-------
units using these reactions also tend to have both high heating values and
a high percentage application of combustion devices.
2,5 VOLATILE ORGANIC COMPOUND EMISSIONS FROM DISTILLATION UNITS
The discussions on distillation column operating theory and design
show the basic factors of column operation. Vapors separated from the
liquid phase in a column rise out of the column to a condenser. The gases
and vapors entering the condenser can contain VOC, water vapor, and
noncondensibles such as oxygen, nitrogen, and carbon dioxide. The vapors
and gases originate from vaporization of liquid feeds, dissolved gases in
liquid feeds, inert carrier gases added to assist in distillation (only
for inert carrier distillation), and air leaking into the
column—especially in vacuum distillation. Most of the gases and vapors
entering the condenser are cooled enough to be collected as a liquid-
phase. The noncondensibles (oxygen, nitrogen, C0£, and other organics
with low boiling points), if present, are not usually cooled to the
condensation temperature and are present as a gas stream at the end of the
condenser. Portions of this gas stream are often recovered in devices
such as scrubbers, adsorbers, and secondary condensers. Vacuum generating
devices (e.g., pumps and ejectors), when used, might also affect the
amount of noncondensibles. Some organics can be absorbed by condensed
steam in condensers located after vacuum jets. In the case of oil-sealed
vacuum pumps, the oil losses increase the VOC content of the
noncondensibles exiting the vacuum pump. The noncondensibles from the
last process equipment (e.g., condensers, pumps, ejectors, scrubbers,
adsorbers, etc.) constitute the emissions from the distillation unit,
unless they are controlled by combustion devises such as incinerators,
flares, and boilers.
The most frequently encountered emission points from fractionation
distillation operations are illustrated for several types of distillation
units in Figures 2-9 to 2-12. These emission points are indicated by the
numbers in parenthesis as follows: condenser (1), accumulator (2), hot
wells (3), steam jet ejectors (4), vacuum pump (5), and pressure relief
valve (6). Emissions of VOC's are created by the venting of
noncondensible gases that concurrently carry out some hydrocarbons.
2-43
-------
Vent to Atmosphere
Distillation
Column
Pressure Relief
VeJve(6)
Overhead Product
Figure 2-9. Potential VOC emission points for a nonvacuum distillation
column.
2-44
-------
Steam
Steam Jet
Ejector (4)
Pressure Relief
Valve (6)
Accumulator
(2)
Cooling
Water (CW)
Overhead Product
I
Steam
Steam Jet
Ejector (4)
Barometric
Condenser
Distillation
Column
(3) Hot well
Vent
Vent
Wastewater
Figure 2-10.
Potential VOC emission points for a vacuum distillation
column using steam jet ejectors with barometric condenser.
2-45
-------
Steam
Vapor Phase
Cooling Water
Condenser
(1)
C
Accumulator
(2)
Overhead Product
Distillation
Column
Steam Jet
Ejector (4)
Accumulator
(2)
Waste Water
Figure 2-11.
Potential volatile organic compound emission points for a
vacuum distillation column using steam jet ejectors.
2-46
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Vapor Phase
C
cw
Condenwr (1)
Uquld Reflux
Distillation
Column
Vent
Vacuum Pump (5)
Accumulator (2)
Overhead Product
Figure 2-12.
Potential VOC emission points for vacuum distillation column
using a vacuum pump.
2-47
-------
The total volume of gases emitted from a distillation operation
depends upon air leaks into the vacuum column (reduced pressure increases
leaks and Increased size Increases leaks), the volume of inert carrier gas
used, gases dissolved in the feed, efficiency and operation conditions of
the condenser and other process recovery equipment, and physical
properties of the organic constituents. Knowledge of the quantity of air
leaks and dissolved gases in the column in conjunction with information on
organic vapor physical properties and condenser operating parameters
allows estimation of the VOC emissions that may result from a given
distillation unit operation.
The operating parameters for the industry vary to such a great
extent that it is difficult to develop precise emission factors for
distillation units. However, an extensive data base was gathered for
organic chemical industry distillation units. The data base contains
information on operating characteristics, emission controls, exit flows,
and VOC emission character!sties.23 This data base is presented in
Appendix B.
The distillation emission profile contains information on the type
of distillation involved, the produced recovery and VOC control equipment,
the vent stream characteristics, and the other distillation units in the
plant. The vent stream characteristics listed for each column in the
profile (determined downstream of product recovery devices, but upstream
of combustion devices) are: (1) volumetric flow rate, (2) heat content,
(3) VOC emission rate, (4) VOC concentration, and (5) chlorine
concentration. A summary of the distillation emissions profile is
presented in Table 2-5.
2-48
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TABLE 2-5. OVERVIEW OF THE DISTILLATION OPERATIONS
EMISSIONS PROFILE
Operating Characteristics of the D.1 sti 11 atlon Emisslon Prof 11 e
Average offgas flow rate, tifi/min 1.0 (35)
(scfm)
Flow range, m3/roin (scfm) 0.001-18 (0.035-636)
Average VOC emission rate, kg/hr 36 (79)
(Ib/hr), precontrolled3
Average VOC emission rate, kg/hr 5.9 (13)
(Ib/hr), controlled**
VOC emission range, kg/hr (Ib/hr), 0-1,670 (0-3681)
precontrolled
Calculated downstream of adsorbers, absorbers, and condensers, but
upstream of combustion devices.
^Controlled VOC emission rates were estimated using a 98-percent
destruction efficiency for flares, boilers, and incinerators (where it
was indicated that control devices were being used).
2-49
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2.6 REFERENCES
1. Synthetic Organic Chemicals, United States Production and Sales.
U, S, International Trade Commission. USITC Publication 2219.
Washington, D.C. U. S. Government Printing Office. 1989. p. 1,3,
and 4 through 7,
2. Memorandum from Lesh, S. A., Radian Corporation, to Evans, L. B.,
EPA/CPB. June 22, 1984. 13 pp. Revised list of high-volume
reactor process chemicals.
3. Memorandum from Read, B. S., Radian Corporation, to Reactor
Processes File. May 28, 1985. 12 pp. Summary of the emission data
profile.
4. Memorandum from Fidler, K., Radian Corporation, to L. B. Evans,
EPA/CPB. July 6, 1983. 66 pp. Identification of chemical
production routes and unit processes expected to be used in the
future to manufacture the chemicals considered in the Carrier Gas
Project.
5. Urea Manufacturing Industry--Technical Document.
U. S. Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-450/3-81-001. January 1981. p. 3-8.
6. Faith, W., et al. Industrial Chemicals 4th Edition. New York,
John Wiley & Sons. 1975. pp. 129 and 130.
7. Chemical Products Synopsis—Methyl Chloride. Mannsville Chemical
Products. Cortland, New York. May 1984. 2 pp.
8. Herrick, E. C., et al, Mitre Corporation. Unit Process Guide to
Organic Chemical Industries. Ann Arbor, Ann Arbor Science
Publishers, Inc., 1979. pp. Ill, and 120 and 121.
9. Ref. 8.
10. Ref. 3.
11. Waddams, A, L. Chemicals from Petroleum, 4th Edition. Houston,
Gulf Publishing Company. 1978. p. 24, 145 and 146, 173 and 174,
and 221 and 222.
12. Industrial Process Profiles for Environmental Use.
U. S. Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA- 600/2-77-023f. February 1977. pp. 6-637
through 6-641, and 6-667.
13. Cg-Ca Olefins (Dimersol X). Hydrocarbon Processing. 60(11):192.
November 1981.
14. Alpha Olefins. Hydrocarbon Processing. 58(11):128. November 1979.
2-50
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15. C6-Cg Olefins (Dimersol Process). Hydrocarbon Processing.
56(11):170. November 1977.
16. Organic Chemical Manufacturing, Volume 7: Selected Processes.
U. S. Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-450/3-80-028b. December 1980. Section 1-i,
p. III-l to III-4,
17. Ref. 8.
18. Van Winkle, M. Distillation. New York, McGraw-Hill, 1967.
19. Letter from Desai, T., Energy and Environmental Analysis (EEA) to
Beck, D., U. S. Environmental Protection Agency. 12 pp.
August 11, 1980.
20. King, C. J. Separation Processes, Second Edition. New York,
McGraw-Hill, 1980.
21. Foust, A. S., et al. Principles of Unit Operations. New York,
John Wiley & Sons, 1960.
22. Treybal, R. E. Mass Transfer Operations, Third Edition. New York,
McGraw-Hill, 1980,
23. Distillation Operations in Synthetic Organic Chemical Manufacturing
Industry--Background Information for Proposed Standards.
U. S. Environmental Protection Agency, Research Triangle Park, N.C.
Publication No. EPA-450/3-83-005a. December 1983.
2-51
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3.0 EMISSION CONTROL TECHNIQUES
This chapter discusses the volatile organic compound (VOC) emission
control techniques that are applicable to distillation and reactor process
vent streams. The control techniques discussed are grouped into two broad
categories: (1) combustion control devices and (2) recovery devices.
Combustion control devices are designed to destroy the VOC's in the vent
stream prior to atmospheric discharge. Recovery devices limit VOC
emissions by recycling material back through the process.
The design and operating efficiencies of each emission control
technique are discussed in this chapter. The conditions affecting the VOC
removal efficiency of each type of device are examined, along with an
evaluation of their applicability for use to reduce emissions from
distillation vents and reactor vents. Emphasis has been given to
combustion control devices due to their wide applicability for the control
of VOC's in Synthetic Organic Chemical Manufacturing Industry (SOCMI) vent
streams.
3.1 COMBUSTION CONTROL DEVICES
Combustion control devices, unlike noncombustion control devices,
alter the chemical structure of the VOC. Combustion is complete if all
VOC's are converted to carbon dioxide and water. Incomplete combustion
results in some of the VOC being totally unaltered or being converted to
other organic compounds such as aldehydes or acids.
The combustion control devices discussed in the following four
subsections are flares, thermal incinerators, catalytic incinerators, and
boilers/process heaters. Each device is discussed separately with respect
to its operation, destruction efficiency, and applicability to reactor
process and distillation vent streams.
3-1
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3.1.1 Flares
3.1.1.1 nare^Process Description. Flaring is an open combustion
process in which the oxygen required for combustion is provided by the air
around the flame. Good combustion in a flare is governed by flame
temperature, residence time of components in the combustion zone,
turbulent mixing of the components to complete the oxidation reaction, and
the amount of oxygen available for free radical formation.
Flare types can be divided into two main groups: (1) ground flares
and (2) elevated flares, which can be further classified according to the
method to enhance mixing within the flare tip (air-assisted,
steam-assisted, or nonassisted). The discussion in this chapter focuses
on elevated flares, which are the most common type in the chemical
industry. The basic elements of an elevated flare system are shown in
Figure 3-1. The vent stream is sent to the flare through the collection
header (1). The vent stream entering the header can vary widely in
volumetric flow rate, moisture content, VOC concentration, and heat value.
The knock-out drum (2) removes water or hydrocarbon droplets that could
create problems in the flare combustion zone. Vent streams are also
typically routed through a water seal (3) before going to the flare. This
presents possible flame flashbacks, caused when the vent stream flow rate
to the flare is too low and the flame front pulls down into the stack.1
Purge gas (nitrogen [N2], carbon dioxide [C02], or natural gas)
(4) also helps to prevent flashback in the flare stack (5) caused by low
vent stream flow. The total volumetric flow to the flame must be
carefully controlled to prevent low flow flashback problems and to avoid a
detached flame (i.e., a space between the stack and flame with incomplete
combustion), which is caused by an excessively high flow rate. A gas
barrier (6) or a stack seal is sometimes used just below the flare head to
impede the flow of air into the flare gas network.
The VOC stream enters at the base of the flame, where it is heated by
already burning fuel and pilot burners (7) at the flare tip (8). Fuel
flows into the combustion zone, where the exterior of the microscopic gas
pockets is oxidized. The rate of reaction is limited by the mixing of the
fuel and oxygen from the air. If the gas pocket has sufficient oxygen and
3-2
-------
Gas Collection Header
0)
Vent Stream-*.
Knock-out
Drum —'
(2)
Gas Barrier
(6) .
Flare Stack
(5) '
Purge
Gas
Water
Seal-
(3)
Steam Nozzles
(9)
u
Flare Tip
(8)
*— .
v.
x^
1
^J
«•-
L
(7)
Sf
— Steam Une
Snitlon
evice
Air Una
Gas Une
Drain
Figure 3-1. Steam assisted elevated flare system.
3-3
-------
residence time in the flame zone, it can be completely burned. A
diffusion flame receives its combustion oxygen by diffusion of air into
the flame from the surrounding atmosphere. The high volume of flue gas
flow in a flare requires more combustion air at a faster rate than simple
gas diffusion can supply. Thus, flare designers add high velocity steam
injection nozzles (9) to increase gas turbulence in the flame boundary
zones, thus drawing in more combustion air and improving combustion
efficiency. This steam injection promotes smokeless flare operation by
minimizing the cracking reaction that forms carbonaceous soot.
Significant disadvantages of steam use are increased noise and cost. The
steam requirement depends on the composition of the gas flared, the steam
velocity from the injection nozzle, and the tip diameter. Although some
gases can be flared smokelessly without any steam, typically 0.01 to
0.6 kilograms (kg) (0.02 to 1.33 pounds [lb]} of steam per kg of flare gas
is required.
Steam injection is usually controlled manually by an operator who
observes the flare (either directly or on a television monitor) and adds
steam as required to maintain smokeless operation. Several flare
manufacturers offer devices such as infrared sensors, which monitor flame
characteristics and adjust the steam flow rate automatically to maintain
smokeless operation.
Some elevated flares use forced air instead of steam to provide the
combustion air and the mixing required for smokeless operation. These
flares consist of two coaxial flow channels. The combustible gases flow
in the center channel and the combustion air (provided by a fan in the
bottom of the flare stack) flows in the annul us. The principal advantage
of air-assisted flares is that they can be used where steam is not
available. Air assist is rarely used on large flares because air flow is
difficult to control when the gas flow is intermittent. About
67.7 kilowatts (90.8 horse power) of blower capacity is required for each
45.4 kilograms per hour (kg/hr) [100 pounds per hour (lb/hr)] of gas
flared.2
Ground flares are usually enclosed and have multiple burner heads
that are staged to operate based on the quantity of gas released to the
flare. The energy of the gas itself (because of the high nozzle pressure
3-4
-------
drop) is usually adequate to provide the mixing necessary for smokeless
operation and air or steam assistance is not required. A fence or other
enclosure reduces noise and light from the flare and provides some wind
protection.
Ground flares are less numerous and have less capacity than elevated
flares. Typically, they are used to burn gas continuously, while
steam-assisted elevated flares are used to dispose of large amounts of gas
released in emergencies.3
3.1.1.2 Factors Affecting Flare Efficiency.^ Flare combustion
efficiency is a function of many factors: (1) heating value of the gas,
(2) density of the gas, (3) flammability of the gas, (4) auto-ignition
temperature of the gas, and (5) mixing at the flare tip.
The flammability limits of the gases that are flared influence
ignition stability and flame extinction. The flammability limits are
defined as the stoichiometric composition limits (maximum and minimum) of
an oxygen-fuel mixture that will burn indefinitely at given conditions of
temperature and pressure without further ignition. In other words, gases
must be within their flammability limits to burn. When flammability
limits are narrow, the interior of the flame may have insufficient air for
the mixture to burn. Fuels with wide limits of flammability (for
instance, hydrogen) are, therefore, easier to combust.
The auto-ignition temperature of a fuel affects combustion because
gas mixtures must be at high enough temperature and at the proper mixture
strength to burn. A gas with a low auto-ignition temperature will ignite
and burn more easily than a gas with a high auto-ignition temperature.
The heating value of the fuel also affects the flame stability,
emissions, and flame structure. A lower heating value fuel produces a
cooler flame that does not favor combustion kinetics and also is more
easily extinguished. The lower flame temperature will also reduce buoyant
forces, which reduces mixing.
The density of the gas flared also affects the structure and
stability of the flame through the effect on buoyancy and mixing. By
design, the velocity in many flares is very low; therefore, most of the
flame structure is developed through buoyant forces as a result of
combustion. Lighter gases, therefore, tend to burn better. In addition
3-5
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to burner tip design, the density of the fuel also affects the minimum
purge gas required to prevent flashback for smokeless flaring.
Poor mixing at the flare tip or poor flare maintenance can cause
smoking (particulate). Fuels with high cirbon to hydrogen ratios (greater
than 0.35) have a greater tendency to smoke and require better mixing if
they are to be burned smokelessly.
Many flare systems are currently operated in conjunction with
baseload gas recovery systems. Such systems are used to recovery VOC's
from the flare header system for reuse. Recovered VOC's may be used as a
feedstock in other processes or as fuel in process heaters, boilers, or
other combustion devices. When baseload gas recovery systems are applied,
the flare is generally used to combust process upset and emergency gas
releases that the baseload system is not designed to recover. In some
cases, the operation of a baseload gas recovery system may offer an
economic advantage over operation of a flare alone since sufficient
quantities of useable VOC's can be recovered.
3.1.1.3 EPA Flare Specifications. The EPA has established flare
combustion efficiency criteria in the Code of Federal Regulations
(40 CFR 60.18) that specify that 98 percent combustion efficiency can be
achieved provided that certain operating conditions are met: (1) the
flare must be operated with no visible emissions and with a flame present;
(2) the net heating value of the flared stream must be greater than
11.2 megajoules per standard cubic meter (MJ/scm) [300 British thermal
units per standard cubic foot (Btu/scf)] for steam-assisted flares, and
7.45 MJ/scm (200 Btu/scf) for a flare without assist; and (3) steam
assisted and nonassisted flares must have an exit velocity less than
18.3 meters per second (m/sec) [60 feet per second (ft/sec)]. Steam
assisted and nonassisted flares having an exit velocity greater than
18.3 m/sec (60 ft/sec) but less than 122 m/sec (400 ft/sec) can achieve
98 percent control if the net heating value of the gas stream is greater
than 37.3 MJ/scm (1,000 Btu/scf). Air-assisted flares, as well as
steam-assisted and nonassisted flares with an exit velocity less than
122 m/sec (400 ft/sec) and a net heating value less than 37.3 MJ/scm
(1,000 Btu/scf), can determine the allowable exit velocity by using an
equation in 40 CFR 60.18.
3-6
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3.1.1.4 Applicability of Flares. Most of the SOCHI plants are
estimated to have a flare.5 Flares are usually designed to control either
the normal process vents or emergency upsets. The latter involves the
release of large volumes of gases. Often, large diameter flares designed
to handle emergency releases are used to control continuous vent streams
from various process operations. In refineries, many process vents are
usually'combined in a common gas header that supplies fuel to boilers and
process heaters. However, excess gases, fluctuations in flow in the gas
line, and emergency releases are sometimes sent to a flare.
Flares have been found to be useful emission control devices. They
can be used for almost any VOC stream, and can handle fluctuations in VOC
concentration, flow rate, and inerts content. Some streams, such as those
containing high concentrations of halogenated or sulfur-containing
compounds, are not usually flared due to corrosion of the flare tip or
formation of secondary pollutants (such as sulfur dioxide [SOg]).
3.1.2 Thermal Incinerators
3.1.2.1 Thermal Incinerator E)^cj_S4jlescjMBtlp_Q. Any VOC heated to
a high enough temperature in the presence of enough oxygen will be
oxidized to C02 and water. This is the basic principle of operation of a
thermal incinerator. The theoretical temperature required for thermal
oxidation depends on the structure of the chemical involved. Some
chemicals are oxidized at temperatures much lower than others. However, a
temperature can be identified that will result in the efficient
destruction of most VOC's. All practical thermal incineration processes
are influenced by residence time, mixing, and temperature. An efficient
thermal incinerator system must provide:
* A chamber temperature high enough to enable the oxidation
reaction to proceed rapidly to completion;
• Enough turbulence to obtain good mixing between the hot
combustion products from the burner, combustion air, and VOC;
and
• Sufficient residence time at the chosen temperature for the
oxidation reaction to reach completion.
A thermal incinerator is usually a refractory-lined chamber
containing a burner (or set of burners) at one end. As shown in
3-7
-------
Figure 3-2, discrete dual fuel burners (1) and inlets for the offgas (2)
and combustion air (3) are arranged in a premixing chamber (4) to
thoroughly mix the hot products from the burners with the process vent
streams. The mixture of hot reacting gases then passes into the main
combustion chamber (5). This chamber is sized to allow the mixture enough
time at the elevated temperature for the oxidation reaction to reach
completion (residence times of 0.3 to 1.0 second are common). Energy can
then be recovered from the hot flue gases 1n a heat recovery section (6).
Preheating combustion air or offgas is a common mode of energy recovery;
however, it is sometimes more economical to generate steam. Insurance
regulations require that if the waste stream is preheated, the VOC
concentration must be maintained below 25 percent of the lower explosive
limit to remove explosion hazards.
Thermal incinerators designed specifically for VOC incineration with
natural gas as the auxiliary fuel may also use a grid-type (distributed)
gas burner,** as shown in Figure 3-3. The tiny gas flame jets (1) on the
grid surface (2) ignite the vapors as they pass through the grid. The
grid acts as a baffle for mixing the gases entering the chamber (3). This
arrangement ensures burning of all vapors at lower chamber temperature and
uses less fuel. This system makes possible a shorter reaction chamber,
yet maintains high efficiency.
Other parameters affecting incinerator performance are the vent
stream heating value, the water content in the stream, and the amount of
excess combustion air (i.e., the amount of air above the stoichiometric
air needed for reaction). The vent stream heating value is a measure of
the heat available f^om the combustion of the VOC in the vent stream.
Combustion of the vent stream with a heating value less than 1.9 MJ/scm
(50 Btu/scf) usually requires burning auxiliary fuel to maintain the
desired combustion temperature. Auxiliary fuel requirements can be
lessened or eliminated by the use of recuperative heat exchangers to
preheat combustion air. Vent streams with a heating value above
1.9 MJ/scm (50 Btu/scf) may support combustion but may need auxiliary fuel
for flame stability.
Other parameters affecting incinerator performance are the vent
stream heating value, the water content in the stream, and the amount of
3-8
-------
Stack
Waste Gas
Inlet
(2)
Auxiliary ,—i
Fuel Burner —J
(Discrete) I—|
Air ,
Inlet/ Premising
(3) Chamber
Optional Heat
Recovery
(6)
Combustion Chamber
(5)
Figure 3-2. Discrete burner, thermal oxidizer.
3-9
-------
Burner Plots
(2)
Flame Jets
0)
(Natural Gas)
Auxiliary Fuel
Stack
f Fan
w
Optional Heat
Recovery
W
Figure 3-3, Distributed burner, thermal oxidizer.
3-10
-------
excess combustion air (i.e., the amount of air above the stoichiometric
air needed for reaction). The vent stream heating value is a measure of
the heat available from the combustion of the VOC in the vent stream.
Combustion of the vent stream with a heating value less than 1.9 MJ/scm
(SO Btu/scf) usually requires burning auxiliary fuel to maintain the
desired combustion temperature. Auxiliary fuel requirements can be
lessened or eliminated by the use of recuperative heat exchangers to
preheat combustion air. Vent streams with a heating value above
1.9 MJ/scm (SO Btu/scf} may support combustion but may need auxiliary fuel
for flame stability.
A thermal incinerator, handling vent streams with varying heating
values and moisture content, requires careful adjustment to maintain the
proper chamber temperatures and operating efficiency. Since water
requires a great deal of heat to vaporize, entrained water droplets in an
offgas stream can increase auxiliary fuel requirements to provide the
additional energy needed to vaporize the water and raise it to the
combustion chamber temperature. Combustion devices are always operated
with some quantity of excess air to ensure a sufficient supply of oxygen.
The amount of excess air used varies with the fuel and burner type but
should be kept as low as possible. Using too much excess air wastes fuel,
because the additional air must be heated to the combustion chamber
temperature. Large amounts of excess air also increases flue gas volume
and may increase the size and cost of the system. Packaged, single-unit
thermal incinerators can be built to control streams with flow rates in
the range of 8.5 standard cubic meters per second (scm/sec) [300 standard
cubic feet per minute (scfm)] to about 1,415 scm/sec (50,000 scfm).
Thermal oxidizers for halogenated VOC may require additional control
equipment to remove the corrosive combustion products. The halogenated
VOC streams are usually scrubbed to prevent corrosion due to contact with
acid gases formed during the combustion ,of these streams. The flue gases
are quenched to lower their temperature and are then routed through
absorption equipment such as packed towers or liquid jet scrubbers to
remove the corrosive gases.
3.1.2.2 ThermalIncinerator Efficiency. The VOC destruction
efficiency of a thermal oxidizer can be affected by variations in chamber
3-11
-------
temperature, residence time, inlet VOC concentration, compound type, and
flow regime (mixing). Test results show that thermal oxidizers can
achieve 98 percent destruction efficiency for most VOC's at combustion
chamber temperatures ranging from 700 to 1,300 °C (1,300 to 2,370 °F) and
residence times of 0.5 to 1.5 sec.? These data indicate that significant
variations in destruction efficiency occurred for Cj to C§ alkanes and
olefins, aromatics (benzene, toluene, and xylene), oxygenated compounds
(methyl ethyl ketone and isopropanol), chlorinated organics (vinyl
chloride), and nitrogen-containing species (acrylonitrile and ethylamines)
at chamber temperatures below 760 °C (1,400 °F). This information, used
in conjunction with kinetics calculations, indicates the combustion
chamber parameters for achieving at least a 98-percent VOC destruction
efficiency are a combustion temperature of 870 °C (1,600 °F) and a
residence time of 0.75 sec (based upon residence in the chamber volume at
combustion temperature). A thermal oxidizer designed to produce these
conditions in the combustion chamber should be capable of high destruction
efficiency for almost any nonhalogenated VOC.
At temperatures over 760 °C (1,400 °F), the oxidation reaction rates
are much faster than the rate of gas diffusion mixing. The destruction
efficiency of the VOC then becomes dependent upon the fluid mechanics
within the oxidation chamber. The flow regime must ensure rapid, thorough
mixing of the VOC stream, combustion air, and hot combustion products from
the burner. This enables the VOC to attain the combustion temperature in
the presence of enough oxygen for sufficient time so the oxidation
reaction can reach completion.
Based on studies of thermal oxidizer efficiency, it has bien
concluded that 98 percent VOC destruction or a 20 parts per million volume
(ppmv) compound exit concentration is achievable by all new incinerators.
The maximum achievable VOC destruction efficiency decreases with
decreasing inlet concentration because of the much slower combustion
reaction rates at lower inlet VOC concentrations. Therefore, a VOC weight
percentage reduction based on the mass rate of VOC exiting the control
device versus the mass rate of VOC entering the device would be
appropriate for vent streams with VOC concentrations above approximately
2,000 ppmv (corresponding to 1,000 ppmv VOC in the incinerator inlet
3-12
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stream since air dilution is typically 1:1). For vent streams with VOC
concentrations below approximately 2,000 ppmv, it has been determined that
an incinerator outlet concentration of 20 ppmv (by compound), or lower, is
achievable by all new thermal oxidizers.8 The 98-percent efficiency
estimate is predicated on thermal incinerators operated at 870 K
(1,600 °F) with 0.75 sec residence time.
3.1.2.3 Applicability of Thermal Incinerators. In terms of
technical feasibility, thermal incinerators are applicable as a control
device for most SOCMI vent streams. They can be used for vent streams
with any VOC concentration and any type of VOC, and they can be designed
to handle minor fluctuations in flows. However, excessive fluctuations in
flow (i.e., process upsets) might not allow the use of incinerators and
would require the use of a flare. Presence of elements such as halogens
or sulfur might require some additional equipment, such as scrubbers for
acid gas removal. Thermal incinerators are currently used to control VOC
emissions from a number of process operations, including reactors and
distillation operations.
3.1.3 Industrial Boilers/Process Heaters
Industrial boilers and process heaters can be designed to control
VOC's by incorporating the reactor process or distillation vent stream
with the inlet fuel or by feeding the stream into the boiler or heater
through a separate burner. The major distinctions between industrial
boilers and process heaters are that the former produces steam at high
temperatures while the latter raises the temperature of process streams as
well as superheating steam, typically at temperatures lower than with an
industrial boiler. The process descriptions for an industrial boiler and
a process heater are presented separately in the following two sections.
The process descriptions focus on those aspects that relate to the use of
these combustion devices as a VOC control method.
3.1.3.1 Industrial Boiler/Process Description. Surveys of
industrial boilers show that the majority of industrial boilers used in
the chemical industry are of watertube design. Furthermore, over half of
these boilers use natural gas as a fuel.9 In a water tube boiler, hot
combustion gases contact the outside of heat transfer tubes, which contain
hot water and steam. These tubes are interconnected by a set of drums
3-13
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that collect and store the heated water and steam. The water tubes are of
relatively small diameter, 5 centimeters (2.0 inches), providing rapid
heat transfer, rapid response to steam demands, and relatively high
thermal efficiency.*u Energy transfer from the hot flue gases to water in
the furnace water tube and drum system can be above 85 percent efficient.
Additional energy can be recovered from the flue gas by preheating
combustion air in an air preheater or by preheating incoming boiler feed
water in an economizer unit.
When firing natural gas, forced or natural draft burners are used to
thoroughly mix the incoming fuel and combustion air. If a SOCHI vent
stream is combusted in a boiler, it can be mixed with the incoming fuel or
fed to the furnace through a separate burner. In general, burner design
depends on the characteristics of either the fuel mix (when the SOCMI vent
stream and fuel are combined) or on the characteristics of the vent stream
alone (when a separate burner is used). A particular burner design,
commonly known as a high intensity or vortex burner, can be effective for
vent streams with low heating values (i.e., streams where a conventional
burner may not be applicable). Effective combustion of low heating value
streams is accomplished in a high intensity burner by passing the
combustion air through a series of spin vanes to generate a strong vortex.
Furnace residence time and temperature profiles vary for industrial
boilers depending on the furnace and burner configuration, fuel type, heat
input, and excess air level.H A mathematical model has been developed
that estimates the furnace residence time and temperature profiles for a
variety of industrial boilers.12 This model predicts mean furnace
residence times of from 0.25 to 0.83 second for natural gas-fired water
tube boilers in the size range from 4.4 to 44 megawatts (MM) (15 to
150 x ID6 Btu/hr). Boilers at or above the 44 MW size have residence
times and are generally operated at temperatures that ensure a 98-percent
VOC destruction efficiency. Furnace exit temperatures for this range of
boiler sizes are at or above 1,200 °C (2,200 °F) with peak furnace
temperatures occurring in excess of 1,540 °C (2,810 °F).
3.1.3.2 Process Heater Description. A process heater is similar to
an industrial boiler in that heat liberated by the combustion of fuels is
transferred by radiation and convection to fluids contained in tubular
3-14
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coils. Process heaters are used in chemical manufacturing to drive
endothermic reactions, such as natural gas reforming and thermal cracking.
They are also used as feed preheaters and as reboilers for some
distillation operations. The fuels used in process heaters include
natural gas, refinery offgases, and various grades of fuel oil. Gaseous
fuels account for about 90 percent of the energy consumed by process
heaters.l^
There are many variations in the design of process heaters depending
on the application considered. In general, the radiant section consists
of the burner(s), the firebox, and a row of tubular coils containing the
process fluid. Most heaters also contain a convection section in which
heat is recovered from hot combustion gases by convective heat transfer to
the process fluid.
Process heater applications in the chemical industry can be broadly
classified with respect to firebox temperature: (1) low firebox
temperature applications, such as feed preheaters and reboilers;
{2) medium firebox temperature applications, such as stream superheaters;
and (3) high firebox temperature applications, such as pyrolysis furnaces
and steam-hydrocarbon reformers. Firebox temperatures within the chemical
industry can range from about 400 °C {750 °F) for preheaters and reboilers
to 1,260 OC {2,300 op) for pyrolysis furnaces.
3.1.3.3 Industrial Boilers and Process Heater Control Efficiency. A
boiler or process heater furnace can be compared to an incinerator where
the average furnace temperature and residence time determines the
combustion efficiency. However, when a vent gas is injected as a fuel
into the flame zone of a boiler or process heater, the required residence
time is reduced due to the relatively high flame zone temperature. The
following test data, which document the destruction efficiencies for
industrial boilers and process heaters, are based on injecting the wastes
identifiid Into the flame zone of each combustion control device.
A U. S. EPA-sponsored test was conducted to determine the destruction
efficiency of an industrial boiler for polychlorinated biphenyls
(PCB's).l* The results of this test indicated that the PCB destruction
3-15
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efficiency of an oil-fired industrial boiler firing PCB-spiked oil was
greater than 99 percent for a temperature range of 1,361 to 1,520 °C
(2,482 to 2,770 °F) and a range of residence time of 2 to 6 sec. This
efficiency was determined based on the PCB content measured by a gas
chromatograph in the fuel feed and flue gas.
As discussed in previous sections, firebox temperatures for process
heaters show relatively wide variations depending on the application (see
Section 3.1.3.2). Tests were conducted by the EPA to determine the
benzene destruction efficiency of five process heaters firing a benzene
offgas and natural gas mixture.15-17 jne units tested are representative
of process heaters with low temperature fireboxes (reboilers) and medium
temperature fireboxes (superheaters). Sampling problems occurred while
testing one of these heaters, and, as a result, the data for that test may
not be reliable and are not presented.1% The reboiler and superheater
units tested showed greater than a 98-percent overall destruction
efficiency for Cj to C$ hydrocarbons.^ Additional tests conducted on a
second superheater and a hot oil heater showed that greater than
99 percent overall destruction of Cj to Cg hydrocarbons occurred for both
units.20
3.1.3,4 Applicability of Industrial Boilers and Process Heaters.
Industrial boilers and process heaters are currently used by industry to
combust process vent streams from distillation operations, reactor
operations, and general refinery operations. These devices are most
applicable where high vent stream heat recovery potential exists.
Both boilers and process heaters are essential to the operation of a
plant. As a result, only streams that are certain not to reduce the
device's performance or reliability warrant use of a boiler or process
heater as a combustion control device. Variations in vent stream flow
rate and/or heating value could affect the heat output or flame stability
of a boiler or process heater and should be considered when using these
combustion devices. Performance or reliability may be affected by the
presence of corrosive products in the vent stream. Because these
compounds could corrode boiler or process heater materials, vent streams
with a relatively high concentration of halogenated or sulfur-containing
compounds are usually not combusted in boilers or process heaters. When
3-16
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corrosive VOC's are combusted, the flue gas temperature must be maintained
above the acid dew point to prevent acid deposition and subsequent
corrosion from occurring.
The introduction of a vent stream into the furnace of a boiler or
heater could alter the heat transfer characteristics of the furnace. Heat
transfer characteristics are dependent on the flow rate, heating value,
and elemental composition of the vent stream, and the size and type of
heat generating unit being used. Often, there is no significant
alteration of the heat transfer, and the organic content of the process
vent stream can, in some cases, reduce the amount of fuel required to
produce the desired heat. In other cases, the change in heat transfer
characteristics after introduction of a vent stream may affect the
performance of the heat-generating unit, and increase fuel requirements.
For some vent streams, there may be potential safety problems associated
with ducting reactor process or distillation vents to a boiler or process
heater. Variation in the flow rate and organic content of the vent stream
could, in some cases, lead to explosive mixtures within a boiler furnace.
Flame fluttering within the furnace could also result from variations in
the process vent stream characteristics. Precautionary measures should be
considered in these situations.
When a boiler or process heater is applicable and available, they are
excellent control devices providing at least 98 percent destruction of
VOC's. In addition, near complete recovery of the vent stream heat
content is possible. However, both devices must operate continuously and
concurrently with the pollution source unless an alternate control
strategy is available in the event that the heat generating capacity of
either unit is not required and is shut down.
3.1.4 Catalytic Oxidizers
3.1.4.1 Catalytic Oxidation Process Description. Catalytic
oxidation is the fourth major combustion technique examined for VOC
emission control. A catalyst increases the rate of chemical reaction
without becoming permanently altered itself. Catalysts for catalytic
oxidation cause the oxidizing reaction to proceed at a lower temperature
than is required for thermal oxidation. These units can also operate well
at VOC concentrations below the lower explosive limit, which is a distinct
3-17
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advantage for some process vent streams. Combustion catalysts include
pal adiurn and platinum group metals, magnesium oxide, copper oxide,
chromium, and cobalt.21 These are deposited in thin layers on inert
substrates to provide for maximum surface area between the catalyst and
the VOC stream. The substrate may be either pelletized or cast in a rigid
honeycomb matrix.
A schematic of a catalytic oxidation unit is shown in Figure 3-4.
The waste gas (1) is introduced into a mixing chamber (2), where it is
heated to about 316 °C (600 °F) by contact with the hot combustion
products from auxiliary burners (3). The heated mixture is then passed
through the catalyst bed (4). Oxygen and VOC's migrate to the catalyst
surface by gas diffusion and are adsorbed in the pores of the catalyst.
The oxidation reaction takes place at these active sites. Reaction
products are desorbed from the active sites and transferred by diffusion
back into the waste gas.22 The combusted gas may then be passed through a
waste heat recovery device (5) before exhausting into the atmosphere.
The operating temperatures of combustion catalysts usually range from
260 to 427 °C (500 to 800 °F). Lower temperatures may slow down and
possibly stop the oxidation reaction. Temperatures greater than 732 °C
(1,350 °F) may result in shortened catalyst life and possible
deterioration of the catalyst. Any accumulation of particulate matter,
condensed VOC, or polymerized hydrocarbons on the catalyst could block the
active sites and, therefore, reduce effectiveness. Some catalysts can
also be deactivated by compounds containing sulfur, bismuth, phosphorous,
arsenic, antimony, mercury, lead, zinc, tin, or halogens.23 if the
catalyst is exposed to any of these compounds, VOC's will pass through
unreacted or be partially oxidized to form compounds such as aldehydes,
ketones, and organic acids. Catalysts are now being marketed that are
resistant to various poisons, specifically sulfur and halogenated
compounds. Other designs incorporate a sacrificial bed to protect the
catalyst. Materials accumulated on the catalyst can be removed by
physical or chemical means, thus restoring the catalyst activity to its
original (fresh) level. Condensed organics accumulated on the catalyst
can be removed with thermal treatment.
3-18
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Auxiliary Fuel
Burners
(3)
Waste Gas
(1)
Auxiliary Fuel
Burners
Catalyst Bed
Mixing Chamber
(2)
To Atmosphere
Stack
Optional Heat
Recovery
(5}
Figure 3-4, Catalytic oxidizer.
3-19
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3.1.4.2 Catalytic Oxidizer Control Efficiency. Catalytic oxidizer
destruction efficiency is dependent on the space velocity (i.e, the
catalyst volume required per unit volume gas processed per hour),
operating temperature, oxygen concentration, and waste gas VOC composition
and concentration. A catalytic unit operating at about 450 °C (840 °F)
with a catalyst bed volume of 0.014 to 0.057 cubic meters (0.5 to 2 cubic
feet) per 0.47 son/sec (1,000 scfm) of vent stream passing through the
device can achieve 95 percent VOC destruction efficiency. However,
catalytic oxidizers have been reported to achieve efficiencies of
99 percent or greater.24 These higher efficiencies are usually obtained
by increasing the catalyst bed volume-to-vent stream flow ratio.
3.1.4.3 Applicability ofCatalytic Oxidizers. Catalytic oxidation
has been successfully applied to a variety of SOCHI processes.25 it is
basically a chemical process that operates at a lower temperature than
thermal oxidation, thereby reducing fuel consumption. In addition,
catalytic oxidation produces smaller amounts of secondary air emissions
such as nitrous oxides and carbon dioxide than thermal incinerators. High
destruction efficiencies have been achieved through catalytic oxidation,
partly because the SOCMI exhausts are generally very clean and suitable
for this technology. The SOCMI industry has been accustomed to using a
variety of process catalysts and is skilled in understanding and
maintaining catalytic systems at maximum performance.
Periodic replacement of catalyst is required at intervals of 2 to
5 years due to thermal aging, masking, and poisoning processes. Thermal
aging is caused by high temperatures damaging the active metal, sintering,
or crystallizing the surface area. This results in permanent loss of
surface area. Masking occurs when there is a loss of active sites due to
a buildup of dust, carbons, or resins, which plug the catalyst's pores.
This process is reversible; the catalyst can be cleaned off periodically
with a caustic solution and restored. Poisoning occurs when an active
site is taken up by contaminants and usually results in permanent loss of
catalyst. Because of the sensitivity of catalytic oxidizers to VOC inlet
stream flow conditions, the applicability of catalytic units for control
of VOC's in the SOCMI industry is limited, particularly for halogenated
streams.
3-20
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3.2 RECOVERY DEVICES
The recovery devices discussed in this section include adsorbers,
absorbers, and condensers. These devices are generally applied to recover
reactant, product, or by-product VOC's from a vent stream for use as a
product or to recycle a compound. The chemical structure of the VOC
removed is usually unaltered.
3.2.1 Adsorption
3.2.1.1 Adsorption Process Description. Adsorption is a
mass-transfer operation involving interaction between gaseous- and
solid-phase components. The gas phase (adsorbate) is captured on the
solid-phase (adsorbent) surface by physical or chemical adsorption
mechanisms. Physical adsorption is a mechanism that takes place when
intermolecular (van der Waals) forces attract and hold the gas molecules
to the solid surface.26 Chemisorption occurs when a chemical bond forms
between the gaseous- and solid phase molecules. A physically adsorbed
molecule can readily be removed from the adsorbent (under suitable
temperature and pressure conditions), while the removal of a chemisorbed
component is much more difficult.
The most commonly encountered industrial adsorption systems use
activated carbon as the adsorbent. Activated carbon is effective in
capturing certain organic vapors by the physical adsorption mechanism. In
addition, the vapors may be released for recovery by regeneration of the
adsorption bed with steam or nitrogen. Oxygenated adsorbents, such as
silica gels, diatomaceous earth, alumina, or synthetic zeolites, exhibit a
greater selectivity than activated carbon for capturing water vapor rather
than organic gases. Thus, these adsorbents would be of little use for the
high moisture gas streams characteristic of some SOCHI vents.27
The design of a carbon adsorption system depends on the chemical
characteristics of the VOC's being recovered, the physical properties of
the offgas stream (i.e., temperature, pressure, and volumetric flow rate),
and the physical properties of the adsorbent. The mass quantity of VOC's
that adhere to the adsorbent surface is directly proportional to the
difference in VOC concentration between the gas-phase and the solid
surface. In addition, the quantity of VOC's adsorbed is dependent on the
adsorbent bed volume, the surface area of adsorbent available to capture
3-21
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VOC's, and the rate of diffusion of VOC's through the gas film at the gas-
and solid-phase interface. Physical adsorption is an exothermic operation
that is most efficient within a narrow range of temperature and pressure.
A schematic diagram of a typical fixed bed, regenerative carbon
adsorption systems is given in Figure 3-5. The process offgases are
generally filtered and cooled (1) before entering the carbon bed. The
inlet gases to an adsorption unit are filtered to prevent bed
contamination. The gas is cooled to maintain the bed at optimum operating
temperature and to prevent fires or polymerization of the hydrocarbons.
Vapors entering the adsorber stage of the system (2) are passed through
the porous activated carbon bed.
Adsorption of inlet vapors •sually occurs until the outlet VOC
concentration reaches some preset level (the "breakthrough"
concentration). The dynamics of the process may be illustrated by viewing
the carbon bed as a series of layers or mass-transfer zones (3a, b, c).
Gases entering the bed are adsorbed first in zone (a). Because most of
the VOC is adsorbed in zone (a), very little adsorption takes place in
zones (b) and (c). Adsorption in zone (b) increases as zone (a) reaches
equilibrium with organics and proceeds through zone (c). When the bed is
completely saturated (breakthrough), the incoming VOC-laden offgases are
routed to an alternate bed, while the saturated carbon bed is regenerated.
Regeneration of the carbon bed is accomplished by heating the bed or
applying vacuum to draw off the adsorbed gases. Low pressure steam (4) is
frequently used as a heat source to strip the adsorbent of organic vapor.
After steaming, the carbon bed is cooled-and dried typically by blowing
air through it with a fan; the steam-laden vapors are routed to a
condenser (5) and on to a solvent recovery system (6). The regenerated
bed is put back into active service, while the saturated bed is purged of
organics. The regeneration process may be repeated numerous times, but
eventually the carbon must be replaced.
3.2.1,2 Adsorption Control Efficiency. Hany modern, well-designed
systems achieve 95 percent removal efficiency for some chemicals.28 The
VOC removal efficiency of an adsorption unit Is dependent upon the
physical properties of the compounds present in the offgas, the gas stream
3-22
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VOC-Laden
Vent Stream
Fan
Low
Pressure (4)
Steam
Closed
Open
Vent to
Atmosphere
Adsorber 1
(Adsorbing)
Open
Steam
, Closed
Adsorber 2
(Regenerating)
(5)
Condenser
Decanter and/or
Distilling Tower
(6)
Recovered
Solvent
Water
Figure 3-5. Two stage regenerative adsorption system.
3-23
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characteristics, the physical properties of the adsorbent, and the
condition of the regenerated carbon bed.
Gas temperature, pressure, and velocity are important in determining
adsorption unit efficiency. The adsorption rate in the bed decreases
sharply when gas temperatures are above 38 °C (100 opj.29,30 nigh
temperature increases the kinetic energy of the gas molecules, causing
them to overcome van der Haals forces. Under these conditions, the VOC's
are not retained on the surface of the carbon. Increasing vent stream
pressure and temperature generally will improve VOC capture efficiency;
however, care roust be taken to prevent solvent condensation and possible
fire.
3.2.1.3 Applicability of Adsorption. Although carbon adsorption is
an excellent method for recovering some valuable process chemicals, it
cannot be used as a universal control method for distillation or reactor
process vent streams. The conditions where carbon adsorption is not
recommended are present in many SOCMJ vent streams. These include streams
with: (1) high VOC concentrations, (2) very high or low molecular weight
compounds, and (3) mixtures of high and low boiling point VOC's.
The range of organic concentrations to which carbon adsorption safely
can be applied is from only a few parts per million to concentrations of
several percent.31 Adsorbing vent streams with high organic concentration
may result in excessive temperature rise in the carbon bed due to the
accumulated heat of adsorption of the VOC loading. However, streams with
high organic concentrations can be diluted with air or inert gases to make
a workable adsorption system.
The molecular weight of the compounds to be adsorbed should be in the
range of 45 to 130 grams per gram-mole (gm/gm-mole) (45 to 130 pounds per
pound-mole [lb/lb-mole]) for effective adsorption. Carbon adsorption may
not be the most effective application for compounds with low molecular
weights (below 45 gm/gm-mole [45 lb/lb-mole]) due to their smaller
attractive forces, or for high molecular weight components (above
130 gm/gm-mole [130 lb/lb-mole]), which attach so strongly to the carbon
bed that they are not easily removed.32
Properly operated adsorption systems can be very effective for
homogenous offgas streams but can have problems with a multicomponent
3-24
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system containing a mixture of light and heavy hydrocarbons. The lighter
organics tend to be displaced by the heavier (higher boiling) components,
greatly reducing system efficiency.33
3.2.2 Absorption
3.2.2.1 Absorption Process Description. The mechanism of absorption
consists of the selective transfer of one or more components of a gas
mixture into a solvent liquid. The transfer consists of solute diffusion
and dissolution into a solvent. For any given solvent, solute, and set of
operating conditions, there exists an equilibrium ratio of solute
concentration in the gas mixture to solute concentration in the solvent.
The driving force for mass transfer at a given point in an operating
absorption tower is related to the difference between the actual
concentration ratio and the equilibrium ratio.34 Absorption may only
entail the dissolution of the gas component into the solvent or may also
involve chemical reaction of the solute with constituents of the
solution.35 The absorbing liquids (solvents) used are chosen for high
solute (VOG) solubility and include liquids such as water, mineral oils,
nonvolatile hydrocarbon oils, and aqueous solutions of oxidizing agents
(e.g., sodium carbonate and sodium hydroxide).36
Devices based on absorption principles include spray towers, venturi
and wet impingement scrubbers, packed columns, and plate columns. Spray
towers require high atomization pressure to obtain droplets ranging in
size from 500 to 100 micrometers (/m) (0,019 to 0.004 in.) in order to
present a sufficiently large surface contact area.37 Although they can
remove particulate matter effectively, spray towers have the least
effective mass transfer capability and, thus, are restricted to
particulate removal and control of high-solubility gases such as sulfur
dioxide and ammonia.38 Venturi scrubbers have a high degree of gas-liquid
mixing and high particulate removal efficiency but also require high
pressure and have relatively short contact times. Therefore, their use is
also restricted to high-solubility gases.39 As a result, VOC control by
gas absorption is generally accomplished in packed or plate columns.
Packed columns are mostly used for handling corrosive materials,
liquids with foaming or plugging tendencies, or where excessive pressure
drops would result from use of plate columns. They are less expensive
3-25
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than plate columns for small-scale or pilot plant operations where the
column diameter is less than 0.6 ra (2 ft). Plate columns are preferred
for large-scale operations, where internal cooling is desired or where low
liquid flow rates would inadequately wet the packing.40
A schematic of a packed tower is shown 1n Figure 3-6. The gas to be
absorbed is introduced near the bottom of the tower (1) and allowed to
rise through the packing material (2). Solvent flows in from the top of
the column, countercurrent to the vapors (3), absorbing the solute from
the gas-phase and carrying the dissolved solute out of the tower (4).
Cleaned gas exits at the top (5) for release to the atmosphere or for
further treatment as necessary. The solute-rich liquid is generally sent
to a stripping unit where the absorbed VOC's are recovered. Following the
stripping operation, the absorbing solution is either recycled back to the
absorber or sent to a water treatment facility for disposal.
The major tower design parameters to be determined for absorbing any
substance are column diameter and height, system pressure drop, and liquid
flow rate required. These parameters are derived by considering the waste
gas solubility, viscosity, density, and concentration, all of which depend
on column temperature; and also the total surface area provided by the
tower packing material, and the quantity of gases to be treated.
3.2.2.2 Absorption Control Efficiency. The VOC removal efficiency
of an absorption device 1s dependent on the solvent selected, and on
proper design and operation. For a given solvent and solute, an increase
in absorber size or a decrease In the operating temperature can increase
the VOC removal efficiency of the system. It may be possible In some
cases to increase VOC removal efficiency by a change in the absorbent.
Systems that use organic liquids as solvents usually include the
stripping and recycling of the solvent to the absorber. In this case, the
VOC removal efficiency of the adsorber is dependent on the solvent's
stripping efficiency.
3.2.2.3 Applicablllty of Absorptlon. Absorption 1s an attractive
control option if a significant amount of VOC's can be recovered for
reuse. Although absorption is applicable for many SOCMI vent streams, it
cannot be universally applied. It is usually not considered when the VOC
concentration is below 200 to 300 ppmv.41
3-26
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Absorbing
Liquid In
(5) Cleaned Gas Out
To Final Control Device
or to Atmosphere
(4)
Absorbing Liquid
with VCC Out
To Disposal or VOC/Sofvent Recovery
d) VOC Laden
Gas In
Figure 3-6. Packed tower for gas absorption.
3-27
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3.2,3 Condensation
3.2.3.1 Condensation Process Description. Condensation is a process
of converting all or part of the condensable components of a vapor phase
into a liquid phase. This is achieved by the transfer of heat from the
vapor phase to a cooling medium. If only a part of the vapor phase is
condensed, the newly formed liquid phase and the remaining vapor phase
will be in equilibrium. In this case, equilibrium relationships at the
operating temperatures must be considered. The heat removed from the
vapor phase should be sufficient to lower the vapor-phase temperature to
at or below its dew point temperature (i.e, temperature at which first
drop of liquid is formed).
Condensation devices are of two types: surface condensers and
contact condensers.42 Surface condensers are typically shell-and-tube
type heat exchangers. The coolant and the vapor phases are separated by
the tube wall, and they never come in direct contact with each other. As
the coolant passes through the tubes,the VOC vapors condense outside the
tubes and are recovered. Surface condensers require more auxiliary
equipment for operation but can recover valuable VOC's without
contamination by the coolant, thus minimizing waste disposal problems.
Only surface condensers are considered in the discussion of control
efficiency and applicability since they are used more frequently in the
chemical industry.
The major equipment components used in a typical surface condenser
system for VOC removal are shown in Figure 3-7. This system includes a
dehumidifier (1), surface condenser exchanger (2), refrigeration unit (3),
and VOC storage tanks and operation pumps (4). Most surface condensers
use a shell-and-tube type heat exchanger to remove heat from the vapor.*3
The coolant selected depends upon the saturation temperature of the VOC
stream. Chilled water can be used down to 7 °C (45 °F), brines to -34 °C
(-30 °F), and chlorofluorocarbons below -34 °C (-30 °F).4* Temperatures
as low as -62 °C (-80 °F) may be necessary to condense some VOC streams.*5
3.2.3.2 Condenser Control Efficiency. The VOC removal efficiency of
a condenser is dependent upon the type of vapor stream entering the
condenser, and on condenser operating parameters. Efficiencies of
condensers usually vary from 50 to 95 percent,^ with higher efficiencies
3-28
-------
Cleaned Gas Out
To Primary Control Flare,
Afterburner, Etc.
VOC Laden
Gas
Dehumidlfication
Unit
To Remove Water
and
Prevent Freezing
In Main Condenser
, % ^~/,,.,^..
-.vv. *,fsffWf.-.wXvJ*&Sf4&ff..^
. Main Condenser?*' \ (2)
woe
Ret
i
lorn f
urn
Refrigeration
Unit
(3)
Coolant-
Condensed
VOC
To Process
• Or Disposal
Figure 3-7. Condensation system.
3-29
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expected for streams with low flow rates (less than 2,000 cubic feet per
minute) and high VOC concentrations (greater than 5,000 ppmv).
3.2.3.3 AppJJcjbi11ty of Condensers. A primary condenser system is
usually an integral part of most distillation operations. Primary
condensers are needed to provide reflux in fractionating columns and to
recover distilled products. At times additional (secondary) condensers
are used to recover more VOC's from the vent stream exiting the primary
condenser. Condensers are sometimes present as accessories to vacuum
generating devices {e.g., barometric condensers). Condensers are also
commonly used product recovery devices on reactor process vent streams.
The use of a secondary condenser to control VOC emissions may not be
applicable to some vent streams. Secondary condensers used as
supplemental product recovery devices are not well suited for vent streams
containing VOC's with low boiling points or for vent streams containing
large quantities of inerts such carbon dioxide, air, and nitrogen. Low
boiling point VOC's and inerts contribute significantly to the heat load
that must be removed from the vent stream, resulting in costly design
specifications and/or operating costs. In addition, some low boiling
point VOC's cannot be condensed at normal operating temperatures. For
example, process units producing chlorinated methanes have vent streams
with substantial amounts of methane, methyl chloride, and methylene
chloride. These compounds are not readily condensed and, as a result, are
usually vented to the atmosphere or destroyed in a combustion device.
However, some difficult-to-condense vapors can be compressed upstream of
the condenser, thereby making them easier to recover in the condenser.
3.3 SUMMARY
The two general classifications of VOC control techniques discussed
in the preceding sections are combustion and noncombustion control
devices. This section summarizes the major points regarding control
device applicability and performance.
The combustion control devices considered were flares, industrial
boilers, process heaters, thermal incinerators, and catalytic oxidizers.
With the exception of catalytic units, these devices are applicable to a
wide variety of process vent stream characteristics and can achieve at
least 98-percent destruction efficiency. Combustion devices are generally
3-30
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capable of adapting to moderate changes In process vent stream flow rate
and VOC concentration, while control efficiency is not greatly affected by
the type of VOC's present. This is generally not the case with
noncombustion control devices. In general, combustion control devices may
require additional fuel, except in some cases where boilers or process
heaters are applied and the energy content of the vent stream is
recovered. Since boilers and process heaters are important in the
operation of a chemical plant, only process vent streams that will not
reduce boiler or process heater performance and reliability warrant use of
these systems. Application of a scrubber prior to atmospheric discharge
may be required when process vent streams containing high concentrations
of halogenated or sulfonated compounds are combusted in an enclosed
combustion device. The presence of high concentrations of corrosive
halogenated or sulfonated compounds may preclude the use of flares because
of possible flare tip corrosion and may preclude the use of boilers and
process heaters because of potential internal boiler corrosion.^ The
presence of a halogen acid, such as hydrogen chloride, in the atmosphere
may cause adverse health effects and equipment corrosion.
The noncombustion control devices discussed include adsorbers,
absorbers, and condensers. In general, although noncombustion devices are
widely applied in the Industry, no one device is universally applicable to
SOCHI vent streams because of the many restrictions applying these devices
across a broad category of reactor process and distillation operation vent
streams. For example, adsorbers may not always be applicable to vent
streams with: (1) high VOC concentrations, (2) low molecular weight, and
(3) mixtures of low and high molecular weight compounds. These conditions
exist in many reactor process vent streams. Absorbers are generally not
applied to streams with VOC concentrations below 200 to 300 ppmv, while
condensers are not well suited for application to vent streams containing
low boiling point VOC's or to vent stream with large inert concentrations.
Even though these restrictions exist, many condensers and absorbers are
applied to distillation and reactor process vent streams in the SOCHI to
recover VOC's. Control efficiencies for the noncombustion devices
considered vary from 50 to g5 percent for condensers and absorbers and up
to 95 percent for adsorbers.
3-31
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3.4 REFERENCES
1. Blackburn, J. W., et al. (IT Enviroscience, Inc.), Organic
Chemical Manufacturing Series Volume 4: Combustion Control
Devices. Prepared for the U. S. Environmental Protection
Agency. Research Triangle Park, N.C. Publication No, EPA-
450/3-80-026. December 1980. 67 pp.
2. Klett, M. G. and J. B. Galeski (Lockheed Missiles and Space Co.,
Inc.). Flare Systems Study. Prepared for U. S. Environmental
Protection Agency. Huntsville, AL. Publication No. EPA-
600/2-76-079. March 1976. pp. ia, 22, 27, and 71 through 75.
3. D. Joseph, et al. (Energy and Environmental Research
Corporation). Evaluation of the Efficiency of Industrial
Flares: Background- Experimental Design-Facility. Prepared for
the U. S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-600/2-83-070. August 1983.
Abstract page only.
4. Ref. 1.
5. Letter from Matey, J. S., Chemical Manufacturers Association, to
Beck, D., U. S. Environmental Protection Agency. 14 pp.
November 25, 1981.
6. North American Manufacturing Company. North American Combustion
Handbook, Second Edition. Cleveland, Ohio. 1979. p. 269.
7. Memorandum and attachments from Farmer, J. R., EPA/ESD to
Distribution. 30 pp. August 22, 1980. Thermal incinerators
and flares.
8. Ref. 7.
9. Devitt, T., et al. (PEDCo Environmental, Inc.). Population and
Characteristics of Industrial Boilers in the U.S. Prepared for
the U. S. Environmental Protection Agency, Washington, D.C.
Publication No. EPA-600/7-79-178a. August.1979.
10. Fossil Fuel Fired Industrial Boilers - Background Information
Document, Volume 1: Chapters 1-9. Draft EIS.
U, S. Environmental Protection Agency. Research Triangle Park,
N.C. Publication No. EPA-450/3-82-006a. March 1982. p. 3-27
and technical report data sheet.
11. C. Castaldini, et al. (Acurex Corporation). A Technical
Overview of the Concept of Disposing of Hazardous Wastes in
Industrial Boilers. Prepared for the U. S. Environmental
Protection Agency. Cincinnati, Ohio. EPA Contract No. 68-03-
2567. October 1981. pp. 44 and 73.
12. Ref. 11, p. 73.
3-32
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13. Hunter, S. C. and S. C. Cherry (KVB.) NOX Emissions from
Petroleum Industry Operations. Washington, D.C. API
Publication No. 4311. October 1979. p. 83.
14. J. Hall, et al. (GCA Technology Division). Evaluation of PCB
Destruction Efficiency in an Industrial Boiler. Prepared for
the U. S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-600/2-81-055a. April 1981. pp.
4 through 10, 117 through 128, and 161.
15. M. W. Hartman and C. W. Stackhouse (TRW Environmental
Engineering Division). Benzene—Organic Chemical Manufacturing
Emission Test Report, Ethyl benzene/Styrene, Amoco Chemicals
Company, Texas City, Texas. Prepared for U. S. Environmental
Protection Agency. Research Triangle Park, N.C. EHB Report
No. 79-OCM-13. August 1979.
16. W. Kelly (TRW Environmental Engineering Division). Benzene
Organic Chemical Manufacturing Ethylbenzene/Styrene Test Report,
El Paso Products Company, Odessa, Texas. Prepared for the
U. S. Environmental Protection Agency. Research Triangle Park,
N.C. EMB Report No. 79-OCM-15. April 1981.
17. W. Kelly (TRW Environmental Engineering Division). Benzene—Organic
Chemical Manufacturing Ethylbenzene/Styrene Emission Test Report, USS
Chemicals, Houston, Texas. Prepared for the U. S. Environmental
Protection Agency. Research Triangle Park, N.C. EMB Report No. 80-
OCM-19. August 1980.
18. Ref. 15.
19. Ref. 16.
20. Ref. 17.
21. Ref. 1.
22. Control Techniques for Volatile Organic Emissions from Stationary
Sources. U. S. Environmental Protection Agency. Research Triangle
Park, N.C. EPA Publication No. EPA-450/2-78-002. May 1978. pp. 32
and 33, 53, 72, 76, and 83 and 84.
23. Control of Volatile Organic Emissions. MetPro Corp., Systems
Division. Harleysville, Pennsylvania. 1981. 8 pp.
24. Letter from Connor, R. J., Manufacturers of Emission Controls
Association, to Rosensteel, R. E., EPA. May 4, 1992.
25. Ref. 24, p. 6.
26. Ref. 22, p. 53.
3-33
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27. Stern, A. C. Air Pollution, Volume IV, Third Edition, New York,
Academic Press. 1977. pp. vii through xii, 22 through 27, 336
and 337, and 354 through 359.
28. Barnett, K. W. (Radian Corporation). Carbon Adsorption for
Control of VOC Emissions: Theory and Full Scale System
Performance. Prepared for the U. S. Environmental Protection
Agency. Research Triangle Park, N.C. EPA Contract
No. 68-02-4378. June 6, 1988. p. 3-52.
29. Ref. 27, p. 356.
30. Ref. 28.
31. H. S. Basdekis, et al (IT Enviroscience, Inc.). Organic
Chemical Manufacturing Volume 5: Adsorption, Condensation, and
Absorption Devices, Report 2. Prepared for the U. S.
Environmental Protection Agency. Publication
No. EPA-450/3-80-027. Research Triangle Park, N.C.
December 1980. 336 pp.
32. Ref. 31, p. 1-4.
33. Staff of Research and Education Association. Modern Pollution
Control Technology: Volume I. New York, Research and Education
Association. 1978. pp. 22-20 through 22-25.
34. Ref. 31, p. 11-15.
35. Perry, R.H., and Chilton, C.H. Eds. Chemical Engineers
Handbook. 6th Edition. New York, McGraw-Hill. 1984. pp. 14-1
through 14-2.
36. Ref. 22, p. 76.
37. Ref. 27, p. 24.
38. Ref. 22, p. 72.
39. Ref. 31, p. II-l.
40. Ref. 35, p. 14-1.
41. Ref. 31, p. III-5.
42. Ref. 31, Report 2, p. II-l.
43. Ref. 22, p. 84.
44. Ref. 31, Report 2, p. IV-1.
45. Ref. 31, Report 2, pp. II-3.
3-34
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46. Ref. 31, Report 2, p. I1I-5.
47. Ref. 1.
3-35
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4.0 ENVIRONMENTAL IMPACTS
The environmental impacts associated with applying reasonably
available control technology (RACT) to synthetic organic chemical
manufacturing industry (SQCMI) distillation and reactor process vent
streams are analyzed in this chapter. As discussed further in
Chapter 6.0, the recommended RACT is based on the combustion of certain
SOCMI reactor and distillation process vent streams to achieve a
98 weight-percent volatile organic compound (VOC) reduction. The
requirements of RACT can be achieved at distillation and reactor process
facilities by either thermal incinerators or flares; therefore, the
environmental impacts analysis assumes that RACT is represented by thermal
incineration and flaring.
The environmental impacts analysis considers effects on air quality,
water quality, solid waste, and energy consumption. Ten model vent
streams derived from the emissions profiles presented in Appendix B are
used to assess these impacts. The model vent streams represent the range
of flow rates and heating values typical of SOCMI distillation and reactor
process vent streams. Table 4-1 presents the environmental impacts for
the 10 model vent streams. Calculated impacts are based on the lowest
cost control technique (thermal incineration versus flares) for
nonhalogenated streams, and on a thermal incinerator/scrubber system for
halogenated streams.
4.1 AIR POLLUTION IMPACTS
Section 4.1.1 presents the uncontrolled VOC.emissions from each model
vent stream and the expected VOC emission reductions from the application
of RACT. Section 4.1.2 discusses additional air quality impacts that may
be observed in applying RACT to specific reactor and distillation process
vents. Also included is discussion on possible impacts from the
4-1
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TABLE 4-1. ENVIRONMENTAL IMPACTS FOR DISTILLATION AND REACTOR MODEL VENT STREAMS
Air Impacts
Model vent
stream type8
Distillation
LFLH
LFHH
HFLH
HFHH
Average
Reactor
LFLH
LFHH
HFLH
HFHH
Average
Uncontrolled
VOC emissions'1
(Mg/yD
5.16
8.14
24.41
605.30
79.25
14.29
33.3*
5.36
802.97
31.95
Controlled
VOC emissions'1
(Mg/yr)
0.10
0.16
0.49
12.11
1.58
0.29
0.67
. 0.11
16.06
0.64
Secondary. NOX
emissions"'0
(Mg/yr)
0.043
0.006
0.531
1.789
0.074
0.035
0.032
7.165
47.82
2.05
Secondary CO
emissionsb'd
(Mg/yr)
0.001
0.002
0.121
1.347
0.030
0.010
0.024
0.369
19.128
0.820
Energy Impacts
Auxiliary
fuel useb
(MMBtu/yr)
1,126
620
6,997
3.163
620
289
56
1,083
34,653
1.485
Electrical
demand per vent"
(Kw-hr/yr)
1,131
0
6,508
46,836
0
902
836
10,2*6
315,639
12,377
Water Impacts
Scrubber
uasteuater flow"
(gal/yr)
404,367
0
0
16,719,531
0
325,728
297,661
0
0
0
"LFLH - low flow low heating value
LFHH - low flow high heating value
HFLH - high flow low heating value
HFHH - high flow high heating value
Average - average flow, average heating value
blmpacts are based on the lower cost control technique (thermal incineration versus flaring) for nonhalogenated stream and on a thermal Incinerator/scrubber
system for halogenated streams.
CNOX emission factors used:
Incinerators: 200 pp» in exhaust for stream* containing nitrogen compounds, and 21.5 ppm NOX on all other streams (based on test data).
Flares: 0.05 Ib/HMBtu (based on EPA 600/2-83-052)
dco emissions based on 20 Ib/MMscf (AP-42).
-------
inefficient operation of the control devices used to meet RACT
requirements.
4.1.1 Volatile OrganicCompound Emission Impacts
The VOC emissions (megagrams per year) for the distillation and
reactor model vent streams in Table 4-1 were estimated using an assumption
of 8,760 working hours per year. Controlled emissions were calculated
using a 98 weight-percent VOC reduction efficiency.
Uncontrolled VOC emissions from the distillation vent streams range
from about 5 megagrams per year (Mg/yr) (5.5 tons/yr) for the Low Flow Low
Heat (LFLH) model, to 600 Hg/yr (661 tons/yr) for the High Flow High Heat
(HFHH) model. Uncontrolled VOC emissions from the average distillation
vent stream are 80 Mg/yr (88 tons/yr). The controlled VOC emissions from
the distillation vent streams range from 0.10 Mg/yr (0.11 ton/yr) (LFLH)
to 12 Mg/yr (13 tons/yr) (HFHH), with 2 Mg/yr (2.2 ton/yr) representing
the average.
Uncontrolled VOC emissions from the reactor model vent streams range
from 5 Mg/yr (5.5 tons/yr) (HFLH) to 800 Mg/yr (882 tons/yr) (HFHH), with
32 Mg/yr (35 tons/yr) representing the average model vent stream. The
controlled VOC emissions from the reactor model streams range from
0.11 Mg/yr (0.12 tons/yr) (HFLH) to 16 Mg/yr (17.6 tons/yr) (HFHH), with
0.6 Mg/yr (0.66 tons/yr) representing the average.
4.1.2 Secondary Air Impacts
Other air quality impacts from the application of incinerator or
flare control technologies include secondary pollutants produced from the
combustion of vent streams containing VOC's. Possible by-product
emissions from VOC combustion include nitrogen oxides, sulfur dioxide,
carbon monoxide, particulate matter. Generally, the only
combustion-related secondary pollutants of any potential concern are
nitrogen oxides and carbon monoxide. Data are not available on carbon
monoxide emissions from thermal incinerators and flares. However, a
reasonable estimate can be made using the AP-42 factor for natural gas
combustion. Test data on nitrogen oxides emissions from thermal
incinerator and flares are available as discussed below.
Incinerator outlet concentrations of nitrogen oxides are generally
below 100 ppm, except for cases where the vent stream contains nitrogenous
4-3
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compounds. Test data for a toluene dlisocyanate process unit in the
reactor processes emissions profile showed a nitrogen oxide concentration
of 84 per million by volume (ppmv).l Testing at a polymer and resin
process unit using an incinerator for VOC control measured nitrogen oxide
ranging from 20.2 to 38.6 ppmv.2 The fuels tested were mixtures of
natural gas, waste gas, and/or atactic waste; incineration temperatures
ranged from 980 to 1,100 °C (1,800 to 2,000 °F). In a series of seven
tests conducted at three air oxidation process units, incinerator outlet
nitrogen oxide concentrations ranged from 8 to 200 ppmv.3 The maximum
outlet nitrogen oxide concentration was measured at an acrylonitrile (air
oxidation) process unit, which has a vent stream containing nitrogenous
compounds. The nitrogen oxide concentration measured at the other process
units, where the vent streams do not contain nitrogenous compounds, ranged
from 8 to 30 ppmv, with a median value of 21.5 ppm.
The use of flares for combustion may also produce nitrogen oxide
secondary air pollution impacts. Concentrations of nitrogen oxide were
measured at two flares used to control hydrocarbon emissions from refinery
and petrochemical processes. One flare was steam-assisted and the other
air-assisted, and the heat content of the fuels ranged from 5.5 to
81 megajoule per standard cubic meter (148 to 2,175 British thermal units
per standard cubic feet). The measured nitrogen oxide concentrations were
somewhat lower than those for incinerators, ranging from 0.4 to 8.2 ppmv.
The ranges of relative NOX emissions per unit of heat input are 7.8 to
90 gram per gigajoule (0.018 to 0.208 Ib/MMBtu) for flares.4
Table 4-1 presents the secondary air impacts for the 10 model vent
streams. As shown, nitrogen oxide emissions range from 0.006 Mg/yr
(0.007 tons/yr) for the LFHH distillation vent stream to 48 Mg/yr
(12,9 tons/yr) for the HFHH reactor vent stream. The carbon monoxide
emissions range from 0.001 Mg/yr (0.0011 tons/yr) for the LFLH reactor
vent stream to 19 Mg/yr (20.9 tons/yr) for the HFHH reactor vent stream.
In addition to nitrogen oxide and carbon monoxide emissions,
combustion of halogenated VOC emissions may result in the release of
halogenated combustion products to the environment. Generally, streams
containing halogenated VOC would not be controlled by a flare.
Incinerators are generally more capable of tolerating the corrosive
4-4
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effects of halogenated VOC and its combustion by-products. In addition,
scrubbing is used to remove these halogenated compounds from an
incinerator's flue gas. Generally, incineration temperatures greater than
870 °C (1,600 °F) are required to ensure 98-percent destruction of
halogenated VOC. For example, when incinerating chlorinated VOC's at
temperatures of 980 to 1,100 °C (1,800 to 3,000 °F), almost all chlorine
present exists in the form of hydrogen chloride. The hydrogen chloride
emissions generated by thermal oxidation at these temperatures can be
efficiently removed by wet scrubbing.5 As discussed further in
Chapter 5.0, the cost of the scrubber was added to the overall thermal
incinerator system cost.
4.2 WATER POLLUTION IMPACTS
Control of VOC emissions using combustion does not typically result
in any significant increase in wastewater discharge; that is, no water
effluents are generated by the combustion device. However, the use of an
incinerator/scrubber system for control of vent streams with halogenated
VOC does result in slightly increased water consumption. In this type of
control system, water is used to remove the acid gas contained in the
incinerator outlet stream. In most cases, any increase in total process
unit wastewater would be relatively small and would not affect plant waste
treatment or sewer capacity. Table 4-1 presents the water pollution
impacts for the 10 model vent streams. Scrubber wastewater flow ranges
from less than 0.001 million gallons per day (Mgal/d) for the LFLH reactor
vent stream to 0.05 Mgal/d for the HFHH distillation vent stream.
The absorbed acid gas may cause the water leaving the scrubber to
have a low pH. This acidic effluent could lower the pH of the total plant
effluent if it is released into the plant wastewater system. The water,
effluent guidelines for individual States may require that industrial
sources maintain the pH of water effluent within specified limits. To
meet these guidelines, the water used as a scrubbing agent would have to
be neutralized prior to discharge to the plant effluent system. The
scrubber effluent can be neutralized by adding caustic sodium hydroxide to
the scrubbing water. The amount of caustic needed depends on the amount
of acid gas in the waste gas. For example, approximately 1.09 kilograms
4-5
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(kg) (2.4 Ib) of caustic (as sodium hydroxide) are needed to neutralize
1 kg (2.2 Ib) of hydrogen chloride.
The salt formed In the neutralization step must be purged from the
system for proper disposal. The methods of disposal include direct
wastewater discharge Into sewer systems, salt water bodies, brackish
streams, freshwater streams, deep well injection, and evaporation. Use of
the latter disposal method is not widespread, and data show that most
plants currently incinerating halogenated streams have State permits to
dump the brine or use on-site wells to dispose of salty wastewater at a
relatively low cost.7 The increased water consumption and caustic costs
were included in the projected operating costs for control of halogenated
vent streams using an incinerator/scrubber system. The costs associated
with the disposal of the salty wastewater were judged not to be
significant in comparison to the control costs and, therefore, were not
included in the projected cost impacts presented in Chapter 5.0.?
An alternative to brine disposal is to use the brine as feed to
chlorine production. Such a use would be site specific, where there was a
need for the chlorine in subsequent syntheses, and where quantities of
brine either alone or in combination with other brine sources were
adequate for economical production.
The use of scrubbers to remove hydrogen chloride from the incinerator
flue gas also has the potential to result in small increases in the
quantities of organic compounds released into plant wastewater. However,
only small amounts of organics are released into the scrubber wastewiter;
the flow of wastewater from the scrubber is small compared to total plant
wastewater, especially in installations where there are multiple chemical
processing units using a central wastewater treatment facility.
Therefore, the increase in the generation of organics in plant wastewater
is not likely to be significant.
4.3 SOLID WASTE DISPOSAL IMPACTS
There are no significant solid wastes generated as a result of
control by thermal oxidation. A small amount of solid waste for disposal
could result if catalytic oxidation, instead of thermal oxidation, were
used by a facility to achieve RACT requirements. The solid waste would
consist of spent catalyst.
4-6
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used by a facility to achieve RACT requirements. The solid waste would
consist of spent catalyst.
4.4 ENERGY IMPACTS
The use of incineration to control VOC's from reactor and
distillation process vent streams requires fuel and electricity.
Supplemental fuel is frequently required to support combustion.
Electricity is required to operate the pumps, fans, blowers and
Instrumentation that may be necessary to control VOC's using an
incinerator or flare. Fans and blowers are needed to transport vent
streams and combustion air. Pumps are necessary to circulate absorbent
through scrubbers that treat corrosive offgases from incinerators
combusting halogenated VOC's. Fuel and energy usage requirements for
incinerators and flares are discussed in detail as part of the overall
cost methodology 1n Chapter 5.0.
Table 4-1 presents the estimated energy impacts associated with each
model vent stream from reactor and distillation units. These energy
values include both fuel and electricity usage estimates. As shown,
auxiliary fuel use ranges from 56 MMBtu/year for the LFHH reactor vent
streams to 34,653 MMBtu/yr for the HFHH reactor vent stream. Electrical
demand per vent ranges from zero for two vent streams to
315,639 kilowatt-hour per year for the HFHH reactor vent stream.
Electricity generally accounts for a small fraction of the total energy
impacts, while fuel use accounts for the remainder. Heat recovery systems
may substantially affect fuel usage requirements for incinerators.
4-7
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4.5 REFERENCES
1. Reactor Processes in Synthetic Organic Chemical Manufacturing
Industry-- Background Information for Proposed Standards. Draft EIS.
U. S. Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-450/3-90-016a. June 1990.
2. Lee, K. W., et al (Radian Corporation). Polymers and Resins,
Volatile Organic Compound Emissions from Incineration, Emissions Test
Report, ARCO Chemical Company, LaPorte Plant, Deer Park, Texas.
Volume I: Summary of Results. Prepared for the U. S. Environmental
Protection Agency. Research Triangle Park, N.C. EMB Report
No. 81-PMR-l. March 1982. pp. 12 through 15.
3. Air Oxidation Processes in Synthetic Organic Chemical Manufacturing
Industry--Background Information for Proposed Standards. Draft EIS.
U. S. Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-450/3-82-001a. October 1983. pp. ii, 7-5, C-22,
and technical report data sheet.
4. HcDaniel, M. (Engineering Science). Flare Efficiency Study.
Prepared for the U. S. Environmental Protection Agency. Washington,
D.C. Publication No. EPA-600/2-83-052. July 1983. p. 134 and
technical report data sheet.
5, Ref. 4.
6. Memorandum from Piccot, S. D., and Lesh, S. A., Radian Corporation,
to Reactor Processes NSPS file. June 25, 1985. Disposal of brine
solutions from wet scrubbers.
7. Memorandum from Stelling, J. H. E., Radian Corporation, to
Distillation Operations NSPS file. September 2, 1982. Caustic and
salt disposal requirements for incineration. 1 p.
4-8
-------
5.0 COST ANALYSIS
5.1 INTRODUCTION
This chapter presents the costs associated with control options for
reducing volatile organic compound (VOC) emissions from distillation
column and reactor process vents. Control system elements, design
assumptions, and costing equations are provided for incinerator and flare
control systems. For streams containing halogenated VOC's, the
incinerator control system cost includes a packed tower scrubber system to
remove acidic vapors from the incinerator flue gas.
Since synthetic organic compound manufacturing industry (SOCMI)
processes encompass a wide range of emission parameters, a model stream
approach was used to present example control system costs. Ten model
systems were selected from the distillation and reactor process emission
profiles to represent a broad spectrum of possible vent streams. The
model vent stream characteristics are presented in Appendix B. Because
flow rates, heating values, and VOC concentrations of the model streams
vary considerably, there is a large variation in system costs and cost
effectiveness values.
5.2 COST METHODOLOGY FOR INCINERATOR SYSTEMS
This section presents the methodology used to develop VOC control
system costs for incinerators and scrubbers. Incinerator costs were
developed using Chapters 2 and 3 of the EPA's Control Cost Manual (OCCM).1
Scrubber costs were based on the procedure outlined in the EPA's Handbook
on Control Technologies for Hazardous Air Pollutants,2 with equipment
costs updated from recent technical journal Information.3
5.2.1 Thermal Incinerator Design Considerations
The thermal incinerator system consists of the following equipment:
combustion chamber, instrumentation, recuperative heat exchanger, blower,
5-1
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collection fan and ductwork, quench/scrubber system (if applicable), and
stack. The OCCM contains further discussion of incinerator control system
design. Control system elements and design assumptions specific to SOCHI
vent streams are discussed below. General incinerator design
specifications are presented in Table 5-1.
5.2,1.1 Combustion Air Requirements. The amount of oxygen in the
waste gas or that provided by the VOC's is important because it
establishes the auxiliary combustion air required, which has an impact on
both the capital and operating costs of the thermal oxidizer. This cost
analysis assumes that the waste gas does not contain free oxygen and that,
therefore, auxiliary combustion air must be added. (In other words, the
vent stream is essentially a mixture of VOC's and an inert gas such as
nitrogen.) After combustion, the design excess oxygen content in the
incinerator flue gas is assumed to be 3 mole percent, which is based on
commonly accepted operating practice.
In order to calculate the amount of combustion air required to ensure
a flue gas oxygen concentration of 3 mole percent, a complete
stoichiometric equation must be balanced for each compound present in the
waste gas stream. In many cases, the complete chemical composition of the
waste stream is not known. Thus, for the purpose of costing incinerator
systems for typical vent streams encountered in the SOCHI, a design
molecule approach was used for halogenated and nonhalogenated waste gas
streams.
The design molecule was based on a survey of typical values for
carbon, hydrogen, oxygen, sulfur and chloride ratios for group of
219 organic compounds.* For nonhalogenated streams, the average VOC
molecular composition of 68.3 percent carbon, 11.4 percent hydrogen, and
20.3 percent oxygen was used to calculate combustion air requirements.
These weight ratios correspond to a molecular formula of C£, 8^5.700.53.
For halogenated streams, component averages of 34.3 percent carbon,
4.7 percent hydrogen, and 6.1 percent chlorine were used to predict
combustion air requirements. This corresponds to a molecular formula of
c2.86H4.7c1l.71« In D0tn cases, assuming zero percent oxygen in the waste
5-2
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TABLE 5-1. INCINERATOR GENERAL DESIGN SPECIFICATIONS
Item
Specification
Emission control efficiency
Minimum incinerator capacity*
Maximum incinerator capacity
Incinerator temperature
- nonhalogenated vent streams
- halogenated vent streams0
Chamber residence times
- nonhalogenated vent streams
- halogenated vent streams0
Auxiliary fuel requirement
Scrubber system
- type
- packing type
- scrubbing liquid
- scrubber gas temperature
98 percent destruction
500 scfm
50,000 scfm
870 °C (1,600 OF)
1,100 °c (2,000
0.75 sec
1.00 sec
Natural gas required to maintain
incinerator temperature with
3 mole percent excess oxygen in
flue gas
Used when halogenated VOC is
present to remove corrosive
combustion by-products
Packed tower
2-inch rings, carbon steel
Water
100 oc (212 °F)
aFor capital cost purposes. A minimum flow rate of 50 scfm was used for
determining operating costs.
when halogenated VOC are present due to the difficulty of achieving
complete combustion of halogenated VOC at lower temperatures.
5-3
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stream, a dilution ratio (mole of air per mole of VOC) of approximately
18:1 is required to achieve 3 percent oxygen in the incinerator flue gas.
5.2.1.2 Dilution Air Requirements. After the required combustion
air is calculated and added to the total vent stream flow, the overall
heat value megajoules per standard cubic meter (MJ/scm) of the stream is
recalculated. Addition of combustion air will effectively dilute the
stream and lower the heat content of the combined stream fed to the
incinerator. However, if the heat content of the vent stream is still
greater than 3,648 kilojoules per standard cubic meters (KJ/scm)
[98 British thermal units per standard cubic feet (Btu/scf)] for
nonhalogenated streams or greater than 3,536 KJ/scm (95 Btu/scf) for
halogenated streams, then additional dilution air must be added to ensure
these maximum heat content levels are not exceeded. The imposition of a
maximum heat content level prevents the temperature in the incinerator
from exceeding the design specifications.
The minimum flow rate to the incinerator is 1.42 standard cubic meter
per minute (scmm) (50 scfm). It is assumed that vent streams smaller than
1.42 scmm (50 scfm) will be mixed with air to achieve this minimum flow
rate. The maximum incinerator flow rate is 1,416 scmm (50,000 scfm}.
Flow rates greater than this will be handled by multiple incinerators in
this cost analysis.
5.2.1.3 Recuperative Heat Recovery. Halogenated vent streams are
not considered candidates for heat recovery systems, and are costed
assuming zero percent heat recovery. This conservative design assumption
is imposed because of the potential for corrosion in the heat exchanger
and incinerator. If the temperature of the flue gas leaving the heat
exchanger, Tf0, were to drop below the acid dew temperature, condensation
of acid gases would result. Significant corrosion can lead to shortened
equipment life, higher maintenance costs, and potentially unsafe working
conditions.
Nonhalogenated vent streams are considered candidates for
recuperative heat recovery. The extent of heat recovery depends on the
heat value of the vent stream after dilution. Four different heat
recovery scenarios are evaluated for nonhalogenated streams. The cost
algorithm includes systems with 0, 35, 50 and 70 percent heat recovery.
5-4
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The extent of heat exchange to be utilized is decided by an economic
optimization procedure with the following restrictions. No heat recovery
is allowed for vent streams with a heat value greater than 25 percent of
the lower explosive limit (LEL), due to the possibility of explosion or
damaging temperature excursions within the heat exchanger. This limit
typically corresponds to a heat content of 484 KJ/scm (13 Btu/scf).
Therefore, if the heat content of the total vent stream--even after
addition of required combustion and dilution a1r--is still greater than
484 KJ/scm (13 Btu/scf), no heat recovery for the entire stream is
allowed. For streams with a heat content less than 484 KJ/scm
(13 Btu/scf}, the entire stream is preheated in the recuperative heat
exchanger, allowing for maximum energy recovery. However, for streams
with a heat content greater than 484 KJ/scm (13 Btu/scf}, the flammable
vent gas stream cannot be preheated, but the combustion/dilution air
stream can. In this case, the cost optimization procedure evaluates the
option of preheating only the air stream, and combines the VOC stream with
the preheated air stream in the incinerator.
All allowable heat recovery percentages are evaluated and the
calculated total capital and annual costs are based on the most
cost-effective configuration. The tradeoff between the capital cost of
the equipment and the operating cost (fuel} of the system determines the
optimum level of energy recovery.
5.2.1.4 IncineratorDesign Temperature. The destruction of VOC's is
a function of incinerator temperature and residence time in the combustion
chamber. The design VOC destruction efficiency Is 98 weight-percent,
which can be met by well-designed and well-operated thermal incinerator
systems. Previous studies by the EPA show that 98 weight-percent
destruction efficiency can be met in a thermal incinerator operated at a
temperature, Tfi, of 871 °C (1,600 °F) and a residence time of 0.75
second. Thermal oxidation of halogen-containing VOC's requires higher
temperature oxidation to convert the combustion product to a form that can
be more readily removed by flue gas scrubbing. For instance,
chloride-containing waste gases are burned at high temperature to convert
the chlorine to hydrogen chloride instead of to chlorine, since hydrogen
chloride is more easily scrubbed. Available data indicate that a
5-5
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temperature of 1,093 QC (2,000 OF) and residence time of 1 second are
necessary to achieve 98 weight-percent VOC destruction efficiency for
halogen-containing waste gas streams. Chapter 3,0 contains additional
details on thermal incinerator performance,
5.2.2 Thermal Incinerator Capital Costs
The costing analysis follows the methodology outlined in the OCCM.
Equipment cost correlations are based on data provided by various vendors;
each correlation is valid for incinerators in the 14.2 scinm to 1,416 scmm
(500 to 50,000 scfm) range.5 Thus, the smallest incinerator size used for
determining equipment costs was 14.2 scmm (500 scfm) and for flow rates
above 1,416 scmm (50,000 scfm) additional incinerators were costed.
Purchased equipment costs (PEC's) for thermal incinerators are given
as a function of total volumetric throughput, Qtot> in scfm. Four
equations were used in the costing analysis, each pertaining to a
different level of heat recovery (HR):
PEC = 10294 Qtot0'2355 HR - 0%
PEC = 13149 Qtot0'2609 HR " 35%
PEC = 17056 Qtot0'2502 HR • 50%
PEC - 13149 Qtot0'2500 HR - 70%
The cost of ductwork (not included in PEC) was calculated based on
1/8 inch (in.) carbon steel with two elbows per 100 feet (ft), using the
equation in Reference 6. The length of duct was assumed to be 300 feet.
Collection fan costs were developed using methods in Reference 7. The
duct and fan costs are added to the total equipment cost and installation
factors applied to this total.
Installation costs are estimated as a percentage of total equipment
costs. Table 5-2 lists the values of direct and indirect installation
factors for thermal incinerators.
5.2.3 Thermal Incinerator Annualized Cost
Annualized costs for the thermal incinerator system include direct
operating and maintenance costs, as well as annualized capital charges.
It should be pointed out that vendor contacts indicate that an incinerator
turndown ratio of 10/1 is available.8 Consequently, the minimum flow rate
5-6
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TABLE 5-2. CAPITAL COST FACTORS FOR THERMAL INCINERATORS3
Cost item Factor
Direct Costs
Purchased equipment costs
Incinerator (EC) + auxiliary equipment*5 As estimated, A
Instrumentation0 0.10 A
Sales taxes 0.03 A
Freight __ 0.05 A
Purchased equipment cost, PEC B - 1.18 A
Direct installation costs
Foundations and supports 0.08 B
Handling and erection 0.14 B
Electrical 0.04 B
Piping 0.02 B
Insulation for ductwork" 0.01 B
Painting 0.01 B
Direct installation cost " 0.30 B
Site preparation As required, SP
Buildings As required,Bldg.
Total direct costs, DC 1.30 B + SP + Bldg.
Indirect Costs (Installation)
Engineering 0.10 B
Construction and field expenses 0.05 B
Contractor fees 0.10 B
Start-up 0.02 B
Performance test 0.01 B
Contingencies 0.03 B
Total indirect cost, 1C 0.31 B
Total Capital Investment - DC + 1C 1.61 B + SP + Bldg.
Reference 1.
^Ductwork and any other equipment normally not included with unit
furnished by incinerator vendor.
Instrumentation controls often furnished with the incinerator, and thus
often included in the EC.
ductwork dimensions have been established, cost may be estimated based
on $10 to $12 per ft^ of surface area for field application. Fan
housings and stacks may also be insulated.
5-7
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for determining operating costs is assumed to be 1.42 scmm (50 scfm).
Additional dilution air is added where necessary to raise the fuel-waste
gas-air mixture to 1,42 scmm (50 scfm). The bases for determining thermal
incinerator annualized costs are presented in Table 5-3. Each cost
parameter is reviewed below.
5.2.3.1 labor Costs. The operating labor requirements vary
depending on the components of the overall system. Incinerator systems
not employing a scrubber require the least amount of operating labor
[548 hours per year (hr/yr) or 0.5 hours per 8-hour shift). Systems
employing a scrubber require an additional 548 hr/yr operating labor.
Maintenance labor requirements are assumed to be identical to operating
labor requirements--that is 548 hr/yr for the incinerator and 548 hr/yr
for the scrubber. Supervisory cost is estimated to be 15 percent of the
operating labor cost. The maintenance labor hourly rate is assumed to be
10 percent higher than the operating labor hourly rate.
5,2.3.2 CapitajjCharges. Return on investment for the incinerator
system is not included, but the cost of the capital investment is
accounted for in evaluating total annual costs. The capital recovery
factor (0.163) is based on a 10-percent interest rate and a 10-year life
for the equipment. Taxes, insurance, and administrative costs are assumed
to be 4 percent of the total capital investment. Overhead is estimated to
be 60 percent of the total labor and maintenance costs.
5.2.3.3 Utility Costs. The utilities considered in the annual cost
estimates include natural gas and electricity. The procedures for
estimating electricity and supplemental fuel requirements are described in
Chapter 3 of the OCCM.
5.2.3.4 Maintenance Costs. Maintenance labor costs are discussed
above. Maintenance material costs are assumed to be equal to maintenance
labor costs.
5.3 COST METHODOLOGY FOR FLARE SYSTEMS
This section presents the methodology used to develop VOC control
system costs for flares. Flare design aspects and costs are based on
Chapter 7 of the OCCM.
5-8
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TABLE 5-3. ANNUAL OPERATING COST BASIS FOR THERMAL INCINERATORS
DirectOperating Cost Factors
Hours of operation (hrs/yr) 8,760
Operating labor (manhours)
Incinerator (0.5 hrs/8 hr shift) 548
Incinerator with scrubber (1 hr/8 hr shift) 1,096
Maintenance labor (manhours) per incinerator
Incinerator (0.5 hr/8 hr shift) 548
Incinerator with scrubber (1 hr/8 hr shift) 1,096
Labor rates ($/hr) based on 1990 data
Operating labor
Maintenance labor
Supervisory cost
Cost
Maintenance materials cost
Labor Cost
Utilities (1990 $)
Electricity ($/l,000 kWh) 59
Natural Gas ($/106 Btu) 3.30
Indirect Operating Cost Factors
Equipment life (years) 10
Interest rate (percent) 10
Capital recovery factor 0.163
Taxes, insurance, administration 4
(percent of total installed cost)
Overhead
15.64
17.21
15% of Operating Labor
100% of Maintenance
60% of Total Labor and
Maintenance Costs
5-9
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5.3.1 Flare Design Considerations
The flare design consists of an elevated, steam-assisted, smokeless
flare. Elements of the flare system include knock-out drum, liquid seal,
stack, gas seal, burner tip, pilot burners, and steam jets. For flare
system sizing, correlations were developed relating process vent stream
flow rate and heat content value to the flare height and tip diameter.
The general design specifications used in developing these correlations
are discussed below and presented in Table 5-4.
Flare height and tip diameter are the basic design parameters used to
determine the installed capital cost of a flare. The tip diameter
selected is a function of the combined vent stream and supplemental fuel
flow rates, and the assumed tip velocity. Supplemental fuel requirements
and tip velocity values are shown in Table 5-4. Determination of flare
height is based on worker safety requirements. The flare height is
selected so the maximum ground level heat intensity including solar
radiation is 2,525 watts per square meter (W/m^) [800 Btu/hr per foot
squared (ft^JJ. Vendor contacts indicate the smallest elevated flare
commercially available is 30 ft high and 1 in. in diameter. For vent
streams requiring smaller flare systems, this is the minimum flare size
used.
After flare tip diameter (D) and flare height (H) are determined, the
natural gas required for pilots and purge, and the mass flow rate of steam
required are calculated. Pilot gas consumption is a function of the
number of pilots and, in turn, of the tip diameter as shown in Table 5-4.
The number of pilots is selected based on the tip diameter. The pilot gas
consumption is calculated based on an energy-efficient model of
1.98 scm/hr {70 scf/hr) per pilot burner. The purge gas requirement is
also a function of the tip diameter and the minimum design purge gas
velocity of 0,012 meters per second (m/s) [0.04 ft/second (sec)] at the
tip, as shown in Table 5-4. A design flare tip velocity 14.6 mps
(48 ft/sec) equal to 80 percent of the maximum smokeless velocity 1s used
in the costing equations. Steam use is that flow which maintains a steam
to flare gas ratio of 0.4 pound (Ibj steam/lb vent gas [kilogram (kg)
steam/kg vent gas].
5-10
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TABLE 5-4. FLARE GENERAL DESIGN SPECIFICATIONS
Item
Specification
Emission control efficiency
General flare design
- minimum net heating valve
- minimum flare tip diameter
- mininun flare height
- maxinun gound level heat intensity*
- flare tip velocities"
• emissfvity
- muter of pilots6
- pilot gas requirement
- steam requirement
- purge gas requirement
Supplemental fuel requirement''
98 percent destruction
Elevated, steam assisted
Smokeless flare
300 Btu/scf of gas being combusted
2.5 OB (1.0 inch)
9.1 • (30 ft)
2,525 U/*2 (800 itu/hr ft2)
HV s 11.2 (300); V « 18.3 ml* (60 ft/s) + natural gas
to 11.2 MJ/Ha3 (300 Btu/scf)
11.2 (300) < HV < 37.3 (1,000): lo§(V) * (KV * 1,214)/852
HV > 37.3 (1,000): V « 122 ml* (400 ft/i)
0.3
Number of Pilots Tip Diameter
1
2
3
4
2.0 sr^/hr (70 scf/hr) of natural gas per pilot
0.4 kg steam/kg vent gas
Natural gas added to maintain a niniau* flare tip velocity of
0.01 mis (0.04 ft/s)
Natural gas required to Maintain vent stream HV of 11.2 NJ/Hm3
(300 Btu/scf for V 18.3 «/s (60 ft/s)
0 5 25
25 152
(D 3 10)
(10 60)
Including solar radiation of 300 Btu/hr ft2.
bHV = Heat content value of process vent stream, MJ/nr (Btu/scf). A flare tip velocity equal to 80 percent of the
maximum smokeless velocity (18.3 n/s [60 ft/s}) is used in the costing equations.
CD - tip diameter, cm (inch).
^dV « flare tip velocity, «/s (ft/s).
5-11
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5.3.2 Development of Flare Capital Costs
The capital cost of a flare is based on vendor supplied information
as described in the OCMM cost equations are developed from a regression
analysis of the combined data set over a range of tip diameters and flare
heights. Flare equipment costs (CF) are calculated based on stack height,
H (ft) and tip diameter, D (in.) according to support type as follows:
• Self Support Group:
CF • [78.0 + 9.14(0) + 0.749(H)]2
• Guy Support Group:
CF «= [103 + 8.68(0) + 0.470(H)]2
• Derrick Support Group:
CF . [76.4 + 2.72(0) + 1.64(H)]2
The flare equipment cost includes the flare tower (stack) and support,
burner tip, pilots, utility piping from base, utility metering and
control, water seal, gas seal, and galvanized caged ladders and platforms
as required. The material of construction basis is carbon steel, except
for the upper 4 ft and burner tip, which is 310 stainless steel.
Vent stream piping costs, Cp, are a function of pipe, or flare,
diameter, D, and length of piping.
• Cp - 508 (D)1-21 (where 1" < D < 24")
• Cp - 556 (0)1-O7 (where 30" < D < 60")
These costs include 400 ft of straight piping and are directly
proportional to the distance required.
Knock-out drum costs CK, are a function of drum diameter, d (in.) and
drum thickness, t (in.)*
• CK - 14.2 [(d)(t)(h -i- 0.812(d)]°-737
Total flare system equipment cost is the sum of flare, piping, and
knock-out drum costs.
EC - Cp + CK + Cp
Purchased equipment cost, PEC, is equal to equipment cost, EC, plus
factors for ancillary equipment (i.e., instrumentation at 0.10, sales
5-12
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taxes at 0.03, and freight at 0.05). Installation costs are estimated as
a percentage of total equipment costs. The total capital Investment, TCI,
is obtained by multiplying PEC by an installation factor of 1.61.
5,3.3 Development of Flare Annualized Costs
The annualIzed costs Include direct operating and maintenance costs,
and annualized capital charges. The assumptions used to determine
annualized costs are presented 1n Table 5-5, and are given 1n first
quarter 1990 dollars. Direct operating and maintenance costs Include
operating and maintenance labor, replacement parts, and utilities.
5.3.3.1 LaborCosts. The operating labor requirements are
500 hrs/yr for typical flare systems. Supervisory labor is estimated to
be 15 percent of the operating labor cost. Maintenance labor is assumed
to be 10 percent higher than the operating labor cost.
5.3.3.2 CapitalCharges. The capital recovery factor (0.1314) is
based on a 10-percent interest rate and a 15-year life for the equipment.
Taxes, insurance and administrative costs are assumed to be 5 percent of
the total capital investment.
5.3.3.3 Utility Costs. The utilities considered in the annual cost
estimates Include natural gas and electricity. The procedures for
estimating electricity and supplemental fuel requirements are described in
Chapter 4 of the OAQPS Cost Manual.
5.3.3.4 HajntenanceCos.ts. Maintenance labor costs are discussed
above. Maintenance material costs are assumed to be equal to maintenance
labor costs.
5.4 COMPARISON OF CONTROL SYSTEM COSTS
This section presents and discusses the capital costs, annualized
costs, average cost effectiveness, and natural gas costs for the
application of Incinerators or flares to representative SOCMI vent
streams. These costs are determined by applying the costing methodology,
developed in the previous sections, to the 10 model vent streams described
in Appendix B.
For a specific combustion control system, capital and annualized
costs vary with vent stream flow rate and heat content. Therefore, five
reactor process vent streams and five distillation vent streams are used
as examples to show how the costs of control vary for vent streams with a
5-13
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TABLE 5-5. ANHUAL OPERATING COSTS FDR FLARE SYSTEMS
Direct Annual Costs
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Natural Gas - Pilot Gas
- Auxiliary Fuel
- Purge Gas
Steam
Electricity
Factor/Basis
630 manhours/yr
15% of operating labor
1/2 hour per shift
equal to maintenance labor
}
} All utilities equal to:
}consumption rate * hours/yr *
} unit cost
}(Natural Gas - $330/10^ Btu)
}(Electr1c1ty - $59.0/1,000 kWh)
}(Steam - $5.30/1,000 lb)
Indirect Annual Costs
Overhead
Capital Recovery Factor
General and Administrative,
Taxes, and Insurance
60% of total labor costs
0.1314 (assuming 15 year life at 10%)
(4% of total installed capital)
5-14
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wide range of vent stream characteristics. These example cases are
selected from the emission profiles in Appendix B and represent the range
of vent stream characteristics found. Stream characteristics for the
10 example cases are as follows:
Case 1 - reactor process - low flow rate, high heat content -
(R-LFHH);
Case 2 - reactor process - low flow rate, low heat content - (R-LFH);
Case 3 - reactor process - high flow rate, high heat content -
(R-HFHH);
Case 4 - reactor process - high flow rate, low heat content -
(R-HFLH);
Case 5 - reactor process - medium flow rate and medium heat content -
(R-AVG);
Case 6 - distillation - low flow rate, high heat content - (D-LFHH);
Case 7 - distillation - low flow rate, low heat content - (D-LFLH);
Case 8 - distillation - high flow rate, high heat content - (D-HFHH);
Case 9 - distillation - high flow rate, low heat content - (D-HFLH);
Case 10 - distillation - medium flow rate and medium heat content -
(D-AVG);
Table 5-6 presents the results of the costing analysis for the
10 example SOCMI vent streams. The values presented are the lower cost
control option (thermal incineration versus flaring) for nonhalogenated
streams. For halogenated streams, the values in the table represent the
cost of a thermal incineration/scrubber system.
Table 5-6 shows that average cost effectiveness for each control
system varies with the vent stream characteristics. The lowest
cost-effectiveness values shown occur for those vent streams with the
highest vent stream energy flow (i.e., (flow rate) x (heat content) in
megajoules per minute); Cases 3 and 8. The cost effectiveness for Case 3
is about $300/megagram (Mg) ($272/ton), while the cost effectiveness for
Case 8 is about $270/Mg ($245/ton). In general, the low cost
effectiveness values for high-energy content vent streams are a result of
the large mass of VOC's available to support combustion and, subsequently,
5-15
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TABLE 5-6. COST RESULTS FOR MODEL SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY VENT STREAMS
Source 10
R-LFHH
R-LFLH
R-HFHH
R-HFLH
D-IFHH
R-AVC
O-IFLH
D-HFHH
D-HHH
D-AVG
Halogenation
status Control device
H
H
NH
NH
NH
NH
H
H
NH
NH
Incin +
Incin +
Thermal
Thermal
Thermal
Flare
Incin +
Incin *
Thermal
Flare
Scrubber
Scrubber
Incineration
Incineration
Incineration
Scrubber
Scrubber
Incineration
Total
inlet flow
(scfm)
3.8
40
5.090
1.078
564
0.2
2.6
344
632
13.8
Inlet VOC
flow rate
(Ib/hr)
8.4
3.6
202.3
1.4
8.1
2.1
1.3
152.5
6.2
20
Inlet
heat value
(Btu/scf)
1.286
40
776
70
300
2.870
62
804
19
449
Total
emissions
reduction
(Mg/yr)
32.7
14
786.9
5.3
31.3
8
5.1
593.2
23.9
77.7
Natural
gas cost
(VyD
186
953
114,355
3.575
4,902
2.046
3,715
10.438
23.089
2,046
Capital
cost
(*)
114,450
115,506
292,118
109,698
114,284
28,991
115,318
243.020
100.786
29,836
Annual
cost
(VyD
115.323
116,314
238,743
72,348
74.736
52.936
119,068
158.061
89,828
54.087
Cost
effectiveness
(t/Mg removed)
3.529
8.306
303
13.778
2,387
6.638
23,546
266
3,758
696
(Jl
I
-------
the low supplemental fuel costs. Also, relatively large VOC emission
reductions occur for these streams, which greatly decreases the cost per
megagram of VOC removed/destroyed.
Table 5-6 also shows the highest cost effectiveness occurs for vent
streams with a low energy flow (Case 7). This occurs even though this
type of stream does not have extremely high annualized costs. For Case 4,
cost effectiveness is $13,778/Mg ($12,497/ton) with incineration.
Application of controls to this low heat content stream results in
moderately low annual costs but very low emissions reductions. A
relatively small amount of VOC's are controlled because of the low VOC
content associated with this vent stream.
5-17
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5.5 REFERENCES
1. OAQPS Control Cost Manual, Fourth Edition. U. S, Environmental
Protection Agency. Research Triangle Park, N.C. Publication
Mo. EPA-450/3-90-006. January 1990. pp. 1-1 through 1-7, 2-1
through 2-32, 3-1 through 3-66, 4-1 through 4-44, 5-1 through 5-54,
6-1 through 6-74, and 7-1 through 7-43.
2. Handbook: Control Technologies for Hazardous Air Pollutants.
U. S. Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-625/6-86-014. September 1986. 176 pp.
3. W. M. Vatavuk. Pricing Equipment for Air Pollution Control.
Chemical Engineering. May 1990. pp 126 through 130.
4. Organic Chemical Manufacturing Series. Volume 4: Combustion Control
Devices. U. S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-450/3-80-026. December 1990.
5. Ref. 1.
6. Richardson Engineering Services, Inc. The Richardson Rapid System
Process Plant Cost Estimating Standards. Volume 3, p. 16-0.2 and
Volume 4, pp. 100-110.4 and 100-653.13 and 100-653.14, 1988.
7. Telecon. Stone, D. K., Radian Corporation with E. Oowd, ARI
Technology. January 18, 1990. Incinerator sizes and turndown. 1 p.
5-18
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6.0 SELECTION OF REASONABLY AVAILABLE
CONTROL TECHNOLOGY
This chapter provides State and local regulatory authorities with
guidance on the selection of reasonably available control technology
(RACT) for volatile organic compound (VOC) emissions from synthetic
organic chemical manufacturing industry (SOCNI) reactor processes and
distillation operations. Background on the regulatory authority and goals
for establishment of RACT is discussed in Section 6.1. The technical
basis for RACT is discussed in Section 6.2, while the approach for
applying RACT is described in Section 6.3. Section 6.4 presents the
impacts of RACT on example vent streams. Finally, Section 6.5 provides an
overall summary of RACT for this source category.
6.1 BACKGROUND
The Clean Air Act Amendments of 1990 mandate that State
implementation plans (SIP's) for ozone nonattainment areas be revised to
require the implementation of RACT to limit VOC emissions from sources for
which the EPA has already published a control techniques guideline (CTG),
or for which it will publish a CTG between the date the amendments are
enacted and the date an area achieves attainment status.
Section 172(c)(l) requires that nonattainment area SIP's provide for the
adoption of RACT for existing sources. As a starting point for ensuring
that these SIP's provide for the required emissions reduction, the EPA has
defined RACT as "...the lowest emission limitation that a particular
source is capable of meeting by the application of control technology that
is reasonably available considering technological and economic
feasibility. The RACT for a particular source is determined on a
case-by-case basis, considering the technological and economic
circumstances of the individual source category."1 The EPA has elaborated
in subsequent notices on how RACT requirements should be applied.2>3
6-1
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The CTG documents are Intended to provide State and local air
pollution authorities with an Information base for proceeding with their
own analysis of RACT to meet statutory requirements. These documents
review existing information and data concerning the technical capability
and cost of various control techniques to reduce emissions. Each CTG
document contains a recommended "presumptive norm" for RACT for a
particular source category, based on the EPA's current evaluation of
capabilities and problems general to the source category. Where
applicable, the EPA recommends that regulatory authorities adopt
requirements consistent with the presumptive norm level, but authorities
may choose to develop their own RACT requirements on a case-by-case basis,
considering the economic and technical circumstances of the individual
source category.
6.2 TECHNICAL BASIS FOR REASONABLY AVAILABLE CONTROL TECHNOLOGY
The technology underlying RACT for SOCMI reactor process and
distillation operations is combustion via either thermal incineration or
flaring. These techniques are applicable to all SOCMI reactor processes
and distillation operations and can generally achieve the highest emission
reduction among demonstrated VOC control technologies. Thermal
incinerators can achieve at least 98 weight-percent reduction of VOC
emissions (or reduction to 20 parts per million by volume [ppmv] dry
basis, corrected to 3 percent oxygen) for any vent stream if the control
device is well operated and maintained. Likewise, the EPA has presumed
that flares can achieve at least 98 weight-percent control of VOC
emissions if the design and operating specifications given in the Code of
Federal Regulations (40 CFR 60.18) are met. (Chapter 3.0 contains more
detail on the performance capabilities of thermal incinerators and flares
as applied to SOCMI vent streams.) Although the control level
representing RACT is based on the application of thermal incineration or
flaring, it does not specify these techniques as the only VOC control
methods that may be used. Any device can be used to comply with RACT
requirements as long as the 98 weight-percent destruction or 20 ppmv dry
basis, corrected to 3 percent oxygen emission limit is met.
Other VOC control technologies were considered 1n the RACT
evaluation, including catalytic incinerators, carbon adsorbers, condensers
6-2
-------
and absorbers. However, for several reasons, these technologies were
rejected as the basis for the recommended presumptive norm for RACT.
Catalytic incinerators are difficult to apply one costing model to,
because different catalysts are required depending on the feed stream
characteristics. Thus, it would be difficult to evaluate the cost impacts
of RACT options based on this technology. Carbon adsorbers cannot achieve
98 weight-percent control in all cases and may not be applicable to
certain vent streams (i.e., streams containing sulfur compounds or heavy
metals) due to problems with carbon bed fouling. Finally, refrigerated
condensers and absorbers, while effective for certain SOCHI vent streams,
cannot achieve 98 weight-percent control in all cases because they are
highly dependent on the type and concentration of organic compounds
present in the vent stream. As explained in Section 6.5, recovery
devices, such as adsorbers, absorbers, and condensers, can be used as
pollution prevention techniques to meet the cutoffs described in
Section 6.3.
In summary, the control level for RACT is represented by a VOC
emission reduction of 98 weight-percent or reduction to 20 ppmv dry basis,
corrected to 3 percent oxygen. Section 6.3 discusses how to determine
which vent streams should apply control.
6.3 REASONABLY AVAILABLE CONTROL TECHNOLOGY SIZE CUTOFFS
Vent streams from reactor processes and distillation operations can
vary widely in flow rate, VOC concentration, heating value, and VOC
emission rate. Therefore, the uncontrolled emissions, emission
reductions, and control costs can also vary considerably for different
vent streams. Accordingly, it may not be reasonable from a technical or
economic standpoint to apply controls to all distillation and reactor vent
streams.
Important vent stream parameters in determining the emission
reduction and cost impacts of control are flow rate, heating value, and
VOC emission rate. Flow rate determines control device sizing and,
therefore, equipment cost. Vent stream heating value determines how much
supplemental fuel is necessary to support combustion. The VOC emission
rate determines the amount of emissions that can potentially be reduced.
It should be noted that heating value is closely related to VOC
6-3
-------
concentration. Similarly, VOC emission rate is dependent on the flow rate
and VOC concentration. In general, as flow rate and VOC concentration
Increase, the VOC emission reduction achievable by controlling these
streams increases and they become more cost effective to control.
Alternatively, if the flow rate and VOC concentration are low, the
achievable VOC emissions reduction is low and the cost effectiveness of
control is high.
The total resource effectiveness (TRE) Index was chosen as the
applicability approach to be adopted for this CT6. The TRE index is a
decision tool used to determine if the annual cost of controlling a given
vent gas stream is acceptable when considering the emission reductions
achieved. The TRE index equation is a measure of the cost per unit of VOC
emissions reduction and is normalized so that the decision point has a
defined value of 1.0. The variables in the TRE Index equation are the
stream characteristics (i.e., flow rate, heat value, VOC emission rate and
maximum cost effectiveness). If the result for plugging in the
characteristics of a specific vent stream is less than or equal to 1.0,
the stream could effectively be controlled further using a combustion
device (flare or incinerator). If the result of the TRE index equation is
greater than 1.0, the stream would not be controlled further without
incurring an unreasonable cost burden. The Radian memorandum, "Total
Resource Effectiveness Derivation," explains the TRE development and
results.*
6.4 IMPACTS OF APPLYING VARIOUS COST EFFECTIVENESS CUTOFFS
This section describes the impacts of applying various stream
parameters and cost-effectiveness value cutoffs to SOCMI reactor process
and distillation vent streams. Options for the recommended presumptive
norm for RACT have been identified using a TRE index less than or equal
to 1.0. Thus, the impacts analysis assumes that any vent stream with a
calculated TRE index of less than or equal to 1.0 would be required to
reduce emissions by 98 weight-percent (or to 20 ppmv) via thermal
incineration or flaring.
Table 6-1 summarizes the impacts of various options for the
recommended presumptive norm for RACT. These options are based on the
different maximum cost-effectiveness values for the model streams
6-4
-------
TABLE 6-1. SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY REASONABLY AVAILABLE CONTROL TECHNOLOGY
IMPACTS--HALOGENATED AND NONHALOGENATED VENT STREAMS*
Option
1
2
3
4
5
6
7
8
Max i nun Cost
effectiveness
(S/Mg)
All
20.000
10.000
8.000
5.000
3.000
2.500
2.000
Stream
controlled"
(X)
100
63
41
36
23
16
15
12
National
voc
emission
reduction0
(Mg/yr)
4,800
4,700
4.500
4.450
4.300
4.100
4,000
3.900
National
secondary
emissions
NO, (Max)d
(Mg/yr)
153 (48)
100 (48)
84 (8)
83 (8)
80 (2)
79
79
74
National
secondary
emissions
of CO*
(Mg/yr)
69
40
38
38
36
36
36
34
National
cost
impacts0' f
($ x 10*/yr>
6 - 13
3.4 - 7.3
2.3 - 4.5
2.0 - 3.9
1.7 - 2.5
1.6 - 1.9
1.5 - 1.8
1.3 - 1.5
Average
($ x lO'/Mg)
1.2
0.7
0.5
0.45
0.4
0.39
0.38
0.34
- 2.6
>
- 1.5
>
- 1
>
- 0.9
>
- 0.6
>
- 0.46
>
- 0.44
>
- 0.39
>
Incremental
CE'
($ x KP/Kg)
31 - 64
5.9 - 15
4.3 - 9
1.7 - 6.9
0.5 - 3.4
1.4 - 2.6
1.9 - 2.3
0.34 - 0.39
Average
emission
reduction
per vent in
increment
controlled9
(Mg/yr)
1.5
5.2
9.5
10.2
17.5
21.3
26.6
206
Average
cost per
vent in
increment
controlled''
($/yr)
93.000
80,000
85,000
70,000
59,000
55,000
62.000
80,000
•it is assumed that 95 percent control on all streams >5 Itm/hr reflects current level of control due to State regulations; based on first quarter
1990 dollars.
Represents the number of vent streams controlled at a particular cutoff level-divided by the total number of model vent streams in the data base.
clt is assumed that 60 percent of the facilities are nonattainment areas.
dNOx emission factors used:
Incinerators: 200 ppm in exhaust for streams containing nitrogen compounds, and 21.5 ppm NOX on all other streams (based on test data).
Flares: 0.05 lb/10* Btu (Based on EPA 600/2-83-052).
'CO emissions based on 20 lb/106 scf (AP-42).
'impacts shown for two cases: (1) utilization of existing controls for streams below 27 scfm, while streams above 27 scfm are costed with a dedicated device;
and (2) all streams costed with dedicated devices.
^Represents the additional emission reduction divided by the additional number of vent streams controlled at a particular cutoff level relative to the next
least stringent cutoff level.
Represents the additional cost divided by the additional number of vent streams controlled at a particular cutoff level relative to the next least
stringent cutoff level.
-------
controlled by each option. These impacts were calculated for a population
of model vent streams that represents a subset of SOCMI reactor process
and distillation facilities. National impacts were calculated by scaling
up impacts that would be incurred by a typical population of facilities
for this source category.3 A discussion of the procedure for estimating
impacts incurred by the model vent stream population 1s contained in the
Radian memorandum, "Reasonably Available Control Technology (RACT) Impacts
for the SOCMI CTG."5
After reviewing the impacts in Table 6-1, the EPA has selected option
number 7 as the recommended presumptive norm for RACT. This control level
would reduce an estimated 83 percent of the available VOC emissions and
would require controls on an estimated 15 percent of the vent streams for
a typical population of facilities. At the recommended cutoff level,
there are no technical reasons why controls could not be applied. In
fact, many facilities with reactor process and distillation operations are
already controlling streams of this size. The EPA recognizes that the
impacts estimation procedure includes certain average assumptions for
variables that affect emission reduction and cost. For example,
assumptions have been made regarding the piping distance to the control
device, and availability of space within existing facilities to
accommodate new control devices. However, it is the EPA's judgment that
even if the characteristics of any individual facility were to deviate
somewhat from the assumed characteristics, the feasibility and costs of
control would remain reasonable.
6.5 REASONABLY AVAILABLE CONTROL TECHNOLOGY SUMMARY
The recommended presumptive norm for RACT is the reduction of VOC
emissions by 98 weight-percent or to 20 parts per million by volume (ppmv)
on a dry basis, corrected to 3 percent oxygen in any vent stream that has
both a calculated TRE index less than or equal to 1.0. When calculating
aTo avoid "double-counting," national impacts include only those impacts
resulting from control after the implementation of the Hazardous Organic
National Emission Standard for Hazardous Air Pollutants (HON) has
occurred. The SOCMI CTG and HON process vents regulatory actions will
affect many of the same vents at SOCMI plants. In addition, only
facilities in nonattainment areas are considered subject to the CTG.
6-6
-------
the TRE index, the standardized TRE equation should be used with the plant
specific characteristics, not quoted values from vendors or manufacturers.
Several additional considerations in applying RACT warrant mention.
First, it is recommended that any vent stream for which an existing
combustion device is employed to control VOC emissions should not be
required to meet the 98 weight-percent destruction or 20 ppmv emission
limit until the combustion device is replaced. In other words, it is
recommended that facilities not be required to upgrade or replace existing
combustion devices. This approach would avoid penalizing those facilities
which have already undertaken efforts to control VOC emissions through
combustion, but whose control device is not designed to achieve the
98 weight-percent/20 ppmv level of control.
Second, it is important to note that the presumptive norm for RACT
provides incentives for pollution prevention by letting each facility
consider the trade-offs between process modifications and add-on controls.
Specifically, as an alternative to installing an add-on control device,
facilities can choose to improve product recovery equipment so that the
calculated TRE index falls above the cutoff value of 1.0. In this manner,
the facility would be limiting VOC emissions via process changes and would
thereby avoid having to install an add-on combustion device.
Another important consideration in applying RACT is emissions of
pollutants such as carbon monoxide and nitrogen oxides from
combustion-based control devices. The potential consequences of emission
from control devices are twofold. First, depending on the
VOC's-to-nitrogen oxides ratio in the ambient air, nitrogen oxides
emissions from control devices may cause more ozone to be formed than
could be eliminated through the VOC reductions. Second, emissions from
control devices may be enough to trigger New Source Review. (Table 6-1
shows expected national emissions of nitrogen oxides and, in parentheses,
the maximum annual emissions of nitrogen oxides at a single facility.)
Whether the VOC emission decreases are worth the increases in other
pollutants from the VOC control device is highly dependent on air quality
and meteorological conditions in each specific geographical area.
Therefore, States may select a less stringent level of control as RACT
based on these considerations.
6-7
-------
Finally, other regulatory Initiatives under Title I (Nonattainment)
and Title III (Air Toxics) provisions of the Clean Air Act Amendments of
1990 may result in the application of controls to vent streams with a TRE
index above the cutoff value of 1.0. For example, maximum achievable
control technology (MACT) requirements for the process vents portion of
the proposed HON may impact SOCHI vents more stringently than would the
presumptive norm for RACT as described above. Furthermore, all revised
ozone SIP's (except for "marginal" areas) must demonstrate a total net
reduction in VOC emissions in accordance with a specified percentage
reduction schedule. This requirement could also result in more stringent
control of SOCMI reactor process and distillation vents than would be
required by the presumptive norm for RACT.
6-8
-------
6.6 REFERENCES
1. Federal Register. State Implementation Plans; General Preamble for
Proposed Rulemaking on Approval of Plan Revisions for Nonattainment
Areas - Supplement (on Control Techniques Guidelines). 44 FR 53761-
53763. September 17, 1979.
2- Federal Register. Emissions Trading Policy Statement; General
Principles for Creation, Banking and Use of Emission Reduction
Credits. 51 FR 43814-43860. December 4, 1986.
3. Federal Register. Approval and Promulgation of Implementation Plan;
Illinois. 53 FR 45103-45106. November 8, 1988.
4. Hemorandum from Barbour, W. J., Radian Corporation, to L. Evans,
EPA/CPB. July 19, 1993. Total resource effectiveness equation
development.
5. Memorandum from Quincey, K. and Pring, M., Radian Corporation, to
L. Evans, EPA/CPB. November 17, 1992. Reasonably available control
technology (RACT) impacts for the SOCMI CTG.
6-9
-------
7,0 REASONABLY AVAILABLE CONTROL TECHNOLOGY IMPLEMENTATION
7.1 INTRODUCTION
This chapter presents information on factors State agencies should
consider when developing an enforceable rule limiting volatile organic
compound (VOC) emissions from synthetic organic chemical manufacturing
industry (SOCMI) reactor processes and distillation operations.
Information is provided on important definitions, rule applicability,
emission limit format, performance testing, monitoring, and
reporting/recordkeeping. Where several options exist for implementing a
certain aspect of the rule, each option is discussed along with its
relative advantages and disadvantages. In some cases, there may be other
equally valid options. The State or other implementing agency can
exercise its prerogative to consider other options provided the options
meet the objectives prescribed in this chapter.
For each aspect of the rule, one option is identified as the
preferred option. This guidance is for instructional purposes only and,
as such, is not binding. Appendix D contains an example rule that
incorporates the guidance provided in this document. The example rule
provides an organizational framework and sample regulatory language
specifically tailored for reactor processes and distillation operations.
As with the preferred option, the example rule is for instructional
purposes and is not intended to be binding. The State or other
implementing agency should consider all information presented in this
control techniques guideline (CTG), together with additional information
about specific sources to which the rule will apply. The reasonable
available control technology (RACT) rule should address all the factors
listed in this chapter to ensure that the rule is enforceable and has
reasonable provisions for demonstrating compliance.
7-1
-------
7.2 DEFINITIONS
The RACT rule should accurately describe the types of sources that
would be affected and clearly define terms used to describe the SOCMI
industry or applicable control methods. This section offers guidance to
agencies in selecting terms that need clarification when used in a
regulatory context. This section presents example definitions of
pertinent terms (or cites sources where definitions may be found) the
agency may refer to when drafting RACT regulations for these source
categories.
Two important terms that should be defined are "reactor processes"
and "distillation operations." An example definition of the first term
might be "unit operations in which one or more chemicals or reactants
other than air are combined or decomposed in such a way that their
molecular structures are altered and one or more new organic compounds are
formed." An example definition of the second term might read as: "an
operation separating one or more feed streams into two or more exit
streams, each exit stream having component concentrations different from
those in the feed streams. The separation is achieved by the
redistribution of the components between the liquid- and vapor-phase as
they approach equilibrium within the distillation unit." A detailed
discussion of these terms can be found in Sections 2.2 and 2.3 of this
document.
Certain types of equipment associated with reactor processes may need
further clarification, such as the terms "process unit" or "product."
Certain descriptors for reactor processes or distillation operations may
be helpful to define, such as "batch reactor process," "batch distillation
operation," "vent stream," or "halogenated vent stream." A discussion of
these terms is found in Chapter 2.0 of this document.
Other terms requiring definition are those used to describe emission
control techniques such as "recovery device," "incinerator," "flare,"
"boiler," and "process heater." A discussion of flares and incinerators
is presented in Section 3.1. A discussion of recovery devices is found in
Section 3.2. A description of boilers 1s given in Section 3.2.3.1 and a
description of process heaters is given in Section 3.2.3.2.
7-2
-------
Terms pertaining to equipment used in monitoring and recording
emissions which may also require further clarification are "continuous
recorder," "flow indicator," and "temperature monitoring device," An
example definition of continuous recorder might be "a data recording
device recording an instantaneous data value at least once every
15 minutes." An example definition of flow indicator might be "a device
which indicates whether gas flow is present in a line." Finally, an
example definition of temperature monitoring device might be "a unit of
equipment used to monitor temperature and having an accuracy of ±1 percent
of the temperature being monitored expressed in degrees Celsius or
±0.5 degrees Celsius, whichever is greater."
7.3 REGULATORY SUMMARY ;
The EPA has published one CTG, promulgated two New Source Performance
Standards (NSPS), and proposed a third NSPS for SOCMI. These regulatory
actions are summarized in the following subsections. Table 7-1 presents
the list of chemicals affected by the proposed and promulgated SOCMI NSPS
and air oxidation CTG. The marks alongside the chemicals indicate which
NSPS or CTG apply to that specific chemical.
7.3.1 A_1 r Qxidation Control Technijugs Guidelines
The air oxidation CTG published in December, 1984, was written in
response to the Clean Air Act Amendment of 1977. The purpose of the CTG
was to provide State and local air quality management agencies with an
initial information base for proceeding with their own assessment of RACT
for specific stationary sources. The cutoff total resource effectiveness
index (TRE) of 1.0 was based on a cutoff cost effectiveness value of
1,600 ($/megagram). Table 7-1 lists the chemicals affected by this CTG.
7.3.2 A1r OxidationProcessesNew SourcePerformance Standard
The NSPS for Volatile Organic Compound Emissions from the Synthetic
Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Processes
(55 FR Z6912, June 29, 1990: 40 CFR 60, Subpart III) was promulgated on
June 29, 1990. This NSPS regulates SOCMI air oxidation processes
constructed, reconstructed, or modified after October 21, 1983, that
produce any of the affected
7-3
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE
Chemical
Acet aldehyde
Acetaldol
Acetic acid
Acetic anhydride
Acetone
Acetone cyanohydrin
Acetylene
Acrylic acid
Acrylonitrile
Adipic acid
Adiponitrile
Alcohols, C-ll or lower, mixtures
Alcohols, C-12 or higher, mixtures
Alcohols, C-12 or higher, unmixed
Allyl chloride
Amylene
Amylenes, mixed
Aniline
An thraqu inone
Benzaldehyde
Benzene
Benzenesulfonic acid
Benzenesulfonic acid C^Q.^g-alkyl
derivatives, sodium salts
Benzoic acid tech
Benzyl chloride
Bisphenol h
Brometone
1,3 -Butadiene
Butadiene and butene fractions
n-Butane
1,4-Butanediol
Butanes, mixed
1-Butene
2-Butene
CAS number*
75-07-0
107-89-1
64-19-7
108-24-7
67-64-1
75-86-5
74-86-2
79-10-7
107-13-1
124-04-9
111-69-3
-
-
-
107-05-1
513-35-9
—
62-53-3
84-65-1
100-52-7
71-43-2
98-11-3
68081-81-2
65-85-0
100-44-7
80-05-7
76-08-4
106-99-0
-
106-97-8
110-63-4
—
106-98-9
25167-67-3
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
X
X
X
X
X
X
X
X
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE (CONTINUED)
Chemical
Butenes, mixed
n-Butyl acetate
Butyl acrylate
n-Butyl alcohol
sec-Butyl alcohol
tert-Butyl alcohol
p-1 Butyl ben zoic acid
Butylbenzyl phthalate
tert-Butyl hydroperoxide
2-Butyne-l , 4-diol
Butyraldehyde
n-Butyric acid
Butyric anhydride
Caprolactam
Carbon disulfide
I Carbon tetrabromide
tn Carbon tetrachlori.de
Chloroacetic acid
Chlorobenzene
Ch lorod i £ luoromet hane
Chloroform
p-Chloronitrobenzene
Chloro-4- (ethy lamino } - < isopropylamino ) -
8-triazine
Chloroprene
Citric acid
Crotona Idehyde
Crotonic acid
Cumene
Cumene hydroperoxide
Cyanuric chloride
Cyclohexane
Cyclohexane, oxidized
Cyclohexanol
Cyclohexanone
CRS number*
123-86-4
141-32-2
71-36-3
78-92-2
75-65-0
98-73-7
85-86-7
75-91-2
110-65-6
123-72-8
107-92-6
106-31-0
105-60-2
75-15-0
558-13-4
56-23-5
79-11-8
108-90-7
75-45-6
67-66-3
100-00-5
1912-24-9
126-99-8
77-92-9
4170-30-0
3724-65-0
98-82-8
80-15-9
108-77-0
110-82-7
68512-15-2
108-93-0
108-94-1
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
X
X
X
X
X
X
X
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE (CONTINUED)
-4
I
Chemical
Cyclohexanone ox line
Cyclohexene
1 , 3 -Cy c lopen t ad iene
Cyclopropane
Diacetone alcohol
Dibutanized aromatic concentrate
1, 4-Dlchlorobutene
3, 4-Dichloro-l-butene
Dichlorodif luoromethane
Dichlorodlmethylsilane
Dichlorof luoromethane
Diethanolamine
Diethylbenzene
Diethylene glycol
Di-ieodecyl phthalate
Diiaononyl phthalate
Dimethylaraine
Dimethyl terephthalate
2, 4- (and 2»6)-dinltrotoluene
Dloctyl phthalate
Dodecene
Dodecylbenzene, nonlinear
Dodecylbenzeneaulf onic acid
Dodecylbenrenesulfonic acid, sodium salt
Epichlorohydrin
Ethanol
Ethanolamlne
Ithyl acetate
Ethyl acrylate
Ethylbenzene
Ethyl chloride
Ethyl cyanide
Ethylene
Ethylene dibr oroide
CAS number3
100-64-1
110-83-8
110-83-8
75-19-4
123-42-2
-
110-57-6
64037-54-3
75-71-8
75-78-5
75-43-4
111-42-2
25340-17-4
111-46-6
26761-40-0
28553-12-0
124-40-3
120-61-6
121-14-2
606-20-2
117-81-7
25378-22-7
-
27176-87-0
25115-30-0
106-89-8
64-17-5
141-43-5
141-78-6
140-88-5
100-41-4
75-00-3
107-12-0
74-85-1
106-93-4
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
X
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE (CONTINUED)
Chemical
Ethylene dichloride
Ethylene glycol
Ethylene glycol monobutyl ether
Ethylene glycol monoethyl ether acetate
Ethylene glycol monomethyl ether
Ethylene oxide
2-Ethylhexyl alcohol
(2-Ethylhexyl) amine
6-Ethyl-l, 2 , 3 , 4-tetrahydro-9 , 10-antracenedione
Formaldehyde
Formicacid
Glycerol
Glyoxal
n-Heptane
Heptenei (mixed)
Hexamethylene diamine
Hexamethylene diamine adipate
Hexamethylenetetramine
Hexane
2-Hexenedinitrile
3-Hexenedinitrile
Hydrogen cyanide
iBobutane
Iflobutanol
laobutylene
Isobutyric acid
I aobytyraldehyde
leodecyl alcohol
laooctyl alcohol .
iBopentane
laoprene
Isopropanol
Ketene
Linear alcohols, ethoxylated, mixed
CAS number*
107-06-2
107-21-1
111-76-2
111-15-9
109-86-4
75-21-8
104-76-7
104-75-6
15547-17-8
50-00-0
64-18-6
56-81-5
107-22-2
142-82-5
-
124-09-4
3323-53-3
100-97-0
110-54-3
13042-02-09
1119-85-3
74-90-8
75-28-5
78-83-1
115-11-7
79-31-2
78-84-2
25339-17-7
26952-21-6
78-78-4
78-79-5
67-63-0
463-51-4
-
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
X
X
X
X
.
X
X
X
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE (CONTINUED)
I
CO
Chemical
Linear alcohols, ethoxylated, and Bulfated,
sodium salt, mixed
Linear alcohols, sulfated, sodium salt, mixed
Linear alkylbenzene
2 -Methyl pentane
1 -Methy 1-2 -pyrrol idone
Magnesium acetate
Maleic anhydride
Melamine
Meaityl oxide
Methacrylonitrile
Methane 1
Methylamine
ar-Methylbenzenediamine
Methyl chloride
Methylene chloride
Methyl ethyl ketone
Methyl isobutyl ketone
Methyl met hacry late
1 -Methyl -2 -py rr o 1 idone
a-Methyl styrene
Methyl tert-butyl ether
Naphthalene
Nitrobenzene
1-Nonene
Nonyl alcohol
Nonylphenol
Nonylphenol, ethoxylated
Oil-noluble petroleum sulfonate,
•odium salt
Octene
Oil -soluble petroleum aulfonate,
calcium aalt
n-Petane
Pentaerythritol
CAS number*
-
123-01-3
107-83-5
872-50-4
142-72-3
108-31-6
108-78-1
141-79-7
126-98-7
67-56-1
74-39-5
25376-45-8
74-87-3
75-09-2
78-93-3
108-10-1
80-62-6
872-50-4
98-83-9
—
91-20-3
98-95-3
27215-95-8
143-08-08
25154-52-3
9016-45-9
-
25377-83-7
-
109-66-0
115-77-5
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
X
X
X
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE (CONTINUED)
Chemical
3-Pentenenitrile
Pentenes, mixed
Perchloroethylene
Phenol
1-Phenylethyl hydroperoxide
Pheny 1 propane
Phosgene
Phthalic anhydride
Propane
Propionic acid
Propionaldehyde
Propyl alcohol
Propylene
Propylene chlorohydrin
Propylene glycol
Propylene oxide
Sodium cyanide
Sorbitol
Styrene
Terephthalic acid
Tetraethyl lead
Tetrahydrofuran
Tetra (methyl-ethyl) lead
1,1,2, 2-Tetrachloroethane
Tetraethyl lead
Tetramethyl lead
Toluene
Toluene-2 , 4-diamine
Toluene-2 , 4- ( and, 2,6) -diiaocyanate
(80/20 mixture)
Tribromomethane
1, 1, 1-Trichloroethane
1, 1,2-Trichloroethane
Trichloroethylene
Trichlorofluoromethane
CAS number3
4635-87-4
109-67-1
127-18-4
108-95-2
3071-32-7
103-65-1
75-44-5
85-44-9
74-98-6
79-09-4
123-38-6
71-23-8
115-07-1
78-89-7
57-55-6
75-56-9
143-33-9
50-70-4
100-42-5
100-21-0
78-00-2
109-99-9
-
79-34-5
78-00-2
75-74-1
108-88-3
95-80-7
26471-62-5
75-25-2
71-55-6
79-00-5
79-01-6
75-69-4
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
X
X
X
X
X
X
X
-------
TABLE 7-1. CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY RULES AND GUIDELINE (CONTINUED)
Chemical
l»l,2-Trichloro-l,2,2-trifluoroethane
Triethanolamine
Triethylene glycol
Vinyl acetate
Vinyl chloride
Vinylidene chloride
m-Xylene
o-Xylene
p-Xylene
Xylenes (mixed)
m-Xylenol
CAS number3
76-13-1
102-71-6
112-27-6
108-05-4
75-01-4
75-35-4
108-38-3
95-47-6
106-42-3
1330-20-7
576-26-1
Reactor
NSPS
X
X
X
X
X
X
X
X
X
X
Distillation
NSPS
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation
CTG/NSPS
*CAS numbers refer to the Chemical Abstracts Registry numbers assigned to specific chemicals, isomers,
or mixtures of chemicals. Some isomers or mixtures that are covered by the standards do not have CAS
numbers assigned to them. The standards apply to all of the chemicals lilted, whether CAS numbers
have been assigned or not.
-------
chemicals listed in Table 7-1 as a product, co-product, by-product, or
intermediate.
7.3.3 Distillation Process New Source Performance Standard
The NSPS for Volatile Organic Compound Emissions from the Synthetic
Organic Chemical Manufacturing Industry Distillation Operations
(55 FR 26931, June 29, 1990; 40 CFR 60, Subpart NNN) was also promulgated
on June 29, 1990. This NSPS covers SOCMI distillation operations
constructed, reconstructed, or modified after December 30, 1983, that
produce any of the affected chemicals listed in Table 7-1 as a product,
co-product, or intermediate.
7.3.4 Reactor Process New Source Performance Standard
Standards of performance for SOCMI reactor process operations were
proposed in the Federal Register on June 29, 1990 (55 FR 26953),* but have
not yet been promulgated. The proposed standards apply to reactor
processes operating as part of a process unit that produces any of the
affected chemicals listed in Table 7-1 as a product, by-product,
co-product, or intermediate.
7.4 APPLICABILITY
Because most industrial plants are comprised of numerous pieces or
groups of equipment that may be viewed as "sources" of air pollutant
emissions, it is helpful to define the specific source or "affected
facility" that will be regulated. A possible definition for affected
facility is "an individual reactor or distillation column with its own
individual recovery system (if any) or the combination of two or more
reactors or distillation columns and the common recovery system they
share." Reactors or distillation units operated in a batch mode are
excluded from this definition since this CTG focuses on reactor processes
and distillation operations that are continuous. Also excluded from this
definition are distillation operations that are a part of polymer
manufacturing processes.
Other facilities to consider exempting from RACT requirements include
reactor or distillation processes in plants with very low capacities.
Most research and development facilities or laboratory-scale facilities
are not designed to produce more than 1 gigagram (2.2 x 106 pounds) of
chemicals per year. These facilities generally operate on an intermittent
7-11
-------
basis making control techniques that apply to Industry-scale production
facilities inappropriate for these operations. For these same reasons, it
may also be appropriate to exempt facilities with vent stream flow rates
or VOC concentrations below a specified level. It would be appropriate,
however, to require Initial measurements or engineering assessments and
reports of the low flow rate to verify that these facilities are entitled
to the exemption. It may also prove valuable to require owners and
operators of both low capacity and low flow rate facilities to report if a
process or equipment change occurs that increases the production capacity
or flow rate above the specified cutoff levels.
7.5 FORMAT OF THE STANDARDS
Several formats are available for RACT regulations covering these
source categories. Because emissions can be measured from reactor process
and distillation operation vents and from applicable control devices, an
emission limitation (performance) standard, rather than an equipment
standard, is recommended.
Possible emission limitation formats would include a mass emission
rate limit, a concentration limit, or a percent reduction level. A
percent reduction format best represents performance capabilities of
control devices used to comply with the RACT regulation. Alternate
formats (such as mass emission rate or concentration limit) could cause
greater control than is required by RACT at some sources versus others and
less control than is required by RACT at others. For example, under a
mass emission rate or concentration format, the required control
efficiency is greater for streams with higher emission rates or higher
vent stream concentrations. Furthermore, the required control level for
vent streams with a low mass emission rate or concentration would not
reflect the capabilities of RACT.
A weight-percent reduction standard is feasible when applied to
incinerators, boilers, and process heaters because emission rates can be
measured readily from the control device inlet and outlet. As discussed
in Chapter 3.0 of this document, new incinerators can achieve at least
98 weight-percent reduction in total organics (minus methane and ethane),
provided that the total organic (minus methane and ethane) concentration
of the process vent stream is greater than approximately 2,000 parts per
7-12
-------
raillion by volume (ppmv). For vent streams with organics concentrations
below 2,000 ppmv, a 98 weight-percent reduction may be difficult to
achieve, but an incinerator outlet concentration of 20 ppmv dry basis,
corrected to 3 percent oxygen is achievable. Therefore, the recommended
option is an emission limitation format based on a combination
weight-percent reduction standard and a volume concentration standard.
This recommended standard would demonstrate a 98 weight-percent reduction
in total organic compounds (minus methane and ethane) or a reduction to
20 ppmv total organic compounds (minus methane and ethane) dry basis,
corrected to 3 percent oxygen, whichever is less stringent.
Available data indicate that boilers and process heaters with design
heat input capacity greater than 150 million British thermal unit per hour
(MHBtu/hr) can achieve at least a 98 weight-percent reduction provided the
waste stream is introduced into the flame zone where temperatures are
highest 1,538 to 1,649 °C (2,800 to 3,000 °F). Therefore, vent stream
combustion in a boiler or a process heater of this size makes performance
testing unnecessary. However, to ensure sufficient destruction of the
VOC, the regulation must require that the vent stream be introduced into
the flame zone.
Flares differ from boilers, process heaters, and incinerators because
combustion occurs in the open atmosphere rather than in an enclosed
chamber. For this reason, it is difficult to measure the emissions from a
flare to determine flare efficiency. However, the EPA test data indicate
that if certain design and operating condition are met, flares can be
presumed to be in compliance with the 98 percent/20 ppmv dry basis,
corrected to 3 percent oxygen, emission limit. These conditions are found
in Section 118 of Part 60 of Chapter 40 of the Code of Federal Regulations
(40 CFR 60).1
7.6 PERFORMANCE TESTING
When the owner or operator of an affected facility conducts either an
initial or subsequent performance test, it is recommended that the
facility be running at full operating conditions and flow rates.
Performance tests needed to achieve the specified RACT requirements are an
initial test for a facility demonstrating either compliance with the
98-percent/20 ppmv emission limit, or maintenance of vent stream flow
7-13
-------
rates and VOC concentrations at levels that assuie a TRE value greater
than 1.0. Specific recommendations pertaining to performance and
compliance testing are provided in Appendix D of this document.
The best available procedure recommended for determining
concentrations from reactor process and distillation vents Is EPA
Method 18. This method has the advantage of being able to detect and
measure individual organic compounds. Details concerning the use of this
method, including sampling, analysis, preparation of samples, calibration
procedures, and reporting of results are discussed in Appendix D of this
document. All of the reference methods mentioned in this section are
found in Appendix A of 40 CFR 60.
7,6.1 Incinerators
For the owner or operator of a facility using an incinerator to
achieve the suggested RACT emission limit. Reference Method 18 is
recommended for determining compliance during any performance test.
Reference Method 1 or 1A is recommended for selecting the sampling site.
To determine the reduction efficiency, it is recommended that the control
device inlet sampling site be located prior to the control device inlet
and following the product recovery device. Reference Methods 2, 2A, 2C,
or 20 are recommended for determining the volumetric flow rate, and
Reference Method 3 is recommended for determining the air dilution
correction, based on 3 percent oxygen in the emission sample.
7.6.2 Flares
The recommended compliance test for a flare includes measuring exit
velocity and stream heat content to verify compliance with the operating
specifications listed in 40 CFR 60.18.
7-6.3 Boiler or Process Heater
The performance test requirements for a small boiler or process
heater (less than 150 MMBtu/hr) are Identical to those for incinerators.
For a large boiler or process heater, the initial performance test could
be waived. It is the EPA's judgment that a boiler or process heater of
this size would be able to meet the 98 percent/20 ppmv dry basis,
corrected to 3 percent oxygen emission limit provided that the vent stream
is introduced into the flame zone of the boiler or process heater.
7-14
-------
7.6,4 Recovery Devices
A facility may choose to comply with RACT requirements by maintaining
its product recovery system in such a manner that the vent stream flow
rate and VOC concentration are below the cutoff points. Calculation of
flow rate and VOC concentration must be immediately downstream of all
product recovery equipment and prior to the introduction of any
nonaffected stream. It is recommended that the volumetric flow rate be
determined according to Reference Methods 2, 2A, 2c, or 20, as
appropriate. Molar composition of the vent stream should be measured via
Reference Method 18.
7.7 COMPLIANCE MONITORING REQUIREMENTS
Note: The monitoring requirements need to be consistent with the
Enhanced Monitoring Rule, once it is promulgated. The Hazardous Organic
National Emission Standard for Hazardous Air Pollutants (HON) can be used
as guidance in the interim. If a facility is covered by the HON, the HON
monitoring requirements would also satisfy the RACT compliance
determination requirements, and no additional monitoring is necessary.
7.7.1 Thermal Incinerators
There are two possible monitoring methods for facilities with an
incinerator to determine compliance with the suggested RACT emission
limit. They are continuous emission monitoring and continuous combustion
control device monitoring. Continuous combustion control device inlet and
outlet monitoring is preferred because it would give a continuous, direct
measurement of actual emissions. However, no continuous monitor measuring
total organics has been demonstrated for incinerators because each of the
many diverse types of compounds in process vent streams would have to be
identified separately and the concentrations of each determined.
Continuous monitoring of all the individual compounds would be too
expensive to be practical.
The other possible monitoring method is continuous combustion control
device measurement. Certain parameters, such as temperature and flow
rate, when measured, can reflect the level of achievable control device
efficiency. It has been demonstrated that a decrease in combustion
temperatures from the design value can cause significant decreases in
control device efficiency. Because temperature monitors are relatively
7-15
-------
inexpensive and easy to operate, it is recommended that the owner or
operator of an affected facility should be required to install, calibrate,
maintain, and operate a temperature measurement device according to
manufacturer's instructions.
Flow indicators are also relatively inexpensive and easy to operate.
Flow indicators determine control device efficiency by indicating whether
or not organic-laden streams are being routed for destruction. It is
recommended that the owner or operator of an affected facility should be
required to install, calibrate, maintain, and operate a flow indicator
according to the manufacturer's specifications. It is recommended that
the flow indicator be installed at the entrance to any bypass line that
could divert the stream away from the combustion device to that
atmosphere.
7.7.2 Flares
In order comply with the recommended RACT requirements (see
Section 7.5), flares must be operated in accordance with 40 CFR 60.18.
Visual inspection is one method of determining whether a flame is present;
however, if the flare is operating smokelessly, visual inspection would be
difficult. An inexpensive heat sensing device, such as an ultra-violet
beam sensor or a thermocouple, is recommended for use at the pilot light
to indicate continuous presence of a flame. Measuring combustion
parameters (as recommended for incinerators), such as temperature and flow
rate, is not feasible for flares because these parameters are more
variable in an unenclosed combustion zone.
It is also recommended that flow rate and heat content of the flared
stream be determined by a flow indicator in the vent stream of the
affected facility. This should be performed at a point closest to the
flare and before the stream is joined with any other vent stream.
7.7,3 Boiler or Process Heater
To ensure that a boiler or process heater is operating properly as a
combustion control device, it is recommended that the owner or operator
maintain steam production (or equivalent) records. The owner or operator
should also install and operate a flow indicator that provides a record of
vent stream flow to the boiler (or process heater). It is recommended
that temperature be monitored for boilers and process heaters of less than
7-16
-------
150 MMBtu/hr design heat input capacity. Any boiler or process heater in
which all vent streams are introduced with primary fuel is exempt from
this requirement.
7.7.4 RecoveryDevices
Facilities using product recovery devices to determine compliance
with the recommended RACT, should ensure that the measured flow rate and
VOC concentration have not changed since the time of the initial
performance test. To accomplish this the facility owner or operator
should monitor product recovery device parameters that correlate with
proper operation of the device. The type of parameters to be monitored
depends on the final device in the product recovery system.
For an absorber, two operating parameters are recommended as adequate
determinants of performance: the specific gravity of the absorbing liquid
and the flow rate of the absorbing liquid. For a condenser, the exit
stream temperature is recommended as the main determinant of performance.
For a carbon adsorber, the carbon bed temperature (after regeneration and
completion of any cooling cycle) and the quantity of steam used to
regenerate the carbon bed are recommended as the main determinants of
performance.
As an alternative to monitoring the above parameters, the EPA
recommends that a vent stream (post-recovery system) organic monitoring
device with a continuous recorder be allowed.
7.8 REPORTING/RECORDKEEPING REQUIREHENTS
Each facility subject to the RACT requirements should keep records of
certain key parameters that would indicate compliance. First, the
facility should identify the control method selected to meet the RACT
requirements. Next, the results of any performance testing results
(discussed in Section 7.6) should be recorded. Further, the facility
should record all parameters monitored on a routine basis to determine
continued compliance with the RACT emission limit. These parameters
(listed 1n Section 7.7) differ depending on the means by which the RACT
requirements are met. Any deviations of the monitored parameters listed
in Section 7.7 should also be recorded along with any corrective actions.
7-17
-------
7.9 REFERENCES
!• Federal Register. Standards of Performance for New Stationary
Sources; Volatile Organic Compound (VOC) Emissions from the Synthetic
Organic Chemical Manufacturing Industry (SOCHI) Distillation
Operations. Final rule. 55 FR 26931-26952. June 29, 1990.
2. U, S. Environmental Protection Agency. Code of Federal Regulations.
Chapter 40, Part 60. Washington, D.C. Office of the Federal
Register. July 1, 1990. pp. 630 through 633.
7-18
-------
APPENDIX A
LIST OF SYNTHETIC ORGANIC CHEMICAL
MANUFACTURING INDUSTRY CHEMICALS
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEHICAL MANUFACTURING INDUSTRY CHEMICALS
CAS
nuitoer
83-32-9
105-57-7
107-89-1
60-35-5
103-84-4
10S-24-7
123-86-4
108-05-4
141-78-6
142-72-3
102-01-2
...
...
...
79-06-1
...
...
72-48-0
00-8
...
Chemical
Acenaphthem (POM)
Acetal
Aeetaldol
Acet amide
Aeetanilide
Acetic acid, anhydride
Acetic acid, butyl ester
Acetic acid, ethenyl ester
Acetic acid, ethyl ester
Acetic acid, magnesitnt salt
Acetoacetanilide
Acetoantides
Acetyl chloride
Acetylene tetrabromide
Acrylamide
Alcohols, C-11 or loner, mixtures
Alcohols, C-12 or higher, mixtures
Alizarin (POM)
Alkyl anthraqui nones
Alkyl naphthalenes sulfonates
Reactor and
distillation
CTG
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included Air
in-HOH oxidation Distillation Reactor
impacts SOCHI processes operations processes
analysis list NSPS NSPS NSPS
X
X
X
X
X
X XX
X X
X X X
X X
X
X
X
X
X
X
X X
X X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nunber Chemical
107-18-6 Allyl alcohol
Allyl bromide
109-75-1 Allyl cyanide
Aluminum acetate
Aluminum formates
— Aminobenzoic acid (p-)
141 -43-5 2-Aminoethanol
— Aminoethylethanolamine
I 0-01-0 Aminophenol sulfonic acid
123-30-8 Aminophenol (p-isomer)
Amino-3,4,6-trichlorophenol (2-)
— Ammonium acetate
— Ammonium thiocyanate
— Amyl acetates
Amyl alcohol (n-)
Amyl alcohol (tert-)
Amyl alcohols (mixed)
Amyl chloride (n-)
Amyl chlorides (mixed)
Reactor and
distillation
CTG
X
X
X .
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included Air
in-HON oxidation Distillation Reactor
impacts SOCHI processes operations processes
analysis list NSPS NSPS NSPS
X
X
X
X
X
X
X X
X
X
X
X
X
X
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEHICAL HANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuriber
...
...
142-04-1
90-04-0
...
120-12-7
...
103-33-7
1
W
...
62-53-3
71-43-2
98-48-6
121-91-5
100-21-0
117-81-7
Chemical
Amy I ether
Amy I amines
Aniline hydrochloride
Anisidine (o-fsomer)
Anisole
Anthracene (POM)
Anthrenil ic acid
Azobenzene
Barium acetate
Benzamide
Benzenamine
Benzene
'Benzenedisulfonic acid
1,3-Benzenedicarboxylic acid
1,4-Benzenediearboxylic acid
1,2-Benzenedicarboxylic acid.
Reactor and
distillation
CTG
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in- HOW
impacts SOCMI
analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X X
X X
X X
XXX
bis (2-ethylhexyl) ester
85-68-7 1,2-Benzenedicarboxylic acid
butyl, phenylmethyl ester
1,2-Benzenedicarboxylic acid
di-n-heptyl-n-nonyl undecyl ester
-------
CAS
renter
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
Chemical
Reactor and
distillation
CTG
Included
in-HON
impacts
analysis
SOCHI
list
Air
oxidation
processes
NSPS
Distillation
operations
NSPS
Reactor
processes
NSPS
26761-40-0 1,2-Benzenedicarboxylic acid
diisodecyl ester
1,2-Benzenedicarboxylic acid
diisononyl ester
120-61-6 1.4-Benzenedicarboxylic acid,
dimethyl ester
98-48-6 Benzenedisulfonic acid
98-11-3 Benzenesulfonic acid
Benzenesulfonic acid,
mono-CiQ.ig-alkyl derivatives,
sod inn salts
Benzidine
134-81-6 Benzil (POM)
76-93-7 Benzilic acid (POM)
Benzoguanamine
119-53-9 Benzoin (POM)
100-47-0 Benzonitrile (POM)
119-61-9 Benzophenone (POM)
98-07-7 Benzotrlchloride
96-88-4 Benzoyl chloride
Benzoyl perioxid*
140-11-4 Benzyl acetate
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nwfcer
100-51-6
120-51-4
98-87-3
...
...
92-52-4
542-88-1
> 115-77-5
tn
108-86-1
27497-51-4
...
123-72-8
106-97-8
...
584-03-2
107-88-0
110-63-4
106-31-0
71-36-3
Chemical
Benzyl alcohol
Benzyl benzoate (POM)
Benzyl di chloride
Benzylamlne
Benzyl Ideneacetone
1,1-Biphenyl
Bis (chloromethyl) ether
(dichloromethyl ether)
2,2-Bis (hydroKymethyl)-
1,3-propanediol
Bromobenzene
Bromonaptithalene (POM)
Butadiene and butene fractions
Butanol
Butane
Butanes, mixed
1,2 (and 1,3) Butanediol
1,4-Butanediol
Butanofc acid, anhydride
1-Butanol
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X X
X X
X X
X X
X X
X X
X X
X X
X X
X X
X
X
X
X
X X
X X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X
X X
X X
X X
X X
X X
X
X X
X X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEHICAL HANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
s<
CAS
nunber Chemical
ButylMine (s-isomer)
ButylMine (t-isomer)
Butylbenzene Ctert-)
tert-Sutylbenzene
Butylbenzoic acfd (p-tert-)
85-68-7 Butylbenzyl phtnalate
p-tert -Butyl toluene
110-65-6 2-Butyne-1,4-diol
Butyrolactone
Sutyronitrile
— Calcium acetate
— Calcium propionate
Caproic acid
--- Carbamic acid, monoanmoniun salt
63-25-2 Carbaryl
86-74-8 Carbazole
75-73-0 Carbon tetrafluoride
75-1S-0 Carbon disulf ide
75-44-5 Carbonic dichloride
Reactor and
distillation
CTG
X
X
X .
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in-HON
impacts SOCHI
analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation teactor
processes operat ions processes
NSPS NSPS NSPS
X
X
X X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
75-87-6
...
79-11-8
532-27-4
...
...
106-47-8
>
I
CO 108-90-7
...
...
...
.
...
126-99-8
25497-29-4
75-45-6
75-00-3
108-05-4
Chemical
Chloral
Chloranil
Chloroacetic acid
Chloroacetophenone (2-)
Chloroani line (m-i saner)
Chloroani line {o-isomer)
Chloroani line (p-isomer)
Chi orobenza I dehyde
Chlorobeniene
Chlorobenzoic acid
Chlorobeniotrichlor Ide (o-}
Ch I orobeniotri chloride (p-)
.Chlorobenzoyl chloride (o-)
Chlorobenzoyl chloride (p-)
2-Chloro-1,3-butadtene
Chlorodif luoroethane
Ch 1 orodi f I uorome thane
Chloroethane
Chloroethene
Reactor and
distillation
CTC
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in-HON
impacts SOCHI
analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
HSPS NSP5 HSPS
X " X
X
X X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
1912-24-9
...
...
74-87-3
100-00-5
106-89-8
25586-43-0
1 121-73-3
V£>
88-73-3
109-69-3
...
78-89-7
107-05-1
...
108-41-8
95-49-8
106-43-4
...
Chemical
6-Chloro-N-ethyl-N'-
(1-methylethyl)-1,3,5-
triazine-2,4-diamine
Ch I orof I uorocarbons
Chlorohydrin
Chloromethane
(Chloromethyl) benzene
(Chloromethyl) oxirane
Chloronaphthalene (POM)
Chloronitrobenzene (1,3-)
Chloronitrobenzene (o-isomer)
1-Chloro-4-nitrobenzene
Chlorophenols (all isomers)
2 - Ch I oro- 1 - propane I
3 - Ch 1 oro- 1 - propene
Chlorosulfonic acid
Chlorotoluene (m-isomer)
Chlorotoluene (o-isomer)
Chlorotoluene (p-isomer)
Chlorotrifluoroethylene
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X
X X
X X
X
X X
X X
X X
X X
X X
X X
X X
X
X X
X X
X X
X X
X X
X X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X
X X
X X
X X
X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
75-72-9
...
218-01-9
...
...
...
...
•f 108-39-4
L_^«
0 1319-77-3
95-48-7
106-44-5
...
372-09-8
0-01-1
...
...
110-82-7
...
...
Chemical
Ch lorot r i f I uoronethane
Cholint chloride
Chrysen* (WX)
Ctnramic acid
Cobalt acetate
Coconut oil acids, sodium salt
Copper acetate
Cresol (m-isomer)
Cresols/cresylie acid (mixed)
Cresols (o-isomer)
Cresols (p-isomer)
Cyanamide
Cyanoacetic acid (CM compound)
Cyanof ormam i de
Cyanogen chloride (CD compound)
Cyanuric acid
Cyclohexane
Cyclohexane, oxidized
Cyclohexanone oxime
Included
Reactor and in-HON
distillation impacts
CTG analysis
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
SOCHI
list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
HSPS NSPS MSPS
X X
X X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
muter
110-83-8
108-91-8
111-78-4
1552-12-1
542-92-7
75-19-4
91-17-8
0-01-2
...
131-17-9
...
137-09-7
117-83-9
106-93-4
---
27134-27-6
106-46-7
541-73-1
95-50-1
Reactor and
distillation
Chemical CTG
Cyclohexene
Cyclohexylamine
Cyclooctadiene
Cyclooctadiene (1,5-isomer)
1 ,3-Cyclopentadiene
Cyclopropane
Decahydronaph thai ate
Diacetoxy-2-Butene (1,4-)
Diallyl isophthalate
Diallyl phthalate
Diaminobenzoic acids
Diaminophenol hydrochloride
Dibutoxyethyl phthalate
1,2-Dibromoethane
Di botanized aromatic concentrate
Dichloroani line (all isomers)
Dichlorobenzene (1,4-isomer) (p-isomer)
Dichlorobenzene (m-isomer)
Dichlorobenzene (o-isomer)
X
X
X
X
X
X
X
X
X
X
X
X
X'
X
X
X
X
X
X
Included Air
in-HON oxidation Distillation Reactor
impacts SOCHI processes operations processes
analysis list NSPS NSPS NSPS
X X
X
X
X
X X
X
X
X
X
X
X
X
X XX
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuitoer
91-94-1
760-23-6
764-41-0
111-44-4
540-59-0
...
...
1
NJ
...
542-75-6
...
...
764-41-0
...
75-71-8
75-78-5
107-06-2
75-35-4
Reactor and
distillation
Chemical CTG
Dichlorobenzidine (3,3'-)
Dichloro-1-butene (3,4-isomer)
Oichloro-2-butene (1.4-isomer)
Oichloroethyl ether
(bis(2-chloroethyl )ether)
Dichloroethylene (1,2-isomer)
D ich loroni trobenzenes
Oichloropane (1,1-)
D ichloropentanes
Dichlorophenol (2,4-isomer)
Dichloropropane (1,1-)
Dichloropropene (1,3-isomer)
Oichloropropene/dichloropropane (mixed)
D i ch I orotet raf luoroethane
1,4-Oichloro-2-butene
3,4-Dichloro-1-butene
D i ch lorodi f I uoromethane
Dichlorodimethylsilane
1.2-Dichloroethane
1,1-Dichloro«thene
X
X
X.
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included Air
in-HON oxidation Distillation Reactor
impacts SOCHI processes operations processes
analysis list NSPS NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
75-43-4
75-09-2
96-23-1
...
...
---
25340-17-4
84-66-2
64-67-5
109-89-7
579-66-8
121-69-7
112-73-2
112-36-7
111-96-6
124-17-4
112-34-5
Chemical
Dichlorof luoromethane
Dichlorome thane
1,3-Di chloro-2-prepanol
Dicyanidianide
Dicyclohexylamine
Dicyclopentadiene
Diethylbenzene
Diethyl phthalate
Oi ethyl sulfate
Di ethyl ami ne
Oiethylaniline (2,6-isomer)
Diethyl aniline (H,N-)
Oiethylene glycol dibutyl ether
Diethylene glycol diethyl ether
(glycol ether)
Oiethylene glycol dimethyl ether
(glycol ether)
Oiethylene glycol monobutyl ether
acetate (glycol ether)
Diethylene glycol monobutyl ether
Reactor and
distillation
CT6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in-HON
impacts SOCHI
analysts list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X X
X X
X
X X
(glycol ether)
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
112-15-2
111-90-0
629-38-9
111-77-3
...
...
584-84-9
91-08-07
27554-26-3
...
...
...
119-93-7
115-10-6
68-12-2
57-14-7
131-11-3
77-78-1
Chemical
Diethylene glycol monoethyl ether
acetate (glycol ether)
Diethylene glycol monoethyl ether
(glycol ether)
Diethylene glycol monomethyl ether
acetate (GE)
Diethylene glycol monomethyl ether
(glycol ether)
Difluoroethane (1,1-)
Diisobutylene
1,3-Diisocyanato-2-(and 4-)
methy (benzene (80/20 mixture)
Dilsooctyl phthalate
Diisopropyl amine
Diketene
Dimethyl acetamide
Dimethyl benzidine (3,3-isomer)
Dimethyl ether - N.N
Dimethyl formmide (NN-isomer) (DMF)
Dimethyl hydrazine (1,1-isomer)
Dimethyl phthalate
Dimethyl sulfate
Included
Reactor and in-HOM
distillation impacts
CTG analysis
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
SOCHI processes operations processes
list NSPS NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
...
...
108-01-0
121-69-7
95-47-6
108-38-3
106-42-3
>• 1330-20-7
1
£ 75-91-2
1300-71-6
25154-54-5
...
51-28-5
...
...
123-91-1
646-06-0
101-81-5
101-84-8
Chemical
Dimethyl sulfide
Dimethyl sulfoxide
Dimethylminoethanol (2-isomer)
Dimethyl aniline - N,N
(N,N Diethylaniline)
1,2-Dimethylbenzene
1 ,3-D i methyl benzene
1 ,4-Dimethylbenzene
Dimethylbenzenes (mixed)
1, 1-Dimethylethyl hydroperoxide
2,6-Dimethylphenol
Dinitrobenzenes
Dinitrobenzoic acid (3,5-)
Dinitrophenol (2,4-isomer)
Dinitrotoluene (2,3-)
Dinitrotoluene (3,4-)
Dioxane (1,4-Diethyleneoxide)
Di oxo lane
Diphenyl methane
Diphenyl oxide (POM)
Reactor and
distillation
CTG
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in-HOM
impacts SOCMI
analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operat i ons processes
NSPS NSPS NSPS
X X
X X
X X
X X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
muter
102-08-9
122-39-4
110-98-5
117-82-8
97-39-2
6842-15-5
...
123-01-3
...
25155-30-0
...
...
...
28675-17-4
27193-86-8
74-84-0
107-21-1
112-27-6
Chemical
Diphenyl thi cures (POM)
Diphenylamine (POM)
Dipropylene glycol
Di(2-methoxyethyl) phthalate
Di-o-tolyguanidine
1 -Dodecene
Dodecylbenzene, linear
Dodecylbenzene, nonlinear
Dodecylbenzenesulfonic acid
Dodecylbenzenesulfonic acid,
sodiuM salt
Dodecene (branched)
Dodecyl mercaptan (branched)
Dodecyl phenol (branched)
Dodecyl aniline
Dodecyl phenol
Ethane
1,2-Ethanediol
2.2'-(1.2-Ethanediylbis (oxy))
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X X
X X
X X
X X
X X
X
X
X
X
X
X X
X X
X X
X X
X X
X X
X X
X X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X X
X X
X X
X X
bisethanol
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nunber
64-17-5
74-85-1
463-51-4
100-42-5
110-80-5
111-15-9
...
I
,j
105-39-5
...
...
...
...
...
...
75-04-7
103-69-5
578-54-1
Chemical
Ethanol
Ethene
Ethenone
Ethenylbenzene
2-Ethoxyethanol
2-Ethoxyethyl acetate
acetate
Ethyl acetoacetate
Ethyl bromide
Ethyl caproate
Ethyl chloroacetate
Ethyl ether
Ethyl hexanol (2-)
Ethyl mercaptan (ethanethiol)
Ethyl orthoformate
Ethyl oxalate
Ethyl sodium oxalacetate
Ethylamine
Ethylaniline (N-isomer)
Ethylaniline (o-isomer)
Reactor and
distillation
CTG
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in- HOW
impacts SOCHI
analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X X
X X
X X
XXX
X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
100-41-4
9004-57-3
105-56-6
96-49-1
...
106-93-4
111-55-7
•j, 112-48-1
M 629-14-1
OS
110-71-4
542-59-6
112-07-2
111-76-2
111-15-9
110-49-6
109-86-4
Reactor and
distillation
Chemical CTG
Ethylbemene
Ethylcellulose
Ethylcyanoacetate
Ethylene carbonate
Ethylene chlorohydrin
Ethylene dibromide (dibromoethane) (EDB)
Ethylene glycol diacetate
Ethylene glycol dibutyl ether (GE)
Ethylene glycol diethyl ether
Ethylene glycol dimethyl ether
(glycol ether)
Ethylene glycol monoacetate
Ethylene glycol monobutyl ether acetate
(glycol ether)
Ethylene glycol monobutyl ether
(glycol ether)
Ethylene glycol monoethyl ether acetate
(glycol ether)
Ethylene glycol mooomethyl ether acetate
(glycol ether)
Ethylene glycol monomethyl ether
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
included Air
in-HOH oxidation Distillation Reactor
impacts SOCM1 processes operations processes
analysis list NSPS NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
(glycol ether)
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
00-2
122-99-6
2807-30-9
...
107-15-3
60-00-4
151-56-4
123-05-7
...
104-76-7
103-11-7
104-75-6
...
...
Chemical
Ethylene glycol nonooctyl ether (GE)
Ethylene glycol monophenyl ether
(glycol ether)
Ethylene glycol nonopropyl ether
(glycol ether)
Ethylene {mine (azirfdine)
Ethylenediamine
Ethylenediamine tetraacetic acid
Ethyleneimine (aziridine)
2-Ethylhexanal
Ethylhexanoic acid
2-Ethyl-1-hexanol
Ethylhexyl acrylate (2-isomer)
(2-Ethylhexyl) amir*
Ethylhexyl succinate (2-)
E thy Imethy 1 benzene
Reactor and
distillation
CTG
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in- HOW
impacts SOCHI
analysis list
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operat i ons processes
NSPS NSPS NSPS
X
X X
X
74-86-2
Ethylnaphthalene (2-isomer)
(alkyl naphthalene)
6-Ethyl-1,2,3,4-tetrahydro-
9,10-anthracenedione
Ethyne
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
...
206-44-0
75-12-7
110-17-8
108-31-6
50-70-4
111-30-8
^ 367-47-5
1
O
...
56-40-6
...
...
...
142-82-5
...
118-74-1
87-68-3
...
Chemical
Fatty acids, tall oil, sodium salt
Fluoranthene (POM)
Foraamide
Fumaric acid
2,5-Furandione
D-Glucitol
Glutaraldehyde
Glyceraldehyde
Glycerol dichlorohydrin
Glycidol
Glycine
Glycol ethers
(other than those presented)
Guanidine
Guanidine nitrate
Heptane
Heptenes (mixed)
Hexach I orobenzene
Hexach lorobutadiene
Hexach 1 orocyc I opent ad i ene
Reactor and
distillation
CTG
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Included
in-HON
impacts SOCHI
analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
XXX
X
X X
X X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
67-72-1
...
592-45-0
105-60-Z
110-53-3
124-09-4
...
*, 111-69-3
y
KJ 124-04-9
^mmt
106-69-4
...
...
...
...
...
74-90-8
123-31-9
0-01-6
...
Chemical
Hexachloroethane
Kexadecyl alcohol (cetyl alcohol)
Bexadiene (1,4-isomer)
H*xahydro-2H-a*epin-2-one
Hexane
1 ,6-Hexanediamine
1,6-Hexanediamine adipate
Hexanedinitrite
Hexanedioic acid
Hexanetriol (1,2,6-isomer)
2-HexenedinitriU
3-Hexenedinitrile
Hexyl alcohol
Hexyltne glycol
Miflher glycols
Hydrocyanic acid
Hydroquinom
Hydroxyadipaldehyde
Hydroxybcnioic acid (p->
included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X X
X
X
X X
X
X
X
X X
X
X
X
X
X
X
X
X X
X
X
X
Air
oxidation Distillation
processes operations
NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
Reactor
processes
NSPS
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
muter
...
123-42-2
75-86-5
J..
11-42-2
111-42-2
74-88-4
>'
1
to
to
...
85-44-9
...
...
106-63-8
...
—
25339-17-7
—
Chemical
3-Hydroxybutyraldehyde
4-Hydroxy-4-methyl-2-pentanone
2-Hydroxy-2-methylpropanenitrile
2-Hydroxy-1,2,3-
propanetricarboxylic acid
2,2'-Iminobisethanol
Iminodiethanol (2,2-)
lodo-methane
Isoamyl alcohol
Isoamyl chloride (mixed)
Isoamylene
1,3-1 sobenzof urandi one
Isobutanol
Isobutyl acetate
Isobutyl acrylate
Isobutyl methacrylate
Isobutyl vinyl ether
(vinyl isobutyl ether)
Isodecanot
Isohexyldecyl alcohol
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X X
X X
X. X
X
X X
X
X
X
X
X
X X
X
X
X
X
X
X
X
Air
oxidation Distillation
processes operations
NSPS NSPS
X
X
X
X
X
X
X
X
X
X X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nutter Chemical
— Isartonyl alcohol
78-59-1 Isophorone
0-01-? Isophorone nitrile
— Isopropanol
— Isopropyl acetate
— Isopropyl chloride
— Isopropyl ether
-•- Isopropylamine
1 25168*06-3 Isopropyl phenol
Ul
Lactic acid
— Lauryl dimethylamine oxide
— Lead acetate
0-01-8 Lead phthalate
Lead subacetate
Linear alcohols, ethoxylated, mixed
Linear alcohols, ettuutylated and
Included
Reactor and in-HON
distillation inpacts SOCMI
CTG analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
oxidation Distillation
processes operations
NSPS KSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
sulfated, sodium salt, nixed
Linear alcohols, sulfated, sodiun
salt. Mixed
Linear alkylbenzene
(linear dodecylbenzene)
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
5-'
1
NJ
CAS
number
...
123-33-1
6915-15-7
...
...
121-47-1
79-41-4
- . .
74-89-5
...
67-56-1
63-68-3
109-86-4
79-20-9
...
96-33-3
74-83-9
...
Chemical
Maleic acid
Maleic hydrazide
Malic acid
Mercuric acetate
Mesityl oxide
Metanilic acid
Methacrylic acid
Methallyl alcohol
Methallyl chloride
Methanamine
Methane
Methanol
Hethionine
2-Methoxyethanol
Methyl acetate
Methyl acetoacetate
Methyl acrylate
Methyl bromide (bromomethane)
Methyl butenols
Included
Reactor and in-HON
distillation impacts SOCMI
CTG analysis list
X
X
X
X
X
X
X
X
X
X X
X
X X
X
X X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X
X
X
X
X
X
X
X
X
X X
X
X X
X
X X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
...
107-31-3
60-34-4
108-11-2
108-10-1
624-83-9
74-93-1
98-85-1
1
NJ
Ui
100-61-8
108-88-3
95-80-7
...
78-79-5
...
78-78-4
513-35-9
...
1634-04-4
Chemical
Methyl butynol
Methyl formate
Methyl hydrazine
Methyl isobutyl carbinol
Methyl isobutyl ketone (hexone}
Methyl isocyanate
Methyl liter cap tan
Methyl phenyl carbinol
(methyl benzyl alcohol)
Methyl salicylate
Methylaniline (n-isomer)
Methylbenzene
4-Methyl-1,3-benzenediamine
ar-Methylbenzenediamine
2-Methyl- 1 ,3-butadi ene
Methylbutanol (2-)
2-Methylbutane
2 -Methyl -2- but eoe
2-Nethylbutenes, nixed
Methyl tert -butyl ether
Included
Reactor and in-NON
distillation impacts SOCM1
CTS analysis list
X
X
X
X
X
X
X
X
X
X
X X
X X
X
X
X
X
X
X
X X
Air
oxidation Distillation
processes operations
NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuiber
606-20-2
121-14-2
98-82-8
80-05-7
26952-21-6
108-87-2
> 25639-42-3
£? 1331-22-2
101-77-9
101-68-8
79-69-6
124-40-3
...
...
75-56-9
107-83-5
108-10-1
Included Air
Reactor and in-HON oxidation Distillation
distillation impacts SOCHI processes operations
Chemical CTG analysis list NSPS NSPS
1-Methyl-2,4-dinitrobenzene
(and 2-Methyl-1.3-dinitrobenzene)
1-Methyl-2,4-dtnitrobenzene
(1-Methylethyl) benzene
4,4'-(1-Methylethylidene)
bisphenol
6-Methyl-heptanol
Methylcyc(ohexane
Methylcyclohexanol
Methy I eye I ohexanone
Methylene dianiline (4,4-isomer) (MO A)
Methylene diphenyl dtisocyanate (HOI)
Methyl ionones (a-isomer)
N -Methy Inethanamine
Methylnaphthalene (1-isomer)
(alkyl naphthalene)
Methylnaphthalene (2-isomer)
(alkyl naphthalene)
Methyloxirane
2-Methylpentane
4-Methyl -2-pentanone
X
X X
X X
X X
X
X
X
X
X
X
X
X X
X
X
X X
X
X X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
Reactor
processes
NSPS
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
muter
141-79-7
80-15-9
78-84-2
75-28-5
78-83-1
75-65-0
115-11-7
126-98-7
1 80-62-6
NJ
•sj
872-50-4
...
77-75-8
...
91-20-3
85-47-2
120-18-3
...
90-15-3
Chemical
4-Methyl-3-penten-2-one
1 -Methyl -1-phenylethy I hydroperoxide
2-Methylpropanal
2-Methyl propane
2-Methyl -1-propanol
2-Methyl -2-propanol
2-Methyl -1-propene
2-Methyl -2-propenenitrile
2-Methyl- 2- propenoic acid,
methyl ester
1 -Methyl -2-pyrrol idinone
Methyl -1-pentene (2-)
Methylpentynol
Morpholine
Naphthalene
Naphthalene sulfonic acid
(a-isomer) (POM)
Naphthalene sulfonic acid
(b-isomer) (POM)
Naphthenic acids
Naphthol (a-isomer) (POM)
Included
Reactor and in-HON
distillation impacts SOCMI
CTG analysis list
X
X X
X
X
X
X X
X X
X
X
X
X
X
X
X X
X
X
X
X
Air
oxidation Distillation
processes operations
NSPS NSPS
X X
X
X
X
X
X
X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEHICALS
(CONTINUED)
CAS
nuMbtr
135-19-3
567-18-0
84-86-6
81-16-3
134-32-7
91-59-8
...
1
K)
...
...
102-71-6
99-09-2
88-74-4
...
91-23-6
100-17-4
98-95-3
...
included
Reactor and in-HON
distillation impacts SOCHI
Chemical CTG analysis list
Naphthol (b-isomer) (POH)
NaphthoUulfonic acid (1-) (POM)
Naphthylemine sulfonic acid (1,4-) (POM)
Naphthylamine sulfonic acid (2.1-) (POM)
Naphthylamine (1-) (POM)
Naphthylamine (2-) (POM)
Neohexane
Meopentanoic acid (trimethylacetic acid)
Heopentyl glycol
Nickel formate
Nitriloacetic acid
2,2,2-Nitrilotrisethanol
Nitroaniline (m-isomer)
Nitroaniline (o-isomer)
Nitroaniline (p-i*omer)
Nitroanisole (o-isomer)
Nitroanisole (p-i sower)
Nitrobenzene
Hitrobenzoic acid (n->
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
X
X
X X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
X
X
X X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
lumber
...
...
...
...
...
...
86-57-7
> 100-02-7
I
Is) 88-75-5
vo
79-46-9
79-46-9
13Z1M2-6
88-72-2
99-08-1
99-99-0
25168-04-1
143-08-8
124-11-8
—
Included Air
Reactor and in-HON oxidation Distillation Reactor
distillation impacts SOCHI processes operations processes
Chemical CTG analysis list NSPS NSPS NSPS
Nitrobenzoic acid Co-)
Nitrobenzoic acid (p-)
Hitrobenzoyl chloride (p-)
Nitroethane
Nitroguanidine
Nitronethane
Nitronaphthalene (1-) (POM)
Nitrophenol (4-) (p-)
Nitrophenol (o-is'omer) (2-Nitrophenol)
Nttropropane (1->
Nitropropane (2-)
Nitrotoluene
Nitrotoluene (2-isomer) (o->
Nitrotoluene (3-isomer) (ra-)
Nitrotoluene (4-isomer) (p-)
Nitroxylene
1-Nonanol
1-Nonene
Nonene (nonylene)
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nuifcer
1081-77-2
15154-52-3
...
25154-52-3
88-12-0
...
111-66-0
...
2719J-28-8
...
...
...
...
75-21-8
...
11-46-6
30525-89-4
123-63-7
Chemical
Monylbenzer* (branched)
Nonylphenol
Nonylphenol, ethoxylated
Nonylphenol (branched)
N-Vinyl-2-Pyrrolidine
Octane
Octene-1
Octy lamina (tert-)
Octyl phenol
Oil-soluble petroleum sulfonate,
calcium salt
Oil -soluble petroleum sulfonate,
sodium salt
Oxalic acid
Oxamide
Oxi rane
Oxo chemicals
2,2'-Oxybisethanol
Paraf orma I dehyde
Paraldehyde
Included
Reactor and in-HON
distillation iipacts SOCM1
CTG analysis list
X
X X
X
X
X
X
X X
X
X
X
X
X
X
X X
X
X X
X
X
Air
oxidation Distillation
processes operations
NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
Reactor
processes
HSPS
X
X
X
X
X
X
-------
TABLE A-I. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nutter Chemical
87- 66 -5 Pentachlorophenol
Pentaerythrftol tetranitrate
109-66- 0 Pentane
Pentanethiol
Pentanol (2->
Pentanol (3-)
Pentene (2-)
•y 79-21-0 Peraeetie acid
1
W 594-42-3 Perchloromethyl mercaptan
— 3-Penetenenitri le
— Pentenes, mixed
Phenaeetin (acetophenetidin)
85-01-8 Phenanthrene (PON)
Phenetidine (o-)
156-43-4 Phenetidine
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEHICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
...
106-50-3
—
...
108-73-6
88-99-3
85-41-6
91-15-6
...
108-99-6
...
...
110-85-0
...
25322-68-3
25322-69-4
...
12J-3B-6
74-98-6
Chemical
Phenylenedianiine (o-)
Phenylenedianfne (p-i saner)
PhenylMthylpyrazolone
(methylhenylpyrazolinooe)
1-Phenylethyl hydroperoxide
Phloroglucinol
Phthalic acid
Phthal imide
Phthalonl trite
Picoline
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
57-55-6
107-12-0
56-81-5
71-23-8
67-63-0
67-64-1
115-07-1
&,• 107-13-1
£ 79-10-7
K1-32-2
140-88-5
57-57-8
•
...
...
...
103-65-1
78-87-5
Chemical
1,2-Propanediol
Propanenitrile
1,2,3-Propanetriol
1-Prop«nol
2-Propanol
2-Propanone
1-Propene
2-Propenenitrile
2-Propenoic acid
2-Propenoic acid, butyl ester
2-Propenoic acid, ethyl ester
Propiolacetone (b-isomer)
• Propyl acetate (n-)
Propyl carbonate
Propyl chloride
PropylaMine
Propylbenzene
Propylene dichloride
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X X
X
X X
X X
X
X X
X
X X
X X
X X
X X
X
X
X
X
X
X
X
Air
oxidation Distillation
processes operations
NSPS NSPS
X X
X X
X
X
X X
X
X X
X X
X
X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
X
X
X
' X
X
X
X
(1,2-Dichloropropane)
107-98-2 Propylene glycol monomethyl ether
-------
I
UJ
lilt"
TABLE A-l. LIST OF SYNTHETIC
CAS
number Chemical
Pseudocumene
Pseudocumidine
129-00-0 Pyrene (POM)
110-86-1 Pyrldine
Pyrrol idon* (2-)
106-51-4 Quinone
108-46-3 Resorcinol
69-72-7 Salicylic acid
— Sebacic acid
— Sodium acetate
— Sodium benzoate
— Sodium chloroacetate
143-33-9 Sodium cyanide
Sodium dodecyl benzene sulfonate
--- Sodium formate
124-41-4 Sod inn methooxide
— Sodium oxalate
139-02-6 Sodium phenate
Sodium propionate
1 r > >
ORGANIC CHEMICAL MANUFACTURING INDUSTRY
(CONTINUED)
Included Air
Reactor and in-HOM oxidation
distillation impacts SOCHI processes
CTG analysis list NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
CHEMICALS
Distillation Reactor
operations processes
NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
...
588-59-0
110-15-6
110-61-2
121-57-3
126-33-0
...
1
w
526-83-0
...
...
100-97-0
558-13-4
632-79-1
95-94-3
•-- .
117-08-8
79-34-5
Chemical
Sorbic acid
Stilbene
Succinic acid
Succinonitrile
Sulfanilic acid
Sulfolane
Synthesis gas
Tallow acids, potassium salt
Tallow acids, sodium salt
Tartar ic acid
Terephthaloyl chloride
Tetra (methyl -ethyl) pi urbane
1,3.5.7-Tetraazatricyclo
(3,3,1,13,7)-decane
Tet rabromomethane
Tetrabromophthalic anhydride
Tetrachlorobenzene (1,2,4,5-)
Tetrachlorobenzene (1,2,3,5-isomer)
Tetrachlorophthalic anhydride
1,1,2,2-Tetrachloroethane
Included
Reactor and in-HOH
distillation impacts SOCHI
CTG analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X X
X X
X
X
X
X
X X
Air
oxidation Distillation
processes operat i ons
NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
number
127-18-4
56-23-5
112-60-7
112-57-2
78-00-2
...
109-99-9
> 119-6A-2
^ 85-43-8
C*
110-60-1
110-18-9
75-74-1
102-08-9
...
26741-62-5
...
104-15-4
98-59-9
95-53-4
Included
Reactor and in-HON
distillation impacts SOCHI
Chemical CTG analysis list
Tetrachloroethene
Tetrachlorome thane
Tetraethylene glycol
Tetraethylenepentamine
Tetraethylplumbane
Tetraf luoroethylene
Tetrahydrofuran
Tetrahydronapthalene (tetralin) (POM)
Tetrahydrophthalic anhydride
Tetramethyl enedi ami ne
Te tramethy 1 ethy I enedi ami <
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nutter
108-78-1
75-25-2
...
108-77-0
76-13-1
...
634-93-5
I 87-61-6
U)
120-82-1
71-55-6
79-00-5
79-01-6
75-69-4
67-66-3
95-95-4
...
...
...
Chemical
1,3,5-Trfazfne-2,4,6-triamine
TrfbroMomethane
1 , 1 ,1 -TribroMO-2-methyl-2-propanol
2,4,6-Trichloro-1,3,5-triazine
1,1,2-Trichloro-1.2.2-
trffluoroethane
Trichloroacetic acid
Trichloroaniline (2,4,6- isomer)
Trichlorobenzene (1,2,3-)
Trichlorobenzene (1,2,4-isomer)
Trichlorobenzem (1,3,5-)
1,1, 1 -Trichloroethane
1,1,2-Trichloroethane
Trichloroethene
Trichlorof luoromethane
trichloromethane
Trichlorophenol (2,4,5-)
Trichloropropane (1,2,3-)
Tricresyl phosphate
Tridecyl alcohol
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X
X X
X
X
X X
X
X
X
X
X
X X
X X
X X
X X
X X
X
X
X
X
Air
oxidation Distillation
processes operations
NSPS NSPS
X
X
X
X X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reactor
processes
NSPS
X
X
X
X
X
X
X
-------
TABLE A-l. LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY CHEMICALS
(CONTINUED)
CAS
nunber
121-44-8
112-49-2
...
112-35-6
...
...
...
I 75-50-3
W
05 80-56-8
...
933-48-2
2408-37-9
00-7
77-99-6
540-84-1
24800-44-0
57-13-6
...
Chemical
Triethylamine
Triethylene glycol dimethyl ether
(glycol ether)
Trlethytene glycol nonoethyl ether
Triethylene glycol nonomethyl ether
Triisobutylene
Trinwllitic anhydride
Trinethyl pentanol
Trimethylanrine
2,6,6-Trimcthylbicycto
(3,1,1) hept-2-ene
Trimethyl-1,3-pentan*diol (2,2,4-)
Tr imethylcyc lohexanol
T r iwethylcye 1 obexanone
Triwethylcycloheaylamine
Trimethylopropane
Trimethylpentane (2,2,4-)
Tripropylene glycol
Urea
Urea awnonium nitrate
Included
Reactor and in-HON
distillation impacts SOCHI
CTG analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation
processes opera t i ons
NSPS NSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reactor
processes
MSPS
-------
TABLE A-l. LIST OF SYNTHETIC ORGAHIC CHEMICAL HANUFACTURIHG INDUSTRY CHEMICALS
(CONCLUDED)
u
vo
CAS
nunber
...
25013-15-4
100-40-3
...
25321-41-9
---
...
...
...
...
...
...
...
...
...
...
...
...
Chemical
Vinyl toluene
Vinyl toluene
Vinylcyelohexene (4-isomer)
Xanthates (potassiim ethyl xanthate)
Xylene sulfonic acid
Xytenol (2,3->
Xylenol (2,4-)
Xytenol C2.5-)
Xylenol (2,6-),
Xylenol 13,4-)
Xylenol (3,5-)
Xylidine (2,3-)
Xytidine (2,4-)
Xylidirw (2,5-)
Xylidine (2,6-)
Xylidine C3.4-)
Xylidine <3,5->
Zinc acetate
Included
Reactor and in- HO*
distillation impacts SOCHI
CTG analysis list
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Air
oxidation Distillation Reactor
processes operations processes
NSPS NSPS ttSPS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
-------
APPENDIX B
EMISSION DATA PROFILES
-------
TAUU! » 1. Rl-ACTOR PROCIiSS VliWFS EMISSION DATA PROHLI?
PRODUCT
PROCESS
Butyl Acetate
Dtoctyi phthalate
Vinyl Accute
Ethyl Acetate
Ethylene Gtycol Monoethyl ether accute
Bthylbenzene
Butynediol
Vinylidene Chloride
Nitrobenzene
Elhytbenzene
Ethyl Chloride
Methyl Chloride
Ethyknc Dichloride
CMorobenzene
llexamcthyl diamine
Ethyl AcryUtc
Pfopykne Oxide .
Hexamethyl diamioe
Acetic Anhydride
Elhykne Dkttoride
Elhykne Dichloride
Eihykne Dichloride
Siyrcne
Butynldehyde
Dinilrotoluene
AdipicAcid
Adiponitrik
Benzene
Hexamethykne Diamiac
Dodecylbenzene sulfonic acid
AdipicAcid
AdipicAcid
Slyrerte
n Butyl Alcohol
1.4-Dichloride
Elhykne Oxide
Methanol
PROCESS
DESCRIPTION
Eslerification
EsleriKcation
Oiyacerylalion
Eslerifioilion
Eucrification
Alkylation
EihynyUikm
Dehydrothlorinalion
Nitration
Alkyteikm
HydiochloriMiion
Hydrochlorinaiion
ChloriMtion
ChloriMtion
HydrogeMlion
Eclerificalion
llydrolysic
Hydrofc nation
Condcnulion
Chlorination
Chlorinalion
OiychlorinaliOA
Dehydroge nation
Hydroformylaiion
Nitration
Ondaikm
Hydrodimerizaiion
Catalytic Reforminj
Hydroge nation
Sulfonalion
Oxidation
Oxidation
Dehydrofe nation
llydrofcnation
Chlorinalion
Oxidation •
Carbonytalion
•EimukNU data taken from Appendix C of Reactor Processes in Synthetic Ortank Chemical
FLOWRATB
(SCFM)
2
5
7
7
8
8.7
9.2
10
13
17
20
20
40
SS
70
7S
99
113
147
167
267
304
574
729
822
848
1080
1289
1304
1863
2800
4653
5208
5429
9195
12187
18950
Manufacturing Industry
HEAT CONTENT
(BTU/SCF)
102
102
407
102
102
4
747
600
434
181
1286
500
40
0
323
102
0
900
1069
163
1228
713
300
1233
0
0
70
205
462
0
0
0
280
7»
0
4
295
- Background Information for Proposed
VOC FLOWRATE
LB/IIR)
01
01
01
0.5
Ntf
0.1
194
41
19
16
168
2.1
3.6
4
6.6
6.1
0.1
0
305
74
113
748
161
2394
0.1
0
27
8.3
0
0.1
0
0
711
4046
7.2
130
75
Standards
(EPA 450/3-*5-005a)
6 Data not reported.
-------
TABLE B-i DISTILLATION EMISSION DATA PROFILE1
PRODUCT
PROCESS
ChlorobenzeDC
Aniline
ChtorobenzeDC
ChJorobenzcDC
Aniline
Chlorobenzene
Tcrephthalic Acid
Confidential
Ethylbenzene
Methyl MethacryUte
84
Acetone
Acetone
Acetic ACid
Chloroprene
Malic Anhydride
Confidential
Dimethyl Terephthalau
Chloroprene
Acetic Anhydride
Phthalic Anhydride
Ethylaceuu
Ethyldichloride
Alkyt Benzene
Acetic Anhydride
Perchloroethylene
Acetone
Acetone
Acetic Acid
Acetone
Nitrobenzene
Methyl MethacryUte
Chloroprene
Dichlorobenzene
Acetic Acid
Diphenylamine
Methyl Ethyl Ketone
Ethykne Oxide
Ethylaceuu
Vinyl AceUU
Ethyldichloride
Phthalic Anhydride
Terephthalic Acid
Methyl Methacryiate
DichJorobenxeac
86
Acetic Anhydride
Dimethyl Terephthalate
EthanoUmiae*
Acetone Cymnoaydride
Ethyldichloride
Methyl Ethyl Ketooe
Acetic Anhydride
Ethyldichloride
Malic Anhydride
Ethylbenzene
Ethyfdichloridc
Dimethyl TcrephthaJate
Methyl MethacryUte
Acrylic Acid
Ethyldichloride
Acetic Anhydride
NUMBER OF
COLUMNS AND
OPERATING
CONDITIONS
1NV
IV
1NV
1NV
IV
1NV
1NV
ICO
1NV
1NV
2NV
IV
2NV
1NV
1NV
3V
ICO
IV
IV
ICO
IV
1NV
IV
1NV
ICO
1 NV
1NV
IV
1 NV
1NV
IV
1NV
2V
IV
ICO
IV
1NV
1NV
1NV
1NV
1NV
IV
1NV
IV
IV
1NV
ICO
1NV
IV
1NV
IV
1NV
ICO
2NV
IV
1NV
1NV
1NV
1NV
IV
1NV
4 CO
FLOWRATB
(SCFM)
0.005
0.007
0.012
0.015
0.02
0.02
0.02
0.02
0.063
0.1
0.1
0.1
0.1
0.18
0.2
0.2
036
0.3
0.4
0.48
0.5
0.7
0.9
U
1.2
U
1.39
1.39
1.45
U
1.5
1.7
1.8
1.8
1.94
2
27
2-3
2-3
2-3
14
2.4
2J
2.6
2.6
3J
3.66
4.2
2J
4.4
4.8
4.9
4.98
6
6J
6J
6.94
7
7.4
7.4
8.1
8.16
HEAT CONTENT
(BTU/SCF)
133
3752
374
755
3047
432
169
0
7
1056
834
360
36
207
2778
0
1375
4978
2224
1024
3602
680
1024
3643
1024
143
966
966
903
1225
352
1483
858
651
68
0
1183
1191
1012
781
1024
260
114
2870
62
90
1024
180
0
190
53
2003
1024
727
0
1286
727
0
439
0
91
1024
VOC FLOWRATE
(LB/HR)
0.004
0.11
0.025
0.034
0.29
0.031
0.02
0
0
0.4
075
07
07
0.08
2
0
1.83
4.9
4.9
1.53
11.5
0.4
14 «
15
3.81
3.4
6.04
6.04
1.6
10.4
1.8
13.6
4.9
8.1
0.8
0.003
10
13.8
6.4
57
38
4
1.9
41
U
28.8
11.61
5
0
4
3.9
3168
15.81
63.9
0
3
55
10
12
0
6.6
25.88
B-2
-------
TABLE B-2. DISTILLATION EMISSION DATA PROTOJ? (Coetiayed)
PRODUCT
PROCESS
Dimeiltyl TerepbtfuUtt
Dimethyl Tertphth»l«te
Vmyt Acetttt
PhtluUc Anhydride
Chiorobeazeae
DichJorabeazcae
OioropreiM
Aoyioniirile
Vinyl Aeettte
CUoropteM
Act tone
BikytticUoridc
Fonaiklthyde
Eshyidkhloridc
Pbtkslk Anhydride
Acrylic Acid
PerchJoroethykne
Dimethyl Tcitpbihalate
Vinyl Acetate
Dimethyl Teiephtlmlate
as
Dimethyl TercphthaUw
Pbttialie Anhydride
Act tone
Methyl MethacryUte
EifcmnoUtmine*
Ethytbenzene
Acrylic Ac*
Acetone
Butadiene
Acrytk Acid
Acrytonitrile
Cyciohenuvofte/cyclohtxaaol
CMoropfcnc
AcrytcBitrik
CWorobciuent
Phttultc Anhydride
Ethyl AnyUu
AcryUc Add
Aceuae Cyinohydrid*
Acrylic E««ti
CUofobeneeiM
IS
Acetoot Cytflohydrkte
Coof»deati«l
Coefldeatial
Acetic Acid
Acetoee
Dineihyl Ttrephthtltte
M«Ui»oot
Cyciobcnoooc/cyOobcjautol
Methyl Meth*cryUw
Adipcmjtrik
Ethytene Glycol
Confidestial
Dimethyl TtrephUuUte
86
Hcximelhytene Dumine
AUcyl Benzene
Methyl Meth*oyUte
NUMBEKOP
COLUMNS AND
OPERATING
CONDITIONS
1NV
2V
1NV
IV
IV
IV
IV
1NV
1NV
2V
IV
1NV
ZV
IV
IV
2V
1 NV
1 NV
I NV
2V
4NV
1NV
IV
1NV
iv
3V
IV
2V
1NV
1NV
IV
IV
3V
1NV
IV
IV
2V
2V
2V
INV
3V
INV
7V
IV
SCO
4CO
3NV
INV
2V
INV
IV
IV
9V
6V
ICO
1 NV
INV
fv
IV
IV
FLOWRATB
(SCPM)
8.4
8.9
9
93
9.9
9,9
10
W2
10J
11.0
12.15
123
12-5
13
13.2
13-2
13.6
15
IS
15
16.7
17.4
17.9
18
18.3
19JS
19.7
20
21.13
2ZS
2X6
22.7
22,701
234
2S.6
241
27
272
27.6
3U
33.9
34.9
36.701
39.2
4039
494
SO
50.4
544
63.4
68.7
7X9
75
75.1
77J2
793
80
81.1
85.9
96J
HEATCONTa^T
Owu/scp)
234
47
1308
690
177
177
3
379
74
30
0
727
9
183
979
8
6
236
149
47
1464
12S2
69
0
2870
0
0
0
2192
1453
92
439
18
0
346
346
505
69
400
1916
168
495
123
4
0
0
4
70
47
449
72
«
0
0
6
1453
9
0
104
295
VOC FLOWRATE
(LB/HR)
13
U
34.8
42.7
6
2
02
15.8
152
1.1
0
98J
OJ
32J
84.1
04
2.1
12
6.6
5
0.1
1203
• 1
0
289
0
0
0
170.2
1003
103
44
15
0
37.9
43.1
100
5.6
5SJ
289
15.7
59
15.498
0.18
0.09
036
1.1
16.9
17
399.3
263
263
0
0
136
601
194
0
304
1483
B-3
-------
TABLE B-i DISTHIATION EMISSION DATA PROFILE (Coonoued)
NUMBER OP
PRODUCT COLUMNS AND FLOWRATE H1AT CONTENT VOCROWRATE
PX0OS8V OrERATINO (SCFM) (BTU/SCf) (LB/HR)
EthyMkUoridc
Acetone Cyanohydnde
Dimethyl Terephthalate
Mtthyl MethaciyUte
ChkwopreneMethyl
MethacryUI*
Dimethyl Ttcpfathalate
Methyl MethacryUte
Ethyl Acrylatt
Dimethyl Terephthalate
Ace tk Acid
AoylieAcJd
Ethyldichlonde
Methanoi
Acetic Acid
Ijophthtlk Arid
Acetaldehyde
84
INV
2V
INV
2NV
3V
IV
2V
INV
2V
INV
INV
INV
INV
INV
INV
INV
2NV
6NV
100
10U
1231
1244
145
152
176
178J
219
281
35S
364
5355
560
575
637
6473
656
6
4
768
155
12
13
47
1316
45
768
333
ISO
804
1258
380
19
293
6
SJ
u
628J
116-2
7J
9J
57
1300
454
1426
375
289
3050
3668
600
123
183
19
1 Emotions data taken from Appendix C at DiitilUrion Qsemioni in Synthetic Orniuc Manuficturini - Biefatround Information
for Piopoied Sundarti (EPA-450/3-83-005*).
B-4
-------
APPENDIX C
COST CALCULATIONS
-------
APPENDIX C
COST CALCULATIONS
C.I SIZING CALCULATIONS FOR THERMAL INCINERATOR
Hjj^__CaTjcu.Tation_s .for the_VENTCQST Program - Incineration Procedure
• Used to assess control equipment costs for the SOCMI CTG for
Reactor Process and Distillation Vents.
• Calculations based on OAQPS Control Cost Manual, Chapter 3.
• The stream costed in this example is model stream R-LFHH. Its
characteristics are as follows:
VOC to be controlled
MM
Flow rate (total)
VOC flow rate
Heat value
Oxygen content
Inert content
Ethyl Chloride*
64,5 Ib/lb mole
3.839 scfm
8.4 Ib/hr
1,286 Btu/scf
0%
Assume all H
*Most of the following calculations are based on the actual
compound in the SOCMI Profile. However, the combustion and
dilution air calculations are based on the design molecule
^2.85^5.700.63' which represents the average ratio of carbon,
hydrogen, and oxygen for streams in the SOCMI profile. The
molecular weight of this "design molecule" is 50 lb/lb-mole.
Check to see if the stream to be controlled is halogenated--yes,
ethyl chloride contains chlorine. Since the stream is
halogenated, the following applies,
1. No heat recovery is allowed for halogenated streams.
2. A scrubber will be required to remove acidic vapors from
the flue gas following combustion. Scrubber sizing and
costing calculations for this vent stream immediately
follow the incinerator calculations (see Section C.2).
C-l
-------
B. Calculate total moles of the vent stream, and quantify moles of
VOC, 02 and inerts.
1. VOC moles only:
VOC moles - (8.4 lb/hr)(hr/60 min)(lb-mole/64.5 Ib)
- 0.0022 Ib-moles/min
2. Total vent stream moles:
Vent moles - (3.839 scfm)(lb-mole/392 scf)
- 0.0098 lb-moles/min
3. Oxygen moles:
02 moles - 0
4. Inert moles:
Inert moles - Vent moles - VOC moles - 02 moles
- (0.0098 - 0.0022 - 0) lb-mole/min
- 0.0076 lb-mole/min
C. Calculation of Molar Ratio of Air to VOC
Please note that the combustion and dilution air calculations
are based on the design molecule C2.85H5.7°0.63» which
represents the average ratio of carbon, hydrogen, and oxygen.
The molecular weight of this "design molecule" is 50 Ib/lb-mole.
Assume 3.96 moles of 02 are required for each VOC mole.
1. Since no oxygen is present in the stream, additional
combustion air must be added, to insure proper combustion.
2. Calculate the ratio of 02 to VOC required for combustion.
02 theory - 3.96 - 02 ratio already in stream*
*Additional air is not required if sufficient oxygen is
already present in the vent stream.
3. Since air is 21% 02 the necessary ratio of air to VOC is:
Air ratio - (3.96)/0.21 - 18.86 moles air/mole VOC
D. Calculation of molar ratios of inert moles to moles VOC
1, Inert ratio - inert moles/VOC moles
- 0.0076/0.0022
- 3.4545 moles inert/mole VOC
C-2
-------
In order to ensure sufficient 03 1s present in the combustion
chamber, enough air must be added to provide 3% Og in the
exhaust (flue) gas stream after combustion. The 0£ material
balance is :
(Initial 09%)(vent stream) + (0.21)(dilution air) -
(0.03)(exhaust)
Initial 02% • 0; therefore,
(0.21)(Dilution air) - (0.03)(exhaust stream)
(0.21)(Dilution air) - (0.03)(dilution air + vent stream)*
*Assume no increase in moles after combustion
(0.21)(Dilution air) - (0.03)(dilution air) +
(0.03)(vent stream)
Dilution air = (0.03)/(0.21 - 0.03) (Vent stream flow)
*This factor will be used later.
Exhaust gas consists of noncombustibles (N£) + C02 + H£0 (see
"Combustion Stoichiometry Memo")
1. Exhaust ratio - (0.79)(air ratio) + 2.85 + 2.85
- 20.6 moles exhaust/mole VOC
2. Dilution ratio - 0.03/(0.21 - 0.03)
(Inert ratio + Exhaust ratio)
Calculate flows of stream components based on calculated ratios
1. Dilution ratio - Factor * (Inert ratio - Exhaust ratio)
- (0.1667)(3.4545 + 20.6)
- 4.009
2. Dilution air flow - (Dilution air ratio)(VOC moles)
(392 scf/lb-mole)
Dilution air flow - (4.009)(0.0022)(392)
- 3.457 scfm
3. Combustion air flow - (Air ratio)(VOC moles)(392)
• (18,86)(0.0022)(392)
- 16.26 scfm
Combined air flow « Combustion air + Dilution air
- (16.26 + 3.4545)
- 19.7 scfm
C-3
-------
4. Inert gas flow = (Inert ratio)(VOC moles)(392)
- (3.4545)(0.0022)(392)
" 2.98 scfm
5. Total flow - Combined air flow + Initial vent stream flow
+ Inert gas flow
- 19.7 -i- 3.839 scfm
New flow - 26.519 scfm
H. Recalculate heat value of the stream after adding air streams
(prior to combustion)
1. Heatval - (Initial flow * Initial heatval)/New flow
- (3.839 * 1.286J/26.519
- 186.2 Btu/scf
I. Check the heat value of the precombustion vent stream, to see if
it is acceptable from a safety perspective
1. Streams containing halogens must have a heat value
< 95 Btu/scf, nonhalogens < 98 Btu/scf.
186.2 > 95
2. Dilute stream to have a heat value < 95 Btu/scf.
Dilution air - [New flow * (Heatval - 95)]/95
- [26.5 * (186.2 - 95)]/95
- 25.5 scfm
Heatval - 95 Btu/scf
New flow * 26.5 + 25.5
- 52.0 scfm
J. Minimum incinerator flow is 50 scfm. Streams less than 50 scfm
will be increased by addition of air.
52 scfm > 50 scfm
K. Establish temperature that incinerator operates:
Halogenated: 2,000°F
Nonhalogenated: 1,600°F
C-4
-------
L. Nonhalogenated streams are potential candidates for heat
recovery.
If addition of air flows results in lowering the heat value of
the entire vent stream below 13 Btu/scf («25% LEL), then the
entire vent stream is eligible for heat (energy) recovery in a
heat exchanger.
High heat value streams cannot be heated in a preheater because
of combustion/explosion concerns, but the VENTCOST program will
calculate economic options that allow preheating of the air
stream only.
The energy recovery equations are weighted to account for the
mass of the heated streams since the flows being preheated may
be smaller than the exhaust (flue) gas flows.
No calculations are presented here since the example stream is
halogenated, and, therefore, heat recovery is not allowed.
M. Calculate the auxiliary fuel (Qaf) requirement
Qaf " [0.0739 * new flow * [0.255 * (1.1 * incinerator
temperature - temperature gas - 0.1 * 77) -
(heatval/0.0739))] * [0.0408 * [21,502 -
(1.1 * .255 * (incinerator temperature - 77))]
-» Incinerator Temperature » 2,000 °F
*See OAQPS Control Cost Manual, Incinerator Chapter for
Derivation and Assumptions.
[.0739 * 52 * [.255 * (1.1 * 2,000 -
Qaf = 77 - 0.1 * 77) - (209/.0739)11
[0.0408 * [21,502 - (1.1 * .255 * (2,000 - 77)]]
Qaf " F.0739 * 52 * (-2288)1
855.27
Qaf = -10.3 scfm
Negative value indicates no auxiliary fuel is theoretically
needed. Therefore, set Qaf = 0.
N. Calculate sufficient auxiliary fuel to stabilize flame (5% of
TEI).
1. Thermal Energy Input (TEI) - 0.0739 * (new flow + Qaf) *
(0.255 * (incinerator
temperature - 77)
TEI - 0.0739 * (52 + 0) * 0.255 * (2,000 - 77)
= 1,884
C-5
-------
2. Qaf - (0.05 • 1,884)/(0.0408 • 21,502)
* 0.107 * 0.1 scfm
0. Calculate the total volumetric flow rate of gas through the
incinerator, Qfj. Include auxiliary air for the natural gas.
1. Qfi - new flow + Qaf +• combustion air for fuel
2. Assuming the fuel is methane, CH4, the combustion reaction
is:
CH4 + 202 • C02 • C02 + 2H2°
So two moles of 0? are required for each mole of fuel.
Since air is 21% Og.
2/0.21 * 9.5 moles air/mole of fuel
Combustion air for fuel - (Qaf • 9.5)
3. Qf1 - New flow + Qaf + (Qaf * 9,5)
- 52 + 0.107 + (0.107 • 9.5)
= 53 scfm
C.2 COST ANALYSIS - ESTIMATING INCINERATOR TOTAL CAPITAL INVESTMENT
A. The equipment cost algorithms are only good for the range of
500 scfm to 50,000 scfm. The minimum design size is 500 scfm,
so capital costs are based on 500 scfm, and annual operating
costs are based on calculated
1. Design Q - 500 scfm
B. For 0% heat recovery, equipment cost, EC, is;
EC = 10,294 * (Design QA.2355j * (# incinerators) •
(CE INDEX/340.1)
EC = 10,294 * (500A-2355) * 1 * (355.6/340.1)
EC - $46,510.
C. Add duct cost. Based on an article in Chemical Engineering
(5/90) and assuming 1/8- in. carbon steel and 24-in, diameter
with two elbows per 100 feet.
Ductcost - [(210 * 24*0-839) + (2 * 4.52 * 24Al-43) *
(length/100) * (CE INDEX/352.4)]
Ductcost - $11,722.52 (for length of 300 ft)
C-6
-------
D. Add auxiliary collection fan cost, based on 1988 Richardson
manual.
Fancost - (96.96418 * Initial Q*0.5472) • 355.6/342.5
- 210.18
E. Total Equipment Cost, ECjOT» is given by:
ECfQj "EC * Ductcost + Fancost
- 46,510 + 11,723 + 210.18
- $58,443
F. Purchased Equipment Cost, PCE, is:
PCE - 1.18 • ECjOT
. $68,963
6. Estimate Total Capital Investment, TCI
if Design Q > 20,000, installation factor - 1.61
if Design Q < 20,000, installation factor - 1.25
TCI - 1.25 • PCE
» 1.25 • $68,963
- $86,203
C.3 CALCULATING ANNUAL COSTS FOR INCINERATORS
A. Operating labor including supervision (15%)
1, Assume operating labor rate - $15.64/hr (1/2 hour per
shift)
Op labor = (0.5 • Op hours)/8 • ($15.64/hr)(1.15)
(Op hours » 8,760)
Op labor - $9,847.34/yr
B. Maintenance labor and materials
M labor - (0.5/8 • 8,760) * ($17.21/hr)
- $9,422.48
Materials - M labor - $9,422.48
C. Utilities - Natural Gas & Electrical Costs
Assume value of natural gas - $3.30/1,000 scf
1. Natural gas - (3.30/1,000) • qaf • 60 min/hr • Op hours
Natural gas - (3.30/1,000) • 0.107 scfm • 60 * 8,760
- $186/yr
2. Power - (1.17 • 10A-* • Qfi • 4)/0.60
Power - (1.17 • 10'4 • 53 • 4)/0.60
- 0.0413 kW
C-7
-------
3. ElecCost - (0.061 $/kWh) * (0.0413) * (8,760)
- $22.07
D. Calculate total direct costs, TDC
TDC • Op Labor + H Labor + Material + NatGas + ElecCost
- (97847 + 9,422 + 9,422 + 186 + 22.07)
- $28,899/yr
E. Overhead - 0.60 * (Op_Labor + M_Labor + Material)
- $17,214.6/yr
F. Administrative - 2% of TCI
Admin - (0.02)(86,203)
- $l,724/yr
G.
H.
Tax * 1% of TCI
Tax - $862/yr
Insurance - 1% of TCI
Ins = 0.01 * TCI
- $862/yr
I. Annualized Capital Recovery Costs, Anncap, is:
AnnCap = 0.16275 * $86,203
•= $14,029.54/yr
J. Total Indirect Capital Cost, 1C, is:
1C - overhead + administrative + tax + insurance + Anncap
= (17,215 + 1,724 + 862 + 862 + 14,029) $/yr
= 34,692 $/yr
K. Total Annual Cost, TAC, is:
TAC = 1C + DC
= 34,692 + 28,899
- 63,591 $/yr
C.4 SIZING CALCULATIONS FOR SCRUBBER
Hand Calculations for the Ventcost Program Scrubber Procedure
• Stream to be costed is R-LFHH as it exists after combustion in
incinerator
C-8
-------
Calculate stream parameters after combustion. Assume 98 percent
VOC destruction
-» Ethyl chloride 1s the VOC in stream R-LFHH. There is one
mole of Cl for every mole of VOC. Therefore, for every
mole of VOC destroyed, one mole of HC1 is created.
VOC destroyed - (initial VOC flow-lb/hr)(0.98) + VOC MW
- (8.4 lb/hr){0.98)/(64.5 Ib/lb-mole)
- 0.13 Ib-mole/hr
HC1 created - 0.13 Ib-mole/hr
HC1 (Ib/hr) - (0.13 lb«mole/hr){36.5 Ib/lb-mole)
« 4,66 Ib/hr
Calculate inlet halogen concentration
HC1 (scfm) - (4.66 lb/hr)(lb-mole/36.5 lb) * 392 scf/lb-mole *
1 hr/60 min
» 0.83 scfm/min
HC1 (ppm) - (0.83 scfrnJ/Qfi • 10Afi
- (0.83/53) * 10A*
- 15,660 ppm (inlet concentration)
The halogen is chlorine, therefore
Molecular weight (Hal_MW) - 35.5
Slope of operating curve (slope) = 0.10
Schmidt No. for HC1 in air (SCG) - 0.809
Schmidt No. for HC1 in water (SCL) - 381.0
Calculate the solvent flow rate.
New flow - 53 scfm
Gas moles - (53 scfm)(.075 lb/ft3)(lb-mole/29 lb)(60 min/hr)
- (53)(0.155)
- 8.22 Ib-mole/hr
Assume L/g « 17 gpm/1,000 scfm
Convert to unitless ratio
L/G - 17 * (8.34 * 60)/[(1,000/392) * 60 * 29] - 1.916
C-9
-------
Absorption factor (AF) = (L/G)/slope
AF = 1.916/0.1
AF = 19.16
Liquid moles = (slope of operating curve) (adsorption factor AF)
(gas moles)
= 15.75 Ib-mole/hr
Liquid flow (gal/min) = (15.75 lb-mole/hr)(18 lb/lb.mole)/
(62.43 Ib/ft3)/60 min/hr * 7.48 gal/ft3
Liquid flow = 0.57 gal/min
Liquid flow (Ib/hr) = (0.57 gal/min) (8. 34 lb/gal)(60 min/hr)
= 283.3 Ib/hr
Calculate Column Diameter
Density of air = 0.0739 lb/ft3 (from ideal gas law)
Density of liquid = 62.2 lb/ft3
MW of gas stream = MW HCL x Volume Fraction + MW Air x Volume
Fraction
MW stream = 36.5 * (15,660/10*6) + 29 * [(10A6-15,880)/10A6]
= 36.5 * 0.0157 + 29 * 0.98434
= 29.12 lb/lb-mole
-*• Column diameter based on correlation for flooding rate in
randomly packed towers (see HAP manual)
ABSCISSA = (liquid lb/hr)/(gas Ib/hr) *
(density of gas/density of liquid)A°-5
ABS = [283.3/[8.22 * 29)] * (0. 0739/62. 2)A0-5
ABS = 0.0410
ORD = 0.9809237 * (ABS)A(-0. 0065226 * log [ABS]) +
(ABS)A(-0. 021897)
= 0.9809237*(0.0410)A(-0. 0065226 * log[0.0410]) +
(0.0410)A(-0. 012897)
ORD = 0.15
Calculate G_Area (Ib/ft^.sec) based on column cross sectional
area at flooding conditions.
G_Area = F * (ORD * density of gas * density of liquid *
32.2/69.1 * 0.85A0.2)A0.5
= 0.6 * (0.15 * 0.0739 * 62.2 * 32.2/69.1 * 0.85A0.2)A°-5
= 0.34
C-10
-------
Calculate the Area of the Column
Area of column = (MW stream * gas moles)/ (3, 600 * G_Area)
Area (ft2) - (29.12 * 8.22)/(3,600 * 0.34)
Area (ft2) . 0.19 ft2 •
Calculate Diameter of Column
D col - [(4/;r) Area]AQ-5
- 1.27 (Area)AQ-5
- 0.5 ft
Calculate liquid flux rate
Li. (Ib/hr-ft?) = (liquid flow lb/hr)/Area
LL - (283.3)/(0.19)
- 1,491
Calculate the number of gas transfer units (NOG) (Assume 98%
removal efficiency)
NOG = In [(Hal concentration/(0.02 * Hal concentration)) *
(1-d/AF)) 4 (1/AF)]/(1-(1/AF))]
- In [(15,660/(0.02 * 15,660))* (1-1/19.16) +
NOG =4.07
Calculate the height of the overall gas transfer unit (HOG)
using:
HOG = Hg + (1/AF) HL
where
HQ = Height of a single gas transfer unit (ft)
HL - Height of a liquid transfer unit (ft)
Based on generalized correlations:
HQ « [b * (3,600 * G_Area)Ac/(LLAd)](SCG)A°-5
HL - Y * (LL/liquid viscositv)AS * (SCL)A°-5 assuming 2-in.
ceramic raschig rings for packing
b - 3.82
c - 0.41
d - 0.45
C-ll
-------
s = 0.22
Y = 0.0125
-» To convert from centipoise to Ib/hr * ft2
Liquid viscosity = 0.85 * 2.42
g = 11.13
r = 0.00295
Therefore,
HG = [3.82 * (3,600 * 0.34)A°-41/(l,491A0-45)] * SCGA0.5
= 2.63 x 0.809A°-5 = 2.37
HL = (0.0125) * (1,491/2.05)A0.22 * SGLA°-5
= 0.051 * 381*0-5 = 1.0
Solving for HOG:
HOG = HG + (1/AF) * HL
= 2.37 + (1/19.16) * 1.0
= 2.42
Calculate the height of the packed column from HOG and NOG.
Allow for 2 ft of freeboard above and below the packing for gas
disentanglement, and additional height based on column.
Height (Ht) = (NOG)(HOG) + 2 + 0.25 * Diam. Col
= (4.07)(2.42) + 2 + 0.25 * 0.5
= 12 ft
Calculate Volume of Packing
Volume = (i7/4) * (D)2 * (NOG * HOG)
= (ii/4) * (.5)2 * (4.07 * 2.42)
= 1.93 ft3
Calculate Volume of Column
Volume = (/7/4)(Diam col)2 x Ht
= (0.785)(0.5)A2 x 12
= 2.36 ft3
Calculate Pressure Drop
DelPa = (g x 10'8) * [10A(r * LL/liquid density)] *
[(3,600 * G_Area)A2]/gas density
C-12
-------
* DelPa - (11.13 x 10-8) * (io*(0.00295 * 1,491/62.2)) *
((3600 * 0.34)A2)/0.0739
Del Pa - 2.66
Del Ptot - Del Pa * (NOG + H06)/5,2
- 2.66 * {4.07 * 2.42)/5.2
- 5.09
C.5 COST ANALYSIS--ESTIHATING SCRUBBER TOTAL CAPITAL INVESTHENT
* Total Cost of Tower 1s:
wt - (48 * D1am * ht) + 39 * Diarn*
- (48 * 0.5 * 12) + 39 * (0.5)2
wt - 297.8 Ibs
TCost - [1.900604 * (wt/1,000)A0.93839] * 1,000 * (355.6/298,2)
TCost - [1.900604 * (297.8/1,000)A0,93839] * 1,000 *
(355,6/298.2)
- 727
• Cost of Packing
Packcost - Volume of packing * 20
- 1.93 • 20
. 38.6
* Assume Cost of Duct Work and Fan
Duct cost - 3,907.5
Fan cost - 488.9
• Calculate Platform Cost. For columns less than 3 ft in diameter
design dlam (DD) - 3.
Platform Cost - 10A(0.78884 * In (diam) + 3.325) * (355.6/298.2)
- 10A(0.7884 * In (0.5) + 3.325) * (355.6/298.2)
- 715.6
• Assume Stackcost • 5,000
• Calculate Total Capital Investment (TCI)
TCI - (towercost + packcost + ductcost + fancost +
platform cost + stackcost) * 1.18 * 2.2
C-13
-------
TCI - (727 + 38.6 + 3,907 + 488.9 + 715.6 + 5,000) *
1.18 • 2.2
- $28,237
C.6 CALCULATING ANNUAL COSTS FOR SCRUBBERS
• Calculate Water Costs
Water - (liquid flow lb/hr)/8.34 Ib/gal * price per 1,000 gal *
8,760 hr/yr
Water - (283.4)/(8.34) * 0.22/1,000 • 8,760
Water - 65.49
• Calculate Electrical Costs Based on Pressure Drop
Elec = 0.0002 * new flow * DelPtot * 8,760 * elec_cost $/KW-Hr
- 0.0002 * 53 * 5.09 * 8,760 * 0.061
= 29 $/yr
• Calculate Cost of Labor, Supervision, Maintenance
Op labor - (1/2 hour per 8 hour shift ) *
(Annual operating hours) * (Op labor rate)
Op labor - 0.5/8 * 8,760 * 15.64
Op labor * 8,563 $/yr
Supervision - 0.15 * Op_Labor
Supervision • 0.15 * 8,563 - 1,284.44
Maintenance labor - 0.5/8 * 8,760 * 17.21
Maintenance labor - 9,422.48 $/yr
Maintenance materials - 9,428.48 $/yr
• Calculate Direct Operating Costs
Dir Op Cost » Water + electric + op_labor + supervision +
main labor + maintenance materials
Dir Op Cost = 65.49 + 29 + 8,563 + 1,284.44 +
9,422.5 + 9,422.5
Dir Op Cost = 28,786 $/yr
C-14
-------
• Calculate cost of overhead, tax, insurance, administrative, and
capital recovery costs
Tax - 0.01 * TCI - 282.4
Insurance - 0.01 * TCI - 282.4
Administrative - 0.02 * TCI - 564.7
CRC - 0.16275 * TCI - 4,596
Overhead - 0.6 * (op_labor + supervision +
main_La + maint)
Overhead - 17,215
• Calculate indirect operating costs
Ind Op Cost * Overhead + Tax + Insurance + Administrative + CRC
- 17,215.44 + 282.4 + 282.4 + 564.7 + 4,596
- 22,940
• Annual Operating Cost, Anncost
Anncost « 28,786 + 22,940
Anncost - 51,726 $/yr
C.7 SIZING CALCULATIONS FOR FLARES
Hand Calculations for the VENTCOST Program - Flare Procedure
* Used to assess control equipment cost for the SOCMI CTG
* Calculations based on OAQPS Control Cost Manual, Chapter 7.
• The stream costed in this example is model stream D-HFLH. Its
characteristics are the following;
VOC to be controlled
MW
Flow rate (total)
VOC flow rate
Heat value
Oxygen content
Isophthalic acid
166 Ib/lb mole
632.401 scfm
6.15 Ib/hr
19 Btu/scf
0%
A. Flare tip diameter is generally sized on a velocity basis.
Flare tip sizing is governed by EPA rules defined in the
Federal Register. For flares with a heat value less than
300 Btu/scf the maximum velocity 1s 60 ft/sec.
1. The net heating value of vent stream - 19 Btu/scf
C-15
-------
2. Thus maximum velocity (Vmax), - 60 ft/sec. (It is standard
practice to size flares at 80 percent of
3. Calculate the heat released by combustion of the vent
stream
Heatrel (Btu/hr) - Vent Flow * heat value * 60 min/hr
« 632.401 scfro * 19 Btu/scf * 60
- 720,937 Btu/hr
4. Flare height (ft) 1s determined using Equation 7-3 in OAQPS
SOCMI flares chapter.
Height - (TFQ/rwk)0-5
where
T = Fraction of heat intensity transmitted
F = Fraction of heat radiated
Q - Heat release (Btu/hr) - 720,937 Btu/hr
k = allowable radiation, (500 Btu/hr-ft2)
Assuming (a) no wind effects, (b) center of radiation at
the base of the flare, and (c) thermal radiation limited at
base of the flare.
T - 1
F = 0.2
k - 500
Substituting and simplifying,
Height « ((heatre1)0«5)./iJ7.24
(Note that this assumes allowable radiation =
500 Btu/hr. ft*)
Height - 4.79 ft
The minimum flare height is 30 ft. Therefore,
Height » 30 ft
C-16
-------
5. Calculate the auxiliary fuel flow required to sustain a
stable flame. A minimum heat value of 300 Btu/scf is
required by 40 CFR, Section 60.18. Therefore, the
auxiliary fuel flow, Qaf (scfro) is:
Qaf - Vent flow * (300 - heat value)/{1000-300)
- 632 * (300-19)/(1000-300)
- 253.70 scfm
6. Calculate total stream flow, Qj0t (scfm):
Qtot " Vent flow + Qaf
- 632 + 253.7
- 886 scfm
7. Calculate minimum flare tip diameter, D, (in.) by
D
- 12[4/ir * (Qtot/6fl)/0,8
- 12[4/ir * (886/60)]°-5
12(0.392)°-
- 7.51 in.
Since the calculated diameter is rounded up to the next
commercially available size, available in 2-in. increments,
the diameter would be D - 8 in.
B. Purge Gas Requirement - Purge gas is used to maintain a minimum
required constant flow through the system. Using the
conservative value of 0.04 ft/sec (gas velocity) and knowing the
flare diameter, the annual P volume can be calculated.
1. P(scfm/yr) - (0.04) * ((ir)/4) * (D2)/144 * 60
- 0.006 scfm
C. Pilot Gas Requirement
1. Since the number of pilot burners (n) is based on flare
size (flare diameter 1 to 10 in, - 1 pilot burner) this
stream would require 1 burner (our flare tip is 8 in.)
2. Pilot gas flow (fp)
Fp - (70 scf/hr) * N * (hr/60 min)
- 1.167 scfm
D. Steam Requirement
The steam requirement depends on the composition of the vent gas
being flared, the steam velocity from the injection nozzle, and
the flare tip diameter.
C-17
-------
1. The steam requirement can be calculated based on steam -
C0£ weight ratio of 0.68 (see Equation 7-7, OCCM flares
chapter).
Wsteam = flow * (0.075 * 60) * 0.4
= 632 * (0.075 * 60) * 0.4
* 1,137 Ib/hr
E. Knockout Drum
The dropout velocity, U, of a particle in a stream, or the
maximum design vapor velocity, is calculated by:
1. U = K x ((P1 - Pv)/pv)°-5 ft/sec
where
k = design vapor velocity factor = .2 assumed as
representative of the k range of 0.15 to 0.25
P! = 37 = liquid density, assumed
Pv = 0.1125 vapor density, assumed
U = 3.62
F. The maximum vessel cross-sectional area, A, can be calculated
by:
A = Q (ft3/min)/(60 x U (ft/sec), ft?
Q = 632 scfm
A = 632/(60 x 3.62)
A = 2.91
G. Calculate vessel diameter
1. The vessel diameter, dmin, is calculated by:
dmin = 12 (in/ft) x (4 x A (ft2)/77)0.5, in.
dmin = 12 x (4 x 2.91/77)0-5
dmin = 23.1 in.
2. In accordance with standard head sizes, drum diameters in
6-in. increments are assumed so:
d = dmi-n to the next largest 6 in.
d = 24 in.
C-18
-------
3. The vessel height, h, is determined by:
h - 3 x d, in.
h - 3 x 24 = 72 in.
C.8 COST ANALYSIS - ESTIMATING TOTAL CAPITAL INVESTMENT FOR FLARES
(*Assuming March 1990 Dollars)
A. Flare costs (Cf) are calculated as a function of stack height,
H (ft) and tip diameter, D, (in), and are based on support type.
Derrick support group was not considered since the stack height
is < 100 ft.
1. Self Support Group
Cf = [78 + 9.14 (D) -i- .75 (H)]2
Cf - [78 + 9.14 (8) + .75 (30)]2
Cf - 30,144
2. Guy Support Group:
Cf - [103.17 + 8.68(8) + .47 (30)]2
Cf - 34,861
Since Self Support is < Guy Support, the cheaper is chosen.
B, Cost for 100 ft of transfer and header pipe, Cp, assuming
400 length needed.
Cp - (127.4 x D-) x 4
Cp » (127.4 x 8l-!21) x 4
Cp = 5,243
Cost for knockout drum, C^, is a function of drum diameter,
d (ft) and height (ft)
Cfc - 14.2 x [d x t x (h + 0.0812 x d)]0-737
where
t * vessel thickness (in.)
C-19
-------
vessel thickness Is determined based on drum diameter. Since
Drum diameter, d - 24 in. - 2.0 ft and
Drum height, h - 90 1n. - 7.5 ft,
Drum thickness, t • 0.25 in.
Cfc - 14.2 x [24 x 0.25 x (90 + 0.0812 x 24)]0-737
Ck - 1,484
0. Collection Fan Cost
Cfan " (96.96418 x 632 scfm<>.5471969) x 355.6/342.5
- 3,431
Collection Fan Cost based on 1988 Richardson Manual; see Chris
Bagley's March 9, 1990, calculation placed in the polystyrene
file.
E. Flare system equipment cost, EC, 1s the total of the calculated
flare, knockout drum, manifold piping, and collection fan cost.
Ec - [Cf + Ck + Cp) * 355.6/354.6] + Cfan
Ec - [30,144 + 1,484 + 5,243) * 355.6/354.6] + 3,431
EC - 41,712
F. Purchased equipment cost, PEC, 1s equal to equipment cost, EC,
plus factors for instrumentation (.10), sales taxes (0.03), and
freight (0.05) or
PEC - EC x (1 + 0.10 + 0.03 + 0.05)
PEC - 1.18 x 41,712
PEC - 49,220
G. Installation Costs: The total capital investment, TCI, is
obtained by multiplying the purchased equipment costs, PEC, by
an Installation factor of 1.92
TCI - 1.92 x PEC
TCI - 1.92 x 48,916
TCI - 94,502
C-20
-------
C.§ CALCULATING ANNUAL COST FOR FLARES
A. Direct Annual Cost
1. Total natural gas cost* Cf, to operate a flare system
includes pilot, Cp, auxiliary fuel, Ca, and purge cost Cpu:
Cf • Cp + Ca + Cpy
where Cp 1s equal to the annual volume of pilot gas, fp,
multiplied by the cost per scf
Cn ($/yr) - Flow * 60 * 8,760
- fp (scf/yr) x ($/scf)
Assume price of natural gas - 3.30 $/Mscf
Cp - 1.167 scfm * 60 • 8,760 x (3.30 $/Mscf)
Cp - $2,024/yr
2. Annual Purge gas cost CDU « 247.68 x D2 {Mscf/yr) *
(3.3 $/Mscf)
Annual Cpu - $817.3/yr
3. Auxiliary Gas Cost Ca
133,350 Mscf/yr x 3.3 $/Mscf - $440,055/yr
4. Cf - 2,024 + 817.3 + 440,055 - $442,896/yr
B. Calculate Steam Cost (Cs) required to eliminate smoking
Cs ($/y) - 8,760 (hr/yr) x steam use (Ib/hr) x ($/lb)
Cs » 8,760 x 1,137 x 4.65 x 10'3
Cs - $46,315
C. Calculate operating labor cost, based on 630 manhours/yr
Operator labor - 0.5/8 * 8,760 * $15.64 - 8,562
Supervisor labor 8,572 x .15 « 1.286
Total labor - 9,848
D. Naintenance labor cost and materials
Haintenance labor ($/yr) - (1/2 hr/8 hrs shift) x 8,760 hr/yr x
$17.21/hr - $9,422/yr
Haterials assumed equal to maintenance labor - $9,422/yr
C-21
-------
APPENDIX D
SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY
CONTROL TECHNIQUES GUIDELINE EXAMPLE RULE
-------
EXAMPLE ONLY
APPENDIX D
SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY
CONTROL TECHNIQUES GUIDELINE EXAMPLE RULE
D.I INTRODUCTION
This appendix presents an example rule limiting volatile organic
compound (VOC) emissions from reactor processes and distillation
operations. The example rule is for informational purposes only and, as
such, is not legally binding. The purpose of the example rule is to
provide a model containing information on the sections and typical issues
that need to be considered in writing a rule to ensure clarity and
enforceability of the standards.
Two points concerning implementation of the recommended reasonably
available control technology (RACT) in Chapter 6.0 warrant consideration
in drafting a regulation. First, Chapter 6.0 recommended that any reactor
process or distillation vent stream for which an existing combustion
device is employed to control VOC emissions should not be required to meet
the 98 percent destruction or 20 parts per million by volume emissions
limit until the combustion device is replaced for other reasons. Second,
Chapter 6.0 recommended that the total resource effectiveness index limit
be applied on an individual process vent stream basis for a given process
unit.
An additional point warranting consideration when drafting a
regulation pertains to the reporting requirements. Section 7.8 stated
that reporting frequency is left to the discretion of State air quality
management agencies; however, this model rule provides example
D-l
-------
E. Overhead Cost
= 0.60 x (op labor + supervisor + labor + materials)
= 0.60 x (8,572 + 1,286 + 9,422 + 9,422)
- 17,221
F. Capital Recovery Factor: Assume 15 year life and 10% interest
so CRF - 0.1314
Capital recovery cost = 0.1314 x TCI
= 0.1314 x 94,502
= $12,418
G. General and Administrative, Taxes, and Insurance Costs
Assume 4% of total capital investment
4% of 94,502
= 3,780
H. Utilities--Power consumption based on actual minimum flow
Pressure drop = [1.238 * 10'6 * flow - (1.15 * 10'4)] *
length of pipe
= [1.238 * ID'5 * 632 - 1.15 * 10'4] * 400
= 0.27 in. H20
Power = (1.17 * 10'4 * flow * pressure drop)/0.6
= [1.17 * 10'4 * 632 * 0.27J/0.6
= 0.03 kW
I. Elec cost = Power x op hours x elec price (S/1000 kW-hrs)
= (0.03)(8,760)(0.061)
= 16.03
J. Calculating total Annual Costs (Indirect and Direct)
1. Direct Annual Cost
Direct Cost = Cost electricity + materials +
maintenance labor + supervisors +
operation labor + steam cost + fuel cost
Direct cost = 16.03 + 9,422 + 9,422 + 1,286 + 8,562 +
46,315 + 443,162
= 518,383
C-22
-------
2. Indirect Annual Cost
IAC - general + capital recovery cost + overhead
IAC = 3,757 + 12,341 + 17,221
IAC - 33,320
K. Annual Cost - Direct cost + Indirect Cost
• 518,383 + 33,320
• 551,702
C-23
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EXAMPLE ONLY
(iii) Any boiler or process heiter in which all vent streams are
Introduced with primary fuel are exempt from these requirements.
(3) Where an owner or operator subject to the provisions of this
subpart seeks to demonstrate compliance with D.4(a)(2) through use of a
smokeless flare; flare design (I.e., steam-assisted, air-assisted, or
nonassisted), all visible emission readings, heat content determinations,
flow rate measurements, and exit velocity determinations made during the
performance test, continuous records of the flare pilot flame monitoring,
and records of all periods of operations during which the pilot flame is
absent.
(4) Where an owner or operator subject to the provisions of this
subpart seeks to demonstrate compliance with D.4(b):
(i) Where an absorber is the final recovery device in the recovery
system, the exit specific gravity (or alternative parameter which is a
measure of the degree of absorbing liquid saturation, if approved, by the
permitting authority), and average exit temperature of the absorbing
liquid measured at least 15 minutes and averaged over the same time period
of the performance testing (both measured while the vent stream is
normally routed and constituted), or
(ii) Where a condenser is the final recovery device the recovery
system, the average exit (product side) temperature measured at least
every 15 minutes and averaged over the same time period of the performance
testing while the vent stream is routed and constituted normally, or
(iii) Where a carbon adsorber is the final recovery device in the
recovery system, the total stream mass or volumetric flow measured at
least every 15 minutes and averaged over the same time period of the
performance test (full carbon bed cycle), temperature of the carbon bed
after regeneration (and within 15 minutes of completion of any cooling
cycle(s)), and duration of the carbon bed steaming cycle (all measured
while the vent stream is routed and constituted normally), or
(iv) As an alternative to D.7(a)(4)(1), (a)(4)(ii) or (a)(4)(iii),
the concentration level or reading indicated by the organics monitoring
device at the outlet of the absorber, condenser, or carbon adsorber,
measured at least every 15 minutes and averaged over the same time period
D-20
-------
EXAMPLE ONLY
as the performance testing while the vent stream is normally routed and
constituted.
(v) All measurements and calculations performed to determine the
flow rate, and volatile organic compound concentration, heating value, and
TRE index value of the vent stream.
(b) Each reactor process or distillation operation subject to this
guideline will also be subject to the exceedance reporting requirements of
the draft Enhanced Honitoring Guideline. The specifics of the
requirements will be added to this document when the Enhanced Monitoring
Guideline is quotable.
(c) Each reactor process or distillation operation seeking to comply
with D.4(b) shall also keep records of the following information:
(1) Any changes in production capacity, feedstock type, or catalyst
type, or of any replacement, removal, and addition of recovery equipment
or reactors and distillation units.
(2) Any recalculation of the flow rate, TOC concentration, or TRE
value performed according to D.5(g).
(d) Each reactor process or distillation operation seeking to comply
With the flow rate or concentration exemption level in D.2(b)(4) shall
keep records to indicate that the stream flow rate is less than
0.0085 standard cubic meters per minute or the concentration is less than
500 parts per million by volume.
(e) Each reactor process or distillation operation seeking to comply
with the production capacity exemption level of 1 gigagrams per year shall
keep records of the design production capacity or any changes in equipment
or process operation that may affect design production capacity of the
affected process unity.
D-2I
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EXAMPLE ONLY
(d) The owner or operator of an affected facility that seeks to
demonstrate compliance with the total resource effectiveness index limit
specified under D.4(b) shall install, calibrate, maintain, and operate
according to manufacturer's specifications the following equipment:
(1) Where an absorber is the final recovery device in the recovery
system:
(i) A scrubbing liquid temperature monitor equipped with a
continuous recorder.
(ii) Specific gravity monitor equipped with continuous recorders.
(2) Where a condenser is the final recovery device in the recovery
system, a condenser exit (product side) temperature monitoring device
equipped with a continuous recorder and having an accuracy of ±1 percent
of the temperature being monitored expressed in degrees Celsius or
±0.5 °C, whichever is greater.
(3) Where a carbon adsorber is the final recovery device unit in the
recovery system, an integrating regeneration stream flow monitoring device
having an accuracy of ±10 percent, capable of recording the total
regeneration stream mass flow for each regeneration cycle; and a carbon
bed temperature monitoring device having an accuracy of ±1 percent of the
temperature being monitored expressed in degrees Celsius of ±0.5 °C,
capable of recording the carbon bed temperature after each regeneration
and within 15 minutes of completing any cooling cycle.
(4) Where an absorber scrubs halogenated streams after an
incinerator, boiler, or process heater, the following monitoring equipment
is required for the scrubber.
(1) A pH monitoring device equipped with a continuous recorder.
(ii) Flow meters equipped with a continuous recorders to be located
at the scrubber influent for liquid flow and the scrubber inlet for gas
stream flow.
(e) The owner or operator of a process vent using a vent system that
contains bypass lines that could divert a vent stream away from the
combustion device used shall either:
(1) Install, calibrate, maintain, and operate a flow indicator that
provides a record of vent stream flow at least once every 15 minutes. The
D-18
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EXAMPLE ONLY
flow indicator shall be installed at the entrance to any bypass line that
could divert the vent stream away from the combustion device to the
atmosphere; or
(2) Secure the bypass line valve in the closed position with a
car-seal or a lock-and-key type configuration. A visual inspection of the
seal or closure mechanism shall be performed at least once every month to
ensure that the valve is maintained in the closed position and the vent
stream is not diverted through the bypass line.
D.7 REPORTING/RECORDKEEPING REQUIREMENTS
(a) Each reactor process or distillation operation subject to this
rule shall keep records of the following parameters measured during a
performance test or TRE determination required under D.5, and required to
be monitored under D.6.
(1) Where an owner or operator subject to the provisions of this
subpart seeks to demonstrate compliance with 0.4(a)(l) through use of
either a thermal or catalytic incinerator:
(i) The average firebox temperature of the incinerator (or the
average temperature upstream and downstream of the catalyst bed for a
catalytic incinerator), measured at least every 15 minutes and averaged
over the same time period of the performance testing, and
(ii) The percent reduction of TOC determined as specified in D.5(c)
achieved by the incinerator, or the concentration of TOC (parts per
million by volume, by compound) determined as specified in D.5(c) at the
outlet of the control device on a dry basis corrected to 3 percent oxygen.
(2) Where an owner or operator subject to the provisions of this
subpart seeks to demonstrate compliance with D.4(a)(l) through use of a
boiler or process heater:
(i) A description of the location at which the vent stream is
introduced into the boiler or process heater, and
(ii) The average combustion temperature of the boiler or process
heater with a design heat input capacity of less than 44 megawatt measured
at least every 15 minutes and averaged over the same time period of the
performance testing.
D-19
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EXAMPLE ONLY
(1) For the purpose of demonstrating that a process vent stream has
a VOC concentration below 500 parts per million by volume, the following
to set procedures shall be followed:
(1) The sampling site shall be selected as specified in D.5(c)(l).
(2) Method 18 or Method 25A of Part 60, Appendix A shall be used to
measure concentration; alternatively, any other method or data that has
been validated according to the protocol in Method 301 of Part 63,
Appendix A may be used.
(3) Where Method 18 is used, the following procedures shall be used
to calculate parts per million by volume concentration:
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or four grab samples shall be taken. If grab
sampling is used, then the samples shall be taken at approximately equal
intervals in time, such as 15 minute intervals during the run.
(ii) The concentration of TOC (minus methane and ethane) shall be
calculated using Method 18 according to D.5(c)(4).
(4) Where Method 25A is used, the following procedures shall be used
to calculate parts per million by volume TOC concentration:
(i) Method 25A shall be used only if a single VOC is greater than
50 percent of total VOC, by volume, in the process vent stream.
(ii) The process vent stream composition may be determined by either
process knowledge, test data collected using an appropriate EPA Method or
a method of data collection validated according to the protocol in
Method 301 of Part 63, Appendix A. Examples of information that could
constitute process knowledge include calculations based on material
balances, process stoichiometry, or previous test results provided the
results are still relevant to the current process vent stream conditions.
(iii) The VOC used as the calibration gas for Method 25A shall be
the single VOC present at greater than 50 percent of the total VOC by
volume.
(iv) The span value for Method 25A shall be 50 parts per million by
volume.
(v) Use of Method 25A is acceptable if the response from the
high-level calibration gas is at least 20 times the standard deviation of
D-16
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EXAMPLE ONLY
the response from the zero calibration gas when the instrument is zeroed
on the most sensitive scale.
(vi) The concentration of TOC shall be corrected to 3 percent oxygen
using the procedures and equation in D.5(c)(3).
(5) The owner or operator shall demonstrate that the concentration
of TOC including methane and ethane measured by Method 25A is below
250 parts per million by volume with VOC concentration below 500 parts per
million by volume to qualify for the low concentration exclusion.
D.6 HONITORING REQUIREMENTS
(a) The owner or operator of an affected facility that uses an
incinerator to seek to comply with the TOC emission limit specified under
D.4{a)(l) shall install, calibrate, maintain, and operate according to
manufacturer's specifications: a temperature monitoring device equipped
with a continuous recorder and having an accuracy of ±0.5 °C, whichever is
greater.
(1) Where an incinerator other than a catalytic incinerator is used,
a temperature monitoring device shall be installed in the firebox.
(2) Where a catalytic incinerator is used, temperature monitoring
devices shall be installed in the gas stream immediately before and after
the catalyst bed.
(b) The owner or operator of an affected facility that uses a flare
to seek to comply with D.4(a)(2) shall install, calibrate, maintain, and
operate according to manufacturer's specifications, a heat-sensing device,
such as a ultraviolet beam sensor or thermocouple, at the pilot light to
indicate continuous presence of a flame.
(c) The owner or operator of an affected facility that uses a boiler
or process heater with a design heat input capacity less than 44 megawatts
to seek to comply with D.4(a){l) shall install, calibrate, maintain, and
operate according to the manufacturer's specifications, a temperature
monitoring device in the firebox. The monitoring device should be
equipped with a continuous recorder and having an accuracy of ±1 percent
of the temperature being measured expressed 1n degrees Celsius or ±0.5 °C,
whichever is greater. Any boiler or process heater in which all vent
streams are introduced with primary fuel is exempt from this requirement.
D-17
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EXAMPLE ONLY
Qs = Vent stream flow rate standard cubic meters per minute at a
standard temperature of 20 °C.
Hj - Vent stream net heating value (megajoules per standard
cubic meter), as calculated in D.5(e}(6).
ETQC " Hourly emission rate of TOC (minus methane and ethane),
(kilograms per hour) as calculated in paragraph D.5(e)(4).
a,b,c,d = Coefficients presented in Table D-l.
(2) The owner or operator of a vent stream shall use the applicable
coefficients in Table D-l to calculate the TRE index value based on a
flare, a thermal incinerator with 0 percent heat recovery, and a thermal
incinerator with 70 percent heat recovery, and shall select the lowest TRE
index value.
(3) The owner or operator of a unit with a halogenated vent stream,
determined as any stream with a total concentration of halogen atoms
contained in organic compounds of 200 parts per million by volume or
greater, shall use the applicable coefficients in Table D-l to calculate
the total resource effectiveness index value based on a thermal
incinerator and scrubber.
(g) Each owner or operator of an affected facility seeking to comply
with D.4(b) shall recalculate the flow rate and TOC concentration for that
affected facility whenever process changes are made. Examples of process
changes include changes in production capacity, feedstock type, or
catalyst type, or whenever there is replacement, removal, or addition of
recovery equipment. The flow rate and VOC concentration shall be
recalculated based on test data, or on best engineering estimates of the
effects of the change to the recovery system.
(h) Where the recalculated values yield a total resource
effectiveness index <1.0, the owner or operator shall notify the State air
quality management agency within 1 week of the recalculation and shall
conduct a performance test according to the methods and procedures
required by D.5.
D-14
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TABLE D-l. COEFFICIENTS FOR TOTAL RESOURCE EFFECTIVENESS FOR
NONHALOGENATED AND HALOGENATED VENT STREAMS
Type of stream
Control device basis
Values of Coefficients
Nonhalogenated
o
•
1—4
in
Halogenated
Flare
Thermal incinerator
0 Percent heat
Recovery
Thermal incinerator
70 Percent heat
Recovery
Thermal incinerator
and scrubber
2.129 0.183 -0.005 0.359
3.075 0.021 -0.037 0.018
3.803
5.470
0.032
0.181
-0.042
-0.040
0.007
0.004
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EXAMPLE ONLY
attributable to the reactor or distillation vent stream. The resulting
organic compound concentrations are then used to perform the calculations
outlined in D.5(e)(4).
(2) The molar composition of the vent stream shall be determined as
follows:
(i) Method 18 to measure the concentration of organic compounds
including those containing halogens.
(ii) ASTM 01946-77 to measure the concentration of carbon monoxide
and hydrogen.
(iii) Method 4 to measure the content of water vapor.
(3) The volumetric flow rate shall be determined using Method 2, 2A,
2C, or 20, as appropriate.
(4) The emission rate of TOC (minus methane and ethane) (Ejoc) in
the vent stream shall be calculated using the following equation:
Em - <2 Z CjMj Qs
j=l
where:
EJOC * Emission rate of TOC (minus methane and ethane)
in the sample, kilograms per hour.
K£ - Constant, 2.494 x 10'6 (liters per parts per
mill ion)(gram-moles per standard cubic meter)(kilogram per
gram)(minute per hour), where standard temperature for
(gram-mole per standard cubic meter)(g-mole/scm) is 20 °C.
Cj = Concentration of compound j, on a dry basis, in parts per
million as measured by Method 18, as indicated in D.5(c)(3).
MJ - Molecular weight of sample j, grams per gram-mole.
Qs * Vent stream flow rate (standard cubic meters per minute) at a
temperature of 20 °C.
(5) The total process vent stream concentration (by volume) of
compounds containing halogens (parts per million by volume, by compound)
shall be summed from the individual concentrations of compounds containing
halogens which were measured by Method 18.
0-12
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EXAMPLE ONLY
(6) The net heating value of the vent stream shall be calculated
using the equation;
HJ
where:
Hj * Net heating value of the sample (mega joule per standard cubic
meter), where the net enthaply per mole of vent stream 1s based
on combustion at 25 °C and 760 millimeters of mercury* but the
standard temperature for determining the volume corresponding
to one mole 1s 20 °C, as In the definition of Qs (vent stream
flow rate).
K! * Constant, 1.740 x 10"? (parts per million)'! (gram-mole per
standard cubic meter), (megajoule per ki local or! e), where
standard temperature for (gram-mole per standard cubic meter)
is 20 °C.
BVIS - Water vapor content of the vent stream, proportion by volume;
except that if the vent stream passes through a final stream
jet and is not condensed, it shall be assumed that B^s - 0.023
in order to correct to 2.3 percent moisture.
Cj « Concentration on a dry basis of compound j in parts per
million, as measured for all organic compounds by
Method 18 and measured for hydrogen and carbon monoxide by
the American Society for Testing and Materials 01946-77.
HJ « Net heat of combustion of compound j, ki local or ie per
gram-mole, based on combustion at 25 °C and 760 millimeters of
mercury. The heats of combustion of vent stream components
shall be determined using American Society for Testing and
Materials D2382-76 if published values are not available or
cannot be calculated.
(f)(l) The total resource effectiveness index value of the vent
shall be calculated using the following equation:
TRE - _ 1_ [a + b (Qs) + c (HT) + d (ETOc)3
ETOC
where :
TRE - TRE index value.
* Hourly emission rate of TOC (kilograms per hour) as
calculated in D.5(e)(4).
D-13
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EXAMPLE ONLY
(iii) The mass rates of TOC (E-j, E0) shall be computed using the
following equations:
n
E-j - K£ ( Z CijMij) Qi
j-l
n
EQ * K£ ( X CojMgj ) QO
j-l
where:
C0j = Concentration of sample component "j" of the gas stream at
the inlet and outlet of the control device, respectively,
dry basis, parts per million by volume.
Mij> MOJ * Molecular weight of sample component "j" of the gas stream
at the inlet and outlet of the control device,
respectively, grams per gram-mole.
Qi, Q0 « flow rate of gas stream at the inlet and outlet of the
control device, respectively, dry standard cubic meters
per minute.
K2 « 2.494 x 10~6 (liters per minute)(gram-mole per standard
cubic meter)(kilogram per gram)(minute per hour), where
standard temperature for (gram-mole per standard cubic
meter) is 20 °C.
(iv) The TOC concentration (Cjoc) is the sum of the individual
components and shall be computed for each run using the following
equation:
n
CTOC " * Cj
j-l
where:
Cjoc " Concentration of TOC (minus methane and ethane), dry basis,
parts by million by volume.
Cj - Concentration of sample component "j", dry basis, parts per
million by volume.
n * Number of components in the sample.
D-10
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EXAMPLE ONLY
(5) When i boiler or process heater with a design heat input
capacity of 44 megawatts or greater, or a boiler or process heater into
which the process vent stream is introduced with the primary fuel, is
used to comply with the control requirements, in initial performance test
Is not required.
(d) When a flare is used to comply with the control requirements of
this rule, the flare shall comply with the requirements of 40 CFR 60.18.
(e) The following test methods shall be used to determine compliance
with the TRE index value,
(1) Method 1 or 1A, as appropriate, for selection of the sampling
site.
(i) The sampling site for the vent stream molar composition
determination and flow rate prescribed in D.5(e)(2) and (e)(3) shall be,
except for the situations outlined in paragraph (e)(l){ii) of this
section, after the final recovery device, if a recovery system is present,
prior to the inlet of any control device, and prior to any post-reactor or
post-distillation unit introduction of halogenated compounds into the
process vent stream. No traverse site selection method is needed for
vents smaller than 10 centimeters in diameter.
(ii) If any gas stream other than the reactor or distillation vent
stream is normally conducted through the final recovery device:
(A) The sampling site for vent stream flow rate and molar
composition shall be prior to the final recovery device and prior to the
point at which any nonreactor or nondistillation stream or stream from a
nonaffected reactor or distillation unit is introduced. Method 18 shall
be used to measure organic compound concentrations at this site.
(B) The efficiency of the final recovery device is determined by
measuring the organic compound concentrations using Method 18 at the inlet
to the final recovery device after the introduction of all vent streams
and at the outlet of the final recovery device.
(C) The efficiency of the final recovery device determined according
to D.5(e)(l){11)(B) shall be applied to the organic compound
concentrations measured according to D.5(e)(l)(11)(A) to determine the
concentrations of organic compounds from the final recovery device
D-ll
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EXAMPLE ONLY
properties. Examples for analytical methods Include, but are not limited
to:
(A) Use of material balances based on process stoichiometry to
estimate maximum VOC concentrations.
(B) Estimation of maximum flow rate based on physical equipment
design such as pump or blower capacities.
(C) Estimation of TOC concentrations based on saturation conditions.
(D) Estimation of maximum expected net heating value based on the
stream concentration of each organic compound, or, alternatively, as if
all TOC in the stream were the compound with the highest heating value.
(v) All data, assumptions, and procedures used in the engineering
assessment shall be documented.
(b) For the purpose of demonstrating compliance with the control
requirements of this rule, the process unit shall be run at representative
operating conditions and flow rates during any performance test.
(c) The following methods in 40 CFR 60, Appendix A, shall be used to
demonstrate compliance with the emission limit or percent reduction
efficiency requirement listed in D.4(a)(l).
(1) Method 1 or 1A, as appropriate, for selection of the sampling
sites. The control device inlet sampling site for determination of vent
stream molar composition or TOC (less methane and ethane) reduction
efficiency shall be located after the last recovery device but prior to
the inlet of the control device, prior to any dilution of the process vent
stream, and prior to release to the atmosphere.
(2) Method 2, 2A, 2C, or 20, as appropriate, for determination of
gas stream volumetric flow rate.
(3) The emission rate correction factor, integrated sampling, and
analysis procedure of Method 3 shall be used to determine the oxygen
concentration (% 0£d) for the purpose of determining compliance with the
20 parts per million by volume limit. The sampling site shall be the same
as that of the TOC samples, and samples shall be taken during the same
D-8
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EXAMPLE DULY
time that the TOC samples are taken. The TOC concentration corrected to
3 percent oxygen (Cc) shall be computed using the following equation:
Cc - CTQC
c lut
20.9 -
where:
Cc - Concentration of TOC (minus methane and ethane) corrected to
3 percent Og, dry basis, parts per million by volume.
CTOC " Concentration of TOC (minus methane and ethane), dry basis,
parts per million by volume.
Concentration of oxygen, dry basis, percent by volume.
(4) Method 18 to determine the concentration of TOC (less methane
and ethane) at the outlet of the control device when determining
compliance with the 20 parts per million by volume limit, or at both the
control device inlet and outlet when the reduction efficiency of the
control device is to be determined.
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or four grab samples shall be taken. If grab
sampling is used then the samples shall be taken at 15 -minute intervals.
(ii) The emission reduction (R) of TOC (less methane and ethane)
shall be determined using the following equation:
R - Ei ' E° x 100
Ei
where:
R - Emission reduction, percent by weight.
Ei - Mass rate of TOC (minus methane and ethane) entering the control
device, kilogram TOC per hour.
E0 = Mass rate of TOC (minus methane and ethane) discharged to the
atmosphere, kilogram TOC per hour.
D-9
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EXAMPLE ONLY
negligible photochemical reactivity. The Administrator has designated the
following organic compounds as negligibly reactive: methane; ethane;
1,1,1-trichloroethane; methylene chloride, trichlorofluoromethane;
dichlorodifluoromethane; chlorodifluoromethane; trifluoromethane;
trichlorotrifluoroethane; dichlorotetrafluoroethane; and
chloropentaf1uoroethane.
Total resource effectiveness index value or "TRE index value" means a
measure of the supplemental total resource requirement per unit reduction
of organic hazardous air pollutants associated with a process vent stream,
based on vent stream flow rate, emission rate of volatile organic
compound, net heating value, and corrosion properties (whether or not the
vent stream contains halogenated compounds) as quantified by the given
equations. The TRE index is a decision tool used to determined if the
annual cost of controlling a given vent gas stream is acceptable when
considering the emissions reduction achieved.
Vent stream means any gas stream discharge directly from a
distillation operation or reactor process to the atmosphere or indirectly
to the atmosphere after diversion through other process equipment. The
vent stream excludes relief valve discharges and equipment leaks
including, but not limited to, pumps, compressors, and valves.
D.4 CONTROL REQUIREMENTS
(a) For individual vent streams within a process unit with a TRE
index value less than or equal to 1.0, the owner or operator shall comply
with paragraphs (1) or (2) of this section.
(1) Reduce emission of TOC (less methane and ethane) by
98 weight-percent, or to 20 parts per million by volume, on a dry basis
corrected to 3 percent oxygen, whichever is less stringent. If a boiler
or process heater is used to comply with this paragraph, then the vent
stream shall be introduced into the flame zone of the boiler or process
heater.
(2) Combust emissions in a flare. Flares used to comply with this
paragraph shall comply with the requirements of 40 CFR 60.18. The flare
operation requirement does not apply if a process, not subject to this
CTG, vents an emergency relief discharge into a common flare header and
D-6
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EXAMPLE ONLY
causes the flare servicing the process subject to this CTG to be out of
compliance with one or more of the provisions of the flare operation rule.
(b) For each individual vent streams within a process unit with a
TRE index value greater than 1.0, the owner or operator shall maintain
vent stream parameters that result in a calculated total resource
effectiveness greater than 1.0 without the use of a volatile organic
compound control device. The TRE index shall be calculated at the outlet
of the final recovery device.
D.5 TOTAL RESOURCE EFFECTIVENESS DETERMINATION, PERFORMANCE TESTING, AND
EXEMPTION TESTING
(a) For the purpose of demonstrating compliance with the TRE index
value in D.4(b), engineering assessment may be used to determine process
vent stream flow rate, net heating value, and TOC emission rate for the
representative operating condition expected to yield the lowest TRE index
value.
(1) If the TRE value calculated using such engineering assessment
and the TRE equation in paragraph D.5(f)(l) is greater than 4.0, then it
is not recommended that the owner or operator perform the measures
specified in Section D.5(e).
(2) If the TRE value calculated using such engineering assessment
and the TRE equation in paragraph D.5(f)(l) is less than or equal to 4.0,
then it is recommended that the owner or operator perform the measurements
specified in Section D.S(e).
(3) Engineering assessment includes, but is not limited to, the
following:
(i) Previous test results proved the test are representative of
current operating practices at the process unit.
(ii) Bench-scale or pilot-scale test data representative of the
process under representative operating conditions.
(iii) Maximum flow rate specified or implied within a permit limit
applicable to the process vent.
(iv) Design analysis based on accepted chemical engineering
principles, measurable process parameters, or physical or chemical laws or
D-7
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EXAMPLE ONLY
D.3 DEFINITIONS
Batch mode means a noncontinuous operation or process in which a
discrete quantity or batch of feed is charged into a process unit and
distilled or reacted at one time.
Boiler means any enclosed combustion device that extracts useful
energy in the form of steam.
By compound means by individual stream components, not carbon
equivalents.
Continuous recorder means a data recording device recording an
instantaneous data value at least once every 15 minutes.
Distillation operation means an operation separating one or more feed
stream(s) into two or more exit stream(s), each exit stream having
component concentrations different from those in the feed stream(s). The
separation is achieved by the redistribution of the components between the
liquid and vapor-phase as they approach equilibrium within the
distillation unit.
Pi still ation unit means a device or vessel in which distillation
operations occur, including all associated internals (such as trays or
packing) and accessories (such as reboiler, condenser, vacuum pump, stream
jet, etc.), plus any associated recovery system.
Flamezone means the portion of the combustion chamber in a boiler
occupied by the flame envelope.
Flow indicator means a device that indicates whether gas flow is
present in a vent stream.
Halogenated vent stream means any vent stream determined to have a
total concentration of halogen atoms (by volume) contained in organic
compounds of 200 parts per million by volume or greater determined by
Method 18 of 40 CFR 60, Appendix A, or other test or data validated by
Method 301 of 40 CFR 63, Appendix A, or by engineering assessment or
process knowledge that no halogenated organic compounds are present. For
example, 150 parts per million by volume of ethylene dichloride would
contain 300 parts per million by volume of total halogen atoms.
Incinerator means any enclosed combustion device that is used for
destroying organic compounds. Auxiliary fuel may be used to heat waste
D-4
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EXAMPLE ONLY
gas to combustion temperatures. Any energy recovery section present is
not physically formed into one section; rather, the energy recovery system
is a separate section following the combustion section and the two are
joined by ducting or connections that carry fuel gas.
Primary fuel means the fuel that provides the principal heat input to
the device. To be considered primary, the fuel must be able to sustain
operation without the addition of other fuels.
Processheater means a device that transfers heat liberated by
burning fuel to fluids contained in tubes, including all fluids except
water that is heated to produce steam.
Processunit means equipment assembled and connected by pipes or
ducts to produce, as intermediates or final products, one or more SOCMI
chemicals (see Appendix A of this document). A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient product storage facilities.
Product means any compound or SOCMI chemical (see Appendix A of this
document) that is produced as that chemical for sale as a product,
by-product, co-product, or intermediate or for use in the production of
other chemicals or compounds.
Reactor processes mean unit operations in which one or more
chemicals, or reactants other than air, are combined or decomposed in such
a way that their molecular structures are altered and one or more new
organic compounds are formed.
Recoverydevice means an individual unit of equipment, such as an
adsorber, carbon adsorber, or condenser, capable of and used for the
purpose of recovering chemicals for use, reuse, or sale.
Recovery jystem means an individual recovery device or series of such
devices applied to the same vent stream.
Total organic compounds or "TOC" means those compounds measured
according to the procedures of Method 18 of 40 CFR 60, Appendix A. For
the purposes of measuring molar composition as required in D.5(c)(4);
hourly emissions rate as required in D.S(e)(4) and D.4(b); and TOC
concentration as required in D.7(a)(4) and D.7(b). The definition of TOC
excludes those compounds that the Administrator designates as having
D-5
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EXAMPLE ONLY
requirements to make the example rule more complete. These requirements
may also be revised by the State agencies.
The remainder of this appendix constitutes the example rule.
Sections are provided on the following rule elements: applicability,
definitions, control requirements, performance testing, monitoring
requirements, and reporting/recordkeeping requirements.
D.2 APPLICABILITY
(a) The provisions of this rule apply to any vent stream originating
from a process unit in which a reactor process or distillation operation
is located. A decision tree is provided (Figure D.I) to facilitate
determination of applicability to this guideline on a per vent basis.
(b) Exemptions from the provisions of this guideline are as follows:
(1) Any reactor process or distillation operation that is designed
and operated in a batch mode is not subject to the provisions of this
rule.
(2) Any reactor process or distillation operation that is part of a
polymer manufacturing operation is not subject to the provisions of this
guideline.
(3) Any reactor process or distillation operation operating in a
process unit with a total design capacity of less than 1 gigagram per year
for all chemicals produced within that unit is not subject to the
provisions of this guideline except for the reporting and recordkeeping
requirements listed in D.7(e).
(4) Any vent stream for a reactor process or distillation operation
with a flow rate less than 0.0085 standard cubic meter per minute or a
total VOC concentration less than 500 parts per million by volume is not
subject to the provisions of this guideline except for the performance
testing requirement listed in D.5(c)(2), D.5(i) and the reporting and
recordkeeping requirements listed in D.7(d).
D-2
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EXAMPLE ONLY
NA
SOCMI
VOC Sources?
(Produces One or More
Chemicals in
Appendix
A)
Is the
Vent Controlled
Via Combustion
Does the
Process Unit Produce
Over 1 Gg/yr
Vent Flow
Over 0.0085 scmm ?
Vent Total
VOC Concentration
Over 500 ppmv?
TREs
• " — 1 N
a 1 i j
Y
i ! ) | •
98% Reduction
20 ppm | Flares J
i i
Monitoring
.
Reporting
Figure D.I.
Synthetic organic chemical manufacturing Industry
reactor/distillation control techniques guideline
logic diagram per vent.
D-3
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APPENDIX E
ENVIRONMENTAL IMPACTS CALCULATIONS
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APPENDIX E
ENVIRONMENTAL IMPACTS CALCULATIONS
E.I CALCULATION OF SECONDARY AIR IMPACTS
Calculations will be based on model stream R-LFHH, the same stream
used as an example in Appendix C.
1.2 ESTIMATING CARBON MONOXIDE EMISSIONS
Calculate total heat input of the stream to be combusted.
(1) HI - Initial heat input of waste stream
HI - (flow rate)(heat value)
= (23.54 scfm)(209.7 Btu/scf)
- 4,936 Btu/min x (60 min/hr) x (8,760 hr/yr) x
(MMBtu/105 Btu)
- 2,595 MMBtu/yr
(2) Hg * Heat input from auxiliary fuel
Hg = (flow rate)(heat value)
= (0.1 scfm)(1,000 Btu/scf)
- 100 Btu/min
=52.5 MMBtu/yr
(3) Total heat input - HI + H£
- (2,595 + 52.5) MMBtu/yr
- 2,648 MMBtu/yr
Calculate carbon monoxide (CO) emissions using AP-42 factor of 20 Ib
CO/MMscf of fuel.
(1) Convert MMBtu/yr to equivalent fuel flow (Qp)
Qp - (2,698 MMBtu/yr)(scf/1,000 Btu)
- 2.6 MMscf/yr
(2) C0em - (2.6 MMscf/yr)(20 lb/MMscf)(Mg/2,207 Ib)
- 0.02 Mg/yr of CO
E-l
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E.3 ESTIMATING NITROGEN OXIDES EMISSIONS
Determine method of control (flare or incinerator). Model stream
R-LFHH is cheapest to control using incinerator with scrubber (see
Appendix C for costing analysis).
For incinerators, two nitrous oxide (NOX) emission factors are used:
one for streams containing nitrogen compounds, and one for streams without
nitrogen compounds. Inert nitrogen gas (N£) is not included. The NOX
factors for incinerators are as follows:
with nitrogen compounds: 200 ppm in exhaust
without nitrogen compounds: 21.5 ppm in exhaust
The model stream R-LFHH has no nitrogen, so 21.S ppm will be used. These
factors reflect testing data that was gathered for the Air Oxidation
Reactor processes CTG and the Polymers and Resins CTG.
Calculate total outlet flow, as explained in Appendix C. As shown in
Section C.4, the total outlet flow exiting the incinerator/scrubber system
is 53 scfm.
(1) NOX emissions - (53 scfm)(21.5/106)/(392 scf/lb-mole) x
(46 Ib/lb-mole)
NOX emissions - (0.000134 Ib/min) x (60 min/hr) x
(8,760 hr/yr) x (Mg/2,207 Ib)
- 0.032 Mg/yr
(2) If the total outlet flow rate from the incinerator is not known,
the following emission factors may be used to calculate NOX emissions:
with nitrogen compounds: 0.41 Ib NQx/MMBtu
without nitrogen compounds: 0.08 Ib NOx/MMBtu
As calculated in E.2 (3), the total heat input is 2,648 MMBtu/yr,
Therefore, the NOX emissions estimated using this factor are calculated
by:
NOX emissions - (2,648 MMBtu/yr)(0.08 Ib NOx/MMBtu) x (Mg/2,207 Ib)
- 0.10 Mg/yr
E-2
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APPENDIX F
RESPONSE TO PUBLIC COMMENTS RECEIVED ON THE DRAFT SYNTHETIC
ORGANIC CHEMICAL MANUFACTURING INDUSTRY REACTOR PROCESSES
AND DISTILLATION OPERATIONS CONTROL TECHNIQUES GUIDELINE
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APPENDIX F
RESPONSE TO PUBLIC COMMENTS RECEIVED ON THE DRAFT SYNTHETIC
ORGANIC CHEMICAL MANUFACTURING INDUSTRY REACTOR PROCESSES
AND DISTILLATION OPERATIONS CONTROL TECHNIQUES GUIDELINE
F.I INTRODUCTION
On December 12, 1991, the U. S. Environmental Protection Agency (EPA)
announced the availability of a draft control techniques guideline (CTG)
document for "The Control of Volatile Organic Compound Emissions from
Reactor Processes and Distillation Operations Processes in the Synthetic
Organic Chemical Manufacturing Industry" (56 FR 64785). Public comments
were requested on the draft CTG in that Federal Register notice. Thirteen
comments were received. Table F.l-1 lists the commenters, their
affiliations, and the EPA docket number assigned to their correspondence.
The major topics of the comments were: the recommendation to incorporate a
total resource effectiveness (TRE) index approach for determining
applicability; the recommendation for less stringent flow cutoffs; and a
concern that the cost of complying with the recommended control level is
too high. The comments that were submitted, along with responses to these
comments, are summarized in this appendix. The summary of comments and
responses serve as the basis for the revisions made to the CTG between the
draft and final document.
F.2 SUMMARY OF CHANGES TO THE DRAFT CONTROL TECHNIQUES GUIDELINE
Several changes and clarifications were made in the CTG as a result
of review of public comments. These changes and clarifications were made
in the following areas; (1) use of the TRE index equations;
(2) aggregation of vent streams to a control device; (3) location of flow
indicators; (4) definition of total organic compounds (TOC's);
(5) description of catalytic incinerators; (6) applicable chemicals;
F-l
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TABLE F.l-1. LIST OF COMMENTERS AND AFFILIATIONS
Docket item
number3 Commenter and affiliation
IV-D-1 Mr. Charles D. Malloch
Director, Regulatory Management
Environment, Safety and Health
Monsanto Company
800 N. Lindbergh Boulevard
St. Louis, Missouri 63167
IV-D-2 Mr. R.L. Arscott, General Manager
Health, Environmental and Loss
Protection
Chevron Corporation
Post Office Box 7924
San Francisco, California 94120-7924
IV-D-3 Mr. David W. Gustafson
Environmental Quality
Mr. Sam P. Jordan
Environmental Law
The Dow Chemical Company
Midland, Michigan 48667
IV-D-4 Mr. John A. Dege
CAA Issue Manager
DuPont Chemicals
Wilmington, Delaware 19898
IV-D-5 V.M. Mclntire
Environmental Affairs
Eastman Chemical Company
Post Office Box 511
Kingsport, Tennessee 37662
IV-D-6 Ms. Sherry L. Edwards, Manager
Government Relations
Synthetic Organic Chemical Manufacturers
Association, Incorporated
1330 Connecticut Avenue, N.W., Suite 300
Washington, D.C. 20036-1702
IV-G-2 M.L. Mullins
Vice President, Regulatory Affairs
Chemical Manufacturers Association
2501 M Street, N.W.
Washington, D.C. 20037
F-2
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TABLE F.l-1. LIST Of COMMENTERS AND AFFILIATIONS
(CONCLUDED)
Docket item
number* Commenter and affiliation
IV-G-3 Mr. E. G. Collier
Chairman, Control Techniques
Guidelines Subcommittee
Texas Chemical Council
IV-G-4 Mr. B.L. Taranto
Environmental Affairs Department
Exxon Chemical Americas
Post Office Box 3272
Houston, Texas 77253-3272
IV-G-S Ms. Regina M. Flahie
Chief
Division of Interagency and International
Affairs
U. S. Department of Labor, Occupational
Safety and Health Administration
Washington, D.C. 20210
IV-G-6 Mr. G. E. Addison
Manager, Planning and Development
ARI Technologies, Incorporated
600 N. First Bank Drive
Palatine, Illinois 60067
IV-G-7 Mr. Raymond J. Connor
Technical Director
Manufacturers of Emission Controls
Association
1707 L Street, N.W., Suite 570
Washington, D.C. 20036-4201
IV-6-8 Mr. Kevin Ewing
Market Manager
Thermotron Industries
291 Kollen Park Drive
Holland, Michigan 49423
aThe docket number for this project is SOCHI CTG A-91-38. Dockets are on
file at the EPA Air Docket 1n Washington, D.C.
F-3
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(7) definition of product; (8) definition of halogenated stream;
(9) exemption of streams with a flow rate or concentration below a cutoff
value; and (10) definition of affected facility.
The comments summarized in this appendix have been organized into the
following categories: Applicability of the Control Techniques Guideline;
Recommendation of Reasonably Available Control Technology; Cost
Effectiveness, Monitoring and Testing, and Editorial.
F.3 APPLICABILITY OF THE CONTROL TECHNIQUES GUIDELINE
F.3.1 Comment; One commenter (IV-G-4) disagreed with the assertion on
pages 6-7 and 6-8 of the draft CTG that the recommended applicability
criteria provide an incentive for pollution prevention. The commenter
stated that since control by combustion (or equivalent control) would be
required for the residual emissions from virtually any recovery device, the
incentive to install such a device would be diminished. The commenter
suggested that an incentive could be provided for control of vent emissions
by combusting the residuals as primary fuel.
Response: The incentive referred to on pages 6-7 and 6-8 of the
draft CTG pertains to an incentive for any pollution prevention or
recycling practice that lowers emissions below the cutoff level. Pollution
prevention and recycling can include any process change—including the
addition of recovery devices—that significantly reduces the amount of
pollutants that are emitted from the process unit. In the case of this
CTG, the recommended presumptive norm for reasonably available control
technology (RACT) would allow an affected facility to avoid having to
install an add-on combustion control device if the affected facility lowers
emissions below the cutoff. The EPA believes that this provision
encourages pollution prevention and recycling.
F.3.2 Comment; One commenter (IV-D-5) requested that the EPA include in
this CTG a statement that distillation operations that are part of polymer
manufacturing processes are not covered by this CTG. The commenter
reasoned that this would be consistent with the applicability criteria for
the new source performance standards (NSPS) for distillation operations
(40 CFR Part 60 Subpart NNN).
Response: It is not the intent of this CTG to provide guidance for
process vents that are subject to regulations for the polymer manufacturing
F-4
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industry. To clarify that these facilities are not subject to this CTG, an
exemption statement has been added to this document (see Section 7.4).
F.3.3 Comment: Two commenters (IV-D-2, IV-G-2) suggested that the CTG
provide a more detailed discussion of the overlap between the source
categories and chemicals covered under this CTG, and the source categories
and hazardous air pollutants (HAP's) covered under Title III of the Clean
Air Act (CAA), as amended in 1990.
One commenter (IV-G-2) further stated that the EPA should strive for
consistency between Title I RACT and Title III maximum achievable control
technology (MACT) with respect to the application of control standards,
testing, monitoring, and reporting requirements.
Response: The EPA understands that more clarification is needed to
explain which chemicals within the SOCMI source category are applicable to
this CTG and which are subject to Title III of the CAA. The SOCMI is a
broad source category that includes any manufacturer of synthetic organic
chemicals. Appendix A of this CTG has been revised to present the organic
chemicals that are subject to this CTG. Appendix A also indicates which
chemicals in this list are listed as part of the SOCMI source category and
which chemicals are subject to the proposed Hazardous Organic National
Emission Standard for Hazardous Air Pollutants (HON), or any of the
following regulations: the air oxidation processes NSPS; distillation
operations NSPS; and the reactor processes NSPS. The regulations' and
rules' applicability criteria is based on the chemical manufactured. For
example, hexanedioic acid is manufactured using a reactor and distillation
unit and is subject to this CTG, the distillation NSPS, and the reactor
process NSPS. However, hexanedioic acid is not manufactured using an air
oxidation process and, therefore, is not subject to the air oxidation
process NSPS.
Although there are appropriate differences with respect to
applicability, the EPA wants to eliminate duplicate performance testing,
reporting and recordkeeping, and monitoring requirements. The EPA is
considering options to deal with the interface between regulations
promulgated under Section HE of the Clean Air Act and RACT rules.
Specifically, the EPA is developing a policy statement for emission points
that will be affected both by the HON and RACT rules. This policy
statement will be published in the Federal Register when completed.
F-5
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Pursuant to the CTG, recordkeeping and reporting requirements have been
left to the discretion of the State air quality management agencies as
stated in Section 7.7 (Reporting/Recordkeeping Requirements) of the CTG
document; however, emission points subject to the HON would be subject to
the recordkeeping and reporting requirements of the HON.
The controls required to comply with the SOCHI NSPS, CTG's and the
HON are the same and are based on the same control technology--that is,
combustion. The cutoff levels for applicability may be different, however,
because VOC's are the subject of the CTG's and the NSPS, and organic HAP's
are the subject of the proposed HON.
F.3.4 Comment: Several commenters (IV-D-3, IV-D-4, IV-D-5, IV-D-6,
IV-G-2, IV-G-3) recommended the incorporation of a TRE index as another
option to the already suggested presumptive norm for RACT. Two commenters
(IV-D-3, IV-G-2) suggested that using a TRE index would help to achieve a
more cost-effective VOC control by using the least amount of energy,
capital, and total resources. The commenters also suggested that
incorporation of a TRE index furthers the application of pollution
prevention principles by encouraging increased product recovery techniques
and other process modifications that ultimately reduce VOC emissions, often
by using more cost-effective techniques.
Response: To remain consistent with the other SOCHI regulations, the
EPA has decided to incorporate the TRE index applicability approach to
replace the flow and concentration limits that appeared in the draft CTG.
This decision was reached after the draft CTG document was made available
for public comment. The final copy of the CTG includes the TRE index.
The TRE index equation is a decision tool used to determine if the
annual cost of controlling a given vent stream (as determined using the
standard procedure described in Chapter 5) is acceptable when considering
the emission reductions achieved. The TRE index is a measure of the total
resource burden associated with emission control for a given vent stream.
The TRE index equation is normalized so that the decision point has a
defined value of 1.0. The variables in the TRE index equation are the
stream characteristics (i.e., flow rate, heat content, VOC emission rate).
This TRE index equation is developed from a multivariable linear regression
of the cost algorithm. It is recommended that the owner or operator
demonstrate that a TRE index is greater than 1.0 at the outlet of the final
F-6
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recovery device in order to avoid having to control VOC emissions. If the
TRE index is less than or equal to 1.0 at the point of measurement, the
owner or operator could elect either to modify the process or, install an
additional recovery device or a control device that results in a TRE index
greater than 1.0.
The cost-effectiveness criteria built into the TRE index equation
allow for greater emission reductions at the same cost compared to the flow
and concentration limits alone. With the TRE equation, the CTG allows the
flexibility to reduce VOC emission by whatever means the owner or operator
prefers. Pollution prevention that increases product or raw material
recovery may be the most cost-effective (and even the most beneficial)
method to reduce VOC emissions and is encouraged.
F.3.5 Comment: Several commenters (IV-D-3, 1V-D-5, 1V-G-2, IV-G-3,
IV-6-4) questioned the feasibility and stringency of the CTG combined vent
criteria. Several commenters (IV-D-3, IV-D-5, IV-G-2, IV-G-3) argued that
the concentration and flow cutoff should apply only to individual vent
streams and not the combination of all vent streams in the process unit.
Two commenters (IV-D-3, IV-G-2) also pointed out that the combined vent
criteria appear to be more stringent than those in the NSPS because the CTS
flow cutoff applies to multiple vents, regardless of whether a common
recovery system into which the vents are discharged exists.
Several commenters (IV-D-3, IV-G-2, IV-G-3, IV-G-4) suggested that
situations exist where it is not technically feasible, economical, or safe
to combine vent streams. One commenter (IV-G-3) noted the following two
examples that illustrate the safety concerns:
• Combining two streams where one stream is below the lower
explosive limit and another stream is above the explosive
limit, or
• Combining two streams that are chemically reactive.
Response: The combined stream criteria were included in this CTG
because the practice of combining streams is often used in industry for
similar process vent streams within the same process unit. The EPA
recognizes that circumstances exist where it may not be technically
feasible, economical, or safe to combine vent streams and, therefore, it
should not be a control criterion. Because this approach cannot be
generalized across the entire industry, the combined vent applicability
F-7
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approach has been omitted from the CTG document. Furthermore, 1t should be
noted that the applicability limits were written for Individual streams and
were not intended to determine applicability limitations on a combined
stream basis. The applicability calculations continue to be conducted on
an individual vent stream basis after the CTG was revised to incorporate
the TRE.
F.3.6 Comment: One commenter (IV-D-1) noted that on page 2-7 of the draft
CTG, the EPA refers to "176 high-volume chemicals" that "involve reactor
processes." The commenter further noted that on page 2-33, the EPA refers
to the scope of the reactor processes covered in the CTG as representing
"one of the 173 reactor process chemicals." The commenter recommended that
the EPA revise Appendix A of the CTG to indicate 173 chemicals (thus
representing the similar list used in the NSPS), which the CTG intended to
cover under reactor processes.
In addition, the commenter noted that the final NSPS for distillation
operations lists the chemicals for Its applicability. The commenter
recommended that Appendix A of the draft CTG be shortened to include only
those chemicals used for determining applicability of distillation
operations. The commenter then suggested that the applicability statement
in Section D.2.a on page D-l of Appendix D in the draft CTG should be
expanded to state that the process unit subject to this CTG should be one
for which a chemical is listed in Appendix A.
Response: The reference on page 2-7 of the document is an industry
characterization. There is no statement to suggest that the
176 high-volume chemicals listed there are the only chemicals within the
scope of this CTG. These 176 chemicals are a subset of SOCHI chemicals
that are produced in large quantities. Appendix A lists the 719 chemicals
subject to this CTG. This list also identifies those chemicals that are
also subject to the Distillation NSPS, Air Oxidation NSPS, the Reactor
Process NSPS, the HON and other chemicals under the SOCMI source category.
It is the intent of the EPA to make subject of this CTG, any distillation
column or reactor operating as part of a process unit that makes one of the
chemicals listed in Appendix A. The applicability statement in Appendix D
has been expanded to state that the applicability of this CTG is based on
the chemicals that are listed In Appendix A.
F-8
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F.3.7 Comment: One commenter (IV-D-1) recommended that Table 2-5 on
page 2-47 of the draft CTG be revised to address more clearly the minimal
emissions occurring from atmospheric distillation operations. The
commenter said that, as drafted, the table does not identify what type of
operation corresponds to either the high or low emission rates. The
commenter cited personal experience that atmospheric distillation columns
used with low vapor pressure chemicals, such as adiponitrile or
hexamethylene diamine, do not have any detectable emissions from the
atmospheric vent.
The commenter also argued that condensers between the steam jets and
sometimes on the final jet discharge are very effective in controlling
emissions from distillation columns that process low-volatility chemicals,
with control efficiencies exceeding 95 percent in situations as described
above.
Response: Table 2-5 of the CTG document lists the average operating
characteristics of the distillation emission profile, in addition to the
range for these characteristics. The EPA realizes that the types of
operations that correspond to the values listed are not identified and that
processes may exist that are below those values.
With respect to the alternative VOC emissions reduction approach
described by the comraenter, the EPA would like to clarify that the RACT
presumptive norm would not preclude the use of a condenser to reduce VOC
emissions from affected vent streams. If use of such a condenser were to
result in a TRE index value for the vent stream that is above the limit,
then no additional control would be required.
F.4 RECOMMENDATION OF REASONABLE AVAILABLE CONTROL TECHNOLOGY
F-4.1 Comment: Several commenters (IV-D-2, IV-D-4, IV-D-6, IV-G-2,
IV-G-4) expressed concern that the recommended control applicability cutoff
is too stringent. Six commenters (IV-D-4, IV-D-I, IV-D-6, IV-6-2, IV-G-3,
IV-G-4) pointed out that the proposed RACT de minimus flow rate is up to
four times more stringent than the distillation operations NSPS
requirements.
One commenter (IV-G-4) said that CTG cutoffs of 0.1 standard cubic
feet per minute (scfm) and 0.05 weight-percent VOC would result in a
calculated TRE of approximately 6,000 using the TRE equation from the
proposed HON. The commenter also noted that the proposed cutoffs
F-9
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correspond to a VOC emission rate of less than 5 pounds per year (Ib/yr),
and compared this emission rate to that of a single "nonleaking" valve in
light liquid service, which has an emission rate of 6 Ib/yr as calculated
using the EPA emission factors.
Two commenters (IV-D-6, IV-G-2) suggested that the CTG adopt Option 3
(e.g., flow rate <0.5 scfm and VOC weight percent <1) in Table 6-1 as the
RACT cutoff. One commenter (IV-D-6) emphasized that this option reduces
nationwide emissions by over 73 percent, and reduces the nationwide cost of
control by nearly 60 percent; yet still obtains almost 77 percent of the
emissions reduction achieved by the RACT cutoff proposed by the EPA.
Response; The EPA has reevaluated the applicability cutoff, as
mentioned in the response to comment number F.3.6, and the TRE index
equation will replace the flow or concentration limits that appeared in the
draft CTG. As pointed out by the commenters, use of the TRE equation will
provide consistency with the distillation NSPS and HON requirements.
F.4.2 Comment: One commenter (IV-D-3) noted that it is not obvious
whether the RACT cutoffs recommended by the CTG refer to instantaneous or
average values. The commenter suggested that the EPA specifically state
that the cut-off criteria for the concentration and flow are to be based on
an annual weighted average.
Response: The inputs to the TRE index equation are stream flow rate,
VOC emission rate, and heat content. These parameters should be average
values over the period of the performance test. The performance test
should be conducted under typical operating conditions, the specifics of
which are defined in the example rule (Appendix D).
F.4.3 Comment; One commenter (IV-D-6) stated that by definition in the
CAA, RACT requirements are less stringent than MACT requirements.
Therefore, the proposed RACT for SOCHI should be less stringent than MACT
for the same source categories.
Response; There is some confusion between MACT and RACT and the
level of stringency for each requirement. One cannot compare the
stringency levels of the two requirements because they are applicable to
two different groups of pollutants; MACT is applied to HAP's listed in
Section 112(b) of the CAA as amended in 1990, whereas RACT is applicable to
various of the criteria pollutants, including VOC, a precursor to ozone.
In some cases, the same vent stream may be subject to RACT criteria but not
F-10
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MACT criteria. Regardless of the applicability criteria, the control
requirement in all SOCMI regulations is 98 percent reduction of pollutants
or pollutant reduction down to a concentration level of 20 parts per
million by volume (ppmv) on a dry basis, corrected to 3 percent oxygen,
F.4.4 Comment: One commenter {IV-G-2) stated that the presumptive norm
described in the CT6 document for SOCMI does not accurately describe the
types of emissions found to be emitted from reactor processes and
distillation operations. Although the VOC concentration cutoff and flow
rate cutoff help to ensure that insignificant vent streams do not require
unnecessary cost controls, the cutoffs do not account for the variation
that occurs from stream to stream due to chemical properties and associated
heating values. The commenter argued that a low heating value stream would
result in a much higher control cost than a high heating value stream, and
may not be appropriate as a presumptive norm for RACT.
Reisfionse: The EPA understands that in some cases low heating value
streams could result in higher costs than high heating value streams to
control, and has, therefore, incorporated the TRE index equation to the
applicability section. The TRE index identifies only those streams that
can be controlled in a cost-effective manner.
F.4.5 Comment: One commenter {IV-G-2) observed that the de minimus levels
suggested in the CTG document are incompatible with the levels found in the
NSPS. The commenter said that the establishment of such a low level will
prove to be of little use to the regulated community and, furthermore, by
setting a level that is inconsistent with current NSPS regulations, the EPA
places facilities in the awkward position of trying to comply with two
conflicting levels of control.
Response: This comment is resolved by the incorporation of TRE. As
indicated in the previous response, the parameters incorporated into the
TRE equation will allow for control of only those streams that can be
controlled on a cost-effective basis.
F.5 COST EFFECTIVENESS AND COST ESTIMATION
F.S.I Comment: One commenter (IV-G-3) suggested that because a scrubber
is needed to remove hydrogen chloride (HC1) from the incinerator flue gas,
the discharge from this scrubber may significantly contaminate wastewater,
which would require treatment prior to discharge. Another commenter
(IV-D-5) questioned the EPA's judgment that costs associated with the
F-ll
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disposal of salty wastewater formed by the neutralization of acidic
scrubber effluent were not significant. The cornmenter suggested that the
opportunity to use on-site wells is significantly limited, not only by
geographic considerations, but also regulatory concerns. Direct and
indirect discharges could also be limited by aquatic toxicity limits of the
National Pollutant Discharge Elimination Standards (NPDES) permit program.
Response: It is the decision of the EPA not to include the costs
associated with the disposal of salty wastewater in the cost equation for
VOC control devices. This decision was based on earlier work done on the
SOCHI reactor process NSPS. The effects from the discharge of wastewater
from the scrubbers were presented in 1984 in the background information
document {BID} for the Reactor Process NSPS. The water pollution impacts
were studied in 1982, at which time it was determined that the costs
associated with the disposal of the salty wastewater are not significant in
comparison to the overall control costs and, therefore, were not included
in the projected cost impacts. The specific reference in the Reactor
Process NSPS docket that explains the methodology is EPA Docket
No. A-83-29, Item No. II-B-25.
F.5.2 Comment: Several commenters (IV-D-4, IV-D-6 IV-6-2, IV-G-3)
emphasized that the EPA underestimated the installed equipment costs,
resulting in lower average cost-effectiveness numbers than industry is
currently experiencing. Three commenters (IV-D-4, IV-G-2, IV-G-3) noted
that the EPA indicated an installation factor of 1.61, which is much lower
than installation factors of 3 to 10 commonly encountered in the chemical
industry.
Response: The installed equipment costs and the installation factor
of 1.61 were determined using the EPA's Office of Air Quality Planning and
Standards Control Cost Manual (OCCM). Each chapter of the OCCM underwent
extensive industry review prior to finalization making this document the
accepted source by the EPA. The EPA believes that this installation factor
is consistent with what the majority of facilities from different
industries that install Incinerators would encounter.
F.5.3 Comment: Two commenters (IV-G-4, IV-D-6) suggested that the
cost-effectiveness analysis is flawed and does not support the
applicability criteria. One commenter (IV-G-4) noted that in Table 6-1 of
the CTG, the average emission reduction per vent in the increment going
F-12
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from Option 3 to Option 2 is 0.0035 megagrams per year (Hg/yr). However,
vents of less than 0.003 Mg/yr would have to be controlled by the 0.1 scfm
and 0.05 weight percent applicability criteria given in the draft CTG.
Thus, the incremental cost effectiveness is calculated on a basis that
misrepresents the recommended applicability criteria by more than four
orders of magnitude. The commenter further noted that the cost
effectiveness of controlling a 0.1 scfm and 0.05 weight percent vent stream
is not addressed, and it should be in order to support its selection.
The commenter also felt that the cost data used to analyze regulatory
options is very low and unrealistic and should be updated or corrected to
reflect actual costs based on real plant experience. The commenter noted a
cost of $5,274 was assumed for 400 feet of an 8-inch flare collection
header, and suggested that the actual cost for this piping would exceed
$34,000, even in a noncongested area where pipe supports already exist.
The commenter also expressed concern that the flare cost estimate does not
appear to include the cost of piping and pumps to manage liquid from the
knockout drum, or the cost of piping and controls for the water supply to
the water seal drum, or for the air, steam, or gas to the flare tip.
Two commenters (IV-D-4, IV-D-6) stated that under the recommended
minimum emission levels, an emission flow rate of 0.11 scfra, with VOC
concentration of 0.06 weight-percent (which corresponds to 2.6 lb/yr},
would require incineration and control. The cost effectiveness for the low
flow low heat case in Table 5-6 is $23,954 per megagram (Mg) for a
1.3 Ib/hr VOC inlet flow. The de minimus flow rate mentioned above emits
400 times less. The commenter then said that by simple multiplication, the
cost effectiveness balloons to $96,000,000 per megagram.
Response: The incremental cost effectiveness was calculated
correctly in the draft CTG document. The data base used for this analysis
contains many streams with high flow rates, but low concentrations.
Therefore, some streams with relatively high VOC loadings are not included
in the analysis until the most stringent options are imposed. Again,
further discussion of this table and calculated cost effectiveness is no
longer appropriate because the applicability format has been changed to
incorporate a TRE index equation. The TRE equation takes into account
these high cost considerations.
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As stated In response F.5.2, ill costing analyses are In accordance
with the OCCM. The duct work cost assumptions are believed to represent
industry averages. The flare costs do include water seals and steam piping
to flare tip. Piping costs are accounted for by an installation factor.
F.5.4 Comment: Three commenters (IV-D-S, IV-G-2, IV-G-7) questioned
whether the EPA accounted for full "costing" of controls. One commenter
(IV-D-5) expressed concern that the EPA neither acknowledged nor adequately
considered the upstream impact of the control equipment in their emissions
analysis. The commenter suggested that there is a direct usage of fuel to
run control devices, as well as indirect emission impacts of:
(1) producing the fuels consumed as energy to produce the controls;
(2) producing the raw materials, such as caustic, to operate the control
devices; and (3) transporting these materials. The commenter asserted that
the EPA should consider these upstream impacts by including a factor, such
as an economic or cash flow multiplier, that would account for these
indirect impacts in the decision process as to what levels of controls are
actually environmentally beneficial.
Another consideration regarding full costing of controls was made by
two commenters (IV-G-2, IV-G-7) who requested that the EPA give greater
consideration to secondary air impacts due to the application of the
suggested control technologies. One commenter (IV-G-2) noted that by the
EPA's own admission, the recommended 98 percent control requirements
generate additional oxides of nitrogen (NOX), sulfur dioxide (SOg), carbon
monoxide (CO) and particulate matter (PM). The commenter suggested that by
reducing the required level of control efficiency, secondary air impacts
will be reduced. One commenter (IV-G-7) argued that a significant issue
with thermal incineration is the production of NOX and CO as secondary
pollutants when large amounts of fuel are combusted to sustain the high
temperatures needed to operate these units. The commenter further cited
several disadvantages of thermal incineration including:
• High operating temperatures usually mean additional fuel
requirements and associated higher fuel costs;
• High generating temperatures require thi use of special, more
costly heat resistant materials;
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• Longer residence times (greater than 1.5 seconds) than those
cited in the draft CTG mean larger, heavier reactors, which
generally must be installed at ground level rather than roof
mounted, resulting in additional expenses.
The commenter recommended that these should be viewed as
disadvantages for this control technology, and that Sections 3.1.2.1 and
3.1.2.2 of the CTG be expanded to include those disadvantages.
Response: With respect to "upstream" effects, it is beyond the scope
of this CTG to include in the costing equation those indirect emission
impacts listed by the commenter. However, the EPA generally includes
secondary air impacts due to the application of the suggested control
technologies in the analysis of RACT. These secondary air impacts are
explained in the environmental impacts discussion in Section 4.1.2 of the
draft CTG document rather than in the process description discussion.
Local agencies should consider the NOX and CO emissions associated with
control devices and may allow lower levels of VOC control to mitigate
secondary impacts if appropriate.
The disadvantages concerning thermal incineration cited in the
comment are realized by the EPA; however, recommendations for control
technologies assume average stream characteristics therefore, while thermal
incineration may not be appropriate for some lines, it would be a cost
effective means of control for others. The EPA need not consider the
"worst case" in developing the CTG.
F.5.5 Comment: One commenter (IV-G-4) recommended that the costs of
performance tests, monitoring, recordkeeping, and reporting also be
included in the CTG cost analysis.
One commenter (IV-G-3) argued that as the level of control and
monitoring continues to increase and as the regulatory guidelines for
"Enhanced Monitoring" evolve, the costs associated with the required
monitoring of new incineration devices are continuing to increase. The
commenter recommended that the present instrumentation cost factor of 0.10A
(e.g., instrument cost * 0.10 * [incinerator + auxiliary costs]) should be
reevaluated in light of the increasing costs associated with regulatory
monitoring requirements.
Response: The EPA's OCCM was used to determine the cost of
combustion technologies for control of VOC emissions. The capital costs
are presented in Table 5.2. As indicated in Table 5.2, performance test
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costs are included in the indirect cost of the control. Also in Table 5.2,
listed under the purchased equipment cost, is the instrumentation cost
required for the control device. This instrumentation would be used for
monitoring the control device. For example, temperature instrumentation
can be used to monitor the control efficiency of the control device.
The "Enhanced Monitoring" rule requirements are under development,
and that package will address the potential cost of the requirements of
that regulation, including additional costs placed on sources that are
already subject to some type of monitoring. The recordkeeping and
reporting requirements will vary among the States and, therefore, are not
included here.
F.5.6 Comment: One commenter (IV-G-4) thought that the annual operating
cost for an incinerator seems to be reasonably accurate but on the low
side.
Response: The EPA intends to Investigate any documented numbers the
public may have, and invites this commenter to submit any documented
numbers to the EPA. Again, the annual operating costs were calculated from
the EPA's OCCM (see the response to comment F.5.2).
F.6 MONITORING AND TESTING
»
F.6.1 Comment: Two commenters (IV-D-4, IV-D-6) stated that the
requirements for scrubbing liquid temperature and specific gravity may not
be pertinent compliance information for some scrubbers, such as a
once-through water scrubber. They added that instrumentation should be
required only if it provides information essential to emission compliance.
Response: The CTG document has been revised to address the issue of
absorbers used as recovery devices versus absorbers used as scrubbers to
scrub halogens from a vent stream following an incinerator. The EPA
assumes that if an absorber is used in a recovery system, then the absorber
recycles (or has the potential to recycle) a portion of its effluent and is
not a once-though scrubber. Furthermore, the EPA assumes that the latter
use of absorbers, that is, to scrub halogens from an incinerator's
effluent, is the absorber the commenter refers to as a once-through
scrubber. As such, there are two sets of monitoring and testing
requirements in the model rule (Appendix D of the CTG) for the two absorber
types just described. For absorbers used in recovery systems, a scrubbing
liquid temperature monitor and a specific gravity monitor are required,
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both with continuous recordkeeping. For absorbers used after an
incinerator (a once-through scrubber), a pH monitoring device and flow
meter to measure scrubber liquid influent and inlet gas flow rates are
required, both with continuous recordkeeping.
F.6.2 Comment: One commenter (IV-D-6) suggested that as an alternative to
monitoring low flow rate vents, engineering calculations, and/or mass
balances information should be allowed to demonstrate an exemption from
control requirements.
Response: In order to be consistent with the draft HON, the EPA has
revised the section of the model rule [Section D.5(h)] addressing this
issue. Engineering assessment is recommended in the model rule as an
option to calculate process vent stream flow parameters for those streams
with a TRE index of 4.0 or greater.
F.6,3 Comment
Two commenters (IV-D-4, IV-D-6) said that Section D-5 of the CT6
document, "Performance Testing," should not be more restrictive than what
was proposed in the Enhanced Monitoring Guidelines for existing sources.
One commenter (IV-D-6) also suggested that an applicability paragraph be
added that excludes small sources.
Response: The draft Enhanced Monitoring Guidelines for existing
sources has not been proposed, making it difficult to comment on stringency
comparison between its requirements and those within this CTG. With
respect to the applicability paragraph, it was difficult to interpret if
commenter IV-D-6 was requesting an applicability cutoff for performance
testing or general facility applicability. However, it should be noted
that facilities with a very low capacity (less than 1 gigagram of chemicals
per year) were exempt from recommended RACT requirements. Additionally,
the CTG has been revised to recommend exempting certain individual streams
with low flow rates from TRE testing.
F.6.4 Comment: Two commenters (IV-D-3, IV-G-4) argued that requiring flow
indicators on individual streams prior to a control device is an excessive
cost that is not necessary in determining when a flow is diverted.
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One commenter (IV-D-3) recommended that the current reference to flow
Indicators in D.6(a)(2), (b)(2), and (c)(l) be eliminated and replaced with
language similar to the following:
(i) Install a flow indicator at the entrance to any bypass line that
could divert the vent stream away from the control device to the
atmosphere; or
(ii) Secure the bypass line valve in the closed position with
car-seal, locked, or otherwise secured arrangement. A visual inspection of
the secured arrangement shall be performed once a month to ensure that the
valve is maintained in the closed position and that the vent stream is not
diverted through the bypass line.
Response: The EPA considers it very important to ensure that vent
streams are continuously vented to the flare (or other combustion device).
The primary intent of the flow monitoring recommendation in this CTG was to
provide a means for indicating when vent streams are bypassing the flare or
other combustion device. The flow indicators envisioned by the EPA were
intended to provide an indication of flow or no flow, and not to provide
quantitative estimates of flow rates.
The EPA has reevaluated the use of flow indicators in process vent
streams in light of the comments received for the SOCMI Reactor Process
NSPS as proposed. Because flow indicators located on the vent stream
between the emission source and the combustion device may be insufficient
to meet the intent of the CTG, the EPA has decided to alter the flow
indicator location. The CTG will be revised to indicate that the new flow
indicator location will be at the entrance to any bypass line that could
divert the vent stream before it reaches the combustion device. This
location would indicate those periods of times when uncontrolled emissions
are being diverted to the atmosphere. In those instances when the vent
stream is rerouted to another combustion device, a performance test would
need to be conducted on the second combustion to determine if it meets the
control requirements.
In some situations, there may be no bypass lines that could divert
the vent stream to the atmosphere. In these cases, there will be no flow
indicator recommendation. Language similar to the commenter's suggested
paragraph (ii) have been added to the CTG document. In addition, records
that show an emission stream is hardpiped to a combustion source are
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sufficient to demonstrate that the entire flow will be vented to the
combustion device. Other piping arrangements can be used, but flow
indicators located in any bypass line that could divert a portion of the
flow to the atmosphere, either directly or indirectly, become necessary.
If the piping arrangement for the process changes, then it is recommended
that the facility revise and retain the information.
The CTG was revised to suggest a flow indicator be equipped to
indicate and record whether or not flow exists at least once every
15 minutes. Because the monitor collects flow or no flow data on a
continuous basis, this additional recording would not be an additional
burden. If an owner or operator believes that an alternate recording
frequency or placement of a flow indicator is equally appropriate, then the
owner or operator can petition the State regulating agency.
F.6.5 Comment: One commenter (IV-D-1) said that the requirement that
temperature monitors be equipped "with strip charts" is too narrowly drawn.
The commenter pointed out that many instrument systems in the modern
chemical plant are computer driven and the recordkeeping is not via the
"old" strip chart method. The commenter suggested that the EPA require
continuous temperature monitoring, without a reference to the recordkeeping
mode selected by the source.
Response: The temperature monitoring recording requirements have
been revised, omitting any specific reference to a strip chart.
F.6.6 Comment: One commenter (IV-D-1) noted that on page D-9 of the draft
CTG, subparagraphs (a)(2), (b)(2) and (c)(l), require the installation of a
"flow indicator" on the vent stream to the control device. The commenter
emphasized that difficulties were encountered when attempting to comply
with similar requirements promulgated in the NSPS for air oxidation unit
processes and distillation operations. Specifically, the vent streams from
the affected distillation systems were hardpiped to a common flare header
with no means to automatically divert the vent stream to the atmosphere.
Each system had a nitrogen purge on its vent stream to the flare header to
control plugging caused by the polymerization of organics. The continuous
nitrogen purge precludes accurate measurement of vent stream flow to the
flare. The commenter suggested the problem may be widespread, noting that
a number of organic compounds will polymerize under the right set of
conditions. In addition to causing line pluggage, the commenter added that
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polymerization can also plug flow measuring devices, negating any
opportunity to select appropriate instrumentation. The commenter then
recommended adding a provision to this CTG that allows an appropriate
compliance alternative method for flow indication, with a reference to the
means by which a source could seek approval.
Response: The paragraphs cited in the comment contain a discussion
about the need to monitor the flow of streams before they are joined with
similar streams to a common control device. As a result of public comments
from this CTG and the distillation operations NSPS, these paragraphs have
been deleted from the final CTG document for two reasons: (1) the EPA is
no longer requiring that similar vent streams be combined due to technical
and safety concerns that may exist at some facilities (see response to
Comment F.3.1), and (2) the EPA has revised the purpose of flow indicators
so that they now continuously monitor the presence, not the extent, of vent
stream flow. Please refer to the response to comment number F.6.4 to
determine how the flow indicator section is being revised in the CTG. The
owner or operator can petition the State agency if it is felt that an
alternate method for flow indication should be conducted.
F.6.7 Comment: One commenter (IV-D-1) cited a significant recordkeeping
burden in complying with requirements promulgated in the NSPS for air
oxidation processes and the NSPS for distillation operations, and that the
CTG contains the same recordkeeping requirements. The commenter then
recommended that the source be allowed to select an annual performance test
as an alternative means of compliance.
Response: Conducting an annual performance test in lieu of the
required reporting requirements is not an appropriate alternative to
monitoring a process parameter. An annual performance test would not
indicate compliance through the year. The reporting and recordkeeping
requirements provide a means of documenting monitoring compliance on a
continuous basis and allow the source to demonstrate its continuous ability
to meet the standard.
F.6.8 Comment: One commenter (IV-D-3) noted that the reporting
requirements for the control and recovery devices in Section D.7(b) of the
CTG document require exceedance reports when temperatures or flows deviate
by more than a set level. The commenter further noted that current
interpretations of reporting requirements have identified situations where
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"deviations" require reporting, even when the regulated vent stream has
been shut down for maintenance and a vent is not actually flowing to the
control or recovery device. The commenter requested that language be added
to ensure that this reporting is required only during those periods when a
vent stream is actually flowing to the control or recovery device.
Response: The exceedance reporting requirement section of the CTG is
being revised. The final document will incorporate the language for these
requirements from the draft Enhanced Monitoring Guideline.
F.7 CONTROL TECHNOLOGY
F-7.1 Comment: Several commenters (IV-D-5, IV-D-6, IV-6-6, IV-G-7,
IV-G-8) argued that RACT should not be limited to combustion control
devices. One commenter (IV-G-8) suggested that rather than choosing
combustion devices or the most widely applicable control technique and
critically analyzing the limitations of alternative methods, the CTG should
point out applications or guidelines that indicate when use of each
technique is appropriate. The commenter was also disappointed that the EPA
had chosen to emphasize control devices that destroy rather than recover
solvents, noting that this decision seemed to be a counterproductive
solution to pollution prevention.
Three commenters (IV-D-5, IV-G-6, IV-G-7) recommended that catalytic
oxidation be recognized as an acceptable control alternative. By excluding
catalytic oxidation in the CTG, one commenter (IV-D-5) expressed concern
that the EPA is unnecessarily limiting its use since the lengthy approval
process required for alternative controls effectively precludes their use
within the defined compliance time limit.
Two commenters (IV-G-6, IV-G-7) provided data to support the
conclusions that modern catalytic oxidation systems perform well in almost
all circumstances, require minimum maintenance, minimize the formation of
secondary air pollutants, and commonly achieve values as high as
99.0 percent destruction for years without interruption. The commenters
requested that the CTG reflect this information when it is issued in its
final form.
One commenter (IV-G-7) cited personal experience that has shown that
catalytic oxidizers operate very successfully on SOCHI exhaust streams and
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recommended that the EPA delete the present statement in Section 3.1.4.3
and replace it with the following new language:
Catalytic oxidation is very effective in controlling VOC
emissions; it is an extremely flexible technology that can be
applied to a variety of SOCMI processes. It is basically a
chemical process which operates at much lower temperature than
thermal incineration and thereby minimizes fuel and other costs.
In addition, catalytic oxidation does not produce secondary air
emissions such as NOv and CO as occurs with thermal
incineration. High destruction efficiency (>98 percent) is
achieved through catalytic oxidation. Catalytic streams are
successfully operating on SOCMI vent streams. The SOCMI
exhausts are generally very clean and are therefore suitable for
catalytic systems. The SOCMI industry has been accustomed to
using a variety of process catalysts and are very skilled in
understanding and maintaining catalytic systems at maximum
performance. Sulfur resistant and halocarbon resistant
catalysts are available when needed.
One commenter (IV-D-6) stated that recovery devices and other
upstream process changes should be allowed to demonstrate RACT control.
Furthermore, to enable the use of these alternative pollution prevention
techniques, a suitable before control emission point must be defined. The
commenter recommended the following definition for before control
emissions:
Emissions after the first reflux/product recovery condenser, or
actual hourly average emission rate, after all control for the
years 1987 to present, whichever is greater.
Response: It is not the intent of this CTG to limit the owner or
operator to only one VOC control technology, many technologies are
presented in the CTG. For the purpose of calculating national impacts,
however, combustion via thermal incineration or flaring was chosen as the
control technology. This decision was based on the wide applicability and
ability of combustion devices to achieve 98 percent destruction efficiency
for SOCMI reactor and distillation vents. Additionally, even though
pollution prevention in the form of product or solvent recovery may be more
economical, these control techniques require modifications within the
process and are site specific, making it difficult to generalize these
modifications across the entire industry. Appropriate applications for
each control technology are given in Chapter 3.0 of the CTG. Catalytic
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incinerators are, in fact, recognized as acceptable alternative controls as
discussed in the CTG document.
The EPA appreciates the comment regarding Section 3.1,4.3 of the
document and has revised that section to incorporate some of the language
suggested.
F.7.2 Comment• One commenter (IV-D-3) said that the monitoring
requirements for carbon adsorbers should be modified to accommodate the
various types of regeneration systems currently in use. The commenter
recommended the following:
• All references to the use of "steam" for carbon adsorbers be
replaced with the term "regeneration stream." Changing to
this recommended language allows the owner or operator to use
either steam, a regeneration gas, heated nitrogen, or similar
technologies in the absorber system without requiring specific
waivers in a case-by-case basis.
• The recordkeeping and reporting requirements associated with
carbon absorber units refer only to "mass" flow measurements.
Rather than specifically referring to mass, we recommend that
either a mass or volumetric flow rate is appropriate.
Response: The EPA realizes that steam is not the sole method of
carbon adsorber regeneration. The CTG document has been revised to reflect
the commenters recommendations to modify the monitoring requirements for
carbon adsorbers.
F.7,3 Comment; One commenter (IV-G-5) expressed concern that two proposed
controlled techniques may pose worker safety or health hazards.
Specifically, the commenter named the combustion of VOC's in flares with
high velocity steam injection nozzles, and combustion of VOC's in boilers
or process heaters as potentially hazardous. The commenter noted that the
safety concern of high velocity steam injection nozzles is the increased
noise. Also, the variation in the flow rate and organic content of the
vent stream could lead to explosive mixtures with a boiler furnace.
Response: The proposed control techniques discussed in the CTG
document must be installed in compliance with Occupational Safety and
Health Administration (OSHA) requirements. Specifically, the flares must
be installed at such a height and location to minimize noise.
The venting of streams to boiler furnaces is listed as an alternative
control technology because it is not appropriate for all vent streams for
the exact reasons the commenter listed. As stated in the CTG, "variations
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in vent stream flow rate and/or heating value could affect the heat output
or flame stability...and should be considered when using these combustion
devices."
F.7.4 Comment: One commenter (IV-6-8) recommended that the discussion in
the CTG regarding condensation as an emission control technique needs
clarification.
Regarding Section 3.2.3.1, the commenter noted that
chlorofluorocarbons, hydrochlorofluorocarbons, and hydrof1uorocarbons can
be used in single stage or cascade cycles to reach condensation
temperatures below -73 °C (-100 °F), and liquid chillers using d-limonene
are capable of reaching temperatures below -62 °C (-80 °F).
With reference to Section 3.2.3.2, the commenter stated that
condenser efficiencies are frequently in excess of 95 percent, with
recovery by condensation working particularly well for low flow rates (less
than 2,000 cubic feet per minute [cfm]} and high VOC concentration (greater
than 5,000 ppmv). The commenter said that it is below the 5,000 ppmv
concentration level that the recovery efficiency of condensation drops
below 95 percent, and, furthermore, since condensation is not recommended
for use in applications involving concentration levels below 5,000 ppmv, it
does not make sense for the CTG to state that "efficiencies of condensers
usually vary from 50 to 95 percent."
Regarding Section 3.2.3.3, the commenter requested that the CTG
document state that condensation is applicable in many cases where other
control methods are not, including when lower explosion limits are too
high, when flow rates are too low; and when recovery rather than
destruction is required.
Response: The ranges listed in the CTG document (e.g., "below
-34 °C") include the specific examples cited by the commenter.
In Section 3.2.3.2 of the draft CTG, it is stated that the condenser
efficiency ranges depend on the flow parameters of the vent stream and the
operating parameters of the condenser. A statement has been added to the
CTG explaining that the higher efficiencies are expected for the low flow
(less than 2,000 cubic feet per minute [cfm]}, high VOC concentration
(greater than 5,000 ppmv} streams. Finally, the CTG document has been
revised to state those cases where condensation is applicable and other
control methods are not.
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F.8 EDITORIAL
F.8.1 Comment: Two commenters (IV-D-6) recommended that the introduction
state clearly what sources are included and excluded by this CTG,
preferably in the opening paragraph.
Response; Chapter 1.0 of the CTG document has been revised to
incorporate a discussion of the applicable chemicals.
F.8.2 Comment. Four commenters (IV-D-3, IV-D-5, IV-D-6, IV-G-2) observed
that the flow rate cutoffs do not appear to be consistent, and requested
additional clarification. The commenters noted that the flow rate cutoff
in D.2(b}(3) is 0.011 scm/min (0.4 scfm), but the RACT summary on page 6-7
refers to the presumptive norm for RACT by requiring controls on streams
with a flow rate greater than 0.1 scfm.
Response; The units listed in D.2(b)(3) contained a typographical
error in the draft CTG document; however, this comment is no longer of
concern because the low flow cutoff for individual streams will be
calculated by determining the flow rate which identifies those streams with
a TRE index less than or equal to 1.0 when the stream characteristics from
the data base are inserted into the TRE equation. Furthermore, the
comparison of this number with the flow and concentration cutoff is no
longer of concern because the latter is being replaced with the TRE index
equation to determine applicability.
F.8.3 Comment: Several commenters (IV-D-3, IV-D-S, IV-D-6, IV-G-2) said
that in Section 0,6 of the CTG, paragraph (a)(l), the temperature
monitoring requirements for incineration appear to be incomplete and
additional language (e.g., ±1 percent of temperature) is necessary.
Response: The CTG document has been revised to reflect this comment.
F-8.4 Comment: Two commenters (IV-D-4, IV-D-6) argued that the definition
of "total organic compounds" should be changed to exclude all compounds
accepted by the EPA as photochemically nonreactive.
Response: The EPA agrees with this comment. The current, updated
list of compounds considered photochemically nonreactive by the
Administrator has been incorporated into the document (see page D-5).
F.8.5 Comment: One commenter (IV-D-3) requested that the use of the term
"recovery device" be clarified. The commenter noted that the current
recovery device definition states that the equipment is capable of and used
for the purpose of recovering chemicals for use, reuse, or sale. The
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commenter emphasized that situations exist where the recovered material
from an absorber or condenser does not technically meet the recovery device
definition and it would not be subject to the monitoring and reporting
standards of the rule. In addition, the commenter stated that if the
concentration at the outlet vent of the condenser falls below the
concentration and flow cutoff, and if it is the only vent for the process,
then only minimum recordkeeping applies. The commenter asserted that this
type of "recovery device" also meets the intent of the rule and that many
compliance interpretation issues could be eliminated by revising the
definition. The definition recommended by the commenter is "...an
individual unit of equipment, used for the purposes of recovering chemicals
for use, reuse, sale, or treatment."
Response: The EPA appreciates this comment and the CTG document has
been revised to reflect this comment.
F.8.6 Comment: One commenter (IV-0-3) pointed out that the text that
identifies the examples in Figures 2-6 and 2-7 does not currently match the
diagrams.
Response: Figures 2-6 and 2-7 represent specific examples of a
direct reactor process vent and a recovery vent applied to the vent stream
from a liquid phase reactor, respectively. More specifically, Figure 2-6
presents a schematic of nitrobenzene production venting to the atmosphere,
whereas Figure 2-7 depicts an alkylation unit process used to produce
ethylbenzene. The EPA believes the figures do correspond to the text. The
EPA invites the conmenter to call the EPA for further clarification if this
is still unclear.
F.8.7 Comment: Two commenters (1V-D-5, IV-G-2) suggested that the
Chemical Abstracts Service (CAS) number of the individual chemicals listed
in Appendix A should be provided.
Response: The EPA agrees with this comment and the CTG document has
been revised to reflect this comment.
F.8.8 Comment: One commenter (IV-D-6) noted that in the Ks definition in
the middle of page D-6, Ks should be K£.
Response; The EPA agrees with this comment and the document has been
revised to reflect this comment.
F.8.9 Comment: One commenter (IV-D-1) recommended that the definition of
"product" would be clearer if the EPA would define it as "any compound or
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chemical listed in Appendix A which is produced as that chemical for sale
as a final product, by-product, co-product, or intermediate or for use in
the production of other chemicals or compounds,"
Response: The EPA agrees with this comment and the CTG document has
been revised to reflect this comment.
F.8.10 Comment: One commenter (IV-D-1) said that the definition of
"affected facility" would be easier to follow if it were changed as
follows: "an affected facility is an individual reactor process or
distillation operation with its own individual recovery system (if any) or
the combination of two or more reactor processes or distillation operations
and the common recovery system they share." The commenter noted that
reactor processes and distillation columns are not single pieces of
equipment, but embrace several other components which are considered part
of the system. The commenter suggested that rewording this definition
would help make this distinction more apparent to the reader.
Response: The EPA agrees with this comment and the CTG document has
been revised to reflect this comment.
F.8.11 Comment: One commenter (IV-D-1) noted that the CTG states that of
the three possible emission limitation formats, the regulatory agency
should consider applying the "percent reduction format" since the EPA
believes it "best represents performance capabilities of the control
devices used to comply with the RACT regulation." The commenter suggested
that there are other opportunities which would present themselves for using
one of the other two formats. The commenter then recommended that the
wording at the top of page 7-4 be changed in the second line by eliminating
"...are not preferred because they...." The commenter noted that this does
not change the general intent of the statements contained on the page, but
does remove a direct inference that the other two formats should not be
used.
Response: This comment 1s no longer applicable because the
applicability format has been revised to incorporate the TRE Index
equation. The CTG now recommends reduction of VOC emissions until the TRE
index is greater than one.
F.8.12 Comment: One commenter (IV-G-2) requested that any deviation from
the list of chemicals established in the corresponding NSPS for reactor
processes and distillation operations be explained in the CTG.
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Response: The list of applicable chemicals for this CTG correspond
to all appropriate chemicals addressed by previous NSPS plus chemicals in
the SOCHI source category. Any deviations in the list of chemicals in this
CTG from the list presented in previous NSPS result from the inclusion of
SOCHI chemicals.
F.8.13 Comment: One commenter (IV-G-7) recommended the following language
changes in Section 3.1.4.1:
• Paragraph 1, sentence 5, change to read: "Combustion catalysts
include palladium and platinum group metals, manganese oxide,
copper oxide, chromium and cobalt."
• Paragraph 3, sentence 1, charge to read: "The operating
temperatures of combustion catalysts usually range from 500 °F
to 800 op."
• Paragraph 3, sentence 3, change to read: "Temperatures greater
than 1.3SO °F may result in shortened catalyst life." Delete
the rest of the original sentence because it is not true that
the catalyst or substrate will evaporate or melt at higher
temperatures (>1,200 °F). In order for a metal substrate to
melt the temperature must exceed 2,600 °F."
• Paragraph 3, add the following after the last sentence:
"Materials accumulated on the catalyst can be removed by
physical or chemical means, thus restoring the catalyst
activity to its original (fresh) level. Condensed organics
accumulated on the catalyst can be removed with thermal
treatment.
The commenter also stated that not all of the poisons listed in
paragraph 3 of Section 3.1.4.1 are detrimental to VOC catalysts. The
commenter suggested that masking of the catalyst by particulate or
carbon-based materials is reversible, and catalysts are commercially
available to handle many of the poisons listed, including sulfur,
halocarbons, and phosphorous.
Response: The EPA agrees with all these comments and will revise the
CTG document to reflect them.
F.8.14 Comment; One commenter (IV-6-7) said that the example cited in
Section 3.1.4.2 is an oversimplification and is not VOC species specific.
The commenter stated that at 840 °F and a space velocity of 30,000/seconds
(the example shown), many VOC's can be reduced by 9i percent or more with
catalytic oxidation technology.
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Response: The EPA believes that the commenter cited an example that
verifies the referenced numbers In the document. The CTG document stated
that "catalytic oxldizers hive been reported to achieve efficiencies of
98 percent or greater," and the 99 percent reduction reported by the
commenter does fall within the 98 percent or greater range.
F.8.15 Comment. One commenter (IV-G-7) recommended that sentence 2 of
paragraph 2 In Section 3.3 be deleted. The commenter stated that there are
not technical obstacles preventing catalytic oxidation from achieving at
least 98 percent destruction efficiency, and that this level of control is
becoming the rule rather than the exception.
Response; The sentence the commenter is referring to states that,
with the exception of catalytic oxidizers, the other combustion devices
listed are applicable to a wide range of vent streams. The EPA agrees with
this comment and has revised the CTG document to reflect this comment.
F.8.16 Comment; One commenter (IV-G-7) requested that several statements
in Section 6.2 of the draft CTG be modified to present a more neutral
treatment of catalytic oxidation and to ensure that this technology is not
excluded from consideration as an available control technology.
Response: The EPA has revised the CTG document to reflect this
request.
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