yes No If No, describe
(b) Any changes or modification in
equipment? Yes No If Yes, describe
(c) Evidence of lack of maintenance
Yes No If Yes, describe
6-9
-------
6.3 INSPECTION FOLLOW-UP PROCEDURES
After the completion of the inspection, the 10 must determine
the compliance status of the source. If an inspection indicates that
a source is not operating in compliance with applicable regulations,
the 10 should follow the established Agency procedures regarding
notice of violation, request for source test, and related matters.
The various items which could result in a determination of
non-compliance would include:
• Emissions in excess of 30% opacity for over three
minutes in any one hour*
• Emissions of carbon monoxide in excess of 0.050 percent
by volume
« Emissions of particulate matter in excess of 1.0 kg per
1,000 kg of coke burnoff
9 Monitoring equipment for opacity not being in operation
• Records of daily average coke burnoff rate and hours
of operation for any fluid catalytic unit catalyst
regenerator subject to NSPS not being kept
The 10 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, issues violation notices if appropriate, and ascer-
tains adequacy of plans for prevention of future accidents. 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 participat-
ing in pollution reduction effort. As a part of inspection follow-up
procedures, he also checks to see that engineering, procurement,
installation, and testing of equipment is proceeding according to the
approved plan.
Appendix 2 demonstrates the proposed change to this regulation limit.
6-10
-------
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.),
New York, Academic Press, 1968.
3. "Guide for Compiling a Comprehensive Emission Control Inventory
(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 Hold Co., Pasadena, California
for Environmental Protection Agency, Research Triangle Park, N.C.,
July, 1973.
5. Federal Register, Vol. 41, No. 171, September 1, 1976.
6-11
-------
7.0 PERFORMANCE TEST
The NSP Standards require a performance test of any new or
modified Fluid Catalytic Cracking Regenerator. In order to guarantee
the validity of the test, an inspection team will be present at the
facility for observation. The ideal team consists of three enforce-
ment personnel with the following areas of responsibility during the
test period.
• Monitor process operating conditions from the control room
• Make visible observations of opacity and process operations
from the plant area.
• Monitor emission testing procedures from the test site
Each team member should fill out check list type data during the test
and submit a report including analysis of the data and indication of
any upset conditions which may have affected the test.
7.1 PROCESS OPERATING CONDITIONS
For the purpose of obtaining source test data which is truly
representative of the operating characteristics of the Catalyst Regen-
eration Unit being tested, it is extremely important that the test be
conducted at or above the maximum production rate at which the par-
ticular unit will normally be operated. In certain cases, the EPA may
feel that conditions other than the maximum production operating rate
of the unit should be used to achieve valid test results. In such
cases, the EPA will specify the conditions at which source testing
must take place. In all cases, inspectors must personally verify that
the unit is operating at the specified conditions and has stabilized
at a steady state of operation. Such verification should be made
with the unit operator and refinery manager, and inspectors should observe
process controls (i.e., gauges, rate meters, and recorders) to deter-
mine that operating conditions are as specified. During the course
of the source test, inspectors should periodically check operating
conditions of the unit, carefully noting any changes in operating
parameters such as temperature, pressure, fuel flow rate, or changes
in the input and/or product process rate.
Since the standards apply at the point(s) where undiluted gases
are discharged from the air pollution control system (or from the
point of discharge from the unit, if no pollution control device is
present), inspectors must make sure testing is done at correct locations.
While the requirement to correct for dilution air during sampling was
deleted from 40 CFR Section 60.106 (c), the 10 should constantly be
aware of signs of concealment due to deletion (circumvention). This
7-1
-------
practice is a violation of 40 CFR Section 60.12: "No owner or operator
subject to the provisions of this part (NSPS) shall build, erect, in-
stall, or use any article, machine, equipment or process, the use of
which conceals an emission which would otherwise constitute a violation
of an applicable standard. Such concealment includes, but is not
limited to, the use of gaseous diluents to achieve compliance with an
opacity standard or with a standard which is based on the concentration
of a pollutant in the gases discharged to the atmosphere."
7.2 PROCESS OBSERVATIONS
The products of the Fluid Catalytic Cracking Unit are: gaseous
hydrocarbons, gasoline, gas oil, and coke. The coke is adsorbed
on the spent catalyst fines which are then rendered useless for fur-
ther cracking until they are regenerated. Spent catalyst fines
settle out of the cracking reactor and are drawn off at a control-
led rate. They are then purged with steam, and transferred (by air
stream) to the regenerator where the coke deposited on the cat-
alyst fines is burned off. The normal decoking operation produces
large amount of carbon monoxide (CO) which is routed by means of
ducting to a "CO Boiler" which burns the carbon monoxide (CO) to
carbon dioxide (COJ utilizing the resultant heat of combustion
to produce steam for other refinery processes (auxiliary fuel is
used to aid the combustion of CO to COJ. The particulate mater-
ial carried over consists of suspended catalyst fines which are
recovered by the emission control equipment. This equipment
should consist of a series of centrifugal collectors (cyclones)
and an electrostatic precipitator.
At the time the performance test is conducted, the inspector
should make careful notation as to the existing layout of the
process unit, operating range parameters of the unit, and the type
of pollution control equipment with which the unit is equipped. The
control equipment is especially important since subsequent source
performance testing will be affected by any modifications in this
equipment. Inspectors should note the number, size, and order of
centrifugal collectors (cyclones), as well as the model and maximum
efficient operating rate and the number of parallel trains of the
electrostatic precipitator. If possible, a photographic record
should be obtained of control equipment installations for future
record. Specific note should also be made as to provisions for
disposal of carbon monoxide from the catalyst decoking operation.
Inspectors should determine that this gas is transported to a
"CO Boiler" and what provisions exist for accurately measuring
the feed of CO from the regeneration unit to the CO boiler.
The equipment check list is the same as that which is sug-
gested in Section 6.2.
7-2
-------
7.3 EMISSION TEST OBSERVATIONS
Emission source testing discussed here concerns determining
compliance of new sources with EPA New Source Performance Standards.
During the source testing operations, field inspectors should
periodically spot check testing procedures, equipment, and data to
make certain that the test being conducted is valid.
All performance tests should be conducted while the unit being
tested is operating at or above maximum production rate at which the
untt wtll normally be operated. If the EPA Administrator feels that
other conditions should be used to achieve valid test results, such
conditions must be used as basis for testing.
The official EPA testing procedures are periodically improved.
In order to familiarize the 10 with the most current methods, a brief
description of the various applicable official EPA methods is presented.
7.3.1 Traversing (EPA Method No. 1)
Of first importance is the selection of a sampling point and
determination of the minimum number of traverse points to ensure
the collection of a representative sample. Inspectors should check
to determine if the sampling site selected is a minimum of two (2)
diameters downstream and at least one-half (1/2) diameters upstream
from any disturbance to the flow of gases within the duct or stack
which is being sampled. Such disturbances are commonly caused by
expansions or contractions, bends, visible flames* observable cross
members, or other entering ducts.
For certain processes, this may prove impossible to meet. In
that case, the 10 will determine the sampling point based upon the
equation presented in the official EPA methods appearing in the
Federal Register, Volume 39, No. 47, - Friday March 8, 1974.
7.3.2 Stack or Duct Gas Velocity Determination (EPA Method No. 2)
In the determination of gas velocity within the duct or stack,
the inspector should be certain that all data from each traverse point
is carefully and accurately recorded, as this is the basic information
used to determine the isokinetic sampling rate. Each point shall be
identified by a number and the following information shall be recorded
for each point: velocity head in mm (or inches) of water, stack (duct)
pressure in mm (or inches) of mercury, and temperature. Care should be
taken to determine that a type "S" pitot tube or equivalent is used to
obtain the velocity head readings and that this tube is of sufficient
length to reach all traverse points. The pitot tube should be graduated
with temporary markings (i-e., tape or indelible ink, etc.) such that
7-3
-------
each traverse point may be reached by successively moving the tube
deeper into or withdrawing it further from the duct or stack being
sampled. All tubing and connectors between the pi tot tube and the
inclined manometer or draft gauge should be tight and leak-free. An
inclined manometer or draft gauge should be used to obtain velocity
head readings from the pitot tube. Make certain that this gauge is
filled with sufficient colored liquid to give readings throughout its
range of calibration, and that the manometer liquid level is adjusted
to read "zero" with the end of the pitot tube shielded from incidental
breezes prior to beginning the velocity head measurment. Periodically
check to make sure that no constriction occurs in the hose connections
during the course of the velocity head measurement.
The most common means of stack temperature measurement is by
thermocouple and potentiometer; operation of this equipment is rather
straight-forward although several points should be checked to ensure
accurate measurement. The thermocouple connecting wires should be
securely tightened to the terminal lugs on the potentiometer, and it
should be determined that the thermocouple circuit is complete (an
open circuit will be evident if the potentiometer fails to balance,
giving readings off the scale of the instrument). If the potentiometer
being used is not an automatic compensating type (automatic reference
to ambient temperature), see that the ambient air temperature has been
recorded or that the potentiometer scale has been calibrated with this
temperature as a reference. While taking gas temperature readings,
sufficient time should be allowed (normally about five minutes) for the
thermocouple probe to reach thermal equilibrium with the duct gas before
taking the first few readings.
As part of the data necessary for the velocity determination,
the static pressure within the stack or duct should be measured. If
a "S"type pitot tube is used, the static pressure in the stack can be
determined by rotating the pitot tube onto its side. This can also be
done using a mercury filled "U" tube manometer, one end of which is open
to the atmosphere and the other connected to a probe extending into the
duct or stack itself. Again, the tubing from the probe to the manometer
must be free of constrictions and tightly connected at both ends. A
barometric pressure reading (of atmospheric pressure) in inches of
mercury, should be obtained from a standard barometer located in the
general vicinity of the test site; this can be a wall mounted barometer
in the plant offices, laboratory, or any convenient location which is
at ambient temperature and free of vibration.
If such a device is not available, barometric measurements in
the general vicinity of the test site can also be obtained by calling
the local weather station and asking for the station pressure and
correcting for test conditions (i.e. altitude).
7-4
-------
7.3.3 Gas Analysis (EPA Method No. 3)
Two methods of sampling are acceptable in obtaining an analysis
of the gases within a duct or stack: grab sampling and integrated
sampling. In the grab sampling method, the gases are drawn through
a probe directly into an Orsat type analyzer. If grab sampling is
used, inspectors should make sure that the sampling probe is of pyrex
or stainless steel (316) construction and that a small piece of glass
wool has been loosely inserted in the end of the probe to stop parti-
cles. A flexible tubing is used to connect the probe with the analyzer,
however, there must be some provision for purging the line; most often
a one-way squeeze bulb is used. During analysis using the Orsat,
notice that care is being taken to equalize the liquid levels with
the leveling bottle when readings are taken, and that the efficiencies
of the absorbing solutions are such that no more than ten (10) passes
are required to achieve constant readings (usually three to five pas-
ses will produce a constant reading).
The integrated sampling method utilizes the same type of probe,
but requires an air-condenser to remove moisture, as well as a valve,
pump, and rotameter in line between the probe and sample. If the
velocity of the gas varies with time or if a "sample traverse" is
taken,-a type "S" pitot tube may be used along with the probe so that
the sampling rate can be kept proportional to the gas velocity. The
rotameter should have a flow range from 0 to 0.001 cubic meters/min.
In operation, the sampling line is purged using the pump and the pre-
eyacuated flexible sample bag is attached to the system via a quick
disconnect coupling. Sampling is carried out at a rate proportional
to the gas velocity using the rotameter as a guide and the valve for
control. The sample bag should be large enough to obtain a
sample of about 0.232 to 0.786 cubic meters. Again, all connec-
tions must be leak-free. After sampling is complete, the bag is
transferred to an Orsat apparatus for analysis. Gas analysis must be
performed whenever a determination of particulate matter (Method 5),
sulfur dioxide (Method 6), or carbon monoxide (Method 10) is carried
out.
7.3.4 Moisture (EPA Method No. 4)
The moisture content of the duct or stack gas is obtained by
extracting a sample at isokinetic rate and collecting the condensate
in midget impingers. The moisture determination is carried out at
the same site used to determine the volumetric flow rate. Sampling
time must be at least 60 minutes with the minimum final collected
volume being 0.6 M3 (20 ft3) at standard conditions. Select the
sampling site and minimum number of sampling points according to EPA
Method 1.
7-5
-------
The items to be spot checked by inspectors during moisture
sampling are the same observed during particulate matter testing with
the following differences:
The impingers in this case are of the "midget" variety (30 ml
capacity) and should contain about 5 ml of distilled water each.
Since condensate silicon gel is determined on a weight basis, make
certain that it has been tared prior to their placement in the ice-
water bath. As before, determine that initial temperature, volume,
and barometric pressure have been properly recorded. Check probe
heater operation (120QC at impinger end) and all connections for tight
seals. A silica gel drying tube should be placed in the line directly
behind the impingers.
The following data should be recorded for the purpose of check-
ing calculations later: sampling time, gas volume through meter,
rotameter setting, and the temperature of the meter throughout the
testing period.
7.3.5 Particulate Matter (EPA Method No. 5)
When sampling for particulate matter according to EPA Method 5,
the minimum sampling rate will be 0.014 M^ per minute and the sampling
period will be at least 2 minutes per point. During the sampling opera-
tion, the inspector should check the probe liner to make sure it is
either pyrex or quartz glass. When length limitations are encountered
stainless steel (316) or Incoloy 825 may be used. The probe nozzle will
be a stainless steel (316) nozzle with a sharp, tapered leading edge.
The use of stainless steel ensures non-reactivity of the probe material
with either the gas stream or the sample being collected. These ma-
terials are selected also because of their resistance to distortion at
elevated temperature. The probe nozzle must be pointed opposed to the
direction of gas flow while the sample is being collected, and a type
"S" pitot tube be attached with a 1.9 cm (3/4 inch) separation between
it and the nozzle in order to monitor the gas velocity. Check to
determine that the probe heater is working (about 120°C at the probe
outlet), and that a fresh filter was placed in the filter holder before
beginning the test. The filter-heating system must also be operating.
The impinger box must be filled with an ice and water bath and
there should be an additional supply of ice on hand to maintain the bath
cold enough so that the impinger temperature remains at 20°C or less
throughout the test. Four Greenburg-Smith type impingers are placed
in series in the ice bath and connected by means' of ball and socket
joints. All glassware should be clean and the. ball joints should be
snugly connected and secured with the proper size metal spring clamp.
7-6
-------
Note that the second impinger in the series has the conventional im-
pingement nozzle, but that all others have the straight glass tubing
extending to 1/2 inch from the bottom. The first two impingers in the
series have exactly 100 ml of water each (measured by graduated cylin-
der); the third is empty, and the fourth must contain 200 grams (pre-
weighted) of silica gel, preferable the indicating type.
A thermometer should be placed in or just after the fourth
impinger, followed by a check valve to prevent reverse-flow surges.
From this point the line should contain the following components:
vacuum gauge, main valve, air tight pump with bypass valve, dry gas
meter with temperature dials at inlet and outlet, and an orifice
meter connected to an inclined manometer, respectively.
Check to make sure that all gauges and temperature dials are
operating properly, and that all appropriate valves are in open
position (bypass will normally remain closed), that pump and test
meter are correctly functioning, and be sure than connecting lines
are attached to their proper inlets and outlets - reverse order is
a common mistake here. Both pitot and orifice manometers should be
checked out as previously described.
The following information should be recorded from the data
sheets for the purpose of spot-checking the accuracy of the cal-
culated final results.
(a) Average velocity, head, mm h^O
(b) Average gas temperature, °C
(c) Static pressure in duct or stack, mm Hg
(d) Barometric pressure, mm Hg
(e) Diameter of duct or stack
(f) Sampling time (start to finish)
(g) Average pressure differential across orifice meter
(h) Gas sample volume
(i) Gas sample temperature at dry gas meter (average
for inlet and for outlet)
(j) Impinger bath temperature, °C
(k) Impinger temperature, °C
(1) Volume of condensate collected in impingers, ml
7-7
-------
7.3.6 Carbon Monoxide (EPA Method No. 10)
The sampling train should consist of the following: A stain-
less steel or pyrex (sheathed) probe equipped with a particulate
filter, an air condenser to remove excess moisture, a needle valve
and flow rate meter (rotameter), and finally a quick disconnect
coupling. A pump and flexible bags (60-90 liters) must be on hand
or, bags can be pre-evacuated in the laboratory.
Not less than 60 minutes shall be consumed in sampling. A
type "S" pitot tube should be used along with the sampling probe
in order to monitor the gas velocity and keep the rate of sampling
proportional to the gas velocity. Since analysis is accomplished
by instrumental means based on comparison of sample to prepared
standards, collection of field data for checking results is not
applicable here. If analysis is at or near the sampling location,
check to make sure the NDIR analyzer has an operating range of at
least 0 - 1,000 ppm and several scales of various sensitivities.
The line to the analyzer will then also have a quick-disconnect
coupling followed by a pump, needle valve, flow rate meter, two traps
in series (one containing "indicating" type of silica gel; the other
containing "Ascarite" or equivalent), and provisions for introduction
of calibrating gas. The calibrating gas will include a "zero gas"
and a "span gas" (standard concentration of CO); these gases can be
introduced to the sampling line via a branch "T" pipe with provisions
for metering the rate of introduction of the calibration gases. The
nondispersive infrared analyzer (NDIR) is the last step in the
sampling analysis line.
7.3.7 Emission Monitoring
Since continuous emission source monitoring is required for
opacity of particulate materials, inspection must be made of moni-
toring instruments to determine that they are properly installed
and operating, and that proper calibration and maintenance proce-
dures are being followed.
For particulate emission monitoring the photoelectric monitor
may be used. This essentially measures the opacity or optical den-
sity of a stream of gases. Characteristically such installations are
in widespread use and operate on the principle that particulate mat-
ter, in a gas stream, will interrupt a beam of light (between source
and detector) in proportion to its concentration in the gas stream.
In practice the system consists of a light source, a detector (photo-
multiplier tube), and a recorder. Often an alarm feature is incorporated
in the system to sound when the opacity reaches a predetermined level.
These systems work well if maintenance and calibration are performed on
7-8
-------
a regular and thorough basis. It should be determined that: calibration
is frequently performed, optical surfaces are kept clean and in proper
repair, proper alignment of source and detector is maintained, and that
recorder and alarm systems are in good working order. Variations exist
between many different suppliers of such opacity metering systems, how-
ever, the principle involved as well as the operating problems are
basically alike for these systems in general.
Some systems may have both the source and detector on the same
side of the stack, utilizing reflectance to return the light beam.
Calibration and zeroing is quite a problem while the plant is opera-
ting; one technique often employed uses a sliding tube to connect
the source and detector and thus exclude the gas stream from the
beam path for calibration.
Source monitoring installations should be free from vibration,
shock, and excessive heat, should be weathertight and so placed as
to provide safe and convenient access for calibration purposes.
The Inspection Officer should be careful to ascertain from the
operators the frequency of calibration and the calibration techniques
used. Calibration frequencies of less than once every two or three
days are not desirable.
7-9
-------
REFERENCES FOR CHAPTER 7
1. Federal Register, Vol. 36, December 23, 1971.
2. Federal Register, Vol. 38, No. 1111, 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.
4. Federal Register, Vol. 41, No. Ill, June 8, 1976.
7-10
-------
APPENDIX 1
NEW SOURCE PERFORMANCE STANDARDS FOR
FLUID CATALYTIC CRACKING REGENERATORS
-------
Subpart '—Standards of Performance for
Pstroleum Refin«ri«s 5
§ 60.100' Applicability and desijrnalion
of iiiTeclcd facility.
The provlsioris of this subpart are ap-
plicable to tht foilo—ing affected facil-
ities ir. petroleum refineries: Fluid cata-
lytic crocking unit catalyst regenerators,
fluid catalytic cracking unit incinerator-
waste heat boilers, p.ad fuel gas Combus-
tion devices.
§60.101 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given th^m in. the Act and in subpart A.
(a)'' '''Petroleum refinery" 'means any
facility engaged in producing gasoline,
kerosertp, distillate fuel oils, residual fuel
oils, lubricants, or other products
through distillation 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 as canned in this section.
(d) "Fuel gas" means any gas which
Is generated by a petroleum refinery
process unit and which is combusted, in-
cluc'.;n;< any gaseous mixture of natural
gas and fuel gas which is combusted.
01 "Piw-fiss upset gas" means any gas
generated by a petroleum refinery process
unit a,« a. result of start-up, shut-down,
lipr-et or malfunction.
(f) "'Refinery process unit" means any
segment of the petroleum refinery in
which a specific processing operation is
conducted
-(£) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers artf, flares ii?ed to com-
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
produce sulfur or sulfuric acid,
Ch) "Coke bum-off" means the coke
removac! from th'e surface of the fluid
catalytic, cracking unit catalyst by com-
bustion in the catalyst regenerator. The
rate of coke bum-off is calculated by the
formula specified in s 60.106.
(2) Gases exhibiting- 30 percent opac-
ity or greater, except _for 3 miautes in
any 1 hour. 13
(b) In these 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 paraffraph (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 !b/rnffiion Stu) of heat
input attributable to such liquid or solid
fuel.
§ 60*103 Standard for carbon imonoxuile-
(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 § 50.8 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 HLS in excess of 230 mg/dscm
(0.10 gr/dscf), except as provided in
"a~c^T£.~ f this -ti rr"i^<* f^T.-
I 60.102 Star.dzu-d
in alter.
for pnrticulule
(a) On and after the date on which
Lhe 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 any
fluid catalytic cracking licit catalyst re-
?eaeraior or from any fluid catalytic
cracking unit incinerator-waste heat
boiler:
(1) Paniculate matter in excess of
1.0 ks.'lOQO kg (i.o lb/1000 Ib) of coke
burn-off in the catalyst regenerator.
under ^ar-a^r^pn 2.1, Pc.-forrnar.w? ;.;v?ci-
fication 2 iji-.c 'or calibration checks un-
der 5 SOilSic1) to th,is part, shall be-sul-
fur dioxids C.O.-). The span shaft ijs-set
at 100 pprp.. i-or conducting mor.if.-oring
system performance evaluations under
sEO.ISCc), "?.<• ->rer,ce Method 6 shall be-
used.
(4) [Reserved!
(b) [Reserved) ', ^
(c) The 'iiV^rage- coke 'biim-oil rate
(thousands ;.i kilogram/hr) and hc-jrTbf
operation for any fiuid catalytic crack-
in;? unit "catalyst'regenerator subject'to
.5 60.102 or 63.103 sfiaU be recorded daily.
(d) For 'any fluid catalytic cracking
unit catalyst regenerator which is subject
to § 60.102 r-.nd which utilizes an ineiaer-
ator-waste "..-sat boiler to combust the
exhaust gas U), the fol-
lowing reference methods and calcula-
tion procedures shall be used:
(1) For gas«s released to the atmos-
phere from th,5.fluid catalytic cracking'
unit catalyst regenerate!:
(i) Method 5 for the concentration of
participate matter s.nd moisture con-
tent,
(ii-i Method 1 for sample "^ad velocity
traverses, zinc!
(ill) Method 2 for velocity and. volu-
metric flow r?,te.
(2) For Teethed 5, the sampling tiime
for each run shall b-e at least 80 raiuutes
and the sampling rate shall be jv» least
0.0.15 dscaA-rdn (0,50 clsc'/min), except
that sliortar Seunpi-'rigr tirces may ba ap-
proved by ma Aclailnistr&tor when proc-
ess vartaV.es or other factors.preclude
sampling lor at least 60 minutes.
.(3) Por »'X'haust gastis from the fiuki
catalytic cr^ckicg unit catalyst regenera-
tor prior to tee emission control system:
the integrated sample tecaniqjes "oi
Metiod 3 and Method 4 for. gas analysis
and moisture content, respectively;
Method 1 for velocity traverses; and
Method.2 ia? velocity and-voiizmetric flow
rate.
(4) Cok,; o'jra-oar rate shall be deter-
mined by t_ie following formula:
-------
H.»0.:s« Qia (%COj+%CO)+I.C«Ji QBA-O.
fc.-0.0r* Q», i7,COrr-%CO)-r-0,l3C3 Qn»-0.00« Q»» |
where:
0.0! 56-
I %COrr-aOi) (Metric Ufllti)
Dalss)
cokebum-oa rata, Vgibr (cssliah units: Ib/br).
m»i~-.c umu malarial b.Uauca !icu>r uivlded by 100, kg-mln/hr-m'.
Kr:Jjb unlu mauu-.ii bailee factor divided by 100, lb-min/br-R>.
.".ilia catalytic cracking urn; catalyst regenerator exhaust gas flow rat* before euUrlog the emission
o>n*ro) system, as detemuctd by method 2, uscm/mln (EnxUsb. unlU: rlscJ/min).
^COi^p^rrent carbon percent carbon conouce by 7olume, dry b&sij, as deUrmlnMl by ]bUtbod3.
% Oiap<>(T«nt ory^en by vniume, dry buiA. ^s detarmined by Method :L
2.C*S=«r:«t.-:c uniu malarial bjiaace factor divided by 100, ks-min/br-m1.
O.IXa-Kix'JsQ uniu maurtal baUnc* factor divided by 1'JO, lb-mia/br-R>.
air rit« to Quid caUiytlc craciann unit catalyst rwenerau/r, as determined from fluid eatalytift crackinf
crut control room iastnim«ntatioa. d£cm/min (English. unlU: dscA'min).
O.OW4—metric units matorial beJance (actor diTided by 100, ks-mln/hr-m'.
O.OOrM!«£n£Ush uniu inai^n^l balance faciA/ divided by 100, Ib-mln/bT-fl'.
(5) Particulate emissions shall be determined by the following equation:
Rsi=-(eoxiO-»)0,xvC. (Metric Units)
R»-(8.47X10-i)Q,TC. (English Units)
P.E<-particu!aUemission rate, kg,7u (Engiiat uniu: Ib/hr).
WX10-«—metric units conversion tictor, min-kn/hr-raK.
8-67XI'T'=Ea«hsh uniu coo«araon ,'acUir, mla-lo/br-gr.
Qav^oiumetric fio-» rata of <:uee discharged Into the atrcotphere from lie Buld catalytio cracking unit
catalyst regenerator Touoving the emission control sysum, u deuumlned by Method 2, dscm/mla
(English units: dsclymin).
C.-eparticulat« emission concentration discharged into Ibe atmosphera, as. detarmin«d by ^Uthod 5.
mg/dscm (EngUsh units: gr/dscJ).
(6) For each run, emissions expressed in kg/1000 kg (English units: lb/1000 Ib)
of co^e burn-off in the catalyst regenerator shall be determined by the following
equation:
(d) Method 6 shall be used for de-
termining concentration of SOj in de-
termining compliance with 5 SO.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 How rate. The sampling site
for determining GO, concentration by
Method 6 shall be the same as for
determining volusjetric flow rate by
Method 2. The sampling point in thTT
duct for determining SOS concentration
by Method 6 shall be at the centroid of
the cross section if the cross sectional
area is less than 5 m' (54 ft') or at a
point no closer to the walls than 1 m
(39 inches) If the cross sectional area
is 5 m* or more and the centroid is more
than one meter from the wall The
sample shall be extracted at a. rate pro-
portional to the gas velocity at the
sampling point. The minimum sampling
time shall be 10 minutes and the mini-
mum sampling volume 0.01 dscm (0.35
dscf) for each sample. The arithmetic
average of two samples shall constitute
one run. Samples shall be taken at ap-
proximately 1-hour intervals.
(Metric of English Unili)
wbers:
R.-pv.icula'-e emission rate, tgAOOO kg (English units: lb/1000 Ib) of coke born-oS In the ftuid catalytic crack-
i.'L? nnit catalyst regenerator.
:<"'•)-,:"nversion [actor, tj to ICuj kz (Eneiish units: Ib to 1000 Ib).
£3= paniculate emission ra:e, k?/hr (English units: Ib/br).
P..=coia oom-ofl ra'-e, kg/a.- (English aniu: 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-
mitted under § 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 particulate emissions permitted under
S 60.102(b) shall be calculated from the following equation:
0.18 H
(Metrlo Units)
nglish Units).
H.=aUo J3bi« partlcuUto emission rate, kg/lCOO kg (English units: lb/1000 Ib) 01 coke burn-oft in the
"t-^'l caUiyUc cracking unit catalyu regenerator.
l.O-emjssioD standard, 1.0 kg/1000 kg (Ecgbjli uciu: 1.0 lb/1000 Ib) oJ coke bura-oH In the Bold catalytic
crocking unit catalyst regenerator,
O.M^Tnetrc units maxlrcuci aljowabie Incremental rate of particnlAt« emissions, g/million ca).
0.10= Ennusa -units matimnTn allowable l/icnmeatal rate oi partlculaU) emlssioas, Ib/milUoo Bta.
H»*b«*t lapnt (rora solid or liquid foeail fnel, milUoo cal/br fEoallsb tmits: ralUlon Btn/hr).
B.-coi« bura-oS rate, kg/or (EngUih uniu: ]b/hr).
(b) For the purpose of determining
compliance with 5 60.103, the integrated
sample technique of Method 10 shall be
used. The sample shall be extracted at a
rate proportional to the gas velocity at a
sampling point near the centroid of the
duct. The sampling time shall not be less
than 60 minutes.
(c) For the purpose 61 determining
compliance with 3 60.104(a), Method 11
shall be used. When refinery fuel gaa
lines are operating at pressures substan-
tially above atmospheric, the gases sam-
pled must be introduced Into the sam--
pling train at approximately atmospheric
pressure. This may be accomplished with
a flow control valve. If the line pressure
is high enough to operate the sampling
train without a vacuum pump, the pump
may be eliminated from the sampling
train. The sample shall be drawn from a
point near the centroid of the fuel- gas
line. The minimum sampling time shall
be 10 minutes and the minimum sam-
pling voJuma 0.01 dscm (0.33 dscf) for
each sample. The arithmetic average of
two samples shall constitute one run.
Samples shall b« taken at approximately
1-hour intervals. For most fuel gases.
sample times exceeding 20 minutes may
result In depletion of the collecting solu-
tion, although fuel gases containing low
concentrations of hydrogen sulfide may
necessitate sampling for longer periods of
time.
-------
Subpart K-"—Standards of Performance for
Storage Vessels for Petroleum Liquids5
§ 60.110 Applicability and desieniuion
of affect
(a) Except as provided in 5 60.110(b),
the affected facility to which this sub-
part applies is each storage vessel for
petroleuta liquids which has a storage
capacity greater than 151,412 liters
*40,000 gallons).
(b) This subpart. does not apply to
storage vessels for iiie=cnsde petroleum
or condensate stored, processed, and/or
treated at a drilling and production
facility prior to' custody transfer.8
§60.111 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Storage vessel" means any tank,
reservoir, or container used for the
stora.ee of petroleum liquids, but does
not include:
(1) Pressure vessels which are designed
«3 operate in excess of 15 pounds per
square inch gautre -'Uhout emissions to
the atmosphere except under emergency
conditions,
(2) Subsurface caverns or porous rock
reservoirs, or
(3) \7ndererround tanks if the total
volume o.f petroleum liquids added to
an4 taken from a "vank annually does
not exceed twee the volume of the tank.
(b) "Petroleum liquids" means petro-
leum, condensate, and any finished or
intermediate products manufactured in
a, petroleum refinery but does not mean
Number 2 through Number- 6 fuel oils
as specified in A.S.T.M. D396-69, gas
turbine fuel oils NumDers 2-<3T through
4-GT as specified in A.S.T.M. D2880-71,
or dlesel fuel oils Numbers 2-D and 4-D
as specified in A.3.T.M. D97K-68.8
(c) "Petroleum refinery" means any
facility engaged in producing gasoline,
kerosene, distillate i'uel oils, residual iuel
oila, lubricants, or other products through
distillation of petroleum or through
li.itillation, cracking, or reforming of
i.^hiMshed rjf.trolKum derivatives.
(d) "Petroleum" means the crude oil
i moved from the earth and the oils
aerived from tar sands, shale, and coal.8
(e) "Hydrocarbon" means any organic
compound consisting predominantly of
carbon and hydrogen 4
(f) "Condensate" means hydrocarbon
liquid ssparal/ed from natural gas which.
condenses due to changes in the tem-
perature and/or pressure and remains
.liquid at standard conditions.
(g) "Custody transfer" means the
transfer of produced petroleum and/or
condensate, after processing and/or
treating in the producing opei-stions.
from storage tanks c'r automatic trans-
fer facilities to pipelines or any other
forms of transportation. 8
(h) "Drilling and production facility"
means all drilling and servicing equip-
ment, wells, flow lines, separators, equip-
ment, gathering lines, and auxiliary non-
transportation-rclated equipment used
In the production of petroleum but does
not include natural gasoline plants. 8
(S) "True vapor pressure" means tha
equilibrium partial pressure exerted by
a petroleum liquid as determined In ac-
cordance with methods described in
American Petroleum Institute Bulletin
2517, Evaporation Loss from Floating
Roof Tanks. 1962.
(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 Js supported by the petroleum
liquid being contained, and is equipped
with a closure seal or seals to close the
space between the roof 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 hydrocarton vapors and
gases BO 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, except.liquified petroleum gases,
as determined by ASTM-D-323-68 (re-
approved 1958).
§ 60.112 Standard for hydrocarbons.
(a) The owner or operator of any stor-
age vessel to which this subpart applies
shall store petroleum liquids as -follows:
(1) If the true vapor pressure of the
petroleum liquid, as stored, is equal to
or greater than 78 mm Hg (1.5 psia) but
not greater than 570 mra Hg (11.1 psia),
tho 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 Kg (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) The 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, of the typical Reid 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 oi any stor-
age vessel to which this subpart applies
shall for 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 iii.
vapor, pressure, as stored, greater thai
470 mm Hg (9.1 psia) and is stored r
a storage vessel other than one equlppe.
with a vapor recovery -system or It
equivalent.
(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
peratures determined at least one
every '7 days.
(d) The true vapor pressure shall I;
determined by the procedures in AP
Bulletin 2517. This procedure is de
pendent upon determination of th
storage temperature and the Reid vapo
pressure, which requires sampling of th
petroleum liquids in the storage vessel'
Unless the Administrator requires i;
specific cases that the stored petroleui:
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 specifi
cations limiting the Reid vapor pressur
exist, that Reid vapor pressure may b
used. For other liquids, supporting ana
lytical data must be made available 01
request to the Administrator when typl
cal ReM vapor pressure is used.
-------
APPENDIX 2
PROPOSED REVISION TO THE OPACITY STANDARD FOR
NEW FLUID CATALYTIC CRACKING REGENERATORS
-------
SGGOO
ENVIRONMENTAL PROTECTION
AGENCY
[fereiu'eci In Wethrd I). Tl.o use
«f tcta of opacity d:itn will preclude
-------
PROPOSED RULES
3GG01
50,000 barrels pei day arc built, or exist-
ing unsts urc modified or reconstructed.
and three facilities have trouble mcelini:
the proposed revised opacity stand;.rd,
relief can bu obtained through the
mechanism of SGO.lKe).
At most fluid catalytic eraekim units,
carbon monoxide einiyslwis are eon-
trolled by carbon in"no.\Hlo boilvrs. Pe-
riodically, the boiler uil.uis ;o>'.uirc soot
blowing to remove dusi or .soot deposited
on these tubos. Soot blowing increases
the opacity of the plume from the cata-
lyst regenerator dramatically, although
only momentarily. Rutlior than increase
the level of the opacity Standard to in-
clude soot blowing, therefore, it is more
appropriate to provide an exemption
from the standard. The opacity data in-
dicate that nn exemption of two six-
minute average opacity readings per
hour is necessary to permit soot blowing.
Thus, an exemption for SOOL blowing is
Included in tine proposed revision to the
opacity standard.
It should be noted that standards of
performance for new sources established
under section 111 of the Clean Air Act
reflect emission limits achievable with
the best adequately demonstrated sys-
tems of emission reduction considering
the cost of such system. State implemen-
tation plans (SIP's) approved or pro-
mulgated under section 110 of the Act,
on the other hand, must provide for the
attainment and maintenance of national
ambient air quality standards (.NAAQS)
designed to protect public healtii .and
•welfare. >'or that purpose SIP's must in
some cases require greater emission re-
ductions than those required by stand-
ards of performance for new sources. In
addition, States are free under section
110 of the Act to establish more strin-
gent emission limits than those estab-
lished under sec-lion 111 or thus nere.«-
sftvy to attain or friaiiitain thn NAAQ.S
under .section 110. Thus, new iiiul c\:st-
Jnrt sources may in some case.; bn Mib.iwt
to limitations more ?lriM'.'.cnt than I^P.V.s
standards ol performance under section
111.
PUBLIC P*imi;iPATioN
IntciTslod persons may participate in
this proposed ruleirtaliinp; '•>:•' Milwiiums
writ ton coninH'iit.'i uu triplu—.tci to the
Emi.-.r.ion Stantluids and Encinerring
Diviri.on, U.S. Environmental Protection
Aijcncy, Research Triangle Park. North
Carolina 2771 1, Attention: Mr. Don B.
Goodwin. The Administrator will wel-
come comments on all aspects of the
proposed revision.
All relevant comments received on or
before October 29. 1976 will be consid-
ered. Comments received will be avail-
able for puolic inspection and copying at
the EPA Public Information Reference
Unit, Boom 2922 fEPA Library) , 401 M
Street. S.W., Washington, D.C.
Background information on this pro-
posed revision of the opacity standard
for petroleum refinery fluid catalytic
cracking unit catalyst regenerators has
been published in a document "Rcevalua-
tion of Opacity Standards of Perform-
ance: Petroleum Refinery Fluid Catalytic
Cracking Unit Catalyst Regenerators."
Copies oi this document may be obtained
by writing to the Public Information
Center (PM-215), U.S. Environmental
Protection Agency, Wasnington, D.C.
204CO (specify Reevaluation of Opacity
Standards of Performance: Petroleum
Refinery Fluid Catalytic Cracking Unit
Catalyst Regenerators) .
30Hu) of tliC f'lcixn Air ACt, us nmciidcit by
Ki'cllon 'l(n) of I'ulillc l-:iw !i)-om, 81 8 tat.
10V8 pnd by !.rcl ton lli(c)(2) of 1'i'bllc I.iiw
Ol-dO-S, M St:if. 1713 (43 U.S.U. J057C-G,
18(i7c-n, nud JB.IVe(n)).
. Dated:
1£), JP7C.
KUSSIILI. R. TRAIN.
Administrator.
It is proposed to amend ."art CO. Chap-
ter I of Tiilc -JO of the Co.jc ol Federal
Regulations as lollows:
1. Section 60.102(a) (2)
read as follows:
is revised to
StiuiJ:irariiru!alc m.it-
This notice of proposed rulemaking is Issued
under authority of sections 111, 114, and
§ 60.102
icr.
(a) * * '
(2) Gases exhibiting greater than 25
percent opacity, except for two six-
minute average opacity readings in any
one hour. Where the presence of uncom-
bined water is the only reason for failure
to meet the requirements of this sub-
paragraph, such failure shall not be &
violation of this section.
2. Section G0.1,05(e) (1) is revised to
read as follows:
§ 60.105 Emission monitoring.
(c) * • •
(1) Opacity. All hourly periods in
•which there are three or more six-niinute
average opacity readings during which
the average opacity of the gases .dis-
charged into the atmosphere from any
fluid catalytic cracking unit catalyst re-
generator subject to § 60.102 exceeds 25
percent.
* # * * * *
[FRDOC.7G-250BO Filed 8-27-76;8.-45 ani]
FfcDERAl titGilTtX, VOL t\, MO. 169—MONDAY, AUGUST 30, 1976
-------
APPENDIX 3
ESTIMATION OF THE EXIT GAS VOLUME LEAVING THE
FLUID CATALYTIC CRACKING UNIT REGENERATOR
-------
In order for the Inspection Officer or other members of an
enforcement agency to determine the compliance of a FCC regenerator
with NSPS, it is necessary to use the coke burnoff equation discussed
in the text. The problem is that after checking with many refineries,
it was discovered that a continuous readout of the exit gas volume
(QRE) 1S n°t available. The problem then becomes; how can this param-
eter be derived in order to use the equation?
One quantity which is oh a continuous readout in the control
room is the amount of air entering the regenerator on a dry basis.
(QRA)- This gas is assumed to consist of 79% nitrogen and 21% oxygen.
Since nitrogen is neither produced or destroyed in the regenerator,
the only exit source for the nitrogen is through the top of the regen-
erator vessel. The nitrogen leaves as either nitrogen gas (N2) or a
nitrogen oxide (NOX). The amount of the exit gas volume leaving as
NOX is approximately 200 ppm (from source test data) or 0.02% which
is considered to be negligible. Therefore basically all of the nitrogen
leaves as N2- If the amounts of hydrocarbons, aldehydes, ammonia, and
other trace elements are also considered to be on a negligible scale
with respect to the exit gas volume, then the only exit gases on a dry
basis will be CO, C02, Q£ and Ng.
%N2 + %C02 + %CO + %02 = 100% of exit gas volume
%N2 = 100% - (%C02 + %co -(- %02)
If the amount of nitrogen leaving is equal to the amount
entering the regenerator:
.79 QDA = (%N0) (QDtr) where QDC is the exit gas volume on
RA L RE Rh a dry basis
100% -%co2 - %co - %o2
-------
TECHMICAL REPORT DATA
.• ''.\ :>e read l.tztfu'ti'jr.s on the rsvirsc btf'are completing)
EPA 340/1-77-006
,TL5 inspection Manual for the Enforcement
of New Source Performance Standards: Fluid Catalytic
Cracking Regenerators
3. RECIPIENT'S ACCESS'OiVNO.
5. REPORT DATS
October, 1976
5. PERFORMING ORGANIZATION CODE
'. ALjTHORiS)
3. PERFORMING ORGANIZATION REPORT NO.
3. PERFORMING ORGANIZATION NAME AND ADDRESS
Pacific Environmental Services, Inc.
1930 14th Street
Santa Monica, California 90404
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-01-3156, T.O. #19
] 12. SPONSORING AGSNCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Division of Stationary Source Enforcement
Washington, D.C.
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
|15. SUPPLEMENTARY NOTES
16. ABSTRACT
The purpose of this document is to assist air pollution agencies in the enforcement of
Federal new source performance standards (NSPS) for fluid catalytic cracking (FCC) re-
generators. The standards restrict the visible (opacity), particulate, and carbon mon-
oxide emissions from FCC regenerators whose construction on modification commenced on
or after June 11, 1973.
This manual outlines the various NSPS regulations which currently apply to an FCC unit,
and describes the different types of FCC operations the field inspector must be prepared
to examine. This manual also provides an on-site inspection procedure and information
checklist which will supply an agency with the information needed to determine com-
pliance with NSPS regulations. A short summarization of the official EPA source test
methods is included to enable the inspector to observe performance testing and ensure
that proper procedures are used.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
Catalytic Cracking
Regeneration
Standards
New Source Performance
Standards
FCC - Fluid Catalytic
Cracking
Inspection Procedures
C03ATI Field/Group
1308/0701
1407
1407
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF
61
Release Unlimited
20 SECURITY CLASS (Tllis pay-.-)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
------- |