p//e •—^ AP-42
Fifth Edition
Supplement F
September 2000
SUPPLEMENT F
TO
COMPILATION
OF
AIR POLLUTANT
EMISSION FACTORS
VOLUME I:
STATIONARY POINT
AND AREA SOURCES
Office of Air Quality Planning and Standards
Office of Air and Radiation
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
September 2000
U.S. Environmental Protection Agency
Region 5, Library {PL-12.0
77 West Jsckson Boulevard, 12tb
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This report has been reviewed by the Office of Air Quality Planning and Standards, U. S. Environmental
Protection Agency, and has been approved for publication. Any mention of trade names or commercial
products is not intended to constitute endorsement or recommendation for use.
AP-42
Fifth Edition
Volume I
Supplement F
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Instructions for Inserting
Supplement F of Volume I
Into AP-42
Chap. 3, Sec. 3.1 Stationary Gas Turbines
Chap. 3, Sec. 3.2 Natural Gas-fired Reciprocating Engines
Chap. 12, Sec. 12.2 Coke Production
Insert new Technical Report Data Sheet
Replace Entire Major Revision
Replace Entire Major Revision
Replace Entire Minor Revision
'"X.
IN
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PUBLICATIONS IN SERIES
SUPPLEMENT F 9/00
Section
3.1 Stationary Gas Turbines
3.2 Natural Gas-fired Reciprocating Engines
12.2 Coke Production
9/00 Publication in Series
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3.1 Stationary Gas Turbines
3.1.1 General1
Gas turbines, also called "combustion turbines", are used in a broad scope of applications
including electric power generation, cogeneration, natural gas transmission, and various process
applications. Gas turbines are available with power outputs ranging in size from 300 horsepower (hp) to
over 268,000 hp, with an average size of 40,200 hp.2 The primary fuels used in gas turbines are natural
gas and distillate (No. 2) fuel oil.3
3.1.2 Process Description1 '2
A gas turbine is an internal combustion engine that operates with rotary rather than reciprocating
motion. Gas turbines are essentially composed of three major components: compressor, combustor, and
power turbine. In the compressor section, ambient air is drawn in and compressed up to 30 times ambient
pressure and directed to the combustor section where fuel is introduced, ignited, and burned. Combustors
can either be annular, can-annular, or silo. An annular combustor is a doughnut-shaped, single, continuous
chamber that encircles the turbine in a plane perpendicular to the air flow. Can-annular combustors are
similar to the annular; however, they incorporate several can-shaped combustion chambers rather than a
single continuous chamber. Annular and can-annular combustors are based on aircraft turbine technology
and are typically used for smaller scale applications. A silo (frame-type) combustor has one or more
combustion chambers mounted external to the gas turbine body. Silo combustors are typically larger than
annular or can-annular combustors and are used for larger scale applications.
The combustion process in a gas turbine can be classified as diffusion flame combustion, or lean-
premix staged combustion. In the diffusion flame combustion, the fuel/air mixing and combustion take
place simultaneously in the primary combustion zone. This generates regions of near-stoichiometric
fuel/air mixtures where the temperatures are very high. For lean-premix combustors, fuel and air are
thoroughly mixed in an initial stage resulting in a uniform, lean, unburned fuel/air mixture which is
delivered to a secondary stage where the combustion reaction takes place. Manufacturers use different
types of fuel/air staging, including fuel staging, air staging, or both; however, the same staged, lean-premix
principle is applied. Gas turbines using staged combustion are also referred to as Dry Low NOX
combustors. The majority of gas turbines currently manufactured are lean-premix staged combustion
turbines.
Hot gases from the combustion section are diluted with additional air from the compressor section
and directed to the power turbine section at temperatures up to 2600°F. Energy from the hot exhaust gases,
which expand in the power turbine section, are recovered in the form of shaft horsepower. More than
50 percent of the shaft horsepower is needed to drive the internal compressor and the balance of recovered
shaft horsepower is available to drive an external load.2 Gas turbines may have one, two, or three shafts to
transmit power between the inlet air compression turbine, the power turbine, and the exhaust turbine. The
heat content of the exhaust gases exiting the turbine can either be discarded without heat recovery (simple
cycle); recovered with a heat exchanger to preheat combustion air entering the combustor (regenerative
cycle); recovered in a heat recovery steam generator to raise process steam, with or without supplementary
firing (cogeneration); or recovered, with or without supplementary firing, to raise steam for a steam turbine
Rankine cycle (combined cycle or repowering).
4/00 Stationary Internal Combustion Sources 3.1-1
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The simple cycle is the most basic operating cycle of gas turbines with a thermal efficiency ranging
from 15 to 42 percent. The cycle thermal efficiency is defined as the ratio of useful shaft energy to fuel
energy input. Simple cycle gas turbines are typically used for shaft horsepower applications without
recovery of exhaust heat. For example, simple cycle gas turbines are used by electric utilities for
generation of electricity during emergencies or during peak demand periods.
A regenerative cycle is a simple cycle gas turbine with an added heat exchanger. The heat
exchanger uses the turbine exhaust gases to heat the combustion air which reduces the amount of fuel
required to reach combustor temperatures. The thermal efficiency of a regenerative cycle is approximately
35 percent. However, the amount of fuel efficiency and saving may not be sufficient to justify the capital
cost of the heat exchanger, rendering the process unattractive.
A cogeneration cycle consists of a simple cycle gas turbine with a heat recovery steam generator
(HRSG). The cycle thermal efficiency can be as high as 84 percent. In a cogeneration cycle, the steam
generated by the HRSG can be delivered at a variety of pressures and temperatures to other thermal
processes at the site. For situations where additional steam is required, a supplementary burner, or duct
burner, can be placed in the exhaust duct stream of the HRSG to meet the site's steam requirements.
A combined cycle gas turbine is a gas turbine with a HRSG applied at electric utility sites. The
gas turbine drives an electric generator, and the steam from the HRSG drives a steam turbine which also
drives an electric generator. A supplementary-fired boiler can be used to increase the steam production.
The thermal efficiency of a combined cycle gas turbine is between 38 percent and 60 percent.
Gas turbine applications include gas and oil industry, emergency power generation facilities,
independent electric power producers (IPP), electric utilities, and other industrial applications. The
petroleum industry typically uses simple cycle gas turbines with a size range from 300 hp to 20,000 hp.
The gas turbine is used to provide shaft horsepower for oil and gas production and transmission.
Emergency power generation sites also utilize simple cycle gas turbines. Here the gas turbine is used to
provide backup or emergency power to critical networks or equipment. Usually, gas turbines under 5,000
hp are used at emergency power generation sites.
Independent electrical power producers generate electricity for resale to larger electric utilities.
Simple, regenerative, or combined cycle gas turbines are used at IPP; however, most installations use
combined cycle gas turbines. The gas turbines used at IPP can range from 1,000 hp to over 100,000 hp.
The larger electric utilities use gas turbines mostly as peaking units for meeting power demand peaks
imposed by large commercial and industrial users on a daily or seasonal basis. Simple cycle gas turbines
ranging from 20,000 hp to over 200,000 hp are used at these installations. Other industrial applications for
gas turbines include pulp and paper, chemical, and food processing. Here, combined cycle gas turbines are
used for cogeneration.
3.1.3 Emissions
The primary pollutants from gas turbine engines are nitrogen oxides (NOX), carbon monoxide
(CO), and to a lesser extent, volatile organic compounds (VOC). Particulate matter (PM) is also a
primary pollutant for gas turbines using liquid fuels. Nitrogen oxide formation is strongly dependent on the
high temperatures developed in the combustor. Carbon monoxide, VOC, hazardous air pollutants (HAP),
and PM are primarily the result of incomplete combustion. Trace to low amounts of HAP and sulfur
dioxide (SO2) are emitted from gas turbines. Ash and metallic additives in the fuel may also contribute to
PM in the exhaust. Oxides of sulfur (SOX) will only appear in a significant quantity if heavy oils are fired
3.1-2 EMISSION FACTORS 4/00
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in the turbine. Emissions of sulfur compounds, mainly SO2, are directly related to the sulfur content of the
fuel.
Available emissions data indicate that the turbine's operating load has a considerable effect on the
resulting emission levels. Gas turbines are typically operated at high loads (greater than or equal to 80
percent of rated capacity) to achieve maximum thermal efficiency and peak combustor zone flame
temperatures. With reduced loads (lower than 80 percent), or during periods of frequent load changes, the
combustor zone flame temperatures are expected to be lower than the high load temperatures, yielding
lower thermal efficiencies and more incomplete combustion. The emission factors for this sections are
presented for gas turbines operating under high load conditions. Section 3.1 background information
document and emissions database contain additional emissions data for gas turbines operating under
various load conditions.
Gas turbines firing distillate oil may emit trace metals carried over from the metals content of the
fuel. If the fuel analysis is known, the metals content of the fuel ash should be used for flue gas emission
factors assuming all metals pass through the turbine.
If the HRSG is not supplementary fuel fired, the simple cycle input-specific emission factors
(pounds per million British thermal units [lb/MMBtu]) will also apply to cogeneration/combined cycle
systems. If the HRSG is supplementary fired, the emissions attributable to the supplementary firing must
also be considered to estimate total stack emissions.
3.1.3.1 Nitrogen Oxides -
Nitrogen oxides formation occurs by three fundamentally different mechanisms. The principal
mechanism with turbines firing gas or distillate fuel is thermal NOX, which arises from the thermal
dissociation and subsequent reaction of nitrogen (N2) and oxygen (O2) molecules in the combustion air.
Most thermal NOX is formed in high temperature stoichiometric flame pockets downstream of the fuel
injectors where combustion air has mixed sufficiently with the fuel to produce the peak temperature fuel/air
interface.
The second mechanism, called prompt NOX, is formed from early reactions of nitrogen molecules
in the combustion air and hydrocarbon radicals from the fuel. Prompt NOX forms within the flame and is
usually negligible when compared to the amount of thermal NOX formed. The third mechanism, fuel NOX,
stems from the evolution and reaction of fuel-bound nitrogen compounds with oxygen. Natural gas has
negligible chemically-bound fuel nitrogen (although some molecular nitrogen is present). Essentially all
NOX formed from natural gas combustion is thermal NOX. Distillate oils have low levels of fuel-bound
nitrogen. Fuel NOX from distillate oil-fired turbines may become significant in turbines equipped with a
high degree of thermal NOX controls. Otherwise, thermal NOX is the predominant NOX formation
mechanism in distillate oil-fired turbines.
The maximum thermal NOX formation occurs at a slightly fuel-lean mixture because of excess
oxygen available for reaction. The control of stoichiometry is critical in achieving reductions in thermal
NOX. Thermal NOX formation also decreases rapidly as the temperature drops below the adiabatic flame
temperature, for a given stoichiometry. Maximum reduction of thermal NOX can be achieved by control of
both the combustion temperature and the stoichiometry. Gas turbines operate with high overall levels of
excess air, because turbines use combustion air dilution as the means to maintain the turbine Met
temperature below design limits. In older gas turbine models, where combustion is in the form of a
diffusion flame, most of the dilution takes place downstream of the primary flame, which does not minimize
peak temperature in the flame and suppress thermal NOX formation.
4/00 Stationary Internal Combustion Sources 3.1-3
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Diffusion flames are characterized by regions of near-stoichiometric fuel/air mixtures where
temperatures are very high and significant thermal NOX is formed. Water vapor in the turbine inlet air
contributes to the lowering of the peak temperature in the flame, and therefore to thermal NOX emissions.
Thermal NOX can also be reduced in diffusion type turbines through water or steam injection. The injected
water-steam acts as a heat sink lowering the combustion zone temperature, and therefore thermal NOX.
Newer model gas turbines use lean, premixed combustion where the fuel is typically premixed with more
than 50 percent theoretical air which results in lower flame temperatures, thus suppressing thermal NC^
formation.
Ambient conditions also affect emissions and power output from turbines more than from external
combustion systems. The operation at high excess air levels and at high pressures increases the influence
of inlet humidity, temperature, and pressure.4 Variations of emissions of 30 percent or greater have been
exhibited with changes in ambient humidity and temperature. Humidity acts to absorb heat in the primary
flame zone due to the conversion of the water content to steam. As heat energy is used for water to steam
conversion, the temperature is the flame zone will decrease resulting hi a decrease of thermal NOX
formation. For a given fuel firing rate, lower ambient temperatures lower the peak temperature in the
flame, lowering thermal NOX significantly. Similarly, the gas turbine operating loads affect NOX
emissions. Higher NOX emissions are expected for high operating loads due to the higher peak
temperature in the flame zone resulting in higher thermal NOX.
3.1.3.2 Carbon Monoxide and Volatile Organic Compounds -
CO and VOC emissions both result from incomplete combustion. CO results when there is
insufficient residence time at high temperature or incomplete mixing to complete the final step in fuel
carbon oxidation. The oxidation of CO to CO2 at gas turbine temperatures is a slow reaction compared to
most hydrocarbon oxidation reactions. In gas turbines, failure to achieve CO burnout may result from
quenching by dilution air. With liquid fuels, this can be aggravated by carryover of larger droplets from
the atomizer at the fuel injector. Carbon monoxide emissions are also dependent on the loading of the gas
turbine. For example, a gas turbine operating under a full load will experience greater fuel efficiencies
which will reduce the formation of carbon monoxide. The opposite is also true, a gas turbine operating
under a light to medium load will experience reduced fuel efficiencies (incomplete combustion) which will
increase the formation of carbon monoxide.
The pollutants commonly classified as VOC can encompass a wide spectrum of volatile organic
compounds some of which are hazardous air pollutants. These compounds are discharged into the
atmosphere when some of the fuel remains unburned or is only partially burned during the combustion
process. With natural gas, some organics are carried over as unreacted, trace constituents of the gas, while
others may be pyrolysis products of the heavier hydrocarbon constituents. With liquid fuels, large droplet
carryover to the quench zone accounts for much of the unreacted and partially pyrolized volatile organic
emissions.
Similar to CO emissions, VOC emissions are affected by the gas turbine operating load
conditions. Volatile organic compounds emissions are higher for gas turbines operating at low loads as
compared to similar gas turbines operating at higher loads.
3.1.3.3 Particulate Matter13-
PM emissions from turbines primarily result from carryover of noncombustible trace constituents
in the fuel. PM emissions are negligible with natural gas firing and marginally significant with distillate oil
firing because of the low ash content. PM emissions can be classified as "filterable" or "condensable" PM.
Filterable PM is that portion of the total PM that exists in the stack in either the solid or liquid state and
3.1-4 EMISSION FACTORS 4/00
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can be measured on a EPA Method 5 filter. Condensable PM is that portion of the total PM that exists as
a gas in the stack but condenses in the cooler ambient air to form particulate matter. Condensable PM
exists as a gas in the stack, so it passes through the Method 5 filter and is typically measured by analyzing
the impingers, or "back half of the sampling train. The collection, recovery, and analysis of the impingers
is described in EPA Method 202 of Appendix M, Part 51 of the Code of Federal Regulations. Condensable
PM is composed of organic and inorganic compounds and is generally considered to be all less than 1.0
micrometers in aerodynamic diameter.
3.1.3.4 Greenhouse Gases5"11-
Carbon dioxide (CO2) and nitrous oxide (N2O) emissions are all produced during natural gas and
distillate oil combustion in gas turbines. Nearly all of the fuel carbon is converted to CO2 during the
combustion process. This conversion is relatively independent of firing configuration. Methane (CH4) is
also present in the exhaust gas and is thought to be unburned fuel in the case of natural gas or a product of
combustion in the case of distillate fuel oil.
Although the formation of CO acts to reduce CO2 emissions, the amount of CO produced is
insignificant compared to the amount of CO2 produced. The majority of the fuel carbon not converted to
CO2 is due to incomplete combustion.
Formation of N2O during the combustion process is governed by a complex series of reactions and
its formation is dependent upon many factors. However, the formation of N2O is minimized when
combustion temperatures are kept high (above 1475°F) and excess air is kept to a minimum (less than 1
percent).
3.1.3.5 HAP Emissions -
Available data indicate that emission levels of HAP are lower for gas turbines than for other
combustion sources. This is due to the high combustion temperatures reached during normal operation.
The emissions data also indicate that formaldehyde is the most significant HAP emitted from combustion
turbines. For natural gas fired turbines, formaldehyde accounts for about two-thirds of the total HAP
emissions. Polycyclic aromatic hydrocarbons (PAH), benzene, toluene, xylenes, and others account for the
remaining one-third of HAP emissions. For No. 2 distillate oil-fired turbines, small amount of metallic
HAP are present in the turbine's exhaust in addition to the gaseous HAP identified under gas fired turbines.
These metallic HAP are carried over from the fuel constituents. The formation of carbon monoxide during
the combustion process is a good indication of the expected levels of HAP emissions. Similar to CO
emissions, HAP emissions increase with reduced operating loads. Typically, combustion turbines operate
under full loads for greater fuel efficiency, thereby minimizing the amount of CO and HAP emissions.
3.1.4 Control Technologies12
There are three generic types of emission controls in use for gas turbines, wet controls using steam
or water injection to reduce combustion temperatures for NOX control, dry controls using advanced
combustor design to suppress NOX formation and/or promote CO burnout, and post-combustion catalytic
control to selectively reduce NOX and/or oxidize CO emission from the turbine. Other recently developed
technologies promise significantly lower levels of NOX and CO emissions from diffusion combustion type
gas turbines. These technologies are currently being demonstrated in several installations.
Emission factors in this section have been determined from gas turbines with no add-on control
devices (uncontrolled emissions). For NOX and CO emission factors for combustion controls, such as
water-steam injection, and lean pre-mix units are presented. Additional information for controlled
4/00 Stationary Internal Combustion Sources 3.1-5
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emissions with various add-on controls can be obtained using the section 3.1 database. Uncontrolled, lean-
premix, and water injection emission factors were presented for NOX and CO to show the effect of
combustion modification on emissions.
3.1.4.1 Water Injection -
Water or steam injection is a technology that has been demonstrated to effectively suppress NOx
emissions from gas turbines. The effect of steam and water injection is to increase the thermal mass by
dilution and thereby reduce peak temperatures in the flame zone. With water injection, there is an
additional benefit of absorbing the latent heat of vaporization from the flame zone. Water or steam is
typically injected at a water-to-fuel weight ratio of less than one.
Depending on the initial NOX levels, such rates of injection may reduce NOx by 60 percent or
higher. Water or steam injection is usually accompanied by an efficiency penalty (typically 2 to 3 percent)
but an increase in power output (typically 5 to 6 percent). The increased power output results from the
increased mass flow required to maintain turbine inlet temperature at manufacturer's specifications. Both
CO and VOC emissions are increased by water injection, with the level of CO and VOC increases
dependent on the amount of water injection.
3.1.4.2 Dry Controls-
Since thermal NC^ is a function of both temperature (exponentially) and time (linearly), the basis
of dry controls are to either lower the combustor temperature using lean mixtures of air and/or fuel staging,
or decrease the residence time of the combustor. A combination of methods may be used to reduce NOX
emissions such as lean combustion and staged combustion (two stage lean/lean combustion or two stage
rich/lean combustion).
Lean combustion involves increasing the air-to-fuel ratio of the mixture so that the peak and
average temperatures within the combustor will be less than that of the stoichiometric mixture, thus
suppressing thermal NOX formation. Introducing excess air not only creates a leaner mixture but it also
can reduce residence time at peak temperatures.
Two-stage lean/lean combustors are essentially fuel-staged, premixed combustors in which each
stage burns lean. The two-stage lean/lean combustor allows the turbine to operate with an extremely lean
mixture while ensuring a stable flame. A small stoichiometric pilot flame ignites the premixed gas and
provides flame stability. The NOX emissions associated with the high temperature pilot flame are
insignificant. Low NOX emission levels are achieved by this combustor design through cooler flame
temperatures associated with lean combustion and avoidance of localized "hot spots" by premixing the fuel
and air.
Two stage rich/lean combustors are essentially air-staged, premixed combustors in which the
primary zone is operated fuel rich and the secondary zone is operated fuel lean. The rich mixture produces
lower temperatures (compared to stoichiometric) and higher concentrations of CO and H2, because of
incomplete combustion. The rich mixture also decreases the amount of oxygen available for NOX
generation. Before entering the secondary zone, the exhaust of the primary zone is quenched (to extinguish
the flame) by large amounts of air and a lean mixture is created. The lean mixture is pre-ignited and the
combustion completed in the secondary zone. NOX formation in the second stage are minimized through
combustion in a fuel lean, lower temperature environment. Staged combustion is identified through a
variety of names, including Dry-Low NOx (DLN), Dry-Low Emissions (DLE), or SoLoNOx.
3.1-6 EMISSION FACTORS 4/00
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3.1.4.3 Catalytic Reduction Systems -
Selective catalytic reduction (SCR) systems selectively reduce NOX emissions by injecting
ammonium (NH3) into the exhaust gas stream upstream of a catalyst. Nitrogen oxides, NH3, and O2 react
on the surface of the catalyst to form N2 and H2O. The exhaust gas must contain a minimum amount of O2
and be within a particular temperature range (typically 450°F to 850°F) in order for the SCR system to
operate properly.
The temperature range is dictated by the catalyst material which is typically made from noble
metals, including base metal oxides such as vanadium and titanium, or zeolite-based material. The removal
efficiency of an SCR system in good working order is typically from 65 to 90 percent. Exhaust gas
temperatures greater than the upper limit (850°F) cause NOX and NH3 to pass through the catalyst
unreacted. Ammonia emissions, called NH3 slip, may be a consideration when specifying an SCR system.
Ammonia, either in the form of liquid anhydrous ammonia, or aqueous ammonia hydroxide is
stored on site and injected into the exhaust stream upstream of the catalyst. Although an SCR system can
operate alone, it is typically used in conjunction with water-steam injection systems or lean-premix system
to reduce NOX emissions to their lowest levels (less than 10 ppm at 15 percent oxygen for SCR and wet
injection systems). The SCR system for landfill or digester gas-fired turbines requires a substantial fuel
gas pretreatment to remove trace contaminants that can poison the catalyst. Therefore, SCR and other
catalytic treatments may be inappropriate control technologies for landfill or digester gas-fired turbines.
The catalyst and catalyst housing used in SCR systems tend to be very large and dense (in terms of
surface area to volume ratio) because of the high exhaust flow rates and long residence times required for
NOX, O2, and NH3, to react on the catalyst. Most catalysts are configured in a parallel-plate, "honeycomb"
design to maximize the surface area-to-volume ratio of the catalyst. Some SCR installations incorporate
CO catalytic oxidation modules along with the NOX reduction catalyst for simultaneous CO/NOX control.
Carbon monoxide oxidation catalysts are typically used on turbines to achieve control of CO
emissions, especially turbines that use steam injection, which can increase the concentrations of CO and
unburned hydrocarbons in the exhaust. CO catalysts are also being used to reduce VOC and organic HAPs
emissions. The catalyst is usually made of a precious metal such as platinum, palladium, or rhodium.
Other formulations, such as metal oxides for emission streams containing chlorinated compounds, are also
used. The CO catalyst promotes the oxidation of CO and hydrocarbon compounds to carbon dioxide
(CO2) and water (H2O) as the emission stream passes through the catalyst bed. The oxidation process
takes place spontaneously, without the requirement for introducing reactants. The performance of these
oxidation catalyst systems on combustion turbines results in 90-plus percent control of CO and about 85 to
90 percent control of formaldehyde. Similar emission reductions are expected on other HAP pollutants.
3.1.4.4 Other Catalytic Systems14'15 -
New catalytic reduction technologies have been developed and are currently being commercially
demonstrated for gas turbines. Such technologies include, but are not limited to, the SCONOX and the
XONON systems, both of which are designed to reduce NOX and CO emissions. The SCONOX system is
applicable to natural gas fired gas turbines. It is based on a unique integration of catalytic oxidation and
absorption technology. CO and NO are catalytically oxidized to CO2 and NO2. The NO2 molecules are
subsequently absorbed on the treated surface of the SCONOX catalyst. The system manufacturer
guarantees CO emissions of 1 ppm and NOX emissions of 2 ppm. The SCONOX system does not require
the use of ammonia, eliminating the potential of ammonia slip conditions evident in existing SCR systems.
Only limited emissions data were available for a gas turbine equipped with a SCONOX system. This data
reflected HAP emissions and was not sufficient to verify the manufacturer's claims.
4/00 Stationary Internal Combustion Sources 3.1-7
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The XONON system is applicable to diffusion and lean-premix combustors and is currently being
demonstrated with the assistance of leading gas turbine manufacturers. The system utilizes a flameless
combustion system where fuel and air reacts on a catalyst surface, preventing the formation of NOX while
achieving low CO and unburned hydrocarbon emission levels. The overall combustion process consists of
the partial combustion of the fuel in the catalyst module followed by completion of the combustion
downstream of the catalyst. The partial combustion within the catalyst produces no NOX, and the
combustion downstream of the catalyst occurs in a flameless homogeneous reaction that produces almost
no NOx- The system is totally contained within the combustor of the gas turbine and is not a process for
clean-up of the turbine exhaust. Note that this technology has not been fully demonstrated as of the
drafting of this section. The catalyst manufacturer claims that gas turbines equipped with the XONON
Catalyst emit NOX levels below 3 ppm and CO and unburned hydrocarbons levels below 10 ppm.
Emissions data from gas turbines equipped with a XONON Catalyst were not available as of the drafting
of this section.
3.1.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the new EFIG home page
(http://www.epa.gov/ttn/chief).
Supplement A, February 1996
• For the PM factors, a footnote was added to clarify that condensables and all PM from oil-
and gas-fired turbines are considered PM-10.
• In the table for large uncontrolled gas turbines, a sentence was added to footnote "e" to
indicate that when sulfur content is not available, 0.6 lb/106 ft3 (0.0006 Ib/MMBtu) can be
used.
Supplement B, October 1996
• Text was revised and updated for the general section.
• Text was added regarding firing practices and process description.
• Text was revised and updated for emissions and controls.
• All factors for turbines with SCR-water injection control were corrected.
• The CO2 factor was revised and a new set of N2O factors were added.
Supplement F, April 2000
• Text was revised and updated for the general section.
• All emission factors were updated except for the SO2 factor for natural gas and distillate
oil turbines.
3.1-8 EMISSION FACTORS 4/00
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Turbines using staged (lean-premix) combustors added to this section.
Turbines used for natural gas transmission added to this section.
Details for turbine operating configurations (operating cycles) added to this section.
Information on new emissions control technologies added to this section (SCONOX and
XONON).
HAP emission factors added to this section based on over 400 data points taken from over
60 source tests.
PM condensable and filterable emission factors for natural gas and distillate oil fired
turbines were developed.
NOx and CO emission factors for lean-premix turbines were added.
Emission factors for landfill gas and digester gas were added.
4/00 Stationary Internal Combustion Sources 3.1-9
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Table 3.1-1. EMISSION FACTORS FOR NITROGEN OXIDES (NOX) AND
CARBON MONOXIDE (CO) FROM STATIONARY GAS TURBINES
Emission Factors1
Turbine Type
Natural Gas-Fired Turbines
Uncontrolled
Water-Steam Injection
Lean-Premix
Distillate Oil-Fired Turbines6
Uncontrolled
Water-Steam Injection
Landfill Gas-Fired Turbines8
Uncontrolled
Digester Gas-Fired Turbines'
Uncontrolled
Nitrogen Oxides
(lb/MMBtu)c
(Fuel Input)
3.2 E-01
1.3E-01
9.9 E-02
(lb/MMBtu)f
(Fuel Input)
8. 8 E-01
2.4 E-01
(lb/MMBtu)h
(Fuel Input)
1.4 E-01
(lb/MMBtu)k
(Fuel Input)
1.6 E-01
Emission Factor
Rating
A
A
D
Emission Factor
Rating
C
B
Emission Factor
Rating
A
Emission Factor
Rating
D
Carbon Monoxide
(lb/MMBtu)°
(Fuel Input)
8.2 E-02d
3.0 E-02
1.5 E-02
(lb/MMBtu)f
(Fuel Input)
3.3 E-03
7.6 E-02
(lb/MMBtu)h
(Fuel Input)
4.4 E-01
(lb/MMBtu)k
(Fuel Input)
1.7 E-02
Emission Factor
Rating
A
A
D
Emission Factor Rating
C
C
Emission Factor Rating
A
Emission Factor Rating
D
a Factors are derived from units operating at high loads (>80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief.
b Source Classification Codes (SCCs) for natural gas-fired turbines include 2-01-002-01, 2-02-002-01,
2-02-002-03, 2-03-002-02, and 2-03-002-03. The emission factors in this table may be converted to
other natural gas heating values by multiplying the given emission factor by the ratio of the specified
heating value to this average heating value.
c Emission factors based on an average natural gas heating value (HHV) of 1020 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106 scf), multiply by 1020.
It is recognized that the uncontrolled emission factor for CO is higher than the water-steam injection and
lean-premix emission factors, which is contrary to expectation. The EPA could not identify the reason
for this behavior, except that the data sets used for developing these factors are different.
e SCCs for distillate oil-fired turbines include 2-01-001-01, 2-02-001-01, 2-02-001-03, and
2-03-001-02.
f Emission factors based on an average distillate oil heating value of 139 MMBtu/103 gallons. To
convert from (Ib/MMBtu) to (lb/103 gallons), multiply by 139.
g SCC for landfill gas-fired turbines is 2-03-008-01.
h Emission factors based on an average landfill gas heating value of 400 Btu/scf at 60°F. To convert from
(Ib/MMBtu), to (lb/106 scf) multiply by 400.
j SCC for digester gas-fired turbine is 2-03-007-01.
k Emission factors based on an average digester gas heating value of 600 Btu/scf at 60°F. To convert from
(Ib/MMBtu) to (lb/106 scf) multiply by 600.
3.1-10
EMISSION FACTORS
4/00
-------
Table 3.1-2a. EMISSION FACTORS FOR CRITERIA POLLUTANTS AND GREENHOUSE
GASES FROM STATIONARY GAS TURBINES
Emission Factors" - Uncontrolled
Pollutant
CO2f
N20
Lead
SO2
Methane
VOC
TOCk
PM (condensible)
PM (filterable)
PM (total)
Natural Gas-Fired Turbines
(lb/MMBtu)c
(Fuel Input)
110
0.003g
ND
0.94Sh
8.6 E-03
2.1 E-03
1.1 E-02
4.7 E-031
1.9 E-031
6.6 E-031
Emission Factor
Rating
A
E
NA
B
C
D
B
C
C
C
Distillate Oil-Fired Turbines
(lb/MMBtu)e
(Fuel Input)
157
ND
1.4E-05
1.01Sh
ND
4.1E-04j
4.0 E-031
7.2 E-031
4. 3 E-031
1.2 E-021
Emission Factor
Rating
A
NA
C
B
NA
E
C
C
C
C
a Factors are derived from units operating at high loads (>80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief'. ND = No Data, NA = Not Applicable.
b SCCs for natural gas-fired turbines include 2-01-002-01, 2-02-002-01 & 03, and 2-03-002-02 & 03.
0 Emission factors based on an average natural gas heating value (HHV) of 1020 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106 scf), multiply by 1020. Similarly, these emission factors can be
converted to other natural gas heating values.
d SCCs for distillate oil-fired turbines are 2-01-001-01, 2-02-001-01, 2-02-001-03, and 2-03-001-02.
e Emission factors based on an average distillate oil heating value of 139 MMBtu/103 gallons. To convert
from (Ib/MMBtu) to (lb/103 gallons), multiply by 139.
Based on 99.5% conversion of fuel carbon to CO2 for natural gas and 99% conversion of fuel carbon to
CO2 for distillate oil. CO2 (Natural Gas) [Ib/MMBtu] = (0.0036 scf/Btu)(%CON)(C)(D), where %CON
= weight percent conversion of fuel carbon to CO2, C = carbon content of fuel by weight, and D =
density of fuel. For natural gas, C is assumed at 75%, and D is assumed at 4.1 E+04 lb/106scf. For
distillate oil, CO2 (Distillate Oil) [Ib/MMBtu] = (26.4 gaVMMBtu) (%CON)(C)(D), where C is assumed
at 87%, and the D is assumed at 6.9 Ib/gallon.
8 Emission factor is carried over from the previous revision to AP-42 (Supplement B, October 1996) and is
based on limited source tests on a single turbine with water-steam injection (Reference 5).
All sulfur in the fuel is assumed to be converted to SO2. S = percent sulfur in fuel. Example, if sulfur
content in the fuel is 3.4 percent, then S = 3.4. If S is not available, use 3.4 E-03 Ib/MMBtu for natural
gas turbines, and 3.3 E-02 Ib/MMBtu for distillate oil turbines (the equations are more accurate).
J VOC emissions are assumed equal to the sum of organic emissions.
k Pollutant referenced as THC in the gathered emission tests. It is assumed as TOC, because it is based on
EPA Test Method 25 A
Emission factors are based on combustion turbines using water-steam injection.
4/00
Stationary Internal Combustion Sources
3.1-11
-------
Table 3. l-2b. EMISSION FACTORS FOR CRITERIA POLLUTANTS AND GREENHOUSE
GASES FROM STATIONARY GAS TURBINES
Emission Factors3 - Uncontrolled
Pollutants
CO/
Lead
PM-10
SO2
voch
Landfill Gas-Fired Turbines
(lb/MMBtu)c
50
ND
2.3 E-02
4.5 E-02
1.3 E-02
Emission Factor
Rating
D
NA
B
C
B
Digester Gas-Fired Turbines
(lb/MMBtu)e
27
< 3.4 E-06g
1.2 E-02
6.5 E-03
5.8 E-03
Emission Factor
Rating
C
D
C
D
D
a Factors are derived from units operating at high loads (>80 percent load) only. For information on
units operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief'. ND = No Data, NA = Not Applicable.
b SCC for landfill gas-fired turbines is 2-03-008-01.
c Emission factors based on an average landfill gas heating value (HHV) of 400 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106 scf), multiply by 400.
d SCC for digester gas-fired turbine include 2-03-007-01.
c Emission factors based on an average digester gas heating value of 600 Btu/scf at 60°F. To convert
from (Ib/MMBtu) to (lb/106 scf), multiply by 600.
f For landfill gas and digester gas, CO2 is presented in test data as volume percent of the exhaust stream
(4.0 percent to 4.5 percent).
8 Compound was not detected. The presented emission value is based on one-half of the detection limit.
h Based on adding the formaldehyde emissions to the NMHC.
3.1-12
EMISSION FACTORS
4/00
-------
Table 3.1-3. EMISSION FACTORS FOR HAZARDOUS AIR POLLUTANTS
FROM NATURAL GAS-FIRED STATIONARY GAS TURBINES3
Emission Factors - Uncontrolled
Pollutant
l,3-Butadiened
Acet aldehyde
Acrolein
Benzene6
Ethylbenzene
Formaldehyde1
Naphthalene
PAH
Propylene Oxided
Toluene
Xylenes
Emission Factor
ab/MMBtu)c
< 4.3 E-07
4.0 E-05
6.4 E-06
1.2 E-05
3.2 E-05
7. 1 E-04
1.3 E-06
2.2 E-06
< 2.9 E-05
1.3 E-04
6.4 E-05
Emission Factor Rating
D
C
C
A
C
A
C
C
D
C
C
a SCC for natural gas-fired turbines include 2-01-002-01, 2-02-002-01, 2-02-002-03, 2-03-002-02, and 2-
03-002-03. Hazardous Air Pollutants as defined in Section 112 (b) of the Clean Air Act.
b Factors are derived from units operating at high loads (> 80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief.
c Emission factors based on an average natural gas heating value (HHV) of 1020 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106 scf), multiply by 1020. These emission factors can be converted to
other natural gas heating values by multiplying the given emission factor by the ratio of the specified
heating value to this heating value.
d Compound was not detected. The presented emission value is based on one-half of the detection limit.
e Benzene with SCONOX catalyst is 9.1 E-07, rating of D.
f Formaldehyde with SCONOX catalyst is 2.0 E-05, rating of D.
4/00
Stationary Internal Combustion Sources
3.1-13
-------
Table 3.1-4. EMISSION FACTORS FOR HAZARDOUS AIR POLLUTANTS
FROM DISTILLATE OIL-FIRED STATIONARY GAS TURBINES"
Emission Factors - Uncontrolled
Pollutant
l,3-Butadiened
Benzene
Formaldehyde
Naphthalene
PAH
Emission Factor
(lb/MMBtu)°
<1.6E-05
5.5 E-05
2.8 E-04
3.5 E-05
4.0 E-05
Emission Factor Rating
D
C
B
C
C
a SCCs for distillate oil-fired turbines include 2-01-001-01, 2-02-001-01, 2-02-001-03, and 2-03-001-02.
Hazardous Air Pollutants as defined in Section 112 (b) of the Clean Air Act.
b Factors are derived from units operating at high loads (>80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief.
0 Emission factors based on an average distillate oil heating value (HHV) of 139 MMBtu/103 gallons. To
convert from (Ib/MMBtu) to (lb/103 gallons), multiply by 139.
d Compound was not detected. The presented emission value is based on one-half of the detection limit.
3.1-14
EMISSION FACTORS
4/00
-------
Table 3.1-5. EMISSION FACTORS FOR METALLIC HAZARDOUS AIR POLLUTANTS
FROM DISTILLATE OIL-FIRED STATIONARY GAS TURBINES8
Emission Factorsb - Uncontrolled
Pollutant
Arsenic*3
Berylliumd
Cadmium
Chromium
Lead
Manganese
Mercury
Nickeld
Seleniumd
Emission Factor
(lb/MMBtu)c
< 1.1E-05
<3.1E-07
4.8 E-06
1.1E-05
1.4E-05
7.9 E-04
1.2 E-06
< 4.6 E-06
< 2.5 E-05
Emission Factor Rating
D
D
D
D
D
D
D
D
D
a SCCs for distillate oil-fired turbines include 2-01-001-01, 2-02-001-01, 2-02-001-03, and
2-03-001-02. Hazardous Air Pollutants as defined in Section 112 (b) of the Clean Air Act.
Factors are derived from units operating at high loads (> 80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www. epa. gov/ttn/chief'.
c Emission factors based on an average distillate oil heating value (HHV) of 139 MMBtu/103 gallons. To
convert from (Ib/MMBtu) to (lb/103 gallons), multiply by 139.
Compound was not detected. The presented emission value is based on one-half of the detection limit.
4/00
Stationary Internal Combustion Sources
3.1-15
-------
Table 3.1-6. EMISSION FACTORS FOR HAZARDOUS AIR POLLUTANTS
FROM LANDFILL GAS-FIRED STATIONARY GAS TURBINES8
Emission Factors - Uncontrolled
Pollutant
Acetonitrile
Benzene
Benzyl Chlorided
Carbon Tetrachlorided
Chlorobenzened
Chloroformd
Methylene Chloride
Tetrachloroethylened
Toluene
Trichloroethylened
Vinyl Chlorided
Xylenes
Emission Factor (lb/MMBtu)°
< 1.2E-05
2.1E-05
<1.2E-05
<1.8E-06
< 2.9 E-06
<1.4E-06
2.3 E-06
< 2.5 E-06
1.1E-04
< 1.9 E-06
< 1.6 E-06
3.1E-05
Emission Factor Rating
D
B
D
D
D
D
D
D
B
D
D
B
a SCC for landfill gas-fired turbines is 2-03-008-01. Hazardous Air Pollutants as defined in
Section 112 (b) of the Clean Air Act.
b Factors are derived from units operating at high loads (>80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief.
c Emission factors based on an average landfill gas heating value (HHV) of 400 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106 scf), multiply by 400.
d Compound was not detected. The presented emission value is based on one-half of the detection limit.
3.1-16
EMISSION FACTORS
4/00
-------
Table 3.1-7. EMISSION FACTORS FOR HAZARDOUS AIR POLLUTANTS
FROM DIGESTER GAS-FIRED STATIONARY GAS TURBINES8
Emission Factors'5 - Uncontrolled
Pollutant
1,3-Butadiene
1 ,4-Dichlorobenzene
Acetaldehyde
Carbon Tetrachloride
Chlorobenzene
Chloroform
Ethylene Dichlorided
Formaldehyde
Methylene Chloride
Tetrachloroethylened
Trichloroethylened
Vinyl Chlorided
Vinylidene Chlorided
Emission Factor (lb/MMBtu)c
< 9.8 E-06
< 2.0 E-05
5.3 E-05
< 2.0 E-05
< 1.6 E-05
< 1.7 E-05
< 1.5 E-05
1.9E-04
< 1.3 E-05
< 2.1 E-05
< 1.8 E-05
< 3.6 E-05
< 1.5 E-05
Emission Factor Ratings
D
D
D
D
D
D
D
D
D
D
D
D
D
SCC for digester gas-fired turbines is 2-03-007-01. Hazardous Air Pollutants as defined in
Section 112 (b) of the Clean Air Act.
Factors are derived from units operating at high loads (>80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www. epa.gov/ttn/chief.
Emission factors based on an average digester gas heating value (HHV) of 600 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106scf), multiply by 600.
Compound was not detected. The presented emission value is based on one-half of the detection limit.
4/00
Stationary Internal Combustion Sources
3.1-17
-------
Table 3.1-8. EMISSION FACTORS FOR METALLIC HAZARDOUS AIR POLLUTANTS
FROM DIGESTER GAS-FIRED STATIONARY GAS TURBINES3
Emission Factors*5 - Uncontrolled
Pollutant
Arsenicd
Cadmiumd
Chromium*5
Leadd
Nickel
Selenium
Emission Factor (lb/MMBtu)c
< 2.3 E-06
< 5.8 E-07
< 1.2 E-06
< 3.4 E-06
2.0 E-06
1.1E-05
Emission Factor Rating
D
D
D
D
D
D
a SCC for digester gas-fired turbines is 2-03-007-01. Hazardous Air Pollutants as defined in
Section 112 (b) of the Clean Air Act.
b Factors are derived from units operating at high loads (^80 percent load) only. For information on units
operating at other loads, consult the background report for this chapter (Reference 16), available at
"www.epa.gov/ttn/chief.
0 Emission factor based on an average digester gas heating value (HHV) of 600 Btu/scf at 60°F. To
convert from (Ib/MMBtu) to (lb/106 scf), multiply by 600.
d Compound was not detected. The presented emission value is based on one-half of the detection limit.
3.1-18
EMISSION FACTORS
4/00
-------
References For Section 3.1
1. Alternative Control Techniques Document - NOX Emissions from Stationary Gas Turbines,
EPA 453/R-93-007, January 1993.
2. C. C. Shih, et al., Emissions Assessment C/Conventional Stationary Combustion Systems,
Vol. II: Internal Combustion Sources, EPA-600/7-79-029c, U. S. Environmental Protection
Agency, Cincinnati, OH, February 1979.
3. Final Report - Gas Turbine Emission Measurement Program, GASLTR787, General Applied
Science Laboratories, Westbury, NY, August 1974.
4. Standards Support And Environmental Impact Statement, Volume 1: Proposed Standards Of
Performance For Stationary Gas Turbines, EPA-450/2-77-017a, U. S. Environmental Protection
Agency, Research Triangle Park, NC, September 1977.
5. L. P. Nelson, et al., Global Combustion Sources Of Nitrous Oxide Emissions, Research Project
2333-4 Interim Report, Sacramento: Radian Corporation, 1991.
6. R. L. Peer, et al., Characterization Of Nitrous Oxide Emission Sources, U. S. Environmental
Protection Agency, Office of Research and Development, Research Triangle Park, NC, 1995.
7. S. D. Piccot, et al., Emissions And Cost Estimates For Globally Significant Anthropogenic
Combustion Sources OfNOx, N2O, CH4, CO, And CO2, U. S. Environmental Protection Agency,
Office of Research and Development, Research Triangle Park, NC, 1990.
8. G. Marland and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U. S. Department of Energy, Oak Ridge, TN, 1983.
9. G. Marland and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus 366:232-261, 1984.
10. Inventory OfU. S. Greenhouse Gas Emissions And Sinks: 1990-1991, EPA-230-R-96-006,
U. S. Environmental Protection Agency, Washington, DC, November 1995.
11. 1PCC Guidelines For National Greenhouse Gas Inventories Workbook, Intergovernmental Panel
on Climate Change/Organization for Economic Cooperation and Development, Paris, France,
1995.
12. L. M. Campbell and G. S. Shareef, Sourcebook: NOX Control Technology Data, Radian Corp.,
EPA-600/2-91-029, Air and Energy Engineering Research Laboratory, U. S. Environmental
Protection Agency, Research Triangle Park, July 1991.
13. In-stack Condensible Paniculate Matter Measurement and Permitting Issues for Maryland
Power Plants, Maryland Department of Natural Resource, Prepared by Versar, INC, January
1998.
4/00 Stationary Internal Combustion Sources 3.1-19
-------
14. Catalysts for Power Generation, The SCONOX System. Goal Line Environmental Technologies,
www.glet.com/gLprocLSCONOX.htm, March 1998.
15. Information form Chuck Solt of Catalytica Combustion Systems, Inc., to EPA, XONON Flameless
Combustion, January 1996.
16. Emission Factor Documentation ofAP-42 Section 3.1, Stationary Combustion Turbines, EPA
Contract No. 68-D7-0070, Alpha-Gamma Technologies Inc., Raleigh, North Carolina, April 2000.
3.1-20 EMISSION FACTORS 4/00
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3.2 Natural Gas-fired Reciprocating Engines
3.2.1 General1"3
Most natural gas-fired reciprocating engines are used in the natural gas industry at pipeline
compressor and storage stations and at gas processing plants. These engines are used to provide
mechanical shaft power for compressors and pumps. At pipeline compressor stations, engines are used to
help move natural gas from station to station. At storage facilities, they are used to help inject the natural
gas into high pressure natural gas storage fields. At processing plants, these engines are used to transmit
fuel within a facility and for process compression needs (e.g., refrigeration cycles). The size of these
engines ranges from 50 brake horsepower (bhp) to 11,000 bhp. In addition, some engines in service are
50 - 60 years old and consequently have significant differences in design compared to newer engines,
resulting in differences in emissions and the ability to be retrofitted with new parts or controls.
At pipeline compressor stations, reciprocating engines are used to power reciprocating
compressors that move compressed natural gas (500 - 2000 psig) in a pipeline. These stations are spaced
approximately 50 to 100 miles apart along a pipeline that stretches from a gas supply area to the market
area. The reciprocating compressors raise the discharge pressure of the gas in the pipeline to overcome
the effect of frictional losses in the pipeline upstream of the station, in order to maintain the required
suction pressure at the next station downstream or at various downstream delivery points. The volume of
gas flowing and the amount of subsequent frictional losses in a pipeline are heavily dependent on the
market conditions that vary with weather and industrial activity, causing wide pressure variations. The
number of engines operating at a station, the speed of an individual engine, and the amount of individual
engine horsepower (load) needed to compress the natural gas is dependent on the pressure of the
compressed gas received by the station, the desired discharge pressure of the gas, and the amount of gas
flowing in the pipeline. Reciprocating compressors have a wider operating bandwidth than centrifugal
compressors, providing increased flexibility in varying flow conditions. Centrifugal compressors
powered by natural gas turbines are also used in some stations and are discussed in another section of this
document.
A compressor in storage service pumps gas from a low-pressure storage field (500 - 800 psig) to
a higher pressure transmission pipeline (700 -1000 psig) and/or pumps gas from a low-pressure
transmission line (500 - 800 psig) to a higher pressure storage field (800 - 2000 psig).
Storage reciprocating compressors must be flexible enough to allow operation across a wide
band of suction and discharge pressures and volume variations. The compressor must be able to
compress at high compression ratios with low volumes and compress at low compression ratios with high
volumes. These conditions require varying speeds and load (horsepower) conditions for the
reciprocating engine powering the reciprocating compressor.
Reciprocating compressors are used at processing plants for process compression needs (e.g.
refrigeration cycles). The volume of gas compressed varies, but the pressure needed for the process is
more constant than the other two cases mentioned above.
3.2.2 Process Description "
Natural gas-fired reciprocating engines are separated into three design classes: 2-cycle (stroke)
lean-burn, 4-stroke lean-burn, and 4-stroke rich-bum. Two-stroke engines complete the power cycle in a
7/00 Stationary Internal Combustion Sources 3.2-1
-------
single crankshaft revolution as compared to the two crankshaft revolutions required for 4-stroke engines.
All engines in these categories are spark-ignited.
In a 2-stroke engine, the air-to-fuel charge is injected with the piston near the bottom of the
power stroke. The intake ports are then covered or closed, and the piston moves to the top of the
cylinder, compressing the charge. Following ignition and combustion, the power stroke starts with the
downward movement of the piston. As the piston reaches the bottom of the power stroke, exhaust ports
or valves are opened to exhaust, or scavenge, the combustion products, and a new air-to-fuel charge is
injected. Two-stroke engines may be turbocharged using an exhaust-powered turbine to pressurize the
charge for injection into the cylinder and to increase cylinder scavenging. Non-turbocharged engines
may be either blower scavenged or piston scavenged to improve removal of combustion products.
Historically, 2-stroke designs have been widely used in pipeline applications. However, current industry
practices reflect a decline in the usage of new 2-stroke engines for stationary applications.
Four-stroke engines use a separate engine revolution for the intake/compression cycle and the
power/exhaust cycle. These engines may be either naturally aspirated, using the suction from the piston
to entrain the air charge, or turbocharged, using an exhaust-driven turbine to pressurize the charge.
Turbocharged units produce a higher power output for a given engine displacement, whereas naturally
aspirated units have lower initial costs and require less maintenance.
Rich-burn engines operate near the stoichiometric air-to-fuel ratio (16:1) with exhaust excess
oxygen levels less than 4 percent (typically closer to 1 percent). Additionally, it is likely that the
emissions profile will be considerably different for a rich-burn engine at 4 percent oxygen than when
operated closer to stoichiometric conditions. Considerations such as these can impact the quantitative
value of the emission factor presented. It is also important to note that while rich-bum engines may
operate, by definition, with exhaust oxygen levels as high as 4 percent, in reality, most will operate
within plus or minus 1 air-to-fuel ratio of stoichiometry. Even across this narrow range, emissions will
vary considerably, sometimes by more than an order of magnitude. Air-to-fuel ratios were not provided
in the gathered emissions data used to develop the presented factors.
Lean-bum engines may operate up to the lean flame extinction limit, with exhaust oxygen levels
of 12 percent or greater. The air to fuel ratios of lean-burn engines range from 20:1 to 50:1 and are
typically higher than 24:1. The exhaust excess oxygen levels of lean-burn engines are typically around 8
percent, ranging from 4 to 17 percent. Some lean-burn engines are characterized as clean-burn engines.
The term "clean-bum" technology is a registered trademark of Cooper Energy Systems and refers to
engines designed to reduce NOX by operating at high air-to-fuel ratios. Engines operating at high air-to-
fuel ratios (greater than 30:1) may require combustion modification to promote stable combustion with
the high excess air. These modifications may include a turbo charger or a precombustion chamber
(PCC). A turbo charger is used to force more air into the combustion chamber, and a PCC is used to
ignite a fuel-rich mixture that propagates into the main cylinder and ignites the very lean combustion
charge. Lean-burn engines typically have lower oxides of nitrogen (NOX) emissions than rich-burn
engines.
3.2.3 Emissions
The primary criteria pollutants from natural gas-fired reciprocating engines are oxides of
nitrogen (NOX), carbon monoxide (CO), and volatile organic compounds (VOC). The formation of
nitrogen oxides is exponentially related to combustion temperature in the engine cylinder. The other
pollutants, CO and VOC species, are primarily the result of incomplete combustion. Particulate matter
(PM) emissions include trace amounts of metals, non-combustible inorganic material, and condensible,
3.2-2 EMISSION FACTORS 7/00
-------
semi-volatile organics which result from volatized lubricating oil, engine wear, or from products of
incomplete combustion. Sulfur oxides are very low since sulfur compounds are removed from natural
gas at processing plants. However, trace amounts of sulfur containing odorant are added to natural gas at
city gates prior to distribution for the purpose of leak detection.
It should be emphasized that the actual emissions may vary considerably from the published
emission factors due to variations in the engine operating conditions. This variation is due to engines
operating at different conditions, including air-to-fuel ratio, ignition timing, torque, speed, ambient
temperature, humidity, and other factors. It is not unusual to test emissions from two identical engines in
the same plant, operated by the same personnel, using the same fuel, and have the test results show
significantly different emissions. This variability in the test data is evidenced in the high relative
standard deviation reported in the data set.
3.2.3.1 Nitrogen Oxides -
Nitrogen oxides are formed through three fundamentally different mechanisms. The principal
mechanism of NOX formation with gas-fired engines is thermal NOX. The thermal NOX mechanism
occurs through the thermal dissociation and subsequent reaction of nitrogen (N2) and oxygen (O2)
molecules in the combustion air. Most NOX formed through the thermal NOX mechanism occurs in high-
temperature regions in the cylinder where combustion air has mixed sufficiently with the fuel to produce
the peak temperature fuel/air interface. The second mechanism, called prompt NOX, occurs through early
reactions of nitrogen molecules in the combustion air and hydrocarbon radicals from the fuel. Prompt
NOX reactions occur within the flame and are usually negligible compared to the level of NOX formed
through the thermal NOX mechanism. The third mechanism, fuel NOX, stems from the evolution and
reaction of fuel-bound nitrogen compounds with oxygen. Natural gas has negligible chemically bound
fuel nitrogen (although some molecular nitrogen is present).
Essentially all NOX formed in natural gas-fired reciprocating engines occurs through the thermal
NOX mechanism. The formation of NOX through the prompt NOX mechanism may be significant only
under highly controlled situations in rich-burn engines when the thermal NOX mechanism is suppressed.
The rate of NOX formation through the thermal NOX mechanism is highly dependent upon the
stoichiometric ratio, combustion temperature, and residence time at the combustion temperature.
Maximum NOX formation occurs through the thermal NOX mechanism near the stoichiometric air-to-fuel
mixture ratio since combustion temperatures are greatest at this air-to-fuel ratio.
3.2.3.2 Carbon Monoxide and Volatile Organic Compounds -
CO and VOC emissions are both products of incomplete combustion. CO results when there is
insufficient residence time at high temperature to complete the final step in hydrocarbon oxidation. In
reciprocating engines, CO emissions may indicate early quenching of combustion gases on cylinder walls
or valve surfaces. The oxidation of CO to carbon dioxide (C02) is a slow reaction compared to most
hydrocarbon oxidation reactions.
The pollutants commonly classified as VOC can encompass a wide spectrum of volatile organic
compounds mat are photoreactive in the atmosphere. VOC occur when some of the gas remains
unburned or is only partially burned during the combustion process. With natural gas, some organics are
carryover, unreacted, trace constituents of the gas, while others may be pyrolysis products of the heavier
hydrocarbon constituents. Partially burned hydrocarbons result from poor air-to-fuel mixing prior to, or
during, combustion, or incorrect air-to-fuel ratios in the cylinder during combustion due to
maladjustment of the engine fuel system. Also, low cylinder temperature may yield partially burned
hydrocarbons due to excessive cooling through the walls, or early cooling of the gases by expansion of
the combustion volume caused by piston motion before combustion is completed.
7/00 Stationary Internal Combustion Sources 3.2-3
-------
3.2.3.3 Paniculate Matter4 -
PM emissions result from carryover of noncombustible trace constituents in the fuel and
lubricating oil and from products of incomplete combustion. Emission of PM from natural gas-fired
reciprocating engines are generally minimal and comprise fine filterable and condensible PM. Increased
PM emissions may result from poor air-to-fuel mixing or maintenance problems.
3.2.3.4 Carbon Dioxide, Methane, and Nitrous Oxide5 -
Carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) are referred to as greenhouse
gases. Such gases are largely transparent to incoming solar radiation; however, they absorb infrared
radiation re-emitted by the Earth. Where available, emission factors for these pollutants are presented in
the emission factors tables of this section.
3.2.4 Control Technologies
Three generic control techniques have been developed for reciprocating engines: parametric
controls (timing and operating at a leaner air-to-fuel ratio); combustion modifications such as advanced
engine design for new sources or major modification to existing sources (clean-burn cylinder head
designs and prestratified charge combustion for rich-burn engines); and postcombustion catalytic controls
installed on the engine exhaust system. Post-combustion catalytic technologies include selective
catalytic reduction (SCR) for lean-burn engines, nonselective catalytic reduction (NSCR) for rich-burn
engines, and CO oxidation catalysts for lean-burn engines.
3.2.4.1 Control Techniques for 4-Cycle Rich-burn Engines ' -
Nonselective Catalytic Reduction (NSCR) -
This technique uses the residual hydrocarbons and CO in the rich-burn engine exhaust as a
reducing agent for NOX. In an NSCR, hydrocarbons and CO are oxidized by 02 and NOX. The excess
hydrocarbons, CO, and NOX pass over a catalyst (usually a noble metal such as platinum, rhodium, or
palladium) that oxidizes the excess hydrocarbons and CO to H2O and CO2, while reducing NOX to N2.
NOX reduction efficiencies are usually greater than 90 percent, while CO reduction efficiencies are
approximately 90 percent.
The NSCR technique is effectively limited to engines with normal exhaust oxygen levels of
4 percent or less. This includes 4-stroke rich-burn naturally aspirated engines and some 4-stroke rich-
burn turbocharged engines. Engines operating with NSCR require tight air-to-fuel control to maintain
high reduction effectiveness without high hydrocarbon emissions. To achieve effective NOX reduction
performance, the engine may need to be run with a richer fuel adjustment than normal. This exhaust
excess oxygen level would probably be closer to 1 percent. Lean-burn engines could not be retrofitted
with NSCR control because of the reduced exhaust temperatures.
Prestratified Charge -
Prestratified charge combustion is a retrofit system that is limited to 4-stroke carbureted natural
gas engines. In this system, controlled amounts of air are introduced into the intake manifold in a
specified sequence and quantity to create a fuel-rich and fuel-lean zone. This stratification provides both
a fuel-rich ignition zone and rapid flame cooling in the fuel-lean zone, resulting in reduced formation of
NOX. A prestratified charge kit generally contains new intake manifolds, air hoses, filters, control valves,
and a control system.
3.2-4 EMISSION FACTORS 7/00
-------
4 6
3.2.4.2 Control Techniques for Lean-burn Reciprocating Engines ' -
Selective Catalytic Reduction ' -
Selective catalytic reduction is a postcombustion technology that has been shown to be effective
in reducing NOX in exhaust from lean-burn engines. An SCR system consists of an ammonia storage,
feed, and injection system, and a catalyst and catalyst housing. Selective catalytic reduction systems
selectively reduce NOX emissions by injecting ammonia (either in the form of liquid anhydrous ammonia
or aqueous ammonium hydroxide) into the exhaust gas stream upstream of the catalyst. Nitrogen oxides,
NH3, and O2 react on the surface of the catalyst to form N2 and H20. For the SCR system to operate
properly, the exhaust gas must be within a particular temperature range (typically between 450 and
850°F). The temperature range is dictated by the catalyst (typically made from noble metals, base metal
oxides such as vanadium and titanium, and zeolite-based material). Exhaust gas temperatures greater
than the upper limit (850 °F) will pass the NOX and ammonia unreacted through the catalyst. Ammonia
emissions, called NH3 slip, are a key consideration when specifying a SCR system. SCR is most suitable
for lean-bum engines operated at constant loads, and can achieve efficiencies as high as 90 percent. For
engines which typically operate at variable loads, such as engines on gas transmission pipelines, an SCR
system may not function effectively, causing either periods of ammonia slip or insufficient ammonia to
gain the reductions needed.
Catalytic Oxidation -
Catalytic oxidation is a postcombustion technology that has been applied, in limited cases, to
oxidize CO in engine exhaust, typically from lean-burn engines. As previously mentioned, lean-burn
technologies may cause increased CO emissions. The application of catalytic oxidation has been shown
to be effective in reducing CO emissions from lean-burn engines. In a catalytic oxidation system, CO
passes over a catalyst, usually a noble metal, which oxidizes the CO to CO2 at efficiencies of
approximately 70 percent for 2SLB engines and 90 percent for 4SLB engines.
3.2.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the Clearinghouse for
Inventories/Emission Factors (CHIEF) electronic bulletin board (919-541-5742), or on the new Emission
Factor and Inventory Group (EFIG) home page (http://www.epa.gov/ttn/chief).
Supplement A, February 1996
• In the table for uncontrolled natural gas prime movers, the Source Classification Code
(SCC) for 4-cycle lean-burn was changed from 2-01-002-53 to 2-02-002-54. The SCC
for 4-cycle rich-burn was changed from 2-02-002-54 to 2-02-02-002-53.
• An SCC (2-02-002-53) was provided for 4-cycle rich-burn engines, and the "less than"
symbol (<) was restored to the appropriate factors.
Supplement B, October 1996
• The introduction section was revised.
• Text was added concerning process description of turbines.
7/00 Stationary Internal Combustion Sources 3.2-5
-------
Text concerning emissions and controls was revised.
References in various tables were editorially corrected.
The inconsistency between a CO2 factor in the table and an equation in the footnote was
corrected.
Supplement F, July 2000
Turbines used for natural gas compression were removed from this section and combined
with utility turbines in Section 3.1. Section 3.2 now only contains information on natural
gas-fired reciprocating engines.
All emission factors were updated based on emissions data points taken from 70
emission reports containing over 400 source tests. Many new emission factors have been
incorporated in this section for speciated organic compounds, including hazardous air
pollutants.
3.2-6 EMISSION FACTORS 7/00
-------
TABLE 3.2-1 UNCONTROLLED EMISSION FACTORS FOR 2-STROKE LEAN-BURN ENGINES
(SCC 2-02-002-52)
Pollutant
Emission Factor
(Ib/MMBtu)
(fuel input)
Emission Factor
Rating
Criteria Pollutants and Greenhouse Gases
NOXC 90 - 105% Load
A
NOXC <90% Load
A
COC 90 -105% Load
CO° <90% Load
CO/
SO2e
TOCf
Methane8
voch
PM10 (filterable)1
PM2.5 (filterable)1
PM Condensable'
3.17E+00
1.94E+00
3.86 E-01
3.53 E-01
1.10E+02
5.88 E-04
1.64E+00
1.45E+00
1.20 E-01
3.84E-02
3.84 E-02
9.91 E-03
A
A
A
A
A
A
A
C
C
C
C
E
Trace Organic Compounds
1 , 1 ,2,2-Tetrachloroethanek
1 , 1 ,2-Trichloroethanek
1 ,1 -Dichloroethane
1 ,2,3-Trimethylbenzene
1 ,2,4-Trimethylbenzene
1 ,2-Dichloroethane
1 ,2-Dichloropropane
1,3,5-Trimethylbenzene
1,3 -Butadiene
1 ,3-Dichloropropene
2,2,4-Trimethylpentanek
2-Methylnaphthalene
Acenaphthene
6.63 E-05
5.27 E-05
3.91 E-05
3.54 E-05
1.11 E-04
4.22 E-05
4.46 E-05
1.80 E-05
8.20 E-04
4.38 E-05
8.46 E-04
2.14 E-05
1.33E-06
C
C
C
D
C
D
C
D
D
C
B
C
C
7/00
Stationary Internal Combustion Sources
3.2-7
-------
Table 3.2-1. UNCONTROLLED EMISSION FACTORS FOR 2-STROKE LEAN-BURN
ENGINES
(Continued)
Pollutant
Acenaphthylene
kl
Acetaldehyde '
Acroleink>1
Anthracene
Benz(a)anthracene
Benzene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(e)pyrene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Biphenyl
Butane
Butyr/Isobutyraldehyde
Carbon Tetrachloride
Chlorobenzene
Chloroform
Chrysene
Cyclohexane
Cyclopentane
Ethane
Ethylbenzene
Ethylene Dibromide
Fluoranthene
Fluorene
kl
Formaldehyde '
Emission Factor
(Ib/MMBtu)
(fuel input)
3. 17 E-06
7.76 E-03
7.78 E-03
7.1 8 E-07
3.36 E-07
1.94 E-03
5.68 E-09
8.51 E-09
2.34 E-08
2.48 E-08
4.26 E-09
3.95 E-06
4.75 E-03
4.37 E-04
6.07 E-05
4.44 E-05
4.71 E-05
6.72 E-07
3.08 E-04
9.47 E-05
7.09 E-02
1.08 E-04
7.34 E-05
3.61 E-07
1.69 E-06
5.52 E-02
Emission Factor
Rating
C
A
A
C
C
A
D
D
D
D
D
C
C
C
C
C
C
C
C
C
A
B
C
C
C
A
3.2-8
EMISSION FACTORS
7/00
-------
Table 3.2-1. UNCONTROLLED EMISSION FACTORS FOR 2-STROKE LEAN-BURN ENGINES
(Concluded)
Pollutant
Indeno(l ,2,3 -c,d)pyrene
Isobutane
Methanol
Methylcyclohexane
Methylene Chloride
n-Hexane
n-Nonane
n-Octane
n-Pentane
Naphthalene
PAHk
Perylenek
Phenanthrene
Phenolk
Propane
Pyrenek
Styrenek
Toluene
Vinyl Chloridek
Xylenek
Emission Factor
(lb/MMBtu)b
(fuel input)
9.93 E-09
3.75 E-03
2.48 E-03
3.38 E-04
1.47 E-04
4.45 E-04
3.08 E-05
7.44 E-05
1.53 E-03
9.63 E-05
1.34 E-04
4.97 E-09
3.53 E-06
4.21 E-05
2.87 E-02
5.84 E-07
5.48 E-05
9.63 E-04
2.47 E-05
2.68 E-04
Emission Factor
Rating
D
C
A
C
C
C
C
C
C
C
D
D
C
C
C
C
A
A
C
A
Reference 7. Factors represent uncontrolled levels. ForNOx, CO, and PM10,
"uncontrolled" means no combustion or add-on controls; however, the factor may
include turbocharged units. For all other pollutants, "uncontrolled" means no oxidation
control; the data set may include units with control techniques used for NOx control,
such as PCC and SCR for lean burn engines, and PSC for rich bum engines. Factors are
based on large population of engines. Factors are for engines at all loads, except as
indicated. SCC = Source Classification Code. TOC = Total Organic Compounds.
PM10 = Paniculate Matter < 10 microns (/um) aerodynamic diameter. A "<" sign in
front of a factor means that the corresponding emission factor is based on one-half of the
method detection limit.
' Emission factors were calculated in units of (Ib/MMBtu) based on procedures in EPA
7/00
Stationary Internal Combustion Sources
3.2-9
-------
Method 19. To convert from (Ib/MMBtu) to (lb/106 scf), multiply by the heat content of
the fuel. If the heat content is not available, use 1020 Btu/scf. To convert from
(Ib/MMBtu) to (Ib/hp-hr) use the following equation:
Ib/hp-hr = (Ib/MMBtu, (heat input, MMBtu/hr, , I/operating HP, 1/hp,
c Emission tests with unreported load conditions were not included in the data set.
d Based on 99.5% conversion of the fuel carbon to CO2. CO2 [Ib/MMBtu] =
(3.67)(%CON)(C)(D)(l/h), where %CON = percent conversion of fuel carbon to CO2,
C = carbon content of fuel by weight (0.75), D = density of fuel, 4.1 E+04 lb/106 scf, and
h = heating value of natural gas (assume 1020 Btu/scf at 60 °F).
e Based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas
of 2,000 gr/106 scf.
Emission factor for TOC is based on measured emission levels of 43 tests.
8 Emission factor for methane is determined by subtracting the VOC and ethane emission
factors from the TOC emission factor. Measured emission factor for methane compares
well with the calculated emission factor, 1.48 Ib/MMBtu vs. 1.45 Ib/MMBtu,
respectively.
VOC emission factor is based on the sum of the emission factors for all speciated
organic compounds less ethane and methane.
Considered < 1 /^m in aerodynamic diameter. Therefore, for filterable PM emissions,
. PMlO(filterable) = PM2.5(filterable).
J No data were available for condensable PM emissions. The presented emission factor
reflects emissions from 4SLB engines.
k Hazardous Air Pollutant as defined by Section 112(b) of the Clean Air Act.
For lean burn engines, aldehyde emissions quantification using CARB 430 may reflect
interference with the sampling compounds due to the nitrogen concentration in the stack.
The presented emission factor is based on FTIR measurements. Emissions data based on
CARB 430 are available in the background report.
3.2-10 EMISSION FACTORS 7/00
-------
Table 3.2-2. UNCONTROLLED EMISSION FACTORS FOR 4-STROKE LEAN-BURN ENGINES
(SCC 2-02-002-54)
Pollutant
Emission Factor
(Ib/MMBtu)
(fuel input)
Emission Factor
Rating
Criteria Pollutants and Greenhouse Gases
NOx°90-105%Load
NOX° <90% Load
C0° 90 -105% Load
COC <90% Load
C02d
S02e
TOCf
Methane8
voch
PM 10 (filterable)1
PM2.5 (filterable)1
PM Condensable^
4.08 E+00
8.47 E-01
3.17 E-01
5.57 E-01
1.10E+02
5.88 E-04
1.47 E+00
1.25 E+00
1.18 E-01
7.71 E-05
7.71 E-05
9.91 E-03
B
B
C
B
A
A
A
C
C
D
D
D
Trace Organic Compounds
1 , 1 ,2,2-Tetrachloroethane
1 , 1 ,2-Trichloroethane
1 , 1 -Dichloroethane
1 ,2,3 -Trimethylbenzene
1 ,2,4-Trimethylbenzene
1 ,2 -Dichloroethane
1 ,2-Dichloropropane
1 ,3,5-Trimethylbenzene
l,3-Butadienek
1 ,3 -Dichloropropene
2-Methylnaphthalenek
2,2,4-Trimethylpentane
Acenaphthene
<4.00 E-05
<3. 18 E-05
<2.36 E-05
2.30 E-05
1.43 E-05
<2.36 E-05
<2.69 E-05
3.38 E-05
2.67E-04
<2.64 E-05
3.32 E-05
2.50 E-04
1.25E-06
E
E
E
D
C
E
E
D
D
E
C
C
C
7/00
Stationary Internal Combustion Sources
3.2-11
-------
Table 3.2-2. UNCONTROLLED EMISSION FACTORS FOR 4-STROKE LEAN-BURN ENGINES
(Continued)
Pollutant
Acenaphthylene
Acetaldehydek>1
Acroleink>1
Benzene
i,
Benzo(b)fluoranthene
Benzo(e)pyrene
Benzo(g,h,i)perylene
Biphenyl
Butane
Butyr/Isobutyraldehyde
Carbon Tetrachloride
Chlorobenzene
Chloroethane
Chloroformk
Chrysenek
Cyclopentane
Ethane
Ethylbenzene
Ethylene Dibromide
Fluoranthene
Fluorenek
kl
Formaldehyde '
Methanolk
Methylcyclohexane
Methylene Chloride
n-Hexane
n-Nonane
Emission Factor
(lb/MMBtu)b
(fuel input)
5.53 E-06
8.36 E-03
5. 14 E-03
4.40 E-04
1.66E-07
4.15E-07
4.14E-07
2. 12 E-04
5.41 E-04
1.01 E-04
<3.67 E-05
<3.04 E-05
1.87 E-06
<2.85 E-05
6.93 E-07
2.27 E-04
1.05E-01
3. 97 E-05
<4.43 E-05
1.11 E-06
5.67 E-06
5.28 E-02
2.50 E-03
1.23 E-03
2.00 E-05
1.11 E-03
1.10 E-04
Emission Factor
Rating
C
A
A
A
D
D
D
D
D
C
E
E
D
E
C
C
C
B
E
C
C
A
B
C
C
C
C
3.2-12
EMISSION FACTORS
7/00
-------
Table 3.2-2. UNCONTROLLED EMISSION FACTORS FOR 4-STROKE LEAN-BURN
ENGINES
(Continued)
Pollutant
n-Octane
n-Pentane
Naphthalene
PAHk
Phenanthrene
Phenolk
Propane
Pyrene
Styrenek
Tetrachloroethane
Toluene
Vinyl Chloridek
Xylenek
Emission Factor
(lb/MMBtu)b
(fuel input)
3.51 E-04
2.60 E-03
7.44 E-05
2.69 E-05
1.04 E-05
2.40 E-05
4.19 E-02
1.36E-06
<2.36 E-05
2.48 E-06
4.08 E-04
1.49 E-05
1.84 E-04
Emission Factor
Rating
C
C
C
D
D
D
C
C
E
D
B
C
B
Reference 7. Factors represent uncontrolled levels. For NOX, CO, and PM10,
"uncontrolled" means no combustion or add-on controls; however, the factor may include
turbocharged units. For all other pollutants, "uncontrolled" means no oxidation control;
the data set may include units with control techniques used for NOx control, such as PCC
and SCR for lean burn engines, and PSC for rich burn engines. Factors are based on large
population of engines. Factors are for engines at all loads, except as indicated. SCC =
Source Classification Code. TOC = Total Organic Compounds. PM-10 = Particulate
Matter < 10 microns (urn) aerodynamic diameter. A "<" sign in front of a factor means
that the corresponding emission factor is based on one-half of the method detection limit.
' Emission factors were calculated in units of (Ib/MMBtu) based on procedures in EPA
Method 19. To convert from (Ib/MMBtu) to (lb/106 scf), multiply by the heat content of
the fuel. If the heat content is not available, use 1020 Btu/scf. To convert from
(Ib/MMBtu) to (Ib/hp-hr) use the following equation:
Ib/hp-hr = (Ib/MMBtu, (heat input, MMBtu/hr, (I/operating HP, 1/hp,
Emission tests with unreported load conditions were not included in the data set.
! Based on 99.5% conversion of the fuel carbon to C02. C02 [Ib/MMBtu] =
(3.67)(%CON)(C)(D)(l/h), where %CON = percent conversion of fuel carbon to CO2,
C = carbon content of fuel by weight (0.75), D = density of fuel, 4.1 E+04 lb/106 scf, and
7/00
Stationary Internal Combustion Sources
3.2-13
-------
h = heating value of natural gas (assume 1020 Btu/scf at 60 °F).
Based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of
2,000 gr/106scf.
Emission factor for TOC is based on measured emission levels from 22 source tests.
8 Emission factor for methane is determined by subtracting the VOC and ethane emission
factors from the TOC emission factor. Measured emission factor for methane compares
well with the calculated emission factor, 1.31 Ib/MMBtu vs. 1.25 Ib/MMBtu, respectively.
VOC emission factor is based on the sum of the emission factors for all speciated organic
compounds less ethane and methane.
Considered < 1 /um in aerodynamic diameter. Therefore, for filterable PM emissions,
. PMlO(filterable) = PM2.5(filterable).
J PM Condensable = PM Condensable Inorganic + PM-Condensable Organic
Hazardous Air Pollutant as defined by Section 112(b) of the Clean Air Act.
For lean burn engines, aldehyde emissions quantification using CARB 430 may reflect
interference with the sampling compounds due to the nitrogen concentration in the stack.
The presented emission factor is based on FTIR measurements. Emissions data based on
CARB 430 are available in the background report.
3.2-14 EMISSION FACTORS 7/00
-------
Table 3.2-3. UNCONTROLLED EMISSION FACTORS FOR 4-STROKE RICH-BURN
ENGINES3
(SCC 2-02-002-53)
Pollutant
Emission Factor
(lb/MMBtu)b
(fuel input)
Emission Factor
Rating
Criteria Pollutants and Greenhouse Gases
NOXC 90 - 105% Load
A
NOX° <90% Load
CO° 90 -105% Load
CO° <90% Load
C02d
so2e
TOCf
Methane8
voch
PM10(filterable)lJ
PM2.5 (filterable)1
PM Condensable1"
2.21 E+00
2.27 E+00
3. 72 E+00
3.51 E+00
1.10E+02
5.88 E-04
3.58 E-01
2.30 E-01
2.96 E-02
9.50 E-03
9.50 E-03
9.91 E-03
A
C
A
C
A
A
C
C
C
E
E
E
Trace Organic Compounds
1 , 1 ,2,2-Tetrachloroethane1
1 , 1 ,2-Trichloroethane1
1 , 1 -Dichloroethane
1 ,2-Dichloroethane
1 ,2-Dichloropropane
1,3-Butadiene1
1 ,3 -Dichloropropene
Acetaldehyde1'"1
Acrolein '
Benzene
Butyr/isobutyraldehyde
Carbon Tetrachloride
2.53 E-05
<1.53E-05
<1.13 E-05
<1. 13 E-05
<1. 30 E-05
6.63 E-04
< 1.27 E-05
2.79 E-03
2.63 E-03
1.58 E-03
4.86 E-05
<1.77E-05
C
E
E
E
E
D
E
C
C
B
D
E
7/00
Stationary Internal Combustion Sources
3.2-15
-------
Table 3.2-3. UNCONTROLLED EMISSION FACTORS FOR 4-STROKE RICH-BURN ENGINES
(Concluded)
Pollutant
Chlorobenzene
Chloroform
Ethane"
Ethylbenzene
Ethylene Dibromide
Formaldehyde 'm
Methanol
Methylene Chloride
Naphthalene
PAH1
Styrene
Toluene
Vinyl Chloride
Xylene
Emission Factor
(lb/MMBtu)b
(fuel input)
<1.29E-05
<1.37E-05
7.04 E-02
<2.48 E-05
<2.13 E-05
2.05 E-02
3.06 E-03
4. 12 E-05
<9.71 E-05
1.41 E-04
<1. 19 E-05
5.58 E-04
<7.18E-06
1.95 E-04
Emission Factor
Rating
E
E
C
E
E
A
D
C
E
D
E
A
E
A
Reference 7. Factors represent uncontrolled levels. For NOX, CO, and PM-10,
"uncontrolled" means no combustion or add-on controls; however, the factor may
include turbocharged units. For all other pollutants, "uncontrolled" means no oxidation
control; the data set may include units with control techniques used for NOx control,
such as PCC and SCR for lean burn engines, and PSC for rich burn engines. Factors are
based on large population of engines. Factors are for engines at all loads, except as
indicated. SCC = Source Classification Code. TOC = Total Organic Compounds.
PM10 = Paniculate Matter < 10 microns Cum) aerodynamic diameter. A "<" sign in
front of a factor means that the corresponding emission factor is based on one-half of the
method detection limit.
Emission factors were calculated in units of (Ib/MMBtu) based on procedures in EPA
Method 19. To convert from (Ib/MMBtu) to (lb/106 sci), multiply by the heat content of
the fuel. If the heat content is not available, use 1020 Btu/scf. To convert from
(Ib/MMBtu) to (Ib/hp-hr) use the following equation:
Ib/hp-hr =
(heat input, MMBtu/hr, ,1/operating HP, 1/hp,
° Emission tests with unreported load conditions were not included in the data set.
d Based on 99.5% conversion of the fuel carbon to CO2. C02 [Ib/MMBtu] =
(3.67)(%CON)(C)(D)(l/h), where %CON = percent conversion of fuel carbon to CO2,
3.2-16
EMISSION FACTORS
7/00
-------
C = carbon content of fuel by weight (0.75), D = density of fuel, 4.1 E+04 lb/106 scf,
and h = heating value of natural gas (assume 1020 Btu/scf at 60 °F).
e Based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas
of 2,000 gr/106scf.
Emission factor for TOC is based on measured emission levels from 6 source tests.
8 Emission factor for methane is determined by subtracting the VOC and ethane emission
factors from the TOC emission factor.
VOC emission factor is based on the sum of the emission factors for all speciated
organic compounds. Methane and ethane emissions were not measured for this engine
category.
1 No data were available for uncontrolled engines. PM10 emissions are for engines
equipped with a PCC.
J Considered < 1 ^ni in aerodynamic diameter. Therefore, for filterable PM emissions,
PMlO(filterable) = PM2.5(filterable).
k No data were available for condensable emissions. The presented emission factor
reflects emissions from 4SLB engines.
1 Hazardous Air Pollutant as defined by Section 112 (b) of the Clean Air Act.
m For rich-burn engines, no interference is suspected in quantifying aldehyde
emissions. The presented emission factors are based on FTIR and CARB 430
emissions data measurements.
" Ethane emission factor is determined by subtracting the VOC emission factor from
the NMHC emission factor.
7/00 Stationary Internal Combustion Sources 3.2-17
-------
References For Section 3.2
1. Engines, Turbines, And Compressors Directory, American Gas Association, Catalog
#XF0488.
2. Standards Support And Environmental Impact Statement, Volume I: Stationary Internal
Combustion Engines, EPA-450/2-78-125a, U. S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC, July 1979.
3. Alternative Control Techniques Document - NOX Emissions From Stationary
Reciprocating Engines, EPA-453/R-93-032, July 1993.
4. Handbook- Control Technologies For Hazardous Air Pollutants, EPA-625/6-91-014,
June 1991.
5. Limiting Net Greenhouse Gas Emissions In The United States, Volume II: Energy
Responses, Report for the Office of Environmental Analysis, Office of Policy, Planning
and Analysis, Department of Energy (DOE), DOE/PE-0101 Volume II, September 1991.
6. C. Castaldini, NOX Reduction Technologies For Natural Gas Industry Prime Movers,
GRI-90/0215, Gas Research Institute, Chicago, IL, August 1990.
7. Emission Factor Documentation for AP-42 Section 3.2, Natural Gas-Fired
Reciprocating Engines, EPA Contract No. 68-D2-0160, Alpha-Gamma Technologies,
Inc., Raleigh, North Carolina, July 2000.
3.2-18 EMISSION FACTORS 7/00
-------
12.2 Coke Production
12.2.1 General
Metallurgical coke is produced by destructive distillation of coal in coke ovens. Prepared coal is
"coked", or heated in an oxygen-free atmosphere until all volatile components in the coal evaporate. The
material remaining is called coke.
Most metallurgical coke is used in iron and steel industry processes such as blast furnaces, sinter
plants, and foundries to reduce iron ore to iron. Over 90 percent of the total metallurgical coke production
is dedicated to blast furnace operations.
Most coke plants are co-located with iron and steel production facilities. Coke demand is
dependent on the iron and steel industry. This represents a continuing decline from the about 40 plants that
were operating in 1987.
12.2.2 Process Description1-2
All metallurgical coke is produced using the "byproduct" method. Destructive distillation
("coking") of coal occurs in coke ovens without contact with air. Most U. S. coke plants use the Kopper-
Becker byproduct oven. These ovens must remain airtight under the cyclic stress of expansion and
contraction. Each oven has 3 main parts: coking chambers, heating chambers, and regenerative chambers.
All of the chambers are lined with refractory (silica) brick. The coking chamber has ports in the top for
charging of the coal.
A coke oven battery is a series of 10 to 100 coke ovens operated together. Figure 12.2-1 illustrates
a byproduct coke oven battery. Each oven holds between 9 to 32 megagrams (Mg) (10 to 35 tons) of coal.
Offtake flues on either end remove gases produced. Process heat comes from the combustion of gases
between the coke chambers. Individual coke ovens operate intermittently, with run times of each oven
coordinated to ensure a consistent flow of collectible gas. Approximately 40 percent of cleaned oven gas
(after the removal of its byproducts) is used to heat the coke ovens.
The rest is either used in other production processes related to steel production or sold. Coke oven gas is
the most common fuel for underfiring coke ovens.
A typical coke manufacturing process is shown schematically in Figure 12.2-2. Coke
manufacturing includes preparing, charging, and heating the coal; removing and cooling the coke product;
and cooling, cleaning, and recycling the oven gas.
Coal is prepared for coking by pulverizing so that 80 to 90 percent passes through a 3.2 millimeter
(1/8 inch) screen. Several types of coal may be blended to produce the desired properties, or to control the
expansion of the coal mixture in the oven. Water or oil may be added to adjust the density of the coal to
control expansion and prevent damage to the oven.
Coal may be added to the ovens in either a dry or wet state. Prepared wet coal is finely crushed
before charging to the oven. Flash-dried coal may be transported directly to the ovens by the hot gases
used for moisture removal. Wall temperatures should stay above 1100°C (2000 °F) during loading
operations and actual coking. The ports are closed after charging and sealed with luting ("mud") material.
9/00 Metallurgical Industry 12.2-1
-------
ffl
I
SO)
12.2-2
EMISSION FACTORS
9/00
-------
ICULATE
I
PARTICULATE PARTICULATE PART
L WATER] T
111 1
0
CULATE
t
1-
K
^
Ul
i-
_j
3
o-*
P
a.
t
ce
o
>-
a
<£
<
_i
BLENDED COAL
BUNKER
MIXING/
CRUSHING
SCREENING
(aCCMMOMO)
_i
<
O
O
5
<
a
STORAGE 1
PARTICULATE VOCs PARTICULATE PARTICULATE PARTICULATE
t SULFUR f t VOCs * VOCa *
1 "T 1 1 t 1 1 1
COKE
STORAGE
COKE CRUSHING
AND SCREENING
(80CMMOMS)
QUENCHING
POCMMOM*
COKE
REMOVAL
COKE OVEN
J
<£
8^
TAR &
AMMONIA
«-
*-
r~
COMBUSTION
GAS
TAR
EXTRACTOR
CONDENSER/
" EXHAUSTER
AMMONIA
SOLUTION
SPRAY
(0
<
O
_i
3
O
u_
CLEAN
COKE OVEN
COAL GAS
HYDROGEN
SULFIDE
-
SCRUBBING
TOWER
CO
_i
O
t-
z
o
~
«-
ABSORPTION
TOWER
NAPHTHALENE
AMMONIUM
SULFATE
-
-
CONDENSER
SATURATOR
9/00
Metallurgical Industry
12.2-3
-------
The blended coal mass is heated for 12 to 20 hours for metallurgical coke. Thermal energy from
the walls of the coke chamber heats the coal mass by conduction from the sides to the middle of the coke
chamber. During the coking process, the charge is in direct contact with the heated wall surfaces and
develops into an aggregate "plastic zone". As additional thermal energy is absorbed, the plastic zone
thickens and merges toward the middle of the charge. Volatile gases escape in front of the developing zone
due to heat progression from the side walls. The maximum temperature attained at the center of the coke
mass is usually 1100 to 1150°C (2000 to 2100°F). This distills all volatile matter from the coal mass and
forms a high-quality metallurgical coke.
After coking is completed (no volatiles remain), the coke in the chamber is ready to be removed.
Doors on both sides of the chamber are opened and a ram is inserted into the chamber. The coke is pushed
out of the oven in less than 1 minute, through the coke guide and into a quench car. After the coke is
pushed from the oven, the doors are cleaned and repositioned. The oven is then ready to receive another
charge of coal.
The quench car carrying the hot coke moves along the battery tracks to a quench tower where
approximately 1130 liters (L) of water per Mg of coke (270 gallons of water per ton) are sprayed onto the
coke mass to cool it from about 1100 to 80°C (2000 to 180°F) and to prevent it from igniting. The quench
car may rely on a movable hood to collect paniculate emissions, or it may have a scrubber car attached.
The car then discharges the coke onto a wharf to drain and continue cooling. Gates on the wharf are
opened to allow the coke to fall onto a conveyor that carries it to the crushing and screening station. After
sizing, coke is sent to the blast furnace or to storage.
The primary purpose of modern coke ovens is the production of quality coke for the iron and steel
industry. The recovery of coal chemicals is an economical necessity, as they equal approximately 35
percent of the value of the coal.
To produce quality metallurgical coke, a high-temperature carbonization process is used. High-
temperature carbonization, which takes place above 900°C (1650°F), involves chemical conversion of coal
into a mostly gaseous product. Gaseous products from high-temperature carbonization consist of
hydrogen, methane, ethylene, carbon monoxide, carbon dioxide, hydrogen sulfide, ammonia, and nitrogen.
Liquid products include water, tar, and crude light oil. The coking process produces approximately
338,000 L of coke oven gas (COG) per megagram of coal charged (10,800 standard cubic feet of COG per
ton).
During the coking cycle, volatile matter driven from the coal mass passes upward through cast iron
"goosenecks" into a common horizontal steel pipe (called the collecting main), which connects all the ovens
in series. This unpurified "foul" gas contains water vapor, tar, light oils, solid paniculate of coal dust,
heavy hydrocarbons, and complex carbon compounds. The condensable materials are removed from the
exhaust gas to obtain purified coke oven gas.
As it leaves the coke chamber, coke oven coal gas is initially cleaned with a weak ammonia spray,
which condenses some tar and ammonia from the gas. This liquid condensate flows down the collecting
main until it reaches a settling tank. Collected ammonia is used in the weak ammonia spray, while the rest
is pumped to an ammonia still. Collected coal tar is pumped to a storage tank and sold to tar distillers, or
used as fuel.
The remaining gas is cooled as it passes through a condenser and then compressed by an exhauster.
Any remaining coal tar is removed by a tar extractor, either by impingement against a metal surface or
collection by an electrostatic precipitator (ESP). The gas still contains 75 percent of original ammonia and
95 percent of the original light oils. Ammonia is removed by passing the gas through a saturator containing
12.2-4 EMISSION FACTORS 9/00
-------
a 5 to 10 percent solution of sulfuric acid. In the saturator, ammonia reacts with sulfuric acid to form
ammonium sulfate. Ammonium sulfate is then crystallized and removed. The gas is further cooled,
resulting in the condensation of naphthalene. The light oils are removed in an absorption tower containing
water mixed with "straw oil" (a heavy fraction of petroleum). Straw oil acts as an absorbent for the light
oils, and is later heated to release the light oils for recovery and refinement. The last cleaning step is the
removal of hydrogen sulfide from the gas. This is normally done in a scrubbing tower containing a solution
of ethanolamine (Girbotol), although several other methods have been used in the past. The clean coke
oven coal gas is used as fuel for the coke ovens, other plant combustion processes, or sold.
12.2.3 Emissions And Controls
Particulate, VOCs, carbon monoxide and other emissions originate from several byproduct coking
operations: (1) coal preparation, (2) coal preheating (if used), (3) coal charging, (4) oven leakage during
the coking period, (5) coke removal, (6) hot coke quenching and (7) underfire combustion stacks. Gaseous
emissions collected from the ovens during the coking process are subjected to various operations for
separating ammonia, coke oven gas, tar, phenol, light oils (benzene, toluene, xylene), and pyridine. These
unit operations are potential sources of VOC emissions. Small emissions may occur when transferring coal
between conveyors or from conveyors to bunkers. Figure 12.2-2 portrays major emission points from a
typical coke oven battery.
The emission factors available for coking operations for filterable paniculate, sulfur dioxide,
carbon monoxide, VOCs, nitrogen oxides, and ammonia are given in Tables 12.2-1 and 12.2-2. Tables
12.2-3 and 12.2-4 give size-specific emission factors for coking operations.
A few domestic plants preheat the coal to about 260°C (500°F) before charging, using a flash
drying column heated by the combustion of coke oven gas or by natural gas. The air stream that conveys
coal through the drying column usually passes through conventional wet scrubbers for particulate removal
before discharging to the atmosphere. Leaks occasionally occur from charge lids and oven doors during
pipeline charging due to the positive pressure. Emissions from the other methods are similar to conventional
wet charging.
Oven charging can produce significant emissions of particulate matter and VOCs from coal
decomposition if not properly controlled. Charging techniques can draw most charging emissions into the
battery collecting main. Effective control requires that goosenecks and the collecting main passages be
cleaned frequently to prevent obstructions.
During the coking cycle, VOC emissions from the thermal distillation process can occur through
poorly sealed doors, charge lids, offtake caps, collecting main, and cracks that may develop in oven
brickwork. Door leaks may be controlled by diligent door cleaning and maintenance, rebuilding doors, and,
in some plants, by manual application of lute (seal) material. Charge lid and offtake leaks may be
controlled by an effective patching and luting program. Pushing coke into the quench car is another major
source of particulate emissions. If the coke mass is not fully coked, VOCs and combustion products will
be emitted. Most facilities control pushing emissions by using mobile scrubber cars with hoods, shed
enclosures evacuated to a gas cleaning device, or traveling hoods with a fixed duct leading to a stationary
gas cleaner.
Coke quenching entrains particulate from the coke mass. In addition, dissolved solids from the
quench water may become entrained in the steam plume rising from the tower. Trace organic compounds
may also be present.
9/00 Metallurgical Industry 12.2-5
-------
12.2.4 Updates Since the Fifth Edition
Revisions to this section since the Fifth Edition release in January 1995 are summarized below.
Supplement F, April 2000
• Units for the emission factors provided in Tables 12.2-1 and 12.2-3 have been changed
from kg of pollutant/Mg of coke produced to kg of pollutant/Mg of coal charged. None of
the numerical values were changed.
• Units for the emission factors provided in Tables 12.2-2 and 12.2-4 have been changed
from Ib of pollutant/ton of coke produced to Ib of pollutant/ton of coal charged. None of
the numerical values were changed.
The October 1986 version of this section reported the emission factor units as Ib of pollutant/ton of coal
charged (kg of pollutant/Mg of coal charged). The January 1995 revision of this section did not change the
numerical value for any of the emission factors but, due to a formatting error, the units were mistakenly
reported as Ib of pollutant/ton of coke produced (kg of pollutant/Mg of coke produced). Thus the revisions
noted above correct errors to the January 1995 revision of this section.
September, 2000
In Table 12.2-4, the PM factors in Metric units were incorrectly transcribed into the
English unit table. This has been corrected. The PM factors in Table 12.2-4 now
accurately reflect the English unit factors from the Fourth Edition. Some additional SCC
codes were also added for the combustion stack and for oven charging.
More errors were found and corrected in Table 12.2-1. The PM factor for uncontrolled
combustion stack with an ESP (BFG) was corrected to "ND", and the PM factor for the
same unit with ESP (COG) was corrected to 0.055 kg/MG of coal charged.
The PM factors in all of the tables were labeled "filterable" to make the terminology
consistent with the present day convention.
12.2-6 EMISSION FACTORS 9/00
-------
H U <1
1
Eo H g
g'
^5 [T. CC
DJ ^^
s
II
6
u
w H H
0
on
IR|
|£s
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? i
||
§
TypeOfOperati
*
Z
z
z
S
s
S
<
z
2
g
Q
•n
0
o
^
8
Coal crushing (SCC 3-03-
With cyclone
^
S
^
i
S
e
^
p
*
^
i
o
~
£T
0
9
IGoal preheating (SCC 3-0
Uncontrolled'
t$
gg
11
gg
ii
ee
II
PP
z,i
II
ii
o o
m
Oven door leaks (SCC 3-C
Uncontrolled
o|
OP
d Z
II
gg
P P
o o
P P
<^n wi
CO CO
o o
o o
II
Si
m o
oo r^J
d d
^
o
S
Oven pushing (SCC 3-03-
Uncontrolled
With ESP«
III
ggg
III
iSi
P P P
o o o
p p p
fl f"J fl
o o o
o o o
III
ggg
P P O
^ >0
o o o
odd
t
With venturi scrubber11
With baghouseh
With mobile scrubber ca
^^
9
1 Quenching (SCC 3-03-001
Uncontrolled
II
§1
II
II
II
ee
II
ee
22
z z
^
p p
VD m
c~i d
Dirty water*
Clean water1"
With baffles
II
II
II
2 £
ii
ee
II
PP
xi xC
a
ii
ffl PQ
VD CS
d d
Dirty water*
Clean water1"
9/00
Metallurgical Industry
12.2-7
-------
g
o
•8
H
Z r^
O Q 9
oc H H
-jj CL, «
"oi
a
O
1
9 o g
oo H R
W ^
£
§gg
111
0
Z
S H P
W ^
S
log
1§ ^
w to
0
VI
EMISSION
FACTOR
RATING
^
-^ ^2
S "
^s '"S
pe Of Operation
£
•^ -<1 -^ -<1 <1 •£-*£-* ^-4 £*£-, £+
Q O O r^ O Q "^
z
£-*£*£*£-*<£*£-* &
gggggg S
imgl 1
gggggg $
li H li zi ^ I! z
gggggg g
Q 0 Q 0 |j |j |>
0 r- •?) CO R P P
p p Q
Tf rf 10 VO
_S
3
.0
&
a
^
T3
blast furnace gas.
Reference 1 . Filterable particulate is define
j,
Reference 23.
0
ao
"S
fi
e
£
o
0
1
^3
1
1
&
o
•a
_8
1 8
§ 3
% 2
&s
S ^
0 d
•8 >
w O
,0 o
'S«1
(U
g
S
J1
•~*
"*
G/
d"
!/5
(D
•S
"o
«3
60% is used in other operations where the r
not been desulfurized.
Reference 21, desulfurized COG.
Reference 22.
&. o"
Reference 23.
Defined as crushing and screening.
M »
12.2-8
EMISSION FACTORS
9/00
-------
lo z
1^
"a
0
1
w H P
i^S
pa *
u
o
z
C/3 fc-* H
o
p
§0°
li§
o
o
Eo H P
e-
o
1/1
111
II
0
Ul
o
a
o
^
<^
z
2
S
z
^
ee
z z
z z
QP
gz
SS
e e
g g
IS
z z
o o
-* m
,0-
Dirty water*
Clean water"
With baffles
%%
Q Q
z z
22
i-5 ^5
z z
s$
PP
z z
££
Q e
Z g
^
z z
m m
o •*
— 0
1 Dirty water*
Clean water"
9/00
Metallurgical Industry
12.2-9
-------
(N
(N
i&5
«
Q 0 0 0
p, 0< I.
oo oo TI-
CS o ^o
< < CQ Q O
Q
CC 3-0
ng
nes
is
o
E
R
D
12.2-10
EMISSION FACTORS
9/00
-------
Table 12.2-3. (Metric Units). SIZE-SPECIFIC EMISSION FACTORS
FOR COKE MANUFACTURING"
EMISSION FACTOR RATING: D (except as noted)
Process
Coal preheating (SCC 3-03-003-13)
Uncontrolled
Controlled with venturi scrubber
Oven charging sequential or stage0
(SCC 3-03-003-02)
Coke pushing (SCC 3-03-003-03)
Uncontrolled
Particle
Size
(Mm)b
0.5
1.0
2.0
2.5
5.0
10.0
15.0
0.5
1.0
2.0
2.5
5.0
10.0
15.0
0.5
1.0
2.0
2.5
5.0
10.0
15.0
0.5
1.0
2.0
2.5
5.0
10.0
15.0
Cumulative
Mass %
s Stated Size
44
48.5
55
59.5
79.5
97.5
99.9
100
78
80
83
84
88
94
96.5
100
13.5
25.2
33.6
39.1
45.8
48.9
49.0
100
3.1
7.7
14.8
16.7
26.6
43.3
50.0
100
Cumulative
Mass
Emission
Factors
0.8
0.8
1.0
1.0
1.4
1.7
1.7
1.7
0.10
0.10
0.10
0.11
0.11
0.12
0.12
0.12
0.001
0.002
0.003
0.003
0.004
0.004
0.004
0.008
0.02
0.04
0.09
0.10
0.15
0.25
0.29
0.58
Reference
Source
Number
8
8
9
10-15
9/00
Metallurgical Industry
12.2-11
-------
Table 12.2-3 (cont.).
Process
Controlled with venturi scrubber
Mobile scrubber car
Quenching (SCC 3-03-003-04)
Uncontrolled (dirty water)
Uncontrolled (clean water)
With baffles (dirty water)
Particle
Size
(Mm)b
0.5
1.0
2.0
2.5
5.0
10.0
15.0
1.0
2.0
2.5
5.0
10.0
15.0
1.0
2.5
5.0
10.0
15.0
1.0
2.5
5.0
10.0
15.0
1.0
2.5
5.0
10.0
15.0
Cumulative
Mass %
s Stated Size
24
47
66.5
73.5
75
87
92
100
28.0
29.5
30.0
30.0
32.0
35.0
100
13.8
19.3
21.4
22.8
26.4
100
4.0
11.1
19.1
30.1
37.4
100
8.5
20.4
24.8
32.3
49.8
100
Cumulative
Mass
Emission
Factors
0.02
0.04
0.06
0.07
0.07
0.08
0.08
0.09
0.010
0.011
0.011
0.011
0.012
0.013
0.036
0.36
0.51
0.56
0.60
0.69
2.62
0.02
0.06
0.11
0.17
0.21
0.57
0.06
0.13
0.16
0.21
0.32
0.65
Reference
Source
Number
10,12
16
17
17
17
12.2-12
EMISSION FACTORS
9/00
-------
Table 12.2-3 (cont.).
Process
With baffles (clean water)
Combustion stack (SCC 3-03-003-17
for COG)
Uncontrolled
Particle
Size
(um)b
1.0
2.5
5.0
10.0
15.0
1.0
2.0
2.5
5.0
10.0
15.0
Cumulative
Mass %
s Stated Size
1.2
6.0
7.0
9.8
15.1
100
77.4
85.7
93.5
95.8
95.9
96
100
Cumulative
Mass
Emission
Factors
0.003
0.02
0.02
0.03
0.04
0.27
0.18
0.20
0.22
0.22
0.22
0.22
0.23
Reference
Source
Number
17
18-20
a Emission factors are filterable PM and are expressed in kg of pollutant/Mg of coal charged.
b /^m = micrometers
c EMISSION FACTOR RATING: E
9/00
Metallurgical Industry
12.2-13
-------
Table 12.2-4. (English Units). SIZE-SPECIFIC EMISSION FACTORS
FOR COKE MANUFACTURING3
EMISSION FACTOR RATING: D (except as noted)
Process
Coal preheating (SCC 3-03-003-13)
Uncontrolled
Controlled with venturi scrubber
Oven charging sequential or stage0
(SCC 3-03-003-02)
Coke pushing (SCC 3-03-003-03)
Uncontrolled
Particle
Size
(um)b
0.5
1.0
2.0
2.5
5.0
10.0
15.0
0.5
1.0
2.0
2.5
5.0
10.0
15.0
0.5
1.0
2.0
2.5
5.0
10.0
15.0
0.5
1.0
2.0
2.5
5.0
10.0
15.0
Cumulative
Mass %
s Stated Size
44
48.5
55
59.5
79.5
97.5
99.9
100
78
80
83
84
88
94
96.5
100
13.5
25.2
33.6
39.1
45.8
48.9
49.0
100
3.1
7.7
14.8
16.7
26.6
43.3
50.0
100
Cumulative
Mass
Emission
Factors
1.5
1.7
1.9
2.1
2.8
3.4
3.5
3.5
0.20
0.20
0.21
0.21
0.22
0.24
0.24
0.25
0.002
0.004
0.005
0.006
0.007
0.008
0.008
0.016
0.04
0.09
0.17
0.19
0.30
0.50
0.58
1.15
Reference
Source
Number
8
8
9
10-15
12.2-14
EMISSION FACTORS
9/00
-------
Table 12.2-4 (cant.).
Process
Controlled with venturi scrubber
Mobile scrubber car
Quenching (SCC 3-03-003-04)
Uncontrolled (dirty water)
Uncontrolled (clean water)
With baffles (dirty water)
Particle
Size
(um)b
0.5
1.0
2.0
2.5
5.0
10.0
15.0
1.0
2.0
2.5
5.0
10.0
15.0
1.0
2.5
5.0
10.0
15.0
1.0
2.5
5.0
10.0
15.0
1.0
2.5
5.0
10.0
15.0
Cumulative
Mass %
s Stated Size
24
47
66.5
73.5
75
87
92
100
28.0
29.5
30.0
30.0
32.0
35.0
100
13.8
19.3
21.4
22.8
26.4
100
4.0
11.1
19.1
30.1
37.4
100
8.5
20.4
24.8
32.3
49.8
100
Cumulative
Mass
Emission
Factors
0.04
0.08
0.12
0.13
0.13
0.16
0.17
0.18
0.020
0.021
0.022
0.022
0.024
0.023
0.072
0.72
1.01
1.12
1.19
1.38
5.24
0.05
0.13
0.22
0.34
0.42
1.13
0.11
0.27
0.32
0.42
0.65
1.30
Reference
Source
Number
10,12
16
17
17
17
9/00
Metallurgical Industry
12.2-15
-------
Table 12.2-4 (cont.).
Process
With baffles (clean water)
Combustion stack (SCC 3-03-003-17
for COG)
Uncontrolled
Particle
Size
(Mm)"
1.0
2.5
5.0
10.0
15.0
1.0
2.0
2.5
5.0
10.0
15.0
Cumulative
Mass %
s Stated Size
1.2
6.0
7.0
9.8
15.1
100
77.4
85.7
93.5
95.8
95.9
96
100
Cumulative
Mass
Emission
Factors
0.006
0.03
0.04
0.05
0.08
0.54
0.36
0.40
0.44
0.45
0.45
0.45
0.47
Reference
Source
Number
17
18-20
a Emission factors are filterable PM and are expressed in Ib of pollutant/ton of coal charged.
b jum = micrometers.
0 EMISSION FACTOR RATING: E
Combustion of gas in the battery flues produces emissions from the underfire or combustion
stack. Sulfur dioxide emissions may also occur if the coke oven gas is not desulfurized. Coal fines may
leak into the waste combustion gases if the oven wall brickwork is damaged. Conventional gas cleaning
equipment, including electrostatic precipitators and fabric filters, have been installed on battery combustion
stacks.
Fugitive paniculate emissions are associated with material handling operations. These operations
consist of unloading, storing, grinding and sizing of coal, screening, crushing, storing, and unloading of
coke.
References For Section 12.2
1. George T. Austin, Shreve's Chemical Process Industries, McGraw-Hill Book Company, Fifth
Edition, 1984.
2. Theodore Baumeister, Mark's Standard Handbook For Mechanical Engineers, McGraw-Hill
Book Company, Eighth Edition, 1978.
3. John Fitzgerald, et al, Inhalable Paniculate Source Category Report For The Metallurgical
Coke Industry, TR-83-97-g, Contract No. 68-02-3157, GCA Corporation, Bedford, MA, July
1986.
12.2-16
EMISSION FACTORS
9/00
-------
4. Air Pollution By Coking Plants, United Nations Report: Economic Commission for Europe,
ST/ECE/Coal/26, 1986.
5. R. W. Fullerton, "Impingement Baffles To Reduce Emissions From Coke Quenching", Journal Of
The Air Pollution Control Association, 17: 807-809, December 1967.
6. J. Varga and H. W. Lownie, Jr., Final Technological Report On A Systems Analysis Study Of The
Integrated Iron And Steel Industry, Contract No. PH-22-68-65, U. S. Environmental Protection
Agency, Research Triangle Park, NC, May, 1969.
7. Paniculate Emissions Factors Applicable To The Iron And Steel Industry, EPA-450/479-028,
U. S. Environmental Protection Agency, Research Triangle Park, NC, September 1979.
8. Stack Test Report For J & L Steel, Aliquippa Works, Betz Environmental Engineers, Plymouth
Meeting, PA, April 1977.
9. R. W. Bee, et. al., Coke Oven Charging Emission Control Test Program, Volume I, EPA-650/2-
74-062-1, U. S. Environmental Protection Agency, Washington, DC, September 1977.
10. Emission Testing And Evaluation Of Ford/Koppers Coke Pushing Control System,
EPA-600-2-77-187b, U. S. Environmental Protection Agency, Washington, DC, September 1974.
11. Stack Test Report, Bethlehem Steel, Burns Harbor, IN, Bethlehem Steel, Bethlehem, PA,
September 1974.
12. Stack Test Report For Inland Steel Corporation, East Chicago, IN Works, Betz Environmental
Engineers, Pittsburgh, PA, June 1976.
13. Stack Test Report For Great Lakes Carbon Corporation, St. Louis, MO, Clayton Environmental
Services, Southfield, MO, April 1975.
14. Source Testing Of A Stationary Coke Side Enclosure, Bethlehem Steel, Burns Harbor Plant,
EPA-3401-76-012, U. S. Environmental Protection Agency, Washington, DC, May 1977.
15. Stack Test Report For Allied Chemical Corporation, Ashland, KY, York Research Corporation,
Stamford, CT, April 1979.
16. Stack Test Report, Republic Steel Company, Cleveland, OH, Republic Steel, Cleveland, OH,
November 1979.
17. J. Jeffrey, Wet Coke Quench Tower Emission Factor Development, Dofasco, Ltd.,
EPA-600/X-85-3.40; U. S. Environmental Protection Agency, Research Triangle Park, NC, August
1982.
18. Stack Test Report For Shenango Steel, Inc., Neville Island, PA, Betz Environmental Engineers,
Plymouth Meeting, PA, July 1976.
19. » Stack Test Report For J'&L Steel Corporation, Pittsburgh, PA, Mostardi-Platt Associates,
Bensenville, IL, June'19 80.
9/00 Metallurgical Industry 12.2-17
-------
20. Stack Test Report For J&L Steel Corporation, Pittsburgh, PA, Wheelabrator Frye, Inc.,
Pittsburgh, PA, April 1980.
21. R. B. Jacko, et al., Byproduct Coke Oven Pushing Operation: Total And Trace Metal Paniculate
Emissions, Purdue University, West Lafayette, IN, June 27,1976.
22. Control Techniques For Lead Air Emissions, EPA-450/2-77-012, U. S. Environmental Protection
Agency, Research Triangle Park, NC, December 1977.
23. Stack Test Report For Republic Steel, Cleveland, OH, PEDCo (Under Contract to
U. S. Environmental Protection Agency), weeks of October 26 and November 7,1981, EMB
Report 81-CBS-l.
24. Stack Test Report, Bethlehem Steel, Sparrows Point, MD, State Of Maryland, Stack Test Report
No. 78, June and July 1975.
25. Stack Test Report, Ford Motor Company, Dearborn, MI, Ford Motor Company, November 5-6,
1980.
26. Locating And Estimating Air Emissions From Sources Of Benzene, EPA-450/4-84-007, U. S.
Environmental Protection Agency, Washington, DC, March 1988.
27. Metallurgical Coke Industry Paniculate Emissions: Source Category Report,
EPA-600/7-86-050, U. S. Environmental Protection Agency, Washington, DC, December 1986.
28. Benzene Emissions From Coke Byproduct Recovery Plants: Background Information For
Proposed Standards, EPA-450/3-83-016a, U. S. Environmental Protection Agency, Washington,
DC, May 1984.
U.S. Environmental Ptotection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12th Fioar
Chicago. IL 60604-3590
12.2-18 EMISSION FACTORS 9/00
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