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
PA
U.S Environmental Protection Agency
Office of Research and Development
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-80-064a
March 1 980
Field Tests of Industrial
Stoker Coal-fired Boilers
for Emissions Control and
Efficiency Improvement -
Site E
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-600/7-80-064a
March 1980
Field Tests of Industrial
Stoker Coal-fired Boilers for
Emissions Control and Efficiency
Improvement - Site E
by
P.L. Langsjoen, J.O. Burlingame, and J.E. Gabrielson
KVB, Inc.
6176 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: Robert E. Hall (EPA) and William T. 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
-------
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'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 pro-
gram. The participating 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 E were Jim
Burlingame, 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.
11
-------
TABLE OF CONTENTS
Section Page
ACKNOWLEDGEMENTS ii
LIST OF FIGURES V
LIST OF TABLES vi
1.0 INTRODUCTION 1
2.0 EXECUTIVE SUMMARY 3
3.0 DESCRIPTION OF FACILITY TESTED AND COALS FIRED 9
3.1 Boiler E Description 9
3.2 Overfire Air System 9
3.3 Particulate Collection Equipment 13
3.4 Test Port Locations 13
3.5 Coals Utilized 13
4.0 TEST EQUIPMENT AND PROCEDURES 17
4.1 Gaseous Emissions Measurements (NOx, CO, CO2, O2, HC) . . 17
4.1.1 Analytical Instruments and Related Equipment ... 17
4.1.2 Recording Instruments 21
4.1.3 Gas Sampling and Conditioning System 21
4.1.4 Gaseous Emission Sampling Techniques 21
4.2 Sulfur Oxides (SOx) Measurement and Procedures 23
4.3 Particulate Measurement and Procedures 25
4.4 Particle Size Distribution Measurement and Procedures . . 27
4.5 Coal Sampling and Analysis Procedure 28
4.6 Ash Collection and Analysis for Combustibles 30
4.7 Boiler Efficiency Evaluation 31
4.8 Trace Species Measurement 31
5.0 TEST RESULTS AND OBSERVATIONS 35
5.1 Overfire Air 35
5.1.1 Overfire Air Flow Rate Measurements 35
5.1.2 Particulate Loading vs Overfire Air 37
5.1.3 Nitric Oxide vs Overfire Air 41
5.1.4 Boiler Efficiency vs Overfire Air 41
5.2 Excess Oxygen and Grate Heat Release 44
5.2.1 Excess Oxygen Operating Levels . . : 44
5.2.2 Particulate Loading vs Oxygen and Grate Heat
Release 46
, 5.2.3 Stack Opacity vs Oxygen and Grate Heat Release . . 48
5.2.4 Nitric Oxide vs Oxygen and Grate Heat Release . . 50
5.2.5 Carbon Monoxide vs Oxygen and Grate Heat Release . 54
5.2.6 Combustibles vs Oxygen and Grate Heat Release . . 64
5.2.7 Boiler Efficiency vs Oxygen and Grate Heat Release 64
111
-------
TABLE OF CONTENTS
(Continued)
Section Page
5.3 Coal Properties 65
5.3.1 Chemical Composition of the Coals 67
5.3.2 Coal Size Consistency 72
5.3.3 Sulfur Balance 77
5.4 Particle Size Distribution of Flyash 77
5.5 Efficiency of Multiclone Dust Collector 83
5.6 Source Assessment Sampling System 83
APPENDICES 91
-------
LIST OF FIGURES
Figure
No. Page
3-1 Boiler E Schematic 12
3-2 Boiler E Sampling Plane Geometry 14
4-1 Flow Schematic of Mobile Flue Gas Monitoring Laboratory ... 22
4-2 SOx Sample Probe Construction 24
4-3 Sulfur Oxides Sampling Train (Shell-Emeryville) 24
4-4 EPA Method 5 Particulate Sampling Train . .- 26
4-5 Brink Cascade Impactor Sampling Train Schematic 29
4-6 Source Assessment Sampling System (SASS) Flow Diagram .... 32
5-1 Pressure Flow Relationship, Overfire Air System 38
5-2 Particulate Loading Breakdown for Kentucky Coal as a Function
of Overfire Air Conditions 39
5-3 Oxygen vs Grate Heat Release 45
5-4 Boiler Out Part, vs Grate Heat Release 47
5-5 Multiclone Out Part, vs Grate Heat Release 49
5-6 Stack Opacity vs Grate Heat Release 51
5-7 Stack Opacity vs Multiclone Out Part 52
5-8 Nitric Oxide vs Grate Heat Release 53
5-9 Nitric Oxide vs Oxygen 55
5-10 Nitric Oxide vs Oxygen 56
5-11 Nitric Oxide vs Oxygen 57
5-12 Nitric Oxide vs Oxygen 58
5-13 Trend in Nitric Oxide Emissions as a Function of Grate Heat
Release (GHR) and Oxygen 59
5-14 Carbon Monoxide vs Grate Heat Release 60
5-15 Carbon Monoxide vs Oxygen 61
5-16 Boiler Out Comb vs Grate Heat Release 62
5-17 Bottom Ash Comb vs Grate Heat Release 63
5-18 Boiler Efficiency vs Grate Heat Release 66
5-19 Size Consistency of "As Fired" Kentucky Coal vs ABMA
Recommended Sizing for Spreader Stokers 74
5-20 Size Consistency of "As Fired" Crushed Kentucky Coal vs ABMA
Recommended Sizing for Spreader Stokers 75
5-21 Size Consistency of "As Fired" Eastern Kentucky Coal vs ABMA
Recommended Sizing for Spreader Stokers 76
5-22 Particle Size Distribution at the Economizer Outlet from
Brink Cascade Impactor Tests 81
5-23 Particle Size Distribution at the Boiler Outlet from SASS
Cyclone Tests 82
5-24 Multiclone Eff vs Grate Heat Release 85
-------
LIST OF TABLES
Table
No.
2-1 Emission Data Summary 8
3-1 Design Data 10
3-2 Predicted Performance 11
3-3 Average Coal Analysis 15
5-1 Over fire Air Flow Rates 36
5-2 Effect of Overfire Air on Emissions and Efficiency, Kentucky
Coal 40
5-3 Nitric Oxide Emissions vs Overfire Air 42
5-4 Combustibles in Flyash vs Overfire Air 43
5-5 Ash Carryover vs Coal Type 48
5-6 Average Heat Losses by Coal Type 65
5-7 Coal Properties Corrected to a Constant lO^Btu Basis .... 67
5-8 Fuel Analysis - Kentucky Coal 68
5-9 Fuel Analysis - Crushed Kentucky Coal 69
5-10 Fuel Analysis - Eastern Kentucky Coal 70
5-11 Mineral Analysis of Coal Ash 71
5-12 Relationship Between Coals Fired and Emissions 72
5-13 As Fired Coal Size Consistency 73
5-14 Sulfur Balance 78
5-15 Description of Particle Size Distribution Tests 79
5-16 Results of Particle Size Distribution Tests 80
5-17 Efficiency of Multiclone Dust Collector 84
5-18 Polynuclear Aromatic Hydrocarbons Sought in the Site E
SASS samples 86
5-19 Particulate Emissions 87
5-20 Heat Losses and Efficiencies 88
5-21 Summary of Percent Combustibles in Refuse 89
5-22 Steam Flows and Heat Release Rates 90
VI
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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 infor-
mation 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 equip-
ment 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
facilitate 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 reinjection,
overfire 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 fifth 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 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 con-
taining 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 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 interest of the host boiler facilities, each test
site in this program has been given a letter designation. As the fifth
site tested, this is the Final Technical Report for Test Site E under the
program entitled "A Testing Program to Update Equipment Specifications and
Design Criteria for Stoker Fired Boilers."
-------
2.0 EXECUTIVE SUMMARY
A spreader stoker rated at 180,000 Ibs steam/hour was tested for
emissions and efficiency between November 15, 1978, and January 19, 1979.
This stoker was unique in that it had been recently retrofitted to use paint
oven exhaust gases as combustion air. The paint oven exhaust gases contained
between 14.5 and 20.5% oxygen. A side effect of this retrofit was a reduced
steaming capacity. Maximum obtainable load during the period these tests were
run was in the range 110-125 thousand pounds of steam per hour. This repre-
sents a 30% reduction in design capacity.
All but three of the tests run on this boiler used the paint oven
exhaust gases as combustion air. The three tests run on ambient air resulted
in similar emission levels and boiler efficiencies to those run on paint oven
exhaust gases. The three ambient air tests are indicated on all plots in this
report with solid symbols to differentiate them from tests run on paint oven
exhaust gases.
Unfortunately, the test plan for Test Site E was not completed due to
the unanticipated boiler loading limitations and the difficulty in obtaining
ambient air test data. This section summarizes the results of those tests
completed at Test Site E, and provides references to supporting figures, tables
and commentary found in the main text of this report.
UNIT TESTED; Described in Section 3.0, pages 9-13.
0 Riley Boiler
Built 1973
Type VOSP
180,000 Ib/hr rated capacity
175 psig operating steam pressure
427°F steam leaving superheater
Economizer
0 Riley Spreader Stoker
Four overthrowing type feeders
Traveling grate with front ash discharge
Flyash reinjection from boiler hopper only
Two rows OFA jets on rear wall
One row OFA jets and one row underfeeder air jets on front wall
-------
COALS TESTED; Individual coal analysis results given in Tables 5-8, 5-9,
5-10 and 5-11, pages 68-71. Commentary in Section 3.0, pages
13, 15. Coal analyses are summarized below.
0 Kentucky Coal
12,773 Btu/lb
8.52% Ash
0.86% Sulfur
6.13% Moisture
2700+°F Initial ash deformation temperature
0 Crushed Kentucky Coal
12,831 Btu/lb
9.08% Ash
0.71% Sulfur
5.69% Moisture
2700+°F Initial ash deformation temperature
0 Eastern Kentucky Coal
12,722 Btu/lb
8.21% Ash
0.78% Sulfur
6.31% Moisture
2700+°F Initial ash deformation temperature
OVERFIRE AIR TEST RESULTS; Overfire air (OFA) pressure was the independent
variable on several tests. Normal operation is
high pressure on the front upper, front lower and
rear lower jets, and low pressure on the rear
upper jets. Variations to the rear upper and lower
OFA pressures were examined with the following
results. (Section 5.1, pages 35-43.
0 Particulate Loading
Changing the rear overfire air pressures had no significant effect
on particulate mass loading (Section 5.1.2, pages 37-41;
Figure 5-2, page 39; Table 5-2, page 40.
0 Nitric Oxide
Changing the rear overfire air pressures had no significant effect
on nitric oxide concentrations (Section 5.1.3, page 41; Table
5-3, page 42)
0 Boiler Efficiency
Changing the rear overfire air pressures had no significant effect
on boiler efficiency (Section 5.1.4, page 41; Table 5-4, page 43.
-------
BOILER EMISSION PROFILES; Boiler emissions were measured over the load range
46-73% of design capacity which corresponds to a
grate heat release range of 274,000 to 604,000
Btu/hr-ft2. Measured oxygen levels ranged from
3.9-10.0%. The range of values and trends of the
various emissions are summarized below (Section
5.2, pages 44-65).
0 Excess Oxygen Operating Levels
The excess oxygen operating level was within the normal range for
a spreader stoker. At 70% of design capacity the unit success-
fully operated at 5.9% 02- In one test the unit was operated at
3.9% C>2 but the resulting particulate loading and opacity were
excessive. The design excess air on this unit is 30%, or 5.3% 02-
The data indicates that this level could be easily met at design
capacity (Section 5.2.1, pages 44-46, Figure 5-3, page 45).
0 Particulate Loading
Boiler outlet and dust collector outlet particulate loadings both
showed an increasing trend with increasing grate heat release.
At high grate heat release above 500x103Btu/hr-ft2, boiler outlet
particulate loadings averaged 5.51±0.66 lb/106Btu, and dust
collector outlet particulate loadings averaged 1.90^1.49. Reducing
the excess air to 3.9% 02 resulted in excessively high particulate
loadings of 6.5 lb/106Btu at the boiler outlet and 3.8 lb/106Btu
at the dust collector outlet (Section 5.2.2, pages 46-48,
Figures 5-4, 5-5, pages 47, 49) .
0 Stack Opacity
Stack opacity was measured with a transmissometer which was not
checked for calibration. Opacity readings ranged from 17 to 55%.
Opacity showed no trend with grate heat release but did correlate
with dust collector outlet particulate loading (Section 5.2.3,
pages 48-50; Figures 5-6, 5-7, pages 51, 52).
0 Nitric Oxide
At high grate heat release, above 500xlO%tu/hr-ft2, nitric oxide
(NO) averaged 0.533^0.047 lbs/106Btu and increased with increasing
oxygen at a rate of 0.037 lbs/106Btu increase in NO for each one
percent increase in ©2- There is some evidence that the paint
oven exhaust gases produced higher NO levels than ambient air did
(Section 5.2.4, pages 50-54; Figures 5-8 through 5-13, pages
53, 55-59).
0 Carbon Monoxide
Limited data shows that carbon monoxide (CO) concentrations were
at insignificant levels of less than 150 ppm (0.015%). The data
shows a decreasing trend in CO with increasing grate heat release.
CO data was insufficient to establish any trend with oxygen.
(Section 5.2.5, pages 54-61; Figures 5-14, 5-15, pages 60-62).
-------
0 Combustibles in Ash
Combustibles in the boiler outlet flyash averaged 66% by weight
and accounted for an average 4.4% heat loss. They showed an
increasing trend with increasing grate heat release and were
not affected by the change in combustion air composition. Com-
bustibles in the bottom ash averaged ten percent by weight and
accounted for an average 0.87% heat loss. Bottom ash combustibles
were invariant with grate heat release and combustion air com-
position (Section 5.2.6, page 61; Figures 5-16, 5-17, pages
63-64).
BOILER EFFICIENCY; Boiler efficiency was determined for sixteen tests using
the ASTM heat loss method. At high grate heat release,
above SOOxlcPBtu/hr-ft^, boiler efficiency averaged 79.88%.
Design efficiency on the boiler was 80.41% based on Ohio
coal. Boiler efficiency showed a decreasing trend with
increasing grate heat release and was invariant with com-
bustion air composition (Section 5.2.7, pages 61-65;
Figure 5-18, page 66; Table 5-6, page 65; Table 5-20, page
88).
COAL PROPERTIES; Emissions and boiler efficiency were studied to determine
any effects which could be related to differences in the
properties of the three coals fired. Very few coal related
differences were found due to the similarities of the three
coals (Section 5.3, pages 65-77).
0 Particulate Loading
Crushed Kentucky coal showed the highest particulate loadings at
the dust collector outlet. Coal was not a factor at the boiler
outlet (Figure 5-5, page 49; Figure 5-4, page 47).
0 Opacity
Crushed Kentucky coal showed the highest opacity of the three
coals (Figure 5-6, page 51).
0 Nitric Oxide
Crushed Kentucky coal had the highest NO, East Kentucky coal had
the lowest NO (Figure 5-8, page 53).
0 Combustibles in Ash
East Kentucky coal had the lowest combustible level in the boiler
outlet flyash. Coal was not a factor in bottom ash combustibles
(Figures 5-16, 5-17, pages 63-64).
0 Boiler Efficiency
No correlation found.
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PARTICLE SIZE DISTRIBUTION: Size distribution of the flyash was measured twice
at the boiler outlet using SASS cyclones, and
twice at the economizer outlet using a Brink
Cascade Impactor. In general, test results show
that ten percent of the boiler outlet flyash was
below 3 ym in diameter, and 25% was below 10 ym.
(Section 5.4, pages 77-83; Tables 5-15, 5-16,
pages 79-80; Figures 5-22, 5-23, pages 81, 82.)
EFFICIENCY OF MULTICLONE DUST COLLECTOR; Dust collector efficiency was deter-
mined in thirteen tests. Apparent plugging of the
collector tubes resulted in a deterioration of
collection efficiency with time. Efficiency averaged
87% during the first month of testing and 55%
during the second month. Design efficiency of the
collector was 96% based on a dust loading of 15%
under 10 ym. (Section 5.5, page 83; Table 5-17,
page 84; Figure 5-24, page 85.)
SOURCE ASSESSMENT SAMPLING SYSTEM: Flue gas was sampled for polynuclear aromatic
hydrocarbons and trace elements during one test on
Kentucky coal and one test on Eastern Kentucky coal.
Data from these tests will be presented in a
separate report at the completion of this test
program. (Section 5.6, page 83; Table 5-18,
page 86.)
The emissions data are summarized in Table 2-1 on the following page.
Other data tables are included at the end of Section 5.0, Test Results and
Observations. For reference, a Data Supplement containing all the unreduced
data obtained at Site E is available under separate cover but with the same
title followed by the words "Data Supplement," and having the same EPA document
number followed by the letter "b" rather than "a". Copies of this report and
the Data Supplement are available through EPA and NTIS.
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TABLE 2-1.
EMISSION DATA SUMMARY - TEST SITE E
Test
No.
02
03
04
05
06
07
08
09
lOa
lOb
lOc
lOd
lOe
11
12
13
14
15
16
17
18a
18b
18c
18d
19
20
%
Design
Date Capacity
11/16/78
11/18/78
11/20/78
11/21/78
12/12/78
12/13/78
12/15/78
12/16/78
12/17/78
12/17/78
12/17/78
12/17/78
12/17/78
12/18/78
12/20/78
12/20/78
12/20/78
1/05/79
1/08/79
1/10/79
1/12/79
1/12/79
1/12/79
1/12/79
1/17/79
1/18/79
61
46
73
62
65
67
61
57
61
61
61
61
61
62
65
48
69
70
62
62
65
65
65
65
—
63
4 * <>2 in1
Coal Comb Air
Ky
Ky
Ky
Ky
Ky
Ky
Ky
Ky
Ky
Ry
Ky
Ky
Ky
Ky
Cr Ky
Cr Ky
Cr Ky
East Ky
East Ky
Ky
Ky
Ky
Ky
Ky
—
Ky
16.6
20.9
16.3
15.7
14.7
19.6
20.3
20.9
—
—
—
—
—
19.9
19.9
19.9
18.7
20.4
19.7
19.5
—
—
—
—
—
20.9
Excess
Test Air
Description %
Baseline
Low Load- Arab Air
Maximum Load
Medium Load
Low RU, RL OFA
Low FL, RL OFA
High Balanced OFA
Me d Load-Arab Air
Vary OFA-Baseline
-Low RU
-High Balanced
-Low RL
-Low Balanced
Low Rear OFA
Baseline
Low Load
High Load
Baseline
SASS-SOx
SASS-SOx
Vary 02 -Low
-Medium
-High
-Medium
OFA Velocity
High Load-Amb Air
52
67
47
83
70
29
43
53
53
52
85
59
60
40
35
73
19
35
60
37
62
70
82
74
—
45
02
%
7.6
8.8
7.2
9.9
9.0
5.2
6.8
7.7
7.7
7.6
10.0
8.2
8.3
6.5
5.9
9.2
3.9
5.9
8.3
6.2
8.4
9.0
9.8
9.3
—
7.0
C02
%
12.0
11.1
12.5
9.7
11.7
13.9
12.5
11.6
11.4
11.6
9.9
11.1
11.3
12.9
12.9
10.1
14.5
13.5
11.0
13.4
11.2
10.6
10.0
10.0
—
12.3
CO
ppm
81
100
38
83
62
147
DOS
DOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
OOS
NO
PP"!
480
372
421
477
456
367
367
368
424
404
439
423
435
357
393
483
454
385
360
389
358
421
435
428
--
405
NO N022
lb/106Btu lb/106Btu
0.645
0.500
0.566
0.641
0.614
0.494 0.000
0.493 -0.005
0.496 -0.001
0.571
0.544
0.591
0.570
0.481
0.480
0.528 -0.003
0.650 -0.001
0.610
0.518 0.000
0.486
0.524
0.482
0.567
0.586
0.576
—
0.545
Boiler Out
Part
lb/106Btu
3.464
2.960
4.972
6.188
2.060
5.230
4.493
3.984
—
—
—
—
4.316
3.509
3.631
6.469
5.380
—
--
—
—
—
—
—
0.785
D.C. Out
Part
lb/106Btu
2.9663
0.313
0.198
0.271
0.335
1.824
0.190
0.641
—
—
—
—
1.558
1.852
1.460
3.843
1.746
—
—
__
—
—
—
—
2.408
Stack
Opac i ty
%
24
34
28
20
17'
45
38
32
25
25
25
25
25
46
33
45
55
38
31
48
33
33
33
33
—
43
00
1Paint oven exhaust fumes used on all but three tests, Test Nos. 3, 9, 20 used anibient air.
2The negative NC>2 concentrations result from limitations to instruments resolution and may be
considered as zero readings.
No. 2 particulates were measured at boiler outlet and economizer outlet. All other
particulate tests were at boiler outlet and dust collector outlet.
^Maximum obtainable load was restricted to 73% of design capacity due to retrofit combustion
air system.
— means data not obtained; OOS means instrument out of service.
-------
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 E. The coals utilized in
this test series are also discussed.
3.1 BOILER E DESCRIPTION
Boiler E is a Riley (VOSP) unit, designed for 250 psig, and capable
of a maximum continuous capacity of 180,000 pounds of steam per hour at 175
psig and a final superheated steam temperature of 427°F using feedwater at
220°F. The unit has a Riley Stoker Company traveling grate spreader stoker,
with a front end ash discharge. Undergrate air utilizes paint oven exhaust
gases. Design data on the boiler and stoker are presented in Table 3-1.
Predicted performance data are given in Table 3-2. A side elevation of the
boiler is shown in Figure 3-1.
The boiler is equipped with a Western Precipitator multiclone dust
collector. The collector has a predicted collection efficiency of 96%,
assuming that 15% of the particles are under ten micrometers.
3.2 OVERFIRE AIR SYSTEM
The overfire air system on Boiler E consists of two rows of air jets
on the back wall and two rows of jets on the front wall. The configuration
of the overfire air system is described below:
Front Upper Row: 8 jets:
6' 6" above grate
15° below horizontal
Rear Upper Row: 8 jets
6' 0" above grate
Horizontal
Rear Lower Row: 8 jets
2' 0" above grate
Horizontal
-------
TABLE 3-1
DESIGN DATA
TEST SITE E
BOILER:
Type
Boiler Heating Surface
Water Wall Heating Surface
Design Pressure
Tube Diameter
Riley (VOSP) Boiler
13,639 ft2
2,551 ft2
250 psi
3.5"
SUPERHEATER:
Heating Surface
No. of Steam Passes
480
1
ECONOMIZER:
Type
Heating Surface
Tube
6,350 ft2
FURNACE
Volume
Width (centerline to centerline waterwall
tubes)
Depth (front to back)
Height (mean)
10,255 ft3
16 '11- 3/4"
21 '06- 3/8"
32' 0"
STOKER:
Stoker Type
Grate Type
Grate Width
Grate Length
Effective Grate Area
Riley Spreader (4 feeders)
Traveling (front discharge)
16'0"
23'0"
344 ft2
HEAT RATES:
Maximum Continuous Steam Capacity
Input to Furnace
180,000 Ibs/hr
232xl06Btu/hr
10
-------
TABLE 3-2
PREDICTED PERFORMANCE
TEST SITE E
Steam Leaving Superheater
Fuel
Excess Air Leaving Boiler
Coal Flow
Flue Gas Leaving Boiler
Steam Pressure at SH Outlet
Economizer to Drum Pressure Drop
Temperature Steam Leaving Superheater
Temperature Flue Gas Leaving Boiler
Temperature Flue Gas Leaving Economizer
Temperature Water Entering Economizer
Temperature Water Leaving Economizer
Furnace Draft Loss
Boiler Draft Loss
Economizer Draft Loss
Damper and Duct Draft Loss
Dust Collector Draft Loss
Total Draft Loss
Dry Gas Heat Loss
H20 and H2 in Fuel Heat Loss
Moisture in Air Heat Loss
Unburned Combustible Heat Loss
Radiation Heat Loss
Unaccounted for and Manufacturers Margin
Total Heat Loss
Efficiency of Unit
180,000 lbs/hr
Ohio Coal *
30%
21,100 lbs/hr
247,000 lbs/hr
175 psig
20 psig
427°F
600°F
350°F
220°F
310°F
0.15 "H20
1.08 "H2O
3.94 "H2O
0.77 "H2O
2.96 "H2O
8.90 "H2O
6.55 %
5.18 %
0.16 %
5.80 %
0.40 %
1.50 %
19.59 %
80.41 %
*Predicted performance is based on combustion air entering at 80°F and
coal fuel containing 10% moisture, 2.5% sulfur, 4.5% H2, 1.2% N2,
62.2% C, 7.6% O2, 12% ash.
11
-------
PAINT OVEN EXHAUST
GAS INLET
Figure 3-1. Boiler E Schematic
a - Boiler Outlet Sampling Plane
b - Economizer Outlet Sampling Plane
c - Dust Collector Outlet Sampling Plane
12
-------
Rear Lower Row: 8 jets
2'0" above grate
Horizontal
3.3 PARTICULATE COLLECTION EQUIPMENT
The boiler is equipped with a Western Precipitator multiclone dust
collector. The multiclone's collection efficiency deteriorated during the
testing period, probably due to dust buildup.
3.4 TEST PORT LOCATIONS
Emissions measurements were made at three locations — at the boiler
outlet (before the economizer), after the economizer, and at the dust collector
outlet. The locations of these sample sites are shown in Figure 3-1. Their
geometry is shown in Figure 3-2.
Whenever particulate loading was measured it was measured simultaneously
at both locations using 24-point sample traverses. Gaseous measurements of O2,
CX>2, CO and NO were obtained by pulling samples individually and compositely
from six probes distributed along the width of the boiler outlet duct. SOx
measurements and SASS samples for organic and trace element determinations
were each obtained from single points within the boiler outlet duct. A heated
sample line was attached to one of the middle gaseous probes at the boiler out-
let. Its purpose was to eliminate losses due to condensation when measuring
N02 and unburned hydrocarbons.
3.5 COALS UTILIZED
Three coal types were fired at Test Site E. These were an Eastern
Kentucky coal, a Kentucky coal and a crushed Kentucky coal. Coal samples were
taken for each test involving particulate or SASS sampling. The average analyses
obtained from these samples are presented in Table 3-3. The analyses show that
the three coals are quite similar in their composition, based on both proximate
and ultimate analyses. The analyses of each individual coal sample are pre-
sented in Section 5.0, Test Results and Observations, Tables 5-7 through 5-10.
13
-------
Boiler Outlet Sampling Plane
Cross Sectional Area = 98.64 ft2
5 '7"
1 '
0 ©
* "
* *
A
1 I 1 1
.
...
0 O El
O
ii M ii
17 '8"
•
•
•
0
1 1
4'2'
Economizer Outlet Sampling Plane
Cross Sectional Area = 73.61 ft2
O
17'8"
Multiclone Dust Collector Outlet Sampling Plane
Cross Sectional Area = 38.50 ft2
5'6'
0
• Particulate Sampling Points
O Gaseous Sampling Points
SOx
D SASS
Figure 3-2. Boiler E Sampling Plane Geometry
14
-------
TABLE 3-3
AVERAGE COAL ANALYSIS
TEST SITE E
Kentucky
Coal
Crushed
Kentucky
Coal
East
Kentucky
Coal
PROXIMATE (As Rec'd)
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu/Ib
% Sulfur
ULTIMATE (As Rec'd)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen (Diff)
6.13
8.52
35.06
50.29
12773
0.86
6.13
71.69
4.73
1.30
0.13
0.86
8.52
6.67
5.69
9.08
33.50
51.73
12831
0.71
5.69
71.95
4.72
1.36
0.14
0.71
9.08
6.36
6.31
8.21
34.47
51.02
12722
0.78
6.31
71.31
4.70
1.13
0.08
0.78
8.21
7.50
15
-------
(BLANK PAGEl
16
-------
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.
4.1 GASEOUS EMISSIONS MEASUREMENTS (NOx, CO, CO-}, 0?, 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 (CO2), 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: ±1% 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
17
-------
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 chemiluminescent reaction of NO and Oo to form NO2.
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+N02), 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, N02 molecules in the sample gas are reduced
to NO molecules, and the analyzer now reads NOx. NO2 is obtained by the dif-
ference 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 ±1 ppm in 24 hours
Power requirements 115+10V, 60 Hz, 1000 watts
Response 90% of full scale in 1 sec. (NOx mode),
0.7 sec. NO mode
Output 4-20 ma
18
-------
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 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 115+15V rms
Response 90% of full scale in 0.5 or 2.5 sec.
Precision +1% 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 CO2 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 115-15V rms
Response 90% of full scale in 0.5 or 2.5 sec.
Precision *1% of full scale
Output 4-20 ma
19
-------
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 02 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 CH4.
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
addition, span control provides continuously variable
adjustment within a dynamic range of 10:1
Response time 90% full scale in 0.5 sec.
Precision -1% of full scale
Electronic stability ±1% of full scale for successive
identical samples
20
-------
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 contained
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 Metallurgical
Corporation sintered stainless steel filter is attached to each probe for
removal of particulate material.
21
-------
to
NJ
ET
*l
n
-*,,.,.,
1*1*,
=oT>
L H
.•n
1
s ;
n
P
l
n
» 1
ST'
"i A o^
. > i |
r\
""•• "'••
i;
i)
:j
in- ii
T"
^
"O»
i*r
{
>(•»;
Jli
•o no», i
v»lv. ^
-r>-«t ""
U j-— •
••«%/ | ^ '
U j oplury
ni
t5
U
ft
ai.
Figure 4-1. Flow Schematic of Mobile Flue Gas Monitoring Laboratory
-------
Gas samples to be analyzed for 02/ CO , 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. Flow 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 (SOx) MEASUREMENT AND PROCEDURES
Measurement of SO2 and SO^ concentrations is made by wet chemical
analysis using both the "Shell-Emeryville" method and EPA Method 6. In the
Shell-Emeryville method the gas sample is drawn from the stack through a
glass probe (Figure 4-2), containing a quartz wool filter to remove particulate
matter, into a system of three sintered glass plate absorbers (Figure 4-3). The
first two absorbers contain aqueous isopropyl alcohol and remove the sulfur
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
isoprophy 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.
23
-------
Flue Wall
Asbestos Plug
Ball Joint
vycor
Sample Probe
Heating
Tape Pryometer
and
Thermocouple
Figure 4-2. SOx Sample Probe Construction
Dial Thermometer
Spray Trap
Pressure Gauge. \
Volume Indica-v \ \
v lA
Vapor Trap Diaphragm
Pump
Dry Test Meter
Figure 4-3. Sulfur Oxides Sampling Train
(Shell-Emeryville)
24
-------
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 SO2,
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.
Three repetitions of SOx sampling are made at each test point.
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 4-4). 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.
25
-------
PROBE
THERMOMETER
PROBE
STACK /£
THERMOMETER
REVERSE-TYPE
PITOT TUBE
HEATED AREA
FILTER HOLDER
THERMOMETER
THERMOMETER
THERMOMETER
STACK
WALL
VELOCITY
PRESSURE
GAUGE
IMPlNGERS ICE BATH
THERMOMETERS ^______ FINE CONTROL VALVE
VACUUM
GAUGE
CHECK VALVE
VACUUM LINE
ORIFICE
GAUGE
COARSE CONTROL VALVE
DRY TEST METER
AIR-TIGHT
PUMP
Figure 4-4. EPA Method 5 Particulate.Sampling Train
-------
All peripheral equipment is carried in the instrument van. This
includes a scale (accurate to lo.l mg), 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 PARTICLE SIZE DISTRIBUTION MEASUREMENT AND PROCEDURES
Particle size distribution is measured using several methods. These
include the Brink Cascade Impactor and the SASS cyclones. No Bahco samples
were taken at this site. Each of these particle sizing methods has its
advantages and disadvantages as described below.
Brink. The Brink cascade impactor is an in-situ particle sizing de-
vice which separates the particles into six size classifications. It has the
advantage of collecting the entire sample. That is, everything down to the
collection efficiency of the final filter is included in the analysis. It
has, however, some disadvantages. If the particulate matter is spatially
stratified within the duct, the single-point Brink sampler will yield
erroneous results. Unfortunately, the particles at the outlets of stoker
boilers may be considerably stratified. Another disadvantage is the instru-
ment's small classification range (0.3 to 3.0 micrometers) and its small sample
nozzle (1.5 to 2.0 mm maximum diameter). The particles being collected at the
boiler outlet are often as large as the sample nozzle.
The sampling procedure is straight forward. First, the gas velocity
at the sample point is determined using a calibrated S-type pitot tube. For
this purpose a hand held particulate probe, inclined manometer, thermocouple
and indicator are used. Second, a nozzle size is selected which will main-
tain isokinetic flow rates within the recommended .02-.07 ft^/min rate at
stack conditions. Having selected a nozzle and determined the required flow
rate for isokinetics, the operating pressure drop across the impactor is
determined from a calibration curve. This pressure drop is corrected for
temperature, pressure and molecular weight of the gas to be sampled.
27
-------
A sample is drawn at the predetermined AP for a time period which is
dictated by mass loading and size distribution. To minimize weighing errors
it is desirable to collect several milligrams on each stage. However, to
minimize reentrainment, a rule of thumb is that no stage should be loaded
above 10 mg. A schematic of the Brink sampling train is shown in Figure 4-5.
SASS. The Source Assessment Sampling System (SASS) was not designed
principally as a particle sizer but it includes three calibrated cyclones
which can be used as such. The SASS train is a single point in-situ sampler.
Thus, it is on a par with cascade impactors. Because it is a high volume
sampler and samples are drawn through large nozzles (0.25 to 1.0 in.), it
has an advantage over the Brink cascade impactor where large particles are
involved. The cut points of the three cyclones are 10, 3 and 1 micrometers.
A detailed description of the SASS train is presented in Section 4.9.
4.5 COAL SAMPLING AND ANALYSIS PROCEDURE
Coal samples at Test Site E were taken during each test from the
unit's two coal scales. The samples were processed and analyzed for both
size consistency and chemical composition. The use of the coal scale as
a sampling station has two advantages. It is close enough to the furnace
that the coal sampled simultaneously with testing is representative of the
coal fired during the testing. Also, because of the construction of the
coal scale, it is possible to collect a complete cut of coal off the scales'
apron feeder thus insuring a representative size consistency.
In order to collect representative coal samples, a sampling device
having the same width as the apron feeder belt was moved directly under the
belt's discharge end to catch all of the coal over a short increment of time
(approximately five seconds).
The sampling procedure is as follows. At the start of testing, one
increment of sample is collected from each feeder. This is repeated twice more
during the test (three to five hours duration) so that a six increment sample
is obtained. The sample is then riffled using a Gilson Model SP-2 Porta
Splitter until two representative twenty pound samples are obtained.
28
-------
PRESSURE TAP
FOR 0-20"
MAGNAHELIX
CYCLONE
STAGE 1
STAGE 2
STAGE 3
EXHAUST
STAGE 4
STAGE 5
FINAL FILTER
DRY GAS
METER
FLOW CONTROL
VALVE
ELECTRICALLY HEATED PROBE
DRYING
COLUMN
Figure 4-5. Brink Cascade Impactor Sampling Train Schematic
29
-------
The sample to be used for sieve analysis is weighed, air dried over-
night, and re-weighed. 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 chemical 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 a proximate analysis. In addition, composite samples consisting of
one increment of coal for each test for each coal type receive ultimate
analysis, ash fusion temperature, mineral analysis, Hardgrove grindability
and free swelling index measurements.
4.6 ASH COLLECTION AND ANALYSIS FOR COMBUSTIBI£S
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 EJ*A 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. The 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 E the bottom ash samples were collected in several in-
crements from the discharge end of the grate during testing. These samples
were mixed, quartered, and sent to Commercial Testing and Engineering Company
for combustible determination. Multiclone ash samples and economizer ash
30
-------
samples were taken from ports near the base of their hoppers. These
samples, approximately two quarts in size, were sent to Commercial Testing and
Engineering Company for combustible determination.
4.7 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.
Unlike the ASME test in which combustible losses are lumped into one
category, combustible losses are calculated and reported separately for com-
bustibles in the bottom ash, combustibles in the mechanically collected ash
which is not reinjected, and combustibles in the flyash leaving the mechanical
collector.
4.8 TRACE SPECIES MEASUREMENT
The EPA (IERL-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 ]m. B) 3 urn to 10 ym c) 1 ym to 3 urn
With a filter, a fourth cut (>1 jam) 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
31
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U)
Stack T.C.
Gil cooltr
ratvrt
Imp/cooler
tract clement
collector
Vacuum
gage
OrtfUe AM,
mgnehel 1c
Dry test neter
Figure 4-6. Source Assessment Sampling System (SASS) Flow Diagram
-------
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 polymer
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.
33
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(BLANK PAGE)
34
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5.0 TEST RESULTS AND OBSERVATIONS
This section presents the results of the tests performed on Boiler E.
Observations are made regarding the influence on efficiency and gaseous and
particulate emissions as the control parameters were varied. Twenty tests
were conducted in a defined test matrix to develop this data. Tables 5-19
through 5-22 are included at the end of this section for reference.
As was mentioned in the executive summary to this report, problems were
encountered which prevented the entire test program from being completed. As
a result, interpretation of some of the data is rendered very difficult. In
general, however, the data obtained at Site E are useful and informative.
These data are discussed in the following paragraphs.
5.1 OVERFIRE AIR
Boiler E had four rows of overfire air jets in the configuration
shown in Figure 3-1. Several tests were run in which overfire air pressure
to individual rows of air jets (and thus overfire air flow) was the indepen-
dent variable. Emissions and boiler efficiency were measured as the overfire
air pressures were varied in order to determine which overfire air pressure
settings were optimum.
5.1.1 Overfire Air Flow Rate Measurements
Overfire air flow rates were determined for one pressure setting on
each of the four rows of air jets. Overfire air flow rate was also determined
at the overfire air fan outlet, thus allowing the flyash reinjection air flow,
which is supplied by the same fan, to be determined by difference. These
data are shown in Table 5-1.
Based on these measurements it is possible to determine the individual
and total air flows into the furnace at any overfire air pressure setting. The
relationship used to make this determination is derived from Bernaulli's
35
-------
TABLE 5-1
OVERFIRE AIR FLOW RATES
TEST SITE E
Overfire Air
Header
Front Upper
Front Lower
Rear Upper
Rear Lower
Static Pressure
"H70
24.0
29.5
8.5
23.0
Measured
Air Flow Percentage of Total
Ibs/hr Overfire Air
13,200
300
13,300
16,000
31%
1%
31%
37%
Total
42,800
100%
36
-------
equation for fluid flow through an orifice. It has been verified by KVB on
previous tests. One form of Bernaulli's equation is:
AP Av2
P 2g
The velocity (v) is proportional to the square root of the pressure drop (AP).
At AP = 0, v = 0. Therefore, a line drawn through the square root of each
static pressure listed in Table 5-1 and through the (0,0) point will define
the airflow or velocity as a function of /AP (Figure 5-1) .
5.1.2 Particulate Loading vs Overfire Air
Four tests were run on Kentucky coal to determine the effect of adjust-
ments to the overfire air system on particulate emissions. The results are
shown in Figure 5-2 and in Table 5-2.
The results show that reducing the overfire air pressure to the rear
upper and lower rows of air jets had no effect on particulate loading. This
conclusion is based on the results of test 8 which averaged 27"H2O pressure
on the rear jets, and test 11 which averaged 3"H20 pressure on the rear jets.
The boiler outlet particulate loadings for tests 8 and 11 were 4.49 and 4.32
lbs/106 Btu, respectively, which is not a significant difference. Both tests
were run under similar conditions of boiler loading and excess air.
Test 6 had the lowest particulate loading of any test run at this site
and it is not understood why this was the case. It is suspected that high
excess air played a part. The overfire air settings during test 6 were the
normal day-to-day operating settings for this unit.
When the air pressure to the lower front and lower rear rows of overfire
air jets was reduced, as it was during test 7, the boiler outlet particulate
loading increased to 5.23 lbs/106 Btu. This increase is significant when com-
pared to test 8 (4.49 lbs/106 Btu), but it must be noted that the variable
excess air was not held constant. Therefore, it is entirely possible that the
increase in particulate loading was due to reduced excess air and not the change
in overfire air conditions. Figure 5-2 shows that the increased particulate
loading of test 7 resulted entirely from its increased combustible content when
compared to test 8.
37
-------
u>
QO
I
in
ex,
« 2
§
6 8 10
AIR FLOW RATE, 103LB/HR
12
14
Figure 5-1. Pressure-Flow Relationship, Overfire Air System, Test Site E
-------
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TEST NO. 6 7 8 11
CONDITIONS Reduced Reduced High Bal Reduced
RU & RL FL & RL OFA RU & RL
OFA OFA OFA
Figure 5-2. Particulate Loading Breakdown for Kentucky
Coal as a Function of Overfire Air Conditions,
39
-------
TABLE 5-2_
EFFECT OF OVERFIPE AIR ON EMISSIONS AND EFFICIENCY
KENTUCKY COAL - TEST SITE E
TEST NO.
DESCRIPTION
OVERFIRE AIR CONDITIONS
Front Upper, "H2O
Front Lower, "HjO
Rear Upper, "H20
Rear Lower, "f^O
FIRING CONDITIONS
Load, % of Capacity *
Grate Heat Release, 103Btu/hr-ft2
Coal Sizing, % Passing 1/4"
Excess Air, %
BOILER OUTLET EMISSIONS
Particulate Loading, lb/10°Btu
Combustible Loading, lb/106Btu
Inorganic Ash Loading, lb/10°Btu
Combustibles in Flyash, %
02, % (dry)
CO, ppm (dry) @ 3% O2
NO, lb/106Btu
MULTICLONE OUTLET EMISSIONS
Particulate Loading, lb/106Btu
Combustible Loading, lb/106Btu
Inorganic Ash Loading, lb/106Btu
Combustible in Flyash, %
Multiclone Collection Efficiency, %
Stack Opacity, %
HEAT LOSSES, %
Dry Gas Loss
Moisture in Fuel
H20 from Combustion of H2
Combustibles in Boiler Outlet Flyash
Combustibles in Bottom Ash
Radiation Loss
Unmeasured Losses
Total Losses
Boiler Efficiency
Reduced Reduced
RU S RL FL S RL
OFA OFA
(Baseline)
28
31
3
19
65
454
34
70
2.060
1.283
0.777
62.3
9.0
62
0.614
0.335
0.205
0.130
61.2
83.7
17
7.60
0.63
1
21
3.88
5.89
1.17
0.71
50
38
78.62
28
19
28
19
67
504
34
29
5.230
3.938
1.292
75.3
5.2
147
0.494
1.824
1.226
0.598
67.2
65.1
45
6.55
0.43
3.78
5.64
0.76
0.68
1.50
19.34
80.66
High Bal
OFA
28
28
28
26
61
458
34
43
4.493
3.172
1.321
70.6
6.8
0.493
0.190
95.8
38
7.32
0.40
3.89
4.52
0.31
0.75
1.50
18.69
81.31
11
Reduced
RU S RL
OFA
28
28
3
3
62
454
31
40
4.316
2.529
1.787
58.6
6.5
0.480
1.558
0.966
0.592
62.0
63.9
46
6.85
0.48
3.85
3.60
1.55
0.73
1.50
18.56
81.44
*Design capacity of boiler is 180,000 Ib steam/hr. Maximum ob-
tainable load was 60-70% of design capacity due to retrofit
combustion air system.
40
-------
5.1.3 Nitric Oxide vs Overfire Air
The nitric oxide data obtained at Test Site E indicates that overfire
air changes had little or no effect on nitric oxide emissions. The nitric
oxide data are presented in Table 5-3.
An effort was made to sort out the effects of differing oxygen levels
on nitric oxide emissions so that overfire air setting would be the only
variable. This was accomplished by first fitting a line to the NO vs C>2 data
in the load range of interest. Linear regression by least squares was used
to do this. The slope of this line was then used to correct the nitric oxide
data to a constant 9% 02.
Having corrected for the effects of oxygen, the data compared as
follows: Tests lOb and lOd were carried out under identical conditions,
except for the biasing of the overfire air pressure to the lower and upper
rear rows of air jets. In these two tests NO changed from 0.582 to 0.592
lbs/10^ Btu corrected, an insignificant change.
Tests 8 and 11 were carried out under identical conditions, except
that test 8 had high pressure to both rear rows of air jets and test 11 had
low pressure to the same rows. In these two tests NO changed from 0.552 to
0.548 lbs/10 Btu corrected, again an insignificant change.
5.1.4 Boiler Efficiency vs Overfire Air
Boiler efficiency data for the overfire air tests are shown in Table
5-2. Because overfire air changes would be expected to effect primarily the
combustibles-in-flyash heat loss, these data are presented in Table 5-4. The
lowest heat loss due to combustibles in the flyash occurred during test 11,
which had high overfire air pressures on the front jets and low pressures on
the rear jets. There is no evidence that overfire settings were responsible
for the low combustible heat loss.
41
-------
TABLE 5-3
NITRIC OXIDE EMISSIONS vs OVERFIRE AIR
TEST SITE E
Test
No.
6
7
8
lOb
lOd
11
Design O
Coal Capacity %
Kentucky 65 9 .
Kentucky 67 5.
Kentucky 61 6 .
Kentucky 61 7.
Kentucky 61 8.
Kentucky 62 6.
'„ Overfire Air Pressure, "H^O
FU FL RU RL
0 28 31 3 19
2 28 19 28 19
8 28 28 28 26
6 31 ND 3 29
2 31 ND 31 9
5 28 28 3 3
* Corrected to 9% 0 by applying the established
1% 0 increase = 0.027 lbs/10 Btu Nitric Oxide
FU —
FL —
RU — •
RL ~
ND —
front upper
front lower
rear upper
rear lower
no data
Nitric Oxide, lb/106Btu
Measured Corrected*
.614 .614
.494 .597
•493 .552
•544 .582
-570 .592
-480 .548
02-NO relationship:
increase .
42
-------
TABLE 5-4
COMBUSTIBLES IN FLYASH vs OVEKFIRE AIR
TEST SITE E
Test
No. _
6
7
8
11
Kentucky
Kentucky
Kentucky
Kentucky
Design
Capacity
65
67
61
r 62
°2
%
9.0
5.2
6.8
6.5
Over fire Air
PU
28
28
28
28
PL
31
19
28
28
Pressure, "H^O % Coirib .
RU
3
28
28
3
RL
19
19
26
3
in Flyash
62.3
75.3
70.6
58.6
% Comb.
Heat Loss
5.89
5.64
4.52
3.60
FU — front upper
PL — front lower
RU -- rear upper
RL — rear lower
43
-------
5.2 EXCESS OXYGEN AND GRATE HEAT RELEASE
The boiler at Test Site E was tested for emissions and boiler efficiency
under a variety of operating conditions. This section presents the results of
these emissions and efficiency tests as a function of load, expressed as grate
heat release, and excess air, expressed as percent oxygen in the flue gas. The
data are also differentiated by coal type in many of the plots.
Before examining the test data it is important to understand the
special nature of the combustion air on this boiler, and corrections that have
been made to the steam flow readings.
The boiler at Test Site E was recently retrofitted with a new combustion
air system. This system, which uses paint oven exhaust gasses for combustion
air, has reduced the steam capacity of the boiler by about 30% or 55,000 Ibs
stm/hr. The majority of tests at this test site were run at the maximum
obtainable load, but were limited by fan capacity to the range 110-125 thousand
pounds of steam per hour.
It is also worth noting that the paint oven exhaust gasses contained
varying amounts of oxygen in the range 14.5 - 20.5% G>2. These combustion air
oxygen levels are included in the Emission Data Summary, Table 2-1.
During three tests — tests 3, 9, 20 — the boiler was operated on
ambient air. These tests are identified in the plots by the use of solid
rather than open symbols. The same load restriction was experienced when
using ambient air as was experienced when using paint oven exhaust gasses.
The same retrofit FD fan was used in both cases.
The steam flow and percent boiler loading data reported herein have
been corrected for a calibration error in the steam flow integrator. The
steam flow integrator was found to be 20,000 Ibs/hr low by a Hays repairman
subsequent to the test program at site E. Consequently, all measured steam
flows have been corrected upwards by 20% to compensate for the error.
5.2.1 Excess Oxygen Operating Levels
Figure 5-3 depicts the various conditions of grate heat release and
44
-------
DC
O
UJ
O
oc
U-1
Q- S-l
8-
•
to
>- *
X
O >
-J+
300.0
400.0
500.0
600.0
700.0
GRflTE HERT RELERSE 1000 BTU/HR SOFT
: KENTUCKY -j- I CRUSHED KY A ' ERST KENT. £ : AMBIENT AIR TESTS
VS. GRflTE HERT RELERSE
FIG. 5-3
OXYGEN
TEST SITE E
45
-------
excess oxygen under which tests were run on the boiler at site E. Different
symbols are used to distinguish the three coals fired. The three solid
symbols are those tests run on ambient air.
The oxygen operating level is shown to decrease with increasing load
expressed here as grate heat release. If this trend were to continue, the
boiler would easily be able to operate at its design excess air of 30%, or
about 5.3% C>2, at full design capacity. Even at its restricted capacity of
between 500 and 600 x 103 Btu/hr-ft2 grate area, the unit was successfully
operated near this excess air level on several tests.
5.2.2 Particulate Loading vs Oxygen and Grate Heat Release
Figure 5-4 profiles boiler outlet particulate loading as a function
of grate heat release. The data points in this plot are keyed to the coal
fired with the ambient air tests shown as solid symbols.
With two exceptions, the data show a defined upward trend in boiler
outlet particulate loading with increasing grate heat release. No explanation
could be found for the two anomolous data points. The upper one, test 5, was
a baseline or as-found test. The lower one, test 6, was a low overfire air
test.
The average boiler outlet particulate loading at high load was 5.51
± .66 lbs/10^ Btu. High load on this unit is defined as a grate heat release
of 500x103 Btu/hr - ft2 or greater.
The average ash carryover was 20% in these tests. Table 5-5 shows
the average ash content of the three coals and the percentage of this ash
which was carried over with the flyash. Note that only the inorganic ash
fraction of the flyash is considered in making this determination. Average
ash contents of the three coals were nearly identical.
46
-------
CD
•ZL
o
00
-1 BH
oc
cc
Q_
o
DC
LU
O
DO
7/iiiir
300.0 400.0 500.0 600.0 700.0
GRflTE HEflT RELERSE 1000 BTU/HR SQFT
O : KENTUCKY + : CRUSHED KY A : ERST KENT. • : AMBIENT AIR TESTS
FIG. 5-4
BOILER OUT PflRT. VS. GRRTE HERT RELERSE
TEST SITE E
47
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TABLE 5-5
ASH CARRYOVER VS COAL TYPE
TEST SITE E
Average Ash Average Ash
Content of Coal, Content of Flyash, Average Ash
Coal lbs/106 Btu lbs/106 Btu Carryover, %
Kentucky 6.78 1.34 19.7
Crushed Kentucky 6.80 1.45 21.3
Eastern Kentucky 6.39 2.14 33.4
Particulate measurements were made at the outlet of the multiclone dust
collector simultaneously with the measurements made at the boiler outlet.
Figure 5-5 plots the multiclone outlet particulate loadings as a function of
grate heat release. Again the data points are keyed to coal type and the
ambient air tests are indicated by solid symbols. The data show a general
upward trend in particulate loading with increasing grate heat release.
The particulate loadings are very scattered at the multiclone outlet.
It is suspected that the multiclone dust collector hopper was filled to
capacity during several tests resulting in reintrainment of the ash and a
lowered collection efficiency. Multiclone collection efficiency will be
discussed in section 5.5.
At both the boiler outlet and the multiclone dust collector outlet, the
ambient air particulate test data were no different than the data from tests
run on paint oven exhaust gasses. Therefore, it is concluded that this unique
retrofit to the boiler at site E has no impact on particulate emission levels.
5.2.3 Stack Opacity vs Oxygen and Grate Heat Release
Stack opacity was measured during most tests by a transmissometer
mounted between the multiclone outlet and the inlet to the induced draft fan.
48
-------
00
-z.
o
CD
DC
CE
0_
O S
•
(SI
O
CJ
A
1 1 —T- 1 r
300.0 400.0 500.0 600.0 700.0
GRRTE HERT RELERSE 1000 BTU/HR SOFT
O : KENTUCKY + : CRUSHED KY A '• ERST KENT. % : AMBIENT AIR TESTS
FIG. 5-5
MULTICLONE OUT PRRT. VS. GRRTE HERT RELERSE
TEST SITE E
49
-------
It became apparent during the course of testing that the opacity readings
were increasing with time as the light source and light receiver glasses
became covered with dust or soot. Thus beginning with test no. 5, the
sight glasses were cleaned prior to each opacity reading.
Figure 5-6 presents the opacity readings taken at site E as a
function of grate heat release. This plot shows that there is no obvious
trend in opacity data versus load. This plot also shows that there may be
some correlation of opacity with coal type, but there is insufficient data
to substantiate this speculation.
A better correlation is obtained by plotting opacity against multi-
clone outlet particulates as shown in Figure 5-7. This plot again indicates
that changes in coal composition and combustion air flow were not factors in
opacity level.
5.2.4 Nitric Oxide vs Oxygen and Grate Heat Release
Nitric oxide (NO) concentration was measured during each test in units
of parts per million (ppm). It is presented here in units of lbs/106 Btu to
be more easily compared with existing and proposed emission standards.
Nitric oxide is plotted as a function of grate heat release in Figure
5-8. The data points in this figure are keyed to coal being fired, while the
three ambient air tests are indicated by solid symbols. The average nitric
oxide concentration at high boiler loading (above 500X103 Btu/hr-Ft2) was
0.533 ± 0.047 lbs/106 Btu. Figure 5-8 does not isolate the variable oxygen,
and therefore, the trend shown is for NO versus grate heat release under
normal operating conditions. Ignoring the three ambient air tests, nitric
oxide concentration is seen to be highest at low loads on this unit. The
maximum measured NO was 0.65 lbs/10 Btu at a load of 48% design capacity.
The ambient air tests produced nitric oxide concentrations which were generally
lower than the tests utilizing paint oven exhaust gasses as combustion air.
This was especially evident in the two lower load tests.
50
-------
8-
S
8-
UJ
CJ
DC
UJ
Q_ 8-
4-
o
cc
Q_
O
300.0
400.0
I
500.0
600.0
700.0
GRRTE HEflT RELERSE 1000 BTU/HR SOFT
; KENTUCKY
: CRUSHED KY ^ : ERST KENT.
FIG. 5-6
STflCK OPflCITY
TEST SITE E
: AMBIENT AIR TESTS
VS. GRRTE HERT RELERSE
51
-------
o
O —
o
in
8-
9
CJ
cc
LJJ
Q- 8-
S-
°
LJ
CE
Q_
O
SB-
o: d
i— *"
CD
\
\
i
1.000 2.000 3.000 4.000 5.000
MULTICLONE OUT PflRT. LB/MILLION BTU
S KENTUCKY
; CRUSHED KY
°> EflST KENT.
: AMBIENT AIR TESTS
FIG. 5-7
STRCK OPRCITY
TEST SITE E
VS. MULTICLONE OUT PflRT.
52
-------
CD
o 8-1
LU
a
I—I
X
O
O
300.0 400.0 500.0 600.0 700.0
GRRTE HERT RELERSE 1000 BTU/HR SOFT
(JJ ; KENTUCKY + I CRUSHED KY
FIG. 5-8
NITRIC OXIDE
TEST SITE E
: ERST KENT.
: AMBIENT AIR TESTS
VS. GRRTE HERT RELERSE
53
-------
Nitric oxide concentration was found to increase sharply with oxygen at con-
stant boiler load. There are a few data points which cannot be explained,
but on the whole, the data gives a good NO vs 02 profile for the boiler at
Site E. All the NO data are plotted against oxygen in Figure 5-9, and the
NO data in specific grate heat release ranges are plotted against O2 in
Figures 5-10., 5-11 and 5-12.
A nitric oxide trend line has been applied to the data in Figures
5-11 and 5-12 using linear regression analysis by method of least squares.
The slope of these two trend lines indicates the following relationships.
Nitric oxide increases by .027 lbs/10" Btu for each one percent increase in
oxygen at 400-499xl03 Btu/hr-ft2 grate area. Nitric oxide increases by .037
lbs/106 Btu for each one percent increase in oxygen at 500-605xl03 Btu/hr-ft2
grate area.
Combining the trend lines for the two main grate heat release ranges
produces the plot shown in Figure 5-13. The low load data, i.e., 300-399
GHR, was not included in this plot. Because of their extreme variance from
the expected relationship, the two low load data points should be considered
suspect.
5.2.5 Carbon Monoxide vs Oxygen and Grate Heat Release
Carbon monoxide (CO) was measured during the first seven tests at
Site E. The CO analyzer was inoperative at the start of Test 8 and remained
out of sarvice for the remainder of the testing at this site.
The CO data are presented in units of parts-per-million (ppm) by
volume on a dry basis, corrected to 3% 02- Carbon monoxide is a by-product
of incomplete combustion and a sensitive indicator of combustion problems,
but if it is kept below 400 ppm it is considered insignificant for the
purposes of this report. As a reference, 400 ppm CO is equivalent to
0.04% CO and represents a 0.20% heat loss in a coal fired boiler operating
at 8% Q>2- Figure 5-14 presents the carbon monoxide data gathered under a
variety of firing conditions and plotted as a function of grate heat release.
54
-------
o o
CD
A
o g-i
X
O
o
gA O
A
—i 1 1 1 r
4.00 6.00 8.00 10.00 12.00
OXYGEN . PERCENT, DRY
; 200-399GHR Q '• 400-499GHR A '• 500-599GHR £ + : AMBIENT AIR TESTS
FIG. 5-9
NITRIC OXIDE VS. OXYGEN
TEST SITE E
55
-------
ID
»—
DO
z:
\
QQ
LU
O
»—H
X
o
cc a-
o
4.00
OXYGEN
6.00
8.00 10.00
PERCENT. DRY
12.00
: 200-399OW
FIG. 5-10
NITRIC OXIDE
TEST SITE E
AMBIENT AIR TEST
VS. OXYGEN
56
-------
o
ID
h—
CO
o SH
CO
X
o
CJ
S 1
4.00
OXYGEN
6.00
\ I I
8.00 10.00 12.00
PERCENT. DRY
400-499GHR
AMBIENT AIR TESTS
FIG. 5-11
NITRIC OXIDE
TEST SITE E
VS. OXYGEN
57
-------
CQ
CD
!lj
I
•^
3
X
CD
4.00
OXYGEN
6.00
8.00 10.00
PERCENT, DRY
—r
12.00
: 500-599GHR
FIG. 5-12
NITRIC OXIDE
TEST SITE E
VS. OXYGEN
58
-------
.65
.60
PQ
&
o
.55
H
X
o
u
EH
H
s
.50
.45
500
499 GHR
6 8
OXYGEN, PERCENT
10
FIGURE 5-13.
Trend in Nitric Oxide Emissions as a Function of
Grate Heat Release (GHR) and Oxygen at Site E.
59
-------
CM
O
2
UJ
CJ
DC
LU
0- o.
co 8
en
z:
Q_
LU
a
•—•
X
O
O
m °
QQ .-
DC S
CE
CJ
T
400.0
—r
600.0
300.0
500.0
700.0
GRflTE HEflT RELEflSE 1000 BTU/HR SQFT
: KENTUCKY
FIG. 5-14
CflRBON MONOXIDE
TEST SITE E
: AMBIENT AIR TESTS
VS. GRRTE HEflT RELEflSE
60
-------
With one exception the trend shows decreasing CO with increasing grate heat
release. The one exception was Test 7, a low O2 test. All measured CO
concentrations were low, and insignificant in terms of their contribution
to incomplete combustion and heat loss.
Figure 5-15 presents the measured carbon monoxide data as a function
of oxygen. There are only weak indications of a trend here. The highest CO
concentration measured was also at the lowest oxygen level.
5.2.6 Combustibles vs Oxygen and Grate Heat Release
In this report the term "combustibles" refers only to the solid com-
bustibles in the various ashes leaving the boiler. Combustibles are described
here in terms of their percent by weight in the flyash at the boiler outlet
and in the bottom ash collected from the ash pit.
Figure 5-16 shows the combustibles in the boiler outlet flyash as a
function of grate heat release. The data points are keyed to coal, and the
solid symbols refer to ambient air tests. Boiler outlet combustibles ranged
from 50 to 84% on the spreader stoker, and averaged 66% overall. They
accounted for an average 4.40-0.89% heat loss. All three coals produced
flyash combustible levels which were in the same general range. It is also
evident that the ambient air tests produced flyash combustibles in the same
range as the paint oven exhaust gas tests. The flyash combustible level
showed an increasing trend with grate heat release.
Figure 5-17 shows the combustibles in the bottom ash as a function of
grate heat release. The bottom ash combustibles ranged from 6 to 17% by
weight and averaged 10% overall. They accounted for an average 0.87-0.41%
heat loss. Variations in coal and combustion air composition did not sig-
nificantly affect bottom ash combustible levels.
5.2.7 Boiler Efficiency vs Oxygen and Grate Heat Release
Boiler efficiency was determined for each test that included a boiler
outlet particulate loading measurement. The efficiency determinations were
made by the ASTM heat loss method.
61
-------
CM
O o
»- S"
z
UJ
CJ
GC
UJ
0- o.
co a
\
Q_
Q- °.-
8
\
\
LU
Q
»— i
X o'
o
o
o
8
\
\
\
\
\
\
QC
CC
CJ
I L/
/7 1 1
4.00 6.00
OXYGEN
1
~~i
8.00 10.00
PERCENT
p DRY
1 1
12.00
; KENTUCKY -|- : CRUSHED KY ^ '• Efl3T KENT-
FIG. 5-15
CflRBON MONOXIDE
TEST SITE E
: AMBIENT AIR TESTS
VS. OXYGEN
62
-------
o
8~
o
8"
UJ
O
cc
UJ
Q_ °.-
CD
O o
O f
O
cc
o
CD
s
4
A
i i ^ 1 r
300.0 400.0 500.0 600.0 700.0
GRRTE HERT RELERSE 1000 BTU/HR SOFT
O : KENTUCKY + : CRUSHED KY A • ERST KENT. * : AMBIENT AIR TESTS
FIG. 5-16
BOILER OUT COMB. VS. GRRTE HERT RELERSE
TEST SITE E
63
-------
o
a"
8
O
cc
UJ
o_ °.
8
CD
z:
O o
o g-
X
CO
-------
Figure 5-18 shows the calculated boiler efficiencies as a function of
grate heat release. Data points are keyed to the coal being fired, while the
anbient air tests are shown as solid symbols. A general downward trend is
seen here with boiler efficiency dropping off as grate heat release increases.
At high load — above 500x10 %tu/hr-ft grate area — the average boiler
efficiency was 79.88ll.48%.
Table 5-6 shows the average heat losses for the three coals tested.
Kentucky and Crushed Kentucky coals gave almost identical boiler efficiencies.
This would be expected because they were from the same mine. East Kentucky
coal gave efficiencies which averaged 2.5% lower than the other two coals.
The difference appears in two areas, dry gas loss (1.6%) and loss due to
combustibles in refuse (0.9%).
Dry Moisture
Coal Gas in Fuel
Kentucky 7.11 0.55
Crushed
Kentucky 7.20 0.52
East
Kentucky 8.74 0.59
TABLE 5-6
AVERAGE HEAT LOSSES BY COAL TYPE
Boiler
H2O From Combustibles Radiation & Total Efficiency,
j in Fuel in Refuse Unmeasured Losses Percent
3.85
3.84
3.89
5.27
5.23
6.14
2.25 19.03 80.97
2.25 19.04 80.96
2.17 21.53 78.47
5.3 COAL PROPERTIES
Three coals were tested in this boiler and are described in this section.
They are identified here and throughout this report as Kentucky coal, Crushed
Kentucky coal and East Kentucky coal.
The Kentucky and East Kentucky coals were from separate mines, while
the Crushed Kentucky coal was a specially sized shipment of the Kentucky coal.
65
-------
8
8-
8
_
cc
LU
Q_ g-
>-
CJ
LU
DC
LU
O
CO
8-
8-
8
N
N
//
300.0
•»00.0
500.0
600.0
700.0
GRflTE HEflT RELERSE 1000 BTU/HR SOFT
O : KENTUCKY + ; CRUSHED KY & °. ERST KENT. • ; AMBIENT AIR TESTS
FIG. 5-18
BOILER EFFIENCY VS. GRRTE HERT RELERSE
TEST SITE E
66
-------
Representative coal samples were taken from the unit's two coal scales
during each test that included either a particulate measurement or SASS sample
catch. Proximate and ultimate analyses were performed on these samples.
A composite sample for each coal was also obtained. The composite sample con-
tained incremental coal samples from each test and was analyzed for ash fusion
temperature, Hardgrove grindability index, free swelling index, and minerals
in the ash. This section will summarize all test results that appear to be
influenced by coal composition and will discuss coal size consistency and
sulfur balance data.
5.3.1 Chemical Composition of the Coals
The most significant properties of the coals tested are presented in
Table 5-7 on a heating value basis in order to allow for meaningful comparisons
between coals.
TABLE 5-7
COAL PROPERTIES CORRECTED TO A CONSTANT 106 BTU BASIS
Kentucky
Coal
4.8
6.7
Crushed
Kentucky
Coal
4.4
7.1
East
Kentucky
Coal
5.0
6.5
Moisture, lbs/106Btu
Ash, lbs/106Btu
Sulfur, lbs/106Btu 0.67 0.55 0.61
The chemical analyses of each coal sample are grouped by coal and
presented in Tables 5-8, 5-9, 5-10, and 5-11. These tables also show the
average and standard deviation for each item in the analysis. By comparing
these tables, it is evident that all three coals were similar in makeup.
The influence of coal properties on emissions and boiler efficiency is
summarized in Table 5-12 with references to the relevant figures. Each of these
relationships has been addressed elsewhere in the report but is reviewed here
for convenience.
67
-------
TABU 5-8
FUEL ANALYSIS - KENTUCKY COAL
TEST SITE E
oo
TEST NO.
PROXIMATE (As Rec'd)
% Moisture
% Ash
% Volatile
% Fixed Carbon
BTU/lb
% Sulfur
ULTIMATE (As Rec'd)
t Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygten (diff.)
ASH FUSION (Reducing)
Initial Deformation
Soft (H«W)
Soft (H->jW)
Fluid
HARDGROVE GRINDABILITY
FREE SWELLING INDEX
4
5
36
52
2
.63
.89
.78
.70
13651
0
4
74
4
1
0
0
5
6
INDEX
.86
.63
.94
.99
.51
.20
.86
.89
.98
3
6.52
8.68
34.51
50.29
12546
0.96
6.52
70.87
4.75
1.29
0.17
0.96
8.68
6.76
4
5.
6.
35.
52.
77
71
44
08
12942
0.
5.
72.
4.
1.
0.
0.
6.
7.
74
77
97
89
47
09
74
71
36
5
8.13
10.24
33.03
48.60
12021
0.85
8.13
67.74
4.59
1.31
0.14
0.85
10.24
7.00
6
6.70
9.71
32.53
51.06
12417
0.85
6.70
70.15
4.60
1.25
0.12
0.85
9.71
6.62
7
4.81
9.89
32.97
52.33
12957
1.01
4.81
72.43
4.67
0.94
0.10
1.01
9.89
6.15
8
4.65
5.80
47.67
41.88
13519
0.73
4.65
75.98
5.01
1.20
0.15
0.73
5.80
6.48
9
5.27
10.25
32.77
51.71
12666
0.77
5.27
71.53
4.58
1.44
0.09
0.77
10.25
6.07
11
5.23
10.19
33.73
50.85
12790
0.89
5.23
71.43
4.70
1.49
0.17
0.89
10.19
5.90
17
7.11
8.07
33.81
51.01
12530
0.82
7.11
70.66
4.65
1.19
0.08
0.82
8.07
7.42
20
8.61
8.33
32.38
50.68
12460
0.99
8.61
69.89
4.58
1.19
0.08
0.99
8.33
6.33
COMP
2.03
10.35
34.12
53.50
13193
0.95
2.03
74.33
4.78
0.92
0.11
0.95
10.35
6.53
2700+
2700 +
2700+
2700+
47
7>5
AVG
6.13
8.52
15.06
50.29
12773
0.86
6.13
71.69
4.73
1.30
0.13
0.86
8.52
6.67
STD
DEV
1.39
1.73
4.39
3.01
480
0.10
1.39
2.33
0.16
0.17
0.04
0.10
1.73
0.53
-------
TABLE 5-9
FUEL ANALYSIS - CRUSHED KENTUCKY COAL
TEST SITE E
O
TEST NO.
PROXIMATE (As Rec'd)
% Moisture
% Ash
% Volatile
% Fired Carbon
Btu/lb
% Sulfur
ULTIMATE (as Rec'd)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen (diff)
ASH FUSION (Reducing)
Initial Deformation
Soft (H=W)
Soft (H=%W)
Fluid
HARDGROVE GRINDABILITY
FREE SWELLING INDEX
12
6.09
8.76
33.00
52.15
12793
0.78
6.09
71.65
4.72
1.44
0.21
0.78
8.76
6.35
INDEX
13
5.93
10.35
33.38
50.34
12565
0.68
5.93
70.56
4.61
1.31
0.14
0.68
10.35
6.42
14
5.04
8.13
34.12
52.71
13135
0.67
5.04
73.64
4.82
1.32
0.08
0.67
8.13
6.30
COMP
2.49
8.10
35.05
54.36
13508
0.76
2.49
75.79
5.02
1.00
0.14
0.76
8.10
6.70
2700+
2700+
2700+
2700+
41
6*5
AVG
5.69
9.08
33.50
51.73
12831
0.71
5.69
71.95
4.72
1.36
0.14
0.71
9.08
6.36
STD
DEV
0.57
1.14
0.57
1.24
287
0.06
0.57
1.56
0.11
0.07
0.07
0.06
1.14
0.06
-------
TABLE 5-10
FUEL ANALYSIS - EASTERN KENTUCKY COAL
TEST SITE E
-j
o
TEST NO.
PROXIMATE (as Rec'd)
% Moisture
% Ash
% Volatile
% Fixed Carbon
Btu/lb
% Sulfur
ULTIMATE (as Rec'd)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen (diff.)
ASH FUSION (Reducing)
Initial Deformation
Soft (H=W)
Soft (H=^W)
Fluid
HARDGROVE GRINDABILITY INDEX
FREE SWELLING INDEX
15
5
8
34
51
.04
.41
.92
.63
12958
0.81
5
72
4
1
0
0
8
6
.04
.59
.80
.39
.09
.81
.41
.87
16
7
8
34
50
.57
.01
.02
.40
12486
0.74
7
70
4
0
0
0
8
8
.57
.02
.60
.86
.07
.74
.01
.13
STD
COMP
2.44
8.26
36.17
53.13
13224
0.77
2.44
74.26
4.90
1.35
0.09
0.77
8.26
7.93
2700+
2700+
2700+
2700+
37
W
AVG
6
8
34
51
.31
.21
.47
.02
12722
0.78
6
71
4
1
0
0
8
7
.31
.31
.70
.13
.08
.78
.21
.50
•
DEV
1
0
0
0
0
1
1
0
0
0
0
0
0
.79
.28
.64
.87
334
.05
.79
.82
.14
.37
.01
.05
.28
.89
-------
TABLE 5-11
MINERAL ANALYSIS OF COAL ASH
TEST SITE E
Coal
Silica, SiO2
Alumina,
Titania,
Kentucky Crushed Kentucky Eastern Kentucky
Ferric Oxide,
Lime, CaO
Magnesia, MgO
Potassium Oxide,
Sodium Oxide,
K.20
Sulfur Trioxide, 803
Phos . Penoxide,
Undetermined
Silica Value
Base: Acid Ratio
T250 Temperature
% Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
52.67
31.68
3.71
6.22
1.64
0.77
1.88
0.26
0.81
0.18
0.03
85.92
0.12
2900+°F
0.18
0.00
0.77
52.03
33.59
1.66
5.34
1.95
1.08
2.56
0.32
0.76
0.49
0.06
86.14
0.13
2890°F
0.08
0.00
0.68
49.80
36.27
1.63
5.19
2.07
0.88
2.07
0.25
1.15
0.43
0.06
85.95
0.12
2900+°F
0.15
0.01
0.61
71
-------
TABLE 5-12
RELATIONSHIP BETWEEN COALS FIRED AND EMISSIONS
TEST SITE E
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Parameter
Excess 02
Particulates (Boiler Outlet)
Particulates (Multiclone Outlet)
Opacity
Nitric Oxide
Carbon Monoxide
Combustibles (Boiler Outlet Flyash)
Combustibles (Bottom Ash)
Boiler Efficiency
Multiclone Efficiency
No.
5-3
5-4
5-5
5-6
5-8
5-14
5-16
5-17
5-18
5-24
Relationship to Coal Tvoe
East Ky coal fired at highest
None
Crushed Ky coal highest part.
Op
£.
Crushed Ky coal highest opacity
Crushed Ky coal highest NO
East Ky coal lowest NO
Data on Kentucky coal only
East Ky coal lowest comb.
None
None
None
5.3.2 Coal Size Consistency
The individual coal samples and the composite 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 5-13. The average coal size
consistency and standard deviation for each of the three coals were determined
and are plotted against the ABMA recommended limits for spreader stokers in
Figures 5-19, 5-20 and 5-21.
The specially sized Crushed Kentucky coal, which had been ordered for
test purposes, turned out to be nearly identical to the Kentucky coal that
was not specially sized. This unfortunate occurrence eliminated coal size
consistency as one of the variables at this test site.
All three coals fell within the ABMA recommended limits for coal
sizing. The Kentucky and Crushed Kentucky coals fall in the center of the
ABMA recommended limits while the East Kentucky coal is on the high fines
side. Using the generally accepted definition of coal fines — percent by
72
-------
TABLE 5-13
AS FIRED COAL SIZE CONSISTENCY
TEST SITE E
i
KENTUCKY
Test
No.
02
03
04
05
06
07
08
09
11
17
20
Composite*
Ave rage
1"
93.2
95.6
96.8
95.1
86.6
89.5
87.9
85.3
90.4
93.0
93.4
90.6
91.5
PERCENT PASSING
1/2"
51.9
66.1
65.9
77.0
56.7
65.1
57.0
62.0
59.0
66.1
73.5
61.7
63.7
STATED
1/4"
20.6
36.9
29.5
54.6
33.8
33.9
34.3
37.4
31.4
40.2
52.0
35.2
36.8
SCREEN SIZE
#8
8.9
19.1
12.7
31.7
19.1
15.3
18.4
19.2
16.0
20.6
26.2
18.5
18.8
#16
4.8
11.6
7.5
17.2
12.7
9.8
12.2
12.2
10.7
12.4
9.7
12.3
11.0
J
1 °
g ^
tJ tr*
On !Z
uy
12
13
14
Composite*
Average
97.8
91.5
88.5
95.7
92.6
61.4
54.3
56.0
57.1
57.2
30.4
29.0
32.6
30.3
30.7
13.7
15.2
16.2
14.2
15.0
8.5
10.3
10.3
8.5
9.7
£J
U o
M U
V) EH
« s
15
16
Composite*
Average
85.7
89.4
94.9
87.6
60.8
63.9
73.8
62.4
40.6
41.5
49.5
41.1
21.7
22.8
27.5
22.3
13.5
13.5
16.8
13.5
*The composite sample consists of one incremental coal sample from
each test on a given coal. It is not included in the average.
73
-------
KENTUCKY COAL
SIZE RANGE
ABMA RECOMMENDED
COAL SIZE RANGE
50#
16# 8# 1/4" 1/2" 1"
SIEVE SIZE DESIGNATION
Figure 5-19.
Size Consistency of "As Fired" Kentucky
Coal vs ABMA Recommended Sizing for
Spreader Stokers.
74
-------
2
8
95
80
50 M
w 30
H
20
10
CRUSHED KENTUCKY COAL
SIZE RANGE
ABMA RECOMMENDED
COAL SIZE RANGE
50#
16# 8# 1/4" 1/2"
SIEVE SIZE DESIGNATION
1"
2"
Figure 5-20.
Size Consistency of "As Fired" Crushed
Kentucky Coal vs ABMA Recommended Sizing
for Spreader Stokers.
75
-------
w
95
80
50
30
20
I
8 10
Z
W
W
EAST KENTUCKY COAL
SIZE RANGE
50 #
ABMA RECOMMENDED
COAL SIZE RANGE
16# 8# 1/4" 1/2"
SIEVE SI2E DESIGNATION
1"
2"
Figure 5-21.
Size Consistency of "As Fired" Eastern Kentucky
Coal vs ABMA Recommended Sizing for Spreader Stokers
76
-------
weight passing a 1/4" square mesh screen — the percentage of fines in the three
coals was: Kentucky coal - 37±10%, Crushed Kentucky coal - 31±2%, East
Kentucky Coal - 41±1%.
5.3.3 Sulfur Balance
Sulfur oxides — SC>2 and SO-, — were measured in the flue gas during
one test on Kentucky coal and one test on East Kentucky coal. EPA Method 6
and the Shell-Emeryville wet chemical methods were used to make these
measurements.
A sulfur balance was calculated for the boiler based on the sulfur
content of the fuel and the measured sulfur in the bottom ash, flyash, and
flue gas. This sulfur balance is shown in Table 5-14. It shows measurement
errors, some serious, resulting in a greater sulfur output than input. The
Shell-Emeryville method shows a greater error than EPA method 6. The source
of this error has not been determined.
5.4 PARTICLE SIZE DISTRIBUTION OF FLYASH
The purpose of the particle size distribution tests carried out under
this program is to accumulate a data bank of particle size distribution data
from all types of stoker boilers firing a variety of coals under a variety of
firing conditions. This data will be valuable to manufacturers of dust
collection equipment and to consulting engineers faced with the task of
specifying such equipment.
At test site E, two particle size distribution tests were run at the
boiler outlet using SASS cyclones for sizing. Two additional tests were run
at the economizer outlet with a Brink cascade impactor. The test conditions
for all four particle size distribution tests are given in Table 5-15. Test
results are presented in Table 5-16 and Figures 5-22 and 5-23.
In general, the test results show that 10% of the boiler outlet flyash
was below three micrometers in diameter, and 25% was below ten micrometers.
These results are considered valid for the point sampled, but it should be
77
-------
TABLE 5-14
SULFUR BALANCE
TEST SITE E
Test
No.
SULFUR IN FUEL
Fuel
Sulfur
%
16 0.74
17 0.82
As S02
lbs/106Btu
SULFUR IN BOTTOM ASH
Ash
Sulfur
%
1.185 0.08
1.309 0.11
As SO 2
lbs/106Btu
0.0066
0.0096
Retention
%
SULFUR IN FLYASH
Ash
Sulfur
%
0.6 0 . 39
0.7 0.25
As SO2
lbs/106Btu
0.0351
0.0225
Retention
%
SULFUR IN FLUE GAS
SOX
ppm ( dry )
3.0 780
1273
1.7 746
770
As SO2
lbs/106Btu
1.502
2.399
1.411
1.458
Fuel Sulfur
Emitted*
%
127
202
108
111
Sampling
Methodology
EPA Method 6
Shell-Emeryville
EPA Method 6
Shell-Emeryville
00
*The imbalance between the sulfur in the fuel and the sulfur emitted can be
attributed to measurement error.
-------
TABLE 5-15
DESCRIPTION OF PARTICLE SIZE
DISTRIBUTION TESTS
TEST SITE E
Test
No.
11
14
16
17
%
Design
Coal Capacity
Kentucky
Crushed Kentucky
East Kentucky
Kentucky
62
69
62
62
02
%
6.5
3.9
8.3
6.2
OFA*
Low
High
High
High
Particle Size
Distribution
Methodology Used
Brink Impactor
Brink Impactor
SASS Cyclones
SASS Cyclones
Sample
Location
Econ Outlet
Econ Outlet
Boiler Outlet
Boiler Outlet
*High overfire air (OFA) is the normal mode of operation
at this facility
79
-------
TABLE 5-16
RESULTS OF PARTICLE SI2E DISTRIBUTION TESTS
TEST SITE E
Test Description
Test 11 Brink Econ Out
Test 14 Brink Econ Out
Test 16 SASS Boiler Out
Test 17 SASS Boiler Out
Size Distribution
% Below % Below
3 ym 10 ym
11.0
4.3
10.7 26.8
9.1 23.3
Size Concentration
lbs/10bBtulbs/10bBtu
Below 3ym Below IQym
0.47
0.28
0.48 1.2
0.41 1.0
80
-------
0.3 I 3
EQUIVALENT PARTICLE DIAMETER, MICROMETERS
Figure 5-22.
Particle Size Distribution at the Economizer
Outlet from Brink Cascade Impactor Tests -
Test Site E.
81
-------
E3
H
50
20
0.1
1 3 10
EQUIVALENT PARTICLE DIAMETER, MICROMETERS
Figure 5-23.
Particle Size Distribution at the Boiler
Outlet from SASS Cyclone Tests - Test Site
82
-------
noted that both methodologies used, sample from a single point within the
duct or breeching. Single point samplers are subject to errors if signifi-
cant size stratification of the flyash exists within the area being tested.
5.5 EFFICIENCY OF MULTICLONE DUST COLLECTOR
The multiclone dust collector efficiency was determined in thirteen
tests under various boiler operating conditions. In each case, collector in-
let and outlet dust loadings were measured simultaneously for best accuracy.
The results of these tests are shown in Table 5-17 and Figure 5-24.
The efficiency of the multiclone dust collector deteriorated with
time during the two months of testing. During the first month of testing the
collection efficiency averaged 87% and dipped below 80% only once. During
the second month of testing, however, the collection efficiency remained below
70% and averaged 55%. Design efficiency is 96% with 15% of the particles
below ten micrometers.
It is theorized that the reduction in collection efficiency resulted
from plugging of several cyclone tubes in the collector, perhaps as a result
of infrequent cleaning of the multiclone ash hopper.
As a result of this problem, no correlation has been attempted between
collection efficiency and other variables such as coal or boiler loading.
5.6 SOURCE ASSESSMENT SAMPLING SYSTEM
Two Source Assessment Sampling System (SASS) tests were run at Test
Site E. One test was run on Kentucky coal and one on East Kentucky coal,
tests 17 and 16 respectively. The sample catches from these two tests were
sent to Battelle Columbus Laboratories where they will be analyzed by combined
gas chromatography/mass spectroscopy for total polynuclear content, seven
specific polynuclear aromatic hydrocarbons (PAH), and trace elements. The SASS
testing is a separately funded segment of this overall test program and all
SASS test results will be reported under separate cover at the conclusion of
this test program.
83
-------
TABLE 5-17
Test
No.
02
03
04
05
06
07
08
09
11
12
13
14
15
20
Coal
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky'
Kentucky
Kentucky
Crushed Kent
Crushed Kent
Crushed Kent
East Kent
Kentucky
TICIENCY OF MULTICLONE DUST COLLECTOR
Design
Capacity
61
46
73
62
65
67
61
57
62
65
48
69
70
63
TEST
02
7.6
8.8
7.2
9.9
9.0
5.2
6.8
7.7
6.5
5.9
9.2
3.9
5.9
7.0
SITE E
Particulate Loading
lb/106Btu
Collector Collector
Inlet Outlet
3.464
2.960
4.972
6.188
2.060
5.230
4.493
3.984
4.316
3.509
3.631
6.469
5.380
4.785
—
0.313
0.198
0.271
0.335
1.824
0.190
0.641
1.558
1.852
1.460
3.843
1.746
2.408
Collector
Efficiency, %
89.4
96.0
95.6
83.7
65.1
95.8
83.9
63.9
47.2
59.8
40.6
67.5
49.7
84
-------
o_
o
t—
z
LU
CJ
0=
LU
Q- °-
S
U_ o
LU o'
LU
O
_1
CJ
o
-H- r
0 300.0
T
400.0
EARLY TESTS
11/16/78 - 12/16/78
LATER TESTS
12/18/78 - 1/18/79
500.0
600.0
700.0
GRRTE HERT RELERSE 1000 BTU/HR SOFT
O : KENTUCKY -j- : CRUSHED KY ^ : ERST KENT. ^ : AMBIENT AIR TESTS
FIG. 5-24
MULTICLONE EFF. VS. GRRTE HERT RELERSE
TEST SITE E
85
-------
TABLE 5-18
POLYNUCLEAR AROMATIC HYDROCARBONS
SOUGHT IN THE SITE E SASS SAMPLES
Name
7,12 Dimethylbenz (a) 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
C18H12
C2lHi6
C20H12
C24H14
C24H14
C20H13N
5.7 DATA TABLES
Tables 5-19 through 5-22 summarize the test data obtained at Test
Site E. These tables, in conjunction with Table 2-1 in the Executive
Summary, are included for reference purposes.
86
-------
TABLE 5-19
PARTICULATE EMISSIONS
TEST SITE E
E-t
3
§
1
H
Test
No.
02
03
04
05
06
07
08
09
11
12
13
14
15
20
Coal
Kent
Kent
Kent
Kent
Kent
Kent
Kent
Kent
Kent
Crushed
Crushed
Crushed
E. Kent
Kent
Load*
61
46
73
62
65
67
61
57
62
65
48
69
70
63
°2
7.6
8.8
7.2
9.9
9.0
5.2
6.8
7.7
6.5
5.9
9.2
3.9
5.9
7.0
EMISSIONS
Ib/lO^Btu
3.464
2.960
4.972
6.188
2.060
5.230
4.493
3.984
4.316
3.509
3.631
6.469
5.380
4.785
gr/SCF
1.601
1.245
2.366
2.367
0.961
2.848
2.203
1.824
2.160
1.828
1.476
3.824
2.801
2.309
lb/hr
467
279
888
864
322
912
708
549
674
582
429
1204
1118
818
Velocity
ft/sec
13.99
11.98
18.97
17.53
17.65
19.92
18.49
18.47
17.94
18.70
18.26
21.00
21.25
21.33
2 W
O 14
O E-i
O
02
Kent
61
7.6
2.966
1.319
400
16.58
g
ti
£J
8 u
p
8 8
H
<
s
03
04
05
06
07
08
09
11
12
13
14
15
20
Kent
Kent
Kent
Kent
Kent
Kent
Kent
Kent
Crushed
Crushed
Crushed
E. Kent
Kent
46
73
62
65
67
61
57
62
65
48
69
70
63
8.8
7.2
9.9
9.0
5.2
6.8
7.7
6.5
5.9
9.2
3.9
5.9
7.0
0.313
0.198
0.271
0.335
1.824
0.190
0.641
1.558
1.852
1.460
3.843
1.746
2.408
0.120
0.092
0.104
0.150
0.880
0.089
0.284
0.769
0.926
0.578
2.018
0.909
1.162
29.5
35.4
37.8
52.3
316
30.0
88.3
243
307
173
715
363
412
35.69
58.71
59.79
52.42
53.19
50.63
45.02
54.20
53.10
52.06
54.16
52.99
55.50
*Load is expressed as a percent of the boilers design capacity.
Maximum obtainable load was 60-70% of design capacity due to a.
retrofit combustion air system.
87
-------
TABLE 5-20
HEAT LOSSES AND EFFICIENCIES
TEST SITE E
3
o
o
g
EH
3
E
•
§
EH
CO
B
02
03
04
05
06
07
08
09
11
17
20
AVG
|
1
6.54
6.61
7.36
8.82
7.60
6.55
7.32
6.66
6.85
6.81
7.33
7.13
Ed
5 Cx)
EH 5
CO fit
H
O 3
0.39
0.59
0.52
0.76
0.63
0.43
0.40
0.48
0.48
0.66
0.81
0.56
1 CM
s «
0 g
2
§§
fa H
f4
O CO
CMD
a PQ
3.77
3.89
3.97
3.87
3.88
3.78
3.89
3.74
3.85
3.89
3.85
3.85
g~
O
CO
CQ m
H —
EH
BS
s ^
o 3
O fa
3.25
2.78
4.67
5.81
5.89
5.64
4.52
3.57
3.60
4.00
5.30
4.46
z
H
CO
03 CO
H fiC
B s
g) S
O O
U PQ
0.44
0.56
0.52
0.69
1.17
0.76
0.31
1.78
1.55
0.55
0.71
0.82
CO
n
^
B
§ H
o 10
0 2
EH H
3.69
3.34
5.19
6.50
7.06
6.40
' 4.83
5.35
5.15
4.55
6.01
5.28
P4
3 3
O n
s*
H S
Q O
^ PCi
K fo
0.75
1.00
0.63
0.79
0.71
0.68
0.75
0.81
0.73
0.68
0.68
0.75
Q
s
a
g
1.50
1.50
1.50
1.50
1.50
1.50
1.50
1.50
1.50
1.50
1.50
1.50
CO
H
CO
Q
^
g
16.64
16.93
19.17
22.24
21.38
19.34
18.69
18.54
18.56
18.09
20.18
19.07
£
£5
w
H
O
H
fe
fa
a
83.36
83.07
80.83
77.76
78.62
80.66
81.31
81.46
81.44
81.91
79.82
80.93
Q J
Q1 f£
^5 C^
K ><
U «
12
13
14
AVG
6.86
8.50
6.25
7.20
0.55
0.55
0.45
0.52
3.86
3.83
3.84
3.84
2.48
3.03
7.70
4.40
0.91
0.82
0.77
0.83
3.39
3.85
8.45
5.23
0.68
0.95
0.63
0.75
1.50
1.50
1.50
1.50
16.84
19.18
21.12
19.05
83.18
80.82
78.88
80.96
S j
*3
S3 8
< w
u
15
16
AVG
9.97
7.51
8.74
0.46
0.71
0.59
3.91
3.87
3.89
4.62
5.98
5.30
0.86
0.81
0.84
5.48
6.79
6.14
0.65
0.68
0.67
1.50
1.50
1.50
21.97
21.06
21.52
78.03
78.94
78.49
88
-------
TABLE 5-21
SUMMARY OF PERCENT COMBUSTIBLES IN REFUSE
TEST SITE E
,
g
o
s
8
^
3
Test
No.
02
03
04
05
06
07
08
09
11
17
20
AVG
Boiler
Outlet
__ _j
—
—
—
62.3
75.3
70.6
62.8
58.6
—
77.8
67.9
Economizer
Hopper
52.71
65.25
41.58
44.14
47.70
44.34
47.96
30.95
51.77
51.68
46.24
47.67
Mechanical
Collector
Hoppe r
50.85
55.47
42.26
38.26
57.83
57.02
42.70
48.59
34.21
33.02
48.49
46.25
Mechanical
Collector
Outlet
__
28.8
20.0
—
61.2
67.2
—
61.4
62.0
—
—
50.1
Bottom
Ash
8.00
5.68
8.24
6.75
10.51
10.10
6.97
16.93
15.84
6.39
8.07
9.41
Q £J
E 0 d
gls
SB
12
13
14
AVG
49.5
58.6
83.5
63.9
53.98
53.98
53.98
53.98
53.86
—
—
53.86
56.0
56.9
—
56.5
11.53
7.70
—
9.60
b
EH 0 J
CQ P <
28
B
15
16
AVG
60.3
—
60.3
71.20
47.89
59.55
57.15
56.95
57.05
12.63
10.46
11.55
89
-------
TABLE 5-22
STEAM FLOWS AND HEAT RELEASE RATES
TEST SITE E
Test
No.
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
20
Capacity*
%
61
46
73
62
65
67
61
57
61
62
65
48
69
70
62
62
65
63
• **
Steam Flow
103lb/hr
109.5
82.9
131.2
110.8
116.9
121.4
109.5
102.0
109.0
112.1
117.6
86.4
124.6
125.8
112.2
111.2
117.9
114.1
***
Heat Input
106Btu/hr
135.0
94.3
178.6
139.6
156.3
173.4
157.7
137.7
156.4
156.2
165.8
118.3
186.1
207.9
175.5
203.1
156.3
171.0
Front Foot
Heat Release
106Btu/hr-ft
8.44
5.89
11.16
8.73
9.77
10.84
9.86
8.61
9.78
9.76
10.36
7.39
11.63
12.99
10.97
12.69
9.77
10.69
Grate
Heat Release
103Btu/hr-ft2
392
274
519
406
454
504
458
400
455
454
482
344
541
604
510
590
454
497
Furnace
Heat Release
103Btu/hr-ft3
13.2
9.2
17.4
13.6
15.2
16.9
15.4
13.4
15.3
15.2
16.2
11.5
18.2
20.3
17.1
19.8
15.2
16.7
* The boilers steam loading was restricted to 60-70% of its
design capacity because of a retrofit combustion air system.
Most of these tests represent the maximum obtainable load
on a given day.
** Based on steam flow integrator and corrected upward by a
factor of 1.2 to account for a calibration error in the
integrator.
*** Based on integrated coal scale counters and higher heating
value of coal.
90
-------
APPENDICES
Page
APPENDIX A English and Metric Units to SI Units 92
APPENDIX B SI Units to English and Metric Units 93
APPENDIX C SI Prefixes 94
APPENDIX D Emissions Units Conversion Factors 95
91
-------
CONVERSION FACTORS
ENGLISH AND METRIC UNITS TO SI UNITS
To Convert From
in
in
ft
To
cm
m
m'
ft
Multiply By
2.540
6.452
0.3048
0.09290
0.02832
Ib
Ib/hr
lb/106BTU
g/Mcal
BTU
BTU/lb
BTU/hr
J/sec
JAr
BTU/ft/hr
BTU/ft/hr
BTU/ft2Ar
BTU/ft2/hr
BTU/ft3/hr
BTU/ft3Ar
psia
"H20
Rankine
Fahrenheit
Celsius
Rankine
FOR TYPICAL COAL FUEL
Kg
Mg/s
ng/J
ng/J
J
JAg
W
W
W
W/m
J/hr/m
W/m2
J/hr/m2
W/m3
JAr/m3
Pa
Pa
Celsius
Celsius
Kelvin
Kelvin
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
ppm @ 3% O2 (SO2)
ppm @ 3% O2 (803)
ppm @ 3% O2 (NO)*
ppm @ 3% 02 (N02)
ppm @ 3% 02 (CO)
ppm @ 3% O2 (CH4)
*Federal environmental
thus NO units should
ng/J (lb/106Btu)
ng/J (Ib/lO^Btu)
ng/J (lb/106Btu)
ng/J (lb/106Btu)
ng/J (lb/106Btu)
ng/J (lb/106Btu)
regulations express NOx in
be converted using the NO2
0.851 (1.98xlO~3)
1.063 (2.47xlO~3)
0.399 (9.28xlO~4)
0.611 (1.42xlO~3)
0.372 (8.65xlO~4)
0.213 (4.95xlO~4)
terms of NO2 ;
conversion factor.
92
-------
CONVERSION FACTORS
SI UNITS TO ENGLISH AND METRIC UNITS
To Convert From
cm
cm
m
m2
m3
Kg
Mg/s
ng/J
ng/J
J
J/kg
J/hr/m
J/hr/m2
J/hr/m3
W
W
W/m
W/m2
W/m3
Pa
Pa
Kelvin
Celsius
Fahrenheit
Kelvin
To
Multiply By
in
in2
ft
ft2
ft3
Ib
Ib/hr
lb/106BTU
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
0.
0.
3.
10.
35.
2.
7.
0.
0.
0.
0.
0.
0.
0.
3.
0.
3937
1550
281
764
315
205
937
00233
00418
000948
000430
000289
0000881
0000269
414
.000278
1.041
0.317
0.0967
0.000145
0.004014
F
F
R
R
= 1.8K-460
= 1.8C+32
= F+460
= 1.8K
FOR TYPICAL COAL FUEL
ng/J
ng/J
ng/J
ng/J
ng/J
ng/J
ppm @ 3% 02 (SO2)
ppm @ 3% O2 (SO3)
ppm @ 3% O2 (NO)
ppm @ 3% O2 (N02)
ppm @ 3% 02 (CO)
ppm @ 3% O2 (CH4)
1.18
0.941
2.51
1.64
2.69
4.69
93
-------
SI PREFIXES
Multiplication
Factor _ Prefix SI Symbol
1018 exa E
1015 peta P
1012 tera T
109 giga G
106 mega M
kilo k
10 hecto* h
10* deka* da
10 deci* d
10~2 centi* c
10~3 milli m
10~6 micro y
10~~9 nano n
10-12 pico p
10~15 femto f
10~18 atto a
*Not recommended but occasionally used
94
-------
EMISSION UNITS CONVERSION FACTORS
FOR TYPICAL COAL FUEL (HV = 13,220 BTU/LB)
Multiply
To "^"-v^ By
Obtain
% Weight in Fuel
S N
lbs/106Btu
S02 N02
grams/106Cal
SO2 NO2
PPM
(Dry @ 3% 02)
SOx NOx
Grains/SCF.
(Dry @ 12% CO2)
SO2 NO2
% Weight
In Fuel
0.666
N
0.370
0.405
13.2xlO~4
0.225
1.48
5.76xlO~4
.903
lbs/106Btu
SO-
1.50
NO-,
(.556)
19.8x10
-4
(2.23)
2.47
(.556)
14.2xlO~4
(2.23)
SO,
2.70
grams/106Cal
(1.8)
NO.
4.44
35.6x10
-4
(4.01)
(1.8)
25.6xlO~4
(4.01)
SOx
PPM
(Dry <§ 3% O2)
NOx
758
505
281
1736
704
1127
391
1566
SO-
.676
Grains/SCF
(Dry @12% C02)
N02
(.448)
(.249)
8.87x10
-4
1.11
(.448)
(.249)
/i
6.39xlO~4
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, particulates, etc.
2. Standard reference temperature of 530°R was used.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-80-064a
3. RECIPIENT'S ACCESSION NO.
4. TITLE ANDSUBTITLE
Field Tests of Industrial Stoker Coal-fired Boilers for
Emissions Control and Efficiency Improvement--
Site E
5. REPORT DATE
March 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.
JAG-D7-E681 (EPA) and
EF-77-C-01-2609 (DOE)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development*
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
PER10D COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTESIERL-RTP project officer is R.E.Hall. (*) Cosponsors are DoE
(W. T. Harvey Jr.) and the American Boiler Manufacturers Assoc. EPA-600/7-78-
136a> -79-041a, -79-130a, and -79-237a are Site A,B,C, and D reports.
16. ABSTRACT
The report gives results of field measurements made on a 180,000 Ib/hr
coal-fired spreader-stoker boiler. The effects of various parameters on boiler emis-
sions and efficiency were studied. Parameters included overfire air, excess air,
boiler load, and coal properties. Measurements included O2, CO2, CO, NO, NO2,
SO2, SOS, controlled and 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. This unit was unique: it used paint oven exhaust gases
as combustion air. Particulate loading on the unit averaged 5. 51 Ib/million Btu un-
controlled at high load. Nitric oxide emissions averaged 0. 53 Ib/million Btu at high
load.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATl Field/Group
Air Pollution
Boilers
Combustion
Coal
Field Tests
Dust
Stokers
Improvement
Efficiency
Flue Gases
Fly Ash
Particle Size
Nitrogen Oxides
Sulfur Oxides
Air Pollution Control
Stationary Sources
Combustion Modification
Spreader Stokers
Particulate
Overfire Air
Flyash Reinjection
13B
13A
21B
2 ID
14B
11G
07B
3. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
102
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
96
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