EPA/600/7-86/043
November 1986
EXTERNAL COMBUSTION PARTICULATE EMISSIONS: SOURCE CATEGORY REPORT
by
Donald Van Buren, David Barbe, and A. Walter Wyss
Acurex Corporation
Environmental Systems Division
485 Clyde Avenue
P. 0. Box 7044
Mountain View, California 94039
EPA Contract 58-02-3159
Technical Directive No. 12^
EPA Project Officer: Dale Harmon
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
AIR AND ENERCY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AKD DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION" AGENCY
RESEARCH TRIANGLE PARK, SC 27711
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TECHNICAL REPORT DATA
(Please read lauructwns on the reverse before completingj
) REPORT NO. 2.
EPA/600/7-36/043
3. RECIPIENT'S ACCESSION NO, „
- /*, it * < CN-
Zll * *! 4; w «• i'
4. TITLE ano subtitle
External Combustion Particulate Emissions: Source
Category Report
5. REPORT DATE
November 1986
6. PERFORMING ORGANIZATION CODE
7 AUTHORISI
Donald Van Buren, David Barbe, and A. Walter Wyss
B. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING OROANlZATlON NAME AND ADDRESS
Acurex Corporation
P. O. Box 7044
Mountain View, California 94039
10 PROGRAM ELEMENt NO.
11. CONTRACT/GRANT NO.
68-02-3159 , Task 12
12. SPONSORING AGENCY NAME ANO ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOO COVERED
Task Final: 6/84 - 7/86
14, SPONSORING AGENCY COOE
EPA/600/13
is.supplementary NDT£SaeERL project officer is Dale L. Harmon, Mail Drop 61, 919/541-
2429.
i6. abstract The report gives results of the development of particulate emission factors
based on cutoff size for inhalable particles for external combustion sources. After a
review of available information characterizing particulate emissions from external
combustion sources, the data were summarized and rated in terms of reliability.
Size specific emission factors were developed for these data for the major processes
used in combustion. A detailed process description is presented with emphasis on
factors affecting the generation of emissions. A replacement for Sections 1.1 (Bitu-
minous and Subbituminous Coal Combustion), 1,2 (Anthracite Coal Combustion), 1.3
(Fuel Oil Combustion), 1.4 (Natural Gas Combustion), 1.6 (Wood Waste Combustion
in Boilers), and 1. 7 (Lignite Combustion) of AP-42 was prepared, containing the size
specific emission factors developed under this program.
17. KEY WORQS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.lOENTlFienS/OPEN ENOEO TERMS
c. COSATl Field/Group
Pollution Fuel Oil
Combustion Natural Gas
Emission Wood Wastes
Particles Lignite
Aerosols
Coal
Pollution Control
Stationary Sources
External Combustion
Particulate
Emission Factors
13 B
21B
14G 11L
07D
21D
19. DISTRIBUTION STATEMENT
Release to Public
19 SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
203
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (»-7J) B~3
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NOTICE
This document has been reviewed in accordance with
U.S. Environmental Protection Agency policy and
approved for publication. Mention of trade names
or commercial products does not constitute endorse-
ment or recommendation for use.
ii
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ABSTRACT
The objective of this study was to develop particulate emission
factors based on cutoff size for inhalable particles for external com-
bustion sources. After review of available information characterizing
particulate emissions from external combustion sources, the data were
summarized and rated in terms of reliability. Size specific emission
factors were developed from these data for the major processes used in
combustion. A detailed process description was presented with emphasis
on those factors affecting the generation of emissions. A replacement
for Sections 1.1 (Bituminous and Subbitumous Coal Combustion), 1.2
(Anthracite Coal Combustion), 1.3 (Fuel Oil Combustion), 1.4 (Natural
Gas Combustion), 1.6 (Wood Waste Combustion in Boilers), and 1.7 (Lig-
nite Combustion) of AP-42 was prepared, containing the size specific
emission factors developed under this program.
i i i
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CONTENTS
Abstract iii
Figures viii
Tables ..... ix
1 Introduction 1
2 External Combustion Sources 5
2.1 General 5
2.2 Bituminous and Subbituminous Coal Combustion .... 5
2.2.1 General 5
2.2.2 Particulate Emissions and Controls 6
2.3 Anthracite Coal Combustion 8
2.3.1 General 8
2.3.2 Particulate Emissions and Controls 8
2.4 Fuel Oil Combustion 9
2.4.1 General 9
2.4.2 Particulate Emissions and Controls 10
2.5 Natural Gas Combustion 11
2.5.1 General 11
2.5.2 Particulate Emissions and Controls 11
2.6 Wood Waste Combustion in Boilers 11
2.6.1 General 11
2.6.2 Firing Practices 12
2.6.3 Particulate Emissions and Controls 12
2.7 Lignite Combustion . 14
2.7.1 General 14
2.7.2 Particulate Emissions and Controls 14
v
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CONTENTS (continued)
3 Particle Size Distribution for External Combustion
Sources 17
3.1 Data Collection 19
3.2 Data Categorization ...... 19
3.3 Data Evaluation 28
3.3.1 Bituminous and Subbituminous Coal 32
3.3.2 Anthracite Coal ...... 66
3.3.3 Fuel 011 73
3.3.4 Natural Gas 89
3.3.5 Wood Waste 89
3.3.6 Emission Source Discussion 89
3.3.7 Lignite Coal 101
3.4 Particulate Emission Factors 104
3.5 Recommend Cumulative Size-Specific Emission
Factors 105
3.5.1 Bituminous Coal 109
3.5.2 Anthracite Coal 113
3.5.3 Fuel Oil 114
3.5.4 Wood Waste 116
3.5.5 Lignite 119
Proposed AP-42 Sections
1.1 Bituminous and Subbituminous Coal
Combustion 124
1.1.1 General 124
1.1.2 Emissions and Controls 127
1.2 Anthracite Coal Combustion 141
1.2.1 General 141
1.2.2 Emissions and Controls 141
1.3 Fuel Oil Combustion 148
1.3.1 General 148
1.3.2 Emissions 148
1.3.3 Controls 155
vi
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CONTENTS (continued)
1.4 Natural Gas Combustion 159
1.4.1 General 159
1.4.2 Emissions and Controls 159
1.6 Wood Waste Combustion in Boilers ....... 165
1.6.1 General 165
1.6.2 Firing Practices 165
1.6.3 Emissions and Controls 167
1.7 Lignite Combustion 175
1.7.1 General 175
1.7.2 Emissions and Controls 175
References for Sections 1 through 3 |g2
Appendix A — Glossary of Terms A-l
Appendix B -- List of Contacts B-l
vii
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FIGURES
Number Paye
1 Cross section of Mark III cascade impactor 18
2 Categories for which data was sought for the development of
size-specific emission factors . . 20
v i i i
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TABLES
Number Page
1 Data Sources Used for the Development of Size-Specific
Emission Factors 22
2 FPEIS Test and Other Reports Reviewed But Not Used for
Emission Factor Development . 24
3 External Combustion Source Categories and Identified Data
Sets Used for Emission Factor Development 29
4 Particle Size Distribution Data for Uncontrolled Dry
Bottom Boilers Burning Pulverized Bituminous Coal 33
5 Particle Size Distribution Data for Multiple Cyclone
Controlled Dry Bottom Boilers Burning Pulverized
Bituminous Coal 35
6 Particle Size Distribution Data for Scrubber Controlled
Boilers Burning Pulverized Bituminous Coal 36
7 Particle Size Distribution Data for ESP Controlled Dry
Bottom Boilers Burning Pulverized Bituminous Coal 37
8 Particle Size Distribution Data for Baghouse Controlled
Dry Bottom Boilers Burning Pulverized Bituminous Coal ... 39
9 Particle Size Distribution Data for Uncontrolled Wet
Bottom Boilers Burning Pulverized Bituminous Coal 39
10 Particle Size Distribution Data for Multiple Cyclone
Controlled Wet Bottom Boilers Burning Pulverized
Bituminous Coal 40
11 Particle Size Distribution Data for ESP Controlled Wet
Bottom Boilers Burning Pulverized Bituminous Coal 40
12 Particle Size Distribution Data for Uncontrolled Cyclone
Furnaces Burning Bituminous Coal ..... 41
ix
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TABLES (continued)
Number Page
13 Particle Size Distribution Data for Scrubber Controlled
Cyclone Furnaces Buring Bituminous Coal 41
14 Particle Size Distribution Data for ESP Controlled
Cyclone Furnaces Burning Bituminous Coal 42
15 Particle Size Distribution Data for Uncontrolled
Spreader Stoker Boilers Burning Bituminous Coal 43
16 Particle Size Distribution Data for Bituminous Coal Fueled
Spreader Stokers with Multiple Cyclones with Flyash
Reinjection 44
17 Particle Size Distribution Data for Bituminous Coal Fueled
Spreader Stokers with Multiple Cyclones without Flyash
Reinjection 44
18 Particle Size Distribution Data for ESP Controlled Spreader
Stokers Burning Bituminous Coal 45
19 Particle Size Distribution Data for Baghouse Controlled
Spreader Stroker Burning Bituminous Coal 45
20 Particle Size Distribution Data for Uncontrolled Overfeed
Stokers Burning Bituminous Coal 47
21 Particle Size Distribution Data for Multiple Cyclone
Controlled Overfeed Stokers Burning Bituminous Coal .... 47
22 Particle Size Distribution Data for Uncontrolled Underfeed
Stokers Burning Bituminous Coal 48
23 Particle Size Distribution Data for Multiple Cyclone
Controlled Underfeed Stoker Burning Bituminous Coal .... 48
24 Test Sites and Test Conditions 64
25 Particle Size Distribution Data for Multiple Cyclone
Controlled Dry Bottom Boilers Burning Anthracite Coal
(With Petroleum Coke) 67
26 Particle Size Distribution Data for Baghouse Controlled
Boilers Burning Pulverized Anthracite Coal (With Petroleum
Coke) 69
x
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27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
Page
71
74
75
75
76
77
77
78
79
90
90
91
91
92
92
TABLES (continued)
Particle Size Distribution Data for Uncontrolled Stokers
Burning Anthracite Coal
Particle Size Distribution Data for Uncontrolled Utility
Boilers Burning Residual Fuel Oil
Particle Size Distribution Data for ESP-Controlled Utility
Boilers Burning Residual Fuel Oil
Particle Size Distribution Data for Scrubber-Controlled
Utility Boilers Burning Residual Fuel Oil
Particle Size Distribution Data for Uncontrolled Industrial
Boilers Burning Residual Fuel Oil
Particle Size Distribution Data for Multiple-Cyclone-
Controlled Industrial Boilers Burniny Residual Fuel Oil . .
Particle Size Distribution Data for Uncontrolled Industrial
Boiler Burning Distillate Fuel Oil
Particle Size Distribution Data for Uncontrolled Commercial
Boilers Burning Residual Fuel Oil
Particle Size Distribution for Uncontrolled Commercial
Boilers Burning Distillate Fuel Oil
Particle Size Distribution Data for Uncontrolled Boilers
Burning Bark
Particle Size Distribution Data for a Multiple-Cyclone-
Controlled Boiler with Flyash Reinjection Burning Bark . .
Particle Size Distribution Data for Scrubber-Control led
Boilers Burning Bark
Particle Size Distribution Data for Uncontrolled Boilers
Burning Wood/Bark
Particle Size Distribution Data for Uncontrolled Boilers
Burning Wood/Bark
Particle Size Distribution Data for Uncontrolled Boilers
Burning Salt-Laden Wood/Bark
xi
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TABLES (continued)
Number Paye
42 Particle Size Distribution Data for Multiple-Cyclone-
Controlled Boiler with Flyash Reinjection Burniny
Wood/Bark 93
43 Particle Size Distribution Data for Multiple-Cyclone-
Controlled Boiler with No Flyash Reinjection Burning
Salt-Laden Wood/Bark 93
44 Particle Size Distribution Data for Multiple-Cyclone-
Controlled Boiler with No Flyash Reinjection Burning
Wood/Bark 94
45 Particle Size Distribution Data for Multiple Cyclone-
Controlled Boiler with No Flyash Reinjection Burning
Salt-Laden Wood/Bark 94
46 Particle Size Distribution Data for Scrubber-Controlled
Boilers Burniny Wood/Bark 95
47 Particle Size Distribution Data for Baghouse-Controlled
Boilers Burniny Salt Laden Wood/Bark 95
48 Particle Size Distribution Data for Dry Electrostatic
Granular Filter-Controlled Boiler Burning Wood/Bark .... 96
49 Particle Size Distribution Data for Uncontrolled Boilers
Burning Pulverized Lignite Coal 102
50 Particle Size Distribution Data for Multiple-Cyclone-
Controlled Boilers Burning Pulverized Lignite Coal .... 102
51 Particle Size Distribution Data for Multiple-Cyclone-
Controlled Spreader Stokers Burniny Lignite Coal 103
52 Particulate Emission Factors for Bituminous and
Subbituminous Coal Combustion 106
53 Particulate Emission Factors for Anthracite Coal
Combustion 106
54 Particulate Emission Factors for Fuel Oil Combustion . . . 107
55 Particulate Emission Factors for Wood Waste Combustion in
Boilers 107
xii
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TABLES (continued)
Number Page
56 Particulate Emission Factors for Liynite Coal Combustion. . 108
57 Cumulative Size Distributions and Particulate Emission
Factors Used in the Development of Cumulative Size-Specific
Emission Factors for Bituminous and Subbituminous Coal
Combustion 112
58 Cumulative Size Distributions and Particulate Emission
Factors Used in the Development of Size-Specific Emission
Factors for Anthracite Coal Combustion 115
69 Cumulative Size Distribution and Particulate Emission
Factors Used in the Development of Cumulative Size-Specific
Emission Factors for Fuel Oil Combustion 117
60 Cumulative Size Distribution and Particulate Emission
Factors Used in the Development of Cumulative Size-Specific
Emission Factors for Wood Waste Combustion in Boilers . . . 120
61 Cumulative Size Distribution and Particulate Emission
Factors Used in the Development of Size-Specific Emission
Factors for Lignite Coal Combustion 122
xiii
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SECTION 1
INTRODUCTION
This document is a source category report on inhalable particulate
matter emitted by external combustion sources. Inhalable particulate matter
can be characterized as particles of respirable size capable of reaching the
lower lung.
The source category report summarizes available data on inhalable
particulate emissions from typical source combustion units fired with coal,
oil, natural gas, and wood wastes. The main objectives of this study are
to:
• Develop reliable total and size-specific particulate emission
factors for controlled and uncontrolled emissions for various
external combustion sources
• Update Sections 1.1 "Bituminous Coal Combustion," 1.2 "Anthracite
Coal Combustion," 1.3 "Fuel Oil Combustion," 1.4 "Natural Gas
Combustion," 1.6 "Wood Waste Combustion in Boilers," and 1.7
"Lignite Combustion" in the document "Compilation of Air Pollutant
Emission Factors," (AP-42) (Ref. 1) with the size-specific emission
factors developed during this study
These objectives were met by an intensive review of EPA's Fine Particle
Emission Information System (FPEIS) (Ref. 2 and 3 and see Appendix A,
Glossary of Terms), a literature search, and personal contact with
individuals and organizations known to be familiar with external combustion
sources. The individuals and organizations are listed in Appendix B. Sources
for data included:
• Regulatory agencies
— U. S. Environmental Protection Agency
— State and local air pollution control agencies
• Trade organizations
— American Petroleum Institute
— American Boiler Manufacturers Association
1
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-- Chemical Manufacturers Association
-- Edison Electric Institute
-- Electric Power Research Institute
-- National Council of the Paper Industry for Air and Stream
Improvement (NCASI)
• Industry contacts
• AP-42 external combustion sources background file at the Office of
Air Quality Planning and Standards (OAQPS)
• EPA's FPEIS listings dated June 20-21, 1983 (Ref. 2) and
September 19, 1983 (Ref. 3)
Particle sizes are usually expressed in terms of the aerodynamic
equivalent diameter (see Glossary of Terms). This method of size expression
is useful because it is readily determined through straightforward
measurement where the other properties of actual particle size and density
may not be obtainable. A particle's inertia! characteristics can be used to
best predict where deposition will occur in the respiratory system, and
actual particle size and density may not be obtainable.
There are two general classifications of particle size measurement
systems, namely, inertial separation and optical or electrical mobility
measurement. The majority of all particle sizing currently performed in
source testing uses equipment based on inertial separation. Data in this
report are primarily the result of measurements using either of two inertial
instruments, the cascade impactor or the Source Assessment Sampling System
(SASS) three-cyclone train.
The data were reviewed; classified according to type of fuel, combustion
process, and particulate control device; analyzed; and ranked from A (high
quality) to E (low quality) according to the criteria provided in the report
"Technical Procedures for Developing AP-42 Emission Factors and Preparing
AP-42 Sections," (Ref. 4). Data expected to be more representative, as
described in Section 3, are ranked higher and preferentially used in emission
factor development. After ranking the data, a size distribution and
size-specific emission factor were calculated for each source category,
taking into consideration the data quantity and quality and the particulate
emission factor obtained from AP-42 or estimated by applying a nominal
particulate control device efficiency (Ref. 5) to an AP-42 particulate
emission factor. The reliability of this emission factor is indicated by an
emission factor rating. The ratings are subjective quality evaluations
rather than statistical confidence intervals and range from A (excellent) to
E (poor) as described in Section 3.
It was beyond the scope of this report to analyze process technology and
particulate control device technology in detail. However, future revisions
2
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may want to subclassify emissions sources in greater detail. As an example,
newer electrostatic precipitators (ESP's) would generally be larger and have
a higher particulate collection efficiency than older ESP's installed on a
similar source. A subclassification using ESP efficiency, age, or relative
size may then yield a more useable size-specific emission factor.
A description of the external combustion sources was abstracted from
AP-42 and included in Section 2. The descriptions in AP-42 were not
extensively revised having recently been updated and are included in
Section 2 to provide general background information. Because of the nature
of AP-42, certain duplication of Information occurs in Sections 1 through 3
and the proposed AP-42 sections of this report.
During a review cycle for this report, a comment was received concerning
salt-laden wood waste and boiler types. In this, the final report,
cumulative size-specific particle size distribution data is now shown
separately by boiler types for wood waste and salt-laden wood waste. Since
insufficient data was available to generate salt-laden particulate emission
factors, salt-laden cumulative size-specific emission factors were not able
to be calculated at this time and are therefore not presented in AP-42. Wood
waste boiler types are now noted with each cumulative size-specific particle
size distribution and cumulative size-specific emission factor. Since
insufficient data was available to generate a particulate emission factor for
a wood-waste fired fluidized bed boiler, a cumulative size-specific emission
factor was not able to be calculated at this time and cannot be included in
AP-42.
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SECTION 2
EXTERNAL COMBUSTION SOURCES (REF. 1)
2.1 GENERAL
External combustion sources include steam/electric generating plants,
industrial boilers, and commercial and domestic combustion units. Coal, fuel
oil, and natural gas are the major fossil fuels used by these sources. Other
fuels, used in relatively small quantities, are liquefied petroleum gas,
wood, coke, refinery gas, blast furnace gas, and other waste or byproduct
fuels. Coal, oil, and natural gas currently supply about 95 percent of the
total thermal energy consumed in the United States. In 1980 the nation
consumed over 530 million megagrams (585 million tons) of bituminous coal,
nearly 3.6 million megagrams (4 million tons) of anthracite coal, 91 x 10*
liters (24 billion gallons) of distillate oil, 114 x 10$ liters (37 billion
gallons) of residual oil, and 57 x lO*2 (20 trillion ft-*) of natural gas.
Power generation, process heating, and space heating are some of the
largest fuel combustion sources of sulfur oxides, nitrogen oxides, and
particulate emissions. The following subsections present a brief description
of the processes used to combust coal, fuel oil, natural gas, and wood waste
and control particulate emissions. Other fuels are not discussed in this
report.
2.2 BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION
2.2.1 General
Coal is a complex combination of organic matter and inorganic ash formed
over eons from successive layers of fallen vegetation. Coal types are
broadly classified as anthracite, bituminous, subbituminous, or lignite, and
classification is made by heating values and amounts of fixed carbon,
volatile matter, ash, sulfur, and moisture. Formulas for differentiating
coals based on these properties are given in Ref. 6. See Sections 2.3
and 2.7 for discussions of anthracite and lignite, respectively.
There are two major coal combustion techniques, suspension firing and
grate firing. Suspension firing is the primary combustion mechanism in
pulverized coal and cyclone systems. Grate firing is the primary mechanism
in underfeed and overfeed stokers. Both mechanisms are employed in spreader
stokers.
5
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Pulverized-coal furnaces are used primarily In utility and large
industrial boilers. In these systems, the coal is pulverized in a mill to
the consistency of talcum powder (i.e., at least 70 percent of the particles
will pass through a 200-mesh sieve). The pulverized coal is generally
entrained in primary air before being fed through the burners to the
combustion chamber, where it is fired in suspension. Pulverized-coal
furnaces are classified as either dry or wet bottom, depending on the ash
removal technique. Dry-bottom furnaces fire coals with high ash fusion
temperatures, and dry ash removal techniques are used. In wet-bottom (slag
tap) furnaces, coals with low ash fusion temperatures are used, and molten
ash is drained from the bottom of the furnace. Pulverized coal furnaces are
further classified by the firing position of the burners, i.e., single (front
or rear) wall, horizontally opposed, vertical, tangential (corner fired),
turbo or arch fired.
Cyclone furnaces burn low ash fusion temperature coal crushed to a
4-mesh size. The coal is fed tangentially, with primary air, to a horizontal
cylindrical combustion chamber. In this chamber, small coal particles are
burned in suspension, while the larger particles are forced against the outer
wall. Because of the high temperatures developed in the relatively small
furnace volume, and because of the low fusion temperature of the coal ash,
much of the ash forms a liquid slag which is drained from the bottom of the
furnace through a slag tap opening. Cyclone furnaces are used mostly in
utility and large industrial applications.
In spreader stokers, a flipping mechanism throws the coal into the
furnace and onto a moving fuel bed. Combustion occurs partly in suspension
and partly on the grate. Because of significant carbon in the particulate,
flyash reinjection from mechanical collectors is commonly employed to improve
boiler efficiency. Ash residue in the fuel bed is deposited in a receiving
pit at the end of the grate.
In overfeed stokers, coal is fed onto a traveling or vibrating grate,
and it burns on the fuel bed as it progresses through the furnace. Ash
particles fall into an ash pit at the rear of the stoker. The term
"overfeed" applies because the coal is fed onto the moving grate under an
adjustable gate. Conversely, in "underfeed" stokers, coal is fed into the
firing zone from underneath by mechanical rams or screw conveyers. The coal
moves in a channel, known as a retort, from which it is forced upward,
spilling over the top of each side to form and to feed the fuel bed.
Combustion is completed by the time the bed reaches the side dump grates from
which the ash is discharged to shallow pits. Underfeed stokers include
single retort units and multiple retort units, the latter having several
retorts side by side.
2.2.2 Particulate Emissions and Controls
Particulate composition and emission levels are a complex function of
firing configuration, boiler operation, and coal properties. In
pulverized-coal systems, combustion is almost complete, and thus particulate
is largely comprised of Inorganic ash residue. In wet-bottom,
6
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pulverized-coal units and cyclones, the quantity of ash leaving the boiler is
less than in dry-bottom units, since some of the ash liquifies, collects on
the furnace walls, and drains from the furnace bottom as molten slag. In an
effort to increase the fraction of ash drawn off as wet slag and thus to
reduce the flyash disposal problem, flyash is sometimes reinjected from
collection equipment into slag tap systems. Ash from dry-bottom units may
also be reinjected into wet-bottom boilers for this same purpose.
Because a mixture of fine and coarse coal particles is fired in spreader
stokers, significant unburnt carbon can be present in the particulate. To
improve boiler efficiency, flyash from collection devices (typically
mechanical collectors) is sometimes reinjected into spreader-stoker furnaces.
This practice can dramatically increase the particulate loading at the boiler
outlet and, to a lesser extent, at the mechanical collectors outlet. Flyash
can also be reinjected from the boiler, air heater, and economizer dust
hoppers. Flyash reinjection from these hoppers does not increase particulate
loadings nearly as much as from multiple cyclones.
Particulate emissions from uncontrolled overfeed and underfeed stokers
are considerably lower than from pulverized-coal units and spreader stokers,
since combustion takes place in a relatively quiescent fuel bed. Flyash
reinjection is not practiced in these kinds of stokers.
Variables other than firing configuration and flyash reinjection can
affect emissions from stokers. Particulate loadings will often increase as
load increases (especially as full load is approached) and with sudden load
changes. Similarly, particulate can increase as the ash and fines contents
increase. ("Fines" are defined in this context as coal particles smaller
than one sixteenth inch, or about 1.6 mm, in diameter.) Conversely,
particulate can be reduced significantly when overfire air pressures are
increased.
The primary kinds of particulate control devices used for coal
combustion include multiple cyclones, electrostatic precipitators (ESP's),
fabric filters (baghouses) and scrubbers. Some measure of control will even
result due to ash settling in boiler/air heater/economizer dust hoppers,
large breeches, and chimney bases.
ESP's are the most common high-efficiency control device used on
pulverized-coal and cyclone units, and they are being used increasingly on
stokers. Generally, ESP collection efficiencies are a function of collection
plate area per volumetric flowrate of flue gas through the device. Total
mass particulate control efficiencies of 99.9 weight percent are obtainable
with ESP's. Recently, the use of fabric filters has increased in both
utility and industrial applications, generally effecting about 99.8 percent
total mass efficiency. An advantage of fabric filters is that they are
unaffected by high flyash resistivities associated with low-sulfur coals.
ESP's located after air preheaters (i.e., cold side precipitators) may
operate at significantly reduced efficiencies when low-sulfur coal is fired.
Scrubbers are also used to control particulate, although their primary use is
7
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to control sulfur oxides. One drawback of scrubbers is the high energy
required to achieve control efficiencies comparable to those of ESP's and
baghouses.
Mechanical collectors, generally multiple cyclones, are the primary
means of control on many stokers and are sometimes installed upstream of
high-efficiency control devices to reduce the ash collection burden.
Depending on the application and design, multiple-cyclone efficiencies can
vary tremendously. Where cyclone design flowrates are not attained (which is
common with underfeed and overfeed stokers), these devices may be only
marginally effective and may not prove to be any better in reducing
particulate than large breeching. Conversely, well-designed multiple
cyclones operating at the required flowrates can achieve collection
efficiencies on spreader-stokers and overfeed stokers of 90 to 95 percent.
Even higher collection efficiencies are obtainable on spreader stokers with
reinjected flyash because of the larger particle sizes and increased
particulate loadings reaching the controls.
2.3 ANTHRACITE COAL COMBUSTION
2.3.1 General
Anthracite coal is a high-rank coal with a high fixed-carbon content and
low volatile-matter content, relative to bituminous coal and lignite, and it
has higher ignition and ash fusion temperatures. Because of its low volatile
matter content and slight clinkering, anthracite is most commonly fired in
medium-sized, traveling-grate stokers and small hand-fired units. Some
anthracite (occasionally along with petroleum coke) is used in pulverized-
coal-fired boilers. It is also blended with bituminous coal. None is fired
in spreader stokers. Because of its low sulfur content (typically less than
0.8 weight percent) and minimal smoking tendencies, anthracite is considered
a desirable fuel where readily available.
In the United States, all anthracite is mined in Northeastern
Pennsylvania and is consumed primarily in Pennsylvania and several
surrounding states. The largest use of anthracite is for space heating.
Lesser amounts are used for steam/electric production, coke manufacturing,
sintering, and pelletizing, and other industrial uses. Anthracite combustion
currently is only a small fraction of the total quantity of coal combusted in
the United States.
2.3.2 Particulate Emissions and Controls
Particulate emissions from anthracite combustion are a function of
furnace firing configuration, firing practices (boiler load, quantity and
location of underfire air, sootblowing, flyash reinjection, etc.), and the
ash content of the coal. Pulverized-coal-fired boilers emit the highest
quantity of particulate per unit of fuel because they fire the anthracite in
suspension, which results in a high percentage of ash carryover into the
exhaust gases. Pulverized-anthracite-fired boilers operate in the dry-tap or
dry-bottom mode because of anthracite's characteristically high ash fusion
8
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temperature. Traveling-grate stokers and hand-fired units produce much less
particulate per unit of fuel fired because combustion takes place in a
quiescent fuel bed without significant ash carryover into the exhaust gases.
In general, particulate emissions from traveling-grate stokers will increase
during sootblowing and flyash reinjection and with higher fuel bed underfeed
air from forced draft fans. Smoking is rarely a problem because of the low
volatile matter content of the anthracite.
Control of emissions from anthracite combustion has mainly been limited
to particulate matter. The most efficient particulate controls — fabric
filters, scrubbers, and ESP's -- have been installed on large pulverized-
anthracite-fired boilers. Fabric filters and venturi scrubbers can effect
total mass collection efficiencies exceeding 99 percent. ESP's, on the other
hand, are typically only 90 to 97 percent total mass collection efficient,
because of the characteristic high resistivity of low-sulfur anthracite
flyash. It is reported that higher efficiencies can be achieved using larger
precipitators and flue gas conditioning. Mechanical collector are frequently
used upstream from these devices for large particle removal.
Traveling-grate stokers are often uncontrolled. Indeed, particulate
control has often been considered unnecessary because of the low smoking
tendencies of anthracite and because a significant fraction of large-size
flyash from stokers is readily collected in flyash hoppers, as well as in the
breeching and base of the stack. Cyclone collectors have been used on
traveling-grate stokers and limited information suggests these devices may be
up to 75 percent efficient on total mass particulate collection. Flyash
reinjection, frequently used in traveling-grate stokers to enhance fuel use
efficiency, tends to increase particulate emissions per unit of fuel
combusted.
2.4 FUEL OIL COMBUSTION
2.4.1 General
Fuel oils are broadly classified into two major types, distillate and
residual. Distillate oils (fuel oil grade nos. 1 and 2) are used mainly in
domestic and small commercial applications in which easy fuel burning is
required. Distillates are more volatile and less viscous than residual oils,
having negligible ash and nitrogen contents and usually contain less than 0.3
weight percent sulfur. Residual oils (grade nos. 4, 5, and 6), on the other
hand, are used mainly in utility, industrial, and large commercial
applications with sophisticated combustion equipment. No. 4 oil is sometimes
classified as a distillate, and no. 6 is sometimes referred to as Bunker C.
Being more viscous and less volatile than distillate oils, the heavier
residual oils (nos. 5 and 6) may need to be heated to facilitate handling and
proper atomization. Because residual oils are produced from the residue left
after lighter fractions (gasoline, kerosene, and distillate oils) have been
removed from the crude oil, residual oils contain significant quantities of
ash, nitrogen, and sulfur.
9
-------
2.4.2 Particulate Emissions and Controls
Particulate emissions are most dependent on the grade of fuel fired.
The lighter distillate oils result in significantly lower particulate
formation than do the heavier residual oils. Among residual oils, nos. 4
and 5 usually result in less particulate than does the heavier no. 6.
In boilers firing no. 6, particulate emissions can be described, on the
average, as a function of the sulfur content of the oil. Particulate
emissions can be reduced considerably when low-sulfur grade no. 6 oil is
fired. This is because low-sulfur no. 6, whether refined from naturally
occurring low-sulfur crude oil or desulfurized by one of several current
processes, exhibits substantially lower viscosity and reduced asphaltene,
ash, and sulfur -- all of which results in better atomization and cleaner
combustion.
Boiler load can also affect particulate emissions in units firing no. 6
oil. At low load conditions, particulate emissions may be lowered by 30 to
40 percent from utility boilers and by as much as 60 percent from small
industrial and commercial units. No significant particulate reductions have
been noted at low loads from boilers firing any of the lighter grades,
however. At too low a load condition, proper combustion conditions cannot be
maintained, and particulate emissions may increase drastically. It should be
noted, in this regard, that any condition that prevents proper boiler
operation can result in excessive particulate formation.
Flue gas cleaning equipment generally is used only on large oil-fired
boilers. Mechanical collectors, a prevalent type of control device, are
primarily useful in controlling particulates generated during soot blowing,
upset conditions, or when a very dirty, heavy oil is fired. During these
situations, high-efficiency cyclonic collectors can effect up to 85 percent
control of particulate. Under normal firing conditions or when a clean oil
is combusted, cyclonic collectors will not be nearly as effective due to a
high percentage of small particles (less than 3 microns in diameter) being
emitted.
ESP's are commonly used in oil-fired powerplants. Older precipitators
which are also small precipitators generally remove 40 to 60 percent of the
total particulate matter emissions. Due to the low ash content of the oil,
greater total mass collection efficiency may not be required. Today, new or
rebuilt ESP's have total mass collection efficiencies of up to 90 percent.
Scrubbing systems have been installed on oil-fired boilers, especially
recently, to control both sulfur oxides and particulate. These systems can
achieve S0£ removal efficiencies of up to 90 to 95 percent and provide
particulate control efficiencies of approximately 50 to 60 percent.
10
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2.5 NATURAL GAS COMBUSTION
2.5.1 General
Natural gas is one of the major fuels used throughout the country. It
is used mainly for power generation, industrial process steam and heat
production, and domestic and commercial space heating. The primary component
of natural gas is methane, although varying amounts of ethane and smaller
amounts of nitrogen, helium, and carbon dioxide are also present. Gas
processing plants are required for recovery of liquefiable constituents and
removal of hydrogen sulfide (^S) before the gas is used. The average gross
heating value of natural gas is approximately 9,350 kcal/scm (1,050 Btu/scf),
usually varying from 8,900 to 9,800 kcal/scm (1,000 to 1,100 Btu/scf).
Because natural gas in its original state is a gaseous, homogenous
fluid, its combustion is simple and can be precisely controlled. Common
excess air rates range from 10 to 15 percent, but some large units operate at
lower excess air rates to increase efficiency and reduce nitrogen oxide (N0X)
emissions.
2.5.2 Particulate Emissions and Controls
Although natural gas is considered to be a relatively clean fuel, some
emissions can occur from the combustion reaction. For example, improper
operating conditions, including poor mixing, insufficient air, etc., may
cause large amounts of smoke, carbon monoxide, and hydrocarbons to be
produced. A sulfur-containing mercaptan is added to natural gas for
detection purposes, therefore, small amounts of sulfur oxides will also be
produced in the combustion process. However, nitrogen oxides are the major
pollutants of concern when burning natural gas. Particulate control
equipment is not normally used on natural-gas-fired equipment due to
extremely low particulate loading.
2.6 WOOD WASTE COMBUSTION IN BOILERS
2.6.1 General
The burning of wood waste in boilers is mostly confined to those
industries where it is available as a byproduct. It is burned to obtain heat
energy and alleviate possible solid waste disposal problems. Wood waste may
include large pieces like slabs, logs, and bark strips as well as cuttings,
shavings, pellets, and sawdust. Heating values for this waste range from
about 4,400 to 5,000 kilocalories per kilogram of fuel dry weight (7,940 to
9,131 Btu/lb). However, because of typical moisture contents of 40 to
75 percent, the heating values for many wood waste materials as fired range
as low as 2,200 to 3,300 kilocalories per kilogram of fuel. Generally, bark
is the major type of waste burned in pulp mills, and a varying mixture of
wood and bark waste, or wood waste alone, are most frequently burned in the
lumber, furniture, and plywood industries.
11
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2.6.2 Firing Practices
A variety of boiler firing configurations is used for burning wood
waste. One common type in smaller operations is the dutch oven, or extension
type of furnace with a flat grate. This unit is widely used because it can
burn fuels with a very high moisture content. Fuel is fed into the oven
through apertures at the top of a firebox and is fired in a cone-shaped pile
on a flat grate. The burning is done in two stages, drying and gasification,
and combustion of gaseous products. The first stage takes place in a cell
separated from the boiler section by a bridge wall. The combustion stage
takes place 1n the main boiler section. The dutch oven is not responsive to
changes in steam load, and it provides poor combustion control.
In a fuel cell oven, the fuel is dropped onto suspended fixed grates and
is fired in a pile. Unlike the dutch oven, the fuel cell also uses
combustion air preheating and repositioning of the secondary and tertiary air
Injection ports to improve boiler efficiency.
In many large operations, more conventional boilers have been modified
to burn wood waste. These units may include spreader stokers with traveling
grates, vibrating-grate stokers, etc., as well as tangentially fired or
cyclone-fired boilers. The most widely used of these configurations is the
spreader stoker. Fuel is dropped in front of an air jet which casts the fuel
out over a moving grate, spreading it in an even, thin blanket. The burning
is done in three stages in a single chamber, (1) drying, (2) distillation and
burning of volatile matter, and (3) burning of carbon. This type of
operation has a fast response to load changes, has improved combustion
control, and can be operated with multiple fuels. Natural gas or oil are
often fired in spreader-stoker boilers as auxiliary fuel. This is done to
maintain constant steam when the wood waste supply fluctuates and/or to
provide more steam than is possible from the waste supply alone.
Sander dust is often burned in various boiler types, especially those in
plywood, particle board, and furniture plants. Sander dust contains fine
wood particles with a low moisture content {less than 20 weight percent). It
is fired in a flaming horizontal torch, usually with natural gas as an
ignition aid or supplementary fuel.
2.6.3 Particulate Emissions and Controls
The major pollutant of concern from wood boilers is particulate matter,
although other pollutants, particularly carbon monoxide, may be emitted in
significant amounts under poor operating conditions. These emissions depend
on a number of variables, including (1) the composition of the waste fuel
burned, (2) the degree of flyash reinjection employed, and (3) furnace design
and operating conditions.
The composition of wood waste depends largely on the industry from which
it originates. Pulping operations, for example, produce great quantities of
bark that may contain more than 70 weight percent moisture and sand and other
noncombustibles. Because of this, bark boilers in pulp mills may emit
12
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considerable amounts of particulate matter to the atmosphere unless they are
well controlled. On the other hand, some operations such as furniture
manufacture produce a clean, dry (5 to 50 weight percent moisture) wood waste
that results in relatively few particulate emissions when properly burned.
Other operations, such as sawmills, burn a variable mixture of bark and wood
waste that results in particulate emissions somewhere between these two
extremes.
Furnace design and operating conditions are particularly important when
firing wood waste. For example, because of the high moisture content that
can be present in this waste, a larger than usual area of refractory surface
is often necessary to dry the fuel before combustion. In addition,
sufficient secondary air must be supplied over the fuel bed to burn the
volatiles that account for most of the combustible material in the waste.
When proper drying conditions do not exist, or when secondary combustion is
incomplete, the combustion temperature is lowered, and increased particulate,
carbon monoxide, and hydrocarbon emissions may result. Lowering of
combustion temperature generally results in decreased nitrogen oxide
emissions. Also, emissions can fluctuate in the short term due to
significant variations in fuel moisture content over short periods of time.
Flyash reinjection, which is common in many larger boilers to improve
fuel efficiency, has a considerable effect on particulate emissions. Because
a fraction of the collected flyash is reinjected into the boiler, the dust
loading from the furnace, and consequently from the collection device,
increases significantly per unit of wood waste burned. It is reported that
full reinjection can cause a tenfold increase in the total dust loadings of
some systems, although increases of 1.2 to 2 times are more typical for
boilers using 50 to 100 percent reinjection. A major factor affecting this
dust loading increase is the extent to which the sand and other
noncombustibles can successfully be separated from the flyash before
reinjection to the furnace.
Although reinjection increases boiler efficiency from 1 to 4 percent and
minimizes the emissions of uncombusted carbon, it also increases boiler
maintenance requirements, decreases average flyash particle size and makes
collection more difficult. Properly designed reinjection systems should
separate sand and char from the exhaust gases to reinject the larger carbon
particles to the furnace and to divert the fine sand particles to the ash
disposal system.
Several factors can influence emissions, such as boiler size and type,
design features, age, load factors, wood species, and operating procedures.
In addition, wood is often cofired with other fuels. The effect of these
factors on emissions is difficult to quantify. It is best to refer to the
references for further information.
The use of multitube cyclone multiple cyclones provides the particulate
control for many hogged boilers. Usually, two sets of multiple cyclones used
in series, allowing the first collector to remove the bulk of the dust and
the second collector to remove smaller particles. The total mass collection
13
-------
efficiency for this arrangement is from 65 to 95 percent. Low-pressure drop
scrubbers and fabric filters have been used extensively for many years. On
the West Coast, pulse jets have been used.
2.7 LIGNITE COMBUSTION
2.7.1 General
Lignite is a relatively young coal with properties intermediate to those
of bituminous coal and peat. It has a high moisture content (35 to 40 weight
percent) and a low, wet basis heating value (1,500 to 1,900 kilocalories per
kilogram) and generally is burned only close to where it is mined, in some
midwestern states and in Texas. Although a small amount is used in
industrial and domestic situations, lignite is mainly used for steam/electric
production in powerplants. In the past, lignite was burned mainly in small
stokers, but today the trend is toward use in much larger
pulverized-coal-fired or cyclone-fired boilers.
The major advantages of firing lignite are that, in certain geographical
areas, it is plentiful, relatively low in cost, and low in sulfur content
(0.4 to 1 wet basis weight percent). The major disadvantages are that more
fuel and larger facilities are required to generate a unit of power than is
necessary with bituminous coal. There are several reasons for this. First,
the higher moisture content means that more energy is lost in the gaseous
combustion, which reduces boiler efficiency; second, more energy is required
to grind lignite to the combustor-specified size, especially in pulverized-
coal-fired units; third, greater tube spacing and additional sootblowing are
required because of the higher ash fouling tendencies and, fourth, because of
its lower heating value, more fuel must be handled to produce a given amount
of power, since lignite usually is not cleaned or dried before combustion
(except for some drying that may occur in the crusher or pulverizer and
during transfer to the burner). Generally, no major problems exist with the
handling or combustion of lignite when its unique characteristics are taken
into account.
2.7.2 Particulate Emissions and Controls
The major pollutants of concern when firing lignite, as with any coal,
are particulates, sulfur oxides, and nitrogen oxides. Volatile organic
compound (V0C) and carbon monoxide emissions are quite low under normal
operating conditions.
Particulate emission levels appear most dependent on the firing
configuration in the boiler. Pulverized-coal-fired units and spreader
stokers, which fire all or much of the lignite in suspension, emit the
greatest quantity of flyash per unit of fuel burned. Cyclones, which collect
much of the ash as molten slag in the furnace Itself, and stokers (other than
spreader), which retain a large fraction of the ash in the fuel bed, both
emit less particulate matter. In general, the relatively high sodium content
of lignite lowers particulate emissions by causing more of the resulting
flyash to deposit on the boiler tubes. This is especially so in
14
-------
pulverized-coal-fired units wherein a high fraction of the ash is suspended
in the combustion gases and can readily come into contact with the boiler
surfaces.
Newer lignite-fired utility boilers are equipped with large ESP's that
may achieve as high as 99.5 percent total mass particulate control. Older
and smaller ESP's operate at about 95 percent total mass collection
efficiency. Older industrial and commercial units use cyclone collectors
that normally achieve 60 to 80 percent total mass collection efficiency on
lignite flyash. Flue gas desulfurlzation systems currently are in operation
on several lignite-fired utility boilers. These systems are identical to
those used on bituminous-coal-fired boilers.
15
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SECTION 3
PARTICLE SIZE DISTRIBUTION FOR EXTERNAL COMBUSTION SOURCES
Cumulative size-specific emission factors for the external combustion
source categories listed in Section 1 are presented in this section. The
subsections identify the data obtained and reviewed for inclusion into the
size-specific emission factors, the data categorization by emission source
and control device, size-specific emissions on a weight percent with a data
quality ranking, particulate emission factor estimates, and, finally,
recommended cumulative size-specific emission factors. Particle sizes used
in the emission factors are usually expressed in terms of the aerodynamic
equivalent diameter. This method of size expression is useful because it is
readily determined through straightforward measurement; a particle's inertial
characteristics can be used to best predict where deposition will occur in
the respiratory system; and actual particle size and density may not be
obtainable. Small particles are not likely to be round and may be hollow or
deeply cratered spheres.
There are two general classifications of particle size measurement
systems, namely, inertial separation and optical or electrical mobility
measurement. The majority of all particle sizing currently performed in
source testing uses equipment based on inertial separation. Data in this
report are primarily the result of measurements using either of two inertial
instruments, the cascade impactor or the Source Assessment Sampling System
(SASS) three-cyclone train.
The cascade impactor is a low-speed impaction device in which jet stages
and impaction plates are paired. The second jet stage has less open area
than the first, so the air moves through it faster and undergoes more
acceleration in turning to flow around the impaction plate. Thus the second
stage impaction plate is able to collect smaller particles. The cascade
Impactor is designed so that each plate collects particles of one size range
expressed as the particle size in microns for which 50 percent of the
particles are theoretically collected on a particular sampling plate or
stage. The cross section of an Andersen Mark III cascade impactor is shown
in Figure 1. Cascade impactors of similar design and significantly different
designs are offered by several companies.
The SASS train is a system consisting of three cyclones and a filter in
series. It is primarily used to obtain sufficient particulate for trace
element and organics analyses. The SASS may be used to determine the total
particulate concentration plus particulate concentrations in the greater than
10 urn, less than 10 ym but greater than 3 um, less than 3 um but greater than
17
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fCOLt
»*xt scttion
COliETOs "utTl 1C1
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csafir-»K n.iTi >c. 2
JET ST4C£ *G. 3
cfcxccN (VAJi »c s
XT ST*C£ >0 «
cslletbn mjcc tc. *
JC ST*Z tC. s
cousro* rjor ic 5
XT STACC I
couirr** *jn x. t
XT STM£ KS. 7
rr> ¦ PTVX ^UTE «Q 7
nji* coua*
rtrw
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Figure 1. Cross section of Andersen Mark III cascade impactor.
18
-------
1 am, and less than 1 um particulate size ranges. The SASS train does not
provide a sufficient number of particulate size cutpoints to be a preferred
sampling system for determining size distribution but is based on generally
sound methodology.
The particle size distribution of emissions from different points within
a particular source category is expected to vary just as total mass emissions
from similar processes vary. It is possible that emissions from a specific
point may vary significantly from others in the same category. The data
presented herein are considered typical for that category. Quality ratings
of emission factors indicate relative levels of confidence in the data's
representativeness for similar processes operated in an average manner.
Differences may result from subtle or gross differences in design, operating
conditions, feedstocks, control device performance, and maintenance programs.
Care should be taken to remember these limitations when using the particle
size distributions presented herein, and emission factors in general.
A literature review was also conducted to locate inhalable particulate
data. Reports that included the results of measurements and observations of
the author were considered as primary sources and were considered the most
highly desirable for use in calculating inhalable particulate emission
factors. (Individual FPEIS test series were considered primary sources.)
Secondary sources were those in which the author reported emission data
performed by a different organization. When attempts failed to obtain the
primary sources on which key secondary sources were based, it became
necessary to utilize those secondary sources in the development of inhalable
particulate emission factors. Many individual FPEIS test series were
researched to ensure proper classification of the data.
3.1 DATA COLLECTION
Information was sought for categories shown in Figure 2. Data sources
used for the development of size-specific emission factors are listed in
Table 1. FPEIS was used as a primary data source.
Several FPEIS test series and reports provided by others were reviewed
and found to be not useable for emission factor development. Those FPEIS
test series numbers plus other reports and data sources are listed in
Table 2 along with an explanation.
3.2 DATA CATEGORIZATION
The FPEIS printouts and other sources of data were reviewed to determine
the appropriate data categorization by emission source and control device.
In evaluating the data for its usefulness, sufficient Information was
required to assign the data to a. specific source category, to establish the
representativeness of the emission source, control device, and operating
conditions, and to identify the particle sampling method, conditions, and
results. To assign data to a specific source category required
identification of the fuel, emission source, and control device. It was
necessary in cases with some solid fuels to establish whether or not flyash
19
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Bi tuminous
Pulverized coal
Cyclone furnace
Stoker
Handfed
Dry bottom
Wet bottom
Spreader
Overfeed
Underfeed
Uncontrolled
Controlled
Uncontrolled
Controlled
Uncontrolled
Controlled
Uncontrolled
Controlled
Uncontrolled
Control led
Uncontrolled
Controlled
Uncontrolled
Controlled
Anthraci te
Pulverized coal
Stoker
Handfed
Dry bottom
Traveling grate
Uncontrolled
Controlled
Uncontrolled
Controlled
Uncontrolled
Controlled
Fuel oil
Utility boilers
Industrial boilers
Residual oil
Residual oil
Distillate oil
Uncontrolled
I Controlled
Uncontrolled
1 Controlled
Uncontrolled
1 Controlled
Uncontrolled
Uncontrolled
Uncontrolled
(continued)
Figure 2. Categories for which data was sought for the development of
size-specific emission factors.
Commercial boilers
Residual oil
_ Distillate oil
Residential furnaces Distillate oil.
20
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Natural gas
Utility boilers
Industrial boilers
Domestic and commercial boilers
Uncontrolled
Uncontrolled
Uncontrolled
Wood waste
Bark fired
Wood-bark fired
Wood fired
Uncontrolled
Control led*
Uncontrolled
Controlled*
Uncontrolled
Controlled
Ligni te
Pulverized coal
Cyclone furnace
Spreader stoker
Other stokers
Dry bottom
Uncontrolled
Control led
Uncontrolled
Controlled
Uncontrolled
Controlled
Uncontrolled
Controlled
*With and without flyash reinjection to boiler for additional carbon burnup.
Figure 2. (continued)
21
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TABLE 1. DATA SOURCES USED FOR THE DEVELOPMENT OF SIZE-SPECIFIC
EMISSION FACTORS
Source FPEIS test series numbers
category (Ref. 2, 3)
Other data sources
Bituminous and
subbi tuminous
coal combustion
13
181
EMB Report 80-1BR-12
(Ref. 7)
15
128
182
EMB Report 82-1BR-17
(Ref. 8)
16
129
183
EMB Report 82-1BR-18
(Ref. 9)
29
130
242
EPA 68-02-3271
(Ref. 10)
35
169
248
EPA 600/7-81-020A
(Ref. 11)
36
171
250
Ohio Edison Co.
(Ref. 12)
37
172
251
38
173
252
39
174
262
40
175
264
57
176
267
63
177
274
64
178
281
81
179
307
115
180
Anthracite 11 99 247
coal combustion 73 100 253
74 101 254
75 102
98 103
Fuel oil 14 62 198 TR-83-110/EE (Ref. 13)
combustion
14
62
198
17
66
205
22
67
206
23
72
207
24
170
212
59
186
213
60
188
214
61
192
Natural gas EPA 68-02-3512 (Ref. 5)
combustion
(continued)
22
-------
TABLE 1. (continued)
Source FPEIS test series numbers
category (Ref. 2,3) Other data sources
Wood waste 109
combustion in 138
boilers
141
258
EMB
256
259
EMB
257
260 c
EMB
EMB
EMB
EMB
Report 80-WFB-2 (Ref. 14)
Report 80-WFB-4 (Ref. 15)
Report 80-WFB-5 (Ref. 16)
Report 80-WFB-8 (Ref. 17)
Report 80-WFB-9 (Ref. 18)b
Report 80-WFB-10 (Ref. 19)
il (Ref. 20)
Lignite 166 167 168 ERC #7246 (Ref. 21)
combustion
aThe total mass and particle size data for each FPEIS test series listed
in Tables 1 and 2 are given in FPEIS Computer Printout A4F361(Ref. 2) or
43CETA (Ref. 3). Reference 22 lists the original reference document for
each FPEIS test series as of August, 1986.
^Although originally intended to be used in the development of size-specific
emission factors, these tests used salt-laden wood wastes with insufficient
data to generate a reliable particulate emission factor. Size distributions
are presented in this report (but not in the AP-42 section) for informational
purposes and may be of value for future revisions to AP-42.
CA1though originally intended to be used in the development of size-specific
emission factors, this test reported on emissions from a fluidized bed
boiler. Insufficient data exists to generate a reliable particulate emis-
sion factor. Size distributions are presented in this report (but not
in the AP-42 section) for informational purposes and may be of value for
future revisions to AP-42.
23
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TABLE 2. FPEIS TEST AND OTHER REPORTS
EMISSION FACTOR DEVELOPMENT
REVIEWED BUT NOT USED FOR
FPEIS test series numbers
Comments
184 194 197 245 268
191 195 200 246 269
193 196 201 261 270
Insufficient number of SASS
train component catches
reported either due to one or
two cyclones not used or data
not reported
272 273 277
Inadequate sizing device
283
Data from original report used
12 264
187 276
244 287
Data not supported by PADRE
(see Glossary of Terms)
292
Particulate size distribution
data noted to be inconsistent
and not representative
127
Operating conditions not
representative due to ammonia
injection and varied ESP
rapping to study effect on
emi ssions
140
Test agencies could not
confirm this data but did
support FPEIS test series
no. 141 for same boiler
243 278 280 312* 314* 316*
275 279 311* 313* 315*
(*Used SASS train without cyclones)
Test series presented total
mass emission rate data only
(no particle size distribution
data)
(continued)
24
-------
TABLE 2. (continued)
FPEIS test series numbers
Comments
18
51
89**
119
125**
133**
Insufficient data for source
25
58
111
120
126**
163
category classification and
32
65*
116**
121**
131**
185*
test location listed as
50
85
118
122**
132**
190
"confidenti al"
249
(*More detailed information requested from site but not received)
(**Report requested but not received)
Other reports/data sources
Comments
General
"Emission test report, WESTVAVCO Bleached
Board Division, Covington, VA," EMB Report
80-WFB-3, February 1980.
"Compilation of a Preliminary
Particle-Sized Emission Factor Data Base,"
EPA-450/4-82-016, November 1982.
"Fine Particulate Emission Inventory and
Control Survey," by Midwest Research
Institute January 1974, EPA Report No.
EPA-450/3-74-040.
Bark plus coal cofired boiler,
therefore, not applicable to
source categories under review
No primary data presented,
primarily FPEIS test series
data
Limited information presented
in old report. Unable to
determine identity of sites
used as emission sources,
sampling conditions and
equipment and operating
conditions. Since sources are
not identified, they may also
be contained in FPEIS.
Bituminous Coal
"Evaluation of the George Neal No. 3
Electro-static Precipitator," EPRI FP-1145
Project 780-1, August 1979.
Anthracite Coal
"Source Sampling of Anthracite Coal-Fired
Boilers," by Scott Environmental
Technology, Inc., May 1975.
Particulate size data not
reported in a useable format
Report used Coulter Counter for
particle count in a liquid
(continued)
25
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TABLE 2. (continued)
Other reports/data sources Comments
Oil
"Environmental Assessment of an Oil-Fired
Controlled Utility Boiler,"
EPA-600/7-80-087, April 1980.
"Emissions Assessment of Conventional
Stationary Combustion Systems; Vol. 1.
Gas- and Oil-Fired Residential Heating
Sources," EPA-600/7-79-0296, May 1979.
"Particulate Emission Characteristics of
Oil-Fired Utility Boilers," EPRI CS-1995,
Research Project 1131-1, August 1981.
"Kramer Station Fabric Filter Evaluation,"
EPRI CS-1669, Research Project 1130-1,
January 1981.
Due to the extremely light
particulate loading,
particulate size distribution
data were not presented
SASS train used without
cyclones thus no particle size
distribution data were
presented
Reduced data not presented in
a directly useable form
Reduced data not presented in
a directly useable format
Wood
"An Investigation of Source Particulate
Measurement Procedures, Particle Sizes, and
Practiced Control Technology for Wood
Fuel-Fired Boilers," Atmospheric Quality
Improvement Technical Bulletin No. 72,
National Council of the Paper Industry for
Air and Stream Improvement, Inc., June
1974.
Report does not present
particulate size distributions
for uncontrolled or controlled
flue gas streams
"Emission Test Report, WI Forest Products
Inc., Long Lake Lumber Division," EMB
Report 80-WFB-ll, March 1981.
Size distribution data validity
extremely questionable since
one to seven stages of each
sample using an Andersen
cascade impactor with seven
stages (and a backup filter
plus either a preimpactor
cyclone or an eighth stage)
were reported as collecting no
particulate
(continued)
26
-------
TABLE 2. (continued)
Other reports/data sources Conments
Li gnite
Portions of data provided with letter from
Mr. Dana Mount, North Dakota State
Department of Health to Mr. A. Walter Wyss,
Acurex Corporation.
Specific Portions:
December 17, 1980 sampling at boiler
no. 6 at North Dakota State University in
Fargo, North Dakota.
March 12, 1980 sampling at Boiler No. 7
at North Dakota State University in
Fargo, North Dakota.
October 30, 1979 sampling at American
Crystal Sugar Plant at Drayton, North
Dakota.
May 10, 1979 sampling on no. 91 auxiliary
boiler Baghouse at the Oak Creek Station
near Underwood, North Dakota.
October 17, 1978 sampling on boiler
no. 1 at the San Haven State Hospital
in Dunseith, North Dakota.
November 18, 1976 sampling at boiler
no. 4 at North Dakota State University
in Fargo, North Dakota.
Standards Support and Environmental Impact
Statement Volume 1: Proposed Standards of
Performance for Lignite-Fired Steam
Generators, December 1975, EPA
Sizing procedures used X-ray
sedimentation
Sizing procedure used X-ray
sedimentation
Sizing procedure used
MSA-Whitby sedimentation
centri fugation
Sizing procedure used MSA
sedimentation centrifugation
Sizing procedure used MSA
sedimentation centrifugation
Sizing procedure apparently
used MSA sedimentation
centri fugation
No particle sizing
presented
information
27
-------
captured by a control device was reinjected into the combustor. Emission
sources and control devices representative of actual units in operation were
preferred over small-scale demonstration and development sources and control
devices. Normal operating conditions were preferred as opposed to low-load
conditions and conditions with severe operating malfunctions. Particle
samples using inertial separation were preferred over other methods, but
enough information was required to establish if the sampling was performed in
an acceptable manner and to show completeness of sampling data. Table 3
shows the number of data sets obtained for each emission source and control
device.
3.3 DATA EVALUATION
The data obtained were reviewed, analyzed, and ranked according to the
criteria provided in the report "Technical Procedures for Developing AP-42
Emission Factors and Preparing AP-42 Sections," If there was no reason to
exclude particular data from consideration (see Section 3.2), each data set
was assigned a ranking. The data were ranked as follows:
A — Tests performed by a sound methodology and reported in enough
detail for adequate validation. These tests are not necessarily
EPA reference method tests, although such reference methods will
certainly be used as a guide.
B — Tests performed by a generally sound methodology but lacking enough
detail for adequate validation
C -- Tests based on an untested or new methodology or lacking a
significant amount of background data
D — Tests based on a generally unacceptable method but which may
provide an order-of-magnitude value for the source
In general, FPEIS and other data were ranked as A-quality if a standard
cascade impactor was used, sampling flowrate isokinetic value was reported
and fell with an acceptable range of 90 to 110 percent and sufficient
operating data were listed to firmly classify the system tested into one of
the categories for which a particulate emission factor has been developed.
Data were typically downgraded to B-quality if the isokinetic values were not
reported or were not within the 90 to 110 percent range. Reports and points
of contact listed in the FPEIS data base were frequently sought to further
clarify test data and operating conditions.
SASS data were generally ranked as B-quality if the sampling flowrate
isokinetic value was reported and sufficient operating data was listed to
firmly classify the system into one of the external combustion sources. Data
were typically ranked as C-quality if the sampling isokinetic values were not
reported or were reported as not within the 90 to 110 percent isokinetic flow
range.
28
-------
TABLE 3. EXTERNAL COMBUSTION SOURCE CATEGORIES AND IDENTIFIED DATA SETS
USED FOR EMISSION FACTOR DEVELOPMENT
External combustion Number of
emission source category Emission control device data sets
Bituminous and subbituminous
coal combustion
• Dry bottom, pulverized coal None 126
fired Multiple cyclones 4
.Scrubber 62
ESP 127
Baghouse 2
• Wet bottom, pulverized coal None 3
fired Multiple cyclones 1
ESP 5
• Cyclone furnace None 1
Scrubber 1
ESP 5
• Spreader stoker None 43
Multiple cyclone with flyash
injection 1
Multiple cyclone without flyash 11
reinjection
ESP 1
Baghouse 59
¦ Overfeed stoker None 3
Multiple cyclones 3
• Underfeed stoker None 6
Multiple cyclones --a
• Hand-fired units None
Anthracite Coal Combustion
• Pulverized coal fired None
Multiple cyclones 101
Baghouse 66
• Stoker None 3
• Hand-fed units None
(continued^
29
-------
TABLE 3. (continued)
External combustion Number of
emission source category Emission control device data sets
Fuel oil combustion
t Utility boilers, residual None 28
oil ESP 2
Scrubber 4
• Industrial boilers None 17
-- Residual oil Multiple cyclones 1
-- Distillate oil None 2
• Commercial boilers
— Residual oil None 19
-- Distillate oil None 3
• Residential furnaces
-- Distil late oil None
Natural gas combustion
• Utility boilers
• Industrial boilers
• Domestic and commercial
boi1ers
Wood combustion
• Bark fired None 11
Multiple cyclones with flyash
reinjection 9
Multiple cyclones without flyash
reinjection
Scrubber 8
• Wood bark fired None 2^
Multiple cyclones with flyash
reinjection 3C
Multiple cyclones without flyash
reinjection 4^
Scrubber 2
Baghouse —d
Dry electrostatic granular filter 9
f Wood fired None
(conti nued)
30
-------
TABLE 3. (continued)
External combustion
emission source category
Emission control device
Number of
data sets
Lignite coal combustion
• Dry bottom, pulverized
None
Multiple cyclone
2
4
coal fired
• Cyclone furnace
• Spreader stoker
None
None
• Other stokers
Multiple cyclone
None
1
aTwo data sets presented but not used for emission factor development for
underfeed stokers with multiple cyclone controls burning bituminous coal.
Uncontrolled emissions (i.e., emissions into the control device) appeared to
be approximately double average uncontrolled emissions.
^Three data sets also presented for salt-laden wood bark and fluidized bed
boilers but not used for emission factor development at this time.
cFifteen data sets also presented for salt-laden wood bark but not used for
emission factor development at this time.
dSame as c except 3 data sets.
31
-------
The rated data were grouped according to process type. In cases where a
single test report presented data on two processes or both controlled and
uncontrolled emission data on the same process, each was considered
separately. Size-specific emission data are presented in this report in the
uniform format of size ranges 0.625, 1.0, 1.25, 2.5, 6, 10, and 15 microns
aerodynamic equivalent diameter. The FPEIS data base used the Particulate
Data Reduction (PADRE) program for size reporting. The PADRE program is an
interactive computer program that facilitates entry of validated cascade
impactor data for particle size distributions from representative in-stack
runs into FPEIS. PADRE was developed to ensure the quality of data included
in FPEIS, which is a component of the Environmental Assessment Data Systems
(EADS). Impactor stage cut points are calculated and cumulative and
differential mass concentrations are determined and interpolated to standard
diameters. In several cases the FPEIS data base did not report emission data
for the entire size range and those data are reported without extrapolation
(Ref. 2 and 3). Essentially all of the non-FPEIS test reports did not report
particle size distributions in terms of the specific cut points of interest
(i.e., 0.625, 1.00, 1.25, and 2.5 ym, etc.). In these cases, a computer was
used to plot the reported data. A curve or line was then fit to the plotted
points and the values of interest were selected. In cases where the
individual runs were graphically presented in the test report, the values for
the specific size ranges were read from the individual graphs and averaged
arithmetically. In cases where only stage cut point and mass data were
presented, the desired particle size information was acquired by
arithmetically calculating percent mass less than the cutpoint and plotting
the data on a log-probability graph to visually interpolate the specific size
ranges.
3.3.1 Bituminous and Subbituminous Coal
Cumulative size-specific particle size distribution data for each
emission source and control device for bituminous and subbituminous coal
combustion are listed in Tables 4 through 23. The tables include an assigned
rating for each data set.
The FPEIS data base managed by the Environmental Protection Agency was
extensively used to provide data sets for this study. A discussion of these
data sets and those obtained from other reports follows. The FPEIS data sets
are listed numerically by their test series number (TSN) and are followed by
a discussion of other relevant tests.
TSN 13
The data in this series came from emissions sampling of a 450-GJ/hr
(125-MW), dry-bottom utility boiler firing pulverized bituminous coal. This
unit (Widows Creek unit no. 5 near Bridgeport, Alabama operated by the
Tennessee Valley Authority (TVA)) used multiple cyclones to reduce
particulate emissions.
Emissions testing lasted 3 days 1n August of 1974. Operating loads were
in the range of 96 percent to 99 percent of design capacity. Samples were
32
-------
TABLE 4. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED DRY BOTTOM
BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET 1 DENT I F I CAT J ON CUMULATIVE MASS PERCENT LESS Than DATA
TEST TEST TEST 5TMEU SI2C tnlOVUNSl RAr.r
SITE* KCj. SHFv 0.625 2.00 1.25 2.50 6.00 10.00 IS.uO
13
I
2
I
1
2
4
13
32
56
B
2
2
i
J
I
3
15
31
U
3
2
l
J
2
4
IB
34
57
6
15
1
1
20
30
4U
/5
94
Vfc
100
D
J
2
17
34
40
59
7B
B/
93
D
2
1
45
71
82
J 00
100
100
loO
D
16
28
36
50
80
B9
94
0
3
1
9
18
25
47
71
83
90
D
3
2
i 3
26
33
55
77
87
92
D
3
3
13
21
33
67
91
97
99
D
16
1
1
3
IV
26
40
72
U4
9|
D
I
-
4
17
26
50
74
U5
91
D
29
1
2
4
6
U
21
60
81
92
A
1
3
0
1
1
U
27
44
6w
A
2
2
->
3
4
10
24
40
62
A
3
2
0
0
1
3
7
22
4V
A
3
2
3
20
46
63
76
A
1
54
t,4
55
61
63
66
D
2
4
5
10
23
31
42
U
J
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2
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4 2
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b
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2
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6
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26
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1
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11
16
24
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12
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n
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2
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1 4
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1
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9
14
22
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2
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13
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1
4
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3
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31
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14
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1
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1
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10
15
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b
5
3
2
9
13
21
B
5
4
1
1
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12
17
25
b
5
5
1
1
2
13
20
28
b
to
1
1
1
o
10
16
24
b
6
2
0
O
1
8
12
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6
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6
4
0
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10
16
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b
6
5
0
n
9
14
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b
7
1
1
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10
15
23
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7
->
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2
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15
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3
0
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10
15
23
is
7
4
1
1
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1
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0 1
1
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9
12
23
B
1
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1 1
I
4
io
2
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B
1
3
1 2
6
17
20
29
b
1
4
0 1
1
4
12
17
23
b
2
1
1 1
1
->
1 1
15
23
b
">
2
1 1
1
4
9
13
19
b
3
1 2
5
14
20
29
b
4
0 0
1
n
7
10
ia
C\
2
5
1 2
15
21
31
b
2
6
1 1
1
3
12
15
23
b
3
1
1 1
1
6
19
26
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i 1
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33
k
3
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h
33
(continued)
-------
TABLE 4. (continued)
DATA SET IDENTIFICATION
TEST TEST TEST
SITEl NO. SMPL
CUriULAUVfc MASS PtKCtENf LESS ThAN DATA
STATED SIZE (MICRONS) RANK
0.6213 1.O0 1.25 2. 50 6.00 JO. 00 lb.00
1
1
1
2
4
9
26
35
43
y
1
2
0
1
1
2
7
11
lb
t)
1
3
2
4
5
10
22
29
40
b
1
4
1
-»
3
IO
IB
25
36
b
3
I
I
1
1
3
16
25
37
a
3
2
1
2
3
I 3
29
39
49
b
3
3
0
1
1
5
12
17
25
b
3
4
0
2
2
7
19
26
35
b
3
5
1
2
3
] 3
27
40
52
B
4
1
3
4
4
7
23
27
43
h
4
2
0
0
1
n
7
10
16
B
4
3
0
1
2
9
23
30
46
E>
4
4
0
1
1
6
1
31
43
h
4
5
0
0
1
3
B
12
13
b
5
1
3
5
6
13
30
37
51
B
5
2
1
1
1
4
17
21
29
b
s
3
3
4
t,
16
34
43
62
b
5
4
1
2
5
14
31
40
53
B
6
1
2
6
6
10
20
23
36
B
6
2
2
4
5
10
25
31
45
b
6
3
3
A
5
10
27
32
42
h
6
4
2
3
4
9
18
24
32
B
8
1
•»
2
3
6
13
20
29
b
3
2
1
2
3
5
13
16
2a
h
e
3
2
3
5
12
24
29
42
B
8
4
2
4
z
i s
21
26
39
&
9
2
2
2
4
10
10
24
3B
&
1
2
2
->
6
1Q
23
26
&
2
O
0
1
1 1
19
22
B
2
1
0
0
2
15
19
21
b
2
2
4
1 1
17
27
b
3
1
0
1
3
1 1
IB
29
B
3
2
o
0
1
2
i l
15
25
b
A
1
0
0
0
1
6
1 1
23
b
4
2
0
1
3
9
18
32
B
5
1
i
3
8
12
13
B
5
2
1
3
9
1 2
16
b
6
1
2
3
3
7
14
IB
27
b
6
2
7
3
10
16
23
B
7
i
i
\
3
12
15
20
b
7
2
!
\
3
B
1 2
16
b
6
1
0
1
1
3
13
Ifi
23
b
I
1
1
5
B
20
39
42
44
B
1
2
2
4
5
13
32
35
40
b
2
1
0
2
3
7
34
37
42
b
2
2
3
a
1 1
22
4b
49
52
b
->
T
3
n
3
14
34
3&
44
b
2
4
0
1
2
6
13
17
23
b
2
5
2
3
3
1 1
24
20
31
b
3
1
1
2
3
12
26
33
4 2
b
3
2
0
]
1
4
1
14
16
b
3
3
t
1
2
6
13
16
IB
b
4
l
I
3
4
I
25
29
36
b
4
2
1
2
4
12
26
30
35
b
X
1
4
&
15
40
55
71
&
1
2
2
3
4
-
10
16
26
A
1
5
4
t)
7
12
21
28
38
A
1
B
4
6
7
10
17
23
30
A
2
2
3
3
4
6
13
6
31
A
NK
DATA AVERAGL
3
4
10
23
34
49
NK
DAIA AVERAGE
1
2
2
6
16
->2
31
115
24U
30/
A
b
A*B RANK DATA AVERAGE
23
9 SEE TEXT FDR TEST SITE IDENTIFICATION.
34
-------
TA3LE 5. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE CONTROLLED
DRY BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL O.625 i.00 1.25 2.50 6.00 10.00 15.00
13
1
4
O
0
0
1
13
29
54
B
2
4
3
3
3
4
13
28
53
B
3
4
0
0
1
3
17
31
55
B
169**
1
2
o
0
0
1
2
23
D
B
RANK DATA
AVERAGE
1
1
1
3
14
29
54
~SEE TEXT FOR TEST SITE IDENTIFICATION.
• * ME CHANICAL COLLECTOR MALFUNCTION DURING TEST PERIOD.
35
-------
TABLE 6. PARTICLE SIZE DISTRIBUTION DATA FOR SCRUBBER CONTROLLED BOILERS
BURNING PULVERIZED BITUMINOUS COAL
DATA SET I DEnT 1F !CAT IO; DJM'Ji-ATI vE ftASS PERCENT LESS fnAN l)i'< i A
TEST TCS1 T E:iT STATED SIZE ;M1LkUNS> kANK
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20
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ti
£
•WE 11 »
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50
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b
A
rank:
DATA
AVERAGE
39
/o
78
92
96
9 7
9&
b
ra->:
15A1 A
average
17
24
2/
44
56
67
77
C
rank
DATA
AVFRAGE
27
34
50
53
53
63
A*&
RAN<
DATA
AvFRAEE
20
31
35
51
62
71
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B*C
A AUK
DATA
AVERAGE
17
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WANK
DATA
AVERAGE
20
30
35
51
62
71
80
ISEE TEXT FDR TEST SITE IDENTIFICATION.
»1MECHANICAL COLLECTOR UPST Rfc Aft OF SCHUbbEh
• *»AVEKAGE OF 6 SAMPLES FOR D. B SAMPLES FOR E. ESP UPS 1 REAM Df-
SCRUbbER.
36
-------
TABLE 7. PARTICLE SIZE DISTRIBUTION DATA FOR ESP CONTROLLED DRY BOTTOM
BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE r!AE5 PCftCCNT LESS THAN LATA
TEST TEST TEST STATED Q12E (MlCkUNSJ HANi:
SITt:l NO. SnF-L 0-62S 1.00 ] . 2b i'.bO 6.1.0 IO. Iti.l'U
29
I
->->
36
43
64
/5
81
00
1
7
20
34
53
73
93
99
A
2
5
211
39
16
67
EJ5
93
97
A
2
7
27
43
37
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93
94
96
A
3
3
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46
35
/£>
08
93
97
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3
7
30
53
63
00
95
98
99
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81
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5
16
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60
83
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&
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6
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22
47
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84
b
1
7
6
10
20
43
60
70
b
1
6
7
1 1
24
42
54
70
U
2
7
0
12
20
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64
76
0
2
a
14
IV
44
74
83
97
b
2
9
6
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24
56
75
07
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2
10
15
19
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58
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03
b
3
4
3
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63
79
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3
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2
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4B
63
7B
b
3
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£>6
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b
115
1
5
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15
27
52
67
76
b
1
6
6
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37
47
&
1
7
2
7
10
22
48
61
73
b
129
h
I
5
11
29
50
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73
C
6
1
U
13
20
44
56
69
c
9
1
7
9
20
35
49
63
c
10
1
3
7
23
47
61
75
L
12
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81
91
94
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b
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62
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2
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9
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90
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3
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s
a
I 1
23
60
92
99
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3
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8
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45
67
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3
l
3
12
26
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62
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4
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30
63
84
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2b
54
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ti
23
50
70
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5
3
2
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10
24
41
55
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6
1
0
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13
c
6
2
12
1 6
-»-»
43
73
91
b
6
3
1
3
1 3
33
61
80
b
7
1
1
2
->
B
23
43
59
&
7
0
1
8
26
50
68
&
7
3
i
3
10
26
5-;
76
b
B
1
2
2
8
26
59
79
&
e
2
2
2
9
28
54
73
8
e
3
2
3
12
33
62
80
&
9
1
1
2
8
27
46
62
&
9
2
3
4
13
37
63
81
B
9
3
2
3
10
27
54
74
b
16
I
2
2
a
24
50
ad
8
10
2
3
4
15
44
75
93
D
10
3
3
5
16
38
67
83
6
(continued)
37
-------
TABLE 7. (continued)
DATA SET IDENTIFICATION CUMULATIVE MASS PLliCENT LESS THAN DAI A
TEST TEST TEST STATED SUE (MICRONS) RANK
51TCf NO. SMfL 0.625 J . 0<» 1.25 2.50 6-00 10.00 15.00
i I ]
3
8
17
39
36
F'
1 1 2
2
3
13
30
54
70
b
1 1 3
1
3
20
*»3
68
89
b
12 i
1
2
6
14
30
45
Ei
12 2
)
2
7
19
47
69
b
12 3
1
3
1 3
33
55
73
B
13 1
2
2
9
23
51
70
t<
13 2
;
2
8
2?
48
66
b
13 3
6
20
53
79
fa
267 4 1
I 1
15
16
36
81
89
95
A
EPA-68- A AVE*tV
3
5
8
ID
38
57
71
b
02-3271 B AVEltt
&
14
10
32
52
64
74
6
C AVE#If
5
8
10
15
27
37
47
fi
OHIO- EDJ 3 1
23
35
42
64
91
too
too
8
EDISON EDI 3 2
13
25
32
52
79
95
99
&
EDi 3 3
7
12
15
30
65
88
98
8
EDI 3 4
22
32
38
5 9
80
90
too
8
G025 3A
17
26
32
52
76
90
95
8
G025 31*
1Q
24
20
41
59
74
64
B
GQ25 4A
17
us
30
4 V
72
93
99
fa
G025 46
lb
24
2 b
40
50
68
73
b
G02S 1A
1 1
15
17
27
4 1
51
60
H
G02S 1 &
->->
33
40
60
81
92
96
8
G025 2A
16
25
29
<15
67
77
87
a
G023 2B
22
32
37
54
74
05
90
B
G025 IA
12
21
25
42
65
86
95
8
G025 IB
13
23
30
49
74
90
97
8
GD25 2A
12
22
27
44
71
04
91
8
G025 26
to
25
30
44
VO
BV
96
B
G026 IA
13
23
28
43
67
05
95
8
G026 1B
t 2
21
27
37
58
82
94
8
G026 2A
It.
23
27
43
66
82
91
b
GO26 28
9
13
15
22
Jb
44
51
&
G026 IA
i 5
24
30
50
75
88
94
8
G026 lb
20
30
35
53
74
89
95
8
TOli i
29
44
«%•¦»
73
97
lOu
loo
8
TOi 1 2
29
41
48
68
bo
99
J 00
8
T011 3
2/
37
43
60
uv
99
100
8
TO 1 1 4
2 6
3G
44
63
87
100
100
8
T009 1
10
19
25
40
76
95
99
8
T009 2
24
30
35
54
bl
92
96
B
T009 3
16
28
34
55
H2
97
too
b
T009 S
27
40
47
67
93
99
too
8
TOlO t
12
21
24
37
67
86
93
8
TOlO 2
15
21
24
39
70
87
92
8
A DATA AVERAGE
22
37
45
67
05
92
96
8 DATA AVERAGE
1 1
1 2
15
27
48
65
77
C DATA AVERAGE
0
22
25
36
46
54
65
A+8 DATA AVERAGE
1 2
14
17
29
50
67
79
£mC DATA AVERAGE
11
13
16
27
47
65
76
A«-b*C DATA AVERAGE
12
14
18
30
50
66
7B
*GCC TEXT FOR TEST
SITE IDENTIFICATION.
»»nULTIPLE CYCLONES
UPSTREAM
OF
ESP.
19tAVERAGE Of 11 SAMPLES FCR A, 8 SAMPLES FOR B, AnD 8 SAMPLES FOR C.
NOTE THAT C HAS 2 ELECTROSTATIC PRECIPATORS JN SERIES.
38
-------
TABLE 8. PARTICLE SIZE DISTRIBUTION DATA FOR BAGHOUSE CONTROLLED
DRV BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRON S) RANK
SITE* NO. SMPL 0.625 l.OO 1.25 2.50 6.00 10.OO 15.00
OHIO- SAM3 1 16 28 34 55 79 96 99 B
EDISON SAM3 2 12 22 28 50 75 B7 94 B
B RANK DATA AVERAGE 14 25 31 53 77 92 97
•SEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 9. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED
WET BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 l.OO 1.25 2.50 6.00 10.00 15.OO
64
1
1
3
5
7
26
41
44
46
B
1
2
4
S
10
14
16
18
B
2
1
2
4
5
26
43
50
57
B
B RANK DATA AVERABE 2 4 6 21 33 37 40
*SEE TEXT FOR TEST SITE IDENTIFICATION.
39
-------
TABLE 10. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE CONTROLLED
WET BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL O.625 l.OO 1.25 2.50 6.00 iO.OO 15.OO
264 11 19 31 61 B4 93 99 C
C RANK DATA AVERAGE 19 31 61 84 93 99
*SEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 11. PARTICLE SIZE DISTRIBUTION DATA FOR ESP CONTROLLED
WET BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITEt NO. SMPL O.625 l.OO 1.23 2.50 6.00 IO.OO 15.OO
174««
1 1
21
39
79
95
99
100
C
175
1 1
11
22
55
B8
lOO
100
C
176
1 1
6
18
31
80
91
98
C
177
1 1
n
4
9
31
48
65
C
178
1 1
1
2
5
20
36
54
c
C RANK DATA AVERAGE B 17 40 63 75 83
~SEE TEXT FOR TEST SITE IDENTIFICATION.
ttMECHANICAL COLLECTOR FOLLOWED BY ESP.
40
-------
TABLE 12. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED CYCLONE
FURNACES BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.00 15.OO
17112 O 0 0 B 13 33 D
D RANK DATA AVERAGE 0 0 O B 13 33
•SEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 13. PARTICLE SIZE DISTRIBUTION DATA FOR SCRUBBER CONTROLLED
CYCLONE FURNACES BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.623 1.00 1.23 2.50 6.00 10.OO 15.OO
171 14 B2 85 92 93 94 95 A
A RANK DATA AVERA6E B2 B5 92 93 94 95
•SEE TEXT FOR TEST SITE IDENTIFICATION.
41
-------
TABLE 14. PARTICLE SIZE DISTRIBUTION DATA FOR ESP CONTROLLED
CYCLONE FURNACES BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.OO 13.00
179
1
2
2
10
33
49
66
C
100
1
25
31
48
69
BO
89
C
1B1
1
11
15
27
47
61
74
C
1B2
1
32
38
34
71
80
88
B
183
1
17
24
42
61
71
81
B
B
DATA
RANK
AVERAGE
25
31
48
66
76
BS
C
DATA
RANK
AVERAGE
13
16
28
50
63
76
B+C
DATA
RANK
AVERAGE
17
4.4m
36
56
68
BO
•SEE TEXT FOR TEST SITE
IDENTIFICATION.
42
-------
TABLE 15. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED
SPREADER STOKER BOILERS BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 l.OO 1.25 2.50 6.00 10.OO 15.00
35
1
2
10
12
17
24
27
B
2
2
3
4
8
12
22
B
3
2
2
7
11
23
B
4
2
1
1
4
7
21
B
5
2
3
4
8
12
20
B
6
2
3
4
12
27
37
B
7
2
4
10
18
30
B
a
2
7
13
19
33
B
9
2
5
10
23
34
B
io
2
3
8
15
29
B
11
2
2
5
11
22
40
B
12
2
8
13
20
26
35
B
13
2
2
6
11
o*->
34
B
14
2
1
4
11
17
26
B
16
n
at-
1
6
12
20
31
B
17
2
1
4
11
19
33
B
IB
2
1
4
9
17
32
B
19
2
3
7
12
19
31
B
20
2
O
4
7
11
17
B
21
2
4
7
15
20
28
B
22
2
8
16
23
2B
33
, B
63
1
1
1
1
1
8
13
16
28
C
274
2
3
2
2
2
12
35
60
A
-IBR
1
1
1
1
1
2
2
3
3
A
-12
1
2
4
4
5
5
7
9
10
A
¦IBR
1
1
1
1
1
1
2
4
6
A
-17
1
2
1
1
1
2
4
6
9
B
1
3
1
3
4
7
12
14
15
A
2
1
1
1
1
2
4
8
13
A
2
2
3
4
4
6
12
18
24
A
2
3
3
5
6
9
15
19
24
A
3
1
3
3
4
5
8
12
16
A
3
2
3
3
3
5
B
10
14
A
3
3
1
2
2
4
8
11
14
A
¦IBR
1A
1
1
1
1
1
4
6
8
B
-IB
2
1
4
10
13
30
59
73
B4
B
3
1
2
4
5
9
17
20
25
B
4
1
8
12
13
17
27
29
31
B
5
1
7
7
7
8
14
14
B
6
1
2
3
3
6
14
17
20
B
7
1
4
7
9
19
38
SO
54
B
B
1
7
13
15
19
30
34
37
B
9
1
13
17
19
30
55
67
76
B
A
RANK
DATA
AVERAGE
2
3
3
4
8
13
IB
B
RANK
DATA
AVERAGE
5
8
5
8
16
23
32
A+B
RANK
DATA
AVERAGE
4
5
5
7
14
20
28
•SEE TEXT FOR TEST SITE IDENTIFICATION.
43
-------
TABLE 16. PARTICLE SIZE DISTRIBUTION DATA FOR BITUMINOUS COAL FUELED
SPREADER STOKERS WITH MULTIPLE CYCLONES WITH FLYASH
REINJECTION
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.OO 15.00
242 62 1 2 2 B 51 73 86 C
C RANK DATA AVERAGE 1 2 2 B 51 73 86
tSEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 3-17. PARTICLE SIZE DISTRIBUTION DATA FOR BITUMINOUS COAL FUELED
SPREADER STOKERS WITH MULTIPLE CYCLONES WITHOUT FLYASH
REINJECTION
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE «MICRONS> RANK
SITE* NO. SMPL 0.625 1.OO 1.25 2.50 6.00 10.00 15.00
BO-IBR 1 1 17 22
-12**
B2-IBR 11 B 11
-IB** 1A 1 13 17
2 1 13 19
3 1 12 20
4 1 10 17
5 1 2 2
6 1 5 8
7 1 6 11
B 1 13
9 1 7 14
26
40
55
60
65
A
12
19
47
67
80
B
20
28
5B
65
68
A
22
34
62
7B
91
A
21
32
62
78
88
A
22
40
70
77
B5
A
3
9
26
39
51
A
9
16
39
57
70
A
13
2B
54
70
BO
B
4
15
42
58
70
A
17
30
57
73
81
A
A
RANK
DATA
AVERAGE
9
14
16
27
52
65
74
B
RANK
DATA
AVERAGE
7
11
13
24
51
69
BO
A+B
RANK
DATA
AVERAGE
9
13
15
26
52
66
75
•SEE TEXT FOR TEST SITE IDENTIFICATION
t(TWO STAGES OF MULTIPLE CYCLONES
44
-------
TABLE 18. PARTICLE SIZE DISTRIBUTION DATA FOR ESP CONTROLLED
SPREADER STOKERS BURNING BITUMINOUS COAL
DATA SET
IDENTIFICATION
CUMULATIVE MASS PERCENT LESS THAN
DATA
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE*
NO.
SMPL
O.625 l.OO 1.25 2.50 6.00 10.OO 15.00
262**
1
1
41 46 61 B2 9Ci 97
C
C RANK DATA AVERAGE 41 46 61 B2 90 97
*SEE TEXT FDR TEST SITE IDENTIFICATION.
**MULTIPLE CYCLONES UPSTREAM OF ESP
45
-------
TABLE 19. PARTICLE SIZE DISTRIBUTION DATA FOR BAGHQUSE CONTROLLED
SPREADER STOKER BURNING BITUMINOUS COAL
DAT ft SET I DENT JFICAT!On CUMULATIVE MASS PEFtCFNT LESS THAN DATA
TES! TEST TEST STATED SIZE" ihlCRONSJ DAI A
SITE* NO. SMPL 0.6?5 1.00 1.23 2. Si.' 6.00 10.00 13.00
35
3
4
5
5
B
:5
23
37
B
2
4
3
16
33
62
D
3
4
B
B
1 0
17
28
57
B
4
4
3
16
49
D
5
4
1 3
;3
lb
25
39
S3
b
6
4
12
12
IS
1 7
32
62
b
7
4
6
9
13
26
42
61
b
e
4
2
3
10
18
24
50
b
9
4
V
13
23
35
55
73
b
10
4
3
6
15
28
40
6£>
b
11
4
4
6
14
27
45
7
D
12
4
BO
b9
Q9
90
91
94
U
13
4
3
7
33
24
34
64
b
14
4
58
59
62
67
74
B2
b
15
4
6
9
15
33
39
5/
b
16
4
B
1 1
19
34
4B
68
b
17
4
13
18
20
45
hi
76
b
1U
4
93
93
94
93
96
96
b
19
4
9
13
27
47
62
79
b
20
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15
16
2b
4 1
53
74
b
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4
11
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43
59
7a
F»
•j2
3
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16
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47
67
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9
10
1 9
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69
A
1
13
16
30
64
BO
85
A
2
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ti
10
21
41
53
57
A
2
13
17
32
55
64
72
A
3
I
20
26
33
61
73
70
A
A
1
V
16
23
46
67
72
A
3
1
di
9
15
44
56
t,7
A
37
1
1
1 3
13
id
31
38
42
A
1
15
i 9
33
65
BO
b5
A
2
I
3
4
13
32
52
71
A
3
1
6
7
1 4
25
48
61
A
4
I
20
23
30
49
62
e>7
A
5
1
25
2fci
3b
£>3
//
82
A
6
I
11
16
30
61
77
B2
A
38
I
45
49
53
65
73
78
A
o
1
26
29
37
56
70
77
A
3
1
23
27
38
59
72
80
A
4
1
25
29
42
65
75
83
M
5
1
18
24
27
35
55
66
73
A
39
1
3
5
14
39
55
38
A
2
1
4
8
10
17
40
51
57
A
3
1
5
7
10
19
5?
72
78
A
4
I
6
1 1
M
24
60
73
61
A
5
1
5
10
14
24
57
76
80
A
6
1
15
20
23
27
59
78
83
A
7
3
io
16
24
Si
69
74
A
G
I
2
5
7
1 1
37
65
76
A
9
!
4
10
15
22
52
78
93
A
10
i
-»
9
12
21
51
Bl
97
A
1
1
7
13
22
50
65
68
A
40
1
1
1 1
16
29
53
65
7 l
A
2
1
4
1 1
17
29
53
66
73
A
3
1
6
15
20
34
34
62
66
A
4
1
13
12
17
29
59
68
73
A
5
1
0
15
20
33
56
65
71
A
6
1
7
14
17
27
59
79
89
A
7
1
e
35
IB
29
36
7to
67
A
A
RANK DATA
AWERAEE
7
14
17
27
C-O
67
75
B
HANK. DATA
AVEHACiE
IB
20
26
35
48
68
A+6
RANK DATA
AVERAGE
7
15
10
26
46
60
72
*SE£ TEXT FCR TEST SITE 7 DENT J FTCAT 3 DN.
46
-------
TABLE 20. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED
OVERFEED STOKERS BURNING BITUMINOUS COAL
DATA SET
IDENTIFICATION
CUMULATIVE MASS
PERCENT LESS
THAN
DATA
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE*
NO.
SMPL
0.625
1. OO 1. 25
2.50 6.00 lO.
00 15.00
281
3
3
4 5
6 23
45 67
A
EPA—600
L2
AVE**
10
12 13
15 22
30 38
B
/7-ei-
L4
AVE**
17
IV 20
20 27
35 42
B
02 OA
A
RANK
DATA
AVERAGE
4
5
6
23
45
67
B
RANK
DATA
AVERAGE
14
16
17
18
25
33
40
A+B
RANK
DATA
AVERAGE
14***
12
13
14
24
37
49
•SEE TEXT FOR TEST SITE IDENTIFICATION.
**TREATED AS ONE SAMPLE EACH.
St(AVERAGE NOT USED DUE TO INCONSISTENCY IN REPORTING.
TABLE 21. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE CONTROLLED
OVERFEED STOKERS BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL O.625 1.OO 1.25 2.50 6.00 10.00 15.00
251
1 1
B1
82
85
92
95
98
B
EPA-600
/7-81-
020A
L2 AVE**
L4 AVE**
11
20
13
22
14
22
17
27
22
33
29
40
35
47
El
B
B AVER
16
39
39
43
49
55
60
• SEE
TEXT FOR TEST SITE
IDENTIFICATION.
t*TREATED AS ONE SAMPLE EACH.
47
-------
TABLE 22. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED
UNDERFEED STOKERS BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION
TEST TEST TEST
SITE* NO. SMPL
CUMULATIVE MASS PERCENT LESS THAN DATA
STATED SIZE (MICRONS) RANK
0.625 1.00 1.25 2.50 6.00 10.00 15.00
EPA-600
LI
AVE**
8
9
10
14
23
32
40
B
/7-B1-
L3
AVE»»
4
5
6
7
12
19
2B
B
020A
L3
AVEtt*
6
7
8
10
14
20
30
B
L5
AVE***
29
31
31
35
42
52
60
B
L6
AVE***
4B
56
59
62
70
76
B2
B
L7
AVE**
15
16
16
20
33
46
5B
B
B RANK DATA AVERAGE IB 21 22 25 32 41 50
~SEE TEXT FOR TEST SITE IDENTIFICATION
**TREATED AS ONE SAMPLE EACH
••~TREATED AS ONE SAMPLE EACH. STACK OUTLET WHICH INCLUDES EFFECT
OF DUST SETTLING IN DUCTING AND STACK.
TABLE 23. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE
CONTROLLED UNDERFEED STOKERS BURNING BITUMINOUS COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.OO 1.25 2.50 6.00 10.OO 15.OO
EPA—600 LI AVE** 20 22 25 30 45 61 71 B
/7-B1- L7 AVE** 32 37 38 4B 73 08 96 B
020A
B RANK DATA AVERAGE 26 30 32 39 59 75 04
•SEE TEXT FOR TEST SITE IDENTIFICATION
**TREATED AS ONE SAMPLE EACH
48
-------
obtained each day at the multiple cyclone inlet and outlet using Brink BMS-11
impactors. Isokinetic values were not reported for any of the impactor
runs.
Impactor size data without a reported isokinetic value was given a
B-ranki ng.
TSN's 15, 16, and 57
These test series all were performed on the TVA-operated Shawnee unit
no. 10 at the Shawnee Steam Plant in Paducah, Kentucky. This unit is a
540-GJ/hr (150-MW), dry-bottom boiler which fires pulverized bituminous coal.
A portion of the exhaust stream passed through one of three liquid
scrubbers.
TSN's 15 and 16 were performed to specifically evaluate the
effectiveness of experimental scrubbers for removing particulates and SO2
from the flue gas. This testing took place in May 1974. Inlet samplings of
the scrubbers were performed using an unconventional sampling train for mass
loading plus particle size distribution with a cyclone and Brink impactor.
The outlet samplings were performed with a Brink Impactor. The reported
isokinetic values for the testing were all 100 percent. The scrubber outlets
were reheated with a direct-fired oil heater upstream of the sampling point.
The developmental scrubbers may not be representative of scrubbers used
by utilities and industry but were included due to limited data availability.
Although not mentioned in FPEIS, the uncontrolled inlet samples neglect
cyclone catch and are thus an unacceptable method, with a resultant D-quality
rating. The outlets probably include some oil particles but were taken in a
relatively acceptable manner and are thus A-quality.
TSN 57 was part of a separate study of the scrubber effectiveness. The
tests occurred during January and February 1977. Loads varied from 360 to
544-GJ/hr (100 to 151 MW).
Inlet sampling was performed with Brink BMS-11 impactors, and particle
size distributions in the outlet gases were determined with MRI Model 1502
impactors. Sampling flowrate isokinetic values were not reported.
The lack of reported isokinetic values reduced impactor data to
B-quality. One data set was further downgraded to D-quality since the data
varied too drastically from the average and an error in data handling was
suspected.
TSN's 29 and 115
Meramec no. 1, operated by Union Electric Company in St. Louis,
Missouri, was the emissions source for these two test series. This unit, a
450-GJ/hr (125-MW), dry-bottom boiler, fired pulverized bituminous coal. The
only emission control device was an ESP.
49
-------
Samplings for TSN 29 were performed during boiler loads of 79 and
96 percent during March 1975. Brink impactors sampled the ESP inlet, and
Andersen impactors sampled the ESP outlet. Specific impactor models were not
given. All runs were reportedly performed under 100 percent isokinetic
conditions. The sizing data for TSN 29 are A-quality.
Test data reported in TSN 115 occurred during November 1974. These
tests established baseline emissions to compare to later tests during waste
plus coal cofiring. Boiler loads varied from 62 percent to 113 percent of
design capacity. A modified Brink BMS-11 Impactor was used for ESP inlet
samplings. An Andersen Mark III was the sampling device for outlet samples.
The FPEIS report did not report sampling flowrate isokinetic values. The
lack of reported isokinetic values lowers the sizing data to B-quality.
TSN 35
This test series was performed on a 43-GJ/hr (12-MW) utility boiler,
boiler no. 2 at the Nucla Station in Nucla, Colorado, operated by Colorado
Ute Electric Association. The unit, a bituminous-coal-fired spreader stoker,
controlled emissions with a fabric filter baghouse. The effectiveness of the
baghouse was the focus of the study.
The testing spanned from September through October 1974. In all, there
were 22 days of testing. On each day of testing, baghouse inlet and outlet
emission samples were taken using EPA Method 5 to determine total loading and
Andersen Mark III impactors to determine size distribution. No system
operating conditions were included in FPEIS. Additionally, sampling flowrate
isokinetic values were not recorded for the impactor runs.
Impactor data are considered reliable, but without a reported isokinetic
value it generally cannot be ranked better than B-quality. A data set,
test 15 sample 2, was deleted because its distribution varied drastically
from others in TSN 35.
TSN's 36, 37, 38, 39, and 40
These five test series contain the data from a single study in 1974 to
investigate the application of a fabric filter baghouse to an industrial
boiler exhaust stream. The boiler was a bituminous-coal-fired spreader
stoker operated by Kerr Industries in Concord, North Carolina.
Operating conditions were not specified for the boiler unit during any
of the test runs. All samples were at the baghouse outlet. Andersen
Mark III impactors were the samplng devices. All samplings reported
100 percent sampling flowrate isokinetic values. The methodology and
conditions were acceptable for all these samplings, and the resultant data
are considered A-quality.
50
-------
TSN 63
A 54-GJ/hr (15-MW) industrial boiler was the source for these data. It
was a spreader stoker in Illinois which fired bituminous coal. No emission
controls were mentioned.
At 40 percent of design capacity, a single sampling was performed using
a Brink BMS-11 impactor. A sampling flowrate isokinetic value was not
included. The low load and the lack of such supporting information reduced
the sizing data of this report to C-quality.
TSN 64
This test series had as its emission source a wet-bottom boiler unit
which fired pulverized bituminous coal. Although listed as "industrial," the
unit tested was actually L. D. Wright no. 7 in Fremont, Nebraska, which is
operated by the Fremont Department of Utilities. The unit had both a
mechanical collector and a fabric filter baghouse to process emissions.
The unit operating load was at 54 percent of design capacity when three
samplings were taken. All three samplings were obtained using a Brink BMS-11
impactor located upstream of both emission control devices. Sampling
conditions were mostly unrecorded. The information left unreported included
the flowrate isokinetic value for each sampling run. Although impactor runs
were reliable, the lack of important substantiating data reduces the results
to B-quality.
TSN 81
The source of these test data was a dry-bottom utility boiler firing
pulverized bituminous coal. This unit, boiler no. 4 at the Colbert Steam
Plant in Florence, Alabama, processed emissions with an ESP prior to the
stack.
Emissions testing was conducted during a 3-day period in January 1976.
On the first emissions testing day, the operating load was a constant
576-GJ/hr (160-MW). A variance was detected on the second and third day.
For these 2 days, the morning load was 576-GJ/hr (160 MW), but the afternoon
load decreased to 403-GJ/hr (112 MW).
Samplings were conducted on both the inlet and outlet of the ESP. Inlet
samples were obtained with a Brink BMS-11 impactor. Outlet samples were
obtained by using an Andersen Mark III impactor. Of the 13 inlet samplings
and 12 outlet samplings, only one test (an inlet run) reported a sampling
flowrate isokinetic value. That value was 107 percent. Excluding flowrate
isokinetic values the sampling conditions were otherwise reported in adequate
detai1.
The run which includes a reported flowrate isokinetic value within
acceptable limits 1s considered A-quality. The lack of reported isokinetic
values in the remaining impactor tests reduces the sizing data to B-quality.
51
-------
TSN's 128 and 250
These test series comprise two separate studies on the same dry-bottom,
pulverized-bituminous-coal-fired utility boiler. The boiler, the 3280-GJ/hr
(910-MW) Bull Run no. 1 operated by the TVA in Clinton, Tennessee, used an
ESP as the sole control device in both studies.
TSN 128 conducted during July 1974 includes no operating or control
device condition data. Both ESP inlet and outlet samples were obtained with
the use of impactors. The ESP inlet sampling device was a modified Brink
impactor. The modification was not specified. ESP outlet sampling device
was an Andersen Mark III impactor. Sampling flowrate isokinetic values were
unreported for all tests. The lack of reported isokinetic values reduces the
sizing data of TSN 128 to B-quality.
TSN 250 contains impactor data for the inlet and outlet of a mobile ESP
installed for demonstration purposes. Brink BMS-11 impactors were used for
inlet samples, and University of Washington Mark III and Andersen Mark III
impactors were both used for outlet samples. Unit operating conditions were
assumed to be normal.
The test series reports that inlet samples were obtained at an average
isokinetic value of 33 percent. The report also states that inlet
measurements were corrected for subisokinetic samplings. This gross
departure from standard methodology impairs the ESP inlet data's reliability
and reduces those results to C-quality. Due to the availability of higher
quality data, the uncontrolled (ESP inlet) sample data was excluded. The ESP
outlet data was downgraded to B-quality since the sampling flowrate
isokinetic value was not reported. One outlet data set was further reduced
to C-quality since it varied quite drastically from the other outlet data
sets.
TSN 129
This test series had as its emissions source a 79-GJ/hr (22-MW),
dry-bottom utility boiler firing pulverized bituminous coal. The source,
boiler no. 1 at the Mitchell Power Station in rural Georgia, had two ESP's in
series for emissions control.
Testing occurred during May and June 1977. Operating loads varied from
31 percent to 100 percent of design capacity. ESP inlet samplings were
performed using both a SASS train with cyclones and a device denoted only as
"other impactor" by the FPEIS listing. ESP outlet samples were obtained by
means of a SASS train with cyclones only. The FPEIS listing did not clearly
indicate whether the outlet sample point was downstream of both ESP's or only
the first. Isokinetic values were not given for any sampling. Most other
sampling conditions were also left unreported.
SASS train sizing data are considered C-quality due to the methodology
and lack of substantiating data. For the impactor runs, the resultant sizing
data are considered B-quality, except those runs during which the operating
52
-------
loads fell below 35 percent. These low-load test results were considered
C-quali ty.
TSN 130
This test series had as its source a 1310-GJ/nr (364-MW) dry-bottom
utility boiler firing pulverized bituminous coal. The unit, located in
Col strip, Montana, was operated by the Montana Power Company. The test
series assessed the effectiveness of a novel variable-throat venturi scrubber
as the sole particulate emissions control device.
Scrubber inlet and outlet samples were obtained while the boiler
operated at 90 percent to 98 percent capacity over a 4-day period (May 17
through 20, 1977). A Brink model BMS-11 impactor was used for all scrubber
inlet (uncontrolled) samples. A University of Washington Mark III impactor
was used for all scrubber outlet samples. Sampling flowrate isokinetic
values were left unreported for all impactor samplings. Though all these
data are impactor generated, the lack of reported isokinetic values reduces
the reliability to B-quality.
TSN 169
These data were reported from tests on boiler no. 4 at the Firestone
Tire 8 Rubber plant in Pottstown, Pennsylvania. This is a dry-bottom boiler
which fires pulverized bituminous coal. All exhaust gases passed through
multiple cyclones, and then part of the exhaust was further treated in a
pilot FMC double alkali flue gas desulfurization liquid scrubber system.
Testing took place on September 29, 1977, with the unit operating
continuously at 97.5 percent of capacity. Samplings were obtained between
the multiple cyclones and scrubber plus downstream of the scrubber.
The first sample was obtained by polarized light microscopy. This
methodology is considered unsound. There was a multiple cyclone malfunction
during the test; thus, the resultant data are D-quality.
The second sample was obtained by an Andersen impactor at 110 percent of
sampling flowrate isokinetic value but reported in a SASS format. Since the
specific impactor model and primary data were not reported, the resultant
data are considered B-quality.
TSN 171
This test series came from data from testing on La Cygne no. 1 operated
by Kansas City Power & Light. This boiler was built by Babcock & Wilcox and
rated at 3150-GJ/hr (875-MW). The furnace was of the cyclone class and fired
bituminous coal. Emissions passed through one of eight two-stage
venturi-absorption liquid scrubbers.
53
-------
Testing took place April 18, 1978. The electrical output was reported
operating continuously at 87 percent of design capacity. One uncontrolled
particulate emissions sample and one controlled particulate emissions sample
were obtained.
Due to high particulate concentrations at the uncontrolled sampling
point, an impactor could not be used. Instead, polarized light microscopy
was used. For the purposes of evaluation, this technique is not considered a
sound methodology and is therefore 0-quality.
The scrubber-controlled sample was obtained by use of an MRI impactor
(model unreported) with a sampling flow of 99 percent of isokinetic flow.
The use of sound methodology with acceptable conditions makes these data
A-quality.
TSN 172
This test emission source was a 328-GJ/hr (91-MW) Babcock & Wilcox
pulverized bituminous-coal-fired, dry-bottom utility boiler located in
Delaware. Particulate emissions were controlled by a mechanical collector
and ESP.
Testing took place on October 9, 1977. Operating conditions were normal
with electrical output at 104 percent of design capacity. A SASS train with
cyclones was used to obtain a single sample downstream of both control
devices. The sampling flowrate isokinetic value of the test was not
reported.
SASS train data that lacks a reported sampling flowrate isokinetic value
are considered C-quality.
TSN 173
Source data for this test series reported that the emission source was a
Babcock & Wilcox 328-GJ/hr (91-MW), dry-bottom utility boiler in Delaware
fueled with pulverized bituminous coal. Source emissions passed through a
multiple cyclone collector followed by an ESP.
Sampling took place on November 10, 1977 with electrical output at
85 percent of design capacity. A single SASS train with cyclone samples was
extracted downstream of the multiple cyclones and ESP. The sampling flowrate
isokinetic value was not reported. SASS train data without a reported
sampling flowrate isokinetic value are considered C-qualty.
TSN 174
This report is one of a series for wet-bottom boiler units firing
pulverized bituminous coal. In this case, the unit was a 460-GJ/hr (128-MW)
Combustion Engineering utilty boiler in South Carolina. For emission
control, this unit had a multiple cyclone followed by an ESP.
54
-------
Operating conditions on test date, January 7, 1978, were normal. Unit
output was at 87 percent of design capacity. The test date was January 7,
1978. A single stack sampling was performed downstream of the ESP using a
SASS train with cyclones. The sampling flowrate isokinetic value was not
reported. The less reliable nature of a SASS train plus the lack of a
reported sampling flowrate isokinetic value makes the size data for this test
series C-quality.
TSN 175
This test series documents testing performed on a 522-GJ/hr (145-MW),
pulverized-bltuminous-coal-fired, wet-bottom utility boiler manufactured by
Combustion Engineering and located in South Carolina. An ESP served as the
emissions control device.
A single size sampling was conducted on June 1, 1978 with operating
conditions reported as normal. Power production was at 93 percent of design
capacity. The sampling point was downstream of the ESP. Sampling conditions
were sparsely documented. No sampling flowrate isokinetic value was reported
for the sample obtained with a SASS train with cyclones. SASS train data
without a reported sampling flowrate isokinetic value are considered
C-quality.
TSN 176
Test series number 176 documents testing performed on a 493-GJ/hr
(137-MW), pulverized-bituminous-coal-fired, wet-bottom utility boiler
manufactured by Combustion Engineering and located in South Carolina. An ESP
served as the emissions control.
A single size sampling was conducted on June 2, 1978 with operating
conditions reported as normal. Power production was at 95 percent of design
capacity. The sampling point was downstream of the ESP. The sampling device
was a SASS train with cyclones, sampling conditions were sparsely documented,
and no sampling flowrate isokinetic value was reported.
Sampling with a SASS train, compounded by the lack of reported sampling
flowrate isokinetic value, reduces the data to C-quality.
TSN 177
This test series had as its source a 1300-GJ/hr (360-MW),
pulverized-bituminous-coal -fired, wet-bottom utility boiler located in South
Carolina. An ESP served as the sole emission control device.
On September 18, 1978, as the unit operated at 100 percent of design
capacity, a single ESP-controlled emission sampling occurred using a SASS
train with cyclones. The sampling flowrate isokinetic value was not
reported. SASS train data without any documented sampling flowrate
isokinetic value cannot be considered better than C-quality.
55
-------
TSN 178
This test series had as its source a 1300-G0/hr (360-MW),
pulverized-bitumirious-coal-fired, wet-bottom utility boiler located in South
Carolina. An ESP served as the sole emission control device.
On September 26, 1978, as the unit operated at 100 percent of design
capacity, a single ESP-controlled sampling occurred using a SASS train with
cyclones. The sampling flowrate isokinetic value was not reported. SASS
train data without any documented sampling flowrate isokinetic value cannot
be considered better than C-quality.
TSN 179
A 2315-GJ/hr (643-MW) Babcock & Wilcox utility boiler located in
Illinois was the source for this test series. The unit contained a cyclone
furnace fueled with bituminous coal. An ESP controlled the emissions.
A single ESP-controlled particle sampling was performed on May 30, 1978
with the boiler operating under normal conditions at 68 percent of design
capacity. The sampling was performed using a SASS train with cyclones. The
sampling flowrate isokinetic value was not reported. SASS train data without
a documented sampling flowrate isokinetic value cannot be considered better
than C-quality.
TSN 180
A 1300-GJ/hr (360-MW) utility boiler was the source for this test
series. The unit contained a Babcock & Wilcox cyclone furnace fueled with
bituminous coal. An ESP controlled the emissions.
A single ESP-controlled sampling was performed on April 30, 1978. The
boiler operated under normal conditions at 70 percent of design capacity.
The sampling was performed with a SASS train with cyclones. The sampling
flowrate isokinetic value was not reported. SASS train data without any
documented sampling flowrate isokinetic value cannot be considered as better
than C-quality.
TSN 181
A 2315-GJ/hr (643-MW) Babcock & Wilcox utility boiler located in
Illinois was the source for this test series. The unit contained a cyclone
furnace fueled with bituminous coal. An ESP controlled the emissions.
A single ESP-controlled sampling was performed on May 9, 1978 with the
boiler operating under normal conditions at 70 percent of design capacity.
The sampling was performed with a SASS train with cyclones. The sampling
flowrate isokinetic value was not reported. SASS train data without
documented sampling flowrate isokinetic value cannot be considered better
than C-quality.
56
-------
TSN 182
This test series was conducted on
located in Ohio. The unit contained a
coal. Emissions were controlled by an
a 486-GJ/hr (135-MW) utility boiler
cyclone furnace fueled with bituminous
ESP.
A single sampling was performed on August 14, 1978, as the unit operated
at 88 percent of design capacity under normal conditions. A SASS train with
cyclones was used as the sampling device. The sampling location was
downstream of the ESP and achieved 93 percent of sampling flowrate isokinetic
value. The use of a SASS train for sampling makes the resultant data
B-quality.
TSN 183
This test series cane from sampling on a 486-GJ/hr (135-MW) utility
boiler located in Ohio. The unit contained a cyclone furnace fueled with
bituminous coal with emissions controlled by an ESP.
A single sampling was performed on August 16, 1978, with the unit
operating at 88 percent of design capacity under normal conditions. A SASS
train with cyclones was used as the sampling device. The sampling point was
downstream of the ESP and achieved 95 percent of sampling flowrate isokinetic
value. The use of a SASS train for sampling makes the resultant data
B-quality.
TSN 242
These test data came from testing at Site A in the EPA tests on
industrial stokers. Site A was an 317-GJ/hr (88-MW) Foster Wheeler boiler
fueled with bituminous coal fed by a Detroit Stoker spreader stoker with
traveling grate. Emissions passed through multiple cyclones with flyash
reinjection, then to an ESP followed by a liquid scrubber.
While most of the data are simply EPA Method 5 runs, on August 26, 1977,
a single particle size distribution sampling was performed. The boiler was
operated at 74 percent of design capacity as a Brink Model B impactor sampled
emissions at the multiple cyclones outlet. The sampling flowrate isokinetic
value of 113 percent was beyond the acceptable limit. In addition, the FPEIS
report notes that the catch of the impactor was limited to particle sizes
between 0.3 and 3.0 microns, which accounted for less than 6 percent of the
total catch. Given the limiting conditions under which the size data were
obtained, the rating is C-quallty.
TSN 248
A 148-GJ/hr (41-MW) boiler of the commercial/institutional class served
as the source for this test series. The unit, a dry-bottom wall-fired
boiler, was fueled with bituminous coal. No emission controls were in use.
57
-------
Testing was performed on February 27, 1978, as the unit operated at
79 percent of design capacity. This load was indicated to be the normal
maximum operating load. A single particle sizing sample was drawn using a
SASS train with cyclones. The sampling flowrate isokinetic value was
reported to be 92 percent. Though the conditions for this test are
acceptable, the use of a SASS train with cyclones for particle size sampling
reduced the particle data to B-quality.
TSN 251
TSN 251 comes from testing performed on a 15-GJ/hr (4-MW) overfeed
stoker commercial/institutional boiler. Bituminous coal was fired, and
emissions were controlled with a mechanical collector.
Testing took place March 13, 1979, as the unit operated continuously at
100 percent of design capacity. A SASS train with cyclones sampled
downstream of the mechanical collector with a sampling flowrate isokinetic
value of 99 percent. Though the conditions for this test are acceptable, the
use of a SASS train with cyclones for sampling purposes reduces the particle
data to B-quality.
TSN 252
A 92-GJ/hr (25-MW) commercial/institutional, dry-bottom, wall-fired
boiler was the source for these reported data. The boiler was fueled with
pulverized bituminous coal. Emission control was achieved with multiple
cyclones and a liquid scrubber.
The boiler operated continuously at 94 percent of capacity as a single
particle size distribution sampling was performed between the multiple
cyclones and liquid scrubber. This particle size sampling was performed
March 21, 1979, using a SASS train with cyclones. The reported sampling
flowrate isokinetic value was 87 percent. These data, being
SASS-train-sampled below the acceptable range for isokinetics, must be ranked
as C-quality.
TSN 262
A 158-GJ/hr (44-MW) industrial spreader-stoker boiler firing bituminous
coal was sampled to obtain the data for TSN 262. The boiler's emissions were
controlled by both a mechanical collector and an ESP. This testing was part
of a comprehensive survey of industrial combustion source emissions.
A single sampling was performed on February 8, 1979, as the boiler
operated continuously at 91 percent of design capacity. The sampling device,
a SASS train with cyclones, was placed downstream of the ESP. No sampling
flowrate isokinetic value was reported.
SASS train data without a documented sampling flowrate isokinetic value
cannot be considered better than C-quality.
58
-------
TSN 264
A 185-GJ/hr (50-MW) industrial wet-bottom boiler firing pulverized
bituminous coal was sampled to obtain the data for TSN 264. The only
emission control was multiple cyclones. This testing was part of a
comprehensive survey of emissions from industrial sources.
A single particle size sampling was performed on May 18, 1979, as the
boiler operated continuously at 65 percent of design capacity. The sampling
occurred downstream of the multiple cyclones using a SASS train with
cyclones. The sampling flowrate isokinetic value was not reported. SASS
train data without a documented sampling flowrate isokinetic value cannot be
considered better than C-quality.
TSN 267
The emission source for this data set was a 1080-GJ/hr (300-MW)
tangentially fired utility dry-bottom boiler fueled with pulverized
bituminous coal. The effluent stream was treated by an ESP followed by a
liquid scrubber.
Two particle size distribution tests were performed on 2 consecutive
days in December 1979. An MR I 15-oz impactor was used to sample one
ESP-control1ed and one ESP-plus-scrubber-controlled emission sample each
day.
On the first day, the boiler was fed coal at a rate of 78,810 kg/hr
(173,740 Ib/hr), and generated 806-GJ/hr (224-MW) of electricity. The
sampling flowrate isokinetic value for the ESP-controlled sample was
126 percent, and the dually controlled sample had an isokinetic value of
77 percent.
The second day of impactor testing had a lower feed rate with
74,940 kg/hr (164,880 Ib/hr) of bituminous coal being fired continuously.
Sampling flowrate isokinetic values improved for the ESP-controlled sample
but not for the ESP-scrubber sample. The values were 96 percent and
73 percent, respectively.
Only the ESP-controlled sample from the second day merits an A-quality
ranking. The unacceptable isokinetic values from the other three impactor
samples reduces their value to B-quality.
TSN 274
The source for this data set was designated Site E in the EPA testing
series for industrial boilers. Site E was a 190-GJ/hr (53-MW) Riley boiler
fueled with bituminous coal fed by a Riley traveling-grate spreader stoker.
Emissions were controlled by multiple cyclones.
A single particle size distribution test was performed on December 20,
1978, using a Brink Model B impactor. The boiler was fueled at a rate of
59
-------
6,585 kg/hr (14,520 lb/hr), generating steam at 69 percent of design
capacity. The Brink impactor sampled uncontrolled emissions at 101 percent
of the sampling flowrate isokinetic value. All devices and conditions are
well within acceptable limits and hence these data are considered A-quality.
TSN 281
Data from Site K testing as part of EPA tests of industrial stoker
boilers are contained in this test series. Site K was a 54-GJ/hr (15-MW)
Riley bituminous-coal-fueled boiler with a Riley traveling grate overfeed
stoker. Only multiple cyclones were in-line as an emissions control device.
A single size test was performed on November 9, 1979, using a Brink
Model B impactor. The boiler operated at 102 percent of design capacity with
a coal feedrate of 2,200 kg/hr (4,850 Ib/hr). The sampling was upstream of
the multiple cyclones at an unspecified sampling flowrate isokinetic value.
Six EPA Method 5 tests were documented with sampling flowrate isokinetic
values of approximately 102 percent. This single impactor test result is
considered A-quality.
TSN 307
This test series is data from sampling at the Sora Paper Company in
Middletown, Ohio. Investigation found that the tested unit was a dry-bottom
boiler firing pulverized bituminous coal with a rated steam production
capacity of 7 kg/s (55,000 lb/hr) of steam production. A mechanical
collector and liquid scrubber were used for emission controls, but due to a
restrictively small sample port on the scrubber outlet, particle size tests
were only conducted on the mechanical collector inlet.
Four uncontrolled particle size tests were performed in April 1980. The
prevailing operating conditions were not documented beyond noting that three
tests occurred while the boiler operated normally and the fourth occurred
during soot-blow. Samplings were done with an Andersen Mark III impactor
with 1-min sampling periods. No sampling flowrate isokinetic values were
recorded for the impactor tests, but seven EPA Method 5 tests run
simultaneously reported isokinetic values between 100 and 107 percent.
Despite the lack of operating and sampling conditions data, the impactor
results are considered A-quality.
EMB Report 80-IBR-12 (Ref. 7)
The data in this report, prepared for EPA's Emission Measurement Branch,
was from Andersen cascade impactor sampling across the two-stage multiple
cyclones of a 9.5 kg/s (75,000 lb/hr) steam capacity bituminous-coal-fired
spreader stoker with an economizer and multiple cyclones for particulate
control. Flyash from the multiple cyclones was not reinjected. Boiler no. 3
is located at the DuPont Washington Works in Parkersburg, West Virginia.
Testing was performed on December 17, 1980, with the boiler at full
steam production rate. The reported sampling flowrate isokinetic values
60
-------
ranged from a low of 103.7 percent to a high of 110.0 percent. Based on the
acceptable documentation and sampling methodology, the data are rated
A-quality.
EMB Report 82-IBR-17 (Ref. 8)
Boiler no. 2 at the General Motors Corporation, Fisher Body Division
Plant in Lansing, Michigan, was sampled during April 19 to 24, 1982, using an
Anderson cascade impactor. The spreader stoker fed traveling grate boiler
uses an economizer, multiple cyclones, and a baghouse to control particulate
emissions. The baghouse was not sized for full flow, so a portion of the
flue gas from the multiple cyclones is discharged into the exhaust stack.
Flyash from the multiple cyclones was not reinjected. Although
nameplate-rated at 22.7 kg/s (180,000 Ib/hr) of steam, the boiler was
operated at one-third, one-half, and two-thirds capacity.
Particle size sampling was conducted at the multiple cyclones inlet,
baghouse inlet, and stack. The stack sample was not used, since it
represents a mixture of two flow streams. Except for one inlet sample with a
sampling flowrate isokinetic value of 122.3 percent, all sampling data were
A-quality.
EMB Report 82-IBR-18 (Ref. 9)
Boiler no. 6 at the Burlington Industries, Inc. plant in Clarksville,
Virginia, was tested for emissions July 12 to 16, 1982, using Anderson
cascade impactors. Coal was fed into the combustion chamber by flippers onto
a traveling grate, where overfire jets provided air to aid combustion. Two
sets of multiple cyclones were used for emissions control. Although
nameplate-rated at 18.9 kg/s (150,000 Ib/hr) of steam, the boiler normally is
operated under varying load conditions and was operated at full load,
two-thirds load, and one-third load during the sampling.
Sampling was conducted across the dust collectors. The inlet impactor
samples were excessively loaded on the first-stage impactor plate and the
sampling location was too close to upstream and downstream flow disturbances.
Inlet sample 1 was not included in the report, and inlet sample 2 was
conducted at 126 percent sampling flowrate isokinetic value. Except as
noted, the methodology and documentation are adequate and allow the data to
be ranked as B-quality.
The outlet impactor samples were taken with acceptable methodology and
documentation, except that outlet samples 1 and 7 were taken at about
80 percent sampling flowrate isokinetic value. Outlet samples 1 and 7 were
downgraded to a B-quality ranking, while the remaining samples were given an
A-quality ranking.
EPA 68-02-3271 (Ref. 10)
"Emission Characterization of Major Fosll Fuel Power Plants in the Ohio
River Valley" was prepared by PEDCo Environmental, Inc. under EPA contract
61
-------
no. 68-02-3271. Averaged data was presented for five different powerplants
in the area. The powerplants were not specifically identified in the report
but were listed as plants A, B, C, D, and E. All particle size distributions
were obtained using an Anderson 2000 Mark III in-stack cascade impactor with
all eight stages plus a glass fiber backup filter. All particle size samples
were obtained at a single sampling point located in the stack at a point of
average velocity.
Plant A with a rated nameplate generating capacity of 2016-GJ/hr
(560-MW) was placed into service in 1970. This Babcock & Wilcox unit has an
opposed-fired burner configuration and is equipped with a Buel1-weighted wire
ESP to control particulate emissions. Plant A is probably the Dayton Power &
Light Company's unit no. 2 at the J. M. Stuart Plant in Adams County, Ohio.
Testing was conducted from March 4 to 11, 1980. Nominal power output was
2124 to 2178-GJ/hr (590 to 605-MW), but for one run the power output was
approximately 1692-GJ/hr (470-MW). All sampling was conducted downstream of
the ESP.
Eleven particle size distribution samples were taken using an Andersen
Hark III in-stack cascade impactor and eleven total loading samples were
taken using EPA Method 5. The report does not provide the data for each size
distribution sample but only provides an average. Plant operating data,
however, was presented. Due to the lack of sampling details, the average
distribution is only ranked as B-quality.
Plant B has a rated nameplate generating capacity of 450-GJ/hr (125-MW)
and was placed into service in 1954. This Babcock & Wilcox unit has a
front-fired burner configuration and is equipped with a retrofit Research
Cottrell ESP installed in 1973 to control particulate emissions. Plant B is
probably Cincinnati Gas and Electric Company unit no. 3 at the Walter C.
Beckjord Plant in Clermont County, Ohio. Testing was conducted from April 7
through 15, 1980.
Nominal power output was 306 to 410-GJ/hr (85 to 114-MW) with one
excursion to 486-GJ/hr (135-MW). All sampling was downstream of the ESP.
Eight particle size distribution samples and eight EPA Method 5 samples
were taken. As with site A, sampling was not adequately documented and only
a particle size distribution average was reported. As with Plant A, the
average distribution is downgraded to B-quality.
Plant C has a rated nameplate generating capacity of 587-GJ/hr (163-MW)
and was placed into service in 1958. This Combustion Engineering unit has a
tangential-fired burner configuration. The particulate emission control
system consists of two ESP's in series. The newer retrofit Research Cottrell
ESP was installed in 1975. Plant C is probably Cincinnati Gas and Electric
Company unit no. 4 at the Walter C. Beckjord Plant in Clermont County, Ohio.
Testing was conducted from April 17 through 23, 1980. Nominal power output
was 511 to 583-6J/hr (142 to 162 MW), although one excursion to 468-GJ/hr
(130-MW) was recorded. All sampling was downstream of the two ESP's.
62
-------
Eight particle size distribution samples and ten EPA Method 5 samples
were taken. As with site A, sampling was not adequately documented and only
a particle size distribution average was reported. As with Plant A, the
average distribution is downgraded to B-quality.
Plant D has a rated nameplate generating capacity of 1480-GJ/hr (411-MW)
and was placed into service in 1978. This Babcock & Wilcox unit has an
opposed-fired burner configuration. The air pollution control equipment
consists of an American Air Filter (AAF) rigid frame ESP that was installed
in 1978. After passing through the ESP, the flue gas enters a carbide lime
mobile bed flue gas desulfurization (FGD) system, which was also installed in
1978 by AAF.
Plant 0 is probably Louisville Gas and Electric Company unit no. 3 at
the Mill Creek Plant in Dallam County, Kentucky. Testing was conducted from
August 5 through 12, 1980. Nominal power outputs were 1152 to 1440-GJ/hr
(320 to 400-MW) although loads of 634, 637, and 1012-GJ/hr (176, 177, and
281-MW) were recorded. All sampling was downstream of the FGD system.
Six particle size distribution samples and ten EPA Method 5 samples were
taken. As with site A, sampling was not adequately documented and only a
particle size distribution average was reported. As with Plant A, the
average distribution is downgraded to B-quality.
Plant E has a rated nameplate generating capacity of 562-GJ/hr (156-MW)
and was placed into service in 1962. This Combustion Engineering unit has a
horizontal-fired burner configuration. The air pollution control equipment
consists of a Research Cottrell weighted wire ESP installed in 1962. After
passing through the ESP, the flue gas enters an AAF lime slurry FGD system,
which was installed in 1976.
Plant E is probably Louisville Gas and Electric Company unit no. 4 at
the Care Run Plant in Dallam County, Kentucky. Testing was conducted from
August 18 through 22, 1980. Nominal boiler loads were 518 to 630-GJ/hr
(144 to 175-MW). All sampling was downstream of the FGD system.
Seven particle size distribution samples and ten EPA Method 5 samples
were taken. As with site A, sampling was not adequately documented and only
a particle size distribution average was reported. As with Plant A, the
average distribution is downgraded to B-quality.
EPA 60Q/7-81-020A (Ref. 11)
EPA 600/7-81-020A is a report entitled "Field Tests of Industrial Stoker
Coal-Fired Boilers for Emissions Control and Efficiency Improvement --
Sites LI through L7." The report summarizes test results for seven small
institutional-type, stoker-fired boilers. Site location was not disclosed in
the report. The test sites and test conditions are described in Table 24.
Particle size distributions were taken at boiler outlet and in the stack for
all sites except that boiler outlet samples were not taken at sites
L5 and L6. In the cases of sites L3, L5, and L6, however, their stack
63
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TABLE 24. TEST SITES AND TEST CONDITIONS
Test site
Stoker type
Peak
steami ng
capacity
kg/s (Ib/hr)
Operating
rate in
percent of
maximum
capacity
Particulate
emission
control
device
Year
built
LI
Underfeed
(multiple retort)
4.4
(34,500)
75
Multiple
cyclones
1966
L2
Overfeed
(vibrating grate)
5.1
(40,000)
85
Multiple
cyclones
1960
L3
Underfeed
(single retort)
3.9
(31,000)
60
None
1951
L4
Overfeed
(traveling grate)
3.8
(30,000)
78
Multiple
cyclones
1969
L5
Underfeed
(multiple retort)
4.8
(38,000)
55
None
1950
L6
Underfeed
(multiple retort)
3.4
(27,000)
65
None
1957
L7
Underfeed
(multiple retort)
7.0
(55,000)
50
Multiple
cyclones
1968
64
-------
samples are considered to be for uncontrolled
installed particulate control device.
emissions since there is no
No primary or reduced data sets were presented in the report. Instead,
averages were graphically presented for each site. An Andersen Mark III
cascade impactor was used for size distribution sampling as well as a Bahco
classifier. However, the Bahco classifier averages were not used in this
report since the Bahco classifier does not use the preferred methodology for
size distribution determination. Although the lack of sampling data
downgrades the data, the average values presented warrant a rank of
B-quality. Data are presented but not used for emission factor development
for underfeed stokers with multiple cyclone controls burning bituminous coal
from sites LI and L7. Uncontrolled emissions (i.e., emissions into the
control device) appear to be approximately double average uncontrolled
emissions. More data is needed from other sites to substantiate or repudiate
this data since it results in controlled particulate emissions for particle
sizes less than 15 ym exceeding uncontrolled emissions at other sites.
Ohio Edison Company (Ref. 12)
Ohio Edison Company provided particle size data from several of its
powerplants. All particle size distribution samples were taken with Andersen
eight-stage cascade impactors.
Sammis unit no. 3 (SAM3) is a Babcock & Wilcox 666-GJ/hr (185-MW),
pulverized-coal-fired, dry-bottom unit located in Jefferson County, Ohio.
The outlets of its American Air Filter baghouse were sampled on November 11,
1982. The boiler was generating 107 kg/s (850,000 Ib/hr) of steam while
consuming 12.1 kg/s (95,718 Ib/hr) of coal.
Edgewater unit no. 13 (ED13) is a Babcock & Wilcox 378-GJ/hr (105-MW),
pulverized-coal-fired, dry-bottom unit located in Lorain County, Ohio. The
outlet of its six-field ESP was sampled on April 27 and 28, 1982. The boiler
was generating nominally 106 kg/s (840,000 Ib/hr) of steam while consuming
13.1 kg/s (104,000 lb/hr) of coal.
Gorge unit no. 25 (G025) is a Babcock & Wilcox 158-GJ/hr (44-MW),
pulverized-coal-fired, dry-bottom unit located in Summit County, Ohio. The
outlet of its Western three-field ESP was sampled on May 14 and 20, 1982 as
well as October 21, 1982.
The boiler was generating nominally 52 to 59 kg/s (410,000 to
470,000 lb/hr) of steam while consuming 5.2 to 6.3 kg/s (41,000 to
50,000 lb/hr) of coal.
Gorge unit no. 26 (G026) is a Babcock & Wilcox 158-GJ/hr (44-MW),
pulverized-coal-fired, dry-bottom unit located near G025. The outlet of its
Western three-field ESP was sampled on May 13 and 20, 1982. At that time,
the unit was producing 57 kg/s (450,000 lb/hr) and 81 kg/s (640,000 lb/hr) of
steam, respectively, while consuming approximately 5.7 kg/s (45,000 lb/hr)
and 6.4 kg/s (51,000 lb/hr) of coal, respectively.
65
-------
Toronto unit no. 9 {T09) is another Babcock & Wilcox 158-GJ/hr (44-MW),
pulverized-coal-fired, dry-bottom unit and is located in Jefferson County,
Ohio. A four-field Buell ESP was installed in 1970. Outlet samples supplied
by Ohio Edison Company were obtained on January 13 and 14, 1983 while 53 kg/s
(420,000 Ib/hr) of steam was being produced and nominally 6.6 kg/s
(52,700 lb/hr) of coal was being consumed.
Toronto unit nos. 10 and 11 (T010 and T011) are identical Babcock &
Wilcox 238-GJ/hr (66-MW), pulverized-wal1-fired, dry-bottom units that have
been in operation since 1949 at the Toronto Powerplant in Jefferson County,
Ohio. Each received a four-field Buell ESP in 1970. The Ohio Edison Company
provided ESP outlet particle size data for unit no. 10 for testing conducted
on May 7, 1981 and for unit no. 11 for testing on August 10, 1982. Unit
no. 10 produced 80 kg/s (636,000 lb/hr) of steam while consuming 11.8 kg/s
(94,000 lb/hr) of coal. Unit no. 11 produced 81 kg/s (640,000 lb/hr) of
steam while consuming 10.4 kg/s (82,500 lb/hr).
All Ohio Edison Company particle size distribution data sets presented
sampling flowrates, tare, final, and net weights of the eight Andersen
impactor plates plus filter, plus the calculated size distribution as a
function of collected weight and particle size. No mention is made of
sampling flowrate isokinetic values nor are they possible to calculate based
on the limited data provided. Due to this short fall, all the data can only
be considered B-quality.
3.3.2 Anthracite Coal
Cumulative size-specific particle size distribution data for each
emission source and control device for anthracite coal combustion are listed
in Tables 25 through 27. The tables also include an assigned rating for
each data set.
The FPEIS data base managed by the Environmental Protection Agency was
extensively used to provide data sets for this study. A discussion of these
data sets follows. The FPEIS data sets are listed numerically by their test
series number (TSN). Additional references outside of the FPEIS data were
not discovered.
TSN'S 11, 73, 74, 75, 98, 99, 100, 101, 102, and 103
Three separate studies are documented by these test series; the
combustion source, Boiler 1A at the Sunbury Steam Electric Station located in
Shamokin Dam, Pennsylvania is the same for all three. The utility boilers
operated by Pennsylvania Power & Light. The studies each measured the
effectiveness of fabric filter baghouses which controlled emissions that
first passed through multiple cyclones. An important point is that this unit
fired a mixed fuel. Pulverized anthracite slit, anthracite no. 5 buckwheat,
and petroleum coke were fed in varying proportions. Normal operation
specified an 80 percent anthracite coal to 20 percent petroleum coke ratio.
The anthracite factor went as high as 85 percent and as low as 42 percent.
Due to the limited availability of data from anthracite-only fueled boilers,
66
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TABLE 25. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE
CONTROLLED DRY BOTTOM BOILERS BURNING ANTHRACITE COAL
(WITH PETROLEUM COKE)
DATA SET IDENTIFICATION CUMULATIVE MAGS I'EKCbNI LEGO THAN DATA
TEST TEST TEST bTAIEU SIZE (MICHQMSl HANK
SITE* NO. Sni-L 0.625 1.00 I . 25 2.50 6-00 10.00 15.00
1
1
46
49
52
60
86
92
9*
A
2
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12
16
23
40
56
69
A
i
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20
25
28
38
til
53
5i
A
2
1
3
7
10
22
45
57
66
A
2
i
3
8
I 1
->->
49
66
75
A
3
1
3
6
V
22
49
65
72
A
3
-i
2
3
5
1 7
45
5V
67
A
4
1
1 X
14
17
30
48
53
53
A
4
o
3
5
a
17
34
40
54
A
5
1
1
3
6
19
53
71
80
A
5
2
4
a
11
22
55
71
80
A
6
1
13
18
21
33
53
£>4
7 1
A
6
2
9
13
17
32
65
79
84
A
7
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27
36
4 1
A
7
2
IO
13
lb
2 V
59
7
03
A
0
1
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12
26
59
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73
A
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56
6V
7 |
A
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14
IB
31
61
72
77
A
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t>5
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A
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I
9
1 4
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32
62
76
04
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to
2
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14
18
33
6 0
74
03
A
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9
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79
A
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13
22
34
47
54
A
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2
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7
9
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45
LB
65
A
4
1
6
1 J
14
17
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5cj
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1 1
23
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58
69
A
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47
63
74
A
5
2
36
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66
67
71
A
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47
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12
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to
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51
69
?•_.
A
13
J
6
a
9
1 7
33
43
51
A
13
2
I
">
2
19
52
69
74
A
! 4
1
3
3
4
1 7
49
63
68
A
! 4
2
a
1 1
13
25
48
62
63
A
16
I
9
15
39
72
91
96
A
16
2
25
30
45
67
75
94
A
I 7
1
14
19
23
36
49
65
71
A
17
2
6
B
10
23
48
62
70
A
1
n
3
6
9
19
37
47
54
A
1
3
21
26
29
40
49
59
7 2
A
1
4
10
IS
18
39
52
62
68
A
2
-»
5
9
1 1
23
49
61
68
A
2
3
5
e
12
26
52
59
68
A
2
4
11
14
17
31
58
69
75
A
2
6
28
36
38
65
74
02
A
3
->
12
1 ti
17
27
43
55
63
A
3
3
4
V
13
26
48
61
73
A
3
4
3
6
B
ia
39
40
45
A
4
2
7
8
10
23
55
66
71
A
4
3
4
6
10
40
51
65
A
4
4
31
33
36
45
67
73
76
A
(continued)
67
-------
TABLE 25. (continued)
DATA SET JOENTif ICATION
TEST TEST TEG"!
SITE« NO- iittf-'L
curiULAi]vE r.KSH Hbr
A
6
2
5
7
V
19
43
5 1
5V
A
6
3
2
3
5
17
4 1
57
70
A
6
4
13
1 4
1L
23
43
54
65
A
7
2
3
6
8
23
"4
69
75
A
7
3
2
4
6
17
40
53
70
A
7
4
1
a
12
14
51
72
73
A
0
2
B
11
I !
I 1
26
38
49
A
a
3
3
5
7
ia
33
45
56
A
e
4
9
13
17
2G
50
57
65
A
i
1
1
1
1
30
77
93
100
Li
i
I
6
11
13
29
32
33
37
&
n
1
a
17
22
43
71
84
93
h
3
1
s
13
21
At
62
73
84
B
1
1
3
3
6
10
11
1 1
19
&
2
1
9
17
32
51
70
61
90
&
1
1
i
1
6
2V
32
34
&
2
1
i
1
9
31
39
44
L
3
1
1
4
5
17
34
38
38
8
4
1
1
3
6
17
28
33
34
b
5
i
1
3
4
20
38
42
47
L<
6
1
2
3
j
15
42
53
63
8
7
1
2
4
5
17
31
36
45
8
a
1
2
4
4
0
IB
30
43
8
10
1
2
3
£>
22
5/
76
89
U
J
i
a
8
a
10
29
34
35
b
'i
i
S
3
7
20
22
23
8
J
i
3
7
11
30
53
54
55
b
4
i
4
6
a
15
3a
43
43
b
5
j
6
IS
19
3V
64
69
72
&
7
i
1
1
1
3
7
9
12
D
8
I
3
5
&
11
16
17
19
fa
10
l
I
3
5
20
58
74
85
B
11
l
1
9
12
14
38
42
4&
b
! 2
i
•>
-*
3
13
29
3?
32
b
12
4
10
12
) 3
&
1
1
J
3
5
20
43
51
59
b
2
1
2
2
5
27
49
52
57
b
3
2
5
5
32
59
65
67
&
3
13
14
IS
25
34
4 1
59
8
4
1
21
43
61
69
h
5
1
1
3
6
15
33
47
63
8
6
1
62
65
77
93
94
95
6
98
99
A
RANK
DATA
AVEHAGE
8
1 1
14
25
48
59
66
8
RANK
DAI A
AVfcKAGE
4
a
10
22
41
48
54
A+8
rani-:
DATA
AVERAGE
7
10
13
24
46
55
63
•SEE TEXT FOR TEST SITE IDENTIFICATION.
68
-------
TABLE 26. PARTICLE SIZE DISTRIBUTION DATA FOR BAGHOUSE CONTROLLED
BOILERS BURNING PULVERIZED ANTHRACITE COAL (WITH PETROLEUM
COKE)
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS> RANK
SITE* NO. SMPL 0.625 1.OO 1.25 2.50 6.00 10.OO 15.OO
1
2
68
68
69
72
lOO
lOO
lOO
A
2
2
55
59
61
67
lOO
100
100
A
1
3
7
13
16
26
48
70
97
A
1
4
9
12
22
44
64
07
A
2
4
9
19
24
35
57
75
100
A
2
5
24
42
49
62
73
07
100
A
3
4
9
16
19
29
57
79
99
A
3
5
6
14
16
26
54
76
97
A
4
4
8
12
21
45
71
104
A
4
5
->
B
10
10
38
71
97
A
6
4
6
13
18
30
48
69
89
A
7
4
io
23
30
50
62
84
97
A
7
5
7
13
18
33
61
76
09
A
B
4
B
17
21
33
59
79
99
A
8
5
12
20
23
36
61
79
98
A
9
4
5
11
22
50
75
lOO
A
9
5
22
58
78
96
A
10
4
5
5
9
34
60
91
A
10
5
5
26
50
82
A
6
1
12
21
43
57
71
86
A
7
1
5
8
IO
18
19
73
84
A
7
2
12
13
14
16
30
48
69
A
8
1
5
5
25
41
64
78
A
11
1
19
29
37
55
75
86
A
12
1
14
15
19
52
83
96
A
15
1
22
49
71
A
15
2
5
1 1
26
67
94
A
18
1
23
47
71
85
A
18
2
55
55
A
19
1
5
9
11
21
56
79
88
A
19
2
3.2
5
9
37
65
83
A
1
6
9
12
31
58
66
70
A
3
6
11
15
31
58
75
89
A
4
6
5
5
6
10
15
21
A
5
6
97
97
97
98
98
98
96
A
6
6
65
65
66
B1
91
93
94
A
7
6
40
41
41
44
49
58
67
A
7
7
B
11
11
11
26
38
49
A
8
6
36
41
43
54
66
75
81
A
3
2
1
12
20
35
69
78
66
B
(continued)
69
-------
TABLE 26. (continued)
DATft SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE JMICRONS) RANK
SITE* NO. 5MPL 0.625 l.OO 1.25 2.50 &.00 10.00 15.00
lOO 3 1 J? 46 68 B
1
2
41
B2
B6
8B
89
B
2
2
42
83
87
09
90
B
3
2
7
25
43
63
78
B
4
2
12
30
57
80
85
B
3
2
7
9
16
46
62
68
B
6
2
3
4
5
7
14
30
B
11
1
3
4
11
19
41
59
B
11
2
1
1
13
46
65
71
B
1
2
59
61
68
74
B
2
2
16
33
41
B
3
2
2
3
5
8
27
B
4
2
9
15
21
25
35
B
5
2
i
2
23
30
59
66
B
6
2
IO
14
19
34
60
62
B
7
2
16
16
19
36
38
62
B
8
2
6
13
17
30
33
48
B
9
2
5
7
11
40
55
60
8
io
2
25
37
40
46
B
11
2
4
21
27
31
B
1
2
26
27
41
66
79
92
B
3
2
5
IO
40
BB
98
99
B
3
4
6
12
41
85
96
96
B
4
2
18
29
72
97
99
99
B
5
2
62
65
77
93
94
95
B
6
2
7
13
41
81
93
94
B
A
RANK
DATA
AVERAGE
23**
22
24
32
52
71
86
B
RANK
DATA
AVERAGE
1**
12
16
32
49
60
69
A+B
RANK
DATA
AVERAGE
22**
18
21
32
51
67
79
*SEE TEXT FOR TEST SITE IDENTIFICATION. MOST SITES HAVE MULTIPLE
CYCLONES.
*(AVERAGE NOT USED DUE TO INCONSISTENCY IN REPORTING.
70
-------
TABLE 27. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED STOKERS
BURNING ANTHRACITE COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.OO 15.00
247
1 1
4
5
7
16
21
40
B
253
1 1
46
47
52
B3
97
100
B
254
1 1
19
19
21
26
37
53
B
B
RANK DATA AVERAGE
23
24
27
42
52
64
•SEE TEXT FOR TEST SITE IDENTIFICATION.
71
-------
the data sets were retained for use in development of size-specific emission
factors.
TSN 11 contains data from the first recorded study at Sunbury. The
effectiveness of a recently installed Western precipitation fabric filter
baghouse was examined as well as the compliance of emissions with
Commonwealth of Pennsylvania permit requirements.
Baghouse inlet and outlet samples were each drawn twice using Brink
BMS-11 impactors. The first inlet/outlet pair was sampled during continuous
operation at 103 percent of design capacity with 100 percent of capacity
corresponding to 52 kg/s (410,000 Ib/hr) of steam production. The second
pair occurred during continuous operation at 105 percent of design capacity.
Sampling flowrate isokinetic values for the four samples were all reported as
100 percent. This data is A-quality, but the mixed fuel feed renders the
applicability of the data questionable.
Test series numbers 73, 74, and 75 contain data from a study in early
1975 which sought to determine the effectiveness of the baghouse under
different operating conditions with new and used filter bags.
Extensive sampling was performed on both baghouse inlet and outlet using
an Andersen Mark III impactor with a Univeristy of Washington Mark III
impactor used for some outlet samples in TSN 75. Operating loads varied from
90 to 100 percent of design capacity. Impactor sampling flowrate isokinetic
values were not consistently reported, but those that were reported fall into
an acceptable range (92 to 107 percent). Isokinetic values for EPA Method 5
tests went as high as 113 percent. Despite the omission of some validating
data, the reported particle size distribution data is A-quality, but the
mixed fuel inhibits the data's useful value.
Test series numbers 98, 99, 100, 101, 102, and 103 all report data from
the third study at Sunbury Station. In contrast to the other two studies,
the baghouse used for these test series was a novel mobile unit developed for
the Environmental Protection Agency; also, no operating parameters and few
sampling conditions were reported. For example, sampling flowrate isokinetic
values were not reported; but testing was performed during continuous
operation, baghouse inlet samples were drawn by Brink BMS II impactors, and
outlet samples were drawn by Andersen Mark III impactors.
Due to insufficient documentation, this data is considered B-quality.
In addition, the use of mixed fuel and the novel control device detract from
the value of the data.
TSN 247
This test series contains sampling data from a 12-GJ/hr (3.3-MW)
anthracite-coal-fired stoker-fed boiler with uncontrolled emissions. The
test site was one of several sites sampled to determine the fine particle
emissions from commercial/institutional combustion sources.
72
-------
One emission sample using a SASS train with cyclones was obtained on
February 22, 1978 while the unit was operated continuously at normal maximum
conditions. A sampling flowrate isokinetic value of 95 percent was achieved.
Although documentation was complete and conditions were acceptable, the use
of a SASS train with cyclones for sampling reduces the resultant data to
B-quality.
TSN 253
As with TSN 247, the data in TSN 253 came from a study of fine
particulate emissions from commercial/institutional combustion sources. A
9.2-GO/hr (2.6-MW), anthracite-coal-fired, stoker-fed boiler with no
particulate control device was the source of emissions.
On March 27, 1979, anthracite was fed at a rate of 756 kg/hr
(1,700 lb/hr) yielding 100 percent of steam design capacity. A single stack
sampling was drawn using the normal SASS train with three cyclones. Sampling
flowrate isokinetic value was 99 percent. Supporting documentation was
recorded. Only the choice of sampling device inhibits the overall quality of
this data and subsequently makes it B-quality.
TSN 254
The source specifications for this test series were identical to the
source for TSN 253 which was drawn from the same reference report, but is
located at a different site. The unit for this test series was a 9.2-GJ/hr,
anthracite-coal-fired, stoker-fed commercial/institutional boiler without any
emission controls.
While operating continuously at 100 percent of design capacity on
March 29, 1979, a single sample was drawn using a SASS train with cyclones.
The sampling flowrate isokinetic value was 99 percent. As with all SASS
train data, this data is B-quality.
3.3.3 Fuel Oil
Cumulative size-specific particle size distribution data for each
emission source and control device for fuel oil combustion are listed in
Tables 28 through 35. The tables also include an assigned rating for
each data set.
The FPEIS data base managed by the Environmental Protection Agency was
extensively used to provide data sets for this study. A discussion of these
data sets and those obtained from other reports follows. The FPEIS data sets
are listed numerically by their TSN and followed by a discussion of the other
relevant tests.
TSN 14
An industrial watertube boiler with no emission control device rated at
23.4-GJ/hr (6.5-MW) thermal output (2.2 x 10? Btu/hr) was the emissions
73
-------
TABLE 28. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED UTILITY
BOILERS BURNING RESIDUAL FUEL OIL
DATA SET
IDENTIFICATION
CUMULATIVE
MASS
PERCENT LESS
THAN
DATA
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE*
NO.
SCIPL
0.625
1.00 1
.25
2.50
6.00 10
00 15
.00
17
1
1
24
39
46
71
93
98
1O0
A
1
2
25
48
57
74
88
94
97
A
3
1
25
48
57
74
88
94
97
A
3
2
25
41
48
65
81
90
95
A
23
1
1
1
1
3
8
31
60
80
B
24
1
1
4
5
6
11
29
49
68
B
72
1
1
24
32
51
57
63
71
C
2
1
45
49
58
60
61
67
C
3
1
43
44
49
54
60
6B
c
4
1
54
56
62
66
71
77
B
3
1
40
45
55
60
64
71
C
186
1
1
12
17
30
38
46
57
B
2
1
13
20
37
35
65
75
B
3
1
55
56
59
61
65
72
B
4
1
58
61
70
6
93
98
B
188
1
1
85
86
88
89
90
92
C
—>
1
41
42
47
67
78
87
C
3
1
71
72
76
80
B3
87
B
4
1
53
54
60
69
75
81
B
5
1
83
85
87
89
91
92
C
6
1
49
52
61
71
77
83
C
198
1
1
78
79
82
91
96
99
c
212
1
1
56
3B
59
70
c
1
2
48
49
49
50
52
55
68
c
213
1
1
44
47
50
63
B
1
2
33
35
36
41
51
60
73
c
214
1
1
41
46
54
68
B
1
2
37
41
43
46
49
52
67
B
A
RANK
DATA
AVERAGE
25
44
52
71
88
94
97
B
RANK
DATA
AVERAGE
14
36
39
45
48
64
74
C
RANK
DATA
AVERAGE
41
52
54
60
67
71
78
A+B
RANK
DATA
AVERAGE
20
39
43
52
38
71
80
A+B+C
RANK
DATA
AVERAGE
25
44
48
55
62
71
79
•SEE TEXT FOR TEST SITE IDENTIFICATION.
74
-------
TABLE 29. PARTICLE SIZE DISTRIBUTION DATA FOR ESP-CONTROLLED UTILITY
BOILERS BURNING RESIDUAL FUEL OIL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.OO 15.00
22 1 1 10 14 17 26 41 55 71 C
192 1 1 41 45 55 63 71 79 C
C RANK DATA AVERA6E 10 2B 31 41 52 63 75
*SEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 30. PARTICLE SIZE DISTRIBUTION DATA FOR SCRUBBER-CONTROLLED
UTILITY BOILERS BURNING RESIDUAL FUEL OIL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.OO 1.25 2.50 6.00 10.00 15.OO
2
1
71
85
90
96
100
lOO
lOO
A
2
2
49
BO
90
98
lOO
100
lOO
A
4
1
67
85
91
97
lOO
lOO
lOO
A
4
2
67
B5
91
97
lOO
100
lOO
A
: DATA
AVERAGE
64
84
91
97
lOO
lOO
lOO
•SEE TEXT FOR TEST SITE IDENTIFICATION.
75
-------
TABLE 31. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED INDUSTRIAL
BOILERS BURNING RESIDUAL FUEL OIL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITEt NO. SMPL 0.625 1.00 1.25 2.50 6.O0 10.00 15.00
14
1 1
6V
71
76
83
87
91
B
2 1
15
16
22
29
39
52
B
3 1
40
41
47
76
91
99
C
4 1
24
25
31
47
59
70
c
59
1 1
43
47
48
69
96
100
100
B
1 2
39
41
43
60
82
91
95
B
2 1
3B
41
43
58
82
91
95
B
3 1
14
17
IB
44
76
88
94
B
4 1
40
43
46
55
65
75
84
B
60
1 1
59
59
61
7B
89
94
97
B
2 1
20
33
43
66
85
92
96
B
61
1 1
14
17
19
24
31
35
4B
C
62
1 1
12
20
27
62
92
99
100
B
2 1
27
39
43
58
94
100
100
B
3 1
4
B
11
26
49
66
79
B
67
1 1
34
37
39
54
63
92
97
B
2 1
31
33
34
49
76
07
93
B
B RANK DATA AVERAGE
C RANK DATA AVERAGE
B+C RANK DATA AVERAGE
•SEE TEXT FOR TEST SITE IDENTIFICATION.
30
36
39
56
77
86
91
14
27
2B
34
51
62
72
29
34
37
52
73
82
88
76
-------
TABLE 32. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE-CYCLONE-CONTROLLED
INDUSTRIAL BOILERS BURNING RESIDUAL FUEL OIL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.OO 1.25 2.50 6.00 10.00 15.OO
170 1 1 21 21 22 72 95 100 D
D RANK DATA AVERAGE 21 21 22 72 *75 100
•SEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 33. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED INDUSTRIAL
BOILERS BURNING DISTILLATE FUEL OIL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.OO 1.25 2.50 6.00 10.00 15.00
66 1 1 1 1 1 5 26 48 67 C
2 1 3 14 17 19 S3 52 69 C
C RANK DATA AVERABE 2 8 9 12 30 50 68
•SEE TEXT FOR TEST SITE IDENTIFICATION.
77
-------
TABLE 34. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED COMMERCIAL
BOILERS BURNING RESIDUAL FUEL OIL
DATA SET IDENTIFICATION
TEST TEST TEST
SITE* NO. SHPL
CUMULATIVE MASS PERCENT LESS THAN DATA
STATED SIZE (MICRONS) RANK
0.625 l.OO 1.25 2.50 6.00 10.OO 15.OO
40
52
62
74
C
27
32
37
56
B
43
64
75
85
C
24
33
41
59
B
41
53
63
75
C
26
28
32
52
c
29
64
89
98
A
33
59
78
89
A
30
54
72
85
A
30
53
72
86
A
25
45
64
78
A
30
51
67
BO
A
35
58
75
87
A
13
34
57
76
A
12
33
55
74
A
15
35
56
74
A
13
32
53
72
A
16
38
59
77
A
12
32
54
73
A
22
44
64
79
26
33
39
58
38
49
58
72
23
44
62
78
26
45
61
76
205
206
207
TR-83-
110/EE
5
6
7
8
9
10
11
12
13
14
15
16
1
2
1
2
4
17
17
21
IB
17
19
15
20
22
5
5
6
6
7
5
21
17
23
20
19
20
16
21
24
6
6
7
7
B
6
23
IB
24
24
22
21
21
17
22
25
7
7
8
7
9
7
A RANK DATA AVERABE 12 13 14
B RANK DATA AVERAGE 17 19 21
C RANK DATA AVERAGE 21 23 24
A+B RANK DATA AVERABE 13 14 16
A+B+C RANK DATA AVERAGE 13 15 16
•SEE TEXT FOR TEST SITE IDENTIFICATION.
78
-------
TABLE 35. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED COMMERCIAL
BOILERS BURNING DISTILLATE FUEL OIL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE RANK
SITE* NO. SMPL 0.625 l.OO 1.25 2.50 6.00 10.OO 15.OO
TR-S3- 11 IB 18 19 22 29 36 43 A
HO/EE 3 1 40 42 44 50 61 69 75 A
4 1 4B 50 51 54 5B 60 62 A
A RANK DATA AVERAGE 35 37 3B 42 49 55 60
•SEE TEXT FOR TEST SITE IDENTIFICATION.
79
-------
source for TSN 14. The unit was fired with different fuels to examine the
effect of combustion modifications on N0X emissions. FPEIS report only gives
data from residual oil-fired tests during March 1977.
Four test runs, each containing one sample with particle size
distribution data, were reported. Particle size data was taken with Acurex
Corporation's prototype SASS train with three cyclones. Normal operating
conditions prevailed for the first two tests and the remaining two occurred
with combustion modifications.
The first test fired fuel containing 0.55 percent by weight sulfur
generating steam at 1.81 kg/s (14,290 Ib/hr) corresponding to 84.4 percent of
design capacity. Although sampling flowrate isokinetic value was 100 percent
with all other conditions acceptable, the less reliable sampling methodology
makes this data B-quality.
The second test reported in TSN 14 was with 1.17 weight percent sulfur
fuel producing 1.85 kg/s (14,600 Ib/hr) steam corresponding to 85.0 percent
of design capacity. The sampling flowrate isokinetic value was 107 percent.
Again, despite acceptable testing conditions, the sampling methodology
reduces the data to B-quality.
The third test was performed while 1.18 weight percent sulfur fuel was
being burned, producing 1.82 kg/s (14,370 lb/hr) of steam corresponding to
84.8 percent of design capacity. The sampling flowrate isokinetic value of
111 percent falls outside the acceptable range. The use of a SASS train with
cyclones outside the acceptable sampling flowrate isokinetic value range
makes this data C-quality.
The fourth test in the series is reported to have occurred almost
simultaneously with the third test. The weight percent sulfur value of the
residual oil was 1.02. Steam output was 1.78 kg/s (14,050 lb/hr)
corresponding to 83.1 percent of design capacity. This sample was taken at
115 percent of sampling flowrate isokinetic value. Again, this data being
from a SASS sample outside the acceptable sampling flowrate isokinetic value
range makes it C-quality.
TSN 17
The data within this report comes from tests on a 558-GJ/hr (155-MW)
residual oil-fired utility boiler. The specific unit sampled was Mystic
Station no. 6 in Everett, Massachusetts operated by Boston Edison. A liquid
scrubber was in use and had been in operation on the unit for the 6 months
prior to testing.
Two sets of four samples each were taken. Each set contained two
uncontrolled samples taken by Brink impactors plus two scrubber outlet
samples taken by Andersen Mark III impactors. All sampling was reported to
have been drawn under 100 percent sampling flowrate isokinetic value
conditions. The operating rate for the first sampling set was 80.6 percent
of design capacity (3.1 x 10^ L/hr (8,000 gph) feed rate) and the rate for
the second set was 54.8 percent of design (2.1 x 104 L/hr (5,500 gph)).
80
-------
Although the operating rate was "tow for the second set of sampling, the
conditions and methods used for both sampling sets are of a reliable nature
and hence the data from all eight samples is A-quality.
TSN 22
This FPEIS report contains an average of 10 runs sampled from a Boston
Edison residual oil-fired boiler. The unit was characterized by an air
atomizer system and a single-stage ESP controlling emissions.
The samples are all ESP-controlled and taken during continuous operation
with a 248-GJ/hr (69-MW) electrical output. An Andersen impactor was the
measurement device and reportedly leaked during sampling. Additionally,
sampling was not conducted isokinetically (no sampling flowrate isokinetic
value was included, only the particle size preference was towards coarser
particles). Given the departure from reliable methodology, this data is
considered B-quality.
TSN 23
As with TSN 22, this report is averaged data from nine runs from a
Boston Edison residual oil-fired utility boiler. Although this system has an
ESP control device, all samples were taken upstream of the ESP without
benefit of an emissions control device. A mechanical oil atomizer was used
on this unit. Output for testing was 302-GJ/hr (84-MW) under normal
operating conditions.
An Andersen impactor was the sampling device. As with TSN 22, leaks
occurred during testing and sampling was not conducted isokinetically. These
problems reduced the data to B-quality.
TSN 24
This report is the third in a set of testing at a Boston Edison
facility. The data in this report came from an average of eight samples on a
288-GJ/hr (80-MW) boiler tangentially firing residual oil using a steam
atomizer. Although the facility has a single-stage ESP for emissions
control, all emissions samples were taken upstream of the ESP and represent
emissions from an uncontrolled source.
The unit operated at 100 percent of design capacity during Andersen
Impactor sampling. The impactor sampling flowrate was only 68 percent of
isokinetic value and occasionally leaked. The poor measurement conditions
reduce the data to B-quality.
TSN 59
Sample results from a 84-GJ/hr (23.4-MW) residual oil-fired industrial
boiler located in New York are documented in this test series. No emission
controls were in place. One fuel sample was reportedly analyzed showing a
sulfur content of 1.60 weight percent.
81
-------
Five samples were drawn during the study using a Brink BMS-11 impactor.
Loads ranged from 62.5 to 80.0 percent of design capacity during sampling.
Supporting documentations including sampling flowrate isokinetic values, was
not contained in this FPEIS report. This lack of validating information
reduces these data sets to B-quality.
TSN 60
A 105-GJ/hr (29.3-MW) residual oil-fired industrial boiler was the
source for FPEIS Test Series Number 60. No emission control devices were in
use.
Baseline conditions prevailed for two particle size distribution
samplings with a Brink BMS-11 impactor. Residual oil containing 1.29 weight
percent sulfur was fired producing steam at 84 percent of design capacity.
Little supporting documentation was recorded in the FPEIS report. Most
notably, the sampling flowrate isokinetic value was omitted. Although
testing appears to be A-quality, this lack of substantiating data reduces the
test results to B-quality for both samples.
TSN 61
This test series reports the results from a single sampling of the
emissions from an uncontrolled 74-GJ/hr (20.5-MW) industrial boiler located
in Illinois. Residual oil was steam atomized and fired to produce only
41.4 percent of design capacity. The low load renders this data set marginal
for use in the development of emission factors. Other process conditions are
undocumented.
The single sample was taken by a Brink BMS-11 impactor. Sampling
conditions are almost entirely unspecified including no reported sampling
flowrate isokinetic value. While this is impactor data, the low process rate
and lack of validating data make the size data C-quality.
TSN 62
Test series number 62 reports results from testing on a 158-GJ/hr
(43.9-MW) individual boiler located in Minnesota firing steam-atomized
residual oil. The emissions were uncontrolled.
Three particle Size distribution samples were taken with a Brink BMS-11
impactor. Identical ultimate fuel analyses were given with the sulfur
content listed as 2.74 percent by weight. The process rates varied slightly
in the range of 46.3 to 48.0 percent of design capacity. Few other process
and sampling conditions were included. No sampling flowrate isokinetic value
was listed for any of the three samples. The lack of sufficient validating
evidence reduces this impactor data to B-quality.
82
-------
TSN 66
The emissions source in FPEIS test series number 66 was a 158-GJ/hr
(43.9-MW) distillate oil-fired industrial boiler located in Ohio. Although
an ESP controlled stack emissions, the two reported samplings for TSN 66 were
taken at the ESP inlet and, hence, were uncontrolled. Both samples were
gathered with a Brink BMS-11 impactor. Process conditions for the first test
were not mentioned, except for a process rate of 36.7 percent of design
capacity and a fuel sample ultimate analysis. The second test reports a
process rate of 40.7 percent of design and is otherwise incomplete. Sampling
conditions are also incomplete with reported sampling flowrate isokinetic
values being omitted for both tests.
The lack of substantiating data coupled with low operating rates detract
from the value of the data and make it C-quality.
TSN 67
This FPEIS report lists particle size distribution results from a
42-GJ/hr (11.7-MW) residual oil-fired industrial boiler located in New York.
No control devices were in use.
Two size distribution samples were taken using a Brink BMS-11 Impactor.
The first sampling was performed with the boiler at 81.3 percent of design
capacity while the second was performed with the boiler at 80.0 percent.
Both tests reported identical fuel analyses with a 1.91 weight percent sulfur
content. No other process information was reported. The only sampling
conditions given are temperature of the measurement instrument and sampling
time. Sampling flowrate isokinetic values were not stated for either test.
The lack of validating evidence reduces the particle size distribution data
for both test runs to B-quality.
TSN 72
This FPEIS test series data came from testing a 990-GJ/hr (275-MW)
residual oil-fired utility boiler during September and October 1977. The
source unit no. 4 at the Encina Powerplant in Carlsbad, California, used no
emission control device.
Five separate samples were collected during normal operations and
included sootblowing during three of the five tests. Operating conditions
were all similar. Fuel feed rates ranged from 20.8 kg/s to 21.2 kg/s
(165,000 to 168,000 Ib/hr) producing 1073 to 1084-GJ/hr (298 to 301-MW) of
power. Fuel sulfur content varied from 0.30 weight percent for tests 1 and
2, to 0.47 weight percent for test 3, and to 0.50 weight percent for tests 4
and 5.
The samples were collected with a SASS train with three cyclones. All
the sampling flowrate isokinetic values were above the acceptable limit
except for test 4 which took place with a 106 percent isokinetic value. Due
to the sampling methodology used plus the high isokinetic values during
83
-------
sampling, the particle size distribution data for test runs 1, 2, 3, and 5 is
C-quality. Since test 4 is within acceptable isokinetic value limits, this
size data is B-quality.
TSN 170
TSN 170 comes from sampling on a no. 6 fuel oil face-fired industrial
boiler during October 1977. The emissions from the unit, boiler no. 4 at the
Firestone Tire & Rubber facility in Pottstown, Pennsylvania, were controlled
by multiple cyclones followed by a pilot FMC double alkali flue gas
desulfurization liquid scrubber system.
Only one sample reports sufficient data for PADRE reduction. Although
reported as sampled by an Andersen cascade impactor, the sample was reported
in SASS format. The sampling flowrate isokinetic value was only 87 percent
and some of the large particulate could possibly be from previously burned
coal since the unit has a dual-fuel capability. The size data is graded as
D-quality.
TSN 186
Sampling reported in this test series was conducted on unit no. 2, a
360-GJ/hr (100-MW) residual oil-fired utility boiler, located at Encina
Powerplant, Carlsbad, California. The emissions were uncontrolled.
The purpose of the testing was to determine chemical composition as a
function of particulate size distribution. Two sets of samples were
collected. Each set of samples consisted of one sample drawn under normal
operating conditions followed shortly by a second sample, drawn under
identical conditions except the boiler unit underwent sootblow. Each
sampling was performed with a SASS train with cyclones.
The first set of sampling took place September 14, 1977. Residual oil
with 0.26 weight percent sulfur was fired at a rate of 7.2 kg/s
(57,000 lb/hr). Electrical output was 407-GJ/hr (113-MW). The sampling
flowrate isokinetic value of the first sampling (normal conditions) was
102 percent. The sampling flowrate isokinetic value of the sootblow sampling
was 98 percent. Although the conditions are all acceptable, the choice of
sampling device makes this test data B-quality.
The second set of sampling took place October 25 and 26, 1977. Residual
oil with 0.33 weight percent sulfur was fired at a rate of 7.2 kg/s
(57,000 lb/hr). Electrical output was 366-GJ/hr (101.8-MW). The sampling
flowrate isokinetic value of the first sampling in this set (normal
conditions) was 96 percent.
The isokinetic value of the sootblow sampling for this set was
105 percent. While these values are not as optimum as the values in the
first set, they are still within acceptance limits. The use of a SASS train
with cyclones reduces the second pair of sampling data to B-quality.
84
-------
TSN 188
Similar to TSN 72 and TSN 186, this series of tests was performed at the
Encina Powerplant, Carlsbad, California. Uncontrolled emissions were sampled
from unit no. 1, a 396-GJ/hr (110-MW) residual oil-fired utility boiler.
The test purpose was to determine the chemical composition of the
particulate emissions as a function of size distribution. This was
accomplished by collecting three separate sets of samples using a SASS train
with cyclones. Each set contained two individual samples. The first sample
drawn under normal operating conditions, and the second sample of the set
drawn shortly thereafter under similar conditions except the boiler unit
underwent sootblow.
The first set of samples were drawn on September 16, 1977. Residual oil
was fed at a rate of 8.0 kg/s (64,000 lb/hr) with the electrical output
listed as 378-GJ/hr (105-MW). Sulfur content of the oil was 0.23 weight
percent during the sample (normal operation) and 0.28 percent for the second
sample (sootblow). The isokinetic values were 84 percent and 89 percent for
the first and second samples, respectively. Both values fall outside the
acceptable sampling flowrate isokinetic value range. Due to these low values
plus the use of SASS trains, this first pair of sample data was ranked as
C-quality.
The second set of samples were drawn October 13 and 14, 1977. Oil was
fired at a rate of 6.6 kg/s (52,000 lb/hr) with an electrical output of
382-GJ/hr (106-MW). Sulfur content of the fuel was 0.38 percent during
"normal operation" test and 0.32 percent during the "sootblow" sample. Both
samples were collected at 91 percent of sampling flowrate isokinetic value.
Only the choice of sampling device reduces the value of the second set of
particle size distribution data, making the data B-quality.
The third, and final pair of samples reported in this FPEIS report were
collected November 9 and 10, 1977. Residual oil with sulfur content of
0.32 weight percent was fed at a rate of 6.6 kg/s (52,000 lb/hr) producing an
electrical output of approximately 371-GJ/hr (103-MW). The isokinetic value
of the "normal operation" sampling was 94 percent. The isokinetic value of
the "sootblow" sampling was omitted. The use of a SASS sampling train
reduces the first size distribution data to B-qual1ty. The omission of a
reported sampling flowrate isokinetic value reduces the sootblow condition
data to C-quality.
TSN 192
Test series number 192 was performed on a Combustion Engineering
tangential firing residual oil-fired 569-GJ/hr (158-MW) utility boiler unit
1n Delaware on May 25, 1978. A conventional ESP treated boiler exhaust
gases.
The unit was operated normally for more than 5 hours during the sampling
process. The fuel feed rate was 9.9 kg/s (79,000 lb/hr) producing steam at
85
-------
96 percent of design capacity. A SASS train with cyclones was used to
determine the size distribution for one sample. No sampling flowrate
isokinetic value was given, the flowrate in the stack was calculated from the
fuel feed rate, and the sample volume was assumed. The sampling conditions
are given only marginally. The results are C-quality.
TSN 198
Test series number 198 was conducted July 13, 1977 on a residual
oil-fired 612-GJ/hr (170-MW) utility boiler unit (wall firing position)
located in California. The fuel feed rate was 11 kg/s (87,000 lb/hr)
producing 100 percent of design capacity under normal operating conditions.
No emission control devices are used for the test. Ultimate and trace
element chemical analysis were run on a 50-ml fuel sample. One particle size
test result was reported in moderate detail. The test was run with a SASS
train with cyclones sampling the stack for almost 5 hours, but no sampling
flowrate isokinetic value was given. Other basic measurement conditions are
not specified. The lack of sufficient background data, but with otherwise
good methodology gives this size run C-quality.
TSN 205, 206, and 207
Test series numbers 205, 206, and 207 were all performed on the same
80-hp industrial boiler unit at an undisclosed site in Los Angeles,
California. The unit contains a Scotch dry-back research firetube boiler.
No emission controls are used. The test objective was to prepare a
comprehensive emissions inventory of the source by particle size distribution
and chemical composition.
All three test series were conducted while the boiler was in continuous
("as needed") operation. An extensive chemical analysis of a fuel sample is
given for each series. Also, each series records one particulate size
distribution test by a SASS train with cyclones and one size test by a
fabricated three-cyclone sampler used in series with a Method 5 train. The
SASS train sampled flue gas 2.1m from a horizontal bend. The location of the
fabricated cyclones probe is not given. All runs were taken at less than
70 percent steaming capacity.
The testing for TSN 205 occurred on September 13, 1977. The unit was
firing crude oil at a rate of 0.023 kg/s, (183 lb/hr) corresponding to
69 percent of design capacity. The SASS train with cyclones operated at
114 percent of sampling flowrate isokinetic value and is supported by
thorough documentation. This data is at best C-quality because of low
operating conditions and high isokinetic value. The fabricated cyclone
operated at a stated 100 percent of sampling flowrate Isokinetic value but
has few records with which to substantiate this. This lack of documentation
plus the questionable test device necessitates a B-quality rating.
TSN 206 comes from data taken September 15, 1977. Low sulfur no. 6 fuel
oil was fired at a rate of 0.023 kg/s (183 lb/hr) corresponding to 70 percent
of design capacity. The SASS train was operated at 138 percent of sampling
flowrate Isokinetic value. Complete data is reported, but the less than
86
-------
ideal sampling results in C-quality data. The fabricated cyclone sampler
operated at 91 percent of sampling flowrate isokinetic value, but otherwise
insufficient test data and also the nonstandard sampling device lead to a
B-quality rating.
TSN 207 is from September 20, 1977 test data taken while the boiler unit
fired crude oil at a feedrate of 83.1 kg/hr (183 lb/hr) producing steam at
68.8 percent of design capacity. The ultimate analysis of the fuel sample is
identical as for TSN 205, but the elemental analysis differs. The SASS train
sampler was operated at 122 percent sampling flowrate isokinetic value. The
low load capacity and high isokinetic value make the results C-quality
despite thorough data records. The fabricated cyclone sampler had a low
sampling flowrate isokinetic value (79 percent) with sketchy records. This
data 1s rated as C-quality.
TSN 207 also had a particle size sample taken with an Andersen Model III
impactor. The quality of the test device, acceptable sampling flowrate
isokinetic value (95 percent) and adequate records make this impactor data
A-quality.
TSN 212, 213, and 214
Test series numbers 212, 213, and 214 were all conducted on the same
residual oil-fired, 1728-GJ/hr (480-MW) utility boiler unit in Los Angeles,
Cali fornia.
The unit contains a Babcock & Wilcox supercritical boiler with 32
horizontally opposed gas and oil burners. No emission controls were used.
The test objective was to prepare a comprehensive emissions inventory by
particle size distribution and chemical composition.
For test series number 212, testing occurred January 27, 1978 under
continuous ("as-load demands") operation at only 49 percent of design
capacity. The fuel feedrate was 14.5 kg/s (115,000 lb/hr). Two particle
size emission samples were taken simultaneously during one 4-hour test.
Emission sampling conditions are well documented but other unit operating
parameters are vague. A fuel-oil sample underwent extensive chemical
analysis.
One emission sample was taken with a SASS train with cyclones with a
77 percent sampling flowrate isokinetic value. Sampling conditions are well
documented as is a chemical analysis of the particulate catch. The second
(smaller) emission sample was taken from the same stack location as the first
sample with three fabricated cyclones used in series with a Joy train with an
88 percent sampling flowrate isokinetic value. Although TSN 212 contains
significant documentation, the low operating load, low isokinetic values, and
questionable accuracy of the fabricated sampler reduces data to C-quality.
For TSN 213, testing occurred March 6, 1978 under continuous operation
at 95 percent of design capacity. The fuel feedrate was 26.6 kg/s
87
-------
(211,000 Ib/hr). As with TSN 212, the other unit operating parameters are
vague, except for an extensive chemical analysis of a fuel sample. Two
particle size emissions samples were taken, one by a SASS train with cyclones
and the other by three fabricated cyclones used in series with a Method 5
train.
The SASS sample was taken with a 92 percent sampling flowrate isokinetic
value with adequately documented sampling conditions. The second sample
cites minimal sampling conditions, omitting any reported sampling flowrate
isokinetic value.
As the SASS train sample was taken under acceptable conditions with
proper records, it merits a grade of B-quality. But since the fabricated
cyclone sample used questionable methodology with insufficient documentation,
it merits a C-quality grade.
For TSN 214, testing occurred March 8, 1978, under continuous operation
at 95 percent of design capacity. The fuel feed rate was 26.4 kg/s
(210,000 lb/hr). Again, the other operating parameters are vague, except for
an extensive chemical analysis of the fuel. Two particulate size samples
were taken, one by a SASS train with cyclones and the other by three
fabricated cyclones used in series with a Method 5 train.
The SASS sample was taken with a 100 percent sampling flowrate
isokinetic value with adequate documentation. The fabricated cyclone sample
was taken with a 101 percent sampling flowrate isokinetic value with marginal
documentation.
Again the SASS train sample was taken under acceptable conditions with
proper records and merits a B-quality rank. But the fabricated cyclone
merits a B-quality rank due to the questionable methodology and marginal data
on sampling conditions.
AT Report TR-83-110/EE (Ref. 13)
A comprehensive particulate emissions test program was conducted from
April 21 through April 28, 1982 on uncontrolled emissions from a 2.6-GJ/hr
(732-kW (2.5 minion Btu/hr)) North American Scotch-type watertube boiler
located at EPA's Industrial Environmental Research Laboratory (IERL) in
Research Triangle Park, North Carolina.
All testing was conducted at the outlet stack of the boiler while firing
one of three different fuel oils at 52 1/hr (13.7 gph). The first series of
tests was run firing a no. 2 distillate fuel, the second series were run
firing a no. 6 residual oil with 1 percent sulfur content, and the third
series were conducted burning a no. 6 residual oil with 2.9 percent sulfur
content. Particle size distribution samples were obtained by Acurex
personnel using an Andersen Mark III cascade impactor. The sampling flowrate
isokinetic values for the 15 outlet samples ranged from a low of 98.1 percent
to a high of 101.7 percent.
88
-------
Sampling is well documented and the boiler is representative of small
boilers in common usage and renders the reported particle size distribution
data as A-quality.
3.3.4 Natural Gas
Natural gas particulate size distribution data was not found for
external combustion sources. However, a literature search revealed that
100 percent of the particulate from boilers of industrial size are expected
to be less than 1 ym (Ref. 5). Based upon that estimate and until additional
particulate data is brought forward, an assumed particulate size distribution
for natural gas-fired utility boilers, industrial boilers, plus domestic and
commercial boilers is that all particulate is less than 1 pm. A statement to
this effect is simply added to Section 1.4, Natural Gas Combustion, of
AP-42.
3.3.5 Wood Waste
Cumulative size-specific particle-size distribution data for each
emission source and control device for wood waste combustion are listed in
Tables 36 through 43. The tables also include an assigned rating for
each data set.
3.3.6 Emission Source Discussion
The FPEIS data base managed by the Environmental Protection Agency was
extensively used to provide data sets for this study. A discussion of these
data sets and those obtained from other reports follows. The FPEIS data sets
are listed numerically by their test series number (TSN) and followed by a
discussion of the other relevant tests.
TSN 109
The emission source for the data of this FPEIS report was a bark-fired
industrial boiler. A knock-out elbow for large particulate followed by a
fabric filter baghouse controlled emissions. Flyash was pneumatically
transported to an unloading cyclone and the transport air was either returned
to the baghouse inlet or vented to the atmosphere.
On March 16, 1976, three test sets of three samples each were extracted
using a Sierra 226 impactor. The sampling point for two relevant test sets
was located between the knockout elbow and the baghouse. The sampling point
for one test set was located in the ash transport air return from the
unloading cyclone and is not relevant to emission factor development. The
sampling flowrate isokinetic values for all samples were reported as
100 percent. The boiler unit was operating with a continuous steam output of
4.4 kg/s (3.5 x 10^ Ib/hr) for the first set, 5.7 kg/s (4.5 x 10^ Ib/hr) for
the second set, and 6.3 kg/s (5.0 x 10^ lb/hr) for the third set.
Each relevant sampling's methodology and documentation were acceptable,
and subsequently, all that data are considered A-quality.
89
-------
TABLE 36. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED BOILERS
BURNING BARK*
data set identification cumulative mass percent less than data
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITES NO. SMPL 0.625 l.OO 1.25 2.50 6.00 10.00 15.OO
109*»
1
1
17
25
27
34
39
42
48
A
1
2
7
12
13
19
23
27
35
A
1
3
6
7
7
12
17
20
27
A
3
1
7
11
12
17
21
23
28
A
3
2
12
17
19
29
36
40
47
A
3
3
11
16
18
27
31
34
40
A
BO-WFB
1
1
10
17
IB
20
25
49
69
A
-2
1
2
8
9
10
17
31
43
53
A
1
3
10
20
24
32
51
64
74
A
80-WFB
1
3
3
4
4
7
10
12
13
B
-8
1
4
5
8
lO
16
24
27
29
B
A
RANK DATA
AVERAGE
lO
IS
16
23
30
38
47
B
RANK DATA
AVERAGE
4
6
7
12
17
20
21
A+B
RANK DATA
AVERAGE
9
13
IS
21
26
35
42
•SEE TEXT FOR TEST SITE IDENTIFICATION.
••AFTER KNOCK-OUT/SETTLINS HOPPER.
aAl 1 spreader stoker boilers.
TABLE 37. PARTICLE SIZE DISTRIBUTION DATA FOR A MULTIPLE-CYCLONE-
CONTROLLED BOILERS WITH FLYASH REINJECTION BURNING BARK9
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL O.625 l.OO 1.25 2.50 6.00 10.OO 15.00
BO-WFB
1
22
24
26
38
75
92
98
B
-4
2
26
27
28
35
62
80
91
A
3
20
27
29
44
66
78
86
B
BO-WFB
1
1
2
12
36
53
70
91
B
-5
2
B
10
12
30
60
76
86
B
3
lO
12
14
28
56
74
86
A
4
17
*o
54
61
77
84
88
A
5
IB
22
23
47
79
92
98
B
6
13
26
33
40
47
65
87
B
A
RANK
DATA
AVERA6E
18
26
32
41
65
79
88
B
RANK
DATA
AVERAGE
14
19
23
39
63
79
91
A+B
RANK
DATA
AVERA8E
15
21
26
40
64
79
90
•SEE TEXT FOR TEST SITE IDENTIFICATION.
aA11 spreader stoker boilers.
90
-------
TABLE 38. PARTICLE SIZE DISTRIBUTION DATA FOR SCRUBBER-CONTROLLED
BOILERS BURNING BARK
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK.
SITE* NO. SMPL O.625 1.00 1.25 2.50 6.00 10.00 15.00
BO—WFB 1 1
23
30
34
49
63
69
73
A
-4«« 1 2
28
31
36
48
7B
92
98
A
1 3
40
47
49
77
89
91
92
A
80-WFB 1 I
5
IB
27
65
91
96
98
A
-5»* 1 3
5
13
21
66
90
95
96
A
1 4
5
13
21
63
86
91
93
A
1 5
5
e
10
17
37
57
74
A
1 6
13
28
40
56
77
86
92
A
A RANK DATA AVERAGE
14
23
29
56
78
87
92
•SEE TEXT FOR TEST SITE IDENTIFICATION.
••MULTIPLE CYCLONES UPSTREAM WITH FLYASH REINJECTIQN.
TABLE 39. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED BOILERS
BURNING WOOD/BARK3
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.OO 15.00
256 1 1 63 66 74 85 90 94 C
259 1 1 70 72 78 86 90 94 C
C RANK DATA AVERAGE 67 69 76 86 90 94
•SEE TEXT FOR TEST SITE IDENTIFICATION.
aA11 underfeed stoker boilers.
91
-------
TABLE 40. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED BOILERS
BURNING WOOD/BARKa
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.00 15.00
260 1 1 52 54 59 67 74 02 C
C RANK DATA AVERAQE 52 54 59 67 74 82
SSEE TEXT FOR TEST 8ITE IDENTIFICATION.
aF1uidized bed combustor with heat recovery boiler.
TABLE 41. PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED
BOILERS BURNING SALT-LADEN WOOD/BARKa
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE
-------
TABLE 42. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE-
CONTROLLED BOILER WITH FLYASH REJECTION BURNING
WOOD/BARK*
DATA SET
IDENTIFICATION
CUMULATIVE
MASS
PERCENT LESS
THAN
DATA
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE*
NO.
SMPL
0.625
1.00 1.
23
M
Ul
O
0»
o
o
o
in
o
o
,00
80-WFB
1
1
20
30
37
71 8B
92
94
A
-10
1
2
12
15
18
33 67
86
95
A
1
3
15
26
34
57 06
95
98
A
A RANK DATA AVERAGE 16 24 30 54 80 91 96
~SEE TEXT FOR TEST SITE IDENTIFICATION.
aSpreader stoker boiler.
TABLE 43. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE-
CONTROLLED BOILER WITH FLYASH REINJECTION BURNING
SALT-LADEN WOOD/BARK3
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.6ZS 1.00 1.25 2.50 6.00 10.00 15.OO
1
1
55
63
65
73
82
87
90
B
1
2
ss
69
73
64
91
93
95
B
1
3
51
62
64
69
81
85
86
B
2
1
23
32
32
35
65
74
77
B
2
2
34
43
44
48
61
66
71
B
2
3
46
60
69
81
83
86
88
B
2
4
45
57
57
60
61
65
69
B
3
1
45
56
56
60
72
76
79
B
4
1
26
36
37
42
57
64
69
A
4
2
42
50
51
53
64
67
72
A
5
1
33
38
38
43
56
63
72
A
6
2
41
43
43
53
7B
94
100
A
6
3
36
37
38
47
50
62
75
A
7
1
25
27
27
34
52
67
BO
A
8
1
77
78
78
81
90
97
100
A
A
RANK
DATA
AVERAGE
40
44
45
50
64
73
81
B
RANK
DATA
AVERAGE
44
55
58
64
75
79
82
A*B
RANK
DATA
AVERAGE
42
50
51
58
70
76
82
•SEE TEXT FOR TEST SITE IDENTIFICATION.
aSpreader stoker boiler.
93
-------
TABLE 44. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE-
CONTROLLED BOILER WITH NO FLYASH REINJECTION BURNING
WOOD/BARK3
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.25 2.50 6.00 10.00 15.00
NCASI
1
2
5
a
10
17 26
31 35
B
PROVI-
1
3
2
5
7
16 27
33 35
B
DED
1
4
3
6
9
IB 32
3B 40
B
DATA
1
6
3
6
7
13 21
25 28
B
B
RANK DATA
AVERAGE
3
6
e
16 27
32 35
•SEE TEXT FOR TEST SITE IDENTIFICATION.
aSpreader stoker boiler.
TABLE 45. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE CYCLONE-
CONTROLLED BOILER WITH NO FLYASH REINJECTION BURNING
SALT-LADEN WOOD/BARK3
DATA SET IDENTIFICATION
CUMULATIVE MASS
PERCENT LESS
THAN
DATA
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE*
NO.
SMPL 0.
625
1.OO 1.25
2.50 6.00 10.
OO 15.OO
00-NFB
1
1
20
22 24
26 31
35 39
A
-9
1
2
17
21 22
23 37
SO 63
A
1
3
5
12 16
21 33
39 42
A
A
RANK
DATA AVERAGE
14
10 21
23 34
41 4B
•SEE TEXT FOR TEST SITE IDENTIFICATION.
aDutch oven boiler.
94
-------
TABLE 46. PARTICLE SIZE DISTRIBUTION DATA FOR SCRUBBER-CONTROLLED
BOILERS BURNING WOOD/BARKa
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 1.00 1.23 2.50 6.00 10.00 15.OO
257 1 1 97 98 99 99 99 99 C
258 1 1 93 94 96 96 96 97 C
C RANK DATA AVERAGE 95 96 9B 98 98 90
~SEE TEXT FDR TEST SITE IDENTIFICATION.
aAl1 Dutch oven boilers.
TABLE 47. PARTICLE SIZE DISTRIBUTION DATA FOR BAGHOUSE-CONTROLLED
BOILERS BURNING SALT-LADEN WOOD/BARKa
DATA SET
IDENTIFICATION
CUMULATIVE MASS
PERCENT LESS
THAN
DATA
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE*
NO.
SMPL
0.625
1.00 1.25
2.50
6.00 10.
00 15.OO
BO-WFB
1
1
49
52 57
61
80
90 96
A
-9
1
20
37 41
52
68
76 81
A
1
3
32
42 45
49
62
72 79
A
A RANK DATA AVERASE 34 44 48 54 70 79 85
(SEE TEXT FOR TEST SITE IDENTIFICATION.
aDutch oven boiler.
95
-------
TABLE 48. PARTICLE SIZE DISTRIBUTION DATA FOR DRY ELECTROSTATIC
GRANULAR FILTER-CONTROLLED BOILER BURNING WOOD/BARK3
DATA SET IDENTIFICATION CUMULATIVE ftASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SHPL 0.625 1.00 1.25 2.50 6.00 10.00 15.00
1
1
36
44
49
50
50
63
78
A
I
2
34
45
4B
4B
50
58
59
A
I
3
89
90
91
92
92
93
94
A
2
1
56
sa
59
59
60
61
62
A
2
2
45
46
4B
50
52
54
55
A
2
3
52
57
58
61
66
69
72
A
3
1
71
BO
B3
BS
90
93
94
A
3
2
39
43
47
57
68
74
78
A
3
3
40
60
70
S6
96
9B
99
A
A RANK DATA AVERAGE 51 5B 61 65 69 74 77
•SEE TEXT FOR TEST SITE IDENTIFICATION.
aSpreader stoker boiler.
96
-------
TSN 138
This test series presents stack sample data from a forest products
company industrial site which burned salt-laden bark and wood wastes to
supply plant power. Three separate spreader stober boilers, each with its
own multiple cyclones, were served by a single stack.
Fifteen total particle size samplings were performed under three
different sets of operating conditions. All samplings were performed with a
MRI Model 1502 impactor.
Seven samplings occurred on July 27 and 28, 1976. Cumulative steam
output of the three boilers was approximately 5 kg/s (40,000 Ib/hr). Other
operating and sampling conditions are sparsely documented. No sampling
flowrate isokinetic values were reported.
Four more samplings occurred during the period October 26 through 28,
1976. Cumulative steam output had increased to approximately 5.3 kg/s
(42,000 lb/hr). Again, little additional information was given, but sampling
flowrate isokinetic values were reported for all but the first of these
samplings. The second and third samples reported isokinetic values of
102 percent; the fourth sample reported a value of 99 percent.
From June 7 through 9, 1977, a final four additional size samplings were
performed. Operating load was only 4.8 kg/s (38,000 lb/hr) of cumulative
steam output. Sampling flowrate isokinetic values were 98 percent for the
first two runs and 99 percent for the final two runs.
Despite the voids in conditions data, all tests performed with an
impactor under acceptable sampling flowrate isokinetic value conditions have
size data considered to be A-quality. Size data for tests without a reported
sampling flowrate isokinetic value is reduced to B-quality.
TSN 141
The test series data came from a Washington Department of Ecology study
for the St. Regis industrial plant, boiler no. 14, in Tacoma, Washington. A
mixed wood-bark fuel was fired. No emission controls were in place at the
time of the test so all samples were reported as uncontrolled.
Two particle size distribution runs conducted on March 31, 1976 were
included in TSN 141. The boiler's steam production rate was noted as an
average 7.1 kg/s (56,000 lb/hr) during the first sampling period and 6.8 kg/s
(54,000 lb/hr) during the second sampling period. A Nelson cascade impactor
was used with sampling flowrate isokinetic values of 87 and 85 percent
achieved for respective samplings.
Given the low sampling flowrate isokinetic values the size data is
B-quality.
97
-------
TSN 256, 257, 258, 259, and 260
These five test series were performed during February and March, 1979 as
part of a comprehensive study of fine particulates from industrial combustion
sources. The industrial boilers for each of these tests fired a wood/bark
mixture using underfeed stokers (TSN 256 and 259), Dutch ovens (TSN 257
and 258), and fluid beds (TSN 260). Each test series contains extensive fuel
and catch chemical analyses with a single sampling performed with a SASS
train with cyclones.
For TSN 256, the Wellons-Birchfield underfeed stoker boiler was designed
for 13-GJ/hr (3.7-MW) output. It was operated at full load during sampling
and had a fuel feed rate of 16-GJ/hr (4.4-MW) heat input. The boiler has no
particulate control equipment so the single SASS sample was for uncontrolled
emissions. The isokinetic value for the SASS sample was not included in the
FPEIS listing.
The sample data 1n TSN 257 came from a 57-GJ/hr (16.8-MW) rated output
Puget Sound machinery Dutch oven design-boiler operating at 106 percent of
capacity with an equivalent fuel feed rate of 76-GJ/hr (21-MW). The sampling
occurred downstream of a liquid scrubber under an unspecified sampling
flowrate isokinetic value.
Similarly, the SASS sample in TSN 258 was obtained downstream of a
liquid scrubber. There was no mention of a sampling flowrate isokinetic
value. The source for this sample was a 97-GJ/hr (28-MW) rated output Erie
City Iron Works Dutch oven design-boiler operating at 95 percent of capacity
with a corresponding fuel feed rate of 115-GJ/hr (32-MW).
For TSN 259, the Babcock & Wilcox underfeed stoker boiler was rated at
43-GJ/hr (12.6-MW). It operated at 80 percent of capacity for sampling with
a fuel feed rate of 51-GJ/hr (14.2-MW). The sample data was for uncontrolled
particulate emissions, and the sampling flowrate isokinetic value was not
reported.
The sample data in TSN 260 was obtained from a 18.5-GJ/hr (5.4-MW)
Wellons, Inc. fluid bed boiler which was operated at only 20 percent of full
load rating with a fuel input of 5.4-GJ/hr (1.5-MW). One SASS sample was
obtained for uncontrolled boiler emissions. Sampling flowrate isokinetic
value was not reported for the SASS sample.
Due to the choice of sampling device and the lack of reported isokinetic
values, these data are all considered to be C-quality.
Several tests were identified which had not been entered into FPEIS by
mid-1983 but had meaningful particle sizing data. Those tests, for the most
part, were EPA-sponsored and are listed as follows.
98
-------
EMB Report 80-WFB-2 (Ref. 14) and -8 (Ref. 17)
These reports, prepared for the Emission Measurement Branch of the
Environmental Protection Agency, reported the emissions from an
Owens-Illinois Forest Products Division bark-fired industrial stoker-grate
boiler located at Big Island, Virginia. A dedicated multiple cyclone unit
without flyash reinjection exhausted into a common duct which lead to a pair
of ESP's. A coal-fired boiler also exhausted into that common duct.
On December 12, 14, and 15, 1979 the bark-fired boiler was operated at a
greater than 11.4 kg/s (90,000 lb/hr) steaming rate while on September 24
and 25, 1980 the boiler was operated at a steaming rate of approximately
22.2 kg/s {175,000 lb/hr). Samples were taken on those data using an
Andersen cascade impactor located upstream of the multiple cyclones for the
bark-boiler and downstream of the two ESP's.
The ESP outlet sample data were not used since those streams are
mixtures of flue gases from coal and bark combustion. The multiple cyclones
inlet data of December 12 through 15, 1979 are well documented and considered
A-quality while the data of September 24 and 25, 1980 were taken at 80 to
85 percent of the sampling flowrate isokinetic value and are considered
B-quality.
EMB Report 80-WFB-4 (Ref. 15)
The particulate for this report was generated by a bark-fired pneumatic
spreader stoker boiler with traveling grate and flyash reinjection. The
boiler system is located at the St. Regis Paper Company in Jacksonville,
Florida. Multicyclones followed by a venturi wet scrubber were used to
control emissions.
For January 29 through 31, 1980, three sets for Andersen cascade
impactor samples were taken across the venturi wet scrubber. Steam flows
during sampling average 13.9 kg/s (110,000 lb/hr) on the 29th, 18.1 kg/s
(143,000 lb/hr) on the 30th, and 17.0 kg/s (134,000 lb/hr) on the 31st.
The sampling methodology and documentation are acceptable, except that
scrubber Inlet run nos. 1 and 3 exceeded 120 percent of the sampling flowrate
isokinetic value. Scrubber inlet run nos. 1 and 3, therefore, are considered
B-quality while the remaining runs are A-quality.
EMB Report 80-UFB-5 (Ref. 16)
The emissions source for the data of this report was a St. Joe Paper
Company bark-fired spreader stoker with traveling grate boiler with screened
flyash reinjection from multiple cyclones and a variable throat venturi wet
scrubber system. The boiler, located in Port St. Joe, Florida, was sampled
during January 17 through 23, 1980.
Two levels of venturi scrubber pressure conditions were tested, namely a
AP of 8 in. H2O and 13.5 in. H2O, and particle sizings were obtained for
99
-------
three sets of samples across the scrubber at each pressure level using an
Andersen cascade Impactor. The steam output varied from a low of
142.5-GJ/hr (39.6-MW) to a high of 156.3-GJ/hr (43.4-MW).
Four of the six scrubber inlet samples were taken above 110 percent of
the sampling flowrate isokinetic value which caused that data to be
B-quality. The remaining inlet and outlet samples were taken between 94.4
and 107.1 percent of the sampling flowrate isokinetic value, with acceptable
sampling methodology and documentation and the data are considered
A-quality.
EMB Report 80-WFB-9 (Ref. 18)
The data in this report was generated from sampling of Dutch-oven-type
boilers located at the Bellingham Mill of Georgia-Pacific Corporation in
Bellingham, Washington. The boilers were fired with waste wood, of which
roughly 80 percent was salt-laden hog fuel. Captured flyash was not
reinjected during the test.
The Bellingham Mill was sampled during November 19 through 22, 1980 with
one sampling location being between multiple cyclones and a pulse-jet
baghouse while the other sampling location was downstream of the baghouse.
Three sets of samples were taken using Andersen cascade impactors.
Although fuel feed rates and steam generation rates were not documented,
sampling methodology and its documentation were acceptable and, subsequently,
all the resultant data are considered A-quality.
EMB Report 80-WFB-10 (Ref. 19)
The data in this report was also incorporated into FPEIS as TSN 283.
The Weyerhaeuser Company power boiler no. 11 with a traveling-grate spreader
stoker-firing system at Longview, Washington is rated at producing 108-GJ/hr
(30-MW) of power. Steam production 1s rated at 53.2 kg/s (420,000 lb/hr) at
8.6 MPa (1,250 psig) when using 55 percent moisture hog fuel and 72.8 kg/s
(575,000 lb/hr) on dry hog fuel, oil, or gas.
Emissions are controlled with a two-stage multiple cyclone system (with
a form of flyash reinjection from the first stage) and a three-module
Electroscrubber® (a dry electrostatic granular filter device). Two sets of
three Electroscrubber inlet and outlet Anderson cascade impactor samples (one
inlet and outlet pair per module) were taken during December 9 through 11,
1980. Steam was generated at a rate of 51 kg/s (400,000 lb/hr) on December 9
and 10 but was reduced to 44 kg/s (347,000 lb/hr) on December 11.
Sampling flowrate isokinetic values all appear acceptable, although
three values were erroneously omitted from the report. Based on the
acceptable sampling methodology and documentation with the slight reservation
noted above, the data are considered A-quality.
100
-------
NCASI (Ref. 20)
The National Council of the Paper Industry for Air and Stream
Improvement, Inc. (NCASI) provided Acurex with particle sizing information
which had been provided by a member company for particle size distribution on
a bark-fired boiler at the outlet of a single stage of 9-in. multiple
cyclones (and inlet to a wet scrubber device). Flyash was not reinjected
into the boiler. Unfortunately, NCASI had limited information on the boiler
operating conditions but did indicate that the bark and natural gas
combination spreader stoker boiler had a rated capacity of 57 kg/s
(450,000 Ib/hr). Sampling conditions were not reported; however, a
University of Washington Cascade Impactor {Mark V low flow with 11 stages)
was used with a British Coal Utilization Research Association precyclone and
a final filter to separate the particles into 13 fractions according to
aerodynamic size. Without more detailed information, especially concerning
particle collection conditions and sampling data, this data is only
B-quality.
3.3.7 lignite Coal
Cumulative size-specific particle size distribution data for each
emission source and control device for lignite coal combustion are listed in
Tables 49 through 51. The tables also include an assigned rating for each
data set.
The FPEIS data base managed by the Environmental Protection Agency was
extensively used to provide data sets for this study. A discussion of these
data sets and those obtained from other reports follows. The FPEIS data sets
are listed numerically by their TSN and followed by a discussion of the other
relevant tests.
TSN 166
TSN 166 reported data from a 72-GJ/hr (20-MW), pulverized-1ignite-coal-
fired utility boiler with a conventional multiple cyclones for emissions
control. This testing was part of a program to assess the emissions of
stationary combustion sources.
One particle size sampling was performed on September 21, 1977 with the
boiler operating on a continuous basis at 100 percent of design capacity.
The sampling device was a SASS train with cyclones. No mention was made of
the sampling flowrate isokinetic value, but other sampling conditions are
documented. Chemical analyses were performed on both the lignite fuel and
the SASS train catch. This data is C-quality due to the use of a SASS train
and insufficient validating data.
TSN 167
This test source could have been the same as for TSN 166 since the
source was a 72-GJ/hr (20-MW), pulverized-1ignite-coal-fired utility boiler
with a mechanical collector for emissions control. As with TSN 166, this
101
-------
TABLE 49. PARTICLE SIZE DISTRIBUTION DATA FOR AN UNCONTROLLED BOILERS
BURNING PULVERIZED LIGNITE COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE RANK
SITE* NO. SMPL 0.625 l.OO 1.25 2.50 6.O0 10.00 15.OO
ERC « WB -1 4 7 8 1} 29 34 47 C
7246 EB -I 2 5 6 9 22 35 54 C
C RANK DATA AVERAGE 3 6 7 10 26 35 51
•SEE TEXT FOR TEST SITE IDENTIFICATION.
TABLE 50. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE-CYCLONE-CONTROLLED
BOILERS BURNING PULVERIZED LIGNITE COAL
DATA SET IDENTIFICATION
TEST
TEST
TEST
STATED SIZE (MICRONS)
RANK
SITE* NO.
SMPL
0.625
l.OO
1.25
2.50
6. OO lO.
OO
15.00
166
1
2
«•
2
3
B
27
43
61
C
167
1
2
• ••
1
3
8
32
49
66
C
ERC #
WB
-0
14
26
30
50
92
94
93
C
7246
EB
-0 16
26
28
42
77
B1
85
C
C
RANK DATA AVERAGE B
14
16
27
57
67
77
•SEE TEXT FOR TEST SITE IDENTIFICATION.
••NOT MORE THAN 2 PERCENT.
•••NOT MORE THAN 1 PERCENT.
102
-------
TABLE 51. PARTICLE SIZE DISTRIBUTION DATA FOR MULTIPLE-CYCLONE-CONTROLLED
SPREADER STOKERS BURNING LIGNITE COAL
DATA SET IDENTIFICATION CUMULATIVE MASS PERCENT LESS THAN DATA
TEST TEST TEST STATED SIZE (MICRONS) RANK
SITE* NO. SMPL 0.625 l.OO 1.25 2.50 6.00 10. OO 15.00
16B 1 2 22 23 26 31 41 35
C RANK DATA AVERAGE 22 23 26 31 41 55
•SEE TEXT FOR TEST SITE IDENTIFICATION.
103
-------
testing was part of an emissions assessment of stationary combustion
sources.
A single particulate size sampling was performed on September 22, 1977
downstream of multiple cyclones. A SASS train with cyclones drew the sample
while the boiler operated continuously at 100 percent of design capacity.
Sampling conditions were partially recorded, but no sampling flowrate
isokinetic value was included. As with TSN 166, this data is C-quality.
TSN 168
This data came from tests performed on a 29-GJ/hr (8-MW), lignite coal-
fired utility boiler. By cross-matching test results with the data reference
report, this unit was determined to be fed by a spreader stoker. Multiple
cyclones were the only emissions control device in use.
A sampling test was run on September 27, 1977 during continuous
operation of the boiler at 94 percent of design capacity using a SASS train
with cyclones. Sampling conditions were partially reported without any
mention of a sampling flowrate isokinetic value. The sampling method and
insufficient conditions data result in the size data being C-quality.
ERC No. 7246 (Ref. 21)
The North Dakota State Department of Health provided data from a
particulate and gaseous emission inventory performed by Environmental
Research Corporation on June 19 through 21, 1972, on the 648-GJ/hr (180-MW)
United Power Association's Powerplant IV located in Stanton, North Dakota.
The pulverized-1ignite-fired boiler had only multiple cyclones with a nominal
62 percent collection efficiency.
The portion of the report sent to Acurex does not adequately describe
the sampling methodology and data reduction, but it does describe the
approximate 10-stage cascade impactor cut points and mentions that all
samples were taken isokinetically. Size distributions for uncontrolled plus
multiple-cyclone-control led emissions were read directly from the figures
supplied with the report. Due to the lack of clarifying information, the
data sets can only be considered C-quality.
3.4 PARTICULATE EMISSION FACTORS
The development of cumulative size-specific emission factors by weight
requires the application of particle size distributions by weight percent to
particulate emission factors. Impactors used to collect particle size
distribution samples normally are not traversed during sampling and a portion
of the particulate is collected on internal surfaces other than impactor
plates. SASS trains are also not traversed during sampling. Hence, EPA
Method 5 tests provide a more accurate total loading value. In addition,
substantially more total loading samples using EPA Method 5 have been taken
and should yield a more representative particulate emission factor. External
combustion source particulate emission factors in the current edition of
104
-------
AP-42 are listed in Tables 52 through 56 along with estimated emission
factors for controlled sources obtained by applying average collection
efficiencies of various particulate control devices (Ref. 5) to the
uncontrolled AP-42 particulate emissions factors. This comprehensive
cumulative size-specific emission factor development is not used for natural
gas combustion (see Section 3.3.4).
3.5 RECOMMENDED CUMULATIVE SIZE-SPECIFIC EMISSION FACTORS
After ranking, grouping, and calculating various averages for the size
distribution data, the size distribution by weight percent was combined with
a total mass particulate emission factor to form a size-specific emission
factor.
The size distributions by weight percent for most source categories were
developed from two or more test series. Although A-quality ranked data was
preferred, it was almost always necessary to include lower quality data in
the calculation of an average size distribution. When test series were
combined, the respective particle size distributions were averaged, weighting
the data in direct proportion to the number of runs comprising the individual
test series average.
The reliability of this size-specific emission factor is indicated by an
emission factor rating. The ratings are subjective quality evaluations
rather than statistical confidence intervals and range from A (excellent) to
E (poor) as follows:
A — Excellent. Developed only from A-rated particulate emission
factors plus A-rated size-specific test data taken from many randomly
chosen facilities in the industry population. The source category is
specific enough to minimize variability within the source category
population.
B — Above average. Developed only from A-rated particulate emission
factors plus A-rated size-specific 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 to minimize
variability within the source category population.
C -- Average. Developed only from A- and B-rated particulate emission
factors plus A- and B-rated size-specific 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 to
minimize variability within the source category population.
D -- Below average. The emission factor was developed only from A- and
B-rated particulate emission factors plus A- and B-rated size-specific
test data from a small number of facilities, and there may be reason to
suspect that these facilities do not represent a random sample of the
105
-------
TABLE 52. PARTICULATE EMISSION FACTORS FOR BITUMINOUS AND SUBBITUMINOUS
COAL COMBUSTION
Particulate
AP-4? Particulate Average co'' ec: <0'-. en'.sslo-- factors
Eivisio* eniliiion factor (3ef. I) efficiency (Ref. b] («9/>S of coal,
Firing configuration conr-oK (*g/Mg) ^Rati^g) {percent by «*t) as ftred)
PulverUec coat fired
Dry bottom
Cyclone furnace
Spreader stolrer
Overfeec stoker
Underfed itoker
unit*
Woie
Hytf.p'e cyclones
Scrubber
ESP
Raghouse
None
Multiple cyclones
£SP
Hone
Scrubbe'
ESP
None
*u51iple cyclones**
Multiple cyclones*
tiP
Baglouse
Noi»e
Kureachin- fiorfnstreaw of t>e boiler.
TABLE 53. PARTICULATE EMISSION FACTORS FOR ANTHRACITE COAL COMBUSTION
Firing configuration
AP-42 particulate
Emission emission factor (Hef. 1)
controls (kg/Mg) (Rating)
Average collection
efficiency (Ref, 5)
(percent by wt)
Particulate
emission factors
(kg/Mg of coal,
as fired)
Pulverized coal fired
None
Multiple cyclones
Baghouse
Traveling-grate stoker None
Hand-fed units None
5*4
4.6
5.0
BO
99.8
5A«
1A
0.01A
4.6
5.0
aA Is as-f1rtd asn percent by weight.
106
-------
TABLE 54. PARTICULATE EMISSION FACTORS FOR FUEL OIL COMBUSTION
Firing configuration
AP-42 particulate
Emission emission factor3 (Ref. 1)
controls {*9/*j) (Rating)
Average col lection
efficiency (Ref. 5)
(percent by wt)
Particulate
emission factors8
(kg/103 1)
Utility boilers
Residual oil
Industrial boilers
Residual oil
Distillate oil
Co«rterc1al boilers
Residual oil
Distillate oil
Residential furnaces
Distillate oil
None
ESP
Scrubber
None
Multiple cyclones
None
None
None
None
A
0.24
A
0.24
0.3
99.2
94
80
A
0.008A
Q.06A
A
0.2A
0.24
A
0.24
0.3
•Particulate emission factors for residual oil combustion without emission controls are, on average, a
function of fuel oil grade and sulfur content:
For grade 6 oil: A - 1.25 (S) ~ 0.38 where S fs the weight percent of sulfur in the oil
For grade 5 oil: A ¦ 1.25
For grade 4 oil: A • 0.88
TABLE 55. PARTICULATE EMISSION FACTORS FOR WOOD WASTE COMBUSTION IN
B0ILERSf
AP-42 particulate
Average collection
Particulate
F1ring
Emission
enlssion factor
(Ref. 1)
efficiency (Ref. 5)
emission factors
configuration
controls
(kg/Mg)
(Rating)
(percent by wt)
(kg/Mg of fuele)
Bark fired
Hone
24
B
24
Multiple cyclones4
7d
B
--
7
Multiple cyclones'*
4.5d
B
—
4.5
Scrubber
—
—
94
1.44
Wood-bark fired
None
3.6
C
3.6
Multiple cyclones*
3d
c
—
3
Multiple cyclones'1
2.7«
c
--
2.7
Scrubber
—
..
94
0.22
Dry electrostatic
--
--
--
0.16'
granular f i Iter
Wood fired
None
4.4
c
—
4.4
*With flyash reinjection.
btfithout flyash relnjection.
cEmission factor calculated using Ref. 3-14.
^Since these factors were alreay listed as controlled particulate emission factors 1n AP-42, no
corresponding average collection efficiency was required to allow calculation of controlled
particulate emission factors from uncontrolled emission factors.
eBased on moisture content of 50 percent for bark, 33 percent for wood/bark, and as-f1red for xood.
Particulate emission factors not available for salt-laden wood wastes as well as fluldlzed bed
combustors.
107
-------
TABLE 56. PARTICULATE EMISSION FACTORS FOR LIGNITE COAL COMBUSTION
Particulate
AP-42 particulate Average collection emission factors
Emission emission factor (Ref. 1) efficiency (Ref. 5) (kg/Mg of coat,
Firing configuration controls {kg/Kg) (Rating) (percent by wt) as fired)
Pulverized coal fired
Dry bottom None 3.1A4 A -- 3.1A
Multiple cyclones -- « 80 0.62A
Cyclone furnace None 3.3A C — 3.3A
Spreader stoker None 3.4A 8 « 3.4A
Multiple cyclones — — 80 0.68A
Other stokers None 1.5A B — 1.5A
•A Is as-fired ash percent by might.
108
-------
industry. There also may be evidence of variability within the
source category population. Limitations on the use of the emission
factor are footnoted in the emission factor table.
E — Poor. The emission factor was developed from a C-, D-, or E-rated
particulate emission factor and/or C- and D-rated size-specific test
data, and there may be reason to suspect that the facilities tested do
not represent a random sample of the industry. There also may be
evidence of variability within the source category population.
Limitations on the use of these factors are always footnoted.
3.5.1 Bituminous Coal
A summary of the data incorporated into each source and control device
category for cumulative size specific emission factor development and its
assigned rating follows.
Dry-Bottom Pulverized Coal-Fired Systems
The cumulative size-specific emission factor (CSSEF) for uncontrolled
emissions from a pulverized-coal-fired, dry-bottom system was developed from
averaging more than 100 individual size distribution data sets obtained from
nine sites combined with an A-rated particulate emission factor. Due to the
limited A-quality data, B-quality data were included in the average.
According to the rating criteria, the CSSEF rating can be as high as a C
which is appropriate due to the data quantity.
The CSSEF for multiple cyclone controlled emissions was based on limited
B-quality ranked size distribution data from one site combined with an
estimated particulate emission factor. The resultant CSSEF rating is
E-quality.
The CSSEF for wet scrubber controlled emissions was based on A-quality
size distribution data from developmental scrubbers and B-quality data from
one of the scrubbers which had been further refined plus data from F6D
scrubbers installed on two boilers in the Kentucky area. Those data were
combined with an estimated particulate emission factor. The CSSEF rating is
considered D-quality since size distribution data was included for too few
sources.
The size distribution for ESP-controlled emissions was calculated based
on more than 100 total A- and B-quality data sets from several sites.
B-quality ranked data was included since there was only seven A-ranked data
sets. The ESP size distribution data varied substantially. The average size
distribution by weight percent was combined with an estimated particulate
emission factor to form a CSSEF which is rated as D-quality.
The CSSEF for baghouse controlled emissions was determined using only
two B-quality data sets from one facility combined with an estimated
particulate emission factor. Based on the limited data and the use of a
109
-------
estimated particulate emission factor, the CSSEF can only be rated as
E-quali ty.
Wet-Bottom, Pulverized-Coal-Fired Systems
The CSSEF for uncontrolled emissions from a pulverized-coal-fired
wet-bottom system was calculated based on three size distribution B-quality
data sets taken at the same facility combined with a D-rated particulate
emission factor. Based on limited sampling and a low particulate emission
factor rating, the assigned CSSEF ranking is E.
The CSSEF for multipie-cyclone-controlled emissions is based on a single
particle-sizing data set with a C-ranking and is combined with an estimated
particulate emission factor which results in an E-rated CSSEF.
The CSSEF for ESP-controlled emissions is based on single sets of
C-ranked size data from five sites and is combined with an estimated
particulate emission factor (based on a D-ranked factor). The use of low
quality data results in a CSSEF with an E rating.
Coal-Fired Cyclone Furnace Systems
The CSSEF for uncontrolled emissions from a coal-fired cyclone furnace
was based on one set of size distribution data with a D-ranking combined with
a particulate emission factor with a D-ranking and resulted 1n an E-rated
CSSEF.
The CSSEF for wet scrubber controlled emissions from a coal-fired
cyclone furnace was based on one set of data with an A-ranking combined with
an estimated particulate emission factor. The CSSEF qualifies for an
E-rating due to the low quality particulate emission factor ranking.
The CSSEF for ESP-controlled emissions was based on single sets of size
distribution data from each of five separate tests combined with an estimated
particulate emission factor. Since B- and C-ranked data was combined with an
estimated particulate emission factor (based on a D-rated factor), the CSSEF
has an E-rating.
Stoker Units
The CSSEF for uncontrolled emissions from spreader stoker boilers is
based on more than 40 A-plus B-ranked size distribution samples from six
different facilities combined with a particulate emission factor with a
B-ranking. B-ranked size distribution data sets were included in determining
the average, since only 11 A-ranked data sets were available. The CSSEF has
a C-rating.
The CSSEF for emissions from a multiple cyclone control device located
downstream from a spreader stoker and employing flyash reinject!on was
determined using only one set of C-ranked size distribution data combined
110
-------
with a B-rated particulate emission factor. This provides a CSSEF with an
E-rating.
The CSSEF for emissions from a multiple-cyclone-controlled spreader
stoker was determined using nine A-quality ranked size distribution data sets
from two sites combined with an A-rated particulate emission factor. Based
on the limited number of facilities represented, the CSSEF rating is C.
The CSSEF for ESP-controlled emissions from a spreader stoker was
determined using only one C-quality ranked size distribution data set
combined with an estimated particulate emission factor. The resulting CSSEF
rating is E.
The CSSEF for baghouse controlled emissions from a spreader stoker was
determined using 37 A-quality size distribution data sets from one site plus
22 B-quality data sets from another site combined with an estimated
particulate emission factor. All the size distribution data was gathered in
1974. Based on the limited number of sites sampled for size distribution,
the age of the size distribution samples, and the estimated particulate
emission factor, the CSSEF is C-rated.
The CSSEF for uncontrolled emissions from an overfeed stoker was
determined using only one A-quality and two B-quality ranked size
distribution data sets combined with a B-rated particulate emission factor.
Due to the limited data, the CSSEF rating is D.
The CSSEF for multiple-cyclone-controlled emissions from an overfeed
stoker was determined using only three B-ranked size distribution data sets
combined with an estimated particulate emission factor. The CSSEF has an
E-quality rating.
The CSSEF for uncontrolled emission from an underfeed stoker was
determined using one set of B-ranked size distribution data from each of six
sites combined with a B-rated particulate emission factor. The CSSEF is
assessed a C-rating.
Due to the nonavailability of data for all firing configurations, size
distribution estimates need to be made. The estimates are suggested as
fol1ows:
Valid size distribution data, when obtained, negates the requirement to use
these approximations.
The cumulative size distributions and particulate emission factors used
in the development of cumulative size-specific emission factors for
bituminous and subbituminous coal combustion are shown in Table 57.
Firing configuration
Hand-fired units
Suggested approximation
Use size distribution for
underfeed stoker
111
-------
TABLE 57. CUMULATIVE SIZE DISTRIBUTIONS AND PARTICULATE EMISSION FACTORS
USED IN THE DEVELOPMENT OF CUMULATIVE SIZE-SPECIFIC EMISSION
FACTORS FOR BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION
Firing configuration
Controls
Size distribution
data sets
Cumulative mass percent less than stated size
0.625 um 1 um 1.25 mo 2.5 un 6 urn 10 um 15 urn
Number
reviewed
Number
used 1n
average
Particulate
eml sslon
factor
(kg/Ng
of coal,
as fired)
Cuiiulatlve
si ze-
speclflc
emission
factor
rating
Pulverized coal fired
Dry bottom
Hone
1
2
2
6
17
23
32
126
116
5A*
C
Multiple cyclones
1
1
1
3
14
29
54
4
3
1A
E
Scrubber
20
31
35
51
62
71
81
62
61
0.3A
D
ESP
12
14
17
29
SO
67
79
127
118
0.04a
D
Baghouse
14
25
31
53
77
92
97
2
2
O.OiA
E
Wet bottom
None
2
4
6
21
33
37
40
3
3
3.5A
E
Multiple cyclones
19
31
61
84
93
99
1
1
0.7 A
E
ESP
--
8
17
40
63
75
83
5
5
0.028A
E
Cyclone furnace
None
0
0
0
0
8
13
33
1
1
1A
E
Scrubber
82
85
92
93
94
95
1
1
0.06 A
E
ESP
—
17
22
36
56
68
80
5
5
0.008A
E
Spreader stoker
None
4
4
5
7
14
20
28
43
42
30
C
After multiple
Multiple cyclones
1
2
2
8
51
73
86
1
1
8.5
£
cyclones with
flyash relnjectlon
from multiple
cyclones
No flyash relnjectlon
Multiple cyclones
9
14
16
27
52
65
74
11
9
6.0
C
from multiple
cyclones
ESP controlled
41
46
61
82
90
97
1
1
0.24
E
Baghouse controlled
7
15
IB
26
46
60
72
59
59
0.06
C
Overfeed stoker
None
12
13
14
24
37
49
3
3
8
0
Multiple cyclones
16
39
39
43
49
55
60
3
3
4.5
E
Underfeed stoker
None
18
21
22
25
32
41
50
6
6
7.5
C
Hand-fired units
None
Use
size distribution
for
underfeed
stoker
0
0
7.5
-
¦ft is ash content on an as-fired weight percent basis.
-------
The CSSEF for multiple-cyclone-controlled emissions from an underfeed
stoker was originally calculated using only one B-ranked size distribution
data set from each of two sites combined with a C-rated particulate emission
factor. Due to the limited size distribution data and low emission factor
rating, a CSSEF rating of D would have been warranted. However, a
significant discrepancy was discovered which resulted in a decision to not
include the CSSEF in the AP-42 section. As calculated, this CSSEF resulted
in higher emission rates for 15 um si2e and smaller particles than would
occur with no control devices! Obviously, more size distribution data and
total particulate mass emission rate data is required.
3.5.2 Anthracite Coal
A summary of the data incorporated into each source and control device
category for cumulative size-specific emission factor development and its
assigned rating follows.
Pulveri2ed-Coal-Fired Systems
The CSSEF for multiple cyclone emissions from a pulverized-coal-fired
system was developed from the average of 101 A-quality plus B-quality size
distribution data sets obtained from one utility site combined with a B-rated
particulate emission factor. While these size data sets were taken in a
generally acceptable manner, the fuel mixture of anthracite slit, anthracite
no. 5 buckwheat, and petroleum coke may make the particulate emissions
loading and distribution not representative. The CSSEF is rated D-qual1ty.
The CSSEF for baghouse emissions from a pulverized-coal-fired system was
developed from the average of 66 A-quality plus B-quality size distribution
data sets obtained from one utility site (but testing new and used fabric
filters in its stationary baghouse as well as testing a mobile ERA baghouse)
combined with an estimated particulate emission factor. As previously
discussed, the fuel was actually composed of anthracite slit, anthracite
no. 5 buckwheat, and petroleum coke. The particulate emissions loading and
distribution may not be representative for anthracite coal firing. Since the
testing was conducted at only one site, and uses an estimated particulate
emission factor, the resulting CSSEF 1s rated as D-qual1ty.
Stoker Units
The CSSEF for uncontrolled emissions from a stoker unit was based on
single-B-ranked size distribution data sets from each of three sites combined
with a B-rated particulate emission factor. There 1s a significant variation
1n the limited size distribution data, so the average data rating is only
considered D-quality.
Due to the nonavailability of data for all boiler types, size
distribution estimates need to be made. The estimates are suggested as
follows:
113
-------
Boiler type
Suggested approximation
Pulverized coal fired — no controls Use size distribution from
bituminous coal combustion
Hand-fed units Use size distribution for
traveling-grate stoker
Valid size distribution data, when obtained, negates the requirement to use
these approximations.
The cumulative size distributions and particulate emission factors used
in the development of cumulative size-specific emission factors for
anthracite coal combustion are shown in Table 58.
3'5'3 Fuel Oil
A summary of the data incorporated into each source and control device
category for cumulative size-specific emission factor development and its
assigned rating follows.
Utility Systems
The CSSEF for uncontrolled emissions from a utility residual oil-fired
system was based on a total of 16 A-quality plus B-quality size distribution
data sets from eight different sites combined with an A-rated particulate
emission factor. Although A-quality size distribution data sets are limited
to one site, a sufficient number of B-quality data sets from seven other
sites enables the CSSEF to be rated as C-quality.
The CSSEF for electrostatic precipitator controlled emissions from a
utility residual oil-fired system was based on only one set of C-ranked size
distribution data from each of two facilities combined with an estimated
particulate emission factor. Using limited C-ranked data results in an
E-qual1ty rating for the average.
The CSSEF for wet scrubber controlled emissions from a utility residual
oil-fired system was based on only four sets of size distribution data from
one facility combined with an estimated particulate emission factor.
Although the size data has an A-quality ranking, the sampling 1s too limited
to provide a utility average and is rated as D-quality.
Industrial Systems
The CSSEF for uncontrolled emissions from an industrial residual
oil-fired system was calculated using 14 B-quality size distribution sets
from six industrial facilities combined with an A-rated particulate emission
factor. With the inclusion of only B-ranked size distribution data, the
CSSEF is rated as D-quality.
114
-------
TABLE 58. CUMULATIVE SIZE DISTRIBUTION AND PARTICULATE EMISSION FACTORS
USED IN THE DEVELOPMENT OF SIZE-SPECIFIC EMISSION FACTORS FOR
ANTHRACITE COAL COMBUSTION
Size distribution
data sets
Cumulative toss percent less than stated size
Firing conflguraHon Controls
0.625 urn I
Number Number used
1.25 iiin 2.5 ym 6 pro 10 urn 15 um reviewed In average
Particulate
emission
factor
(kg/Mg
of coal.
as fired!
Cumulative
size-
specific
emission
factor
rating
Pulverized coal fired
Hone
Use
size
dlstrlbution
from Table
53
0
0
SA«
-
Multiple cyclones
7
10
13
24
46
55
63
101
101
1A
0
8aghouse
--
IS
21
32
51
67
79
66
66
0.01A
a
Traveling-grate stoker
None
--
23
24
27
42
52
64
3
3
4.6
i)
Hand-fed units
None
Use
size
distribution
for
0
0
5.0
-
traveling-grate stoker
aA is as-fired ash percent by weight.
-------
The size distribution for multiple-cyclone-controlled emissions from an
industrial residual oil-fired system was based on only one D-ranked size
distribution data set combined with an estimated particulate emission factor.
Based on the lack of better quality size distribution data, the CSSEF rating
is E.
The CSSEF for uncontrolled emissions from an industrial distillate
oil-fired system was determined using only two C-quality size distribution
data sets from one test site combined with an A-rated particulate emission
factor. Using only C-quality size distribution data results in an E-rated
CSSEF.
Commercial Systems
The CSSEF for uncontrolled emissions from a commercial residual-oi1-
fired system was based on a total of 15 A-quality plus B-quality size
distribution data sets from four test sites combined with an A-rated
particulate emission factor. This sampling is too limited to provide a
commercial average and is rated as only D-quality.
The CSSEF for uncontrolled emissions from a commercial
distillate-oil-fired system was calculated using only three A-quality size
distribution data sets from one test site combined with an A-rated
particulate emission factor. Due to the limited number of A-quality size
distribution data sets and sites, the resulting CSSEF is only rated as
0-quality.
Due to the nonavailability of data for all boiler types, size
distribution estimates need to be made. The estimates are suggested as
follows:
Boiler type Suggested approximation
Residential furnaces
Distillate oil -- no controls Use size distribution for
commercial boilers
Valid size distribution data, when obtained, negates the requirement to use
these approximations.
The cumulative size distributions and particulate emission factors used
in the development of cumulative size specific emission factors for fuel oil
combustion are shown in Table 59.
3.5.4 Wood Waste
A summary of the data incorporated into each source and control device
category for cumulative size-specific emission factor development and its
assigned rating follows.
116
-------
TABLE 59. CUMULATIVE SIZE DISTRIBUTION AND PARTICULATE EMISSION FACTORS
USED IN THE DEVELOPMENT OF CUMULATIVE SIZE-SPECIFIC EMISSION
FACTORS FOR FUEL OIL COMBUSTION
Source category
Cumulative mass percent less than stated size
Controls 0.625 um 1 um 1.25 um 2.5 mm 6 pm 10 um 15 wm
Size distribution
data sets
Number
reviewed
Number
used in
average
Particulate
emission
fac tora
(kg/103 1)
Cumulative
size-
spec i f ic
emission
factor
rating
Utility boilers
Residual oil
None
20
39
43
52
58
71
80
28
16
9A
C
ESP
10
28
31
41
52
63
75
2
2
0.008A
E
Scrubber
64
84
91
97
100
100
100
4
4
0.06A
0
Industrial boilers
Residual oil
None
30
36
39
56
77
86
91
17
14
A
0
Multiple
—
21
21
22
72
95
100
1
1
0.2A
c
cyclones
Oistl 1 late oil
None
2
a
9
12
30
50
68
2
2
0.24
r
Commercial boilers
Residual oil
None
13
14
16
23
44
62
78
19
15
A
0
Distillate oil
None
35
37
38
42
49
55
60
3
3
0.24
n
Residential furnaces
Distillate oil
None
Use
size distribution
for
commercial
boilers
0
0
0.3
—
Particulate emission factors for residual oil combustion without emission controls are,
on average, a function oF fuel oil grade and sulfur content:
For grade 6 oil
For grade 5 oil
For grade 4 oil
A = 1.25 (S) + 0.38 where S Is the weight percent of sulfur In the oil
A = 1.25
A = 0.88
-------
Bark-Fired Systems
The CSSEF for uncontrolled emissions from a bark-fired spreader stoker
boiler system was developed by averaging 11 size distribution data sets from
three industrial sites combined with a B-rated particulate emission factor.
Bark-firing is extensively used in the forest-products and other industries
and requires more than three sites for a representative sample so the CSSEF
only warrants a D-rating.
The CSSEF for multipie-cyclone-control led emissions with flyash
reinjection was calculated from nine size distribution data sets from two
industrial sites with spreader stoker boilers combined with a B-rated
particulate emission factor. Based on the limited number of sites, CSSEF is
D-rated.
The size distribution for wet scrubber controlled emissions from
spreader stoker boilers was averaged from only eight sets of size
distribution data from two sites combined with an estimated particulate
emission factor. Although the size distribution data is A-quality, the sites
are probably not fully representative of the industry since each site has
flyash reinjection from multiple cyclones upstream of the wet scrubber.
Predicated on the limited sampling, the CSSEF is 0-rated.
Wood/Bark-Fired Systems
The CSSEF for uncontrolled emissions from a wood plus bark-fired
underfeed stoker boiler system was developed by averaging two C-quality size
distribution data sets from two industrial sites combined with a C-rated
particulate emissions factor. This limited sampling only warrants an E-rated
CSSEF.
The CSSEF for multipie-cyclone-controlled emissions with flyash
reinjection from a wood plus bark-fired system was calculated using 3
A-quality data sets from one site combined with a C-rated particulate
emission factor. The number of data sets and sampled sites is insufficient
and the particulate emission factor is too low so that the resultant CSSEF is
rated as E-quality.
The CSSEF for multiple-cyclone-controlled emissions from a wood plus
bark-fired system was calculated using four B-quality size distribution data
sets from one spreader stoker boiler combined with a C-rated particulate
emission factor. The limited number of size distribution data sets and sites
plus the low rating of the particulate emission factor results in an E-rating
for the CSSEF.
The CSSEF for wet scrubber controlled emissions from a wood plus
bark-fired system was calculated from 1 set of C-ranked data from each of two
Dutch oven boiler test sites combined with an estimated particulate emission
factor. The limited low-quality data results in CSSEF with an E-rating.
118
-------
The size distribution for dry electrostatic granular filter-controlled
emissions was calculated from three A-quality data sets from each of three
modules located on the same boiler combined with a particulate emission
factor derived from experimental data. Since the number of dry electrostatic
granular filters in operation on wood plus bark-fired boilers is extremely
limited, the particulate emission factor and CSSEF are both rated A.
Due to the nonavailability of data for all boiler types, size
distribution estimates need to be made. The estimates are suggested as
follows:
Firing configuration Suggested approximation
Bark fired
Valid size distribution data, when obtained, negates the requirement to use
these approximations.
The cumulative size distribution and particulate emission factors used
in the development of cumulative size-specific emission factors for wood
waste combustion in boilers are shown in Table 50.
Although limited particle size distribution data was available for the
following catagories, CSSEFs were not calculated due to insufficient data to
calculate representative total mass particulate emission factors:
Firing Configuration
No controls -- fluidized bed combustor with heat recovery boiler
No controls — salt laden fuel in spreader stoker boiler
Multiple cyclones with flyash reinjection -- salt laden fuel in
spreader stoker boiler
Multiple cyclones with no flyash reinjection — salt laden fuel in
Dutch oven boiler
Baghouse controlled -- salt laden fuel in Dutch oven boiler
3.5.5 Lignite
A summary of the data incorporated into each source and control device
category for cumulative size specific emission factor development and its
assigned rating follows.
Multiple cyclones without
flyash reinjection
Use size distribution for
wood/bark
Wood — no controls
Use size distribution for
wood/bark
Wood/Bark
119
-------
TABLE 60. CUMULATIVE SIZE DISTRIBUTION AND PARTICULATE EMISSION FACTORS
no
O
USED IN THE
DEVELOPMENT
OF
CUMULATIVE
SIZE-SPECIFIC
EMISSION
FACTORS FOR
WOOD
WASTE
COMBUSTION
IN
BOILERS
Sl/e distribution
Part iculate
data
sets
emission
Cumulative
mass percent less
than slated sue
factor
Cumulative
(kg/Mg
sue-specif ic
Source
Number
Number used of fuel.
emission
category
Controls
0.625 iim 1 uin
1.25 mi'
i 2.5 um
6 iim 10 ym
IS um reviewed
in average
as fired)
factor rat1n
-------
Pulveri zed-Lignite-Fi red Systems
The CSSEF for uncontrolled emissions from a pulverized-1ignite-fired
system was calculated using only two C-ranked size distribution data sets
from one site combined with an A-rated particulate emission factor. Due to
the low quality and quantity of size distribution data, the CSSEF is rated
as E.
The CSSEF for multiple-cyclone-controlled emissions from a pulverized-
1ignite-fired system was developed based on only four sets of C-ranked data
combined with an estimated particulate emission factor. Due to the low data
quality input into the average, the CSSEP warrants only an E-quality rating.
Stoker Units
The CSSEF for multiple-cyclone-controlled emissions from a spreader-
stoker-fed, lignite-fueled boiler was obtained from one C-ranked size
distribution data set combined with an estimated particulate emission factor.
The CSSEF only has an E-quality rating.
Due to the nonavailability of data for all boiler types, size
distribution estimates need to be made. The estimates are suggested as
fol1ows:
Fi ring configuration
Cyclone furnace Use si
Spreader stoker Use si
Other stokers Use si
Suggested approximation
ze distribution for bituminous coal
ze distribution for bituminous coal
ze distribution for bituminous coal
Valid size distribution data, when obtained, negates the requirement to use
these approximations.
The cumulative size distributions and particulate emission factors used
in the development of cumulative size-specific emission factors for lignite
coal combustion are shown in Table 61.
121
-------
Table 61. CUMULATIVE SIZE DISTRIBUTION AND PARTICULATE EMISSION FACTORS
USED IN THE DEVELOPMENT OF SIZE-SPECIFIC EMISSION FACTORS FOR
LIGNITE COAL COMBUSTION
F i r i ng
configuration
Size disbribution
d«t,» sets
Cumulative imss percent less than stated size
Controls 0.625 I u"i 1.25 urn 2.5 um 6 gm 10 g«i 15 yi
Number
reviewed
Number used
in average
Particula te
emi ss ion
factor
(kg/Mg
of coal,
as fired)
Cumulative
size-speci fic
emi sslon
factor rating
Pulverized
coal-fired
dry bottom
None
Multiple
cyclones
6
14
7
16
10
?/
26 35
¦W 6/
51
/;
3.1A«
0.62A
Cyclone
furnace
None
Use size distribution for bituminous co.il
3.3A
Spreader
stoker
None
'•lul tlple
cyclones
Use size distribution for bituminous coal
22 23 26 31 41
55
3.4A
0.68A
r\>
ro
Other
stokers
None
Use size distribution for bituminous coal
"A is ash content on an as-fired weight percent hasls.
1.5A
-------
PROPOSED AP-42 SECTIONS
The proposed revision to Sections 1.1, 1.2, 1.3,
1.4, 1.6 and 1.7 of AP-42 is presented in the
following pages as it would appear in the actual
document.
123
-------
1.1 BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION
1,1.1 General 1
Coal is a complex combination of organic matter and Inorganic ash formed
over eons from successive layers of fallen vegetation. Coal types are broadly
classified as anthracite, bituminous, subbituminous or lignite, and classifica-
tion is made by heating values and amounts of fixed carbon, volatile matter,
asb, sulfur and moisture. Formulas for differentiating coals based on these
properties are given in Reference 1. See Sections 1.2 and 1.7 for discussions
of anthracite and lignite, respectively.
There are two major coal combustion techniques, suspension firing and
grate firing. Suspension firing is the primary combustion mechanism in pulver-
ized coal and cyclone systems. Grate firing is the primary mechanism in under-
feed and overfeed stokers. Both mechanisms are employed in spreader stokers.
Pulverized coal furnaces are used primarily in utility and large industrial
boilers. In these systems, the coal is pulverized in a mill to the consistency
of talcum powder (i. e., at least 70 percent of the particles will pass through
a 200 mesh sieve). The pulverized coal is generally entrained in primary air
before being fed through the burners to the combustion chamber, where it is
fired in suspension. Pulverized coal furnaces are classified as either dry or
wet bottom, depending on the ash removal technique. Dry bottom furnaces fire
coals with high ash fusion temperatures, and dry ash removal techniques are
used. In wet bottom (slag tap) furnaces, coals with low ash fusion tempera-
tures are used, and molten ash is drained from the bottom of the furnace.
Pulverized coal furnaces are further classified by the firing position of the
burners, i. e., single (front or rear) wall, horizontally opposed, vertical,
tangential (corner fired), turbo or arch fired.
Cyclone furnaces burn low ash fusion temperature coal crushed to a 4 mesh
size. The coal is fed tangentially, with primary air, to a horizontal cylin-
drical combustion chamber. In this chamber, small coal particles are burned
in suspension, while the larger particles are forced against the outer wall.
Because of the high temperatures developed in the relatively small furnace
volume, and because of the low fusion temperature of the coal ash, much of the
ash forms a liquid slag which is drained from the bottom of the furnace through
a slag tap opening. Cyclone furnaces are used mostly in utility and large
Industrial applications.
In spreader stokers, a flipping mechanism throws the coal into the furnace
and onto a moving fuel bed. Combustion occurs partly in suspension and partly
on the grate. Because of significant carbon in the particulate, flyash rein-
jectlon from mechanical collectors is commonly employed to improve boiler
efficiency. Ash residue In the fuel bed Is deposited in a receiving pit at the
end of the grate.
External Combustion Sources
124
1.1-1
-------
r TABLE 1.1-1. EMISSION FACTORS FOR EXTERNAL BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION8
~—»
I
ro
Particulate*
Sulfur Oxldea(
91 treses
Cnidaad
Carboa Hoaotlde*
lenotheae ¥QC«»* 1
Mathaoe*
Plrlng Conflguretloo
kg/Ng
lb/ton
1bftoo
lb/toa
kg/"*
lb/toa
kg/Kg
lb/toa
kg/Kg
lb/too
Pulvcrlted coal fired
0ry bolt cm
SA
10A
19.5S<17.^S)
J9SOH)
ID.S
39S(3SS>
3.?5
7-5
)
6
0 04
0.07
0.015
0.0)
After eoltiple cyclone
4.5°
9n
19. 5S< 17 .55)
39S(35S)
3.1^
7.5
3
6
0.04
0.07
0.015
0.03
Underfeed itoirr
Uncoat rn|led
7.5P
UP
15.5S
lis
4.7)
9.S
5.5
11
0.65
1.5
0.4
0.8
Alter multiple cyclone
•>.5°
tln
lb . >5
IIS
4.75
9.J
5.5
II
0.65
1.3
0.4
0.6
HendfIrcd unite
15
15.SS
IIS
1. S
3
*5
90
5
10
4
•
•Factors represent uncontrolled (iiniou wlfsi ovhervlae apeclfled ind should be ippliid to coil (ooiiaviioa ti (lif4<
bB»«rd on KPA Hrthod 5 (front half catch) aa described In Reference 12. Mitre particulate (• eepreaaed in terms of eoal
itii concern. A, tidor It drifralnml by auK Ipl yl ng weight X i*h coo tent of coal (ee llred} ky the euaerlcal valiM
preceding the "A". Par paemple, if coal having AS aah la fired la a dry botto* wit, the particulate emlaalon factor
mou 1 d b« *> * 8, or 40 k|/N| (80 lb/ton). The "roadenelble" setter collected In back half catch of IN Method 5 eeeregee
<5X of front half, or "fflterable*, catch foi pulvcrlaed coal aod cyclone furnecee; 101 for epreader etofcere, ISX tot
other etofcera; and *>0X for handflred unite (Refereocea 6, 19, *9).
cCipr«i«*d aa SO^, Includli^ ®®2* sn<' l11"^' aulfaiea. Pactore la pareotheeea ahoald be oaed to eitiaitr gaacOua
50, emiitelone for lubblnainoua coal. In all tima, "S* la wi|ht X iul[«r cootaot of coal aa fired- Sea Footooca b for
ruaplf ralrulatton. On average for blttalaowe coal. 971 ot fuel eulfuf la Ml tied aa SOj, aod OOly about 0.7X of fuel
eulfut la ealud »a SO) and gaeeoua aultete. An tquilly email prfcnl of fwl aoKur la emitted aa particulate sulfate
(Referenceo 9, 13). Sull quaotitiea of auifur are alao retained lo belts aah. With labbltaiDwa coal generally about
10Z wire fuei aulfttr I* retaioed In the boitoo aah and particulate becauae of tha acre alkallae nature of the coal aah.
Conversion to geaeoue sulfate appeare about the aame aa for bltwlnoua coal.
^Eipretaed aa NOj. Generally, 95 - 99 voluae X of nitrogen oaldea preeent lo coabmloei aihauat will be la the for* «(
MO, the reet NO? (ieterence t1>. Tu eapreaa factora aa MO, aultlpl; by factor of 0.64. All faetora repreeent emlaalon
*t bate line operation (i.e.. 60 - 110X load and ao ItO, control meeeuree, aa dlseeaaed la teat).
~Nominal veluea arhteveable under norma 1 operating conditions. Values one or two orders of magnitude higher can occur
whan combvatloo la not ccsplete-
'norm-thane volatile organic compeunde (VOC), eapreeead aa Cj to Cift o-alkaoa equivaleota (Beterenca 5fl>- leceuee of
limited date on MKVOC available to dletlngulah the effecte of firing coafIguratioa, alt data mere averaged
collectively to develop a alngle average for pulverised coat unlta, cfclooaa, apreadara aod overfeed atokera.
^Parenthetic value la for taogealtallr fired bollara.
hUncontrolled particulate emtaelona, Mien no fly aah relnjectlon la apleyed. Ibao control device la Inateiled. aod
collected fly aah la reinjected to holler, particulate (ra* boiler reach log cootrol equ i pmeat cao locraaae by up to a
factor of tvo-
ihecouAta for fly aah aecillag in an econaalier, air haatat or breech lag upat cam of cootrol dsvlte or slack-
(Partlrulace directly at boiler m(l*f typically will be twice thie level.) Pactor should be applied even vhen fly
aah la reinjected to bollci (itm bollet. air heater or ecomomieer duat bopp* re.
klncludea travelling grate, vibrating grate a ad chain grate a take re.
¦Accounta tor tly aah aattllog In breeching or atack baa*. Particulate Imadlnge directly at boiler outlet typlraliy
can be VOX higher.
nSee teat tor tiecuaaion ot apparently low multiple eye lone cootrol efficlenelea, regarding uncontrolled emlaalooa.
PArrounta for fly aah eettllng In breeching downatveam of holler outlet.
-------
TABLE 1.1-2. EMISSION FACTOR RATINGS* AND REFERENCES FOR BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION
K>
&
X
3
O
o
a
a"
c
o
p
LO
o
c
rl
o
ft
X
Firing Configuration
Particulate
Sulfur Oxides
Hal Ing
Re I.
Hating Ref.
Nitrogen Oxide*
Carbon Honoxlde
Nc>naetlia.ie VOC
Rat ing
Ref.
Rat ing
k£f.
ing
Pulverised coal fired
Dry totto»
Ml bOCCOB
Cyclone furnace
Spreader stoker
Uncontrolled
After solriple cyclone
With llyish relojcctiun
troa cyclone
No ilyuah icinjcctiufi
trua cyclone
Overfeed stoker
Uncontrolled
Alter multiple cyclone
Underlaad stoker
lineupt roI led
Alter aultiple cyclone
handfired unite
14-25
14,16,26
14,19,22,
27-29
17,10-35
14,12,16- 38
17,31-35,
39,40,59
6,17,41-43,
45-47
6,41,44-4}
6,19,47-48
6
49-50
9.16-19,21,
31-37,19,
41-46,51-5*
19,40
11,14,16-17,
21,46,56
14.16
11
11,17,11-37
39-40,46
A 11,17,19,
41-45
B 19,47-48
B M
D 50
16,18-19,21
47,57
Re t . Flat Ing Re f.
55,58 A 58
58
1 7,19,31-34,
36,47,51
17,41-42,45,
47.51
19,47-48
SO
A 47,58
A
D 50,58
47,58
50.58
Cheae ratings, in the conteiL of chia Section, refer to the nuaber of tear data oo which each i-aUalon factor la b«8i:d. An mA" rating aeana the
far to i ia baaed on test* at ten or Bura bollera, a "B" rating on els to nine teat data, and a "C" rating on teat data lot tw lo five boileta.
rating indicatea the factor la baaed on only a alngle dalua or aatrapolated tros a secondary reference. Theae ratings are not a aeaaure of
A "D"
the acalter In the u/tderlying tfut data. However, a higher rating will generally increase confldeoc* that a given factor will better approilaate
the average ealaalona for a particular boiler category.
I
OJ
-------
In overfeed stokers, coal ts fed onto a traveling or vibrating grate, and
It burns on the fuel bed as It progresses through the furnace. Ash particles
fall Into an ash pit at the rear of the stoker. The terra "overfeed" applies
because the coal is fed onto the moving grate under an adjustable gate. Con-
versely, in "underfeed" stokers, coal is fed into the firing zone from under-
neath by mechanical rams or screw conveyers. The coal moves In a channel,
known as a retort, from which it is forced upward, spilling over the top of
each side to form and to feed the fuel bed. Combustion is completed by the
time the bed reaches the side dump grates from which the ash is discharged to
shallow pits. Underfeed stokers include single retort units and multiple
retort units, the latter having several retorts side by side.
1.1.2 Emissions And Controls
The major pollutants of concern from external coal combustion are partic-
ulate, sulfur oxides and nitrogen oxides. Some unburnt combustibles, including
numerous organic compounds and carbon monoxide, are generally emitted even
under proper boiler operating conditions.
Particulate^-1^ - Particulate composition and emission levels are a complex
function of firing configuration, boiler operation and coal properties. In
pulverized coal systems, combustion is almost complete, and thus particulate
largely comprises inorganic ash residue. In wet bottom pulverized coal units
and cyclones, the quantity of ash leaving the boiler ts less than in dry bottom
units, since some of the ash liquifies, collects on the furnace walls, and
drains from the furnace bottom as molten slag. To increase the fraction of ash
drawn off as wet slag, and thus to reduce the flyash disposal problem, flyash
may be reinjected from collection equipment into slag tap systems. Dry bottom
unit ash may also be reinjected into wet bottom boilers for the same purpose.
Because a mixture of fine and coarse coal particles is fired in spreader
stokers, significant unburnt carbon can be present In the particulate. To
Improve boiler efficiency, flyash from collection devices (typically multiple
cyclones) is sometimes reinjected into spreader stoker furnaces. This prac-
tice can dramatically Increase the particulate loading at the boiler outlet
and, to a lesser extent, at the mechanical collector outlet. Flyash can also
be reinjected from the boiler, air heater and economizer dust hoppers. Flyash
reinjection from these hoppers does not increase particulate loadings nearly so
much as from multiple cyclones.5
Uncontrolled overfeed and underfeed stokers emit considerably less particu-
late than do pulverized coal units and spreader stokers, since combustion takes
place in a relatively quiescent fuel bed. Flyash reinjection is not practiced
in these kinds of stokers.
Other variables than firing configuration and flyash reinjection can
affect emissions from stokers. Particulate loadings will often increase as
load increases (especially as full load is approached) and with sudden load
changes. Similarly, particulate can increase as the ash and fines contents
increase. ("Fines", in this context, are coal particles smaller than about 1.6
millimeters, or one sixteenth inch, in diameter.) Conversely, particulate can
be reduced significantly when overfire air pressures are increased.^
1.1-4
EMISSION FACTORS
127
-------
The primary kinds of particulate control devices used for coal combustion
include multiple cyclones, electrostatic precipitators, fabric filters (bag-
houses) and scrubbers. Some measure of control will even result from ash
settling in boiler/air heater/economizer dust hoppers, large breeches and chim-
ney bases. To the extent possible from the existing data base, the effects of
such settling are reflected in the emission factors in Table l.l-l.
Electrostatic precipitators (ESP) are the most common high efficiency
control device used on pulverized coal and cyclone units, and they are being
used increasingly on stokers. Generally, ESP collection efficiencies are a
function of collection plate area per volumetric flow rate of flue gas through
the device. Particulate control efficiencies of 99.9 weight percent are
obtainable with ESPs. Fabric filters have recently seen increased use in both
utility and industrial applications, generally effecting about 99.8 percent
efficiency. An advantage of fabric filters is that they are unaffected by high
flyash resistivities associated with low sulfur coals. ESPs located after air
preheaters (i. e,, cold side precipitators) may operate at significantly reduced
efficiencies when low sulfur coal is fired. Scrubbers are also used to control
particulate, although their primary use is to control sulfur oxides. One draw-
back of scrubbers ts the high energy requirement to achieve control efficiencies
comparable to those of ESPs and baghouses.2
Mechanical collectors, generally multiple cyclones, are the primary means
of control on many stokers and are sometimes installed upsteam of high effi-
ciency control devices in order to reduce the ash collection burden. Depending
on application and design, multiple cyclone efficiencies can vary tremendously.
Where cyclone design flow rates are not attained (which is common with under-
feed and overfeed stokers), these devices may be only marginally effective and
may prove little better in reducing particulate than large breeching. Con-
versely, well designed multiple cyclones, operating at the required flow rates,
can achieve collection efficiencies on spreader stokers and overfeed stokers
of 90 to 95 percent. Even higher collection efficiencies are obtainable on
spreader stokers with reinjected flyash, because of the larger particle sizes
and increased particulate loading reaching the controls.5-6
Sulfur Oxides?-^ - Gaseous sulfur oxides from external coal combustion
are largely sulfur dioxide (SO2) and much less quantity of sulfur trioxlde
(SO3) and gaseous sulfates. These compounds form as the organic and pyritic
sulfur in the coal is oxidized during the combustion process. On average, 98
percent of the sulfur present in bituminous coal will be emitted as gaseous
sulfur oxides, whereas somewhat less will be emitted when subbituminous coal
is fired. The more alkaline nature of the ash in some subbituminous coal
causes some of the sulfur to react to form various sulfate salts that are
retained in the boiler or in the flyash. Generally, boiler size, firing con-
figuration and boiler operations have little effect on the percent conversion
of fuel sulfur to sulfur oxides.
Several techniques are used to reduce sulfur oxides from coal combustion.
One way is to switch to lower sulfur coals, since sulfur oxide emissions are
proportional to the sulfur content of the coal. This alternative may not be
possible where lower sulfur coal is not readily available or where a different
grade of coal can not be satisfactorily fired. In some cases, various cleaning
processes may be employed to reduce the fuel sulfur content. Physical coal
cleaning removes mineral sulfur such as pyrite but is not effective in removing
External Combustion Sources
128
1.1-5
-------
organic sulfur. Chemical cleaning and solvent refining processes are being
developed to remove organic sulfur.
Many flue gas desulfurization techniques can remove sulfur oxides formed
during combustion. Flue gases can be treated through wet, semidry or dry
desulfurization processes of either the throwaway type, in which all waste
streams are discarded, or the recovery (regenerable) type, in which the S0X
absorbent is regenerated and reused. To date, wet systems are the most com-
monly applied. Wet systems generally use alkali slurries as the SOx absorbent
medium and can be designed to remove well in excess of 90 percent of the in-
coming SO*. Particulate reduction of up to 99 percent is also possible with
wet scrubbers, but flyash is often collected by upsteam ESPs or baghouses, to
avoid erosion of the desulfurization equipment and possible Interference with
the process reactions.? Also, the volume of scrubber sludge is reduced with
separate flyash removal, and contamination of the reagents and byproducts is
prevented. References 7 and 8 give more details on scrubbing and other S0X
removal techniques.
Nitrogen Oxides - Nitrogen oxides (NOx) emissions from coal
combustion are primarily nitrogen oxide (NO). Only a few volume percent are
nitrogen dioxide (N02). NO results from thermal fixation of atmospheric nitro-
gen In the combustion flame and from oxidation of nitrogen bound in the coal.
Typically, only 20 to 60 percent of the fuel nitrogen is converted to nitrogen
oxides. Bituminous and subbituminous coals usually contain from 0.5 to 2
weight percent nitrogen, present mainly in aromatic ring structures. Fuel
nitrogen can account for up to 80 percent of total NOjj from coal combustion.
A number of combustion modifications can be made to reduce N0X emissions
from boilers. Low excess air (LEA) firing is the most widespread control
modification, because it can be practiced in both old and new units and in all
sizes of boilers. LEA firing is easy to implement and has the added advantage
of Increasing fuel use efficiency. LEA firing is generally effective only
above 20 percent excess air for pulverized coal units and above 30 percent
excess air for stokers. Below these levels, the NOx reduction from decreased 0£
availability is offset by increased N0X because of increased flame temperature.
Another N0X reduction technique Is simply to switch to a coal having a lower
nitrogen content, although many boilers may not properly fire coals of different
properties.
Off-stoichiometric (staged) combustion is also an effective means of
controlling N0X from coal fired equipment. This can be achieved by using
overfire air or low NG^ burners designed to stage combustion In the flame zone.
Other NOx reduction techniques include flue gas recirculation, load reduction,
and steam or water Injection. However, these techniques are not very effective
for use on coal fired equipment because of the fuel nitrogen effect. Ammonia
injection is another technique which can be used, but it is costly. The net
reduction of N0X from any of these techniques or combinations thereof varies
considerably with boiler type, coal properties and existing operating practices.
Typical reductions will range from L0 to 60 percent. References 10 and 60
should be consulted for a detailed discussion of each of these NC^ reduction
techniques. To date, flue gas treatment is not used to reduce nitrogen oxide
emissions because of its higher cost.
1.1-6
EMISSION FACTORS
129
-------
Volatile Organic Compounds And Carbon Monoxide - Volatile organic compounds
(VOC) and carbon monoxide (CO) are unburnt gaseous combustibles which generally
are emitted in quite small amounts. However, during startups, temporary upsets
or other conditions preventing complete combustion, unburnt combustible emis-
sions may increase dramatically. VOC and CO emissions per unit of fuel fired
are normally lower from pulverized coal or cyclone furnaces than from smaller
stokers and handfired units where operating conditions are not so well con-
trolled. Measures used for N0X control can increase CO emissions, so to reduce
the risk of explosion, such measures are applied only to the point at which CO
in the flue gas reaches a maximum of about 200 parts per million. Other than
maintaining proper combustion conditions, control measures are not applied to
control VOC and CO.
Emission Factors And References - Emission factors for several pollutants
are presented in Table 1.1-1, and factor ratings and references are presented
in Table 1.1-2. The factors for uncontrolled underfeed stokers and hand fired
units also may be applied to hot air furnaces. Tables 1.1-3 through 1.1-8
present cumulative size distribution data and size specific emission factors
for particulate emissions from the combustion sources discussed above. Uncon-
trolled and controlled size specific emission factors are presented in Figures
1.1-1 through 1.1-6.
External Combustion Sources
130
1.1-7
-------
TABLE 1.1-3.
FACTORS
CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FOR DRY BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL3
EMISSION FACTOR RATING:
C (uncontrolled)
D (scrubber and ESP controlled
E (multiple cyclone and baghouse)
Nrticla «l• tlr«d!
Uncontrolled
Control Jed^
Mulclple
cyclone
5crubber
ESP
Baghoute
1.6A
0.54A
0.24A
0.032A
O.OIOA
(3.2A)
<1.06A)
(3.48A)
(0.06A)
(0.02A)
1.15A
0.29A
0.2U
0.02H
0.0C9A
(2 .JA)
(0.58A)
C0.42A)
(0.05AJ
<0.02A)
0.85A
0.14A
0.19A
0.020A
0.008A
(0.6A)
(0.08A)
(0.02A)
^Bipraaaad aa aarodyoaalc equivalent dlaaecar.
CA • coal ash 'eight X, •• fired.
^Eatl.aced control efficiency far lultlple cyclone, BOX; aerubber, 94X;
S3F, 99.21, baghouaa. 99.8X.
0 -0
01 O
>— o
2. OA
S.SA
1.6A
1.4A
1.2A
1. OA
0.8A
0.6A
Q.4A
3.2A
0
Scrubber
i i i i i i t i
Baghouse
Uncontrolled
Multiple c/clore
i i i i i i t i
1 .DA
Q.6A
Q.4A
0.2A
C.iA
c. J*
0.06A
o ~
Q.04A u §
"9 U
m T3
a.
41 i.
O —
a. a
•— cn
= x
E
; JS
0.02A
.2
.4 .6 i 2 4 6 10
Particle diameter (^m)
20
40 60 100
O.OIA
0. !A
0.C6A
0.04A
0.02A
0.01A
3.036A
0.004A
0.002A S
E
*
wO -
W '—
-C o
—I Q.001A
Figure 1.1-1.
1.1-8
Cumulative size specific emission factors for dry bottom
boilers burning pulverized bituminous coal.
EMISSION FACTORS 10/86
131
-------
TABLE 1.1-4. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR WET BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL3
EMISSION FACTOR RATING: E
Cumulative mass % < stater! qtze
Cunul.-iclve emission factor0 f'*g/Mg
(lb/ton) coal, sb fired|
Particle size**
Uncontrolled
Cor.t rol led
Uncont rolLed
Controlled1^
Multiple
Hulclple cycLone
ESP
cyclone
ESP
15
40
99
83
I.4A { 2.9 A)
0.69A {I.38A)
0.023A (0.046A)
10
37
93
7rj
I.30A (2.6A)
0.65A C1.3A)
0.021A (0.C42A)
6
33
84
63
I.16A (2.32A)
0.59A U.I8A)
0.018a (0.036a)
2.5
21
61
40
0.74A (I.46A)
0.43A C0.86A)
0.011A (0.022A)
1.25
6
31
17
0.2SA (0.42A)
C.22A (0.44a)
C.OO^A (0.01A)
1.00
19
*
0.14A (9.28A)
O.I3A (0.26A)
0.002A (0.004A)
0.625
2
e
0.07a (0.14A)
e
e
TOTAL
1C0
;oo
100
3.5A (7.OA)
0.7A (l.4A>
0.028A (0.C56A)
^Reference 61. ESP ¦ electrostatic precipitator.
^Expressed a§ aerodynamic equivalent disaster.
cA - coal ash weight *, as fired.
dRBtltaated control efficiency for multiple cyclone, 802; £SP, 99. IX,
eInsuffIcient data.
a.bA
1. 4A
0. ?DA p
tSF "\
Multipl£
cyclone
\ . J._l.
ncc-ntrol led
j i_
1 . LA
3.94 3
«»>
- c
o
'j .Ik ^ 1
3 . Dr*
o
•— n
D.SA o -
D.3A
c e*
C. 1A
C
.2
1 2 4 5 10
Parvcle ciamerer
40 63 100
C.1A
C.Q6A
u
o
3-C4A
c D
u. u^.h o i-
£ *9
0 JIM
XJ —
U.006A O
iP
0.002A
0.00IA
Figure 1.1-2.
Cumulative size specific emission factors for wet bottom
boilers burning pulverized bituminous coal
External Combustion Sources 1.1-9
132
-------
TABLE 1.1-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR CYCLONE FURNACES BURNING BITUMINOUS COAL3
EMISSION FACTOR RATING: E
Particle Bite1'
Cumulative u
s*
3.004A
a*
¦g-
«
0.0Q2A
3
M
w*l
0.001A
Figure 1.1-3. Cumulative size specific emission factors for cyclone
furnaces burning bituainous coal
1.1-10
EMISSION FACTORS
133
10/86
-------
TABLE 1.1-6.
CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR SPREADER STOKERS BURNING BITUMINOUS COAL3
EMISSION FACTOR RATING:
(uncontrolled and controlled for
multiple cyclone without flyash
reinjection, and with baghouse)
(multiple cyclone controlled with
flyash reinjection, and ESP
controlled)
Partlrl# »li»*
Cuaulsetv*
15
21
8*
76
1?
n
9.«
(16.8)
t" '
y.-i
i
<5.4
(1.8)
o o
O.C4)
<0.08*0
10
?o
n
65
90
bO
6.0
(12.n)
6.2
<12.4)
3.
0.22
(O.ki)
0.R3&
(O.CK)
6
u
51
52
*6
4.2
(a.6)
*.1
(9.6)
}. t
'.6.2;
o,i*:
(O.AC)
O.OZ8
(0.O56)
2.5
7
8
27
J
2t
2.1
(6.2)
0.7
(; .&)
0.15
(0.111)
0.016
(o.om
1.25
5
2
16
at
19
1.5
(1.0)
0.2
(0.4)
1.0
(2.C)
o.n
(0.22)
3.011
(0.022)
I.CO
5
2
1*
i
I 5
1.5
I J.<0
0.2
(0.A)
0.8
(1.6)
O.iO
<0.201
0.00* |
{0.0!8> 1
0.625
*
1
9
t
7
1.2
(?.4l
0.1
<0.2)
C. 5
(1.0)
-
3.004
(0.008)
TOTAL
100
100
100
I00
100
30.C
<60.C)
8.5
(ir.o>
6.0
( I2.C)
0.24
-------
TABLE 1.1-7. CUMULATIVE PARTICLE SIZE DISTRIBUTION7 AND SIZE SPECIFIC EMISSION
FACTORS FOR OVERFEED STOKERS BURNING BITUMINOUS COAL3
EMISSION FACTOR RATING: C (uncontrolled)
E (multiple cyclone controlled)
Particle slze<>
Cumulative mass t < stated size
Cumulative ealaslon factor
(lb/ton) coal, as fired]
(uffl)
Uncont rill led
Multiple cyclone
controlled
Unront roi1ed
Multiple cyclone
r.onL rol led^
15
49
60
3.9
(7.8)
2.7
(5.4)
10
37
55
3.0
(6.(1)
2.S
(5.0)
5
24
49
1.9
(3.8)
2.2
(4.4)
2.5
14
43
I.l
(2.2)
1.9
(3.8)
1.25
n
39
1.0
(2.0)
1.8
(3.6)
1.00
12
39
1.0
(2.0)
1.8
(3.6)
0.625
c
lb
c
0.7
(1.4)
TOTAL
100
100
8.0
(16.0)
4.5
(9.0)
^Expressed as aerodynamic equivalent diameter.
cInsufficient data*
^Estimated control efficiency fnr multiple cyclorr, 80Z.
3
ST
i
20
_1 I ' i i i i
40 60 100
0.1
Figure 1.1-5. Cumulative size specific emission factors for
stokers burning bituminous coal
overfeed
1.1-12
EMISSION FACTORS
135
-------
TABLE 1.1-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR UNDERFEED STOKERS BURNING BITUMINOUS COAL*
EMISSION FACTOR RATING: C
Particle size'5
('•m)
Cumulative mass X < stated size
Uncontrolled cumulative emission factor0
lkg/Hg (lb/ton) coal, as fired]
15
50
3.8 (7.6)
10
it 1
3.1 (6.2)
6
32
2.A (4.8)
2.5
25
1.9 (3.8)
1.25
22
1.7 (3.A)
1.00
21
1.6 (3.2)
0.625
18
1.4 (2.7)
TOTAL
100
7.5 (15.0)
aReference 61.
*>Ex pressed as aerodynamic equivalent diameter.
cMay also be used for uncontrolled hand fired unit").
10
9
C
7
3 -
2
1
Uncontrolled
.4 .5 1 2 4 6 10
Particle diaineter (mm)
20
40 60 100
Figure 1.1-6. Cumulative size specific emission factors for underfeed
stokers burning bituminous coal.
10/86
External Combustion Sources
136
1.1-13
-------
References for Section l.l
1. Steam, 38th Edition, Babcock and Wilcox, New York, 1975.
2. Control Techniques for Particulate Emissions from Stationary Sources,
Volume I, EPA-450/3-8l-005a, IJ. S. Environmental Protection Agency,
Research Triangle Park, NC, April 1981.
3. ibidem, Volume II, EPA-450/3-81-0005b.
4. Electric Utility Steam Generating Units: Background Information for
Proposed Particulate Matter Emission Standard, EPA-450/2-78-006a, 'J. S.
Environmental Protection Agency, Research Triangle Park, NC, July 1978.
5. W. Axtraan and M. A. Eleniewski, "Field Test Results of Eighteen Industrial
Coal Stoker Fired Boilers for Emission Control and Improved Efficiency",
Presented at the 74th Annual Meeting of the Air Pollution Control Asso-
ciation, Philadelphia, PA, June 198L.
6. Field Tests of Industrial Stoker Coal Fired Boilers for Emission Control
and Efficiency Improvement - Sites Ll-17, EPA-600/7-81-020a, U. S. Environ-
mental Protection Agency, Washington, DC, February 1981.
7. Control Techniques for Sulfur Dioxide Emissions from Stationary Sources,
2nd Edition, EPA-450/3-81-004, U. S. Environmental Protection Agency,
Research Triangle Park, NC, April 1981.
8. Electric Utility Steam Generating Units: Background Information for
Proposed SO? Emission Standards, EPA-450/2-78-007a, U. S. Environmental
Protection Agency, Research Triangle Park, NC, July 1978.
Environmental Protection Agency, Washington, DC, February 1981.
9. Carlo Castaldini and Meredith Angwln, Boiler Design and Operating Vari-
ables 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.
LO. Control Techniques for Nitrogen Oxides Emissions from Stationary Sources,
2nd Edition, EPA-450/1-78-001, U. S. Environmental Protection Agency,
Research Triangle Park, NC, January 1978.
11. Review of NOy Emission Factors for Stationary Fossil Fuel Combustion
Sources, EPA-450/4-79-021, U. S. Environmental Protection Agency,
Research Triangle Park, NC, September 1979.
12. Standards of Performance for New Stationary Sources, 36 FR 24876, December
23, 1971.
13. L. Scinto, Primary Sulfate Emissions from Coal and Oil Combustion, EPA
Contract Number 68-02-3138, TRW Inc., Redondo Beach, CA, February 1980.
14. S. T. Cuffe and R. W. Gerstele, Emissions from Coal Fired Power Plants:
A Comprehensive Summary, 999-AP-35, U. S. Environmental Protection Agency,
Research Triangle Park, NC, L967.
1.1-14
EMISSION FACTORS
-------
15. Field Testing: Application of Combustion Modifications To Control NOy
Emissions from Utility Boilers, EPA-650/2-74-066, U. S. Environmental
Protection Agency, Washington, DC, June 1974.
16. Control of Utility Boiler and Gas Turbine Pollutant Emissions by Combus-
tion Modification - Phase I, EPA-600/7-78-036a, U. S. Environmental
Protection Agency, Washington, DC, March 1978.
17. Low-sulfur Western Coal Use In Existing Small and Intermediate Size
Boilers, EPA-600/7-78-153a, U. S. Environmental Protection Agency,
Washington, DC, July 1978.
18. Hazardous Emission Characterization of Utility Boilers, EPA-650/2-75-066,
U. S. Environmental Protection Agency, Washington, DC, July 1975.
19. Application of Combustion Modifications To Control Pollutant Emissions
from Industrial Boilers - Phase I, EPA-650/2-74-078a, U. S. Environmental
Protection Agency, Washington, DC, October 1974.
20. Field Study To Obtain Trace Element Mass Balances at a Coal Fired Utility
Boiler, EPA-600/7-80-171, IJ. S. finvi ronmental Protection Agency, Washing-
ton, DC, October 1980.
21. Environmental Assessment of Coal and Oil Firing in a Controlled Industrial
Boiler, Volume II, EPA-600/7-78-164b, U. S. Environmental Protection
Agency, Washington, DC, August 1978.
22. Coal Fired Power Plant Trace Element Study, U. S. Environmental Protection
Agency, Denver, CO, September 1975.
23. Source Testing of Duke Power Company, Plezer, SC, EMB-71-CI-01, U. S.
Environmental Protection Agency, Research Triangle Park, NC, February 1971.
24. J. W. Kaakinen, et al., "Trace Element Behavior in Coal-fired Power Plants",
Environmental Science and Technology, 9(9):862-869, September 1975.
25. Five Field Performance Teats on Koppers Company Precipitators, Docket No.
OAQPS-78-l, Office Of Air Quality Planning And Standards, U. S. Environ-
mental Protection Agency, Research Triangle Park, NC, February-March 1974.
26. H. M. Rayne and L. P. Copian, Slag Tap Boiler Performance Associated with
Power Plant Flyash Disposal, Western Electric Company, Hawthorne Works,
Chicago, IL, undated.
27. A. B. Walker, "Emission Characteristics for Industrial Boilers", Air
Engineering, 9(8):l7-l9, August 1967.
28. Environmental Assessment of Coal-fired Controlled Utility Boiler, EPA-600/
7-80-086, !J. S. Environmental Protection Agency, Washington, DC, April
1980.
29. Steam, 37th Edition, Babcock and Wilcox, New York, 1963.
External Combustion Sources 1.1-15
138
-------
30. Industrial Boiler: Emission Test Report, Formica Corporation, Cincinnati,
Ohio, EMB-80-IBR-7, U. S. Environmental Protection Agency, Research Triangle
Park, NC, October 1980.
31. Field Tests of Industrial Stoker Coal-fired Boilers for Emissions Control
and Efficiency Improvement - Site A, EPA-600/7-78-135a, U. S. Environ-
mental Protection Agency, Washington, DC, July 1978.
32. ibidem-Slte C, EPA-600/7-79-130a, May 1979.
33.
ibidem-Site
E,
EPA-600/7-80-064a,
March 1980.
34.
ibidera-Si te
F,
EPA-600/7-80-065a,
March 1980.
35.
ibidem-Site
G,
EPA-600/7-80-082a,
April 1980.
36.
ibidem-Si te
B,
EPA-600/7-79-04 la,
February 1979.
37. Industrial Boilers: Emission Test Report, General Motors Corporation,
Parma, Ohio, Volume I, EMB-80-I8R-4, TJ. S. Environmental Protection Agency,
Research Triangle Park, NC, March 1980.
38. A Field Test Using Coal: dRDF Blends in Spreader Stoker-fired Boilers,
EPA-600/2-80-095, U. S. Environmental Protection Agency, Cincinnati, OH,
August 1980.
39. Industrial Boilers: Emission Test Report, Rickenbacker Air Force Base,
Columbus, Ohio, EMB-80-IBR-6, IJ. S. Environmental Protection Agency,
Research Triangle Park, NC, March 1980.
40. Thirty-day Field Tests of Industrial Boilers: Site 1, EPA-600/7-80-085a,
U. S. Environmental Protection Agency, Washington, DC, April 1980.
41. Field Tests of Industrial Stoker Coal-fired Boilers for Emissions Control
and Efficiency Improvement - Site D, EPA-600/7-79-237a, IJ. S. Environmental
Protection Agency, Washington, DC, November 1979.
42. lbldem-Site H, EPA-600/7-80-112a, May 1980.
43.
ibidem-Si te
I,
EPA-600/7-80-136a, May
1980.
44.
ibidem-Si te
J,
EPA-600/7-80-137a, May
1980.
45.
ibidem-Si te
K,
EPA-600/7-80-138a, May
1980.
46. Regional Air Pollution Study: Point Source Emission Inventory, EPA-600/4-
77-014, U. S. Environmental Protection Agency, Research Triangle Park, NC,
March 1977.
47. R. P. Hangebrauck, et al., "Emissions of Polynuclear Hydrocarbons and
Other Pollutants from Heat Generation and Incineration Process", Journal
of the Air Pollution Control Association, 14(7):267-278, July 1964.
1.1-16
EMISSION FACTORS
139
-------
49
50
51
52
53
54
55
56
57
58
59
60
61
EPA-600/2-78-004o, U. S. Environmental Protection Agency, Washington, DC,
June 1978.
Source Sampling Residential Fireplaces for Emission Factor Development,
EPA-450/3-76-010, U. S. Environmental Protection Agency, Research Triangle
Park, NC, Noveraher 1975.
Atmospheric Emissions from Coal Combustion: An Inventory Guide, 999-AP-24,
U. S. Environmental Protection Agency, Washington, DC, April 1966.
Application of Combustion Modification To Control Pollutant Emissions from
Industrial Boilers - Phase II, EPA-600/2-76-086a, U. S. Environmental
Protection Agency, Washington, DC, April 1976.
Continuous Emission Monitoring for Industrial Boiler, General Motors Cor-
poration, St. Louis, Missouri, Volume I, EPA Contract Number 68-02-2687,
GCA Corporation, Bedford, MA, June 1980.
Survey of Flue Gas Desulfurization Systems: Cholla Station, Arizona
Public Service Company, EPA-600/7-78-048a, UT S"I Envl ronmental Protection
Agency, Washington, DC, March 1978.
ibidem: La Cygne Station, Kansas City Power and Light, EPA-600/7-78-048d,
March 1978.
Source Assessment: Dry Bottom Utility Boilers Firing Pulverized Bituminous
Coal, EPA-600/2-79-019, U. S. Environmental Protection Agency, Washington,
DC, August 1980.
Thirty-day Field Tests of Industrial Boilers: Site 3 - Pulverized - Coal
Fired Boiler, EPA-600/7-80-085c, U. S. Environmental Protection Agency,
Washington, DC, April 1980.
Systematic Field Study of Nitrogen Oxide Emission Control Methods for
Utility Boilers, APTD-1163, U. S. Environmental Protection Agency, Research
Triangle Park, NC, December 1971.
Emissions of Reactive Volatile Organic Compounds from Utility Boilers,
EPA-600/7-80-111, U. S. Environmental Protection Agency, Washington, DC,
May 1980.
Industrial Boilers: Emission Test Report, DuPont Corporation, Parkers-
burg, West Virginia, EMB-80-IBR-12, U. S. Environmental Protection Agency,
Research Triangle Park, NC, February 1982.
Technology Assessment Report for Industrial Boiler Applications: NOy
Combustion Modification, EPA-6QO/7-79-178f, U. S. Environmental Protection
Agency, Washington, DC, December 1979.
Inhalable Particulate Source Category Report for External Combustion
Sources, EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View,
CA, January 1985.
External Combustion Sources
140
1.1-17
-------
1.2 ANTHRACITE COAL COMBUSTION
1.2.1 General
AnChracite coal is a high rank coal with more fixed carbon and less vola-
tile matter than either bituminous coal or lignite, and it has higher ignition
and ash fusion temperatures. Because of its low volatile matter content and
slight clinkering, anthracite is most commonly fired in medium sized traveling
grate stokers and small hand fired units. Some anthracite (occasionally with
petroleum coke) is used in pulverized coal fired boilers. It is also blended
with bituminous coal. None is fired in spreader stokers. For its low sulfur
content (typically less than 0.8 weight percent) and minimal smoking tendencies,
anthracite is considered a desirable fuel where readily available.
In the United States, all anthracite is mined in northeastern Pennsylvania
and is consumed mostly in Pennsylvania and several surrounding states. The
largest use of anthracite is for space heating. Lesser amounts are employed
for steam/electric production; coke manufacturing, sintering and pelletizing;
and other industrial uses. Anthracite currently is only a small fraction of
the total quantity of coal combusted in the United States.
1.2.2 Emissions And Controls2~14
Particulate emissions from anthracite combustion are a function of furnace
firing configuration, firing practices (boiler load, quantity and location of
underfire air, sootblowing, flyash reinjection, etc.), and the ash content of
the coal. Pulverized coal fired boilers emit the highest quantity of partic-
ulate per unit of fuel because they fire the anthracite in suspension, which
results In a high percentage of ash carryover into exhaust gases. Pulverized
anthracite fired boilers operate in the dry tap or dry bottom mode, because of
anthracite's characteristically high ash fusion temperature. Traveling grate
stokers and hand fired units produce much less particulate per unit of fuel
fired, because combustion takes place in a quiescent fuel bed without signifi-
cant ash carryover Into the exhaust gases. In general, particulate emissions
from traveling grate stokers will increase during sootblowing and flyash rein-
jection and with higher fuel bed underfeed air from forced draft fans. Smoking
is rarely a problem, because of anthracite's low volatile matter content.
Limited data are available on the emission of gaseous pollutants from
anthracite combustion. It is assumed from bituminous coal combustion data that
a large fraction of the fuel sulfur is emitted as sulfur oxides. Also, because
combustion equipment, excess air rates, combustion temperatures, etc., are
similar between anthracite and bituminous coal combustion, nitrogen oxide and
carbon monoxide emissions are assumed to be similar, too. Volatile organic
compound (VOC) emissions, however, are expected to be considerably lower,
since the volatile matter content of anthracite is significantly less than that
of bituminous coal.
External Combustion Sources
141
1.2-1
-------
Table 1.2-1. UNCONTROLLED EMISSION FACTORS FOR ANTHRACITE COMBUSTION3
m
f-H
CA
LTj
I—I
o
4> Z
fs?
>
n
H
o
c/i
Boiler type
Particulate^
Sulfur
oxldesc
Nitrogen oxides''
Carbon monoxidee
Volatile organics
Noxunethane
Methane
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
Pulverized coal fired
f
f
19.5S
39 S
9
IB
f
f
f
f
Traveling grate
stoker
4 .68
9.IK
19.5S
39 S
5
10
0.3
0.6
f
f
Hand fed units
5h
10h
19.5S
39 S
1.5
3
f
f
f
f
aFactors are for uncontrolled emissions and should he applied to coal cousuraption as fired.
''Based on EPA Method 5 (t ront half catch).
cA8sumes, as with bituminous coal combustion, most fuel sulfur Is emitted as S0X. Limited data In Reference 5
verify this for pulverized anthracite fired boilers. Emissions are mostly SO2, with 1-3% SO3. S indicates that
weight X sulfur should be multiplied by the value given.
^For pulverized anthracite fired hollers and hand fed units, assumed to be similar to bituminous coal combustion. For
traveling grate stokers, see References 8, 11.
eMay increase by several orders of magnitude with boilers not properly operated or maintained. For traveling grate
stokers, based on limited information in Reference 8. For pulverized coal fired boilers, substantiated by additional
data in Reference 14.
fFac tors in Table 1.1-1 may be used, based on similarity of anthracite and bituminous coal.
SReferences 12-13, 15-18. Accounts for limited fallout that may occur in fallout chambers and stack, breeching. Factors
for individual boilers may be 2.5 - 25 kg/Mg (5 - 50 lb/ton), highest during soot blowing.
hRef erenee 2,
-------
Controls on anthracite emissions mainly have been applied to particulate
matter. The most efficient particulate controls, fabric filters, scrubbers and
electrostatic precipitators, have been installed on large pulverized anthracite
fired boilers. Fabric filters and venturi scrubbers can effect collection
efficiencies exceeding 99 percent. Electrostatic precipitators typically are
only 90 to 97 percent efficient, because of the characteristic high resistivity
of low sulfur anthracite fly ash. It is reported that higher efficiencies can
be achieved using larger precipitators and flue gas conditioning. Mechanical
collectors are frequently employed upstream from these devices for large part-
icle removal.
Traveling grate stokers are often uncontrolled. Indeed, particulate
control has often been considered unnecessary, because of anthracite's low smok-
ing tendencies and of the fact that a significant fraction of large size flyash
from stokers is readily collected in flyash hoppers as well as in the breeching
and base of the stack. Cyclone collectors have been employed on traveling
grate stokers, and limited information suggests these devices may be up to 75
percent efficient on particulate. Flyash reinjection, frequently used in
traveling grate stokers to enhance fuel use efficiency, tends to increase
particulate emissions per unit of fuel combusted.
Emission factors for pollutants from anthracite coal combustion are given
in Table 1.2-1, and factor ratings in Table 1.2-2. Cumulative size distribution
data a*id size specific emission factors and ratings for particulate emissions
are in Tables 1.2-3 and 1.2-4. Uncontrolled and controlled size specific emis-
sion factors are presented in Figures 1.2-1 and 1.2-2. Size distribution data
for bituminous coal combustion may be used for uncontrolled emissions from
pulverized anthracite fired furnaces, and data for anthracite tired traveling
grate stokers may be used for hand fed units.
TABLE 1.2-2. ANTHRACITE COAL EMISSION FACTOR RATINGS
Volatile organics
Furnace Type
Particulate
Sulfur
oxides
Nitrogen
oxides
Carbon
monoxide
Nonmethane
Methane
Pulverized coal
B
B
B
B
C
C
Traveling grate
stoker
B
B
B
B
c
C
Hand fed units
B
B
B
B
D
D
External Combustion Sources
143
1.2-3
-------
TABLE 1.2-3. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
EMISSION FACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED
ANTHRACITE COAL3
EMISSION FACTOR RATING: D
Cumulative emission Cartorc
Cuaulative aase X < 9tale<
• tie
|fcg'*g (lb/ton) bark, as fired)
Particle aiseb
Uncontrolled
Cont rolled
L'ncont rol led
Control led^
Si 0 - 5A
~ v.iA
0.2A
0
Sagicuse
P.j 11' p 1 e
cyclone
Lncort'c led
3A
9A ~-
8A §
;A '= ?
«, u
ok 1.-
5A
:c 1A
I
. 0.2A
, 0 1A
4 o 1C
:1c ai 3 cter i,ii;
23
J I i i i
40
LL J
1
C.O.jA
C.0C5A
3 0C3A
— j. jC'A
C. OCtA E
Qj S.
C.0C5A a J
¦— m
o c
C.C04A i «
a x
C.C33A * 2"
C J02A 1
c.:-o;» *
Figure 1.2-1.
Cuaulative size specific emission factors for dry bottom
boilers burning pulverized anthracite coal.
EMISSION FACTORS
144
-------
TABLE 1.2-4. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
EMISSION FACTORS FOR TRAVELING GRATE STOKERS BURNING ANTHRACITE COAL^
EMISSION FACTOR RATING: E
Particle sizeb
Cumulative
£ stated
mass %
size
Cumulative emission
[kg/Mg (lb/ton) coal,
factor
as fired]
(um)
Uncontrolled0
Controlled
15
64
2.9
(5.8)
10
52
2.4
(4.8)
6
42
1.9
(3.8)
2.5
27
1.2
(2.4)
1.25
24
1.1
(2.2)
1.00
23
1.1
(2.2)
0.625
d
d
TOTAL
100
4.6
(9.2)
^Expressed as aerodynamic equivalent diameter.
cMay also be used for uncontrolled hand fired units.
^Insufficient data.
Figure 1.2-2. Cumulative size specific emission factors for traveling
grate stokers burning anthracite coal.
10/86
External Combustion Sources
145
1.2-5
-------
References for Section 1.2
1. Minerals Yearbook, 1978-79, Bureau of Mines, U. S. Department of the
Interior, Washington, DC, 1981.
2. Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection
Agency, Research Triangle Park, NC, April 1970.
3. Steam, 38th Edition, Babcock and Wilcox, New York, NY, 1975.
4. Fossil Fuel Fired Industrial Boilers - Background Information for Proposed
Standards, Draft, Office Of Air Quality Planning And Standards, U. S.
Environmental Protection Agency, Research Triangle Park, NC, June 1980.
5. R. W. Cass and R. W. Bradway, Fractional Efficiency of a Utility Boiler
Baghouse: Sunbury Steam Electric Station, EPA-600/2-76-077a, U. S.
Environmental Protection Agency, Washington, DC, March 1976.
6. R. P. Janaso, "Baghouse Dust Collectors on a Low Sulfur Coal Fired Utility
Boiler", Presented at the 67th Annual Meeting of the Air Pollution Control
Association, Denver, CO, .June 1974.
7. J. R. Phelan, et al., Design and Operation Experience with Baghouse Dust
Collectors for Pulverized Coal Fired Utility Boilers - Sunbury Station,
Hoitwood Station, Proceedings of the American Power Conference, Denver,
CO, 1976.
8. Source Test Data on Anthracite Fired Traveling Grate Stokers, Office Of
Air Quality Planning And Standards, U. S. Environmental Protection Agency,
Research Triangle Park, NC, 1975.
9. Source and Emissions information on Anthracite Fired Traveling Grate
Stokers, Office Of Air Quality Planning And Standards, U. S. Environmental
Protection Agency, Research Triangle Park, NC, 1975.
10. R. J. Milligan, et al., Review of NOy Emission Factors for Stationary
Fossil Fuel Combustion Sources, EPA-450/4-79-021, U. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1979.
11. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume IV: Commercial/Institutional Combustion
Sources, EPA Contract No. 68-02-2197, GCA Corporation, Bedford, MA, October
1980.
12. Source Sampling of Anthracite Coal Fired Boilers, RCA-Electronlc Com-
ponents, Lancaster, Pennsylvania, Final Report, Scott Environmental
Technology, Inc., PI urnsteadvi11e, PA, April 1975.
13. Source Sampling of Anthracite Coal Fired Boilers, Shlppensburg State
College, Shlppensburg, Pennsylvania, Final Report, Scott Environmental
Technology, Inc., Plumsteadville, PA, May 1975.
1.2-6
EMISSION FACTORS
146
-------
14. W. Bartok, et al., Systematic Field Study of NQy Emission Control Methods
for Utility Boilers, APTD-1163, U. S. Environmental Protection Agency,
Research Triangle Park, NC, December 1971.
15. Source Sampling of Anthracite Coal Fired Boilers, Ashland State General
Hospital, Ashland, Pennsylvania, Final Report, Pennsylvania Department of
Environmental Resources, Harrisburg, PA, March 16, 1977.
16. Source Sampling of Anthracite Coal Fired Boilers, Norristown State Hospi-
tal, Norristown, Pennsylvania, Final Report, Pennsylvania Department of
Environmental Resources, Harrisburg, PA, January 19, 1980.
17. Source Sampling of Anthracite Coal Fired Boilers, Pennhurst Center, Spring
City, Pennsylvania, Final Report, TRC Environmental Consultants, Inc.,
Wethersfield, CT, January 23, 1980.
18. Source Sampling of Anthracite Coal Fired Boilers, West Chester State, West
Chester, Pennsylvania, Final Report, Roy Weston, Inc., West Chester, PA,
April 4, 1977.
19. Inhalable Particulate Source Category Report for External Combustion
Sources, EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View,
CA, January 1985.
External Combustion Sources
147
1.2-7
-------
1.3 FUEL OIL COMBUSTION
1.3.1 General1~2,22
Fuel oils are broadly classified Into two major types, distillate and
residual. Distillate oils (fuel oil grade Nos. 1 and 2) are used mainly in
domestic and small commercial applications in which easy fuel burning is
required. Distillates are more volatile and less viscous that residual oils,
having negligible ash and nitrogen contents and usually containing less than
0.3 weight percent sulfur. Residual oils (grade Nos. 4, 5 and 6), on the other
hand, are used mainly in utility, industrial and large commercial applications
with sophisticated combustion equipment. No. 4 oil is sometimes classified as
a distillate, and No. 6 is sometimes referred to as Bunker C. Being more vis-
cous and less volatile than distillate oils, the heavier residual oils (Nos. 5
and 6) must be heated to facilitate handling and proper atoraization. Because
residual oils are produced from the residue after lighter fractions (gasoline,
kerosene and distillate oils) have been removed from the crude oil, they contain
significant quantities of ash, nitrogen and sulfur. Properties of typical fuel
oils can be found in Appendix A.
1.3.2 Emissions
Emissions from fuel oil combustion depend on the grade and composition of
the fuel, the type and size of the boiler, the firing and loading practices
used, and the level of equipment maintenance. Table 1.3-1 presents emission
factors for fuel oil combustion pollutants, and Tables 1.3-2 through 1.3-5 pre-
sent cumulative size distribution data and size specific emission factors for
particulate emissions from fuel oil combustion. Uncontrolled and controlled
size specific emission factors are presented in Figures 1.3-1 through 1.3-4.
Distillate and residual oil categories are given separately, because their
combustion produces significantly different particulate, SO2 and NQ^ emissions.
Particulate Matter^-?*12-13,24,26-27 _ particulate emissions depend most on
the grade of fuel fired. The lighter distillate oils result in particulate
formation significantly lower than with heavier residual oils. Among residual
oils, Nos. 4 and 5 usually produce less particulate than does the heavier No. 6.
In boilers firing No. 6, particulate emissions can be described, on the
average, as a function of the sulfur content of the oil. As shown in Table
1.3-1), particulate emissions can be reduced considerably when low
sulfur No. 6 oil is fired. This is because low sulfur No. 6, either refined
from naturally low sulfur crude oil or desulfurized by one of several current
processes, exhibits substantially lower viscosity and reduced asphaltene, ash
and sulfur, which results in better atoraization and cleaner combustion.
Boiler load can also affect particulate emissions in units firing No. 6
oil. At low load conditions, particulate emissions may be lowered 30 to 40
percent from utility boilers and by as much as 60 percent from small industrial
and commercial units. No significant particulate reductions have been noted at
External Combustion Sources
148
1.3-1
-------
TABLE 1.3-1, UNCONTROLLED EMISSION FACTORS FOR FUEL OIL COMBUSTION
EMISSION FACTOR RATINC: A
I
-O
\£j
m
2
M
cn
en
r**
C
Z
>
n
H
c
C/5
Partlrulate
Miller
Sulfur ftioxide
Sulfur
Trioxtde
Carbon
Monoxide
Nitrogen Oxide
Volatile Organlcs
Ho ruse thane Hethane
Boiler Type
kg/l03| Ih/loV' kg/«05l lb/IOJg«l kg/IO3! lb/103gal kg/IO3! lb/IO^al kg/103l lb/103gal kg/103| Ib/I03gal hg/103! Ib/loVl
lit 11 I ty BolIrrs
Ke*idual Oil
S
8
19S
I57S
0.3*Sh
2.9Sh
0.6
5
8.0
{I2.6X5)1
67
(105X42)
0.09
0.76
0.01
0.28
Indti.s ( r 1106 x 10^ J/hr (>100 x 10^ 8c«/ltr)
Industrial hollers: 10.6 x 10* to 106 i I09 J/hr (ID x 10* to 100 x IU6 Btu/hr)
< .nwm-rf i.il boilers: 0.5 * i 0H to 10.6 x 109 J/hr <0.5 x I0fr to 10 x I0b Btu/hr)
Ri*f. ideni I a \ furnaces: <0.5 x M)9 J/hr (<0.5 x 10^ Btu/hr)
bBeJ vinues W and 24-25. Particulate utter in defined In thin section aa that Material collected by EPA Nethod 5 (front half cratch).
1-5. S Indlr.itoft that rlu* weight Z of sulfur In the oil should he Multiplied by Lhe value given.
H.t.rcncPs )-5 and 8-10. Carbon Monoxldr etrlfi-. lonn may Increase by factors of 10 to 100 If the unit is improperly operated or not well maintained.
eKxprc*ih«d hk N0a. References 1-5, 8-11, IJ and 2b. Test result* indicate that at least 951 by weight of NO* is NO for ail boiler types except residential
jfuiiidti's, where about J5X la HO.
Kvltren. ch ttt-2l, Volatile organic compound enU^ioA8 .ire generally negligible unlet** boiler la improperly operated or not well Maintained, in which cane
emissions may Increase by several tirdrra ot lanpn 11 ode .
^K>ri jfuJjUt! asistfion factors for residual oil eoabustlon are, on average, a function of fuel oil grade and sulfur content:
Or .trie f> oil; l.25(S) * Q. 38 kg/lfl' liter f 10 oil: 1.25 kg/101 liter <10 lh/l0s gal)
*;r»»de i* nil: 0.8« kg/10* Uter 15X) excess air. Several combustion aodifications can be eaployed for HO* reduction; (t)
limited excess air can reduce N0„ emissions 5-20X, (2) staged co»busllon 20-401, (3) using low NO* burnera 20-50X, and (4) aaonlfl injection can reduce NOx
ealKHlonH <.0-/01 but may increuse emissions of aomonis. Combinations of theae sodifIcations have been employed for further reductions in certain boilers.
See Referent** 21 for a discussion of theae and other NO* reducing techniques and thefr operational and environmental Inpacts.
accurately by the empirical relationship:
HOa/10* liters • 2.75 ~ 50(N)a (lb NOj/lU^itl - 22 ~ 4t>0(H)a| where M Is the weight X of nitrogen in the oil. For residual oils having high
(X). 5 weight X> nitrogen content, age 15 kg N0,/l0* liter (l?0 lb NOj/lO'gsl) as an e«iS8ian factor.
-------
low loads from boilers firing any of Che lighter grades, however. At too low a
load condition, proper combustion conditions cannot be maintained, and partic-
ulate emissions may increase drastically. It should be noted, in this regard,
that any condition that prevents proper boiler operation can result in excessive
particulate formation.
i_c o c 07
Sulfur Oxides - Total S0X emissions are almost entirely dependent
on the sulfur content of the fuel and are not affected by boiler size, burner
design, or grade of fuel being fired. On the average, more than 95 percent of
the fuel sulfur is emitted as SO2, about 1 to 5 percent as SO3 and about 1 to 3
percent as sulfate particulate. SO3 readily reacts with water vapor (in both
air and flue gases) to form a sulfuric acid mist.
Nitrogen Oxides 1-11 >17»23,27 _ raechanisras form N0X, oxidation of
fuelbound nitrogen and thermal fixation of the nitrogen In combustion air.
Fuel NO^ is primarily a function of the nitrogen content of the fuel and the
available oxygen. On average, about 45 percent of the fuel nitrogen is con-
verted to N0X, but this may vary from 20 to 70 percent. Thermal N0X, rather,
is largely a function of peak flame temperature and available oxygen, factors
which depend on boiler size, firing configuration and operating practices.
Fuel nitrogen conversion is the more Important NOx forming mechanism in
residual oil boilers. Except in certain large units having unusually high peak
flame temperatures, or in units firing a low nitrogen residual oil, fuel
will generally account for over 50 percent of the total N0X generated. Thermal
fixation, on the other hand, is the dominant N0X forming mechanism in units
firing distillate oils, primarily because of the negligible nitrogen content in
these lighter oils. Because distillate oil fired boilers usually have low heat
release rates, however, the quantity of thermal N0X formed in them is less than
that of larger units.
A number of variables influence how much NOx f°™ed by these two
mechanisms. One important variable is firing configuration. Nitrogen oxide
emissions from tangentially (corner) fired boilers are, on the average, less
than those of horizontally opposed units. Also Important are the firing prac-
tices employed during boiler operation. Limited excess air firing, flue gas
recirculation, staged combustion, or some combination thereof may result in N0X
reductions of 5 to 60 percent. See Section 1,4 for a discussion of these
techniques. Load reduction can likewise decrease NOx production. Nitrogen
oxide emissions may be reduced from 0.5 to 1 percent for each percentage
reduction in load from full load operation. It should be noted that most of
these variables, with the exception of excess air, infuence the N0X emissions
only of large oil fired boilers. Limited excess air firing is possible in many
small boilers, but the resulting NO^ reductions are not nearly so significant.
Other Pollutantsl8-21 - As a rule, only minor amounts of volatile organic
compounds (V0C) and carbon monoxide will be emitted from the combustion of fuel
oil. The rate at which VOCs are emitted depends on combustion efficiency.
Emissions of trace elements from oil fired boilers are relative to the trace
element concentrations of the oil.
External Combustion Sources
150
1.3-3
-------
TABLE 1.3-2.
CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR UTILITY BOILERS FIRING RESIDUAL OIL3
EMISSION FACTOR RATING: C (uncontrolled)
E (ESP controlled)
D (scrubber controlled)
.
Cumulative nass Z < stated size
Cu.milatlve eraia3ion factor1- |_fcg/I©3 1 (lb/10^ gal}]
Particle alzeb
(urn)
I'ncontrol led
Cont rolled
Uncontrolled
Control led*1
ESP
Scrubber
ESP
Scrubber
15
80
75
100
O.HOA (6.7A)
0.0060A (0.05A)
0.06A (0.50A)
10
7i
63
I DO
0.7U (5.9A)
0.0050A (0.042A)
O.ObA (0.50A)
6
53
52
100
0.58A (4.8A)
0.0042A (0.035A)
0.06A O.50A)
2.5
52
41
97
0.52A (4.3A)
0.U033A (0.028A)
0.058A (0.48A)
1.25
*3
31
91
0-43A C3.6A)
0.0025A (0.021A)
0.055A C0.46A)
1.00
39
26
84
0.39A (3.3A)
0.0022A (0.018A)
0.050A (0.42A)
0.625
20
10
6 k
Q.20A (1.7A)
0.0008A (0.007A)
0.038A (0.32A)
TOTAL
100
100
100
1A (8.3A)
C.008A (n.[)67A)
0.06A (0.50A)
aReference 29. ESP - electrostatic precipitator.
^Expressed as aerodynamic equivalent diameter.
Particulate emission factors for resldjal oil coobustlon without emission controls are, on average, a function
of fuel oil grade are! sulfur content:
Grade b Oil; A - 1.2MS) + 0.38
Where S la the weight X of autfur In the oil
Grade 5 Oil: A - i .25
Grade i Oil: A - 0.88
^Estimated control efficiency for scrubber, 94X; ESP, 99.21.
l.OA
0.9A
0.8A
l.
o
u
0.7ft
*¥-
c
o
0.6A
vt —
0.5A
«)
73 i
o»
0.4A
o
V.
0.3A
c
o
u
e
3.2A
3
C.1A
0
-
r i
-
-
Incgntro'led
-
-
S ^-Scrubber
-
-
-
1
1 I I I M I I
1 1 1 1 l 111 1 ill
lill
.1
0.1QA
0.09A 3
o
*
0.O8A c
0
0.07ft S
1
0.06A Tj-
0.05A p~
h O
0.04A g
u
0.03A |
3
0.C2A 5
0.C1A
0
0.01A
Q.006A
0.C04A
0-002A
0.001A
3-GD06A
i 2
0.0304ft o
0.0C02A £
C.0001A
1 2 4 6 10
Particle dia-eter (jin)
20
40 60 100
Figure 1.3-1.
1.3-4
Cumulative size specific emission factors for utility
boilers firing residual oil.
EMISSION FACTORS
151
10/86
-------
TABLE 1.3-3. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR INDUSTRIAL BOILERS FIRING RESIDUAL OIL3
EMISSION FACTOR RATING: D (uncontrolled)
E (multiple cyclone controlled)
Particle size'*
Cumulative mass
Z < stated size
Cumulative emission faceorc
kg/103 1 (lb/103 gal)
(ura)
Uncontrol 1 ed
Multiple cyclone
controlled
Uncontrolled
Multiple cyclone
controlled® j
1
15
91
100
0.91A (7.59A)
0.20A (1.67A)
10
86
95
0.86A (7.17A)
0.19A (1.58A)
6
77
72
0.77A (6.42A)
0.14A (1.17a)
2.5
56
22
0.56A (4.67A)
0.0AA (0.33A)
1.25
39
21
0.39A (3.25A)
0.04A (0.33A)
1.00
36
21
0.36A (3.00A)
0.04A (0.33A)
0.625
30
d
0.30A (2.50A)
d
TOTAL
100
100
1A (8.34A)
0.2A (1.67A)
"Expressed as aerodynamic equivalent diameter.
particulate emission factors for residual oil combustion without emission controls are, on
average, a function of fuel oil grade and sulfur content;
Grade 6 Oil: A » l.25(S) ~ 0.38
Where S is the weight 7, of sulfur In the oil
Grade 5 Oil: A =» 1.25
Grade 4 Oil: A - 0.88
''insufficient data.
eEatiaated control efficiency for multiple cyclone, 801.
I OA
0.9A
Q.&A
0.7A
0.6A
0.5A
0.4A
0.3A
Q.2A
0.1A
OA
O.cOV
-
—
0. ISA
-
Incontrolled
-
0.16A
-
-
0.14A
_
/ Vmul tipli
0.12A
/ eye 1 one
-
-
0.1QA
-
-
0.08A
-
-
0.06A
-
-
0.04A
-
-
0.02A
i
i i i i i i I 1 . i i
i i i i i t i i
i i i i l i
OA
.1
= £
.4 .6 1 2 4 6 10
Particle dialer („m)
20
40 60 100
Figure 1.3-2. Cumulative size specific emission factors for Industrial
boilers firing residual oil.
10/86
External Combustion Sources
1.3-5
152
-------
TABLE 1.3-4. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR UNCONTROLLED INDUSTRIAL BOILERS FIRING DISTILLATE OILa
EMISSION FACTOR RATING: E
Cumulative aaaa Z
Cumulative emission factor
< stated size
kg/103 1 (lb/lO* gal)
Particle size''
(urn)
Uncontrolled
Uncontrolled
15
68
0.16 (1.33)
10
50
0.12 (1.00)
6
30
0.07 (0.58)
2.5
12
0.03 (0.25)
1.25
9
0.02 (0.17)
1.00
8
0.02 (0.17)
0.625
2
0.005 (0.04)
TOTAL
100
0.24 (2.00)
aReference 29.
^Expressed as aerodynamic equivalent diameter.
0.25
0.20
0.15
o
o.io
0.05
1
2
4
2
6 10
4
20
40 60 100
tj
Particle diameter (ur:)
Figure 1.3-3. Cumulative size specific emission factors for uncontrolled
industrial boilers firing distillate oil.
1.3-6
EMISSION FACTORS
153
10/86
-------
TABLE 1.3-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR UNCONTROLLED COMMERCIAL BOILERS BURNING RESIDUAL
AND DISTILLATE OIL3
EMISSION FACTOR RATING: D
Cumulative mass X < stated size
Cumulative emission factor
kg/103 1 (lb/103 gal)
Particle size''
(ura)
Uncontrolled with
residual oil
Uncontrolled with
distillate oilc
Uncontrolled with
residual oil
Uncontrolled with
distillate oil
15
78
60
0.78A (6.50A)
0.14 (1.17)
10
62
>5
0.62A (5.17A)
0.13 (1.08)
6
44
49
0.44A (3.67A)
0.12 (1.00)
2.5
23
42
0.23A (1.92A)
0.10 (0.83)
1.25
16
38
0.16A (1.33A)
0.09 (0.75)
1.00
14
17
0.14A (1.17A)
0.09 (0.75)
0.625
13
35
0.13A (1.08A)
0.08 (0.67)
TOTAL
100
100
1A (8.34A)
0.24 (2.00)
^Reference 29.
bE* pressed as aerodynamic equivalent diameter.
particulate emission factors far residual oil combustion without emission controls are, on average,
a function of fuel oil grade and sulfur content:
Grade 6 Oil: A - 1.25 (S) + 0.38
Where S Is the weight Z of sulfur In the oil
Grade 5 Oil: A - 1.25
Crade 4 Oil: A » 0.88
1 - 0C)A
C.90A
C. SOA
C 7OA
C.63A
0. 5CA
C. AC A
C. 3CA
G.2CA
0. Iji.
j
Disii 1 U;e c 1
Residjcl oi:
"1 C. 25
1C'"Q '5
T
0. lb
10.10 «
0.C:
I I
_J I L.
LI 1
_l_L
2 £ £ 10 20 6'j IOC
Particle diameter (pp)
Figure 1.3-4,
Cumulative size specific emission factors for uncontrolled
commercial boilers burning residual and distillate oil.
10/86
External Combustion Sources
1.3-7
154
-------
Organic compounds present in the flue gas streams of boilers include
aliphatic and aromatic hydrocarbons, esters, ethers, alcohols, carbonyls,
carboxylic acids and polycylic organic matter. The last Includes all organic
matter having two or more benzene rings.
Trace elements are also emitted from the combustion of fuel oil. The
quantity of trace elements 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 separation of emissions Into bottom ash and fly ash.
If a boiler unit is operated Improperly or is poorly maintained, the
concentrations of carbon monoxide and VOCs may increase by several orders of
magni tude.
1.3.3 Controls
The various control devices and/or techniques employed on oil fired
boilers depend on the type of boiler and the pollutant being controlled. All
such controls may be classified into three categories, boiler modification,
fuel substitution and flue gas cleaning.
Boiler Modification 1-4,8-9,13-14,23_ Boiler modification includes any
physical change In the boiler apparatus Itself or in its operation. Maintenance
of the burner system, for example, is important to assure proper atomization
and subsequent minimization of any unburned combustibles. Periodic tuning is
important in small units for maximum operating efficiency and emission control,
particularly of smoke and CO. Combustion modifications, such as limited excess
air firing, flue gas recirculation, staged combustion and reduced load opera-
tion, result in lowered NOx emissions in large facilities. See Table 1.3-1 for
specific reductions possible through these combustion modifications.
Fuel Substitution^'^,12,28_ Fuel substitution, the firing of "cleaner" fuel
oils, can substantially reduce emissions of a number of pollutants. Lower
sulfur oils, for instance, will reduce S0X emissions in all boilers, regardless
of size or type of unit or grade of oil fired. Particulates generally will be
reduced when a lighter grade of oil is fired. Nitrogen oxide emissions will be
reduced by switching to either a distillate oil or a residual oil with less
nitrogen. The practice of fuel substitution, however, may be limited by the
ability of a given operation to fire a better grade of oil and by the cost and
availability thereof.
Flue Gas CIeaning!5-lft,28 _ yiUe gas cleaning equipment generally is
employed only on large oil fired boilers. Mechanical collectors, a prevalent
type of control device, are primarily useful in controlling particulates gen-
erated during soot blowing, during upset conditions, or when a very dirty heavy
oil is fired. During these situations, high efficiency cyclonic collectors can
effect up to 85 percent control of particulate. Under normal firing conditions,
or when a clean oil is combusted, cyclonic collectors will not be nearly so
effective because of the high percentage of small particles (less than 3 micro-
meters diameter) emitted.
1.3-8
EMISSION FACTORS
155
-------
Electrostatic precipitators are commonly used in oil fired power plants.
Older precipitators, usually small, remove generally 40 to 60 percent of the
particulate matter. Because of the low ash content of the oil, greater
collection efficiency may not be required. Today, new or rebuilt electrostatic
precipitators have collection efficiencies of up to 90 percent.
Scrubbing systems have been installed on oil fired boilers, especially of
late, to control both sulfur oxides and particulate. These systems can achieve
SO2 removal efficiencies of 90 to 95 percent and particulate control
efficiencies of 50 to 60 percent.
References for Section 1.3
1. W. S. Smith, Atmospheric Emissions from Fuel Oil Combustion; An Inventory
Guide, 999-AP-2, U. S. Environmental Protection Agency, Washington, DC,
Nov emb e r 1962.
2. J. A. Danielson (ed.), Air Pollution Engineering Manual, Second Edition,
AP-40, U. S. Environmental Protection Agency, Research Triangle Park, NC,
1973. Out of Print.
3. A. Levy, et al., A Field Investigation of Emissions from Fuel Oil Combus-
tion for Space Heating, API Bulletin 4099, Battelle Columbus Laboratories,
Columbia, OH, November 1971.
4. R. E. Barrett, et al., Field Investigation of Emissions from Combustion
Equipment for Space Heating, EPA-R2-73-084a, U. S. Environmental Protec-
tion Agency, Research Triangle Park, NC, June 1973.
5. G. A. Cato, et al., Field Testing: Application of Combustion Modifications
To Control Pollutant Emissions from Industrial Boilers - Phase I, EPA-650/
2-74-078a, U. S. Environmental Protection Agency, Washington, DC, October
1974.
6. G. A. Cato, et al~, Field Testing: Application of Combustion Modifications
To Control Pollutant Emissions from Industrial Boilers - Phase II, EPA-600/
2-76-086a, U. S. Environmental Protection Agency, Washington, DC, April
1976.
7. Particulate Emission Control Systems for Oil Fired Boilers, EPA-450/3-74-
063, U. S. Environmental Protection Agency, Research Triangle Park, NC,
December 1974.
8. W. Bartok, et al., Systematic Field Study of hOy Emission Control Methods
for Utility Boilers, APTD-1163, U. S. Environmental Protection Agency,
Research Triangle Park, NC, December 1971.
9. A. R. Crawford, et al., Field Testing: Application of Combustion Modi-
fications To Control NOy Emissions from Utility Boilers, EPA-650/2-74-066,
U. S. Environmental Protection Agency, Washington, DC, June 1974.
External Combustion Sources
156
1.3-9
-------
10. J. F. Deffner, et al., Evaluation of Gulf Econojet Equipment with Respect
to Air Conservation, Report No. 731RC044, Gulf Research and Development
Company, Pittsburgh, PA, December 18, 1972.
11. C. E. Blakeslee and H. E. Burbach, "Controlling NOx Emissions from Steam
Generators", Journal of the Air Pollution Control Association, 23: 37-42,
January 1973.
12. C. W. Siegmund, "Will Desulfurized Fuel Oils Help?", American Society of
Heating, Refrigerating and Air Conditioning Engineers Journal, 11:29-33,
April 1969.
13. F. A. Govan, et al., "Relationships of Particulate Emissions Versus
Partial to Full Load Operations tor Utility-sized Boilers", Proceedi ngs
of Third Annual Industrial Air Pollution Control Conference, Knoxville,
TN, March 29-30, 1973.
14. R. E. Hall, et al., A Study of Air Pollutant Emissions from Residential
Heating Systems, EPA-650/2-74-003, U. S. Environmental Protection Agency,
Washington, DC, January 1974.
15. Flue Gas Desulfurization: Installations and Operations, PB 257721,
National Technical Information Service, Springfield, VA, September 1974.
16. Proceedings: Flue Gas Desulfurization Symposium - 1973, EPA-650/2-73-038,
U. S. Environmental Protection Agency, Washington, DC, December 1973.
17. R. J. Milligan, et al., Review uf NOy Emission Factors for Stationary
Fossil Fuel Combustion Sources, EPA-450/4-79-02I, U. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1979.
18. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume I: Gas and Oil Fired Residential Heating
Sources, EPA-600/7-79-029b, U. S. Environmental Protection Agency,
Washington, DC, May 1979.
19. C. C. Shih, et al., Emissions Assessment of Conventional Stationary Com-
bustion Systems, Volume III: External Combustion Sources for Electricity
Generation, EPA Contract No. 68-02-2197, TRW, Inc., Redondo Beach, CA,
November 1980.
20. N. F. Suprenant, et al., Emissions Assessement of Conventional Stationary
Combustion System, Volume IV: Commercial Institutional Combustion Sources,
EPA Contract No. 63-02-2197, GCA Corporation, Bedford, MA, October 1980.
21. N. r. Suprenant, et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume V: Industrial Combustion Sources, EPA Contract
No. 68-02-2197, CCA Corporation, Bedford, MA, October 1980.
22. Fossil Fuel Fired Industrial Boilers - Background Information for Proposed
Standards (Draft EIS), Office Of Air Quality Planning And Standards, U. S.
Environmental Protection Agency, Research Triangle Park, NC, June 1980.
L.3-10
EMISSION FACTORS
157
-------
23. K. J. Lira, et al., Technology Assessment Report for Industrial Boiler
Applications: Combustion Modification, EPA-bOO/7-79-l78f, U. S.
Environmental Protection Agency, Washington, DC, December 1979.
24. Emission Test Reports, Docket No. OAQPS-78-i, Category II-I-257 through
265, Office Of Air Quality Planning And Standards, (J. S. Environmental
Protection Agency, Research Triangle Park, NC, 1972 through L974.
25. Primary Sulfate Emissions from Coal and Oil Combustion, EPA Contract No.
68-02-3138, TRW, Inc., Redondo Beach, CA, February 1980.
External Combustion Sources
158
1.3-11
-------
1.4 NATURAL GAS COMBUSTION
1.4.1 General
Natural gas Is one of the major fuels used throughout the country. It Is
used mainly for power generation, for Industrial process steam and heat produc-
tion, and for domestic and commercial space heating. The primary component of
natural gas Is methane, although varying amounts of ethane and smaller amounts
of nitrogen, helium and carbon dioxide are also present. Gas processing plants
are required for recovery of liquefiable constitutents and removal of hydrogen
sulfide (H2S) before the gas is used (see Natural Gas Processing, Section 9.2).
The average gross heating value of natural gas is approximately 9350 kilo-
calories per standard cubic meter (1050 British thermal units/standard cubic
foot), usually varying from 8900 to 9800 kcal/scm (1000 to 1100 Btu/scf).
1.4.2 Emission And Controls3~26
Even though natural gas is considered to he a relatively clean fuel, some
emissions can occur from the combustion reaction. For example, improper oper-
ating conditions, including poor mixing, insufficient air, etc., may cause
large amounts of smoke, carbon monoxide and hydrocarbons. Moreover, because a
sulfur containing mercaptan is added to natural gas to permit detection, small
amounts of sulfur oxides will also be produced in the combustion process.
Nitrogen oxides are the major pollutants of concern when burning natural
gas. Nitrogen oxide emissions are functions of combustion chamber temperature
and combustion product cooling rate. Emission levels vary considerably with
the type and size of unit and with operating conditions.
In some large boilers, several operating modifications may be used for NOj^
control. Staged combustion, for example, including off-stoichiometric firing
and/or two stage combustion, can reduce emissions by 5 to 50 percent.26 jn off-
stoichioraetric firing, also called "biased firing", some burners are operated
fuel rich, some fuel lean, and others may supply air only. In two stage combus-
tion, the burners are operated fuel rich (by introducing only 70 to 90 percent
stoichiometric air), with combustion being completed by air injected above the
flame zone through second stage "NO ports". In staged combustion, N0X emissions
are reduced because the bulk of combustion occurs under fuel rich conditions.
Other N0x reducing modifications include low excess air firing and flue
gas recirculation. In low excess air firing, excess air levels are kept as
low as possible without producing unacceptable levels of unburned combustibles
(carbon monoxide, volatile organic compounds and smoke) and/or other operating
problems. This technique can reduce N0X emissions 5 to 35 percent, primarily
because of lack of oxygen during combustion. Flue gas recirculation into the
primary combustion zone, because the flue gas is relatively cool and oxygen
deficient, can also lower NOx emissions 4 to 85 percent, depending on the
amount of gas recirculated. Flue gas reelrculatlon is best suited for new
boilers. Retrofit application would require extensive burner modifications.
External Combustion Sources
159
1.4-1
-------
I
N)
TABLE 1.4-1, UNCONTROLLED EMISSION FACTORS FOR NATURAL GAS COMBUSTION3
r*3
-H
C/3
C/3
t—<
o
H* 2;
o "1
;>
o
H
O
(/>
1 time furl ft red.
differences 11-18.
ctofer<»nce 6. Basfd no «vg. aulftir content of n«mr*l 46110 g/10^ (2000 gr/10* arf).
<-ncra 4-5. 7-8. II. I*. 18-19. 21.
*K*pre«acd as NOj. Te«t* Indicate About 95 weight Z NO <« NO*.
'dclcrenreB 4, 7-«, I*, Id, 72-25. "
8*cf oreitcea 16, |6. May lnrri»««r 10 - lOrt Hmea with Improper operation or f»al nttiuinrr.
hfor tangent lally I i r+d unlrn, one 4400 kg/IO& r»3 (2tb lh/UJh ft'). At reduced Inadn, multiply
factor by load reduction coefficient In Figure l.4-|. For potential N(\ reduction# by
ctxabuat Ion aodl f 1 cation, aee te* t. Not r that N(>n reduction f run thear «Xl 1 f I tat Ion w will
alto occur at reduced load condlttuna.
Particulate*1
Sulfur
d 1 o* 1 d ec
HltroKtMt oaldea^
Carbon monoxide*
Volatile o
rtinica
Furnace slie 4 type
(l()k Btu/hr heal lnyut)
NuiaeiliaM
Hethane
kg/IO<>ii3
lb/10^
ft^
kg/ I0*>w3
lb/106 ft3
kg/IO^m3
lb/ I0& ft"*
kg/n^B-*
lb/10* ft3
fcg/10<>m3
lb/10* ft*
kfl/lO^a3
ib/io^ it3
(Jlllfiy boilers <> 100)
16 - 00
1 -
5
9.6
0.6
aiionh
Wlh
640
40
21
1.4
4.8
0.1
Industrial hollrra (10 - 100)
16 - RO
I -
S
9,6
0.6
7740
140
S60
15
44
2.8
48
3
Domestic and rnanserrlnl
bollera (< 10)
16 - 80
1 -
5
9.6
0.6
1600
(00
170
20
S4
5.1
41
2
-------
Studies Indicate that low NOx burners (20 to 50 percent reduction) and ammonia
injection (40 to 70 percent reduction) also offer NOx emission reductions.
Combinations of the above combustion modifications may also be employed to
reduce NOx emissions further. In some boilers, for instance, NOx reductions
as high as 70 to 90 percent have been produced by employing several of these
techiques simultaneously. In general, however, because the net effect of any
of these combinations varies greatly, it is difficult to predict what the
reductions will be in individual applications.
Although not measured, all particulate has been estimated to be less
than 1 micrometer in size.27 Emission factors for natural gas combustion are
presented in Table 1.4-1, and factor ratings in Table 1.4-2.
TABLE 1.4-2. FACTOR RATINGS FOR NATURAL GAS COMBUSTION
Furnace
Sulfur
Nitrogen
Carbon
Volatile organics
type
Particulate
oxides
oxides
monoxide
Nonmethane
Methane
Utility
boiler
B
A
A
A
C
C
Industrial
boi1er
B
A
A
A
C
C
Commercial
boiler
B
A
A
A
D
D
Residential
furnace
B
A
A
A
D
D
External Combustion Sources
161
1.4-3
-------
u.
u.
o
u
3
SO
100
110
LOAD, per cent
Figure 1.4-1. Load reduction coefficient as function of boiler load.
(Used to determine NOy- reductions at reduced loads in large boilers.)
References for Section 1.4
1. D. >1. Hugh, et al., Exhaust Gases from Combustion and Industrial Processes,
EPA Contract No. EHSD 71-36, Engineering Science, Inc., Washington, DC,
October 2, 1971.
2. J. H. Perry (ed.), Chemical Engineer's Handbook, 4th Edition, McGraw-Hill,
New York, NY, 1963.
3. H, H. Hovey, et al., The Development of Air Contaminant Emission Tables
for Non-process Emissions, New York State Department of Health, Albany,
NY, 1965.
4. W. Bartok, et al., Systematic Field Study of NO., Emission Control Methods
for Utility Boilers, APTD-1163, U. S. Environmental Protection Agency,
Research Triangle Park, NC, December 1971.
1.4-4
EMISSION FACTORS
162
-------
5. F. A. Bagwell, et al., "Oxides of Nitrogen Emission Reduction Program for
Oil and Gas Fired Utility Boilers", Proceedings of the American Power Con-
ference, J_4:683-693, April 1970.
6. R. L. Chass and R. E. George, "Contain!nant Emissions from the Combustion
of Fuels", Journal of the Air Pollution Control Association, 10:34-43,
February 1980.
7. H. E. Dietzmann, A Study of Power Plant Boiler Emissions, Final Report No.
AR-837, Southwest Research Institute, San Antonio, TX, August 1972.
8. R. E. Barrett, et al., Field Investigation of Emissions from Combustion
Equipment for Space Heating, EPA-R2-73-084, IJ. S. Environmental Protection
Agency, Research Triangle Park, NC, June 1973.
9. Confidential information, American Gas Association Laboratories, Cleveland,
OH, Hay 1970.
10. Unpublished data on domestic gas fired units, U. S. Environmental Pro-
tection Agency, Cincinnati, OH, 1970.
11. C. E. Blakeslee and H. E. Burbock, "Controlling NOjj Emissions from Steam
Generators", Journal of the Air Pollution Control Association, 23: 37-42,
January 1979.
12. L. K. Jain, et al., "State of the Art" for Controlling NOy Emissions:
Part 1, Utility Boilers, EPA-Contract No. 68-02-0241, Catalytic, Inc.,
Charlotte, NC, September 1972.
13. J. W. Bradstreet and R. J. Fortman, "Status of Control Techniques for
Achieving Compliance with Air Pollution Regulations by the Electric
Utility Industry", Presented at the 3rd Annual Industrial Air Pollution
Control Conference, Knoxville, TN, March 1973.
14. Study of Emissions of NOy from Natural Gas Fired Steam Electric Power
Plants in Texas, Phase II, Volume II, Radian Corporation, Austin, TX,
May 8, 1972.
15. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume I; Gas and Oil Fired Residential Heating
Sources, EPA-600/7-79-029b, Environmental Protection Agency,
Washington, DC, May 1979.
16. C. C. Shih, et al., Emissions Assessment of Conventional Stationary Com-
bustion Systems, Volume III: External Combustion Sources for Electricity
Generation, EPA Contract No. 68-02-2197, TRW, Inc., Redondo Beach, CA,
November 1980.
17. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary
Combustion Sources, Volume IV: Commercial Institutional Combustion
Sources, EPA Contract No. 68-02-2197, GCA Corporation, Bedford, HA,
October 1980.
External Combustion Sources
163
1.4-5
-------
18. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary
Combustion Systems, Volume V: Industrial Combustion Sources, EPA Contract
No. 68-02-2197, GCA Corporation, Bedford, MA, October 1980.
19. R. J. Milllgan, et al., Review of NOy Emission Factors for Stationary
Fossil Fuel Combustion Sources, EPA-450/4-79-021, (J. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1979.
20. W. H. Thrasher and D. W. Dewerth, Evaluation of the Pollutant Emissions
from Gas Fired Water Heaters, Research Report No. 1507, American Gas
Association, Cleveland, OH, April 1977.
21. W. H. Thrasher and D. W. Dewerth, Evaluation of the Pollutant Emissions
from Gas Fired Forced Air Furnaces, Research Report No. 1503, American
Gas Association, Cleveland, OH, May 1975.
22. G. A. Cato, et al., Field Testing: Application of Combustion Modification
To Control Pollutant Emissions from Industrial Boilers, Phase 1, EPA-650/
2-74-078a, U. S. Environmental Protection Agency, Washington, DC, October
1974.
23. G. A. Cato, et al., Field Testing: Application of Combustion Modification
To Control Pollutant Emissions from Industrial Boilers, Phase II, EPA-600/
2-76-086a, U. S. Environmental Protection Agency, Washington, DC, April
1976.
24. W. A. Carter and H. J. Buening, Thirty-day Field Tests of Industrial
Boilers - Site 5, EPA Contract No. 68-02-2645, KVB Engineering, Inc.,
Irvine, CA, May 1981.
25. W. A. Carter and H. J. Buening, Thirty-day Field Tests of Industrial
Boilers - Site 6, EPA Contract No. 68-02-2645, KVB Engineering, Inc.,
Irvine, CA, May 1981.
26. K. J. Lim, et al., Technology Assessment Report for Industrial Boiler
Applications: NOy Combustion Modification, EPA Contract No. 68-02-3101,
Acurex Corporation, Mountain View, CA, December 1979.
27. H. J. Taback, et al., Fine Particle Emissions From Stationary and Miscel-
laneous Sources in the South Coast Air Basin, California Air Resources
Board Contract No. A6-191-30, KVB, Inc., Tustin, CA, February 1979.
1 .4-6
EMISSION FACTORS
164
-------
1.6 WOOD WASTE COMBUSTION IN BOILERS
1.6.1 General1-3
The burning of wood waste in boilers is mostly confined to those industries
where it is available as a byproduct. It Is burned both to obtain heat energy
and to alleviate possible solid waste disposal problems. Wood waste may include
large pieces like slabs, logs and bark strips, as well as cuttings, shavings,
pellets and sawdust, and heating values for this waste range from about 4,400
to 5,000 kilocalories per kilogram of fuel dry weight (7,940 to 9,131 Btu/lb).
However, because of typical moisture contents of 40 to 75 percent, the heating
values for many wood waste materials as actually fired are as low as 2,200 to
3,300 kilocalories per kilogram of fuel. Generally, bark is the najor type of
waste burned in pulp mills, and either a varying mixture of wood and bark waste
or wood waste alone are most frequently burned in the lumber, furniture and
plywood Industries.
1.6.2 Firing Practices1-3
Varied boiler firing configurations are used in burning wood waste. One
common type in smaller operations is the dutch oven, or extension type of
furnace with a flat grate. This unit is widely used because it can burn fuels
with very high moisture. Fuel is fed Into the oven through apertures atop a
firebox and is fired in a cone shaped pile on a flat grate. The burning is
done in two stages, drying and gasification, and combustion of gaseous products.
The first stage takes place in a cell separated from the boiler section by a
bridge wall. The combustion stage takes place in the main boiler section. The
dutch oven is not responsive to changes in steara load, and it provides poor
combustion control.
In another type, the fuel cell oven, fuel is dropped onto suspended fixed
grates and is fired in a pile. Unlike the dutch oven, the fuel cell also uses
combustion air preheating and repositioning of the secondary and tertiary air
injection ports to improve boiler efficiency.
In many large operations, more conventional boilers have been modified
to burn wood waste. These units may include spreader stokers with traveling
grates, vibrating grate stokers, etc., as well as tangentially fired or cyclone
fired boilers. The most widely used of these configurations is the spreader
stoker. Fuel is dropped in front of an air jet which casts the fuel out over
a moving grate, spreading it in an even thin blanket. The burning is done in
three stages in a single chamber, (1) drying, (2) distillation and burning of
volatile matter and (3) burning of carbon. This type of operation has a fast
response to load changes, has improved combustion control and can be operated
with multiple fuels. Natural gas or oil are often fired in spreader stoker
boilers as auxiliary fuel. This is done to maintain constant steam when the
wood waste supply fluctuates and/or to provide more steara than is possible
from the waste supply alone.
External Combustion Sources
165
1.6-1
-------
TABLE 1.6-1. EMISSION FACTORS FOR WOOD AND BARK COMBUSTION IN BOILERS
Pollutant/Fuel type
M/MS
lb/ton
Enlssion Factor
Rating
Particulate8
Bark^
Multlclone, with flyash reinjection^
7
14
B
Multiclone, without flyash
reinjectlonc
4.5
9
B
Uncontrolled
26
47
E
Wood/bark mixture**
Multiclone, with flyash
relnjectionc«e
3
6
C
Multiclone, without flyash
reinj ectionc»e
2.7
5.3
C
Uncontrolled^
3.6
7.2
C
WoodS
Uncontrolled
4.4
8.8
C
Sulfur dioxide*1
0.075
<0.01 - 0.2)
0.15
(0.02 - 0.4)
B
Nitrogen oxides (as
50,000 - 4CT),000 lb steam/hr
<50,000 lb steam/hr
1 .4
0.34
2.8
0.68
S
B
Carbon monoxide*
2-24
4 - <.7
C
VOC
Noronechaners
0.7
1.4
D
Methane"
0.15
0.3
E
References 2, 4, 9, 17-18, 20. With gab or oil as auxiliary fuel, all particulate assumed
to result from only wood waste fuel. May include condenslble hydrocarbons of pitches and
tare, mostly from back half catch of EPA Method 5. Tests Indicate condeaslble hydrocarbons
about 4Z of total particulate weight.
^Based on fuel moisture content about 50X.
cReferences 4,7-8. After control equipment, assuming an average collection efficiency of
80S. Data indicate that 50? fly ash reinjection Increases dust load at cyclone ir.let 1.2 to
1.5 times, and 100? flyash reinjection Increases the load 1,5 to 2 times.
dgased on fuel moisture content of 33X.
eBased on large dutch ovens ard spreader stokers (avg. 23,430 kg steao/hr) with steara
pressures 23 - 75 kpa (I4C - 530 psi).
* Baaed on small dutch ovens and spreader stokers (usually <9075 kg steam/hr), with steam
pressures 5-30 kpa (35 - 230 psl). Careful air adjustments and improved fuel separation and
firing sometimes used, but effects can not be Isolated.
^References 12-13, 19, 27. Wood waste includes cuttings, shavings, sawdust and chips, but
not bark. Moisture content ranges 3-50 weight X. Based on small units (0000 kg steam/hr).
^Reference 23. Based on dry weight of fuel. From tests of fuel sulfur content and SO2
emissions at 4 mills burning bark. Lover limit of range (In parentheses) should be usee for
wood, and higher values for bark. Heating value of 5000 itcal/kg (9000 Btu/lb) is assumed.
^References 7, 24-26. Several factors can influence emission rates, including combustion
zone, temperature, excess air, boiler operating conditions, fuel moisture and fuel
nitrogen content.
kReference 30.
"References 20, 30. Nonmethar.e V0C reportedly consists of compounds with high vapor
pressure, such as alpha plnene.
nReference 30. Baaed on approximation of aethane/nonoethane ratio, quite variable.
Methane, expressed as X total VOC, varied C - 74 weight X.
1.6-2
EMISSION FACTORS
166
-------
Sander dusC is often burned in various boiler types at plywood, particle
board and furniture plants. Sander dust contains fine wood particles with low
moisture content (less than 20 weight percent). It is fired in a flaming
horizontal torch, usually with natural gas as an ignition aid or supplementary
fuel.
1.6.3 Emissions And Controls^-^
The major emission of concern from wood boilers is particulate matter,
although other pollutants, particularly carbon monoxide, may be emitted in
significant amounts under poor operating conditions. These emissions depend
on a number of variables, including (1) the composition of the waste fuel
burned, (2) the degree of flvash reinjection employed and (3) furnace design
and operating conditions.
The composition of wood waste depends largely on the industry whence it
originates. Pulping operations, for example, produce great quantities of bark
that may contain more than 70 weight percent moisture and sand and other non-
combustibles. Because of this, bark boilers in pulp mills may emit considerable
amounts of particulate matter to the atmosphere unless they are well controlled.
On the other hand, some operations, such as furniture manufacturing, produce a
clean dry wood waste, 5 to 50 weight percent moisture, with relatively little
particulate emission when properly burned. Still other operations, such
as sawmills, burn a varying mixture of bark and wood waste that results in
particulate emissions somewhere between these two extremes.
Furnace design and operating conditions are particularly important when
firing wood waste. For example, because of the high moisture content that can
be present in this waste, a larger than usual area of refractory surface is
often necessary to dry the fuel before combustion. In addition, sufficient
secondary air must be supplied over the fuel bed to burn the volatiles that
account for most of the combustible material in the waste. When proper drying
conditions do not exist, or when secondary combustion is incomplete, the
combustion temperature is lowered, and increased particulate, carbon monoxide
and hydrocarbon emissions may result. Lowering of combustion temperature
generally means decreased nitrogen oxide emissions. Also, short term emissions
can fluctuate with significant variations in fuel moisture content.
Flyash reinjection, which is common to many larger boilers to improve
fuel efficiency, has a considerable effect on particulate emissions. Because
a fraction of the collected flyash is reinjected into the boiler, the dust
loading from the furnace, and consequently from the collection device, increases
significantly per unit of wood waste burned. It is reported that full reinjec-
tion can cause a tenfold increase in the dust loadings of some systems, although
increase of 1.2 to 2 times are more typical for boilers using 50 to 100 percent
reinjection. A major factor affecting this dust loading increase is the extent
to which the sand and other noncombustibles can be separated from the flyash
before reinjection to the furnace.
Although reinjection increases boiler efficiency from 1 to A percent and
reduces emissions of uncombusted carbon, it increases boiler maintenance
requirements, decreases average flyash particle size and makes collection more
difficult. Properly designed reinjection systems should separate sand and char
External Combustion Sources
167
1 .6-3
-------
TABLE 1.6-2. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
EMISSION FACTORS FOR BARK FIRED BOILERS3
EMISSION FACTOR RATING: D
Particle slzeh
Cumulative w4as X
£ stated size
Cumulative- emission factor
(.3
: u.*)
1.0
(3.6)
1.32
(2.64)
10
35
79
36
8?
8.4
CH.a)
5.5
(i; .o)
1.62
(3.24)
1.25
(2.50)
6
28
64
30
78
6.7
(13.6)
4.5
(9.0)
i. 35
(2.7)
1.12
(2.24)
2.5
21
40
19
5b
3.0
(IC.O)
2.8
(5.6)
0.86
(1.72)
0.61
(1.62)
1.23
15
26
U
29
3.6
.'7.2)
1.8
(3.6)
0.63
( 1.26)
0.42
(0.84)
1.00
13
21
;t
23
3.1
(6.2)
1.5
(1.0)
0.5
(1.0).
0.33
(0.66)
0.625
V
15
6
14
2.2
(4.4)
1.1
(3.2)
0.36
(3.72)
C.20
(C.40)
TOTAL
100
too
103
100
?£,
(4a)
7
(14)
4.5
(9.0)
1.44
(2.*«;>
aReference 31. All spreader stoker boilers.
^Expressed as aerodynamic equivalent dianeter.
cWith flyash reinjectlon.
^Without fiyash reinfection.
^Estimated control efficiency for scrubber, 94%.
»— C71
O £
L
c*
C
c
1.6-4
25
20
15
10
.1
.2
Multiple cyclone
with fiyash relnjectlor.
ScrLboer
lincontrol led.
.6 1 2 4 6 10
Particle diameter (pmj
13
3 m
Multip'e c/clane
witnout flyasn -
reinjcction
20
- 1
40 60 1C0
It
s -
« x
C
o =*
• 2.0
- 1.8
- 1.6
- 1.4
' 1.2
- 1.0
- 0.8
- C.6
¦ Q. 4
¦ 0.2
¦ 0.0
<—
o v.
L. rtj
«-» a
c
o OS
U -3L
Figure 1.6-1,
Cumulative size specific emission factors
for bark fired boilers.
EMISSION FACTORS
168
-------
from the exhaust gases, to reinject the larger carbon particles to the furnace
and to divert the fine sand particles to the ash disposal system.
Several factors can influence emissions, such as boiler size and type,
design features, age, load factors, wood species and operating procedures. In
addition, wood is often cofired with other fuels. The effect of these factors
on emissions is difficult to quantify. It is best to refer to the references
for further information.
The use of multitube cyclone mechanical collectors provides particulate
control for many hogged boilers. Usually, two multicyclones are used in series,
allowing the first collector to remove the bulk of the dust and the second to
remove smaller particles. The efficiency of this arrangement is from 65 to 95
percent. Low pressure drop scrubbers and fabric filters have been used
extensively for many years, and pulse jets have been used in the western U. S.
Emission factors and emission factor ratings for wood waste boilers are
presented in Table 1.6-1, except for cumulative size distribution data, size
specific emission factors for particulate, and emission factor ratings for Che
cumulative particle size distribution, all presented in Tables 1.6-2 through
1.6-3. Uncontrolled and controlled size specific emission factors are in
Figures 1.6-1 and 1.6-2.
External Combustion Sources
169
1.6-5
-------
I
C*)
X
h-1
cn
c/>
~H
o
»-» 25
O ^
>
o
H
O
*3
CO
TABLE 1.6-3. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
EMISSION FACTORS FOR WOOD/BARK FIRED BOILERS*
EMISSION FACTOR RATING: E (A tor dry electrostatic granular tilter [DEGF])
Cumulative mflSH X < giHled 8lze
Cunml /it Ivr «ninslon Ittcturs
(kg/Mg (lb/ton) wood/bark, as ftredl
Part trie slte^
(ii m)
llocontrol lerlr
Cont rol 1 ed
llnront nil 1 edc
(,'onl rol led
Mill t Ipli'
cyrlone^
Mill I Iple
rycloneB
Scruhher^
DECF
Multiple
cy r* 1 on?
Hit! tl pi e
rye 1onptf
Scrubber^
f>F.CFFrom dot* on uprrader *lokertf. Without fly Ash relnjortlon.
'From datrt on dutch ovens. Estimated control eltlclency, 94X.
-------
m
x
rt
re
P
a.
0
1
cr
o
3
CT
o
c
o
(ii
i-.
o
4->
"D
u
a>
to
L.
H-
• r-
*~-
c
o
1/1
•r—
to
l/l
in
•
•r—
J*
G
L.
Q)
fH
-Q
O
(U
T3
r—
O
r—
O
o
X
*->
CP
c
3E
o
u
CD
c.
ID
3. &
2.8
2.1
1.4
0.7
Uncontrol led
Dry electrostatic
granular filter
Multiple cyclone
with flyash
reinjection
J I 1 I I
Scrubber
Multiple cyclone
without flyash
reinjection
I I I 11 I 1—I I I H I
3.0
2.7
2.4
2.1
1.8
1.5
1.2
0.9
0.6
0.3
0
L.
o
4->
o
TJ
4-
C
o
-o
vt
a>
I/)
u
lf»
«r-
e
«*-
Ol
w>
"O
«T3
o
r—
*
J*
o
L.
L.
ra
4->
-O
c
o
X>
u
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O
(J
3
c
o
m
Li
C7>
u
a
r—»
CL
»r—
4->
r—
3
X
.1 .2 .4 .6
1 2 4 6 10
Particle diameter (pm)
20
40 60 100
0.220
0.218
0.216
0.214
0.212
0.210
0.208
0.206
0.204
0-202
0.200
0.2
O
<4- "O
CJ
c u
o —
«*-
t/>
u\ in
•r- TO
E
-
j*.
"O 4-
Q> *3
-O
O T3
1~ O
O
u a%
X
L V
.o
-Q '
3
U
U
«~>
w.
Oi
i-'
o
¦a
k. u ^
£ ™ £
i/»
*
0.1 ai
i-
U c 'D
w " O
Or-*
U n
f P [71
o in
41 c
¦— o Ol
-------
References for Section 1.6
1. Steam, 38th Edition, Babcock and Wilcox, New York, NY, 1972.
2. Atomspherlc Emissions from the Pulp and Paper Manufacturing Industry,
EPA-450/1-73-002, U. S. Environmental Protection Agency, Research Triangle
Park, NC, September 1973.
3. C-E Bark Burning Boilers, C-E Industrial Boiler Operations, Combustion
Engineering, Inc., Windsor, CT, 1973.
4. A. Barron, Jr., "Studies on the Collection of Bark Char throughout the
Industry", Journal of the Technical Association of the Pulp and Paper
Industry, 53(8):1441-1448, August 1970.
5. H. Kreisinger, "Combustion of Wood Waste Fuels", Mechanical Engineering,
6J_: 115-120, February 1939.
6. P. L. Magi11 (ed.), Air Pollution Handbook, McGraw-Hill Book Co., New
York, NY, 1956.
7. Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection
Agency, Research Triangle Park, NC, April 1970.
8. J. F. Mullen, A Method for Determining Combustible Loss, Dust Emissions,
and Recirculated Refuse for a Solid Fuel Burning System, Combustion
Engineering, Inc., Windsor, CT, 1966.
9. Source test data, Alan Lindsey, U. S. Environmental Protection Agency,
Atlanta, GA, May 1973.
10. H. K. Effenberger, et al., "Control of Hogged Fuel Boiler Emissions: A
Case History", Journal of the Technical Association of the Pulp and Paper
Industry, 56(2):111 — 115, February 1973.
11. Source test data, Oregon Department of Environmental Quality, Portland,
OR, May 1973.
12. Source test data, Illinois Environmental Protection Agency, Springfield,
IL, June 1973.
13. J. A. Danielson (ed.), Air Pollution Engineering Manual, Second Edition,
AP-40, U. S. Environmental Protection Agency, Research Triangle Park, NC,
1973. Out of Print.
14. H. Droege and G. Lee, "The Use of Gas Sampling and Analysis for the
Evaluation of Teepee Burners", presented at the Seventh Conference on the
Methods in Air Pollution Studies, Los Angeles, CA, January 1967.
15. D. C. Junge and K. Kwan, "An Investigation of the Chemically Reactive
Constituents of Atmospheric Emissions from Hog-fuel Boilers in Oregon",
Northwest International Section of the Air Pollution Control Association,
November 1973.
1.6-8
EMISSION FACTORS
172
-------
16. S. F. Galeano and K. M. Leopold, "A Survey of Emissions of Nitrogen Oxides
in the Pulp Mill", Journal of the Technical Association of the Pulp and
Paper Industry, 56(3):74-76, March 1973.
17. P. B. Bosserman, "Wood Waste Boiler Emissions in Oregon State", presented
at the Annual Meeting of the Pacific Northwest International Section of
the Air Pollution Control Association, September 1976.
18. Source test data, Oregon Department of Environmental Quality, Portland,
OR, September 1975.
19. Source test data, New York State Department of Environmental Conservation,
Albany, NY, May 1974.
20. P. B. Bosserraan, "Hydrocarbon Emissions from Wood Fired Boilers", pre-
sented at the Annual Meeting of the Pacific Northwest International
Section of the Air Pollution Control Association, November 1977.
21. Control of Particulate Emissions from Wood Fired Boilers, EPA-340/1—77—
026, U. S. Environmental Protection Agency, Research Triangle Park, NC,
1978.
22. Wood Residue Fired Steam Generator Particulate Matter Control Technology
Assessment, EPA-450/2-78-044, U. S. Environmental Protection Agency,
Research Triangle Park, NC, October 1978.
23. H. S. Oglesby and R. 0. Blosser, "Information on the Sulfur Content of
Bark and Its Contribution to SO2 Emissions When Burned as a Fuel", Journal
of the Air Pollution Control Association, 30(7): 769-772, July 1980.
24. A Study of Nitrogen Oxides Emissions from Wood Residue Boilers, Technical
Bulletin No. 102, National Council of the Paper Industry for Air and Steam
Improvement, New York, NY, November 1979.
25. R. A. Kester, Nitrogen Oxide Emissions from a Pilot Plant Spreader Stoker
Bark Fired Boiler, Department of Civil Engineering, University of
Washington, Seattle, WA, December 1979.
26. A. Nunn, NQy Emission Factors for Wood Fired Boilers, EPA-600/7-79-219,
U. S. Environmental Protection Agency, September 1979.
27. C. R. Sanborn, Evaluation of Wood Fired Boilers and Wide Bodied Cyclones
in the State of Vermont, U. S. Environmental Protection Agency, Boston,
MA, March 1979.
28. Source test data, North Carolina Department of Natural Resources and
Community Development, Raleigh, NC, June 1981.
29. Nonfossil Fueled Boilers - Emission Test Report: Weyerhaeuser Company,
Longvlew, Washington, EPA-80-WFB-10, Office Of Air Quality Planning And
Standards, U. S. Environmental Protection Agency, Research Triangle Park,
NC, March 1981.
External Combustion Sources
173
1.6-9
-------
30. A Study of Wood Residue Fired Power Boiler Total Gaseous Nonmethane Organic
Emissions in the Pacific Northwest, Technical Bulletin No. 109, National
Council of the Paper Industry for Air and Steam Improvement, New York, NY,
September 1980.
31. Inhalable Particulate Source Category Report for External Combustion
Sources, EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View,
CA, January 1985.
1.6-10 EMISSION FACTORS
174
-------
1.7 LIGNITE COMBUSTION
1.7.1 General
Lignite is a relatively young coal with properties intermediate to those
of bituminous coal and peat. It has a high moisture content (35 to 40 weight
percent) and a low wet basis heating value (1500 to 1900 kilocalories) and
generally is burned only near where it Is mined, in some midwestern states and
Texas. Although a small amount Is used in industrial and domestic situations,
lignite is used nainly for steam/electric production in power plants. In the
past, lignite has been burned mainly in small stokers, but today the trend is
toward use in much larger pulverized coal fired or cyclone fired boilers.
The major advantages of firing lignite are that, in certain geographical
areas, it is plentiful, relatively low in cost and low in sulfur content (0.4
to 1 wet basis weight percent). Disadvantages are that more fuel and larger
facilities are necessary to generate a unit of power than is the case with
bituminous coal. The several reasons for this are (1) the higher moisture
content means that more energy is lost In the gaseous products of combustion,
which reduces boiler efficiency; (2) more energy is required to grind lignite
to combustion specified size, especially in pulverized coal fired units; (3)
greater tube spacing and additional soot blowing are required because of the
higher ash fouling tendencies; and (4) because of Its lower heating value, nore
fuel must be handled to produce a given amount of power, since lignite usually
is not cleaned or dried before combustion (except for some 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.
1.7.2 Emissions And Controls^-!!
The major pollutants from firing lignite, as with any coal, are particulate,
sulfur oxides, and nitrogen oxides. Volatile organic compounds (VOC) and carbon
monoxide emissions are quite low under normal operating conditions.
Particulate emission levels appear most dependent on the firing configu-
ration in the boiler. Pulverized coal fired units and spreader stokers, which
fire much or all of the lignite in suspension, emit the greatest quantity of
flyash per unit of fuel burned. Cyclone furnaces, which collect much of the
ash as molten slag in the furnace itself, and stokers (other than spreader),
which retain a large fraction of the ash in the fuel bed, both emit less par-
ticulate matter. In general, the relatively high sodium content of lignite
lowers particulate emissions by causing more of the resulting flyash to
deposit on the boiler tubes. This is especially so in pulverized coal fired
units wherein a high fraction of the ash is suspended in the combustion gases
and can readily come into contact with the boiler surfaces.
Nitrogen oxide emissions are mainly a function of the boiler firing
configuration and excess air. Stokers produce the lowest N0X levels, mainly
External Combustion Sources
175
1.7-1
-------
I
N>
TABLK 1.7-1. EMISSION FACTORS FOR EXTERNAL COMBUSTION OF LIGN1TK COALa
cn
JZ
r-i
CO
LTj
t-H
>
O
H
O
73
ya
Pa rtl cul ate'1
Sulfur
oxidesc
Nitrogen oxides^
Carbon
Volatile organics
Firing configuration
monoxide
kg/Mg
lb/ton
kg/Mg
Lb/ton
kg/Mg
lb/ton
Nonmethanc
Methane
Pulverized coal Hred
dry bottom
3. IA
6.3A
15S
30S
6*.f
12".t
g
g
g
Cyclone furnace
3.3A
6.7 A
15S
30S
8.5
17
g
8
g
Spreader stoker
3.4A
6.8A
1 5S
30 S
3
6
g
g
e
Other stoker
1.5A
2.9A
15S
30S
3
6
g
g
g
aFor lignite consumption as fired.
^References 5-6, 9, 12. A = wet basis % ash content of Lignite.
rRelerences 2, b-6, 10-11. S = wet basis weight % sulfur content of lignite. For high sodium/ash
Lignite (Na2U >8%), use 8.5S kg/Mg (I7S lb/ton); for low sodium/ash lignite (Na^O <2%), use 17.5S
kg/Mg (35S lb/ton). If unknown, use 15S kg/Mg (30S lb/ton). The conversion of SO2 is shown to be
,1 function ol alkali ash constituents.
^References 2, 5, 7-H. F.xpressed as NO2 •
^Use 7 kg/Mg (14 ib/ton) for front wall fired and horizontally opposed wall fired units, and 4 kg/Mg (8 lb/ton)
for tangentially fired units.
fMay be reduced 20 - 402 with low excess firing and/or sraged combustion In front fired and opposed wall fired
units and cyclones.
KFactors in Table 1.1-1 may be used, based on combustion similarity of lignite and bituminous coal.
-------
because most existing units are relatively small and have lower peak flame
temperatures. In most boilers, regardless of firing configuration, lower
excess combustion air means lower NO^ emissions.
Sulfur oxide emissions are a function of the alkali (especially sodium)
content of the lignite ash. Unlike most fossil fuel combustion, in which over
90 percent of the fuel sulfur is emitted as SO2, a significant fraction of the
sulfur in lignite reacts with the ash components during combustion and is
retained in the boiler ash deposits and fly ash. Tests have shown that less
than 50 percent of the available sulfur may be emitted as SO2 when a high
sodium lignite is burned, whereas more than 90 percent may be emitted from low
sodium lignite. As a rough average, about 75 percent of the fuel sulfur will
be emitted as SO2, the remainder being converted to various sulfate salts.
Newer lignite fired utility boilers are equipped with large electrostatic
precipitators with as high as 99.5 percent particulate control. Older and
smaller electrostatic precipitators operate at about 95 percent efficiency.
Older industrial and commercial units use cyclone collectors that normally
achieve 60 to 80 percent collection efficiency on lignite flyash. Flue gas
desulfurization systems identical to those on bituminous coal fired boilers
are in current operation on several lignite fired utility boilers. (See
Section 1.1).
Nitrogen oxide reductions of up to 40 percent can be achieved by changing
the burner geometry, controlling excess air and making other changes in operat-
ing procedures. The techniques for bituminous and lignite coal are identical.
TABLE 1.7-2. EMISSION FACTOR RATINGS FOR LIGNITE COMBUSTION
Firing configuration
Particulate
Sulfur dioxide
Nitrogen oxides
Pulverized coal
fired dry bottom
A
A
A
Cyclone furnace
C
A
A
Spreader stoker
B
B
C
Other stokers
3
C
" 1
External Combustion Sources
177
1.7-3
-------
TABLE 1.7-3. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
EMISSION FACTORS FOR BOILERS BURNING PULVERIZED LIGNITE COALa
EMISSION FACTOR RATING: E
ParticLe slze^
Cuniulative mass
X < stated size
Cumulative emission factorc
|'Kg/Mg (lb/ton) coal, as ftred]
Ojn)
Uncont rol1ed
Multiple cyclone
cont rolled
Itncont rol led
Multiple cyclone
contrailed^
1 5
51
77
1.58A
(3.16A)
0.477A
(0.954a)
10
35
ft 7
1 .09 A
(2.18A)
0.415A
(0.S30A)
6
26
57
0.81 A
(i. 6 2 A)
0. 353a
(0.706A)
2.5
10
27
0 . 3 1 A
(Q.62A)
0.167A
(0.334A)
1.25
7
16
0.22A
('J .44a)
0.099A
(0.I90A)
1.00
6
14
0.I9A
(:j.3SA)
O.0R7A
(0. 174A)
0.625
3
8
0.09A
(0. ISA)
0.050A
(0.I00A)
TOTAL
100
100
3.1A
(6.2A)
0.62A
(1.24A)
aRcference 13.
^Expressed as aerodynamic equivalent dianeter.
CA ¦ coal aah weight X content, as fired.
^Estimated control efficiency foe multiple cyclone, ROX.
3A
2.7A
2.4A
-o
2.1A
U
l.UA
-------
TABLE 1.7-4 CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
EMISSION FACTORS FOR LIGNITE FUELED SPREADER STOKERS3
EMISSION FACTOR RATING: E
Parctcle size0
Cumulative mass
t <_ stated size
Cumulative emission factorc
|kg/Mg (lb/ton) coal, as fired)
ty «)
Uncontrolled
Multiple cyclone
cont rolled
Uncontrolled
Multiple cyclone
controlled^
15
28
55
0.95a
(1.9a)
0.374A (0.748A)
10
20
41
0.68 a
(1.36A)
0.279A (0.558A)
6
14
31
0.48A
(0.96A)
0.211A (0.422A)
2.3
26
0.24A
(0.48A)
0.177A (0.354A)
1.25
5
23
0.17A
(0.34A)
0.156A (0.312A)
1.00
5
22
0.17A
(0.34A)
0.150A (0.300A)
0.625
4
e
0. 14a
(0.28A)
e
TOTAL
100
100
3.4 A
(6.BA )
0.68A (1.36A)
dReference 13.
''Expressed as aerodynamic equivalent diameter.
cCoal ash weight % concent, as fired.
dEatlmated control efficiency for multiple cyclone, 80%.
insufficient data.
1. OA
0.9A
Ol
o
0.8A
* *
4
L.
C.7A
z> °
s.
C.6A
*O
£ ?
T3 S
C
o
0.5A
* "O
u
n ^
m
G.4A
^ °
0 t
1 §
-*
0.3A
§ -
u
c
0.2A
=5
0.1A
0
Jncontr'jl led
flu 1 tiole cyclone
I I III
' i ' i .inl
' I ''''I
.4 .6 1 2 4 6 10 20 40 60 100
?art
-------
Emission factors for particulate, sulfur dioxide and nitrogen oxides are
presented in Table 1.7-1, and emission factor ratings in Table 1.7-2. Specifi
emission factors for particulate emissions, and emission factor ratings for th
cumulative particle size distributions, are given in Tables 1.7-3 and 11.7-4.
Uncontrolled and controlled size specific emission factors are presented in
Figures 1.7-1 and 1.7-2. 3ased on the similarity of lignite combustion and
bituminous coal combustion, emission factors for carbon monoxide and volatile
organic compounds (Table I.1-1), and cumulative particle size distributions
for cyclone furnaces, uncontrolled spreader stokers and other stokers (Tables
1,1-5 through 1.1-8) may be used.
References for Section 1.7
1. Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition, Volume
12, John Wiley and Sons, New York, NY, 1967.
2. G. H. Gronhovd, et al., "Some Studies on Stack Emissions from Lignite
Fired Powerplants", Presented at the 1973 Lignite Symposium, Grand Forks,
NB, May 1973.
3. Standards Support and Environmental Impact Statement: Promulgated
Standards of Performance for Lignite Fired Steam Generators: Volumes I
and II, 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 Depart
•tient of Health, Bismarck, ND, December 1973.
6. G. H. Gronhovd, 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. A. R. Crawford, et al., Field Testing: Application of Combustion Modi-
fication To Control NOy Emissions from Utility Boilers, EPA-650/2-74-066,
U. S. Environmental Protection Agency, Washington, DC, June 1974.
8. "Nitrogen Oxides Emission Measurements for Lignite Fired Power Plant",
Source Test No. 75-LSG-33, 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. C. Castaldini 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.
1.7-6
EMISSION FACTORS
180
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11. C. C. Shih, 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.
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.
External Combustion Sources
131
1.7-7
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REFERENCES FOR SECTIONS 1 THROUGH 3
1. Compilation of Air Pollutant Emission Factors, Third Edition, (including
Supplements 1 through 7), AP-42, U. S. Environmental Protection Agency,
August 1977, plus supplements 8 through 15.
*2. FPEIS Computer Printout, Run Identification A4F361, U. S. Environmental
Protection Agency, Research Triangle Park, NC, June 1983.
*3. FPEIS Computer Printout, Run Identification 43CETA, U. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1983.
4. Technical Procedures for Developing AP-42 Emission Factors and Preparing
AP-42 Sections, U. S. Environmental Protection Agency, Research Triangle
Park, NC, April 1980.
5. Generic Particle Size Distributions for use in Preparing Particle Size
Specific Emission Inventories, EPA Contract No. 68-02-3512, PEDCO
Environmental, Golden, CO, September 1983.
6. Steam, 38th Edition, Babcock & Wilcox, New York, 1975.
7. Industrial Boilers: Emission Test Report, DuPont Corporation, Parkersburg,
WV, EMB-80-IBR-12, U.S. Environmental Protection Agency, Office of A1r
Quality Planning and Standards, Research Triangle Park, NC, February 1982.
8. Industrial Boilers: Emission Test Report, General Motors Corporation,
Lansing, MI, EMB-82-IBR-17, U.S. Environmental Protection Agency, Office
of Air Quality Planning and Standards, Research Triangle Park, NC,
April 1982.
9. Industrial Boilers: Emission Test Report, Burlington Industries Boiler
No. 6, Clarksvi11e, VA, EMB-82-IBR-18, U.S. Environmental Protection
Agency, Research Triangle Park, NC, February 1983.
10. Emission Characterization of Major Fossil Fuel Power Plants in the Ohio
River Valley, EPA Contract No. 68-02-3271, PEDCO Environmental,
Cincinnati, OH, October 1983.
11. Field Tests of Industrial Stoker Coal-Fired Boilers for Emissions Control
and Efficiency Improvement - Sites L1-L7, EPA-600/7-81-020a, U.S.
Environmental Protection Agency, Research Triangle Park, NC, February 1981.
12. Written communication from Robert A. Kaiser, Ohio Edison Company to
A. Walter Wyss, Acurex Corporation, dated February 24, 1983, with attach-
ments.
~Individual FPEIS test series included 1n references 2 and 3 are listed
in tables 1 and 2, pages 22 to 25. The original reference document for
each FPEIS test series is listed in reference 22.
182
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13. Murray, M.M. and M. Chips, Characterization of Inhalable Particulate
Matter Emissions from a 2.5-million Btu Per Hour Experimental Boiler,
EPA-600/x-85-333, Acurex Corporation, Mountain View, CA, December 1984.
14. Nonfossil Fueled Boilers, Emission Test Report, Owens-Illinois, Forest
Products Division, Big Island, VA EMB-80-WFB-2, U. S. Environmental
Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, February 1980.
15. Nonfossil Fueled Boilers, Emission Test Report, St. Regis Paper Company,
Jacksonville, FL, EMB-80-WFB-4, U. S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park,
May 1980.
16. Nonfossil Fueled Boilers, Emission Test Report, St. Joe Paper Company,
Port St. Joe, FL, EMB-80-WFB-5, U. S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC,
May 1980.
17. Nonfossil Fueled Boilers, Emission Test Report, Owens-Illinois, Forest
Products Division, Big Island, VA, EMB-80-WFB-8, U. S. Environmental
Protection Agency, Office of Air Quality Planning and Standards,
Research Triangle Park, NC, November 1980.
18. Nonfossil Fueled Boilers, Emission Test Report, Georgia-Pacific Corp-
oration, Bellingham, WA, EMB-80-WFB-9, U. S. Environmental Protection
Agency, Office of Air Quality Planning and Standards, Research Triangle
Park, NC, March 1981.
19. Nonfossil Fueled Boilers, Emission Test Report, Weyerehaeuser Conpany,
Longview, WA, EMB-80-WFB-10, U. S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC,
March 1981.
20. Written communication from John E. Pinkerton, National Council of the
Paper Industry for Air and Stream Improvement, Inc., to A. Walter Wyss,
Acurex Corporation, dated February 8, 1983, with attachments.
21. Written communication from Dana K. Mount, North Dakota State Department
of Health to A. Walter Wyss, Acurex Corporation, dated March 1, 1983
with attachments including excerpts of a test report by Environmental
Research Corporation.
22. FPEIS Computer Printout, Run Identification 30GLJ, U. S. Environmental
Protection Agency, Research Triangle Park, NC, August 1986.
183
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APPENDIX A
GLOSSARY OF TERMS
Aerodynamic equivalent diameter:
Diameter of a sphere of unit density that reaches the same terminal
settling velocity at low particle Reynolds number 1n still air as the
actual particle.
Cascade impactor:
An inertial-based particle collection instrument for determining
mass-based size fractions.
Inhalable particulate matter:
Particles of resplrable size and capable of reaching the lower lung,
usually whose diameter is less than or equal to 15 ym.
Isokinetic sampling:
Sampling in which the linear velocity of the gas entering the sampling
nozzle is equal to that of the undisturbed gas stream at the sample
point.
AAF:
American Air Filter
EPA:
U. S. Environmental Protection Agency
FGD:
Flue gas desulfurization
ESP:
Electrostatic precipitator
Mg:
106 grams
kg:
103 grams
MW:
megawatts
J:
joule
GJ:
gigajoule
A-l
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kg/s: kilograms per second
1: Liter
Mechanical collector:
A device that separates suspended particles from a gas stream by causing
the gas stream to change direction while the particles, due to their
inertia, tend to continue in their original direction and be separated
from the gas.
PADRE and FPEIS:
The Particulate Data Reduction (PADRE) system is an interactive computer
program that facilitates entry of validated cascade impactor data for
particle size distributions from representative in-stack runs into the
Fine Particle Emissions Information System (FPEIS). PADRE was developed
to ensure the quality of data included in FPEIS, which is a component of
the Environmental Assessment Data Systems (EADS). Impactor stage cut
points are calculated and cumulative and differential mass
concentrations are determined and interpolated to standard diameters.
Data entered through PADRE are not automatically included in FPEIS; the
test contractor should designate representative runs after data
validation.
Upon request, FPEIS can generate computer listings of the entered and
PADRE-reduced data for each test series. One test series is normally
associated with all source sampling at a tested site during a continuous
period which may be less than one day to more than a week.
SASS train:
Source Assessment Sampling System. An inertial-based system normally
consisting of three cyclones and a filter in series used to obtain
particulate greater than 10 urn, less than 10 pm but greater than 3 urn,
less than 3 urn, but greater than 1 urn, and less than 1 um. Organic and
inorganic materials are also captured in the XAD-2 and impinger.
TVA: Tennessee Valley Authority
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APPENDIX B
LIST OF CONTACTS
Dr. Ralph F. Altman
Electric Power Research Institute
Coal Combustion Systems Division
516 Franklin Building
Chattanooga, TN 37411
Mr. Michael J. Atherton
Environmental Affairs
Columbia Gas System
Service Corporation
20 Montchanin Road
Wilmington, DE 19807
Mr. W. H. Axtman
Executive Director
American Boiler
Manufacturers Association
Suite 700 AM Building
1500 Wilson Boulevard
Arlington, VA 22209
Mr. Robert Beck
Manager, Environmental Programs
Edison Electric Institute
1111 19th Street, NW
Washington, PA 17120
Mr. James R. Benson, Chief
Abatement Monitoring and
Emission Inventory Section
Department of Environmental
Resources
P.O. Box 2063
Harrisburg, PA 17120
Mr. Russell 0. Blosser
Technical Director
National Council of the Paper Industry
for Air and Stream Improvement, Inc.
260 Madison Avenue
New York, NY 10016
Andre Caron
National Council of the Paper
Industry for Air and Stream
Improvement, Inc.
P.O. Box 458
Corvallis, OR 97339
Mr. Robert Carr, Program Manager
Air Quality Control
Electric Power Research Institute
3412 Hi! 1 view Avenue
P.O. Box 10412
Palo Alto, CA 94303
Mr. A. 0. Courtney
Director of Air Quality
Commonwealth Edison
72 West Adams Street
P.O. Box 767
Chicago, IL 60690
Mr. E. P. Crockett
American Petroleum Institute
2101 L Street, NW
Washington, DC 20037
B-l
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L. Blaine Dehaven
Pennsylvania Department of
Environmental Resources
P.O. Box 2063
Harrisburg, PA 17120
Mr. Peter C. Freudenthal, Director
A1r and Noise Programs
Consolidated Edison Company
of New York, Inc.
4 Irving Place
New York, NY 10003
Dale Harmon
U. S. Environmental Protection
Agency
Industrial Environmental
Research Laboratory
Research Triangle Park, NC 27711
Gary Johnson
U. S. Environmental Protection
Agency
Industrial Environmental
Research Laboratory
Research Triangle Park, NC 27711
Mr. Robert A. Kaiser
General Environmental Engineer
Ohio Edison Company
76 South Main Street
Akron, OH 44308
William H. Lamason, II
U. S. Environmental Protection
Agency
Office of Air Quality Planning
and Standards
Research Triangle Park, NC 27711
Ms. Janet S. Matey
Manager, Air Programs
Chemical Manufacturers Association
2501 M Street, NW
Washington, DC 20037
Mr. Dana K. Mount, PE Director
North Dakota State Department
of Health
Environmental Health Section
Missouri Office Building
1200 Missouri Avenue
Bismark, ND 58505
Frank Noonan
U. S. Environmental Protection
Agency
Office of Air quality Planning and
Standards MD-14
Research Triangle Park, NC 27711
John Pinkerton
National Council of the Paper
Industry for Air and Stream
Improvement, Inc.
260 Madison Avenue
New York, NY 10016
Dr. Robert R. Romano
Chemical Manufacturers
Association
2501 M Street NW
Washington, DC 20037
B-2
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