EMISSION FACTOR
DOCUMENTATION FOR
AP-42 SECTION 1.1
BITUMINOUS AND SUBBITUMINOUS COAL
COMBUSTION
By:
Acurex Environmental Corporation
Research Triangle Park, North Carolina 27709
Edward Aul & Associates, Inc.
Chapel Hill, North Carolina 27514
E. H. Pechan and Associates, Inc.
Rancho Cordova, California 95742
Contract No. 68-DO-00120
Work Assignment No. II-68
EPA Project Officer: Alice C. Gagnon
Office of Air Quality Planning and Standards
Office Of Air And Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
April 1993
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DISCLAIMER
This report has been reviewed by the Office of Air Quality Planning and Standards,
U. S. Environmental Protection Agency, and approved for publication. Mention of trade
names or commercial products does not constitute endorsement or recommendation for
use.
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TABLE OF CONTENTS
LIST OF TABLES v
LIST OF FIGURES vi
CHAPTER! INTRODUCTION 1-1
CHAPTER 2. SOURCE DESCRIPTION 2-1
2.1 CHARACTERIZATION OF BITUMINOUS AND
SUBBITUMINOUS APPLICATIONS 2-1
2.2 PROCESS DESCRIPTIONS 2-2
2.2.1 Suspension Firing 2-3
2.2.2 Stoker Firing 2-4
2.2.3 Fluidized Bed Combustion 2-5
2.2.4 Handfeed Units 2-6
2.3 EMISSIONS 2-7
2.3.1 Particulate Matter Emissions 2-8
2.3.2 Sulfur Oxide Emissions 2-9
2.3.3 Nitrogen Oxide Emissions 2-9
2.3.4 Carbon Monoxide Emissions 2-11
2.3.5 Organic Compound Emissions 2-12
2.3.6 Trace Element Emissions 2-14
2.3.7 Fugitive Emissions 2-15
2.4 CONTROL TECHNOLOGIES 2-16
2.4.1 Fuel Treatment/Substitution 2-16
2.4.2 Combustion Modification 2-18
2.4.3 Post-Combustion Control 2-22
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REFERENCES 2-47
CHAPTER 3. GENERAL EMISSION DATA REVIEW AND
ANALYSIS PROCEDURE 3-1
3.1 CRITERIA POLLUTANTS 3-1
3.1.1 Literature Search 3-1
3.1.2 Literature Evaluation 3-1
3.1.3 Emission Factor Quality Rating
3.2 SPECIATED VOCs 3-5
3.2.1 Literature Search 3-5
3.2.2 Literature Evaluation
3.2.3 Data and Emission Factor Quality Rating 3-5
3.3 AIR TOXICS 3-6
3.3.1 Literature Search 3-6
3.3.2 Literature Evaluation for Air Toxics 3-7
IV
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TABLE OF CONTENTS (continued)
3.3.3 Data and Emission Factor Quality Rating Criteria 3-7
3.4 N20 3-8
3.4.1 Literature Search 3-8
3.4.2 Literature Evaluation 3-8
3.4.3 Data and Emission Factor Quality Rating 3-9
3.5 FUGITIVES 3-9
3.6 PARTICLE SIZE DISTRIBUTION 3-10
3.6.1 Literature Search 3-10
3.6.2 Literature Evaluation 3-11
3.6.3 Data Quality Ranking 3-12
REFERENCES 3-18
CHAPTER 4. EMISSION FACTOR DEVELOPMENT 4-1
4.1 CRITERIA POLLUTANTS 4-1
4.1.1 Review of Previous AP-42 Data 4-1
4.1.2 Review of New Baseline Data 4-2
4.1.3 Compilation of Baseline Emission Factors 4-5
4.1.4 Compilation of Controlled Emission Factors 4-13
4.2 SPECIATED VOCs 4-13
4.3 AIR TOXICS 4-14
4.3.1 Review of New Data 4-14
4.3.2 Baseline Emission Factors 4-17
4.3.3 Controlled Emission Factors 4-19
4.4 N20 4-20
4.5 PARTICLE SIZE
DISTRIBUTION 4-22
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4.5.1 Review of Previous AP-42 Data 4-22
4.5.2 Review of New Data 4-23
4.6.3 Compilation of Uncontrolled Emission Factors 4-25
4.6.4 Control Technology Emission Factors 4-26
REFERENCES 4-57
CHAPTER 5. AP-42 SECTION 1.1: BITUMINOUS AND SUBBITUMINOUS
COAL COMBUSTION 5-1
APPENDIX A. BACKGROUND FILE SPOT CHECK SUMMARY A-1
APPENDIX B. CONVERSION FACTORS B-1
APPENDIX C. MARKED-UP 1988 AP-42 SECTION 1.1 C-1
VI
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LIST OF TABLES
Table Page
2-1 U.S. Coal Consumption by Sector, 1990 2-30
2-2 Boiler Usage by Sector 2-31
2-3 Total 1985 U.S. Emissions from Coal Combustion by Use Sector 2-32
2-4 NSPS Summary for Fossil Fuel-fired Boilers 2-33
2-5 Commercially Available NOX Control Techniques for
Pulverized Coal-fired Boilers 2-34
2-6 Commercially Available NOX Control Techniques for
Stoker Coal-fired Boilers 2-36
2-7 Post Combustion S02 Controls for Combustion Sources 2-37
3-1 Speciated VOC Literature Search Results 3-14
3-2 Literature Search Checklist 3-15
3-3 Evaluation of Air Toxics References 3-16
3-4 N20 Literature Search Checklist 3-17
4-1 Background Document Check 4-29
4-2 New S02 Baseline Data For Bituminous Coal 4-30
4-3 New NOX Baseline Data For Bituminous Coal 4-32
4-4 New CO Baseline Data 4-35
4-5 New PM Baseline Data For Bituminous Coal 4-38
4-6 New CH4 Baseline Data For Bituminous Coal 4-39
4-7 Controlled Particulate Emissions 4-40
4-8 Controlled SOX Emissions 4-42
4-9 Controlled NOX Emissions 4-43
4-10 Metal Enrichment Behaviors 4-45
4-11 Enrichment Ratios for Classes of Elements 4-45
4-12 Enrichment Ratios for Boilers and ESP 4-46
4-13 HAP Emission Factors (English Units) for Uncontrolled
Bituminous Coal-fired Boilers 4-47
4-14 HAP Emission Factors (Metric Units) for Uncontrolled
Bituminous Coal-fired Boilers 4-48
4-15 HAP Emission Factors (English Units) for Controlled
Bituminous Coal-fired Boilers 4-49
4-16 HAP Emission Factors (Metric Units) for Controlled
Bituminous Coal-fired Boilers 4-50
4-17 Average Trace Element Removal Efficiency For Control Devices 4-51
4-18 N20 Emissions Data 4-52
4-19 Summary of N20 Emission Factors for Bituminous and
Subbituminous Coal Combustion 4-54
4-20 Particulate Sizing Data for 1986 AP-42 Database: Number
of A& B Ranked Data Sets 4-55
4-21 Comparison of Organic and Inorganic CPM Emissions From a
Coal-fired Boiler 4-55
4-22 Filterable Particulate for a Front Wall Fired Boiler Fueled on a
Low Sulfur Western Bituminous Coal 4-56
4-23 Filterable Particulate for Subbituminous Coal Fired Fluidized
VII
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Bed Combustors with Multiclone Controls 4-56
VIM
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LIST OF FIGURES
2-1 Single-retort horizontal-feed underfeed stoker.
2-2 Multiple-retort gravity-feed underfeed stoker....
2-3 Overfeed chain-grate stoker
2-4 Spreader stoker
2-5 Bubbling FBC schematic
2-6 Circulating FBC schematic
2-7 Two-pass HRT boiler
2-8 Firetube boiler
2-9 D-type packaged boiler and watertubes
2-10 Four-pass Scotch boiler
2-11 Exposed-tube vertical boiler
2-12 Submerged-tube vertical boiler
4-1 FBC S02 emissions vs. calcium to sulfur ratio..
IX
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1. INTRODUCTION
The document, "Compilation of Air Pollutant Emission Factors" (AP-42), has
been published by the U.S. Environmental Protection Agency (EPA) since 1972.
Supplements to AP-42 have been routinely published to add new emissions source
categories and to update existing emission factors. An emission factor is an average
value which relates the quantity (weight) of a pollutant emitted to a unit of activity of
the source. In some cases, emission factors are presented in terms of an empirical
formula to account for source variables. Emission factors are developed from source
test data, material balance calculations, and engineering estimates. The uses for the
emission factors reported in AP-42 include:
• Estimates of area-wide emissions;
• Emission estimates for a specific facility; and
• Evaluation of emissions relative to ambient air quality.
The EPA routinely updates AP-42 in order to respond to new emission factor
needs of State and local air pollution control programs, industry, as well as the Agency
itself. Section 1.1 in AP-42, the subject of this Emission Factor Documentation (EFD)
report, pertains to bituminous and subbituminous coal combustion in stationary,
external equipment.
The purpose of this EFD is to provide background information and to document
the procedures used for the revision, update, and addition of emission factors for
bituminous and subbituminous coal combustion. The scope of the present AP-42
Section 1.1 update is as follows:
• Update baseline, criteria emission factors with data identified since the
prior updates;
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* Modify equipment classifications to give separate treatment of
tangentially-fired boilers and fluid bed combustors (FBCs);
• Extend emission factors to non-criteria species where data are available
for volatile organic compounds (VOC) speciation, trace metals and other
air toxics, and greenhouse gases [nitrous oxide (e.g., N2O), carbon
dioxide (CO2)]; and
* Extend documentation and emission factor development for controlled
operation to reflect advances in control development and the increased
importance of emission controls for combustion sources.
Data from approximately 20 test reports were used to revise and update emission
factors for existing source categories; determine new emission factors for additional
non-criteria pollutants; and add FBC units as a new source category.
The update of Section 1.1 of AP-42 began with a review of the existing version
of Section 1.1. Spot checks were made on the quality of existing emission factors by
recalculating emission factors from selected primary data references contained in the
background files. These recalculated emission factors were then compared against
those in the existing version of AP-42.
An extensive literature review was undertaken to improve technology
descriptions, update usage trends, and collect new test reports for criteria and non-
criteria emissions. The new test reports were subjected to data quality review as
outlined in the draft EPA document, Technical Procedures For Developing AP-42
Emission Factors And Preparing AP-42 Sections" (March 6, 1992). Test reports
containing sufficiently tiigh quality data ratings were combined with existing data to
revise emission factors or to produce new emission factors, as appropriate. When
sufficient new data were obtained that were of higher quality than existing data, old
lower-quality data were removed from the existing emission factor averages. In some
cases, data sources and test reports were identified during the literature review but
were not received in sufficient time to incorporate into emission factor development
This information has been placed in the background files for use in future updates.
Several new emission factors for non-criteria pollutants have been added.
These new emission factors pertain to total organic compounds (TOC), speciated
volatile organic compounds (speciated VOC), air toxics, N2O, CO2, and fugitive
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emissions. Additionally, in this revision, the information on control technologies for
paniculate matter (PM), PM less than 10 microns (PM-10), sulfur oxide (SQX), and
nitrogen oxides (NOx) emissions has been revised and updated. Add-on controls for
non-criteria pollutants are not covered here because these controls have not been
demonstrated on commercial scale combustors for this source category. Finally,
because fluidized bed combustion of coal is finding increased commercial application
in industrial and utility systems, a new source category for this combustion
configuration has been added.
Including the introduction (Chapter 1), this EFD contains five chapters. Chapter
2 provides an overall characterization of bituminous and subbituminous coal
combustion usage. This includes a breakdown of coal application by industry, an
overview of the different source categories, a description of emissions, and a
description of the technology used to control emissions resulting from coal
combustion. Chapter 3 is a review of emissions date collection and analysis
procedures. It describes the literature search, the screening of emissions data
reports, and the quality rating system for both emission data and emission factors.
Chapter 4 details pollutant emission factor development. It includes the review of
specific data sets and details of emission factor compilations. Chapter 5 presents the
revised AP-42 Section 1.1. Appendix A provides conversion factors and example
calculations for emission factor development from test data. Appendix B contains an
example of spot checking data from the fourth edition AP-42 primary references.
Appendix C contains a marked-up copy of the 1988 AP-42 Section 1.1 indicating
where changes have been made as a result of this update.
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2. SOURCE DESCRIPTION
The amount and type of coal consumed, design of combustion equipment, and
application of emission control technology have a direct bearing on emissions from
coal-fired combustion equipment. This chapter characterizes bituminous and
subbituminous coal combustion processes, and emission control technologies which
are commercially available in the United States.
2.1 CHARACTERIZATION OF BITUMINOUS AND SUBBITUMINOUS COALS
APPLICATIONS
Coal is a complex combination of organic matter and inorganic mineral matter
formed over eons from successive layers of fallen vegetation. Coal types are broadly
classified as anthracite, bituminous, subbituminous, and lignite. These classifications
are made according to heating value as well as relative amounts of fixed carbon,
volatile matter, ash, sulfur, and moisture. Formulas and tables for classifying coals
based on these properties are given in Reference 1.
In general, bituminous coals have heating values of 5,800 to 7,800 kcal/kg
(10,500 to 14,000 Btu/lb) while the heating values of subbituminous coals are lower at
4,600 to 6,400 kcal/kg (8,300 to 11,500 Btu/lb).1 Subbituminous coals are typically
higher in volatile matter, moisture, and oxygen contents than bituminous coals and, as
a result, are lower in fixed carbon content. Because of their high heating values and
high volatile contents, both bituminous and subbituminous coals burn easily when
pulverized to fine powder. Because of its characteristically lower sulfur content and
higher moisture content, SO2 and NOx emissions are generally lower for combustion of
subbituminous coals relative to bituminous coals.
In 1990, a total of almost 860 million short tons of coal were consumed by the
utility, industrial, commercial/institutional, and residential sectors. These four sectors
can be described as follows: (1) utility boilers producing steam for generation of
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electricity; (2) industrial boilers generating steam or hot water for process heat,
generation of electricity, or space heat; (3) boilers for space-heating of commercial
and institutional facilities; and (4) residential furnaces for space- heating purposes. As
shown in Table 2-1, the utility sector consumed the most fuel [over 700 million metric
tons (770 million short tons)]. The residential usage of coal for space heating has
generally declined since 1973 as stoker- and hand-fired furnaces and boilers have
been replaced by oil, gas, and electric heating systems. Of the total coal produced in
1939, approximately 67 percent was bituminous, 24 percent subbituminous, 9 percent
lignite, and less than 1 percent anthracite.
2.2 PROCESS DESCRIPTIONS
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). Table 2-
2 summarizes boiler type usage by sector. Most of the installed capacity of firetube
and cast iron units is oil- and gas-fired ; however, a description of these designs for
coal is included here for completeness.
A watertube boiler is one 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 consist of pulverized coal, cyclone,
stoker, fluidized bed, and handfeed units. Pulverized coal and cyclone boilers are
types of suspension systems because some or all of the combustion takes place while
the fuel is suspended in the furnace volume. In stoker-fired systems and most
handfeed units, the fuel is primarily burned on the bottom of the furnace or on a grate.
Some fine particles are entrained in upwardly flowing air, however, and are burned in
suspension in the upper furnace volume. In a fluidized bed combustor, the coal is
introduced to a bed of either sorbent or inert material (usually sand) which is fluidized
by an upward flow of air. Most of the combustion occurs within the bed, but some
smaller particles burn above the bed in the "freeboard" space.
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2.2.1 Suspension Firing
In pulverized coal-fired (PC-fired) boilers the fuel is pulverized to the consistency
of light powder 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,
depending on whether the ash is removed in 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. Wet bottom furnaces are also referred to as slag tap furnaces.
Depending upon the location of the burners and the direction of coal injection
into the furnace, PC-fired boilers can also be classified into three different firing types.
These are:
• Single and opposed wall, also known as face firing;
• Tangential, also known as corner firing; and
• Cyclone.
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. PC-fired suspension boilers usually are characterized by very high
combustion efficiencies, and are generally receptive to low-NO burners and other
combustion modification techniques. Tangential or corner-fired boilers have burners
mounted in the corners of the furnace. The fuel and air are injected toward the center
of the furnace to create a vortex that is essentially the burner. Because of the large
flame volumes and relatively slow mixing, tangential boilers tend to be lower NOx
emitters for baseline uncontrolled operation. Cyclone furnaces are often categorized
as a PC-fired system even though the coal burned in a cyclone is crushed to a
maximum size of about 4.75 mm (4 mesh). The coal is fed tangentially, with primary
air, into a horizontal 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.
Because of their high furnace heat release rate, cyclones are high NOx emitters and
are generally more difficult to control with combustion modifications.
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2.2.2 Stoker Firing
Stoker firing 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 less than 29 MW (100 million Btu/hr) heat
input. Field erected units with capacities in excess of 116 MW (400 million Btu/hr)
are common. Stoker systems can be divided into three groups: underfeed stokers,
overfeed stokers, and spreader stokers. These systems differ in how fuel is supplied
to either a moving or stationary grate for burning. One important similarity among all
stokers is that all design types use underfeed air to combust the coal char on the
grate, combined with one or more levels of overfire air introduced above the grate.
This helps ensure complete combustion of volatiles and low combustion emissions.
Underfeed stokers are generally of two types; the horizontal-feed, side-ash-
discharge type shown in Figure 2-1; and the gravity-feed, rear-ash-discharge type
shown in Figure 2-2. The horizontal-feed, side-ash-discharge type of stoker is used
primarily in small boilers supplying relatively constant steam loads of less than about
14,000 kg/hr (30,000 Ib/hr).1 The gravity-feed, rear-ash-discharge underfeed stoker
can be as large as 150 MW (500 million Btu/hr) heat input capacity , although there
are a few underfeed coal stokers of up to 440 MW (1500 million Btu/hr) .
An overfeed stoker, shown in Figure 2-3, uses a moving grate assembly. Coal
is fed from a hopper onto a continuous grate which conveys the fuel into the furnace.
Caking bituminous coals can cause agglomeration and matting which can restrict the
airflow through the grate causing further combustion problems.5 The three types of
grates used with overfeed coal stokers are the chain, travelling, and water-cooled
vibrating grates. These overfeed stoker systems are often referred to by the type of
grate employed. Overfeed coal-fired systems typically range up to 100 MW (350
million Btu/hr) heat input.
In a spreader stoker, shown in Figure 2-4, 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
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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.6 Heat input capacities of spreader stokers typically range from 1 to
13C MW (5 to 450 million Btu/hr).3 Unlike overfeed stokers, fuels with the potential to
cake have little negative effect on spreader stokers and can be generally fired with
success in these units.5
2.2,3 Fluidized Bed Combustion
Fluidized bed combustion boilers, 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. Fluidized bed combustion is a boiler design which can lower sulfur
dioxide (SO2) and NOx emissions without the use of post-combustion or add-on
controls. A calcium-based limestone or dolomitic sorbent is often used for the bed
material to capture S02 evolved during combustion. The sulfur is retained as a solid
sulfate and is removed from the flue gas stream by the particulate control device.
Emissions of thermal NOX are reduced because FBCs are able to operate at lower
combustion temperatures compared to the more conventional designs, thus reducing
the fixation of atmospheric nitrogen. Typical maximum firing temperatures for FBCs
are 930°C (170Q°F) compared with typical furnace-exit-gas-temperatures of 1430°C
(2600°F) for dry bottom boilers and up to 1760°C (3200°F) for wet bottom boilers.1
Conversion of fuel nitrogen to NOX is also suppressed with FBC compared to
suspension firing.
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
(iO to 450 psig). Pressurized FBC systems are being demonstrated at two utility sites
in the U.S.; however, they are not yet considered fully commercialized. The remainder
of this section will therefore describe only atmospheric FBCs.
Figures 2-5 and 2-6 show the two principal types of atmospheric FBC boilers,
bubbling bed and circulating bed. The fundamental distinguishing feature between
these types is the fluidization velocity. In the bubbling bed design, the fluidization
velocity is relatively low, ranging between 1.5 and 3.6 m/s (5 and 12 ft/s), in order to
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minimize solids carryover or elutriation from the combustor. Circulating FBCs,
however, employ fluidization velocities as high as 9 m/s (30 ft/s) 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.
2.2.4 Handfeed Unite
Small, coal-fired boilers and furnaces are sometimes found in small industrial,
commercial, institutional, or residential applications. Small firetube boilers in these
installations are sometimes capable of being hand-fired. From an emissions
standpoint, handfeed units can have high carbon monoxide (CO) and VOC emissions
because of generally low combustion efficiencies due, in part, to the presence of
quench surfaces. Most small units may not have particulate controls while some are
only equipped with simple cyclone or multiclone collectors. Small boilers and furnaces
without particulate controls do not generally have emission factors as high'as large
uncontrolled industrial boilers because typical combustion intensities and firebox
velocities are lower in the smallest units. Lower firebox velocities mean that smaller
quantities of particulate matter are entrained in the combustion gases.
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 handfeed configuration. The HRT boilers
are generally fired with gas or oil instead of coal. A two-pass HRT boiler is shown in
Figure 2-7. A Scotch or shell boiler differs from the HRT boiler in that the boiler and
furnace are contained in the same shell. In a two-pass unit, combustion occurs in the
lower half of the unit, with the flue gases passing beneath the bottom of the water
basin occupying the upper half. Like HRT boilers, coal is not as commonly used in
Scotch boilers due to slagging and scaling. More common gas- and oil-fired Scotch
units are shown in Figures 2-8 and 2-9.
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A vertical firetube boiler is a single-pass unit in which the firetubes come straight
up from the water-cooled combustion chamber located at the bottom of the unit.
Figures 2-10 and 2-11 show two types of vertical firetube boilers. Vertical boilers are
small, with input capacities under 0.7 MW (2.5 million Btu/hr). 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.
Currently available coal-fired firebox units employ mechanical stokers or are capable of
being hand-fired. They are generally limited in size to below 7.3 MW (25 million
Btu/hr) input capacity. Cast iron boilers consist of several vertical sections of heat
exchange tubes mounted above a firebox. Water enters each section at the bottom
and is heated or converted to steam as it passes upward through the heat exchange
tubes. Figure 2-12 shows a typical cast iron boiler.
2.3 EMISSIONS
Emissions from coal combustion depend on coal rank and composition, the
design type and capacity of the boiler, the firing conditions, load, the type of control
technologies, and the level of equipment maintenance. Baseline, uncontrolled sources
are those without add-on air pollution control (APC) equipment, low-NOx burners, or
other modification for emission control. Baseline emission for SO2 and participate
matter (PM) can also be obtained from measurements taken upstream of APC
equipment.
Because of the inherent low N0x emission characteristics of FBCs and the
potential for in-situ SO2 capture with calcium-based bed materials, uncontrolled
emission factors for this source category were not developed in the same sense as
with the other source categories. For NOx emissions, the data collected from test
reports were considered to be baseline if no additional add-on NOx control (such as
ammonia injection) was in place. For SO2 emissions, a correlation was developed
from reported data on FBCs to relate SO2 emissions with the coal sulfur content and
the calcium to sulfur ratio in the bed.
For this update of AP-42, point source emissions of NOX, S02, PM, PM-10, and
CO are evaluated as criteria pollutants (those emissions which have established
National Primary and Secondary Ambient Air Quality Standards8). This update
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includes point source emissions of some non-criteria pollutants (e.g., N2O, VOCs, and
air toxics) as well as data on particle size distribution to support PM-10 emission
inventory efforts. Emissions of CO2 are also being considered because of its possible
participation in global climatic change and the corresponding interest in including this
gas in emission inventories. Most of the carbon in fossil fuels is emitted as CO2 during
combustion. Minor amounts of carbon are emitted as CO or as carbon retained in the
fly ash. Finally, fugitive emissions associated with the use of coal at the combustion
source are being included In this update of AP-42.
The total 1985 emissions of PM, SO2, and NOX emissions resulting from
bituminous coal combustion in the major use sectors are summarized in Table 2-3
shown below. Table 2-4 summarizes the federal New Source Performance Standards
9-12
(NSPS) applicable to PM, SO2, and NOK emissions from fossil fuel-fired boilers.
A general discussion of emissions of criteria and non-criteria pollutants from
coal combustion is given in the following paragraphs.
2.3.1 Particulate Matter Emissions
Uncontrolled PM emission from coal-fired boilers include the ash in the fuel as
well as unburned carbon resulting from incomplete combustion. Emission factors for
PM have generally been expressed as a function of fuel ash content. Coal ash may
either settle out in the boiler (bottom ash) or be carried out with the flue gas (fly ash).
The distribution of ash between the bottom and fly ash fractions directly affects the PM
emissions rate and is a function of the following:
» Boiler firing method - The type of firing is perhaps the most important
factor in determining ash distribution. For example, stoker-fired units
emit less fly ash than dry bottom, PC boilers; and
» Wet or dry bottom furnace - Wet bottom cyclone furnaces remove
approximately 70 percent of ash as slag or bottom ash; with dry bottom
units, the inverse is roughly the case, where 70 percent of ash exits the
boiler with the combustion gases to be treated by paniculate collectors.
Boiler load also affects PM emissions from coal-fired boilers. In general,
decreasing load tends to reduce PM emissions; however, the magnitude of the
reduction varies considerably depending on boiler type, fuel, and boiler operation.
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Soot blowing is a source of intermittent PM emissions in coal-fired boilers.
Steam soot blowing is used periodically to dislodge ash from heat transfer surfaces in
the furnace, convective section, and economizer/preheater. On small boilers with
single soot blowers, soot blowing may only take place for a few seconds once a shift.
Large boilers may have numerous soot blowers installed and operated in a cycle
which may approach "continuous" soot blowing.
2-3.2 Sulfur Oxide Emissions
Sulfur oxide emissions are generated during coal combustion from the oxidation
of sulfur contained in the fuel. The emissions of SOx from conventional combustion
systems are predominantly in the form of S0r On average, more than 95 percent of
the fuel sulfur is converted to SO2, about 1 to 5 percent is further oxidized to sulfur
trioxide (SO3), and about 1 to 3 percent is converted to sulfate paniculate. Sulfur
trioxide readily reacts with water vapor (both in air and in flue gases) to form sulfuric
acid mist.
Uncontrolled SOX emissions are almost entirely dependent on the sulfur content
of the fuel and, with the exception of fluidized bed combustors, are not affected by
boiler type, size, or burner design . There is some potential that stoker boilers firing
high ash coal with a significant alkaline content could result in SO2 emissions which
are lower than a PC-fired boiler firing the same fuel due to sulfur retention as an alkali
sulfate in the ash bed on the grate. In some cases, combustion of highly alkaline,
Western subbituminous coals can result in 20 percent of the sulfur in the coal being
retained in the bottom ash or fly ash.16 However, the data reviewed did not justify the
presentation of separate emission factors for stoker-fired systems. Therefore, as in
the earlier versions of AP-42, a consistent SO2 emission factor, based only on fuel
sulfur content (within a coal rank), was retained for all combustion configurations, with
the single exception of FBC units.
2-3.3 Nitrogen Oxide Emissions
Oxides of nitrogen formed in combustion processes are due either to thermal
fixation of atmospheric nitrogen in the combustion air ("thermal NOX") or to the
conversion of chemically bound nitrogen in the fuel ("fuel NOX"). The term NOX
customarily refers to the composite of nitric oxide (NO), and nitrogen dioxide (NO2).
2-9
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Nitrous oxide is excluded, but is an oxide of definite interest. Test data have shown
that for most stationary combustion systems, over 95 percent of the emitted NOX is in
the form of NO.15
The qualitative global kinotics of thermal NOx formation have shown that NOX
formation rates are exponentially dependent on temperature, and proportional to N2
concentration in the flame, the square root of the oxygen (O2) concentration in the
flame, and the residence time,17 Thus, the formation of thermal NOx is affected by four
factors; (1) peak temperature, (2) nitrogen concentration, (3) oxygen concentration or
flame stoiehiometry, and (4) time of exposure at peak temperature. The emission
trends resulting from changes in these factors are fairly consistent for all types of
boilers - an increase in flame temperature, oxygen availability, and/or residence time
at high temperatures leads to an increase in thermal NOx production regardless of the
boiler type.
Fuel nitrogen conversion is the more important NOX forming mechanism in coal-
fired combustion systems because of the high nitrogen content in the fuel. Fuel NOX
can account for 80 percent of the total NOX emissions in coal firing. The percent
conversion of fuel nitrogen to NOx can vary greatly. Anywhere from 5 to 60 percent of
nitrogen in the coal can be converted to NOx.17 Furthermore, test data indicate that
the percent of fuel nitrogen conversion decreases as the fuel nitrogen content
increases,19
A number of variables influence how much NOX is formed by these two
mechanisms. One important variable is firing configuration. The NO emissions from
tangentially (corner) fired boilers are, on the average, less than those of horizontally
opposed units. Also important are the firing practices employed during boiler
operation. Low excess air (LEA) firing, flue gas recirculation (FGR), staged
combustion (SC), or some combination thereof may result in NOx reductions of 5 to 60
percent. (See Section 2.4,1 for a discussion of these techniques). Load reduction
can likewise decrease NOx production. The NOX emissions may be reduced from 0.5
to 1 percent for each percentage reduction in load from full load operation. Levels of
NOx emissions do not decrease significantly in response to load reductions in some
boilers and have, in some cases, been observed to increase (due to the higher excess
2-10
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air levels sometimes required to maintain stable combustion). It should be noted that
the discussion of these variables, with the exception of excess air, applies to the NOx
emissions only of large coal-fired boilers. Low excess air firing is possible in many
small boilers, but the resulting NOX reductions are not nearly so significant
Test data on pulverized coal combustion utility boilers indicate that N2O
9H
emissions were always less than 10 ppm and often less than 1 ppm in the units
tested.21 Generally, N2O emissions from FBC boilers can be higher, but are generally
less than 100 ppm with U.S. coals.22 Some of the higher N2O emissions that have
23
been reported are from European FBC installations and pilot plant studies. Some
pilot plant configurations have been suspected of producing spuriously high N2O
emissions data which are not representative.
At the third N2O workshop held in France in June 1988,24 data were presented
suggesting the presence of an N2O sampling artifact in sampling containers awaiting
analysis. Recent N20 emissions data indicate that direct N20 emissions from coal
combustion units are considerably below the measurements made prior to 1988. The
emission ranges quoted above are based on tests employing methods to minimize or
eliminate the sampling artifact. Nevertheless, the N2O formation and reaction
mechanisms are still not well understood or well characterized. Additional sampling
and research is needed to fully characterize N2O emissions and to understand the N2O
mechanism. Emissions can vary widely from unit to unit, or even at the same unit at
different operating conditions. It has been shown in some cases that N2O increases
with decreasing boiler temperature.22 For this AP-42 update, an average emission
factor based on reported test data was developed for conventional coal combustion
systems, and a separate emission factor was developed for fluidized bed combustors.
2.3.4 Carbon Monoxide Emissions
The rate of CO emissions from combustion sources depends on the oxidation
efficiency of the fuel. By controlling the combustion process carefully, CO emissions
can be minimized. Thus, if a unit is operated improperly or not maintained, the
resulting concentrations of CO (as well as organic compounds) may increase by
several orders of magnitude. Smaller boilers, heaters, and furnaces tend to emit more
of these pollutants than larger combustors. This is because smaller units usually have
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less high-temperature residence time and, therefore, less time to achieve complete
combustion than larger combustors.
The presence of CO In the exhaust gases of combustion systems results
principally from incomplete fuel combustion. Several conditions can lead to
incomplete combustion. These include:
• Insufficient oxygen availability;
» Extremely high levels of excess air leading to quenching (more common
with industrial boilers);
• Poor fuel/air mixing;
* Cold wall flame quenching;
• Reduced combustion temperature;
* Decreased combustion gas residence time; and
• Load reduction (reduced combustion intensity).
Since various combustion modifications for NO reduction can produce one or more of
the above conditions, the possibility of increased CO emissions is a concern for
environmental, energy efficiency, and operational reasons.
2.3.5 Organic Compound Emissions
Total organic compounds include VOCs which remain in a gaseous state in
ambient air, semi-volatile organic compounds and condensible organic compounds.
According to the Federal Register, VOC has been defined as any organic compound
excluding CO, CO2, carbonic acid, metallic carbides or carbonates, and ammonium
carbonate which participates in atmospheric photochemical reactions. The following
additional compounds have been deemed to be of "negligible photochemical reactivity"
and so are exempt from the definition of VOC: methane, ethane, methyl chloroform,
methylene chloride, and most chlorinated-fluorinated compounds (commonly referred
to as CFCs). Although these compounds are considered "exempt" from most ozone
control programs due to their low photochemical reactivity rates, they are of concern
when developing complete emission inventories which are necessary for the design of
effective ozone control strategies. The term TOC will be considered to include all
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organic compounds, i.e. VOCs plus the "exempt" compounds including methane and
ethane, toxic compounds, aldehydes, perchloroethylene, semi-volatiles, and
condensibles (as measured by EPA Reference Methods).25
Emissions of VOCs are primarily characterized by the criteria pollutant class of
unburned vapor phase hydrocarbons. Unburned hydrocarbon emissions can include
essentially all vapor phase organic compounds emitted from a combustion source.
These are primarily emissions of aliphatic, oxygenated, and low molecular weight
aromatic compounds which exist in the vapor phase at flue gas temperatures. These
emissions include all alkanes, alkenes, aldehydes, carboxylic acids, and substituted
SN§ S'T
benzenes (e.g., benzene, toluene, xylene, ethyl benzene, etc.). '
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). There
are also PAH-nitrogen analogs. Information available in the literature on POM
compounds generally pertains to these PAH groups. Because of the dominance of
PAH information (as opposed to other POM categories) in the literature, many
reference sources have inaccurately used the terms POM and PAH interchangeably.
Polycyclic organic matter can be especially prevalent in the emissions from coal
burning, because a large fraction of the volatile matter in coal exits as POM. A few
comments are in order concerning an extremely toxic subclass of PNA - the
polychlorinated and polybrominated biphenyls (PCBs and PBBs). A theoretical
assessment of PCB formation in combustion sources28 concluded that, although PCB
formation is thermodynamically possible for combustion of fuels containing some
chlorine (e.g., some coals and residual oil), it is unlikely due to short reaction
residence times at conditions favoring PCBs and to low chlorine concentrations. Also
with efficient mixing, oxygen availability, and adequate residence time at temperatures
in the 800-1000 °C (1470-1830 °F) range, PCBs [together with polychlorinated dibenzo-
p-dioxins (PCDD) and polychlorinated dibenzofurans (PCDF)] may be efficiently
-------
formed via catalyzed reactions on fly ash particles at low temperatures in equipment
downstream of the combustion device.
Formaldehyde is formed and emitted during the combustion of hydrocarbon-
based fuels including coal and oil. Formaldehyde is present in the vapor phase of the
flue gas. Since formaldehyde is subject to oxidation and decomposition at the high
temperatures encountered during combustion, large units with efficient combustion
resulting from closely regulated air-fuel ratios, uniformly high combustion chamber
temperatures, and relatively long retention times should have lower formaldehyde
emission rates than do small, less efficient combustion units. '
2.3.6 Trace Element Emissions
Trace elements are also emitted from the combustion of coal. For this update
of AP-42, trace metals included in the list of 189 hazardous air pollutants under Title III
go
of the 1990 Clean Air Act Amendments (GAAA-90) are considered. The quantity of
trace metals emitted depends on combustion temperature, fuel feed mechanism and
the composition of the fuel. The temperature determines the degree of volatilization of
specific compounds contained in the fuel. The fuel feed mechanism affects the
partitioning of emissions into bottom ash and fly ash.
The quantity of any given metal emitted, in general, depends on:
» Its concentration in the fuel;
• The combustion conditions;
» The type of particulate control device used, and its collection efficiency
as a function of particle size; and
« The physical and chemical properties of the element itseff.
It has become widely recognized that some trace metals concentrate in certain
waste particle streams from a combustor (bottom ash, collector ash, flue gas
particulate), while others do not. Various classification schemes to describe this
*sc
partitioning have been developed. The classification scheme used by Baig et al.
is as follows:
• Class 1 : Elements which are approximately equally distributed between
fly ash and bottom ash, or show little or no small particle enrichment;
2-14
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» Class 2: Elements which are enriched in fly ash relative to bottom ash,
or show increasing enrichment with decreasing particle size;
• Class 3; Elements which are intermediate between Class 1 and 2;
» Class 4: Volatile elements which are emitted in the gas phase.
By understanding trace metal partitioning and concentration in fine particulate, it
is possible to postulate the effects of combustion controls on incremental trace metal
emissions.4 For example, several NOx controls for boilers reduce peak flame
temperatures [e.g., staged combustion, flue gas recirculation (FGR), reduced air
preheat, and load reduction]. If combustion temperatures are reduced, fewer Class 2
metals will initially volatilize, and fewer will be available for subsequent condensation
and enrichment on fine particulate matter. Therefore, for combustors with particulate
controls, lowered volatile metal emissions should result due to improved particulate
removal. Flue gas emissions of Class 1 metals (the non-segregating trace metals)
should remain relatively unchanged.
Lowered local O2 concentrations are also expected to affect segregating metal
emissions from boilers with particle controls. Lowered O2 availability decreases the
possibility of volatile metal oxidation to less volatile oxides. Under these conditions,
Class 2 metals should remain in the vapor phase into the cooler sections of the boiler.
More redistribution to small particles should occur and emissions should increase.
Again, Class 1 metals should not be significantly affected.
Other combustion NOx controls which decrease local O2 concentrations (staged
combustion and low NOx burners) may also reduce peak flame temperatures. Under
these conditions, the effect of reduced combustion temperature is expected to be
stronger than that of lowered O2 concentrations.
2.3.7 Fugitive Emissions
Fugitive emissions are pollutants which escape from an industrial process due
to leakage, materials handling, inadequate operational control, transfer or storage.
Depending on how the fugitive emissions are measured, under what conditions, and
for what specific type of operation used, emission factors tend to vary widely in
validity, absolute value, and methodology of calculation.
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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 transfer operations from silos to trucks or rail cars.
2.4 CONTROL TECHNOLOGIES
Only controls for criteria pollutants are discussed here because controls
specifically for non-criteria emissions have not been demonstrated or commercialized
for coal combustion sources.
Control techniques may be classified into three broad categories; fuel
treatment/substitution, combustion modification, and post-combustion control. Fuel
treatment includes coal cleaning using physical, chemical, or biological processes.
Combustion modification and post-combustion control are both applicable and widely
commercialized for coal combustion sources. Combustion modification is applied
primarily for NOx control purposes, although for small units, some reduction in PM
emissions may be available through improved combustion practice. Post combustion
control is applied to emissions of PM, SO2, and, to some extent, NOX for coal
combustion.
Particulate emissions may be categorized as either filterable or condensible.
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. Particles less than 0.3 microns and vapors pass through the filter. Condensible
particulate matter (CPM) is material that is emitted in the vapor state which later
condenses to form homogeneous and/or heterogeneous aerosol particles. The
condensible particulate emitted from boilers fueled on coal or oil is primarily inorganic
in nature.
2.4.1 Fuel Treatment/Substitution
Fuel treatment (or benefication) and fuel substitution are pre-combustion
techniques for reducing NOX, SO2, and PM emissions from combustion sources. Fuel
substitution involves the use of naturally occurring clean fuels, whereas benefication
provides a physically or a chemically cleaned fuel.
2-16
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Naturally occurring low sulfur coals may allow a source to meet SO2 emission
limits or reduce emissions with no additional controls. Low sulfur coal is sometimes
defined as run-of-mine (ROM) coal which can comply with a given emission standard.
Although the terms "high" and "low" are dependent on the specifics of the fuel analysis
(and the area where the coal was mined), generally the break point between high and
low sulfur coal is considered to be around 1100 ng/J (2.5 Ibs SO2 per million Btu of
heat input).36 This is roughly equivalent to 1.5 percent sulfur for bituminous coals, and
about 1.0 percent for subbituminous coals. Nearly 85 percent of the reserve base of
low sulfur coal is located in states west of the Mississippi River. The bulk of western
coals are, however, of a lower rank than are the Eastern coals.
Low sulfur western coals can be burned in stoker-fired systems as long as
there is sufficient undergrate air to handle any caking that may occur. Also, many low
sulfur western coals have low ash fusion temperatures which may cause slagging on
the grate for some stoker designs,
Pulverized coal and FBC boilers can be designed for almost any type of coal.
However, once a design is set (especially for PC systems), substitutions are limited to
coals with compatible combustion characteristics and ash properties. Fluidized bed
boilers are generally more tolerant of alternate or "off-spec" fuels. The choice of
alternate coal will depend on the type of pulverizer at the boiler site (for PC-fired
systems), the spacing of watertubes in the steam generator and superheater sections,
37
and the materials used in the furnace wall. Also, the higher resistivity of the fly ash
from the combustion of low sulfur coal may affect the paniculate control performance
of the ESP.
Physical coal benefication consists of a series of steps including size reduction,
classification, cleaning, dewatering and drying, waste disposal, and pollution control.
Basic physical coal cleaning techniques have been commercial for at least 50 years.
Currently, more than 50 percent of domestic coal is cleaned to some level before
3fi
use. There are in excess of 500 coal cleaning plants in the U.S., most of which are
located east of the Mississippi River. Although coal cleaning was originally envisioned
as an ash reduction technology, it also accomplishes reduction in SO2 emissions. The
level of reduction is dependent on the pyritic (inorganic) sulfur content and the nature
2-17
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and extent of cleaning operations (primarily crushing) done on the feed coal. Current,
commercial physical coal cleaning plants are capable of removing 20 to 50 percent of
the pyritic sulfur.36 Assuming the high range to be achievable, and using published
levels of pyritic and toted sulfur for Individual coals,30 the total possible reduction in SO2
emissions for common bituminous coals are:
* Illinois No. 6: 27%
» Upper Freeport: 47%
» Upper Kittanning: 11%
These reduction values are shown for illustration purposes only since the ratio
of pyritic to organic sulfur can vary substantially alon ghe length of a seam (e.g.,
reductions could bary between 20 and 40 percent for Illinois No. 6 coal). It is evident
that the degree of SO2 removal available with physical coal benefication depends on
the cleaning process as well as the coal type and pyrrtic/organic sulfur ratio. It is also
clear that the removal of SO2 is well below the 90 percent level usually required under
the New Source Performance Standards (NSPS).10"12
Several chemical and biological benefication processes are under development,
but are not yet commercialized for full-scale coal combustion applications. These
advanced cleaning processes are being designed to work on the organically bound
sulfur as opposed to most of the physical processes which are aimed at the pyritic
sulfur. The goals of the research and development efforts which have been funded by
the U.S. Department of Energy, the Electric Power Research Institute, and private
industry is to produce a coal that can meet the NSPS and Clean Air Act Amendments
of 1990 SO2 emission limits without additional controls.
2.4.2 Combustion Modification
Combustion modification includes any physical or operational change In the
4 39-44
furnace or boiler apparatus itself. ' Maintenance of the burner system, for
example, is important to assure proper mixing and subsequent minimization of any
unburned combustibles. Periodic tuning is important in small units for maximum
operating efficiency and emission control, particularly of smoke and CO.
2.4.2.1 Particulate Matter Control. Uncontrolled PM emissions from small
stoker-fired and handfeed coal combustion sources can be minimized by employing
2-18
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good combustion practice. This involves operation of the combustion source within
recommended load ranges, controlling the rate of load changes, and ensuring steady
and uniform fuel introduction. Proper design of combustion air delivery systems can
also minimize uncontrolled PM emissions. Insufficient combustion air will generate
soot and condensible organic compound emissions. Conversely, the use of excessive
air flow under the grate, beyond that necessary to complete char burnout and to cool
the grate can give high PM emissions. Also, localized areas of high velocities near the
fuel bed can entrain ash into the flue gases leaving the combustor. Excess air in
these types of units should be introduced through overfire air ports where possible for
volatile burnout and upper furnace temperature control.
Large industrial and utility boilers are generally well designed and maintained so
that soot and condensible organic compound emissions are minimized. Particulate
matter emissions are more a result of entrained fly ash in suspension-fired and FBC
systems. Therefore, post combustion controls are necessary to reduce PM emissions
from these sources.
2.4.2.2 Nitrogen Oxide Control. Combustion modifications, such as limited
excess air firing, flue gas recirculation, staged combustion and reduced load
operation, are primarily used to control NOx emissions in large coal-fired facilities.
The formation of thermal NOx occurs in part through the Zeldovich mechanism:
(2-1) N2 -i- O~ NO + N
(2-2) N + O2~ NO + O
(2-3) N + OH <-» NO + H
Reaction (2-1) is generally the rate determining step due to its large activation energy.4
On an overall, idealized, global basis, the thermal NOx formation rate is related to N2
concentration, combustion temperature, and O2 concentration by the following
equation:
(2-4) [NO] = k, exp(-k2/T) [NJ [02]V2t
where:
[ ] - mole fraction
T = temperature (°K)
t = residence time
2-19
-------
kv k2 = reaction rate coefficient constants
This idealized relationship suggests thermal NOX formation can be controlled by four
approaches: (1) reduction of peak temperature of reaction, (2) reduction of N2
concentration, (3) reduction of oxygen level or stoichiometric ratio, and (4) reduction of
the residence time of exposure at peak temperature. Typically, the N2 mole fraction in
hydrocarbon-air flames is on the order of 0,7 and is difficult to modify.4 Therefore,
combustion modification techniques to control thermal NOX in boilers have focused on
reducing oxygen level, peak temperature, and time of exposure at peak temperature in
the primary flame zones of the furnaces. Equation 2-4 also shows that thermal NOX
formation depends exponentially on temperature, parabolically on oxygen
concentration, and linearly on residence time. Therefore initial efforts to control NOX
emissions are often focused on methods to reduce peak flame temperatures.
In boilers fired on coal, the control of fuel NOX is also very important in
achieving the desired degree of NOX reduction, since fuel NOx can account for 80
percent of the total NOx formed.18'45'46 Fuel nitrogen conversion to NOX is highly
dependent on the fuel to air ratio in the combustion zone, and in contrast to thermal
NOX formation, is relatively insensitive to small changes in combustion zone
temperature,47 In general, increased mixing of fuel and air increases nitrogen
conversion which, in turn, increases fuel NOX. Thus, to reduce fuel NOX formation, the
most common combustion modification technique is to suppress combustion air levels
below the theoretical amount required for complete combustion. The lack of oxygen
creates reducing conditions that, given sufficient time at high temperatures, cause
volatile fuel nitrogen to convert to N2 rather than NO.
In the formation of both thermal and fuel NOX, all of the above reactions and
conversions do not take place at the same time, temperature, or rate. The actual
mechanisms for NOx formation in a specific situation are dependent on the quantity of
fuel-bound nitrogen and the temperature and stoichiometry of the flame zone.
Although the NOX formation mechanisms are different, both thermal and fuel NOX are
promoted by rapid mixing of fuel and combustion air. This rate of mixing may itself
depend on fuel characteristics such as the atomization quality of liquid fuels or the
particle fineness of solid fuels.48 Additionally, thermal NO is greatly increased by
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increased residence time at high temperatures under oxidizing conditions. Thus,
primary combustion modification controls for both thermal and fuel NOX typically rely
on the following control approaches;
* Decrease residence time at high temperatures and oxidizing conditions
(for oxidizing conditions);
- Decreased adiabatic flame temperature through dilution,
- Decreased combustion intensity,
- Increased flame cooling,
- Decreased primary flame zone residence time,
» Decrease primary flame zone O2 level:
• Decreased overall O2 level,
- Controlled (delayed) mixing of fuel and air, and
- Use of fuel-rich primary flame zone.
Tables 2-5 and 2-6 summarize available NOx control techniques currently in use of
under full-scale demonstration on pulverized coal-fired boilers and stoker coal-fired
boilers, respectively.
For cyclone boilers, natural gas reburning has been investigated as a
combustion modification NOx control technique. In this process, natural gas is
injected into a furnace reburn zone downstream from the cyclone burners. The
injection of additional fuel creates a fuel-rich zone in which NOx from the cyclone
burners is converted to molecular nitrogen and water vapor. Additional air is injected
downstream of the reburn zone to complete the combustion of unburned fuel. Flue
gas recirculation may be employed to facilitate mixing of natural gas with the flue gas
and penetration of natural gas into the furnace.
Parametric tests for natural gas reburning aplied to a 108 MW electric output
(MWe) cyclone boiler using 18 percent natural gas injection and FGR showed that
emissions were reduced to approximately 300 ppm (at 3 percent O2), corresponding
|^r>
to a 58 percent reduction efficiency. However, the reburn system resulted in an
2-21
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unacceptable amount of slag build-up on the near wall of the secondary furnace. The
use of a water-cooled natural gas injection system in lieu of the FGR system eliminated
the excess slag build up but NOx reduction efficiencies dropped to 46 to 48 percent,
based on preliminary testing.
2.4.2.3 Fluidized Bed Combustion. Fluidized bed combustion is often considered a
combustion modification for SO2 control because FBC can sometimes be retrofit to
conventional combustors and boilers. Limestone or dolomite added to the bed is
calcined to lime and reacts with SO2 to form calcium sutfate. Bed materials can also
effectively capture trace metals. Bed temperatures are typically maintained between
760 and 870 °C (1400 to 1600 °F) to promote the sulfation reaction and to prevent ash
fusion. Particulate matter emitted from the boiler is generally captured in a cyclone
and recirculated or sent to disposal. Additional paniculate control equipment, such as
an ESP or baghouse, may be used after the cyclone to further reduce paniculate
emissions.
2.4.3 Post-Combustion Control
2.4.3.1 Paniculate Matter Control. The post-combustion control of PM
emissions from coal-fired combustion sources can be accomplished by using one or
more of the following paniculate control devices:
• Electrostatic preciprtator (ESP),
« Fabric filter (or baghouse),
• Wet scrubber,
» Cyclone or muliclone collector, or
* Side stream separator.
Filterable paniculate emissions can be controlled to various levels by all of these
devices. Cyclones, ESPs, and fabric filters have little effect on measured condensible
paniculate matter (CPM) because they are generally operated at temperatures above
the upper limit of the front-half of EPA Method 5 [135°C (275°F)]. Most CPM would
remain vaporized and pass through the control device. Wet scrubbers, however,
reduce the gas stream temperature so they could theoretically remove some of the
CPM.
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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. Application of an ESP 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 micron)
and coarse particles (greater than 10 microns). These data show a reduction in
collection efficiency for particle diameters between 0.1 and 10 microns.
Fabric filtration has been widely applied to coal combustion sources since the
early 1970's. A fabric filter (baghouse) consists of a number of filtering elements
(bags) along with a bag cleaning system contained in a main shell structure
incorporating dust hoppers. Bag materials, such as fiberglass, Nomex, or Teflon
are selected based on operating temperature, particle abrasiveness, and acid gas
content in the flue gases. Woven, non-woven (felted), and texturized filament fabrics
are chosen based on collection efficiency and cleanability requirements.
The particulate removal efficiency of fabric filters is 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 (A/C),
» Operating pressure loss,
* Cleaning sequence,
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* Interval between cleaning,
» Cleaning method, and
• Cleaning intensity.
In addition, fabric properties affect the particle collection efficiency and size
distribution:
• Structure of fabric
» Fiber composition
* Bag properties
In fabric filtration, both the collection efficiency and the pressure drop across
the bag surface increase as the dust layer on the bag builds up. The method and
frequency of bag cleaning determines the overall collection performance and pressure
drop as well as the bag life. Cleaning processes include mechanical shaking, reverse-
flow, and pulse-Jet. Mechanical shaking and reverse-flow systems require lower air to
cloth (A/C) ratios (2 to 3 rather than 6 to 12 for pulse jet) and are typically found in
the electric utility industry, whereas pulse-jet types are used across most of the
industrial and commercial size spectrum. There is increased interest in pulse-jet
baghouses in the very large systems because of the equipment size advantage.
Emission tests conducted on an industrial spreader stoker equipped with a reverse-
flow fabric filter have shown fractional efficiencies as high as 99.9 percent for particles
in the 0.02 to 2 micron size range. Other reported test data for seven industrial
boilers equipped with baghouses showed controlled PM emissions ranging from 4.1 to
15 ng/J (0.010 to 0.035 Ib/million Btu) and fractional efficiencies of 99.7 to 99.9+
*52
percent.
The above tests indicate that fabric filter performance is not significantly affected
by boiler design type or size. It should be noted that most bag materials will develop
holes or leak paths due to flex abrasion wear, hot embers ("sparklers"), or failure of
attachment points. Very small leaks can substantially diminish the collection efficiency
of a baghouse system, particularly in the size range below 10 microns. Therefore,
careful design and an established maintenance program are important for continued
performance at the specified levels.
2-24
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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 SO2 control on coal-fired combustion sources. One
disadvantage of using scrubbers for PM control is the disposal requirements of the
resulting wet sludge as opposed to the dry product as produced by ESPs, fabric
filters, or cyclone collectors. Tray tower units are best suited for SO2 control and are
effective only for particles greater than 1 micron in diameter, Venturi type scrubbers
are effective down to the submicron range. Scrubber collection efficiency depends on
particle size distribution, gas side pressure drop through the scrubber, and water (or
scrubbing liquor) pressure. Reported fractional efficiencies for a venturi scrubber
range between 95,00 and 99.89 percent for a 2 micron particle.53 Corresponding
pressure drops ranged from 2 to 10 kPa (8 to 40 inches of water).
Cyclone separators can be installed singly, in series, or grouped as in a multi-
cyclone or muiticlone collector. These devices are referred to as mechanical
collectors because they do not rely on electrical, liquid, or barrier principles for
removal of PM from a gas stream. 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 PM-10. Mechanical collectors are often used as a preeollector
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.
Mechanical collectors are designed for a specified range of gas flows. Because the
available collection efficiencies for a given collector depend on inlet velocity, these
devices are not effective for a combustion source which typically operates over wide
load ranges. The typical overall collection efficiency for mechanical collectors ranges
from 90 to 95 percent.
The side-stream separator combines a multi-cyclone 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.
2-25
-------
Atmospheric fluidized bed combustion (AFBC) boilers may tax conventional
particulate control systems. The paniculate mass concentration exiting AFBC boilers
is typically 2 to 4 times higher than pulverized coal boilers . Atmospheric FBC
particles are also, on average, smaller in size, 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
54
recycling, inherent with the AFBC process, tends to reduce exit gas stream particulate size .
2.4.3.2 SOa Control. Commercialized post-combustion flue gas desulfurization
(FGD) uses an alkaline reagent to absorb SO2 in the flue gas and produces a sodium
or a calcium sutfate compound. These solid sulfate compounds are then removed in
downstream particulate control devices as described in Section 2.4.3.1. Flue gas
desulfurization technologies are categorized as wet, semi-dry, or dry depending on the
state of the reagent as it leaves the absorber vessel. These processes are either
regenerate such that the reagent material can be treated and reused, or are non-
regenerable in which all waste streams are de-watered and discarded. Table 2-7
summarizes commercially available post-combustion SO2 control technologies.
Wet regenerable FGD processes are attractive because they have the potential
for better than 95 percent sulfur removal efficiency, have minimal waste-water
^fl
discharges, and produce saleable sulfur product. Some of the current non-
regenerable calcium based processes can, however, produce a saleable gypsum
product.
To date, wet systems are the most commonly applied. Wet systems generally
use alkali slurries as the SOX absorbent medium and can be designed to remove
greater than 90 percent of the incoming S0x. Lime/limestone scrubbers, sodium
scrubbers, and dual alkali scrubbing are among the commercially proven wet FGD
systems. The effectiveness of these devices depends not only on control device
design but also on operating variables.
The lime and limestone scrubbing process uses a slurry of calcium oxide (CaO)
or limestone (CaCO3) to absorb SO2 in a wet scrubber. Control efficiencies in excess
2-26
-------
of 91 percent for lime and 94 percent for limestone over extended periods have been
demonstrated.53 The process produces a calcium sulfite and calcium sulfate mixture.
Calcium sulfite and calcium sulfate crystals precipitate in a hold tank. The hold tank
effluent is recycled to the scrubber to absorb additional SOr A slip stream from the
hold tank is sent to a solid-liquid separator to remove precipitated solids. The waste
solids, typically 35 to 70 weight percent solids, are generally disposed of by ponding
or landfill.
Sodium scrubbing processes generally employ a wet scrubbing solution of
sodium hydroxide (NaOH) or sodium carbonate (Na2CO3) to absorb SO2 from the flue
gas. Sodium scrubbers are generally limited to smaller sources because of high
reagent costs; however, these systems have been installed on industrial boilers up to
125 MW (430 million Btu/hr) thermal input.14 SO2 removal efficiencies of up to 96.2
percent have been demonstrated. Because the SO2 removal efficiency can vary
during load swings and process upsets, a long term mean efficiency of at least 91
percent is necessary to comply with the 90 percent NSPS reduction requirement
based on a 30-day rolling average. The operation of the scrubber is characterized by
a low liquid-to-gas ratio [1.3 to 3.4 l/m3 (10 to 25 gal/ft3)] and a sodium alkali sorbent
which has a high reactivity relative to lime or limestone sorbents. The scrubbing liquid
is a solution rather than a slurry because of the high solubility of sodium salts.
The double or dual alkali system uses a clear sodium alkali solution for SO2
removal followed by a regeneration step using lirne or limestone to recover the sodium
alkali and produce a calcium sulfite and sulfate sludge. Most of the effluent from the
sodium scrubber is recycled back to the scrubber, but a slipstream is withdrawn and
reacts with lime or limestone in a regeneration reactor. The regeneration reactor
effluent is sent to a thickener where the solids are concentrated. The overflow is sent
back to the system while the underflow is further concentrated in a vacuum filter (or
other device) to about 50 percent solids content. The solids are washed to recover
soluble sodium compounds which are returned to the scrubber. Performance data
indicate average SO2 removal efficiencies of 90 to 96 percent.14 However, initial
reports of long-term operating histories with dual alkali scrubbing have indicated
system reliability averages of only slightly higher than 90 percent.
2-27
-------
Spray drying is a dry scrubbing approach to FGD. The technology is best
suited for low to medium sulfur coals with sulfur contents up to 3 percent, but may be
applied to higher sulfur-content coals. A solution or slurry of alkaline material is
sprayed into a reaction vessel as a fine mist and contacted with the flue gas for a
relatively long period of time (5 to 10 seconds). The SO2 reacts with the alkali solution
or slurry to form liquid phase salts. The slurry is dried by the hot flue gas to about
one percent free moisture. The dried material continues to react with SO2 in the flue
gas to form sulfite and sulfate salts. The spray dryer solids are entrained in the flue
gas and carried out of the dryer to a paniculate control device such as an ESP or
baghouse. Systems using a baghouse for paniculate removal report additional SO2
capture across the baghouse.
Spray drying is a relatively new FGD technology and extensive large-scale
commercial experience is limited. Vendors have offered commercial guarantees of up
to 90 percent capture on low sulfur (less than 2.percent) coal.14 Pilot data on calcium-
based sorbents have also showed SO2 reduction efficiencies of 90 percent. Spray
drying with sodium-based sorbents should produce greater removal efficiencies due to
the greater reactivity of sodium hydroxide or sodium carbonate compared with lime.
A number of dry and wet sorbent injection technologies are under development
to capture SO2 in the furnace, the boiler sections, or ductwork downstream of the
boiler. These technologies are generally designed for retrofit applications and are well
suited for coal combustion sources requiring moderate SO2. There are commercial
applications of furnace sorbent injection in Europe; however, the technologies are not
yet commercialized in the U.S. The objectives for SO2 removal efficiencies are
A»
between 25 and 50 percent.
2.4.3.3 NO^ Control. The injection of ammonia (NH3)- or urea-based reagents
into the furnace or flue gas path for NOx control is considered to be post- combustion
control. This process, known as Selective Non-Catalytic Reduction (SNCR), is seeing
some commercial application, primarily for industrial FBC boilers in California. In
bubbling bed FBCs, the reagent is injected above the bed in the freeboard space. In
circulating bed FBCs, injection occurs just prior to, or sometimes within, the first stage
cyclone separator.
2-28
-------
The NOX reduction reactions occur in a relatively narrow temperature window
between 920 and 1030 °C (1700 to 1900 °F), Because of the typically limited
residence times available in this temperature range, the reagent must be injected at
high velocity or with steam or air assist in order to achieve good mixing. Poor quality
mixing or excessive reagent use results in emissions of ammonia (slip) in the flue gas.
Demonstrated efficiencies for NO reduction range from 30 to 50 percent for bubbling
bed FBCs, and up to 80 percent for circulating bed FBCs at NOx/NH3 molar ratios
between 2 and 4.s Reduction efficiencies are apparently higher for circulating FBCs
because of the residence time and intense mixing available in the cyclone.
2-29
-------
Sector
TABLE 2-1. U.S. COAL CONSUMPTION BY SECTOR in 1990
Total Consurrption,
10 metric tons (10 short tons)
Electric Utility
Industrial (Excluding Coke Plants)
Residential/Commercial
Total For All Sectors
701,759 (773,549)
69,246 (76,330)
6,100 (6,724)
777,105 (856,603)
2-30
-------
TABLE 2-2. BOILER USAGE BY SECTOR
Capacity,
Sector MW
Utility >100
Industrial 10-100
Boiler
type
Watertube
Watertube
Watertube
Watertube
Firetube
Firetube
Application
Electricity Generation
Electricity Generation
Process Steam
Space Heating
Process Steam
Space Heating
Commercial
0.5-10
Residential
<0.5
Watertube
Firetube
Cast Iron
Cast Iron
Space Heating
Space Heating
Space Heating
Space Heating
2-31
-------
TABLE 2-3. TOTAL 1985 EMISSIONS FROM COAL COMBUSTION
BY USE SECTOR
Sector
Residential
Commercial/
Institutional
Industrial
Electric
Generation
Total
so*
27(30)
126 (139)
1,478 (1,629)
13,427 (14,801)
20,998 (23,146)
Annual emissions, 10 metric tons
NO
1.8 (2)
26 (29)
513 (§65)
5,084 (5,604)
18,635(20,541)
(103 short tons)
TSPa
10(11)
15(17)
102 (112)
432 (476)
7,605 (8,383)
VOC
7(8)
0-9 (1)
5(6)
26(29)
20,024 (22,073)
Total suspended paniculate.
2-32
-------
TABLE 2-4. NSPS SUMMARY FOR FOSSIL FUEL-FIRED BOILERS
Standard/
Boiler Types/
Applicability
Criteria
Subpart D
Industrial-
Utility
Commence
construction after
8/17/71
Subpart Da
Utility
Commence
construction after
9/18/78
Subpart Db
Industrial-
Commercial-
Institutional
Commence
construction,after
6/19/84
Subpart DC
Small Industnal-
Commercial-
Institutional
Commence
construction after
6/9/89
Fuel
Boiler Size or
MW Boiler
(Million Btu/hr) Type
>73 Gas
(>250)
CHI
Bii/Subblt.
Coal
>73 Gas
(>250)
Oil
Bit/Subbit.
Coal
>29 Gas
(>100)
Distillate Oil
Residual Oil
Pulverized
Bft/Subbit.
Coal
Spreader
Stoker & FBC
Mass-Feed
Stoker
2.9 - 29 Gas
(10 - 100)
Oil
Bit. & Subbit.
Coal
PM
ng/J
(Ib/MMBtu)
[% reduction]
43
(0,10)
43
(0.10)
43
(0.10)
13
(0.03
[NA]
13
(0.03)
[70]
13
(0,03)
[99]
NAd
43
(0,10)
(Same as for
distillate oil)
22°
(0.05)
22*
(0.05)
226
(0.05)
h
,
."•'
22U
(0.05)
SO
ng/D
(Ib/MMBtu)
[% reduction]
NA
340
(0.80)
520
(1-20)
340
(0.80)
rfwi'i
340
(0.80J
[90f
§20
(1-20J
POT
NAd
340
(0.80)
[90]
(Same as for
distillate oil)
520*
(1.20)
f90]
520°
(1.20)
[90]
520*
(1.20)
[90]
.
215
(0.50)
520"
(1.20
[90]
NO
ng/3
(Ib/MMBtu)
[% reduction]
86
(0.20)
129
(0.30)
300
(0.70)
86
(020)
[25]
130
(0.30)
[30]
260/210°
(0.60/0.50)
165/65]
43f
(0-10)
43f
(0.10)
130s
(0.30)
300
(0.70)
260
(0,60)
210
(0.50)
„
-
_
2-33
-------
Footnotes For Table 2-4
Zero percent reduction when emissions are less than 86 ng/J (0.20 Ib/MMBtu).
70 percent reduction when emissions are less than 260 ng/J (0.60 Ib/MMBtu).
'The first number applies to bituminous coal and the second to subbituminous coal.
Standard apples when gas is fired in combination with coal, see 40 CFR 60, Subpart Db.
Standard is adjusted for fuel combinations and capacity factor limits, see 40 CFR 60, Subpart Db.
For furnace heat release rates greater than 730,000 J/s-m (70,000 Btu/hr-fr), the standard is 86 ng/J (0JO
Ib/MMBtu),
8For furnace heat release rates greater than 730,000 J/s-m (70,000 Btu/hr-ft3), the standard is 170 ng/J (0.40
Ib/MMBtu).
. Standard applies when gas or oil is fired in combination with coal, see 40 CFR 60, Subpart DC.
^20 percent capacity limit applies for heat input capacities of 8.7 Mwt (30 MMBtu/hr) or greater.
^Standard is adjusted for fuel combinations and capacity factor limits, see 40 CFR 60, Subpart DC.
Additional requirements apply to facilities which commenced construction, modification, or reconstruction
after 6/19/84 but on or before 6/19/86 (see 40 Code of Federal Regulations Part 60, Subpart Db).
215 ng/J (0 JO Ib/million Btu) limit (but no percent reduction requirement) applies if facilities combust only
very low sulfur oil (< 0.5 wt. % sulfur).
2-34
-------
TABLE 2-5. COMMERCIALLY AVAILABLE NO CONTROL TECHNIQUES FOR PULVERIZED COAL-FIRED
Control technique
Description of technique
Effectiveness of control, Commercial
% NO reduction Range of application availability/R&D status Comments
Low Excess Air (LEA)
Reduction of combustion
air
0-25 {avg. 9) Excess oxygen reduced to Available,
5.2% on the average.
Added benefits of technique Include
increase In boiler efficiency, limited by
increase In CO, HC and smoke
emissions.
03
Ul
Burners out of service
(BOOS)
One or more burners on air
only. Remainder firing fuel
rich.
Overfire aJr injection (OFA) Secondary air from OFA
ports above fuel rich firing
burners.
Flue gas recirculation
(FOR)
LJOW NO burner (LNB}
x
Recirculation of ftue gas to
burner wind box,
New burner designed
utilizing controlled air-fuel
mixing,
27-39 (avg. 33)
5-30
0-20
45-60
Applicable only for boilers Available. However,
with minimum of 4 burners, extensive engineering
work necessary before
implementation.
Limited by the number of burners
available. Load reduction required in
most cases. Possible Increased
slagging, corrosion.
Burner stoichiometry as lowCommercially offered but Requires installation of OFA ports, etc.
as 100%. not demonstrated for Possible increased slagging, corrosion.
industrial size boilers.
Up to 25% of the flue gas Not offered because
rectr ciliated. relatively ineffective.
Requires installation of FQR ducts, fan,
etc. Can cause combustion instability.
Burner wind box may need extensive
modifications,
Prototype LNB limited to Still in the development Active R&D efforts underway.
size ranges above 29 MW stage. Prototype LNB
(100 x 10 Btu/h) available from major
boiler mfrs.
Ammonia Injection (SNCfi) Injection of NH In
connective section of boiler
40-60 Umited by furnace Commercially offered but Elaborate NH Injection, monitoring, and
geometry. NH. Injection not demonstrated, control system required. Possible load
restrictions on boiler and air preheatar
fouling by ammonium bisulfate,
rate limited to ,5 NH./NO.
3
Reduced load (RL)
Reduction of fuel and air Varies from 45% reduction Applicable to all boilers.
flow to the boiler.
to 4% Increase in NO
Load can be reduced to
25% of capacity.
Available now but not Load reduction often not effective
implemented because of because of increase in excess O . Best
adverse operational implemented with increase in furnace
impacts. size for new boilers.
Low NO burners are the minimum control technology required for NO emissions from PC-fired utility boilers.
X X
-------
TABLE 2-6.
COMMERCIALLY AVAILABLE NOx CONTROL TECHNIQUES FOR STOKER COAL-FIRED BOILERS
Control technique
Description of technique
Effectiveness of control,
% NO reduction
Range of application
Commercial
availability/R&D status
Comments
ro
ft
Low Excess Air (LEA)
Staged combustion
(LEA + OFA)
Load reduction (LR)
Reduced sir preheat
(RAP)
Ammonia injection
Reduction of air flow under
stoker bed
Reduction of under grate air
flow and increase of
overtire air flow.
5-25
5-25
Excess oxygen limited to 5-Available now but need
6% minimum. R&D on lower limit of
excess air.
Excess oxygen limited to
5% minimum.
Reduction of coal and air
feed to the stoker.
Reduction of combustion
air temperature.
Varies from 49% decrease
to 25% increase In NO
(average 15% decrease*).
Injection of NH In 40-60 (from gas- and oil-
convective secnon ol boiler.fired boiler experience).
Has been used down to
25% load.
Most stokers have OFA
ports as smoke control
devices but may need
better air flow control
devices.
Available.
Combustion air
temperature reduced from
473K to 453K.
Limited by furnace
geometry. Feasible NH.
injection rate limited to 1.5
NH^/NO.
Danger of overheating grate, clinker
formation, corrosion, and high CO
emissions.
Need research to determine optimal
location and orientation of OFA ports for
NO emission control. Overheating grate,
corrosion, end high CO emission can
occur If undergrate airflow Is reduced
below acceptable level as In LEA.
Only stokers that can reduce load without
increasing excess air. Not a desirable
technique because of toss In boiler
efficiency.
Available now if boiler has Not a desirable technique because of loss
combustion air heater. In bolter efficiency.
Commercially offered but Elaborate NH. Injection, monitoring, and
not yet demonstrated. control system required. Possible toad
restrictions on boiler and air preheater
fouling by ammonium bisulfate.
-------
TABLE 2-7. POST COMBUSTION SO CONTROLS FOR COMBUSTION SOURCES
Control
technology
Process
Available
control
efficiencies
Remarks
Wet Scrubber
Spray Drying
Furnace Injection
Duct Injection
Ume/Umestone
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%
80-95-1-%
90-96%
70-90%
25-50%
25-50+%
Applicable to high sulfur fuel,
Wet sludge product
1,5-125 MWt [5 - 430 million Btu/hr
(MMBtu/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
underway
Several R&D and demonstration
projects underway,
Not yet commercially available
in the U.S.
2-37
-------
Coal Ram
Figure 2-1. Single-retort horizontal-feed underfeed stoker.
Tuyeres
I
Ash Discharge Plate
Furt Distributors
Figure 2-2. Multiple-retort gravity-feed underfeed stoker.
2-38
-------
Coal Hopper
Drive
Linkage
Drive
Sprocket
Sittings
Hopper
Return
Bend
Air Seals Air Compartments Drag Frame
Figure 2-3. Overfeed chain-grate stoker.
Figure 2-4. Spreader stoker.
2-39
-------
. 56
Figure 2-5. Bubbling FBC schematic.
Figure 2-6, Circulating FBC schematic.
2-40
. 56
-------
ro
BOILER SUPPORT STRUCTURE
GAS OUTLET
SMOKE BOX
PRIMARY COMBUSTION CHAMBEfl --
FEED CHUTE
A3 REQUIRED
ORATES OR
TANGENTIAL
FURNACE
INDUSTRIAL HRT BOILER
• STEAM CONNECTION
r-REAR ARCH TILE
I/-REAR TURNING
AREA
^REFRACTORY
-CURTAIN WMJ.
BLOW OFF VALVES
BLOW OFF PROTECTOR
TILE
BRIDGE mu.
SECONDARY COMBUSTION
CHAMBER
Figure 2-7. Two-pass HRT boiler.
57
-------
s
I
DJ
C3)
LL
2-42
-------
en
-------
Figure 2-10. Four-pass scotch boiler.
2-44
-------
SAFETY
WUGCTOft
Figure 2-11. Exposed-tube vertical boiler,*
2-45
-------
WATER
COLUMN
STEAM
OUTLET
•smreoos
Figure 2-12. Submerged-tube vertical boiler.3
2-46
-------
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2-47
-------
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2-48
-------
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34. Coles, D.G. et al., "Chemical Studies of Stack Fly Ash From a Coal-Fired Power
Plant". Environ. Sci. Technol.. 13: 455-459, 1979.
35. Baig, S. et al., Conventional Combustion Environmental Assessment. EPA
Contract No. 68-02-3138, U.S. Environmental Protection Agency, Research
Triangle Park, NC, 1981.
36. South, D.W. et al., Technologies and Other Measures For Controlling
Emissions: Performance. Costs, and Applicability. Acidic Deposition: State of
Science and Technology, Volume IV, Report 25, National Acid Precipitation
Assessment Program, U.S. Government Printing Office, Washington, DC,
December 1990.
37. Buroff, J. et al., Technology Assessment for Industrial Boiler Applications: Coal
Cleaning and Low Sulfur Coal. EPA-60Q/7-79-178C, U.S. Environmental
Protection Agency, Research Triangle Park, NC, December 1979,
38. Gluskoter, H J. et al., Trace Elements in Coal: Occurrence and Distribution.
EPA-600/7-77-064, U.S. Environmental Protection Agency, Research Triangle
Park, NC, 1977.
2-49
-------
39. Danielson, J.A. (ed.), Air Pollution Engineering Manual. Second Edition, AP-40,
U.S. Environmental Protection Agency, Research Triangle Park, NC, 1973.
40. Barrett, R.E. et al,, Field investigation of Emissions from Combustion Equipment
for Space Heating. EPA-R2-73-084a, U.S. Environmental Protection Agency,
Research Triangle Park, NC, June 1973.
41. Bartok, W. et al., Systematic Field Study of NO^ Emission Control Methods for
Utility Boilers. APTD-1163, U.S. Environmental Protection Agency, Research
Triangle Park, NC, December 1971.
42. Crawford, A.R. et al., Field Testing: Application of Combustion Modifications to
Control NCX Emissions from Utility Bolters. EPA-65Q/2-74-066, U.S.
Environmental Protection Agency, Washington, DC, June 1974.
43. Govan, F.A. et al., "Relationships of Paniculate Emissions Versus Partial to Full
Load Operations for Utility-sized Boilers", Proceedings of the Third Annual
Industrial Air Pollution Control Conference. Knoxville, TN, March 29-30, 1973.
44. Hall, R.E. et al., A Study of Air Pollutant Emissions from Residential Heating
Systems. EPA-650/2-74-003, U.S. Environmental Protection Agency,
Washington, DC, January 1974.
45. Pohl, J.H. and A.F. Sarofim, Devolatilization and Oxidation of Coal Nitrogen
(presented at the 16th International Symposium on Combustion). August 1976.
46. Pershing, D.W. and J. Wendt, Relative Contribution of Volatile and Char
Nitrogen to NOx Emissions From Pulverized Coal Flames. Industrial Engineering
Chemical Proceedings, Design and Development, 1979.
47. Pershing, D.W. Nitrogen Oxide Formation in Pulverized Coal Flames. Ph.D.
Dissertation, University of Arizona, 1976.
48. Nutcher, P.B. High Technology Low NOx Burner Systems for Fired Heaters and
Steam Generators. Process Combustion Corp., Pittsburgh, PA. Presented at the
Pacific Coast Oil Show and Conference, Los Angeles, CA, November 1982.
49. EPRI CS-5040, "Precipitator Performance Estimation Procedure", prepared by
Southern Research Institute, February 1987 (AP-42 #208))
50. Roeck, D.R. and R. Dennis, Technology Assessment Report for industrial Boiler
Applications: Particulate Collection. EPA-600/7-79-178h, U.S. Environmental
Protection Agency, Research Triangle Park, NC, December 1979.
51 • Determination of the Fractional Efficiency. Opacity Characteristics. Engineering.
and Economics of a Fabric Filter Operating of a Utility Boiler. EPRI Report FP-
297, Electric Power Research Institute, Palo Alto, CA.
2-50
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52. Overview of the Regulatory Baseline. Technical Basis, and Alternative Control
Levels for Particulate Matter fPM) Emissions Standards for Small Steam
Generating Units. EPA-450/3-89-11, U.S. Environmental Protection Agency,
Research Triangle Park, NC, May 1989.
53. Overview of the Regulatory Baseline. Technical Basis, and Alternative Control
Levels for Sulfur Dioxide (SOJ Emissions Standards for Small Steam Generating
Units. EPA-450/3-89-12, U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1989.
54. EPA Industrial Boiler FGD Survey: First Quarter 1979. EPA-600/7-79-067b, U.S.
Environmental Protection Agency, Research Triangle Park, NC, April 1979.
55. State-of-the-Art Analysis of NO /NO Control for Fluidized Bed Combustion
Power Plants. EPRI Contract NoR>3197-02, Acurex Report No. 90-102/ESD,
Acurex Environmental, Mountain View, CA, July 1990.
56. Gaglia, B.N. and A. Hall (Gilbert/Commonwealth, Inc.). Comparison of
Bubbling and Circulating Fluidized Bed Industrial Steam Generation.
Proceedings of the 1987 International Conference on Fluidized Bed
Combustion. The American Society of Mechanical Engineers/Electric Power
Research Institute/Tennessee Valley Authority. New York, NY, 1987.
57. Industrial Boiler Co., Inc. Fusion Welded Horizontal Return Tubular Boiler to
ASME Code. Industrial Boiler Co., Inc. Thomasville, GA, Bulletin No. F3350.
58. Industrial Boiler Co., Inc. Pacemaker II. Industrial Boiler, Inc. Thomasville, GA.
Bulletin No. F2350 R1. December, 1987.
59. Cleaver Brooks. Packaged Watertube Steam Boilers. Cleaver Brooks.
Milwaukee, Wl. Bulletin No. CBW-227 R9. July, 1987.
60. Cleaver Brooks. CB Packaged Boilers. Cleaver Brooks. Milwaukee, Wl.
Bulletin No. CBF-178 R11. December, 1986.
61. W.R. Seeker, et. al., Municipal Waste Combustion Study: Combustion of MSW
Combustors to Minimize Emissions of Trace Organics. EPA-530-SW-87-021 e,
U.S. Environmental Protection Agency, Research Triangle Park, NC, May 1987.
62. S.W. Brown and R.W. Borio, Gas Reburn System Operating Experience on a
Cyclone Boiler. Presented at the NOX Controls for Utility Boilers Conference,
Cambridge, MA, July 1992.
2-51
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3. GENERAL EMISSION DATA REVIEW AND ANALYSIS PROCEDURE
3.1 CRITERIA POLLUTANTS
3.1.1 Literature Search
The first step in this revision and update involved an extensive literature search
to identify sources of criteria (non-criteria) pollutant emissions data associated with
bituminous and subbrtuminous coal combustion. This search included:
• Existing AP-42 background files;
• Files maintained by EPA's Emission Standards Division and Emission
Factor and Methodologies Section of the Office of Air Quality Planning
and Standards (OAQPS);
» PM-10 documents;
» NSPS Background Information Documents;
» Various EPA emissions assessment and control technology reports;
• National Technical Information Service (NTIS) holdings;
• Reports from industry organizations including the Electric Power
Research Institute (EPRI) and API;
» Various on-line computerized data bases and search services;
» EPA contractor reports; and
• Contractor in-house files.
A summary of these information sources is given in Table 3-1.
3.1-2 Literature Evaluation
To reduce the large amount of available literature to a final group of references
pertinent to this task, the following general criteria were used:
3-1
-------
1. Emissions data must be from a well documented reference;
2. The referenced study must contain results based on more than one test
run; and
3. The report must contain sufficient data to evaluate the testing
procedures and source operating conditions.
Employing these criteria in a thorough review of the reports, documents, and
information, a final set of reference materials was compiled. The data contained in this
final set of references were then subjected to a thorough quality and quantity
evaluation to determine their suitability for use in emission factor calculations.
Checklists were employed to facilitate and document this evaluation. The completed
checklists were placed in the background files for this AP-42 update. Data with the
following characteristics were excluded from further consideration:
1. Test series averages reported in units that cannot be converted to the
selected reporting units;
2. Test series representing incompatible test methods (i.e., comparison of
EPA Method 5 front-half with EPA Method 5 front-and back-half);
3. Test series of controlled emissions for which the control device is not
specified;
4. Test series in which the source or control process is not clearly identified
and described; and
5. Test series in which it is not clear whether the emissions were measured
before or after the control device.
Data sets that were not excluded were assigned a quality rating. The rating
system used was that specified in the draft EPA document, 'Technical Procedures For
Developing AP-42 Emission Factors And Preparing AP-42 Sections" (March 6, 1992).
The data were rated as follows:
A: Multiple tests performed on the same source using sound methodology
and reported in enough detail for adequate validation. These tests are
not necessarily EPA reference method tests, although such reference
methods are preferred and certainly to be used as a guide.
3-2
-------
B: Tests that were performed by a generally sound methodology but lack
enough detail for adequate validation.
C: Tests that were based on an untested or new methodology or that
lacked a significant amount of background data.
D: Tests that were based on a generally unacceptable method but may
provide an order-of-magnftude value for the source.
The following criteria were used to evaluate source test reports for sound
methodology and adequate detail:
1. Source operation. The manner in which the source was operated is well
documented in the report. The source was operating within typical
parameters during the test.
2. Sampling procedures. The sampling procedures conformed to generally
acceptable methodology. If actual procedures deviated from accepted
methods, the deviations are well documented. When this occurred, an
evaluation was made of the extent such alternative procedures could
influence the test results.
3. Sampling and process data. Adequate sampling and process data are
documented in the report. Many variations can occur unnoticed and
without warning during testing. Such variations can induce wide
deviations in sampling results. If a large spread between test results
cannot be explained by information contained in the test report, the data
are suspect and given a lower rating.
4. Analysis and calculations. The test reports contain original raw data
sheets. The nomenclature and equations used were compared to those
(if any) specified by EPA to establish equivalency. The depth of review of
the calculations was dictated by the reviewer's confidence in the ability
and conscientiousness of the tester, which in turn was based on factors
such as consistency of results and completeness of other areas of the
test report.
In most cases, emissions data were obtained from original source assessment
or source test reports. In addition, there is a large body of data that have been
summarized by EPA in background documents, emissions assessment reports, and
control technology reports.
These reports were used to support regulatory development efforts, control
technology determinations, permitting, and for setting further research priorities.
3-3
-------
Because of their Intended usage, the data contained in these reports have been
produced under rigorous quality assurance/quality control procedures and, before
being summarized, have undergone data quality review by EPA. Because of these
procedures, emissions data were take,) directly from the summary reports for input
into the emission factor calculations. The data taken from these reports were
assigned a "B" quality rating. This rating was given to reflect the fact that testing
followed EPA reference methods or otherwise sound methodology; however, the
summary reports do not contain enough raw data to verify the data reduction
calculations. To supplement the summary report information, orders were placed for
copies of the original test reports cited in the summary reports. These test reports,
when received, were placed in the background files.
3.1.3 Emission Factor Quality Rating
In each AP-42 section, tables of emission factors are presented for each
pollutant emitted from each of the emission points associated with the source. The
reliability or quality of each of these emission factors is indicated in the tables by an
overall Emission Factor Quality Rating ranging from A (excellent) to E (poor). These
ratings incorporate the results of the above quality and quantity evaluations on the
data sets used to calculate the final emission factors. The overall Emission Factor
Quality Ratings are described as follows:
A--Excellent: Developed only from A-rated test data taken from many randomly
chosen facilities in the industry population. The source category is specific
enough so that variability within the source category population may be
minimized.
B--Above average: Developed only from A-rated test data from a reasonable
number of facilities. Although no specific bias is evident, it is not clear if the
facilities tested represent a random sample of the industries. As in the A-rating,
the source category is specific enough so that variability within the source
category population may be minimized.
C--Averao.e: Developed only from A- and B-rated test data from a reasonable
number of facilities. Although no specific bias is evident, it is not clear if the
facilities tested represent a random sample of the industry. As in the A-rating,
the source category is specific enough so that variability within the source
category population may be minimized.
3-4
-------
D--Below average: The emission factor was developed only from A- and B-
rated test data from a small number of facilities, and there is reason to suspect
that these facilities do not represent a random sample of the industry. There
also may be evidence of variability within the source category population.
Limitations on the use of the emission factor are noted in the emissions factor
table.
E-Poor: The emission factor was developed from C- and D-rated test data,
and there is reason to suspect that the facilities tested do not represent a
random sample of the industry. There also may be evidence of variability within
the source category population. Limitations on the use of these factors are
always noted.
The use of these criteria is somewhat subjective and depends to an extent on
the individual reviewer. Details of the rating of each candidate emission factor are
provided in Chapter 4 of this report.
3.2 SPECIATED VOCs
3.2.1 Literature Search
An extensive literature search was conducted during this revision to identify
sources of speciated VOC emissions data associated with coal fired boilers. Some
specific areas of search include Tennessee Valley Authority, Electric Power Research
Institute (EPRI)/PISCES, EPA/Air and Waste Mangement Association (AWMA) Air
Toxics Symposia, and Toxic Air Pollutants: State and Local Regulatory Strategies 1989.
The details of the literature search are summarized in Table 3-2.
3.2.2 Literature Evaluation
Until recently, little concern existed for VOC speciation on stationary external
sources. Nearly all organics sampling was focused on semi-volatile compounds.
Reliable methods for volatile organics sampling and analysis to low levels have only
been developed since the late 1980's. Therefore, available data for VOC speciation
were sparse, limiting this data evaluation essentially to the OAQPS databases, the
VOC/PM Speciation Data System (SPECIATE) and the Crosswalk/Air Toxic Emission
Factor data base (XATEF), and their references.
3.2.3 Data and Emission Factor Quality Rating
The ratings of emission factors in SPECIATE and XATEF should not be used
without first reviewing primary sources of numerical data against the criteria presented
in Chapter 3.1. The quality of the data is insufficient to satisfy the requirements for
3-5
-------
-------
Western States Petroleum Association (WSPA), the Canadian Electrical Association
(CEA), the Ontario Ministry of the Environment and KEMA of the Netherlands.
3.3.2 Literature Evaluation for Air Toxics
The references obtained from the literature search were evaluated for their
applicability for generating emission factors. Table 3-3 summarizes the data sources
and indicates which sources were used in generating the emission factors and which
sources were eliminated from use. The table contains a reference number which
corresponds to the list of references provided at the end of this section. The
references are evaluated and discussed in greater detail in Section 4.3.1. The criteria
used to perform this evaluation are discussed in detail in Section 3.3.3.
3.3.3 Data and Emission Factor Quality Rating Criteria
Emissions data used to calculate emission factors are obtained from many
sources such as published technical papers and reports, documented emissions test
results, and regulatory agencies such as local air quality management districts. The
quality of these data must be evaluated in order to determine how well the calculated
emission factors represent the emissions of an entire source category. Data sources
may vary from single source test runs to ranges of minimum and maximum values for
a particular source. Some data must be eliminated all together due to their format or
lack of documentation. Factors such as the precision and accuracy of the sampling
and analytical methods and the operating and design specifications of the unit being
tested are key in the evaluation of data viability.
The first step in evaluating a data report is to determine whether the source is a
primary or secondary source. A primary source is that which reports the actual
source test results while a secondary source is one that references a data report.
Many of the sources referenced by XATEF, SPECIATE, and the CD ROM are
secondary or tertiary sources. Preferably only primary sources were used in the
development of emission factors. When there was not time in this work effort to obtain
or evaluate the primary sources, data were taken from a secondary reference if it
appeared that an adequate evaluation of the data was performed.
The primary source reports are evaluated to determine if sufficient information is
included on the device of interest and on any abatement equipment associated with
3-7
-------
rtal Protection Agency, Generalized Particle Size Distributions
arinq Size Specific Particulate Emission Inventories. EPA-450/4-
sh Triangle Park, North Carolina, 1986.
ntal Protection Agency, Technical Procedures for Developing
Factors and Preparing AP-42 Sections - Draft. Research
lorth Carolina, March 1992. W
for
:a
•rds
e:
d.
re
a
ir
;DS
3-21
-------
3.4.3 Data and Emission Factor Quality Rating
Data obtained through the literature search, except that derived from on-line
N2O analysis with gas chromotography/electron capture detection (GC/ECD), were
rated C or poorer, because the data were based on untested or new methodology
that lacked sufficient background data. A problem has been identified in using grab
sampling techniques measuring N2O emissions from coal combustion. Storing
combustion products in grab samples containing SO2, NOx and water for periods as
short as 1 hour can lead to the formation of several hundred parts per million (ppm) of
N2O where none originally existed. Presented below are some improved
methodologies for N2O sampling and analysis and their relative effects on data quality
ratings:
» On-line N2O analysis with GC/ECD (preferred method)
• Grab samples
Removing H2O - drying the sample reduces the most important
reactant§ but may not entirely eliminate N2O formation.
Removing SO2 - scrubbing the sample through NaOH solution.
A combination of the two (second preference)
The emission factor for pulverized coal-fired boilers was calculated with B rated
data. Of the data reported, eighty percent of the values used to calculate the emission
factor were below the detection limit of the analytical instrument. Therefore, the
emission factor was assigned a D quality rating.
The emission factor for fluidized bed combustors was developed from D rated
test data. Because the data were not recorded with an on-line GC/ECD N2O analysis
and the tested facilities are not representative of the industry, the emission factor
received an E rating.
3.5 FUGITIVES
A literature search was conducted on fugitive emissions as described in section
3.1.1. A literature evaluation and data rating was not conducted for coal storage and
handling operations, because those fugitive emissions are covered in sub-sections of
AP-42 Chapter 11. The fly ash handling operations in most modern utility and
3-9
-------
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 paniculate matter emissions from these systems are therefore minimal.
Fugitive paniculate emissions can sometimes occur during transfer operations from
silos to trucks or rail cars. Particulate matter emission factors resulting from these
operations can be developed using the procedures in AP-42 Chapter 11.
3.6 PARTICLE SIZE DISTRIBUTION
3.6.1 Literature Search
The literature search emphasized filling the perceived gaps in the previous
updates. Updates to AP-42 are supposed to report PM-10 emissions as the sum of
the in-stack filterable paniculate and the organic and inorganic CPM. Upon review of
the 1988 AP-42 update of paniculate sizing emission data, the largest gap appeared to
be the lack of CPM data.
The background files for the 1988 AP-42 update were reviewed. A Dialog data
base search was conducted, focussing on reports issued since 1980. Based on the
results of the Dialog search, NTIS documents, EPA reports, and conference
proceedings were ordered and journal articles were collected. Conference symposia
that were searched included the Eighth and Ninth Particulate Control Symposia and
the Air and Waste Management Association Conferences for 1988 through 1991.
The following PM-10 "gap filling" documents were examined (with results
indicated):
• "PM-10 Emission Factor Listing Developed by Technology Transfer"
fEPA-450/4-89-022): The factors presented for bituminous coal came
from AP-42.
* "Gap Filling PM-10 Emission Factors for Selected Open Area Dust
Sources" (EPA-450/88-OQ31: Not applicable to stationary source
combustion.
* "Generalized Particle Size Distributions for Use in Preparing Size Specific
Particulate Emission Inventories" (EPA-45Q/4-86-013): Lists the average
collection efficiencies of various particulate control devices for different
size fractions. This was the source of the overall collection efficiency
estimates for the 1986 PM-10 update of AP-42 Chapter 1.
3-10
-------
The following regional EPA offices and state and regional air pollution control boards
were contacted;
» EPA Region 2
* EPA Region 3
* EPA Region 4
* EPA Region 5
* California Air Resources Board: Stationary Sources Division, Monitoring
and Laboratory Division, and the Compliance Division
* Illinois Air Pollution Control
• New York Air Pollution Control
• New Jersey Air Pollution Control
* Bay Area Air Quality Management District (CA)
• Kern County Air Pollution Control District (CA)
« Stanislaus County Air Pollution Control District (CA)
» San Joaquin County Air Pollution Control District (CA)
The primary source of the particulate size distribution data for the previous AP-
42 update was the Fine Particulate Emissions Information System (FPEIS). The FPEIS
has not been updated since the previous AP-42 update.
The EPA OAQPS Emissions Monitoring Branch was contacted for test data
from method development studies for EPA Method 202.
Contacts were also made with Electric Power Research Institute (EPRI),
Wheelabrator Air Pollution Control, Southern Research Institute, and Entropy.
3-6.2 Literature Evaluation
The previous update was reviewed and evaluated. The size distribution data
were evaluated by spot-checking the tabulated results against the original FPEIS
printouts. If during the literature search, the original test report was uncovered that
corresponded to a particular FPEIS printout, the data were compared. The objective
3-11
-------
of the review was to ensure that the data collected in the 1986 update were ranked
and used appropriately.
The previous update was also evaluated with respect to the development of
emission factors from the particle size distribution data.
The original FPEIS printouts were also examined. There were two objectives in
the reevaluation of the FPEIS printouts:
(1) Ensure that only filterable PM was included in the cumulative percent
mass results; and
(2) Search for impinger results to provide CPM emission data.
New literature was evaluated based on the use of appropriate sampling
methods and documentation of sufficient process information.
3.6.3 Data Quality Ranking
Data were reviewed and ranked according to the criteria described previously
(Ref. 31 } and the data evaluation criteria presented for the previous update. Data
quality was assessed based on the particle sizing and/or PM-10 measurement method
used and the availability of sampling and process data.
For paniculate sizing and filterable PM-10 data the following criteria were used:
A - Particle sizing tests performed by cascade impactors or PM-10
measurements performed via Method 201 or 201 A. The test information
must provide enough detail for adequate validation and the isokinetics
must fall between 90 and 110 percent.
B - Particle sizing tests performed via SASS trains if the sampling flowrate
isokinetic value was reported and sufficient operating data were used,
Cascade irnpactor data or Method 201 or 201A data if isokinetics not
reported or if isokinetics not within the 90 to 110 percent range.
C - SASS train data if the isokinetics were not reported or if the isokinetics
did not fall within the 90 to 110 percent range.
D - Test results based on a generally unaccepted particulated sizing method,
such as polarized light microscopy.
Although cascade impactors are generally considered the best available method
for measuring paniculate size distributions, errors in segregating specific sizes of
combustion particles arise from the following:
3-12
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• Particle bounce and re-entrainment
* Diffusive deposition of fine particles
* Deposition of condensible/adsorbable gases
« Losses to the impactor walls
The effects of such errors are described in "Cascade Impactors in the Chemical and
Physical Characterization of Coal-Combustion Aerosol Particles", by John M. Ondov,
Chapter 25 of Fossil Fuels Utilization: Environmental Concerns. 1986.
The ranking of data for CPM was based primarily on the methodology. Most
CPM source tests have been conducted using the back-half of a Method 5, Method 17
or South Coast methods 5.2 or 5.3 trains. However, these test methods do not
require a nitrogen (N2) purge of the impingers. Without the N2 purge, dissolved SO2
remains in the impingers and is included in the inorganic CPM results. This type of
CPM data is considered very low quality. In contrast, Method 202 includes a one-hour
N2 purge of the impingers immediately after sampling to remove dissolved SO2.
Therefore Method 202 CPM data should be ranked higher than Method 5 or Method
17 CPM data, even though Method 202 is a relatively new method. The following
rankings were selected for CPM data:
A - CPM tests performed via Method 202. The test information must provide
enough detail for adequate validation and the isokinetics must fall
between 90 and 110 percent.
B - CPM tests performed via Method 202 but isokinetics not reported or
isokinetics not within the 90 to 110 percent range. CPM tests performed
via Method 5 or Method 17 or another acceptable EPA Method that does
not include an impinger N2 purge, if the isokinetics were within the 90 to
110 percent range.
C - CPM tests performed via Method 5 or Method 17 or another acceptable
EPA Method that does not include an impinger N2 purge, if the
isokinetics were not reported or not within the 90 to 110 percent range.
D - Test results based on a generally unaccepted CPM method.
3-13
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TABLE 3-1. LITERATURE RESULTS
Literature Type
1. AP-42 files
2. ESD Files/
NSPS Background
Information Documents
3. CTC publications
4. ORD reports
5. NTIS
6. EPRt
7. Contractor in-house
documents
8. API
New baseline NO control Paniculate control
data information Information
/ / /
None / /
None J None
/ J /
/ / /
None / None
/ / /
/ None None
SOX control
information
/
-
None
s
'
None
'
None
ESD = Emission Standard Division (of EPA)
CTC = Control Technology Center (of EPA)
OflD = Office of Research and Development (of EPA)
NTIS - National Technical Information Service
EPRI = Electric Power Research Institute
API = American Petroleum Institute
-------
TABLE 3-2. SPECIATED VOC LITERATURE SEARCH RESULTS
Literature Type
Remarks
EPA/AWMA Air Toxics Symposia (1988-
1990)
TOXIC AIR POLLUTANTS: State and
Local Regulatory Strategies (1989)
Contractor in-house documents
Journals
COMPENDEX
EPRl/PISCES
Papers
No Data
Called those states and localities listed in air toxics
report. Received some data, but all was criteria data
No useful data,
No useful data.
No references found.
Available end of 1992.
No useful data.
3-15
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TABLE 3-3. EVALUATION OF AIR TOXICS REFERENCES
CO
_A
o>
Section 3
Reference
8
9
to
10a
11
I1a
lib
12
13
14
IS
16
17
18
19
20
21
22
23
24
Used in
update?
No
Yes
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Reason
Not a primary reference. Document references other low quality references.
Not a primary reference, however, data are presented for use for rough estimates.
Not a primary reference. Document references 3a.
Data of unacceptable quality to generate emission factors.
Not a primary reference. Document references 4a and 4b.
Data not of sufficient quality to generate emission factors or enrichment ratios.
Emission factors units can not be converted to desired units.
Fuel mixture Is not applicable.
Fuel mixture Is not applicable.
Fuel mixture Is not applicable.
Data from Reference 4a were sited. These data are of unacceptable quality.
Document presents criteria data only.
Same as Reference 2.
Not a primary reference. Data are of sufficient quality for emission estimates.
Not a primary reference. Data of sufficient quality for emission estimates.
Not a primary reference. Data of sufficient quality lor emission estimates.
Source test data are of sufficient quality to calculate enrichment ratios and
emission factors.
Enrichment ratio data are of sufficient quality to present.
Emission factor are of sufficient quality for emission estimates.
Reference used In discussion of partitioning behavior.
Parameter of
Interest
POM
Chromium
Formaldehyde
Metals
PAH,
radlonuclides,
metals
Metals
Manganese
-------
TABLE 3-4. NgO LITERATURE SEARCH RESULTS
Literature Type
Remarks
TOXIC AIR POLLUTANTS: State and Local Regulatory
Strategies (1989)
Contractor in-house documents
University of North Dakota
TVA
COMPENDEX
EPRI/PISCES
FBC International Conferences
Journals
EPA workshops
No useful data
One primary reference
Data apply to lignite combustion
No useful data
No references identified
Available end of 1992
Did not get 11th conference proceedings;
others not useful
Used one journal as a primary reference
Some useful references
TVA = Tennessee Valley Authority
3-17
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REFERENCES FOR CHAPTER 3
1. Fossil Fuel Fired Industrial Boilers - Background Information: Vols. 1 and 2.
EPA-450/3-82-0068 and b, U. S. Environmental Protection Agency, Research
Triangle Park, NC, March 1982.
2. Overview of the Regulatory Baseline. Technical Basis, and Alternative Control
Levels for Participate Matter (PM) Emission Standards for Small Steam
Generating Units. (Final Report! EPA-45Q/3-89-11, U. S. Environmental
Protection Agency, Research Triangle Park, NC, May 1989.
3. Overview of the Regulatory Baseline. Technical Basis, and Alternative
Control Levels for Sulfur Dioxide (SO2) Emission Standards for Small
Steam Generating Units. (Final Report). EPA-450/3-89-12, U, S.
Environmental Protection Agency, Research Triangle Park, NC, May
1989.
4. Overview of the Regulatory Baseline. Technical Basis, and Alternative Control
Levels for Nitrogen Oxides (NQJ> Emission Standards for Small Steam
Generating Units, fFinal Report!. EPA-450/3-89-13, U. S, Environmental
Protection Agency, Research Triangle Park, NC, May 1989.
5. Emissions Assessment of Conventional Stationary Combustion Systems:
Volume V. EPA-600/7-81-003C, U. S. Environmental Protection Agency,
Research Triangle Park, NC, 1981.
6. Emissions Assessment of Conventional Stationary Combustion Systems:
Volume iV. EPA-6QQ/7-81-Q03C, U. S. Environmental Protection Agency,
Research Triangle Park, NC, January 1981.
7. Evaluation and Costing of NO^ Controls for Existing Utility Boilers in the
NESCAUM Region. EPA Contract No. 68-D9-0131, WA 1-19, (Draft Report),
Acurex Environmental, Mountain View, CA, September 1991.
8. Krishnan R.E. and G.V. Helwig, Trace Emissions from Coal and Oil
Combustion". Environmental Progress. 1(4): 290-295. 1982.
9. Brooks, G.W., M.B. Stockton, K.Kuhn, and G.D. Rives, Locating and Estimating
Air Emission from Source of Polycyclic Organic Matter. EPA-450/4-84-007p,
U.S. Environmental Protection Agency, Research Triangle Park, North Carolina,
May 1988.
10. Fossil Fuel Fired Industrial Boilers - Background Information.Volume 1:
Chapters 1-9. EPA-45Q/3-82-Q06a, Office of Air Quality Planning and Standards,
U.S. EPA, Research Triangle Park, North Carolina, March 1982, and Fossil Fuel
Fired Industrial Boilers - Background Information Volume 2: Appendices. EPA-
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45-/3-82-006b, OAQPS, Research Trianle Park, North Carolina, U.S.
Environamental Protection Agency, March 1982.
11. Leavitt, C., K. Arledge, C. Shih, R. Orsini, W. Hamersma, R. Maddalone, R.
Beimer, G. Richard, M. Yamada, Environmental Assessment of Coal- and Oil-
Firing in a Controlled Industrial Boiler: Volume 1. II. 111. Comprehensive
Assessment and Appendices. EPA-600/7-78-164abc, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina, August 1978.
12. Ackerman, D.G., M. T. Haro, G. Richard, A.M. Takata, PJ. Weller, D.J. Bean,
W,B. Cornaby, G.J. Mihlan, and S.E. Rogers, Health Impacts. Emissions, and
Emission Factors for Noncrteria Pollutants Subject to De Minimis Guidelines
and Emitted from Stationary Conventional Combustion Processes. EPA-450/2-
80-074, U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina, June 1980.
13. Shih, C., R.A. Orsini, D.G. Ackerman, R. Moreno, E.L Moon, LL Scinto, and C.
Yu. Emissions Assessment of Conventional Combustion Systems: Volume III.
External Combustion Sources for Electricity Generation. EPA-600/7-81-Q03a,
U.S. Environmental Protection Agency, Research Triangle Park, North Carolina,
November 1980.
14. Surprenant, N, R. Hall, S. Slater, T. Susa, M. Sussman, and C. Young,
Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems: Volume II -Final Report. EPA-60Q/2-76-046B, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina, March 1976.
15. Van Buren, D., and LR. Waterland, Environmental Assessment of a
Coal/Water Slurry Fired Industrial Boiler. EPA-8QO/S7-86/004, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina, May
1986.
16, Waterland, L.R., and R. DeRosier, Environmental Assessment of a Watertube
Boiler Firing a Coal/Water Slurry. EPA-6QO/S7-86/004, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina, May 1986.
17. Waterland, L.R.; R. DeRosier, H. Lips, Environmental Assessment of a
Commercial Boiler Fired with a Coal/Waste Plastic Mixture. EPA-6QQ/S7-
86/011, U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina, May 1986.
18. Johnson, N.D. and M.T. Schultz. MOE Toxic Chemical Emissions Inventory for
Ontario and Eastern North America. Draft Report. Prepared for Ontario Ministry
of the Environment, Air Resources Branch, Rexdale, Ontario, Draft Report No.
P89-50-5429/OG, March 15, 1990.
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19. U.S. Environmental Protection Agency, Regional Air Pollution Study - Point
Source Emission Inventory. EPA-600/4-77-014 (NTIS No. PB 269567), March
1977.
20. U.S. Environm ?ntal Protection Agency, Crosswalk/Air Toxic Emission Factor
Data Base Management System User's Manual. Version 1.2. EPA-450/4-91-028,
Research Triangle Park, North Carolina, October 1991.
21. U.S. Environmental Protection Agency, Locating and Estimating Air Emissions
from Sources of Chromium. EPA-450/4-84-007g, Research Triangle Park, North
Carolina, July 1984.
22. U.S. Environmental Protection Agency, Locating and Estimating Air Emissions
From Sources of Formaldehyde fRevised). EPA-450/4-91-012, Emission
Inventory Branch Technical Support Division, Research Triangle Park, North
Carolina, 1991.
23. U.S. Environmental Protection Agency, Estimating Air Toxic Emissions from
Coal and Oil Combustion Sources. EPA-450/2-89-001, Research Triangle Park,
North Carolina, April 1989.
24. Evans, J.C., K.H. Abel, K.B. Oisen, E.A. Lepel, R.W. Sanders, C.L Wilkerson,
D.J. Hayes, and N.F. Mangelson, Characterization of Trace Constituents at
Canadian Coal-Fired Plants. Phase I:. Final Report and Appendices. Report for
the Canadian Electrical Association, R&D, Montreal, Quebec, Contract Number
001G194.
25. Meij, Auteru dr. R., The Fate of Trace Elements at Coal-Fired Plants.
Rapportnummer;32561-MOC 92-3641, Rapport te bestellen bij: Bibliotheek N.V.
KEMA, February 13, 1992.
26. U.S. Environmental Protection Agency, Locating and Estimating Air Emissions
from Sources of Manganese. EPA-450/4-84-007h, Research Triangle Park,
North Carolina, September 1985
27. Lyon, W.S.; Trace Element Measurements at the Coal-Fired Steam Plant. CRC
Press, 1977.
28. U.S. Environmental Protection Agency, PM-10 Emission Factor Listing
Developed by Technology Transfer. EPA-450/4-89-022, Research Triangle Park,
North Carolina, 1989.
29. U.S. Environmental Protection Agency, Gap Filling PM-10 Emission Factors tor
Selected Open Area Dust Sources. EPA-450/88-003, Research Triangle Park,
North Carolina, 1988.
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30. U.S. Environmental Protection Agency, Generalized Particle Size Distributions
for Use In Preparing Size Specific Particulate Emission Inventories. EPA-450/4-
86-013, Research Triangle Park, North Carolina, 1986.
31. U.S. Environmental Protection Agency, Technical Procedures for Developing
AP-42 Emission Factors and Preparing AP-42 Sections - Draft. Research
Triangle Park, North Carolina, March 1992.
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4. EMISSION FACTOR DEVELOPMENT
This chapter describes the test data and methodology used to develop pollutant
emission factors for bituminous and subbituminous coal combustion.
4.1 CRITERIA POLLUTANTS
4.1.1 Review of Previous AP-42 Data
The emission factor documentation files from the prior AP-42 updates of Section
1-1 were obtained and reviewed. The criteria emission factors were developed in 1981
and documented in Reference 1. The emission factors for particle sizing and
particulate collection efficiencies by particle size were developed in 1984 in Reference
2. Initially, much of the documentation used in developing these prior emission factors
were reviewed. The references included;
« The 61 primary references cited in the 1988 Section 1.1.;
« Secondary references from background files;
• Memoranda and emission factor worksheets from the prior updates.
The references used in developing the prior emissions factors were checked in several
cases as a first-level quality check on the documentation. Table 4-1 lists several of the
cases where the reference trail was spot checked. Several anomalies regarding
reference documentation were revealed, but none which invalidated the quality of the
results. A review of the 1988 version of Section 1.1 was accomplished by spot
checking the quality of existing emission factors. This was done by selecting primary
data references from the background files, reviewing data quality sampling and
analytical procedures, determining completeness, and verifying that the site emission
factors in the background files could be reconstructed and were accurate. Examples
of spot-check data are presented in Appendix A.
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Spot checks revealed that, in general, ample A-quality rated data points were
available for the criteria pollutants or that most poor quality data had little affect on the
published AP-42 emission factors. However, questions regarding the quality of the
data used to calculate the emission factors were justified end point to a need to
properly review references, assigned data quality ratings, and calculations, when
developing improved emission factors for well-defined equipment categories.
4-1-2 Review of New Baseline Data
A total of 60 references were identified and reviewed during the literature
search. These references are listed in the checklists added to the background files for
this update to AP-42. The original group of 60 documents was reduced to a set of
rated references utilizing the criteria outlined in Chapter 3. The following is a
discussion of the data contained in each of the rated references.
Reference 3
This report covers the emissions of two hand-feed space heaters tested in
cooperation with the Vermont Agency of Environmental Conservation. Oxygen, CO2
and CO were measured by Orsat from a grab sample collected over the test duration.
SO2 and light hydrocarbons were analyzed from a grab sample in a gas
chromatograph. Particulate measurement was made from front half catch of a
Modified Method 5 (MM5) sampling train. Hazardous air pollutants (HAPs) were also
reported. No original data sheets were found. Coal analysis was reported on a dry
basis and higher heating value (HHV) was reported on dry ash free basis. Emissions
were calculated in the report (p. 15) but appear to be reported incorrectly. Particulate
emissions were recalculated using the F-factor in 40 Code of Federal Regulations
(CFR) Part 60 Appendix A, EPA Method 1i. Data were assigned a rating of C.
Reference 4
This report covers the emissions of one 40,000 Ib steam/hr (18,000 kg
steam/hr) FBC for long term performance. Data were collected to support NSPS for
small boilers. Oxygen, CO2, SO2» NOX, and CO were analyzed by certified continuous
emission monitors (CEMs). Test data for the thirty day testing period are presented in
the report in molar concentration units. Data from February 28, 1986 were averaged
to obtain NOX and CO emission factors. Sulfur dioxide emissions were controlled by
limestone addition to the FBC. No uncontrolled particulate data were found. Data
were given a quality rating of B.
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Reference 5
This is a compliance test report for PM, SO2, and NOE on a 100 MWe
tangential-fired boiler for the Nebraska Department of Environmental Control in Lincoln,
Nebraska. Particulate was sampled after an ESP and was not useful for uncontrolled
emissions. Sampling was performed by EPA Methods 6 and 7. Emissions were given
in Ib/million Btu (MMBTU). Data were given a quality rating of A.
Reference 6
This is a compliance test report for SO2 on a 145 MWe PC-fired unit
manufactured by Riley Stoker Corporation, Sampling was performed by EPA Method
6 after an ESP. Emissions were given in Ib/MMBTU. Data were given a quality rating
of A.
Reference 7
This is a test report for short-term testing on seven separate boilers with
different configurations over a five-day period. Emphasis of the report is on specific
organic compounds; however, CEMs were used to monitor O2, CO, and total
hydrocarbons (THC) during test conditions. There was Inadequate information in this
report to determine reporting units and measurement method for THC. No CEM
specifications or calibration procedures were found but method is fairly well
established. Some sampling sites were located after ESPs but this was not expected
to significantly alter CO emissions. Sulfur dioxide and NOX data were available for one
of the plants tested via plant-installed CEMs after an ESP. Data were given a quality
rating of B.
Reference 8
This is a compliance test report for the Kansas Board of Public Utilities for two
coal-fired cyclone boilers. Testing was done by EPA Method 6. Raw data were
available but titrations were not checked. Sampling was conducted at the stack after a
baghouse and ESP, respectively. A summary table listed emissions in Ib/MMBTU
based on Tabulated F-factor in 40 CFR Part 60 Appendix 19, Data were given a
quality rating of A.
Reference 9
This is a compliance test report for the Kansas Board of Public Utilities on a PC-
fired boiler. Insufficient detail for the unit was given to specify firing configuration;
however, this information is not necessary for emission factor development at this
time. Samples were taken both before and after an ESP to show removal efficiency.
Unit was operating at nominally 90 percent of nameptate rating (145 MWe). Raw data
were available. Emissions were presented in Ib/MMBTU based on an F-factor derived
from the fuel analysis. Data were given a quality rating of A.
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Reference 10
This report is an EPA/Office of Air Quality Planning and Standards
(OAQPS)/Emission Measurements Branch (EMB) document describing a test of
Tennessee Eastman's Boiler 24 in Kingsport, Tennessee, in support of the Indus trial
boiler NSPS. The tests were conducted to determine the effects of boiler load, (X and
preheat on NO emissions. Continuous monitors were used to measure NOX, Co and
O2; NO was also measured using EPA Method 7. Comparison of the two NOx
methods was acceptable and the average was used for emission factor calculation.
Five of the nine runs were conducted at acceptable boiler loads (> 70 percent). The
remaining runs at low load (approximately 55 percent) indicated a 20 percent
reduction in NOX emissions with little effect on CO levels. An A rating has been
assigned to this data.
Reference 11
This report is an EPA/OAQPS/EMB document describing a test of an industrial
boiler with stoker gas recirculation (SGR) at Upjohn Company's Kalamazoo, Ml,
facility. These tests were also in support of the industrial boiler NSPS. The effects of
boiler load, O2 and SGR on NOx emissions were measured. Continuous monitors
were used to measure NOX, CO, and O2. Nine of the ten runs were made at boiler
loads of 75 to 100 percent with O2 levels between 3.2 and 8.0 percent. These data
were used in the emission factor calculations. The remaining run at 50-percent load
showed no noted effect on NOX or CO levels. An A rating has been assigned to this
data.
Reference 12
T report is an EPA/OAQPS/EMB report describing a test of an industrial
spreader stoker at the Burlington Industries facility in Clarksville, VA. These tests were
conducted in support of the industrial boiler NSPS for PM. Nine runs were performed
at various boiler loads using a slight variation of EPA Method 5 for the particulate
measurements. The modification to the sampling method was in heating the filter box
to 160°C (320°F). In a previous report comparing results using this variation to
standard Method 5 data, this method produced particulate catches of 94 to 100
percent of Method 5 results. Five of the nine runs were used in the emission factor
calculations. Three of the remaining runs were at one-third boiler load and one run
exceeded the acceptable percent-isokinetic standard. A B rating was assigned to this
data because of the method modification and wide variation in results.
Reference 13
Contains SO* and NOX summary data for the Tennessee Valley Authority's
(TVA) bubbling becTFBC (with and without fly ash reinjection) and Batelle's circulating
bed FBC. Original test reports are referenced in the document and should be
obtained in order to upgrade quality rating. Data were assigned a quality rating of D.
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4.1.3 Compilation of Baseline Emission Factors
The references described above were used in updating the uncontrolled
(baseline) emission factors for criteria pollutants. Computerized spreadsheets were
set up to calculate new data points from the information contained in these references.
Sections of the spreadsheets, pertaining to specific pollutants are shown as Tables 4-2
through 4-8.
The new data points were combined with the 1988 AP-42 Section 1.1 data
points retained from spot checking to develop new emission factors. The various
formulae and conversion factors used in the spreadsheet programs and in the
calculation of new emission factors are shown in Appendix B.
4.1.3.1 SO2 Emission Factors. The new SO2 baseline data are summarized in
Table 4-2. The following new data points were added to the emission factor database:
» Cyclone furnace: 3 points
• Spreader stoker: 2 points
« Pulverized coal, tangential fired: 1 point
• Pulverized coal, dry bottom, wall fired: 1 point
» Handfeed: 1 point
* Bubbling bed FBC: 6 points
» Circulating bed FBC: 1 point
The spot checks revealed only minor anomalies in the 1988 AP-42 emission
factor calculations. One test report appeared to have a discrepancy in the fuel
analysis procedures. For the "ALMA" site, the facility data point was developed from
the fuel sulfur content measured on a dried and pulverized (as-fired) basis, but with
the as-received HHV. However, making this correction only changes the data point
from 33S to 33.7S, where S is the percent sulfur in the fuel. Also, for the
subbituminous coal testing at the same site, the coal sample averages did not match
the emissions average periods. Again, however, making these corrections did not
effectively change the site data point. Therefore, all previous SO2 emission factor
background data were retained in the current update effort.
For bituminous coal firing, three new data points were added for cyclone
boilers, and one data point each was added for PC wall-fired and tangential-fired
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boilers. Of the three cyclone boiler tests, data from two tests were rated E because
the calculated emission factors were above the theoretical maximum value of 40S; the
remaining cyclone boiler test produced a B-rated emission factor of 31.5S. Test data
from the two PC-fired boilers were rated A and B, The average of the emission factors
from these two tests was 38,18. These data, when combined with a 1984 review of
the 1982 emission factor development effort and data base, justify a revision of the
SOx emission factor from 39S to 38S for PC-fired, cyclone, spreader stoker, and
overfeed stoker boilers.
One new data point from Reference 1 was obtained for a small 2.9 KW (10,000
Btu/hr) hand-fired unit. However, this data point was assigned a C rating and, at a
value of 52.4S, was significantly different from the existing average emission factor of
31S for underfeed and hand-fired units. Therefore, the existing AP-42 emission factor
was retained.
No new data for subbltuminous coal firing were identified during this update.
Therefore, the existing emission factor of 35S for PC, cyclone, and spreader and
overfeed stokers was retained.
New emission factors were developed for FBCs which have been included in
this update of AP-42 as a new source category. As discussed in Chapter 2, a
correlation was developed with the coal sulfur content and the calcium-to-sulfur ratio in
the bed. The data obtained from the FBC test reports are plotted against calcium-to-
sulfur ratio (Ca/S) in Figure 4-1.
Four data points were obtained from Reference 4 showing the effect of available
Ca/S ratio on SO2 emissions. Reference 4 data were given an A rating. The FBC in
Reference 4 is a bubbling bed FBC incorporating reinjection of fly ash captured in the
first stage cyclone. Fly ash reinjection results increase in higher calcium utilization and
lower SO2 emissions.
Reference 13 presented summary data from both bubbling and circulating bed
FBCs. These data were given D ratings because the report lacked sufficient
background data to fully evaluate the source operation and test methodology.
However, when plotted on Figure 4-1, the data point from the bubbling bed unit with
fly ash reinjection matched the data from the similar FBC in Reference 2. Because of
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the limited number of FBC test data reports which were obtained for this update of AP-
42, all these data points were used in developing the SO2 emission factor correlation.
The date from the bubbling bed unit without fly ash reinjection do not match the
rejection data and therefore were not considered in the correlation. Also, the data
point from the circulating bed FBC plotted on Figure 4-1 follows the same trend as the
bubbling bed units with fly ash reinjection. This behavior is not surprising because
circulating bed units are essentially an extension of bubbling bed technology but with
higher fluidizing velocities and a high ratio of fly ash reinjection,
AH data shown in Figure 4-1 from the bubbling bed units with fly ash reinjection
and the circulating bed unit were curve-fit to develop a correlation for the emission
factor. The best-fit equation reflecting the SO2 emissions performance of FBCs was;
Ib SO, f Ca"19
2 = 39.6(51° '
ton coal
where S is the weight percent sulfur in the coal and Ca/S is the molar calcium-to-
sulfur ratio in the bed. This correlation was used for the SO2 emission factor for both
bubbling bed and circulating bed FBCs. An emission factor quality rating of D was
given for bubbling bed units because of the limited number of facilities used to obtain
the test data. An emission factor quality rating of E was given to the circulating bed
units.
When no calcium-based sorbents are used and the bed material is inert with
respect to sulfur capture, the emission factor for underfeed stokers should be used to
estimate FBC SOa emissions. In this case, the emission factor quality ratings should
be E for both bubbling and circulating bed units.
4.1.3.2 NO Emission Factors. The new NO baseline data are summarized in
>* X
Table 4-3. The following new data points were added to the emission factor database:
» Cyclone furnace: 1 point
« Spreader stoker: 2 points
* Pulverized coal, tangential fired: 1 point
» Handfed: 1 point
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• Bubbling bed FBC: 1 point
« Circulating bed FBC: 1 point
One new data ooint was averaged with prior data to calculate a new emission
factor for cyclone boilers. Although the data point value of 7.52 kg/Mg (15.04 Ib/ton)
was considerably below the previous AP-42 emission factor of 18.2 kg/Mg (36,4
Ib/ton), it appears to be of at least equal quality to the previous background data.
The new emission factor of 16.9 kg/Mg (33.8 Ib/tony-was calculated by averaging the
new data with the old data, all of which have a B quality rating. The emission factor
rating of C was retained to indicate that a reasonable set of data points were used to
develop the emission factor; however, it is not clear that the facilities tested represent
a random sample of the population.
Data from References 10 and 11 were averaged with the prior data for spreader
stokers. The resulting change in emission factor was minor. The existing value of 7
kg/Mg (14 Ib/ton) was changed to 6.9 kg/Mg (13.7 Ib/ton). The emission factor
rating of A was retained.
One data point for a tangential-fired boiler was obtained from Reference 5. At
3.5 kg/Mg (6.9 Ib/ton), this data point was somewhat below the 1988 AP-42 emission
factor of 7.5 kg/Mg (15 Ib/ton); however, it was rated as A quality because Reference
5 is a well-documented and complete compliance test report. A new emission factor
of 7.2 kg/Mg 14.4 Ib/ton) was developed by averaging the new data point with the
old A-rated data. The emission factor rating of A was retained.
Two data points were obtained for bubbling bed FBCs. The FBC boiler in
Reference 4 is a bubbling bed unit installed in Prince Edward Island, Canada. The
data quality rating given to the Reference 4 data point was A because it is a complete
and well-documented emission assessment report. Because the FBC unit in
Reference 13 is the TVA 20 MWe demonstration unit, it may be more representative of
NOx emissions from new bubbling bed units designed to meet the Federal New
Source Performance Standards. However, the data quality assigned to Reference 13
was D because of the lack of supporting information in the test report. Therefore, only
the A-rated data from Reference 4 were used for the bubbling bed FBC emission
factor. The emission factor is 7.6 kg/Mg (15.2 Ib/ton) and has been given an
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emission factor quality rating of D because the data have been obtained from only one
facility.
One data point was obtained for a circulating fluidized bed boiler from
Reference 13. Because the data quality rating is D from this standard reference, an
emission factor rating of E has been assigned to this source category.
One data point was obtained from a small, hand-fed domestic furnace in
Reference 3. To determine if this data point should be combined with the existing data
used in the 1988 AP-42 emission factor, a detailed spot check was performed. The
emission factor could be reproduced from the data contained in the reference;
however, with no supporting sampling discussion or data documentation, the data
quality for the existing data point would warrant a C or D rating. Therefore, the new
emission factor was developed by averaging the two data points [i.e., 7.6 kg/Mg (15.2
Ib/ton) from Reference 1 and 1.5 kg/Mg (3 Ib/ton) from the single data point in the
1988 AP-42 emission factor] to obtain a value of 4.55 kg/Mg (9.1 Ib/ton). An
emission factor quality rating of E was assigned for this source category.
No additional data points were obtained for overfeed and underfeed stokers nor
for wet bottom wall-fired pulverized coal units. Therefore, the 1988 AP-42 emission
factors were retained for these sources categories. The emission factor ratings of A
were retained for the overfeed and underfeed stokers based on the quality of the
original references.
Based on the existing AP-42 emission factor spot checks discussed in Section
4.1.1, two data points were removed from the emission factor calculation for wall-fired
pulverized coal, drv bottom boilers. This resulted in a change in the emission factor
from 10.5 kg/Mg (21 Ib/ton) to 10.9 kg/Mg (21.7 Ib/ton). The emission factor quality
rating of A was retained based on the quality of the remaining references.
4.1.3.3 CO Emission Factors
PC Boilers. Four new data points were obtained as shown in Table 4-4. The
two wall-fired data points were lower than the 1988 emission factor of 0.3 kg/Mg (0.6
Ib/ton), but the individual runs were consistent at each site. The vertical V-fired data
point of 0.76 kg/Mg (1.52 Ib/ton) was obtained from the average of individual runs
that varied from 0.16 kg/Mg (0.37 Ib/ton) to 1.85 kg/Mg (2.71 Ib/ton). This point was
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not used because of Its variability and the fact that the resulting number was far
outside of the previous data grouping. The tangentially-fired (T-fired) data point of
0.05 kg/Mg (0.10 Ib/ton), although unusually low, appears to be high quality data.
Two lew cyclone boiler points were also found and added to the baseline database.
Both were lower than the computed emission factor but were considered reliable data.
A new average emission factor of 0.25 kg/Mg (0.52 Ib/ton) was computed. This
compares to the previously-computed factor of 0.29 kg/Mg (0.58 Ib/ton). The current
emission factor has been changed from 0.3 kg/Mg (0.6 Ib/ton) to 0.25 kg/Mg (0.5
Ib/ton).
The new T-fired data point was considered as a candidate tor a new, separate
T-fired emission factor. After it was averaged with the existing T-fired data, however, a
new emission factor was not warranted.
Spreader Stoker. Two new data points were added to the existing 22 data
points [i.e., 0.8 kg/Mg (1.60 Ib/ton and 0.46 kg/Mg (0.92 Ib/ton)]. Both were
considerably below the average emission factor of 0.29 kg/Mg (0.58 Ib/ton). A new
average emission factor of 2.46 kg/Mg (4.92 Ib/ton) was computed. It is
recommended to retain the existing factor of 2.5 kg/Mg (5 Ib/ton).
Overfeed and Underfeed Stoker. No new data were found. It is recommended
to retain the current value.
Hand-fed Units. Two new data points were obtained. The data were assessed
to be of C quality. A spot check of Reference 15 revealed that the prior data should
be discarded in light of the new data. It is recommended to change the emission
factor to 215 kg/Mg (430 Ib/ton), which is a simple average of the two new data
points.
Fluidized Bed Combustors. A new data point was obtained and is shown in
Table 4-4. An emission factor of 9 kg/Mg (18 Ib/ton) is recommended for both
bubbling bed and circulating FBCs.
4.1.3.4 Paniculate Emission Factors
PC-fired. Dry Bottom. Wall Fired. A spot check revealed one data point of low
quality. This value was removed from the emission factor data base. Because of the
large number of data points and the proximity of the rejected point to the average
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value, this process had little effect on the new average emission factor. A new data
point shown in Table 4-5 was added to the data base. Although the new value was
9.16 kg/Mg (18.31 Ib/ton), its addition to the data base did not cause the average
emission factor to increase beyond 5.22 kg/Mg (10.44 Ib/ton).
PC-fired. Pry Bottom. Tangentially Fired. Existing data were reviewed and an
average emission factor was computed. The average value of four data points
generated by EPA Method 5 measurements was 5.2 kg/Mg (10.3 Ib/ton). An
emission factor of 5 kg/Mg (10 Ib/ton) is recommended. Because only four data
points were used, a quality rating of B was assigned.
PC-fired. Wet Bottom. The existing data were reviewed. Because only one
data point was used (the only one found using EPA Method 5), the quality rating was
confirmed to be D.
Cyclone Furnace. The existing data were reviewed. Because only one data
point was available and it was not obtained by an EPA-appraved method, the quality
rating was downgraded to E.
Spreader Stoker. Based on the findings of the spot checks, the data point
based on Reference 16 was discarded from the new emission factor calculation. The
remaining seven data points were averaged with the one new data point obtained from
Reference 12 to give a new emission factor of 33 kg/Mg (66.0 Ib/ton), The B
emission factor quality rating was retained.
Spreader Stoker with Multiclones and Reinfection. Six data points were used
and all were based on EPA Method 5 measurements.
Spreader Stoker with Multiclones and No Reinjection. Twelve data points were
used and all were based on EPA Method 5 measurements. The A quality rating
appears to be warranted since these data are from many diverse facilities. This is also
an extremely specific source category and the data did not have a high degree of
variability.
Overfed Stoker. Eight data points were used and all were based on EPA
Method 5 measurements. Considerable data scatter indicates C quality data.
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Overfed Stoker, with Multiple Cyclones. All five data points were obtained using
EPA Method 5 measurements. Reasonable data consistency warrants a B quality
rating.
Underfed Stoker. Auhough nine EPA Method 5 data points were used,
considerable variability exits. A quality rating of C is recommended.
Underfed Stoker with Multiple Cyclone. A quality rating of D is recommended
because, although the data are consistent, only two data points are available,
Hand-fed Units. Data were reviewed from the two sources (References 17 and
15). Data from Reference 17 were discounted because the unit was from an open
fireplace. Data from Reference 15 were secondary data. Two new data points were
added, taken from Table 4-5. Because the two new data points have an average
emission factor of approximately 7.5 kg/Mg (15 Ib/ton), it is recommended that the
emission factor remain unchanged.
Fluidized Bed Combustor. Bubbling Bed. No baseline particulate data, either
old or new, were available. It is estimated that PM emissions would most closely
match those of a spreader stoker with multiple cyclones and no flyash reinjection. The
corresponding PM emission factor of 6 kg/Mg (12 Ib/ton) is recommended for use.
This assumption warrants the lowest quality rating of E.
Fluidized Bed Combustor. Circulating Bed. No data, either old or new, were
available. It was estimated that PM emissions would most closely match those of a
spreader stoker with multiple cyclones and no fly ash reinjection. Its PM emission
factor of 6 kg/Mg (12 Ib/ton) is recommended for use. This assumption warrants the
lowest quality rating of E.
4.1.3.5 Methane Emission Factors. Reference 15 was spot checked, and it
was found that methane (CH^ emission factors could be computed for individual
boiler types. The existing data were grouped into their appropriate boiler types and
new individual emission factors were calculated. Although the same data were used,
the emission factor data quality was downgraded to B since each boiler type had only
three to five data points.
4-12
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The only new data obtained were for hand-fed boilers. The spot checks of prior
data showed these data to be outdated and unusable. A new emission factor was
calculated based on two new data points as shown in Table 4-6.
No CH4 data were available for FBCs. Possibilities of using data from
comparable combustion devices were explored. No suitable estimation procedure was
identified.
4.1.3.6 Non-CH4 Emission Factors. As with CH4, Reference 15 revealed
individual emission data for each boiler type. The existing data were grouped into
boiler categories and new individual emission factors were calculated. Although the
same data were used, the emission factor data were downgraded to B since each
boiler type had only three to five data points.
No new data were found for hand-fed units. Spot checks revealed previous
data to be outdated and unusable. Because no other data were available, the existing
emission factor was retained in this update. Its quality rating was downgraded to E.
4.1.4 Compilation of Controlled Emission Factors
A compilation of controlled emissions and control efficiencies achieved through
application of some of the control technologies discussed in Section 2.4 is given in
Tables 4-7 through 4-9.
4.2 SPECIATED VOCs
The VOC speciation data base was very sparse, as described in Section 3.2.
The data evaluation was limited to the single report referenced in the database. The
report contained only two references for VOC speciation data; only one of these
references documented the protocols used for collecting and analyzing the samples.
In the one case, samples were collected with Tedlar bags using a vacuum pump. Gas
chromatography was the analysis technique. There were no data sheets, calibration
procedures or quality control (QC) methods mentioned and no source operating
conditions listed. Without these details, the data were considered "unratable," and not
suitable for use in developing emission factors.
In the absence of developed emission factors for VOC speciation, the
SPECIATE and XATEF databases for speciated VOCs can be consulted for qualitative
guidance.
4-13
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4.3 AIR TOXICS
4-3.1 Review of New Data
The data search summarized in Section 3.3 identified several key documents
with primary test date or data compilations for air toxics emissions. The evaluation of
several of the key references follows:
^Reference 24
This article summarizes the emissions of certain trace metals and hazardous
pollutants from bituminous coal combustion. The data presented are a summary of a
literature review. Emission factors are presented in the units of mass emitted per heat
input quantity combusted and are presented for boilers of different sizes and
configurations. The article references several primary references which were evaluated
but determined to be of insufficient quality.
Reference 25
This document is a compilation of the available information on sources and
emission of POM and is not a primary reference. The document cautions the use of
these data for development of an exact assessment of emissions from any particular
facility, however, the data are useful for providing rough estimates of POM emissions
from boilers firing bituminous coal. The emission factors provided are for controlled
devices. Data for utility boilers are used in this update because this is the largest and
most complete data set for coal combustion.
Reference 26
The data quality in this report is of unacceptable quality to generate enrichment
ratios for metals or emission factors for metals, organics, and POM.
Metals: Metals samples were not taken after the boiler and before
the mufticyclones so enrichment factors for the pieces of
equipment could not be calculated. The multicyclones
malfunctioned during the coal test rendering the metals data
of questionable quality.
Organics: It was stated in the report (on page 6-28) that the organics
recovered were not combustion products but were
components in the sample collection media and in the
analytical lab.
POM: POM data were below detection limit. The malfunctioning multicyclones
would also impact the quality of these data.
4-14
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Reference 29
The data quality and documentation in this report are of unacceptable quality to
generate emission factors.
Metals: Level I sampling and analysis program which is semiquantiative (a factor
of jt 3) data quality. A source assessment sampling system (SASS) train
and spark source mass spectroscopy (SSMS) analyses were used.
These data are not suited for calculation of enrichment factors or mass
balances as stated in the source on page 269.
POM: The sampling and analytical procedures are also of lower quality [i.e.,
SASS and gas chromatography/mass spectrometry (GC/MS)].
The documentation for the analytical results is not clear as to why only
portions of the samples were analyzed; therefore, one cannot determine
if the entire sample is being accounted for.
Reference 28
The purpose of this document is to provide a preliminary emission assessment
of conventional stationary combustion sources. The data presented deals with
national averages or ranges based on the best available information. Emission factors
in mass emitted per heat unit input are not provided.
Reference 29
The emission factors for oil combustion that were summarized in this document
came from Reference 29. These data were eliminated from use in this update due to
their poor quality.
Reference 30
This report summarizes testing performed on several sizes and types of boilers;
however, only criteria pollutant testing was performed.
J Reference 31
Measured and calculated emission factors for bituminous coal are presented in
this document. The emission factors are rated as low quality because the document
is nota^primary source and the quality of the data cannot be verified.
Reference 32"
~___x-
This document presents a summary of emission factors for different types of
processes which emit formaldehyde. The emission factors are presented in mass per
unit heat input. A factor is provided for coal-fired sources; however, the factors are
4-15
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based on one or two tests. Also, the type of coal is not specified. The emission
factor is therefore assigned a low rating and represents an approximate emission
estimate.
Reference 33
This document provides a summary of the emissions factors for metals, POM,
and formaldehyde for bituminous coal-fired boilers. Control efficiencies are reported
for some control devices. No data are reported for uncontrolled emissions of POM
and radionuclides. The formaldehyde data are from 1964 and are considered to be of
unacceptable quality. The emission factors are based on source test data from coal-
fired utility and industrial boilers. Data for different boiler configurations are presented
in the units of mass emitted per unit of fuel input.
This reference is not a primary source. The document cautions that relatively
limited data are available on toxic air pollutants resulting from these types of processes
and that emissions data in the document should not be used to develop an exact
assessment of emissions from any particular facility. Emission factors for the
processes outlined in the document are summarized and provided for use in
determining order-of-magnitude emissions. The emission factors are rated low quality
because the data acquisition and manipulation could not be verified.
Reference 34
The data quality and documentation in this report are of high enough quality to
develop enrichment ratios for metals and radionuclides on boilers and their associated
abatement devices. Emission factors expressed as mass emitted per unit heat
combusted are calculated for PAH compounds.
Reference 35
This report summarizes the current research effort in the Netherlands to
determine the fate of trace elements at coal-fired power plants. A total of sixteen test
and mass balance programs were undertaken to determine enrichment ratios for
boilers and high-efficiency cold-side ESPs. Enrichment ratios for boilers are presented
by classes of metals. Enrichment ratios for the ESPs are also presented. The data
are of sufficient quality for use in this update.
Reference 36
This document presents emission factors for sources of chromium. A literature
survey was used to compile emission estimates from bituminous coal-fired boilers.
The emission data for utility boilers is used to generate the emission factor.
The data from these references were reviewed and ranked according to the
quality criteria discussed in Section 3.
4-16
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4.3.2 Baseline Emission Factors
Emission factors for metals, radionuclides, and other HAPs are quite often
presented in units of mass emitted per heat input combusted. These units are
adequate for developing emission factors for organic HAPs but are not desirable for
developing factors for metals and radionuclides. Ideally, emission factors for trace
elements should be developed as a function of the boiler firing configuration, boiler
size, trace element content of the fuel, ash content, higher heating value, enrichment
ratio (see discussion below), and the collection efficiency of the control device.
The concepts of partitioning and enrichment are needed to describe the fate of
trace metals within the boiler and collection devices. The concept of partitioning is
used to describe the distribution of trace elements among the boiler system outlet
streams. These streams may include the bottom ash collector hoppers,
boiler/economizer/preheater hoppers, and flue gas. Enrichment refers to the
preferential migration of specific trace metals to a process stream or to a specific
particle size range, especially the respirable range and below. The process of
enrichment typically involves a control device, where collection efficiency varies by
particle size range. When metals are distributed unequally across size ranges, the
collection device will then yield disproportionate partitioning from the size enrichment.
The physical and chemical properties of a trace metal governs how that rnetal will be
distributed in the outlet streams. For example, mercury is a highly volatile metal and
therefore, the majority of the mass of mercury in the coal tends to be emitted from the
boiler in the flue gas and not in the bottom ash or in the fly ash.
A method for describing partitioning behavior is to report the fraction of the total
elemental mass input that has exited the boiler in an outlet stream. Another method
for quantifying the distribution of a metal is to calculate an enrichment ratio by
comparing the trace element concentration of an outlet stream to the trace element
concentration in the inlet coal stream. The enrichment ratio calculation that is outlined
in Reference 33 is performed using the following equation:
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where: ER(, = enrichment ratio for element i in stream j
Cr - concentration of element i in stream j
C^ = concentration of reference element R in stream j
C|q - concentration of element i in coal
Cpp = concentration of reference element R in coal
Enrichment ratios greater than 1 indicate that an element is enriched in a given
stream, e.g. stream j, or that it partitions to a given stream. The reference element is
used because its partitioning and enrichment behavior is often comparable to that for
the total ash. In other words, the reference element partitions with consistent
concentrations in all ash streams and normalizes the calculation. Typical reference
elements are aluminum, iron, scandium, and titanium. The enrichment behavior of
elements is relatively consistent in different types of boilers and can be explained by a
volatilization-condensation or adsorption mechanisms. A summary of the enrichment
behavior for air toxic metals and the reference metals is presented in Table 4-10.
Table 4-11 presents a summary of enrichment behaviors including approximate
enrichment ratios for particular classes of compounds.
The enrichment ratio can be used in conjunction with additional data from a
specific facility to estimate emissions of trace elements. The equation outlined in
Reference 35 is used to calculate the emission factor for a trace element as follows:
EF = (C/H)*F*(1-E)*ER*103
where; EF = emission factor for a specific trace element, ng/J
C = concentration of element in coal, j/g/g
H = higher heating value of coal, kJ/kg
F = fraction of coal ash as fly ash
E = fractional particulate collection efficiency of control device
(zero for uncontrolled emissions)
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ER = enrichment factor for the trace element (ratio of concentration of
element in emitted fly ash to concentration of element in coal
ash, often based on aluminum).
In many cases, the source test programs did not include key parameters such
as: ultimate and trace element analyses of coal used for the test, measurements of
the boiler effluent for metals and ash, and measurements of metals and ash after the
collection device. This made ft impossible to calculate partitioning of metals within the
bottom and fly ash. When supporting documentation to develop enrichment ratios
were not available, emission factors in the units of mass emitted per unit thermal heat
input were provided. Although this is not the optimal method of estimating emissions,
it provides a means of performing approximate emission estimation.
Table 4-12 summarizes the enrichment ratios for metals and radionuclides for
various uncontrolled boilers and for a high efficiency cold-side ESP. The enrichment
ratios presented are the ranges for the references obtained. The quality of these
enrichment ratios is low (E quality) because of the small number of boilers tested and
limited control data used to perform the calculations. Enrichment ratio data are a
significant data gap in the air toxic data bases.
Table 4-13 and 4-14 present summaries of emission factors in the units of mass
emitted per unit thermal heat input combusted for uncontrolled boilers. Data are
presented for metals, POM, and formaldehyde. The tables are presented in English
units and metric units, respectively. The quality rating of these data are low because
many of the sources of information are of low quality and the number of data points
are too small to represent an entire source category. Limited data are available on
organic air toxic compounds but could not be obtained for this update. The rnetals
data were most abundant and the data for formaldehyde were very limited. The POM
data were also fairly limited. When received, these data will be added to the AP-42
Section 1.1 Background File for consideration in the next update of this section.
4.3.3 Controlled Emission Factors
Table 4-15 and 4-16 present the summary of emission factors for various
controlled emissions in the units of mass emitted per unit thermal heat input. The data
obtained in the literature review were very limited. The quality rating of these data are
low because many of the sources of information are of low quality and the number of
4-19
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data points are too small to represent an entire source category. Table 4-17
summarizes control efficiencies for various parameters of several control devices.
4.4 N2O
A total of 43 references were documented and reviewed during the literature
search. These references are listed at the end of this chapter.
The original group of 43 documents was reduced to a final set of primary
references using the criteria outlined in Chapter 3. Many of the references were based
on the pre-1988 protocol which resulted in unrelaible N£O measurements because of
reactions in sample containers. For the 40 references documents not used, the
reason(s) for rejection are summarized below (the reference number corresponds to
the reference list at the end of this chapter):
Reference Reason for rejection
39 Data were pre-1988
40 Data were pre-1988
41 Pilot-scale boiler
42 Duplicate of test in Reference 2
43 No NO data
44 Only information on N2O emissions from global sources
45 Data were pre-1988
46 Data were pre-1988
47 Test data taken from an airplane
48 Duplicate of test in Reference 12
49 Duplicate of test in Reference 2
50 Insufficient lab, process, analytical data
51 Chemical kinetics calculation
52 Insufficient lab, process, analytical data
53 No N2O data
54 No N2O data
55 Insufficient lab, process, analytical data
56 No N2O data
57 Duplicate of test in Reference 2
58 Insufficient lab, process, analytical data
59 Insufficient lab, process, analytical data
60 Insufficient lab, process, analytical data
61 No N2O data
62 Data were pre-1988
63 Data were pre-1988
64 Data were pre-1988
65 Data were pre-1988
66 Data were pre-1988
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67 Solid waste co-fired in boiler
68 Data were pre-1988
69 Data were pre-1988
70 Data were pre-1988
71 Data were pre-1988
72 Not cltable as a primary reference
73 Not eitable as a primary reference
74 Pilot-scale boiler
75 Pilot-scale boiler
76 Pilot-scale boiler
77 Pilot-scale boiler
This screening resulted in the selection of three references which could be used
to develop N2O emission factors. The following paragraphs discuss the data
contained in each of the primary references used to develop emission factors.
Emission factor calculations were made in terms of mass of pollutant per unit mass of
coal feed. It should be noted that the terms "controlled" and "uncontrolled" in this
discussion are indicative only of the location at which the measurements were made
[i.e., after or before control device(s), respectively].
Reference 78
This reference contained N2O emissions data from eight full-scale tests. All test
reports were rejected except for the test report from the Italian power plant. The
Italian power plant had two sources. One source combusted fuel oil while the other
source combusted bituminous coal. The data from both the boilers were acceptable;
only the coal data were used for the update of AP-42 Section 1.1.
In the Italian test report, a B quality rating was assigned to the data from both
sources. The report provided adequate detail for validation and the sampling and
analysis methodology appeared sound,
Reference 79
This reference contained data from N2O emissions tests conducted at six
boilers. Data were used from four of the sources, because the other two boilers were
operated below 70 percent of full load (although the data were comparable). The
acceptable N2O emissions data correspond to coal boiler test conducted with on-line
GC. The tests were conducted after the economizer and flue gas cleaning.
An A quality rating would have been applied to the data except that the
calibration data showed excessively high values; therefore a B quality rating was
assigned.
4-21
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Reference 80
This reference contained data for N?O emissions from FBCs, The data are in
graphical form and presented in units of milligrams per megajoule. The conversion
from milligram per megajoule to ppm is one milligram per megajoule equals 1.7 ppm.
The test was performed on a circulating fluidized bed boiler controlled by recirculation
of flue gases. The reference case is defined by a bed temperature of 850 °C (1,560
°F), a primary air stoichiometry of 0.75 and excess air ratio of 1.2. The actual emission
values can only be estimated from the graphs and, therefore, the data were assigned
a rating of D,
The new N2O emissions data are presented in Table 4-18 and a summary of the
emission factor results are shown in Table 4-19,
4.5 PARTICLE SIZE DISTRIBUTION
For the current revision, the scope of AP-42 was extended to include
segregation of filterable and condensible PM-10 emission factors along with the
particle size distribution data. The prior AP-42 updates include detailed analysis of
paniculate size distribution data.
4.5.1 Review of 1986 AP-42 Data
The 1986 database2 was evaluated with respect to sources of data, data
analyses, and calculations. Data retrieved and analyzed for that update were all
filterable particulate.
Table 4-20 lists the sets of A and B rated data that the 1986 AP-42 emission
factors update used. This table shows where high-quality data are lacking. The Fine
Particulate Emission Inventory System (FPEIS) data base was the primary source of
emissions data for the 1986 update. In some instances, the data were given a low
rating because of insufficient data in the FPEIS printouts. During the literature search,
original documents with primary test data were uncovered that corresponded to the
FPEIS documents.
The original test document for the FPEIS Test Series Number 35 in the 1986
background document is EPA-6QO/2-75-Q13-a (Reference 81). The tests were
conducted on a bituminous-coal-fired spreader stoker to determine the fractional
efficiency of the boiler baghouse. Inlet and outlet data are provided for 22 tests. All
22 data sets were used for the particle size distribution for baghouse controlled
spreader stokers and 21 of the 22 data sets were used in the preparation of the size
4-22
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distribution data for uncontrolled spreader stoker boilers. The data were B-rated in the
1986 update because the system operating conditions and sampling flowrate isokinetic
results were unknown. Review of the report did not uncover isokinetic results;
however, there was considerable discussion of the baghouse operating conditions.
Eleven of the 22 tests were conducted under normal baghouse operating conditions
while the remaining tests were conducted under experimental conditions. The range
of conditions may explain the large variation in the controlled emissions results. For
instance, the cumulative mass less than 10 microns ranged from 16 percent to 96
percent. However, little difference was found overall by comparing the average
distribution of the "normal" runs with the average distribution of all 22 runs. Because
of this finding, it was concluded that the data need not be changed and are indeed
representative of baghouse emission distributions. The values in the 1986 background
document were also spot-checked against the numbers in the plots of the original test
report. The numbers compared favorably.
4.5.2 Review of New Data
A search for additional data was conducted. Of primary interest was CPM data
collected via EPA Method 202 because this particulate fraction has not been
addressed in previous AP-42 updates. Unfortunately, only methods development
source test data were found because this is still a relatively new protocol.
Although a variety of sources were contacted regarding particulate sizing and
PM-10 data, very little additional data were located. State and district offices that were
contacted either had no PM-10 data available or were unable to process such a
request due to other staff commitments. Several groups within the California Air
Resources Board were contacted because California considers condensible particulate
as a portion of total particulate; however, no data were received.
The New Jersey Air Pollution Control Office likely has particulate sizing data for
coal emissions. Their policy is to conduct data searches only when a written request
is submitted which includes lists of specific facilities. Because specific facility lists
were unavailable, this avenue was not pursued.
One test report was obtained that contained CPM emission data for coal-fired
boilers. The tests were conducted by EPA/OAQPS/EMB. The test objectives were to
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determine the adequacy of and produce documentation to support Draft Method 202;
revise the candidate method based on results of laboratory experiments; validate the
method in field tests; and revise the method, if necessary.
It #as not possible to prepare emission factors from the results. "Hie data wer
presented as mg emitted/m and no data were presented regarding the volumetric flue
gas flow rate or the size of the boiler. F-factors are provided in 40 CFR Part 60.45 to
convert emissions into mass emitted per unit heat input. However, to use an F-factor,
one must first be able to correct the flue gas volume to zero percent O2. No data
were available regarding the percent O2 in the flue gas flow; therefore the calculation
was not conducted.
Emission factors from these tests would not be reliable because the sampling
was single-point sampling rather than a duct traverse (since the objective was to
examine the test method rather than to obtain representative data). Therefore, any
emission factors derived from this data would be of D-rating. However, inferences
may be drawn regarding the relative size of the organic and inorganic fractions of the
CPM. These results are presented in Table 4-21. The results indicate that CPM
originating from coal-fired boilers are at least 90 percent inorganic matter.
An EPRI report84 describes tests of a 22 MW Babcock and Wilcox front wall
fired boiler fueled on low-sutfur bituminous coal. The particulate sizing data were
collected with a cascade impactor upstream of the fabric filter control system. The
results are presented in Table 4-22. Total particulate was measured both upstream
and downstream of the fabric filter via EPA Method 5. The overall baghouse efficiency
was 99.8 percent. Because sufficient raw data were not provided in the report, the
data were rated B quality. Because sufficient A quality data exist for pulverized coal-
fired boilers in the 1988 version of AP-42, it was not necessary to incorporate these
new data.
For atmospheric fluidized bed boilers, two sets of data are available for the
filterable particulate emissions. A pilot AFBC unit was tested while firing both
subbituminous coal and lignite. The purpose of these tests was to investigate the
corrosive and/or erosive properties of low-rank coal ash on heat transfer surfaces.
4-24
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As part of the test, the PM exiting a multicyclone system was measured for
particule size distribution, A flow sensor multicyclone and laser aerodynamic particle
sizer (APS) provided particle size distribution data at the inlet to the scrubber (after the
multiclone controls). The APS is a real-time particle sizer that measures sizes in the
range of 0.5 to 15 microns.
The data are rated as D quality due to the pilot-scale size, the paniculate
collection methods, and lack of sufficient background data on protocols and unit
operation. For these tests, the cumulative percent mass collection values were
inferred via interpolation of log-log graphs of the results. The paniculate size
distribution data are shown on Table 4-23.
A paper presented at the 51st American Power Conference describes
particulate size distribution data from a coal-fired pressurized fluidized bed combustion
(PFBC) unit, before and after high-pressure, high-temperature emission control
eye
devices. As PFBC is not a common coal-combustion device at this time, these data
were not evaluated.
4.6.3 Compilation of Uncontrolled Emission Factors
The 1988 update was reviewed with respect to the procedure used to develop
emission factors from the particle size distribution data. The uncontrolled emission
factors were calculated for each size fraction by multiplying the total particulate
emission factor by the cumulative percent mass for the given size interval. Therefore
all uncontrolled emission factors will change as a result of updating the total PM
emission factors.
It is apparent that the level of uncertainty increases as one moves from the
cumulative percent mass to the uncontrolled emission factors. The uncontrolled
emission factors are functions of two numbers estimated generally from different sets
of data: the cumulative percent mass, and the total PM emission factor.
The filterable PM-10 emission factors are included in the particulate size
distribution tables. There is currently no need to prepare tables devoted only to PM-
10. As CPM data become available, a new table should be added to each AP-42
section. The table should include columns for filterable PM-10, inorganic CPM, and
organic CPM.
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4.6.4 Control Technology Emission Factors
There were two calculation steps used in the development of controlled
emission factors in the 1986 paniculate sizing update.2 First, a controlled emission
factor was developed tar total particulate by multiplying the uncontrolled total
paniculate emission factor from the criteria pollutant table by one of the following
estimated control efficiency factors:
» Multiple cyclone - 80 percent,
• Baghouse - 99.8 percent,
» ESP - 99.2 percent, and
» Scrubber - 94 percent.
Next, a controlled emission factor was developed for each of the cumulative size
ranges by multiplying the controlled emission factor for total particulate by the
cumulative percent mass for the size range. Thus the quality of the right-hand side of
each size distribution table in Section 1.1 of AP-42 is directly related to the quality of
three other numbers: (1) the control efficiency factors, (2) the total particulate emission
factor (from the criteria pollutant table), and (3) the cumulative percent mass data.
This, in part, explains the low data rating generally listed in AP-42 for the controlled
particle-specific emission factors.
The disadvantage of this procedure is the loss of emission factor quality. The
advantage of the procedure is that it allows the determination of control device-specific
controlled emission factors rather than using generalized control efficiency results.
Control device-specific controlled emission factors are better than generalized control
efficiencies results because control efficiency is dependent on particulate parameters,
such as the resistivity, and not just the particle size distribution.
It is useful to note that the procedure does not assume a single control
efficiency for each particle size. Rather, it assumes a single overall efficiency and
applies this to the total particulate emission factor. The size-based emission factors
depend on the total controlled emission factor and the percent of the total controlled
mass within a particular size range. For example, collected data indicated that 71
percent of controlled PM from a wet scrubber is less than or equal to 10 microns.
Based on this value; on an uncontrolled emission factor of 5A kg/Mg; and on an
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estimated scrubber control efficiency of 94 percent, the controlled PM-10 emission
factor is calculated as 0.21 kg/Mg:
0.71 x 5A x (1.0-0.94) = 0.21 kg/Mg.
Although different methods could be used to develop controlled emission
estimates, the procedure used in the 1986 document is a logical way to compensate
for sparse data. The process appears to create conservatively high values for the
controlled emission factors, as there are occasionally controlled emission factors in the
tables that are larger than the uncontrolled factors.
The particulate control efficiencies for the four technologies used throughout the
previous update are all reasonable and were retained in the current update.
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CO 10
i
ca
o
•
o
W 6
fi ~
CO
u_
LU 4
I"
CO
to
E o
UJ 2
D
O
reinfection
D
D
O w/o ash re injection (not fitted)
D FBC BB w/ash reinjection, Ref 2
O FBC-BB,Ref13
A FBC-C,Rel13
D
34 5 6
Calcium to Sulfur Ratio, Ca/S (mole/mole)
Rgure 4-1. FBC SO, emissions versus calcium-to-sulfur ratio.
-------
TABLE 4-1. BACKGROUND DOCUMENT CHECK
Pollutant
PM
PM
so2
so2
so2
NOx
NOx
CO
VOC
VOC
VOC
VOC
VOC
CH4
CH4
CH,
Configuration
PC dry bottom
Handfired units
Bituminous emission-based
Bituminous retention-based
Subbituminous
PC dry bottom
Handfired units
Handfired units
PC dry bottom
PC wet bottom
Cyclone, spreader stoker, overfeed stoker
Underfeed stoker
Handffred units
PC, Cyclone, Spreader Stoker, Overfeed
Stoker
Underfeed Stoker
Handfired Units
References cited in
1988 AP-42 Section 1.1
15, 16, 17, 1i, 21 EPA-650/7-80-171 (20)
9, 16, 17, 18, 19, 21, 31, 37, 39, 41, 42, 43,
46, 51,52,55
17, 18, 32, 33, 34, 35, 41, 42, 44, 45
9, 17,31,53,54
11, 14, 16, 17,21,58
58
58
Site
No,
17
49
11
15
28
17
16
Emission
factor
10A
39S
39S
35S
21
,07
.03
References spot
checked
15, 17
4i, 50
17, 18
18
17
17
50
50
58
58
58
58
58,50
58
58
58,50
A = weight percent ash In fuel
S = weight percent sulfur in fuel
-------
TABLE 4-2. NEW SCXBASELINE DATA FOR BITUMINOUS COAL
Deli
Ret. qelity
8 E
B E
B E
a E
B E
B E
7 B
T B
7 e
7 B
7 B
8 E
8 E
B E
B E
B E
B E
4 A
4 A
4 A
Boiler
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
Cyclone
FBC-tB
FBC-BB
FBC-BB
Site
KAW Ural 1
KAW Unit 1
KAW Unit 1
KAW Unit 1
KAW Unit 1
KAW Unit 1
Plent6
Ptent5
Plem B
Went 6
PfentS
Quindero f 1 '
Quinttere *1
Quindero f 1
Quindera *1
Quindero ft
Quindero f 1
Surnmeriwfe
Summemide
SunmeraMe
Run
3B
18
3A
2B
IA
2A
3
1
I
4
6
2A
2B
3A
IB
3B
IA
AVE
AVE
AVE
Fuel
HHV,
Blu*
11488
11629
11498
, .. .11684
11829
"'"
12121
12121
12121
1212*
12121
11376
11376
11387
113O9
ttW7
11309
11770
11610
meo
s,
2.68
2,63
2.88
2.68
2.83
2.68
1.81
1.81
1.81
1.81
1.B1
2,«1
2.81
1 B3
2.76
1.93
2.76
696
6.02
6,90
Opnritlon SO, Emieeione, FBC central efficiency
lota Feetor Ce/S, SO2,
Cepecity Unit* ppm IbMMBtu nwton)/S mole/mole %
400000 Ib/hr 0.06 6.0700 43 .60
400000 Ib/hr 096 4.9700 43.95
400000 Ib/ht 0.96 5.O70O 43.60
400000 Ib/hr 0,96 6.OBOO 46,44
400000 tMhr 0.96 6,2100 46.07
4OOOOO IWhr 0.98 6,0600 4C.44
44.66
664 MW 1-01 980.0 2,4860 33.32
684 MW 1.01 840,0 2.2163 29.67
,684 MW 1,00 BEO.O 2.6064 39,66 -
684 MW 0.79 9OO.O 2.1263 28.48
684 MW 0.63 960.0 2.4118 32,30
31.47
826000 MMhr 0.74 6.700O 46.16
62EOOO Ib/hr 0.7* 6.6800 46.99
626000 Ib/hr 0.76 6.86OO 66.67
826000 Ib/ht 0.74 6.7200 4B.B7
626000 Ib/hr 0,76 6.7400 67,73
826000 Ib/hr 0.74 6.6400 46.40
63,14
60 MMBTU/nr 0.72 2.03OO 8,02* 2.70 0.73
60 MMBTU/hr 0.73 0,4800 1.87* 4.10 O.B6
BO MMBTWtv 0.73 212.3 0.6981 2.78' 3,40 0.93
-------
TABLE 4-2. NEW SO BASELINE DATA FOR BITUMINOUS COAL
Oita
Ref. qility
4 A
13 D
t3 D
13 D
3 C
3 E
8 A
6 A
8 A
• A
6 A
g A
6 A
S A
6 A
6 A
Boitar
type Site
FBC-BB Summereide
FBC-BB TVA 20MWe
FBC-BB TVA 2QMW«
FBC-C BATTRLE
Hind-Fed
H*nd-F*d
PC -I! red Quindaro 12
PC-f«ed OuindifO 93
PC-fired duindaro 12
PC-Bred Quirxtaro *2
PC-fired Quindtro fS
PC-fired Quindaro *2
PC-fired Quindiro »2
PC-TFtred
PC-T Fired
PC-TFire
-------
TABLE 4-3. NEW NO BASELINE DATA FOR BITUMINOUS COAL
Fti
Dati HHV, S,
Ref. qilttr Boiler type S)t* Run Btuflb w(%
7 B Cyclon* PlmtS 4 12121 181
7 B Cyclone Ptint6 1 12121 1.81
7 B Cyclone PI ml 6 3 -..12121 1.81
7 8 CydMW Plants a 12121 1.81
7 B Cyclon* Plirt 6 6 12121 1.81
el Operation
N, Aril, Load
«vt% wt% Ciptctty Urrita factor
13.81 584 MW 079
13.81 SB* MW 1.01
13.81 684 MW 1.01
13.81 (84 MW 1,00
13.81 G84 MW O.B3
NO, «**»,,
Ib/MMBtu Ibfton
0.5773 14.00
0.6307 12.8T
O.T11T 1T.ZS
0 844B 18.82
0.8387 16.48
16.04
f"
ro
FBC-BB
SurmwftNta Avo 11430
Summ«n4de
11760
6.20
6.80
1.06
1.06
11.20
B.BB
60
MMBtuftv
MMBtuAv
0.66
0.73
O.SBOO 16.64
0.91»5 14.56
FBC-BB
6.82 .
11.40
BO
MMBIu/hr
O.73
0.860O 14.B6
FBC-BB
Summeraiito
Avg. 1177d
6.18
1.03
8.73
MMBtu/fx
0.72
0.8700 16.77
16.21
13
FBC-BB
TVA 20MWe
1 13000
4.45
228
MMBtuffy
0,68
0.3400 8.84
13
PBC-BB
TV* 20MW*
11000
384
228
MMilurtv
088
0 2JOO 6.M
7.41
13
fBC-C
l*TTEU.t
13OOO
1.60
MMBtuAw
0.1600 3.90
-------
TABLE 4-3, NEW NO BASELINE DATA FOR COAL
DM>
Rot. qiity
3 C
6 A
6 A
6 A
10 A
to A
10 A
10 A
10 A
tl A
11 A
Fuel
HHV, S, N, A»N,
Boiler type Sit* nun fltu* wt% wl» wt%
Hind-Fed Mod- 13421 0,78 6.43
ifM
PC:T Fifsd 1 B104 0.44 6.42
PCiT-Fiteq1 3 8104 0.44 6,42
PC:T Firod 2 8104 0.44 6.42
Stekw Bolter 24 2 12*06
Stoker- Better 24 6 13681
Stoker- Boiler 24 7 13761
Stoker- Boiler 24 6 13874
*pre«d0r
Stoker- Boiler 24 1 13203
Stoker- K«l«m>i<» 2 '3646
Stoker- Kdimuoo 6 13692
•preader
Opatition MO, emintgni,
UK!
Capacity Umti f«tw IWMMBtu Men
0.0? MMBtu/hr 0.6070 16.22
10O MW 1,02 0.43 tO S.B0
tOO MW 1.02 0.4140 6.71
100 MW 1.02 0.4390 7.12
8.S4
320000 IbAv O.B2 0.7 BOO 19,38
32OOOO Ib/hr 0.82 0.67BO 16.62
320000 IbAv O.B1 0.8K» 18.99
320000 Ib/rir 1.00 O.S660 17.B1
32000O Ib.lir 0.8 1 0.6000 tB,*4
17.64
•0000 IbAv 1,00 0,4347 11.85
90000 Ib/hr 0.76 0.3667 8.70
-------
TABLE 4-3. NEW NO BASELINE DATA FOR BITUMINOUS COAL
Ref.
11
0*tl
qility
A
Boilw type Site flun
Fual
HHV, S, N, Mi,
Btuflb wt% wt% wt%
Op«r«t!on
C*p*city Unit*
SloVor- K«lnn«rt>t> 3 1 38 1 7 flOOOO Ib/hr
•pretdar
La*d
iKttH
NO, «fnMon*r
Ib/MMBtu
0.76 0.4S28
Ib/lon
ti.eo
11
11
tl
11
Stoker-
•prevdar
Sloker-
apreidar
Stoker-
•praadar
Stoker-
•praadar
Kalimuoo
Kiturmoo
Kdimnoo
Kdtmizoo
13827
130GB
13678
137Z7
BOOOO
eoooo
BOOOO
eoooo
Ib/hf
Ib/hf
Ibffrr
Ib/hr
0.76
0.7G
1.OO
1.OO
0.6088
0.6346
0.3702
0.4032
14.01
13.86
10.06
11.07
11
Stoker-
•pfaKler
13668
BOOOO
Ib/hr
0.76
0.3840 10.41
•f*.
4
Stoker-
*pra«ter
Kilamizoo
10
13828
80000
ttoAw
0.76
0.3648 8.87
11.48
-------
TABLE 4-4. NEW CO BASELINE DATA
CO
tn
Dale
Rel. quality
7 B
7 B
7 B
7 B
7 B
7 B
7 B
7 B
7 B
4 A
4 A
4 A
4 A
3 C
3 C
7 B
7 8
Fust
tell* HHV. N, Aah,
type Fue) Site Bun Btuflb wt% wt%
Cyclom Bituminoui Plants 3 12111 13,81
Cyclone Bitumlnoua Plant 6 1 12121 13.81
Cyclone Bitumioou* Mint 6 4 12121 13.81
Cydone Bituminoui Plants . 2 12121 13.81
Cyctonn Bituminoui Plants 4 8896 11.06
Cyclone Bitumrnoue Plant 6 3 6806 1 1 .08
Cyclone Bttumloout Plant fl 6 BBBG 1 1 .06
Cycm-K, Bituminoui Plant 6 1 8896 1 1 .06
Cyclone Bttuminoua Plant 6 2 8896 11,06
F6C BB Biluminoua Sumnweida Avg. 11 760 '.06 9.68
FBC-8B Bituminoui Summei«ide Avg. UBtO 1.08 11.40
FBC-BB Biluminoua SumnwnUa Avo 11430 1 OB 11.20
FBC-BB Bllumlnoua Summaraida Avo 11770 1.O3 9.73
Hand-Fad Bittiminoua Modilied wood 13421 6.43
atove
Hand-Fed Bitumlnoia Coal etove 14119 309
PC-TFirad Subbituminoua Plant 1 4B 7842 13J1
PC-Tfired Subbituminoua Plant 1 4A 7842 13.91
Oper Mian CO EmMen .
load
Capacity Uratt Factor ppm Ib/MMBtu Ihftsn
684 MW 1,01 7.3 0.0088 0.16
684 MW 1.01 12.* 0.0129 0.31
684 MW 0.79 9.4 0.0060 0.22
684 MW 1.00 8.0 0.0076 0.18
O.f2 .
1BO MW 0.84 36.4 0.0364 0.83
180 MW 1.03 17.9 0.0168 0.30
180 MW 0.98 16.1 0.0148 0.26
180 MW 1.00 28.3 0.0277 0.4fl
180 MW 1.02 12.1 0.0)20 0.21
O.38
60 MMBtuftw O.73 419.2 0.8O32 14.17
60 MMBtuAu 0.73 462,6 0.6418 14.78
BO MMBtuftv 0.66 800,7 1.1788 2696
60 MMBtuftw O.72 432.4 0.9B60 16.44
17.83
O.O1 MBtuAir 40OO.O 8,6283 231.60
0.01 MBtu/hr 6000.0 11.3042 319.20
276.40
860 MW O.B4 8.6 O.OO83 0.10
86® MW 0.84 8,6 O.0063 O.10
-------
TABLE 4-4. NEW CO BASELINE DATA
£
Data Boiler
Rat. quality typ* Fuel Site
7 B PC-TFired SubUtuminoui Plant 1
7 B PC-TFirod SubWtuminoya Plant 1
7 B PC-TBred Subbiluminoua Plant 1
7 B PC:V Firod Bituminoua Plant 2
7 B PC:V-Fired BitumlroxM Plant 2
7 B PC:V-Fired Bituminoua Plant 2
7 B PC :V- Firod Rliuminoua Plant 2
7 B PC :V Fired Bitumlnou* Plant 2
7 . B PC ;V- Fired Bitumtncut Plant 2
7 B PC:V-Hted Bttuminaua Plant 2
7 8 PC :V- Firod Bituminoua Plant 2
7 B PC:V-Fired Bituminous Plant 2
7 B PC;V.F(f«d flituminoua Plant 2
7 B PC :W Fired aituminoue Plants
7 B PC;W-Nrad Biluminoua Plant 3
7 B. PC:W-Firs
-------
TABLE 4-4. CO DATA
p«il
R«f. quality
7 i
7 B
Boiler
type Fuel Site Run
Fuel
HHV, N,
BtU/lb wtX
PC:W-Ftrad iituminoua Plant 4 3 1 1B20
PCiW-Fired Bituminous Plant 4 4 1 1920
A»h,
wt%
Operation
Capacity Unit*
11. n 217 MW
11.78 217 MW
Load
factor
CO Emissions,
ppm IWMMBtu
0.99 2O.1 0.0208
0.98 24.4 0.0250
Ib/ton
0.60
o.so
0.43
CO
10
10
10
10
10
11
11
11
11
11
11
11
11
11
A
A
A
A
A
A
A
A
A
A
A
A
A
A
Sprdr Stkr
Sprdr Stkr
Sprdr Stkr
Sprdr Stkr
Sprdr Slkr
Sprdr Stkr
Sprdr Stkr
Sprdr Stkr
Sprdr Stkr
SfirdrStkr
Sprdf Stkr
Sprdr Stkr
Sprdr Stkr
Sprdr Stkr
Bituminous
Blttimrnoua
Bituminous
Bi.yrr.ir*-
Bituminous
BitUrminausi
Bituminaui
NMmtaui
&itumirKK«
BJtumlnOM
BitMmir»u.
BMumhw.
6-Jtumtnou*
Bituminous
Boiler 24
iojNr 24
8«i*r 24
loilsr 24
Boil«r 24
Kilanwaa
Kiritmiaoo
MMM.
K*t*mstitao
IC»ltm*tos
Ktlamtzaa
Kstan...
Kdimaioo
Kal*m«zao
1
a
7
S
2
2
6
3
a
6
4
1
9
10
13203
13GB1
13761
13174
12SOS
13846
13S92
13617
13827
13061
13B78
13727
13669
13628
320OOO
32000O
320000
320000
320000
BOOOO
8OOOO
90000
90000
•oooo
90000
eoooo
aoooo
90000
IWhr
IWIw
IMw
Itt/hr
Ib/hr
Ib/hr
Ib/hr
Ib.lT
Ib/hr
JWh,
Ib/hr
to*,
Ib/hr
Ib/hr
0.81
O.B2
0.81
1,00
0.82
1.00
0.76
0,78
0.76
0.7B
1.00
1,00
0.7B
0.76
29.0
80,0
4O.O
96.0
72.0
42.0
as .0
24.O
22.0
26.0
«2.O
»3.O
28.0
43.0
0.0271
0.06F2
O.O431
0.0928
0.0782
0.0434
0.0316
O.O241
0X2238
0,0300
0.0353
O.OB4B
0.0266
0,0374
0.72
1,61
1.11
Z.S4
2.02
1.80
1.18
O.Bfl
0.96
0.65
0.78
0.96
t.BI
0.69
1.02
0.92
-------
TABLE 4-5. NEW PM BASELINE DATA FOR BITUMINOUS COAL
Oiti
fl«f. qillly
3 C
3 C
Boiler
type Stta
Hand- Fed
Hind-Fed
Run
Fuel
HHV,
Btu/lb
C tul Stove 14119
Modified Wood 13421
s,
wt%
0.77
0.79
Aih,
wt%
OpetMion
Cipacitv
3.09 0.01
6.43 0.01
toed
Unid factor
PM EiDiMiQfVf
RMMMBtu Ibrton
MMBIuff* 20.94
MMBtuffn 10.14
»
B
B
B
It
It
It
12
12
A PC-
A PC-
A PC-
A PC-
B Stoker-Spreader
B Stoker-Spreader
B Stoker-Spreader
B Stoker-Spreader
B Stoker-Spreader
Quindwo »2
Quindiro 92
Quindaro #2
-------
TABLE 4-6. NEW ChL BASELINE DATA FOR BITUMINOUS COAL
4
Ret.
3
3
Ditt
qu«Mt|f
C
C
Boiler
type fuel Run
Fu*I
HHV,
BMb
Htnd Fod BMumkMUi CM! Stov* 14119
H«nd-F«f B.-nnninom Motfficd Wood 13421
S,
wt%
0.77
0.78
Ajh.
wt%
Operation
C«PKIIY MM
3.08 0,01
6.43 0,01
CH4 EmMom,
ppm IWMMIilu
MMBtUftv 2tO.O 0.220)
MMBtuftv 96.0 0,1171
Ib/ton
8.36
3.14
4,78
-------
Table 4-7. CONTROLLED PM EMISSIONS
Boiler capacity,
actual/design
36 MW
10. 2/1 BMW
34/50 MMBtuftH
I2.B-14/16MW
39-4 7 /BO MMBtuAw
1B.6-1S/20MW
66-66/JO MMBtu/hr
1 8,3- 1 8,4/23 MW
66,«-64rtO MMBtu/hf
17.8 18.9/18 MW
69.4-63/flO MMBtuAir
t7.6-)9.4/18 MW
63.8-86/80 MMBIUrtw
24.7-28.1/29 MW
••-•1/100 MMBtufhr
»/» MW31/31 MMBluft*
BO .4/88 MW
172.3/236 MMBtufhr
58.7-62.8/69 MW
300-216/238 MMBtu/hf
34/37 MW
11 6/1 26 MMBtuflw
i8.8-t9/i9Mw
62.7-64/64 MMBtu/hf
1MB.2/1 BMW
EB.3-Bt.4/B4MMBtufhr
28.6/37 MW
98/1 m MMBtu/h<
43.2/46 MW
173.8/1BMMBtuftv
23,4/33 MW
81 .7/11 6 MMBtu/hr
Boiler type
CoiMnduairid
Coil Find/
•praader etofcer
Coal fired/
•preeder iceker
Colt fired/
tpraadw Maker
Cod fired/
•preedaf etoker
Carifi"
•preader
(22.9'».17»
(2t.r».1»)
I22.7*/0.12)
(NIVO.10I
!NWO.OTJ
)MH/O.OB(
("22.1 /O.O1B)
tNR/0.033)
(•22,2/0,01 »
f21.7».028|
INH/0.019
Ib/MMBtiul
Iwfnc^* •fnctflncy
<%)
BB.4
99.6'
99.6'
•«,4'
99.«'
89.4'
M.31
99.3-
«*.«•
K.'A
NM
N/A
•8.7'
N/A
100.0*
99.9'
NM
Ret.
20
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
-------
Table 4-7, CONTROLLED PM EMISSIONS
Boiler capacity,
•etu*Vds*lg*v
9.6/13 MW
36.6/48 MMBtu/br
B 3,4/6 9 MW
206/208 MMBtu/hr
21.8-29Mm MW
96*98/92 MVBtjAr
32.6-34.3/35 MW
112-1 IB/120 MMBlu/hr
46 B 46.9/46 MW
tE4-169/1E6MMBtuAv
03.6-66/7 1 MW
21B-223/260MMBtu/ht
•3.6/t 10 MW
266:376 MMBluA*
ST. 2-64.8/110 MW
1B6/221 MMBtufhr
Boiler type
Co. fired/
aprsacter ttokar
Crrcutatins FBC
Coal lir«d/
tpr«adflr iloker
Coil find/
•preaeier ctoker
Cod f.rod/
•praadar itok«r
Coal Mrad/
«(if»adar atokar
Coa« lit«d/
apr«ad«f tfoksf
Cad Kr«d/
apr«ad«r ttoker
FL»|
S,
wt %
0.8
0.4
N«, .
1,O
O.B7
0,78
O.54
O.«3
A«h,
wt %
8.3
88
12.O
11.2
tl.4
6,8
B. 3
6.4
HHV,
Bm/tto
13,700
12,200
12,iW
1 2,600
1 1 ,400
13,100
10,200
10,600
Control technology
fabric tiller
Fabric filter
ESP
ESP
ISP
ESP
ESP
ESP
EmMom tuneontfelM/
control ledl,
Ib/MMBICJ
r21.9lb/MM8tu;
0.016 IWMMBtu)
f 24.6 Ib/MMBtu/
0.03B Ib.iMMatu)
1*24.0 Ib/MMBW
0,007 iWMM0tu)
1*24.0 Ib/MMBtu/
0.006 tb/MMBtut
f28.3 Ib/MMStu/
0.012lb/MMB.«*
89.8'
89. B'
99.9'
10O.O*
99. »•
99 »'
88,8*
Ref.
21
21
21
21
21
2( .
21
21
Calculated
NR = not reported
-------
TABLE 4-8. CONTROLLED SO EMISSIONS
Boiler capacity,
aenuUdaiian
KH/li MW
MR/400 MW
NR/1360 MMBlu/TH
NR/183 MW
NR/57O MMBluAw
NRMO MW
Nfl/140 MMBMtr
82/82 MW
2 BO/280 MMBMff*
24/34 MW
86.3/116 MMBlyffif
24/68 MW
82.1/236 MMBlu/hr
«9/«9 MW
1 046/236 MMBturtx
67/89 MW
1 93/236 MMBiu/h.
36-62/89 MW
I1B-1 74/236 MMflluftv
69/69 MW
236/236 MMBtu/tY
306, OOO SCFM
210.0OO SCFM
•7,000 SGFM
236,000 SCFM
38,000 SCFM
140,000 SCFM
8,070 SCFM
126,400 SCFM
Boiler type
CMMnduMrial
Coil
Corf
Coil
Pulvwind cod
Puiverirnrf cad
Coal *pre*4or ttofcer
Spr«ad«r (taker
Sp««*dflr ctokar
Spraidar vlokar
Puhrflfitad coil
tndmtf if co»l
InduMrW cod
InJyitrW co»l
InduttrM coil
InduMrM CM)
IndUBtrivl col!
Induvtrid cod
Induilrid cod
Fortr,
%
2.6-2,8
2,6
3-3,6
13.33lbSOj,'MMBtu
.99 Ib
SO/MMBtu
6.08 Ib SOj/MMBtu
G.OB Ib SOj/MMBtu
6 09 Ib SO-..VMBtu
e.e ib so/
MMBIU
.9« it SO/
MMBtu
3.0
3.2
3.2
3.2
3.2
3.2
2.6-3.O
2.6
Control technology
Wet tcruMMr
DiM «lk«li/wot icrubber
Dud »tk»li/wet icrubber
Dud *ik*lt/w*i icFufabn
Duel «IWVw*l mnAbar
Lime *p*«y dry F3D
Lima ipriy dry f QD
Lim« ipny dry FCD
Uma tpray dry FGD
Ume spray dry FGD
Lima torty dry FGD
Doutota Alkili Syilam
OouM> Alkili Syitam
Doubte Alkali Syitom
DouWa Alkali SylUm
DouW. Alkali Syitam
Daubto Alluli Sv*t«m
Doubto Mkali SyMem
OoUit* MUi Synom
ImWora (uncontrellarf/
controllodl,
Ib./MMBtu"
(tlEkgMS.TkaM
(6.4/O.eS MMMMBTU!
(3.B6/O.31 MMMiTU)
(6.0/0.47 Ib/MMBTU)
M/A
MM
M/A
N/A
N/A
N/A
NM
(1 8,000 ppm/ 1 ,800 ppml
(2O.OOO ppm/ 2,000 ppml
(20,000 ppm,' 2,000 ppm)
(20,000 pom/ 2,000 ppm)
<20,OOO ppm/ 2,000 ppm]
120,000 ppm/ 2.0OO ppml
( 10 ,000 ppm/ 1 ,OOO ocml
(8,000 ppm/ BOO ppm)
Ramewil •HManey,
%
98.B
88.0
02.2
91.2
74,6
92.4
78. T
88.9
06.6
84-98
•a .e
'•0
to
•0
eo
80
BO
>O.E
90
Rot.
2O
22
22
22
22
22
22
22
22
22
22
23
23
23
23
23
23
23
23
Unless otherwise noted
N/A = Not available
-------
TABLE 4-9. CONTROLLED NOX EMISSIONS
Boiler load (•*•(
14,8/18 MW
61/63MMBtuA¥
23.6tt8 MW
78/94 MMBtuftx
28.7/29 MW
>e/m MMBiuftr
28.7/29 MW
98/89 MMBMw
21. S/2* MW
73.6/B8 MMBtiVht
21.8/28 MW
73.6/98 MMBtuAv
21 ,8/28 MW
76/h/100 MMBtu/h.
22/29 MW
78/100MMBtuftw
1 8,9/22 MW
67.8/76 MMBtil.'V
18.8/22 MW
67.8,76 MMBtuAv
29.V28MW
98.8/96 MMBtu/hr
28.8/28 MW
86. e/BB MMBtu/hr
23/23 MW
Tim MMStu*r
1 8,2/1 «MW
63.8/83 MMBiuAv
9,1/8 MW
3t.9/5eMMBlu*r
40-82%- 160 MW«
4O-B2%-1fO MW*
Boilfif ty|9e
Coilfrpreider •tokar
Coil/ipr«ader •tokiir
Coi)/ipra«der *toker ' •
Coal/Mpraader MoMr
Coal/tpreactaf atoMr
Co«l/*p[0ad«r ttokflr
Ca^/*pr0ad0r ftokef
Coaf/ipre«d«r ttok«r
Co«l/yfid0rftr
Coii/ovarfed *totor
Co«l/ov«rft«J «tok«r
Coal/sverfa^ Mskw
Ceil/vHsrctinci gfit« itokftf
PC: t«no«ntiilly tiroct
PC; will 'i'od
FuelN.
wt %
1.6
1.4
1.0
1.0
1.2
1.1
1,1
O6
1.4
1.4
t.a
1.4
t.7
1.8
0.9
NM
N/A
Control technology
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
LEA
OFA
OFA
EfflMwn lurcontrcrfled/
controtW],
ItaMMBtu
10. 635*. 4 6 21
10.834(0,491)
IO.B40/O.4121
HSJ 2/0.4011
10. 468/0.4131
(0.464/0.3121
10.606/0.4061
10.483/0.448)
10.184/0.2631
(0.433/0.341)
(0.400/0.283)
{0.228/0.211)
(0,363/0.318)
IO,3f4»,31O)
I0.2TIS.209)
I0.69W.48)
IO,II».O6)
Rafnovrf efficiency,
%
29
23
24
30
6
31
20
13
28
1?
29
8
10
4
26
19
22
R*f,
24
24
24
24
24
24
24
24
Z4
24
24
24
24
24
24
26
26
-------
TABLE 4-9.
CONTROLLED NO^EMISSIONS
Bete told tovol
40-82%-160MW«
40-82%- 160 MW«
40-82%- 160 MW*
40-82%- 160 MWe
40-82%- 1 BOM We
40-82%-160MW*
40-8J%-160 MW«
40-82 V 190 MWe
•0-123 M Wo/ 160 MW*
«M 23 MWe/ 1 BO MW»
80-123 MW«/ 160 M We
flO-123 M We; 160 MW*
90 123 MWe;' ISO MW*
«O-1 23 M We/ 160 MWe
60-123 MWe/IBQ MWe
80-123 M We/1 60 MWe
60-123 N»W«/1EO MWe
60-123 MW«/160 MWe
Bailor t v£»
PC: will fired
PC: wall frwd
PC: ttngantWly timd
PC: Un»«fH..lly fired
PC: will fired
PC: will firwt
PC: ttrgemidly drod
Cyetem
CMUwM Hrad
Cad/wili liratf
Gail/will fired
Co«l/l«ngemi^
€oii/e¥^one
Cotf/wiM + (•npential
Coil/will * t»ngenl.»(
Catf/wffl 4 lingentiiil
C oil/will + twiflonrid
PC: t«a«nMv firnd
FueIN,
wt *
N/A
N/A
N/A
MM
NM
N/A
NM
N/A
NM
NlA
NM
N/A
NM
N/A
NM
N/A
N/A
N/A
Control Mdmologf
LNB t OFA
LNB
LBN + OFA + FOR
SNC*
SNCR
SCR
sen
NGR
OFA
LNB
1MB 4- OFA
LNB + OFA +FQR
raburn
SCR
SCR
SNCfl
SNCR
OFA
EmlttJm tuncontisHtd/
cantroNadi,
Irj/MMBru
W.??».33)
C0.77/O.46I
n.Gt/O,2Bl
(0.7O/0.36)
[0.;B,X).18]
(0.2Brt).OBI
rO. 70AX1 El
(1.28/O.66>
B.77»,80)
(0.77W.4BI
P.77W.33I
t0.68/O.28l
(1-28/O.66I
(0.2B/O.OBI
(0.70/0. IB)
(0.2r3A3.18!
(0.70/0.361
10 .69/0. 48)
ftemovil tHictency ,
*
67
42
B!
BO
39
71
78
6fl
22
41
67
M
67
71
7B
36
SO
1*
M.
25
26
2B
26
2B
26
25
26
as
26
26
26
26
26
2E
26
26
26
^y»
t
LEA = Low excess air
OFA - Overtired air ports
LNB = Law NO burner
FGR = Flue gas* recirculation
NGR = Natural gas reburn
N/A - Not available
-------
TABLE 4-10 METAL ENRICHMENT BEHAVIORS
QMS
Description
Reference 35
Reference 28
Reference 39
Equal distribution
between fly ash and
bottom ash
Aluminum (Al), Cobalt (Go), Iron
(Fe). Manganese (Mn), Scandium
(Sc), Titanium (Ti)
Al, Co, Chromium (Cr),
Fe Mn, Sc, Tl
II
HI
IV
Enriched in fly ash
relative to bottom
ash
Somewhere In
between Class I and
II, multiple behavior
Emitted in gas
phase
Arsenic (As), Cadmium (Cd)
Beryllium (Be), Cr, Nickel
(Ni), Mn
Mercury (Hg)
As, Cd, Lead (Pb), Antimony (Sb)
Cr, Ni
Hg
As,
Ni
Hg
Cd.Pb, Sb
TABLE 4-11. ENRICHMENT RATIOS FOR CLASSES OF ELEMENTS
Class
I
lla
lib
HC
III
Description
Nonvolatile
Volatile with varying condensation on ash
particles
Very volatile, almost no condensation
Metals
Cr, Sc, Ti, Fe
As, Cd, n, Sb
Be, Co, Ni
Mn
Hfl, Se
Fly ash enrichment ratio
ER- 1
ER>4
2 < ER < 4
1.3 < ERs 2
ER = Enrichment ratio
4-45
-------
TABLE 4-12. ENRICHMENT RATIOS FOR BOILERS AND ESP
Boitor typa
ISCCI
Pulvafiied Coat
Dry Bottom
1)01002021
Pulvailied Coal
Dry Bottom
(101002)2)
High efficiency
Cold-wde
ESP
Sb
1.07
0.97
to
1.33
6.4
to
26
Al
1.26
I.OB
to
1.27
6
to
29. a
Be Cd Cr
O.BB 0.66 0,98
0.78 0.48 O.42
to to to
1.12 O.BB 0.97
2.1 8 1
to
21.7
Co
1.02
o.eo
to
0.97
1.1
to
9.9
Pb
1.48
1.28
to
1.42
3.0
to
18.3
Mn
).07
O.B8
to
1.02
1.4
to
13.8
HO
0,72
0.71
1.0
to
19.3
m
0.97
0.94
to
1.64
1.8
to
10.1
Se
1.01
0.76
to
0.82
7
to
86.2
Th
232
1.43
1.04
to
1.18
0.04
to
0.88
Th
228
o.ee
0.82
to
).ie
1.19
u
238
1.19
1.08
to
1.24
1.16
to
1.36
Til Ra
230 228
0.98
1.1 8 0.96
to
1.19
1.88
Pb
210
1.33
1.36
0.94
-------
TABLE 4-13. HAP EMISSION FACTORS (ENGLISH UNITS) FOR UNCONTROLLED BITUMINOUS COAL-FIRED
BOILERS*
Rring configuration
(SCC) As
Pulverized Coal
Configuration Unknown N/A
(No SCC)
Pulverized Coal
Wet Bottom 538
(10100201)
Pulverized Coal
Dry Bottom 684
(10100202)
Pulverized coal
Dry Bottom, Tangential N/A
(10100212)
Cyclone Furnace
(10100203) 115
Stoker
Configuration Unknown N/A
(No SCC)
Spreader Stoker
(10100204) 264-542
Traveling Grate,
Overfed Stoker 542-1030
(10100205)
Be
N/A
81
81
N/A
<81
73
N/A
N/A
Cd Cr Pb Mn
N/A 1922 N/A N/A
44-70 1020-1570 507C 808-2980
44.4 1250-1570 507° 228-2980
N/A N/A N/A N/A
28 212-1502 507° 228-1300
N/A 19-300 N/A 2170
21-43 942-1570 507° N/A
43-82 N/A 507° N/A
Hg
N/A
1i
16
N/A
16
18
N/A
N/A
Ni
N/A
840-1290
1030-1290
N/A
174-1290
775^1 290
N/A
N/A
POM
N/A
N/A
2,08
2.4
N/A
N/A
N/A
N/A
HCOH
112b
N/A
N/A
N/A
N/A
N/A
221d
140°
A tfi *
, All emission factors in lb/10 Btu; all emission factors rated E.
° Based on 2 units; 456 MWe and 133 MMBtu/hr.
, Lead emission factors were taken directly from an EPA background document for support of the NAAQS.
Based on 1 unit; 59 MMBtu/hr.
0 Based on 1 unit; 52 MMBtu/hr.
-------
TABLE 4-14. HAP EMISSION FACTORS (METRIC UNITS) FOR UNCONTROLLED BITUMINOUS COAL-FIRED
BOILERS*
Bring configuration
(SCC)
Pulverized Coal
Configuration Unknown
(No SCC)
Pulverized Coal
Wet Bottom
(10100201)
Pulverized Coal
Dry Bottom
(10100202)
Pulverized coal
Dry Bottom, Tangential
(10100212)
Cyclone Furnace
(10100203)
Stoker
Configuration Unknown
(No SCC)
Spreader Stoker
(10100204)
Traveling Grate,
Overfed Stoker
(10100205)
As
N/A
231
294
N/A
49,5-133
N/A
114-233
233-443
Be
N/A
35
35
N/A
<34.9
31,4
N/A
N/A
Cd
N/A
18-30
19
N/A
12
N/A
9.0-18.5
1S-35
Cr
825
439476
538-676
N/A
91.2-676
8,1-675
N/A
N/A
Pb
N/A
2WC
218°
N/A
218°
N/A
218°
218°
Mn
N/A
348-1282
98-1282
N/A
98-559
934
N/A
N/A
Ha NI
N/A N/A
7 361-555
? 443-555
N/A N/A
6.9 74,9-555
6.9 334-555
N/A N/A
N/A N/A
POM
N/A
N/A
0.894
1.03
N/A
N/A
N/A
N/A
HCOH
48b
N/A
N/A
N/A
N/A
N/A
95d
60*
. All emission factors In pg/J; all emission factors rated E.
Based on 2 units; 456 MWe and 39 MW.
. Lead emission factors were taken directly from an EPA background document for support of the NAAQS.
Based on 1 unit; 17 MW.
Based on 1 unit; 15 MW,
-------
TABLE 4-15, HAP EMISSION FACTORS (ENGLISH UNITS) FOR CONTROLLED
^ BITUMINOUS COAL-FIRED BOILERS
Boiler configuration
(SCC) Control device Cr Mn POM
Pulverized coal
Configuration unknown
(no SCC)
Multicyclones 12
ESP 5.8-7990
Wet scrubber 0.61-12
MuMcyclones/wet scrubber 18
Pulverized coal
Wet bottom
(10100201)
Cyclone Furnace
(10100203)
Stoker
Configuration unknown
(no SCC)
Pulverized coal
Dry bottom
(10100202)
ESP
Wet scrubber
ESP
Wet scrubber
Multicyclones
ESP
ESP
Wet scrubber
Multicyclones/
ESP
78
19-22 60.8
107 126
62-2423 110
135
96.2
112
18.6
565
0.46
57,2
16.2
8.55
0.033-18.6
/Ml emission factors in Ib/MMBtu; all emission factors rated E.
4-49
-------
TABLE 4-16. HAP EMISSION FACTORS (METRIC UNITS) FOR CONTROLLED
BITUMINOUS COAL-FIRED BOILERS
Boiler configuration
(SCO) Control device Cr Mn POM
Pulverized coal
Configuration unknown
(No SCC)
Pulverized coal
Wet bottom
(10100201)
Cyclone furnace
(101002)3)
Multicydones 5.3
ESP 2.5-3430
Wet scrubber 0.26-5.3
Multicydones/wet scrubber 7.8
ESP
Wet scrubber
ESP
Wet scrubber
8.4-9.7
47.3
33.5
27
55.8
8.0
2.43
0.20
25.3
Stoker
Configuration unknown
(No SCC)
Pulverized coal
Dry bottom
(10100202)
Multicydones
ESP
ESP
Wet scrubber
Multicyclones/ESP
27.4-1072
59.7
48.7
7.2
41.3
48.2
3.68
0.014-8
All emission factors in pg/J; all emission factors rated E.
4-50
-------
TABLE 4-17. AVERAGE TRACE ELEMENT REMOVAL EFFICIENCY FOR CONTROL
DEVICES8
Compound
Arsenic
Beryllium
Cadmium
Chromium
Manganese
Nickel
Mechanical
precipitation
51
37
28.9
42.3
54.3
49.4
ESP
87.5
91.9
74.6
71.5
78.1
79.1
FGD
scrubber
94.3
94.4b
91 .8b
89.1b
96.4b
Two ESPs
In series
99.6
99.94
90.5
93.7
96.4
96.6
ESP/
scrubber
98.9
92.9
97.7
97.2
Two
mufticyclones
50"
These average control efficiencies represent measured control levels reported in the literature. They
may or may not be indicative of the long-term performance of these types of controls on emissions
from coal combustion sources. The average values should not be construed to represent an EPA-
recommended efficiency level for these devices. Only limited data are available for lead and mercury
removal efficiencies. Each emission test was weighted equally.
The type of scrubber was not specified.
These control efficiencies are for hexavalent chromium; the remaining values are for total chromium.
The chromium control efficiencies may be biased low due to contamination from sampling equipment.
Emission factors calculated using these efficiencies probably represent, in most cases, upper bound
estimates.
4-51
-------
TABLE 4-18.
NLO EMISSIONS DATA
Ref.
78
78
76
78
78
78
78
7fl
78
79
78
78
78
78
78
78
78
78
76
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
78
79
78
78
78
79
79
78
Dm*
quality
B
1
B
B
B
B
e
B
B
B
B
B
e
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
Boilw typ0
DRUM-BOILER NAT. CIRC.
DRUM-BOILER NAT, CIRC.
DRUM-BOILER NAT. CIRC.
DRUM-BOILER NAT. CIRC.
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-SHED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-FIRED
f.c. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-FIRED
P.C. CIRCULAR WALL-RRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-HRED
P.C. CIRCULAR WALL-FIRED
P.C. TRIPLE CELL WALL-FIRED
P.C. TRIPLE CELL WALL-RRED
P.C. TRIPLE CELL WALL-HRED
P.C. TRIPLE CELL WALL-HRED
P.C. TRIPLE CELL WALL-HRED
P.C. TRIPLE CELL WALL-HRED
P.C. TRIPLE CELL WALL-RRED
P.C. TRIPLE CELL WALL-HRED
P.C. TRIPLE CELL WALL-FIRED
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
Full
tVP«
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
Baiter
dpoelty
171 MW
171 MW
171 MW
171 MW
2BOMW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
26OMW
26OMW
26OMW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
26OMW
260 MW
260 MW
26OMW
26OMW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
260 MW
26OMW
26OMW
260 MW
26OMW
260 MW
260 MW
260 MW
260 MW
700 MW
700 MW
700 MW
70OMW
Boilw
iMd
0.86
0.82
0.76
0.86
1.O8
0.82
1.08
0.82
I.OB
1.08
1.08
0.82
1.08
1.08
0.82
O.82
0.82
1.0B
0.82
1.08
1.08
1.08
1.08
1.08
i.oe
1.08
1.O8
1.08
i.oe
0.82
1.O8
1.06
1.08
1.08
1.08
0.92
1.08
1.06
1.08
1.08
1.OB
1.O9
1.O9
1.08
1.08
1.08
1.08
0.8
0.6
0.6
0.8
Uncomrollvl N,O
•nwwwiBt
ppm
2.1
2.6
6.1
3.3
3.0
2
3.6
1.8
2.4
4.6
2.4
0.7
3.0
2.4
1.1
O.B
0.8
2.4
0.8
2.4
3.6
2.4
2.4
2.4
3
3.0
3.0
2.4
3.6
2.1
3.6
2.4
3.0
0.7
2.4
1.4
2.1
2.4
2.4
. 2.4
2.4
3.0
2.4
2.4
3.6
3.6
3.6
0.4
0.9
0.7
O.B
NjO omMon factor,
Ib/un
7.60E-02
8.00E-02
1.B4E-01
1.18E-01
1.17E-O1
1.28E-O1
7.2BE-02
1.2BE-01
6.66E-02
8.63E-02
1.84E-01
6.63E-02
2.66E-02
1.28E-01
8.63E-02
4.01 E-02
3.28E-02
2.81 E-02
6.63E-02
3.2BE-02
6.E3E-02
1.26E-01
8.63E-02
8.53E-02
8.63E-02
1.07E-01
1.28E-01
1.2BE-O1
B.63E-02
1.2BE-01
7.66E-O2
1.28E-O1
B.63E-02
1.28E-01
2.48E-02
8.53E-02
6.10E-02
7. 47 E-02
8.63E-02
8.74E-02
8.64E-02
8.94 E-02
8.S4E-O2
1.3OE-O1
8.S4E-O2
6.64E-02
1.30E-01
1 .30E-01
1.30E-01
1.06E-01
1 .42E-02
3.2OE-O2
2.49E-02
2.B4E-02
4-52
-------
TABLE 4-18. hLO EMISSIONS DATA
Haf,
70
70
78
79
78
70
70
78
70
70
78
70
70
78
7ft
70
70
7§
78
78
78
78
70
70
SO
DM*
quality
B
B
B
B
s
B
B
B
B
8
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
Boilw type
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANSENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
TANGENTIAL
FLUIDIZED BED COMBUSTION CIRC
Fuel
type
BCT.
BIT,
BIT.
BIT.
«T.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT.
BIT-
BIT.
BIT.
BIT.
BIT.
Bortw
capacity
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
7OOMW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
700 MW
BMW
B otter
load
0.8
0.8
O.B
O.B
0.8
o.e
0.8
o.e
0.8
0.8
o.e
O.B
O.B
0.8
0.8
O.B
0.8
0.8
0.8
O.B
0.8
0.8
0.8
0.8
Uncontrolled N2O
amMem,
pwn
2.3
t.2
1.2
0.6
0.*
0.4
1.2
0.6
0.7
O.B
0.*
0.4
1.2
OJ
1.2
0.6
0.0
1.2
0.6
0.7
0.8
0.9
0.7
1.2
136
N 3O amMan f aetor,
Ib/ion
B.18E-Q2
4.27E-OS
4.S7I-02
1.7BE-02
1 .42E-02
1.42E-02
4.27E-02
1.781-02
2.4BE-02
2.84E-02
1.42E-O2
1.42E-Q2
4.27E-02
2.48E-O2
4.27E-02
1 -78E-02
3.2OE-02
4.271-02
OSI-02
2.4BE-03
2.84E-O2
3.2OE-O2
2.49E-02
4.27E-02
2.96E-02
S.BSE-i-00
4-53
-------
TABLE 4-19.SUMMARY OF N2O EMISSION FACTORS FOR BITUMINOUS AND
SUBBITUMINOUS COAL COMBUSTION
Firing
configuration
Pulverized coal fired
Dry bottom - wail fired
Dry bottom - tangential
Wet bottom
Cyclone furnace
Spreader stoker
Overfeed stoker
Underfeed stoker
Handfired units
Fluid ized beds
Bubbling
Circulating
Rating
D
D
E
E
E
E •
E
E
•E .
E
N90
Ib/ton
0.09
0.03
O.Oi8
0.09°
o.oe*
o.oia
0.09°
0.0ia
5.5b
S.5
emission factor,
kg/Mg
0.045
0.015
0.045*
0.045a
0.0458
0.045a
0.045*
0.045*
2.7"
2.7
No date; value for pulverized coal dry bottom - wall fired was assigned.
No data; value for circulating fluidized bed was assigned.
4-54
-------
TABLE 4-20. PARTICULATE SIZING DATA FOR THE 1986 AP-42 DATABASE:
NUMBER OF A & B RANKED DATA SETS8
Emission control device
Source category
Bituminous/subbttuminous coal
combustion
- Dry bottom, pulv. coal
- Wet bottom, pulv. coal
- Cyclone furnace
- Spreader stoker
- Overfeed stoker
- Underfeed stoker
None
>30
3
0
>30
3
6
Multiple
cyclones
3
0
$
2
Scrubber
>30
0
1
0
0
0
ESP
>30
0
2
0
0
0
Baghouse
2
0
0
>30
0
0
Data from Reference 2
' All data correspond to no fly ash reinfection
TABLE 4-21. COMPARISON OF ORGANIC AND INORGANIC CPM EMISSIONS FROM
A COAL-FIRED BOILER8
Run
Number
1
2
3
4
5
Organic CPM
mg/m
0.5
0.5
1.6
1.6
0,6
emissions,
% of total
1.2
1.3
4.5
3.7
1.5
Inorganic CPM
mg/m
40.1
37.4
33.i
42.0
38.9
. . c
emissions ,
% of total
98.8
98.7
95.5
96.3
98.5
Based on Reference 83. ."
Run 1 results consist of one train with an NZ purge. Run 2 is an average of two simultaneous trains
purged with N2. Runs 3 and 5 are averages of three simultaneous trains purged with N2. Run 4 is an
average of four simultaneous trains purged with N
c Corrected for chlorides.
4-55
-------
TABLE 4-22. FILTERABLE PARTICULATE FOR A FRONT WALL FIRED BOILER
FUELED ON A LOW SULFUR WESTERN BITUMINOUS COAL
Filterable paniculate,
Cumulative mass percent less than stated size fin microns) Data
•—^-"———•—-——--——•—•——————•—•————^———- quality
Side of duct 0.62S 1,00 1.25 2.50 6.00 10 15 rating Ref,
West side < 4 < 4 4 5 8 13 18 B 86
East side < 2 < 2 2 4 S1524 B 86
TABLE 4-23. FILTERABLE PARTICULATE FOR SUBBITUMINOUS COAL FIRED
FLUIDIZED BED COMBUSTORS WITH MULTICLONE CONTROLS
Filterable paniculate,
Fuel
Navajo
subbituminous
Sarpy Creek
subbituminous
Cumulative
0.625 1
mass
.00
< 2 12
< 2
9
percent
1.25
22
17
less than
2.50
56
55
stated size
6.00
82
74
(in microns)
10
as
85
15
90
90
Data
quality
rating
D
0
Ret.
85
85
4-56
-------
REFERENCES FOR CHAPTER 4
1. Background Data Used to Develop Emission Factors for Bituminous and
Subbituminous Coal Combustion, Tom Lahre, Environmental Protection
Agency, September 1981.
2. Van Buran, D., D. Barbe, and A.W. Wyss, External Combustion Particulate
Emissions: Source Category Report, November 1986, EPA-600/7-86-043.
3. ANALYSIS OF RESIDENTIAL COAL STOVE EMISSIONS, EPA Contract No. 68-
02-3169, BATTELLE, Columbus, Ohio, July 1983.
4. Foley, J.M. and H. Schiff, Fluidized Bed Boiler Emission Test Report: Canadian
Forces Base Summersude. Prince Edward Island Canada. EMB Report 86-SPB-
2. U.S. Environmental Protection Agency, Research Triangle Park, NC, March
1986.
5. Gaseous & Particulate Emissions Studies Performed for Grand Island Electric
Department at the Platte River Generating Station Unit No. 1, Mostardi-Platte
Associates, inc, Bensenville, Illinois, December 1982.
6. SO? Emissions Test Report for Kansas City, Kansas Board of Public Utilities
Quindaro Station Unit 2, Burns & McDonnell, Kansas City, Missouri, January
1989.
7. Haile. C.L et. al.. Comprehensive Assessment oLthe Specific Compounds
Present in Combustion Processes. EPA-560/5-83-006, U.S. Environmental
Protection Agency, Washington, D.C., September 1983.
8. SO. EMISSIONS TEST REPORT for KANSAS CITY KANSAS BOARD OF
PUBLIC UTILITIES - KAW STATION UNIT 1 & QUINDARO STATION UNIT 1.
Burns & McDonnell, Kansas City, MO, August 1988.
9- PARTICULATE EMISSION PROGRAM PERFORMED FOR BOARD OF PUBLIC
UTILITIES AT THE QUINDARO POWER STATION UNIT Q2. Mostardi Platt
Associates Inc., Bensenville IL, July, 1986.
10. Emissions Test Report: Tennessee Eastman Boiler 24. Kingsport. TN. EMB 84-
1BR-23, U.S. Environmental Protection Agency.
11. Industrial Boilers Emissions Test Report: Upjohn Co. Kalamg^QQ. Michigan.
EMB 85-1BR-25, U.S. Environmental Protection Agency, January 1985.
12. Emissions Test Report: Burlington Industries. Clarksville. VA. EMB 82-1BR-18.
U.S. Environmental Protection Agency, June 1982.
4-57
-------
13. Fluidtzed Bed Combustion: Effectiveness of an SO, Control Technology for an
Industrial Boiler. EPA-450/3-85-010, U.S. Environmental Protection Agency,
September 1984.
14- Low-Sulfur Western Coal Use in Existing Small and Intermediate Size Boilers.
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July 1978.
15. Atmospheric Emissions From Coal Combustion: An Inventory Guide. 999-AP-
24, U. S. Environmental Protection Agency, Washington, D.C., April 1966.
16- Field Tests of Industrial Stoker Coal-fired Boilers for Emissions Control and
Efficiency Improvement - Site F. EPA-600/7-80-065a, U.S. Environmental
Protection Agency, Washington, D.C., March 1980.
17. Source Sampling Residential Fireplaces for Emission Factor Development. EPA-
450/3-76-010, U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina, November 1975.
18. Environmental Assessment of Coal- and Oil-Firing in a Controlled Industrial
Boiler. EPA/600/7-78/164C, U.S. Environmental Protection Agency, August
1978,
19- Overview of the Regulatory Baseline: Technical Basis and Alternative Control
Levels for Particulate Matter fPM) - Emission Standards for Small Steam
Generating Units. EPA-450/3-89-011, U.S. Environmental Protection Agency,
Research Triangle Park, NC, May 1989.
20. Overview of the Regulatory Baseline: Technical Basis and Alternative Control
Levels for Sulfur Dioxide fSQJ Emission Standards for Small Steam Generating
Units. EPA-450/3-89-012, U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1989.
21. Fossil Fuel-Fired Industrial Boilers - Background Information. Volume I, EPA-
45Q/3-82-006A, U.S. Environmental Protection Agency, Atlanta, GA, March
1982.
22. Overview of the Regulatory Baseline. Technical Basis, and Alternative Control
Levels for Nitrogen Oxides (NOJ Emission Standards for Small Steam
Generating Units. EPA-450/3-89-13, U.S. Environmental Protection Agency,
Research Triangle Park, NC, May 1989.
23. Evaluation and Costing of NO^ Controls for Existing Utility Boilers in the
NESCAUM Region. Acurex Environmental, Mountain View, CA, EPA Contract
No. 68-D9-Q131, Work Assignment 1-19, September 1991.
4-58
-------
24. Krishnan R.E. and G.V. Helwig. Trace Emissions from Coal and OH
Combustion. Environmental Progress, 1(4): 290-295. 1982.
25. Brooks, G.W., M.B. Stockton, KKuhn, and G.D. Rives, Radian Corporation.
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(POMV EPA-450/4-84-Q07p. U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, May 1988.
26. Leavitt, Arledge, Shih, et. al., Environmental Assessment of Coal- and Oil-firing
in a Controlled Industrial Boiler: Volume I. II. and III. August 1978
27. Shih, C.C.; R. A. Arisini, D.G! Ackerman, R. Moreno, E.L Moon, LL Scinto,
and C. Yu, Emissions Assessment of Conventional Stationary Combustion
Systems: Volume HI. External Combustion Sources for Electricity Generation.
EPA-6QQ/7-81-003a, November 1980,
28. Surprenant, N; R, Hall, S. Slater, T. Susa, M. Sussman, and C. Young.
Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems: Volume II -Final Report. Report prepared by GCA/Technology Division
for the U.S. Environmental Protection Agency. EPA-60Q/2-76-Q46B. March 1976.
29. ORTECH Corporation. MOE Toxic Chemical Emissions Inventory for Ontario
and Eastern North America. Draft Report. Prepared by N.D. Johnson and M.T.
Schultz. Prepared for Ontario Ministry of the Environment, Air Resources
Branch, Rexdale, Ontario. Draft Report No. P89-5Q-5429/OG. March 15, 1990
30. U.S. Environmental Protection Agency, Regional Air Pollution Study - Point
Source Emission Inventory. Publication No. EPA-6QO/4-77-014 (NTIS No. PB
269567), March 1977
31- Locating and Estimating Air Emissions from Sources of Chromium. EPA-450/4-
84-007g, U.S. Environmental Protection Agency, July 1984
Locating and estimating Air Emissions from Sources of Formaldehyde
(Revised). EPA-450/4-91O12, U.S. Environmental Protection Agency, March
1991
33. Estimating Air Toxics Emissions from Coal and Oil Combustion Sources. EPA-
450/2-89-001, Radian Corporation, N.C., RTP, Project Officer: Dallas W.
Safriet, April 1989
Evans, J.C.; K.H. Abel, K.B. Olsen, E.A. Lepel, R.W. Sanders, C.L. Wilkerson,
DJ. Hayes, and N.F. Mangelson from BYU, Provo, Utah. Characterization of
Trace Constituents at 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
4-59
-------
Laboratories, Richland, Washington
35. Meij, Airteru dr. R.; The Fate of Trace Elements at Coal-Fired Plants.
Rapportnummemmer:32561-MOC 92-3641, Rapport te bestellen bij: Bibliotheek
N.V. KEMA, Feruary 13, 1992.
36. Locating and Estimating Air Emissions from Sources of Manganese. EPA-
450/4-84-007h, September 1985
37. Lyon, W.S., Trace Element Measurements at the Coal-Fired Steam Plant. CRC
Press, 1977.
38. EPA/NOAA/NASA/USDA N.Q Workshop V.I. Measurements Studies and
Combustion Sources. EPA-600/8-88-079, U.S. Environmental Protection
Agency, Research Triangle Park, NC, May 1988.
39. EPA Workshop on NLO Emissions from Combustion. EPA-600/8-86-035, U.S.
Environmental Protection Agency, Research Triangle Park and Durham, NC,
February 13-14, 1986.
40. Abbas, T. et. al., "Nitrous Oxide Emissions from and Industry-type Pulverized-
Coal Boiler." Combustion and Flame. 87: 104-108 (1991).
41. Linak, W.P. et. al., "N2O Emissions from Fossil Fuel Combustion," CRB, MD-65,
U.S. Environmental Protection Agency, Research Triangle Park, NC.
42. Oude Uohuis, J.A. et. al., "Parametric Study of N2O Formation in Coal
Combustion," Fuel. Vol. 71, 9-14, January 1992.
43. Khalil, M.A.K. and R.A. Rasmussen, "The Global Sources of Nitrous Oxide,"
Final Report, December 1991.
44. Hao, W.M. et. al., "Sources of Atmospheric Nitrous Oxide from Combustion,"
Journal of Geophysical Research. Vol. 92, No. D3, 3098-3104, March 20, 1987.
45. Hao, W.M. et. al., "Nitrous Oxide Emission from Coal, Oil, and Gas Furnace
Flames," Presented at the Twenty-first International Symposium on Combustion,
1986.
46. Khalil, M.A.K. and R.A. Rasmussen, Nitrous Oxide from Coal Fired Power
Plants: Experiments on the Centralia Power Plant. Final Report, U.S.
Environmental Protection Agency, Research Triangle Park, Research Triangle
Park, NC, December 1991.
47. Anderson, S. "N20 Emission from Fluidized Bed Combustion," Presented at the
IEA AFBC Technical Meeting, Amsterdam, November 1988.
4-60
-------
48. Linak, W.P. et. al, "Nitrous Oxide Emission from Fossil Fuel," Journal of
Geophysical Research. June 1989, Prepared for Submission.
49. Aho, M.J. et a!., "Formation and Destruction of N2O in Pulverized Fuel
Combustion Environments Between 750 and 970 °C," Fuel. Vol. 68, August
1990.
-------
Combustion Sources," ROP No. 43, April 1988.
63. Weiss, R.W. "Combustion Effluent N2O ECD Measurement,"
64. Pierotti, D. and R.A. Rasmussen, "Combustion as a Source of Nitrous Oxide in
the Atmosphere." Geophusical Research Letters. Vol. 3, No. 5, May 1976.
65. Cicerone, R.J. et. al., "Atmosphere N2O: Measurements to Determine its
Sources, Sinks, and Variations," Journal of Geophysical Research. Vol. 83, No.
26, June 20, 1978.
66. Kavanaugh, M. "Estimates of Future CO, N2O and NOx Emissions from Energy
Combustion." Atmosphere Environment. Vol. 21, No. 3, pp. 453-468, 1987.
67. de Soete, G.G. "Formation of N2O from NO and SO2 During Solid Fuel
Combustion," Presented at the Joint EPA/EPRI Symposium on Stationary
Combustion NOX Control, San Francisco, CA, March 6-9, 1989.
68. Kramlich, J.C. et. al., "Mechanisms of NO Formation in Coal Flames,"
Combustion and Flames. December 1987.
69. Weiss, R.F. et. al., "Production of Atmosphere N2O by Combustion,"
Geophysical Research Letters. Vol. 3, No. 12, December 1976.
70. EPA Workshop on N,O Emission from Combustion. EPA-600/8-86-035, U.S.
Environmental Protection Agency, Research Triangle Park and Durham, NC,
February 13-14, 1986.
71. EPA/NOA/NASA/USDA N2O Workshop. EPA-600/8-88-079, Vol. I, Boulder,
CO, September 15-16, 1987.
72. Evaluation of Fuel-based Additives for N-p Air Toxic Control in Fluidized Bed
Combustion Boilers. EPRI Contract No. RP3197-02, Acurex Environmental
Project No. 8407, Mountain View, CA, June 1991.
73. State-of-the-Art Analysis of NOyN O Control for Fluidized Bed Combustion
Power Plants. EPRI Contract No. R>3197-02, Acurex Environmental Final Report
No. 90-102/ESD, Mountain View, CA, July 1990.
74. Mann, M.D. et. al., "Effect of Operating Parameters on N2O Emissions in a 1-
MW CFBC," Presented at the Eighth Annual Pittsburgh Coal Conference,
Pittsburgh, PA, October 1991.
75. Collings, M.E. et. ai, "Nitrous Oxide Emissions in the Fluidized Bed Combustion
of Coal," Presented at the Western States Combustion Institute Spring Meeting,
Corvallis, OR, March 1992.
4-62
-------
76. Mann, M.D. et a!., "Nitrous Oxide Emissions in Fiuidized Bed Combustion:
Fundamentals Chemistry and Combustion Testing," Energy and Combustion
Science. 1992, University of North Dakota, EERC.
77. Henderson, A.K. et. a!., "Design and Operation of the EERC Pilot-Scale
Circulating Fluidized-Bed Combustor," Presented at the Sixteenth Biennial Low-
Rank Fuels Symposium, Billings, Montana, May 1991.
78. 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.
79. Clayton, R. et. al., N.O Field Study. EPA-600/2-89-006, U.S. Environmental
Protection Agency, Research Triangle Park, NC February 1989.
80. Amand, L.E. and S. Anderson, "Emissions of Nitrous Oxide from Fiuidized Bed
Boilers," Presented at the Tenth International Conference on Fiuidized Bed
Combustor, San Francisco, CA, 1989.
81. Bradway, R.M., et. al.. Fractional Efficiency of a Utility Boiler Baghouse. EPA
600/2-75-0133, August 1975.
82. Communication between S. Hughes, Acurex Environmental and C. Young, New
Jersey Air Pollution Control, April 13, 1992.
83. DeWees, W. and K. Steinsberger, Method Development and Evaluation of Draft
Protocol for Measurements of Condensible Particulate Emissions, EPA-450/4-
90-012, May 1990.
84. Muzio, L, et. al., Dry Particulate Removal for Coal-fired Boilers. CS-2894 Vol. 1,
Electric Power Research Institute, March 1983.
85. Mann, M.D., et. al., Fiuidized Bed Combustion of Low Rank Coals, September
1986, DOE/FE/60181-2127
86. Bossart, S.J., Advanced Particle Control Technologies for Pressurized Fiuidized
Bed Combustion Applications. 51st American Power Conference, ASME,
Chicago, 1989.
87. Berry, R.S., et. al., An Examination of EPA's August 1982 Revision of the AP-42
Bituminous Coal SQ^ Emission Factor. Kilkelly Environmental Associates, Inc.,
Utility Air Regulatory Group, April 1984.
4-63
-------
APPENDIX A
BACKGROUND FILE DATA SPOT CHECK SUMMARY
A-1
-------
A review of the 1988 AP-42 version of Section 1.1 was accomplished by spot
checking the quality of existing emission factors. This was sone by selecting primary
data references from the background file, reviewing data quality sampling and analytical
procedures, determining completeness, and verifyuing that the site emission factors in
the background files could be reconstructed and were accurate. The results of these
spot checks are summarized below; the reference numbers correspond to the 1988 AP-
42 Section 1.1 reference list. Example spot check data are presented in Table A-1.
Reference 15
Contains six data points. States in the paper that a sampling was only for
comparative purposes and emission shouldn't be taken as absolute. Couldn't get all
representative sampling locations due to obstruction or bends. Able to recreate
"background" data values in histogram.
Reference 17
Checked "ALMA" site. Particulate tests done with bituminous and subbituminous
coal. Appears two values were averaged and entered in histogram twice.
Sulfur dioxide data are questionable because sulfur analysis was taken from
samples after the blower but HHV is baseed on "as received" coal. Need to eliminate
some anomalous data points. Requires minor adjustment to S02 histograms. Chedked
"ALMA" site. Appears that emission factor was calculated from parametric test
midifying combustion air. Normal operation should be used for emission factor
indicating a revision of the histogram and emission factor.
Reference 18
Sample train was an unproven Method 5 midified to collect HAPs from utility
boilers. Sulfur dioxide based on sulfur retention in bottom ash was acceptable. Carbon
monoxide data were not of good quality but hadd not been used in the previous AP-42
update. Particulate data (uncontrolled) were colleced in an improper sampling location
with poor flow distribution and significant swirl because it was only two diameters from
the inlet breaching. Data should be rated as poor quality but calculated emission factor
(96A) is very close to the AP-42 published average, therefore, inclusion or exclusion is
not significant.
Reference 23
Particulate measurements were nade using currently unapproved APCO and
ASME methods. Correlation between tow methods was not good; test conditions,
methodologies, and data collected were not well-documented (no raw data sheets).
Data quality should be reated no better than C. Calculations were correct.
A-2
-------
Reference 34
Appeared to be a well-codumented test report with good quality measurement
methodology, the source operation, however, appeared to be somewhat variable with
paramenter swings and intermittent periods of fly ash reinjection.
Reference 49
All dat for fireplaces. Several points burning coal in fireplaces. Discard data.
New data available for hand-fed particulate.
Reference 50
No CH4 data. Emission factor given as "estimate", but references 1966 data not
representative of current protocols. Recommend not using current published emission
factor.
Reference 58
No CH4 data for handfed units. All data in this report are for larger utility boilers.
Volatile organic compound data were acceptable.
A-3
-------
TABLE A-1. SOX EMISSIONS FROM PULVERIZED COAL, DRY BOTOM BOILERS
FW
B 17 AJvIA 75
6 1O776 3.66 1 .OO 13.47 1 96/23O
1O3 Ib st/hr
Cold side ESP
Shell-
Emery
Vile
35
5.957
34.9 (S)
N/A
Uses S
sample
HHVis
analysis from blower catch in report. Th
has been ground and dried substantially
taken from 1 as received ultimate analys
Recalculate EF data point with
FW
FW
FW
FW
FW
FW
FW
FW
B 17 AJvIA 75
B 17 AJvIA 75
S 17 AJvIA 75
S 17 AJvIA 75
S 17 AJvIA 75
S 17 AJvIA 75
S 17 AJvIA 75
S 17 AJvIA 75
9 1O776 3.66 1 .OO 13.47 57/23O
1O3 Ib st/hr
16 1O776 3.66 1 .OO 13.47 6O/23O
1O3 Ib st/hr
63 9336 O.81 O.73 17.26 131/23O
1O3 Ib st/hr
64 9336 O.81 O.73 17.26 1 7O/23O
1O3 Ib st/hr
72 9336 O.81 O.73 17.26 1O1/23O
1O3 Ib st/hr
73 9336 O.81 O.73 17.26 94/23O
1O3 Ib st/hr
74 9336 O.81 O.73 17.26 9O/23O
1O3 Ib st/hr
75 9336 O.81 O.73 17.26 1 6O/23O
1O3 Ib st/hr
Cold side ESP
Cold side ESP
Cold side ESP
Cold side ESP
Cold side ESP
Cold side ESP
Cold side ESP
Cold side ESP
Shell-
Emery
Vile
Shell-
Emery
Vile
Shell-
Emery
Vile
Shell-
Emery
Vile
Shell-
Emery
Vile
Shell-
Emery
Vile
Shell-
Emery
Vile
Shell-
Emery
Vile
4O
12
2
28
29
67
SO
68
58
6.396
37.5 (S)
N/A
4.9O5
28.7 (S)
N/A
2.888
66.6 (S)
1.44O
33.2 (S)
2.387
55 (S)
1.799
41.5 (S)
1.4O7
32.4 (S)
1.367
31.5
ulimate analysis
Previous average appears to be 335. New avera
would be 33.7(S) but 12.2% O2
low load, probably should drop
sheets
is very high and
. No sampling d;
in this reference; they are contained in
EPA6OO1 7-78-1 -55b.
aFW-Front wall-fired pulverized coal boiler.
bB-Bituminous coal, S-Subbituminous coal.
•"Reference numbers as cited in 1988 AP-42 Section 1.1.
-------
TABLE A-2. NOX EMISSIONS FROM PULVERIZED COAL, DRY BOTTOM BOILERS
Boiler Fuel Refer
Type
ence Site Data
Date
FW B 17 ALMA 75
FW B 17 ALMA 75
FW B 17 ALMA 75
FW B 17 ALMA 75
FW B 17 ALMA 75
FW S 17 ALMA 75
FW S 17 ALMA 75
FW S 17 ALMA 75
Run
No.
5O
25
42
47
49
57A
57A
68
Fue
HHV S% N%
Btu/lb,
Btu/g
1O776 3.66 1.O
Operation Samp
Ash% Load/ Method
Capacity
9 13.47 2OO/23O Teco 1O
1O3 Ib styhr
1O776 3.66 1.O9 13.47 2OO/23O
1O3 Ib styhr
1O776 3.66 1.O
9 1 3.47 2OO/23O
1O3 Ib styhr
1O776 3.66 1.O9 13.47 2OO/23O
1O3 Ib styhr
1O776 3.66 1.O
9 1 3.47 2OO/23O
1O3 Ib styhr
9336 O.81 O.73 17.26 1 7O/23O
1O3 Ib styhr
9336 O.81 O.73 17.26 1 7O/23O avgsinlade
1O3lbs17hr 5.1-1O
9336 O.81 O.73 17.26 1 7O/23O
1O3 Ib styhr
ling Emission
02% UC, C
# NO,
1 O3 Btu
5.2 O.935
3.8 O.834
2.9 O.785
3.7 O.86O
1.8 O.481
5.7 O.958
25.1% of
fuel N
2.7 O.469
Remarks
Presented in summary table = 2O.1 5 + 15.5. Burner difl
varied from normal, high O2.
EF-1 7.97 Air Reg. as found.
EF-1 6.9 as found.
EF-1 8. 54 Air Reg. as found.
EF-1 0. 36
Burners varied. Low O2 appears EF based on parametric
tests No. 47, 49, SO-yielding 15.2 normal operation wou
better described by "as found" No. 25, 42, 47-yielding EF
Chosen for summary table EF-1 7.89 old EFD value - 1 2 (
high load test w/o modifying air.
EF-1 2.O4 but includes averages from all parametric test;
including 25% and 5O% loads.
CO high, 75O ppm, ignore EF-8.76.
aFW-front wall-fired pulverized coal boiler.
bB-Bituminous coal, S-Subbituminous coal.
•"Reference numbers as cited in 1988 AP-42 Section 1.1.
-------
TABLE A-3. PM EMISSIONS FROM PULVERIZED COAL, DRY BOTTOM BOILERS
Boiler
Type
Fuel
Reference
Site
Data
Date
Run
No.
Fuel
HHV
Btu/lb,
Btu/g
Operation
Load/
Capacity
Sampling
Method
O2%
Emission
UC, C
# NO,
1 O3 Btu
Emission Factor
HO
HO
FW
15
15
Hartlee #3 72
Hartlee #3 72
Hartlee #3 72
Four Corners #4 72
Four Corners #4 72
Widows Creek#6 72
Widows Creek#6 72
Barry #3 73
Barry #3 73
1 1477
127O6
12641
49O/48O
488/48O
483/48O
755/8OO
755/8OO
125/125
128/125
293/36O
283/3 6O
5.O
4.5
7.89
2.O
5.14
9.72A
21.92A
15.87A
18.39A
4.89A
4.86A
FW= Front Wall.
HO = Horizontally opposed pulverized coal boiler.
T = tangentially fired pulverized coal boiler.
B = Bituminous coal, S- Subbituminous coal.
Reference numbers as cited in 1988 AP-42 Section 1.1.
A-6
-------
APPENDIX B
CONVERSION FACTORS
B-4
-------
TABLE B-1. CONVERSION FACTORS
Given
ppm
Ib/MBtu
Ib/ton
HHV dry, mineral matter
free
To Obtain
Ib/MBtu
Ib/ton
kg/Mg
HHV (as rec'd)
Multiply By
2.59X10-9(MW)Fd
(20.9/20.9-02) Where Fd
from 40 CFR Part 60
Appendix A
M1 9 -usually 9820
HHV (as rec'd) =
2, 000/1 06
0.5
(100-M-A)/100
MW = Molecular weight of pollutant.
02 = Oxygen concentration at sampling point in percent.
M = Moisture in as received coal sample in percent.
A = Ash in as received coal sample in percent.
B-5
-------
APPENDIX C
MARKED-UP 1988 AP-42 SECTION 1.1
C-6
-------
REPORT ON REVISIONS TO
5TH EDITION AP-42
SECTION 1.1
Bituminous and Subbituminous
Coal Combustion
Prepared for:
Contract No. 68-D2-0160, Work Assignment 92
EPA Work Assignment Officer: Roy Huntley
Office of Air Quality Planning and Standards
Office of Air and Radiation
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Prepared by:
Eastern Research Group
Post Office Box 2010
Morrisville, North Carolina 27560
October 1996
-------
Table of Contents
Page
1.0 INTRODUCTION 1-1
2.0 REVISIONS 2-1
2.1 General Text Changes 2-1
2.2 Sulfur Oxides, SOX 2-1
2.3 Nitrogen Oxides, NOX 2-1
2.4 Carbon Monoxide, CO 2-3
2.5 Filterable Paniculate Matter (PM) and PM Less Than 10 Microns (PM-10) . . 2-3
2.6 Particle Size Distribution, PSD 2-3
2.7 Total Non-Methane Organic Compounds, TNMOC 2-3
2.8 Greenhouse Gases 2-3
2.9 Toxic Air Pollutants 2-6
3.0 REFERENCES 3-1
4.0 REVISED SECTION 1.1 4-1
5.0 EMISSION FACTOR DOCUMENTATION, APRIL 1993 5-1
Appendix A
-------
1.0 INTRODUCTION
This report supplements the Emission Factor (EMF) Documentation for AP-42 Section
1.1, Bituminous and Subbituminous Coal Combustion, dated April, 1993. The EMF describes
the source and rationale for the material in the most recent updates to the 4th Edition, while this
report provides documentation for the updates written in both Supplements A and B to the 5th
Edition.
Section 1.1 of AP-42 was reviewed by internal peer reviewers to identify technical
inadequacies and areas where state-of-the-art technological advances need to be incorporated.
Based on this review, text has been updated or modified to address any technical inadequacies or
provide clarification.
Emission factors for criteria pollutants were checked for accuracy with information in the
EMF Document and new emission factors generated if recent test data were available. If
discrepancies were found when checking the factors with the information in the EMF Document,
the appropriate reference materials were then checked. In some cases, the factors could not be
verified with the information in the EMF Document or from the reference materials, in which
case the factors were not changed.
The emission factors for toxic air pollutants in Section 1.1 were not examined; however,
emissions data from several sources were evaluated for toxic emission factors of sufficient
quality that could replace existing factors of relatively lower quality or that would be added to the
section as new factors. None of the existing toxic emission factors were replaced, but many new
factors were added as a result of the evaluation.
Four sections follow this introduction. Section 2 of this report documents the revisions
and the basis for the changes. Section 3 presents the references for the changes documented in
this report. Section 4 presents the revised AP-42 Section 1.1, and Section 5 contains the EMF
documentation dated April, 1993.
1-1
-------
2.0 REVISIONS
This section documents the revisions made to Section 1.1 of the 5th Edition of AP-42.
2.1 General Text Changes
Text was clarified or added concerning coal rank, firing practices, emissions, and
controls. The table presenting NOX controls for stoker coal-fired boilers was modified to include
NOX controls for all types of coal-fired boilers. Also, at the request of EPA, metric units were
removed.
2.2 Sulfur Oxides. S(X
The SOX emission factors were checked against information in Table 4-2 of the EMF
Document and no changes were required.
2.3 Nitrogen Oxides. MX
The NOX emission factors were checked against information in Table 4-3 of the EMF
Document and no changes were required. However, data were available to create an emission
factor for a new firing configuration—cell burner fired boilers. The cell burner boiler is a special
type of an opposed wall-fired boiler that has two or three closely (vertically) spaced burners
(referred to as a "cell"). Cell burner boilers can emit up to twice as much NOX as typical wall-
fired boilers due to higher heat release rates, higher combustion temperatures, and more
turbulence in the primary combustion zone. All of these factors contribute to higher NOX levels.
2-1
-------
Data for six cell burner units from four references were reviewed.(1"4) The data ranged from 18.5
Ib/ton to 44.4 Ib/ton, with an average of 31 Ib/ton. The data are summarized in Table 1.2.4.
-------
o
Table 1. Summary of Cell Burner Data
CO
o
O
OQ
O
O
H
Reference3
1
1
1
1
1
2
1
1
3
4
4
Overall Rating:
Average
Data
Rating
B
B
B
B
B
C
B
B
C
B
B
C
Unit
Cumberland 1
Cumberland 2
Cumberland 2
Four Corners 4
Four Corners 4
Four Corners 4
Harlee Branch 3
Harlee Branch 3
Four Corners 5
J.M. Stuart 4
J.M. Stuart 4
Capacit
y(MW)
1300
1300
1300
800
800
800
480
480
800
610
610
Coal Type
Bit (1)
Bit (1)
Bit (1)
Subbit (2)
Subbit (2)
Subbit (3)
Bit (2)
Bit (2)
Subbit (4)
Bit (2)
Bit (2)
Heating Value,
Btu/lb
13064
13016
13016
13016
13000
13000
13848
13000
13848
13000
13000
Tested
Load, %
78
95
100
75
95
100
83
100
93
75
100
NOX
Ib/mmBtu
1.7
1.5
1.4
1.08
1.09
1.27
0.71
0.95
1.15
0.92
1.22
1.18
NOX
Ib/ton
44.42
39.05
36.44
28.08
28.34
35.17
18.46
24.70
31.85
23.92
31.72
31.10
I
3
fa
'
H
fa
Heating Value Notes:
(1) From reference, p. 102
(2) Typical value, AP-42, 5th Edition, Appendix A
(3) Estimated from Four Corners 5 data in Reference 5
(4) From Reference 4
aREFERENCES:
-------
2.4 Carbon Monoxide. CO
The CO emission factors were checked against information in Table 4-4 of the EMF
Document and no changes were required.
2.5 Filterable Paniculate Matter (PM) and PM Less Than 10 Microns (PM-10^)
The filterable PM and PM-10 emission factors were checked against Table 4-2 of the
EMF Document and remain the same as in the 7/93 version of AP-42.
2.6 Particle Size Distribution. PSD
The PSD emission factors for dry bottom boilers, wet bottom boilers, cyclone furnaces,
spreader stokers, overfeed stokers, and underfeed stokers were checked against information in the
EMF Document and the 9/88 version of AP-42. There were no changes required.
2.7 Total Non-Methane Organic Compounds. TNMOC
The TNMOC emission factors were checked against information in the EMF Document
and no changes were necessary.
2.8 Greenhouse Gases
2.8.1 Carbon Dioxide, CO2
The CO2 emission factors provided in the footnotes to Tables 1.1-1 and 1.1-2 were based
on 100% conversion of fuel carbon content to CO2. References 5-8 suggest that 99% is a more
accurate conversion factor for solid fuel combustion. Therefore, the conversion factor in the
footnotes of Table 1.1-1 was changed from 73.3C to 72.6C.
2-4
-------
In case an ultimate analysis is not available, default CO2 emission factors for U.S. coals
were computed based on the conversion factor presented above and average carbon content (dry
basis) for each class of coal. Several references were located that listed carbon content of U.S.
coals. These reference sources were then compared and default emission factors were computed
based on the average of all reference sources for the bituminous and subbituminous coals in
Table 2. Because of the geographical variance of carbon content within each subtype, these
default factors were assigned a "C" rating.
Table 2. Default CO2 Emission Factors for U.S. Coals
Emission Factor Rating: C
Coal Type
Subbituminous
High- Volatile Bituminous
Medium- Volatile Bituminous
Low- Volatile Bituminous
Average
%ca
66.3
75.9
83.2
86.1
Conversion
Factor"
72.6
72.6
72.6
72.6
Emission Factor
(Ib CO2/ton coal)
4810
5510
6040
6250
An average of the values given in References 9-12. Each of these references listed
average carbon contents for each coal type (dry basis) based on extensive sampling of
U.S. coals.
Based on the following equation:
44 ton CO
2
12 ton C
x 0.99 x 2000-
Ib CO
2
ton C09
100^
= 72.6
Ib CO
2
ton - %C
Where: 44 = molecular weight of CO2;
12 = molecular weight of carbon; and
0.99 = fraction of fuel oxidized during combustion (Reference 6).
2-5
-------
2.8.2 Methane, CH4
No data were found to improve the current "B" rated CH4 emission factors for bituminous
and subbituminous coal combustion in Tables 1.1-11 and 1.1-12.
2.8.3 Nitrous Oxide, N2O
The existing N2O emission factors for coal combustion in Table 1.1-11 were "E" rated
and may possibly be based on test data obtained before the discovery of a testing artifact that
caused erratic readings in test samples.(13) The following emission factors are based on source
test data obtained since the discovery of the N2O testing artifact and were obtained using proper
testing protocols.
Table 3. Emission Factors for Coal Combustion in Section 1.1
(Ib N2O/ton coal)
Combustion Category
Fluidized bed - utility
Pulverized coal - utility
Spreader-stoker - utility
Tangentially fired - utility / industrial
Wall fired - utility / industrial
New
B
D
D
B
B
New
3.5a
0.04b
0.04b
0.08a
0.3a
Previous
5.5
0.09
0.09
0.03
0.09
Previous AP-42
E
E
E
D
D
a References 14, 15.
b References 16, 17.
The fluidized bed emissions data are based on 17 source tests at 5 different facilities
collected by Nelson.(14) This data were regressed and emission factors were developed by Peer.(15)
The pulverized coal and spreader-stoker factor is based on data taken at six coal-fired power
plants collected by Montgomery(16) and analysis of this data conducted by Piccot.(17) The
tangentially-fired data are based on 24 source tests at 10 different facilities collected by Nelson.
2-6
-------
The wall-fired data are based on 15 source tests conducted at 7 different facilities collected by
Nelson.
The data sets were converted to pounds per million BTU (Ib/MMBtu) according to the
procedures given in 40 CFR 60, Appendix A. To obtain Ibs/MMBtu, the emissions (in ppm)
were first multiplied by 1.141 x 10~7 (lb/scf)/ppm. These values were then converted to
Ib/MMBtu using the following formula:
E - C F f 20'9
d d I 20.9 - %CX
Where: Cd = N2O concentration (Ib/scf);
Fd = Fuel factor (F-factor) for coal; and
%O2 = oxygen concentration in the exhaust gas.
An F-factor of 9,780 scf/MMBtu was used for bituminous coal. Lb/MMBtu values were then
converted to mass-based emission factors using a heating value of 13,000 Btu/lb for bituminous
coal (AP-42 Appendix A).
2.9 Toxic Air Pollutants
The existing toxic emission factors in Section 1.1 were not replaced but an evaluation of
toxic emissions data resulted in the development of new factors that were added to the section.
Most of the emissions data were stack test reports that presented emission factors, or reports that
presented emissions and process data from which emission factors were developed. The
following sections describe the documents evaluated and the methods used to develop the toxic
emission factors.
2-7
-------
2.9.1 General Document Evaluation and Emission Factor Development
Section 1.1, Bituminous And Subbituminous Coal Combustion and Section 1.7, Lignite
Combustion were updated simultaneously and, therefore, emissions data from both types of
combustion were of interest during the emissions data evaluation.
The focus of the emissions data evaluation was on toxic air pollutants, especially metals.
Several documents provided emissions data for compounds that are not considered hazardous air
pollutants and these data were not used to develop emission factors. Because of the limited
scope of the emission factor development project, some data for toxic air pollutants were not
used. Emissions data for radionuclides were encountered but were not used because the list of
potential radionuclide emission factors is quite extensive. Emissions data for dioxins/furans
were not used unless data for the tetra— through octa— homologue groups were provided.
Because of budget constraints, the document evaluation concentrated on air emissions, or
final stack emissions, only. Emissions data obtained from sampling at control device inlets, or
outlets of intermediate control devices, were not used to develop emission factors.
Following EPA guidance, the emission factors developed for Section 1.1 of AP-42 are
expressed in units of pound of pollutant emitted per ton of coal fired (Ib/ton). Thus, the
emissions documents were evaluated in order to identify emission factors, or information from
which emission factors could be developed, in units of Ib/ton. Many of the documents presented
emission factors, but they were in units of pound of pollutant emitted per million British thermal
units of heat input (Ib/MMBtu). In such cases, a higher heating value (HHV) for coal in units of
Btu/lb was used to convert the factor to units of Ib/ton. Several of the documents provided
emissions and process information, such as emission rates and coal feed rates, that were used to
develop emission factors. Some of the documents provided coal data, such as the HHV and coal
feed rate, on a dry-basis. When the moisture content of the coal was provided, the dry-basis data
were converted to as-fired, or as-received, data. The methods used for each document to develop
the emission factors are described in Section 2.9.2 Description Of Documents Evaluated.
2-8
-------
The majority of the documents evaluated were emissions test reports obtained from
various sources. One source of emissions information was test reports provided by the Electric
Power Research Institute (EPRI) and the U.S. Department of Energy (DOE). EPRI and DOE
conducted an extensive emissions test program at several coal-fired power plants in order to
characterize their emissions. Most of the individual facility test reports and the summary report
of the test program were provided to EPA for use in emission factor development.
Another source of information was several emissions test reports from coal-fired power
plants provided to EPA by the Northern States Power Company (NSP). In addition, several test
reports obtained by EPA from other sources were evaluated.
A computer spreadsheet was constructed for each document where calculations were
required to develop and characterize emission factors from information presented in the
document. A spreadsheet was created for every reference except Reference 18. Reference 18 is
a summary of an emissions test program conducted by EPRI and DOE. The spreadsheets were
used as mathematical tools and as a means of documenting all calculations and assumptions.
Also, information from each document that was used to characterize the emission factors was
included in the spreadsheets. For example, information provided about the boiler(s) tested was
used to assign a source classification code (SCC). In addition, any control devices in use by the
emission source were noted. The spreadsheets are included in Appendix A.
When assigning SCCs to an emission source described in a reference, the boiler was
assumed to be dry bottom unless the document specified that the boiler was wet bottom or
mentioned an ash removal method that would be indicative of a wet bottom boiler. All emission
controls described by the reference as being in use at the time the emissions data were collected
were noted and no attempt was made to judge the effect of a control device on any of the
sampled pollutants. Emissions data were characterized as "uncontrolled" unless there was no
type of pollution control device at all in use when the emissions data were collected.
2.9.2 Description of Documents Evaluated
2-9
-------
The following paragraphs provide a summary of the information presented in each
document that was evaluated for emission factors. Also, the methods used to develop emission
factors from the information provided in each document are described. The computer
spreadsheets that were constructed for each document (except Reference 18) are contained in
Appendix A. The text descriptions are provided as a supplement to the spreadsheets in order to
ensure that the development of all emission factors is fully explained.
Reference 18
This document summarizes the results of the emissions test program conducted by EPRI
and DOE. This document presents emission factor equations for nine trace metals and emission
factors for five organic pollutants that were developed from emissions data collected during the
test program. The emission factor equations were judged to be of sufficient quality for inclusion
in AP-42 and are presented there "as is," i.e., no adjustments or conversions were made. The
organic emission factors were not used for AP-42 because they are a geometric, instead of
arithmetic, mean. The reference was assigned a data quality rating of "A." The emission factor
equations are discussed in detail in Section 2.9.3 Emission Factor Development.
Reference 19
This reference presents the results of an emissions test at the NSP Sherco Plant located in
Becker, Minnesota. The boiler tested was Unit Three, which is an 860 megawatt (MW) Babcock
and Wilcox (B&W) unit which came on line in 1987. The boiler was firing pulverized
subbituminous coal from Montana during the emissions test. Emission controls utilized during
the emissions test were a spray dryer absorber and a baghouse.
Three sampling runs were conducted for dioxins/furans, and the emissions test results are
reported as emission rates in units of grams per second (g/sec). The reference indicates that all
sampling results were above the detection limits. Emission rates in units of g/sec were converted
to pounds per hour (Ib/hr).
2-10
-------
The report did not provide coal feed rates or the HHV of the coal fired during the
emissions tests. A fuel factor (F-factor) for coal of 9,780 dry standard cubic feet per MMBtu
(dscf/MMBtu), provided in 40 Code of Federal Regulations (CFR) Part 60 Appendix A Method
19, and the stack gas volumetric flow rate, dry standard cubic feet per hour (dscf/hr) were used to
develop an energy input rate in MMBtu/hr. An HHV of 8,547 Btu/lb, provided in another stack
test report (Reference 25) from the same facility was used to convert the energy input rate to a
coal feed rate in units of ton/hr. The dioxin/furan emission rates (Ib/hr) were then divided by the
coal feed rate to arrive at emission factors in Ib/ton.
A data quality rating of "C" was assigned to the reference because the coal feed rate
during the emissions tests and the HHV of the coal were not provided.
Reference 20
This document presents the results of two emissions tests conducted at the NSP Sherco
plant in Becker Minnesota. One emission test was conducted on Unit Three, which is a B&W
860 MW boiler firing pulverized subbituminous coal from Montana. Unit Three came on line in
1987. Emissions controls utilized during the test were a spray dryer absorber and a baghouse.
The second emissions test was performed simultaneously on Units One and Two, which
are identical Combustion Engineering 750 MW boilers which came on line in 1976. During the
tests, both boilers were firing 70% Wyoming and 30% Montana pulverized subbituminous coal.
Emissions from Units One and Two were controlled by a venturi scrubber spray tower during the
emissions tests.
Both emissions tests consisted of three sampling runs for mercury and the results are
presented as emission rates in units of Ib/hr. The reference indicates that all sampling results
were above the detection limits. In addition, the document presents the coal feed rates in ton/hr
during both tests. Mercury emission factors in units of Ib/ton were developed by dividing the
emission rates by the coal feed rates.
2-11
-------
The document was assigned a data quality rating of "A."
Reference 21
This reference presents the results of an emissions test conducted simultaneously on the
Number One, Number Three, and Number Four boilers at the NSP Black Dog Plant located in
Burnsville, Minnesota. The boilers are water tube boilers and were fired with pulverized
subbituminous coal from the Antelope and North Antelope mines during the test. Emissions
controls utilized during the test were two electrostatic precipitators (ESPs) in series.
The emissions test consisted of three sampling runs for metals and the results are
presented as emission rates in units of Ib/hr. Full detection limit values were used to develop
emission rates for pollutants that were not detected in any sampling run. Stack gas volumetric
flow rates presented in the report (dscf/hr) and an average F-factor for coal of 9,780 dscf/MMBtu
were used to develop an energy input rate in units of MMBtu/hr. The reference provides an
HHV for the coal fired during the emissions test of 8,707 Btu/lb on an as-received basis. This
value was used to convert the energy input rate to a coal feed rate in ton/hr. The emission rates
were divided by the coal feed rate to arrive at emission factors in units of Ib/ton.
The document was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 22
The results of an emissions test conducted on the Number Two boiler at the NSP Black
Dog plant in Burnsville, Minnesota, are presented in this report. The Number Two boiler is a
137 MW Foster-Wheeler atmospheric fluidized bed combustor (AFBC). At the time of the
emissions test, Unit Two was firing 100% Western coal (blend of Antelope and Northern
Antelope), which is subbituminous coal. Emission control devices in use during the test were a
mechanical dust collector and two ESPs in series.
2-12
-------
Three sampling runs were conducted for metals and the results are presented as emission
rates in units of Ib/hr. Full detection limit values were used to develop emission rates for
pollutants that were not detected in any sampling run. Stack gas volumetric flow rates (dscf/hr)
provided in the document and an average F-factor for coal of 9,780 dscf/MMBtu were used to
develop an energy input rate in units of MMBtu/hr. The reference provides an FtHV for the coal
fired during the emissions test of 8,553 Btu/lb on an as-received basis. This value was used to
convert the energy input rate to a coal feed rate in ton/hr. The emission rates were divided by the
coal feed rates to arrive at emission factors in units of Ib/ton.
2-13
-------
The reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 23
This reference presents the results of an emissions test conducted simultaneously on the
Number Three, Number Four, Number Five, and Number Six boilers at the NSP High Bridge
plant in St. Paul, Minnesota. All of these boilers are B & W boilers and are equipped to fire
pulverized coal. During the test, the boilers were fired with subbituminous coal from the
Rochelle mine. A coldside ESP was in use during the emissions test.
Three sampling runs were conducted for metals, benzene, toluene, ethylbenzene, and
xylene and the results are presented as emission rates in units of Ib/hr. All sampling results for
metals were above the detection limits. Benzene, toluene, ethylbenzene, and xylene were not
detected in any sampling run and no emission factors for these pollutants were developed. Stack
gas volumetric flow rates (dscf/hr) provided in the document and an average F-factor for coal of
9,780 dscf/MMBtu were used to develop an energy input rate in MMBtu/hr. The reference
presents an FtHV for the coal fired during the emissions test of 8,498 Btu/lb on an as-received
basis. This value was used to convert the energy input rate to a coal feed rate in ton/hr. The
emission rates were divided by the coal feed rates to arrive at emission factors in units of Ib/ton.
This reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 24
This document presents the results of emissions tests conducted on the Units Six and
Seven at the NSP Riverside plant in Minneapolis, Minnesota. These boilers are pulverized
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coal-fired boilers and were firing subbituminous coal from the Rochelle mine during the
emissions tests. Emission controls in use during the test consisted of a baghouse.
Three sampling runs were conducted for metals, benzene, toluene, ethylbenzene and
xylene. For metals, the emissions data from both units were combined and presented as emission
rates in units of Ib/hr. The benzene, toluene, ethylbenzene and xylene emissions data are
presented separately for each unit as emission rates in Ib/hr. All sampling results for metals were
above the detection limits. Toluene, ethylbenzene, and xylene were not detected in any sampling
run and no emission factors for these pollutants were developed. Stack gas volumetric flow rates
(dscf/hr) provided in the document and an average F-factor for coal of 9,780 dscf/MMBtu were
used to develop an energy input rate in MMBtu/hr. The reference provides an FtHV for the coal
fired during the emissions test of 8,602 Btu/lb on an as-received basis. This value was used to
convert the energy input rate to a coal feed rate in ton/hr. The emission rates were divided by the
coal feed rates to arrive at emission factors in units of Ib/ton.
The reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 25
The results of an emissions test conducted simultaneously on Units One and Two at the
NSP Sherburne County Generating Station located in Becker, Minnesota, are presented in this
reference. The units are identical Combustion Engineering 750 MW boilers which came on line
in 1976 and were fired with 80% Rochelle and 20% Coalstrip pulverized subbituminous coal
during the test. The boilers were controlled by a wet limestone scrubbing system consisting of
twelve individual rod venturi scrubber spray towers during the test.
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Three sampling runs were conducted for metals and the results are presented as emission
rates in units of Ib/hr. Full detection limit values were used to calculate emission rates for
pollutants that were not detected in any sampling run. Stack gas volumetric flow rates (dscf/hr)
provided in the document and an average F-factor for coal of 9,780 dscf/MMBtu were used to
develop an energy input rate in MMBtu/hr. The reference provides an FtHV for the coal fired
during the emissions test of 8,547 Btu/lb on an as-received basis. This value was used to convert
the energy input rate to a coal feed rate in ton/hr. The emission rates were divided by the coal
feed rates to arrive at emission factors in units of Ib/ton.
The reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 26
This document presents the results of an emissions test conducted simultaneously on
Units One and Two at the NSP Sherburne County Generating Station located in Becker,
Minnesota. The units are identical Combustion Engineering 750 MW boilers which came on line
in 1976. The document does not specify the type of coal being fired during the tests. Two other
test reports from this facility are included in this documentation (References 25 and 19) and the
boilers were firing pulverized subbituminous coal during those tests. Thus, it was assumed that
the boilers were firing pulverized subbituminous coal during the tests described in this reference.
Emissions were controlled by a wet limestone scrubbing system consisting of twelve individual
rod venturi scrubber spray towers during the emissions test.
Three sampling runs were conducted for metals and the results are presented as emission
rates in units of Ib/hr. Full detection limit values were used to develop emission rates for
pollutants that were not detected in any sampling run. Stack gas volumetric flow rates (dscf/hr)
provided in the document and an average F-factor for coal of 9,780 dscf/MMBtu were used to
develop an energy input rate in MMBtu/hr. The reference does not provide an FtHV for the coal
fired during the emissions test and, therefore, an FtHV for coal of 8,547 Btu/lb presented in
Reference 25 (test report from the same facility) was used to convert the energy input rate to a
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coal feed rate in ton/hr. The emission rates were divided by the coal feed rates to arrive at
emission factors in units of Ib/ton.
The reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 27
The results of an emissions test conducted on Unit Three at the NSP Sherburne County
Generating Station located in Becker, Minnesota, are presented in this document. Unit Three is a
B & W 860 MW boiler which came on line in 1987 and was fired with pulverized subbituminous
coal from Montana during the emissions test. The boiler was controlled by a spray dryer
absorber and a baghouse during the emissions test.
Three sampling runs were conducted for metals and the results are presented as emission
rates in units of Ib/hr. Full detection limit values were used to develop emission rates for
pollutants that were not detected in any sampling run. Stack gas volumetric flow rates (dscf/hr)
provided in the document and an average F-factor for coal of 9,780 dscf/MMBtu were used to
develop an energy input rate in MMBtu/hr. The document does not provide an HHV for the coal
fired during the test and, therefore, an HHV for coal of 8,547 Btu/lb presented in Reference 25
(test report from the same facility) was used to convert the energy input rate to a coal feed rate in
ton/hr. The emission rates were divided by the coal feed rates to arrive at emission factors in
units of Ib/ton.
The reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
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Reference 28
This reference presents the results of emission testing at a facility designated as EPRI Site
10. The boiler at this site is a fluidized bed combustor capable of producing approximately 100
MW of power at full load. According to the EPRI Synthesis Report (Reference 18), the boiler is
a circulating bed AFBC and was firing subbituminous coal during the tests. Emissions controls
utilized during the tests were flue gas desulfurization (FGD) by limestone injection into the
boiler combustion chamber and a fabric filter.
Test sampling runs were conducted for metals and organics. Because of a forced boiler
outage, only one sampling run was conducted for all compounds except benzene. Five samples
for benzene were collected at a later date. Full detection limit values were used to develop
emission factors for pollutants that were not detected in any sampling run.
Emissions test results for dibutyl phthalate, bis(2-ethylhexyl), and
N-nitrosodimethylamine are presented as concentrations in units of microgram per Normal cubic
meter (//g/Nm^). The reference indicates that all sampling results for these pollutants were
above the detection limits. The concentrations were converted to units of pounds per dry
standard cubic feet (Ib/dscf) and multiplied by the stack gas volumetric flow rate (dscf/hr) to
arrive at an emission rate in Ib/hr. The reference presents a dry-basis coal feed rate of 108,626
Ib/hr during the test and a coal moisture percent of 7.3. The dry coal feed rate was divided by
100% minus 7.3% (92.7%) to obtain a coal feed rate, as fired, of 117,180 Ib/hr. The emission
rates for the three pollutants were divided by the coal feed rate, as fired, to obtain emission
factors in units of Ib/ton.
The emissions results for the other compounds are presented as emission factors in units
of lb/1012 Btu. Full detection limit values were used to develop emission factors that are based
only on sampling results that were below detection limits. The reference presents an HHV for
the coal of 11,000 Btu/lb on a dry basis. The dry-basis HHV was divided by 100% plus 7.3%
(107.3%) to obtain a HHV of 10,252 Btu/lb for the coal, as fired. The as-fired coal HHV was
used to convert the emission factors in units of lb/l()12 Btu to factors in units of Ib/ton.
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This reference was assigned a data quality rating of "A."
Reference 29
This document presents the results of emissions testing at a facility designated as EPRI
Site 11. The boiler tested is a 700 MW Combustion Engineering dry bottom, tangentially fired
unit with pulverized subbituminous coal from the Power River basin. Emission controls utilized
during the test were over-fire air, an ESP, and a wet limestone scrubber/absorber.
Three sampling runs were conducted for metals, formaldehyde, and naphthalene and the
results are presented as emission factors in units of Ib/MMBtu. However, Run Three was invalid
because of suspected contamination. For Run One, the vapor phase samples were lost and,
therefore, were not analyzed. Emissions results for the solid phase of Run One and the Run Two
solid and vapor phase results were used to calculate the average emission factors presented in the
report. Rather than convert the emission factors presented in the reference from lb/l()12 Btu to
Ib/ton, the data from Run Two were used to develop emission factors. Pollutant concentrations
in jUg/Nm^ provided in the report for Run Two were converted to Ib/dscf and then multiplied by
the stack gas volumetric flow rate (dscf/hr) provided in the report to obtain emission rates in
Ib/hr. Full detection limit values were used to develop emission rates for pollutants that were not
detected. An F-factor for coal of 9,780 dscf/MMBtu and the stack gas volumetric flow rate
(dscf/hr) were used to calculate an energy input rate in MMBtu/hr. The reference presents an
FtHV for the coal fired during the emissions test of 8,300 Btu/lb, as received. This value was
used to convert the energy input rate to a coal feed rate in ton/hr. The pollutant emission rates
were divided by the coal feed rate to obtain emission factors in units of Ib/ton.
This reference was assigned a data quality rating of "B" because the coal feed rate was not
provided.
Reference 30
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The results of emissions testing at a facility designated as EPRI Site 12 are presented in
this report. The boiler at Site 12 is an approximately 700 MW which commenced commercial
operation in the mid-1980's. The boiler is a B & W balanced draft, opposed-wall, natural
circulation, pulverized coal-fired, dry bottom boiler. The boiler was firing western Pennsylvania
bituminous coal and was controlled by a wet limestone scrubber and ESP during the emissions
test.
Three sampling runs were conducted for metals and organics, however, one of the metals
runs was declared invalid because of a sample processing error. The emissions results are
presented as emission factors in units of Ib/10l2 Btu. Full detection limit values were used to
develop emission factors that are based only on results that were below detection limits. The
reference provides an average HHV for the coal fired during the emissions test of 13,733 Btu/lb
on a dry basis and a coal moisture content of 4.12% The dry-basis HHV was converted to an
as-fired basis by dividing 13,733 Btu/lb by 104.12%, resulting in an HHV of 13,190 Btu/lb. The
as-fired coal HHV was used to convert the emission factors in units of lb/l()12 Btu to factors in
units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 31
This reference presents the results of emissions testing at a facility designated as EPRI
Site 15. Site 15 has a boiler with a capacity of approximately 600 MW which began commercial
operation in 1970. The boiler is a tangentially fired furnace manufactured by
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Combustion Engineering and was firing pulverized Eastern bituminous coal during the emissions
test. The pollution control system in use during the test consisted of an ESP.
Three sampling runs were conducted for metals and organics and the results are presented
as emission factors in units of lb/l()12 Btu. Full detection limit values were used to develop
emission factors that are based only on results that were below detection limits. The reference
provides an HHV for the coal fired during the test of 13,000 Btu/lb, which was assumed to be on
an as-fired basis. This value was used to convert the emission factors in units of lb/l()12 Btu to
factors in units of Ib/ton.
A data quality rating of "A" was assigned to this reference.
Reference 32
The results of emissions testing at a facility designated as EPRI Site 19 are presented in
this report. The boiler tested at Site 19 is a B & W opposed, wall-fired unit and was burning
bituminous coal from western Virginia and Kentucky during the emissions test. An ESP was in
use during the test.
Three sampling runs were conducted for various metals. The results for antimony,
beryllium, and cobalt are presented as concentrations in units of microgram per Normal cubic
meter. The results for the three compounds were above detection limits for all sampling runs.
The concentrations were converted to Ib/dscf and multiplied by the stack gas volumetric flow rate
(dscf/hr) to obtain emission rates in units of Ib/hr. The reference provides an average coal feed
rate during the test of 694,000 Ib/hr on a dry-basis and a coal moisture content of 6.1%. The
dry-basis coal feed rate was converted to an as-fired basis by dividing 694,000 by 93.9% (100% -
6.1%), resulting in a value of 739,084. The pollutant emission rates were divided by the coal
feed rate to obtain emission factors in units of Ib/ton.
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The results for the other metals are expressed as emission factors in units of Ib/10l2 Btu.
The reference indicates that sampling results for all compounds were above the detection limits.
The reference provides an average HHV of the coal fired during the test of 13,467 Btu/lb on a dry
basis. This HHV was converted to an as-fired HHV of 12,693 Btu/lb by dividing 13,467 by
106.1%. The as-fired coal HHV was used to convert the emission factors in units ofIb/10l2 Btu
to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 33
This reference presents the results of emissions testing at a facility designated as EPRI
Site 20. The boiler tested at Site 20 is a B & W wall-fired, drum type boiler with a normal
full-load value of 680 MW. The boiler was firing pulverized lignite from Wilcox, Texas during
the emissions test. Emissions controls in use during the test include two parallel cold-side ESPs
and a FGD system that uses limestone slurry for reagent.
Four sampling runs were conducted for various metals. The results for antimony are
presented as concentrations in units of microgram per Normal cubic meter. Antimony was not
detected in any of the sampling runs the concentrations are based on full detection limits. The
concentrations were converted to Ib/dscf and multiplied by the stack gas volumetric flow rate
(dscf/hr) to obtain emission rates in units of Ib/hr. The reference provides a coal feed rate during
the test of 618,000 Ib/hr on a dry-basis and a coal moisture content of 34.4%. The dry-basis coal
feed rate was converted to an as-fired basis by dividing 618,000 by 66.4% (100% - 34.4%),
resulting in a value of 942,073. The average antimony emission rate was divided by the coal feed
rate to obtain an emission factor in units of Ib/ton.
The results for the other metals are expressed as emission factors in units of lb/l()12 Btu.
The reference indicates that all pollutants were detected in all sampling runs. The reference
provides an HHV of the coal fired during the test of 6,760 Btu/lb on an as-received basis. This
value was used to convert the emission factors in units of lb/l()12 Btu to factors in units of Ib/ton.
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This reference was assigned a data quality rating of "A."
Reference 34
The results of emissions testing at a facility designated as EPRI Site 21 are presented in
this reference. The boiler at Site 21 is rated at 667 MW, gross load, and was firing bituminous
coal from Pennsylvania and West Virginia during the emissions test. Emission controls utilized
during the emissions test were a pilot ESP and FGD system. The FGD system is a spray tower
absorber using an alkaline slurry. The pilot system has demonstrated the capability to produce
the same results as a full-scale FGD system.
Eight sampling runs were conducted for metals and seven for polycyclic aromatic
hydrocarbons (PAHs). The results of the sampling runs are presented as emission factors in unit
of lb/lC)12 Btu. Full detection limit values were used to develop emission factors that are based
only on sampling results that were below the detection limits. The reference presents an average
HHV for the coal fired during the test of 14,032 Btu/lb on a dry basis and a coal moisture content
of 7%. The dry-basis FtHV was converted to an FtHV on an as-fired basis by dividing 14,032 by
107%, resulting in a value of 13,114. The as-fired coal FtHV was used to convert the emission
factors in units of lb/1012 Btu to factors in units of Ib/ton.
A data quality rating of "A" was assigned to this reference.
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Reference 35
This reference presents the results of emissions testing at a facility designated as EPRI
Site 22. The boiler tested at Site 22 is a B & W 700 MW, wall-fired, radiant boiler. The boiler
was burning pulverized subbituminous coal from the Powder River region during the emissions
test. Emission controls used during the test were two parallel cold-side ESPs.
Three sampling runs were conducted for metals, dioxins/furans, and PAHs and the results
are presented as emission factors in units ofIb/10l2 Btu. Full detection limit values were used to
develop emission factors that are based only on results that were below the detection limits. The
reference provides an average HHV for the coal fired during the emissions test of 11,981 Btu/lb
on a dry-basis and a coal moisture content of 29.5%. The dry-basis HHV was converted to an
as-fired HHV of 9,252 Btu/lb by dividing 11,981 by 129.5%. The as-fired coal HHV was used to
convert the emission factors in units of Ib/10l2 Btu to factors in units of Ib/ton.
This report was assigned a data quality rating of "A."
Reference 36
This reference presents the results of emissions testing at a facility designated as EPRI
Site 101. The boiler tested at this site is a B & W, 800 MW, wall-fired unit and was burning
pulverized subbituminous coal from New Mexico during the emissions test. Emission controls
in use during the test include low NOX burners, a fabric filter, and FGD system consisting of a
wet lime scrubber.
Three sampling runs were conducted for metals and organics. The solid phase sample for
metals test Run Two was destroyed prior to analysis and, therefore, except for mercury, the
metals emissions results are based on two sampling runs. Because mercury is present
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primarily in the vapor phase, the solid phase average of Runs One and Three was used to
represent the solid phase results for mercury for Run Two.
The test runs results are presented as emission factors in units of lb/l()12 Btu. The
reference presents an average HHV for the coal fired during the test of 10,190 Btu/lb on a dry
basis and a coal moisture content of 14%. The dry-basis HHV was converted to an as-fired HHV
by dividing 10,190 by 114%, resulting in a value of 8,939. The as-fired coal HHV was used to
convert the emission factors in units of Ib/10l2 Btu to factors in units of Ib/ton.
A data quality rating of "A" was assigned to this reference.
Reference 37
The results of emissions testing at a facility designated as EPRI Site 111 are presented in
this reference. The boiler at this site is 267 MW, two-flow, single-reheat, balanced draft, drum
type boiler. The boiler was burning a Western subbituminous coal during the tests. The
pollution control system in use during the test consists of a fabric filter and spray dryers for FGD.
Two sampling runs were conducted for metals, PAHs, and various other organics. The
results are expressed as emission factors in units of Ib/10l2 Btu. Full detection limit values were
used to develop emission factors that are based only on sampling results that were below
detection limits. The reference provides an average HHV for the coal fired during the test of
10,020 Btu/lb on an as-received basis. This value was used to convert the emission factors in
units of lb/lQl2 Btu to factors in units of Ib/ton.
This report was assigned a data quality rating of "A."
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Reference 38
This reference presents the results of emissions testing at a facility designated as Site 114.
The unit at Site 114 is a B & W, cyclone-fired reheat boiler rated at 100 MW. Bituminous coal
from Indiana was fired during the emissions tests. Emissions sampling was conducted under two
boiler operating conditions, baseline and reburn. Emissions controls used under the baseline
operating condition consisted of an ESP. Controls used during the reburn operating condition
were an ESP along with wall-fired burners located at a higher elevation in the boiler and overfire
air to reduce NOX emissions.
Three sampling runs for metals, PAHs, and various other organics were conducted under
each operating condition and the results for each condition are reported separately and are
expressed as emission factors in units of Ib/10l2 Btu. PAHs are reported as "not detected" and
no emission factors were developed. For the other "not detected" pollutants, full detection limit
values were used to develop emission factors.
The reference reports an average HHV for the coal fired during the baseline condition of
13,490 Btu/lb on a dry-basis and a coal moisture content of 15.6%. The dry-basis HHV was
converted to an as-fired basis by dividing 13,490 by 115.6%, resulting in an as-fired HHV of
11,670 Btu/lb. The reported average HHV for the coal fired during the reburn condition was
13,280 Btu/lb, dry-basis, and the average content was 12.5%. The dry-basis HHV was converted
to an as-fired HHV by dividing 13,280 by 112.5%, resulting in an as-fired HHV of 11,804
Btu/lb. The as-fired coal HHVs were used to convert the emission factors in units of lb/l()12 Btu
to factors in units of Ib/ton.
This reference was assigned a quality rating of "A."
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Reference 39
The results of emissions testing at a facility designated as EPRI Site 115 are presented in
this report. The unit tested at this site is a 117 MW B & W roof-fired boiler commissioned in
1955. The boiler was firing pulverized Western bituminous coal during the emissions tests.
Emissions tests were conducted in two phases. Emissions controls in use during both phases
included low NOX burners, overfire air, and a fabric filter. Additional controls used in Phase II
included a urea injection system for selective non-catalytic NOX reduction.
Three sampling runs were conducted for metals and organics during both operating
conditions, and the results are presented separately and are expressed as emission factors in
lb/l()12 Btu. Full detection limit values were used to develop emission factors that are based
only on sampling results that were below detection limits.
The report presents an average HHV for the coal of 12,565 Btu/lb and 12,638 Btu/lb fired
during Phase I and Phase II, respectively. The reported HHV for the coal is on a dry basis and
the reference does not provide the moisture content of the coal, as received. A test report from
the facility designated as EPRI Site 111 (Reference 37) where the boiler was firing a Western
bituminous coal reports a moisture content of 9.8%. This value was used to convert the dry-basis
coal HHV at Site 115 to an as-fired basis by dividing 12,565 and 12,638 by 109.8%, resulting in
an as-fired HHV for the coal fired during Phase I testing of 11,444 Btu/lb and 11,510 Btu/lb for
the coal fired during Phase II. The as-fired coal HHVs were used to convert the emission factors
in units of Ib/10l2 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "C" because an as-fired coal HHV or
information that could be used to calculate it were not provided.
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Reference 40
This reference presents the results of DOE emissions testing at Springerville Generating
Station Unit No. 2. This facility is owned and operated by the Tucson Electric Power Company
and is located near Springerville, Arizona. Unit No. 2 was manufactured by Combustion
Engineering and is a 397 MW, corner-fired, balanced-draft design. According to the EPRI
Synthesis Report (Reference 18), this boiler is tangentially-fired. The unit was burning
pulverized subbituminous coal from the Lee Ranch Mine in New Mexico during the emissions
tests. Emissions controls in use during the emissions test included overfire air and spray dryer
absorbers.
Three sampling runs were conducted for metals and the results are expressed as emission
factors in units of Ib/10l2 Btu. Full detection limit values were used to develop emission factors
that were not detected in any sampling run. The report presents an average as-received HHV for
the coal fired during the emissions test of 9,446 Btu/lb. This value was used to convert the
emission factors in units of Ib/10l2 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 41
The results of DOE emissions testing at the Niles Station Unit No. 2 of Ohio Edison are
presented in this reference. Unit No. 2 is a B & W, 108 MW, cyclone boiler and was burning
pulverized bituminous coal during the emissions test. The coal is a blend of eastern Ohio and
western Pennsylvania coals and is received in the respective proportions of 70/30. Emissions
controls in use during the test consisted of an ESP.
Three sampling runs were conducted for metals and various organics and the results are
presented as emission factors expressed in units of Ib/10l2 Btu. Emission factors for pollutants
that were not detected in any sampling run were developed using one-half of the detection limit
value. The average as-received HHV of the coal fired during the emissions test was 12,184
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Btu/lb. This value was used to convert the emission factors in units of Ib/10l2 Btu to factors in
units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 42
This reference presents the results of DOE emissions testing at the Coal Creek Station
which is operated by Cooperative Power and is located about 50 miles north of Bismarck, North
Dakota. The unit tested is a 550 MW, tangentially-fired, water walled, dry bottom furnace, with
a Combustion Engineering controlled circulation boiler. The furnace is fueled by lignite from the
Falkirk mine located adjacent to the plant. Emissions controls used during the test were an ESP
and wet limestone scrubber.
Three sampling runs were conducted for metals and various organics and the results are
presented as emission factors expressed in units of lb/l()12 Btu. Emission factors for pollutants
that were not detected in any sampling run were developed using one-half of the detection limit
value. The average as-received HHV for the lignite fired during the emissions test was 6,230
Btu/lb. This value was used to convert the emission factors in units of lb/l()12 Btu to factors in
units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 43
The results of DOE emissions testing at Baldwin Power Station Unit 2 are presented in
this reference. Unit 2, located in Baldwin, Illinois, is a B & W cyclone furnace rated at 568 MW
and was built in 1973. The furnace was firing Illinois bituminous coal during the emissions test.
Emissions controls used during the test were an ESP.
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Three sampling runs were conducted for metals and various organics, including PAHs
and dioxins/furans. Test results are reported as emission factors expressed in units of lb/lC)12
Btu. Full detection limit values were used to develop emission factors for pollutants that were
not detected in any sampling run. The average of the HHV values reported in the reference for
the coal fired during the emissions test was 10,633 Btu/lb, as received. The as-received coal
HHV was used to convert the emission factors in units of lb/lC)12 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 44
This reference presents the results of DOE emissions testing at the Boswell Energy
Center Unit 2 located in Cohasset, Minnesota. This unit is a Riley Stoker front-fired boiler built
in 1957 and rated at 69 MW. The boiler was burning pulverized western subbituminous coal
from the Powder River Basin area of Wyoming and Montana during the emissions tests.
Emissions controls in use during the test were a baghouse.
Three sampling runs were conducted for metals and various organics, including PAHs
and dioxins/furans. Emissions results are reported as emission factors expressed in units of
lb/l()12 Btu. When a pollutant was not detected in any sampling run, full detection limit values
were used to calculate an emission factor. The average of the HHV values reported in the
reference for the coal fired during the emissions test was 8,798 Btu/lb, as received. This value
was used to convert the emission factors in units of lb/lC)12 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
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Reference 45
The results of DOE emissions testing at Cardinal Plant Unit 1 located in Brilliant, Ohio,
are presented in this reference. Unit 1 is a wall-fired boiler rated at 615 MW and was burning
pulverized Pittsburgh No. 8 bituminous coal during the emissions test. The unit is equipped with
two ESPs arranged in parallel.
Three sampling runs for metals and various organics were conducted during sootblowing
operations and three were conducted during non-sootblowing conditions. Emissions results are
presented for both conditions, but only the results for non-sootblowing conditions were used to
develop AP-42 emission factors. The emissions test results are reported as emission factors
expressed in units of lb/l()12 Btu. For pollutants where the results for all sampling runs were
below the detection limit, the average of the run detection limits was used to develop an emission
factor. The reference does not report a coal feed rate or the HHV of the coal fired during the
emissions test and, therefore, a value of 13,000 Btu/lb listed in Appendix A of AP-42 was used
to convert the reported emission factors to emission factors in units of Ib/ton.
A data quality rating of "C" was assigned to this reference because the coal feed rate and
the coal HHV were not reported.
Reference 46
This reference presents the results of DOE emissions testing at a facility designated as
Site 16. The unit tested is a Foster Wheeler wall-fired boiler rated at 500 MW. The EPRI
Synthesis Report (Reference 18) indicates that the boiler was burning pulverized bituminous coal
from Virginia and Kentucky during the emissions test. Emissions controls in use during the test
were low NOX burners with overfire air and an ESP.
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Three sampling runs were conducted for metals and various organics and the emissions
results are presented as emission factors in units of Ib/10l2 Btu. Full detection limit values were
used to develop emission factors that are based only on results that were below the detection
limit. The reference reports an average HHV for the coal fired during the emissions test of
13,800 Btu/lb, dry-basis, and a coal moisture content of 3.8%. The average dry-basis HHV was
divided by 103.8% to obtain an average as-fired HHV of 13,295 Btu/lb. The as-fired coal HHV
was used to convert the emission factors in units of lb/l()12 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 47
The results of emissions testing at a facility designated as EPRI Site 122 are presented in
this reference. The unit tested is a cyclone boiler constructed during the 1950s and has a nominal
power production capacity of 275 MW. The boiler was burning bituminous coal from the Illinois
No. 5 Seam in Saline County, Illinois. An ESP was in use during the emissions test.
Three sampling runs were conducted for metals and organics and the emissions results are
reported as emission factors that are expressed in units of Ib/10l2 Btu. Full detection limit
values were used to develop emission factors that are based only on results that were below the
detection limit. The average HHV of the coal fired during the emissions test was 12,327 Btu/lb,
as fired. This value was used to convert the emission factors in units of Ib/10l2 Btu to factors in
units of Ib/ton.
This reference was assigned a data quality rating of "A."
2-32
-------
Reference 48
This reference presents hydrogen chloride (HC1) and hydrogen fluoride (HF) emission
factors that were developed from the results of a literature search. The literature search was
conducted under the National Acid Precipitation Assessment Program (NAPAP).
The reference lists four emission factors each, or four pairs of factors, for HC1 and HF.
The factors are in units of Ib/ton and represent both controlled and uncontrolled boilers. One pair
of emission factors is for electric generation (utility) and industrial boilers firing bituminous or
subbituminous coal. The second pair of factors is for utility and industrial boilers firing lignite.
The third pair of emission factors is for commercial/institutional boilers firing bituminous or
subbituminous coal. The fourth pair of factors is for commercial/institutional boilers firing
lignite.
The reference states that AP-42 procedures for assigning quality ratings were used to
assign ratings to the factors. The emission factor quality ratings were retained and it was not
necessary to assign a data quality rating to this reference.
References Examined But Not Used For Emission Factor Development
Several documents were examined and the emissions data they contained were not used
to develop emission factors because the data were not considered representative of the general
population of coal or lignite-fired boilers. For example, data from boilers that were not burning
100% coal or lignite were excluded. Data from boilers that were not operating normally or were
using experimental control devices were not used. Also, data whose use would result in
relatively low quality emission factors were not used. The following paragraphs describe the
documents that were examined but not used and an explanation of why they were not used.
2-33
-------
Results of the May 28-31. 1991 Trace Metal Characterization Study and Dioxin
Emission Test on Unit 1 at the A.S. King Plant in Bayport Minnesota. Interpoll Laboratories.
Inc.. Circle Pines. Minnesota. November 6. 1991. The boiler was firing a mixture of coal (90%)
and petroleum coke (10%) at the time of the emissions tests.
Results of the July 1992 Air Toxic Emission Study on Unit 8 at the NSP Riverside Plant.
Interpoll Laboratories. Inc.. Circle Pines. Minnesota. September 29. 1992. The boiler was firing
a mixture of coal (94%) and coke (6%) at the time of the emissions
tests.
Measurement of Chemical Emissions Under the Influence of Low-Nox Combustion
Modifications. Submitted To Southern Company Services. Inc. Final Report. October 8. 1993.
This facility was included in the emissions sampling program sponsored by EPRI and was
designated Site 110. The reference states, "Site 110 provides control over the emissions of NOX,
however, it does so with modified combustion conditions having the potential of producing
unwanted increases in the emissions of toxic organic compounds and conceivably undesirable
changes in the emissions of inorganic substances."
A Study of Toxic Emissions From a Coal-fired Power Plant Utilizing an ESP While
Demonstrating the ICCT CT-121 FGD Project. Radian Corporation. Austin. Texas. 28
December. 1993. This facility was included in the emissions sampling program sponsored by
EPRI and was designated DOE Site 4. The boiler was utilizing an experimental, or
"demonstration", type of flue gas desulfurization technology during the emissions tests.
Preliminary Draft. Field Chemical Emissions Monitoring Project: Site 14 Emissions
Monitoring. Radian Corporation. Austin. Texas. November. 1992. This facility was included in
the emissions sampling program sponsored by EPRI and was designated Site 14. The facility
was utilizing a pilot-scale dry FGD system at the time of the test. The pilot system consisted of a
spray dryer followed by a pulse-jet fabric filter. A portion of the flue
2-34
-------
gas exiting the boiler was treated by the FGD system and then recombined with the gas entering
the outlet stack.
Preliminary Draft. Field Chemical Emissions Monitoring Project: Site 18 Emissions
Monitoring. Radian Corporation. Austin. Texas. April. 1993. This facility was included in the
emission sampling program sponsored by EPRI and was designated Site 18. At the time of the
emissions test, the unit was not operating under optimal conditions. One of the five coal
pulverizing mills was out of service and adjustments were made to the other four in order to
maintain a steady operating load. Due to the adjustments, operating conditions for the unit were
not normal. In addition, one of the control devices utilized by the boiler was experiencing
problems and had to be repaired after the emissions test.
Field Chemical Emissions Monitoring Project: Site 116 Emissions Report. Radian
Corporation. Austin. Texas. Preliminary Draft Report. October. 1994. This facility was included
in the emission sampling program sponsored by EPRI and was designated Site 116. The facility
was utilizing a "demonstration" pollution control system at the time of the emissions tests. A
portion of the flue gas was treated by the system and then rejoined with the flue gas exiting the
boiler prior to entering another control device.
2.9.3 Emi s si on F actor D evel opment
Once the evaluation of all documents was completed and spreadsheets were created to
contain the emissions information extracted from each reference, the emission factors from the
individual spreadsheets were combined into groups of factors according to pollutant type. This
grouping was performed in order to more easily identify patterns in the emission factor values
that could be attributed to coal type, boiler configuration (SCC), and/or control devices
employed. Emission factors making up a pattern would be averaged together in order to develop
an AP-42 emission factor that represents the boilers and emission controls included in the
pattern. The groups are: (1) metals emission factor equations; (2) hydrogen chloride and
hydrogen fluoride emission factors; (3) dioxin/furan emission factors; (4) metals emission
factors; (5) PAH emission factors; and, (6) emission factors for various organics. A spreadsheet
2-35
-------
was constructed for each group of emission factors, except for the metals emission factor
equations. These spreadsheets are hereafter referred to as "main" spreadsheets.
The metals emission factor equations in Reference 18 were not revised or converted.
Because no calculations were necessary, a main spreadsheet for the emission factor equations
was not constructed. The main spreadsheet containing the HC1 and HF emission factors has only
four factors for each pollutant and no extensive data manipulation was necessary. The main
spreadsheets for dioxins/furans, metals, PAHs, and organics contain factors from numerous
sources, and some processing of the data was necessary in order to develop AP-42 emission
factors. The following paragraphs describe how these data were processed.
Each main spreadsheet for dioxins/furans, metals, PAHs, and organics was constructed
with all emission factors from a single reference arranged on one row, except in the case of
multiple emission factors representing different operating conditions. In such cases, the factors
for each operating condition were arranged on one row. In addition to the emission factors, other
data obtained from the reference were included on the appropriate spreadsheet row. These data
included the reference number, number of boilers tested, coal type, boiler type, boiler MW rating,
boiler SCC, control devices used, reference data quality, and number of test runs. These data
were included in order to document and characterize the emission factors. Each type of data was
entered in a single column of the spreadsheet. For example, all SCCs are in a single column, all
coal types are in a single column, all emission factors for arsenic are in a single column, etc.
With this arrangement, the data can be sorted by SCC, coal type, and control device in order to
identify patterns in the emission factor values.
According to EPA guidance, emission factors that are based completely on detection
limits should be calculated using one half of the detection limit. When the emission factors were
extracted from the references, those factors based completely on detection limits were identified
and it was noted if full value or one-half value detection limits were used to calculate them. All
such factors were calculated using full detection limit values except for factors from Reference
41 and Reference 42, which were based on one-half detection limit values. All emission factors
in the main spreadsheets that are based completely on detection limits were divided by two
2-36
-------
except for factors from Reference 41 and Reference 42. The factors from all references that are
based completely on detection limits are identified by a "DL/2" in the column to the right of the
emission factor.
EPA guidance also prescribes that when averaging emission factors together in order to
obtain an AP-42 factor, the average should be an arithmetic mean. In addition, values
representing factors based completely on detection limits that are larger than values representing
factors that are based on detectable sample quantities (the pollutant was detected in at least one
sampling run) should not be included in the overall averaging. In the main spreadsheets, after a
group of emission factors for a pollutant were selected to be averaged together, the factors based
only on detection limits were examined to determine if they should be included in the overall
average. The "non-detected" factors that were higher in value than "detected" factors were not
included in the overall average. In each column of pollutant emission factors, the factors
(detected and non-detected) that are included in the overall average are marked with an asterisk
in the column to the left of the factors. The average of the selected factors is at the bottom of the
column. The quality rating of the average factor is included in the column to the right of the
average factor.
When a pollutant was not detected at any facility, no AP-42 emission factor was
developed for that pollutant. These pollutants appear in the main spreadsheets with a "DL/2" to
the right of every factor for the pollutant. Although no emission factor was developed for these
pollutants, they are identified in the footnotes of the AP-42 table that they would appear in if a
factor had been developed.
2-37
-------
The metals emission factor equations and the development of the HC1/HF emission
factors are discussed below. The factors in the dioxin/furan, metals, PAHs, and organic main
spreadsheets were sorted by SCC and control devices in order to identify patterns in the factor
values that could be attributed to one or more of these parameters. The result of this sorting is
also discussed below.
Metals Emission Factor Equations
The emission factor equations provided in Reference 18 are included in AP-42 "as is,"
i.e., no conversions or revisions were made to the equations. There are equations for nine metals
and they may be used to generate emission factors for both controlled and uncontrolled boilers.
In addition, the equations may be used to generate emission factors for all typical firing
configurations for utility, industrial, and commercial/industrial boilers. The emission factor
equations are based on statistical correlations among measured trace element concentrations in
coal, measured fractions of ash in coal, and measured paniculate 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 to generate emission factors when the
inputs to the equations are available. If the inputs to the emission factor equations are not
available for a pollutant and there is an emission factor for the provided in Section 1.1, then the
factor should be used. The emission factor equations are provided in Table 4.
Hydrogen Chloride and Hydrogen Fluoride Emission Factors
All HC1 and HF emission factors were obtained from Reference 48. These factors are
shown in Table 5. The factors for utility/industrial boilers firing bituminous/subbituminous coal,
commercial/industrial boilers firing bituminous/subbituminous coal, and commercial/industrial
boilers firing lignite were averaged together to obtain an overall factor (one for HC1 and one for
HF) that represents all three categories. The emission factors for utility/industrial boilers firing
lignite were not used in developing the AP-42 emission factors because of the relatively low
value of the emission factors.
2-38
-------
Dioxin/Furaru Metals. PAHs. and Various Organic Emission Factors
As described above, the emission factors for these pollutants were sorted by SCC and
control device in order to identify patterns. No patterns became apparent in any of the four
spreadsheets except in the spreadsheet containing the dioxin/furan emission factors. One pattern
includes factors for a boiler controlled by a spray dryer absorber and a fabric filter and a second
pattern is for boilers controlled by an ESP (2 boilers) or fabric filter (1). What makes the patterns
apparent is that the factors for the first pattern are consistently higher in value for all
dioxins/furans than the factors for the second pattern. Thus, the dioxin/furan emission factors
added to Section 1.1 are for two control device scenarios. The factors for the other groups were
averaged together to arrive at one AP-42 factor for each pollutant. The SCCs and controls
attributed to the AP-42 factor are a combination of the SCCs and controls represented by the
individual factors.
Copies of the spreadsheets used to develop the dioxin/furan, metals, PAHs, and various
organic emission factors are shown in Tables 6, 7, 8, and 9, respectively.
2-39
-------
Table 4. Metals Emission Factor Equations for Section 1.1 of AP-42a>b
Emissions Equation0
Pollutant (lb/1012 Btu)
Antimony 0.92 x (C/A x PM)a63
Arsenic 3.1 x (C/A x PM)a85
Beryllium 1.2 x (C/A x PM)L1
Cadmium 3.3 x (C/A x PM)°5
Chromium 3.7 x (C/A x PM)a58
Cobalt 1.7x(C/AxPM)°-69
Lead 3.4 x (C/AxPM)a8°
Manganese 3.8 x (C/A x PM)a6°
Nickel 4.4 x (C/A x PM)a48
aReference 18
"All equations are rated "A." The emission factor equations are applicable to all typical firing
configurations (SCCs) for electric generation (utility) boilers, industrial boilers, and
commercial/industrial boilers firing bituminous coal, subbituminous coal, or lignite. Also, the
equations apply to boilers using typical control devices, including no controls.
CC = concentration of trace metal in the coal, parts per million by weight (ppm wt)
A = weight fraction of ash in coal, (dimensionless)
PM = site-specific emission factor for total paniculate matter, (lb/10^ Btu)
2-40
-------
Table 5. Data Used to Develop Hydrogen Chloride and Hydrogen Fluoride Emission
Factors for Section 1.1 of AP-42ab
BOILER SCC DESCRIPTIONS
Source
Classification
Codes0
Hydrogen
Chloride
(lb/ton)c
Hydrogen
Fluoride
(Ib/ton)
Commerical/Industrial Boilers
Bituminous and Subbituminous Coal
Firing Types
Pulverized Coal Wet Bottom
Pulverized Coal Dry Bottom
Overfeed Stoker
Underfeed Stoker
Spreader Stoker
Hand-fired
Pulverized Coal Dry Bottom Tangential
Atmospheric Fluidized Bed Combustor
Cyclone Furnace
Traveling Grate Overfeed Stoker
1-03-002-05/21*
1-03-002-06/22
1-03-002-07
1-03-002-08
1-03-002-09/24
1-03-002-14
1-03-002-16/26
1-03-002-17/18
1-03-002-23
1-03-002-25
1.48*
0.17
Electric Generation & Industrial Boilers
Bituminous and Subbituminous Coal
Firing Types
Pulverized Coal Wet Bottom
Pulverized Coal Dry Bottom
Cyclone Furnace
Spreader Stoker
Traveling Grate Overfeed Stoker
Overfeed Stoker
Pulverized Coal Dry Bottom,
Tangential Firing
1-01-002-01/21*
1-02-002-01/21
1-01-002-02/22
1-02-002-02/22
1-01-002-03/23
1-02-002-03/23
1-01-002-04/24
1-02-002-04/24
1-01-002-05/25
1-02-002-25
1-02-002-05
1-01-002-12/26
1-02-002-12
1.9*
0.23
2-41
-------
Table 5. Continued
BOILER SCC DESCRIPTIONS
Atmospheric Fluidized Bed
Underfeed Stoker
Commerical/Industrial Boilers
Lignite
Firing Types
Pulverized Coal
Pulverized Coal Tangential Firing
Traveling Grate Overfeed Stoker
Spreader Stoker
Electric Generation & Industrial Boilers
Lignite
Firing Types
Pulverized Coal
Pulverized Coal Tangential Firing
Cyclone Furnace
Traveling Grate Overfeed Stoker
Spreader Stoker
Source
Classification
Codes0
1-01-002-17
1-01-002-18
1-02-002-17
1-02-002-18
1-02-002-06
1-03-003-05*
1-03-003-06
1-03-003-07
1-03-003-09
1-01-003-01
1-02-003-01
1-01-003-02
1-02-003-02
1-01-003-03
1-02-003-03
1-01-003-04
1-02-003-04
1-01-003-06
1-02-003-06
Overall Average
Quality Rating
Hydrogen Hydrogen
Chloride Fluoride
(lb/ton)c (Ib/ton)
0.351* 0.063
0.01 0.01
1.2 0.15
B B
aAll factors are from Reference 48.
bFactors are for both uncontrolled and controlled boilers.
°An asterisk to the left of a factor indicates that it was used in calculating the overall emission factor.
2-42
-------
Table 6. Data Used to Develop Dioxin/furan Emission Factors for Section 1.1 of AP-42
Ref.
No.
19
Quality rating
35
43
44
Average Factor
Quality rating
Coal
Type
Subituminous
Subituminous
Bituminous
Subituminous
Boiler CONTROL CONTROL DATA No. of
Type3 MW SCCs DEVICE lb DEVICE 2b QUALITY Test Runsc
PC,DB 860 10100222 FGD-SDA FF C
PC,DB 700 10100222 ESP none A
Cyclone 568 10100203 ESP none A
PC,DB 69 10100222 FF none A
3
3
3
3*
2-43
-------
Table 6. Continued
Ref.
No.
19
Quality rating
35
43
44
Average Factor
Quality rating
2.3.7.8-
TCDDdc
—
3.1e-llDL/2*
2.70e-llDL/2*
1.43e-ll *
1.43e-ll
E
TOTAL
TCDDdc
3.93e-10
E
8.7e-ll
2.85e-ll *
1.63e-10*
9.28e-ll
D
TOTAL
PeCDDdc
7.06e-10
E
No dataDL/2
7.85e-12DL/2*
8.16e-ll *
4.476-11
D
TOTAL
HxCDDdc
3.00e-09
E
No dataDL*
2.046-11 *
3.706-11 *
2.876-11
D
TOTAL
HpCDDdc
l.OOe-08
E
1.80e-10*
5.386-11 *
1.64e-l 1DL/2*
8.346-11
D
TOTAL
OCDDdc
2.87e-08
E
9.60e-10 *
9.45e-llDL/2*
1.94e-10 *
4.16e-10
D
2-44
-------
Table 6. Continued
Ref.
No.
19
Quality rating
35
43
44
Average Factor
Quality rating
2.3.7.8-
TCDFdc
—
3.35e-llDL/2*
1.35e-llDL/2*
1.06e-10*
S.lOe-11
D
TOTAL
TCDFdc
2.49e-09
E
1.10e-10*
4.06e-llDL/2*
1.06e-09*
4.04e-10
D
TOTAL
PeCDFdc
4.84e-09
E
1.4e-10*
8.49e-ll *
8.34e-10 *
3.53e-10
D
TOTAL
HxCDFdc
1.27e-08
E
6.5e-ll *
1.18e-10*
3.92e-10 *
1.92e-10
D
TOTAL
HpCDFdc
4.39e-08
E
4.1e-ll *
6.746-11 *
1.22e-10 *
7.686-11
D
TOTAL
OCDFd
1.37e-07
E
7.8e-ll
8.836-11
3.276-11
6.636-11
D
2-45
-------
Table 6. Continued
Ref.
No.
19
Quality rating
35
43
44
Average Factor
Quality rating
TOTAL
CDDe
4.28e-08
E
—
—
—
6.66e-10
D
TOTAL
CDFe
2.01e-07
E
—
—
—
1.09e-09
D
TOTAL
CDD/CDF6
2.44e-07
E
—
—
—
1.76e-09
D
a PC = Pulverized Coal; DB = Dry Bottom.
b FGD-SDA = Flue Gas Desulfurization, Spray Dryer Absorber, ESP = Electrostatic Precipitator,
FF = Fabric Filter
c An "*" to the left of a factor indicates that it was used in calculating the average factor.
d A "DL/2" to the right of a factor indicates that the factor is based only on sampling results that were
below the detection limits. The value shown here represents a factor based on one half of the detection limit.
e Total CDD is the sum of Tetra- through Octa- CDD. Likewise for CDF. Total CDD/CDF is the sum of
Total CDD and Total CDF.
2-46
-------
Table 7. Data Used to Develop Controlled Metals Emission Factors for Section 1.1 of AP-42
Ref.
No.
20
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
No. of
Boilers
1
2
3
1
4
2
2
2
1
1
1
1
1
1
1
1
1
1
1
Fuel
Type
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Lignite
Bituminous
Subbituminous
Subbituminous
Subbituminous
Boiler
Type3
PC, DB
PC, DB
PC, DB
AFBC, CB
PC, DB
PC, DB
PC, DB
PC, DB
PC, DB
AFBC, CB
PC, DB, T
PC, DB, O
PC, DB, T
PC, DB, O
PC
PC, DB, O
PC, DB, O
PC, DB, W
PC, DB
MW
860
750 ea.
—
137
—
—
750 ea.
750 ea.
860
110
700
700
600
1,160
680
667
700
800
267
sec
10100222
10100222
10100222
10100238
10100222
10100222
10100222
10100222
10100222
10100238
10100226
10100202
10100212
10100202
10100301
10100202
10100222
10100222
10100222
Control
Device lb
FGD-SDA
FGD-VSST
ESP
Cyclone
ESPC
FF
FGD-VSST
FGD-VSST
FGD-SDA
FGD-FIL
OFA
ESP
ESP
ESP
ESP
ESP
ESP
LNB
LNB
Control
Device 2b
FF
none
ESP
ESP
none
none
none
none
FF
FF
FGD-WLS
FGD-WLS
none
none
FGD-WLS
FGD-WLS
none
FF
FGD-SD
Control Data No. of
Device 3b Quality Test Runs0
none
none
none
ESP
none
none
none
none
none
none
ESP
none
none
none
none
none
none
FGD-WLS
FF
A
A
B
B
B
B
B
B
B
A
B
A
A
A
A
A
A
A
A
3
3
3
3
3*
3*
3*
3*
3*
1
1
2
3
3*
4
8
3
2
2
2-47
-------
Table 7. Continued
Ref.
No.
38
38
39
39
40
41
42
43
44
45
46
47
Average
No. of
Boilers
1
1
1
1
1
1
1
1
1
1
1
1
Factor
Fuel
Type
Bituminous
Bituminous
Bituminous
Bituminous
Subbituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Boiler
Type3
Cyclone
Cyclone
PC, DB
PC, DB
PC, DB, T
Cyclone
PC, DB, T
Cyclone
PC, DB
PC, DB
PC, DB
Cyclone
MW
100
100
117
117
422
108
550
568
69
615
500
275
sec
10100203
10100203
10100202
10100202
10100226
10100203
10100302
10100203
10100222
10100202
10100202
10100203
Control
Device lb
ESP
Reburn/OFA
LNB/OFA
LNB/OFA
LNB/OFA
ESP
ESP
ESP
FF
ESP
LNB/OFA
ESP
Control
Device 2b
none
ESP
FF
SNCR
FGD-SDA
none
FGD-WLS
none
none
none
ESP
none
Control
Device 3b
none
none
none
FF
FF
none
none
none
none
none
none
none
Data
Quality
A
A
B
B
A
A
A
A
A
C
A
A
No. of
Test Runs0
3
3
3
3
3*
3
3*
3*
3
3*
3
3
Quality Rating
2-48
-------
Table 7. Continued
Ref.
No.
20
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Antimonydc
—
—
4.80e-05 DL/2*
4.66e-06 DL/2*
1.23e-05 *
5.78e-06 *
9.12e-06*
1.48e-05 *
7.06e-06 *
—
*
*
*
3.83e-05 *
8.70e-06 DL/2*
*
3.52e-05 DL/2*
*
Arsenicdc
—
—
1.06e-05
9.03e-06
5.63e-06 *
1.89e-05 *
4.42e-05 *
4.26e-05 *
4.14e-07DL/2*
1.03e-05 DL/2
1.41e-05
1.19e-05
3.38e-04 *
2.01e-04 *
8.52e-06 *
1.62e-04 *
1.61e-06
6.08e-06 *
2.11e-06DL/2
Berylliumdc
—
—
1.16e-06DL/2*
2.33e-07 DL/2*
1.33e-06 *
8.09e-06 *
4.34e-06 *
4.80e-06 *
l.lle-07
2.05e-06 DL/2
1.41e-06DL/2*
2.11e-06DL/2*
1.04e-05 *
3.08e-05 *
4.73e-06 *
3.41e-06 *
2.87e-07 DL/2*
6.44e-07 *
Cadmiumdc
—
—
5.31e-05 *
l.lle-04*
l.lle-05 *
4.83e-04 *
1.80e-05 *
4.78e-05 *
*
4.10e-06DL/2*
1.83e-05 *
3.17e-05 *
8.06e-05 *
3.30e-06 *
9.46e-06 *
1.49e-05 *
2.96e-06 *
7.15e-06*
2.11e-05DL/2
Chromiumdc Chromium VIdc
—
—
4.89e-05
1.08e-04
1.18e-04
2.35e-04
1.95e-04
1.34e-04
1.59e-04 * 1.49e-05
3.28e-05
9.87e-05 — *
9.23e-05
3.12e-04 — *
3.30e-04 — *
3.79e-05 — *
7.19e-05 — *
9.81e-06
3.93e-05 — *
4.3 le-05 DL/2
2-49
-------
Table 7. Continued
Ref.
No.
38
38
39
39
40
41
42
43
44
45
46
47
Average Factor
Quality Rating
Antimonydc
*
*
*
*
7.75e-07 *
4.39e-06 DL/2*
2.24e-06 *
3.23e-05 *
5.95e-06 DL/2*
6.14e-05 *
*
*
1.84e-05
A
Arsenicdc
1.63e-04 *
1.89e-04 *
1.72e-05
3.45e-06
2.83e-06
1.02e-03 *
1.50e-05
2.85e-04 *
5.70e-06
9.07e-05 *
2.92e-03 *
5.42e-03 *
4.08e-04
A
Berylliumdc
5.60e-05 *
1.89e-05 *
2.29e-07 DL/2*
2.30e-07 DL/2*
3.78e-07 DL/2*
4.63e-06 *
1.06e-05 DL/2
3.00e-05 *
1.14e-06DL/2
1.82e-06 *
8.24e-05 *
9.86e-05 *
2.12e-05
A
Cadmiumdc
4.20e-05 *
9.44e-06 *
2.75e-06 *
8.05e-07 DL/2*
4.91e-07 *
1.71e-06 *
1.99e-05 DL/2
6.42e-05 *
5.70e-06 DL/2*
2.20e-05 *
9.57e-05 *
8.88e-05 *
5.08e-05
A
Chromiumdc Chromium VIdc
3.27e-04
1.09e-04
1.51e-05
6.91e-06
1.89e-06
7.31e-05
—
1.08e-03
3.59e-05
1.95e-04
5.58e-04 *
2.47e-03
2.55e-04
A
—
—
—
—
—
*
*
*
*
*
1.44e-04 *
*
7.95e-05
D
2-50
-------
Table 7. Continued
Ref.
No.
20
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Cobaltdc
—
—
*
*
*
*
*
*
*
8.20e-06 DL/2*
2.40e-05 *
1.32e-05DL/2*
5.20e-05 *
1.32e-04
9.33e-06 *
1.08e-04*
6.50e-06 DL/2*
2.32e-06 *
Leaddc
—
—
3.59e-04 *
8.59e-04 *
6.06e-05 *
1.15e-04*
1.26e-04*
1.41e-04*
1.34e-04*
1.23e-05
1.97e-04
1.50e-04
1.12e-04
—
5.14e-05
1.66e-04
2.04e-06 *
1.29e-05
Magnesiumdc
—
—
1.60e-02 *
1.22e-02 *
5.44e-03 *
5.63e-02 *
1.33e-02 *
7.75e-03 *
4.30e-04 *
*
*
*
*
*
*
*
8.70e-04 *
*
Manganesedc
*
*
1.04e-04*
1.05e-04*
1.38e-04
3.32e-04 *
5.24e-04 *
3.91e-04*
3.21e-04 *
6.36e-04
1.61e-03 *
4.22e-05 *
2.24e-04
1.37e-04*
1.15e-04*
3.93e-04 *
2.04e-05 *
1.79e-04*
Mercurydc
8.40e-05
6.82e-05
8.05e-05 *
4.41e-05 *
3.28e-05 DL/2*
8.36e-05 *
1.79e-05 *
9.56e-05 *
6.26e-05 *
—
5.24e-05 *
4.22e-06 *
*
1.57e-04 *
1.62e-04 *
2.20e-05 *
7.03e-05 *
3.40e-05 *
6.70e-04 DL/2*
Nickeldc
—
—
1.23e-04 *
4.91e-04 *
5.84e-05 *
5.76e-04 *
2.36e-05 *
7.53e-05 *
l.Ole-04
2.05e-05 DL/2
6.63e-05
1.16e-04*
1.53e-04 *
2.01e-04 *
5.81e-05 *
4.41e-05 *
1.18e-05 *
5.01e-05 *
1.06e-04
Seleniumd
—
—
2.12e-05
6.97e-06
1.31e-05
4.14e-05
1.33e-04
1.49e-04
2.07e-05 DL/2
1.64e-04DL/2
2.12e-05DL/2
3.43e-04
2.00e-03
6.60e-03
2.16e-03
2.60e-04
9.81e-07
2.50e-05
2-51
-------
Table 7. Continued
Ref.
No.
38
38
39
39
40
41
42
43
44
45
46
47
Average Factor
Quality Rating
Cobaltdc
*
*
2.52e-06 DL/2*
2.65e-06 DL/2*
2.84e-06 DL/2*
1.46e-06DL/2*
1.87e-05 *
1.45e-04*
1.23e-05 *
1.64e-05 *
1.73e-04*
6.41e-04 *
1.03e-04
A
Leaddc
2.01e-03
1.35e-03
l.Ole-05
9.21e-06
1.32e-05
3.90e-05
8.60e-06
6.08e-04 *
4.29e-05 *
9.96e-05 *
2.92e-04
4.44e-03
4.23e-04
A
Magnesiumdc
*
*
*
*
*
*
*
6.17e-03 *
3.61e-03 *
4.26e-04 *
*
*
l.lle-02
A
Manganesedc
4.67e-04 *
3.54e-04 *
2.29e-05 *
2.05e-05 *
2.13e-04*
8.29e-05 *
3.74e-04 *
4.74e-04 *
3.24e-04 *
3.90e-04 *
5.58e-04 *
5.05e-03 *
4.86e-04
A
Mercurydc
1.05e-04 *
8.97e-05 *
4.0 le-06 DL/2*
9.44e-06 *
7.90e-05 *
3.41e-04 *
1.18e-04*
8.14e-05 *
3.40e-05 *
1.16e-05 *
1.28e-04 *
2.02e-04 *
8.30e-05
A
Nickeldc
1.82e-03 *
8.03e-04 *
3.43e-05 *
1.04e-05 *
2.84e-06 DL/2*
1.34e-05 *
6.35e-05 *
4.70e-04 *
3.47e-05 *
1.23e-04 *
4.52e-04 *
1.75e-03 *
2.80e-04
A
Seleniumd
5.60e-03
3.54e-03
8.24e-06
6.90e-07 DL/2
3.59e-07DL/2
1.51e-03
1.03e-04
2.76e-03
5.68e-05
2.41e-03
3.72e-03
1.65e-03
1.32e-03
A
2-52
-------
Table 7. Continued
aPC = Pulverized Coal, DB = Dry Bottom, T = Tangential, O = Opposed, W = Wall, AFBC = Atmospheric Fluidized Bed Combustor,
CB = Circulating Bed
bESP = Electrostatic Precipitator, FGD = Flue Gas Desulfurization, FIL = Furnace Injection of Limestone, FF = Fabric Filter,
LNB = Low Nox Burners, OFA = Overfire Air, SDA = Spray Dryer Absorber, SNCR = Selective Non-catalytic Reduction,
WLS = Wet Limestone Scrubber, VSST = Venturi Scrubber Spray Tower
These are the controls that were in place during the emissions tests.
°An asterisk before a factor indicates that the factor was used in calculating the overall average.
dA "DL/2" after a number indicates that the pollutant was not detected in any of the sampling runs used to develop the factor. The value
shown here represents a factor based on one half of the detection limit.
2-53
-------
Table 8. Data Used to Develop Controlled PAH Emission Factors for Section 1.1 of AP-42
No. of
Ref. No. of
No. Boilers
29 1
34 1
35 1
37 1
39 1
41 1
42 1
43 1
44 1
45 1
46 1
Average Factor
Quality Rating
Type of
Coal
Subbituminous
Bituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Bituminous
Boiler
Type
PC,DB,T
PC,DB,O
PC,DB,O
PC,DB
PC,DB
Cyclone
PC,DB,T
Cyclone
PC,DB
PC,DB
PC,DB
MW
700
667
700
267
117
108
550
568
69
615
500
sec
10100226
10100202
10100222
10100222
10100202
10100203
10100302
10100203
10100222
10100202
10100202
Control
Device lb
OFA
ESP
ESP
LNB
LNB/OFA
ESP
ESP
ESP
FF
ESP
LNB/OFA
Control Control Data Test
Device 2b Device 3b Quality Runsc
FGD-WLS
FGD-WLS
none
FGD-SD
FF
none
FGD-WLS
none
none
none
ESP
ESP
none
none
FF
none
none
none
none
none
none
none
B
A
A
A
B
A
A
A
A
C
A
1
7
3
2
3
3*
3*
3
3
3
3
2-54
-------
Table 8. Continued
Ref.
No.
29
34
35
37
39
41
42
43
44
45
46
Average Factor
Quality Rating
Biphenyldc
—
*
___*
___*
—
3.06e-06 *
2.87e-07 *
9.35e-06DL/2*
1.57e-06DL/2*
—
___*
1.67e-06
D
Acenaph-
thenedc
—
4.72e-07 *
l.lle-07*
1.60e-06*
—
6.46e-07 *
2.16e-07*
6.70e-08 DL/2*
7.18e-07*
—
2.15e-07*
5.06e-07
B
Acenaph-
thylenedc
—
1.97e-07*
6.29e-08 *
6.01e-07 *
—
1.66e-07*
1.31e-07*
6.78e-07 *
9.34e-08 *
—
7.98e-08 *
2.51e-07
B
Anthracenedc
—
2.60e-07 *
8.51e-08*
4.01e-07 *
—
5.04e-07 *
1.83e-07 *
5.61e-08 *
1.09e-07 *
—
9.84e-08 *
2.12e-07
B
Benz(a)an-
thracenedc
—
3.41e-08 *
1.85e-08 *
1.80e-07
—
9.02e-08
2.62e-08 *
2.49e-08
8.23e-08 *
—
1.86e-07 *
8.03e-08
B
Benzo(a)-
pyrenedc
—
4.72e-08 *
2.04e-08 *
4.0 le-08 DL/2*
—
2.92e-08 DL/2*
1.12e-08*
5.80e-09DL/2*
3.68e-09 *
—
1.09e-07 *
3.83e-08
D
2-55
-------
Table 8. Continued
Ref.
No.
29
34
35
37
39
41
42
43
44
45
46
Average Factor
Quality Rating
Benzo(b,j,k)-
fluoranthenedc
—
1.73e-07*
5.00e-08 *
2.40e-07 *
—
1.71e-07
5.61e-08 *
8.32e-08
5.37e-08 *
—
3.99e-08 *
1.08e-07
B
Benzo(g,h,i)-
perylenedc
—
3.15e-08 *
4.07e-08 *
8.02e-08 *
—
2.92e-08 DL/2*
7.48e-09 *
1.20e-08DL/2
4.55e-09DL/2
—
8.24E-08*
2.74e-08
D
Chrysenedc
—
1.81e-07*
4.63e-08 *
4.0 le-08 DL/2*
—
2.17e-07*
6.60e-08 *
___*
*
—
4.79e-08 *
9.97e-08
C
Fluoran-
thenedc
—
1.39e-06 *
4.44e-07 *
6.01e-07 *
—
6.58e-07 *
5.26e-07 *
3.70e-07 *
1.45e-06 *
—
2.66e-07 *
7.13e-07
B
Fluorenedc
—
1.68e-06 *
2.22e-07 *
3.61e-06 *
—
7.63e-07
5.17e-07*
1.04e-07
1.56e-07 *
—
2.63e-07 *
9.14e-07
B
Indeno( 1,2,3 -
cd)pyrenedc
—
3.93e-08
1.59e-07
8.02e-08 *
*
2.92e-08 DL/2*
7.48e-09 *
1.18e-08DL/2*
6.07e-09 *
*
7.18e-08
6.06e-08
C
2-56
-------
Table 8. Continued
Ref.
No.
29
34
35
37
39
41
42
43
44
45
46
Average Factor
Quality Rating
Naphthalenedc Phenanthrenedc
2.82e-05 DL/2
*
___*
1.52e-05 *
5.95e-06
5.25e-06 *
3.18e-06*
8.38e-06 *
4.45e-06 *
5.04e-05
___*
1.33e-05
C
—
5.51e-06*
1.28e-06 *
2.61e-06 *
—
1.89e-06 *
3.91e-06 *
1.21e-06 *
3.70e-06 *
—
1.17e-06*
2.66e-06
B
Pyrenedc
—
6.29e-07 *
2.96e-07 *
2.00e-07
—
3.39e-07
2.02e-07
6.00e-08
6.56e-07
—
2.92e-07
3.34e-07
B
5 -methyl
chrysened
—
3.93e-08
4.3 5e-09 DL/2
—
—
—
—
—
—
—
—
2.18e-08
D
aPC = Pulverized Coal, DB = Dry Bottom, T = Tangential, O = Opposed
bESP = Electrostatic Precipitator, FF = Fabric Filter, FGD = Flue Gas Desulfurization LNB = Low Nox Burners,
OFA = Overfire Air, SD = Spray Dryer, WLS = Wet Limestone Scrubber
These controls were in use during emissions tests.
°An asterisk before a factor indicates that it was used in calculating the overall average.
dA DL/2 after a factor indicates that the pollutant was not detected in any of the sampling runs used to develop factor.
The value shown here represents a factor based on one half of the detection limit.
2-57
-------
Table 9. Data Used to Develop Organic Emission Factors for Section 1.1 of AP-42
Ref.
No.
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
46
47
Average
Quality
No. of
Boilers
4
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Factor
Rating
Coal Type
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Subbituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Bituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Boiler
Type*
PC,DB
PC,DB
PC,DB
AFBC,CB
PC,DB,T
PC,DB,O
PC,DB,T
PC,DB,O
PC,DB,O
PC,DB,W
PC,DB
Cyclone
Cyclone
PC,DB
Cyclone
PC,DB,T
Cyclone
PC,DB
PC,DB
PC,DB
Cyclone
MW
—
—
—
110
700
700
600
667
700
800
267
100
100
117
108
550
568
69
615
500
275
sec
10100222
10100222
10100222
10100238
10100226
10100202
10100212
10100202
10100222
10100222
10100222
10100203
10100203
10100202
10100203
10100302
10100203
10100222
10100202
10100202
10100203
Control
Device lb
ESP
FF
FF
FGD-FIL
OFA
ESP
ESP
ESP
ESP
LNB
LNB
ESP
Reburn/OFA
LNB/OFA
ESP
ESP
ESP
FF
ESP
LNB/OFA
ESP
Control
Device 2b
None
None
None
FF
FGD-WLS
FGD-WLS
None
FGD-WLS
None
FF
FGD-SD
None
ESP
FF
None
FGD-WLS
None
None
None
ESP
None
Control
Device 3b
None
None
None
None
ESP
None
None
None
None
FGD-WLS
FF
None
None
None
None
None
None
None
None
None
None
Data
Quality
B
B
B
A
B
A
A
A
A
A
A
A
A
B
A
A
A
A
C
A
A
No. of
Test Runs
3
3
3
1
1
2
3
7
3
2
2
3
3
3
3
3
3
3
3
3
3
-------
Table 9. Continued
Ref.
No.c
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
46
47
Average Factor
Quality Rating
Acetaldehyded'° Acetophenone40 Acroleind>c Benzene40
*5.45E-07 DL/2
*1.66E-02
6.30E-04DL/2
*4.10E-05
—
*1.82E-05
*2.08E-05
—
—
*1.02E-05
*4.23E-04
*6.07E-05 — — *5.37E-05
*3.07E-05DL/2 — — *2.46E-05
*5.95E-05
*2.17E-03 *1.55E-05 *9.99E-04 *1.93E-04
*8.35E-04 *6.76E-06 *1.37E-05 DL/2 *5.11E-04
*2.91E-04 *2.62E-05 *7.55E-05 *2.57E-03
*9.60E-06 DL/2 *1.25E-05 *5.98E-05 *1.81E-03
*8.84E-05
*1.36E-05
*1.92E-04
5.66E-04 1.52E-05 2.87E-04 1.33E-03
C D D A
bis(2-ethyl-hexyl-
Benzyl-chlorided'c phtlialated
—
—
—
*9.24E-05
—
—
—
—
—
—
—
—
—
—
1.44E-07DL/2
*7.10E-08
*9.78E-05
*2.96E-05
*1.40E-03
—
—
7.00E-04 7.33E-05
D D
-------
Table 9. Continued
Ref. 2-Chloro-
No.° Bromoformd'c Carbon Disulfided>c Carbon Tetrachlorided'c acetophenone40
23
24
24
28
29
30
34
35
36
38
38
39
41 5.85E-05DL/2 *1.44E-04 *6.09E-05 DL/2 7.02E-06
42 *3.86E-05 *4.24E-05 *3.99E-05 DL/2
43 — *2.91E-06
44 — *3.11E-04
4.S
T",J — — ___ ___
46
47
Average 3.86E-05 1.25E-04 5.04E-05 DL/2 7.02E-06
Factor
Quality ED E
Rating
Chlorobenzened'c Chloroformd
—
—
—
—
—
—
— —
—
—
— —
—
—
6.09E-05 DL/2* *6.09E-05 DL/2
*4.11E-05 *3.99E-05 DL/2
—
*2.87E-06
*7.59E-05
—
—
2.20E-05 5.89E-05
D D
-------
Table 9. Continued
-------
Table 9. Continued
Ref.
No.c
Cumene
Cyanided
1,3-Dichloro- N-nitroso
propylened'c Dibutyl Phthalated-c Dimethylamined-c 2,4-Dinitro-toluened
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
*4.77E-05
*4.39E-03
6.35E-04
*6.09E-05 DL/2
*3.99E-05 DL/2
*4.80E-07
*8.10E-08
*5.31E-06
*6.38E-05
*1.71E-05DL/2
*7.80E-06 DL/2
46
47
Average
Factor
Quality
Rating
5.31E-06
2.51E-03
D
5.04E-05 DL/2
4.29E-05 DL/2
7.80E-06 DL/2
2.81E-07
D
-------
Table 9. Continued
-------
Table 9. Continued
Ref.
No.c
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
46
47
Average
Factor
Quality
Rating
Dimethyl Sulfate^ Ethyl Benzene40
*5.45E-07 DL/2
6.30E-04 DL/2
6.30E-04 DL/2
—
—
—
—
—
—
—
—
—
—
—
6.09E-05 DL/2
3.99E-05 DL/2
*2.68E-06
*7.51E-06
*4.76E-05
—
—
4.76E-05 9.38E-05
E D
Ethylidene
Ethyl Chloride40 Ethylene Dichlorided'c Ethylene Dibromided'c Dichlorided
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6.09E-05DL/2 6.09E-05 DL/2 — 6.09E-05 DL/2
*3.99E-05 DL/2 *3.99E-05 — 3.99E-05 DL/2
—
*4.40E-05 — *1.15E-06
—
—
—
4.20E-05 3.99E-05 1.15E-06 5.04E-05 DL/2
DEE
-------
Table 9. Continued
-------
Table 9. Continued
Ref.
No.c
Formaldehyde40
Hexachloro-
butadiened>c
Hexachloro-ethane
Hexane^
Isophorone'
d,c
Methyl Bromided
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
1.54E-04DL/2
7.05E-05 DL/2
*2.22E-04
6.50E-05 DL/2
*6.07E-05
3.07E-05 DL/2
*3.78E-04
*9.50E-05
*2.24E-05
*3.57E-05
*1.49E-05DL/2
*1.56E-03
*1.44E-07DL/2
*1.44E-07DL/2
*3.49E-06
*2.71E-05
*1.70E-04
*5.57E-04
*6.06E-04
7.80E-05 DL/2
*5.36E-05
*2.06E-05
*3.93E-04
46
47
*3.46E-05
*1.73E-05
Average
Factor
Quality
Rating
2.44E-04
1.44E-07DL/2
1.44E-07 DL/2
6.69E-05
D
5.81E-04
D
1.56E-04
D
-------
Table 9. Continued
Ref.
No.c
Methyl Chlorided-c Methyl Hydrazined'c Methyl Ethyl Ketone^ Methyl Methacrylate^
Methyl Tert Butyl
Etherd-c Methylene Chlorided
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
*1.19E-04
*1.32E-03
*1.66E-04
*1.71E-04
*1.24E-04
*1.22E-04
*7.87E-05
;.78E-05 DL/2
*1.52E-03
*2.01E-05
*3.89E-04
*1.88E-04
*3.54E-05
46
47
Average
Factor
Quality
Rating
5.35E-04
D
1.71E-04
3.94E-04
D
2.01E-05
3.54E-05
2.89E-04
D
-------
Table 9. Continued
Ref.
No.c
Phenor
Propion-aldehyded'c Propylene Dichlorided'c l,l,2,2-Tetrachloro-ethaned'c Tetrachloro-ethened'°
Styrened
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
*6.09E-04
*1.50E-04
*6.09E-05 DL/2
*3.99E-05 DL/2
*6.09E-05 DL/2
*3.99E-05DL/2
*2.45E-05
*7.55E-06
*7.55E-05
3.99E-05 DL/2
*9.87E-06
6.09E-05 DL/2
*4.11E-05
*4.23E-06
*3.08E-05
46
47
Average
Factor
Quality
Rating
1.60E-05
D
3.79E-04
D
5.04E-05 DL/2
5.04E-05 DL/2
4.27E-05
D
2.54E-05
D
-------
Table 9. Continued
Ref.
No.c
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
46
47
Average
Factor
Quality
Rating
1,1,1-Trichloro- 1,1,2-Trichloro-
Toluened'c ethaned'c ethane40
*5.45E-07 DL/2
6.30E-04 DL/2
6.30E-04 DL/2
—
—
*2.74E-05 *1.98E-05
*1.35E-04
—
—
*1.02E-05
—
*2.38E-05
*1.65E-05
*2.40E-03
*8.53E-05 6.09E-05 DL/2 *5.85E-05 DL/2
*2.99E-04 3.99E-05 DL/2 *3.99E-05 DL/2
*4.25E-05
*9.59E-05
*1.34E-04
*1.86E-05
*4.68E-05
2.38E-04 1.98E-05 4.92E-05 DL/2
A E
Trichloroethened'c Xylenes4" Vinyl Acetated
*5.45E-07 DL/2
6.30E-04 DL/2
6.30E-04 DL/2
—
—
*1.90E-05
—
—
—
—
—
—
—
—
*6.09E-05 DL/2 6.09E-05 DL/2 6.09E-05 DL/2
*3.99E-05DL/2 *4.36E-05 3.99E-05 DL/2
*3.97E-05
*4.27E-05 *7.55E-06
*7.75E-05
—
—
5.04E-05 DL/2 3.72E-05 7.55E-06
C E
-------
Table 9. Continued
Ref.
No.0 Vinyl Chloride'1'0 Hexachlorobenzened
23
24
24
28
29
30
31
34
35
36
3-7
38
38
39
41 *6.09E-05 DL/2 *1.44E-07DL/2
42 *3.99E-05DL/2 *1.12E-08 DL/2
43
44
45
46
47 -» -»
Average Factor 5.04E-05 DL/2 7.76E-08 DL/2
Quality Rating
-------
Table 9. Continued
PC = Pulverized Coal, DB = Dry Bottom, AFBC = Atmospheric Fluidized Bed Combustion, CB = Circulating Bed, T = Tangential, O =
Opposed, W = Wall.
Controls in use during emissions tests: ESP = Electrostatic Precipitator, FF = Fabric Filter, FGD = Flue Gas Desulfurization, FIL = Furnace
Injection of Limestone, LNB = Low Nox Burners, SD = Spray Dryer, WLS = Wet Limestone Scrubber.
An asterisk before a factor indicates that it was used in calculating the overall emission factor.
A DL/2 after a factor indicates that the pollutant was not detected in any of the sampling runs used to develop the factor. The value shown
here represents a factor based on one-half of the detection limit.
-------
3.0 REFERENCES
1. Stamey-Hall, S., Evaluation Of Nitrogen Oxide Emissions Data From TV A Coal-Fired
Boilers, EPA-600/R-92-242, U. S. Environmental Protection Agency, Research Triangle
Park, NC, December 1992.
2. Vatsky, J. and T. W. Sweeney, Development Of An Ultra-Low NOX Pulverizer Coal
Burner, Presented at the EPA/EPRI 1991 Joint Symposium on Stationary Combustion
NOX Control, Washington, DC, March 25-28, 1991.
3. Lu, T. L.et al, Performance Of A Large Cell-Burner Utility Boiler Retrofit With Foster
Wheeler Low-NOx Burners, Presented at the EPA/EPRI 1991 Joint Symposium on
Stationary Combustion NOX Control, Washington, DC, March 25-28, 1991.
4. Alternative Control Techniques Document NOx Emissions From Utility Boilers, EPA-
453/R-94-023, U. S. Environmental Protection Agency, Research Triangle Park, NC,
March 1994.
5. Jaques, A. P., Canada s Greenhouse Gas Emissions: Estimates for 1990, Prepared for
Environment Canada, Report EPS 5/AP/4, 1992.
6. Marland, G. 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.
7. Rosland, A., Greenhouse Gas Emissions In Norway: Inventories And Estimation
Methods, Oslo: Ministry of Environment, 1993.
8. 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, DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy,
1994.
9. "Alternative Control Techniques Document—NOX Emissions From Utility Boilers," EPA-
453/R-94-023, Office of Air Quality Standards, Research Triangle Park, NC, 1994.
10. "Evaluation of Significant Anthropogenic Sources of Radiatively Important Trace
Gases," PB91-127753, Report prepared for the U.S. EPA, Alliance Technologies
Corporation, Chapel Hill, NC, 1990.
11. Steam: Its Generation And Use, Babcock and Wilcox, New York, 1975.
3-1
-------
12. Winschel, R. A., "The Relationship of Carbon Dioxide Emissions with Coal Rank and
Sulfur Content," Journal Of The Air And Waste Management Association, Vol. 40, no. 6
(June), pp. 861-865, 1990.
13. Muzio, LJ. and J.C. Kramlich, "An Artifact in the Measurement of N2O from
Combustion Sources," Geophysical Research Letters, Vol 15, No. 12 (Nov), pp. 1369-
1372, 1988.
14. Nelson, L. P. et al., "Global Combustion Sources of Nitrous Oxide Emissions," Research
Project 2333-4 Interim Report, Sacramento: Radian Corporation, 1991.
15. Peer, R. L. et al., "Characterization of Nitrous Oxide Emission Sources," Prepared for the
US EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995.
16. Montgomery, T. A. etal., "Continuous Infrared Analysis of N2O in Combustion
Products," The Journal Of The Air And Waste Management Association, Vol. 39, No. 5,
pp. 721-726, 1989.
17. Piccot, S. D. et al., "Emissions and Cost Estimates for Globally Significant
Anthropogenic Combustion Sources of NOX, N2O, CH4, CO, and CO2," EPA Contract
No. 68-02-4288, Research Triangle Park, NC: Radian Corporation, 1990.
18. Electric Utility Trace Substances Synthesis Report Volume 1: Synthesis Report. Electric
Power Research Institute, Palo Alto, California. November, 1994.
19. 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, MN, July
11, 1990.
20. Results of the September 10 and 11, 1991 Mercury Removal Tests on the Units 1 and 2,
and Unit 3 Scrubber Systems at the NSP Sherco Plant in Becker, Minnesota, Interpoll
Laboratories, Inc., Circle Pines, MN, October 30, 1991.
21. 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, MN, January 3, 1992.
22. 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, MN, May 4, 1992.
23. 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, MN,
January 3, 1992.
3-2
-------
24. Results of the December 1991 Air Toxic Emission Study on Units 6 & 7 at the NSP
Riverside Plant, Interpoll Laboratories, Inc., Circle Pines, MN, February 28, 1992.
25. 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, MN, July 1990.
26. 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, MN, July
18, 1990.
27. Results of the March 1990 Trace Metal Characterization Study on Unit 3 at the Sherburne
County Generating Station, Interpoll Laboratories, Circle Pines, MN, June 7, 1990.
28. Field Chemical Emissions Monitoring Project: Site 10 Emissions Monitoring, Radian
Corporation, Austin, TX, October 1992.
29. Field Chemical Emissions Monitoring Project: Site 11 Emissions Monitoring, Radian
Corporation, Austin, TX, October 1992.
30. Field Chemical Emissions Monitoring Project: Site 12 Emissions Monitoring, Radian
Corporation, Austin, TX, November 1992.
31. Field Chemical Emissions Monitoring Project: Site 15 Emissions Monitoring, Radian
Corporation, Austin, TX, October 1992.
32. Field Chemical Emissions Monitoring Project: Site 19 Emissions Monitoring, Radian
Corporation, Austin, TX, April 1993.
33. Field Chemical Emissions Monitoring Project: Site 20 Emissions Monitoring, Radian
Corporation, Austin, TX, March 1994.
34. Field Chemical Emissions Monitoring Project: Site 21 Emissions Monitoring, Radian
Corporation, Austin, TX, August 1993.
35. Field Chemical Emissions Monitoring Project: Site 22 Emissions Report, Radian
Corporation, Austin, TX, February 1994.
36. Field Chemical Emissions Monitoring Project: Site 101 Emissions Report, Radian
Corporation, Austin, TX, October 1994.
37. Field Chemical Emissions Monitoring Project: Site 111 Emissions Report, Radian
Corporation, Austin, TX, May 1993.
3-3
-------
38. Field Chemical Emissions Monitoring Project: Site 114 Report, Radian Corporation,
Austin, TX, May 1994.
39. Field Chemical Emissions Monitoring Project: Site 115 Emissions Report, Radian
Corporation, Austin, TX, November 1994.
40. "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.
41. 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.
42. 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, OH,
December 1993.
43. Toxics Assessment Report, Illinois Power Company, Baldwin Power Station—Unit 2,
Baldwin, Illinois, Volume I—Main Report, Roy F. Weston, Inc., West Chester, PA,
December 1993.
44. Toxics Assessment Report, Minnesota Power Company Boswell Energy Center—Unit 2,
Cohasset, Minnesota, Volume I—Main Report, Roy F. Weston, Inc., West Chester, PA,
December 1993.
45. Assessment of Toxic Emissions From a Coal Fired Power Plant Utilizing an ESP, Final
Report—Revision 1, Energy and Environmental Research Corporation, Irvine, CA,
December 23, 1993.
46. 500-MW Demonstration of Advanced Wall-Fired Combustion Techniques for the
Reduction of Nitrogen Oxide (NOx) Emissions from Coal-Fired Boilers, Radian
Corporation, Austin, TX.
47. Field Chemical Emissions Monitoring Report: Site 122, Final Report, Task 1 Third
Draft, EPRIRP9028-10, Southern Research Institute, Birmingham, AL, May 1995.
48. Hydrogen Chloride And Hydrogen Fluoride Emission Factors For The NAPAP
Inventory, EPA-600/7-85-041, U. S. Environmental Protection Agency, October, 1985.
3-4
-------
4.0 REVISED SECTION 1.1
This section contains the revised Section 1.1 of AP-42, 5th Edition. The electronic
version can be located on the EPA TTN CHIEF Web site at
http://www.epa.gov/ttn/chief/ap42c 1. html
4-1
-------
5.0 EMIS SIGN FACTOR DOCUMENTATION, APRIL 1993
This section contains the Emission Factor Documentation for Section 1.1, Bituminous
and Subbituminous Coal Combustion, dated April 1993. The electronic version can be located
on the EPA TTN at http:\\134.67.104.12\html\chief\fbgdocs.htm.
5-1
-------
REFERENCE 19 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
Appendix A
TEST REPORT TITLE:
RESULTS OF THE MARCH 28, 1990 DIOXIN EMISSION
PERFORMANCE TEST ON UNIT 3 AT THE NSP SHERCO
PLANT IN BECKER, MINNESOTA
FACILITY: NSP SHERCO
UNIT NO.: 3
LOCATION: Becker, Minnesota
FILENAME SHERCO3.tbl
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal
(Btu/lb)d
HHV Bituminous Coal
(Btu/ton)
Coal Feed (ton/hr)
Coal type6
Boiler configuration6
Coal source6
sec
Control device le
Control device 2e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
Run 1
6.30
1,971,603
118,296,180
9,780
8,450
8,547
17,094,000
Run 2 Run 3
5.80 5.80
1,939,776 1,952,851
116,386,560 117,171,060
9,780 9,780
8,598 8,656
8,547 8,547
17,094,000 17,094,000
503
494
Subbituminous
Pulverized, dry bottom
Montana
10100222
Flue Gas Desulfurization, Spray Dryer absorber
Baghouse
C- Coal heating value and feed rate not provided.
860 megawatts, on line in 1987.
MM5
3
506
5-1
-------
REFERENCE 19 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
aPage 8.
bPage 9.
C40 CFR Pt 60, App A, Meth. 19, Bituminous coal
dFrom report "Results of the May 29, 1990 Trace Metal Characterization Study on Units 1 and 2 at
the Sherburne County Generating Station in Becker, Minnesota", page G-l. (Reference No. 25).
ePage 1. Assumed dry bottom.
fPage 1.
gPage 5.
5-2
-------
REFERENCE 19 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
DIOXIN/FURAN EMISSION
EMISSION RATES (g/sec)a
TCDD
PeCDD
HxCDD
HpCDD
OCDD
TCDF
PeCDF
HxCDF
HpCDF
OCDF
EMISSION RATES (lb/hr)b
TCDD
PeCDD
HxCDD
HpCDD
OCDD
TCDF
PeCDF
HxCDF
HpCDF
OCDF
FACTORS
Run 1
4.0e-08
7.8e-08
3.2e-07
1.19e-06
3.51e-06
3.2e-07
5.7e-07
1.43e-06
5.12e-06
1.670e-05
Run 1
3.18e-07
6.19e-07
2.54e-06
9.45e-06
2.79e-05
2.54e-06
4.52e-06
1.14e-05
4.06e-05
1.33e-04
Run 2
2.0e-08
3.8e-08
1.6e-07
4.6e-07
1.16e-06
l.Oe-07
2.2e-07
6.5e-07
1.97e-06
5.12e-06
Run 2
1.59e-07
3.02e-07
1.27e-06
3.65e-06
9.21e-06
7.94e-07
1.75e-06
5.16e-06
1.56e-05
4.06e-05
Run 3 AVG
1.4e-08
1.7e-08
8.6e-08
2.4e-07
7.2e-07
4.8e-08
1.2e-07
3.2e-07
1.18e-06
4.02e-06
Run 3 AVG
l.lle-07
1.35e-07
6.83e-07
1.91e-06
5.72e-06
3.81e-07
9.53e-07
2.54e-06
9.37e-06
3.19e-05
5-3
-------
REFERENCE 19 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
EMISSION FACTORS
(lb/ton)c
TCDD
PeCDD
HxCDD
HpCDD
OCDD
TCDF
PeCDF
HxCDF
HpCDF
OCDF
Run 1
6.42e-10
1.25e-09
5.14e-09
1.91e-08
5.64e-08
5.14e-09
9.15e-09
2.30e-08
8.22e-08
2.68e-07
Run 2
3.16e-10
6.00e-10
2.53e-09
7.26e-09
1.83e-08
1.58e-09
3.47e-09
1.03e-08
3.11e-08
8.08e-08
Run 3
2.19e-10
2.67e-10
1.35e-09
3.76e-09
1.13e-08
7.52e-10
1.88e-09
5.02e-09
1.85e-08
6.30e-08
AVG
3.93e-10
7.06e-10
3.00e-09
l.OOe-08
2.87e-08
2.49e-09
4.84e-09
1.27e-08
4.39e-08
1.37e-07
aPage 4
bConvert g/sec to Ib/hr.
°Divide emission rate by coal feed rate.
5-4
-------
REFERENCE 20 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 10 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
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
FACILITY:
UNIT NO.:
LOCATION:
FILENAME:
NSP SHERCO
3
Becker, Minnesota
SHRCO123.tbl
PROCESS DATA UNIT 3
Vol. Flow Rate (dscf/m)a
Vol. Flow Rate (dscf/hr)
Coal Feed (ton/hr)b
Coal type0
Boiler configuration0
Coal source0
sec
Control device 1°
Control device 2°
Data Quality
Process Parameters0
Test methods0
Number of test runsd
Run 1 Run 2 Run 3
1,909,745 1,908,275 1,850,934
114,584,700 114,496,500 111,056,040
490 494 503
Subbituminous
Pulverized, dry bottom
Montana
10100222
Flue Gas Desulfurization, Spray Dryer absorber
Baghouse
A
860 megawatts, on line in 1987.
EPA 101 A for mercury
3
aPage 18.
bPage 7.
°Page 1. Assumed to be dry bottom.
dPage 5.
MERCURY EMISSION FACTORS
EMISSION RATES (lb/hr)a
EMISSION FACTOR (lb/ton)b
UNIT 3
Run 1 Run 2 Run 3 AVG
0.038 0.043 0.044
7.76e-05 8.70e-05 8.75e-05 8.40e-05
aPage 5.
bDivide emission rate by coal feed rate.
5-5
-------
REFERENCE 20 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 10 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
PROCESS DATA UNITS 1 & 2
Vol. Flow Rate (dscf/m)a
Vol. Flow Rate (dscf/hr)
Coal Feed (ton/hr)b
Coal typec
Boiler configuration0
Coal source0
sec
Control device 1°
Control device 2°
Data Quality
Process Parameters0
Test methods0
Number of test runsd
Run 1 Run 2 Run 3
3,334,932 3,376,641 3,313,486
200,095,920 202,598,460 198,809,160
764 775 766
Subbituminous
Pulverized, assume dry bottom
70% Wyoming/30% Montana
10100222
Flue Gas Desulfurization, Venturi Scrubber Spray Tower
A
750 MW each, on line in 1976
EPA 101 A for mercury
3
aPage 16.
bPage 7.
°Page 1.
dPage 5.
MERCURY EMISSION FACTORS
EMISSION RATES (lb/hr)a
EMISSION FACTOR (lb/ton)b
UNIT 1 & 2
Run 1 Run 2 Run 3 AVG
0.042 0.025 0.090
5.50e-05 3.23e-05 1.17e-04 6.82e-05
aPage 5.
bDivide emission rate by coal feed rate.
5-6
-------
REFERENCE 21 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 11 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
RESULTS OF THE NOVEMBER 5, 1991 AIR TOXIC EMISSION
STUDY ON THE NO. 1, 3 & 4 BOILERS AT THE NSP BLACK DOG
PLANT
FACILITY:
UNIT NO.:
LOCATION:
FILENAME
NSP BLACK DOG
1,3&4
Burnsville, Minnesota
BLKDG134.tbl
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Coal type6
Boiler configuration6
Coal source6
sec
Control device le
Control device 2e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
METALS
Run 1 Run 2 Run 3
7.10 6.80 6.60
836,298 842,891 824,638
50,177,880 50,573,460 49,478,280
9,780 9,780 9,780
3,388 3,489 3,462
8,707 8,707 8,707
17,414,000 17,414,000 17,414,000
195 200 199
Subbituminous
Pulverized, dry bottom
Antelope/North Antelope
10100222
ESP
ESP
B Had to use F-factor and average HHV to get
coal feed rate, ton/hr.
Three watertube boilers at 720,000, 775,000 and
1,250,000 Ib/hr steam.
MM 5 metals
3
aPage 22.
bPage 29.
cPage 29.
dSection 4 Results of Fuel Analyses.
ePage 1. Assumed dry bottom.
fPage 1.
8Various pages.
5-7
-------
REFERENCE 21 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 11 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimonyb
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum13
Nickel
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
Run 1
8.8
0.019
0.0021
0.67
0.00036
0.11
0.0017
12.6
0.0071
0.037
3.1
0.017
2.7
0.019
0.017
0.0063
0.012
0.52
0.0042
0.0038
1490
1.5
0.23
0.023
0.059
Run 2
9.7
0.019
0.0021
0.51
0.00047
0.099
0.013
15.2
0.013
0.14
3.8
0.19
3.2
0.021
0.0087
0.0063
0.052
0.93
0.0042
0.0032
1630
2.5
0.23
0.025
0.46
Run 3 AVG
10.9
0.019
0.0021
0.22
0.00055
0.12
0.017
13.2
0.009
0.034
4.1
0.0084
3.6
0.022
0.022
0.0063
0.0092
0.65
0.0042
0.0078
1460
1.9
0.19
0.026
0.091
5-8
-------
REFERENCE 21 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 11 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS (lb/ton)c
Aluminum
Antimonyb
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenumb
Nickel
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
aTable 3 (page 13?).
bNot detected in any of the sampling runs,
°Divide emission rate by coal feed rate.
Run 1
4.52e-02
9.77e-05
1.08e-05
3.44e-03
1.85e-06
5.65e-04
8.74e-06
6.48e-02
3.65e-05
1.90e-04
1.59e-02
8.74e-05
1.39e-02
9.77e-05
8.74e-05
3.24e-05
6.17e-05
2.67e-03
2.16e-05
1.95e-05
7.66e+00
7.71e-03
1.18e-03
1.18e-04
3.03e-04
emission factor is
Run 2
4.84e-02
9.48e-05
1.05e-05
2.55e-03
2.35e-06
4.94e-04
6.49e-05
7.59e-02
6.49e-05
6.99e-04
1.90e-02
9.48e-04
1.60e-02
1.05e-04
4.34e-05
3.14e-05
2.60e-04
4.64e-03
2.10e-05
1.60e-05
8.14e+00
1.25e-02
1.15e-03
1.25e-04
2.30e-03
based on detection
Run 3
5.48e-02
9.56e-05
1.06e-05
l.lle-03
2.77e-06
6.04e-04
8.55e-05
6.64e-02
4.53e-05
1.71e-04
2.06e-02
4.23e-05
1.81e-02
l.lle-04
l.lle-04
3.17e-05
4.63e-05
3.27e-03
2.11e-05
3.92e-05
7.34e+00
9.56e-03
9.56e-04
1.31e-04
4.58e-04
limits.
AVG
4.95e-02
9.60e-05
1.06e-05
2.37e-03
2.32e-06
5.54e-04
5.31e-05
6.90e-02
4.89e-05
3.53e-04
1.85e-02
3.59e-04
1.60e-02
1.04e-04
8.05e-05
3.18e-05
1.23e-04
3.53e-03
2.12e-05
2.49e-05
7.71e+0
9.92e-03
1.10e-03
1.25e-04
1.02e-03
5-9
-------
REFERENCE 22 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 12 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
RESULTS OF THE JANUARY 1992 AIR TOXIC EMISSION STUDY
ON THE NO. 2 BOILER AT THE NSP BLACK DOG PLANT
FACILITY:
UNIT NO.:
LOCATION:
FILENAME
NSP BLACK DOG
2
Burnsville, Minnesota
BLKDOG2.tbl
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Coal type6
Boiler configuration6
Coal source6
sec
Control Device le
Control device 2e
Control device 3e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
METALS
Run 1 Run 2 Run 3
10.40 10.20 10.20
354,118 351,097 354,635
21,247,080 21,065,820 21,278,100
9,780 9,780 9,780
1,091 1,103 1,114
8,553 8,553 8,553
17,106,000 17,106,000 17,106,000
64 64 65
Subbituminous
Atmospheric Fluidized bed Combustor (AFBC), circulating bed
Antelope/North Antelope
10100238
Cyclone (mechanical dust collector)
ESP
ESP
B
Had to use F-factor and average HHV to get
coal feed rate (ton/hr).
137 MW
MM 5 metalS.
2 for lead, 3 for all others
aPage 20.
bPage25.
cPage25.
dPage31
ePage 1. Coal from Antelope/Northern Antelope is subbituminous, according to another report.
fPage 1.
gVarious pages.
5-10
-------
REFERENCE 22 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 12 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimonyb
Arsenic
Barium
Berylliumb
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silverb
SO2
Sodium
Strontium
Vanadium
Zinc
Run 1
1.05
0.0006
0.000584
0.0541
0.00003
0.0927
0.00403
4.05
0.00573
0.0139
0.969
0.0496
0.704
0.00529
0.0029
0.0064
0.0376
0.07
0.000602
0.0006
362
0.837
0.056
0.00437
0.122
Run 2
1.29
0.0006
0.000603
0.0639
0.00003
0.101
0.0117
4.59
0.0112
0.0177
1.04
0.812
0.00615
0.00265
0.0135
0.0471
0.107
0.000299
0.0006
356
0.983
0.0651
0.00434
0.092
Run 3 AVG
1.33
0.0006
0.000559
0.0691
0.00003
0.0847
0.00575
4.76
0.00386
0.0113
1.15
0.0613
0.835
0.00895
0.00297
0.0051
0.01
0.0901
0.000445
0.0006
334
0.829
0.0733
0.00436
0.0479
5-11
-------
REFERENCE 22 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 12 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS (lb/ton)c
Aluminum
Antimonyb
Arsenic
Barium
Berylliumb
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silverb
SO2
Sodium
Strontium
Vanadium
Zinc
Tage 11
bPollutant was not detected in any of the
°Divide emission rate by coal feed rate.
Run 1
1.65e-02
9.40e-06
9.15e-06
8.48e-04
4.70e-07
1.45e-03
6.32e-05
6.35e-02
8.98e-05
2.18e-04
1.52e-02
7.77e-04
1.10e-02
8.29e-05
4.55e-05
l.OOe-04
5.89e-04
1.10e-03
9.43e-06
9.40e-06
5.67e+00
1.31e-02
8.78e-04
6.85e-05
1.91e-03
sampling runs,
Run 2
2.00e-02
9.31e-06
9.35e-06
9.91e-04
4.65e-07
1.57e-03
1.81e-04
7.12e-02
1.74e-04
2.75e-04
1.61e-02
1.26e-02
9.54e-05
4.11e-05
2.09e-04
7.31e-04
1.66e-03
4.64e-06
9.31e-06
5.52e+00
1.52e-02
l.Ole-03
6.73e-05
1.43e-03
detection limits used to
Run 3
2.04e-02
9.21e-06
8.58e-06
1.06e-03
4.61e-07
1.30e-03
8.83e-05
7.31e-02
5.93e-05
1.74e-04
1.77e-02
9.41e-04
1.28e-02
1.37e-04
4.56e-05
7.83e-05
1.54e-04
1.38e-03
6.83e-06
9.21e-06
5.13e+00
1.27e-02
1.13e-03
6.70e-05
7.36e-04
develop rates
AVG
1.90e-02
9.31e-06
9.03e-06
9.67e-04
4.65e-07
1.44e-03
l.lle-04
6.93e-02
1.08e-04
2.22e-04
1.63e-02
8.59e-04
1.22e-02
1.05e-04
4.41e-05
1.29e-04
4.91e-04
1.38e-03
6.97e-06
9.31e-06
5.44e+00
1.37e-02
l.OOe-03
6.76e-05
1.36e-03
5-12
-------
REFERENCE 23 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 13 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
RESULTS OF THE NOVEMBER 7, 1991 AIR TOXIC EMISSION
STUDY ON THE NOS. 3, 4, 5 & 6 BOILERS AT THE NSP HIGH
BRIDGE PLANT
FACILITY:
UNIT NO.:
LOCATION:
FILENAME
NSP High Bridge
3, 4, 5 & 6
St. Paul, Minnesota
HIBRIDGE.tbl
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Coal type6
Boiler configuration6
Coal source6
sec
Control device le
Control device 2e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
METALS
Run 1
7.70
804,786
48,287,160
9,780
3,118
8,498
16,996,000
183
Subbituminous
Run 2
7.60
788,668
47,320,080 48,
9,780
3,079
8,498
16,996,000 16,
181
Run 3
7.80
815,076
904,560
9,780
3,134
8,498
996,000
184
Pulverized, dry bottom
Rochelle
10100222
ESPC
None
B
Watertube boilers
Had to use F-factor and
coal feed rate, ton/hr.
with economizers and air
average HHV to get
preheaters
MM 5 metals, Method 18 for BTEX
3
aPage 29.
bPage 37.
C40 CFR Pt 60, App A, Meth. 19
dPage 42
ePage 1. Assumed dry bottom.
fPage 1 for metals, page 3 for BTEX.
8Various pages.
5-13
-------
REFERENCE 23 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 13 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercuryb
Molybdenum
Nickel
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
Run 1
4.17
0.00126
0.00126
0.406
0.00018
0.127
0.0023
5.25
0.023
0.036
1.66
0.015
1.03
0.033
0.013
0.059
0.012
0.54
0.0036
0.072
1,319
1.22
0.17
0.0066
0.074
Run 2
3.24
0.00456
0.00091
0.350
0.00018
0.105
0.0018
4.12
0.018
0.024
1.42
0.0091
0.82
0.015
0.010
0.046
0.0091
0.38
0.0018
0.051
1,290
1.02
0.12
0.0067
0.049
Run 3 AVG
4.63
0.00092
0.00092
0.433
0.00037
0.118
0.002
6.45
0.024
0.028
1.55
0.0092
1.14
0.028
0.013
0.061
0.011
0.49
0.0018
0.037
1,247
1.40
0.15
0.0068
0.050
5-14
-------
REFERENCE 23 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 13 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS (lb/ton)c
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercuryb
Molybdenum
Nickel
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
Run 1
2.27e-02
6.87e-06
6.87e-06
2.21e-03
9.81e-07
6.92e-04
1.25e-05
2.86e-02
1.25e-04
1.96e-04
9.05e-03
8.18e-05
5.61e-03
1.80e-04
7.09e-05
3.22e-04
6.54e-05
2.94e-03
1.96e-05
3.92e-04
7.19e+00
6.65e-03
9.27e-04
3.60e-05
4.03e-04
"Table 4, page 16.
bPollutant not detected in any of the sampling runs, detection
°Divide emission rate by coal feed rate.
Run 2
1.79e-02
2.52e-05
5.02e-06
1.93e-03
9.94e-07
5.80e-04
9.94e-06
2.27e-02
9.94e-05
1.32e-04
7.84e-03
5.02e-05
4.53e-03
8.28e-05
5.52e-05
2.54e-04
5.02e-05
2.10e-03
9.94e-06
2.82e-04
7.12e+00
5.63e-03
6.62e-04
3.70e-05
2.70e-04
limit used to
Run 3
2.51e-02
4.99e-06
4.99e-06
2.35e-03
2.01e-06
6.40e-04
1.08e-05
3.50e-02
1.30e-04
1.52e-04
8.41e-03
4.99e-05
6.18e-03
1.52e-04
7.05e-05
3.31e-04
5.96e-05
2.66e-03
9.76e-06
2.01e-04
6.76e+00
7.59e-03
8.13e-04
3.69e-05
2.71e-04
develop emission
AVG
2.19e-02
1.23e-05
5.63e-06
2.16e-03
1.33e-06
6.37e-04
l.lle-05
2.88e-02
1.18e-04
1.60e-04
8.43e-03
6.06e-05
5.44e-03
1.38e-04
6.55e-05
3.02e-04
5.84e-05
2.57e-03
1.31e-05
2.92e-04
7.02e+00
6.62e-03
8.01e-04
3.66e-05
3.15e-04
factor.
5-15
-------
REFERENCE 23 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 13 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
BTEX EMISSION FACTORS
EMISSION RATES (lb/hr)a
Benzeneb
Tolueneb
Ethyl Benzeneb
Xyleneb
Run 1
0.2
0.2
0.2
0.2
Run 2
0.2
0.2
0.2
0.2
Run 3
0.2
0.2
0.2
0.2
apage 22
EMISSION FACTORS (lb/ton)c
Benzeneb
Tolueneb
Ethyl Benzeneb
Xyleneb
apage 22
bPollutant was not detected in any of the
factor.
°Divide emission rate by coal feed rate.
Run 1
1.09e-03
1.09e-03
1.09e-03
1.09e-03
sampling runs,
Run 2
1.10e-03
1.10e-03
1.10e-03
1.10e-03
detection limits used to
Run 3
1.08e-03
1.08e-03
1.08e-03
1.08e-03
AVG
1.09e-03
1.09e-03
1.09e-03
1.09e-03
develop emission
5-16
-------
REFERENCE 24 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 14 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
RESULTS OF THE DECEMBER 1991 AIR TOXIC EMISSION
STUDY ON UNITS 6 & 7 AT THE NSP RIVERSIDE PLANT
FACILITY: NSP Riverside
UNIT NO.: 6,7
LOCATION: Minneapolis, Mn
FILENAME RIVERSID.tbl
PROCESS DATA
Coal type3
Boiler configuration3
Coal source3
sec
Control device lb
Control device 2b
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Subbituminous
Pulverized, dry bottom
Rochelle
10100222
Baghouse
None
B
575,000 Ib/hr steam
preheaters.
Had to use F-factor and average HHV to get
coal feed rate (ton/hr)
each; equipped with economizers and air
MM5 for PM/Metals, Method 18 for BTEX.
3
FLOW RATES, COAL FEED RATES
Volumentric flow rate (dscf/m)e
Volumentric flow rate (dscf/hr)
F-Factor (dscf/MMBtu)f
O2 %v/v8
Heat input (MMBtu/hr)
Coal HHV (Btu/lb)h
Coal HHV (Btu/ton)
Coal feed rate (ton/hr)
Run 1
193,851
11,631,060
9,780
6.00
848
8,602
17,204,000
49.28
Unit 6
Run 2
189,541
11,372,460 11,
9,780
6.00
829
8,602
17,204,000 17,
48.19
Run 3
187,122
227,320
9,780
6.60
785
8,602
204,000
45.66
5-17
-------
REFERENCE 24 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 14 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
Volumentric flow rate (dscf/m)e
Volumentric flow rate (dscf/hr) 1 1,
F-Factor (dscf/MMBtu)f
O2 %v/v8
Heat input (MMBtu/hr)
Coal HHV (Btu/lb)h
Coal HHV (Btu/ton) 17,
Coal feed rate (ton/hr)
Tage 1. Assumed dry bottom.
bPage 2.
Tage 1, 3, 24.
dVarious pages.
Tage 29 for Unit 6 metals, Page 30 for Unit 7
fPage 28.
8Page 23 for Unit 6 metals, Page 24 for Unit 7
Tage 36.
METALS EMISSION FACTORS UNITS 6 &
EMISSION RATES (lb/hr)a
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Run 1
188,847
330,820
9,780
6.30
809
8,602
204,000
47.04
metals.
metals.
7
Run 1
13.9
0.00075
0.00174
0.073
0.00073
0.132
0.115
23.4
0.0228
0.060
5.5
0.0134
4.9
0.0298
Unit 7
Run 2
188,814
11,328,840
9,780
6.20
815
8,602
17,204,000
47.36
Run 2
16.7
0.00067
0.00183
0.005
0.0007
0.022
0.0141
27.7
0.0209
0.065
6.7
0.0100
5.9
0.0400
Run 3
194,376
11,662,560
9,780
6.30
833
8,602
17,204,000
48.42
Run 3 AVG
15.5
0.00024
0.00183
0.002
0.00088
0.007
0.0101
19.0
0.0234
0.053
5.9
0.0096
5.3
0.0252
5-18
-------
REFERENCE 24 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 14 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS UNITS 6 & 7
EMISSION RATES (lb/hr)a
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
EMISSION FACTORS (lb/ton)b
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Run 1
0.013
0.00198
0.0285
0.55
0.00706
0.005
875
2.03
0.328
0.0289
0.071
Run 1
1.44e-01
7.79e-06
1.81e-05
7.58e-04
7.58e-06
1.37e-03
1.19e-03
2.43e-01
2.37e-04
6.23e-04
5.71e-02
1.39e-04
5.09e-02
3.09e-04
1.35e-04
2.06e-05
2.96e-04
Run 2
0.006
0.00409
0.113
0.78
0.00289
0.002
788
2.85
0.372
0.0390
0.278
Run 2
1.75e-01
7.01e-06
1.92e-05
5.23e-05
7.33e-06
2.30e-04
1.48e-04
2.90e-01
2.19e-04
6.80e-04
7.01e-02
1.05e-04
6.18e-02
4.19e-04
6.28e-05
4.28e-05
1.18e-03
Run 3
0.005
0.00434
0.0234
0.61
0.00193
0.002
762
2.49
0.256
0.0347
0.006
Run 3
1.65e-01
2.55e-06
1.95e-05
2.13e-05
9.35e-06
7.44e-05
1.07e-04
2.02e-01
2.49e-04
5.63e-04
6.27e-02
1.02e-04
5.63e-02
2.68e-04
5.31e-05
4.61e-05
2.49e-04
AVG
AVG
1.61e-01
5.78e-06
1.89e-05
2.77e-04
8.09e-06
5.58e-04
4.83e-04
2.45e-01
2.35e-04
6.22e-04
6.33e-02
1.15e-04
5.63e-02
3.32e-04
8.36e-05
3.65e-05
5.76e-04
5-19
-------
REFERENCE 24 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 14 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS (lb/ton)b
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
Run 1
5.71e-03
7.33e-05
5.19e-05
9.08e+00
2.11e-02
3.41e-03
3.00e-04
7.37e-04
Run 2
8.16e-03
3.02e-05
2.09e-05
8.25e+00
2.98e-02
3.89e-03
4.08e-04
2.91e-03
Run 3
6.48e-03
2.05e-05
2.13e-05
8.10e+00
2.65e-02
2.72e-03
3.69e-04
6.38e-05
AVG
6.79e-03
4.14e-05
3.14e-05
8.48e+00
2.58e-02
3.34e-03
3.59e-04
1.24e-03
aTable 8, page 16.
bDivide emission rate by coal feed rate.
BTEX EMISSION FACTORS UNIT 6
Emission Rates (lb/hr)a
Benzene
Tolueneb
Ethylbenzeneb
Xyleneb
Emission Factors (lb/ton)°
Benzene
Tolueneb
Ethylbenzeneb
Xyleneb
apage 19.
bPollutant was not detected in any of the
°Divide emission rate by coal feed rate.
BTEX EMISSION FACTORS UNIT 7
Emission Rates (lb/hr)a
Benzeneb
Tolueneb
Ethylbenzeneb
Xyleneb
Run 1
1.02
0.06
0.06
0.06
2.07e-02
1.22e-03
1.22e-03
1.22e-03
sampling runs.
Run 1
0.06
0.06
0.06
0.06
Run 2
1.05
0.06
0.06
0.06
2.18e-02
1.25e-03
1.25e-03
1.25e-03
Run 3
0.33
0.06
0.06
0.06
7.23e-03
1.31e-03
1.31e-03
1.31e-03
avg
1.66e-02
1.26e-03
1.26e-03
1.26e-03
EF is based on detection limits.
Run 2
0.06
0.06
0.06
0.06
Run 3
0.06
0.06
0.06
0.06
5-20
-------
REFERENCE 24 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 14 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
Emission Factors (lb/ton)°
Benzeneb
Tolueneb
Ethylbenzeneb
Xyleneb
apage 19.
bPollutant was not detected in any of the
°Divide emission rate by coal feed rate.
1.28e-03
1.28e-03
1.28e-03
1.28e-03
sampling runs.
1.27e-03 1
1.27e-03 1
1.27e-03 1
1.27e-03 1
EF is based on detection
24e-03
24e-03
24e-03
24e-03
limits.
1.26e-03
1.26e-03
1.26e-03
1.26e-03
5-21
-------
REFERENCE 25 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 15 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
RESULTS OF THE MAY 29, 1990 TRACE METAL
CHARACTERIZATION STUDY ON UNITS 1 AND 2 AT THE
SHERBURNE COUNTY GENERATING STATION IN BECKER,
MINNESOTA
FACILITY:
UNIT NO.:
LOCATION:
FILENAME
NSP Sherco
1,2
Becker, Minnesota
SHERCO 12.tbl
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Coal type6
Boiler configuration6
Coal source6
sec
Control device P
Control device 2e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
PM/METALS
Run 1 Run 2 Run 3
6.60 6.50 6.60
3,305,953 3,340,203 3,106,503
198,357,180 200,412,180 186,390,180
9,780 9,780 9,780
13,877 14,119 13,040
8,547 8,547 8,547
17,094,000 17,094,000 17,094,000
812 826 763
Subbituminous
Pulverized, dry bottom
80% Rochelle/20% Coalstrip
10100222
Flue Gas Desulfurization, Venturi Scrubber Spray Tower
None
B
Had to use F-factor and average HHV to get coal
feed rate, ton/hr.
750 MW each, on line in 1976.
MM 5
2 for nickel, 3 for all others
aPage 7.
bPage 8.
C40 CFR Pt 60, App A.
dPageG-l.
ePage 1.
fPage 1.
gVarious pages.
5-22
-------
REFERENCE 25 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 15 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silverb
Sodium
Strontium
Vanadium
Zinc
aPage 5.
bPollutant was not detected in any of the
Run 1
8.9725
0.0084
0.0304
3.3101
0.0033
4.1097
0.0205
67.2241
0.2046
0.1302
10.3672
0.1116
7.0757
0.3068
0.0093
0.0279
0.0186
1.5806
0.0818
0.0112
4.7419
2.5197
0.2603
0.2696
sampling runs.
Run 2
23.3877
0.0041
0.0433
6.4375
0.0036
86.2852
0.0132
141.6439
0.1788
0.1694
13.7879
0.0941
18.5219
0.3294
0.0196
0.0471
—
2.0705
0.1129
0.0113
6.8704
4.5928
0.3294
0.3106
EF is based on
Run 3 AVG
7.7052
0.0092
0.0326
2.6330
0.0035
43.3077
0.0097
72.3851
0.0881
0.1321
9.5545
0.0969
6.6221
0.6076
0.0141
0.0264
0.0185
1.8493
0.1233
0.0114
5.4597
2.4657
0.2906
0.2378
detection limits.
5-23
-------
REFERENCE 25 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 15 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS (lb/ton)c
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silverb
Sodium
Strontium
Vanadium
Zinc
aPage 5.
bPollutant was not detected in any of the
°Divide emission rate by coal feed rate.
Run 1
l.lle-02
1.03e-05
3.74e-05
4.08e-03
4.06e-06
5.06e-03
2.53e-05
8.28e-02
2.52e-04
1.60e-04
1.28e-02
1.37e-04
8.72e-03
3.78e-04
1.15e-05
3.44e-05
2.29e-05
1.95e-03
l.Ole-04
1.38e-05
5.84e-03
3.10e-03
3.21e-04
3.32e-04
sampling runs.
Run 2
2.83e-02
4.96e-06
5.24e-05
7.79e-03
4.36e-06
1.04e-01
1.60e-05
1.71e-01
2.16e-04
2.05e-04
1.67e-02
1.14e-04
2.24e-02
3.99e-04
2.37e-05
5.70e-05
2.51e-03
1.37e-04
1.37e-05
8.32e-03
5.56e-03
3.99e-04
3.76e-04
EF is based on
Run 3
l.Ole-02
1.21e-05
4.27e-05
3.45e-03
4.59e-06
5.68e-02
1.27e-05
9.49e-02
1.15e-04
1.73e-04
1.25e-02
1.27e-04
8.68e-03
7.97e-04
1.85e-05
3.46e-05
2.43e-05
2.42e-03
1.62e-04
1.49e-05
7.16e-03
3.23e-03
3.81e-04
3.12e-04
detection limits.
AVG
1.65e-02
9.12e-06
4.42e-05
5.11e-03
4.34e-06
5.54e-02
1.80e-05
1.16e-01
1.95e-04
1.80e-04
1.40e-02
1.26e-04
1.33e-02
5.24e-04
1.79e-05
4.20e-05
2.36e-05
2.29e-03
1.33e-04
1.41e-05
7.11e-03
3.97e-03
3.67e-04
3.40e-04
5-24
-------
REFERENCE 26 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 16 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE: RESULTS OF THE MAY 1, 1990 TRACE METAL
CHARACTERIZATION STUDY ON UNITS 1 AND 2 AT THE
SHERBURNE COUNTY GENERATING STATION
FACILITY: NSP Sherco
UNIT NO.: 1,2
LOCATION: Becker, Minnesota
FILENAME SHRCO12A.TBL
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Coal type6
Boiler configuration6
Coal source
sec
Control device P
Control device 2e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
METALS
Run 1 Run 2 Run 3
6.60 6.60 6.70
3,284,153 3,326,471 3,347,367
197,049,180 199,588,260 200,842,020
9,780 9,780 9,780
13,786 13,963 13,953
8,547 8,547 8,547
17,094,000 17,094,000 17,094,000
806 817 816
Subbituminous
Pulverized, dry bottom
no data
10100222
Flue Gas Desulfurization, Venturi Scrubber Spray Tower
None
B
Had to use F-factor and average HHV to get coal
feed rate, ton/hr.
750 MW each, on line in 1976.
MM 5 metals.
2 for cadmium, nickel, copper and zinc; 3 for all others
aPage 14.
bPage 19.
C40 CFR Pt 60, App A.
dFrom report "Results of the May 29, 1990 Trace Metal Characterization Study on Units 1 and 2
at the Sherburne County Generating Station in Becker, Minnesota", page G-l. (Reference
No. 25)
ePage 1 of "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" (Reference 19).
Dry bottom assumed.
fPage 2.
gVarious pages.
5-25
-------
REFERENCE 26 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 16 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum b
Nickel
Potassium
Selenium
Silver
Sodium
Strontium
Vanadium
Zinc
Run 1
9.58
0.016
0.035
3.59
0.0037
98.0
—
126
0.133
—
14.6
0.127
5.36
0.281
0.092
0.027
—
2.00
0.109
0.009
7.67
3.26
0.300
—
Run 2
11.06
0.011
0.039
5.81
0.0042
18.1
0.029
141
0.101
0.200
14.6
0.118
7.65
0.401
0.078
0.027
0.071
1.88
0.137
0.010
6.42
3.82
0.291
0.70
Run 3 AVG
8.86
0.009
0.030
2.25
0.0038
38.1
0.049
129
0.092
0.227
12.9
0.100
5.91
0.273
0.063
0.027
0.052
1.74
0.118
0.030
5.13
3.09
0.282
0.45
5-26
-------
REFERENCE 26 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 16 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS (lb/ton)c
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenumb
Nickel
Potassium
Selenium
Silver
Sodium
Strontium
Vanadium
Zinc
"Pages 5 and 7.
bPollutant was not detected in any of the
°Divide emission rate by coal feed rate.
Run 1
1.19e-02
1.98e-05
4.34e-05
4.45e-03
4.59e-06
1.22e-01
1.56e-01
1.65e-04
1.81e-02
1.57e-04
6.65e-03
3.48e-04
1.14e-04
3.35e-05
2.48e-03
1.35e-04
1.12e-05
9.51e-03
4.04e-03
3.72e-04
sampling runs.
Run 2
1.35e-02
1.35e-05
4.77e-05
7.11e-03
5.14e-06
2.22e-02
3.55e-05
1.73e-01
1.24e-04
2.45e-04
1.79e-02
1.44e-04
9.37e-03
4.91e-04
9.55e-05
3.31e-05
8.69e-05
2.30e-03
1.68e-04
1.22e-05
7.86e-03
4.68e-03
3.56e-04
8.57e-04
EF is based on
Run 3
1.09e-02
1.10e-05
3.68e-05
2.76e-03
4.66e-06
4.67e-02
6.00e-05
1.58e-01
1.13e-04
2.78e-04
1.58e-02
1.23e-04
7.24e-03
3.34e-04
7.72e-05
3.31e-05
6.37e-05
2.13e-03
1.45e-04
3.68e-05
6.28e-03
3.79e-03
3.45e-04
5.51e-04
detection limits.
AVG
1.21e-02
1.48e-05
4.26e-05
4.77e-03
4.80e-06
6.35e-02
4.78e-05
1.62e-01
1.34e-04
2.61e-04
1.73e-02
1.41e-04
7.75e-03
3.91e-04
9.56e-05
3.32e-05
7.53e-05
2.30e-03
1.49e-04
2.01e-05
7.89e-03
4.17e-03
3.58e-04
7.04e-04
5-27
-------
REFERENCE 27 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 17 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
RESULTS OF THE MARCH 1990 TRACE METAL
CHARACTERIZATION STUDY ON UNIT 3 AT THE SHERBURNE
COUNTY GENERATING STATION
FACILITY:
UNIT NO.:
LOCATION:
FILENAME
NSP SHERCO
3
Becker, Minnesota
SHERCO3A.tbl
PROCESS DATA
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Oxygen (% v/v)a
Vol. Flow Rate (dscf/m)b
Vol. Flow Rate (dscf/hr)
F-factor (dscf/MMBtu)c
Heat input (MMBtu/hr)
HHV Bituminous Coal (Btu/lb)d
HHV Bituminous Coal (Btu/ton)
Coal Feed (ton/hr)
Coal typee
Boiler configuration6
Coal source6
sec
Control device le
Control device 2e
Run 1
6.50
1,950,168
117,010,080
9,780
8,243
8,547
17,094,000
482
METALS
Run 2
6.20
1,965,867
117,952,020
9,780
8,483
8,547
17,094,000
496
CHROME VI
Run 2
6.10
1,950,487
116,691,780
9,780
8,474
8,547
17,094,000
496
Run 3
6.10
1,962,255
117,735,300
9,780
8,525
8,547
17,094,000
499
Run 3
6.00
1,944,863
Run 1
6.10
1,957,528
117,029,220
9,780 9,780 9,780
8,504 8,474 8,506
8,547 8,547 8,547
17,094,000 17,094,000 17,094,000
497 496 498
Subbituminous
Pulverized, dry bottom
Montana
10100222
Flue Gas Desulfurization, Spray Dryer absorber
Baghouse
5-28
-------
REFERENCE 27 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 17 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
B
Had to use F-factor and average HHV to get coal
feed rate (ton/hr)
860 megawatts, on line in 1987.
MM5 for metals, MM 13 for chrome VI.
2 for calcium, nickel, sodium and zinc. 3 for all others.
aPage 12 for metals runs; page 13 for chrome VI runs.
bPage 16 for metals runs, page 18 for chrome VI runs.
C40 CFR Pt 60, App A, Meth. 19, Bituminous coal.
dFrom report "Results of the May 29, 1990 Trace Metal
at the Sherburne County Generating Station in Becker,
No. 25).
ePage 1. Assumed dry bottom.
fPage 1 for MM5, page 2 for MM 13.
gVarious pages.
Characterization Study on Units 1 and 2
Minnesota", page G-l. (Reference
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimony
Arsenicb
Bariumb
Beryllium
Boron
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenumb
Nickel
Potassium
Seleniumb
Silverb
Run 1
1.91
7.09e-03
0.048
1.61e-05
19.1
0.114
0.789
1.04
0.123
0.294
0.0565
0.0411
0.032
1.83
0.0199
2.41e-03
Run 2
0.493
1.62e-03
4.12e-04
0.049
4.93e-05
3.28
1.91
0.0682
0.384
0.759
0.0394
0.123
0.382
0.0172
0.033
0.0736
0.624
0.0205
2.43e-03
Run 3
0.742
1.6e-03
4.12e-04
0.050
9.92e-05
13.9
1.85
0.0520
0.188
0.248
0.033
0.215
0.0379
0.0338
0.033
0.0264
0.602
0.0207
2.50e-03
AVG
5-29
-------
REFERENCE 27 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 17 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Sodium
Strontium
Vanadiumb
Zinc
EMISSION FACTORS (lb/ton)c
Aluminum
Antimony
Arsenicb
Bariumb
Beryllium
Boron
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenumb
Nickel
Potassium
Seleniumb
Silverb
Sodium
Strontium
Vanadiumb
Zinc
"Pages 5 and 7.
bPollutant was not detected in any of the
°Divide emission rate by coal feed rate.
Run 1
—
0.0119
8.04e-04
—
Run 1
3.96e-03
1.47e-05
9.95e-05
3.34e-08
3.96e-02
2.36e-04
1.64e-03
2.16e-03
2.55e-04
6.10e-04
1.17e-04
8.52e-05
6.64e-05
3.79e-03
4.13e-05
5.00e-06
2.47e-05
1.67e-06
sampling runs.
Run 2
4.62
0.0411
8.10e-04
0.262
Run 2
9.93e-04
3.26e-06
8.30e-07
9.87e-05
9.93e-08
6.61e-03
3.85e-03
1.37e-04
7.74e-04
1.53e-03
7.94e-05
2.48e-04
7.70e-04
3.47e-05
6.65e-05
1.48e-04
1.26e-03
4.13e-05
4.90e-06
9.31e-03
8.28e-05
1.63e-06
5.28e-04
EF is based on
Run 3
4.80
0.0412
8.09e-04
0.172
Run 3
1.49e-03
3.21e-06
8.26e-07
l.OOe-04
1.99e-07
2.79e-02
3.71e-03
1.04e-04
3.77e-04
4.97e-04
6.62e-05
4.31e-04
7.60e-05
6.78e-05
6.62e-05
5.29e-05
1.21e-03
4.15e-05
5.01e-06
9.63e-03
8.26e-05
1.62e-06
3.45e-04
detection limits.
AVG
AVG
2.15e-03
7.06e-06
8.28e-07
9.95e-05
l.lle-07
2.47e-02
3.78e-03
1.59e-04
9.29e-04
1.39e-03
1.34e-04
4.30e-04
3.21e-04
6.26e-05
6.63e-05
l.Ole-04
2.09e-03
4.14e-05
4.97e-06
9.47e-03
6.34e-05
1.64e-06
4.36e-04
5-30
-------
REFERENCE 27 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 17 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
CHROME VI EMISSION FACTORS
Emission Rates (lb/hr)a
Emission Factors (lb/ton)b
Run 1
0.0095
1.91e-05
Run 2
0.0028
5.65e-06
Run 3
0.0100
2.01e-05
AVG
1.49e-05
aPage 8.
bDivide emission rate by coal feed rate.
5-31
-------
REFERENCE 2!
REFERENCE 1!
OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 10 EMISSIONS MONITORING.
RADIAN CORPORATION, AUSTIN, TEXAS. OCTOBER, 1992.
FACILITY:
FILENAME
EPRI SITE 10
SITElO.tbl
PROCESS DATA
Coal feed rate, dry (lb/hr)a
Coal moisture percent by weightb
Coal feed rate, as received (Ib/hr)
Coal feed rate, as received (ton/hr)
Stack gas flow rate (dscf/hr)a
Coal type0
Boiler configurationd
Coal source0
sec
Control device le
Control device 2e
Data Quality
Process Parameters'1
Test methodsf
Number of test runs8
108,626 Coal HHV, dry (Btu/lb)b
7.3% Coal HHV, as received (Btu/lb)
117,180 Coal HHV, as received (MMBtu/lb)
58.59 Coal HHV, as received (MMBtu/ton)
15,500,000
Subbituminous
Circulating Fluidized Bed Combustor (CFBC)
Salt River
10100238
Flue gas desulfurization by limestone injection into the combustion chamber (FGD-FIL)
Fabric Filter
A
110 megawatts
EPA, or EPA-approved, test methods
5 for benzene, 1 for all others.
11,000
10,252
0.01
20.50
aPage C-3
bPage B-3
°Appendix B of EPRI Synthesis Report, page B-3.
dAppendix B of EPRI Synthesis Report, page B-6.
ePage 1-1
fPages A-3 through A-13
gPage 3-1 and B-15 for benzene, page 3-1 for others.
5-32
-------
REFERENCE 28 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 18 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS, VOC
Pollutant
Arsenicb
Barium
Berylliumb
Cadmiumb
Chloride
Chromium
Cobaltb
Copperb
Fluorideb
Lead
Manganese
Molybdenumb
Nickelb
Phosphorousb
Seleniumb
Vanadiumb
Formaldehydeb
Benzene
EMISSION FACTORS3
(lb/10A12 Btu)
1
12.1
0.2
0.4
958
1.6
0.8
2
18
0.6
31
4
2
24
16
2
15
2
(Ib/MMBtu)
l.OOe-06
1.21e-05
2.00e-07
4.00e-07
9.58e-04
1.60e-06
8.00e-07
2.00e-06
1.80e-05
6.00e-07
3.10e-05
4.00e-06
2.00e-06
2.40e-05
1.60e-05
2.00e-06
1.50e-05
2.00e-06
(lb/ton)c
2.05e-05
2.48e-04
4.10e-06
8.20e-06
1.96e-02
3.28e-05
1.64e-05
4.10e-05
3.69e-04
1.23e-05
6.36e-04
8.20e-05
4.10e-05
4.92e-04
3.28e-04
4.10e-05
3.08e-04
4.10e-05
aPage 3-12
bEmission factor is based only on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-33
-------
REFERENCE 2!
REFERENCE 1!
OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
MISC. EMISSION FACTORS
Pollutant
Dibutyl Phthalate
bis(2-Ethylhexyl) phthalate
N-Nitrosodiethylamine
Stack Gas Cone. Stack Gas Cone.
(ug/Nm3)a (ug/dscm)b
3.1 2.89
6.0 5.59
15 13.98
Stack Gas Cone. Emission Rate Emission Factor
(lb/dscf)c (lb/hr)d (lb/ton)e
1.80e-10 2.80e-03 4.77e-05
3.49e-10 5.41e-03 9.24e-05
8.73e-10 1.35e-02 2.31e-04
aPage 3-14
bConvert Normal meter to standard meter, i.e., multiply by 273/293.
°Convert ug/dscm to Ib/dscf.
dMultiply concentration by stack gas flow rate.
"Divide emission rate by coal feed rate.
5-34
-------
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 19 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 11 EMISSIONS MONITORING.
RADIAN CORPORATION, AUSTIN, TEXAS. OCTOBER, 1992.
FACILITY:
FILENAME
EPRI SITE 11
SITEll.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device I3
Control device 23
Control device 33
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Stack gas flow rate (dscf/m)e
Stack gas flow rate (dscf/hr)
Stack Gas O2 %e
F-factor (dscf/MMBtu)f
Heat input (MMBtu/hr)
Coal HHV, as recieved (Btu/lb)3
Coal HHV, as received (MMBtu/lb)
Coal HHV, as received (MMBtu/ton)
Subbituminous
Pulverized, dry, tangential
Powder River Basin
10100226
Over Fire Air
ESP
Flue Gas Desulfurization, Wet Limestone Scrubber (Absorber)
B
700 MW
EPA, or EPA-approved, test methods
1
1,598,400
95,904,000
6.9
9,780
6568.7
8,300
0.008
16.60
5-35
-------
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 19 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
Coal feed rate as received (ton/hr) 395.70
3Page2-l.
bPage 2-1. Assumed dry bottom.
°Appendix A.
dPage3-18.
ePage D-7.
f40 CFR Pt 60, App. A, Meth. 19, bituminous coal.
METALS, VOC EMISSION FACTORS
Pollutant
Arsenic
Barium
Berylliumb
Cadmium
Chlorine
Chromium
Cobalt
Copper
Fluorine
Lead
Manganese
Mercury
Molybdenumb
Nickel
Particulate
Phase
(ug/Nm3)a
1.0
97
NR(0.2)
7.0
1.7
2.1
3.9
0.016
NR(5)
4.7
Vapor
Phase
(ug/Nm3)a
NR(3)
NR(6)
NR(1)
1.3
2200
NR(6)
NR(6)
NR(10)
130
14
110
3.7
NR(30)
NR(10)
Total
(ug/Nm3)
1.0
97.0
0.20
1.3
2,200
7.0
1.7
2.1
130.00
14.00
113.90
3.72
5
4.7
Total
(ug/dscm)
0.93
90.38
0.19
1.21
2049.83
6.52
1.58
1.96
121.13
13.04
106.13
3.46
4.66
4.38
Total
(Ib/dscf)
5.82e-ll
5.64e-09
1.16e-ll
7.56e-ll
1.28e-07
4.07e-10
9.89e-ll
1.22e-10
7.56e-09
8.15e-10
6.63e-09
2.16e-10
2.91e-10
2.73e-10
Emission
Rate
(lb/hr)c
5.58e-03
5.41e-01
1.12e-03
7.25e-03
1.23e+01
3.91e-02
9.49e-03
1.17e-02
7.25e-01
7.81e-02
6.36e-01
2.07e-02
2.79e-02
2.62e-02
Emission
Factor
(lb/ton)d
1.41e-05
1.37e-03
2.82e-06
1.83e-05
3.10e-02
9.87e-05
2.40e-05
2.96e-05
1.83e-03
1.97e-04
1.61e-03
5.24e-05
7.05e-05
6.63e-05
5-36
-------
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 19 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
I Phosphorous13 NR(20) 20 18.63 1.16e-09 1.12e-01 2.82e-04
5-37
-------
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 19 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS, VOC EMISSION FACTORS
Pollutant
Seleniumb
Vanadium
Formaldehyde13
Naphthaleneb
Particulate
Phase
(ug/Nm3)a
2.6
NR(4)
Vapor
Phase
(ug/Nm3)a
NR(3)
NR(10)
NR(10)
Total
(ug/Nm3)
3
2.6
10
4
Total
(ug/dscm)
2.80
2.42
9.32
3.73
Total
(Ib/dscf)
1.75e-10
1.51e-10
5.82e-10
2.33e-10
Emission
Rate
(lb/hr)c
1.67e-02
1.45e-02
5.58e-02
2.23e-02
Emission
Factor
(lb/ton)d
4.23e-05
3.67e-05
1.41e-04
5.64e-05
aPage 3-18, Run 2 data only (other runs invalid).
bPage 3-18. Detection limit value for one run used in calculating EF.
°Multiply concentration by stack gas flow rate.
dDivide emission rate by coal feed rate.
5-38
-------
REFERENCE 30 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 20 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 12
EMISSIONS MONITORING. RADIAN CORPORATION, AUSTIN,
TEXAS. NOVEMBER, 1992.
FACILITY:
FILENAME
EPRI SITE 12
SITE12.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device 1°
Control device 2°
Control device 3
Data Quality
Process Parameters0
Test methodsd
Number of test runs6
Coal HHV, dry (Btu/lb)f
Coal moisture %f
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Pulverized, dry, opposed
West Pa.
10100202
ESP
Flue Gas Desulrurization, Wet Limestone Scrubber
(Absorber)
None
A
700 MW
EPA, or EPA-approved, test methods
2 for Metals, 3 for VOCs.
13,733
4.12%
13,190
26,379,178
26.4
3Page3-5.
bPage 2-1. Assumed dry bottom.
cPage2-l.
dAppendix A.
ePage 3-11 for PM/metals, Page 3-14 for VOC.
fPage 3-6.
5-39
-------
REFERENCE 30 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 20 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS, VOC EMISSION FACTORS3
Pollutant
Arsenic
Barium
Berylliumb
Cadmium
Chloride
Chromium
Cobaltb
Copper
Fluoride
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Vanadiumb
Formaldehyde13
Bromomethaneb
1,1,1 -trichloroethane
Benzene
Toluene
m,p-xylene
Emission Factor
(lb/10A12 Btu)
0.45
6.3
0.16
1.2
2500
3.5
1.0
4.4
27
5.7
1.6
0.16
4
4.4
13
1.6
8.4
0.43
0.75
0.69
1.04
0.72
Emission Factor
(Ib/MMBtu)
4.50e-07
6.30e-06
1.60e-07
1.20e-06
2.50e-03
3.50e-06
l.OOe-06
4.40e-06
2.70e-05
5.70e-06
1.60e-06
1.60e-07
4.00e-06
4.40e-06
1.30e-05
1.60e-06
8.40e-06
4.30e-07
7.50e-07
6.90e-07
1.04e-06
7.20e-07
aPage 3-12 for metals, page 3-14 for VOC. See page 3-11 for number of non-detect
pm/metals.
bDetection limit value for two runs used in calculating EF.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
Emission Factor
(lb/ton)c
1.19e-05
1.66e-04
4.22e-06
3.17e-05
6.59e-02
9.23e-05
2.64e-05
1.16e-04
7.12e-04
1.50e-04
4.22e-05
4.22e-06
1.06e-04
1.16e-04
3.43e-04
4.22e-05
2.22e-04
1.13e-05
1.98e-05
1.82e-05
2.74e-05
1.90e-05
runs for
5-40
-------
REFERENCE 31 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 21 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 15
EMISSIONS MONITORING. RADIAN CORPORATION, AUSTIN,
TEXAS. OCTOBER, 1992.
FACILITY:
FILENAME
EPRI SITE 15
SITE15.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device I3
Control device 2
Control device 3
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Coal HHV, dry (Btu/lb)e
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Pulverized, dry, tangential
Eastern US
10100212
ESP cold side
None
None
A
600 MW
EPA, or EPA-approved, test methods
2 for lead, 3 for all others
13,000
26,000,000
26.0
3Page2-l.
bPage 2-1. Assumed dry bottom.
°Appendix A.
dPage 3-9.
ePage 3-4, assumed to be as fired.
5-41
-------
REFERENCE 31 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 21 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS3
Pollutant
Arsenic
Barium
Beryllium
Cadmium
Chloride
Chromium
Cobalt
Copper
Fluoride
Lead
Manganese
Molybdenum
Nickel
Selenium
Vanadium
Benzene
Formaldehyde13
Toluene
Tage 3-10.
bEmission factors is based
°Multiply emission factor,
Emission Factor
(lb/10A12 Btu)
13
34
0.4
3.1
46,700
12
2.0
5.5
3,850
4.3
8.6
5.3
5.9
77
14
0.8
5
5.2
only on detection limits.
Ib/MMBtu, by coal HHV, MMBtu/ton
Emission Factor
(Ib/MMBtu)
1.30e-05
3.40e-05
4.00e-07
3.10e-06
4.67e-02
1.20e-05
2.00e-06
5.50e-06
3.85e-03
4.30e-06
8.60e-06
5.30e-06
5.90e-06
7.70e-05
1.40e-05
8.00e-07
5.00e-06
5.20e-06
Emission Factor
(lb/ton)c
3.38e-04
8.84e-04
1.04e-05
8.06e-05
1.21e+00
3.12e-04
5.20e-05
1.43e-04
l.OOe-01
1.12e-04
2.24e-04
1.38e-04
1.53e-04
2.00e-03
3.64e-04
2.08e-05
1.30e-04
1.35e-04
5-42
-------
REFERENCE 32 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 22 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 19 EMISSIONS MONITORING.
RADIAN CORPORATION, AUSTIN, TEXAS. NOVEMBER, 1992.
FACILITY:
FILENAME
EPRI SITE 19
SITE19.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source
sec
Control device 1°
Control device 2
Control device 3
Data Quality
Process Parameters'1
Test methods6
Number of test runsf
Bituminous
Pulverized, dry, opposed
Virginia, Kentucky
10100202
ESP cold side
None
None
A
1160MW
EPA, or EPA-approved, test methods
3
Coal HHV, dry (Btu/lb)8
Coal moisture %8
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Coal feed rate, dry (lb/hr)h
Coal moisture percent by weight8
Coal feed rate, as received (Ib/hr)
Coal feed rate, as received (ton/hr)
Stack gas flow rate (Nm3/hr)h
13,467
6.1%
12,693
25,385,485
25.4
694,000
6.1%
739,084
369.54
4,000,000
aPage2-l.
bPage 2-1. Assumed dry bottom.
cPage2-l.
dPage 2-2.
eAppendix A.
fPage 3-7.
8Page 3-5.
hPage 3-8.
5-43
-------
REFERENCE 32 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 22 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS
Pollutant
Arsenic
Cadmium
Chloride
Chromium
Copper
Fluoride
Manganese
Mercury
Nickel
Selenium
aPage 3-8.
bMultiply emission
Emission
Factor3
(lb/1012Btu)
7.9
0.13
75,000
13
12
5,800
5.4
6.2
7.9
260
Emission
Factor
(Ib/MMBtu)
7.90e-06
1.30e-07
7.50e-02
1.30e-05
1.20e-05
5.80e-03
5.40e-06
6.20e-06
7.90e-06
2.60e-04
Emission
Factor
(lb/ton)b
2.01e-04
3.30e-06
1.90e+0
3.30e-04
3.05e-04
1.47e-01
1.37e-04
1.57e-04
2.01e-04
6.60e-03
factor. Ib/MMBtu. bv coal HHV. MMBtu/ton.
5-44
-------
REFERENCE 32 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 22 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
MISCELLANEOUS EMISSION FACTORS
Pollutant Concentration (ug/Nm3)a
Antimony
Beryllium
Cobalt
Pollutant emissions
Antimony
Beryllium
Cobalt
aPage 3-9.
bMultiply concnetration by stack gas flow
dDivide emission rate by coal feed rate.
Solid
Run 2
0.47
1.1
4.3
emission rate
(ug/hr)b
6,413,333
5,160,000
22,133,333
rate.
Phase Cone.
Run 3
0.39
1.0
4.2
emission
rate
(Ib/hr)
1.41e-02
1.14e-02
4.88e-02
Vapor Phase Cone. Total cone.
Run 4 Run 2 Run 3 Run 4 Run 2 Run 3 Run 4
0.35 0.76 1.9 1.7 0.47 2.29 2.05
0.72 0.49 0.55 0.50 1.1 1.55 1.22
2.8 2.5 2.8 2.5 4.3 7 5.3
emission
factor
(lb/ton)c
3.83e-05
3.08e-05
1.32e-04
avg
1.60
1.29
5.53
5-45
-------
REFERENCE 33 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 23 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 20
EMISSIONS MONITORING RADIAN CORPORATION, AUSTIN,
TEXAS. MARCH, 1994.
FACILITY:
FILENAME
EPRI SITE 20
SITE20.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal sourcef
sec
Control device la
Control device 2a
Control device 3
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Coal HHV, as received (Btu/lb)e
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Lignite
Pulverized
Wilcox, Texas
10100301
ESP cold side
Flue Gas Desulrurization- Wet Limestone Scrubber
(absorber)
None
A
680 MW
EPA, or EPA-approved, test methods
4
6,760
13,520,000
13.5
3Page2-l.
bPage2-5.
°Appendix A.
dPage 3-9.
ePage 2-2.
fAppendix B of EPRI Synthesis Report, page B-3.
5-46
-------
REFERENCE 33 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 23 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS
Pollutant
Arsenic
Barium
Beryllium
Cadmium
Chloride
Chromium
Emission
Factor3
(lb/10A12 Btu)
0.63
42
0.35
0.70
390
2.8
Emission
Factor
(Ib/MMBtu)
6.30e-07
4.20e-05
3.50e-07
7.00e-07
3.90e-04
2.80e-06
Emission
Factor
(lb/ton)b
8.52e-06
5.68e-04
4.73e-06
9.46e-06
5.27e-03
3.79e-05
5-47
-------
REFERENCE 33 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 23 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS
Pollutant
Cobalt
Fluoride
Lead
Manganese
Mercury
Nickel
Phosphorous
Selenium
Vanadium
3Page3-ll, Stack data.
bMultiply emission factor,lb/MMBtu
Emission
Factor3
(lb/10A12 Btu)
0.69
430
3.8
8.5
12
4.3
21
160
3.08
Emission
Factor
(Ib/MMBtu)
6.90e-07
4.30e-04
3.80e-06
8.50e-06
1.20e-05
4.30e-06
2.10e-05
1.60e-04
3.08e-06
Emission
Factor
(lb/ton)b
9.33e-06
5.81e-03
5.14e-05
1.15e-04
1.62e-04
5.81e-05
2.84e-04
2.16e-03
4.16e-05
, by coal HHV, MMBtu/ton.
Antimony EMISSION FACTOR: Note that antimony was not detected in
Coal feed rate (Ib/hr, dry)3
Coal moisture (%)a
Coal feed rate (Ib/hr, wet) (as fired)
Coal feed rate (ton/hr)
Stack gas flow rate (Nm3/hr)b
Antimony concentration (ug/Nm3)b'°
Antimony emission rate (ug/hr)d
Antimony emission rate (lb/hr)e
Antimony emission factor (lb/ton)f
Run 1
630,000
33.5%
947,368
474
3,100,000
1.31
4,061,000
8.95e-03
1.89e-05
aPage 3-6.
bPage 3-9.
Tollutant was not detected in any sampling runs. EF based
dMultiply concentration by stack gas flow rate.
eConvert ug/hr to Ib/hr.
fDivide emission rate by coal feed rate.
Run 2
614,000
34.2%
933,131
467
3,140,000
1.07
3,359,800
7.41e-03
1.59e-05
any of the sampling runs.
Run 3
619,000
33.6%
932,229
466
3,100,000
1.13
3,503,000
7.72e-03
1.66e-05
Run 4
618,000
34.4%
942,073
471
3,040,000
1.29
3,921,600
8.65e-03
1.84e-05
avg
1.74e-05
on detection limits.
5-48
-------
REFERENCE 34 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 24 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 21
EMISSIONS MONITORING. RADIAN CORPORATION, AUSTIN,
TEXAS. AUGUST, 1993.
FACILITY:
FILENAME
EPRISITE21
SITE21.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device 1°
Control device 2°
Control device 3
Data Quality
Process Parameters0
Test methods'1
Number of test runs6
Coal HHV, dry (Btu/lb)f
Coal moisture %8
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Pulverized, dry, opposed
Pa., W. Va.
10100202
ESP
Flue Gas Desulrurization, Wet Limestone Scrubber
(Absorber)
None
A
667 MW
EPA, or EPA-approved, test methods
8 for PM/metals, 7 for semi-volatiles
14,032
7%
13,114
26,228,037
26.2
3Page 3-6.
bAssumed to be pulverized, dry bottom.
cPage2-3.
dAppendix A.
ePage 3-10 for metals, page 3-14 for semi-volatiles.
fPage 3-5.
gPage 7-2.
EMISSION FACTORS
Pollutant
Acenapthene
Acenapthylene
Anthracene
Arsenic
Emission Factor3
(lb/10A12 Btu)
0.018
0.0075
0.0099
6.17
Emission Factor
(Ib/MMBtu)
1.80e-08
7.50e-09
9.90e-09
6.17e-06
Emission Factorb
(Ib/ton)
4.72e-07
1.97e-07
2.60e-07
1.62e-04
5-49
-------
REFERENCE 34 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 24 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS
Pollutant
Barium
Benz(a)anthracene
Benzo(a)pyrene
Benzo(b,j ,k)fluoranthenes
Benzo(g,h,i)perylene
Beryllium
Cadmium
Chloride
Chromium
Chrysene
Cobalt
Copper
Fluoranthene
Fluorene
Fluoride
Indeno(l,2,3-cd)pyrene
Lead
Manganese
Mercury
Molybdenum
Nickel
Phenanthrene
Pyrene
Selenium
Vanadium
5 -Methyl Chrysene
3Page3-15.
bMultiply emission factor,
Emission Factor3 Emission Factor Emission Factorb
(lb/10A12 Btu)
3.21
0.0013
0.0018
0.0066
0.0012
0.13
0.57
1,980
2.74
0.0069
4.1
1.57
0.053
0.064
31.9
0.0015
6.32
15
0.84
0.61
1.68
0.21
0.024
9.9
5.50
0.0015
Ib/MMBtu, by coal HHV, MMBtu/ton.
(Ib/MMBtu)
3.21e-06
1.30e-09
1.80e-09
6.60e-09
1.20e-09
1.30e-07
5.70e-07
1.98e-03
2.74e-06
6.90e-09
4.10e-06
1.57e-06
5.30e-08
6.40e-08
3.19e-05
1.50e-09
6.32e-06
1.50e-05
8.40e-07
6.10e-07
1.68e-06
2.10e-07
2.40e-08
9.90e-06
5.50e-06
1.50e-09
(Ib/ton)
8.42e-05
3.41e-08
4.72e-08
1.73e-07
3.15e-08
3.41e-06
1.49e-05
5.19e-02
7.19e-05
1.81e-07
1.08e-04
4.12e-05
1.39e-06
1.68e-06
8.37e-04
3.93e-08
1.66e-04
3.93e-04
2.20e-05
1.60e-05
4.41e-05
5.51e-06
6.29e-07
2.60e-04
1.44e-04
3.93e-08
5-50
-------
REFERENCE 35 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 25 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT: SITE 22
EMISSIONS REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
FEBRUARY, 1994.
FACILITY:
FILENAME
EPRI SITE 22
SITE22.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device I3
Control device 2
Control device 3
Data Quality
Process Parameters0
Test methods'1
Number of test runs6
Coal HHV, dry (Btu/lb)f
Coal moisture %f
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Subbituminous
Pulverized, dry, opposed
Powder River
10100222
ESP Cold Side
None
None
A
700 MW
EPA, or EPA-approved, test methods
3
11,981
29.5%
9,252
18,503,475
18.5
3Page 2-1
bAssumed pulverized, dry bottom.
cPage 2-2.
dAppendix A
Tages 3-7 through 3-11
fPage 3-6
5-51
-------
REFERENCE 35 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 25 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS, ORGANIC EMISSION FACTORS
Emission
Pollutant (lb/10A
Arsenic
Barium
Berylliumb
Cadmium
Chloride
Chromium
Cobaltb
Copper
Fluoride
Lead
Manganese
Mercury
Molybdenum
Nickel
Phosphorous
Selenium
Vanadium
Aluminum
Antimonyb
Calcium
Iron
Magnesium
Potassiumb
Sodium
Titanium
aPage 3-12.
bEmission factor is based only on detection limits.
°Multiply emission factor, Ib/MMBtu, by coal HHV,
Factor3
12 Btu)
0.087
16
0.031
0.16
726
0.53
0.70
1.0
855
0.11
1.1
3.8
1.9
0.64
11
0.053
0.78
136
3.8
325
52
47
82
86
12
Emission Factor
(Ib/MMBtu)
8.70e-08
1.60e-05
3.10e-08
1.60e-07
7.26e-04
5.30e-07
7.00e-07
l.OOe-06
8.55e-04
1.10e-07
1.10e-06
3.80e-06
1.90e-06
6.40e-07
1.10e-05
5.30e-08
7.80e-07
1.36e-04
3.80e-06
3.25e-04
5.20e-05
4.70e-05
8.20e-05
8.60e-05
1.20e-05
Emission Factor0
(Ib/ton)
1.61e-06
2.96e-04
5.74e-07
2.96e-06
1.34e-02
9.81e-06
1.30e-05
1.85e-05
1.58e-02
2.04e-06
2.04e-05
7.03e-05
3.52e-05
1.18e-05
2.04e-04
9.81e-07
1.44e-05
2.52e-03
7.03e-05
6.01e-03
9.62e-04
8.70e-04
1.52e-03
1.59e-03
2.22e-04
MMBtu/ton.
5-52
-------
REFERENCE 35 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 25 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
PAH EMISSION FACTORS
Pollutant
Acenaphthalene
Acenaphthene
Anthracene
Benzo(a)pyrene
Benzo(b,j ,k)fluoranthenes
Benzo(g,h,i)perylene
Benz(a)anthracene
Chrysene
Fluoranthene
Fluorene
Indeno(l,2,3-cd)pyrene
5 -Methyl Chryseneb
Phenanthrene
Pyrene
Emission Factor3
(lb/10A12 Btu)
0.0034
0.0060
0.0046
0.0011
0.0027
0.0022
0.0010
0.0025
0.024
0.012
0.0086
0.00047
0.069
0.016
3Page3-14..
bEmission factor is based only on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu,
DIOXIN/FURAN EMISSION FACTORS
Pollutant
2,3,7,8-TCDDb
Total TCDD
Total PeCDD
Total HxCDD
Total HpCDD
OCDD
Emission Factor
(lb/10A12 Btu)a
3.3e-06
4.7e-06
ND
ND
9.8e-06
5.2e-05
Emission Factor
(Ib/MMBtu)
3.40e-09
6.00e-09
4.60e-09
1.10e-09
2.70e-09
2.20e-09
l.OOe-09
2.50e-09
2.40e-08
1.20e-08
8.60e-09
4.70e-10
6.90e-08
1.60e-08
ton.
Emission Factor
(Ib/MMBtu)
3.3e-12
4.7e-12
ND
ND
9.8e-12
5.2e-ll
Emission Factor0
(Ib/ton)
6.29e-08
l.lle-07
8.51e-08
2.04e-08
5.00e-08
4.07e-08
1.85e-08
4.63e-08
4.44e-07
2.22e-07
1.59e-07
8.70e-09
1.28e-06
2.96e-07
Emission Factor0
(Ib/ton)
6.1e-ll
8.7e-ll
ND
ND
1.8e-10
9.6e-10
5-53
-------
REFERENCE 35 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 25 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
DIOXIN/FURAN EMISSION FACTORS
Pollutant
2,3,7,8-TCDFb
Total TCDF
Total PeCDF
Total HxCDF
Total HpCDF
OCDF
Emission Factor
(lb/10A12 Btu)a
3.6e-06
6.2e-06
7.3e-06
3.5e-06
2.2e-06
4.2e-06
3Page3-15.
bEmission factor is based only on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu,
Emission Factor
(Ib/MMBtu)
3.6e-12
6.2e-12
7.3e-12
3.5e-12
2.2e-12
4.2e-12
ton.
Emission Factor0
(Ib/ton)
6.7e-ll
l.le-10
1.4e-10
6.5e-ll
4.1e-ll
7.8e-ll
5-54
-------
REFERENCE 36 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 26 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
SITE 101 EMISSIONS REPORT. RADIAN CORPORATION,
AUSTIN, TEXAS. OCTOBER, 1994.
FACILITY:
FILENAME
EPRI SITE 101
SITElOl.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source0
sec
Control device la
Control device 2a
Control device 3a
Data Quality
Process Parameters3
Test methods'1
Number of test runs6
Coal HHV, dry (Btu/lb)f
Coal moisture %f
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Subbituminous
Pulverized, dry, wall-fired
New Mexico
10100222
Low Nox Burners (LNB)
Fabric Filter
Flue Gas Desulfurization- Wet Limestone Scrubber
A
800 MW
EPA, or EPA-approved, test methods
3 for benzene, toluene, chloride and fluoride; 2 for all others.
10,190
14%
8,939
17,877,193
17.9
3Page2-l.
bPage 2-1, assumed dry bottom.
°Appendix B of the EPRI Synthesis Report, page B-3.
dAppendix A.
ePage 3-10 for benzene and toluene, page 3-6 for others.
fPage 3-5.
5-55
-------
REFERENCE 36 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 26 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS, ORGANIC EMISSION FACTORS
Emission
Pollutant (lb/10A
Arsenic
Barium
Beryllium
Cadmium
Chloride
Chromium
Cobalt
Copper
Fluoride
Lead
Manganese
Mercury
Molybdenum
Nickel
Phosphorous
Selenium
Vanadium
Benzene
Toluene
3Page3-13.
bMultiply emission factor, Ib/MMBtu, by coal HHV,
Factor3
12 Btu)
0.34
18
0.036
0.40
2,500
2.2
0.13
2.2
3,600
0.72
10
1.9
2.6
2.8
9.2
1.4
0.93
0.57
0.57
MMBtu/ton
Emission Factor
(Ib/MMBtu)
3.40e-07
1.80e-05
3.60e-08
4.00e-07
2.50e-03
2.20e-06
1.30e-07
2.20e-06
3.60e-03
7.20e-07
l.OOe-05
1.90e-06
2.60e-06
2.80e-06
9.20e-06
1.40e-06
9.30e-07
5.70e-07
5.70e-07
Emission Factorb
(Ib/ton)
6.08e-06
3.22e-04
6.44e-07
7.15e-06
4.47e-02
3.93e-05
2.32e-06
3.93e-05
6.44e-02
1.29e-05
1.79e-04
3.40e-05
4.65e-05
5.01e-05
1.64e-04
2.50e-05
1.66e-05
1.02e-05
1.02e-05
5-56
-------
REFERENCE 37 OF AP-42 SECTION 1.1 BACGROUND DOCUMENTATION
REFERENCE 27 OF AP-42 SECTION 1.7 BACGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
SITE 111 EMISSIONS REPORT. RADIAN CORPORATION,
AUSTIN, TEXAS. MAY, 1993.
FACILITY:
FILENAME
EPRI SITE 111
SITElll.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source0
sec
Control device 1°
Control device 2°
Control device 3°
Data Quality
Process Parameters0
Test methods'1
Number of test runs6
Coal HHV, as fired (received) (Btu/lb)f
Coal HHV, as fired (received) (Btu/ton)
Coal HHV, as fired (received) (MMBtu/ton)
Subbituminous
Pulverized, dry bottom
Western
10100222
Low Nox Burners (LNB)
Flue Gas Desulfurization- Spray Dryer (FGD-SD)
Fabric Filter (FF)
A
267 MW
EPA, or EPA-approved, test methods
2
10,020
20,040,000
20.0
aPage 2-2.
bAssumed dry bottom.
cPage2-l.
d Page 1-4.
e Page 3-12.
f Page 2-2.
5-57
-------
REFERENCE 37 OF AP-42 SECTION 1.1 BACGROUND DOCUMENTATION
REFERENCE 27 OF AP-42 SECTION 1.7 BACGROUND DOCUMENTATION
EMISSION FACTORS
Pollutant
Arsenicb
Cadmiumb
Chromiumb
Mercuryb
Nickel
Chloride
Benzene
Naphthalene
Acenaphthalene
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Chryseneb
Benz(a)anthracene
Benzo(b)fluoranthene
Benzo(k)fluoranthene
Benzo(a)pyreneb
Indeno(l,2,3-cd)pyrene
Benzo(g,h,i)perylene
Emission
Factor3
(lb/10A12 Btu)
0.21
2.1
4.3
67
5.3
1,250
21.1
0.76
0.03
0.08
0.18
0.13
0.02
0.03
0.01
0.004
0.009
0.008
0.004
0.004
0.004
0.004
Emission Emission Factor
Factor
(Ib/MMBtu)
2.10e-07
2.10e-06
4.30e-06
6.70e-05
5.30e-06
1.25e-03
2.11e-05
7.60e-07
3.00e-08
8.00e-08
1.80e-07
1.30e-07
2.00e-08
3.00e-08
l.OOe-08
4.00e-09
9.00e-09
8.00e-09
4.00e-09
4.00e-09
4.00e-09
4.00e-09
(lb/ton)c
4.21e-06
4.21e-05
8.62e-05
1.34e-03
1.06e-04
2.51e-02
4.23e-04
1.52e-05
6.01e-07
1.60e-06
3.61e-06
2.61e-06
4.01e-07
6.01e-07
2.00e-07
8.02e-08
1.80e-07
1.60e-07
8.02e-08
8.02e-08
8.02e-08
8.02e-08
3Page3-15.
bEmission factor is based only on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-58
-------
REFERENCE 38 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 28 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
SITE 114 REPORT. RADIAN CORPORATION, AUSTIN, TEXAS.
MAY, 1994.
FACILITY:
FILENAME
EPRI SITE 114
SITE114.tbl
PROCESS DATA
Coal type3
Boiler configuration3
Coal source3
sec
Control device I3
Control device 23
Control device 3
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Coal HHV, dry (Btu/lb)d
Coal moisture %d
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Cyclone
Indiana Lamar
10100203
ESP for baseline condition, Reburn/Overfire Air for
condition two
None for baseline, ESP for condition two
none
A
100 MW
EPA, or EPA-approved, test methods
3
Baseline
13,490
15.6%
11,670
23,339,100
23.3
Reburn
13,280
12.5%
11,804
23,608,889
23.6
3Page2-l.
bPage 1-4.
Tages 3-8 and 3-9.
dPages3-4&3-5.
5-59
-------
REFERENCE 38 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 28 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS- BASELINE CONDITION
Pollutant
Arsenic
Beryllium
Cadmium
Chromium
Manganese
Nickel
Lead
Selenium
Mercury
Chloride
Fluoride
Benzene
Toluene
PAHsb
Formaldehyde
Acetaldehyde
aPage 3-10.
bND = not detected
°Multiply emission
Emission Factor3
(lb/10A12 Btu)
7
2.4
1.8
14
20
78
86
240
4.5
4,310
64
2.3
1.02
ND
2.6
2.6
in three runs, no EF calculated. See page 3-8
factor, Ib/MMBtu, by coal HHV, MMBtu/ton
Emission Factor
(Ib/MMBtu)
7.00e-06
2.40e-06
1.80e-06
1.40e-05
2.00e-05
7.80e-05
8.60e-05
2.40e-04
4.50e-06
4.31e-03
6.40e-05
2.30e-06
1.02e-06
ND
2.60e-06
2.60e-06
Emission Factor0
(Ib/ton)
1.63e-04
5.60e-05
4.20e-05
3.27e-04
4.67e-04
1.82e-03
2.01e-03
5.60e-03
1.05e-04
l.Ole-01
1.49e-03
5.37e-05
2.38e-05
ND
6.07e-05
6.07e-05
5-60
-------
REFERENCE 38 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 28 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS- REBURN
Pollutant
Arsenic
Beryllium
Cadmium
Chromium
Manganese
Nickel
Lead
Selenium
Mercury
Chloride
Fluoride
Benzene
Toluene
PAHsb
Formaldehyde0
Acetaldehyde0
CONDITION
Emission Factor3
(lb/10A12 Btu)
8.0
0.8
0.4
4.6
15
34
57
150
3.8
6,000
89.9
1.04
0.70
ND
2.6
2.6
Emission Factor
(Ib/MMBtu)
8.00e-06
8.00e-07
4.00e-07
4.60e-06
1.50e-05
3.40e-05
5.70e-05
1.50e-04
3.80e-06
6.00e-03
8.99e-05
1.04e-06
7.00e-07
ND
2.60e-06
2.60e-06
Emission Factor
(lb/ton)d
1.89e-04
1.89e-05
9.44e-06
1.09e-04
3.54e-04
8.03e-04
1.35e-03
3.54e-03
8.97e-05
1.42e-01
2.12e-03
2.46e-05
1.65e-05
ND
6.14e-05
6.14e-05
aPage 3-9.
bND = not detected in three runs, no EF calculated. See page 3-9.
°Emission factors based completely on detection limits.
dMultiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-61
-------
REFERENCE 39 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING PROJECT:
SITE 115 EMISSIONS REPORT. RADIAN CORPORATION,
AUSTIN, TEXAS. NOVEMBER, 1994.
FACILITY:
FILENAME
EPRI SITE 115
SITE115.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device 1°
Control device 2°
Control device 3°
Data Quality
Process Parameters3
Test methods'1
Number of test runs6
Coal HHV, dry (Btu/lb)f
Coal moisture %8
Coal HHV, as received (Btu/lb)
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Pulverized, Dry bottom
Western
10100202
PHASE I
LNB/OFA
Fabric Filter
none
B
117MW
EPA, or EPA-approved, test methods
2 for nickel during Phase I, 3 for all others
PHASE II
LNB/OFA
SNCR
Fabric Filter
(coal moisture percent not provided)
PHASE I
12,565
9.8%
11,444
22,887,067
22.9
PHASE II
12,638
9.8%
11,510
23,020,036
23.0
3Page 6.
bPage 6. Assumed dry bottom.
°Page 6. LNB= Low Nox Burners; OFA = Overfire Air; SNCR = Selective non-catalytic
reduction.
dAppendix A, Table A-l.
ePage 26 for Phase I, page 35 for Phase II. Also, see footnote to nickel EF in Table 3-4.
fPage 20 for Phase I; Page 32 for Phase II.
8The test report does not provide a moisture content for the coal. EPRI Site 111 (Reference 19)
also uses a "western bituminous" coal and the value used here is from that reference.
5-62
-------
REFERENCE 39 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
EMISSION FACTORS- PHASE I
Pollutant
Arsenic
Barium
Beryllium0
Cadmium
Chromium
Cobalt0
Copper
Lead
Manganese
Mercury0
Molybdenum
Nickelb
Phosphorus
Selenium
Vanadium
Chloride
Fluoride
Benzene
Toluene
Formaldehyde
Cyanide
Naphthalene
Emission Factor3
(lb/10A12 Btu)
0.75
1.1
0.02
0.12
0.66
0.22
1.1
0.44
1.0
0.35
0.17
1.5
6.7
0.36
0.24
630
4,300
2.6
105
16.5
8
0.26
Emission Factor
(Ib/MMBtu)
7.50e-07
1.10e-06
2.00e-08
1.20e-07
6.60e-07
2.20e-07
1.10e-06
4.40e-07
l.OOe-06
3.50e-07
1.70e-07
1.50e-06
6.70e-06
3.60e-07
2.40e-07
6.30e-04
4.30e-03
2.60e-06
1.05e-04
1.65e-05
8.00e-06
2.60e-07
apage 28, 29. ND = not detected in 3 runs, no EF developed. See page 26 for run
bOne run invalid, data from two runs used to develop EF.
°Emission factor is based only on detection limits.
dMultiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
Emission Factord
(Ib/ton)
1.72e-05
2.52e-05
4.58e-07
2.75e-06
1.51e-05
5.04e-06
2.52e-05
l.Ole-05
2.29e-05
8.01e-06
3.89e-06
3.43e-05
1.53e-04
8.24e-06
5.49e-06
1.44e-02
9.84e-02
5.95e-05
2.40e-03
3.78e-04
1.83e-04
5.95e-06
data.
5-63
-------
REFERENCE 39 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
EMISSION FACTORS- PHASE II
Pollutant
Arsenic
Barium
Berylliumb
Cadmiumb
Chromium
Cobaltb
Copper
Lead
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Seleniumb
Vanadium
Chloride
Fluoride
Cyanide
Emission Factor3
(lb/10A12 Btu)
0.15
1.1
0.02
0.07
0.30
0.23
1.3
0.40
0.89
0.41
0.27
0.45
4.6
0.06
0.29
720
4,800
9
Emission Factor
(Ib/MMBtu)
1.50e-07
1.10e-06
2.00e-08
7.00e-08
3.00e-07
2.30e-07
1.30e-06
4.00e-07
8.90e-07
4.10e-07
2.70e-07
4.50e-07
4.60e-06
6.00e-08
2.90e-07
7.20e-04
4.80e-03
9.00e-06
Emission Factor0
(Ib/ton)
3.45e-06
2.53e-05
4.60e-07
1.61e-06
6.91e-06
5.29e-06
2.99e-05
9.21e-06
2.05e-05
9.44e-06
6.22e-06
1.04e-05
1.06e-04
1.38e-06
6.68e-06
1.66e-02
1.10e-01
2.07e-04
aPage 37.
bEmission factor is based only on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-64
-------
REFERENCE 40 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 30 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
CHARACTERIZING TOXIC EMISSIONS FROM A COAL-FIRED
POWER PLANT DEMONSTRATING THE AFGD ICCT PROJECT
AND A PLANT UTILIZING A DRY SCRUBBER/BAGHOUSE
SYSTEM. SPRINGERVILLE GENERATING STATION UNIT NO. 2.
SOUTHERN RESEARCH INSTITUTE, BIRMINGHAM, AL.
DECEMBER, 1993.
FACILITY:
FILENAME
Springerville, Arizona
DOET.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device I3
Control device 23
Control device 33
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Coal HHV, as received (Btu/lb)e
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Subbituminous
Pulverized, dry bottom, tangential
New Mexico
10100226
Low Nox Burners- Overfire Air (LNB/OFA)
Flue Gas Desulfurization- Spray Dryer (FGD-SD)
Baghouse
A
422 MW
EPA, or EPA-approved, test methods
2 for selenium, cadmium and manganese, 3 for others.
9,446
18,892,000
18.9
3Page3-l.
b"Pulverized" from page 3-1, assumed dry bottom,
"Tangential" from Appendix B of EPRI Synthesis Report. Page B-7.
cPage 4-2.
dPages 6-53, 6-54, and 6-55.
ePage 6-2, average for conveyor.
5-65
-------
REFERENCE 40 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 30 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS
Pollutant
Antimony
Arsenic
Barium
Berylliumb
Boron
Cadmium
Chromium
Cobaltb
Copper
Lead
Manganese
Mercury
Molybdenum
Nickelb
Seleniumb
Vanadium
Emission Factor3
(lb/10A12 Btu)
0.041
0.15
14.1
0.04
609
0.026
0.10
0.3
0.98
0.70
11.36
4.18
1.4
0.3
0.038
1.0
Emission Factor
(Ib/MMBtu)
4.10e-08
1.50e-07
1.41e-05
4.00e-08
6.09e-04
2.60e-08
l.OOe-07
3.00e-07
9.80e-07
7.00e-07
1.14e-05
4.18e-06
1.40e-06
3.00e-07
3.80e-08
l.OOe-06
Emission Factor0
(Ib/ton)
7.75e-07
2.83e-06
2.66e-04
7.56e-07
1.15e-02
4.91e-07
1.89e-06
5.67e-06
1.85e-05
1.32e-05
2.15e-04
7.90e-05
2.64e-05
5.67e-06
7.18e-07
1.89e-05
aPagel-ll.
bEmission factor is based only on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-66
-------
REFERENCE 41 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 31 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
A STUDY OF TOXIC EMISSIONS FROM A COAL-FIRED POWER
PLANT-NILES STATION BOILER NO. 2. BATTELLE,
COLUMBUS, OHIO. DECEMBER 29, 1993.
FACILITY:
FILENAME
Niles, Ohio
DOE2.tbl
PROCESS DATA
Coal type3
Boiler configuration3
Coal source3
sec
Control device I3
Control device 2
Control device 3
Data Quality
Process Parameters3
Test methods
Number of test runsb
Coal HHV, as received (Btu/lb)c
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Cyclone
Ohio/W. Pa.
10100203
ESP
None
None
A
108 MW
Assumed EPA, or EPA-approved, test methods
3
12,184
24,368,000
24.4
3Page2-l.
bPages 6-24, 6-26, 6-27, 6-28, 6-30, 6-32, 6-33, 6-35.
cPage 2-18. Average of 11964, 12504, 12397, 12139, 12031, and 12068 Btu/lb.
METALS EMISSION FACTORS
Pollutant
Aluminum
Antimonyb
Arsenic
Barium
Beryllium
Cadmium
Emission Factor3 Emission Factor Emission Factor0
(lb/10A12 Btu) (Ib/MMBtu) (Ib/ton)
1114 l.lle-03 2.71e-02
0.18 1.80e-07 4.39e-06
42 4.20e-05 1.02e-03
5.4 5.40e-06 1.32e-04
0.19 1.90e-07 4.63e-06
0.07 7.00e-08 1.71e-06
5-67
-------
REFERENCE 41 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 31 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
Pollutant
Chromium
Cobaltb
Copper
Lead
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Sodium
Titanium
Vanadium
Emission Factor3
(lb/10A12 Btu)
3.0
0.06
4.0
1.6
3.4
14
2.3
0.55
705
62.0
1767
23
2.5
Emission Factor
(Ib/MMBtu)
3.00e-06
6.00e-08
4.00e-06
1.60e-06
3.40e-06
1.40e-05
2.30e-06
5.50e-07
7.05e-04
6.20e-05
1.77e-03
2.30e-05
2.50e-06
Emission Factor0
(Ib/ton)
7.31e-05
1.46e-06
9.75e-05
3.90e-05
8.29e-05
3.41e-04
5.60e-05
1.34e-05
1.72e-02
1.51e-03
4.31e-02
5.60e-04
6.09e-05
aPage 6-24, "Average" values.
bPollutant was not detected in any of the sampling runs. EF is based on detection limits (1/2).
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
AMMONIA/CYANIDE EMISSION FACTORS
Pollutant
Ammoniab
Cyanide
aPage 6-26, Table 6-8, "Average" values.
bDetection limit values (1/2) for two runs
'Multiply emission factor, Ib/MMBtu, by
HC1, HF1 EMISSION FACTORS
Pollutant
Hydrogen Chloride
Hydrogen Fluoride
aPage 6-27, Table 6-10, "Average" values
bMultiply emission factor, Ib/MMBtu, by
Emission Factor
(lb/10A12 Btu)a
70
180
used in developing EF.
coal HHV, MMBtu/ton.
Emission Factor
(lb/10A12 Btu)a
132,049
8,921
coal HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
7.00e-05
1.80e-04
Emission Factor
(Ib/MMBtu)
1.32e-01
8.92e-03
Emission Factor
(lb/ton)c
1.71e-03
4.39e-03
Emission Factor
(lb/ton)b
3.22e+00
2.17e-01
5-68
-------
REFERENCE 41 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 31 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ORGANIC EMISSION FACTORS
Pollutant
Chloromethane (Methyl Chloride)
Bromomethane (Methyl Bromide )b
Vinyl Chlorideb
Chloroethane (Ethyl Chloride)b
Carbon Bisulfide
1 , 1 -Dichloroethane (Ethylidene
Dichloride)b
Chloroform b
1,2-Dichloroethane (Ethylene
Dichloride)b
2-Butanone (Methyl Ethyl Ketone)
1,1,1 -Trichloroethaneb
Carbon Tetrachlorideb
Vinyl Acetateb
1,2-Dichloropropane (Propylene
Dichloride)b
Trichloroetheneb
1 , 1 ,2-Trichloroethaneb
Benzene
l,3-Dichloropropyleneb
Bromoformb
Tetrachloroethene
1 , 1 ,2,2-Tetrachloroethaneb
Toluene
Chlorobenzeneb
Ethylbenzeneb
Styreneb
Xylenesb
aPage 6-28 (189 HAPs, only).
bPollutant not detected in any sampling
c Multiply emission factor, Ib/MMBtu,
Emission Factor3
(lb/10A12 Btu)
4.9
3.2
2.5
2.5
5.9
2.5
2.5
2.5
5.1
2.5
2.5
2.5
2.5
2.5
2.4
7.9
2.5
2.4
3.1
2.5
3.5
2.5
2.5
2.5
2.5
Emission Factor
(Ib/MMBtu)
4.90e-06
3.20e-06
2.50e-06
2.50e-06
5.90e-06
2.50e-06
2.50e-06
2.50e-06
5.10e-06
2.50e-06
2.50e-06
2.50e-06
2.50e-06
2.50e-06
2.40e-06
7.90e-06
2.50e-06
2.40e-06
3.10e-06
2.50e-06
3.50e-06
2.50e-06
2.50e-06
2.50e-06
2.50e-06
Emission Factor0
(Ib/ton)
1.19e-04
7.80e-05
6.09e-05
6.09e-05
1.44e-04
6.09e-05
6.09e-05
6.09e-05
1.24e-04
6.09e-05
6.09e-05
6.09e-05
6.09e-05
6.09e-05
5.85e-05
1.93e-04
6.09e-05
5.85e-05
7.55e-05
6.09e-05
8.53e-05
6.09e-05
6.09e-05
6.09e-05
6.09e-05
runs. EF is based on detection limits (1/2).
by coal HHV, MMBtu/ton.
5-69
-------
REFERENCE 41 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 31 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
PAH/ORGANIC EMISSION FACTORS
Pollutant
Benzyl chlorideb
Acetophenone
Hexachloroethaneb
Naphthalene
Hexachlorobutadieneb
2-Chloroacetophenone
Biphenyl
Acenaphthylene
Acenaphthene
Dibenzofurans
2,4-Dinitrotoluene
Fluorene
Hexachlorobenzeneb
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthracene
Chrysene
Benzo(b,k)fluoranthene
Benzo(a)pyreneb
Indeno(l,2,3-c,d)pyreneb
Benzo(g,h,i)peryleneb
Emission Factor3
(lb/10A12 Btu)
0.0059
0.6360
0.0059
0.2153
0.0059
0.2879
0.1257
0.0068
0.0265
0.0654
0.0197
0.0313
0.0059
0.0776
0.0207
0.0270
0.0139
0.0037
0.0089
0.0070
0.0012
0.0012
0.0012
Emission Factor
(Ib/MMBtu)
5.90e-09
6.36e-07
5.90e-09
2.15e-07
5.90e-09
2.88e-07
1.26e-07
6.80e-09
2.65e-08
6.54e-08
1.97e-08
3.13e-08
5.90e-09
7.76e-08
2.07e-08
2.70e-08
1.39e-08
3.70e-09
8.90e-09
7.00e-09
1.20e-09
1.20e-09
1.20e-09
Emission Factor0
(Ib/ton)
1.44e-07
1.55e-05
1.44e-07
5.25e-06
1.44e-07
7.02e-06
3.06e-06
1.66e-07
6.46e-07
1.59e-06
4.80e-07
7.63e-07
1.44e-07
1.89e-06
5.04e-07
6.58e-07
3.39e-07
9.02e-08
2.17e-07
1.71e-07
2.92e-08
2.92e-08
2.92e-08
aPage 6-30 (most common PAHs, 189 HAPs).
bPollutant not detected in any sampling runs. EF is based on detection limits (1/2).
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-70
-------
REFERENCE 41 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 31 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
DIOXINS/FURANS EMISSION FACTORS
Pollutant
2,3,7,8-TCDDb
OCDD
2,3,7,8-TCDF
OCDF
Emission Factor3 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
1.05e-06 1.05e-12
1.89e-05 1.89e-ll
4.76e-06 4.76e-12
1.95e-05 1.95e-ll
Emission Factor0
(Ib/ton)
2.56e-ll
4.61e-10
1.16e-10
4.75e-10
3Page 6-32.
bPollutant not detected in any sampling runs. EF is based on detection limits (1/2).
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
ALDEHYDES EMISSION FACTORS
Pollutant
Formaldehyde
Acetaldehyde
Acrolein
Propionaldehyde
Tage 6-33.
bMultiply emission factor, Ib/MMBtu, by
Emission Factor3 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
3.9 3.90e-06
89 8.90e-05
41 4.10e-05
25 2.50e-05
coal HHV, MMBtu/ton.
Emission Factorb
(Ib/ton)
9.50e-05
2.17e-03
9.99e-04
6.09e-04
5-71
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
A STUDY OF TOXIC EMISSIONS FROM A COAL-FIRED POWER
PLANT UTILIZING AN ESP/WET FGD SYSTEM. BATTELLE,
COLUMBUS, OHIO. DECEMBER 29, 1993.
FACILITY: Underwood, North Dakota
FILENAME DOE6.tbl
PROCESS DATA
Coal type3
Boiler configuration3
Coal source3
sec
Control device I3
Control device 2b
Control device 3
Data Quality
Process Parameters0
Test methodsd
Number of test runs6
Coal HHV, as received (Btu/lb)f
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Lignite
Pulverized, Dry bottom, tangential
North Dakota
10100302
ESP
Flue Gas Desulfurization- Wet Limestone Scrubber
(FGD-WLS)
None
A
550 MW
Assumed EPA, or EPA-approved, test methods
2,3
6,230
12,460,000
12.5
3Page2-l.
bPages 2-1, 2-4, and 2-5.
cPage 2-1.2 identical units @ 1,100 MW- one unit = 550 MW.
dPage 3-26.
eSee pages referenced below by groups of EFs.
fPage 2-33, average of "As received" values.
5-72
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
Pollutant
Aluminum
Antimony
Arsenic
Barium
Berylliumb
Boron
Cadmiumb
Calcium
Chromium0
Cobalt
Copper
Lead
Manganese
Mercury
Molybdenum0
Nickel0
Potassium
Selenium
Sodium
Titanium
Vanadium
Emission Factor3
(lb/10A12 Btu)
578
0.18
1.2
162
0.85
19
1.6
1308
10.0
1.5
4.9
0.69
30
9.5
0.51
5.1
109
8.3
218
42
4.4
Emission Factor
(Ib/MMBtu)
5.78e-04
1.80e-07
1.20e-06
1.62e-04
8.50e-07
1.90e-05
1.60e-06
1.31e-03
l.OOe-05
1.50e-06
4.90e-06
6.90e-07
3.00e-05
9.50e-06
5.10e-07
5.10e-06
1.09e-04
8.30e-06
2.18e-04
4.20e-05
4.40e-06
Emission Factord
(Ib/ton)
7.20e-03
2.24e-06
1.50e-05
2.02e-03
1.06e-05
2.37e-04
1.99e-05
1.63e-02
1.25e-04
1.87e-05
6.11e-05
8.60e-06
3.74e-04
1.18e-04
6.35e-06
6.35e-05
1.36e-03
1.03e-04
2.72e-03
5.23e-04
5.48e-05
aPage 6-76, "Average" values.
bPollutant was not detected in any of the sampling runs. EF is based on detection limits (1/2).
°Data from one run not used, EF based on data from two runs.
dMultiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-73
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
AMMONIA/CYANIDE EMISSION FACTORS
Pollutant
Ammoniab
Cyanide
Emission Factor3
(lb/10A12 Btu)
1.9
51
aPage 6-78.
bPollutant was not detected in any sampling runs. EF is based on
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton
HC1, HF1 EMISSION FACTORS
Pollutant
Hydrogen Chloride
Hydrogen Fluoride
Tage 6-80.
bMultiply emission factor, Ib/MMBtu,
ORGANIC EMISSION FACTORS
Pollutant
Chloromethane (Methyl Chloride)
Bromomethane (Methyl Bromide)
Vinyl Chlorideb
Chloroethane (Ethyl Chloride)b
Carbon Bisulfide
1 , 1 -Dichloroethane (Ethylidene
Dichloride)b
Chloroform b
1,2-Dichloroethane (Ethylene
Bichloride)
2-Butanone (Methyl Ethyl Ketone)
1,1,1 -Trichloroethaneb
Carbon Tetrachlorideb
Vinyl Acetateb
Emission Factor
(lb/10A12 Btu)a
1,339
3,976
by coal HHV, MMBtu/ton
Emission Factor3
(lb/10A12 Btu)
106
4.3
3.2
3.2
3.4
3.2
3.2
3.2
9.8
3.2
3.2
3.2
Emission Factor
(Ib/MMBtu)
1.90e-06
5.10e-05
Emission Factor0
(Ib/ton)
2.37e-05
6.35e-04
detection limits (1/2).
Emission Factor
(Ib/MMBtu)
1.34e-03
3.98e-03
Emission Factor
(Ib/MMBtu)
1.06e-04
4.30e-06
3.20e-06
3.20e-06
3.40e-06
3.20e-06
3.20e-06
3.20e-06
9.80e-06
3.20e-06
3.20e-06
3.20e-06
Emission Factor
(lb/ton)b
1.67e-02
4.95e-02
Emission Factor0
(Ib/ton)
1.32e-03
5.36e-05
3.99e-05
3.99e-05
4.24e-05
3.99e-05
3.99e-05
3.99e-05
1.22e-04
3.99e-05
3.99e-05
3.99e-05
5-74
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ORGANIC EMISSION FACTORS
Pollutant
1,2-Dichloropropane (Propylene
Dichloride)b
Trichloroetheneb
1 , 1 ,2-Trichloroethaneb
Benzene
l,3-Dichloropropyleneb
Bromoform
Tetrachloroetheneb
1 , 1 ,2,2-Tetrachloroethaneb
Toluene
Chlorobenzene
Ethylbenzeneb
Styrene
Xylenes
Emission Factor3
(lb/10A12 Btu)
3.2
3.2
3.2
41
3.2
3.1
3.2
3.2
24
3.3
3.2
3.3
3.5
3Page 6-82 (only 189 HAPs).
bPollutant was not detected in any sampling runs. EF is based on
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton
PAH/SVOC EMISSION FACTORS
Pollutant
Naphthalene
Acenaphthene
Dibenzofurans
2,4-Dinitrotoluene
Fluorene
Hexachlorobenzeneb
Phenanthrene
Anthracene
Fluoranthene
Emission Factor3
(lb/10A12 Btu)
0.2549
0.0173
0.0516
0.0065
0.0415
0.0009
0.3142
0.0147
0.0422
Emission Factor
(Ib/MMBtu)
3.20e-06
3.20e-06
3.20e-06
4.10e-05
3.20e-06
3.10e-06
3.20e-06
3.20e-06
2.40e-05
3.30e-06
3.20e-06
3.30e-06
3.50e-06
Emission Factor0
(Ib/ton)
3.99e-05
3.99e-05
3.99e-05
5.11e-04
3.99e-05
3.86e-05
3.99e-05
3.99e-05
2.99e-04
4.11e-05
3.99e-05
4.11e-05
4.36e-05
detection limits (1/2).
Emission Factor
(Ib/MMBtu)
2.55e-07
1.73e-08
5.16e-08
6.50e-09
4.15e-08
9.00e-10
3.14e-07
1.47e-08
4.22e-08
Emission Factor0
(Ib/ton)
3.18e-06
2.16e-07
6.43e-07
8.10e-08
5.17e-07
1.12e-08
3.91e-06
1.83e-07
5.26e-07
5-75
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
PAH/SVOC EMISSION FACTORS
Pollutant
Pyrene
Benz(a)anthracene
Chrysene
Benzo(b,k)fluoranthene
Benzo(a)pyrene
Indeno(l,2,3-c,d)pyrene
Benzo(g,h,i)perylene
Biphenyl
Acetophenone
Acenaphthylene
Benzyl Chloride
Emission Factor3
(lb/10A12 Btu)
0.0162
0.0021
0.0053
0.0045
0.0009
0.0006
0.0006
0.0230
0.5425
0.0105
0.0057
3Page 6-84 (most common PAHs, 189 HAPs).
bPollutant was not detected in any sampling runs. EF is based on
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton
DIOXINS/FURANS EMISSION FACTORS
Pollutant
2,3,7,8-TCDDb
OCDD
2,3,7,8-TCDF
OCDF
Emission Factor3
(lb/10A12 Btu)
9.90e-07
1.51e-05
9.89e-06
6.29e-06
3Page 6-86.
bPollutant was not detected in any sampling runs. EF is based on
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton
Emission Factor Emission Factor0
(Ib/MMBtu)
1.62e-08
2.10e-09
5.30e-09
4.50e-09
9.00e-10
6.00e-10
6.00e-10
2.30e-08
5.43e-07
1.05e-08
5.70e-09
detection limits (1/2)
Emission Factor
(Ib/MMBtu)
9.90e-13
1.51e-ll
9.89e-12
6.29e-12
detection limits (1/2)
(Ib/ton)
2.02e-07
2.62e-08
6.60e-08
5.61e-08
1.12e-08
7.48e-09
7.48e-09
2.87e-07
6.76e-06
1.31e-07
7.10e-08
Emission Factor
(lb/ton)c
1.23e-ll
1.88e-10
1.23e-10
7.84e-ll
5-76
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ALDEHYDES EMISSION FACTORS
Pollutant
Formaldehyde13
Acetaldehyde
Acrolein
Propionaldehyde
Emission Factor3
(lb/10A12 Btu)
1.8
67
1.1
12
aPage 6-88.
bPollutant was not detected in any sampling runs. EF is based on
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton
Emission Factor Emission Factor0
(Ib/MMBtu)
1.80e-06
6.70e-05
1.10e-06
1.20e-05
detection limits (1/2).
(Ib/ton)
2.24e-05
8.35e-04
1.37e-05
1.50e-04
5-77
-------
REFERENCE 43 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 33 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
TOXICS ASSESSMENT REPORT. ILLINOIS POWER COMPANY.
BALDWIN POWER STATION-UNIT 2. VOLUMES I THROUGH IV.
ROY F. WESTON, INC. DECEMBER, 1993
FACILITY:
FILENAME
Baldwin, Illinois
DOES.tbl
PROCESS DATA
Coal type3
Boiler configuration3
Coal source3
sec
Control device lb
Control device 2
Control device 3
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Coal HHV, as received (Btu/lb)e
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Bituminous
Cyclone
Illinois
10100203
ESP
None
None
A
568 MW
EPA, or EPA-approved, test methods
6 for filterable PM, 3 for other pollutants
10,633
21,266,000
21.3
3Page2-l.
bPage 2-4.
cPage 1-12.
dSee pages referenced below by groups
ePage 2-23. Average of 10765, 10681,
non-soot blowing periods.
ofEFs.
10722, 10412, 10426 and 10794 Btu/lb, as received,
METALS EMISSION FACTORS
Pollutant
Aluminum
Antimony
Arsenic
Barium
Beryllium
Emission Factor
(lb/10A12 Btu)3
5.55e+03
1.52e+00
1.34e+01
5.32e+00
1.41e+00
Emission Factor Emission Factor
(Ib/MMBtu)
5.55e-03
1.52e-06
1.34e-05
5.32e-06
1.41e-06
(lb/ton)b
1.18e-01
3.23e-05
2.85e-04
1.13e-04
3.00e-05
5-78
-------
REFERENCE 43 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 33 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
Pollutant
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Phosphorous
Selenium
Sodium
Titanium
Vanadium
aPage 4-18, "Average" values.
bMultiply emission factor, Ib/MMBtu,
Emission Factor
(lb/10A12 Btu)a
7.67e+03
3.02e+00
3.25e+02
5.06e+01
6.80e+00
1.89e+01
8.39e+03
2.86e+01
2.90e+02
2.23e+01
3.83e+00
3.37e+01
2.21e+01
9.33e+02
1.98e+02
1.30e+02
1.17e+03
3.82e+02
l.OOe+02
bv coal HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
7.67e-03
3.02e-06
3.25e-04
5.06e-05
6.80e-06
1.89e-05
8.39e-03
2.86e-05
2.90e-04
2.23e-05
3.83e-06
3.37e-05
2.21e-05
9.33e-04
1.98e-04
1.30e-04
1.17e-03
3.82e-04
l.OOe-04
Emission Factor
(lb/ton)b
1.63e-01
6.42e-05
6.91e-03
1.08e-03
1.45e-04
4.02e-04
1.78e-01
6.08e-04
6.17e-03
4.74e-04
8.14e-05
7.17e-04
4.70e-04
1.98e-02
4.21e-03
2.76e-03
2.49e-02
8.12e-03
2.13e-03
5-79
-------
REFERENCE 43 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 33 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ORGANICS EMISSION FACTORS
Pollutant
Phenol
Acetophenone
Isophorone
Biphenylb
Di-n-butylphthalate
bis(2-Ethylhexyl)phthalate
3Page 4-74.
bEmission factor based on only non-detects.
°Multiply emission factor, Ib/MMBtu, by coal
PAH EMISSION FACTORS
Pollutant
Naphthalene
Acenaphthylene
Acenaphtheneb
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthraceneb
Benzo(b,k)fluoranthene
Benzo(a)pyreneb
Indeno(l,2,3-c,d)pyreneb
Benzo(g,h,i)peryleneb
3Page 4-74.
bPollutant not detected in any sampling runs.
°Multiply emission factor, Ib/MMBtu, by coal
Emission Factor3
(lb/10A12 Btu)
1.15e+00
1.23e+00
2.62e+01
8.78e-01
3.00e+00
4.60e+00
HHV, MMBtu/ton.
Emission Factor3
(lb/10A12 Btu)
3.94e-01
3.19e-02
6.32e-03
4.87e-03
5.69e-02
2.64e-03
1.74e-02
2.82e-03
1.17e-03
3.91e-03
5.44e-04
l.lle-03
1.13e-03
Emission Factor
(Ib/MMBtu)
1.15e-06
1.23e-06
2.62e-05
8.78e-07
3.00e-06
4.60e-06
Emission Factor
(Ib/MMBtu)
3.94e-07
3.19e-08
6.32e-09
4.87e-09
5.69e-08
2.64e-09
1.74e-08
2.82e-09
1.17e-09
3.91e-09
5.44e-10
l.lle-09
1.13e-09
Emission Factor0
(Ib/ton)
2.45e-05
2.62e-05
5.57e-04
1.87e-05
6.38e-05
9.78e-05
Emission Factor °
(Ib/ton)
8.38e-06
6.78e-07
1.34e-07
1.04e-07
1.21e-06
5.61e-08
3.70e-07
6.00e-08
2.49e-08
8.32e-08
1.16e-08
2.36e-08
2.40e-08
EF is based on detection limits.
HHV, MMBtu/ton.
5-80
-------
REFERENCE 43 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 33 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
DIOXINS/FURANS EMISSION FACTORS
Pollutant
2,3,7,8-TCDDb
Total TCDD
Total PeCDDb
Total HxCDD
Total HpCDD
Total OCDDb
2,3,7,8-TCDFb
Total TCDFb
Total PeCDF
Total HxCDF
Total HpCDF
Total OCDF
3Page 4-76.
bPollutant not detected in any sampling runs.
°Multiply emission factor, Ib/MMBtu, by coal
Emission Factor3
(lb/10A12 Btu)
2.54e-06
1.34e-06
7.37e-07
9.59e-07
2.53e-06
8.91e-06
1.27e-06
3.82e-06
3.99e-06
5.57e-06
3.17e-06
4.15e-06
HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
2.54e-12
1.34e-12
7.37e-13
9.59e-13
2.53e-12
8.91e-12
1.27e-12
3.82e-12
3.99e-12
5.57e-12
3.17e-12
4.15e-12
Emission Factor0
(Ib/ton)
5.40e-ll
2.85e-ll
1.57e-ll
2.04e-ll
5.38e-ll
1.89e-10
2.70e-ll
8.12e-ll
8.49e-ll
1.18e-10
6.74e-ll
8.83e-ll
ALDEHYDES/KETONES EMISSION FACTORS
Pollutant
Formaldehyde
Acetaldehyde
Acrolein
Methyl Ethyl Ketone
3Page 4-78, ESP Outlet data, only 189 HAPs.
bMultiply emission factor, Ib/MMBtu, by coal
Emission Factor3
(lb/10A12 Btu)
1.68e+00
1.37e+01
3.55e+00
3.70e+00
HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
1.68e-06
1.37e-05
3.55e-06
3.70e-06
Emission Factor0
(Ib/ton)
3.57e-05
2.91e-04
7.55e-05
7.87e-05
5-81
-------
REFERENCE 43 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 33 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ORGANICS EMISSION FACTORS
Pollutant
Bromomethane (Methyl Bromide)
Carbon Bisulfide
Methylene Chlorideb
Hexane
Benzene
Tolueneb
Ethylbenzene
Xylenes(m/p + o)
Styrene
aPage 4-80.
bResults suspected to be biased by lab
°Multiply emission factor, Ib/MMBtu,
Emission Factor3
(lb/10A12 Btu)
9.70e-01
1.37e-01
1.83e+01
1.64e-01
1.21e+02
2.00e+00
1.26e-01
1.87e+00
1.99e-01
solvents, do not use.
by coal HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
9.70e-07
1.37e-07
1.83e-05
1.64e-07
1.21e-04
2.00e-06
1.26e-07
1.87e-06
1.99e-07
Emission Factor0
(Ib/ton)
2.06e-05
2.91e-06
3.89e-04
3.49e-06
2.57e-03
4.25e-05
2.68e-06
3.97e-05
4.23e-06
5-82
-------
REFERENCE 44 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 34 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
TOXICS ASSESSMENT REPORT. MINNESOTA POWER
COMPANY BOSWELL ENERGY CENTER UNIT 2. COHASSET,
MINNESOTA. VOLUME 1-MAIN REPORT. ROYF.WESTON,
INC. WEST CHESTER, PENNSYLVANIA. DECEMBER, 1993.
FACILITY:
FILENAME
Cohasset, Minnesota
DOE8.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device 1°
Control device 2
Control device 3
Data Quality
Process Parameters3
Test methodsd
Number of test runs6
Coal HHV, as received (Btu/lb)f
Coal HHV, as received (Btu/ton)
Coal HHV, as received (MMBtu/ton)
Subbituminous
Pulverized, Dry bottom
Montana/Wyoming
10100222
Baghouse
None
None
A
69 MW
EPA, or EPA-approved, test methods
3
8,798
17,596,000
17.6
8,692
8,749
8,839
8,815
8,871
8,820
avg
8,798
3Page2-l.
bPage 2-1 for "pulverized", assumed dry bottom.
cPage 2-4.
dPage 1-12.
eSee pages listing emission factors.
fPage 2-23. average of 8692. 8749. 8839. 8815. 8871. 8820 Btu/lb.
5-83
-------
REFERENCE 44 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 34 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
Pollutant
Aluminum
Antimonyb
Arsenic
Barium
Berylliumb
Boron
Cadmiumb
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Phosphorous
Selenium
Sodium
Titanium
Vanadium
Emission Factor3
(lb/10A12 Btu)
1.93e+03
6.77e-01
3.24e-01
8.16e+01
1.29e-01
6.09e+02
6.48e-01
4.76e+02
2.04e+00
7.01e-01
2.40e+00
4.12e+02
2.44e+00
2.05e+02
1.84e+01
1.93e+00
1.29e+00
1.97e+00
5.71e+01
2.67e+01
3.23e+00
1.97e+02
5.78e+01
1.53e+00
Emission Factor
(Ib/MMBtu)
1.93e-03
6.77e-07
3.24e-07
8.16e-05
1.29e-07
6.09e-04
6.48e-07
4.76e-04
2.04e-06
7.01e-07
2.40e-06
4.12e-04
2.44e-06
2.05e-04
1.84e-05
1.93e-06
1.29e-06
1.97e-06
5.71e-05
2.67e-05
3.23e-06
1.97e-04
5.78e-05
1.53e-06
Emission Factor0
(Ib/ton)
3.40e-02
1.19e-05
5.70e-06
1.44e-03
2.27e-06
1.07e-02
1.14e-05
8.38e-03
3.59e-05
1.23e-05
4.22e-05
7.25e-03
4.29e-05
3.61e-03
3.24e-04
3.40e-05
2.27e-05
3.47e-05
l.OOe-03
4.70e-04
5.68e-05
3.47e-03
1.02e-03
2.69e-05
aPage 4-14, "Average" values.
bPollutant not detected in any sampling runs. EF is based on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-84
-------
REFERENCE 44 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 34 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ORGANICS EMISSION FACTORS
Pollutant
n-Nitrosodimethylamineb
Phenol
Acetophenone
Biphenylb
Di-n-butylphthalateb
bis(2-Ethylhexyl)phthalate
Emission Factor3 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
8.87e-01 8.87e-07
4.29e-01 4.29e-07
7.13e-01 7.13e-07
1.78e-01 1.78e-07
1.94e+00 1.94e-06
1.68e+00 1.68e-06
Emission Factor0
(Ib/ton)
1.56e-05
7.55e-06
1.25e-05
3.13e-06
3.41e-05
2.96e-05
3Page4-43.
bPollutant not detected in any sampling runs. EF is based on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
PAH EMISSION FACTORS
Pollutant
Naphthalene
Acenaphthylene
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthracene
Benzo(b,j ,k)fluoranthene
Benzo(a)pyrene
Indeno(l,2,3-c,d)pyrene
Benzo(g,h,i)peryleneb
Emission Factor3 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
2.53e-01 2.53e-07
5.31e-03 5.31e-09
4.08e-02 4.08e-08
8.84e-03 8.84e-09
2.10e-01 2.10e-07
6.17e-03 6.17e-09
8.25e-02 8.25e-08
3.73e-02 3.73e-08
4.68e-03 4.68e-09
3.05e-03 3.05e-09
2.09e-04 2.09e-10
3.45e-04 3.45e-10
5.19e-04 5.19e-10
Emission Factor0
(Ib/ton)
4.45e-06
9.34e-08
7.18e-07
1.56e-07
3.70e-06
1.09e-07
1.45e-06
6.56e-07
8.23e-08
5.37e-08
3.68e-09
6.07e-09
9.13e-09
3Page4-43.
bPollutant not detected in any sampling runs. EF is based on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-85
-------
REFERENCE 44 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 34 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
DIOXINS/FURANS EMISSION FACTORS
Pollutant
2,3,7,8-TCDD
Total TCDD
Total PeCDD
Total HxCDD
Total HpCDDb
Total OCDD
2,3,7,8-TCDF
Total TCDF
Total PeCDF
Total HxCDF
Total HpCDF
Total OCDF
Emission Factor3 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
8.14e-07 8.14e-13
9.29e-06 9.29e-12
4.64e-06 4.64e-12
2.10e-06 2.10e-12
1.86e-06 1.86e-12
1.10e-05 1.10e-ll
6.03e-06 6.03e-12
6.04e-05 6.04e-ll
4.74e-05 4.74e-ll
2.23e-05 2.23e-ll
6.95e-06 6.95e-12
1.86e-06 1.86e-12
Emission Factor0
(Ib/ton)
1.43e-ll
1.63e-10
8.16e-ll
3.70e-ll
3.27e-ll
1.94e-10
1.06e-10
1.06e-09
8.34e-10
3.92e-10
1.22e-10
3.27e-ll
3Page4-45.
bPollutant not detected in any sampling runs. EF is based on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
ALDEHYDES/KETONES EMISSION FACTORS
Pollutant
Formaldehyde13
Acetaldehydeb
Acrolein
Methyl Ethyl Ketoneb
Emission Factor3 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
1.70e+00 1.70e-06
1.09e+00 1.09e-06
3.40e+00 3.40e-06
4.99e+00 4.99e-06
Emission Factor0
(Ib/ton)
2.99e-05
1.92e-05
5.98e-05
8.78e-05
3Page 4-47, ESP Outlet data, only 189 HAPs.
bPollutant not detected in any sampling runs. EF is based on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-86
-------
REFERENCE 44 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 34 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
VOC EMISSION FACTORS
Pollutant
Chloroethane (ethyl chloride)
Carbon Bisulfide
Methylene Chloride
Hexane
Vinyl acetateb
2-Butanone (Methyl Ethyl Ketone)
Benzene
Methyl Methacrylate
Ethylene Dibromide0
Toluene
Tetrachloroethene (PCE)
Chlorobenzene
Ethylbenzene
Xylenes(m/p + o)
Styrene
Cumene
Emission Factor3
(lb/10A12 Btu)
2.50e+00
1.77e+01
1.07e+01
1.54e+00
4.29e-01
1.64e+01
1.03e-02
1.14e+00
6.56e-02
5.45e+00
5.61e-01
1.63e-01
4.27e-01
2.43e+00
1.75e+00
3.02e-01
Emission Factor
(Ib/MMBtu)
2.50e-06
1.77e-05
1.07e-05
1.54e-06
4.29e-07
1.64e-05
1.03e-08
1.14e-06
6.56e-08
5.45e-06
5.61e-07
1.63e-07
4.27e-07
2.43e-06
1.75e-06
3.02e-07
Emission Factor0
(Ib/ton)
4.40e-05
3.11e-04
1.88e-04
2.71e-05
7.55e-06
2.89e-04
1.81e-07
2.01e-05
1.15e-06
9.59e-05
9.87e-06
2.87e-06
7.51e-06
4.27e-05
3.08e-05
5.31e-06
aPage 4-49.
bPollutant not detected in any sampling runs. EF is based on detection limits.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
5-87
-------
REFERENCE 45 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 35 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
ASSESSMENT OF TOXIC EMISSIONS FROM A COAL FIRED
POWER PLANT UTILIZING AN ESP. FINAL REPORT-REVISION
1. ENERGY AND ENVIRONMENTAL RESEARCH
CORPORATION. IRVINE, CALIFORNIA. DECEMBER 23, 1993.
FACILITY: Brilliant, Ohio, Cardinal Unit 1
FILENAME DOES.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal source3
sec
Control device I3
Control device 2
Control device 3
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Coal HHV (Btu/lb)e
Coal HHV (Btu/ton)
Coal HHV (MMBtu/ton)
Bituminous
Pulverized, Dry bottom
Pennysylvania
10100202
ESP
None
None
C (no HHV for the coal, had to use average from AP-42)
615
EPA, or EPA-approved, test methods
3
13,000
26,000,000
26.0
3Page 1-1.
bPage 1-1 for "pulverized", assumed dry bottom.
cPage 1-4.
dPage 1-5.
e Appendix A of AP-42, "Typical Parameters of Various Fuels".
METALS EMISSION FACTORS
Pollutant
Aluminum
Calcium
Iron
Magnesium
Emission Factor3 Emission Factor Emission Factorb
(lb/10A12 Btu) (Ib/MMBtu) (Ib/ton)
235 2.35e-04 6.11e-03
283 2.83e-04 7.36e-03
568 5.68e-04 1.48e-02
16.4 1.64e-05 4.26e-04
5-88
-------
REFERENCE 45 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 35 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS EMISSION FACTORS
Pollutant
Phosphorous
Potassium
Silicon
Sodium
Titanium
Zinc
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Lead
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Vanadium
aPage 1-11.
bMultiply emission factor, Ib/MMBtu,
Emission Factor3
(lb/10A12 Btu)
141
88.7
60.9
249
16.6
18.3
2.36
3.49
0.872
0.070
1,912
0.846
7.51
0.631
1.39
3.83
15.0
0.448
0.567
4.72
92.8
0.200
1.57
by coal HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
1.41e-04
8.87e-05
6.09e-05
2.49e-04
1.66e-05
1.83e-05
2.36e-06
3.49e-06
8.72e-07
7.00e-08
1.91e-03
8.46e-07
7.51e-06
6.31e-07
1.39e-06
3.83e-06
1.50e-05
4.48e-07
5.67e-07
4.72e-06
9.28e-05
2.00e-07
1.57e-06
Emission Factorb
(Ib/ton)
3.67e-03
2.31e-03
1.58e-03
6.47e-03
4.32e-04
4.76e-04
6.14e-05
9.07e-05
2.27e-05
1.82e-06
4.97e-02
2.20e-05
1.95e-04
1.64e-05
3.61e-05
9.96e-05
3.90e-04
1.16e-05
1.47e-05
1.23e-04
2.41e-03
5.20e-06
4.08e-05
5-89
-------
REFERENCE 45 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 35 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
DIOXINS/FURANS EMISSION FACTORS
Pollutant
Total TCDD
Total HxCDD
Total HpCDD
Total OCDD
2,3,7,8-TCDF
Total PeCDF
Total HxCDF
Total HpCDF
Total OCDF
3Page 1-11.
bMultiply emission factor, Ib/MMBtu, by coal
Emission Factor3
(lb/10A12 Btu)
5.15e-05
2.23e-05
7.61e-06
2.03e-05
6.58e-07
2.79e-06
2.51e-05
2.68e-06
1.07e-05
HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
5.15e-ll
2.23e-ll
7.61e-12
2.03e-ll
6.58e-13
2.79e-12
2.51e-ll
2.68e-12
1.07e-ll
Emission Factorb
(Ib/ton)
1.34e-09
5.80e-10
1.98e-10
5.28e-10
1.71e-ll
7.25e-ll
6.53e-10
6.97e-ll
2.78e-10
SEMIVOLATILE ORGANICS EMISSION FACTORS
Pollutant
Benzyl Chloride
Isophorone
Dimethyl Sulfate
Naphthalene
3Page 1-11.
bMultiply emission factor, Ib/MMBtu, by coal
ORGANIC EMISSION FACTORS
Pollutant
2-Butanone (Methyl Ethyl Ketone)
Formaldehyde
Benzene
Bromomethane (Methyl Bromide)
Chloroform
Chloromethane (Methyl Chloride)
Emission Factor3
(lb/10A12 Btu)
53.9
23.3
1.83
1.94
HHV, MMBtu/ton.
Emission Factor3
(lb/10A12 Btu)
48.1
60.0
3.40
15.1
2.92
6.38
Emission Factor
(Ib/MMBtu)
5.39e-05
2.33e-05
1.83e-06
1.94e-06
Emission Factor
(Ib/MMBtu)
4.81e-05
6.00e-05
3.40e-06
1.51e-05
2.92e-06
6.38e-06
Emission Factorb
(Ib/ton)
1.40e-03
6.06e-04
4.76e-05
5.04e-05
Emission Factorb
(Ib/ton)
1.25e-03
1.56e-03
8.84e-05
3.93e-04
7.59e-05
1.66e-04
5-90
-------
REFERENCE 45 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 35 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ORGANIC EMISSION FACTORS
Pollutant
Hexane
m,p-Xylene
Methyl Hydrazine
Methyl Tert Butyl Ether
Toluene
3Page 1-13.
bMultiply emission factor, Ib/MMBtu, by coal
OTHER EMISSION FACTORS
Pollutant
Ammonia
Chlorine
Hydrogen Chloride
Hydrogen Cyanide
Hydrogen Fluoride
CO
THC
NOX
SOX
3Page 1-14. Note that SOx and NOx units are
bMultiply emission factor, Ib/MMBtu, by coal
Emission Factor3
(lb/10A12 Btu)
6.53
2.98
6.57
1.36
5.16
HHV, MMBtu/ton.
Emission Factor3
(lb/10A12 Btu)
40.7
1,547
22,915
0.591
1,869
753
365
Ib/MMBtu.
HHV, MMBtu/ton.
Emission Factor
(Ib/MMBtu)
6.53e-06
2.98e-06
6.57e-06
1.36e-06
5.16e-06
Emission Factor
(Ib/MMBtu)
4.07e-05
1.55e-03
2.29e-02
5.91e-07
1.87e-03
7.53e-04
3.65e-04
1.22e+00
4.41e+00
Emission Factorb
(Ib/ton)
1.70e-04
7.75e-05
1.71e-04
3.54e-05
1.34e-04
Emission Factorb
(Ib/ton)
1.06e-03
4.02e-02
5.96e-01
1.54e-05
4.86e-02
1.96e-02
9.49e-03
3.17e+01
1.15e+02
5-91
-------
REFERENCE 46 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 36 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
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.
FACILITY:
FILENAME
EPRI SITE 16
SITE16.tbl
PROCESS DATA
Coal type3
Boiler configuration13
Coal sourcef
sec
Control device la
Control device 2a
Control device 3
Data Quality
Process Parameters3
Test methods0
Number of test runsd
Coal HHV, dry (Btu/lb)e
Coal moisture percent by weight6
Coal HHV, as received (Btu/lb)
Coal HHV, as received (MMBtu/lb)
Coal HHV, as received (MMBtu/ton)
Coal feed rate (lb/hr,dry)e
Coal feed rate, as received, (Ib/hr)
Coal feed rate, as received, (ton/hr)
Bituminous
Pulverized, dry bottom
Virginia/Kentucky
10100202
Low Nox Burners/Overfire Air (LNB/OFA)
ESP
none
A
500 MW
EPA, or EPA-approved, test methods
3
13,800
3.8%
13,295
0.013
26.59
315,000
327,443
164
aPage 2-1
bConversation with Greg Behrens, Radian, Austin, Texas.
cPage 3-1
dPage 3-21, 3-22, 3-23
ePage 3-7
fAppendix B of EPRI Synthesis Report, page B-2
5-92
-------
REFERENCE 46 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 36 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
STACK EMISSION FACTORS
Pollutant
Arsenic
Barium
Beryllium
Cadmium
Chloride
Chromium
Chrome VI
Cobalt
Copper
Fluoride
Lead
Manganese
Mercury
Molybdenum
Nickel
Phosphorous
Selenium
Vanadium
Benzene0
Toluene
Formaldehyde
Acenaphthene
Acenaphthylene
Anthracene
Benzo(a)pyrene°
Benzo(b,j ,k)fluoranthenes
Benzo(g,h,i)perylene°
Benz(a)anthracene
Chrysene
(lb/10A12 Btu)a
110
140
3.1
3.6
15,000
21
5.4
6.5
30
5,100
11
21
4.8
12
17
180
140
41
0.51
0.7
1.3
0.0081
0.0030
0.0037
0.0041
0.0015
0.0031
0.0070
0.0018
(Ib/MMBtu)
1.10e-04
1.40e-04
3.10e-06
3.60e-06
1.50e-02
2.10e-05
5.40e-06
6.50e-06
3.00e-05
5.10e-03
1.10e-05
2.10e-05
4.80e-06
1.20e-05
1.70e-05
1.80e-04
1.40e-04
4.10e-05
5.10e-07
7.00e-07
1.30e-06
8.10e-09
3.00e-09
3.70e-09
4.10e-09
1.50e-09
3.10e-09
7.00e-09
1.80e-09
(Ib/ton)
2.92e-03
3.72e-03
8.24e-05
9.57e-05
3.99e-01
5.58e-04
1.44e-04
1.73e-04
7.98e-04
1.36e-01
2.92e-04
5.58e-04
1.28e-04
3.19e-04
4.52e-04
4.79e-03
3.72e-03
1.09e-03
1.36e-05
1.86e-05
3.46e-05
2.15e-07
7.98e-08
9.84e-08
1.09e-07
3.99e-08
8.24e-08
1.86e-07
4.79e-08
5-93
-------
REFERENCE 46 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 36 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
STACK EMISSION FACTORS
Pollutant
Fluoranthene
Fluorene
Indeno(l,2,3-c,d)pyreneb
Phenanthrene
Pyrene
"Pages 3 -24, 3-25. Individual run
(lb/10A12 Btu)a
0.010
0.0099
0.0027
0.044
0.011
data on pages 3-21, 3-22, 3-23.
(Ib/MMBtu)
l.OOe-08
9.90e-09
2.70e-09
4.40e-08
1.10e-08
(Ib/ton)
2.66e-07
2.63e-07
7.18e-08
1.17e-06
2.92e-07
5-94
-------
REFERENCE 47 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 37 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
TEST REPORT TITLE:
FIELD CHEMICAL EMISSIONS MONITORING REPORT: SITE 122.
SOUTHERN RESEARCH INSITUTUE, BIRMINGHAM, ALABAMA.
MAY, 1995.
FACILITY:
FILENAME
EPRI SITE 122
SITE122.tbl
PROCESS DATA
Coal type3
Boiler configuration3
Coal source3
sec
Control device I3
Control device 23
Control device 33
Data Quality
Process Parameters3
Test methodsb
Number of test runs0
Coal HHV, as fired (Btu/lb)d
Coal HHV, as fired (Btu/ton)
Coal HHV, as fired (MMBtu/ton)
Bituminous
Cyclone
Illinois
10100203
Electrostatic Precipitator, Cold side
none
none
A
275 MW
EPA, or EPA-approved, test methods
2 for manganese, 3 for all others
12,327
24,654,000
24.7
3Page2-l.
bPage 1-3.
Tages 3-17, 3-20 and 3-22.
dPage 3-4.
5-95
-------
REFERENCE 47 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 37 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
METALS, NONMETALS AND ORGANIC
EMISSION FACTORS
Emission Factor3 Emission Factor
Pollutant
Arsenic
Barium
Beryllium
Cadmium
Chromium
Cobalt
Lead
Manganeseb
Mercury
Nickel
Selenium
Vanadium
Fluorine
Chlorine
Sulfur (sulfur dioxide)
Formaldehyde
Benzene
Toluene
(lb/10A12 Btu)
220
69
4.0
3.6
100
26
180
205
8.2
71
67
148
3.8e+03
2.3e+05
1.5e+06
0.7
7.8
1.9
Tage 3-30.
bEF developed from two sampling runs. See footnote c to Table 3.10,
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
(Ib/MMBtu)
2.20e-04
6.90e-05
4.00e-06
3.60e-06
l.OOe-04
2.60e-05
1.80e-04
2.05e-04
8.20e-06
7.10e-05
6.70e-05
1.48e-04
3.80e-03
2.30e-01
1.50e+00
7.00e-07
7.80e-06
1.90e-06
page 3-17.
Emission Factor0
(Ib/ton)
5.42e-03
1.70e-03
9.86e-05
8.88e-05
2.47e-03
6.41e-04
4.44e-03
5.05e-03
2.02e-04
1.75e-03
1.65e-03
3.65e-03
9.37e-02
5.67e+00
3.70e+01
1.73e-05
1.92e-04
4.68e-05
5-96
-------
TITLE: Hydrogen Chloride and Hydrogen Fluoride Emission Factors for the NAPAP Emission
Inventory. EPA-600/7-85-041. October, 1985.
Filename: NAPAP.tbl
BOILER SCC DESCRIPTIONS
Source
Classification
Codes
Hydrogen
Chloride
(lb/ton)a-b
Hydrogen
Fluoride
(lb/ton)a-b
Commerical/Industrial Boilers
Bituminous and Subbituminous Coal
Firing Types
Pulverized Coal Wet Bottom
Pulverized Coal Dry Bottom
Overfeed Stoker
Underfeed Stoker
Spreader Stoker
Hand-fired
Pulverized Coal Dry Bottom
Tangential
Atmospheric Fluidized Bed
Combustor
Cyclone Furnace
Traveling Grate Overfeed Stoker
1-03-002-05/21
1-03-002-06/22
1-03-002-07
1-03-002-08
1-03-002-09/24
1-03-002-14
1-03-002-16/26
1-03-002-17/18
1-03-002-23
1-03-002-25
1.48
0.17
Electric Generation & Industrial Boilers
Bituminous and Subbituminous Coal
Firing Types
Pulverized Coal Wet Bottom
Pulverized Coal Dry Bottom
Cyclone Furnace
Spreader Stoker
1-01-002-01/21 *
1-02-002-01/21
1-01-002-02/22
1-02-002-02/22
1-01-002-03/23
1-02-002-03/23
1-01-002-04/24
1-02-002-04/24
1.9
0.23
5-97
-------
BOILER SCC DESCRIPTIONS
Source
Classification
Codes
Hydrogen
Chloride
(lb/ton)a-b
Hydrogen
Fluoride
(lb/ton)a'b
Traveling Grate Overfeed Stoker
Overfeed Stoker
Pulverized Coal Dry Bottom,
Tangential Firing
Atmospheric Fluidized Bed
Underfeed Stoker
1-01-002-05/25
1-02-002-25
1-02-002-05
1-01-002-12/26
1-02-002-12
1-01-002-17
1-01-002-18
1-02-002-17
1-02-002-18
1-02-002-06
Commerical/Industrial Boilers
Lignite
Firing Types
Pulverized Coal 1-03-003-05
Pulverized Coal Tangential Firing 1-03-003-06
Traveling Grate Overfeed Stoker 1-03-003-07
Spreader Stoker 1-03-003-09
0.351
0.063
Electric Generation & Industrial Boilers
Lignite
Firing Types
Pulverized Coal
Pulverized Coal Tangential Firing
Cyclone Furnace
1-01-003-01
1-02-003-01
1-01-003-02
1-02-003-02
1-01-003-03
1-02-003-03
0.01
0.01
5-98
-------
Source Hydrogen Hydrogen
Classification Chloride Fluoride
BOILER SCC DESCRIPTIONS Codes (lb/ton)a-b (lb/ton)a>b
Traveling Grate Overfeed Stoker 1-01-003-04
1-02-003-04
Spreader Stoker 1-01-003-06
1-02-003-06
Overall Average 1.2 0.15
Quality Rating B B
aPages 29, 30, 31. Factors are for both uncontrolled and controlled boilers.
bAn asterisk to the left of a factor indicates that it was used in calculating the overall emission
factor.
REFERENCE 48 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 38 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
5-99
-------
2.0A
1.8A
* 1.6A
0
If 1.4A
a 2 1.2A
»o l.OA
•0 o
Q
§
D
0.8A
0.6A
0.4A
0.2A
0
Scrubber
Baghouse
Uncontrolled
Multiple cyclone
I i
l.OA
0.6A -o
§9
0.4A 11
!S
o.2A ;-a -
0.1A i
0.06A
0-°
H ^
32
g S
w
0.02A
0.01A -1
0.1A
0.06A fi
c
0.04A 2
0.02A
O.OIA ;,j
w §
0.006A ^
fl
0
0.002A |
s
0.001A "
.1 .2 .4 .6 1
246 10 20 40 60 100
Particle diameter (urn)
-------
s
It
P *S
S g
U
u
|l
r
3.5 A
2.8A
2.1A
1.4A
0.70A
0
ESP
Multiple cyclone
l.OA
0.9A
0.8A
0.7A
0.6A
0.5A
0.4A
0.3A
0.2A
0.1A
.1
.4 .6 1
0
4 6 10 20 40 60 100
1
§
= 8
±2 "rt
18
O a/)
fl> ^
o ab
1*
u
0.1A
0.06A
0.04A |
^ if
0.02A -2 £
0.01 A * 1
-------
l.OA
0.9A
£ 0.8A
| f 0.7A
O tft
'i § 0.6A
'S
(U
*8 »
u 1 0.5A
O
s
0.4A
0.3A
0.2A
0.1 A
0
.1
j L
Uncontrolled
i i
0.1 OA
0.06A
0.04A
0.02A
c
o
T3
(U
0.01A £ -f
0.006A | ,M
0.004A w 1.
0.002A
0.001A
.4 .6 1 2 4 6 10
Particle diameter f jjm)
20
40 60 100
-------
10
9
8
7
6
5
4
3
2
1
0
.1
Multiple cyclone with-
flyash reinjection
Multiple cyclone without
flyash reinjection
Baghouse
Uncontrolled
ESP
I
1 2 4 6 10
Particle diameter ( m)
20
10.0
6.0
4.0
2.0
1.0
0.6
0.4
0.2
0.1
40 60 100
0.10
0.06
0.04
0.02
0.01
I
0.004
a
0.006 |
I
0.002 m
0.001
-------
3
o
a
_o
'S
CA
8
7.2
6.4
5.6
4.8
• ^H "**
g —r
•S 8 4'°
IS 2.4
1.6
0.8
0
o
Multiple
cyclone
i i i i
I
10
6.0
4.0
2.0
1.0
0.6
0.4
0.2
0.1
& a
o ^
oo
-------
S-i
O
O
• i—i
Cfl
a-^
o
o
o
o
10
9
8
7
6
5
4
3
2
1
0
.1
Uncontrolled
i i i i i i 1
i i i i i i 1
i i i i i i i
.4 .6 1 2 4 6 10
Particle diameter ( m)
20
40 60 100
------- |