&EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-79-008
March 1979
Air
A Review of Standards
of Performance for New
Stationary Sources -
Petroleum Refineries
.
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EPA-450/3-79-008
A Review of Standards
of Performance for New
Stationary Sources -
Petroleum Refineries
by
Kris Barrett and Alan Goldfarb
Metrek Division of the MITRE Corporation
1820 Dolley Madison Boulevard
McLean, Virginia 22102
Contract No. 68-02-2526
EPA Project Officer: Thomas Bibb
Emission Standards and Engineering Division
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1979
-------
This report has been reviewed by the Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, Office of Air, Noise
and Radiation, Environmental Protection Agency, and approved for publica-
tion . Mention of company or product names does not constitute endorsement
by EPA. Copies are available free of charge to Federal employees, current
contractors and grantees, and non-profit organizations - as supplies permit
from the Library Services Office, MD-35, Environmental Protection Agency,
Research Triangle Park, NC 27711; or may be obtained, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
VA 22161.
Publication No. EPA-450/3-79-008
11
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ABSTRACT
This report reviews the current Standards of Performance for New
Stationary Sources: Subpart J - Petroleum Refineries. It includes a
summary of the current standards, the status of current applicable
control technology, and the ability of refineries to meet the current
standards. Compliance test results are analyzed and recommendations
are made for possible modifications and additions to the standard,
including future studies needed for unresolved issues.
iii
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ACKNOWLEDGEMENT
The authors wish to acknowledge those who gave so generously of
their time and patience during the preparation of this report* The
many helpful suggestions and technical assistance of Mr. William
Lowenbach and Ms. Sally Price of The MITRE Corporation are greatly
appreciated.
iv
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TABLE OF CONTENTS
Page
LIST OF ILLUSTRATIONS vii
LIST OF TABLES viii
1.0 EXECUTIVE SUMMARY 1-1
1.1 Particulate Matter 1-1
1.2 Carbon Monoxide 1-3
1.3 Sulfur Dioxide 1-4
1.4 Hydrocarbons 1-5
2.0 INTRODUCTION 2-1
2.1 Purpose and Scope 2-1
2.2 Background Information 2-2
2.2.1 Catalytic Cracking Units 2-5
2.2.2 Description of Fuel Gas Combustion Device 2-9
3.0 CURRENT STANDARDS FOR PETROLEUM REFINERIES 3-1
3.1 Facilities Affected 3-1
3.2 Pollutants Controlled 3-2
3.2.1 Standard for Particulate Matter 3-2
3.2.2 Standard for Carbon Monoxide 3-2
3.2.3 Standard for Sulfur Dioxide 3-3
3.3 Monitoring and Reporting Requirements 3-3
4.0 STATUS OF CONTROL TECHNOLOGY 4-1
4.1 Scope of Industrial Operations 4-1
4.1.1 Distribution of Sources 4-1
4.1.2 Industry Growth Pattern 4-1
4.2 Applicable Control Technology to Meet Standards 4-3
4.2.1 Fluid Catalytic Cracker 4-7
4.2.2 Fuel Gas Combustion Device 4-21
4.3 Achievable Emission Levels 4-23
4.3.1 Fluid Catalytic Cracker 4-23
4.3.2 Fuel Gas Combustion Device 4-25
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TABLE OF CONTENTS (Concluded)
Page
4.4 Special Problems Using Control Technologies 4-25
4.4.1 Wet Scrubbers 4-25
4.4.2 Condensable Participates 4-28
4.5 Energy Needs and Environmental Effects 4-30
4.5.1 Expander Technology 4-30
4.5.2 Carbon Monoxide Oxidation Catalysts 4-32
4.5.3 Sulfur Dioxide Catalysts 4-33
5.0 INDICATIONS FROM TEST RESULTS 5-1
5.1 Test Coverage in Regions 5-1
5.2 Analysis of Test Results 5-5
6.0 ANALYSIS OF POSSIBLE REVISIONS TO THE STANDARD 6-1
6.1 Particulate Matter 6-1
6.2 Carbon Monoxide 6-4
6.3 Sulfur Dioxide 6-5
6.4 Hydrocarbons 6-7
7.0 CONCLUSIONS 7-1
7.1 Particulate Matter 7-1
7.2 Carbon Monoxide 7-1
7.3 Sulfur Dioxide 7-1
7.4 Hydrocarbons 7-2
8.0 RECOMMENDATIONS 8-1
8.1 Particulate Matter 8-1
8.2 Carbon Monoxide 8-1
8.3 Sulfur Dioxide 8-1
8.4 Hydrocarbons 8-2
9.0 REFERENCES 9-1
APPENDIX A REPORTED FCC UNITS AT PETROLEUM REFINERIES A-l
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LIST OF ILLUSTRATIONS
Figure Number Page
2-1 Processing Plan for Complete Modern
Refinery 2-3
2-2 Modern Fluid Catalytic Cracking Unit with
Controls and Energy Recovery 2-8
4-1 Effect of Particle Size on Collection
Efficiency of an Electrostatic Precipitator 4-9
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LIST OF TABLES
Table Number Page
2-1 Potential Sources of Atmospheric Emissions
Within Refineries 2-6
2-2 Nationwide Fluidized Bed Catalytic Cracker
Regenerator Emissions, Uncontrolled 2-10
4-1 Geographic Distribution of Fluid Catalytic
Cracker Units 4-2
4-2 Reported Predictions of Refinery Growth
1977 - 1980 4-4
4-3 Approximate Characteristics of Dust and Mist
Collection Equipment 4-15
4-4 Particle Collection Efficiency 4-16
4-5 Effects of Variables on Dust Collection
Equipment 4-18
4-6 Use of Carbon Monoxide Oxidation Catalyst 4-20
4-7 Compliance Test Data for Participate Matter 4-24
4-8 Compliance Test Data for Carbon Monoxide 4-26
4-9 Compliance Test Data for Sulfur Dioxide 4-27
4-10 Condensable Participates from FCC Unit
Regenerators 4-29
5-1 NSPS Compliance Test Data - Petroleum
Refineries 5-2
5-2 Geographic Distribution of Possible NSPS
Affected Facilities 5-3
6-1 Hazardous Hydrocarbons Emitted from FCC
Unit Regenerators 6-8
viii
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1.0 EXECUTIVE SUMMARY
New Source Performance Standards (NSPS) for petroleum refineries
were promulgated by the Environmental Protection Agency (EPA) on
March 8, 1974. These standards regulate the emission of particulate
matter and carbon monoxide, and the opacity of flue gases from fluid
catalytic cracking (FCC) unit catalyst regenerators and FCC unit
regenerator incinerator-waste heat boilers. They also regulate the
emission of sulfur dioxide from fuel gas combustion devices. These
regulations apply to any affected facility which commenced construc-
tion or modification after June 11, 1973.
The objective of this report is to review the New Source Perfor-
mance Standard (NSPS) for petroleum refineries in terms of the impact
of new developments in control technology, industry operating condi-
tions, process changes, and other issues that have evolved since the
standards were promulgated. Possible revisions to the standard,
based on NSPS compliance test results, are also analyzed. The
following paragraphs summarize the results and conclusions of the
analysis, as well as recommendations for future action.*
1.1 Particulate Matter
The current NSPS for particulate matter emissions were based
on electrostatic precipitator technology. The use of multi-stage
cyclones in conjunction with an electrostatic precipitator is still
considered the best demonstrated control technology. A number of
*This report reflects information and data available in June 1978.
1-1
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refineries are using high-efficiency separators to reduce particulate
matter loading prior to energy recovery in an expander turbine. This
is then followed by a preclpitator. Bag filters and venturi scrubbers
can also be used on a FCC unit regenerator exhaust gas stream.
Only one NSPS compliance test was available for analysis during
this task. The three test runs had a range of emission values from
0.76 to 1.35 kg particulate matter/kg coke burn-off with an average
of 1.01 kg/kg coke burn-off (NSPS - 1.0 kg/kg). Based on this one
compliance test and previous data from tests performed to support the
standard, no change to the present particulate matter standard is
recommended.
Technological advances in catalysts, temperature of regeneration
and catalyst-to-feed ratios have had the effect of reducing particu-
late matter mass emission rates. However, the allowable emission is
based on coke burn-off in the regenerator, not mass rate. Therefore,
the new technologies which reduce coke formation and therefore coke
burn-off, also reduce the allowable emissions in total kg of particu-
late matter emitted per hour. This has required the industry to
Increase control of the emission of entrained catalyst.
Technological advances in controls are limited to new, high-
efficiency third-stage cyclones or separators. Use of a third-stage
separator may control the effect of increased emissions with time due
to erosion of the regenerator internal cyclones. Use of a separator
to control turbine blade erosion is mandatory if energy recovery from
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an expander turbine is incorporated in the FCC unit regenerator flue
gas stream.
The available compliance test report included an appendix
describing a problem with EPA Reference Method 5 for measuring
particulate matter due to condensable sulfates. Because this method
is the key to defining particulate matter and it determines the
compliance/noncompliance of an affected facility, it is recommended
that Reference Method 5, as it applies to catalyst regenerator
emissions, be reevaluated.
An additional recommendation for the particulate matter stan-
dard is to require that the opacity be measured at the same time
the mass emission is measured. This requirement will provide much
needed data and will ensure that the opacity standard is consistent
with the mass emission limit.
1.2 Carbon Monoxide
The best demonstrated control technology for carbon monoxide
(CO) is considered to be the carbon monoxide incinerator-waste heat
boiler. No compliance test data were available for carbon monoxide
emissions from FCC unit regenerators using controls other than carbon
monoxide boilers. These incinerator waste heat boilers are capable
of reducing the emission of CO to 0 to 14 ppm, far below the current
standard of 500 ppm. The standard was established at 500 ppm to
permit control of CO emissions by regenerator in-situ oxidation.
There is no data to substantiate the level of CO emissions from
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regenerators using in-situ oxidation other than journal statements of
"less than 500 ppm." Approximately 20 percent of the U.S. regener-
ators are operating with CO oxidation promoters (Wallendorf, 1978).
It is recommended that data be collected to ascertain the capabiliy
of these systems to reduce CO and the level of reduction possible,
then reevaluate the CO standard based on this new data.
1.3 Sulfur Dioxide
Sulfur dioxide emissions from fuel gas combustion devices can be
controlled by reducing the hydrogen sulfide content of the fuel gas
or by flue gas desulfurization (FGD). The standard was written to
limit the I^S content of fuel gas, although the owner/operator has
the option of using FGD. The available compliance test data Indicate
that: (1) all NSPS affected facilities identified chose to limit the
H2& content of fuel gas Instead of using FGD, and (2) the technol-
ogy for reducing I^S concentrations substantially below the present
NSPS limit is being used. There is no data to show the effect of the
increased sulfur content of feedstock expected with increased Imports.
This relationship should be considered before a decision is made on
whether the standard can be changed to reduce the allowable H2S
content of fuel gas.
Another recommendation Is to change the definition of a fuel gas
combustion device so that a regenerator incinerator-waste heat boiler
is no longer excluded from compliance with the SOX standard. The
original rationale for excluding the boiler from the standard, even
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when using fuel gas as an auxiliary fuel, is not known. A third
recommendation concerns the monitoring of hydrogen sulfide in fuel
gas. The lack of a continuous monitoring method for ^2^ ^as been
reported by EPA Regional personnel as a weakness in the current NSPS
(Watson et al., 1978).
There is currently no NSPS for sulfur dioxide emissions from
the FCC unit regenerator/regenerator incinerator-waste heat boiler.
Arthur D. Little, Inc. (1976) has estimated that a SOX flue gas
control level of 300 ppm or 500 ppm will reduce emissions by 85,000
tons/year and 49,000 tons/year respectively by 1985. This is a
reduction from their estimate of 480,000 tons/year of SOX emitted
by FCC units in 1985. It is recommended that further analysis be
done to determine if a suitable standard can be developed and that
this standard include an additional sulfur dioxide allowance for
regenerator incinerator-waste heat boilers using auxiliary liquid
or solid fossil fuels.
1.4 Hydrocarbons
The emission of hydrocarbons of concern to public health offi-
cials from uncontrolled FCC unit regenerators has been established by
Radian Corporation (Bombaugh et al., 1976). The actual emissions
released under differing operating conditions or control equipment
have not been determined. Arthur D. Little, Inc. (1976) has stated
that the emission of hydrocarbons is negligible when using either &
CO boiler or high temperature regeneration (HTR). New CO oxidation
1-5
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promoters can reduce the temperature at which effective HTR can be
carried out and the emissions from a regenerator under these condi-
tions are unknown. It is recommended that data he collected to
ascertain the need for a MSPS for hydrocarbon emissions.
1-6
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2.0 INTRODUCTION
2.1 Purpose and Scope
On March 8, 1974, the Environmental Protection Agency promulgated
New Source Performance Standards (NSPS) for Petroleum Refineries (39
FR 9315). Revisions were made on October 6, 1975 (40 FR 46250) and
again on July 25, 1977 (42 FR 37937). These standards establish
emissions limits and require emission testing; monitoring; and
reporting for particulate matter, opacity, and carbon monoxide from
fluid catalytic cracking unit regenerators, and sulfur dioxide from
fuel gas combustion devices.
The Clean Air Act Amendments of 1977 require that the Adminis-
trator of the EPA review, and if appropriate, revise established
standards of performance for new stationary sources at least every
four years (Section 111(b)(1)(B)). This report includes reviews of
the current standards, the status of current applicable control
technology, and the ability of petroleum refineries to meet the cur-
rent standards. The compliance test results, information retrieved
from the literature, and discussions with industry representatives
form the basis for analyses of the current standards to determine if
they are sufficient, too stringent, or not stringent enough. The
problems associated with the monitoring requirements of the standards
were analyzed, and recommendations are made concerning specific
changes or studies to be conducted. Also discussed are problems at
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petroleum refineries that relate directly to the environmental
pollution load emitted and that may affect present or future NSPS.
2.2 Background Information
A petroleum refinery transforms crude oil into a variety of
useful products. The petroleum refining industry produces more than
2500 products that can be categorized into the following classes:
fuel gas, gasoline, kerosine, fuel oil, lubricating oil, grease, wax,
asphalt, coke, chemicals, and solvents. There is no "typical"
refinery, since the number of products and the product mix varies
widely within a refinery as well as between refineries. The manu-
facturing processes also vary depending on refinery age, type of
technology, capacity, location, and type of crude processed.
Petroleum refinery operations involve physical separation of
components of the crude oil (e.g., crude distillation) and chemical
conversion processes which transform some of the less useful compon-
ents of the oil into more useful products (e.g., cracking of high
molecular weight oils into lower molecular weight products such as
gasoline).
The processing sequence of a modern refinery is illustrated
in Figure 2-1. The crude oil is heated and charged to an atmospheric
distillation tower where it is separated Into several light, inter-
mediate, and heavy fractions. The bottoms from the tower are sent
to a vacuum distillation unit for further separation. The bottoms
from the vacuum still are thermally cracked in a coker to produce a
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DRY GAS
NI
STRAIGHT RUN GASOLINE
LIGHT HYDROCRACKED GASOLINE
MIDDLE
DISTILLATES
HEAVY
HTDBOCRACKED
GASOLINE
HEAVY GAS OIL
HYDROGEN SULFIDE
CRACKED GAS
CATALYTIC
GASOLINE
CATALYTIC
CRACKING
UNIT
LIGHT FUEL OIL
REDUCED
CRUDE
OIL _
COKBR GASOLINE
LUBE DISTILLATES
CRUDE OIL
SEPARATION
UNIT
*-FUEL GAS
*-LP GAS
MOTOR
GASOLINE
AVIATION
GASOLINE
OLEFINS TO
CHEMICAL
*-KEROSENE
*• LIGHT FUEL
OIL
DIESEL
FUEL
*-SULFUR
LUBES
WAXES
GREASES
HEAVY FUEL
OIL
*-ASPHALT
•-COKE
Source: Laster, 1973.
FIGURE 2-1
PROCESSING PLAN FOR COMPLETE MODERN REFINERY
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wet gas, coker gasoline, and coke. A portion of the bottoms from the
vacuum still may be processed into asphalt. Gas oils from the
atmospheric and vacuum distillation units are used as feedstocks for
the catalytic cracking and hydrocracking units. These units convert
the gas oils to gasoline and distillate fuel. The gasoline from
these units is fed to a catalytic reformer to improve the octane
number and then blended with other refinery streams to make gasolines
for marketing.
The wet gas streams from the distillation, coker, and cracking
units are combined and fractionated into fuel gas, liquified petroleum
gas, and unsaturated and saturated branched chain and straight chain,
light hydrocarbons containing from 3 to 5 carbon atoms. The fuel
gas is used as fuel in the refinery furnaces. The straight chain
saturated hydrocarbons are blended into gasoline. The unsaturated
hydrocarbons and the branched chain hydrocarbons, primarily isobutane,
are processed in an alkylatlon unit. In the alkylation unit the
unsaturated hydrocarbons react with isobutane to form isoparaffins
which are blended into gasoline to increase the octane.
The middle distillates from the crude unit, the coker unit,
and the cracking unit are blended into diesel and jet fuels and
furnace oil. Heavy vacuum gas oils and reduced crude oil from some
crudes can be processed into lubricating oils, waxes, and grease.
Only a few process units emit pollutants directly to the
atmosphere—the catalytic cracking unit, the coker, and the process
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heaters. Pump seals, valves, relief vents, leaks, and sampling
operations are sources of fugitive emissions. Air pollutants
that may be released into the environment from a refinery, and some
of the sources of these emissions, are summarized in Table 2-1.
2.2.1 Catalytic Cracking Units
Catalytic cracking is a process for converting heavy oils into
more valuable gasoline and lighter products. Almost 5 million
barrels of oil are processed daily in catalytic cracking units in the
U.S. Originally, cracking was accomplished thermally, but catalytic
processes have almost completely replaced thermal cracking because of
the improved yield and quality of the product from the catalytic
process. Three types of catalytic cracking processes have been used:
the fixed bed (Houdry process), the moving bed (Thermofor process),
and the fluidized bed.
The fixed bed process is considered obsolete, and only three
refineries still use this process. The moving bed process is being
phased out and only 16 refineries use this method.
There are 122 fluidized bed catalytic cracking units currently
operating with the capability of processing 4.7 million barrels of
oil daily. During the next 2 years an additional 16 fluid bed
catalytic crackers are scheduled to be placed in operation. The
combined capacity of these units is approximately 321,000 barrels of
oil per day. However, this figure does not represent increased
capacity, since some units may replace existing older units. Also,
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TABLE 2-1
POTENTIAL SOURCES OF ATMOSPHERIC EMISSIONS WITHIN REFINERIES
Type of Emission
Source
Participates
Sulfur Oxides
Nitrogen Oxides
Hydrocarbons
Carbon Monoxide
Odors
Catalytic Cracker, Fluid Coking,
Catalyst Regeneration, Process
Heaters, Boilers, Decoking Opera-
tions, Incinerators
Sulfur Recovery Unit, Catalytic
Cracking, Process Heaters, Boilers,
Decoking Operations, Unit Regenera-
tions, Treating Units, Flares
Process Heaters, Boilers, Catalyst
Regeneration, Flares
Storage Tanks, Loading Operations,
Water Treating, Catalyst Regenera-
tion, Barometric Condensers, Pro-
cess Heaters, Boilers, Pumps,
Valves, Blind Changing, Cooling
Towers, Vacuum Jets
Catalyst Regeneration, Decoking,
Compressor Engines, Incinerators
Treating Units, Drains, Tank Vents,
Barometric Condensers, Sumps, Oil-
Water Separators
Source: Dickerman, et al., 1977.
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although some units represent additions to refinery capacity, this
figure represents the total capacity of the refinery after the
addition.
The fluidized catalytic cracking (FCC) process uses a catalyst
in the form of fine particles that are fluidized with a vapor. The
fluidized catalyst is continuously circulated between a reaction zone
and a regeneration zone. Two types of FCC units are commonly used.
In the "side-by-side" type, the reaction and regeneration chambers
are separate vessels next to each other. In the stacked type, the
reactor is mounted on top of the regenerator and the two vessels
appear as one when viewed externally. Other variations in FCC design
and operation relate to the type of catalyst employed and the design
of the catalyst transfer line between the regenerator and the reactor.
However, the operating principles of the various FCC reactors are
essentially the same.
A schematic diagram of a fluid catalytic cracking unit is
shown in Figure 2-2. In operation, the gas oil is fed to the bottom
of the riser pipe where it joins the hot, regenerated catalyst. The
fuel is vaporized and flows upward along with the catalyst particles.
The cracking reaction takes place in the riser. Because the reaction
is endothermic, cooling of the reacting mixture occurs as it rises
into the reactor. The product gases exit through the top of the
separator and the catalyst particles drop into the stripper section
where they are blown with steam to strip hydrocarbons that are
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•*• PRODUCT
CARBON
MONOXIDE
BOILER
•*-STEAM
ho
do
ELECTROSTATIC
PRECIPITATOR
TO
~~^ STACK
DUST
STEAM
TURBINE
FIGURE 2-2
MODERN FLUID CATALYTIC CRACKING UNIT
WITH CONTROLS AND ENERGY RECOVERY
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entrained on the catalyst. During the cracking process, the catalyst
loses its activity due to the formation of coke deposits. In order
to restore the catalytic activity, the spent catalyst is passed into
a regenerator where the coke is burned off in a controlled combustion
process with preheated air. The hot regenerated catalyst then flows
to the bottom of the riser to mix with incoming gas oil feed and the
cycle is repeated.
The products of combustion are vented through the top of the
regenerator. The regenerator vent gases contain particulate matter
from entrained catalyst, sulfur oxides from sulfur retained in the
coke, carbon monoxide from incomplete combustion of coke, hydrocarbons,
nitrogen oxides, aldehydes, and ammonia. Table 2-2 lists emission
factors for each of these pollutants discharged from an uncontrolled
fluid bed catalyst regenerator along with the potential nationwide
emissions based on the current capacity of fluidized bed catalytic
reactors in the U.S.
2.2.2 Description of Fuel Gas Combustion Device
Fuel gas is produced in a refinery from a wide variety of pro-
cess operations including: crude oil separation, catalytic cracking,
hydrocracking, coking, and reforming. The gas is treated and then
used in process heaters, boilers, flares, and various other places in
the refinery. A fuel gas combustion device is quite literally any
equipment in a petroleum refinery that is used to burn fuel gas.
Fluid coking units, fluid catalytic cracking unit incinerator-waste
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TABLE 2-2
NATIONWIDE PLUIDIZED BED CATALYTIC CRACKER REGENERATOR EMISSIONS* UNCONTROLLED
Pollutant
Emission Factor
(kg/m3 fresh fuel)a
Estimated
Maximum
Dally Emission (kg)b
Estimated
Annual
Emission (kg)b
Partlculatee
Sulfur Oxides
Carbon Monoxides
Hydrocarbons
Nitrogen Oxides
Aldehydes
Ammonia
0.267 - 0.976
0.898 - 1.505
39.2
0.630
0.107 - 0.416
0.054
0.155
2.1 x 105 - 7.7 x 105
7.1 x 105 - 1.2 x 106
3.1 x
5.0 x 10J
8.4 x 104 - 3.3 x 105
4.3 x 10"
1.2 x 10"
6.9 x 107 - 2.5 x 108
2.3 x 108 - 3.9 x 108
1.0 x 10
10
1.6 x 108
2.8 x 107 - 1.1 x 108
1.4 x 107
4.0 x 10'
Vs. EPA, 1973.
Calculated from capacity data reported In Cantrell, 1978.
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heat boilers, and facilities that burn fuel gas to produce sulfur or
sulfuric acid are excluded from the NSFS definition of a fuel gas
combustion device. Flue gases from these sources are vented to the
atmosphere with or without heat recovery and/or treatment.
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3.0 CURRENT STANDARDS FOR PETROLEUM REFINERIES
3.1 Facilities Affected
The NSPS for petroleum refineries are applicable to fluid cata-
lytic cracking unit catalyst regenerators, fluid catalytic cracking
unit regenerator incinerator-waste heat boilers, and fuel gas com-
bustion devices that commenced construction or modification after
June 11, 1973.
The following terms are pertinent to the determination of the
applicability of the NSPS to a facility.
• A petroleum refinery is any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, or other products through distillation of petro-
leum or through redistillation, cracking or reforming of
unfinished petroleum derivatives.
• Construction is the fabrication, erection, or installation
of an affected facility, or any apparatus to which a standard
is applicable. This includes construction that is completed
within an organization as well as the more common situation
in which the facility is designed and constructed by a
contractor.
• A modification is any physical change in, or change in the
method of operation of, an existing facility which increases
the amount of any air pollutant (to which a standard applies)
emitted into the atmosphere by that facility or which results
in the emission of any air pollutant (to which a standard
applies) not previously emitted into the atmosphere. However,
increases in production rates up to design capacity, reloca-
tion or change in ownership of an existing facility, and fuel
switches if the equipment was originally designed to accom-
modate such fuels, are not considered to be modifications.
• Reconstruction is the replacement of components of a facility
to such an extent that the capital costs of the new components
is greater than 50 percent of the capital costs of a compara-
ble entirely new facility. After replacement, the facility
must be technologically and economically capable of complying
with the NSPS. If a facility meets these criteria, it is
designated an affected facility, regardless of any changes in
the rate of emissions.
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3.2 Pollutants Controlled
The NSPS for petroleum refineries regulate the emission of:
• particulate matter from FCC unit catalyst regenerators or FCC
unit regenerator incinerator-waste heat boilers,
• carbon monoxide from FCC unit catalyst regenerators, and
• sulfur dioxide from fuel gas combustion devices.
3.2.1 Standard for Particulate Matter
The standard for particulate matter has been set at 1.0 kg/1,000
kg (1.0 lb/1,000 Ib) of coke burn-off in the catalyst regenerator.
In addition, no gases are to be emitted that exhibit greater than
30 percent opacity except for one six-minute average opacity reading
in any one—hour period.
In those instances in which auxiliary liquid or solid fossil
fuels are burned in the FCC unit regenerator incinerator-waste heat
boiler, the incremental rate of particulate matter emissions may
exceed the above, but not exceed 0.18 g/million cal (0.10 Ib/million
Btu) of heat input attributable to the auxiliary liquid or solid
fuel.
3.2.2 Standard for Carbon Monoxide
The standard for carbon monoxide restricts emissions to no
greater than 0.050 percent by volume of carbon monoxide in gases
discharged from a FCC unit catalyst regenerator.
3-2
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3.2.3 Standard for Sulfur Dioxide
The standard for sulfur dioxide applies to any fuel gas com-
bustion device. These devices are defined as any equipment used to
burn fuel gas, such as process heaters, boilers, and flares.
Fluid coking units, FCC unit incinerator-waste heat boilers, and
facilities in which gases are burned to produce either sulfur or
sulfuric acid are not included.
The standard prohibits the burning of fuel gas containing in
excess of 230 mg I^S/dscm (0.10 gr/dscf) in any fuel gas combustion
device, except as discussed below. The combustion of process upset
gas in a flare, and process gas or fuel gas released to a flare from
relief valve leakage is exempt from this standard.
The alternative to the 230 mg ^S/dscm fuel gas standard is
that an owner or operator may elect to treat the gases resulting from
the combustion of fuel gas so as to limit the release of SC>2 to the
atmosphere. The EPA Administrator must be satisfied that treating
of the combustion gases controls SO2 emissions as effectively as
compliance with the li^S standard.
3.3 Monitoring and Reporting Requirements
Continuous monitoring is required for opacity, carbon monoxide,
and sulfur dioxide. The regulations require owners or operators to
install, calibrate, maintain, and operate a continuous monitoring
system for the opacity of emissions from FCC unit catalyst regener-
ators. The opacity monitoring system is to be spanned at 60, 70, or
80 percent opacity.
3-3
-------
The continuous monitoring of carbon monoxide emissions from FCC
unit catalyst regenerators will be required on all NSPS affected
facilities as soon as instrument specifications are promulgated by
EPA. This will require a retrofit of instruments on affected facili-
ties already in place.
A continuous monitoring system is required for the measurement
of sulfur dioxide in the gases discharged to the atmosphere from the
combustion of fuel gases. Calibration checks are made using SO2 as
the calibration gas. The span is set at 100 ppm. Reference Method 6
is used for conducting monitoring system performance evaluations.
This continuous monitoring system is not required where a continuous
monitoring system for the measurement of hydrogen sulfide is installed.
The EPA has not yet developed performance specifications for hydrogen
sulfide continous monitoring system. Therefore, owners and operators
electing to monitor R^S are effectively exempt from the SO2 monitoring
requirements (40 FR 46250) until EPA establishes Instrument perform-
ance specifications for an I^S monitor.
The average coke burn-off rate (thousands of kilograms/hour)
and hours of operation for any FCC unit catalyst regenerator are
required to be recorded daily. Computation of the coke burn-off
rate is done using the formula in 40 CFR 60.106(4).
Owners and operators of FCC unit catalyst regenerators who use
an incinerator-waste heat boiler to burn the regenerator exhaust
gases are required to record the dally rate of combustion of liquid
3-4
-------
or solid fossil fuels (liters/hour or kilograms/hour) and the hours
of operation during which these fuels are burned in the boiler.
The reports required for NSPS affected facilities are submitted
to the EPA Administrator for every calendar quarter within 30 days
of the end of the quarter.
The following reports of excess emissions are required:
• opacity - all one-hour periods that contain two or more six-
minute periods during which the average opacity exceeds 30
percent as measured by the continuous monitoring system, and
• sulfur dioxide - any six-hour period during which the average
(arithmetic average of six contiguous one-hour periods)
emissions of SO2 exceed the standard as measured by the
continuous monitoring system.
3-5
-------
4.0 STATUS OF CONTROL TECHNOLOGY
4.1 Scope of Industrial Operations
4.1.1 Distribution of Sources
There are 285 operating petroleum refineries in the U.S. with a
total capacity of nearly 18 million barrels of crude oil per stream
day. The largest number of refineries are located in EPA Region VI
(37 percent of total refineries and 45 percent of total capacity)*
Texas, California, and Louisiana are the three largest refinery
states with 19, 14, and 8 percent of the refineries and 27, 14, and
12 percent of the capacity, respectively.
The fluid catalytic cracker is an essential part of the modern
refinery. Nearly one-half of all refineries have FCC units as part
of their process. Table 4-1 shows the distribution of these fluid
catalytic cracking units by EPA Region. EPA Regions V and VI con-
tain 53 percent of the FCC equipped refineries and 62 percent of the
refinery FCC unit capacity. Texas, Louisiana, and California are the
states with the largest FCC unit capacity (Cantrell, 1978).
4.1.2 Industry Growth Pattern
The growth of the petroleum refinery industry has been affected
by government regulation of fuel prices and the oil embargo. According
to data presented in the Oil and Gas Journal (Cantrell, 1978), 27 new
refineries have been built between 1975 and 1978. Thirteen of these
refineries were built in EPA Region VI. Although the actual number
of new FCC units built in the same period is unknown, capacity was
4-1
-------
TABLE 4-1
GEOGRAPHIC DISTRIBUTION OF FLUID CATALYTIC CRACKER UNITS
Fluid Catalytic Cracker Units
Region
I
11 III
IV
V
VI
VII
VIII
IX
X
Total
Number of
Refineries
1978
1
7
16
20
36
100
13
35
44
13
285
75-78
_
(Db
5
-
13
-
3
5
1
26
Number of
Refineries
With FCCU
1978
—
3
6
3
19
45
16
15
13
2
122
Capacity8
1978
_
197
309
120
771
2081
373
175
509
66
4600
75-78
-
10
15
-
86
147
(10)b
5
111
3
368
Percent of
Total
Number
_
2
5
2
16
37
13
12
11
2
100
Capacity
-
4
7
3
17
45
8
4
11
1
100
Sources: Cantrell, 1975; 1978.
a Capacity in 10^ barrels per stream day*
b Reduction in number of refineries or capacity*
-------
increased by 368,000 barrels per stream day. A distribution of this
growth in FCC unit capacity is shown in Table 4-1.
The data from the Oil and Gas Journal (Cantrell, 1978) on
increased capacity of FCC units show that 50 refineries have built
new FCC units or expanded FCC unit capacity during the period 1975-
1978. It is not within the scope of this report to make a deter-
mination on how many of these units are affected facilities and sub-
ject to the NSPS. During interviews with each EPA Regional office,
only two FCC units were reported as subject to NSPS. (Data from EPA
Region IX were not received.)
In Table 4-2, data from Hydrocarbon Processing (1978) are pre-
sented to show a planned growth in seventeen FCC units during the
period 1978-1980. Of these, six projects are under construction and
eleven are in an engineering phase. Four of the units under con-
struction are indicated as new units.
4.2 Applicable Control Technology To Meet Standards
The NSPS are based on best demonstrated control technology which
is reasonable from an economic viewpoint. For this reason, a review
of available control technologies used by petroleum refineries is very
important. In this section, the control technologies currently used
to meet the NSPS are reviewed. The technologies are discussed in the
order of their prevalence in the industry.
4-3
-------
TABLE 4-2
REPORTED PREDICTIONS OF REFINERY GROWTH 1977-1980s
EPA Region
Region I
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Region II
New Jersey
New York
Region III
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
Region IV
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
Company/City
None indicated
ii
it
n
ft
FCC
CO
Boiler
Refinery
Mobil, Paulsboro
None indicated
None indicated
Crown Central,
Baltimore
Stewart, Piney
Point
Sun, Marcus Hook
Hampton Roads
Energy, Portsmouth
None indicated
None Indicated
N
N
It
It
n
Delta, Memphis
30 Mb/d,U80
Re,E
200 Mb/d,E
100 Mb/d,P
184.1 Mb/d,
E80
25 Mb/d,E79
Phase: CKJompleted since 9/1/77, EHBngineerlng, P-Planning, Re-Revamp,
U^Jnder construction
Year: (77, 78, 79, 80)
* Compiled as of 1/1/78 and reported In thousand barrels/day (Mb/d)
Source: Hydrocarbon Processing, 1978.
4-4
-------
TABLE 4-2 (Continued)
REPORTED PREDICTIONS OF REFINERY GROWTH 1977-1980"
EPA Region
Region V
Illinois
Indiana
Iowa
Michigan
Minnesota
Wisconsin
Company/City
None indicated
Energy Coop,
East Chicago
None indicated
Total Petroleum,
Alma
None indicated
FCC
ExpnnHion.E
By A Mb/d,C77
CO
Boiler Refinery
Region VI
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
None indicated
Continental, Lake
Charles
Good Hope, Good Hope
Gulf, Alliance
Marathon, Garyvllle
Murphy, Meraux
Shepherd, Jennings
T&S, Mermentau
Plateau, Bloomfleld
Continental, Ponca
City
Diamond Chamrock,
Dumas
La Gloria, Tyler
Phillips, Sweeny
Sun, Corpus Christ!
Texas City, Texas
City
Tipperary, Ingleside
Unl, Rockport
Union, Nederland
30.8 Mb/d,E79
Ex 55 Mb/d,U
By 11 Mb/d,E79
75 Mb/d,E79
25 Mb/d,E79
5 Mb/d,U77
32.5 Mb/d,U79
Re,E79
Re,C
To 190 Mb/d,E79
To 25 Mb/d,C
By 8 Mb/d,E78
Re.C
Exp.,E79
10 Mb/d,U
10 Mb/d,E78
5 Mb/d,C
By 15 Mb/d,E78
10 Mb/d,E78
Phase: C-Completed since 9/1/77, E-Englneerlng, P-Planning, Re-Revamp,
U=Under construction
Year: (77, 78, 79, 80)
a Compiled as of 1/1/78 and reported in thousand barrels/day (Mb/d)
Source: Hydrocarbon Processing, 1978.
4-5
-------
TABLE 4-2 (Concluded)
REPORTED PREDICTIONS OF REFINERY GROWTH 1977-1980*
EPA Region
Region VII
Kansas
Missouri
Nebraska
Ohio
Company/City
CRA, Phillipsburg
None indicated
it
ti
FCC
To 9 Mb/d,D79
Co.
Boiler
Refinery
Region VIII
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Region IX
Arizona
California
Hawaii
Nevada
Region X
Alaska
Idaho
Oregon
Washington
Gary Western, Fruita
None indicated
Amoco, Mandan
None indicated
it
Little America,
Casper
Mountaineer, La Barge
None indicated
Lion, Bakersfield
Hawaiian Independent,
Barbers Point
None indicated
None indicated
n
Cascade Energy,
Columbia
United Independent,
Seattle
17 Mb/d,E78
To 10 Mb/d,D78
U
By 4.2 Mb/d,P80
E78
By 7.5 Mb/d, E78
30 Mb/d,P
Re,E
Phase: Completed since 9/1/77, B-Bngineering, P-Planning, Re-Revamp,
D-Cnder construction
Year: (77, 78, 79, 80)
a Compiled as of 1/1/78 and reported in thousand barrels/day (Mb/d)
Source: Hydrocarbon Processing, 1978.
4-6
-------
4.2.1 Fluid Catalytic Cracker
The fluid catalytic cracker regenerator and regenerator waste
heat boiler have NSPS for opacity, participate matter, and carbon
monoxide* Opacity and particulate matter will be discussed together
since the controls are the same. Control of carbon monoxide will
be discussed separately.
4.2.1.1 Particulate Matter Control. The present NSPS for opac-
ity and particulate matter was based on the use of electrostatic
precipitators as the best demonstrated control technology, (EPA, 1973a)
Even with new innovations, electrostatic precipitators remain the
best demonstrated control technology for particulate matter.
Electrostatic precipitators are fine particle agglomerators
combined with a gravity settling chamber. On FCC unit regenerators,
the precipitator is generally a horizontally mounted steel box con-
taining positive electrodes and grounded plates. A corona discharge
at the electrode ionizes gases which transfer their charge to the
particles present. The charged particles then drift to the plates or
electrodes where they agglomerate. A rapping mechanism knocks these
larger, agglomerated particles free from the plates and electrodes
and they settle into a gravity settling chamber or hopper from which
they are collected and discarded.
The precipitator efficiency is dependent on: the effective
voltage of the emitting electrodes, the resistivity of the particulate
matter, the particle drift velocity, the collector plate area,
4-7
-------
the plate rapping cycle, and the velocity, residence time and flow
rate of the gas stream. The primary design parameter is the collec-
tor plate area. Operating parameters include electrode voltage
adjustment, plate rapping cycle, velocity distribution, and ammonia
injection to reduce particle resistivity.
Moderate changes in FCC regenerator operation will not affect
the precipitator efficiency. However, changes in catalyst (affecting
particle resistivity), flue gas flow, or particle size can affect
efficiency significantly. Particle size is of particular importance.
As particle size decreases, the efficiency of the precipitator
decreases. Figure 4-1 shows the effect of particle size on the
efficiency of an electrostatic precipitator. The particle drift
velocity (w) is proportional to particle radius. For any given plate
size, efficiency will decrease as particle size decreases. This is
a very important consideration when designing precipitators for FCC
regenerators built or retrofitted with modern, high efficiency cy-
clones and separators that can remove essentially all particulate
matter greater than 15 microns in diameter (Krueding, 1975). Other
parameters affecting particle drift velocity, such as electrode volt-
age and gas velocity are controlled to increase the drift velocity of
the smaller particles. Precipitators for FCC regenerator emissions
are currently designed for gas velocities of 5 to 6 feet per second
and 21 to 27 feet of gas travel for 80 to 95 percent removal effi-
ciency; gas velocities of 3 to 4 feet per second and 30 to 36 feet of
4-8
-------
I
-------
gas travel for 95 to 99 percent removal efficiency; with a distance
of 8 1/2 to 9 3/4 inches between colector plates. Plate rapping is
done approximately every four hours (American Petroleum Institute,
1978).
Cyclone technology is integral to the operation of a FCC unit.
The primary purpose of the cyclone is to return entrained catalyst to
the fluid bed. Multiple cyclones in series are used in the reactor
and the regenerator to reduce the loss of catalyst. These cyclones
are internal to the process unit and, therefore, cannot be repaired
without suspending operations. Deterioration of the cyclones is an
important factor in determining the operating period of an FCC unit
since most units operate for more than two years before shutdown.
A cyclone is a centrifugal dust collection device with a tangen-
tial opening through which a particle carrying gas stream enters a
cylindrical barrel at high speed. The gas stream is given a downward
spiral which forces the particles to the outer wall of the barrel and
downward to a dust hopper. The "cleaned" gas stream then exits
through the center of the top of the barrel while the collected
particles return to the fluid bed through a dipleg. The exhaust gas
stream then passes through a series of one or more additional cyclones
prior to its exit from the regenerator. A thorough description of
cyclone theory is beyond the scope of this report. For more complete
information, refer to the Manual on Disposal of Refinery Wastes,
Volume On Atmospheric Emissions (American Petroleum Institute, 1978).
4-10
-------
There are three important factors that affect emissions from
cyclones (American Petroleum Institute, 1978):
• Catalyst attrition - production of fine particles
• Particle size - particle collection efficiency decreases
exponentially with decreasing particle size*
• Particle loading - particle collection efficiency increases
with increased loading*
Catalyst attrition, defined as the production of fines (particles
less than 44 microns in diameter), results almost exclusively from
impaction of particles in the first stage cyclone rather than from
the breakdown of particles in the catalyst bed. Catalyst attrition
is observed in most installations, and makeup catalyst is required to
maintain the fluid bed in the reactor* Losses occur through the
cyclones which are incapable of collecting the fines. The bed
inventory eventually reaches an equilibrium which can consist of as
much as 30 weight percent less than 40 microns (American Petroleum
Institute, 1978).
The particle collection efficiency of a cyclone is affected by
particle size and gas stream loading. Efficiency decreases exponen-
tially with decreases in particle size until nearly all fines less
than 5 microns pass through uncollected. On the other hand, effi-
ciency increases with gas stream loading. This can amount to as much
as a 60 percent increase in efficiency in a cyclone operating at 35
4-11
-------
percent single particle collection efficiency at no load (< 1 grain
solid/cubic foot gas) when increased to a load of 1,000 grains
solid/cubic foot of gas (American Petroleum Institute, 1978).
Filters have been used for the collection of particulate matter
throughout the industry. There are various types and their use
depends on the particular characteristics of the gas stream to be
cleaned. Filters may be: flexible tubes, bags, or sheets of
material; semirigid supported fabric or mats of fibrous material;
fixed or packed beds of granular particles; and/or fluidized or
moving beds of granules or fibers. Pertinent gas stream character-
istics are particle size, temperature, moisture content, corrosivity,
and flammability. Collectively, these characteristics will determine
the suitability of a filter medium.
The theory of filtration for particulate matter control is that
collection of particles in the micron range will take place by:
• Impaction - of the particle on the filter medium due to
inertial impingement as related to gas stream velocity and
particle size
• Interception - of the particle by the medium due to the
size of the particle with respect to the pore size of the
medium
• Diffusion - of extremely small particles due to Brownian
movement which increases the probability of contact with
the filter medium
• Miscellaneous - mechanisms such as electrostatic forces,
thermal effects on agglomeration and Brownian movement,
and sedimentation of heavy particles in low velocity gas
streams due to gravity.
4-12
-------
The filter medium can be used either under pressure or vacuum In
order to maintain gas flow. As particulate matter Is collected,
filter efficiency Increases because the collected material acts as a
filter medium. As efficiency Increases however, the energy required
to maintain gas flow Increases* A trade-off point Is reached where
cleaning or replacement of the medium Is required.
Cleaning is achieved by gentle shaking or reverse gas flow.
Beds are usually not cleaned but are replaced when the pressure drop
becomes excessive.
Filters are the most efficient particulate matter control device,
especially for very small (sub-micron) particles. The cost of this
efficiency is relatively high however, and few filters are used on
FCC unit regenerators.
Wet Scrubbers can be used to remove gaseous pollutants as well
as particulate matter from flue gases. Although scrubbers are not as
efficient as fabric filters, they can be used for many gaseous
streams that would be unsuitable for fabric filters due to moisture
content, corrosivity, temperature, or flammability. Scrubbers have
disadvantages such as cost and resulting sludge disposal*
The sequence of removing particles from a gas stream by using
scrubber technology can be summarized as:
• Conditioning - the particles so that a high degree of contact
occurs between the particle and liquid
4-13
-------
• Separation - of the particle/liquid from the gaseous stream
using cyclones or impingement baffles
• Removal - of the particle/liquid from the scrubber, usually
as a slurry that can be disposed of as is or dewatered for
recirculatlon to the scrubber.
Comparisons of the various particulate matter control tech-
nologies have been made by the American Petroleum Institute (1978).
In Table 4-3, relative cost, particle size collection, pressure drop,
and energy consumption are compared for the four types of control
equipment previously discussed. Filters and electrostatic preclpi-
tators are capable of removing the smallest particles, but the
precipitators have a substantially lower pressure drop. Single stage
cyclones, spray towers, and electrostatic precipitators have the
lowest power consumption and the lowest relative cost including
auxiliaries.
Data on the particle collection efficiency of the various con-
trols are shown In Table 4-4. Fabric filters and venturi scrubbers
have the highest overall efficiency (American Petroleum Institute,
1978). Many of the controls discussed show a dramatic decrease in
efficiency when collecting smaller sized particles. Table 4-4 shows
the particle collection efficiency of particle? 5, 2, and 1 micron
in diameter. It is apparent from this data that the FCC unit regen-
erator cyclones are incapable of significantly reducing small (<5
micron) particle emissions. The effects of dust, gas stream, and
collector variables on particulate matter control equipment are
4-14
-------
TABLE 4-3
anaaxax CHARACTERISTICS OF DOST ua> MIST COLLECTION EQUIPMENT
Equipment
Cyclones:
Single
Multiple
Electrostatic preclpltators:
One-stage
Two-stage
Filters:
Tabular
Reverse jet
I Envelope
Ul
Scrubbers:
Spray tower
Jet
Venturi
Cyclonic
Inertia!
Packed
Rotating Impeller
Smallest Particle
Relative Collected
Coat (microns)1'
1-2 15
3-6 5
6-30 <0.1
2-6 <0.1
3-20 O.I
7-12 <0.1
3-20 <0.1
1-2 10
4-10 2
4-12 1
3-10 5
4-10 2
3-6 5
4-12 2
•rCttBBUKA UCOp
(Inches of
water)
0.5-3
2-10
0.1-0.5
0.1-0.3
2-6
2-6
2-6
0.1-0.5
-
10-15
2-8
2-15
0.5-10
Power Used
(kilowatt per
1000 cubic feet per
0.1-0.6
0.5-2
0.2-0.6
0.2-0.4
0.5-1.5
0.7-1.5
0.5-1.5
0.1-0.2
2-10
2-10
0.6-2
0.8-8
0.6-2
2-10
Remarks
Staple, Inexpensive, most widely used
Abrasion and plugging problems
High efficiency, heavy duty, expensive
Compact, air conditioning service
High efficiency, temperature and humidity llmiat
More compact, constant flow
Limited capacity, constant flow possible
Low water use
Pressure gain, high-velocity liquid jet
High-velocity gas stream, higher pressure drop
(40 to 70 Inches) will remove submlcron-slced
particles
Modified dry collector
Abrasion problems
Abrasion problem
"includes auxiliaries.
''With 90-95 percent efficiency (weight).
pressure loss, water pumping, and electrical energy.
Source: American Petroleum Institute, 1978.
-------
TABU 4-4
PARTICLE COLLECTION EFFICIENCY
Collection Hithod
Cyclone, eedlua efficiency
Cyclone; high-efficiency
Cyclone, Irritated
Electrostatic preclpltetor
Fabric filter
Spray tower
Scrubber; wet Isplngeeent
Scrubber; eelf- Induced apray
Scrubber; venturi
Disintegrator
Overall Efficiency
(percent)
65.3
84.2
91.0
94.1
99.9
96.3
97.9
93.5
99.7
98.5
Efficiency at 5w
(percent)
27
73
87
92
>99.9
9A
97
93
99.6
98
Efficiency et 2u
(percent)
14
46
60
85
99.9
87
92
75
99
95
Efficiency at Ip
(percent)
8
27
42
70
99
55
80
40
97
91
Source: American Petroleua Institute, 1978.
-------
summarized in Table 4-5. Many of these variables are limiting
factors due to equipment or regulatory requirements.
4.2.1.2 Carbon Monoxide Control. The NSPS for FCC unit regen-
erators require that carbon monoxide emissions not exceed 0.05 percent
(volume) of the flue gases. The flue gas from an uncontrolled
regenerator typically contains 10 percent carbon monoxide (Murphy
and Soudek, 1977). The emission of carbon monoxide is reduced by
oxidation to carbon dioxide either in a CO boiler or in the regen-
erator itself (in situ combustion). The oxidation reaction is
exothermic and the heat generated is removed as steam.
Carbon monoxide boilers are generally water wall boilers using
carbon monoxide and an auxiliary fuel to maintain firing temperatures
of 700°C to 760°C. The oxidation of CO to C02 is essentially com-
plete* and FCC regenerators using CO boilers do not have difficulty
meeting the MSPS.
Increased participate matter emissions are permitted from CO
boilers using solid or liquid fossil fuels as auxiliary fuel. The
increase is calculated from the heat value of the auxiliary fuel as
0.18 gram of particulate matter per million calories of heat input
attributable to the auxiliary fuel. An exemption from the particu-
late matter standard for a six-minute period permits soot blowing
from the boiler tubes.
Regenerator in situ combustion of carbon monoxide is achieved by
either raising the temperature in the regenerator or.by using a CO
4-17
-------
TABLE 4-5
EFFECTS OF VARIABLES OH DUST COLLECTIOH EQOIPMENT
Variable
Effect of Dust Variations:
Efficiency, particles:
<1 micron
1-10 micron
10-20 micron
>20 micron
Abrasion resistance
Ability to handle sticky, adhesive
materials
Bridging materials give trouble
Fire or explosion hazard minimlted
Can handle hygroscopic materials
Large foreign materials cause
plugging
Poor
Poor
Poor
Fair to Good
Fair
Fair
Slight
Fair
Yes
Seldom
High-Efficiency
Cyclones
Poor
Poor to Fair
Good
Good
Fair
Poor
Tea
Fair
Fair
Yes
Electrostatic
Precipltators
Good
Good
Good
Good
Good
Poor
Yes
Poor
With Care
Yes
Fabric
Collectors
Good
Good
Good
Good
Good
Poor
Yes
Poor
With Care
Seldom
Wet
Collectors
Poor to f*ir
Fair to good
Good
Good
Good
Poor to good
No
Good
Yes
Seldom to yes
00
Effect of Gas Stream Variations:
Maximum temperature (C),
standard construction
Troubles from condensed or entrained
mists or vapors
Corrosive gases attack standard
construction
Collector:
Space
Pressure drop (Inches of water)
Reduced volume adversely affects
collection efficiency
400
Slight
Slight
Large
1-2 Inches
Yes
400
Considerable
Slight
Modest
3-5 Inches
Yes with most
designs
400
Some
Slight
Large
1-2 inches
No
82-135 °
Considerable
Slight
Modest to large
2-6 inches
No
No limit
Slight
Severe
Modest
3-6 inches2
Depends on
ifl^fljp
*Venturl scrubbers are considered good.
b Filters for higher temperatures are available.
cPressure drop for venturl scrubbers is in the range of 10 to 70 Inches of uater.
Source: American Petroleum Institute, 1978.
-------
combustion promoter catalyst. Very often, in situ combustion, which
generally requires that the FCC regenerator unit be capable of with-
standing continuous operation at 760°C, is not feasible in an older
FCC unit regenerator because of metallurgical constraints.
Increasing the temperature in the regenerator has a number of
beneficial effects in addition to combustion of coke to carbon dioxide,
such as, increased gasoline yields due to greater carbon removal from
catalyst, and decreased coke formation on catalyst. The decreased
coke formation reduces the overall carbon monoxide and particulate
matter emissions from the FCC regenerator unit. It does not affect
the ability to meet the particulate matter standard, as the allowable
emission is based on coke burn-off. Carbon monoxide emissions have
been reported as negligible when using high temperature regeneration
(Rheaume et al., 1976a).
Carbon monoxide oxidation catalysts are capable of promoting the
oxidation of CO to C(>2 in the regenerator dense bed. In addition,
these catalysts Increase the yields of gasoline by Improving regener-
ation i.e., reducing the carbon on regenerated catalyst. If these
catalysts are added to a regenerator already using high temperature
regeneration, the regenerator temperature is reduced. Because the
oxidation of CO is exothermic, adding oxidation catalyst to a conven-
tional regenerator will raise the operating temperature. Table 4-6
shows data from three FCC regenerators used to test a CO oxidation
4-19
-------
TABLE 4-6
USE OF CARBON MONOXIDE OXIDATION CATALYST
Operating Parameter
Regenerator:
Dense, °C
Dilute, °C
Cyclones, °C
Flue gas, °C
Flue gas CO, vol %
NSPS Standard, vol %
Unit
1
1325
1333
1450
1422
0
0.05
A
2a
1303
1304
1405
1370
0
0.05
Unit
3
1336
1362
1370
1375
3.6
0.05
B
43
1326
1324
1321
1325
0.3
0.05
Unit
5
1156
1154
1312
1193
9.3
0.05
C
6a
1296
-
1342
1427
0.4
0.05
1 - conventional catalyst
2 - CCA-22 with conventional catalyst mixture
3 - CBZ-1 catalyst
4 - CCZ-22 catalyst
5 - DHZ-15 catalyst
6 - CCZ-22 catalyst
a CCZ-22 carbon monoxide oxidation catalyst
Source: Rheaume et al., 1976.
4-20
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catalyst. Carbon monoxide levels were reduced to 0.4 percent or less
depending on the operating temperature.
4.2.2 Fuel Gas Combustion Device
The NSPS standard for sulfur dioxide limits the concentration
of hydrogen sulfide in fuel gas burned at a refinery. Hydrogen
sulfide in fuel gas is controlled by amine stripping and hydrodesul-
furization. The standard also permits, as an alternative, the direct
removal of sulfur dioxide emissions from the fuel gas burner stack
gases. This can be accomplished, for example, by use of wet scrub-
bers.
Amine gas treating processes include chemical and physical
solvent processes and dry absorbent processes. The most common
process in petroleum refineries is the diethanolamina (DEA) process
(Gary and Handwerk, 1975). In this process, sour refinery gas con-
taining hydrogen sulfide and carbon dioxide contacts DEA in an
absorber unit. The hydrogen sulfide and carbon dioxide are removed
from the refinery gas and the treated, I^S-free gas Is then used as
fuel elsewhere in the refinery. The treated gas will usually contain
less than 0.57 gram of sulfur/I00 scm of gas (Gary and Handwerk,
1975). The acid-rich DEA solution is regenerated by steam stripping
in a regenerator or still. The steam is condensed and the separated
0*28 is piped to a sulfur recovery unit. The regenerated DEA is
recycled to the absorber unit.
4-21
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Hydrotreating can be applied at any point In the refinery process
stream. It is applied to a wide variety of feedstocks ranging from
reduced crude to napthas and is used to stabilize products and/or
remove undesirable elements in feedstocks by reaction with hydrogen*
Hydrodesulfurization is the removal of sulfur from feedstocks by
catalytic reaction with hydrogen. The feedstock is mixed with
hydrogen, heated, and passed over a catalyst where the hydrogen
reacts with sulfur in the feedstock to form hydrogen sulfide.
Excess hydrogen is recovered and recycled and a hydrogen sulfide fuel
gas stream is steam distilled from the feedstock. The fuel gas
stream is sent to an H2S removal unit and the desulfurized product
is ready for further processing. Any fuel gas generated from further
processing will be very low in hydrogen sulfide. Since all products
of this feedstock are also low in sulfur, the use of hydrodesulfurl-
zation has significant effects outside the refinery.
Wet scrubber technology was discussed previously with regard to
the control of particulate matter emissions. The removal of sulfur
dioxide from flue gases is the subject of a significant amount of
current research. Processes now in commercial use are: ammonia
scrubbing, lime-limestone slurry processes, dry limestone processes,
and the Wellman-Lord process (sodium sulfite scrubber). At least one
proprietary process using an aqueous caustic solution is being used
on an FCC unit regenerator (American Petroleum Institute, 1978).
There are no known examples of S02 scrubbers on process heater
exhaust streams.
4-22
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4.3 Achievable Emission Levels
The emission levels of particulate matter, carbon monoxide, and
sulfur dioxide from regenerators and fuel gas combustion devices are
discussed in the following section.
4.3.1 Fluid Catalytic Cracker
The emission levels achievable from FCC unit regenerators
will be discussed for each of the standards. There is little data
within the EPA Regional offices on operational units which have been
tested for new source compliance. This is a shortcoming of the
present reporting system being used by EPA Regional offices.
4.3.1.1 Particulate Matter. The emission of particulate matter
can be controlled to less than the present standard of 1 kg/I,000 kg
coke burn-off. However, there is insufficient data to determine the
actual effect of cyclone deterioration with time. Table 4-7 shows
the currently available compliance test data on particulate matter
emissions from FCC regenerators. These data indicate that regenera-
tors equipped with electrostatic preclpitators can reduce the emission
of particulate matter to 1.0 kg/1,000 kg of coke burn-off. Since
electrostatic precipltators are significantly more attractive eco-
nomically than filter systems or venturl scrubbers, they are consid-
ered as the best demonstrated control technology considering cost for
the control of particulate matter emissions from FCC regenerators.
The additional particulate matter emission permitted from
carbon monoxide boilers is based on data from typical oil or coal-
4-23
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TABLE 4-7
COMPLIANCE TEST DATA FOR PAKTICULATE MATTER
Refinery
Particulate
Matter
(kg/1000 k£ coke burn-off)
Champlin Petroleum Co.,
Tx. (1977)
Run #1
Run #2
Run #3
Average
NSPS Standard
1.35
0.91
0.76
1.01
1.0
Source: EPA, 1978.
4-24
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fired boilers. There Is no data to substantiate that emissions can
be reduced below this level.
4.3.1.2 Carbon Monoxide. The compliance test data for carbon
monoxide emissions from FCC regenerators is shown in Table 4-8. It
is apparent from these data that the carbon monoxide boiler is capable
of reducing CO emissions to less than 0.004 percent by volume. The
use of regenerator In situ combustion of carbon monoxide with or
without promoter catalysts can reduce emissions to nearly zero percent
if operated at a high enough temperature (Rheaume et al; 1976).
4.3.2 Fuel Gas Combustion Device
The reduction of sulfur dioxide emissions from the combustion
of fuel gas is done primarily by removing sulfur from the fuel gas by
amlne stripping. The available data on achievable concentrations of
H2& in fuel gas are shown in Table 4-9. It is apparent from these
data that it is feasible to reduce the H^S concentration of fuel
gas to less than 230 mg/dscm.
4.4 Special Problems Using Control Technologies
4.4.1 Wet Scrubbers
It has been reported that it is not possible to use wet scrubbers
in the State of Alaska (EPA, 1978a). Although this could affect
compliance with National Ambient Air Standards or possibly state
standards for the reduction of sulfur dioxide emissions, this problem
should not affect compliance with the current NSPS for petroleum
refineries. The best available control technologies considering cost
4-25
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TABLE 4-8
COMPLIANCE TEST DATA FOR CARBON MONOXIDE
Refinery
Carbon Monoxide
(Vol %)
Champlin Petroleum Co., Tx. (1977)
Run #1
Run #2
Run #3
Average
NSPS Standard
0.00306
0.00353
0.00330
0.05
Source: EPA, 1978.
4-26
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TABLE 4-9
COMPLIANCE .TEST DATA FOR SULFUR DIOXIDE
Refinery ELS
(mg/dscm)
Mobil Oil Co., N.J. (1977) 137
Delta Refining, TN. (1976) 7
Hill Petroleum Co., LA. (1977) 81
Marathon Oil, LA. (1977) 121
Getty Refining, KA. (1976) 65
Standard Oil, CA. (1976) 229*
NSPS Standard 230
*reported as "typical analysis - 0.1 gr BLS/dscf"
Source: EPA, 1978.
4-27
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are electrostatic precipitators, either CO boilers or regenerator in
situ combustion, and amine strippers. It should, therefore, be pos-
sible for petroleum refineries in Alaska to comply with the current
NSPS as it is unlikely that climatic conditions will affect these
controls.
4.4.2 Condensable Particulates
It has been reported that a significant portion of the particu-
late matter measured by EPA Reference Method 5 from FCC regenerators
using in situ combustion is condensable matter (Huddle, 1978; and
EPA, 1978). Since the definition of particulate matter is "...any
finely divided solid or liquid material, other than uncombined water,
as measured by Method 5 of Appendix A to this part or an equivalent
or alternative method" (40 CFR 60.2(V)), the difficulty is not what
is collected, but the measurement of the particulate matter catch.
The problem appears to be caused by the condensation of sulfuric acid
mist in the Reference Method 5 probe and filter. Sulfuric acid mist
is very hygroscopic and water of hydration remains with the particu-
late matter catch after drying. The Champlin Petroleum Company com-
pliance test report (EPA, 1978) states the results of various analyt-
ical tests performed on a particulate catch. The results, summarized
in Table 4-10, showed that over 50 percent of the measured Reference
Method 5 particulate matter catch is other than catalyst fines.
4-28
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TABLE 4-10
CONDENSABLE PARTICULATES FROM FCC UNIT REGENERATORS
TEST
RESULT
ASME Instack filter
NaOH titration of Method 5
catch for
Thermal analysis of Method 5
catch
Sulfate analysis of Method 5
catch
X-ray spectre graph of
Method 5 catch
89% less particulate matter than
Method 5
50%
60% weight loss
64% sulfate
27% H-SO, in probe wash
Source: EPA, 1978.
4-29
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4.5 Energy Needs and Environmental Effects
Energy consumption has always been a factor in the economics of
industrial operations. Today it has become a topic of national con-
cern. Because petroleum refineries use approximately 10 percent of
the crude feedstock for energy requirements within the refinery
itself, reductions in this energy use are of interest from both an
economic and supply viewpoint. Energy consumption in FCC units can
be reduced through the use of carbon monoxide oxidation promoter
catalysts and energy recovery expansion turbines.
New technologies that will reduce the emission of pollutants to
the atmosphere are of national interest* These technologies are of
interest to industry as well because of government regulations,
environmental concern, and very often, excessive emissions are an
indication of inefficient process operations.
4.5.1 Expander Technology
Expander turbines are used to recover some of the energy usually
lost in the FCC regenerator flue gas. The amount of energy that is
actually recovered is dependent on the inlet gas temperature, gas
flow rate, and the pressure drop. Barbier (1977) has estimated that
the maximum recovery is approximately 45 kcal/kg of flue gas. In
1973, the largest installation was recovering 15,500 horsepower from
a FCC unit installed at a Martinez, California, refinery in 1966
(Braun, 1973). Since that time, expanders as large as 22,000 hp have
been installed (C.F. Braun & Co., 1976). Today, an estimated 20,000
4-30
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hp can be recovered from the average catalytic cracking unit (Oil and
Gas Journal, 1977).
Two limiting factors have influenced Installation of the energy
recovery units. First, erosion of the turbine blades by catalyst
fines destroyed early test units. Experiments and commercial experi-
ence show that virtually all partlculate matter greater than 10
microns must be removed to keep this erosion within acceptable limits
(Murphy and Soudek, 1977). The development of third-stage catalyst
separators has solved this problem. There is a slight reduction in
the efficiency of the turbine due to erosion of the turbine blades
with time, but after five years, refineries can expect to recover 95
percent of the energy recovered under the startup conditions (Barbier,
1977).
The other limiting factor is temperature. Present state-of-the-
art turbines cannot use gases over 680°C (Barbier, 1977). Since flue
gas temperatures from regenerators operating with total In situ com-
bustion can reach 760°C a separator and expander capable of continu-
ous operation at 760°C are required. Without this capability, gases
must be cooled before passing through the expander.
The power recovered by the expander Is generally used for the
FCC unit air blower. Any excess power is used to generate elec-
tricity for use at the refinery. Yearly savings of $685,000 were
obtained at the Shell Oil Company refinery at Martinez, California.
This level of savings yields a 1.8 year payout on a $1.25 million
investment (Braun, 1973).
4-31
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4.5.2 Carbon Monoxide Oxidation Catalysts
Carbon monoxide oxidation catalysts were introduced in the early
1970's as an alternative to the zeolite catalysts being used in fluid
catalytic crackers. Typical of these catalysts are the partial com-
bustion zeolite (PCZ) and complete combustion zeolite (CCZ) series
catalysts offered by W.R. Grace and Company, Davison Chemical Division.
During their first commercial trial in April 1975, CCA-44 was charged
to a FCC unit operating with high-temperature regeneration. It is
estimated that there are now (1978) 12 FCC units using CO oxidation
catalysts and 12 more using CO oxidation additives (Wallendorf,
1978).
The PCZ catalysts promote partial combustion of carbon monoxide
with an increase of 17°C to 28°C in the regenerator and are particu-
larly useful where the metallurgy of the regenerator limits the allow-
able operating temperature. Where the temperature increase is not a
limiting factor, CCZ catalysts can be used to promote complete com-
bustion of carbon monoxide in the dense bed with a regenerator
temperature increase of approximately 56°C. This increase in
regenerator operating temperature is generally accompanied by a
reduced cyclone temperature since CO oxidation no longer occurs in
the cyclones. Only in the case of replacing catalysts under conven-
tional regeneration conditions with CCZ catalysts is the temperature
increased in both the regenerator bed and cyclones.
4-32
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The advantages of using CO oxidation catalysts are:
• Reduced cyclone temperatures When operating with regen-
erator in situ combustion since the oxidation reaction ia
held in the regenerator dense bed.
• Reduced excess air requirements because burning is promoted
in the dense bed and increased catalyst activity promotes
more efficient use of air. The reduced air requirements
should decrease the gas volume through the cyclones, and
the increased catalyst activity permits the reduction of
catalyst circulation rates. The combination of these
effects should reduce the erosion of the cyclone because
of decreased gas volume and particle loading.
• Decreased coke on the regenerated catalyst due to burning
off more of the coke formed in the reactor and reducing
the amount of coke formed in the first place. The less
coke on the catalyst, the higher the catalytic activity
and the greater the yield of useful products. PCZ and
CCZ catalysts are approximately 40 and 150 times more
active, respectively, than conventional catalysts (Rheaume
et al., 1976).
• The use of torch oil may be discontinued. Torch oil is
often used in the regenerator to maintain the high tem-
perature required for in situ carbon monoxide combustion.
• The emission of carbon monoxide is reduced although the
actual emissions are dependent on the temperature main-
tained In the regenerator.
The only disadvantage to the use of carbon monoxide oxidation
catalysts Is on those FCC units presently using a CO boiler. The
heat value of the carbon monoxide must be made up using an alternate
fuel.
4.5.3 Sulfur Dioxide Catalysts
Some of the sulfur in the FCC feedstock is retained in the coke
on the surface of the catalyst during the cracking process. Steam
stripping is used to remove entrained hydrocarbons from this
4-33
-------
deactivated catalyst prior to regeneration. This leaves a sulfur/coke
covered catalyst for regeneration. During the regeneration process,
the coke is oxidized to CO and C02, and the sulfur to SOX, pri-
marily S02« The sulfur content of the coke is directly related
to the sulfur content of the feed. It is estimated that uncontrolled
emissions of SOX from FCC unit regenerators in the U.S. average
805 ppm and may be as much as 2,750 ppm when high-sulfur feed is
processed (Vasalos et al., 1977).
Amoco Oil Company has developed a new UltraCat cracking process
which reduces sulfur oxide emissions from FCC unit regenerators. The
process uses a new catalyst that retains sulfur oxides on the catalyst
and returns them to the reactor where they are removed with the prod-
uct stream. If a low sulfur product is required, the sulfur will
be removed by amine stripping or hydrotreating and eventually
recovered in a sulfur recovery unit. Pilot tests indicate that
the new catalyst is capable of reducing sulfur oxide emissions
80 to 90 percent and commercial tests are planned to confirm this
data (Vasalos et al., 1977).
4-34
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5.0 INDICATIONS FROM TEST RESULTS
5.1 Test Coverage in Regions
In January of 1978, the Metrek Division of MITRE Corporation
made a survey of the NSPS compliance test data available at EPA
Regional offices (Watson et al., 1978). The Compliance Data System
(CDS) Indicated a total of thirteen tests; however, data were avail-
able for only nine. There were no reported failures of compliance
tests. The Champlin Petroleum Refinery, Corpus Christ!, particulate
matter test is questionable. EPA Region VI has indicated that no
retest Is scheduled pending review of the actual method used when
taking the third particulate sample (lowest measured level of par-
ticulate matter) and results of continuous monitoring in the future*
The NSPS compliance test data for petroleum refineries that is
available at the EPA Regional offices is presented in Table 5-1.
There is one particulate matter test at 1.01 kg/1,000 kg coke burn-
off, no opacity data, one carbon monoxide test at 0.0033 percent, and
seven hydrogen sulfide tests with averages ranging from a low concen-
tration of 1.4 mg H2S/dscm fuel gas to a high of 228.8 mg u^S/dscm
fuel gas. There are indications in the CDS system that four addi-
tional tests have been performed but the data were not available.
This indicates that a total of 13 tests have been performed (Watson
et al., 1978).
The data presented in Table 5-2 is presented in contrast to this
figure of thirteen NSPS compliance tests. This table shows the
5-1
-------
TABLE 5-1
NSPS COMPLIANCE TEST DATA - PETROLEUM REFINERIES
EPA Region
Region II
Mobil Oil, Paulsboro, N.J.
Region IV
Delta Refining, Memphis, TN
Region V
Reglor VI
Charaplin Petroleum, Corpus Christl, TX
Hill Petroleum, Krotz Springs, LA
Marathon Oil, Garyville, LA
Region VII
Getty Refining, El Dorado, KA
Region IX
Chevron U.S.A.., El Segundo, CA
Standard Oil, Richmond, CA
Current NSPS
NSPS Data
Indicated Total Particulate Matter Opacity Carbon Monoxide Sulfur Dioxide
Number of Teats (kK/10 kg coke burnof f) (Z) (DDm) (mg HjS/dscm)
Performed Range Average Range Average Range Average Range Average
3
<2.3-3.9 1.4
1 3.7-14.0 7.3
1
3
0.76-1.35 1.01 30.6-35.3 33
58.3-110.5 80.8
99.4-157.1 120.6
2
42.3-73.5 64.5
1
50.8-117.4 80.0
228.8
1.0 30 500 230
Source: Watson et al., 1978.
-------
TABLE 5-2
GEOGRAPHIC DISTRIBUTION 0? POSSIBLE HSP8 AFFECTED FACILITIBS
RPA
Region
I
II
III
IV
V
VI
VII
VIII
IX
X
Total
Nusber of lew or
Increased Capacity Fluid
"fl^^vtlc Cracker I*"ft8
Cosvleted* .
-
1/10
4/15
-
11/86
16/149
4/4
7/6
6/112
1/3
50/385
Under .
Construction
(conp. date)
-
1C80)
-
-
-
USA)
1C77)
1(79)
1C79)
1(78)
-
-
1(77)
1(78)
2(79)
1(80)
KRA)
Engineering
(conp. data)
-
1(HA)
1(79)
KHA)
1(78)
6(79)
-
1(78)
-
-
2(78)
7(79)
2 (HA)
Huober of Facilities
Reported by Regional
OfflcesC
Fluid Cat
Cracker
(FCC)
-
-
-
-
-
1
-
w
f
-
1
Fuel Gas
Coobustor
(FOC)
-
3
-
2
1
38
6
6
f
6
62
Future
Sources
(FCC/FGC)
-/IP
-/-
-/-
-/-
-/-
1U, 1P/38U, 37P
-/-
e
f
-/IP
in, IP/380, 39P
'Cantrall, 1975.
Hydrocarbon Processing, 1978; data as of 1 January 1978.
°Watson at al., 1978. (0 - under construction; P - planned)
Capacity in 103 barrels per stream day.
eCDS .file does not show any sources planned or under construction. Dse of these entries varies among the
Regions. It should not be assuoed that no new sources are planned or are under construction in this Region.
Tlot available.
-------
distribution of possible NSPS affected facilities. The EPA Regional
offices have reported that there are two NSPS affected FCC units and
62 fuel gas combustion devices (Watson et al., 1978). A literature
search shows that fifty refineries have built new FCC units or
increased FCC unit capacity during the period 1975-1978 (Cantrell,
1975; 1978).* Data on fuel gas combustion sources is not available.
It is not within the scope of this project to determine which facili-
ties are, in fact, subject to the NSPS.
In addition to the data on present NSPS affected facilities,
Table 5-2 presents information on the geographic distribution of the
growth of these sources. The EPA Regional offices reported one FCC
unit under construction and one being planned (Watson et al., 1978).
Hydrocarbon Processing (1978) on the other hand reports six FCC units
under construction (new or being modified/revamped to increase
capacity) and eleven more in the engineering phase.** Again this
data is presented for further consideration for a determination of
which, if any, of these FCC units might be considered affected
facilities and hence subject to the NSPS.
*See Appendix A for details on which refineries have reported growth
during this period.
**See Table 4-2 for details on refineries reporting future growth
plans.
5-4
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5.2 Analysis of Test Results
There is insufficient compliance test data in CDS to make a
Judgement on the adequacy of the present NSPS for petroleum refineries.
The available compliance test data presented indicates that:
• The particulate matter standard is compatible with
the present state of control technology.
• The opacity standard, which was set to match the
mass standard, is compatible with the present state
of control technology.
• The carbon monoxide standard could be changed to reduce
the allowable emission of carbon monoxide although the
present data are insufficient to establish an appropriate
standard.
• The sulfur dioxide standard could also be changed to
reduce the allowable concentration of hydrogen sulfide
in fuel gas although more data should be collected which
will relate the H2& reduction achievable to the sulfur
content of feedstocks.
5-5
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6.0 ANALYSIS OF POSSIBLE REVISIONS TO THE STANDARD
This section will approach the analysis of possible revisions
to the NSFS by examining the emission of particulate matter, carbon
monoxide, sulfur dioxide, and hydrocarbons. The analysis consists of
an examination of the available data in light of environmental,
economic, control technology, and process effects.
6.1 Particulate Matter
There is -Insufficient data to support a change to the present
particulate matter standard. New control technologies have been
developed that can reduce the emission of particulate matter effec-
tively, but not to a sufficient degree to justify a change in the
NSPS of 1 kg particulate matter per 1,000 kg of coke burn-off.
Technological trends in the industry do not appear to signifi-
cantly affect the particulate matter standard. These trends include
the use of higher temperature reactors and regenerators, and new
catalysts and/or additives. The actual quantity of particulate
matter emitted will be affected by a reduction In the quantity of
coke formed on the catalyst and a reduction In catalyst flow rates,
thereby reducing catalyst and carbon emissions. This reduction does
not affect the present standard because allowable emissions are based
on the quantity of coke burned off the catalyst.
The particulate matter emitted from a FCC unit regenerator con-
sists primarily of catalyst fines produced in the first stage cyclone.
Additional particulate matter is the result of chemical reactions In
6-1
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the flue gas which result in the formation of condensable sulfates.
The particles range in size from 0.5 micron to 60 microns in diameter
with as much as 86 percent of these particles greater than 10 microns
in diameter (BalT. rt, 1976). As a result, a number of control tech-
nologies are suitable for reducing the emission level, but present
data show that electrostatic precipitators are the best demonstrated
control technology considering cost for minimizing the final emission
level. Only filters are as efficient at removing small particles as
electrostatic precipitators. Wet scrubbers, which have the potential
for efficient small particle removal, also have the added advantage
(from an environmental viewpoint) of removing sulfur compounds.
The measurement of particulate matter requires the use of
Reference Method 5 or its equivalent. It has been recognized in
the past that condensable particulate matter will collect in the
impingers of the Method 5 sampling train. This material is not
included in the reportable particulate matter catch. It was also
recognized that condensable particles were being collected in the
sampling probe and on the filter (EPA, 1975). These particles are
reportable as particulate matter. Most of these condensable parti-
cles are believed to be sulfuric acid mist, a highly hygroscopic
material, and other sulfates. Because of this, it is difficult to
actually be assured of the quantity of catalyst fines, condensable
particles, and moisture being measured. At present, all this mate-
rial is, by definition, particulate matter.
6-2
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There are no CDS opacity data to comment on. The fact that
there is no requirement to record mass emissions and opacity at the
same time is a shortcoming. There is no reason to require mass
emission testing whenever opacity is measured, but the reverse would
result in the availability of significant data on the relationship
of opacity and mass emissions from FCC regenerators.
The particulate matter standard was set at a higher level than
can be attained in newly installed FCC unit regenerator systems.
This was done in recognition of the fact that the systems are nor-
mally operated continuously for up to two years or longer without a
major shutdown. The internal cyclones are inaccessable for mainte-
nance during the period and because of erosion, emissions tend to
Increase (EPA, 1973b). It is possible that particulate emissions
could be maintained at a lower level through the use of an additional
high efficiency separator external to the regenerator but upstream of
the precipltator. This separator is reported to be less prone to
erosion, and, because it is external to the regenerator, is more
accessable for maintenance. The efficiency of the separator is
dependent on the efficiency of the cyclones preceding It. This effi-
ciency change is due primarily to the size distribution of the par-
ticles In the Inlet stream. Efficient cyclones change the size dis-
tribution of the particles in the separator inlet stream and there-
fore reduce the separator efficiency. Separator efficiencies range
6-3
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from approximately 70 percent to over 90 percent In units with highly
efficient internal cyclones to poor cyclones, respectively (Krueding,
1975).
6. 2 Carbon Monoxide
The NSPS for carbon monoxide can be met by the use of a waste
heat boiler which not only controls emissions but recovers the
heat value of the oxidation reaction of carbon monoxide to carbon
dioxide. The other commonly used control technology is combustion
of the carbon monoxide in the regenerator itself. The advantages
of in situ regeneration are: increased yields of useful products,
decreased emissions of particulate matter, and recovery of waste heat
in an energy expander. There is no CDS data on the carbon monoxide
emissions from a regenerator using regenerator in situ combustion of
carbon monoxide.
In the past, the metallurgy of the regenerator and cylones was
a limiting factor which determined those FCC units capable of
operating with high temperature in situ combustion. The recent
development of carbon monoxide oxidation catalysts and additives has
permitted many units to at least partially, and often completely,
oxidize carbon monoxide in the regenerator without resorting to high
temperatures. Little data are available on the emission level of
carbon monoxide from FCC unit regenerators using CO oxidation pro-
motors. An additional advantage of using the oxidation promoter
over conventional high temperature regeneration is that the
6-4
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oxidation reaction remains In the dense bed, the cyclone temperature
is reduced, and presumably erosion and particulate matter emissions
will be reduced* There Is no data as yet to substantiate the last
conclusion, although It Is reasonable.
6.3 Sulfur Dioxide
The present NSPS for sulfur dioxide limits the concentration of
hydrogen sulflde in fuel gas burned In a petroleum refinery to 230
mg H2S/dscm of fuel gas. There Is provision for the refinery
owner/operator to reduce sulfur dioxide emissions In flue gas
Instead of hydrogen sulflde In fuel gas. The CDS data that were
available at the EPA Regional offices Indicate that refineries are
presently reducing the concentration of H2S in fuel gas to levels
substantially below the present NSPS. There were no data to Indicate
by what amount the H£S concentration was being reduced (efficiency
of the controls) nor how the R^S concentration related to the
sulfur content of the feedstock.
According to Gary and Handwerk (1975), amlne gas treating units
usually reduce sulfur concentrations to less than 5.72 mg/dscm. The
concentration of H2& in treated fuel gas reported in the CDS files
ranges from less than 7 mg/dscm to 229 mg/dscm (Watson et al., 1978).
Although the compliance test data show concentrations significantly
above the concentration reported in Gary and Handwerk, most of these
measurements are still substantially below the 230 mg/dscm maximum
concentration allowed by the NSPS.
6-5
-------
Presently, there is no NSPS for sulfur dioxide emissions from
the fluid catalytic cracker regenerator nor from the regenerator
incinerator waste-heat boiler. The FCC unit regenerator emissions of
sulfur oxides are oocimated at 2.3 x 108 to 3.9 x 108 kg/yr based
on current FCC capacity and emission factors from the EPA (1973).
In addition, there are additional sulfur oxide emissions from the
regenerator waste heat boiler due to the use of auxiliary fuel. The
actual quantity of emissions depends on the sulfur content of the
auxiliary gaseous, liquid, or solid fuel. Even if fuel gas is used
as the auxiliary fuel, there are no requirements to control SOX as
the boiler has been exempted from the sulfur dioxide standard for
fuel gas combustion devices.
State air pollution standards (1976) for SOX from new source
FCC unit regenerators range from 440 ppm to 2,000 ppm in the flue gas.
However, the actual achievable emission rate is dependent on feed-
stock, feedstock sulfur content, and other process variables. If
the feedstock is low in asphaltenes, hydrodesulfurization may have
the capability to reduce the sulfur oxide emission rate. Process
variables such as high temperature regeneration and the use of SOX
recycle catalysts may also be capable of reducing the level of SOX
emitted from the regenerator. Data are not available to specify the
actual levels of these emissions.
6-6
-------
6.4 Hydrocarbons
The emission of hydrocarbons from FCC unit regenerators is not
addressed in the present NSPS. There is a great interest in hydrocar-
bons because of the relationship of many of these compounds with health
hazards and the formation of smog. A number of potentially hazardous
hydrocarbons are known to be present in the flue gas from an uncon-
trolled FCC unit regenerator. Table 6-1 lists some of the hydrocar-
bons which are known to be hazardous and are known to be present in
the regenerator flue gas stream. Of particular concern are the poly-
nuclear aromatics (PNA's) because of their potential carcinogenic
effects. The most abundant FNA in regenerator flue gas is benzo-a-
pyrene (BAP) with a concentration of 0.218 kg BAP/1,000 barrels of
feed. The concentration of BAP can effectively be reduced in a car-
bon monoxide boiler to 1.41 x 10~5 kg BAP/I,000 barrels of feed
(Arthur D. Little, Inc., 1976). There are no data to determine the
concentration of BAP in the flue gas from high temperature (in situ)
regeneration nor in the case of regenerators using CO oxidation pro-
moting catalysts.
6-7
-------
TABLE 6-1
HAZARDOUS HYDROCARBONS EMITTED FROM FCC UNIT REGENERATORS
Hydrocarbons Concentration
(ppm)
Aldehydes (as H2CO) 3-130
Cyanides (as HCN) 0.19 - 0.94
Anthracene 2,070a
Pyrenes 40 - 28,000a
Benzo (ghi) perylenes 15 - 424a
Benzo (a) pyrene 4 - 460a
Benzo (e) pyrene 11 - 3,600a
Phenanthrenes 400,000
a Micrograms per barrel of oil charged
Source: Bombaugh et al., 1976.
6-8
-------
7.0 CONCLUSIONS
7.1 Particulate Matter
The available data do not support any changes to the present
NSPS. New technologies such as high efficiency separators, high
temperature regeneration, and new catalysts have reduced the total
quantity of partlculate matter emitted. The method of calcu-
lating the allowable emissions has already corrected for the
reduction due to changes In catalysts and operating procedures. The
current standard remains valid.
The Reference Method 5 for measuring partlculate matter emis-
sions continues to be controversial because the temperature of the
sampling train affects the amount of condensable particles present In
the measured partlculate matter.
7.2 Carbon Monoxide
The NSPS for carbon monoxide emissions was based on the use of
regenerator in situ combustion. This method of controlling carbon
monoxide emissions is less effective than a carbon monoxide boiler.
There are Insufficient data to substantiate any change in the original
finding that it is not practical to control CO emissions to less than
500 ppm by in situ regeneration. The recent advent and Increased use
of CO oxidation catalysts and additives may have altered that original
finding although no compliance test data were found to substantiate
this.
7.3 Sulfur Dioxide
. A number of conclusions regarding the present NSPS for sulfur
7-1
-------
dioxide have been discussed previously, namely:
• Compliance with the present standard is difficult to ensure
without a continuous monitoring method.
• Compliance test data indicates that a reduction in the
allowable ^ncentratlon of hydrogen sulfide in fuel gas is
possible.
• The present standard for fuel gas combustion devices has
excluded regenerator waste-heat boilers even though they may,
in fact, generate and emit SOX when using fuel gas as an
auxiliary fuel.
• Although a separate standard for particulate matter was
promulgated for regenerator waste heat boilers using liquid
or solid fossil fuel, no standard applies to the SOX gen-
erated when these fuels are used. This should be examined if
the SOX standard is revised for fuel gas combustion devices
or a standard is developed for FCC unit regenerators.
• The FCC unit regenerator emits significant quantities of sul-
fur oxides which are presently uncontrolled. Control technol-
ogies for the reduction of sulfur dioxide emissions from
other industries exist and may be applicable to FCC regener-
ators, and, in fact, there are FCC regenerators with SOX
emission controls. At least ten states have a sulfur oxide
emission limit for FCC regenerators which apply to existing
and new sources and may be a source of data on the applica-
bility of SOX control devices.
• Little is known of the actual effect of an increased sulfur
content of feedstocks on the emission of sulfur oxides from
the regenerator. Refineries are being forced to process a
higher sulfur content feed due to shortages of domestic crude
and this will have an effect on the final emission level as
well as on the ability to control the emissions.
7.4 Hydrocarbons
There is not enough known about the emission of hydrocarbons
from FCC units to justify setting a standard. The present data
however indicate that: the uncontrolled emissions are significant,
they depend on the process, and because of potential adverse health
effects, they may require control.
7-2
-------
8.0 RECOMMENDATIONS
The following recommendations are made regarding the NSPS
for particulate matter, carbon monoxide, sulfur dioxide, and hydro-
carbons .
8.1 Particulate Matter
• Do not change the present standard of 1.0 kg/1,000 kg
coke burn-off and 30 percent opacity.
• Reevaluate the Reference Method 5 for particulate
matter.
• Require that opacity be measured when mass loading tests
are made.
8.2 Carbon Monoxide
• Collect data to ascertain the level of carbon monoxide
emissions from high temperature (in situ) regenerators with
and without the use of CO oxidation catalysts and additives.
• Reevaluate the carbon monoxide standard in light of the
findings from the above research.
8.3 Sulfur Dioxide
• Change the definition of a fuel gas combustion device
to include the regenerator incinerator-waste heat boiler by
deleting the exemption.
• Develop a continuous monitoring method for hydrogen
sulfide.
• Reevaluate the present standard in light of the effect of an
increased sulfur content of feedstock on the concentration of
hydrogen sulfide in fuel gas and of current compliance test
data on achievable levels of hydrogen sulfide in fuel gas.
• Investigate FCC unit regenerator sulfur oxide control tech-
nology, including cost, performance, applicability, effect of
feed stocks, etc. Subject to the findings of such an investi-
gation* develop a standard for sulfur dioxide emissions from
FCC unit regenerators.
8-1
-------
8.4 Hydrocarbons
Evaluate the effect of: conventional regeneration, CO boil-
ers, high temperature regeneration, and regeneration with CO
combustion catalysts and additives on the emission of hydro-
carbons fr-"" FCC unit regenerators.
Assess the need for the regulation of hydrocarbon emissions
from FCC unit regenerators based on results from the above
research.
8-2
-------
9.0 REFERENCES
American Petroleum Institute, 1978. Manual on Disposal of Refinery
Wastes. Volume on Atmospheric Emissions. Washington, D.C.
Arthur D. Little, Inc., 1976. Screening Study to Determine Need
for SOX and Hydrocarbon NSPS for FCC Regenerators. NT IS,
Springfield, VA. Pfi-275 162.
Balfoort, J.P., 1976. Improved Hot-Gas Expanders for Cat Cracker
Flue Gas. Hydrocarbon Processing 55(3):141-143.
Barbier, J.C., 1977. Save Energy When Making Gasoline. Hydrocarbon
Processing 56(9):85-96.
Bombaugh, K.J., E.G. Cavanaugh, J.C. Dickerman, S.L. Keil, and T.P.
Nelson, 1976. Sampling and Analytical Strategies for Compounds
in Petroleum Refinery Streams, Volumes 1 and 2. Radian Corpora-
tion. NT IS, Springfield, VA. PB-251 744 and PB -251 745.
Braun, S.S., 1973. Power Recovery Pays Off at Shell Oil. Oil and
Gas Journal 71(21):128-134.
C.F. Braun & Company, 1976. Power Recovery for Fluid Catalytic
Cracking Units. Alhambra, CA.
Cantrell, A., 1975. Annual Refinery Survey. Oil and Gas Journal
73 (14): 96-118.
Cantrell, A., 1978. Annual Refining Survey. Oil and Gas Journal
76(12):108-142.
Dickerman, J.C., T.D. Raye, J.D. Colley, and R.H. Parsons, 1977.
Industrial Process Profiles for Environmental Use: Chapter 3.
Petroleum Refining Industry. Radian Corporation. NTIS,
Springfield, VA PB-273 649.
Gary, J.H. and G.E. Handwerk, 1975. Petroleum Refining, Technology
and Economics. Chemical Processing and Engineering Volume 5.
L.F. Albright, R.N. Maddox, and J.J. McKetta, ed.
Huddle, J., 1978. Personal communication. J. Huddle, AMOCO Oil
Company and K. Barrett, The Metrek Division of The MITRE
Corporation*
Hydrocarbon Processing, 1978. World-Wide HPI Construction Boxscore,
Section 2, Feb. 1978.
9-1
-------
Krueding, A.P., 1975. Cat Cracker Power Recovery Techniques.
Chemical Engineering Progress 71(10):56-61.
Laster, L.L., 1973. Atmospheric Emissions from the Petroleum
Industry. National Environmental Research Center, Research
Triangle Par^- NC. NTIS, Springfield, VA. PB-225 040.
Murphy, J.R. and M. Soudek, 1977. Modern FCC Units Incorporate
Many Design Advances. Oil and Gas Journal 75(3):70-76.
Nader, J., 1978. Personal communication. U.S. Environmental
Protection Agency, Research Triangle Park, and K. Barrett,
The Metrek Division of The MITRE Corporation.
Oil and Gas Journal, 1977. Mobil Plans Recovery from FCC Unit. Oil
and Gas Journal 75 (9):66.
Rheaume, L., R.E. Ritter, J.J. Blazek, and J.A. Montgomery, 1976.
New FCC Catalysts Cut Energy and Increase Activity. W.R.
Grace & Company. Oil and Gas Journal 74(20):103-110.
Rheaume, L., R.E. Ritter, J.J. Blazek, and J.A. Montgomery, 1976a.
Two New Carbon Monoxide Oxidation Catalysts Get Commercial
Tests. W.R. Grace & Company. Oil and Gas Journal 74(21):
66-70.
U.S. Environmental Protection Agency, 1973. Compilation of Air
Pollutant Emissions Factors, AP-42.
U.S. Environmental Protection Agency, 1973a. Background Information
for Proposed New Source Performance Standards: Asphalt Concrete
Plants, Petroleum Refineries, Storage Vessels, Secondary Lead
Smelters and Refineries, Brass and Bronze Ingot Production
Plants, Iron and Steel Plants, Sewage Treatment Plants. Volume
I. Main Text. Office of Air Programs, Research Triangle Park,
North Carolina.
U.S. Environmental Protection Agency, 1973b. Background Information
for New Source Performance Standards: Asphalt Concrete Plants,
Petroleum Refineries, Storage Vessels, Secondary Lead Smelters
and Refineries, Brass and Bronze Ingot Production Plants, Iron
and Steel Plants, and Sewage Treatment Plants. Volume III.
Promulgated Standards. Office of Air Programs, Research Triangle
Park, North Carolina.
U.S. Environmental Protection Agency, 1975. Emission Monitoring
Requirements and Revisions to Performance Testing Methods.
40 FR 46250-46271.
9-2
-------
U.S. Environmental Protection Agency, 1978. Compliance Test Report
for Champlln Petroleum Company, Corpus Christ!, XX.
U.S. Environmental Protection Agency, 1978a. Personal communication
between E.L. Keitz, The Metrek Division of the MITRE Corporation,
and K.A. Lepic, M.H. Hooper, and B. Swan, EPA Region X. Jan.
10-11, 1978.
Vasalos, I.A., E.R. Strong, C.K.R. Hsieh, 6.J. D'Souza, 1977. New
Cracking Process Controls FCCU SO^. Oil and Gas Journal 75(26):
141-148.
Wallendorf, W., 1978. Personal communication, W. Wallendorf, Technical
Services, W.R. Grace & Company, and K. Barrett, Me trek Division,
MITRE Corporation.
Watson, J.W., L.J. Duncan, E.L. Keitz, and K.J. Brooks, 1978. Regional
Views on NSPS for Selected Categories. MTR-7772. Metrek Division
of The MITRE Corporation, McLean, VA. (Draft)
9-3
-------
APPENDIX A
REPORTED FLUID CATALYTIC CRACKING
UNITS AT PETROLEUM REFINERIES
-------
APPENDIX A
REPORTED FCC UNITS AT PETROLEUM REFINERIES
FCC Capacity (Mb/ad)
EPA Ragion Company/City 1975* 197V>Changa*
Ragion It
Connactieut Nona raportad
n
Maaaachuaatta
Naw Hanpahlra
Rhoda Island
Vanont
Subtotal:
Raglan Hi
Haw Jaraay Exxon, Uadan 125 135 10
Taxaco. Vaatvllla 40 40 0
Naw York Aahland, North Tonavanda 22 22 _0
Subtotal: 187 197 10
Raglan Hit
Dalawara
Maryland
Pannaylvanla
Virginia
Wait Virginia
Gatty, Dalawara City
Nona raportad
BP, Marcua Book
Oulf , Fhlladalphia
Sun, Marcua Book
united. Warran
Aavco, Torktom
Nona raportad
Subtotal:
62
-.
40
80
75
10
27
_I_
294
62
_
48
84.6
75
11.5
28
"
309.1
0
_
8
4.6
0
1.5
1
"*
15.1
*Zacraaaa/(aaeraaaa) la FCC capacity
'Raportad in Mb/cd. Mb/ad calculatad
(Mb/cd - thouaand barrala par calandar day, Mb/ad - thouaand barrala par at
Sonreaa:
*Canerall, 1975.
bCantraU, 1978.
A-l
-------
REPORTED FCC UNITS AT PETROLEUM REFINERIES
EPA Region
Region IV:
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
Company/City
None reported
ti
M
Ashland, Catlettsburg
Ashland, Louisville
Chevron, Pascagoula
Standard of Kentucky,
Pascagoula
None reported
FCC
1975°
-
-
54
10.5
-
56
-
Capacity
1978">
-
-
54
10
56
-
-
(Mb/ed)
Change*
-
-
-
0
(0.5)
56 *
+
(56)
-
South Carolina
Tennessee
Subtotal:
120.5
120
(0.5)
Region V:
Illinois
Indiana
Iowa
Michigan
Minnesota
Wisconsin
Amoco, Wood River 38 38 0
Clark, Blue Island 24 26 2
Clark, Hartford 26 26 0
Marathon, Robison 36.5 36.5 0
Mobil, Joliet 66 92 26
Shell, Wood River 94 94 0
Texaco, Lawrenceville 31 34 3
Texaco, Lockport 30 30 0
Union of CA, Lemont 54 55 1
Amoco, Whiting 118 140 22
Atlantic Richfield, t
East Chicago 48 - (48)f
Energy Coop, East Chicago - 48 48
Indiana Farm Bureau,
Mt. Vernon 6.1 6.3 0.2
Rock Island, Indianapolis 15 17 2
None reported
Marathon, Detroit 21.5 25.5 4
Total Leonard, Alma 12 - (12)
Total Petroleum, Alma - 16 16+
Continental, Wrenshall 9.5 9.5 0
Koch, Pine Bend 24 - (24)T
Koch, Rosemont - 45 451"
Northwestern, St. Paul Park 21 22 1
Murphy, Superior 9.7 9.7 0
Subtotal: 684.3 770.5 86.2
*Increase/(decrease) In FCC capacity
'('Change in ownership
Reported in Mb/cd, Mb/ad calculated
(Mb/cd - thousand barrels per calendar day, Mb/sd
Sources:
"Cantrell, 1975.
thousand barrels per stream day)
1,
Cantrell, 1978.
A- 2
-------
IEPOKTED FCC WITS AT PETROLEUM HKHIBRIKS
EPA Region Conpany/City
Region VI:
Arkansas Lion Oil Co., Eldorado
Louisiana Citiea Service, Lake Charles
Exxon, Baton Rouge
Good Hope Raf . , Good Hope
Gulf, Belle Chasaa
Murphy, Keraux
Shall, Horco
Tenneco, Chalaette
Texaco, Convent
Ha* Mexico Shall Oil. Clnlsa
Oklahoaa Apeo, Cyril
Cbaaplln, ""I**
Continental. Ponce City
Hudaon, Cashing
Esrr-MeGaa. Wynnewood
Midland, fflffiifpfl
Sun, Duncan
Sun, Tulaa
Texaco, Heat Tulaa
Viekara, Ardaore
Texas AMerican, Fort Arthur
ASDCO, Texaa City
Atlantic RlrhHeld, Houston
Chaaplin, Corpna Cbristi
Houston
Chevron, El Paao
Coastal Stataa, Corpus
Cbristi
Cosdan, Big Spring
Croan "~"-"*''j Houston
Exxon, Bay town
Gulf. Port Arthur
La Gloria, Tyler
Marathon, Taxaa Ctiy
Mobil. Beanaont
Phillips, Borger
Phillips, Owainy
Shall, Deer Park
Shall, Odaaaa
Southwestern, Corpus
Christi
Suntida, Corpus Christi
Sun, Corpus Christi
Texaco, saarlTIo
Texaco, El Paso
Texaco, Port Arthur
Texaa City, Texaa City
union of Calif., Hnftr1j-"1
Onion of Calif., Beaumont
Bineton. Fort Worth
FCC Caoaclty (Mb/ad)
1975* 1979°
15
125
163
15
78
10.5
100
22
70
7.2
6
19.5
44
11.5
7
25
30,
IB1
13
30
135
69
10
24
22
19
24
43
124
120
10
28.5
80
55
30
70
10.5
9.5
20
-
a,l
H
1351
27
40
3.4
15
125
169
17
78
10.5
100
22
70
7.2
6.7
19
44
7
11.5
-
25
30,
IB1
21.5
32
167
74
54
37.5
22
19
24
43
135
120
10
30
90
. 56
34
70
10.5
12
-
25
8*
7*
1351
27
39
3.4
Change*
0
0
6
2
0
0
0
0
0
0
0.7
(0.5)
A
7f
0 .
(7)
0
0
0
8.5
2
32
5
44
13.5
0
0
0
0
11
0
0
1.5
10
1
4
0
0
2.5
(20)t
25*
0
0
0
(40.+
39*
Subtotals 1933.6 2080.8 147.2
nncraasa/(dacrassa) la ICC capacity
Chanaa in oanarahla
'laportad in ht/cd, Vb/sd calculated
Qfc/ed - thousand barrels par calendar day. Mb/ad - thousand barrela par atraaa day)
Soureaai
*Cantrell, 1975.
A-3
-------
REPORTED FCC UNITS AT PETROLEUM REFINERIES
EPA Region
Region VII:
Kansas
Company /City
American Petroleum, El
FCC Capacity
1975" 1978°
11
(Mb/sd)
Change*
(ID*
Missouri
Nebraska
Ohio
Dorado
APCO, Arkansas City
CRA, Coffeyvllle
CRA, Phillip
Derby. Wichita
Getty, El Dorado
National Coop, McPherson
Pester, El Dorado
Phillips, Kansas City
Skelly, El Dorado
Amoco, Sugar Creek
CRA. Scotts Bluff
Ashland, Canton
Gulf, Toledo
Gulf, Cleves
Standard of Ohio, Lima
Standard of Ohio, Toledo
Sun of Pennsylvania, Toledo
Subtotal:
9.2
14.5
7
10.8
20
32
31
41
2.4
24.5
20
18
37
55
50
9.6
16
8.5
10.8
17
20
11
32
41
2.4
24.5
19.8
18
37.7
55
50
383.4 373.3
0.4
1.5
1.5
(31) f
0
0
0
(0.2)
0
0.7
0
0
(10.1)
Region VIII:
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Asamera, Commerce City
Continental, Commerce City
The Refinery Corp. ,
Commerce City
Cenex, Laurel
Continental, Billings
Exxon, Billings
Phillips, Great Falls
Amoco, Mandan
None reported
Amoco, Salt Lake City
Chevron, Salt Lake City
Major, Roosevelt
Plateau, Roosevelt
Amoco , Casper
Husky, Cheyenne
Husky, Cody
Pasco, Sinclair
Sinclair, Sinclair
Texaco , Casper
Subtotal:
-
14
7.6
10.5
14
19
1.8
23
-
17
10
5
-
9.5
10
3.3
17.7
_
7
169.4
7
15
-
12
15
19.2
1.8
23
-
18
11
-
5.2
9.4
10
3.3
-
17.7
7
174.6
7T
1
X
(7.6)f
1.5
1
0.2
0
0
-
1
1 +
(5> t
5.2T
(0.1)
0
0 +
(17.7);
17.7 f
0
5.2
*Increase/(decrease) In FCC capacity
Change in ownership
Reported in Mb/cd, Mb/sd calculated
(Hb/cd - thousand barrels per calendar day, Mb/sd - thousand barrels per stream day)
Sources:
"Cantrell, 1975.
bCantrell, 1978.
A-4
-------
REPORTED FCC UNITS AT PETROLEUM REFINERIES
EPA Region
Region IX:
Arizona
California
Hawaii
Nevada
Company/City
None reported
Atlantic Richfield,
Carson
Chevron, El Segundo
Chevron, Richmond
Exxon, Benecla
Gulf, Santa Fe Springs
Mobil, Torrance
Phillips, Avon
Powerine Oil, Sante Fe
Springs
Shell Oil, Martinez
Shell Oil, Wilmington
Texaco, Wilmington
Tosco Corp., Lion Oil, Avon
Union Oil of Calif., Los
Angeles
Chevron, Barbers Point
Standard of Calif.,
Barbers Point
None reported
Subtotal:
FCC Canai
1975«
(Mb/ad)
57
_
45
13.5
56
47
11
46
35,
28s
45
14.1
397.6
56
47
55
46
13.5
60
11.5
46
35§
28s
47
45
19
-
509
(1)
47
55
1
0
(47)f
0.5
0
0
Jy
0
19+
0.4.1)*
111.4
Region X:
Alaska
Idaho
Oregon
Washington
None reported
Shell, Anacortes
Texaco, Anacortes
Subtotal:
36,
27*
63
36
30*
66
0
3
GRAND TOTAL
4232.8 4600.3
367.5
•Increase/(decrease) in FCC capacity
Change in ownership
'Reported in Mb/cd, Kb/ad calculated
(Mb/cd - thousand barrels per calendar dayt Kb/fed:- thousand barrels per stream day)
Sources:
•Cantrell, 1975.
bCantrell, 1978.
A-5
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/3-79-008
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
A Review of Standards of Performance for New
Stationary Sources - Petroleum Refineries
5. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Kris Barrett and Alan Goldfarb
8. PERFORMING ORGANIZATION REPORT NO.
MTR-7825
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Metrek Division of the MITRE Corporation
1820 Do!ley Madison Boulevard
Me Lean, VA 22102
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-2526
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
DAA for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
14. SPONSORING AGENCY CODE
EPA 200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report reviews the current Standards of Performance for New Stationary
Sources: Subpart J - Petroleum Refineries. It includes a summary of the
current standards, the status of current applicable control technology, and
the ability of refineries to meet the current standards. Compliance test
results are analyzed and recommendations are made for possible modifications
and additions to the standard, including future studies needed for unresolved
issues.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (ThisReport}
Unclassified
21. NO. OF PAGES
83
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (R«». 4-77) PREVIOUS EDITION is OBSOLETE
------- |