ABMA
American
Boiler Manufacturers
Association
1500 Wilson Boulevard
Arlington VA 22209
DoE
United States
Department
of Energy
Division of Power Systems
Energy Technology Branch
Washington DC 20545
EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-80-136a
May 1980
Field Tests of Industrial
Stoker Coal-fired Boilers
for Emissions Control and
Efficiency Improvement
Site I
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide-range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/7-80-136a
May 1980
Field Tests of Industrial Stoker Coal-fired
Boilers for Emissions Control and
Efficiency Improvement Site I
by
P.L. Langsjoen, J.O. Burlingame,
and J.E. Gabrielson
KVB, Inc.
6'~*6 Olson Memorial Highway
Minneapolis, Minnesota 55422
lAG/Contract Nos. IAG-D7-E681 (EPA), EF-77-C-01-2609 (DoE)
Program Element No. EHE624
Project Officers: R.E. Hall (EPA) and W. Harvey, Jr. (DoE)
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
U.S. DEPARTMENT OF ENERGY
Division of Power Systems/Energy Technology Branch
Washington, DC 20545
and
AMERICAN BOILER MANUFACTURERS ASSOCIATION
1500 Wilson Boulevard
Arlington, VA 22209
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ACKNOWLEDGEMENTS
The authors wish to express their appreciation for the assistance
and direction given the program by project monitors W. T. (Bill) Harvey of
the United States Department of Energy (DOE) and R. E. (Bob) Hall of the
United States Environmental Protection Agency (EPA). Thanks are due to
their agencies, DOE and EPA, for co-funding the program.
We would also like to thank the American Boiler Manufacturers
Association, ABMA Executive Director, W. H. (Bill) Axtman, ABMA Assistant
Executive Director, R. N. (Russ) Mosher, ABMA's Project Manager, B. C. (Ben)
Severs, and the members of the ABMA Stoker Technical Committee chaired by
W. B. (Willard) McBurney of The McBurney Corporation for providing support
through their time and travel to manage and review the program. The partici-
pating committee members listed alphabetically are as follows:
R. D. Bessette Island Creek Coal Company
T. Davis Combustion Engineering
N. H. Johnson Detroit Stoker
K. Luuri Riley Stoker
D. McCoy E. Keeler Company
J. Mullan National Coal Association
E. A. Nelson Zurn Industries
E. Poitras The McBurney Corporation
P. E. Ralston Babcock and Wilcox
D. C. Reschley Detroit Stoker
R. A. Santos Zurn Industries
We would also like to recognize the KVB engineers and technicians who
spent much time in the field, often under adverse conditions, testing the
boilers and gathering data for this program. Those involved at Site I in
addition to co-author Jim Burlingame were Russ Parker, Mike Jackson, and Jim
Demont.
Finally, our gratitude goes to the host boiler facilities which in-
vited us to test their boiler. At their request, the facilities will remain
anonymous to protect their own interests. Without their cooperation and
assistance this program would not have been possible.
KVB 4-15900-544
11
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TABLE OF CONTENTS
Section Page
ACKNOWLEDGEMENTS ii
LIST OF FIGURES iv
LIST OF TABLES V
1.0 INTRODUCTION 1
2.0 EXECUTIVE SUMMARY 3
3.0 DESCRIPTION OF FACILITY TESTED AND COALS FIRED 9
3.1 Boiler I Description 9
3.2 Overfire Air 9
3.3 Test Port Locations 9
3.4 Coals Utilized 13
4.0 TEST EQUIPMENT AND PROCEDURES 15
4.1 Gaseous Emissions Measurements (NOx, CO, C02, HC) . . . 15
4.1.1 Analytical Instruments and Related Equipment . . 15
4.1.2 Recording Instruments 19
4.1.3 Gas Sampling and Conditioning System 19
4.1.4 Gaseous Emission Sampling Techniques 19
4.2 Sulfur Oxides (SOx) Measurement and Procedures .... 21
4.3 Particulate Measurement and Procedures 23
4.4 Coal Sampling and Analysis Procedure 26
4.5 Ash Collection and Analysis for Combustibles 27
4.6 Boiler Efficiency Evaluation 27
4.7 Trace Species Measurement 28
5.0 TEST RESULTS AND OBSERVATIONS 31
5.1 Overfire Air 31
5.1.1 Particulate Loading vs Overfire Air 31
5.1.2 Nitric Oxide vs Overfire Air 33
5.1.3 Boiler Efficiency vs Overfire Air 33
5.1.4 Overfire Air Flow Rate 35
5.2 Excess Oxygen and Grate Heat Release 37
5.2.1 Excess Oxygen Operating Levels 38
5.2.2 Particulate Loading vs Oxygen and Grate Heat
Release 38
5.2.3 Nitric Oxide vs Oxygen and Grate Heat Release . 41
5.2.4 Combustibles in the Ash vs Grate Heat Release . 46
5.2.5 Boiler Efficiency vs Grate Heat Release .... 49
5.3 Coal Properties 49
5.3.1 Chemical Composition of the Coals 49
5.3.2 Coal Size Consistency 51
5.3.3 Effect of Coal Properties on Emissions and
Efficiency 58
5.4 Source Assessment Sampling System (SASS) 61
5.5 Data Tables 63
APPENDICES 67
111
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LIST OF FIGURES
Figure
No.
3-1 Boiler I Schematic 11
3-2 Boiler I Sample Plane Geometry 12
4-1 Flow Schematic of Mobile Flue Gas Monitoring Laboratory . . 20
4-2 SOx Sample Probe Construction 22
4-3 Sulfur Oxides Sampling Train (Shell-Emeryville) 22
4-4 EPA Method 6 Sulfur Oxide Sampling Train 24
4-5 EPA Method 5 Particulate Sampling Train 25
4-6 Source Assessment Sampling System (SASS) Sampling Train . . 29
5-1 Nitric Oxide vs Oxygen 34
5-2 Relationship Between Overfire Air Flow Rate and Static
Pressure Within the Overfire Air Duct - Test Site I ... 36
5-3 Oxygen vs Grate Heat Release 39
5-4 Boiler Out Part, vs Grate Heat Release 40
5-5 Boiler Out Part, vs Oxygen 42
5-6 Nitric Oxide vs Grate Heat Release 43
5-7 Nitric Oxide vs Oxygen 44
5-8 Nitric Oxide vs Oxygen 45
5-9 Flyash Combustibles vs Grate Heat Release 47
5-10 Bottom Ash Comb, vs Grate Heat Release 48
5-11 Boiler Efficiency vs Grate Heat Release 50
5-12 Size Consistency of "As-Fired" Ohio Coal vs ABMA Recom-
mended Limits of Coal Sizing for Overfeed Stokers - Test
Site I 52
5-13 Size Consistency of "As-Fired" Kentucky Coal vs ABMA
Recommended Limits of Coal Sizing for Overfeed Stokers -
Test Site I 53
IV
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LIST OF TABLES
Table
No.
2-1 Test Outline for Test Site I 7
2-2 Emission Data Summary 8
3-1 Design Data 10
3-2 Average Coal Analysis 14
5-1 Effect of Overfire Air on Emissions and Efficiency 32
5-2 Particulate Loading vs Overfire Air 33
5-3 Boiler Efficiency vs Overfire Air 35
5-4 Overfire Air Flow Rates 37
5-5 Ash Carryover vs Firing Conditions 41
5-6 Average Nitric Oxide Concentrations vs Load and Coal .... 46
5-7 Boiler Efficiency vs Load 49
5-8 Coal Properties Corrected to a Constant 106Btu Basis .... 51
5-9 Fuel Analysis - Ohio Coal 54
5-10 Fuel Analysis - Kentucky Coal 55
5-11 Mineral Analysis of Coal Ash 56
5-12 As-Fired Coal Size Consistency 57
5-13 Particulate Loading vs Coal Ash 58
5-14 Nitric Oxide vs Coal 59
5-15 Sulfur Oxides vs Fuel Sulfur 60
5-16 Boiler Efficiency vs Coal 61
5-17 Polynuclear Aromatic Hydrocarbons Analyzed in the Site I
SASS Sample 63
5-18 Particulate Emissions 64
5-19 Percent Combustibles in Refuse 64
5-20 Heat Losses and Efficiencies 65
5-21 Steam Flows and Heat Release Rates 66
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1.0 INTRODUCTION
The principal objective of the test program described in this report,
one of several reports in a series, is to produce information which will in-
crease the ability of boiler manufacturers to design and fabricate stoker
boilers that are an economical and environmentally satisfactory alternative
to oil-fired units. Further objectives of the program are to: provide
information to stoker boiler operators concerning the efficient operation of
their boilers; provide assistance to stoker boiler operators in planning
their coal supply contracts; refine application of existing pollution control
equipment with special emphasis on performance; and contribute to the design
of new pollution control equipment.
In order to meet these objectives, it is necessary to define stoker
boiler designs which will provide efficient operation and minimum gaseous and
particulate emissions, and define what those emissions are in order to facili-
tate preparation of attainable national emission standards for industrial
size, coal-fired boilers. To do this, boiler emissions and efficiency must
be measured as a function of coal analysis and sizing, rate of flyash rein-
jection, overfire air admission, ash handling, grate size, and other variables
for different boiler, furnace, and stoker designs.
A field test program designed to address the objectives outlined above
was awarded to the American Boiler Manufacturers Association (ABMA), sponsored
by the United States Department of Energy (DOE) under contract number
EF-77-C-01-2609, and co-sponsored by the United States Environmental Protection
Agency (EPA) under inter-agency agreement number IAG-D7-E681. The program is
directed by an ABMA Stoker Technical Committee which, in turn, has subcontracted
the field test portion to KVB, Inc., of Minneapolis, Minnesota.
This report is the Final Technical Report for the ninth of eleven
boilers to be tested under the ABMA program. It contains a description of
the facility tested, the coals fired, the test equipment and procedures, and
the results and observations of testing. There is also a data supplement to
this report containing the "raw" data sheets from the tests conducted. The
data supplement has the same EPA report number as this report except that it
KVB 4-15900-544
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is followed by "b" rather than "a". As a compilation of all data obtained
at this test site, the supplement acts as a research tool for further data
reduction and analysis as new areas of interest are uncovered in subsequent
testing.
At the completion of this program, a Final Technical Report will
combine and correlate the test results from all sites tested. A report
containing operating guidelines for boiler operators will also be written,
along with a separate report covering trace species data. These reports
will be available to interested parties through the National Technical Infor-
mation Service (NTIS) or through the EPA's Technical Library.
Although it is EPA policy to use S.I. units in all EPA sponsored
reports, an exception has been made herein because English units have been
conventionally used to describe boiler design and operation. Conversion
tables are provided in the Appendix for those who prefer S.I. units.
To protect the interests of the host boiler facilities, each test
site in this program has been given a letter designation. As the ninth
site tested, this is the Final Technical Report for Test Site I under the
program entitled, "A Testing Program to Update Equipment Specifications and
Design Criteria for Stoker Fired Boilers."
KVB 4-15900-544
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2.0 EXECUTIVE SUMMARY
A coal fired traveling grate stoker rated at 70,000 Ibs steam/hr
was extensively tested for emissions and efficiency between April 29 and
May 24, 1979. This section summarizes the results of these tests and pro-
vides references to supporting figures, tables and commentary found in the
main text of the report.
UNIT TESTED; Described in Section 3.0, page 9.
0 Wickes Boiler
Built 1960
Type RB
70,000 Ibs/hr rated capacity
250 psig operating pressure
Saturated stea^
0 Riley Stoker
Overfeed stoker
Traveling grate
Two rows overfire air jets on front wall
COALS TESTED; Individual coal analysis given in Tables 5-9, 5-10 and 5-11,
pages 54-56. Commentary in Section 3.4, page 13, and Section
5.3, page 49.
0 Ohio Coal
12,858 Btu/lb
9.57% Ash
2.77% Sulfur
3.28% Moisture
2060°F Initial ash deformation temperature
0 Kentucky Coal
13,823 Btu/lb
6.04% Ash
1.49% Sulfur
2.26% Moisture
2070°F Initial ash deformation temperature
KVB 4-15900-544
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OVERFIRE AIR TEST RESULTS; The normal operating practice on this boiler was
to maintain overfire air pressure at 3-4" HoO
for all boiler loads. During three full load
tests the overfire air pressure was increased to
its maximum of about 10" H2O with the following
results. (Section 5.1, page 31)
0 Particulate Loading
Particulate loading dropped an average 40% when overfire pressure
was increased. The percentage of combustible material in the
particulate matter did not drop. (Section 5.1.1, page 31)
0 Nitric Oxide
Nitric oxide emissions increased 2 to 16% when overfire air
pressure was increased. (Section 5.1.2, page 33)
0 Carbon Monoxide
No data is available. The carbon monoxide gas analyzer was
out-of-service during testing at Site I.
0 Boiler Efficiency
Boiler efficiency decreased an average 2.8% when overfire air
pressure was increased. The increased heat losses were bottom
ash combustible losses and dry gas losses. (Section 5.1.3,
page 33)
0 Overfire Air Flow Rate
Overfire air flow rate, as measured by a standard pitot tube,
was shown to account for 14% of the combustion air at full
load and 8% 03. (Section 5.1.4, page 35)
BOILER EMISSION PROFILES; Boiler emissions and efficiency were measured at
loads of 50%, 75% and 100% of the units design
capacity. At the two higher loads, excess oxygen
was varied over the range 5.0 to 10.1% 02- Test
results were as follows. (Section 5.2, page 37)
0 Excess Oxygen Operating Levels
The normal or "as-found" excess oxygen ranged from 8% O2 at
full load to nearly 12% at 50% capacity. (Section 5.2.1,
page 38)
KVB 4-15900-544
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0 Particulate Loading
At full load, uncontrolled particulate loading ranged from 0.90
lb/106 Btu at high overfire air to 1.76 lb/105 Btu at low over-
fire air. Ash carryover averaged 11% for all tests. Particulate
loading increased with increasing excess oxygen. (Section 5.2.2,
page 38)
0 Nitric Oxide Emissions (NO)
At full load, nitric oxide averaged 0.31 lb/106 Btu burning
the Ohio coal and 0.23 lb/106 Btu burning the Kentucky coal.
The slope of NO vs ©2 was 0.014 and 0.010 Ib NO/106 Btu respectively
for the two coals. Nitric oxide concentrations decreased slightly
as load increased under normal firing conditions. (Section
5.2.3, page 41)
0 Combustibles in the Ash
Flyash combustibles ranged from 22 to 37%. Bottom ash com-
bustibles ranged from 14 to 45%. Flyash combustibles increased
with load while bottom ash combustibles decreased with in-
creasing load. (Section 5.2.4, page 46)
0 Boiler Efficiency
Boiler efficiency was highest at full load where it averaged
74.0%. The average was 73.2% at 75% capacity and 69.6% at
50% capacity. Dry gas loss was the primary factor relating
boiler efficiency to load. (Section 5.2.5, page 49)
COAL PROPERTIES; Of the two coals tested, the Kentucky coal was considered
a better coal than the Ohio coal because of its higher Btu
content, lower sulfur, and slightly lower ash and fines.
The observed effect of these coals on emissions efficiency
were as follows. (Section 5.3.3, page 58)
0 Particulate Loading
Both coals produced similar particulate mass loadings.
(Figure 5-4, page 40 and Table 5-13, page 58)
0 Nitric Oxide
Nitric oxide emissions were as much as 36% lower while burning
Kentucky coal than while burning Ohio coal. (Table 5-14, page 59)
0 Sulfur Balance
Sulfur balance on the Kentucky coal was good with 98% of the fuel
sulfur measured in the flue gas and the remaining 2% assumed re-
tained in the ash. Sulfur balance on the Ohio coal was not as
good with 30% more sulfur measured in the flue gas than measured
in the coal. (Table 5-15, page 60)
=1 KVB 4-15900-544
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0 Combustibles in the Ash
Combustibles in the flyash were invarient with coal. Com-
bustibles in the bottom ash were less while firing Kentucky
coal. (Figure 5-9 and 5-10, pages 47 and 48)
0 Boiler Efficiency
Kentucky coal averaged 3% higher boiler efficiency than did
Ohio coal. Combustible heat losses account for the difference.
(Table 5-16, page 61)
PARTICLE SIZE DISTRIBUTION OF FLYASH; Two particle size distribution measure-
ments were made on the uncontrolled
particulate matter in the flyash by
cyclone separation at 1, 3 and 10 micro-
meters. These show that 24% of the
sampled flyash is smaller than 10 micro-
meters. (Figure 5-14, page 62)
SOURCE ASSESSMENT SAMPLING SYSTEM (SASS) ; Flue gas was sampled for polynuclear
aromatic hydrocarbons and trace ele-
ments during one full load test on
each of the two coals. Data will be
presented in a separate report at the
completion of this test program.
(Section 5.4, page 61)
The Test Outline and Emission Data Summary are presented in Tables 2-1
and 2-2 on the following pages. For reference, additional data tables are in-
cluded in Section 5.6. A "Data Supplement" containing all the unreduced data
obtained at Site I is available under separate cover for those who wish to
further analyze the data. The "Data Supplement" has the same EPA document
number as this report except that it is followed by the letter "b" rather than
"a". Copies of this report and the Data Supplement are available through EPA
and the National Technical Information Service (NTIS).
KVB 4-15900-544
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TABLE 2-1
TEST OUTLINE FOR TEST SITE I
FIRING CONDITIONS
TEST MEASUREMENTS BY TEST NUMBER*
% Boiler
Capacity
100
100
100
100
100
75
75
50
Excess
Air
Norm
Norm
Low
Low
Vary
Norm
Vary
Norm
Overfire
Air
Low
High
Low
High
Low
Low
Low
Low
Gaseous
Emissions
2,
3,
6
4,
7,
5,
8
1,
(15)
(18)
9
(16)
(14)
(10)
Particulate Other
Loading Tests
2, (15)
3 (18)SASS & SOx
4 9 SASS & SOx
5, (14)
1, (10)
*Parenthesis "( )" Around Test Numbers Indicate Kentucky Coal.
In Addition to the Above Tests, Test No's 11, 12 and 13 Were
For OFA Flow Rate Measurements.
KVB 4-15900-544
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TABLE 2-2
oo
Test
No.
1
2
3
4
5
6
7a
7b
7c
8a
8b
8c
8d
9
10
14
15
16a
16b
16c
16d
16e
18
Date
4/28/79
4/30/79
5/01/79
5/01/79
5/02/79
5/08/79
5/09/7Q
5/09/79
5/09/79
5/09/79
5/09/79
5/09/79
5/09/79
5/10/79
5/12/79
5/14/79
5/22/79
5/23/79
5/23/79
5/23/79
5/23/79
5/23/79
5/23/79
% Design
Capacity
50
98
103
100
82
99
104
104
104
72
72
72
72
102
48
71
101
102
102
102
102
102
101
Coal*
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
EMISSION DATA SUMMARY
TEST SITE I
Excess
Air, %
120
63
62
43
69
39
50
39
30
84
66
54
45
37
116
88
54
91
68
57
44
38
56
02
%
dry
11.8
8.3
8.3
6.6
8.9
6.1
7.2
6.1
5.0
9.9
8.6
7.6
6.8
5.9
11.6
10.1
7.6
10.1
8.7
7.8
6.6
5.9
7.8
CO2
%
dry
7.6
11.3
11.0
11.6
10.2
12.5
12.1
12.7
13.5
9.5
10.8
11.3
11.9
12.9
8.0
9.3
11.7
10.9
11.5
12.2
13.0
13.6
11.0
NO
lb/106
Btu
0.268
0.213
0.400
0.306
0.288
0.252
0.324
0.285
0.283
0.343
0.330
0.329
0.311
0.295
0.326
0.288
0.236
0.258
0.243
0.221
0.211
0.201
0.255
NO
ppm
dry
179
157
294
225
212
185
238
210
208
252
243
242
229
217
245
213
175
191
180
164
156
149
188
SOx
lb/106
Btu
__
__
__
3.656
1.865
Uncontrolled
Particulate
lb/106Btu
0.541
1.763
0.999
0.904
0.954
0.734
1.341
1.430
* 1 - Ohio Coal,
2 - Kentucky Coal
KVB 4-15900-544
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3.0 DESCRIPTION OF FACILITY TESTED
AND COALS FIRED
This section discusses the general physical layout and operational
characteristics of the boiler tested at Test Site I. The coals utilized in
this test series are also discussed.
3.1 BOILER I DESCRIPTION
Boiler I is a Wickes type RB boiler, built in 1960. The boiler is
designed to operate at a maximum continuous capacity of 70,000 pounds of
steam per hour at 250 psig and saturated temperature. This unit has a Riley
traveling grate stoker with continuous front-end discharge. Coal is
brought to the boiler from the coal bunkers by a weigh lorry and is mass
fed to the grate. There is no suspension burning. Undergrate air can be
controlled by six zones. There is no dust collector, economizer or flyash
reinjection. Design data on the boiler and stoker are presented in Table 3-1.
3.2 OVERTIRE AIR
The overfire air system on Boiler I consists of two rows of air jets
on the front wall. The lower overfire air nozzles are 4-1/2 feet above the
grate at a 45° angle. The upper overfire air nozzles are 6"9" above the
grate, at a 30° angle below horizontal. The overfire air was found to be
operating at about 3" H20. At maximum flow the pressure is about 10"
3.3 TEST PORT LOCATIONS
Emission measurements were made at the stack. Because there was no
dust collector, particulate measurements at this location are equivalent to
boiler outlet measurements. The location of this sampling site is shown in
Figure 3-1 and its geometry is shown in Figure 3-2.
Particulate measurements were made using a 24-point traverse. Gaseous
measurements of 02, C02, and NO were obtained by pulling samples individually
KVB 4-15900-544
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TABLE 3-1
DESIGN DATA
TEST SITE I
BOILER: Manufacturer
Type
Boiler Heating Surface
Design Pressure
Wickes Boiler Company
RB
9500 ft2
250 psig
FURNACE: Volume
3900 ft3
STOKER: Manufacturer
Type
Width
Length
Effective Grate Area
Riley Stoker
Traveling Grate
14'0"
18-1/2"
252.6 ft2
HEAT RATES: Steam Flow
Input to Furnace
Furnace Width Heat Release
Grate Heat Release*
Furnace Liberation
70,000 Ibs/hr
95 xlO6 Btu/hr
5.2 xlO6 Btu/hr-ft
377 xlO3 Btu/hr-ft2
24 xlO3 BtuAr-ft3
* Heat input and heat release rates were determined by KVB
based on available data and are not necessarily those of
the equipment manufacturer.
KVB 4^15900-544
10
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STACK SAMPLING
PLANE
Figure 3-1. Boiler I Schematic
KVB 4-15900-544
11
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59-5/8"
Stack Sampling Plane
Cross Sectional Area = 19.39 ft*
+ Particulate Sampling Points
O Gaseous Sampling Points
A sox
SASS
Figure 3-2. Boiler I Sample Plane Geometry
KVB 4-15900-544
12
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from two probes. SOx measurements and SASS samples for organic and trace
element determinations were obtained from single points within the boiler
duct.
3.4 COALS UTILIZED
Two coals were test fired at Test Site I. These are referred to as
Ohio coal and Kentucky coal in this report. The primary coal tested was the
Ohio coal/ which was supplied by C and W Mining (Columbian County, Lisbon,
Ohio). The secondary coal was a higher Btu coal and it was supplied by
Island Creek Coal Company. It came from the Spurlock mine in Salisbury,
Kentucky.
Coal samples were taken for each test involving particulate or SASS
sampling. The average coal analyses obtained from these samples are pre-
sented in Table 3-2. The analyses of each individual coal sample are pre-
sented in Section 5.0, Test Results and Observations, Tables 5-9, 5-10, and
5-11.
KVB 4-15900-544
13
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TABLE 3-2
AVERAGE COAL ANALYSIS
TEST SITE I
Proximate (As Rec'd)
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu/lb
% Sulfur
Ohio Coal
3.28
9.57
38.02
49.05
12,858
2.77
Kentucky Coal
2.26
6.04
38.79
52.92
13,823
1.49
Ultimate (As Rec'd)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen (diff)
2.96
72.62
4.97
1.26
0.40
1.88
8.37
7.54
2.20
77.23
5.
1.
0.
1.
5.
28
50
13
38
34
6.93
KVB 4-15900-544
14
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4.0 TEST EQUIPMENT AND PROCEDURES
This section details how specific emissions were measured and the
sampling procedures followed to assure that accurate, reliable data were
collected. Note that the carbon monoxide monitor was out-of-service during
testing on this unit.
4.1 GASEOUS EMISSIONS MEASUREMENTS (NOx, CO, CO2, O2, HC)
A description is given below of the analytical instrumentation, re-
lated equipment, and the gas sampling and conditioning system, all of which
are located in a mobile testing van owned and operated by KVB. The systems
have been developed as a result of testing since 1970, and are operational
and fully checked out.
4.1.1 Analytical Instruments and Related Equipment
The analytical system consists of five instruments and associated
equipment for simultaneously measuring the constituents of flue gas. The
analyzers, recorders, valves, controls, and manifolds are mounted on a panel
in the vehicle. The analyzers are shock mounted to prevent vibration damage.
The flue gas constituents which are measured are oxides of nitrogen (NO, NOx),
carbon monoxide (CO), carbon dioxide (CC^), oxygen (O2), and gaseous hydro-
carbons (HC) .
Listed below are the measurement parameters, the analyzer model
furnished, and the range and accuracy of each parameter for the system. A
detailed discussion of each analyzer follows:
Constituent: Nitric Oxide/Total Oxides of Nitrogen (NO/NOx)
Analyzer: Thermo Electron Model 10 Chemiluminescent Analyzer
Range: 0-2.5, 10, 25, 100, 250, 1000, 2500, 10,000 ppm NO
Accuracy: il% of full scale
Constituent: Carbon Monoxide
Analyzer: Beckman Model 315B NDIR Analyzer
Range: 0-500 and 0-2000 ppm CO
Accuracy: ±1% of full scale
KVB 4-15900-544
15
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Constituent: Carbon Dioxide
Analyzer: Beckman Model 864 NDIR Analyzer
Range: 0-5% and 0-20% CC>2
Accuracy: -1% of full scale
Constituent: Oxygen
Analyzer: Teledyne Model 326A Fuel Cell Analyzer
Range: 0-5, 10, and 25% 02 full scale
Accuracy: ±1% of full scale
Constituent: Hydrocarbons
Analyzer: Beckman Model 402 Flame lonization Analyzer
Range: 5 ppm full scale to 10% full scale
Accuracy: ±1% of full scale
Oxides of nitrogen. The instrument used to monitor oxides of nitrogen
is a Thermo Electron chemiluminescent nitric oxide analyzer. The instrument
operates by measuring the cherailuminescent reaction of NO and 03 to form NOn.
Light is emitted when electronically excited NO2 molecules revert to their
ground state. The resulting chemiluminescence is monitored through an optical
filter by a high sensitivity photomultiplier, the output of which is linearly
proportional to the NO concentration.
Air for the ozonator is drawn from ambient air through a dryer and
a ten micrometer filter element. Flow control for the instrument is accomplished
by means of a small bellows pump mounted on the vent of the instrument down-
stream of a separator that prevents water from collecting in the pump.
The basic analyzer is sensitive only to NO molecules. To measure NOx
(i.e., NO+NO2)» the NO2 is first converted to NO. This is accomplished by a
converter which is included with the analyzer. The conversion occurs as the
gas passes through a thermally insulated, resistance heated, stainless steel
coil. With the application of heat, NO2 molecules in the sample gas are re-
duced to NO molecules, and the analyzer now reads NOx. N©2 is obtained by the
difference in readings obtained with and without the converter in operation.
Specifications: Accuracy 1% of full scale
Span stability *1% of full scale in 24 hours
Zero stability il ppm in 24 hours
Power requirements 115ilOV, 60 Hz, 1000 watts
Response 90% of full scale in 1 sec. (NOx mode),
0.7 sec. NO mode
Output 4-20 ma
KVB 4-r 15900-^544
16
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Sensitivity 0.5 ppm
Linearity -1% of full scale
Vacuum detector operation
Range: 2.5, 10, 25, 100, 250, 1000, 2500, 10,000 ppm
full scale
Carbon Monoxide. Carbon monoxide concentration is measured by a
Beckman 315B non-dispersive infrared analyzer. This instrument measures the
differential in infrared energy absorbed from energy beams passed through a
reference cell (containing a gas selected to have minimal absorption of infra-
red energy in the wavelength absorbed by the gas component of interest) and a
sample cell through which the sample gas flows continuously. The differential
absorption appears as a reading on a scale from 0 to 100 and is then related
to the concentration of the specie of interest by calibration curves supplied
with the instrument. The operating ranges for the CO analyzer are 0-500 ppm
and 0-2000 ppm.
Specifications: Span st ,ility il% of full scale in 24 hours
Zero stability -1% of full scale in 24 hours
Ambient temperature range 32°F to 120°F
Line voltage 115-15V rms
Response 90% of full scale in 0.5 or 2.5 sec.
Precision il% of full scale
Output 4-20 ma
Carbon Dioxide. Carbon dioxide concentration is measured by a Beckman
Model 864 short path-length, non-dispersive infrared analyzer. This instrument
measures the differential in infrared energy absorbed from energy beams passed
through a reference cell (containing a gas selected to have minimal absorption
of infrared energy in the wavelength absorbed by the gas component of interest)
and a sample cell through which the sample gas flows continuously. The dif-
ferential absorption appears as a reading on a scale from 0 to 100 and is then
related to the concentration of the specie of interest by calibration curves
supplied with the instrument. The operating ranges for the C02 analyzer are
0-5% and 0-20%.
Specifications: Span stability ±1% of full scale in 24 hours
Zero stability -1% of full scale in 24 hours
Ambient temperature range 32°F to 120°F
Line voltage 115ll5V rms
Response 90% of full scale in 0.5 or 2.5 sec.
Precision -1% of full scale
Output 4-20 ma
17 KVB 4-15900-544
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Oxygen. The oxygen content of the flue gas sample is automatically
and continuously determined with a Teledyne Model 326A Oxygen analyzer.
Oxygen in the flue gas diffuses through a Teflon membrane and is reduced on
the surface of the cathode. A corresponding oxidation occurs at the anode
internally and an electric current is produced that is proportional to the
concentration of oxygen. This current is measured and conditioned by the
instrument's electronic circuitry to give a final output in percent O2 by
volume for operating ranges of 0% to 5%, 0% to 10%, or 0% to 25%.
Specifications: Precision ±1% of full scale
Response 90% in less than 40 sec.
Sensitivity 1% of low range
Linearity ±1% of full scale
Ambient temperature range 32-125°F
Fuel cell life expectancy 40,000%-hours
Power requirement 115 VAC, 50-60 Hz, 100 watts
Output 4-20 ma
Hydrocarbons. Hydrocarbons are measured using a Beckman Model 402
hydrocarbon analyzer which utilizes the flame ionization method of detection.
The sample is drawn to the analyzer through a heated line to prevent the loss
of higher molecular weight hydrocarbons. It is then filtered and supplied to
the burner by means of a pump and flow control system. The sensor, which is
the burner, has its flame sustained by regulated flows of fuel (40% hydrogen
plus 60% helium) and air. In the flame, the hydrocarbon components of the
sample undergo a complete ionization that produces electrons and positive ions.
Polarized electrodes collect these ions, causing a small current to flow through
a circuit. This ionization current is proportional to the concentration of
hydrocarbon atoms which enter the burner. The instrument is available with
range selection from 5 ppm to 10% full scale as 014.
Specifications: Full scale sensitivity, adjustable from 5 ppm CH4 to
10% CH4
Ranges: Range multiplier switch has 8 positions: XI,
X5, X10, X50, X100, X500, XlOOO, and X5000. In
addit n, span control provides continuously variable
adjustment within a dynamic range of 10:1
Response time 90% full scale in 0.5 sec.
Precision il% of full scale
Jlectronic stability ±1% of full scale for successive
identical samples
KVB 4-15900-544
18
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Reproducibility ±1% of full scale for successive
identical samples
Analysis temperature: ambient
Ambient temperature 32°F to 110°F
Output 4-20 ma
Air requirements 350 to 400 cc/min of clean, hydro-
carbon-free air, supplied at 30 to 200 psig
Fuel gas requirements 75 to 80 cc/min of pre-mixed
fuel consisting of 40% hydrogen and 60% nitrogen
or helium, supplied at 30 to 200 psig
Electrical power requirements 120V, 60 Hz
Automatic flame-out indication and fuel shut-off valve
4.1.2 Recording Instruments
The output of the four analyzers is displayed on front panel meters
and are simultaneously recorded on a Texas Instrument Model FL04W6D four-pen
strip chart recorder. The recorder specifications are as follows:
Chart size 9-3/4 inch
Accuracy ±0.25%
Linearity <0.1%
Line voltage 120V±10% at 60 Hz
Span step response: one second
4.1.3 Gas Sampling and Conditioning System
The gas sampling and conditioning system consists of probes, sample
lines, valves, pumps, filters and other components necessary to deliver a
representative, conditioned sample gas to the analytical instrumentation. The
following sections describe the system and its components. The entire gas
sampling and conditioning system shown schematically in Figure 4-1 is con-
tained in the emission test vehicle.
4.1.4 Gaseous Emission Sampling Techniques
Boiler access points for gaseous sampling are selected in the same
sample plane as are particulate sample points. Each probe consists of one-
half inch 316 stainless steel heavy wall tubing. A 100 micrometer Mott Metal-
lurgical Corporation sintered stainless steel filter is attached to each
probe for removal of particulate material.
KVB 4-15900-544
19
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ro
o
Figure 4-1. Plow Schematic of Mobile Flue Gas Monitoring Laboratory
KVB 4-15900-544
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Gas samples to be analyzed for 02, CC>2. CO and NO are conveyed to the
KVB mobile laboratory through 3/8 inch nylon sample lines. After passing
through bubblers for flow control, the samples pass through a diaphragm pump
and a refrigerated dryer to reduce the sample dew point temperature to 35°F.
After the dryer, the sample gas is split between the various continuous gas
monitors for analysis. Plow through each continuous monitor is accurately
controlled with rotometers. Excess flow is vented to the outside. Gas samples
may be drawn both individually and/or compositely from all probes during each
test. The average emission values are reported in this report.
4.2 SULFUR OXIDES CSOx) MEASUREMENT AND PROCEDURES
Measurement of S02 and 803 concentrations is made by wet chemical
analysis using both the "Shell-Emeryville" method and EPA Method 6. In the
Shell-Emeryville method the 713 sample is drawn from the stack through a
glass probe (Figure 4-2), containing a quartz wool filter to remove particu-
late matter, into a system of three sintered glass plate absorbers (Figure 4-3) .
The first two absorbers contain aqueous isopropyl alcohol and remove the sul-
fur trioxide; the third contains aqueous hydrogen peroxide solution which
absorbs the sulfur dioxide. Some of the sulfur trioxide is removed by the
first absorber, while the remainder -, which passes through as sulfuric acid
mist, is completely removed by the secondary absorber mounted above the first.
After the gas sample has passed through the absorbers, the gas train is purged
with nitrogen to transfer sulfur dioxide, which has dissolved in the first
two absorbers, to the third absorber to complete the separation of the two
components. The isopropyl alcohol is used to inhibit the oxidation of sulfur
dioxide to sulfur trioxide before it gets to the third absorber.
The isopropyl alcohol absorber solutions are combined and the sulfate
resulting from the sulfur trioxide absorption is titrated with standard lead
perchlorate solution using Sulfonazo III indicator. In a similar manner, the
hydrogen peroxide solution is titrated for the sulfate resulting from the
sulfur dioxide absorption.
The gas sample is drawn from the flue by a single probe made of
quartz glass inserted into the duct approximately one-third to one-half way.
KVR 4-15900-544
21
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Flue Wsll
Asbestos Plug
Ball Joint
Vycor
Sample Probe
Heating
Tape Pryometer
and
Thermocouple
Figure 4-2. SOx Sample Probe Construction
Spray Trap
Pressure Gauge
Volume Indica
Vapor Trap Diaphragm
Pump
Dry Test Meter
Figure 4-3.
Sulfur Oxides Sampling Train
(Shell-Emeryville)
KVB 4-15900-544
22
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The inlet end of the probe holds a quartz wool filter to remove particulate
matter. It is important that the entire probe temperature be kept above
the dew point of sulfuric acid during sampling (minimum temperature of
260°C). This is accomplished by wrapping the probe with a heating tape.
EPA Method 6, which is an alternative method for determining SC>2
(Figure 4-4), employs an impinger train consisting of a bubbler and three
midget impingers. The bubbler contains isopropanol. The first and second
impingers contain aqueous hydrogen peroxide. The third impinger is left dry.
The quartz probe and filter used in the Shell-Emeryville method is also used
in Method 6.
Method 6 differs from Shell-Emeryville in that Method 6 requires
that the sample rate be proportional to stack gas velocity. Method 6 also
differs from Shell-Emeryville in that the sample train in Method 6 is purged
with ambient air, instead of nitrogen. Sample recovery involves combining
the solutions from the first and second impingers. A 10 ml aliquot of
this solution is then titrated with standardized barium perchlorate.
Two repetitions of Shell-Emeryville and two repetitions of EPA
Method 6 were made during each test.
4.3 PARTICULATE MEASUREMENT AND PROCEDURES
Particulate samples are taken at the same sample ports as the gaseous
emission samples using a Joy Manufacturing Company portable effluent sampler
(Figure 4-5). This system, which meets the EPA design specifications for
Test Method 5, Determination of Particulate Emissions from Stationary Sources
(Federal Register, Volume 36, No. 27, page 24888, December 23, 1971), is used
to perform both the initial velocity traverse and the particulate sample
collection. Dry particulates are collected in a heated case using first a
cyclone to separate particles larger than five micrometers and a 100 mm glass
fiber filter for retention of particles down to 0.3 micrometers. Condensible
particulates are collected in a train of four Greenburg-Smith impingers in an
ice water bath. The control unit includes a total gas meter and thermocouple
indicator. A pitot tube system is provided for setting sample flows to obtain
isokinetic sampling conditions.
KVB 4^15900-544
23
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PROBE (END PACKED'
WITH QUARTZ OK
PVREX WOOL)
STACK WALL
MIDGET IMPINGERS
THERMOMETER
MIDGET BUBBLER
GLASS WOOL
SILICA GEL
DRYING TUBE
ICE BATH
THERMOMETER
PUMP
SURGE TANK
Figure 4-4. EPA Method 6 Sulfur Oxide Sampling Train
KVB 4-15900-544
24
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TEMPERATURE SENSOR
IMPINGER TRAIN OPTIONAL,MAY BE REPLACED
BY AN EQUIVALENT CONDENSER
PITOTTUBE
PROBE
PROBE
TEMPERATURE
SENSOR
/M STACK
HEATED AREA THERMOMETER
THERMOMETER
REVERSE TYPE
PITOTTUBE
THERMOMETERS
DRY GAS METER
CHECK
VALVE
VACUUM
LINE
Figure 4-5. EPA Method 5 Particulate Sampling Train
KVB 4-15900-544
25
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All peripheral equipment is carried in the instrument van. This
includes a scale (accurate to io.l mgj , hot plate, drying oven (212°F), high
temperature oven, desiccator, and related glassware. A particulate analysis
laboratory is set up in the vicinity of the boiler in a vibration-free area.
Here filters are prepared, tare weighed and weighed again after particulate
collection. Also, probe washes are evaporated and weighed in the lab.
4.4 COAL SAMPLING AND ANALYSIS PROCEDURE
Coal samples at Test Site I were taken during each test from the
weigh lorry, as coal was being added to the boiler. The samples were pro-
cessed and analyzed for both size consistency and chemical composition. This
is close enough to the furnace that the coal sampled simultaneously with
testing is representative of the coal fired during testing. In order to col-
lect representative coal samples, ten pounds of coal were taken from each
batch added from the weigh lorry.
The sampling procedure is as follows. At the start of testing one
increment of sample is collected from the weigh lorry. This is repeated for
each batch of coal added during the test Cthree to five hours duration) so
that a 7 to 12 increment sample is obtained. The total sample is then riffled
using a Gilson Model SP-2 Porta Splitter until two representative twenty-point
samples are obtained.
The sample to be used for sieve analysis is air dried overnight.
Drying of the coal is necessary for good separation of fines. If the coal is
wet, fines cling to the larger pieces of coal and to each other. Once dry,
the coal is sized using a six tray Gilson Model PS-3 Porta Screen. Screen
sizes used are 1", 1/2", 1/4", #8 and #16 mesh. Screen area per tray is
14"xl4". The coal in each tray is weighed on a triple beam balance to the
nearest 0.1 gram.
The coal sample for cnemical analysis is reduced to 2-3 pounds by
further riffling and sealed in a plastic bag. All coal samples are sent to
Commercial Testing and Engineering Company, South Holland, Illinois. Each
sample associated with a particulate loading or particle sizing test is given
KVB 4-15900-544
26
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a proximate analysis. In addition, composite samples consisting of one incre-
ment of coal for each test for each coal type receive ultimate analysis, ash
fusion temperature, mineral analysis, Hardgrove grindability and free swelling
index measurements.
4.5 ASH COLLECTION AND ANALYSIS FOR COMBUSTIBLES
The combustible content of flyash is determined in the field by KVB
in accordance with ASTM D3173, "Moisture in the Analysis Sample of Coal and
Coke" and ASTM D3174, "Ash in the Analysis Sample of Coal and Coke."
The flyash sample is collected by the EPA Method 5 particulate sample
train while sampling for particulates. The cyclone catch is placed in a desic-
cated and tare-weighed ceramic crucible. The crucible with sample is heated
in an oven at 230°F to remove its moisture. It is then desiccated to room
temperature and weighed. Th<=> crucible with sample is then placed in an
electric muffle furnace maintained at a temperature of 1400°F until ignition
is complete and the sample has reached a constant weight. It is cooled in a
desiccator over desiccant and weighed. Combustible content is calculated as
the percent weight loss of the sample based on its post 230°F weight.
At Test Site I the bottom ash samples were collected in several in-
crements from the ash pit after testing. These samples were mixed, quartered,
and sent to Commercial Testing and Engineering Company for combustible deter-
mination.
4.6 BOILER EFFICIENCY EVALUATION
Boiler efficiency is calculated using the ASME Test Form for Abbre-
viated Efficiency Test, Revised, September, 1965. The general approach to
efficiency evaluation is based on the assessment of combustion losses. These
losses can be grouped into three major categories: stack gas losses, com-
bustible losses, and radiation losses. The first two groups of losses are
measured directly. The third is estimated from the ABMA Standard Radiation
Loss Chart.
KVB 4-15900-544
27
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Unlike the ASME test in which combustible losses are lumped into
one category, combustible losses are calculated and reported separately for
combustibles in the bottom ash and combustibles in the flyash leaving the
boiler.
4.7 TRACE SPECIES MEASUREMENT
The EPA (IEKL-RTP) has developed the Source Assessment Sampling
System (.SASS) train for the collection of particulate and volatile matter in
addition to gaseous samples (Figure 4-6). The "catch" from the SASS train
is analyzed for polynuclear aromatic hydrocarbons (PAH) and inorganic trace
elements.
In this system, a stainless steel heated probe is connected to an
oven module containing three cyclones and a filter. Size fractionation is
accomplished in the series cyclone portion of the SASS train, which incor-
porates the cyclones in series to provide large quantities of particulate
matter which are classified by size into three ranges:
A) >10 pen Bl 3 ym to 10 ym C) 1 ym to 3 ym
Together with a filter, a fourth cut «1 ym) is obtained. Volatile organic
material is collected in an XAD-2 sorbent trap. The XAD-2 trap is an integral
part of the gas treatment system which follows the oven containing the cyclone
system. The gas treatment system is composed of four primary components:
the gas conditioner, the XAD-2 organic sorbent trap, the aqueous condensate
collector, and a temperature controller. The XAD-2 sorbent is a porous poly-
mer resin with the capability of absorbing a broad range of organic species.
Some trapping of volatile inorganic species is also anticipated as a result
of simple impaction. Volatile inorganic elements are collected in a series
of impingers. The pumping capacity is supplied by two 10 cfm high volume
vacuum pumps, while required pressure, temperature, power and flow conditions
are obtained from a main controller.
KVB 4-15900-544
28
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Filter
Stick T.C.
G»i cooler
l«if>/cooltr
tnct element
collector
Orlflct AH,
nqnetiettc
VtCUUB
9«9«
Orj teit tuter
Figtire 4-6. Source Assessment Sampling System (SASS)
Sampling Train
KVB 4-15900-544
29
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(THIS PAGE INTENTIONALLY LEFT BLANK)
30
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5.0 TEST RESULTS AND OBSERVATIONS
This section of the report presents the results of tests performed
on Boiler I. Observations are made regarding the influence on gaseous and
particulate emissions and on boiler efficiency as the control parameters were
varied. Reference may be made to the Emission Data Summary, Table 2-2, in
the Executive Summary, and to Tables 5-18 through 5-21 at the end of this
section when reading the following discussions.
5.1 OVERFIRE AIR
The overfire air system on Boiler I consisted of two rows of air jets
on the front water wall. Air flow to these jets could be manually controlled
up to a maximum of about eleven inches water pressure. However, normal operating
procedure at this site was to maintain overfire air flow at 3-4" H2O for all
boiler loads.
In order to investigate the effect of overfire air on emissions and
efficiency, the OFA was increased to 8-11" I^O during four tests at full load.
The test data, presented in Table 5-1, indicate that increased overfire air
reduced the particulate mass loading, increased nitric oxide emissions slightly,
and reduced boiler efficiency. Each of these results are discussed further in
the following paragraphs.
Tests were also run to determine the amount of combustion air supplied
by the overfire air system, and to relate overfire air flow rate to static
pressure in the overfire air duct. These tests indicate that overfire air
supplies 14% of the combustion air on Boiler I at full load, 8% 02 and 11"
H2O overfire air pressure.
5.1.1 Particulate Loading vs Overfire Air
Particulate mass loading dropped when overfire air pressure was in-
creased from an average of 3.6 to an average of 10.7" 1^0. The mechanism for
this particulate reduction can be partially attributed to improved flyash burn-
out as seen in the two directly comparable tests, No's. 2 and 3. In these tests
the high overfire air. Test No. 3, resulted in a 43% decrease in particulate
KVB 4-15900-544
31
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TABLE 5-1
EFFECT OF OVERPIKE AIR ON EMISSIONS AND EFFICIENCY
TEST SITE I
TEST NO.
Description
FIRING CONDITIONS
Load, % of Capacity
Grate Heat Release, lO^tu/hr-ft2
Coal
Coal Fines, % Passing 1/4"
Excess Air, %
Overfire Air Static Press., "H20
UNCONTROLLED EMISSIONS
Participate Loading, lb/106Btu
Conbustible Loading, U>/106Btu
Inorganic Ash Loading, Ib/lO^Btu
Combustibles in Flyash, %
Conbustibles in Bottom Ash, %
02, % (dry)
C02, % (dry)
NO, Ib/loSfitu
HEAT LOSSES, %
Dry Gas
Moisture in Fuel
H20 from Combustion of Hj
Combustibles in Flyash
Conbustibles in Bottom Ash
Radiation
Unmeasured
Total Losses
Boiler Efficiency
SET
1 2
Low OFA
Norm 03
98
414
Ohio
37
63
3.2
1.76
0.65
1.12
36.7
24.3
8.3
11.3
~
15.90
0.39
4.57
0.92
2.72
0.55
1.50
26.55
73.45
I
3 I
High OFA
Norm C>2
103
436
Ohio
22
62
10.5
1.00
0.22
0.78
22.0
35.9
8.3
11.0
0.400
16.73
0.34
4.59
0.31
5.05
0.52
1.50
29.04
70.96
SET
1 6
Low OFA
Low O2
99
415
Ohio
25
39
3.0
6.1
12.5
0.252
13.11
0.26
4.37
0.39
4.80
0.55
1.50
24.98
75.02
II
4 1
High OFA
Low Oj
100
422
Ohio
24
43
10.8
0.90
0.23
0.67
25.6
6.6
11.6
0.306
15.20
0.36
4.61
0.33
5.57
0.54
1.50
28.11
71.89
SET
I' IS "
LOW OFA
Norm 02
101
423
Ky
30
54
4.0
1.43
14.1
7.6
11.7
0.236
14.84
0.24
4.45
0.57
0.81
0.54
1.50
22.95
77.05
III
18 I
High OFA
Norm 02
101
430
Ky
11
56
8.0
« .
18.4
7.8
11.0
0.255
17.49
0.19
4.51
0.61
0.92
0.53
1.50
25.75
74.25
KVB 4-15900-544
32
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loading. Slightly over one-half of this decrease can be attributed to im-
proved flyash burnout. The two tests were run with identical total air flows.
Therefore, Test No. 3, the one with higher overfire air, had a slightly lower
air flow through the grate. This lower grate air flow, about 7% lower, may
also have contributed to the particulate reduction. The data are summarized
in Table 5-2 and presented graphically in Figure 5-4 of Section 5.2.
TABLE 5-2
PARTICULATE LOADING VS OVERFIRE AIR
Uncontrolled
Test Overfire Air Particulate Loading
No. "H7O lb/106 Btu
2 3.2 (Norm) 1.76
15 4.0 (Norm) 1.43
3 10.- (High) 1.00
4 10.8 (High) 0.90
5.1.2 Nitric Oxide vs Overfire Air
The nitric oxide (NO) concentration increased slightly when overfire
air pressure was increased. This relationship between NO concentration and
OFA is shown in Figure 5-1. When data from each of the two coals are examined
separately, the high overfire air NO concentrations are shown to be greater
than the low overfire air concentrations by 2 to 16% at the same oxygen levels.
5.1.3 Boiler Efficiency vs Overfire Air
Boiler efficiency decreased an average 2.8% when overfire air pressure
was increased. The effect of overfire air on the pertinent heat loss categories
is summarized in Table 5-3. For complete heat loss data refer back to Table
5-1.
KVB 4-15900-544
33
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ID
»
GO
O
»i
O
O
O
o
o
^ o
GO O
_l O _J
CO
O
O
X
o
"
100% DESIGN CAPACITY
/-* HIGH OFA
LOW OFA
-LJ-
T 1 1
8.00 9.00 10.00
PERCENT (DRY)
0
T~7 I - 1 -
6.00 7.00
EXCESS OXYGEN
: OHIO co«.
con.
FIG. 5-1
NITRIC OXIDE
TEST SITE I
VS. EXCESS OXYGEN
LINES CONNECT THOSE DATA POINTS FOR WHICH EXCESS OXYGEN IS THE ONLY
KNOWN VARIABLE, AND WHICH WERE OBTAINED SUCCESSFULLY ON THE SAME DAY.
4-15900-544
34
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TABLE 5-3
BOILER EFFICIENCY VS OVERFIRE AIR
SELECTED HEAT LOSSES, %
Dry Gas
14.62
16.47
Flyash
Combustibles
0.63
0.42
Bottom Ash
Combustibles
2.78
3.85
BOILER
EFFICIENCY
%
75.17
72.37
Low OFA (avg of tests 2, 6, 15)
High OFA (avg of tests 3, 4, 18)
Heat Loss Difference +1.85 -0.21 +1.07 -2.81
Table 5-3 indicates that increasing the overfire air pressure also
increases the dry gas heat loss. This occurs despite a relatively constant
excess air which averages 52% for the three low OFA tests and 54% for the three
high OFA tests. Also evident is a decrease in heat loss due to combustibles
in the flyash, and an increase in heat loss due to combustibles in the bottom
ash. The increased dry gas and bottom ash combustible heat losses override
the small flyash combustible heat gain resulting in the 2.8% efficiency loss
due to increased overfire air.
For a graphical presentation of the flyash combustible, bottom ash
combustible and boiler efficiency data, and the effect of overfire air change
on this data, look ahead to Figures 5-9, 5-10 and 5-11 in Section 5.2.
5.1.4 Overfire Air Flow Rate
The rate at which air is injected into the furnace above the grate was
measured using a standard pitot tube traverse of the overfire air duct. These
measurements were made at three overfire air settings of 3.5, 7.8 and 10.8"
H2O static pressure. This allows us to plot the relationship between static
pressure and air flow rate, and to use this relationship to determine air flow
rate for any static pressure on Boiler I.
The test data are presented in Figure 5-2 and Table 5-4. From these
data it is calculated that 10.8" H2O of overfire air accounts for 14% of the
combustion air at 100% load and 8% 02- Under "normal" operating conditions of
KYB 4-15900-544
35
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10 15 20
OVERFIRE AIR FLOW RATE, 103LB/HR
25
Figure 5-2.
Relationship Between Overfire Air Flow Rate and Static
Pressure Within the Overfire Air Duct - Test Site I.
KVB 4-15900-544
36
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of 3.5" H2O overfire air pressure, the overfire air accounts for only 8%
of the combustion air. This also assumes 100% load and 8% 02-
In relating overfire air pressure to flow rate, use is made of
Bernoulli's equation for fluid flow through an orifice which predicts that
flow rate will be proportional to the square root of the pressure drop.
For this reason, the Y-axis of Figure 5-2 is the square root of static pres-
sure and the relationship is drawn as a straight line which crosses the XY-
intercept.
TABLE 5-4
OVERFIRE AIR FLOW RATES
Low OFA Med OFA High OFA
Overfire Air Static Pressure, "H2O 3.5 7.8 10.8
Measured OFA Flow Rate, SCF/sec 37.5 56.1 68.6
Measured OFA Flow Rate, Ib/hr 10.1 15.1 18.5
Percent Combustion Air Supplied by OFA* 8% 11% 14%
*Calculated combustion air requirement at
full load and 8% O2 = 134x103 Ib/hr
5.2 EXCESS OXYGEN AND GRATE HEAT RELEASE
Tests were conducted on Boiler I at loads of 50%, 75% and 100% of
the unit's design capacity. At the higher loads, excess air was varied over a
wide range. This section profiles emissions and boiler efficiency as a
function of these two variables.
The units chosen to present this data are percent oxygen, and grate
heat release in Btu/hr-ft^. Grate heat release, which is proportional to
the unit's steam loading, was chosen because it provides a common basis for
comparing this unit's emissions with those of other units tested in this pro-
gram.
KVB 4-15900-544
37
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5.2.1 Excess Oxygen Operating Levels
The excess oxygen operating levels encountered during testing are
shown in Figure 5-3. The normal or "as-found" excess oxygen ranged from a
nominal 8% at full load to nearly 12% at 50% of capacity. This is comparable
to other overfed stokers tested.
All but one of the particulate tests were conducted under normal
excess oxygen conditions. The exception was Test 4, a low 02/ high overfire
air test. Particulate tests are indicated by solid syitibols in Figure 5-3.
Gaseous tests for 02/ CO^ an<3 NO were conducted at all points shown. These
included full load tests ranging all the way from 5.0 to 10.1% 0?, and 75%
load tests ranging from 6.8 to 9.9% C>2.
5.2.2 Particulate Loading vs Oxygen and Grate Heat Release
Figure 5-4 profiles the uncontrolled particulate loading as a function
of grate heat release. The two coals are differentiated by symbol, and the
shaded area encompasses the low overfire air tests to illustrate the reduction
of particulate loading due to high overfire air. This reduction was dis-
cussed previously in Section 5.1.1.
Uncontrolled particulate loading was observed to increase with grate
heat release, tripling in magnitude between 50% of capacity and full load.
At full load, uncontrolled particulate loading ranged from 0.90 lb/106 Btu
at high OFA to 1.76 lb/106 Btu at low OFA, and averaged 1.27 lb/106 Btu.
The average ash carryover was 11% for all tests, but was found to
vary directly with load and inversely with overfire air. Table 5-5 presents
the ash carryover data for the six particulate tests for which complete data
were available.
It is noted that the single Kentucky coal data point indicates a
higher ash carryover than all of the Ohio coal data points. This may be a
trend but more data would be required to establish it as such.
KVB 4-15900-544
38
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o
o
CM
LU
LJ
CC O
LU O
Q_
GO
CD
>-
X
O
CO
CO
LU
CJ
X
CD
o
o
o
100.0 200.0 300.0 400.0 500.0
GRRTE HEflT RELERSE 1000 BTU/HR-SQ FT
: OHIO COHL
KY- con-
VS. GRRTE HERT RELERSE
FIG. 5-3
EXCESS OXYGEN
TEST SITE I
THIS PLOT SHOWS THE RANGE IN OXYGEN LEVEL UNDER WHICH TESTS WERE CONDUCTED
AT SITE I. THE SHADED AREA ENCOMPASSES THE NORMAL OR "AS-FOUND" TEST
CONDITIONS, AND THE SOLID SYMBOLS REPRESENT TEST CONDITIONS FOR THE EIGHT
PARTICULATE TESTS.
4-15900-544
39
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00
o
o
LO
(\J
O
f\J
\ o
CD O
_i in
CD
oc
O
CD
g
LOW OFA
^
HIGH OFA
*"" HIGH 02
HIGH OFA
LOW 02
100.0 200.0 300.0 400.0 500.0
GRRTE HERT RELERSE 1000 BTU/HR-SQ FT
0
: OHIO cow.
: ** con.
FIG. 5-4
BOILER OUT PRRT.
TEST SITE I
VS. GRRTE HERT RELERSE
4-15900-544
40
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TABLE 5-5
Test
No.
2
3
4
5
14
ASH
CARRYOVER VS FIRING CONDIT]
Firing Condition
Load
100%
100%
100%
75%
75%
22
Norm
Norm
Low
Norm
Norm
OFA
Low
High
High
Low
Low
Coal
Ohio
Ohio
Ohio
Ohio
Ky
Ash in Coal
lb/106Btu
7.09
7.10
8.19
8.31
5.40
Ash in Flyash
lb/106Btu
1.116
0.779
0.673
.683
.968
50% Norm
Low Ohio
7.99
0.417
Ash Carryover
15.7
11.0
8.2
8.2
17.9
5.2
Figure 5-5 plots the uncontrolled particulate data as a function of
oxygen. Data sets are connected by lines and labeled to isolate them from
the variables of load and overfire air (OFA). The data shows that particulate
loading increases with increasing oxygen at 75% and 100% load.
5.2.3 Nitric Oxide vs Oxygen and Grate Heat Release
Nitric oxide (NO) concentration was measured during each test in
units of parts per million (ppm) by volume. A chemiluminescent NOx analyzer
was used to make these measurements. The units have been converted from ppm
to lb/106 Btu in this report so that they can be more easily compared with
existing and proposed emission standards. Table 2-2 in the Executive Summary
lists the nitric oxide data in units of ppm for the convenience of those who
prefer these units.
Figure 5-6 presents the nitric oxide data as a function of grate heat
release under the various excess oxygen conditions encountered during testing.
Two trends are evident: NO tends to decrease with increasing load and the
Kentucky coal has lower NO than the Ohio coal under similar load conditions.
This conclusion is further illustrated in Table 5-6.
Figures 5-7 and 5-8 present the nitric oxide data as a function of
oxygen for the two coals tested. Again, there is no evidence of a separation
KVB 4-159QO-544
41
-------
o
o
LO
c\i
o <-" -
\ O
CO O
_J LO
o
CC
LtJ
O
GO
LT> _
-H-
LOW OFA
100% LOAD
75% LOAD
HIGH OFA
100% LOAD
50% LOAD
T
T
T
0
4.00 6.00
EXCESS OXYGEN
A ! LOU LOAD + : MED LORD
FIG. 5-5
BOILER OUT PRRT.
TEST SITE I
8.00 10.00 12.00
PERCENT (DRY)
: HIGH LOflO
VS. EXCESS OXYGEN
4-15900-544
42
-------
O
O
O
LT>
O
O
O _1
-s. O
CD O
_J O
CO
O
O
LLJ
O
i i
X
O
0
100.0 200.0 300.0 400.0 500.0
GRRTE HERT RELERSE 1000 BTU/HR-SQ FT
: OHIO COM.
: KY. COHL
FIG. 5-6
NITRIC OXIDE
TEST SITE I
VS. GRRTE HERT RELERSE
4-15900-544
43
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o
o
o
LO
00 O
-r O
o P
x o
CD O
I O
CO
O
O
X
o
0 o
^ 8
GC < '
OHIO COAL DATA
J-J-
8.00 10.00 12.00
PERCENT (DRY)
I HIGH LORD
0 4.00 6.00
EXCESS OXYGEN
A : L.GU LORD -f- : MED LORD
FIG. 5-7
NITRIC OXIDE
TEST SITE I
TREND LINE DETERMINED BY LINEAR REGRESSION ANALYSIS,
SLOPE = 0.030, COEFFICIENT OF DETERMINATION (R) = 0.60
VS. EXCESS OXYGEN
4-15900-54*
44
-------
o
o
o
LD
UJ Q
Z °
o 2-
^ o
CD O
O
O
x
o
KENTUCKY COAL DATA
T
T
8.00 10.00
PERCENT (DRY)
12.00
: HIGH LORD
T7 1 1
0 4.00 6.00
EXCESS OXYGEN
A : IOM LORD -)- : MED LORD
FIG. 5-8
NITRIC OXIDE
TEST SITE I
TREND LINE DETERMINED BY LINEAR REGRESSION ANALYSIS, SLOPE = 0.021,
COEFFICIENT OF DETERMINATION (R) = 0.94. THIS PLOT SHOWS THAT BOILER
LOAD, AS INDICATED BY THE THREE SYMBOLS, HAS NO APPARENT EFFECT ON
EMISSION LEVEL AT CONSTANT 02.
VS. EXCESS OXYGEN
4-15900-544
45
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by load. Using linear regression analysis on full load Tests 16a through 16e
yields a slope of 0.014 Ib NO/10" Btu increase for each one percent increase
in Op. Using the same technique on 75% capacity Tests 8a through 8d yields
a slope of 0.010 Ib NO/10^ Btu increase for each one percent increase in O2.
TABLE 5-6
AVERAGE NITRIC OXIDE CONCENTRATIONS VS LOAD AND COAL
Nitric Oxide Nitric Oxide
Coal % O0 lb/106 Btu ppm @ 3% O?
225
236
172
213
245
The increase of nitric oxide as load decreases is due to the
accompanying increase in oxygen. On this boiler it appears that boiler
load at constant 02 has little if any effect on nitric oxide emissions.
5.2.4 Combustibles in the Ash vs Grate Heat Release
100% Load
75% Load
50% Load
100% Load
75% Load
50% Load
Ohio
Ohio
Ohio
Ky
Ky
Ky
*
6.5
8.4
11.8
7.8
10.1
11.6
0.306
0.320
0.232
0.288
0.326
Flyash and bottom ash samples were collected during most of the
particulate tests and baked in a high temperature oven for determination of
combustible content. The combustible determinations are plotted as a function
of grate heat release in Figures 5-9 and 5-10.
In general, the percent of combustibles in the flyash increased with
load while combustibles in the bottom ash decreased with load. Overfire air
had the effect of reducing combustibles in the flyash while increasing com-
bustibles in the bottom ash. Kentucky coal had less combustible material in
its bottom ash than did Ohio coal. Flyash combustibles ranged from 22 to 37%
and averaged 27%. Bottom ash combustibles ranged from 14 to 45% and averaged
29%.
KVB. 4-15900-544
46
-------
o
o
o
o
CO
CJ
QC
UJ O
CO
UJ
QQ
OQ
O
CJ
CD
CM
0
HIGH
OFA TESTS
100.0 200.0 300.0 400.0 500.0
GRRTE HERT RELERSE 1000 BTU/HR-SQ FT
: OHIO COM.
: KY. COBL
FIG. 5-9
FLYRSH COMBUSTIBLES
TEST SITE I
VS. GRRTE HERT RELERSE
4-15900-544
47
-------
o
o
o
oo
CJ
oc o
LU .
Q_ O
CD
OQ o
8?
z:
CD
cr
o
o
00
o
(\J
HIGH OFA TESTS
OHIO COAL
HIGH OFA TEST
KENTUCKY COAL
-A
A
0
1 1 1 1 1
100.0 200.0 300.0 400.0 500.0
GRRTE HERT RELERSE 1000 BTU/HR-SQ FT
; OHIO COM.
KT-
FIG. 5-10
BOTTOM RSH COMB.
TEST SITE I
VS. GRRTE HERT RELERSE
4-15900-544
48
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5.2.5 Boiler Efficiency vs Grate Heat Release
Boiler efficiency was determined using the ASME heat loss method for
all tests which included a particulate mass loading or SASS determination.
The boiler efficiencies are plotted in Figure 5-11 as a function of grate heat
release. On the average, boiler efficiency was highest at full load and de-
creased as load decreased. Table 5-7 shows that dry gas loss was the primary
factor causing boiler efficiency to drop at low loads.
TABLE 5-7
BOILER EFFICIENCY VS LOAD
AVERAGE HEAT LOSSES, %
Flyash
Dry Gas Combustibles
100% Load
75% Load
50% Load
15.19
16.47
18.09
0.50
0.46
0.24
Bottom Ash
Combustibles
3.47
3.04
4.81
Radiation
0.54
0.71
1.09
BOILER
EFFICIENCY
Other %
6.28
6.17
6.18
74.02
73.15
69.59
5.3 COAL PROPERTIES
Two coals were tested in Boiler I. These coals are identified in
this report as Ohio and Kentucky (abbreviated Ky) coals. This section discusses
the chemical and physical properties of these two coals, and discusses their
observed influence on boiler emissions and efficiency.
5.3.1 Chemical Composition of the Coals
Representative coal samples were obtained dn-ing each particulate and
SASS test. From each sample, a proximate analysis was obtained. In addition,
an ultimate analysis was obtained on three of the samples and mineral analysis
of the ash was obtained on one sample.
Composite coal samples, containing portions of each individual sample,
were also collected for each coal. The composite samples were given complete
coal analysis including proximate, ultimate, ash fusion and minerals in the ash.
KVB 4-15900-544
49
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O
CD
o
o
LO
CO
o
o
o
f- 00
LU
O
cc o
LU O
Q_ - J
LO
£8
E8'
LU
rr o
n i O
AVG = 73.85%
TEST NO. 1 HAD AN EXCEPTIONALLY
HIGH COMBUSTIBLE LOSS AND DRY
GAS HEAT LOSS
0
T
T
T
100.0 200.0 300.0 400.0 500.0
GRRTE HEflT RELERSE 1000 BTU/HR-SQ FT
OHIO COHL
KY. COHL
FIG. 5-11
BOILER EFFICIENCY
TEST SITE I
VS. GRRTE HERT RELERSE
4-15900-544
50
-------
The moisture, ash and sulfur content of the two coals are compared
on a. heating value basis in Table 5-8. Such a comparison is often more
meaningful than percentage by weight. This table shows the Kentucky coal
to be the better coal in terms of its lower moisture, ash and sulfur, and
its higher heating value.
TABLE 5-8
COAL PROPERTIES CORRECTED TO A CONSTANT 106 BTU BASIS
Ohio Coal Kentucky Coal
Moisture, lb/106Btu 2.6 1.6
Ash, lb/!06Btu 7.4 7.1
Sulfur, lb/106Btu 2.2 1.1
Heating Value, Btu/lb 12,858 13,823
The coal analysis for each individual sample are tabulated in
Tables 5-9, 5-10 and 5-11.
5.3.2 Coal Size Consistency
Coal size consistency was determined for each coal sample obtained
at Site I. The individual coal samples were screened at the site using 1",
1/2", 1/4", #8 and #16 square mesh screens. The results of these screenings
are presented in Table 5-12. It is noted that the Kentucky ccal, which was
considered the better coal in terms of moisture, ash, sulfur and heating
value/ averaged slightly lower fines than the Ohio coal.
The coal size consistency measurements are presented on a statistical
basis in Figures 5-12 and 5-13. Here, the standard deviation of the coal size
consistency measurements are compared with the ABMA recommended limits for
overfed stokers. Both coals are sized on the low fines side of the ABMA recom-
mended limits for overfeed stokers. This sizing is considered acceptable and
should have no undesirable effects on the emissions.
KVB 4-15900-544
51
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16
8 1/4 1/2
SIEVE SIZE DESIGNATION
ABMA Recommended Limits of Coal
Sizing for Overfeed Stokers
Statistical Limits of the Measured
Ohio Coal Size Consitency
Figure 5-12.
Size Consistency of "As-Fired" Ohio Coal vs ABMA
Recommended Limits of Coal Sizing for Overfeed
Stokers - Test Site I.
KVB 4-15900-544
52
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H
1
W
95
80
50
30
20
10
50
16 8 1/4 1/2
SIEVE SIZE DESIGNATION
ABMA Recommended Limits of Coal
Sizing for Overfeed Stokers
Statistical Limits of the Measured
Kentucky Coal Size Consistency
Figure 5-13.
Size Consistency of "As-Fired" Kentucky Coal
vs ABMA Recommended Limits of Coal Sizing
For Overfeed Stokers - Test Site I.
KVB 4-15900-544
53
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TABLE 5-9
FUEL ANALYSIS - OHIO COAL
TEST SITE I
TEST NO.
PROXIMATE (As Rec)
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu/lb
% Sulfur
ULTIMATE (As Rec)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen (diff)
ASH FUSION (Red)
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid
EQUILIBRIUM MOISTURE
HARDGROVE GRINDABILITY
FREE SWELLING INDEX
1234569
4.08 3.76 3.28 3.50 2.69 2.67 2.96
10.09 9.05 9.15 10.37 10.58 9.38 8.37
37.43 38.10 37.96 38.61 38.05 37.84 38.15
48.40 49.09 49.61 47.52 48.68 50.11 50.52
12634 12757 12881 12660 12739 13024 13308
3.50 3.14 2.81 2.83 2.98 2.28 1.88
2.96
72.62
4.97
1.26
0.40
1.88
8.37
7.54
COMP AVG
3.08 3.28
10.07 9.57
38.16 38.02
48.69 49.05
12718 12858
2.95 2.77
3.08
70.30
4.88
1.76
0.16
2.95
10.07
6.80
2060°F
2195°F
2335°F
2465°F
4.43 4.43
50 50
STD
DEV
0.54
0.80
0.36
1.02
240
0.54
__
--
KVB 4-15900-544
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in
ui
TABLE 5-10
FUEL ANALYSIS - KENTUCKY COAL
TEST SITE I
TEST NO.
PROXIMATE (As Rec)
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu/lb
% Sulfur
ULTIMATE (As Rec)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen (diff)
ASH FUSION (Red)
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid
HARDGROVE GRINDABILITY
FREE SWELLING INDEX
10 14
2.47 2.10
5.23 7.32
39.38 37.87
52.92 52.71
14053 13558
1.43 1.75
2.42
76.57
5.34
1.51
0.13
1.43
5.23
7.32
15 18
2.50 1.97
6.14 5.45
38.38 39.53
52.98 53.05
13687 13995
1.46 1.33
1.97
77.88
5.22
1.49
0.13
1.33
5.45
6.53
2065°F
2235 °F
2415°F
2575°F
COMP
2.32
6.46
37.79
53.43
13708
1.43
2.32
76.05
5.15
1.40
0.14
1.43
6.46
7.05
2075°F
2225°F
2365°F
2535°F
48
4
AVG
2.26
6.04
38.79
52.92
13823
1.49
2.20
77.23
5.28
1.50
0.13
1.38
5.34
6.93
48
4
STD
DEV
0.27
0.94
0.80
0.15
239
0.18
0.32
0.93
0.08
0.01
0.00
0.07
0.16
0.56
KVB 4-15900-544
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TABLE 5-11
MINERAL ANALYSIS OF COAL ASH
(PERCENT BY WEIGHT)
TEST SITE I
Coal
Test No.
Silica, Si02
Alumina,
Titania,
Ferric Oxide,
Lime , CaO
Magnesia, MgO
Potassium Oxide, K2O
Sodium Oxide, Na2O
Sulfur Trioxide, 803
Phos. Pentoxide, P2O5
Strontium Oxide, SrO
Barium Oxide, BaO
Manganese Oxide,
Undetermined
Alkalies as Na2O, dry
Silica Value
Base: Acid Ratio
T250 Temperature, °F
% Equilibrium Moisture
Hardgrove Grindability Index
Free Swelling Index
Fouling Index
Slagging Index
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
Ohio
Composite
38.94
23.04
1.22
27.22
2.39
0.81
1.93
0.33
1.55
0.34
0.00
0.04
0.05
2.14
100.00
__
56.14
0.52
2295
4.43
50
0.17
1.52
1.70
0.06
1.19
Kentucky
18
42.57
25.24
1.59
18.87
2.99
0.75
1.48
0.96
3.08
0.26
0.18
0.36
0.02
1.65
100.00
0.11
65.31
0.36
2460
0.35
0.49
0.55
0.02
0.76
Kentucky
Composite
43.98
23.64
1.42
17.78
3.44
0.79
1.75
0.73
3.64
0.28
0.05
0.25
0.02
2.23
100.00
__
66.65
0.35
2470
48
4
0.65
0.03
0.75
KVB 4-15900-544
56
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TABLE 5-12
AS-FIFED COAL SIZE CONSISTENCY
TEST SITE I
PERCENT PASSING STATED SCREEN SIZE
1" 1/2" 1/4" #8 #16
8
o
H
§
Average
95.6
87.9
82.2
79.0
78.1
83.2
85.6
85.2
79.6
63.2
49.7
44.5
48.5
47.7
54.9
59.4
45.4
37.2
21.8
23.7
27.3
25.0
30.8
33.4
17.2
16.2
11.1
12.9
14.3
12.4
14.9
15.5
10.4
10.2
8.2
8.2
10.0
8.7
10.1
10.3
84.5
55.4
30.2
14.1
9.4
10
14
15
18
Comp
Average
94.7
50.8
24.5
31.6
30.3
10.8
24.5
24.3
13.1
17.8
16.0
5.9
13.6
13.2
8.7
KVB 4-15900-544
57
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5.3.3 Effect of Coal Properties on Emissions and Efficiency
The observed influence which changing coal properties had on boiler
emissions and efficiency is discussed below. Frequent references are made
to figures in Section 5.2, Excess Oxygen and Grate Heat Release, which
illustrate the differences in emissions between the two coals.
Excess Oxygen Operating Conditions. In general, both coals were
tested under similar excess oxygen conditions. There are no data indicating
that one coal required more excess oxygen than the other. Figure 5-3 shows
the oxygen levels under which the various tests were run for each coal.
Particulate Mass Loading. The two coals produced similar particulate
mass loadings even though the Kentucky coal was lower in ash. Table 5-13
presents three sets of data where coal is the variable. In each case the
Kentucky coal had less ash than the Ohio coal, but in two out of three cases,
the Ohio coal had a lower particulate mass loading. The differences are viewed
as normal data scatter and, as such, are not given any significance. There are
not enough data here to say with any certainty that one coal produces higher
particulate loadings than the other. For a graphical presentation of this
data refer back to Figure 5-4 in Section 5.2.
TABLE 5-13
PARTICULATE LOADING VS COAL ASH
Ohio Coal
Kentucky Coal
Ohio Coal
Kentucky Coal
Ohio Coal
Kentucky Coal
Boiler
Capacity, %
100
100
75
75
50
50
Ash in Coal
lb/106Btu
7.09
4.49
8.31
5.40
7.99
3.72
Particulate
lb/105Btu
1.76
1.43
0.95
1.34
0.54
0.73
Mass Loading
% of Ash in Coal
25
32
11
25
7
20
KVB 4-15900-544
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Nitric Oxide. Nitric oxide concentrations were as much as 36% lower
for Kentucky coal than for Ohio coal under similar firing conditions. The
reason for this behavior has not been ascertained, but the evidence for it is
strong. Table 5-14 presents three sets of data where coal is the variable.
It is seen that the difference is greatest at full load and high O2-
TABLE 5-14
NITRIC OXIDE VS COAL
Ohio Coal
Kentucky Coal
Ohio Coal
Kentucky Coal
Ohio Coal
Kentucky Coal
Test
No.
3
18
7b
16c
8a
14
Firing Conditions !
% Load
103
101
104
102
72
71
8.3
7.8
6.1
5.9
9.9
10.1
OFA
High
High
Low
Low
Low
Low
Nitric Oxide
lb/106Btu
0.400
0.255
0.285
0.201
0.343
0.288
Difference
-36%
-29%
-16%
The evidence for Kentucky coal's lower nitric oxide concentrations are
illustrated graphically in Figure 5-1 of Section 5.1, and also in Figures 5-7,
and 5-8 of Section 5.2.
It should be noted that Kentucky coal contained 26% less nitrogen on
a heating value basis than did Ohio coal. However, fuel nitrogen and nitric
oxide emissions have not correlated well at previous test sites. Thus, no
conclusions about their relationship will be made until all the data are
examined in the Final Project report.
Sulfur Dioxide. Sulfur dioxide (502) and sulfur trioxide (SO3) were
measured during one test on each of the two coals. Each test consisted of
two repetitions of the Shell Emeryville method and one repetition of EPA Method
6. The test data are presented in Table 5-15 and compared with the sulfur con-
tent of the coal sample obtained during each test.
KVB 4-15900-544
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TABLE 5-15
SULFUR OXIDES VS FUEL SULFUR
lb SOx/106Btu Fuel Sulfur Conversion
Ohio Coal
(Test 9)
Kentucky Coal
(Test 18)
Method
Shell
Meth 6
Shell
Shell
Meth 6
Shell
S02
4.151
3.105
3.554
1.781
2.104
1.675
SO3 Ib/lO^Btu as SO2
0.053
0.058
0.048
0.020
0.008
0.008
2.825
2.825
2.825
1.901
1.901
1.901
Fac tor , %
149
112
128
95
111
89
The conversion factor in Table 5-15 is the percentage of fuel sulfur
which is converted to SC>2 and 503. For Test 9, because the conversion factors
for all three SOx repetitions are greater than 100, it is believed that the
fuel sulfur determination was low. The average conversion factor for Test 18
is 98%, which is the expected value. The remaining two percent of the fuel
sulfur is assumed to be retained in the ash.
Combustibles in the Ash. Combustibles in the flyash were invarient
with coal, averaging 27.1% for five Ohio coal tests and 27.8% for the single
determination on Kentucky coal. These data were presented graphically in
Figure 5-9.
Combustibles in the bottom ash were less while firing Kentucky coal
than while firing Ohio coal. Overall, bottom ash combustibles averaged 34.2%
in the Ohio coal and 16.3% in the Kentucky coal. These data were presented
in Figure 5-10.
Boiler Efficiency. Kentucky coal resulted in a 3% higher boiler
efficiency than Ohio coal. As seen in Table 5-16, combustible heat losses
account for this difference. More specifically, it was the heat loss due to
combustibles in the bottom ash which accounted for the difference.
KVB 4-15900-544
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TABLE 5-16
BOILER EFFICIENCY VS COAL
Ohio Coal (Test 2)
Kentucky Coal (Test 15)
Ohio Coal (Test 3)
Kentucky Coal (Test 18)
Ohio Coal (Test 5)
Kentucky Coal (Test 14)
BOILER HEAT
Dry Gas
15.9
14.8
16.7
17.5
15.6
17.3
Moisture
Related
5.0
4.7
4.9
4.7
4.8
4.6
LOSSES, %
Combus-
tible
3.6
1.4
5.4
1.5
5.2
1.8
Other
2.0
2.0
2.0
2.0
2.2
2.2
BOILER
EFFICIENCY
%
73.5
77.1
71.0
74.3
72.2
74.1
5.4 SOURCE ASSESSMENT SAMPLING SYSTEM (SASS)
Two SASS tests were run at Test Site I. These two tests, nos. 9 and
18, were conducted at full load and high overfire air on each of the two coals.
The SASS samples have been processed by combined gas chromatography/mass
spectroscopy for total polynuclear content, seven specific polynuclear
aromatic hydrocarbons (Table 5-17), and trace elements.
Particle size distribution of the flyash as determined by the three
cyclones in the SASS train are presented in Figure 5-14. All other SASS test
results will be reported under separate cover at the conclusion of this
test program.
KVB 4-15900-544
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w
50
20
0.1
1 3 10
EQUIVALENT PARTICLE DIAMETER, MICROMETERS
Figure 5-14.
Particle Size Distribution of the Uncontrolled
Particulate Matter as Determined by SASS
Gravimetrics - Test Site I.
KVB 4-15900-544
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TABLE 5-17
POLYNUCLEAR AROMATIC HYDROCARBONS
ANALYZED IN THE SITE I SASS SAMPLE
Element Name
7,12 Dimethylbenz ta) anthracene
Dibenz (a,h) anthracene
Benzo (c) phenanthrene
3-methyl cholanthrene
Benzo (a) pyrene
Dibenzo (a,h) pyrene
Dibenzo (a,i) pyrene
Dibenzo (c,g) carbazole
Molecular
Weight
256
278
228
268
252
302
302
267
Molecular
Formula
C20H16
C22H14
Cl8Hl2
C21H16
C20H12
C24H14
C24H14
C20H13N
5.5 DATA TABLES
Tables 5-18 through 5-21 summarize the test data obtained at Test
Site I. These tables/ in conjunction with Table 2-2 in the Executive
Summary, are included for reference purposes.
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TABLE 5-18
PARTICULATE EMISSIONS
Test
No.
01
02
1 03
S 04
8 °5
o 10
ffl
14
15
Coal Load
Type %
Ohio 50.3
Ohio 97.8
Ohio 103.1
Ohio 100.0
Ohio 81.6
Kent 50.3
Kent 71.4
Kent 100 . 0
TEST SITE I
O2 EMISSIONS
% Ib/lO&BtU
11.8 0.541
8.3 1.763
8.3 0.999
6.6 0.904
8.9 0.954
11.6 0.734
10.1 1.341
7.6 1.430
TABLE 5-19
PERCENT COMBUSTIBLES IN
Test
No.
01
02
$ 03
° 04
O
3 05
O
09
AVG
£
BS 15
H O
1° ^
AVG
TEST SITE I
Boiler
Outlet
23.0
36.7
22.0
25.6
28.4
27.1
27.8
27.8
gr/SCF Ib/hr
0.168 31
0.766 180
0.439 106
0.443 85
0.395 66
0.237 31
0.496 79
0.658 130
REFUSE
Bottom
Ash
44.69
24.27
35.89
30.82
35.51
34.24
14.14
18.39
16.27
Velocity
ft/sec
34.01
43.99
47.22
41.37
35.38
28.09
40.15
39.89
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TABLE 5-20
HEAT LOSSES AND EFFICIENCIES
TEST SITE I
i
CO
01
02
03
04
05
06
09
10
14
15
18
cn
8
J
!
a
18.51
15.90
16.73
15.20
15.64
13.11
13.03
17.67
17.29
14.84
17.49
Z
M
CO tJ
M W
O D
S3 &4
0.41
0.39
0.34
0.36
0.27
0.26
0.29
0.22
0.20
0.24
0.19
1
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TABLE 5-21
STEAM FLOWS AND HEAT RELEASE RATES
TEST SITE I
Test
No.
1
2
3
4
5
6
7
8
9
10
14
15
16
18
Capacity
50
98
103
100
82
99
104
72
102
48
71
101
102
101
Steam Flow
Ib/hr
35,207
68,462
72,188
70,000
57,143
68,936
72,727
50,294
71,345
33,488
50,000
70,612
71,087
71,000
Heat Input
106Btu/hr
57.7
102.1
106.3
93.5
69.5
85.2
109.0
83.2
95.1
42.2
59.2
90.9
96.6
85.0
Heat Output
106Btu/hr
35.4
68.9
72.7
70.5
57.5
69.4
73.2
50.6
71.8
33.7
50.3
71.1
71.5
71.5
Front Foot
Heat Release
106Btu/hr-ft
2.59
5.03
5.31
5.15
4.20
5.07
5.35
3.70
5.25
2.46
3.63
5.19
5.23
5.22
Grate
Heat Release
106Btu/hr-ft2
190
369
389
377
308
371
392
271
384
180
269
380
383
382
Furnace
Heat Release
12.3
23.9
25.2
24.4
19.9
24.0
25.4
17.5
24.9
11.7
17.4
24.6
24.8
24.8
NOTE: Steam flow based on steam flow integrator readings.
Heat input based on coal flow rate and heating value.
Heat output based on steam flow and steam enthalpy minus feedwater enthalpy.
Heat release rates based on heat output and 74% boiler efficiency
because heat input data is believed to contain inaccuracies.
KVB 4-15900-544
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APPENDICES
Page
APPENDIX A English and Metric Units to SI Units 68
APPENDIX B SI units to English and Metric Units 69
APPENDIX C SI Prefixes 70
APPENDIX D Emissions Units Conversion Factors 71
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APPENDIX A
CONVERSION FACTORS
ENGLISH AND METRIC UNITS TO SI UNITS
To Convert From
in
ft
ft3
To
cm
m
Multiply By
2.540
6.452
0.3048
0.09290
0.02832
Ib
IbAr
lb/106BTU
g/Mcal
BTU
BTU/lb
BTUAr
J/sec
JAr
BTU/ftAr
BTU/ftAr
BTU/ft2Ar
BTU/ft2/hr
BTU/ft3/hr
BTU/ft3Ar
psia
"H20
Rankine
Fahrenheit
Celsius
Rankine
FOR TYPICAL COAL FUEL
ppm @ 3% 02 (S02)
ppm @ 3% O2 (SO3)
ppm @ 3% O2 (NO)*
ppm @ 3% 02 (N02)
ppm @ 3% 02 (CO)
ppm @ 3% 02 (CH4)
g/kg of fuel**
Kg
Mg/s
ng/J
ng/J
J
JAg
w
w
w
W/m
JAr/m
W/m2
JAr/m2
W/m3
JAr/m3
Pa
Pa
Celsius
Celsius
Kelvin
Kelvin
ng/J (lb/106Btu)
ng/J (Ib/I06stu)
ng/J (lb/!06Btu)
(lb/106Btu)
ng/J
ng/J
ng/J
ng/J
(lb/106Btu)
(Ib/lO^Btu)
(lb/10 Btu)
0.4536
0.1260
430
239
1054
2324
0.2929
1.000
3600
0.9609
3459
3.152
11349
10.34
37234
6895
249.1
C
C
K
K
5/9R-273
5/9(F-32)
C+273
5/9R
0.851
1.063
0.399
0.611
0.372
0.213
(1.98xlO~3)
(2.47xlO-3)
(9.28xlO~4)
(1.42xlO~3)
(8.65xlO~4)
(4.95xlO~4)
(10)
4300
*Federal environmental regulations express NOx in terms of
thus NO units should be converted using the NO2 conversion factor.
**Based on higher heating value of 10,000 Btu/lb. For a heating value
other than 10,000 Btu/lb, multiply the conversion factor by
10,OOO/(Btu/lb).
KVB 4-15900-544
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APPENDIX B
CONVERSION FACTORS
SI UNITS TO ENGLISH AND METRIC UNITS
To Convert From
cm
m
Kg
Mg/s
ng/J
ng/J
J
JAg
J/hr/m
J/hr/m2
J/hr/m3
W
W
W/ro
W/m2 '
W/m3
Pa
Pa
Kelvin
Celsius
Fahrenheit
Kelvin
To
in
in2
ft
ft2
ft3
lb
lb/hr
Ib/lO^TU
g/Mcal
BTU
BTU/lb
BTU/ft/hr
BTU/ft2/hr
BTU/ft3/hr
BTU/hr
J/hr
BTU/ft/hr
BTU/ft2/hr
BTU/ft3/hr
psia
"H20
Fahrenheit
Fahrenheit
Rankine
Rankine
Multiply By
0.3937
0.1550
3.281
10.764
35.315
2.205
7.937
0.00233
0.00418
0.000948
0.000430
0.000289
0.0000881
0.0000269
3.414
0.000278
1.041
0.317
0.0967
0.000145
0.004014
F « 1.8K-460
F = 1.8C+32
R » F+460
R « 1.8K
FOR TYPICAL COAL FUEL
ng/J ppm @
ng/J ppm @
ng/J ppm @
ng/J ppm @
ng/J ppm @
ng/J ppm @
ng/J g/kg c
3% O2 (SO2)
3% 02 (S03)
3% 02 (NO)
3% 02 (N02)
3% O2 (CO)
3% 02 (CH4)
f fuel
1.18
0.941
2.51
1.64
2.69
4.69
0.000233
KVB 4-15900-544
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APPENDIX C
SI PREFIXES
Multiplication
Factor Prefix SI Symbol
1018 exa E
1015 peta P
1012 tera T
10 mega M
K>3 kilo k
10 hecto* h
101 deka* da
10 deci* d
10~2 centi* c
10~3 milli m
10"^ micro y
10~9 nano n
10~12 pico p
10-15 femto f
10"18 atto a
*Not recommended but occasionally used
KVB 4-15900-544
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APPENDIX D
EMISSION UNITS CONVERSION FACTORS
FOR TYPICAL COAL FUEL (HV = 13,320 BTU/LB)
Grains/SCF.
(Dry C12» C02)
S02 N02
PPM
(Dry C 3% 02)
SOx NOx
NOTE: 1. Values in parenthesis can be used for all flue gas constituents such as oxides of carbon,
oxides of nitrogen, oxides of sulfur, hydrocarbons, participates, etc.
2. Standard reference temperature of 530*R was used.
KVB 4-15900-544
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TECHNICAL REPORT DATA
(Please read lasiructions on the reverse before completing)
REPORT NO
EPA-600/7-80-136a
3. RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE Field Tests of Industrial Stoker Coal-
fired Boilers for Emissions Control and Efficiency
ImprovementSite I
5. REPORT DATE
May 1980
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
P.L. Langsjoen, J.O.Burlingame, and
J.E. Gabriels on
9 PERFORMING ORGANIZATION NAME AND ADDRESS
KVB, Inc.
6176 Olson Memorial Highway
Minneapolis, Minnesota 55422
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
EPA-IAG-D7-E681 and
DoE-EF-77-C-01-2609
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development*
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 4-5/79
14. SPONSORING AGENCY CODE
EPA/600/13
15 SUPPLEMENTARY NOTES IERL-RTP project officer is R. Hall. (*)Cosponsors are DoE (W.
Harvey Jr.) and the American Boiler Manufacturers Assn. EPA-600/7-78-136a,
-79-041a,-130a,-147a,-80-064a,-065a,-082a, and -112a are site A-H reports.
16. ABSTRACTr
The report gives results of field measurements made on a 70,000 Ib steam/
hr coal-fired overfeed stoker with traveling grate. The effects of various parameters
on boiler emissions and efficiency were studied. Parameters include overfire air,
excess oxygen, grate heat release, and coal properties. Measurements include 02,
CO2, NO, SO2, SOS, uncontrolled particulate loading, particle size distribution
of the uncontrolled flyash, and combustible content of the ash. In addition to test
results and observations, the report describes the facility tested, coals fired,
test equipment, and procedures. Uncontrolled particulate loading on this unit
averaged 1.2 Ib/million Btu at full load. Full-load NO emissions ranged from
0.2 to 0.4 Ib/million Btu.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATl Field/Group
Air Pollution
Boilers
Combustion
oal
Field Tests
.Oust
Stokers
Improvement
Efficiency
Flue Gases
Fly Ash
Particle Size
Nitrogen Oxides
Sulfur Oxides
Air Pollution Control
Stationary Sources
Combustion Modification
Spreader Stokers
Traveling Grate Stokers
Particulate
Overfire Air
13 B
13A
21B
2 ID
14B
11G
14G
07B
3. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report;
Unclassified
21. NO. OF PAGES
77
2O. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
72
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