svEPA
United States Industrial Environmental Research EPA-600'7-78-153a
Environmental Protection Laboratory July 1978
Agency Research Triangle Park NC 2771 1
Low-sulfur Western
Coal Use in Existing
Small and
Intermediate Size
Boilers
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-600/7-78-153a
July 1978
Low-sulfur Western Coal Use in Existing
Small and Intermediate Size Boilers
by
Kenneth L. Maloney
George L. Moilanen
Peter L. Langsjoen
KVB, Inc.
17332 Irvine Boulevard
Tustin, California 92680
Contract No. 68-02-1863
Program Element No. EHE624A
EPA Project Officer: David G. Lachapelle
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
ABSTRACT
The testing of ten representative industrial coal-fired boilers in the
upper-midwest has resulted in an assessment of sulfur oxides, nitrogen
oxides, carbon monoxide, unburned hydrocarbon and particulate emissions
from these units as well as an assessment of the operational impact of coal
switching.
This study has shown that western subbituminous coals can be substituted
for eastern bituminous coals as an industrial boiler fuel. The western coals
are compatible with industrial coal-fired units of current design. Two unit
types of older design (underfed and traveling grate stokers) were found to
experience difficulty burning western coal. Some cases have been noted
where the maximum load capacity of the boiler had to be limited. This pro-
blem can be eliminated by predrying the coal or by increased superheat
steam attemperation capacity.
Western subbituminous coals were found to be superior to eastern coals
in terms of SOX, NOX, particulate, and unburned hydrocarbon emissions.
The western coals could be fired at lower excess air and exhibited substan-
tially lower combustible losses than eastern coals.
The size of delivered western coal proved to be a problem in most of the
stoker-fired units tested. The coal generally had too large a percentage of
fine coal resulting from the poor weathering characteristics of western coals.
Stoker performance on western coal could be improved if the coal were
sized locally at the point of use so that delivery distances could be reduced
to about 200 miles.
Boiler efficiencies on western coal were lower due to the high moisture
content of the western coal. The reduced efficiency due to the moisture los-
ses were somewhat offset by the lower combustible losses and lower excess
oxygen (02) required for western coal combustion.
This study has defined the operational parameters that must be followed
in order to successfully burn western coal in industrial-sized stokers and
pulverized coal units. Excess O2 and carbon monoxide monitors for combus-
tion control would improve overall industrial boiler performance on both
eastern and western coal. These controls are necessary since many times
the margin of success can be as small as + or - 0. 5% excess O2 in the flue.
For the most part, present instrumentation does not provide sufficient pre-
cision in combustion control. Operator training and education must go hand-
in-hand with improved controls for successful western coal firing.
11
-------
CONTENTS
Section Page
Abstract ii
Figures V
Tables Xiii
Conversion Factors xvi
Acknowledgement XViil
Dedication XViii
1.0 INTRODUCTION 1
2.0 CONCLUSIONS 3
2.1 Properties of Western Subbituminous Coals 3
2.2 Pulverized Coal Combustion - 12
2.3, Stoker-Fired Boilers 25
3.0 RECOMMENDATIONS FOR FURTHER WORK 42
4.0 TEST EQUIPMENT AND PROCEDURES 43
4.1 Gaseous Emissions Measurements 43
4.2 Gaseous Emission Sampling Techniques 49
4.3 Sulfur Oxides Measurement and Procedure 49
4.4 Particulates Measurement and Procedures 52
4.5 Sampling and Analysis Procedure 54
4.6 Efficiency Evaluation 55
5.0 TEST RESULTS 57
5.1 Dairyland Power Cooperative, Alma, Wisconsin 57
5.2 Uniroyal Boiler #2 87
5.3 University of Wisconsin, Stout 106
iii
-------
Section
5.4 University of Wisconsin, Eau Claire
5.5 University of Wisconsin, Madison
5.6 Willmar Municipal Utilities Commission
5.7 Fairmont Public Utilities Commission, Unit #3, 224
Fairmont, Minnesota
5.8 Waupun Central Generating Plant, Unit #3, 267
Waupun, Wisconsin
5.9 St. John's Central Generating Plant Unit #2, 291
St. John's Abbey, Collegeville, MN
5.10 Fremont Department of Utilities, Fremont, Nebraska 320
APPENDIX A - INDUSTRIAL-SIZED BOILER POPULATION SURVEY 347
APPENDIX B - GEOGRAPHICAL COAL SULFUR DISTRIBUTION AND 361
IMPACT ON AIR QUALITY OF FUEL SWITCHING TO
WESTERN COAL
APPENDIX C - DETAILED COMBUSTION REQUIREMENTS FOR SPECIFIC 373
BOILER FIRING TYPES
APPENDIX D - CANDIDATE WESTERN COAL DEFINITION 395
APPENDIX E - EXAMINATION OF SUPPLY VARIABLES OF SPECIFIC 407
WESTERN COALS
iv
-------
FIGURES
Number Page
2-1 Nitric oxide vs. excess oxygen, Alma Unit 3, western coal. 17
2-2 Nitric oxide vs. excess oxygen, Alma Unit 3, eastern coal. 18
2-3 Nitric oxide vs. excess oxygen. Comparison of 29 kg/s 21
four-burner PC boiler and 20.2 kg/s four-burner PC boiler.
2-4 Chronological display of the development of stoker-type 27
boilers.
2-5 Comparison of western and eastern coal nitric oxide 31
emissions, University of Wisconsin, Stout.
2-6 Comparison of western and eastern coal nitric oxide 32
emissions, University of Wisconsin, Eau Claire.
2-7 Stoker firing staging limits, Willmar Unit 3, 20.2 kg/s 33
steam, western coal.
2-8 Carbon monoxide vs. excess oxygen, University of Wisconsin, 34
Madison 12.6 kg/s steam spreader stoker.
2-9 Percent carbon in outlet fly ash, Willmar Unit 3, 20.2 kg/s 36
steam spreader stoker, western coal.
2-10 Carbon monoxide emissions vs. load, Willmar Unit 3, 20.2 kg/s 38
steam spreader stoker, western coal.
2-11 Boiler efficiency comparison of pulverized coal firing to 40
spreader stoker coal firing for a high and low moisture
coal type.
4-1 Flow schematic of mobile flue gas monitoring laboratory. 48
4-2 Cutaway showing SO /SO sampling probe. 50
£. J
4-3 Shell-Emeryville SO_/SO sample system. 51
4-4 Method 5 particulate sampling train. 53
-------
FIGURES (continued)
Number Page
5-1-1 Vertical layout of Dairyland Power Cooperative's Unit 3, 59
Alma, Wisconsin, before installation of the electrostatic
precipitator.
5.1-2 Sample area geometry, Dairyland Power Cooperative Unit 3. 60
5.1-3 Nitric oxide vs. oxygen, Dairyland Power Cooperative 66
Unit 3, western coal.
5.1-4 Nitric oxide vs. oxygen, Dairyland Power Cooperative 6?
Unit 3, eastern coal.
5.1-5 Uncontrolled particulates vs. boiler load, Dairyland Power 76
Cooperative Unit 3.
5.1-6 Controlled particulate emissions vs. boiler load, 77
Dairyland Power Cooperative Unit 3.
5.1-7 Sulfur oxides emissions vs. boiler load, Dairyland 80
Power Cooperative Unit 3.
5.1-8 Carbon monoxide emissions vs. excess oxygen, Dairyland 82
Power Cooperative Unit 3.
5.1-9 Boiler efficiency vs. capacity and coal type, Dairyland Power 85
Cooperative Unit 3.
5.2-1 Multiple retort underfeed stoker with link grate, Uniroyal 90
Boiler 2.
5.2-2 Cross-sectional view of stoker, Uniroyal Boiler 2. 92
5.2-3 Orientation of thermocouples on grate, Uniroyal Boiler 2. 99
5.2-4 Detailed view of thermocouple installation, Uniroyal Boiler 2. 100
5.2-5 Detail of tuyere plate with orientation of thermocouple 101
probe, Uniroyal Boiler 2.
5.3-1 Water-cooled vibrating grate stoker. 107
5.3-2 Front view section showing water-cooled grate. 108
5.3-3 Load vs. excess oxygen, as-found operation, Stout Boiler 2, 114
West Kentucky coal.
5.3-4 Load vs. SOX emissions, as-found operation, Stout Boiler 2, 116
West Kentucky coal.
VI
-------
FIGURES (continued)
Number Page
5.3-5 Excess oxygen vs. sulfur oxide emissions at various loads, 118
Stout Boiler 2, West Kentucky coal.
5.3-6 Load vs. NO emissions, as-found operation, Stout Boiler 2, 119
West Kentucky coal.
5.3-7 NO emissions vs. excess 02 at various loads, Stout Boiler 2, 120
West Kentucky coal.
5.3-8 Load vs. carbon monoxide emissions at as-found operation, 121
Stout Boiler 2, West Kentucky coal.
5.3-9 Excess ©2 vs. carbon monoxide emissions at various loads, 122
Stout Boiler 2, West Kentucky coal.
5.3-10 Particulate emissions vs. percent of rated load, as-found 124
operation, Stout Boiler 2, West Kentucky coal.
5.3-11 Particulates vs. excess oxygen, Stout Boiler 2, West Kentucky 125
coal.
5.3-12 Carbon monoxide emissions during grate vibration, Stout 127
Boiler 2, Wyoming coal.
5.3-13 Load vs. excess oxygen, as-found operation, Stout Boiler 2, 129
Wyoming coal.
5.3-14 Load vs. sulfur oxide emissions, as-found operation, Stout 131
Boiler 2, Wyoming coal.
5.3-15 Excess oxygen vs. sulfur oxide emissions at various loads, 134
Stout Boiler 2, Wyoming coal.
5.3-16 Load vs. NO emissions, as-found operation, Stout Boiler 2, 135
Wyoming coal.
5.3-17 Excess oxygen vs. NO emissions, Stout Boiler 2, Wyoming coal. 136
5.3-18 Load vs. CO emissions, as-found operation, Stout Boiler 2, 137
Wyoming coal.
5.3-19 Excess oxygen vs. CO emissions at various loads, Stout 138
Boiler 2, Wyoming coal.
5.3-20 Particulates vs. load, as-found operation, Stout Boiler 2, 140
Wyoming coal.
5.3-21 Particulates vs. excess oxygen, Stout Boiler 2, Wyoming coal. 141
vii
-------
FIGURES (continued)
Number
5.4-1 Chain grate overfeed stoker.
5.4-2 Sample port locations in Unit 1 at University of Wisconsin, 148
Eau Claire.
5.4-3 Nitric oxide emissions vs. excess O_, University of 152
Wisconsin, Eau Claire, eastern coal.
5.4-4 Nitric oxide emissions vs. excess 0 , University of 154
Wisconsin, Eau Claire, western coal.
5.4-5 Nitric oxide vs. percent of rated load, University of I55
Wisconsin, Eau Claire.
5.4-6 SO emissions vs. excess O , University of Wisconsin, I57
Eau Claire.
5.4-7 SO component of SO emissions, University of Wisconsin, I58
Eau Claire.
5,4-8 Carbon monoxide emissions vs. excess 02, University of 159
Wisconsin, Eau Claire, eastern coal.
5.4-9 Carbon monoxide emissions vs. excess O , University of 161
Wisconsin, Eau Claire, western coal.
5.4-10 Particulate emissions vs. excess 0_, University of Wisconsin, 164
Eau Claire.
5.4-11 Particulate emissions vs. percent rated load, University of 165
Wisconsin, Eau Claire.
5.4-12 Boiler efficiency vs. percent rated load, University of 166
Wisconsin, Eau Claire.
5.5-1 Westinghouse Centrafire spreader stoker with traveling grate. 170
5.5-2 Excess oxygen vs. boiler load, University of Wisconsin, 173
Madison, Unit 2, Montana Colstrip coal.
5.5-3 Excess oxygen vs. boiler load, University of Wisconsin, 174
Madison, Unit 2, Illinois Stonefort coal.
5.5-4 Nitric oxide vs. excess oxygen, University of Wisconsin, 175
Madison, western coal.
5.5-5 Nitric oxide vs. excess oxygen, University of Wisconsin, 176
Madison, eastern coal.
viii
-------
FIGURES (continued)
Number Page
5.5-6 Carbon monoxide vs. excess oxygen, University of Wisconsin, 177
Madison, eastern coal.
5.5-7 Carbon monoxide vs. excess oxygen, University of Wisconsin, 178
Madison, western coal.
5.5-8 Nitric oxide vs. boiler load, University of Wisconsin, 180
Madison, eastern and western coals.
5.5-9 Particulate loading vs. boiler load, University of Wisconsin, 181
Madison.
5.5-10 Feeder distribution and fuel feed drive. 185
5.5-11 Effect of spill plate position. 186
5.5-12 Boiler efficiency vs. excess O , University of Wisconsin, 193
Madison.
5.5-13 Efficiency vs. load, University of Wisconsin, Madison^ 194
5.6-1 Unit 3, Willmar Municipal Utilities Commission, Willmar, 196
Minnesota.
5.6-2 Side view, inlet sampling area. 199
5.6-3 Cross section, inlet sampling duct, top view, gas flow is 200
into paper.
5.6-4 Cross section, outlet sampling duct, top view, gas flow is 201
out of paper.
5.6-5 Nitric oxide vs. excess oxygen, Willmar Unit 3, western coal. 209
5.6-6 Nitric oxide vs. excess oxygen, Willmar Unit 3, eastern coal. 210
5.6-7 Carbon monoxide vs. load, Willmar Unit 3, western coal. 211
5.6-8 Carbon monoxide vs. load, Willmar' Unit 3, eastern coal. 212
5.6-9 Carbon vs. load, Willmar Unit 3, western coal. 214
5.6-10 Carbon vs. load, Willmar Unit 3, eastern coal. 215
5.6-11 Excess oxygen vs. load, staging limits, Willmar Unit 3, 216
western coal.
5.6-12 Excess oxygen vs. load, staging limits, Willmar Unit 3, 217
eastern coal.
ix
-------
FIGURES (continued)
Number Page^
5.7-14 Nitric oxide emissions vs. excess O_, Fairmont Unit 3,
coal blend.
5.7-1 Inlet sampling duct configuration, Fairmont Unit 3. 227
5.7-2 Configuration of outlet sampling probes, Fairmont Unit 3. 228
5.7-3 Schematic of coal handling system, Fairmont, Minnesota 237
Public Utilities Commission.
5.7-4 Conditions under which unit was tested, Fairmont Unit 3, 240
eastern coal.
5.7-5 Conditions under which unit was tested, Fairmont Unit 3, 241
coal blend.
5.7-6 Inlet particulates vs. load, Fairmont Unit 3. 244
5.7-7 Outlet particulates vs. load, Fairmont Unit 3. 246
5.7-8 Cyclone efficiency vs. particulate loading, Fairmont Unit 3, 247
eastern coal and blended coal.
5.7-9 Cyclone efficiency vs. load, Fairmont Unit 3. 248
5.7-10 Percent combustibles vs. load, Fairmont Unit 3. 249
5.7-11 SO comparison for eastern coal vs. blend, Fairmont Unit 3. 252
JC
5.7-12 Sulfur mass balance, Fairmont Unit 3. 254
5.7-13 Nitric oxide emissions vs. excess O , Fairmont Unit 3, 256
eastern coal.
257
5.7-15 Nitric oxide emissions vs. load, Fairmont Unit 3, eastern coal. 259
5.7-16 Nitric oxide emissions vs. load, Fairmont Unit 3, coal blend. 260
5.7-17 CO comparison for eastern coal vs. blend, Fairmont Unit 3. 265
5.8-1 Schematic of boilers and flue gas duct system, Waupun, 269
Wisconsin.
5.8-2 Sample area geometry, Waupun Unit 3. 271
5.8-3 Photograph of a 30% d-RDF blend as fired at Waupun. 276
x
-------
FIGURES (continued)
Number Page
5.8-4 Particulates vs. fuel mixture, Waupun Unit 3. 281
5.8-5 Outlet particulates vs. boiler load, Waupun Unit 3. 282
5.8-6 Excess 0 vs. load, Waupun Unit 3. 284
5.8-7 Carbon monoxide vs. load, Waupun Unit 3. 286
5.8-8 Nitric oxide vs. excess 0 , Waupun Unit 3. 287
5.8-9 Sulfur in fuel and grate ash vs. fuel blend, Waupun Unit 3. 288
5.9-1 Schematic of boilers and flue gas duct system, St. John's Unit 2.295
5.9-2 Sample area geometry, St. John's Abbey Unit 2. 296
5.9-3 Western coal test conditions, St. John's Unit 2. 301
5.9-4 Eastern coal test conditions, St. John's Unit 2. 302
5.9-5 Particulates vs. load, St. John's Unit 2. 303
5.9-6 Particulate emissions vs. excess O , St. John's Unit 2. 304
5.9-7 Total oxides of sulfur vs. boiler load, St. John's Unit 2. 306
5.9-8 Sulfur trioxide vs. boiler load, St. John's Unit 2. 307
5.9-9 Nitric oxide vs. excess O , St. John's Unit 2. 309
5.9-10 Carbon monoxide vs. excess Q~, St. John's Unit 2, western coal. 310
5.9-11 Carbon monoxide vs. excess O , St. John's Unit 2, eastern coal. 311
5.9-12 Hydrocarbons vs. excess O , St. John's Unit 2, western coal. 312
5.9-13 Hydrocarbons vs. excess O , St. John's Unit 2, eastern coal. 313
£,
5.9-14 Western coal ash balance (disregarding carbon analyses), test 317
numbers arranged in order of excess O , St. John's Unit 2.
£t
5.9-15 Eastern coal ash balance (disregarding carbon analyses), test 318
numbers arranged in order of excess 0_, St. John's Unit 2.
XI
-------
FIGURES (continued)
Number Page
5.10-1 Sample area geometry, Fremont Department of Utilities Unit 6. 323
5.10-2 Excess 02 vs. boiler load, test parameters, Fremont Department 326
of Utilities Unit 6.
5.10-3 Uncontrolled particulate emissions vs. boiler load, Fremont 330
Department of Utilities Unit 6.
5.10-4 Controlled particulate emissions vs. boiler load, Fremont 331
Department of Utilities Unit 6.
5.10-5 Multiclone dust collector efficiency vs. boiler load, Fremont 333
Department of Utilities Unit 6.
5.10-6 Sulfur oxide emissions vs. boiler load, Fremont Department 335
of Utilities Unit 6.
5.10-7 Sulfur balance, Fremont Department of Utilities Unit 6. 336
5.10-8 Nitric oxide emissions vs. boiler load, Fremont Department 339
of Utilities Unit 6.
5.10-9 Nitric oxide emissions vs. excess oxygen, Fremont Department 340
of Utilities Unit 6.
5.10-10 Carbon monoxide emissions vs. excess oxygen at three boiler 342
loads, Fremont Department of Utilities Unit 6, Walden Colorado
coal.
5.10-11 Boiler efficiency vs. excess 0 , Fremont Department of 345
Utilities Unit 6.
xii
-------
TABLES
Number page
2-1 Fuel and Mineral Analyses for All Coals Tested 4
2-2 Some Specific Western Coal Problems 9
2-3 Design Type of Units Tested and Overall Performance 10
on Eastern and Western Coals
2-4 Screen Analyses of Pulverized Coal 14
2-5 Coal Performance Comparison, Alma Unit 3 15
2-6 Impact on NO Emissions Due to Fuel Switching from 20
Eastern Bituminous to Western Subbituminous Coals
2-7 SO Emission Comparison for Western and Eastern Coals 23
X
2-8 Particulate Emissions Data for All Coals Tested 24
2-9 Comparison of HC Emissions from Eastern and Western Coals 35
5.1-1 Coal Analysis Summary, Unit #3, Dairyland Power Cooperative, 61
Alma, Wisconsin
5.1-2 Screen Analyses of Pulverized Coal 63
5.1-3 Effect of Varying Air Registers 64
5.1-4 Effect of Varying Diffuser Position 65
5.1-5 Effect of Excess Oxygen 68
5.1-6 Effect of Staged Combustion 69
5.1-7 Emission Data Summary, Unit 3, Dairyland Power Cooperative, 70
Alma, Wisconsin
5.1-8 Average Particulate and Fuel Ash Data 75
7fi
5.1-9 Sulfur Balance Summary, Unit 3, Dairyland Power /0
Cooperative, Alma, Wisconsin
5.1-10 Relation of Fuel Nitrogen to Nitric Oxide Emissions 79
xiii
-------
Number Page_
83
5.1-11 Boiler Efficiency Summary, Dairyland Power Cooperative,
Unit 3, Alma, Wisconsin
5.2-1 Characteristics of Coals Fired in Uniroyal Boiler #2
97
5.2-2 Thermocouple Readings of Grate Metal Temperatures at 102
Uniroyal Boiler #2, Eau Claire, Wisconsin
5.3-1 Comparison of Test Coals Fired at Stout Boiler #2
5.3-2 Emission Data Summary, University of Wisconsin, Stout Boiler #2
5.3-3 S0x Data Summary, University of Wisconsin, Stout Boiler #2 117
West Kentucky Coal
5.3-4 Sulfur Oxides Emissions Summary, University of Wisconsin, 132
Stout Boiler #2, Wyoming Coal
5.4-1 Fuel Analysis - Base Coal, West Kentucky - Vogue 149
5.4-2 Fuel Analysis - Test Coal, Wyoming, Bighorn 149
5.4-3 Emission Data Summary - University of Wisconsin, Eau Claire 151
5.4-4 Comparison of SO Emissions for Similar Load Ranges 156
X
5.4-5 Particulate Emissions Data Summary for Eau Claire 162
5.5-1 Emission Data Summary, University of Wisconsin, Madison, I"72
Unit 2
5.5-2 SO Data Summary University of Wisconsin, Madison, Unit 2 182
X
5.5-3 Comparison of Boiler Efficiency on Eastern and Western Coal 187
5.5-4 Calculation of Efficiency 189
5.6-1 Emission Summary, Willmar Unit 3 205
5.6-2 Calculation of Efficiency 218
5.6-3 Flue Gas Distribution Before and After Stoker Readjustment 223
xiv
-------
Number Page
5.7-1 Comparison of Test Coals at Fairmont Unit 3 230
5.7-2 Gaseous Emissions Summary, Fairmont Public Utilities 242
Commission, Unit 3
5.7-3 Sulfur Oxides Data, Fairmont Public Utilities Commission, 251
Unit 3
5.7-4 Sulfur Oxides Retention in Ash, Fairmont Public Utilities 253
Commission, Unit 3
5.7-5 Nitric Oxide Data, Fairmont Public Utilities Commission, 255
Unit 3
5.7-6 Boiler Efficiency Data, Fairmont Public Utilities 261
Commission, Unit 3
5.8-1 Comparison of Test Fuels Fired at Waupun Unit 3 273
5.8-2 Fuel Mixing Schedule, Waupun Unit 3 274
5.8-3 Operating Variables, Waupun Unit 3 279
5.8-4 Particulate Emissions from Waupun Unit 3 280
5.8-5 Gaseous Emissions, Waupun Unit 3 283
5.8-6 Sulfur Oxides Balance, Waupun Unit 3 289
5.9-1 Comparison of Test Coals, St. John's Unit 2 292
5.9-2 Gaseous Emission Summary, St. John's Unit 2 299
5.9-3 Sulfur Balance Comparison for Two Fuels, St. John's Unit 2 305
5.9-4 Ash Balance Data, St. John's Unit 2 316
5.10-1 Comparison of Test Coals 321
5.10-2 Emission Data Summary, Fremont Department of Utilities, 328
Unit 6
5.10-3 Sulfur Balance Summary, Fremont Department of Utilities, 329
Unit 6
5.10-4 Emissions Summary for Special Tests, Fremont Department 338
of Utilities, Unit 6
5.10-5 Boiler Efficiency Summary, Fremont Department of Utilities, 343
Unit 6
xv
-------
CONVERSION FACTORS
SI Units to Metric or English Units
To Obtain ppm
*These conversions depend on fuel composition.
The values given are for typical fuels.
Multiply*
Concentration
To Obtain
g/Mcal
106 Btu
Btu
lb/106 Btu
ft
in.
ft2
3
ft
Ib
Fahrenheit
Fahrenheit
psig
psia
iwg (39.2 °F)
6
10 Btu/hr
GJ/hr
From
ng/J
GJ
gm cal
ng/J
m
cm
2
m
3
m
kg
Celsius
Kelvin
Pa
Pa
Pa
MW
MW
Multiply By
0.004186
0.948
3.9685xlO~3
0.00233
3.281
0.3937
10.764
35.314
2.205
tp = 9/5 (tc) + 32
t_ = 1.8t - 460
A
P . = (P ) (1. 450x10 )-14. 7
psig pa
Posia = (Pua) (1-450xl° >
psia pa
P. = (P ) (4.014x10 )
iwg pa
3.413
3.60
at 3% On of
Natural Gas Fuel
CO
HC
NO or NO
x
SO0 or SO
2 x
Oil Fuel
CO
HC
NO or NO
x
SO_ or SO
2 x
Coal Fuel
CO
HC
NO or NO
x
SO,, or SO
2 x
in ng/J by
3.23
5.65
1.96
1.41
2.93
5.13
1.78
1.28
2.69
4.69
1.64
1.18
-------
English and Metric Units to SI Units
!±
Multiply*
To Obtain
ng/J
ng/J
GJ
m
cm
2
m
3
m
kg
Celsius
Kelvin
Pa
Pa
Pa
MW
MW
From
lb/106 Btu
g/Mcal
106 Btu
ft
in.
2
ft
3
ft
Ib
Fahrenheit
Fahrenheit
psig
psia
iwg (39.2 °F)
e.
10° Btu/hr
GJ/hr
Multiply By
430
239
1.055
0.3048
2.54
0.0929
0.02832
0.4536
t = 5/9 (t_ - 32)
C c
t = 5/9 (t_ - 32) + 273
K F
P = (P . + 14.7) (6.895x10 )
pa psig
P = ^psia* (6-895xl° >
P = (P. ) (249.1)
n a T wrr
MCI .L.WM
0.293
0.278
To Obtain C
oncentrat
ng/J of in ppm @ 3% i
Natural Gas Fuel
CO
HC
NO or NO (as NO )
x 2
S0_ or SO
2 x
Oil Fuel
CO
HC
NO or NO (as NO,)
x 2
SO_ or SO
2 x
Coal Fuel
CO
HC
NO or NO (as NO )
X £,
SO_ or SO
0.310
0.177
0.510
0.709
0.341
0.195
0.561
0.780
0.372
0.213
0.611
0.850
*These conversions depend on fuel composition.
The values given are for typical fuels.
-------
ACKNOWLEDGEMENTS
The authors would like to express their appreciation to Mr. David G.
Lachapelle for his support and understanding throughout this program.
The following people also deserve our public appreciation for their
respective contribution to the services of this program: Messer: Forrest
McGrew, Fremont Public Utilities, Fremont, NB; Wendle Wilson, Uniroyal;
George Davis, PUC Willmar, MN; Lester Madsen, PUC Fairmont, MN; Rev. James
Tingerthal, St. Johns Abby, Collegeville, MN; Gary Carleson and N. W. Moser,
Dairyland Power Coop., Alma, WI; Jim Maloney, State of Wisconsin; and Ralph
Bosben, University of Wisconsin, Eau Claire.
DEDICATION
The authors would like to dedicate this report to the memory of the
late Mr. Donald Mattimore whose generosity and cooperation to a large degree
made this program possible.
xvili
-------
SECTION 1.0
.INTRODUCTION
Faced with the problem of complying with sulfur dioxide control regu-
lations, electric utilities and industries in the Midwest have been increasing
their use of low-sulfur western coal. The extent to which Midwestern demand
for western coal will continue to increase depends on a number of factors.
Foremost among these are: (1) the evolution of federal, state, and local
sulfur dioxide control regulations, (2) the growth of coal as a boiler fuel,
and (3) the cost of western coal relative to the costs of alternate fuels
and control technologies.
The upper Midwest region (Minnesota, Wisconsin, Iowa, Nebraska, and
Illinois) is presently the only area where low-sulfur western sub-bituminous
coal is cost competetive with midwestern and eastern coals. Within this
region, there is considerable variation with regard to western coal use
versus the traditional eastern supply. This variability is due in part to
equipment limitations which dictate that a certain coal be burned.
For this reason it is necessary to determine the operational compa-
tibility of western coal with existing industrial coal-fired equipment, if
fuel substitution is to be considered a viable sulfur oxides control strategy.
The purpose of this program, the test results of which are detailed
in this report, was to assess the effectiveness of the use of lower sulfur
western coals as a means of reducing sulfur oxides emissions from industrial-
sized boilers in the size range 1.25 to 31.4 kg/s (10,000 to 250,000 Ib/hr).
The impact of SO , NO , CO, particulates, and unburned hydrocarbons emissions
JC «
has been assessed as a consequence of this fuel conversion.
-------
The scope of the testing program included testing ten representative
types of coal-fired industrial boilers for a period of one month each on
eastern and western coal. During this testing period, the pollutant emis-
sions listed above were measured both in a baseline configuration and in an
optimized firing mode. Operational problems of the unit were characterized
for each coal. Potential reductions of pollutant emissions have been esti-
mated for each unit type and each coal tested.
In addition to the regular comparison testing of eastern and western
coals, two special test series were performed. A thorough characterization
of blended eastern and western coal was performed. Also a short study of
a densified refuse derived fuel (d-RDF) blended with western coal was done
to demonstrate the feasibility of resource recovery as a fuel source for
the industrial market.
The format of this report is as follows:
present the general overall conclusions and recommendations
of this study
outline the testing procedure
boiler-by-boiler description of the testing, detailing
all of the emissions results and operational problems
encountered
Appendices A-E contain the results of several tasks that were completed
before the field testing began. Appendix A summarizes the American Boiler
Manufacturers Association sales data for the years 1965-1974. These data were
used as a basis for boiler selection. Appendix B contains an analysis of the
impact on sulfur emissions by switching to western coals. The detailed com-
bustion requirements for specific coal fired industrial boilers are described
in Appendix C. Appendix D contains information on western coal reserves that
could potentially be produced as a boiler fuel. Appendix E examines the
variables associated with bringing these western coals to the market place.
A Final Report Supplement will soon be available. This Supplement
will contain results of an examination of the data from this study with
emphasis on exploiting the sulfur retention characteristics of the ash from
western coals.
2
-------
SECTION 2.0
CONCLUSIONS
2.1 PROPERTIES OF WESTERN SUBBITUMINOUS COALS
A large supply of low sulfur, subbituminous coal exists in the Powder
River region of Wyoming and the Fort Union region of southeast Montana. This
coal is being mined at a rapidly increasing rate. One mine in Wyoming, for
example, increased production from 0.81 million metric tons per year in 1973
to 3.0 million metric tons per year in 1974, a factor of 3.7 in only one year.
However, the most impressive statistics are the reserve capacity of these
western coal fields. That same mine in Wyoming whose production increased so
dramatically in 1974 has a reserve capacity of 16.8 billion metric tons. This
translates to a lifetime of 50 years at current production rates. The large
reserves, coupled with the relative ease of strip mining, point to a ready
supply of coal for fuel if other constraints are met. One of these constraints
is the subject of this report.
The compatibility of these western subbituminous coals with existing
industrial boilers could be a hinderance to their wide acceptance as a boiler
fuel. The compatibility of coal and boiler are determined both by coal prop-
erties and boiler design. Since the boiler designs are fixed in existing
units, the coal properties are the variables of interest.
Western coal characteristics are those of a typical subbituminous
coal: an ash-free higher heating value of 19 to 24 MJ/kg (8,200 to 10,500
moist Btu/lb), and a high moisture content of 20% to 30%. The ash content of
most of these coals is less than 10% by weight. The western subbituminous
coals exhibit high volatile to fixed carbon ratios, typically approaching a
value of one. The coals tested during this study are presented in Table 2-1.
The mineral analysis is also included for selected coals. The sequence
number keys the ultimate analysis with the mineral analysis.
-------
TABLE 2-1. FUEL AND MINERAL ANALYSES FOR ALL COALS TESTED
Seq.
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Test
No.
9
6
16
55
57
73
74
75
76
78
4
14
15
19
27
-
36
4
7
10
Coal Type
w. Kentucky
M
«
«
Montana
n
M
M
r
"
Wyoming
**
"
W. Kentucky
n
n
Wyoming
"
**
Test
Location
Alma
II
»
»
tt
It
"
**
"
**
u/w stout
"
H
n
N
**
"
U/W B.C.
11
Proximate
Analysis (%)
Vo la-
tiles
—
22.32
17.58
16.45
24.14
35.09
33.71
31.78
31.55
31.87
34.19
32.82
34.39
33.95
39.82
32.41
34.40
Fixed
Carbon
-
60.00
61.20
55.08
47.00
36.30
36.80
37.70
38.30
38.06
43.33
41.69
49.48
57.13
41.61
40.31
38.60
Ultimate Analysis (Percent)
As Received
Ash
14.49
16.00
19.02
16.39
12.62
10.67
36.80
11.19
11.36
12.32
4.68
3.92
7.06
7.11
0.50
7.25
4.88
5.44
5.13
8.22
Mois-
ture
7.46
1.68
2.20
12.08
16.24
17.94
11.56
19.33
18.89
17.75
17.80
21.53
18.43
9.02
9.47
4.49
13.69
21.84
20.16
18.78
Sulfur
3.68
3.71
3.33
4.32
1.74
0.86
0.84
0.84
0.79
0.78
0.83
0.83
1.23
3.41
2.60
2.81
0.82
0.62
0.72
0.84
Hydro-
gen
4.24
5.34
4.13
5.03
4.01
Carbon
59.87
57.26
56.76
71.36
57.98
Nitro-
gen
1.09
0.79
0.91
1.28
1.10
Oxygen
(diff)
9.07
7.14
11.91
7.78
10.90
Chlor-
ine
0.10
0
0.01
0
0
AFT(H=W)
°K
<°F)
1431
(2115)
1361
(1990)
1431
(2115)
1467
(2180)
1428
(2110)
As Reed
MJ/kg
Btu/lb)
25.013
10,754)
21.7B3
(9,365)
21.864
(9,400)
21.632
(9,300)
21 .961
(9,450)
21 .588
(9,290)
24.139
(10,378)
23 .030
(9,901)
23.044
(9,907)
27 .977
(12,028)
27.954
(12,018)
30 .180
(12,975)
24.525
(10,544)
21 ,932
(9,429)
23 .439
(10,077)
21 .220
(9,123)
Sulfur
As
Pyr i te
1.21
0.53
0.11
1.39
0.35
Received
Sulfate
0.05
0.07
0.02
0.06
0.02
Organic
2.42
0.26
0.70
1.36
0.35
(continued)
-------
TABLE 2-1 (continued).
Seq.
No.
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
36
Test
No.
11
20
30
2
5
7
10
11
14
15
19
8
34
3
5
7
9
10
Coal Type
W. Kentucky
"
**
Montana
M
X
o
W . Kentucky
M
H
"
Montana
Illinois
So. Illinois
"
"
11
11
Test
Location
U/W E.G.
"
n
U/W Mad.
M
"
"
"
If
H
H
Willmar
"
Fairmont
"
"
"
"
Proximate
Analysis («)
Vola-
tile s
37.09
38.24
32.06
29.57
30.46
37.19
38.98
36.28
35.03
33.44
34.42
35.53
Fixed
Carbon
48.19
48.03
39.65
37.66
36.26
45.60
46.23
44.65
49.88
51.37
50.31
50.33
Ultimate Analysis (Percent)
As Received
Ash
6.86
6.31
8.03
8.26
8.29
7.99
8.95
8. 79
9.60
7.98
9.20
9.12
7.76
8.35
8.24
8.07
7.48
7.88
Mois-
ture
7.86
7.42
9.15
20.03
25.28
24.78
24.33
8.42
7.37
6.81
9.87
25.56
7.11
8.55
6.85
7.12
7.79
6.27
Sulfur
3.02
2.80
2.79
1.05
0.73
0.93
1.26
2.94
3.07
3.23
2.93
1.15
2.28
2.56
2.51
1.89
2.06
2.01
Hydro-
gen
4.60
3.35
4.62
3.31
4.73
4.55
4.57
Carbon
65.05
51.09
66.32
49.32
69.26
67.96
68.73
Nitro-
gen
1.24
0.78
1.30
0.68
1.37
1.35
0.77
Oxygen
(diff)
9.13
10.45
7.71
10.85
7.47
6.67
8.76
Chlor-
ine
0.01
0.03
0.01
0.01
0.02
0.01
0.09
AFT (H=W
°K
(°F)
1414
(2085)
1514
(2265)
1467
(2180)
1486
(2215)
1461
(2170)
1481
(2205)
1533
(2300)
As Reed
MJ/kg
(Btu/lb)
28.698
(12,338)
28-905
(12,427)
27.186
(11,688)
21.985
(9,452)
20.246
(8,704)
20.459
(8,796)
20.557
(8,838)
27.705
(11,911)
27.926
12,006)
29.110
12,515)
27.286
11,731)
19.557
(8,408)
29.047
12,488)
28.517
12,260)
28.938
12,441)
28.652
12.318)
28.873
12,413)
29.201
12,554)
Sulfur Forms, Percent
As Received
Pyrite
0.94
0.39
1.59
0.89
1.09
1.33
0.76
Sulfate
0.27
O.OO
0.15
0.04
0.07
0.09
0.11
Organic
1.58
0.34
1.34
0.22
1.12
1.14
1.02
(continued)
-------
TABLE 2-1 (continued).
Seq.
No.
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
Test
Ho.
12
15
17
18
—
8
16
2
—
—
3
4
5
6
7
—
—
9
11
Coal Type
Blend
"
ft
"
Pure Heat
Western
Eastern
Montana/RDF
Montana
RDF
Hyoming(Hana)
"
tl «l
" "
"
W. Kentucky
Wyoming
Colorado
Test
Location
Fairmont
"
"
"
"
St. Johns
St. Johns
Waupan
"
"
Fremont
"
**
**
"
Uni royal
"
Fremont
"
Proximate
Analvsis (»
Vola-
tiles
31.73
32.24
31.64
31.78
31.11
37.52
35.58
30.60
35.44
54.34
35.40
33.46
34.43
33.99
35.26
37.00
32.36
35.83
36.71
Fixed
Carbon
46.39
46.20
47.32
46.65
34.36
41.57
53.95
36.43
43.13
10.84
45.43
45.38
45.67
44.59
42.44
40.50
38.49
43.36
42.78
Ultimate Analysis (Percent)
As Received
Ash
7.69
7.73
8.47
7.68
11.95
5.14
5.29
7.81
10.55
30.49
8.83
9.19
8.89
6.61
6.71
5.76
5.30
7.91
7.78
Mois-
ture
14.19
13.83
12.57
13.89
22.58
15.77
5.18
25.16
10.88
4.33
10.34
11.97
11.01
14.81
15.59
9.0
23.85
12.90
12.73
Sulfur
1.49
1.49
1.70
1.69
0.80
0.61
0.58
0.60
0.93
0.22
1.39
1.48
1.39
0.99
0.96
2.50
0.61
0.27
0.29
Hydro-
gen
4.21
3.10
4.26
5.17
3.61
3.86
4.59
4.38
4.81
4.07
Carbon
62.28
48.38
59.95
72.26
50.96
58.16
34.31
61.63
68.21
53.75
Nitro-
gen
0.48
0,63
0.81
0.95
0.43
0.48
0.57
1.25
1.26
1.01
Oxygen
(diff)
9.62
12.54
13.45
10.54
11.42
15.13
24.95
10.07
8.46
11.41
Chlor-
ine
0.04
0.02
0.01
0.03
0.01
0.01
0.54
0.03
<0.01
<0.01
AFT(H=W>
°K
CF>
1472
(2190)
1633
(2480)
1439
(2130)
1592
(2405)
1497
(2235)
1439
(2130)
1381
(2025)
1441
(2133)
1428
(2110)
A3 Reed
MJ/kg
(Btu/lb)
25.405
(10,922)
25.514
(10,969)
25.912
(11,140)
25.030
(10,761)
18 .489
(7,949)
24.458
10,515)
30.524
13,123)
20.139
(8,658)
22 .774
(9,791)
14.330
(6,161)
25.328
10,889)
25.893
(11,132)
24.346
10,467)
24.223
(10,414)
28.377
(12,200)
22.097
(9,500)
24.407
(10,493)
24 .181
(10,396)
Sulfur Forms, Percent
As Received
Pyrite
0.51
0.41
0.24
0.09
0.46
0.50
—
Sulfate
0.12
0-07
0.00
0.00
0.01
0.13
0.00
Organic
0.86
0.32
0.37
0.49
0.13
0.30
—
(continued)
-------
TABLE 2-1 (continued).
Seq.
No.
58
59
Test
No.
14
16
Coal Type
Colorado
H
Test
Location
Fremont
n
Proximate
Analysis (%)
Vola-
tiles
40.26
35.24
Fixed
Carbon
39.79
45.02
Ultimate Analysis (Percent)
As Received
Ash
6.82
6.89
Mois-
ture
13.13
12.85
Sulfur
0.33
0.32
Hydro-
gen
4.31
Carbon
61.59
Nitro-
gen
0.93
Oxygen
(diff)
13.08
Chlor-
ine
0.03
AFT(H=W)
°K
<'F)
As Reed
MJ/kg
(Btu/lb)
24.621
(10.585)
24.984
(10,741)
Sulfur Forms, Percent
As Received
Pyrite
Sulfate
Organic
Seq.
No.
1
6
12
16
19
23
25
29
32
33
34
36
39
43
44
45
46
47
48
49
50
51
52
53
56
MINE
Phosphorus
pentoxide
P2°5
0.22
—
0.59
0.11
0.40
0.12
0.18
0.11
0.19
0.23
0.21
0.20
0.30
0.20
1.09
0.43
0.14
0.16
0.70
0.38
0.11
0.36
0.21
0.15
0.48
Silica
sio2
49.28
33.38
29.82
45.77
35.40
37.38
39.41
45.78
36.47
47.30
46.54
52.33
45.42
24.87
35.19
50.23
38.66
33.42
59.41
48.27
50.08
47.54
61.43
62.90
56.58
Ferric
oxide
FE2°3
18.06
11.55
8.18
25.81
11.71
37.16
6.87
25.04
13.40
20.65
24.26
14.19
12.28
4.39
6.36
8.11
5.31
7.76
5.88
12.15
13.74
12.68
10.48
11.62
3.33
RAL ANALYSIS (Perce
Alumina
A12°3
18.15
31.91
16.42
20.25
18.00
16.87
18.58
21.00
17.25
22.50
21.38
22.50
22.35
12.15
18.89
28.60
18.83
16.24
9.07
20.85
19.24
18.91
15.02
13.37
30.41
Titania
Ti02
0.93
1.01
1.05
1.17
1.10
0.93
0.86
1.08
0.81
1.22
1.05
1.20
1.00
0.48
1.15
2.03
0.76
0.71
1.05
0.77
0.80
0.86
0.61
0.64
1.30
it Weiaht) lanited Basis
Lime
CaO
5.30
11.55
17.15
1.50
12.00
2.30
14.60
1.80
12.40
2.50
1.50
2.80
5.80
44.00
14.85
3.60
15.40
20.20
11.67
6.77
7.50
7.72
4.70
4.27
5.72
MgO
0.90
2.57
4.80
0.78
3.00
0.75
3.00
0.75
3.00
0.81
0.75
1.13
2.28
3.12
4.36
1.47
4.96
4.32
1.66
2.16
1.92
2.38
1.90
1.80
0.53
Sulfur
so3
3.91
—
17.48
1.30
14.40
2.23
14.41
1.10
14.54
1.92
0.36
2.81
8.75
9.12
14.20
4.18
14.40
15.26
2.23
6.65
4.15
7.34
3.70
3.02
6.04
Potassium
K2°
1.97
0.60
0.68
2.23
1.22
1.76
0.58
2.12
0.48
2.36
2.30
2.37
1.48
0.53
0.66
1.13
0.58
0.48
1.95
1.52
1.61
1.57
1.48
1.44
0.28
Sodium
oxide
Na20
1.08
7.4
2.98
0.38
1.61
0.42
0.62
0.42
0.52
0.38
0.48
0.32
0.32
0.22
2.28
0.71
0.55
0.52
6.04
0.28
0.48
0.41
0.42
0.34
0.50
Undeter-
mined
0.20
0.03
0.85
0.70
0.16
0.08
0.89
0.80
0.94
0.13
0.67
0.15
0.02
0.92
0.97
0.49
0.41
0.93
0.34
0.20
0.37
0.23
0.05
0.44
0.83
Gronho vd ' s
Prediction
(Percent)
105
92
109
99.5
108
99.36
109
100.3
108
109
108
106
64
97
108
99
93
89
106
105
104
106
106
107
Actual (Measured)
Fuel Sulfur
Emitted
(Percent)
92
71
106
81
91
91
79
88
109
118
113
95
28
93
87
107
95
87
113
-------
The western subbituminous coals are also classed as "free-burning"
coals. In the free-burning coals, the pieces do not fuse together, but
burn separately or, after fusion, the mass breaks up quickly into fragments.
This characteristic causes problems in certain types of stokers where there
is inadequate control of undergrate air distribution. Some specific western
coal problems for five types of combustion devices, and the property that
causes these problems, are presented in Table 2-2.
The high moisture content of the western coals causes the greatest
combustion difficulty in industrial-sized equipment. In most units with
superheaters, it leads to high steam superheat temperatures. It also causes
flame stability problems in pulverized coal combustion and ignition problems
in stoker-fired units. To recover the lost steam capacity, some pre-drying
of western coals will be necessary for firing in units designed for eastern
coal.
The second major problem with western coal is the size distribution
of the delivered coal. Most western coals do not travel or weather well.
The coal has a tendency to break into fine sizes while in transit. There-
fore, even if the coal has been sized before shipment, the as-received coal
will exhibit a change in size distribution toward the smaller sizes. This
shift becomes more severe with longer transit and/or storage periods. The
effect of this coal property on stoker unit performance is discussed below.
This paper is divided into a discussion of pulverized coal firing
and stoker firing of both eastern and western coal. A general overview of
boiler performance is presented in Table 2-3. Here, the units tested are
rated in terms of emissions, efficiency, and overall ease of operation.
The type and source of the coals tested are also given for each boiler.
-------
TABLE 2-2. SOME SPECIFIC WESTERN COAL PROBLEMS
tJ
g
L)
BB
U)
<
PROPERTIES
Low Heating
Value
High Moisture
Lew Sulfur
Dustiness/
.Fineness
Friability
free Burning
Slaking/
Weathering
Sodium and
Calcium
COMBUSTION DEVICES
VIBRATING
GRATE STOKER
o Ignition
problems
o Uneven
fuel bed
o Uncovered
grate
SPREADER
STOKER
o Flame
stability
o Reduced
capacity
o High
superheat
temperature
o Poor grate
coverage
o Overheating
of grates
o Ash pit
fires
o Increased
fouling
PULVERIZER
o Reduced
capacity
o High
maintenance
0 Flcimi:
stability
o High
superheat
temperature
o Poor
grinding
o Feeder
plugging
o FouJ ing
o Sintering
UNDERFED
STOKER
o Reduced
capacity
o Poor
ignition
o Nonuniform
bed
thickness
o Uneven fuel
bed with
uncovered
grate areas
o Ash pit
fires
o Uncovered
gi ate
OVERFED
STOKER
o Reduced
capac^y
o Poor
ignition
o Carbon
carryover
o Undergrate
air res-
triction
o Ash pit
fires
o Uncovered
grate
TRANSPORTATION
o Lower btu ' s/
ton-mile
o Freezing
o Coal loss
o Fugitive
dust
o Coal size
degradation
STORAGE
o Increased
equipment
loading
o Fires
o Fires
o Fugitive
dust
o coal size
degradation
ASH COLLECTION./
DISPOSAL
o More ash/Btu
o More ash/Btu
o Inc-ff icier.t
prccipita tors
o caking
VO
-------
TABLE 2-3. DESIGN TYPE OF UNITS TESTED AND OVERALL PERFORMANCE ON EASTERN AND WESTERN COALS
Type of Unit Tested
Overall Performance Rating
Per Coal
Good
Unacceptable
Comments
PULVERIZED COAL (Riley)
o 28.9 kg/s (230xl03 Ib/hr)
o Four Burner Face-Fired
o Two Ball Tube Mill Pulverizers
o UOP ESP
Dairyland Power Cooperative
Alma, HI
Reduced maximum capacity
'estern Kentucky
River King)
Eastern
and
Western
Montana
Sarpy Creek
(Westmoreland)
UNDERFED STOKER (Westinghouse)
o Multiple Retort
o 12.6 kg/s (100x10 Ib/hr)
o cyclone Dust Collector
Uniroyal
Eau Claire, HI
Eastern
Specially sized western
coal was used for the test,
however, the unit would
not respond to load demand.
Modifications are neces-
sary to undergrate air
system in order to burn
western coal.
Kentucky and
llinois
Wyoming
(Big Horn)
VIBRATING GRATE STOKER (Detroit)
o Water-Cooled Grate
o 5.7 kg/s (45xl03 Ib/hr)
o FD Fan/Natural ID
o Cinder Trap Partic. Removal
University of Wisconsin, Stout
Improved coal sizing
would improve performance
Western Kentucky
I Vogue)
Wyoming
(Big Horn)
TRAVELING GRATE STOKER (LaClede)
o 7.6 kg/s (60xl03 Ib/hr)
o FD Fan/Natural ID
o No Particulate Controls
University of Wisconsin, Eau Claire
Eastern
Severely affected by
coa 1 size
Western Kentucky
(Vogue)
Wyoming
(Big Horn)
SPREADER STOKER (Westinghouse)
o 12.6 kg/s (lOOxlO3 Ib/hr)
o Traveling Grate
o FD and ID Fans
o Superheat, Economizer
University of Wisconsin, Madison
Western
and
Eastern
Able to maintain full
load on western coal
Kentucky
(Vogue)
Montana
(Colstrip)
(continued)
-------
TABLE 2-3 (continued).
Type of Unit Tested
Overall Performance Rating
Per Coal
Good
Fair
Unacceptable
Comments
SPREADER STOKER (Detroit)
o 20.2 kg/s (160xl03 Ib/hr)
o Traveling Grate
o Multiclone Cyclone
o FD and ID Fans
o Superheat, Economizer and
Air Heater
Willmar Municipal Utilities
willmar. UN
Eastern
Maximum load reduced to
16.4 kg/s (130xl03 Ib/hr)
steam on western coal due
to high superheat tempera-
tures. Large carbon
losses on eastern coal—
smoking.
Southern
Illinois
Montana
(Colstrip)
SPREADER STOKER (Erie City)
o 10.1 kg/s (SOxlO3 Ib/hr)
o Traveling Grate
o FD and ID Fans
o Superheat
Fairmont Public Utilities Commission
Fairmont, MM
Blend
Blending problem due to
fines in western coal.
So. Illinois
(Sahara)
Blend
2/3 So. 111.
1/3 Montana
(Colstrip)
SPREADER STOKER (Wickes)
o 3.8 kg/s (30xl03 Ib/hr)
o Traveling Grate
o FD and ID Fans
o Superheat
o Cyclone Dust Collector
Waupun Central Generating Plant
Haupun. WI
No problems with
western coal.
SPREADER STOKER (Keeler)
o 1.7 kg/s C13xl03 Ib/hr)
o Dumping Grate
o FD Fan and Natural ID
o No Particulate Controls
St. John's Abbey
Collegeville, MM
Western
and
Eastern
Western coal used all the
time with no problems.
Wyoming
(Big Horn)
PULVERIZED COAL (BsW)
o 20.2 kg/s (160x10 Ib/hr)
o 4-Burner Front-Fired
o Ball and Race Pulverizers
o Cyclone Dust Collector
Fremont Department of Utilities
Fremont, NB
Eastern
(Bitumin.)
and
Western
(Subbitumin.)
Both the bituminous and
the subbituminous coals
performed well on this
unit.
Colorado
(Walden)
Wyoming
(Hana)
-------
2.2 PULVERIZED COAL COMBUSTION
One of the two pulverized coal-fired boilers tested was Unit No. 3 at
Dairyland Power Cooperative at the Alma, Wisconsin generating station. This
four-burner face-fired unit manufactured by Riley Stoker Corporation is rated
at 29 kg/s (230,000 Ib/hr) steam flow. The coal is pulverized with two ball
tube mills, one mill for the upper two burners and one for the lower two
burners. The unit is equipped with a spray steam attemperator. Fly ash col-
lection is accomplished with a UOP-designed cold-side electrostatic precipita-
tor (ESP).
The two fuels used during the testing were:
Western Kentucky Coal
4% sulfur
. 16% ash
. 24 MJ/kg (10,500 Btu/lb)
18% volatiles
and
Montana Coal
. 0.77% sulfur
. 12% ash
. 19.5 MJ/kg (8,400 Btu/lb)
37% volatiles
2.2.1 Boiler Performance - Alma Unit No. 3
The boiler performed well on both coals, although the unit was limited
in maximum load due to excessive superheat steam temperature on the Montana
coal. The steam attemperation system was not adequate to reduce the temperature
to the desired 755 °K (900 °F) level at loads above 22 kg/s (174,000 Ib/hr)
steam on western coal. This compares to a maximum load of 25.7 kg/s (204,000
Ib/hr) steam on eastern coal. The boiler is design rated at 29 kg/s (230,000
Ib/hr) steam, however, this load is no longer achieved.
12
-------
The primary factor causing the excessive steam temperature is the
high moisture content of the coal. The water reduces the flame temperature
which in turn reduces the radiant heat flux to the water walls, resulting
in lower steam generation. This lower heat transfer (a function of temper-
ature to the fourth power) removes less heat in the radiant section; how-
ever, the gas still contains a large enthalpy which then acts on a decreased
amount of steam in the convective section, resulting in increased steam
temperatures. The water in the fuel also results in greater gas flows which
increase heat transfer rates in the convective pass.
The excessive steam temperature problem is a function of boiler
design. For example, a boiler designed for western coal might not be able
to make design steam temperature on eastern coal.
Increased steam attemperation would result in full capacity opera-
tion on western coal.
2.2.2 Pulverizing Mill Performance
Eastern coking coals, when exposed to furnace temperatures, will
swell and form lightweight, porous coke particles. These may float out
of the furnace before they are completely burned. As a result, carbon loss
will be high unless pulverization is very fine. Free-burning (western)
coals, on the other hand, do not require the same degree of fineness because
the swelling characteristic is absent.
High volatile (western) coals ignite more readily than those with
a low volatile content. Therefore, they do not require the same degree of
fine pulverization. With the exception of anthracite, however, the low-
volatile coals are softer, and therefore have a higher grindability. As
a result, mill capacity is greater at increased fineness than with high
volatile coals (Ref. 2-1).
Table 2-4 shows the screen analyses and the loads of the coal burned
in tests 9, 16, 57, 63, 75, and 78. Tests 9 and 16 were on eastern coal.
Test 16 was with one mill out of two operating so the load in the mill was
13
-------
TABLE 2-4. SCREEN ANALYSES OF PULVERIZED COAL
Test
Load
- 80
- 80
-100
-140
-200
No.
kg/s
10 3 Ib/hr
mesh , %
+100 mesh, %
+140 mesh, %
+200 mesh, %
mesh, %
Moisture, %
EA
9
-15 ..8
125
0.65
0.75
2.75
6.95
88.90
5.15
STERN
16
6.6
52
1.00
1.00
3.35
8.20
86.45
2.20
WESTERN
57
21.4
170
2.90
2.30
20.65
34.60
39.55
22.05
63
16.5
131
1.40
1.30
4.05
8.30
84.95
12.75
73
11-8
94
0.65
2.32
8.91
32.26
55.66
17.94
75
20.2
160
8.74
7.70
21.65
16.75
45.15
19.33
78
13.9
110
1.53
2.23
6.60
17.46
72.18
17.75
the same as it would have been with both mills operating at 13.1 kg/s (104,000
Ib/hr) steam. The screen analyses of tests 16 and 78 may then be compared.
It is seen that the western coal did not grind quite as well as the eastern
coal. However in the opinion of de Lorenzi (Ref. 2-1), free-burning coals
need not be ground as finely as coking coals, and this was not thought to be
a severe problem. An equally important factor in mill grinding capacity is
moisture. From Reference 2-1, frequently too much emphasis is placed on
grindability, while other factors such as moisture, which also affect mill
capacity, are almost entirely overlooked. The capacity of a pulverizer is
not directly proportional to the grindability of a coal. Correction must be
made for variation in fineness and moisture content.
Without quantitative analysis, it can be seen in Table 2-4 that the
moisture content of test 78 is a factor of eight times higher than test 16.
The grindability of the other tests tend to follow the moisture content. Test
57 with the highest moisture content exhibited the poorest grindability,
followed by tests 75, 73, 78, and 63 in order of increasing grindability.
The poorly pulverized coal burns more slowly resulting in lowered
heat transfer in the near-flame region (radiant section) and increased heat
transfer to the convective section. At high loads (tests 57 and 75), the
poor grind probably contributed to the excessive superheat steam temperature
problem.
14
-------
2.2.3 Emissions From Alma Unit 3
A coal performance comparison for Alma Unit 3 is presented in Table
2-5. In this table, western coal (test 66), is compared to eastern coal
(test 9).
Significant differences in coal performance are noted for:
SOX emissions
NO emissions
Carbon carryover
Uncontrolled particulate emissions
Unit efficiency
TABLE 2-5. COAL PERFORMANCE COMPARISON
ALMA UNIT NO. 3
Coal
Test No.
Western Eastern
66 (ESP Inlet) 9 (ESP Inlet)
Load, kg/s (10 Ib/hr)
Excess O,
ppm
NO, dry at 3% O , ppm
CO, at 3% O , ppm
7.4 (130)
3.4
996
372*
31
Particulate^ ng/J (Ib/MBtu) 2266(5.28)
'2' *
SO at 3% O ,
ESP Efficiency, %
Carbon Carryover, % by wt
Unburned HC, at 3% O , ppm
Boiler Efficiency, %
99.6
0.55
25
85
7.4 (130)
3.4
3283
490 +
21
3411(7.947)
99.6
4.13
31
88.5
*223 ng/J (0.52 Ib/MBtu)
§
296 ng/J (0.69 Ib/MBtu)
Uncontrolled
15
-------
For the first four items, the western coal performed better than the eastern
coal. Sulfur oxides emissions were reduced by a factor of 3 by substituting
western coal. At the same time nitric oxide emissions were reduced 24% and
carbon carryover was virtually eliminated. Uncontrolled particulate loadings
were reduced 33%. The performance of the ESP was not affected by the fuel
switch. It continued to operate at 99+% efficiency. Carbon monoxide and
unburned hydrocarbon emissions were generally less than 100 ppm each. In
the optimum furnace configuration, these emissions are controlled by excess
air. Below 3% excess O in the flue gas, these emissions became signifi-
cant. Soot formation, resulting in a "black stack" was also a problem
below 3% excess 0 , However, boiler efficiency was lower on western coal
due to high moisture losses resulting from fuel-contained water.
Nitric Oxide
Figure 2-1 is a plot of nitric oxide as a function of excess O in
the flue for western coal at four loads. Figure 2-2 contains the same type
data for the base eastern coal. Both figures show increasing NO with increas-
ing O at a constant load; however, the absolute magnitude of NO emissions
from western coal is less at any given load and O level. Most of the NO
data on Figure 2-1 fall below the EPA limit for new coal-fired units of 301
ng/J (0.7 Ib of NO,, as NO- per million Btu or about 500 ppm). Attempts to
X 2:
reduce the NO emissions of the eastern coal to these same (less than 500 ppm)
levels resulted in high CO emissions.
Included in the factors that influence NO emissions are:
Flame temperature
Fuel nitrogen
Excess oxygen
All three of these influence NO emissions when switching to western coal. The
temperature of the western coal flame is lower than the eastern due to the
high moisture content of the coal resulting in lower NO emissions from atmos-
pheric nitrogen fixation and to a lesser extent fuel nitrogen conversion. In
general the western coal could be fired at lower excess air before combustible
losses became a problem. This is due to the higher ratio of the volatile matter
16
-------
800
700
o
*
500
§
400
300
200
(High CO)
I
Fuel N = 0.79%
61.
62
Steam Flow
O H.3 kg/s (90xl03 Ib/hr)
D 7.6 kg/s (60xl03 Ib/hr)
A 16.4 kg/s (130xl03 Ib/hr)
• 21.4 kg/s (170xl03 Ib/hr)
6 8
EXCESS OXYGEN, percent
10
12
Figure 2-1. Nitric oxide vs. excess oxygen, Alma Unit 3, western coal.
-------
700
oo
600 _
*
ro
-P
us
•o
500
400
300
200
BOOS 51
49
52'
BOOS 40 . A „„_
«**<*< A^hco,
O BOOS 41
(Smoke)
I
I I
Fuel N = 1.09% /
17 O
16 pp.
D21
20Q
Steam Flow
O 25.2 kg/s (200xl03 Ib/hr) —
A 16.4 kg/s (130X103 Ib/hr)
D 7.6 kg/s (60xl03 Ib/hr)
I
6 8
EXCESS OXYGEN, percent
10
12
14
Figure 2-2. Nitric oxide vs. excess oxygen, Alma Unit 3, eastern coal.
-------
to fixed carbon content of the western coal which results in less solid
carbon to be burned out in the post-flame gases. The lower excess air
requirements result in lower NO emissions.
Table 2-6 contains data for all coals tested which show that the fuel
nitrogen content of the western coal is generally lower than eastern coal.
In any case, not all of the fuel nitrogen present in coal is converted to
nitric oxide. Typically, only 40% to 60% is converted with the amount
dependent on coal type, fuel nitrogen content, the structure of the nitrogen-
containing molecule within the coal, and firing conditions.
The substitution of western coal for eastern coal results in an
9% reduction in NO emissions on the average. The western coals used in
this comparison had 18% less fuel-bound nitrogen than the eastern coals.
The emission comparisons were based on western and eastern coal tests at
comparable loads and excess O levels. Since NOV arises from both conver-
£. X
sion of fuel-bound nitrogen and fixation of atmospheric nitrogen, it is
difficult to draw any correlation between fuel nitrogen content and NOX
emissions. This is further influenced by the fact that different coals
have different types of nitrogen-containing molecules which, depending on
their structure, are more or less easily oxidized to NO in the flame.
The conversion of fuel nitrogen to NO is a function of the structure
and distribution of the nitrogen-containing molecules within the coal. For
example, under certain conditions it could be important if the nitrogen
containing molecules are associated with the volatile fraction of the coal
rather than the fixed carbon portion. The chemical oxidation state of the
nitrogen species in coal is important since nitrogen that is partially oxi-
dized will be more easily converted to NO. For example, azide groups (N E
N) will more readily be reduced to N than -NH groups which will be more
easily oxidized to NO under flame conditions.
Figure 2-3 compares the NO emission behavior as a function of excess
O for three western coals on two pulverized coal units. The Fremont data
were taken on a 20.2 kg/s steam flow {160,000 Ib/hr) four-burner boiler while
the Alma data came from a 29 kg/s £team flow (230,000 Ib/hr) four-burner unit.
19
-------
TABLE 2-6. IMPACT ON NO EMISSIONS DUE TO FUEL SWITCHING FROM EASTERN BITUMINOUS
TO WESTERN SUBBITUMINOUS COALS
Test Site
(Boiler Type)
Alna (PC)
Fremont (PC)
Eau Claire (VG)
WillBwr (SSI
Madison (SS)
Fainont (SSI
St. Johns (SS)
Coal Type
E H. Kentucky (River King)
w Montana (Sarpy Creek)
w Wyoming (Hanna)
H Colorado (Walden)
E H. Kentucky
H Wyoming (Bighorn)
E So. Illinois (Stonefort)
H Montana (Colstrip)
B W. Kentucky (Vogue)
w Montana (Colstrip)
E So. Illinois (Sahara)
Blend -1/3 Montana (Colstrip)
2/3 So. Illinois
Unknown
H Wyoming (Bighorn)
Load
Mg/hr
91
77
46
49
11
11
50
SO
41
41
27.2
28.1
3.8
3.9
103 Ib/hr
200
170
101
109
25
25
110
111
90
90
60
62
8.4
8.7
Percent
05
5.2
5.7
4.4
4.4
10.1
9.8
6.6
6.6
7.3
7.2
6.5
7.0
15.6
15.2
Fuel Nitrogen
Percent
1.09
0.73
1.25
0.93
1.24
1.10
1.37
0.68
1.30
0.78
1.35
0.4S
0.95
0.81
ng NO/J
lib NO/MBtu)
934
(2.17)
779
(1.81)
1059
(2.46)
BOO
(1.86)
921
(2.14)
1076
(2.50)
1016
(2.36)
745
(1.73)
998
(2.32)
826
(1.92)
1013
(2.36)
403
(0.94)
667
(1.55)
710
(1.65)
NO dry at 3% 02
ppn
690
695
515
369
300
178
375
324
379
446
282
278
413
281
ng NO/J
(Ib NO/MBtu)
262
(0.610)
269
(0.625)
196
(0.456)
139
(0.324)
115
(0.268)
68
(0.158)
146
(0.340)
144
(0.336)
146
(0.340)
172
(0.40)
108
(2.53)
107
(0.249)
153
(0.355)
105
(0.245)
NO Change Due to Fuel
Switch (E to H)
ng NO/J
(Ib NO/HBtu)
+7
(+0.015)
-60
(-0.132)
-47
(-0.110)
-2
(-0.004)
+26
(+0.06)
-1
(-0.004)
-48
(-0.110)
Average
Percent
+2.6
-30.6*
-40.9
-1.4
+17.8
-0.9
-31.4
-9
to
o
• Hot included in average
-------
700
600
500
o
dt>
400
ro
300
200
Fremont (Wyoming)
at 16.4 kg/s
(130X103 Ib/hr?
Alma (Montana)
at 16.4 kg/s
(130xl03 Ib/hr)
Fremont (Colorado)
at 16.4 kg/s (130xl03 Ib/hr)
8
EXCESS OXYGEN, percent
10
12
14
Figure 2-3. Nitric oxide vs. excess oxygen. Comparison of 29 kg/s (230x10"
PC boiler and 20.2 kg/s (IGOxlO3 Ib/hr) four-burner PC boiler.
Ib/hr) four-burner
-------
These data indicate that the NO emissions are unit-dependent as well as coal-
dependent. Furnace volume, burner heat release rate, burner spacing, and
fuel/air mixing characteristics all have been found to affect NO emissions.
In order to control CO emissions from the eastern coal, it was
necessary to operate at higher 0 levels; this led to higher NO emissions.
For western coal firing, it has been shown that the furnace can operate at
lower excess O , thus lower NO. VJestern coal typically contains less bound
fuel nitrogen than eastern coal. This fuel nitrogen can be as little as half
the amount found in typical eastern coals.
The third factor affecting NO emissions is flame temperature. The
high moisture content of western coal causes the temperature of the western
coal flame to be lower than the eastern coal flame. This lower flame tempera-
ture lowers the fixation of molecular nitrogen in the combustion air. The
effect of flame temperature lowers the fixation of molecular nitrogen in the
combustion air.
Sulfur Oxides
Sulfur oxides emissions are largely a function of sulfur in the fuel.
There has been some work that indicates that coal ash composition may affect
the amount of sulfur oxides emitted (Ref. 2-2). The comparison of the eastern
and western coals at Alma (see Table 2-7) show the benefit of fuel substitu-
tion in the control of SO emissions.
x
Particulates
Table 2-8 contains particulate emissions data from the eastern and
western coals tested. The ash content of the coal and the combustible con-
tent of the fly ash emissions are given for a comparison of the maximum
potential emissions from each coal. For a 4-burner, 29 kg/s steam flow
(230,000 Ib/hr) pulverized coal boiler at Alma firing eastern coal, approxi-
mately 60% of the coal ash was found in the flue gas stream; whereas only 40%
of the western coal ash was found in the flue gas under identical firing con-
ditions and for coals with the same ash content. Electrostatic precipitator
efficiencies were unimpaired by the fuel switch. Combustible losses were
higher on eastern coal than on western coal. A 34% reduction in uncontrolled
particulate emissions was realized by switching to western coal.
22
-------
TABLE 2-7. SO EMISSION COMPARISON FOR WESTERN AND EASTERN COALS
x
Test Site
Alma
Stout
Madison
Willmar
Eau Claire
St. Johns
Fremont
Fremont
Alma
Stout
Willmar
Eau Claire
Madison
Fairmont
Coal Source (Mine)
Western Coal
Montana (Sarpy Creek)
Wyoming (Bighorn)
Montana (Colstrip)
Montana (Colstrip)
Wyoming (Bighorn)
Wyoming (Bighorn)
Wyoming (Hana-Rosebud)
Colorado (Walden)
Overall Average
Eastern Coal
Kentucky (River King)
Kentucky (Vogue, Seam 2)
So. Illinois (Stonefort)
W. Kentucky (Vogue)
W. Kentucky (Vogue)
So. Illinois (Sahara)
Overall Average
Average Fuel Sulfur
percent
0.96
0.96
0.99
1.15
0.73
0.61
1.38
0.38
3.57
2.94
2.28
2.87
3.04
2.13
ng/J
(Ib S02/106
Btu Fired)
880 (2.05)
822 (1.92)
949 (2.21)
1174 (2.74)
657 (1.53)
498 (1.16)
957 (2.23)
263 (0.61)
775 (1.81)
2800 (6.64)
2043 (4.76)
1567 (3.65)
1803 (4.72)
2167 (5.05)
1471 (3.43)
2021 (4.71)
Average SO Emissions
ppm
791
681
1044
934
695
592
1053
235
3036
2129
1815
2363
2378
1628
ng/J
(Ib S02/106
Btu Fired)
649 (1.51)
559 (1.30)
858 (2.00)
766 (1.79)
570 (1.33)
486 (1.13)
864 (2.01)
193 (0.45)
618 (1.44)
2491 (5.81)
1747 (4.07)
1489 (3.47)
1939 (4.52)
1952 (4.55)
1336 (3.11)
1826 (4.25)
Fuel
Sulfur
Emitted
percent
73.8
69.6
90.4
65.3
86.8
97.5
90.3
73.4
79.8
87.0
85.5
94.0
95.0
90.0
89.7
90.4
to
U)
Average SO
Average SO
x
reduction based on flue gas emission measurements = 1206 ng/J
reduction based on fuel analysis = 1244 ng/J (2.90 Ib SO /10
(2.81 Ib SO2/10
Btu) = 61.7%
Btu) = 66.1%
-------
TABLE 2-8. PARTICULATE EMISSIONS DATA FOR ALL COALS TESTED
Test Site
(Unit Type)
Alma
(PC)
Eau Claire
(TGS)
Madison
(SS/TG)
St. Johns
(SS/DG)
Fremont
(PC)
Hillmar
(SS/TG)
Stout
(VG)
Fairmont
(SS/TG)
AVERAGE
WESTERN COAL
Test
No.
66
5
6
2
5
9
8
34
17
Coal Type
Montana
Wyoming
Montana
Wyoming
Wyoming*
(Uana)
Colorado*
Montana
Wyoming
1/3 Wstn *
2/3 Batn
Fuel Ash
ng/J
(Ib/MBtu)
5,781
(13.47)
2,476
(5.767)
4,088
(9.52)
2,098
(4.888)
3,429
(7.986)
3,235
(7.538)
4,655
(10.847)
1,986
(4.628)
3,263
(7.603)
3,478
(8.104)
Emissions
ng/J
(Ib/MBtu)
Uncon-
trolled
2,266
(5.28)
104
(0.2414
742
(1.73)
192
(0.446)
1,545
(3.6)
1,605
(3.74)
97
(0.2263!
914
(2.13)
719
(1.676)
Con-
trolled
9
(0.0214)
~
—
—
420
(0.978)
313
(0.729)
303
(0.705)
—
212
(0.49S)
175
(0.407)
Combus-
tion
Content
percent
0.55
28
— -
20
Emission -
Combustion
Fuel Ash
percent
39
4
• 23
9
45
50
—
5
28
EASTERN COAL
Test
No.
9
28
14
11
34
33
9
Coal Type
W. Kentucky
W. Kentucky
W. Kentucky
Unknown
So. Illinois
K. Kentucky
So. Illinois
Fuel Ash
ng/J
(lb/M3tu)
5,781
(13.47)
2,949
(6.87)
3,432
(7.996)
1,730
(4.031)
2,667
(6.32)
2,537
(5.911)
2,586
(6.026)
3,098
(7.22)
Emissions
ng/J
(Ib/MBtu)
Uncon-
trolled
3,411
(7.947)
150
(0.3504)
738
(1.72)
617
(1.435)
—
2.715
(0.6412)
1,133
(2.64)
1,054
(2.46)
Con-
trolled
8
(0.0184)
—
~
—
329
(0.765)
—
176
(0.409)
170
(0.397)
Combus-
tion
Content
percent
4.13
50
26
3.25
inission -
Combustion
Fuel Ash
percent
59
—
22
—
—
11
44
34
Change
percent;
-34
-31
+0.6
-69
- 8
-65
-19
-32
•Hot included in awngn
-------
A 4-burner, 20.2 kg/s steam flow (160,000 Ib/hr) pulverized coal unit
was tested at Fremont, Nebraska, on a Wyoming subbituminous coal and a Colorado
subbituminous coal. Again the Wyoming coal with a higher ash content had less
fly ash in the flue gas than the Colorado coal. However, the cyclone dust
collector efficiency was reduced to 72% on the Wyoming coal from 80.5% on the
Colorado which resulted in 108 ng/J (0.25 Ib/MBtu) greater controlled particu-
late emissions.
2.3 STOKER-FIRED BOILERS
Coal firing of industrial boilers can be separated into two broad
classes-suspension firing and grate firing.
Suspension firing is normally applied in larger sized units, however,
units as small as 4.4 kg/s (35,000 Ib/hr) steam flow have been built for
pulverized coal firing. Current economics indicate a break-even point in the
25.2 to 31.5 kg/s (200,000 to 250,000 Ib/hr) steam flow range. Suspension
firing includes both pulverized coal firing (70% through a 200 mesh screen)
and cyclone firing (crushed to 6.35 mm (1/4") with about 10% through a 200
mesh screen).
Grate firing comprises three general stoker types:
Underfed
Overfed
Spreader
Within these three types, there are a number of variations in feed methods
and grate design. Stoker-fired boilers have been built covering the entire
capacity range of this study: 1.3 to 31.5 kg/s (10,000 to 250,000 Ib/hr)
steam flow. The present stoker-fired boiler population represents a highly
individualized array of equipment.
Table 2-3, presented previously, lists stoker types tested in this
study. From this assortment of units, the emissions and operating character-
istics of western coal firing have been determined.
25
-------
2.3.1 Operational Characteristics of Western Coals in Stokers
A chronological display of the development of the various stoker types
would appear as shown in Figure 2-4.
Two properties of western subbituminous coals result in operational
problems for stoker-fired units. They are:
Coal weathering - resulting in size reduction
"Free burning" characteristic - resulting in an
uncovered grate
Many older underfed and traveling grate stokers were manufactured with insuf-
ficient control of the undergrate air to use western coal as a fuel. The
problem is manifested when a dark spot of unburned coal develops on the grate.
This patch of coal can grow into a large clinker if special measures are
not taken to remove it. The "black patches" occur because there is insuffi-
cient local air pressure under the patch to maintain vigorous burning. The
loss of local air pressure occurs because some other portion of the grate,
in the same plenum control area, has become thin or bare and allows the com-
bustion air to pass through easily. These units were designed for an eastern
coal that formed some coke while burning and in turn maintained even coverage
of the grate. The free-burning western coals, on the other hand, tend to
form a fine powdery ash which either blows off or falls through the grate,
leaving it bare. This problem is compounded by the serious size reduction
that occurs while the western coal is in transit. The small coal particles
burn more rapidly when there is available air . However, when there is insuf-
ficient air they tend to plug the grate and fuel-bed openings and form dark
patches which turn into clinkers.
The older underfed and overfed stokers designed for eastern coal
will require modifications to the undergrate air chamber to allow finer
control of the air distribution, if western coals are to be used.
26
-------
Chronology of Stokers
1850 1900 1950
Jingle Retort Underfed Stokers 1
Multiple Retort
Underfed Stokers
Chain or Traveling .
Grate Stokers
Spreader Stokers-
Vibrat-^
ing Grate
Figure 2-4. Chronological display of the development of stoker-type
boilers.
27
-------
Spreader stokers are affected by the same coal properties but to
a lesser extent since approximately half of the combustion takes place in
suspension. This suspension burning reduces the number of "fines" that
reach the grate. However, the fines in the coal tend to burn close to the
spreader, sometimes flashing back into the feeder opening. This flash-back
mode can be dangerous since there is the possibility of a fire in the coal
feeder. Coke and slag also have a tendency to build up on the spill plates
and rotor blades if the flash back is allowed to persist. This problem can
be alleviated somewhat by rotor speed and spill plate adjustments.
The western coal performed well in the spreader stoker units. However,
some units designed for eastern coal, the maximum attainable load was about
80% while on western coal. This was due to insufficient induced draft fan
capacity and, as in pulverized coal units, high superheat steam temperatures.
Removing the major part of the moisture from the coal prior to combustion
would alleviate both of these problems.
2.3.2 Emissions From Stoker-Fired Units
Sulfur Oxides—
The emissions of sulfur oxides from stokers is to a large degree,
governed by the sulfur in the fuel. These emissions are independent of load
and excess air in the flue gas. Table 2-7, presented earlier, contains the
results of a SO emission comparison for all the coals tested in this study.
X
The overall average SO emissions from actual operating industrial type
boilers decreases from 1826 ng/J (4.25 Ib/MBtu) on eastern coal to 618 ng/J
(1.44 Ib/MBtu) on western coal, or 66%. This is to be compared to the reduc-
tion as calculated from the fuel analysis from 2025 ng/J (4.71 Ib/MBtu) on
eastern to 778 ng/J (1.81 Ib/MBtu) on western coal, or ,62%. The sulfur
content of the fuel was calculated from analyses of actual fuels burned.
The mineral analyses of the coals tested, given in Table 2-1, show
that the western coal contains a high percentage of lime (CaO), and magnesia
(MgO). The amount of sulfur trioxide retained in the ash closely approximates
the lime content of the ash in all cases. This suggests that the CaO may tie
up some of the sulfur as a sulfate. The western coal with its greater lime
content retains more sulfur than the eastern coal as indicated by the data in
Table 2-7.
28
-------
Gronhovd, et al. (Ref. 2-2) have published a study of sulfur oxides
emissions from lignite-fired power plants. They found significant amounts of
sulfur retained by the ash. They could satisfactorily correlate their data
by using the following relationship:
Sulfur emitted, as % of sulfur in coal =
Na_O
110.1 - 12.7 |A?a? I - 48.1
% A1203 / -«•^ I % Si02
This correlation could not predict the amount of sulfur emitted in
the flue gas as SO- when the subbituminous coals used in this study were com-
pared to the actual emissions. The Gronhovd correlation gave consistently
higher emission factors than actually measured.
Table 2-7 contains the results of fuel sulfur analyses and SO emis-
sion analyses for six western and eastern coals. The fuel analysis and the
SO_ emissions analysis for the same tests were compared for each coal. The
results were averaged where there was more than one test. The results show
that on the average, the western subbituminous coal emitted only 80% of the
available fuel sulfur, whereas the eastern base coal emitted 90.4% of the
available fuel sulfur under comparable boiler operating conditions.
It can be concluded from this data that naturally reduced sulfur
emissions are influenced by coal type and are of a magnitude such that the
reductions should be considered when choosing a coal for reasons of SO
X
compliance.
Nitric Oxide—
Nitric oxide emissions from stokers exhibited a similar dependence
on excess O in the flue gas as were observed with pulverized coal firing.
At constant load, nitric oxide emissions increased with increasing excess 02-
Additionally, nitric oxide emissions increased slightly with increasing load.
29
-------
However, the slope of the NO vs. O curve is less for stoker-fired
units than for the higher intensity combustion devices. Figure 2-5 shows an
interesting NO vs. 0 result for a water-cooled vibrograte stoker. The
western coal (Wyoming Bighorn) has a slope of 12 (ppm NO/% O^ compared to
the eastern coal (Kentucky Vogue) which has a slope of 35 (ppm NO/% Q^).
Figure 2-6 gives the NO vs. O plot for the same two coals on an overfed tra-
veling grate stoker without a water-cooled grate. On this unit, both coals
exhibit the same NO vs. O dependence. In fact, of the boilers tested, the
water-cooled grate was the only unit having different NO vs. O slopes for
the two coals tested. It is speculative as to whether the additional cool-
ing of the grate affects the conversion of atmospheric nitrogen to NO.
Stokers have overall lower NO emissions than pulverized coal units
since the stokers operate in a "staged combustion" configuration. The stokers
that have little or no suspension burning such as underfed and overfed stokers
have a greater degree of staging than do the spreader stokers. In the stoker,
the fuel devolatizes in the fuel bed under reducing conditions, then is mixed
with the combustion air above the bed. Mixing is provided by overfire air
jets or by front or rear arches in the furnace. Clinkering in the fuel bed
establishes a limit to the degree of staging that can be achieved on stokers.
Figure 2-7 shows these limits for a 12.6 kg/s (100,000 Ib/hr) steam spreader
stoker.
Carbon Monoxide and Unburned Hydrocarbons—
Carbon monoxide (CO) and unburned hydrocarbons (UHC) emissions from
stokers as with all combustion systems, can be controlled by providing ade-
quate excess air and proper mixing to insure complete combustion. High
excess air conditions can cause CO and UHC emissions as can too low a level of
excess air. Figure 2-8 gives the results of CO emission measurements on a
12.6 kg/s (100,000 Ib/hr) steam spreader stoker as a function of excess
air for both eastern and western coal. At high load, 11.3 kg/s (90,000 Ib/hr)
steam, CO emissions increase with decreasing excess air. However, at low
and intermediate loads, a point is reached where increasing excess air
results in rapidly increasing CO emissions. This behavior was observed
30
-------
250
225 -
JN200
n
4J
j-i
•a
175
150
125
1 1 1 r
Water-cooled vibrograte stoker,
5.7 kg/s (45xl03 Ib/hr) steam.
/
4
<>/
4
/
o
3.2 kg/ s /\
(25xl03 Ib/hr) -
/
/
n
Eastern Coal (Kentucky Vogue)
Load
/S 1.9 kg/s (ISxlO3 Ib/hr)
^3.2 kg/s (25xl03 Ib/hr)
D 5 kg/s (40xl03 Ib/hr)
Western Coal (Wyoming Bighorn)
Load
1 \ 1
O
•
1 1
3.
2.
1
2
0
kg/s
kg/s
(25x10
(15x10
1
3
3
Ib/hr)
Ib/hr)
i
7 P 9
EXCESS OXYGEN, percent
10
11
12
Figure 2-5. Comparison of western and eastern coal nitric oxide emissions, University of
Wisconsin, Stout.
-------
350
w
to
300
250
fit
*.
O
200
150
Overfed traveling grate stoker,
7.6 kg/s (GOxlO3 Ib/hr) steam.
J
V
1
Western Coal (Wyoming Bighorn)
Load
O 3.8-4.4 kg/s (30-35 xlOJ Ib/hr)
• 1.9-2.3 kg/s (15-18 xlO3 Ib/fcr)
Eastern Coal (Kentucky Vogue)
Load
^2-9-3.4 kg/s (23-27 xlOJ Ib/hr)
Y1.9-2.3 kg/s (15-18 xlO3 Ib/hr)
10 12
EXCESS OXYGEN, percent
14
16
18
Figure 2-6.
Comparison of western and eastern coal nitric oxide emissions, University
of Wisconsin, Eau Claire.
-------
12.0
11.0
r°
u
9.0
•P
c
v
o
H
0)
CN
O
en
8
8.0
7.0
6.0
of
45
T 1 r
Normal Operation
ID Fan Limited
CO, Clinker, or
Excessive Smoke Limitation
51
57 63 69
PERCENT OF RATED LOAD
75
81
Figure 2-7. Stoker firing staging limits, Willmar Unit 3, 20.2 kg/s steam,
western coal.
33
-------
2000
OJ
11.3
(90x10 Ib/hr)
0\°
f)
4-1
(0
g
a
a
O 10.1 kg/s (SOxlO Ib/hr)
O 7.6 kg/s (60xl03 Ib/hr)
Q 3.8 kg/s ( 30x10 3 Ib/hr)
— — Eastern Coal
Western Coal
w
Q
H
X
o
is
o
§
1000
500
6 8 10
EXCESS OXYGEN, percent
14
16
Figure 2-8. Carbon monoxide vs. excess oxygen, University of Wisconsin, Madison
12.6 kg/s steam spreader stoker.
-------
for both coals. At low excess air, CO results from inadequate mixing of
fuel and air. At high excess air settings, the fuel bed is thin even to
the extent of some uncovered grate area which is thought to lead to local
quenching of the flame by the combustion air and incomplete oxidation of
CO to C02. The western coal can be fired at 2% lower excess O at high
load while producing comparable levels of CO emissions. This translates
to higher unit efficiency because of lower dry gas and combustible losses.
Table 2-9 contains unburned hydrocarbon emission data for both an
eastern and a western coal on the same spreader stoker unit described above.
Unburned hydrocarbon emissions were higher at low load and high excess air
than at high load and normal excess air, thus following the same trends as
the CO emissions. No appreciable differences in UHC emissions were noted
between eastern and western coals.
TABLE 2-9. COMPARISON OF HC EMISSIONS
FROM EASTERN AND WESTERN COALS
kg/s
5.0
7.6
11.3
11.3
Load
(103 Ib/hr)
40
60
90
90
Eastern Coal
o2(%)
15.
12.7
9.7
8.7
HC
(corr. ppm)
114
54
48
44
Western Coal
o2(%)
13.8
11.3
—
8.8
HC
(corr. ppm)
125
18
—
44
Carbon monoxide emissions are a much more sensitive measure of incom-
plete combustion than are unburned hydrocarbons. A comparison of CO emissionr
and carbon carryover can be made. Figure 2-9 is a plot of percent carbon in
the outlet flyash of a 20.2 kg/s (160,000 Ib/hr) steam spreader stoker firing
western (Montana) coal. This unit exhibited rather high carbon losses which
increased with unit load. The carbon losses on eastern coal were even larger
35
-------
30
25
20
-------
than for the western coal. However, the point to be made here is that by
measuring the carbon monoxide emissions, an indication of the other combust-
ible losses can be gained. The CO emissions for the same tests are shown
in Figure 2-10.
Particulate Emissions—
Three types of stoker-fired boilers were tested. They were
spreader stoker
vibrating grate stoker
traveling grate stoker
Within the spreader stoker category, four unit sizes and two grate
configurations were tested. The stoker at St. Johns was fitted with a dump-
ing grate while the boilers at Madison, willmar, and Fairmont were all equipped
with traveling grates. The spreader stokers with their greater degree of
suspension burning and thin fuel bed have higher particulate emissions than
the mass fed vibrating grate and traveling grate stokers. The spreaders
are intermediate between the pulverized coal units and the mass fed stokers.
Uncontrolled particulate emissions from spreader stokers average about 858
ng/J (2 Ib/MBtu).
In three of the four spreader stokers, western coal produced mark-
edly lower particulate emissions. In the case of Madison, both eastern
and western coal produced the same particulate loadings although the western
coal had 16% more ash. The combustible content of the western coal fly ash
was half that of the eastern.
Dramatic reductions in particulate emissions were obtained on both
a vibrating grate stoker (65%) and a traveling grate stoker (31%) by switch-
ing to western coal. These units both have inherently low particulate emissions
because the combustion takes place in thick fuel beds with little or no sus-
pension burning.
37
-------
o
<*>
I
a
H
Q
H
1
1
<
u
1800
1600 —
1400 —
1200 —
1000 —
800 —
600 —
400 —
200
45
51
57 63 69
PERCENT OF RATED LOAD
81
Figure 2-10.
Carbon monoxide emissions vs. load, Willmar Unit 3, 20.2 kg/s
steam spreader stoker, western coal.
38
-------
For a given ash content in the coal, the quantity of participate
matter in the flue gas from stoker-fired boilers depends primarily upon
the amount of burning that takes place in suspension or on the grate.
Table 2-8 gives an average flue gas particulate loading from both eastern
and western coals as measured before the control device for the stoker
types tested as well as pulverized coal-fired boilers.
Spreader stokers with the greater suspension burning have from two
to three times the particulate loading of the traveling grate and the vibro-
grate stokers. On the average, the western coal test results showed a 32%
lower particulate loading than the eastern coal.
In summary it can be concluded that there is a distinct advantage
from a particulate emissions standpoint, for switching to western coals.
2.3.3 Western^ Coal Efficiency Tests
Figure 2-11 presents boiler efficiency data as a function of boiler
load at two different coal-fired boilers each burning an eastern bituminous
low moisture coal and a western subbituminous high moisture coal. Data are
shown for a 12.6 kg/s (100,000 Ib/hr) spreader stoker with a traveling grate
and a 4-burner wall-fired, 29 kg/s (230,000 Ib/hr) pulverized coal unit.
The latter boiler was equipped with a tubular air preheater while the stoker
was equipped with a feedwater economizer.
An examination of the curves in Figure 2-11 suggests both boiler-to-
boiler efficiency differences and the importance of coal properties on the
efficiency characteristics of an individual boiler. The efficiency of the
pulverized coal boiler is greater than the stoker efficiencies over the load
range primarily due to the higher excess oxygen and combustible loss character-
istics of the stoker boiler. Although dissimilar heat recovery devices are
used at each boiler (air preheater versus economizer) this has little impact
on the efficiency comparisons since stack temperatures were roughly equiva-
lent at both boilers.
Firing with western coal reduced the efficiency of the pulverized
coal boiler by approximately 5% while very similar efficiencies were exhibited
by both coals on the stoker unit. In the first case the shift in efficiency
39
-------
100
95
90
4J
fi
0)
a
w
H
u
H
H
rt
a
80
75
70
65
60
55
50
29 kg/s (230x10" Ib/hr) Pulv. Unit: "
\/ Eastern Coal (5% Moisture)
A Western Coal (18% Moisture) ~
12.6 kg/s (lOOxlO3 Ib/hr) Spreader Stoker
O Eastern Coal (7% Moisture)
D Western Coal (25% Moisture)
20
40 60
PERCENT OF RATED LOAD
80
100
Figure 2-11.
Boiler efficiency comparison of pulverized coal firing to
spreader stoker coal firing for a high and low moisture
coal type.
40
-------
is attributed to the dissimilar moisture content of the two coals which
resulted in different "moisture" heat losses. Slight variations in excess
O2 levels, stack temperatures, and combustibles had no appreciable effect
on the other heat losses (dry gas, solid, and gaseous combustible losses).
For the stoker unit, a similar impact on efficiency would be expected
if coal properties were the only variable. However, in this case, the com-
bination of higher combustible losses experienced with the eastern coal
resulted in similar efficiencies. As a point of interest, the combustible
losses were less than 1% for all the pulverized coal tests shown, whereas
combustible losses on the stoker unit were 2% to 4% and 7% to 11% for the
western and eastern coals respectively. The absence of cinder reinjection
and combustion air preheat on the stoker boiler contributed to the rather
high combustible losses.
REFERENCES FOR SECTION 2.0
2-1. de Lorenzi, O. (ed.), Combustion Engineering, Combustion Engineering
Company, Inc., p. 7-8, 1947.
2-2. Gronhovd, G. H., Tufte, P. H., and Selle, S. J., "Some Studies on
Stack Emissions from Lignite-Fired Power Plants," Presented at 1973
Lignite Symposium, Grand Forks, ND, May 9-10, 1973.
41
-------
SECTION 3.0
RECOMMENDATIONS FOR FURTHER WORK
The major areas of future work on western coals as defined by this
program are as follows:
Coal drying
Coal sizing for stokers
Demonstration of sulfur retention by the ash.
Drying western coals will increase the heat content of the coal and
should improve the performance of these coals on units designed for higher
Btu coals.
Facilities and techniques for local coal sizing should be developed
to provide stoker quality coal to industrial users. Proper load preparation
prior to shipment should reduce coal size deterioration in transit.
Further work should be done on the sulfur retention characteristics
of most western coals. Some work has been done on this problem, the results
are contained in Appendix F. This project showed the potential for sub-
stantial retention of fuel sulfur in the boiler ash. The mechanism of this
retention should be investigated and demonstrated in order to optimize the
conditions for maximum sulfur reductions.
42
-------
SECTION 4.0
TEST EQUIPMENT AND PROCEDURES
This section details specific emissions measurements, and the sampling
procedures followed, to assure accurate, reliable data collection.
4.1 GASEOUS EMISSIONS MEASUREMENTS
This section describes the analytical instrumentation and related
equipment used to measure NO, NO2, CO, CO , 0 , and hydrocarbons. The gas
sampling and conditioning system are described. This equipment is located
in a mobile testing van owned and operated by KVB. The systems described
below were developed as a result of over five years of field testing.
4.1.1 Analytical Instruments and Related Equipment
The analytical system consists of five instruments and associated
equipment for simultaneously measuring the composition of the flue gas. The
analyzers, recorders, valves, controls, and manifolding are mounted to a panel
in the van. The analyzers are shock-mounted to prevent damage from vibration.
The flue gas constituents measured are oxides of nitrogen (NO, N0x), carbon
monoxide (CO), carbon dioxide (CO ) , oxygen (O2), and gaseous hydrocarbons
(HC). A detailed discussion of each analyzer follows.
The oxides of nitrogen monitoring instrument used is a Thermo Electron
Model 10 chemiluminescent nitric oxide analyzer. The operational basis of the
instrument is the chemiluminescent reaction of NO and 03 to form NO2. Light
emission results 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.
43
-------
Ambient air for the ozonator is drawn through an air dryer and a 10
micron filter element. Flow control for the instrument is accomplished by
means of a small bellows pump mounted on the vent of the instrument, downstream
of a separator, which insures that no water collects in the pump.
The basic analyzer is sensitive only to NO molecules. To measure
NO (i.e., NO + NO ) , the NO is first converted to NO. This is accomplished
X £ £
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, NO molecules in the sample gas
are reduced to NO molecules, and the analyzer now reads NO . NO2 is obtained
by the difference in readings obtained with and without the converter in
operation.
Specifications:
Accuracy: ;+ 1% of full scale
Span Stability: +_ 1% of full scale in 24 hours
Zero Stability: +_ 1 ppm in 24 hours
Power Requirements: 115 +_ 10 V, 60 Hz, 1000 watts
Response: 90% of full scale in 1 sec (NO 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 concentration is measured by a Beckman Model 315B
nondispersive infrared (NDIR) analyzer. This instrument measures the dif-
ferential in infrared energy absorbed from energy beams passing 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)
44
-------
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.
Specifications:
Accuracy: +_ 1% of full scale
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
Output: 4-20 ma
Range: 0-500 and 0-2000 ppm CO
Carbon dioxide concentration is measured by a Beckman Model 864
short path-length NDIR analyzer. This instrument measures the differential
in infrared energy absorbed from energy beams passing 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 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.
Specifications:
Accuracy: +_ 1% of full scale
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
Output: 4-20 ma
Range: 0-5% and 0-20% 0
45
-------
A Teledyne Model 326A oxygen analyzer is used to automatically and
continuously determine the oxygen content of the flue gas sample. 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 inter-
nally and an electric current is produced that is proportional to the concen-
tration of oxygen. This current is measured and conditioned by the instru-
ment's electronic circuitry to give a final output in percent O^ by volume.
Specifications:
Accuracy: •+ 1% of full scale
Response: 90% in less than 40 sec.
Sensitivity: 1% of low range
Linearity: +_ 1% of full scale
Ambient Temperature Range: 32 °F to 125 °F
Fuel Cell Life Expectancy: 40,000 + hours
Power Requirement: 115 VAC, 50-60 Hz, 100 watts
Output: 4-20 ma
Range: 0-5%, 0-10%, 0-25% 0 full scale
Hydrocarbons are measured using a Beckman Model 402 hydrocarbon
analyzer which utilizes the flame ionization method of detection. The sample
is drawn through a heated line to prevent the loss of higher molecular weight
hydrocarbons to the analyzer. It is then filtered and supplied to the burner
by means of a pump and flow control system. The sensor, which is at the burner,
has its flame sustained by regulated flows of fuel (40% hydrogen + 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 an
electronic measuring circuit. This ionization current is proportional to
the concentration of carbon atoms which enter the burner.
Specifications:
Accuracy: +_ 1% of full scale
Full scale sensitivity, adjustable from 5 ppm CH
to 10% CH
Response Time: 90% full scale in 0.5 sec
46
-------
Electronic Stability: + 1% of full scale for successive
identical samples
Reproducibility: +_ 1% of full scale for successive
identical samples
Analysis Temperature: Ambient
Ambient Temperature: 32 °F to 110 °F
Output: 4-20 ma
Electrical Power Requirements: 120 V, 60 Hz
Automatic Flame-Out Indication and Fuel Shut-Off Valve
Range: 5 ppm full scale to 10% full scale as CH
Recording instruments. The outputs of the four analyzers are pre-
sented on front panel meters and are simultaneously recorded on strip chart
recorders. The recorder specifications are as follows:
Specifications:
Strip Chart Display
Chart Size: 9-3/4 inch
Accuracy: jf 0.25%
Linearity: < 0.1%
Line Voltage: 120 V j^ 10% at 60 Hz
Span Step Response: 1 sec
4.1.2 Gas Sampling and Conditioning System
The gas sampling and conditioning system consists of the probes,
sample line, valves, pumps, filters, and other components necessary to deliver
a representative, conditioned gas sample to the analytical instrumentation.
The following section describes the system and the components which make up
the system. The entire gas sampling and conditioning system shown sche-
matically in Figure 4-1 is contained in the emission test vehicle.
47
-------
03
- ^
DUCT 8 — 1
'. i
FLO*
CC- TSC
FLO*
INOICA
......
=— =
srffrnnji
7 X \
C )
^>
7 t
(3
^
^
u
g
3
u
;j
;)
1
r v
O.1CK
Figure 4-1. Flow schematic of mobile flue gas monitoring laboratory.
-------
4.2 GASEOUS EMISSION SAMPLING TECHNIQUES
Boiler access points for sampling were selected as near as possible
to comply with the EPA guidelines regarding number and location. Probe
bundles dividing the duct into equal area sampling zones were installed.
Each probe consisted of 1/2" 316 stainless steel heavy wall tubing. A 0.7
micron Pall-Trinity sintered stainless steel filter was attached to each
probe for removal of particulate material.
Gas samples to be analyzed for O , CO, CO , and NO were conveyed
•b £
to the KVB mobile laboratory through 3/8" nylon sample lines. After passing
through bubblers for flow control, the samples passed through a diaphragm
pump and a refrigerated dryer to reduce the sample dew point temperature to
35 °F. After the dryer, the sample gas was split between the various contin-
uous gas monitors for analysis. Flow through each continuous monitor was
accurately controlled with rotameters. Excess flow was vented to the outside.
Gas samples were drawn sequentially from all probes for each test. The
average emission values were reported except where stratification of the gase
gases was severe or could be related to problems in the fuel bed. In spe-
cial cases such as this,the values from each individual probe were reported.
For obtaining NO« and HC data, a heated sample line was used to
prevent condensation losses. This line bypasses the bubblers and feeds the
hydrocarbon and nitric oxide monitors directly. A heated filter removed
particulate matter and flows were controlled with rotameters. Both of
these instruments have sample pumps located after the analyzer so that they
will not interfere with the sample gas. Heated line samples were drawn
through a single fixed probe.
4.3 SULFUR OXIDES MEASUREMENT AND PROCEDURE
Measurement of SO,. AND SO concentrations was done by wet chemical
£• -J
analysis using the "Shell-Emeryville" method. In this technique, the gas
sample is drawn from the stack through a glass probe (Figure 4-2), contain-
ing a quartz wool filter to remove particulate matter, into a system of
three sintered glass plate absorbers (Figure 4-3). The first two absorbers
contain aqueous isopropyl alcohol and remove the sulfur trioxide, the third
49
-------
_l
Flue Wall
Asbestos Plug
Ball Joint
Vycor
Sample Probe
Pryometer
and
Thermocouple
Figure 4-2. Cutaway showing SO /SO sampling probe.
•^ J
50
-------
Spray Trap
Pressure Gauge
Volume Indica
tor
Vapor Trap Diaphragm
Pump
Dry Test Meter
Figure 4-3. Shell-Emeryville S02/SO3 sample system.
51
-------
contains aqueous hydrogen peroxide solution which absorbes the sulfur dioxide.
Some of the sulfur trioxide is removed by the first absorber while the
remainder, which passes through a sulfuric acid mist, is completely removed
by the secondary absorber mounted above the first. After the gas sample
has passed through the absorbers, the gas train is purged with nitrogen to
transfer sulfur dioxide, which has dissolved in the first two absorbers, to
the third absorber to complete the separation of the two components. The
isopropyl alcohol is used to inhibit the oxidation of sulfur dioxide to
sulfur trioxide before it gets to the third absorber.
The isopropyl alcohol absorber solutions are combined and the sul-
fate resulting from the sulfur trioxide absorption is titrated with standard
lead perchlorate solution using Sulfonazo III indicator. In a similar manner,
the hydrogen peroxide solution is titrated for the sulfate resulting from
the sulfur dioxide absorption.
The gas sample was drawn from the flue by a single probe made of
quartz glass inserted into the duct approximately one-third to one-half way.
The inlet end of the probe holds a quartz wool filter to remove particulate
matter. It is important that the entire probe temperature be kept above the
dew point of sulfuric acid during sampling (minimum temperature of 260 °C) .
This was accomplished by wrapping the probe with heating tape.
Three repetitions of SO were made at each test point.
X
4.4 PARTICULATES MEASUREMENT AND PROCEDURES
Particulate samples were taken at the same sample ports as the
gaseous emission samples using a Joy Manufacturing Company portable effluent
sampler (Figure 4-4). This system, which meets the EPA design specifica-
tions for Test Method 5, Determination of Particulate Emissions from Sta-
tionary Sources (Federal Register, Volume 36, No. 27, page 24888, December
23, 1971), was used to perform both the initial velocity traverse and the
particulate sample collection. Dry particulates were collected in a heated
case using first a cyclone to separate particles larger than 5 microns, and
a 100 mm glass fiber filter for retention of particles down to 0.3 microns.
52
-------
Ul
w
Heated Probe
Sampling Nozzle
Filter Holder
T/C (Impinger
in Temp)
T/C (Impinger
Out Temp)
Reverse Type
Pitot Tube and
Gas Temp T/C
Control
Unit
Velocity
Pressure
Gage (AP)
Impingers ^Ice Bath
Fine Control Valve
Check Valve
Umbilical
Cord
\
Sample
Vacuum
Gage
Orifice
Gage (AP)
Dry Test Meter
Coarse
Control
Valve
Air-Tight
Pump
Figure 4-4. Method 5particulate sampling train.
-------
Condensible particulates are collected in a train of four Greenburg-Smith
impingers in an ice water bath. The control unit includes a total gas
meter and thermocouple indicator. A pitot tube system is provided for
setting sample flows to obtain isokinetic sampling conditions.
All peripheral equipment was carried in the instrument van. This
included a scale (accurate to j^ 0.1 mg), hot plate, drying oven (212 °F),
high temperature oven, dessicator, and related glassware. A particulate
analysis laboratory was set up in the vicinity of the boiler in a vibration-
free area. Filters were prepared, tare weighed, and weighed again after
particulate collection in this area. Condensible particulates were measured
by boiling the impinger liquid to dryness in a container of known weight and
then reweighing. Condensible particulate determination is not specified
in EPA Method 5 but was included in many of the tests. Combustible parti-
culates were measured by baking the filter at 750 °C for at least one hour
and reweighing.
Testing was performed both upstream and downstream of the particu-
late collection device to determine collection efficiency. Multipoint
(traverse) sampling was used in each case as in the EPA Test Method 5.
4.5 SAMPLING AND ANALYSIS PROCEDURE
Sampling and analysis proceeded as follows: the sample train was
assembled with a filter baked to dryness for one hour at 783 °K (950 °F),
dessicated, and weighed to a constant weight precise to 0.1 mg. The glass-
ware, probe, and nozzles were washed, rinsed with distilled water three
times, and dried. The impinger box and control unit were leak checked at
38.1 cm (15 in.) Hg vacuum to a leakage rate less than 566.4 cc (0.02 cfm) .
The probe was then attached to the box.
The probe was inserted into the gas stream, the pump turned on,
and samples were taken isokinetically. The following data were recorded
for each sample point: % Q^, sample time, static pressure (in. Hg), stack
temperature (°F), velocity head, orifice AP (in. H2O), gas sample volume
(ft ), oven temperature (°F), impinger temperature-inlet and outlet (°F) ,
and dry gas meter outlet temperature (°F). The sample pump was turned off
54
-------
was
while the sample train was moved from one location to the next. At the
conclusion of the test, the probe was removed from the gas stream, the
sample pump was turned off, and a final set of data were taken.
The equipment was then taken to the laboratory where the probe
washed twice with reagent grade acetone, then cleaned with a probe brush,
and washed again with acetone. The acetone washings and probe brush rinse
were collected in clean dry sample bottles. The cyclone, sampling nozzle,
and collection flask were emptied into a tared 250 ml beaker and washed in
the same manner as the probe with the washings collected in the same sample
bottle. The collection filter was removed from the filter holder and trans-
ferred to a petri dish. The top bell jar of the filter holder and the
connecting glassware were washed into the same sample bottle used for the
probe washings. The volume of liquid collected in the impingers was mea-
sured and recorded. The first three impingers and connecting glassware
with the bottom bell jar of the filter holder were rinsed with distilled
water into a sample bottle which also contained the flue gas condensate
collected by the impingers. The acetone rinses and the cyclone collection
were dried and dessicated in tared 250 ml beakers, the filter was dried
and dessicated. . The beakers and filter were then weighed to a constant
weight and the total amount of particulate collected was determined by addi-
tion of the individual component weights. A blank filter tare weight change
was used to correct the sample filter weight difference for changes due to
handling, baking, and humidity. Blank (control) samples of both the acetone
and distilled water used in testing were also dried, dessicated, and weighed.
Weight corrections for dissolved solids in the washing liquids were made as
appropriate.
4.6 EFFICIENCY EVALUATION
Thermal efficiency is an important tradeoff consideration during
the course of testing. A low emission operating mode may appear satisfac-
tory on the surface but an increase in stack temperature , slagging or
changes in steam temperatures may cause this mode to be discarded.
55
-------
Boiler efficiency was calculated and reported using the ASME Test
Form for Abbreviated Efficiency, revised September 1965, where possible.
The general approach to efficiency evaluation was based on the assessment
of combustion losses. The losses considered were stack gas composition/
temperature and carbon carryover losses.
Flue gas composition parameters included CO and O as well as
2, £
incomplete combustion parameters such as CO. Measurement of the combus-
tible components of particulate matter were made. This was done by baking
particulate collection filters at 750 °C for at least one hour.
Carbon carryover analysis was done by collecting ash samples at
the various outlet points and baking a known quantity of ash at 750 °C
for at least one hour.
These results, when coupled with a fuel analysis and ambient and
exit temperatures, permitted a carbon/heat balance to be run. Steam para-
meters were recorded to assess changes.
56
-------
SECTION 5.0
TEST RESULTS
5.1 DAIRYLAND POWER COOPERATIVE, ALMA, WISCONSIN
Unit #3, Dairyland Power Cooperative, Alma Station, was the first unit
tested under this program. A total of 78 tests were run, the first 55 tests
were on eastern coal and the last 23 on western coal. The unit tested was the
largest pulverized coal burning boiler tested. The unit generated electricity
for a rural populace in southern Wisconsin. The results were very encouraging
for western coal use.
A special series of tests were conducted in which the sulfur retention
properties of the western coal ash were investigated.
5.1.1 Boiler Description
The boiler tested was Unit #3 of the Dairyland Power Cooperative
located in Alma, Wisconsin. This unit is a small, dry bottom, pulverized coal
burning boiler built in 1950 by Riley Stoker Company. It is face fired with
four Riley flare type burners which give it a rated capacity of 29 kg/s
(230,000 Ib/hr) steam flow. The burners are supplied with pulverized coal
from two ball tube mill pulverizers. One mill feeds the top two burners while
the other feeds the bottom two burners.
The unit was recently fitted with a cold side UOP electrostatic
precipitator and a tall stack 183 m (600 ft) . This stack height was required
because of the facility's location in a river valley and the need to disperse
the flue gases above the level of the river bluffs.
The furnace has balanced draft with the induced draft fan located
after the electrostatic precipitator. The air heater is tubular, and the
pendant type superheater has spray steam attemperation.
57
-------
Additional boiler specifications are as follows:
Design Pressure - 7.00 MPa (1,000 psig)
. Design Temperature - 755 °K (900 °F)
. Design Efficiency - 86.0% at 29 kg/s (230,000 Ib/h:
Actual Day-to-Day Operating Conditions
. Throttle pressure - 6.03 MPa (860 psig)
. Drum pressure - 6.31 MPa (900 psig)
. Superheat outlet temperature - 733 °K (860 °F)
. Furnace Width - 5.01 m (16'5-1/4")
. Furnace Depth - 2.53 m (21'1-1/8")
. Furnace Volume - 425 m3 (15,000 ft3)
. Boiler Heating Surface - 1189 m2 (12,700 ft2)
2 2
. Water Wall Heating Surface - 971 m (10,450 ft )
. Heat Release - 20.36 MJ at 29 kg/s steam (19,300 Btu at 230,000 Ib/hr)
Coal is unloaded from a river barge at this site. West Kentucky River
King coal was the base coal tested. The western test coal came from
Sarpy Creek, Montana. Testing was done during the summer months and, there-
fore, coal handling problems due to freezing of the coal were not observed.
Fugitive dust during coal handling was not a problem.
Figure 5.1-1 shows the vertical layout of Alma Unit #3 as it looked
prior to installation of the electrostatic precipitatpr. Table 5.1-1
summarizes the coal analysis made during the test period.
5.1.2 Sampling Locations
Gaseous and particulate emissions were measured upstream and down-
stream of the electrostatic precipitator (ESP). The geometry of the sample
areas is shown in Figure 5.1-2.
The sample area upstream of the electrostatic precipitator was located
just downstream of the old cyclone breeching. The cyclones, shown in Figure
5.1-1, were removed when the electrostatic precipitator was installed. The
sample area consisted of 4 4-inch pipe ports. A bundle of 3 stainless steel
58
-------
Figure 5.1-1.
Vertical layout of Dairyland Power Cooperative's Unit 3, Alma,
Wisconsin, before installation of the electrostatic precipitator.
59
-------
D
-i-
a
H-
D
II
D D D
+ — -4-
ffl Q s
H- + +
° ? °
y
(8-
\
II II II (6-1/2")
*1 _,_^^^^H^
(41-1/2")
Sample Area Upstream of ESP
Average temp.: 480 °K (405 °F)
6 a a 6
-H +• -f +
9 9 9 Q
innnr
(18")
1
(12")
Sample Area Downstream of ESP
Average temp.: 422 °K (300 °F)
-j- Particulate sample point
D Gaseous sample point
Figure 5.1-2. Sample area geometry, Dairyland Power Cooperative Unit 3.
60
-------
TABLE 5.1-1.
COAL ANALYSIS SUMMARY, UNIT #3, DAIRYLAND POWER COOPERATIVE
ALMA, WISCONSIN
Test
Ho.
6
9
16
55*
Average
Coal Type
W. Kentucky
W. Kentucky
W. Kentucky
W. Kentucky
W. Kentucky
As Received Proximate Analysis, %
Moisture
1.68
5.15
2.20
12.08
3.01
Ash
16.00
15.96
19.02.
16.39
16.99
Volatile
60.00
61.65
61.20
55.08
60.95
Fixed
Carbon
22.32
17.24
17.58
16.45
19.05
As Reed
Sulfur
%
3.65
4.23
3.26
3.80
3.71
As Reed
Htg Value
MJ/kg
(Btu/lb}
—
—
--
—
25. 043
(10,776t)
57
63
64*
72
73
74
75
76
78
Average
Montana
Montana
Montana
Montana
Montana
Montana
Montana
Montana
Montana
Montana
16.24
12.75
20.09
17.23
17.94
17.94
19.33
.18.89
17.75
17.26
12.62
16.31
18.19
12.64
10.67
11.56
11.19
11.36
12.32
12.33
47.00
48.42
48.89
37.30
36.30
36.80
37.70
38.30
38.06
39.99
24.14
22.52
12.83
32.83
35.09
33.71
31.78
31.55
31.87
30.44
1.46
1.90
0.79
1.36
. 0.86
0.84
0.84
0.79
0.78
1.23
21-764
(9,365)
22. 740
(9,785)
22. 520
(9,690)
21.846
(9,400)
—
21. 613
(9,300)
21.962
(9,450)
21.570
(9,290)
22.006
(9,469)
Coal Type
H. Kentucky
Montana #
As Received Ultimate Analysis, %
Moisture
7.46
17.26
Carbon
59.87
55.44
Hydrogen
4.24
4.03
Nitrogen
1.09
0.73
Sulfur
3.68
0.81
Ash
14.49
10.04
Oxygen
by diff.
9.17
11.69
As Reed
Htg Value
MJ/kg
(Btu/lb)
25.043
(10,776t)
21.697
(9,336)
* Samples taken from coal feeder, not included in averages because of higher
moisture. Other samples from coal pipes leading to burners.
t Heating value calculated from Ultimate analysis, by Dulong's Formula.
# Mine analysis originally 25.11% moisture corrected to average "as-received"
moisture.
61
-------
probes were inserted into each port so that gaseous samples could be drawn
from the centroid of twelve equal areas dividing the duct. Particulates were
samples from the sample ports with a twenty-point traverse. Sulfur oxides
were sampled from a single point using a 6-foot vycor probe. Initially/
dropout flasks were used on each sample line to remove particulate matter.
Later these were removed in favor of sintered stainless steel filters placed
on the sampling end of the probes.
The sample locations downstream of the electrostatic precipitator
was located after the induced draft fan. Access was provided by 4 4-inch pipe
ports. Twelve stainless steel probes were installed but because stratifica-
tion of the gases within the duct was almost nonexistent, only the center
probe in each port was used. Sintered stainless steel filters were not
required here due to the low particulate loadings. Particulates were sampled
with a twenty-point traverse. Sulfur oxides were sampled from a single point
using a 3-foot vycor probe.
5.1.3 Unit Operation
Alma Unit #3 performed well on both test coals with the exception that
13% of maximum load capacity was lost while burning Montana coal. This was
due to excessive superheat steam temperatures. The steam attemperation system
was not adequate to maintain steam temperatures below 744 °K (880 °F) at loads
above 21.9 kg/s (174,000 Ib/hr) steam flow on Montana coal. Although the unit
was design rated at 29 kg/s (230,000 Ib/hr), it has since been derated to
25.2 kg/s (200,000 Ib/hr) and this was the maximum achievable load on eastern
coal.
The primary factor causing the excessive steam temperature was the
high moisture content of the Montana coal. Moisture reduces the flame temper-
ature which in turn reduces the radiant heat flux (a function of temperature
to the fourth power) to the water walls resulting in lower steam generation.
Although less heat is removed in the radiant section of the boiler, the gas
still contains a large enthalpy which acts on a decreased amount of steam in
/
the convective section resulting in increased steam temperatures. Moisture
in the fuel also results in greater gas flows which increase heat transfer
rates in the convective pass.
62
-------
Unit performance factors such as slagging and flame stability were
not problems while burning Montana coal. Fouling in the superheat pendants
was a problem. Increased tube spacing would help. Mill performance decreased
somewhat but was not detrimental to unit performance as will be described
below-
Pulverizing Mill Performance—
Eastern coking coals, when exposed to furnace temperatures, will swell
and form lightweight, porous coke particles. These may float out of the
furnace before they are completely burned. As a result, carbon loss will be
high unless pulverization is very fine. Free burning (western) coals, on the
other hand, do not require the same degree of fineness because the swelling
characteristic is absent.
High-volatile (western) coals ignite more readily than those with a
low volatile content. Therefore, they do not require the same degree of fine
pulverization. With the exception of anthracite, however, the low-volatile
coals are softer, and may be said to have a higher grindability. As a result,
mill capacity is greater at increased fineness than with high-volatile
coals (Ref. 1).
Table 5.1-2 shows the screen analysis, moisture content, and loads for
the coal burned during several tests. Test number 16 was with one mill in
operation and is thus equivalent to approximately twice the load when compared
with the others.
TABLE 5.1-2. SCREEN ANALYSES OF PULVERIZED COAL
Test No.
Load, % Capacity
103 Ib/hr
- 80 mesh,
- 80 +100
-100 +140
-140 +200
-200 mesh,
Moisture,
%
mesh, %
mesh, %
mesh, %
%
%
EASTERN
9
57
130
0.65
0.75
2.75
6.95
88.90
5.15
16
26
60
1.00
1.00
3.35
8.20
86.45
2.20
WESTERN
57
74
170
2.90
2.30
20.65
34.60
39.55
22.05
63
57
131
1.40
1.30
4.05
8.30
84.95
12.75
73
41
94
0.65
2.32
8.91
32.26
55.66
17.94
75
70
160
8.74
7.70
21.65
16.75
45.15
19.33
78
48
110
1.53
2.23
6.60
17.46
72.18
17.75
63
-------
It is seen that the western coal did not grind quite as well as the
eastern coal. However, this is not thought to be a severe problem. As stated
earlier, western coals do not require the same degree of fineness as eastern
coals because of their higher volatile content and their free burning charac-
teristics. It is noted that the grindability tends to follow the moisture
content.
Boiler Optimization for Nitric Oxide—
A series of tests were conducted to determine the effect of air
register setting, coal diffuser position, excess oxygen, and off-stoichio-
metric firing on the formation of nitric oxide. Limiting factors were the
formation of carbon monoxide, flame impingement on the furnace walls and
slagging tendencies of the different firing modes.
Air Registers were varied at peak load on eastern coal. They were
opened towards the radial position until the flames began to impinge on the
back wall, then they were closed down a little.
The overall trend seen for changing the air registers from tangential
type flow to radial type flow was a decrease in NO emissions. NO was seen to
decrease 17.5% from test #25 to test #27 as the air registers were made more
radial in flow characteristics. The results are summarized in Table 5.1-3
below.
TABLE 5.1-3. EFFECT OF VARYING AIR REGISTERS
(Eastern Coal)
Test
No.
25
26
27
Air Register
Position
As Found
Opened Toward
Radial Position
All in Radial
Flow Position*
Excess
02, %
3.8
3.5
3.5
CO
Dry, ppm
23
26
20
NO
Dry, ppm
617
546
509
Furnace
Conditions
Good
Good
Slight Increase
in Slagging at
Burner Throat
& Back Wall
(*Except lower left air register which was stuck)
64
-------
Some slight increase in slagging was noted for the air registers in
radial position. This slagging occurred around the burner throat and along
the back wall. It was not considered serious.
Coal diffusers were varied while the air registers were in the
tangential or as-found position. These tests were conducted at peak loading
on eastern coal. From the various positions tried, it was concluded that
varying the diffuser position did not change emissions characteristics
significantly. There is some evidence here that nitric oxide emissions
drop as the diffuser is pulled out. However, variations in excess oxygen
mask this effect.
TABLE 5.1-4. EFFECT OF VARYING DIFFUSER POSITION
(Eastern Coal)
Test
No.
42
43
44
45
46
Diffuser
Position
As Found
2" Out
1" In
As Found
As Found
Air Reg. Radial
Excess
02, %
2.9
3.2
2.9
3.4
3.5
CO
Dry, ppm
7
14
15
16
17
NO
Dry, ppm
579
594
611
687
584
When the air registers were opened to the radial position for test #46,
a 15% reduction in nitric oxide was observed. This reinforces the earlier
findings concerning air register position. Thus, the optimized mode of opera-
tion for this unit is diffusers as-found and air registers in a maximum radial
flow position without flame impingement on the back walls. This then became
the normal operating mode for the western coal tests.
Excess oxygen has a pronounced effect on nitric oxide emissions in
Alma Unit #3. This oxygen dependence is seen in Figures 5.1-3 and 5.1-4 where
NO emissions are plotted against excess O for both coals. To measure its
£t
effect in the optimized burner mode, the test series in Table 5.1-5
were run.
65
-------
800
en
700 .
600
4J
rt)
s
I
500
400
300
200
QH. 3 kg/s ($0xl03 Ib/hr5
Q 7.6 kg/s (60xl03 Ib/hr)
A16.4 kg/s (130xlCT Ib/hr)
• 21.4 kg/s (170x10^ Ib/hr)
6 8
OXYGEN, percent
10
12
Figure 5.1-3. Nitric oxide vs. oxygen, Dairyland Power Cooperative Unit 3, western coal.
-------
700
600
0™ 500
<#>
ro
•O
400
300
200
i <*cP
BOOS 41
(Smoke)
6 8
OXYGEN, percent
D21
17,
16
DD19
20Q
Q25.2 kg/s (200x10 Ib/hr) steam
A16.4 kg/s (130xl03 Ib/hr) steam
Q 7.6 kg/s (60xl03 Ib/hr) steam
10
12
14
Figure 5.1-4. Nitric oxide vs. oxygen, Dairyland Power Cooperative Unit 3, eastern coal.
-------
TABLE 5.1-5. EFFECT OF EXCESS OXYGEN
(Eastern Coal)
Test
No.
47
49
50
Test Conditions
Air Reg. As-
Found Normal O
Air Reg.
Radial Low O
Air Reg.
Radial High 02
Excess
02, %
3.7
1.8
5.2
CO
Dry, ppm
20
570
20
NO
Dry, ppm
635
355
690
It is evident that nitric oxide formation is far more sensitive to
excess oxygen than it is to burner adjustments in this particular unit. Thus,
the optimized mode of operation is to lower the excess air to a point just
above the smoke and/or carbon monoxide limit. If we chose the carbon monoxide
limit to be 100 ppm, then 3.0% excess oxygen would be the optimum operating
mode.
Taking burners out-of-service to achieve off-stoichiometric (OS) firing
(or staged combustion) is a technique often used in larger units for emissions
control. However, on boilers the size of Alma Unit #3 this technique has
limited application. Since there are only four burners to adjust, OS firing
can only be achieved effectively at greatly reduced loads.
Four series of tests were run at Alma in which one of the upper burners
was taken out-of-service to achieve OS conditions. In each case, gaseous emis-
sions were measured before and after opening the air register on the inactive
burner. The results are presented in Table 5.1-6.
It is concluded that nitric oxide emissions can be reduced by going
to an off-stoichiometric mode. However, at high loads the CO emissions are
unacceptably high due to the inability of the three active burners to success-
fully do the work of four burners. Also the coal grind is adversely affected
in the OS mode.
68
-------
TABLE 5.1-6. EFFECT OF STAGED COMBUSTION
Test
No.
40 *
41 *
38*
39*
51*
52*
70 t
71 t
Boiler
Capacity
85%
74%
57%
53%
Burner
Configuration
Upper Right BOOS
Air Reg. Closed
Upper Right BOOS
Air Reg. Opened
Upper Left BOOS
Air Reg. Closed
Upper Left BOOS
Air Reg. Opened
Upper Right BOOS
Air Reg. Closed
Upper Right BOOS
Air Reg. Opened
Upper Left BOOS
Air Reg. Closed
Upper Left BOOS
Air Reg. Opened
Excess
02 f %
1.9
2.2
2.4
2.3
4.9
4.1
4.0
1.6
CO
Dry, ppm
1536
1475
78
1766
35
37
251
2000+
NO
Dry, ppm
361
277
472
269
528
361
456
192
Reduction
%
23%
43%
32%
58%
*Eastern Coal
tWestern Coal
5.1.4 Emissions
Emissions were either reduced or unchanged by the switch to Montana
coal at Alma Unit #3. A summary of the Montana coals average effect on all
emissions measured is given below:
Uncontrolled Particulates
Controlled Particulates
Sulfur Dioxide (S02)
Sulfur Trioxide (SO )
Nitric Oxide (NO)
Nitrogen Dioxide (N02)
26% reduction
71% reduction
67% reduction
Unchanged
18% reduction
Insignificant
Unchanged
Unchanged
Carbon Monoxide (CO)
Unburned Hydrocarbons (HC)
The emissions data is summarized in Table 5.1-7. This is followed by
a discussion of each emissions category. Direct comparisons are made between
the emissions from both fuels, and emissions were related to fuel properties
whenever possible.
69
-------
TABLE 5.1-7. EMISSION DATA SUMMARY, UNIT 3, DAIRYLAND POWER COOPERATIVE, ALMA, WISCONSIN
Test
No.
1
2
3
4
5
6
7
8
9
10
11
13
14
16
17
18
Date
5/29/75
6/2/75
6/3/75
6/3/75
6/4/75
6/5/75
6/6/75
6/9/75
6/10/75
6/11/75
6/11/75
6/18/75
6/19/75
6/23/75
6/24/75
6/24/75
Load
% Capacity
(103lb/hr)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
85
(196)
49
(112)
87
(200)
57
(130)
57
(130)
53
(122)
87
(200)
89
(205)
26
(60)
26
(60)
26
(60)
$
2.9*
3.0
3.6
3.9
3.9
3.5
4.7
2.0
4.0
6.1
4.2
3.1
3.1
12.2
13.0
12.8
^
14.6
14.2
14.4
—
—
--
13.6
13.2
14.6
11.8
—
—
—
7.4
6.5
—
CO
(dry)
ppm
134
—
—
—
—
—
—
—
—
—
—
—
—
—
--
--
HC
(wet)
ppm
—
—
—
—
—
—
—
—
—
--
—
~
—
—
—
—
NO
(dry)
ppm _,
534
590
586
—
—
~
605
574
491
610
—
—
—
611
636
—
ng/J
(lh/106Btu)
203
(0.472)
224
(0.521)
223
(0.518)
—
—
—
230
(0.535)
218
(0.507)
187
(0.434)
232
(0.539)
—
~
—
232
(0.540)
242
(0.562)
--
SO
X
(dry)
ppm
—
—
2805
—
3060
3160
3007
--
3393
~
3932
3343
3563
2602
—
—
ng/J
(lb/,106Btu)
—
—
2273
(5.288)
—
2480
(5.768)
2561
(5.957)
2437
(5.668)
~
2750
(6.396)
—
3187
(7.412)
2709
(6.302)
2888
(6.717)
2109
(4.905)
--
—
so3
(dry)
ppm
—
—
23.6
—
20.7
30.0
20.4
--
286
—
21.5
185
4.6
5.0
—
—
ng/J
(lb/106Btu)
—
--
19.1
(0.044)
—
16.8
(0.034)
24.3
(0.057)
16.5
(0.038)
--
232
(0.539)
—
17.4
(0.041)
150
(0.349)
3.7
(0.009)
4.1
(0.009)
—
—
Fuel
Sulfur
Emitted
»
—
—
~
—
—
101
~
—
94
—
102
—
107
86
—
—
Uncont.
Part.
ng/J
(lb/106Btu)
—
--
--
2207
(5.133)
1978
(4.600)
—
2236
(5.202)
—
3289
(7.649)
—
—
--
—
—
4119
(9.581)
3667
(8.529)
Cont.
Part.
ng/J
(lb/106Btu)
—
—
—
11.61
(0.027)
9.73
(0.023)
—
10.83
(0.025)
—
7.61
(0.018)
—
—
—
~
—
—
18.80
(0.044)
Dust
Coll.
Eff.
%
—
—
—
99.47
99.51
—
99.52
—
99.77
—
—
—
—
—
—
99.49
Comb.
in
Flyash
«
—
—
—
—
3.5
—
~
2.3
5.4
—
—
—
—
—
9.3
10.7
(continued)
-------
TABLE 5.1-7 (continued).
Test
No.
19
20
21
22
23
24
25
26#
27#
33
34
35
37*
38*
39*
40«
Date
6/25/75
6/25/75
6/25/75
6/26/75
6/27/75
6/27/75
6/30/75
6/30/75
6/30/75
7/9/75
7/9/75
7/9/75
7/14/75
7/14/75
7/14/75
7/15/75
% Capacity
(103lb/hr)
26
(60)
26
(60)
26
(60)
54
(125)
55
(127)
55
(127)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
65
(150)
74
(170)
74
(170)
85
(195)
?>
12.3
13.8
10.2
5.0
4.4
3.7
3.8
3.5
3.5
2.4
2.4
2.4
3.1
2.4
2.3
1.9
CO,
7.2
5.6
9.0
13.8
13.9
—
14.6
15.5
15.4
—
—
—
15.1
16.1
16.4
16.3
CO
(dry)
ppm
82
283
36
18
20
--
23
26
20
—
—
—
21
78
1766
1536
HC
(wet)
ppm
—
—
—
—
—
«
—
~
—
—
—
—
30
22
20
25
NO
(dry)
ppm
612
525
596
543
429
—
616
546
509
—
—
—
466
472
269
361
ng/J
(lb/106Btu)
233
(0.541)
i;3
(0.464)
226
(0.527)
206
(0.480)
163
(0.379)
—
234
(0.544)
207
(0.482)
193
(0.450)
—
—
—
177
(0.412)
179
(0.417)
102
(0.238)
137
(0.319)
SOx
(dry)
ppm
—
--
2875
~
—
~
—
—
—
—
--
—
—
—
~
—
ng/J
(lb/106Btu)
—
—
2330
(5.420)
—
—
—
—
—
—
—
~
—
~
—
—
—
so3
(dry)
ppm
--
~
1.9
--
—
--
—
—
—
—
—
—
—
—
—
—
ng/J
UbA06Btu)
—
—
1.5
(0.004)
—
--
--
—
~
—
—
~
—
~
—
—
—
Fuel
Sulfur
Emitted
%
—
—
—
~
—
—
—
~
~
—
"
—
—
—
—
—
Uncont.
Part.
ng/J
(lb/106Btu)
—
—
3705
(8.617)
—
2740
(6.374)
2200
(5.118)
—
—
~
2677
(6.227)
2285
(5.314)
1586
(3.688)
—
—
—
--
Cont.
Part.
ng/J
(lb/106Btu
~
—
14.69
(0.034)
—
7.19
(0.017)
—
—
—
—
—
—
—
—
—
—
--
Oust
Coll-
Eff-
%
—
—
99.60
—
99.74
~
—
—
—
—
—
—
—
—
—
—
Comb.
in
Flyash
%
—
—
4.9
—
3.9
5.2
~
—
—
11.8
8.7
6.9
—
—
—
—
(continued)
-------
TABLE 5.1-7 (continued).
Test
Ho.
41*
42
43t
44t
45t
46t
47
48t
49t
50t
51*
52*
53
54
3LT
4LT
Date
7/15/75
7/16/75
7/16/75
7/17/75
7/17/75
7/18/75
7/21/75
7/21/75
7/22/75
7/22/75
7/23/75
7/23/75
7/23/75
7/24/75
10/15/75
10/29/75
% Capacity
(103lb/hr)
85
(195)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
87
(200)
57
(130)
57
(130)
57
(130)
57
(130)
87
(200)
87
(200)
s»
2.2
2.9
3.2
2.4
3.4
3.5
3.7
3.1
1.8
5.2
4.9
4.1
6.2
3.8
1.7
1.6
co2
15.5
16.1
15.9
15.8
15.0
14.6
15.5
15.8
16.7
13.2
13.5
14.9
12.5
14.9
16.9
16.0
CO
(dry)
ppm
1475
7
14
15
16
17
20
20
570
20
35
37
63
21
0
4000
HC
(wet)
ppm
23
28
22
25
19
24
28
28
34
28
27
17
41
31
—
—
NO
(dry)
ppm
277
579
594
611
687
584
635
542
355
690
528
361
646
505
—
—
ng/J
(lb/10bBtu)
105
(0.245)
220
(0.512)
226
(0.525)
232
(0.607)
261
(0.607)
222
(0.516)
241
(0.561)
206
(0.479)
135
(0.314)
262
(0.610)
201
(0.467)
137
(0.319)
245
(0.571)
192
(0.446)
—
—
SOK
(dry)
ppm
—
._
—
—
.
—
—
3504
3748
3329
2599
ng/J
(lb/106Btu)
„
—
—
—
—
2840
(6.605)
3038
(7.065)
2698
(6.275)
2106
(4.899)
S°3
(dry)
ppm
—
—
—
—
23.6
16.1
28.0
11.3
ng/J
(lb/106Btu)
„
—
—
—
—
19.1
(0.044)
13.0
(0.030)
22.7
(0.053)
9.2
(0.021)
Fuel
Sulfur
Emitted
»
„
__.
— _
95
—
„
—
Uncont.
Part.
ng/J
(lb/106Btu)
...
—
—
—
—
2645
(6.152)
—
2897
(6.739)
Cont.
Part.
ng/J
-------
TABLE 5.1-7 (continued).
Test
No.
56
57A
57B*
58#
59*
60*
61
62
63*
64*
65
66
67
68
70*
71*
Date
8/5/75
8/6/75
8/6/75
8/7/75
8/8/75
8/11/75
8/12/75
8/13/7S
8/14/75
8/15/75
8/18/75
8/19/75
8/20/75
8/21/75
8/25/75
8/25/75
% Capacity
(103lb/hr)
73
(168)
74
(170)
74
(170)
74
(170)
72
(166)
76
(175)
26
(59)
26
(60)
57
(131)
74
(170)
57
(130)
57
(130)
57
(130)
75
(173)
52
(120)
53
(121)
?'
1.9
5.7
4.2
3.9
2.6
2.8
11.8
9.4
2.8
2.9
4.5
3.4
3.5
2.7
4.0
1.6
°>
17.5
13.9
15.7
14.2
16.9
15.8
8.6
9.5
16.4
16.4
14.8
15.7
14.6
16.3
15.4
17.1
CO
(dry)
ppm
2000+
16
27
16
139
163
37
15
126
—
27
31
23
750
251
2000+
HC
(wet)
ppm
30
—
22
—
—
—
—
24
—
39
25
23
23
—
—
MO
(dry)
ppm
339
695
461
560
452
438
675
468
342
409
493
372
410
340
456
192
ng/J
(lb/106Btu>
131
(0.305)
269
(0.625)
178
(0.415)
217
(0.504)
175
(0.407)
169
(0.394)
261
(0.607)
181
(0.421)
132
(0.308)
158
(0.368)
191
(0.444)
144
(0.335)
159
(0.369)
132
(0.306)
176
(0.410)
74
(0.173)
SOX
(dry)
ppm
913
—
1113
878
—
1941
1162
1504
750
963
996
—
874
--
—
ng/J
(lb/10bBtu)
—
754
(1.753)
—
919
(2.137)
725
(1.686)
—
1602
(3.727)
959
(2.231)
1242
(2.888)
619
(1.440)
795
(1.849)
822
(1.912)
~
721
(1.678)
—
—
so3
(dry)
ppm
53.9
—
35.6
14.9
—
9.5
13.8
17.6
1.2
5.7
2.7
—
25.3
—
—
ng/J
(lb/106Btu)
—
44.5
(0.103)
—
29.4
(0.068)
12.3
(0.029)
—
7.8
(0.018)
11.4
(0.026)
14.5
(0.034)
1.0
(0.002)
4.7
(0.011)
2.2
(0.005)
—
20.9
(0.049)
—
--
Fuel
Sulfur
Emitted
*
~
~
—
—
—
—
--
—
74
77
88
—
—
76
—
—
Uncont .
Part.
ng/J
(lb/106Btu)
—
1966
(4.572)
—
1687
(3.923)
—
1161
(2.099)
—
2216
(5.155)
—
—
—
2895
(6.733)
2781
(6.468)
—
—
--
Cont.
Part.
ng/J
(lb/106Btu
—
4.35
(0.010)
—
2.22
(0.005)
—
3.73
(0.009)
5.57
(0.013)
4.07
(0.009)
—
—
—
1.66
(0.004)
2.61
(0.006)
—
—
—
Dust
Coll.
Eff.
%
—
99.78
—
99.87
—
99.68
~
99.82
—
—
—
99.94
99.91
--
—
--
Comb.
in
Flyash
1
—
1.1
—
—
—
—
~
1.9
—
—
—
1.0
—
-
--
—
(continued)
-------
TABLE 5.1-7 (continued).
Test
No.
72
73
74
75
76
78
LT-1
LT-2
Date
8/26/7S
8/27/75
8/28/75
—
—
—
9/17/75
10/1/75
» Capacity
(103lb/hr)
44
(101)
41
(94)
39
(90)
70
(160)
70
(160)
48
(110)
71
(163)
74
(170)
*
6.7
5.0
6.8
5.8
3.8
4.8
1.4
2.3
^
12.9
13.8
12.0
~
~
—
17.4
16.5
CO
(dry)
ppm
11
31
48
—
—
--
7000
0
HC
(wet)
ppm
37
28
27
—
—
—
~
NO
(dry)
ppm
530
386
606
—
—
—
512
ng/J
(lb/10bBtu)
205
(0.477)
149
(0.347)
234
(0.545)
—
~
—
198
(0.461)
SO
X
(dry)
ppm
1243
937
733
712
750
790
906
1067
ng/J
(lb/106Btu)
1026
(2.387)
773
(1.799)
60S
(1.407)
588
(1.367)
619
(1.440)
652
(1.517)
748
(1.740)
881
(2.049)
S°3
(dry)
ppm
6.1
2.3
0.6
4.6
2.8
1.9
26.6
18.5
ng/J
(lb/106Btu)
5.0
(0.012)
1.9
(0.004)
0.5
(0.001)
3.8
(0.009)
2.3
(0.005)
1.6
(0.004)
22.0
(0.051)
15.3
(0.036)
Fuel
Sulfur
Emitted
%
85
98
84
76
86
90
—
Uncont.
Part.
ng/J
(lb/106Btu)
2679
(6.231)
1760
(4.094)
1721
(4.0O3)
--
—
~
2240
(5.211)
2702
(6.284)
Cont-
Part.
ng/J
(lb/106Btu)
3.75
(0.009)
3.01
(0.007)
4.11
(0.010)
—
—
~
2.76
(0.008)
2.33
(0.005)
Dust
Coll.
Eff.
t
99.86
99.83
99.76
—
--
~
99.98
99.91
Comb.
in
Tlyash
%
1.2
1.0
--
—
—
--
~
"
f s Burner air registers varied from normal for test purposes.
f = Burner diffusers varied from normal for test purposes.
* = Burners taken out of service to achieve off-stoichiometric firing.
Eastern Coal Test Numbers 1 - 4LT
Western Coal Test Numbers 56 - LT-2
-------
Particulate Emissions—
Uncontrolled particulates (before ESP) were reduced an average 26%
while controlled particulates (after ESP) were reduced 71% when Montana coal
was burned. These reductions were the result of lower ash in the fuel, reduced
ash carryover in the furnace and increased precipitator efficiency while
burning the Montana coal. Average data for those tests in which both controlled
and uncontrolled particuiates were measured are shown in Table 5.1-8.
TABLE 5.1-8. AVERAGE PARTICULATE AND FUEL ASH DATA
Coal Type
W. Kentucky
Montana
Difference
Particulates
Before ESP
ng/J
2832
2096
-26%
Particulates
After ESP
ng/J
11.49
3.28
-71%
ESP
Efficiency
%
99.59
99.84
+0.25%
Ash In
Fuel
ng/J
6779
5599
-17%
Ash
Carryover
%
42
37
-10%
Uncontrolled particulate emissions are shown in Figure 5.1-5. Although
there is considerable scatter in the data, the average 26% decrease in emissions
is evident. Two-thirds of this decrease can be attributed to lower ash in the
fuel, one-third to reduced ash carryover in the furnace. The noncoking char-
acteristics of the Montana coal may account for the lower ash carryover. Slag-
ging and fouling of the ash may also account for reduced carryover, especially
at higher loads.
Controlled particulate emissions are shown in Figure 5.1-6. Montana
coal emissions after the precipitator were an average 71% lower than Kentucky
coal emissions. This can only be explained as an increase in precipitator
efficiency. This increase in efficiency may have been related to a shift in
75
-------
5000
4000
8 3000
en
w
2000
8
EH
§ 1000
u
o«—^
0 K 20
W. Kentucky Coal
Montana Coal
30 40 50 60 70 80
BOILER DESIGN CAPACITY, percent
90 100
Figure 5.1-5. Uncontrolled particulates vs. boiler load, Dairyland Power
Cooperative Unit 3.
if,
-------
^'25
CP
c
H
CO
cn
H
w
w
E-i
D
O
10
8 o
W. Kentucky Coal
Montana Coal
20 30 40 50 60 70 80
BOILER DESIGN CAPACITY, percent
90
100
Figure 5.1-6. Controlled participate emissions vs. boiler load, Dairyland
Power Cooperative Unit 3.
particle size, or a decrease in fly ash resistivity. There were no discern-
able differences in sulfur trioxide emissions between the two fuels. However,
carbon carryover was about 70% lower while burning the Montana coal. The
combination of these two factors could have affected fly ash resistivity in
favor of the Montana coal.
Sulfur Oxides Emissions—
Sulfur dioxide (SO ) emissions were reduced an average 67% by burning
Montana coal. These emissions were found to be invariant with unit load and
excess oxygen. Sulfur trioxide (S03) emissions were found to be approximately
the same for both fuels, although scatter in the data made it difficult to
assess small differences with any degree of accuracy. Sulfur dioxide is
plotted against boiler load in Figure 5.1-7.
The two most significant findings concerning sulfur emissions are:
(1) the electrostatic precipitator efficiency was not decreased by the lower
sulfur fuel, and (2) a significant portion of the sulfur (11-16%) was retained
in the ash and, therefore, not emitted.
77
-------
TABLE 5.1-9. SULFUR BALANCE SUMMARY, UNIT 3, DAIRYLAND POWER COOPERATIVE, ALMA, WISCONSIN
Test
No.
Percent
of Rated
Capacity
°2
percent
Sulfur in Fuel
Fuel
Sulfur
percent
HHV Fuel
MJ/kg
(Btu/lb)
As SO2
nq/J
(lb/106 Btu)
Sulfur in Ash
Ash
Percent
of Fuel
Sulfur
Percent
of Ash
As SO2
ng/J
(lb/106 Btu)
Retention
percent
Sulfur Emissions
SOX
ng/J
(lb/10 Btu)
Fuel Sulfur
Emitted
percent
W. Kentucky, River King Coal
6
9
16
85
57
26
3.5
4.0
12.2
3.65
4.23
3.26
25 .064
(10,776)
25.064
(10,776)
25.064
(10,776)
2,913
(6.774)
3,375
(7.851)
2,601
(6.050)
16.00
15.96
19.02
—
— -
—
—
—
—
—
—
--
2,561
(5.957)
2,750
(6.396)
2,109
(4.905)
88
81
81
Westmoreland, Montana Coal
63
64
72
73
74
75
76
78
57
74
44
41
39
70
70
48
2.8
2.9
6.7
5.0
6.8
5.8
3.8
4.8
1.90
0.79
1.36
0.86
0.84
0.84
0.79
0.78
22.759
(9,785)
22.024
(9,469)
22.538
(9,690)
21.863
(9,400)
22.024
(9,469)
21.631
(9,300)
21.980
(9,450)
21.608
(9,290)
1,670
(3.883)
717
(1.669)
1,207
(2.807)
787
(1.830)
763
(1.774)
777
(1.806)
719
(1.672)
722
(1.679)
16.31
18.19
12.64
10.67
11.56
11.19
11.36
12.32
—
—
0.83
1.12
1.06
0.96
0.53
0.49
-
—
93
109
(0.254)
111
(0.259)
99
(0.231)
55
(0.127)
56
(0.130)
—
—
7.7
13.9
14.6.
12.8
7.6
7.7
1,242
(2.888)
619
(1.440)
1,026
(2.387)
773
(1.799)
605
(1.407)
588
(1,.367)
619
(1.440)
652
(1.517)
74
86
85
98
79
76
86
90
-J
00
-------
The results of a sulfur balance study are shown in Table 5.1-9. Based
on this study, it was found that only 84% of the fuel sulfur was emitted from
both coals. Approximately 11%, +4% of the retained sulfur, was found in the
fly ash (Montana coal only), while 0.4% was found in the bottom ash (not shown
in the Table) . The difference can be assumed to be errors in fuel analysis
and/or nonrepresentative sampling.
As was found at Fremont Unit 6, discussed in Section 5.10, sulfur reten-
tion may be related to excess oxygen and load. More sulfur appears to be retained
at the higher excess air conditions. Test number 72 is an exception to this
case and more data is required before a definite conclusion can be drawn.
Nitric Oxide Emissions—
Nitric oxide emissions were found to be very sensitive to excess oxygen
and only slightly sensitive to boiler load at Alma Unit #3. At similar load
and excess oxygen conditions, the nitric oxide emissions were 10 to 20% lower
on a higher heating value basis when Montana coal was burned. This reduction
in nitric oxide formation may be partially due to the lower fuel nitrogen of
the Montana coal as shown in the table below.
TABLE 5.1-10. RELATION OF FUEL NITROGEN TO NITRIC OXIDE EMISSIONS
Coal Type
W. Kentucky
Montana
Difference
Fuel Bound
Nitrogen As NO
ng/J
932
720
-23%
Average NO
Emissions
ng/J
221
181
-18%
% Fuel Nitrogen
Conversion*
23.7%
25.1%
—
*Assuming total conversion of fuel-bound nitrogen
79
-------
Cn
K
cn
§
H
X
O
I
to
5000
4000
3000
2000
1000
nA
£ W. Kentucky Coal
O Montana Coal
11
'I
?
• l6
O61
72
74
O63 58
^65 7^S>56«
I 64
20 30 40 50 60 70 80
BOILER DESIGN CAPACITY, percent
90
100
Figure 5.1-7. Sulfur oxides emissions vs. boiler, Dairyland Power Cooperative
Unit 3.
80
-------
Note that for the other pulverized coal unit studied, Fremont Unit 6,
approximately 20% of the fuel bound nitrogen was assumed converted to nitric
oxide for both fuels.
Nitric oxide is plotted against excess oxygen in Figures 5.1-3 and
5.1-4. The pronounced dependence on excess oxygen of this unit compared to
Fremont Unit 6, and the higher average nitric oxide emissions indicate higher
flame temperature. This condition could be rectified by modifying the burners
to lower the flame temperature and, consequently, the emissions. Experiments
with the burners'air registers, diffusers, and with staged combustion to lower
the nitric oxide emissions are described in Section 5.1.3.
Nitrogen dioxide (NO ) was measured but was found in such low concen-
trations, if at all, that it was not included in the emissions data summary.
Generally, less than two parts per million NO was found.
Carbon Monoxide and Hydrocarbon Emissions—
Carbon monoxide emissions increased significantly below 3% excess oxygen
at high loads, and below about 12% excess oxygen at low loads. The former is due
to oxygen starvation and the latter due to premature quenching of the flame. Between
these two extremes, carbon monoxide emissions were found to be insignificant.
Figure 5.1-8 illustrates the oxygen dependence. Boiler load, except for its
relationship to excess oxygen, had no effect on carbon monoxide emissions.
Neither did changing the fuel type.
Hydrocarbon emissions were consistently low in the range of 20 to 40
ppm, dry at 3% O . They did not appear to be a function of either load, exc
oxygen or fuel type. Where measured, they are included in Table 5.1-7.
5.1.5 Boiler Efficiency
Alma Unit #3 experienced a 3.7% loss in boiler efficiency when Montana
coal was burned. Most of this loss was due to moisture in the fuel (3.3%) and
dry gas losses (1.4% at peak loads). The lower combustible loss of the Montana
coal (1.0%) compensated for some of this efficiency loss. Table 5.1-11
summarizes the boiler heat losses for several tests on both fuels.
81
-------
n
T)
a
500
400
300
H 200
X
o
1
o 100
u
High
Load
W. Kentucky Coal
Montana Coal
O
o
•—Q
6 8 10
EXCESS OXYGEN, percent
12
14
16
Figure 5.1-8. Carbon monoxide emissions vs. excess oxygen, Dairyland Power
Cooperative Unit 3.
82
-------
TABLE 5.1-11. BOILER EFFICIENCY SUMMARY, DAIRYLAND POWER COOPERATIVE,
UNIT 3, ALMA, WISCONSIN
Test No.*
Test Load
kg/s
% Capacity
Stack O2 (% Dry)
Stack CO (ppm)
Stack Temp. (°K/°F)
Ambient Air Temp. (°K/°F)
Corr. Stack Temp. (°K/°F)
Boiler Heat Bal. Losses (%)
Dry Gas
Moisture + H-
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency
5
25.3
87
3.0
13.5
443/338
316/109
437/328
6.12
5.16
0.15
0.01
0.63
0.50
87.44
9
16.4
57
3.4
21.0
416/290
321/118
408/275
4.80
5.06
0.12
0.01
0.74
0.76
88.52
17
7.5
26
12.7
108.0
408/275
334/141
393/248
8.24
5.00
0.20
0.09
1.61
1-70
83.15
18
7.5
26
12.6
86.0
411/280
336/146
395/251
8.50
5.01
0.21
0.07
1.94
1.70
82.56
21
7.5
26
10.2
37.0
416/290
334/142
394/249
6.70
5.00
0.16
0.03
0.85
1.65
85.61
57
21.4
74
5.7
16.3
447/346
314/105
439/331
7.49
8.42
0.18
0.01
0.09
0.58
83.23
62
7.5
26
9.4
15.0
429/312
324/124
415/287
7.80
8.28
0.19
0.01
0.13
2.53
81.06
66
16.4
57
3.4
30.5
433/320
311/100
426/308
5.83
8.35
0.14
0.01
0.07
0.76
84.83
72
12.8
44
6.7
11.0
433/320
321/118
420/297
7.26
8.31
0.18
0.01
0.10
0.98
83.17
03
U>
*Test No. 5, 9, 17, 18, 21 are W. Kentucky Coal; Test No. 57, 62, 66, 72 are Montana Coal.
-------
Boiler efficiency variation with load and fuel type is shown
graphically in Figure 5.1-9. At low load (26% capacity) on eastern coal, a
2.5% increase in excess oxygen decreased boiler efficiency by the same amount,
2.5%. The increased heat losses were two-thirds dry gas loss and one-third
combustible loss.
In order to improve the efficiency of western coal burning, the first
order cure would be to pre-dry the coal. In the absence of this technology,
improved heat recovery in the economizer and air heater sections would provide
the most significant improvement. In designing new boilers to burn high
moisture western coals, increased waterwall and/or boiler heating surface
should be considered.
5.1.6 Conclusions and Recommendations
Alma Unit #3 successfully burned a high moisture sub-bituminous coal
without boiler modification. The following advantages and disadvantages can
be listed for such a fuel change:
D i sadvantage s
1. Decreased peak load capacity due to high superheat temperatures.
13% load restriction was experienced with Westmoreland coal.
2. Increased fouling in the superheat section.
3. Anticipated coal handling problems in the winter due to
freezing of the coal.
4. Reduced heat rates due to moisture and dry gas losses.
Advantages
1. Greatly reduced sulfur oxide and particulate emissions.
2. Anticipated savings in fuel costs.
3. Because Dairyland Power is building a new coal fired unit at
Alma, and because this unit will be burning western coal to
meet new source emission requirements, it is advantageous to con-
vert all Alma units to western coal. In this way, all of the
facilities fuel could be delivered by unit train. Unloading
and storage could be centralized. Man-hours in coal handling
could be reduced.
84
-------
90.00
88.00
c
0)
o
M
. 86.00
H
a
84.00
82.00
80.00
3.4% O,
3.0%
10.2% O,
3.4% O
12.7% O, Q'6.7% O,
5.7% 0,
12.6% 0
W. Kentucky Coal
Montana Coal
20 30 40 50 60 70 80 90
BOILER DESIGN CAPACITY, percent
100
Figure 5.1-9. ' Boiler efficiency vs. capacity and coal type, Dairyland
Power Cooperative Unit 3.
85
-------
It would be advantageous to make modifications to Alma Unit #3 if a
permanent change to western coal were anticipated. The most cost effective
modification would be to remove sections of the superheat pendants. This
could effect a reduction in superheat temperature and increase peak load
capability. Improved steam attemperation would also help.
Fouling of the superheat pendants would be reduced by removal of
alternate tube sections. In designing new units for western coals, tube
spacing should be increased in this area, along with increased sootblowing
capability.
REFERENCES FOR SECTION 5.1
1. de Lorenzi, O. (ed.), Combustion Engineering, Combustion Engineering
Company, Inc., p. 7-8, 1947.
86
-------
5.2 UNIROYAL BOILER #2
A series of tests were run on Boiler #2 to determine the feasi-
bility of burning western coal on a multiple-retort underfeed stoker. The
stoker on this unit had a long and unsuccessful history of western coal firing
attempts. Plant personnel agreed to a short series of tests to determine if
the stoker controls could be manipulated in a manner so as to accommodate the
western coal. If a satisfactory firing mode was found, then a complete test
series would be initiated and the whole plant would convert to the cheaper
western coal.
A three day test sequence was run on Boiler #2. A specially ordered
and prepared Wyoming coal was the test fuel. The western coal did not burn
well in the boiler. The fuel bed was nonuniform, thin and not well established.
High grate metal temperatures were recorded with a thermocouple matrix that
was installed in the grate. Visual observations revealed that lower sections
t
of the tuyere plates were completely exposed.
It was found that this type of stoker had inadequate undergrate air
control. For burning a coking and agglomerating eastern type fuel the coal
will self regulate the air flow distributions as the fuel burns. A free
burning western coal, however, requires manual control over the air distri-
bution, which was not available on Boiler #2.
A set of dampers installed beneath the tuyere grate area would per-
mit better control over air distribution and would permit this type of stoker
to fire a western coal.
5.2.1 Introduction
A preliminary series of tests were performed on Boiler #2 at the
Uniroyal Company in Eau Claire, Wisconsin, to determine whether the further
extensive type of test program was warranted. The unit tested at Uniroyal
had a long and unsuccessful history of western coal burning attempts. Economics
and unavailability of eastern type coals had forced Uniroyal personnel into
experimenting with western coals during 1974-1975. Several western coals
87
-------
were tried in the boiler but none were burned successfully. The main
problem common to all western type coals tested by Uniroyal were: inability
to sustain ignition; raw fuel falling into ash pit and burning there; and
insufficient ash protection of the grate area, thus causing sections of the
grate to overheat and melt.
At the time Uniroyal was approached by KVB, Inc. to participate in
this study,the availability problem Uniroyal initially had in obtaining
eastern coal was no longer present. However, there was still some attrac-
tiveness in being able to successfully fire a cheaper western coal as opposed
to their eastern fuels. Through discussions with Uniroyal, it was decided
that due to their previous unsuccessful experience with western coal burning
that a short preliminary study be conducted to determine if a small amount of
specially prepared western coal could be fired in the unit. Two carloads
were ordered. Little space was available for the western coal to be stored,
therefore the test coal was burned directly after being unloaded from train
cars.
The preliminary tests involved personnel from Uniroyal and KVB, Inc.
The purpose was to try and successfully fire the unit with the test batch of
western coal. If this test was successful, then Uniroyal would be willing to
order additional western coal for a more comprehensive evaluation of the coal
burning characteristics. No exhaust gas samples were taken during these
tests. The main effort was aimed at keeping the boiler operating on the
western coal and manipulating boiler control devices in an attempt to define
a successful operating mode. A grate area thermocouple matrix was installed
for the test run. One main concern of Uniroyal about attempting to burn
western coal again, was that on one previous attempt the grate became over-
heated and failed, requiring an unscheduled unit outage and expensive repairs.
Therefore, a grid of thermocouples were installed in the grate and monitored
during the western coal tests.
88
-------
The test burn took place over a three day period. Uniroyal personnel
operated the boiler and KVB representatives observed the tests and made
recommendations. All modes of possible boiler operation were attempted in
an effort to continuously burn the western coal. None proved fruitful.
However, much insight was gained as to why the western coal would not burn in
this type of boiler. In addition, information and observations were made
which suggested changes in this type of boiler which may make it possible to
successfully fire western coal in the future.
5.2.2 Unit Description
Unit #2 tested at the Uniroyal Company Power Plant in Eau Claire,
Wisconsin, is an underfed, multiple retort type boiler. It is fed by a
Westinghouse Continuous Ash Discharge Link Grate Stoker. The tests took
place November 5, 6, and 7, 1976. Figure 5.2-1 shows a side view of the
stoker.
Boiler Description—
The boiler was manufactured by the Babcock and Wilcox Company in 1944.
The Stirling type boiler has three steam drums and a single mud drum. Name-
plate data for the boiler is 16.4 kg/s (130,000 pounds per hour) steam flow
at a design pressure of 1.83 MPa (250 psig) . The steam temperature is at the
saturation temperature.
Combustion air is supplied by a forced draft fan. The unit is balanced
draft and a slightly negative furnace pressure is maintained by an induced
draft fan. The feedwater is preheated by an economizer in the back pass of
the boiler.
The actual day-to-day operating conditions of the boiler have been
reduced due to a retrofitted cyclone type dust collector and limited fan
capacity. Current maximum continuous load for the boiler is about 12.6 kg/s
(100,000 Ib/hr) steam flow at about 1.65 MPa (225 psig) steam pressure.
89
-------
Figure 5.2-1. Multiple retort underfeed stoker with link grate, Uniroyal Boiler 2.
-------
Stoker Description—
The furnace is supplied with coal by a multiple retort type underfed
stoker built by the Westinghouse Corporation. Two conical coal distributors
continuously supply raw coal to the Westinghouse Continuous Ash Discharge Link
Grate Stoker. This stoker has eleven coal chutes or retorts into which raw
fuel is pushed by eleven cylindrical rams. Between the retorts are ten
rows of tuyeres which are plates stacked in a fish-scale-like fashion with
holes in their outer surface through which combustion air is supplied. Figure
5.2-2 shows a reproduction of this type of stoker. The unit #2 stoker has
an inclined grate of about 5.44 m (18 feet) in length. The tuyere section is
3.66 m (12 feet) long. The last 1.83 m (6 feet) are designated as the link grate
section. At this section, combustion of the fuel should be almost completed and
the undulating action of this section of the stoker forces the ash off onto
the discharge end of the stoker and into the ash hopper.
The furnace section of the boiler is refractory lined. Neither the
ram side or the ash discharge side of the stoker has an ignition arch.
Ram injection of the coal into the retorts is determined by the speed
of the steam turbine driven crankshaft. The drive shaft has two speeds to
govern fuel flow. The eleven retort feeding rams are separately attached to the
drive shaft in groups of three, three, three, and two. A clutch type arrange-
ment allows disengagement of sections of the rams to regulate fuel flow to
different sections of the grate.
Combustion air is supplied through the tuyeres and link grate from
below by the forced draft fan. The air is not preheated. A single damper
regulates total air flow to the undergrate air chamber. A second damper in
the undergrate plenum divides air flow between the link grate section of the
stoker and the tuyere section. No other means of air distribution to the
grate air is provided.
91
-------
ISJ
WESTINGHOUSE CONTINUOUS ASH DISCHARGE.
LINK GRATt STOKER
FRO*T WMV. SUPPORTS
Figure 5.2-2. Cross-sectional view of stoker, Uniroyal Boiler 2.
-------
5.2.3 Stoker Operation
Normal Design Conditions—
The Westinghouse Continuous Ash Discharge Link Grate Stoker is in the
class of coal stokers known as the multiple retort underfed type. As the
name underfed implies, fuel is supplied to the stoker from underneath. In
the early development of underfeed stokers, the entire grate was of this type
of fuel feeding configuration; however, design evolution of the underfed type
stoker lead to the inclusion of a back section of grate area that actually is
of an overfed type design. So the current designs might more correctly be
©ailed an underfeed-overfeed type stoker.
During normal operation of the stoker,raw coal is introduced into
each of the eleven retorts at the front face of the furnace by the primary
rams. These rams are cylindrical in shape and are attached to a large drive
shaft on the outside of the boiler. The entire apparatus of cylindrical rams
and drive shaft resemble a large internal combustion engine's crankshaft with
oversized connecting rods and giant pistons. The primary rams feed raw coal
continuously into the deep troughs of the retorts until coal begins spilling
over the upper edges of the chutes and covers the tuyere sections. The coal
over the tuyere section is ignited and combustion is mainly located in lanes
running down the center lines of the tuyere rows. The combustion zones that
follow the tuyere rows down the underfeed section of the grate are often
referred to as burning lanes. Ideally, the burning lanes are well defined
and narrow at the front end of the grate (where coal is initially introduced
into the retorts) and become wider and start to merge into a single active
fuel bed as they reach the end of the underfeed section and flow onto the link
grate area. The retorts are designed so that they are deep at the ram end
of the grate and decrease in depth as they decline towards the link grate
section. At the link grate section, they are designed to essentially act
as an overfed stoker for that area.
93
-------
Normal combustion requires well defined burning lanes in the retort
section of the grate that blend into a uniformly well established single fuel
bed by the time the fuel reaches the link grate section. The main means of
controlling fuel bed contour and movement in the retort section is with
devices called secondary rams. These are pushing or moving sections located
in the bottom plane of the retorts which use a reciprocating motion to help
move the fuel bed forward and downward towards the link grate.
The secondary pushers or auxiliary rams located in the bottom of the
retorts tend to even out the fuel bed as it travels downward. In Uniroyal
boiler #2, each retort had two sets of secondary rams. These secondary
rams are mechanically linked to the primary rams but can be individually
adjusted to contour the fuel bed. Adjusting levers outside the boiler are
provided to shorten or lengthen the individual stroke of each auxiliary ram.
Combustion air for this type of stoker is supplied from underneath
through the tuyere rows and through the extension grate. A single forced draft
fan forces the air into a windbox area under the retort section of the grate,
and from this plenum chamber a single damper permits some air to be diverted
rearward to the link grate area. This damper is split, so there is some
control laterally from side to side on the undergrate section; but, the
primary control is diversion of air to either the retort section or link
grate section.
Burning Western Coals in Multiple-Retort Type Stokers—
The key to successful combustion of western coal in a multiple-retort
underfeed type stoker is control of air distribution to the fuel bed. The
noncoking, noncaking and free burning characteristics of western type coal
demands precise placement of combustion air. The air distribution system
is marginally adequate with coals for which the unit was originally designed.
For western free-burning type coals the undergrate air control is inadequate.
Western coal burns freely, that is to say, each piece of coal will
burn individually and not swell up and form large nonporous coke masses that
are a common characteristic of an eastern type coal. In multiple retort type
stokers, when an eastern type coal is initially introduced into the stoker, it
94
-------
is porous enough to allow air to freely flow through it, thus allowing intimate
mixing of the fuel and air to start combustion. As the coal burns and travels
downward, the eastern coal swells up, cokes, agglomerates and effectively
presents an increasingly nonporous or resistive area for combustion air to
penetrate. Hence, less air flows through the lower portion of the underfed
(or retort) section of the stoker and most of the air continues to find its
way into the inlet end of the coal stoker.
On the Uniroyal stoker, a single damper divides the undergrate air
chamber into two sections, between the retort section and the link grate
area. By the natural properties of coking and agglomerating the eastern coal
self-regulates air distribution in the retort area of the grate. When the
burning fuel bed reaches the link grate, the undulating action of this section
breaks up the coke masses or any coking areas and effectively exposes more
fuel surface area for completion of combustion. Regulation of the damper
between the retort area and link grate plenum permits fairly adequate control
of air into the link grate chamber. With eastern coal, one can adjust the
damper to permit the appropriate amount of air into this section to complete
final combustion.
Western coal burning on the Uniroyal multiple-retort underfeed type
stoker presents a more difficult situation due to the nature of western coal
burning properties and lack of sufficient air distribution control. As
western coal enters the stoker, it is coarse and of sufficient porosity to
permit the air to come in contact with the coal and begin combustion. However,
as the coal burns, it does not form a nonporous mass of air resisting material.
This is due to the free burning and nonagglomerating properties of western
coal. This results in a fuel bed that as it moves towards the link grate is
increasing in porosity and decreasing in resistance to air flow.
On this boiler the only way to control the western coal firing would
be by increasing the control over the air distribution. Two air control
modes are required. The first would be longitudinally, up and down the
firing lanes. The second would be laterally or across the width of the
stoker.
95
-------
5.2.4 Test Series
Overview—
The test firing of western coal in Boiler #2 took place over a period
of three days, November 5, 6, and 7, 1975. The boiler initially was fired
on 100% eastern coal on November 5, and preliminary data and observations were
made at that time. Data from the thermocouple grid was also taken at this
normal operating configuration for comparison with western coal readings.
Table 5.2-1 presents a comparison of the two coals that were test
fired in Boiler #2. The eastern coal was from West Kentucky and had a sulfur
content of 2.5% and a higher heating value of about 28.8 MJ/kg (12,400 Btu/lb)
as received. The western coal came from the Bighorn mine in Wyoming. It
had been specifically ordered for these tests and had been carefully sized
so that most of the fuel was 1-1/2 by 1 inch stoker coal. The fuel was also
oil-treated to prevent dusting and help any fines in the coal adhere to the
larger pieces. The western coal had a sulfur content of 0.61% and a higher
heating value of 22.1 MJ/kg (9,500 Btu/lb) as received.
The switch over from 100% eastern coal and normal operation to
western coal and modified operation occurred on November 6, 1976. On the
previous day, the coal bunker had been allowed to burn down and, beginning
in the early hours of the 6th, western coal was fed into Boiler #2 bunker.
By morning, western coal began to reach the conical distributors and, by
late morning, western coal was being fired in the stoker.
The remainder of November 6 was spent trying to maintain an acceptable
fire on the stoker of Boiler #2 with 100% western coal. As long as the unit
load demand remained somewhat steady, a marginally acceptable fuel bed was
obtained. Unfortunately, Boiler #2 is used in a process plant where
large fluctuations in load are present. Every time a load swing occurred,
the marginal fuel bed would become unacceptable, and personnel would spend
time trying to compensate for the changing conditions, only to have them
change again once the initial correction was instituted.
96
-------
TABLE 5.2-1.
CHARACTERISTICS OF COALS FIRED IN UNIROYAL BOILER #2
Source
Type and Size
Preparation
% Moisture
% Ash
% Volatiles
% Fixed Carbon
HHV As Received MJ/kg
% Sulfur
Hardgrove Grindability
% Carbon
% Hydrogen
% Nitrogen
% Chlorine
Ash Fusion Temp H=W
% Oxygen
BASE COAL - EASTERN
West Kentucky, Seam #9
1 1/4 x 1/4 Straight Run
Stoker
Double Screened, Washed, No
Fines
PROXIMATE ANALYSIS*
6.0 - 9.0
7.0 -11.0
37.0
40.0
28.4
2.5
65
ULTIMATE ANALYSIS"1"
68.21
4.81
1.26
<0.01
1440 °K (2133 °F)
8.46
TEST COAL - WESTERN
Wyoming - Bighorn
11/2x1 Stoker
Oil Treated
PROXIMATE ANALYSIS*
23.85
5.3
32.36
38.49
22.1
0.61
—
ULTIMATE ANALYSIS"1"
57.37
4.07
1.01
<0.01
1427 °K (2110 °F)
11.41
* Proximate Analyses were obtained from Uniroyal personnel
+ Ultimate Analyses obtained from coals delivered to University of
Wisconsin by same supplier as Uniroyal
Note: Table 5.2-1 is a comparison of the Eastern and Western coals which were
used in the testing of Unit #2 at Uniroyal. Because the testing was of a much
shorter duration then had been anticipated, and was, in fact, designed to determine
whether it would be possible to undertake a full test program at this site, no
coal samples were obtained. The data in Table 5.2-1 has, therefore, been obtained
in part from Uniroyal personnel and, in part, from analysis of coal samples taken
at the University of Wisconsin, Eau Claire, and the University of Wisconsin, Stout.
We feel confident in using the ultimate analysis of the coals sampled
at the University of Wisconsin, Eau Claire and Stout facilities, as these tests
were run during the same time frame and the coal was supplied to all three units
by the same supplier, from the same stockpile.
97
-------
Sometime during the period between the evening of the 6th and the
morning of the 7th some eastern coal was inadvertently dumped into the bunker
containing the western coal. Much of the morning was spent trying to contend
with this situation. It became apparent that a blend of eastern and western
coals did not work well together on this type of stoker.
The afternoon of the 7th resulted in the boiler marginally firing
100% western fuel again. The test personnel continued to vary operating
parameters the remainder of the day in order to improve the western coal
combustion. No successful firing mode was ever established. By the end of
the 7th, eastern coal again began to enter the stoker, all the western coal
had been consumed.
Thermocouple Configuration—
Boiler operators and Uniroyal personnel were especially concerned
with stoker grate metal temperatures. A previous attempt to fire western
coal on their underfeed stoker resulted in the overheating and failure of the
grate around the link grate area. To help control and measure the grate
temperatures, a twelve point thermocouple (T/C) matrix was installed in the grate
area before the tests began. There, thermocouples were monitored during the
tests and the data obtained is presented in this section.
Figure 5.2-3 presents a plan view of the thermocouple matrix configu-
ration. The first four T/C's were installed in the link grate area and the
remaining eight T/C's were placed in the tuyere area of the stoker. Figure
5.2-4 shows a detailed side view of the thermocouple installation. Figure
5.2-5 presents an even more detailed sketch of the T/C orientation in the
tuyere plate area of the grate. The thermocouples were all installed as close
to the surface of the grate area metal as possible so that true metal tempera-
tures could be obtained.
Table 5.2-2 present the data obtained from the thermocouple grid during
the course of the test sequence. Tests 1 to 5 show readings obtained during
normal operation of Boiler #2 while firing the West Kentucky eastern coal. As
can be seen, most areas on the tuyere sections are cool indicating a well
98
-------
w
co
X-/
o
v^i
VX
j y
-20'
-
Is
3.66 m
(12')
1.83 m
(61)
Figure 5.2-3. Orientation of thermocouples on grate, Uniroyal Boiler 2.
99
-------
o
o
Figure 5.2-4. Detailed view of thermocouple installation, Uniroyal Boiler 2,
-------
mnnnnnnnnnnnnn
Figure 5.2-5.
Detail of tuyere plate with orientation of thermocouple probe,
Uniroyal Boiler 2.
101
-------
TABLE 5.2-2. THERMOCOUPLE READINGS OF GRATE METAL TEMPERATURES
AT UNIROYAL BOILER #2, EAU CLAIRE, WISCONSIN
Test
No.
Load
Coal (10 Ib/hr)
Date
Time
Comments
Grate Location Temperatures, °K
2 3 -1567
(see Figure
8 9
5.2-3)
10
11 12
O
NJ
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
East
East
East
East
East
switch
Over
Switch
Over
Switch
Over
West
west
West
West
West
West
West
West
West
West
West
3.15
(25)
6.30
(50)
8.19
(65)
8.19
(65)
6.30
(50)
6.93
(55)
6.93
(55)
5.04
(40)
7.56
(60)
8.19
(65)
8.19
(65)
5.67
(45)
8.19
(65)
5.69
(45)
6.93
(55)
8.19
(65)
5.67
(45)
6.30
(SO)
6.93
(55)
11/5/75 10:15 No FO fan 710
11/5/75 10:55 FD fan on, normal operation 744
11/5/75 11:30 FD fan on, normal operation 666
11/5/75 1:15 FD fan on, normal operation 661
11/5/75 3:10 FD fan on, normal operation 722
11/6/75 9:08 Western coal on west side for 40 min. 550
11/6/75 10:00 All western coal in tuyere area 589
11/6/75 11:00 All western coal except for last foot 522
11/6/75 12:45 Tuyeres visible at lower edge 755
11/6/75 1:10 All western coal 733
11/6/75 1:53 All western coal 689
11/6/75 2:30 All western coal 666
11/6/75 4:20 All western coal 700
11/7/75 8:30 Poor fuel bed, dark zones 425
11/7/75 9:07 Mixed fuel 536
11/7/75 11:20 Fire lanes better defined 505
11/7/75 1:00 Grate surface visible 639
11/7/75 1:30 Fire lanes well defined but dark 644
11/7/75 2:30 Fire lanes improved but still dark 683
488 600 533 316 322 339 327 461 455 400 389
591 658 522 311 311 316 316 472 389 383 372
611 672 544 314 311 311 311 566 422 455 394
572 705 566 322 322 322 311 422 405 339 339
477 664 533 322 311 316 325 394 400 389 389
477 436 444 300 327 383 316 327 333 311 316
533 380 611 300 308 336 305 455 405 300 300
480 558 616 386 339 322 325 680 558 322 466
616 502 550 439 455 330 500 605 544 550 522
677 561 658 464 461 386 739 694 555 625 525
627 391 569 414 436 597 511 536 541 744 497
691 544 700 600 516 614 564 633 658 880 572
689 766 761 750 689 661 616 772 811 933 763
772 625 600 647 566 655 647 758 747 739 711
772 622 608 652 577 669 669 761 750 769 755
422 577 602 515 564 677 733 725 733 855 794
383 339 677 527 544 633 672 689 722 800 733
511 350 677 566 533 608 664 561 705 766 727
411 411 689 500 500 577 577 380 708 758 716
-------
covered and protected grate. In the link grate area where combustion is
fully developed and completed during.normal operation, temperatures are
somewhat higher. Still, overall metal temperatures are well below 755 °K
(900 °F) which is considered a starting point for oxidation of the grate
metal.
Tests 6, 7, and 8 present the readings obtained during the switch
over from 100% eastern coal to 100% western coal from Bighorn, Wyoming. The
western coal is first "seen" on the west-side of the boiler (or left side of
plan view). This is noted by a rise in west side T/C readings on the upper
tuyere plate T/C's. Test 8 has the grate almost completely covered by
western coal except for the last foot or so of link grate. Temperatures are
beginning to rise over the entire T/C matrixed area.
Tests 9 through 13 present thermocouple data from 100% western coal
firing in Boiler #2 during November 6, 1975. All grate area metal tempera-
tures are elevated above normal readings for eastern coal. Temperatures
especially on the tuyere area are higher than normal. Temperatures in excess
of 755 °K (900 °F) are noted in several areas. Sections of tuyeres are
visible in lower areas of grate sections when one viewed the fuel bed during
actual firing of coal.
November 7, 1975, thermocouple data is presented in Tests 14 through
19. Test 15 shows the grate area metal temperatures during the mix-up in
eastern and western coal supplies. Temperatures continue to be excessively
high contributing to oxidation and fatigue of grate metal. The last test,
19, shows eastern coal beginning to come down the stoker as seen by lowering
of grate area temperatures at position #9.
In summary, grate area metal temperatures were significantly increased
when the fuel was switched from eastern coal to western coal. The increase
was caused by either lack of coverage of the metal by coal and ash or by the
uneven and intense combustion in certain zones. Operators were unable to
correct this situation with the available operating controls. A few weeks
after the burning of the western coal, the weakened tuyere section of the
103
-------
grate which exhibited the excessively high temperatures failed and had to be
replaced. Much overheating and metal oxidation damage was observed during
the unscheduled outage. The damaged area included all the lower set of tuyere
plates and the adjoining side plates that formed the retort chutes. The
damaged areas occurred all across the bottom section of tuyeres and were not
confined to the middle section or ends. The damaged zones corresponded to
high temperature areas noted on the T/C grid and also to the zones of exposed
tuyeres that could be observed visually through view ports at the back section
of Boiler #2.
5.2.5 Results and Conclusions
Boiler #2 is equipped with an underfeed multiple-retort type stoker.
This stoker was designed to burn an eastern type coal which cokes, agglomer-
ates and cakes. Marginal undergrate air control is provided by means of
a single air damper which effectively divides the air plenum into a tuyere
section and a link grate section. With eastern coal burning, the fuel bed
thickens and becomes more nonporous (and more resistive to air flow) as it
travels downwards through the stoker. This is because the eastern coal
swells-up and pieces stick together when the fuel burns and cokes. This
"natural" self regulation of air distribution permits successful firing of
eastern coal in this type of stoker.
A series of preliminary tests were performed on Boiler #2 to devise
a firing mode to permit burning of a western coal on this type of stoker.
Boiler #2 could not burn western coal successfully. Without sufficient under
grate air control, burning western coal is difficult on an underfeed stoker.
Western coal does not swell-up and form a nonporous mass when it burns.
Instead, western coal is classified as free-burning, that is, each individual
piece of coal will tend to retain its individual identity through the combus-
tion process. This property of the fuel causes the fuel bed to become
increasingly porous as it moves down the stoker. The more porous it becomes,
the less resistive it is to air flow. This causes air to be diverted to
lower regions of the stoker thus starving the inlet regions where more air
104
-------
is required. Without dampers or baffles underneath the grate in the air
plenum to prevent this, the air will flow to the lower sections of the
stoker. This extra air causes nonuniform combustion, unstable fires and
overheating of the lower sections of the tuyere grate. In an extreme case,
the grate may become uncovered and unprotected from radiation. The data
gathered indicate that it may overheat enough to reach the oxidation point
where there is the possibility of grate failure.
To fire western coal on a multiple-retort underfeed stoker requires
more control of undergrate air distribution. A series of laterally arranged
air dampers would help. Also, provision for biasing air up and down the
stoker length would improve performance; although it would not be as important
as being able to control air from inlet zones to lower tuyere zones.
105
-------
5.3 UNIVERSITY OF WISCONSIN, STOUT
The third test site was at the University of Wisconsin, Stout, at
Menomonie, Wisconsin. The boiler tested was Unit #2 of the Central Heating
Plant on the university campus. This boiler supplied all the steam heating
for the camput facilities but did not generate any power.
The test crew arrived at the test location on September 8, 1975,
and prepared the sampling plan and test site for testing which began on
September 10, 1975. Initial tests were run to determine temperature and
pressure distributions in the sampling duct from which velocity determina-
tions were to be made. Also, preliminary gaseous emission surveys were
performed to determine if any stratifications existed within the exhaust
duct. After the site set-up and preliminary flue gas measurements, actual
testing began on September 12, 1975, and continued through November 7, 1975.
A total of 36 tests were performed, 20 on western coal and 16 on eastern
coal.
5.3.1 Boiler Description
The UW Stout boiler was manufactured in 1964 by the Wickes Boiler
Company. The boiler supplies saturated steam for the university's steam
heating/cooling system. This boiler is rated at 5.7 kg/s (45,000 Ib/hr) steam
flow. Actual operation of the boiler rates the unit at a 5 kg/s (40,000 Ib/hr)
steam maximum on a good eastern coal. Maximum steam pressure is 1.2 MPa
2 2
(160 psig). Total boiler heating surface is 473.5 m (5,097 ft ). The water
2 2
wall heating surface is 51.5 m (554 ft ). The boiler does not have an air
preheater, and combustion air is supplied by a single forced draft fan from
below the boiler. A second, smaller fan supplies air for overfire air above
the grate area. Although the furnace is forced draft it is kept at a slightly
negative pressure '^ -0.25 cm HO (^ -0.10 in. HO) by manipulation and adjust-
ment of the furnace outlet damper. Natural draft is provided by the boiler's
tall smokestack. The boiler does not have a superheater or economizer. Flue
gas passes out of the furnace and through a cinder trap which removes some of
the larger particles of dust. Remaining particles settle out by gravity as
the exhaust gases flow through a long horizontal duct before exiting the
smokestack for dispersion into the atmosphere.
106
-------
5.3.2 Stoker Description
Stout Unit #2 represents a boiler class in the lower size range of
interest of the EPA study and also is a boiler of interesting firing type.
Stout #2 is fired by a vibragrate stoker manufactured by the Detroit Stoker
Company of Monroe, Michigan, as illustrated in Figures 5.3-1 and 5.3-2.
OverfireAir Coal
Hopper
Grate
Tuyere
Blocks
Coal
Gate
Air Control Dampers Flexing Plates Vibration Generator
Figure 5.3-1- Water-cooled vibrating grate stoker.
Coal is conveyed from an underground storage bunker at the central
heating plant via an enclosed conveyor belt and is dumped into a distributor
above the stoker. From the distributor, coal is fed by gravity downward onto
the grate area. Fuel bed thickness is regulated by an adjustable guillotine
gate. Bed thickness is maintained at about 12.7 cm (5 in.). The grate area
is horizontally inclined and is attached from below to a vibration generator.
The grate is water-cooled by connection to the main boiler water circulation
to prevent overheating. The vibration generator causes the entire grate area
107
-------
Figure 5.3-2. Front view section showing water-cooled grate.
108
-------
to be agitated. The period and length of vibration can be adjusted. As load
increases the period is shortened while the duration of vibration time is
increased. The combination of'vibrating grate area and gravity cause the fuel
bed to travel downward from the coal inlet to the ash discharge end of the
grate.
As coal enters the stoker, ignition is achieved by radiant energy
reflected from the established fire via a short ignition arch. Combustion
air is regulated from below by a series of undergrate air dampers. This
stoker had five dampers and each was individually adjustable. Each damper
controlled a zone that extended laterally across the stoker grate width.
Additionally, air for completion of suspension burning was supplied by the
overfire air ports located on the front wall. An adjustable ash dam plate
retards ash discharge until combustion is complete. This also can help
regulate fuel bed thickness although this is mainly determined by the fuel
gate (guillotine) setting at the inlet side of the stoker. Several viewing
ports are available along the length of the grate on both sides. The condi-
tion of the fuel bed can be observed and approximate adjustments in bed
thickness or grate vibration duration and cycle time can be made as necessary.
Ash dumped'off the grate is stored in a dry condition in hoppers
below the boiler and is pneumatically removed periodically during the day.
5.3.3 Sample Site Location
Since Stout #2 did not have a dust collection device, only
boiler outlet emissions were measured. After the flue gases exited the
boiler, they made a horizontal pass through a long section of flue before
beginning the final pass up and out of the chimney. Five sampling ports
were placed in this long section of horizontal duct. The bottom sampling
probe was completely covered with settled-out flyash which the test crew and
plant personnel were unable to remove, hence only the top four ports were
used for sampling. At each of the remaining four ports, three gaseous data
collection probes were installed. One probe was placed at the centroid of
109
-------
equal areas of the duct. Each probe was of corrosion resistant 316 stain-
less steel and each probe inlet was fitted with a ten micron sintered stain-
less steel filter to prevent introduction of flyash into the gaseous sampling
system. High temperature, inert, Type T, 9.5 mm (3/8 in.) nylon tubing
connected each probe with the self-contained mobile test lab located just
outside the central heating plant. Additionally, a heated Teflon sample
line was strung from the mobile laboratory to the duct sampling location
to enable measurement of hydrocarbons and the NO component of NO .
£, X
Particulate sampling trains were carried to the sampling location
and set up. A special cantilevered beam was hung to allow support for the
Joy Manufacturing Company particulate sampling box during particulate tests.
Also, a special support was built to handle the Shell-Emeryville SO samp]-
X
ing system which was used at the sample duct.
5.3-4 Comparison of Test Coals
Two different test coals were fired in the Stout #2 boiler. The
first was a western low-sulfur coal from Bighorn, Wyoming. The second fuel
tested was an eastern high-sulfur coal from West Kentucky. The two fuels
are compared in Table 5.3-1.
5.3.5 Eastern Coal Burning on Vibragrate Stoker
A. Normal Stoker Operation—
Stout Boiler #2 was designed and built to burn a high Btu bituminous
type coal. For this study, the previously defined eastern coal was from West
Kentucky and had an average high heating value of 28.7 MJ/kg (12,340 Btu/lb).
The coal was coarse and did not have over 30% fines. Normal combustion on
the vibrating grate stoker is as follows:
Coal enters the inlet edge of the stoker through an adjustable guil-
lotine gate. This gate height determines the depth of the fuel bed. For
eastern coal this gate height or bed thickness is set at 10.16 cm (4 in.).
Heat from the furnace radiates and re-radiates under the ignition arch at the
inlet end of the stoker and ignites the raw coal. West Kentucky coal ignites
well up into the arch and near to the gate. By the time the coal travels out
110
-------
TABLE 5.3-1. COMPARISON OF TEST COALS FIRED AT STOUT BOILER #2
FUEL: Western Coal
LOCATION: Kleenburn, Wyoming
MINE: Big Horn
Eastern Coal
Marlesville, W. Kentucky
Vogue, Seam #11
TEST
% Moisture
% Ash
% Volatile
% Fixed Carbon
MJ/kg
Btu/lb
% Sulfur
TEST
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Proximate
Western Coal
17.80 18.43
4.68 7.06
34.19 32.82
43.33 41.69
24.1 23.0
10378 9907
0.83 1.23
Ultimate
Western Coal
As Reed Dry
21.53 xx
56.76 72.33
4.13 5.26
0.91 1.15
0.01 0.01
0.83 1.06
3.92 5.00
Oxygen (by diff) 11.91 15.18
Analyses
Eastern Coal
9.02 9.47
7.11 7.50
34.39 33.95
49.48 57.13
28.0 28.0
12028 12018
3.41 2.60
Analyses
Eastern Coal
As Reed Dry
4.49 xx
71.36 74.71
5.03 5.27
1.28 1.34
0.00 0.00
2.81 2.94
7.25 7.59
7.78 8.15
Mineral Analyses of Ash
Western
P205 0.59
Si02 29.82
Fe2o3 8.18
A1203 16.42
Ti02 1.05
CaO 17.15
% Pyrites
% Sulfate
% Organic
% Total Sulfur
Eastern
0.11 MgO
45.77 SO
25.81 K20
20.25 Na20
1.17 Undeter
1.50
Sulfur
Western Coal
As Reed Dry
0.11 0.14
0.02 0.03
0.70 0.89
0.83 1.06
Western Eastern
4.80 0.78
17.48 1.30
0.68 2.23
2.98 0.38
0.85 0.70
Forms
Eastern Coal
As Reed Dry
1.39 1.46
0.06 0.06
1.36 1.42
2.81 2.94
Fusion Temperature of Ash
Western Coal
Reducing Oxidizing
°K (°F) »K (CF)
Eastern Coal
Reducing Oxidizing
oy /OEM °v f°isM
j\. \ t ) f^ \ * 1
Initial Deform. 1416 (2090) 1458 (2165)
Softening (H-W) 1430 (2115) 1469 (2185)
Softening (H-l/2 W) 1447 (2145) 1480 (2205)
Fluid 1461 (2170) 1491 (2225)
1405 (2070) 1610 (2440)
1466 (2180) 1644 (2500)
1521 (2280) 1671 (2550)
1577 (2380) 1697 (2595)
111
-------
of the covering of the arch, combustion is well established. The grate is at
an inclination to the horizontal and is attached from beneath to a vibration
generator. By a combination of gravity and the shaking motion of the grate,
the fuel bed moves slowly down the stoker. For eastern fuels, the length of
time between vibrating periods is somewhat longer than for western coals and
the duration of the shaking is generally shorter. The active burning length
of the fuel bed using eastern coal does not extend as far along the stoker
length as western coal.
Undergrate air dampers have a definite pattern when firing West
Kentucky coal. Usually, most of the air is introduced into the second and
third air zones when firing eastern coals. The first zone is closed and the
last two zones (4 and 5) are opened somewhat. The flames are usually heavy
and contain more orange color than a similar western coal fire. The fuel
bed will also coke and swell. Clinkers may form from time to time and must
be removed with a hand rake. Generally, combustion is completed well before
the ash dam discharge end of the stoker is reached.
B. Eastern Coal Firing Exhaust Gas Emissions—
Table 5.3-2 contains a summary of the measured emissions for Stout
#2 on both western and eastern coal.
Figure 5.3-3 presents the as-found excess oxygen versus boiler load
characteristics for Stout #2. The excess O tends to decrease with increas-
ing load as expected. Also shown is the maximum load obtained on the unit
with eastern coal. The maximum load obtainable on the West Kentucky coal
was 5.5 kg/s (44,000 Ib/hr) steam flow at an excess 0 reading of 4.7%.
Carbon monoxide emissions were high at this point and averaged 1120 ppm at
3.0% O across the flue gas duct. Maximum load was determined by the inabil-
ity to maintain a clear stack and by excessive CO emissions. Essentially,
the natural draft of the furnace limited an increase in load since furnace
pressure was becoming difficult to maintain. Additionally, heavy smoke would
appear during grate vibration.
112
-------
TABLE 5.3-2. EMISSION DATA SUMMARY, UNIVERSITY OF WISCONSIN* STOUT BOILER #2
Test
No.
Date
1975
Load
kg/s|dO3lb/hr
o2(%)
CO
(ppm)
co2
(%)
NO (dry)
(ppm)
NO (wet)
(ppm)
%
Combust.
Particulates
(ng/J)|(lb/MBtu)
r
S°x
(ppm)
*•
SO
X
(ng/J)|0.b/.MBtu)
1
Fuel S
(ng/J)Klb/MBtii.)
1
Sulfur
Retention
Factor, %
WESTERN COAL
]
2
3
4
6
•j
a
g
10
11
12
13
14
15
16
17
34
35
36
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
9/12
9/15
9/16
9/17
9/18
9/19
Q/-yj
y/ ££
9/23
Q/?d
»/ ^«l
9/25
9/26
9/29
9/30
10/1
10/2
10/3
10/6
11/4
11/5
11/7
10/8
10/9
10/10
10/13
10/14
10/15
10/16
10/17
10/17
10/20
10/21
10/22
10/23
10/28
10/29
10/30
2.46
2.71
2.27
2.14
21 *
- X4
2.18
1. 03
3.28
1. 89
3.34
4.16
3.21
3.21
3.15
4.47
1.95
2.01
3.50
3.78
3.72
1.89
1.89
2.52
1.89
1.89
1.89
3.02
5.04
1.89
3.03
2.27
2.64
1.76
5.54
5.54
3.78
19.5
21.5
18. 0
17.0
1 "7 O
i. / - U
17.3
i 7 n
x / . u
26.0
1C ft
J.3 . V
26.5
33.0
25.5
25.5
25.0
35.5
15.5
16.0
30.0
30.0
29.5
15.0
15.0
20.0
15.0
15.0
15.0
24.0
40.0
15.0
24.0
18.0
21.0
14.0
44.0
44.0
30.0
7.8
6.4
6.7
9.4
9Q
. O
9.7
7-5
• J
6.9
6c •
• 3
7.5
4.5
5.2
5.7
9.3
7.5
7.9
8.7
7.8
7.8
6.3
10. 2
9.9
8.2
10.5
10.3
9.0
8.0
5.4
9.5
11.5
10.2
8.8
10.5
4.7
4.7
8.2
30.
36.7
30.6
25.
•Jrt
JU*
47.5
1 A
14 •
41.
—
—
111.
84.
30.
94.
18.
108.
2000+
2000+
2000+
38.
32.
48.
36.
42.
31.
18.
~
—
295.
~
—
54.
1120.
—
23.
12.
12.9
12.6
10.4
9*7
» /
9.6
UA
• 4
12.5
, 1 5 Q
J.Z* y
11.9
14.2
13.9
13.4
9.9
11.9
11.1
10.6
11.1
10.6
11.5
8. 75
8.9
10.6
8.6
~
10.5
--
—
—
10.2
9.0
10.2
8.5
14.0
—
11.0
141
179
1 Q-5
i.7A
168
160
1 A -a
143
176
160
146
163
192
176
197
206
156
158
143
206
201
187
222
195
173
195
221
211
211
214
219
237
185
187
148
156
197
205
203
204
221
229
223
236
232
228
—
—
...
—
—
—
—
—
45.5
—
17.3
—
~
48.5
43.9
—
—
EASTERN COl
—
—
~
—
—
—
—
~
—
—
—
51.6
—
45.8
44.4
~^""
301.9
202.0
190.7
242.5
310.4
125.
97.3
tL
176.
175.
146.
457.
—
220.
441.
276
0.702
0.4697
0.4434
0.564
0.7218
0.2908
0.2263
0.4096
-,-
0.4073
0.3385
—
1.0635
—
0.5118
1.0349
O.6412
658
485
525
650
485
513
687
833
476
683
606
709
2258
2304
2308
2550
2447
2532
1804
2416
2441
2578
2325
—
—
559
412
446
553
412
436
584
708
405
581
515
603
1919
1958
1962
2167
2105
2152
1533
2054
2075
2191
1976
—
—
—
1.3
0.96
1.04
—
1.285
—
0.959
—
1.014
1.358
1.647
0.941
—
1.35
1.198
1.402
4.46
4.55
--
4.56
—
5.04
4.9
5.01
3.57
4.78
4.83
5.10
4.60
~
—
688
722
1066
671
2438
1860
1862
—
—
1.6
— :
—
—
1.68
2.48
1.56
5.67
-i_
4.326
4.331
—
~
~
—
76.3
—
—
—
—
—
—
80.8
66.4
—
—
—
—
90.
78.7
—
—
—
—
—
—
—
82.
—
—
—
105.8
—
—
-------
11
10
-p
£ 8
0
M
0)
>H
X
o
CO
co
H
Rated capacity = 5.7 kg/s (45,000 Ib/hr) steam
37
47 57 67 77
PERCENT OF RATED CAPACITY
87
97
Figure 5.3-3. Load vs. excess oxygen, as-found operation, stout
Boiler 2, West Kentucky coal.
114
-------
Sulfur oxides and particulate data were obtained at this maximum load
of 5.5 kg/s (44,000 Ib/hr) steam flow. Total sulfur oxides measured were
2325 ppm at 3.0% excess 0 . SO, was about 1.0% of the total SO measured.
^ o x
Particulates taken at maximum load were measured at 441 ng/J (1.0349 Ib/MBtu).
NO and NO at maximum load were 185 ppm and 232 ppm at 3.0% 0
x 2
respectively. Some hydrocarbons were measured at about 15 ppm at 3.0% 0 .
Figure 5.3-4 presents the as-found SO emissions for Stout #2 versus
X
load for normal operation. Table 5.3-3 presents the summary of all SO data
taken on West Kentucky coal. Emissions based on the fuel analysis of an
average fuel sulfur content of 2.94% S and higher heating value of 29 MJ/kg
(12,975 Btu/lb) would yield 2110 ppm.
Figure 5.3-5 presents the SO emissions as a function of excess
X
oxygen for various boiler loads. No particular trend seems to be present
with either load or excess O .
Figure 5.3-6 presents the NO emissions for Stout #2 as a function
of load for the as-found normal operating conditions. The emissions appear
to be quite constant with load. The average value of NO is 197 ppm at 3.0%
excess O in the as-found condition. Figure 5.3-7 presents the variation of
£t
NO emissions with excess oxygen level at various loads. NO formation shows
a definite dependency on excess oxygen level at all loads. The curves show
NO increasing sharply with small changes in excess oxygen.
Figure 5.3-8 presents the carbon monoxide emissions over the stout #2
load range in the as-found condition. CO emissions were generally quite low
(less than 100 ppm) except for the maximum load point of 5.5 kg/s (44,000
Ib/hr) steam flow. Figure 5.3-9 presents the CO emissions as a function of
excess oxygen at various loads. At the excess air levels tested, the CO
emissions remained quite low except for the previously mentioned maximum
load point.
115
-------
2600
2500
CN
O
* 2400
+J
fl
a
a 2300
B.
U)
Q
0 2200
D
W 2100
>
1 1 1 1 1 1
24 Q
o25 ~
o29
— —
31
O
19
0
o33
PHBVM ^^^
Rated capacity = 5.7 kg/s (45,000 Ib/hr) steam
nU 1 1 1 1 1 1
37 47 57 67 77
PERCENT OF RATED LOAD
87
97
Figure 5.3-4. Load vs. SOX emissions, as-found operation, Stout
Boiler 2, West Kentucky coal.
116
-------
TABLE 5.3-3.
DATA SUMMARY, UNIVERSITY OF WISCONSIN, STOUT BOILER #2, WEST KENTUCKY COAL
Test
NO.
19A
19B
19C
20A
2 OB
20C
22A
22B
22C
27A
27B
27C
28A
2SB
28C
29A
29B
29C
31A
31B
31C
33A
33B
33C
Lc
kq/s
1.9
1.9
1.9
2.5
2.5
2.5
1.9
1.9
1.9
3.0
3.0
3.0
2.3
2.3
2.3
2.7
2.7
2.7
5.5
5.5
5.5
3.8
3.8
3.8
«d °2 (unc^Sr.
ilO^lb/hr) (%) ppm)
15.0
15.0
15.0
20.0
20.0
20.0
15.0
15.0
15.0
24.0
24.0
24.0
18.0
18.0
18.0
21.0
21.0
21.0
44.0
44.0
44.0
30.0
30.0
30.0
10.0
10..0
10.0
9.0
9.0
7.2
10.7
10.7
10.7
11.6
11.3
7.9
9.5
10.63
10.75
8.5
8.75
9.2
4.2
4.15
4.1
7.7
8.15
8.15
1391.9
1323.2
1329.7
1788.
(uncorr
ppm)
14.4
15.5
15.0
17.9
Backwashed
1433.3
1333.
1171.6
1238.5
901.3
1020.7
1239.
1309.
1511.7
1358.
1604.
1653.
1585.
2104.
2167.
2213.
1594.
1502.
1538.
22.8
18.3
144.
57.3
16.0
21.4
27.
34.
49.
30.2
34.8
37.9
39.4
30.5
0
15.3
28.6
28.4
31.2
(uncorr. •
ppm)
1406.3
1338.7
1344.
1805.9
Sample
1456.1
1351.
1315.6
1295.8
917.3
1042.1
1266.
1343.
1560.7
1388.2
1638.8
1590.9
1624.4
2134.5
2167.
2228.3
1622.6
1530.4
1569.2
SOj
(corr.
ppm)
2277.6
2164.9
2175.9
2682 . 0
1869.5
2330.
2047.4
2164.4
1722.
1884.
1700.
2049.
2624.
2384.8
2310.
2429.
2418.
2254.
2315.
2357.
2157.
2104.
2154.
S03
(corr.
ppm)
23.6
25.4
24.5
26.9
29.7
32.
251.6
100.
30.5
39.5
37.
53.2
85.
53.
50.
55.7
60.
32.7
0
16.3
38.7
39.7
43.7
(corr.
ppm)
2301.2
2272.1
2200.1
2708.9
1899.2
2362
2299.0
2264.4
1752.5
1923.5
1737.
2102.2
2709.
2437.8
2360.
2484.7
2478.
2286.7
2315.
2373.3
2195.7
2143.7
2197.7
Test Description
Low
n
Ned
Low
n
n
Hed
ft
II
LOW
n
n
Med
n
ti
load, norm O_
n ii n
load, norm O_
load
n
M
load
»
"
load
n
ii
load
n
ii
Max contin load
"
ii
High
"
"
ti ii
n M
load, norm O
n n n
*i i* ii
-------
•• w w v/
CN
0
w 2600
w
o
0)
* 2400
ro
+J
rfl
e 2200
CO
Q 2000
H
X
o
Pi
g 1800
D
" ^
01
1 1 1 1 1 1
__ __
Q n _j
— — ^OQ 1 lOQ ^ •
~^ AJ ^•^AO
31
<-^ O Q22
20 fi ^^
— O 19 ""
_
O Medium load, 2.5-3.1 kg/s (20-24. 5xl03 lb/nr)
Q Low loadr 1.9-2.2 kg/s (15-17^5x10 Ib/hr) .^2 7
— ^Maximum load, 5.5 kg/s (44x10 Ib/hr) —
^>.Med-High load, 3.8 kg/s (30xl03 Ib/hr)
,1 1 1 1 1 1
\s
0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0
EXCESS OXYGEN
Figure 5.3-5.
Excess oxygen vs. sulfur oxide emissions at various loads,
Stout Boiler 2, West Kentucky coal.
118
-------
500
400
tN
300
3
I
*
o
200
100
I \ \
18
19
29
D 24
D
33
25
D
u
31
Rated capacity =5.7 kg/s (45x10 Ib/hr) steam
I I
I I I
37 47 57 67 77 87
PERCENT OF RATED LOAD
97
107
Figure 5.3-6. Load vs. NO emissions, as-found operation, Stout Boiler 2.
West Kentucky coal.
119
-------
250
225
CN
200
n
4-1
(d
>i
M
•a
175
ft
.. 150
g
125
31
Loads
£ 1.9 kg/s (ISxiO3 Ib/hr) steam
O 5.0-5.5 kg/s (40-44xl03 Ib/hr) steam_
O 2.5-3.0 kg/s (20-24::103 Ib/hr) steam
I I I I I I
6 7
EXCESS O
2'
8 9
percent
10
11
12
Figure 5.3-7. NO emissions vs. excess O at various loads, Stout Boiler 2,
West Kentucky coal.
120
-------
700
Rated capacity = 5.7 kg/s
(45xl03 Ib/hr) steam
O
47 57 67 77
PERCENT OF RATED LOAD
87
97
107
Figure 5.3-8.
Load vs. carbon monoxide emissions at as-found operation,
Stout Boiler 2, West Kentucky coal.
121
-------
CN
o vnn
n
rfl
>H ^®®
s
E
a 50°
a
o
i 40°
H
S
w
Q
H
X
O
g 200
§
< 100
u
0
1
A
£j 31
(1120 ppm)
«««...
3
o-
27
QLow load, 1.8-2, .3 kg/s (14-18x10 Ib/hr) steam
— ^Medium load, 2.5-3.1 kg/s (20-24..5xl03 Ib/hr) steam —
^Med-High load, 3.8 kg/s (30x10 Ib/hr) steam
OMaximum load, 5.5 kg/s (44x10 Ib/hr) steam
20 23 2Lr-|
1 24(^33 9 1GSJ
L_y\
0 4567 89 10
_ ^^
30
21
11 12
EXCESS OXYGEN, percent
Figure 5.3-9.
Excess O_ vs. carbon monoxide emissions at various loads,
Stout Boiler 2, West Kentucky coal.
122
-------
Figure 5.3-10 presents the participate emission data versus boiler
load in the as-found operating mode. Dust loading shows a trend of increasing
particulates with increasing boiler load. The highest emissions recorded
were at the maximum load of 5.5 kg/s (44,000 Ib/hr) and were 474 ng/J (0.986
Ib/MBtu). Figure 5.3-11 presents the particulate emissions versus excess
oxygen at a low load of 1.9 kg/s (15,000 Ib/hr) steam flow. The dust loading
seems to increase slightly with increasing excess air; but, the trend is not
pronounced. Increasing air flow could blow additional material off the grate
accounting for the increased emissions with increasing oxygen.
Hydrocarbon data revealed slight emissions of hydrocarbons at all
loads and excess 0 levels. Generally, hydrocarbon emissions were less than
40 ppm at all points tested.
5.3.6 Western Coal Burning on Vibragrate Stoker
A. Stoker Operation—
Minor but definite changes must be made on vibrating grate type
stokers in order to burn western coals. Three distinct problems exist when
attempting to fire western coal on this type of stoker. First, coal ignition
is not as rapid. The western coal fire has a tendency to "walk away" from
the ignition arch. This problem was remedied by opening up the first air
zone control damper and allowing extra air to penetrate the inlet zone of
the stoker. Reducing the speed of the grate also helped keep the fire
ignited and under the arch.
The second problem with western coal firing is the formation of "blow
holes". These bare areas of grate occur when the insulating ash layer is
blown off the grate and exposes the metal to the heat of the furnace. This
condition was remedied by increasing the normal fuel bed thickness 25% to
38% from about 10.2 cm (4.0 inches) to 15.2 cm (5 inches). This increased
the resistance to the air flow from the undergrate air.
123
-------
T3
O
JJ
0)
S
m 1-0
w
3 0.8
-P
CQ
3
O
H
W
to
H
S
H
o
H
EH
).2
Rated load =5.7 kg/s (45x10 Ib/hr) steam
37 47 57 67 77 87 97
PERCENT OF RATED LOAD
107
Figure 5.3-10. Particulate emissions vs. percent of rated load, as-found
operation, Stout Boiler 2, West Kentucky coal.
124
-------
1.2
•o
.8
.p
IT)
1.0
w
0.8
0.6
§
H
a
w
13
0.4
3 o.;
i r
I l
1.9 kg/s
(ISxlO3 Ib/hr)
o-
23
19
21
7 8 9 10
EXCESS OXYGEN, percent
11
12
Figure 5.3-11. Particulates vs. excess oxygen, Stout Boiler 2, West
Kentucky coal.
125
-------
A third problem the vibragrate stoker exhibited was an interesting
phenomenon with respect to CO emissions. Every time the grate would shake the
agitation of the fuel bed would release a large amount of volatiles at once
which caused the CO emissions to increase rapidly or "spike" from their
relatively low levels to values often in excess of 2000 ppm (the upper range
of the CO recording instrument). This behavior is shown graphically on the
section of recorder chart presented in Figure 5.3-12 for Wyoming coal firing.
This figure shows the steady state emission record for test number 3. Note
the spike in CO emission that corresponds to the cyclic vibration of the grate.
Another possible explanation of the high CO spikes could be the rapid evolu-
tion of volatiles and moisture followed by a quenching effect of the water
vapor on the volatile combustion could explain the observed CO spikes. This
phenomenon mainly occurred at medium and high loads. Decreasing the vibration
frequency and/or amplitude would lessen bed agitation and allow the HO and
volatiles to evolve more slowly from the Wyoming coal. Also an air preheater
could be added to increase the combustion air temperature to help burn up the
CO and improve efficiency. A third possible solution would be to promote
mixing of the distilled volatiles with air above the fuel bed by increasing
the overfire air jet momentum such that the air penetrates further over the
fuel bed. This may require redesign of the nozzles or an increase in fan
capacity.
When the CO spikes occurred, the furnace pressure would increase. As
the load was increased there was less negative draft available from the chimney.
When the rapid release of volatiles and moisture occurred, the furnace pressure
sometimes went positive. This would cause sparks and smoke to emit from
cracks in the breeching. This could be a problem at very high loads.
Ash removal was not a problem with western coal nor was storage of
the coal. The western coal did not clinker and, once ignited, burned well.
The coal was free burning and individual coal pieces tended to retain their
identify throughout the combustion process. That is, they did not swell up
in size or stick to other adjacent pieces of fuel. Storage in the under-
ground bunker was no problem. The fuel had been oil treated and even though
it contained 40% fines they stuck to the larger pieces of coal and did not
become a problem in either storage or conveying.
126
-------
t
CO
L
NO
I
CO,
_ Grate
Vibration
01234567
Figure 5.3-12. Carbon monoxide emissions during grate vibration,
Stout Boiler 2, Wyoming coal.
127
-------
B. Exhaust Gas Emissions from Western Coal Firing—
Figure 5.3-13 presents the as-found excess oxygen versus unit load
characteristics for combustion of Wyoming coal in Stout Boiler #2. Excess
O tended to decrease with increasing load although some scatter is present
in the data at the 3.8 kg/s (30,000 Ib/hr) steam load point. Maximum load
achievable on Wyoming coal was 4.2 kg/s (33,000 Ib/hr) steam flow. Maximum
load was determined as .follows:
Unit was stabilized at 1.9-2.1 kg/s (15-17,000 Ib/hr) steam flow. The
load was increased artificially by using steam to drive fans and ash conveyor
system. Boiler steam load was increased slowly to 4.2 kg/s (33,000 Ib/hr).
At this point, ignition began to fail as fire started to "walk away" from the
furnace arch. This problem was remedied by increasing the overfire air from
8.89 cm (3.5 inches) water at the top, and 20.3 cm (8.0 inches) water at the
bottom, to 12.95 cm (5.1 inches) water, and 25.4 cm (10.0 inches) water respec-
tively. The higher overfire air seemed to help keep the fire under the arch.
The fuel bed began to stretch out over the grate area once ignition
was stabilized. Initially the flame front extended to zone four, but soon
increased its length to midway into zone five. The 4.2 kg/s (33,000
Ib/hr) load apparently is maximum load since furnace draft goes positive each
time the grate vibrates. The boiler outlet (or uptake) damper is wide open
(100%) and no additional natural induced draft is available to keep the
furnace negative. The air is lowered somewhat to reduce furnace draft. A
point is reached where furnace draft is staying more or less negative with
slight excursions into the positive regime when the grate vibrates. CO
emissions are relatively high at about 1200-1800 ppm. The stack emits a dark
puff of smoke with each grate vibration. A steam flow of 4.2 kg/s (33,000
Ib/hr) is the maximum reliable load due to high CO emissions, visible smoke
and low furnace draft. Hence, with western coal Stout Boiler #2 was able to
operate at 4.2 kg/s (33,000 Ib/hr) steam out of a possible 5.5 kg/s (44,000
Ib/hr) steam that was obtained on the West Kentucky fuel or 75% of the boiler
potential on eastern coal. The excess O level at the maximum load was
found to be 4.5%.
128
-------
10
4J
§ 8
I 7
g
X
o
U)
H
34,35
Rated load - 5.7 kg/s (45x10 Ib/hr) steam
37 47 57 67 77 87
PERCENT OF RATED LOAD
97
Figure 5.3-13. Load vs. excess oxygen, as-found operation, Stout Boiler 2,
Wyoming coal.
129
-------
Sulfur oxide emissions were obtained at the maximum load for western
coal and were found to be 485 ppm at 3.0% excess O . The SO component of
£ n3
total sulfur oxides was about 5.0%.
Nitrogen oxide (NO) was found to be 160 ppm at 3.0% excess O at the
maximum load. NO was not measured due to an out-of-service hot line.
X
Figure 5.3-14 presents the as-found SO emissions for Stout #2 versus
load for normal operation. Table 5.3-4 presents the summary of all SOx data
taken on Wyoming coal. Overall average SO at 3.0% excess O were 616 ppm
X &,
for the western coal. Emissions based on the fuel analysis of an average
fuel sulfur content of 0.83% and higher heating value of 23 MJ/kg CV3900
Btu/lb) would yield 763 ppm at 3.0% O . This seems to indicate some sulfur
retention by the ash when western coal is fired.
Figure 5.3-15 presents the SOY data as a function of excess oxygen.
A.
SOx emissions appear constant at low loads with changes in excess O . At
high and medium loads, the SO emissions appear to increase with increasing
X
excess air.
Figure 5.3-16 presents the NO emissions for Stout #2 versus load
for the as-found normal operation condition. The emissions are constant with
increasing load. The average value of measured NO is 164 ppm at 3.0% excess
oxygen in the as-found condition. Figure 5.3-17 presents the variation of NO
emissions with excess oxygen level at low and medium loads. NO formation show
a definite trend of increasing emissions with increasing oxygen levels.
Figure 5.3-18 presents the carbon monoxide emissions over the Stout
#2 load range in the as found condition CO emissions were generally low (less
than 160 ppm) except for the maximum load point of 4.2 kg/s (33,000 Ib/hr)
steam flow. Figure 5.3-19 presents CO emissions as a function of excess O_
levels at low and medium loads. Except for the high CO level at maximum load
most CO emissions were low. The CO emissions did spike to high levels when
the grate shook at loads of medium size and up. The data shown in Figure
5.3-19 does not present the spiking values.
130
-------
900
800
700
600
-P
(0
E
S1
a
g 500
Q
H
X
O
rt
g 400
0 0
15 36
Q
34
O,
O
35
•tv
Rated load =5.7 kg/s (45xl0 Ib/hr) steam
0 37 47 57 67 77
PERCENT OF RATED LOAD
87
Figure 5.3-14. Load vs. sulfur oxide emissions, as-found operation, Stout
Boiler 2 , Wyoming coal.
131
-------
TABLE 5.3-4. SULFUR OXIDES EMISSIONS SUMMARY, UNIVERSITY OF WISCONSIN, STOUT BOILER #2, WYOMING COAL
Test
No.
2A
2B
2C
3A
3B
3C
4A
4B
4C*
8A
BB
8C
11A
11B
lie
13A
13B
13C
kg/s
(103 ib/hr)
Steam
Load
2.7
(21.5)
2.7
(21.5)
2.7
(21.5)
2.3
(18)
2.3
(18)
2.3
(18)
2.1
(17)
2.1
(17)
2.1
(17)
3.5
(27.5)
3.5
(27.5)
3.5
(27.5)
4.2
(33)
4.2
(33)
4.2
(33)
3.2
(25.5)
3.2
(25.5)
3.2
(25.5)
o2 (%)
7.7
7.7
7.6
6.2
6.2
6.2
9.1
9.9
10.0
7.3
7.3
7.3
3.75
3.75
3.75
6.0
6.0
6.0
S02
(uncorr ppm)
391.7
457.5
559.4
371.6
383.0
367.0
352.7
281.2
204.3
569.3
448.5
384.2
478
435.8
4J9.4
-J39.1
399.5
392.3
S03
(uncorr ppm)
24.2
17.4
14.2
20.7
27.2
27.8
18.4
20.1
19.4
28.3
31.0
22.2
29.7
17.2
24.8
16.8
12.9
23.7
SOx
(uncorr ppm)
415.9
474.9
573.6
392.3
410.2
394.8
371.1
301.3
223.7
597.6
479.5
406.4
497.7
453.0
434.2
455.9
412.4
416.0
S02
(corr ppm)
530
619.2
751.4
451.9
465.8
446.3
533.5
456
334.3
748.0
589.3
504.8
498.8
454.7
427.2
526.9
479.4
470.8
S03
(corr ppm)
32.8
23.5
19.1
25.2
33.1
33.8
27.8
32.6
31.7
37.2
40.7
29.2
30.9
17.9
25.5
20.2
15.5
28.4
SOx
(corr ppm)
562.8
642.7
770.5
477.1
398.9
480.1
561.3
488.6
366.0
785.2
630.0
534.0
529.7
472.6
453.1
547.1
494.9
499.2
Percent
SO /SOx
5.8
3.6
2.5
5.3
6.6
7.0
4.9
6.7
8.7
4.7
6.5
5.5
5.1
3.6
5.5
3.7
3.1
5.7
Test Description
Norn. O,
1
Norn. 0_
i
Norn. O.
2
Norn. O
Norn. O
High O,
2
High 0,
2
*A leak was found in
system during sam-
pling @ 0.4 CF. Dura-
tion of leak is un-
known
Med. load, Horn. O
Med. load, Horn. O
Med. load, Norn. O,
2
Max. load, Norn. O
Max. load, Norn. O
Max. load, Norn. O,
2
Med. load. Low O
Med. load. Low O
Med. load. Low O
(continued)
-------
TABLE 5.3-4 (continued).
Test
No.
14A
14B
14C
ISA
15B
15C
16A
M 16B
U)
16C
35A
35B
35C
36A
36B
36C
*!/*
(103 Ib/hr)
Steam
Load
3.2
(25)
3.2
(25)
3.2
(25)
4.5
(35.5)
4.5
(35.5)
4.5
(35.5)
2.0
(15.5)
2.0
(15.5)
2.0
(15.5)
3.8
(30.0)
3.8
(30.0)
3.8
(30.0)
3.7
(29.5)
3.7
(29.5)
3.7
(29.5)
0 (*)
9.9
8.25
8.5
7.0
7.0
7.0
7.4
7.5
7.5
7.9
8.2
—
6.7
5.8
6.5
S02
(uncorr ppn)
554
462.7
474.1
649.3
662.3
634.9
364
317.3
350.6
419
420
425
833
645
535
so3
(uncorr ppn)
20.
15.
12.
9.
13.
14.
11.
15.
14.
16.
11.
10.
7.
14.
7.
7
4
2
27
9
0
2
4
6
0
6
7
0
0
5
SOx
(uncorr ppn)
574.7
478.1
486.3
658.6
676.2
648.9
375.2
332.7
365.2
435.0
431.6
435.7
840.0
659.0
542.5
S02
(corr ppn)
898
653.2
682.7
834.8
800.1
816.3
481.8
423.0
467.4
575
591
598
1049
764
664
S03
(corr ppn)
33.6
21.2
17.6
11.9
17.9
18.0
14.8
20.5
19.5
22.0
16.3
15.0
9.0
16.6
9.3
SOx Percent
(corr ppn) SO /SOx Test Description
931.6
674.4
700.3
846.7
818.0
834.3
496.6
443.5
486.9
597
607.3
613.0
1058.0
780-6
673.3
Ned. load,
(• May be
Med. load.
Med. load.
Med. load.
Med. load.
Ned. load,
High O
in error)
High O
High O
NOB. O
No*. °2
Hon. O
Low load, NOB. O
Low load, NOB. O
Low load, Norn. O
High load,
High load.
High load.
High load.
High load.
High load.
Norn. O
Norn. O
Norn. 02
Norn. O
Horn. O
Norm. 02
-------
1000
900
-p
«3
5 800 —
ft
ft
w 700
H
600
i—r
Ol5
A 36
11
Q Low loads, 2-2.3 kg/s (15.5-18x10 lb/hr) steam
Medium loads, 2.7-3.5 kg/s (21.5-27.5xl03 lb/hr) steam
High loads, 3.7-4.2 kg/s (29.5-33xl03 lb/hr) steam
I
I
I
1
I
10
EXCESS OXYGEN, percent
11
Figure 5.3-15. Excess oxygen vs. sulfur oxide emissions at various loads,
Stout Boiler 2, Wyoming coal.
134
-------
500
fN
O
ro
<« 400
2
| 300
w
OXIDE EMISSION
M NJ
0 0
0 0
u
i r •
Rated load =5.7 kg/s (45xl03 Ib/hr) steam
— —
— —
— 7 10,15 —
36
/V
37 47 57 67 77
PERCENT OF RATED LOAD
87
Figure 5.3-16. Load vs. NO emissions, as-found operation, Stout Boiler 2,
WyoirJLng coal.
135
-------
250
225
200
ro
4J
IT!
I
ft
0150
125
100
10
13
•, 1.9-2.3 kg/s (15-18x10 Ib/hr)steam
C 3.2 kg/s (25xl03 Ib/hr) steam "
10
11
12
EXCESS 0 , percent
Figure 5.3-17. Excess oxygen vs. NO emissions. Stout Boiler 2, Wyoming coal.
136
-------
ro
-P
2000
500
34,35,36
(2000+)
I
en
s
o
H
in
to
H
400
300
g 20°
s
§
o
100
Rated load =5.7
(45xl03 Ib/hr)
steam
7
O.
37
47 57 67
PERCENT OF RATED LOAD
77
87
Figure 5.3-18. Load vs. CO emissions, as-found operation, Stout Boiler 2,
Wyoming coal.
137
-------
r-i
0 500
n
4J
(0
>< 400
1
300
O
to
H 200
CARBON MONOXIDE
M
o
0 O
1 1 111
Q Low loads, 1.9-2.3 kg/s (15-18x10 Ib/hr) steam
Q Medium loads, 2.5-3.3 kg/s (19.5-26x10 Ib/hr) steam
— —
— —
r>. 17
13 — . 14 -1
>v 1 1 sTQf0! 1 ®JP'\
04 56 789 10 1]
EXCESS OXYGEN, percent
Figure 5.3-19.
Excess oxygen vs. CO emissions at various loads, Stout
Boiler 2, Wyoming coal.
138
-------
Figure 5.3-20 presents the particulate emissions versus boiler load
in the as-found operating mode. Dust loading shows a trend of increasing
particulates with increasing boiler load. The highest emissions recorded were
at 3.8 kg/s (30,000 Ib/hr) steam flow and were found to be 625.2 ng/J (1.454
Ib/MBtu). Figure 5.3-21 presents the particulate emissions versus excess 0
at loads of about 2.1 and 3.2 kg/s (17,000 and 25,500 Ib/hr) steam. These
two curves show an interesting rise at both high and low excess air levels.
The increased particulates at high excess air levels would indicate extra
mass blown off the grate by the higher air flows. The increased particulates
at low excess oxygen may be due to incomplete combustion of the carbon
particles.
Limited hydrocarbon data was obtained due to a faulty hydrocarbon
analyzer. However, emissions that were obtained showed emissions to be low
and less than 50 ppm.
5.3.7 Comparison of Eastern Versus Western Coal Burning on a Vibrating
Grate Stoker
The stoker being considered is of the vibrating grate configuration
with a nameplate capacity of 5.7 kg/s (45,000 Ib/hr) steam flow. Actual
continuous capacity tests found that the maximum continuous load obtainable
while firing a West Kentucky coal of about 28.6 MJ/kg (12,300 Btu/lb) heat-
ing value was 5.5 kg/s (44,000 Ib/hr) steam flow. Under similar defining
conditions the Wyoming coal could only obtain 75% of that figure or had a
maximum continuous capacity of 4.2 kg/s (33,000 Ib/hr) steam flow.
This type of stoker was designed and built to fire an eastern type
fuel but it can successfully fire a western type fuel with certain definite
changes in operating procedures. First , one must increase the fuel bed
thickness 25-38%. Normal bed thickness for West Kentucky coal was approxi-
mately four inches. When firing Wyoming coal this had to be increased to
12.7-13.97 cm (5 to 5-1/2 inches). The increased fuel bed thickness de-
terred formation of blow holes in the fuel bed by increasing its resistance
to undergrate air flow. This also helped protect the grate since less ash
is present when firing western coals. Ignition is a problem with Wyoming
139
-------
I
<
ft
1.6
1.4
1.2
1.0
0.8
§
H
W
S 0.6
g
H
13
u
H
0.4
0.2
i r
Rated Load = 5.7 kg/s
(45xl03 lb/hr)
steam
D
34
i i i i
37 47 57
PERCENT RATED LOAD
77
Figure 5.3-20. Particulates vs. load, as-found operation. Stout Boiler 2,
Wyoming coal.
140
-------
in
3
-P
en
8
1.0
0.8
0.6
0.2
2,8 kg/s Steam
(22.5xl03 Ib/hr) "X,
,14
2.1 kg/s Steam
(17xl03 Ib/hr)
6789
EXCESS OXYGEN, percent
10
11
Figure 5.3-21. Particulates vs. excess oxygen, Stout Boiler 2, Wyoming
coal.
141
-------
coal. Heat required to raise the fuel to ignition temperature is lost to
distilling off the high moisture content of the western coal. This problem
is overcome by opening up the first air zone (the one directly under the
ignition arch) and permitting air to mix with the fuel to start firing
earlier in the arch. Also, the grate speed can be slowed somewhat to allow
the fuel to spend more time under the arch. Additionally, some increase
in overfire air seems to keep the fire "pushed" back under the arch when
Wyoming coal is fired.
When looking at the two different coals burning there is a noticeable
difference in firing under the arch. On the eastern coal combustion the
fire is much more pronounced and defined than the western coal. The West
Kentucky coal seemed to burn closer to the inlet gate and deeper in or
under the arch. On the other hand, Wyoming coal, although it does burn
under the arch and maintains ignition once you slow down the grate a little,
does burn a little farther out from underneath the arch. The eastern coal
also had a darker orangish color to its flames than did the western coal.
Air dampers had to be changed when burning Wyoming coal. For
eastern coal firing,the predominant air passages were zones two and three,
especially zone two. Zone one, by the way, is always closed when firing eastern
coal. For Wyoming coal combustion the first zone is opened up a little, the
second zone is pinched back and the third zone is opened some more.
Another problem initially associated with western coal firing was
fines sifting through the grate. This was only a problem during initial
start-up before an ash bed could be established over the grate area. However,
when the fines sifted through the grate they would land on the top of the air
zone dampers and ignite forming metal-warping fires on the dampers. Once
this problem was discovered, the solution was found to be a quick series of
snapping open and shut of the dampers periodically during start-up to purge
the tops of the dampers of the fine sittings. Once a fuel bed was established
this action was no longer necessary.
142
-------
There were no problems concerning piling and storage of the western
coal. It conveyed well in the conveyor, stored well and worked fine in
the coal elevator. The batch of Western coal tested appeared to have a
considerable amount of fines in it, perhaps 40% or more. However, this coal
had been oil-treated and there was no problem with fugitive dust.
From time to time some segregation was noted in the coal hopper.
Pines seemed to congregate in certain areas. There didn't appear to be any
pattern for this and the segregation sometimes resulted in an unevenly
distributed fuel bed with the fines being more closely packed and more
restrictive to air flow.
Another observation of the differences in the two fuels was the free
burning characteristic of the Wyoming coal. As the western coal burned, each
piece would retain its individual identity and original size more or less. On
the other hand, the eastern coal would coke and then swell up in size to two
or three times its original size. During this swelling process adjacent
pieces of eastern coke would tend to stick to one another and form a non-
porous air-resistive area. This, of course, is one reason more air was re-
quired in the later air zones in the stoker when firing eastern coal.
There seemed to be more "sparklers" or air-borne incandescent
particles associated with the Wyoming coal firing. Also, extreme changes in
furnace pressure would accompany the shaking of the grate. This grate
agitation would release large quantities of volatiles which would combust
quickly and increase the relative volume in the furnace quite rapidly.
This was especially noticeable at medium to high loads and at high excess
air levels. Also, there were more sparklers with the Wyoming coal particularly
when the grate shook. When that happened, you could see them fly out from
the fuel bed in large numbers. This was not so apparent for eastern coal
combustion.
There seemed to be some slag formations on the water tubes that
made up the ignition arch when western coal was burned. This was not as
prevalent on the eastern coal.
Another, phenomenon that western coal exhibited when the grate shook,
besides an increase in furnace pressure, was large increases in carbon
143
-------
monoxide emissions. The nominal steady state levels of CO were generally less
than 50 ppm but would take a sharp spike upward and go off the scale of the
mobile lab's 0-2000 ppm CO analyzer's high range.
There were no problems at all with clinker formation while burning
Wyoming coal. As a matter of fact, there was only one day when a clinker
started to form and that was a day when there was quite a few fines in the
hopper and segregation was severe. On eastern coal, however, there were
three or four days when clinkers were formed and some were quite large. One
in particular almost covered the entire grate area and took quite some time
and effort to remove.
Overfire air was used and is used for both western and eastern coal
firing. The overfire air did not seem to make any improvement in the CO spikes
mentioned above during western coal firing but did seem to help keep the
western coal flame-front under the ignition arch.
There were some interesting differences in emission characteristics
between the western and eastern coal firing. The excess oxygen requirement
was slightly reduced for western coal firing. Sulfur oxides were significantly
lower on the Wyoming coal at 616 ppm at 3.0% 02 versus 2265 ppm at 3.0% ©2
for the West Kentucky fuel. This represents a 72.8% reduction in emissions.
Emissions based on the fuel analysis showed western coal to be 763 ppm at
3.0% ©2 and Eastern coal to be 2110 ppm at 3.0% 02 or only a 64% reduction.
The additional loss in sulfur oxides may be due to some sulfur retention
characteristic of western coal ash.
NO emissions were slightly lower on the Wyoming coal. Western coal
NO averaged 164 ppm at 3.0% excess oxygen versus an average of 185 ppm at 3.0%
excess oxygen for the eastern fuel.
Both fuels had low overall CO emissions during normal operation except
at maximum load. The western coal firing exhibited the interesting phenomenon
of spiking to high levels of CO (>2000 ppm) when the grate shook when firing
at medium loads and higher. Eastern coal did not exhibit this behavior.
Particulate emissions were lower on western coal at low and medium
loads but tended to increase at the higher loads. Hydrocarbon emissions
were about the same for both fuels,and very low (<50 ppm).
144
-------
5.4 UNIVERSITY OF WISCONSIN, EAU CLAIRE
The testing described in this section was done on Boiler "#1 of the
Central Heating Plant on the University of Wisconsin, Eau Claire campus located
in Eau Claire, Wisconsin.
The unit is an overfed traveling grate stoker manufactured by Bros
Inc. in 1966. It has a nameplate eating of 7.6 kg/s (60,000 Ib/hr) steam
flow and is fired with a Laclede traveling grate stoker supplied by the Laclede
Stoker Company. Additional data on the unit design and operation are listed
below:
. Design Pressure - 1.2 MPa (160 psig)
Design Temperature - saturated
Actual Day-to-Day Operating Conditions
Operating Pressure - 1.1 MPa (150 psig)
Operating Temperature - saturation
Boiler Heating Surface - 568 m (6,117 sq. ft.)
2
. Water Wall Heating Surface - 50.4 m (543 sq. ft.)
. Furnace Width - 3.96 m (13'0")
. Furnace Depth - 3.12 m (1013-1/2")
. Effective Combustion Volume - 78.7 m (2,780 cu. ft.)
. Grate Width - 366 m (12'0")
Effective Grate Length - 4.6m (14'11")
Net Effective Gr
Grate Zones - 6
2
. Net Effective Grate Area - 16.6 m (179 sq. ft.)
. Overfire Air Fan Capacity - 59.5 m /min (2,100 CFM)
. Percent of Total Air Supplied by Overfire Air Fan - 10%
. Forced Draft Fan Capacity - 623 m /min (22,000 CFM)
. Heat Release - 9.43xl05 GJ/hr m3 (25,300 Btu/cu. ft.)
A drawing of the stoker is shown in Figure 5.4-1.
145
-------
Coal Hopper
Drive
Linkage
Drive
Sprocket
Sittings
Hopper
Sittings Dump
Mechanism
Return
Bend
Air Seals Air Compartments Drag Frame
Figure 5.4-1. Chain grate overfeed stoker.
146
-------
5.4.1 Unit Operation
Coal enters the stoker from above from a hopper which is fed by a
conveyor system. The coal then passes through an adjustable coal gate onto the
leading edge of the grate. The gate height determines the fuel bed thickness.
Fuel feed rate is determined by the forward speed of the traveling grate. The
traveling grate is in a horizontal position.and travels from the coal hopper
towards the ash pit side of the furnace. The grate is not watercooled; there-
fore, it is important that changes in factors such as fuel bed thickness and
distribution, ash quantity and composition, and excess air level be carefully
considered or else overheating of grate may occur.
As coal enters the furnace, it is heated to ignition temperature
in a short refractory arch section. Unheated combustion air is supplied to the
unit by a-forced draft fan. Combustion air enters the system from below the
grate through individually adjustable air dampers. Local fuel-to-air ratios
can be adjusted across the fuel bed as the bed travels slowly toward the ash
pit. There are six burner-zone air dampers. Additional overfire air is intro-
duced above the grate surface to complete combustion and prevent smoking.
Overfire air is supplied by a separate blower. The furnace is maintained
slightly negative by the natural draft created by the smoke stack.
Hot combustion gases from the grate travel upward in the furnace.
At the top of the boiler they begin a downward pass through the back section
of the boiler and then one more upward passage before exiting the unit.
From the unit the gases flow through a horizontal exhaust duct to the base
of the stack, then upward and exit to atmosphere.
This unit has no dust collection device per se; however, the exhaust
duct is oversized for the boiler and considerable particulates settle out by
gravity in the horizontal section of the breaching and bottom of the stack.
Siftings from the grate and ash from the ash pit are pneumatically removed
from the system.
147
-------
5.4.2 Sampling Location (Gaseous, Particulates, SOx)
Gaseous, particulates, and SOx samples were taken from the breeching
between Unit #1 and the stack. Figure 5.4-2 is a cross section of the breech-
ing showing locations of gaseous probes and particulate traverse points. SO
samples were taken in either port 2 or 3 using probes which varied in length
from 45.7 to 91.44 cm (1.5 to 3.0 feet).
1.5 m
East
Port 1
TOD
o o o o
X 2 X 4 X 6 X8
o o o o
o o o o
Xi X 3 Xs X?
o o o o
U U U II
J
1
59 m
(6'3")
L.333m
(5'3")
0.95m
(3'9")
0.57 m
— 1-(2'3")
0.305ml
1 f
.
1
Bottom
Port 2 Port 3
(12"]
Port 4
0.084 m (4") pipe nipples
O Traverse Points
X Gaseous Probe Locations
Figure 5.4-2. Sample port locations in Unit 1 at University of Wisconsin,
Eau Claire.
148
-------
5.4.3 Fuels
The base coal was a West Kentucky coal from the Vogue mine, Seam #11.
Proximate and ultimate analyses of fuel samples taken during the testing are
presented in Table 5.4-1.
The test coal was from the Bighorn mine in Wyoming. Proximate and
ultimate analyses of fuel samples taken during the testing are presented in
Table 5.4-2.
TABLE 5.4-1. FUEL ANALYSIS - BASE COAL, WEST KENTUCKY - VOGUE
Proximate Analysis
Moisture %
Volatiles %
Fixed Carbon %
Ash %
Sulfur %
As Received MJ/kg
Btu/lb
(2 Samples)
7.86?
37.09;
48.19;
6.86;
3.02;
28.7
12338;
7.42
38.24
48.03
6.31
2.80
28.9
12427
Ultimate Analysis (1
Hydrogen %
Carbon %
Nitrogen %
Oxygen %
Chlorine %
Ash Fusion Temp (H=W)
Moisture %
Ash %
Sulfur %
Sample)
4.60
65.05
1.24
9.13
0.01
1292 °K
2085 °F
9.15
8.03
2.79
TABLE 5.4-2. FUEL ANALYSIS - TEST COAL, WYOMING, BIGHORN
Proximate Analysi
Moisture %
Volatiles %
Fixed Carbon %
Ash %
Sulfur %
As Received MJ/kg
Btu/lb
s (2 Samples)
21.84;
32.41;
40.31
5.44;
0.62;
21.9
9429
18.78
34.40
38.60
8.22
0.84
21.2
9123
Ultimate Analysis (1
Hydrogen %
Carbon %
Nitrogen %
Oxygen %
Chlorine %
Ash Fusion Temp (H=W)
Moisture %
Ash %
Sulfur %
Sample)
4.01
57.98
1.10
10.90
-0-
1306 °K
2110 °F
on 1 A
5.13
0.72
149
-------
This unit was part of a heating plant, therefore the maximum load
available for the test was a function of the ambient temperature. At the
beginning of the testing it was warm and only low loads were available, so
all of the low load tests were run first on the western coal and then on the
eastern coal. As the weather began to get cooler, testing was resumed on
the western coal. The high load tests on western coal were cut short due
to operational difficulties in burning the western coal and the unit was
switched back to eastern coal for the remainder of the test program. Table
5.4-3 contains a summary of all emissions data taken on Unit 1 at University
of Wisconsin, Eau Claire.
5.4.4 Nitric Oxide Emissions - Eastern Coal
For "normal" operating conditions the NO was lowest at low loads
1.9 kg/s (15x10 Ib/hr)steam flow. This may have been due to poor mixing
of the fuel and air which caused poor combustion. As the load was increased
to the 2.3-3.4 kg/s (18-27x10 Ib/hr) steam flow range the mixing improved
causing better combustion which created more NO. At high loads of 5.4-6.2
kg/s (43-49x10 Ib/hr)steam flow, the amount of air available for combustion
decreased because a larger percentage of the fuel bed was engaged in active
burning than at the lower loads and this resulted in lower NO emissions. Figure
5.4-3 is a plot of NO vs. excess O for eastern coal, with normal operating
conditions indicated by test numbers 11, 22, 24, 25, 26, 29, 30, 31, and
33. In every test in which the excess O level was raised there was an increase
in NO emissions (tests 12, 19, and 32), and in every test where the excess
O level was lowered, there was a decrease in NO emissions (tests 20 and 27).
5.4.5 Nitric Oxide Emissions - Western Coal
For "normal" operating conditions the NO emissions were lowest at
the low loads and highest at the high loads. This situation may be mislead-
ing because at the high loads the fuel bed was separated into large areas of
150
-------
TABLE 5.4-3. EMISSION DATA SUMMARY - UNIVERSITY OF WISCONSIN, EAU CLAIRE
Test
No.
Date
1975
Load
kg/a 103 Ib/hr
°2
percent
CO
3» 02
(ppm)
C02
percent
IK)
3» O2
(dry)
(ppm)
Percent
Combust .
Particulates
ng/J
Ib/MBtu
sox
(ppm)
SOx
ng/J
3% 07
Ib/MBtu
Fuel S
ng/J Ib/MBtu
Sulfur
Retention
Factor,
percent
WESTERN COAL
1
2
3
4
S
6
7
B
9
10
21
9/22
9/23
9/24
9/25
9/26
9/30
10/1
10/2
10/3
10/7
10/29
Average
3.14
3.14
3.78
3.14
2.28
1.89
4.42
4.03
4.42
4.17
4.42
3.53
25.0
25.0
30.0
25.0
18.0
15.0
35.0
32.0
35.0
33.0
35.0
28
7.2
7.7
7.1
9.75
10.55
10.39
9.8
9.7
10.5
10.6
11. 1
9.49
11
12
13
14
15
16
17
IB
19
20
22
23
24
25
26
27
2B
29
30
32
33
34
10/9
10/10
10/13
10/14
10/15
10/16
10/17
10/20
10/21
10/22
10/30
10/31
11/1
11/3
11/4
11/5
11/10
11/11
11/12
11/13
11/17
11/18
11/19
Average
East-West,
East *
1.89
1.89
1.89
1.89
2.39
3.35
3.14
2.78
2.28
2.85
3.35
1.89
1.89
1.89
1 . 89
3.14
2.28
5 . 67
6.17
5.42
1.89
1.89
2.89
+25.6
15.0
15.0
15.0
15.0
19.0
27.0
25.0
22.0
18.0
23.0
27 . 0
15.0
IE (1
I -> - U
15.0
15.0
25.0
18.0
45. 0
49.0
43.0
15.0
15.0
32.3
+25.6
13.2
15.9
15.1
15.7
11.3
11.4
11.7
14.2
15.1
10.3
10. 9
16.0
12.2
12.6
12.8
10.1
9.8
6.6
6.6
8.9
12.2
13.6
12.1
-21.6
250
155
500
145
125
48
175
85
299
371
1 1 41
J.i.4 J
300
12.0
11.8
12.1
9.6
9.2
9.66
9.B
10.3
9.0
B.2
9. 3
10.09
135
173
135
178
147
151
222
274
308
275
302
209
—
29.02
26.92
29.11
64.9
41.04
48.29
39.88
Ill
63
-_-
68.4
146.2
211.1
298.9
390
184
—
0.258
0.146
0.159
0.34
0.491
0.695
0.907
0.428
619
498
551
585
618
574
EASTERN COAL
259
1091
947
971
528
97
134
663
886
73
50
1548
383
547
—
41
102
134
84
340
467
-35.8
6.9
4.7
5.2
4.8
8.7
8.3
8.0
6.45
5.48
9.3
9. 1
4.8
7.8
6.95
7 . 3
9.5
9.1
10. 9
11.4
9. 2
8.1
6.6
7.66
+31.7
264
308
340
253
286
339
229
203
226
300
201
255
211
233
199
183
252
-17
43.95
—
—
—
—
—
38.5
—
—
~
—
—
43.57
44.44
35.69
—
—
41.23
-3.3
149.2
498.8
160.4
491.5
332
131
808
122
336.6
-45.3
0.347
1.16
0.373
1.143
0.772
0.305
1.88
0.283
0.783
-45.3
2374
2265
2306
2622
2072
2517
2343
— _
2197
2110
2312
-75.2
526
423
468
497.3
525.3
488
1.224
0.984
1.089
1.156
1.222
1.135
—
—
565.5
—
614.9
—
791.6
657
2018
1925
1960
2229
—
1761
—
2139
1992
—
—
1867
—
1794
1965
75.2
4.693
4.477
4.558
5.183
4.096
—
4.975
4.63
4.34
4.1709
4.569
-75.2
2105
—
—
—
—
~
—
—
~
1938
—
—
—
--
2053
--
—
2032
-67.6
1.315
1.43
1.841
1.53
4.895
—
—
—
4.506
—
--_
4.774
—
4.725
-67.6
._
82.8
80.8
66.4
76.7
95.9
~
—
—
—
—
—
—
—
109.4
-
—
—
--
90.9
—
--
98.7
-22. 3
-------
o
<*>
•P
(0
ft
*.
o
2
350
300
250
200
150
29
30
Q High Load - 5.4-6.2 kg/s
(43-49x103 Ib/hr)
ol ys.
Medium Load - 2.3-3.4 kg/s
(18-27xl03 Ib/hr)
Low Load - 1.9 kg/s
(15xl03 Ib/hr)
12
8 10 12
EXCESS OXYGEN, percent
14
16
18
Figure 5.4-3. Nitric oxide emissions vs. excess 0^, University of Wisconsin,
Eau Claire, eastern coal.
152
-------
unburned coal which were bordered by thin ribbons of intense combustion.
These areas of intense combustion may have generated much more NO than an
evenly burning fuel bed. Figure 5.4-4 is a plot of NO vs. excess O for
western coal, with normal operating conditions indicated by test numbers 1,
2, and 7. Raising the excess O2 level resulted in higher NO emissions at
medium [3.2 to 3.3 kg/s (25 to 26xl03 Ib/hr) steam flow] and high loads
[3.8 to 4.4 kg/s (30 to 35xl03 Ib/hr) steam flow], while in the single case
where it was possible to lower the excess O2 (test 3) the NO emissions were
substantially lowered.
Figure 5.4-5 is a comparison of NO emissions vs. load for eastern
and western coals. It must be noted that the trend of increasing NO emis-
sions with increasing load for eastern coal is misleading as the data does
show a decrease in NO emissions at loads of 5.4 to 6.2 kg/s (43 to 49xl03
Ib/hr) steam flow; however, it was not possible to reach loads of that
magnitude with western coal so only the comparable load ranges are plotted.
The higher average NO emissions with eastern coal may be due either to the
higher fuel nitrogen content ,of the eastern coal or that the eastern coal
exhibited much better combustion in this unit.
5.4.6 Sulfur Oxides Emissions
The fuel analyses (Table 2-1) show that the eastern coal averages
3.9 times higher in fuel sulfur content than the western coal. If the SOx
results from Table 5.4-4 are compared for medium loads [4.4 kg/s (35x10 Ib/hr)
steam on eastern and 3.2 kg/s (25x10 Ib/hr) steam on western] over a range of
excess air levels, the eastern coal averages 3.55 times the western coal in
SO emissions. This indicates that a greater percentage of the fuel sulfur
x
in eastern coal may be converted to organic sulfur oxides than with western
coal; however, the results show that this eastern coal emits an average of
2445 ppm SO at 3% excess O^, while the western coal emits only an average
** x 2
of 688 ppm SO at 3% excess O .
It appears, from examining the data, that variations in the fuel
sulfur content are as much a factor as load and excess O2 changes in giving
different SO results for each coal. The western coal results must be treated
x
153
-------
350
300
0^250
-g
(0
£ 200
s
a
a
o 150
z
100
High Load -
3.8-4.4 kg/s
(30-35xl03 Ib/hr)
Medium Load -
3.2-3.3 kg/s
(25-26xl03 Ib/hr)
O
Load -
1.9-2.3 kg/s
(15-18xl03 Ib/hr)
6 8 10 12
EXCESS OXYGEN, percent
14
Figure 5.4-4.
Nitric oxide emissions vs. excess O_, University of Wisconsin,
Eau Claire, western coal.
154
-------
350
300
O
*
-P
fl
200
0.
O 150
2
100
O
Rated Load =7.36 kg/s
(60xl03 Ib/hr)
16
O Western Coal
/\ Eastern Coal
33 50
PERCENT OF RATED LOAD
66
Figure 5.4-5. Nitric oxide vs. percent of rated load, University of Wisconsin,
Eau Claire.
155
-------
TABLE 5.4-4. COMPARISON OF SOX EMISSIONS
FOR SIMILAR LOAD RANGES
kg/s
4.
4.
4.
4
4
4
WESTERN
COAL
Load
(103 Ib/hr) 2
(35)
(35)
(35)
Low,
Med,
6.9%
10.7%
High, 11.1%
Average
SOX , ppm
at 3% 02
530
760
775
688
kg/s
3.
3.
3.
2
4
2
EASTERN
COAL
Load 0
(103 Ib/hr) 2
(25)
(27)
(25)
Low,
Med,
10.1%
12.2%
High, 15.0%
Average
SOX, ppm
at 3% 0
2520
2622
2195
2445
carefully in cases where more than 10% of the sample is reported as SO .
In these cases, it is possible that some of the sample could be lost through
volatilization of the SO or conversion of the SO to sulfurous acid, instead
of sulfuric acid, which may not react properly with the titrant. In this
report, the samples which contained more than 10% SO have been eliminated
from the data analysis and the data plots.
A plot of SO versus excess O is shown in Figure 5.4-6. There are
X £.
no clearly defined trends in the data; however it does illustrate the dif-
ferences in SO levels for eastern and western coals. Figure 5.4-? is a
plot of S03 versus excess O^ and shows that the SO concentration increases
with increases in excess O for both the eastern and the western coals.
5.4.7 Carbon Monoxide Emissions
The CO emissions for eastern coal are shown in Figure 5.4-8. The
highest CO emissions occurred at the lowest loads or at excess O levels
that were either higher or lower than "normal" operating conditions. The
high CO levels at low loads and for the low excess O conditions were due
to the poor mixing of fuel and air. The high CO emissions at high air flow
were caused by a high air stream velocity which tended to agitate the fuel
bed and quench CO combustion to CO . The highest CO level for "normal"
operating conditions was 550 ppm (corrected to 3% O ), but this was under
a low load condition. The average CO level for "normal" operation was 226
ppm (corrected to 3% O ).
156
-------
2800
2400
_ 2000
CM
<*>
n
5 1800
I
ft
1200
800
400
0
16
/\ Eastern Coal
O Western Coal
11111
8 10 12 14
EXCESS OXYGEN, percent
16
18
Figure 5.4-6. SO emissions vs. excess Q-, University of Wisconsin,
Eau Claire.
157
-------
100
80
* 60
& 40
20
^ Eastern Coal
O Western Coal
(3.4 kg/s)
(2.8 kg/s)
8 ~~
12
(1.9 kg/s
34
(1.9 kg/s)
15 (2.4 kg/s)
10 12 14
EXCESS OXYGEN, percent
16
18
20
Figure 5.4-7. SO component of SO emissions, University of Wisconsin,
Eau Claire.
158
-------
1400
1200
1000
* 800
o
u
600
400
200
D High Load - 5.4-6.2 kg/s
(43-49x103 lb/hr)
A Medium Load - 2.3-3.4 kg/s
(18-27xl03 lb/hr)
O Low Load - 1.9 kg/s
(15xl03 lb/hr)
xfl
31
g29 |32g22
o
15
8 10 12" 14
EXCESS OXYGEN, percent
16
18
Figure 5.4-8. Carbon monoxide emissions vs. excess O
Wisconsin, Eau Claire, eastern coal.
, University of
159
-------
The CO emissions for western coal, Figure 5.4-9', do not show a
definite relationship to excess O levels; however, it can be seen that the
CO levels increase as the unit load increases. This situation is opposite
to the trends observed on eastern coal. The reason for this change is the
extremely poor combustion conditions which were present at medium and high
load ranges while burning the western coal. The CO levels varied from 48
to 1143 ppm (at 3% 0 ) depending on the load and the condition of the fuel
bed during the test.
5.4.8 Excess O
The excess air in this type of unit is generally higher than for
pulverized coal or spreader stoker units because there are more places where
the air can get by the fuel without mixing, e.g., near the side walls and
through air dampers which are under the back portion of the grate where the
fuel bed has already been burned out.
The excess air also tends to be higher at low loads for the same
reasons. At low loads the fuel bed is very short and a large percentage of
the grate is available for air to get through leaky air dampers. As the
load is increased, the fuel bed lengthens, covering more of the grate
and causing more turbulence and better mixing of air and fuel particles above
the grate.
5.4.9 Particulates
Table 5.4-5 is a summary of all the particulate tests which were
run at the University of Wisconsin-Eau Claire. Loads, excess 03 levels,
fuel types, and particulate emissions for each test by the total and EPA Method
5 procedures are indicated. The total particulates are the sum of the weights
of the filter after a 616 °K (650 °F) bake, the impinger water catch, the
probe, cyclone, flask, and filter holder top rinsings, and the particulate
collected in the flask. All rinsings were done first with acetone and then
with water. All liquids were boiled down and dessicated to dryness before
weighing. The Method 5 EPA particulates are the sum of the weights of the
160
-------
600
500
O
*>
400
S
0)
4J
M
O
O
300
a
200
8
100
21
Qnigh Load - 3.8-4.4 kg/s
(30-35xl03 Ib/hr)
10
. Load - 3.2 kg/s
(25xl03 Ib/hr) Q
Low Load - 1.9-2.3 kg/s
(15-18xl03 Ib/hr) Q
D9
D7
A4
O5
D1
6 8 10 12
EXCESS OXYGEN, percent
14
Figure 5.4-9. Carbon monoxide emissions vs. excess 0 , University of
Wisconsin, Eau Claire, western coal.
161
-------
TABLE 5.4-5. PARTICULATE EMISSIONS DATA SUMMARY FOR EAU CLAIRE
Test
No .
2X
3
5
7
8
9
10
11
14
17
19
27
28
30
32
33t
Steam Load
kg/s (103 Ib/hr)
3.2 25
3.8 30
2.3 18
4.4 35
4.0 32
4.4 35
4.2 33
1.9 15
1.9 15
3.2 25
2.3 18
3.2 25
2.3 18
6.2 49
5.4 43
1.9 15
°2
(%)
7.7
7.1
10.6
9.8
9.7
10.5
10.6
13.2
15.7
11.7
15.1
10.1
9.8
6.6
6.7
12.2
Fuel
Western coal
Western coal
Western coal
Western coal
Western coal
We stern coal
Western coal
Eastern coal
Eastern coal
Eastern coal
Eastern coal
Eastern coal
Eastern coal
Eastern coal
Eastern coal
Eastern coal
Particulate Emissions
Ib/MBtu
Total
0.2574
0.2175
0.2414
0.3394
0.4899
0.6930
0.9045
0.3986
1.3327
0.4285
1.3129
0.8870
0.3504
2.7557
0.6925
0.3251
EPA
0.1786
0.1456
0.1586
0.2743
0.3620
0.6501
0.7643
0.3081
1.1911
0.4188
1.2333
0.8884
0.3046
2.1353*
0.5835*
0.2800
g/Mcal
Total
0.4622
0.3926
0.4335
0.6120
0.8841
1.2488
1.6297
0.7165
2.4059
0.7728
2.3633
1.5986
0.6325
3.8929
1.2471
0.5877
EPA
0.3226
0.2617
0.2867
0.4942
0.6520
1.1711
1.3770
0.5546
2.1448
0.7543
2.2203
1.600
0.5485
3.8442*
1.0510*
0.5044
ng/J
Total
110.42
93.79
103.56
146.20
211.20
298.33
389.33
171.17
574.75
184.62
564.57
381.88
151.10
929.98
297.93
140.40
EPA
77.07
62.52
68.49
118.06
155.76
279.77
328.96
132.49
512.37
180.20
530.42
382.18
131.03
918.35*
251.07*
120.50
Sulfates
33.35
31.27
35.07
28.14
55.44
18.56
60.37
38.68
62.38
4.42
34.15
-0.3
20.07
11.63
46.86
19.9
to
*No 419 °K (250 °F) bake weight available for EPA Method 5 calculation.
No blank filter weight available.
-------
filter after a 394 °K (250 °F) bake, the probe, cyclone, flask, and filter
holder top rinses, and the participates collected in the flask. The rinsings
were done only with acetone. The liquid was boiled down and dessicated to
dryness before weighing.
Figures 5.4-10 and 5.4-11, particulate emissions by EPA Method 5 vs.
excess 02 and load respectively, indicate that at a constant excess O2 level,
an increase in load will result in an increase in particulate emissions and,
similarly, at a constant load level an increase in excess 02 will result in
an increase in particulate emissions. These results are valid for both the
eastern and western coal except for the medium load range [3.2 kg/s (25xl03
Ib/hr) steam flow] with eastern coal where the particulate emissions were
higher at the lower excess O level.
Test numbers 30 and 31 do not follow the EPA Method 5 procedures in
that the filters were baked at 616 °K (650 °F) before they were weighed, this
may have resulted in slightly lower weights. Test number 30 also differs con-
siderably from the other tests in the amount of particulate matter collected
by the cyclone separator and flask. The particulate matter collected was
nearly three times the weight of that collected in any of the other tests.
Examination of the raw data does not show any discrepancies in procedure so
the result has been included in the data presentation.
5.4.10 Efficiency
The unit efficiency varied from 69.34% to 78.51% on eastern coal
and from 69.89% to 78.34% on western coal. Efficiencies were calculated for
only a selected number of tests. Figure 5.4-12 shows the variation of effi-
ciency with load for both coals. Referring to this figure, the change in
efficiency with increasing load is similar for both eastern and western
coals for loads ranging from 1.9 to 3.8 kg/s (15 to 30x10 Ib/hr) steam flow.
At loads above 3.8 kg/s (30xl03lb/hr) steam flow, the unit efficiency on
eastern coal remains constant at approximately 78% while the unit efficiency
on western coal drops dramatically at loads between 3.8 and 4.4 kg/s
163
-------
1000
800
1-3
c
O 600
H
to
CO
H
S
W
400
p
u
H
FM 200
V30
A
31
27/
2S
.10
17
A
o
A33 A11
Western Coal
Eastern Coal
19,
8 10 12 14
EXCESS OXYGEN, percent
16
18
Figure 5.4-10. Particulate emissions vs. excess 0 , University of Wisconsin,
Eau Claire.
164
-------
1000
'si 800
03
§
w 600
H
I 4°°
U
H
|J
S5 200
O Western Coal
^ Eastern Coal
14
A
19
A2
27
O
,10
80 o'
33
50
66
"—\A
0 16 jj -j^j wv-/
PERCENT OF RATED LOAD [7.6 kg/s (60x10 Ib/hr)]
0A
84
Figure 5.4-11. Particulate emissions vs. percent rated load, University of
Wisconsin, Eau Claire.
165
-------
80
78
76
u
s-l
&
74
U
@ 72
H / *•
U
H
W
70
68
0 v 16
'30
Poor
Combustion
O Western Coal
/\ Eastern Coal
33
50
66
PERCENT OF RATED LOAD [7.6 kg/s (60x10 Ib/hr)]
Figure 5.4-12. Boiler efficiency vs. percent rated load, University of
Wisconsin, Eau Claire.
166
-------
(30 and 35x10 lb/hr) to only 70%. The drop in efficiency on western coal was
the result of higher stack gas temperatures, higher excess ^ levels, and
higher gas velocities. These conditions were created by the need to force
more air through the fuel bed to try to improve the very poor combustion
which was experienced with western coal.
5.4.11 Operational Difficulties
Because this unit is part of a central heating unit, the loads were
affected a great deal by the ambient temperature. It was necessary for the
plant personnel to switch fuels on four occasions in order for the KVB crew
to obtain as complete a test as possible with the load conditions that were
available.
Testing began on western coal with loads of 3.2 kg/s (25xl03 lb/hr)
steam flow. The load was then increased to 4.4 kg/s (35x10 lb/hr) steam flow
by venting steam through the roof of the building. This practice is very
expensive for the plant and was halted after several tests. The unit was then
loaded with eastern coal as there was insufficient load to continue testing
3
western coal. Tests in the 1.9 to 3.4 kg/s (15 to 27x10 lb/hr) steam flow
range were run on the eastern coal. The plant load began to increase at this
point so the unit was reloaded with western coal and attempts were made to
run high loads [> 4.4 kg/s (35x10 lb/hr) steam flow]. The tests were dis-
continued because of operational problems. The unit was reloaded with eastern
coal and a series of low, medium, and high load tests were run to complete
the test schedule.
No operational difficulties with eastern coal burning were experienced.
The eastern coal was easy to handle, it stored well, did not clog the conveyor
system, did not show a tendency to segregate, and fed easily into the unit.
The coal sizing was good with few fines. It exhibited good ignition character-
istics with ignition occurring under the arch uniformly across the boiler.
The tendency of this coal to swell encouraged the combustion which was very
uniform and the fuel bed burned out at the end of the active undergrate air zones
167
-------
with no carryover of fuel into the ash pits. Some clinkers did form and
carry into the ash pits but these were easily removed. The ash bed following
the burning zone was sufficiently heavy to protect the grate from overheating.
Overall, the unit operated very well on eastern coal. It responded well,
there were no problems with load swings, and the fire could be banked easily.
The major problem on this unit is the lack of precise control over the fuel
bed length where the air damper sections are long, in grate sections 3 and
4 from the front of the unit. This could be solved by dividing each of these
sections into two separate air dampers. A modification such as this would
also help in the burning of western coal; however, the problems on western
coal were quite severe and even improved air damper controls might not insure
proper combustion.
The western coal was as easy to store and feed into the boiler as
the eastern coal; however, there were very severe problems associated with
burning the western coal. The unit was set up with the bed thickness at
17.8 to 19.0 cm (7.0 to 7.5 in.) which is about 6.5 cm (3 in.) more than is
common on eastern coal. The coal feeder was set on manual and the stoker
air dampers were set for more air at the rear of the grate. Ignition of the
western coal was poor; it did not occur under the ignition arch. When igni-
tion occurred it was not uniform across the width of the boiler. The area
of poor ignition was followed by poor combustion in the main section of the
boiler. The areas of the fuel bed which contained fines would burn out
creating holes through which the combustion air would pass without mixing
with the rest of the fuel bed. This in turn would leave large masses of
unburned fuel in the boiler. On many occasions, even by manual raking the
fuel bed and opening extra air dampers beneath the fuel bed, these masses of
unburned coal were carried into the ash pit where they would burn, causing a
safety hazard. In situations where it was possible to burn out the fuel before
it reached the ash pit, the grate coverage of the ash from the western coal was
not sufficient to protect the grate from overheating. The overall unit opera-
tion on western coal was very poor. It was characterized by a large decrease
in unit capacity [limited to 4.4 kg/s (35x10 Ib/hr) steam flow compared to
6.3 kg/s (50x10 Ib/hr) for eastern], a dramatic decrease in unit efficiency
(from 78 to 70%), and a significant increase in operational manpower.
168
-------
5.5 UNIVERSITY OF WISCONSIN, MADISON
The boiler tested was Boiler No. 2 of the Central Heating Plant on
the University of Wisconsin campus located in Madison, Wisconsin.
The boiler was manufactured by Babcock and Wilcox in 1952. The name-
plate rating of this boiler is 12.6 kg/s (100,000 Ib/hr steam). The boiler,
which is depicted in Figure 5.5-1, is fired with a Westinghouse Centrafire
spreader stoker with a traveling grate, and is a balanced draft unit. Other
specifications are as follows:
o Design pressure - 4.9 MPa (700 psig)
o Steam temperature - 656°K (720°F)
o Actual day-to-day operating pressure - 4.2 MPa (600 psig)
o Boiler heating surface - 131.18 m (1412 sq.ft)
2
o Economizer heating surface - 518.12 m (5577 sq.ft)
o Stoker grate size - 4.038 m x 4.94 m (13' 3" x 16' 2-1/2")
o Stoker grate area - 19.96 m (214.8 sq.ft)
Base Coal - Vogue, Southern Illinois, Stonefort
Western Coal - Montana Colstrip
5.5.1 Unit Operation
Coal enters the stoker from a hopper above the stoker which is fed
by a conveyor system from the coal bunker. Coal is discharged by the feeder
to a rotary spreader which throws the coal into the furnace and distributes
it uniformly over the grate. Three Westinghouse Centrafire feeders are
used with this boiler. The finer particles of fuel burn in suspension and
the coarse particles fall to the surface of the fuel bed. The grate surface,
with an area of 19.96 m2 (214.8 sq.ft.) travels from rear to front with ash
discharge at the front. Control of coal feed rate distribution over the
grate is by adjustment of rotor speed and spill plate adjustment. Overfire
air is supplied by a separate blower and can be controlled with a damper.
169
-------
EOUAU1ER
SPILL PL ME
CONSTANT
VELOCITY
PAIRED RAMS
FEED RAM
HYDRAULIC
ENGINE
AIR COOLED DISTR\BUTING ROTOR
SILL NOZZLES
Figure 5.5-1. Westinghouse Centrafire spreader stoker with traveling grate.
-------
Hot combustion gases travel upward in the furnace. At the top of the
boiler, the gases begin a downward pass through an economizer section and then
upward through a duct to a common breeching to the stack.
The unit has no dust collection device as such; fly ash drops out
at the end of the economizer pass before the flue gases enter the ID fans
and is removed by a pneumatic system.
5.5.2 Emission Data
A summary of the emission data is presented in Table 5.5-1 for both
western and eastern coal.
The testing was begun with western coal (Montana Colstrip) and the
boiler at 7.56 kg/s (60,000 Ib/hr) steam output. The boiler was operating in
the normal or "as-found" condition. Tests were conducted at three loads -
11.3, 7.56, and 3.78 kg/s (90, 60, and 30xl03 Ib/hr) steam. At each load
the excess O was varied from a "normal" to a higher and lower value if
possible. At the high load, O variation was limited by the capacity of
the induced draft fan. At low load conditions, the bed was very thin or
areas of the grate were not covered with coal, so that the 0 could not be
lowered below about 13.5% O . No control of the undergrate air was possible
except for the damper on the forced draft fan. Figure 5.5-2 is a plot of excess
oxygen as a function of boiler load when firing Montana Colstrip coal. A
line is drawn through the points representing the normal O^ condition. The
range of 0 variation possible at each load point is shown. Figure 5.5-3 pre-
sents the same information for the Illinois Stonefort coal.
The effect of excess O on NO is shown in Figures 5.5-4 and 5.5-5 for
western and eastern coals respectively. Both coals exhibited significant
reduction in NO with decreasing O . Western coal showed a reduction of
34% in NO for a 3.5% reduction in 00. A 3% decrease in 0 when firing
x 2 ^
eastern coal resulted in a reduction of 26% in NO . Carbon monoxide as
a function of excess oxygen is presented in Figures 5.5-6 and 5.5.7 for eastern
and western coals respectively. High CO levels were measured with both
171
-------
TABLE 5.5-1. EMISSION DATA SUMMARY, UNIVERSITY OF WISCONSIN-MADISON, UNIT 2
Test
No.
Date
Load
Kg/s
(103lb/hr)
°2
percent
CO
(ppm)
co2
NO (dry)
(ppm)
NO * (wet)
(ppm)
Percent
Combust.
Particulates
(ng/J)|(lb/MBtu)
SO
X
(ppm)
S0x
(ng/J)|(lb/MBtu)
Fuel S
(ng/J)
(Ib/MBtu)
Sulfur
Retention
Factor,
oercent
WESTERN COAL
1
2
3
4
5
6
7
8
9
10
1-13-76
1-13-76
1-14-76
1-14-76
1-15-76
1-16-76
1-21-76
1-22-76
1-22-76
1-23-76
Average
7.56
7.56
7.56
7.56
11.33
11.33
3.78
10.08
10.08
3.78
7.06
60
60
60
60
90
90
30
80
80
30
64
7.9
6.5
10.9
11.4
7.2
7.5
13.6
9.7
6.2
13.5
9.44
111
36
309
716
426
291
1619
634
380
1244
577
11.0
12.3
10.1
8.6
12.1
12.3
6.7
10.8
11.5
7.4
341
321
485
593
446
435
403
482
294
406
420
NA
308
447
593
424
—
396
417
274
422
23.16
20.26
15.65
44.7
27.98
16.42
36.05
49.14
29.17
NA
388
447
429
888
742
451
897
725
618
NA
0.903
0.949
1.00
2.07
1.73
1.06
2.09
1.69
1.44
1051
1808
1121
1146
600
1540
1576
1407
1281
862
919
492
1155
857
2.01
2.14
1.147
2.69
1.997
953
719
908
1224
951
2.22
1.677
2.115
2.85
2.216
90.5
122
54
94
90
-J
ro
EASTERN COAL
11
12
13
14
15
16
17
18
19
1-26-76
1-26-76
1-27-76
1-28-76
1-29-76
1-29-76
1-30-76
2-2-76
2-2-76
Average
Difference of
Western and
Eastern/ %
7.56
7.56
7.56
11.33
11.33
11.33
3.78
7.56
3.78
7.17
60
60
60
90
90
90
30
60
30
63
10.0
12.0
7.8
7.3
9.1
10.3
14.7
11.3
15.8
10.98
-14
29
200
0
1106
215
236
484
13
1275
445
+23
10.3
8.4
11.5
11.1
10.3
9.4
6.9
9.1
6.4
450
511
401
379
436
505
404
445
508
449
-6
464
538
411
397
454
540
404
517
519
44.9
49.13
51.22
49.64
46.37
47.56
56.61
45.63
48.89
-40
674
1060
455
738
644
880
605
584
704
-12
1.57
2.47
1.06
1.72
1.50
2.05
1.41
1.36
—
1.64
2085
2146
—
2119
2345
—
3094
—
2963
2458
-48
1711
1739
1924
2431
1952
-56
3.99
4.053
4.484
5.665
4.548
2119
2195
2215
2144
2168
-56
4.937
2.114
5.162
4.995
5.052
80.8
79
86.9
112
90
*Corrected for low converter efficiency.
-------
20
•P
g 15
V4
<0
04
10
W
CO
w
w
(10)
Rated Load = 12.6 kg/s
(lOOxlO3 Ib/hr)
( ) Test Number
1
(4)
(6)1
V5—-TST
20 40 60
PERCENT OF RATED BOILER LOAD
80
Figure 5.5-2. Excess oxygen vs. boiler load, University of Wisconsin,
Madisonf Unit 2, Montana Colstrip coal.
173
-------
Rated Load =12.6 kg/s
(lOOxlO3 Ib/hr)
( ) Test Number
40 60
PERCENT OF RATED BOILER LOAD
Figure 5.5-3.
Excess oxygen us. boiler load, University of Wisconsin,
Madison, Unit 2, Illinois Stonefort coal.
174
-------
600
500
m
+J
<6
>t
M
2
g
400
300
200
100
10.1 kg/s
(SOxlO3 Ib/hrJ
11.3 kg/s
(90xl03 Ib/hr)
X
7.95 kg/s
(60x103 Ib/hr) / 4.04 kg/s
130xl03lb/h»
4 6 8 10 12
EXCESS OXYGEN, percent
14
16
Figure 5.5-4. Nitric oxide vs. excess oxygen, University of
Wisconsin, Madison, western coal.
175
-------
600
500
-------
2000
1500
CN
o
n
^3
ft
ft 1000
H
1
500
1
O 7.6
D 3.8
kg/s
kg/s
kg/s
1
(90xl03
(60xl03
(30xl03
1 1 1 1
Ib/hr)
Ib/hr)
Ib/hr)
1
6 ~8 10
EXCESS OXYGEN, percent
12
14
16
Figure 5.5-6. Carbon monoxide vs. excess oxygen, University of Wisconsin, Madison, eastern coal.
-------
-j
oo
2000,
1500
<*>
n
1
1000
500
H.3 kg/s (90xl0 Ib/hr)
10-1 k9/s (SOxlO3 Ib/hr)
O 7.6 kg/s (60xl03 Ib/hr}
Q 3.8 kg/s (30xl03 Ib/hr)
6 8
EXCESS OXYGEN, percent
10
12
14
16
Figure 5.5-7. Carbon monoxide vs. excess oxygen, University of Wisconsin, Madison, western coal.
-------
coals at high excess air, low load conditions. The high CO is due to
portions of the grate being uncovered which probably leads to quench.
ing and xncomplete combustion. Figure 5.5-8 shows the effect of boiler
load on NO emissions for both western and eastern coals.
Results of the particulate tests are presented in Figure 5.5-9 where
particulate loading as a function of boiler load is shown for both west-
ern and eastern coals. The numbers in parentheses refer to the excess
oxygen percentage for each test. The particulate loading is seen to be
higher for eastern coal at the low and intermediate loads and approxi-
mately the same as western coal at the high load condition. The sulfur
oxide test results are presented in Table 5.5-2. A summary of the SO data
was presented in Table 5.5-1 where average SO data are tabulated. Fuel
X
samples were taken for each test and were analyzed for sulfur content to
complete the analysis of this data.
The hydrocarbon instrument was inoperative until the last week
of testing so that no hydrocarbon data could be taken during the normal
test period. When the instrument was repaired, two days were used to
measure HC emissions with both western and eastern coals. The boiler
load was varied and HC measurements made at 3 loads: 5,0, .7.6, and 11.3 kg/s
(40, 60, and 90x10 Ib/hr). The hydrocarbon data show the same trend as the
CO data. At low load and high excess O , the unburned hydrocarbon emissions
increase. This is thought to be due to combustion quenching by the air.
The results of the HC measurements are shown below:
Eastern Coal Western Coal
Load HC
kg/s (103 Ib/hr) °2l ' (corr. ppm)
5.0
7.6
11.3
11.3
40
60
90
90
15.
12.7
9.7
8.7
114
54
48
44
o2(%)
13.8
11.3
—
8.8
HC
(corr . ppm)
125
18
—
44
179
-------
\J\J\J 1
500
""^,400
Q
dP
-P
10 300
g
a 200
Ul
g
100
0
1 1 | 1 i
(11
(15.8) Q (12
(10
(10
BV X -L
(7
(13.6)
(7
(6
•—
Rated Load = 12.6 kg/s
(lOOxlO3 Ib/hr) ( }
"~ * Solid
coal.
1 1 1 1 1
0 10 20 30 40 50
V 1
.4)
.'••')•
.9)0 (9.7)
.o) A
-8)W
'
.9)Q
.5)0
(6.2)
Excess Oxygen, %
1
(10.3)
o 1
(7.2) J
(9.1) I
(7.5) -4
(7.3) J
o -
^•""
symbols are eastern
1 1
60 70
1
80 9C
PERCENT OF RATED BOILER LOAD
Figure .5.5-8. Nitric oxide vs. boiler load, University of Wisconsin,
Madison, eastern and western coals.
180
-------
2.5
3
0)
o 2.0
o
H
H
~ 1.5
o
S3
H
§
z i.o
1
H 0.5
ft
0
i i I i i — v — i r
(12.0)
(9.7) O
(6.2) O
_ do.o) D
(14 7^ n ^^
•-1 (11.8) D
- (13. 6) O ([l\l] g
(10.9) (6.5)
- Rated Load =12.6 kg/s C } EXC6SS °2' %
(lOOxlO3 Ib/hr) O Western coal
Q Eastern Coal
1 1 1 t 1 1 1 1
(10. 8J
(7.24:
(7.5)C
(7.3JT
(9.3TU
^.^
—
10 20 30 40 50 60
PERCENT OF RATED BOILER LOAD
70
80
90
Figure 5.5-9. Particulate loading vs. boiler load, University of
Wisconsin, Madison.
181
-------
TABLE 5.5-2. SOX DATA SUMMARY
UNIVERSITY OF WISCONSIN-MADISON, UNIT NO. 2
°2
Test per-
No. kq/s (103lb/hr) cent
1A 1
IB > 7.6 60 7.7
1C J
3A 1
3B > 7.6 60 9.6
3C J
SA "I
SB 111. 3 90 7.2
5C J
6A "I 90 8.05
6B >11.3 90 8.0
6C J 90 6.9
7A -I
7B >3.8 30 13.5
7C J
8A T
8B >10.1 80 9.5
8C J
9A 1
9B VlO.l 80 6.7
9C J
10A 1
10B U.8 30 13.4
IOC J
11A 1
11B >7.6 60 10.0
11C J
12A 1
12B >7.6 60 12.0
12C J
14A "I
14B >11.3 90 7.3
14C J
ISA 1
1SB 111. 3 90 9.2
ISC J
17A -j
17B U.8 30 14.5
17C J
19A I IS- 5
19B >3.8 30 15.5
19C J 16.6
S02
(uncorr.
ppm)
854
632
842
1047
1168
1212
853
862
867
960
1021
699
247
238
250
977
986
981
1284
1223
1255
597
572
602
1188
1317
1312
1097
1039
1069
1505
1497
1809
1509
1533
1547
1004
1078
1152
1170
707
749
so3
(uncorr .
PPm)
2
2
2
9
7
7
2
3
2
4
5
4
4
5
6
5
5
6
8
7
6
2
4
6
3
9
8
2
4
8
8
11
20
—
17
18
8
13
3
6
5
6
SOX
(uncorr.
ppm)
WESTERN COAL
856
634
844
1056
1175
1219
855
865
869
964
1026
703
251
243
256
982
991
987
1292
1230
1261
599
576
608
EASTERN COAL
1191
1326
1320
1099
1043
1077
1513
1508
1829
1509
1550
1565
1112
1091
1155
1176
712
755
S02
(corr.
ppm)
1153
853
1137
1653
1833
1902
1108
1120
1127
1228
1306
887
593
571
600
1524
1538
1535
1605
1528
1568
1433
1316
1446
1936
2147
2138
2194
2078
2138
2031
1962
2315
2293
2338
2351
2780
2984
3455
3826
2312
2696
so3
(corr.
ppm)
3
3
3
14
11
11
3
4
3
5
7
5
10
12
14
7
7
9
10
9
8
S
9
13
5
15
13
4
8
16
11
14
26
—
26
27
21
35
8
20
16
22
SOX
(corr.
ppm)
-1156
856
1140
1667
1844
1913
1111
1124
1130
1232
1313
892
603
583
614
1531
1545
1544
1615
1537
1577
1438
1325
1459
1941
2162
2151
2198
2086
2154
2042
1976
2341
2293
2364
2378
2801
3019
3463
3846
2328
2717
Test Description
Medium load, normal O
t
Medium load, normal C>2
Medium load, normal O2
Medium load, high O2
Medium load, high O,
Medium load, high 0^
High load, normal 0^
High load, normal 0
High load, normal 0.
High load, normal O
t,
High load, normal O
High load, normal 0^
Low load, high O2
Low load, high O
Low load, high O
High load, high 0.
&
High load, high O
High load, high O
High load, low O
High load, low O2
High load, low 02
Low load, high O
Low load, high O_
Low load, high O
Medium load, normal O.
2
Medium load, normal 0.
Medium load, normal O_
Medium load, high O
Medium load, high O2
Medium load, high O
High load, low O2
High load, low O
High load, low O.
High load, normal O.
High load, normal O.
High load, normal 0.
Low load, high 0.
Low load, high 02
Low load, high O_
Low load, high O2
Low load, high 0,
Low load, high 0.,
182
-------
5.5.3 Summary of Operational Factors
Normal operation of the boiler when firing coal is conducted at a
high excess oxygen percentage to prevent smoking and to assure complete
burnout of the coal. When the low excess oxygen test at 7.6 kg/s (60xl03 Ib/hr)
was attempted, difficulties were encountered. The operator was requested to
lower the air to a level where the air pen and steam pen were coincident on
the control room chart. This condition had been satisfactory at a previously
higher load.
A patch of unburned coal formed at the rear of the furnace. The
low O2 (4.5% to 5.5%) condition was maintained and the unburned coal patch
increased xn size. The load then started dropping and the boiler would not
respond to load demand. Finally the air was increased to attempt to burn
out the unburned patches, but with no success. Grate speed was increased
to discharge the unburned coal before clinkers formed. The unburned coal
ignited when it dropped into the ash pit, making the pulling of ashes
dangerous.
At low to intermediate loads the furnace is not hot enough to ignite
the coal in suspension, allowing it to fall to the grate. At these loads
the air must be kept at a level to assure rapid heat release to maintain
ignition. Ignition of the coal is impaired by the low combustion air
temperature [256 to 240°K (0 to -20°F) ] and high moisture content of the
coal. Any unburned spots in the furnace can rapidly create a large mass
of unburned coal which is extremely difficult to burn out even with increased
excess air. When low excess O2 conditions are attempted, the coal bed must
be observed carefully to detect any unburned coal patches. If any patches
are detected, the test should be aborted and the excess O2 increased.
During a nontesting period, the traveling grate failed. It
appeared that the rear seal failed due to overheating and the broken
parts jammed the grate. A total of nine grate links were broken. Two
test days were lost while the unit was repaired.
183
-------
After the boiler was brought back on-line, the left feeder
spill plate appeared bent. The feeder-distribution is shown in Figure 5.5-
10 and the effect of spill plate position is shown in Figure 5.5-11.
At low load [3.8 gk/s (30x10 lb/hr)], a patch of unburned coal
accumulated toward the front of the furnace. The left side spill plate
was adjusted to try to reduce the coal accumulation in the front of the
furnace. The fire was situated too far forward in the furnace resulting
in bare grate in the rear. The coal size was such that the spreader could
not throw coal to the rear of the furnace through the hot forward zone.
Therefore, much of the coal burned in suspension resulting in bare grate
areas in the rear. The rotor speed was increased which improved the
situation somewhat.
The excess O at low load conditions could not be reduced
about 13% due to the open grate areas. Therefore, only one O. level W*6
tested at low load.
The coal trajectory is governed by several spreader variables
as shown in Figures 5.5-10 and 5.5-11. The variables include:
o spill plate setting
o rotor speed
o coal size/density
o rotor blade pitch/size
During the testing on eastern coal, extreme smoking occurred when the
0 was reduced too far. At the high load setting, the 0_ could not be
reduced below 7.5% without the smoke indicator pegging upscale. At 6%
O_, the CO instrument was off scale (>2,000 ppm) and the smoke indicator
was pegged at 100%. During all tests on eastern coal, the fire in the
furnace was much smokier than with western coal. An uneven bed thick-
ness on the grate will cause the unit to smoke with eastern coal even
at normal O_ levels.
184
-------
EQUALIZER
NOTCHED PLKTE
SPILL PLATE
FUEL FEED RAMS
ROCKER
\
SILL NOZZLES
FUEL FEED ENGINE
FEEDER-DISTRIBUTOR
DRIVEN
FEEDER
DIAGRPM OF
FUEL FEED DR\VE
DRIVING
FEEDER
AD3USTABLE
RADIUS
DRIVE ARM
TO
ADDITIONAL
FEEDERS
OF USED)
ADJUSTABLE
LENGTH CON-
NECTING LINK
Figure 5.5-10.
Feeder distribution and fuel feed drive,
185
-------
-v
SP1LL PLATE. MOVED AWAY
FROM CENTER OF ROTOR
*
\
SPILL PLATE MOVED TOWARD
CENTER OF ROTOR
FINE FUEL
PLAN OF
SPILL PLATE.
Figure 5.5-11. Effect of spill plate position.
186
-------
5.5.4 Efficiency Comparison of Eastern and Western Coals
Table 5.5-3 compares boiler efficiencies while burning eastern (Test 14)
and western (Tests 5 and 6) coal at the same load and excess O with com-
parable combustible losses. The main differences in efficiency occur in
the dry gas and moisture losses. The dry gas contribution is larger because
of the greater amount of the lower Btu western coal that must be fired to
maintain load. The moisture contribution is due to the higher moisture con-
tent of the western coal. Test 6 was at comparable boiler conditions to
Tests 5 and 14 except for combustible losses which were half. Based on the
averages of combustible losses for both coals in Table 5.5-1, the western coal
had 40% lower losses. When this is coupled with the average 12% lower par-
ticulate emissions, combustible losses out the stack are better than 50%
lower for the western coal. Thus Test 6 offers a fair comparison of unit
efficiencies under typical western coal firing conditions. This comparison
shows that the lower combustible losses affect the higher dry gas and
moisture losses for western coal. The overall unit efficiency is unimpaired
by the fuel change.
TABLE 5.5-3. COMPARISON OF BOILER EFFICIENCY ON EASTERN AND WESTERN COAL
Test No.
Test Load
kg/s
103 Ib/hr
% of Capacity
Stack 0 (% Dry)
Stack CO (ppm)
Stack Temp (°K/°F)
Ambient Air Temp (°K/°F)
Corr. Stack Temp (°K/°F)
Boiler Heat Bal Losses (%)
Dry Gas
Moisture + H
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency %
14 (eastern)
11.3
90
90
7.3
1106
450/350
267/20
450/350
6.84
4.92
0.17
0.47
8.57
0.63
78.40
5 (western)
11.3
90
90
7.2
426
422/490
29/272
422/490
8.87
7.91
0.21
0.19
8.37
0.63
73.82
6 (western)
11.3
90
90
7.5
291
410/483
16/264
410/483
9.18
7.88
0.22
0.14
4.02
0.63
77.93
187
-------
The efficiency data for both eastern and western coal is contained in
Table 5.5-4. These data are plotted as a function of excess O in Figure 5.5-12
and as a function of load in Figure 5.5-13. At all excess 0 levels the western
coal had higher boiler efficiencies. This was due to the lower combustible
losses which affect the higher dry gas and moisture losses. The efficiency
as a function of load for both coals was almost the same at high and medium
loads, however at low load the eastern coal efficiency was four percentage
points lower than the western due to large combustible losses.
5.5.5 Conclusions
In general, the stoker at University of Wisconsin/Madison performed
well on both eastern and western coals. There were no significant opera-
tional problems on either coal that would preclude their use. Maximum rated
load was attained on each coal without difficulty.
From an emission standpoint, the western coal had an average of 48%
lower SO emissions, 12% lower particulate emissions, a 40% reduction in
X
combustible in the fly ash, and a 6% reduction in NO emissions; CO emissions
were 23% higher however. The western coal could be fired at an average of
14% lower excess O than the eastern coal. From a boiler efficiency stand-
point, this lower excess air requirement offsets the additional moisture
content of the western coal which resulted in comparable boiler efficiencies
of some 78% at high load. In addition, the lower combustible losses for
western coal helped improve the efficiency of western coal.
Based on fuel analyses and gaseous emissions measurements of SO
it was calculated that on the average, the western1 coal emitted 99.5% of
the sulfur contained in the coal whereas the eastern coal emitted 93% of
the fuel sulfur.
188
-------
TABLE 5.5-4. CALCULATION OF EFFICIENCY
Location No.
Boiler No.
Furnace Type
Unit Description
5 (UW/Madison)
2
Wt
Western Coal
Fuel Analysis (%)
Capacity
kg/s 12.6
103 Ib/hr 100
MBtu/hr 113
Installed 1952
Erection Method Field
Burner Type SS
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
H20
Ash
HHV/(Btu/lb)
MJ/kg
51.09
3.35
10.45
0.78
0.73
25.28
8.29
8704
20.2
Test No.
Test Load
kg/s
103 Ib/hr
% of Capacity
Stack O (% Dry)
£t
Stack CO (ppm)
Stack Temp (°K/°F)
Coal
Boiler Conditions
7.6
60
60
6.5
36
462/372
270/26
462/372
7.6
60
60
10.9
309
467/380
267/24
467/380
7.6
60
60
11.4
716
479/402
268/22
479/402
11.3
90
90
7.2
426
490/422
272/29
490/422
11.3
90
90
7.5
291
483/410
264/16
483/410
Boiler Heat Balance Losses (%)
Dry Gas
Moisture + H2
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency* *
Corrected to 300°K (80°F)
7.65
7.77
0.18
0.02
3.12
0.94
11.19
7.79
0.27
0.20
2.63
0.94
12.70
7.85
0.31
0.48
1.92
0.94
Entering Air Temp
8.87
7.91
0.21
0.19
8.37
0.63
9.18
7.88
0.22
0.14
4.02
0.63
80.32
76.98
75.80
73.82
77.93
189
-------
TABLE 5.5-4 (continued)
Unit Description
Eastern Coal
Fuel Analysis (%)
Location No.
Boiler No.
Furnace Type
Capacity
kg/s
103 Ib/hr
MBtu/hr
Installed
Erection Method
Burner Type
5 (UW/Madison)
2
WT
12.6
100
113
1952
Field
SS
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
H2°
Ash
HHV/(Btu/lb)
MJ/kg
66.32
4.62
7.71
1.30
3.07
7.37
9.60
12006
27.9
Coal
Boiler Conditions
7.6
60
60
10
29
467/380
264/16
467/380
7.6
60
60
12
200
478/400
266/18
478/400
7.6
60
60
7.8
0
450/350
259/6
450/350
11.3
90
90
7.3
1106
450/350
267/20
450/350
11.3
90
90
9.1
215
489/420
263/15
489/420
Test No. 11 12 13 14 15
Test Load
kg/s
103 lb/hr
% of Capacity
Stack O (% Dry)
Stack CO (ppm)
Stack Temp (°K/°F)
Ambient Air Temp (°K/°F) 264/16
Boiler Heat Balance Losses (%)
Heat Balance Losses Corrected to 300°K (80°F) Entering Air Temp
Dry Gas
Moisture + H
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency, % 77.12 72.96 77,77 78.40 76.39
9.60
4.98
0.23
0.02
7.11
0.94
12.26
5.01
0.30
0.13
8.40
0.94
7.07
4.92
0.17
0
9.13
0.94
6.84
4.92
0.17
0.47
8.57
0.63
10.06
5.05
0.24
0.11
7.52
0.63
190
-------
TABLE 5.5-4 (continued)
Unit Description
Eastern Coal
Fuel Analysis (%)
Location No.
Boiler No.
Furnace Type
Capacity
kg/s
103 Ib/hr
MBtu/hr
Installed
Erection Method
Burner Type
5 (UW/Madison)
2
WT
12.6
100
113
1952
Field
SS
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
H2°
Ash
HHV/ (Btu/lb)
MJ/kg
66.32
4.62
7.71
1.30
3.07
7.37
9.60
12006
27.9
Coal
Boiler Conditions
16
17
18
11.3
90
90
10.3
236
494/430
269/24
494/430
3.8
30
30
14.7
484
444/340
266/18
444/340
7.6
60
60
11.8
13
467/380
258/4
467/380
Test No.
Test Load
kg/s
103 Ib/hr
% of Capacity
Stack O (% Dry)
Stack CO (ppm)
Stack Temp (°K/°F)
Ambient Air Temp (°K/°F)
Corr. Stack Temp (°K/°F)
Boiler Heat Balance Losses (%)
Heat Balance Losses Corrected to 300°K (80°F) Entering Air Temp
Dry Gas
Moisture + H_
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency, %
11.43
5.07
0.28
0.13
7.89
0.63
13.54
4.90
0.33
0.44
11.35
1.88
11.40
4.98
0.28
0.01
7.30
0.94
74.58
67.57
75.10
191
-------
TABLE 5.5-4 (continued)
Unit Description
Location No.
Boiler No.
Furnace Type
Western Coal
Fuel Analysis (%)
5 (UW/Madison)
2
Wt
Capacity
kg/s 12.6
103 Ib/hr 100
MBtu/hr 113
Installed 1952
Erection Method Field
Burner Type SS
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
H20
Ash
HHV/(Btu/lb)
MJ/kg
Coal
Boiler Conditions
8 <
3.8
30
30
13.6
1619
476/380
270/26
467/380
10.1
80
80
9.7
634
492/425
263/14
492/425
10.1
80
80
6.2
38
472/390
266/19
472/390
51.09
3.35
10.45
0.78
0.73
25.28
8.29
8704
20.2
Test No.
Test Load
kg/s
10§ Ib/hr
% of Capacity
Stack O (% Dry)
Stack CO (ppm)
Stack Temp (°K/°F)
Ambient Air Temp (°K/°F) 270/26
Boiler Heat Balance Losses (%)
Heat Balance Losses Corrected to 300°K (80°F) Entering Air Temp
Dry Gas
Moisture + H
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency, %
15.10
7.79
0.37
1.40
2.03
1.88
11.15
7.92
0.27
0.35
5.84
0.71
7.37
7.82
0.18
0.02
10.01
0.71
71.43
73.77
73.91
192
-------
90
85
-P 80
Q>
O
^
0
u 75
w
H
O
H
Pn
En
W
H
80
75
70
Rated Load = 12.6
(lOOxlO3 Ib/hr) steam
Eastern coal at 7% HO
Western coal at 25% HO
10
15
20
EXCESS OXYGEN, percent
Figure 5.5-12. Boiler efficiency vs. excess O , University of Wisconsin, Madison.
-------
90
85
80
fi
dJ
D
I
u
H
H
H
£>
75
70
65
60
l r
— 12.6 kg/s (100x10 Ib/hr) Spreader Stoker
O Eastern coal at 7% HO
Western coal at 25% HO
J
10 20 30 40 50 60
PERCENT OF RATED LOAD
70
80
90
100
Figure 5.5-13. Efficiency vs. load, University of Wisconsin, Madison.
-------
5.6 WILLMAR MUNICIPAL UTILITIES COMMISSION
5.6.1 Boiler Description
The fourth boiler tested was Unit #3 of the Willmar Municipal Utilities
Commission located in Willmar, Minnesota. The boiler is of the two drum
Stirling type built by Babcock and Wilcox in 1960. The nameplate rating for
the boiler is 20.2 kg/s (160,000 Ib/hr) steam flow. The unit is fired by
six spreader stoker feeders supplied by the Detroit Stoker Company. They are
described in the next section. The stoker is equipped with a front end dis-
charge traveling grate. Figure 5.6-1 contains the layout and elevation of
Unit #3.
The boiler is balanced draft and combustion air is supplied from under-
neath the grate by a forced draft fan. The undergrate air plenum is
divided into two sections which are adjustable with an air damper. Grate
combustion air can be biased left to right across the,stoker. The negative
draft of the furnace is supplied by an induced draft fan located between the
air preheater and smoke stack.
The boiler has an economizer and a pendant type superheater. Combus-
tion air is preheated by a tubular type air preheater located between the
induced draft fan and the dust collector. The air preheater was found to be
defective during testing, this caused a fraction of the incoming air to be
"short circuited" through the air heater and out the stack.
Fly ash is removed with a Western Precipitator Multiclone dust
collector. This mechanical type cyclone dust collector is located between
the economizer and the air heater. The steam produced is superheated and
used both for electrical power generation and for direct heating. The
following data applies to this unit:
Based on 27.9 MJ/kg (12,000 Btu/lb) Southern Illinois coal
(April 1961)
. Maximum continuous steam output - 20.2 kg/s (160,000 Ib/hr)
. Efficiency - 87.78%
195
-------
GAS
OUTLET
12.6 m
(41'3")
4.88 m
Figure 5.6-1. Unit 3, Willmar Municipal Utilities Commission, Willmar,
Minnesota.
196
-------
. Based on 19.2 MJ/kg (8,240 Btu/lb) Montana coal (December 1972)
. Maximum continuous steam output - 16.4 kg/s (130,000 Ib/hr)
. Efficiency - 82.63%
Steam conditions at superheater outlet
Temperature - 672 °K (750 °P)
. Pressure - 2.9 MPa (425 psi)
Design Pressure - 6.8 MPa (1000 psi)
. Heating Surfaces
. Boiler - 1.316xl03 m2 (14,168 ft2)
. Water Wall - 20xl02 m2 (2,158 ft2)
. Superheater, primary - 3.5x10 m2 (3,778 ft2)
. Superheater, secondary - 1.61xl02 m2 (1,731 ft2)
. Economizer - 3.95xl02 m2 (4,250 ft2)
. Air heater - 1.21xl03 m2 (13,030 ft2)
5.6.2 Stoker Description
Willmar Boiler #3 is fired by a Detroit Stoker Company Rotograte spreader
stoker. Figure 5.6-1 includes a side view of the stoker. This stoker is
fired by six individual feeders. Raw coal leaves the bunker and is weighed
by two coal scales as the coal is divided into a left and a right feed stream.
After the coal scales (left and right) , the coal enters left and right coal
distributors. Each distributor supplies raw coal to three feeders. From the
distributor, coal enters each stoker feeder.
Each feeder can be independently adjusted to distribute coal on the
grate. Three mechanisms give this control. First, is a spill plate adjust-
ment which regulates the point at which coal is dropped onto the rotating
paddle wheel. The second, is the length of stroke of the feed plate which
pushes the coal over the spill plate. The third, is the rotor speed.
Additionally, the fuel bed thickness can be controlled by the speed of the
traveling grate.
197
-------
5.6.3 Sampling Locations
Willmar Unit #3 is equipped with a Western Precipitator Multiclone
cyclone type dust collector. Sampling sites were selected such that inlet
and outlet data and emission characteristics were obtained for the collection
device. The inlet sampling plane, located just upstream of the cyclone in
the inlet breaching, was the only area available to obtain inlet data due to
the duct configuration of the boiler. Figure 5.6-2 presents a cross sectional
diagram of the inlet sampling site. This site was somewhat unsuitable for
particulate measurements due to its nearness to an upstream bend in the
ducting. Some of the inlet particulate data is questionable, however the
gaseous data is accurate. Figure 5.6-3 presents the cross sectional view of
the inlet sampling probe locations. The duct was wide but narrow. Twelve
probes were installed for gaseous emission testing and of these twelve stain-
less steel probes, six were equipped to measure hot line data. The twelve
probes were installed in six ports, two in each port. Twelve 3/8 inch
diameter type-T nylon sample lines connected the sample probes to the mobile
test lab. Sampling took place during the middle of winter in the cold
prairie section of Minnesota. The sections of sample lines that were outside
the building were insulated with fiberglass insulation and wrapped with a
pipe heating tape. The entire sample line bundle was covered with a water-
proof plastic liner to protect it from moisture.
An existing location in a section of breeching between the ID fan and
chimney was used for the outlet sample site (Fig. 5.6-4). This location had
been used for previous State of Minnesota Pollution Control Agency compliance
tests. Four ports were located at the site. Three probes were installed into
each port at the centroids of equal areas for a total of twelve sample probes.
This sample site was outside and special insulating material and heating tapes
were required to keep the nylon sample lines from freezing during the cold
winter weather.
198
-------
CAT WALK
172.7cm O
(68")
104.1 cm
O (41")
I
121.9cm >
(48")
WESTERN
PRECIPITATION
MULTICLONE
Figure 5.6-2. Side view, inlet sampling area.
199
-------
2 2
Cross Sectional Area: 6.039 m (65.0 ft )
Probe Lengths from Outside Edge of Port: 43.34 cm (17-3/4"),
93.98 cm (37-1/4")
Probe Numbers Shown
Probe Numbers 1, 4, 5, 8, 9, 12 equipped for Hot Line Testing
609.6 cm
(240") -
f1 +3
+2 +4
+5 -v7
+6 +8
+9
+10
t +"
99 . 06cm
T'^12
I II II I l> 20.32cm
*0.8cm <101.6cm *
(20") (40")
Figure 5.6-3. Cross section, inlet sampling duct, top view, gas flow is
into paper.
200
-------
Cross Sectional Area:
2.016 m2 (21.7 ft2)
Probe Lengths From Outside Edge of Port: 35.56 cm (14-1/8"),
76.2 cm (30-3/8'"), 16.8 cm (46-5/8")
Probe Numbers Shown
— "
4-
*
162.6 err
(64")
13 16
14
17
f
15 18
-h 4-
30.5 cm
(12-1/2")
i
•*-
o.19 -U22
-r -r
20
23
t-
21 24
f +
J (6")
/
12
(48-
!1.9 cm
•3/4")
f
33.02 cm
(13")
Figure 5.6-4.
Cross section, outlet sampling duct, top view, gas flow is
out of paper.
201
-------
5.6.4 Comparison of Test Coals
Willmar Unit #3 normally burns a western type fuel, because the
utility had trouble in obtaining a reliable supply of eastern coals. Several
years ago so they switched to the more dependable western coal supplier. The
western coal burned during these tests was a Montana coal from Colstrip,
Montana. For the test series a special order of eastern type coal was obtained.
This fuel was from the Sahara mine in Southern Illinois. Analyses of the two
test fuels are presented in Table 2-1. As with most western subbituminous
coals the Colstrip coal had a high moisture content, high volatile and low
fixed carbon content and moderate sulfur content.
5.6.5 Western Coal Burning at Willmar
Montana coal is normally burned at Willmar. A small penalty is paid
in total unit capacity when using the subbituminous coal in a stoker originally
designed to fire a high Btu eastern type coal. The maximum load obtained with
the Montana coal was 16.1 kg/s (128,000 Ib/hr) steam flow while the maximum
load on the Southern Illinois fuel was 16.8 kg/s (133,400 Ib/hr) steam flow.
These values are somewhat deceptive since, at the time the boiler was tested,
there was a defective air heater in service. This air heater had large leaks
in it which allowed incoming air to short circuit its route to the combustion
zone, and hence starve the undergrate air chamber. This resulted in the unit
smoking at a lower than normal maximum load on the eastern coal and resulting
in a reduced maximum load at the given conditions. The unit should be able
to make 20.2 kg/s (160,000 Ib/hr) steam flow with the eastern coal when
the air heater is repaired and the stoker is properly adjusted.
Western coal can be successfully fired on a spreader stoker with only
minor changes in existing equipment. For a given boiler output, feeder rates
must be increased to get the same amount of energy input into the stoker on
western coal as for eastern coal. The fineness of the western coal ash
requires thicker bed to prevent ash from being blown off the grate. Willmar
Unit #3 ran an ash bed thickness of 5 to 10 cm when firing western fuel.
Feeder rates were increased about 10 to 15%.
202
-------
Higher superheat temperatures were encountered with the higher moisture
western coals. Willmar Unit #3 was equipped with a through-the-mud drum type
steam attemperator. This device was used when firing western coal to control
the superheat temperature. No control read-outs were available to measure the
absolute percentage of steam by-passed into the attemperator but the controller
which controlled the bypass valve was set at about 50% for Montana coal.
Increasing the over fire air can reduce the CO emissions somewhat; but, the unit
did not operate in that mode as a normal operating procedure. A short series
of tests ran overfire air pressure from normal as-found settings of 7.5 - 8.5
inches H2
-------
5.6.6 Emissions Data
A. Sulfur Oxides—
Table 5.6-1 contains a summary of all emission tests conducted at
Willmar on both eastern and western coal. In all, thirty-four tests were
run (fourteen on eastern coal and twenty on western coal). Sulfur oxides emis-
sions from western coal were about half that of eastern coal. The average
g
SO emissions from the eastern coal were 1489 ng/J (3.47 lb/10 Btu) compared
to 766 ng/J (1.79 lb/10 Btu). The Colstrip coal tested on this unit
exhibited the greatest sulfur retention of any coal tested with an average
of only 65% of the fuel sulfur emitted in the flue gas. This number compares
to a fuel sulfur emissions of 94% on eastern coal on this same unit.
The SO emissions from either the western or the eastern coal did
not follow a trend with either load or excess air. The SO component of
the SOx emission was generally less than 3 percent of the total. Neither the
amount of SO nor the ratio of SO /SOx exhibited a definable trend with any
of the test variables.
B. Particulates—
The uncontrolled particulate loadings were found to exceed the ash
content of the fuel by as much as a factor of four. Even when the carbon
content of the ash was taken into account, these figures could not be reconciled
with the uncontrolled particulate loadings. Therefore the error must be with
the sampling location described above.
Controlled particulate loading were within reasonable limits of 166-
545 ng/J (0.39 - 1.27 lb/10 Btu). The overall average particulate loading of
all the tests for eastern and western coal are shown in Table 5.6-1. The
average western coal emission was some 24% less than the average for eastern
coal. The carbon content of the western coal fly ash was also 33% less than
that from the eastern coal. The particulate emissions followed no definable
204
-------
TABLE 5.6-1. EMISSION SUMMARY, WILLMAR UNIT 3
Test
No.
BASTE
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Aver
Date
RN COAL
1/15/75
1/19
1/20
1/21
1/22
1/23
1/26
1/27
1/28
1/30
1/31
2/1
2/2
2/5
ige
1
Load
kg/s
103lb/hr)
13.5
(107.4)
14.1
(112.0)
22.8
(114.5)
14.1
(111.7)
13.3
(105.4)
13.3
(105.5)
15.6
(124.0)
15.8
(125.4)
11.4
(91.0)
10.5
(83.5)
9.6
(76.1)
11.0
(87.3)
13.8
(109.8)
16.8
(133.4)
13.4
(106.2)
Conditions
Normal O. Hed. Load
Normal O^, Hed. Load
Normal O.,, Hed. Load
Normal Oj, Hed. Load
High 0_, Hed. Load
Spill Plate Reset
High O,, Hed. Load In
Out
Normal O , High Load
Normal O., High Load
Normal O,, Low-Hed.
Load
Normal OJf Low Load
Low 02, Low Load
High 02, Low Load
Low 02, Ned. Load
Max. Cont. Load, Post
D.S. Boiler Tune Up
so2
Meter
3» 02
ppm
OOS
OOS
OOS
OOS
1798
1795
1712
OOS
OOS
OOS
OOS
OOS
OOS
OOS
CYCLONE INLET
02, %
8.59
8.22
8.17
8.38
9.43
8.56
6.62
6.45
7.42
9.95
8.38
11.92
6.63
5.85
8.18
CO
ppm
3% 02
314
369
146
368
44
39
289
509
113
51
26
84
89
216
190
C02
9.15
9.74
9.9
9.67
9.03
9.16
11.13
11.24
10.54
8.55
9.91
7.38
11.08
11.7
9.87
NO
PPm
3% 02
447
471
491
514
491
532
415
395
366
441
341
492
375
336
436
CYCLONE OUTLET
02, %
9.0
8.65
9.13
8.6
11.0
8.7
7.4
10.7
12.3
—
7.2
9.27
CO
ppm
3% 02
188
351
367
1306
20
44
FROZE
520
FROZE
58
FROZE
90
—
205
315
co2
8.8
9.4
8.9
8.8
8.4
8.8
10.6
7.88
7.4
—
10.9
8.99
NO
PPm
3% 02
495
445
439
515
502
520
293
432
—
481
—
326
445
kg Steam
kg Coal
8.2
8.6
8.7
8.6
8.6
8.7
8.4
8.3
8.9
8.5
8.1
8.5
8.7
8.67
8.53
* C
in Ash
—
_.
26.8
25.8
—
~
26.9
—
25.9
28.4
26.8
28.0
28.0
27
Part
ng/J
(•/MBtu
Out
—
_-
316
(0.7355)
371
(0.8622)
—
--
294
(0.6834)
—
350
(0.8135)
264
(0.6131)
545
(1.2670)
234
(0.5443)
320
(0.7650)
338
(0.7855)
SOx
ppm
1643
1534
—
1462
1589
—
2067
1849
1721
—
1651
1788
1792
1778
1815
1724
Notes
Prelim. Unit
Check Out
Part In and
Out
SOx In
SOx Out
Part In and
Out
SOx Inlet
SOx Inlet
SOx Inlet
Caseous Only
Part In and
Out; SOx In
Part In and
Out) SOx In
'art In and
Out; SOx In
Part In and
Out) SOx In
'art In and
Out) SOx In
to
O
Ul
(continued)
-------
TABLE 5.6-1 (continued).
Test
No.
Date
WESTERN COAL
1
2
3
4
5A
SB
5C
5D
6A
60
6E
7
8
9A
9B
12/2/75
12/3
12/4
12/5
12/8
12/8
12/8
12/8
12/9
12/9
12/9
12/10
12/11
12/12
12/12
Load
kg/s
(lo3lb/hr)
13.5
(107)
14.1
(112)
12.3
(97.5)
13.0
(103)
13.2
(105)
13.2
(105)
13.2
(105)
13.2
(105)
13.8
(109.5)
13.8
(109.5)
13.8
(109.5)
12.9
(102)
13.7
(108.5)
14.6
(111)
14.0
(111)
Conditions
Normal O_, Normal
Operation
Normal 02, Normal
Operation
Normal O , Normal
Operation
Normal O , Normal
Operation
Vary Overfire Air
(OFA) As Found
Vary OFA - Increase
Air
Vary OPA - Further
Increase Air
Vary OFA - Return
to Normal
Vary OFA - Bias Top
Row
Vary OFA - As Found
Vary OFA - Bias Top
Row
Vary Grate Air,
Normal 02
Max. O , Normal In
Operation Out
Vary Grate Air - As
Found
Vary Grate Air - West
Throttle, East Open
so2
Meter
3% 02
ppm
972
827
793
776
1126
955
920
945
978
—
~
980
915
1091
880
875
CYCLONE INLET
02, %
7.8
7.3
7.9
7.6
9.2
9.5
7.5
8.2
7.7
7.3
7.2
7.5
8.6
7.4
7.3
CO
ppm
3» 02
540
880
527
800
463
136
145
181
378
237
313
176
332
280
337
C02
%
10.3
10.4
10.1
10.4
9.1
9.0
10.9
10.5
10.4
10.9
10.9
10.5
9.7
10.6
10.6
NO
ppm
3* 02
363
387
389
398
366
362
356
333
333
355
352
355
427
392
369
CYCLONE OUTLET
02, *
—
--
8.6
—
~
—
--
--
—
8.1
8.2
9.1
—
—
CO
ppm
31 02
—
—
466
~
--
—
—
—
—
209
227
326
—
—
"'
—
—
10.1
~
—
—
~
—
—
10.2
10.3
9.4
—
—
NO
ppm
3% O2
--
—
407
—
~
--
—
—
—
412
362
439
--
—
kg Steam
kg Coal
5.85
5.80
5.81
5.86
5.72
5.72
5.72
5.72
7.72
7.52
7.52
6.49
5.75
5.8
5.8
» C
in Ash
—
—
19.1
—
—
~
—
—
—
—
—
—
19.9
—
--
Part
ng/J
(#/MBtu)
Out
--
--
10,956
325
/ 25.4B\
\0.7551/
—
—
~
—
—
—
—
—
--
18,146
303
(42 . 199\
3.7054/
—
—
SOx
ppm
867
785
851
—
—
—
—
—
—
859
1020
934
—
—
Notes
SOx Out
SOx In
Part In
Part Out
Meter Outlet
Meter Out
Meter Out
Part In and
Out; SOx In
O
CTl
(continued)
-------
TABLE 5.6-1 (continued).
Test
No.
Date
Load
kg/s
<103lb/hr
Conditions
WESTERN COAL -_ Continued
10
11
12
13
14
15
16
17
18
19
20
Aver
12/16/75
12/17
12/18
12/19
12/20
12/22
1/6/76
1/7
1/8
1/12
1/13
age
9.1
(72)
10.4
(83)
10.4
(82)
10.2
(80)
9.9
(79)
9.9
(79)
14.0
(111)
15.9
(126)
16.1
(128)
19.-2
(113)
14.5
(115)
12.9
(107.6)
Normal O., Low Load
Normal O_, Low Load
High O , Low Load
High O , Low Load
Low O., Low Load
Low-Med. O , Low
Load
Low-Med. O , Low
Load
Normal O , Maximum
Load
Normal O , Maximum
Load
Low O , Medium Load
Normal O , Medium
Load
SO2
Meter
3% 02
ppm
1020
1129
712
770
664
736
937
1057
963
OOS
OOS
CYCLONE INLET
02, »
9.5
8.6
10.6
9.9
7.7
8.2
6.6
6.7
6.0
6.8
6.9
7.9
CO
ppm
3% 02
262
143
165
198
129
234
1182
642
2200
1221
1003
504
co2
%
9.4
9.8
9.3
9.0
10.5
10.4
11.6
11.4
11.9
11.4
OOS
10.36
NO
ppm
3% 02
338
366
370
382
284
344
324
366
315
343
374
359
CYCLONE OUTLET
02, %
—
—
—
—
8.6
—
—
—
—
7.85
8.3
8.39
CO
ppm
3» 02
—
—
—
—
Ill
—
—
—
--
876
1052
467
cos
~
—
—
—
10.0
—
-
—
-
11.4
11.0
10.34
NO
Ppm
3* O2
—
--
—
—
307
—
—
—
—
356
350
376
kg Steam
kg Coal
5.73
5.82
5.63
5.70
OOS
5.72
5.75
5.68
5.59
5.58
5.61
5.98
» C
in Ash
12.2
—
—
13.3
15.0
~
21.9
--
25.5
—
-
18.14
Part
ng/J
(#/MBtu
Out
8,028
186
/18.67\
\0.4315^
—
—
8,080
290
^18.79^
-6754/
5,803
166
{ 13. 496^
0.3867^
—
4,657
277
/10.83 \
jO.6432/
~
12,234
258
28.45 \
\0.6001/
—
--
258
(0.5996)
SOx
ppm
~
1146
846
—
—
815
849
932
—
878
-
699
Notes
Part In and
Out
SOx In
SOx In
Part In and
Out
Part In and
Out
SOx In
Part In and
Out; SOx In
SOx In
'art In and
Out
SOx Out
Complete
nlet and
Outlet Gaseous
-------
trend with either boiler load or flue gas excess 0 . Indicated cyclone
collection efficiencies were very high due to the questionable inlet
particulate loadings. Assuming a cyclone efficiency of 85% one can back-
calculate the inlet particulate loading of about 2252 ng/J (5.3 lb/10 Btu)
which is a factor of 4 to 5 lower than the measured loading. Therefore the
measured inlet loadings are considered to be unreliable. The problem is
thought to be the sampling location rather than any procedural error in the
sampling technique.
C. Nitric Oxide—
Nitric oxide (NO) emissions measurements are given in Table 5.6-1
for both coals. The overall average emission of NO was reduced approximately
18% by switching to western coal. Figures 5.6-5 and 5.6-6 contain the nitric
oxide vs. Q data for Montana and Illinois coal respectively. Both data sets
are at a medium load and both exhibit the expected trend of increasing NO
with increasing excess O . The NO emissions from the Montana coal are all
about 50 ppm lower than the NO emissions from the Illinois coal. This
difference may be a result of differing fuel nitrogen content (111. = 1.35%
fuel N, and Mont. = 0.68% fuel N) of the two coals; or it may be due to the
high moisture content of the Montana coal which affects the combustion
intensity (flame temperature) resulting in lower thermal fixation. The
nitric oxide emissions were relatively constant with load for both coals.
D. Carbon Monoxide and Carbon Carryover—
The characteristic carbon monoxide emissions are given for Montana
and Illinois coals in Figures 5.6-7 and 5.6-8 respectively. Both coals
exhibit increasing CO emissions with increasing load. The quenching of the
CO combustion is more extensive on Montana coal than on the Illinois coal.
It has been demonstrated on other units, as well as this one, that CO
emissions can be controlled by increasing the excess air. Inspection of the
data in Table 5.6-1 shows that when the excess O2 is lowered to 6%, the CO
emissions become significant. Comparing Tests 17 and 18, at the same load,
demonstrated that increasing the excess 0 by 0.7% reduced the CO from 2200
ppm to 642 ppm.
208
-------
600
500
*
ro
0)
-P
fC 0
>, £400
M
•o -u
— 0)
rH
B C
0)
w" o 300
S3 -i
o u
H >i
en u
to
H 'H
S o
^200
H
X
u
H
Pi
EH
H
100
Medium Load
13.6 kg/s (108xl03 Ib/hr) steam
I
5.0
6.0
7.0 8.0 9.0
EXCESS OXYGEN, percent
10.0
11.0
Figure 5.6-5. Nitric oxide vs. excess oxygen, Willmar Unit 3, western coal.
209
-------
700
600
n
« 500
4->
-------
2000 ppm
1800
1600
1400
o _
* £1200
ro Jj
*»
Q»
a a
ft c
1000
800
— 600
400
200
Bated Load
44
Figure 5.6-7.
20.2 kg/s
(160xl03 Ib/hr) steam
L4L
20
8H
50
56 62 68
PERCENT OF RATED LOAD
74
18
17
80
Carbon monoxide vs. load, Willmar Unit 3, western coal.
211
-------
1400
1200
o
ro
100°
- c
w o
S H
o y
H >i
w u
w
H M-l
X
-------
Figures 5.6-9 and 5.6-10 contain the carbon carryover data as a
function of load for western coal and eastern coal respectively. The western
coal shows increasing carbon carryover with increasing load while the eastern
coal data was a monotonic function of load. The magnitude of the eastern
coal carbon carryover was approached only at high loads while firing
western coal.
5.6.7 Stoker Operation and Boiler Efficiency
The operational limits of the stoker are presented in Figures 5.6-11
and 5.6-12 for western and eastern coal respectively. The data is plotted as
a function of excess O and unit load. The upper dashed line represents
the limit of the induced draft fan. The lower dashed line represents the
limit defined by fuel bed clinkering, high CO, and/or smoke. The region
defined by these two dashed lines is the area of normal operation. The solid
line on these figures is drawn through test points within this normal operating
range. Comparison of the two solid lines shows that the western coal can be
fired at lower excess air than the eastern coal over the entire load range.
These plots may also be viewed as defining the limits of staged combsution in
this particular unit.
Table 5.6-1 contains a column labeled kg steam/kg coal. On the
average the western coal produced 30% less steam per kilogram of coal than the
eastern coal. This number gives some indication of how much more coal a plant
would have to process to obtain the same steam load. However the actual
boiler efficiencies are not so severely impaired as shown in Table 5.6-2 which
contains the heat loss boiler efficiency calculation results for eastern
coal and western coal respectively. Tests 23-34 are on eastern coal and
tests 3-18 are on western coal. On the average the western coal reduced
the boiler efficiency by three percent from 80.9% to 78.5%. The largest
differences between the two coals occur in the moisture and hydrogen losses.
This, of course, is due to the high moisture content of the western coal.
There are three factors which would cause loss of steam generation on western
213
-------
35
30
25
-------
40
35
30
4J
-------
12.0
11.0
10.0
4J
c
fl>
g 9.0
&
g 8.0
w
w
u
ti
7.0
6.0
I I I
Percent Carbon in Outlet Fly Ash is
Value in Brackets [%C in Ash]
[13.3] Normal Operation
•
•
[12.2] 13H "V^ / ID Fan Limit
Q
lo
I
CO, Clinker, or
Excessive Smoke Limit
Rated Load = 20.2 kg/s
(160xl03 Ib/hr) steam
I I I
44
50
56 62 68
PERCENT OF RATED LOAD
[25.5]
74
80
Figure 5.6-11. Excess oxygen vs. load, staging limits, Willmar Unit 3,
western coal.
216
-------
12.0
Normal Operation
CO, Clinker, or
Excessive Smoke Limited
Rated Load =20.2 kg/s
(160xl03 Ib/hr) steam
56 62 68
PERCENT OF RATED LOAD
Figure 5.6-12. Excess oxygen vs. load, staging limits, Willmar Unit 3,
eastern coal.
217
-------
TABLE 5.6-2. CALCULATION OF EFFICIENCY
to
i-1
00
Unit Description
Location No.
Boiler No.
Furnace Type
Capacity
kg/s
103 ib/hr
MBtu/hr
Installed
Erection Method
Burner Type
4
3
WT
20.2
160.0
285
1960
Field
SS
Boiler Category 312
Eastern Coal
Fuel Analysis
C 69.26
H 4.73
0 7.47
N 1.37
S 2.28
H20 7.11
Ash 7.76
HHV/(Btu/lb) 12448
MJ/kg 28 . 9
BOILER CONDITIONS
Teat No.
Test Load, % of Capacity
Stack O2 (% Dry)
Stack CO
Stack Temperature
•K
•f
Anbient Air Temperature
•K
•r
AH Inlet Excess Air
AH Exit Excess Air
Air Heater Leakage
Air Heater Efficiency
PCT. Air Through Air Heater
Dry Gas
Moisture + H2
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency
23
71.6
8.2
146.0
484
412.5
302
as.o
61.86
74.72
7.49
36.88
102.15
Heat Balance
10.41
4.93
0.25
0.08
2.48
0.56
81.30
25
65.9
9.4
44.0
491
425.8
305
90.0
Calculated
79.18
106.86
14.65
29.47
79.44
BOILER HEAT
Losses Corrected
12.74
4.95
0.31
0.03
2.36
0.61
79.01
28
78.4
6.5
509.0
484
411.0
300
81.0
Air Heater
43.06
52.86
6.51
37.89
110.08
30
52.2
10.0
51.0
473
391.5
303
86.5
Values, percent
87.48
100.92
6.82
38.51
103.29
31
47.6
8.4
26.0
469
385.0
308
95.5
64.50
75.73
6.45
38.93
100.72
32
54.6
11.9
84.0
472
390.0
299
78.1
127.53
137.34
4.14
40.66
115.56
33
68.6
6.6
89.0
500
440.0
301
82.5
44.82
53.97
5.92
29.83
84.92
34
83.4
5.9
216.0
489
420.0
299
78.0
37.51
50.68
8.94
34.67
102.46
BALANCE LOSSES, percent
to 300 °K
9.12
4.93
0.22
0.24
2.49
0.51
82.49
(80 °F) Entering
11.16
4.89
0.27
0.03
2.37
0.77
80.52
Air Temperature
9.42
4.87
0.23
0.01
2.69
0.84
81.94
13.21
4.89
0.32
0.06
2.48
0.73
78.30
10.00
4.98
0.24
0.04
2.64
0.58
81.52
9.28
4.95
0.22
0.10
2.64
0.48
82.34
(continued)
-------
TABLE 5.6-2 (continued).
to
M
VO
Unit Description
Location Ho.
Boiler
Furnace Type
Capacity
kg/s
103 ib/hr
MBtu/hr
Installed
Erection Method
Burner Type
4
3
WT
20.2
160.0
176.0
1960
Field
SS
Boiler Category 312
Western Coal
Fuel Analysis
C 49.32
H 3.31
0 10.85
H 0.68
S 1.15
H2O 25.56
Ash 9.12
HHV/(Btu/lb) 8408
.MJ/kg 19.5
BOILER CONDITIONS
Test Ho.
Test Load, 1 of Capacity
Stack 02 (» Dry)
Stack CO (ppn)
Stack Temperature
•K
•F
Ambient Air Tenperature
•K
•F
3
60.9
7.9
527.0
479
402.0
305
90.0
8
67.8
8.6
332.0
484
412.0
298
77.0
10
45.0
9.5
262.0
462
373.0
304
88.0
Calculated Air Heater
AH Inlet Excess Air
AH Exit Excess Air
Air Heater Leakage
Air Heater Efficiency
PCT. Air Through Air Heater
Dry Gas
Moisture + H2
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency
59.0
70. S7
6.6S
38.18
100.23
Heat Balance
9.88
8.11
0.24
0.28
2.80
0.66
78.04
67.85
74.81
3.82
38.38
113.73
BOILER HEAT
Losses Corrected
10.61
8.15
0.25
0.18
2.93
0.59
77.28
80.84
97.86
8.73
39.10
105.20
13
50.0
9.9
198. 0
475
395.0
305
90.0
Values, percent
87.28
105.61
9.10
36.87
99.17
14
49.4
7.7
179.0
465
378.0
306
91.0
56.65
67.87
6.57
40.29
107.30
16
69.4
6.6
1182.0
450
351.0
301
82.0
44.83
54.34
5.98
47.80
134.98
18
80.0
6.0
2200.0
450
351.0
300
80.0
39.12
48.90
6.37
49.19
143.06
BALANCE LOSSES, percent
to 300 *K
10.52
8.02
0.25
0.16
1.64
0.89
78.51
(80 *F) Entering
11.73
8.09
0.28
0.13
1.81
0.80
77.17
Air Tentierature
9.04
8.03
0.22
0.09
2.08
0.81
79.72
7.54
7.96
0.18
0.56
3.31
0.58
79.88
7.22
7.97
0.17
0.99
4.04
0.50
79.11
-------
coal, they are: (1) limitation of maximum steam generation due to high
superheat temperature, (in this case this limit resulted in a four percent
reduction in maximum load); (2) limited coal handling and feeder capacity,
(this was not a problem at Willmar); and (3) reduction in boiler efficiency
due to increased moisture losses, (efficiency reductions of some three per-
cent were measured when comparing western to eastern coal at comparable load
and excess 0 ' s).
5.6.8 Eastern Coal Burning on Spreader Stoker^
Willmar Unit 3 was designed to burn a high heat content eastern type
coal. However, the Southern Illinois coal did not perform as well on the
Montana coal. There were two reasons for the poor performance of the eastern
coal. First, the test batch of eastern coal contained a large percentage of
fines. Second, the overfire air fan was not functioning properly. The stoker
developed a smoking problem and a Detroit Stoker factory representative was
sent out to retune the stoker. The results of that effort are summarized
below.
The boiler had a smoking problem when firing the Southern Illinois
coal. The field representative from the stoker manufacturer noticed several
problems with the boiler operation. First, the furnace draft was too low
at -0.203 cm (-0.08 inches) of HO when it should have been almost twice
that at -0.38 cm (-0.15 inches) HO. Second, the feeders on the stoker
were out of adjustment in two ways. Both the hand wheels were out of adjust-
ment and the spill plates were not set right. Third, the overfire air was
not biased properly and not of sufficient pressure. After determining these
three items, correction of the problem proceeded as follows.
First, all spill plates were reset to the factory recommended setting
of approximately 1.27 cm (1/2 inch). This adjustment is made by turning the
spill plate adjusting screw clockwise all the way in until the center rib
of the spill plate bears against the inner end of the screw. The adjusting
screw was then backed off counter-clockwise until the 1.27 cm (1/2 inch)
setting existed between the rib and inner end of the screw. This was done
for all six feeders. Once the spill plates were set the hand wheels were
readjusted.
220
-------
To readjust the hand wheels, which control the feed rate, all the
hand wheels were turned clockwise until they could not be tightened anymore.
From this position, they were backed off from 1-1/2 to 2-1/2 turns counter-
clockwise until a satisfactory fuel bed was formed, up and down the firing
lane. From the 1-1/2 to 2-1/2 turn position the adjustment was made in 1/4
turn intervals. This concluded the fuel supply controls adjustment.
The overfire air was then reset. The first problem with this system
was that the outlet of the blower was producing only 25.4 cm (10.0 inches)
of HO pressure and it should have been about 68.6 cm (27 inches) of H 0.
*• 2
A search for leaks in the overfire air system turned up none. Subsequent
discussions with plant personnel revealed that the overfire air blower had
been overhauled recently and closer inspection of the blower showed that the
impeller had not been reinstalled properly. This reinstallation error
resulted in insufficient "bite" by the impeller in the shroud to the fan and
a resultant loss in air pressure. To compensate for the low fan capacity
a blower from the adjacent unit #4 which was connected via a crossover duct
was put in service. This additional fan raised the overfire air supply
pressure to the required 68.6 cm (27 inches) of water pressure.
With sufficient air pressure restored to the overfire air system,
the overfire air pressures were reset to factory specifications.
An overview of the overfire air settings were such that the back
wall was at a higher pressure than the front wall. The back wall upper
and lower rows were almost equal at about 43.2 cm (17 inches) H20 pressure
on the upper row and 41.4 cm (16.3 inches) H20 pressure on the lower rear
wall. On the front wall (feeder wall) the overall pressure was lower than
the back wall. The upper and lower rows on the front wall were similarly
biased. The lower row had about 38.1 cm (15 inches) of ^O pressure, and
only three to four inches on the top row on the front wall. This low
pressure was just sufficient to keep the nozzles from heating up and did
little to aid combustion. With most of the air through the lower jets
the turbulence mixing immediately above the bed was increased. This resulted
in increased residence time and improved carbon burnout.
221
-------
This improved firing mode of the unit allowed the combustion air to
be reduced which allowed the furnace draft to be increased. The final
boiler configuration was a definite improvement over the initial condition
of the stoker but still was not a complete solution to the smoking problem.
Some smoking still existed and flue gas analyses of the excess O distribu-
tion at the boiler outlet in a test (#34) immediately preceding the boiler
tune-up revealed a high degree of stratification in the exhaust duct. This
is shown in Table 5.6-3 which presents the inlet cyclone flue gas distribu-
tions. The cyclone inlet is essentially the same as the boiler outlet. Also,
shown in Table 5.6-3 is a flue gas distribution from before the stoker tune
up, this was test #23. The important thing to notice is the maldistribution
of excess O across the duct from east side to west side. For test 34 the
average of east side probes (#1 through #6) is 4.98% excess O and the west
side probes (#7 through #12) average 6.79% 0 . A difference of 1.81% excess
O,, from east to west. Test 23's corresponding excess O_ distribution is
6.69% for the east side and 9.58% for the west side. A change in excess 0
of 2.89% from east to west. For test 34 the percentage variation of excess
O across the duct is 31% and for test 23 the percentage is 35%. The ultimate
cause of the maldistribution of fuel and air was not discovered, even though
a change in the smoking problem resulted.
Western coal burned better on the stoker. The eastern fuel had a
tendency to form clinkers more readily than the western coal. This was
probably due to the uneven fuel/air distribution which resulted in local
cooling of the ash below its fusion temperature. The poor air/fuel distri-
bution also caused the eastern fires to impinge on the back wall of the
boiler. The western coal fires did not do this. Flame impingement and
flame carryover into the superheat pendant section which caused slagging
was more evident with the eastern than with the western coal. However, high
superheat steam temperatures were a problem with western coal and some
attemperation was required. Smoking was a continuous problem with the
eastern coal firing. Interestingly enough, CO emissions tended to be higher
for the western coal firing, yet smoke formation was not a problem as it was
with eastern firing. The volatile matter to fixed carbon ration (vm/FC) is
higher for eastern coal than for western coal resulting in a burnout problem
on eastern coal.
222
-------
TABLE 5.6-3. FLUE GAS DISTRIBUTION BEFORE AND
AFTER STOKER READJUSTMENT
2
CO
NO
(East)
Inlet
Averages:
0 - 5.85%
CO - 216
NO - 336
TEST 34 - INLET CYCLONE - 83% load
1
4.8%
278 ppm
333 ppm
2
4.85%
312
331
3
4.6%
258
316
4
5.7%
353
308
5
4.7%
364
309
6
5.2%
399
321
7
5.4%
213
312
8
6.3%
196
331
9
6.55%
69
354
10
7.3%
53
374
11
7.7%
54
337
12
7.5%
53
333
Outlet averages 7.2% O-, 267 ppm CO, 326 ppm NO
Test 23 - Inlet Cyclone - 72% load
(West)
°2
CO
NO
Inlet
Averages:
02 - 8.17%
CO - 145
NO - 491
1
6.0%
360
444
2
5.87%
357
438
3
6.3%
343
453
4
6.9%
243
466
5
7.45%
66
494
6
7.6%
87
500
7
8.2%
91
534
8
8.8%
59
528
9
9.48%
39
539
10
9.3%
38
548
11
10.95%
36
546
12
10.75%
35
558
Outlet averages 9.13% 02/ 177 ppm CO, 439 ppm NO
223
-------
5.7 FAIRMONT PUBLIC UTILITIES COMMISSION, UNIT #3, FAIRMONT, MINNESOTA
A blend of 1/3 Colstrip, "low sulfur" subbituminous coal and 2/3
Southern Illinois bituminous coal was fired in Fairmont (MN) Public Utilities
Commission Boiler #3. The results are compared with the results of firing the
Illinois coal alone in the boiler. The blend fired with some difficulty until
a number of operational changes were made. Although the blend contained 14%
less sulfur in terms of mass per heating value, the sulfur oxide emissions
were reduced by only 5%. Other emissions were not substantionally changed.
5.7.1 Introduction
The seventh test site was Boiler 3 of the Fairmont Public Utilities
Commission in Fairmont, Minnesota. This site was of particular interest
since the unit fired a blend of western and eastern coal in its boiler. The
user had attempted firing 100% western coal on the stoker but ran into prob-
lems of boiler slagging and high superheat temperatures. The boiler was not
equipped with any superheat temperature controlling device such as an
attemperator or desuperheater. A maximum blend of western with eastern was
determined to be in the ratio of 1/3 western coal with 2/3 eastern coal.
This blend was prepared at the site by plant personnel. As will be seen,
blending in situ is not an easy task and many problems are encountered.
The data presented will compare the results of tests performed on
Unit 3 while firing 100% eastern coal from Southern Illinois and the results
of the test series performed on Unit 3 when the eastern coal was blended with
the western fuel from Colstrip, Montana. In all, twenty tests were run.
Test numbers 1 to 10 were performed on the eastern fuel. Tests 11 to 20 were
on the blend. Testing commenced on February 20, 1976, and was completed on
April 1, 1976.
A. Boiler Description—
Boiler 3 of the Public Utilities Commission at Fairmont, Minnesota,
has a nameplate rating of 10.1 kg/s (80,000 Ib/hr) steam flow. The boiler
was manufactured by the Erie City Boiler Company. The unit is fired by a
spreader stoker also furnished by the Erie City Boiler Company. The stoker
has four feeders supplied by a single conical coal distributor.
224
-------
The boiler supplies superheated steam to a steam turbine which
generates power for the rural community of Fairmont. The final steam pressure
is 2.9 MPa (400 psig) . The steam is superheated to 522 °K (660 °F) . The
furnace is balanced draft and is kept at about -0.1 cm (-0.15 inches) of H 0.
Forced draft is supplied by a Buffalo Forge F.D. fan. Induced draft is
supplied by a single Buffalo Forge I.D. fan. Additionally, a Buffalo fan
supplies the forced air for the overfire air blower and ash reinjection
system on the back wall of the furnace.
The feedwater is heated by an economizer located in the back pass of
the boiler. Hot flue gases from the furnace pass through the superheat section
and then through the economizer. The unit has no air preheater, combustion
air is supplied at ambient conditions; however, the inlet to the FD fan is
inside the building and ambient conditions generally are at least 294 °K
(70 °F) or higher. After the economizer, the flue gases pass through a long
section of exhaust duct into which three sample ports were installed for the
test program. The hot gases then flow through a retrofitted cyclone-type
dust collector supplied by Western Precipitator Company. The multiclone dust
collector mechanically removes much of the particulates from the exhaust gas
before it travels through the ID fan then up the tall smokestack and exits
to atmosphere.
B. Stoker Operation—
The spreader stoker is made up of four individually controlled
feeders and a singly-driven traveling grate. The grate moves in a continuous
motion towards the front end of the stoker. The motion is supplied by a
hydraulically operated drive that can be adjusted to vary the speed of the
grate depending on the load being carried. Ash is discharged from the grate
at the front end of the stoker. The ash falls into an ash hopper below the
stoker and is pneumatically removed periodically during the day.
Each feeder can be individually adjusted to vary the quantity and
distribution of fuel. Each feeder is supplied with an electric motor with
an adjustable pulley arrangement to vary the feeder's rotor speed. By alter-
ing the rotor speed and the position of the adjustable split plate, the tra-
jectory of the fuel can be changed. The fuel feed rate is determined by the
225
-------
stroke of the rams located above the spill plate in each feeder. Every
feeder is equipped with three separately adjustable rams. The stroke of each
ram can be individually adjusted to tailor the fuel bed contour. Correct
stoker operation requires the proper setting of ram speed, spill plate posi-
tion and rotor speed. A final feature of this type of feeder is a natural
draft air sweep chamber. This chamber, located just behind and beneath the
rotor housing, draws room air through side vents and directs it through a
channel in the rotor housing into the feeder throat. Air also enters through
holes in the back plate into the feeder throats from the air sweep chamber.
This chamber often becomes filled with small pieces of coal and then becomes
inoperative. This can result in slight overheating of the feeder plus a loss
in the "sweeping" action of the air through the feeder throat.
C. Sample Site Description—
Flue gas was sampled at two locations at Fairmont Unit 3. One was
located upstream of the mechanical dust collector in a straight section of
exhaust duct. The second was downstream of the cyclone in the stack.
The cyclone inlet location had three sampling ports arranged vertically
along the duct. Figure 5.7-1 presents the schematic of the inlet sampling
duct configuration. Twelve gaseous sampling probes were used, four each at
each port located at the centroids of equal areas. Particulates and SO
emissions were also measured at this location. A special platform was con-
structed to permit personnel to test at the site.
Outlet data for the cyclone was obtained from two ports located on
the smokestack. The two ports were located 90 deg apart from one another
about 12.2 m (40 ft) up the stack. A catwalk provided access to the ports.
A sampling probe bundle consisting of three stainless steel probes
was installed in one port at a time. The orientation of the three stainless
steel probes is shown in" Figure 5.7-2. When sampling outlet gaseous data, the
probes were first sampled in one duct and then the bundle was removed and
reinstalled in the other port. Since much of the sampling took place during
the winter, the outlet sampling tube bundle had to be heated and insulated to
prevent freezing of the sample line.
226
-------
Inlet - Fairmont
c
c
L
i
i
i
i
i
i
L *-
r
i
Ix
'V
I
L,
/
1.58 m
(62.25") -
^X8.9 cm
(3.5")
• i - ni 1 AQ m
(58.75")
i
k
-»
\
•7
i
f -1
-c
2.3 m
(90" out
side)
-c
| 29.375"
L 0.75
i^
-e*-=
i
End of Port to mid filter - 0.84 m (32.875") + 0.076 m (3") = 0.91 m (35 7/8")
0.34 m (13.3") + 0.076 m (3") = 0.41 (16.3")
1.33 m (52.5") + 0.076 m (3") = 1.4 m (55.5")
^E
C
, i
K
t-cp-
1
1
1
1.5 m j
(58 3/4" )(
i
1
1
— — C
1
1
\i
A
T 1
!
1.1 m (42") + 0.66 m (26")
+ 0.076 m (3") = 1.8 m (71")
1.1 m (43")
2.5 m (99")
Figure 5.7-1. Inlet sampling duct configuration, Fairmont Unit 3.
227
-------
(110")
2.8 m
Figure 5.7-2. Configuration of outlet sampling probes, Fairmont Unit 3.
228
-------
D. Comparison of Test Coals—
Two fuels were fired at Fairmont Boiler 3. The first was 100% eastern
coal from Southern Illinois. This coal was from the Sahara mine. The second
fuel was a blend of 2/3 Sahara coal and 1/3 western coal. The western coal
was from the Rosebud and McKay seam of the Big Sky mine in Colstrip, Montana.
Table 5.7-1 presents a tabulation of the fuel analysis received on the two
coals. Also a composite average column has been made for the 100% eastern
coal and the blend. These columns represent an average of the various
analyses made for each fuel. If one considers the 100% western fuel analysis,
the composite eastern fuel analysis and the composite blend analysis, one can
write:
X(7949)Btu/lb + (1-X)(12404)Btu/lb = 10948 Btu/lb (25.5 MJ/kg)
where X = fraction of 100% western in the blend
Solving for X, one finds that the average fraction of western fuel to
the total amount of fuel used was 0.327, approximately 1/3. This corresponds
well to the intended blending ratio. Also, it is important to note the method
employed to collect the fuel samples. During each test a one quart sample of
coal was obtained from the coal scale once every hour. Typically, the test
would be 5 to 7 hours in duration. These one quart samples would be placed in
a large pail and at the end of the test the contents of the pail would be
thoroughly mixed. After mixing, the contents would be dumped on a sheet of
plastic and the pile arbitrarily halved. One half was returned to the pail
for further mixing. The second half was discarded. This process of mixing
and halving continued until a suitable pile remained for enclosure in the one
quart sample collection can. This final one quart fuel sample was then sent
to the laboratory for analysis. Therefore the time-average values for various
items in the fuel analysis, i.e. heating value, are representative of the fuel
fed over a long period of time but may not be representative of instaneous
fuel properties. This may be especially true in the case of the blend. There
was some evidence that the coal blend was not as well mixed as the fuel analy-
ses indicate. That is, the indication by fuel analyses that the fuel was well
mixed may be due to the fuel sampling technique rather than to the fuel blend-
ing procedure.
.229
-------
TABLE 5.7-1. COMPARISON OF TEST COALS AT FAIRMONT UNIT 3
Test
No.
3
5
7
9
10
Avg.
From
Coal
Pile
12
15
17
18
Avg.
Coal Type
Eastern
Eastern
Eastern
Eastern
Eastern
Eastern
100*
Western
1 part
Western
2 parts
Eastern
i«
"
n
"
Proximate Analysis,
percent
Fixed
Moisture Volatiles Carbon Ash S
8.55 — — 8.35 2.56
6.85 35.03 49.88 8.24 2.51
7.12 33.44 51.37 8.07 1.89
7.79 34.42 50.31 7.48 2.06
6.27 35.53 50.33 7.88 2.01
7.32 34.60 50.47 8.00 2.21
22.58 31.11 34.36 11.95 0.80
14.19 31.73 46.39 7.69 1.49
13.83 32.24 46.20 7.73 1.49
12.57 31.64 47.32 8.47 1.70
13.89 31.78 46.65 7.68 1.69
13.62 31.85 46.64 7.89 1.60
Ultimate Analysis,
percent
H C N o Cl
4.55 67.96 1.35 6.67 0.01
—
4.57 68.73 0.77 8.76 0.09
—
—
4.56 68.35 1.06 7.72 0.05
3.10 48.38 0.63 12.54 0.02
4.21 62.28 0.48 9.62 0.04
—
—
—
.-
Ash Fusion Temperatures
Reducing/Oxidizing
Initial Softening
Deformation H*W H-1/2W Fluid
1430/16030K 1481/1644'K 1533/1683°K 1578/1706°K
211S/242S°F 220S/2500T 2300/2570°F 2380/2610°F
„
1389/1589°K 1533/1661°K 1561/1683°K 1633/1744°K
2040/2400-F 2300/2530°F 23SO/2570°F 2480/2680°F
—
—
—
1567/1633°K 1663/1667°K 1656/16B9°K 1711/1750'K
2360/2480'F 2480/2540'F 2520/2580°F 2620/2700°F
1394/1517-K 1472/1589°K 1489/1617«K 1644/1650'K
2050/2270°F 2190/2400°F 2220/2450"F 2320/2S10T
—
„
—
—
Higher
Heating Value
As Received
Btu/lb / MJ/kg
12,293/28.6
12.441/28.8
12,318/28.6
12,413/28.9
12,554/29.2
12,404/28.9
7,949/lS.5
10.92J/2S.4
10,969/25.5
11,140/25.9
10,761/25.0
10,948/25.5
t-o
U)
o
-------
TABLE 5.7-1 (continued).
Test No. Coal Type
Mineral Analysts of Ash
Ondeter-
A12°3
SO3 K2°
Sulfur Forms
percent
Pyrito
percent percent % Total
Sulfate Organic Sulfur
3
5
7
9
10
Average
From
Coal
Pile
12
15
17
18
Average
Eastern 0.21 46.54 24.26 21.38 l.OS l.SO 0.75 0.86 2.30 0.48 0.67
Eastern
Eastern 0.20 52.33 14.19 22.50 1.20 2.80 1.13 2.81 2.37 0.32 0.15
Eastern
Eastern
Eastern 0.20 49.43 19.12 21.94 1.13 2.15 0.94 1.84 2.33 0.40 0.41
100%
Western 0.20 24.87 4.39' 12.15 0.48 44.00 3.12 9.12 0.53 0.22 0.92
1 part
Western
2 parts
Eastern 0.30 45.42 12.38 22.35 1.00 5.80 2.28 8.75 1.48 0.32 0.02
1.33
0.76
1.05
0.41
0.51
0.09
0.11
0.10
0.12
1.14
1.02
1.08
0.32
0.86
2.56
2.51
1.89
2.06
2.01
2.21
0.80
1.49
1.49
1.70
1.69
1.60
-------
5.7.2 Eastern Coal Blended with Western Coal Burning on Spreader Stoker
at Fairmont Unit #3
Testing on the one part western coal to two parts eastern coal began
with Test #11 on March 9, 1976. It became readily apparent during Test #11
that a severe operating problem existed on the unit when it fired the blend.
The problem was that clinkers would form on the grate directly under certain
feeders. Raw coal would pile up on these clinkers and slowly ignite or
smolder forming a larger clinker. The problem, as found, is described in this
section along with the test program developed to try to solve the problem.
Also included in this section is an outline of the eventual solution to the
clinkering problem and an evaluation of the successfulness of that solution.
Finally, this section will conclude with a discussion of the blending process
used at the site.
Test #11 started the test series on the blend at Fairmont Unit #3.
The blend was to be one part Montana coal and two parts Southern Illinois coal.
From Section 5.7.1.D it is seen that the overall blend was essentially in that
ratio (although there is some doubt as to whether the instantaneous blend was
in those proportions). Test #11 was a high load test in the as-found operating
mode. The conditions found on the stoker for this first run on the blend were
as follows. The ash bed thickness across the width of the grate was non-
uniform. The ash bed thickness on the #4 feeder side (east side) was 3.8 cm
(1-1/2 inches) while the ash bed thickness of the #1 feeder side (west side)
was 6.3 cm (2-1/2 inches). Fingers of glowing embers of coal were tending to
fall into the ash pit directly below each feeder. Coal was piling up just
beneath each feeder on the top of clinkers that had formed directly in front
of each feeder. The problem was particularly severe on the second feeder from
the west side, feeder #2. On feeder #2, much of it's coal supply dropped
directly in front of the feeder, piled up and formed clinkers.
These raw coal pile clinker formations had to be individually broken
up by the boiler operator using a hand rake. The job was time consuming and
difficult. If the coal pile/clinkers were not raked, the raw coal could
(1) continue to pile up until coal began to back up into the throat of the
feeder, or (2) coal could begin burning at the top of the clinker and spread
232
-------
fire back into the feeder. Additionally, the raw coal could ride on top of
the clinker and would be dumped into the ash hopper. One obvious problem is
a loss of efficiency due to dumping raw fuel into the ash pit. A second
problem is the possibility of the raw coal igniting in the ash hopper. A
third possible problem of the clinker would be inadequate cooling of the
grate. The clinker covered area can become overheated and melt or warp the
grate plates. This, in turn, can easily cause destruction of the grate and
a forced outage.
During test #11 there was no "flash backing" of fires into the feeders
as seen on 100% eastern coal burning. It was felt that this may not be
particularly due to the blend being burnt, but to the fact that the coal on
that day appeared wetter and perhaps the fines (believed to be responsible
for the "flashing back" phenomenon) were sticking to the larger pieces of
coal.
The following paragraphs outline the procedure followed in defining
a modified operating mode to eliminate clinkering.
Why were the clinkers and coal piles forming? The coal piles were
caused because the clinker underneath formed an effective shield between
undergrate air and the raw fuel. Hence, the fuel would not ignite and would
continue to collect in a pile until air circumventing the clinker could
reach the edges of the pile and ignite the coal. Another possibility is
that the clinker would not entirely block the air flow but impede it suffi-
ciently to locally starve the incoming raw coal of air and form a larger
clinker. If the clinkers were eliminated the coal piling phenomenon would
also be solved.
Two theories of clinker formation were developed. The first was a
chemical theory where the lower ash fusion temperature of the blend caused
the clinker. The second theory related the clinker problem to a physical
property of the fuel. If the latter was the case, then a change in operating
variables might eliminate the problem. Since the ash fusion temperature was
fixed for the coal, the physical theory was adopted and changes in the opera-
ting parameters on the stoker were employed to solve the clinker problem.
233
-------
What physical property of the coal could cause the clinkers? Several
answers could be posed but a persistent one was "the fines in the coal." The
fine particles in the fuel seemed a strong candidate for a cause of the clink-
ering. Western coal is known for its tendency to shatter and break down into
small particles. Since the clinkering was not seen with 100% eastern coal,
perhaps the addition of the component of western coal added extra fines into
the coal supply thus causing the clinker. If it were the fines, then how did
they cause the clinker? Two mechanisms were considered. The first suggested
that the fines were too light to remain on the grate and "blow holes" were
formed where the particles were blown off the metal. This would cause hot
spots that would raise local temperatures high enought to reach fusion
temperatures of the ash, causing clinkers to form. A second mechanism
suggested a plugging up of grate air holes by the fine material of the fuel
and that these "no-flow" grate areas became hot spots and formed clinkers.
It was never resolved which mechanism caused the clinker formation but it
was established that the fines in the coal were causing the clinker problem.
Rotor speed setting changes were a starting point in the search for
a solution to the clinker formation problem. The unit was set at a load of
about 7.6 kg/s (60x10 Ib/hr) steam flow and the rotor speeds were left in
the as-found position. The clinker problem was as originally noted; that is,
well defined zones of coal piles/clinkers were formed directly in front of the
feeders, especially feeders #1 and #2. The rotor speed was then increased as
follows. Each feeder has an individually controlled rotor speed motor con-
nected to the rotor by a variable tension pulley belt. Each rotor speed
adjusting handle was turned in a counter clockwise direction until the slack
was taken up in the drive belt. Then an additional two turns counter clock-
wise were given to each handle. Indicators on the side of the motor/pulley
housing indicated a 0.6 cm (1/4 inch) change in position. By increasing the
rotor speed it was hoped that the trajectory of the fuel towards the back of
the boiler would increase. This procedure should prevent the coal from falling
directly onto the area in front of the feeders. There was no improvement as
a result of this move.
234
-------
The stoker performed well over the weekend in the modified spill
plate mode. In order to further verify the validity of the spill plate
adjustment, the spill plate position of #2 feeder was returned to its original
as-found setting and the grate was observed. Within forty minutes, a clinker
began to form just off feeder #2. After 1-1/2 hours had passed, a definite
clinker of moderate size was formed.
The situation overnight was one of continued problems with clinker
formation. Much hand raking and attention was required to keep the stoker
operating. Feeder #2 spill plate was returned to the successful 6.5 cm
(2-1/2 inch) position and the clinker disappeared.
This new operating mode became the established mode for day-to-day
firing. The remaining tests on the blend was with the #2 feeder spill plate
backed off to the 6.3 cm (2-1/2 inch) mark while the remaining three feeders
(#1, #3, and #4) were at the 5 cm (2 inch) mark. This mode proved successful
in controlling clinkers. Some additional problems with clinkers did occur
from time to time during the remaining test series but they were not as
severe or persistent as the original ones. Some minor adjustments were made
in the feeder #2 spill plate later in the program but essentially it remained
set back farther than its adjacent feeder's spill plates.
A. Blended Eastern and Western Coals as a Boiler Fuel—
Coal blending is not a new concept. Coal producers have for many
years blended different seams of coal to produce a specific product. This
blending usually takes place at the mine or in some coal preparation facility
near the coal mines.
Today there is considerable interest in blending the high sulfur
eastern and midwestern coals with the low sulfur western coals to achieve
SO emission control and to promote the use of the abundant western coal
A
resources. Several problems occur when one contemplates the blending of
these coals. Some of these are:
. Long transportation distances to bring the coals together,
. Poor handling characteristics of most western subbituminous
coals,
Fires in storage piles,
235
-------
Poor mixing due to size differences of the coals,
Lack of blending facilities,
Problems with on-site blending,
Problems with coal feeders, and
Combustion-related problems.
With the exception of the first two, the problems listed are open to
at least partial solution. It is the intent of this report to identify the
specific problems that occur while firing a blend of Montana subbituminous
coal and Southern Illinois bituminous coal, and to recommend solutions.
B. Discussion—
Blending coal at a boiler is difficult. Tracing the coal flow through
the handling system shown in Figure 5.7-3 shows that the coal can only be
mixed in three locations: (1) the coal silo, (2) the conical coal hopper,
and (3) in the furnace. The extent of mixing depends on the diameter of the
receptacle and the height to which it is filled. If the diameter of the
receptacle is small compared to the length of the coal, then the coal will
stay stratified. Mixing will occur in the furnace, however, due to combustion.
This mixing is limited to the residence time of the coal in the furnace and
the size of each parcel of unblended coal that arrives at the furnace feeders.
The mixing problem is compounded by the size variation of the two
coals. In any hopper, feeder, or silo there will be some segregation of coal
due to the separation of the "fines" from the larger pieces. In the present
case, the western coal with its larger percentage of fines will tend to
separate from the eastern coal even if it was originally well mixed. This
causes severe feeding problems with stoker fired units since the finer coal
is not thrown as far into the unit and tends to build up on the chain grate
immediately in front of the feeder, causing a clinker to form. Another
manifestation of this problem appears in the form of uneven distribution of
fines to the feeders, resulting in an uneven fuel bed which can lead to a
clinker.
236
-------
Conveyor
Belt
1/3 western
2/3 eastern
to
u>
-j
\
grate
shaker
Bucket
Loader
Coal
Silo
QJ
•s
0)
u
«
Belt
Meter
Coal Scale
Conical Coal
Hopper Section
Feeders
Figure 5.7-3.
Schematic of coal handling system, Fairmont, Minnesota
Public Utilities Commission.
-------
Adjustments can be made to the stoker to allow the feeding of off-
size coal. If the feed coal is uniform, this will result in acceptable
operation. However, if the size of the coal is uneven, no feeder setting is
adequate. In the case at hand, the blending of the two coals actually
aggravated the feeding problem since the added handling of the coal during
blending served to further reduce the size.
5.7.3 Eastern Coal Burning on Spreader Stoker at Fairmont Unit #3
Fairmont Unit #3 was designed to burn a high Btu/lb bituminous eastern
coal. The Southern Illinois coal fired on Unit #3 stoker performed well. A
series of ten tests were run on the unit while firing the Illinois fuel. These
tests were at high, medium and low loads ranging from 7.9 kg/s (62.6x10 Ib/hr)
steam flow to 3.6 kg/s (28.6x10 Ib/hr) steam flow. Various excess air levels
were tested at each load. Once each test was set up,the stoker required little
or no attention from the boiler operator. The unit held steady state conditions
well. There was a minor clinkering problem at times when firing this coal.
When firing the eastern fuel a thin ash bed is required. Generally,
a protective ash thickness of 2.5 to 5 cm (1 to 2 inches) was used. This ash
bed was of uniform thickness across the width of the traveling grate, indicating
a uniformly distributed fuel bed laterally across the grate. The ash was
completely burnt out when it reached the ash discharge end of the stoker. No
embers were present. Clinkers sometimes were a problem with eastern coal
firing. Generally, this was when the flames were flashing back into the rotor
housing on #3 feeder. On one test in particular (Test #7\ a large clinker
formed off the #3 feeder and had to be removed by a hand rake. The same fines
that caused the flash back caused the clinker. This occurs when the fine coal
drops in front of the feeder and forms a clinker just below the feeder throat
on the grate. The fused material forms a patch of grate area that doesn't
receive any air flow. Additional fuel material falls on this patch and smolders
instead of burning completely and soon a larger clinker is formed. These
clinkers must be removed or they will fall into the ash pit and complete
combustion there, forming a potential fire hazard. This problem of flame
flash-back and clinker formation in front of the feeders was not as severe
as it was when the western/eastern coal blend was burned.
238
-------
The flames on eastern coal firing were a luminescent orange-red in
color. There was no flame impingement on the front, back or side walls. One
minor problem persisted from time to time, and that was "flame lick" back into
the number 3 feeder's rotor housing. This problem is thought to be caused by
the fine particles in the feeder not being thrown clear of the rotor and
combusting in front of the feeder. If this problem becomes severe, the fires
can either coke up the rotors or make their way back up into the fuel distri-
butor and cause damage. The problem was not severe on the eastern coal
firing.
Dark gray smoke would rise up from base of the back wall when eastern
coal was fired. However, the smoke was directed into the flames and was
apparently consumed before exiting through the furnace. Sparklers were
slight to moderate in the furnace.
The maximum load tested on Unit #3 was 7.9 kg/s (62,600 Ib/hr)
steam flow. This was not the maximum continuous load possible on this
boiler. The high maximum test load was defined by how much steam the avail-
able steam turbines could handle. The plant's main (and largest) steam
turbine was down for overhaul during the test program and the turbines
remaining in service could not handle all the steam that Unit 3 boiler could
potentially generate. Plant personnel estimated a possible maximum continuous
load of about 10.1 kg/s (80,000 Ib/hr) steam flow on the eastern fuel.
5.7.4 Emissions
Fairmont, Unit #3 emissions were characterized by an eight point test
matrix as shown in Figures 5.7-4 and 5.7-5. The numbers on these and all
following graphs refer to test numbers and can be used for cross reference.
This section is divided into four subsections describing the various emissions.
They are particulates, sulfur oxides, nitric oxide, and combustion efficiency
related emissions such as carbon monoxide, carbon retention in the ash and
thermal efficiency of the unit. A summary of all the gaseous emissions is
included in Table 5.7-2.
239
-------
30
40
50
60
4-1
C
0)
U
M
0)
I
o
CO
CO
H
U
X
W
14
12
10
1
O
A
High 0
Norm 0
Low
10
Rated Load = 10.1 kg/s (80x10 Ib/hr) steam
38
50 62
PERCENT OF HATED LOAD
74
Figure 5.7-4. Conditions under which unit was tested, Fairmont Unit 3,
eastern coal.
240
-------
30
w
w
14
-P I 9
fi "
0)
O
J-l
B 10
W
s
X
o
40
G High O
O Norm 0
50
60
Low 0
Rated Load = 10.1 kg/s (80x10 Ib/hr) steam
38
50 62
PERCENT OF RATE) LOAD
74
Figure 5.7-5- Conditions under which unit was tested, Fairmont Unit 3,
coal blend.
241
-------
TABLE 5.7-2. GASEOUS EMISSIONS SUMMARY, FAIRMONT PUBLIC UTILITIES COMMISSION, UNIT 3
test
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Date
1976
2/20
2/24
2/25
2/26
2/27
3/1
3/2
3/3
3/4
3/5
3/9
3/17
3/18
3/22
3/23
3/24
3/25
3/30
3/31
4/1
Load
kg/s
(103 Ib/hr)
4.0
(31.5)
6.1
(48.6)
6.2
(48.9)
6.2
(49.2)
6.2
(48.9)
7.2
(57.4)
7.2
(58.8)
3.6
(28.6)
7.9
(62.6)
7.6
(60.5)
7.6
(60.2)
7.6
(61.0)
7.7
(61.1)
5.8
(45.9)
3.8
(30.2)
7.1
(56.4)
7.6
(60.0)
5.8
(45.7)
5.5
(44.0)
4.3
(33.8)
Conditions
Low Load,
Med Load,
Med Load,
Med Load,
Med Load,
High Load,
High Load,
Low Load,
High Load,
High Load,
High Load,
High Load,
High Load,
Med Load,
Low Load,.
High Load,
High Load,
Med Load,
Med Load,
Low Load,
Horn 02
Norn 0.
Norn 02
High O
Low Oj
Norm 02
Norn 02
High 02
Low 02
High 02
Norn 02
Norm O
High 02
Low 02
Norn 02
Norm 02
Low 02
Norm O2
High 02
High O2
3% 02
ppm
77
82
—
31
12
—
33
23
9
37
18
12
—
54
7
50
16
164
32
14
Particulates
ng/J
(Ib/MBtu)
—
—
618
(1.437)
639
(1.486)
527
(1.225)
—
757
(1.760)
630
(1.465)
1110
(2.582)
1068
(2.484)
—
1104
(2.567)
1201
(2.794)
1209
(2.811)
1677
(3.900)
—
909
(2.114)
987
(2.295)
935
(2.174)
1565
(3.639)
Stack
CO NO Particulates
8 3» 0 a 3» o ntj/J
0 , » CO , \ ppm ppn (Ib/MBtu)
13.06 6.32 160 285
9.70 8.63 51 227
10.10 8.40 34 280 163
(0.379)
11.41 7.20 41 314 133
(0.309)
125
(0.294)
8.80 9.70 44 317
8.15 10.10 56 312 170
(0.395)
14.00 5.60 219 450 191
(0.444)
8.78 9.60 127 302 198
(0.414)
200
(0.464)
8.20 10.40 77 260
7.97 10.37 57 311 222
(0.517)
8.70 10.07 76 354 199
(0.463)
8.83 9.13 75 360 177
(0.411)
13.00 5.93 375 420 271
(0.630)
—
7.08 10.97 507 296 211
(0.491)
10.27 8.50 190 335 208
(0.484)
12.40 — — — 233
(0.542)
13.95 5.60 627 425 248
(0.576)
-------
A. Particulates—
Particulates were measured at both the inlet to the dust collector
and in the stack using EPA Method 5. At the inlet, seven point traverses were
made at each of the upper two ports. The bottom port was found to be unusable
for particulates because its proximity to the platform floor did not allow
enough room for the filter box. Inlet particulates were corrected for excess
02 using the average of a nine-point gaseous traverse made in conjunction with
the particulate sampling. Figure 5.7-2 shows the inlet sampling area with
gaseous probes installed.
In the stack, two ports at 90 deg to each other allowed for a thirty-
two point "equal area" traverse as described in Method 1, the Federal Register.
Excess O used for correcting the data was obtained from a three probe bundle
installed alternately in the port not being used for particulate sampling.
Figure 5.7-6 illustrates the particulate loading at the dust collector
inlet for both fuels. The eastern coal behaved as might be expected. Partic-
ulates remained relatively low except at high loads where vertical gas veloc-
ities were high enough to "blow" some of the ash off the grate. The critical
load above which particulates were observed to rise sharply occurred at about
7.2 kg/s (57xl03 Ib/hr), or 71% of design load.
The particulate behavior for the coal blend firing did not resemble
that of the eastern coal. On the average, the dust collector loading was
36.2% greater with the blend than with the eastern coal. Also, a sharp rise
in particulate loading was observed at low loads. The explanation for this
behavior is not readily apparent. Carbon carryover, Figure 5.7-10, was
actually lower for the blend and thus cannot explain this difference.
The ash content of both fuels was very similar, averaging 8.64% for
the eastern coal (5 samples analyzed) and 9.14% for the blend (4 samples
analyzed). Sodium content and ash fusion temperatures were also very similar
(see Table 5.7-1). However, the coal blend was observed to have more fines in
it, and this combined with the noncoking properties of the western coal probably
accounts for the increased particulates of the coal blend.
243
-------
1700
« 1500
u
2
H
Q
g 1300
w
|
y 1100
CM
g 900
30
40
50
60
o
CJ
D
Q
700
500
8H
Eastern
O
Eastern coal
Coal blend
Rated Load = 10.1 kg/s
(SOxlO3 Ib/hr)
steam
38
50 62
PERCENT OF RATED LOAD
3.0
2.0
74
Figure 5.7-6. Inlet participates vs. load, Fairmont Unit 3.
244
-------
As for the rise at low loads, it is likely that agglomeration of sus-
pended ash particles does not occur as readily at the lower loads because of
the accompanying lower temperatures. Thus, the particles remain smaller and
are more easily carried over into the flue duct.
Figure 5.7-7 illustrates the particulate loading in the stack. As
was observed at the dust collector inlet, the coal blend firing produced a
33.3% higher particulate loading in the stack than did the eastern coal firing.
With the exception of Test #15, however, both fuels met the applicable emis-
sions regulation for this unit of 258 ng/J (0.6 Ib/MBtu).
Cyclone efficiency increases not only with increasing particle size
and inlet velocity, but also with increasing inlet loading (see Figure 5.7-8).
This would certainly explain the shape of the dust collector efficiency curves
shown in Figure 5.7-9. Here, the increase in cyclone efficiency at low
loads with the coal blend can be accounted for by the sharp rise in inlet
loading.
Combustibles in the fly ash were an average 18.1% lower while firing
the blend as shown in Figure 5.7-10. And, they are seen to increase at low
loads where combustion conditions (primarily temperature profile and fuel air
mixing) are inadequate to complete their combustion. Exactly why the blend
firing showed lower percent combustibles in its fly ash is unknown. However,
it should be noted that the total carbon carryover on a heat input basis
would show that both fuels emitted approximately the same amount of combustible
material.
B. Sulfur Oxides—
Sulfur oxides were measured at the inlet to the dust collector from
a single point. To help determine the validity of this sample location,
sulfur oxides were measured at both the inlet to the dust collector and at
the stack during test #2. Very good agreement was found with the stack
showing 1.26% more SOx than the inlet. This difference is well within
experimental error.
245
-------
30
40
hi
>
290
I 24°
Q
s
w
EH 200
D
U
160
u
EH
W
120
2 OH
50 §0
I T
£ Eastern coal
O Coal blend
Rated Load = 10.1 kg/s
(SOxlO3 Ib/hr) steam
38
50 62
PERCENT OF RATED LOAD
0.6
I
0.4
74
Figure 5.7-7. Outlet particulates vs. load, Fairmont Unit 3.
246
-------
90
w
CJ
85
80
O
14
II)
04
X
u
B 75
H
u
70
65
01234
PARTICULATE LOADING, ng/J
Figure 5.7-8. Cyclone efficiency vs. particulate loading, Fairmont Unit 3,
eastern coal and blended coal.
247
-------
85
+j
-------
45
s
0)
M 40
-------
Table 5.7-3 summarizes the sulfur oxides data, and Figure 5.7-11
illustrates the test results for both fuels. It can be readily seen that
although the blend showed an average 4.9% reduction in SOx over the eastern
coal, statistically there was no significant difference between the two. It
can also be seen that the SOx did not vary significantly with either load or
excess O_, the two main test variables.
Studies have shown that a portion of the sulfur is retained in the
ash and is not emitted as a gaseous pollutant. Table 5.7-4 and Figure 5.7-12
illustrate an attempt to make a mass balance of sulfur-in versus sulfur-out
at Fairmont Unit #3. The unaccountable differences of up to +_ 15% point out
deficiencies in the experimental methods used. These could include non-
representative sampling of both fuel and emissions, and/or inaccuracies in
the analytical method.
Despite these inconsistencies in the data, one point is clear. Sulfur
retention was quite low at about 0.8% as measured in the ash, and it did not
significantly vary between the two fuels.
Sulfur trioxide does sometimes show a correlation with load or excess
0_. In the case of Fairmont Unit #3, however, no correlation was found and for
this reason no plot of the SO data was made. Sulfur trioxide concentrations
are included in Table 5.7-3. They averaged 19.6 ng/J (0.046 Ib/MBtu) for the
eastern coal and 21.3 ng/J 90.50 Ib/MBtu) for the blend. This corresponds
to 2.3% and 2.6%, respectively, of the total measured sulfur oxides.
C. Nitric Oxides—
Nitric oxide concentrations as measured at the inlet to the dust
collector are tabulated in Table 5.7-5. Average concentrations between the
two fuels are seen to be about the same, averaging 130 ng/J (0.30 Ib/MBtu).
The similarity, however, stops there. Figures 5.7-13 and 5.7-14 illustrate
the variation of nitric oxide concentration with excess O_. For eastern coal
firing,a very high dependence on excess O was found. This dependence appeared
to increase slightly as the loads were lowered. For example, at a load of
250
-------
TABLE 5.7-3. SULFUR OXIDES DATA, FAIRMONT PUBLIC UTILITIES COMMISSION, UNIT 3
Test No.
1
2
4
5
7
8
9
10
Average
Eastern
Coal
Standard
Deviation
11
12
14
15
16
17
IS
19
20
Average
Coal
Blend
Standard
Steam Load
kg/s
(103 Ib/hr)
4.0
(31.5)
6.1
(48.6)
6.2
(49.2)
6.1
(48.9)
7.4
(58.8)
3.6
(28.6)
7.9
(62.6)
7.6
(60.5)
7.6
(60.2)
7.7
(61.0)
5.8
(45.9)
3.8
(30.2)
7.1
(56.4)
7.6
(60.0)
5.8
(45.7)
5.5
(44.6)
4.3
(33.8)
Excess 0
percent
12.40
9.09
10.08
8.16
7.99
13.53
6.45
9.76
6.95
6.95
8.01
12.94
8.26
6.62
9.37
12.40
14.13
Total
ppm
* 3» 02
1585
1673
1740
1434
1949
1797
1682
1445
1663
163
1539
1636
1615
1248
1828
1502
1672
1565
1439
1560
1 H9
Oxides of Sulfur
Ib/NBtu
2.958
3.122
3.247
2.676
3.637
3.354
3.139
2.697
3.104
0.325
2.912
3.095
3.055
2.361
3.458
2.842
3.163
2.961
2.722
2.952
0.306
ng/J
1272
1342
1396
1151
1564
1442
1350
1159
1335
140
1252
1331
1314
1015
1487
1222
1360
1273
1170
1269
131
Sulfur Trioxide
ppn
8 3% 02 Ib/KBtu
77 0.144
82 0.153
31 0.058
12 0.022
33 0.062
23 0.043
9 0.017
37 0.069
38 0.071
27 0.051
18 0.034
12 0.023
54 0.102
7 0.013
JO 0.095
16 0.030
164 0.310
32 0.061
14 0.026
f
i
41 0.077
49 0.093
ng/J
61.8
6S.8
24.9
9.6
26.5
18.5
7.2
29.7
30.5
22.0
14.6
9.8
43.9
5.7
40.7
13.0
133.4
26.0
11.4
33.2
40.0
251
-------
2000
1600
^_^
(N
O
a°
ro
^ 1200
g
a
800
O
400
0
1 1
7
A
•8 18 * 0
Q ^ 16 12 •
— ~ A /"N^ 2 ^
i^ i -jJQ-i i
—*2 0 19 1 7CZ.-1 -*-
o • •
5 10
— ^
— °15
—
0 Eastern coal (avg. 1663 ppm)
O Coal blend (avg. 1560 ppm)
Rated Load = 10.1 kg/s (SOxlO3 Ib/hr) steam
— —
III 1
38
42 62
PERCENT OF RATED LOAD
74
_ 0.6
— 0.4
Figure 5.7-11. SO comparison for eastern coal vs. blend, Fairmont Unit 3.
252
-------
TABLE 5.7-4. SULFUR OXIDES RETENTION IN ASH, FAIRMONT PUBLIC UTILITIES COMMISSION, UNIT 3
Test No.
5
7
9
10
Average
12
15
S 17
w
18
Average
Computed Sulfur
Into System
% S HHV Fuel
Fuel MJ/kg
2.69 31.. 06
2.04 30.84
2.23 31.30
2.14 31.14
2.28 31.09
(.29)
1.74 29.60
1.73 29.60
1.94 29.63
1.96 29.06
1.84 29.47
Difference
%
-19.0% -5.2%
S0x
ng/J
1732
1323
1425
1374
1463
1176
1169
1309
1349
1251
-14.5%
Measured Sulfur
Ash
% of Fuel
8.85
8.69
8.11
8.41
8.52
8.96
8.97
9.69
8.92
9.14
+7.3%
Sulfur
% of Ash
—
—
0.28
0.11
0.20
0.17
0.16
— Tm
0.17
-15.4%
Retention
SOx
ng/J
—
—
14.6
6.0
10.3
10.3
9.9
— _
10.3
-4.2%
Retention
percent
—
—
1.03
0.44
0.74
0.88
0.85
__
0.87
+16.4%
Measured Emissions
so*
ng/J
1151
1564
1350
1160
1306
1330
1015
1222
1360
1232
-5.7%
Unaccounted
Difference
ng/J
—
—
67.5
211
140
160
149
__
-6.0
Percent
Difference
—
—
4.74
15.39
-13.64
12.73
~~
-------
to
D
03
Cn
O
W
§
H
X
O
tJ
<
Q Computed from sulfur in fuel
LJ Measured stack emissions _
| Measured sulfur retention in
ash (test #9,10,12,15 only)
10 12
TEST NO.
15
17
18
2000
D
1500 13
LO
S
1000
500
to
g
H
X
0
Figure 5.7-12. Sulfur mass balance, Fairmont Unit 3.
-------
TABLE 5.7-5. NITRIC OXIDE DATA,
FAIRMONT PUBLIC UTILITIES COMMISSION, UNIT 3
Test
No.
1
2
3
4
5
6
7
8
9
10
Load
kg/s
(103 Ib/hr)
4.6
(31.5)
6.1
(48.6)
6.2
(48.9)
6.1
(49.2)
7.4
(48.9)
7.2
(57.4)
7.4
(58.8)
3.6
(28.6)
7.9
(62.6)
7.6
(60.5)
Excess 0
percent
12.40
9.09
9.32
10.08
8.16
8.03
7.99
13.53
6.45
9.76
Average Eastern Coal
11
12
13
14
15
16
17
18
19
20
Average
7.6
(60.2)
7.7
(61.0)
7.6
(61.1)
5.6
(45.9)
3.8
(30.2)
7.1
(56.4)
7.6
(60.0)
5.8
(45.7)
5.5
(44.0)
4.3
(33.8)
Coal Blend
6.95
6.95
8.06
8.01
12.94
8.26
6.62
9.37
12.40
14.13
Nitric
ppm
@ 3% Oj
311
333
320
388
265
391
313
422
282
411
344
278
303
353
372
413
338
307
323
349
415
345
Oxide Concentration
Ib/MBtu
0.272
0.291
0.280
0.339
0.232
0.342
0.274
0.369
0.247
0.359
0.300
0.246
0.269
0.313
0.330
0.366
0.300
0.272
0.286
0.309
0.368
0.306
ng/J
117
125
120
146
100
147
118
159
106
154
129
106
115
134
142
157
129
117
123
133
158
131
255
-------
200
0M 160
+J
~ 120
^
\
e
o 80
40
i r
Q.7.5 kg/s (60x10 Ib/hr) steam
O 6.3 kg/s (SOxlO3 Ib/hr) steam
A 3.8 kg/s (30xl03 Ib/hr) steam
I I
9 10 11 12
EXCESS OXYGEN, percent
13
14
Figure 5.7-13. Nitric oxide emissions vs. excess ©„, Fairmont Unit 3,
eastern coal.
256
-------
600
500
CM
O
0\o 400
ro
-P
rti
>, 300
S
g
a 200
o
100
15 20
14 —A A — _
Ql3 ._ 19
Tf\j*^' is _
17 12 ^^J I \ -i /r ^^ — *r "
u n-^ — ~~~®
i^**TZl 1 1
n 7.5 kg/s (60xl03 Ib/hr)
O 6.3 kg/s (45xl03 Ib/hr)
A 3. 8 kg/s (30xl03 Ib/hr)
1
steam
steam
steam
9 10 11 12
EXCESS OXYGEN, percent
13
14
Figure 5.7-14.
Nitric oxide emissions vs. excess
coal blend.
, Fairmont Unit 3,
257
-------
7.6 kg/s (60x10 Ib/hr), NO concentration increased at a rate of 14.65 ng/J
per % O • at 6.2 kg/s (49xl03 Ib/hr) , 22.6 ng/J per % O2/- and at 3.8 kg/s
(30x103 Ib/hr), 41.72 ng/J per % 0 For the coal blend, on the other hand,
the trend was reversed with a decreasing dependence in excess 0_ as the load
dropped. The corresponding figures are 15.09, 4.88 and 1.19 ng/J per % O^
at loads of 7.6, 5.7 and 4.0 kg/s, respectively- No explanation for this
behavior is attempted in this report.
The variation of nitric oxide with load is shown in Figure 5.7-15
and 5.7-16. Increased load results in increased furnace temperatures and
consequently increased nitric oxide formation. However, as can be seen in
Figures 5.7-4 and 5.7-5, the excess O is lowered as the load is increased.
This tends to counteract the temperature effect resulting in nitric oxide
concentrations which are relatively invariant with the load.
D. Boiler Efficiency—
Boiler efficiencies are generally determined by the heat loss method.
These heat losses occur in the form of unburned fuel such as carbon monoxide
in the stack and carbon retention in the ash; endothermic processes such as
i
vaporization of the moisture in the fuel; and direct thermal losses out of
the stack and radiation from the boiler surfaces. Each of these heat losses,
except for the radiation loss, may be a function of the fuel burned.
Thermal efficiency losses for several Fairmont Unit #3 tests on both
coals were computed. These computations are based on the ASME abbreviated
heat loss method or so-called "short form" computation from the ASME Power
Test Code 4.1. The results are shown in Table 5.7-6.
Carbon monoxide emissions are plotted as a function of excess 0» in
Figure 5.7-17. It is quite obvious that the coal blend emitted more CO than
did the eastern coal. It is also seen that the emissions increased at both
high and low excess 0_- However, because of the interrelationship between
load and 02 (excess 0^ is higher at lower loads in stoker fired units), it
is sometimes hard to determine which parameter has the most effect on emissions.
In this unit, low loads and high excess 0 created the most carbon monoxide.
258
-------
500
400
300
200
100
Q High 02
O Norm 02
A LOW O
Rated Load = 10.1 kg/s (SOxlO3 Ib/hr) steam
38
50 62
PERCENT OF RATED LOAD
74
Figure 5.7-15. Nitric oxide emissions vs. load, Fairmont Unit 3, eastern
coal.
259
-------
O
0\°
500
400
300
g 200
4
100
30
Q High O2
O Norm O
A Low 0
Rated Load = 10.1 kg/s (SOxlO3 Ib/hr) steam
40 50
PERCENT OF RATED LOAD
60
Figure 5.7-16. Nitric oxide emissions vs. load, Fairmont Unit 3, coal blend.
260
-------
TABLE 5.7-6. BOILER EFFICIENCY DATA,
FAIRMONT PUBLIC UTILITIES COMMISSION, UNIT 3
B3ILER CATEG0RY 21 1
DATE: 10/13/76
UNIT DESCRIPTI0N
TIME: 14:16:36
PAGE:
L0CATI0N N0.
B3ILER N0.
FURNACE TYPE
CAPACITY
103 Ib/hr
MRTU/HR
INSTALLED
ERECT!3N METH0D
RIJRNER TYPE
6
3
WT
10.1 kg/s (80.0)
80.0
1951
FIELD
55
FUEL ANALYSIS
NATURAL liAS
C02 0.
C3 0.
N2 Q.
H2S 0.
C»A 0.
C2H6 0.
C3H8 0.
C4H10 0.
C5H12 0.
HHVCBTU/CUFT) 0
C
H
0
N
S
H20
ASH
01L *)R CiJAL
62<
4.
9.
1
14
1
28
21
62
48
49
19
69
HHV//CBTU/LB) 10922
TEST N3.
TEST L3AD
KLB/HR
^ 0F CAP
STACK 02 <% DRY)
STACK CO (PPM)
STACK TEMP CF)
AMR AIR TEMP CF)
CBRR. STACK TEMP
HEAT BALANCE LOSSES C3RRECTED T0 80.F ENTERING AIR TEMP.
DRY GAS
M3IST + H2
M0ISTURE IN
UNTURNED C0
C3MRUSTIBLES
RAD I AT I 3N
12
6
AIR
EFFICIENCY
THERM3DYNAM1C EFF
78
0
,06
• 14
.29
>03
.61
.76
• 12
13.
6.
76.
0.
80
19
33
04
67
76
21
12.
6
2
1
77
0
40
09
30
04
30
.01
.86
17
6
3.
1 <
70.
0.
.51
• 00
,42
.41
.23
.54
.89
1 1
6
77.
0.
73
,14
.28
.15
• 99
.77
-94
261
-------
TABLE 5.7-6. Continued
BOILER CATEGORY 21 1
DATE: 10/13/*76
TIME: 14:16:36
PAGE:
UNIT DESCRIPTION
LOCATION N0.
BOILER Ni3.
FURNACE TYPE
CAPACITY
103 Ib/hr
MBTU'HR
INSTALLED
ERECTI0N METH3D
BURNER TYPE
6
3
WT
10.1 kg/s (80.0)
80.0
1951
FIELD
SS
FUEL ANALYSIS
NATURAL
C02
ca
N2
H25
CH4
C2H6
C3H8
C4H10
C5H12
GAS
o.
0-
o.
o.
o.
o.
o.
o.
0-
0
c
H
0
N
S
H20
ASH
IL 0R C0AL
62*28
4.21
9.62
.48
1 .49
14.19
7.69
HHV/CQTU/LB) 10922
HHV(BTJ/*CUFT>
TEST N3.
TEST LOAD
KLB/HR
% 0F CAP
STACK 0? (% DRY)
STACK C0 (PPM>
STACK TEMP CF)
AMB AIR TEMP CF)
C0RR. STACK TEMP(F)
01L 3R C0AL
B0ILER C0NDITI0NS
19
20
45.7
57-1
9.4
165-0
399-0
75.0
399.0
44.6
55.7
11.4
189.0
388.0
72.0
388-0
33.8
42.3
14. 1
805.0
393.0
83-0
393.0
B0ILER HEAT BALANCE LOSSES (Z)
HEAT BALANCE L0SSES C0RRECTED T0 80.F ENTERING AIR TEtfP*
DRY GAS
M3IST + H2
M3ISTURE IN AIR
IJNBIJRNED C0
C0MBUSTIBLES
RAD I AT 10N
R0ILER EFFICIENCY
THERM3DYNAMIC EFF.
10.
5
2
1
29
87
25
09
69
02
1 1
5
• 97
• 84
• 29
• 13
• 56
.04
16
5
2
1
75
85
41
74
74
37
79-80
0.
78-17
72-14
0.
262
-------
TABLE 5.7-6. Continued
BOILER CATEGORY 21 1
DATE: 10/13/76
UNIT DESCRIPTION
TIME: 15:17:04
PAGE:
FUEL ANALYSIS
LOCATION NO.
B3ILER NO.
FURNACE TYPE
CAPACITY
103 Ib/hr
M8TU/HR
INSTALLED
RRECTI0N METHOD
BURNER TYPE
6
3
WT
10.1 kg/s (80.0)
134
1951
FIELD
SS
NATURAL
C02
CO
N2
H2S
CH4
C2H6
C3H8
C4H10
C5H12
GAS
0
0
0
0
0
0
0
0
0
HHVCBTU/CUFT)
0IL -3R C3AL
BOILER CONDITIONS
OIL OR Ck)AL
C
H
0
N
S
H29
ASH
HHV/(8TU/LB>
68
A
1
\
2
7
35
56
72
06
23
84
8.21
12306
TEST N0
TEST LOAD
XLB/HR
% OF CAP
STACK 02 (X DRY)
STACK CO (PPM)
STACK TEMP (F)
A18 AIR TEMP CF)
C3RR. STACK TEMP(F)
48-9
61 •!
9.3
38.0
491 .0
77.0
491 .0
49-2
61 .5
10. 1
32.0
505-0
84.0
505.0
48 « 9
61 • 1
8.2
81 .0
429-0
81 .0
429-0
58-8
73.5
8.0
52-0
484.0
73.0
484.0
28-6
35-8
13.5
208.0
451 .0
70-0
451 .0
BOILER HEAT BALANCE LOSSES (%)
HEAT BALANCE LOSSES CORRECTED TO 80.F ENTERING AIR
DRY GAS
M0IST + H2
MOISTURE IN AIR
UNBURNED CvJ
C3MBUSTIBLES
RADIATION
EFFICIENCY
13
5
P.
77
13
05
31
02
56
95
1 4
5
45
07
35
02
91
94
76.26
99
94
.24
04
.78
• 95
80.07
11
5
.62
.04
.28
.03
-64
.79
79.61
17
4
48
98
.42
. 17
6- 10
1 .62
69.23
263
-------
TABLE 5.7-6. Continued
BdlLER CATEGORY 211
DATE: 10/13/76
UNIT DESCRIPTI0N
TIME: 15:17:04
PAGE:
L0CATI0N
BOILER N3.
FURNACE TYPE
CAPACITY
103 Ib/hr
MBTU/HR
INSTALLED
ERECT I0N METH0D
BURNER TYPE
6
3
WT
10.1 kg/s (80.0)
80-0
1951
FIELD
SS
FUEL ANALYSIS
NATURAL
C02
ca
N2
H2S
CH4
C2H6
C3H8
C4H10
C5H12
GAS
o.
o.
0-
o.
o.
o.
o.
0-
o.
UIL
C
H
k)
N
S
H20
ASH
0R C0AL
68.35
4*56
7.72
1 .06
2.23
7.84
8*21
HHV/CBTU/LB) 12306
HHVCBTU/CUFT)
TEST N0.
TEST L3AD
XLB/HR
% 0F CAP
•^TACK 02 (% DRY)
STACK Ca CPPM)
STACK TEMP (F>
AMB AIR TEMP (F)
C0RR. STACK TEMPCF)
OIL 3R CJAL
B0ILER C3NDITI0NS
62*6
78-2
6.5
155.0
486.Q
65.0
486*0
10
60.5
75.6
9.8
81 -0
493.0
66*0
493.0
R3ILER HEAT BALANCE L0SSES <%)
HEAT BALANCE L0SSES CORRECTED T0 80.F ENTERING AIR TEMP*
DRY GA*
M0IST * H2
M0ISTURE IN AIR
UNBURNED C0
C0MBUSTIBLES
RAD I AT 1 0N
EFFICIENCY
THE7?M0DYNAMIC EFF.
10.43
5.04
• 25
• 07
3. 19
• 74
80.29
0.
13.61
5.05
• 33
• 04
3. 1 1
.77
77.09
0.
264
-------
500
400
300
I
o
u
200
100
Coal blend
Eastern coal
J1
805 ppm
20
9 10 11 12
EXCESS OXYGEN, percent
Figure 5.7-17. CO comparison for eastern coal vs. blend, Fairmont Unit 3.
265
-------
E. Emissions Summary—
The emissions in brief are as follows. Particulates met applicable
regulations with both fuels,although the blend emitted 33% more than the
eastern coal. Sulfur oxides were basically unchanged at 1300 ng/J (3.0 Ib/MBtu),
with sulfur trioxide making up 2.5% of the total. Nitric oxide emissions were
basically unchanged on the average although they showed a much greater
dependence on excess O. while burning the eastern coal and therefore the
lowest nitric oxide emissions found were for eastern coal at minimum excess
oxygen. And, combustion efficiency was reduced when burning the blend.
The conclusion can only be that burning this particular blend in this
particular boiler is not justified on an emissions basis.
266
-------
5.8 WAUPUN CENTRAL GENERATING PLANT, UNIT #3, WAUPUN
WISCONSIN
Densified Refuse-Derived Fuel (d-RDF) was blended directly with coal
and successfully fired in a spreader stoker fired water tube boiler without
boiler modification. Twenty percent and thirty percent d-RDF blend, computed
on a Btu basis, were successfully fired while a 40% blend firing failed due
to excessive clinker formation on the grate. Particulate, nitric oxide and
carbon monoxide emissions were found to be unaffected by the addition of
d-RDF. Sulfur oxide emissions were reduced.
5.8.1 Introduction
The testing conducted at Waupun Central Generating Plant (CGP) represents
an important deviation from the mainstream of the Western Coal Project.
Instead of evaluating western coal combustion against a base line eastern coal,
a refuse derived fuel was evaluated as a fuel supplement against a base line
western coal.
The importance of such an evaluation is easily seen. With dwindling
fossil fuel reserves and increasing solid waste disposal problems, the success-
ful demonstration of a refuse-derived fuel supplement could lead to a signifi-
cant improvement in our energy situation. As an added benefit, these refuse-
derived fuels are usually very low in sulfur thus reducing sulfur oxide
emissions.
It has been said that boilers can be designed to burn any fuel. Of
more importance in this case are the following questions. How can refuse
derived fuels be made to burn in existing boilers? To what extent can the
normal fuel (usually coal) be supplemented with this fuel? To answer these
questions the Wisconsin Solid Waste Recycling Aughority in cooperation with
other state and private agencies tested several state-owned boilers with a
densified Refuse-Derived Fuel (d-RDF).
KVB, Inc. was invited to participate in the data-taking at the CGP,
Waupun State Prison, for the purposes of this report. Credit is due OSM, Inc.
and the various Wisconsin state agencies for organizing and conducting the
testing, and to the Wisconsin Division of Natural Resources for supplying us
with the particulate data taken during the actual d-RDF firing.
267
-------
5.8.2 Boiler Description
The boiler tested was Unit 3 at the Waupun Central Generating Plant,
Waupun, Wisconsin. This unit consists of a four drum, bent tube boiler manu-
factured by Wickes Boiler Company and installed in 1948. It is fired by two
Riley Corporation spreader stokers feeding a hydraulically operated-traveling
grate. The furnace is a balanced draft unit and the furnace pressure is
maintained at -20 cm HO. Induced draft (ID) and forced draft (FD) fans were
supplied by the Clarage Fan Company. The boiler design capacity is 3.8 kg/s
(30,000 Ib/hr steam flow). This unit has twelve overfire air ports, four on
each side wall and four on the back wall of the furnace. An interesting
feature of this unit is that the overfire air is preheated before entering
the furnace.
After combustion, the hot flue gases pass upward in the boiler through
a superheater section. Day-to-day operating data indicates an outlet steam
pressure of 3.0 MPa (425 psig) and steam temperature of 650 °K (710 °F) .
The unit does not have steam attemperation. After passing the superheater
section, the hot gases cross a short section of water tubes connecting the
lower drum to the chemical drum and then enter the cyclone dust collector.
Fly ash captured in the cyclone is returned to the grate ash hopper under the
boiler. Originally the ash from the cyclone was reinjected into the furnace,
but, the reinjection was eliminated several years ago. The flue gas is
finally pulled through the ID fan and exhausted into a breeching (shared by
other boilers at the facility) that leads to the smokestack.
The role of the Waupun CGP is to provide power to the adjacent Wisconsin
State Prison and the nearby state hospital. Very significantly, Waupun CGP
has no tie-in with outside power sources. As a result, special precautions
' i
were required during testing which resulted in inconveniences which will be
described later.
5.8.3 Sample Locations
The facility at Waupun CGP consists of three identical coal- fired
boilers and one gas-fired boiler connected to a single stack by a common
manifold. Figure 5.8-1 is a schematic of the facility.
268
-------
O Test ports used
to
<£>
X^Test ports not u
/Orsat
Particulates
x ox
x o tt
Xf\ f^
O \.s
* rt *
x 8 x
STACK
\
O
CO
p /co
Multiclone Multiclone Multiclone^
',.._ „. „ , Zi C-/L
2
i j _...J i . ., .... .' O*^[ SU9
UNIT 1 UNIT 2 UNIT 3
Stoker Backup stoker d-RDF
not operating operating at test boiler
low load
-<«
•^ E
t
1
UNIT 4
Gas boiler
not operating
Dampers closed
to prevent air
leakage
Figure 5.8-1. Schematic of boilers and flue gas duct system, Waupun, Wisconsin.
-------
The initial plan was to test Unit 2 using the gas boiler as a backup.
For this purpose, four sample ports were installed at the inlet to the dust
collector on Unit 2. The sample ports located where the breeching enters the
stack were already in existence and were to be used for particulate and sulfur
oxide testing. Because of the dilution effect of the gas boiler effluents,
four ports were installed at the outlet of the gas boiler. The objective was
to sample gas flows, excess 0 and CO at the gas boiler in order to correct
the stack data. A series of nine complete tests were made on Units 2 and 4
in this manner.
Just prior to the RDF test burning it was decided to use Unit 3 for
the tests with Unit 2 as backup. In this way, the emissions would not be
subject to dilution. Test ports were installed as shown in Figure 5.8-1.
Cross sections of the inlet and outlet sample areas are shown in Figure 5.8-2.
Because the tests were of short duration; it was only possible to
sample particulates at the outlet and gaseous components at the inlet.
Unfortunately, due to time restrictions and crowded conditions at the sample
areas, KVB was not allowed to sample sulfur oxides by the Shell-Emeryville
wet chemical method. A sulfur oxides continuous monitor was used instead,
but due to problems with this unit, its data was rejected.
5.8.4 Discussion of Refuse-Derived Fuel
The refuse-derived fuel tested at Waupun CGP was supplied by Grumman
Ecosystems, Inc. of St. Louis. It arrived in the form of cylindrically
shaped pellets measuring 1.9 cm (3/4 inch) in diameter and varying in length
from 1.27 to 7.5 cm (1/2 to 3 inches). It is properly called densified refuse
derived fuel (d-RDF) to distinguish it from the shredded variety-
In order to understand the problems encountered while burning d-RDF
in Waupun Unit 3, some of the fuel related factors affecting spreader stoker
operation must be understood. For example, fuel pellet sizing is important.
It must be sized to mix well with the coal. It must be large enough to be
distributed evenly on the grate without piling up under the feeders yet small
enough to burii out completely before being dumped into the ash pit.
270
-------
2.43 m
-(96")—
r
0.56 m
(22")
O , CO , CO, NO and SO Monitors
DUST COLLECTOR INLET
1.51 m
(59.5") •
Particulate
and Orsat
Sample Points
4-4-+--I-4+-+-+
+ •«-
0.19m
(7.5")
DUST COLLECTOR OUTLET
1.78 m
(70")
Figure 5.8-2. Sample area geometry, Waupun Unit 3.
271
-------
The moisture content must be controlled to low levels to facilitate
easy ignition and complete burnout. High moisture levels affect the dis-
tribution of radiant-to-convective heat transfer resulting in high superheat
temperatures. Consequently, boilers burning a high moisture fuel often
experience decreased capacity and slagging problems in the convective
passes. Increased ID fan requirements may also result from the requirement
to remove the water vapor from the boiler along with the flue gas.
Ash properties pose another problem. Refuse-derived fuels often
contain large concentrations of chloride compounds which are very corrosive.
This disadvantage is partially offset by their inherently low sulfur
content. Also, ash fusion temperatures have been reported to be very low
resulting in clinker problems on the grate and fouling in the convective
passes.
The high ash content of refuse-derived fuels can mean reduced
capacity due to ash handling limitations, and more man-hours in ash
pulling operations. It can also mean greater FD fan requirements due to
the higher resistance of the thick ash bed.
Spreader stokers rely on a certain percentage of their fuel to be
burned in suspension. Since there were no fines in the d-RDF supplied to
Waupun, fuel blends containing more than 50% d-RDF on a Btu basis would be
unsatisfactory unless the coal used had a high concentration of fines. In
addition to the combustion factors just mentioned, d-RDF fuel cannot be stored
unprotected outside as can coal, since it is hygroscopic (absorbs moisture).
When this happens, it literally comes unglued and can't be burned. Each of
these factors, as well as other as yet unknown factors, must be considered
when converting an existing boiler to burn refuse-derived fuel. The fuel
analysis of the d-RDF and coal fired at Waupun is given in Table 5.8-1. It
can be noted that the sulfur in the d-RDF is low (0.22%) and even on a weight
of equivalent S02 per unit heating value it is low at 300 ng/J (0.7 lb/106
Btu). The fuel nitrogen in the d-RDF is high on a heating value basis but
not as high as it was in some of the coals burned in this program. Certainly
the heating value of the d-RDF is high enough to warrant handling and limited
shipping of this fuel.
272
-------
TABLE 5.8-1. COMPARISON OP TEST FUELS FIRED AT WAUPUN UNIT 3
DENSIFIED REFUSE-DERIVED FUEL
Grununan Ecosystems, St. Louis
PROXIMATE ANALYSIS As
% Moisture
% Ash
% Volatile
% Fixed Carbon
High Htg Value, MJ/kg
Btu/lb
* Sulfur
» Alk. as Na 0
SULFUR FORMS
» Pyritic Sulfur
% Sulfate Sulfur
* Organic Sulfur
% Total Sulfur
ULTIMATE ANALYSIS As
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
MINERAL ANALYSIS
Phos. pentoxide, P,O
Silica, SiO2
Ferric oxide, Fe_O
Alumina/ A1,,O_,
23
Titania, TiO-
Lime , CaO
Magnesia, MgO
Sulfur trioxide, SO
Potassium oxide , K_O
Sodium oxide, Na_0
Undetermined
Silica Value « 75.57
T250 » 2415 «F (1597 •
FUSION TEMPERATURE OF ASH
Initial Deformation
Softening (H=w)
Softening (H=1/2W!
Fluid
Received Dry Basis
4, 33 xxxxx
30.49 31.87
54.34 56.80
10.84 11.33
100.00 100.00
14.3 14.9
6161 6440
0.22 0.23
xxxxx 2.33
* *
0.00 0.00
* *
0.22 0.23
» Weight
Received Dry Basis
4. 33 xxxxx
34.31 35.86
4.59 4.80
0.57 0.60
0.54 0.56
0.22 0.23
30.49 31.87
24.95 26.08
100.00 100.00
» Weight
Ignited Basis
0.70
59.41
5. 88
9.07
1.05
11.67
1.66
2.23
1.95
6.04
0.34
100.00
K)
Reducing
1930 °F (1328 °K)
2025 °F (1380 °K)
2120 °F (1433 °K>
2215 °F (1485 °K)
n£,D iHKW
Colstrip,
PROXIMATE ANALYSIS
* Moisture
« Afih
% Volatile
* Fixed Carbon
High Htg Value, MJ/kg
Btu/lb
» Sulfur
* Alk. as Na 0
SULFUR FORMS
% Pyritic Sulfur
% Sulfate Sulfur
» Organic Sulfur
% Total Sulfur
ULTIMATE ANALYSIS
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
MINERAL ANALYSIS
Phos. pentoxide, ?S>,
Silica, SiO
Ferric oxide, Fe^
Alumina, *12O3
Titania, Ti&2
Lime , CaO
Magnesia, MgO
Sulfur trioxide, SO
Potassium oxide, K^o
Sodium oxide, Na2O
Undetermined
Silica Value - 50.86
(JUAL
Montana
As Received Dry Basis
10.88 xxxxx
10.55 11 84
35.44 39. 76
43.13 48.40
100.00 100.00
22.8 25.5
9791 10986
0.93 1.04
xxxxx 0.06
0.50 0.56
0.13 0.15
0.30 0.33
0.93 1.04
* Weight
As Received Dry Basis
10.88 xxxxx
58.16 65.26
3.86 4.33
0.48 0.54
0.01 0.01
0.93 1.04
10.55 11.84
15.13 16.98
100.00 100.00
% Weight
Ignited Basis
0.16
33.42
7. 76
16.24
0.71
20.20
4.32
15.26
0.48
0.52
0.93
100.00
T250 - 2220 °F (1489 °K)
FUSION TEMPERATURE OF ASH
Initial Deformation
Softening (H-=W)
Softening (H-1/2W)
Fluid
Reducing
2100 °F (1422 °K)
2130 "F (1439 °K)
2160 °F (1455 °K>
2180 °F (1467 °K>
(H = cone height;
w = cone width)
•Unable to determine
Standard method not applicable
(H * cone height;
W = cone width)
273
-------
5.8.5 Fuel Blending
The d-RDF was transported from St. Louis to Waupun by truck and piled
in an open area outside the plant. To protect it from the weather, the pile
was covered with large plastic sheets.
Mixing was accomplished with a front-end loader. Buckets of each
fuel were alternately dumped into the freight car unloading hopper in a pre-
determined ratio as outlined in Table 5.8-2. Mixing was accomplished at the
various transfer points as the fuel was transported to live storage.
The 20% and 40% mixtures were prepared the day before actual firing.
The 30% blend was accomplished by alternately feeding the previously mixed 40%
blend into the feeder hopper for 90 seconds followed by 30 seconds of pure
western coal. This procedure was continued until all of the 40% blend was
mixed.
TABLE 5.8-2. FUEL MIXING SCHEDULE, WAUPUN UNIT 3
d-RDF
Coal
14.3 MJ/kg
(6161 Btu/lb)
22.8 MJ/kg
(9791 Btu/lb)
0.761 g/cm3
(47.5 Ib/ft )
0.785 g/cm3
(49 Ib/ft3)
10,900 J/cm3
(292,648 Btu/ft )
17,873 J/cm3
(479,759 Btu/ft )
20% BLEND (26.3% d-RDF by volume; 17.9% d-RDF on Btu basis)
10 parts d-RDF + 28 parts coal by volume
= 16,035 J/cm3 (430,519 Btu/ft3)
= 20.6 MJ/kg (8,840 Btu/lb) assuming 0.780 g/cm (48.7 Ib/ft )
40% BLEND (50.0% d-RDF by volume; 37.9% d-RDF on Btu basis)
20 parts d-RDF + 20 parts coal by volume
= 14,384 J/cm3 (386,203 Btu/ft3)
= 18.6 MJ/kg (7,979 Btu/lb) assuming 0.775 g/cm (48.4 Ib/ft )
30% BLEND (37.5% d-RDF by volume; 26.8% d-RDF on Btu basis)
3 parts 40% mixture + 1 part coal by volume
= 15,256 J/cm3 (409,592 Btu/ft3)
=19.6 MJ/kg (8,436 Btu/lb) assuming 0.778 g/cm (48.55 Ib/ft )
274
-------
As can be seen, our computations show that the actual mixture
contained less d-RDF on a BTU basis than the test labels (i.e., 20, 3J
and 40%) indicate. Nevertheless, the labels will be used throughout this
report.
A problem was encountered in blending the d-RDF. As the mixture
traveled down the chute towards the spreaders, the less dense d-RDF
pellets tended to move towards the sides of the chute. This segregation
of the fuels may have contributed to the clinkering problem. It is suggested
that smaller sized d-RDF pellets might blend more easily with the coal.
5.8.6 Control Room Observations
The following observations were made during the actual test firing.
It should be noted that the "average load" was computed by dividing the steam
flow integrator readings by the time between readings. A summary of the
more important operating variables is given at the end of this section.
TEST #1, 20% d-RDF, JUNE 3, 1976
The first test was for a mixture containing 20% d-RDF and 80%
Western coal on a BTU basis. The duration of the test was 5 1/2 hours.
The mixture, having been fed into the bunker, was not expected to reach
the feeders until about 9:00 am. To everyone's surprise, the pellets were
first observed on the grate at about 8:15 am. It was estimated that the
actual start was at 8:00 am.
There were no immediate problems or obvious changes in boiler
operation at transition. The first indication of transition to the d-RDF
blend was the visual observance of pellets on the grate. The d-RDF ash
retained its form and appeared to "float" on top of the ash bed. These ash
pellets fell apart when picked up and appeared to be nearly if not completely
burned out.
275
-------
Figure 5.8-3.
Photograph of a 30% d-RDF blend as
fired at Waupun.
276
-------
As the burning progressed, the ash bed began to thicken. To keep
the bed thickness within limits, the grate speed was increased gradually
throughout the run from three to six (relative numbers on the grate speed
control). Despite this increase in grate speed, the ash bed increased in
thickness to 6-8 cm (2-1/2 - 3 inches). On pure western coal, the ash bed
is 4-5 cm (1-1/2 - 2 inches) thick.
At 9:40 am, a problem with clinkers developed. It appeared that the
d-RDF was piling up in front of the feeders. At 10:45, the spill plates
(trajectory plates) were pulled back 1 cm (3/8 inch) in an attempt to throw
the coal and pellets further back on the grate. Immediately after this change,
the load dropped from its peak of 3.1 kg/s (24xl03lb/hr) to 2.3 kg/s (ISxlO3 Ib/hr)
due to lunch break at the prison. Fuel distribution on the grate appeared to
improve with the spill plate adjustment and clinker problems were moderate
for the duration of this run.
Smoke remained at 11% on the opacity meter throughout this run. This
is the same as for pure western coal under the same load condition. Average
load for this test was 2.8 kg/s (22,500 Ib/hr) steam.
TEST #2, 40% d-RDF, JUNE 3, 1976
When the fuel from test #1 had burned down to the windows just above
the feeders, a d-RDF/coal blend containing 40% d-RDF on a Btu basis was added
to the bunker. Transition to the new blend occurred at 1:30 p.m.
The grate speed was increased in steps from 6 to 8.2 to handle the
increased ash. At 2:10 p.m. clinkering became moderate. By 2:34 p.m. a massive
coal pile covered the entire front of the grate riding on top of a very large
clinker. Carbon monoxide was rising out of limits (2000+ ppm) and smoke was
increasing (25%). By 3:00 p.m. the clinker problem became severe. The pile under
the feeders was so high you couldn't see into the boiler through the ash doors.
The pile covered the full width of the boiler, extended four to five feet back
from the front wall and was about one foot thick.
277
-------
Luckily, only a small amount of the 40% mixture had been put in the
bunker and transition to 100% western coal was made at 3:20 p.m. Duration of
this test was one hour, fifty minutes. Average load was 2.9 kg/s (22,900
Ib/hr) steam.
TEST #3, 100% WESTERN COAL, JUNE 4, 1976
In order to obtain base line data on Unit 3, pure western coal was
burned long enough to allow the Wisconsin DNR to get particulate data at the
multiclone outlet and KVB to get control room data and gaseous emissions data
at the multiclone inlet.
Burning was routine with no clinker problems. Ash was completely
burned out, grate speed was set at 2.8 and spill plates were set at 5 cm
(2 inches). Ash bed was 4 cm (1-1/2 inches) thick and smoke varied from
10-12% opacity.
Testing commenced at 8:30 a.m. and terminated at 10:20 a.m. Duration
of this test was one hour, fifty minutes. Average load was 2.77 kg/s-(22,000
Ib/hr) steam.
TEST #4, 30% d-RDF, JUNE 4, 1976
A 30% d-RDF mixture was obtained by feeding the previously mixed 40%
d-RDF mixture into a bunker for 90 seconds followed by 30 seconds of pure
western coal. This procedure was continued until all of the 40% blend was
mixed.
Based on the previous day's experience, the spill plates (stoker
trajectory plates) were set back to 4.75 cm (1-7/8 inches) and the grate speed
increased from 2.8 to 5.6 (relative indication on control device) immediately
upon transition. The combustion air was raised considerably over what it had
been during the previous d-RDF burns.
The flame appeared to become more luminous. The flame front became
more irregular but moved forward about half a foot. This may have been partly
due to increased grate speed. Flame impingement on the back wall also in-
creased. At 11:15 a.m. the load dropped drastically to about 1.25 kg/s
(10,000 Ib/hr) steam, then oscillated back and forth around 1.9 kg/s (15,000
Ib/hr) steam. It appeared to be an automatic control problem which over-
corrected for the noon time drop in load.
278
-------
One very large clinker formed and was removed at 12:30 p.m. This was
the only major problem with the 30% blend. Testing started at 10:20 a.m. and
concluded at 1:00 p.m. Duration of test was two hours and forty minutes.
Average load was 2.2 kg/s (17,600 Ib/hr) steam.
SUMMARY OF OPERATING VARIABLES
Some of the more important operating variables are given in Table 5.8-3
below. The first nine items are used in boiler efficiency calculations dis-
cussed in Section 5.8.9. # steam/# fuel, or evaporation as it is commonly
called, is an average for each test excluding the transition period when most
of the stoker adjustments were made. Smoke (%) indicates the extremes for the
three or four readings taken off the opacity meter each test. Grate speed is
a relfttive indication on the control device. The numbers shown represent the
final setting for that test. Spill plate (trajectory plate) setting is relative.
The lower numbers indicate the plate was pulled back in an attempt to throw
the fuel further back on the grate.
TABLE 5.8-3. OPERATING VARIABLES, WAUPUN UNIT 3
Feedwater Temperature, °K
OF
Steam Temperature, °K
oF
Steam Pressure, Pa
psig
Steam Flow, 10 3 Ib/hr
Heating Rate, kg/s
FD Fan Inlet Temperature, °K
oF
Relative Humidity at FD Fan, %
Flue Gas Temp., Boiler Outlet, °K
op
Excess ©2, Boiler Outlet, %
Carbon Monoxide, Boiler Outlet, ppm
Evaporation, # steam/# coal or
Kg steam/Kg coal
Smoke, % opacity
Grate Speed, Relative
Spill Plate Position, Relative
0% RDF
425
305
652
713 6
3.03x10
425
22.0
13.5
303
86
55
608
635
9.75
589
5.68
10-12%
2.8
5.08 cm
(2")
20% RDF
426
306
650
710
3.01x10
422
22.5
13.8
303
85
40
—
—
9.25
510
4.99
11%
6.0
4.76 cm
(1-7/8
30% RDF
428
310
646
703
3.03x10
425
17.6
10.8
305
89
37
604
627
11.0
818
4.84
10-11%
6.6
4.76
11 ) (1-7/8
40% RDF
427
308
656
720 .
£5
3.02x10
423
22.9
14.0
306
90
33
618
652
8.63
2450
4.22
13-25%
8. 2
cm 4.76 cm
") (1-7/8")
279
-------
The demonstration burning at Waupun CGP was of too short a duration
for the operators to become thoroughly familiar with the new fuel. Had more
time been available stoker controls could have been optimized and many of the
clinkering problems reduced. The operators now feel that more undergrate air
would have helped.
5.8.7 Particulate Emissions
Particulates were measured at the dust collector outlet as described
in Section 5.8.3. The actual sampling was conducted by the Wisconsin DNP,
while the computations were made by KVB, Inc. based on our own fuel analysis.
The data, Table 5.8-4, shows that particulate emissions remained
relatively stable until the 40% blend was fired. At this point,
doubled. This doubling of emissions was probably due to the ashes
stirred up while trying to break up and remove clinkers forming on the gfftte.
TABLE 5.8-4. PARTICULATE EMISSIONS FROM WAUPUN UNIT 3
Blend
% d-RDF
0%
20%
30%
40%
Average Load
kg/s 103 Ib/hr
2.74
2.83
2.22
2.89
22.0
22.5
17-6
22.9
Concentration
02, % Ib/scfxlO"4
9.73
9.59
11.53
10.50
0.282
0.319
0.206
0.577
Emissions
Ib/MBtu
0.520
0.576
0.446
1.122
Emissions
ng/J
224
248
192
482
Figure 5.8-4 illustrates the particulate emissions as a function of
fuel blend. The slight drop in emissions during the 30% blend firing is due
to the lower boiler load during this test. To illustrate this point, the d-RDF
test data is plotted against load along with the base line data obtained from
Unit #2 on Figure 5.8-5 (see Section 5.8.3 for explanation of Unit #2 base
line testing). Because the two units are identical, they should have the
same characteristic emissions plot. As can be seen, only the 40% blend was
out of line.
280
-------
500
400
hj
\
c
W
EH
5 300
H
§
CM
H 200
EH
D
O
100
0 10 20 30 40 50
PERCENT RDF IN FUEL ON BTU BASIS
60
Figure 5.8-4. Particulates vs. fuel mixture, Waupun Unit 3.
281
-------
600
500
C 400
w
§
5 300
u
H
cu
200
100
Q40% d-RDF
Baseline Data, Unit 2
d-RDF Test Data, Unit 3
Rated Load =3.78 kg/s (30xl03 Ib/hr) steam
50
30% d-RDF
20% d-RDF
o
O 0% d=RDF
O
67 84
PERCENT OF RATED LOAD
100
Figure 5.8-5. Outlet particulates vs. boiler load, Waupun Unit 3.
282
-------
5.8.8 Gaseous Emissions
Gaseous emissions were measured at the boiler outlet just before the
dust collector as shown in Figures 5.8-1 and 5.8-2. They included excess 0 ,
C02, CO, and NO. The data represents average emissions over the most stable
portion of each test, usually covering a one hour period. The data is
tabulated in Table 5.8-5.
TABLE 5.8-5. GASEOUS EMISSIONS, WAUPUN UNIT 3
o2, %
co2, %
C00 + 0 , %
2 2
CO, ppm @ 3% O
NO, ppm @ 3% 02
NO, Ib/MBtu
NO, ng/J
0% d-RDF
9.75
10.00
19-75
589
266
0.226
97
20% d-RDF
9.25
10.40
19.65
510
247
0.219
94
30% d-RDF
11.00
8.40
19.40
818
273
0.241
103
40% d-RDF
8.63
11.10
19.73
2450
205
0.180
77
In a spreader stoker, excess air requirements normally drop with
increasing load. The characteristic excess O2 versus load curve for Unit 2
was determined with the base line tests as explained in Section 5.8.3. It is
plotted in Figure 5.8-6 along with the d-RDF test series data. Unit 3, being
identical to Unit 2, would be expected to have a similar characteristic plot.
The dashed line through the 0% d-RDF test point represents this expected plot.
Based on this curve, the 40% blend, and to a lesser extent the 20% blend, were
low in air. Probably the extra thickness of the RDF ash bed restricted air
flow through the grate. For the 30% blend firing, a conscious effort was
made by the operators to increase grate air. Their effort appears to have
been successful and the result was a more uniform fire with only minor
clinkering.
283
-------
13
12
ft
- 10
X
o
o
X
H
o
'o
o
Baseline Data, Unit 2
Q d-RDF Test Data, Unit 3
Rated Load = 3.78 kq/s (30xl03 Ib/hr) steam
50
67 84
PERCENT OF RATED LOAD
100
Figure 5.8-6. Excess O vs. load, Waupun Unit 3.
284
-------
Carbon monoxide did not vary from the norm except as a result of
excessive clinker formation during the 40% blend firing, in Figure 5.8-7,
carbon monoxide is plotted against load and compared with the base line data
obtained from Unit 2. The numbers, except for the 40% blend, are in good
agreement.
Nitric oxide emissions dropped during the 40% blend firing because of
the lower furnace temperatures and the lower excess 02- During the 30% blend
test they were higher because of the higher excess 0 . This dependence on
excess 02 is normal. There is no indication that blending of d-RDF with the
coal affected nitric oxide emissions except in the already mentioned case of
the 40% blend where, due to poor combustion conditions, the NO emissions were
reduced. Figure 5.8-8 illustrates the dependence of nitric oxide emissions
on excess 0_.
The results of the sulfur oxide tests were inconclusive. Normally,
sulfur oxides are measured quite accurately with the Shell-Emeryville wet
chemical method. Unfortunately, this could not be fit into the already cramped
test schedule. Instead, measurements were made with a continuous SO monitor
built by Theta Sensors with which we were having calibration problems. We
believe that the instrument was sensitive to changes in emissions levels but
low in absolute value.
The 0% and 30% blends were both monitored for SO on the same day
without changing the zero and span settings on the monitor. Based on this
data, the reduction in SO emissions for the 30% blend firing was 31%. This
is about double the 15% reduction in fuel sulfur on a Btu basis.
A more accurate indication of sulfur oxide emissions in this case is
obtained from the fuel and grate ash analysis. Table 5.8-6 represents a sulfur
balance on the various d-RDF tests with sulfur oxide emissions determined by
the difference between fuel sulfur and sulfur retention in the ash. Figure
5.8-9 graphically represents this data. The data shows that an 18.8% reduction
in sulfur emissions could be realized by blending 30% d-RDF in with the
Montana coal.
285
-------
1200
O* 1000
800
5 600
W
Q
H
x
§ 400
o
200
t
30% d-RDF
2450 ppm
40% d-RDF
20% d-RDF
0 Baseline Data, Unit 2
Q d-RDF Test Data, Unit 3
Rated Load = 3.78 kg/s (30xl03 Ib/hr) steam
50
67 84
PERCENT OF RATED LOAD
100
Figure 5.8-7. Carbon monoxide vs. load, Waupun Unit 3
286
-------
120
110
100
X 90
o
I 80
70
ol—^
0% d-RDF
d-RDF
9 10
EXCESS OXYGEN, percent
11
Figure 5.8-8. Nitric, oxide vs. excess 0^, Waupun Unit 3.
287
-------
2.5
+j
CQ
•)
O
\ 2.0
1-1
Crl"
Q
H
H 1'5
Q
D
a
!D
m 1.0
a-
1
w 0.5
0 Sulfur from Fuel Analysis
Q Sulfur from Ash Analysis
__
—
m
f.
V
1
1
1
1
I
1
1250
^
1000^
k
H
Q
H
750 0
Q
cc;
D
g
500 w
D
250 w
0 20 30 40
PERCENT d-RDF IN FUEL
Figure 5.8-9. Sulfur in fuel and grate ash vs. fuel blend, Waupun Unit 3.
288
-------
The sulfur retained in the ash is especially significant. It is
shown to increase with the % d-RDF blended in the fuel. This is probably
due to the alkalinity of the d-RDF ash. Basic (alkali) ashes retain more
sulfur oxides than neutral or acidic ashes. Table 5.8-1 shows the sodium
oxide (Na2O) content of the d-RDF ash to be 6.04%. This is over ten times
the 0.52% Na O found in the western coal ash. Sodium oxide is the most
basic of most common ash components in coal.
TABLE 5.8-6. SULFUR OXIDES BALANCE, WAUPUN UNIT 3
Fuel Blend
% d-RDF
Fuel Sulfur
As SO2,
lb/106 Btu
Ash Sulfur
As SO2,
lb/106 Btu
Calculated
Emissions
S02, ng/J
(lb/106 Btu)
Sulfur Retention
in Ash, %
0%
20%
30%
40%
1.900
1.652
1.612
1.479
0.153
0.170
0.193
0.307
751
(1.747)
637
(1.482)
610
(1.419)
504
(1.172)
8.1
10.3
12.0
20.8
289
-------
5.8.10 Conclusions
1. A coal refuse blend containing 30% d-RDF has been
successfully fired in Waupun Unit 3 for a short
period of time without boiler modification.
2. Long term tests are required to assess any fouling
tendencies, corrosion effects, or ash removal
problems, and to further refine the stoker adjustments
to minimize clinker formation.
3. Measured pollutant emissions were not adversely affected
by the fuel blending. Nitric oxide, carbon monoxide
and particulate emissions were unchanged for mixtures
of up to 30% d-RDF. Sulfur oxides are expected to
decrease although further testing is required to
confirm this.
4. When firing d-RDF, more undergrate air is required
due to the resistance of the thicker ash bed.
5. Because of the thicker ash bed from firing d-RDF,
faster grate speeds are required to keep ash
buildup to a minimum.
6. Adjustment of the stoker spill plate is necessary
to distribute the fuel further back on the grate
when firing d-RDF.
7. Smaller d-RDF pellets should be tried for improved
blending and improved distribution on the grate.
The overall conclusion is that the tests were successful. We feel
that enough was learned to proceed with a longer term test. Such a test
would be required to fully assess the operating and environmental effects
of burning densified refuse derived fuel in spreader stokers of this type.
290
-------
5.9 ST. JOHN'S CENTRAL GENERATING PLANT UNIT #2, ST. JOHN'S ABBEY
COLLEGEVILLE, MN '
An eastern coal and a western coal were burned in a 1.7 kg/s
(13,500 Ib/hr) steam water-walled steam generating unit equipped with two
Riley spreader stokers and a split dumping grate. Both fuels could be
burned equally well without clinker or smoke problems, and without capacity
limitation. The western coal emitted lower particulates and lower nitric
oxide emissions. Carbon monoxide emissions were unchanged, and the western
coal emitted greater concentrations of sulfur oxides and hydrocarbons.
Overfire air was found to effect only the nitric oxide emissions which it
increased slightly. An ash balance was made on the system.
5.9.1 Introduction
The testing conducted at St. John's Unit #2 was unique in two ways.
First, this boiler was the smallest in the test series having a capacity
of only 1.7 kg/s (13,500 Ib/hr steam) continuous load. Secondly, this
was the only boiler tested in the series having a dumping grate.
This particular ash handling system allowed the weighing of ash
produced from a given amount of coal and allowed an ash balance to be made
on the system. Section 6.0 is devoted to this topic.
The eastern coal upon which the baseline tests were conducted was
also unique. It had an unusually low sulfur content of only 0.58%. This
coal was of unknown origin. It had been sitting outside for ten years,
ever since the facility had switched to a western coal as its primary fuel.
The present power plant superintendent had not ordered it and could find
no records on it.
The eastern coal had a lower sulfur level than the western coal.
This is probably due to the fact that the coal was stored outdoors for ten
years. During this time the insoluble pyritic sulfur was probably air oxi-
dized to soluble sulfate sulfur and leached out as sulfuric acid or sulfate
salts. This is supported by the low pyritic sulfur concentration found in
the analysis. A complete analysis of the two coals is given in Table 5.9-1.
Testing took place between 6/10/76 and 7/8/76.
291
-------
TABLE 5.9-1. COMPARISON OF TEST COALS, ST. JOHN'S UNIT 2
WESTERN COAL
Bighorn,Wyoming
PROXIMATE ANALYSIS As Received
» Moisture
* Ash
» Volatile
% Fixed Carbon
High Htg Value, MJ/kg
Btu/lb
» Sulfur
15.77
5.14
37.52
41.57
100.00
24.5
10515
0.61
—
„
6.10
44.54
49.36
100.00
29.0
12484
0.73
0.17
EASTERN COAL
Origin Unknown
PROXIMATE ANALYSIS As Received
t Moisture
% Ash
» Volatile
% Fixed Carbon
Higii Htg Value, MJ/Xg
Btu/lb
% Sulfur
% Alk. as Na.,0
5.18
5.29
35.58
53.95
100.00
30.5
13123
0.58
—
..
5.58
37.52
56.90
100.00
32.2
13840
0.61
O.OB
SULFUR FORMS
% Pyritic Sulfur
» Sulfate Sulfur
% Organic Sulfur
t Total Sulfur
ULTIMATE ANALYSIS
0.24
0.00
0.37
0.61
0.29
0.00
0.44
0.73
% Weight
As Received Dry Basis
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
15.
59.
4.
0.
0.
0.
5.
13,
100.
77
,95
26
81
.01
,61
,14
.45
.00
_.
71.
5.
0.
0.
0.
6.
15.
100.
18
06
96
01
73
10
96
00
* Weight
MINERAL ANALYSIS
Phos.pentoxide, P,o
Silica, Si02
Ferric oxide, Fe2O3
Alumina, A12O3
Titania, TiO2
Lime , CaO
Magnesia, MgO
Sulfur trioxide, SO3
Potassium oxide, K20
Sodium oxide, Na2o
Undetermined
Ignited
'
1.
35.
6.
18.
1.
14.
4.
14.
0.
2.
0.
Basis
09
19
36
89
15
85
36
20
66
28
97
Silica Value - 57.91
T250 = 1525°K (2285°F)
FUSION TEMPERATURE OF ASH
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid
(H «= cone height;
W = cone width)
100.00
1400°K(2060°F)
1439°K(2130°F)
1478°K(2200'>F)
1522°K(2280°F)
SULFUR FORMS
* Pyritic Sulfur
% Sulfate Sulfur
% Organic Sulfur
% Total Sulfur
ULTIMATE ANALYSIS
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen (diff)
0.09
0.00
0.49
0.58
% Weight
As Received Dry
0.09
0.00
0.51
0.60
5.18
72.26
5.17
0.95
0.03
0.58
5.29
10.54
100.00
76.21
5.45
1.00
0.03
0.61
5.58
11.12
100.00
MINERAL ANALYSIS
Phos.pentoxid
Silica, SiO2
Ferric oxide, Fe2O3
Alumina, A12O3
Titania, TiO2
Lime, CaO
Magnesia, MgO
Sulfur trioxide, SO-j
Potassium oxide, K2O
Sodium oxide, Na2O
Undetermined
Silica Value = 79.21
T250 = 1772°K (2730°F)
FUSION TEMPERATURE OF ASH
Initial Deformation
Softening (H=W)
Softening (H=1/2W)
Fluid
(H •= cone height;
W - cone width)
% Weight
Ignited Basis
0.43
50.23
8.11
28.60
2.03
3.60
1.47
4.18
1.13
0.71
0.49
100.00
1533°K(2300°F)
1592°K(2405°F)
1656°K(2520°F)
1719°K(2635°F)
292
-------
5.9.2 Boiler Description
The boiler tested was Unit #2 at St. John's Abbey, Collegeville,
Minnesota. It is a Keeler C.P. water-walled steam generating unit of the
forced draft type with a motor-driven forced draft fan and a draft naturally
induced by the stack. The unit was installed in 1945 with a Detroit single
retort underfeed stoker. This stoker was replaced in 1958 with a Riley spreader
stoker having two Model "B" feeders and a steam operated split dumping grate.
The dumping cycle is discussed in more detail in Section 5.9.6.
The unit does not have a mechanical dust collector. Cinders settl-
ing in the back pass are picked up by an aspirator and reinjected into the
furnace through four cinder return tubes located 38.1 cm (15") above the
grate along the back furnace wall. Overfire air is injected through fire
tubes along the back wall 45.7 cm (18") above the grate. Forced air from
the same fan which supplies the overfire air and cinder return is used to
cool the "air swept cut-off plate" on each of the feeders.
Coal is manually weighed and dumped into the feeder hopper with an
overhead coal scale having a 454 Kg (1000 Ib) capacity. This scale travels
on overhead rails to feed all three of the small boilers.
The following design specifications apply to Unit #2:
Max. Continuous Load 1.7 kg/s (13,500 Ib/hr steam)
Peak Load 1.9 kg/s (15,000 Ib/hr steam)
Feed Water Temperature 373 °K (212°F)
Operating Pressure 1.48 MPa (200 psi)
Heating Surface 209 m2 (2,250 sq.ft)
Grate Area 4.27 m2 (45 sq.ft)
Furnace Volume 13.88 m3 (490 cu.ft)
Stack Height 33 m (174.5 ft)
Stack Inside Diameter at Top 152 cm (60 in.)
The following approximate analyses were specified for this boiler
by the E&A contractor when the spreader stoker was installed:
293
-------
Moisture Content 5%
Volatile Matter 38.7%
Fixed Carbon 49.8%
Ash 6.5%
High Heating Value, as fired 30.2 MJ/kg (13,000 Btu/lb)
Ash Fusion Temperature 1478°K (2,200°F)
Sizing 3.2 cm x 0 cm to 1.27 cm x 0 cm
(1-1/4" x 0" to 1/2" x 0") with
less than 40% passing through
0.635 cm (1/4") round mesh screen
5.9.3 Sample Location
St. John's Unit #2 is one of three identical boilers connected to
the smoke stack by a common breeching. A fourth boiler of identical
construction but of three times the capacity is connected to the
stack by a separate duct. A schematic of the three small boilers
and the flue gas duct system is shown in Figure 5.9-1.
Because the unit had no mechanical dust collector, only one particu-
late sample location was necessary. The physical layout of the duct system
restricted that sample location to the one shown in Figure 5.9-1. Most of the
gaseous samples were taken from this location although late in the series,
two gaseous probes were inserted into the back of the boiler just before the
breeching to check the left to right fuel air balance of the stoker.
The sample area selected was not ideal for particulate sampling. Due
to its proximity to a 90° bend in the flue gas stream it contained turbulence
and negative velocity regions. A traverse of the area with a pitot tube
gave the profile shown in Figure 5.9-2. Particulates were only sampled in the
positive velocity regions. Gaseous probes were centered in each of the upper
four ports. The bottom port was unusable because -the bottom of the breaching
was filled with flyash.
Because of the turbulence, the magnitude of the particulate numbers
could suffer some accuracy. However, they should accurately portray
the effects of load, excess O2 and fuel properties on particulate emissions
from this unit.
294
-------
Fly Ash Collected
on Bottom of Breaching
Particulate and
Gaseous Sample Ports
o
o
o
Unit 1
Shut Down
Unit 2
Test Boiler
Unit 3
Shut Down
Stack
Figure 5.9-1. Schematic of boilers and flue gas duct system, St. John's
Unit 2.
-------
1.08m (42-3/4")
Particulate Sample Points
/V^,
+ + 4- +
+ 20cm
(0.08")
) to
(0 in.) H00
Pitot Tube Readings
Scale 1 cm = 10 cm (1" = 10")
Effective Area = 1.76 m2 (18.93 ft )
Figure 5.9-2. Sample area geometry, St. John's Abbey Unit 2.
296
20.5 cm
(80-3/4")
-------
5.9.4 Control Room Observations
During each test, complete records were kept of boiler temperatures
and pressures, stoker and boiler controls, coal, feedwater and steam flow
rates, etc. Additionally, notes were kept on flame observations and general
operating problems. In comparing the two fuels, the following differences
were observed:
Last-pass temperature, or temperature of the flue gas exiting the
boiler, averaged 602°K (623°F) for the eastern coal burning compared to
579°K (573°F) for the western coal burning. This 28°K (50°F) difference
represents a significant heat loss for the eastern coal. Temperatures at
the particulate sampling point in the breeching were 507°K (452°F) versus
696°K (425°F) respectively for eastern versus western coal firing; less
difference, but still in the same direction.
When ashes from western coal fires are dumped and coal feed is restored
to the bare grate, air must be added immediately to initiate burning. When
eastern coal is burned, air is not added until the fire has started and is
well under way, otherwise it will blow out the fire.
The eastern coal flame appeared more orange and luminous than the
western coal flame.
Clinker formation on the grate was not a problem with either coal
as long as adequate grate air was supplied. However, low excess air tests
revealed that the western coal forms clinkers more readily than the eastern
coal. This observation is supported by the western coal's lower ash fusion
temperature as indicated in Table 5.9-1.
St. John's Unit #2 operating personnel disliked this particular
eastern coal because it was dry and dusty. They ordinarily prefer eastern
coals to western coals because of the reduced fuel handling involved in
firing higher heating value coals.
297
-------
This boiler is not load-limited when firing western coal according
to the chief engineer. However, the western coal seems to react slower to
load demand changes.
Both coals can be burned in this boiler without problems. In fact,
neither boiler nor stoker controls changed noticeably from one coal to the
next. Smoke was not a problem.
During test number 18, an eastern coal test, the effect of overfire
air (OFA) on gaseous emissions was investigated. Varying overfire air
between its maximum and minimum settings was found to have no observable
effect on either smoke or carbon monoxide at medium loads. However,
raising overfire air increased nitric oxide emissions by 14 ppm or 4.6%.
A similar experiment during western coal test number 9 showed no effect on
smoke, carbon monoxide or hydrocarbons. Again, nitric oxide emissions
increased by about 10 ppm. A particulate test at maximum OFA (test #9)
could not be directly compared with one at minimum OFA (test #2)
because of the inability to duplicate load and excess O2 conditions.
However, no significant change is apparent from the data.
5.9.5 Gaseous Emissions
A. Discussion of Gaseous Testing—
Compared to the baseline eastern coal, the western coal showed
lower particulates by a factor of 0.5, increased sulfur dioxide emissions
by a factor of 1.3, much higher sulfur trioxide emissions by a factor of
6.9, reduced nitric oxide emissions by a factor of 0.7, nearly equivalent
carbon monoxide emissions, and increased hydrocarbon emissions by a factor
of 1.5. Each of these emissions is discussed in more detail in'the follow-
ing subsections. The gaseous data is summarized in Table 5.9-2.
Unit #2 was the only boiler operating at St. John's during the
summer, and the facility has no tie-in with outside power sources. For
these reasons, test loads were restricted to internal demand. A six point
test matrix was selected consisting of normal, high, and low excess O tests
298
-------
TABLE 5.9-2. GASEOUS EMISSION SUMMARY, ST. JOHN'S UNIT 2
Test
No.
1
2
3
4
5
6
7
8
9
WG
10
11
12
13
14
15
16
17
IB
AVG
Load
kq/s (I03lb/hr)
1.1 (B.82)
1.1 (8.48)
0.7 (5.60)
0.7 (5.85)
0.7 (5.72)
0.7 (5.86)
1.1 (8.69)
1.1 (8.75)
1.2 (9.16)
0.9 (7.44)
11 / Q AA \
.4 \y. o4 )
1.1 (8.57)
0.8 (6.08)
0.7 (5.90)
0.7 (5.87)
1.1 (8.36)
1.0 (7.98)
0.9 (7.12)
1.0 (7.75)
0.9 (7.47)
°2
»
13.96
13.75
16.33
16.48
15.16
17.00
15.21
13.36
13.50
14.97
1 ^ *)")
1 J . **
14.20
15.48
16.30
15.48
15.58
13.40
14.60
14.34
14.73
co2
%
5.93
5.57
3.98
3.65
4.89
3.51
5.45
6.53
6.35
5.10
6Jf\
. A\J
5.72
4.20
3. 75
4.55
5.08
6.10
5.50
4.68
5.12
o2+co2
%
19.89
19.32
20.31
20.13
20.05
20.51
20.66
19.91
19.85
20.07
1 Q T)
i.y . f £
19.92
19.68
20.05
20.03
20.66
19.50
20.10
19.02
19.85
CO
ppm »t
3%02
48
50
961
1032
95
1645
543
80
78
504
41
4i.
157
778
1446
418
490
116
170
226
427
HC
ppn at
3%0?
36
—
348
277
377
233
125
132
218
__
54
367
143
93
71
—
130
143
Hitrit
ppm at
»0,
238
226
216
232
199
244
261
250
245
237
__
357
—
305
413
264
325
344
335
• Oxide (1
Ib/MBtu
0.208
0.197
0.188
0.202
0.174
0.213
0.245
0.218
0.214
0.207
...
0.307
0.262
0.355
0.227
0.280
0.296
0.288
JO)
ng/J
89
85
81
87
75
94
105
94
92
89
__
132
—
113
153
98
120
127
124
ppn at
3* 02
489/20
635/52
614/45
759/44
636/55
600/39
592/26
618/40
464/19
448/3
388/1
523/14
471/8
375/0
445/6
SVS03
Ib/MBtu
0.911/
0.037
1.183/
0.097
1.143/
0.084
1.414/
0.082
1.184/
0.102
1.117/
0.073
1.103/
0.048
1.1S1/
0.075
0.852/
0.017
0.823/
0.006
0.713/
0.002
0.961/
0.026
0.865/
0.015
0.689/
0.000
0.817/
0.011
392/
16
508/
42
492/
36
608/
35
S09/
44
480/
31
474/
21
--
495/
32
366/
7
354/
2
306/
1
413/
11
372/
6
296/
0
—
—
351/
5
Partica
1 h/nre
0.446
0.846
1.114
0.225
1.887
0.8SB
0.817
0.557
O.B44
1.435
2.407
3.395
1.075
1.827
0.530
2.710
1.287
1.833
ates
192
364
479
97
811
369
351
240
363
617
1035
1460
462
785
226
1165
553
788
299
-------
at both a low and a medium load. The low load tests were run at night
between the hours of 11:30 pm and 4:30 am. During this period the load
remained relatively stable at about 0.7 kg/s (5.8x10 Ib/hr) steam, or 43%
of maximum continuous load. Medium load tests were conducted during the
day and averaged about 1.1 kg/s (8.5xl03 Ib/hr) steam, or 63% of maximum
continuous load. During the day tests, the load varied, between about
0.9 kg/s and 1.3 kg/s (7xl03 Ib/hr and lOxlO3 Ib/hr) steam which contributed
to scatter in the data. Peak load tests could not be obtained during the
summer.
Non-steady boiler loads were not the only difficulty at this test
site. Small units seldom have the excess O monitors or sophisticated
control equipment to maintain excess O at a given level. Instead, much
depends on operator judgment by visual reference to the fire. Thus, test
conditions (excess O and boiler load) were subject to variation.
Figures 5.9-3 and 5.9-4 show the excess O and boiler load con-
ditions under which the various tests were conducted. The numbers on these
and all following graphs refer to test numbers and can be used for cross
reference.
1. Particulate Emissions—Particulate emissions from the western
coal firing were less than half those of the eastern coal firing under
the same conditions. These emissions showed a strong dependence on excess
air. To illustrate, the particulate emissions are plotted against boiler
load in Figure 5.9-5 and against excess O in Figure 5.9-6. Some care
must be taken in interpreting the data of Figure 5.9-6 due to the fact
that the nominal low, normal, and high O levels change as the load changes
so the curves do not show decreasing particulates at constant O for load
"—"—"— £.
increases.
Of special significance are the shapes of the curves in Figure
5.9-6. The western coal behaved as might be expected, increasing at an
accelerating rate as the excess CL increased, and increasing with load at
constant excess O . The eastern coal, on the other hand, increased at a
£•
decelerating rate as the excess Q^ increased and the particulate emissions
were greater at lower load.
300
-------
18
17
4J
§ 16
u
n
-------
18
17
4J 16
c
0)
o
s-i
3
w
X
o
U)
§ 14
X!
W
13
15
Rated Load =1.7 kg/s (13,500 Ib/hr) steam
I
I
10
45 52 59 66
PERCENT OF RATED LOAD
73
80
Figure 5.9-4. Eastern coal test conditions, St. John's Unit 2.
302
-------
2000
Rated Load = 1.7 kg/s
(13,000 Ib/hr)
steam
52
59 66 4S '52 59
PERCENT OF RATED LOAD
.6cT
Figure 5.9-5. Particulates vs. load, St. John's Unit 2.
303
-------
2000
1600 —
CO
§
H
CO
CO
O
H
1200
80C —
I T
O Western coal
£ Eastern coal
400- 8
High _-SV
r i
0 13 14 15 16 17
EXCESS OXYGEN, percent
18
19
Figure 5.9-6.
Particulate emissions vs. excess 0 , St.
John's Unit 2.
304
-------
B.
Sulfur Oxides Emissions—
Total oxides of sulfur emissions were lower with eastern coal
firing by an average of 40%. This unusual occurrence is a direct result
of the low fuel sulfur in this eastern coal, as a comparison of tests 8
(western coal) and 11 (eastern coal) demonstrates. These data are given
in Table 5.9-3.
TABLE 5.9-3. SULFUR BALANCE COMPARISON FOR TWO FUELS,
ST. JOHN'S UNIT 2
Sulfur in Fuel
HHV of Fuel
Test No. MJ/kg
8 (western)
11 (eastern)
16 (eastern)
24.
31.
30.
4
7
5
Ib/MBtu
10515
13640
13123
s
0.
0.
0.
Ib/MBtu
fc as S02 '
61 1.160
58 0.884
58 0.884
SO Emissions .
2 % Emission
ng/J Ib/MBtu of Fuel S
474 1.103 95%
366 0.852 96%
296 0.689 78% (clinker
formation)
It is evident that the emissions are directly related to the sulfur
input, and that sulfur retention in the ash is low. In the case of test
number 16, the computed sulfur retention was 22%. This high sulfur reten-
tion could be related to the heavy clinker formation during this test.
These are the only three tests for which sulfur analyses were made.
Total oxides of sulfur are plotted against boiler load in Figure
5.9-7. The apparent drop in sulfur emissions at medium load for the
western coal may be related to variations in fuel sulfur or just scatter
in the data. No variation with excess O2 was observed. Average SOx emis-
sions were 495 ng/J (1.15 Ib/MBtu) for the western coal and 351 ng/J (0.82
Ib/MBtu) for the eastern coal.
Sulfur trioxide emissions are plotted against boiler load in Figure
5.9-8. For the eastern coal firing, average S03 emissions were 4.6 ng/J
(0.011 Ib/MBtu). This is 1.3% of the total oxides of sulfur. For the
western coal firing, the SO3 emissions were 32.1 ng/J (0.075 Ib/MBtu).
This represents a factor of 6.8 in SO3 emissions over the eastern coal and
accounts for 6.5% of the total western coal oxides of sulfur emission.
305
-------
700
600
50°
400
H
O 300
200
14
13
Rated Load = 1.7 kg/s
(13,000 Ib/hr)
steam
I I
O Western coal
A Eastern coal
1
45
52 59
PERCENT OF RATED LOAD
66
Figure 5.9-7. Total oxides of sulfur vs. boiler load, St. John's
Unit 2.
306
-------
50
40
Cn
G
g 30
H
X
o
H
g
a
D
OT
20
10
Rated Load =1.7 kg/s (13,500 Ib/hr) steam
O Western coal
£ Eastern coal
O'
151
12
45
52 59
PERCENT OF RATED LOAD
66
Figure 5.9-8.
Sulfur trioxide vs. boiler load, St. John's
Unit 2.
307
-------
1. Nitric Oxide Emissions — Compared to the eastern coal, western
coal firing produced an average 28% lower nitric oxide emissions. This
reduction is probably the result of the higher moisture content of the west-
ern coal. Based on the fuel analysis, Table 5.9-1, the western coal had
15.77% moisture compared to 5.18% for the eastern coal. The moisture in
the fuel absorbs heat equal to its heat of vaporization. This reduces
flame temperature which in turn reduces thermal nitric oxide formation.
Figure 5.9-9 shows nitric oxide emissions as a function of excess
O . The effect of load (furnace temperature) is apparent in the separation
of the two western coal plots. Also, the eastern coal emissions are seen to
have a greater dependence on excess O than the western coal emissions. The
western coal's reduced dependence on excess O is probably also a result of
the fuel moisture wherein lower flame temperatures result in reduced rates
of reaction for nitric oxide formation and thus less sensitivity to excess
Fuel bound nitrogen does not appear to have been a factor in the
differences in nitric oxide emissions between the two fuels since the western
coal contains slightly more fuel nitrogen than the eastern coal on a ng/J
basis.
2. Carbon Monoxide and Hydrocarbon Emissions — Compared with the base-
line coal, the western coal's carbon monoxide (CO) emissions were slightly
reduced under most test conditions while the hydrocarbon (HC) emissions
were 52% greater on the average. Both of these emission rates are closely
related indicators of combustion efficiency.
The CO and HC data are plotted against excess 0 in Figures 5.9-10,
5.9-11, 5.9-12, and 5.9-13. As with particulates, the western coal data
behaved well while the eastern coal behaved in an unorthodox manner. Both
emissions increase with excess O at constant load and this can be explained
as a cooling or quenching of the flame by the excess air before combustion
is complete.
308
-------
150
H
W
W
100
8
H
5
50
18
16
/O
15.
NOTE: Test #9 at maximum
overfire air
0 L—^-
1
1
Western coal
Eastern coal
13
14 15 16 17
EXCESS OXYGEN, percent
18
Figure 5.9-9. Nitric oxide vs. excess O2, St. John's Unit 2,
19
309
-------
2500
CN
O
*
T3
1500
§
H
X
§ 1000
i
500
KA
radon1— —
Medium Load
Low Load
13
14 15 16 17
EXCESS OXYGEN, percent
18
19
Figure 5.9-10. Carbon monoxide vs. excess O , St. John's Unit 2,
western coal.
310
-------
2500
(N
2000
CO
1500
Q 1000
H
I
500
Medium Load
13
I
Low Load
13
14 15 16
EXCESS OXYGEN, percent
17
18
19
Figure 5.9-11. Carbon monoxide vs. excess 0 , St. John's Unit 2,
eastern coal.
311
-------
500
,-. 400
(N
o
300
•a
.. 200
in
§
100
1
Low Load
I
I
1
13 14 15 16 17
EXCESS OXYGEN, percent
18
19
Figure 5.9-12. Hydrocarbons vs. excess O_, St. John's Unit 2,
western coal.
312
-------
500
CN
o
400
>H
S4
•O
300
I
a
200
s
o
Q
>H
33
100
13
13
12
I
Low Load
14 15 16 17
EXCESS OXYGEN, percent
18
Figure 5.9-13. Hydrocarbons vs. excess O , St. John's Unit 2,
eastern coal.
313
-------
The CO and HC emissions generally increase with load in the region
of the boiler's load range tested. However, excess O requirements decrease
as load increases. The net result is a slight decrease in these emissions
as load increases under actual firing conditions. Based on previous test
experience, these emissions would be expected to increase again as the
maximum boiler capacity is approached.
5.9.6 Ash Balance Measurements
St. John's Unit #2 was the only boiler in this test series where
accurate ash balance measurement could be made. We felt that such measure-
ments would be informative and so they were included in the test plan.
The system worked as follows. The left and right sides of the boiler
had separate dumping grates, spreader stokers, and air plenum chambers. At
the end of each operator's shift when a considerable amount of ash had built
up on the grates, the operator would shut off the coal feeder to one side of
the boiler. After 5 to 10 minutes without coal, that side would burn out
leaving only smoldering ashes. At this point the air would be shut off and
the ashes dumped into the bottom of the plenum chamber under the grate.
Coal feed would be resumed immediately- The coal feeder would throw coal
onto the bare grate and ignition would start at the hot sides and work its
way toward the center of the grate. Coal feed to the opposite side of the
boiler would be simultaneously increased to handle the entire load demand
until the fire on the freshly dumped side had built up sufficiently. About
15 to 20 minutes after the first side had been dumped, the fire would be
built up sufficiently to repeat the process on the second side.
Normally, a sprinkler system in the plenum chamber would be used
to cool the ashes and keep the dust down before removal. For the purposes
of these test measurements, however, they were left dry.
The ashes were shoveled into a wheelbarrow from a door in the air
plenum chamber while the air was still shut off. The wheelbarrow was weighed,
tare weighed, and the net ash weight recorded. One heaping wheelbarrow full
from each side was all that was required. Ash formation rates were thus
determined on a mass per unit time basis.
314
-------
Fuel feed rates were simultaneously determined on a Kg/hr and
Ib/hr basis. The feeder hopper was topped off at the start and finish of
each test and the times recorded. The coal added to the hopper during
the test was weighed to the nearest ten pounds.
Finally, particulate emissions were computed on a Kg/hr and Ib/hr
basis. This data is tabulated in Table 5.9-4 and graphically illustrated
in Figures 5.9-14 and 5.9-15. A discussion of the results follows.
The western coal's ash balance was very good. During test number
7 the fuel flow rate was apparently erroneously measured since it is unu-
sually high for the boiler load. This would account for the high "ash in
fuel" flow rate.
For a given load, the fly ash fraction of the total ash increases
sharply with excess air. The only deviation from this trend is test number
8 where clinker formation may have resulted in higher local air flows through
portions of the grate, thus increasing ash carry over.
The "ash in fuel" flow rate for all the western coal measurements
is based on a coal analysis from test number 8. Thus, test number 8 should
be the most accurate ash balance test. An analysis of the bottom ash for
test number 8 shows 11.29% combustibles and ignition of fly ash samples for
test numbers 2 through 9 gave an average weight loss of 8%. Therefore,
about 90% of the carbon containing ash was accounted for.
"Ash in fuel" calculations for the eastern coal were made from a
coal analysis of the fuel used in test number 16. The dry combustibles in
the grate ash from test number 16 were found to be 20.72%. An average of
eight fly ash samples showed a loss on ignition of 39.4%. Very close to a
100% ash balance for the seven tests was obtained.
315
-------
TABLE 5.9-4. ASH BALANCE DATA, ST. JOHN'S UNIT 2
i-H
0
o
Western
LO
H
-------
15
j-i 10
Cn
8
W
EH
S
1
fa 5
w:
0
—
—
?
fj
y
/.
y
^
/.
/
N«.
u
T
/.
/.
/
/
y
y
'y
J
y
\
^
Mi
2
y
^
y
y
/
y
/
^
f
*/
E3 Fly ash _
Q Grate ash
Q Ash in fuel _
u
7
PI
/
Ub
1
/
u
PV
r
^
X
y
/
y
^
f
T?
uH
J
I
/
^ccs^c^^^c^^^^xs^^^^^NS^
:
!•«•
8975346
__
70
60
50 M
^
1-1
40 ,
ta
t"j
" 1
20 |
10
n
V*
LEAST EXCESS OXYGEN MOST EXCESS OXYGEN
Figure 5.9-14. Western coal ash balance (disregarding carbon analyses),
test numbers arranged in order of excess 02,
Unit 2.
St. John's
317
-------
15
$
v 10
W
1
ASH FORMATION
O Ul
—
—
r;
V\\\\\\\\\\\\\\\\\\\\X\N
^
r
KXX\\XXVv\X\\\\\\\\\\\N
•M
7
lx\xx^^c^c^^oc^^c^^cV>
!;!;
^
^••M
—
70
60
50 ^
K
w
40 g
M 10 CO
o o o o
ASH FORMATION
16
11
LEAST EXCESS OXYGEN
18 15 14 12 13
MOST EXCESS OXYGEN
Figure 5.9-15, Eastern c.oal ash balance (disregarding carbon analyses) ,
test numbers arranged in order of excess O , St. John's
Unit 2.
2'
318
-------
5.9.7 Concluding Remarks
1. A western coal can be burned in small dumping grate spreader stokers
of this type without operating problems. No boiler modifications
are required.
2. Particulate and nitric oxide emissions were significantly reduced
by burning the western coal, while carbon monoxide emissions were
unaffected.
3. Total oxide of sulfur emissions were in direct proportion to the
sulfur content of the fuel based on a higher heating value.
Sulfur retention in the boiler was not a significant factor.
4. Units of this type would benefit from the installation of continuous
excess O monitors because al]
highly sensitive to excess CL.
excess O monitors because all emissions and clinker formations are
319
-------
5.10 FREMONT DEPARTMENT OF UTILITIES, FREMONT, NEBRASKA
Lon D. Wright Memorial Power Plant in Fremont, Nebraska, was the last
site in our test series. The unit tested was a small 20.2 kg/s (160,000
Ib/hr) steam face-fired pulverized coal burning unit with a dry bottom, and
a mechanical dust collector.
The unit was originally designed for a subbituminous Kansas coal. At
the time our testing started, the unit was burning Hanna Wyoming coal as its
primary fuel and was considering a switch to one of several Colorado coals for
reasons of emissions and economics. At the completion of our test program
the facility continued to burn the Colorado coal we had tested. This allowed
us to assess the long term operational problems of both coals.
Proximate and ultimate analysis of the two fuels is given in Table
5.10-1.
5.10.1 Boiler Description
The boiler tested was Unit 6 at the Lon D. Wright Memorial Power Plant
in Fremont, Nebraska. It is a 20.2 kg/s (160,000 Ib/hr) steam flow, pulverized
coal burning unit of the Stirling type built by Babcock and Wilcox Company
(B&W) in 1956. The unit is face-fired with four B&W burners arranged in two
rows of two. Pulverized coal is supplied to the burners by two B&W ball and
race type pulverizers.
Incoming combustion air is preheated by a tubular type air heater to
about 589 °K (600 °F). The flue gases pass through a pendant type super-
heater before beginning the final boiler pass. Superheated steam tempera-
ture is controlled at 744 °K (880 °F) by a coil type attemperator. Fly
ash is removed by a mechanical dust collector. Ash from the dust collector
and from the bottom of the smoke stack is pneumatically conveyed under vacuum
to a point where it is mixed with the ash slurry from the bottom ash hopper.
The ash slurry is piped to a settling pond and eventually used for land
fill. The unit is of the balanced draft type with both induced draft (ID)
and forced draft (FD) fans. Furnace draft is maintained at about negative
0.64-0.76 cm (0.25-0.30 inches) of water.
320
-------
TABLE 5.10-1. COMPARISON OF TEST COALS
FROM TEST #16
Walden Colorado Coal
P ROXIMAgE ANALYSIS
% Ash
% Volatile
% Fixed Carbon
MJAg
Btu/lb
% Sulfur
As Rec'd
12.85
6.89
35.24
__45. 02
100.00
24.9
10741
0.32
ULTIMATE ANALYSIS
As P.jec'_d_
Moisture 12.85
Carbon 61.59
Hydrogen 4.31
Nitrogen 0.93
Chlorine 0.03
Sulfur 0.32
Ash 6.89
Oxygen (dif) 13.08_
100.00
Dry
xxxxx
7.91
40.43
51.66
100.00
28.6
12324
0.37
FROM TEST #4
Hanna Wyoming Coal
PROXIMATE AKALYSIS
As Rec'd
% Moisture 11.97
% Ash 9.19
% Volatile 33.46
% Fixed Carbon 45.38
100.00
MJ/kg 25.3
Btu/lb 10889
% Sulfur 1.48
ULTIMATE A NA LYSIS
As Rec'd
Moisture 11.97
Carbon 61.63
Hydrogen 4.38
Nitrogen 1.25
Chlorine 0.03
Sulfur 1.48
Ash 9.19
Oxygen (dif) 10.07
100.00
MINERAL ANALYSIS
Phos. pentoxide, P7°5
Silica, SiO2
Ferric oxide, Fe2C>3
Alumina, A1203
Titania, TiO2
Lime, CaO
Magnesia, MgO
Sulfur trioxide, SO3
Potassium oxide, K O
Sodium oxide, Na^O
Undetermined
xxxxx
10.44
38.01
51.55
100.00
28.7
12370
1.68
Dry,
xxxxx
70.01
4.98
1.42
0.03
1.68
10.44
11.44
100.00
lonited
0.11
50.08
13.74
19.24
0.80
7.50
1.92
4.15
1.61
0.48
0.37
T250 Poises = 2460 °F
Silica Value = 68.38
. as Na2O, DCS* = 0.16
321
-------
The following design data applies to Unit #6:
. Boiler rating - 20.2 kg/s (160,000 Ib/hr) steam flow
Design pressure - 7-0 MPa (1000 psig)
Design temperature - 761 °K (910 °F) (Superheated)
. Year built - 1956
Boiler heating surface - 841 m (9,050 sq. ft.)
Total waterwall heating surface - 333 m (3,584 sq. ft.)
2
Superheater heating surface - 441 m (4,748 sq. ft.)
2
Air heater heating surface - 3,958 m (42,600 sq. ft.)
Total furnace volume - 323 m (11,400 cu. ft.)
Western precipitator multiclone dust collector - 138-8
Predicted Multiclone Efficiency
Particle Size Expected Efficiency
5-10 microns 53.8%
10-20 microns 96.5%
30-43 microns 98.6%
> 43 microns 99.0%
Overall Average 80.0%
. Stack height - 43.9 m (144 feet)
B&W ball and race pulverizers - Type E, Size EL-35
Day-to-day operating conditions:
Superheat steam temperature - 744 °K (880 °F)
Superheat steam pressure - 6.1 MPa (875 psig)
5.10.2 Sample Locations
Sample ports were available at three different locations along the
duct system of the boiler. At each location, the duct was about 4.66 m
(15'3") wide and required ports on both sides to provide access to its entire
area. The locations of these sample areas and their geometry is shown in
Figure 5.10-1.
322
-------
UNCONTROLLED PARTICULATE SAMPLE AREA
(Immediately before dust collector)
J
: +
:
*
i
_j
r'
+ + + + f + +(5'
* + + t + * +
f~
66 m
6")
f
GASEOUS AND SOx SAMPLE AREA
(Immediately after dust collector)
L >
— ' 1— 1 84 m
. ' ' ' ' (6'1-J
••.. 1 ' —
~i r
4.66 m ^
_J
+•
D
J
H
— 1
(15 '3")
CONTROLLED PARTICULATE SAMPLE AREA
(After dust collector and air heater)
L. i
•f +• +• + +
c
1 — (5''
c
+• + + + +
5")
(
4.44 m x_
Figure 5.10-1. Sample area geometry, Fremont Department of Utilities Unit 6.
323
-------
The sample area at the immediate inlet to the dust collector was used
for particulates. Because of obstructions in the working area, two particulate
probes were required, a twelve foot (3.7 m) probe for sampling from the west
side and a two foot (0.5 m) probe for sampling from the east side. Combined,
the two probes could reach 23 of the 24 sample points in this sample area. The
one which could not be reached was in an area where velocities were normally
either zero or negative and thus would not normally be sampled anyway. Turbu-
lence in this sample area was a problem and contributed to the scatter in the
dust collector inlet particulate data. Gaseous probes were inserted one quar-
ter of the way into the duct from each side and were used for obtaining excess
0 data during the particulate sampling.
The sample area at the immediate outlet of the dust collector could
not be used for particulate sampling because of severe turbulence. This turbu-
lence was due to a 90 degree bend in the flue gas stream as it exited the multi-
clone. Instead, six gaseous probes with sintered stainless steel filters were
inserted in the staggered manner shown in Figure 5.10-1. The O , CO , CO, NO,
£ £
and HC data were obtained individually from each of the six probes and the
average concentration of each was determined. These averaged readings are the
ones used throughout this report. The SO? and SO concentrations were obtained
from this area by the Shell-Emeryville method.
The sample area after the dust collector and immediately before the
induced draft fan was used for obtaining the outlet particulate samples. Again,
as at the dust collector inlet, a twenty-four point sample matrix was used.
Two probes, one six foot (1.8 m) and one twelve foot (3.7 m) effective lengths,
were required. In this way, all twenty-four sample points could be reached.
Turbulence was not a major problem here and the data was very consistent. As
at the dust collector inlet, two gaseous probes were inserted for the purpose
of obtaining excess O values for correcting the particulate data.
324
-------
5.10.3 Gaseous Data
A. Discussion of Testing—
Some test difficulties did exist at this site. The scheduled start-
up of a new unit placed time restrictions on our testing because it would
require bringing Unit #6 down. Delays in the shipment of the Walden Colorado
test coal and the small size of that shipment placed further time constraints
on our test program. Finally, contractual obligations of the plant to a
regional electrical power inter-tie made availability of specific unit loads
difficult.
To overcome these difficulties and still adequately characterize the
boiler emissions as a function of boiler load and excess 0 , a modified test
plan was adopted. First, a five point test matrix was selected including low,
medium and high load tests followed by one test at higher than normal air and
one test at lower than normal air both at the medium load. During each of
these tests, the time-consuming inlet and outlet particulates and sulfur
oxides tests were run in addition to recording the emissions of O , CO , CO,
NO, and HC monitored in the KVB mobile laboratory.
To more accurately characterize the monitored emissions against excess
0 , a special series of tests were run. In this series, the fuel/air ratio was
changed in increments both above and below the normal excess O2 level. The
changes were made at 15 minute intervals. These tests proved to be very
beneficial. Boiler loads along with other operating parameters were held
constant eliminating the usual probelm of duplicating combustion conditions
when these conditions are changed one day at a time. As an added benefit,
this approach allowed more accurate determination of the carbon monoxide limit
under low excess air conditions.
Figure 5.10-2 shows the conditions under which the various tests were
conducted. The numbers on these and all following graphs refer to test numbers
and can be used for cross reference.
325
-------
0) 5
U s
M
0)
A
CO
en
PL)
Rated Load =20.2 kg/s (160,000 Ib/hr) steam
HANNA WYOMING COAL
WALDEN COLORADO COAL
14
O
o
13
11
16
5 9
• o
High Air
6 ^\ Normal Air
Air
40
50 60 70 80
PERCENT OF BOILER DESIGN CAPACITY
90
Figure 5.10-2. Excess O2 vs. boiler load, test parameters, Fremont Department
of Utilities Unit 6.
326
-------
Based on the control room monitor, the normal 0? for the boiler is
3.8% at all loads. During the Hanna Wyoming coal tests, recalibration of the
control room monitor after test number 5 showed that all three baseline tests
had been at higher than normal air. Thus, test 6 represents a normal 02 and
test 7 represents a low 0 . The Walden Colorado coal tests followed the
desired test matrix more closely, although test 9 was at a higher than normal
excess O value. The excess 0 numbers used in this report were from samples
taken after the second stage air heater and the dust collector. Therefore,
there was some dilution of the flue gas due to leakage resulting in higher 02
values than actually existed in the furnace.
Table 5.10-2 presents an emissions data summary for the five compre-
hensive tests on each fuel. Table 5.10-3 presents the data for those tests in the
which fuel/air ratio was varied in increments. The following subsections will
address each of the emissions separately and make a direct comparison between
the two coals.
B. Particulate Emissions—
The data shows the Walden Colorado coal's particulate emissions were
an average 36% less than the Hanna Wyoming coal's emissions as measured at the
dust collector outlet. The reason for this reduction appears to be primarily
improved collector efficiency in removing the Walden ash, and not the lower
ash content of the same fuel. The data is presented in Table 5.10-2 and on
Figures 5.10-3, 5.10-4, and 5.10-5 respectively which show particulate emis-
sions before and after the dust collector and collector efficiency as a
function of boiler load.
In Figure 5.10-3, inlet particulate loadings for both coals are
plotted against boiler load. The difference in ash contents of the two coals,
24% on a HHV basis, is not seen here. Instead, the uncontrolled particulate
emissions from both fuels are statistically the same.
Excess air is a factor before the dust collector. Comparing high air
tests 3 and 13 against low air tests 7 and 16 shows that a 1% decrease in
excess 0 can decrease emissions by 15% or more. However, this improvement is
reduced to around 5% by the normalizing effect of the cyclones as will be
discussed in a later paragraph.
327
-------
TABLE 5.10-2. EMISSION DATA SUMMARY, FREMONT DEPARTMENT OF UTILITIES, UNIT 6
Test
No.
Date
Load
Kg/s
(103lb/hr)
02
aercent
C02
percent
CO
(dry)
ppm
HC
(wet)
ppm
NO
(dry)
ppm
ng/J
(lb/106BTU)
SO
X
(dry)
ppm
ng/J
(lb/106BTU)
S03
(dry)
ppm
ng/J
(lb/106BTU)
Fuel
Sulfur
Emitted
percent
Unc.
Part
ng/J
( Ib/lO^TU)
Con.
Part
ng/J
(lb/106BTU)
Dust
Coll
Eff.
percent
Comb.
in
Flyash
oercent
HANNA WYOMTNG COAL
3
4
5
6
7
7/23/76
7/24/76
7/25/76
7/27/76
7/28/76
Average
13.6
(108.4)
8.3
(66.0)
17.0
(133.5)
14.7
(116.8)
13.6
(108.2)
13.3
(106.6)
5.39
5.28
5.43
4.14
3.61
4.77
13.51
13.45
13.31
14.88
15.01
14.03
11
17
20
18
17
17
90
110
74
62
84
591
460
659
—
—
570
225
(0.523)
175
(0.407)
251
(0.583)
—
—
217
(0.504)
1215
1249
1417
951
849
1136
987
(2.295)
1014
(2.359)
1151
(2.677)
772
(1.796)
689
(1.604)
923
(2.146)
5
5
5
4
3
4
4.1
(0.009) '
4.1
(0.009)
4.1
(0.009)
3.2
(0.008)
2.4
(0.006)
3.6
(0.008)
92.8
86.9
107.3
95.1
86.8
93.8
1133
(2.636)
1141
(2.654)
1508
(3.507)
—
911
(2.119)
1173
(2.729)
437
(1.017)
621
(1.445)
413
(0.961)
425
(0.988)
431
(1.003)
465
(1.083)
61.4
45.6
72.6
—
52.7
58.1
1.1
1.3
0.5
0.7
0.7
0.86
U)
NJ
00
WALDEN COLORADO COAL
9
11
13
14
16
8/18/76
8/20/76
8/21/76
8/22/76
8/22/76
Average
lalden - Hanna
Halden
x 100
17.5
(139.9)
14.4
(114.9)
14.2
(111.7)
8.9
(71.0)
14.2
(112.6)
13.9
(110.0)
+3%
5.46
4.33
5.06
4.18
3.41
4.49
-6%
13.70
14.40
13.91
14.75
15.47
14.45
+3*
14
12
10
13
61
22
-23%
71
33
46
161
63
75
-11%
488
390
438
396
341
411
184
(0.428)
147
(0.342)
165
(0.384)
150
(0.349)
129
(0.299)
155
(0.361)
-28%
312
259
283
228
252
267
251
(0.584)
208
(0.485)
228
(0.530)
184
(0.427)
203
(0.472)
215
(0.499)
-77%
0.3
0.9
26.9
3.8
0
6
0.2
(0.001)
0.7
(0.002)
21.7
(0.050)
3.1
(0.007)
0
5.2
(0.012)
+33%
113.4
87.5
68.4
78.7
87.1
-7%
1566
(3.642)
1176
(2.735)
1194
(2.777)
896
(2.085)
995
(2.315)
1208
(2.711)
-0.7%
300
(0.698)
287
(0.667)
330
(0.768)
265
(0.617)
296
(0.688)
-36%
80.8
76.0
63.2
73.3
73.3
+21%
0.6
0.3
0.5
1.4
0.9
0.74
-14%
-------
TABLE 5.10-3. SULFUR BALANCE SUMMARY, FREMONT DEPARTMENT OF UTILITIES, UNIT 6
Test
No.
Load
fcg/s
t>2
percent
SULFUR IN FUEL
Fuel Sulfur
percent
HHV Fuel
MJ/ko
(BTU/lb)
As S02
ng/J
(Ib/lO&BTU)
SULFUR IN ASH
Ash
Percent
of Fuel
Sulfur
Percent
of Ash
As S02
ng/J
CU>/106BTU)
Retention
percent
SULFUR EMISSIONS
SOx
ng/J
(lb/106BTU)
Fuel Sulfur
Emitted
percent
HANNA WYOMING COAL
3
4
5
6
7
Average
13.6
8.5
17.0
14.7
13.6
13.3
5.39
5.28
5.43
4.14
3.61
4.77
1.55
1.68
1.56
1.16
1.14
1.42
29.2
(12533)
28.8
(12370)
29.1
(12509)
28.6
(12287)
28.7
(12337)
28.9
(12407)
1063
(2.473)
1168
(2.716)
1072
(2.494)
812
(1.888)
795
(1.848)
984
(2.289)
9.85
10.44
9.99
7.76
7.95
9.20
1.30
1.03
1.10
0.96
0.51
0.98
88
(0.204)
75
(0.174)
76
(0.176)
52
(0.121)
28
(0.066)
62
(0.145)
8.3
6.4
7.0
6.4
3.6
6.4
987
(2.295)
1014
(2.359)
1151
(2.677)
772
(1.796)
690
(1.604)
923
(2.146)
92.8
86.9
107.3
95.1
86.8
93.8
WALDEN COLORADO COAL
9
11
13
14
16
Average
Wald.-Han.
Maiden
x 100
17.5
14.4
14.2
8.5
14.2
13.9
+3%
5.46
4.33
5.06
4.18
3.41
4.49
-6%
0.31
0.33
—
0.38
0.37
0.35
-75*
28.0
(12047)
27.7
(11912)
--
28.3
(12186)
28.7
(12324)
28.3
(12186)
-2%
221
(0.515)
238
(0.554)
—
268
(O.624)
258
(0.600)
247
(0.574)
-75%
—
8.91
—
7.85
7.91
8.22
-11%
—
0.15
—
O.23
0.10
0.16
-84%
—
9
(0.022)
—
13
(0.030)
6
(0.013)
9
(0.022)
-85%
--
4.0
—
4.7
2.1
3.6
-44%
251
(0.584)
209
(0.485)
228
(0.530)
184
(0.427)
203
(0.472)
215
(0.500)
-77%
113.4
87.5
—
68.4
78.7
87.1
-47*
-------
1600
^
>
G 1400
D
U
(H 1200
8-
1000
800
Rated Load =20.2 kg/s (160,000 Ib/hr) steam
HANNA WYOMING COAL
WALDEN COLORADO COAL
.o
High Air Tests
Normal Air Tests
o16
7 /"f- Low Air Tests
40
50 60 70 80
PERCENT OF BOILER DESIGN CAPACITY
90
Figure 5.10-3. Uncontrolled particulate emissions vs. boiler load, Fremont
Department of Utilities Unit 6.
330
-------
600
^
c
k,
W
w
s
D
o
500
400
Q
O
8.
300
200
Rated Load =20.2 kg/s (160,000 Ib/hr) steam
HANNA WYOMING COAL
WALDEN COLORADO COAL
40
50 60 70 80
PERCENT OF BOILER DESIGN CAPACITY
90
Figure 5.10-4. Controlled particulate emissions vs. boiler load, Fremont
Department of Utilities Unit 6.
331
-------
Of special interest when studying pulverized coal burning units is
the percent of total ash carried over as emissions. To calculate the total
ash input to the boiler, mass fraction of ash in the fuel is divided by the
fuel's heating value. Expressed in metric units, the results is 2758 ng/J
ash input for the Walden Colorado coal and 3629 ng/J ash input for the Hanna
Wyoming coal. Comparing these figures with the ash emissions data from
Figure 5.10-13, we concluded that at 85% capacity 17.2 kg/s (136x10 Ib/hr
steam) about 40-55% of the ash is carried over. At 50% capacity 10.1 kg/s
(80x10 Ib/hr steam) this figure is about 25 to 40%.
One way to reduce the fly ash carryover and thus the emissions would
be to increase the sizing of the pulverized coal. However, this may be
impractical because it is tied in with combustion efficiency. Another solution
would be to increase the furnace cross sectional area thus reducing the verti-
cal velocity of the combustion gases and allow a larger fraction of the ash to
settle and be removed as bottom ash. This is also impractical because it adds
to the cost of construction and may reduce thermal efficiency of the unit.
The dust collector outlet (controlled) emissions plotted in Figure
5.10-4 clearly show the average 36% reduction in particulates from burning
the Walden Colorado coal. Also apparent is the normalizing effect inherent to
cyclone type dust collectors. This normalizing effect is due to the fact that
cyclone efficiency increases substantially with velocity of the entering gases.
Boiler load and excess air both increase the particulate loading entering the
collector while at the same time increasing gas velocity. As a result, much
of the increase in emissions with load and the effects of excess air are not
visible in the outlet data.
«
Cyclone type dust collectors such as the one installed on Fremont Unit
6 are designed for maximum boiler load where they operate at efficiencies in
the 80 to 90% range (see Predicted Multiclone Efficiency from design data in
Section 5.10.1). From Figure 5.10-5 where this unit's collector efficiency is
plotted against load, we can project maximum load efficiency at 83-86% depend-
ing on the coal burned. At one-half load this number is cut by 20-30%. In
other words, this type of collector is very inefficient at medium and low loads.
This can be a real disadvantage where boilers are operated below peak loading
over the majority of their cycle.
332
-------
4J
C
a)
o
H
&
90
80
H
U
H
S 70
O 60
U
CQ
B
50
Rated Load =20.2 kg/s (160,000 Ib/hr) steam
HANNA WYOMING COAL
WALDEN COLORADO COAL
40
SO 60 70 80 90
PERCENT OF BOILER DESIGN CAPACITY
100
Figure 5.10-5. Multiclone dust collector efficiency vs. boiler load, Fremont
Department of Utilities Unit 6.
333
-------
The improved collector efficiency in handling Walden Colorado coal
is quite evident. It may be due to larger average sizing of this pulverized
coal stemming from a difference in its grindability, or it may result from
agglomeration of the ash.
C. Sulfur Oxides Emissions—
Sulfur content was one of the primary differences between the two fuels
fired at Fremont. On a HHV basis, the Walden Colorado coal contained 75% less
sulfur than the Hanna Wyoming coal. As one would expect, the sulfur oxide
emissions showed a similar trend. The Walden Colorado coal emitted 77% less
sulfur than the Hanna Wyoming coal.
Variations in excess 0- and boiler load did not appear to significantly
effect sulfur oxide emissions. Figure 5.10-6 plots these emissions for both
fuels against boiler load. The scatter in emissions data was found to be
related to day-to-day variations in sulfur content of the fuel.
A sulfur balance was made comparing sulfur input to the furnace as
determined from coal analysis with sulfur output as determined from ash
analysis and emissions data. This data is summarized in Table 5.10-3 and
illustrated graphically in Figure 5.10-7. The results are not inconsistent
with previous attempts to balance sulfur in a coal-fired boiler during this
program. Difficulties in obtaining representative coal and ash samples due
to their ever changing properties account for much of the error.
Several conclusions can be drawn. The scatter in the emissions data
shown in Figure 5.10-6 is related to the scatter in sulfur content of the
coal, not experimental error, or excess O as tests 2, 3, 6, and 7 might
indicate.
There may be a correlation between excess O and sulfur retention in
the ash. Based on limited data, the sulfur retention appears to increase as
excess O is increased.
Finally, the sulfur retention was on the order of 5%, with the Walden
Colorado coal appearing to retain a slightly lower percentage of the total
sulfur in its ash.
334
-------
125J
ID
Cn
C
1000
W
o
H
(O
fj 750
Q
H
X
0
§ 500
W
250
Rated Load =20.2 kg/s (160,000 Ib/hr) steam
(Q HANNA WYOMING COAL
,~
vx
s
4
• 3
A
6
7 •
*
—
Q
" " p.
ii in ^^T^"^ — i^— ^"' ™* V^/
O " " 16
1 1 1
40
SO 60 70 80
PERCENT OF BOILER DESIGN CAPACITY
90
Figure 5.10-6. Sulfur oxide emissions vs. boiler load, Fremont Department
of Utilities Unit 6.
335
-------
1250
f
^ 1000
ts
o
M
s
S 750
w
(A)
CTl
500
250
— —
*™— ™*^
777
'//f
i
v/
'///,
'//,
%
I
W
^fSS
//y
^//
I
v/,
vx,
^
//'/
%
1
///
^
I
///
///
y/
W
I
*.•.-.•.•'
///
^
l/VVy
^
I
^
:>>>:«
///
w
vvv
1
/>x
1
<
i
SULFUR IN FUEL
3ULFOR EMISSIONS
^^°xa\ y//-r^, v%"*—\
i i i
11
14
16
TEST NUMBER
Figure 5.10-7. Sulfur balance, Fremont Department of Utilities Unit 6.
-------
Sulfur trioxide was not plotted. It accounted for 0.38% of the total
sulfur oxides when Hanna Wyoming coal was burned and over the range of 02 levels
studied was not a function of either load or excess 0.,. When Walden Colorado
coal was burned, the sulfur trioxide fraction varied from 0 to 9.5%. These
variations could not be correlated with any of the test variables.
D. Nitric Oxide Emissions—
As seen in Table 5.10-2, the average nitric oxide emissions were 26%
lower when burning Walden Colorado coal as compared to Hanna Wyoming coal.
One reason for this may be found in the fuel analysis. Table 5.10-1, which
shows the Walden Colorado coal contained 25% less fuel bound nitrogen.
Fuel-bound nitrogen is the primary source of nitric oxide from coal
fired boilers. If we assume that all of the nitric oxide was formed from fuel-
bound nitrogen, then we find that 19.9% of the Hanna Wyoming coals' nitrogen
and 19.4% of the Walden Colorado coals' nitrogen was converted to nitric
oxide.
Nitric oxide increased with load as shown in Figure 5.10-8. Test
numbers 3, 4, and 5 can be considered to be at constant excess O . Here, a
10% increase in load resulted in a 7.5% increase in nitric oxide emissions at
80% load. It should be noted that low load tests 4 and 14 were run with only
two of the units four burners in service. This is normal low load configura-
tion. The two burners taken out were diagonally opposed so that both mills
could remain in operation, each feeding one burner.
Nitric oxide increased with excess O2 as shown in Figure 5.10-9. For
this series of tests, boiler load was held constant while the air/fuel ratio was
varied at 15 minute intervals. On the average, nitric oxide was found to
increase by 16 ng/J, or about 10% for each 1% increase in excess Or This
data is contained in Table 5.10-4.
E. Carbon Monoxide and Hydrocarbon Emissions—
Under normal operating conditions, carbon monoxide remained insignifi-
cant at values of less than 20 ppm for both fuels. However, this unit was
fired at higher than necessary excess O levels.
337
-------
TABLE 5.10-4. EMISSIONS SUMMARY FOR SPECIAL TESTS,
FREMONT DEPARTMENT OF UTILITIES, UNIT 6
TEST LOAD LOAD
NO. kg/s % Cap.
8 13.8 63
(Hanna Wyoming Coal)
(7/29/76)
10 17.8 88
(Walden Colorado Coal)
(8/18/76)
12 13.6 68
(Walden Colorado Coal)
(8/20/76)
15 8.9 45
(Walden Colorado Coal)
(8/22/76)
02
%
4.10
4.05
4.40
4.90
4.10
3.75
3.40
5.45
5.30
4.80
4.50
4.15
4.40
3.90
3.50
3.15
4.10
3.85
3.35
2.70
CO
Dry r ppm
6
13
13
13
13
7
15
13
13
12
22
59
11
8
19
38
13
14
36
148
NO
Dry, ppm
490
488
515
525
479
463
450
469
464
443
431
420
369
353
324
325
370
399
398
NO
ng/J
186
186
196
200
182
176
171
177
175
167
163
158
139
133
122
123
140
150
150
338
-------
250
H
w
CO
200
ISO
H
8
U 100
Rated Load =20.2 kg/s (160,000 Ib/hr) steam
14
o
BANNA WYOMING COAL, 5.3% O.
WALDEN COLORADO COAL, 4.6%
40 50 60 70 80
PERCENT OF BOILER DESIGN LOAD
90
Figure 5.10-8. Nitric oxide emissions vs. boiler load, Fremont Department
of Utilities Unit 6.
339
-------
CP
§
H
W
to
w
Q
H
O
U
H
EH
H
s
200
175
150
125
100
-A-
.A-
63% Stm Capacity, lest #8
(Hanna Coal)
88% Stm Capacity, lest #10
(Walden Coal)
68% Stm Capacity, Test #12
(Walden Coal)
3.0 3.5 4.0 4.5 5.0
EXCESS OXYGEN, percent
5.5
Figure 5.10-9. Nitric oxide emissions vs. excess oxygen, Fremont Department
of Utilities Unit 6.
340
-------
During tests 10, 12, and 15 when air/fuel ratio was varied in
increments, carbon, monoxide was monitored to determine the point at which it
would begin to rise. The data is shown in Figure 5.10-10. At low and medium
loads this point was reached at 3.9% excess cy For high loads, carbon monoxide
began to increase below 4.8% excess Or According to the control room o
monitor, which was closer to the furnace than ours, an increase in carbon
monoxide occurred as the excess 02 dropped below 3.0% for all three loads.
By sampling from each side of the boiler separately it was discovered
that the CO was being formed much sooner on the west side than on the east.
The following data illustrates this point:
West Side East Side
Excess O2 2.22% 3.55%
Carbon Monoxide 280 ppm 15 ppm
(Data from test 12, August 20, 1976}
According to B&W, the burners should be able to operate continuously
at 3% excess O_ without CO formation. It is concluded that the present opera-
£
tion at 3.8% excess 0 could be reduced to 3.0% if the fuel/air ratio were
balanced on both sides. A substantial savings in operating cost through
improved efficiency would result.
Hydrocarbon emissions were measured but showed no significant correla-
tion with load or excess O . Part of the problem in measuring hydrocarbons
was a contaminated heated sample line from which background emissions had
to be subtracted. These varied with time and flow rate. The net hydrocarbon
emissions measured ranged from 33 to 161 ppm and were about 30% lower for
the Walden Colorado coal. This data is contained-.in Table 5.10-2.
5.10.4 Boiler Efficiency
Table 5.10-5 compares boiler efficiencies while burning the Hanna
Wyoming and Walden Colorado coals. The largest heat losses are moisture + H2
and dry gas losses. The fuel moisture losses did not vary significantly from
one fuel to the other. The dry gas losses were the main variables. The
overall unit efficiency was slightly higher when burning the Walden Colorado
coal due to lower dry gas losses.
341
-------
<*>
rn
-p
(0
T)
I
I/I
H
Q
H
X
I
8
80
w 60
§
H
40
20
A 88% CAPACITY, TEST #10
|~| 68% CAPACITY, TEST #12
Q 45% CAPACITY, TEST #15
\
A A-
3.0
3.5
4.0
4.5
5.0
5.5
EXCESS OXYGEN, percent
Figure 5.10-10. Carbon monoxide emissions vs. excess oxygen at three boiler
loads, Fremont Department of Utilities Unit 6, Walden Colorado
coal.
342
-------
TABLE 5.10-5. BOILER EFFICIENCY SUMMARY, FREMONT DEPARTMENT OF UTILITIES, UNIT 6
Test No.
Test Load
kg/s
Percent of Capacity
Stack O2 (% Dry) *
Stack CO (ppra)
Stack Temp. <0K/0F)
Ambient Air Temp. (°K/°F)
Corr. Stack Temp. ("K/T)
Boiler Heat Bal. Losses (%)
Dry Gas
Moisture + H2
Moisture in Air
Unburned CO
Combustibles
Radiation
Boiler Efficiency
HANNA WYOMING
3
13.6
67.7
4.9
11.0
443/338
315/108
434/321
5.99
5.64
0.14
0.00
0.11
0.59
87.52
4
8.3
41.3
4.8
17.0
434/322
311/100
427/310
5.68
5.61
0.14
0.01
0.13
0.97
87.46
5
16.9
83.4
5.4
20.0
447/346
309/96
442/336
6.40
5.67
0.15
0.01
0.05
0.48
87.24
6
14.7
73.0
3.6
18.0
437/328
307/94
433/320
5.54
5.63
0.13
0.01
0.07
0.55
88.07
7
13.6
67.6
3.3
17.0
434/321
314/106
425/305
5.05
5.60
0.12
0.01
0.07
0.59
88.56
WALDEN COLORADO
9
17.5
87.4
5.2
14.0
442/337
309/97
437/327
6.12
5.76
0.15
0.01
0.04
0.46
87.47
11
14.4
71.8
3.8
12.0
429/314
306/92
426/307
5.26
5.71
0.13
0.00
0.02
0.56
88.32
13
14.2
69.8
5.0
10.0
435/323
306/91
431/316
5.72
5.73
0.14
0.00
0.04
0.57
87.79
14
8.9
44.4
3.8
13.0
430/315
308/95
426/307
5.21
5.71
0.12
0.01
0.11
0.90
87.95
16
14.2
70.4
3.4
61.0
437/328
311/100
431/316
5.21
5.73
0.12
0.02
0.07
0.57
88.28
OJ
•fe.
10
Stack 02 measured at dust collector inlet
-------
Excess oxygen played an important role (Figure 5.10-11). Lowering the
excess O by 1% raised the unit overall efficiency by about 0.5%. When boiler
load was raised from 70 to 85% of capacity, the overall efficiency dropped
0.3% due to greater dry gas losses. When boiler load was dropped from 70% to
45%, and two burners were taken out of service, the overall unit efficiency
dropped somewhat due to radiation loss accounting for a larger percentage of
the total heat output. Moisture in the air, unburned CO and combustibles in
the ash did not play a significant part in shaping the overall boiler effi-
ciency.
5.10.5 Operational Problems and Observations
Unit #6 of Fremont Department of Utilities was designed f
bituminous Kansas coal. When the switch was made to Hanna-RosebuS
coal in an attempt to meet air pollution regulations, several op
problems developed. Full steam capacity could not be obtained. BeC*Use of
day-by-day variations in the coal properties, the steam capacity of Unit #6
was sometimes reduced by as much as one-third of design capacity. Unloading
this coal created a dust problem in the summer. In the winter, it froze in
the coal cars and was difficult to remove.
The switch to Colorado coal was made during our testing because of
its lower ash, lower sulfur, lower price and more feasible shipping point.
This coal proved to be cleaner burning. Design steam capacity was easily
met. When mixed with the Wyoming coal there was less problem maintaining
load. Following our test program at Fremont, the remaining Wyoming coal was
burned by mixing it with the Colorado coal.
Although the Colorado coal burned well, it was even harder to unload
than the Wyoming coal. The dust problem was very bad in the summer. In
the winter, there were times when only four cars could be unloaded per day
because of freezing.
During testing, when the Colorado coal was burned, the mills were
not pulverizing the coa-1 as well as they should have been. This problem was
later corrected .by adjustments to the mills. It is possible that the reduced
344
-------
c
0)
u
u
H
U
H
H
g
89.0
88.5
88.0
87.5
HANNA WYOMING COAL
WALDEN COLORADO COAL
o
3.0
3.5 4.0 4.5 5.0
EXCESS OXYGEN, percent
5.5
Figure 5.10-11. Boiler efficiency vs. excess 02, Fremont Department of
Utilities Unit 6.
345
-------
controlled particulate emissions obtained when burning the Colorado coal
were due to a coarser fuel sizing rather than any other fuel property. A
table of the coal sizing tests follows:
Date Coal Mill <50 Mesh >100 Mesh >200 Mesh
8/4/76
8/18/76
8/18/76
Wyoming
Colorado
Colorado
A
A
B
0.4%
4.0%
1.3%
95.6%
86.0%
92.7%
77.4%
58.3%
64.7%
Also during testing, peak loads were limited by a cooling problem
with the Unit #6 steam turbine. This problem prevented us from testing at
peak boiler load with the Colorado coal.
346
-------
APPENDIX A
INDUSTRIAL-SIZED BOILER POPULATION SURVEY
347
-------
A.I INTRODUCTION
The purpose of"this section of the western coal study which this
Appendix covers was to survey and screen the small and intermediate-sized
coal-fired boilers in the United States in order to determine the feasibi-
lity of converting a portion of them to a low-sulfur western coal as a
means of reducing sulfur oxides emissions. The American Boiler Manufac-
turers Association (ABMA) sales data which included 362 units for 1965-1974
was used to obtain a more detailed geographical distribution, both by popu-
lation and capacity, of coal-fired boilers in the range 1.3 to 38 kg/s
[10,000 to 300,000 Ib/hr (pph)] steam. The results of this survey show
that the heaviest concentration of coal-fired units is in the midwest
around the Great Lakes. This will then be the area where the maximum poten-
tial SO reduction exists.
In addition to the boiler survey, an analysis was made of the geo-
graphical distribution of sulfur in coals used as industrial boiler fuel.
This data was then used with the boiler population to arrive at an estimate
of the maximum possible SO reduction achievable by changing fuel to low
X
sulfur western coal. The impact of this reduction was demonstrated for
four areas of the United States and with four coals which are typical of
the largest western-coal-producing regions. The results indicate that SO
reductions in emissions from coal-fired industrial boilers of 46% to 78%
could theoretically be realized on a nationwide basis, and reductions of
53% to 81% for the midwestern-Great Lakes region by using western coal.
An informal survey was conducted in order to determine current
western coal users. One hundred and eleven boiler owners and operators in
Minnesota, Wisconsin, Iowa, Nebraska, Michigan, Indiana, Missouri, and
Illinois were contacted. Information was gathered on the following:
349
-------
Installed boiler population and geographical distribution
Western coal users and operational experience with parti-
cular firing equipment
Conversion from coal to gas and/or oil
Potential hosts for boiler testing
A study of the supply variables made it apparent that the two states
of Wyoming and Montana are the only western states that are in a position to
supply coal to the midwestern and eastern parts of the country during the
next ten years. The factors that were taken into consideration were:
Current production from specific sources
Production trends and costs
Shipping costs
Mine capacities
Analyses of the coal from all of the major producing areas in Wyoming and
Montana have been obtained. These typical coal analyses were then compared
to the combustion requirements for the individual firing types to arrive at
an estimate of the difficulty that would be encountered in switching to the
western coal.
The data gathered during the first phase of the program indicate
that a conversion to western coal can be an effective SO emission control
x
technique for most types of coal combustion systems. However, some penal-
ties are involved with unit performance and efficiency. Furthermore, it
seems likely that the supply of western coal, especially from Wyoming and
Montana, can be made available in midwestern markets at competitive prices.
A.1.1 Boiler Survey
Figure A-l contains ABMA sales data for boilers sold between 1965
and 1974. The data have been sorted according to the following categories:
Firing Type (pulverized, spreader stoker, overfed stoker,
underfed stoker, or other)
Capacity [1.3 to 38 kg/s (10,000 to 300,000 Ib/hr pph)
steam]
Year of Sale (1965-1974)
350
-------
ririnq; Method
Pulverized
Spreader
Underfeed
Overfeed
Other
Region 18
1
5
1
2
2
Total 1965-1974 11
Firing Method
Pulverized'
Spreader
Underfeed
Overfeed
Other
Region
2
22
0
4
3
Firing Method
Pulverized
Spreader
Underfeed
Overfeed
Other
Region
13
70
4
27
43
Firing Method
Pulverized
Spreader
Underfeed
Overfeed
Other
Total 1965-1974
Firing Method
Pulverized
Spreader
Underfeed
Overfeed
Other
Region
o
1
0
1
0
Total 1965-1974
ME
It
"'4(^9
. CT
NJ
-DE
^
NH
r— MA
RI
Firing Method
Pulverized
* Spreader
Underfeed
Overfeed
Other
Total 1965-1974
Region »2
8
31
10
8
17
74
Firing Method Region S7
Pulverized
Spreader
Underfeed
Overfeed
Other
Total 1965-1974
0
9
2
0
1
12
Firing Method Region ft6
Pulverized 0
Spreader 4
Underfeed 0
Overfeed 0
Other 5
Total 1965-1974 9
Firing Method
Pulverized
Spreader
Underfeed
Overfeed
Other
Total 1965-1974
Region 14
6
34
9
5
10
64
Figure A-l. Regional boundaries used in Table A-l.
-------
Geographical Location (1973-1974 have full zip code, 1970-
1972 have first three digits of zip code, and 1965-1970 have
a one-digit zip code)
Primary and Alternate Fuel (units that use coal or lignite
as a primary fuel or units that can fire coal or lignite as
an alternate fuel)
Domestic Sale
Stationary Unit
Standard Industrial Classification Code
These boilers have been located on the map shown in Figure A-l and compiled
in Table A-l in such a manner that the geographic impact of western coal
conversion can be seen. In a similar manner, Table A-2 gives the capacity
of the coal-fired units distributed into regions and firing types. This
survey presents a more detailed look at this particular class of unit than
is available from either Walden (Ref. A-l) or the Battelle studies (Ref. A-2).
Population of Coal-Fired Units Surveyed
Region 3 had 157 boilers installed during the nine year pexiod. This
represents about 44% of the total population. Within Region 3, the distribution
among firing types is as follows: pulverized units account for 8.3%; spreader
stokers, 44.5%; overfed stokers, 17.2%; underfed stokers, 2.5%; and other
units, 27.4%. Regions 2 and 4 had about 20% and 18% of the total population,
respectively. The remaining 18.5% of the total population was spread over
the other regions.
Nationally, spreader stokers account for about 50% of the units sold
during the period followed by 20% for other types of coal firing, 13% for
overfed stokers, 9% for pulverized, and 7% for underfed stokers.
The total number of coal-fired boilers that have been sold in the
last nine years in this size category is small (362) compared to the total
number existing in the United States which are still firing coal. Ehrenfeld
(Ref. A-l) estimated that there were 5,239 boilers installed in the country
in the size range 1.3 to 35 kg/s (10,000 to 250,000 Ib/hr) steam that could
burn coal. The number of units that actually fire bituminous coal or lignite
is considerably smaller. For example, in 1973, 36 overfed units were sold;
352
-------
TABLE A-l. NUMBER OF UNITS SOLD
FROM 1965 to 1974 BY REGION
Categories
Other
Pulverized
Spreader Stoker
Underfed
Overfed
Total
% of Total
1 2
17
8
1 31
10
1 8
2 74
0.6 20.4
Geographic Regions*
345678
43
13
70
4
27
157
43.4
10
6
34
9
5
64
17.7
3
2
22
4
31
8.5
512
1
495
2
3
9 12 11
2.5 3.3 3.0
9 Total
2 83
30
176
25
48
2 362
0.6
*Geographic Region (by number code)
1. New England States
Connecticut, Maine, New
Hampshire, Massachusetts,
Rhode Island, Vermont
2. Mid-Atlantic States
Delaware, Maryland, New
Jersey, New York, Pennsyl-
vania, Virginia, West
Virginia
3. East-North-Central States
Illinois, Indiana, Kentucky,
Michigan, Ohio, Wisconsin
4. South-Atlantic States
Alabama, Florida, Georgia,
Mississippi, North Carolina,
South Carolina, Tennessee
5. West-North-Central States
Iowa, Kansas, Minnesota,
Missouri, Nebraska, North
Dakota, South Dakota
6. West-South-Central States
Arkansas, Louisiana, Oklahoma,
Texas
7. Rocky Mountain States
Colorado, New Mexico, Utah,
Wyoming
8. Northwestern States
Idaho, Montana, Oregon,
9. Southwestern States
Arizona, California, Nevada
353
-------
however, 33 of these units were specifically designed to burn wood. Overfed
and spreader stoker units are two categories of firing types where there
appears to be a significant wood-burning contribution. Typically, these
units are installed in the wood and paper processing industries where the
waste wood and paper products are burned as boiler fuel. However, such units
will fire bituminous coal when there is insufficient waste wood to meet load
demands.
The pulverized coal firing type and the underfed stoker firing type
are limited to bituminous coal and lignite firing.
The "other" category includes cyclone units at the larger end of
the size range, above 25.2 kg/s (200,000 Ib/hr) steam. The smaller units in
the "other" category include vibrating grate, reciprocating, and oscillating
grate stokers. Some of these units may be equipped with a system whereby the
ash is blown off the water-cooled grate with either steam or air.
More detailed information about grate design is not available from
the ABMA records. For example, spreader stokers may be equipped with travel-
ing grates or dumping grates. Some smaller overfed units are equipped with
water-cooled grates; however, this is not common.
Capacity of Coal-Fired Units Surveyed
Table A-2 gives the steam capacity in thousands of pounds per hour
for all of the coal-fired boilers in the size range 1.3 to 38 kg/s (10,000
to 300,000 Ib/hr) steam. Inspection of the data indicates that the capacities
of the units sold closely follows the population distribution for both firing
categories and geographic regions. In Region 3, spreader stokers account for
49.4%; other units, 24%; pulverized, 17.1%; overfed, 8.8%; and underfed,
0.73% of the total capacity of the region. Again, the overall capacity
distribution for the nine regions follows population distribution. Region 3
has 41.3% of the total followed by Region 2 at 16.8%, Region 6 at 4.7%, and
Regions 9 and 1 at 0.5% and 0.25%, respectively.
354
-------
TABLE A-2. CAPACITY [kg/S (10 Ib/hr) STEAM] OF COAL-FIRED UNITS
SOLD FROM 1965 TO 1974 BY GEOGRAPHIC REGION
OJ
en
Ul
Firing
Category
Other
Pulverized
Spreader Stoker
Underfed
Overfed
1 2
155
(1,230)
191
(1,516)
3.9 327
(30) (2,598)
30.
(241)
7.5 94
(60) (429)
3
322.5
(3,562)
318
(2,524)
917
(7,281)
3 13.6
(108)
163
(1,295)
Geographic Regions
4567
117
(931)
167.
(1,329)
355.
(2,821)
29.
(197)
46.
(370)
30.3
(240)
5 56.7
(450)
3 395.3
(3,137)
7 51
(405)
7
100.8 25.3
(801) (200)
109.7 139.7
(870) (1,110)
3.9
(31)
8
34.7
(275)
31.4
(250)
128.1
(1,020)
20.8
(245)
9 Total
22.5 934.5
(178) (7,417)
764.5
(6,069)
2,376.7
(18,867)
72.8
(577)
353.3
(2,804)
Total
11.4 757.5 1,360.6 711.4 533 210.6 168.9 225.6 22.5 4,501.7
(90) (6,014)(14,770) (5,648) (4,232) (1,671) (1,341) (1,790) (178) (35,734)
Percent of Total 0.25 16.8
41.3
15.8
11.8
4.7
3.8
5.0
0.5
-------
Sales Trends
Figure A-2 contains the 1965-1974 ABMA sales data for coal-fired
units in the size range 1.3 to 38 kg/s (10,000 to 30,000 Ib/hr) steam. The
data are plotted by year as population and total steam capacity for the five
firing types. It can be seen that boiler sales have declined steadily from
1965 to a low point in 1971. Beginning in 1973, however/ there was a general
increase in sales with spreader stoker sales approaching 1966 sales levels.
Spreader stokers represent the largest single firing type, both by number and
total capacity. Pulverized-coal-fired units are predominantly the larger
units above 25.2 kg/s (200,000 Ib/hr) steam. This becomes obvious when popu-
lation data and capacity data for pulverized coal units are compared.
Spreader stoker units cover the entire size range of interest for this study
with units as small as 1.3 kg/s (10,000 Ib/hr) steam and as large as 28 kg/s
(300,000 Ib/hr) steam. The spreader stoker appears to be the unit of choice
for most industrial coal-fired installations. Spreader stokers are also
found in small utilities where they are used as peaking units.
For the ten-year period, the sales of each firing type relative to
each other has remained roughly constant. During years of heavy sales, the
spreader stoker has outsold all other types. Over this period, spreader
stoker sales accounted for 49% of all units by population and 53% by capa-
city. The next largest category is the other firing types which account
for 23% of the units by population and 21% by capacity. Overfed and underfed
units combined represent 20% of the population, but only 9% of the capacity.
Finally, the pulverized-coal-firing category contains 8% of the population
and 17% of the capacity.
Design Trends
The versatility of ..the spreader stoker has made it the preferred fir-
ing method over the years and this trend appears to be continuing with even
greater strength. The recent sales increase in coal-fired equipment has
been dominated by the spreader stoker. The data also show a trend toward
larger spreader stokers. One reason for the popularity of the spreader stoker
356
-------
2268 -|
1814 -
so
40
KEY:
PC - Pulverized Coal
SS * Spreader Stoker
OF - Overfed Stoker
UF * Underfed Stoker
O * Other
Capacity (metric tons/hr)
Population
1360 -
3 907-1
01 *
-J «
PC
ss
OF
UF
O
%
8.3
46.6
13.3
6.9
22.9
100
No. of
Units
30
176
48
25
83
362
Rg/s
Steam
764
Z377
353
73
934
4502
%
17.0
52.8
7.8
1.6
20.8
100
30
20
10
0 JO
* §
w a
§ 1
PC SS UF OF
1966 —•
D PC SS UF OF
1967
O PC SS UF OF
1969 -••
O PC SS UF OF
••• 1970
SS UF OF | O PC SS UF OF | O PC SS UF OF
1972 • I * 1973 -"-I— 1974
Figure A-2. Coal-fired units sold from 1965-1974 in the size range
1.3 to 38 kg/s (10,000 to 300,000 Ib/hr) steam.
g.
3
-------
is that they are capable of burning a wide range of coals, from high ranked
eastern bituminous to lignite, as well as many byproduct waste fuels.
Spreader-stoker firing has a very quick response to load changes and the
turndown range extends from 20% of full load to maximum capacity. Travel-
ing grates remain the most popular grate configuration for spreader-stoker-
fired boilers rated higher than 9.4 kg/s (75,000 Ib/hr) steam. They are
designed to handle a wide range of coals as well as process wastes and muni-
cipal refuse. In view of this flexibility and the fluctuating coal economy,
the traveling grate is expected to be the system of choice for at least the
next five years.
New Developments
It is difficult to estimate the environmental and economic impact
of potential developments on this boiler size category. Some examples of
these new developments whose effect may be to increase the total capacity of
this size range or to decrease it are given below:
Greatly expanded in-plant electrical generation would
increase the size range capacity.
Deregulation of natural gas prices would serve to increase
the size range capacity by a reconversion to coal firing.
Further oil price increases would increase the size range
capacity in the same way gas deregulation would.
Legislation restricting the use of natural gas for process
units would increase the number of units and the capacity
in the size range.
Large-scale coal gasification and/or liquefaction would
tend to decrease the coal-fired capacity of the size
range; however, this development is at least ten years
in the future.
Increased commercial electrical generation with resultant
lower energy rates would not measurably affect this size
category of boiler.
Environmental legislation aimed at sulfur, particulates, and
NOX,would probably not measurably affect this size category
due to the severity of the energy constraints.
358
-------
REFERENCES FOR APPENDIX A
A-l Ehrenfeld, J. R., et al., "Systematic Study of Air Pollution from
Intermediate Size Fossil-Fuel Combustion Equipment," Final Report,
Contract CPA 22-69-85, Walden Research Corporation, July 1971.
A-2 Locklin, D. W., et al., "Design Trends and Operating Problems in
Combustion Modification of Industrial Boilers," Battelle Final
Report for EPA Grant No. R-802402, April 1974.
359
-------
APPENDIX B
GEOGRAPHICAL COAL SULFUR DISTRIBUTION
AND IMPACT ON AIR QUALITY
OF FUEL SWITCHING TO WESTERN COAL
361
-------
B.I BOILER CAPACITY
The total output capacity of boilers in the size range 1.3 to 32
3
kg/s (10 to 250x10 Ib/hr) steam was estimed by Locklin (Ref. B-l) to be
1.15x10 MJ/hr for the 1.3 to 12.6 kg/s (10 to lOOxlO3 Ib/hr) steam range
14 ,
and 8.44x10 MJ/hr for the 12.7 to 32 kg/s (100 to 250x10 Ib/hr) steam
range. These figures were based on the 1971 estimate of Ehrenfeld (Ref.
B-2) , updated for sales during the period of 1967 to 1974.
The percent capacity as coal-fired units was given in Reference
B-l as 10% for the 1.3 to 12.6 kg/s range and 19% for the 12.7 to 32 kg/s
range. Thus the total heat capacity installed for coal is estimated to be:
Q1.3 - 12.6 ' 1-°1*10 MJ/yr
Q12.7 - 32
For a heating value of 23.2 MJ/kg (10,000 Btu/lb) , the coal consump-
tion in these boilers is:
.6
M
., „ , „ _ = 43.3x10 metric tons/yr
1.3 - 12.6
M.
6
= 60.46x10 metric tons/yr
* / ~ O ^£
B.2 CURRENT COAL SULFUR DISTRIBUTION
The current distribution of sulfur in coal was estimated from seam
analyses given in the Keystone Coal Manual (Ref. B-3) , from mine analyses
in the same source, and from mine analyses summarized by Reference B-4. For
western coals, only the mine analyses were used since they were a more reli-
able indication of available coals. For midwestern and eastern coal, the
seam analyses were used since the area is heavily mined and better charac-
terized. Where seam reserve estimates were available, the sulfur percentage
was weighted by these estimates. For the western coal, the sulfur percentage
was weighted by mine capacity.
363
-------
Table B-l summarizes the results obtained by this method for the
western coal states. Table B-2 summarizes the values for midwestern and
eastern states obtained from the seam analyses and reserve estimates.
Table B-3 (which was not used for estimating purposes) summarizes the values
for midwestern and eastern states obtained from mine analyses and capacity.
As can be seen, the number of mine analyses available is very low
for some states, making a uniform basis for averaging by this method impos-
sible. Furthermore the averages for states with few mines reporting (such
as Illinois or Missouri) are quite different from the seam analyses. For
these reasons. Tables B-l and B-2 were used in subsequent calculations.
B-3. COAL USAGE BY REGION AND ORIGIN
In order to determine the sulfur emissions in coal-burning boilers,
it is necessary to first estimate the consumption of coal by its origin in
order to relate the average sulfur values determined above to the total coal
consumed. A study by the Bureau of Mines has categorized coal consumption
by regions of consumption and origin (Ref. B-5). This study considered
utility consumption, coking operations, barge and train propulsion, and
"other categories". Since most of the boilers considered in this study are
smaller than utility size, coal-burning boiler distribution was assumed to
be in accordance with the use distribution of coal in "other categories".
In order to check this assumption, the percentage of the total coal burned
by boilers of less than 63 kg/s (500x10 Ib/hr) steam [given by Ehrenfeld
(Ref. B-2)] for the Great Lakes and Central Regions was compared to the
value resulting from the method described above. A value of 51.3% was
obtained from Reference B-l versus 54.5% calculated from the Bureau of
Mines report. The slight disagreement could be due to the somewhat heavier
concentration of industrial boilers in this region which would bias the
sample toward the under 32 kg/s (250x10 Ib/hr) steam range than if the
32 to 63 kg/s (250 to SOOxlO3 Ib/hr) steam units are included.
364
-------
TABLE B-l. WESTERN COAL SULFUR CONTENT, HEATING VALUE,
AND ASH FUSION TEMPERATURE (AVERAGED BY PRODUCTION)
State
Arizona
Colorado
Montana
New Mexico
North Dakota
Utah
Washington
Wyoming
Capacity*
12.26
8.58'
23.49
14.32
11.14
9.08
11.19
33.35
1973
Production*
2.70
5.66
9.03
9.03
8.48
4.9
2.91
12.35
Sulfur
159
340
296
262
645
241
342
254
AFT
1466
1529
1490
1589*
1457
1475
1533
1482
Heating
Value*
25.3
31.1
20.2
22.8
16.3
30.5
18.8
23.5
*10 metric tons/year
§°K
*MJ/kg, as received
^Navajo Mine not included
TABLE B-2. MIDWESTERN AND EASTERN COAL CHARACTERISTICS
(AVERAGED BY SEAM RESERVES WHERE GIVEN)
State
Alabama
Illinois
Indiana
Kansas
Kentucky (East)
Kentucky (West)
Maryland
Missouri
Ohio
Oklahoma
Pennsylvania
Tennessee
Virginia
West Virginia
Sulfur
ng/J
434
1272
942
1892
340
1036
658
1350
1127
585
632
645
292
378
Number of
Seam Analyses
67
61
8
10
17
4
11
6
16
20
43
44
45
27
365
-------
TABLE B-3. MIDWESTERN AND EASTERN COAL CHARACTERISTICS
FROM MINE DATA (WEIGHTED BY PRODUCTION)
State
Alabama
Illinois
Indiana
Kentucky
Maryland
Missouri
Ohio
Oklahoma
Pennsylvania
Virginia
West Virginia
Sulfur
ng/J
211
778
1170
439
619
2391
1729
185
727
348
464
No. of Mines
Reporting
5
4
1
40
3
1
14
1
39
4
39
366
KVB 8800-482
-------
Table B-4 summarizes the data for coal consumption according to the
region of origin and the state of use. These data were converted to percent-
ages to estimate the regional distribution of the total boiler heat (coal)
consumption. The regions of origin and average sulfur content (derived by
averaging state averages of Tables B-l and B-2) are delineated in Table B-5.
B.4 ESTIMATE MAXIMUM POSSIBLE SULFUR REDUCTION
B.4.1 Present Sulfur Emissions
The data of Tables B-2 through B-5 were applied to calculate the
sulfur emissions from coal-burning boilers in the 1.3 to 32 kg/s (10,000
to 250,000 Ib/hr) steam range. The sulfur emitted was simply:
23
Ms1.3-12.6 = i Si Q22-221
o
S12.7-32
23
T f. s.
where
Ms = mass of sulfur (as sulfur) emitted from boilers
1.3-12.6 in the 1.3 to 12.6 kg/s range
f. = fraction of the coal originating in region i
s. = average sulfur content of coal in region i
Ms = mass of sulfur (as sulfur) emitted from boilers
12.7-32 in the 12.7 to 32 kg/s
Substitution of the appropriate values gives:
M_ = 7.31 x 105 metric tons/year (as sulfur)
T..3-12.6
Mo = 1.019 x 10 metric tons/year (as sulfur)
T.2.7-32
When the same data was used to estimate the sulfur emissions only in the
midwestern (CU) and Great Lakes (GL) states, the following values were obtained:
Ms (CU,GL) = 4.194 x 105 metric tons/year
1.3-12.6 5
M (CU,GL) = 5.855 x 10 metric tons/year
s!2.7-32
367
-------
TABLE B-4. COAL USAGE FOR "OTHER DEVICES" BY REGION OF ORIGIN
AND STATE OF USE (1973) (Thousands of Metric Tons/Year)
Region of Origin
STATE OF USE
Massachusetts
Connecticut
Maine, N.H., Vt, R.I.
New York
New Jersey
Pennsylvania
Ohio
Indiana
Illinois
Michigan
Minnesota
Wisconsin
Iowa
Missouri
N. Dak., S. Dak.
Neb. , Kansas
Del., Maryland
Hash. DC
Virginia
W. Virginia
N. Carolina
S . Carolina
Georgia, Florida
Kentucky
Tennessee
Ala., Miss.
Ark, La, Ok, Texas
Colorado
Utah
Mont., Idaho
Wyoming
New Mexico
Ar iz . r Nevada
Hash. , Oregon
1
4
38
8
917
1400
47
3
91
700
21
6
11
2
1
276
2083
277
408
346
43
9
724
728
131
8
120
20
55
12
42
997
15
28
4
84
3
92
4459
3
985
3
51
434
5
7
1
66
15
8
264
2
34
48
56
156
175
5
23
27
38
9
8
8
6
10
131
67
760
3422
260
571
3333
231
1265
11
5
73
172
2122
1937
1287
1004
182
674
1324
5
68
9
•
159
101
363
10
230
174
11
971
418
1652
10
580
3104
360
96
585
1045
1241
91
289
11
3748
91
66
239
62
—
91
91
12
34
91
13
151
1514
49
14
5
94
12
15
12
25
121
1927
16
91
17
12
45
284
18
2
109
4
23
19
1
6
240
318
29
131
223
75
20
655
122
114
103
21
285
22
345
23
2
27
853
6
15
27
Total
55
44
28
2,144
71
5,149
8,484
4,768
3,868
5,405
1,768
2,433
1,324
1,293
291
411
840
235
2,284
3,962
1,307
1,004
454
1,696
2,011
3,498
2,044
796
684
268
223
16
124
211
59,157
00
en
oo
-------
TABLE B-5. AVERAGE SULFUR CONTENT BY COAL-PRODUCING
REGIONS (1973)
Region
1
2
3 & 6
4
5
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
States Where Used
E. Perm. , Md
W. Perm.
W. Virginia
Ohio
Michigan
W. Virginia
W. Va., E. Ky. , Tenn.
W. Kentucky
Illinois
Indiana
Iowa
Ala. , Ga. , Tenn.
Ark., Okla.
Ky., Tenn., Mo., Okla.
Colorado
Colorado, N. Mex.
N. Mex. , Arizona
Wyoming
Utah
N . Dak . , S . Dak .
Montana
Wash., Oregon
Sulfur
ng/J (Ib/MBtu)
632 (1.47)
632 (1.47)
378 (0.88)
1127 (2.62)
—
378 (0.88)
456 (1.06)
1036 (2.41)
1277 (2.97)
942 (2.19)
—
542 (1.26)
585 (1.36)
903 (2.10)
340 (0.79)
301 (0.70)
211 (0.49)
254 (0.59)
241 (0.56)
645 (1.50)
396 (0.92)
344 (0.80)
% of Total Coal
ng/J (Ib/MBtu)
2261 (5.49)
2215 (5.15)
2133 (4.96)
4442 (10.33)
—
688 (1.60)
13,756 (31.99)
2971 (6.91)
5371 (12.49)
3152 (7.33)
—
1247 (2.90)
82 (0.19)
1514 (3.52)
65 (0.15)
250 (0.58)
99 (0.23)
744 (1.73)
718 (1.67)
206 (0.48)
245 (0.57)
662 (1.54)
369
-------
It is significant that the total emissions from this district (which
is most accessible to western coal sources) are 57% of the national total.
This is because of the high concentration of boilers in this region and the
high sulfur content of the coal burned in these regions.
B.4.2 Reduction in Sulfur by Using Western Coal
The sulfur emissions using western coal were estimated both nation-
wide arid for the midwestern-Great Lakes region for two different cases:
1. Western coal characteristics were weighted according
to present mine capacity. That is, increases in pro-
duction would be met by increases in all mines propor-
tional to their present capacity.
2. Western coal characteristics of individual states were
used.
Table B-6 summarizes the nationwide sulfur emissions and net savings
realized by using western coal for the boilers in the 1.3 to 32 kg/s range.
TABLE B-6. NATIONWIDE SULFUR EMISSIONS
USING WESTERN COAL
Total Sulfur
Coal Source Emitted*
Composite western
Arizona
Wyoming
Montana
7.
3.
6.
9.
7
8
08
53
Net
Decrease* 5
9.
13.
11.
7.
8
71
35
988
fe Decrease
56
78
65
46
*10 metric tons/yr as sulfur
Table B-7 summarizes the sulfur emissions and reduction possible
for the midwestern-Great Lakes region for the same conditions.
370
-------
TABLE B-7. MIDWESTERN-GREAT LAKES SULFUR EMISSIONS
USING WESTERN COAL
Coal Source
Composite western
Arizona
Wyoming
Montana
Total Sulfur
Emitted*
3.813
1.906
2.996
4.721
Net
Decrease*
6.264
8.17
6.99
5.356
Percent
Decrease
62
81
70
53
*10 metric tons/yr as sulfur
In both cases, sizable reductions are seen to be possible. The
midwestern-Great Lakes region has the potential for even larger reductions
than the nationwide average because of the higher sulfur fuels currently
being burned in this region.
These reductions are theoretical reductions and do not reflect any
problems that may occur while firing western coal. Potential problems such
as requipment derating or an increase in other emissions would adversely
impact these projections. On the positive side, an additional reduction may
be realized in SO stack emissions due to differing sulfur forms (organic,
pyritic, or sulfates) in western coals as compared to midwestern or eastern
coals. Also, the different nature of the western coal ash (high CaO, NaO,
and MgO) may act to effectively reduce SOx emissions.
371
-------
REFERENCES FOR APPENDIX B
B-l Locklin, D. W., et al., "Design Trends and Operating Problems in
Combustion Modification of Industrial Boilers," EPA 650/2-74-032,
April 1974.
B-2 Ehrenfeld, J. R.-, et al. , "Systematic Study of Air Pollution from
Intermediate Size Fossil-Fuel Combustion Equipment," Final Report,
Contract CPA 22-69-85, Walden Research Corporation, July 1971.
B-3 Neilson, G. J., ed., 1974 Keystone Coal Industry Manual, McGraw-
Hill, New York, 1974.
B-4 Ctvrtnicek, J. E., et al., "Evaluation of Low-Sulfur Western Coal
Characteristics, Utilization, and Combustion Experience,"
EPA 650/2-75-046, May 1975.
B-5 Bituminous Coal and Lignite Distribution - Calendar Year 1973,
Mineral Industries Surveys, U.S. Dept. of the Interior, Bureau
of Mines, Washington, D.C., April 12, 1974.
372
-------
APPENDIX C
DETAILED COMBUSTION REQUIREMENTS
FOR SPECIFIC BOILER FIRING TYPES
373
-------
C.1 INTRODUCTION
Coal firing of industrial boilers can be separated into two broad
classes—suspension firing and grate firing.
Suspension firing is normally applied in larger size units; however,
units as small as 4.4 kg/s (35,000 Ib/hr) steam have been built for pulverized
coal firing. Current economics would indicate a break-even point in the 25.2
to 32 kg/s (200,000 to 250,000 Ib/hr) steam flow range. Suspension firing
includes both pulverized coal firing in which the coal is crushed to less
than 6.4 mm (1/4 in.) size which produces about 10% through a 200-mesh
screen.
Grate firing comprises three general stoker types: underfed, over-
fed, and spreaders with a number of variations in feed methods and grate
designs. Stoker-fired units have been built covering the entire capacity
range of this study.
Considering the number of stoker manufacturers and the number of
boiler companies serving the industrial boiler market and the changes in
design philosophy which have taken place over the years since stokers were
first introduced around 1900, the present stoker-fired boiler population
represents a highly individualized array of equipment.
A similar situation exists regarding pulverized coal-fired boilers.
Since their commercial inception in 1920, many changes in furnace shape,
burner design, amount of furnace water cooling, method of ash removal, and
heat release rate have evolved, so that each unit is highly individualized
and tailored to the expected coal characteristics and plant requirements.
Generalization will be made in this study which can be directly
applied to certain units; undoubtedly other units can be found which will
not conform to these generalizations by reason of furnace design, firing
system characteristics or fuel preparation.
375
-------
The principal methods for firing coal in industrial boilers are
categorized in Table C-l, along with salient features which describe their
application. Fuel requirements are outlined in Table C-2.
C.2 UNDERFED STOKERS
C.2.1 Single Retort Stokers
Single retort stokers, as illustrated in Figure C-l, are the earliest
type of underfed stokers. Coal is fed to the bottom portion of the fuel bed
either in small increments by a power-driven ram or continuously by a screw
conveyor. Moisture and volatile matter are driven off in the lower part of
the fuel bed and the coal is coked in an oxidizing atmosphere. The hydro-
carbons burn in an air-rich atmosphere and pass upward through the hot incan-
descent fuel bed, thus lessening the tendency for smoke formation. The
coked coal is forced upward into the active fuel bed and spills over onto
side grates where combustion is completed. Dead-plates at the stoker sides
are provided for collecting ash and refuse.
While the earliest patents date from 1838, intensive development
of this stoker occurred between 1889 and 1906. Important improvements were
reciprocating retort bottom with auxiliary feed rams to distribute the coal
from front to rear; moving grate bars to break up coke formations and dis-
tribute coal laterally across the grate; hollow, air-cooled grate bars; and
side dumping grates for discharging ash. These features are incorporated
into the majority of single retort underfed stokers in service or on the
market today.
A number of distinctive designs are manufactured ranging from 0.93
2 2
to 11.7 m (10 to 126 ft ) of grate area. These stokers are generally con-
sidered applicable up to 4.4 kg/s (35,000 Ib/hr) steam.
Fuels ranging from lignite to anthracite are successfully burned;
however, single-retort underfed stokers are principally used for burning
eastern coking bituminous coals and those midwestern free-burning coals
with sufficiently high ash softening temperatures [1589 °K (2400 8F) or
greater] to avoid clinkering in the relatively thick fuel beds. The pre-
ferred sizing of bituminous coal is 2.54 cm to 3.81 cm (1 to 1-1/2 in.)
376
-------
TABLE C-l. COAL FIRING METHODS FOR INDUSTRIAL BOILERS
Firing Method
Grate Area Size
Range, m2 (ft2)
Grate, HWTnv'
(Btu/ft2-hr)
Furnace Construction
Max. Furnace Heat Release
MJ/m3 (Btu/ft3)
Boiler Capacity
Range, kg/s (Ib/hr)
Load
Response
1. Underfed Stoker
Single Retort
Stationary Grate
Reciprocating Grate
Reciprocating Grate
Multiple Retort
2. Overfed Stoker
Chain Grate
Traveling Grate
Vibrating Grate
3. Spreader Stoker
Stationary Grate
Dunping Grate
Traveling Grate
Vibrating Grate
Oscillating Grate
4. Pulverized Coal
5. Cyclone Furnace
0.9-4.5 (10-48)
1.4-4.6 (15-50)
3.3-11.6 (36-125)
3.3-47 (35-500)
4.6-65 (50-700)
4.6-65 (50-700)
1.4-23 (15-250)
2.6-8.4 (28-90)
2.6-15.8 (28-170)
9.3-44.6 (100-480)
4.6-13.9 (50-150)
27.9 (300)
0.79 (250,000)
1.10 (350,000)
1.34 (425,000)
1.89 (600,000)
1.58 (500,000)
1.58 (500,000)
1.26 (400,000)
1.42 (450,000)
1.42 (450,000)
2.36 (750,000)
1.89 (600,000)
1.89 (600,000)
Refractory
Refractory
Water Cooled
Partial to Full W.C.
Partial to Full B.C.
Partial to Full W.C.
Partial to Full W.C.
Refr to Partial W.C.
Refr to Partial W.C.
Partial to Full W.C.
Partial to Full W.C.
Water Cooled
Hater Cooled
1676 (45,000)
1676 (45,000)
2235 (60,000)
1304 (35,000)
1118 (30,000)
1118 (30,000)
1118 (30,000)
1118 (30,000)
1118 (30,000)
1118 (30,000)
1118 (30,000)
N/A
N/A
1.2-6.1 (2,000-10,000)
1.2-9.2 (2,000-15,000)
1.2-28 (10,000-45,000)
12-18-1 (20,000-300000
15-153 (25,000-250,000)
15-153 (25,000-250,000)
4-61 (6,000-100,000)
3-24 (5,000-40,000)
3-46 (5,000-75,000)
46-214 (75,000-350,000)
3-46 (5,000-75,000)
92 (150,000)
Fair
Good
21 (35,000) up
52 (85,000) up
Sxcellent
-------
TABLE C-2. FUEL REQUIREMENTS FOR VARIOUS FIRING METHODS.
•o
QJ
M-l
U
1
3
fl>
H
s
a
W
U
u
X
o
JJ
10
14
o
'O
fl
0)
b
0
w
Firing Type
Single Retort
Multiple Retort
Chain Grate
Traveling Grate
Vibrating Grate
Stationary Grate
Dunging Grate
Traveling Grate
Vibrating Grate
Pulverized Coal
Cyclone
Coal Type'9'
Coking and caking
Free burning
Free burning coal
Tends to drift(b'f)
All except caking
bituminous'^'
All except caking
bituminous '"
All types referred
L.91 cm (3/4") nut and
slack
L.91 cm (3/4") nut and
;lack
L.91 cm(3/4") nut and
Slack
L.91 cm (3/4") nut and
ilack - less fines
ireferred
L.91 cm (3/4") nut and
slack
:rushed to 95t thru
1-mesh screen
Aslu %
<10%
<10»
<6%
on dry
basis
<6»
on dry
basis
<6%
on dry
basis
___
6- 25%
AST
«K fF)
1589(2400)
-------
Single Retort Stoker for a
Cross-Drum Straight-Tube Boiler.
View with part
of the front and
fuel bed in phantom
to show interior
and fire on rear
part of grate
(Ref. C-l).
Cross-section showing
air distribution ,
system (Ref. C-l).
OVER -FIRE AIRPORTS
X * / -
RQCK6I* BAR "l7?WT ROCKER BAR
DUMP GRATES
DUMP GRATE
AUXILIARY -
AIR CHAMBER
AUXILIARY
AIR CHAMBER.
CHAMBER
DAMPER'
^DAMPER
Figure C-l. Single retort stoker.
379
-------
nut and slack with not more than 50% passing a 6.4 cm (1/4") round hole
screen and a top individual lump size not larger than 3.18 cm (1-1/4").
Easily friable coals can be used with larger lump size because of the degra-
dation occurring in transit and handling.
Single-retort underfed stokers do not require ignition or combustion
arches, so the furnace can be constructed with simple vertical walls either
2
refractory or water cooled. Combustion rate in terms of W/m (Btu per square
6 ? 2
foot per hour) of grate area range from 1.1x10 W/m (350,000 Btu/ft -hr) for
the smaller stokers with refractory furnaces up to 1.34x10 W/m (425,000
2
Btu/ft -hr), for the larger stokers in water-cooled furnaces. Heat liberation
53 3
rates up to 4.7x10 W/m (45,000 Btu/ft -hr) of furnace volume are acceptable
for refractory furnaces. Heat liberation rates up to 6.2x10 W/m (60,000
Btu/ft -hr) can be used with water-cooled furnaces.
C.2.2 Multiple Retort Stokers
Multiple retort stokers were developed shortly after 1900 to ful-
fill a need for larger stokers. This type, as illustrated in Figure C-2,
consists of a series of inclined retorts with tuyeres between for air admis-
sion. Each retort is equipped with a primary ram which feeds coal at the
head of the retort. Secondary pushers slowly move the coal to the rear and
upward over the tuyeres. An overfeed section is located at the rear to com-
plete combustion before the refuse reaches the discharge section which can
be one of three types: clinker-grinder, continuous discharge, or dump grate.
Application of rearwall and sidewall water cooling enabled success-
ful operation in capacities up to 38 kg/s (300,000 Ib/hr) steam. Furnaces
are generally sized to limit heat liberation rates to 3.6x10 W/m (35,000
Btu/ft -hr).
The multiple retort underfed stoker works best on crushed coal with
a maximum size of 5.1 cm (2 in.) with not more than 50% through a 6.4 cm
(1/4") round hole screen, a volatile content between 20% and 30%, ash con-
tent of 6% to 8%, and an ash softening temperature above 1589°K (2400 °F).
The ash should not contain more than 15% Fe 0 . The coal sizing should be
^ J
uniform across the width of the stoker hopper.
380
-------
Multiple-Retort Stoker Showing Details of Components (Ref. C-2)
Ash Discharge Arrangement Showing
Single-Dump Type of Construction
Ash Discharge Arrangement of Air-
Admitting Fire Bars, Protecting
Wall Blocks, Breaker Plates, and
Double-Roll Clinker Grinders
Figure C-2. Multiple retort stoker.
381
-------
Control of the stoker fuel bed has been difficult with non-agglomerating
(western) coals which do not form coke in the furnace. Partially ignited fuel
or raw coal drifts to the rear of the stoker and blowholes develop in the fuel
bed. Ignition is improved and drifting coal is redeposited at the front of
the stoker if a long rear arch is installed in the furnace as shown in Figure
03.
The installation of multiple retort stokers has declined since the
introduction of spreader stokers because of higher cost, higher maintenance,
and more difficult operation associated with multiple retort stokers.
C.3 OVERFED STOKERS
C.3.1 Chain or Traveling Grate Stokers
Chain or traveling grate stokers can be described as endless belts
in which the grate surface is the belt. Fuel is deposited on one end of the
grate which moves continuously toward the rear of the furnace. Ash and
refuse are discharged at the opposite end.
The grate surface of a chain grate stoker consists of a series of
cast-iron or steel links connected by bars to form an endless chain. In
the traveling grate or bar-and-key design, a series of cast-iron sections
or keys are mounted on carrier bars which are fastened to two or more drive
chains to form an endless conveyor. The links of the chain grate stoker
are assembled so that a scissoring action occurs when the chain goes over
the end drums. This action tends to break loose any ash or clinker adher-
ing to the grate surface or plugging the air spaces between links. There
is no such relative motion between adjacent keys on the traveling grate
design, hence badly clinkering ash coals are not well suited (see Figure
04).
Natural draft chain-grate stokers were developed in the latter half
of the 19th Century and offered commercially in 1896. Traveling grate
stokers were introduced commercially in 1893. Natural draft stokers have
a free air space through the grate of 18% to 22% and operate with a draft
loss through the fuel bed of 2.54 mm to 12.7 mm (0.1 to 0.5 in.) of water.
A coarse coal with few fines is preferred.
382
-------
Figure C-3.
Three-drum steam generating unit fired by a continuous-
discharge multiple-retort stoker with rear-arch furnace.
Capacity 24 kg/s (150,000 Ib/hr) steam.
383
-------
OJ
oo
id.
^
Grate-Bar Construction
for Traveling Grate
Stokers (Ref. C-l).
Steam Generating
Unit Equipped with Traveling-
Grate Stoker and Rear-Arch
Furnace .
Chain and Sprocket Drive
Chain Grate Stoker ^
(Ref. C-2).
DRIVE
LINK
SIDE SEAL
LINK
Figure C-4. Chain or traveling grate stoker.
-------
Forced draft stokers, introduced in the 1920's to meet the demand
for higher capacity and better performance, have generally made the natural
draft design obsolete. Forced draft stokers have a free air space through
the grate of 6% to 10% and consequently can burn finer coal. Normally,
draft loss through the fuel bed is 2.54 to 5.08 cm <1 to 2 in.). These
stokers are suitable for boiler sizes from 3 to 31 kg/s (25,000 to 250,000
Ib/hr) steam.
A wide variety of coals can be burned on chain and traveling grate
stokers. The notable exception is highly coking bituminous coal which tends
to mat and prevent air from passing through the fuel bed.
A great deal of experimentation has been done on furnace design to
provide satisfactory ignition and eliminate stratification resulting in
unburned gases or carbon carry-over. Initially front, rear, or combinations
of front and rear arches were relied on to promote ignition and mixing. More
recently, high-velocity air jets have replaced front arches to provide tur-
bulence for completing combustion of distilled volatile matter (see Figure
C-5). Long rear arches are still considered effective in promoting burnout
and transporting incandescent particles to the front of the stoker.
Maximum continuous burning rates for bituminous coals range from
62 2
1.34 to 15.8x10 W/m (425,000 to 500,000 Btu/ft 'hr). The lower burning
rate applies to high moisture (>20%) , high ash (>20%) coals. Coals with
less than 8% ash on a dry basis do not provide enough ash residue to pro-
tect the grates and are considered unsuitable for chain or traveling grate
stokers.
C.3.2 Vibrating Grate Stokers^
Vibrating grate stokers are a more recent development in which coal
from the hopper is fed onto an inclined grate and moved over the grate by
intermittent vibrations as illustrated in Figure C-6. The grate surface is
mounted on a grid of water tubes tied into the boiler circulation and the
entire grate structure is supported by flexing plates which allow the grate
to be vibrated as a unit. These units are available up to a boiler capacity
385
-------
CO
CO
Steam Generating Unit with Overfire Air
and Combination-Arch Furnace. Capacity
10 kg/s (80,000 Ib/hr) steam.
An Early Front-Arch Type of Furnace for
Free-Burning Bituminous Coals.
An Open-Type Furnace for Bituminous Coals.
Figure C-5. Chain or traveling grate stoker with high-velocity air jets.
-------
Grate cooling
tubes
Adjustable
os/i
Figure C-6. Vibrating-grate-type stoker combines water-
cooling protection of the grate with inter-
mittent grate vibration.
of 12.6 kg/s (100,000 Ib/hr) and can be operated up to 1.3x10 W/m (400,000
2
Btu/ft -hr) of grate surface per hour. Heat liberation rate is usually limited
to 3.1x10 W/m (30,000 Btu/ft *hr) of furnace volume per hour. Overfire air jets
are used to provide turbulence for burnout of volatile matter. The vibra-
grate stoker will operate successfully with caking coals but an excessive
amount of fines will create problems with fine coal or ash sifting through
the grate.
C.3.3 Spreader Stokers
The modern spreader stoker, illustrated in Figure C-7, consists of
one or more feeder units mounted on the boiler front, each comprising a coal
hopper, a feeder that regulates the flow of coal, and a distributor rotor
that throws the coal into the furnace and distributes it on the grate. The
stoker grates may be of the stationary, dumping, or continuous discharge
type.
The stationary grate is the simplest and least expensive form and
is suitable up to about 5 kg/s (40,000 Ib/hr) steam. Ash removal is manual
through grate-level doors at the front of the stoker. Dumping grates are used
up to 9 kg/s (75,000 Ib/hr) steam. Grates are sectionalized so that one
portion of the fuel bed may be cleaned at a time. Coal feed to the section
387
-------
Dumping-Grate Spreader-Stoker-Fired
Unit Having a Capacity of 5 kg/s
(39,000 Ib/hr) steam.
A
Views of Dumping-Grate Spreader
Stoker showing arrangement of
feeder units. Grates are shown
in both the operating and dumping
positions (Ref. C-l).
HOPPER BASE
SHUT-OFF PLATE
(EMERGENCY H
USE ONLY) \
FILLER FOR
SHUT-OFF PLATE
OPENING
CUT-OFF GATE
SCRAPER BLADE
FRONT ACCESS
DOOR
TOP CROSS
CHANNEL-
REFRACTORY
ARCH
SCRAPER FEEDER
DRUM
SIFTINGS SCRAPER-
VARIABLE SPEED
DRIVE
OIL LEVEL GAGE
COOLING AIR
INLET
SEAL PLATE
REAR CROSS TIE
(WATER COOLED)
DISTRIBUTOR
WATER COOLED
BOX
COOLING WATER-
Feeder for Spreader Stoker
Figure C-7. Spreader stokers.
388
-------
is stopped during the cleaning operation. For units from 9.9 to 38 kg/s
(75,000 to 300,000 Ib/hr) steam, a traveling grate is used for continuous
ash discharge. The usual direction of travel is from rear to front as illus-
trated in Figure C-8, although travel in the opposite direction can also be
used. Vibrating or oscillating grates have also been used with the spreader
stokers.
The spreader stoker can burn a wider range of fuels than any other
stoker type. This method of firing was developed primarily to burn the
lower grades of coal with high ash content and low ash fusion temperature.
Caking qualities of coals have little effect on performance.
As with other stoker types, mechanical spreader firing dates from
the 1800's. However, the spreader stoker did not become widely accepted
until the 1930's following the introduction of more efficient feeding and
distributing mechanisms and high-resistance forced-draft grate surfaces.
The spreader stoker now ranks high in industrial applications burning solid
fuels with respect to efficiency, operational flexibility, maintenance,
capacity, and ability to burn a wide range of fuels.
When used with stationary or dumping grates, heat release rates are
62 2
limited to 1.4x10 W/m (450,000 Btu/ft -hr) of grate. With continuous dis-
62 ?
charge grates, heat release rates up to 2.4x10 W/m (750,000 Btu/ft -hr) are
possible. The furnace heat release rate is generally limited to 3.1x10 W/m
(30,000 Btu/ft3-hr) of furnace volume because of the greater amount of
suspension firing. Vertical furnace walls are preferred with overfire air jets
providing turbulence for mixing and combustible burnout.
The fuel should be sized to pass a 1.91 cm (3/4") screen with consid-
erable range in particle size to produce a uniform fuel bed. If the particles
are all of one size, much of the fuel will fall on one portion, of the grate.
Larger lumps tend to increase ashpit losses. When the coal is too coarse
with a large proportion above 0.54 cm (1/4"), the fuel bed may not burn down
evenly and clinkers may tend to form in the areas containing the larger
sizes.
389
-------
Figure C-8. Steam generating unit equipped with continuous-
discharge type of spreader stoker. Capacity
19 kg/s (150,000 Ib/hr) steam.
390
-------
C.3.4 Pulverized Coal Firing
The application of pulverized coal firing to steam-generating units
began around 1920. There has been a progressive increase in its use for
power and process steam generation in preference to stoker firing. Much
larger units are possible than with stoker firing, labor costs are lower,
and operating flexibility is greater.
Although it would be technically possible to design small units
for pulverized coal firing, stoker units are presently considered more
economical below 25 kg/s (200,000 Ib/hr) steam.
Pulverizer capacity is one of the most important considerations in
designing a pulverized-coal-fired unit. Four functions are normally pro-
vided by the pulverizer system: pulverizing, drying, classifying to required
fineness, and transporting the coal to the burners in an air stream. The
system capacity is dependent upon coal properties such as moisture content,
grindability, and burning characteristics. If sufficient heat is not avail-
able in the preheated air to evaporate the surface moisture in the fuel, the
drying operation will limit mill output rather than the grinding capacity.
High volatile coals ignite more readily than low volatile coals and conse-
quently need less fine pulverization. Typically, with high volatile coals,
70% through 200-mesh screen is considered adequate. The percentage greater
than 50-mesh should be limited to 2% to reduce slagging tendencies and car-
bon loss.
Three general types of pulverizers are available:
1. Low speed, ball or tube mills which tumble coal and
2.54 cm (1") to 5.08 cm (2") steel balls in a rotating
cylinder.
2. Medium speed, roll-and-race or ball-and-race.
3. High speed, attrition or impact mills.
Generally, the pulverizers supply coal directly to the burners and
load variations are accommodated by changing pulverizer load. An alternate
system is the bin or storage system, in which the pulverized coal is stored
391
-------
before firing. The bin system allows less pulverizer capacity but requires
pulverized storage capacity, additional feeders and venting systems, and a
complex fire protection system. The direct-fired system is normally used
today.
Burners are of three general types:
1. Turbulent - located in one furnace wall or opposed
furnace walls.
2. Vertical - located in roof, firing down.
3. Tangential - located in furnace corners firing toward
furnace center.
The furnace may be designed for dry ash removal with a hopper or water-screen
bottom or for molten ash removal as in a slag tap furnace.
The furnace size requirement is dependent on the burning and ash
characteristics of the coal as well as the firing system and type of furnace
bottom. The general objectives are to provide control over ash deposition
in the furnace and provide sufficient cooling so that ash entrained in the
gases leaving the furnace is below the softening temperature before enter-
ing closely spaced convection sections.
C.3.5 Cyclone Firing
The cyclone furnace (Figure C-9) is a water-cooled horizontal cyl-
inder in which fuel is fired, heat is released as extremely high rates,
and combustion is completed. Its water-cooled surfaces are studded and
covered with refractory chrome ore. Coal crushed in a simple crusher, so
that approximately 95% will pass a 4-mesh screen, is introduced into the
burner end of the cyclone. About 15% of the combustion air also tangen-
tially enters the burner and imparts a whirling motion to the incoming coal.
Secondary air with a velocity of approximately 91 m/sec (300 fps) is admitted
in the same direction tangentially at the roof of the main barrel of the cyclone
and imparts a further whirling or centrifugal action to the coal particles. The
combustibles are burned from the fuel at volumetric heat release rates
of 4.7x10 to 8.8x10 W/m (450,000 to 800,000 Btu/ft3-hr), and gas tempera-
tures exceeding 1922 °K (3000 °F) are developed. These temperatures are
392
-------
CRUSHED
COAL
*
HIGH-SPEED
SECONDARY AIR
HOT GASES
MOLTEN
SLAG
Figure C-9. Molten slag tap, water-cooled cyclone furnace (Ref. C-2)
sufficiently high to melt the ash into a liquid slag, which forms a layer
on the walls of the cyclone. The incoming coal particles (except for a few
fines which are burned in suspension) are thrown to the walls by centrifugal
force, held in the slag, and scrubbed by the high-velocity tangential secon-
dary air. Thus the air required to burn the coal is quickly supplied, and
the products of combustion are rapidly removed.
The cyclone furnace is suitable for coal ash slag having a visco-
sity of 250 poises or less at 1700 °K (2600 °F) . The volatile matter should
exceed 15% on a dry basis to obtain the required high combustion rate. For
coals of very high moisture content it may be necessary to limit the coal
ash-softening temperature and slag viscosity to a lower value. An increase
in combustion air temperature above a normal value of 589 °K (600 °F) will
compensate to some extent for higher moisture content. Coals with too high
sulfur content and/or a high iron ratio are not considered suitable.
393
-------
Cyclone furnaces have been built commercially in sizes ranging from
1.52 to 3.05 m (5 to 10 ft) diameters with a corresponding allowable maximum
heat input per cyclone furnace of 29.3 to 124.5 MW (100 to 425 MBtu/hr)
respectively. A single cyclone furnace could therefore be applied to a mini-
mum size industrial boiler generating 10.7 kg/s (85,000 Ib/hr) steam. The
load range is from full to approximately half load. Therefore a single
cyclone furnace would be limited in turndown capacity.
REFERENCES FOR APPENDIX C
C-l de Lorenzi, Otto (Ed.), Combustion Engineering, published by
Combustion Engineering, Inc., 1955.
C-2 Babcock s Wilcox Company, Steam, Its Generation and Use, 1960.
394
-------
APPENDIX D
CANDIDATE WESTERN COAL DEFINITION
395
-------
D.I INTRODUCTION
Wyoming and Montana are the two largest western coal producing
states. The geography of the western coal deposits dictates that these
two states will be the most successful in supplying midwestern and eastern
coal consumers at competitive prices to eastern coal. Therefore, the coal
resources of these two states will be the focus of this appendix.
D.2 WYOMING
Wyoming has 495 billion metric tons of coal between 0 and 1,829 m
(6,000 ft) of cover. This is 17% of the national total and ranks Wyoming
first among the states in total coal resources. Of this resource, only
25%, or 124 billion metric tons, has been mapped and explored within 914 m
(3,000 ft) of the land surface. Of that amount, approximately 2% is lig-
nitic, 10% is bituminous, and 88% is subbituminous. One-half, or 62 billion
metric tons, of the mapped resources is considered recoverable. Seventeen
percent, or 22 billion metric tons, of the explored resources are classified
as strippable. This strippable resource is greater than that of any other
state and represents nearly 20% of the nation's known strippable coals. Of
those 22 billion metric tons, 17 billion are termed recoverable and 13
billion of that are classed as reserves by today's standards. While almost
90% of Wyoming's strippable coals underlie the Powder River basin, the Hams
Fork and Green River regions each contain over 4%. The remaining 1% to 2%
of the resources lie in the Hanna field and Bighorn basin areas. A map show-
ing active Wyoming coal mines is shown in Figure D-l.
The rank of Wyoming coal ranges from lignitic to high-volatile "A"
bituminous. Lignite occupies a very small region in the northeastern part
of the Powder River basin. Bituminous coal is restricted to the Black Hills
region and portions of the Hanna field, Green River region, and Bighorn
basin. High-volatile "B" and "A" bituminous coal is reported only in the
Hams Fork region. Subbituminous coals are found in all major coal regions
397
-------
°0
6>
<.s Million^ .5-2.0 M ^ >2.0 M
A •
Mine Size (Tonnage)
Open Symbols - Underground Mine
Closed Symbols - Surface Mine
Figure D-l. Active Wyoming coal mines.
398
-------
except the Black Hills region, and account for most of the state's resources
and current production.
Typical Wyoming coal analyses exhibit the following ranges and averages;
Seam Reserve
As Received Range Average
Moisture, % 1.7 - 32.8 14.2
Volatile Matter, % 32.0-46.0 39.0
Fixed Carbon, % — 41.0
Ash, % 1.4 _ 17.5 5.2
Sulfur, % 0.2 - 5.0 0.7
Heating Value, MJ/kg 17.5-31.4 25.2
(Btu/lb) (7,500 - 13,500) (10,850)
In terms of quality, coals with the lowest heating values, as well as
the highest moisture and volatile contents, are found in the Powder River
basin. The higher heating values are more prevalent in the western and south-
ern portions of the state. Ash varies widely, with small isolated pockets of
high-ash content (15% to 18%, dry basis) coals in the Powder River basin, Big-
horn basin, and Hams Fork region. Sulfur contents are relatively low and
variable. The southern and eastern parts of the Green River region contain
some of the highest sulfur values. Overall, more than 99% of Wyoming's coal
contains less than 1% sulfur and about one-half of that is less than 0.7% (as-
received basis). Ninety-six percent of the strippable coals contain less than
1% sulfur, 3.5% is between 1% and 2%, and 0.5% is greater than 2% sulfur (as
received).
There are 25 coal seams currently being mined in Wyoming. Surface-
mined seams are between 1.83 and 36 m (6 and 118 ft) thick, but average 9.75 m
(32 ft*. Seams mined underground range from 1.13 to 6.1 m (3.7 to 20 ft) , av-
eraging 2.6 m (8.5 ft). The thickest surface-mined seams occur in the Hams
Fork region and Powder River basin. The latter basin also contains the na-
tion's, and perhaps the world's, thickest seam of 67 m (220 ft) .
399
-------
Table D-l contains a listing of the active mines in Wyoming and
Montana. Also shown are the estimated reserves, estimated useful life, and
current 1973 and 1974 production of the mines.
The coal analyses of the 14 largest mines in Wyoming and Montana are
presented in Table D-2.
TABLE D-l. COAL CANDIDATES FOR TESTING (ACTIVE MINES)
Company
MONTANA :
Westmoreland
Decker
Peabody
Western Energy
WYOMING:
Amax
Wyodak
Arch Mineral
Rosebud
Kemmerer
Bighorn
Energy Development
Pacific Pwr & Light
Mine Reserves
Sarpy Creek 1500 MT
Decker No. 1 2240 MT
Big Sky
Colstrip 1440 MT
Belle Ayr 1 18/50QMT
Wyodak j
Seminoe 1 1
Seminoe 2 V 3Q5 MT
Rosebud J
Ek01 1 1679. 9MT
Sorenson I
Bighorn
Dave Johnston
Jim Bridger
Life
(yrs)
100
30
50
50
15
100
60
15
35
35
Current Production
(Mill. Metric Tons/
Year)
1973
4-00
4.15
1.97
4.25
0.89
0.75
2.87
1.50
1.51
0.40
2.55
0.45
2.90
1974
—
6.79
2.23
3.21
3. 30
--
3.14
2.59
1.96
2.44
—
2.7
Sulfur content of the Wyoming coal produced by these mines is all
well below 1% and the heating value is generally around 23.3 MJ/kg (10,000
Btu/lb). The ash softening temperature (reducing atmosphere) of these coals
400
-------
TABLE D-2. COAL ANALYSES OF THE FOURTEEN LARGEST MINES IN WYOMING AND MONTANA
MINE
WYOMING
Belle Ayr
Wyodak
Seminoe 1
Seninoe 2
Rosebud
Sorenson & Ekol
Bighorn
Energy Development
Dave Johnston
Jin Br i fJTsr
MONTANA
Sarpy Creek
Big Sky
Decker No. 1
Colstrip
SEAM
Smith -Roland
Smith-Roland
Bed No. 25
Hanna No. 2
No. 80 & 82 Bed
Adaville
Armstrong & Monarch
Bed 65
School
Rosebud-McKay
Robinson
Rosebud-McKay
Dietr
Rosebud
—
0)
3
.p
Ifl
•H
28.86
28.13
UQft
• 7O
11.5
14.20
20.2
23.85
11.6
13.66
24.12
20. 52
2.
26.5
23.
25.5
y
m
rH
•H
Q
H
§
29.86
31.63
42.6
35.03
42.3
32.35
39.89
29 09
29.
29.11
34.
27.72
C
o
a
n*
U
•8
X
fc,
30.47
34.32
39.3
42.56
53.4
38.49
17.75
40 71
37.
34.5
39.3
38.33
^^
v
i
5.18
5.90
6Qfl
• yo
6.6
8.]1
4.3
5.30
7.1
6 5
18.24
9 68
9.
9.89
3.7
8.45
dp
»w
(A
0.29
0.52
017
• J /
0.4
1.0
0.9
0.61
0.7
0 45
0.33
aA~)
, *t I
0.73
1.31
0.4
0.8
5
X -rt
zl
m -H
— V
o
C7> 4J
J* «
X.
18.2
(7,821)
19.4
(8,332)
23 2
(10,000)
25.3
(10,890)
23.9
(10,300)
23.4
(10,080)
21.6
(9,300)
25.6
(11,020)
25 1
(10,806)
16.4
(7,070)
21 3
(9,150)
19.6
(8,450)
19.4
(8,360)
22.3
(9,600)
20.3
(8,750)
H
N^
3
m
S &
g
26.2
(11,237
26.7
(11,470)
28.4
(12,200)
28.6
(12,620)
(2,140)
,
21.7
(9,317)
30.6
(13,134)
28.7
(12,320)
fa
D* o
C
•H fl)
s 3
V 4->
IA V
£ S
U] V
1,410
(2,078)
1,522
(2,280)
1,483
(2,210)
1,594
(2,410)
1,444
1,456
(2,161)
1,490
(2,222)
1,505
(2,250)
1,505
(2,250)
C
-H
»H
U
f
01
k.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
0.5
N.A.
N.A.
N.A.
N.A.
S1
•H
0) H
> -H
0 fl
M fl)
ty «o x
•oca
M -H «0
a H e
x o H
53.28
54.0
58.0
58.0
45.6
48.3
56.
51.6
52.
* MAF = Mineral matter and ash free;
N.A. = Non-agglomerating coals
-------
varies somewhat from seam to seam but is generally around 1500 °K (2150 °F).
Grindability of the coals as measured by the Hardgrove Index indicates that
they are slightly harder to grind than comparable eastern coals. The Hard-
grove Index ranges from 0 to 100 with 100 representing good grindability.
Therefore the lower the Hardgrove Index number, the more difficult the coal
is to grind. This poorer grindability will have an effect on the performance
of coal pulverizing mills in pulverized-coal-fired units. The Hardgrove In-
dex, however, does not give a true representative indication of the western
coals grindability as received,since the coal must be air dried prior to per-
forming the test. The higher moisture content of western coals requires
higher air temperature in the pulverizer to improve grinding performance.
Montana
Figure D-2 depicts the geographical areas of Montana coal fields.
The Fort Union region of eastern Montana is presently the focus of major
development. The interest in this area is expected to continue for the fore-
seeable future. Estimates place the strippable coal in this region at more
than 38 billion metric tons. Table D-3 gives the name of the field, the
coal bed, thickness, estimated reserves, average tons/acre, ash, sulfur, and
Btu. Although coal is present in other parts of the state, it is of less sig-
nificance because recovery would require deep mine methods.
Characteristics of the topography and the thickness of the Fort Union
coal beds make possible the mining of large quantities of coal from rela-
tively small, compact areas, which facilitate reclamation. Coal beds
7.6 - 18 m (25 to 60 ft) thick are not uncommon, and in the Decker area, the
coal in a single bed reaches a thickness of 24 m (80 ft). Matson and Blumer
(Ref. D-l) have surveyed southeastern Montana and analyzed 32 coal deposits;
proximate analyses, forms of sulfur, calorific values, and major ash consti-
tuents of the coal samples are included.
Currently, only five companies are producing coal from the Fort Union
beds of eastern Montana. They are:
402
-------
Bitumi- Subbitu- Lignite
nous Coal minous Coal
Figure D-2 . Index map of Montana coal fields.
403
-------
TABLE D-3. STRIPPABLE SUBBITUMINOUS AND
LIGNITE COAL FIELDS, EASTERN MONTANA
No.
Of
Hap
1
2
3
4
5
6
7
e
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Name of Field
Decker
Hanging Woman
Creek
Moorhead
Poker Jim Lookout
Roland
Squirrel Creek
Upper Rosebud
Birney
Canyon Creek
Poker Jim-O'Dell
Creek
Otter Creek
Ashland
Cook Creek
Beaver Creek
Liscom Creek
Greenleaf-Miller
Creek
Sweeny-Snyder
Colstrip
Carpenter Creek
Fire Creek
Upper Cache Creek
Lower Cache Creek
Sonnette
Pumpkin Creek
Broadus
Sand Creek
Foster Creek
Pine Hills
Lame Jones
Lames teer
Hilbaux
Little Beaver
Four Buttes
Hodges
Griffith Creek
Smith- Dry Creek
O' Brian-Alkali
Creek
Breezy Flat
Burns Creek
N.F. Thirteen
Mile Crk.
Fox Lake
Lane
Carroll
Redwater River
We Idon- Timber
Creek
Fort Kipp
Lanark
Medicine Lake
Reserve
Coal Ridge
Sarpy Creek
East Moorhead
Knowlton
Cheyenne
Meadows
Charter
Thick-
ness in
Coal Bed Meters
Anderson- Dei tz
Anderson-Dei tz
Anderson-Canyon
Anderson-Deitz
Roland
Roland
Anderson
Brews ter- Arnold
Wall
Knoblock
Knoblock
Knoblock
Sawyer
Knoblock
Knoblock
Knoblock
Terret
Rosebud
Carpenter
Pawnee
Pawnee
Broadus
Pawnee
Sawyer
Broadus
Knoblock
Knoblock
Domlny
Dominy
Harmon (?)
c
c
c
G
Pust
Pust
Pust
Pust
Lane
Carroll
S
S
Ft.Kipp-Ft.Peck
Lanark
Coal Ridge
Rosebud-McKay
Cache
Dominy
Knoblock
Mammoth
6-27
3-11
2-9
4-18
3
3
6
5
9-18
3-12
6-20
6-30
2-4
3-7
2
3-6
5
6
1-2
5-7
6
4
6
9
1-8
5-11
2-5
5
2-3
2-3
2-12
2-5
2-6
2-3
2-4
2-4
2-4
4-6
2-13
2-5
2
2
3-6
2-6
2-3
3
3
3
3
3-10
3-10
3-11
11-22
2-6
Estimated*
Reserves
in M of
Metric Tons
1,947 F
3,099 G
1,089 G
573 G
315 F
130 F
220 F
321 G
200 F
770 G
1,041 G
2,595 G
53 F
160 F
75 F
260 F
312 G
1,440 G
50 F
40 G
40 G
10 G
206 G
1.900 G
737 G
278 G
1,200 G
280 G
150 R
35 R
643 G
134 R
91 G
10 R
10 R
150 R
150 R
200 F
200 R
225 F
46 F
561 R
345 R
642 G
724 G
331 G
100 G
58 F
246 F
1 ISO-*
1,500 F
541 G
798 G
1,200 G
60 G
Average
Tons/Acre
76,435
38,625
40,005
67,825
17,700
17,800
35,400
26,470
70,800
47,825
51,290
95,000
17,700
30,030
14,160
32,655
29,650
43,835
14,015
31,870
35,400
21,275
35,400
45,315
38,985
46,660
20,690
30,950
14,160
17,700
34,720
15,865
17,570
12,390
17,800
17,700
17,700
30,090
30,090
44,250
21,240
12,390
11,584
26,550
28,320
22,830
12,390
15,510
13,495
17,700
35,400
33,850
52,030
88 , 500
17,700
t
Ash
4.0
6.4
5.3
5.7
5.6
5.6
4.4
5.9
4.6
4.9
4.7
4.8
5.1
7.0
8.7
7.8
5.8
8.4
6.0
6.0
7.2
6.6
7.9
7.2
6.7
7.7
7.2
7.9
6.7
5.5
6. 1
4. 6
6. 3
7.2
7.6
7. 5
6. 5
7.2
4. 1
^
t
Sulfur
0.4
0.3
0.3
0.4
0.3
0. 3
0.4
4.4
0.3
0.3
0.4
0.2
0.7
0.5
0.6
0.8
0.7
0. 7
0.4
0.4
0.3
0.7
0.5
0.3
0.3
0.5
0.5
0.9
0.5
0. 3
0. 4
0.2
0.4
1. 0
0.4
0-4
Oc
. 3
0.5
OA
t 4
0 « 4
MJ/kg
22.4
19.6
19.3
18.1
17.7
17.7
19.5
20.6
21.1
20.6
19.7
21.8
18.4
18.9
18.4
19.5
19.0
20.2
17.3
17.8
17.3
17.0
17.3
17.3
17.1
17.7
16.9
14.0
14.7
14.1
14,3
15.1
16.0
16.0
16.6
17.2
17.2
17.8
14.2
15.9
16.0
15.3
13.5
20.0
16.6
15.5
19.5
* "As received basis (where more than one sample available. Figures
are averages) Source Montana Bureau of Mines and Geology.
t(G, good; F, fair; R, rough)
404
-------
Knife River Coal Co. has an average annual production of slightly
over 300,000 metric tons of lignite coal with a heat content of 15.2 MJ/kg
(6,520 Btu/lb) and a sulfur content of 0.5%. This mine is dedicated to the
Montana-Dakota Utilities Co. power plant at Sidney, MT.
Western Energy Co. is a wholly-owned subsidiary of Montana Power Co.
with operations at Colstrip. Coal analyses are given in Table D-2.
Decker Coal Co.' is a joint venture between Pacific Power and Light
and Peter Kiewit Sons' Co.; the latter being the operating partner. Table
D-2 gives coal analyses for this company.
Peabody Coal Co. is currently mining over 1.5 million metric tons
annually from the Rosebud and McKay beds near Colstrip, MT. Unit trains haul
coal 800 miles to Cohassett, MN for Minnesota Power and Light.
Westmoreland Resources is a Montana-based partnership owned by
Kewanee Oil Co., Penn Virginia Corp., Morrison-Knudsen Co., Inc., and West-
moreland Coal Co. Westmoreland's operations are located at Sarpy Creek, MT.
Westmoreland ships coal to five midwest utilities:
Northern States Power Co., Minneapolis, MN
Wisconsin Power and Light, Madison, WI
Dairyland Power Cooperative, LaCrosse, WI
Interstate Power Company, Dubuque, IA
Central Illinois Light Company, Peoria, IL
The coal analyses of the four producing mines in Montana from Table
D-2 show somewhat higher sulfur content (0.8% average), and lower heat
value (19.8 MJ/kg average) than Wyoming coals. It is this combination that
could make Montana coals of marginal value for reducing sulfur below the 520
ng/J (1.2 Ib SO /MBtu) regulation. Ash softening temperaures and Hardgrove
grindability are comparable to Wyoming coals.
Coal analyses for the 14 largest mines in Montana and Wyoming are
presented in Table D-2. They are representative of approximately 95% of
the projected coal production capacity from these two western states through
1983. The use of any one of these coals in the test program would be valid
based on the ability of that mine to produce coal at better than present
production levels through 1983. However, all mines listed in the table have
405
-------
expansion plans. Most mines project a doubling of present production by
1980 and some, such as Westmoreland Resources, expect to increase production
by a factor of five by 1982.
REFERENCES FOR APPENDIX D
D-l Matson, R. E. and Blumer, J. W., "Quality and Reserves of Strippable
Coal, Selected Deposits, Southeastern Montana," Montana Bureau of
Mines and Geology Bulletin 91, December 1973.
406
-------
APPENDIX E
EXAMINATION OF SUPPLY VARIABLES
OF SPECIFIC WESTERN COALS
407
-------
E. 1 INTRODUCTION
Availability, mining and transportation costs determine the price
that must be ultimately paid by a user of western coal. Coals with desirable
properties such as relative high heating value and low sulfur content demand
a higher price as do coals in limited supply. Prices at the mine are also
subject to several factors including type of mining operation, storage and
handling facilities and the extent to which the coal is processed. Variables
affecting transportation cost are size and frequency of shipment and location
of user with respect to existing transport facilities.
The data presenting the current production from the mines in Montana
and Wyoming are presented in Table D-l (Appendix D) , along with projec-
tions of future expansion.
Table E-l gives the average value per ton of bituminous and lignite
coals at the mine for 1971 and 1972. Note that strip mining costs per ton
had risen from $1.79 to $2.01 in Montana and from $3.35 to $3.69 in Wyoming
or approximately 10%. Projected cost to maintain and expand future production
are considered confidential by the mine operators and therefore were not
made available for this study. Additional increases beyond the 10% annual rate
were expected for 1973, 1974 and beyond due to inflationary pressures.
Transportation costs have the greatest influence on western coal
prices to potential users in the midwest due to the long distances involved.
The only feasible means of transporting western coal to users and to distri-
bution centers in the midwest is by rail. No other alternative exists. Once
the coal reaches the Great Lakes or Mississippi River, water transportation
systems become available. Early transfer to waterway shipment is preferred
over all-rail transport since the cost is lower.
409
-------
TABLE E-l. AVERAGE VALUE PER TON, P.O.B.
OF BITUMINOUS AND LIGNITE PRODUCED, BY DISTRICT
1.
2.
3.
4.
6.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
1".
1«.
19.
20.
21.
22.
23.
District
Ohio
Panhandle ....
lo»-a
New Mexico
Utah
Norlh-South Dakota
ToUl
1971
Under-
ground
J10
9
7.
6.
6.
13.
9
5.
5.
6.
'4.
11.
13,
5.
a.
6
7
9
13
.... 8
.08
.53
.73
75
60
82
32
46
96
Gl
.R2
30
.99
.25
.18
.25
.37
.33
.55
.87
Strip
$6.49
6.09
6.12
4.75
4.56
10.22
6.31
4.50
4.95
5.05
4.54
5.K3
9.13
5.16
3.91
2.62
3.35
8.00
1.91
1.79
7.16
5.19
AuEcr
J6.26
6.61
5.53
4.35
10.02
6.67
5.25
6.05
8.50
2.20
6.57
Total
J8.12
S.78
7.36
5.24
C.55
13.21
8. IK
4.83
5.46
5.18
4.66
7.97
10.53
5.16
5.25
6.71
2.62
3.39
7.37
1.91
1.82
7.27
7.07
Under-
ground
S9.60
10.79
8.55
7.41
7.51
14.87
10.19
5.97
6.83
6.62
4.80
13.40
14.79
5.17
9.46
4.89
8.93
9.74
1C. 40
9.70
1972
Strip
*6.
6.
6.
5.
6.
11.
6.
4.
5.
5.
4.
6.
ft.
4.
4.
2.
3.
8.
2.
2.
6.
5.
52
38
84
29
SO
40
41
81
49
51
91
98
37
86
ii
68
69
00
02
01
99
48
Auger
$6.66
5.34
6.36
4.69
6.50
11.88
6.47
5.64
6.18
6.54
ToUl
JK.25
9.93
8.16
6.96
7.49
14.45
8.86
5.23
6.14
5.58
4.R6
9.43
9.04
4.86
5.17
7.25
2. 68
3.74
8.93
2.02
2.03
7.07
7.66
410
-------
E.2 RAIL TRANSPORTATION
Existing rail lines of three major carriers service the Montana-
Wyoming coal fields. The Burlington Northern (BN) has extensive rail connections
in both states that transport coal from the Powder River basin along main line
connections to several key distribution points. Existing mining operations
along the main line of the Union Pacific (UP) through southern Wyoming ship coal
to Omaha and Kansas City. Tracks of the Chicago and Northwestern Railroad (C&NW)
extend into the Powder River basin in eastern Wyoming with existing facilities
that generally split the BN and UP systems to the Great Lakes. Several joint
ventures between the UP and C&NW are under way to deliver southern Wyoming
coal to the Minnesota, Wisconsin, and Chicago areas.
Figure E-l presents a geographical distribution of the various types
of coals employed in the operations of the firms questioned during this study.
Western coal is available at reasonable shipping costs to users along major
rail connections to the west. The coal is also transferred from existing rail
to river barges for distribution along the Mississippi River and from rail to
lake barge in Duluth to allow transport to other Great Lakes ports.
No additional main line connections are planned for western coal
shipments; however, some trace extensions and improvements have been deemed
necessary. A 187 km (116-mile) trace connecting the main lines of the BN
and the C&NW has been proposed jointly by the two railroads to open up the
central Powder River basin. Also planned for the C&NW is a complete
upgrading of the main lines from Shawnee, Wyoming, to Freemont, Nebraska.
Extensive additions and improvements to the coal-handling equipment have also
been undertaken.
E.3 UNIT TRAIN OPERATION
Currently the most economical means of transporting western coal to
midwestern markets is by unit train. A unit train is a set of locomotives and
411
-------
Western Coal Experience
O Tested
^ Blended with other coals
A Used 100%
O
/-w* Minnesota
Iowa
Wisconsin
Illinois
Other Coals Used
100% Midwestern
(Iowa,Okla.,Kan.)
^ 100% Lignite
Q 100% Eastern (111.,
KY, Ohio)
Figure E-l. Coal users contacted during survey.
412
-------
cars that operate in a continuous cycle from one origin to one destination
and return. Techniques and equipment are now in use that have made the
widespread use of western coal possible. The continued application of the
unit train is a key factor in future western coal shipments.
Loading is generally accomplished by a high-speed conveyor system.
The coal is carried to a storage bin located at the top of a tipple and
loaded into the train as it moves continuously underneath. A typical load-
ing operation of 100 cars can be completed in approximately four hours.
The trains are multiple engine powered with the diesels generally
separated into two groups. The lead diesel, located in a group in the front
of the train, is manually operated and transmits commands to the other group
of engines located near the middle. The purpose of this group is to spread
the tractive efforts through the train so that the draw bar pull on the
front car is not excessive. Problems due to the extremely heavy trail-
ing weights are also significantly diminished. The locomotive arrangement
also helps in overcoming potential brakeline air pressure losses which is a
serious problem in the operation of long trains. Stops during long hauls are
limited to routine maintenance and inspection.
The unloading process is accomplished by the use of either rotary or
bottom dumping cars. Rotary dumpers are equipped with swivel couplings so
that each car can be rotated about the coupling without being detached from
the train. Significant improvements to coupling designs and positioners have
greatly reduced unloading times. Bottom dump cars with specially designed
hoppers for fast unloading are employed with shakers or vibrators for complete
discharge. Unloading of ar. entire train to storage facilities or water
transportation can usually be accomplished in under four hours.
The unloaded coal is stored in conical piles or in bins and silos.
Covered storage is usually preferred due to the protection from the weather
and reduced handling costs; however, the increased initial capital investment
is higher than with open storage. The key factor in ground storage is to make
it possible to recover as much of the coal as possible with the minimum aount
of handling. Problems are also encountered with unsightly and dusty open
storage conditions in metropolitan areas.
413
-------
Improvements in unit train performance are being made by the use of
advanced car designs and materials, along with better scheduling of equipment,
employment and maintenance. The regions of long-distance hauling have required
modifications to the dynamic braking system and coupling devices. Coal hopper
cars are larger, 100 ton vs. 70 ton, and equipped with automatic door opening
and closing devices or swivel couples for rapid unloading. It is estimated
that an additional 2800 new large coal hopper cars will be needed to haul
western coal once full production is met. Periodic inspections and maintenance
are conducted ar regular intervals (usually 800 km) for safety and improved
mechanical reliability.
While the continued improvement of unit train operation has allowed
railroads to hold shipping rates down, current inflationary pressures are
requiring adjustments to shipping costs. The primary factors affecting these
costs are labor and materials. Rates over a particular route are determined
through negotiations between the railroad and the receiver. These rates are
periodically adjusted based on a mechanism established during negotiations.
These rate adjustments are usually based on the Index of Railroad, Material
Prices and Wage Rates of the Association of American Railroads.
Current unit train shipments involving the BN, UP and C&NW are out-
lined in Table E-2. Listed are the location (mine) of origin, destination
(user), 1974 shipment volume and the rates as of March 1, 1975. In all cases,
shipments are made directly to utilities and are primarily used in boilers of
greater than 38 kg/s (300,000 Ibs steam/hr). As illustrated in Table E-2,
/:
shipping rates range from $3.43 per net ton, (17<=/10 Btu) for delivery in
Sergeant's Bluff, Iowa, to almost $9.00 per net ton (45C/10 Btu) for receipt
in Hammond, Indiana.
In addition to unit train deliveries, several hundred cars per month
are moved from the western coal fields to the midwest in single and multiple
car shipments, and in entire train loads on a non-unit train operation. These
shipments generally go to paper companies, industrial concerns and small
utilities in Iowa, Wisconsin and Minnesota.
414
-------
TABLE E-2. UNIT TRAIN SHIPMENTS OF WESTERN COAL
From
Hanna, Wyoming
(Arch Minerals)
Hanna, Wyoming
Hanna, Wyoming
(Energy Dev. Corp)
Hanna, Wyoming
llanna, Wyoming
(Arch Minerals)
Hanna, Wyoming
(Arch Minerals)
Hanna, Wyoming
H1 (Arch Minerals)
Ul
Colstrip, Montana
(Western Energy Co)
Colstrip, Montana
(Western Energy Co)
Decker, Montana
(Decker Coal Co)
Colstrip, Montana
(Western Energy Co)
Decker, Montana
(Decker Coal Co)
Sarpy Creek, Montana
'Westmoreland)
Approximate 1974 Rate as of March 1, 1975
To Volume in Tons cents/net ton cents/MBtu
Oak Creek, Wisconsin 750,000 690 35
(Wisconsin Electric Power)
Omaha, Nebraska 500,000 594 3'o
(Omaha Public Power)
Sergeant Bluff, Iowa 1,100,000 343 17
(Iowa Public Service)
Council Bluffs, Iowa 220,000 650 33
(Iowa Power & Light)
Waukegan, Illinois 2,800,000 774 39
(Commonwealth Edison)
Hammond, Indiana 1,550,000 887 45
(No. Indiana Pub Serv)
Kansas City, Missouri 800,000 374 19
(Kansas City P £ L)
Chicago, Illinois
(Commonwealth Edison)
Becker, Minnesota Proposed for 1976
(Northern States Power)
Superior, Wisconsin 1,000,000
(Distribution in the
Detroit Edison system)
Portage, Wisconsin 2,000,000 530 30
(Wisconsin P S L)
Havana, Illinois 4,500,000
(Commonwealth Edison)
St. Paul, Minnesota Proposed for 1976
(NSP and others)
(
Carrier
UP-CNW
UP
UP-CNW
UP
UP-CNW
UP-CNW
UP
BN
BN
BN
BN
BN-CSIM
BN
(continued)
-------
From
To
Sarpy Creek, Montana
(Westmoreland)
Sarpy Creek, Montana
(Westmoreland)
Sarpy Creek, Montana
(Westmoreland)
Sarpy Creek, Montana
(Westmoreland)
Sarpy Creek, Montana
(Westmoreland)
Colstrip, Montana
(Peabody Coal Co)
Belle Ayr, Wyoming
(Amax Coal Co)
Belle Ayr, Wyoming
(Amax Coal Co)
Approximate 1974
Volume .in Tons
Madison, Wisconsin
(Wisconsin Power S Light)
Alma, Wisconsin
(Dairyland Power Coop)
Dubuque, Iowa
(Interstate Power Co)
Peoria, Illinois
(Central Illinois Light)
.Minneapolis, Minnesota
(Northern States Power)
Cohassett, Minnesota
(Minnesota Power & Light)
Cason, Texas
(Southwestern Elec Pwr)
St. Louis, Missouri
(Distribution in the
American Electric Power
System)
Rate as of March 1, 1975
cents/net ton cents/MBtu
Current total shipments of
4,000,000
1,500,000
1,750,000
2,000,000
Carrier
BN
BN
BN
BN
BN
BN
BN-KCS
BN
-------
Shipping rates for non-unit train deliveries as supplied by Burling-
ton Northern demonstrate the dramatic cost increases that must be absorbed
by the small users. The tariff from Colstrip, MT, to Minneapolis, MN on
shipments of train load lots on a single line haul not under unit train
operation is $5.55 per net ton (p.n.t.), while a single car shipment is
$9.03 p.n.t. Similarly in the UP system, unit train deliveries from Hanna, WY
to Kansas City, MO are shipped for $3.74 p.n.t., while lot deliveries of 1,500
tons cost $7.99 p.n.t. A typical western coal tariff is presented in
Table E-3.
Multiple line haul deliveries are even more expensive. For example,
the proposed unit train tariff from Colstrip to Columbia, WI, via the BN and
C&NW is $5.30, while a single car delivery to the same area is $13.12, or
148% higher.
The above shipping costs point out the problem facing small users
of western coal. Unit train operation for large users (primarily utilities),
has allowed shipping costs, and therefore total cost, of western coal to
become competitive with the traditional bituminous coal suppliers in the
east and midwest. In order to make western coal more attractive to non-
utility users, a method must be found to incorporate the unit train concept
into the small user's supply system.
E.4 RAIL-TO-WATER TRANSFER FACILITIES AND DISTRIBUTION CENTERS
The concept of a central distribution center supplied by unit trains
and feeding several users has been proposed. All of these facilities will be
used initially to supply a large utility and will be in conjunction with a
rail-to-water transfer system. Since many present coal users are supplied
from traditional sources in Illinois and Kentucky by water, the importance
of this transfer is obvious. Currently, western coal supply/distribution
centers are planned or under construction in the Duluty, Minneapolis, and
St. Louis areas.
417
-------
TABLE E-3. WESTERN COAL TARIFF FOR LOCAL, JOINT, AND PROPORTIONAL RATES
BURLINGTON NORTHERN, INC.
Effective April 8, 1975
oo
SECTION 1
SPECIFIC RATES IN CENTS PER 2,000 L8S
(For application, see page 22 of tariff)
ITEM
©
200-F
COMMODITY, CARLOADS
BITUNQNOUS COAL. In open top cars.
Minimum weight marked capacity of car,
except when loaded to full visible
capacity, actual weight will apply.
(ML A-8G96)
APPLICATION
FROM
Colstrip . . . .MT
TO
Ames ....
Austin.
Burlington
Cedar Falls \
CedarRapids
Clinton .
Com Belt .
Dsvejiport .
Dubuque.
Eau Claire . '
Humbolt, . "
lowana .
Menasha .•
Milwaukee .
Muscatine
Necnah . j [
IA
MN
IA
IA
1A
LA
LA
IA
IA
WI
IA
1A
WI
WI
IA
WI
Neenah-Menasha_Wl
Rochester
SDCDCZT . . j
Waterloo
Waupun
MN
LA
IA
WI
RATES
<2) 1044
(?)(£)© 1000
(V) 1049
©3) 1029
©@@©1044
§1029
1044
1029
©Si 3) (a) 1000
©1044
O)1029
(3)@1312
(2> ®^©1312
®@(©1029
(3)®®1312
©1312
raiooo
©(D1044
®<5)1312
Route via;
BN-direct.
BN-N1inneapolis,MN-CNW.
BN- Minneapolis, MN-SOO.
BN-St Paul,MN-MILW.
BN-St Paul,MN-RI.
BN- Miles Citv, MT-MILW.
Expires a? indicated in Item ]50.
-------
A rail-to-ship coal handling facility is currently under construction
in Superior, Wisconsin, to handle western coal shipments to Detroit Edison
that will result in a 40-50% reduction in all rail shipping costs through
Chicago. Initially, this facility will handle 8,000,000 tons per year of
Decker coal to Detroit Edison delivered by unit trains on the Burlington
Northern, and Chicago and Northwestern systems. An additional 6,000,000 tons
per year capacity that is as yet uncommitted will be available for other
users.
The C. Reise Coal Company, who will have joint ownership of this
facility, is planning an additional facility to handle primarily smaller
customers in train load lots of 50 cars on a non-unit train operation from
the Peter Kewitt operations at the Big Horn and Rosebud Mines. Significant
shipping cost reductions will be realized from single car deliveries. The
coal will be loaded on to lake barges to distribution to customers along the
Great Lakes. It may prove feasible to subsequently transfer the coal from
lake barge to other surface transportation for delivery to user.
A plan for a coal wharf to store and transfer coal from trains to
river barges has been proposed for the Minneapolis-St. Paul area. The facility,
commonly called "Pig's Eye", will be supplied by unit trains along the
Burlington Northern, and Chicago and Northwestern Railroads from the Sarpy
Creek Mine in Montana. The facility is primarily designed for use by
Northern States Power, Dairyland Cooperative, Interstate Power Company, and
Wisconsin Power and Light. However, storage and transfer facilities for
smaller users have been planned. The facility will handle approximately
5,000,000 tons of coal per year.
Currently the coal wharf project has not been approved by the State
of Minnesota due to environmental concerns. Arguments against the facility
include unsightly conditions, dust and noise. Several proposals to improve
the situation including a possible dome to cover the facility, have been
made. None has yet been approved. Without this facility, future expansion
of western coal to small users in the Minnesota-Wisconsin area is in serious
j eopardy.
419
-------
Four other rail-to-river facilities are currently proposed or under
construction in the St. Louis area. A 10,000,000-ton facility in Metropolis,
Illinois, is under construction. This will be for the sole use of the
American Electric Power Company, a holding company that consists of several
utilities in Ohio, Michigan, West Virginia, and Tennessee. Coal will be
delivered by unit trains from Wyoming and Utah by the Burlington Northern
and Missouri Pacific-Railroads. This facility may eventually expand to
20 million tons per year.
A facility initially designed for industrial users has been proposed
for the Tri Cities Regional Port District. Again, deliveries will be made
by unit train, stockpiled, and supplied to users either by river barge using
existing port facilities or by truck. The initial capacity for the facility
is 2-3 million tons per year but may go as high as 15 million tons.
An existing rail-to-water facility in St. Louis operated by the
Peabody Coal Company has been employed to transfer coal to the American
Electric Power Company for test purposes. Once the Metropolis, Illinois,
facility is completed, this may be available for unit train delivery and
storage for non-utility users.
Another planned operation to be developed by the American Commercial
Barge Company similar to the Pig's Eye coal wharf has been proposed for the
St. Louis area. Initially, this would be employed for shipments to utilities
in the lower Mississippi River. Like the St. Paul facility, this project
is meeting resistance from environmental groups and has been forced to alter
locations. This operation, once approved, will have a capacity of between
10 and 20 million tons per year, the portion of which will be available for
small users is as yet undetermined.
E.5 LAKE AND RIVER TRANSPORTATION
The lower transportation costs and existing coal-handling facilities
make an early transfer to waterway shipment preferred over an all-rail ship-
ment. The existing inland waterway system composed of the Mississippi and
Ohio Rivers and the Great Lakes provides an excellent means of transporting
western coal to potential domestic markets.
420
-------
E.6 CONCLUSION
Estimates are that the present 50 million tons annual output of
western coal will increase to 250 million tons annually. The coal reserves
and technology required to mine it are presently available. Adequate rail
and water transportation facilities exist to transport the western coal to
potential domestic users. The development of rail-to-water transfer facilities,
distribution centers, and additional transportation equipment are the key
elements in future expansion of western coal use. In order for this expan-
sion to occur, a favorable economic climate must exist that will encourage the
development of this coal on a long-term basis.
421
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
i. REPORT NO.
EPA-600/7-78-153a
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Low-sulfur Western Coal Use in Existing Small and
Intermediate Size Boilers
5 REPORT DATE
July 1978
6. PERFORMING ORGANIZATION CODE
1. AUTHOR(S)
Kenneth L. Maloney, George L. Moilanen, P. L. Langsjoen
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
KVB, Inc.
17332 Irvine Boulevard
Tustin, California 92680
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-1863
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 2/75-2/78
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES J.ERL-RTP project officer is David G. Lachapelle, Mail Drop 65,
919/541-2236.
16. ABSTRACT
The report gives results of testing of 10 representative coal-fired boilers
in the Upper-Midwest, including an assessment of SOx, NOx, CO, unburned HC, and
particulate emissions from these units, as well as an assessment of the operational
impact of coal switching. The study showed that western subbituminous coals can be
substituted for eastern bituminous coals as an industrial boiler fuel. Western coaLs
are compatible with industrial coal-fired units of current design. Two unit types of
older design (underfed and traveling grate stokers) experienced difficulty burning
western coal. In some cases, the boiler's maximum load capcity had to be limited,
a problem that can be eliminated by predrying the coal or by increasing superheat
steam attemperation capacity. Western subbituminous coals were superior to eas-
tern coals in terms of SOx, NOx, particulate, and unburned HC emissions. Western
coals could be fired at lower excess air and exhibited substantially lower combustible
losses than eastern coals. The size of delivered western coal was a problem in most
of the stoker-fired units tested: it generally had too large a percentage of fine coal,
caused by its poor weathering characteristics. Stoker performance on western coal
can be improved by sizing the coal at the point of use, to reduce delivery distances
to about 200 miles.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Air Pollution
Coal
Combustion
Products
Nitrogen Oxides
Sulfur Oxides
rnr.arhnns
Sulfur
Stokers
Boilers
Efficiency
Industrial
Population
Dust
Processes Industrial
Air Pollution Control
Stationary Sources
Low-sulfur Coal
Western Coal
Boilers
Bolter Efficiency
Particulate
13 B
2 ID
21B
07B
13A
14B
13H
3. DISTRIBUTION STATEMEN1
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
440
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
422
-------
|