EPA-650/2-74-002-B
February 1975
Environmental Protection Technology Series
EFFECTS OF DESIGN AND OPERATING
VARIABLES ON NOX
FROM COAL-FIRED FURNACES-
PHASE II
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Develoj
mental Protection Agency, have been grouped into seri
categories were established to facilitate further develo
tion of environmental technology. Elimination of tradil
consciously planned to foster technology transfer and i
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
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EPA-650/2-74-002-b
EFFECTS OF DESIGN AND OPERATING
VARIABLES ON NOX
FROM COAL-FIRED FURNACES
PHASE II
-
by
W. Joseph Armcnto
Babcock and VVilcox Company
Research and Development Division
Alliance, Ohio 44601
Contract No. 68-02-0634
ROAP No. 21ADG-041
Program Element No. 1AB014
EPA Project Officer: David G. Lachapelle
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
February 1975
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ABSTRACT
The purpose of this contract was to investigate various combus-
modification techniques for control
cation on pulverized coal-fired boilers.
tion modification techniques for control of NO which might find appli-
The laboratory tests were made on a single burner coal-fired
test unit. The techniques studied were: (1) excess air, (2) air preheat,
(3) firing rate, (4) flue gas recirculation, (5) staged combustion,
(6) quench, and (7) swirl. Natural gas, No. 6 oil and two coals were
used in the tests.
For coal combustion, reductions of up to 65% in NO emission
levels were observed using staged combustion. Reduction of excess air
from 30 to 0% yielded similar results. Flue gas recirculation reduced
NO by a small amount, but apparently only thermally formed NO is reduced.
Fuel nitrogen conversion increases with increasing excess air.
At substoichiometric conditions, the final precursors for NO formation
from either fuel bound nitrogen conversion or thermal atmospheric
fixation are identical.
For existing units, control of excess air appears to be the
simplest method for NO reduction. In addition, when possible staged
J\
combustion on existing units could be used to achieve further NO
^
reductions.
For new units, staged combustion combined with low excess air
firing appears to be the most promising method of NO control.
J\
This report was submitted in fulfillment of Contract No. 68-02-
0634 by The Babcock & Wilcox Company under the sponsorship of the
Environmental Protection Agency. Work was completed as of October 31,
1974.
IT i
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ACKNOWLEDGEMENTS
The results of this phase of the contract are due to the efforts
of others as well at the Alliance Research Center. In particular, W.
L. Sage and C. L. Wagoner were responsible for administrative help; E.
D. Scott and F. M. Holsopple were responsible for furnace operation;
and E. W. Stoffer, J. M. Kibler, and F. M. Holsopple were responsible
for instrumentation.
F. M. Holsopple also contributed to two Appendices and Figures
in Section II.
B&W makes no warranty or representation, expressed or implied:
with respect to the accuracy, completeness, or usefulness of the
information contained in this report
that the use of any information, apparatus, method, or process
disclosed in this report may not infringe privately owned rights.
B&W assumes no liability with respect to the use of, or for damages
resulting from the use of:
any information, apparatus, method, or process disclosed in
this report
experimental apparatus furnished with this report.
IV
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TABLE OF CONTENTS
SYMBOLS AND ABBREVIATIONS - xi
I. INTRODUCTION - - 1
A. Objectives of the Contract 1
B. Phase I 1
C. Phase II .2
D. Background and Description of Work T 2
E. Significant Results of the Phase II Work 3
II. APPARATUS - 5
A. Description of the Basic Combustion Test Unit 5
B. Furnace and Burner Detail 14
C. Instrumentation and Sampling 16
III. PROCEDURES - 19
IV. MEASUREMENTS 21
A. Variables Studied 21
B. Variable Testing 21
C. Range of Variables - - - 22
D. Measurements Taken 22
V. PHASE II RESULTS - 23
VI. ANALYSIS OF DATA AND RESULTS 25
A. Data ^ 25
B. Colorado Coal Results 40
VII. COMPARISON OF PHASE I AND PHASE II RESULTS 55
VIII. DISCUSSION - - 63
A. Results 63
B. Data and Testing Effects - 77
C. Final Presentation 81
D. Interrelated Variables 81
IX. CONCLUSIONS - - - 83
X. REMARKS (Recommendations) 87
APPENDIX A, FUELS DATA, ANALYSES, AND CALCULATIONS 89
APPENDIX B, OPERATING CONDITIONS, MEASUREMENTS AND CALCULATIONS 95
APPENDIX C, PRELIMINARY TEST DATA - 99
APPENDIX D, PRELIMINARY DATA PLOTS 109
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TABLE OF CONTENTS (Cont'd)
APPENDIX E, MATHEMATICAL DERIVATIONS AND CALCULATIONS 125
APPENDIX F, FUEL NITROGEN CONTENT OF THE OHIO AND COLORADO COALS 131
APPENDIX G, COMPARATIVE DATA FOR THE OHIO COAL AND NATURAL GAS 133
APPENDIX H, TABLE OF CONVERSION FACTORS FOR SI UNITS 135
APPENDIX I, COMBUSTIBLES AND NOV - - 137
A
List of Tables
Table
6.1 Base Line Tests for Colorado Coal (Series VII) 26
6.2 Fineness Tests for Colorado Coal (Series VIII) 27
6.3 Flue Gas Recirculation Tests for Colorado Coal (Series IX) 27
6.4 Staged Combustion Tests for Colorado Coal (Series X) 28
6.5 Slot Changes for Colorado Coal (Series XI) 29
6.6 Burner Changes for Colorado Coal (Series XII) - 30
6.7 Summary of Series IX, Part 1 - 32
6.8 Summary of Series IX, Part 2 32
6.9 Summary of Series X, Part 1 * 33
6.10 Summary of Series X, Part 2 - - 33
6.11 Summary of Series XI, Part 1 34
6.12 Summary of Series XI, Part 2 35
6.13 Summary of Series XII, Part 1 - 36
6.14 Summary of Series XII, Part 2 - 37
6.15 Carbon Loss and Burner Efficiency 38
6.16 Slot Changes - Staged Combustion 39
6.17 Burner Changes Excess Air 41
6.18 Burner Changes Staged Combustion 41
8.1 Relative Effects on NO in the Flue Gas 81
VI
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TABLE OF CONTENTS (Cont'd)
Table Page
A.I Colorado Coal Analysis 93
A.2 Natural Gas Analysis 94
A.3 Ohio Coal Analysis ~ - - - 94
C.1-C.4 Series VII, Preliminary Data 101
C.5-C.8 Series VIII, Preliminary Data 102
C.9-C.12 Series IX, Preliminary Data 102
C.13-C.16 Series X, Preliminary Data - 103
C.17-C.20 Series XI, Preliminary Data - - 105
C.21-C.24 Series XII, Preliminary Data - 106
F.I Fuel Bound Nitrogen Content 132
I.I Comparison of All Phase I and Phase II Work - 138
List of Figures
Figure
2.1 Basic Combustion Unit 7
2.2 Coal Burner 7
2.3 Coal Impeller - - 7
2.4 Coal Impeller 8
2.5 Coal Impeller 8
2.6 Coal Impeller - 9
2.7 Coal Burner Assembly - 9
2.8 Front Slot Positions - ~ 10
2.9 Side Slot Positions 10
2.10 Slots - No Change - 10
2.11 Slots -No Change - 12
2.12 Slots - First Change - 12
2.13 Slots - Second Change - 12
2.14 Slots - No Change 13
2.15 Slots - Final Change - - 13
2.16 Furnace Cross Section 14
2.17 Burner Cross Section 15
vn
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TABLE OF CONTENTS (Cont'd)
Figure Page
2.18 Burner Changes 15
2.19 Sample System - - 17
2.20 Instrumentation 17
6.1 Excess Air - 43
6.2 Load - - 43
6.3 Preheat - 44
6.4 Fineness Excess Air 44
6.5 Fineness Load 45
6.6 Fineness Preheat 45
6.7 Flue Gas Recirculation 46
6.8 Staging Options - 47
6.9 Staged Combustion 48
6.10 Slot Changes 48
6.11 Slot Changes 51
6.12 Burner Changes 51
6.13 Burner Changes 52
6.14 Burner Changes 52
6.15 Burner Changes 53
6.16 Burner Efficiency - - 53
6.17 Burner Efficiency 54
7.1 Excess Air 57
7.2 Load - 57
7.3 Preheat, Normal Excess Air 59
7.4 Preheat, High Excess Air 59
7.5 Secondary Flue Gas Recirculation - 60
7.6 Staged Combustion 62
D.1-D.14 Preliminary Data, Colorado Coal - Ill
D.15-0.20 Fineness - 114
D.21,0.22 Flue Gas Recirculation - 116
D.23,0.24 Substoichiometric Tests - 116
D.25-D.34 Staged Combustion - - - 117
viii
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TABLE OF CONTENTS (Cont'd)
Figure Page
D.35-D.42 Slot Changes - - 119
D.43-D.54 Burner Changes 121
D.55 Substoichiometric Tests - 124
F.I Fuel Nitrogen Content 132
G.I Excess Air - 133
G.2 Load - - 133
G.3 Preheat - - 133
G.4 Preheat, High Excess Air 134
G.5 Secondary Flue Gas Recirculation 134
G.6 Coal Staged Combustion 134
G.7 Gas, Staged Combustion 134
I.I CO Versus NO (Ohio Coal) - 141
1.2 CO Versus No (Ohio Coal) 141
1.3 CO Versus 02 (Ohio Coal) - 141
1.4 CO Versus 02 (Ohio Coal) 141
1.5 CO Versus NO (Natural Gas) - 142
1.6 CO Versus NO (Natural Gas) 142
1.7 CO Versus 02 (Natural Gas) - 142
1.8 CO Versus 02 (Natural Gas) 142
IX
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SYMBOLS AND ABBREVIATIONS
This list of symbols and abbreviations is included so that all items in the
text may be easily interpreted. All air weights and measurements are calculated
dry unless otherwise noted. All items without specific units are used in a
"general" form of descriptive equation not requiring numerical calculation.
Symbol, Abbreviation Definition
A Pre-exponential rate constant
Aver The average of two measurements
BTU Fuel enthalpy release, BTU/hr
BTUa Air enthalpy, BTU/lb
BTUf Flue gas enthalpy, BTU/lb
BTU6 Total enthalpy release in furnace, BTU/hr
BTUm Humidity (in air) enthalpy, BTU/lb of air
d Differential
D, Diameter of orifice, inches
D2 Diameter of pipe, inches
e Natural constant
E Activation energy
f Subscript indicating forward
FB Fraction of total air at burner
FC02 Fraction of C02 in flue gas
FGR Flue gas recirculation, %
FH20 Fraction of H20 in flue gas
k Kinetic rate constant
L, Measured value #1, base point
U Standard deviation on base point
measurement
l_2 Measured value #2, reduced point
Li Standard deviation on reduced point
measurement
L~ Calculated reduction
Li Standard deviation of calculated
reduction
MA Moles of stoichiometric air/lb fuel
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SYMBOLS AND ABBREVIATIONS (Continued)
Symbol, Abbreviation Definition
MAI Moles of stoichiometric igniter air/lb
igniter fuel
MAR Moles of stoichiometric test air/lb
test fuel
MC Moles of C02 in flue gas/lb fuel
MCI Moles of C09 in igniter flue gas/lb igniter
fuel i
MCR Moles of CO, in test flue gas/lb test
fuel i
MF Moles of flue gas/lb fuel
MFI Moles of igniter flue gas/lb igniter fuel
MFR Moles of test flue gas/lb test fuel
MM Moles of moisture in flue gas/lb fuel
MMF Moles of moisture from the fuel
MMH Moles of moisture from the air humidity
MMI Moles of moisture in igniter flue gas/lb
igniter fuel
MMR Moles of moisture in test flue gas/lb
test fuel
n Temperature exponential in kinetic rate
expression
NDIR NO measurement from the NDIR instrument, ppm
Also used for Beckman "Nondispersive Infrared"
NF Fraction of full meter flow for natural
gas igniter
NO Nitric Oxide*
N02 Nitrogen dioxide
NOX A mixture of NO and N02
N2 Nitrogen*
02 Oxygen*
PB Barometric pressure, atm
PBA Percent of stoichiometric air at burner
*This symbol in brackets; i.e., [NO], indicates the concentration of that gas.
The units on concentration terms as used in calculations in this report are ppm
(parts per million); ordinarily, the symbols are used only in descriptive equa-
tions not requiring numerical calculations.
XII
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SYMBOLS AND ABBREVIATIONS (Continued)
Symbol. Abbreviation
PH20
Pnet
POP
PS
PT
PTA
r
R
R-N
STDV
t
T
TA
TAG
TECo
TFG
TM
Total
W
W
"fg
'fg
"N
rfNI
Definition
Partial pressure of H20 In atmosphere, atm
Total pressure on orifice, atm
Percent oxygen measured in flue gas,
corrected for combustibles
Pnet - PH20' atm
PB -
atm
Percent stoichiometric (theoretical) air
Subscript indicating reverse
Gas constant
Specified an organic fuel bound nitrogen
molecule
Standard deviation of Aver
Time
Temperature of orifice, °F; also used as
kinetic temperature for any reaction
Ambient temperature, F
Air preheat temperature, °F
NO measurement from TECo instrument, ppm;
also used for "Thermo Electron Corp."
chemi 1 umi nescence
Flue gas temperature, °F
Total moles/1 b fuel
Subscript designating sum of all partial
concentrations
Weight of gas flow, Ib/hr
Weight of air input to furnace, Ib/hr
Weight of fuel input to furnace, Ib/hr
Weight of flue gas from furnace, Ib/hr
Weight of recycled flue gas, Ib/hr
Weight of natural gas flow, Ib/hr
Weight of natural gas flow in igniter,
Ib/hr
Xfii
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SYMBOLS AND ABBREVIATIONS (Continued)
Symbol, Abbreviation Definition
Wg Weight of air through second stage, Ib/hr
x Subscript of variable type indicating any
combination; i.e., r, 1, etc.
AH Differential pressure across orifice,
inches H^O
1,2,3... Subscript indicating reaction number for
partial value
xiv
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I. INTRODUCTION
A. Objectives of the Contract
The primary objective of this contract was to investigate on an
experimental coal fired furnace, a variety of combustion techniques
which could be applicable for control of NO and related combustible
X
emissions such as CO, carbon, and hydrocarbons. Additionally, details
for defining the critical conditions for application of the most prom-
ising combustion control techniques to a single burner furnace were to
be provided. Finally, the most successful techniques for pollution
control in the burning of coal were to be optimized and potential
problems in boiler operational and thermal performance were to be
identified. The work for the contract was divided into two phases:
Phase I: Identification of the most promising control
techniques using a single burner, pulverized
coal fired furnace.
Phase II: Definition of the conditions for the most
promising techniques as applied to the single
burner unit used in Phase I.
The criteria applied to the testing included the degree to which nitro-
gen oxides were reduced and the effects on thermal and operational
performance.
B. Phase I
This phase concentrated on a comparison of the NO and combus-
y\
tible emissions from an Ohio coal. Natural gas and a #6 fuel oil were
-------
also tested for comparison with the coal. A general comparison of the
NO control techniques was made. The effects on thermal and operational
A
performance for the application of these techniques were evaluated.
The results of the Phase I effort were documented in Final Report EPA-
650/2-74-002a.
C. Phase II
The primary objective of this phase was to verify and further
define the major variables which were found to influence the formation
of NO and related combustible emissions in Phase I. A Colorado coal
^
was burned in the single burner, experimental coal fired furnace
during Phase II. A comparison of the combustion and NO emission
/\
characteristics of the Ohio and Colorado coals was also required to
determine the general applicability of the control techniques to all
utility boiler types which fire coal.
D. Background and Description of Work
The contract work on Phase II was started in July, 1973 and was
was completed in July, 1974. A Colorado coal was tested to determine
if the same combustion control, techniques would control or inhibit NO
/\
formation to a similar degree as was shown in the Phase I work with
the Ohio coal. Additionally the levels of NO reduction for both
^
coals were to be compared.
The design and operational variables studied with the Colorado
coal were excess air, load, air preheat, staged combustion and port
position, port geometry, burner velocity, and to a limited extent,
flue gas recirculation. For all test series, except port position and
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geometry, the variables were changed over a wide range to include both
normal operating conditions and extreme operating conditions which
would not ordinarily be practical.
A comparison of the two coals was made. The comparison was based
on the percent reduction in NO emission levels rather than by the
/\
absolute change in NO emission levels for each control technique.
A
E. Significant Results of the Phase II Work
It was found that the Colorado coal yielded absolute NO emission
yx
levels that were as much as 25% greater than the Ohio coal, apparently
due to differences in the way fuel bound nitrogen is converted to NO .
A
However, the responses of the two coals to the variable trends were
similar. Both coals showed about the same percentage reduction in NO
A
emission levels over most of the variable ranges.
In the Colorado coal tests, major changes in NO emission levels
A
were due to excess air and load. Flue gas reci rail ation was not
effective except at very high levels of recirculation. Staged com-
bustion was the most promising and effective method for NO control.
A
Additionally variable port geometry indicated that optimization of the
combustion patterns could yield even larger decreases in NO . Burner
y\
velocity changes had a minimal effect on NO emission levels in these
A
tests.
Conversion of fuel bound nitrogen to NO was found to increase
A
with increasing excess air. Apparently, the same free radicals are
present in the final kinetic step for conversion of fuel bound nitro-
gen and thermal fixation of atmospheric nitrogen.
-------
The variables studied for both the Ohio and Colorado coals were:
1) excess air, 2) load, 3) preheat, 4) staging, and 5) flue gas recircu-
lation. Both coals showed the same qualitative trends to all of the
above five control techniques. There is a distinct quantitative differ-
ence in the NO emission levels for these two coals: this must be due
/\
to the percentage of the fuel bound nitrogen converted to NO since both
fuels have the same amount of chemically bound nitrogen.
Both coals and natural gas show an identical relationship between
NO emission level and total combustion air when fired substoichio-
/\
metrically. All three fuels show NO emissions becoming zero at a total
J\
combustion air of 60% of stoichiometric. This would indicate a lower
limit of 60% of stoichiometric air for the first stage of a multistage
combustion process: no further reduction in NO emission levels by
^
reduction of the first stage combustion air would seem practical.
During Phase II, the effects of fineness, port geometry, and
burner velocity were determined for the Colorado coal. These control
techniques could not be studied for the Ohio coal since major changes
were required in our pulverizer or furnace equipment. The time and
cost of these changes did not permit more than one change and this was
made during Phase II testing of the Colorado coal.
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II. APPARATUS
The single burner coal furnace used at the Alliance Research
Center is called "The Basic Combustion Test Unit." Adjacent to the
furnace is a laboratory area where the instrumentation for stack gas
measurements was operated.
A. Description of the Basic Combustion Test Unit
A schematic of the furnace is shown in Figure 2.1. It is of
cylindrical construction with a water-cooled jacket and is partially
lined with a 1-inch thick refractory brick. The air input at the
burner is split into primary (fuel transport) and secondary air flows.
The following burner input represents a typical loading of 5,000,000
Btu per hour for single stage combustion:
Primary (fuel transport) ^ 15% total air (^ 500 Ib/hr)
500 Ib/hr coal
Secondary ^ 85% total air (balance of the
air or * 3000 Ib/hr)
Figure 2.2 is an illustration of the burner used for coal firing. The
spinning vanes are fixed with constant swirl applied to the secondary
air. The coal spreader at the end of the primary pipe, Figures 2,3
through 2.6, is set at a 45 degree angle of divergence from the center-
line to disperse the coal into the secondary air stream.
Figure 2.7 is a photograph of the coal burner hardware (no
fuel supply is shown) as it looked before placement in the windbox. In
summary, the following configuration was used for firing:
-------
1) Coal coal burner (6 vaned) for all tests -coal feed
pipe carried primary air (^ 15% total combustion air)
for coal transport and had a divergent 45 degree
spreader outlet.
2) Natural gas igniter - supplied up to 1% by weight of the
fuel and up to 2% of the Btu release rate in furnace.
Used about 3 Ib natural gas per hour. Used during all
coal tests to maintain stable burning, especially for
low air and high load.
The positions of the staging ports are illustrated in Figures
2.8 and 2.9. Figure 2.10 is a photograph of the ports which were cut
through the furnace. The front slots were set up to admit second stage
air from 1-inch by 12-inch inlets parallel to the burner fuel/air feed.
The side slots were set up to introduce air into the furnace from 2-inch
by 6-inch slots perpendicular to the central axis but offset circum-
ferentially and arranged so that the mixing swirl around the center axis
is opposite to the secondary burner swirl. Only one set of second stage
ports was operated at one time; both sets were never operated simultane-
ously.
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NATURAL GAS
LIGHTER
FIGURE 2.1 BASIC COMBUSTION UNIT
(SINGLE BURNER)
FIGURE 2.2 COAL BURNER
)
/
v /
I
v>
?-
~
rri
^-^
/
/
7
.
»
i
I
\
%
\
v
A
,
\
/
2 1
^
^
/2"
I
FIGURE 2.3 COAL IMPELLER
-------
FIGURE 2.4 COAL IMPELLER
FIGURE 2.5 COAL IMPELLER
8
-------
FIGURE 2.6 COAL IMPELLER
FIGURE 2.7 COAL BURNER ASSEMBLY
-------
FIGURE 2.8 FRONT SLOT POSITIONS
FIGURE 2.9 SIDE SLOT POSITIONS
FIGURE 2.10 SLOTS - NO CHANGE
-------
Two changes were made in each set of slots to test the effect
of "geometry" of the second stage combustion. The slot geometry for
each set of tests is shown below:
1) Base Line (see Figure 2.11)
Front slots - air entered parallel to burner
axis; area of slots 1 x 12 inches.
Side slots air entered perpendicular to
burner axis on 26-inch diameter circle;
area of slots 2x6 inches.
(2) First Change (see Figure 2.12)
Front slots air entered at a 30 degree inward angle
at burner axis; area of slots 1 x 12 inches
Side slots air entered perpendicular to burner
axis on 13-inch diameter circle, area of
slots 3x6 inches (50% increase in
slot area beyond base line tests)
(3) Second Change (see Figure 2.13)
Front slots air entered at a 30 degree outward angle
to burner axis; area of slots 1 x 12
inches
Side slots air entered perpendicular to burner
axis on 13-inch diameter circle,
area of slots 4x6 inches (100%
increase in slot area beyond base
line tests)
11
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FRONT
SLOTS«
l"x 12"
BURNER
^IGNITER
FRONT
SLOTS
I"xl2
ANGLED
INWARDS
/30°
SIDE
SIDE
SUOTS=
3" x 6"
FIGURE 2.11 SLOTS - NO CHANGE FIGURE 2.12 SLOTS - FIRST CHANGE
SIDE
SLOTS'
4" x 6"
ANGLED
OUTWARDS
30°
FIGURE 2.13 SLOTS - SECOND CHANGE
12
-------
Figures 2.14 and 2.15 illustrate the first change in the front slots and
are directly comparable to Figure 2.10.
FIGURE 2.14 SLOTS - NO CHANGE
FIGURE 2.15 SLOTS - FINAL CHANGE
13
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B. Furnace and Burner Detail
Figures 2.16 and 2.17 illustrate the details of the furnace
and burner cross sections. The impeller position is shown for the coal
burner. The coal nozzle exit position is at the beginning of the throat
flair.
Burner changes, to study the effect of combustion air burner
velocity on NO emissions, were made by welding cones of metal into the
burner face. Figure 2.18 shows the burner changes that were made to
reduce the area by fractions of 1/4 and 1/2. An error of 4% in the
calculated area reductions is present because it was thought that the
igniter would have to be extended past the burner insert cones to
maintain ignition and the area of the igniter was subtracted from the
overall area reductions of the throat. Actually, when tested, the flame
from the ignition was found to pass smoothly around the inserts and the
adjustments to the igniter were not made.
The refractory lining of the furnace is 1-inch brick. The
refractory lining extends all around the furnace from the burner to the
mid section of the furnace, or a length of 4 feet.
REFRACTORY
BRICK
WATER-*
JACKET
BURNER
WMDBOX
IGNITER
FIGURE 2.16 FURNACE CROSS SECTION
14
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GAS
IGNITER
COAL FEED
PIPE
a
IMPELLER
(SPREADER)
APPARENT
BURNER
OPENING
AT THROAT
FIGURE 2.17 BURNER CROSS SECTION
NORMAL
75% AREA
50% AREA
STAINLESS STEEL CONE
WELDED INTO THROAT
APPARENT OPENING OF BURNER AT THROAT
FIGURE 2.18 BURNER CHANGES
15
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C. Instrumentation and Sampling
There are two probes in the stack from which gases and ash
were regularly taken for measurement. Figure 2.19 shows the probe
penetration positions into the stack and the relative position of the
gas sampling probe inside the stack during sampling. The first probe
was used exclusively for pulling ash samples into a bag filter to
determine the ash loading in the gas stream and to provide an ash sample
for further analysis. The second probe was used exclusively for gas
samples and subsequent measurements.
The instrumentation probe branched into two gas sample lines. The
first line carried the gas sample into a pair of Bailey Meter hot-wire
analyzers used for measuring Op and total gaseous combustibles. The
output from these two meters was continually monitored and recorded.
The second line carried the gas sample into a 50°F ice bath (see Figure
2.20) before being carried into the instruments. This removed most of
the water in the sampled flue gas. The temperature was maintained as
closely as possible to 50°F. The gas sample then flowed separately into
each of the following instruments:
1) A Thermo Electron Corporation (TECo) chemiluminescence
NO-N02 monitor
2) A Whittaker NO chemical cell instrument with a Mallcosorb
column to remove S02, COp, and H20 before NO measurement
3) A Beckman nondispersive infrared (NDIR) NO analyzer with
a pretreatment chamber to remove most of the 1^0 which
interferes in the NO measurement
16
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4) A Whittaker chemical cell S02 analyzer
5) An MSA infrared analyzer (LIRA) for CO
6) An MSA paramagnetic 02 analyzer
TO EPA
TRAM
TO BAILEY
METERS
T0
"GAS'
CO, 02 INSTRUMENTS
4'
BAG A )
FILTER CJ
FIGURE 2.19 SAMPLE SYSTEM
jTECo
"|_NOx_
__^AljCOSORBUwHIT.
-i OK n un
I BUBBLER [| NO
LIRA
CO
MSA
02
FIGURE 2.20 INSTRUMENTATION
17
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All instrumental outputs except for the CO and 02 analyzers were con-
tinuously recorded. The outputs of the CO and 02 instruments were
manually recorded for each test. The 50°F water bath was sufficient for
the TECo and the reading of the TECo was unaffected by minor changes of
temperature in this bath.
It was found that a 34°F water bath was the only successful
treatment for flue gas measurement of NO with the NDIR infrared instru-
ment in the presence of SOp and 02. The temperature of the sample gas
in the cold finger was maintained during testing at 34 +_ 0.5°F by
periodic addition of ice to the water in the bath. The water inter-
ference due to the humidity of 34°F saturated flue gas was determined
experimentally by bubbling warm air at 70-80°F through water of the same
temperature, passing it through the 50°F water bath, and then through
the 34°F ice bath, noting condensation of water in the cold finger. The
measured interference used to correct all future flue gas measurements
was 55+5 ppm NO (the instrument cannot be read to better than +_ 5 to
10 ppm NO).
18
-------
III. PROCEDURES
A day's testing always commenced with the furnace warmup period and
instrument calibration. The test series to be carried out in the day's
testing started with one or two base line tests at normal operating
conditions to verify that everything was operating properly. Testing
began only when the furnace, its related systems, and the instrumenta-
tion were functioning properly.
The sequence for a test run was to set furnace conditions and check
the operation for all instruments. When all equipment and all tempera-
tures were equilibrated to a constant state of firing, the data were
taken; first, data were read from nonrecording instruments, and then,
data were read off the strip charts for recording instruments on the
basis of the time the test was made.
If there were to be comparison tests run in pairs to determine the
relative decrease in emissions, both tests were always run together on
the same day in order to minimize day-to-day variations.
19
-------
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-------
IV. MEASUREMENTS
A. Variables Studied
There are two types of control (operational and design) that
can be used for reduction of NO . Operational control techniques are
/v
more easily applied to existing units; the physical change on the unit
is minimized and the final cost of the change on the unit will be lower.
Design methods are best applied to new unit designs to minimize redesign
and construction costs. Additionally, it is important to realize that
modifications of existing units can be physically impractical or economi-
cally unsound.
The design variables, which suggest physical and mechanical changes
to a unit, include flue gas recirculation, staged combustion, and basic
coal type. The operational variables used on existing units include
reductions in excess air, fuel firing rate, and air preheat. These
groups of variables are not meant to be mutually exclusive nor totally
inclusive. In addition, the geometry of the second stage air addition
and the burner air velocity represent important variables.
B. Variable Testing
An attempt was made to hold all conditions constant and to
change the one variable under study over a wide range. However, many of
the variables are interrelated and thus as load, excess air, preheat,
and the other variables were changed, the burner air velocities changed,
leading to a variation in mix rate, turbulence, and combustion intensity.
No attempt was made to correlate the interactions of all of these vari-
ables.
21
-------
C. Range of Variables
As each variable was in turn studied, the other variables were
held constant. Generally the two extremes and the middle of the range
of a variable were tested.
The range of each variable was selected so that the entire
practical range of field unit operation could be studied. The extremes
of the range were usually outside the practical limits for normal opera-
tion of boilers. Conditions have occurred where our basic combustion
unit showed unstable combustion tendencies and therefore no meaningful
test data could be obtained. Each variable is specifically described
under the results.
D. Measurements Taken
The raw flue gas analysis data* taken was: barometric pres-
sure; temperature of the instrument area; oxygen from the MSA; carbon
monoxide from the MSA; S02 from the Whittaker; and NO from the TECo,
Whittaker (no CO,,, SO,,, or H,,0 in measured sample), and the NDIR (34°F
saturated). For substoichiometric firing, only gas chromatography could
be used for carbon monoxide and other combustibles. Ash samples were
also taken during some tests and the measurements required were: time,
differential pressure, and absolute pressure. An ash sample was removed
from the filter bag for analysis of unburned carbon.
The furnace data recorded was: the temperature, and absolute
and differential pressures, across a flowmeter or an orifice for each of
primary air, secondary air, the second stage air, the flue gas, and the
i
natural gas igniter. The coal feeder rate was also recorded, but was
used only as a check for the stoichiometric calculations. Finally, the
Bailey oxygen and combustibles meter readings were recorded.
*Unless otherwise specified, all instrumental flue gas measurements
were made at the equivalent of 50 F saturated.
22
-------
V. PHASE II RESULTS
There were six series of tests run during Phase II. A total of
about 200 test points are available. Data are presented in tables in
Appendix C, in figures in Appendix D, and the mathematical equations and
derivations are in Appendix E.
23
-------
(This page intentionally left blank.)
-------
VI. ANALYSIS OF DATA AND RESULTS
The data in final form are presented in two forms: tables and
graphs. The data in the tables were used to prepare all of the graphs
which are in this section.
A. Data
The headings for Tables 6.1 to 6.6 are described below:
1) Original Series and Run Numbers Self explanatory.
2) Total Air, % The total air added as the percentage
of 100% theoretical (stoichiometric) air. The
excess air is simply 100% less than this number.
3) Heat, kBtu/ft /hr - The overall net heat release rate
in the furnace in thousands of Btu per unit volume.
4) Gas Preheat, °F - Combustion air preheat (this is a
weighted average which includes the ambient primary
air).
5) Flue Gas Input, % - The weight percentage of flue
gas recycled back into the combustion air:
W'
-r-$ x 100
6) Air in Burner, % - The total air at the burner as
percent of 100% theoretical (stoichiometric) air. The
balance of the air (difference between columns 2 and 6)
is the air which entered through the second stage ports,
25
-------
7) NO , ppm - The NO content of the flue gas corrected
A
to 3% oxygen, dry conditions.
8) CO, ppm The as measured concentration of CO (and H«
equivalent as CO) in the flue gas.
9) 02, % - The as measured (except for combustibles)
concentration of 0« in the flue gas.
TABLE 6.1 BASE LINE TESTS FOR COLORADO
COAL (SERIES VII)
SERIES VII - COLORADO COAL
FINAL DATA EVALUATION
ORIGINAL
SERIES
ANO
RUN S-S
VII - 1
VI I - 2
VI
VI
VI
VI
VI
VI
VI
vi
VI
VI
VI
VI
VI
VI
VI
VI
VI
VI
VI
VI
VI
VI
VI
- 3
- 4
- 5
- fc
- 7
- 8
- 9
-10
-11
-12
-13
-14
-15
-16
-17
-IB
-19
-20
-21
-22
-23
-24
-25
VII -26
VII -27
VII -28
VII -29
TOTAL
AIR,
1
113.0
138.0
101.5
119.2
146.2
105.0
115.6
102.1
92.8
77.4
72. 8
66.5
115.0
140.0
103.6
114.9
141.0
104.6
115.6
115.0
138.9
142.0
115.0
104.0
113.6
113.0
142.1)
136.0
104.5
HEAT,
KBTU/
FT»*1
/ HR.
49.59
50.77
48.96
30.26
29.08
25.15
66.65
47.24
46.21
45.66
45.66
45.58
63.74
63.19
56.90
46.76
45.66
43.54
58.40
59.10
56.67
30.34
28.84
28.22
31.12
52.42
51.64
55.02
48.89
GAS
PRE-
HEAT
DEC, F
608
635
509
548
570
500
620
585
574
542
537
520
622
631
602
296
298
285
286
290
289
285
279
270
556
621
637
633
600
FLUE
GAS
INPUT
m
0.0
0.0
o.c
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
o.o
o.o
0.0
0.0
AIH
IN
BURNER
(*)
113.0
138.0
101.5
119.2
146.2
105.0
115.6
102.1
92.8
77.4
72.8
66.5
115.0
14Q. 0
103.6
114.9
141.0
104.6
115.6
115.0
138.9
142.0
115.0
104.0
113.6
113.0
142.0
136.0
104.5
NOX
PPM
953
1250
643
820
981
510
1085
673
535
207
104
79
1196
1368
845
917
1102
577
945
912
1042
854
657
443
774
1064
1327
1305
862
CO
PPM
90
60
3500
40
40
850
120
3000
34490
95427
145000
205000
70
60
2600
150
60
2600
240
115
115
60
40
930
375
100
100
150
950
02
*
2.7
5.8
0.5
3.6
6.6
1.1
3.1
Q.6
0.2
0.0
0.0
0.0
3.0
6.0
0.9
3.0
6.1
1.1
3.1
3.0
5.9
6.2
3.0
0.9
2.8
2.7
6.2
5.6
1.0 II
26
-------
TABLE 6.2 FINENESS TESTS FOR COLORADO
COAL (SERIES VIII)
SERIFS VIII - FINENESS - COLORADO COAL
FINAL DATA EVALUATION
ORIGINAL
SERIES
AND
RUN «-S
VIII- 1
VIII- 2
VIII- 3
VIII- 4
VIII- 5
VIII- 6
VIII- 7
VIII- 8
VIII- 9
VI II- 10
VI I I- 11
VIII- 12
1 VIII- 13
1 VIII- 14
TOTAL
AIP,
*
115.0
113.7
149.4
102.8
114.3
102.9
15Q.5
114.9
144.1
110.9
117.0
115. >>
143.0
102.7
HEAT,
KBTU/
FT*»3
/ HR.
52.97
52.97
51.44
49.91
32.54
31.04
33.09
52.50
54. 86
51.64
61.78
47.63
49.20
44.01
GAS
PRE-
HEAT
DFG F
610
615
633
592
551
530
583
610
629
621
6?0
293
282
270
FLUE
GAS
INPUT
<*>
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
22.2
0.0
0.0
0.0
0.0
AIR
IN
BURNER
(T)
115.0
113.7
149.4
102.8
114.3
102.9
150.5
114.9
144.1
119.9
117.0
115.6
143.0
102.7
NOX
PPM
1044
1094
1309
727
786
539
1143
1086
1299
962
.
1226
856
1014
617
CO
PPM
80
100
80
2150
150
1700
100
ISO
8
00
100
105
90
475
II
02 II
%
3.0
2.8
6.9
0.7
2.9
0.7
7.0
3.0
6.4
3.7
3.3
3.1
6.3
0.6
TABLE 6.3 FLUE GAS RECIRCULATION TESTS
FOR COLORADO COAL (SERIES IX)
SERIES IX - F. G. R. COLORADO COAL
FINAL DATA EVALUATION
ORIGINAL
SERIES
AND
RUN «-S
+
IX A - 1
IX A - 2
IX B - 3
1 IX B - 4
IX 3 - 5
TOTAL
AIRf
3
^
112.4
115.7
111.8
110.4
113.7
HEAT,
KBTU/
FT**3
/ HR.
1 H
52.58.
36.63
53.21
53.29
38.90
GAS
PRE-
HEAT
OEG F
615
586
618
616
588
FLUE
GAS
INPUT
-------
TABLE &4 STAGED COMBUSTION TESTS FOR
COLORADO COAL (SERIES X)
FINAL DATA EVALUATION
ORIGINAL
SERIES
AND
RUN »-S
X A - 1
X A - 2
X A - 3
X A - 4
X A - 5
X A - 6
X A - 7
X A - 8
X A - 9
X A - 10
X A - 11
X A - 12
X A - 13
X A - 14
X A - 15
X A - 16
X A - 17
X A - 18
X A - 19
X A - 20
X A - 21
X A - 22
X A - 23
X A - 24
X B - 25
X 6 - 26
X B - 27
X. B - 28
X B - 29
X B - 30
X B - 31
X B - 32
X B - 33
X B - 34
X B - 35
X R - 36
X B - 37
X 8 - 38
X B - 39
X B - 40
X 0 - 41
X B - 42
X B - 43
X B - 44
X R - 45
X B - 46
X B - 47
X B - 48
X B - 49
X B - 50
I
X B - 51
X B - 52
X'-B - 53
X B - b4
X R - 55
X B - 56
X B - 57
TOTAL
AIRt
%
103.9
116.3
115.7
133.2
148.3
112.3
113.7
114.3
113.0
115.0
114.3
123.8
135.1
117.7
114.3
113.7
145.1
147.2
114.3
104.8
119.2
115.0
144.1
103.4
103.7
115.6
115.0
144.0
139.9
114.9
114.9
111.3
116.2
119.7
119.1
113.6
117.7
112.3
120.6
132.3
126.2
123.8
128.7
120.6
150.5
14Q.O
152.8
105.1
104.0
117.0
119.1
118.8
115.9
118.8
118.8
147.2
104.7
HEAT,
KBTU/
FT**3
/ HR.
34.35
38.43
38.20
36.63
39.61
52.42
51.95
50.93
51.17
50.93
51.32
53.37
54.62
49.99
51.72
51.48
52.89
52.82
57.31)
46.21
60.99
47.47
34.42
43.38
33.17
37.57
34.82
39.06
39.30
51.7?
49.91
52.50
47.63
46.61
48.96
47.16
44.72
45.27
48.10
43.07
43.93
44.48
43.15
48. H9
48.41
52.03
46.53
44.41
42.36
59.73
56.75
45.27
44.33
43.46
44.17
32.93
41.89
GAS
PRE-
HEAT
OEG F
555
580
593
606
620
610
615
594
597
598
619
630
6*1
623
603
622
607
587
630
596
638
286
290
275
537
574
583
606
632
593
594
620
629
639
621
636
629
634
603
585
606
606
611
592
5S4
591
606
5«8
604
627
644
276
279
2S1
279
283
273
FLUE
GAS
INPUT
<*)
0.0
0.0
0.0
0.0
0.0
0.0
0.. 0
0.0
0.0
0.0
0.0
o-.o
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
AIR
IN
BURNER
<*)
---
103.9
116.3
115.7
133.2
148.3
112.3
113.7
114.3
113.0
115.0
114.3
123.8
135.1
117.7
114.3
113.7
145. 1
147.2
114.3
104.8
119.2
115.0
144.1
103.4
78.4
94.3 >
67.7
117.2
88.1
104.4
93.6
72.1
62.4
54.4
96.8
7Q.6
58.4
45-5
109.6
107.3
78.3
66.5
56.2
98.7
106.2
106.4
70.2
80.2
53.5
94.7
72.5
87.9
5R.9
89.8
63.0
88.1
46.9
NOX
ppH
568
917
869
1057
120?
986
990
965
1056
1135
1068
1248
1391
1129
1121
1035
1364
1396
1033
679
1182
874
897
415
252
571
288
990
582
.935
761
398
366
389
784
412
385
329
899
898
651
539
505
748
1Q39
979
771
331
312
763
496
433
395
493
477
477
255
CO
PPH
_._
1700
130
30
100
100
325
60
150
120
90
100
70
75
ISO
150
120
60
60
180
1600
120
130
.30
9500
12500
300
1900
100
100
180
150
360
360
510
180
360
210
360
210
30
60
90
150
240
60
60
60
4400
3100
150
340
1200
1200
1100
1100
150
4000
02
%
»_ «4.
T
0.9
3.2
3.1
5.3
6.8
2.6
2.8
2.9
2.7
3.0
2.9
4.2
5.5
3.4
2.9
2.8
6.5
6.7
2.9
1.1
3.6
3.0
6.4
1.2
1.4
3.1
. 3.1
6.4
6.0
3.0
3.0
2.4
3.2
3.7
3.6
2.8
3.4
2.6
3.8
5.2
4.5
4.2
4.8
3.6
7.0
6.0
7.2
1.3
1.0
3.3
3.6
3.6
3.2
3.6
3.6
6.7
1.2
28
-------
TABLE a5 SLOT CHANGES FOR COLORADO COAL
(SERIES XI)
FINAL CATA EVALUATION
ORIGINAL
SERIES
AND
RUN »-S
XI A - 1
XI A - 2
XI A - 3
XI A - 4
XI A - 5
XI A - 6
XI A - 7
XI A - 8
XI A - 9
XI A -10
XI A -11
XI A -12
XI A -13
XI A -14
XI B - 1
XI 8 - 2
XI B - 3
XI fl - 4
XI B - 5
XI B - 6
XI B - 7
XI B - 8
XI B - 9
XI B -10
XI B -11
XI 3 -12
XI B -13
XI B -14
XI C - 1
XI C - 2
XI C - 3
XI C - 4
XI C - 5
XI C - 6
XI C - 7
XI C - 8
XI C - 9
. XI C -10
XI C -11
XI C -12
XI C -13
XI C -14 |
TOTAL
AIR t
*
115.6
114.6
117.0
113.6
114.3
102.0
103.9
106.4
104.2
104.2
115.0
116.3
115.0
115.6
113.7
115.6
114.0
112.3
115.6
104.3
104.0
104.4
102.1
104.0
114.0
114.3
116.3
116.3
116.3
114.2
114.1
115.9
114.9
103.8
103.7
104.3
100. B
101.1
113.6
114.7
113.5
114.3
HEAT,
KBTU/
FT**3
/ HR.
49.44
56.59
45.74
48.02
47.55
48.65
46.45
43.07
40.95
44.01
36.00
33.80
30.26
32.77
51.01
48.49
44.96
50.77
48.10
48.02
43.93
41.18
47.31
45.35
36.31
33.56
31.91
31.83
51.32
48.65
46.45
48.18
47.31
49.59
46.29
44.56
43.23
45.82
37.02
33.56
32.62
33.87
GAS
ORC-
HEAT
OtG F
618
584
620
605
618
595
593
609
640
607
588
587
605
594
649
609
620
616
661
595
594
605
601
606
591
592
590
580
616
598
628
604
630
605
608
615
603
623
595
593
.
613
610
FLUF
GAS
INPUT
m
0.0
0.0
0.0
0.0
o.c
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0.
0.0
0.0
0.0
0.0
AIR
IN
BURNER
( *)
115.6
91.4
62.6
87. 0
61.6
102.9
75.4
49.6
71.9
49.3
115.0
81.9
43.6
48.8
113.7
«8.3
58.0
85.2
64.0
104.3
76.6
49.9
77.3
55.9
114.0
84.5
57.4
57.3
116.3
87.1
60.2
88>0
62.5
103.8
75.7
49.5
70.7
47.7
113.6
79.2
48.1
49.1
NOX
PPM
1108
885
414
745
551
757
467
315
389
315
981
557
288
342
1083
834
414
704
574
796
434
399
401
318
857
601
434
360
1096
673
295
611
513
784
338
199
385
226
940
356
250
364
CO
PPM
120
120
100
200
90
3700
3500
120
2200
1200
75
60
90
100
90
165
115
310
115
2700
2000
12QO
8000
3200
165
140
150
190
150
430
810
1200
300
4000
6500
4000
9500
9500
125
960
500
260
02
%
3.1
2.9
3.3
2.8
2.9
0.8
1.0
1.3
1.0
0.9
3.0
3.2
3.0
3.1
2.B
3.1
2.8
2.6
3.1
1.0
0.9
1.0
O.S
1.0
2.8
2.9
3.2
3.2
3.2
2.9
2.9
3.2
3.0
1.0
1.1
1.1
0.6
0.7
2.8
3.0
2.8
2.9
29
-------
TABLE 6.6 BURNER CHANGES FOR COLORADO
COAL (SERIES XII)
FINAL DATA EVALUATION
ORIGINAL
SERIES
AND
RUN »-S
XII A- 1
XII A- 2
XII A- 3
XII A- 4
XII A- 5
XI I A- 6
XII A- 7
XII A- 8
XII A- <)
XII A-10
XII A-ll
XII A-12
XII A-13
XII A-14
XII A-15
XII A-16
XII A-17
XII A- 1 8
XII A-19
XII 4-20
XII H- 1
XII B- 2
XII B- 3
XII R- 4
XII B- 5
XII 8- 6
XII H- 7
XII B- 8
XII 8- 9
XII B-10
XII B-ll
XII B-12
XII B-13
XII B-14
XII B-15
XII B-16
XII B- 1 7
XII 8-18
XII B- 1 9
XII 8-20
XII C- 1
XI I C- 2
XII C- 3
XI I C- 4
XII C- 5
XII C- 6
XII C- 7
XI I C- 8
XII C- 9
f XI I C-10
XII C-ll
XII C-12
XII C-13
XII C-14
XI I C-15
XII C-16
XII 017
XII C-18
XII C-19
XII C-20
TOTAL
AIR.
?
116.3
117.7
117.0
114.6
115.6
104.0
105.6
105.5
104.1
105.6
153.8
116.3
113.7
115.0
118.4
117.7
114.3
115.0
155.1
104.5
114.6
112.9
113.9
113.3
114.0
103.7
104.4
104.4
102.0
104.7
155.0
114.0
113.6
113.0
114.3
115.0
115.6
113.5
150.5
102.9
114.0
112.6
115.0
113.7
113.9
101. B
102.1
10^-5
102.8
105.5
145.0
112.4
112.1
111.5
113.0
111.5
111.7
114.2
148.3
103.1
HEAT,
KBTU/
FT»*3
/ HP.
49.83
48.89
46.45
38.59
48.81
48.81
47.39
45.51
48.26
47.71
55.65
50.2?
37.02
33.48
31.36
33.87
33.80
46.53
47.79
44.33
51.01
49.12
46.76
48.18
47.00
45.58
44.88
42.28
48.34
45.03
53.44
50.69
36.63
35.13
32.22
34.66
34.5S
47.94
47.94
45.11
51.32
48.34
45.11
47. 86
46.92
46.06
42.76
40.48
45.11
42.99
51.24
51.56
37.18
47.00
34.03
36.86
34.50
47.24
50.30
45.19
GAS
PRE-
HEAT
OEG F
620
623
630
598
629
603
607
617
606
616
650
620
590
579
605
581
609
301
313
296
620
611
625
598
623
587
6Ql
603
597
611
642
618
589
593
609
594
600
289
288
280
628
616
637
628
635
600
594
609
598
609
639
614
583
605
596
584
605
294
302
285
FLUE
GAS
INPUT
It)
1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
. 0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0.0
AIR I
IN .
BURNER
(SI
116.3
88.9
63.1
79.5
63.8
104.0
79.4
56.6
79.1
58.1
153.8
116.3
113.7
80.2
48.0
81.6
49.5
115.0
155.1
104.5
114.6
86.3
60.3
86.2
61.4
103.7
76.9
51.2
77.1
53.7
155.0
114.Q
113.6
79.0
44.8
80.5
52.7
113.5
150.5
102.9
114.0
85. 4
60.2
S6.4
M.I
101.8
72.9
44.7
74.2
48.0
145.0
112.4
112.1
86.4
49.3
79.0
47.1
114.2
148.3
103.1
1
NOX
PPM
1191
933
512
720
567
824
538
278
434
363
1327
1037
892
506
341
540
332
1002
1192
745
1220
914
420
865
566
871
576
303
524
304
1401
1216
1022
631
357
607
383
1046
1183
748
1108
875
426
726
489
726
4Q8
326
420
238
1395
1172
1048
549
351
569
287
1062
1165
714
CO
PPM
100
75
... 60
75
150
3200
1200
1600
2600
2100
180
200
90
80
75
60
150
100
60
2000
65
330
300
60
100
2400
4300
1400
3600
2150
120
100
200
140
75
55
115
450
30
3900
60
330
100
120
300
4400
5000
1000
3950
2800
200
200
100
500
155
240
330
500
180
3700
II
02
X
3.2
3.4
3.3
2.9
3.1
1.0
1.3
1.3
1.0
1.3
7.3
3.2
2.8
3.0
3.5
3.4
2.9
3.0
7.4
1.0
2.9
2.7
2.8
2.8
2.8
0.9
1.1
1.0
0.6
1.1
7.4
2.8
2.8
2.7
2.9
3.0
3.1
2.8
7.0
0.8
2.8
2.6
3.0
2.8
2.8
0.6
0.7
1.0
0.8
1.3
6.5
2.6
2.5
2.4
2.7
2.4
2.5
2.9
6.8
0.8
30
-------
In addition, Tables 6.7 to 6.14 inclusive are the final calculations
based on the data from Tables 6.1 to 6.6 for use in evaluation of the
NO reduction for flue gas recirculation and/or staged combustion. Each
of the series is described by two tables; part 1 and part 2. The
tabular headings are described as:
Part 1 1) Original Test Numbers: When coupled with
the Series Number in the table title, this
is self-explanatory.
2) Averages for Tests: These values are the
average values for the two tests for:
a) Load, %: The percentage of fuel Btu
input based on 5,000,000 Btu/hr.
b) Excess Air, %: The percent of air
based on stoichiometric air added over
and above the 100% theoretical air level.
c) Temperature, °F: The total preheat for
the fuel/air input.
3) Burner air, %: The percentage of 100%
theoretical (stoichiometric) air coming
through the burner as first stage air.
4) Side or Front Slots: The slot position
used for second stage air if the tests
involved staged combustion.
5) Flue Gas Recycled, %: The percentage of
31
-------
flue gas recycled from the stack into the
combustion atr-.
6) Burner or Ports: Not applicable to Phase II,
Part 2 7) NO (ppm): The NO measurements in the flue
gas corrected to dry, 3% oxygen conditions
for the following tests:
a) Base Value: The test before any NO
reduction methods were used.
b) With Changes: The test made with NO
reduction methods(s) applied.
c) Reduction: The difference between
columns a and b.
8) Reduction in NO, %: The percentage reduction
from columns 7a and 7b based on the initial
value in 7a.
TABLE 6.7 SUMMARY OF SERIES IX. PART 1
FINAL DEDUCTIONS (PART 1)
ORIGINAL
TEST
NOS.
IX - 1/3
IX - 1/4
IX - 2/5
AVERAGES FOR TESTS
LOAD,
2
US. 8
119.3
85.0
tXCESS
AIR, *
12.1
11.*
14. T
TEMP.
OEG F
616
615
587 |
1
BURNER
AIR,
%
112.1
111.4
1 114.7
1
SIDE
OR
FRONT
SLOTS
FLUE
GAS
RECYC.
%
6.6
18.5
2?. 7
BURNER ||
OR 1 1
PORTS 1 1
II
1 11
II
BURNER | 1
BURNER 1 1
BURNER (I
II
TABLE 6.8 SUMMARY OF SERIES IX. PART 2
FINAL REDUCTIONS (PART 2)
TEST
II
NAL
1/3
1/4
2/5
BASE
VALUE
1019 + 12
1018 + 12
811 ± 7
NO (PPM)
WITH
CHANGES
96fl + It
888 *- 28
770 »- 11
REDUCTION
50 * 16
130 ± 30
41 ± 13
REDUCTION ||
TM II
NO, * II
II
11
II
4.0 ± 1.6 II
12.9 ± 3.0 1 1
5.1 t. 1.6)1
II
32
-------
TABLE 6.9 SUMMARY OF SERIES X. PART 1
FIN41 SEDUCTIONS (PART 1)
II ORIGINAL II
HTC C T II
II
II
JJ
II
II X
II x
II X
II x
II X
II x
II X
II X
II x
II X
II
II X
II X
II X
II x
II x
II x
II X
II X
II x
II X
II
II X
II X
1 1 X
II x
II X
II x
II X
II X
II x
II X
1 1
II x
II x
II X
1 1 J 1 11
NOS. I I
II
II
II
- 1/25 1 1
- 2/26 1 1
- 3/27 1 1
- 5/28 1 1
- 5/2") 1 1
-15/30 ||
-10/31 1 |
-19/32 ||
-10/33 II
-14/3* | |
1 1
-14/35 1 1
-11/3* 1 1
-14/37 II
-11/38 1 1
-14/30 1 1
-13/40 1 1
-12/41 ||
-12/42 ||
-13/43 II
-14/44 | |
1 1
-18/45 II
-13/46 1 1
-18/47 | |
-20/48 1 1
-20/49 | |
-21/50 1 1
-21/51 1 1
-72/52 ||
-22/53 1 1
-22/54 | |
1 1
-22/S5 | |
-23/56 1 1
-24/S7 1 1
AVERAGES F0» TESTS
LOAD,
X
7S. 7
88.1
86.1
86.3
89.9
UP. 3
116.4
127.5
115.9
113.7
113.2
114.4
111.1
114.2
111.6
110.1
112.1
113.5
113.3
113.0
114.8
120.4
114.9
105.9
105.4
137.7
136.1
113.7
113.3
111.5 .
113.0
B2.4
105.9
EXCESS TE«P.
AIR, t 1 DEC, f
l_ _l
3.B
15.9
15.3
46.1
44.1
14.6
14.9
12.8
15.6
18.7
18.4
13.0
17.7
13.3
19.1
33.7
25.0
?3.8
31.0
19.1
48. R
37.5
50.0
4.9
4.4
18.1
19.1
16.9
15.4
16.9
16.1
45.6
4.0
546
577
5E8
613
626
598
596
625
613
631
622
627
626
626
613
613
618
618
676
607
585
616
596
592
6QO
632
64 1
281
282
283
282
286
274
II
II
II
||
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
BURNER
A I fi
t
78.4
94.3
67.7
117.2
R8. 1
104.4
93.6
72.1
62.4
54.4
96.8
70.6
58.4
45.5
109.6
107.3
78. 3
66.5
56.2
98.7
106.2
106.4
70.2
80.2
53.5
94.7
72.5
87.9
58.9
89. 8
63.0
88.1
46.9
SIDE
OR
FRONT
SLOTS
FRONT
FRONT
FRONT
FRONT
FRONT
FRONT
FRONT
FPONT
FRONT
FRONT
FRONT
FRONT
FRONT
FRONT
SIDE
SIOF
SIOF
SIDE
SIDE
SIDE
FRUNT
SIDE
SIDE
FRONT
FRONT
FRONT
FRUNT
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
II
II
II
| |
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
1 1
II
II
II
II
II
II
II
II
II
1 1
1 1
II
II
II
II
1 1
II
II
II
1 1
FLUE 1 BURNER
GAS * no
RECYC.
t
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0 .
0.0
0.0
0.0
0.0
0.0
o.o
0.0
wr*
PORTS
....
....
--
....
....
....
__..
..._
_-
....
....
....
_--
....
.
--__
....
....
__
....
--
. .
.___
_-
-.-.
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
TABLE 6.10 SUMMARY OF SERIES X. PART 2
FINAL REDUCTIONS I PART 2)
II ORIGINAL II
II TEST ||
II NOS. II
II II
II
II X
II x
II X
II X
II X
II X
II X
II x
II x
II X
II
II x
II x
II x
II X
II x
II x
II X
II x
II X
II X
II
II X
II x
II x
II X
II x
II X
II X
II X
II X
II x
1 1
II X
II x
II X
II
II
- 1/25 I I
- 2/26 1 I
- 3/27 | |
- 5/28 | |
- 5/29 | |
-15/30 II
-10/31 | |
-19/32 II
-10/33 ||
-14/34 II
II
-14/35 II
-11/36 | |
-14/37 ||
-11/38 ||
-14/30 | |
-13/40 ||
-12/41 ||
-12/42 II
-13/43 1 1
-14/44 1 |
II
-18/45 ||
-13/46 II
-18/47 | |
-20/48 II
-20/40 | |
-21/50 II
-21/51 ||
-22/52 II
-22/53 ||
-22/54 II
II
-22/55 ||
-23/56 | 1
-24/57 | |
1 1
NO (PPM)
... _._.__.-
BASE
VALUE
568
017
869
1207
1207
1121
1135
1038
1135
1129
1129
1068
1120
1068
1129
1301
1248
1248
1391
1129
1396
1391
1396
679
679
1182
1182
874
874
974
874
897
415
±
*
±
I
I
t
+
i
»
1
»
±
*
+
»
±
1
»
t
+
7
0
37
26
64
64,
34
9
16
0
16
16
23
16
23
16
73
40
40
73
16
11
73
11
10
10
20
20
26
26
26
26
4
14'
WITH
CHANGES
252 ±
571 ±
288 «
900 i
582 *
935 i
761 +
308 ±
386 »
380 »
784 »
412 1
385 »
329 7
899 »
808 *
651 »
539 »
505 »
748 »
1039 »
979 »
771 »
331 »
312 *
763 »
496 »
433 »
395 »
403 »
477 »
477 »
255 »
5
6
1
22
3
40
36
12
2
6
48
55
2
2
19
29
19
14
18
7
5
17
31
5
2
7
10
2
2
9
9
7
1 8
REDUCTION
316
346
581
217
625
186
374
640
749
740
345
656
744
730
230
403
597
709
886
381
357
412
625
348
367
419
686
441
479
381
397
420
160
+
7
*
l
±
*
±
i
±
±
*
I
*
t
±
*
7
t
7
+
+ .
7
+
i
*
±
+
7
+
*
I
10
37
26
68
64
52
37
20
9
17
51
60
16
23
25
79
44
42
75
17
12
75
33
11
10
21
22
26
26
28
28
8
23
REDUCTION II
IN II
NO, » II
II
II
55.6 ±
37.7 ±
66.0 l
18.0 ±
51.8 t
16.6 1
33.0 t
61.7 t
66.0 1
65.5 t
30.6 1
61.4 »
65.0 i
69.2 ±
20.4 1
35.4 t
47.8 *
56.8 1
63.7 t
33.7 ±
25.6 1
29.6 *
44.8 t
51.3 ±
54.1 »
35.4 ±
58.0 »
50.5 »
54.8 i
43.6 t
45.4 ±
46.8 ±
38.6 1
II
2.0 II
4.4 II
3.6 II
5.7 ||
6.0 ||
4.7 II
3.3 ||
2.1 II
1.0 II
1.8 II
II
4.5 II
5.7 II
1.7 II
2.6 II
2.2 II
5.9 II
3.0 II
3.9 II
6.4 II
1.6 II
II
0.9 II
5.6 II
2.4 ||
1.8 II
1.7 II
1.9 II
2.1 II
3.3 II
3.4 II
3.4 II
II
3.4 II
0.9 ||
5.6 II
II
33
-------
TABLE 6.11 SUMMARY OF SERIES XI, PART 1 :
FINAL REDUCTIONS (PART II
ORIGINAL
TC C T
1 t J 1
NOS.
_L_
A 1/2
A I/ 3
A I/ 4
A I/ 5
A 6/ 7
A 6/ 8
A 6/ 9
A 6/10
A 11/12
A 11/13
A 11/14
81/2
B I/ 3
R I/ 4
B I/ 5
B 6/ 7
86/8
B 6/ 9
B 6/10
B 11/12
B 11/13
B 11/14
JJ_ L
C 1/2
C I/ 3
C It 4
C I/ 5
C 6/ 7
C 6/ 8
C 6/ 9
C 6/10
C 11/12
C 11/13
II C 11/14
II .
AVERAGES FOR TESTS II BURNER
LOAD,
%
120.6
111.3
112.3
113.7
111.3
10
-------
TABLE 6.12 SUMMARY OF SERIES XI. PART 2
FINAL REDUCTIONS (PART 21
ORIGINAL
TC C T
1 1 a i
NOS.
1
A I/ 2
A I/ 3
A I/ 4
A I/ 5
46/7
A 6/ 8
A 6/ 9
A 6/10
A 11/12
A 11/13
A 11/14
B I/ 2
B I/ 3
B 1/4
B I/ 5
86/7
B 6/ 8
B 6/ 9
B 6/10
B 11/12
B 11/13
B 11/14
C I/ 2
C I/ 3
C I/ 4
C I/ 5
C 6/ 7
C 6/ 8
C 6/ 9
C 6/10
C 11/12
C 11/13
C 11/14
BASE
VALUE
1108 » 63
1108 ± 63
1108 + 63
1108 * 63
757 ± 20
757 * 20
757 t 20
757 ± 20
961 4- 48
981 * 48
981 » 48
-
1083 t 30
1083 + 30
1083 ± 30
10B3 + 30
796 i 26
796 ± 26
796 * 26
796 ± 26
857 t 11
857 ± 11
857 » 11
1096 + 45
1096 » 45
1096 + 45
1096 ± 45
784 ± 16
784 i 16
784 + 16
784 » 16
940 » 10
940 + 10
~
940 * 10
NO (PPM)
WITH
CHANGES
885 t 29
414 » 17
745 + 32
551 ± 20
467 ± 12
315 ± 8
389 * 13
315 ± 11
557 * 17
288 » 6
342 » 11
834 ± 18
414 » 13
704 t 21
574 * 17
434 ± 15
399 t 8
401 i 11
318 i 5
601 » 6
434 + 12
360 ± 9
673 ± 67
295 + 6
611 ± 17
513 * 13
338 * 8
1?9 + 1
385 + 4
226 « 8
356 ± 2
250 ± 6
364 » 9
REDUCTION
223 * 69
694 * 65
363 ± 71
557 ± 66
290 + 23
442 ± 22
368 » 24
442 ± 23
424 t 51
693 1 48
639 » 49
249 i 35
669 * 33
379 ± 37
509 » 34
362 » 30
397 » 27
395 i 28
478 » 26
256 i 13
423 * 16
497 + 14
423 ± 81
801 * 45
485 ± 4B
583 i 47
446 + 18
585 » 16
399 + 16
558 + 18
584 + 10
690 ± 12
576 * 13
REDUCTION II
lu II
IN II
NO. X II
II
11
II
20.1 ± 6.4 II
62.6 t 6.9 1 1
32.8 i 6.6 II
50.3 t 6.6 1 1
38.3 * 3.2 II
58.4 ± 3.2 II
48.6 i 3.4 I I
58.4 ± 3.* II
43.2 t 5.6 1 1
70.6 i 6.0 II
II
65.1 t 5.9 II
Li
II
23.0 t 3.3 II
61.8 i 3.5 II
35.0 i 3.5 II
47.0 1 3.4 ||
45.5 ± 4.1 I I
49.9 i 3.8 I |
49.6 1 3.9 | |
60.1 ± 3.9 ||
29.9 ± 1.5 ||
49.4 ± 2.0 ||
II
58.0 t 1.8 1 1
II
38.6 ± 7.5 II
73.1 t 5.1 II
44.3 » 4.8 ||
53.2 ± 4.8 1 1
56.9 t 2.6 1 1
74.6 t 2.5 II
50.9 ± 2.3 II
71.2 ± 2.7 ||
62-1 i 1-3 II
73.4 t 1.5 1 1
II
61.3 ± 1.6 II
II
35
-------
TABLE 6.13 SUMMARY OF SERIES XII, PART 1
FINAL REDUCTIONS (PART i)
ORIGINAL
TP C T
icai
NOS.
-
A I/ 2
A I/ 3
A It 4
A I/ 5
A 6/ 7
A 6/ 8
A bl 9
A 6/10
A 13/14
A 13/15
A 13/16
A 13/17
B I/ 2
B I/ 3
B I/ 4
B I/ 5
86/7
86/8
B 6/ 9
B 6/10
B 13/14
B 13/15
B 13/16
B 13/17
C It 2
C 1/3
C I/ 4
C I/ 5
C 6/ 7
C 6/ 8
C 6/ 9
C 6/10
C 13/14
C 13/15
C 13/16
C 13/17
1
AVERAGES FOR TESTS II BURNER
LOAOf
%
113.9
112.9
102.4
115.6
112*3
111.7
113.3
114.3
82.4
81.5
82.8
84.4
115.5
114.6
114.4
114.9
105.9
104.9
110.1
108.0
83.8
S2.2
83. 1
84. 8
114.8
112.9
114.1
115.0
104.3
103.5
106.9
106.4
98.0
85.0
86.6
85.6
EXCESS
AIR, Z
-
17.0
16.6
15.4
15.9
4.8
4.8
4.0
4.8
14.3
16.0
15.7
14.0
13.7
14.2
13.9
14.3
4.0
4.0
2.8
4.2
13.3
13.9
14.3
14.6
13.3
14.5
13.8
13.9
1.9
3.1
2.3
3.6
11.8
12.5
11.8
11.9
TEMP.
DEC F
621
625
609
624
605
610
60 4
609
584
597
585
599
615
622
6Q 9
621
594
595
592 .
599
591
599
591'
594
622
632
62S
631
597
604
599
604
594
589
583
594
M IP f
t
88.9
63.1
79.5
63.8
79.4
56.6
79.1
58.1
8Q.2
48.0
81.6
49.5
86.3
60.3
86.2
61.4
76.9
51.2
77.1
53.7
79.0
44.8
80. S
52.7
85.4
60.2
86.4
61.1
72.9
44.7 .
74.2
48.0
86.4
49.3
79.0
SIDE
no
UK
FRONT
SLOTS
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
'
SIDE
SIDE
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
SIDE
SIDE
FRONT
FRONT
SIDE
47.1 | SIDE
FLUE
/AC
l?Ao
RECYC.
%
J
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
BURNER 1 1
no 1 1
UK | 1
PORTS 1 1
II
1 t
II
1 1
1 1
1 1
1 1
1 1
1 1
1 1
II
1 1
1 1
II
1 1
II
II
II
1 1
1 1
- 1 1
1 1
1 1
1 1
1 1
1 1
1 1
1 1
II
1 1
1 1
11
II
1 1
1 1
1 1
1 1
1 1
1 1
1 1
1 1
1 1
1 1
II
1 1
1 1
II
36
-------
TABLE 6.14 SUMMARY OF SERIES XII, PART 2
FINAL REDUCTIONS (PART 2)
1 OPIGINAL
TC C T
1 C i 1
NOS.
,
11/2
41/3
41/4
A It 5
46/7
A 6/ «
A 6/ 9
A 6/10
A 13/14
A 13/15
A 13/16
A 13/17
a i/ 2
B I/ 3
91/4
81/5
B &/ 7
B 6/ 8
86/9
S 6/10
8 13/14
9 13/15
R 13/16
B 13/17
C I/ 2
C I/ 3
C »/ 4
C I/ 5
C 6/ 7
C 6/ B
C 6/ 9
C 6/10
C 13/14
C 13/15
C 13/16
C 13/17
BASE
VALU6
1191 ± 13
1191 * 13
1191 » 13
1191 ± 13
824 1 23
824 ± 20
824 ± 20
R24 » 20
892 I 29
892 * 29
892 + 29
»92 + 29
1220 + 34
1220 + 34
1220 + 34
1220 * 34
871 » 14
871 + 14
371 * 14
871 + 14
1022 » 15
1022 + 15
1022 t 15
1022 + 15
1108 » 12
1108 ± 12
1108 ± 12
1108 + 12
726 ± 0
726 + 0
726 + 0
726 + 0
1048 * 22
1048 + 22
1048 + 22
1048 + 22
NC (PPM)
WITH
CHANGES
_ - ._ .
933 * 8
512 ± 21
720 * 23
567 t 21
538 * 22
278 + 8
434 * 15
363 ± 15
506 + 24
341 t 13
540 * 14
332 ± 13
914 + 18
420 ±
865 + 15
566 « 17
576 1 16
303 + 7
524 » 6
304 + 7
631 * 10
357 » 2
607 -f 3
383 + 14
875 ± 8
426 * 3
726 » 16
439 * 13
408 + 2
. 326 + 0
420 » 8
238 i 0
549 t 3
351 * 2
569 + 3
287 + 4
REDUCTION
258 » 15
679 * 25
471 » 26
624 » 25
286 * 30
546 + 22
390 + 25
461 i 25
386 + 3R
551 » 32
352 * 32
560 ± 32
306 + 33
800 ± 35
355 t 37
654 t 38
295 ± 21
568 + 16
347 » 15
567 » 16
391 » 18
665 * 15
415 * 15
639 + 21
233 1 14
682 + 12
382 t 20
619 ± 18
318 + 2
400 ± 0
306 ± 8
488 i 0
499 » 22
697 + 22
479 + 22
761 ± 22
REDUCTION
1 M
1 T
NO. *
21.7 * 1.3
57.0 ± 2.2
39.5 ± 2.3 ||
52.4 t 2.2 II
34.7 » 3.7 I)
66.3 » 3.1 II
47.3 ± 3.2 II
55.9 ± 3.3 II
43.3 * 4.4 ||
61.8 t 'I 1
1
39.5 i 3.8 1 1
62.8 * 4.1 II
11
1
25.1 ± 3.2 II
65.6 ± 3.4 I 1
29.1 » 3.2 I
53.6 + 3.5
33.9 ± 2.5 1 1
65.2 » 2.1 II
39.9 * 1.9
65.1 ± 2.1 1
38.3 ± 1.9 I 1
65.1 * 1.8 II
II
40.6 i 1.6 | |
62.5 t 2.2 II
11
1
21.0 ± 1.3
61.6 ± 1.3 I
34.5 ± 1.8 II
55.9 i 1.7||
43.8 i 0.3 II
55.1 * 0.0 II
42.1 ± 1.1 II
67.2 t 0.0 ||
47.6 ± 2.3 1
66.5 t 2.5
II
45.7 ± 2.3 ||
72.6 i 2.6 1 1
II
37
-------
TABLE 6.15 CARBON LOSS AND BURNER EFFICIENCY;
SESIFS
AND
TEST
NIJ«BE°
VI I - 1
VII - 3
VI 1 - 5
VII - lo
VII - 11
VII - 15
VIII- 1
VIII- 11
VIII- 14
X - 5
X - 6
X - 22
X - 26
X - 32
X - 40
X - 42
X - 43
X - 45
X - 47
X - 48
X - 53
X - 55
FIRING DATA II WEIGHTS, LR./HR.
AIR
113
102
142
77
73
104
115
117
103
148
112
115
116
111
132
124
129
151
153
105
116
119
FLUC
HEAT
49.59
48.16
29.08
45.66
45.66
56.00
52.97
61.78
44.01
39.61
52.42
47.47
37.57
52.50
43.07
44.48
43.15
4?. 41
46.53
44.41
44.33
44.17
1
OEG II FUEL
F II (QPVI
II
608 || 428 *****
5«9 II 427
570 1 1 244
542 II 413 (SUB)
537 |l 414 (SUB)
602 1 1 496
610 II 454
620 |l 530
270 || 410
620 || 329
II
610 1 1 453
286 || 439
574 | | 334 Is)
620 | | 477 (S)
585 II 379 (S)
606 II 410 (S)
611 II 404 (S)
584 II 428 (S)
606 || 429 IS)
58B (I 401 (S)
II
279 |l 421 (S)
279 || 419 (S)
II
. ||
FLUE
fiAS
5684
5133
4Q62
3783
3594
6015
5911
7059
4058
5467
5825
5851
4376
6064
5710
5814
5913
7214
7386
4958
5590
5690
»SH
IN
F.r,.
t
0.39
U.36
0.40
0.80
0.35
0.82
0.45
0.45
0.65
0.28
0.78
0.69
0.61
0.91
0.59
0.54
0.51
0.45
0.44
1.03
0.99
0.83
II
M
C
'IN
ASH,
*
28.0
43.2
3.8
50.2
52.1
??
13.3
3.3
31.5
18.1
26.1
15.6
??
39.0
20.9
17.9
?5.3
9.1
8.2
35.1
33.4
29.0
BURNER
FFFIC.
IN X
BY WT.
98.6
98.1
99.7
96.3
«6.2
??
99.2
99.8
97.6
99.2
97.4
98.6
??
95.5
98.1
98.6
98.1
90.3
99.4
95.5
95.6
96.7 |
1
II
(SUB) INDICATES SU8STOICHIQHETRIC
(S) INDICATES STAGED COMBUSTION
Table 6.15 is the table showing burner efficiency calculated from
combustibles (mostly solid carbon found in ash samples) from a wide
sampling of coal tests. The tabular headings are:
1) Test and Series Number - Self explanatory.
2) Firing Data The fuel/air input data:
a) Air, % The percent of 100% theoretical air.
b) Flue Heat - Net heat release rate in the furnace
in kBtu/ft3/hr.
c) Deg F The total air preheat in °F.
3) Weights, Ib/hr - For dry fuel (coal Only) and total flue
gas weight.
38
-------
4) Ash in F.G., % The total weight percent of solid ash in
the flue gas.
5) C in Ash, % The total weight percent of carbon in the
solid ash.
6) Burner Efficiency in Percent by Weight - The amount of coal
burned to total flue gas after correction due to unburned
solid (and gaseous for all except substoichiometric tests)
combustibles.
TABLE 6.16 SLOT CHANGES - STAGED COMBUSTION
STAGED COMBUSTION TESTS: PERCENT REDUCTION IN NO
"A" "B" "C"
Test No.* No Change First Change Second Change
39 + 8
73 + 5
, 44 + 5
53 + 5
57 + 3
75 + 3
51+2
71 + 3
62 + 1
73 + 2
61 + 2
*F Indicates front slots for staging; S indicates side slots
Tables 6.16 tabularizes in a simple form the differences in No
emission levels for each of the changes in the slots. The column
headings in the table represent:
1) "A", No Change (these are the base line tests):
front slot air entered parallel to the burner
side slot air entered perpendicular to the burner
axis on a 26-inch diameter circle
1/2 (F)
1/3 (F)
1/4 (S)
1/5 (S)
6/7 (F)
6/8 (F)
6/9 (S)
6/10 (S)
11/12 (F)
11/13 (F)
11/14 (S)
20 + 6
63 + 7
33 + 7
50 + 7
38 + 3
58+3
49 + 3
58+3
43 + 6
71 + 6
65 + 6
23 + 3
62 + 4
35 + 4
47 + 3
46 + 4
50 + 4
50 + 4
60 + 4
30+2
49 + 2
58+2
39
-------
2) "B", First change:
front slot air entered at a 30 degree inward angle
side slot air entered perpendicular to the burner
axis on a 13-inch diameter circle with a 50%
increase in slot area opening
3) "C", Second Change:
front slot air entered at a 30 degree outward angle
side slot air entered perpendicular to the burner axis
on a 13-inch diameter circle with a 100% increase
(over "A") in slot area opening
Tables 6.17 and 6.18 tabularize in the same way as Table 6.16
the differences in NO emission levels for each of the changes in the
burner. The column headings in these tables represent:
1) "A", No change,- the original burner opening with no
cone inserted (These are the base line tests)
2) "B", First change - insertion of a cone into the
burner inlet to reduce the effective throat area by
25% and therefore increasing the burner velocity by
33%.
3) "C", Second change - insertion of another cone into
the burner inlet to reduce the effective throat area
by 50% and thereby increasing the burner velocity by
100%.
B. Colorado Coal Results
All of the figures which follow are the final results of the
trends determined in Phase II for the Colorado coal tests. No other
fuel was studied in Phase II.
40
-------
TABLE 6.17 BURNER CHANGES - EXCESS AIR
EXCESS AIR TESTS: PPM NO
Test No.*
1 (15S)
6 (<5X)
11 (35%)
12 (15%)
13 (15*)**
18 (15«)*»*
19 (35X)*»*
20 (<5«)***
"A"
No Change
1191 +13
824 + 20
1327 + 13
1037 + 27
892 + 29
1002 + 35
1192 + 46
745 + 10
*Number 1n parenthesis 1s excess air
**Low load.
***Low preheat,
TABLE
Test No.*
1/2 (F)
1/3 (F)
1/4 (S)
1/5 (S)
6/7 (F)
6/8 (F)
6/9 (S)
6/10 (S)
13/14 (F)
13/15 (F)
13/16 (S)
13/17 (S)
11 B"
First Change
1220 + 34
871 + 14
1401 + 58
1216 +38
1022 + 15
1046 + 8
1183 + 24
748 + 12
level.
"C"'
Second Change
1108 + 12
726 + 0
1395 + 29
1172 + 27
1048 + 22
1062 + 20
1165 + 5
714 + 12
6.18 BURNER CHANGES - STAGED COMBUSTION
STAGED COMBUSTION TESTS
"A"
No Change
22 + 1
57 + 2
40 + 2
52 + 2
35 + 4
66+3
47 + 3
56 +_ 3
43 + 4
62 + 4
40 + 4
63 + 4
: PERCENT REDUCTION OF
"B"
First Change
25 + 3
66+3
29 + 3
54 + 4
34 + 3 .
65 + 2
46 + 2
65 + 2
38 + 2
65 + 2
41+2
63 + 2
NO
»C"
Second Change
21 +1
62 + 1
35 + 2
56 + 2
44 + 0
55 + 0
42 + 1
67 + 0
48 + 2
67 i 3
46 + 2
75 + 3
*F Indicates front slots used for staging; S Indicates side slots
41
-------
Figures 6.1 to 6.3 illustrate the typical major effects observed
for the Colorado coal. The variables observed are excess air, firing
intensity, and preheat. For these figures, two of the three variables
were held constant, and the third is shown on the abscissa. The
constant conditions observed in these figures are:
Excess air level about 15%
Preheat level - about 600°F
Firing intensity - about 40,000 Btu/ft3/hr.
The important trends observed were:
Excess air rapid increase in NO emission
level peaking at about 30 to 35% excess air
Firing intensity (load or rate of heat release)
increasing NO with increasing load with
no apparent leveling or turnover
Preheat - a slight increasing trend of about
35 ppm per 100°F
Figures 6.4 to 6.6 show a comparison of a fine and coarse pulveri-
zation* of the Colorado coal for these same three variables. The
fine pulverization is ^90% through a 200 mesh screen and the coarse
pulverization is ^70% through 200 mesh. Fineness is not a major
variable in our coal fired test unit. (Ordinarily, for all tests
other than fineness, the 70%/-200 mesh pulverization is used for the
Colorado coal tests.)
Figure 6.7 illustrates the effect of secondary flue gas recircu-
lation. The flue gas was added to the windbox so that there was
thorough mixing of the flue gas and secondary air stream. Very little
reduction of NO emission levels was seen for FGR with the Colorado
coal.
*See Appendix A for the sieving analyses for the. Colorado coal.
42
-------
Q_
D_
Q_
O.
T
T
T
EXCESS RIB. X
FIGURE 6.1 COLORADO COAL
I
I
T
I
20 10 80
RflTE OF HEflT RELERSE. KBTU/FT**3/HR
FIGURE 6.2 COLORADO COAL
43
-------
Q_
O
I 1 T I 1 I I I I
I I I I I I I I T
500
PREHERT. °F
FIGURE 6.3 COLORADO COAL
700
-
Q_
0. ~
f
1 1 1 1 1 1 .1 1 1
^
"
EXCESS flIR. /.
FIGURE 6.4 COLORADO COAL - FINENESS
44
-------
1000-
o.
Q_
500-
I
r
1
20 to eo
RflTE OF HEflT RELERSE, KBTU/FT*«3/HR
FIGURE 6.5 COLORADO COAL - FINENESS
1000-
2:
Q_
Q_
500-
300
I
500
PREHEflT. °F
FIGURE 6.6 COLORADO COAL - FINENESS
45
-------
o
z
z
o
Q
UJ
OC
10O 1III 1III 1iiI 1I*i fr-
vw iiii i i i i ii ii T i i r T r
IS
FLUE GflS RECYCLED. 7.
FIGURE 6.7 FLUE GAS RECIRCULATION
46
-------
Second stage combustion air can be added to our furnace in two
ways (see Figure 6.8). The front slots produce a "progressive mixing"
and involve addition of the air in the burner area. The side slots,
however, produce a defined second stage addition downstream of the
burner area. When using the side slots for Colorado coal combustion,
incomplete combustion occurred in the center core of the flame at low
burner air to total combustion air ratios.
TYPICAL FURNACE LAYOUT
(SMLARTO
SIDE SLOTS)
«l
BURNER
AREA
(SMLAR TO x
FRONT SLOTS)
FIGURE 6.8 STAGED COMBUSTION OPTIONS
Figure 6.9 shows the normal (front slot) staged combustion with
a total excess air of 15%. The substoichiometric curve was generated
by simply shutting off the second stage air. Two important points to
be noted in these curves are:
1) The maximum reduction of NO emission level for normal,
staged combustion is about 65%.
2) The substoichiometric curve shows no NO emission below about
60% of stoichiometric air.
47
-------
so-
o
UJ
cc
100 1 I I I HI I I
SO 100 ISO
STOICHIOMETRY flT BURNERS. 7.
FIGURE 6.9 STAGED - 15% EXCESS AIR
-
z: ~
Q_
Q_ ~
O
/
X
S
s -
.'JT
^
NO (
FIR:
X
HflNGE (BflSE L
>T CHRNGE
tUPI ^_
SECOND CHflNGE
""'""I""1""
20
EXCESS RIR. X
FIGURE 6.10 SLOT CHANGES
48
-------
Figure 6.10 is a curve showing excess air (a variable which should
be unaffected by the slot changes) and giving an idea of the nonreproduc-
ible day-to-day fluctuations that were seen, especially at higher excess
air levels.
Two changes in the second stage air addition were made to deter-
mine the effect of mixing. The front slots were changed to add either
the second stage air earlier or later to the first stage combustion.
The side slots were changed to lower the mixing velocity of the air.
Figure 6.11 represents the effect of these changes:
Change in:
Front Slots Side Slots
No change: baseline air parallel to air perpendicular to
burner burner axis on 26-inch
diameter circle
First change air angled inward air perpendicular to
at 30 degrees burner axis on 13-inch
diameter circle, slot
area increased 50%
Second change air angled outward air perpendicular to burner
at 30 degrees axis on 13-inch diameter
circle, slot area increase
100%
The first change in slot geometry and size did not affect the NO
reduction. The second change did have some effect the change in
side slots and in front slots had the same effect. The difference
in NO reduction is not large.
Additionally, to compensate for differences in air velocity when
excess air was varied or staging occurred, the burner cross section
was modified twice to approximate constant velocity conditions.
Figures 6.12 to 6.15 show the effects of these changes:
No change or base line is 100% burner cross sectional
area or no change in burner velocity
49
-------
First change is a reduction of the burner area by 25%
and an increase in burner velocity of 33%
Second change is a reduction of the burner area by
50% and an increase in burner velocity of 100%.
The changes in burner velocity produced a minimum or no change in the
NO emission levels. The variation in day-to-day testing and experi-
mental variations observed in the NO emission levels were of the same
order of magnitude of any changes in NO emission due to the burner
velocity changes. As a result no significant changes in NO emission
levels were evident for changes in burner velocity. (See Figures D.43
to D.48 in Appendix D.)
Figures 6.16 and 6.17 illustrate the effect of load and stoichi-
ometry on the burner efficiency and carbon loss. These figures
indicate an interdependence of load and stoichiometry on carbon loss
and burner efficiency.
50
-------
o ~
z
z J
^ _
s
DC ~
rfr^
/
s
NO CHflNGE (BflSE LINE)
FIHST CHflNGE
SECOND CHflNGE
50 tOO IS
STOICHIOMETRY RT 'BURNERS. X
FIGURE 6.11 SLOT CHANGES - 15% AIR
1000-
2:
Q_
0_
500-
-1000 ppra
NO CHANGE (BflSE LINE)
FIRST CHflNGE
SECOND CHflNGE
-N
to
EXCESS flIR. 7.
FIGURE 6.12 BURNER CHANGES
51
-------
1000-
Q_
O-
500-
I
NO CHANGE (BASE LINE)
FIRST CHANGE
SECOND CHANGE
I
20 >io so
RflTE OF HEflT RELEflSE. KBTU/FT««3/HR
FIGURE 6.13 BURNER CHANGES
tooo
Q_
Q-
NO CHANGE (BASE LINE)
FIRST CHANGE
SECOND CHANGE
10 500
PREHEflT. °F
FIGURE 6.14 BURNER CHANGES - 15% AIR
52
-------
so-
o
UJ
oc
100-
NO CHRNGE (BASE LINE)
FIRST CHANGE
SECOND CHANGE
so
STOICHIOMETRY flT BURNERS. X
FIGURE 6.15 BURNER CHANGES - 15% AIR
ISO
100-
*
£
**
* . *
1
*
o-I25% LOAD
1 1 1
KX) BO MO
STOICMOMETMC. %
FIGURE 6.16 CARBON LOSS AND BURNER
EFFICIENCY
53
-------
100
£
I
oe
95
D
*
*
I
t
1
*
* *
'
*
*
1
*
% STOICWOMi
TRIG
-< 107.5
*- 107. 5 -125
1 - > 125
1
100
120 140
LOAD, %
160
FIGURE 6.17 CARBON LOSS AND BURNER
EFFICIENCY
54
-------
VII. COMPARISON OF PHASE I AND PHASE II RESULTS*
The data variables which are to be compared in this section are
shown in the following table:
Variables Phase I Phase II Phase I To be
(x if tested) Ohio Coal Colorado coal Natural Gas Compared
Excess Air x x x yes
Load (heat
release rate) x x x yes
Preheat x x x yes
Fineness x no
Swirl x no
Quench x no
Staged
Combustion x x x yes
Flue Gas
Recirculation x x x yes
Port Geometry x no
Burner Velocity x no
Each variable to be compared will be shown on a single figure and a
table of results will be given in the text. These tables of results
will be presented again, in duplicate form, in Section VIII, the
Discussion.
*The Phase I results for the Ohio coal and natural gas tests are
taken from the Phase I Final Report, EPA 650/2-74-002a. The
original data for Phase I used for comparison are in Appendix G.
55
-------
Excess Air (Figure 7.1}
The comparison of NO emission level dependency on excess air for
the three fuels follows:
Effect
Average Emission
(under standard
conditions)
Peak Position
(percent excess
Colorado Coal
Major
1100 ppm
1350 ppm
(35%)
Ohio Coal
Major
700 ppm
1000 ppm
(35%)
Gas
Strong
300 ppm
350 ppm
(20%)
air)
Variation from
Maximum to
Minimum Emission
Percent Variation
About Mean
+350 ppm +300 ppm
+65 ppm
650-1350 ppm 400-1000 ppm 220-350 ppm
The trends of the Colorado coal and the Ohio coal are qualitatively
identical - the absolute NO levels are quantitatively different,
however. Natural, gas shows a different qualitative trend with peak
NO emission levels at lower excess air.
Load (Figure 7.2, Rate of Heat Release)
The dependency of NO emission level on load or heat release rate
resulted in:
Colorado coal
Ohio coal
Gas
very strong effect; varied from 700-1150 ppm
under normal conditions
very strong effect; varied from 400-800 ppm
under normal conditions
no dependence; 300 ppm under normal conditions.
56
-------
The trends are almost identical for the two coals. The change over
the whole range of load is about 400 ppm for both coals. Again, the
trend for gas is different with the result that load is not a variable
for gas.
Q_
Q_
1000
COLORflOO COflL
OHIO CORL
NflTURRL G9S
I
I
T
EXCESS RIR. 7.
FIGURE 7.1 EXCESS AIR
20 40 60
Rfl.TE OF HERT RE.LERSE, KBTU/FT**3/HR
FIGURE 7.2 LOAD
57
-------
Preheat (Figures 7.3 and 7.4)
Figure 7.3, for normal excess air yields the following depen
dence:
NO Range, ppm
Fuel _ Dependence (Deviation about Mean)
Colorado Coal Slight 925-1050
Ohio Coal None 725 (-v0%)
Gas Strong 100-300 (^50%)
On a part per million basis, the gas is most dependent at about 50 ppm/
100°F slope to the line, Colorado coal is. next with about 30 ppm/100°F
slope, and Ohio coal is least dependent with 0 ppm/100°F slope. In
general, the coals behave similarly on a percentage change basis; on
a basis of quantitative change, no two of the fuels behave similarly.
At high excess air (Figure 7.4), the comparision yields the
following:
NO Range, ppm
Fuel _ Dependence (Deviation about Mean)
Colorado Coal Slight 1100-1350
Ohio Coal Moderate 750-1000
Natural Gas Strong 100-300
The three fuels behave identically on a quantative basis; the slope of
the lines is 50-60 ppm/100°F. On a percentage basis, the two coals
behave similarly.
58
-------
2:
Q_
Q_
OHIO COHL
T
soo
PREHEflT. °F
700
FIGURE 7.3 PREHEAT, NORMAL EXCESS AIR
1000-
Q_
Q.
O
500-
500
PREHERT. °F
700
FIGURE 7.4 PREHEAT. HIGH EXCESS AIR
59
-------
Flue Gas Recirculation (Figure 7.5)
The following results were observed for (secondary) flue gas
recirculation:
Fuel
Effect
Reduction of NO, %
(at 30% FGR)
Colorado Coal
(Ohio Coal
(primary)
Ohio Coal
(secondary)
Natural Gas
Little
Little
Moderate
Very Strong
M2% (extrapolated
<5% (at 5% FGR))
30%
85%
Natural gas NO emission levels are greatly affected by flue gas recircu-
lation. There is only a moderate effect on coal emissions at best.
50-
ID _
LU
oc
100-
FLUE GflS RECYCLED, 7.
FIGURE 7.5 SECONDARY FLUE GAS REC.
60
-------
Staged Combustion (Figure 7.6)
The results are:
Colorado Coal
Ohio Coal
Gas
%
Normal Firing:
Effect on NO
Maximum Reduction
Burner Air at Max.
Red., % Stoich. ^55
Substoichiometric:
Maximum Reduction, % 100
Burner Air at Max.
Red. , % Stoich.
Variable Port Position
Strong
70
Some Effect
(Not extended
to low burner air
for side ports)
Strong
60
^55
100
^60
Some Effect
(Max. Red.:
Side Ports 50
Front Ports 60)
Very Strong
90
100
^60
No Effect
*Unknown if maximum reduction occurs at 50% air.
The Substoichiometric curves for all three fuels are identical
- the NO emission level goes to 0 ppm at 60% stoichiometry.
The reduction of NO emission levels for two stage combustion of
all three fuels are similar between 60 and 115% stoichiometry at the
burner. Below 60% burner stoichiometry, natural gas does not show a
distinct valley in the curve at 50 to 60% burner stoichiometry. In
addition, gas shows a greater maximum reduction than the two coals.
61
-------
100-
1 " i" " i" " r "'
50 100 ISO
STGICHIOMETRY flT BURNERS. X
FIGURE 7.6 STAGED COMBUSTION
62
-------
VIII. DISCUSSION
The discussion section is divided into four sections. These
sections deal with the data results, special effects observed in the
testing, final data discussion, and possible correlated interrelation-
ships. The discussion presents the data as measured and interpreted.
A. Results
The effects of each variable studied were usually straight-
forward for the Colorado coal when surveying a single variable; the
simplest curve was drawn through the available data. These data were
usually taken at the extremes and middle of the range for each vari-
able; but in a few cases, only at the extremes of the range. In most
cases, if a straight line did not fit the data, a slightly curving
line did. It must be emphasized that in many cases the extremes of a
single variable are beyond the range of what is currently considered
acceptable operating practice. In addition, these results apply only
to a small single burner test unit. Even so, it is believed that the
trends will probably hold for large multiburner units, although the
magnitude of these changes may be appreciably different. Finally,
some of these variable changes may not be acceptable on large units.
In reviewing these results, it should be borne in mind that
NO emissions are due to a combination of thermal fixation and fuel
bound nitrogen conversion. During combustion of natural gas, only
thermal fixation of atmospheric nitrogen is possible since there is
no fuel bound nitrogen:
(1)
63
-------
(Only the overall formation is discussed here, not the mechanism of
formation.) In contrast, coal contains fuel bound nitrogen and an
additional source of nitric oxide is oxidation of this fuel bound
nitrogen to NO:
and *- j
N2 + O, +>'2 NO (1)
i. ,2 ,
2 R-N + O2 *-2 NO (2)
where R is the fuel portion of the molecule.
The kinetic form of these equations is given by:
from (1): ^°J- = kfj [N2][02] - k|.J [NO]2 (3a)
from (2): ^IIM = kf ^ [R-N]2[02] - k^ [NO]2 (3b)
where kf , , kf 9, k^ ,, and k^ 9 are of the form:
T,I T,t r,i. r ,t
kx = Ax (T)n e)l (3c)
(Note: by definition: k^ , = k /,)
> i r , c
It should be noted that the reverse reactions of (1) and (2) are
identical and therefore it is not valid to say:
[N0]total = [N0](1) + [N0](2)
if reactions (1) and (2) are considered separately. If this happens
to be true for a given case, it is simply coincidential .
64
-------
Excess Air
The results of the excess air tests show:
Effect
Average Emission
(under standard
conditions)
Peak Position
(percent excess
air)
Variation from
Maximum to
Minimum Emission
Percent Variation
About Mean
Colorado Coal
Major
1100 ppm
1350 ppm
(35%)
+350 ppm
650-1350 ppm
^35%
Ohio Coal
Major
700 ppm
1000 ppm
(35%)
+300 ppm
400-1000 ppm
M0%
Gas
Strong
300 ppm
350 ppm
(20%)
+65 ppm
220-350 ppm
^25%
The Phase I results, showed that there were significant
differences in the NO emission levels of gas and the Ohio coal which
are at least partially attributable to fuel bound nitrogen. Although
there are differences between the two fuels in flame temperature,
combustion rate, physical state of the fuel, and even gas velocities,
these differences would be expected to produce less change in NO
J\
than the fuel bound nitrogen. In particular, the difference in the
shape of the curve is expected to be a change due to fuel bound
nitrogen.
The NO emission from gas, the thermal fixation of atmo-
spheric nitrogen, depends upon temperature and excess air level. At
low excess air levels, the effect of increasing oxygen level more
than offsets the decreasing flame temperature, thus the curve ini-
tially rises. In addition, the flame can be more luminous at lower
excess air level; this can lead to more rapid quench rates. At high
excess air levels, the decreasing temperature becomes the overriding
effect and the curve drops after passing through a maximum.
65
-------
In contrast, the coal, which contains fuel bound nitrogen
as a second source of NO, shows both a different position of an NO
maximum which is shifted to higher excess air, and an increase in
formation of NO at all excess air levels. These differences are, at
least qualitatively, due to the fuel bound nitrogen. The trend thus
shown indicates a positive correlation between increasing fuel bound
nitrogen conversion to NO and increasing excess air. It is felt that
the fuel bound nitrogen conversion cannot be quantitatively evaluated.
(An additional factor is the apparent greater luminosity, and there-
fore greater rate of radiation, of the coal flame as compared to the
gas flame at low excess air. Also, the coal flame luminosity appears
to be insensitive to excess air level whereas the gas flame luminosity
is very greatly dependent upon excess air.)
The Colorado coal shows the same qualitative dependence
upon excess air as the Ohio coal. But quantitatively, the NO emission
levels from the Colorado coal are 25% to 50% higher than from the
Ohio coal. In addition, the Colorado coal had a different type of
flame structure than the Ohio coal. Under normal or high excess air,
the flame was clear, like a natural gas flame, and almost nonluminous.
Only at low excess air did the flame become similar to the large,
luminous Ohio coal flame.
The overall differences between the Ohio and Colorado coals
are:
1) Less luminosity of the Colorado coal flame
(this would be expected to cause the Colorado
coal to have a higher flame temperature than
the Ohio coal)
2) Higher (wet) Btu content of the Colorado coal
(this would also be expected to yield a higher
flame temperature)
66,
-------
3) Lower sulfur content of the Colorado coal.
The fuel bound nitrogen content of the Colorado coal is about the
same in quantity as the Ohio coal; both have ^1.1% fuel bound nitrogen
by weight.
The Colorado coal curve is the same shape as the Ohio coal
curve and so, qualitatively, the increase in the NO emission at any
given quantity of excess air was probably due to a change in the
conversion of fuel bound nitrogen to NO. This could have been due to
any or all of the following for the Colorado coal (as compared to the
Ohio coal):
1) The flame structure at higher excess air levels
indicated more rapid combustion due to shortened
flame; and probably with higher flame temperature,
at least momentarily during the initially more
rapid burning
2) The flame structure indicated more complete com-
bustion (as does the stack measurement of burner
efficiency) due to clearer flame and less carbon
emission in the flame
3) The Colorado coal could have a greater fraction
of the fuel bound nitrogen as a volatile nitrogen
content (as opposed to a nonvolatile slow burning
char content)
4) No. 1). 2) and 3) would imply a lower residence
time for the reduced fuel bound nitrogen con-
stituents in a reducing atmosphere and less
carryover of these reduced species
67
-------
The overall result could be 1) increased conversion of fuel bound
nitrogen to NO, due to lack of time for recombination to N2 or
reduction to N2; 2) higher rate of reaction of fuel bound nitrogen
fragments to NO, due to higher temperature; and 3) higher free radical
concentrations, as would be observed from the higher temperatures.
These conclusions agree with the NO levels of the Ohio and Colorado
coals which tend to differ less at low excess air where the flame
patterns tend to become similar. The staged combustion results also
indicate this since two stage combustion on the Colorado coal, although
giving somewhat greater percentage NO reduction than the Ohio coal
(60 to 75% versus 50 to 60%), tends to yield about the same absolute
NO emission levels, in ppm, as the Ohio coal when the flame patterns
are almost identical.
However, it may be argued that the increase of NO emission
level is due to thermal conversion of atmospheric nitrogen from the
higher flame temperature. This is definitely a contributor to the
higher NO emission level, but the question is, is it the major source
of NO increase? (The fuel bound conversion is not likely to be the
only contributor to the increased NO emission because the overall
increase is about 350 ppm at 35% excess air (1000 ppm versus 1350 ppm
absolute for the Ohio and Colorado coals respectively), and at a 1%
fuel bound nitrogen equivalence of 2300 ppm NO for total conversion,
this would indicate a 15% increase in the fuel bound nitrogen con-
version efficiency from the Ohio to the Colorado coal.) There are
three fundamental reasons for believing that the increase is not
primarily due to increases in thermal NO:
1) The shape of the curve does not show a dependence
on flame temperature between 20% to 30% excess
air (at constant flame luminosity) where a thermal
conversion peak would be expected. The shape of
the Colorado coal curve matches the Ohio coal
68
-------
curve and does not show an intermediate shape
between the Ohio coal and natural gas. For
natural gas, beyond 20% excess air, the lower
temperature at higher excess air levels indicates
stronger dependence on temperature than on excess
air --not the case for the coal curves.
2) The high NO levels from the two coals are not
unrealistic and would be compatible with a 25%
to 50% fuel bound nitrogen conversion to NO.
This would correspond to 600 ppm to 1250 ppm
for a 1.05% to 1.15% nitrogen coal. (This should
not be interpreted as a quantitative evaluation
of the fuel bound nitorogen conversion to NO. It
is a relative estimate only.)
3) The ineffectiveness of flue gas recirculation
indicates that this increase is not due to thermal
NO since the flue gas recirculation would have
been more effective for the Colorado coal than
for the Ohio coal since flue gas recirculation
reduces thermal NO significantly.
Finally, it cannot be ruled out that the change in NO is
A
due to a synergistic effect caused by the reduced sulfur content.
Some preliminary, unpublished results of other investigators indicate
that higher sulfur levels can lower NO emission levels. Although
this is a possible explanation for the difference in NO emission
levels for the Ohio and Colorado coals, it can be neither proven nor
disproven by the results of this study.
Load
The result of load change shows:
69
-------
Colorado coal -very strong effect; varied
from 700 - 1150 ppm under
normal conditions
Ohio coal very strong effect; varied
from 400-800 ppm under normal
conditions.
Gas - No dependence; 300 ppm under normal
conditions.
Again it should be pointed out that with the burner arrange-
ment used for these tests, both the air velocity through the burner
and the turbulence changed with load. However, there is no indica-
tion of a peak level having been reached under increasing load con-
ditions. (There is refractory shielding in the front half of the
furnace.) The two coals respond in a similar manner with identical
qualitative trends (the rate of change over the whole range is 450 ppm
for the Colorado coal and 400 ppm for the Ohio coal).
Preheat
The dependence of NO emission level on air preheat is inter-
esting. Normal conditions (15% excess air and 100% load) result in:
NO Range, ppm
Fuel Dependence (Deviation About Mean)
Colorado coal Slight 925-1050
Ohio Coal None 725
Gas Strong 100-300 (^50%)
and for high excess air and normal load:
Colorado coal Slight 1100-1350
Ohio coal Moderate 750-1000
Gas Strong 100-300 (fo50%)
70
-------
The indication from the natural gas is that thermal production of NO
is increasing at a rate of about 50 ppm per 100°F preheat increase
regardless of excess air level. This is determined from the total
change over the range of the curve for gas. This same type of
increase of thermal emission of NO should, but does not, occur for
the Ohio coal and for the Colorado coal. Both coals would be
expected to show the same effect on preheat by excess air as gas.
Since little is known of the local temperature history of the flames
any conclusions based on these observations would be very speculative.
t
The different dependence of the Colorado and Ohio coal
preheat curve slopes on excess air can be considered on either a ppm
basis or a percentage basis. The normal excess air to high excess
air responses of the preheat curve slopes for the Ohio and Colorado
coals are:
Slope of preheat curve Slope of preheat curve
normal excess air range high excess air range
%* ppm % ppm
Ohio coal +0 +0 +15 +125
Colorado coal +6 +65 ±10 ±125
The effect of the flame temperature change would probably explain the
different preheat dependence, for the two coals, especially at the
normal excess air level of 15% below which the flame color, shape,
and luminosity begin to change.
*Expressed as a deviation about the mean: i.e., in the previous table,
Colorado coal showed a range of 1100 to 1350 ppm at high excess air from
low to high preheat. The mean (straight line) is 1225 ppm and the
deviation about the mean is +_ 125 ppm (or ± 10%).
71
-------
Fineness
Fineness is not a major variable in our basic combustion
unit when comparing the excess air, load, or preheat as variables.
The slight variation curve for any one of the variables is less than
5% and less than the maximum error of measurement or reproducibility.
Flue Gas Recirculation
The following results were obtained for flue gas recircula-
tion:
Reduction of NO, %
Fuel Effect (at 30% FGR)
Colorado coal Little VI2% (extrapolated)
Ohio Coal, primary Little <5% (at 5% FGR)
Ohio coal, secondary Moderate 30
Gas Very Strong 85
Since the primary transport air for coal represents about 15% of the
total combustion air, a high level of primary flue gas recirculation
is not possible, even if a maximum amount of primary flue gas substitu-
tion is used. Primary flue gas recirculation did not significantly
lower the NO emission levels for the Ohio coal tests. For this
reason, primary flue gas recirculation was not run with the Colorado
coal. In addition, primary flue gas recirculation experience with
the Ohio coal resulted in decreased burner performance and ignition
problems. It is felt, however, that any reduction of NO on coal fired
units by use of this approach is relatively insignificant. The
effect of flue gas recirculation on the Colorado coal indicated
little or no reduction of NO emission levels. Addition of 10 to 15%
flue gas recirculation reduced the NO emission levels in the Ohio coal
by 10 to 15% and in the Colorado coal by 5 to 10%.
72
-------
The overall effect of flue gas recirculation (secondary
flue gas recirculation for coal) appears to be reduction of thermal
NO emissions as evidenced by the natural gas data. The effect of
flue gas recirculation on conversion of fuel bound nitrogen is unknown,
but the reduction of this component is probably minimal.
Staged Combustion
The results of the staged combustion data are as follows:
REDUCTION IN NO. %
Staging Test
Normal:
Effect on NO
Maximum Reduction
Burner Air at Max.
Red., % Stoich.
Substoichiometric:
Maximum Reduction
Burner Air at Max.
Red., % Stoich
Variable Port Position
Colorado Coal
Strong
70
^55
100
^60
Some effect
(Not extended
to low burner air
for side ports)
Ohio Coal
Strong
60
100
Gas
Very Strong
90
^50?*
100
^60
Some effect
(Max. Red.:
Side Ports 50
Front Ports 60)
No effect
The difference in the second stage port position was moder-
ately important for the Colorado coal firing tests. Although the
reduction of NO is not significantly different numerically at lower
burner to total air ratios** for the two slot positions, the visible
*Unknown if maximum reduction occurs at 50% air.
**The burner to (total) air ratio is defined as the weight of
air through the burner divided by the total weight of air into
the furnace.
7.3
-------
flame pattern indicated a low second stage combustion efficiency for
the side slots. In particular, a large cylindrical, highly turbulent
flame envelope surrounded a blacker carbon containing core. Carbon
became visible in the smoke from the stack. Therefore, only the
front slot, or "progressive combustion" data are used for discussion
of further results.
It should be noted that these staged combustion data were
obtained with fixed burner and slot openings. Thus, as the burner to
total air ratio decreased and staging increased, the air velocity
through the burner decreased and the air velocity through the ports
increased. It is for this reason that the performance and the effect
on two stage combustion was unsatisfactory at lower burner to air
ratios when using the side slots.
The greatest effect of staging was found with gas. Almost
all of the NO was eliminated by staging the gas combustion. (The
addition of flue gas recirculation can remove all or most of the
rest of the NO emission.)
Coal tests showed reduction of up to 60% of the NO emission
levels for staged combustion. An apparent maximum reduction of the
NO is reached at about 50% burner to total air ratio. This minimum
is not unexpected because it represents the diminishing return on the
reduction of the thermal NO precursors and conversion of the fuel
bound nitrogen in the first stage as contrasted to increasing thermal
NO formation in the second stage due to increasing enthalpy release
in the second stage combustion. In addition, it is possible that
significant amounts of fuel bound nitrogen fragments (such as HCN, CN,
etc.) may be formed which survive long enough to be oxidized to NO in
the second stage.
74
-------
An attempt was made to determine if a valley in the reduction
curve for coal emissions really exists at the 50%-60% burner stoichi-
ometry. Although the curve leveled out below 70% burner stoichiometry,
it never clearly indicated a rise from the curve valley again, even
down to 45-50% burner stoichiometry.
The substoichiometric tests for gas and the two coals, when
superimposed, are the same curve and intercept 100% reduction of NO
emission level (0 ppm NO) at 60% of stoichiometry. These results
seem to mean that both thermal NO formation and fuel bound nitrogen
conversion to NO under substoichiometric combustion conditions have
the same final precursors in atomic or free radical form such as NH,
N, etc. In other words, the reactions directly leading to NO are
independent of the source which provides these free radicals. In
addition, it would appear that there is a lower level of burner air
below which NO formation in the first stage drops to zero and it is
of no further use to decrease the burner to air ratio. Obviously,
this is a function of second stage geometry, spacing, gas temperature,
etc. Actual staged tests indicate that the residence time in the
first stage is really too short and a greater physical separation is
required between stages. If so, the burner area may not be the place
to add second stage air. An alternative might be to increase swirl
and mixing in the first stage, but increased temperature and com-
bustion intensity will result.
Slot Changes
Little or no effect on NO emission levels was observed for
the slot changes which were made. It would appear from observation
of the NO emission levels and the reduction of these levels that
there was no overall effect. However, two of these modifications
greatly affected the combustion patterns.
75
-------
The angling of the front slots outward had little effect
except to somewhat broaden the oblong shape of the flame. The inward
angling (the first change) showed an extreme change in flame pattern:
the first stage combustion was wiped out and a new long, circular
pattern of flame appeared. Apparently, the internal recirculation
zones of the first stage combustion extended up to and beyond the
intersection of the second stage addition of air and the burner air;
the result was loss of ignition at the burner and ignition held (by
hot wall radiation and new post burner recirculation patterns) at the
intersection of the two air streams. The combustion pattern showed
up as a new longer, lazier, single stage combustion pattern.
Both changes in the side slots involved a halving of the
radius of the "circle of air injection" for the second stage air. At
the center of the flame, the smokey core surrounded by a bright
firing halo disappeared and the overall flame became thoroughly
bright with little or no radial changes apparent.
In testing the effect of port position for staging, no
significant difference in NO emission levels from the side or front
ports was observed. All points were used to draw a single curve.
Burner Changes
The effect of velocity on NO emission levels was minimal.
The effect of velocity on overall excess air levels, load levels, and
preheat levels showed some slight variation, but this was less than
the error in the experimental measurement.
The effect of burner velocity on the staged combustion
tests was also unimportant. In general, it appears that velocity is
not a major variable in our basic combustion unit.
The flame patterns were usually unaffected by the velocity
changes.
-------
B Data and Testing Effects
NDIR/TECo
The NDIR and TECo instruments are very easy to use and
require only minimum maintenance. Both instruments or one instrument
and another independent method of NO measurement should be used at
the same time. Either instrument may slowly drift away from the true
NO measurement and require recalibration. An indication of some
problem is indicated almost immediately when the instruments do not
agree on an NO measurement. The most common problems encountered
were due to changing temperature in the furnace area where the
instrumentation is located:
1) Loss of the temperature controller on the NDIR and
subsequent drift.
2) Loss of calibration on the TECo due to increased
temperature and an increase in the dark current.
3) Loss of NO in the 34°F ice bath at the highest
excess air levels.
Any of these problems for either instrument is easily corrected if it
is recognized; during our testing all of these problems were easily
identified.
Temperature changes in the furnace room were unavoidable
and since the instrumentation was in the same area, it was inevitable
that these changes affected the TECo and NDIR. These changes were
.minimized by calibrating after the furnace was warmed up and the room
became hot.
Preventative maintenance eliminated almost all other problems
that had appeared in Phase I with the instruments. Whenever measure-
ments were made, the instruments had to agree within +_ 10 ppm or +_ 5%
Z7
-------
(whichever is larger) or a problem was suspected and the situation
corrected. Calibration checks were made several times a day and
usually no significant drift for either instrument over a single day
was noticed. When a drift was noticed it was usually due to one of
the three problems listed above and recalibration solved the problem.
The only gaseous interferent observed for either instrument
was HpO which absorbs infrared like NO when measured by the NDIR.
The presence of CO with NO does not reduce the NO measurement, even
when passed through the heated stainless steel coil used for the N02
conversion in the TECo.
It was noticed that the NDIR/TECo error is greatest at the
highest excess air levels. Inevitably, the NDIR read low when com-
pared to the TECo. In some cases this error exceeded 5% .and could
not be reconciled with any calibration checks. Recently some time
was spent working on this problem and the results were:
1) NO disappeared in the 34°F ice bath but not
A
to any large extent in the 50 F ice bath,
although the smell of M^ was present in the
50°F bath.
2) When the flue gas was replaced by air, there
was a "lingering, but decreasing" NO leyel
recorded on the NDIR and TECo from the 34°F
ice bath.
3) When the 34°F cold finger was opened, a strong
smell of N02 was present on wanning.
4) No increase of NO (from the 50°F ice bath)
was indicated by the TECo.
78
-------
It is suspected that at 34°F the glass surface may aid in oxidizing
NO to N02, especially at high levels of excess air where the oxygen
concentration is 7% (versus 3% and <1% at lower excess air levels)
and then N02 dissolves in the water of condensation to produce nitrous
acid:
H2O
NO + N02
11
N2°3
2 HN02
In addition, irreversible oxidation to nitric acid is also possible:
O2 + 2 HIM02 ^ 2 HN03
Whittaker (NO)
The Whittaker chemical cell NO monitor has shown unreconcil-
able differences when compared to readings from the NDIR and TECo
during most coal testing. It did not respond to the true NO levels
in the flue gas. Although it read correctly at times, it did not do
so consistently. When the reading was in error (greater than +
10% deviation), it always read a value higher than the NDIR and TECo.
This higher reading cannot be reconciled and it does not seem to
involve the following:
1) Calibration This was checked even before and
after bad measurements.
2) S02 - Fresh Malcosorb and calibration steps rule this
out because of the very rapid response.
3) C0/C02 -Test gases with these, even when
saturated with water, had no effect except at very
high concentrations of CO (>1% CO).
79
-------
The higher reading appears to be the result of some component in the
flue gas which is not taken out completely by the filters, water
bath, or Malcosorb. Substitution of Dynascience's "SCL Scrubber
Solution" in a normal bubbler did not remove the interferences in the
NO measurement either. The solution bubbler made the instrument
somewhat more erratic and the maximum errors in any single reading
seemed greater. The average error of all readings appeared to be
somewhat lower with the bubbler, however.
Fluctuation in Coal Data
From day to day, changes in the NO emission levels for
duplicate tests occurred. The causes of these changes are unknown.
The following suggestions have been made, but it is not known if
these even contribute to the problem:
1) Air temperature variations (no air preheat in
primary)
2) Changes in air humidity
3) Moisture variations in coal
4) Slight changes in fraction of total air
used for primary coal transport (changes
primary air to coal weight by a much
larger amount)
5) Changes in the coal, chemically, as day by
day slightly different grindings are used.
The magnitude of these changes is usually less than the
error of measurement (+_ 5%) but can sometimes become +_ 10%. It was
considered not to be a major problem however and was usually ignored.
80
-------
Carbon Loss
The carbon loss (as opposed to burner efficiency) from the
coal fired tests on our unit (there is no observable solid carbon
loss during oil or gas fired tests on our unit) is dependent upon the
excess air. The efficiency for the combustion of the Colorado coal
was above 95% and usually about 98%.
C. Final Presentation
Table 8.1 shows the final results for the Phase II studies.
This table is used to indicate the effect of each variable on NO
emission levels. The number of pluses or minuses is meant only to be
a relative indication of NO reduction.
D. Interrelated Variables
Some of the variables are interrelated and should be con-
sidered only in combination. (For example, see preheat and excess
air effect upon preheat as shown in Table 8.1.) In addition, many of
the variables studied could be defined by a new set of variables such
as enthalpy content,, temperature, velocity, etc.
TABLE ai RELATIVE EFFECTS ON NO IN THE FLUE GAS*
Phase II From Phase I
Under Normal Conditions
Increasing Level of
Variable Colorado Coal Ohio Coal Gas
Excess A1r ++++ -H-H- -H-/--
Load +++ 1111 0
Preheat (normal air) ++ o +++
(high air) +++ ++++++
Fineness 0 no data no data
Flue Gas Recirculation -
Staged Combustion / /
Slot Changes (added effect) 0 to + no data no data
Burner Changes (added effect) + to 0 no data no data
*+ Indicates increasing; number of +'s Indicates relative magnitude.
- Indicates decreasing; number of -'s indicates relative magnitude.
/ Indicates maximum or minimum is reached.
81
-------
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-------
IX. CONCLUSIONS
The following conclusions have been derived from the work per-
formed in Phases I and II for coal firing on the single burner test
unit:
1) There is a distinct difference in NO emissions
from the Ohio and Colorado coals attributable
to fuel bound nitrogen and possibly flame
temperature.
2) The conversion of fuel bound nitrogen increases
with increasing excess air level for both coals.
3) Air preheat affects the .coal NO emission levels
differently for different excess air levels.
The reasons for this are unknown.
4) A very small reduction of NO for the Colorado coal
and a moderate reduction for the Ohio coal for
secondary flue gas recirculation has been shown,
and apparently only thermally formed NO is
reduced.
5) A minimum of 60% burner air (total burner to 100%
theoretical air) for reduction of NO is indicated
for staged combustion of both coals. No further
first stage reduction of NO seems to occur at
lower percentages of burner air.
6) A definite physical separation appears to be
required for addition of the second stage air for
reduction of NO from coal combustion. Progressive
83
-------
mixing may be adequate. Even so, a separately
spaced second stage probably is better.
7) It appears that the same free radicals are
responsible for conversion of fuel bound nitrogen
and thermal fixation of NO in the final steps of
NO production under substoichiometric conditions.
8) It has not been possible in Phase II to determine
quantitatively what fraction of the NO is from
fuel bound nitrogen for either coal» About
10%-15% more of the Colorado coal fuel bound
nitrogen appears to be converted to NO than for
the Ohio coal.
The final conclusions to be drawn from the Phase I and Phase II
work shows that for coal testing on our basic combustion unit and
applicable to single burner units (no consideration of burner design
is attempted):
1) Thermal fixation/fuel bound nitrogen conversion
NO emission effects are different. Conditions
to reduce one source of NO are not the same as
those to reduce the other.
2) Flue gas recirculation does not show promise for
NO reduction in coal flames.
3) For existing units, excess air level shows the
most promising means of controlling flue gas
emissions of NO.
84
-------
4) For new units, staged combustion and total air
control show the most effective means of reducing
NO emissions.
5) The second stage air probably should not be added
with the burner air for greatest effect, but from
separate NO ports.
85-
-------
(This page intentionally left blank.)
-------
X. REMARKS (Recommendations)
The indications from the Phase I single burner work have been
reinforced by the Phase II single burner work. The most promising NO
reduction method for existing units without construction or costly
modification is control of excess air. This requires lowered excess
air, probably below 10%. Another method for new units is staged
combustion. Again the requirement appears to be a separate first
stage with reducing conditions prevalent. Since these concepts
require a change in overall utility design and manufacturing, there
will be a long period of development and testing required to demon-
strate the practicality of these ideas. Much of the problem will be
fears of increased corrosion (which may or may not be substantiated
in the future), increased carbon loss, decrease in burner stability
(which may or may not exist), slagging, etc. There is a need for
continuing research so that the anticipated problems either can be
shown to be nonexistent or can be solved by the utility and manufac-
turing people.
87
-------
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-------
APPENDIX A
FUELS DATA, ANALYSES, AND CALCULATIONS
A. Fuel Data
The coal used in all of our coal fired tests during Phase II was
a Colorado coal from the Bear Mine in Somerset Colorado. The time
lag for an analysis was at least 30 days from the time of submission
of samples. Therefore all calculations pertaining to stoichiometry
and load were carried out based on a prior, but recent coal analysis.
This analysis and the average moisture used in calculations are shown
in Table A.I. Although there was some variation in the moisture
analyses, the calculations were not corrected since any error was
considered smaller than the experimental measurement techniques.
The natural gas analysis used for the igniter is shown in Table
A.2. The analyses first used were averaged and all calculations
based on these numbers. Later, a new analysis was found and although
the molecular constituents were about the same, the density and Btu
value were different. However the new analysis was not used in the
calculations due to the small effect that the igniter gas would have
in the coal fired tests.
In addition to those analyses listed in Table A.I, other coal
fuel bound nitrogen and moisture analyses were also run. Below
follows the listing of these:
Coal
Date of Sample 2/13/74 3/18/74 4/11/74
Nitrogen, % dry 1.2
Moisture 4.9 5.3 5.6
89
-------
B. Fuels Analyses
No fuels analyses were done at B&W ARC for natural gas. All
values were reported to B&W by the Columbia Gas Company at regular
intervals.
All of the important fuels analyses for coal are shown below by
the method used at B&W ARC:
Moisture
ASTM by heating and weight
difference in samples
Btu
Total carbon
ASTM by bomb calorimetry
ASTM by collection of
in ultimate train
hydrogen
nitrogen
ASTM by collection of
in ultimate train
Kjeldahl distillation and
titration
sulfur
- ash
ASTM by bomb calorimetry
washings as BaSO.
ASTM by complete combustion
and residual weight
- oxygen
By difference
90
-------
C. Fuels Calculations
In the chemical description of the coal for mathematical purposes,
all weight percent contents including moisture were converted to atomic
percentages. The ash was considered to be Si02> An ash analysis
indicated large amounts of Al^O., and Fe^O., and so the Si02 was a good
average in molecular weight between A10, 5 and FeO-| 5- The fuel
values on conversion showed the following atomic ratios for chemical
balance at stoichiometric conditions:
Colorado coal
(wet)
- C = 1.0000
H
N
S
Si
0
0.91614
0.01408
0.00564
0.02680
0.19563
Stoichiometric Air
(dry)
N = 8.6808
0 = 2.3273
Natural gas -C = 1.0000 Stoichiometric Air - N = 14.639
(dry)
H = 3.8851 0 = 3.9267
N = 0.0087
0 = 0.0158
(For reference, the following are included:
Ohio coal
(wet)
- C = 1.0000
H
N
S
Si
0
Stoichiometric Air
(dry)
0.94309
0.01328
0.01504
0.03519
0.24269)
N
0
9.1830
2.3294
9.1
-------
The theoretical air requirement for the coals and gas above
yielded a curve of excess air versus oxygen concentration in the flue
gas after combustion had taken place. Suitable curves were chosen*
rather than calculating each case separately. The curves chosen are:
Either coal: If
0.0 £% 02 £ 2.5102
Then PTA = 100 + 4.7279 (POP)
If
2.5102
Then
PTA = 100 + (POP) + (POP)
Gas:
If
If
0.0 < % 02 <_ 2.4588
Then PTA = 100 + 4.7279 (POP)
2.4588
Then PTA = 100 + \ (POP) + \ (POP)'
where: PTA = % theoretical air
and POP = % oxygen as measured in the
flue gas
*Useful Tables for Engineers and Steam Users, llth Ed., 1969, The
Babcock & Wilcox Company.
92
-------
The two sizes of Colorado coal used in the fineness tests were:
Percent through
30 mesh
50
100
140
200
270
375
Coarse (Series VII, IX,
X, XI, and XII)
99.6
98.5
91.8
81.5
70.0
58.8
50.0
Fine
(Series VIII)
99.7
99.2
98.5
96.1
91.6
85.2
76.8
The coarse pulverization was used for all Colorado coal tests except
Series VIII.
TABLE A.1 COLORADO COAL ANALYSIS
B&W Lab
Serial No. C-13864
Date 2/11/74
% Volatile
Fixed Carbon
Ash 9.8
% Total Moisture 4.4
Btu/lb, Dry 12980
Ultimate. Dry %
C 73.1
H 5.1
N (determined) 1.2
S 1.1
Ash 9.8
0 (difference) 9.7
Average
3/5/74 2/13/74
4.1,5.2 4.9
00
4.65
C-13864
3/17/75
38.5
52.6
8.9
3.3
93
-------
TABLE A.2 NATURAL GAS ANALYSIS
Type Columbia Gas Transmission Corp Average of
Pittsburgh Group, Steubenvllle three groups
Date 12/20/71
Mole %*
N2 0.47
C02 0.72
CH4 95.01
r u i 10
Long 0. 13
C3H8 °'41
C4H1Q 0.15
CgH12 0.05
C6H14*
p(calc.) °'5864
Btu (calc.) 1038.7
*Sulfur bearing materials
the calculations.
TABLE
6/21/71
0.40
0.97
95.57
2.63
0.30
0.10
0.03
0.5835
1029.0
were small
A.3 OHIO
1/23/71
0.49 0.45
0.77 0.82
95.08 95.22
2.93 2.92
0.49 0.40
0.19 0.15
0.05 0.04
0.5872 0.5857
1038.1 1035.3
and therefore not entered
COAL ANALYSIS
New Analysis
(Not Used)
12/18/72
0.40
0.78
95.84
2.54
0.30
0.11
0.03
--
0.5814
1030.5
into
COAL ANALYSIS DATA
B&W Lab C-13688
Serial No.
Date of Sample 4/20/72
% Volatile 38.6
Fixed Carbon 49.4
Ash 12.0
% Total Moisture 5.7
Btu/lb, Dry 12290
Ultimate, Dry %
C 69.1
H 4.8
N (determined) 1.1
S 2.8
Ash 12.0
0 (difference) 10.2
C-13689
5/9/72
38.1
48.7
13.2
6.4
12020
67.9
4.6
1.0
2.7
13.2
10.6
C-13692 Average
Used in
Calculations
5/15/72
39.6
49.2
11.2
6.3 6.13
12410 12240
69.7 68.9
4.9 4.77
1.1 1.07
2.8 2.77
11.2 12.1
10.3 10.4
C-l 3762
(Not used
1n Average)
1/18/73
5.4
72.8
5.0
1.1
--
7.6
94
-------
APPENDIX B
OPERATING CONDITIONS, MEASUREMENTS, AND CALCULATIONS
A. Operating Conditions
Before any data runs for a day's testing commenced, the furnace
was warmed up and all instruments were calibrated. The furnace
warmup period was at least one half to one hour. During this time,
all instruments were zeroed and calibrated with at least one standard
gas.
The NO instrumentation was checked with at least three or four
.A
Matheson gas standards of ^200, ^500, ^800, and M300 ppm NO in
nitrogen. As standard tanks of gas neared the point of being empty,
new standards of the same concentration were ordered with a certified
analysis. These new standards were checked against the old ones to
verify the analysis before use as calibration gases.
The standard operating conditions selected for our basic com-
bustion tunnel were 115% theoretical air, 600 F preheat for the
secondary air, and a 5,000,000 Btu (5 MBtu)/hour load or heat release
rate. During all coal tests, the natural gas igniter was operated at
three Ib/hr and a heat release rate of about 70,000 Btu (70 kBtu)/hr.
B. Calculations
The orifice calculations used are based on the ASTM Fluid Meter
Report, 1940. The important equations are:
,2
W = 358.9 (DjT KEY v/Ptrue AH
95
-------
where:
KEY = 0.935 (0.7 - D1/D2)5/4 + D^
and
273.16 (Pnet)
ptrue = °-0741 0.55556 (T + 459.67)
For all inlets the air calculations for the furnace firing reduce to:
u - K / (PS)(AH)
w N VT + 459.67
Where:
Dry air inlet description D-, Dp K, a constant
Primary air 2.25 4.00 7028.
Secondary air 7.0 12.0 68689.
Secondary flue gas 5.0 12.0 33601.
Second stage air 4.5 8.0 28110.
The addition of humidity in the air is easily accomplished:
<<>H2o>(p
~~ W_ .
'H20 "airy lPalr)(PSa1r)
PSH.O
= W . /0.62133
air
96
-------
Where:
WH 0 is the weight of water in Ib/hr
and
W3. is the weight of air in Ib/hr (previously calcu-
a i r
lated above)
The ash sampling probe also reduces to the same type of equation
whereby D, is 0.625, Dp is 1.5, and K is 525.3. For the natural gas
igniter, the orifice equation is:
10p0(0.61278 + log(NF)) . 21.3480(0.0072527 AH + P.)
U =
w ;(T + 459.7)
Although the form is awkward, it shows the flowmeter/orifice
constants.
97
-------
APPENDIX C
PRELIMINARY TEST DATA
The preliminary data is presented in the tables on the following
pages. Six series of tests were run. Each series of tests is
described by four tables. The series of data are:
VII. Base line Colorado coal tests (included substoichiometric
tests)
VIII. Fineness tests with Colorado coal
IX. Flue gas recirculation for Colorado coal (secondary
FGR only)
A. Base line (no FGR)
B. FGR
X. Staged combustion tests with Colorado coal
A. Base line (no staging)
B. Staged
XI. Slot changes with Colorado coal
A. Base line (original configuration)
B. Change #1
C. Change #2
XII. Burner changes with Colorado coal
A. Base line (original configuration)
B. Change #1
C. Change #2
The table headings are discussed below also:
99
-------
Table 1 - Furnace input data in pounds per hour for the natural
gas igniter, fuel, primary air (used as transport air
for coal only), secondary air, second stage air, and
flue gas recycled. (The two numbers for VII-1, fuel
are 428/448 and are respectively the fuel weight dry
and the fuel weight with normal moisture.)
Table 2 - Total amount of air, in percent of stoichiometric; the
heat release rate in 10 Btu per cubic foot per hour;
the total, averaged gas preheat for all air and any
recirculated flue gas; the weight percent of flue gas
recycled; and the percent of stoichiometric air which
enters through the burner (primary and secondary summed
together).
Table 3 - The three NO instrument readings in ppm NO reduced to
/\
3% oxygen and dry for the Beckman NDIR, TECo chemi-
luminescence, and the Whittaker chemical cell; the
average of the NDIR and TECo expressed as ppm NO +_ the
standard deviation of the average; and the conversion
of the ppm NO to pounds of NO (not N02) per million
Btu input as fuel Btu only.
Table 4 - The humidity and barometric pressure in mm Hg; the un-
corrected ("raw, as recorded") concentration of oxygen,
carbon monoxide, sulfur dioxide, and carbon dioxide;
and the ash loadings as weight percent of ash in the
flue gas (pounds of ash per hundred pounds of flue gas)
and weight percents of carbon and nitrogen as found in
the ash (pounds of total carbon and total nitrogen,
forms undeterminable, per hundred pounds of ash).
1_QO
-------
TABLE C.I SERIES VII - COLORADO COAL.
FURNACE DATA (INPUT)
TABLE C.2 SERIES VII - COLORADO COAL.
FURNACE DATA (FINAL)
II OIICIUl. II IB. / M. lOfl HI. / HIT HI. I
II SOIES II IMITfl
II or win li lusi
1 1
II
1 1 ₯1
II VI
II »l
1 1 VI
II VI
II VI
II VI
II VI
II VI
II
II VI
II VI
II VI
II VI
II VI
II VI
II VI
II VI
II VI
II VI
II
II VI
II VI
II VI
II VI
1 1 VI
II VI
II VI
-
-
~
_
_
.
-1
-1
-1
-1
_1
-1
-1
ii
M
II
II
1 1
II
II
II
II
II
II
II
II
II
II
II
II
II
II
-11 II
20 II
II
-11 II
-22 II
-21 II
-2* II
-29 II
-26 II
-27 II
II VII -11 II
FUEL
~~~
421 444
261 274
221 212
97 3/6Q 1
411/414
410/41Q
411/411
414/414
416/417
547/574
527/552
496 520
413 494
416 437
405 429
541 967
546 971
519/549
2T6/290
266/279
261/274
452/474
426/446
P*|NA«V
m
590/648
545/6O9
549/994
609/650
611/651
619/660
626/669
604/643
611/652
674/713
675/742
667/726
569/647
545/651
596/653
674/730
661/722
661/724
Si 6/551
514/550
519/591
606/646
606/644
SecONQART
AIR
5137/S438
2510/2709
1754/1901
5867/6269
1529/1762
1109/1120
2509/2476
2395/2S14
2102/2244
5474/5950
6516/T171
4162/4764
4205/4715
5159/5649
396O/1910
5440/4900
5461/5794
6180/6768
3392/3583
2507/2664
2167/2302
4397/4685
3746/3994
2ND STI
AIR
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
O/
II
II
II ORIGINAL II TOTAL
II RUN MO II AID,
|| Of HUNS II
II II
II
M
II
II
It
II
II
II
II
II
II
II
II
)|
M
II
II
II
II
M
II
II
II
||
II
II
II
M
II
II
II
- i li m.
- 2 II 111.
- 3 II 101.
- * II lit.
- 5 II 1**.
-6 || 104.
-7 M US.
- a II 102.
- 9 II 92.
-10 II 7T.
I |
-11 ii 72.
-12 II 66.
-13 II US.
-1* II 140.
-15 M 101.
-16 || U*.
-IT II 141.
-la M »04.
-19 II IIS.
-20 II US.
II
-21 II U.
-22 1 1 42.
-29 II IS.
-24 1 1 04.
-25 II 1».
-26 | | 1).
-27 1 1 42.
-28 II M.
-29 1 1 04.
NfAf,
MTU/
/ MR.
49. S9
SO
46
30
29
2S
66
47
45
4S
4S
'63
61
56
46
45
43
56
59
56
SO
2ft
2B
11
52
5|
99
.40
7T
9*
26
06
19
69
24
21
66
66
98
T4
19
90
76
66
54
40
10
6T
14
a*
22
12
42
64
02
89
GAS II FLUE CAS
ntf- ii ifcrcifo
DEC. F II ttt
~~ II
60ft II 0.0
615 II 0.0
549 1 1 0.
546 1 1 0.
570 1 1 0>
500 1 1 0.
620 1 1 0.
485 II 0.
574 | 1 0.
942 1 1 0.
II
517 |l 0.
520 li 0.
622 1 1 0.
611 1 1 0.
602 1 1 Q.
296 1 1 0.0
296 1 1 0.0
285 II 0.0
266 II 0.0
29O II 0.0
II
269 || 0.0
285 II 0.0
279 I) 0.0
270 II 0.0
556 1 1 0.0
621 II 0.0
61T II 0.0
611 II 0.0
600 II 0.0
111 AT II
ftUMU II
II
ii
M
111.0 II
1W.O II
101.9 II
119.1 II
1*6.1 II
105.0 II
119.6 II
101. II
M. II
n. li
II
n. II
66. II
111.0 II
1*0.0 n
101.6 II
11*.» II
161.0 II
10*. 6 II
III. 6 II
111.0 II
II
Ill.t II
162.0 II
119.0 II
106.0 II
111.6 II
111.0 II
IU.O II
116.0 II
106.9 II
TABLE C.3 SERIES VII - COLORADO COAL,
NOX MEASUREMENTS
TABLE C.4 SERIES VII - COLORADO COAL.
OTHER MEASUREMENTS
U Sf
1 1 PU
t»
.11
1 1 vi
II v
II v
II v
M v
ll-v
M v
II v
II VI
II
II VI
II vt
II VI
II VI
II VI
M vi
II VI
If VI
1 1
II VI
II VI
II v
II v
1 1 v
II v
II v
II VI
IFS -
i fl-S
- 1
- 2
- 3
- 9
- 7
- t
-10
-11
-13
-14
-16
-17
-IB
-1«
-20
-21
-22
-23
-24
-26
-27
-28
-29
1
1
I
1
1
I
1
SI
1»
«1
57
OS
99
7*
32
08
C9
69
24
17
32
C9
?2
61
66
C9
65
50
50
99
C7
69
91%
1212
f>4»
100S
sis
1071
6*1
518
2 Oh
2
1 02
t 2
t *&
1
3
2
3
6
2
17
10
72
107
5
1
1
9
t 1
3
9
I0'*6 «TU
O.Qb ± .
USl t .
0.59 i .
1.Z3 1 .
0.*T i .
I .0« * .
0.60 * .
0.** z
0.1* i .
0,07 t
U21 t *
1.67 ± .
0.94 * .
1.35 * .
0.54 1 .
0.96 * .
0.90 1 .
1.23 1 .
1.03 £ .
0.65 1 '
0.40 * .
1.04 t
l.«9 t .
1.51 t
O.TB ± .0
1 1
1 1
II
* 1 1
1 1
* N
1 II
2 1 1
1 1
1 1
II
II
II
II
M
II
II
It
II
II
II
M
II
M
II
II
II
tl
1 II
WIGI1U
!.--!lL.
:
:
-
-
-
-
'_
-
:
-2
UM.
HI
1.6
2.4
1.1
S.2
S.4
9.4
9.4
0.3
0.9
1.5
*.*
.
5.9
5.2
4*6
II 4.6
II 4.6.
BAD. || 0?
t-CTt II
TT
1 1
725 II *.«
72* || 0.5
T27 II I.I
735 1 1 0.6
73S II 0.0
II
71
-------
TABLE C.5 SERIES VIII - FINENESS - COLORADO COAL,
FURNACE DATA (INPUT)
II OMCIKAl II
II RUN < AXO II
II SfHlll II
1 1 or RUNS 1 1
!! .,-
II nu-
ll VIII-
II VIII-
II VIII-
II VIII-
II VIII-
II VIII-
II VIII-
II VIII- 1
II VIII- 1
II VIII- 1
II VIII- 1
II VIII- 1
II
1 II
II
II
II
II
II
II
II
II
II
II
II
II
II
Lf. / M. IMV VT. / Hf T VI
IGNITER
(MSI
1.1
1.2
1.4
9.4
1.4
1.2 '
1.2
1.2
1.2
1.2
1.2
1.2
Futl | MINMV
1 AIR
494/471
494/470
442/464
419/496
2B2/296
2T1/2B6
276/2*9
496/4T*
42V490
330/396
4M/461
450/472
410/410
622/699
616/691
62W666
61T/674
Iff/620
979/610
61T/6f6
624/674
666/711
613/634
611/691
621/664
SfCOMMKV 1
l> 1
4479/4773 1
4664/4722 1
M92/61U 1
1792/1972 1
2600/2738 1
3324/3740 |
4469/4741 1
3827/6191 1
441T/4T12 j
9404/5787 |
4966/4697 1
9701/6069 1
1910/1761 |
mo s»ct I n.« II
AIR | US II
O/
01
01
01
01
01
01
01
01
01
01
\ II
1 f II
1 0 II
1 0 II
1 0 Ii
.1 0 II
1 0 II
1 0 II
1 0 II
1 0 II
1 1248 ||
1 II
1 0 II
1 0 II
! .11
TABLE C.6 SERIES VIII - FINENESS - COLORADO COAL,
FURNACE DATA (FINAL)
II ORIGINA
II RUN « A
II SERIES
II OF >IM
II
II VIII.
II VIII-
II VIII-
II VIII-
II VIII-
II Vlll-
II Hi-
ll VIII-
II VIII- 1
II
II VIII- 1
II VIII- 1
II VIII- 1
II VIII- 1
1 1 TOTAL
<0 II HI,
II I
t II
II
II 115.0
II 113. T
II 10J. 6
II II*. 3
II 102.9
II 190.9
II 114.4
II 144.1
II 119.9
II
II 117.0
II 115.6
II Ul.O
II 102. T
HEAT,
KBTU/
FT**»
/ MI.
52.97
52.47
49.41
32.34
)1.0«
33.09
32.90
94.86
91.64
61.78
47.61
49.20
44.01
GAS II FLUE GAS
ME- II RECYCLED
HEAT || TO IHFUT
OEG. F II III
II
610 II 0.0
61! || 0.
942 1 1 0.
$91 II 0.
930 1 1 0.
983 1 1 0.
610 II 0.
629 || 0.0
621 II 22.2
II
620 II 0.0
291 II 0.0
It! II 0.0
2TO || 0.0
AIR AT II
BUPWER II
HI II
II
II
119.0 II
113. T II
102.8 II
114.9 II
102.9 1
190.9 1
114.9 |
144.1 1
119.9 |
II
117.0 II
119.6 II
143.0 II
102.7 II
TABLE C.7 SERIES VIII - FINENESS - COLORADO COAL,
NOx MEASUREMENTS
II nntciNAi || OPM NIIX 3t 02. oftv II PPM NOX IN , IB. NOX /
II StftltS - M M DRY. 31 02 1 10**6 BTU
1 1 DUN «-S | 1 1DIR | TECO
II II
II Vll
II Vll
II vll
II Vll
II VII
1 1 VII
II Vll
M Vll
M VII
II VII
II
It vll
II vll
II VII
II VII
-
-
-
_
-
-
-
- 1
- 1
- 1
- 1
II 1CC2
1 1 1096
il 12*2
1 1 MB
1 1 796
1 1 552
II 1 1 52
II 105H
II 1248
1 1 965
1 1
1 1 1224
1 1 861
II 1011
II 631
1065
10*>l
1326
716
776
527
1134
1115
1350
939
1227
DM
1016
604
>H|T || FLUE GAS 1 INPUT
1 1 1
1C57 | | 1044 J 58 | 1.03
10*4 M 1094 t 4 I 1.1*7
1297 | | 1309 i 24 | 1.64
7?3 || 727 1 If. | 0.65
74) | | 78* * 14 | 0.77
*6l || 531 » 14 1 0.48
1151 1 1 1141 i 11 1 1.4$
109Q | | IQ86 i 41 | 1.U7
1254 | | 1299 t 72 | 1.56
924 | | 962 t 33 | j .00
II 1
1155 || 1226 1 2 1 1.24
551 || flS6 i 7| 0.86
100? 1 I 1014 t. 5 | 1.21
621 II 617 19 | Q.55
.0*
0
.03
'.01
.01
.02
.02
.04
.09
.03
.0
.01
.01 1
.02 1
TABLE C.8 SERIES VIII - FINENESS - COLORADO COAL,
OTHER MEASUREMENTS
tmiGiNA
SCBIFS
mi* «-S
VI 1 1-
vin-
vl II-
vlll-
viH-
vin-
viM-
₯111-
vlll-
II vin- i
1 1
II vin- 1
II VIII- 1
1 1 vlll- 1
II vin- l
1 1 M
II 1
1 1 v
tt
1 1
H
II
1 1 *
M
II
II
1 1
II
M
II
1 1
U
M
1 1
II
N.
61
Tl
.6
.-1
.3
.3
.6
.6
.6
.ft
.4
.3
b.3
i,.e
S.I
1.1
HA"
|MN
t>ET
73
73
76
76
76
73
71
73
Tl
71
73
73
73
73
I |
II
1 1
-++-
1 1
II
| |
1 1
M
II
M
II
II
II
1 |
M
1 1
1
t
.
.
.
.
.
1 »pu
1 CO
60
too
60
2150
150
1700
100
150
8
90
100
105
90
475
PPM
S02
67
675
540
790
650
00
25
00
10
40
700
1125
900
1250
C02 II AS*
tilt
II
M
II 0.45
II
- 1 1
_--- 1 1
M
- 1 1
-' 1 1
- || -*.
, | |
_. | | _ -
II
| 1 0.45
_." M --
1 1
II 0.65
C IN
ASH
f
13.3
-
__--
----
-
__--
-
3.3
«
31.*
N IN II
ASH II
X 1 1
II
II
1 1
- 1 1
1 1
1 1
1 1
- 1 1
- 1 1
- 1 1
- 1 1
It
- 1 1
1 1
1 1
TABLE C.9 SERIES IX - F. G. R. COLORADO COAL,
FURNACE DATA (INPUT)
TABLE C.10 SERIES IX - F. G. R. COLORADO COAL,
FURNACE DATA (FINAL)
II OD1GINAI
1 i RUN AND
1 1 OF RUNS
II
II IX A - 1
II m * - 2
II ix a - 3'
II ix a - 4
II IX A - 5
I
i
1 tc*si
1
1 3.1
i ,:r
1 3.1
1 3.1
IB.
454/4 Tt
317/332
496/478
452/474
HB. (Oft
AID
605/64(i
51A/551
*4r4
II
II IX A
M U A
M IX H
II IX B
i
2
3
4
HUB 5
II
1 |
*t
II
M
II
II
M
1 1
NOIR i TECQ i
T 1"
1 1
1010
fl06
)tO
B6B
7(2
102T |
«lh 1
97ft |
9J6 |
776 |
HIT
flSO
726
fttfi
IRQ
«54
II
I |
T+
1 1
M
II
II
1 1
1 1
oov.
FLUt
1016
«11
<)66
866
7.70
)( 02
GAS
± 12
± T
1 U
1 23
! 11
1 10**6 tf
1 INPUT
1
1 0.99 *
1 O.fll Jt
1 0.94 i
1 0.65 1
1 0.77 1
TU 1 1
| |
ft
II
oi II
.01 | |
.01 II
.03 M
.01 | 1
TABLE C.12 SERIES IX - F. G. R. COLORADO COAL,
OTHER MEASUREMENTS
II ORIGINAL | | HUM.
I I HUN »-S I | NET)
II II
tl IX * - 1 || 6.2
(I U B - 3 || 5.5
II ix a - 4 || 5.0
II IX B - 5 M 10.)
B" . II 02
he T 1 II
1 1
737 II 2.
737 !, 2.
737 | | 2.
737 II 2.
PPM
120
240
130
30
PPM
500
400
590
550
CO? II AS"
II
U
II
II
M
1 1
C IN
X
N IN H
X M
II
II
II
M
1 1
II
102
-------
TABLE C.13 SERIES X - STAGING COLORADO COAL.
FURNACE DATA (INPUT)
TABLE C.14 SERIES X - STAGING COLORADO COAL.
FURNACE DATA (FINAL)
I a
1
1
I
>*--
1
I
1
1
1
1
I
II
I
1
1
I
I
i
I
i
I
I
I
UN A*D M - "
OF RUNS 1
-t
1
1
1
1
1
1
1
1
I
1
- 11
- 12
- 14
- 17
- 19
- 21
- 31
- 41
- 42
- 43
- 44
- M
- 33
- 54
- *7
1 ICA
1
1 1.
1 3.
1 3.
1 2.
1 3.
1 1.
1 3.
1 3.
>.
3.
2.
2.
3.
2.
2.
2.
2,
3.
t
404/423
430/431
*21/*42
I*
590/6)6
601/671
602/647
AIR
2079/2244
lbl6/lT58
3336/3938
IR32/1967
»fq
if
2301/2491
2869/3093
920/1026
2134/2331
1134/12*0
II
II
GAS II
II
II
II
II
II
II
II
M
M
I |
H
H
1 1
1 1
II
II
II
II
1 1
II
II
1 1
II
II
1 1
II
1 1
II
II
II
M
1 1
II
M
1 1
II
1 1
II
i i
n
1 1
1 1
1 1
1 1
M
M
II
II
II
II
n
M
n
n
n
n
1 1
1 1
n
1 1
n
H
II 11
II «
II
Ji~
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
1!
1 1
II
II
II
M
II
M
II
M
M
II
MGINAL ||
UN f AND ll
3F IIJNS II
II
- 1 II
- 2 II
- * II
- s ii
- 6 II
- 7 ||
- 8 II
- 9 ||
- 10 II
II
- 11 II
- 12 II
- 11 II
- IS ||
- 16 II
- 17 M
- 18 II
- 19 ||
- 20 ||
II
- 21 II
- 21 II
- 23 ||
- 27 ||
- 28 ||
- 29 M
- 30 M
31 II
- 32 H
- 33 II
- 34 II
- 33 ||
- 36 H
- 37 M
- 38 ||
- 39 ||
- 40 (|
II
- 42 II
- 43 M
- 44 ||
- 43 ||
- 46 ||
- 47 H
- 48 ||
- 49 (I
- 30 ||
M
- 51 ||
- 52 ||
- 53 M
- 54 ||
- 53 II
- 56 II
CTAL
In*
Cl.
16.
48.
Ill
14.
13.
14.
21.
15.
14.
13.
47.
14.
04.
19.
44.
03.
13.
44.
39.
14.
11.
16.
19.
19.
13'
17.
12.
20.
32.
26.
21.
28.
20.
30.
40.
52.
03.
04.
17.
19.
18.
15.
18.
18.
47.
HfAT.
/ MR.
14.13
38.41
19.61
32.42
51.95
SO. 93
31.17
31.32
31.17
34.62
51.72
3l.4fl
52.82
37.10
46.21
60.99
14.4?
13.17
14.82
19.06
39.30
51.7?
32.50
47.63
46.61
48.46
47.16
44.72
45.27
48.10
41.0T
41.9}
44.4ft
41.15
4B.89
48.41
52.03
46.31
44.41
42.36
39.7)
45.27
44.33
43.46
44.17
12.9)
CAS i i FLU{ CAS
OEC. F 1 1 <*l
II
353 1 1 0.
380 1 1 0.
620 1 1 0.
610 II 0.
615 II 0.
394 1 t 0.
347 || 0.
«19 M 0.
610 1 1 0.
641 | | 0.
603 1 1 0.
622 | | 0.
387 1 1 Q.
630 1 1 0.
596 1 1 0.
1 1
63* | | 0.
290 1 1 0.
3)7 || 0.
3H3 II 0.
606 1 I 0.
632 II 0.
593 1 | o.
II
620 | | 0.
629 | | 0.
639 | | 0.
621 II 0.
636 ( | 0.
629 || 0.
634 | | 0.
603 1 1 0.
385 1 1 0>
II
606 | 1 0.
606 | | 0.
611 II 0.
392 | | 0.
384 M 0.
391 | | 0.
606 | | 0.
388 | | 0.
604 | | 0.
627 || O.C
II
276 M 0.0
279 || 0.0
281 II 0.0
279 (t 0.0
203 II 0.0
AIR AT ||
RUMMER 1 1
II
II
03.4 M
16.3 II
48.1 ||
12.3 ||
13.7 M
14.) -||
13.0 II
II
14.3 ||
21.8 II
13.1 II
14.3 II
13.7 ||
47.2 II
14.3 II
04.1 | |
II
19.2 II
44.1 II
7B.4 II
94.) ||
67.7 II
117.2 II
fti.l M
104.4 1)
II
72.1 II
62.4 ||
94. II
96. II
70. II
58. II
45. II
109. II
107. ||
I)
7«. 1 II
66.9 II
96.2 II
«.7 II
106.2 II
106.4 II
70.2 II
80.2 II
99.9 II
«.7 II
II
87.9 ||
*a.9 n
89.8 II
63.0 II
88.1 II
1Q3
-------
TABLE C.15 SERIES X - STAGING COLORADO COAL.
NOX MEASUREMENTS
TABLE C.16 SERIES X - STAGING COLORADO COAL.
OTHER MEASUREMENTS
II UftlGlNAL II " SUM )f 02. 0»Y II PPM Nnx !»
|| RUN -* || HO IB | TECO MI IT II
U II
II
II
II
1 1
II
II
II
II
1 1
II
II
II
j j
II
II
1)
II
II
II
II
J
I
1
1
I
t
1
t
1
1
1
1
I
I
1
1
1
1
1
!
1
1
I
1
1
I
1
t
I
1
1
1
1
I
I
1
1
1
1
- 1 II
- 2 It
- 3 | |
* 1 1
- * 11
- 6 ||
- 4 ||
- 9 ||
II
- 11 M
- 12 tl
- 13 II
- 1* II
- 15 1 1
- 16 1 1
- 17 ||
- 18 ||
- 19 tl
- 20 | |
1 1
- 21 II I
- 23 It
- 2* | |
- 27 ||
- 28 M
- 30 ||
II
- M I |
- 12 ||
- 33 | |
- 1* M
- 35 ||
- 16 | |
- 37 | |
- '8 ||
- 39 | |
- 40 | |
- 41 II
- 42 | |
- 43 | |
- 44 ||
- ** 1 1 I
- *6 | j
- 47 ||
- *8 ||
- 44 ||
- 50 II
II
- 51 ||
- 52 ||
- 5* ||
- 54 M
- 5* 1 1
- 56 | |
- 57 | |
62
91
51
55
(7
62
41
52
20
18
97
21
13
98
27
72
67
25
07
75
CT
35
90
67
91
50
73
66
30
05
7fl
)ft
29
*"J
36
67
44
20
11
58
90
31
9t\
99
ei
P2
ti*
57*
4*1
016
493
072
04*
277
1*1
1*4
416
4O4
0*9
606
lUb
405
289
lOOfc
463
706
07
64
45
11
51
14
?7
12
18
664
5*4
510
753
10*3
992
74)
335
31)
761
503
1*
9*
*6
71
72
*2
II
462 1 1
791 II
065 1 1
42" It
13) | |
404 1 |
M
916 ||
1075 1 1
9*T II
9)) I |
1170 tl
1200 II
4) ||
S46 tl
II
10+4 1 1
790 1 I
*01 M
215 1 1
110 II
II
*.»" ||
>50 1 1
)21 II
334 ||
672 1 1
319 | |
3)6 1 1
2flf> 1 1
779 1 1
774 ||
5*0 I I
*69 | |
*2« It
637 | |
925 II
04 l|
£6 It
12 | |
24 | |
67 | |
II
4*1 II
303 ||
356 tl
4*4 I I
427 | |
424 I I
252 II
FlUt GAS
i
564
917
496
440
465
05»>
135
061
2*0
124
121
364
346
030
679
112
097
990
935
7M
39fl
int.
344
412
3R-i
329
098
651
53
50
T*
03
97
77
))
76
496
4))
195
491
*T7
477
255
4
2
2
4
t
1
7
1
1
1
2
1
4 '
3
4
^
1
2
1
1
1
3
1
1 i
A. N01 / |
IKPUT tl
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-------
TABLE C.17 SERIES XI - SLOT CHANGES.
FURNACE DATA (INPUT)
TABLE C.18 SERIES XI - SLOT CHANGES,
FURNACE DATA (FINAL)
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TABLE C.19 SERIES XI - SLOT CHANGES.
NOX MEASUREMENTS
TABLE C.20 SERIES XI - SLOT CHANGES,
OTHER MEASUREMENTS
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-------
TABLE C.21 SERIES XII - BURNER CHANGES.
FURNACE DATA (INPUT)
TABLE C.Z2 SERIES XII - BURNER CHANGES.
FURNACE DATA (FINAL)
1 OR
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-------
TABLE C.23 SERIES XII - BURNER CHANGES.
NOx MEASUREMENTS
TABLE C.24 SERIES XII - BURNER CHANGES.
OTHER MEASUREMENTS
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-------
(This page intentionally left blank.)
-------
APPENDIX D
PRELIMINARY DATA PLOTS
The data plots are split up into two groups. First, the original
data points are plotted and the appropriate data line(s). drawn to
describe the points. Secondly, a blank graph is presented with the
"normal", mid air, mid load data line drawn on it. The data plots
require the grouping of data into variable ranges which are defined
below:
Variable
Excess Air, %
Load, %
(kBtu/ft^/hr
Preheat, °F
Low
< 7.5
<100.
< 40.
<450.
Range
Mid
7.5 - 25.
100. - 125.
40. - 50.
450. - 550.
High
> 25.
>125.
> 50.)
>550.
These data groupings, although arbitrary, recognize the fact that data
were gathered at the extremes and center of the variable ranges studied.
The representation of these ranges is:
Variable
Excess Air, %
Load, %
Preheat QF
Low
~ 3
* 75
^50
Range
Mid
~ 15
^115
^500
High
* 35
VI 40
^50
The lines which are drawn through the data points are "eyeball" fits
and are simply used to describe the apparent trend of the data.
These lines are drawn from visual fitting and no mathematical correla-
tion has been used. The simplest form of line has been drawn through
the data points straight where possible.
10,9
-------
Figure D.23 shows the substoichiometric tests plotted as ppm NO.
The line drawn in D.24 was used to calculate the line data for plotting
D.55. The data below show these calculations:
Stoichiometry % Reduction,
Burners NO, ppm; D.23/D.24 NO; D.55
115 1045 = 0
112.5 1000 4
100 625 40
95 500 52
85 288 72
70 75 93
60 0 = 100
no
-------
-
Q_
O
2 500
*
B.''
O - HIGH LORI
+ - NEO. LORI
X - LBH LORD
""'""
$/''
X ffi
/*
*,.,.-
1
)
,,,,,
^~~~
-'"
*T1
i
i."
EXCESS RIR. X
FIGURE D.1 COLORADO - HIGH PREHEAT
Q- HIGH LORD
+ - HEO. LORD
X - LOW LORD
}-
l^
\
T1
EXCESS OIR. X
FIGURE D.2 COLORADO - LOW PREHEAT
o.
Q.
,
- $
-V
Q- NIGH RIH
+ - NEO. RIR
X - LOU RIM
/'^
^^,
_.--
0 HI
RflTE OF HEflT RELEP
T
-------
Q_
Q_
EXCESS flIR. /.
FIGURE D.5 COLORADO - HIGH PREHEAT
Tl-J f I
EXCESS RIB. 7.
FIGURE D.6 COLORADO - LOW PREHEAT
-
z
Q_
a.
o
2 cm
^
^-
^^
' \
-
.
-
-
/
^
l^*^~~~'
"~^
' ' '
RHTE OF HERT RELEflSE. KBTU/FT««3/HR
FIGURE D.7 COLORADO - HIGH PREHEAT
ROTE OF HEflT RELEflSE. KBTU/FT««3/HR
FIGURE D.8 COLORADO - LOW PREHEAT
112
-------
O- MEO. BIB
+ - HIGH BIB
X - LOW BIB
too 900
PREHEflT. °F
FIGURE D.9 COLORADO - MEDIUM LOAD
PREHEflT. °F
FIGURE D.10 COLORADO - HIGH LOAD
-
.
0.
°- a~.
0
z jjo
»--
-
0
~~ "~ *"
Q - NEC. BIB
+ - HIGH B1R
__-
- I
"a
i
*- '
X- LOW BIB - - -- |
1 I I 1 | 1 1 1 1 | I 1 1 I | 1 1 l I I I I I | I I I I j i i i i , i i i I
-
000
:
"
-
-
= -<
.
=-
300 500 TOO SOO SCO To
PREHEflT. op PREHEOT. °F
FIGURE D.11 COLORADO - LOW LOAD
FIGURE D.12 COLORADO - MEDIUM LOAD
113
-------
PREHERT. °F
FIGURE D.13 COLORADO - HIGH LOAD
SOD
PREHERT, °F
FIGURE D.14 COLORADO - LOW LOAD
frrr
100
0.
a.
/ ^;
-.',":-''
O - HIGH LOR
- NEO. LOR
A - LOW IBRD
X - NCO. LOR
1 1 1 1 | 1 1 1 1
JB
/' . ;
VA
/ '
*','
,^i'
) / NIGH PRCHI
D / HIGH PRCHI
/HIGH PRCHCf
0 / LOU PRCHCI
^
HI
BT
«T
__,--
Horn
EXCESS RIR. /.
FIGURE D.1S FINE COAL - AIR
a
t
a- HIGH RIR
X - HIGH RIR
4- - HEO. RIR
V - LOU RIR
1 1 I i | 1 1 I 1
-'^
^
/HIGH PREHES
/ LOU PREHEAT
/ LOU PREHEAT
' LOU PREHERT
P~ 1
T s*
.;-"
, -.-
^
1 1 1 I | 1 I
RRTE OF HERT RELERSE. KBTU/FT««3/HR
FIGURE D.16 FINE COAL - LOAD
114
-------
J
-
-
^^
_ -
+ - HIGH All
--""
r- -~~
_
\ 1 NEC. LORD
.,..,..,.
------«
1
300
PREHERT. °F
FIGURE D.17 FINE COAL - PREHEAT
» " i '
EXCESS RIR. X
FIGURE D.18 FINE COAL - AIR
-
£
Q_
Q-
0
'Z UM
it
/
1
. ^
\
^
g
^
«
-
-
-
I SO
_
0
.-----""
5
M
^
1C
ROTE OF HERT RELEflSE. KBTU/FT««3/HR . PREHEflT. °F
FIGURE D.19 FINE COAL - LOAD
FIGURE 0.20 FINE COAL - PREHEAT
115
-------
o
z
z
o
a
LU
cc
O - NOBMPL LOAD / NOMIM. R1R
X - LOU LOBO / N8HKOL B1R
I
I
T
FLUE GRS RECrCLEO. 7.
FIGURE D.21 FLUE GAS RECIRCULATION
FLUE GBS RECTCLED. 7.
FIGURE D.22 FLUE GAS RECIRCULATION
Q_
O.
100 190 SO 100
STOICHIOMETRY flT BURNERS. 7. STOICHIOMETRt flT BURNERS. 7.
FIGURE D.23 SUBSTOICHIOMETRIC TESTS
FIGURE D.24 SUBSTOICHIOMETRIC TESTS
-------
_
0
Z
z
z
O
O
O
-
~~
(DO, .-7*
.£
y
x
//
T i'
.''
NOHNRL LO
ID RNO RIR
Q - FRONT SLOTS
f
-* -r
.'
x
/
(RLL FRO
O -
X -
m -
NT SLOT FlftCO
UGH LORD
KCOIUN LORO
LOU LORO
STOlCHIOMETRt RT BURNERS. 7.
FIGURE D.25 STAGED - PORT VARIABLE
ST01CHIOMETRY flT BURNERS. 7.
FIGURE 0.26 STAGED - 15% EXCESS AIR
O ~
z J
z
O
0 -
Q
OC
.
100
»
.
tc
/
IRLL FRO
Or
X -
9
4T SLOT FIREO
MEOIUH LORO
LOU LORO
.. 1 .... 1 . i i i
-
-
-
-
.
« ' ti
g
1
T
D
\ -\^
f
0
X
M
U
Y
xl
KEOIUM LORO
MEOIUH LORD
LOW LORD / F
10
^
/ S»OE SLOT
/ FRONT SLOT
RONT SLOT
i i | i i i i | . . .
STOICHIOMETRT RT BURNERS. 7.
FIGURE D.27 STAGED - 3% EXCESS AIR
STOICHIOMETRY RT BURNERS. 7.
FIGURE D.28 STAGED - 35% EXCESS AIR
117
-------
-
o
z
z
0
o
cc
-
~
SI
v^ f
₯
)
/"
?
Q - MEDIUM
X - MEDIUM
- MICH BI
X - LOU R1R
10
RIR BNO LORD
Bin RNO LOflO
R / LOU LORD
/ Hf.0. LORD
0
" FRONT SLOTS
- SIOE SLOTS
- FRONT SLOTS
- FRONT SLOTS
tsi
STOICHIOMETRT RT BURNERS. 7.
FIGURE D.29 STAGED - LOW PREHEAT
FB8NT PORTS
SIDE PORTS
11'' "
STOICHJOMETRY RT BURNERS. 7.
FIGURE D.30 STAGED - PORT VARIABLE
o
UJ
cc
I"11!1
100
STOICHIOME7RY RT BURNERS, 7.
FIGURE D.31 STAGED - 15% EXCESS AIR
STOICHIQMETRT PT BURNERS. 7.
FIGURE 0.32 STAGED - 3% EXCESS AIR
11B
-------
o
Z3
O
UJ
tc
1I'-'TJ!
STOICHIOMETRT RT BURNERS. X
FIGURE D.33 STAGED - 35% EXCESS AIR
\
STOICHIOMETRT RT BURNERS. 7.
FIGURE D.34 STAGED - LOW PREHEAT
-
-
t
0-
0.
0
Z um
_
.
-
_
.1&
VT
.1.*
H
O - NORHRL LORD - R
» - LOU LORD - fl
X - NORNRL LORD - B
M - LOM LORD - B
X - N8BMHL LORD - C -
Z - LOW L8PO - C
""'""I""1""
1
~"
0
Z
z.
.
o
0
UJ
-
_
f.J
''-'
\
Y /
JL /
'«
*s Ir
'
i1"1!" I I
-
X - 8 TESTS
X - C TESTS
1 1 1 1
EXCESS R1R. X
FIGURE D.3S SLOT CHANGES
STOICHIOMETRT RT BURNERS. X
FIGURE D.36 SLOT CHANGES - 15% AIR
119
-------
z
z
o
LU
^
O- S TESTS
X - 6 TESTS
8 - C TESTS
100 ISO
STOICHIOMETRY BT BURNERS. X
FIGURE D.37 SLOT CHANGES - LOW AIR
O - B TESTS
X - 6 TESTS
I - C TESTS
1 "I" "I1
STOICHIOMETRT RT BURNERS. 'I.
FIGURE D.38 SLOT CHANGES - LOW LOAD
o_
o_
1' I 'r'
EXCESS RIR. X
FIGURE D.39 SLOT CHANGES
STOICHIOMETRY flT BURNERS. X
FIGURE D.40 SLOT CHANGES - 15% AIR
-------
50 100
ST01CH10METRT HT BURNERS. 7.
FIGURE D.41 SLOT CHANGES - LOW AIR
STOICHIOHETRY RT BURNERS. 7.
FIGURE D.42 SLOT CHANGES - LOW LOAD
f' B
Q- NORHBL PREHERT - R
« - LOU PREHERT - R
Z - NORMAL PREHEAT - 8
X - LOW PREHERT - a '
X - NORMAL PREHERT - C
Z - LOW PRE'MERT - C
T
T
T
O - A TESTS
X - 6 TESTS
« r C TESTS
T
EXCESS RIR. 7.
FIGURE D.43 BURNER CHANGES
RRTE OF HERT RELERSE, KBTU/FT««3/HR
FIGURE D.44 BURNER CHANGES
121
-------
r
_
-
v
.
-
"
-
0
i
r- = -
1
1
_
j- ~ _ _
,
_ _ - - -
.
I
O - NORMRL RIR - R
* - LOU RIR - R
r^ i.
r »
$
S
« - HIGH RIR - R
» - NORHRL RIR - 8
X - LOU RIR - 8
Z - HIGH RIR - B
Z - LOU RIR - C
Y - HIGH R1R - C
,...,.. ,,|. ,..,.,..
i
-
_
-
o
i 2.
z
0 ~
C_)
o
o
UJ
cc ""
-
^iff
*»
xl
,*
.. ,1 | ..,.; 1 1 ............
X - 6 TESTS
8 - C TESTS
Tl 1 I|I I . | 1 ll| II . . | 1 .1
PREHEflT. °F
FIGURE 0.45 BURNER CHANGES
STOICHI8METRY HT BURNERS. X
FIGURE D.46 BURNER CHANGES - 15% AIR
Z
o
CJ B -
O - R TESTS
X - 6 TESTS
8 - C TESTS
O- R TESTS
X - B TESTS
8 - C TESTS
I1
TF
STOICH10METRY RT BURNERS. X
FIGURE D.47 BURNER CHANGES - LOW AIR
STOICHJOMETRT BT BURNERS. 7.
FIGURE D.48 BURNER CHANGES - LOW LOAD
122
-------
a.
a, ^
EXCESS RIR. /.
FIGURE D.49 BURNER CHANGES
RflTE OF HEflT RELEHSE. KBTU/FT«i«3/HR
FIGURE D.50 BURNER CHANGES
1000
0_
0. ~
O
0
K
'
K>
J
B-- - '
; c
r~
soo
PREHERT, °F
__J
it
0 ~
2
2
O ~
O
ra _
o
UJ
cc
n
^
= i^
/
/
/
g 10
STOICHIOMETRt
0 IK
HT BURNERS, X
FIGURE D.51 BURNER CHANGES
FIGURE D.52 BURNER CHANGES - 15% AIR
12.3
-------
T1
T1
T1
T1
STOICHIOMETRY RT BURNERS. X
FIGURE D.53 BURNER CHANGES - LOW AIR
STOICHIOMETRY flT BURNERS. X
FIGURE D.54 BURNER CHANGES - LOW LOAD
o ~
z
z
z
o
o
o
UJ
oc ~
-
~
SI
.
JS
^^
/
> It
/
/
/
THE LINE IN
THIS FIGURE
HAS BEEN CALCULATED
FROM THE LINE IN FIGURE
0.2<4
a n
STOICHIOMETRY HT BURNERS. X
FIGURE D.5S SUBSTOICHIOMETRIC TESTS
124
-------
APPENDIX E
MATHEMATICAL DERIVATIONS AND CALCULATIONS
Initial calculations were done by computer and yielded the
weight of fuel, air, and natural gas from the igniter including any
moisture if present (see Appendices A and B). In addition, the
percentage of theoretical air was calculated. For large amounts of
combustibles (>3%) in the flue gas during substoichiometric tests, a
gas chromatographic sample was analyzed for CO and Hp (and CH^) to
determine equivalent combustibles as CO; or the equivalent CO was
hand calculated if the fuel feed had remained steady and primary air
rate constant from the previous base test. (The equivalent CO for
combustibles assumed all combustible gas was present as CO for ease
of excess air calculations - hL and CO both required 1/2 02 and no
other combustibles were found in the flue gas except solid carbon.
Since there was little unburned carbon in all coal tests and the
amount was relatively constant, it was ignored in these excess air
calculations.)
The flue gas recirculation was calculated by taking the ratio of
flue gas recycled to the total weight of fuel and air in the com-
bustion:
FGR = 100.0 x
wa + wf
The criterion for staging was the stoichiometry at the burner which
is given by:
pBA = PTA x FB
H 100.0
where
FB =
a
125
-------
In addition, corrections were applied to the NO instrument
A
readings for C(L and HpO. The following series of constants were
used:
Constant Used
Colorado
Ohio
Wt of stoich. air n 00-,
Wt of Fuel
Wt of moisture/
100 Ib fuel
MF <
MA
MM
MC
, MFI
MFR
MAI
MAR
MMI
MMR
j MCI
1 MCR
4.65
0.6298
0.3380
0.5694
0.02664
0.1192
0.02664
0.06135
0.05816
Ohio
Coal
8.588
6.13
0.6298
0.3154
0.5694
0.02549
0.1192
0.02549
0.06135
0.05405
Gas*
16.48
0.0
0.6315
0.6315
0.5709
0.1197
0.1197
0.1197
0.06138
0.06138
The equations are thus given as:
TM = MF +
x MA + MMH + MMF
where
MF = MFI x WNI + MFR x Wf
MA = MAI x WNI + MAR x Wf
NMH = MA x
H20
*Gas analysis used for coal igniter firing,
12fi
-------
MMF = 0.0465 Ib H20/lb coaT (only for Colorado coal)
MCI x WNI + MCR x Wf
TM
MMI x W + MMR x VL MMH + MMF
FH20 =
TM TM
Corrections applied to the NO instrumentation are:
Whittaker: Multiply by (1.0 - FH20 - FC02)
[With bubbler solution, multiply by
(1.0 - FH20 + 0.029268*7(1.0 - FH20))]
TECo: Multiply by (1.0 - FH20 + 0=012117*7(1.0 - FH20))
NDIR: Multiply by (1.0 - FH20 + 0.0065342*7(1.0 - FH20))
after subtraction of 50 ppm correction due to water
absorption.t
(The NDIR correction due to water absorption at 34°F saturation was
determined experimentally.)
For all: correction to dry, 3% 02 in flue gas, multiply by:
18.0
PT x (21.0 - PDF) (1.0 - FH20)
The average of the NDIR and TECo, Aver, was calculated by:
Aver = p~z
and the standard deviation, STDV, by:
*Saturation factor at temperature of measurement.
tlnfrared absorption correction for actual water content
of sampled flue gas.
127
-------
STDV = \/(NDIR - Aver)2 + (TECo - Aver)2
2.0 x |TECo - Aver]
The Btu value from the fuel enthalpy release is given by these
equations, one for each fuel:
Colorado Coal: BTU = 23855 x WNI + 12404 x Wf
Ohio Coal: BTU = 23855 x WNI + 11533 x Wf
Gas: BTU = 23920 x (WNI + Wf)
The air and recycled flue gas preheat adds enthalpy to the flue gas
during combustion also. This addition is given by (no primary
preheat):
BTUG = BTU + Wa x BTUa + (MM x Wf x 18.016 +
(MMH + MMF) x 18.016) x BTUm + Wl x BTUf
where
BTU = (TAG - TA) x (0.240 + 10"5 x TAG)
a
BTUm = (TAG - TA) x (0.444 + 2 x 10"5 x TAG)
BTUf = (TFG - TA) x (0.252 + 10"5 x TFG)
For correction of ppm NO at 3% 09, dry flue gas conditions to Ib NO
AC. *»
(as NO) per million Btu (fuel Btu only) input, the NO value is
multiplied by:
Wfn (No conversion constant is necessary since the Btu
19 e
BTU and ppm must both be divided by 10 .)
128
-------
In conversion of load percentages to thousands of Btu per ft
per hour, the factors to be remembered are:
o
1) furnace volume - M27 ft (8 ft long,
4.5 ft diameter)
2) 100% load = 5,000,000 Btu per hr
and therefore if million Btu load is divided by 0.1272, the result is
in kBtu/ft3/hr.
For calculation of the fractional reduction, L-, of the measured
values L, (base point) and L« (reduced value with reduction modifica-
tion in firing test):
and since the values were
+ L] and
then
ft'2 +L'2 I2
u-i ^ L2 ; +
XL'
The calculations as used in data tables and graphs do not include
conversion to the Si/metric system. It is intended that these con-
versions can be made by consultation of Appendix H. In this way, all
data presented in the Phase II final report is consistent and
directly comparable to the data in the previous Phase I final report.
129
-------
(This page intentionally left blank.)
-------
APPENDIX F
FUEL NITROGEN CONTENT OF THE OHIO AND COLORADO COALS
A direct comparison of the fuel bound nitrogen content* of the
Ohio and Colorado coals was necessary to determine the effect on the
NO emission levels. There were six samples of Ohio coal and five
samples of Colorado coal analyzed for total nitrogen content simul-
taneously for statistical purposes. All of the samples had been
collected at different times and therefore were representative of the
nitrogen content and its variability over a long period of time. In
the case of the Ohio coal, the samples covered the entire period of
Phase I. For the Colorado coal, the samples covered the first half
of Phase II.
A blank was run at the same time the eleven samples were analyzed.
The results of the analyses are shown in Table F.I. Figure F.I shows
a one dimensional illustration of these samples with nitrogen per-
centage in the horizontal: the banded regions are the average with
+_ 1 a shown as the total band width.
As can be seen from these data, the two separate sets of fuel
bound nitrogen as determined for the coals are statistically identical.
The two coals do not differ in fuel bound nitrogen content.
*The fuel bound nitrogen was determined by the Kjeldahl method.
131
-------
TABLE F.1 FUEL BOUND NITROGEN CONTENT
Sample No.
1
2
3
4
5
6
Nitrogen Content, %
Ohio Coal Colorado Coal
Average of above
1.18
1.15
1.13
1.11
0.98
1.07
1.105
1.18
1.20
1.07
1.12
1.25
1.164
Standard deviation
on average, a
Statistical band
Statistically
determined fuel
bound nitrogen
±0.073
1.032 - 1.178
1.1 ± 0.1
±0.070
1.094 - 1.234
1.2 ± 0.1
OHIO COAL
(D (D 0 (D (D (D
OHIO AVERAGE
COLORADO COAL
9 e
COLORADO AVERAGE
1.0 lil 1.2
FUEL BOUND NITROGEN,%
FIGURE F.1 FUEL BOUND NITROGEN CONTENT
132
-------
APPENDIX G
COMPARATIVE DATA FOR THE OHIO COAL AND NATURAL GAS
The figures included, G.I to G.7<, show the most important trends of
the NO emission levels from the Ohio coal and natural gas tests. All
/\
of these test results have been taken from the Phase I report.
Q-
Q-
NBTURfll GflS
EXCESS flIR. 7.
FIGURE G.1 EXCESS AIR
NATURAL CRS
RRTE OF HEflT RELERSE. KBTU/FT«x3/HR
FIGURE G.2 LOAD
Q_
O.
OHIO com
500
PREHERT. °F
FIGURE G.3 PREHEAT
133
-------
Q-
Q-
8*1°
10 500
PREHERT, °F
FIGURE G.4 PREHEAT. HIGH EXCESS AIR
FLUE GRS RECYCLED. 7.
FIGURE G.5 SECONDARY FLUE GAS REC.
SO 100 ISO
STOJCHIOMETRT HT BURNERS. 7.
FIGURE G.8 COAL, STAGED COMBUSTION
0 100 ISO
STOICHIOMETRY FIT BURNERS. 7.
FIGURE G.7 GAS, STAGED COMBUSTION
134
-------
APPENDIX H
TABLE OF CONVERSION FACTORS FOR SI UNITS
The most important factors for conversion from the English system
of measurements to the SI system are:
(One of each of the following)
English units
atmosphere (normal)
atmosphere9(technical is
1 kgf/oiT)
British thermal unit
(Inter. Table)
Btu (mean)
Btu (thermochemical)
Btu/pound mass
Btu/lbm-°F
Btu/hour
degrees Farenheit
foot
pound-mass
pound-force
poundal
to SI Units (to 4 significant
figures)*
1.013 E + 05 pascals (Pa)t
9.807 E + 04
1.055 E + 03 joules (J)
1.056 E + 03 " (J)
1.054 E + 03 " (J)
2.326 E + 03 joules/kilogram
(J/kg)
4.187 E + 03 joules/kg-Kelvin
(J/kgK)
2.931 E - 01 watts (W)
(t°F + 459.7)/1.8 Kelvins (K)
3.048 E - 01 meters (m)
4.536 E - 01 kilograms (kg)
4.448 E + 00 newtons (N)
1.383 E - 01 newtons (N)
*The number 1.013 E + 05 is equivalent to 1.013 x
tThe symbol for the unit follows in parentheses
135
-------
The following table is included for sample conversions from English
units to metric units:
(One of each of the following)
English units
atmosphere
British thermal unit
(International)
Btu (mean)
Btu (thermochemical)
to Metric units
= 76 cm Hg
1.01 3E + 06 degrees/sq.cm
1.03 3E + 00 kg/sq.cm
2.520 E + 02 (g)cal
2.520 E - 01 (kg)Cal
Btu/pound mass
5.556 E-01 (g)cal/gram
5.556 E-01 (kg)Cal/kg
Btu/lbm°F
1.0 E + 00 (g)cal/gram °C
1.0 E + 00 (kg)Cal/kg°C
Btu/hour
2.520 E + 02 (g)cal/hr
2.520 E-01 (kg)Cal/hr
degrees Farenheit
(tF - 32)/1.8 degrees
Centrigrade
foot
pound-mass
pound-force
Poundal
3.048 E - 01 meters (m)
4.536 E - 01 kilograms (kg)
4.448 E + 00 newtons (N)
1.383 E - 01 newtons (N)
136
-------
APPENDIX I .
COMBUSTIBLE AND NOX
Table I.I is all of the data from the coal and natural gas testing
that has been run for this EPA contract. The data include:
Test Numbers - the series number and test number
within the series (all Phase I and
Phase II tests are included)
Comments - deviations to the usual base testing such
as staging, flue gas recirculation, etc.
CO, ppm - the as read, "raw" data
NO, ppm - corrected to 3% Op, dry
02, ppm - the as read, "raw" data
subheadings separate the Ohio coal, natural
gas, and Colorado coal.
The figures I.I to 1.12 show the CO emission levels plotted against
either the NO emission levels or the 02 levels in the flue gas for
single tests. (For any single test, a point is plotted.) It should be
noted that odd numbered graphs (I.I, 1.3, 1.5, etc.) are log (CO) and
the even numbered graphs are just CO.
Observations
For the Ohio coal, the log (CO) plots show a better picture of the
pattern. A somewhat linear dependency of the log (CO) on 02 is
indicated.
The natural gas curves show the same type of variation with NO and
Op, although the absolute values of CO are lower than for the Ohio coal.
The dependency of the log (CO) on 02 is less linear and shows a leveling
out at >3% 02.
The Colorado coal again shows the same trends as the Ohio coal and
natural gas. The absolute values of CO emission are similar to the
Ohio coal. (A single curve could fit all data 1.3 and I.11) The log
(CO) versus 02 is almost linear.
137
-------
TABLE 1.1 COMPARISON OF ALL PHASE I AND PHASE II WORK
OHIO
_
_
-,
_
_
-
.
-
_
- 0
- 11
- 12
- 13
- 14
- 15
- 14
- 17
- IB
- 19
- 70
- 21
- 22
- 21
- 24
25
- 26
- 27
- 26
- 29
- 10
- 51
* 12
- 13
- 34
- 35
- 36
- 37
- 38
- 39
- 40
- 41
- 4?
- 43
_
.
-
-
-
-
_
_
-
-
_
-
_
-
.
PRIM
PRIM
PRIM
PRIM
PRIM
0
1 "RIM
2
3 PRIM
*
5 PRIM
6
APV FGR
ARY FGR
APY FGR
ARY FGR
ARY FGR
ARV FGR
ARV FGR
ARV FGR
. 17 PRIMARY FGR
- Ifl PRIMARY FGR
9
- 20
- ?2
-
-
_
3 PRIM
4 PRIM
5
6
ARY FGR
ARV FGR
- 27 PRIMARY FC.R
- 28 PRIMARY FGR
.
_
-
-
-
_
_
_
0
0
11 PRIM
)Z
3 PRIM
14
15 PRIM
IS
ARV fGR
ARV FGR
lARY FGR
37 PRIMARY FGR
_
-
.
_
.
_
_
_
-
-
.
_
_
.
-
-
M -
SECC
StCL
SFCfl
SECr
0
i
2
3
4 SFCU
«
7
ft StCl
o
NflARY FGR
WOARV FGR
Ml) ARV FG«
WAVY FGR
MUABV FGR
INDAKV FGR
INI) ARY Ff.P
CO. PP»
COAL
205
60
AJOO
iao
90
"000
760
115
15000
115
9000
65
240
360
500
4000
70
65
240
3200
60
90
165
20000
400
4000
140
100
BOO
400
18000
S75
50
4500
260
400
50
750
3000
90
3200
360
7000
90
60
90
100
90
4000
3700
90
90
140
140
100
65
1500
2600
660
240
90
90
4000
90
125
115
105
4000
4000
240
110
350
200
165
260
9O
90
115
115
115
115
115
100
100
7600
1*00
00
40
4JOO
40
*0
70
60
10
2000
. 1400
100
90
NO, PPM
725
91 J
431
714
948
431
746
998
546
534
292
795
546
*OB
663
420
634
621
460
12 1
681
965
791
2,82
746
53*
956
676
424
601
312
731
958
466
789
749
922
634
558
739
449
764
509
77*
694
659
898
696
449
472
624
740
9BO
969
762
794
571
552
470
494
699
656
24
65
63
86
91
44
38
63
66
45
50
61
62
706
734
910
T91
P?tt
70»
*99
416
537
722
333
251
P32
1010
269
1014
"33
54
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGF.D
STAGED
STAGED
IT AGED
STAGED
i STAGED
k STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGFO
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
FGR, S GEO
FGR. S GEO
FGR. S GEO
FC.R, S GFD
FGB. S GEO
FT.R, S CEO
SIIHSTO CHIC-ETHK
SUBSTO CHIOMETRIC
STAGED
STAGFD
FGR
STAGED
STAGED
FGR
DO
"0
3500
450
70
5000
50
60
1 000
60
160
150
114
9O
500
0
229
3000
1350
1035
1175
200
260
165
210
240
7000
115
140
130
170
175
475
650
1050
1125
300
265
300
205
210
4000
3250
2600
1175
1100
1600
2350
1000
4000
200
250
260
200
210
2800
1500
285
265
240
110
0
660
1050
400
17000
47000
510
75
7500
"50
200
1050
295
2700
2S5
BIO
660
500
420
?72S
750
720
810
96
70
42
1 11
36
62
1 51
BO
93
112
62
R6
63
79
06
76
5J
64
66
59
94
73
1001
605
770
2°4
677
*08
505
711
343
295
467
359
432
733
365
350
374
369
399
263
371
693
409
656
524
334
469
689
685
674
607
644
261
362
410
5**
320
465
366
411
32)
655
377
203
65R
649
717
7«1
971
710
43*
556
707
555
*71
fcOl
B2<>
545
766
699
6.
6.
|,
1.
5.
0.
3.
5.
0.
2.
6.
3.
5.
2.
3.1
3.1
3.1
0.8
0.9
3.0
0.9
.7
.6
.6
.4
.6
.9
.2
3.2
3.8
3.4
3.2
3.0
3.2
1.2
3.2
3.2
3.3
3.6
2.9
3.1
O.fl
0.9
0.'
3.2
3.1
3.4
O.fl
o.s
.1
.0
.4
.1
2*9
2.6
6t<
.1
.1
C
3^;
o.c
o.c
3.
).
3.
3.2
5.4
3.
5.
0.*
3.C
1.
3.
3.
5.
1.
3.
5.
138
-------
TABLE 1.1 (DON'T) COMPARISON OF ALL PHASE I AND PHASE II WORK
IFST IDS. COMMENTS
TEST HO5. COMMENTS
VA - 1
lyA - ?
IV* - 3
V» - 4
IVA - 5
IVA - 6
VA - 7
|VA - *
VA - 4
VA - 10
IVA - 11
IVA - 12
IVA - 11
IVA - 1*
IVA - 15
IVA - 16
IVA - 17
IVA - 11
IVA - 19 F
IVA - 20 f
IVA - 71 F
IVA - 22 F
IVA - 23 F
VA - 24 F
VA - 25 FG
VA - 26
VA - 27 STAGED
VA - 29 FOB , STAf
VA - 30 STAGED
VA - 32 STAGED
VA - 34 fdK, STAG
VA - 35 STAGED
VA - 37
VA - 38 STAGED
VA - 34 F&R, STAG
VA - 40
VA - 41 SUBSTU1C*
VA - 4i suaSTnic*
VA - 44
VA - 45
VA - 46
VA - 4T
VA - 4fl
VA - 44
A - I
VA .
VA -
V* -
VA -
VA -
VA -
VA -
VA -
VA - 0
VA - I
VA - 1?
VI 1 -
vl I -
VI| -
VI I -
VI 1 -
VI 1 -
vll -
vii -
VI I - SUBSTOIO
vii - o SURSTOIO
VII - 11 SURSTOIC
Vll - 12 SUBSTOIO
VII - 13
VII - 14
VII - 15
Vll - 16
Vll - 17
VII - 18
VI I - 14
VI 1 - 20
VII - 21
VI I - 22
Vll - 23
VII - 24
VI I - 5
VI 1 - 6
VI 1 - 7
Vll - 8
VII - 9
VIM - 1
VIII - 2
VIII - 3
VII - 4
VII - 5
VII - 6
VI I - 7
vii - a
VIII - 4
VIII - 10 FGR
VIII - 11
MTURAi CAS
.150 322
10) 120
113 267
TO 308
33 310
810 244
40 303
4Q 111
640 245
40 1 48
40 135
10TO 123
35 144
50 27
IQ20 24
23 36
96Q 09
13 39
7 44
22 74
22 T
ZOO 0
133 3
22 4
480 4
3 6
2 6
EO 1 8
0
ED 93
310
ED 220
T 120
330
269
ED 198
369
IO*iT"IC 105 251
332
235
6 144
460 27B
»5 314
15 2F3
hn 330
80 129
75 ?«3
TO 261
JW 212
70 275
* 269
SlO 230
TO 265
75 270
160 2)4
40 24*
COlCRAOO COAL
40 953
60 1230
35QQ 643
40 820
40 981
930 510
120 1083
3000 673
lOMETBIC 34490 535
IO-ETBIC 45427 20 T
IOMETRIC 145000 104
IDMETRIC 205000 79
70 1146
60 136
2600 B4
15.0 ' 41
60 110
2600 5T
240 44
115 41
US 1042
60 834
40 637
930 443
375 TT4
100 1064
tOO 1327
150 1305
990 862
80 1044
IQO 1094
80 1304
2190 T2T
19O 786
1700 3)9
100 1143
150 1086
8 1244
90 462
100 1226
2.9
9.9
0.6
3.0
9.
0.
2.
5.
0.
2.
3.6
.7
B
6
,T
.8
.«
.»
3.1
3.1
3.8
0.8
O.T
2.9
0,6
3.1
1.0
2'.t
1.2
3.3
2.9
3.0
3.0
0.8
5*8
3.6
5.8
3.1
0.4
J.O
0.0
2.T
2.5
0.7
O.ft
S.«
5. 7
2.1
2.4
2.T
2.8
0.7
5.6
2.8
0.6
5.7
2."
0.6
5.6
2.T
5.8
0.5
3.6
6.6
1.1
3.1
0.6
0.2
0.0
0.0
0.0
1.0
6.0
0.9
1.0
6.1
1.1
3.1
3.0
5*4
6.2
3.0
0.4
2.8
2.7
6.2
5.6
1.0
3.0
2.8
6.9
O.T
2.9
O.T
T.O
3.0
6.4
3.7
J.3
VIII
Vlll
VI II
IXA
IXA
|XM
ixe
1X8
XA -
XA -
XA -
KA -
XA -
I* -
XA -
KA -
XA -
XA -
XA -
XA -
XA -
A -
XA -
XA -
XA -
XA -
XA -
XA -
XA -
KA -
XA -
XA -
XB -
XB -
XB -
XB -
XB -
XB -
x» -
XB -
KH -
XB -
xa -
xe -
xfl -
XB -
XB -
xn -
>* -
xa -
i -
H _
B -
a -
H -
XB -
Xft -
IB -
Xfl -
Xfl -
10 -
XI
X(A
X| A
XIA
>|A
XI A
Xll
tIA
XIA
XIA
XIA
XIA
XIA
XIA
X|B
XI A
' xin
KIA
Kll
*l 1
XI"
KIP
X]1
xt **
*|f*
X|H
KI1
118
KlC
XIC
X C
X C
« c
X C
X C
xir.
XIC
XIC
1C
If.
1C
1C
1 1A
I IA
II*
- 12
- 13
- 14
- 1
- 2
- 3
. 4
- 5
1
2
3
4
5
0
1
2
13
14
15
16
IT
18
14
20
21
22
23
24
23
26
27
28
24
10
32
33
34
IS
1
1
V
4l
4
43
44
43
46
47
4*
50
51
*2
5*
54
?5
56
S7
- 1
- ?
- 3
- 6
- 7
- 8
- Q
- 10
- 11
- 12 .
- 13
- 14
- 1
- f
- 1
- 4
- 5
- 6
- 7
- O
- 10
- It
- 12
- 13
- 14
- 1
- 2
- 3
- A
_ 7
- B
- «J
- 10
- 11
- 12
- 11
- 14
- 1
- 2
- 3
FGR
FGfl
FGR
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
TAGED
TAGEO
TAGEO
TAGEO
TAGED
TAGED
TAGFD
STAGED
STACFD
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGFO
STAGED
STAGED
STAGED
STAGED
STAGE"
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGFD
STAGED
STAGFD
STAC.ED
STAGFD
STAGED
-STAT.Fn
STAGED
STAGED
STAGtD
STAGED
STAGED
STAGED
STAGED
STARED
STAKED
STAGFO
STAGED
STAGED
103
90
473
120
30
240
130
30
1700
130
30
too
100
123
60
130
120
40
too
TO
T5
IflO
150
120
60
60
1BO
1600
120
130
10
4900
12900
300
1400
100
100
180
150
360
360
510
180
360
210
360
210
10
60
90
150
240
60
60
60
4400
3100
150
340
1200
1200
1100
1100
150
4000
120
120
100
700
90
3 TOO
3500
120
2200
1200
75
60
90
100
90
65
11
10
15
2 00
2000
1?00
010
3200
165
140
150
190
150
410
PlO
1200
300
4000
6500
4000
4500
«5QO
125
960
«00
260
100
75
60
96
1014
617
101"
01
46
*8
77
56
91
86
105
1207
986
440
463
1056
1133
1068
1248
191
129
121
013
164
346
03B
679
1182
874
847
415
252
71
88
40
82
13
61
48
116
84
84
u
85
24
49
48
31
34
503
T4fl
1034
479
77
31
11
76
49
43
395
49J
477
477
255
11C8
883
*14
745
5*1
75T
467
315
389
113
981
337
288
142
1083
R34
414
704
974
796
434
349
»01
318
37
601
434
360
1046
673
295
611
'11
784
3)8
149
385
226
940
356
230
1*>4
1191
433
512
3.1
.1
.6
.6
.1
.9
.2
. B
.4
.2
l.l
9.
6.
2.
2.
2.
2.
3.
2.
4.
5.5
3.4
2.9
2.8
6.3
6.7
2.9
1.1
1.6
3.0
6.4
1.2
1.4
3.1
3.1
6.4
6.0
1.0
3.0
2.4
3.2
3.7
3.6
. 2.8
3.4
2.6
3.8
5.2
4.3
4.2
.8
.4
.0
.0
.2
.3
.0
.1
.6
3.6
1.2
3.6
3.6
6.7
.2
.1
.9
.3
.8
.9
0.8
1.0
1.1
1.0
0.9
3.0
3.2
1.0
3.1
2.8
3.1
2."
2. A
3.1
1.0
0.9
1.0
0.*
1.0
2.1
2.4
3.2
3.2
1.2
2.9
2.9
1.2
1.0
1.0
1.1
1.1
0.6
0.7
2.'
3.0
2.fl
2.9
3.2
3.4
3.3
139
-------
TABLE 1.1 (CON'T) COMPARISON OF ALL PHASE I AND PHASE II WORK
TEST NUS. CIMHFNTS
02,
Ill> -
XIIA -
XIU -
<1 11 -
XI U -
XIU -
XI|» - 10
III* - 11
XIU - 12
XIIA - 13
XIU - 1*
XIIA - H
Xl|« - 16
XIU - 17
xiu - in
XIU - 11
XIU - 20
XI Id - 1
XIIH - 2
X|l» - 3
XIU -
XI 18 -
XIIB -
Kill -
XI IB -
XIIR -
XI IB - 10
XlIB - 11
xi ta - 12
XIIO - 13
XlIB - 14
xnn - is
XlIB - 16
XI11 - 17
ilia - IK
xim - 10
XI IB - 20
XIIC - 1
XIIC - 2
XlIC - 3
XIIC - 4
XIIC - 5
XIIC - 6
XIIC - 7
XIIC - B
XIIC - 9
XIIC - 10
XIIC - 11
XIIC - 12
XIIC - 13
XIIC - 14
XIIC - 15
XIIC - 16
XIIC - 17
XIIC - I"
XI 1C - 19
XIIC - 20
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
STAGED
75
150
3200
1200
1600
2600
2100
180
200
90
no
75
60
MO
100
60
2300
65
130
3)0
60
100
2400
4300
1400
3600
21SO
120
100
200
140
75
55
115
450
30
3900
60
330
100
120
300
4400
5000
1000
3950
2800
200
200
100
500
155
240
330
500
180
3700
720
567
»24
538
278
434
363
1327
10J7
B92
506
341
540
332
1002
119?
745
1220
914
420
865
506
871
576
303
524
304
1401
1216
1022
631
357
607
3B3
1046
1183
748
1108
875
426
726
489
726
408
326
420
238
1395
1172
1048
. 549
351
569
ZH7
1062
1165
714
2.9
3.1
1.0
1.3
1.3
1.0
1.3
7.3
3.2
2.1
3.0
3.5
3.4
2.9
3.0
7.4
1.0
2.9
2.7
2.3
2.8
2.8
0.9
1.1
1.0
0.6,
1.1
7.4'
2. a.
2.8
2.7
2.9
3.0
3.1
2.8
7.0
0.8
2.8
2.6
3.0
2.«
2.B
0.6
0.7
1.0
0.8
1.3
6.5
2.6
2.5
2.4
2.7
2.4
2.5
2.9
6.8
0.8
Summary
The CO emission levels are dependent on Op levels, and in general
CO is a function of 02 - i.e., low 02 levels (for lower NOX emission
levels) yield greater CO emission levels. However, CO is not as closely
associated to NO but rather both CO and NO, although somewhat inter-
dependent, are both a function of 02- Operation of our coal fired unit
below 1% 02 yields substantial quantities of CO.
140
-------
1E6
Q_
Q_
rC 1E3 --
CD
O
1EO
800 1600
NO, PPM
FIGURE 1.1 CO VERSUS NO (OHIO COAL)
8E4 --
Q_
Q_
S 4E4
0
0
i i i | , . . | .
800
1600
NO. PPM
FIGURE 1.2 CO VERSUS NO (OHIO COAL)
1 CO -
21 ~
Q_
Q_
0 1E3 ~
CD -
0
_J
iVn
" A
JL
>M*fc H
w >4j
"taHUJX* * «£"
%'" -Tf
1 1 h 1 1 1 1 1 1
8E4 -
2.Z
tx_
Q_
3 4E4 -
n
- V
" A
Jfe^4**ifcM MM tu i i i
0 4.0 8.0
02. X
FIGURE 1.3 CO VERSUS O2 (OHIO COAL)
4.0 . 8.0
FIGURE 1.4 CO VERSUS O2 (OHIO COAL)
141
-------
1E6
Q-
Q_
o
CD
O
1EO
t *
-HH
800 1600
NO, PPM
8E4 --
S 4E4-f
800 '1600
NO. PPM
FIGURE 1.5 CO VERSUS NO (NATURAL GAS)
FIGURE 1.6 CO VERSUS NO (NATURAL GAS)
i CD
21 ~
Q_
Q_
o 1E3 -
CJ
CD
O
1
' '
1 F~n
1 C.U
'*
" "»
- *
'fr -*m
I » 2 "
IMV V
H NH
1
I 1 ^ 1 1 MM 1 1
- 1 t 1 -» 1 1
0 4.0 8.0
02. 7.
8E4 --
Q_
Q_
S 4E4
" I ' 1 ' I
4.0 8.0
08. X
FIGURE 1.7 CO VERSUS O2 (NATURAL GAS)
FIGURE 1.8 CO VERSUS O2 (NATURAL GAS)
142
-------
1E6
Q_
0_
1E3
cj
G --
**.***
* * * «
««**. ."
1EO I I I I | I I I | I I I | I I I | I I I
0 800 1600
NO. PPM
8E4 --
Q.
Q-
5 4E4
800 1600
NO. PPM
FIGURE 1.9 CO VERSUS NO (COLORADO COAL) FIGURE 1.10 CO VERSUS NO (COLORADO COAL)
1E6
CL
o_
^ 1E3 --
LJ
o
1EO
*C
"Hut1'*
MM UK
M
M
' I ' I ' I ' I '
4.0
02. X
8.0
8E4 --
Q_
Q_
S 4E4
4.0
02.
8.0
FIGURE 1.11 CO VERSUS O2 (COLORADO COAL) FIGURE 1.12 CO VERSUS O2 (COLORADO COAL)
143
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TECHNICAL REPORT DATA
(Pieae read Instructions on the reverie before completing)
1. REPORT-NO.
EPA-650/2-74-002b
2,
3. RECIPIENT'S ACCESSION* NO;
4. TITLE AND SUBTITLE
Effects of Design and Operating Variables on NOx
from Coal-Fired Furnaces--Phase II
5. REPORT DATE
February 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
W. Joseph Armento
I. PERFORMING ORGANIZATION NAME AND ADDRESS
Babcock and Wilcox Company
Research and Development Division
Alliance, Ohio 44601
10. PROGRAM ELEMENT NO.
1AB014; ROAP 21ADG-041
11. CONTRACT/GRANT NO.
68-02-0634
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
Phase II Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
repOrt gives results of Phase II of an investigation of combustion modi-
fication techniques for controlling NOx emissions that have application to pulverized
coal-fired utility boilers. The techniques, studied on a 5 million Btu/hr single-
burner pilot unit, included: excess air, air preheat, firing rate, flue gas recircu-
lation, staged combustion, quench, and swirl. Phase II tests, conducted with a
Colorado coal, showed that NOx reductions of up to 65% were possible by using
staged combustion or by lowering excess air levels from 30 to zero %. Flue gas
recirculation yielded only moderate NOx reductions for coal. For existing units ,
control of excess air appears to be the simplest method for NOx reduction. Where
possible , staged combustion could be retrofitted on existing units to achieve further
NOx reductions. For new units, staged combustion combined with low excess air
firing appears to be the most promising method for NOx control.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Nitrogen Oxides
Combustion Control
Coal
Combustion Chambers
Flue Gases
Thermodynamics
Quenching (Cooling
Swirling
Air Pollution Control
Stationary Sources
NOx Reduction
Staged Combustion
Flue Gas Recirculation
Air Preheat
Excess Air
13B, 13H
07B, 07A
21B
21D
2QM_
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Thit Report)
Unclassified
21. NO. OF PAGES
160
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
145
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