June 1974
EPA-65Q/2-74-066
Environmental Protection Technology Series
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EPA-650/2-74-066
FIELD TESTING:
APPLICATION OF COMBUSTION MODIFICATIONS
TO CONTROL NOX EMISSIONS
FROM UTILITY BOILERS
by
A. R. Crawford, E. H. Manny, andW. Bartok
Exxon Research and Engineering Company
Government Research Laboratory
P. O. Box 8
Linden, New Jersey 07036
Contract No. 68-02-0227
ROAP No. 21ADG-AL
Program Element No. 1AB014
EPA Project Officer: Robert E. Hall
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
June 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
11
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- ill -
TABLE OF CONTENTS
Page
ACKNOWLEDGMENTS ................................................. xii
SUMMARY [[[ xiii
1. INTRODUCTION [[[ 1
2 . OVERALL CORRELATIONS AND CONCLUSIONS ............................ 4
2.1 NOX Emissions for Coal Fired Boilers ....................... 5
2.2 Particulate Mass Loading ................................... 16
2 . 3 Furnace Corrosion Tes ting .................................. 17
2.4 Effects of Combustion Modifications
on Boiler Performance ...................................... 19
2.5 NOX Emissions for Boilers Converted
from Coal to Oil Firing .................................... 19
3. EFFECT OF ELECTROSTATIC
PRECIPITATORS ON NOX FORMATION .................................. 24
4. FIELD STUDY PLANNING AND PROCEDURES ............................. 26
4.1 Program Design ............................................. 26
4.1.1 Boiler Selection Criteria ........................... 26
4.1.2 EPA/Exxon/Boiler Operators/
Boiler Manufacturers Cooperation .................... 28
4.1.3 Test Program Strategy ............................... 28
4.2 Test Procedures ............................................ 31
4.2.1 Gaseous Sampling and Analysis ....................... 31
4.2.2 Particulate Sampling ................................ 36
4.2.3 Furnace Corrosion Rate Measurements ................. 38
5. COMBUSTION VARIABLES ............................................ 43
5.1 Load Reduction ............................................. 43
5 . 2 Low-Excess Air Firing ...................................... 43
5.3 Staged Combustion . . .................................. ...... 44
5.4 Flue Gas Recirculation .......... ......... . ................. 45
5 . 5 Burner Tilt ................................................ 45
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TABLE OF CONTENTS (Cont'd)
Page
6. FIELD TEST RESULTS 48
6.1 Coal Fired Boilers 48
6.1.1 Gaseous Emission Results for
Individual Coal Fired Boilers 48
6.1.1.1 Gaseous Emissions from
Front Wall Fired Boilers 48
6.1.1.1.1 Widows Creek, Boiler No. 6 50
6.1.1.1.2 Dave Johnston, Boiler No. 2 .... 54
6.1.1.1.3 E. D. Edwards, Boiler No. 2 .... 61
6.1.1.1.4 Crist Station, Boiler No. 6 .... 69
6.1.1.2 Gaseous Emissions from Horizontally
Opposed Coal Fired Boilers 72
6.1.1.2.1 Harllee Branch, Boiler No. 3 ... 72
6.1.1.2.2 Leland Olds, Boiler No. 1 75
6.1.1.2.3 Four Corners, Boiler No. 4 78
6.1.1.3 Gaseous Emissions from
Tangentially Fired Boilers 82
6.1.1.3.1 Barry, Boiler No. 3 82
6.1.1.3.2 Naughton, Boiler No. 3 83
6.1.1.3.3 Barry, Boiler No. 4 91
6.1.1.3.4 Dave Johnston, Boiler No. 4 95
6.1.1.4 Gaseous Emissions from
Turbo-Furnace Boilers 96
6.1.1.4.1 Big Bend, Boiler No. 2 96
6.1.2 Particulate Emission Results 103
6.1.3 Accelerated Corrosion Probing Results 105
6.1.4 Boiler Performance Results 109
6.2 Oil Fired Boilers Converted from Coal to Oil Firing 113
6.2.1 Front-Wall Fired Boilers 113
6.2.1.1 Deepwater, Boiler No. 3 113
6.2.1.2 Deepwater, Boiler No. 5 119
6.2.1.3 Deepwater, Boiler No. 8 121
6.2.1.4 Deepwater, Boiler No. 9 129
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TABLE OF CONTENTS (Cont'd)
Page
6.2.2 Cyclone Fired Boilers 136
6.2.2.1 B. L. England, Boiler No. 1 136
6.2.2.2 B. L. England, Boiler No. 2 138
7. RECOMMENDATIONS FOR FURTHER FIELD TESTING 146
7.1 Utility Boiler Testing 146
8. REFERENCES 150
APPENDIX A - Operating and Gaseous Emission Data Summaries A-l
APPENDIX B - Coal Analyses B-l
APPENDIX C - Cross Section Drawings of Typical Utility Boilers C-l
APPENDIX D - Comments from Boiler Manufacturers D-l
APPENDIX E - Conversion Factors E-l
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LIST OF FIGURES
No. Page
2-1 PPM NO vs 7o Stoichiometric Air Normal Firing 11
X
2-2 Uncontrolled NO Emissions vs Gross Load Per
Furnace Firing Wall 13
2-3 Effect of Excess Air on NO Emissions
Under Normal Operation 14
2-4 Effect of Excess Air on NO Emissions
Under Mod if ied F iring Condit ions 15
4-1 Exxon Research Transportable Sampling and
Analyt ica1 System 32
4-2 NOX Regression - Beckman NO + NOo vs
Chemiluminescence NOX Measurements 35
4-3 Relationship Between % C02 and % 02 Flue
Gas Measurements (Widows Creek, Boiler No. 6) 37
4-4 Corrosion Probe Detail of 2-1/2" IPS Extension
Pipe and End Plate (Outside of Furnace) 41
4-5 Corrosion Probe Detail of Corrosion Coupon
As sembly (Ins ide of Furna ce) 42
6-1 PPM NOX (37. 02, Dry) vs % Stoichiometric Air
To Active Burners (Widows Creek, Boiler No. 6) 51
6-2 PPM NOX (37o 02, Dry) vs Overall Stoichiometric Air
(Widows Creek, Boiler No. 6) 52
6-3 PPM NOX (3% 02, Dry) vs 7» Stoichiometric Air
to Active Burners for S^ and S^ Runs 56
6-4 PPM NOX (3% 02, Dry) vs 7, Stoichiometric Air to
Active Burners (Dave Johnston, Boiler No. 2) 57
6-5 PPM NO (37o 02, Dry) vs Adjusted Average 7.
Stoichiometric Air to Active Burners (Dave Johnston, Boiler No. 2) .. 62
6-6 PPM NOX (3% 02, Dry) vs J0 Stoichiometric Air to
Active Burners (E. D. Edwards, Boiler No. 2) 65
6-7 PPM NOX (37» 02, Dry) vs 7, Oxygen in Flue Gas
(Run 9A, E.D. Edwards, Boiler No. 2) 67
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LIST OF FIGURES (Cont'd)
No. Page
6-8 PPM NOX vs % Oxygen in Flue Gas (Run 7A,
E. D. Edwards, Boiler No. 2) 68
6-9 PPM NOX (37, 02, Dry) vs % Stoichiometric
Air to Active Burners (Crist, Boiler No. 6) 70
6-10 Harllee Branch, Boiler No. 3 Pulverizer
and Coal Pipe Layout 73
6-11 PPM NOX (3% 02, Dry) vs % Stoichiometric
Air to Active Burners (Harllee Branch, Boiler No. 3) 74
6-12 PPM NOX (3% 02, Dry) vs % Stoichiometric
Air to Active Burners (Leland Olds, Boiler No. 1) 77
6-13 Four Corners Station, Boiler No. 4
Pulverizer-Burner Configuration 79
6-14 PPM NOX (3% 02, Dry) vs % Stoichiometric
Air to Active Burners (Four Corners, Boiler No. 4) 81
6-15 PPM N0x (3% 02, Dry) vs 7, Stoichiometric
Air to Active Burners (Barry, Boiler No. 3) 85
6-16 Effect of Mill Fineness and Burner Tilt on NOX
Emissions for Low Excess Air Staged Firing
(Naughton, Boiler No. 3) 88
6-17 PPM N0x (3% 02, Dry) vs % Stoichiometric
Air toXActive Burners (Naughton, Boiler No. 3) , 90
6-18 % Oxygen Measured in Flue Gas Before
and After Air Preheater (Barry, Boiler No. 4) , 93
6-19 PPM N0x (3% 02, Dry) vs % Stoichiometric
Air to Active Burners (Barry, Boiler No. 4) 94
6-20 PPM NOX (3% 02, Dry) vs % Stoichiometric
Air to Active Burners (Dave Johnston, Boiler No. 4) , 98
6-21 PPM NOX (3% 02, Dry) vs % Stoichiometric
Air to Active Burners (Big Bend, Boiler No. 2) 101
6-22 PPM NOX Emissions vs Probe Location (Big Bend,
Boiler No. 2) 102
6-23 Furnace Corrosion Probe Locations 106
6-24 PPM NOX vs % 02 Measured in Flue Gas (Deepwater,
Boiler No. 3) 116
6-25 PPM NOX vs % 02 in Flue Gas (Deepwater, Boiler No. 8) 122
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LIST OF FIGURES (Cont'd)
No. Page
6-26 PPM NO vs 7, Oo in Flue Gas (Deepwater, Boiler No. 8) 123
X
6-27 PPM NO vs 7e, D£ Measured in Flue Gas (B. L. England,
BoilerXNo. 9) 133
6-28 PPM NOx vs % Q£ Measured in Flue Gas (B. L. England,
Boiler No. 1) 140
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LIST OF TABLES
No. Page
2-1 Summary of Coal Fired Boilers Tested 6
2-2 Summary of NOX Emissions for Front Wall Fired Boilers ...... 7
2-3 Summary of NOX Emissions for Opposed Wall Fired Boilers .... 8
2-4 Summary of NOX Emissions for Tangentially Fired Boilers .... 9
2-5 Atlantic City Electric Company
Summary of Coal-to-Oil Converted Boilers Tested 21
2-6 Atlantic City Electric Company
Summary of NOX Emissions for Coal-to-Oil Converted Boilers.. 22
3-1 NOX Emission Measurements Tests Across the Electrostatic
Precipitator—Alabama Power Company,Barry, Boiler No. 4 .... 25
4-1 Test Program Experimental Design — Widows Creek, No. 6 ...... 30
4-2 Continuous Analytical Instruments in Exxon Van ............. 34
4-3 Summary of Corrosion Probing Tests ................... . ..... 40
6-1 Summary of Coal Fired Boilers Tested ........ ......... ...... 49
6-3 Calculation of Expected NOX Emissions from
% Stoichiometric Air to Active Burners ..................... 55
6-4 Calculation of Expected NOX Emissions from Average
"Effective" % Stoichiometric Air to Active Burners ......... 55
6-5 Experimental Design with % 02 and PPM NOX (3% 02, Dry)
(Dave Johnston, Boiler No. 2) .............................. 58
6-6 Summary of Low Excess Air, Staged Test Runs ................ 60
6-7 Experimental Design with PPM NOX (3% 02, Dry) and % Oo
(E. D. Edwards, Boiler No. 2) .............................. 63
6-8 Test Program Experimental Design (Crist, Boiler No. 6) ..... 71
6-9 Experimental Design with Run No., % 0, and PPM NOX
(Le land Olds, Boiler No. 1) ......... T ...................... 76
6-10 Experimental Design - % Oxygen and PPM N0 (3% 02, Dry)
(Four Corners, Boiler No. 4)
x
80
6-11 Test Program Experimental Design (Barry, Boiler No. 3) ..... 84
6-12 Test Program Experimental Design (Naughton, Boiler No. 3) ^ 87
6-13 Pulverizer Screen Analyses (Naughton, Boiler No. 3) ......... 89
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LIST OF TABLES (Cent M)
No,
6-14 Test Program Experimental Design (Barry, Boiler No. 4) ............. 92
6-15 Experimental Design with 7. 0, and PPM NOX (3% 02, Dry)
(Dave Johnston, Boiler No. 4) ...................................... 97
6-16 Experimental Design with % 02 and PPM N0x (3% 02, Dry)
(Big Bend, Boiler No . 2) ........................................... 100
6-17 Particulate Emission Test Results .................................. 104
6-18 Accelerated Corrosion Rate Data .................................... 107
6-19 ASME Test Form For Abbreviated Efficiency Test ..................... 110
6-20 ASME Test Form For Abbreviated Efficiency Test ..................... Ill
6-21 Summary of Boiler Performance Calculations ......................... 112
6-22 Summary of Operating and Emission Data (Deepwater, Boiler No. 3) ... 114
6-23 Experimental Design and Average Emission Measurements
(Deepwater, Boiler No . 3)
6-24 Flue Gas Emission Measurements and Temperatures (Deepwater,
Boiler No. 3) ............................. ........................ H8
6-25 Summary of Operating and Emission Data
(Deepwater, Boiler No. 5) .......................................... 12°
6-26 Flue Gas Emission Measurements and Temperatures
(Deepwater, Boiler No . 5) .......................................... 124
6-27 Summary of Operating and Emission Data (Deepwater, Boiler No. 8) .... 125
6-28 Experimental Design and Average Emission Measurements
(Deepwater, Boiler No. 8) .......................................... I26
6-29 Firing Patterns Used During NOX Testing
(Deepwater, Boiler No. 8 ) ......................... • .............. 127
6-30 Flue Gas Emission Measurements and Temperatures
(Deepwater, Boiler No. 8) .......................................... I30
6-31 Summary of Operating and Emission Data (Deepwater, Boiler No. 8) ---- 131
6-32 Experimental Design and Average Emission Measurements
(Deepwater, Boiler No .9) ...........................................
6-33 Flue Gas Emission Measurements and Temperatures
(Deepwater, Boiler No. 9)
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LIST OF TABLES (Cont'd)
No.
6-34 Summary of Operating and Emission Data (B. L. England,
Boiler No. 1) 137
6-35 Experimental Design and Average Emission Measurements
(B. L. England, Boiler No. 1 ) 139
6-36 Flue Gas Measurements and Temperatures (B. L. England,
Boiler No. 1) 141
6-37 Summary of Operating and Emission Data (B. L. England,
Boiler No. 2) 143
6-38 Experimental Design and Average Emission Measurements
(B. L. England, Boiler No. 2) 144
6-39 Flue Gas Measurements and Temperatures (B. L. England,
Boiler No. 2) 145
7-1 Number and Type of Utility Boilers to be
Tested in Future Field Test Programs 146
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ACKNOWLEDGMENTS
The authors wish to acknowledge the constructive participation
of Mr. R. E. Hall, EPA Project Officer, in planning the field test
programs and providing coordination with boiler operators and manufacturers,
The helpful cooperation, participation and advice of the major U.S.
utility boiler manufacturers, Babcock and Wilcox, Combustion Engineering
Inc., Foster Wheeler Corp. and Riley-Stoker Corp. were essential to
selecting representative boilers for field testing and conducting the
program. The voluntary participation of electric utility boiler operators
in making their boilers available is gratefully acknowledged. These
boiler operators included the Alabama Power Company, Arizona Public
Service Company, Atlantic City Electric Company, Basin Electric Power
Cooperative, Central Illinois Power and Light Company, Georgia Power
Company, Gulf Power Company, Pacific Power and Light Company, Tampa
Electric Company, the Tennessee Valley Authority, and Utah Power and
Light Company. Special thanks are due to Combustion Engineering for
supplying their basic corrosion probe design which was adapted to
furnace corrosion probing tests in this study. The authors also
express their appreciation for the extensive coal analyses services
provided by Exxon Research's Coal Analysis Laboratory at Baytown, Texas
and to Messrs. A. A. Ubbens and E. C. Winegartner for their contributions
and advice on coal related matters. The invaluable assistance of
Messrs. L. W. Blanken, R. Campbell, R. W. Kochanczyk, R. W. Schroeder,
and A. J. Smith, and Mrs. M. V. Thompson in these field studies is also
acknowledged.
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SUMMARY
Exxon Research and Engineering Company has been conducting
field studies on utility boilers under EPA sponsorship to develop NO
and other pollutant control technology through the modification of
combustion operating conditions. Under the present contract on this
problem, Exxon's mobile sampling-analytical system has been used to test
12 pulverized coal-fired boilers of cooperating electric utilities.
These boilers, including wall, tangentially, and turbo-furnace fired
units, had been recommended by the utility boiler manufacturers as
being representative of their current design practices. Also, combustion
modifications for NOX control were tested for six oil-fired boilers
which had been converted from coal firing service.
In addition to gaseous emission measurements, particulate emis-
sions and accelerated furnace corrosion rates also have been determined
in a number of cases for coal-fired boilers. The test design used con-
sisted of three phases. First, statistically designed short-term runs
were made, to define the optimum "low NOX" conditions within the con-
straints imposed by boiler operability and safety, slagging, unburned
combustible emissions and other undesirable side effects. Second, the
boilers were usually operated for about two days under the "low NOX"
conditions defined in the first phase, to check operability on a sus-
tained basis. Third, several boilers were operated under both baseline
and "low NOx" conditions for about 300 hours, with carbon steel corrosion
coupons mounted on air-cooled probes exposed near the water walls of the
furnaces, to obtain relative corrosion tendencies at accelerated rates.
Analysis of the gaseous emission data obtained shows that com-
bustion operating modifications, chiefly low excess air firing coupled
with staged burner patterns, can reduce NOX emissions from the coal fired
boilers tested by 25 to 60%, depending on the unit and its flexibility
for modifications. The NOX emissions measured have been successfully
correlated for both normal and modified firing conditions with the per-
cent stoichiometric air supplied to the burners.
For dry particulate mass loadings, the differences observed
under baseline and "low NOX" operating conditions have been found to be
relatively minor. However, unburned carbon in the fly-ash seems to
increase for "low NOX" firing in front wall and horizontally opposed
fired boilers, and to decrease for tangentially fired units. The potential
debits in overall performance based on these limited data for front wall
and horizontally opposed fired boilers have been shown to be offset by
improved efficiencies realized through lower excess air operation in "low
NOX" firing.
Boiler efficiency calculations comparing baseline and modified
"low NOX" operations indicate essentially no efficiency penalty for the
implementation of combustion modifications to control NOX emissions.
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Significantly, the accelerated corrosion tests have not
revealed major differences in corrosion rates measured under normal and
staged firing operating conditions. More tests and long term runs, with
particular emphasis on corrosion and slagging problems, are needed to
demonstrate the promising leads uncovered in this study.
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1. INTRODUCTION
In continuing studies sponsored by EPA, Exxon Research and
Engineering Company (Exxon) is involved in the development of nitrogen
oxides (NOX) emission control techniques for stationary sources. Our
"Systems Study of Nitrogen Oxide Control Methods for Stationary Sources"
(1-3) characterized the nature and magnitude of the stationary NOX
emission problem, assessed existing and potential control technology
based on technical feasibility and cost-effectiveness, developed a first-
generation model of NOX formation in combustion processes, and prepared
a set of comprehensive 5-year R&D plan recommendations for the Government
with priority rankings.
Fossil fuel fired electric utility boilers were identified by the
above study as the largest single stationary NOX emission sector, responsible
for about 40% of all stationary NOX. Consequently, as part of Phase II of our
"Systems Study of Nitrogen Oxide Control Methods for Stationary Sources",
Exxon conducted a systematic field study of NOX control methods for
utility boilers (4-6). The objectives of this field study were to determine
new or improved NOX emission factors according to fossil fuel type and
boiler design type, and to explore the application of combustion modifica-
tion techniques to control NOX emissions from such installations.
Exxon provided a specially designed mobile sampling-analytical
van for the above field testing. This van was equipped with gas sample,
thermocouple, and velocity probes, with associated sample treating equip-
ment, and continuous monitoring instrumentation for measuring NO, N02, CO,
^<")2' ^2' ^?» anc^ hydrocarbons.
Gas, oil, and coal fired utility boilers representative of the
U.S. boiler population were tested. Combustion modifications were
implemented in cooperation with utility owner-operators (and with major
boiler manufacturer subcontractors for three of the coal fired boilers
tested), and emission data were obtained in a statistically designed
field program. The 17 boilers (25 boiler-fuel combinations) tested
included wall-fired, tangentially-fired, cyclone-fired, and vertically-
fired units ranging in size between 66 and 820 MW generating capacity.
Major combustion operating parameters investigated consisted of
the variation of gross boiler load, excess air level, staged firing patterns
flue gas recirculation, burner tilt, primary/secondary air ratio, and air
preheat temperature. Operation under reduced load conditions reduced the NO
emissions, but only for gas firing was the percent NOX reduction greater than
the percent load reduction. Base-line emissions were correlated in a
statistically significant manner with the MW generated per "equivalent" furnace
firing wall. In general, unburned combustible emissions, i.e. CO and
hydrocarbons were found to be negligibly small under base-line conditions
and acceptably iow even with NOX control combustion modifications. The NO-
portion of the flue gas was always five percent or less of the total NO emitted
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The effectiveness of combustion modifications was found to vary
with individual boiler characteristics for each fuel. For gas fired
boilers, NOX emissions could be reduced on the average by about 60% at
full load, even though in large, gas fired boilers limited by heat transfer
surface, NOX emission levels as high as 1000 ppm prevailed in the absence
of combustion modifications. Uncontrolled emissions from fuel-oil fired
boilers averaged lower values than for gas firing, but combustion modifica-
tions could be less readily implemented. With coal firing, only two of
the seven boilers tested (one a tangential unit, the other a front wall
fired boiler) could be operated in a manner conducive to reducing NOx
emissions. This operation consisted of firing the operating burners in
the lower burner rows or levels with substoichiometric quantities of air,
and supplying the additional air required for the burn-out of combustibles
(keeping overall excess air as low as possible) through the air registers
of the uppermost row or level. In these short-term, exploratory tests,
NOX emissions were reduced by over 50% compared with the standard firing
mode. In one set of boiler tests, this was demonstrated to be possible
without decreasing thermal efficiency or increasing the amount of unburned
carbon in the fly-ash. Due to stopping the pulverizer mill supplying coal
to the top level of burners, the amount of fuel that could be fired was
reduced, resulting in a decrease of about 15% from maximum rated capacity.
The NOX reductions achieved were not affected by this reduction in load,
as normal and modified combustion operations were compared at the same
boiler load.
While the exploratory data obtained in the above study on con-
trolling NOx and other pollutant emissions from utility boilers by com-
bustion modifications showed good potential, a number of critical questions
had remained to be answered. Thus, for coal fired utility boilers, potential
problems of slagging, corrosion, flame instability and impingement,
increased carbon in the fly-ash, the actual particulate loadings and
potential decreases in boiler efficiency which could result from the
modified combustion operations still needed to be assessed in sustained
test runs.
The purpose of Exxon's present field testing program, sponsored
by EPA under Contract No. 68-02-0227, has been to obtain more detailed
information primarily on the application of combustion modification
technqiues to coal fired utility boilers, in cooperative efforts with
boiler operators and manufacturers coordinated by EPA. U.S. utility
boiler manufacturers (Babcock and Wilcox, Combustion Engineering, Foster
Wheeler, and Riley-Stoker) have recommended boilers characteristic of
their current design practices. They have provided their help in making
arrangements for testing with the cooperating boiler owner/operators,
and in a number of cases assigned representatives to participate in
Exxon's field tests.
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In addition to the continuous monitoring instrumentation
described above, four EPA-type particulate sampling trains have been
added to Exxon's system. These trains and other equipment have been
transported to the testing sites in an auxiliary van.
The approach used for field testing coal-fired boilers in
this study has been first, to define the optimum operating conditions
for NOX emission control without apparent unfavorable side effects,
in short-term, statistically design test programs. Second, the boiler
was operated for 1-3 days under the "low NOX" conditions determined during
the optimization phase, for assessing boiler operability problems. Finally,
where possible, sustained 300-hour runs were made under both baseline
and modified combustion ("low NOX") operating conditions. During this
period, air-cooled carbon steel coupons mounted on corrosion probes were
exposed in the vicinity of furnace water tubes, to determine through
accelerated corrosion tests whether operating the boiler under the reducing
conditions associated with staged firing results in increased fire-side
water tube corrosion rates. Particulate samples were obtained under both
baseline and "low NOX" conditions, and engineering information on boiler
operability, e.g., on slagging problems, and on boiler performance were
also obtained. For the coal-to-oil converted boilers tested, gaseous
emission measurements were made in the same manner as for the coal-fired
units.
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2. OVERALL CORRELATIONS AND CONCLUSIONS
This section of the report presents the overall correlations and
conclusions based on the results obtained in a field program conducted on
twelve representative coal-fired utility boilers. Also, our conclusions
on the results of six boilers converted from coal to oil service are pre-
sented. Because of the emphasis in this study on the control of NOX
emissions by combustion modifications, the gaseous emission measurements
obtained without adverse side-effects during short-term optimization runs
are analyzed in depth in the section that follows.
Baseline NOX emissions from the boilers tested under normal
operating conditions, usually at full rated boiler capacity, have been
successfully correlated with excess air (or percent stoichiometric air
to the active burners) and boiler load. Also, the percent reduction from
baseline levels in NOX emissions resulting from the application of staged
firing has been correlated with the percent stoichiometric air supplied
to the active burners.
Particulate measurements have been made under both baseline and
modified combustion ("low NOx") conditions for several of the boilers tested.
The objective was to assess the relative changes in total flue gas particu-
late loadings and in the unburned carbon content of the flyash that may be
due to the application of combustion modification techniques, chiefly
staged firing of burners with low overall levels of excess air. No major
differences in particulate loadings have been found, but the unburned carbon
content of flyash appears to be somewhat affected by combustion modifica-
tions.
In a similar manner, the potential of increased furnace water-
tube corrosion rates resulting from reducing conditions created by sub-
stoichiometric air supply to the burners has been explored. For this
purpose, accelerated corrosion tests have been made under both baseline
and modified combustion conditions for 300-hour sustained periods. The
objective of these corrosion probing studies was to establish whether the
application of staged firing with low overall excess air supply could cause
severe corrosion problems in the furnace. As will be discussed further,
comparison of the corrosion rates measured under baseline and modified
firing conditions indicates that the reducing environment in the furnace
does not appear to cause severe corrosion problems.
The overall correlations and conclusions discussed in this section
will be followed by subsequent sections of this report containing our re-
commendations for boiler operators and manufacturers on NOX emission con-
trol, details of the field tests, results on each individual boiler tested,
and recommendations on future emission field studies.
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2.1 NO Emissions for Coal Fired Boilers
—x—
In this section the results obtained for all coal-fired boilers
tested will be analyzed. Individual boiler test data are summarized in
Section 6 of this report and further details on gaseous emissions are presen-
ted in Appendix A. Typical boiler cross-sectional diagrams for wall,
tangential, and turbo-furnace fired boilers are shown in Appendix C.
The design and operating features of the twelve coal-fired
boilers tested are summarized in Table 2-1, listed in the sequence of the
individual tests. Of the twelve boilers, seven were wall fired units
(four front wall and three horizontally opposed fired units, ranging in
size from 100 MW to 800 MW), four were tangentially fired, ranging in size
from 250 MW to 350 MW) and one was a turbo-furnace boiler (with maximum
rated design capacity of 450 MW, but tested only at 370 MW) . These
boilers are representative of current design practices, and have been
selected for field studies at the recommendation of their respective
manufacturers as discussed in Section 4.1.
Tables 2-2, 2-3, and 2^-4 summarize the NOX emission levels
measured from single wall-fired, horizontally opposed wall-fired, and
tangentially-fired (plus a turbo-furnace) boilers, respectively. "Low
NOx" operation at essentially full load reduced NOX emission reductions
of 55 to 64% compared to full load, baseline emission levels.
Comparison of the NOX emission data in Table 2-4 with those in
Tables 2-2 and 2-3 reveals that baseline NOx emission levels from tan-
gentially fired boilers are lower than those from wall fired boilers.
(The turbo-furnace boiler was tested at 370 MW, due to operating
problems at the time of our test, compared with design full load of
450 MW, and hence, additional testing is needed to measure baseline,
full load NOX emission levels.) Combustion modifications for "low NOX"
staged firing operation with 15-20% load reduction enabled these tan-
gentially fired boilers to further decrease NOX emissions. "Low NOX"
operation with further load reduction resulted in NOX reductions of 55
to 64% compared to full load, baseline emission levels.
As will be discussed in Section 6 of this report, it should be
recognized that these results were obtained during short-term test periods
and that long-term testing is needed to study slagging, corrosion and other
operating conditions. It is expected that slagging problems in some boilers
can be largely overcome by increasing slag blower steam pressures, increasing
the use of slag blowers and perhaps the addition of slag blowers at trouble-
some locations. Lower NOX emissions would also be expected in many boilers
from improved furnace maintenance, so that air-to-fuel ratios are as uniform
as practical across the furnace. Research at extremely low levels of
stoichiometric air to the active burners (less than 75%) with staged
firing may yield significantly improved NOX emission levels with
decreased slagging, because of lower temperatures. Also, the addition
of secondary air-ports (frequently termed "NO-ports" or "overtired air-
ports") would probably allow most boilers to reduce NOX emissions
significantly during full-load operation with all burners firing coal.
-------
TABLE 2-1
SUMMARY OF COAL FIRED BOILERS TESTED
Boiler Operator
Tennessee Valley
Authority
Gulf Power
Georgia Power
Arizona Public Service
Utah Power and Light
Alabama Power
Alabama Power
Tampa Electric
Central Illinois Light
Basin Electric
Pacific Power and Light
Pacific Power and Light
Station and
Boiler No.
Widows Creek
Crist
Harllee
Branch
Four Corners
Naught on
Barry
Barry
Big Bend
E.D. Edwards
Leland Olds
Dave Johnston
Dave Johnston
(a) B&W - Babcock and Wilcox
CE - Combustion Engineering
F-W - Foster Wheeler
RS - Riley Stoker
Boiler
Mfr.(a>
6(c) B&W
6<"> F-W
3*c^$iw
4(C) (ilw
3(c) %
4(°)(&
3 CE
2 RS
2 RS
1 B&W
2 B&W
4 RS
(b) FW -
HO -
T -
Turbo -
Type of M
Firing fl" £
FW
FW
HO
HO
T
T
T
Turbo
FW
HO
FW
CR No. of
MW) Burners
125
320
480
800
330
350
250
350
256
218
105
T 348
Front Wall
Horizontally Opposed
Tangential
Turbo -Furnace
16
16
40
54
20
20
48
24
16
20
18
28
Test
Variables
4
4
4
5
6
7
4
4
4
3
3
7
No. of
Test
Runs
41
22
51
26
26
46
8
14
19
13
14
6
236
(c) Particulate tests performed on these boilers.
(d) Corrosion probe tests performed on these units.
-------
TABLE 2-2
SUMMARY OF NOX EMISSIONS
FOR FRONT WALL FIRED BOILERS
(COAL FIRING)
NOX Emissions
Boiler
Dave Johnston No. 2
Widows Creek No. 6
E. D. Edwards No. 2
Crist No. 6
Operating
(Gross Load
Baseline
"Low NOX I
Baseline
"Low NOX I
"Low NOX II
Baseline
"Low NOX I
"Low NOX II
Baseline
"Low NO I
"Low NO* II
Mode
- MW)
(101)
" (99)
(125)
" (123)
" (100)
(253)
" (256)
" (221)
(350)
" (320)
" (260)
7.0.
.... £_
5.0
5.2
3.4
2.0
2.7
3.5
1.6
3.0
3.3
2.2
3.5
ppm
(3% 00)
454
214
634
379
295
703
359
295
832
550
526
Lb.
106 BTU *
0.60
0.28
0.84
0.50
0.39
0.93
0.48
0.39
1.11
0.73
0.70
gm.
100 cal *
1.08
0.50
1.51
1.90
0.70
1.67
0.86
0.70
2.00
1.31
1.26
ppm CO
(3% 00)
112
962
258
665
818
42
172
26
22
196
217
X
* Calculated as NO,
-------
TABLE 2-3
SUMMARY OF NOX EMISSIONS
FOR OPPOSED WALL FIRED BOILERS
(COAL FIRING)
NOX Emissions
— .
Operating Mode
Boiler
Leland Olds No. 1
Harllee Branch No. 3
Four Corners No. 4
(Gross Load •
Baseline
"Low NOX
"Low NOX
Baseline
"Low NOx
"Low NOX
Baseline
"Low NOX
"Low NOX
I"
II"
I"
II"
I"
II"
• MW)
(219)
(218)
(185)
(490)
(473)
(400)
(800)
(794)
(600)
%00
3
2
2
3
1
1
5
3
3
.9
.8
.2
.5
.4
.6
.0
.2
.0
ppm
(VI n 1
(. J /o U,, )
569
375
260
711
463
359
935
488
452
Lb . gm .
106
0.
0.
0.
0.
0.
0.
1.
0.
0.
BTU * 10°
76
50
34
95
62
48
24
65
60
1.
0.
0.
1.
1.
0.
2.
1.
1.
ppm GI
Cal * (37, 0,
37
90
61
71
12
86
23
17
08
24
231
518
27
152
316
18
172
33
I
oo
I
* Calculated as NO.-
-------
TABLE 2-4
SUMMARY OF NOx EMISSIONS
FOR TANGENTIALLY FIRED BOILERS
(COAL FIRING)
NOX Emissions
Boiler
Barry No. 3
Naught on No. 3
Barry No. 4
Dave Johnston No. 4
Operating Mode
(Gross Load - MW) 7o00
Baseline
"Low NOx
Baseline
"Low NOX
"Low NOX
Baseline
"Low NOX
"Low NOX
Baseline
"Low NOX
(250)
I" (248)
(334)
I" (310)
II" (256)
(350)
I" (300)
II" (186)
(306)
" (304)
£.
3.1
1.3
4.2
2.3
3.0
4.4
2.4
2.2
4.2
3.3
TURBO - FURNACE
Big Bend No. 2
Baseline
"Low NOX
"Low NOX
(370)
I" (370)
II" (300)
2.8
1.4
1.8
ppm
Lb.
Gm/100
(3% 00) 10*" BTU * Cal *
410
310
531
219
197
415
273
189
434
384
BOILER
600
398
341
0.55
0.41
0.71
0.29
0.26
0.55
0.36
0.25
0.53
0.51
0.80
0.53
0.45
0.99
0.74
1.28
0.52
0.47
0.99
0.65
0.45
1.04
0.92
1.44
0.95
0.81
ppm CO
61
100
27
499
376
24
113
281
19
99
28
319
87
* Calculated as N0r
-------
- 10 -
The ranges of NOX emissions measured as a function of % stoichio-
metric air without staging during the short term optimization phases of
the individual field test programs are presented graphically in Figure 2-1.
In this figure, and in subsequent graphica] presentations, the power
generating stations and boilers are coded by the following letters (for
clarity, the boiler numbers appear in these figures only for stations
where more than one boiler was tested) :
Code Letters Station Boiler No.
WC 6 Widows Creek 6
HB 3 Harllee Branch 3
FC 4 Four Corners 4
N 3 Naughton 3
B 3 Barry 3
B 4 Barry 4
BB 2 Big Bend 2
E 2 E. D. Edwards 2
0 1 Leland Olds 1
J 2 Dave Johnston 2
J 4 Dave Johnston 4
C 6 Crist 6
The absolute levels of NOx emissions shown in Figure 2-1 are
clearly related to the level of excess air (or % stoichiometric air) for
each boiler tested. In fact, the slopes of the NOx vs- ^ stoichiometric
air lines exhibit a rather small variability, which is remarkable in view
of the fact that the data have been obtained on different boiler and burner
types and sizes, fired with different types of coal. The very strong
dependence of NOx emission levels on available oxygen will be discussed
further.
As in our "Systematic Field Study", the uncontrolled baseline
NOX emissions have been correlated with the load generated per equivalent
furnace firing wall. The earlier data ( 4 ) have been recalculated using
the same set of assumptions as for the result of the study i.e., that the
number of equivalent firing walls is 1, 2, and 4 for front wall, horizontally
opposed, and tangentiaily fired boilers, respectively. For boilers having
twin furnaces, this number has been doubled. However, in contrast to the
earlier correlations (4), the above factor of 2 was not used to account for
the presence of a division wall in the furnace, because the heat absorbing
effect of a division wall is smaller than that of furnace side waxxa.
Also, the data for two wet-bottom (one of them cyclone fired) boilers
tested previously (4 ) have been omitted from the correlations, because
of the uncharacteristically long residence time at high temperatures in
these two units.
-------
- 11 -
FIGURE 2-1
PPM NOx VS % STOICHIOMETRIC
Am NORMAL FIRING
(COAL FIRED BOILERS)
1000
900 -
Q Front Wall Fired
Opposed Wall Fired
Tangentially ^ired
I I
200
120 125
STOICHIOMETRIC AIR
135
-------
- 12 -
As a first approximation, the above type of correlation takes
into account the relationship of furnace heat release rate to the heat
absorption rate. Figure 2-2 presents the correlation of baseline NOx
emission levels (ppm at 3% 02, dry basis) vs. gross load per furnace firing
wall. The dashed line labeled "Present Study" is the least squares regres-
sion of the 12 data points corresponding to the 12 boilers tested in the pre-
sent program. The dotted line in Figure 2-2 is calculated from
our "Systematic Field Study" (_4_), while the solid line is the regression
for all boilers. There appears to be a very good correlation on this
basis, as the correlation coefficient is 0.9, and the standard error on
the estimate is 70 ppm NOX. It should be noted that individual boilers
of unusual furnace or burner design may produce emission rates outside
of the expected range calculated for the relationship shown in Figure 2.2.
Our sample of 12 boilers plus 5 out of 7 for the 1971 field study is a
relatively small sample of the highly diverse populations of boilers
operating in the United States. The regression intercept of 390 ppm NOX
at zero load corresponds to a conversion of about 20% of the average fuel
nitrogen content of 1.3 wt. % of the coal types fired in this study. This
observation is a strong indication of the significant contribution of
bound fuel nitrogen to NOx emissions from coal fired boilers. On an
absolute scale, this contribution would account for over 50% of the total
NOX emitted for the majority of the coal-fired boilers tested, which is
in agreement with laboratory results (7 ) on this problem. Substoichio-
metric air supply to the active burners is expected to reduce both the
fixation of molecular N£, and the oxidation of fuel nitrogen, based on
independent laboratory data (8 ) .
Figures 2-3 and 2-4 have been prepared to show the overall
correlations of NOx emissions vs overall % stoichiometric air and %
stoichiometric air supplied to the active burners. Figure 2-3 is a plot
of "normalized" NOx emissions, expressed as the % of baseline NOx emis-
sions (full load and 20% excess air) vs. % overall stoichiometric air
(or % stoichiometric air to active burners under normal firing conditions).
The solid lines shown for each boiler are based on least-squares linear
regression analysis of all test runs made uner normal (all burners
firing coal), full load firing conditions. With the exception of the
turbo-furnace boiler, all of these regressions show very good agreement
with about a 20% reduction in NOx at 110% vs. 120% stoichiometric air.
The three tangentially fired boilers show especially good agreement
in this significant correlation of NOX emission levels with excess air
levels.
Figure 2-4 is a plot of "normalized" NOx emissions expressed
as the % of baseline NOx emissions (full load and 20% overall excess air)
vs. % stoichiometric air to the active burners under staged firing con-
ditions. Thus, the ordinates are identical in Figures 2-3 and 2-4.
However, the least squares regression lines of Figure 2-4 do not neces-
sairly pass through the 100% normalized NOx point at 120% stoichiometric
air to the active burners, as they must, by definition, in Figure 2-3.
Figure 2-4 indicates the importance of low excess air firing
on NOx emissions, as well as the further benefits of staged firing and
additional firing modifications. The opposed wall fired boilers (Harllee
Branch No. 3, and Four Corners No. 4 boilers) showed excellent agreement, as
-------
FIGURE 2-2
1000
fi
w
u
X
w
800
600
(3s?
CO
400
x
g
PL*
200
UNCONTROLLED NOx EMISSIONS VS
GROSS LOAD PER FURNACE FIRING WALL
(COAL FIRED BOILERS)
T
~~1 T
ALL BOILERS
1971 FIELD STUDY (4 )
V^PRESENI
STUDY -
fpcl
FRONT WALL FIRED
OPPOSED WALL FIRED
TANGENTIAL FIRED
"2W"
"35IT
u>
I
"550
GROSS LOAD PER FURNACE FIRING WALL - MW
-------
i
esi
CQ
fc
O
140
120
fi
<
CQ 100
CO
W
><
W
80
60
40
20
FIGURE 2-3
EFFECT OF EXCESS AIR ON NOX
EMISSIONS UNDER NORMAL OPERATION
(COAL FIRED BOILERS)
A-^ «9VX
O Front Wall Fired
n Opposed Wall Fired
/\ Tangentially Fired
1
104
108 112 116 120 124
\VERAGE % STOICHIOMETRIC AIR
128
132
136
-------
FIGURE 2-4
i
I
<
OT
03
w
o
X
w
W
w
<:
PQ
fe
O
100
80 -
60 _
40 -
20 ~
0
EFFECT OF EXCESS AIR ON NOX EMISSIONS
UNDER MODIFIED FIRING CONDITIONS
(COAL FIRED BOILERS)
Front Wall Fired
Opposed Wall Fired
/\ Tangentially Fired
Ul
I
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 16 -
would be expected, since both of them represent modern design practices
of Babcock and Wilcox with their cell-type burners. Leland Olds No. 1
representing a t,ouiewhat different type of design shows more of a deviation
from this behavior. The tangentially fired boilers, Barry No. 4 and
Naughton No. 3, that employed staged firing showed similar trends, with
Naughton No. 4 producing lower NQx emissions because it was tested at
lower % stoichiometric air levels. Of the tront wail-fired units, Widows
Creek No. 6 boiler showed consistently larger reductions in normalized
NOX under normal operating conditions than the other front wall fired units
at the same % stoichiometric air levels. However, under modified firing
conditions all front wall fired boilers gave similar results. Boiler para-
meters such as size, coal type fired, pulverizer conditions, and other
design and operating variables undoubtedly contributed to the differences
found.
2.2 Particulate Mass Loading
As described in detail in Section 4 of this report, four
Research Appliance Company EPA-type particulate sampling trains were
used in this program. The design of this equipment follows the guidelines
of EPA Method No. 5 (9). Many difficulties occur in actual operation, as
is inherent to particulate testing. Care must be taken to assure that
the probes and test boxes are at specified temperatures. Even so,
especially in cold weather, moisture in the flue gases condensing in the
apparatus can quickly plug filters which results in aborting the test.
Tests for leaks in each train prior to testing is also needed if meaningful
data are to be obtained. Plugging of sampling probes on occasion also
occurs, and can present difficulties in boilers with high particulate
loadings.
The boilers tested proved to be another source of recurrent
problems. Most boilers were not equipped with suitable testing facilities.
Sample test ports are often located too close to bends in the flue ducts
where particulate concentrations, due to centrifugal action, are strongly
stratified. Interferences of the probes with supports inside the flue
ducts and of the test apparatus with other obstructions near test loca-
tions outside the boiler contribute to the difficulty of running par-
ticulate loading tests. Last but not least, the EPA-type test train is
built for horizontal probing, while most boiler test locations require
vertical probing. Our equipment has been modified for vertical probing,
so that usually the construction of scaffolding was necessary for access
to the ducting.
Despite the problems of conducting particulate tests, the
results obtained in this program, summarized in Table 6-17, are consistent
and appear to be reliable within the limitations of this type of testing.
The objective of our work was to develop information on potential "side
effects" of "low NOX" firing techniques on total particulate loadings and
on the carbon content of the flyash produced. Although strict adherence
to EPA recommended sampling procedures was not possible, due to the
limited availability of sample port locations and interferences with
-------
- 17 -
building and boiler structures, the same procedures were used under both
baseline and "low NOX" conditions. Therefore, the differences observed
in the results on particulate emissions and particulate carbon content
are felt to be representative of the relative effects of combustion
modifications on particulate emissions.
As expected, some side effects did develop under "low NOX" firing
conditions. Total quantities of particulates tend to increase but not
significantly and the consequences appear to be relatively minor. This
trend would have an adverse effect on the required collection efficiency
of electrostatic precipitators to meet present Federal emission standards,
but the increases required in precipitator efficiency appear to be quite
small based on these limited tests.
Another potentially adverse side effect of "low NOX" operation
with staged firing is that of increased carbon content of flyash. The
carbon content of the particulates with "low NOX" operation, according
to the results of the study, in some cases increased on front wall fired
boilers by as much as from 6 to 10.5% on the average and from 5 to 8% on
horizontally opposed fired boilers. However, the data are quite scattered,
and these increases do not appear to be directly related to the change in
emissions with "low NOX" firing techniques, or other boiler operating
variables. In the limited test data obtained, the debit due to increased
carbon on particulates, as discussed in Section 6.1.4 is offset at least
in part by the improved boiler efficiency due to the lower excess air
operation at "low NOX" conditions. Surprisingly, there is some evidence
that "low NOX" firing techniques for tangentially fired boilers decrease
carbon losses by about 25 to 40%. If this finding can be substantiated for
other tangentially fired boilers, a net credit may be applied to "low
NOx" operation of these units. Also it appears that "low NOX" firing
may decrease carbon losses for boilers fired with Western coals. Such
improvements, however, would not be substantial since unburned combustible
losses with the easy-to-burn Western coals are already low.
More data are needed on all types of boilers to substantiate
these findings. It is important to note, however, that no major adverse
side effects on particulate emissions appear to result from the application
of staged combustion and low excess air levels for NOX emission control
for the coal fired boilers tested.
2.3 Furnace Corrosion Testing
Corrosion of furnace sidewall tubes caused problems in the
early days of the development of pulverized coal firing in utility boilers.
A considerable level of effort was devoted to the solution of this problem
through actual field trials and in laboratory experiments to determine
the corrosion mechanism. Eventually practical solutions to the furnace
tube corrosion problem were found by increasing the level of excess air
and improving the fineness of pulverization so that oxidation of the
pyrites in the coal was complete before these ash particles could impinge
on the sidewall tubes. As practical solutions to this problem became
available, very little information on this subject was documented in
publications.
-------
- 18 -
For the purpose of reducing nitrogen oxide emissions from
boilers, decreasing the level of excess air has been practical as one
of the principal combustion modification techniques. The potential use
of this approach has resulted in a considerable amount of speculation and
apprehension that furnace sidewall corrosion problems might again be
encountered in coal fired installations. Consequently, boiler owners
have been reluctant to subject their units to long term tests to determine
potential corrosion problems associated with low excess air firing without
some evidence that the risks are not grave, particularly for staged firing
that produces a net reducing environment in some portions of the furnace.
For the above reasons, part of the current program was devoted
to obtaining "measurable" corrosion rates on probes exposed to actual
furnace conditions. The objective of this effort was to obtain data on
potential effects of "low NOX" firing conditions on furnace wall tube
corrosion rates. The approach used in obtaining these data was to
deliberately accelerate the rate of corrosion of coupons exposed to
temperatures in excess of normal tube metal temperatures of about 600°F.
It was decided that exposure for 300 hours at 875°F in susceptible furnace
areas would be sufficient to show major differences in corrosion rates
between coupons exposed to "low NOx" firing conditions and those exposed
under normal conditions.
Although there was some scatter in the data obtained, the
results showed some consistent trends. A major finding was that no major
differences in accelerated corrosion rates were observed between coupons
exposed to "low NOx", reducing conditions and those exposed under normal
boiler operating conditions. In fact, in some of the tests, the corrosion
rates were found to be lower under modified combustion operation than under
baseline conditions.
Since corrosion was deliberately accelerated for these corrosion
tests in order to develop "measurable" corrosion rates in a short time
period, the measured rates were much higher than normal tube wastage
experienced in actual furnace walls. In future tests, the coupons should
not be acid pickled prior to exposure in the furnace to remove oxide
coatings, and coupon temperatures should be reduced to obtain corrosion
rates more closely simulating actual tube wastage rates.
More information is required for assessing the importance of
furnace tube corrosion problems that may result from firing coal with
substoichiometric quantities of air. The data obtained in this program
helps provide evidence that furnace tube corrosion may not necessarily be
a severe side effect of combustion modification techniques for NOX emission
control. Long term "low NOX" tests using corrosion probes and the direct
determination of actual furnace wall tube corrosion rates by measuring
tube wall thicknesses are needed for a thorough assessment of the problem.
-------
- 19 -
2.4 Effects of Combustion Modifications
on Boiler Performance
Modifications of the combustion process for minimizing NOX
emissions in general tend to result in less intense combustion conditions,
Lowering the level of excess air supply increases flame temperatures
which aids combustion, but tends to limit the amount of oxygen available
for the combustion process. Thus, this factor directionally increases
the probability of burnout problems. Similarly, staged combustion burner
patterns, in which some burners are operated at substoichiometric
conditions, and the remaining burners are used as secondary or overfire
"air-ports" to complete the combustion of the fuel, can produce major
changes. These consist of further limiting the supply of available
oxygen in the initial combustion phase, lengthening the flames, and
slower diffusive mixing of air and fuel. Thus, this mode of operation
potentially increases unburned combustibles and, in turn, could have
an adverse effect on boiler efficiency.
During each major test at baseline and "low NOX" firing
conditions particulate dust loading data were obtained in accordance
with EPA recommended procedures. The particulate samples were analyzed
for carbon content (uncombustibles) and the differences in results from
tests at baseline and "low NOX" conditions provide an indication of
potential adverse side-effects. In addition, critical control room
board data and other information pertinent to boiler performance cal-
culations were recorded. Boiler efficiency was calculated for each
test following the ASME Abbreviated Efficiency Test heat loss method
using this information. The results are discussed in Section 6.1.4.
The conclusion reached from these performance data is that
there are no major performance debits with regard to boiler efficiency
when operating a boiler under "low NOX" emission conditions. Differences
discerned in boiler efficiency, if any, with "low NOX" firing were
negligible. This shows that, with proper controls, the problems discussed
above can be minimized or eliminated.
2.5 NOX Emissions for Boilers Converted
from Coal to Oil Firing
Very little information is available on the level and potential
control of NOX emissions for utility boilers converted from coal to oil
firing. For this reason, short-term emission tests were made on several
units of this type.
This section summarizes the emission field tests conducted on
utility boilers converted from coal to oil firing. Six units of this
type were tested, four of them at Atlantic City Electric Company's
Deepwater Station, and the other two boilers at that company's B. L.
England Station.
-------
- 20 -
Design and operating features of these six oil-fired boilers
tested are summarized in Table 2-5. All of the boilers tested at the
Deepwater Station are front-wall fired units having maximum continuous
ratings ranging between 23 MW and 83 MW gross load. The two cyclone-
fired boilers tested at the B. L. England Station have full load ratings
of 136 MW and 168 MW, respectively.
Table 2-6 summarizes the NOX emissions measured from these
coal-to-oil converted boilers tested.
In general, low NOX levels were measured even under normal,
baseline conditions. Thus, the baseline NOX emissions measured from
Deepwater Boilers No. 3 and 5 were found to be lower than the EPA new
source emission standard of 0.3 Ib NOX per million Btu fired, which is
equivalent to about 225 ppm, corrected to 3% 02, on a dry basis. For
Deepwater Boilers No. 8 and 9, the baseline NOX emissions were found
to be slightly above the 0.3 Ib/lO^ Btu level, but staged firing of
these boilers reduced the emissions from these boilers well below the
level of 0.3 lb/106 Btu.
As expected, the cyclone fired coal-to-oil converted Boilers No.
1 and 2 at ACE's B.L. England Station produced significantly higher NOX
emissions than the wall-fired units tested at Deepwater. In the case of
B.L. England No. 1, the baseline level was 441 ppm NOX (corrected to 3%
02, on a dry basis), compared with the 225 ppm equivalent of the 0.3
Ib/lO^ Btu recommended EPA standard. Similarly, the baseline NOX emissions
level from B.L. England Boiler No. 2 was 361 ppm, corrected to 3% 02 on a
dry basis. This is in line with the expected effect of the high temperature
environment prevailing in cyclone fired boilers, which are conducive to
relatively high NOX emission levels.
Staged firing of front wall fired Boilers No. 8 and 9 at the
Deepwater Station produced NOX emission levels well below the 0.3 Ib/lO^ Btu
level, even at full boiler load. Lowering the excess air level was
effective in all boilers tested (including the cyclone boilers), for
reducing NOX emissions, particularly in combination with staged firing.
The relative contribution of atmospheric nitrogen fixation and
chemically bound nitrogen oxidation NOX emissions can be estimated based
on the data of Turner et al., obtained in a modified packaged boiler (8).
The fuel oils fired at Deepwater averaged about 0.13 wt. % N content.
According to the fuel nitrogen conversion data, about 70% of the nitrogen
in the fuel is expected to be converted into NOX. Thus, roughly 130-140
ppm NOX would be predicted to be produced through the oxidation of fuel
nitrogen. When comparing this prediction with the actual NOX levels
measured, it appears that in all cases fuel nitrogen oxidation accounts
for significant portions, and in some cases, the bulk of the NOX emission.
Similar arguments can be made about the cyclone fired boilers at the B.L.
-------
TABLE 2-5
ATLANTIC CITY ELECTRIC COMPANY
SUMMARY OF COAL-TO-OIL CONVERTED BOILERS TESTED
Station
Deepwater
Deepwater
Deepwater
Deepwater
B. L. England
B. L. England
Blr No.
3
5
8
9
1
2
Blr Mfr.
B&W
B&W
B&W
CE
B&W
B&W
Type of
Firing
FW
FW
FW
FW
Cyc.
Cyc.
MCR
(MW)
57
56
83
22.8
133
168
No. of
Burners
6
6
16
6
3
4
Test No. of
Variables Test Runs
5 8
4 4
14 25
6 7
4 7
2 2
-------
TABLE 2-6
ATLANTIC CITY ELECTRIC COMPANY
SUMMARY OF NOX EMISSIONS
FOR COAL-TO-OIL CONVERTED BOILERS
NOX Emissions
Boiler
Depwater No. 3
Deepwater No. 5
Deepwater No. 8
Deepwater No. 9
B.
B.
L. England No. 1
L. England No. 2
Operating Mode
(Gross Load-MW) %
Baseline
"Low NO "
X
Baseline
"Low NO "
X
Baseline
"Low NO "
X
Baseline
"Low NO "
X
Baseline
"Low NO "
X
Baseline
"Low NO "
(57)
(57)
(56)
(56)
(83)
(81)
(23)
(21)
(133)
(132)
(167)
(167)
6
5
4
2
4
4
1
2
1
0
2
1
_°2.
.1
.0
.2
.8
.5
.4
.8
.6
.5
.5
.2
.6
ppm
(3% 02)
142
118
221
209
246
123
286
101
441
313
361
303
Ib
10b
-
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
Btu
-
29
28
33
16
38
13
59
42
48
42
Gr/106 Cal
-
0.
0.
0.
0.
0.
0.
1.
0.
0.
0.
-
52
50
59
29
68
23
06
76
86
76
CO
ppm
(3% 02)
67
81
55
84
49
64
44
64
57
1523
85
231
N3
NJ
-------
- 23 -
England Station, where fuel nitrogen contribution to NOX emissions is
expected to be significant, but proportionately less because of the more
intense combustion conditions. Therefore, the use of combustion modifica-
tion techniques, if possible on cyclone fired installations might become
necessary if high nitrogen content fuel oils or other liquid fuels (such
as coal liquids or shale oil) are fired in such boilers.
In conclusion, much valuable information has been obtained in
this test program on the levels of NOX emissions and their potential
control in boilers converted from coal to oil firing. Although further
emission data are needed for establishing broad generalizations for this
type of equipment, it may be concluded that the NOX response of such
units to combustion modifications is similar to that of boilers designed
for oil firing. In fact, the furnace characteristics of coal-fired boilers
converted to oil firing are expected to favor the control of NOX emissions
through combustion modifications, because of the more liberal sizing of
coal fired furnaces, which should result in higher heat removal rates
when firing oil.
-------
- 24 -
3. EFFECT OF ELECTROSTATIC
PRECIPITATORS ON NOX FORMATION
Electrostatic precipitators are used extensively for reducing
particulate emissions for coal fired, steam-electric plants. High
voltages across electrodes in this equipment create a corona discharge
that ionizes gas molecules and electrically charges particles passing
through the field. The charged particles are attracted to oppositely
charged surfaces where they can be removed from the flue gas.
The effect of electrostatic precipitation on NOX formation is
not clear. It is possible that the corona discharge (or perhaps arcing)
forms ozone and atomic oxygen, which form nitrogen oxides through reactions
with nitrogen.. However, data reported to date have not resolved this
question since both increases and decreases of NOX have been found (I) .
As part of the present field test program, emission measurements
were made upstream and downstream of the precipitator in the A and B flue
gas ducts of Boiler No. 4 at the Barry Power Station of the Alabama Power
Company, in an attempt to shed more light on this potential problem. The
precipitators of Boiler No. 4 at the Barry Station are well suited to such
tests, as the ash removal system at present is incapable of removing the
flyash collected in the precipitator collection hoppers sufficiently rapid.
This results in a build-up to a point where the plates are shorted and
arcing occurs. It has been expected that this condition may promote the
formation of NOX, if any occurs.
Table 3-1 summarizes gas analyses taken before and after the
Barry A and B precipitators with the precipitators on and off. All data
reported have been corrected to 3% G£ in the flue gas for comparison
purposes. Analysis of the data shows that there are no statistically
significant differences in NOX values measured upstream and downstream
of the precipitators on either the A or B sides. It is concluded from
these tests that either the conditions required for the formation of
NOX in precipitators were not present in these tests, or more likely,
that there is no net production of NOX from the precipitators. Additional
research, over a variety of both corona discharge as well as arcing opera-
tions is needed to better quantify the effect of electrostatic precipitators
on NOX formation in flue gas from coal fired boilers.
As reported earlier in our "Systems Study" (1) , electric
discharge precipitation has been successfully used to remove NO from
manufactured gas (10). However, it appears that unsaturated hydrocarbons
are essential for NO removal (11) by this method. Since power plant flue
gases contain negligible amounts of unsaturates, such compounds would
have to be added at prohibitively high costs to use such a proposed method
(12) for power plant NOX emission control.
-------
- 25 -
TABLE 3-1
NOx EMISSION MEASUREMENTS TESTS ACROSS THE ELECTROSTATIC PRECIPITATOR
ALABAMA POWER COMPANY BARRY, BOILER NO. 4
(NOX
Avg.
Avg.
Avg.
Avg.
Avg.
Avg.
Concentrations in ppm, Corrected to 3% 0~, Dry Basis)
I. Precipitator Off - A Side
Before
Probe
414
401
407
407
Before
Probe
428
431
436
432
Before
Probe
389
400
405
398
*>
Before
Precipitator
1 Probe 2
388
380
381
383
^ J
395
II. Precipitator
Precipitator
1 Probe 2
417
424
416
4J9
426
III. Precipitator
Precipitator
1 Probe 2
371
387
399
386
•— • *~^._ ,*^*™ ^^f
372
IV. Precipitator
Precipitator
Probe 1 Probe 2
Avg.
Avg.
411
411
413
412
404
464
406
405
— •v -'
408
After Precipitator
Port a Port b
Short 386 401
Medium 373 414
Long 376 422
Ave. ^378 412,
Avg. 395
On - A Side
After Precipitator
Port a Port b
Short 420 416
Medium 421 416
Long 429 427
Ave. ^423 420^,
Avg. 422
Off - B Side
After Precipitator
Port a Port b
Short 373 383
Medium 404 392
Long 392 393
Ave. V390 389V
Avg. 394
On - B Side
After Precipitator
Port a Port b
Short 398 379
Medium 400 387
Long 403 394
Ave. ^400 38J
Avg. 394
-------
- 26 -
4. FIELD STUDY PLANNING AND PROCEDURES
This section discusses the major steps involved in field study
planning and the test procedures used to obtain emission and corrosion
measurements. Field study planning steps included developing boiler
selection criteria, establishing EPA/Exxon/Boiler Operators/Boiler
Manufacturers cooperation, and designing an effective test program strategy.
Testing procedures included gaseous sampling and analyses, particulate
sampling and corrosion probing. Methods of gaseous emission testing
were quite similar to those used in Exxon's "Systematic Field Study" (4-6) •
Particulate loadings of the flue gas stream, and the carbon content of the
particulates were also determined to identify potentially adverse side-
effects. In addition, corrosion probes were designed, and acclerated cor-
rosion test measurements were conducted under baseline and low NOX operations.
4.1 Program Design
As discussed earlier in this report, the major problem area in
reducing NOX emissions by combustion modification is to apply such
techniques to coal fired boilers. Coal fired utility boilers are the
largest single source of stationary NQx emissions in the United States,
i.e., 3 million tons NOX estimated for 1970, compared to 0.5 million tons
for gas, and 0.3 million tons for oil firing (1) . The operating flexibility
of coal fired boilers is generally less than that of oil or gas fired
boilers. This section will discuss the criteria developed and the coopera-
tive efforts required for selecting representative coal fired boilers, as
well as the broad testing program strategy developed for efficiently
measuring gaseous emissions, particulate emissions, and accelerated cor-
rosion rates.
4.1.1 Boiler Selection Criteria
Criteria recommended for selection of coal fired boilers were
classified into five groups which are discussed in turn below: (1) boiler
design factors, (2) boiler operating flexibility, (3) boiler measurement
and control capability, (4) boiler operating management policy concerning
research and operating practices and (5) logistic and scheduling considerations,
Boilers representing the current design practices of the
utility boiler manufacturers (Babcock and Wilcox, Combustion Engineering,
Foster Wheeler and Riley-Stoker) were desired. Design factors such as
size (150 MW or larger), type of firing (wall tangential, turbo-furnace
and possibly cyclone), furnace loading (normal, not extreme), burner con-
figuration (size, number and spacing), draft system (both balanced draft
and pressurized), and furnace bottom design (wet and dry bottom) were
considered.
-------
- 27 -
Boiler operating flexibility was a prime consideration in
selecting boilers. Specific variables (with the desired operating
ranges listed ln parentheses) were: excess air level (5-30%), furnace load
with all burners firing (60 to 100% of maximum continuous rating),
staged firing (individual burners or rows of burners on air only, or
biased firing of individual burners), air register settings (20% to
100% open), combustion air preheat temperature (100°F variation),
wind box pressure (low to high, over wide ranges of furnace load'and
excess air levels), fuel burned (coal types characteristic of major
U.S. regions), flue gas recirculation (location of injection point
and amount recirculated) and independent steam temperature controls
(attemperation water, burner tilt, air register flexibility, adequate
soot blower capacity, etc.).
Boilers vary considerably with regard to their operating
parameters, and measurement and control capabilities. These capabilities
are needed to assure accurate, quantative measurements representing
each operating condition, and to maintain stable operations during
each test run. Key measurements needed are fuel, air and water tem-
peratures and feed rates; steam temperatures, pressures and flow rates;
and flue gas component measurements of oxygen, combustibles, smoke,
and temperatures. In addition, furnace viewing ports should be avail-
able for visual inspection of furnace conditions such as burner flames
and slag buildup, in order to monitor potential problem areas during
each test run. Also, ports are needed for sampling coal supplied to or
from the pulverizers, sampling the flue gas before air preheaters,
sampling particulates before precipitators, and for inserting corrosion
probes in furnace sidewalls.
The attitude of the utility station operating management
towards research programs, and their operating practices are other key
elements affecting the productivity of field programs. Operating
management support includes providing the necessary technical, super-
visory and^ operating personnel for both planning and conducting the test
program. "Research-mindedness" means support for exploiting the full
range of boiler operating flexibility in the test program. A willingness
to schedule boiler load changes, to provide expert help in pre-test
boiler checkout, including the calibration of key boiler instruments,
and to use experienced plant people for coal sampling and analysis is
the result of a constructive management policy towards research programs.
The criteria discussed above are extremely useful,in selecting
candidate boilers for testing. Individual boilers can then be selected
to provide maximum overall program effectiveness and efficiency by
taking into account total schedule and logistic considerations. Thus,
utilities and stations should be so selected that they would offer a
number of boilers suitable for testing to minimize travel and set-up
time, and provide flexibility in case of unplanned boiler shutdowns,
with appropriate availability and load range.
-------
- 28 -
4.1.2 EPA/Exxon/Boiler Operators/
Boiler Manufacturers Cooperation
This cooperative program of field testing utility boilers was
conducted by Exxon Research with the cooperation of utility boiler opera-
tors and manufacturers under the coordination of EPA. The proper selection
of boilers representing current design practices for this program was
the result of a cooperative planning effort. Exxon Research developed
the comprehensive list of selection criteria discussed above to assist
EPA and boiler manufacturers in preparing a list of potential boiler
candidates. Each boiler manufacturer submitted a list of suggested
boilers to EPA for review and screening. After consideration of such
factors as design variables, operating flexibility, fuel type, geographic
location and logistics, a tentative list of boilers was selected by EPA
and Exxon. Field meetings were then held at power stations to confirm
the validity of the boilers selected and to obtain necessary boiler
operating and design data.
The field meetings were attended by representatives of EPA,
Exxon Research, boiler manufacturers and utility boiler operating manage-
ment. EPA described the background and need for developing emission
control technology for coal fired boilers, and how this fits into the
overall EPA program. Exxon Research presented a broad summary of pre-
vious findings, and an outline of the three-phase program to be run at
each boiler. This led to the discussion aimed at developing the informa-
tion necessary to construct a detailed program plan. These discussions
produced a mutually agreeable list of combustion operating variables, the
specific levels to be tested, estimated ease and length of time to change
from one level to another, how the variables were interrelated, and what
operating limitations or restrictions might be encountered. In addition,
the proper number and specific location of sampling ports for gaseous,
particulate, and corrosion probes were also agreed upon. If existing
sampling ports were not adequate, new ports were installed by the
utility. Tentative testing dates were scheduled with provisions made
for possible segregation of coal types, scheduling of pre-test boiler
inspection, calibration of measuring instruments and controls, scheduled
maintenance, and other preparatory steps.
The excellent support and cooperation provided by boiler
manufacturers and utility boiler operators contributed significantly
to the success of this program.
4.1.3 Test Program Strategy
The up-to-date, comprehensive information obtained in field
meetings provided the necessary data for Exxon to develop detailed,
run-by-run, proposed test program plans for review by all interested
parties. Each test program, tailored to take full advantage of the
-------
- 29 -
particular combustion control flexibility of each boiler, was comprised
of three phases: (1) short test-period runs, (2) a 1-3 day sustained
"low NOx" run and (3) 300-hour sustained "low NOX" and normal operation
runs. Thus the strategy used for field testing coal-fired boLlers consisted
first, of defining the optimum operating conditions for NOx emission con-
trol, without apparent unfavorable side effects in short-term statistically
designed test programs. Second, the boiler was operated for 1-3 days under
the "low NOx" conditions determined during the optimization phase, for
assessing boiler operability problems. Finally, where possible, sustained
300-hour runs were made under both baseline and modified ("low NOX")
operating conditions. During this period, air-cooled carbon steel coupons
were exposed on corrosion probes in the vicinity of furnace water tubes,
to determine through accelerated corrosion tests whether operating the
boiler under the reducing conditions associated with staged firing
results in increased furnace water tube corrosion, rates. Particulate
samples were obtained under both baseline and "low NOY" conditions.
A.
Engineering information on boiler operability, e.g., on slagging problems,
and data related to boiler performance were also obtained.
Statistical principles (as discussed in more detail in our
"Systematic Field Study" (4)) provided practical guidance in planning
the Phase 1 test programs, i.e., how many, and which test runs to conduct,
as well as the proper order in which they should be run. These procedures
allow valid conclusions to be drawn from analysis of data on only a small
fraction of the total possible number of different test runs that could
have been made. Table 4-1 will be used to illustrate briefly these principles
applied to a front-wall fired boiler, TVA's Widows Creek Boiler No. 6.
(Tangentially fired boilers present a more complex problem in experimental
planning, since there are additional operating variables such as burner
tilt and secondary air register settings, that should be included in the
experimental design. However, the same statistical principles apply.
In this example, there are four operating variables: (1) load, (2)
excess air level, (3) secondary air register settings, and (4) burner
firing pattern. Assuming three levels of each of the first three
variables, and eight different firing patterns available at each load,
there are 216 different operating modes. However, only the 33 test runs
shown, i.e., 15% of the potential maximum, provided the required informa-
tion on this boiler to define practical "low NOX" operating conditions.
Test run No. 10 operating conditions were chosen for the second
phase of the experimental program, while test run No. 26 operating condi-
tions are recommended for "low NOX" operation under reduced load condi-
tions. Test run No. 10 conditions could be selected with considerable
confidence, since examination of the data indicates that each of the 83
firing pattern runs produced lower NOX levels than did the corresponding
82 firing pattern. The effects of day-to-day variables, such as coal
type variability, etc. not under study were balanced between the two
firing patterns, since runs No. 5, 6, 7 and 8 were made on one day,
while runs No. 9, 10, 11 and 12 were run on another day. It should also
-------
TABLE 4-1
TEST PROGRAM EXPERIMENTAL DESIGN - WIDOWS CREEK, NO. 6
(Run No., Average % 0~ and Average PPM NO Emissions (3% 00, Dry))
^ x i.
Tjjj-j^econdary
Pattern -Air^
Si - 16 Coal
0 Air Only
S2 - 14 Coal
D]^D4 Air
S3 - 14 Coal
A^A^ Air
84 - 12 Coal
A1A3A3A4
S5 - 12 Coal
A1A4B2B3
85 - 12 Coal
A1A4B1B4
S? - 12 Coal
A1A4°1D4
Sg - 12 Coal
B1B2B3B4
1^ - Rill Load (125 MW)
A. - Normal Air
20%
Open
(3) 2.8%
610
(11) 3.8%
632
(7) 4.5%
532
60%
Open
(1) 3.2%
577
(5) 4.0%
558
(9) 4.1%
518
A~ - Low Air
20%
Open
(4) 1.9%
505
(6) 2.0%
372
(10)* 1.7%
345
60%
Open
(2) 2.0%
491
(12) 1.5%
406
(8) 2.7%
368
L2 - Reduced Load (80 - 110 MW)
A. - Normal
20%
Open
(31) 4.9%
681
(24) 4.5%
399
(27) 4.9%
496
(15) 5.2%
471
(18) 4.3%
418
60%
Open
(29) 4.8%
629
(13) 4.5%
460
(17) 4.4%
480
(21) 6.1%
550
(25) 4.5%
495
A- - Low Air
20%
Open
(32) 2.8%
464
(26)** 2.7%
297
(22) 3.4%
306
(19) 3.1%
301
(16) 2.9%
329
60%
Open
(30) 2.7%
450
(20) 3.0%
345
(14) 2.6%
342
(28) 4.5%
438
(23) 3.9%
438
(20A) 2.2%
*** 371
w
o
**
***
"Low NOX" operation selected for sustained run.
"Low NOx" operation at reduced load
Unplanned run 20A was conducted to obtain additional
information when pulverizer B was down due to
mechanical problems.
Pulverizer— Burner
Configuration
Mill Burner No.
A-Top
B-2nd
C-3rd
D-Bot
Row
Row
Row
, Rov
1
0
0
0
0
2
0
0
0
0
3
0
0
0
0
4
0
0
0
0
-------
- 31 -
be noted that each day's runs completed a one-half replicate of the
complete factorial accomplished by two days of testing. Thus, the
main effects of each factor and interactions between factors could
be estimated independently of each other, with maximum precision.
Repeat test runs under test run 10 conditions, during a two-day
sustained period, were used to validate these results and to obtain
an independent estimate of experimental error.
4.2 Test Procedures
This section of the report describes the procedures used
for performing field tests on utility boilers. Flue gases were
sampled and analyzed for gaseous species in each of the boiler test
programs. To assess potentially adverse side-effects of combustion
modification techniques on particulate emissions (including carbon
losses in the flyash) and on furnace water-wall corrosion rates,
particulate measurements and accelerated corrosion rate determinations
were also made for a number of boilers tested in this study.
4-2.1 Gaseous Sampling and Analysis
The objective of obtaining reliable gaseous emission data in field
testing boilers requires a sophisticated sampling system. The sampling and
analytical system used in this program has already been described in detail
in the Esso Research and Engineering Company Report, "Systematic Field Study
of NOX Emission Control Methods for Utility Boilers" (4).
For the present study, further capabilities were added to the
analytical instrument train by installing a Thermo-Electron chemiluminescent
analyzer to provide measurements of NO and NOX in addition to those obtained
with the Beckman NO and N02 spectroscopic monitors. Figure 4-1 is a
schematic diagram of the configuration of the gaseous sampling and
analytical system used in the present study.
Since samples are taken from zones of "equal areas" in the flue
gas ducts, gas sampling probes are "tailor-made" for each individual boiler
tested. Three stainless steel sampling tubes (short, medium, and long) are
fabricated on the test-site, and installed in quick-disconnect mounting probe
assemblies, along with a thermocouple located at the mid-point of the duct
for gas temperature measurement. At least two probes of this type are installed
in each flue gas duct, or a minimum of four are used when there is only one
large flue duct on the boiler. Thus, a minimum of 6 sample points per duct,
or 12 per boiler are provided, assuring representative gas samples. All
connections between the Esso Analytical Van and the probes are of the
quick-disconnect type for ease of assembly and assurance of leak-proof
joints.
In running field tests, the gas samples are withdrawn from the
boiler under vacuum, through the stainless steel probes to heated filters
where the particulate matter is removed. These filters are maintained
-------
PROBE (4 EACH)
THERMOCOUPLE
FIGURE 4-1
EXXON RESEARCH TRANSPORTABLE SAMPLING
AND ANALYTICAL SYSTEM
BOILER
DUCT
800°F
PITOT TU BE
500°F
PARTICULATE FILTERS (HEATED)
ROTAMETERS
35 F
HEATED
LINES
CO
HYDROCARBONS
NO & NO [
REFRIGERATOR
200 FT
SOLENOID
VALVE
SAMPLING
VAN
I
UJ
N3
->V5 PSI RELIEF
VALVE
-------
- 33 -
at 300-500°F. The gases then pass through rotameters, which are followed
by a packed glass wool column for 803 removal. Initially, gas tempera-
tures are kept as high as possible to minimize condensation in the par-
ticulate filters. After leaving the packed column at 250-300°F, the
gas samples pass at temperatures above the dew-point through heated Teflon
lines to the vacuum/pressure pumps. The sample is then refrigerated to a
35 F dew-point before being sent to the van for analysis. Usually, the van
is located 100 to 200 feet from this point and the gas stream flows through
Teflon lines throughout this distance.
As in our previous studies (4-6), our analytical van was equipped
with Beckman non-dispersive infrared analyzers to measure NO, CO, C02 and S02,
a non-dispersive ultraviolet analyzer for N02 measurement, a polarographic 02
analyzer and a flame ionization detector for hydrocarbon analysis. The
Thermo-Electron chemiluminescent instrument, as indicated above, was added
to provide improved capabilities for NO and NOX measurements. The measuring
ranges of these continuous monitors are listed in Table 4-2.
A complete range of calibration gas cylinders in appropriate
concentrations with N2 carrier gas for each analyzer is installed in
the system. Instruments are calibrated daily before each test, and
in-between tests if necessary, assuring reliable, accurate analyses.
Boiler flue gas samples are pumped continuously to the
analytical van through four probes, each of which combines the effluent
of three individual sampling tubes. While one sample is being analyzed,
the other three are being vented. Switching to a new sample requires
only the flushing of a very short section of sample line before reliable
readings may be obtained. Four duplicate sets of analyses from each probe
can be obtained in less than 32 minutes, thus speeding up the task of
obtaining reliable gaseous emissions, and/or avoiding the need to hold
the boiler too long at steady state conditions.
The validity of using the Thermo-Electron chemiluminescent NO/NO
analyzer as the primary NOX monitoring instrument was checked during the
first series of tests conducted in this program, on TVA's Widows Creek Boiler
No. 6. As shown in Figure 4-2, the NOX data measured with the chemiluminescent
analyzer were correlated with the sum of NO plus N02 data measured with the
Beckman non-dispersive infrared NO and non-dispersive ultraviolet N02
instruments. As seen from the regression in Figure 4-2, excellent agreement
was obtained between the chemiluminescent monitor was validated against the
spectroscopic instruments, which in turn had been validated against a variety
of other technqiues, including the wet chemical phenoldisulfonic acid method
in previous Exxon field studies (4-6).
Our instrumental measurement technique for flue gas 02 and COo
analyses were validated periodically by checking against Orsat determina-
tions made on samples taken from the same points. Measured 02 vs. C02
x
-------
- 34 -
TABLE 4-2
CONTINUOUS ANALYTICAL
INSTRUMENTS IN EXXON VAN
Beckman
Instruments
NO
Technique
2
co2
CO
so2
Hydrocarbons
Non-dispersive Infrared
Non-dispersive ultraviolet
Polarographic
Non-dispersive infrared
Non-dispersive infrared
Non-dispersive infrared
Flame ionization detection
Measuring
Range
0-400 ppm
0-2000 ppm
0-100 ppm
0-400 ppm
0-5%
0-25%
0-20%
0-200 ppm
0-1000 ppm
0-23,600 ppm
0-600 ppm
0-3000 ppm
0-10 ppm
0-100 ppm
0-1000 ppm
Thermo Electron
NO/NO
Chemiluminescent
0-2.5 ppm
0-10.0 ppm
0-25 ppm
0-100 ppm
0-250 ppm
0-1000 ppm
0-2500 ppm
0-10,000 ppm
-------
FIGURE 4-2
>l
II
ra
tf
w
CM
g
i
O
W
CQ
CQ
700
600
500
400
300
200
100
Z
NOx REGRESSION - BECKMAN NO + NO2 VS
CHEMILUMINESCENCE NOx MEASUREMENTS
/
y= 0.42 + 1.0172X
r = 0. 985
Sy(est) = 19 ppm NO
i
OJ
ALL READINGS EXPRESSED AS
PPM NOx, CORRECTED TO 3%
O, DRY BASIS.
100
200
300
400
500
600
700
800
PPM NO BY CHEMILUMINESCENT ANALYZER (X)
X
-------
- 36 -
relationships were also compared with those calculated from the
analysis of the actual fuel fired and different excess air levels. In
addition frequent cross checks of flue gas Q£ content were also made
with a portable polarographic (Beckman) instrument to make certain that
van instrument measurements were accurate and reliable.
The comparison of measured to calculated 02 vs. CC>2 relationships
is shown in Figure 4-3, based on data obtained in testing TVA's Widows
Creek No. 6 Boiler. As can be seen from Figure 4-3, the agreement between
the regressions based on measurements and calculations is very good over
the range of actual measurements.
4.2.2 Particulate Sampling
Modifications of the combustion process for minimizing NOX
emissions in general tend to result in less intense combustion conditions.
Lowering the level of excess air supply increases flame temperatures which
aids combustion, but tends to limit the amount of oxygen available for
the combustion process. Thus, this factor directionally increases the
probability of burnout problems. Similarly, staged combustion burner
patterns, in which some burners are operated at sub-stoichiometric con-
ditions, and the remaining burners are used as secondary or overfire
"air-ports" to complete the combustion of the fuel, can produce major
changes. These consist of further limiting the supply of available oxygen
in the initial combustion phase, lengthening the flames, and slower dif-
fusive mixing of air and fuel. Thus, this mode of operation potentially
increases unburned combustibles. Also, the actual amount and character
of particulate matter in the flue gases may be affected by modified com-
bustion operation. Therefore, it appeared necessary to take into account
that combustion modifications applied for minimizing NOX emissions could
potentially increase particulate emissions from pulverized coal-fired
boilers.
To satisfy the need for this type of information, this field
test program on coal fired boilers included measurement of particulate
emissions. The objective of this effort was to obtain sufficient par-
ticulate loading information to determine the potential adverse side effects
of "low NOX" combustion modifications on particulate emissions by comparing
measurements of total quantities and per cent unburned carbon with
similar data obtained under normal or baseline operating conditions.
Other information, such as changes in particle size distribution or
in flyash resistivity which could affect electrostatic precipitator
collection efficiency is also needed. However, measurements of this
type were beyond the scope of the present program.
Four Research Appliance Company EPA-type particulate sampling
trains designed in accordance with EPA Method 5 (9), including four sample
boxes, probes, and two sets of isokinetic pumping systems were used for
obtaining particulate loading data on six pulverized coal fired utility
-------
18
- 37 -
FIGURE 4-3
RELATIONSHIP BETWEEN % CC>2 AND
% O2 FLUE GAS MEASUREMENTS
(WIDOWS CREEK, BOILER NO. 6-1B)
>H
II
S 16
ro
^
PQ
14
O
w
£3
Psl
O
0
12
CALCULATED FROM
COAL ANALYSIS
(Y- 18. 5-0. 88% O0)
CALCULATED FROM FLUE GAS ANALYSIS
(Y= 18.4-0. 95% 09)
0
% O2 IN FLUE GAS (DRY BASIS)
-------
- 38 -
boilers. The names of the utilities and details of the boilers tested
for particulate emissions are indicated in Table 2-1. Except for tests at
Utah Power & Light Company's Naughton Station, Boiler No. 3, all particulate
mass data for dry, filterable solids loadings were obtained in the
ducting at convenient locations downstream of the air-heaters. At the
Naughton Station particulate testing was done upstream of the air-heaters,
due to the inaccessibility of sampling locations downstream of the air
heaters. Furthermore, at Alabama Power Company's Barry Station Boiler No. 4
particulate sampling was carried out downstream of the precipitator (with
the precipitator shut off), in a location immediately before entering the
stack. For all tests, two duct traverses were made with one probe assembly
in each duct, in accordance with the procedures of Method 5 (9). However,
strict adherence to EPA-recommended test method was not always possible
due to the limited availability of sample port locations, interferences
with building and boiler appurtenances, and the limited time and manpower
available for these tests. However, it should be remembered that the
objective of these tests was not to measure absolute values of particulate
emissions, but to determine relative changes between normal and modified
firing operations. Therefore, it was felt that information obtained on
relative changes in particulate emissions under normal and modified boiler
operating conditions would suffice for determining potential side-effects
of combustion modification techniques.
A.2.3 Furnace Corrosion Rate Measurements
Pulverized coal fired boilers are subject to wastage of the
furnace wall tubes. Normally, this type of corrosion is experienced in
areas where localized reducing environments might exist adjacent to the
midpoint of furnace sidewalls near burner elevations where flame impinge-
ment could occur. To counteract such effects, normal practice is to increase
the excess air level so that an oxidizing atmosphere prevails at these
locations, and to increase the fineness of pulverization, so that the
oxidation of the pyrites in the coal is completed before these species
can come into contact with the furnace wall tubes. For new boilers,
a design improvement consists of increasing the separation between the
burners and the sidewalls, for minizing potential impingement problems.
Several mechanisms have been postulated for this type of corrosion which
appears to be associated with the formation of pyrosulfates from the
coal ash (at 600-900°F), and iron sulfide, or S03 from the pyrites.
Combustion modifications for NOX emission control are generally
most effective at low excess air or substoichiometric air supply condi-
tions in the flame zone, i.e., under conditions that are potentially
conducive to furnace tube wall corrosion. Our prior field tests of
coal-fired boilers have been of short duration, allowing no time to
assess such side-effects. However, the need for evaluating the effects
of modified firing operations on furnace tube wall corrosion has been
recognized (13). Discussions with boiler manufacturers and operators
indicated that this potential problem was one of their major concerns.
-------
- 39 -
Also it became evident that accelerated corrosion rate testing would be
necessary to establish that staged combustion could be used in coal-
fired boilers without creating corrosion problems, because of the
reluctance to operate on a long-term basis using the boiler as a test
medium.
Accordingly, a third aspect of our field testing was to design
and construct corrosion probes, for exposure under controlled conditions
to define the extent of the potential corrosion problem. The objective
of our furnace corrosion probing runs was to obtain "measurable" cor-
rosion rate data to determine potential side effects of "low NOX" firing
conditions on furnace wall tubes.
The approach used for obtaining corrosion rate data was to
expose corrosion probes inserted into available openings located at
"vulnerable" areas of the furnace under both baseline and staged firing
conditions. Based on general corrosion probing experiments, it was
concluded that exposure for approximately 300 hours at elevated coupon
metals temperatures (above normal furnace tube metal temperatures of
about 600°F) to accelerate corrosion, would produce "measurable" rates
of corrosion on SA-192 carbon steel coupon material, used for the manu-
facture of furnace water tubes. Since our objective was to show relative
differences in corrosion, between baseline and "low NOX" firing, exposure
temperatures at both conditions were set at approximately 875OF. Compared
with normal tube wall temperatures this was sufficiently high to accelerate
the rate of corrosion. At the same time, the comparison temperature was
kept below the 900°F limit above which pyrosulfates apparently are not
formed.
Figures 4-4 and 4-5 show details of the corrosion probes
developed for this study based on a design supplied by Combustion Engineering.
Essentially, this design consists of a "pipe within a pipe", where the
cooling air from the plant air supply is admitted to the ring-shaped
coupons exposed to furnace atmospheres at one end of the probe, through
a 3/4-inch stainless steel tube roughly centered inside of the coupons.
The amount of cooling air is automatically controlled to maintain the
desired set-point temperature of 875°F for the coupons. The cooling air
supply tube is axially adjustable with respect to the corrosion coupons
so that temperatures of both coupons may be balanced. To simplify the
presentation, thermocouples mounted in each coupon are not shown in
Figures 4-4 and 4-5. Normally, one thermocouple is used for controlling
and the other one for recording temperatures. The cooling air travels
backwards along the 2-1/2-inch extension pipe and discharges outside of
the furnace. Thus, the cooling air and the furnace atmosphere do not mix
at the coupon location.
A 1/4-inch stainless steel tube is provided in the probe
assembly (Figures 4-4 and 4-5) with an opening on the furnace side in
the vicinity of the furnace wall tubes and corrosion coupons. Furnace
-------
- 40 -
gases may be drawn through this sampling tube for analysis to determine
the type of atmosphere (reducing or oxidizing) prevailing at the coupon
location. Sampling at the various probes during corrosion testing always
showed a net excess of oxygen. Normally the CO levels measured at
these locations were low but in a few cases they exceeded the upper
range of the CO instrument (23,000 ppm). This happened (as expected)
when measured 02 concentrations (0.1-0.2%) were very low. Therefore, in
these isolated instances the atmosphere was net reducing because of the
net excess of CO over oxygen.
Sustained, 300-hour corrosion probe tests were run on boilers
of four utility companies, as shown in Table 4-3.
TABLE 4-3
SUMMARY OF CORROSION PROBING TESTS
Utility
Georgia Power Co.
Utah Power & Light Co.
Arizona Public Service Co.
Alabama Power Co.
Station
Harllee Branch
Naughton
Four Corners
Barry
Boiler Number
Base "Low NOY"
4 3
3
5
4
4
4
Type of Firing
Horizontally Opposed
Tangential
Horizontally Opposed
Tangential
-------
FIGURE 4-4
CORROSION PROBE
DETAIL OF 2-1/2" IPS EXTENSION PIPE AND END PLATE
(OUTSIDE OF FURNACE)
DRILLED AND TAPPED FOR 1/8'HPT THREAD
(SWAGELOCK FITTINGS - FOR THERMOCOUPLES)
\
s—XfD
/ \TO ACCEBT
( /1/2" SS ABR
V /SUPPLY
^ TUBING
2-1/2" I.P.S. PIPE
EXTENSION
1/16" THERMOCOUPLES (2)
AIR SUPPLY
(3/4" SS TUBING)
1/4" GAS SAMPT.TNH TURING (S
SEAL
WELD
HOLE FOR 1/4" SS END PLATE
GAS SAMPLING TUBE
SWAGELOCK FITTING DRILLED FOR 1/2" SS AIR
SUPPLY TUBE (THREADS CUT OFF AND FITTING
WELDED OR SILVER SOLDERED TO END PLATE)
WELD
AIR DISCHARGE
1-1/4" COUPLING
-------
FIGURE 4-5
CORROSION PROBE
DETAIL OF CORROSION COUPON ASSEMBLY
(INSIDE OF FURNACE)
2-1/2" PIPE EXTENSION
\
1/4" S.S. GAS
SAMPLING TUBE
3/4" S.S. COOLING AIR SUPPLY TUBE
THERMOCOUPLE SOCKETS
END CAP
CORROSION
COUPONS
ho
I
FACE OF FURNACE WALL TUBES
-------
- 43 -
5. COMBUSTION VARIABLES
Our Systematic Field Study of NOX Emission Control Methods
for Utility Boilers (1) was designed to explore the broad limits of short-
term applicability of combustion modification on a representative sample
of gas, oil and coal fired boilers. The major combustion operating
variables explored were: (1) load reduction, (2) low excess air firing,
(3) staged combustion, (A) flue gas recirculation, (5) air preheat
temperature, (6) burner tilt, (7) auxiliary to coal air damper settings,
and (8) secondary air register settings. In our current field test pro-
gram, prime interest centered on coal fired boilers; first, to determine
the optimum combination of combustion variables, as listed above, for
NOX emission reduction in short-period tests and second, to determine if
slagging, corrosion or other operating problems were experienced in
extended period tests under "low NOX" operation. Other emissions (CO,
hydrocarbons, and particulates) were also measured to determine whether
they were adversely affected.
In this section, the major combustion variables investigated
are discussed in general terms, while the details of the results obtained
from each boiler tested are given in Section 6.
5.1 Load Reduction
Since load reduction is an economically unattractive method
for reducing NOX emissions, the major emphasis in this program was to
determine the NOx reduction capability of boilers at full or maximum
possible load levels using combustion modifications for effective NOX
emission control. However, as shown by our overall correlations of
gross load per furnace firing-wall and by the individual boiler results,
reducing load in coal fired boilers generally reduced NOx emissions by
a lower percentage than the percentage reduction in load. Reduced load
operation reduces the heat release per unit of furnace area or volume,
lowers effective peak flame temperatures and thus lowers the thermal
fixation of nitrogen in the furnace. In addition, low loads generally
require operation at higher excess air levels than at full load and the
increased availability of oxygen in the flame tends to increase NOX
emissions.
5.2 Low-Excess Air Firing
Low excess air firing is an effective method for NOX emission
control of coal fired boilers, alone and in combination with other com-
bustion variables such as staged firing. This relationship is shown most
clearly by expressing the excess air level as % stoichiometric air to
active burners. Reducing excess air reduces NO formation, due to the
lack of availability of oxygen, which preferentially combines with carbon,
hydrogen and sulfur rather than nitrogen.
-------
The minimum practical level of excess air that can be reached
by each boiler depends upon a number of variables, such as load (lower
loads require higher excess air levels), uniformity of air to fuel ratio
for the operating burners, (greater uniformity permits lower excess air),
slagging potential, furnace design (cyclone furnace requires relatively
high excess air), burner tilt (lower excess air for down-tilt than for up
tilt on tangentially fired boilers), secondary air register settings
(closed-down registers allow lower excess air without violating minimum
wind-box to furnace pressure differentials), steam temperature control
flexibility, coal quality variation, and fuel and air control lags during
load swings. With coal fired boilers, under ideal conditions, 4 to 5%
excess air levels can be reached without exceeding 200 ppm CO emissions.
More typical minimum excess air levels for coal firing in U.S. utility
boilers are 8 to 12% while in some cases excess air levels below 15 to
18% present operating problems.
5.3 Staged Combustion
Staged combustion (with low excess air) has so far proven in
short period tests to be the most effective method of combustion control
for reducing nitrogen oxide emissions from coal fired boilers. Although
coal fired boilers designed for two-stage combustion are just now coming
on line, a modified type of two-stage combustion using some coal burners
on air only has been successfully tested on a number of pulverized coal
fired boilers (4). Staged combustion is effective in reducing both thermal
and fuel NOX emissions (JJ) due to limitation of oxygen and lower flame
temperatures in the primary combustion zone, and lower effective temp-
eratures in the secondary, air-rich combustion zone.
Both practical and theoretical considerations were involved
in conducting staged combustion test runs. The lowest practical air-to-
fuel ratios were applied to operating burners with maximum separation of
"air only burners" from operating burners to provide for cooling between
primary and secondary combustion zones. However, practical design and
operating constraints often limited the modified staged combustion effec-
tiveness for the following reasons:
• The number and location of burners that could be operated
on an "air only" basis depends upon the pulverizer - burner
configuration and the maximum increase of coal supply
to active burners under full load conditions. Otherwise,
modified staged combustion generally resulted in a reduction
in load. Fortunately, some boilers do have the capacity
to operate at full load with one or more pulverizers off,
and thus have more staging flexibility.
• Some boilers do not have the capability of closing off
individual coal burners from a pulverizer. Thus, all
burners fed by a pulverizer are either on "active" '
or on "air only" operation.
-------
- 45 -
• In some boilers, division wall tube temperature limita-
tions, or suspected side wall corrosion problems prevent
the use of ideal "air-only" burner patterns.
• Steam temperature control problems can also prevent
the use of ideal burner patterns.
• Furnace slagging tendencies may prevent the use of
optimum burner staging configuration. For example,
attempts to minimize air-to-fuel ratios in the bottom
levels of a tangentially fired boiler with down-tilt
burners were not successful because of excessive
slag build-up on bottom side-walls and slopes of the
furnace.
• The option to decrease secondary air register openings
on active burners to optimum settings while simultaneously
operating with wide open settings on "air only" burners
to achieve maximum NOX emission reduction is not available
on all boilers. Most boilers with cell-type burners (2 or
3 burners in one assembly) must operate all burners within
each cell at a common register setting, even though one or
two burners are operated with air only. In some boilers
secondary air register settings are tied in with controls
in such a manner that they can only be operated in completely
open, or fully closed modes. Other boilers have fixed
secondary air register settings. Many boilers have broken,
non-operable register mechanical linkages or inaccurate
register setting indicators.
5.4 Flue Gas Recirculation
Flue gas recirculation into the windbox or secondary air ducts
of the furnace combustion has been shown to be an effective method of
reducing NOX emissions from gas and oil fired boilers (_4-_6). One boiler
selected for this test program, in part because of its flue gas recir-
culation capability, unfortunately could not be operated in this mode
because of fan blade erosion during our test period. Based on theoretical
grounds (_!) as well as on actual experience with pulverized coal fired
test rigs (_7), flue gas recirculation is expected to be effective pri-
marily for reducing thermal NOX, and affect fuel NOX formation to a
minor extent only, in coal-fired utility boilers.
5.5 Burner Tilt
Tangentially fired boilers are designed with tilting burners
(plus or minus 30° from horizontal) for superheat steam temperature and
combustion flexibility. Other generally available operating variables
that can assist in steam temperature control are superheat and reheat
-------
- 46 -
attemperation water sprays, excess air level, pulverizer loading patterns,
secondary air register settings and soot-blower operation. Thus, burner
tilt can often be used (within limits) to reduce NOX emission levels
without losing adequate steam temperature control, although operators
must be aware of potentially aggravated slag problems.
Raising burner tilts above the horizontal (on up fired boilers)
tends to enlarge the effective furnace combustion zone, to lower combustion
intensity, and lower effective high temperature residence time resulting
in reduced NOX emission levels for a given excess air level. Down-tilt
tends to reduce the furnace combustion zone, increases combustion
intensity, and increases effective high temperature residence time, result-
ing in increasing NOX emissions levels for a given excess air level. The
usefulness of burner tilt as a NOx emission control variable is partly
offset by the higher excess air levels generally necessary with up-tilt
burner operation. This higher excess air is needed to allow for the
greater flue gas stratification observed with up-tilt burner operation
caused by shorter times for complete mixing and combustion prior to the
flue gases reaching the furnace arch, and dividing into two streams. Of
course, potential slagging problems, and less flexible steam temperature
control systems also limit the usefulness of burner tilt for NOX emission
control. From a NOX emission standpoint, firing with the burners in a
horizontal or slightly upward tilt appears to give the best results.
5. 6 Other Combustion Variables
The importance of secondary air register settings and its rela-
tionship to the use of other combustion variables have been discussed
above in the low excess air and staged combustion sections. Lowering
air preheat temperatures can lower thermal NOx emission within rather
narrow limits in existing boilers with major steam side redesign required
for effecting large changes in air preheat temperatures. Pulverized coal
fineness showed only a minor effect on NOX emissions in the limited
testing performed on this variable.
While it was recognized that other combustion variables such
as burner design and configuration, coal nitrogen content, and primary
to secondary air ratios could have an important effect on NOX emission,
systematic testing of these factors was beyond the scope of the present
study.
Detailed results of the field test program are presented in
the following sections of this report. It should be noted that the
selection of combustion variables was guided by known theoretical
considerations of the formation of NOX in combustion processes. However,
boiler design and practical operating limitations and restrictions
determined the actual, detailed program plan for each boiler tested.
-------
- 47 -
5.7 Combinations of Combustion Modifications
As discussed in considerable detail in earlier Esso studies
on NOX emission control (_l-6), combinations of combustion modification
techniques can be used effectively for this purpose. Undoubtedly, the
most powerful of these combinations is the use of staged burner firing
patterns in conjunction with low overall excess air for all fossil fuel
types. This mode of operation results in the combustion of the bulk of
the fuel under reducing conditions, which affects the formation of both
"thermal" and "fuel" NOX.
Flue gas recirculation into the burner zone is a technique
that by itself suffers from the limitation for coal firing that it
appears to have little effect on "fuel" NOX (_1, _7, &) » because its
principal effect is to reduce the combustion temperature. Thus, the
relatively temperature-insensitive oxidation of chemically bound nitrogen
is not reduced significantly using this technique. These comments also
apply to other means of reducing combustion temperature, such as
steam or water injection, or reducing air preheat temperature. However,
for applications where "trimming" of NOX emissions already controlled
through other techniques is desirable, the use of flue gas recirculation
and steam or water injection should be kept in mind, as they are expected
to have an additive effect on NOX reduction in such cases. Furthermore,
these techniques can be beneficial for improving boiler operability,
e.g., steam temperature control. However, steam or water injection of large
quantities of H20 (on the order of 0.5:1 to 1:1 mass ratio to fuel fired)
reduces boiler efficiency by 4-6%. For similar reasons of reduction in
boiler efficiency, the use of reducing air preheat temperature is usually
not felt to be attractive for utility boiler applications.
"Minor" combustion variables (from the standpoint of NOX
emission control) have to be adjusted and optimized for each individual
boiler, based on the broad experience gained with different types of
boilers having different sizes, and fired with the large variety of
coal and other fuel types in the U.S.
-------
- 48 -
6. FIELD TEST RESULTS
The field test results obtained on individual coal fired boilers
under a variety of operating conditions are presented in four parts. These
parts consist of gaseous emission measurements, flue gas particulate
loadings measured upstream of particulate collector equipment, corrosion
probing data obtained in accelerated furnace fire-side water-tube corrosion
tests, and estimated boiler performance. Gaseous emission data and most of
the particulate emission data were obtained under normal, as well as staged
firing conditions. As discussed before, particulate loadings of the tiue
gas were determined only under conditions corresponding to baseline and
"low NOX" operation, for purposes of_comparison on the relative effect of
modified combustion operation on flue gas particulate loadings in coal
combustion. Similar considerations apply to the sustained, 300-hour
corrosion tests, which had as their objective the determination of whether
staged firing of coal accelerates furnace water tube corrosion rates.
The gaseous emission data obtained under baseline and staged
firing conditions at various load levels are presented first. Throughout
this report, NOX concentrations are expressed as ppm, adjusted to three
per cent 02 in the flue gas, on a dry basis.
In addition to the results obtained in tests coal fired boilers,
this section also presents the gaseous emission data on oil-fired units
converted from coal.
6.1 Coal Fired Boilers
Test programs were conducted on 12 coal fired boilers consisting
of four front-wall fired, three opposed-wall fired, four tangentially fired
and one turbo-furnace boiler. Typical cross-sectional diagrams for these
types of boilers are shown in Appendix C. Table 6-1 lists each boiler by
station and number, boiler manufacturer, type of firing, full load MW
rating, number of burners and number of burner levels. In addition, the
number of operating test variables included in each test program and the
number of completed test runs are shown.
6.1.1 Gaseous Emission Results for
Individual Coal Fired Boilers
The data obtained from the 12 boilers tested are grouped
according to boiler design type, i.e., front-wall fired, opposed-wall
fired, tangentially fired and turbo-furnace boilers.
6.1.1.1 Gaseous Emissions from
Front Wall Fired Boilers
Boilers 1, 2, 3 and 4 are front-wall fired boilers varying in
size from 105 to 320 MW. Dave Johnston No. 2 and Widows Creek No. 6 were
designed by Babcock and Wilcox, while E. D. Edwards No. 2 was designed by
-------
TABLE 6-1
SUMMARY OF COAL FIRED BOILERS TESTED
1
2
3
4
5
6
7
8
9
10
11
12
Station and
Boiler No.
Dave Johnston
Widows Creek
E. D. Edwards
Crist
Leland Olds
Harllee Branch
Four Corners
Barry
Naughton
Barry
Dave Johnston
Big Bend
2
6
2
6
1
3
4
3
3
4
4
2
Boiler
MFG.
B&W
B&W
R-S
FW
B&W
B&W
B&W
C-E
C-E
C-E
FW
R-S
Type of
Firing
FW
FW
FW
FW
HO
HO
HO
T
T
T
T
Turbo
MCR
(MW)
105
125
256
320
218
480
800
250
330
350
348
350
No. of
Burners
18
16
16
16
20
40
53
48
20
20
28
24
No. of
Burner
Levels
4
4
4
4
3
4*
6**
6
5
5
7
1
Test
Variables
3
4
4
4
3
4
5
4
6
7
7
4
No. of
Test
Runs
14
41
19
22
13
51
26
8
26
46
6
14
286
* Two levels of burner cells with two burners per cell.
** Two levels of burner cells with three burners per cell.
-------
- 50 -
Riley-Stoker, and Crist No. 6 was designed by Foster Wheeler. All four
of these boilers have four levels of burners. Widows Creek No. 6 boiler
will be discussed first since it was tested in most detail being the
first boiler studied in this program.
6.1.1.1.1 Widows Creek, Boiler No. 6
Tennessee Valley Authority's Boiler No. 6 at the Widows Creek
Station was the first boiler tested in our present study. Thirty-two
short-term test runs were made in a statistically design optimization
program, to minimize NOX emissions. These tests were followed by two
sustained runs, one at full load, the other one at reduced load, with the
optimum staging patterns. The sustained corrosion probing run was
deferred at TVA's request, until high sulfur coal could be fired, and
other data become available to show that staged firing would not cause
abnormally high furnace corrosion rates.
Widows Creek Unit No. 6 is a 125 MW, 16-burner, front-wall,
pulverized coal fired Babcock and Wilcox boiler. It has a single dry-
bottom furnace with a division wall, and the 16 burners are arranged
with four burners in each of four rows. Each row is fed with coal by
a separate pulverizer.
The statistical test design shown in Table 4-1 for this boiler
has been discussed in Section 4.1.3. The detailed operating and emission
data are listed in Table 1 of Appendix A. The NOX emission data,
expressed as ppm NOX corrected to three per cent oxygen in the flue gas
(dry basis) obtained with the various firing patterns tested are sum-
marized in Figures 6-1 and 6-2. In Figure 6-1, the measured emissions are
plotted vs. per cent of stoichiometric air to the active burners.
Figure 6-2 shows the same emission data, but plotted as a function of the
overall per cent stoichiometric air. Least squares regression lines have
been fitted to the data points corresponding to various firing patterns
designated as "S".
Actual baseline NQx emissions (full load, normal firing with
60% open secondary air registers) averaged 634 ppm at 18% excess air.
(For comparison purposes it should be noted that the baseline NOx emis-
sion level at 120% stoichiometric air calculated from all normal firing,
full load runs is equal to 666 ppm.) Each of the four operating variables
included in the experimental plan, i.e., excess air level, load, firing
pattern and secondary air register setting had a significant effect on
NOX emission levels, and are discussed in turn below.
Low excess air operations consistently reduced NOx emission
levels as shown by the least sqaure regression lines plotted in figures 6-1
and 6-2. A 10% reduction in stoichiometric air to active burners
reduced NOx emissions by 25% under full or reduced load, normal firing
-------
- 51 -
FIGURE 6-1
PPM N0x (3% Oo, DRY) VS % STOICHIOMETRIC
AIR TO ACTIVE BURNERS
(WIDOWS CP*:EK, BOILER NO. 6)
I
T
T
700
1
- 125 MW
- 110 MW
600
S. , (80 - 110 MW)
4-7
£2
CQ
500
8
eg
O
G-
i
O*
fc
400
300
200
100
' a2 3 ~
_
1 1 1
Symbol
O
A
A
D
B
firing
Pattern
(Active /Air)
Sj (16/0)
S, (14/2)
So (H/2)
83 (14/2)
S5_7 (12/4)
S4" (12/4)
1
Gross
Load
125
110
125
125
110
110
J
1
80
90
100
110
120
130
140
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 52 -
FIGURE 6-2
PPM NOx (3% O2, DRY) VS
OVERALL STOICHIOMETRIC AIR
(WIDOWS CREEK , BOILER NO. 6)
£2
CQ
O
eP
oo
i
700
600
n 500
g
400
300
S., - 125 MW
O
25 MW
O
sl- no
.83 - 125 MW
S4_? - 110 MW
200
100
0
80
Symbol
O
•
A
A
D
•
Firing
Pattern
Sl
Sl
S2
S3
S5-7
S4
— ... 1
Gross
Load - M\
125
110
125
125
110
110
90
100
110
120
130
140
OVERALL STOICHIOMETRIC AIR
-------
- 53 -
operation. The same percentage reduction in stoichmetric air under staged
firing reduced NOx emissions by an average of 24% at full load and 28%
at reduced load. The lowest practical level of excess air was dictated
by acceptable CO emissions and stack appearance.
Reducing load from 125 to 110 MW (12% reduction) with normal,
16 burner firing resulted in little change in NOX emission levels since
the average excess air level was raised during low load operation.
However, when operating at equal excess air levels (say 20% overall
excess air) a 12% reduction in load resulted in a 20% reduction in NOX
emission levels under normal firing as well as under staged firing
conditions.
Staged firing had a statistically significant effect on NOX emis-
sion levels under both full load (14% NOX reduction) and reduced load operation
(27% NOX reduction). At full load, staging pattern 83 (top row wing
burners on air only) consistently produced lower NOX emission levels
than staging pattern S2 (bottom row wing burners on air only) as shown
by their least square regression lines of Figure 6-2. At reduced load,
staging pattern 84 (top row of burners on air only) resulted in the
lowest NOX emission levels. The combination of low excess air and
staged firing reduced NOX emissions by 40% at full load, and from 33 to
50% at reduced load. The optimum combination of operating variables
reduced NOX by 46% at full load and by 53% at reduced load compared to
full load, baseline emission levels.
Opening the secondary air registers resulted in a small (5%)
but statistically significant reduction in NOX emissions when firing
coal in all burners. When firing at full load with two burners on air
only, no significant change in average NOX emissions resulted from changing
secondary air registers. However, closed down secondary air registers
consistantly resulted in lower NOx emissions (average of 14%) during staged
firing operation with four burners on air only. This improvement can be
explained by improved mixing of fuel and air with less CO formed as well
as less air to active burners since a higher proportion of air will be
diverted to the open top burners.
The data shown in Figure 6-1 call attention to an apparent
anomaly. A cursory inspection of the data would indicate, that while
as expected NOx levels decrease with decreasing air supply to the active
burners, staging the burners could result in higher NOX emissions than
normal operation at the same burner air/fuel ratio. A refined method for
estimating the actual air/fuel ratio at each burner for each staged firing
pattern can explain this anomaly. Since this method applies to other wall
fired boilers, a specific example will be used here to briefly explain the
method.
Staged firing pattern, 84, (top row of 4 burners on air only
and the bottom 3 rows firing coal) at 20% overall excess air results
in an average % stoichiometric air to each of the 12 active burners of
-------
- 54 -
90% i.e., air to coal = 120/16 to 100/12. (Since 120% air is divided
^o'ng 16 burners while 100% of the coal is divided among the 12 active
burners.) However, some of the air from the inactive top row of burners
mixes with the partially unburned coal/air mixture from row B (less than
5 feet below) raising the actual % stoichiometric air ratio above the
90% for the bottom two rows (12 and 17 feet below) . Based on visual
observation of flame patterns during staged firing and simplified
calculations it appears that a one-third mixing efficiency for the top
row air with the coal-air mixture is a reasonable estimate. Table 6-3
presents the calculations to bring actual NOX emission data in agreement
with those calculated by extrapolating from unstaged levels.
Figure 6-3 presents the least squares regression lines cal-
culated for the six test runs (shown as circles) made at full load with
normal firing, as well as for the six test runs (shown as squares) made
using staged firing pattern 84. The actual ppm NOX emissions for the
six S4 runs are also plotted (as hexagons) vs. the "effective" % stoichio-
metric air. Run No. 24 NOx results fall 13% below their "expected" value
due largely to the low load (89 MW vs. the 104 MW average of other five
runs) for this run. It should also be noted that each of the "expected
ppm NOx" points plotted against the "effective" % stoichiometric air
would fall on, or very close to the extrapolated Si regression line.
Thus, we can estimate the maximum NOX reduction if NO-ports were added
to this boiler (at a sufficiently high elevation so that very little air
would be mixed with the primary flame front). At 120% overall excess
air Si produces 667 ppm NOX, 84 produces 370 ppm, while true 2-stage
combustion would approach 222 ppm NOX emissions.
6.1.1.1.2 Dave Johnston, Boiler No. 2
Boiler number 2 of the Dave Johnston Station of the Pacific
Power and Light Company is a Babcock and Wilcox designed, front wall
fired, single furnace boiler with a maximum continuous rating of 102 MW
gross load. Six pulverizers feed 18 burners arranged in four rows with
3 burners in the top row and 5 burners in each of the other three rows.
(Figure 6-4 shows the mill-burner configuration.) The 18 burners in this
unit are of the circular register type which imparts a spinning action to
the secondary air stream.
Detailed operating and emission data are summarized in
Table 2 of Appendix A. Table 6-5 indicates the experimental design of
operating variables with average flue gas measurements of % oxygen and
ppm NOX (3% 02, dry basis) shown for each of the 14 runs completed on
this boiler. Operating variables were firing pattern, secondary air
register settings on coal mills not firing coal, and excess air level.
Gross load was maintained near full load for all test runs due to a
tight load demand during the test period. Number 12 mill feeding the
-------
- 55 -
TABLE 6-3
CALCULATION OF EXPECTED NOX EMISSIONS FROM
% STOICHIOMETRIC AIR TO ACTIVE BURNERS
Burner
Row
A (Top)
B
C
D
TOTAL
Coal
%
0
33.33
33.33
33.33
99.99
Air
%
28. si
30. 5j
30.5
30.5
120 ^
A/C
%
[1]
120
91.5
91.5
100.7[4]
Expected
NOX, ppm
(E)
[2]
667
222
222
370
Actual
NOX, ppm
(A)
[3]
369
%
Difference
i
A - E
i nn
A
-0.3%
[1] Assumes 1/3 of air from Row A mixes with Row B.
[2] Calculated from S;L Regression Equation: PPM NOX = -1205 + 15.6
(% Stoichiometric Air).
[3] Calculated from 84 Regression Euqation: PPM NO = -1026 + 15 5
(% Stoichiometric Air). X
[4] Average "Effective" % Stoichiometric air to active burners.
[5] Assumes 5% primary air and 95% secondary air.
Similar calculations have been made for each run with staged
firing pattern 84. The results are listed in Table 6-4, and plotted
in Figure 6-3.
TABLE 6-4
CALCULATION OF EXPECTED NOX EMISSIONS FROM AVERAGE
"EFFECTIVE" % STOICHIOMETRIC AIR TO ACTIVE BURNERS
Run
No.
13
20
24
26
26Ai
26A3
% Stoichiometric Air
Overall
126
116
126
114
115
113
To Active
Burners
94
87
94
86
86
85
"Effective"
106
98
106
96
97
95
Expected
PPM NOX
449
319
449
297
308
277
Actual
PPM NOX
460
345
399
297
299
290
% Diff.
( A - E\
V A )
+3
+8
-13
+9
-3
+4
Gross
Load
(MW)
110
108
89
99
99
103
-------
- 56 -
FIGURE 6-3
PPM NO (3% O2, DRY BASIS) VS % STOICHIOME TRIG AIR
ACTIVE BURNERS FOR Si AND 84 RUNS
800
700
600
03
i-^
02
g
CM
o
500
400
i
I
84 - Regression Line
(y= -1026+ 15.50x)
300
200
100
S1 - 125 MW Regression Lin
/(y = -1205 + 15.59x)
Firing
Symbol Pattern
A
D
O
si
S4
S4
% Stoichiometric
Air to Burners
Actual
Actual
"Effective"
80
90
100
110
120
130
140
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
FIGURE 6-4
500
CO
OT
« 400
g
CT
65 30°
£2-
0*
& 200
100
0
8
PPM NOx (3% O2, DRY) VS % STOIC HIOME TRIG
AIR TO ACTIVE BURNERS
(DAVE JOHNSTON, BOILER NO. 2)
1 1 1 1 1 1
Normal Firing:
~~ 15 Burners Fir
12 Burners Firing /
ing-
S r(Tr
Staged Firing: ft m'®(^ *2 Burners FirinS
— Under and Over Ss^ Ju ^
^** Fire Air ^ /©
H©_^^S© a ^ t ,
J2^"^ ® H^ Air Only
-H^ .It © 1 Coal + Air
BS(£) ^ ^
^ ,_ i ^H No Coal or
^^ (2) 51^ ^^*
uX- uver I ire Air vjniy Mi^| _ p1irnpr
~* Xffe") Configuration
© © ©
(jo) (T) (\o) (?)
© © ® ©
(?) (9) (iT) (7)
1 1 1 1 1 ^ | ^ ^-^ | ^
0 90 100 110 120 130 140
Air
©
©
©
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 58 -
TABLE 6-5
EXPERIMENTAL DESIGN WITH % 02 AND PPM NOX (3% 02 BASIS)
(Dave Johnston, Boiler No. 2)
Firing Pattern
FI - No.
12 Pulverizer
Off
15 Burners
Firing
F2 - No.
11 and
12 Pulverizers
Off
12 Burners
Firing Coal
F~ - No. 12 &
10 Pulverizers
Off 12 Burners
Firing ~oal
Secondary Air
Registers
No. 12 Pulv.
Closed
No. 12 Pulv.
Open
Nos. 11 & 12
Closed
No. 11 Closed
No. 12 Wide Open
No. 11 Open
No. 12 Closed
No. 11 Open
No. 12 Open
No. 10 & 12
Closed
No. 10 Closed
No. 12 Open
No. 10 Open
No. 12 Closed
No. 10 Open
No. 12 Open
Staged
Pattern
Si
S2
Sl
S3
S4
S5
Sl
S6
S7
S8
Load: 98 to 106 MW
A^-Normal
Excess Mr
(3)*
U; 5.0% 02
454 ppm NOx
(11)
<*> 4.3
450
(8) 4.6
347
(9)
(10) 4.6%
358
(13) 5.2%
438
A2~Low
Excess Air
(4) 4.3
409
(12)4.1
314
(7) 3.7
413
(2) 4.2
284
(6) 3.3
362
(5) 4.0
311
(14) 4.7
270
(15) 5.3
326
(16) 5>2
214
* Numbers in parentheses are test run numbers.
-------
- 59 -
top row of burners was down during the entire test period due to mechanical
problems. Special advantage was taken of the wide range of firing pat-
terns available at full load by testing 10 different combinations of coal
mills off, with open or closed secondary air registers.
Figure 6-4 is a plot of ppm NOx vs average % stoichiometric
air to the active burners. The data points have been plotted as symbols
indicating visually the various firing patterns tested. Solid lines
have been drawn through the data points with similar operation to show
the strong influence of excess air level.
Five test runs were conducted at about full load without staged
air admission, except the small amount going through the secondary air
registers to cool the "off" burners. Runs 1 and 7 were operated with
mills 11 and 12 off; run 3 and 4 were operated with number 12 mill off
and run 12 was conducted with mills 10 and 12 off. NOX emission levels
(corrected for excess air level) were highest for runs 1 and 7,
intermediate for runs 3 and 4 and lowest for run 13. These results
are in agreement with past operating experience and theory. Runs 1 and
7 were conducted with only 12 active burners (therefore at a higher firing
rate of coal per burner) compared to 15 active burners in runs 3 and 4.
Of more importance, runs 1 and 7 had cooling air flowing through burners
at a lower elevation, counter balancing the beneficial effect of adding
cooling air through 3 top burners, and in run 13, cooling air was added
through 6 top burners to aid in reducing NOX emission levels. Actual
full-load baseline, NOx emissions were 454 ppm.
Seven different staged firing patterns were tested with very
instructive results. The five staging patterns operated with secondary
air admitted through top burners listed in the order of decreasing NOX
reduction efficiency were: SQ top two mills on air only (214 ppm); S/-,
top mill on air only, bottom mill off (284 ppm); $2 top mill on air only
(314 ppm); and Sy, top mill off with cooling air and next to top mill on
air only (326 ppm). The two staging patterns with secondary air admitted
through both top and bottom burners were: 85, top and next to bottom
mills on air only (311 ppm) and 85, top mill off with cooling air only
and next to bottom mill on air only (362) . Table 6-6 lists these low
excess air, staged runs with ppm NOX, % 02 and average % stoichiometric
air to active burners (calculated and adjusted bases) to allow comparisons.
These results clearly demonstrate the importance of maximizing secondary
air admission through top burners, providing minimum % stoichiometric air
to active burners and minimizing the additon of secondary air through
inactive bottom burners. (In other words, "overfire" air staged operation
is preferred to "underfire" air firing modes.)
Analysis of these results are greatly simplified (as shown by
Figure 6-5) when the calculated average % stoichiometric air is made more
realistic by adjusting directionally for the "cooling" air that enters
the furnace through the "closed" secondary registers of burners of "off-
mills". If the closed registers are within the top two burner rows
-------
- 60 -
TABLE 6-6
SUMMARY OF LOW EXCESS AIR, STAGED TEST RUNS
Staged Firing Pattern
Mills Off and Secondary
Air Register Position
Overfire Air
S0 - 12 Open, 10 Open
o
S& - 12 Open, 10 Closed
S3 - 12 Open, 11 Closed
S - 12 Open
S7 - 12 Closed, 10 Open
Over & Under- Fire Air
S - 12 Open, 11 Open
S, - 12 Closed, 11 Open
Run
No.
16
14
2
12
15
5
6
N0x
PPM
214
270
284
314
326
311
362
°2
%
5.2
4.7
4.2
4.1
5.3
4.0
3.3
i
% Stoichiometric Air
To Active Burners
Calculated
[1]
88
102
99
102
106
82
94
Adjusted
[2]
88
99
102
102
103
82
91
ri] Calculated as: % Total Air x No- of Burners Firing Coal
No. of Burners Firing Coal plus No. of Burners on Air Onl]
[2] Adjusted for estimated "cooling" air. Deduct 3% from calculated
% Stoichiometric air for overfire "cooling" air and/or add 3%
for underfire "cooling" air.
-------
- 61 -
("overfire" cooling air) the calculated % stoichiometric air is reduced
by 3%. For underfire air (No. 11 mill off) the adjusted % stoichiometric
air is obtained by adding 3% to the calculated % stoichiometric air.
Figure 6-5 shows that all of the test run data are closely clustered around
three least-squares regression lines: normal firing, 7 = -82 + 4.95x; and
staged "overfire" air, y = -436 + 7.30x. Each of these three operating
methods reveals a strong (64 to 88%) relationship of excess air level with
ppm NOX emissions after adjusting for "cooling" air. The displacement of
the staged firing regression lines from the extrapolated normal firing line
can be accounted for by the mixing of "overfire" (or "underfire" air) into
the burning air cool mixture from the next level of burners as shown for
the Widows Creek No. 6 boiler. For example, the average "effective"
stoichiometric air levels in test runs No. 5 and 12 are 107.4% and 107.3%,
respectively, which produce expected NOX emission of 317 ppm (from normal
firing equation: y = -422 + 7.07x) compared to actual emissions of 311 and
314 ppm, respectively.
To summarize the results from this boiler, emphasis was placed
upon the use of a wide variety of full load, staged firing combinations.
From baseline NOX emissions of 454 ppm, low excess air, staged operation
reduced NOx to as low as 216 ppm with a slightly darkened stack plume.
Other staged firing patterns resulted in 275 to 320 ppm NOX with no
degradation of the plume. Excess air levels showed a strong influence
on NOX emission levels in general agreement with previous experience on
wall fired boilers.
6.1.1.1.3 E. D. Edwards, Boiler No, 2
Boiler No. 2 at the E. D. Edwards station is a Riley Stoker
Corporation, front-wall fired, pressurized, single furnace boiler. It
was designed for a maximum continuous rating of 1,870,000 pounds of
steam per hour with a superheater steam outlet pressure of 2600 psig
at 1005°F. The furnace is fired with 16 burners (4 rows of 4 burners)
and has dimension of 46 feet width, 30 feet depth, a furnace volume of
155,600 cubic feet and a furnace envelop of 37,700 square feet effective
projected radiant surface.
A summary of the operating and emission data for each test
run is contained in Table 3 of Appendix A. Table 6-7 below indicates
the experimental design of operating variables with average flue gas
measurements of % 02 and ppm NOx (3% 02, dry basis) shown for each
short-period test run. Almost all of the planned test runs shown were
completed. Runs 21 and 22, peak load runs, could not be achieved during
the hot summer testing period. Two special, long-period fluctuating
load (load determined by industrial demand) runs were made under the
operating conditions specified for runs 7 and 9. These runs, identified
as 7A and 9A, were conducted in order to determine how NOX emissions
produced during varying load conditions would compare with the emission
data obtained under steady-state short-period test runs. The analysis
of the short-period test run results will be discussed first, followed
by that of results from the two special runs.
-------
- 62 -
FIGURE 6-5
PPM NOx (3% O2, DRY) VS ADJUSTED* AVERAGE
% STOICHIOMETRIC AIR TO ACTIVE BURNERS
(DAVE
sni
1 1
^
HH
<; Staged
JOHNSTON, BOILER NO. 2)
1 1 1 1
* Normal
(TXi) Firine
Firing: xV^J
•H AM Under + Over Fire Air J2)©
tf
Q x
£a Q^X^^
- 300- ^©
o*
s >
^ 20(_ ® /
IOC-
C 1 1
70 bO 90
^ S
^
Over Fire Air /
(i\X S
sffl /-\fR\m 5 and Run 12
/^ / Calculated from _
(J4) 0 "Effective" Stoich. Air
X^x
—
* + or - 3% Adjustment for
"Underfire" or "Overfire" ~
Cooling Air
1 1 1 J
100 110 120 130 14
0
ADJUSTED % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
EXPERIMENTAL DESIGN WITH PPM NOy (3% 02 BASIS) AND % 02
(E. D. Edwards, Boiler No. 2)
Burner
Firing
Pattern
sr
Normal
Firing
Pattern
S2-
AOOA
0000
0000
0000
S3-
OAAO
0000
0000
0000
AAAA
0000
0000
0000
S5-
AOOA
OAAO
0000
0000
Secondary
Air
Register
Setting
R1 - 50%
Open
R2 - 20%
Open
R-L - 50%
Open
R2 - 20%
Open
RX - 50%
Open
R2 - 20%
Open
^ - 50%
Open
R2 - 30%
Open
R-L - 50%
Open
R2 - 30%
L -280 MW
A^-Nor .
Air
(21)
A2~Low
Air
(22)
L2-260 MW
A^-Nor .
Air
(1) 670
3.2% 02
(3) 770
3.1% 02
(5) 644
3.8% 02
(9) 625
*3.9% 02
(11) 609
3.8% 02
(7) 401
7.5% 02
A2-Low
Air
<2) 556
1.5% 02
(4) 692
1.8% 02
(10) 474
2.0% 02
(6) 359
1.6% 02
(8) 524
2.7% 02
<12) 382
*2.1% 02
L3-220-240 MW
A^-Nor .
Air
(13)535
4.9% 02
(17)
(19)
(15)
A2-Low
Air
(18)386
3.5% 02
(14)310
4.4% 02
<16)336
2.8% 02
(20)295
3.0% 02
L.-210 MW
A^-Nor .
Air
(23) 667
4.2% 02
A2-Low
Excess Air
(24) 516
1.6% 02
CO
I
* Secondary air registers 30% Open.
-------
- 64 -
Table 3 Appendix A contains a summary of operating and emission
data for the 20 short-period test runs completed on this boiler. Operating
variables were gross load, excess air level, firing pattern and secondary
air register setting. The maximum gross load tested was 256 MW (vs full
load of 260 MW) with normal and staged firing, while the minimum load
tested was 204 MW using a normal firing pattern. Excess air levels
were set at normal operating levels or at the minimum level as established
by maximum acceptable CO measurements in the flue gas. Five firing
patterns were tested; normal firing with all 16 burners in operation, two
staged firing patterns with two burners on air only, and two staged
firing patterns with 4 burners on air only. Secondary air registers were
set normally (45-50% open) or closed down to a 20 or 30% open position.
Each of the four operating variables showed a significant
independent effect on NOX emission rates and some significant two variable
interaction effects were also apparent. Figure 6-6, a plot of average
ppm NOx vs % stoichiometric air to active burners (all short period test
runs) has been prepared to show the relationship between NOx emissions
and excess air levels for various load, staged firing, and secondary air
register setting test conditions.
Full load, baseline NOx emissions were 703 ppm. Reducing load
to 212 MW (16% reduction) resulted in a NOx emission reduction of 5%
(to 668 ppm).
Reducing excess air levels while holding other variables con-
stant consistently resulted in lowering NOX emissions, as shown by the
least squares regression lines drawn through data points representing
similar types of operation in Figure 6-6. The change in ppm NOX emission
with a 10% stoichiometric air reduction varied between 130 and 200 ppm
and agrees well with other wall type boilers tested.
Secondary air register settings also showed a strong influence
on NOx emission levels. During normal firing of all burners, closing
down dampers (20% open instead of 50%) increased NOX emissions by 116 ppm
(664 to 780) or about 17% when firing with 3% 02 in the flue gas. This
increase in NOx emissions is to be expected due to the greater turbulance
and higher peak flame temperatures associated with increased secondary
air velocity at the burner. However during staged operation, closed
down dampers consistently produced lower NOx emissions than operation
with normal damper positions. With closed down dampers during staged
firing it was generally possible to reduce excess air levels to a lower
level without exceeding the maximum permissible CO levels, and thus, lower
NOX levels were reached with this type of operation. Another explanation
for this phenomenon is that a lower percent of stoichiometric air is
introduced to the fuel rich burners when the air registers are pinched
to 20-30% open because the flow restriction upsets the balance to each
burner. Therefore a boiler operating at 0.9 stoichiometric ratio with
all registers at 50% open may actually reach 0.85% stoichiometric ratio
when the registers are closed to 20% open.
Staged firing operation resulted in lowered NOx emissions, and
as previously experienced, the combination of low excess air and staged
firing showed further improvement. The average ppm NOx emissions for
the four test runs each with normal firing, staged firing 82, and
-------
- 65 -
FIGURE 6-6
PPM NOx (3% O2, DRY) VS % STOICHIOMETRIG
AIR TO ACTIVE BURNERS
(E. D. EDWARDS, BOILER NO. 2, FIRING COAL)
T
800
700
2 600
s
500
400
300
200
100 -
0
1 1
Normal Firing
% Open Secondary Air - Gross
Load 20% - 255 MW
. 50% - 250 MW
/
50% - 210 MW
20% - 250 MW
(je) 50% - 220
(—.30% 230 MW
30% - 220 MW
Burner
Configuration
o
0
©
.firing Pattern
Symbol Burners - Air Onl
OS1
AS2
VS3
DS4
0S5
None
1,4
2,3
1,2,3,4
1,4,6,7
J.
80 90 100 110 120 130 140
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 66 -
staged firing 83, were 670, 526, and 479, respectively, indicating an
average emission of reduction of 22% using 82 (top wing burners off) and
29% using 83 (top middle burners off) compared to normal firing conditions,
As mentioned before, test runs 9A and 7A were conducted in
order to obtain a comparison of NOx emissions levels under normal, load
varying conditions to steady state conditions. Run 9A operating condi-
tions were similar to steady state run 9, i.e., normal excess air, staged
pattern 2 (top wing burners on air only) and secondary air registers
closed down to 30% open; however, the load was allowed to follow its
normal industrial pattern.
Figure 6-7 is a plot of ppm NOX emissions vs % 02 measured in
the flue gas for individual measurements of probe 2 and 3, or 1 and 4
gas composites taken during test run 9A. Also shown is the average NOX
and 02 measurements of run 9. During most of the four and one-half
hour period of this run the load was steady at 255 MW with two short
periods at 230 to 235 MW. Thus, the NOX emissions compared very well
with the results of test run 9 obtained 7 days earlier.
Test run 7A operating conditions were similar those of run 7,
except that the secondary registers were only closed to 30% open (vs
20% open for run 7) and in addition the load was allowed to vary with
industrial load demand from 200 to 260 MW. Figure 6-8 is a plot of
individual NOx vs 02 measurements for run 7A. For comparison purposes,
average results obtained under similar staged firing pattern 3 (middle
top row burners on air only) are also shown as circled run numbers.
This plot indicates that the variation of NOX emissions during run 9A
were largely (77%) related to changes in excess air level as shown by
the solid least-squares line. Test runs 8 and 11, (operated with 50%
open secondary air registers) are above the regression line, while test
run 7 operated with 20% open secondary registers is considerably below
the regression line indicating the importance of register settings.
To sum up, four operating variables were included in the
experimental test program of 20 short-period test runs completed on
boiler No. 2 at the E. D. Edwards Station. Changes in gross load,
excess air level, firing pattern and secondary air registers produced
significant changes in NOx emission levels. Base line emission levels
of about 703 ppm NOX were reduced to between 360 and 380 ppm under low
excess air, staged operation with closed down secondary air registers
at about full load. Reduced load, low excess air - staged operation
with closed down secondary air registers resulted in further reductions
to about 300 ppm. Two normal excess air staged firing runs with gross
load varied according to load demand produced NOx emission levels close
to those predicted from steady-state test runs, with most of the
variation in NOx emissions due to changes in excess air level variation.
-------
500
- 67 -
FIGURE 6-7
PPM NOX (3% O2 BASIS) VS % OXYGEN IN FLUE GAS
(RUN 9A, E. D. EDWARDS, BOILER NO. 2)
CO
I—I
tf
e-;
O
CO
400
300
200
O
100
0
0
% O2 MEASURED IN FLUE GAS
-------
- 68 -
FIGURE 6-8
PPM NOx VS % OXYGEN IN FLUE GAS
(RUN 7A, E. D. EDWARDS, BOILER NO. 2)
500
Probes Sampled
1 and 4
2 and 3
land 2
3 and 4
Circled Numbers
Indicate Run No. Averages
0
6
OXYGEN IN FLUE GAS
-------
- 69 -
6.1.1.1.4 Crist Station, Boiler No. 6^
Crist Station Boiler number 6 is a Foster Wheeler designed,
front wall fired single furnace boiler, with a maximum continuous rating
of 320 MW gross load. The pressurized furnace has 16 burners arranged
in four rows of four burners each. Superheat and reheat steam temperatures
are 1000°F at pressures of 2484 psi and 569 psi respectively during full
load operation.
A cooperative test program by Gulf Power, Foster Wheeler and
Exxon, coordinated by EPA, was planned for this unit. Plans included
short-term firing pattern optimization runs for minimizing NOX emission,
accompanied by boiler performance tests by Foster Wheeler, followed by
boiler operability check-out at "low NOX", then a sustained 300-hour
test under low NOx" and baseline operating conditions for assessing
corrosion problems, and an optional long-term test period of about 6 months
for determining actual furnace water tube wastage. Because of load
demands on this boilei., however, it has been possible only to explore
firing patterns in short-term runs only for minimizing NOX.
Table 4 of Appendix A contains a summary of the operating
and emission data subdivided into the "A" and "B" sides of the boiler.
The flue gas stream leaving the furnace is split into two ducting paths,
and although the boiler operator and manufacturer could at times achieve
02 balance in the two sides, the NOx levels measured were clearly higher
for the "A" side than the "B" side, with all firing patterns tested. The
reason for this difference is not completely understood at present,
although it may be related to differences in air flow, and uncertainties
of the air damper settings on the two sides of the boiler.*
To simplify the presentation and to facilitate comparison
with other boilers, Hgure 6-9 is based on the average of duct A and duct B
results. Table 6-8 presents the experimental! design with % oxygen and
ppm NOX for each test run on duct A, duct B and the ooiler average.
Operating variables tested were load, excess air level and firing patterns.
Reducing load from 320 to 270 MW (16% reduction) resulted in
lowering NOX from 845 to 794 ppm (6% reduction) for normal firing operation.
Reducing excess air levels had a significant effect on NOX emission levels
under both normal and staged combustion operation as shown by the least
squares regression lines of Figure 6-9. Staged firing also resulted in
significant reduction in NOX from the 832 ppm experienced during baseline,
full load operation. The 320 MW staging pattern S3 (middle top row burners
Foster Wheeler has indicated a possible cause of the side to side
differences as attributable to three burner-register assemblies which
were replaced on the "A" side prior to the test series. These registers
have a different register assembly which might have resulted in different
air flow characteristics.
-------
- 70 -
FIGURE 6-9
PPM NOx (3% O2, DRY) VS % STOICHIOME TRIG
AIR TO ACTIVE BURNERS
(CRIST, BOILER NO. 6)
900
en 800
i—i
OT
CQ
1
o
££>
-
600
PH
5 MW
,S1 - 315 - 350 MW
MW
500
400,
300
D / A
/S4 - 270 MW
1 1
Symbol
O S1
• Sl
A S2
A S3
D S4
•S5
1
Burners
On Air
Only
None
None
1, 4
2,3
1, 2, 3, 4
2, 3, 5, 6
1
(jross
Load
(MW)
315-350
270
320
•620
270
270
1
_
1
80
90
100
110
120
130
140
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
TABLE 6-8
TEST PROGRAM EXPERIMENTAL DESIGN - CRIST. BOILER NO. 6
(Run No., Average % Oxygen and PPM KOX (3% 02, Dry Basis) Measured in Flue Gas)
le>--^ Fir±ng
£rW<«5»
Operating
70%
Open
Idle
0%
Open
70%
Open
L -350
MW
A^Nor.
Exc Air
sr
(26)
3.4-898
2.9-743
3.2-820
(26B)
3.2-888
3.5-801
3.4-844
L2 - 315 - 320 MW
A -Normal Excess Air
sr
(i)
3.6-902
3.6-799
3.6-850
(1R)
3.4-916
3.0-765
3.2-840
V
(2)
4.7-946
4. 7-872
4.7-909
(3)
2.3-724
3.4-631
2.8-678
S3-
(5A)
3.1-728
3.6-657
3.4-692
A--Low Excess Air
sr
(6)
2.4-804
2.4-630
2.4-717
(6R)
2.6-862
2.1-660
2.4-761
V
(7)
2.0-788
2.6-565
2.3-676
(8)
1.9-772
4.5-591
3.2-682
(8R)
3.1-738
2.2-526
2.6-632
S3-
(4)
1.4-516
4.0-546
2.7-531
(5)
0.9-532
3.2-620
2.0-576
(10)
1.8-566
2.2-522
2.0-544
(10R)
3.5-802
3.0-593
3.2-698
L3 - 270 MW
Ai-Nor.
Exc Air
sr
U1R)
3.7-840
3.9-748
3.8-794
A^-Low Excess Air
V
(14R)
2.0-754
2.2-640
2.1-697
V
(15A)
2.6-643
2.3-416
3.0-530
(16)
3.8-661
3.7-411
3.8-536
(16R)
1.8-560
4.5-472
3.2-516
V
(25R)
3.1-647
3.1-484
3.1-566
Code for Data in Cells
(26) - Test Run Number
3.4% 02 - 898 ppm NOX - A Duct
2.9% 02 - 743 ppm NOX - B Duct
3.2% 02 - 820 ppm NOx - Average
-------
- 72 -
on air only) produced better results (reduction to 526 ppm NOX) than staging
pattern S2 (outside top row burners on air only) . With the further reduced
load of 270 MW, staging pattern 84 (top row of burner on air only) produced
lower NOX results than staging pattern 85 (top row wing burners and next
to top row middle burners on air only) .
It is hoped that eventually an opportunity may arise for com-
pleting the planned program on this unit.
6.1.1.2 Gaseous Emissions from Horizontally
Opposed Coal Fired Boilers
Three Babcock and Wilcox designed opposed firing boilers were
tested in this program; Leland Olds No. 1, 216 MW; Harllee Branch
Number 3, 480 MW; and Four Corners No. 4, 800 MW full load rating.
Since the Harllee Branch boiler was tested first and most extensively,
it will be discussed first, followed by the Four Corners and Leland
Olds boilers.
6.1.1.2.1 Harllee Branch, Boiler No. 3
Harllee Branch unit No. 3 with a full load rated capacity of
480 MW gross load, is a single furnace, pulverized coal fired Babcock
and Wilcox boiler. It has 40 burners arranged in twenty burner cells of
two burners each, with two rows of five burner cells located in both the
front and rear walls of the furnace. The burner configuration and
pulverizer layout are shown in Figure 6-10.
Table 5 of Appendix A provides a summary of the operating and
emission data from each of the 51 test runs completed on this boiler.
Operating variables included in the test program were load, excess air
level, secondary air register setting and staged firing pattern.
Figure 6-11 contains individual data points and least squares,
regression lines for the NOx vs. average % stoichiometric air to active
burners for normal and staged firing.
Baseline NOx emission levels at full load averaged about 711 ppm.
Lowering the level of excess air was possible both under normal and
staged operating conditions down to flue gas 0£ concentrations of about
1.5% or even lower, without apparent undesirable side effects. The steep
effect of reducing the per cent of stoichiometric air to the active bur-
ners on decreasing NOX emissions is shown by the least squares regressions
of the data in Figure 6-11. A 10% reduction in excess air reduced NOX
emissions by about 100 ppm under normal firing, and by 118 ppm under
staged firing conditions.
Interestingly, by operating four to six top burner cell row
burners on air only, it was possible to maintain boiler load at 480 MW,
and reduce the NOX emission levels to about 488 ppm. This level corresponds
to a reduction in NOX of about one-third, compared with the baseline level.
Usually, wing burners of the top rows of front and rear walls were operated
on air only, but the NOX emission levels were not particularly sensitive
to the exact location of the inactive burners in the top row. Twenty
different firing patterns were tested.
-------
- 73 -
FIGURE 6-10
HARLLEE BRANCH, BOILER NO. 3
PULVERIZER AND COAL PIPE LAYOUT
Two-Burner Cell.
Pulverizer Letter
Burner Number .
B
J
(D
I
'«_*•
D
J
4s
B
*•—-
C
o
G
•^—>
I
E
"3s
K
•-^>
I
K
FACING REAR FACE
H
-—>
I
F
<•—>
O
F
H
FACING FRONT FACE
-------
FIGURE 6-11
w
*—i
CO
H
g
(M
CO,
i*
600
PPM NOx (3% 02, DRY) VS % STOICHIOMETRIC
. AIR TO ACTIVE BURNERS
(HARLLEE BRANCH, BOILER NO. 3)
500
400
300
200
100
0
T
T
T
T
Staged Firing
465 - 485 MW
Staged Firing /
R . _ - 400 MW
Normal Firing
470 - 500 MW
Normal Firing
400 MW
S
l_s4-6
./
y
^ Staged Firing
/ Slg - 275 MW
_L
J_
70 80 90 100 110 120
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
130
-------
- 75 -
With only 30 active burners, i.e., 10 top row burners on air
only, it was possible to reduce NOx emissions to about 354 ppm at low
levels of excess air, or a reduction of over 50% from the baseline level.
However, load was also reduced by 17% from 480 MW to 400 MW using this
staging pattern.
Secondary air register setting had only a small effect on NOx
emission levels. Wide open registers produced lower NOX than the 50%
open position under normal firing, while there were no significant dif-
ferences observed during staged firing operation.
Reducing gross load from 480 MW to 400 MW (17% reduction in
load) resulted in 672 ppm vs. 537 ppm NOX (20% reduction in NOX) at the
same excess air level under normal firing conditions. As discussed
above, larger reductions in NOX emissions resulted from staged firing
with low excess air.
6.1.1.2.2 Leland Olds, Boiler No. 1
Leland Olds unit number 1 has a full load rated capacity of
216 MW gross load. At the time of its first operation in 1966, it
was the largest lignite fueled boiler in the Western Hemisphere. This
Babcock and Wilcox designed boiler has a single furnace with opposed
wall firing. Ten pulverizers feed 20 burners, arranged in three rows
of four burners each in the front wall, and two rows of 4 burners each
in the rear wall.
Table 6 of Appendix A contains a summary of the operating and
emission data obtained from the 13 test runs completed on this boiler.
Table 6-9 presents the experimental design with run number, % oxygen and
ppm NOX shown for each test run. Operating variables tested were gross
load, excess air level and firing pattern.
Figure 6-12 shows a plot of ppm NOX vs. average % stoichiometric
air to the active burners. Full load baseline NOX emissions were 569 ppm.
The least squares regression lines indicate the strong influence of excess
air on NOX emission levels for both normal firing and staged firing. With
normal firing of all burners, low excess air operation reduced NOX emissions
.by 21% to 447 ppm. Low excess air, staged firing at full load (one mill
on air only) reduced NOX emission by as much as 34% to 375 ppm. Low
'excess air, staged firing at 15% reduced load (two mills on air only)
reduced NOX emissions by 54% to 260 ppm using the most effective staged
firing pattern, 84 (top row front wall burners on air only).
The lignite coal fired at this station has a moisture content
of around 34 to 39 percent (Appendix B, Table 9). It was expected that
the high moisture would have a significant effect on baseline NOX emis-
sions. However, this boiler also has an abnormally high air preheat
temperature 100 to 150°F higher than normal designs thought to be necessary
for proper coal pulverization. The potential effect of the high coal
moisture content apparently was cancelled out in our tests by the high
air preheat temperature. Future lignite fired boilers would not require
abnormally high air preheat temperatures and NOX emissions, accordingly,
would be expected to be significantly lower.
-------
- 76 -
TABLE 6-9
EXPERIMENTAL DESIGN WITH RUN NO., 7, 02 AND PPM NOx
(Leland Olds, Boiler No. 1)
S, All Burners
Firing
S2 F Mill On
Air Only
S3 F & K Mills
Air Only
S, A & F Mills
Air Only
S A & H Mills
Air Only
S, A & K Mills
Air Only
LI - 218 MW
Gross Load
AI - Normal
Excess Air
(1) 3.97o-569
(1A) 3.6%- 5 64
(3) 4.27»-560
A2 - Low
Excess Air
(2) 2.17o-447
(4) 2.87o-375
L2 - 180 - 192 MW
Gross Load
f^l - Normal
Excess Air
(6) 4.97»-428
S7 A Mill (4A) 2.67.-418
Air Only (4B) 2 .7Z-401
(4C) 3.1%-475
A£ ~ Low
Excess Air
(5) 3.57o-342
(7) 2.27o-260
(9) 2.67o-329
(11) 3.57»-356
Runs 4A, 4B and 4C
conducted at 205 MW.
© © ; © ©
Rear Wall
(c)
^™^
c
®
Front Wall
Mill-Burner
Configuration
-------
- 77 -
FIGURE 6-12
PPM NO* (3% O2, DRY) VS % STOIC HKME TRIG
_ AIR TO ACTIVE BURNERS _
(LE LAND OLDS, BOILER NO. 1)
600
22
CO
ffl
I"
§
e\
O
CO,
i
500
STAGED
FIRING
400
300
200
100
0
70
80
90
100
110
120
130
AVERAGE % STOICHIOMETRIG AIR TO ACTIVE BURNERS
-------
- 78 -
6.1.1.2.3 Four Corners, Boiler No. 4
Arizona Public Service's No. 4 Boiler at their Four Corners
Station was also tested according to our planned test program design,
except that continuous electricity demand on the station prevented
testing at low loads, and the currently inoperative flue gas recirculation
system could not be utilized due to erosion problems. This unit, with
a maximum rated capacity of 800 MW gross load, is a single furnace
(with division wall), pulverized coal fired Babcock and Wilcox boiler.
It is fired with low sulfur, high ash Western coal. Boiler No. 5 at
the Four Corners Station is a "sister"-unit of similar size and design.
The latter was used for determining accelerated furnace water-tube
corrosion rates under baseline operating conditions.
In each of these two boilers, nine pulverizers feed 54 burners,
arranged in 18 cells of three burners each, as shown in ELgure 6-13. The
front wall has ten burner cells, while eight burner cells are located in
the rear wall of the furnace. Each boiler can maintain the full load
capacity of 800 MW with eight or nine pulverizers in operation when good
quality coal is fired, and all equipment is in good operating condition.
Operating variables during the short-term optimization phase of
the tests were boiler load, burner firing pattern, excess air level,
secondary air register setting, and water injection (used for improving
precipitator efficiency). Our gaseous sampling system was modified to
allow sampling from 18, instead of the usual 12 duct positions, with two
three-probe assemblies each in the north, middle, and south ducts between
the economizer and the air heaters.
Table 7, Appendix A contains a summary of the operating and
emission data from the 26 test runs completed on this boiler. Table 6-10
below, indicates the experimental design with run number, % oxygen and
ppm NOX.
The NOX emission data measured are summarized in Figure 6-14.
Baseline NOX emissions under normal operating conditions averaged a high
level of about 935 ppm, which is consistent with that expected from a
large, horizontally opposed, coal-fired boiler. Reducing the per cent
stoichiometric air to the active burners consistently reduced NOx emis-
sions for both normal and staged firing as shown by the least squares
regression line of Figure 6-14. The expected reductions in NOx for a 10%
reduction in % stoichiometric air calculated from least squares regression
analysis were 147, 184, 147, 159 and 166 ppm for firing patterns Si through
85, respectively.
Through staged firing, the average % stoichiometric air to the
active burners could be reduced considerably below the minimum level of
110% reached for normal firing, thus producing lower NOx emission levels.
Four staged firing patterns were tested: (1) 82 - top 8 burners on air
only, (2) 83-2 top burners of 4 cells on air only to produce a
"tangential" effect, (3) 84 - top 12 burners on air only and (4) 85 - cells
fed from pulverizers 5 and 9 on air only to produce a "tangential" effect.
Full load operation was maintained with 83 and 84 firing, while gross load
was reduced to about 730 MW (9% reduction) during 82 firing and reduced
to 600 MW during 84 type operation. NOx emissions under full load, low
-------
- 79 -
FIGURE 6-13
FOUR CORNERS STATION, BOILER NO. 4
PULVERIZER-BURNER CONFIGURATION
REAR WALL (EAST)
NORTH
WALL
(M)
©
43N
0
o
o
L
»6N
©
®
®
44N
0
o
o
471
O
o
o
i
43S
0
o
o
L
i5S
O
o
0
44S
O
o
o
46£
O
o
0
47S
0
o
o
SOUTH WALL
FRONT WALL (WEST)
9 PULVERIZERS NUMBERED 41 THROUGH 49.
18 BURNER CELLS NUMBERED WITH PULV. NO. "N" OR "S" FOR NORTH OR SOUTH
QTT TYnrrsTryM WA.LT_.-.
54 BURNERS DESIGNATED "T", "M" OR "B" FOR TOP, MIDDLE OR BOTTOM OF
OF EACH CELL.
E.G., 45NT IS TOP LEFT BURNER IN FRONT WALL OF NO. 4 BOILER
TOP BURNER OF CELL
NORTH SIDE OF DIVISION WALL
^NO. 5 PULVERIZER
*NO. 4 BOILER
-------
TABLE 6-10
EXPERIMENTAL DESIGN - % OXYGEN AND PPM NOX (3% 02. DRY BASIS)
(Four Corners, Boiler No. 4)
S. - Normal
Firing
54 Burners
Firing Coal
S2 - 8 Top
Burners
On Air
Only
S~ - Simulated
Tangential
8 Burn on Air
S4 - 12 Top
Burners
On Air Only
S - No. 5 & 9
Mill
Burners
On Air Only
Lt - 710 - 810 MW Gross Load
AI - Normal
Excess Air
DI - Open
Sec. Air
(1A) 5.6-982
(1) 4.6-848
(IB) 5.1-965
(1C) 4.5-843
(ID) 5.2-949
(IE) 3.4-741*
(IF) 3.1-715*
(7) 4.7-754
(9) 4.6-685
(15) 5.5-709
D2 - 1/2 Open
Sec. Air
(5) 5.0-932
(3) 4.6-695
A2 - Low
Excess Air
DI - Open
Sec. Air
(6A) 2.3-641
(6) 2.0-630
(4) 2.2-482
(12B) 3.7-458*
(12C) 2.8-473*
(14) 2.3-494
(12) 3.2-488
D2 - 1/2 Open
Sec. Air
(2) 2.5-659
(2B) 2.8-748
(8) 3.3-609
L2 - 590 - 600 MW Gross Load
AI - Normal
Excess Air
AI - Open
Sec. Air
(19) 6.5-816
(20) 6.4-801
D2 - 1/2 Open
Sec. Air
A2 - Low
Excess Air
D! - Open
Sec. Air
(21) 3.0-452
D2 - 1/2 Open
Sec. Air
I
OT
O
* 100-200 gal. water/hour injected into furnace.
-------
- 81 -
900
800
I 700
m
CM
O
600
500-
FIGURE 6-14
PPM NOx (3% O2, DRY) VS %
STOICHIOMETRIC AIR TO ACTIVE BURNERS
I I I I I ^ T
(FOUR CORNERS, BOILER NO. 4) _ OA)
(IB)
[ID)
•^-^
yNormal wiring
/710 - 800 MW
/
//
Staged (S9) Firing - 730 MW
°
400-
Staged Firing - S4 and S& - 600-800 MW
300-
200-
I
Symbol
Sl
s2
S3
S4
S5
O
n
A
V
O
BUI
Firing
Coal
54
46
46
42
42
'Hers
Air
Only
0
8
8
12
12
Gross Loac
750-800 MW
730 MW
794-800 MW
725-805 MW
590-600 MV
I
I
I
80 90 100 110 120 130
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
140
-------
- 82 -
excess air, staged operation (83 and 84) were reduced to about 490 ppm or
by about 48% from baseline operation. Operation with firing pattern 82
at 730 MW produced 482 ppm NOX (458 to 473 with water injection), while
firing pattern 85 at about 600 MW produced 452 ppm NOX emissions.
Wide open secondary air register settings could reduce NOX emis-
sions by a small amount compared with closed settings (presumably because
of reduced combustion intensity) , but only in combination with low excess
air firing. As before, the effect of damper settings on NOX emissions
was significant, but second-order with respect to the main effects of
reduced excess air and staging.
Data from test runs numbered 12C and 12B were obtained with
staged firing (8 burners on air only) while the boiler operator used
water injection to help improve precipitator efficiency for particulate
removal. The reduction in NOX of about 80 ppm from the expected level
of about 543 ppm is not altogether surprising, based on our estimate of
0.2 Ib. H20 injected/lb. coal fired. This quantity of water injection
should reduce flame temperatures sufficiently to allow for the above
degree in NOX emission reduction.
6.1.1.3 Gaseous Emissions from
Tangentially Fired Boilers
Four Combustion Engineering designed, tangentially fired,
pulverized coal boilers were tested: Barry No. 3, 250 MW; Naughton No. 3,
325 MW; Dave Johnston No. 4, 348 MW; and Barry No. 4 rated at 350 MW
gross load. The number of burners and burner levels were 20 and 5 for
Naughton No. 3 and Barry No. 4, 48 and 6 for Barry No. 3, and 28 burners
arranged in 7 levels for Dave Johnston No. 4. The Naughton and Dave
Johnston boilers were fired with Western coals, while the two Barry
boilers tested were fired with Alabama coal.
6.1.1.3.1 Barry, Boiler No. 3
Alabama Power Company's Boiler No. 3 at their Barry Station
was tested at the boiler operator's request for gaseous emissions only
in a short-term optimization program.
This unit is a 250 MW maximum continuous rating, twin furnace
tangential, pulverized coal fired Combustion Engineering boiler. It has
a separated furnace arrangement, with radiant and horizontal superheater
surfaces in both furnaces. The pendant and platen sections constitute
the superheat surface in one furance, and reheat surface in the other one.
Six pulverizers feed 24 tangential burners (six levels of four burners)
in each of the two furnaces. —
-------
- 83 -
This boiler was of special interest, because cf the small value of
31.25 MW per "equivalent furnace firing wall". Our correlation based on
previously obtained data for coal fired boilers (4_) would predict a
baseline (20% excess air) NOx emission level of 412 ppm for this parameter.
Actual measurements for run 1 baseline operation resulted in a NOX value
of 410 ppm, in good agreement with the correlation.
Table number 8 of Appendix A contains a summary of operating
and emission data for the 8 test runs completed on this boiler. Table 6-11
shows the experimental design with average % oxygen and ppm NOX for each
run.
Operating variables included in the test program were excess
air level, air damper settings, and pulverizer mill fineness setting.
Planned reduced load and staged firing tests could not be implemented,
because mechanical problems with a condenser water valve prevented such
operation, despite all the efforts of the plant personnel to correct this
problem.
As expected, excess air level exerted a major effect on NOX
emissions. These results are shown in the least squares regression line
of Figure 6-15. From a baseline level of about 412 ppm at 117% stoichio-
metric air to the burners, NOX emissions were reduced by about 24% to
310 ppm at 106% stoichiometric air. The effect of damper settings was
very small, 7%, and that of mill fineness was negligible. The normal
practice of 100% open auxiliary dampers and 40% open coal dampers pro-
duced lower NOX emissions than the reverse damper settings.
6.1.1.3.2 Naughton, Boiler No. 3
Utah Power and Light's No. 3 boiler at their Naughton Station
was one of two modern, 320 to 350 MW maximum rated single furnace, pul-
verized coal fired, Combustion Engineering boilers tested. The other
one was Alabama Power's No. 4 Boiler at their Barry Station. Both boilers
have five levels of four corner burners each. Gaseous emission results
obtained in testing the latter unit will be presented in a subsequent
section of this report.
Naughton unit No. 3 was designed to fire a sub-bituminous, low
heat content (9,500 Btu/lb. HHV), low sulfur, high moisture content,
Western coal. The boiler was designed for a larger turbine-generator
than the one actually installed. This factor, in combination with the
lack of "seasoning" of the superheat and reheat surfaces, and the type
of coal fired in this new unit has resulted in a steam temperature control
problem. The use of tilting burners and atfemperation water are the means
available for controlling steam temperatures. To the date of our tests
it had been necessary at load levels exceeding 280 MW to tilt the burners
-------
- 84 -
TABLE 6-11
TEST PROGRAM EXPERIMENTAL DESIGN - BARRY, BOILER NO. 3
(Run No., Average % Oxygen, and ppm NOX (3% 0_ Dry Basis)
Measured in Flue Gas)
Dl
Secondary
Air
Dampers
100% Aux.
30% Coal
D2
Secondary
Air
Dampers
40% Aux.
100% Coal
Fl
Normal
Mill
Fineness
F2
Coarse
Mill
Fineness
Fl
Normal
Mill
Fineness
Coarse
Mill
Fineness
LX 250 MW
Si All Mills
Firing Coal
AI Normal
Excess
Air
(1)
3.1 - 410
(7)
3.5 - 402
(3)
3.2 - 425
(6)
3.5 - 420
A« Low
Excess
Air
(2)
1.3-310
(8)
1.4-312
(4)
1.9-350
(5)
2.0-350
-------
- 85 -
FIGURE 6-15
PPM NOx (3% O2 DRY BASIS) VS %
STOICHIOMETRIC AIR TO ACTIVE BURNERS
(BARRY, BOILER NO. 3)
500
§
CO
•
400
*
0
fc
s
Pk
300
Normal
Firing
200
80
90
100
110
120
130
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 86 -
down, add attemperation water, lower excess air, and use furnace soot
blowers almost continuously. It may be necessary, according to Combustion
Engineering representatives, to reduce the reheat surface area to overcome
this control problem.
Other operating problems encountered in this test program were
furnace slagging (particularly at high loads, with low excess air and
tilting burners down) even under normal operating conditions, and the high
silica content of the boiler feed-water, caused by pin-hole leaks in
the condenser tubing.
The above problems were taken into account for the design of the
statistical test program. Except for base line tests, our short-term NOX
optimization phase was conducted at less than full load levels, to avoid
the limited flexibility associated with operating problems. The six
operating variables studied in the short term optimization tests were
gross boiler load, burner firing pattern, excess air level, burner tilt,
secondary air damper setting, and coal pulverizer fineness setting.
Because of the above-mentioned operating problems with this new boiler,
the 300-hour accelerated corrosion test was performed only under normal
operating conditions, as will be discussed later.
Table number 9 of Appendix A is a summary of the operating
and emission data obtained from the 26 test runs completed on this
boiler. Table 6-12 presents the test program experimental design with
average % oxygen and ppm NOX for each test run.
Baseline NOX emissions at full load measured 531 ppm. Reducing
load from 334 MW to 200 MW (by 40%) reduced NOX emissions by 73 ppm
(from 531 to 458 ppm) or only about 14%. Coarse mill fineness had a
detrimental effect of increasing NOX emissions by about 40 ppm (17%) during
the low excess air, staged operation compared to normal fineness as shown
in Figure 6-16. Table 6-13 presents the change in coal fineness measured
on samples from four mills.
The emission data obtained in testing this boiler.are shown by
the least squares regressions of Figure 6-17. Significant reductions in
NOX emissions were achieved from the baseline level of about 530 ppm
(which is relatively low for a coal fired boiler of this size, but typical
of tangentially fired units from the standpoint of NOX emissions) . With
normal firing, quite a steep decrease was found by reducing the percent
stoichiometric air to the active burners to 110%, resulting in a reduction
of about 30% to 380 ppm. Staged firing in combination with low overall
excess air (less than stoichiometric air/fuel ratio in the active burners)
at 90% of full load resulted in NOX levels as low as 219 ppm, or a
reduction of about 60% from the baseline NOX level. These highest
reductions in NOX (311 ppm), were achieved with "abnormal" air register
settings (coal-air 30% open, and auxiliary air 20% open). Additional small
reductions in NOX emissions could be obtained through the use of optimum
burner tilt positions, and pulverizer mill fineness, each contributing about
10% to the NOX emission reduction achieved.
-------
TABLE 6-12
TEST PROGRAM EXPERIMENTAL DESIGN - NAUGHTON, BOILER NO. 3
(Run No., Average
Oxygen and ppm N(X_ (3% 00 , Dry Basis) Measured In Hue Gas)
" Z
~~ — L4J_Secondary
Cl
Normal
Mill
Fine-
ness
C2
Coarse
Mill
fine-
ness
Horiz .
Burner
Tilt
T2 -
Down
Burner
Tilt
T3 - Up
Tilt
T -Hor.
Tilt
T2 -
Down
T -Up
Tilt
L - 328 - 340 MW
A! - All
Pulv. Firing
Ai-Nor.
Exc . Air
V
(18) 3.9
494
(26) 4.4
568
A2 -
Lea
Dr
(19) 2.0
379
L2
sr
A! -
Nea
Dl-
(24) 3.6
569
(25) 4.2
549
- 300 - 315 MW
S2 - Top Pulv.
Air Only
A2 - Low
Excess Air
V
(20) 2.7
236
V
(21) 2.3
219
L3 - 250 - 275 MW
sr
Ai-
Nea
V
(1) 4.9
537
(23) 3.6
510
S, - Top Pulv.
Air Only
Al -
Nea
Dl-
(2) 4.9
304
(22)*3.1
331
A2 - Low
Excess Air
V
(3) 3.6
265
(4) 3.7
266
(6) 3.1
216
(5) 3.6
284
(9) 3.1
245
V
(10) 3.0
197
(7) 3.0
213
(11) 3.5
216
(13) 3.7
235
(8) 3.2
251
(12) 3.7
273
L^ - 200 MW
V
Al -
Nea
Dr
(14) 4.2
458
S3 - 2 Pulv. Off,
Top Pulv. Air Only
A! -
Nea
Dr
(15) 4.5
169
A2 - Low
Excess Air
Dr
(16) 3.2
182
V
(17) 4.2
176
i
00
*-J
1
* Top pulverizer off with 2nd air registers partly open.
[1] Secondary air registers: DI - 20% auxiliary air, 80% coal air; D2 - 60% auxiliary air, 20% coal air.
-------
FIGURE 6-16
EFFECT OF MILL FINENESS AND BURNER TILT ON
EMISSIONS FOR LOW EXCESS AIR STAGED FIRING
(NAUGHTON, BOILER NO. 3)
30O
S
cT
e«
CO
i
25C-
20C-
,21 Coarse
Mill Fineness
Normal
ill Mill Fineness
oo
00
150.
-30
-20
-10
0
+ 10
+20
+30
BURNER TILT (° FROM HORIZONTAL)
-------
TABLE 6-13
PULVERIZER SCREEN ANALYSES
NAUGHTONf BOILER NO. 3
(Normal vs. Coarse Classifier Setting*)
Kill No.
1
2
3
4
Averages
% Passing Through
48 Mesh Screen
Norr.r.l Ccc.roc
99.2 97.2
99.6 98.2
95. 0 96.6
99.4 97.3
99.3 97.4
Diff. % 1
2.0
1.4
2.4
1.8
1.9
t = 9,1
% Passing Through
100 Mesh Screen
Normal Cor.rse
88.4 32.0
95.2 87.6
89. 6 84.1
90.8 83.6
91.0 84.3
% Passing Through
200 Mesh Screen
fliff. % i Normal Course j Diff. %
6.4
7.6
5.5
7.2
6.7
t » 14.4
76.7 60.9
75.4 64.6
65.1 61.6
69.3 64.8
71.6 63.0
15.8
10.8
3.5
4.5
i
8.6
t = 3.0
I
oo
* The classifier can be set from 0 (very coarse) to 4 (very fine).
For these tests the classifier vas set at: 2.1 normally and at 1.0
for the coarse test runs.
-------
- 90 -
FIGURE 6-17
PPM NOX (3% O2, DRY) VS %
550
500
450
g 400
<
PQ
><
§
* 350
T 1 \ 1 r
STOICHIOMETRIC AIR TO ACTIVE BURNERS
(NAUGHTON, BOILER NO. 3)
Firing Pattern Symbol
Sj - NORMAL O
S - TOP PULVER-Q
IZER ON AIR ONLY
S - 2 PULVER- A
3 IZER OFF
LrFOSS^
Load
2"50-340
250-315
200
Burners
Tilted
Down
Normal Firing
(Horizontal Tilt)
300
PM
250
200 -
150
Itaged Firing
(Horizontal Tilt)
100
I
I
i
60 70 80 90 100 110 IzO
AVERAGE % STOICHIOMETHIC AEP TO ACTIVE BURNERS
~IBO
-------
- 91 -
6.1.1.3.3 Barry, Boiler No. 4
Alabama Power's Boiler No. 4 at their Barry Station was tested
successfully through all three phases of our test program design.
Representatives of Combustion Engineering actively participated in this
series of tests. As mentioned before, this new 350 MW maximum rated
capacity, single furnace, pulverized coal fired Combustion Engineering
boiler is similar to Naughton unit No. 3. Both are representative of
that manufacturer's current design practices. In Barry No. 4, five
pulverizers feed 20 burners that are corner-mounted at five levels of
the furnace. This boiler is designed for firing Eastern bituminous coal
having a HHV of 12,000 Btu/lb.
Table Number 11, Appendix A contains a summary of the operating
and emission data obtained from the 46 test runs completed on this boiler.
Table 6-14 shows the test program experimental design with % oxygen and
ppm NOX listed for each test run. For this boiler, flue gas samples were
taken from ducts after the air preheater. Regression analysis of simul-
taneous measurements of the Q£ concentration upstream and downstream of
the air preheater in several test runs provided a basis (see Figure 6-18)
for estimating the excess air supplied to the furnace.
Seven operating variables were varied independently in the
short period NOX optimization phase of the test program. Gaseous emission
data obtained from this phase are presented in the least squares correla-
tions of Figure 6-19. As discussed below, the most important variables
from the standpoint of NOX emission control were excess air level, staged
firing, and burner tilt. Boiler load, secondary air register settings,
type of coal and coal fineness were less important.
Baseline NOx emissions at full load were only 423 ppm due in
part to the relatively low level of excess air (15%), and to the
tangential mode of firing. Excess air level was the most important
variables as shown by the regression lines of Figure 6-19. Under normal
firing operation with horizontal burner tilt an eight % reduction of
excess air (from 15% to 7%) reduced NOX to 350 ppm, or by 17%.
Burner tilt also had an important effect on NOX emission rates.
Down tilt operation increased NC^ emission by an average of 53 ppm (14%)
under normal firing, and by 5% under staged firing compared to horizontal
burner tilt. Up tilt gave a small further improvement but caused steam
temperature control problems and increased oxygen stratification between
flue gas ducts.
Staged firing (top pulverizer off) at 280 to 325 MW resulted in
lowering NOx emissions by about 34% (to about 280 ppm) when operating
with 90% stoichiometric air to active burners. Staged firing with the
top two pulverizers off at 185 MW produced less than 200 ppm NOX under low
excess air firing.
-------
- 92 -
TABLE 6-14
TEST PROGRAM EXPERIMENTAL PESIGN - BARRY. BOILER NO. 4
(Run Ho. Average 7. Oxygen and PPM NC (37, 0,, Dry Basis) Measured in Flue Gas)
(1)
cl Fl -
Normal
Alabama Mill
Coal Fineness
With
C Pulv.
Firing
Petr.
Coarse
Mill
Fineness
2 1 Normal
Alabama Mill
Coal Fineness
On
All
Pulv.
S Fi -
Normal
Midwest Mill
Coal + Fineness
C. Pulv.
Firing
Coke
T -Horiz
Tilt
T.-DoVm
Tilt
T,-Up
Tilt
T, -Horiz
Tilt
T?-Down
Tilt
T -Horiz
Tilt
T.-Down
Tilt
T,-Up
Tilt
T. -Horiz,
X Tilt
T2~Down
Tilt
Lj - 325 - 360 »I (Gross Load)
ST - All 5 Pulv. Firing Coal
Aj-Nor.
Exc. Air
Di-Nor.
Setting
(1) 4.4-415
(33) 4.37.
497
(13) 4.7-420
(13A) 3.8-415
(17) 5.17,
441
A2~Low Excess
Air
Di-Nor.
Setting
(2) 3.9-398
(42)* 3.9-396
(43)* 2.7-349
(34) 3.17.
445
(3) 3.67.
349
(29) 2.87.
336
(30) 3.67.
336
D2'Rev.
Setting
(35) 3.8-409
(37) 3.9-441
(4) 2.57.
364
(31) 2.87.
398
L2 - 28C - 325 fW (Gross Load)
Si - 4 Pulv.
Firing
Ai-Nor.
Exc. Air
Dl-Nor.
Setting
(50)* 4.47.
436
(42A) 5.0-396
(42B) 4.5-370
S2 - Top Pulverizer on Air Only
A- -Nor.
E:c. Air
D -Nor.
Setting
(51 5.47.
313
(14) 5.17.
309
(18) 6.37.
334
A2-LOW Excess
Air
Dj-Nor.
Setting
(6) 4.87.
286
(10) 3.07.
289
(7) 4.47.
294
(11) 2.97.
299
(15) 3.67.
245
(19) 4.9-283
(19A) 4.4-308
(19E) 4.0-275
D2-Rev.
Setting
(9) 4.47.
295
(8) 2.4T.
257
(12) 4.3%
297
(16) 3.37.
264
(32) 5.77.
282
(20) 3.17.
273
Lj - 180 - 210 MW (Gross Load)
Sl -
A,-Nor.
Exc. Air
D,-Nor.
Setting
(25) 6.07.
440
83 - Top 2 Pulv. o£f;
Top Pulv. Air Only
Al-Nor.
Exc. Air
Dl-Nor.
Setting
(27) 7.17.
260
A2~tow Excess
Air
Dl-Nor.
Setting
(26) 3,77.
189
D2-Rev.
Setting
(28) 4.37.
232
S, - Top Pulv. Air
Cray; C Mill Off
Aj-Nor.
Exc. Air
Di-Nor.
Setting
(40) 7.77.
338
A] -Nor.
Exc. Air
Di-Nor.
Setting
(41) 3.97.
200
(1) Secondary air register settings: normal, auxiliary 100% open and coal 50% open; reversed, auxiliary 507D open, coal 100% open.
* Secondary air registers: Auxil. - 40% open, Coal - 507D open.
-------
>H
I
05
W
ffi
g 4
W
g
PK
w
ffl
FIGURE 6-18
% OXYGEN MEASURED IN FLUE GAS BEFORE
AND AFTER AIR PREHEATER
(BARRY, BOILER NO. 4)
A
Duct B
y= 0.77 + O.SOx
u>
I
0
% O2 - AFTER AIR HEATER - X
-------
- 94 -
FIGURE 6-19
PPM NOx (3% O2, DRY) VS %
STOICHIOMETRIC AIR TO ACTIVE BURNERS
(BARRY, BOILER NO. 4)
500
450
400
en
i— i
w
<
m
><
g
ca
O
eP
CO
350
300
ft
250
200
150
T
S.. - Down Tilt
S, - Horizontal Tilt
O
s9 ou
^ '
Down
1 1
Symbol
O
O
D
D
B! =
S2 =
i
Firing Burner Gross
Pattern Tilt Load
S.. Horiz. 340
Sj Down 340
S2 Horiz. 295
S2 Down 295
All burners firing coal
Top row burners on
air only
1 1
1
80
90
100
110
120
130
140
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 95 -
The effect of secondary air registers settings on NOX emissions
depended upon the burner tilt position. With horizontal burner tilt,
normal damper settings (auxiliary 100% open and coal 50% open) produced
about 7% less NOX than reversed settings. However, with burners tilted
down, reversed damper settings generally produced lower NOX emissions
than did normal settings.
Boiler load, coal type and coal fineness were minor operating
variables from the standpoint of NOX emission control. Reducing load
by 12% reduced NOX levels by about 9% which is in line with our results
obtained on other coal fired boilers. Coal source had a small, but
satistically significant effect on NOX emission levels. Alabama coal
test runs produced about 23 ppm higher NOX emissions than did Midwest
coal after allowing for differences in excess air levels. This difference
is possibly explained by the slightly higher nitrogen content of the
Alabama coal. Pulverizer coal fineness was changed to coarse in only two
test runs, and NOX results obtained did not show statistically significant
differences.
Petroleum coke was fired through the middle level burners
(Pulverizer "C") on most test runs. Comparison of the eight test runs
conducted with Alabama coal fed to all pulverizers with similar runs firing
petroleum coke or petroleum coke/coal mixtures indicated no statistically
significant differences in NOX emission levels.
6.1.1.3.4 Dave Johnston, Boiler No. 4
Boiler No. 4 at the Dave Johnston Station of Pacific Power and
Light is a Combustion Engineering Company designed, tangentially fired,
single furnace boiler with a maximum continuous rating of 2,450,000
pounds of primary steam generated per hour or about 348 MW gross load.
Seven pulverizers feed coal to 28 tilting tangential burners located
at the corners of 7 elevations. The furnace is 50 feet wide and 42 feet
deep with a volume of 280,000 cubic feet. Design operating conditions
at maximum continuous rating include steam temperatures of 1005°F leaving
the superheater and the reheater turbine throttle pressure of 1890 psig
and reheat to the boiler of 475 psig and 670°F.
Table 10 of Appendix A contains a summary of operating and
emission data for the six test runs completed on this boiler. Maximum
load was limited by ID fan capacity due to plugging of the air preheaters.
Therefore, our test runs were made at a reduced load of 303-312 MW
instead of 345-350 MW full load. Normally, this boiler can operate at
full load with one or two pulverizers off. During our test period it
was not possible to remove the top mill without reducing load since
there were always two other mills off, due either to mechanical problems
or to necessary, scheduled maintenance. Thus, no staged firing tests
were possible. Operating variables included in the experimental program
were mills off, excess air level, burner tilt and primary air flow rate.
The variation in primary air (coal transport air) flow rate was made in
order to achieve higher loads without increasing ID fan output.
-------
- 96 -
Table 6-15 indicates the experimental design of operating
variables with average flue gas measurements of % 02 and ppm NOx (3%
02, dry basis) shown for each test run. Figure 6-20 is a plot of ppm
NOX vs % stoichiometric for the data collected during our test runs.
Analysis of the flue gas emission data indicated a consistent
difference in flue gas measurements from duct "A" (probes 1 and 2) and
duct "B" (probes 3 and 4) generally characteristic of tangentially fired
boilers. Duct "A" averaged about 2.3% oxygen and 20 ppm NOX, respectively,
less than the corresponding measurements from "B" duct. This difference
in oxygen levels may be attributed to different burning rates prevailing
due to he centrifugal separation of larger coal particles arriving to the
furnace arch, before the flue gas stream is split into two ducts.
Baseline NOX emission rates at partly reduced load (12%
from full load) were 434 ppm (3% 02, dry basis). Reducing excess air
from 124 to 113% of stoichiometric reduced NOX emissions to 384 ppm, or
by 12%. Operating with burners tilted down resulted in raising NOX
emissions by 40 ppm, or about 10%. Test runs No. 10 and 17 were con-
ducted with increased primary air damper openings so that more coal would
be transported with the same fan settings as used in previous test runs,
and consequently the load would be at increased levels. NOX emissions
rates were about 13% lower in these test runs than corresponding earlier
test runs. Horizontal burner tilt operation produced less NOX emissions
than down tilt burner operation. Additional experiments are needed to
verify these results.
6.1.1.4 Gaseous Emissions from
Turbo-Furnace Boilers
6.1.1.4.1 Big Bend. Boiler No. 2
Tampa Electric Company's Boiler No. 2 at their Big Bend Station
has been the only Riley-Stoker turbo—furnace unit tested by Esso under
EPA sponsorship. This pulverized coal fired, 450 MW maximum continuous
rating, single furnace boiler is fed by three pulverizer mills. Altogether,
24 Riley directional flame burners are fired normally, with one row of
12 burners in the front wall, and another row of 12 burners in the rear
wall.
Maximum load was limited to 375 MW, due to steam temperature,
potential slagging, and other operating problems not related to our test
program. (It is our understanding that until the time of our test, gross
load on this unit had never exceeded 400 MW.) Excess air was set at
normal operating levels, or at the minimum level dictated by maximum
acceptable CO levels measured in the flue gas, and in the slag catcher
at the bottom of the furnace. Other operating variables included in the
statistically designed short-term phase (this was the only phase of our
overall program design performed at Big Bend) were operating with fly-
ash reinjection (practiced to improve carbon burn-out efficiency and
slagging characteristics) or without it, and positioning of the
-------
- 97 -
TABLE 6-15
EXPERIMENTAL DESIGN WITH % Q£ AND PPM NOX (3% 02.BASIS)
(Dave Johnston Station, Boiler No. 4)
^x>»». *Primary
Burner~s'NVAir
Tilt ^\
Tl
Horizontal
T2
-10° Down
T3
+16° Up
S;L Normal Firing Pattern
(Mills 17 & 20 Off)
AI Normal
Excess Air
Pl
(1)
4.2-434
P2
(10)
3.9-362
(17)
3.9-380
A2 Low
Excess Air
Pl
(2)
3.2-386
(3)
3.2-414
(4)
3.4-381
P2
(16)
S2 Staged Firing
Top Mill - Air Only**
AI Normal
Excess Air
Pl
(5)
P2
(12)
A£ Low
Excess Air
Pl
(6)
(7)
(8)
P2
(13)
(14)
(15)
* Primary Air: P Normal Primary Air Flow
P~ High Primary Air Flow
** Pulverizer mechanical problems and maintenance
schedules prevented the running of these tests.
-------
FIGURE 6-20
PPM NOx (3% Oo, DRY) VS %
STOICHIOMETRIC AIR TO ACTIVE BURNERS
(DAVE JOHNSTON STATION, BOILER No. 4)
500
g
CM
o
s
_x
400
300
1 1 1 1
Down Tilt >
/ >
© /
/ /
/ ©0©
/ @
i i i i
80 90 100 110 120
1 1
/Horizontal and
, , Up Tilt
(i)
Down Tilt Increased
Primary
) Horizontal Tilt Air
130 140
VO
00
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
- 99 -
directional air vanes. Normal position is 15° below horizontal for the
air vanes. During our tests baseline data were taken with the dampers in
the normal position and "low NOX" emission data were obtained with the
dampers aligned either 15° below the normal position, in both front and
rear burners, or the front directional vanes were set at 15° below the
normal position, and the rear directional vanes 15° above it. Simulated
"staged" firing, at reduced load levels, was attempted by opening up the
secondary air registers on selected burners, so that the active burners
were supplied with 80% of stoichiometric air.
Table 12, Appendix A contains a summary of the operating and
emission data obtained from the 14 test runs completed in Big Bend No. 2
boiler. The experimental design with average % oxygen and ppm NOX data
for each run is shown in Table 6-16. A diagram of the mill-burner con-
figeration is also shown at the bottom of table to aid in visualizing
the "simulated" staged firing patterns.
The NOX emission results obtained are shown in the least squares
regression of Figure 6-21. Reducing the air to the burners from the
normal level of 115% of stoichiometric to 107% decreased NOX emissions
from about 600 ppm at 370 MW to about 400 ppm, or a reduction of about
one third. This decrease in NOX with reducing excessing air is steeper
than that generally observed in wall and tangentially fired units. On
the other hand, it should be noted that the "baseline" NOjc emission was
determined at a load reduction of 18%, compared with maximum continuous
rating. Further load reduction produced, as expected, further decreases
in NOX.
"Staged" firing, which in this instance was quite different from
the normal pattern of staging burners, produced only a 10% reduction in
NOX at the low load of 230 MW, as shown in Figure 6-21. It was interesting
to note that NOx levels were consistently lower at the ends of the
furnace compared to its middle as shown in Figure 6-22.
The best NOX reductions were obtained with front wall direc-
tional air vanes tilted 15° down, and rear vanes tilted 15° up from
their normal alignment. Flyash reinjection had no significant effect
on NOX emissions.
Further testing is required with coal-fired turbo-furnace
boilers to define optimum operation for NOX control, taking into account
steam temperature control, slagging, and potential furnace water-tube
corrosion problems.
-------
TABLE 6-16
EXPERIMENTAL DESIGN WITH % 0? AND PPM NOX (3% 0? BASIS)
(Big Bend Station, Boiler No. 2)
TI Directional
Vanes
Front - 15°
Rear - 15°
T2 Directional
Vanes
Front - 15°
Rear - 15°
1^ 370 - 385 MW
AI Normal
Excess Air
(1) Ash On
2.8-614
(2) Ash Off
2.8-587
(4 A) Ash On
2.8-547
(4B) Ash Off
2.9-558
A2 Low
Excess Air
(3) Ash Off
2,0-464
(5) Ash Off
1.4-398
L2 300 MW
Aj Normal
Excess Air
(11) Ash Off
2.5-397
(9) Ash Off
2.9-378
A2 Low
Excess Air
(12) Ash Off
2.1-362
(10) Ash Off
1.8-341
L3 225 - 230 MW
AI Normal
Excess Air
(6) Ash On
3.4-370
(20)* Ash Off
3.4-350
A2 Low
Excess Air
(21)** Ash Off
3.5-312
(22)*** Ash Off
3.5-312
o
o
* Run 20 B mill off, secondary air dampers closed on idle burners.
** Run 21 B mill off, secondary air dampers open on 1/2 idle burners.
*** Run 22 B mill off, secondary air dampers open on all idle burners.
** Mill Burner
Configuration
Air Only Burners
Shown by Arrows
Rear Wall Burners
ABCBACCABCBA
ABCBACCABC
Front Wall Burners
B A
-------
- 101 -
FIGURE 6-21
PPM NO* (3% 02, DRY) VS %
STOICHIOMETRIG AIR TO ACTIVE BURNERS
1 1 1
(BIG BEND STATION, BOILER NO. 2)
600
500
§
CM
O
eP
in
i
400
300
Staged" Firing
225 MW
Symbol
370-380 MW
225 MW
Flyash
Reinjection
DLl'. VatifeS Beg.
From Normal Positic i
Front/Rear
O
O
D
D
Off
On
Off
On
-15/-15
-15/-15
-15/+15
-15/+15
200
_L
70
80
90
100
110
120
130
AVERAGE % STOICHIOMETRIC AIR TO ACTIVE BURNERS
-------
FIGURE 6-22
500
PPM NOx EMISSIONS VS PROBE LOCATION
(BIG BEND STATION, BOILER NO. 2)
CO
<
n
40°
Q 300
CM
O
_
g 200
100
Directional
Vanes
Front/Rear
) -15% 15°
) -15% 15°
J -15° A 15°
3 -15V+150
\ -15°/-15°
1 -15°A15°
Excess
Air
Level
Normal
Normal
Normal
Low
Low
Fly Ash
Re injection
Yes
No
Yes
No
No
o
I-O
0
Left
4 Right (Facing Front of Boiler)
PROBE NUMBER
-------
- 103 -
6.1.2 Particulate Emission Results
The results of the particulate emission tests obtained on this
program, summarized in Table 6-17, are internally consistent and appear
to be reliable within the limitations of this type of testing. As men-
tioned in section 4.2.2, the objective of this work was to obtain sufficient
particulate loading information to determine the potential adverse side
effects of "low NO " firing techniques on particulate emissions by com-
paring measurements of total quantities and percent unburned carbon with
similar data obtained under normal or baseline operating conditions. The
differences in emission values and particulate carbon content between
baseline and "low NOX" operation summarized in Table 6-17 afford an
assessment of the adverse affect of "low NOX" firing on a given boiler.
Not unexpectedly, some "side effects" did develop with "low NO "
firing. Total quantities of particulate tend to increase but not signifi-
cantly and the consequences appear to be relatively minor. This trend
would have an adverse effect on the required collection efficiency of
electrostatic precipitators to meet present Federal emission standards,
but the increases in efficiency indicated by these limited tests appear
to be quite small.
Another side-effect of "low NO " operation is that on carbon
losses. Carbon content of the particulates with "low NO " operation are
shown in Table 6-17 to increase significantly for front wall and horizon-
tally opposed fired boilers. The data are quite scattered, and these
increases do not appear to be directly related to the change in emissions
with "low NOX" firing technqiues or other boiler oper?ting variables.
For example, the tests on boiler No. 4 at the Four Corners Station of
Arizona Public Service Company, a horizontally opposed fired boiler burn-
ing western coal, showed marginal decreases in particulate carbon content.
Surprisingly, there is some evidence that "low NO " firing techniques for
tangentially fired boilers may decrease carbon losses significantly. It
also appears that "low NO " operation may decrease carbon losses for boilers
fired with Western coals. Such improvements, however, would not be substan-
tial since unburned combustible losses with these coals are already low.
The effect of these changes in combustibles on boiler efficiency is dis-
cusssed in Section 6.1.4 and are shown to be relatively insignificant.
It is important to note that no major adverse side effects appear
to result from "low NO " firing with regard to particulate emissions.
Additional test data on a variety of boiler types are required to firm up
on these conclusions. It would also be desirable to include investigation
into potential changes in particle size distribution and the resultant
effect on precipitator collection efficiency in the scope of future tests.
Potential changes in fly ash resistivity with respect to precipitator per-
formance is another area for investigation.
-------
TABLE 6-17
Utility
TVA
Georgia
Power
Cojnpany
Arizona
Public
Service Co.
Alabama
Power
Company
Utah Power
& Light Co.
Gulf Power Co.
Test No.
1A
IB
10-C-l
10-C-3
26-A-l
1C
ID
IE
1G
1H
52D
52E
IE
IF
12A
12B
42A
42B
19A
19B
23
23
25
26
1
26B
PARTICIPATE EMISSION TEST RESULTS
Firing
Condition
Base
Base
Low NOX
Low NOX
Low NOX
Base
Base
Base
Low NOX
Low NO
Low NOX
Low NOY
A
Base
Base
Low NO
Low NOX
Base
Base
Low NOX
Low NOX
Base
Base
Base
Base
Base
Low NOY
Av.
Gr/SCF
@ Std.
Cond.
2.68
4.62
2.32
3.36
3.13
1.83
1.86
2.26
2.47
2.60
2.00
2.65
4.52
5.36
4.87
3.26
1.17
3.08
3.31
3.32
0.448
0.301
0.752
0.800
2.54
3.82
lb./106
BTU
4.65
7.89
3.84
5.62
5.10
3.03
3.20
3.84
3.71
3.92
3.12
4.14
7.65
8.91
8.38
5.59
2.00
5.14
5.57
5.49
0.76
0.51
0.44
1.48
4.34
6.45
Grams/
106 cal.
8.37
14.20
6.91
10.12
9.18
5.45
5.76
6.91
6.68
7.06
5.62
7.45
13.77
16.04
15.08
10.06
3.60
9.25
10.03
9.88
1.37
0.92
0.81
2.59
7.81
11.61
Reqd.
Efficiency
To Meet
0.1 lb/
106 BTU
97.85
98.73
97.40
98.22
98.04
96.70
96.88
97.40
97.30
97.45
86.79
97.58
98.69
98.88
98.81
98.21
95.00
98.05
98.20
98.18
86.91
80.55
77.73
93.04
97.70
98.45
%
Carbon on
Particulate
6.29
5.90
10.55
8.46
12.40
5.50
3.17
2.80
6.73
11.82
9.98
7.41
0.69
0.53
0.18
0.46
24.23
25.83
14.75
18.77
22.62
22.62
4.44
1.80
5.08
8.15
Coal
Ash
Wet. %
15.87
18.39
11.50
14.38
15.39
12.05
9.72
8.58
11.28
8.43
10.3
11.86
21.92
21.96
23.13
21.12
4.89
4.86
10.68
8.82
8.16
8.16
6.78
8.10
10.20
12.04
HHV
BTU/lb.
Wet
11,452
11,477
11,918
11,231
10,961
12,310
12,589
12,121
12,200
12,574
11,178
11,887 i
i— '
8,821 °
8,811 i
8,913
8,915
12,706
12,641
11,918
12,720
10,293
10,293
10,273
9,992
11,186
11,282
-------
- 105 -
6.1.3 Accelerated Corrosion Probing Results
As mentioned in Section 4.2.3, corrosion probes were installed
in the furnaces of the boilers tested by inserting them through avail-
able openings closest to the areas of the furnace susceptible to corrosion.
Probe locations are indicated in Figure 6-23. Prior to installing the
probes in the test furnace, the probes were preapred by mild acid pickling,
pre-weighing the coupons, and screwing them onto the probes along with
the necessary thermocouples. Each probe was then exposed to the furnace
atmosphere prevailing for the particular type of operation desired for
approximately 300 hours at coupon temperatures of about 875°F in order to
accelerate corrosion. After exposure, furnace slag was cleaned off and
saved for future analyses, and the coupons were carefully removed from the
probes. In the laboratory the coupons were cleaned ultrasonically with
fine glass beads to the base metal, and re-weighed to determine the weight
loss.
Total weight loss data were converted to corrosion rates on a mils
per year basis, using the combined inner and outer coupon areas, coupon
material density, and exposure time. Wastage was found to have occurred
on the internal surfaces of some of the coupons, possibly because of the
oxidation of the hot metal by the cooling air. Attempts were made to
determine "internal" and "external" corrosion rates by selective cleaning
and weight loss determinations, but the results were found to be more
consistent and reliable on an overall basis.
Corrosion rates have been determined for 40 coupons installed
on 20 probes (2 coupons/probe), in boilers at four different generating
stations as listed in section 4.2.3. Corrosion data obtained are tabulated
in Table 6-18.
Although there is some scatter in the data obtained, as shown
in Table 6-18, most of the information is quite consistent. A major
finding of these tests is that no major differences in corrosion rates have
been observed for coupons exposed to "low NOX" conditions compared to
those subjected to normal operation. In fact, for some probes the corrosion
rates were found to be even lower than for "low NO " exposure.
Since corrosion rates have been deliberately accelerated in
this study in order to develope "measurable" corrosion rates in a short
time period, measured rates, as expected, are much higher than the normal
wastage of actual furnace wall tubes. In future tests, coupons should
not be acid-pickled to remove oxide coatings, and coupon exposure temper-
atures should be maintained lower for a closer approximation of actual
tube wastage.
-------
Georgia Power
Harllee Branch Station
Boilers No. 3 & 4
£
I
1
F.W.
Burners
Arizor
Four Corn*
Sla.3- 1
B lower • • ' — —
Elev. 6-8'
Top 4
Burner 1
Elev.
F. W. X
Burners
Slag Slag
Blower Blower
^o. 9 No. 3 &
•>fr
Probe Prot ej
3B 3 A, B
4A, , B
4B ^
V
Side View
ia Public Service
srs Station - Boil
Slag Blowers
-.'-. V
Probe
Locations
(Both Sides)
- 106 -
FIGURE 6-23
FURNACE CORROSION
PROBE LOCATIONS
Utah Power and Light Company
] Naughton Station Boiler No. 3
s
i 8
Slag
I x Blower
*—/ Elev.
8*
I ^ Top Burner
.W. Elev.
urners -
(
Alabz
Company Barry
ers No. 4 & 5
I
11'
Lower
Burner
Elev.
I'll
ir
— K Slag J
R.W. ?;°wer
/ Burners Elev"
Probe
No. 2
-0 0 D
Ins
Doc
u.
Probe
No. 4
; Probe
No. 1
D J1
P-
Drs
Probe
No. 3
'
-
Front Elevation
Corner Burners)
ima Power Company
Station - Boiler No. 4
Slag Blowers
No. 18 & 26
V m
i
Probes 1
Probes 1
o • • *
, \
\Slag Bl
No.
^Tos. 3&4
sfos. 1&2
s, „ J*k .
f *
owers /
3&11 /
I »IH -
Side Elev.
Side Elev.
(Corner Burners)
-------
TABLE 6-18
ACCELERATED CORROSION RATE DATA
Boiler
Georgia Power, Harllee Branch No. 4
Georgia Power, Harllee Branch No. 4
Georgia Power, Harllee Branch No. 3
Georgia Power, Harllee Branch No. 3
Utah P&L, Naughton No. 3
Utah P&L, Naughton No. 3
Utah P&L, Naughton No. 3
Utah P&L, Naughton No. 3
Arizona Public Service, Four Corners No. 4
Arizona Public Service, Four Corners No. 4
Arizona Public Service, Four Corners No. 5
Arizona Public Service, Four Corners No. 5
Firing Condition
Corrosion Rate,*
Mils/Yr
Baseline
Baseline
Low NO
X
Low NO
X
Baseline
Baseline
Baseline
Baseline
Baseline
Baseline
Low NO
X
Low NO
X
f75
I72
f26
\ 48
r 28
J122.
r6
l155
/124
65
r '
/ 43 M
[47 3
f 16 '
1 24
T25
(157
I59
r5
f«
|160
f25
i 24
-------
Boiler
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
Alabama Power, Barry No. 4
TABLE 6-18 (Cont'd)
ACCELERATED CORROSION RATE DATA
Firing Condition
Baseline
Baseline
Baseline
Baseline
Low NO
X
Low NO
Low NO
Low NO
Corrosion Rate*,
Mils/Yr
o
c»
* Paired corrosion rate values obtained on
two coupons exposed on the same probe.
-------
- 109 -
Much more data are obviously required to resolve the question
of furnace tube corrosion under "low NO " firing conditions. The limited
data obtained in this study should be helpful in providing evidence that
furnace tube corrosion may not necessarily be a severe adverse side-effect
of low N0x firing. Long term "low NO " tests using corrosion probes and
the measurement of actual furnace wall tube corrosion rates are needed to
answer these questions.
6.1.4 Boiler Performance Results
The side effects of "low NO " combustion modifications on boiler
performance were investigated and evaluated for each major test where par-
ticulate runs were made under full load baseline and optimum "low NO "
conditions. Pertinent control room board data and other informationX
representing each test run were recorded and boiler efficiency was cal-
culated in accordance with the ASME Steam Generating Units, Power Test
Codes using the Abbreviated Efficiency Test, heat loss method. Calcula-
tions were based on the assumption that combustibles in the bottom ash
slag was zero and unmeasured losses were 0.5 percent. An example of
typical performance data and the calculations made are shown in the ASME
test forms of Tables 6-19 and 6-20.
The boiler efficiency calculated for each test is tabulated in
Table 6-21 along with other pertinent boiler performance information.
Differences in calculated boiler efficiency between baseline and "low NO "
tests provide a comparison of any debit or credit accruing to "low NO " X
emission combustion operations. However, such comparisons are confounded
by other factors such as boiler load during the test run, the percent
ash of the coal fired during the test and the carbon content of the parti-
culate. In general, boiler efficiency increases with load and decreases
with increases in coal ash or unburned combustible content of the parti-
culate emissions. As discussed in section 6.1.2, particulate carbon
content tends to increase under "low NO " operation for front wall and
horizontally opposed fired boilers. The data, however, are quite scattered
and these increases do not appear directly related to the change in
emissions with "low N0x" firing techniques. For example, the tests at
the Four Corners Station, unit No. 4 (a horizontally opposed boiler fired
with Western coal) showed marginal decreases in particulate carbon content
at the same relative load and coal ash content.
The overall conclusion from these performance data is that only
negligible differences in boiler efficiency occur with "low NO " firing
compared to baseline operation. Stated another way, it appears that there
are no significant performance debits with regard to boiler efficiency
under "low NO" emission operation. More performance data are needed on
all types of boilers to substantiate these important preliminary findings.
-------
- 110 -
SUMMARY SHEET
FOR
TABLE 6-19
ASME TEST FORM
ABBREVIATED EFFICIENCY
TEST
PTC 4.1-a(1964)
TEST NO. 1A BOILER NO. 6
OWNER OF PLANT TVA LOCATION Widows Creek
DATE 4-18-72
TEST CONDUCTED BY Esso Research & Engineering Co. OBJECTIVE OF TEST Boiler PerformanceuRATiONA Hrs.
BOILER, MAKE 8. TYPE B&W Radiant RATED CAPACITY 125 MW
STOKER, TYPE & SIZE
PULVERIZER, TYPE & SIZE Ty?e E BURNER, TYPE
FUEL USED Bituminous Coal MINE COUNTY STATE
& SIZE
SIZE AS FIRED
PRESSURES & TEMPERATURES FUEL DATA
1
2
3
4
S
6
7
8
9
10
11
12
13
14
STEAM PRESSURE IN BOILER DRUM
STEAM PRESSURE AT S. H. OUTLET
STEAM PRESSURE AT R. H. INLET
STEAM PRESSURE AT R. H. OUTLET
STEAM TEMPERATURE AT S. H. OUTLET
STEAM TEMPERATURE AT R.H. INLET
STEAM TEMPERATURE AT R.H. OUTLET
WATER TEMP. ENTERING (ECON.MBOILER)
STEAM QUALITY% MOISTURE OR P. P.M.
AIR TEMP. AROUND BOILER (AMBIENT)
TEMP. AIR FOR COMBUSTION
TEMPERATURE OF FUEL
GAS TEMP. LEAVING (Boiler) (Econ.) (Air Htr.)
GAS TEMP. ENTERING AH (If conditions to be
psio
psio
psio
psia
F
F
F
F
F
F
F
F
F
r) ID
/) Q
^7 &
UNIT QUANTITIES
15
16
17
18
19
20
21
22
23
24
25
ENTHALPY OF SAT. LIQUID (TOTAL HEAT)
ENTHALPY OF (SATURATED) (SUPERHEATED)
STM.
ENTHALPY OF SAT. FEED TO (BOILER)
(ECON.)
ENTHALPY OF REHEATED STEAM R.H. INLET
ENTHALPY OF REHEATED STEAM R. H.
OUTLET
HEAT ABS/LB OF STEAM (ITEM 16-ITEM 17)
HEAT ABS/LB R.H. STEAM(ITEM 19-ITEM 18)
DRY REFUSE (ASH PIT + FLY ASH) PER LB
AS FIRED FUEL
Btu PER LB IN REFUSE (WEIGHTED AVERAGE)
CARBON BURNED PER LB AS FIRED FUEL
DRY GAS PER LB AS FIRED FUEL BURNED
Btu/lb
Btu/lb
Btu/lb
Btu/lb
Btu/lb
Btu/lb
Btu/lb
Ib/lb
Btu/lb
Ib/lb
Ib/lb
HOURLY QUANTITIES
26
27
28
29
30
31
ACTUAL WATER EVAPORATED
REHEAT STEAM FLOW
RATE OF FUEL FIRING (AS FIRED wt)
TOTAL HEAT INPUT (Item 28 X Item 41)
1000
HEAT OUTPUT IN BLOW-DOWN WATER
J° J*L (Item 26xltem 20)+(ltem 27x1 tern 21 ) t|trir -jn
OUTPUT 1000
Ib/hr
Ib/hr
Ib/hr
kB/hr
kB/hr
kB/hr
lS.81
J/7J
/ 1,1*
FLUE CAS ANAL. (BOILERMECON) (AIR HTR) OUTLET
32
33
34
35
36
coa
0,
CO
Nj (BY DIFFERENCE)
EXCESS AIR
% VOL
% VOL
% VOL
% VOL
%
l+.H-
3.3
L>tM
tf&JJc
COAL AS FIRED
PROX. ANALYSIS
37
38
39
40
MOISTURE
VOL MATTER
FIXED CARBON
ASH
TOTAL
41
42
Btu per Ib AS FIRED
ASH SOFT TEMP.*
ASTM METHOD
% wt
-^V
/ju.^2.
COAL OR OIL AS FIRED
ULTIMATE ANALYSIS
43
44
45
46
47
40
37
CARBON
HYDROGEN
OXYGEN
NITROGEN
SULPHUR
ASH
MOISTURE
TOTAL
Ml
v-.tf
0,71
COAL PULVERIZATION
48
49
50
64
GRINDABILITY
INDEX*
FINENESS %THRU
50 M*
FINENESS %THRU
200 M*
INPUT-OUTPUT
EFFICIENCY OF UNIT %
51
52
53
44
41
OIL
FLASH
Sp. Grav
POINT F*
ity Deg. API*
VISCOSITY AT SSU*
BURNER SSF
TOTAL
% wt
Btu per
HYDROGEN
Ib
GAS
54
55
56
5;
58
59
60
61
CO
CH, METHANE
C,H, ACETYLENE
C2H4 ETHYLENE
C,H6 ETHANE
HaS
CO,
Hj
HYDROGEN
TOTAL
62
63
41
TOTAL
% wt
HYDROGEN
%VOL
DENSITY 68 F
ATM. PRESS.
Btu PER CU FT
Btu PER LB
ITEM 31 « 100
ITEM 29
HEAT LOSS EFFICIENCY
65
66
67
68
69
70
71
72
HEAT LOSS DUE TO DRY GAS
HEAT LOSS DUE TO MOISTURE IN FUEL
HEAT LOSS DUE TO H20 FROM COMB.OFH,
HEAT LOSS DUE TO COMBUST. IN REFUSE
HEAT LOSS DUE TO RADIATION
UNMEASURED LOSSES
Btu/lb
A. F. FUEL
TOTAL
EFFICIENCY = (100 - Item 71)
* Not Required for Efficiency Testing
% of A. F
FUEL
6/?o
ft,1}1)
3R3
// 2&
0tC02
c.f
I2>>IL
£6,34-
t For Point of Measurement See Par. 7.2.8.1-PTC 4.1-1964
-------
- Ill -
CALCULATION SHEET
TABLE 6-20
ASME TEST FORM
FOR ABBREVIATED EFFICIENCY TEST
PTC4.1-b (1964)
Revised September, 1965
OWNER OF PLANT XVA
30
24
25
36
65
66
67
68
69
70
71
72
HEAT OUTPUT IN BOILER BLOW-DOWN
If impractical to weigh refuse, this
item can be esf/mafed as follows
DRY REFUSE PER LB OF AS FIRED FUE
ITEM 43
CARBON BURNED L>'~]i $7
FUEL )0°
TEST NO. 1A BOILER NO. g DATE4-X8-7
ITEM 15 ITEM 13
WATER =LB OF WATER BL OW.nOWN PFB HP y —
1000
% ASH IN AS FIRED COAL
100 - % COMB. IN REFUSE SAMPLE D1T ,,.-.-, ...
r 1 1 K t r Ubl
|— — i IN COMBUST
ITEM^2 ITEM 23 1 SHOULD BE
A./-^ ~ (tr,$ ' ° - 7 ITEM 11)] = /jl-SZf,5~.. .
HEAT LOSS DUE TO ITEM 22 ITEM 23 o
COMBUSTIBLE IN REFUSE = Oj^RI X ^/^ / " lif-Lf->6
HEAT LOSS DUE TO TOTAL BTU RADIATION LOSS PER HR
RADIATION* LB AS FIRED FUEL - ITEM 28
UNMEASURED LOSSES **
TOTAL
EFFICIENCY = (100 -ITEM 71)
kB/hr
LUE DUST & ASH
I DIFFER MATERIALLY
riBLE CONTENT, THEY
ESTIMATED
Y. SEE SECTION 7,
ONS.
LtJ_S,
ITEM 47
267 J
Btu/lb
AS FIRED
FUEL
71o
63,3
tftf
/^.8
0.1.
LOSS x
HHV
100 =
65
X 1 00 =
41
— X 100 =
41
67
X100 =
41
68
— X100 =
41
69
41
2°- x ,00 =
41
LOSS
63o
o&
zst?
AZ6
0.MZS
0^.
13, i '6
3*6.^
t For rigo
* If lossc
dele
of.
xcess air se« Appendix 9.2 - PTC 4.1-1964
ed, use ABMA Standard Radiation Loss Chart, Fig. 8, PTC 4,1-1964
** Unmeasured losses listed in PTC 4.1 but not tabulated above may by provided for by assigning a mutually
agreed upon value for Item 70.
-------
TABLE 6-21
SUMMARY OF BOILER PERFORMANCE CALCULATIONS
Company,
Station,
Boiler No.
Tennessee
Valley
Authority
Widows Creek,
No. 6
Georgia
Power
Harllee
Branch, No. 3
Arizona Public
Service
Four Corners,
No. 4
Alabama Power
Companv
Barry, No. 4
Gulf Power
Crist, "o. 6
Firing
Mode
Baseline
Baseline
Low NOX
Low NOX
Low NOV
A
Baseline
Baseline
Baseline
Low NOX
Low NOX
Low NOX
Low NOX
Baseline
Baseline
Low NOX
Low NOX
Baseline
Baseline
Low NOX
Low NOX
Baseline
Low NOX
Test
No.
1A
IB
10-C-l
10-C-3
26-A-l
1C
ID
IE
1G
1H
52D
52E
IE
IF
12A
12B
42A
42B
19A
19B
1
26B
Load,
MW
125
128
120
125
97
490
488
483
478
463
475
465
755
775
725
704
293
283
283
255
320
350
% 02
3.3
3.6
3.0
3.3
2.8
3.0
3.7
3.0
1.2
1.3
1.9
2.0
3.4
3.1
4.3
3.7
5.0
4.5
4.6
4.3
3.6
3.2
NOX, ppm
(3% 02)
669
656
343
397
299
688
711
745
472
582
565
741
715
560
458
396
370
347
288
902
888
Coal,
% Ash
15.87
18.39
11.32
14.38
15.39
12.05
9.72
8.58
11.28
8.43
10.30
11.87
21.92
21.96
23.13
21.12
4.78
4.85
10.69
8.84
10.2
10.2
% Carbon on
Particulate
6.29
5.9
10.55
8.46
12.40
5.5
3.17
2.8
6.73
11.82
9.98
7.41
.69
.53
.18
.46
24.23
25.83
14.75
18.77
5.08
8.15
Boiler
Efficiency
86.8
86.2
86.7
86.5
85.9
90.0
90.2
90.4
90.2
90.0
88.7
89.5
88.2
88.6
88.8
89.1
88.4
88.6
88.8
88.3
88.5
88.1
-------
- 113 -
6.2 Oil Fired Boilers Converted
from Coal to Oil Firing
As discussed in Section 2, short-term tests were made on six
coal-to-oil converted boilers. The emission results obtained are presented
in this section.
6.2.1 Front-Wall Fired Boilers
6.2.1.1 Deepwater, Boiler No. 3
Boiler No. 3 of Deepwater Station is a Babcock and Wilcox designed,
front wall fired, single furnace boiler, with a maximum continuous rating
of 313.000 pounds of steam per hour at 1350°F and 725 pounds per square inch
pressure. It was installed in 1928 to fire pulverized coal, but has re-
cently been converted to oil firing. There are six mechanically atomizing
burners firing in a single row across the front wall of the furnace.
Table 6-22 summarizes operating and emission data for the eight
tear runs-, conducted on this boiler. Operating variables were gross load and
excess air level. Gross load (includes turbine generators 3H and 3L which
run on steam from both No. 3 and No. 5 boilers) was varied from full load
of 57 MW down to 19 MW. Excess air was varied from normal operating level
down to the lowest level that could be reached without excessive CO emis-
sions (greater than 200 ppm), or a visible plume showing from the stack.
It should be noted that the plume from the stack under normal excess air
operation is almost invisible. Under low excess air test operation, the
plume would show slight "efficiency" haze or occasional gray wisps of smoke.
Average NOX measurements are listed on both ppm NOX (3% 02, dry basis) and
pounds NOX (calculated as N02) per 106 Btu. Average % oxygen measurements
are also shown for each test run. Each of the six sampling probes contained
two gas sampling tubes that were positioned to provide samples from the
centers of four equal areas of each of the three ducts between the economizer
and air preheaters. During the test runs, one or two of the probes con-
sistently produced 1 to 2% higher oxygen readings (lower C02 and NOX
readings) than did the other probes, indicating a possible 5 to 10% air
leakage into the sampling system prior to sample pumps. Although inspec-
tion and checking of the complete sampling system from probes to pumps re-
vealed no leaks, the consistency of the measurements taken from the other
four or five probes, and the agreement of the NOX measurements from all
probes on a 3% 02, dry basis does indicate that one and sometimes two probes
were probably leaking. Therefore, the average % oxygen for each test run
includes data from the four or five consistent probes, while the average
ppm NOX (3% 02, dry basis) for each run is the average dilution-corrected
NO measurement from all six probes.
x
-------
TABLE 6-22
SUMMARY OF OPERATING AND EMISSION DATA
Atlantic City Elactric
(Deepwater Station, Boiler No. 3)
Oil Firing
Test
Run
1
2
3
4
5
6
7
8
Boiler Operating Conditions
Gross (3)
Load
(MW)
56.5
57
39
39
19
19
32
32
Excess
Air
Normal
Low
Normal
Low
Normal
Low
Normal
Low
Burner No.
Firing Oil
All
All
2, 3, 4 & 5
2, 3, 4 & 5
2 and 5
2 and 5
2, 3 & 5
2, 3 & 5
Flue Gas Measurements
Smoke
Meter
0.95
1.0
0.8
1.0
0.8
0.9
0.8
1.1
%o2
(2)
6.1
5.0
5.9
5.0
9.2
8.5
7.2
6.3
PPM NOX
(3%02, Dry Basis)
142
118
133
102
143
108
135
96
POUNDS NOY ...
Per 106 Bfu(4)
0.19
0.16
0.18
0.1.4
0.19
0.14
0.18
0.13
(1) Average of three 2-minute gas composites from 2 sample tubes per probe with 2 probes per duct and
3 ducts per boiler.
(2) Average boiler % oxygen calculated from probes 1, 2, 4 and 5 for test runs 1 and 2, and from
probes 2 through 6 for test runs 3 through 8. ppm NO., calculated from all 6 probes.
(3) Boilers No. 3 and 5 provide steam to two turbines. Gross load data represents the
combined gross load of both turbines.
(4) Calculated as N02<
-------
- 115 -
Table 6-23 indicates the experimental design of operating variables,
with average flue gas measurements of % oxygen and ppm NOX (3% 02, dry
basis) shown for each test run. Figure 6-24 is a plot of ppm NOX emissions
vs. % oxygen in the flue gas for the four' gross load conditions tested, at
normal and low excess air levels, respectively.
Baseline operation (test run No. 1), at full load with all six
burners firing oil, produced a relatively low average emission level of
142 ppm HOX (3% 02, dry basis) or 0.19 pounds per 106 Btu. Reducing ex-
cess air by about 5% (to 5% 02 in the flue gas from 6.1% 02) resulted in a
17% reduction in NOx emissions to 118 ppm (3% 02, dry basis). At reduced
loads, very similar results were achieved. At 39 MW gross load (four burn-
ers firing), normal excess air operation resulted in 133 ppm NOX, and low
excess air operation produced 102 ppm NOX, or a reduction of 23%. At 33
MW gross load (three burners firing), normal excess air operation resulted
in 135 ppm NOX, while low excess air operation produced a 24% reduction in
NO emissions to 96 ppm. At the minimum gross load of 19 MW, normal excess
air operation (two burners firing), resulted in 143 ppm NOX, while low
excess air operation at this load produced 108 ppm NOX emissions or a re-
duction of 29%.
Although the constant, relatively low NOX emission levels over
the wide range of total loads from full load to one-third load might appear
to be inconsistent with normal experience on oil fired boilers, we believe
they can be logically explained for this boiler. The heat released per
square foot of heating surface at full load is relatively low in this old
boiler installed in 1928, while the steam rate was only about 255,000 pounds
per hour, or 80% of the full load designed rate of 313,000 pounds per hour.
The fuel rate at each of the six firing burners was a relatively low 348
gallon per hour at full load (Boiler No. 9, for comparison, fired about
820 gallons of fuel oil per hour to give 286 ppm NOX emissions at full load).
As the load was reduced, the number of firing burners was proportionately
decreased so that at 39, 32 and 19 MW the fuel rates per firing burner was
maintained relatively constant at 386, 380 and 392 gallons per hour,
respectively. Also at the highest fuel rate per burner at 19 MW load, the
distance between firing burners increased to three times normal firing
operation and the distance between furnance side walls and firing burners
was double that for full load operating distances.
Table 6-24 summarizes the average flue gas component and tem-
perature measurement for each of the eight test runs completed on Deepwater
Station, Boiler No. 3. This unit had a baseline NOX emission level of
only 142 ppm (3% 02, dry basis) at full load. Reduced load operation at
normal excess air resulted in maintaining NOX emission levels between 133
and 143 ppm. The fact that load had negligible effect on the NOX emissions
strongly suggests that the bulk of the NOX was formed through the oxidation
of fuel nitrogen.
-------
FIGURE 6-24
PPM NOx VS % O2 MEASURED IN FLUE GAS
Atlantic City Electric
(Deepwater Station, Boiler No. 3)
Oil Firing
200
g
CO
• I-H
CO
rt
S 15°
« 100
T
Runs 1, 3, 5 and 7 are Normal Excess Air Runs
Runs 2, 4, 6 and 8 are Low Excess Air Runs
19 MW
50
J . L
I i L
10
% Oxygen in Flue Gas
-------
- 117 -
TABLE 6-23
EXPERIMENTAL DESIGN AND AVERAGE EMISSION MEASUREMENTS
Atlantic City Electric
(Deepwater Station, Boiler No. 3)
Oil Firing
AI - Normal
Excess Air
A? - Low
Excess Air
Gross Load (Boilers 3 and 5) and Number of Burners Firing
L! - 57 MW
(6 Burners)
(1) 6.1% 02 *
142 ppm NOX
(2) 5.0% 02
118 ppm NO
X
L2 - 39 MW
(4 Burners)
(3) 5.9% 02
133 ppm NOX
(4) 5.0% 02
102 ppm NO
*v x
L3 - 33 MW
(3 Burners)
(7) 7.2% 02
135 ppm NO
(8) 6.3% 02
96 ppm NOX
L^ - 19 MW
(2 Burners)
(5) 9.2% 02
143 ppm NOX
(6) 8.5% 02
108 ppm NO
* Each cell gives test run number, average % oxygen and
ppm IK) (3% 00, dry basis).
x 2.
-------
- 118 -
TABLE 6-24
FLUE GAS EMISSION MEASUREMENTS AND TEMPERATURES
Atlantic City Electric
(Deepwater Station, Boiler No. 3)
Oil Firing
TEST
RUN
NO.
1
2
3
4
5
6
7
8
(2)
GROSS
LOAD
(MW)
56.5
57
39
39
19
19
32
32
0?
%
6.1
5.0
5.9
5.0
9.2
8.5
7.2
6.3
FT.ITE
C09
%
9.9
10.5
9.5
10.1
7.2
7.4
8.7
9.3
GAS MKASTTRTflEJflS/^
NOy | CO
PPM $ 1 ppM y
3%02
142
118
133
102
143
108
135
96
3%02
67
81
56
349
53
74
55
141
HC
PPM G
3%02
—
1
1
1
2
1
1
Temp.
°F
601
616
491
477
417
399
454
448
(1) Average of three 2-minute gas composites from two sample tubes
from each of 6 probes.
(2) Boilers No. 3 and 5 provide steam to two turbines. Gross
load data represents the combined gross load of both turbines.
-------
- 119 -
Low excess air operation successfully reduced NOX emissions by
17 to 29%. These low emission levels are likely to be due to the relatively
low heat release per unit volume of this furnace. Under all conditions
tested, the NOX emission levels were significantly below the EPA new source
emission standard of about 225 ppm NOX for oil fired boilers or 0.3 pounds
NOX per 106 Btu heat input.
6.2.1.2 Deepwater, Boiler No. 5
Boiler No. 5 of Deepwater Station is a Babcock and Wilcox designed,
front wall fired, single furnace boiler, with a maximum continuous rating
of 290,000 pounds of steam per hour at 1350°F and 725 pounds per square inch
pressure. Installed in 1928 to fire pulverized coal, it has recently been
converted to oil firing. The burner arrangement is similar to Boiler No. 3,
with six mechanically atomizing oil burners arranged in a single row across
the front wall of the furnance.
Boilers No. 3 and 5 feed main steam to high pressure Turbine
Generator 3H (12 MW capacity). Boiler No. 5 reheats the exhaust steam from
Turbine Generator 3H and feeds Turbine Generator 3L (42 MW capacity). Pres-
ent operating practice results in firing boiler No. 5 with about 133% of
the fuel burned in No. 3 boiler, resulting in Boiler No. 5 having a much
higher heat release per unit furnace volume than No. 3.
Table 6-25 contains a summary of operating and emission data for
the four test runs conducted on Boiler No. 5. In light of the low NOX
emission levels on sister unit No. 3, only baseline, normal and low excess
air test runs 1 and 2 were planned for Boiler No. 5. However, test runs 1
and 2 produced NOx emission levels close to the EPA new source standard of
225 ppm NOx for oil fired boilers, and consequently, test runs 3 and 4 were
conducted in an attempt to obtain lower NOX emissions under full load
operation.
Baseline NOX emissions (test run No. 1) were 221 ppm (3% 02, dry
basis) or 0.29 pounds NOX per 10^ Btu under normal excess air, full load
operation. Low excess air operation run No. 2 resulted in a 5% reduction
in NOX emission levels to 209 ppm. Fuel rates in gallons per hour per
burner were about 33% higher (465 vs. 350) than baseline operation on
sister unit No. 3, with its lower NOX emission rate of 142 ppm. Test run
No. 3 was conducted while firing with five burners equipped with large
capacity tips, and with the air registers wide open on the idle burner
(No. 3) to simulate low excess air, staged firing. However, the higher
fuel firing rate per burner (540 vs. 465 gallons per hour), and single row
of burner configuration resulted in an essentially baseline NOX emission
level of 225 ppm for test run No. 3. The last test run, No. 4, conducted
at a 22% reduced oil firing rate of 365 vs. 465 gallons per burner-hour
produced a 21% lowered NOX emission level of 175 ppm, compared to the base-
line emission level of 221 ppm. The steam rate on Boilar No. 3 was in-
creased by about 40,000 pounds per hour to make up for the lowered steam
rate of No. 5 boiler on run No. 4.
-------
TABLE 6-25
SUMMARY OF OPERATING AND EMISSION DATA
Atlantic City Electric
(Deepwater Station, Boiler No. 5)
Oil Firing
Boiler Operating Conditions
Test
Run
1
2
3
4
Gross
Load
(MW)
56
56
56
53
Excess Air
Level
Normal
Low
Low
Low
No. of Burners
Firing Oil
6
6
5<2>
6<2>
Flue Gas Measurements
Smoke
Meter
0.62
0.65
0.70
0.60
%o2
4.2
2.8
4.3
4.0
PPM NOjj
(3%02, Dry Basis)
221
209
225
175
POUNDS,NO..
PER 10 BTU
0.29
0.28
0.30
0.23
ISJ
O
(1) Average boiler % oxygen .calculated for probes 2, 3, 4 and 5. Ppm NO.,
(3%0o,.dry basis) calculated as arthmetric average of data for all 6 probes.
(2) Large capacity burner tips were used on test runs 3 and 4.
-------
- 121
Boilers No. 3 and 5 utilize the same stack and there is some
flexibility in adjusting the firing rate of the two boilers at full load.
Consequently, there is probably a minimum stack NOX emission rate obtained
by judiciously balancing the heat load of the two boilers.
Table 6-26 contains average flue gas component measurements and
temperatures for each of the four runs completed on Deepwater Station No. 5
boiler. Flue gas temperature, percent 0-, percent CO-, ppm NO and ppm CO
are shown. All data in ppm have all been corrected to a common 3% 0~, dry
basis. Since the hydrocarbon instrument was inoperable during the test
period, no HC measurements were obtained.
6.2.1.3 Deepwater, Boiler No. 8
Boiler No. 8 at the Deepwater Station is a Babcock and Wilcox
designed, front wall fired, single furnace boiler, with a maximum continuous
rating of 560,000 Ib. steam per hour at 1005/1005°F superheat and reheat
temperatures and 1520 psi design pressure. Installed in 1954 to fire
pulverized coal, it has recently been converted to oil firing. The unit is
of balanced draft construction with 16 burners arranged four high and three
wide. Each burner is fired by a mechanical pressure atomizing oil gun of
the return flow type.
Table 6-27 contains a summary of operating and emission data for the
25 test runs conducted on Boiler No. 8. Operating variables were gross load
(data were collected at six different loads), excess air level, and firing
pattern (seven different firing patterns were explored). Excess air was
varied from normal operating level down to the lowest level that could be
reached without excessive CO emissions (greater than 200 ppm), smoke meter
indications greater than 1.0, or producing more than slightly visible stack
plumes with periodic wisps of gray smoke. Under normal excess air opera-
tion, the stack plume is practically invisible. Under low excess air test
operation, the plume often would show slight "efficiency" haze or occasional
gray wisps of smoke. Boiler No. 8 is also limited in fan capacity and
superheat and reheat control, making it difficult to operate at desired
levels to achieve optimum low NO emissions with various staging patterns.
Average ppm NO measurements (3% 02, dry basis), pounds NO per 10& Btu and
average % Q£ measurements are shown in Table 6-27 for each test run. Each...
of the four proBes contained short, medium, and long gas sampling tubes
that were positioned to provide samples from the centers of twelve equal
duct areas located between the economizer and the air preheater inlet.
Flue gas composition was remarkably uniform across the duct.
Table 6-28 summarizes the experimental design of operating vari-
ables, with average flue gas measurements of % oxygen and ppm NOX (3% 02,
dry basis) shown for each run. Table 6-29 details the firing patterns
employed during the NOX tests, and is helpful in visualizing potential
effects of the various firing configurations. Figure 6-25 is a plot of ppm
NOx vs. % oxygen in the flue gas for the seven firing patterns investigated
under full load operations. Figure 6-26 is a plot of ppm NOX vs. % 02 in
the flue gas for intermediate and low loads.
-------
- 122 -
PPM
FIGURE 6-25
VS % O2 IN FLUE GAS
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Full Load
Oil Firing
T
250
Full Load
Normal Firing
Pattern I
CO
5 200
CQ
150
CO
O
Full Load
Staged Firing
Pattern IV
Load
Staged Firing
Patterns
Full Load
Staged Firing
Pattern II
pj 100
50
0
% O2 In Flue Gases
-------
- 123 -
FIGURE 6-26
PPM NOx VS % O2 IN FLUE GAS
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Intermediate and Low Leads
Oil Firing
250
w
d
ffl
CM
o
e£
co
200
150
100
50
0
Low Load Normal
Firing Pattern I
Intermediate Load
(68 MW) - Normal
Firing Pattern I
Intermediate Load
(67 MW) - Staged
Firing Pattern n
Intermediate Load
(66 MW) - Staged
Firing Pattern in
Low Load Staged
Firing Pattern n
11 - 52 MW- Normal Air
12 & 16 - 52 & 50 MW - Staged Firing Patterns
13 - Only 5 of Top Burners Firing - Others Off -
Normal Firing Pattern I
26 - All Burners Operating with Small Oil Guns
Normal Firing Pattern I
I
3 4
% O2 in Flue Gas
-------
- 124 -
TABLE 6-26
FLUE GAS EMISSION MEASUREMENTS AND TEMPERATURES
Atlantic City Electric
(Deepwater Station, Boiler No. 5)
Oil Firing
TEST
RUN
NO.
1
2
: 3
; 4
GRUob
LOAD
(MW)
56
56
56
53
AVERAGE FLUE GAS MEASUREMENTS
0,
%
4.2
2.8
4.3
4.0
CO,
%
11.9
12.5
11.7
11.8
NO
Fra
(3%02)
221
209
225
175
CO
WH
(3%02)
55
84
79
83
Temp.
°F
569
547
561
527
-------
SUMMARY OF OPERATING AND EMISSION DATA
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Oil Firing
Date
5/16
5/17
5/19
5/20
5/24
5/26
Test
Run
No.
1
2
1A
4
6A
5A
7
8
9
10
11
12
16
14
13
17
18
19
20
21
22
23
24
25
26
Boiler Operating conditions
Gross
Load
MW
83
81
82.5
81
82
83
68
66
66
67
52
52
50
22
22
83
82
82
81
47
31
29.5
22
23
23
Excess
Air
Level
Normal
Low
Normal
Low
Low
Normal
Normal
Low
Low
Low
Normal
Low
Low
Low
Normal
Low
Low
Low
Low
Normal
Low
Low
Low
Low
Normal
Firing Pattern
(Burners on
Air Only)
Normal (None)
Normal (None)
Normal (None)
Staged (84 Row)
Staged (84S,84N,82C)
Staged (84S,84N,82C)
Normal (None)
Normal (None)
Staged (84 Row)
Staged (84C,83S,83N)
Normal (None)
Staged (84S.84N)
Staged (83S.83N)
Staged (84S.84N)
Normal (None)
Staged (83 Row)
Staged (84C.83S.83N)
Staged (83S.83N.82C)
Staged (83C.82S.82N)
Normal (None)
Staged (83 Row)
Staged (83S,83N,82C)
Staged (83S.83N.82C)
Staged (83 Row)
Normal (None)
Flue Gas Measurements
Smoke
Meter
0.75
1.0
0.7
0.8
0.8
0.75
0.75
0.9
0.8
0.9
0.75
1.0
0.9
0.8
•0.75
0.7
0.7
0.7
0.65
0.65
0.60
0.60
0.60
0.60
0.60
%02
4. .5
2.3
4.1
5.2
4.4
5.3
5.5
2.6
4.9
5.0
6.9
4.7
4.6
12.9
12.1
4.4
4.5
4.7
4.4
7.1
9.4
9.5
10.7
10.0
10.2
PPM NO
(3%02, Dry)
246
188
208
136
165
192
204
172
124
160
181
94
124
158
191
132
124
142
123
197
157
162
172
162
155
POUNDS NOx
PER 10 BTU
0.33
0.25
0.28
0.18
0.22
0.25
0.27
0.23
0.16
0.21
0.24
0.13
0.16
0.21
0.25
0.18
0.16
0.19
0.16
0.26
0.21
0.22
0-23
0.22
0.21
SJ
Ln
-------
TABLE 6-28
EXPERIMENTAL DESIGN AND AVERAGE EMISSION MEASUREMENTS
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Oil Firing
sl
Normal
Firing
Pattern I
S2
Staged
Firing
Pattern II
3 Staged
Firing
Pattern III
A Staged
Firing
Pattern IV
ss
Staged
Firing
Pattern
s6
Staged
Firing
Pattern
7 Staged
Firing
Pattern
Al
©
4.5% 02
246 PPM
NOx
5.37. 02
192 PPM
NOx
Full Load
Lt - 82 MW
A1-A
©
4. IX 02
208 PPM
HOx
A2
®
2.3% 02
188 PPM
NOx
©
5.2% 02
136 PPM
NOx
0)
4.4% 02
132 PPM
NOx
@
^..4% 02
165 PPM
NOx
®
4.57. 02
124 PPM
NOx
©
*.7% 02
142 PPM
NOx
©
4.4% 02
123 PPM
NOX
Intermediate Load
L2 - 68 MW
Al
®
5.5% 02
204 PPM
NO,
A2
2.6% 02
172 PPM
NOx
®
4.9% 02
124 PPM
NOX
©
5.0% 02
160 PPM
NOx
Inter. Load
L3 - 52 MW
Al
O
6.9Z 02
181 PPM
NOX
A2
4.7% 02
94 PPM
NOX
©
4.647, 0?
124 PPM
NOx
Inter. Load
L^ - 47 MW
Al
7.17. 02
197 PPM
NO,
Inter. Load
L5 - 30 MW
A2
Q*
T.4% 02
157 PPM
NOx
©*
T.57. 02
162 PPM
NOx
Low Load
t6 - 22 MW
Al
0
12.1% 02
191 PPM NOX
©
TO. 27. 02
155 PPM NOx
A2
©
12.97. 02
158 PPM
NOx
©*
10.77. 02
172 PPM
NOx
© *
in o2
162 PPM
NOx
J
Small Oil Guns in Operating Burners
NOTE: Figures in boxes gives test run number, average 7. Oxygen and PPM NOx (3X °2. Dry Basis)
-------
TABLE 6-29
FIRING PATTERNS USED DURING NOX TESTING
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Oil Firing
Full Load 82 MW
Sl
Run 1 & 2
000
000
000
too
Sl
Run 1A
000
000
000
0»0
S2
Run 4
AM
000
000
000
S3
Run 17
000
AAA
000
000
S4
Run 5A, 6A
AOA
000
OAO
000
S5
Run 18
OAO
AOA
000
000
S6
Run 19
000
AOA
OAO
000
S7
Run 20
000
OAO
AOA
000
Intermediate Load 68 MW
Sl
Run 7 & 8
000
000
000
•0«
S2
"Run 9
AAA
000
000
000
S3
Run 10
OAO
AOA
000
000
Intermediate Load
52 MW
Sl
Run 11
000
000
0«0
•••
S2
Run 12
AOA
000
000
•09
S3
Run 16
000
AOA
000
«()•
S3
•vl
Burner Arrangement
si >-i si
•U 0) 4J
3 -U M
o c o
-------
- 128 -
Baseline operation at full load (test run No. 1) conducted with
all burners operating normally, except burner 81 south off, produced average
flue gas NO concentrations of 246 ppm (3% 0_, dry basis) at 4.5 % 0^ in
the flue gas. This is the only measurement recorded which exceeds trie
EPA-recommended emission standard of about 225 ppm for oil fired boilers.
Reducing the excess air level to that corresponding to 2.3 % 02 in the flue
gas resulted in an average level of 188 ppm NO (3% 0^ dry basis), or a
decrease of 23.5% from baseline conditions. Other staging patterns (tests
4, 5A, 6A, 17, 18, 19 and 20) achieved further reductions in N0x emissions
to as low as 123 ppm NO (50% reduction) , but operating conditions were
sometimes marginal. AsXindicated by the results in the attached tables,
it is possible to operate at significantly reduced N0x emission levels at
all loads. However, these reductions were achieved at the expense of re-
duced superheat and reheat temperatures. Superheat temperatures were as
much as 35°F low and 55°F on reheat during some tests at full load. At
lower loads decreases as much as 140°F in superheat and 185°F in reheat
resulted. Superheat and reheat surface would have to be added if the unit
were to be operated full time at low NOX emission conditions.
Carbon monoxide emission levels were generally lower than 100 ppm
(well within the arbitrary limitation of 200 ppm criteria) but occasional
wisps of gray stack emissions were observed during some tests, which may not
be entirely acceptable. Smoke indicator readings during some of the "low
NO " tests were slightly higher than normal but by no means exorbitant.
If low NO emission firing conditions were to be employed full time, a
thorough investigation of combustion conditions would be warranted since bad
or worn sprayer plates on individual (single) burners could account for
these undesirable visible emissions.
With some firing configurations, fans were operated at or near
their maximum output. Fortunately, this did not occur at optimum NOX
reduction conditions but fan capacity limitations under some conditions of
"low NOX" operation might be a problem.
Baseline operation at the intermediate load of 68 MW (test No. 7)
with all burners operating in the normal manner, and wing burners 81S and
81N off, produced average flue gas concentrations of 204 ppm NOX (3% 02,
dry basis) at 5.5 % 0? in the flue gas. Reducing the excess air to a
level of 2.6 % 0- in flue gas, reduced NO emissions to an average of 172
ppm, i.e., a reduction of about 16%. Other staging patterns (tests No. 9
and 10) made further reductions in N0x emissions to a low of 124 ppm; a 40%
reduction.
At 52 MW baseline NO emission at 6.9 5 0- in the flue gas was
181 ppm (test No. 11). This was reduced to 124 ppm NO (31% reduction) by
staging and reducing average excess air to a level of $.6% 02 in the flue
gas.
At low load (22 MW) with large oil guns (test No. 13), the baseline
NO emissions was 191 ppm NO at 12.1% 0 in the flue gas. Replacing the
large sprayer plates with smaller ones and firing all 12 burners produced a
-------
- 129 -
baseline NOX emission (test No. 26) of 155 ppm at the 10.2% oxygen level.
Applying staged firing techniques (test No. 14), reduced the baseline NOX
emission of 191 ppm down to 158 ppm, but, interestingly enough, staging
patterns in comparable tests (tests No. 24 and 25 with small atomizers)
produced higher emissions (172 and 162 ppm) than the 155 ppm baseline NOX
emission (test No. 26). Evidently, with the high excess air levels employed
during these tests, the air/fuel ratio in the operating burners was too high
for staging to be effective for NOX emission control.
Table 6-30 contains average flue gas component emission measure-
ments and flue gas temperatures. Percent 02» percent CO™, ppm NO , ppm CO
are listed. The ppm data have been corrected to a 3% 0_, dry basis.
To sum up, baseline NOX emissions on Boiler No. 8 of 246 ppm are
slightly higher than the new source standard of about 225 ppm for oil
fired boilers. Baseline emissions at other loads are normally below 200
ppm NOX (3% 02, dry basis). Staged firing was effective at all loads in
reducing NOX emission levels, except in two cases at low load, with high
levels of excess air. The NOX emission levels obtained with staged firing
are all well below the EPA standard for new oil fired boilers. Because of
fan and steam temperature control limitations, however, the NOX emission
reductions obtained were not always made at acceptable operating conditions.
Both superheat and reheat steam temperatures during "low NOX" emission con-
ditions were low at all loads which seriously effect overall plant efficiency.
Full time "low NOX" operation would require the addition of superheat and
reheat surface to overcome this undesirable deficiency. Also, under some
conditions, visible grayish wisps were emitted from the stack, which could
be attributed to damaged or worn sprayer plates on individual (single)
burners. Long term operation at "low NO " conditions, therefore, should be
preceded by a thorough revamping of the combustion system (including con-
trols) to eliminate these undesirable visible emissions.
6.2.1.4 Deefrwater, Boiler No. 9
Boiler No. 9 at Deepwater Station is a Combustion Engineering
designed front wall fired, single furnace boiler, with a maximum continuous
rating of 550,000 pounds of steam per hour. It was installed in 1957 to
fire pulverized coal and has been recently converted to oil firing. The
furnace width is 24 feet 3 inches and the furnace volume is 33,000 cubic
feet with a heating surface of 8,625 square feet. Main steam operating
pressure is 1325 pounds per square inch at a temperature of 765°F. There
are six mechanical atomizing burners arranged in three rows of two burners
each.
Table 6-31 lists operating and emissions data for the seven test
runs conducted on this boiler. Operating variables were excess air level
(normal and low) and burner firing patterns (normal firing plus three staged
firing patterns). Gross load was maintained at about full rated capacity
(20.8 to 22.8 MW). Low excess air was defined as the minimum excess air
that produced only a slight visible plume with periodic wisps of gray smoke.
-------
TABLE 6-30
FLUE GAS EMISSION MEASUREMENTS AND TEMPERATURES
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Oil Firing
TEST
RUN
N 1
1
2
1A
A
6A
5A
7
8
9
10
11
12
16
14
13
17
18
19
20
21
22
23
24
25
26
GROSS
LOAD
(M 6)
83
81
82.5
81
82
83
68
66
66
67
52
52
50
22
22
83
82
82
81
47
31
29.5
22
23
23
AVERAGE FLUE GAS MEASUREMENTS
°2
%
4.5
2.3
A.I
5.2
A. A
5.3
5.5
2.6
4.9
5.0
6.9
A. 7
4.6
12.9
12.1
A. 4
4.5
4.7
4. A
7.1
9. A
9.5
10.7
10.0
10.2
co2
%
11.6
13.0
11.5
10.5
11.9
11.3
10.6
12.4
11.2
11.3
9.6
11.2
11.0
4.8
5.5
11.6
11.9
11.6
11.8
9.4
7.5
7.1
6.5
6.5
6.7
NO
X
PPM
(3% 02)
246
188
208
136
165
192
204
172
12A
160
181
9A
12A
158
191
132
12A
1A2
123
197
157
162
172
162
155
CO
PPM
(3% 02)
49
10A
56
83
7A
7A
62
65
59
60
6A
6A
6A
10A
80
78
8A
70
6A
63
72
70
66
64
66
TEMP.
°F
620
579
615
608
608
615
607
547
570
607
593
517
521
495
522
609
590
600
595
560
520
505
498
490
495
OJ
o
-------
TABLE 6-31
SUMMARY OF OPERATING AND EMISSION DATA
Atlantic City Electric
(Deepwater Station, Boiler No. 8)
Oil Firing
Boiler Operating Conditions
Test
Run
No.
1
2
3
4
5
6
7
Gross
Load
(MW)
22.8
22.8
21.7
21.4
20.8
20.8
21.9
Excess
Air
Level
Nor
Low
Nor.
Low
Low
Nor.
Low
Firing Pattern
(Burners on (~^
Air only)
Nor. -(None)
Nor. -(None)
Staged-(l,4)-I
Staged-(l,4)-I
Staged-(l,5)-II
Staged-(l,5)-II
Staged-(2,5)-III
Flue Gas Measurements
%o2
1.8
1.0
3.8
2.6
4.2
4.8
2.6
" PPM NOX I POUNDS£NOY
(3%02, Dry)
286
253
122
101
150
152
123
PER 10°BTU
0.38
0.34
0.16
0.13
0.20
0.20
0.16
u>
M
I
(1) Flue gas measurements made on gas smaples from 12 individual sampling tubes.
Measurements shown are averages of 2 analyses from each of three sampling tubes (short,
medium and long) per probe.
(2) Burner configuration
Top
Middle
Bottom
Q) ©
G ©
-------
- 132 -
Average ppm NOX measurements (3% 02, dry basis),pounds NOX per 10^ Btu and
average % 02 measurements are shown for each test run. Each of the four
probes contained short, medium and long gas sampling tubes that were posi-
tioned to provide samples from the centers of twelve equal duct areas
located between the economizer and air preheaters. Flue gas composition
was uniform across the duct except for the staggered, staged-firing pattern
II, as discussed below.
Table 6-32 indicates the experimental design of operating variables
with average flue gas measurements of % oxygen and ppm NOX (3% 02, dry
basis) shown for each run. A simplified furnace burner diagram is shown
at the bottom of Table 6-32 to aid in visualizing the firing configurations
used in the three different staged firing patterns. Figure 6-27 is a plot
of ppm NOX emission vs % oxygen in the flue gas for the four firing patterns
investigated.
Baseline operations (test run No. 1) conducted with all six
burners firing oil, produced average flue gas concentrations of 286 ppm NOX
(3% 02, dry basis) or 0.38 pounds N0x per 106 Btu heat input at 1.8%
oxygen. Reducing the excess air level to that corresponding to 1.0% oxygen
in the flue gas, resulted in an average level of 253 ppm NOX (3% 02, dry
basis) or a decrease of 12% from baseline conditions. Staged firing pat-
tern I (top row of burners on air only) operation resulted, as expected,
in significant reductions in NOX emission levels; 122 ppm at 3.8% oxygen
and 101 ppm at 2.6% 02- It should be noted that only about 80% of the air
required for complete combustion of the fuel oil entered the active burners
in run No. 3, and only about 75% of stoichiometrically required air entered
the active burners in run No. 4.
Staged firing pattern II (Burners 1 and 5 on air only) operation
did not produce as much NOX emission reduction as staged firing pattern I,
as shown by test runs 5 and 6, compared to runs 3 and 4. Staged firing
pattern II produced an air-fuel imbalance with the left half of the
furnace having a higher excess air level than the right half of the
furnace. This resulted in raising the minimum excess air level of 2.5%
02 in the flue gas achieved using staged firing pattern I, to 4.2% 0, when
using staged pattern II. L
Run No. 7 made with low excess air and staged firing pattern III
was conducted in an attempt to achieve low NOX emissions with increased
superheat temperatures. The NOX level of 123 ppm obtained in run No. 7
was not as low as staged pattern I operation, but superheat temperature
increased by about 5°F (760°F vs 755°F as measured at the turbine
throttle, point 12).
Table 6-33 lists average flue gas component measurements and
temperatures for each of the seven test runs completed—Deepwater Station
Boiler No. 9. Percent 02, percent CO-, ppm NO , ppm CO and "F temperatures
are shown.
-------
- 133 -
FIGURE 6-27
PPM NOx VS % O2 MEASURED IN FLUE GAS
Atlantic City Electric
(B. L. England, Boiler No. 9)
Oil Firing
i , •— | -f | , p-
M
.1-1
%
n
300
250
Normal Firing Pattern
eq 200
O
15°
100
Firing
Pattern II
Staged Firring Pattern in
Staged Firing Pattern I
50
See Table 14 for Staged Firing Patterns
Boiler Gross Load = 21-23 MW
0
1
0
3 4
% 02 in Flue Gas
-------
- 134 -
TABLE 6-32
EXPERIMENTAL DESIGN AND AVERAGE EMISSION MEASUREMENTS
Atlantic City Electric
(Deepwater Station, Boiler No. 9)
Oil Firing
S, -Normal
Firing
Pattern:
S2-Staged
Firing
Pattern-I:
S3~Staged
Firing
Pattern-II:
S4-Staged
Firing
Pattern-Ill:
Oil in 00
All 00
Burners 00
Air Only AA
In Top 00
Burners 00
Air Only AO
in Burners OA
No. 1 & 5 00
Air Only 00
in Middle AA
Burners 00
Full Load
(21 - 23 MW Gross)
A^-Normal
Excess Air
(1) 1.8% 02 *
286 ppm NOX
(3) 3.8% 02
122 ppm NOX
(6) 4.8% 02
152 ppm NOX
A2-Low
Excess Air
(2) 1.0% 02
253 ppm NOX
(4) 2.6% 02
101 ppm NOX
(5) 4.2% 02
150 ppm NOX
(7) 2.6% 02
123 ppm NOX
* Each cell gives test run number, average % oxygen and ppm NOX
(3% 02, dry basis).
Top Row
Middle Row
Bottom Row
Furnace Front:
Burner
Configuration
-------
- 135 -
TABLE 6-33
FLUE GAS EMISSION MEASUREMENTS AND TEMPERATURES
Atlantic City Electric
(Deepwater Station, Boiler No. 9)
Oil Firing
TEST
RUN
NO.
1
2
3
4
5
6
7
GROSS
LOAD
(MW)
22.8
22.8
21.7
21.4
20.8
20.8
21.0
FLUE GAS MEASUREMENTS
09
%
1.8
1.0
3.8
2.6
4.2
4.8
2.6
CO?
%
13.5
14.0
11.5
12.6
11.4
10.9
12.4
NOy
PPM
(3%02)
286
253
122
101
150
152
123
CO
PPM
(3%02)
44
97
45
64
60
48
53
HC
PPM
(3%02)
—
—
—
—
—
Temp.
°F
739
717
734
717
717
726
703
-------
- 136 -
To sum up, this boiler has baseline NO emissions of 286 ppm.
Low excess air plus staged firing operation resulted in a significant
lowering of NO emissions, as shown in Figure 6-27. Three different
staged firing patterns were effective with staged pattern I (top burners
on air only) producing the lowest average NO emission level of 101 ppm
(3% 02, dry basis). The NO emission levels reached with staged firing
are all well below the EPA recommended standards for oil fired boilers.
It was possible to reduce NO emissions to these levels for this boiler
without any adverse effects such as significantly increased smoke and
unburned combustible emissions, and reduced boiler operability.
6.2.2 Cyclone Fired Boilers
6.2.2.1 B. L. England, Boiler No. 1
Boiler No. 1 at the B.L. England Station is a Babcock & Wilcox
Company, cyclone fired pressurized boiler with a maximum continuous rating
of 930,000 Ib. steam/hour. It was installed in 1957, and has recently been
converted to crude oil firing. Design pressure is 1815 psi, and electricity
output is 136 MW gross (127 MW net) at steam and reheat temperatures of
1000/1000°F. The boiler is fired by single, mechanical atomizing oil burn-
ers in each of the three cyclones, which are arranged with two of them on
one level, with the third one elevated between them in a triangular fashion
on the front wall of the furnace.
Table 6-34 lists operating and emissions data for the seven test
runs conducted on this boiler. Operating variables were excess air (normal,
intermediate, and low) and load (full, intermediate, and low). Gross load
was maintained at about full rated capacity on crude oil firing (132-133 MW)
at normal, intermediate, and low excess air firing conditions. Tests were
also made at three similar excess air levels at intermediate loads of 103-
105 MW. Emission data were also obtained at normal excess air conditions
at "minimum" load (62 MW). Low excess air at full load was defined as
1.1% 02 on the control board oxygen meter (0.5% avg. 0- measured by the
Exxon van). At these levels, smoke density on ACE's smoke meter was normal
(30), and no visible emissions were apparent from the stack. Carbon monoxide
emissions as measured by the Esso van, however, were excessive and, there-
fore, operation at such low level of excess air would not be recommended.
Low excess air for the intermediate load of about 103 gross IIW's was de-
fined as the minimum excess air that produced only a slightly visible stack
plume, no appreciable increase in smoke density indication, and reasonable
(about 200 ppm max.) CO emissions. Average ppm NO measurements (3% 0
dry basis) pounds N0x/10b Btu and average % 02 measurements are shown2for
each test run. Each of the four probes contained short, medium, and long
gas sampling tubes which were positioned to provide samples from the centers
of twelve equal duct areas located between the economizer and the air pre-
heaters.
-------
TABLE 6-34
SUMMARY OF OPERATING AND EMISSION DATA
Atlantic City Electric
(B. L. England, Boiler No. 1)
Oil Firing
Test
Run
No.
1
2
3
4
5
6
7
Boiler Operating Conditions
Gross
Load
MW
133
133
132
62
105
105
103
Excess
Air
Level
Normal
Inter.
Low(2)
Normal
Normal
Inter.
Low
Firing
Pattern
All Cyc. On
All Cyc. On
All Cyc. On
Middle Cyc.
Off
All Cyc. On
All Cyc. On
All Cyc. On
Average Flue Gas Measurements
Smoke
Density
30
30*
30
24
26
26
25
%o2
1.5
1.1
0.5
4.2
2.7
2.4
1.0
PPM NOx
(3%02, Dry)
441
396
313
261
404
364
241
POUND S6NOX
PER 10 BTU
0.59
0.53
0.42
0.35
0.54
0.48
0.32
(1) Flue gas measurements made on composite gas samples from 3 individual sampling tubes.
Measurements shown are averages of 3 analyses from three sampling tubes (short, medium,
and long) for each of 4 probes.
(2) Excessively high CO emissions at this condition.
-------
- 138 -
Table 6-35 indicates the experimental design of operating variables
with average flue gas measurements of % oxygen and ppm NO (3% 02, dry basis)
shown for each run. Normal firing patterns with all three cyclones firing
were employed for all, except low load operation. In the latter case, the
middle or upper cyclone was taken out of service- Figure 6-28 is a plot of
ppm NOX emission vs. % oxygen in the flue gas for the three loads tested.
Baseline operations (test run No. 1) conducted with all three
cyclones operated normally, produced average flue gas concentrations of 441
ppm NOX (3% 02, dry basis) at 1.5% oxygen. Reducing the excess air level
to 1.1 and 0.5% oxygen in the flue gas resulted in a reduction in average
emission levels at this load to 396 and 313 ppm NOX (3% 02, dry basis),
respectively. Baseline operation at 105 MW output produced 404 ppm NOX
(3% 02, dry basis) at the level of 2.7% 02 in the flue gas. Reducing excess
air to 2.4 and 1.0% 02 in the flue gas reduced NOX emissions to 364 and 241
ppm, respectively, at the intermediate load. At the minimum load of 62 MW,
a baseline emission level of 261 ppm NOX (3% 02, dry basis) was measured at
4.2% oxygen. This level is about the same as the emissions at the inter-
mediate load level of 105 MW at low excess air conditions, indicating the
particularly significant contribution of fuel nitrogen oxidation to NO
emission at intermediate to low load levels, i.e., at lowered combustion
intensity conditions.
Decreasing excess air levels at both full and intermediate loads
had a substantial effect on reducing NOX emission levels. With cyclone
operation, at least at present, staged firing patterns which might effect
further reductions are not possible.
Table 6-36 lists average flue gas component measurements and
temperatures for each test run. Percent 0 , percent C0?, ppm NO , ppm
CO and temperatures are shown. The ppm data have been correctedXto a 3%
02, dry basis.
To sum up, this boiler has baseline NOX emissions of 441 ppm
which are higher than the original recommended new source emission standards
of about 225 ppm for oil fired boilers. Low excess air operation at full
and intermediate loads resulted in significant lowering of NOX emissions
as shown in Figure 6-28. However, decreases in load and reductions in
excess air levels could not reduce emissions below the recommended standards
for new boilers which are subject to reassessment at present by EPA).
6.2.2.2 B. L. England, Boiler N0. 2
Boiler No. 2 at ACE's B.L. England Station is a Babcock & Wilcox
Company, cyclone fired, pressurized boiler with a maximum continuous rating
of 1,250,000 Ib. of steam per hour. The unit was installed in 1964, and has
recently been converted to crude oil firing. Electricity output is 168 MW
gross (160 MW net) at design pressure of 1815 psi, with 1000/1000°F super-
heat and reheat temperatures. Each of the four cyclones are fired by a
single mechanical pressure, atomizing oil gun. The four cyclones are
arranged in a square pattern in the front wall of the boiler, two at each
elevation as detailed in Table 6-38.
-------
TABLE 6-35
EXPERIMENTAL DESIGN AND AVERAGE EMISSION MEASUREMENTS
Atlantic City Electric
(B. L. England, Boiler No. 1)
Oil Firing
S. Normal (^
Firing ^<
Pattern ( ) ( )
Cyclone
Arrangement
Full Load 133 MW
A.
Norma 1
Air
^ 1.5% 02
441 PPM
NO
X
A
Inter
Air
(2> 1.1% 02
396 PPM
NO
X
A
Low
Air
*2) 0.5% o2
313 PPM
NO
X
Intermediate Load 105 MW
Al
Norma I
Air
^ 2.7% 02
404 PPM
NO
X
A
Inter
Air
© 2.4% 02
364 PPM
NO
X
A
Low
Air
1.0% 02
241 PPM
NO
X
Low Load
62 MW
Al
Normal
Air
® f.2Z 02
261 PPM
NO
X
UJ
VO
* B Cyclone Off
-------
- 140 -
Figure 6-28
PPM NOx VS O2 MEASURED IN FLUE GAS
Atlantic City Electric
(B. L. England, Boiler No. 1)
Oil Firing
I
450
400
350
300
Full Load - Normal Firing Pattern
Intermediate Load -
Normal Firing Pattern
250
Low Load
200
150
100
0
in Flue Gas
-------
TABLE 6-36
FLUE GAS MEASUREMENTS AND TEMPERATURES
Atlantic City Electric
(B. L. England, Boiler No. 1)
Oil Firing
TEST
RUN
NO.
1
2
3
4
5
6
7
GROSS
LOAD
MW
133
133
132
62
105
105
103
AVERAGE FLUE GAS MEASUREMENTS
°2
%
1.5
1.1
0.5
4.2
2.7
2.4
1.0
co2
%
13.1
13.1
13.2
11.9
12.7
12.9
13.8
NO
X
ppm
(3% 02)
441
396
313
261
404
364
241
CO
ppm
(3% 02)
57
74
1523
54
59
53
68
TEMP.
°F
762
760
748
626
727
715
697
-------
- 142 -
Table 6-37 lists operating and emission data for the two test runs
conducted on this boiler. As agreed upon with ACE, the only operating
variable during these tests was excess air. Low excess air was defined as
the minimum excess air that produced only a slight visible plume with
periodic wisps of gray smoke, no appreciable increase in smoke meter indica-
tions, and reasonable increases in CO emission levels (i.e., <200 ppm).
Average ppm NOX measurements (3% 02, dry basis) pounds NOX/10° Btu and
average % 02 measurements are shown in Table 6-37 for each test run. Each of
the four probes contained short, medium, and long gas sampling tubes that
were positioned to provide samples from the centers of equal areas across
the width of the duct at each probe. Gas sampling probes were located
between the economizers and the air preheater. Flue gas composition, ex-
cept for probe No. 1 located on the left hand side of the boiler, was
fairly uniform. Unbalanced gas flow was experienced on the unit with
the major part of the flow concentrated on the left hand side at probe
No. 1.
Table 6-38 shows the operating variables, excess air, with average
flue gas measurements of % oxygen and ppm NOX (3% 00, dry basis) for each
run. The cyclone configuration is shown at the bottom of Table 6-38.
Baseline operations (test run No. 1) conducted at full load with
all four cyclones firing crude oil, produced average flue gas NOX concen-
trations of 361 ppm (3% 02, dry basis) at 2.2% oxygen. Reducing the excess
air level to that corresponding to 1.6% oxygen in the flue gas resulted in
an average level of 303 ppm NOX (3% 02, dry basis), or a decrease of 16%
from baseline conditions.
Table 6-39 lists average flue gas comporert measurements and tem-
peratures for each test run. Percent 0_, percent C02, ppm NO , ppm CO and
temperatures are shown. The ppm data are listed on a 3% 0 dry basis.
To sum up, this boiler has baseline NOX emissions of 361 ppm NO
which are higher than the original EPA recommended standards of about 225X
ppm for new oil fired boilers. Low excess air operation resulted in a 16%
reduction in NOX emissions, but could not reduce them below recommended
standard levels. This reduction in NO emissions was achieved without any
adverse effects, such as significantly increased smoke, unburned combustible
emissions, or reduced operability.
-------
TABLE 6-37
SUMMARY OF OPERATING AND EMISSION DATA
Atlantic City Electric
(B. L. England, Boiler No. 2)
Oil Firing
Boiler Operating Conditions
Test
No.
1(2>
2(2)
Gross
Load
MW
167
167
Excess
Air
Level
Normal
Low
Firing
Pattern
All Burners
On
ii
Flue Gas Measurements
Smoke
Meter
24
24
%o2
2.2
1.6
PPM NOX
(3%02, Dry)
361
303
POUND S,NOx
PER 10 BTU
0.48
0.42
to
I
(1) Flue gas measurements are averages of three composite flue
gas samples taken from each of 4 probes.
-------
- 144 -
TABLE 6-38
EXPERIMENTAL DESIGN AND AVERAGE EMISSION MEASUREMENTS
Atlantic City Electric
(B. L. England, Boiler No. 2)
Oil Firing
S^ Normal
Firing
Pattern
Full Load
167 MV
AI Normal
Excess
Air
2.2% 02
361 PPM
NOV
A.
A2 Low
Excess
Air
1.6% 0
L
303 PPM
NOV
A.
O O
Top Row
Bottom Row
Cyclone Configuration
NOTE: Each run number gives average % oxygen and ppm NO
(3% 02 dry basis).
-------
TABLE 6-39
FLUE GAS EMISSION MEASUREMENTS AND TEMPERATURES
Atlantic City Electric
(B. L. England, Boiler No. 2)
Oil Firing
DATE
5/8/73
TEST
RUN
NO .
1
2
GROSS
LOAD
MW
167
167
FLUE GAS MEASUREMENTS (1)
°2
%
2.2
1.6
co2
%
13.5
13.5
NO
x
ppm @
3% 02
361
303
CO
ppm @
3% 02
85
231
TEMPERATURES
°F
701
698
(1) Average of three 2-minute gas composites from each of four probes.
-------
- 146 -
7. RECOMMENDATIONS FOR
FURTHER FIELD TESTING
As discussed in Section 2, major problem areas and potential
limitations of combustion control techniques for NOX reduction that remain
for coal fired boilers have been well defined. Primary emphasis in
further field test programs should be placed on the longer period, dif-
ficult operating problems of coal fired boilers under "low NOX" combustion
control as detailed below. In addition, gas turbines and stationary
internal combustion engines should be field tested because of their
expanding number and importance in electric power generation. This factor
is directly related to the contribution of equipment categories to the
overall NOX emission problem for stationary sources.
7.1 Utility Boiler Testing
Table 7-1 summarizes the number of boilers by fuel and type of
firing recommended for future field testing based on the results of the
present work and prior Esso field studies (4-6) .
TABLE 7-1
NUMBER AND TYPE OF UTILITY BOILERS TO BE
TESTED IN FUTURE FIELD TEST PROGRAMS
Fuel Fired:
Mixed Waste Expected
Type of Firing Coal Fuels Fuel Total
Wall (FW + HO) 3 1 1 5
Tangential 311 5
Cyclone 1 1
Turbo Furnace 1^ _ _ 1
Expected Total 822 12
Major emphasis should be placed on coal fired boilers. However, mixed
fuels (combinations of coal, gas and oil) and waste-fired fuels should
also be tested. Wall fired (front wall and horizontally opposed) and
tangentially fired boilers should be given about equal emphasis. One or
two cyclone furnace boilers and a turbo furnace boiler should be tested
if sufficiently flexible boilers can be located and arrangements with
boiler operators can be made.
The coal types to be included in future testing should encom-
pass Western low-sulfur bituminous and sub-bituminous, lignite, Midwestern
bituminous and Eastern bituminous and sub-bituminous coals. Because of
-------
- 147 -
their increasing performance as national energy resources, priority should
be given to Western coals and lignite. Simultaneously fired fuels should
include combinations of coal and oil, coal and gas, and oil and gas.
The waste fuel fired boiler could be either waste alone, or a combination
of waste and fossil fuel fired.
The basis for selecting specific boilers for testing within
each of the four types of firing groups includes an evaluation of
all pertinent operating factors in addition to being representative of
current design practices of major boiler manufacturers.
Operating flexibility is the prime selection criteria. Boilers
designed to operate with "NO-ports" or "overfire" air-ports and/or flue gas
recirculation into the windbox should be especially sought out for inclusion into
future test programs. In addition, the operator's ability and willingness
to fire with low excess air, to employ staged combustion, to utilize
water injection, to control air and fuel to individual burners and to
reduce loads are highly important. Obviously, the boilers selected must
be in good repair and have the proper instrumentation and controls so
that good data for fuel usage, combustion and steam-side analysis can
be obtained. Also, the boiler operator's willingness to cooperate by
providing proper sampling ports, assistance in obtaining fuel and ash
samples, good supervision for the required safe changes in operation,
research-mindedness and experience in NOX control should be taken into
account. The boiler selection process will be greatly assisted with the
continued cooperation of boiler manufacturers and boiler operators
experienced in our present and previous field study programs.
The cooperative planning effort of the current field test pro-
gram provides a recommended framework for future test programs. Exxon
Research developed a comprehensive list of selection criteria to assist
EPA and boiler manufacturers in preparing a list of potential boiler
candidates. Each boiler manufacturer submitted a list of suggested
boilers to EPA for review and screening. After consideration of such
factors as design variables, operating flexibility, fuel type, geographic
location and logistics, a tenative list of boilers was selected by EPA
and Exxon. Field meetings were then held at power stations to confirm
the validity of the boilers selected and to obtain necessary boiler
operating and design data.
Since it is desirable to test representative types of coal and
mixed fuels that are fired in different geographic regions of the United
States, it will be desirable to minimize travel time by utilizing the
concept of cluster sampling. Consideration should be given to testing
in fringe areas where different fuel types can be supplied to the same
boilers.
-------
- 148 -
The scope and order of work to be performed on each boiler
can be described in terms of an expanded version of our current three
stage program. First, a statistically designed program of short-period
test runs should be conducted, incorporating all available combustion
control variables, to determine the optimum and near optimum operating
conditions for NOX emission control under both full load and reduced
load operation. Second, the boiler should be operated for 1 to 3 days
under sustained low NOX conditions, to validate optimum NOX emission
reduction conditions, and to assess potential boiler operability
problems such as slagging and steam temperature control. Third, sustained
300-hour runs should be made under both baseline and "low NOX" operation.
During these periods, air-cooled carbon steel coupons will be exposed to
combustion gases in the vicinity of furnace water tubes, to determine
through corrosion tests whether operating the boiler under the reducing
conditions associated with low excess air and staged firing results in
increased fire-side water— tube corrosion rates. Particulate samples
should also be obtained under both baseline and "low NOX" operations to
determine if increased amounts of unburned carbon on fly ash result; also to
determine if fly ash loadings increase under "low NOX" operations. The samples
should be analyzed for trace constituents. Boiler operating data should
be recorded in order to determine boiler efficiency, and operating
observations should be recorded to assess operating problems, such as
excessive furnace slagging or steam temperature problems.
Several additional work items should be included in the
enlarged three stage testing program in future boiler tests.
• The 300-hour sustained runs on selected boilers should
be extended to a six-month period. A representative
sample of tube wall thickness measurements should be
made under normal conditions and before and after the
sustained run to compare with coupon corrosion measurements-
• Precipitator performance tests should be made during
both baseline and "low NOx" operations.
Particle size distribution and conductivity tests
should be made on fly ash samples ,and flue gas
803 measurements obtained in conjunction with per
formance test so that cause-effect relationships
may be established.
Flue gas particulate measurements should be made
both upstream and downstream of electrostatic
precipitators, to assess the effect of combustion
modifications on precipitator performance.
-------
- 149 -
• The particulates collected should be analyzed
for potentially hazardous trace constituents,
such as Hg, Cd, Be and Cd. Special attention
should be paid to the effects of combustion
modifications on the potential segregation of
such constituents into different particle size
ranges •
• Furnace slagging observations should be quantified
as far as practical and related to changes in fuel
composition and boiler operation. Representative
samples of raw coal, furnace slag, fly ash and
bottom ash as well as flue gas should be taken
during both sustained baseline and "low NOX"
operations. These samples should be analyzed so
that changes in slag observations can be correlated
with coal quality (heating value, % ash, ash com-
position, ash viscosity, ash softening point, ash
melting point etc.) and other operating parameters
affecting combustion. Mill performance (coal fineness),
fuel distribution (burner to burner), air distribution
(uniformity of secondary air register openings from
burner to burner, or side to side variation due to
plugged air heaters on unbalance in forced or induced
draft fans), flame shape (coal spreader condition and
setting, air register setting, coal nozzle setting,
burner head distribution vane setting) burner line
velocities, staged firing pattern, and excess air
level are some of the operating variables that
should be observed and recorded for rigorous
regression analysis with slagging observations. This
systematic approach is necessary for solving the
slagging problems that had been identified, but
were beyond the scope of the present and past field
test program.
-------
- 150 -
8. REFERENCES
1. W. Bartok, A. R. Crawford, A. R. Cunningham, H- J. Hall, E. H. Manny
and A. Skopp, "Systems Study of Nitrogen Oxide Control Methods for
Stationary Sources," Esso Research and Engineering Company Final
Report GR-2-NOS-69, Contract No. PH 22-68-55 (PB 192 789) November,
1969.
2. W. Bartok, A. R. Crawford, A. R. Cunningham, H. J. Hall, E. H. Manny
and A. Skopp, "Stationary Sources and Control of Nitrogen Oxide
Emissions," in "Proceedings of the Second International Clean Air
Congress", H- M. England and W. T. Beery, editors, pp. 801-818,
Academic Press, New York, 1971.
3. W. Bartok, A. R. Crawford and A. Skopp, "Control of NOX Emissions
from Stationary Sources", Chem. Eng. Prog. 67, 64 (1971).
4. W. Bartok, A. R. Crawford and G. J. Piegari, "Systematic Field
Study of NOX Emission Control Methods for Utility Boilers," Esso
Research and Engineering Company Final Report No. GRU-4G.NOS.71,
NTIS Report No. PB 210-739, December 1971.
5. W. Bartok, A. R. Crawford and G- J. Piegari, "Systematic Investigation
of Nitrogen Oxide Emissions and Combustion Control Methods for
Utility Boilers," in "Air Pollution and Its Control," AIChE Symposium
Series 68. (126), 66 (1972).
6. W. Bartok, A. R. Crawford and G- J. Piegari, "Reduction of Nitrogen
Oxide Emissions from Electric Utility Boilers by Modified Combustion
Operation," presented at Fourteenth International Symposium on
Combustion, The Pennyslvania State University, August 1972.
7. D- W. Pershing, G. B. Martin and E. E. Berkau, "Influence of Burner
Design Variables On The Production of NOX and Other Pollutants,"
Paper No. 22C, AIChE 66th Annual Meeting, Philadelphia, Pa.,
November 11-15, 1973.
8. D. W. Turner, R. L. Andrews and C. W. Siegmund, "Influence of
Combustion Modification and Fuel Nitrogen Content On Nitrogen
Oxide Emissions From Fuel Oil Combustion" in Air Pollution and
Its Control, AIChE Symposium Series, Vol. 68 (196), 55 (1973).
9. Environmental Protection Agency,"Standards of Performance for New
Stationary Sources," Method 5, Published in the Federal Register,
December 23, 1971, Vol. 36, Number 247, p. 24888-
-------
- 151 -
10. Shively, W. L., and Harlow, E. V., "The Koppers Electrical Process
for the Prevention of Nitrogenous Gases in Distributed Gas",
American Gas Journal, 144(6), 9, (1936).
11. Ehnert, W., "Behavior of Nitric Oxides During Electrostatic Gas
Purification", Bremstoff-Chem. 9(7), 2, (1936).
12. Baum, W. H., Crest, J. G. and Nagee, E. V., "Process for Removing
Nitric Oxide from Gaseous Mixtures", Patent: U.S. 3,428,414
Filed June 2, 1966.
13. A. R. Crawford, E. H. Manny and W. Bartok, "NOX Emission Control
for Coal Fired Utility Boilers," Presented at the "Coal Combustion
Seminar," Environmental Protection Agency, Research Triangle
Park, N.C., June 19-20, 1973; pp. 215-283 of Proceedings, Environmental
Protection Technology Series, EPA-650/2-73-021, September, 1973.
-------
A-l
APPENDIX A
OPERATING AND GASEOUS
EMISSION DATA SUMMARIES
This section of the report contains 12 tables summarizing
the operating and gaseous emission data by test run for each of the
12 coal fired boilers tested.
Table Boilers
1 Widows Creek No. 6
2 Dave Johnston No. 2
3 E. D. Edwards No. 2
4 Crist No. 6
5 Harllee Branch No. 2
6 Leland Olds No. 1
7 Rmr Corners No. 4
8 Barry No. 3
9 Naughton No. 3
10 Dave Johnston No. 4
11 Barry No. 4
12 Big Bend No. 2
Hydrocarbon and S02 measurements made in this study are not
included in the tables of Appendix A for the following reasons- In
all cases, the volatile hydrocarbon emission levels were negligible.
in line with our previous experience in field testing coal-fired boilers
(4-6)• While S02 emissions were measured, it is felt that in general
these results are not reliable because of instrument calibration problems.
This will be corrected for future field testing studies so that the effect
of combustion modifications on flue gas SO-/SO ratios can be determined.
* The initial S02 concentration of fresh calibration gas cylinders has
been found to decrease with time (presumably due to the adsorption of
SOo on the walls of the gas cylinder). This problem will be eliminated
in future studies by frequent re-checking of the certified calibration
gases.
-------
A-2
TABLE 1
SUMMARY Of OPERATING AI.D EMISSION DATA - WIDOWS CREEK. BOILER NO. 6
(125 MW, Front Wall, Pulverized Coal Fired)
Average Gaseous Emissions and Temperatures
Firing Pattern
Date and
Run No.
4/12/72
1
2
3
4
4/17/72
5
6
7
8
4/18/72
20A
9
10
11
12
1A
4/19/72
13
14
15
4/20/72
18
16
19
17
20
4/21/72
IB
4/24/72
21
23
22
24
4/25/72
25
28
27
26
4/26/72
31
32
29
30
4/27/72
lOAl
5/1/72
10 /Ci
5/2/72
10/C3
5/3/72
10 /C 5
26Ai
5/4/72
26A3
Gross
Load
(MW)
125
125
125
125
126
119
122
120
115
125
125
125
121
125
110
110
112
110
110
110
112
108
128
80
83
88
89
110
100
103
99
112
106
110
106
120
120
125
123
97
103
Burners
Code
sl
Si
sl
Sl
S2
S2
S3
S3
S8
Si
S3
S2
S7
.£
Sl
S4
S5
S6
S7
s?
Sfi
O
s5
S4
Sl
S6
S7
S5
S4
s?
S6
S5
S4
Sl
Sl
sl
Sl
S3
S3
S3
S3
S4
S4
No. on
Coal
16
16
16
16
14
14
14
14
12
14
14
14
14
16
12
12
12
12
12
12
12
12
16
12
12
12
12
12
12
12
12
16
16
16
16
14
14
14
14
12
12
On Air
Only
D1D4
DlD4
A1A4
AlA4
B1B2B3B4
XA?
AX
DX
DM
1 4
1 7 x A
A1A?B9Bt
A1A4B2B3
A1A4B1B4
AA.DnD.
A1AXDA
A!AXBt
AWB?
AXA2A3A4
A^A B B
wX
A!AXBt
A1A\2A3
1234
A A D D
A1AXB4
AlAXBt
.1.4.2.3
1234
A1A4
A1A4
A1A4
A1A4
A1A2A3A4
A1A2A3A4
Secondary
Air
Registers
(% Open)
60
60
20
20
60
20
20
60
60
60
20
20
60
60
60
60
20
20
20
20
60
60
60
60
60
20
20
60
60
20
20
20
20
60
60
20
20
20
20
20
20
Exc. Air
Level -
% Stoic.
Act. Bur.
Nor-117
Min-110
Nor-115
Min-109
Nor-108
Min-96
Nor-110
Min-100
Min
Nor-lQ7
Min-94
Nor-106
Min-94
Nor-118
Nor-94
Min-86
Nor-99
Nor-94
Min-86
Min-88
Nor-94
Min-87
Nor-120
Nor-105
Min-92
Min-89
Nor-94
Nor-94
Min-94
Nor-97
Min-86
Nor-129
Min-115
Nor-129
Min-114
Min-105
Min-102
Min-103
Min-102
Min-86
Min-85
NOX
PPM
(3% 02,
Dry)
577
491
610
505
558
372
532
368
371
518
345
632
406
669
460
342
471
418
329
301
480
345
656
550
438
306
399
495
438
496
297
681
464
629
450
409
343
397
403
299
290
Pounds
Per
106 BTU
0.77
0.65
0.81
0.67
0.74
0.49
0.71
0.49
0.49
0.69
0.46
0.85
0.54
0.89
0.61
0.45
0.63
0.56
0.44
0.40
0.64
0.46
0.87
0.73
0.58
0.41
0.53
0.66
0.58
0.66
0.40
0.91
0.62
0.84
0.60
0.54
0.46
0.53
0.54
0.40
0.39
_0Z
%
3.2
2.0
2.8
1.9
4.0
2.0
4.5
2.7
2.2
4.1
1.7
3.8
1.5
3.3
4.5
2.6
5.2
4.3
2.9
3.1
4.4
3.0
3.6
6.1
3.9
3.4
4.5
4.5
4.5
4.9
2.7
4.9
2.8
4.8
2.7
3.6
3.0
3.3
3.2
2.8
2.5
C02
%
15.4
16.2
15.4
16.2
14.1
16.0
13.9
15.0
16.4
14.5
16.3
14.2
15.5
14.4
14.3
15.2
12.5
14.6
15.4
14.9
14.0
15.0
15.1
12.3
13.8
13.9
13.0
14.0
13.6
13.4
14.8
12.7
14.6
14.1
15.9
14.7
14.8
15.0
15.2
15.1
15.9
CO HC**
PPM PPM
3% 02 3% 02
Dry Dry
329
814
247
523
359
1049
491
833
899
383 4
1027 3
415 3
976 3
394 2
773 1
594
176
1110*
3090* -
3180*
167
1920*
52
40
292*
572*
141*
210* -
389* -
83
840*
61
407
52
530
650
867
414*
366
748
867
Temp.
°F
699
691
701
691
716
686
707
692
672
703
681
711
683
700
678
672
706
694
685
688
704
696
-
684
668
672
681
696
682
695
668
707
680
702
678
696
690
698
696
680
685
* High variation in CO measurements between probes.
** Hydrocarbons were measured on each test but values were negligible except where indicated.
-------
TABLE 2
SUMMARY OF OPERATING AND EMISSION DATA - DAVE JOHNSTON, BOILER NO. 2
(105 MW, Front Wall Pulverized Coal Fired)
Date and
Run No.
7/27/73
3
4
7/30/73
1
6
5
2
7/31/73
8
10
7
8/1/73
12
14
16
15
13
Gross
Load
MW
101
101
102
102
102
102
103
103
101
106
102
99
98
99
Boiler Operating Conditions
Firing
Pattern :
Mills
Off
12
12
11,12
11,12
11,12
11,12
11,12
11,12
11,12
12
10,12
10,12
10,12
10,12
Secondary Air
Register
Settings on
Off Mills
Closed
Closed
Closed
11 Op., 12 Cl.
Partly Open
11 Cl., 12 Op.
11 Cl. , 12 Op.
Open
Closed
Open
10 Cl., 12 Op.
Open
10 Op. , 12 Cl.
Closed
Excess Air
Target
Nor.
Low
Nor.
Low
Low
Low
Nor.
Nor.
Low
Low
Low
Low
Low
Nor.
% Stoic.
To Act.
Burners
130
125
125
94
82
99
102
85
120
102
102
88
106
132
Average Gaseous Emissions
N
PPM
(3% 02,
Dry)
454
409
450
362
311
284
347
358
413
314
270
214
326
438
Ox
Pounds
Per
106 BTU
0.60
0.54
0.60
0.48
0.41
0.38
0.46
0.48
0.55
0.42
0.36
0.28
0.43
0.58
02
%
5.0
4.3
4.3
3.3
4.0
4.2
4.6
4.6
3.7
4.1
4.7
5.2
5.3
5.2
CO?
%
14.3
14.6
15.3
16.4
16.3
16.0
14.4
14.8
15.2
15.1
14.5
13.4
13.4
13.4
CO
PPM
(3% 02,
Dry)
112
731
28
112
308
277
370
96
117
918
1054
962
620
420
NOTE: Hydrocarbons were measured on each test but values
were negligible except where indicated.
-------
TABLE 3
SUMMARY OF OPERATING AND EMISSIONDATA - E.D. EDWARDS, BOILER NO. 2
(260
MW, Front
Wall, Pulverized Coal Fired)
Boiler Operating Conditions
Firing Pattern
Date and
Run No.
6/11/63
1
2
6/12/63
5
6
3
4
6/13/63
23
24
13
18
8
7
6/14/63
14
10
11
12
9
6/15/63
16
20
1A
Gross
Load
(MW)
256
251
255
256
254
255
212
204
238
238
250
250
229
243
250
249
252
221
221
250
Burners
Code
Sl
sl
S2
S2
sl
Sl
sl
S4
S3
S3
S4
S2
S3
S3
S2
S5
S5
Sl
No. On
Coal
16
16
14
14
16
16
16
16
12
12
14
14
12
14
14
14
14
12
12
16
On Air
Only
None
None
1,4
1,4
None
None
None
None
1,2,3,4
1,2,3,4
2,3
2,3
1,2,3,4
1,4
2,3
2,3
1,4
1,4,6,7
1,4,6,7
None
Secondary
Air
Registers
(% Open)
45-50
45-50
45-50
20
20
20
50
50
50
50
50
20
30
50
50
30
30
50
30
50
Excess Air
Target
Nor.
Low
Nor.
Low
Nor.
Low
Nor.
Low
Nor.
Low
Low
Nor.
Low
Low
Nor.
Low
Nor.
Low
Low
Nor.
% Stoic.
To Active
Burners
117
107
106
94
117
109
124
108
97
89
100
108
94
96
106
96
107
86
87
121
Average Gaseous Measurements
NOV
PPM
(3% 02,
Dry)
670
556
644
359
770
692
668
516
535
386
524
401
310
474
609
382
625
336
295
736
Pounds
Per
106 BTU
0.89
0.74
0.86
0.48
1.02
0.92
0.89
0.69
0.71
0.51
0.70
0.53
0.41
0.63
0.81
0.51
0.83
0.45
0.39
0.98
02
%.
3.2
1.5
3.8
1.6
3.1
1.8
4.2
1.6
4.9
3.5
2.7
4.0
4.4
2.0
3.8
2.1
3.9
2.8
3.0
3.8
C02
%
14.8
16.0
14.6
16.2
14.4
15.4
14.1
16.3
13.2
14.1
14.3
13.3
13.3
16.6
14.4
15.7
14.4
15.0
14.6
14.2
CO
PPM
(3% 02,
Dry)
69
93
18
172
16
29
17
54
23
234*
117
28
215*
200*
19
333
22
257
26
16
Temp.
°F
644
622
649
642
644
637
620
597
647
633
636
640
627
630
647
474
633
613
610
647
NOTE: Hydrocarbons were measured on each test but
values were negligible except where indicated.
* Average values increased due to high CO measurements with one of 4 probes.
-------
A-5
TABLE 4
SUMMARY OF OPERATING
Boiler Operating Conditions
AND EMISSION DATA - CRIST. BOILER NO. 6
(340 MW, Front Wall, Pulverized Coal
Fired)
Flue Gas Emission Measurements
Excess Air
Firing P£
Date and
Run No.
12/6/72
3
2
12/7/72
26
12/8/72
4
5
12/9/72
ISA
12/11/72
1
5A
10
12/12/72
26B
12/13/72
6
7
8
12/14/72
16
3/19/73
14R
11R
16R
25R
3/20/73
1R
6R
8R
10R
Gross
Load
(MH)
315
318
350
318
320
270
320
320
320
350
320
310
314
250
272
272
272
272
315
320
321
320
i ttern
Burners
Code
S
S2
Sl
S3
S3
S4
S,
S3
S3
S!
S,
S
2
S4
S,
Sl
/
S5
S,
,,1
S
No. on
Coal
14
14
16
14
14
12
16
14
14
16
16
14
14
12
16
16
12
12
16
16
14
14
On Air
Only
1,4
1,4
None
2,3
2,3
1,2,3,4
None
2,3
2,3
None
None
1,4
1,4
1,2,3,4
None
None
1,2,3,4
2,3,5,8
None
None
1 ,4
2,3
Secondary
Air
Registers
(7. Open)
(Oper/Idle)
70/70
70/0*
101-
70/0*
70/70
70/0
101-
70/70
70/70
101-
101-
70/0*
70/70
70/70
70/70
70/70
70/70
TO/10
70/70
70/70
70/70
70/70
7, Stoic.
Air
To Active
Burners
Target
(1)
N
N
N
N
N
L
N
N
L
N
L
L
L
L
L
N
L
L
N
L
L
L
A
98
112
119
94
91
86
120
102
109
117
112
96
96
91
110
120
82
88
119
114
102
104
B
104
112
115
108
102
89
120
105
97
119
112
100
110
90
100
122
94
88
116
110
97
102
NOx 09
PPM
(37. 02)
724
946
898
516
532
643
902
728
566
888
804
788
772
661
754
840
560
647
916
862
738
802
Pounds/
106 BTU
0.96
1.26
1.20
0.69
0.71
0.86
1.20
0.97
0.75
1.18
1.07
1.05
1.03
0.88
1.01
1.12
0.75
0.86
1.22
1.15
0.98
1.07
"L
2.3
4.7
3.4
1.4
0.9
2.6
3.6
3.1
1.8
3.2
2,4
2.0
1.9
3.8
2.0
3.7
1.8
3.1
3.4
2.6
3.1
3.5
Duct A
C02
7,
-_
13.5
15.0
15.9
17.0
16.2
16.0
15.0
15.3
14.8
15.8
15.8
15.2
14.2
15.7
14.3
15.5
13.8
15.0
15.7
15.2
14.9
CO
PPM
(37. 02)
38
26
24
44
900
59
22
32
75
19
80
47
29
29
44
45
396
372
56
66
87
66
HC Temp.
PPM
37, 02 °F
653
619
-
648
651
640
2 659
659
1 651
4 671
651
650
658
600
616
617
611
-
647
638
643
643
NOx
PPM
37. 02
631
872
743
546
620
415
799
565
522
801
630
565
591
411
640
748
472
484
765
660
526
593
Pounds/
106 BTU
0.84
1.16
0.99
0.73
0.83
0.55
1.07
0.88
0.70
1.06
0.84
0.75
0.79
0.55
0.85
1.00
0.63
0.65
1.02
0.88
0.70
0.79
02
7.
3.4
4.7
2.9
4.0
3.2
3.3
3.6
3.6
2.2
3.5
2.4
2.5
4.5
3.7
2.2
3.9
4.5
3.1
3.0
2. 1
2.2
3.0
Duct B
C02
7.
-~
13.4
15.3
13.6
15.0
15.6
15.6
14.5
14.9
14.4
15.6
15.2
13.3
14. 1
15.6
14.1
13.1
13.9
15.3
16.0
15.9
15.1
CO
PPM
(37. 02)
42
32
27
36
28
173
23
34
90
19
140
220
32
94
175
46
131
372
60
230
902
218
HC** Temp.
PPM
(37, 02.) °F
685
662
704
671
-
-
2 696
688
1 680
4 703
_
_
-
643
661
663
653
651
682
676
683
681
(1) Excess air target: N-Normal, L-Low Excess Air.
* Position of idle registeew was uncertain.
** Hydrocarbons were measured on each test but
values were negligible except where Indicated.
-------
TABLE 5
SUMMARY OF OPERATING AND EMISSION DATA - HARLLEE BRANCH, BOILER NO. 3
(480 MW, Horizontal Opposed Wall, Pulverized Coal Fired)
Boiler Operating Conditions Average Gaseous
Firing Pattern
Date and
Run No.
5/22/72
1
2
5/23/72
3
4
5
6
7
8
5/24/72
9
10
11
12
1A
5/31/72
20
14
28
23
IB
6/1/72
40
41
42
29
1C
6/12/72
ID
6/13/72
43
6/14/72
44
45
46
47
IE
6/15/72
48
49
6/19/72
50
51
52
6/27/72
16
6/28/72
1H
7/5/72
52 A
7/11/72
52B
7/12/72
52C
7/13/72
52D
7/14/72
52E
7/17/72
53A
7/18/72
53B
7/24/72
52T
7/25/72
526
7/26/72
53D
7/27/72
1J
IK
7/28/72
421
Gross
Load
(MW)
478
480
480
478
480
477
480
478
485
479
480
478
500
398
400
398
397
500
392
399
400
399
490
488
445
481
480
485
482
483
275
155
475
472
471
477
465
482
467
475
475
465
450
450
477
465
465
455
455
478
Burners
Code
sl
S
s1
s^
s2
5^
S3
S,
s
S,
s2
S2
S,
S*
s3
s°
sl
SB
S10
s
s"
sj
1
Sj
=14
s,,
s
sJi
s"
s^
s
s16
SIR
SIQ
S
S20
S20
S20
S20
S20
S20
S20
S21
S21
S20
S20
S21
S,,
'22
Sll
No. on
Coal
40
40
40
40
36
36
36
36
36
36
36
36
40
30
30
30
30
40
34
34
34
40
40
40
35
35
36
36
35
40
32
20
36
35
34
34
34
34
34
34
34
34
35
35
34
34
35
39
39
34
No. on
Air
0
0
0
0
4
4
4
4
4
4
4
4
0
10
10
10
10
0
6
6
6
0
0
0
5
5
4
4
5
0
8
8
4
5
6
6
6
6
6
6
6
6
5
5
6
6
5
1
1
6
Secondary
Air
Registers
100
100
50
50
100
50
50
100
100
50
50
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Excess Air
T t
Nor.
Lou
Nor.
Lou
Nor.
Lou
Nor.
Lou
Nor.
Lou
Nor.
Lou
Nor.
Low
Low
Low
Low
Nor.
Low
Low
Lou
Nor.
Nor.
Nor.
Low
Low
Lou
Lou
Lou
Nor.
Lou
Lou
Lou
Lou
Lou
Lou
Low
Lou
Lou
Lou
Lou
Lou
Lou
Low
Lou
Lou
Lou
Nor.
Nor.
Lou
% Stoic.
To Act.
119
107
120
110
105
98
107
99
104
95
108
97
120
81
80
80
79
123
92
93
94
116
116
120
94
94
95
96
95
116
92
67
96
94
91
90
90
91
91
91
93
94
94
94
89
91
96
112
113
92
NOX
PPH
(32 02,
Dry)
747
549
735
667
613
569
734
578
680
568
624
493
688
372
334
392
256
707
363
339
360
537
668
711
491
576
594
624
589
745
287
148
486
493
466
463
472
517
520
466
582
565
552
592
403
407
556
608
639
498
Pounds
Per
106 BTU
0.99
0.73
0.98
0.89
0.82
0.76
0.98
0.77
0.90
0.75
0.83
0.66
0.92
0.49
0.44
0.52
0.47
0.94
0.48
0.45
0.47
0.71
0.89
0.95
0.65
0.77
0.79
0.83
0.78
0.99
0.38
0.20
0.65
0.65
0.62
0.62
0.63
0.69
0.69
0.62
0.77
0.75
0.73
0.79
0.54
0.54
0.74
0.81
0.85
0.66
02
%
3.5
1.4
3.7
2.0
3.1
1.9
3.4
2.0
2.9
1.3
3.6
1.7
3.6
1.6
1.5
1.4
1.1
4.1
1.7
1.9
2.0
3.0
3.0
3.7
1.5
1.4
1.2
1.4
1.8
3.0
2.9
2.4
1.4
1.5
1.4
1.2
1.3
1.4
1.5
1.5
1.9
2.0
1.7
1.6
1.1
1.5
2.1
2.8
3.0
1.6
Emissions and Temperatures
C02
%
14.1
16.6
14.8
16.3
14.8
15.9
15.3
16.7
15.6
17.0
14.7
16.9
15.4
16.6
15.5
15.6
16.3
14.5
16.4
16.2
15.8
15.0
15.2
14.3
16.4
17.2
17.0
17.1
16.4
15.4
15.9
16.2
17.1
16.9
16.8
17.3.
17.2
17.4
17.1
17.1
16.0
16.4
17.3
16.6
17.3
16.6
16.5
16.4
15.5
16.1
CO
PPM
(3% 02,
Dry)
21
81
13
26
26
30
24
45
18
38
24
52
27
178
924
92
562
32
159
75
225
28
47
14
96
280
187
147
172
23
417
306
618
321
357
127
24
158
45
45
122
101
20
28
288
47
52
20
26
48
HC* Temp.
PPM
(3% 02,
Dry) °F
604
1 595
0 613
596
600
596
610
1 596
1 610
593
2 614
595
619
567
551
560
558
620
554
560
558
565
606
624
590
601
595
598
593
609
524
460
600
596
592
613
611
614
2 611
0 605
3.1 610
1.2 606
1.2 597
2 591
3 603
1.9 604
2.1 607
2.5 603
2.1 605
1.9 603
* Hydrocarbons uere measured on each test but values were negligible except uhere indicated.
-------
TABLE 6
SUMMARY OF OPERATING AND EMISSIONS DATA - LELAND OLDS. BOILER NO. 1
(218 MW, Horizontally Opposed, Pulverized Coal Fired Boiler)
Boiler Operating Conditions
Average Gaseous Emissions and Temperatures
Firing Pattern
Date and
Run No.
7/6/73
1
2
7/9/73
3
4
5
7/10/73
6
7
9
11
1A
7/11/73
4A
4B
7/12/73
4C
Gross
Load
MW
219
218
218
216
192
187
185
185
180
214
205
205
205
Code
[1]
Si
Si
S2
S2
S3
S4
S4
S5
S6
sl
S7
S7
s?
Firing
20
20
18
18
16
16
16
16
16
20
18
18
18
Air
Only
0
0
2
2
4
4
4
4
4
0
2
2
2
Excess Air
Target
Nor.
Low
Nor.
Low
Low
Nor.
Low
Low
Low
Nor.
Low
Low
Low
% Stoic.
To Act.
Burners
122
110
112
104
95
103
89
91
95
120
103
103
105
NOX
PPM
(3% 02,
Dry)
569
447
560
375
342
428
260
329
256
564
418
401
475
Pounds
Per
106 BTU
0.74
0.58
0.74
0.50
0.45
0.57
0.35
0.44
0.47
0.75
0.56
0.53
0.63
_2z
3.9
2.1
4.2
2.8
3.5
4.9
2.2
2.6
3.5
3.6
2.6
2.7
3.1
CO?
7
15.7
16.9
14.9
16.3
15.9
14.4
16.8
15.9
15.9
15.6
16.3
16.4
16.0
CO
PPM
(3% 02
Dry)
24
283
23
231
139
21
518
226
153
21
50
51
25
Temp.
°F
954
948
945
937 >
883 --J
910
981
922
880
947
935
990
918
NOTE: Hydrocarbons were measured on each test but
values were negligible except where indicated.
-------
A-8
TABLE 7
SUMMARY OF OPERATING AND EMISSION DATA - FOUR CORNERS, BOILER NO. 4
(800 MW, Horizontally Opposed, Pulverized Coal Fired)
Boiler Operating Conditions
Firing Pattern
Date and
Run No.
11/2/72
19
20
21
11/3/72
1A
6A
11/5/72
1
2
3
4
11/7/72
5
2B
8
7
11/8/72
6
IB
11/9/72
1C
ID
11/10/72
9
14
15
12
11/14/72
IE*
11/15/72
IF*
11/18/72
12A
11/20/72
12B*
11/21/72
12C*
Gross
Load
(MW)
600
600
590
750
755
740
710
730
730
760
750
730
730
754
768
810
796
801
794
806
794
755
775
725
704
735
Burners
Code
Jll
S5
S5
S5
sl
sl
sl
S2
S2
sl
Sl
S2
S2
sl
Sl
Sl
Sl
S3
S3
S4
S4
sl
Sl
S4
S2
S2
Firing
42
42
42
54
54
54
54
46
46
54
54
46
46
54
54
54
54
46
46
42
42
54
54
42
44
46
Air
Only
0
12
12
0
0
0
0
8
8
0
0
8
8
0
0
0
0
8
8
12
12
0
0
12
8
8
Second.
Air
Registers
% Open
100
100
100
100
100
100
50
50
100
50
50
50
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Excess Air
Target
Nor.
Nor.
Low
High
Low
Nor.
Low
Nor.
Low
Nor.
Low
Low
Nor.
Low
Nor.
Nor.
Nor.
Nor.
Low
Nor.
Low
Nor.
Nor.
Nor.
Low
Low
% Stoic.
To Act.
Burners
112
111
90
135
112
127
113
108
95
130
115
101
108
110
131
126
132
108
95
105
91
119
117
97
98
98
NOX
PPM
(3% 02,
Dry)
816
801
452
982
641
848
659
695
482
932
748
609
754
630
965
843
949
685
494
709
488
741
715
560
458
473
Pounds
Per
10b BTU
1.08
1.07
0.60
1.31
0.85
1.13
0.88
0.92
0.64
1.24
0.99
0.81
1.00
0.84
1.28
1.12
1.26
0.91
0.66
0.94
0.65
0.99
0.95
0.74
0.61
0.63
02
%
6.5
6.4
3.0
5.6
2.3
4.6
2.5
4.6
2.2
5.0
2.8
3.3
4.7
2.0
5.1
4.5
5.2
4.6
2.3
5.5
3.2
3.4
3.1
4.3
3.7
2.8
C02
%
11.0
11.0
14.3
11.7
14.6
13.8
14.6
12.5
14.4
13.5
15.0
13.1
13.8
15.9
13.5
13.5
12.6
13.9
15.6
12.6
14.6
14.8
15.3
13.9
14.4
15.0
CO
PPM
(3% 02,
Dry)
17
13
33
24
156
18
110
24
260
14
60
113
19
423
15
19
13
48
453
21
172
21
14
40
40
195
Temp.
°F
_
544
514
472
560
582
554
551
588
592
564
578
552
578
576
585
580
550
590
560
587
575
558
540
563
[1] Firing Pattern:
Symbols
Si O
S2 D
S3 A
S4 V
s, O
Burners on Air Only
None
INT, 9NT, 1ST, 9ST, 5NT, 6NT, 5ST, and 6ST.
INT, 1NM, 9ST, 9SM, 6NT, 6NM, 5ST, and 5SM.
INT, 9NT, 1ST, 9ST, 8NT, 2ST, 5NT, 6NT, 5ST, 6ST, 7NT and 3ST.
Burners fed by pulverizers 5 and 9.
100-200 gal./hour water injection into furnace.
NOTE: Hydrocarbons were measured on each test but
values were negligible except where indicated.
-------
TABLE 8
SUMMARY OF OPERATING AND EMISSION DATA - BARRY. BOILER NO. 3
(250 MW, Pulverized
Boiler Operating Conditions*
Firing Pattern
Gross
Date and Load
Run No. (MW)
3/23/73
1 250
2 248
3 248
4 248
5 250
6 250
7 251
8 248
Burners
Code
**
sl
Si
Sl
Sl
Sl
Sl
sl
si
No. on
Coal
48
48
48
48
48
48
48
48
No. on
Air
0
0
0
0
0
0
0
0
Secondary
Air Re£.
Aux/Coal
(% Open)
100/30
100/30
40/100
40/100
40/100
40/100
100/30
100/30
Coal, Tangentially
Excess Air
Mill
Fineness
Nor.
Nor.
Nor.
Nor.
Coarse
Coarse
Coarse
Coarse
Target
Nor.
Low
Nor.
Low
Low
Nor.
Nor.
Low
% Stoic.
To Act.
Burners
117
106
117
109
110
119
119
107
Fired)
Average Gaseous Emissions & Temp.
NOX
PPM
(3% 02,
Dry)
410
310
425
350
350
420
416
512
Pounds
Per
106 BTU
0.54
0.41
0.56
0.46
0.46
0.56
0.55
0.41
o?
%
3.1
1.3
3.2
1.9
2.0
3.5
3.5
1.4
CO?
%
14.8
16.2
14.2
15.2
14.9
13.3
13.1
14.4
CO
PPM
(3% 03,
Dry)
61
100
60
115
130
64
77
129
Temp.
°F
662
646
666
648
654
666
663
645
T
VD
* Tilts welded into fixed position.
** Only normal firing runs because of mechanical problems.
NOTE: Hydrocarbons were measured on each test but
values were negligible except where indicated.
-------
A-10
TABLE 9
SUMMARY OF OPERATING AND EMISSION DATA - NAUGHTON, BOILER NO. 3
(330 MW, Tangential, Pulverized Coal Fired Boiler)
Boiler Operating Conditions
Average Gaseous Emissions and Temperature
Firing Pattern
Date and
Run No.
9/13/72
1
9/14/72
2
3
4
5
9/18/72
6
7
8
9
9/19/72
10
11
12
13
9/20/72
14
15
16
17
9/21/72
18
19
20
21
9/27/72
22
10/4/72
23
10/6/72
24
10/9/72
25
10/10/72
26
Gross
Load
(MW)
256
260
265
254
260
250
262
260
262
256
259
260
260
199
198
200
199
328
328
308
310
275
283
300
315
340
Burners
Code
Si
S2
s2
S2
S2
S2
S2
S2
S2
S2
S
Si
Sj
S3
Si
Si
s2
s2
S2
Si
Si
Si
Si
No. on
Coal
20
16
16
16
16
16
16
16*
16*
16
16
16*
16*
16
12
12
12
20
20
16
16
16
20
20
20
20
No. on
Air
0
4
4
4
4
4
4
4
4
4
4
4
4
0
4
4
4
0
0
4
4
4
0
0
0
0
Secondary
Air
Registers
Aux./coal
(% Open)
20-80
20-80
20-80
20-80
20-80
20-90
70-25
70-25
15-90
60-20
60-20
60-20
60-20
20-80
20-80
20-80
70-30
20-80
20-80
20-80
70-30
20-80
20-70
20-80
20-80
20-80
Burner
Tilt
(° From
Horiz.)
0
0
0
-30
+10
-30
-30
-30
-30
0
+22
+20
0
0
0
0
0
0
0
0
0
0
-30
-30
-30
0
Excess Air
Target
Nor.
Nor.
Low
Low
Low
Low
Low
Low
Low
Low
Low
Low
Low
Nor.
Nor.
Low
Low
Nor.
Low
Low
Low
Nor.
Nor.
Nor.
Nor.
Nor.
% Stoic.
To Act.
Burners
**
127
99
91
92
92
91
92
93
92
88
90
90
91
118
78
74
65
121
109
88
77
105
120
120
124
125
NOX 02 C02
PPM
(3% 02,
Dry)
537
304
265
266
284
216
213
251
245
197
216
273
235
458
169
182
176
494
379
236
219
331
510
569
549
568
Lbs.
Per
106 BTU % %
4.9 12.9
4.9 13.5
3.6 14.2
3.7 14.0
3.6 13.7
3.1 14.5
3.0 16.0
3.2 15.9
3.1 16.4
3.0 16.8
3.5 16.4
3.7 15.9
3.7 16.0
4.2 14.6
4.5 13.4
3.2 13.7
4.2 12.7
3.9 14.7
2.1 15.8
2.7 14.5
2.3 14.8
3.1 15.2
3.6 15.3
3.6 15.3
4.2 14.0
4.4 14.2
HC*** CO
PPM
(3% 02,
Dry)
-
1
1
1
1
1
1
1
1
1
1
1
1
-
-
-
-
-
-
-
-
-
-
-
-
-
PPM
(3% 02,
Dry)
30
14
62
28
23
210
78
82
91
376
354
306
208
20
27
56
102
30
225
44
499
185
21
19
18
24
Temp.
°F
694
693
673
666
672
666
504
666
682
670
673
674
672
626
631
622
636
755
732
715
714
686
702
721
763
757
* Mill fineness set to coarse (1 vs. 2.1)
** Calculated by combustion engineering from air register openings and total air.
*** Hydrocarbons were measured on each test but values were negligible except where indicated.
-------
TABLE 10
SUMMARY OF OPERATING AND EMISSION DATA - DAVE JOHNSTON, BOILER NO. 4
(340 MW, Pulverized Coal, Tangentially Fired)
Boiler Operating Conditions Average Gaseous Emissions & Temp.
Firing Pattern
Date and
Run No.
8/8/73
1
2
3
4
8/9/73
10
17
Gross
Load
(MW)
306
303
303
305
310
312
Excess Air
Burners
Pulv.
Off
17 &
17 &
17 &
17 &
17 6,
17 &
20
20
20
20
21
21
No. on
Coal
20
20
20
20
20
20
No. on
Air
0
0
0
0
0
0
Target
Nor.
Low
Low
Low
Nor.
Nor.
% Stoic.
To Act.
Burners
124
117
117
119
122
122
Burner
Tilt
(° From
Horiz.)
0°
0°
-10°
+16°
0°
-10°
NOX
Primary
Air
Level
Low
Low
Low
Low
+10%
+10%
PPM
(3% 02
Dry)
434
386
414
381
362
380
Pounds
Per
10 6 BTU
0.58
0.51
0.55
0.51
0.48
0.50
02_
%
4.2
3.2
3.2
3.4
3.9
3.9
C02
%
14.6
16.2
16.0
15.6
12.3
13.3
CO
PPM
(3% 02
Dry)
19
56
28
142
41
40
Temp.
°F
780
700
750
765
775
780
NOTE: Hydrocarbons were measured on each test but
values were negligible except where indicated.
-------
A-12
TABLE 11
SUMMARY OF OPERATING AND EMISSION DATA - BARRY. BOILER NO. 4
(360 MW, Tangential, Pulverized Coal Fired)
Boiler Operating Conditions
Firing Pattern
Date and
Run No .
1/19/73
13
29
30
31
1/22/73
17
18
19
20
32
1/23/73
1
2
3
4
5
6
7
8
1/24/73
33
34
35
37
9
10
11
12
2/4/73
40
41
25
26
27
28
2/5/73
13A
14
15
16
2/7/73
42
43
2/9/73
50
2/13/73
19A
2/14/73
19B
2/21/73
19C
19D
19 E
19F
2/22/73
42A
2/23/73
42B
Gross
Load
(MW)
325
328
330
330
290
295
292
281
286
348
348
344
334
299
298
294
294
346
345
360
348
322
297
311
304
186
180
210
186
184
180
343
292
284
283
320
325
323
283
255
282
280
289
288
293
283
Burners
No. on
Code Coal
ASi
ASi
ASi
AS1
BCS!
BCS2
BCS2
BCS2
BCS2
ACS.
ACS*
ACS*
ACS,
ACS,
ACS,
ACSj
ACS.
ACS.
ACS:
ACS:
ACS,
ACS,
ACS,
ACSj
BS.
BS3
BCS^
BCS,
BCS
BCS*
AS1
AS0
2
ACSi
ACSj
BCS2
BCS2
BCS2
BCS
BCS,
BCS^
BCSl
BCS2
20
20
20
20
20
16
16
16
16
20
20
20
20
16
16
16
16
20
20
20
20
16
16
16*
16*
12
12
20
12
12
12
20
16
16
16
20
20
16
16
16
16
16
16
16
16
16
No. on
Air
0
0
0
0
0
4
4
4
4
0
0
0
0
4
4
4
4
0
0
0
0
4
4
4
4
4
4
0
4
4
4
0
4
4
4
0
0
0
4
4
4
4
4
4
0
0
Secondary
Air Reg.
Burner
Tilt
Aux./Coal (" From
(% Open) Horiz.)
100/50
100/50
100/50
50/100
100/50
100/50
100/50
50/100
50/100
100/50
100/50
100/50
50/100
100/50
100/50
100/50
50/100
100/50
100/50
100/50
100/20
50/100
100/50
100/50
50/100
100/50
100/50
50/100
100/50
100/50
100/50
100/50
100/50
100/50
50/100
32/50
32/50
40/50
100/50
100/50
100/50
100/50
30/50
50/20
100/50
100/50
0
0
+20
-30
0
0
0
-30
0
0
0
+15
-25
0
0
+15
-30
-30
-30
0
0
0
-30
-30
0
0
0
0
0
0
-30
0
0
0
-15
-8
-8
-8
-8
-8
-8
-8
-8
-8
-8
-8
Excess Air
% Stoic.
Target
Nor.
Low
Low
Low
Nor.
Nor.
Low
Low
Low
Nor.
Low
Low
Low
Nor.
Low
Low
Low
Nor.
Low
Low
Low
Low
Low
Low
Low
Nor.
Low
Nor.
Low
Nor.
Low
Nor.
Nor.
Low
Low
Nor.
Nor.
Nor.
Low
Low
Low
Low
Low
Low
Nor.
Nor.
To Act.
Burners
115
107
110
107
118
100
94
86
94
115
112
110
106
96
94
92
85
114
108
112
112
92
86
86
91
100
84
123
83
97
86
112
90
88
87
112
107
115
92
91
95
87
90
91
117
115
Average
Gaseous
NOx
PPM
(37. 02,
Dry)
420
336
364
398
441
334
288
273
282
415
398
349
364
313
286
294
257
497
445
409
441
295
289
299
297
338
200
440
189
261
232
415
309
245
264
396
349
436
347
288
338
258
276
274
396
370
Pounds
Per
106 BTU
0.56
0.45
0.48
0.53
0.59
0.44
0.38
0.36
0.51
0.55
0.53
0.46
0.48
0.42
0.38
0.39
0.34
0.64
0.59
0.54
0.59
0.39
0.38
0.40
0.40
0.45
0.27
0.58
0.25
0.35
0.31
0.55
0.41
0.33
0.35
0.53.
0.46
0.58
0.46
0.38
0.45
0.34
0.37
0.36
0.53
0.49
Emissions and Temperature
J02
C02
CO
PPM
Temp.
(K U2,
4.7
2.8
3.6
2.8
5.1
6.3
4.9
3.1
5.0
4.4
3.9
3.6
2.5
5.4
4.8
4.4
2.4
4.3
3.1
3.8
3.9
4.4
3.0
2.9
4.3
7.7
3.9
6.0
3.7
7.1
4.3
3.8
5.1
3.6
3.3
3.8
2.7
4.4
4.6
4.3
5.2
3.3
3.9
4.2
5.0
4.5
13.4
15.4
14.5
15.2
11.5
12.3
12.5
13.3
11.9
13.8
13.8
13.8
14.0
11.5
12.2
12.1
15.9
14.4
15.4
14.0
13.7
13.0
14.1
14.5
13.3
10.5
14.1
11.6
13.7
10.6
13.1
14.6
13.1
14.0
14.5
13.4
14.0
14.6
15.9
14.1
12.7
13.5
13.0
12.6
13.2
14.2
20
227
37
41
19
33
50
43
50
24
115
100
96
26
63
98
107
27
24
169
58
97
113
114
189
22
211
27
281
30
43
25
25
201
58
56
395
37
48
49
21
177
130
69
36
47
308
311
310
312
305
295
295
289
292
305
290
295
291
281
280
288
284
308
308
310
309
291
286
288
285
273
254
266
249
255
250
315
298
290
277
305
303
291
283
290
293
281
282
280
280
215
* Coarse mill setting.
NOTE:
Hydrocarbons were measured on each test but
values were negligible except where indicated.
-------
TABLE 12
SUMMARY OF OPERATING AND EMISSION DATA - BIG BEND. BOILER NO. 2
(450 MW, Turbo-Rirnace, Pulverized Coal Fired)
Boiler Operating Conditions
Average Gaseous Emissions and Temperature
Date and
Run No.
3/5/73
6
4A
4B
3/6/73
2
1
3
5
3/7/73
20*
21**
22***
3/12/73
9
10
11
12
Gross
Load
(MW)
225
375
380
370
370
370
370
230
230
230
300
300
300
300
Direct
Vanes
Front/Rear
-15/+15
-15/+15
-15/+15
-15/-15
-15/-15
-15/-15
-15/+15
-15/+15
-15/+15
-15/+15
-15/+15
-15/+15
-15/+15
-15/+15
Firing
Pattern
Excess Air
Burners
Ash
Inject.
Yes
Yes
No
No
Yes
No
No
No
No
No
No
No
No
No
No. on
Coal
24
24
24
24
24
24
24
16
16
16
24
24
24
24
No. on
Air
0
0
0
0
0
0
0
0
4
8
0
0
0
0
Target
Nor.
Nor.
Nor.
Nor.
Nor.
Low
Low
Nor.
Low
Low
Nor.
Low
Nor.
Low
% Stoic.
To Act.
Burners
119
115
115
115
115
110
107
119
99
79
115
109
113
110
NOV
PPM
(3%, 02
Dry)
370
547
558
587
614
464
398
350
347
312
378
341
397
362
Pounds
Per
106 BTU
0.49
0.73
0.74
0.78
0.82
0.62
0.53
0.46
0.46
0.41
0.50
0.45
0.53
0.48
02
%
3.4
2.8
2.9
2.8
2.8
2.0
1.4
3.4
3.4
3.5
2.9
1.8
2.5
2.1
C02
%
15.0
15.4
15.2
15.3
15.3
15.9
16.2
15.0
14.9
14.6
14.6
15.1
14.2
14.4
CO
PPM
(3% 02,
Dry)
19
24
23
30
25
32
319
21
24
199
24
87
53
376
Temp.
°F
596
672
659
703
724
672
665
587
587
590
633
608
635
632
*
**
***
B mill off - secondary air dampers closed on idle burners.
B mill off - secondary air dampers open on 1/2 of idle burners.
B mill off - secondary air dampers open on all idle burners.
NOTE: Hydrocarbons were measured on each test but
values were negligible except where indicated.
-------
B-l
APPENDIX B
Coal Analyses
Representative coal samples were taken for each major test under
baseline and "low NO " operating conditions. The samples were submitted
to the Exxon Research and Engineering Company's Coal Analysis Laboratory
at Baytown, Texas for analysis. Ultimate analysis determinations, which
were of most importance to the study, were made on all samples as indicated
in the following tables for each boiler tested. Proximate analyses informa-
tion are also tabulated, where available. Ash fusion temperature deter-
minations under reducing and oxidizing conditions and analyses for critical
coal ash elements were obtained on coal samples taken during certain impor-
tant tests in an attempt to shed more light on potential slagging or foul-
ing side effects of "low NO " firing techniques.
x
All coal analyses data, which were used for making various
calculations in this report, are tabulated in Tables 1-10 of Appendix B.
-------
APPENDIX B
TABLE 1
COAL ANALYSES
TENNESSEE VALLEY AUTHORITY
WIDOWS CREEK STATION - UNIT NO. 6
Run No.
1A
10
10-A-l 10-C-l 10-C-3 10-C-5
1-B 26-A-l 26-A-3
Proximate Analysis
Moisture
Ash
Voaltiles
Fixed Carbon
Sulfur
BTU/LB.
Ultimate Analysis
C - % Dry
H - % Dry
S - % Dry
N - % Dry
Cl - % Dry
0 - % Dry
Ash - % Dry
BTU/LB. - % Dry
Ash Fusion Temperature
Reducing
Int.
H=W
H=W/2
Fl.
Oxidizing
Int.
H=W
H=W/2
Fl.
6.3
66.06
4.13
0.82
1.29
5.82
21.88
11,739
2450
2700
2700
2700
2475
2700
2700
2700
5.4
71.11
4.54
0.81
1.40
5.36
16.78
12,106
2350
2600
2625
2680
2400
2700
2700
2700
5.6
8.7
7.2
7.7
8.5
71.22
4.46
0.96
1.39
5.88
16.08
12,689
2460
2675
2700
2700
2500
2700
2700
2700
66.22
4.60
4.04
1.31
7.56
16.28
12,068
1975
2035
2055
2140
2360
2500
2510
2515
69.01
4.97
4.00
1.43
8.39
12.20
12,646
2000
2070
2130
2300
2340
2515
2525
2545
67.27
4.63
3.09
1.37
8.06
15.58
12,168
2085
2160
2190
2250
2450
2535
2560
2570
65.68
4.48
3.70
1.33
7.29
17.53
11,919
2025
2110
2125
2165
2225
2500
2520
2525
5.1
8.8
67.48
4.36
1.36
1.35
6.05
19.38
12,094
2450
2660
2700
2700
2500
2700
2700
2700
66.28
4.55
3.36
1.36
7.58
16.87
12,019
2025
2120
2140
2200
2450
2500
2525
2590
7.5
67.79
46
40
72
6.37
17.27
12,218
2130
2400
2430
2460
2590
2635
2665
2670
-------
APPENDIX B
TABLE 2
COAL ANALYSES
GEORGIA POWER COMPANY
HARLLEE BRANCH STATION - UNIT NO. 3
Run No.
1-A 1-C 1-D 1-E 1-G 1-H 52 52-A 52-B 52-C 52-D 52-E
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Sulfur
BTU/LB.
Ultimate Analysis
7.9 6.31 5.1 5.82 7.86 6.92 7.58 7.4 5.07 5.86 6.98 13.92 7.01
c —
H
S
N
Cl
0
Ash
BTU/LB. -
Ash Fusion
Reducing
Int.
H=W
H=W/2
Fl
Oxidizing
Int.
H=W
H=W/2
Fl.
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
7. Dry
% Dry
Temperature
72.15
4.78
1.12
1.71
8.23
12.02
12,874
2175
2625
2700
2700
2550
2700
2700
2700
73.27
4.89
1.16
1.76
7.63
11.30
13,147
2300
2450
2475
2600
2500
2700
2700
2700
71.69
4.93
1.65
1.71
7.34
12.70
12,972
2140
2400
2415
2450
2375
2660
2675
2685
74.17
5.01
1.27
1.84
7.39
10.32
13,367
2150
2425
2450
2600
2275
2690
2700
2700
73.94
4.89
1.12
1.78
8.97
9.31
13,155
2475
2500
2520
2530
2520
2700
2700
2700
72.53
4.93
1.51
1.81
7.10
12.12
13,108
2250
2450
2470
2500
2615
2656
2685
2700
'5.39
5.06
1.41
1.93
7.09
9.12
i,605
73.96
4.96
1.61
1.87
6.53
11.07
13,309
75.37
5.07
1.08
1.82
7.29
9.44
13,576
73.89
4.97
1.25
1.77
7.18
10.94
13,315
73.34
4.96
1.09
1.77
7.79
11.05
13,185
72.40
4.85
1.24
1.74
7.81
11.96
12,986
71.50
4.77
1.32
1.40
8.26
12.76
12,783
W
1
u>
2400
2500
2515
2570
2525
2700
2700
2700
2200
2400
2450
2475
2420
2640
2670
2690
2350
2450
2465
2550
2575
2700
2700
2700
2325
2480
2525
2600
2595
2700
2700
2700
2330
2490
2510
2540
2600
2700
2700
2700
2270
2475
2500
2530
2700
2700
2700
2700
2360
2600
2630
2695
2700
2700
2700
2700
-------
B-4
APPENDIX B
TABLE 3
GOAL ANA.LYSKS
UTAH POWER AND LIGHT CO.
NAUGHTON STATION, BOILER NO.
Run Number
Date - 1972
Raw Coal Sample
Moisture, %
Tin w> J «w>mvvn f~* -^ •* i-fc J n Vs. -! 1 -S 4-<>v
Hardgrove Gnndability
Pulverized Coal Sample
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Btu/lb
Ultimate Analysis
C, % Dry
H, % Dry
S, % Dry
N, % Dry
Cl, % Dry
0, % Dry
Ash, % Dry
18
9-21
12.23
5.47
39.12
43.18
10,566
70.06
4.89
0.49
1.47
0.01
16.47
6.23
19
9-21
- 23.55
r o /
_> J.4
10.97
5.78
39.57
43.68
10,688
69.86
4.88
0.48
1.57
0.01
16.42
6.49
20
9-21
13.38
6.19
38.23
42.20
10,326
69.37
4.85
0.51
1.58
0.01
16.30
7.15
21
9-21
13.57
6.39
38.04
42.00
10,276
69.19
4.83
0.59
1.53
0.01
16.26
7.39
3
22
9-27
—
14.35
8.80
36.53
40.32
9,866
67.04
4.68
0.55
1.60
0.01
15.76
10.27
23
—
24.41
/ f\ C
49.5
11.55
8.16
38.78
41.51
10,293
67.62
4.71
0.68
1.64
.01
16.11
9.23
25
10-9
22.98
54.9
13.40
6.78
37.75
42.07
10,273
69.14
4.83
0.63
1.65
0.01
15.91
7.83
26
10-10
22.91
51.6
13.99
8.10
36.61
41.30
9,992
67.61
4.75
0.63
1.57
0.01
16.01
9.42
-------
APPENDIX B
TABLE 4
COAL ANALYSES
ARIZONA PUBLIC SERVICE CO.
FOUR CORNERS STATION, BOILER NO.
Run No.
Lab. No.
Date, 1972
Pulverized Coal
12A
1-14B
11-18
621B
1-15A
11-8
1C&1D
1-15A
11-9
1A&6A
1-17A
11-3
19,20,21
1-18A
11-2
1,2,3,4
1-18A
11-5
IE
1-19A
11-14
12B
1-23B
11-21
Ultimate Analysis
c,
H,
s,
N,
Cl,
o,
Ash,
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
IF
1-16B
11-15
Proximate Analysis
Moisture, %
Ash
Volatiles
Fixed Carbon
Btu/lb.
11.71
23.13
31.47
33.69
8,913
12.70
21.35
31.35
34.60
8',947
12.88
21.86
31.02
34.24
8,801
13.97
21.01
30.91
34.11
8,763
14.05
21.18
30.79
33.98
8,787
13.29
20.61
31.42
34.68
8,944
12.91
21.92
30.88
34.29
8,821
13.10
21.12
31.21
34.57
8,915
12.79
21.96
30.68
34.57
8,811
56.95
4.34
0.75
1.23
0.01
10.53
26.19
58.05
4.35
0.79
1.23
—
11.11
24.46
57.51
4.25
0.75
1.31
—
11.10
25.09
58.67
4.26
0.85
1.24
—
11.16
24.42
57.69
4.32
0.80
1.26
—
11.04
24.93
58.43
4.34
0.70
1.29
—
11.47
23.77
57.50
4.30
0.76
1.26
0.01
11.00
25.17
58.15
4.31
0.81
1.24
0.01
11.18
24.30
57.28
4.27
0.67
1.29
0.01
11.30
25.18
I
Ui
-------
B-6
APPENDIX B
TABLE 5
COAL ANALYSES*
GULF POWER COMPANY
Laboratory No
Run No
Date
PROXIMATE ANALYSIS
Moisture
Ash
Volatiles
Fixed Carbon
Sulfur
BRU/Lb .
ULTIMATE ANALYSIS
C - % Dry
H - % Dry
S - % Dry
N - % Dry
Cl- 7. Dry
0 - % Dry
Ash % Dry
BTU/
Lb.% Dry
ASH ELEMENTS
so3
MgO
Si02
A12°3
Fe2°3
CaO
^0
Ti02
P2°5
Total
ASH FUSION TEMPERATURES
Reducing - ID
- H=W
- H=W/2
- Fluid
Oxidizing- ID
- H=W
- H=W/2
- Fluid
CRIST STATION,
M15901
2&3
Dec 6-72
9.24
8.50
36.76
45.5
-
11,855
72.19
5.05
3.32
1.38
-
8.69
9.37
13,060
6.0
0.8
41.9
20.0
24.8
5.9
1.8
1.0
<0.1
102.2
°F
2020
2120
2270
2340
2360
2420
2540
2580
BOILER NO.
M15898
26
Dec 7-72
10.47
12.04
33.06
44.43
_
11,282
69.99
4.81
3.48
1.33
-
6.94
13.45
12,602
9.7
0.7
41.4
14.5
24.6
8.4
1.9
0.9
0.5
102.6
2030
2070
2140
2280
2280
2350
2430
2520
6
M15903
4&5
Dec 8-72
8.13
8.49
37.57
45.81
_
11,920
72.15
5.09
3.62
1.43
-
8.47
9.24
12,974
3.9
0.8
41.7
20.8
27.7
3.4
1.9
1.1
<0.1
101.3
1980
2040
2280
2330
2400
2480
2530
2580
M15691
1,5A,10&26B
Dec 11-12,72
9.6
10.2
-
-
_
11,186
69.23
4.93
4.80
1.33
-
8.43
11.28
12 ,374
0.6
0.6
37.5
20.5
40.6
0.7
1.9
1.0
<0.1
103.4
2000
2040
2080
2130
2530
2570
2610
2650
* Analyses furnished through the courtesy of Foster Wheeler Corporation.
-------
APPENDIX B
TABLE 6
COAL AND PETROLEUM COKE ANALYSES
ALABAMA POWER COMPANY
BARRY STATION, BOILER NO. 4
Run No .
Laboratory No.
Sample Identification*
Sample Date
Raw Coal Sample
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Btu/lb
Ultimate Analysis
C - % Dry
H - % Dry
S - % Dry
N - % Dry
Cl - % Dry
0 - % Dry
Ash - % Dry
% Used
Ash Elements
P205
Si02
Fe203
A12°3
Ti02
CuO
MgO
so3
K20
Na20
Total
Ash Fusion - Reducing
I.D.
H=W
H=1/2W
Fluid
- Oxidizing
I.D.
H=W
H=1/2W
Fluid
1
6076
1-A,B,D,E
1-23-73
7.72
12.11
31.73
48.44
11,877
71.39
4.75
2.73
1.52
0.09
6.40
13.12
80.2
0.37
45.62
19.01
24.06
1.10
2.57
0.89
3.31
2.09
0.31
99.33
2100
2135
2150
2180
2485
2525
2550
2560
2
6077 6078
1-C 2-A,B,D,E
1-23 1-23
6.40 6.99
2.22 11.86
14.67 32.12
76.71 49.03
14,020 12,022
85.11 71.69
4.01 4.77
3.97 2.65
1.20 1.55
0.0
3.34 6.59
2.37 12.75
19.8 80.3
0.38
45.91
16.93
21.91
1.08
4.36
1.09
4.28
2.04
0.03
98.28
—
—
—
—
—
—
—
6
6079 6080
2-C 6-B.D.E
1-23 1-23
5.69 7.25
2.37 10.89
14.76 32.40
77.18 49.46
14,106 12,127
84.99 72.52
4.00 4.83
3.98 2.61
1.08 1.59
—
3.44 6.71
2.51 11.74
19.7 75.6
* Note:
• Letters
• Samples
• Samples
coal and
6081
6-C
1023
5.76
1.93
14.82
77.49
14,163
85.39
4.02
4.03
1.22
—
3.29
2.05
24.4
8
6082
8-B.D.E
1023
6.09
9.95
33.23
50.73
6083
8-C
1023
6.33
2.79
14.59
76.29
12,438 13,943
73.47
4.89
2.68
1.59
—
6.78
10.59
75.8
84.58
3.98
3.81
1.25
—
3.40
2.98
24.2
13
6084
13-A,B,D,E
1-19
8.17
12.76
31.29
47.78
6085
13-C
1-19
8.13
13.14
31.16
47.57
11,714 11,664
70.76
4.71
2.40
1.52
—
6.72
13.89
81.4
70.42
4.69
1.92
1.45
—
7.22
14.30
18.6
13A
6086 6087
13-A,B,D,E 13-C
2-5 2-5-73
2.10 8.09
10.03 9.71
34.78 32.53
53.09 49.67
13,017 12,178
73.75 73.49
4.91 4.89
3.38 3.15
1.43 1.39
—
6.28 6.52
10.25 10.56
77.7 22.3
refer to pulverisers.
marked "A,
marked "C"
petroleum
B, D, E"
are 100%
coal
are petroleum coke or mixtures
coke.
of
-------
APPENDIX B
TABLE 6 (Continued)
COAL AND PETROLEUM COKE ANALYSES
ALABAMA POWER COMPANY
BARRY STATION, BOILER NO. 4
Run No. 20
Laboratory No. 6097
Sample Identification* 20-A,B,D,E
Sample Date 1-22
Conditions
Raw Coal Sample
Proximate Analysis
Moisture 10.38
Ash 9.36
Volatiles 31.76
Fixed Carbon 48.50
Btu/lb 11,890
Ultimate Analysis
C - % Dry 73.59
H - % Dry 4.90
S - % Dry 3.38
N - 7. Dry 1.50
Cl - % Dry
0 - % Dry 6.19
Ash - % Dry 10.44
% Used 76.5
Ash Elements
P205
Si02
Fe203
Ti02
CaO
MgO
S03
K20
Na20
Total
Ash Fusion - Reducing
I.D.
H=W
H-1/2W
Fluid
- Oxidizing
I.D.
H=W
H=1/2W
Fluid
6098
20-C
1-22
6.37
2.55
14.62
76.46
13,974
84.80
4.00
4.04
1.19
—
3.25
2.72
23.5
*
29
6099
29-A,B,D,E
1-19
9.16
13.24
30.71
46.89
11,496
70.19
4.67
2.05
1.51
—
7.00
14.58
81.4
Note:
30 31
6100
29-C
1-19
8.47
10.86
18.83
61.84
11,394
75.74
4.47
2.39
1.47
—
4.07
11.86
18.6
6101
30-A,B,D,E
1-19
7.21
9.08
33.13
50.58
12,401
74.13
4.93
2.58
1.30
—
7.27
9.79
81.2
6102 6103 6104
30-C 31-A,B,D,E 31-C
1-19 1-19 1-19
8.03 8.76 6.98
11.20 12.71 9.43
18.86 31.08 19.51
61.91 47.45 64.08
12,410 11,634 12,843
75.46 70.22 77.22
4.45 4.71 4.55
2.45 2.06 2.18
1.51 1.49 1.34
—
3.95 7.09 4.57
12.18 13.93 10.14
18.8 81.3 18.7
• Letters refer to pulverizers
• Samples marked "A, B,
D, E" are
100% coal
• Samples marked "C" are petroleum coke or
mixtures of coal and petroleum coke.
42A
6106
42A-B.D.E
2-22
10.05
6.85
36.76
46.34
11,929
73.13
5.22
3.18
1.44
.061
9.35
7.62
69.3
.23
45.30
23.95
22.58
1.17
1.50
0.60
1.67
1.95
0.14
99.09
2070
2100
2120
2140
2535
2560
2570
2600
42B
6-107 6108 6109
42A-C 42B-B,D,E, 42B-C
2-22 2-23 2-23
6.74 10.01 6.18
0.11 6.99 0.11
12.03 36.72 12.10
81.12 46.28 81.61
14,382 11,915 14,468
86.42 73.01 86.43
3.86 5.21 3.86
4.52 3.29 4.59
1.13 1.38 1.14
—
4.07 9.34 3.87 ?
0.12 7.77 .114 °°
30.7 69.0 31.0
.39
26.15
20.15
14.29
1.42
3.69
0.98
3.25
2.31
0.49
73.18
—
—
—
—
—
—
—
—
-------
APPENDIX B
Run No.
Laboratory No.
Sample Identification*
Sample Date
Conditions
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Btu/Lb
Ultimate Analysis
C
H
S
N
Cl
0
Ash
7, Used
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
Dry
Ash Elements
P205
Si02
Fe203
A1203
Ti02
CuO
S03
K20
Na20
Total
Ash Fusion - Reducing
I.D.
H-W
H-1/2W
Fluid
- Oxidizing
I.D.
H=W
H-1/2W
Fluid
TABLE 6 (Continued)
COAL AND PETROLEUM COKE ANALYSES
ALABAMA POWER COMPANY
BARRY STATION, BOILER NO. 4
6088
17-A,B,D
1-22
10.33
10.17
31.46
48.04
11,778
72.85
4.85
3.63
1.48
—
5.85
11.34
79.7
17
6089
,E 17-C
1-22
6.42
2.47
14.63
76.48
13,979
84.87
4.00
3.98
1.20
—
3.31
2.64
20.3
* Note:
• Letters
• Samples
• Samples
mixtures
18
6090
19 19A
6091
18-B.D.E 19-B,D,E
1-22
10.58
8.17
32.16
49.09
12,037
74.66
4.97
3.56
1.52
—
6.15
9.14
100.0
re fer to
marked "A
marked "C
of coal
1-22
8.42
9.41
32.52
49.65
12,173
73.73
4.91
3.51
1.50
—
6.08
10.28
77.0
pulverizers
, B, D, E"
6092 6093
19-C 19A-B,D,E
1-22 2-13
6.40 8.05
2.42 11.33
14.64 33.37
76.54 47.25
13,989 11,665
84.92 70.32
4.00 4.88
4.14 2.90
1.17 1.40
—
3.18 8.18
2.59 12.32
23 69.8
are 1007= coal
6094
19A-C
2-13
9.42
9.21
19.00
62.37
12,502
77.19
4.55
3.16
1.32
—
3.61
10.17
30.2
" are petroleum coke or
and petroleum coke.
19B
6095
19B-B.D.E
2-14
9.84
7.67
34.14
48.35
11,936
73.38
5.09
3.29
1.44
0.073
8.23
8.50
69.6
0.40
44.50
22.21
22.49
1.17
1.99
0.88
2.17
2.38
0.32
98.50
2050
2100
2115
2130
2450
2500
2525
2535
6096
19B-C
2-14
6.93
11.51
19.04
62.52
12,531
75.30
4.44
2.81
1.41
—
3.67
12.37
30.4
.81
48.08
13.85
27.47
1.45
2.00
1.10
2.09
2.39
0.28
99.52
—
—
—
__
—
—
—
-------
B-10
APPENDIX B
TABLE 7
COAL ANALYSES
TAMPA
ELECTRIC
CO.
BIG BEND STATION, BOILER NO.
Laboratory No.
Run No .
Date
Time
Proximate Analysis
Moisture - %
Ash - %
Volatiles - %
Fixed C - %
Sulfur - %
BTU/lb - %
Ultimate Analysis
C - % Dry
H - % Dry
S - % Dry
N - % Dry
Cl - % Dry
0 - % Dry
Ash - % Dry
BTU/lb - % Dry
Ash Elements
P205
Si02
Fe203
A1203
Ti02
CaO
MgO
S03
K20
Na20
Total
Ash Fusion Temperatures °F
Reducing - I.D.
- H=W
- H=W/2
- Fluid
Oxidizing - I.D.
- H=W
- H=W/2
- Fluid
96135
4
3-5-73
1730
10.63
13.13
34.16
42.08
3.48
10,682
66.49
4.71
3.89
1.26
.03
8.96
14.69
11,952
96136
2
3-6-73
0930
11.66
14.07
32.60
42.21
3.19
10,585
65.75
4.65
3.61
1.39
0.10
9.21
15.93
11,982
0.31
44.86
22.90
17.83
.80
4.87
0.86
6.16
2.11
0.21
100.89
2000
2015
2035
2045
2340
2370
2450
2475
96137
3
3-6-73
1445
10.75
13.78
34.54
40.93
3.44
19,576
66.02
4.59
3.86
1.41
0.10
8.68
15.44
11,849
0.26
45.21
20.28
17.66
0.87
4.91
0.83
6.85
2.00
0.22
99.10
2000
2040
2050
2075
2320
2380
2450
2470
2
96138
10
3-12-73
1230
10.85
13.52
33.88
41.75
3.66
10,780
66.86
4.71
4.11
1.39
7.77
15.16
12,092
96139
20
3-7-73
0830
10.98
13.85
33.68
41.75
3.72
10,505
65.86
4.56
4.18
1.38
—
8.47
15.55
11,801
-------
B-ll
APPENDIX B
TABLE 8
COAL
ANALYSES
CENTRAL ILLINOIS LIGHT COMPANY
E. D. EDWARDS STATION, BOILER NO. 2
Laboratory Ho.
Run No.
Mills
Date
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Sulfur
BTU/LB.
Hardgrove Grind.
Ultimate Analysis
C - 7. Dry
H - "1, Dry
S - % Dry
N - 7. Dry
Cl - % Dry
0 - % Dry
Ash - '/, Dry
BTU/LB. - % Dry
96168
1
ABCD
6-11-73
15.97
9.94
32.81
41.28
3.07
10,433
68.96
4.96
3.66
1.25
0.02
9.32
11.829
12,416
96169
2
ABCD
6-11-73
15.65
9.38
33.20
41.77
2.90
10,557
69.51
5.00
3.44
1.27
0.02
9.64
11.12
12,516
96170
3
ABCD
6-12-73
16.77
9.83
32.50
40.90
2.94
10,335
68.97
4.97
3.53
1.25
0.02
9.45
11.81
12,417
96171
4
ABCD
6-12-73
16.02
9.34
31.91
42.73
3.00
10,530
54.5
69.66
4.99
3.57
1.26
0.02
9.38
11.12
12,539
96172
5
ABCD
6-12-73
17.07
10.61
32.02
40.29
2.66
10,183
68.21
4.91
3.21
1.20
0.02
9.66
12.79
12,279
96173
6
ABCD
6-12-73
17.26
14.07
30.41
38.26
2.56
10,170
64.91
4.67
3.09
1.19
0.02
9.11
17.01
12,292
96174
7
ABC
6-13-73
17.40
9.68
32.29
40.63
2.69
10,268
69.04
4.97
3.26
1.24
0.02
9.75
11.72
12,431
96175
8
ABC
6-13-73
18.07
9.53
32.06
40.34
2.80
10,195
69.11
4.98
3.41
1.25
0.02
9.60
11.63
12,444
96176
23
ABCD
6-13-73
15.94
9.33
33.28
46.45
2.88
10,576
54.5
69.851
4.993
3.429
1.236
0.022
9.37
11.10
12,582
96177
24
ABCD
6-13-73
16.04
8.89
33.24
41.83
2,98
10,571
69.93
5.03
3.55
1.25
0.02
9.63
10.59
12,591
96178
13
ABC
6-13-73
17.37
9.27
32.48
40.88
2.80
10,330
69.43
5.00
3.39
1.24
0.02
9.70
11.22
12,502
96179
18
ABC
6-13-73
17.65
8.66
32.63
41.06
2.46
10,376
69.98
5.04
2.99
1.25
0.02
10.20
10.52
12,600
96180
14
ABC
6-14-73
17.12
9.90
32.32
40.66
2.80
10,276
68.87
4.96
3.37
1.18
0.02
9.66
11.94
12,399
96181
10
ABC
6-14-73
16.55
9.22
32.87
41.36
2.82
19,452
69.57
5.01
3.38
1.26
0.02
9.71
11.05
12,525
96182
11
ABC
6-14-73
16.29
9.55
32.84
41.32
2.91
10,442
69.29
4.99
3.47
1.26
0.02
9.56
11.41
12,474
96183
12
ABC
6-14-73
15.40
9.59
34.17
40.84
3.10
10,488
55.9
68.86
5.01
3.66
1.32
0.03
9.78
11.34
12,397
96184
9
ABC
6-14-73
15.37
9.37
33.33
41.93
2.93
10,597
69.55
5.01
3.47
1.28
0.02
9.60
11.07
12,522
96185
16
ABCD
6-15-73
14.89
9.17
33.63
42.32
30.1
10,695
69.79
5.02
3.53
1.23
0.02
9.64
10.77
12,565
96186
20
ABC
6-15-73
15.27
9.29
33.40
42.04
3.05
10,623
69.64
5.01
3.60
1.23
0.02
9.54
10.96
12,537
96187
1A
ABCD
6-15-73
13.72
8.24
34.56
43.48
1.97
10,989
70.78
5.10
2.29
1.42
0.02
10.89
9.50
12,670
-------
APPENDIX B
TABLE 9
COAL ANALYSES
BASIN ELECTRIC POWER COOPERATIVE
STANTON, NORTH DAKOTA, BOILER NO. 1
Base
Laboratory No.
Run No.
Source
Date
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Sulfur
Btu/Lb
Hardgrove Grind.
Ultimate Analysis
C - % Dry
H - % Dry
S - % Dry
N - % Dry
Cl - % Dry
0 - % Dry
Ash - % Dry
Btu/Lb - Dry
Ash Elements
P2<>5
Si02
Fe203
A1203
Ti02
CaO
MgO
S03
K20
Na20
Total
Ash Fusion Temperatures
Reducing - I.D.
- H-W
- H=W/2
- Fluid
Oxidizing - I.D.
- H=W
- H=W/2
- Fluid
96189
1
Storage
7/6/73
36.44
7.61
28.01
27.70
0.41
6704
62.81
4.27
0.64
1.04
0.08
19.17
11.97
10548
96190
1A
Mine
7/10/73
38.71
5.90
27.02
28.36
0.53
6643
29.5
64.44
4.43
0.87
1.08
0.07
19.55
9.63
10838
0.08
23.81
9.72
9.69
0.51
19.00
4.10
22.35
0.68
7.90
97.83
2220
2230
2240
2250
2250
2270
2275
2280
96191
3 & 4
Storage
7/9/73
34.42
6.16
29.75
29.41
0.43
7120
64.66
4.39
0.66
1.03
0.08
19.73
9.39
10858
96192
4A & B
—
7/11/73
38.36
5.55
29.19
26.91
0.46
6710
27.3
65.03
4.39
0.47
1.09
0.08
19.76
9.00
10886
0.06
20.79
9.32
9.13
0.47
20.44
4.69
23.58
0.48
7.68
96.63
1990
2120
2150
2240
2200
2275
2280
2290
96193
4C
Mine
7/12/73
37.59
6.30
27.72
28.39
0.34
6728
27.3
64.11
4.35
0.55
1.12
0.08
19.78
10.09
10781
0.07
28.63
8.17
10.07
0.52
18.70
4.40
21.10
0.74
5.20
97.61
2090
2140
2145
2150
2190
2210
2220
2225
Low NOx
96194
5
Storage
7/9/73
36.94
5.29
28.93
28.60
0.35
6922
65.37
4.44
0.55
1.08
0.08
19.95
8.39
10977
96195
6
Mine
7/10/73
37.95
6.03
28.05
27.73
0.43
6712
64.42
4.38
0.69
1.05
0.08
19.66
9.72
10817
96916
7
Mine
7/10/73
39.21
5.92
27.47
27.16
0.38
6575
64.42
4.38
0.62
1.05
0.08
19.66
9.73
10816
96197
9
Mine
7/10/73
38.11
8.54
26.71
26.41
1.11
6392
61.51
4.18
1.37
1.11
0.08
18.77
13.80
10328
96198
11
Mine
7/10/73
37.66
6.11
28.15
27.83
0.46
6737
64.36
4.37
0.74
1.07
0.08
19.64
9.81
10807
-------
APPENDIX B
TABLE 10
COAL ANALYSES
PACIFIC POWER AND LIGHT CO., GLEN ROCK, WYOMING
DAVE JOHNSTON STATION
Laboratory No.
Run No.
Boiler No.
Date
Proximate Analysis
Moisture
Ash
Volatiles
Fixed Carbon
Sulfur
Btu/Lb
Hardgrove Grind.
Ultimate Analysis
C
H
S
N
Cl
0
Ash
Btu/Lb -
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
% Dry
Ash Elements
P205
Si02
Fe203
A1203
TiO
CaO
MgO
S03
K20
Na20
Total
Aah Fusion Temperatures
Reducing
Oxidizing
- I.D.
- H=W
- H=W/2
- Fluid
- I.D.
- H=W
- H=W/2
- Fluid
96203 96204 96205 96206 96207 96208 96209 96210 96211 96212 96213 96214 96215
3 4 1 2 5 6 7 8 10 13 16 24
2222222222244
7/27/73 7/27/72 7/30/73 7/30/73 7/30/73 7/30/73 7/31/73 7/31/73 7/31/73 8/1/73 8/1/73 8/8/73 8/8/73
26.05
13.80
30.67
29.48
0.51
7334
58.41
4.23
0.69
0.77
0.05
17.38
18.66
9918
27.25
11.31
31.33
30.11
0.55
7491
60.65
4.39
0.76
0.79
0.05
18.05
15.54
10298
28.86
7.55
32.42
31.17
0.45
7754
64.19
4.65
0.63
0.83
0.05
19.10
10.61
10899
28.27
7.07
32.97
31.69
0.46
7884
28.7
64.73
4.69
0.64
0.82
0.05
19.26
9.86
10991
0.54
30.56
4.99
15.21
1.11
26.12
3.29
12.37
0.49
0.55
95.24
2125
2145
2150
2155
2170
2190
2200
2210
28.21
7.71
32.67
31.41
0.48
7813
64.01
4.64
0.66
0.82
0.05
19.07
10.74
10883
28.26
7.63
32.69
31.42
0.53
7817
64.17
4.65
0.74
0.86
0.05
19.10
10.64
10896
28.58
7.77
32.46
31.19
0.46
7761
64.00
4.63
0.64
0.83
0.05
19.04
10.88
10866
28.85
7.31
32.55
31.29
0.49
7784
64.44
4.67
0.69
0.81
0.05
19.18
10.27
10941
29.31
7.22
32.36
31.11
0.56
7739
64.47
4.67
0.79
0.83
0.05
19.19
10.22
10947
29.28
6.43
32.78
31.51
0.49
7839
65.28
4.73
0.69
0.81
0.05
19.43
9.09
11085
27.54
7.58
33.08
31.80
0.56
7911
64.30
4.66
0.77
0.84
0.05
19.13
10.46
10918
16.51
13.67
35.55
34.26
0.63
8464
59.36
4.33
0.75
0.75
0.06
18.44
16.38
10138
0.31
42.91
4.24
18.77
0.97
15.67
2.48
10.01
1.09
0.47
96.93
2190
2250
2270
2300
2335
2375
2380
2390
15.32
16.29
34.82
33.56
0.57
8291
57.33
4.18
0.68
0.76
0.05
17.81
19.24
9791
60
I
-------
C-l
APPENDIX C
CROSS SECTION DRAWINGS OF TYPICAL UTILITY BOILERS
Typical utility boiler designs representative of the types of
boilers tested in this program are shown in the cross sectional drawings
in Figures 1 through 6 of Appendix C. Typical front wall and horizontally
opposed fired boilers are shown in Figures 1, 2 and 3, respectively, a
tangentially fired boiler is shown in Figure 4, and Figures 5 and 6 are
typical of turbo furnace and cyclone fired units.
-------
C-2
APPENDIX C
FIGURE 1
TYPICAL FRONT WALL FIRED BOILER
/ \ / LY ASM I // ff\ I /S I -r r- t I \ gTFTU^^Bp
/:.. V^^°" | LJI^-^f^LkAl-.^ _jj--r^-r,5M Llny/C^ I.B
^^rJ^'Kv-^.v v- "'^ >V;. "*-'• :.'s:5fe'" < fe5>''-^^P?r.* *-:'-^ •• '-:::-^\
^"'•'*: -^
-27'-0"-
-32'-0"-
-44'-0"-
-32'-0"-
-30'-0"-
DRAWING FURNISHED THROUGH THE COURTESY OF
THE BABCOCK AND WILCOX COMPANY
-------
C-3
APPENDIX C
FIGURE 2
TYPICAL FRONT WALL FIRED BOILER
EL. l724'-6"
£L. l708'-6"
eo'i.o. J_ SPRAT CONTROL HEADER
^J --B „=.! - El L
HEATER OUTLET
TER
DRAWING FURNISHED THROUGH THE COURTESY OF
THE FOSTER WHEELER CORPORATION
-------
C-4
APPENDIX C
FIGURE 3
TYPICAL HORIZONTALLY OPPOSED FIRED BOILER
223-0"
DRAWING FURNISHED THROUGH THE COURTESY OF
THE BABCOCK AND WILCOX COMPANY
-------
C-5
APPENDIX C
FIGURE 4
TYPICAL TANGENTIALLY FIRED BOILER
DRAWING FURNISHED THROUGH THE COURTESY OF
COMBUSTION ENGINEERING, INC.
-------
C-6
APPENDIX C
FIGURE 5
TYPICAL TURBO FURNACE FIRED BOILER
DRAWING FURNISHED THROUGH THE COURTESY
OF THE RILEY STOKER CORPORATION
-------
C-7
APPENDIX C
FIGURE 6
TYPICAL CYCLONE FIRED BOILER
ATTEMPERATOR
I!
IJ, PRIMARY SUPERHEATER
SECONDARY SUPERHEATER
INLET
ECONOMIZER
OUTLET HEADER
- ECONOMIZER
>— ECONOMIZER
INLET HEADER
DRAWING FURNISHED THROUGH THE COURTESY
OF THE BABCOCK & WILCOX COMPANY
-------
D-l
APPENDIX D
COMMENTS FROM BOILER MANUFACTURERS
At the request of the EPA Project Officer, the boiler
manufacturers have reviewed this report. Written comments were
received from Foster Wheeler Corporation and Riley Stoker Corporation
which are included in Appendix D. These comments, plus verbal comments
received from the Bab cock and Wilcox Company, have been taken into
account in revising the Final Report. Combustion Engineering, Inc.
accepted the report as written.
The Riley Stoker Corporation in their comments, item 2,
suggest that the correlation of NOX emissions against megawatts per
equivalent furnace firing wall should be changed to NOX emissions
versus boiler load in pounds of steam per hour. This is a valid comment
but the suggested adjustment is within the limits of error of the current
relationship. More data is needed in order to add this refinement. Riley
also points out that the correlation does not take into account differences
in fuel nitrogen content in the fuels fired. The authors agree that fuel
nitrogen content is important. However, the factors influencing the
quantitative conversion of fuel nitrogen to NOX emissions in coal fired
utility boilers have not yet been established. Therefore, a correlation
of NOX emissions with fuel nitrogen content is not yet possible. As more
data are developed, the refinements in the correlations, as pointed out
by Riley Stoker Corporation to be desirable, will be possible.
The authors of the report wish to thank the reviewers for their
very constructive comments.
-------
D-2
APPENDIX D
COMMENTS
TO
FINAL REPORT
FOR
EPA CONTRACT NO. 68-02-02227
FIELD TESTING: APPLICATION OF COMBUSTION MODIFICATIONS
TO CONTROL NOX EMISSIONS FOR LARGE UTILITY BOILERS
FOSTER WHEELER CORPORATION
110 SOUTH OKANGK AVKNUK. LIVINGSTON. N. .1.
Prepared by:
R. E. Sommerlad, Manager
Development Contract Operations Dept.
Research Division
-------
D-3
INTRODUCTION
Foster Wheeler Corporation and its client, Gulf Power Company, were
pleased to participate with the Environmental Protection Agency and its
contractor, Esso Research and Engineering Company, in a program entitled
"Field Testing: Application of Combustion Modifications to Control NOV
X.
Emissions for Large Utility Boilers". The purpose of this appendix is to
relate the efforts by the various participants in this program and to
correlate the results found with similar test programs by Foster Wheeler.
TEST PROGRAM
The program was conducted as described in Sections 4.1.1-4.1.3 and
6.1.1.1.4 of the report and included an agreement among the participants.
The test program included specific tests requested by FW as well as those
requested by ERE. New test connections were installed by Gulf. ERE
and FW test crews arrived in early December and data were taken through
Dec. 14, 1972. Due to anticipated load demands and ERE vacation schedules
the test crews re-assembled in January 1973 to renew testing. During the
interim period FW Service Engineers re-aligned registers and pulverizers to
attempt to correct side-to-side unbalances as indicated by the flue gas
composition. The January period also proved fruitless due to operating
demands. All parties had previously agreed that load demand would have
the highest priority. As might be expected this period of time coincided
with unseasonable cold weather requiring peak power almost constantly. In
order to keep other commitments ERE had to go on to other plants. ERE
returned in March for two days. FW resident service staff assisted but
FW test crews had been committed to other assignments.
-------
D-4
PERFORMANCE TESTS
In addition to the resident start-up crew FW provided a performance
test crew comprising five engineers and the district service manager.
Complete performance test data were obtained for five runs and included,
complete control data*, tube metal temperatures, fan and pulverizer power
input*, local steam and water pressures and temperatures, local air and gas
temperatures and pressures*, atmospheric ambient conditions, flue gas com-
position from an array of multiple points, air register and damper positions*,
ash coverage diagrams, and coal, bottom ash and fly ash samples for chemical
analyses. Partial sets of data* were obtained during the eight runs. Two
runs were attempted but then aborted due to lack of stabilization time. FW
was concerned the firing unbalance from side-to-side which was evident by
local 02, NOX and CO data as measured. This concern was later shown by
chemical analyses of bottom ash and fly ash which averaged 10.8 and 24.8%
combustible.
As mentioned previously FW spent considerable time adjusting firing
equipment in late December with the hope that the December tests could be
repeated with more meaningful results. FW had run performance tests
previously on this unit and NOX tests on an identical unit and therefore
could anticipate the results. Unfortunately the results of these endeavors
were not realized in January. During ERE's tests in March the results of
the above endeavors were apparent by the consistency of 02 readings by ERE
as shown in Table 4, Appendix A. However, the NOX data appear to confirm a
*Partial set includes items from complete set marked with asterisks.
-------
D-5
suspicion FW had formulated during the December tests as described below.
GASEOUS EMISSION TESTS
In addition to the FW test crews mentioned earlier, FW also provided
an emission test crew comprising five engineers and technicians. This in-
cluded FW's Mobile Pollution Monitoring Laboratory which housed continuous
analyzers for 02, NOX, and S02. FW also brought in a trailer, the apparatus
to conduct wet chemical analyses and specified by EPA in the Test Methods
for the Standards of Performance. FW probes were installed alongside ERE
probes. The results of these efforts indicated that emission measuring by
FW's continuous analyzers were the same as ERE's analyzers and in addition
were confirmed by the EPA wet chemical procedures. Members of the emission
test crew also aided ERE in particulate testing.
DISCUSSION OF RESULTS
As indicated previously FW has hopes of participating in this program
to achieve meaningful results during the short test-period runs as had
been achieved by FW on an identical unit. For this reason both performance
and emission test crews were committed to this test program. It was also
anticipated that FW would oversee the 1-3 day sustained "low NOX" run and
the 300-hr sustained "low NOX" and normal operation runs. Due to the un-
expected results of the short test-period and the unavailability of the unit
for re-testing, FW felt the performance test results were not indicative of
good commercial operation and declined to submit same in detail.
On an identical unit FW data were the same as the ERE data for "Low NOX
I", S3 (Burners 2 & 3 on Air only). However for "Low NOX II, 34 (Burners 1,
2, 3 & 4 on Air only) and S6 (Burners 5, 6, 7 & 8 on Air only) the NOX
-------
D-6
reduction as % Baseline (20% Excess Air) NC) was 33.3 where the % Stoichio-
A
metric Air to Active Burners calculated by FW was 88.0 which is in agreement
with ERE's analysis as shown in Figure 2-4.
During the December tests there was some confusion about register
settings and rotation on three of the burners on the "A" side (Burner No. 3,
4 and 7). Prior to the test program these burner-register assemblies had
been damaged and had been replaced with three assemblies from Unit No. 7
under construction at the time. The new assemblies were similar to the old
assemblies and were fitted quite easily. However, the new assemblies had
a reversible register assembly. To reverse the assembly is normally a shop
setting. These registers had to be rotated in the field requiring that
the motor drives be reversed, hence the confusion. Morever, the number of
register blades and the shape of each individual blade is different. Even
though all assemblies were realigned in late December 1972 resulting in a
better side-to-side Q£ balance as observed by ERE in March 1973, it is felt
that the individual air flow rate and possibly the flow characteristics
of the new assembly are different than the old assembly and effect swirl
and firing characteristics. It is felt by some that the NOX formation occurs
within 1 or 2 feet of the throat and this could serve to explain the high
NOY on the "A" side.
A.
-------
D-7
RILEY
POST OFFICE BOX 547
WORCESTER, MASSACHUSETTS O1613
STEAM GENERATING
AND FUEL BURNING
EQUIPMENT
"Field Testing - Application of Combustion Modifications to
Control NOX Emissions from Large Utility Boilers"
by W. Bartok, A.R. Crawford, E.H. Manny, L. Berko-
witz, and R.E. Hall
Review:
Speaking for those of us at Riley who had the privi-
lege of working with the Esso "Tigers" test crew during the
planning and execution of their test program, the writer is
pleased to have the opportunity to commend these people for
their excellent work. The subject report illuminates Esso's
experience in reducing nitrogen oxides (NOX) emissions from
coal fired utility boilers.
Our comments and criticisms of this report are few.
It is perhaps the most accurate and fully documented study
of two-staged combustion yet to be published. It was grati-
fying to us that the results of this study corroborate the
results of our own test program which investigated the two-
staged combustion of coal. We also found that there is a
direct relationship between the air/fuel ratio at the fuel-
rich burners and the reduction of NOY emissions from all
J\.
utility boilers. Our own data, when plotted against % of
stoichiometric air to active burners, fit right on top of
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D-8
the data In Figure 2-4 of this report. We also liked the
way Esso addressed iteslf to the potential operating problems
involved with combustion modification. Their corrosion probe
results, although not conclusive, do indicate that the tube
wastage during two-staged combustion may be an overrated fear.
The following are our criticisms of the report:
1. On page 99, where the report describes the test
conditions at Tampa Electric's Big Bend No. 2 unit,
we would like to make a few clarifications. At the
time of the test, the unit was limited to 375 M W
due to superheater slagging (from an isolated ship-
ment of troublesome coal) and a steam temperature
problem which has been corrected after an extensive
research program. This unit has been running for
quite some time at a load of 3,000,000 Ib/HR of
steam (after all, a boiler produces steam, not
megawatts) which is above the maximum continuous
rating of 2,856,000 Ib/HR. However, the unit
still has not exceeded 410-420 M W at this steam
flow due to problems inherent in the turbine.
2. The above point brings up one of the weaknesses
of Esso's method of correlating NO emissions
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with the quantity "M ¥ per equivalent furnace
firing wall." This correlation does not consider
the efficiency of the turbine which is completely
unrelated to boiler operation. Thus units such
as Big Bend 2, whose turbines are less efficient,
are unduly penalized in the correlation.
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The other main weakness of the correlation is the
fact that differences in fuel nitrogen content are
ignored. In this study, the chemically "bound nitro-
gen ranged from 0.75$ at Leland Olds to 1.93$ at
Harllee Branch. Certainly, M W per firing wall,
which is proportional to bulk flame temperature,
does not reflect fuel nitrogen conversion which
has been shown to be essentially independent of
temperature. We would suggest a correlation based
on steam flow or heat input per firing wall, with
a correction factor to "normalize" the data to a
common fuel nitrogen content (say, 1.3$).
3. On page 65, the report indicates that closing
the air registers to the fuel-rich burners maxi-
mized NOY reductions because the minimum allowable
J\.
excess air was reduced. We feel that it is just as
important to note that in addition, a lower $ of
stoichiometric air is introduced to the fuel rich
burners when the air registers are pinched to 20-30$
open because the flow restriction upsets the balance
of air flow to each burner. Therefore a boiler operating at
a .9 stoichiometric ratio with all registers at 50$
open may actually reach a .85 stoichiometric ratio
when the registers are closed to 20$ open.
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D-10
4. In several instances the report states that
baseline NO emissions level out at low loads
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because a larger percentage of the total NOY is
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produced from the fuel nitrogen. This is certainly
true, but no mention is made of the amount of ex-
cess air, which may double at low loads. Increased
oxygen in the flame increases both thermal NO,, for-
J\.
mation and fuel nitrogen conversion in diffusion
flames (in premixed flames, thermal NOX decreases
with high excess air due to overall cooling of the
flame). In cases where fuel NOX is dominant at
low loads, we have observed total NOX emissions to
increase as load decreases.
In conclusion, we are glad to see that this
final report does not mark the end of Esso's involvement
with EPA and NOX testing. There certainly is much more to
learn by extended operation of utility boilers under low
NOX conditions. Such a program as outlined in section 7 of
this report would greatly benefit the utilities, the boiler
manufacturers, and, most of all, the environment.
A. H. Rawdon - Director of R & D
S.A. Johnson - Chemical Research
Engineer
Riley Stoker Corporation
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To Convert From
Btu
Btu/pound
Cubic feet/day
Feet
Gallons/minute
Inches
Pounds
Pounds/Btu
Btu/Pound
Pounds/hour
Pounds/square inch
Tons
Tons/Day
APPENDIX E
CONVERSION FACTORS
ENGLISH TO METRIC UNITS
To
Calories, kg
Calories, kg/kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie, kg
Kcal/Kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.55552
0.028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.555
0.45359
0.070307
0.90719
0.90719
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F-l
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-650/2-74-066
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Field Testing: Application of Combustion Modifications
to Control NOx Emissions from Utility Boilers
5. REPORT DATE
June 1974
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
A.R. Crawford, E.H. Manny, and W. Bartok
GRU.1DJAF.74
9. PERFORMING ORG '\NIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
Government Research Laboratory
P.O. Box 8, Linden, New Jersey 07036
10. PROGRAM ELEMENT NO.
1AB014; ROAP 21ADG-AL
11. CONTRACT/GRANT NO.
68-02-0227
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
The report describes field studies on utility boilers to develop NOx and
other pollutant control technology by modifying combustion operating conditions.
Tests were made on 12 pulverized-coal-fired boilers , including wall, tangentially,
and turbo-furnace fired units representative of utility boiler manufacturers' current
design practices. Six oil-fired boilers, converted from coal-firing, were also tested
with combustion modifications for NOx control. Particulate emissions and acceler-
ated furnace corrosion rates were also determined in some cases for coal-fired
boilers. The tests consisted of three phases: short-term runs to define the optimum
low NOx conditions within the constraints imposed by boiler operability and safety;
boiler operation for 2 days (under low NOx conditions defined in the first phase) to
check operability on a sustained basis; and operation of several boilers under base-
line and low NOx conditions for about 300 hours (with air-cooled carbon steel cor-
rosion coupons exposed near the furnace water walls) to obtain relative corrosion
tendencies at accelerated rates. Analysis indicated that combustion modifications,
chiefly low excess air firing coupled with staged burner patterns , can reduce NOx
emissions from the tested coal-fired boilers by 25-60%, depending on the unit and
its flexibility. NOx.emissions were, successfully correlated for normal and modified
firing condmons with the percent stoicniometnc air supplied to the burners.
16. ABSTRACT
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Gioup
Air Pollution
Combustion
Nitrogen Oxides
Boilers
Emission
Coal
Fuel Oil
Fouling
Corrosion
Burners
Slagging
Air Heaters
Hydrocarbons
Air Pollution Control
Stationary Sources
Combustion Modification
Utility Boilers
Excess Air
Staged Firing
Emission Factors
13B
21B
07B
13A, 13H
21D, 07C
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report!
Unclassified
21. NO. OF PAGES
209
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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