EMISSION FACTOR DOCUMENTATION FOR
AP-42 SECTION 1.7,
LIGNITE COMBUSTION
Prepared by:
Acurex Environmental Corporation
Research Triangle Park, NC 27709
Edward Aul & Associates, Inc.
Chapel Hill, NC 27514
E. H. Pechan & Associates, Inc.
Rancho Cordova, CA 95742
Contract No. 68-DO-0120
EPA Work Assignment Officer: Michael Hamlin
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
[To be completed after review of DRAFT EFD by E.H. Pechan & Assoc., Inc.]
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TABLE OF CONTENTS
LIST OF TABLES vi
LIST OF FIGURES viii
CHAPTER! INTRODUCTION 1-1
CHAPTER 2. SOURCE DESCRIPTION 2-1
2.1 CHARACTERIZATION OF LIGNITE
APPLICATIONS 2-1
2.1.1 North Dakota Region 2-2
2.1.2 Gulf Region 2-3
2.2 PROCESS DESCRIPTION 2-3
2.2.1 Cyclone Firing 2-4
2.2.2 Stoker Firing 2-5
2.2.3 Fluidized Bed Combustion 2-5
2.3 EMISSIONS 2-6
2.3.1 Particulate Emissions 2-6
2.3.2 NOX Emissions 2-7
2.3.3 SOX Emissions 2-8
2.3.4 Carbon Monoxide Emissions 2-8
2.3.5 Total Organic Compounds 2-9
2.3.6 Trace Element Emissions 2-10
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2.4 CONTROL TECHNOLOGIES 2-11
2.4.1 Particulate 2-11
2.4.2 NOX Control 2-13
2.4.3 SOX Control 2-15
REFERENCES 2-25
CHAPTER 3. GENERAL EMISSIONS 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 3-3
3.1.3 Emission Factor Quality Rating 3-5
3.2 SPECIATED VOCs 3-6
3.2.1 Literature Search 3-6
TABLE OF CONTENTS (continued)
Page
3.3 HAZARDOUS AIR POLLUTANTS 3-6
3.3.1 Literature Search 3-6
3.3.2 Literature Evaluation for
HAPs 3-7
3.3.3 Data and Emission Factor
Quality Rating Criteria 3-7
3.4 NITROUS OXIDE 3-9
3.4.1 Literature Search 3-9
3.4.2 Literature Evaluation 3-9
IV
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3.5 FUGITIVE EMISSIONS 3-10
3.6 PARTICLE SIZE DISTRIBUTION 3-10
3.6.1 Literature Search 3-10
3.6.2 Literature Evaluation 3-12
3.6.3 Data Quality Ranking 3-12
REFERENCES 3-16
CHAPTER 4. EMISSION FACTOR DEVELOPMENT 4-1
4.1 CRITERIA POLLUTANTS 4-1
4.1.1 Review of Previous Data 4-1
4.1.2 Pulverized Coal Dry Bottom
Em ission Factors 4-3
4.1.3 Cyclone Emission Factors 4-4
4.1.4 Spreader Stoker and Other
Stoker Emission Factors 4-5
4.1.5 Review of New Baseline and
Controlled Data 4-7
4.1.6 North Dakota Department of
Health Data 4-8
4.1.7 Texas Air Control Board 4-9
4.1.8 Compilation of Baseline
Em ission Factors 4-10
4.1.9 Compilation of Controlled
Em ission Factors 4-11
4.2 NITROUS OXIDE 4-12
4.3 HAZARDOUS AIR POLLUTANTS 4-12
4.3.1 Review of New Data 4-12
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4.3.2 Baseline Emission Factors 4-14
TABLE OF CONTENTS (continued)
4.3.3 Controlled Emission Factors 4-17
4.4 PARTICULATE SIZE DISTRIBUTION 4-17
4.4.1 Review of Previous AP-42 Data 4-17
4.4.2 Review of New Data 4-17
4.4.3 Compilation of Uncontrolled
Em ission Factors 4-18
4.4.4 Control Technology Emission
Factors 4-18
REFERENCES 4-41
CHAPTERS. AP-42 SECTION 1.7: LIGNITE COMBUSTION 5-1
APPENDIXA. CONVERSION FACTORS A-1
APPENDIX B. MARKED-UP 1986 AP-42 SECTION 1.7 B-1
VI
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LIST OF TABLES
Table
2-1 Lignite-Fired Boilers in the North
Dakota Region 2-17
2-2 Lignite-Fired Boilers in the Gulf Region 2-18
3-1 Evaluation of References 3-15
4-1 Baseline Sulfur Oxides Emission Data 4-21
4-2 Summary Baseline NOX and CO Emissions
Data for Pulverized Lignite Units 4-22
4-3 Summary Baseline PM Emission Data for
Pulverized Lignite Units 4-22
4-4 Summary Baseline NOX Emissions Data for
Cyclone-Fired Units 4-23
4-5 Summary Baseline PM Emission Data for
Cyclone-Fired Units 4-23
4-6 Summary Baseline NOX Emissions Data
for Spreader Stoker Units 4-23
4-7 Summary Baseline PM Emissions Data for
Spreader Stoker Units 4-24
4-8 Summary Baseline PM Emissions Data for
Other Stoker Units 4-24
4-9 Atmospheric Fluidized Bed Baseline
NOX, SOX, and CO Emissions Data 4-25
4-10 Controlled NOX, SOX, and CO
Em issions Data 4-26
4-11 Atmospheric Fluidized Bed Units
Controlled SOX Emissions Data 4-28
4-12 Controlled PM Emissions Data 4-29
4-13 Atmospheric Fluidized Bed Units
VII
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Controlled PM Emissions Data 4-31
4-14 Controlled Organic Emissions Data 4-32
4-15 N20 Emission Factors for External
Combustion of Lignite 4-33
4-16 Metal Enrichment Behaviors 4-33
4-17 Enrichment Ratios for Classes of Elements 4-34
4-18 Fly Ash Enrichment Ratios for a Boiler
and Control Device 4-35
4-19 Trace Metal Emission Factors (Metric Units)
for Uncontrolled Lignite-Fired Boilers 4-36
4-20 Trace Metal Emission Factors (English Units)
for Uncontrolled Lignite-Fired Boilers 4-37
4-21 HAP Emission Factors (Metric Units) for
Controlled Lignite-Fired Boilers 4-38
4-22 HAP Emission Factors (English Units) for
Controlled Lignite-Fired Boilers 4-39
LIST OF TABLES (continued)
Table Page
4-23 Filterable Particulate for Lignite-Fired
Fluidized Bed Combustors with
Multiclone Controls 4-40
VIM
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LIST OF FIGURES
Figure
2-1. Lignite-bearing strata of the Gulf
Coast Region 2-19
2-2. Burner arrangements for pulverized fuel-
firing in a utility boiler 2-20
2-3. Schematic of cyclone firing of lignite
in a utility boiler 2-21
2-4. Schematic of stoker-firing in a boiler 2-22
2-5. Bubbling FBC schematic 2-23
2-6. Circulating FBC schematic 2-24
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 1970.
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. 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 needs of
State and local air pollution control programs, industry, and the Agency itself. Section
1.7 in AP-42, the subject of this Emission Factor Documentation (EFD) report, pertains
to lignite combustion in stationary, external equipment.
The last comprehensive update of AP-42 Section 1.7 was in 1982, focusing on
uncontrolled, baseline, emission factors for the criteria pollutants. The section was
appended in 1986 with data on particle sizing distributions. The purpose of the present
effort on AP-42 Section 1.7 is to update the data base for the earlier revisions and to
extend the scope to other pollutant species and revised equipment classifications.
Specifically, the scope of the current update includes the following activities:
! Updating of emission factors for criteria pollutants for baseline,
uncontrolled operation using data generated since the 1982
revision;
! Inclusion of several non-criteria emission species for which data
are available: organics speciation, air toxics, and greenhouse or
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ozone depletion gases [such as nitrous oxide (N20), and carbon
dioxide (C02)];
! Revise and expand emission source classifications to include
fluidized bed combustion and to separate wall-fired boilers from
tangentially-fired boilers; and
! Expand and update technical discussion and control efficiency data
for boiler operation with nitrogen oxides (NOX), carbon monoxide
(CO), or particulate matter (PM) control.
The update began with a review of the existing version of Section 1.7 (last
revised by Supplement A, published in October 1986). Spot checks were made on the
quality of existing emission factors by selecting primary data references from the
Section 1.7 Background File and recalculating emission factors.
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). The data points
obtained from test reports receiving sufficiently high quality ratings were then combined
with existing data, wherever possible, and used to produce new emission factors.
In this revision, several new emission factors for non-criteria pollutants have
been added. These new emission factors pertain to speciated volatile organic
compounds (VOCs), hazardous air pollutants (HAPs), N20, C02, and fugitive
emissions. Additionally, in this revision, the information on control technologies for PM,
sulfur oxides (SOX), and NOX emissions has been updated.
The purpose of this EFD is to provide background information and to document
the procedures used for the revision, update, and development of emission factors for
lignite combustion. Data from two state air pollution control agencies were used to add
controlled emission factors for lignite-fired boilers. Emission factors were also
developed for fluidized bed combustion as a new boiler configuration category.
Because of a lack of new baseline emissions data, the existing data contained in
the Background File for the 1986 Section 1.7 were identified as the best baseline data
available for this update. These data were reviewed and the low quality data were
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purged from the section. The remaining data of higher quality were used as the basis
of the revised baseline criteria pollutant emission factors. In addition, data contained in
the Background File that had not been included in the 1986 section were used to revise
emission factors (since these data were of higher quality than any new data collected
as a result of data search efforts in 1992). The baseline emission factors were
recalculated using different calculation procedures than those used for the previous
section. These revised calculation procedures allowed for more accurate comparison
of emission test data. Using these same calculation procedures, the new controlled
emissions data obtained from the North Dakota Department of Health and the Texas Air
Control Board were used to generate controlled emission factors.
Including this Introduction (Chapter 1), this EFD contains five chapters. Chapter
2 provides an overall characterization of lignite combustion, a description of lignite
usage in both the North Dakota and the Texas regions, and source/control descriptions.
Chapter 3 gives a review of the emissions data collection and review procedures. The
sources examined during the literature search are discussed. The data quality and
emission factor rating procedures are also discussed in this section. Chapter 4 details
the emission factor development procedures. It includes the review of specific data and
details of emission factor compilations. Chapter 5 presents the revised AP-42 Section
1.7. Appendix A provides sample calculations for emission factor development. A
marked-up copy of the 1986 Section 1.7, showing areas of revision, is included in
Appendix B.
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2. SOURCE DESCRIPTION
The two geographical areas of the United States with extensive lignite deposits
are centered around the states of North Dakota and Texas. Lignite combustion occurs
almost exclusively in these two regions. The typical uses of lignite combustion will be
discussed for each of these regions. A process description for each lignite combustion
source category is provided; the pollutants generated from lignite combustion are also
discussed. Finally, the pollution controls used to abate emissions generated from
lignite combustion are described.
2.1 CHARACTERIZATION OF LIGNITE APPLICATIONS1'5
Lignite is a relatively young coal with properties intermediate to those of
bituminous coal and peat. The two geographical areas of the United States with
extensive lignite deposits are centered around the states of North Dakota and Texas.
Lignite in both areas has a high moisture content (30 to 40 weight percent) and a low
wet-basis heating value [1400 to 1900 kcal/kg (2500 to 3400 Btu/lb)]. Consequently,
lignite is burned only near where it is mined because effective transportation costs for
low heating value fuels are prohibitive. A small amount is used for industrial and
domestic combustion. Lignite is mainly used for steam/electric production in power
plants. Lignite combustion was initially limited to small stokers, but the technology has
advanced to the current practice of firing in large cyclone and pulverized coal boilers.
The major advantages of lignite are that, in these two localized areas, it is
plentiful and low in sulfur content. The disadvantages are that more fuel and larger
facilities are necessary to generate a unit of power than is the case with bituminous
coal. There are several reasons for: (1) the higher moisture content means that more
energy is lost in heating the moisture to combustion temperatures, which reduces boiler
efficiency; (2) more energy is required to grind lignite to specified size limits, especially
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in pulverized coal-fired units; (3) greater tube spacing and additional soot blowing are
required because of lignite's higher ash fouling tendencies; and (4) because of its lower
heating value, more lignite must be handled to produce a given amount of power.
Lignite usually is not cleaned or dried before combustion (except for some incidental
drying in the crusher or pulverizer and during transfer to the burner). No major
problems exist with the handling or combustion of lignite when its unique characteristics
are taken into account.
2.1.1 North Dakota Region5
The North Dakota region has the largest lignite reserves in the world. The lignite
deposits of this region are contained in North Dakota, South Dakota, Montana, and
adjacent portions of Canada. The state of North Dakota has identified lignite resources
of approximately 350 billion tons. Overall, the North Dakota region has identified lignite
resources of 465 billion tons. Only a fraction of the identified resources are
demonstrated as economically recoverable lignite reserves.
Most of the lignite-fired combustion sources in the region are located in the State
of North Dakota. Minnesota and South Dakota also have large lignite-fired stations. As
shown in Table 2-1 the state of North Dakota has 15 lignite-fired utility boilers.6 The
firing capacity of the newer boilers is generally much larger than that for the older units.
Six of the newer boilers in the State have capacities greater than 400 MW (unless
otherwise indicated, MW refers to megawatts of electrical output in this report). Many of
the smaller stoker-fired utility boilers have been retired since the 1982 update of AP-42
Section 1.7. The largest spreader stoker in the State was converted to a circulating
fluidized bed boiler in 1987.
The small lignite-fired stokers are used for on-site power generation, space
heating, and process heat. The North Dakota Department of Health had 8 spreader
stokers and 5 other stokers (underfeed and overfeed units) under permit in 1980 at
commercial/institutional facilities.7 The Department also had 5 spreader stokers under
permit in 1980 for industrial facilities.7 The number of small lignite-fired stoker units
seems to be on the decline, however. There are probably less than 50
commercial/institutional and industrial lignite-fired boilers in the entire U.S.
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2.1.2 Gulf Region5
The Gulf lignite region covers portions of five States including Alabama,
Mississippi, eastern and southeastern Arkansas, northern Louisiana, and southeastern
Texas. Figure 2-1 shows the lignite belt in these states. The Gulf region has 68 billion
tons of identified lignite resources. Texas has approximately 52 billion tons of identified
lignite resources. In Texas, the lignite belt runs parallel to the Gulf Coast approximately
150 miles inland from the coast. All of the major lignite-fired power plants in Texas are
located on the lignite belt.
Table 2-2 is a partial listing of boilers located in the Gulf region. There are eight
power generation facilities with lignite- fired utility boilers, including a facility in
Louisiana. One older industrial lignite-fired boiler is operating in Texas. No small
commercial or institutional boilers fired on lignite were identified in Texas during this
update.
2.2 PROCESS DESCRIPTION3
In a pulverized fuel steam generator, the fuel is fed from the stock pile into
bunkers adjacent to the steam boiler. From the bunkers, the fuel is metered into
several pulverizers which grind it to approximately 200 mesh particle size. A stream of
hot air from the air preheater begins the fuel-drying process and conveys the fuel
pneumatically to the burner nozzle where it is injected into the burner zone of the boiler.
Three burner arrangements are used for firing pulverized lignite in existing steam
generators:
! Tangential firing,
! Horizontally-opposed burners,
! Front wall burners.
These arrangements are shown schematically in Figure 2-2.
In the tangential method of firing pulverized coal into the burner zone, the
pulverized coal is introduced from the corners of the boiler in vertical rows of burner
nozzles. Such a firing mechanism produces a vortexing flame pattern which essentially
uses the entire furnace enclosure as a burner.
Other manufacturers have developed both front-wall firing and horizontally-
opposed firing boilers. In these firing mechanisms, the pulverized coal is introduced
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into the burner zone through a horizontal row of burners. For furnaces less than about
200 MW, the burners are usually located on only one wall (i.e., front wall firing). For
larger boilers, the burners are located on the front and back walls firing directly opposed
to each other (i.e., horizontally opposed burners). This type of firing mechanism
produces a more intense combustion pattern than the tangential firing and has a slightly
higher heat release rate in the burner zone itself.
In all of these methods for firing pulverized fuel, the ash is removed from the
furnace both as fly ash and bottom ash. The bottom of the furnace is often
characterized as either wet or dry, depending on whether the ash is removed as a liquid
slag or as a solid. Pulverized coal units have been designed for both wet and dry
bottoms, but the current practice is to design only dry bottom furnaces. The wet bottom
furnace requires higher temperatures [usually > 1,430 °C (> 2,600 °F)] in order to melt
the ash before it is removed from the furnace. This is important to NOX control since
higher temperatures result in higher NOX emissions from thermal fixation (see Section
2.3.2 for discussion of thermal NOX formation).
2.2.1 Cyclone Firing
The cyclone burner is a slag-lined high-temperature vortex burner. The coal is
fed from the storage area to a crusher that crushes the coal (or lignite) into particles of
approximately 6 mm (0.25 inch) in diameter or less. Crushed lignite is partially dried in
the crusher and is then fired in a tangential or vortex pattern into the cyclone burner.
The burner itself is shown schematically in Figure 2-3. The temperature within the
burner is hot enough to melt the ash to form a slag. Centrifugal force from the vortex
flow forces the melted slag to the outside of the burner where it coats the burner walls
with a thin layer of slag. As the solid lignite particles are fed into the burner, they are
forced to the outside of the burner and are imbedded in the slag layer. The solid lignite
particles are trapped there until complete burnout is attained.
The ash from the burner is continuously removed through a slag tap which is
flush with the furnace floor. Such a system ensures that the burner has a sufficient
thickness of slag coating on the burner walls at all times.
One of the disadvantages of cyclone-firing is that in order to maintain the ash in
a slagging (liquid) state, the burner temperature must be maintained at a relatively high
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level. This higher temperature promotes NOX fixation. Unfortunately, this cannot be
offset via the reduction of available oxygen without employing an auxiliary fuel to
maintain stability. Tests on cyclone burners firing lignite alone have shown that the
burner cannot be satisfactorily operated at substoichiometric air conditions because of
flame stability problems (i.e., the fire goes out at air addition rates less than the
theoretical requirements).
2.2.2 Stoker Firing
In a stoker-firing furnace, shown schematically in Figure 2-4, the lignite is spread
across a grate to form a bed which burns until the lignite is completely burned out. In
such a mechanism, the lignite is broken up into approximately 5-cm (2-inch) pieces and
is fed into the furnace by one of several feed mechanisms: underfeed, overfeed, or
spreading. The type of feed mechanism used has little effect on NOX emissions.
The physical size of stoker-fired boilers is limited because of the structural
requirements and difficulties in obtaining uniform fuel and air distribution to the grate.
Most manufacturers of stoker-fired equipment limit their design to 30 MW.
In most stoker units, the grate on which the lignite is burned gradually moves
from one end of the furnace to the other. The lignite is spread on the grate in such a
fashion that at the end of the grate only ash remains (i.e., all of the lignite has been
burned to the final ash product). When the ash reaches the end of the grate, it falls into
an ash collection hopper and is removed from the furnace.
Stoker-fired furnaces are dry-bottom furnaces and, as such, generally have lower
heat release rates and lower temperature profiles than the corresponding pulverized
lignite or cyclone-fired units. Hence, stoker-fired units typically have lower NOX
emission rates than other lignite-burning equipment used for generating steam.
2.2.3 Fluidized Bed Combustion
There are two major categories of fluidized bed combustors (FBCs): (1)
atmospheric FBCs, operating at or near ambient pressures, and (2) pressurized FBCs,
operating at from 4 to 30 atmospheres (60 to 450 psig). Pressurized FBC systems are
not considered a demonstrated technology for lignite combustion.
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
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these types is the fluidization velocity. In the bubbling bed design, the fluidization
velocity is relatively low, ranging between 16 and 39 meters/sec (5 and 12 ft/sec), in
order to minimize solids carryover or elutriation from the combustor. Circulating FBCs,
however, employ fluidization velocities as high as 9 meters/sec (30 ft/sec) 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 unburned solid fuel and
bed material for return to the primary combustion chamber for more efficient fuel
utilization.
Fluidized bed combustion is a boiler design which can lower sulfur dioxide (S02) 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. Captured S02 is retained as a solid sulfate and is either purged
from the bed or 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.
2.3 EMISSIONS
The emissions generated from lignite combustion include the criteria pollutants
PM, NOX, SOX, total organic compounds (TOC), and CO. The non-criteria pollutants
generated from lignite combustion include C02, N20, trace elements, fugitive emissions,
and PM with an aerodynamic diameter of less than 10 microns (PM-10).
2.3.1 Particulate Emissions
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 an EPA Method 5 or EPA Method 17 sampling train.
Particles less than 0.3 microns and vapor-phase elements 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
CPM emitted from lignite-fired boilers is primarily inorganic in nature. The PM-10 is a
portion of total PM and is of concern since particles smaller than 10 microns can easily
enter the lungs.
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Particulate emissions from lignite combustion are directly related to the ash
content of the lignite and firing configuration of the boiler. Cyclone furnaces emit less
PM because, in a wet bottom boiler, more of the incoming ash is retained in the slag.
Pulverized lignite units generate more fine PM because of the size of the fuel that is
fired.
2.3.2 NO. Emissions
The NOX 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"). Although five oxides of nitrogen
exist, the term NOX is customarily used to include the composite of nitric oxide (NO),
and nitrogen dioxide (N02). Nitrous oxide is of increasing interest as an upper
atmosphere gas, but is not included in NOx. Test data have shown that for most
stationary combustion systems, over 90 percent of the emitted NOX is typically in the
form of NO.
Thermal NOX formation rates in flames are exponentially dependent on
temperature; they are proportional to the molecular nitrogen (N2) concentration in the
flame, the square root of the molecular oxygen (02) concentration in the flame, and the
residence time.20 This is corroborated by experimental data which shows thermal NOx
formation is most strongly dependant on three factors: (1) peak temperature, (2) 02
concentration or stoichiometric ratio, and (3) time of exposure at peak temperature.
The emission trends due to changes in these factors are fairly consistent for all types of
boilers: an increase in flame temperature, 02 availability, and/or residence time at high
temperatures leads to an increase in NOX production (under oxidizing conditions),
regardless of the boiler type.
Fuel nitrogen conversion is the most important N0x-forming mechanism in lignite
lignite-fired boilers. It can account for approximately 80 percent of the total NOX
emissions in lignite firing. The percent conversion of fuel nitrogen to NOX, however,
varies greatly with the local stoichiometric ratio and the air/fuel mixing in the near-
burner flame zone.
A number of variables influence how much NOX is formed by these two
mechanisms. One important variable is the firing configuration. The NOX emissions
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from tangentially (or corner)-fired boilers are, on average, less than those of wall-fired
and cyclone units. Also important are the firing practices employed during boiler
operation. Low excess air (LEA) firing, staged combustion (SC), low NOX burners
(LNBs), or some combination thereof may result in NOX reductions of 10 to 60 percent.
Load reduction can likewise decrease NOX production.
The N20 emissions for most coal-fired boilers are only a small fraction of the NOX
levels. During this AP-42 Section 1.7 update, no N20 data for direct lignite-firing were
located, with the exception of FBC units.
2.3.3 SO. Emissions2
The SOX emissions from lignite combustion depend on the sulfur content of the
lignite and the lignite composition (viz., sulfur content, heating value, and alkali
concentration). The conversion of lignite sulfur to SOX is generally inversely
proportional to the concentration of alkali constituents in the lignite. The sodium oxide
content is believed to have the greatest effect on sulfur conversion because the natural
sodium content in ash acts as a built-in sorbent for SOX removal.
2.3.4 Carbon Monoxide Emissions16'19
The CO emission rate 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 do larger combustors. This is because smaller units usually have a
higher ratio of heat transfer surface area to flame volume, leading to reduced flame
temperature and combustion intensity and, therefore, lower combustion efficiency than
large combustors. Larger combustors also have more complex combustion control
systems to trim oxygen to a level which gives low CO and high combustion efficiency.
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 02 availability;
! Extremely high levels of excess air (which leads to quenching);
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! Poor fuel/air mixing;
! Cold-wall flame quenching;
! Reduced combustion temperature;
! Decreased combustion gas residence time; and
! Load reduction (i.e., reduced combustion intensity).
Since various combustion modifications for NOX 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 Total Organic Compounds
Small amounts of TOCs are emitted from lignite combustion. These TOCs
include VOCs, semi-volatile organic compounds, and condensible organic compounds.
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
benzenes (e.g., benzene, toluene, xylene, ethyl benzene, etc.).30'31
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 the 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.
Formaldehyde is formed and emitted during combustion of hydrocarbon-based
fuels including lignite. 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
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relatively long retention times generally 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 lignite. For this update
of AP-42, trace metals included in the list of 189 hazardous air pollutants under Title III
of the 1990 Clean Air Act Amendments (CAAA-90) are considered.36 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 itself.
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.37 Various classification schemes to describe this
partitioning have been developed.38"40 The classification scheme used by Baig, et al. is
as follows:35
! Class 1: Elements which are approximately equally distributed between
fly ash and bottom ash, or show little or no small particle enrichment;
! 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.37 For example, several NOx controls for boilers reduce peak flame
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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 02 concentrations are also expected to affect segregating metal
emissions from boilers with particle controls. Lowered 02 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 02 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 02 concentrations.
2.4 CONTROL TECHNOLOGIES
This section discusses the different emission controls used on lignite-fired
boilers. The PM, NOX and SOX controls will be discussed in this section.
2.4.1 Particulate
The primary PM control systems for large industrial and utility boilers are
electrostatic precipitators (ESPs) and fabric filters (or baghouses). Multiple cyclones
and scrubbers are used for PM control mainly on small industrial stokers, either alone
or in series with an ESP or baghouse. Filterable particulate emissions can be efficiently
controlled by all four of these methods. Cyclones, ESPs, and fabric filters have little
effect on measured CPM because they are generally operated at temperatures above
the upper limit of the front-half of EPA Method 5 [i.e., 135 °C (275 °F)]. Thus, most
CPM would remain vaporized and pass through the control device. Wet scrubbers,
however, reduce the gas stream temperature; as a result, they could theoretically
remove some of the CPM.
2-xxiii
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The operating parameters that influence ESP performance include:19
! Fly ash mass loading,
! Particle size distribution,
! Fly ash electrical resistivity, and
! Precipitator voltage and current.
The larger ESPs built since the mid 1970s can achieve control efficiencies of 99.5 or
better percent for total PM.11
The PM removal efficiency of fabric filters is dependent on a variety of particle
and operational characteristics.20"21 Particle characteristics that effect the collection
efficiency include particle size distribution and particle cohesion characteristics.
Operational parameters that effect fabric filter collection efficiency include:
! Air-to-cloth ratio,
! Operating pressure loss,
! Cleaning sequence,
! Interval between cleaning,
! Cleaning method, and
! Cleaning intensity.
In addition, fabric properties that affect the particle collection efficiency and size
distribution include:
! Structure of fabric,
! Fiber composition, and
! Bag properties.
Baghouses are typically categorized by one of three cleaning methods: (1)
mechanical or shake/deflate cleaned baghouses, (2) reverse gas cleaned baghouses,
and (3) pulsed-jet cleaned baghouses. Baghouses can achieve collection efficiencies
of 99.7 percent or better for total particulate matter.12
2.4.2 NO. Control
Combustion modifications, such as LEA-firing, flue gas recirculation (FGR), SC,
and reduced load operation, are primarily used to control NOX emissions in large coal-
fired facilities.
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The formation of thermal NOX occurs in part through the Zeldovich mechanism:
(2-1) N2 + 0 —NO + N
(2-2) N + 02~NO + 0
(2-3) N + OH —NO + H
Reaction (2-1) is the rate-determining step due to its large activation energy.13
Kinetically, thermal NOX formation is related to N2 concentration, combustion
temperature, and 02 concentration by the following equation:13
(2-4) [NO] = k, exp(-k2/T) [N2] [02]1'21
where:
[ ] = mole fraction
T = temperature (°K)
t = residence time
k.,, k2 = reaction rate coefficient constants
From these considerations, it can be seen that thermal NOX formation can be
controlled by four approaches: (1) reduction of peak temperature of reaction, (2)
reduction of N2 concentration, (3) reduction of 02 level, and (4) reduction of the
residence time of exposure at peak temperature. Combustion modification techniques
to control thermal NOX in boilers have focused on reducing the 02 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 02 concentration, and linearly on
residence time. Therefore, initial efforts to control NOX emissions have often focused
on methods to reduce peak flame temperatures.
In coal-fired boilers, 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.14"16 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.17 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
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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 N0x-formation mechanisms are different, both thermal and fuel NOX are promoted
by rapid mixing of fuel and combustion air. Thus, primary combustion modification
controls for both thermal and fuel NOX typically rely on the following control approaches:
! Decrease residence time at high temperatures (under oxidizing
conditions):
Decrease adiabatic flame temperature through dilution,
Decrease combustion intensity,
Increase flame cooling,
Decrease primary flame zone residence time;
! Decrease primary flame-zone 02 level:
Decrease overall 02 level,
Control (delayed) mixing of fuel and air,
Use of fuel-rich primary flame zone.
The most prevalent NOX control for lignite-fired boilers is overfire air using
dedicated air ports, or by taking a top row of burners out of service and adjusting air
flow to the furnace. Control of NOX via LEA combustion can significantly increase the
ash fouling potential in the boiler.18 Creating overfire air conditions in one tangentially-
fired unit by removing the top three burners from service and adjusting the dampers did
not increase the ash fouling potential.18
No post-combustion, ammonia-based NOX controls have been used with lignite
combustors due to the lack of regulatory requirements.
2.4.3 S(X Control
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Several techniques are used to reduce SOX from lignite combustion. Flue gases
can be treated through wet, semi-dry, or dry desulfurization processes of either the
throwaway type (in which all waste streams are discarded) or the recovery
(regenerable) type (in which the SOX absorbent is regenerated and reused). 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 in excess of 90 percent
of the incoming SOX. Lime/limestone scrubbers, sodium scrubbers, spray drying, and
dual alkali scrubbing are among the commercially proven flue gas desulfurization
techniques. Limestone may also be injected directly into the furnace section of boilers
to capture S02 shortly after formation. Effectiveness of these devices depends not only
on the control device design but also on operating variables, such as liquid-to-gas ratio
and sorbent reactivity.
Sodium scrubbing processes generally employ a wet scrubbing solution of
sodium hydroxide (NaOH) or sodium carbonate (Na2C03) to absorb S02 from the flue
gas. 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 S02
removal followed by a regeneration step using lime or limestone to recover the sodium
alkali and produce a calcium sulfite and sulfate sludge. The S02 is removed from the
flue gas as in sodium scrubbing. Most of the scrubber effluent 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.
The lime and limestone process uses a slurry of calcium oxide (CaO) or
limestone (CaC03) to absorb S02 in a wet scrubber. The process produces a calcium
sulfite and calcium sulfate mixture. Calcium sulfite and calcium sulfate crystals
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precipitate in a hold tank. The hold tank effluent is recycled to the scrubber to absorb
additional S02. 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.
Spray drying is a dry scrubbing approach to flue gas desulfurization. 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
S02 reacts with the alkali solution or slurry to form liquid-phase salts. The slurry is dried
by the latent heat of the flue gas to about one percent free moisture. The dried alkali
continues to react with S02 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 particulate
control device such as an ESP or baghouse. Systems using a baghouse for PM
removal report additional S02 sorption occurring across the baghouse. Gas exit
temperatures are typically in the 65 to 93 °C (150 to 200 °F) range which provides a
safe margin against water condensation.
Limestone may also be injected into the furnace, typically in an FBC, to react
with S02 and form calcium sulfate. An FBC is comprised of a bed of inert material that
is suspended or "fluidized" by a stream of air. Lignite is injected into this bed and
burned. Limestone is also injected into this bed where it is calcined to lime and reacts
with S02 to form calcium sulfate. Bed temperatures are typically maintained between
760 and 870 °C (1,400 and 1,600 °F). Particulate matter emitted from the boiler is
generally captured in a cyclone and recirculated or sent to disposal. Additional PM
control equipment, such as an ESP or baghouse, is used after the cyclone to further
reduce particulate emissions.
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TABLE 2-1. LIGNITE-FIRED BOILERS IN THE NORTH DAKOTA REGION3
Company
Basin Electric Power Coop.
Basin Electric Power Coop.
Basin Electric Power Coop.
Basin Electric Power Coop.
Basin Electric Power Coop.
Basin Electric Power Coop.
Montana Dakota Utilities
Montana Dakota Utilities
Montana Dakota Utilities
Minnkota Power Coop.
Minnkota Power Coop.
United Power Association
United Power Association
United Power Association
United Power Association
Otter Tail Power Company
Otter Tail Power Company
Plant
Antelope Valley
Station Unit #1
Antelope Valley
Station Unit #2
LelandOlds#1
Leland Olds #2
W.J. Neal #1
W.J. Neal #2
Coyote
Heskett #1
Heskett #2
Milton R. Young #1
Milton R. Young #2
Coal Creek #1
Coal Creek #2
Stanton #1
Stanton #2
Big Stone
(South Dakota)
Hoot Lake
(Minnesota)
Firing
configuration
Pulverized Coal
Tangential
Pulverized Coal
Tangential
Pulverized Coal
Horizontally
Opposed
Cyclone
Pulverized Coal
Front Wall
Pulverized Coal
Front Wall
Cyclone
Spreader
Stoker
Fluidized Bed
Cyclone
Cyclone
Pulverized Coal
Tangential
Pulverized Coal
Tangential
Pulverized Coal
Front Wall
Pulverized Coal
Tangential
Cyclone
Pulverized Coal
Tangential
Capacity,
MW
440
440
216
440
25
25
440
25
66
240
440
500
500
130
60
440
59
Year in
service13
1984
1986
1966
1975
1953
1953
1981
1963
1987
1970
1976
1978
1979
1966
After 1978
1975
1959
References 2-3, 6.
bThe year in sevice is an estimate.
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TABLE 2-2. LIGNITE-FIRED BOILERS IN THE GULF REGION5
Company
Texas Utilities
Texas Utilities
Texas Utilities
Southwestern Electric
Power Co.
Southwestern Electric
Power Co.
Houston Lighting &
Power
South Texas Electric
Coop.
Texas New Mexico
Power Co.
Alcoa
Plant
Martin Lake
#1,#2,#3,#4
Monticello
#1,#2,#3,#4
Big Brown #1 ,
#2
H.W. Pirkey#1
Dolet Hills
(Louisiana)
Limestone #1 ,
#2
San Miguel #1
Calve rt
#1,#2
Sandow 1, 2,
&3
Firing configuration
Pulverized Coal
Tangential
Pulverized Coal
Horizontally Opposed
Pulverized Coal
Tangential
Pulverized Coal
Horizontally Opposed
Pulverized Coal
Pulverized Coal
Tangential
Pulverized Coal
Horizontally Opposed
Circulating Fluidized
Bed
Wet Bottom
Tangential, Dried Lignite
Capacity,
MW
750
750
5QO
720
720
800
400
150
100
Year in
service13
1977, 1978
1979, 1980
1975, 1976
1979
Late 60's
1984
1986
1986,
1987
1979
1990, 1991
1953
"References 3, 9.
bThe year in service is an estimate.
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Figure 2-1. Lignite-bearing strata of the Gulf Coast Region.5
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Figure 2-2. Burner arrangements for pulverized fuel-firing in a utility boiler (viewed from above)/
-------
Figure 2-3. Schematic of cyclone-firing of lignite in a utiity boiler.1
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Figure 2-4. Schematic of stoker-firing in a boiler.
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Figure 2-5. Bubbling FBC schematic.10
2-xxxix
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Figure 2-6. Circulating FBC schematic.10
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REFERENCES FOR CHAPTER 2
1. Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition, Volume 12,
John Wiley and Sons, New York, NY, 1967.
2. Gronhovd, G.H., et al., "Some Studies on Stack Emissions from Lignite Fired
Powerplants", Presented at the 1973 Lignite Symposium, Grand Forks, ND, May
1973.
3. Standards Support and Environmental Impact Statement: Promulgated
Standards of Performance for Lignite Fired Steam Generators: Volumes I and
H, EPA-450/2-76-030a and 030b, U.S. Environmental Protection Agency,
Research Triangle Park, NC, December 1976.
4. 1965 Keystone Coal Buyers Manual. McGraw-Hill, Inc., New York, NY, 1965.
5. Low-Rank Coal Study: National Needs For Resource Development:
Volume 2 - Resource Characterization, Prepared for Department of
Energy, Energy Resources Co. Inc., Walnut Creek, CA, November 1980.
6. Source test data on lignite fired power plants, North Dakota State Department of
Health, Bismarck, ND, April 1992.
7. Personal communication dated September 18, 1981. Letter from North Dakota
Department of Health to Mr. Bill Lamason of the U.S. Environmental Protection
Agency, Research Triangle Park, NC conveying stoker data package.
8. White, D.M. et al., "Status of Gulf Coast Lignite Activity", Proceedings of the
Eleventh Biennial Lignite Symposium, Grand Forks, ND, June 1981.
9. Source test data on lignite fired power plants, Texas Air Control Board, Austin
TX, April 1992.
10. Gaglia, B.N. and A. Hall, "Comparison of Bubbling and Circulating Fluidized Bed
Industrial Steam Generation", Proceedings of 1987 International Fluidized Bed
Industrial Steam Conference, ASME, New York, 1987.
11. Cooper, et al., Air Pollution Control: A Design Approach, PWS Engineering,
Boston MS, 1986.
12. References.
13. Lim. K.J.. et al.. Industrial Boiler Combustion Modification NO. Controls - Volume
I Environmental Assessment, EPA-600/7-81-003c, U.S. Environmental
Protection Agency, Research Triangle Park, NC, April 1981.
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14. Pershing, D.W., et al.. Influence of Design Variables on the Production of
Thermal and Fuel NO from Residual Oil and Coal Combustion, Air: Control of
NOX and SOX Emissions, New York, American Institute of Chemical Engineers,
1975.
15. Pohl, J.H. and A.F. Sarofim, Devolatilization and Oxidation of Coal Nitrogen
(presented at the 16th International Symposium on Combustion), August 1976.
16. 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.
17. Pershing, D.W., Nitrogen Oxide Formation in Pulverized Coal Flames, Ph.D.
Dissertation, University of Arizona, 1976.
18. Honea, et al., "The Effects of Overfire Air and Low Excess Air on NOX Emissions
and Ash Fouling Potential for a Lignite-fired Boiler", Proceedings of the American
Power Conference, Volume 40, 1978.
19. "Precipitator Performance Estimation Procedure", prepared by Southern
Research Institute, EPRI CS-5040, February 1987.
20. Miller, S.J. and D. L. Laudal, Particulate Characterization. DOE/FE/60181-
2089, June 1986.
21. Dennis, S. and D. Bubenick, Apparent Fractional Efficiencies for Duct
Collectors, Part 1 - Fabric Filters, Filtration and Separation, March/April
1983, pp. 143-146.
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3. GENERAL EMISSIONS DATA REVIEW AND ANALYSIS PROCEDURES
This section summarizes the procedures for the literature search and the criteria
for evaluating the data which were identified. The results of the search and conclusions
regarding the usefulness of the data obtained for developing emission factors are also
presented. The data and emission factor rating and review criteria are also contained
in this chapter.
3.1 CRITERIA POLLUTANTS
3.1.1 Literature Search
An extensive literature search was conducted to identify sources of criteria and
non-criteria emissions data for lignite combustion. The following sources were
searched for emissions data:
! Existing AP-42 Background files,
! Files maintained by the EPA's Emission Standards Division and Emission
Factor and Methodologies Section,
! PM-10 background documents,
! New Source Performance Standards Background Information Documents,
! National Technical Information Service (NTIS) holdings,
! Various EPA emissions assessment documents for coal combustion,
! Contractor in-house files,
! U.S. Department of Energy (DOE) Clean Coal Project Documents,
! NOX, SOX, and Particulate Control Symposia,
! Lignite and Low Rank Coal Symposia,
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! Proceedings of the American Power Conference,
! Information from boiler manufacturers,
! Proceedings of the International Conference on Fluidized Bed
Combustion,
! Electric Power Research Institute (EPRI) reports and communications.
The main conclusion from the literature search was that the data base on lignite
emissions and control is relatively sparse compared to higher rank coals or oil. Some
articles on lignite combustion were found in the Proceedings of the American Power
Conference, Proceedings of the International Conference on Fluidized Bed
Combustion, Lignite Symposia, and the Low Rank Coal Symposia. Most of the articles
did not contain emissions data but some of these articles supplied specific plant
operational and design data. The lignite symposia, and the conferences on fluidized
bed combustion did contain emissions data for a pilot-scale fluidized bed unit which
were not used since emissions data for the full-scale units were available. The
Reference 1 article was useful for characterizing emissions control techniques.
However, the emissions data in the article were not used because a large amount of
primary data were available for the specific plant tested. The article offered data and
discussion on the effect of NOX control on slagging in a boiler firing North Dakota
lignites. Another useful report was a DOE study (Reference 2). This report offers a
large amount of lignite proximate/ultimate analysis data and discusses the lignite
resources in the U.S.
The information contained in the AP-42 Background File was reviewed. From
this, it was concluded that the most promising source of new emissions data for lignite
combustion would be the air pollution control agencies in the EPA Regions where
lignite combustion is prevalent. The North Dakota Department of Health and the Texas
Air Control Board were both contacted as a result.
The North Dakota Department of Health had supplied emissions data for the
previous updates, and agreed to supply emissions data for this update. The
Department has collected a large amount of data since the last complete update of
Section 1.7 in 1982. The continuous emission monitoring (CEM) equipment at each of
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the seven largest lignite-fired utility boilers in North Dakota are re-certified by the
Department every three years using relative accuracy testing. The older utility boilers
are only required to monitor opacity, and consequently fewer emissions data are
available for these plants. The smaller stoker units generally have only PM emissions
data available.
The Texas Air Control Board (TACB) also agreed to supply emission data for this
update of Section 1.7. The TACB has a main office in Austin and 12 regional offices.
Following the lignite belt and using a map identifying TACB regions, the two regions
with the majority of lignite combustors were determined to be Regions 3 and 12. The
emissions data available from the TACB are NSPS performance testing and CEM
recertification testing.
The regional offices were expected to have a considerable amount of emissions
data available for each lignite-fired power plant. Due to the time constraints of this
update, however, and the limited staff resources available at both of these air pollution
agencies, only a limited amount of the emissions data available could be obtained. In
future, the best way to obtain the data would be to go directly to the North Dakota
Department of Health offices and the main and regional offices of the TACB to search
and find the available emissions data.
3.1.2 Literature Evaluation3
To establish a final group of references for use in the updated section, the
following general criteria were used:
! Emissions data must be from a well documented reference;
! The referenced study must contain results based on more than one test
run; and
! The report must contain sufficient data to evaluate the testing procedures
and source operating conditions.
By 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 standardize and document this evaluation. The completed checklists were
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placed in the background files for this update to Section 1.7. Data with the following
characteristics were always 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. The series in which the source 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 Reference 3. 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.
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-magnitude 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 that such alternative procedures could
influence the test results.
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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
were 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.
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 - Average: 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.
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
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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 noted
where applicable.
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 lignite-fired boilers. Some
specific areas searched include Tennessee Valley Authority (TVA), EPRI/PISCES,
EPA/Air and Waste Management Association (A&WMA) Air Toxic Symposiums, and
Toxic Air Pollutants: State and Local Regulatory Strategies 1989. 3.2.2 Literature
Evaluation
Until recently, little concern existed for VOC speciation on stationary external
sources. Therefore, available data for VOC speciation were inadequate to develop
emission factors. Some qualitative information is available in the EPA Office of Air
Quality Planning and Standards (OAQPS) databases. The primary databases are the
VOC/PM Speciation Data System (SPECIATE) and the Crosswalk/Air Toxic Emission
Factor Database (XATEF), and their associated references. Some VOC speciation
data were also identified in the general HAPs data search.
3.3 Hazardous Air Pollutants
3.3.1 Literature Search
When possible, primary references were obtained in order to calculate or verify
emission factors presented. Many of the data evaluated were not of suitable quality for
developing emission factors and were, therefore, eliminated for use in this update.
A literature search was conducted using the Dialog Information Retrieval
Service. This is a broad-based data retrieval system that has access to over 400 data
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bases. Specifically for the air toxics search, six data bases were queried by key words
relating to the processes and chemicals of concern. The data bases accessed include:
NTIS, COMPENDEX PLUS, POLLUTION ABSTRACT, CONFERENCE PAPERS,
ENERGY SCIENCE & TECHNOLOGY, and EPRI. The list of literature generated from
the search was evaluated for applicability and the relevant documents were obtained.
Searches of the EPA's HAPs data bases were also performed. These data
bases include XATEF, SPECIATE, and the Air Chief CD ROM which contains additional
data. The computer searches were performed by source classification code (SCC) for
all boiler sizes and types that are fired on coal. The reference numbers were recorded
for each of the "hits" and these references were obtained for review.
Several industry and non-agency sources were also contacted in order to obtain
source test data for development of emission factors. Since few data were available for
lignite directly, data for coal combustion in general were compiled to obtain data for
related conditions.
3.3.2 Literature Evaluation for HAPs
The references obtained from the literature search were evaluated for their
applicability for generating emission factors. Table 3-1 summarizes the data sources
and indicates which sources were used in generating the emission factors. 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
Chapter 4, Section 4.3.1. The criteria used to perform this evaluation are discussed in
detail in Section 3.1.2.
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 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
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analytical methods and the operating and design specifications of the unit being tested
are key in the evaluation of data viability.
The EPA has prepared a document that specifies technical procedures for the
development of AP-42 emission factors and the preparation of supporting
documentation.3 See Section 3.1.2 for the description of the evaluation and rating
criteria.
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 the
device. General design parameters such as boiler size, firing configuration, fuel type,
operating parameters during the test, (e.g. load), are all required in order to evaluate
the quality of the data. Information on the type and number of samples, sampling and
analytical methods used, sampling locations, quality control samples and procedures,
modifications to methods, fuel composition and feed rates are also needed. Sufficient
documentation to determine how the data were reduced and how emissions estimates
were made are required. This documentation should include sample calculations,
assumptions, and correction factors. Equivalent information for the abatement
device(s) must also be included.
When primary data could not be obtained in the time frame of this update,
secondary sources were evaluated to determine the representativeness of the emission
factors for a source category. A judgement on the quality of the author's analysis of the
primary data was made in this case, which automatically warrants a lower quality rating
for the emission factor. The secondary sources provide at least an order of magnitude
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estimate of emissions and possibly better; however, this cannot be evaluated without
reviewing the primary data.
3.4 N20
3.4.1 Literature Search
An extensive literature search was conducted to identify sources of N20
emissions data associated with lignite-fired boilers. Some specific areas of search
included University of North Dakota, Air and Energy Engineering Research Laboratory
(AEERL), Combustion and Flame, Journal of Geophysical Research, International
Conferences of Fluidized Bed Combustion, and A&WMA.
3.4.2 Literature Evaluation
Because of the limited test reports for lignite, data from tests of other coal types
were also used. Because the data and emission factor quality rating criteria have been
available only since 1988, data with quality problems (e.g., lack of complete
documentation), were used in order to get, at a minimum, a semi-quantitative estimate.
Data obtained through the literature search, except that derived from on-line N20
analysis with gas chromatography/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 had been identified in using grab sampling
techniques for measuring N20 emissions. Storing combustion products in grab
samples containing S02, NOX and water for periods as short as 1 hour had led to
formation of several hundred parts per million of N20 where none originally existed.
Improved methodologies for N20 sampling and analysis and their relative effects on
data quality ratings are as follows:
1. On-line N20 analysis with GC/ECD (preferred method), and
2. Grab samples:
a. Removing H20 - drying the sample reduces the
most important reactant, but may not entirely
eliminate N20 formation,
b. Removing S02 - scrubbing the sample through
NaOH solution, or
c. A combination of the two (second preference).
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The N20 data for fluidized bed combustors were developed from test reports
using lignite and the data were assigned a quality rating of D. Because the data were
not recorded with an on-line N20 analysis GC/ECD and the facilities tested do not
represent a cross section of the industry; as a result, the emission factor received an E
rating.
3.5 FUGITIVE EMISSIONS
A literature search was conducted on fugitive emissions for coal-fired sources in
general. A literature evaluation and data rating was not conducted for lignite storage
and handling operations, because those fugitive emissions for lignite-fired boilers are
covered in sub-sections of Chapter 11. 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 PM emissions can sometimes occur during transfer operations from silos to
trucks or rail cars. The PM emission factors corresponding to these operations can be
developed using the procedures in Chapter 11.
3.6 PARTICLE SIZE DISTRIBUTION
3.6.1 Literature Search3
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 particulate and the organic and inorganic CPM. Upon review of the
previous AP-42 update of particulate sizing emission data, the largest gap appeared to
be the lack of CPM data.
The Background Files for AP-42 Section 1.7 were reviewed. A Dialog 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:
Reference 9: The factors applicable to sections 1.1, 1.3, and 1.7 all came from AP-42.
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Reference 10: Not applicable to stationary source combustion.
Reference 11: 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.
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); and
! 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
was not updated since the printouts obtained during the previous AP-42 update. The
printouts used for the previous update were available in the Background Files.
The EPA OAQPS Emissions Monitoring Branch was contacted for test data from
method development studies for EPA Method 202.
Contacts were also made with EPRI, Wheelabrator Air Pollution Control,
Southern Research Institute, and Entropy Environmental.
3.6.2 Literature Evaluation
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The previous AP-42 update was reviewed and evaluated.12 The size distribution
data was evaluated by spot-checking the tabulated results against the original FPEIS
printouts. If during the literature search, an original test report was uncovered that
corresponded to a particular FPEIS printout, the data were compared. The objective 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:
! To ensure that only filterable PM was included in the cumulative percent
mass results, and
! To 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 as described in Section 3.1.2 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 particulate sizing and filterable PM-10 data the following criteria were used:
! Particle sizing tests performed by cascade impactors or PM-10
measurements performed via EPA Method 201 or EPA Method 201 A.
The test information must provide enough detail for adequate validation
and the isokinetics must fall between 90 and 110 percent.
! Particle sizing tests performed via source assessment sampling system
(SASS) trains if the sampling flow-rate isokinetic value was reported and
sufficient operating data were used. Cascade impactor data or EPA
Method 201 or EPA Method 201A data were not used if isokinetics were
not reported or if isokinetics were not within the 90 to 110 percent range.
! SASS train data if the isokinetics were not reported or if the isokinetics did
not fall within the 90 to 110 percent range.
! Test results based on a generally unaccepted particulate sizing method,
such as polarized light microscopy.
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Although cascade impactors are generally considered the best available method
for measuring particulate size distributions, errors in segregating specific sizes of
combustion particles arise from the following:
! Particle bounce and re-entrainment,
! Diffusive deposition of fine particles,
! Deposition of condensible/adsorbable gases, and
! Losses to the impactor walls.
The effects of such errors are described in the literature.13
The ranking of CPM data was based primarily on the methodology. Most CPM
source tests have been conducted using the back-half of an EPA Method 5, EPA
Method 17, or South Coast Methods 5.2 or South Coast Method 5.3 trains. However,
these test methods do not require an N2 purge of the impingers. Without the N2 purge,
dissolved S02 remains in the impingers and is included in the inorganic CPM results.
This type of CPM data is considered very low-quality.14 In contrast, EPA Method 202
includes a one-hour N2 purge of the impingers immediately after sampling to remove
dissolved S02. Therefore, EPA Method 202 CPM data should be ranked higher than
EPA Method 5 or EPA Method 17 CPM data, even though EPA Method 202 is a
relatively new method. The following ratings were selected for CPM data:
A - CPM tests performed via EPA 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 EPA Method 202 but isokinetics not reported or
isokinetics not within the 90 to 110 percent range. CPM tests performed
via EPA Method 5 or EPA 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 EPA Method 5 or EPA 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.
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TABLE 3-1. EVALUATION OF REFERENCES
Reference
Evaluation summary
Parameter of interest
4
5
6
7
Not a primary reference; however, emission factors provided for
emission estimates.
Not a primary reference; however, data are of sufficient quality for
estimates.
Not a primary reference; however, data of sufficient quality for estimates.
Source test data of sufficient quality for calculate emission factors and
enrichment
ratios.
POM
Copper
Metals
PAH, metals, radionuclides
8
Emission factors of sufficient quality to perform emission estimates.
Manganese
-------
REFERENCES FOR CHAPTER 3
1. Honea, et al.. The Effects of Overfire Air and Low Excess Air on NOX
Emissions and Ash Fouling for a Lignite-fired Boiler, Proceedings of the
American Power Conference, Vol. 40, 1978.
2. Low-rank Coal Study: National Needs for Resource Development:
Volume 2 - Resource Characterization, Energy Resources, Walnut Creek,
November 1980.
3. Technical Procedures for Developing AP-42 Emission Factors And
Preparing AP-42 Sections (Draft), Emission Inventory Branch, Technical
Support Division, Office of Air and Radiation, Office of Air Quality Planning
and Standards, U.S. Environmental Protection Agency, Research Triangle
Park, NC, draft, March 6, 1992.
4. Brooks, G.W., M.B. Stockton, K.Kuhn, and G.D. Rives, Locating and Estimating
Air Emission from Source of Polvcvclic Organic Matter (POM). EPA-450/4-84-
007p. U.S. Environmental Protection Agency, Research Triangle Park, NC, May
1988.
5. Locating and Estimating Air Emissions from Sources of Chromium, EPA-450/4-
84-007g, U.S. Environmental Protection Agency, Research Triangle Park, NC,
July 1984.
6. Estimating Air Toxic Emissions from Coal and Oil Combustion Sources, EPA-
450/2-89-001, U.S. Environmental Protection Agency, Research Triangle Park,
NC, April 1989.
7. Evans, J.C., et al., 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 by
Battelle, Pacific Northwest Laboratories, Richland, WA.
8. Locating and Estimating Air Emissions from Sources of Manganese, EPA-450/4-
84-007h, U.S. Environmental Protection Agency, Research Triangle Park, NC,
September 1985.
9. PM-10 Emission Factor Listing Developed by Technology Transfer, EPA-
450/4-89-022, U.S. Environmental Protection Agency, Research Triangle
Park, NC, 1989.
10. Gap Filling PM-10 Emission Factors for Selected Open Area Dust
Sources, EPA-450/88-003, U.S. Environmental Protection Agency,
Research Triangle Park, NC, 1988.
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11. Generalized Particle Size Distributions for Use in Preparing Size Specific
Particulate Emission Inventories, EPA-450/4-86-013, U.S. Environmental
Protection Agency, Research Triangle Park, NC, 1986.
12. "Compilation of Air Pollutant Emission Factors", AP-42, Section 1.7,
Supplement A, U.S. Environmental Protection Agency, Research Triangle
Park, NC, October 1986.
13. Ondov, John M., "Cascade Impactors in the Chemical and Physical
Characterization of Coal-Combustion Aerosol Particles", Chapter 25 of
Fossil Fuels Utilization: Environmental Concerns, 1986.
14. Telephone conversation between S. Hughes, Acurex Environmental, and
Ron Myers, U.S. Environmental Protection Agency, March 24, 1992.
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4. EMISSION FACTOR DEVELOPMENT
This chapter describes how the revised AP-42 Section 1.7 was developed from
data in the 1986 section, and new data obtained from the literature search.17 The data
are reviewed and assigned a data quality ranking according to the procedures outlined
in Chapter 3. All of the data incorporated into the revised section are compiled into
summary tables which show the primary data used to develop the emission factors.
4.1 CRITERIA POLLUTANTS
New emissions data for lignite combustors were collected during this update for
NOX and S02. Emissions data for CO and organic compounds were very limited and
highly dependant on source design and operating conditions. The sources of criteria
emissions data were assigned a data quality rating. In addition to the rating rationale, a
brief discussion is provided below for each developed emission factor of the methods
used to collect the data, the level of documentation provided, the data consistency, and
the number of runs per test.
4.1.1 Review of Previous Data
The emissions data that are the basis of the 1986 Section 1.7 emission factors
were reviewed and assigned a quality rating to determine the data that should be
included in the revised section. Major references containing emissions data for more
than one firing configuration are discussed in the following paragraphs.
In developing the 1986 AP-42 Section 1.7, Reference 2 was used extensively.
This reference was the basis of the SOX emission factors for all of the firing
configurations. It presents a summary of SOX emissions from 28 days of testing at a
pulverized lignite-fired tangentially-fired unit; 8 days of testing at a pulverized coal (PC)
horizontally-opposed unit firing lignite; 3 days of testing at a lignite PC front-fired unit; 5
days of testing at a cyclone-fired unit, and 2 days of testing at a spreader stoker. The
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sampling method used to collect the SOX data was the controlled condensation method
of Lisle and Sensenbaugh in which the flue gas is drawn through a condenser at 60 to
90 °C (140 to 194 °F) [where the sulfur trioxide (S03) is selectively condensed and
collected] and then passes through an impinger containing a 3 percent hydrogen
peroxide (H202) solution. The analytical method employed was a titration using a
standard NaOH solution. This reference also contains some NOX emissions data for all
of the plants tested. The method used to collect the NOX data was EPA Method 7. The
calculation procedure is discussed; it was not equivalent to current EPA procedures,
but was valid. This reference was assigned a data rating of B. Even though the data
date to 1973, these tests represent a large number of source test runs executed over a
long time period by valid methods. These data are true baseline data because most of
the sampling occurred at the exit of the boilers, rather than at the stack or after PM
controls.
A second key reference for the 1986 Section 1.7 update was Reference 5. This
reference is the basis of many of the previous emission factors. Individual source test
reports from Reference 5 will be discussed individually for the purpose of data review.
Reference 8 is NSPS support testing for NOX at the Texas Utilities (TU) Big
Brown Power Station in Fairfield, Texas. The background file for the unrevised section
attached to the Big Brown source test report contains two other source test reports also
performed in support of the NSPS testing. The other two reports are for a PC unit
(Leland Olds) and a cyclone fired unit (Milton R. Young I) in North Dakota. These three
source test reports are the primary documents used in support of the NSPS. The NOX
emissions data from the two reports for Milton R. Young and Leland Olds appear
unchanged in Reference 3, the NSPS standards support document. The NOX
emissions data for Big Brown Station in the lignite NSPS support document include fuel
data and different process operation data than appear in the primary test report. The
author of the NSPS support document apparently obtained additional process and fuel
data from the plant for the NSPS support document. Therefore, the emissions and
process data in the NSPS support document for Big Brown are used in this update
rather than the primary report.
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4.1.2 Pulverized Coal Dry Bottom Emission Factors
The PC emission factors contained in the 1986 AP-42 Section 1.7 update for
PM, SOX, and NOX are based on data from five sources: from Reference 5, Reference
18, Reference 6, Reference 2, and the results of the NSPS standards support source
testing conducted at the Leland Olds and Big Brown power plants contained in
Reference 3.
The Stanton source test report has uncontrolled and controlled emissions data
for PM, SOX, and NOX.18 The source test methods are specified for each pollutant (e.g.,
the particulate data was collected according to ASTM Power Test Code 27-1957). The
source testing was conducted using sound methodologies, but the number of source
test runs was inadequate. The boiler had divided flue gas ducting and only one run
was conducted for each pollutant on each duct. The uncontrolled PM data were taken
on two different days. No fuel ash or sulfur contents were given in the report, and the
emission factors generated from these data are based on assumed sulfur and ash
percentages. This report was assigned a data rating of D.
Reference 6 focuses on ash fouling rates when burning low- and high-sodium
lignite. The article presents PM and SOX emissions data from a tangentially-fired boiler.
The particulate data was collected according to ASTM Power Test Code 27-1957. Two
methods were used to collect the SOX data: the selective condensation method of Lisle
and Sensenbaugh, and the absorption method by Berk and Burdick. Agreement is
reported as being good between the two methods. The author of this article is the
primary author of Reference 2; the SOX emissions data in this article are likely also
contained in Reference 2. Since Reference 2 contains a large amount of SOX data for
this specific plant, the data from this article was not rated or treated as additional data.
The coal composition and boiler operating conditions during testing are presented. The
main problem with this source is that there is no documentation on how many source
test runs were incorporated in the final results. The particulate testing results are
presented as a percentage of incoming ash emitted in the flue gas. The particulate
data in this article were given a D rating.
The NSPS standards support testing conducted at Leland Olds, a horizontally
opposed-fired boiler, and at Big Brown I & II, twin tangentially-fired boilers, yielded a
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significant amount of baseline NOX emissions data. Eight days of source testing were
conducted at the twin units of Big Brown station, and three days of testing were
conducted at Leland Olds. The results and original source test reports are contained in
References 3 and 8, respectively. Simultaneous sampling for NOX was conducted at
both plants using EPA Method 7 and continuous emission monitors (CEM). The CEM
data from both reports showed inconsistencies due to recurring problems with the CEM
equipment. The CEM results for the Leland Olds plant had no information regarding
the calibration procedures carried out during testing. The Big Brown source test report
did contain actual copies of the strip charts with pre-test and post-test calibration
results. The first five days of CEM data in the Big Brown report were voided by the
source test contractor because of gas conditioning problems. The last three days of
CEM data were considered valid by the contractor with calibration drifts for the three
days reported as 5, 4, and 2 percent. The current EPA method specifies that the
calibration drift be within 3 percent of the span. The CEM emissions data from the
NSPS support testing were not assigned a data quality rating because sufficient EPA
Method 7 data were available. The NOX emission results for Big Brown Units I & II were
based on 28 baseline EPA Method 7 runs. The NOX emissions results for the Leland
Olds Unit I were based on 31 baseline EPA Method 7 runs. No raw data sheets are
presented in either of these reports. The EPA Method 7 NOX emissions data were
assigned a data quality rating of B.
An additional source of criteria emissions data for the Leland Olds Unit I was
Reference 7. The emissions data were not included in the prior update.17 This report
contains a data summary for one day of baseline CEM data for Leland Olds for NOX and
CO. The detailed description of sampling equipment and methods are contained in
another report which was not reviewed. The report does not specifically cite EPA CEM
methods, but does discuss calibration procedures carried out during the test program.
It was assumed that this test program used EPA CEM methods since it was conducted
for the Agency. These data were assigned a data rating of B.
4.1.3 Cyclone Emission Factors
The cyclone fired-boiler emission factors contained in the previous update for
PM, NOX, and SOX were based on emissions data from five sources: Reference 12,
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Reference 2, two source test reports from Reference 5, and results of the NSPS
support testing from Reference 8.
The main source of baseline particulate emissions data for cyclone furnaces for
the prior update was Reference 12. This contains the results of nine source tests on
three cyclone-fired plants. The PM emission rate in Ib/hr, the coal feed rate in tons/hr,
and the ash content of the coal were provided. This source was assigned a B data
rating.
The most comprehensive source of baseline NOX emissions data was the NSPS
standards support testing contained in Reference 8. This report contains simultaneous
source testing for NOX using EPA Method 7 and CEM taken over four days. The CEM
results for this plant had no information regarding the calibration procedures carried out
during testing. The CEM data were not given a data quality rating. The first two days
of baseline EPA Method 7 NOX data were given a data quality rating of B. The last two
days of EPA Method 7 NOX data cover only one of two boiler exhaust ducts and,
therefore, were excluded from consideration.
An additional source of PM emissions data used in the previous Section 1.7 was
a source test report from Reference 5 for Milton R. Young Unit I. This 1971 report
presents the results from two test runs taken after the dust collector. One test run was
called "preliminary" by the contractor and was conducted on one of the two divided flue
gas ducts. The other run was conducted on both flue gas ducts. No specific method
was specified in the report. Some of the raw data sheets are missing and the
calculation procedures used were not equivalent to current EPA methods. These data
were assigned a D rating.
Another source of NOX and SOX emissions data used in the previous Section 1.7
was a source test report from Reference 5 for Milton R. Young unit I. This 1971 source
test report presents NOX and SOX emissions data taken using CEM. The report does
not specify the CEM method. The report also discusses a problem with moisture in the
flue gas affecting the SOX CEM results. These data were given a C
rating.
4.1.4 Spreader Stoker and Other Stoker Emission Factors
The spreader stoker emission factors contained in the 1986 AP-42 Section 1.7
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update for PM, NOX, and SOX emissions are based on Reference 2 and four source test
reports from Reference 5. The process data were often not reported in these
references. A rough table of plants and the control device information for each plant
was obtained from the Background File. This was the only source of control and
process data available for this update effort. This information is essential for the data in
the current update to meet the exclusion criteria.19
Two of the source test reports cited in Reference 5 are of low quality for
developing emission factors. The first of these reports, Reference 20, has emissions
data for PM, NOX, and SOX. The source test methods are specified as ASTM 27-1957
for PM testing, the Shell Development method for SOX, and Saltzman Reagent for NOX
emissions testing. The main problem is that only one run was conducted at the inlet
and outlet of the control device for PM. One run for NOX and SOX was conducted at the
outlet of the control device. This source was assigned a D rating. The second report,
Reference 21, contains controlled PM emissions data for three boilers. The method
used for collecting the data was specified as ASTM 27-1957, but only one run was
conducted for each plant. This source was assigned a D rating.
Reference 22 contains controlled PM emissions data for two spreader stoker
boilers and uncontrolled PM data for two other overfeed stokers. The method used to
collect the particulate data is specified as the latest National Air Pollution Control
Agency and Public Health Bulletins as well as ASTM Power Test Code 27. The
sampling train used to collect this data was equivalent to a current EPA Method 5 train.
The calculation procedure is well documented but the equations are not completely
equivalent to current EPA Method 5 calculational procedures. The results are based on
three test runs. The main problem with this data is the lack of information regarding the
control device. Reference 5 was the only source of information for the control device.
Therefore, these data were assigned a C data rating.
The Reference 23 report contains SOX and PM data for the P.P. Wood Plant.
The particulate data is invalid because of strong cyclonic flow conditions at the
sampling point. The SOX data were taken at a different location and were not as
sensitive to flow conditions. These SOX data are also contained in Reference 2; no
additional detail is contained in this report. Therefore these data will not be rated as an
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additional source.
A significant amount of baseline emissions data for spreader stokers and other
stokers were contained in the Section 1.7 Background File. Reference 14 is a trip
report describing a visit to the North Dakota Department of Health. The letter has an
attachment describing source test results and process and fuel data for plants in the
Department of Health's permit files. The North Dakota Department of Health provided
copies of the summary pages of these reports in a letter for the 1973 update of this
section. The process and fuel data contained in both letters combined with the
summary pages of the source test reports were reviewed. Source test results which did
not include critical fuel, process, or control data were excluded. Although poorly
documented, the remaining data were collected during triplicate testing conducted at
the inlet and outlet of the control device. The method used to collect this particulate
data is equivalent to the EPA Method 5. The two letters and attachments described
above are considered a single reference (i.e., the stoker data package).14 The stoker
data package was assigned a data rating of C.
4.1.5 Review of New Baseline and Controlled Data
This portion of the chapter reviews and assigns a data rating to new data
obtained from the literature search that were used to derive new emission factors. The
literature search discussed in Chapter 3 revealed that only a small amount of published
emissions data for lignite combustion was available. The literature search, therefore,
focused on obtaining data from the air pollution control agencies which regulate most of
the lignite-fired boilers in the U.S.
The North Dakota Department of Health and the TACB both provided source test
data for this update effort. Both of these agencies have a significant amount of source
test data available for lignite combustion. The data obtained represents only a portion
of the data held by these agencies, however.
Almost all of the new data obtained during the current effort is controlled data.
This is mainly due to the promulgation of two series of NSPS (i.e., Subpart D and
Subpart Da) which regulate emissions from new boilers; TACB and North Dakota
Department of Health air pollution regulations/permits also limit emissions from existing
4-23
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sources.
4.1.6 North Dakota Department of Health Data15
The North Dakota Department of Health supplied source test results for nine
lignite-fired utility boilers. Seven of the utility boilers are required to recertify their CEM
equipment every three years. The majority of the data package received from the
Department is relative accuracy testing to certify the plant CEM equipment. The
department also supplied particulate source test summaries for eight of the nine boilers.
All of the emissions data in the data package were collected in accordance with EPA
methods. The particulate results are all based on three sampling runs, and the CEM
results are based on nine or ten 5-minute averages. The emissions data in the
package were all collected downstream of particulate controls. Process information on
each boiler and associated controls were obtained from copies of the permits for the
units. Coal composition data were supplied for each source test and plant. Some of
the coal composition data applied to the week of testing and some were specific to
each run. All of the boilers tested were operated above 70 percent of design capacity.
All of the major firing configurations are described in the data package. Five of
the boilers are tangentially-fired lignite PC units. Two of the plants are cyclone-fired
units. One of the plants is a spreader stoker, and one of the units is a fluidized bed
boiler. The fluidized bed boiler is a retrofitted spreader stoker unit.
The data package also contains a personal communication which discusses the
conversion of the spreader stoker to the fluidized bed boiler.14 An attachment to this
letter contains emission calculations for the old spreader stoker and the new fluidized
bed boiler. Average Ib/million Btu (Ib/MMBtu) emission rates and coal compositions are
supplied for both units. The spreader stoker NOX data were used to generate Ib/ton
emission factors. The other emissions data were used as a reference for comparison to
other source test data.
The entire North Dakota Department of Health data package was assigned a B
rating. The source testing was performed using sound methods and the reports were
reviewed by the EPA. If the complete documentation can be obtained for this data
during future updates this data could receive an A data quality rating.
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4.1.7 Texas Air Control Board16
The TACB has 12 regional offices in the State. The majority of lignite-fired
boilers are located in Regions 3 and 12 of the State. Emissions data were obtained for
three boilers in Region 3. Three complete source test reports were obtained for two
twin 800 MW tangentially-fired boilers. The text and summary portions only of two
source test reports were obtained for a circulating fluidized bed boiler located in Region
3.
Emissions data were obtained for four lignite-fired boilers in Region 12. Two
complete source test reports were obtained for two twin 750 MW tangentially-fired
boilers. Two complete source test reports were also obtained for a 720 MW and 750
MW horizontally opposed-fired boiler.
Process, control, and coal data used for calculation of emission factors were
obtained from copies of portions of the permit files for each of the non-FBC boilers.
The copies of the permit files were obtained from the main office of the TACB. All of
the source test reports contained coal analyses for the boilers during testing. The
process operating conditions were also contained in the source test reports. All source
tests contained in the package were conducted while the boiler was operating near full
load.
The majority of the Texas emissions data were NSPS compliance testing, and all
of the testing was conducted in accordance with the procedures contained in the
Appendix to the Code of Federal Regulations (CFR), Title 40, Chapter I, Part 60. The
complete source test reports contain extensive documentation on calculation and
calibration procedures. The emission rates were calculated using the F-factor
calculation procedure specified by Reference Method 19 of 40 CFR Part 60 Appendix
A.
All of the complete source test reports obtained from the TACB were assigned a
data quality rating of A. The portions of source test reports obtained for the FBC were
assigned a data quality rating of B due to a lack of adequate information detail
regarding sampling and analytical methods.
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4.1.8 Compilation of Baseline Emission Factors
The only new baseline, uncontrolled, data obtained were the fluidized bed
emissions data, a stoker NOX data point, and a cyclone NOX data point. The new data
for PC units are presented in the compilation of controlled emission factors because the
designs of the current PC units pursuant to the NSPS are so different from the old units,
and because all of the data were obtained after controls. The uncontrolled emission
factors for the fluidized bed source category were not developed in the same sense as
for the other categories. Fluidized bed design might be considered a combustion
modification from the standpoint of NOX emissions; however, these data were classified
as baseline since no additional add-on NOX controls were in place. The SOX emission
factor for this source category is a controlled factor reflecting the absorption of SOX by
the bed material. No baseline particulate emissions data were available for this source
category.
As previously discussed, the majority of new data available for lignite combustion
is controlled emissions data. The baseline emission factors for the revised section are
based on the same data as the prior update section. The actual values of the emission
factors have changed because different calculation procedures were used to generate
emission factors from the previous source test data, and data of extremely poor quality
were excluded from the revised Section 1.7.
The SOX emission factor will still be based on the sulfur content and the sodium
content of the lignite fired for all firing configurations. The values have changed slightly
due to the elimination of duplicate data points and poor-quality data points. The
primary reference for the SOX emission factor is Reference 2. The data that the SOX
emission factor is based on are presented in Table 4.1. Most of the SOX emissions data
available cannot be used to generate emission factors because no ash analysis was
available for the lignite fired during testing.
The only true NOX baseline emissions data are the original data in the 1986
update; all subsequent data identified in the literature search were for post-NSPS units
controlled for NOX. Most of the NOX data are based on sampling downstream of
particulate controls. The particulate device normally does not affect NOX emissions.
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Many of the baseline participate emission factors contained in the 1986 AP-42
update section were derived from controlled data. The control efficiencies used to
back-calculate uncontrolled emissions were often based on poor source test data,
design efficiencies, or values in the now-defunct National Emissions Data Base.
The data available for CO and VOC emissions from lignite-fired boilers are
extremely limited. The Orsat data for CO was not used to generate emission factors.
The revised emission factors were developed by taking source test results in
units of Ibs of pollutant/MMBtu and multiplying by the Btu/ton gross wet heating value of
the coal. Emissions data in parts per million by volume were converted to units of Ib
pollutant/MMBtu using an F-factor as specified by Reference Method 19 of 40 CFR Part
60 Appendix A. The PM emission factor for lignite PC boilers is based on a single data
point from Reference 5 where the Ib/hr particulate emission rate was divided by the coal
burning rate of wet ton/hr. Baseline emission factors are summarized in Tables 4-1
through 4-9.
4.1.9 Compilation of Controlled Emission Factors
Most of the new data obtained from the literature search are for source testing
conducted at the stack after pollution control systems. The plants constructed after the
Subpart D NSPS were implemented were designed with controls integrated with the
boiler to form a complete system. All of the plants built prior to the NSPS had some
add-on PM control. The term baseline emissions is becoming an ambiguous concept.
This is especially true for NOX controls which are a function of boiler design and
operation. The post-NSPS PC units are very different than the PC coal units built prior
to 1971. The emissions data obtained for post-NSPS PC units are presented in this
section. Volatile organic compound and CO emissions data are still considered
essentially uncontrolled. The emissions of these compounds are related to the boiler
design, however. Therefore, they were not combined with the baseline data for boilers
designed prior to the NSPS implementation. The available NOX control data for a
specific boiler were often difficult to obtain for the current update. For example, most of
the post-NSPS boilers were designed with overfire air ports for NOX control, but many
plants do not need to use overfire air to meet the first round of NSPS emission
standards. Some older, wall-fired plants may take a top row of burners out of service to
4-27
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provide a form of overfire air. Most of the process and control information for this
update was obtained from permit files; as a result, the information regarding NOX
controls was often sparse. It was assumed that all of the tangential boilers fired on
lignite built after the NSPS were equipped with overfire air ports.
In general, the calculation procedure started with source test results in units of
Ibs of pollutant/MMBtu and multiplied by the Btu/ton gross wet heating value of the coal.
Emissions data in parts per million by volume were converted to units of Ib
pollutant/MMBtu using the F-factors specified by Reference Method 19 of 40 CFR Part
60 Appendix A. Controlled emission factors are summarized in Tables 4-10 through 4-
14.
4.2 Nitrous Oxide
The literature search for N20 emissions from lignite firing revealed only data
specific to lignite combustion in fluidized bed units. A survey of 42 documents revealed
two documents which were used to develop the N20 emission factor for these units:
Reference 26
This reference contained data from N20 emissions of fluidized bed combustors.
The data is in graphical form and presented in units of milligram per megajoule. The
conversion from milligram per megajoule to ppm is one milligram per megajoule equals
1.7 ppm. The test was preformed on a circulating fluidized bed boiler controlled by
recirculation of flue gases. The reference case is defined by a bed temperature of 850
°C (1600 °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 was
assigned a rating of D.
Reference 27
This test report contained data from a pilot-scale 1MW CFBC. N20 emissions
were continuously monitored by a non-dispersive infrared spectrometer. A rating of C
was assigned to the data for the lignite-fired boiler; therefore, the emission factor rating
could not be higher than an E because the emission factor was developed from C
quality data. The N20 emission factors for lignite-fired FBC units are summarized in
Table 4-15.
4.3 HAZARDOUS AIR POLLUTANTS
4.3.1 Review of New Data
A discussion of the hazardous air pollutants (HAPs) data evaluated for the
development of emission factors for boilers fired on lignite is presented in this section.
The discussion includes a summary of the information presented in the source and an
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evaluation of the quality of the data for use in generating emission factors. The
discussions are presented by the source. The data and emission factors presented in
this section were rated with the criteria outlined in Section 3.3.3.19
Reference 28
This article summarizes the emissions of certain trace metals and HAPs from
lignite coal combustion. The data presented are a summary of a literature review.
Emission factors are presented in the units of mass emitted per heat unit combusted
and are presented for boilers of different sizes and configurations. The article
references several primary references which were evaluated and determined to be of
insufficient quality for emission factor development.
Reference 29
This document is a compilation of the available information on sources and
emissions 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 lignite coal. The emission factors provided are for post-control
devices. Data for utility boilers is used in this update because this is the largest and
most complete data set for coal combustion.
Reference 30
The data quality and documentation in this report are of unacceptable quality to
generate emission factors due to low quality sampling and analytical methods and lack
of information on fuel composition and control device performance.
Reference 31
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 33
This report summarizes testing performed on several sizes and types of boilers;
however, only criteria pollutant testing was performed.
Reference 34
Measured and calculated emission factors for lignite coal are presented in this
document. The emission factors are rated with a low quality because the document is
not a primary source and the quality of the data cannot be verified.
Reference 35
This document provides a summary of the emissions factors for metals,
polycyclic organic matter (POM), and formaldehyde for lignite coal-fired boilers. Control
efficiencies are reported for some control devices. No data are reported for
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uncontrolled emissions of POM and radionuclides. The formaldehyde data are from
1964 and are considered to be of insufficient 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 HAPs 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 with a low quality because the data
acquisition and manipulation could not be verified.
Reference 36
The data quality and documentation in this report are of high enough quality to
develop enrichment ratios for metals and radionuclides on the boilers and their
associated abatement devices. Emission factors are calculated in the units of mass
emitted per heat unit combusted for PAH compounds.
Reference 37
This document presents emission factors for sources of chromium. A literature
survey was used to compile emission estimates from lignite-fired boilers. The emission
factor for utility boilers is used for generating the emission factor.
4.3.2 Baseline Emission Factors
Emission factors for trace metals, radionuclides, and other HAPs are quite often
presented in units of mass emitted per unit of thermal heat input. These units are
adequate for performing emission estimates of the organic HAPs but are not ideal for
estimating emission factors of metals and radionuclides. Ideally, emission factors for
trace elements should be developed as a function of the boiler firing configuration,
boiler size, trace element concentration in the fuel, ash content, higher heating value,
enrichment ratio, and the collection efficiency of the control device. The concepts of
partitioning and enrichment are often used to characterize the behavior of trace
elements in the combustion process. The concept of partitioning is used to describe
the distribution of trace elements among the boiler outlet streams. These streams may
include the bottom ash, fly ash, and flue gas. Enrichment refers to the difference in the
trace element concentrations in the outlet streams. The process of enrichment can also
take place in a control device. The physical and chemical properties of a trace metal
governs how that metal will distribute in the outlet streams. For example, mercury (Hg)
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is a highly volatile metal and therefore, the majority of the mass of Hg in the feed coal
tends to be entirely 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 left the boiler in an outlet stream. Another method for
quantifying the distribution of a metal is to calculate an enrichment factor by comparing
the trace element concentration of an outlet stream to the trace element concentration
of the inlet stream. The enrichment ratio calculation that is outlined in Reference 38 is
performed using the following equation:
ER, = (CyC^/fCyC,*)
where:
ERy = enrichment ratio for element i in stream j
Cy = concentration of element i in stream j
CRj = concentration of reference element R in stream j
Cic = concentration of element i in fuel
CRc = concentration of reference element R i fuel
Enrichment ratios greater than 1 indicate that an element is enriched in a given
stream, 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 (Al),
iron (Fe), scandium (Sc), and titanium (Ti). The enrichment behavior of elements is
somewhat consistent in different types of boilers and can be explained by a
volatilization-condensation or adsorption mechanism. A summary of the enrichment
behavior for the air toxic metals and the reference metals is presented in Table 4-16.
Table 4-17 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 in order to estimate emissions of trace elements. The equation outlined
in Reference 38 which is used to calculate the emission factor for a trace element is as
follows:
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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, ug/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, which is
0 for uncontrolled emissions
ER = enrichment factor for the trace element (ratio of concentration of
element in emitted fly ash to concentration of element in coal ash)
sometimes based on Al
In many cases, the source test programs did not include key parameters such
as: ultimate analyses and speciation 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 it 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 heat input were
provided. Though this is not the optimal method of estimating emissions, it provides a
means of performing a rough emission estimation.
Table 4-18 summarizes the enrichment ratios for metals and radionuclides for an
uncontrolled boiler and for a high efficiency cold-side ESP. The quality of these
enrichment ratios is low (E quality) because of the low number of boilers and control
data used to perform the calculations. Enrichment ratio data are a significant data gap
in the HAP data bases.
Tables 4-19 and 4-20 present a summary of emission factors in the units of mass
emitted per unit thermal heat input for uncontrolled utility boilers. Data on utility boilers
are the most studied group of boilers and, therefore, have the most significant amount
of data. Data are presented for metals. No POM or formaldehyde uncontrolled
emissions data were found. The tables are presented in metric units and English units,
respectively. The quality rating of these data are low because many of the sources of
information are of insufficient quality and the number of data points are too small to
represent an entire source category.
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4.3.3 Controlled Emission Factors
Tables 4-21 and 4-22 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 insufficient quality and the
number of data points are too small to represent an entire source category.
4.4 PARTICULATE SIZE DISTRIBUTION
The scope of AP-42 is being extended to augment particulate size distribution
emission factors with data on the split between filterable and condensible PM-10. The
current AP-42 includes detailed analysis of particle size distribution data. Filterable PM-
10 data is included in this analysis by default because it is among the cumulative size
fractions considered. Condensible PM-10 is not in the current AP-42 and needs to be
added to future versions of AP-42.
4.4.1 Review of Previous AP-42 Data
The 1986 AP-42 particle sizing update was evaluated with respect to sources of
data, data analysis and emission factor development procedure. Data retrieved and
analyzed for that update were exclusively filterable PM.
Very few lignite data sets were available through FPEIS or other sources at the
time of the previous update.39 All the data sets were considered C-quality. The FPEIS
printouts were checked, as was the partial report referenced in the 1986 Emission
Factor Documentation report as ERG No. 7246. The spot-checking indicated that the
previous analysis was as accurate as possible given the data quality.
4.4.2 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 method development source test data
were uncovered.
Although a variety of sources were contacted with regards to 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 time limitations and other staff limitations.
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Two sets of data are available for filterable PM from pilot-scale atmospheric
fluidized bed combustors (AFBCs).38 A pilot AFBC unit was tested while firing either
subbituminous coal or lignite. The purpose of the tests was to investigate the corrosive
and/or erosive properties of low-rank coal ash on heat transfer surfaces.
As part of the test, the particulate emissions exiting a multiclone system were
measured for particulate size distribution. A flow sensor multiclone and laser
aerodynamic particle sizer (APS) provided particle size distribution data at the inlet to
the scrubber (after the multiclone controls).
The data is ranked C due to the pilot-scale size, the particulate collection
methods, and lack of sufficient background data. In addition, the cumulative percent
mass values were obtained via interpolation of log-log graphs of the results. The
particulate size distribution data are shown on Table 4-23.
4.4.3 Compilation of Uncontrolled Emission Factors
The 1986 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 particulate 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 becomes 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.
4.4.4 Control Technology Emission Factors
There were two calculation steps in the development of controlled emission
factors in the previous PM sizing update in 1986.39 First, a controlled emission factor
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was developed for total PM by multiplying the uncontrolled total PM emission factor
from the criteria pollutant table by one of the following 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 every size
distribution table in Section 1.7 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 emission factors
for the particulate size fractions.
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-specific
emission factors rather than using generalized control efficiency results. Control-
specific emission factors are better than generalized control efficiency results because
control efficiency is dependent on particulate parameters, such as the resistivity, 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 41 percent of
controlled PM from a multiple cyclone operating on lignite-fueled spreader stokers was
less than or equal to 10 microns. Based on this value; on an uncontrolled emission
factor of 3.4A kg/Mg; and on an estimated multiple cyclone efficiency of 80 percent, the
controlled PM-10 emission factor is calculated as 0.279A:
0.41 x 3.4A x (1.0 - 0.80) = 0.279A kg/Mg.
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Although different methods could be used to develop controlled emission
estimates, the procedures used in the 1986 document are 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
cited above are reasonable in light of available data for lignite-fired boilers and were
retained in the current update.
Tests of ash from lignite combustion have indicated ash characteristics that may
significantly affect the ability of a fabric filter to achieve high collection efficiencies.40
For instance, lignite ash particles are noncohesive, smooth spheres with few surface
deposits. The ash particles tend to penetrate through the fabric leading to bleed-
through. The noncohesive particles form an unstable dustcake on the fabric surface.
Low collection efficiencies are expected for shake/deflate and reverse gas-cleaned
baghouses because the dustcake is the primary filter medium for those baghouses.
Pulsed-jet cleaned baghouses can achieve higher efficiencies because the bag acts as
the primary filter medium.
A transportable pulsed-jet fabric filter pilot plant was tested at the 575 MW Big
Brown Unit 1 of the TU Electric Company in Fairfield, TX. A medium to low-sulfur
Texas lignite was fired throughout the tests. Two pulse jet cleaning systems were
tested: high-pressure/low-volume and low-pressure/high-volume. During the low-
pressure/high-volume tests, the average particulate collection efficiency was 99.95%
with outlet emissions equivalent to 0.0002 to 0.0003 ng/J (0.005 to 0.008 Ib/MMBtu).
During the high-pressure/low-volume tests the particulate efficiency was 99.81% with
outlet emissions of 0.00007 ng/J (0.0017 Ib/MMBtu).40
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TABLE 4-1. BASELINE SULFUR OXIDES EMISSION DATA3
Na2O in ash,
% by weight
Emission factor13
kg SOv/Mg coal x Sc
Individual
tests
Average for
Na7O range
Ib SOv/ton coal x Sc
Individual
tests
Average for
Na7O range
0.4
0.7
0.8
0.9
1
1.1
1.6
1.7
16.9
17.3
18.1
16.7
15.1
14.7
18.3
16.7
16.7
33.7
34.6
36.1
33.3
30.2
29.3
36.5
33.4
33.4
2
2.1
3
3.1
3.5
3.8
4.8
5.1
5.3
5.4
5.5
5.6
5.8
6
6.1
6.2
7
7.5
7.7
7.8
17.1
18.7
20.0
16.6
17.8
13.9
14.6
13.4
11.6
13.0
15.1
12.7
16.7
17.7
12.3
15.9
16.0
13.2
17.7
13.6
16.2
34.2
37.4
40.0
33.2
35.5
27.8
29.1
26.8
23.1
25.9
30.2
25.4
33.4
35.3
24.5
31.7
31.9
26.4
35.3
27.2
32.3
8
8.2
8.6
8.8
9
10.9
16.8
9.2
8.5
15.6
10.5
5.5
11.0
33.5
18.4
16.9
31.2
21.0
10.9
21.9
"Reference 2.
Excluding fluidized beds which capture SOx by bed absorption.
CS = % sulfur wet basis.
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TABLE 4-2. SUMMARY BASELINE NOV AND CO EMISSIONS DATA FOR PULVERIZED LIGNITE UNITS3
Firing
configuration
Tangential
Tangential
Horizontally
Opposed
Wall Fired
Front Wall
Fired
NOX,
kg/Mg
4.25
3.05
6.7
5.2
2.35
5.0
Ib/ton
8.5
6.1
13.4
10.4
10.7
10.0
Data
quality
rating
B
B
B
B
B
B
Ref. CO,
kg/Mg I by
2
3
8
7 0.125 0
2
2
Data Ref.
quality
ton rating
25 B 7
aAII data, except for front wall firing configuration, taken after PM controls.
TABLE 4-3. SUMMARY BASELINE PM EMISSION DATA FOR PULVERIZED LIGNITE UNITS
Firing configuration
Particulate,3
kg/Mg
Tangential 3. 25 A
Front Wall 2.55 A
Ib/ton
Data quality
rating
Reference
6.5 A D 6
5.1 A D 5
aA = wet basis % ash content of lignite.
-------
TABLE 4-4. SUMMARY BASELINE NOX EMISSIONS DATA FOR CYCLONE-FIRED
UNITS
N0y,
kg/Mg
6.05
6.1
6.6
Ib/ton
Data quality
rating
Reference
Controls3
12.1 B 2
12.2 B 8 P
13.2 B 15 P,S
aData taken after PM controls is designated by P. Data taken after SO2 controls is designated by S.
TABLE 4-5. SUMMARY BASELINE PM EMISSION DATA FOR CYCLONE-FIRED
UNITS
Particulate,3
kg/Mg
2.65A
3.1A
4.3A
Ib/ton
Data quality rating
Reference
5.3A B 12
6.2A B 12
8.6A B 12
aA = wet basis % ash content of lignite.
TABLE 4-6. SUMMARY BASELINE NOV EMISSIONS DATA FOR SPREADER
STOKER
UNITS
N0y,
kg/Mg
2.6
3.2
Ib/ton
Data quality
rating
Reference
Controls3
5.2 B 2 P
6.4 B 15 P
aData taken after particulate controls is designated by P.
4-39
-------
TABLE 4-7. SUMMARY BASELINE PM EMISSIONS DATA FOR SPREADER
STOKER
UNITS
Particulate,3
kg/Mg
3.2A
5.95A
2.85A
Ib/ton
Data quality rating
Reference
6.4A C 14
11. 9A C 14
5.7A C 14
aA = wet basis % ash content of lignite.
TABLE 4-8. SUMMARY BASELINE PM EMISSIONS DATA FOR OTHER STOKER
UNITS
Stoker type
Particulate,3
kg/Mg
Ib/ton
Data
quality
rating
Reference
Underfeed
Overfeed
Overfeed
2.0A
1.2A
1.85A
4.0A
2.4A
3.7A
C
C
C
14
14
14
aA = wet basis % ash content of lignite.
4-40
-------
TABLE 4-9. ATMOSPHERIC FLUIDIZED BED BASELINE NOX, SOX, AND CO
EMISSIONS DATA3
Firing configuration
N0y,
kg/Mg
Ib/ton
soy,b
kg/Mg
Ib/ton
CO,
kg/Mg
Ib/ton
North Dakota Region0
66 MW
Bubbling Bed
Multiclone, ESP
2.3
4.6
4.95S 9.9S
Texas Regiond
180MW
Circulating Bed
Drum Type
1.3
2.6
0.075
0.15
aAII of the source testing conducted at the stack downstream of controls.
bS = wet basis weight % sulfur content of lignite.
Reference 15. All data are rated B.
""Reference 16. All data are rated A.
4-41
-------
TABLE 4-10. CONTROLLED NOX, SOX, AND CO EMISSIONS DATA3
Firing configuration
N0y,
kg/Mg
Subpart D Boilers,
Pulverized Coal
Tangential Firing
Ib/ton
sov,
kg/Mg
Ib/ton
CO,
kg/Mg Ib/ton
North Dakota Region0
440 MW Unit
Spray Dryers, Baghouse
Overfire Air
2.6
5.1
3.1S
6.1S
440 MW Unit
Spray Dryers, Baghouse
Overfire Air
2.4
4.8
4.2S
8.4S
500 MW Unit
ESP, Wet lime scrubbers
FGD 60% of flue gas
Overfire Air
3.6
7.2
8.3S
16.6S
500 MW Unit
ESP, Wet lime scrubbers
FGD 60% of flue gas
Overfire Air
Texas Regiond
780 MW Unit
ESP, Wet lime scrubbers
Overfire Air
4.0
3.7
7.9
7.4
8.5S
7.8S
16.9S
15.6S
780 MW Unit
ESP, Wet lime scrubbers
Overfire Air
4.3
8.5
7.7S
15.3S
Subpart D Boilers,
Horizontally Opposed Firing
730 MW Unit
ESP, Wet lime scrubbers
Overfire Air, Low NOX burners
750 MW Unit
ESP, Wet limestone scrubbers
Overfire Air, Low NOX burners
2.7 5.3 6.9S 13.7S 0.24 0.48
2.0 3.9 9.7S 19.4S
4-42
-------
TABLE 4-10. CONTROLLED NOX, SOX, AND CO EMISSIONS DATA (Continued)3
Firing configuration
N0y,
kg/Mg
Subpart Da Boilers,
Pulverized Coal
Tangential Firing
Ib/ton
sov,
kg/Mg
Ib/ton
CO,
kg/Mg Ib/ton
North Dakota Region0
55 MW
Spray Dryer, Baghouse
Overfire Air
3.3
6.6
4.0S 7.9S
Texas Regiond
780 MW
ESP, Wet limestone
scrubbers
Overfire Air
2.4
4.8
2.1S 4.2S 0.03
0.06
780 MW
ESP, Wet limestone
scrubbers
Overfire Air
3.3
6.6
1.6S 3.2S 0.07
0.13
aAII of the source testing conducted at the stack after all controls.
bS = wet basis weight % sulfur content of lignite.
Reference 15. All data are rated B.
""Reference 16. All data are rated A.
4-43
-------
TABLE 4-11. ATMOSPHERIC FLUIDIZED BED UNITS CONTROLLED SOX
EMISSIONS
DATA3
Firing configuration
soy,b
kg/Mg
Ib/ton
Texas Region0
180MW
Circulating Bed
Drum Type
Limestone injection 3.5S 7.OS
aAII of the source testing conducted at the stack after all controls.
bS = wet basis weight % sulfur content of lignite.
Reference 16. All data are rated A.
4-44
-------
TABLE 4-12. CONTROLLED PM EMISSIONS DATA3
Firing configuration
PMb
kg/Mg
Ib/ton
Subpart D Boilers,
Pulverized Coal
Tangential Firing
North Dakota Region0
440 MW Unit
Spray Dryers, Baghouse
Overfire Air
0.05A
0.09A
440 MW Unit
Spray Dryers, Baghouse
Overfire Air
0.03A
0.06 A
500 MW Unit
ESP, Wet lime Scrubbers
FGD 60% of flue gas
Overfire Air
0.01A
0.02 A
500 MW Unit
ESP, Wet lime Scrubbers
FGD 60% of flue gas
Overfire Air
Texas Regiond
780 MW Unit
ESP, Wet limestone scrubbers
Overfire Air
0.04 A
0.02 A
0.08A
0.04 A
780 MW Unit
ESP, Wet lime scrubbers
Overfire Air
0.04 A
0.07A
Subpart D Boilers,
Horizontally Opposed Firing
730 MW Unit
ESP, Wet limestone scrubbers
Overfire Air, Low-NOx burners
750 MW Unit
ESP, Wet limestone scrubbers
Overfire Air, Low NOy-burners
0.03A
0.02 A
0.05A
0.04 A
4-45
-------
TABLE 4-12. CONTROLLED PARTICULATE EMISSIONS DATA (Continued)3
Firing configuration
PM,b
kg/Mg
Ib/ton
Subpart Da Boilers,
Pulverized Coal
Tangential Firing
Texas Regiond
780 MW
ESP, Wet limestone scrubbers
Overfire Air
0.005A
0.01A
780 MW
ESP, Wet limestone scrubbers
Overfire Air
0.005A
0.01A
aAII of the source testing conducted at the stack after all controls.
bA = wet basis % ash content of lignite.
Reference 15. All data are rated B.
""Reference 16. All data are rated A.
4-46
-------
TABLE 4-13. ATMOSPHERIC FLUIDIZED BED UNITS CONTROLLED PM
EMISSIONS
DATA3
Firing configuration
PM,b
kg/Mg
Ib/ton
North Dakota Region0
66 MW
Bubbling Bed
Multiclone, ESP 0.055A 0.11 A
Texas Regiond
180MW
Circulating Bed
Drum Type 0.01A 0.02A
aAII of the source testing conducted at the stack after all controls.
bA = wet basis weight % ash content of lignite.
Reference 15. All data are rated B.
""Reference 16. All data are rated A.
4-47
-------
TABLE 4-14. CONTROLLED ORGANIC EMISSIONS DATA3
Firing configuration
Subpart Da Boilers,
Pulverized Coal
Nonmethane TOC,
kg/Mg
Ib/ton
Methane,
kg/Mg
I
Ib/ton
Tangential Firing
Texas Region0
780 MW
ESP, Wet limestone scrubbers,
Overfire Air
0.14
0.27
780 MW
ESP,
Wet limestone scrubbers, Overfire Air
Subpart D Boilers,
Horizontally Opposed
0.08b
0.16b
0.01
0.02
730 MW
ESP, Wet limestone scrubbers
Overfire Air, Low-NOx burners
0.01
0.02
0.01
0.02
aAII of the source testing conducted at the stack after all controls.
bNonmethane nonethane hydrocarbons as propane.
Reference 16. All data are rated A.
4-48
-------
TABLE 4-15. N20 EMISSION FACTORS FOR EXTERNAL COMBUSTION OF
LIGNITE
Firing
configuration
Emission
factor
rating
N2O,
kg/Mg
Fluidized Beds E 1.24
Ib/ton
2.48
TABLE 4-16. METAL ENRICHMENT BEHAVIORS
Class
Description
Reference 38
Reference 39
Reference 40
Equal distribution
between fly ash and
bottom ash
Enriched in fly ash
Ala, Co, Fea, Mn, Ala, Co, Cr, Fea, Mn,
Sca, Tia Sca, Tia
III
IV
relative to bottom ash
Somewhere in
between Class I and
II, multiple behavior
Emitted in gas phase
As, Cd
Be, Cr, Ni, Mn
Hg
As, Cd, Pb, Sb
Cr, Ni
Hg
As, Cd, Pb, Sb
Ni
Hg
"Reference metals.
4-49
-------
TABLE 4-17. ENRICHMENT RATIOS FOR CLASSES OF ELEMENTS
Class
Description
Metals
Fly ash enrichment
ratio (ER)
I
lla
lib
lie
Nonvolatile
Volatile with varying
condensation on ash
particles
Very volatile, almost
no condensation
Cr, Sc, Ti, Fe
As, Cd, Pb, Sb
Be, Co, Ni
Mn
Hg, Se
ER * 1
ER>4
2
-------
TABLE 4-18. FLY ASH ENRICHMENT RATIOS FOR A BOILER AND CONTROL DEVICE2
Device
Pulverized
coal boiler
(10100301)
High efficiency
cold-side ESP
Sb
1.09
6.6
As Be
1.1 0.5
3 6
6.3
Cd Cr
0.6 0.9
1 7
3.0
Co
1.0
2
2.1
Pb
1.2
1
6.1
Mn
1.0
3
2.2
Hg
0.6
4
Ni
0.9
6
2.4
Se
1.0
7
4.5
Th
232
1.19
0.70
Th
228
1.20
U
238
1.24
0.86
Th
230
1.31
Ra
226
1.20
Pb
210
1.43
aAII enrichment ratios are rated E quality.
-------
TABLE 4-19. TRACE METAL EMISSION FACTORS (METRIC UNITS) FOR
UNCONTROLLED LIGNITE-FIRED BOILERS3
Firing As Be Cd
configuration
(SCC)
Pulverized Wet 1175 56 21-33
Bottom
(no SCC)
Pulverized Dry 598 56 21
Bottom
(no SCC)
Cyclone Furnace 101-272 56 13
(10100303)
Stoker 51
Configuration
Unknown
(no SCC)
Spreader Stoker 231-473 10-20
(10100306)
Traveling Grate 473-904 20-39
(Overfed) Stoker
(10100304)
Cr Mn Hg Ni
525-809 1917-7065 9 70-504
645-809 7043 9 404-504
109-809 1635 9 68-504
5130 9 303-504
486-809
aAII emission factors in pg/J. All emission factors are rated E.
4-52
-------
TABLE 4-20. TRACE METAL EMISSION FACTORS (ENGLISH UNITS) FOR
UNCONTROLLED LIGNITE-FIRED BOILERS3
Firing As E
configuration
(SCC)
Pulverized
(10100301)
e Cd Cr Mn
Hg Ni
Pulverized Wet 2730 131 49-77 1220- 4410-16,250 21 154-
Bottom 1880 1160
(no SCC)
Pulverized Dry 1390 131 49 1500- 16,200
Bottom 1880
(no SCC)
Cyclone Furnace 235-632 130 31 253- 3760
(10100303) 1880
Stoker 118 11800
Configuration
Unknown
(no SCC)
Spreader Stoker 538-
(10100306) 1100
Traveling Grate 1100-
(overfed) Stoker 2100
(10100304)
23-47 1130-
1880
47-90
21 928-
1160
21 157-
1160
21
696-
1160
aAII emission factors in lb/1012 Btu. All emission factors are rated E.
4-53
-------
TABLE 4-21. HAP EMISSION FACTORS (METRIC UNITS) FOR CONTROLLED
LIGNITE-FIRED BOILERS3
Boiler configuration
Pulverized Coal
(10100301)
Pulverized Wet Bottom
(no SCC)
Pulverized Dry Bottom
(no SCC)
Cyclone Furnace
(10100303)
Stoker
Configuration Unknown
(no SCC)
Spreader Stoker
(10100306)
Control device Cr Mn POM
Multi-cyclones 29-32
ESP 8.6
High Efficiency 0.99
Cold-Side ESP
ESP 14.7
Multi-cyclones 0.78-7.9b
ESP 18.1 1.1b
ESP <3.3 57.2 0.05c-0.68b
Multi-cyclones 711
Multi-cyclones 13 47.3
ESP <2.3
Multi-cyclones 6.3b
aAII emission factors in pg/J. All emission factors are rated E.
bPrimarily trimethyl propenyl naphthalene.
Primarily biphenyl.
4-54
-------
TABLE 4-22. HAP EMISSION FACTORS (ENGLISH UNITS) FOR CONTROLLED
LIGNITE-FIRED BOILERS3
Boiler configuration
Pulverized Coal
(10100301)
Pulverized Wet Bottom
(no SCC)
Pulverized Dry Bottom
(no SCC)
Cyclone Furnace
(10100303)
Stoker
Configuration Unknown
(no SCC)
Spreader Stoker
(10100306)
Control device Cr Mn POM
Multi-cyclones 67-74
ESP 20
High Efficiency 2.32
Cold-Side ESP
ESP 34.2
Multi-cyclones 1.8-1 8. 3b
ESP 42.2 2.6b
ESP 27.7 133 0.11c-1.6b
Multi-cyclones 1656
Multi-cyclones 30 110
ESP <5.4
Multi-cyclones 14.6b
aAII emission factors in lb/1012 Btu. All emission factors rated E.
bPrimarily trimethyl propenyl naphthalene.
Primarily biphenyl.
4-55
-------
TABLE 4-23. FILTERABLE PARTICULATE FOR LIGNITE-FIRED FLUIDIZED BED
COMBUSTORS WITH MULTICLONE CONTROLS
Fuel
Filterable Particulate,
cumulative mass percent less than stated size (microns)
0.625
1.00
1.25
2.50
6.00
10
15
Data
quality
rating
Reference
Gibbons
Creek lignite
<2
11
18
41
82
90
94
38
4-56
-------
REFERENCES FOR CHAPTER 4
1. Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition, Volume
12, John Wiley and Sons, New York, NY, 1967.
2. Gronhovd, G.H., et al., "Some Studies on Stack Emissions from Lignite Fired
Powerplants", Presented at the 1973 Lignite Symposium, Grand Forks, ND,
May 1973.
3. Standards Support and Environmental Impact Statement: Promulgated
Standards of Performance for Lignite Fired Steam Generators: Volumes I and
H, EPA-450/2-76-030a and 030b, U.S. Environmental Protection Agency,
Research Triangle Park, NC, December 1976.
4. 1965 Keystone Coal Buyers Manual. McGraw-Hill, Inc., New York, NY, 1965.
5. Source Test Data on Lignite-Fired Power Plants, North Dakota State
Department of Health, Bismarck, ND, December 1973.
6. Gronhovd, G.H., et al., "Comparison of Ash Fouling Tendencies of High and
Low Sodium Lignite from a North Dakota Mine", Proceedings of the American
Power Conference, Volume XXVIII, 1966.
7. Crawford, A.R., et al., Field Testing: Application of Combustion Modification to
Control NO. Emissions from Utility Boilers. EPA-650/2-74-066, U.S.
Environmental Protection Agency, Washington, DC, June 1974.
8. "Nitrogen Oxides Emission Measurements for Three Lignite Fired Power
Plants", Contract No. 68-02-1401 and 68-02-1404, Office Of Air Quality
Planning And Standards, U.S. Environmental Protection Agency, Research
Triangle Park, NC, 1974.
9. Coal Fired Power Plant Trace Element Study, A Three Station Comparison,
U.S. Environmental Protection Agency, Denver, CO, September 1975.
10. Castaldini, C. and M. Angwin, Boiler Design and Operating Variables Affecting
Uncontrolled Sulfur Emissions from Pulverized Coal Fired Steam Generators,
EPA-450/3-77-047, U.S. Environmental Protection Agency, Research Triangle
Park, NC, December 1977.
11. Shih, C.C., et al.. Emissions Assessment of Conventional Stationary
Combustion Systems, Volume III: External Combustion Sources for Electricity
Generation, EPA Contract No. 68-02-2197, TRW Inc., Redondo Beach, CA,
November 1980.
4-57
-------
12. Source test data on lignite fired cyclone boilers, North Dakota State Department
of Health, Bismarck, ND, March 1982.
13. Inhalable Particulate Source Category Report for External Combustion Sources,
EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA,
January 1985.
14. Personal communication dated September 18, 1981. Letter from North Dakota
Department of Health to Mr. Bill Lamason of the U.S. Environmental Protection
Agency, Research Triangle Park, NC, conveying stoker data package.
15. Source test data on lignite-fired power plants, North Dakota State Department
of Health, Bismarck, ND, April 1992.
16. Source test data on lignite-fired power plants, Texas Air Control Board, Austin,
TX, April 1992.
17. "Compilation of Air Pollutant Emission Factors (AP-42)", Section 1.7,
Supplement A, October 1986.
18. Results of Emission Inventory Test at the United Power Association
Stanton, N.D. Generating Plant, June 19, 20, 21, 1972.
19. "Technical Procedures for Developing AP-42 Emission Factors and
Preparing AP-42 Sections", Draft, U.S. Environmental Protection
Agency, Research Triangle Park, NC, March 1992.
20. Surveillance Project Report, Jamestown Plant of the Otter Tail Power
Company, May 1970.
21. Results of Stack Testing at the Jamestown and Devils Lake Generating
Station. November 28-29, 1972.
22. Particulate Emission Report for the Buelah Plant and the R. M. Heskett
Generating Stations, Montana Dakota Utilities Co., October 1971.
23. Summary of Tests Conducted on Boiler No. 3 at the Minnkota Grand
Forks Plant by the U.S. Bureau of Mines, November 17, 1971.
24. EPA/IFP European Workshop on the Emission of Nitrous Oxide from Fuel
Combustion, EPA Contract No. 68-02-4701, Ruiel-Malmaison, France, June 1-
2, 1988.
25. Clayton, R., et al., N20 Field Study. EPA-600/2-89-006, U.S. Environmental
Protection Agency, Research Triangle Park, NC, February 1989.
4-58
-------
26. Amand, L.E. and S. Anderson, "Emission of Nitrous Oxide from Fluidized Bed
Boilers," Presented at the 10th International Conference on Fluidized Bed
Combustor, San Francisco, CA, 1989.
27. Mann, M.D., et al., "Effect of Operating Parameters on N20 Emissions in a 1-
MWCFBC," Presented at the 8th Annual Pittsburgh Coal Conference,
Pittsburgh, PA, October, 1991.
28. Krishnan, R.E. and G.V. Helwig, "Trace Emissions from Coal and Oil
Combustion", Environmental Progress, 1(4): 290-295, 1982.
29. Brooks, G.W., M.B. Stockton, K.Kuhn, and G.D. Rives, Radian
Corporation, Locating and Estimating Air Emission from Source of
Polvcvclic Organic Matter (POM). EPA-450/4-84-007p, U.S.
Environmental Protection Agency, Research Triangle Park, NC, May
1988.
30. Shih, C.C, et al., Emissions Assessment of Conventional Stationary
Combustion Systems: Volume III. External Combustion Sources for
Electricity Generation, EPA-600/7-81-003a, U.S. Environmental
Protection Agency, Research Triangle Park, NC, November 1980.
31. Surprenant, N., et al.. Preliminary Emissions Assessment of
Conventional Stationary Combustion Systems: Volume II -Final Report,
EPA-600/2-76-046B, U.S. Environmental Protection Agency, Research
Triangle Park, NC, March 1976.
32. 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.
33. Regional Air Pollution Study - Point Source Emission Inventory,
Publication No. EPA-600/4-77-014 (NTIS No. PB 269567), March 1977.
34. Locating and Estimating Air Emissions from Sources of Chromium,
EPA-450/4-84-007g, U.S. Environmental Protection Agency, Research
Triangle Park, NC, July 1984.
35. Estimating Air Toxics Emissions from Coal and Oil Combustion
Sources, EPA-450/2-89-001, U.S. Environmental Protection Agency,
Research Triangle Park, NC, April 1989.
36. Evans, J.C., et al., "Characterization of Trace Constituents at Canadian
Coal-Fired Plants, Phase I: Final Report and Appendices", Report for
4-59
-------
the Canadian Electrical Association, R&D, Montreal, Quebec, Contract
Number 001G194.
37. Locating and Estimating Air Emissions from Sources of Manganese,
EPA-450/4-84-007h, U.S. Environmental Protection Agency, Research
Triangle Park, NC, September 1985.
38. Mann, M. P., et al., Fluidized Bed Combustion of Low Rank Coals,
DOE/FE/60181-2127, U.S. Department of Energy, Washington, D.C.,
September 1986.
39. Van Buren, D., D. Barbe, and A. W. Wyss, External Combustion Particulate
Emissions: Source Category Report, EPA-600/7-86-043, U.S. Environmental
Protection Agency, Research Triangle Park, NC, November 1986.
40. Bustard, C.J. et al., "Demonstration of a Pulse-Jet Fabric Filter at the TU
Electric Big Brown Station", presented at the Ninth Particulate Control
Symposium, Sessions 1B-3B, October 1991.
4-60
-------
5. AP-42 SECTION 1.7: LIGNITE COMBUSTION
The revision to Section 1.7 of AP-42 is presented in the following pages as it
would appear in the document. A marked-up copy of the 1986 version of this section is
included in Appendix B.
-------
APPENDIX A
CONVERSION FACTORS
A-38
-------
TABLE A-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.
A-39
-------
APPENDIX B
MARKED-UP 1986 AP-42 SECTION 1.7
B-40
-------
REPORT ON REVISIONS TO
5TH EDITION AP-42
Section 1.7
Lignite Combustion
Prepared for:
Contract No. 68-D2-0160, Work Assignment 50
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
August 2, 1996
-------
Table of Contents
Page
1.0 INTRODUCTION 1-1
2.0 REVISIONS 2-1
2.1 General Text Changes 2-1
2.2 Nitrogen Oxides, NOX 2-1
2.2.1 Uncontrolled NOX 2-1
2.2.2 Controlled NOX 2-1
2.3 Sulfur Oxides, SOX 2-2
2.3.1 Uncontrolled SOX 2-2
2.3.2 Controlled SOX 2-2
2.4 Carbon Monoxide, CO 2-3
2.4.1 Uncontrolled CO 2-3
2.4.2 Controlled CO 2-3
2.5 Particulate Matter, PM 2-4
2.5.1 Uncontrolled PM 2-4
2.5.2 Controlled PM 2-4
2.6 Particle Size Distribution 2-4
2.7 Trace Metals and Polycyclic Organic Matter (POM) 2-5
2.8 Greenhouse Gases 2-5
2.8.1 Carbon Dioxide, CO2 2-5
2.8.2 Methane, CH4 2-6
2.8.3 Nitrous Oxide, N2O 2-6
2.9 Toxic Air Pollutants 2-6
2.9.1 General Document Evaluation and Emission Factor Development.... 2-7
2.9.2 Description of Documents Evaluated 2-9
2.9.3 Emission Factor Development 2-33
3.0 REFERENCES 3-1
4.0 REVISED SECTION 1.7 4-1
5.0 EMISSION FACTOR DOCUMENTATION, APRIL 1993 5-1
APPENDIX A 5-2
in
-------
1.0 INTRODUCTION
This report supplements the Emission Factor (EMF) Documentation for AP-42
Section 1.7, Lignite 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 1.7 of AP-42 was reviewed by internal peer reviewers to identify technical
inadequacies and areas where state-of-the-art technological advances needed to be incorporated.
Based on this review, text was updated or modified to address any technical inadequacies or
provide clarification.
Emission factors 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.
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 1.7, and Section 5 contains the EMF
documentation dated April 1993.
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2.0 REVISIONS
2.1 General Text Changes
Information in the EMF Document and the Utility Boiler Alternative Control Techniques
(ACT) Document1 was used to enhance text concerning lignite characteristics; firing practices,
emissions and controls. Additionally, at the request of EPA, the metric units were removed.
2.2 Nitrogen Oxides. NO.,
2.2.1 Uncontrolled NOX
The factors were checked against information in Tables 4-2, 4-4, 4-6, and 4-9 of the EMF
Document and the 9/88 version of Section 1.7 and no changes were required.
2.2.2 Controlled NOX
The controlled NOX emission factors were changed from two categories of NOX controls
(tangential boilers with overfire air and tangential boilers with overfire air plus low NOX burners)
to three categories based on information in Table 4-10 of the EMF Document. The three
categories of boilers and NOX controls are Subpart D tangential boilers with overfire air; Subpart
D wall-fired boilers with overfire air plus low NOX burners; and Subpart Da tangential boilers
with overfire air. The changes made are shown in the following table:
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NOX Emission Factors for Controlled Lignite Boilers
Firing Configuration and NOX Control
Subpart D boilers, pulverized coal, tangential-fired
overfire air
Subpart D boilers, pulverized coal, wall-fired, overfire air
plus low NOX burners
Subpart Da boilers, pulverized coal, tangential-fired
overfire air
Revised NOX
Emission
Factor (Ib/ton)
6.8
4.6
6.0
Emission
Factor
Rating
C
C
C
2.3 Sulfur Oxides. S(X
2.3.1 Uncontrolled SOX
The factors were checked against information in Tables 4-1 and 4-9 of the EMF
Document and the 9/88 version of Section 1.7 and the following typographical error was
corrected for the Atmospheric Fluidized Bed Boiler category:
Source Category
Atmospheric Fluidized Bed
Previous Factor (Ib/ton)
30S
Revised Factor (Ib/ton)
10S
2.3.2 Controlled SOX
Table 4-10 of the EMF Document contained SOX emission factors for various lignite
boilers with SOX controls; however, this data was not included in the 4/93 version of AP-42. The
data were divided into four categories according to boiler age (i.e., Subpart D or Da) and SOX
control type (i.e., spray dryer or wet scrubber). The emission factors added are shown in the
following table:
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SOX Emission Factors for Controlled Lignite Boilers
Boiler Type and SO^ Control
Subpart D, pulverized coal, tangential and wall-fired,
spray dryer
Subpart D, pulverized coal, tangential-fired, wet scrubber
Subpart Da, pulverized coal, tangential-fired spray dryer
Subpart Da, pulverized coal, tangential-fired, wet
scrubber
SOX Emission
Factor (Ib/ton)
7.3S
16.8S
7.9S
3.7S
Rating
D
C
D
C
2.4 Carbon Monoxide. CO
2.4.1 Uncontrolled CO
The factors were checked against information in Tables 4-2, 4-9, and 4-10 of the EMF
Document and the 10/86 version of AP-42 and no changes were required.
2.4.2 Controlled CO
The controlled CO emission factors were changed from two categories (tangential boilers
with overfire air and tangential boilers with overfire air plus low NOX burners) to three categories
based on information in Table 4-10 of the EMF Document. Three categories of boilers and NOX
controls are Subpart D tangential boilers with overfire air; Subpart D wall-fired boilers with
overfire air plus low NOX burners; and Subpart Da tangential boilers with overfire air. (NOX
controls may affect CO emission whereas SO2 controls should not.) The changes made are
shown in the following table:
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CO Emission Factors for Controlled Lignite Boilers
Firing Configuration and Nox Control
Subpart D boilers, pulverized coal, tangential-fired
overfire air
Subpart D boilers, pulverized coal, wall-fired, overfire air
plux low NOX burners
Subpart Da boilers, pulverized coal, tangential-fired,
overfire air
Revised CO
Emission
Factor (Ib/ton)
No data
0.48
0.1
Emission
Factor
Rating
Not
applicable
D
D
2.5 Particulate Matter. PM
2.5.1 Uncontrolled PM
The uncontrolled PM emission factors were checked against information in Tables 4-3, 4-
5, 4-7, and 4-8 of the EMF Document and no changes were required.
2.5.2 Controlled PM
The controlled PM emission factors were checked against information in Tables 4-12 and
4-13 of the EMF Document and no changes were required.
2.6 Particle Size Distribution
The particle size factors remain the same as in the 10/86 version of AP-42.
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2.7 Trace Metals and Polvcvclic Organic Matter (POM)
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These emission factors were checked against information in Tables 4-18, 4-19, and 4-20
of the EMF Document and no changes were required. However, the controlled emission factors
for those metals were replaced with new factors. See Section 2.9, Toxic Air Pollutants.
2.8 Greenhouse Gases
2.8.1 Carbon Dioxide, CO2
CO2 emission factors for Table 1.7-2 were developed assuming 99 percent conversion of
fuel carbon content to carbon dioxide during combustion.2"4 An emission factor of 72.6C, where
C is carbon content (weight percentage based on an ultimate analysis, dry basis), was developed
using the following equation:
44 ton CO9 Ib CO9 i Ib CO9
2 x 0.99 x 2000 x —L— = 72.6 2
12 ton C ton CO2 100% ton - %C
Where: 44 = molecular weight of CO2;
12 = molecular weight of carbon; and
0.99 = fraction of fuel oxidized during combustion (Reference 2-4).
If an ultimate analysis is not available, a default CO2 emission factor was computed based
on the emission factor equation presented above and the average carbon content (dry basis) for
several U.S. lignite samples.5"8 Because of the variance of carbon content with the geographical
location of the mine, this default factor was assigned a "B" rating.
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Table 3-2. Default CO2 Emission Factors for U.S. Coals
Quality Rating: B
Fuel Type
Lignite
Average
%ca
63.4
Conversion Factor
72.6
Emission Factor
(Ib/ton coal)
4600
An average of the values given in References 5-8. Each of these references listed average
carbon contents based on extensive sampling of U.S. coals.
2.8.2 Methane, CH4
No emissions data were located.
2.8.3 Nitrous Oxide, N2O
No emissions data were located.
2.9 Toxic Air Pollutants
An evaluation of toxic emissions data resulted in the development of new factors that
were added to the section. In addition, the evaluation resulted in the replacement of controlled
emission factors for chromium and manganese because the new factors were of higher quality.
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.
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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. Originally, the intent was to
develop separate emission factors for the two sections, but after all data were assembled and
examined, the emission factors for the two types of combustion were very similar in value.
Because the factors were similar, it was decided to combine all data and develop one set of
emission factors that would represent bituminous/subbituminous coal combustion as well as
lignite combustion.
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 all congeners was included.
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 1.7 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 (FtHV) for coal in units of
2-8
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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.
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 9. Reference 9 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. Copies of each computer spreadsheet are included in Appendix A.
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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 not 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
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. Copies of the computer
spreadsheets that were constructed for each document (except Reference 9) 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 9
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.
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Reference 10
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 Babcock
and Wilcox (B&W) 860 MW boiler firing pulverized subbituminous coal from Montana. Unit
Three came on line in 1987. Emission 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 that came on line in 1976. During the
tests, both boilers were firing 70 percent Wyoming and 30 percent 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.
The document was assigned a data quality rating of "A."
Reference 11
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. Emission
controls utilized during the test were two electrostatic precipitators (ESPs) in series.
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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
FtHV 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 12
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 percent 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.
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.
2-12
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The reference was assigned a data quality rating of "B" because the coal feed rates during
the emissions test were not provided.
Reference 13
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 14
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 15
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 percent Rochelle and 20 percent 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.
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
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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 HHV 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 16
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. One other
test report from this facility is included in this documentation (Reference 15) and the boilers were
firing pulverized subbituminous coal during that test. 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 12 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 HHV for the coal
fired during the emissions test and, therefore, an HHV for coal of 8,547 Btu/lb presented in
Reference 15 (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 17
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 15
(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.
Reference 18
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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 9), the boiler
is a circulating bed AFBC and was firing subbituminous coal during the tests. Emission 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 cubic Normal
cubic meter. 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 percent
minus 7.3 percent (92.7 percent) 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 percent plus
7.3 percent (107.3 percent) to obtain a HHV of 10,252 Btu/lb for the coal, as fired. The as-fired
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coal HHV was used to convert the emission factors in units of lb/1012 Btu to factors in units of
Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 19
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/1012 Btu to
Ib/ton, the data from Run Two were used to develop emission factors. Pollutant concentrations
in ug/Nm3 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.
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This reference was assigned a data quality rating of "B" because the coal feed rate was not
provided.
Reference 20
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 lb/1012 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 percent The dry-basis HHV was converted to
an as-fired basis by dividing 13,733 Btu/lb by 104.12 percent, 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/1012 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 21
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 Combustion
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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/1012 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/1012 Btu to
factors in units of Ib/ton.
A data quality rating of "A" was assigned to this reference.
Reference 22
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 percent.
The dry-basis coal feed rate was converted to an as-fired basis by dividing 694,000 by
93.9 percent (100 percent - 6.1 percent), 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 lb/1012 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 percent. The as-fired coal HHV was used to convert the emission factors in units of
lb/1012 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 23
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. Emission 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 and 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 percent. The
dry-basis coal feed rate was converted to an as-fired basis by dividing 618,000 by 66.4 percent
(100 percent - 34.4 percent), 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/1012 Btu.
The reference indicates that all pollutants were detected in all sampling runs. The reference
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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/1012 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 24
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 PAHs. The results of the
sampling runs are presented as emission factors in unit of lb/1012 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 percent. The dry-basis HHV was
converted to an HHV on an as-fired basis by dividing 14,032 by 107 percent, resulting in a value
of 13,114. The as-fired coal HHV 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.
Reference 25
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
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was burning pulverized subbituminous coal from the Powder River regions 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 polycyclic aromatic
hydrocarbons (PAHs) and the results 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 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 percent. The dry-basis HHV was converted to an as-fired HHV of 9,252 Btu/lb by dividing
11,981 by 129.5 percent. The as-fired coal HHV was used to convert the emission factors in
units of lb/1012 Btu to factors in units of Ib/ton.
This report was assigned a data quality rating of "A."
Reference 26
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 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.
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The test runs results are presented as emission factors in units of lb/1012 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 percent. The dry-basis HHV was converted to an as-fired
HHV by dividing 10,190 by 114 percent, resulting in a value of 8,939. The as-fired coal HHV
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.
Reference 27
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 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 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/1012 Btu to factors in units of Ib/ton.
This report was assigned a data quality rating of "A."
Reference 28
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
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boiler operating conditions, baseline and reburn. Emission 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 lb/1012 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 percent. The dry-basis HHV
was converted to an as-fired basis by dividing 13,490 by 115.6 percent, 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 percent. The dry-basis HHV was
converted to an as-fired HHV by dividing 13,280 by 112.5 percent, 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/1012 Btu to factors in units of Ib/ton.
This reference was assigned a quality rating of "A."
Reference 29
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. Emission controls in use during both phases
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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/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 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 the
facility designated as EPRI Site 111 (Reference 27) where the boiler was firing a Western
bituminous coal reports a moisture content of 9.8 percent. 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 percent, 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 lb/1012 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.
Reference 30
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 9), this boiler is tangentially-fired. The unit was burning pulverized
subbituminous coal from the Lee Ranch Mine in New Mexico during the emissions tests.
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Emission 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 lb/1012 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 lb/1012 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 31
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. Emission
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 lb/1012 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 Btu/lb. This value was used to convert the emission factors in units of lb/1012 Btu to
factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 32
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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. Emission 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/1012 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/1012 Btu to
factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 33
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.
Emission controls used during the test were an ESP.
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/1012 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/1012 Btu to factors in units of Ib/ton.
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This reference was assigned a data quality rating of "A."
Reference 34
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.
Emission 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/1012 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/1012 Btu to factors in units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 35
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
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develop AP-42 emission factors. The emissions test results are reported as emission factors
expressed in units of lb/1012 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 36
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 9) indicates that the boiler was burning pulverized bituminous coal
from Virginia and Kentucky during the emissions test. Emission controls in use during the test
were low NOX burners with overfire air and an ESP.
Three sampling runs were conducted for metals and various organics and the emissions
results 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 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 percent. The average dry-basis HHV
was divided by 103.8 percent 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/1012 Btu to factors in units of
Ib/ton.
This reference was assigned a data quality rating of "A."
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Reference 37
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 lb/1012 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 lb/1012 Btu to factors in
units of Ib/ton.
This reference was assigned a data quality rating of "A."
Reference 38
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.
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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 percent 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.
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 percent) and petroleum coke (10 percent) 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 (90 percent) and coke (6 percent) 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
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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.
December 28. 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 flue gas desulfurization system (FGD) 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
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
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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
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 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
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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
31 and Reference 32, 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
except for factors from Reference 31 and Reference 32. 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
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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.
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 9 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
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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 1.7, then the
factor should be used. The emission factor equations are provided in Table 1.
Hydrogen Chloride and Hydrogen Fluoride Emission Factors
All HC1 and HF emission factors were obtained from Reference 38. These factors are
shown in Table 2. 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.
Dioxin/Furan. 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. The
emission factors for dioxins/furans are from bituminous and subbituminous coal only. None of
the factors are from lignite combustion. For this reason, it was decided to include the dioxin/
furan emission factors that were developed for AP-42 in Section 1.1 Bituminous and
Subbituminous Coal Combustion but not in Section 1.7 Lignite Combustion. The factors for
metals, PAHs, and organics are 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. These factors are included in both Section 1.1
and Section 1.7.
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Copies of the spreadsheets used to develop the metals, PAHs, and various organic
emission factors are shown in Tables 3, 4, and 5, respectively.
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-------
Table 1. METALS EMISSION FACTOR EQUATIONS FOR SECTION 1-7
a,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)a69
Lead 3.4x (C/AxPM)a8°
Manganese 3.8 x (C/A x PM)a6°
Nickel 4.4 x (C/A x PM)a48
a Reference 9.
b 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.
c C = 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 particulate matter, (lb/106 Btu).
2-39
-------
Table 2. Data Used to Develop Hydrogen Chloride and Hydrogen Fluoride Emission Factors for Section 1.7 of AP-42
a,b
Boiler SCC Descriptions
Commercial/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
Electric Generation and Industrial Boilers
Bituminous and Subbituminous Coal Firing Types
Pulverized Coal Wet Bottom
Pulverized Coal Dry Bottom
Cyclone Furnace
Source Classification Codesc
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
1-01-002-01/21
1-02-002-01/21
1-01-002-02/22
1-02-002-02/22
1-01-002-03/23
Hydrogen Chloride
(lb/tonc
*1.48
*1.9
Hydrogen Fluoride
(Ib/ton)
*0.17
*0.23
(continued)
-------
Table 2. Data Used to Develop Hydrogen Chloride and Hydrogen Fluoride
Emission Factors for Section 1.7 of AP-42 (Continued)3 b
Boiler SCC Descriptions
Source Classification Codesc
1-02-002-03/23
Hydrogen Chloride
(lb/tonc
Hydrogen Fluoride
(Ib/ton)
(continued)
-------
Table 2. Data Used to Develop Hydrogen Chloride and Hydrogen Fluoride
Emission Factors for Section 1.7 of AP-42 (Continued)3 b
Boiler SCC Descriptions
Spreader Stoker
Traveling Grate Overfeed Stoker
Overfeed Stoker
Pulverized Coal Dry Bottom, Tangential Firing
Atmospheric Fluidized Bed
Underfeed Stoker
Commercial/Industrial Boilers
Lignite Firing Types
Pulverized Coal
Pulverized Coal Tangential Firing
Traveling Grate Overfeed Stoker
Spreader Stoker
Source Classification Codesc
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
1-01-002-17
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
Hydrogen Chloride
(lb/tonc
*0.351
Hydrogen Fluoride
(Ib/ton)
*0.063
(continued)
-------
Table 2. Data Used to Develop Hydrogen Chloride and Hydrogen Fluoride
Emission Factors for Section 1.7 of AP-42 (Continued)3 b
Boiler SCC Descriptions
Electric Generation and Industrial Boilers
Lignite Firing Types
Pulverized Coal
Pulverized Coal Tangential Firing
Cyclone Furnace
Traveling Grate Overfeed Stoker
Spreader Stoker
Source Classification Codesc
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 Chloride
(lb/tonc
0.01
1.2
B
Hydrogen Fluoride
(Ib/ton)
0.01
0.15
B
§
w
•g
I
a
to
3 All factors are from Reference 9.
b Factors are for both uncontrolled and controlled boilers.
0 An asterisk to the left of a factor indicates that it was used in calculating the overall emission factor.
-------
TABLE 3. DATA USED TO DEVELOP CONTROLLED METALS
EMISSION FACTORS FOR SECTION 1.7 OF AP-42
Reference
No.
10
10
11
12
13
14
15
16
17
18
19
20
21
22
No.
of
Boilers
1
2
3
1
4
2
2
2
1
1
1
1
1
1
Fuel Type
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Subbituminou
s
Bituminous
Bituminous
Bituminous
Boiler
Type8
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
MW
860
750
ea.
—
137
—
—
750
ea.
750
ea.
860
110
700
700
600
1,160
sec
10100222
10100222
10100222
10100238
10100222
10100222
10100222
10100222
10100222
10100238
10100226
10100202
10100212
10100202
Control
Device
1"
FGD-
SDA
FGD-
VSST
ESP
Cyclone
ESPC
FF
FGD-
VSST
FGD-
VSST
FGD-
SDA
FGD-
FIL
OFA
ESP
ESP
ESP
Control
Device
2"
FF
none
ESP
ESP
none
none
none
none
FF
FF
FGD-W
LS
FGD-W
LS
none
none
Control
Device
3"
none
none
none
ESP
none
none
none
none
none
none
ESP
none
none
none
Data
Quality
A
A
B
B
B
B
B
B
B
A
B
A
A
A
No.
of
Test
Runs0
3
3
3
3
3
3
3
3
3
1
1
2
3
3
Antimonyc'd
—
—
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
Arsenicc>d
—
—
*1.06e-05
*9.03e-06
*5.63e-06
*1.89e-05
*4.42e-05
*4.26e-05
*4.14e-07
DL/2
1.03e-05
DL/2
*1.41e-05
*1.19e-05
*3.38e-04
*2.01e-04
Beryllium^"
—
—
1.16e-06
DL/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-06
DL/2
2.11e-06
DL/2
*1.04e-05
*3.08e-05
Cadmium011
—
—
*5.31e-05
*l.lle-04
*l.lle-05
*4.83e-04
*1.80e-05
*4.78e-05
—
4.10e-06
DL/2
*1.83e-05
*3. 17e-05
*8.06e-05
*3.30e-06
Chromium''11
—
—
*4.89e-05
*1. 08e-04
*1. 18e-04
*2.35e-04
*1. 95e-04
*1.34e-04
*1. 59e-04
*3.28e-05
*9.87e-05
*9.23e-05
*3.12e-04
*3.30e-04
Chromium
VP"
—
—
—
—
—
—
—
—
* 1.49e-05
—
—
—
—
—
Cobalt"
—
—
—
—
—
—
—
—
—
8.20e-
06 DL/2
*2.40e-
05
1.32e-
05 DL/2
*5.20e-
05
*1.32e-
04
(continued)
-------
Table 3. Data Used to Develop Controlled Metals Emission Factors
for Section 1.7 of AP-42 (Continued)3 b
Reference
No.
23
24
25
26
27
28
28
29
29
30
31
32
33
No.
of
Boilers
1
1
1
1
1
1
1
1
1
1
1
1
1
Fuel Type
Lignite
Bituminous
Subbituminou
s
Subbituminou
s
Subbituminou
s
Bituminous
Bituminous
Bituminous
Bituminous
Subbituminou
s
Bituminous
Lignite
Bituminous
Boiler
Type8
PC
PC,
DB,0
PC,
DB,0
PC,
DB,W
PC,DB
Cy-
clone
Cy-
clone
PC,DB
PC,DB
PC,
DB,T
Cy-
clone
PC,
DB,T
Cy-
clone
MW
680
667
700
800
267
100
100
117
117
422
108
550
568
sec
10100301
10100202
10100222
10100222
10100222
10100203
10100203
10100202
10100202
10100226
10100203
10100302
10100203
Control
Device
1"
ESP
ESP
ESP
LNB
LNB
ESP
Rebum/
OFA
LNB/
OFA
LNB/
OFA
LNB/
OFA
ESP
ESP
ESP
Control
Device
2b
FGD-W
LS
FGD-W
LS
none
FF
FGD-SD
none
ESP
FF
SNCR
FGD-SD
A
none
FGD-W
LS
none
Control
Device
3"
none
none
none
FGD-W
LS
FF
none
none
none
FF
FF
none
none
none
Data
Quality
A
A
A
A
A
A
A
B
B
A
A
A
A
No.
of
Test
Runsc
4
8
3
2
2
3
3
3
3
3
3
3
3
Antimonyc>d
8.70e-06
DL/2
—
3.52e-05
DL/2
—
—
—
—
—
—
*7.75e-07
4.39e-06
DL/2
*2.24e-06
*3.23e-05
Arsenicc>d
*8.52e-06
*1.62e-04
*1.61e-06
*6.08e-06
2.11e-06
DL/2
*1.63e-04
*1.89e-04
*1.72e-05
*3.45e-06
*2.83e-06
*1.02e-03
*1.50e-05
*2.85e-04
Beryllium0"11
*4.73e-06
*3.41e-06
2.87e-07
DL/2
*6.44e-07
—
*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
Cadmiumc>d
*9.46e-06
*1.49e-05
*2.96e-06
*7.15e-06
2.11e-05
DL/2
*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
Chromium0'1'
*3.79e-05
*7.19e-05
*9.81e-06
*3.93e-05
4.31e-05
DL/2
*3.27e-04
*1.09e-04
*1.51e-05
*6.91e-06
*1.89e-06
*7.31e-05
—
*1.08e-03
Chromium
VP"
—
—
—
—
—
—
—
—
—
—
—
—
—
Cobalt"
*9.33e-
06
*1.08e-
04
6.50-06
DL/2
*2.32e-
06
—
—
—
2.52e-
06 DL/2
2.65e-
06 DL/2
2.84e-
06 DL/2
*1.46e-
06 DL/2
*1.87e-
05
*1.45e-
04
(continued)
-------
Table 3. Data Used to Develop Controlled Metals Emission Factors
for Section 1.7 of AP-42 (Continued)3 b
Reference
No.
34
35
36
37
Average
Factor
Quality
Rating
No.
of
Boilers
1
1
1
1
Fuel Type
Subbituminou
s
Bituminous
Bituminous
Bituminous
Boiler
Type8
PC,DB
PC,DB
PC,DB
Cy-
clone
MW
69
615
500
275
sec
10100222
10100202
10100202
10100203
Control
Device
1"
FF
ESP
LNB/
OFA
ESP
Control
Device
2b
none
none
ESP
none
Control
Device
3"
none
none
none
none
Data
Quality
A
C
A
A
No.
of
Test
Runs0
3
3
3
3
Antimony0'"
5.95e-06
DL/2
*6.14e-05
—
1.84e-05
A
Arsenic0'"
*5.70e-06
*9.07e-05
*2.92e-03
*5.42e-03
4.08e-04
A
Beryllium01"
1.14e-06
DL/2
*1.82e-06
*8.24e-05
*9.86e-05
2.12e-05
A
Cadmium0'"
5.70e-06
DL/2
*2.20e-05
*9.57e-05
*8.88e-05
5.08e-05
A
Chromium01"
*3.59e-05
*1.95e-04
*5.58e-04
*2.47e-03
2.55e-04
A
Chromium
VI0-"
*1.44e-04
—
7.95e-05
D
Cobalt"
*1.23e-
05
*1.64e-
05
*1.73e-
04
*6.41e-
04
1.03e-
04
A
a PC = Pulverized Coal, DB = Dry Bottom, T = Tangential, O = Opposed, W = Wall, AFBC = Atmospheric Fluidized Bed Combustor, CB = Circulating Bed.
b ESP = 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.
c An asterisk before a factor indicates that the factor was used in calculating the overall average.
d A "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.
-------
Table 4. Data Used to Develop Controlled PAH Emission Factors for Section 1.7 of AP-42
Ref.
No.
29
34
35
37
39
41
42
43
44
45
46
No. of
Boilers
1
1
1
1
1
1
1
1
1
1
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 1"
OFA
ESP
ESP
LNB
LNB/OFA
ESP
ESP
ESP
FF
ESP
LNB/OFA
Control
Device 2"
FGD-WLS
FGD-WLS
none
FGD-SD
FF
none
FGD-WLS
none
none
none
ESP
Control
Device 3b
ESP
none
none
FF
none
none
none
none
none
none
none
Data
Quality
B
A
A
A
B
A
A
A
A
C
A
No.
of
Test
Runs'
1
7
3
2
3
3
3
3
3
3
3
Biphenyl"1
...
...
*3.06e-06
*2.87e-07
9.35e-06 DL/2
1.57e-06DL/2
...
...
1.67e-06
D
Acenaphthene"'11
...
*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-
thyleneca
...
*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
Anthracene'1'1
...
*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)-
anthracene'1"
...
*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)-
pyrenec><1
...
*4.72e-08
*2.04e-08
4.01e-08
DL/2
2.92e-08
DL/2
*1.12e-08
5.80e-09
DL/2
*3.68e-09
...
*1.09e-07
3.83e-08
D
Benzo(b,j,k)-
fluoranthened
...
*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
§
w
•g
I
a
to
PC = Pulverized Coal, DB = Dry Bottom, T = Tangential, O = Opposed.
ESP = 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 the factor was used in calculating the overall average.
A "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.
-------
Table 5. Data Used to Develop Organic Emission Factors for Section 1.7 of AP-42
Referenc
eNo.
23
24
24
28
29
30
31
34
35
36
37
38
38
39
41
42
43
44
45
No. of
Boilers
4
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Coal Type
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Subbituminous
Subbituminous
Subbituminous
Bituminous
Bituminous
Bituminous
Bituminous
Lignite
Bituminous
Subbituminous
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
MW
—
—
110
700
700
600
667
700
800
267
100
100
117
108
550
568
69
615
sec
10100222
10100222
10100222
10100238
10100226
10100202
10100212
10100202
10100222
10100222
10100222
10100203
10100203
10100202
10100203
10100302
10100203
10100222
10100202
Control
Device lb
ESP
FF
FF
FGD-FIL
OFA
ESP
ESP
ESP
ESP
LNB
LNB
ESP
Reburn/O
FA
LNB/OFA
ESP
ESP
ESP
FF
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
Control
Device 3'
none
none
none
none
ESP
none
none
none
none
FGD-WLS
FF
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
No. of Test
Runsc
3
3
3
1
1
2
3
7
3
2
2
3
3
3
3
3
3
3
3
Acetaldehyde"'11
—
—
...
...
...
...
*6.07e-05
*3.07e-05 DL/2
*2.17e-03
*8.35e-04
*2.91e-04
*9.60e-06 DL/2
...
Acetophenone'''1
...
...
...
...
...
...
...
*1.55e-05
*6.76e-06
*2.62e-05
*1.25e-05
...
Acroleinc'd
...
...
...
...
...
...
...
*9.99e-04
*1.37e-05
DL/2
*7.55e-05
*5.98e-05
...
Benzene1'4
*5.45e-07
DL/2
*1.66e-02
6.30e-04
DL/2
*4.10e-05
*1.82e-05
*2.08e-05
*1.02e-05
*4.23e-04
*5.37e-05
*2.46e-05
*5.95e-05
*1.93e-04
*5.11e-04
*2.57e-03
*1.81e-03
*8.84e-05
Benzylchloride'''1
...
...
...
...
...
...
...
1.44e-07DL/2
*7.10e-08
...
*1.40e-03
bis(2-ethyl-
hexyl-
phthalatec'd
...
...
*9.24e-05
...
...
...
...
...
...
*9.78e-05
*2.96e-05
...
Bromo-
form11
...
...
...
...
...
...
...
5.85e-05
*3.86e-05
...
...
(continued)
-------
Table 5. Data Used to Develop Organic Emission Factors for Section 1.7 of AP-42 (Continued)
Referenc
eNo.
46
47
No. of
Boilers
1
1
Average Factor
Quality Rating
Coal Type
Bituminous
Bituminous
Boiler
Type"
PC,DB
Cyclone
MW
500
275
sec
10100202
10100203
Control
Device lb
LNB/OFA
ESP
Control
Device 2b
ESP
none
Control
Device 3'
none
none
Data
Quality
A
A
No. of Test
Runsc
3
3
Acetaldehyde"'11
...
5.66e-04
C
Acetophenone'''1
...
1.52e-05
D
Acroleinc'd
...
2.87e-04
D
Benzene1'4
*1.36e-05
*1.92e-04
1.33e-03
A
Benzylchloride'''1
...
7.00e-04
D
bis(2-ethyl-
hexyl-
phthalatec'd
...
7.33e-05
D
Bromo-
form11
...
3.86e-05
E
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 the detection limit.
-------
3.0 REFERENCES
1. 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.
2. G. Marland and R.M. Rotty, "Carbon Dioxide Emissions from Fossil Fuels: A procedure
for Estimation and Results for 1951-1981," DOE/NBB-0036 TR-003, Carbon Dioxide
Research Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge,
TN, 1983.
3. A. Rosland, Greenhouse Gas Emissions In Norway: Inventories And Estimation
Methods, Oslo: Ministry of Environment, 1993.
4. 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.
5. "Alternative Control Techniques Document—NOX Emissions From Utility Boilers,"
(1994) EPA-453/R-94-023, Office of Air Quality Standards, Research Triangle Park,
NC.
6. "Evaluation of Significant Anthropogenic Sources of Radiatively Important Trace
Gases," (1990) PB91-127753, report prepared for the U.S. EPA, Alliance Technologies
Corporation, Chapel Hill, NC.
7. Steam: Its Generation And Use, Babcock and Wilcox, New York, 1975.
8. R. A. Winschel, "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.
9. Electric Utility Trace Substances Synthesis Report, Volume I, Electric Power Research
Institute, Palo Alto, CA, November 1994.
10. Results of the September 10 and 11, 1991 Mercury Removal Tests on the Units 1 & 2,
and Unit 3 Scrubber Systems at the NSP Sherco Plant in Becker, Minnesota, Interpoll
Laboratories, Inc., Circle Pines, MN, October 30, 1991.
11. 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.
5-1
-------
12. 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.
13. 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.
14. 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.
15. 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.
16. 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.
17. 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.
18. Field Chemical Emissions Monitoring Project: Site 10 Emissions Monitoring, Radian
Corporation, Austin, TX, October 1992.
19. Field Chemical Emissions Monitoring Project: Site 11 Emissions Monitoring, Radian
Corporation, Austin, TX, October 1992.
20. Field Chemical Emissions Monitoring Project: Site 12 Emissions Monitoring, Radian
Corporation, Austin, TX, November 1992.
21. Field Chemical Emissions Monitoring Project: Site 15 Emissions Monitoring, Radian
Corporation, Austin, TX, October 1992.
22. Field Chemical Emissions Monitoring Project: Site 19 Emissions Monitoring, Radian
Corporation, Austin, TX, April 1993.
23. Field Chemical Emissions Monitoring Project: Site 20 Emissions Monitoring, Radian
Corporation, Austin, TX, March 1994.
24. Field Chemical Emissions Monitoring Project: Site 21 Emissions Monitoring, Radian
Corporation, Austin, TX, August 1993.
5-2
-------
25. Field Chemical Emissions Monitoring Project: Site 22 Emissions Report, Radian
Corporation, Austin, TX, February 1994.
26. Field Chemical Emissions Monitoring Project: Site 101 Emissions Report, Radian
Corporation, Austin, TX, October 1994.
27. Field Chemical Emissions Monitoring Project: Site 111 Emissions Report, Radian
Corporation, Austin, TX, May 1993.
28. Field Chemical Emissions Monitoring Project: Site 114 Report, Radian Corporation,
Austin, TX, May 1994.
29. Field Chemical Emissions Monitoring Project: Site 115 Emissions Report, Radian
Corporation, Austin, TX, November 1994.
30. Characterizing Toxic Emissions from a Coal-Fired Power Plant Demonstrating the AFGD
ICCT Project and a Plant Utilizing a Dry Scrubber/Baghouse System, Final Draft Report,
Springerville Generating Station Unit No. 2, Southern Research Institute, Birmingham,
Alabama, December 1993.
31. 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, OH,
December 29, 1993.
32. 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.
33. Toxics Assessment Report, Illinois Power Company, Baldwin Power Station—Unit 2,
Baldwin, Illinois, Volumes I—Main Report, Roy F. Weston, Inc., West Chester, PA,
December 1993.
34. Toxics Assessment Report, Minnesota Power Company Boswell Energy Center—Unit 2,
Cohasset, Minnesota, Volume 1—Main Report, Roy F. Weston, Inc., West Chester, PA,
December 1993.
35. 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.
36. 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.
5-3
-------
37. Field Chemical Emissions Monitoring Report: Site 122, Final Report, Task 1 Third
Draft, EPRIRP9028-10, Southern Research Institute, Birmingham, AL, May 1995.
3 8. Hydrogen Chloride And Hydrogen Fluoride Emission Factors For The NAPAP
Inventory, EPA-600/7-85-041, U. S. Environmental Protection Agency, October 1985.
5-4
-------
4.0 RE VISED SECTION 1.7
This section contains the revised Section 1.7 of AP-42, 5th Edition. The electronic
version can be located on the EPA TTN at http://134.67.104.12/html/chief/fsnpub.htm.
4-1
-------
5.0 EMIS SIGN FACTOR DOCUMENT, APRIL 1993
This section contains the complete Emission Factor Document for Section 1.7, Lignite
Combustion, dated April 1993. The electronic version can be located on the EPA TTN at
http://134.67.104.12/html/chief/fbgdocs.htm. The zipped file on the TTN contains this (1996)
background report as well as the 1993 Emission Factor Documentation.
5-1
-------
Appendix A
-------
REFERENCE 19 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
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
"Page 8.
bPage 9.
C40 CFR Pt 60, Appendix 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.
"Page 1.
gPage 5.
A-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
A-2
-------
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.
A-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 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
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.
A-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 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
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
3Page 5.
bDivide emission rate by coal feed rate.
A-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 P
Control device 2e
Data Quality
Process Parameters6
Test methodsf
Number of test runs8
3Page 22.
bPage 29.
cPage 29.
dSection 4 Results of Fuel Analyses.
ePage 1. Assumed dry bottom.
fPage 1.
8Various pages.
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
A-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
Molybdenumb
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
A-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
Molybdenum13
Nickel
Potassium
Selenium
Silver
SO2
Sodium
Strontium
Vanadium
Zinc
3Table 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
A-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
"Page 20.
bPage25.
cPage25.
dPage31
ePage 1. Coal from Antelope/Northern Antelope is subbituminous, according to another report.
fPage 1.
gVarious pages.
A-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
A-ll
-------
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
3Page 1 1
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
A-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 P
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
9,780
3,079
8,498
16,996,000
181
Run 3
7.80
815,076
48,904,560
9,780
3,134
8,498
16,996,000
184
Pulverized, dry bottom
Rochelle
10100222
ESPC
None
B
Watertube boilers
Had to use F-factor and average HHV to get
coal feed rate, ton/hr.
with economizers and
air preheaters
MM 5 metals, Method 18 for BTEX
3
"Page 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.
A-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
A-14
-------
REFERENCE 23 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 13 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS
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
(lb/ton)c 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.
A-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
Toluene*3
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
^age 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
A-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:
UNIT NO.:
LOCATION:
FILENAME
NSP Riverside
6,7
Minneapolis, Mn
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 Had to use F-factor and average HHV to get
coal feed rate (ton/hr)
575,000 Ib/hr steam each; equipped with economizers and air
preheaters.
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)
Unit 6
Run 1 Run 2
193,851 189,541
11,631,060 11,372,460 11,
9,780 9,780
6.00 6.00
848 829
8,602 8,602
17,204,000 17,204,000 17,
49.28 48.19
Run 3
187,122
227,320
9,780
6.60
785
8,602
204,000
45.66
A-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)
3Page 1. Assumed dry bottom.
bPage 2.
cPage 1, 3, 24.
dVarious pages.
ePage 29 for Unit 6 metals, Page 30 for Unit 7
fPage 28.
8Page 23 for Unit 6 metals, Page 24 for Unit 7
hPage 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
A-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
A-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
"Table 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
Toluene*3
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
A-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)°
Benzene*3
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
A-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 le
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
3Page 7.
bPage 8.
C40 CFR Pt 60, App A.
dPageG-l.
ePage 1.
fPage 1.
gVarious pages.
A-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
3Page 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.
A-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
3Page 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
A-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 le
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
3Page 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.
A-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
A-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
3Pages 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
A-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 type6
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
A-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
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
average HHV to get coal
for all others.
3Page 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 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 for MM5, page 2 for MM 13.
8Various pages.
METALS EMISSION FACTORS
EMISSION RATES (lb/hr)a
Aluminum
Antimony
Arsenicb
Bariumb
Beryllium
Boron
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum13
Nickel
Potassium
Seleniumb
Silverb
Run 1 Run 2
1.91 0.493
7.09e-03 1.62e-03
4.12e-04
0.048 0.049
1.61e-05 4.93e-05
19.1 3.28
1.91
0.114 0.0682
0.789 0.384
1.04 0.759
0.123 0.0394
0.294 0.123
0.0565 0.382
0.0411 0.0172
0.032 0.033
0.0736
1.83 0.624
0.0199 0.0205
2.41e-03 2.43e-03
Run 3 AVG
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
A-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
Arsenic*3
Bariumb
Beryllium
Boron
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenumb
Nickel
Potassium
Selenium*3
Silver13
Sodium
Strontium
Vanadium13
Zinc
3Pages 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
A-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
3Page 8.
bDivide emission rate by coal feed rate.
A-31
-------
REFERENCE 28 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 18 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 typec
Boiler configurationd
Coal source0
sec
Control device P
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.
A-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
Formaldehyde13
Benzene
3Page 3-12
bEmission factor
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
is based only on detection limits.
(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
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
A-33
-------
REFERENCE 28 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 18 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
3Page 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.
eDivide emission rate by coal feed rate.
A-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 received (Btu/lb)3
Coal HHV, as received (MMBtu/lb)
Coal HHV, as received (MMBtu/ton)
Coal feed rate as received (ton/hr)
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
395.70
A-35
-------
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 19 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
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
Phosphorousb
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)
NR(20)
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
20
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
18.63
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
1.16e-09
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
1.12e-01
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
2.82e-04
A-36
-------
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
Naphthalene13
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
3Page 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.
A-37
-------
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 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)
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.
A-38
-------
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
Beryllium*3
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
3Page 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
A-39
-------
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.
A-40
-------
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
Formaldehydeb
Toluene
3Page 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
A-41
-------
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
25
13,467
6.1%
12,693
,385,485
25.4
694,000
6.1%
739,084
369.54
,000,000
3Page2-l.
bPage 2-1. Assumed dry bottom.
cPage2-l.
dPage 2-2.
eAppendix A.
fPage 3-7.
8Page 3-5.
hPage 3-8.
A-42
-------
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
3Page 3-8.
bMultiplv emission factor.
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
Ib/MMBtu. bv coal HHV. MMBtu/ton.
A-43
-------
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
"Page 3-9.
bMultiply concentration 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
A-44
-------
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 Desulfurization- 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.
A-45
-------
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
A-46
-------
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, b>
Antimony EMISSION FACTOR: Note
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>c
Antimony emission rate (ug/hr)d
Antimony emission rate (lb/hr)e
Antimony emission factor (lb/ton)f
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
' coal HHV, MMBtu/ton.
that antimony was not detected in
Run 1
630,000
33.5%
947,368
474
3,100,000
1.31
4,061,000
8.95e-03
1.89e-05
"Page 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.
A-47
-------
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
A-48
-------
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
A-49
-------
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
A-50
-------
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
Beryllium*3
Cadmium
Chloride
Chromium
Cobaltb
Copper
Fluoride
Lead
Manganese
Mercury
Molybdenum
Nickel
Phosphorous
Selenium
Vanadium
Aluminum
Antimony*3
Calcium
Iron
Magnesium
Potassium13
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.
A-51
-------
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
3Page3-14..
bEmission factor is based only on detection
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
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)3
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
A-52
-------
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
3Page3-15.
bEmission factor is based only on detection
Emission Factor
(lb/10A12 Btu)a
3.6e-06
6.2e-06
7.3e-06
3.5e-06
2.2e-06
4.2e-06
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
A-53
-------
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 T
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 Desulrurization- 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.
A-54
-------
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
A-55
-------
REFERENCE 37 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 27 OF AP-42 SECTION 1.7 BACKGROUND 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 Desulrurization- 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.
A-56
-------
REFERENCE 37 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 27 OF AP-42 SECTION 1.7 BACKGROUND 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
3Page3-15.
bEmission factor is based
°Multiply emission factor
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
only on detection limits.
, Ib/MMBtu, by coal HHV, MMBtu/ton.
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
A-57
-------
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.
"Pages 3-8 and 3-9.
dPages3-4&3-5.
A-58
-------
REFERENCE 38 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 28 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
EMISSION FACTORS- BASELINE
Pollutant
Arsenic
Beryllium
Cadmium
Chromium
Manganese
Nickel
Lead
Selenium
Mercury
Chloride
Fluoride
Benzene
Toluene
PAHsb
Formaldehyde
Acetaldehyde
CONDITION
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
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
3Page 3-10.
bND = not detected in three runs, no EF calculated. See page 3-8.
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
A-59
-------
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
"Page 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.
A-60
-------
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 methodsd
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.
A-61
-------
REFERENCE 39 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 29 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
EMISSION FACTORS- PHASE
Pollutant
Arsenic
Barium
Beryllium0
Cadmium
Chromium
Cobalt0
Copper
Lead
Manganese
Mercury0
Molybdenum
Nickelb
Phosphorus
Selenium
Vanadium
Chloride
Fluoride
Benzene
Toluene
Formaldehyde
Cyanide
Naphthalene
I
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.
A-62
-------
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
Beryllium*3
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
3Page 37.
bEmission factor is based only on detection limits.
°Multiply emission factor, Ib/MMBtu,
by coal HHV, MMBtu/ton.
A-63
-------
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 Desulrurization- 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.
A-64
-------
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
3Page 1-11.
bEmission factor is based
°Multiply emission factor
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
only on detection limits.
, Ib/MMBtu, by coal HHV, MMBtu/ton
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
A-65
-------
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
(lb/10A12 Btu)
1114
0.18
42
5.4
0.19
0.07
Emission Factor Emission Factor0
(Ib/MMBtu)
l.lle-03
1.80e-07
4.20e-05
5.40e-06
1.90e-07
7.00e-08
(Ib/ton)
2.71e-02
4.39e-06
1.02e-03
1.32e-04
4.63e-06
1.71e-06
A-66
-------
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
3Page 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
3Page 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
3Page 6-27, Table 6-10, "Average" values
bMultiply emission factor, Ib/MMBtu, by
Emission Factor
(lb/10A12 Btu)3
70
180
used in developing EF.
coal HHV, MMBtu/ton.
Emission Factor
(lb/10A12 Btu)3
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
A-67
-------
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 Disulfide
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
3Page 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.
A-68
-------
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
"Page 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.
A-69
-------
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
3Page6-33.
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
A-70
-------
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 methods'1
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.
bPages2-l,2-4,and2-5.
"Page 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.
A-71
-------
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.
A-72
-------
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
3Page 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
3Page 6-80.
bMultiply emission factor, Ib/MMBtu,
ORGANIC EMISSION FACTORS
Pollutant
Chloromethane (Methyl Chloride)
Bromomethane (Methyl Bromide)
Vinyl Chlorideb
Chloroethane (Ethyl Chloride)b
Carbon Disulfide
1 , 1 -Dichloroethane (Ethylidene
Dichloride)b
Chloroform b
1,2-Dichloroethane (Ethylene
Dichloride)
2-Butanone (Methyl Ethyl Ketone)
1,1,1 -Trichloroethaneb
Carbon Tetrachlorideb
Vinyl Acetateb
Emission Factor
(lb/10A12 Btu)3
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
A-73
-------
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
A-74
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
PAH/SVOC EMISSION FACTORS
Emission Factor3 Emission Factor Emission Factor0
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
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
0.0162 1.62e-08
0.0021 2.10e-09
0.0053 5.30e-09
0.0045 4.50e-09
0.0009 9.00e-10
0.0006 6.00e-10
0.0006 6.00e-10
0.0230 2.30e-08
0.5425 5.43e-07
0.0105 1.05e-08
0.0057 5.70e-09
(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
3Page 6-84 (most common PAHs, 189 HAPs).
bPollutant was not detected in any sampling runs. EF is based on detection limits (1/2).
'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 Emission Factor
(lb/ 1 0 A 1 2 Btu) (Ib/MMBtu)
9.90e-07 9.90e-13
1.51e-05 1.51e-ll
9.89e-06 9.89e-12
6.29e-06 6.29e-12
Emission Factor
(lb/ton)c
1.23e-ll
1.88e-10
1.23e-10
7.84e-ll
3Page 6-86.
bPollutant was not detected in any sampling runs. EF is based on detection limits (1/2).
'Multiply emission factor, Ib/MMBtu, by coal HHV, MMBtu/ton.
A-75
-------
REFERENCE 42 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 32 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
ALDEHYDES EMISSION FACTORS
Pollutant
Formaldehydeb
Acetaldehyde
Acrolein
Propionaldehyde
Emission Factor3
(lb/10A12 Btu)
1.8
67
1.1
12
3Page 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
(Ib/MMBtu)
1.80e-06 2.
6.70e-05 8.
1.10e-06 1.
1.20e-05 1.
detection limits (1/2).
Factor0
(Ib/ton)
24e-05
35e-04
37e-05
50e-04
A-76
-------
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
DOE3.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
A-77
-------
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
3Page 4-18, "Average" values.
bMultiply emission factor, Ib/MMBtu, by
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
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
A-78
-------
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.
A-79
-------
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
A-80
-------
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 Disulfide
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
A-81
-------
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 methods'1
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.
A-82
-------
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
3Page 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.
A-83
-------
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.
A-84
-------
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
3Page4-45.
bPollutant not detected in
°Multiply emission factor
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
any sampling runs. EF is based on detection limits.
, Ib/MMBtu, by coal HHV, MMBtu/ton.
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
ALDEHYDES/KETONES EMISSION FACTORS
Pollutant
Formaldehydeb
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.
A-85
-------
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 Disulfide
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
"Page 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.
A-86
-------
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 DOE5.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
Pennsylvania
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
(lb/10A12 Btu)
235
283
568
16.4
Emission Factor Emission Factorb
(Ib/MMBtu)
2.35e-04
2.83e-04
5.68e-04
1.64e-05
(Ib/ton)
6.11e-03
7.36e-03
1.48e-02
4.26e-04
A-87
-------
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
3Pagel-ll.
bMultiply emission factor, Ib/MMBtu, by
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
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
A-88
-------
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
3Pagel-ll.
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
3Pagel-ll.
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
A-89
-------
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
"Page 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
A-90
-------
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 T
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
3Page 2-1
bConversation with Greg Behrens, Radian, Austin, Texas.
cPage 3-1
dPage3-21,3-22, 3-23
ePage 3-7
fAppendix B of EPRI Synthesis Report, page B-2
A-91
-------
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
A-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
Fluoranthene
Fluorene
Indeno(l,2,3-c,d)pyreneb
Phenanthrene
Pyrene
"Pages 3 -24, 3-25. Individual
(lb/10A12 Btu)a
0.010
0.0099
0.0027
0.044
0.011
run 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
A-93
-------
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 INSTITUTE, 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.
A-94
-------
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
3Page 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
A-95
-------
REFERENCE 48 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 38 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
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
Commercial/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
A-96
-------
REFERENCE 48 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 38 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
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
Commercial/Industrial Boilers
Lignite
Firing Types
Pulverized Coal
Pulverized Coal Tangential Firing
Traveling Grate Overfeed Stoker
Spreader Stoker
1-03-003-05
1-03-003-06
1-03-003-07
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
A-97
-------
REFERENCE 48 OF AP-42 SECTION 1.1 BACKGROUND DOCUMENTATION
REFERENCE 38 OF AP-42 SECTION 1.7 BACKGROUND DOCUMENTATION
BOILER SCC DESCRIPTIONS
Traveling Grate Overfeed Stoker
Spreader Stoker
Source
Classification
Codes
1-01-003-04
1-02-003-04
1-01-003-06
1-02-003-06
Overall Average
Quality Rating
Hydrogen
Chloride
(lb/ton)a'b
1.2
B
3Pages 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
factor.
Hydrogen
Fluoride
(lb/ton)a'b
0.15
B
emission
A-98
-------
Multiple
cyclone
\
Uncontrolled
.2 .4 .6 1 2 4 6 10
Particle diameter ( m)
20
40 60 100
-------
l.OA
0.9A
| 0.8A
^1^ 0.7A
.2 03 a
111
o
•
03
T> 5
0.6A
S .23 _r
* 0.5A
0.4A
0.3A
0.2A
0.1A
0
.1
.2
I
Uncontrolled
Multiple cyclone
I
1 2 4 6 10
Particle diameter ( m)
20
40 60 100
A-103
------- |