# 9/98 External Combustion Sources 1.1-1

1.1 Bituminous And Subbituminous Coal Combustion

1.1.1 General

Coal is a complex combination of organic matter and inorganic mineral matter formed over eons from successive layers of fallen vegetation. Coals are classified by rank according to their progressive alteration in the natural metamorphosis from lignite to anthracite. Coal rank depends on the volatile matter, fixed carbon, inherent moisture, and oxygen, although no single parameter defines a rank. Typically, coal rank increases as the amount of fixed carbon increases and the amount of volatile matter and moisture decreases.

Bituminous coals are by far the largest group and are characterized as having lower fixed carbon and higher volatile matter than anthracite. The key distinguishing characteristics of bituminous coal are its relative volatile matter and sulfur content as well as its slagging and agglomerating characteristics. Subbituminous coals have higher moisture and volatile matter and lower sulfur content than bituminous coals and may be used as an alternative fuel in some boilers originally designed to burn bituminous coals. 1 

# Generally, bituminous coals have heating values of 10,500 to 14,000 British thermal units per pound (Btu/lb) on a wet, mineral-matter-free basis. 2 

# As mined, the heating values of typical U.S. bituminous coals range from 10,720 to 14,730 Btu/lb. 3 

# The heating values of subbituminous coals range from 8,300 to 11,500 Btu/lb on a wet, mineral-matter-free basis 2 

# , and from 9,420 to 10,130 Btu/lb on an as-mined basis. 3 

# Formulae and tables for classifying coals are given in Reference 2.

1.1.2 Firing Practices 4 

# Coal-fired boilers can be classified by type, fuel, and method of construction. Boiler types are identified by the heat transfer method (watertube, firetube, or cast iron), the arrangement of the heat transfer surfaces (horizontal or vertical, straight or bent tube), and the firing configuration (suspension, stoker, or fluidized bed). The most common heat transfer method for coal-fired boilers is the watertube method in which the hot combustion gases contact the outside of the heat transfer tubes, while the boiler water and steam are contained within the tubes.

Coal-fired watertube boilers include pulverized coal, cyclone, stoker, fluidized bed, and handfed units. In stoker-fired systems and most handfed units, the fuel is primarily burned on the bottom of the furnace or on a grate. In a fluidized bed combustor (FBC), the coal is introduced to a bed of either sorbent or inert material (usually sand) which is fluidized by an upward flow of air. In pulverized coal-fired (PC-fired) boilers, the fuel is pulverized to the consistency of talcum powder (i.e., at least 70 percent of the particles will pass through a 200-mesh sieve) and pneumatically injected through the burners into the furnace. Combustion in PC-fired units takes place almost entirely while the coal is suspended in the furnace volume. PC-fired boilers are classified as either dry bottom or wet bottom (also referred to as slag tap furnaces), depending on whether the ash is removed in a solid or molten state. In dry bottom furnaces, coals with high fusion temperatures are burned, resulting in dry ash. In wet bottom furnaces, coals with low fusion temperatures are used, resulting in molten ash or slag.

Depending upon the type and location of the burners and the direction of coal injection into the furnace, PC-fired boilers can also be classified into two different firing types, including wall, and tangential. Wall-fired boilers can be either single wall-fired, with burners on only one wall of the furnace firing horizontally, or opposed wall-fired, with burners mounted on two opposing walls. Tangential (or corner-fired) boilers have burners mounted in the corners of the furnace. The fuel and air are injected tangent to an imaginary circle in the plane of the boilers. Cyclone furnaces are often

# 1.1-2 EMISSION FACTORS 9/98 categorized as PC-fired systems even though the coal is crushed to a maximum size of about 4-mesh. The coal is fed tangentially, with primary air, into a horizonal cylindrical furnace. Smaller coal particles are burned in suspension while larger particles adhere to the molten layer of slag on the combustion chamber wall. Cyclone boilers are high-temperature, wet-bottom type systems.

Stoker-fired systems account for the vast majority of coal-fired watertube boilers for industrial, commercial, and institutional applications. Most packaged stoker units designed for coal firing are small and can be divided into three groups: underfeed stokers, overfeed stokers, and spreader stokers. Underfeed stokers are generally either the horizontal-feed, side-ash-discharge type or the gravity-feed, rear-ash-discharge type. An overfeed stoker uses a moving grate assembly in which coal is fed from a hopper onto a continuous grate which conveys the fuel into the furnace. In a spreader stoker, mechanical or pneumatic feeders distribute coal uniformly over the surface of a moving grate. The injection of the fuel into the furnace and onto the grate combines suspension burning with a thin, fast-burning fuel bed. The amount of fuel burned in suspension depends primarily on fuel size and composition, and air flow velocity. Generally, fuels with finer size distributions, higher volatile matter contents, and lower moisture contents result in a greater percentage of combustion and corresponding heat release rates in suspension above the bed.

FBCs, while not constituting a significant percentage of the total boiler population, have nonetheless gained popularity in the last decade, and today generate steam for industries, cogenerators, independent power producers, and utilities. There are two major categories of FBC systems: (1) atmospheric, operating at or near ambient pressures, and (2) pressurized, operating from 4 to 30 atmospheres (60 to 450 pounds per square inch gauge). At this time, atmospheric FBCs are more advanced (or commercialized) than pressurized FBCs. The two principal types of atmospheric FBCs are bubbling bed and circulating bed. The feature that varies most fundamentally between these two types is the fluidization velocity. In the bubbling bed design, the fluidation velocity is relatively low in order to minimize solids carryover or elutriation from the combustor. Circulating FBCs, however, employ high fluidization velocities to promote the carryover or circulation of the solids. High-temperature cyclones are used in circulating FBCs and in some bubbling FBCs to capture the solid fuel and bed material for return to the primary combustion chamber. The circulating FBC maintains a continuous, high-volume recycle rate which increases the residence time compared to the bubbling bed design. Because of this feature, circulating FBCs often achieve higher combustion efficiencies and better sorbent utilization than bubbling bed units.

Small, coal-fired boilers and furnaces are found in industrial, commercial, institutional, or residential applications and are sometimes capable of being hand-fired. The most common types of firetube boilers used with coal are the horizontal return tubular (HRT), Scotch, vertical, and the firebox. Cast iron boilers are also sometimes available as coal-fired units in a handfed configuration. The HRT boilers are generally fired with gas or oil instead of coal. The boiler and furnace are contained in the same shell in a Scotch or shell boiler. Vertical firetube boilers are typically small singlepass units in which the firetubes come straight up from the water-cooled combustion chamber located at the bottom of the unit. A firebox boiler is constructed with an internal steel-encased, water-jacketed firebox. Firebox firetube boilers are also referred to as locomotive, short firebox, and compact firebox boilers and employ mechanical stokers or are hand-fired.

# 9/98 External Combustion Sources 1.1-3 1.1.3 Emissions 4



# Emissions from coal combustion depend on the rank and composition of the fuel, the type and size of the boiler, firing conditions, load, type of control technologies, and the level of equipment maintenance. The major pollutants of concern from bituminous and subbituminous coal combustion are particulate matter (PM), sulfur oxides (SO

x 

# ), and nitrogen oxides (NO

x 

# ). Some unburned combustibles, including carbon monoxide (CO) and numerous organic compounds, are generally emitted even under proper boiler operating conditions.

1.1.3.1 Particulate Matter 4


# - PM composition and emission levels are a complex function of boiler firing configuration, boiler operation, pollution control equipment, and coal properties. Uncontrolled PM emissions from coal-fired boilers include the ash from combustion of the fuel as well as unburned carbon resulting from incomplete combustion. In pulverized coal systems, combustion is almost complete; thus, the emitted PM is primarily composed of inorganic ash residues.

Coal ash may either settle out in the boiler (bottom ash) or entrained in the flue gas (fly ash). The distribution of ash between the bottom ash and fly ash fractions directly affects the PM emission rate and depends on the boiler firing method and furnace type (wet or dry bottom). Boiler load also affects the PM emissions as decreasing load tends to reduce PM emissions. However, the magnitude of the reduction varies considerably depending on boiler type, fuel, and boiler operation.

Soot blowing is also a source of intermittent PM emissions in coal-fired boilers. Steam soot and air soot blowing is periodically used to dislodge ash from heat transfer surfaces in the furnace, convective section, economizer, and air preheater.

Particulate emissions may be categorized as either filterable or condensable. Filterable emissions are generally considered to be the particles that are trapped by the glass fiber filter in the front half of a Reference Method 5 or Method 17 sampling train. Vapors and particles less than 0.3 microns pass through the filter. Condensable particulate matter is material that is emitted in the vapor state which later condenses to form homogeneous and/or heterogeneous aerosol particles. The condensable particulate emitted from boilers fueled on coal or oil is primarily inorganic in nature.

1.1.3.2 Sulfur Oxides 4


# - Gaseous SO
x 

# from coal combustion are primarily sulfur dioxide (SO 2 

# ), with a much lower quantity of sulfur trioxide (SO 3 

# ) and gaseous sulfates. These compounds form as the organic and pyritic sulfur in the coal are oxidized during the combustion process. On average, about 95 percent of the sulfur present in bituminous coal will be emitted as gaseous SO

x 

# , whereas somewhat less will be emitted when subbituminous coal is fired. The more alkaline nature of the ash in some subbituminous coals causes some of the sulfur to react in the furnace to form various sulfate salts that are retained in the boiler or in the flyash.

1.1.3.3 Nitrogen Oxides 5-6


# - NO
x 

# emissions from coal combustion are primarily nitric oxide (NO), with only a few volume percent as nitrogen dioxide (NO 2 

# ). Nitrous oxide (N 2 

# O) is also emitted at a few parts per million. NO

x 

# formation results from thermal fixation of atmospheric nitrogen in the combustion flame and from oxidation of nitrogen bound in the coal. Experimental measurements of thermal NO

x 

# formation have shown that the NO

x 

# concentration is exponentially dependent on temperature and is proportional to nitrogen concentration in the flame, the square root of oxygen concentration in the flame, and the gas residence time. 7 

# Cyclone boilers typically have high conversion of nitrogen to NO

x 

# Typically, only 20 to 60 percent of the fuel nitrogen is converted to NO

x 

# . Bituminous and subbituminous coals usually

# 1.1-4 EMISSION FACTORS 9/98 contain from 0.5 to 2 weight percent nitrogen, mainly present in aromatic ring structures. Fuel nitrogen can account for up to 80 percent of total NO

x 

# from coal combustion.

1.1.3.4 Carbon Monoxide - The rate of CO emissions from combustion sources depends on the fuel oxidation efficiency of the source. By controlling the combustion process carefully, CO emissions can be minimized. Thus, if a unit is operated improperly or is not well-maintained, the resulting concentrations of CO (as well as organic compounds) may increase by several orders of magnitude. Smaller boilers, heaters, and furnaces typically emit more CO and organics than larger combustors. This is because smaller units usually have less high-temperature residence time and, therefore, less time to achieve complete combustion than larger combustors. Combustion modification techniques and equipment used to reduce NO

x 

# can increase CO emissions if the modification techniques are improperly implemented or if the equipment is improperly designed.

1.1.3.5 Organic Compounds - As with CO emissions, the rate at which organic compounds are emitted depends on the combustion efficiency of the boiler. Therefore, combustion modifications that change combustion residence time, temperature, or turbulence may increase or decrease concentrations of organic compounds in the flue gas.

Organic emissions include volatile, semivolatile, and condensable organic compounds either present in the coal or formed as a product of incomplete combustion (PIC). Organic emissions are primarily characterized by the criteria pollutant class of unburned vapor-phase hydrocarbons. These emissions include alkanes, alkenes, aldehydes, alcohols, and substituted benzenes (e.g., benzene, toluene, xylene, and ethyl benzene). 8,9



# Emissions of polychlorinated dibenzo-p-dioxins and polychlorinated dibenzofurans (PCDD/PCDF) also result from the combustion of coal. Of primary interest environmentally are tetrachloro- through octachloro- dioxins and furans. Dioxin and furan emissions are influenced by the extent of destruction of organics during combustion and through reactions in the air pollution control equipment. The formation of PCDD/PCDF in air pollution control equipment is primarily dependent on flue gas temperature, with maximum potential for formation occurring at flue gas temperatures of 450 degrees to 650 degrees Fahrenheit.

The remaining organic emissions are composed largely of compounds emitted from combustion sources in a condensed phase. These compounds can almost exclusively be classed into a group known as polycyclic organic matter (POM), and a subset of compounds called polynuclear aromatic hydrocarbons (PNA or PAH). Polycyclic organic matter is more prevalent in the emissions from coal combustion because of the more complex structure of coal.

1.1.3.6 Trace MetalsTrace metals are also emitted during coal combustion. The quantity of any given metal emitted, in general, depends on:

- the physical and chemical properties of the metal itself;

- the concentration of the metal in the coal;

- the combustion conditions; and

# 9/98 External Combustion Sources 1.1-5 - the type of particulate control device used, and its collection efficiency as a function of particle size.

Some trace metals become concentrated in certain particle streams from a combustor (e.g., bottom ash, collector ash, and flue gas particulate) while others do not. 10 

# Various classification schemes have been developed to describe this partitioning behavior. 10-12 

# These classification schemes generally distinguish between:

- Class 1: Elements that are approximately equally concentrated in the fly ash and bottom ash, or show little or no small particle enrichment. Examples include manganese, beryllium, cobalt, and chromium.

- Class 2: Elements that are enriched in fly ash relative to bottom ash, or show increasing enrichment with decreasing particle size. Examples include arsenic, cadmium, lead, and antimony.

- Class 3: Elements which are emitted in the gas phase (primarily mercury and, in some cases, selenium).

Control of Class 1 metals is directly related to control of total particulate matter emissions, while control of Class 2 metals depends on collection of fine particulate. Because of variability in particulate control device efficiencies, emission rates of these metals can vary substantially. Because of the volatility of Class 3 metals, particulate controls have only a limited impact on emissions of these metals.

1.1.3.7 Acid GasesIn addition to SO 2 

# and NO

x 

# emissions, combustion of coal also results in emissions of chlorine and fluorine, primarily in the form of hydrogen chloride (HCl) and hydrogen fluoride (HF). Lesser amounts of chlorine gas and fluorine gas are also emitted. A portion of the chlorine and fluorine in the fuel may be absorbed onto fly ash or bottom ash. Both HCl and HF are water soluble and are readily controlled by acid gas scrubbing systems.

1.1.3.8 Fugitive Emissions - Fugitive emissions are defined as pollutants which escape from an industrial process due to leakage, materials handling, inadequate operational control, transfer, or storage. The fly ash handling operations in most modern utility and industrial combustion sources consist of pneumatic systems or enclosed and hooded systems which are vented through small fabric filters or other dust control devices. The fugitive PM emissions from these systems are therefore minimal. Fugitive particulate emissions can sometimes occur during fly ash transfer operations from silos to trucks or rail cars.

1.1.3.9 Greenhouse Gases 13-18


# - Carbon dioxide (CO 2 

# ), methane (CH 4 

# ), and nitrous oxide (N 2 

# O) emissions are all produced during coal combustion. Nearly all of the fuel carbon (99 percent) in coal is converted to CO 2 

# during the combustion process. This conversion is relatively independent of firing configuration. Although the formation of CO acts to reduce CO 2 

# emissions, the amount of CO produced is insignificant compared to the amount of CO 2 

# produced. The majority of the fuel carbon not converted to CO 2 

# is entrained in bottom ash. CO 2 

# emissions for coal vary with carbon content, and carbon content varies between the classes of bituminous and subbituminous coals. Further, carbon content also varies within each class of coal based on the geographical location of the mine.

Formation of N 2 

# O during the combustion process is governed by a complex series of reactions and its formation is dependent upon many factors. Formation of N 2 

# O is minimized when combustion

# 1.1-6 EMISSION FACTORS 9/98 temperatures are kept high (above 1575 o 

# F) and excess air is kept to a minimum (less than 1 percent). N 2 

# O emissions for coal combustion are not significant except for fluidized bed combustion (FBC), where the emissions are typically two orders of magnitude higher than all other types of coal firing due to areas of low temperature combustion in the fuel bed.

Methane emissions vary with the type of coal being fired and firing configuration, but are highest during periods of incomplete combustion, such as the start-up or shut-down cycle for coal-fired boilers. Typically, conditions that favor formation of N 2 

# O also favor emissions of CH 4 

# .

1.1.4 Controls 4



# Control techniques for criteria pollutants from coal combustion may be classified into three broad categories: fuel treatment/substitution, combustion modification, and postcombustion control. Emissions of noncriteria pollutants such as particulate phase metals have been controlled through the use of post combustion controls designed for criteria pollutants. Fuel treatment primarily reduces SO 2 

# and includes coal cleaning using physical, chemical, or biological processes; fuel substitution involves burning a cleaner fuel. Combustion modification includes any physical or operational change in the furnace or boiler and is applied primarily for NO

x 

# control purposes, although for small units, some reduction in PM emissions may be available through improved combustion practice. Postcombustion control employs a device after the combustion of the fuel and is applied to control emissions of PM, SO 2 

# , and NO

x 

# for coal combustion.

1.1.4.1 Particulate Matter Control 4


# - The principal control techniques for PM are combustion modifications (applicable to small stoker-fired boilers) and postcombustion methods (applicable to most boiler types and sizes). Uncontrolled PM emissions from small stoker-fired and hand-feed combustion sources can be minimized by employing good combustion practices such as operating within the recommended load ranges, controlling the rate of load changes, and ensuring steady, uniform fuel feed. Proper design and operation of the combustion air delivery systems can also minimize PM emissions. The postcombustion control of PM emissions from coal-fired combustion sources can be accomplished by using one or more or the following particulate control devices:

C Electrostatic precipitator (ESP),

C Fabric filter (or baghouse),

C Wet scrubber,

C Cyclone or multiclone collector, or

C Side stream separator.

Electrostatic precipitation technology is applicable to a variety of coal combustion sources. Because of their modular design, ESPs can be applied to a wide range of system sizes and should have no adverse effect on combustion system performance. The operating parameters that influence ESP performance include fly ash mass loading, particle size distribution, fly ash electrical resistivity, and precipitator voltage and current. Other factors that determine ESP collection efficiency are collection plate area, gas flow velocity, and cleaning cycle. Data for ESPs applied to coal-fired sources show fractional collection efficiencies greater than 99 percent for fine (less than 0.1 micrometer) and coarse particles (greater than 10 micrometers). These data show a reduction in collection efficiency for particle diameters between 0.1 and 10 micrometers.

Fabric filtration has been widely applied to coal combustion sources since the early 1970s and consists of a number of filtering elements (bags) along with a bag cleaning system contained in a main shell structure incorporating dust hoppers. The particulate removal efficiency of fabric filters is

# 9/98 External Combustion Sources 1.1-7 dependent on a variety of particle and operational characteristics. Particle characteristics that affect the collection efficiency include particle size distribution, particle cohesion characteristics, and particle electrical resistivity. Operational parameters that affect fabric filter collection efficiency include air-to-cloth ratio, operating pressure loss, cleaning sequence, interval between cleanings, cleaning method, and cleaning intensity. In addition, the particle collection efficiency and size distribution can be affected by certain fabric properties (e. g., structure of fabric, fiber composition, and bag properties). Collection efficiencies of fabric filters can be as high as 99.9 percent.

Wet scrubbers, including venturi and flooded disc scrubbers, tray or tower units, turbulent contact absorbers, or high-pressure spray impingement scrubbers are applicable for PM as well as SO 2 

# control on coal-fired combustion sources. Scrubber collection efficiency depends on particle size distribution, gas side pressure drop through the scrubber, and water (or scrubbing liquor) pressure, and can range between 95 and 99 percent for a 2-micron particle.

Cyclone separators can be installed singly, in series, or grouped as in a multicyclone or multiclone collector. These devices are referred to as mechanical collectors and are often used as a precollector upstream of an ESP, fabric filter, or wet scrubber so that these devices can be specified for lower particle loadings to reduce capital and/or operating costs. The collection efficiency of a mechanical collector depends strongly on the effective aerodynamic particle diameter. Although these devices will reduce PM emissions from coal combustion, they are relatively ineffective for collection of particles less than 10 micron (PM-10). The typical overall collection efficiency for mechanical collectors ranges from 90 to 95 percent.

The side-stream separator combines a multicyclone and a small pulse-jet baghouse to more efficiently collect small-diameter particles that are difficult to capture by a mechanical collector alone. Most applications to date for side-stream separators have been on small stoker boilers.

Atmospheric fluidized bed combustion (AFBC) boilers may tax conventional particulate control systems. The particulate mass concentration exiting AFBC boilers is typically 2 to 4 times higher than pulverized coal boilers. AFBC particles are also, on average, smaller in size, and irregularly shaped with higher surface area and porosity relative to pulverized coal ashes. The effect is a higher pressure drop. The AFBC ash is more difficult to collect in ESPs than pulverized coal ash because AFBC ash has a higher electrical resistivity and the use of multiclones for recycling, inherent with the AFBC process, tends to reduce exit gas stream particulate size.

1.1.4.2 Sulfur Oxides Control 4


# - Several techniques are used to reduce SO

x 

# emissions from coal combustion. Table 1.1-1 presents the techniques most frequently used. One way is to switch to lower sulfur coals, since SO

x 

# emissions are proportional to the sulfur content of the coal. This alternative may not be possible where lower sulfur coal is not readily available or where a different grade of coal cannot be satisfactorily fired. In some cases, various coal cleaning processes may be employed to reduce the fuel sulfur content. Physical coal cleaning removes mineral sulfur such as pyrite but is not effective in removing organic sulfur. Chemical cleaning and solvent refining processes are being developed to remove organic sulfur.

Post combustion flue gas desulfurization (FGD) techniques can remove SO 2 

# formed during combustion by using an alkaline reagent to absorb SO 2 

# in the flue gas. Flue gases can be treated using wet, dry, or semi-dry desulfurization processes of either the throwaway type (in which all waste streams are discarded) or the recovery/regenerable type (in which the SO 2 

# absorbent is regenerated and reused). To date, wet systems are the most commonly applied. Wet systems generally use alkali slurries as the SO 2 

# absorbent medium and can be designed to remove greater than 90 percent of the incoming SO 2 

# . Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the commercially

# 1.1-8 EMISSION FACTORS 9/98 proven wet FGD systems. The effectiveness of these devices depends not only on control device design but also on operating variables. Particulate reduction of more than 99 percent is possible with wet scrubbers, but fly ash is often collected by upstream ESPs or baghouses, to avoid erosion of the desulfurization equipment and possible interference with FGD process reactions. 18 

# Also, the volume of scrubber sludge is reduced with separate fly ash removal, and contamination of the reagents and by-products is prevented.

The lime and limestone wet scrubbing process uses a slurry of calcium oxide or limestone to absorb SO 2 

# in a wet scrubber. Control efficiencies in excess of 91 percent for lime and 94 percent for limestone over extended periods are possible. Sodium scrubbing processes generally employ a wet scrubbing solution of sodium hydroxide or sodium carbonate to absorb SO 2 

# from the flue gas. Sodium scrubbers are generally limited to smaller sources because of high reagent costs and can have SO 2 

# removal efficiencies of up to 96.2 percent. The double or dual alkali system uses a clear sodium alkali solution for SO 2 

# removal followed by a regeneration step using lime or limestone to recover the sodium alkali and produce a calcium sulfite and sulfate sludge. SO 2 

# removal efficiencies of 90 to 96 percent are possible.

1.1.4.3 Nitrogen Oxide Controls 4


# - Several techniques are used to reduce NO

x 

# emissions from coal combustion. These techniques are summarized in Table 1.1-2. The primary techniques can be classified into one of two fundamentally different methods—combustion controls and postcombustion controls. Combustion controls reduce NO

x 

# by suppressing NO

x 

# formation during the combustion process, while postcombustion controls reduce NO

x 

# emission after their formation. Combustion controls are the most widely used method of controlling NO

x 

# formation in all types of boilers and include low excess air (LEA), burners out of service (BOOS), biased burner firing, overfire air (OFA), low NO

x 

# burners (LNBs), and reburn. Postcombustion control methods are selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR). Combustion and postcombustion controls can be used separately or combined to achieve greater NO

x 

# reduction from fluidized bed combustors in boilers.

Operating at LEA involves reducing the amount of combustion air to the lowest possible level while maintaining efficient and environmentally compliant boiler operation. NO

x 

# formation is inhibited because less oxygen is available in the combustion zone. BOOS involves withholding fuel flow to all or part of the top row of burners so that only air is allowed to pass through. This method simulates air staging, or OFA conditions, and limits NO

x 

# formation by lowering the oxygen level in the burner area. Biased burner firing involves more fuel-rich firing in the lower rows of burners than in the upper row of burners. This method provides a form of air staging and limits NO

x 

# formation by limiting the amount of oxygen in the firing zone. These methods may change the normal operation of the boiler and the effectiveness is boiler-specific. Implementation of these techniques may also reduce operational flexibility; however, they may reduce NO

x 

# by 10 to 20 percent from uncontrolled levels.

OFA is a technique in which a percentage of the total combustion air is diverted from the burners and injected through ports above the top burner level. OFA limits NO

x 

# by (1) suppressing thermal NO

x 

# by partially delaying and extending the combustion process resulting in less intense combustion and cooler flame temperatures and (2) suppressing fuel NO

x 

# formation by reducing the concentration of air in the combustion zone where volatile fuel nitrogen is evolved. OFA can be applied for various boiler types including tangential and wall-fired, turbo, and stoker boilers and can reduce NO

x 

# by 20 to 30 percent from uncontrolled levels.

LNBs limit NO

x 

# formation by controlling the stoichiometric and temperature profiles of the combustion process in each burner zone. The unique design of features of an LNB may create (1) a reduced oxygen level in the combustion zone to limit fuel NO

x 

# formation, (2) a reduced flame

# 9/98 External Combustion Sources 1.1-9 temperature that limits thermal NO

x 

# formation, and/or (3) a reduced residence time at peak temperature which also limits thermal NO

x 

# formation.

LNBs are applicable to tangential and wall-fired boilers of various sizes but are not applicable to other boiler types such as cyclone furnaces or stokers. They have been used as a retrofit NO

x 

# control for existing boilers and can achieve approximately 35 to 55 percent reduction from uncontrolled levels. They are also used in new boilers to meet New Source Performance Standards (NSPS) limits. LNBs can be combined with OFA to achieve even greater NO

x 

# reduction (40 to 60 percent reduction from uncontrolled levels).

Reburn is a combustion hardware modification in which the NO

x 

# produced in the main combustion zone is reduced in a second combustion zone downstream. This technique involves withholding up to 40 percent (at full load) of the heat input to the main combustion zone and introducing that heat input above the top row of burners to create a reburn zone. Reburn fuel (natural gas, oil, or pulverized coal) is injected with either air or flue gas to create a fuel-rich zone that reduces the NO

x 

# created in the main combustion zone to nitrogen and water vapor. The fuel-rich combustion gases from the reburn zone are completely combusted by injecting overfire air above the reburn zone. Reburn may be applicable to many boiler types firing coal as the primary fuel, including tangential, wall-fired, and cyclone boilers. However, the application and effectiveness are site-specific because each boiler is originally designed to achieve specific steam conditions and capacity which may be altered due to reburn. Commercial experience is limited; however, this limited experience does indicate NO

x 

# reduction of 50 to 60 percent from uncontrolled levels may be achieved.

SNCR is a postcombustion technique that involves injecting ammonia (NH 3 

# ) or urea into specific temperature zones in the upper furnace or convective pass. The ammonia or urea reacts with NO

x 

# in the flue gas to produce nitrogen and water. The effectiveness of SNCR depends on the temperature where reagents are injected; mixing of the reagent in the flue gas; residence time of the reagent within the required temperature window; ratio of reagent to NO

x 

# ; and the sulfur content of the fuel that may create sulfur compounds that deposit in downstream equipment. There is not as much commercial experience to base effectiveness on a wide range of boiler types; however, in limited applications, NO

x 

# reductions of 25 to 40 percent have been achieved.

SCR is another postcombustion technique that involves injecting NH 3 

# into the flue gas in the presence of a catalyst to reduce NO

x 

# to nitrogen and then water. The SCR reactor can be located at various positions in the process including before an air heater and particulate control device, or downstream of the air heater, particulate control device, and flue gas desulfurization systems. The performance of SCR is influenced by flue gas temperature, fuel sulfur content, ammonia-to-NO

x 

# ratio, inlet NO

x 

# concentration, space velocity, and catalyst condition. Although there is currently very limited application of SCR in the U.S. on coal-fired boilers, NO

x 

# reductions of 75 to 86 percent have been realized on a few pilot systems.

1.1.5 Emission Factors

Emission factors for SO

x 

# , NO
x 

# , and CO are presented in Table 1.1-3. Tables in this section present emission factors on both a weight basis (lb/ton) and an energy basis (lb/Btu). To convert from lb/ton to lb/MMBtu, divide by a heating value of 26.0 MMBtu/ton. Because of the inherently low NO X 

# emission characteristics of FBCs and the potential for in-bed SO 2 

# capture by calcium-based sorbents, uncontrolled emission factors for this source category were not developed in the same sense as with other source categories. For NO

x 

# emissions, the data collected from test reports were considered to be baseline (uncontrolled) if no additional add-on NO

x 

# control system (such as ammonia injection) was operated.

# 1.1-10 EMISSION FACTORS 9/98 For SO 2 

# emissions, a correlation was developed from reported data on FBCs to relate SO 2 

# emissions to the coal sulfur content and the calcium-to-sulfur ratio in the bed.

Filterable particulate matter and particulate matter less than, or equal to, 10 micrometers in diameter (PM-10) emission factors are presented in Table 1.1-4. Condensable particulate matteremission factors are presented in Table 1.1.5. Cumulative particle size distributions and particulate sizespecific emission factors are given in Tables 1.1-6, 1.1-7, 1.1-8, 1.1-9, 1.1-10, and 1.1-11. Particulate size-specific emission factors are also presented graphically in Figures 1.1-1, 1.1-2, 1.1-3, 1.1-4, 1.1-5, and 1.1-6.

Controlled emission factors for PCDD/PCDF and PAHs are provided in Tables 1.1-12 and 1.1-13, respectively. Controlled emission factors for other organic compounds are presented in Table 1.1-14. Emission factors for hydrogen chloride and hydrogen fluoride are presented in Table 1.1-15.

Table 1.1-16 presents emission factor equations for nine trace metals from controlled and uncontrolled boilers. Table 1.1-17 presents uncontrolled emission factors for seven of the same metals, along with mercury, POM and formaldehyde. Table 1.1-18 presents controlled emission factors for 13 trace metals and includes the metals found in Tables 1.1-16 and 1.1-17. The emission factor equations in Table 1.1-16 are based on statistical correlations among measured trace element concentrations in coal, measured fractions of ash in coal, and measured particulate matter emission factors. Because these are the major parameters affecting trace metals emissions from coal combustion, it is recommended that the emission factor equations be used when the inputs to the equations are available. If the inputs to the emission factor equations are not available for a pollutant, then the emission factors provided in Table 1.1-17 and 1.1-18 for the pollutant should be used.

Greenhouse gas emission factors, including CH 4 

# , non-methane organic compounds (NMOC), and N 2 

# O are provided in Table 1.1-19. In addition, Table 1.1-20 provides emission factors for CO 2 

# . 1.1.6 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 EFIG home page (http://www.epa.gov/oar/oaqps/efig/).

# 9/98 External Combustion Sources 1.1-11 Supplement A, February 1996

C SCC’s were corrected from 1-01-002-17, 1-02-002-17, and 1-03-002-17, to 1-01-002-18, 1-02-002-18, and 1-03-002-18 in the tables with SO

x 

# , NO
x 

# , CO, and PM/PM10 emission factors.

C For SO
x 

# factors, clarifications were added to the table footnotes to clarify that “S” is a weight percent and not a fraction. Similar clarification was added to the footnote for the CO 2 

# factor.

C For fluidized bed combustors (bubbling bed and circulating bed), the PM10 factors were replaced with footnote "m." The revised footnote "m" directs the user to the emission factor for spreader stoker with multiple cyclones and no flyash reinjection.

C In the table with filterable PM factors, the misspelling of "filterable" was corrected.

C In the cumulative particle size distribution table, text was added to the table footnotes to clarify that “A” is a weight percent and not a fraction.

C In the cumulative particle size distribution for spreader stokers, all of the factors were corrected.

C The N 2 

# O emission factor for bubbling bed was changed from 5.9 lb/ton to 5.5 lb/ton.

Supplement B, October 1996

C Text was added concerning coal rank/classification, firing practices, emissions, and controls.

C The table for NO

x 

# control technologies was revised to include controls for all types of coal-fired boilers.

C SO
x 

# , NO
x 

# , and CO emission factors were added for cell burners.

C The PM table was revised to recommend using spreader stoker PM factors for FBC units.

C Tables were added for new emission factors for polychlorinated toxics, polynuclear aromatics, organic toxics, acid gas toxics, trace metal toxics, and controlled toxics.

C N 2 

# O emission factors were added.

C Default CO 2 

# emission factors were added.

Supplement E, September 1998

C The term “Filterable” was added to the PM-10 column heading of Table 1.1-4.

# 1.1-12 EMISSION FACTORS 9/98 C Reference to condensable particulate matter was deleted from footnote b of Table 1.1-4.

C Emission factors for condensable particulate matter were added (Table 1.1-5).

C Table 1.1-7 was revised to correct a typographical errors in the ESP column.

C The zeros in Table 1.1-8 appeared to be in error. Engineering judgement was used to determine a conservative estimate.

C NO
x 

# emission factors were updated based on data from the Acid Rain program.

# 9/98 External Combustion Sources 1.1-13 Table 1.1-1. POSTCOMBUSTION SO 2 

# CONTROLS FOR COAL COMBUSTION SOURCES

Control Technology Process Typical Control Efficiencies Remarks

Wet scrubber

Spray drying

Furnace injection

Duct injection Lime/limestone

Sodium carbonate

Magnesium oxide/ hydroxide

Dual alkali

Calcium hydroxide slurry, vaporizes in spray vessel

Dry calcium carbonate/hydrate injection in upper furnace cavity

Dry sorbent injection into duct, sometimes combined with water
spray 80 - 95+%

80 - 98%

80 - 95+%

90 - 96%

70 - 90%

25 - 50%

25 - 50+% Applicable to high sulfur fuels, wet sludge product

5-430 million Btu/hr typical application range, high reagent costs

Can be regenerated

Uses lime to regenerate sodium-based scrubbing liquor

Applicable to low and medium sulfur fuels, produces dry product

Commercialized in Europe, several U. S. demonstration projects are completed

Several research and development, and demonstration projects underway, not yet commercially available in the United States.

# 1.1-14 EMISSION FACTORS 9/98Table 1.1-2. NOxCONTROL OPTIONS FOR COAL-FIRED BOILERSaControl TechniqueDescription ofTechniqueApplicable BoilerDesignsNOxReductionPotentialb(%)CommercialAvailability/R & DStatus CommentsCombustion ModificationsLoad reduction Reduction of coaland airStokers Minimal Available Applicable to stokers that can reduce load withoutincreasing excess air; may cause reduction in boilerefficiency; NOxreduction varies with percent loadreduction.Operationalmodifications (BOOS,LEA, BF, orcombination)Rearrangement ofair or fuel in themain combustionzonePulverized coalboilers (somedesigns); Stokers(LEA only)10 - 20 Available Must have sufficient operational flexibility to achieveNOxreduction potential without sacrificing boilerperformance.Overfire Air Injection of airabove maincombustion zonePulverized coalboilers and stokers20 - 30 Available Must have sufficient furnace height above top row ofburners in order to retrofit this technology to existingboilers.Low NOxBurners New burnerdesignscontrolling air-fuel mixingPulverized coalboilers35 - 55 Available Available in new boiler designs and can be retrofit inexisting boilers.LNB with OFA Combination ofnew burnerdesigns andinjection of airabove maincombustion zonePulverized coalboilers40 - 60 Available Available in new boiler designs and can be retrofit inexisting boilers with sufficient furnace height abovetop row of burners.Reburn Injection ofreburn fuel andcompletion airabove maincombustion zonePulverized coalboilers, cyclonefurnaces50 - 60 Commerciallyavailable but notwidely demonstratedReburn fuel can be natural gas, fuel oil, or pulverizedcoal. Must have sufficient furnace height to retrofitthis technology to existing boilers.

# 9/98 External Combustion Sources 1.1-15Table 1.1-2 (cont.).Control TechniqueDescription ofTechniqueApplicable BoilerDesignsNOxReductionPotentialb(%)CommercialAvailability/R & DStatus CommentsPost-Combustion ModificationsSNCR Injection of NH3or urea in theconvective passPulverized coalboilers, cyclonefurnaces, stokers, andfluidized bed boilers30 - 60 Commerciallyavailable but notwidely demonstratedApplicable to new boilers or as a retrofit technology;must have sufficient residence time at correcttemperature (1,750E±90EF); elaborate reagent injectionsystem; possible load restrictions on boiler; and possibleair preheater fouling by ammonium bisulfate.SCR Injection of NH3in combinationwith catalystmaterialPulverized coalboilers, cyclonefurnaces75 - 85 Commerciallyoffered, but not yetdemonstratedApplicable to new boilers or as a retrofit technologyprovided there is sufficient space; hot-side SCR best onlow-sulfur fuel and low fly ash applications; cold-sideSCR can be used on high-sulfur/high-ash applications ifequipped with an upstream FGD system.LNB with SNCR Combination ofnew burnerdesigns andinjection of NH3or ureaPulverized coalboilers50-80 Commerciallyoffered, but notwidely demonstratedas a combinedtechnologySame as LNB and SNCR alone.LNB with OFA andSCRCombination ofnew burnerdesign, injectionof air abovecombustion zone,and injection ofNH3or ureaPulverized coalboiler85-95 Commerciallyoffered, but notwidely demonstratedas a combinedtechnologySame as LNB, OFA, and SCR alone.aReferences 20-21.bNOxreduction potential from uncontrolled levels.

# 1.1-16 EMISSION FACTORS 9/98Table 1.1-3. EMISSION FACTORS FOR SOx, NOx, AND COFROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTIONaFiring Configuration SCCSOxbNOxcCOd,eEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGPC, dry bottom,wall-firedf, bituminousPre-NSPSg1-01-002-021-02-002-021-03-002-0638S A 22 A 0.5 APC, dry bottom,wall-firedf, bituminousPre-NSPSgwith low-NOxburner1-01-002-021-02-002-021-03-002-0638S A 11 A 0.5 APC, dry bottom,wall-firedf, bituminousNSPSg1-01-002-021-02-002-021-03-002-0638S A 12 A 0.5 APC, dry bottom,wall-firedf, sub-bituminousPre-NSPSg1-01-002-221-02-002-221-03-002-2235S A 12 C 0.5 APC, dry bottom, wall firedf,sub-bituminous NSPSg1-01-002-221-02-002-221-03-002-2235S A 7.4 A 0.5 APC, dry bottom, cell burnerhfired, bituminous1-01-002-15 38S A 31 A 0.5 APC, dry bottom, cell burnerfired, sub-bituminous1-01-002-35 35S A 14 E 0.5 A

# 9/98 External Combustion Sources 1.1-17Table 1.1-3 (cont.).Firing Configuration SCCSOxbNOxcCOd,eEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGPC, dry bottom, tangentiallyfired, bituminous, Pre-NSPSg1-01-002-121-02-002-121-03-002-1638S A 15 A 0.5 APC, dry bottom, tangentiallyfired, bituminous, Pre-NSPSgwith low-NOxburner1-01-002-121-02-002-121-03-002-1638S A 9.7 A 0.5 APC, dry bottom, tangentiallyfired, bituminous, NSPSg1-01-002-121-02-002-121-03-002-1638S 10 A 0.5 APC, dry bottom, tangentiallyfired, sub-bituminous, PreNSPSg1-01-002-261-02-002-261-03-002-2635S A 8.4 A 0.5 APC, dry bottom, tangentiallyfired, sub-bituminous, NSPSg1-01-002-261-02-002-261-03-002-2635S A 7.2 A 0.5 APC, wet bottom, wall-firedf,bituminous, Pre-NSPSg1-01-002-011-02-002-011-03-002-0538S A 31 D 0.5 APC, wet bottom, tangentiallyfired, bituminous, NSPSg1-01-002-11 38S A 14 E 0.5 APC, wet bottom, wall-firedsub-bituminous1-01-002-211-02B002-211-03-002-2135S A 24 E 0.5 A

# 1.1-18 EMISSION FACTORS 9/98Table 1.1-3 (cont.).Firing Configuration SCCSOxbNOxcCOd,eEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGCyclone Furnace,bituminous1-01-002-031-02-002-031-03-002-03 38S A 33 A 0.5 ACyclone Furnance, subbituminous1-01-002-231-02-002-231-03-002-2335S A 17 C 0.5 ASpreader stoker, bituminous 1-01-002-041-02-002-041-03-002-0938S B 11 B 5 ASpreader Stoker,sub-bituminous1-01-002-241-02-002-241-03-002-2435S B 8.8 B 5 AOverfeed stokeri1-01-002-05/251-02-002-05/251-03-002-07/2538S(35S)B 7.5 A 6 BUnderfeed stoker 1-02-002-061-03-002-0831S B 9.5 A 11 BHand-fed units 1-03-002-14 31S D 9.1 E 275 E

# 9/98 External Combustion Sources 1.1-19Table 1.1-3 (cont.).Firing Configuration SCCSOxbNOxcCOd,eEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/tonEMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGFBC, circulating bed 1-01-002-181-02-002-181-03-002-18CjE 5.0 D 18 EFBC, bubbling bed 1-01-002-171-02-002-171-03-002-17CjE 15.2 D 18 DaFactors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. SCC = SourceClassificationCode. To convert from lb/ton to kg/Mg, multiply by 0.5.bExpressed as SO2, including SO2, SO3, and gaseous sulfates. Factors in parentheses should be used to estimate gaseous SOxemissions forsubbituminous coal. In all cases, S is weight % sulfur content of coal as fired. Emission factor would be calculated by multiplying theweight percent sulfur in the coal by the numerical value preceding S. For example, if fuel is 1.2% sulfur, then S = 1.2. On average forbituminous coal, 95% of fuel sulfur is emitted as SO2, and only about 0.7% of fuel sulfur is emitted as SO3and gaseous sulfate. An equallysmall percent of fuel sulfur is emitted as particulate sulfate (References 22-23). Small quantities of sulfur are also retained in bottom ash.With subbituminous coal, about 10% more fuel sulfur is retained in the bottom ash and particulate because of the more alkalinenature of thecoal ash. Conversion to gaseous sulfate appears about the same as for bituminous coal.

# 1.1-20 EMISSION FACTORS 9/98Table 1.1-3. (cont.)cExpressed as NO2. Generally, 95 volume % or more of NOxpresent in combustion exhaust will be in the form of NO, the rest NO2(Reference 6).To express factors as NO, multiply factors by 0.66. All factors represent emissions at baseline operation (i. e., 60 to 110% load and no NOxcontrolmeasures).dNominal values achievable under normal operating conditions. Values 1 or 2 orders of magnitude higher can occur when combustion is notcomplete.eEmission factors for CO2emissions from coal combustion should be calculated using lb CO2/ton coal = 72.6C, where C is the weight % carboncontent of the coal. For example, if carbon content is 85%, then C equals 85.fWall-fired includes front and rear wall-fired units, as well as opposed wall-fired units.gPre-NSPS boilers are not subject to any NSPS. NSPS boilers are subject to Subpart D or Subpart Da. Subpart D boilers are boilers constructedafter August 17, 1971 and with a heat input rate greater than 250 million Btu per hour (MMBtu/hr). Subpart Da boilers are boilers constructed afterSeptember 18, 1978 and with a heat input rate greater than 250 MMBtu/hr.hReferences 24-27.iIncludes traveling grate, vibrating grate, and chain grate stokers.jSO2emission factors for fluidized bed combustion are a function of fuel sulfur content and calcium-to-sulfur ratio. For both bubbling bed andcirculating bed design, use: lb SO2/ton coal = 39.6(S)(Ca/S)-1.9. In this equation, S is the weight percent sulfur in the fuel and Ca/S is the molarcalcium-to-sulfur ratio in the bed. This equation may be used when the Ca/S is between 1.5 and 7. When no calcium-based sorbents are used andthe bed material is inert with respect to sulfur capture, the emission factor for underfeed stokers should be used to estimatethe SO2emissions. Inthis case, the emission factor ratings are E for both bubbling and circulating units.

# 9/98 External Combustion Sources 1.1-21Table 1.1-4. UNCONTROLLED EMISSION FACTORS FOR PM AND PM-10FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTIONaFiring Configuration SCCFilterable PMbFilterable PM-10Emission Factor(lb/ton)EMISSIONFACTORRATINGEmission Factor(lb/ton)EMISSIONFACTORRATINGPC-fired, dry bottom,wall-fired1-01-002-02/221-02-002-02/221-03-002-06/2210A A 2.3A EPC-fired, dry bottom,tangentially fired1-01-002-12/261-02-002-12/261-03-002-16/2610A B 2.3AcEPC-fired, wet bottom 1-01-002-01/211-02-002-01/211-03-002-05/217AdD 2.6A ECyclone furnace 1-01-002-03/231-02-002-03/231-03-002-03/232AdE 0.26A ESpreader stoker 1-01-002-04/241-02-002-04/241-03-002-09/2466eB 13.2 ESpreader stoker, with multiplecyclones, and reinjection1-01-002-04/241-02-002-04/241-03-002-09/2417 B 12.4 ESpreader stoker, with multiplecyclones, no reinjection1-01-002-04/241-02-002-04/241-03-002-09/2412 A 7.8 E

# 1.1-22 EMISSION FACTORS 9/98Table 1.1-4 (cont.).Firing Configuration SCCFilterable PMbFilterable PM-10Emission Factor(lb/ton)EMISSIONFACTORRATINGEmission Factor(lb/ton)EMISSIONFACTORRATINGOverfeed stokerf1-01-002-05/251-02-002-05/251-03-002-07/2516gC 6.0 EOverfeed stoker, withmultiple cyclonesf1-01-002-05/251-02-002-05/251-03-002-07/259hC 5.0 EUnderfeed stoker 1-02-002-061-03-002-0815jD 6.2 EUnderfeed stoker, withmultiple cyclone1-02-002-061-03-002-0811hD 6.2jEHand-fed units 1-03-002-14 15 E 6.2kEFBC, bubbling bed 1-01-002-171-02-002-171-03-002-17mEmEFBC, circulating bed 1-01-002-181-02-002-181-03-002-18mEmEaFactors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. To convert from lb/ton tokg/Mg, multiply by 0.5. SCC = Source Classification Code.

# 9/98 External Combustion Sources 1.1-23Table 1.1-4 (cont.).bBased on EPA Method 5 (front half catch) as described in Reference 28. Where particulate is expressed in terms of coal ash content, A, factoris determined by multiplying weight % ash content of coal (as fired) by the numerical value preceding the A. For example, if coal with 8%ash is fired in a PC-fired, dry bottom unit, the PM emission factor would be 10 x 8, or 80 lb/ton.cNo data found; emission factor for PC-fired dry bottom boilers used.dUncontrolled particulate emissions, when no fly ash reinjection is employed. When control device is installed, and collected fly ash isreinjected to boiler, particulate from boiler reaching control equipment can increase up to a factor of 2.eAccounts for fly ash settling in an economizer, air heater, or breaching upstream of control device or stack. (Particulate directly at boileroutlet typically will be twice this level.) Factor should be applied even when fly ash is reinjected to boiler from air heateror economizer dusthoppers.fIncludes traveling grate, vibrating grate, and chain grate stokers.gAccounts for fly ash settling in breaching or stack base. Particulate loadings directly at boiler outlet typically can be 50%higher.hSee Reference 4 for discussion of apparently low multiple cyclone control efficiencies, regarding uncontrolled emissions.jAccounts for fly ash settling in breaching downstream of boiler outlet.kNo data found; emission factor for underfeed stoker used.mNo data found; use emission factor for spreader stoker with multiple cyclones and reinjection.

# 1.1-24 EMISSION FACTORS 9/98Table 1.1-5. CONDENSABLE PARTICULATE MATTER EMISSION FACTORS FOR BITUMINOUS AND SUBBITUMINOUS COALCOMBUSTIONaFiringConfigurationbControlscSCCCPM - TOTd, eCPM - IORd, eCPM - ORGd, eEmissionFactor(lb/MMBtu)EMISSIONFACTORRATINGEmissionFactor(lb/MMBtu)EMISSIONFACTORRATINGEmissionFactor(lb/MMBtu)EMISSIONFACTORRATINGAll pulverizedcoal-firedboilersAll PM controls(without FGDcontrols)1-01-002-01/211-01-002-02/221-01-002-12/261-02-002-01/211-02-002-02/221-02-002-12/261-03-002-05/061-03-002-161-03-002-21/221-03-002-260.1S-0.03f,gB 80% of CPM-TOT emissionfactoreE 20% of CPM-TOT emissionfactoreEAll pulverizedcoal-firedboilersAll PM controlscombined withan FGD control1-01-002-01/211-01-002-02/221-01-002-12/261-02-002-01/211-02-002-02/221-02-002-12/261-03-002-05/061-03-002-161-03-002-21/221-03-002-260.02hE ND NDSpreader stoker,travelling grateoverfeed stoker,underfeed stokerAll PM controls,or Uncontrolled1-01-002-04/241-01-002-05/251-02-002-04/241-02-002-05/251-02-002-061-03-002-07/081-03-002-09/111-03-002-161-03-002-24/250.04iC 80% of CPMTOT emissionfactorgE 20% of CPMTOT emissionfactorgE

# 9/98 External Combustion Sources 1.1-25Table 1.1-5 (cont.).aAll condensable PM is assumed to be less than 1.0 micron in diameter.bNo data are available for cyclone boilers (SCCs 1-01-002-03/23, 1-02-002-03/23, 1-03-002-23) or for atmospheric fluidized bed combustion (AFBC) boilers(SCCs 1-01B002-17, 1-02-002-17, 1-03-002-17). For cyclone boilers, use the factors provided for pulverized coal-fired boilers and applicable controldevices. For AFBC boilers, use the factors provided for pulverized coal-fired boilers with PM and FGD controls.cFGD = flue gas desulfurization.dCPM-TOT = total condensable particulate matter.CPM-IOR = inorganic condensable particulate matter.CPM-ORG = organic condensable particulate matter.ND = No data.eFactors should be multiplied by fuel rate on a heat input basis (MMBtu), as fired. To convert to lb/ton of bituminous coal, multiply by 26 MMBtu/ton. Toconvert to lb/ton of subbituminous coal, multiply by 20 MMBtu/ton.fS = coal sulfur percent by weight, as fired. For example, if the sulfur percent is 1.04, then S = 1.04. If the coal sulfur percent is 0.4 or less, use a defaultemission factor of 0.01 lb/MMBtu rather than the emission equation.gReferences 78-94.hReferences 95 and 96.iReferences 97-104.

# 1.1-26 EMISSION FACTORS 9/98Table 1.1-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSIONFACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS AND SUBBITUMINOUS COALaParticleSizeb(Fm)Cumulative Mass %#Stated SizeCumulative Emission Factorc(lb/ton)UncontrolledControlledUncontrolleddControlledeMultipleCyclones Scrubber ESP BaghouseMultipleCyclonesfScrubbergESPgBaghousef15 32 54 81 79 97 3.2A 1.08A 0.48A 0.064A 0.02A10 23 29 71 67 92 2.3A 0.58A 0.42A 0.054A 0.02A6 17 14 62 50 77 1.7A 0.28A 0.38A 0.024A 0.02A2.5 6 3 51 29 53 0.6A 0.06A 0.3A 0.024A 0.01A1.25 2 1 35 17 31 0.2A 0.02A 0.22A 0.01A 0.006A1.00 2 1 31 14 25 0.2A 0.02A 0.18A 0.01A 0.006A0.625 1 1 20 12 14 0.10A 0.02A 0.12A 0.01A 0.002ATOTAL 100 100 100 100 100 10A 2A 0.6A 0.08A 0.02AaReference 33. Applicable Source Classification Codes are 1-01-002-02, 1-02-002-02, 1-03-002-06, 1-01-002-12, 1-02-002-12, and1-03-002-16. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission Factors are lb of pollutant per ton of coal combusted, as fired. ESP =Electrostatic precipitator.bExpressed as aerodynamic equivalent diameter.cA = coal ash weight percent, as fired. For example, if coal ash weight is 8.2%, then A = 8.2.dEMISSION FACTOR RATING = C.eEstimated control efficiency for multiple cyclones is 80%; for scrubber, 94%; for ESP, 99.2%; and for baghouse, 99.8%.fEMISSION FACTOR RATING = E.gEMISSION FACTOR RATING = D.

# 9/98 External Combustion Sources 1.1-27 Table 1.1-7. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR WET BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL a



# EMISSION FACTOR RATING: E

Particle Size b 

# ( F m) Cumulative Mass % # Stated Size Cumulative Emission Factor c 

# (lb/ton)

Controlled Controlled d



# Uncontrolled Multiple Cyclones ESP Uncontrolled Multiple Cyclones ESP

15 40 99 83 2.8A 1.38A 0.046A

10 37 93 75 2.6A 1.3A 0.042A

6 33 84 63 2.32A 1.18A 0.036A

2.5 21 61 40 1.48A 0.86A 0.022A

1.25 6 31 17 0.42A 0.44A 0.01A

1.00 4 19 8 0.28A 0.26A 0.004A

0.625 2 — e



# — e 

# 0.14A — e



# — e



# TOTAL 100 100 100 7.0A 1.4A 0.056A

a 

# Reference 33. Applicable Source Classification Codes are 1-01-002-01, 1-02-002-01, and 1-03-002-05. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are lb of pollutant per ton of coal combusted as fired. ESP = Electrostatic precipitator.

b 

# Expressed as aerodynamic equivalent diameter.

c 

# A = coal ash weight %, as fired. For example, if coal ash weight is 2.4%, then A = 2.4.

d 

# Estimated control efficiency for multiple cyclones is 94%, and for ESPs, 99.2%.

e 

# Insufficient data.

# 1.1-28 EMISSION FACTORS 9/98 Table 1.1-8. CUMULATIVE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR CYCLONE FURNACES BURNING BITUMINOUS COAL a



# EMISSION FACTOR RATING: E

Particle

Size b 

# ( F m) Cumulative Mass % # Stated Size Cumulative Emission Factor c 

# (lb/ton)

Controlled Controlled d



# Uncontrolled Multiple Cyclones ESP Uncontrolled Multiple Cyclones ESP

15 33 95 90 0.66A 0.114A 0.013A

10 13 94 68 0.26A 0.112A 0.011A

6 8 93 56 0.16A 0.112A 0.009A

2.5 5.5 92 36 0.11A e 

# 0.11A 0.006A

1.25 5 85 22 0.10A e 

# 0.10A 0.004A

1.00 5 82 17 0.10A e 

# 0.10A 0.003A

0.625 0 — f



# — f 

# 0 — f



# — f



# TOTAL 100 100 100 2A 0.12A 0.016A

a 

# Reference 33. Applicable Source Classification Codes are 1-01-002-03, 1-02-002-03, and 1-03-002-03. To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted, as fired.

b 

# Expressed as aerodynamic equivalent diameter.

c 

# A = coal ash weight %, as fired. For example, if coal ash weight is 2.4%, then A = 2.4.

d 

# Estimated control efficiency for multiple cyclones is 94%, and for ESPs, 99.2%.

e 

# These values are estimates based on data from controlled source.

f 

# Insufficient data.

# 9/98 External Combustion Sources 1.1-29Table 1.1-9. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFICEMISSION FACTORS FOR SPREADER STOKERS BURNING BITUMINOUS COALaParticleSizeb(Fm)Cumulative Mass %#Stated Size Cumulative Emission Factor (lb/ton)UncontrolledControlledUncontrolledeControlledMultipleCyclonescMultipleCyclonesdESP BaghouseMultipleCyclonesc,fMultipleCyclonesd,eESPf,gBaghousee,g15 28 86 74 97 72 18.5 14.6 8.8 0.46 0.08610 20 73 65 90 60 13.2 12 7.8 0.44 0.0726 14 51 52 82 46 9.2 8.6 6.2 0.40 0.0562.5 7 8 27 61 26 4.6 1.4 3.2 0.30 0.0321.25 5 2 16 46 18 3.3 0.4 2.0 0.22 0.0221.00 5 2 14 41 15 3.3 0.4 1.6 0.20 0.0180.625 4 1 9Ch7 2.6 0.2 1.0Ch0.006TOTAL 100 100 100 100 100 66.0 17.0 12.0 0.48 0.12aReference 33. Applicable Source Classification Codes are 1-01-002-04, 1-02-002-04, 1-03-002-09. To convert from lb/ton to kg/Mg,multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted, as fired.bExpressed as aerodynamic equivalent diameter.cWith flyash reinjection.dWithout flyash reinjection.eEMISSION FACTOR RATING = C.fEMISSION FACTOR RATING = E.gEstimated control efficiency for ESP is 99.22%; and for baghouse, 99.8%.hInsufficient data.

# 1.1-30 EMISSION FACTORS 9/98 Table 1.1-10. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR OVERFEED STOKERS BURNING BITUMINOUS COAL a



# Particle

Size b 

# ( F m) Cumulative Mass %

# Stated Size Cumulative Emission Factor (lb/ton)

Uncontrolled Multiple Cyclones Controlled Uncontrolled Multiple Cyclones Controlled c



# Emission

Factor EMISSION FACTOR RATING Emission Factor EMISSION FACTOR RATING

15 49 60 7.8 C 5.4 E

10 37 55 6.0 C 5.0 E

6 24 49 3.8 C 4.4 E

2.5 14 43 2.2 C 3.8 E

1.25 13 39 2.0 C 3.6 E

1.00 12 39 2.0 C 3.6 E

0.625 — d 

# 16 — d 

# C 1.4 E

TOTAL 100 100 16.0 C 9.0 E

a 

# Reference 33. Applicable Source Classification Codes are 1-01-002-05, 1-02-002-05, and 1-03-002-07. To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted, as fired.

b 

# Expressed as aerodynamic equivalent diameter.

c 

# Estimated control efficiency for multiple cyclones is 80%.

d 

# Insufficient data.

# 9/98 External Combustion Sources 1.1-31 Table 1.1-11. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR UNDERFEED STOKERS BURNING BITUMINOUS COAL a



# EMISSION FACTOR RATING: C

Particle Size b 

# (μm) Cumulative Mass %

# Stated Size Uncontrolled Cumulative Emission Factor c 

# (lb/ton)

15 50 7.6

10 41 6.2

6 32 4.8

2.5 25 3.8

1.25 22 3.4

1.00 21 3.2

0.625 18 2.7

TOTAL 100 15.0

a 

# Reference 33. Applicable Source Classification Codes are 1-02-002-06 and 1-03-002-08. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are lb of pollutant per ton of coal combusted, as fired.

b 

# Expressed as aerodynamic equivalent diameter.

c 

# May also be used for uncontrolled hand-fired units.

# 1.1-32 EMISSION FACTORS 9/98 Table 1.1-12 EMISSION FACTORS FOR POLYCHLORINATED DIBENZO-P-DIOXINS AND POLYCHLORINATED DIBENZOFURANS FROM CONTROLLED BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION

Controls FGD-SDA with FF a 

# ESP or FF b



# Congener Emission Factor c 

# (lb/ton) EMISSION FACTOR RATING Emission Factor c 

# (lb/ton) EMISSION FACTOR RATING
2,3,7,8-TCDD No data --- 1.43E-11 E

Total TCDD 3.93E-10 E 9.28E-11 D

Total PeCDD 7.06E-10 E 4.47E-11 D

Total HxCDD 3.00E-09 E 2.87E-11 D
Total HpCDD 1.00E-08 E 8.34E-11 D

Total OCDD 2.87E-08 E 4.16E-10 D

Total PCDD d 

# 4.28E-08 E 6.66E-10 D
2,3,7,8-TCDF No data --- 5.10E-11 D

Total TCDF 2.49E-09 E 4.04E-10 D

Total PeCDF 4.84E-09 E 3.53E-10 D

Total HxCDF 1.27E-08 E 1.92E-10 D
Total HpCDF 4.39E-08 E 7.68E-11 D

Total OCDF 1.37E-07 E 6.63E-11 D

Total PCDF d 

# 2.01E-07 E 1.09E-09 D

TOTAL PCDD/PCDF 2.44E-07 E 1.76E-09 D

a 

# Reference 34. Factors apply to boilers equipped with both flue gas desulfurization spray dryer absorber (FGD-SDA) and a fabric filter (FF). SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, and 1-03-002-06/22.

b 

# References 35-37. Factors apply to boilers equipped with an electrostatic precipitator (ESP) or a fabric filter. SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06/22; and, cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, and 1-03-002-03/23.

c 

# Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted.

d 

# Total PCDD is the sum of Total TCDD through Total OCDD. Total PCDF is the sum of Total TCDF through Total OCDF.

# 9/98 External Combustion Sources 1.1-33 Table 1.1-13 EMISSION FACTORS FOR POLYNUCLEAR AROMATIC HYDROCARBONS (PAH) FROM CONTROLLED COAL COMBUSTION a



# Pollutant Emission Factor b 

# (lb/ton) EMISSION FACTOR RATING
Biphenyl 1.7E-06 D
Acenaphthene 5.1E-07 B
Acenaphthylene 2.5E-07 B

Anthracene 2.1E-07 B
Benzo(a)anthracene 8.0E-08 B
Benzo(a)pyrene 3.8E-08 D
Benzo(b,j,k)fluoranthene 1.1E-07 B
Benzo(g,h,i)perylene 2.7E-08 D
Chrysene 1.0E-07 C

Fluoranthene 7.1E-07 B

Fluorene 9.1E-07 B
Indeno(1,2,3-cd)pyrene 6.1E-08 C
Naphthalene 1.3E-05 C

Phenanthrene 2.7E-06 B
Pyrene 3.3E-07 B
5-Methyl chrysene 2.2E-08 D

a 

# References 35-45. Factors were developed from emissions data from six sites firing bituminous coal, four sites firing subbituminous coal, and from one site firing lignite. Factors apply to boilers utilizing both wet limestone scrubbers or spray dryers with an electrostatic precipitator (ESP) or fabric filter (FF). The factors also apply to boilers utilizing only an ESP or FF. Bituminous/subbituminous SCCs = pulverized coal-fired dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06; pulverized coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26; and, cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, and 1-03-002-03/23.

b 

# Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted.

# 1.1-34 EMISSION FACTORS 9/98 Table 1.1-14 EMISSION FACTORS FOR VARIOUS ORGANIC COMPOUNDS FROM CONTROLLED COAL COMBUSTION a



# Pollutant b 

# Emission Factor c 

# (lb/ton) EMISSION FACTOR RATING
Acetaldehyde 5.7E-04 C
Acetophenone 1.5E-05 D

Acrolein 2.9E-04 D

Benzene 1.3E-03 A
Benzyl chloride 7.0E-04 D
Bis(2-ethylhexyl)phthalate (DEHP) 7.3E-05 D

Bromoform 3.9E-05 E

Carbon disulfide 1.3E-04 D
2-Chloroacetophenone 7.0E-06 E

Chlorobenzene 2.2E-05 D

Chloroform 5.9E-05 D

Cumene 5.3E-06 E
Cyanide 2.5E-03 D
2,4-Dinitrotoluene 2.8E-07 D
Dimethyl sulfate 4.8E-05 E
Ethyl benzene 9.4E-05 D
Ethyl chloride 4.2E-05 D
Ethylene dichloride 4.0E-05 E
Ethylene dibromide 1.2E-06 E
Formaldehyde 2.4E-04 A

Hexane 6.7E-05 D
Isophorone 5.8E-04 D
Methyl bromide 1.6E-04 D
Methyl chloride 5.3E-04 D
Methyl ethyl ketone 3.9E-04 D
Methyl hydrazine 1.7E-04 E
Methyl methacrylate 2.0E-05 E

# 9/98 External Combustion Sources 1.1-35 Table 1.1-14 (cont.).

Pollutant b 

# Emission Factor c 

# (lb/ton) EMISSION FACTOR RATING
Methyl tert butyl ether 3.5E-05 E
Methylene chloride 2.9E-04 D

Phenol 1.6E-05 D
Propionaldehyde 3.8E-04 D
Tetrachloroethylene 4.3E-05 D

Toluene 2.4E-04 A
1,1,1-Trichloroethane 2.0E-05 E
Styrene 2.5E-05 D
Xylenes 3.7E-05 C
Vinyl acetate 7.6E-06 E

a 

# References 35-53. Factors were developed from emissions data from ten sites firing bituminous coal, eight sites firing subbituminous coal, and from one site firing lignite. The emission factors are applicable to boilers using both wet limestone scrubbers or spray dryers and an electrostatic precipitator (ESP) or fabric filter (FF). In addition, the factors apply to boilers utilizing only an ESP or FF. SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06/22; pulverized coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26; cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23; and, atmospheric fluidized bed combustors, circulating bed, 1-01-002-18/38, 1-02-002-18, and 1-03-002-18.

b 

# Pollutants sampled for but not detected in any sampling run include: Carbon tetrachloride- 2 sites; 1,3-Dichloropropylene- 2 sites; N-nitrosodimethylamine- 2 sites; Ethylidene dichloride- 2 sites; Hexachlorobutadiene- 1 site; Hexachloroethane- 1 site; Propylene dichloride- 2 sites; 1,1,2,2-Tetrachloroethane- 2 sites; 1,1,2-Trichloroethane- 2 sites; Vinyl chloride- 2 sites; and, Hexachlorobenzene- 2 sites.

c 

# Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by 0.5.

# 1.1-36 EMISSION FACTORS 9/98Table 1.1-15. EMISSION FACTORS FOR HYDROGEN CHLORIDE (HCI) AND HYDROGEN FLUORIDE (HF) FROMCOAL COMBUSTIONaEMISSION FACTOR RATING: BFiring Configuration SCCHCl HFEmission Factor (lb/ton) Emission Factor (lb/ton)PC-fired, dry bottom 1-01-002-02/221-02-002-02/221-03-002-06/221.2 0.15PC-fired, dry bottom, tangential 1-01-002-12/261-02-002-12/261-03-002-16/261.2 0.15PC-fired, wet bottom 1-01-002-01/211-02-002-01/211-03-002-05/211.2 0.15Cyclone Furnace 1-01-002-03/231-02-002-03/231-03-002-03/231.2 0.15Spreader Stoker 1-01-002-04/241-02-002-04/241-03-002-09/241.2 0.15Overfeed Stoker 1-01-002-05/251-02-002-05/251-03-002-07/251.2 0.15Underfeed Stoker 1-02-002-061-03-002-081.2 0.15FBC, Bubbling Bed 1-01-002-171-02-002-171-03-002-171.2 0.15FBC, Circulating Bed 1-01-002-18/381-02-002-181-03-002-181.2 0.15Hand-fired 1-03-002-14 1.2 0.15aReference 54. The emission factors were developed from bituminouscoal, subbituminous coal, and lignite emissions data. To convert fromlb/ton to kg/Mg, multiply by 0.5. The factorsapply to both controlled and uncontrolled sources.

# 9/98 External Combustion Sources 1.1-37 Table 1.1-16. EMISSION FACTOR EQUATIONS FOR TRACE ELEMENTS FROM COAL COMBUSTION a



# EMISSION FACTOR EQUATION RATING: A b



# Pollutant Emission Equation (lb/10 12 

# Btu) c


# Antimony 0.92 * (C/A * PM) 0.63


# Arsenic 3.1 * (C/A * PM) 0.85


# Beryllium 1.2 * (C/A * PM) 1.1


# Cadmium 3.3 * (C/A * PM) 0.5


# Chromium 3.7 * (C/A * PM) 0.58


# Cobalt 1.7 * (C/A * PM) 0.69


# Lead 3.4 * (C/A * PM) 0.80


# Manganese 3.8 * (C/A * PM) 0.60


# Nickel 4.4 * (C/A * PM) 0.48

a 

# Reference 55. The equations were developed from emissions data from bituminous coal combustion, subbituminous coal combustion, and from lignite combustion. The equations may be used to generate factors for both controlled and uncontrolled boilers. The emission factor equations are applicable to all typical firing configurations for electric generation (utility), industrial, and commercial/industrial boilers firing bituminous coal, subbituminous coal, and lignite. Thus, all SCCs for these boilers are assigned to the factors.

b 

# AP-42 criteria for rating emission factors were used to rate the equations.

c 

# The factors produced by the equations should be applied to heat input. To convert from lb/10 12 

# Btu to kg/joules, multiply by 4.31 x 10 -16



# . C = concentration of metal in the coal, parts per million by weight (ppmwt). A = weight fraction of ash in the coal. For example, 10% ash is 0.1 ash fraction. PM = Site-specific emission factor for total particulate matter, lb/10 6 

# Btu.

# 1.1-38 EMISSION FACTORS 9/98Table 1.1-17. EMISSION FACTORS FOR TRACE ELEMENTS, POM, AND HCOH FROM UNCONTROLLED BITUMINOUS ANDSUBBITUMINOUS COAL COMBUSTIONaEMISSION FACTOR RATING: EFiring Configuration(SCC)Emission Factor, lb/1012BtuAs Be Cd Cr PbbMn Hg Ni POM HCOHPulverized coal, configurationunknown (no SCC)ND ND ND 1922 ND ND ND ND ND 112cPulverized coal, wet bottom(1-01-002-01/21, 1-02-002-01/21,1-03-002-05/21)538 81 44-70 1020-1570507 808-2980 16 840-1290 ND NDPulverized coal, dry bottom(1-01-002-02/22, 1-02-002-06/22,1-03-002-06/22)684 81 44.4 1250-1570507 228-2980 16 1030-12902.08 NDPulverized coal, dry bottom,tangential (1-01-002-12/26,1-02-002-12/26, 1-03-002-16/26)ND ND ND ND ND ND ND ND 2.4 NDCyclone furnace (1-01-002-03/23,1-02-002-03/23, 1-03-002-03/23)115 <81 28 212-1502 507 228-1300 16 174-1290 ND NDStoker, configuration unknown(no SCC)ND 73 ND 19-300 ND 2170 16 775-1290 ND NDSpreader stoker (1-01-002-04/24,1-02-002-04/24, 1-03-002-09/24)264-542 ND 21-43 942-1570 507 ND ND ND ND 221dOverfeed stoker, traveling grate(1-01-002-05/25, 1-02-002-05/25,1-03-002-07/25)542-1030 ND 43-82 ND 507 ND ND ND ND 140eaReferences 56-61. The emission factors in this table represent the ranges of factors reported in the literature. If only 1 data point was found,it is still reported in this table. To convert from lb/1012Btu to pg/J, multiply by 0.43. SCC = Source Classification Code. ND = no data.bLead emission factors were taken directly from an EPA background document for support of the National Ambient Air Quality Standards.cBased on 2 units; 133 x 106Btu/hr and 1550 x 106Btu/hr.dBased on 1 unit; 59 x 106Btu/hr.

# 9/98 External Combustion Sources 1.1-39 Table 1.1-18 EMISSION FACTORS FOR TRACE METALS FROM CONTROLLED COAL COMBUSTION a



# Pollutant Emission Factor (lb/ton) b 

# EMISSION FACTOR RATING
Antimony 1.8E-05 A

Arsenic 4.1E-04 A
Beryllium 2.1E-05 A

Cadmium 5.1E-05 A

Chromium 2.6E-04 A
Chromium (VI) 7.9E-05 D

Cobalt 1.0E-04 A

Lead 4.2E-04 A
Magnesium 1.1E-02 A
Manganese 4.9E-04 A
Mercury 8.3E-05 A

Nickel 2.8E-04 A

Selenium 1.3E-03 A

a 

# References 35-53, 62-70. The emission factors were developed from emissions data at eleven facilities firing bituminous coal, fifteen facilities firing subbituminous coal, and from two facilities firing lignite. The factors apply to boilers utilizing either venturi scrubbers, spray dryer absorbers, or wet limestone scrubbers with an electrostatic precipitator (ESP) or Fabric Filter (FF). In addition, the factors apply to boilers using only an ESP, FF, or venturi scrubber. SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06/22; pulverized coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26; cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23; and, atmospheric fluidized bed combustors, circulating bed, 1-01-002-18/38, 1-02-002-18, and 1-03-002-18.

b 

# Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply by 0.5.

# 1.1-40 EMISSION FACTORS 9/98Table 1.1-19. EMISSION FACTORS FOR CH4, TNMOC, AND N2O FROM BITUMINOUS AND SUBBITUMINOUS COALCOMBUSTIONaFiring ConfigurationSCCCH4bTNMOCb,cN2OdEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGPC-fired, dry bottom,wall fired1-01-002-02/221-02-002-02/221-03-002-06/220.04 B0.06 B0.03 BPC-fired, dry bottom,tangentially fired1-01-002-12/261-02-002-12/261-03-002-16/260.04 B0.06 B0.08 BPC-fired, wet bottom1-01-002-01/211-02-002-01/211-03-002-05/210.05 B0.04 B0.08 ECyclone furnace1-01-002-03/231-02-002-03/231-03-002-03/230.01 B0.11 B0.09eESpreader stoker1-01-002-04/241-02-002-04/241-03-002-09/240.06 B0.05 B0.04fDSpreader stoker, with multiplecyclones, and reinjection1-01-002-04/241-02-002-04/241-03-002-09/240.06 B0.05 B0.04fESpreader stoker, with multiplecyclones, no reinjection1-01-002-04/241-02-002-04/241-03-002-09/240.06 B0.05 B0.04fE

# 9/98 External Combustion Sources 1.1-41Table 1.1-19 (cont.).Firing ConfigurationSCCCH4bTNMOCb,cN2OdEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGEmissionFactor(lb/ton)EMISSIONFACTORRATINGOverfeed stokerg1-01-002-05/251-02-002-05/251-03-002-07/250.06 B0.05 B0.04fEOverfeed stoker, with multiplecyclonesg1-01-002-05/251-02-002-05/251-03-002-07/250.06 B0.05 B0.04fEUnderfeed stoker 1-02-002-061-03-002-080.8 B1.3 B0.04fEUnderfeed stoker, with multiplecyclone1-02-002-061-03-002-080.8 B1.3 B0.04fEHand-fed units1-03-002-145E10E0.04fEFBC, bubbling bed 1-01-002-171-02-002-171-03-002-170.06hE 0.05hE 3.5hBFBC, circulating bed1-01-002-181-02-002-181-03-002-180.06 E0.05 E3.5 BaFactors represent uncontrolled emissions unless otherwise specifiedand should be applied to coal feed, as fired. SCC = SourceClassification Code. Toconvert from lb/ton to kg/Mg, multiply by 0.5.bReference 32. Nominal values achievable under normal operating conditions; values 1 or 2 orders of magnitude higher can occurwhen combustion is notcomplete.cTNMOC are expressed as C2to C16alkane equivalents (Reference 71). Because of limited data, the effects of firing configuration on TNMOC emissionfactors could not be distinguished. As a result, all data wereaveraged collectively to develop a single average emission factor for pulverized coal units,cyclones, spreaders, and overfeed stokers.dReferences 14-15.eNo data found; emission factor for pulverized coal-fired dry bottom boilers used.fNo data found; emission factor for spreader-stoker boilers used.gIncludes traveling grate, vibrating grate, and chain grate stokers.hNo data found; emission factor for circulating fluidized bed used.

# 1.1-42 EMISSION FACTORS 9/98 44 ton CO 2



# 12 ton C x 0.99 x 2000 lb CO 2 

# ton CO 2 

# x 1
100% 

# ' 72.6 lb CO 2 

# ton %C 

# Table 1.1-20. DEFAULT CO 2 

# EMISSION FACTORS FOR U. S. COALS a



# EMISSION FACTOR RATING: C

Coal Type Average %C b 

# Conversion Factor c 

# Emission Factor d 

# (lb/ton coal)

Subbituminous 66.3 72.6 4810
High-volatile bituminous 75.9 72.6 5510

Medium-volatile bituminous 83.2 72.6 6040

Low-volatile bituminous 86.1 72.6 6250

a 

# This table should be used only when an ultimate analysis is not available. If the ultimate analysis is

available, CO 2 

# emissions should be calculated by multiplying the %carbon (%C) by 72.6 This resultant factor would receive a quality rating of “B”.

b 

# An average of the values given in References 2,76-77. Each of these references listed average carbon

contents for each coal type (dry basis) based on extensive sampling of U.S. coals.

c 

# Based on the following equation:

Where: 44 = molecular weight of CO 2 

# , 12 = molecular weight of carbon, and 0.99 = fraction of fuel oxidized during combustion (Reference 16).

d 

# To convert from lb/ton to kg/Mg, multiply by 0.5.

# 9/98 External Combustion Sources 1.1-43 Figure 1.1-1. Cumulative size-specific emission factors for an example dry bottom boiler burning pulverized bituminous coal.

Figure 1.1-2. Cumulative size-specific emission factors for an example wet bottom boiler burning pulverized bituminous coal.

# 1.1-44 EMISSION FACTORS 9/98 Figure 1.1-3. Cumulative size-specific emission factors for an example cyclone furnace burning bituminous coal.

Figure 1.1-4. Cumulative size-specific emission factors for an example spreader stoker burning bituminous coal.

# 9/98 External Combustion Sources 1.1-45 Figure 1.1-5. Cumulative size-specific emission factors for an example overfeed stoker burning bituminous coal.

Figure 1.1-6. Cumulative size-specific emission factors for an example underfeed stoker burning bituminous coal.

# 1.1-46 EMISSION FACTORS 9/98 References For Section 1.1

1. Bartok, B., Sarofina, A. F. (eds), Fossil Fuel Combustion, A Source Book , John Wiley & Sons, Inc., 1991, p. 239.

2. Steam: It Generation And Use , 38th Edition, Babcock and Wilcox, New York, 1975.

3. Combustion . Fossil Power Systems. Third Edition. Published by Combustion Engineering, Inc. Windsor, CT., 1981.

4. Emission Factor Documentation For AP-42 Section 1.1 — Bituminous and Subbituminous Coal Combustiont , U. S. Environmental Protection Agency, Research Triangle Park, NC, April 1993.

5. Control Techniques For Nitrogen Oxides Emissions From Stationary Sources , 2nd Edition, EPA-450/1-78-001, U. S. Environmental Protection Agency, Research Triangle Park, NC, January 1978.

6. Review Of NO

x 

# Emission Factors For Stationary Fossil Fuel Combustion Sources
, EPA-450/4-79-021, U. S. Environmental Protection Agency, Research Triangle Park, NC, September 1979.

7. K. J. Lim, et al
., Technology Assessment Report For Industrial Boiler Applications: NO
x 

# Combustion Modification , EPA-600/7-79-178f, U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1979.

8. Particulate Polycyclic Organic Matter, National Academy of Sciences, Washington, DC, 1972.

9. Vapor Phase Organic Pollutants- Volatile Hydrocarbons and Oxidation Products, National Academy of Sciences, Washington, DC, 1976.

10. D. H. Klein, et al ., "Pathways of Thirty-Seven Trace Elements Through Coal-Fired Power Plants", Environmental Science and Technology, 9:973-979,1975.

11. D. G. Coles, et al ., "Chemical Studies of Stack Fly Ash from a Coal-Fired Power Plant", Environmental Science and Technology, 13:455-459, 1979.

12. S. Baig, et al ., Conventional Combustion Environmental Assessment, EPA Contract No. 68-02-3138, U. S. Environmental Protection Agency, Research Triangle Park, NC, 1981.

13. L. P. Nelson, et al
., Global Combustion Sources of Nitrous Oxide Emissions , Research Project 2333-4 Interim Report, Sacramento: Radian Corporation, 1991.

14. 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.

15. S. D. Piccot, et al
., Emissions and Cost Estimates for Globally Significant Anthropogenic Combustion Sources of NO

x 

# , N 2 

# O, CH 4 

# , CO, and CO 2 

# , U. S. Environmental Protection Agency, Office of Research and Development, Research Triangle Park, NC, 1990.

# 9/98 External Combustion Sources 1.1-47 16. 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.

17. G. Marland and R. M. Rotty, Carbon Dioxide Emissions from Fossil Fuels: A Procedure For Estimation and Results For 1950-1982
, Tellus , 36B: 232-261.

18. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of 1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.

19. Control Techniques For Sulfur Dioxide Emissions From Stationary Sources, 2nd Edition , EPA-450/3-81-004, U. S. Environmental Protection Agency, Research Triangle Park, NC, April 1981.

20. Alternative Control Techniques Document--NO

x 

# Emissions From Utility Boilers , EPA-453/R-94- 023, March 1994, pp. 2-15, 2-18, 5-103.

21. Emission Factor Documentation For AP-42, Section 1.1, Bituminous and Subbituminous Coal Combustion , Prepared by Acurex Environmental Corp., Edward Aul & Associates, Inc., E. H. Pechan And Associates, Inc., EPA Contract No. 68-D0-11210, April 1993.

22. Carlo Castaldini, and Meredith Angwin, Boiler Design And Operating Variables Affecting Uncontrolled Sulfur Emissions From Pulverized Coal Fired Steam Generators , EPA-450/3-77-047, U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1977.

23. K. Cushing, et al ., "Fabric Filtration Experience Downstream From Atmospheric Fluidized Bed Combustion Boilers", Presented at the Ninth Particulate Control Symposium, October 1991.

24. Susan Stamey-Hall, Evaluation of Nitrogen Oxide Emissions Data from TVA Coal-Fired Boilers
, EPA-600/R-92-242, U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1992.

25. Joel Vatsky and Timothy W. Sweeney, Development of an Ultra-Low No

x 

# Pulverizer Coal Burner , Presented at the EPA/EPRI 1991 Joint Symposium on Combustion No

x 

# Control, March 25-28, 1991, Washington, DC.

26. T. L. Lu, R. L. Lungren, and A. Kokkinos, Performance of a Large Cell-Burner Utility Boiler Retrofitted with Foster Wheeler Low-NO

x 

# Burners , Presented at the EPA/EPRI 1991 Joint Symposium on Combustion NO

x 

# Control, March 25-28, 1991, Washington, DC.

27. Alternative Control Techniques Document — NO

x 

# Emissions from Utility Boilers , EPA-453/ R-94-023, U. S. Environmental Protection Agency, Research Triangle Park, NC, March 1994.

28. Standards Of Performance For New Stationary Sources , 36 FR 24876, December 23, 1971.

# 1.1-48 EMISSION FACTORS 9/98 29. Field Tests Of Industrial Stoker Coal Fired Boilers For Emission Control And Efficiency Improvement - Sites L1 — 17 , EPA-600/7-81-020a, U. S. Environmental Protection Agency, Washington, DC, February 1981.

30. Application Of Combustion Modifications To Control Pollutant Emissions From Industrial Boilers — Phase I , EPA-650/2-74-078a, U. S. Environmental Protection Agency, Washington, DC, October 1974.

31. Source Sampling Residential Fireplaces For Emission Factor Development
, EPA-50/3-6-010, U. S. Environmental Protection Agency, Research Triangle Park, NC, November 1875.

32. Atmospheric Emissions From Coal Combustion: An Inventory Guide , 999-AP-24, U. S. Environmental Protection Agency, Washington, DC, April 1966.

33. Inhalable Particulate Source Category Report For External Combustion Sources
, EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.

34. Results of the March 28, 1990 Dioxin Emission Performance Test on Unit 3 at the NSP Sherco Plant in Becker, Minnesota. Interpoll Laboratories, Inc., Circle Pines, Minnesota. July 11, 1990.

35. Field Chemical Emissions Monitoring Project: Site 22 Emissions Report. Radian Corporation, Austin, Texas. February, 1994.

36. Toxics Assessment Report. Illinois Power Company. Baldwin Power Station- Unit 2. Baldwin, Illinois. Volumes I- Main Report. Roy F. Weston, Inc. West Chester, Pennsylvania. December, 1993.

37. Toxics Assessment Report. Minnesota Power Company Boswell Energy Center- Unit 2. Cohasset, Minnesota. Volume 1-Main Report. Roy F. Weston, Inc. West Chester, Pennsylvania. December, 1993. (EPRI Report)

38. Field Chemical Emissions Monitoring Project: Site 11 Emissions Monitoring. Radian Corporation, Austin, Texas. October, 1992. (EPRI Report)

39. Field Chemical Emissions Monitoring Project: Site 21 Emissions Monitoring. Radian Corporation, Austin, Texas. August, 1993. (EPRI Report)

40. Field Chemical Emissions Monitoring Project: Site 111 Emissions Report. Radian Corporation, Austin, Texas. May, 1993. (EPRI Report)

41. Field Chemical Emissions Monitoring Project: Site 115 Emissions Report. Radian Corporation, Austin, Texas. November, 1994. (EPRI Report)

42. Draft Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant-Niles Station No. 2. Volumes One, Two, and Three. Battelle, Columbus, Ohio. December 29, 1993.

43. Draft Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing an ESP/Wet FGD System. Volumes One, Two, and Three. Battelle, Columbus, Ohio. December 1993.

# 9/98 External Combustion Sources 1.1-4944. Assessment of Toxic Emissions From a Coal Fired Power Plant Utilizing an ESP. Final ReportRevision 1. Energy and Environmental Research Corporation, Irvine, California. December 23, 1993.

45. 500-MW Demonstration of Advanced Wall-Fired Combustion Techniques for the Reduction of Nitrogen Oxide (NOx) Emissions from Coal-Fired Boilers. Radian Corporation, Austin, Texas.

46. Results of the November 7, 1991 Air Toxic Emission Study on the Nos. 3, 4, 5 & 6 Boilers at the NSP High Bridge Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3, 1992.

47. Results of the December 1991 Air Toxic Emission Study on Units 6 & 7 at the NSP Riverside Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. February 28, 1992.

48. Field Chemical Emissions Monitoring Project: Site 10 Emissions Monitoring. Radian Corporation, Austin, Texas. October, 1992. (EPRI Report)

49. Field Chemical Emissions Monitoring Project: Site 12 Emissions Monitoring. Radian Corporation, Austin, Texas. November, 1992. (EPRI Report)

50. Field Chemical Emissions Monitoring Project: Site 15 Emissions Monitoring. Radian Corporation, Austin, Texas. October, 1992. (EPRI Report)

51. Field Chemical Emissions Monitoring Project: Site 101 Emissions Report. Radian Corporation, Austin, Texas. October, 1994. (EPRI Report)

52. Field Chemical Emissions Monitoring Project: Site 114 Report. Radian Corporation, Austin, Texas. May, 1994. (EPRI Report)

53. Field Chemical Emissions Monitoring Report: Site 122. Final Report, Task 1 Third Draft. EPRI RP9028-10. Southern Research Institute, Birmingham, Alabama. May, 1995. (EPRI Report)

54. Hydrogen Chloride And Hydrogen Fluoride Emission Factors For The NAPAP Inventory, EPA600/7-85-041, U. S. Environmental Protection Agency, October 1985.

55. Electric Utility Trace Substances Synthesis Report, Volume 1, Report TR-104614, Electric Power Research Institute, Palo Alto, CA, November 1994.

56. Locating And Estimating Air Emissions From Sources Of Chromium , EPA-450/4-84-007g, U. S. Environmental Protection Agency, July 1984.

57. Locating And Estimating Air Emissions From Sources Of Formaldehyde , (Revised), EPA-450/4-91-012, U. S. Environmental Protection Agency, March 1991.

58. Estimating Air Toxics Emissions From Coal And Oil Combustion Sources , EPA-450/2-89-001, Radian Corporation, Project Officer: Dallas W. Safriet, Research Triangle Park, NC, April 1989.

59. Canadian Coal-Fired Plants, Phase I: Final Report And Appendices , Report for the Canadian Electrical Association, R&D, Montreal, Quebec, Contract Number 001G194, Report by Battelle, Pacific Northwest Laboratories, Richland, WA.

# 1.1-50 EMISSION FACTORS 9/98 60. R. Meij, Auteru dr., The Fate Of Trace Elements At Coal-Fired Plants , Report No. 2561-MOC 92-3641, Rapport te bestellen bij; bibliotheek N.V. KEMA, February 13, 1992.

61. Locating And Estimating Air Emissions From Sources Of Manganese , EPA-450/4-84-007h, September 1985.

62. Results of the September 10 and 11, 1991 Mercury Removal Tests on the Units 1 & 2, and Unit 3 Scrubber Systems at the NSP Sherco Plant in Becker, Minnesota. Interpoll Laboratories, Inc., Circle Pines, Minnesota. October 30, 1991.

63. Results of the November 5, 1991 Air Toxic Emission Study on the No. 1, 3 & 4 Boilers at the NSP Black Dog Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3, 1992.

64. Results of the January 1992 Air Toxic Emission Study on the No. 2 Boiler at the NSP Black Dog Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. May 4, 1992.

65. Results of the May 29, 1990 Trace Metal Characterization Study on Units 1 and 2 at the Sherburne County Generating Station in Becker, Minnesota. Interpoll Laboratories, Inc., Circle Pines, Minnesota. July, 1990.

66. Results of the May 1, 1990 Trace Metal Characterization Study on Units 1 and 2 at the Sherburne County Generating Station. Interpoll Laboratories, Inc., Circle Pines, Minnesota. July 18, 1990.

67. Results of the March 1990 Trace Metal Characterization Study on Unit 3 at the Sherburne County Generating Station. Interpoll Laboratories, Circle Pines, Minnesota. June 7, 1990.

68. Field Chemical Emissions Monitoring Project: Site 19 Emissions Monitoring. Radian Corporation, Austin, Texas. April, 1993. (EPRI Report)

69. Field Chemical Emissions Monitoring Project: Site 20 Emissions Monitoring. Radian Corporation, Austin, Texas. March, 1994. (EPRI Report)

70. Characterizing Toxic Emissions from a Coal-Fired Power Plant Demonstrating the AFGD ICCT Project and a Plant Utilizing a Dry Scrubber /Baghhouse System. Final Draft Report. Springerville Generating Station Unit No. 2. Southern Research Insititute, Birmingham, Alabama. December, 1993.

71. Emissions Of Reactive Volatile Organic Compounds From Utility Boilers
, EPA-600/7-80-111, U. S. Environmental Protection Agency, Washington, DC, May 1980.

72. EPA/IFP European Workshop On The Emission Of Nitrous Oxide For Fuel Combustion , EPA Contract No. 68-02-4701, Ruiel-Malmaison, France, June 1-2, 1988.

73. R. Clayton, et al
., NO
x 

# Field Study , EPA-600/2-89-006, U. S. Environmental Protection Agency, Research Triangle Park, NC, February 1989.

74. L. E. Amand, and S. Anderson, "Emissions of Nitrous Oxide from Fluidized Bed Boilers", Presented at the Tenth International Conference on Fluidized Bed Combustor, San Francisco, CA, 1989.

# 9/98 External Combustion Sources 1.1-51 75. Alternative Control Techniques Document--NO

x 

# Emissions From Utility Boilers
, EPA-453/R-94-023, Office of Air Quality Standards, Research Triangle Park, NC, 1994.

76. Alliance Technologies Corporation, Evaluation of Significant Anthropogenic Sources of Radiatively Important Trace Gases , U. S. Environmental Protection Agency, Office of Research and Development, Research Triangle Park, NC, 1990.

77. R. A. Winschel, Richard, "The Relationship of Carbon Dioxide Emissions with Coal Rank and Sulfur Content," Journal of the Air and Waste Management Association , Vol. 40, no. 6, pp. 861- 865, June 1990.

78. Public Service Electric and Gas Company Mercer Generating Station Unit No. 2 Emission Compliance Test Program. November 1994.

79. Particulate Emission Study Performed for Madison Gas and Electric Company at the Blount Street Station Units 7, 8, 9 Inlets/Outlets. Mostardi-Platt Associates, Inc. December 6, 1994.

80. Particulate Emission Study Performed for Marshfield Electric and Water Department at the Wildwood Station Marshfield Wisconsin Boiler 5 Stack. Mostardi-Platt Associates, Inc. January 23-25, 1990.

81. Report on Particulate, SO 2 

# , and NO

x 

# Compliance Testing. Dairyland Power Cooperative J.P. Madgett Stack. Alma, Wisconsin. CAE. January 6, 1995.

82. Particulate Emissions Test Results. Portland General Electric Coal-fired Power Plant. Boardman, Oregon. SAIC, Inc. January 25, 1994.

83. Report on Compliance Testing Performed at Marshfield Electric and Water Department Wildwood Station Unit 5, Marshfield, Wisconsin. Clean Air Engineering, December 11, 1989.

84. Portland General Electric Company Boardman Coal Plant. Unit #1 Coal-fired Boiler. Boardman, Oregon. August 24-27,1995.

85. Particulate Emission Compliance Study Performed for Portland General Electric at the Boardman Plant Unit 1 Stack. Boardman, Oregon. September 19, 1996.

86. Emissions Source Test Report. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. October 17, 1990.

87. Source Emissions Test Report Compliance. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services. January 29, 1991.

88. Source Test Report. Particulate Emissions. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. January 14, 1991.

89. Emissions Source Test Rpeort. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. April 3, 1991.

90. Source Emissions Test Report. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. January 21, 1992.

# 1.1-52 EMISSION FACTORS 9/98 91. Particulate Emissions Test Results. Portland General Electric Coal-fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. April 4, 1992.

92. Particulate Emissions Test Results. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. September 9, 1992.

93. Particulate Emissions Test Results. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. November 6, 1992.

94. Particulate Emissions Test Results. Portland General Electric Coal-Fired Power Plant. Boardman, Oregon. OMNI Environmental Services, Inc. January 26, 1993.

95. Stationary Source Sampling Report. Keystone Cogeneration Facility. Keystone Cogeneration Facility. Logan Township, NJ. November 1994.

96. Source Emissions Survey of City Public Service Board J.K. Spruce Unit Number 1 Stack. METCO Environmental. December 1992.

97. Report of Particulate Emission Testing on the Number 1 Boiler at Associated Milk Products Incorporated Located in Jim Falls, Wisconsin. Environmental Services of American, Inc. November 1994.

98. Appletone Papers, Inc. Boiler Emission Test at Appleton, WI. May 11 and 12, 1993. Badger Laboratories and Engineering.

99. Appleton Papers, Inc. Boiler Emission Test Report at Appleton, WI. Badger Laboratories and Engineering. October 11, 1993.

100. Results of a Source Emission Compliance Test on Boiler #2 at the Hills Farm Heating Plant, Madison, Wisconsin. MMT Environmental Services, Inc. January 22, 1993.

101. Results of a Source Emission Compliance Test on Boiler #2 at the Hills Farm Heating Plant, Madison, Wisconsin. MMT Environmental Services, Inc. March 2, 1995.

102. Report to Mosinee Paper Company for Particulate Matter Emission Testing. No. 6 Boiler at Mosinee, Wisconsin. May 18, 19, and 20, 1993.

103. Report to Milwaukee County for Particulate Matter Emission Test Boiler No. 21. Environmental Technology and Engineering Corporation. November 5, 1991.

104. Report on Compliance Testing Conducted at Oscar Mayer Foods Corporation, Madison, Wisconsin. Clean Air Engineering. July 21, 1989.