ABMA
American
Boiler Manufacturers
Association
1500 Wilson Boulevard
Arlington VA 22209
Do I
UllllfcrU Olalco
Department
of Energy
uivision OT rower oysiems
Energy Technology Branch
Washington DC 20545
PA
US Environmental Protection Agency
Office of Research and Development
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-80-112a
May 1980
Field Tests of
Industrial Stoker Coal-
fired Boilers for Emissions
Control and Efficiency
Improvement - Site H
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-600/7-80-112a
May 1980
Field Tests of Industrial Stoker
Coal-fired Boilers for
Emissions Control and Efficiency
Improvement - Site H
by
P.L Langsjoen, R.J. Tidona,
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
EPA Project Officers: R.E. Hall (EPA) and W.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 Assistant
Executive Director, R. N. (Russ) Mosher, ABMA's Project Manager, B. C. (Ben)
Severs, and the members of the ABMA Stoker Technical Committee chaired
by W. B. (Willard) McBurney of the McBurney Corporation for providing
support through their time and travel to manage and review the program. The
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 H were
Mike Gabriel, Jon Cook, Mike Jackson, Mike Bakalor and Mark Shumaker.
Finally, our gratitude goes to the host boiler facilities which in-
vited us to test their boilers. 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
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TABLE OF CONTENTS
Section
ACKNOWLEDGEMENTS
LIST OF FIGURES
LIST OF TABLES
1.0 INTRODUCTION 1
2.0 EXECUTIVE SUMMARY 3
3.0 DESCRIPTION OF FACILITY TESTED AND COAL FIRED 9
3.1 Boiler H Description 9
3.2 Overfire Air System 9
3.3 Test Port Locations 9
3.4 Coal Utilized 13
4.0 TEST EQUIPMENT AND PROCEDURES 15
4.1 Gaseous Emissions Measurements (NOx, CO, CO2, 02, HC,
S02 15
4.1.1 Analytical Instruments and Related Equipment . . 15
4.1.2 Gas Sampling and Conditioning System 20
4.1.3 Continuous Measurements 20
4.2 Sulfur Oxides (SOx) 22
4.3 Particulate Measurement and Procedures 24
4.4 Particle Size Distribution Measurement and Procedure . 24
4.5 Coal Sampling and Analysis Procedure 28
4.6 Ash Collection and Analysis for Combustibles 29
4.7 Boiler Efficiency Evaluation 29
4.8 Trace Species Measurement 30
5.0 TEST RESULTS AND OBSERVATIONS 33
5.1 Overfire Air 33
5.1.1 Particulate Loading vs Overfire Air 33
5.1.2 Nitric Oxide vs Overfire Air 35
5.1.3 Carbon Monoxide and Unburned Hydrocarbon vs
Overfire Air 36
5.1.4 Boiler Efficiency vs Overfire Air 37
5.1.5 Overfire Air Flow Rate 37
5.2 Excess Oxygen and Grate Heat Release 38
5.2.1 Excess Oxygen Operating Levels 40
5.2.2 Particulate Loading vs Grate Heat Release ... 40
5.2.3 Nitric Oxide vs Oxygen and Grate Heat Release . 43
5.2.4 Sulfur Oxides vs Fuel Sulfur 45
5.2.5 Hydrocarbons vs Oxygen and Grate Heat Release . 53
5.2.6 Carbon Monoxide vs Oxygen and Grate Heat Re-
lease 53
5.2.7 Combustibles in the Ash vs Oxygen and Grate
Heat Release 58
5.2.8 Boiler Efficiency vs Grate Heat Release .... 58
1X1
-------
TABLE OF CONTENTS
Section Page
5.3 Coal Properties 62
5.3.1 Chemical Composition of the Coal 62
5.3.2 Coal Size Consistency 65
5.4 Particle Size Distribution of Flyash 67
5.5 Source Assessment Sampling System 71
5.6 Data Tables 72
APPENDICES 75
IV
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LIST OF FIGURES
Figure
No. Page
3-1 General Arrangement Drawing of Boiler H 11
3-2 Boiler H Sample Plane Geometry 12
4-1 Flue Gas Sampling and Analyzing System 21
4-2 Schematic of Goksoyr-Ross Controlled Condensation System (CCS) 23
4-3 EPA Method 5 Particulate Sampling Train 25
4-4 Brink Cascade Impactor Sampling Train Schematic 27
4-5 Source Assessment Sampling (SASS) Flow Diagram 31
5-1 Relationship Between Overfire Air Flow Rate and Static Pressure
Within the Overfire Air Duct - Test Site H 39
5-2 Oxygen vs Grate Heat Release 41
5-3 Boiler Out Part, vs Grate Heat Release 42
5-4 Nitric Oxide vs Grate Heat Release 44
5-5 Nitric Oxide vs Oxygen 46
5-6 Nitric Oxide vs Oxygen 47
5-7 Nitric Oxide vs Oxygen 48
5-8 Nitric Oxide vs Oxygen 49
5-9 Nitrogen Dioxide vs Grate Heat Release 50
5-10 Sulfur Dioxide vs Fuel Sulfur as SO2 51
5-11 Hydrocarbons vs Grate Heat Release 54
5-12 Hydrocarbons vs Oxygen 55
5-13 Carbon Monoxide vs Grate Heat Release 56
5-14 Carbon Monoxide vs Oxygen 57
5-15 Boiler Out Comb, vs Grate Heat Release 59
5-16 Bottom Ash Comb, vs Grate Heat Release 60
5-17 Boiler Efficiency vs Grate Heat Release 61
5-18 Size Consistency of "As Fired" Sands Hill Coal vs ABMA
Recommended Limits of Coal Sizing for Overfed Stokers -
Test Site H 66
5-19 Uncontrolled Particle Size Distribution by Banco classifier
and Sieve Analysis - Test Site H 68
5-20 Uncontrolled Particle Size Distribution by Brink Cascade Im-
pactor - Test Site H 69
5-21 Uncontrolled Particle Size Distribution by SASS Cyclones -
Test Site H 70
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LIST OF TABLES
2-1 Test Plan for Test Site H 7
2-2 Emission Data Summary 8
3-1 Design Data 10
3-2 Average Coal Analysis 14
5-1 Effect of Overfire Air on Emissions and Efficiency 34
5-2 Particulate Loading vs Overfire Air 35
5-3 Nitric Oxide vs Overfire Air 36
5-4 Carbon Monoxide and Hydrocarbon vs Overfire Air 36
5-5 Boiler Efficiency vs Overfire Air 37
5-6 Overfire Air Flow Rate 38
5-7 Ash Carryover vs Load 43
5-8 Nitric Oxide vs Load at Normal Excess Air 43
5-9 Sulfur Balance 52
5-10 Hydrocarbons vs Boiler Load 53
5-11 Boiler Efficiency vs Load 62
5-12 Fuel Analysis - Sands Hill Coal 63
5-13 Mineral Analysis of Coal Ash (Sands Hill Coal) 64
5-14 As Fired Coal Size Consistency - Sands Hill Coal 65
5-15 Description of Particle Size Distribution Tests 67
5-16 Results of Particle Size Distribution Tests 71
5-17 Polynuclear Aromatic Hydrocarbons Analyzed in the Site H SASS
Sample 71
5-18 Uncontrolled Particulate Emissions 72
5-19 Heat Losses and Efficiencies 73
5-20 Percent Combustibles in Refuse 73
5-21 Steam Flows and Heat Release Rates ..... 74
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
information to stoker boiler operators concerning the efficient operation of
their boilers; provide assistance to stoker boiler operators in planning their
coal supply contracts; refine application of existing pollution control 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 air admission, ash handling, grate size, and other variables for
different boiler, furnace, and stoker designs.
A field test program designed to address the objectives outlined above
was awarded to the American Boiler Manufacturers Association (ABMA), sponsored
by the United States Department of Energy (DOE) under contract number
EF-77-C-01-2609, and co-sponsored by the United States Environmental Protection
Agency (EPA) under inter-agency agreement number IAG-D7-E681. The program is
directed by an ABMA Stoker Technical Committee which, in turn, has subcontracted
the field test portion to KVB, Inc., of Minneapolis, Minnesota.
This report is the Final Technical Report for the eighth 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
KVB 15900-542
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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
containing operating guidelines for boiler operators will also be written,
along with a separate report covering trace species data. These reports will
be available to interested parties through the NTIS or through the EPA's
Technical Library.
Although it is EPA policy to use S.I. units in all EPA sponsored
reports, an exception has been made herein because English units have been
conventionally used to describe boiler design and operation. Conversion
tables are provided in the Appendix for those who prefer S.I. units.
To protect the interests of the host boiler facilities, each test
site in this program has been given a letter designation. As the eighth
site tested, this is the Final Technical Report for Test Site H under the
program entitled, "A Testing Program to Update Equipment Specifications and
Design Criteria for Stoker Fired Boilers."
KVB 15900-542
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2.0 EXECUTIVE SUMMARY
A coal fired overfeed stoker rated at 45,000 Ibs steam/hr was
tested for emissions and efficiency at three loads and under various conditions
of excess air and overfire air. Testing was conducted between March 19, 1979,
and April 4, 1979. This section summarizes the results of these tests and pro-
vides references to supporting figures, tables and commentary found in the
main text of the report.
UNIT TESTED; Described in Section 3.0 pages 9-14.
9 Bros Boiler
Built 1959
45,000 Ib/hr rated capacity
140 psig operating steam pressure
Saturated steam
No economizer or air heater
No dust collector
9 Riley Traveling Grate Stoker
Mass Fired
Harrington Traveling Grate
No flyash reinjection
One row OFA jets on front water wall
COAL TESTED: Coal from one mine was tested. Individual coal analysis are
given in Tables 5-12 and 5-13, pages 63 and 64. Commentary
in Section 3.4, page 13, and Section 5.3, page 62.
• Sands Hill Coal
11,417 Btu/lb
8.62% Ash
1.88% Sulfur
11.56% Moisture
2205°F Initial ash deformation temperature
25.9% Fines
KVB 15900-542
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OVERFIRE AIR TEST RESULTS; This unit was normally operated with a low overfire
air setting of about 3" H20 pressure at all loads.
During two tests the overfire air pressure was in-
creased to about 11.5" H2O. In addition, overfire
air flow rate was determined at two pressure settings
(Section 5.1, page 33, Table 5-1, page 34) .
6 Particulate Loading
Increasing overfire air pressure from 2.7 to 11.7" J^O while
maintaining undergrate air flow constant resulted in a 50% re-
duction in uncontrolled particulate loading (Section 5.1.1,
page 33) .
• Nitric Oxide
Nitric oxide concentrations were unaffected by changes in over-
fire air pressure (Section 5.1.2, page 35).
v Carbon Monoxide and Unburned Hydrocarbons
Both carbon monoxide and unburned hydrocarbon concentrations
were reduced significantly when overfire air pressure was in-
creased at high loads (Section 5.1.3, page 36).
9 Boiler Efficiency
Data is inconclusive (Section 5.1.4, page 37).
• Overfire Air Flow Rate
Overfire air was found to supply 12% of the combustion air at
100% capacity, 11.5" H2O pressure in the overfire air duct,
and 8% 02. Data is supplied for determining overfire air flow
rate as a function of pressure (Section 5.1.5, page 37).
BOILER EMISSION PROFILES; Boiler emissions and efficiency were measured over
the load range 50-102% of design capacity, which
corresponds to a grate heat release range of 212,000
to 432,000 Btu/hr-ft^. Measured oxygen levels ranged
from 5.3 to 13.7% (Section 5.2, page 38).
9 Excess Oxygen Operating Levels
The optimum oxygen operating level was determined to be 8.0% at
medium and high loads. Below 8% 02, clinker formation was ex-
cessive (Section 5.2.1, page 40).
KVB 15900-542
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9 Particulate Loading
Particulate loading at full load was 0.90 and 1.13 lb/106 Btu
under high overfire air conditions, and 2.20 lb/106 Btu under
low overfire air conditions. Particulate loading dropped to
0.55 and 0.68 lb/106 Btu at 75% and 50% boiler capacity,
respectively. Ash carryover averaged 7% of the ash in the fuel
(Section 5.2.2, page 40).
9 Nitrogen Oxides
Nitric oxide was more sensitive to oxygen at high loads than
at lower loads. At full load, nitric oxide increased by
0.055 lb/106 Btu for each one percent increase in oxygen. At
75% capacity the slope was 0.040 and at 50% capacity it was
0.019 Ib NO/106 Btu for each one percent O2 increase. Nitric
oxide (NO) averaged 0.416 lb/106 Btu (307 ppm) at full loads
and less at lower loads. Nitrogen dioxide (NO2) averaged 0.004
lb/106 Btu (3 ppm) at all loads (Section 5.2.3, page 43).
9 Sulfur Oxides
Sulfur retention in the ash averaged 3.3%. The remaining 96.7%
of the fuel sulfur was converted to S02 and 803; with 503
accounting for less than 2% of the total (Section 5.2.4, page
45).
9 Hydrocarbons
Unburned hydrocarbons averaged 51 ppm at full load, 78 ppm
at 75% capacity and 104 ppm at 50% capacity. They were
found to be dependent on oxygen, increasing as oxygen increased
at constant load (Section 5.2.5, page 53).
9 Carbon Monoxide
Carbon monoxide remained below 400 ppm except at high loads be-
low 6% 02 and low loads above 13% O2 (Section 5.2.6, page 53).
9 Combustibles in the Ash
Combustibles in the flyash ranged from 23 to 33% by weight.
Combustibles in the bottom ash ranged from 7 to 21% by weight.
Both decreased slightly at full load and showed no correlation
with oxygen (Section 5.2.7, page 58).
KVB 15900-542
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BOILER EFFICIENCY: Boiler efficiency averaged 75.4% at full load, and was
79.2% at 75% of capacity and 77.5% at 50% of capacity.
The drop in efficiency at full load was due to an in-
crease in stack temperature (Section 5.2.8, page 58).
PARTICLE SIZE DISTRIBUTION OF FLYASH; Three particle size distribution
measurements were made of the flyash
using three different techniques. Re-
sults vary with measurement technique
(Section 5.4, page 67).
SOURCE ASSESSMENT SAMPLING SYSTEM; During one test flue gas was sampled for
polynuclear aromatic hydrocarbons and trace
elements. Test results will be presented
in a separate report at completion of test
program (Section 5.5, page 71).
The test plan and the emissions data are summarized in Tables 2-1
and 2-2 on the following pages. Other data tables are included at the end
of Section 5.0, Test Results and Observations. For reference, a Data Supple-
ment containing all the unreduced data obtained at Site H 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.
KVB 15900-542
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TABLE 2-1
TEST PLAN FOR TEST SITE H
FIRING CONDITIONS TEST MEASUREMENTS
% Boiler Excess Overfire Flue Gas Particulate Particle Size Overfire Air Test
Capacity Air Air Composition Loading Distribution SASS 303 Flow Rate No.
100 Vary Low X 1, 2
100 Low Low XXX 3
100 Low High XXX 5
100 High High XX 6
100 Low Low X XXX 11
75 Vary Low X 7
75 Norm Low XX 8
50 Vary Low X 10
50 Norm Low XX 9
50 Norm Vary X X 4
KVB 15900-542
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TABLE 2-2
EMISSION DATA SUMMARY
TEST SITE H
Test
No.
IA
IB
2A
2B
2C
20
2E
2P
3
4
5
6
7A
7B
7C
7D
8
9
10A
10B
IOC
10D
10E
11
Date
3/19/79
3/19/79
3/20/79
3/21/79
3/21/79
3/21/79
3/21/79
3/21/79
3/22/79
3/23/79
3/26/79
3/27/79
3/28/79
3/28/79
3/28/79
3/28/79
3/29/79
3/30/79
3/30/79
3/30/79
3/30/79
3/30/79
3/30/79
4/04/79
% Design
Capacity
88
88
96
96
96
96
96
96
102
50
99
97
76
76
76
76
75
52
51
51
51
51
51
100
Coal
S
S
S
S
S
S
S
S
8
S
S
S
S
5
S
S
S
S
S
S
S
S
S
S
Excess
Air
72
91
49
62
88
73
66
53
58
81
76
97
60
141
88
32
60
114
112
141
72
92
173
75
°2
dry
9.2
10.5
7.2
8.4
10.3
9.3
8.8
7.7
8.0
9.8
9.4
10.6
8.2
12.8
10.1
5.3
8.2
11.6
11.5
12.8
9.2
10.4
13.7
9.4
co2
dry
9.2
7.6
11.0
9.6
7.9
8.9
8.8
9.7
10.8
8.4
9.2
9.1
10.3
5.7
9.4
13.2
10.3
7.3
7.4
5.7
9.2
8.6
5.8
9.2
CO*
ppm
dry
153
239
163
96
274
196
162
712
513
41
41
69
56
340
99
665
76
148
95
265
63
85
443
197
NO*
ppm
dry
305
360
270
275
367
276
312
226
274
279
339
331
207
344
314
161
196
244
247
265
245
252
286
353
NO
lb/106Btu
0.413
0.488
0.366
0.373
0.497
0.374
0.423
0.306
0.371
0.378
0.459
0.448
0.280
0.466
0.425
0.218
0.266
0.331
0.335
0.359
0.332
0.341
0.38?
0.478
NO2
lb/106Btu
_.
—
0.000
0.000
0.000
0.005
0.000
0.000
0.018
—
0.001
0.012
0.001
0.014
0.003
0.000
0.000
0.001
0.012
• 0.000
0.000
0.009
0.000
0.000
SO2
lb/106Btu
..
—
3.014
2 415
2.836
3.258
3.693
3.116
2.617
—
3.524
3.378
5.066
7.358
6.383
4.429
4.539
3.770
3.520
3.106
3.212
3.414
3.351
3.398
HC*
ppm
wet
..
—
OOS
oos
oos
oos
COS
oos
oos
—
5
35
29
132
99
64
68
94
133
113
76
82
127
112
Uncontrolled Special
Particulate Tests or
10/106Btu Conditions
._
—
—
—
--
—
—
2.195 Bahco
—
1.130 Brink, High OFA
0.897 High OFA
—
—
—
—
0.545
0.681
—
—
—
—
—
SASS, SO 3
NOTE: Design Capacity of Boiler is 45,000 Ib/hr Steam
S = Sands Hill Coal
OOS = Analyzer Out-of-Service
SO3 = 33 ppm or 0.065 lb/106Btu as SO2 in Test 11
* All data expressed in parts-per-million (ppm) have been corrected
to 3% O2
KVB 15900-542
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3.0 DESCRIPTION OF FACILITY TESTED AND COAL FIRED
This section discusses the general physical layout and operational
characteristics of the boiler tested at Test Site H. The coal utilized at
this test site is also discussed.
3.1 BOILER H DESCRIPTION
Boiler H is a Bros boiler designed for 200 psig and capable of a
maximum continuous capacity of 45,000 pounds of steam per hour at 140 psig
and saturated temperature.
The unit has a Harrington traveling grate stoker manufacturer by
Riley Stoker Company. Coal is added to the boiler by using a weigh lorry and
is mass fired at the front of the grate. Ash is continuously discharged
into a pit at the end of the grate. There is no suspension burning. Under-
grate air can be controlled in four zones. This unit has no dust collector
and no flyash reinjection. Design data for this unit is presented in Table
3-1.
3.2 OVERFIRE AIR SYSTEM
The overfire air system on Boiler H consists of one row of 10 air
jets on the front wall. The nozzles are 2-1/2 inches in diameter and are lo-
cated 50 inches above the grate at a 45 degree angle. The normal overfire air
pressure was found to be operating at about 3" H2O. At maximum flow the
pressure is about 12" H2O.
3.3 TEST PORT LOCATIONS
Emissions measurements were made at the stack. The location of the
sampling plane is shown in Figure 3-1, and its geometry is shown in Figure 3-2.
KVB 15900-542
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TABLE 3-1
DESIGN DATA
TEST SITE H
BOILER: Manufacturer
Design Pressure
Boiler Heating Surface
Bros
200 psig
5,780 ft2
FURNACE:
Volume
1,850
STOKER: Manufacturer
Type
Width
Length
Effective Grate Area
Riley Stoker Company
Harrington Traveling Grate
13.0 ft
11.0 ft
140.25 ft2
HEAT RATES: Steam Flow
Input to Furnace *
Heat Available *
Furnace Width Heat Release
Grate Heat Release *
Furnace Liberation *
45,000 Ib/hr
59.6 xlO6 Btu/hr
45.3 xlO6 Btu/hr
4.58 XlO6 Btu/ft-hr
425 xlO3 Btu/ft2-hr
32.3 xlO3 Btu/ft3-hr
*Heat rates were determined by KVB based on available
information and are not necessarily those of the
manufacturer.
KVB 15900-542
10
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Sampling Plane
Figure 3-1. General Arrangement Drawing of Boiler H.
KVB 15900-542
11
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Stack Sampling Plane
Cross Sectional Area = 19.6
60*
-f- Particulate Sangling Points
O Gaseous Sampling Points
Q SASS and Brink Sampling Points
A SOx Sampling Point
Figure 3-2. Boiler H Sample Plane Geometry
KVB 15900-542
12
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Particulate loading was measured using a 24-point sample traverse.
Gaseous measurements of Q^ i C®2' ^ an<^ ®® were obtained by pulling samples
individually and compositely from two probes. NC>2, SO2 and unburned hydro-
carbon measurements were made by sampling through a heated line attached to
a probe. Its purpose was to eliminate losses due to condensation. SO3
measurements and SASS samples for organic and trace element determinations were
each obtained from single points.
3.4 COAL UTILIZED
One coal was tested at Test Site H. This coal is identified as
Sands Hill coal as it is from the Sands Hill strip mine in Ohio. Coal samples
were taken for each test involving particulates or SASS sampling. The average
analyses obtained from these samples is presented in Table 3-2. Individual
fuel analyses for each coal sampled are presented in Section 5.0, Test Results
and Observations.
KVB 15900-542
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TABLE 3-2
AVERAGE COAL ANALYSIS
TEST SITE H
SANDS HILL COAL
PROXIMATE (as Rec)
% Moisture
% Ash
% Volatile
% Fixed Carbon
11.56
8.62
35.16
44.66
Btu/lb
% Sulfur
ULTIMATE (as Rec)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen
ASH FUSION (red)
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid
11417
1.88
11.76
63.23
4.36
1.08
0.07
1.72
8.93
8.87
2205°F
2363°F
2403°F
2598°F
KVB 15900-542
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4.0 TEST EQUIPMENT AND PROCEDURES
This section details how specific emissions were measured and
describes the sampling procedures followed to assure that accurate, reliable
data were collected.
4.1 GASEOUS EMISSIONS MEASUREMENTS (NOx, CO, CO2, O2> HC, SO2)
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 (CO?), oxygen (02), gaseous hydrocarbons
(HC), and sulfur dioxide tS02).
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
KVB 15900-542
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Constituent: Carbon Dioxide
Analyzer: Beckman Model 864 NDIR Analyzer
Range: 0-5% and 0-20% CO2
Accuracy: ±1% of full scale
Constituent: Oxygen
Analyzer: Teledyne Model 326A Fuel Cell Analyzer
Range: 0-5, 10, and 25% 02 full scale
Accuracy: il% 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
Constituent: Sulfur Dioxide
Analyzer: Dupont Model 400 Photometric Analyzer
Range: 0-200 ppm and 0-2000 ppm
Accuracy: ll% of reading plus il/4% of full scale range
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 03 to form N02.
Light is emitted when electronically excited NO2 molecules revert to their
ground state. The resulting chemiluminescence is monitored through an optical
filter by a high sensitivity photomultiplier, the output of which is linearly
proportional to the NO concentration.
Air for the ozonator is drawn from ambient air through a dryer and
a ten micrometer filter element. Flow control for the instrument is accomplished
by means of a small bellows pump mounted on the vent of the instrument down-
stream of a separator that prevents water from collecting in the pump.
The basic analyzer is sensitive only to NO molecules. To measure NOx
(i.e., NO+NO2), the NO2 is first converted to NO. This is accomplished by a
converter which is included with the analyzer. The conversion occurs as the
gas passes through a thermally insulated, resistance heated, stainless steel
coil. With the application of heat, NO2 molecules in the sample gas are re-
duced to NO molecules, and the analyzer now reads NOx. NO2 is obtained by the
difference in readings obtained with and without the converter in operation.
KVB 15900-542
16
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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
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 il% of full scale in 24 hours
Zero stability £l% 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%.
KVB 15900-542
17
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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 il% of full scale
Output 4-20 ma
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 ©2 by
volume for operating ranges of 0% to 5%, 0% to 10%, or 0% to 25%.
Specifications: Precision il% 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 Sectarian Model 402
hydrocarbon analyzer which utilizes the flame ionization method of detection.
The sample is drawn to the analyzer through a heated line to prevent the loss
of higher molecular weight hydrocarbons. It is then filtered and supplied to
the burner by means of a pump and flow control system. The sensor, which is
the burner, has its flame sustained by regulated flows of fuel (40% hydrogen
plus 60% helium) and air. In the flame, the hydrocarbon components of the
sample undergo a complete ionization that produces electrons and positive ions.
Polarized electrodes collect these ions, causing a small current to flow through
a circuit. This ionization current is proportional to the concentration of
hydrocarbon atoms which enter the burner. The instrument is available with
range selection from 5 ppm to 10% full scale as 014.
KVB 15900-542
18
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Specifications: Full scale sensitivity, adjustable from 5 ppm CHg 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
Reproducibility tl% of full scale for successive
identical samples
Analysis temperature: auto lent
Ambient temperature 32°F to 110°P
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
Sulfur Dioxide. Sulfur dioxide is measured by a Dupont Model 400
photometric analyzer. This analyzer measures the difference in absorption of
two distinct wavelengths (ultraviolet1 by the sample. The radiation from a
selected light source passes through the sample and then into the photometer
unit where the radiation is split by a semi-transparent mirror into two
beams. One beam is directed to a phototvbe through a filter which removes all
wavelengths except the "measuring" wavelength, which is strongly absorbed by
the constituent in the sample. A second beam falls on a reference phototube,
after passing through an optical filter which transmits only the "reference"
wavelength. The latter is absorbed only weakly, or not at all, by the con-
stituent in the sample cell. The photot\±>es translate these intensities to
proportional electric currents in the amplifier. In the amplifier, full
correction is made for the logarithmic relationships between the ratio of the
intensities and concentration or thickness (in accordance with Beer's Law).
The output is, therefore, linearly proportional, at all times, to the concentra-
tion and thickness of the sample. The instrument has a lower detection limit
of 2 ppm and full scale ranges of 0-200 and 0-2000 ppm.
Specifications: Noise less than 1/4%
Drift less than 1% full scale in 24 hours
KVB 15900-542
19
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Accuracy (-1% of analyzer reading)+(-1/4% of full scale
range)
Sample cell 304 stainless steel, quartz windows
Flow rate 6 CFH
Light source is mercury vapor, tungsten, or "Osram"
discharge type lamps
Power rating 500 watts maximum, 115 V, 60 Hz
Reproducibility 1/4% of scale
Electronic response 90% in 1 sec
Sample temperature 378 K (220°F)
Output 4-20 ma d.c.
4.1.2 Gas Sampling and Conditioning System
A flow schematic of the flue gas sampling and analysis system is shown
in Figure 4-1. The sampling system uses 3 positive displacement diaphragm pumps
to continuously draw flue gas from the stack into the laboratory. The sample
pumps pull from 6 unheated sample lines. Selector valves allow composites of
up to 6 points to be sampled at one time. The probes are connected to the
sample pumps with 0.95 cm (3/8") or 0.64 cm (1/4") nylon line. The positive
displacement diaphrahm sample pumps provide unheated sample gas to the refrigera-
ted condenser (to reduce the dew point to 35°F), a rotameter with flow control
valve, and to the 02, NO, CO, and CO2 instrumentation. Flow to the individual
analyzers is measured and controlled with rotameters and flow control valves.
Excess sample is vented to the atmosphere.
To obtain a representative sample for the analysis of NO2, S02 and
hydrocarbons, the sample must be kept above its dew point, since heavy hydro-
carbons may be condensible and SO2 and NO2 are quite soluble in water. For
this reason, a separate, electrically-heated, sample line is used to bring the
sample into the laboratory for analysis. The sample line is 0.64 cm (1/4-inch)
Teflon line, electrically traced and thermally insulated to maintain a sample
temperature of up to 400°F. Metal bellows pumps provide sample to the hydro-
carbon, SO2 and NOx analyzers.
4.1.3 Continuous Measurements
The laboratory trailer is equipped with analytical instruments to
continuously measure concentrations of NO, N02, CO, C02/ 02/ SO2, and hydro-
carbons. All of the continuous monitoring instruments and sample handling
KVB 15900-542
20
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linpl* Dry l»«pl« llnti
Lint (Typlol Itl-up Hi Llnti).
Plfrlqtritlon Comltmtr
Sanplt
Figure 4-1. Flue Gas Sampling and Analyzing System
KVB 15900-542
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system are mounted in the self-contained mobile laboratory. The entire system
requires only connection to on-site water, power, and sampling lines to be-
come fully operational. The instruments themselves are shock mounted on a
metal console panel. The sample flow control measurement, and selection,
together with instrument calibration are all performed from the console face.
4.2 SULFUR OXIDES (SOx)
Goksoyr-Ross Hethod — Wet Chemical Method
The Goksoyr-Ross Controlled Condensate (G/R) method is used for the
wet chemical 802/803 determination. It is a desirable method because of its
simplicity and clean separation of particulate matter, SO2 and I^SO^ (803) .
This procedure is based on the separation of 112804(503) from SO2 by cooling
the gas stream below the dew point of I^SO^ but above the H2O dew point.
Figure 4-2 illustrates schematically the G/R test system.
Particulate matter is first removed from exhaust gas stream by
means of a quartz glass filter placed in the heated glass filter holder.
Tissue-quartz filters are recommended because of their proven inertness to
1^304. The filter system is heated by a heating tape so that the gas out
temperature of 260°C (500°F) is maintained. This temperature is imperative
to ensure that none of the H2S04 will condense in the filter holder or on the
filter.
The condensation coil where the r^SO^ is collected is cooled by water
which is maintained at 60°C (140°F) by a heater/recirculator. This temperature
is adequate to reduce the exhaust gas to below the dew point of 112804.
Three impingers are shown in Figure 4-2. The first impinger is
filled with 3% ^©2 to absorb SO2- The second impinger is to remove carry
over moisture and the third contains a thermometer to measure the exhaust gas
temperature to the dry gas meter and pump. The sampling rate is 2.3 1pm
(0.08 CFM).
KVB 15900-542
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For both SO2 and 112804 determination, the analytical procedure is
identical. The H2S04 sample is washed from the back part of the filter holder
and the coil using distilled water. The sample from the first impinger which
is assumed to be absorbed and reacted SC>2 in the form of H2SO4 is recovered
with distilled water washing. The amount of H2SO4 in the condensate from the
coil and from the H2O2 impinger is measured by H+ titration. Broraphenol Blue
is used with NaOH as the titrant.
Adapter for Connecting Hose
TC Wei
Asbestos Cloth
Insulation
Glass-Cloth Heating
Mantle **"*•
Stack
Vacuum
Gauge
Dry Test
\
Gas Flow
Rccirculator
lennometer
Styrofoan Ice Chest
Figure 4-2.
Schematic of Goksoyr-Ross Controlled
Condensation System (CCS).
KVB 15900-542
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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 4-3). 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. Hie 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.
All peripheral equipment is carried in the instrument van. This
includes a scale (accurate to to.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 PROCEDURE
Particle size distribution is measured using several methods. These
include the Brink Cascade Impactor, SASS cyclones, and the Bahco Classifier.
Each of these particle sizing methods has its advantages and disadvantages.
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 instrument's small classification
KVB 15900-542
24
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PROBE
THERMOMETER
HEATED AREA
STACK
THERMOMETER
REVERSE-TYPE
PITOT TUBE
FILTER HOLDER
THERMOMETER
—= THERMOMETER
THERMOMETER
IMP1NGERS ICE BATH
THERMOMETERS F'NE CONTROL VALVE
ORIFICE
GAUGE
CHECK VALVE
VACUUM LINE
VACUUM
GAUGE
COARSE CONTROL VALVE
DRY TEST METER
AIR-TIGHT
PUMP
Figure 4-3. EPA Method 5 Participate Sampling Train
KVB 15900-542
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range (0.3 to 3.0 micrometers) and its small sample nozzle (1.5 to 2.0 mm
maximum diamter). Both are inadequate for the job at hand. 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 maintain
isokinetic flow rates within the recommended .02-.07 ft3/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.
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 4-4.
Banco. The Bahco classifier is described in Power Test Code 28. it
is an acceptable particle sizing method in the power industry and is often used
in specifying mechanical dust collector guarantees. Its main disadvantage is
that it is only as accurate as the sample collected. Most Bahco samples are
collected by cyclone separation; thus, particles below the cut point of the
cyclone are lost. The Bahco samples collected at Test Site F came from the
cyclone in the EPA Method 5 particulate train. These samples are spatially
representative because they are taken from a 12-point sample matrix. However,
much of the sample below about seven micrometers is lost to the filter. The
Bahco test data are presented in combination with sieve analysis of the same
sample. An attempt was made to correct for the lost portion of the sample.
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 part 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
KVB 15900-542
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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 4-4. Brink Cascade Impactor Sampling Train Schematic
KVB 15900-542
27
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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 4.8.
4.5 COAL SAMPLING AND ANALYSIS PROCEDURE
Coal samples at Test Site H were taken during each test from the
weigh lorry, as coal was being added to the boiler. The samples were processed
and analyzed for both size consistency and chemical composition. This is close
enough to the furnace that the coal sampled simultaneously with testing is
representative of the coal fired during the testing. In order to collect
representative coal samples, ten pounds of coal were taken from each batch
added from the weigh lorry.
The sampling procedure is as follows. At the start of testing one
increment of sample is collected from the weigh lorry. This is repeated for
each batch of coal added during the test (three to five hours duration) so
that a 7 to 12 increment sample is obtained. The total sample is then riffled
using a Gilson Model SP-2 Porta Splitter until two representative twenty point
samples are obtained.
The sample to be used for sieve analysis is air dried overnight.
Drying of the coal is necessary for good separation of fines. If the coal is
wet, fines cling to the larger pieces of coal and to each other. Once dry,
the coal is sized using a six tray Gilson Model PS-3 Porta Screen. Screen
sizes used are 1", 1/2", 1/4", #8 and #16 mesh. Screen area per tray is
14"xl4". The coal in each tray is weighed on a triple beam balance to the
nearest 0.1 gram.
The coal sample for 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 incre-
ment of coal for each test for each coal type receive ultimate analysis, ash
fusion temperature, mineral analysis, Hardgrove grindability and free swelling
index measurements.
KVB 15900-542
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4.6 ASH COLLECTION AND ANALYSIS FOR COMBUSTIBLES
The combustible content of flyash is determined in the field by
KVB in accordance with ASTM D3173, "Moisture in the Analysis Sample of Coal
and Coke" and ASTM D3174, "Ash in the Analysis Sample of Coal and Coke."
The flyash sample is collected by the EPA Method 5 particulate sample
train while sampling for participates. 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 H the bottom ash samples were collected in several in-
crements from the ash pit, after testing. These samples were mixed, quartered,
and sent to Commercial Testing and Engineering Company for combustible deter-
mination .
4.7 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, combustible
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, and combustibles in the flyash leaving the boiler.
KVB 159QO-542
29
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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 4-5) . 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 ym B) 3 ym to 10 ym C) 1 ym to 3 ym
Together with a filter, a fourth cut (<1 ym) is obtained. Volatile organic
material is collected in an XAD-2 sorbent trap. The XAD-2 trap is an integral
part of the gas treatment system which follows the oven containing the cyclone
system. The gas treatment system is composed of four primary components: the
gas conditioner, the XAD-2 organic sorbent trap, the aqueous condensate
collector, and a temperature controller. The XAD-2 sorbent is a porous 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 ob-
tained from a main controller.
KVB 15900-542
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Convection
•ten
Filter
Gis cooler
Inp/caoler
trice element
collector
Dry ttlt ottir
Figure 4-5. Source Assessment Sampling (SASS) Flow Diagram
KVB 15900-542
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5.0 TEST RESULTS AND OBSERVATIONS
This section presents the results of tests performed on Boiler H.
Observations are made regarding the influence on efficiency and on gaseous and
particulate emissions as the control parameters are varied. Eleven defined
tests were conducted over a two and one-half week period to develop this data.
In addition to the many tables and figures presented in this section, reference
may be made to Tables 2-1 and 2-2 in the Executive Summary, and to Tables 5-18
through 5-21 at the end of this section.
5.1 OVERFIRE AIR
Boiler H has an overfire air (OFA) system consisting of a single row
of air jets along the front water wall just above the arch. Air flow to these
jets is controlled manually. Upon arrival at the test site, it was discovered
that the normal operating procedure was to leave the overfire air set at between
2.4 and 3.0 inches water pressure at all boiler loads. The operators of this
unit believe that the low overfire air setting results in a higher boiler
efficiency and reduced clinkering. This low overfire air setting was used as
the "norm" or baseline condition in these tests.
During Test 4, the overfire air flow rate (Ib/hr) was measured and
related to static pressure in the overfire air duct. During Tests 5 and 6 the
overfire air pressure was increased to 11.7 and 11.2 inches water pressure,
respectively.
The general conclusion was that high overfire air pressure is the de-
sirable mode of operation on this boiler at full steaming capacity. It was
determined that the overfire air system on this boiler supplies 12% of the actual
combustion air at full load (8% 02 and 11.5" H2O overfire air pressure). The
test data are summarized in Table 5-1 and discussed in the following si±»sections.
5.1.1 Particulate Loading vs Overfire Air
The data show a 50% reduction in particulate loading when the over-
fire air pressure was increased from 2.7 to 11.7" H2O while maintaining under-
KVB 15900-542
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TABLE 5-1
EFFECT OF OVERFIRE AIR ON EMISSIONS AND EFFICIENCY
TEST SITE H
Test No.
Description
3
Low OFA
High OFA
High OFA
FIRING CONDITIONS
Load, % of Capacity
Grate Heat Release, lO-^tu/hr-ft
Coal Fines, % Passing 1/4"
Excess Air, %
Overfire Air Pressure,
BOILER EMISSIONS
Particulate Loading, lb/106Btu
Combustible Loading, lb/106Btu
Inorganic Ash Loading, lb/106Btu
Combustibles in Flyash, %
O2, % (dry)
C02, % (dry)
CO, ppm (dry) @
NO, lb/106Btu
N02, lb/106Btu
S02, lb/106Btu
3% O2
HEAT LOSSES, %
Dry Gas
Moisture in Fuel
H2O from Combustion of H2
Combustibles in Flyash
Combustibles in Bottom Ash
Radiation
Unmeasured
Total Losses
Boiler Efficiency
102
432
37
58
2.7
99
421
24
76
11.7
97
413
23
97
11.2
2.195
—
— -
*
8.0
10.8
513
0.371
0.018
2.617
1.130
0.260
0.870
23.0
9.4
9.2
41
0.459
0.001
3.524
0.897
0.226
0.671
25.2
10.6
9.1
69
0.448
0.012
3.378
12.77
1.14
4.17
0.87*
1.54
0.64
1.50
22.63
77.37
13.93
1.43
4.31
0.37
2.52
0.65
1.50
24.71
75.29
13.85
1.45
4.40
0.32
2.67
0.67
1.50
24.86
75.14
*Test 3 flyash was sent to a laboratory for Bahco size classification and
was available in insufficient quantity for both Bahco and combustibles
determination. 28% combustibles in flyash was assumed.
KVB 15900-542
34
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grate air flow constant. It is believed that at least some of the reduction
in particulate mass loading was due to more complete carbon burnout of the
flyash, but combustible data are not available to confirm this belief. The
particulate vs overfire air test data are shown in Table 5-2.
TABLE 5-2
PARTICULATE LOADING VS OVERFIRE AIR
Test Particulate Loading
No. Overfire Air lb/106 Btu
3 Low - 2.7" H2O 2.20
5 High - 11.7" H2O 1.13
6 High - 11.2" H2O 0.90
5.1.2 Nitric Oxide vs Overfire Air
Nitric oxide emissions did not change as a function of overfire air.
The test data, shown in Table 5-3, indicate that the low overfire air nitric
oxide concentration is bracketed by the two high overfire air concentrations
when corrections are made for differences in excess oxygen. The excess oxygen
correction accounts for the fact that nitric oxide concentration increases
by .055 lb/106 Btu for each one percent increase in oxygen on this boiler
at full capacity (see Figure 5-6 in Section 5.2 for supporting data).
KVB 15900-542
35
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TABLE 5-3
NITRIC OXIDE VS OVERFIRE AIR
Test
No.
3
5
6
Overfire Air % 02
Low - 2.7" H20 8.0
High - 11.7" H20 9.4
High - 11.2" H2O 10.6
Measured
Nitric Oxide
lb/106Btu
0.371
0.459
0.448
Nitric Oxide
Corr to 8.0% O2
lb/106Btu
0.371
0.382
0.305
5.1.3 Carbon Monoxide and Unburned Hydrocarbon vs Overfire Air
The data indicate that increasing overfire air flow decreases both
carbon monoxide and unburned hydrocarbon emissions. The two high overfire air
tests produced the two lowest emission levels in both categories. The test
data are presented in Table 5-4 (see Figure 5-12 and 5-14 in Section 5.2 for
supporting data).
TABLE 5-4
CARBON MONOXIDE AND HYDROCARBON VS OVERFIRE AIR
Test
No. Overfire Air
1A-B Low - 2.4" H20
3 Low - 2.7" H2O
2A-F Low - 2.8" H20
11 Low - 3.0" H20
6 High - 11.2" H20
5 High - 11.7" H2O
Carbon Monoxide
ppm @ 3% 02 (dry)
153-239
513
96-712
197
69
41
Unburned Hydrocarbons
ppm @ 3% O? (dry)
112
35
5
KVB 15900-542
36
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5.1.4 Boiler Efficiency vs Overfire Air
Boiler efficiency appears to decrease at high overfire air settings,
but data are incomplete and factors other than overfire air are suspected to
contribute to this effect. The data, shown in Table 5-5, show a measured two-
percent decrease in boiler efficiency as overfire air is increased. One per-
cent of this decrease is in the dry gas heat loss category, and is a result of
the increased excess air. Another one percent of the decreased efficiency is in
the bottom ash combustible category and it also may not be related to overfire
air conditions. A better indicator of the effect of overfire air on boiler
efficiency is the flyash combustible heat loss. Since data in this area are
only estimated, no relationship was established.
TABLE 5-5
BOILER EFFICIENCY VS OVERFIRE AIR
SELECTED HEAT LOSSES
12.77
13.93
13.85
1.54
2.52
2.67
0.87
0.37
0.32
77.37
75.29
75.14
Test Bottom Ash Flyash Boiler
No. Overfire Air Dry Gas Combustibles Combustibles Efficiency, %
3 Low - 2.7" H20
5 High - 11.7" H20
6 High - 11.2" H20
5.1.5 Overfire Air Flow Rate
The rate at which air is injected into the furnace above the grate was
measured using a standard pitot tube traverse of the overfire air duct. This
measurement was made at three overfire air settings corresponding to 2.8, 7.2,
and 11.2" H2O. The 2.8" H2O measurement data was discarded because excessive
turbulence distorted the data. The results of the other two tests are believed
to be reasonably accurate and are presented in Table 5-6.
KVB 15900-542
37
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The relationship between overfire air flow rate and overfire air
pressure is plotted in Figure 5—1. Bernoulli's equation for fluid flow through
an orifice is used in conjunction with the test data to create this relation-
ship. Bernoulli's equation predicts that flow rate will be proportional to the
square root of the pressure drop. This curve is adequate for predicting the
overfire air flow rate on Boiler H at any overfire air pressure setting.
At 100% boiler capacity, 11.5 inches water pressure in the overfire
air duct and 8% C>2, the overfire air system supplies 12% of the combustion air
on Boiler H. This result is based on calculations indicating that 83,900 Ib/hr
air are required to burn Sands Hill coal at 8% 02-
TABLE 5-6
OVERFIRE AIR FLOW RATE
Overfire Air Pressure Air Flow % Combustion Air Supplied by OFA
"H?O Ib/hr @ 8% O? and 100% Capacity
11.2 10,240 (measured) 12.2
7.2 9,710 (measured) 11.6
2.8 5,530 (estimated) 6.6
5.2 EXCESS OXYGEN AND GRATE HEAT RELEASE
The boiler at Test Site H was tested for emissions and boiler efficiency
at three boiler loadings representing 100%, 75% and 50% of design steaming
capacity. At each load the boiler was tested over a wide range of excess air
conditions. This section profiles the various emissions and the boiler
efficiencies as a function of these two variables.
Boiler steam loading is expressed in terms of grate heat release. At
full load, the grate heat release on this unit was 504,000 Btu/hr-ft2. Excess
air is expressed in terms of percent oxygen in the flue gas.
KVB 15900-542
38
-------
|o
CN
D
OT
U
H
CO
s
PREDICTED RELATIONSHIP^
2468
OVERFIRE AIR FLOW RATE, 103 LB/HR
10
12
Figure 5-1. Relationship Between Overfire Air Flow Rate and Static
Pressure Within the Overfire Air Duct - Test Site H.
KVB 15900-542
39
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5.2.1 Excess Oxygen Operating Levels
Figure 5-2 depicts the various conditions of grate heat release and
excess oxygen under which tests were run on the boiler at Site H. Solid symbols
are used to distinguish tests which included particulate mass loadings from
those which did not.
Pull design capacity of 45,000 Ib steam/hour was easily met on this
unit without significant deterioration in combustion efficiency. At full
capacity the unit was operated at oxygen levels ranging from a low of 7.2%
(49% excess air) to a high of 10.6% (97% excess air). The optimum full load
excess oxygen operating point was 8% O2 (58% excess air) in these tests. Below
8% C>2f clinker formation was excessive. At 75% capacity the unit was observed
to operate satisfactorily at 8.2% (>2, but clinkered up at 5.3% 02-
5.2.2 Particulate Loading vs Grate Heat Release
Figure 5-3 presents the Boiler H particulate loading as a function of
grate heat release. These measurements were made at the stack, but because the
unit has no mechanical dust collector they are representative of the boiler
outlet particulate loading.
The shaded area of Figure 5-3 encompasses the particulate data obtained
under optimum operating conditions. The solid symbol represents the low overfire
air test run at high load. This operating condition was determined to be
undesirable because of the resulting high particulate loading shown in this
figure. The uncontrolled variable coal fines (.%
-------
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OPTIMUM 02
EXCESSIVE
CLINKERING
I
0
1 I 1 1 1—
100.0 200.0 300.0 400.0 500.0
GRRTE HEflT RELEflSE 1000 BTU/HR-SQ FT
: GfiSEOUS
PflRT. TEST
FIG. 5-2
EXCESS OXYGEN
TEST SITE H
VS. GRRTE HEflT RELEflSE
4-15900-542
41
-------
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TEST 3, LOW OFA
37% FINES
24% FINES
36% FINES
23% FINES
14% FINES
T
T
T
0
100.0 200.0 300.0 400.0 500.0
GRRTE HERT RELERSE 1000 BTU/HR-SQ FT
: PflRT. TEST
FIG. 5-3
BOILER OUT. PflRT.
TEST SITE H
VS. GRRTE HERT RELERSE
4-15900-542
42
-------
5
6
8
9
99
97
75
52
7.64
11.67
8.59
7.25
0.870
0.671
0.379
0.454
TABLE 5-7
ASH CARRYOVER VS LOAD
TEST SITE H
Test % Ash Content of Coal Ash Content of Ash Carryover
No. Capacity lb/106Btu Flyash, lb/106Btu %_
11.4
5.8
4.4
6.3
5.2.3 Nitric Oxide vs Oxygen and Grate Heat Release
Nitric oxide (NO) and nitrogen dioxide (NO2) concentrations were
measured during each test in units of parts per million (ppm) by volume. A
chemiluminescent NOx analyzer was used to make these measurements. The ppm
units have been converted to units of lb/10°Btu in this report so they can be
more easily compared with existing and proposed emission standards. Table 2-1
in the Executive Summary lists the nitric oxide data in units of ppm for the
convenience of those who prefer these units.
Figure 5-4 presents the nitric oxide data as a function of grate
heat release under the various excess air conditions encountered during testing.
The average nitric oxide emissions increase as full boiler capacity is approached.
Table 5-8 illustrates the trend of nitric oxide with load under normal operating
conditions.
TABLE 5-8
NITRIC OXIDE VS LOAD AT NORMAL EXCESS AIR
100% Capacity
75% Capacity
50% Capacity
Oxygen
% (dry)
9.1±1.1
8.9±2.8
11.3±1.6
Nitric Oxide
lb/106Btu
0.4161.059
0.3311.108
0.3521.023
Nitric Oxide
ppm (dry) @ 3% O?
307±44
244±80
260117
KVB 15900-542
43
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—I 1
100.0 200.0
T
0
300.0 400.0 500.0
GRRTE HEflT RELEflSE 1000 BTU/HR-SQ FT
: GASEOUS
: PflRT. TEST
FIG. 5-4
NITRIC OXIDE
TEST SITE H
VS. GRRTE HERT RELEflSE
4-15900-542
44
-------
When plotted as a function of oxygen, nitric oxide was found to relate
to oxygen differently at the different loads. Figure 5-5 presents all of the
nitric oxide data as a function of oxygen. Figures 5-6, 5-7, and 5-8 present
the data for each of the three loads separately. In each plot, a trend line
has been applied to the data by linear regression analysis. The slope of these
trend lines indicate that nitric oxide increases by 0.055 Ib NO/10°Btu at full
load, 0.041 Ib NO/106Btu at 75% capacity and 0.006 Ib NO/106Btu at 50% capacity.
Thus, nitric oxide was found to be less sensitive to oxygen at lower loads.
Nitrogen dioxide (NC>2) was also measured at Site H. Of the twenty-one
determinations made, eleven were zero and the remaining ten ranged from 0.001
to 0.018 lb/10^3tu. The average was 0.004 ]_b/10"Btu (3 ppm) , or one percent of
the total NOx. The NO2 data is plotted as a. function of grate heat release in
Figure 5-9.
Concentrations of NO2 this small are difficult to measure especially
when NOx concentrations are varying with time. Such was the case at Site H.
Therefore, averages are more meaningful than individual results. The reason for
this is that with the chemiluminescent NOx analyzer NO2 is determined as the
difference between consecutive, not simultaneous, measurements of NOx and NO.
Each of these measurements are accurate to about one percent at best. As an
example, NO2 = 384±4 ppm - 380±4 ppm = 4±8 ppm.
5.2.4 Sulfur Oxides vs Fuel Sulfur
Sulfur dioxide (5O2) was measured during each test using an NDIR type
continuous monitor. Sulfur tricod.de (SO3) was measured once using a wet chemical
method called the Goksoyr-Ross method. The test data and their significance are
discussed in this section.
Sulfur dioxide concentrations were directly related to the sulfur
content of the fuel. SO2 was not observed to vary with load or 02. The small
fraction of fuel sulfur which was not converted to SO2 was either retained in
the ash or converted to S03 and other sulfur compounds.
Sulfur dioxide is plotted as a function of fuel sulfur in Figure 5-10.
The diagonal line in this plot represents 100% conversion of fuel sulfur to SO2.
KVB. 15900-542
45
-------
00
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0 8
-
100% LOAD
75%
LOAD
T
T
0
4.00 6.00
EXCESS OXYGEN
A : LOW LORD -f : NED LOUD
FIG. 5-5
NITRIC OXIDE
TEST SITE H
8.00 10.00 12.00
PERCENT (DRY)
: HIGH LOW
VS. EXCESS OXYGEN
SOLID LINES REPRESENT TRENDS AT THKEE LOADS AS DETERMINED
BY LINEAR REGRESSION ANALYSIS
4-15900-542
46
-------
CD
O
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LO
o
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O
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8-
100% DESIGN CAPACITY
HIGH OFA
HIGH OFA
0
6.00 8.00
EXCESS OXYGEN
—I 1 1
10.00 12.00 14.00
PERCENT (DRY)
HIGH LORD
FIG. 5-6
NITRIC OXIDE
TEST SITE H
VS. EXCESS OXYGEN
TREND LINE DETERMINED BY LINEAR REGRESSION ANALYSIS, SLOPE =
0.055, COEFFICIENT OF DETERMINATION (R) = 0.83, HIGH OVERFIRE
AIR IS SHOWN TO HAVE NO EFFECT ON NITRIC OXIDE CONCENTRATION.
47
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75% DESIGN CAPACITY
-TT 1 1—
0 6.00 8.00
EXCESS OXYGEN
4- : NED LORD
FIG. 5-7
NITRIC OXIDE
TEST SITE H
10.00 12.00 14.00
PERCENT (DRY)
VS. EXCESS OXYGEN
TREND LINE DETERMINED BY LINEAR REGRESSION ANALYSIS,
SLOPE + 0.040, COEFFICIENT OF DETERMINATION (R) = 0.94.
4-15900-542
48
-------
CO
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in
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•x o
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O
x
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50% DESIGN CAPACITY
0
6.00 8.00
EXCESS OXYGEN
10.00 12.00
PERCENT (DRY)
14.00
: t-ou LORD
FIG. 5-8
NITRIC OXIDE
TEST SITE H
VS. EXCESS OXYGEN
TREND LINE DETERMINED BY LINEAR REGRESSION ANALYSIS,
SLOPE = 0.019, COEFFICIENT OF DETERMINATION (R) =0.44
4-15900-542
49
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HIGH OFA
HIGH OFA
0
100.0 200.0 300.0 400.0 500.0
GRRTE HEflT RELEflSE 1000 BTU/HR-SQ FT
I PflRT. TEST
FIG. 5-9
NITROGEN DIOXIDE
TEST SITE H
VS. GRflTE HEflT RELEflSE
4-15900-542
50
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100% CONVERSION OF FUEL S TO SO2
1.000 2.000 3.000 4.000 5.000
FUEL SULFUR RS 302 LB/MILLION BTU
FUEL S
FIG. 5-10
SULFUR DIOXIDE
TEST SITE H
VS. FUEL SULFUR RS S02
4-15900-542
51
-------
It is shown that within measurement error, virtually 100% of the fuel sulfur
is converted to SO2-
Sulfur retention in the bottom ash was determined by direct measure-
ment for the five particulate tests. This data, shown in Table 5-9, shows that
an average 2.9% of the fuel sulfur was retained in the bottom ash. Assuming
similar sulfur concentrations in the flyash, it is calculated that an average
0.4% of the fuel sulfur is retained in this ash. Thus, 96.7% of the fuel
sulfur is converted to SC>2 and S03 while 3.3% is retained in the ash.
Table 5-9 is a sulfur balance on Boiler H. With the exception of
Test 8, the balance is within acceptable limits for measurement accuracy. Even
the six percent average of Test 5 could be accounted for by a fuel sulfur
determination error of only 0.13% (i.e. 2.10% sulfur instead of 1.97% sulfur
in the fuel would yield 100% balance).
Sulfur trioxide (S03) was measured once during Test 11 and found to
be 0.065 lb/106Btu (33 ppm). This is 1.9% of the total SOx (SO2 + SO3).
TABLE 5-9
SULFUR BALANCE
TEST SITE H
Test Sulfur in Fuel
No. lb/106Btuas SO, (A)
3 2.667
5 3.449
6 3.441
8 3.678
9 3.822
Sulfur In Bottom Ash
lb/106Btu as SO2 » of (A)
0.064
0.128
0.077
0.155
0.083
2.4
3.7
2.2
4.2
2.2
Sulfur in Flyash*
Ib/106Btu as SO? * of (A)
0.026
0.017
0.005
0.008
0.007
1.0
0.5
0.2
0.2
0.2
Sulfur in Flue Gas
lb/106Btu as so? % of (A)
2.617 98.1
3.524
3.378
4.539
3.770
102.2
98.2
123.4
98.6
• I Sulfur in Flyuah Assumed to be the Same as in Bottom Ash
KVB 15900-542
52
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5.2.5 Hydrocarbons vs Oxygen and Grate Heat Release
Unburned hydrocarbons (HC) were measured with a heated sample line
and a continuous monitoring instrument utilizing the flame ionization method
of detection. Test data are plotted as a function of grate heat release in
Figure 5-11, and as a function of oxygen in Figure 5-12.
There is some indication that the concentration of hydrocarbons in
the flue gas increased as the load decreased. This slight dependence on load
is illustrated in Table 5-10.
TABLE 5-10
HYDROCARBONS VS BOILER LOAD
TEST SITE H
No. of Measurements Average HC, ppm
100% Capacity 3 51±55
75% Capacity 5 78±39
50% Capacity 6 104±24
Hydrocarbon concentrations were found to be highly dependent on
oxygen as shown in Figure 5-12. Hydrocarbon concentration increased as oxygen
increased. Figure 5-12 also illustrates how high overfire air effectively re-
duced the hydrocarbon concentration at high load.
5.2.6 Carbon Monoxide vs Oxygen and Grate Heat Release
Carbon monoxide (CO) was measured with an NDIR continuous monitor in
units of parts per million (ppm) by volume. The data are plotted as a function
of grate heat release in Figure 5-13, and as a function of oxygen in Figure 5-14.
Carbon monoxide concentrations were found to increase slightly with
load, and to be at their minimum at 9% 02- In general, carbon monoxide concen-
trations remained well below 400 ppm (0.04%), which is considered acceptable for
a coal-fired stoker boiler. Unacceptable conditions included excess oxygen below
6% or above 13%, and low overfire air at high loads.
KVB 15900-542
53
-------
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50% LOAD 75% LOAD
100% LOAD
0
100.0 200.0 300.0 400.0 500.0
GRflTE HERT RELEflSE 1000 BTU/HR-SQ FT
: GRSEDUS
; PflRT. TEST
FIG. 5-11
HYDROCRRBONS
TEST SITE H
VS. GRflTE HEflT RELEflSE
4-15900-542
54
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TEST 5
HIGH OFA
4.00 6.00
EXCESS OXYGEN
8.00 10.00 12.00
PERCENT (DRY)
: LOW LOflD
: MED LOUD O: HIGH urn
FIG. 5-12
HYDROCRRBONS
TEST SITE H
VS. EXCESS OXYGEN
4-1S90D-542
55
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HIGH
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0
100.0 200.0 300.0 400.0 500.0
GRflTE HERT RELERSE 1000 BTU/HR-SQ FT
: GRSEOUS
J PflRT. TEST
FIG. 5-13
CflRBON MONOXIDE
TEST SITE H
VS. GRflTE HEflT RELEflSE
4-15900-542
56
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100% LOAD
I-J-
HIGH OFA
HIGH OFA
-T7
4.00 6.00
EXCESS OXYGEN
A : LOW LORD -f : HED LORD
FIG. 5-14
CflRBON MONOXIDE
TEST SITE H
T
T
8.00 10.00 12.00
PERCENT (DRY)
3 : HIGH LORD
VS. EXCESS OXYGEN
SOLID LINES REPRESENT OBSERVED TRENDS AT THE THREE LOADS
4-15900-542
57
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5.2.7 Combustibles in the Ash vs Oxygen and Grate Heat Release
Samples of flyash and bottom ash were baked in a high temperature oven
for determination of combustible content. The test results are plotted in
Figures 5-15 and 5-16 as a function of grate heat release. Combustibles in the
boiler outlet flyash (Figure 5-15} appear to decrease slightly with increasing
load. However, they all fall in the narrow range of 23-33% combustibles by
weight. Combustibles in the bottom ash (Figure 5-16) also decrease slightly at
high load but not enough to be considered significant. Combustibles in the
bottom ash ranged from 7-21% by weight. Combustibles in the ash showed no
correlation with excess oxygen in either case.
5.2.8 Boiler Efficiency vs Grate Heat Release
Boiler efficiency was determined using the ASME heat loss method for
all tests which included a particulate mass loading or SASS determination. The
test data are plotted as a function of grate heat release in Figure 5-17. The
shaded area on this figure represents how the boiler efficiency may relate to
grate heat release. It shows that boiler efficiency drops off slightly at full
load (425,000 Btu/hr-ft2 grate heat release).
KVB 15900-542
58
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o
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0
T
T
T
100.0 200.0 300.0 400.0 500.0
GRflTE HEflT RELERSE 1000 BTU/HR-SQ FT
: PflfiT. TEST
FIG. 5-15
BOILER OUT. COMB.
TEST SITE H
VS. GRflTE HEflT RELEflSE
4-15900-542
59
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8
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100.0 200.0 300.0 400.0 500.0
GRRTE HEflT RELEflSE 1000 BTU/HR-SQ FT
PflRT. TEST
FIG. 5-16
BOTTOM flSH COMB.
TEST SITE H
VS. GRflTE HEflT RELEflSE
4-15900-542
60
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O
O
•
O
00
oc o
UJ CD
Q_
in
t^
^
o
UJ §
u_
u_
LU
£§
d LO
o
CO
0
HIGH
OFA
T
T
T
T
100.0 200.0 300.0 400.0 500.0
GRRTE HERT RELERSE 1000 BTU/HR-SQ FT
PflRT. TEST
FIG. 5-17
BOILER EFFICIENCY
TEST SITE H
VS. GRRTE HERT RELERSE
4-15900-542
61
-------
TABLE 5-11
BOILER EFFICIENCY VS LOAD
TEST SITE H
HEAT LOSSES, %
Dry Gas
14.52
10.23
12.13
Combustibles
2.32
2.84
2.46
Radiation
0.65
0.86
1.23
Other
7.12
6.92
6.66
BOILER
EFFICIENCY, %
75.39
79.15
77.52
100% Capacity
75% Capacity
50% Capacity
Table 5-11 shows some of the individual heat losses which are part
of the boiler efficiency determination. This table shows that the dry gas heat
loss was primarily responsible for the drop in efficiency at high loads. The
dry gas heat loss represents the heat lost out the stack. At 50% and 75%
capacity, the stack gas temperature was measured at 335°F and 381°F, respectively.
At 100% capacity the average stack gas temperature was measured at 477°F.
5.3 COAL PROPERTIES
Only one coal was tested at Site H. This coal came from the Sands
Hill strip mine in Ohio and is referred to as Sands Hill coal in this report.
This section describes the chemical and physical properties of this coal.
5.3.1 Chemical Composition of the Coal
Representative coal samples were obtained from the weigh lorry during
each particulate and SASS test. Each of these coal samples was given a proximate
analysis. In addition, two coal samples were given an ultimate analysis, and
tested for ash fusion temperature, Hardgrove grindability index, free swelling
index, and mineral composition of the ash. The data from these analyses are
presented in Tables 5-12 and 5-13.
KVB 15900-542
62
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TABLE 5-12
FUEL ANALYSIS - SANDS HILL COAL
TEST SITE H
TEST NO. 3
PROXIMATE (As Rec'd)
% Moisture 10.76
% Ash 7.10
% Volatile 35.88
% Fixed Carbon 46.26
Btu/lb 11773
% Sulfur 1.57
ULTIMATE (As Rec'd)
% Moisture
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
% Sulfur
% Ash
% Oxygen
ASH FUSION (Red)
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid
HARDGROVE GRINDABILITY INDEX
FREE SWELLING INDEX
568
13.01 12.31 11.19
8.73 12.34 9.62
33.53 33.43 36.21
44.73 41.92 42.98
11421 10577 11201
1.97 1.82 2.06
12.31
59.29
4.15
1.04
0.09
1.82
12.34
8.96
2400°F
2550°F
2590°F
2700+°F
43
1-1/2
9 11
10.90 11.20
8.38 5.52
34.42 37.51
46.30 45.77
11566 11963
2.21 1.62
11.20
67.17
4.56
1.11
0.05
1.62
5.52
8.77
2010 °F
2175°F
2215°F
2495 °F
49
2
AVG
11.56
8.62
35.16
44.66
11417
1.88
11.76
63.73
4.36
1.08
0.07
1.72
a. 93
8.87
2205
2363
2403
2598
46
1.75
STD
DEV
0.90
2.32
1.63
1.83
447
0.25
0.78
5.57
0.29
0.05
0.03
0.14
4.82
0.13
276
265
265
145
4.24
0.35
KVB 15900-542
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TABLE 5-13
MINERAL ANALYSIS OF COAL ASH
(SANDS HILL COAL)
TEST SITE H
TEST NO.
MINERAL ANALYSIS OF
Silica
Alumina
Titanic
Ferric Oxide
Lime
Magnesia
Potassium Oxide
Sodium Oxide
Phos . Pentoxide
Sulfur Trioxide
Unde te rmined
Silica Value
Base: Acid Ratio
^250 Temperature
SULFUR FORMS
% Pyritic
% Organic
% Sulfate
ASH
Si02
A1203
TiO2
Fe03
CaO
MgO
K2O
Na2O
P2°5
SO3
6
47.93
27.35
1.06
16.19
1.59
0.72
2.03
0.29
0.33
0.78
1.61
72.15
0.27
2595°F
0.86
0.73
0.23
11
39.73
23.32
1.12
28.23
1.91
0.62
1.74
0.23
0.36
0.66
1.99
56.36
0.51
2300°F
0.96
0.66
0.00
AVG
43.83
25.34
1.09
22.21
1.75
0.67
1.89
0.26
0.35
0.72
1.80
64.26
0.39
2448
0.91
0.79
0.12
KVB 15900-542
64
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5.3.2 Coal Size Consistency
The individual coal samples were screened at the site using 1",
1/2", 1/4", #8 and #16 square mesh screens. The results of these screenings
are presented in Table 5-14. The standard deviation of the coal size con-
sistency is plotted against the ABMA recommended limits for overfeed stokers
in Figure 5-18. This figure shows the as-fired coal to be on the low-fines
side of the recommended range. This is a good coal size. Coal fines, defined
as the percent by weight passing a 1/4" screen, averaged 25.9%.
TABLE 5-14
AS FIRED COAL SIZE CONSISTENCY
SANDS HILL COAL
TEST SITE H
Test
No.
3
5
6
8
9
11
PERCENT PASSING STATED SCREEN SIZE
1" 1/2" 1/4" #8 #16
95.9
94.8
92.7
88.5
95.1
91.5
63.3
60.9
59.4
44.0
67.1
48.5
36.6
23.5
23.2
14.4
35.8
22.0
18.5
9.8
9.4
5.2
16.4
9.7
13.3
6.4
6.2
3.2
11.1
6.8
Average 93.1 57.2 25.9 11.5 7.8
As one might expect, coal fines appear to play a role in particulate
mass loading. In Figure 5-3, page 42, coal fines are indicated for each particu-
late data point. The increase in particulate loading between the intermediate
load and low load tests is very likely due to the differences in coal fines be-
tween the two tests. Also, the fact that the low overfire air test was conducted
during a period of high coal fines very likely contributed to the resultant high
particulate mass loading.
KVB 15900-542
65
-------
95
80
50
16 8 1/4 1/2
SIEVE SIZE DESIGNATION
ABMA Recommended Limits of Coal
Sizing for Overfeed Stokers
Standard Deviation Limits of Measured
Sands Hill Coal Size Consistency
Figure 5-18.
Size Consistency of "As Fired" Sands Hill Coal vs ABMA
Recommended Limits of Coal Sizing for Overfeed Stokers
Test Site H.
KVB 15900-542
66
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.4
Threo particle size distribution determinations wore made ol tho
uncontrolled partic.ul.ato matter in tho flue gas. Those determinations wore
made using a Bahco classifier and sieve, a Brink cascade impact.or, and a
SASS cyclone train. Firing conditions for tho three tests are shown in
Table 5-15.
TABLE 5-15
DESCRIPTION OF PARTICLE SIZE DISTRIBUTION TESTS
TEST SITE H
Test
No.
3
5
11
Boiler
Capacity
%
102
99
ion
02
%
8.0
9.4
9.2
OFA
Low
High
Low
Particle Size Distribution
Methodology Used
Bahco Classifier - Sieve
Brink Cascade Invpactor
SASS Cyclones
The test results are presented in Table 5-l<> and in Figures 5-19,
5-20 and 5-21. Tho test results are as different as the sample methodologies.
A discussion of each method is included in Section 4.4 and may be worth
reviewing.
The Bahco classifier sample was collected with a cyclone followed
by a backup filter. As a result, a fraction of the sample (12.2%) was
not captured by the cyclone and was not part of the sample processed by the
Bahco classifier. Thus, the results of this test are biased such that they
indicate fewer particles below about 15 micrometers than there actually were.
It is hoped that appropriate corrections can be made to the Bahco data at some
future date using the measured cyclone collection efficiency (R7.B%) anil the
theoretical cyclone collection e f f i cienci*v; by particle ;;ize.
The Urink and SASS particle si ?.o distribution data should bo accurate
and require no corrections. However, thcso are single jxiint measurement;;,
whereas the Bahco data wan obtained with a ^4-|«.>int traverse ot the duct. Single
point samplers arc suspect, for ronsons of size stratification within tho Hurt .
t>7 KVH 1VMW-S41'.
-------
oo
99.9
99
95
to
I BO
E-i
co
OS
a
50
20
1
W
0.1
BAHCO CLASSIFIER
TTT
14.^4-144
-u U
lit-
iiil
TTt
n-
til:
X!"--
:| SIEVE ANALYSIS
,^^^H^H^BMM^^HMM^M^«9MiHHWB
Figure 5-19.
10 30 100 300
EQUIVALENT PARTICLE DIAMETER, MICROMETERS
Uncontrolled Particle Size Distribution by Bahco
Classifier and Sieve Analysis - Test Site H
1000
3000
KVB 15900-542
-------
50
H
W
20
hf
^TV
ittltr
rfe
T '". I" T
-4-4-
ttt
Tt- -f
trr
W
0.1
0.3 1 3
EQUIVALENT PARTICLE DIAMETER, MICROMETERS
Figure 5-20.
Uncontrolled Particle Size Distribution by Brink
Cascade Impactor - Test Site H.
KVB 15900-542
69
-------
H
W
Q
B
IS
El
s
(ll
50
20
0.1
13 10
EQUIVALENT PARTICLE DIAMETER, MICROMETERS
Figure 5-21.
Uncontrolled Particle Size Distribution by SASS
Cyclones - Test Site H.
KVB. 15900-542
70
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TABLE 5-16
RESULTS OF PARTICLE SIZE DISTRIBUTION TESTS
TEST SITE H
Test
JNo.
3
5
11
Size Distribution
% Below
3ym
2.2
45.0
4.42
% Below
8.7
14.21
Size Concentration
lb/10bBtu
Below 3um
0.048
0.509
0.097
lO/lO&Btu
Below lOym
0.191
—
0.312
Sample
Collection
Efficiency
87.8
100
100
5.5 SOURCE ASSESSMENT SAMPLING SYSTEM
One SASS test was run at Test Site H. All SASS test results will be
reported under separate cover at the conclusion of this test program. The
SASS sample catches will be analyzed by combined gas chromatography/mass
spectroscopy for total polynuclear content. In addition, seven specific
polynuclear aromatic hydrocarbons (PAH) will be sought. These are listed in
Table 5-17.
TABLE 5-17
POLYNUCLEAR AROMATIC HYDROCARBONS
ANALYZED IN THE SITE H SASS SAMPLE
Element Name
Molecular
Weight
Molecular
Formula
7,12 Dime thy Ibenz (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
256
278
228
268
252
302
302
267
C20H16
C22H14
C2QH12
71
KVB 15900-542
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5.6 DATA TABLES
Tables 5-18 through 5-21 summarize the test data obtained at Test
Site H. These tables, in conjunction with Tables 2-1 and 2-2 in the
Executive Summary, are included for reference purposes.
TABLE 5-18
UNCONTROLLED PARTICULATE EMISSIONS
TEST SITE H
FIRING CONDITIONS
Test
No.
3
5
6
8
9
Load
%
102
99
97
75
52
°2
%
8.0
9.4
10.6
8.2
11.6
OFA
"H2O
2.7
11.7
11.2
2.9
3.0
EMISSIONS
li>/106Btu
2.195
1.130
0.897
0.545
0.681
gr/SCF
1.090
0.485
0.319
0.253
0.239
Ib/hr
136
96
46
15
21
Velocity
ft/sec
28.73
29.47
31.04
13.87
12.81
KVB 15900-542
72
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TABLE 5-19
HEAT LOSSES AND EFFICIENCIES
TEST SITE H
8
EH
CO
03
05
06
08
09
11
w
CO
o
i
1
12.77
13.93
13.85
10.23
12.13
17.54
MOISTURE
IN FUEL
1.14
1.43
1.45
1.20
1.12
1.20
1
-------
TABLE 5-21
STEAM FLOWS AND HEAT RELEASE RATES
TEST SITE H
Test
No.
1
2
3
4
5
6
7
8
9
10
11
Capacity
%
87.8
96.0
101.6
49.9
99.0
97.3
75.5
74.8
51.9
50.8
100.0
Steam Flow*
lb/hr
39,500
43,200
45,700
22,433
44,533
43,800
33,975
33,666
23,333
22,875
45,000
Heat Input**
106Btu/hr
52.3
57.2
60.5
29.7
59.0
58.0
45.0
44.6
30.9
30.3
59.6
Heat Output
106Btu/hr
39.8
43.5
46.0
22.6
44.8
44.1
34.2
33.9
23.5
23.0
45.3
Front Foot
Heat Belease
106Btu/ft-hr
4.03
4.40
4.66
2.29
4.54
4.46
3.46
3.43
2.38
2.33
4.58
Grate
Heat Release
103Btu/ft2-hr
373
408
432
212
421
413
321
318
221
216
425
Furnace
Heat Release
103Btu/ft3-hr
28.3
30.9
32.7
16.1
31.9
31.3
24.3
24.1
16.7
16.4
32.2
Steam Flow is based on panel board chart recordings because the steam flow integrator
was out of calibration.
Heat input is based on heat output divided by an average boiler efficiency of 76%.
This was necessary because there was no accurate method of metering coal flow at
Test Site H. Heat output is calculated from steam flow, steam pressure and feedwater
temperature.
KVB 15900-542
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APPENDICES
APPENDIX A English and Metric Units to SI Units 76
APPENDIX B SI Units to English and Metric Units 77
APPENDIX C SI Prefixes 78
APPENDIX D Emissions Units Conversion Factors 79
APPENDIX E Unit Conversion from ppm to lb/lO%tu .... 80
75
-------
APPENDIX A
CONVERSION FACTORS
ENGLISH AND METRIC UNITS TO SI UNITS
To Convert From
in
ft
ft2
ft3
To
cm
m
m'
m-
Multiply By
2.540
6.452
0.3048
0.09290
0.02832
Ib
lb/hr
lb/106BTU
g/Mcal
BTU
BTU/lb
BTUAr
J/sec
J/hr
BTU/ftAr
BTU/ftAr
BTU/ft2Ar
BTU/ft2Ar
BTU/ft3Ar
BTU/ft3Ar
psia
"H20
Rankine
Fahrenheit
Celsius
Rankine
FOR TYPICAL COAL FUEL
Kg
Mg/s
ng/J
ng/J
W
W
W
W/m
W/m2
JAr/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
5/9 R
(lb/106Btu)
ng/J
ng/J
ng/J (lb/106Btu)
ng/J (lb/106Btu)
ng/J (Ib/lO^tu)
ng/J (lb/106Btu)
0.851
(1.98xlO~3)
1.063
0.399
0.611
0.372
(2.47xlO~3)
(9.28xlO"4)
(1.42xlO"3)
(8.65xlO~4)
ppm @ 3% 02 (SO2)
ppm @ 3% O2 (SO3)
ppm @ 3% O2 (NO)*
ppm @ 3% 02 (NO2)
ppm @ 3% O2 (CO)
ppm @ 3% 02 (CH4)
g/kg of fuel **
*Federal environmental regulations express NOx in terms of N02;
thus NO units should be converted using the N02 conversion factor.
** Based on higher heating value of 10,000 Btu/lb. For a heating value
other than 10,000 Btu/lb, multiply the conversion factor by 10,OOO/(Btu/lb)
0.213 (4.95xlO~4)
KVB 15900-542
76
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APPENDIX B
CONVERSION FACTORS
SI UNITS TO ENGLISH AND METRIC UNITS
To Convert From
cm
cnr
m
m2
ra-
To
in
in
ft
Multiply By
0.3937
0.1550
3.281
10.764
35.315
Kg
Mg/s
ng/J
ng/J
J
JAg
J/hr/m
J/hr/m2
J/hr/m3
W
W
W/m
W/m2
W/m3
Pa
Pa
Kelvin
Celsius
Fahrenheit
Kelvin
Ib
Ib/hr
lb/106BTU
g/Mcal
BTU
BTU/lb
BTU/ft/hr
BTU/ft2/hr
BTU/ft3/hr
BTUAr
JAr
BTU/ftAr
BTU/ft2Ar
BTU/ft3/hr
psia
"H2O
Fahrenheit
Fahrenheit
Rankine
Rankine
2.205
7.937
0.00233
0.00418
0.000948
0.000430
0.000289
0.0000881
0.0000269
3.414
0.000278
1.041
0.317
0.0967
0.000145
0.004014
F = 1.8K-460
F = 1.8C+32
R = F+460
R = 1.8K
FOR TYPICAL COAL FUEL
ng/J
ng/J
ng/J
ng/J
ng/J
ng/J
ng/J
ppm @ 3% O2 (SO2)
ppm 6 3% 02 (S03)
ppm § 3% O2 (NO)
ppm @ 3% 02 (N02)
ppm @ 3% 02 (CO)
ppm @ 3% O2 (CH4)
gAg of fuel
1.18
0.941
2.51
1.64
2.69
4.69
0.000233
KVB 15900-542
77
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APPENDIX C
SI PREFIXES
Multiplication
Factor Prefix SI Symbol
1018 exa E
1015 peta P
1012 tera T
10;? giga G
10 mega M
1Q3 kilo k
10 hecto* h
101 deka* da
10 deci* d
_2
10 centi* c
10~3 milli m
10~^ micro y
10~9 nano n
10~12 pico p
10~15 femto f
10~18 atto a
*Not recommended but occasionally used
KVB 15900-542
78
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APPENDIX D
EMISSION UNITS CONVERSION FACTORS
FOR TYPICAL COAL FUEL (HV = 13,320 BTU/LB)
Multiply
To "\v^ By
Obtain
% Weight in Fuel
S N
lbs/106Btu
SO2 N02
grams/106Cal
S02 N02
PPM
(Dry @ 3% O2)
SOx NOx
Grains/SCF.
(Dry e 12* CO2)
SO? NOj
% Weight
In Fuel
0.666
0.370
0.405
13.2xlO'4
0.225
1.48
5.76xlO~4
.903
Ibs/lO^tu
SO,
1.50
NO,
(.556)
19.8x10
,-4
(2.23)
2.47
(.556)
14.2xlO"4
(2.23)
SO-
grams/106Cal
2.70
(1.8)
NO,
4.44
35.6x10"
(4.01)
(1.8)
25.6x10"
(4.01)
SOx
PPM
(Dry e 3*03)
NOx
758
505
281
1736
704
1127
391
1566
SO,
.676
Grains/SCF
(Dry 612* C02)
(.448)
(.249)
8.87xlO"4
1.11
(.448)
(.249)
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 530aR was used.
KVB 15900-542
-79
-------
APPENDIX E
UNITS CONVERSION FROM PARTS PER MILLION (PPM) TO
POUNDS PER MILLION BTU INPUT (LB/106BTU)
— SfF*
lb/10bBtu = (ppm) (fuel factor,—g-—) (02 correction, n.d.) (density of
emission, ——) (10 )
SCF
SCF* c.
Fuel factor, 1QbBt = 106[1.53C + 3.61H2 + .14N2 + .573 - .4602] •="
(Btu/lb)
where C, H2/ N2, S, O2 & Btu/lb are from ultimate fuel analysis;
(a typical fuel factor for coal is 9820 SCF/106Btu ±1000)
O2 correction, n.d. = 20.9 -f (20.9 - %O2)
where %O2 is oxygen level on which ppm value is based;
for ppm @ 3% ©2, 02 correction = 20.9 T 17.9 = 1.168
Density of emission = SO2 - 0.1696 Ib/SCF*
NO - 0.0778 Ib/SCF
CO - 0.0724 Ib/SCF
CH4 - 0.0415 Ib/SCF
to convert Ibs/lO^Btu to ng/J multiply by 430
Standard conditions are 70°F, 29.92 "Hg barometric pressure
KVB 15900-542
80
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-80-112a
2.
RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE Field Tests of Industrial Stoker Coal-
fired Boilers for Emissions Control and Efficiency
Improvement--Site H
. REPORT DATE
May 1980
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
P.L.Langsjoen, R.J.Tidona, and J.E.Gabriels on
. PERFORMING ORGANIZATION REPORT NO.
PERFORMING ORGANIZATION NAME AND ADDRESS
KVB, Inc.
6176 Olson Memorial Highway
Minneapolis, Minnesota 55422
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
IAG-D7-E681 (EPA) and
EF-77-C-01-2609 (DoE)
2. SPONSORING AGENCV NAME AND ADDRESS
EPA, Office of Research and Development*
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND
Final; 3/79-4/79
PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
5. SUPPLEMENTARY NOTES IERL-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.-130a,-147a.-80-064a.-065a. and -082a are Site A-G reports.
16. ABSTRACT
The report gives test results on a coal-fired, overfeed, traveling-grate
stoker. The boiler tested is rated at 45,000 Ib/hr saturated steam at 140 psig. Mea-
surements include gaseous emissions (O2, CO2, CO, NO, NO2, SO3, and HC), un-
controlled particulate mass loading, particle size distribution of the fly ash, combus-
tible content of the bottom ash and fly ash, and boiler efficiency. Measurements were
made at loads representing 50, 75, and 100% of design capacity, several excess air
levels, and both high- and low-overfire air pressure settings. Increased overfire
air pressures decreased particulate loading, CO, and HC. Particulate loading was
1.0 Ib/million Btu under full-load high-overfire-air conditions. NOx averaged 0.416
Ib/million Btu (307 ppm) at full load.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/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
Traveling Grate Stokers
Particulate
Overfire Air
13B
13A
21B
2 ID
14B
11G
14G
07B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassified
21. NO. OF PAGES
87
22. PRICE
EPA Form 2220-1 (»-73)
81
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