PB-213 297
STATE OF THE ART FOR CONTROLLING NOx
EMISSIONS PART I. UTILITY BOILERS
Catalytic, Incorporated
Charlotte, North Carolina
September 1972
28209
DISTRIBUTED BY:
Ki
National Technical Information Service
U. S. DEPARTMENT OF COMMERCE
5285 Port Royal Road, Springfield Va. 22151
V
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BIBLIOGRAPHIC DATA
1. Report No.
2.
SHEET
EPA-R2-72-07?a
4. 'J'iilr and Subtitle
"State of the Art" for Controlling NO* Emissions
Part I. Utility Boilers
5. Kejum Diue
September 1972
6.
7. Author(s)
8. Performing Organization Rept.
No.
9. Performing Organization Name and Address
Catalyfic, Incorporated
1515 Mockinbird Lane
Charlotte, North Carolina 28209
10, Project/Tjsk/Work Unit No.
No. 2
11. Contract/Grant No.
68-02-0241
12. Sponsoring Organization Name and Address
. U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Monitoring
Washington, D. C. 20460
13. Type of Report & Period
Covered
14.
PB 213 297
15, Supplementary Notes
16. Abstracts
•A report is presented with the objective' of identifying the "State of the Art" of N0X
emission reduction from stationary sources through combustion modification. This
first part of a two part report deals with the control 'of NO^ from utility boilers.
The-report presents information onf Sources of, and formation of nitrogen oxides. A
total of five factors which effect utility boiler emissions are discussed in detail.
A discussion of "Combustion Modification-for N0X Emission Control", includes the
following topics: combustion operating'modification, combustion equipment, design
modif ications , and flue gas treatment': (
17. Key Words and Document Analysis. 17a. Descriptors
Air pollution Cost
.Nitrogen oxides Sources
Boilers
Electric utilities
Combustion.
Combustion control
Combustion efficiency
Combustion chambers
Design
Flue gases
17b. Identifiers/Open-Ended Terms
Stationary Sources
17 c. COSATI Fie Id/Group
13B
j
18. Availability Statement
Roproduced by
NATIONAL TECHNICAL
Unlimited INFORMATION SERVICE
U S Department of Commerce
Springfield VA 2215)
'ORM NTIS-33 (REV. 3-72)
19. Security Class (This
Report)
UNCLASSIFIED
20. Security Class (This
Page
UNCLASSIFIED
21. No. of Pages
118
22. Price
THIS FORM MAY BE REPRODUCED
JSCOMM-ic 14952-P7;
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NOTICE
THIS DOCUMENT HAS BEEN REPRODUCED FROM THE
BEST COPY FURNISHED US BY THE SPONSORING
AGENCY. ALTHOUGH IT IS RECOGNIZED THAT CER-
TAIN PORTIONS ARE ILLEGIBLE, IT IS BEING RE-
LEASED IN THE INTEREST OF MAKING AVAILABLE
AS MUCH INFORMATION AS POSSIBLE.
-------
EPA-R2-72-072b
R272072A
"STATE OF THE ART"
FOR CONTROLLING
NOx EMISSIONS
PARTI. UTILITY.BOILERS
by
L. K. Jain, E. L. Calvin,
and R. L. Looper
Catalytic, Inc.
1515 Mockingbird Lane
Charlotte, N. C. 28209
Contract No. 68-02-0241 (Task No. 2)
Program element No. 1A2014
Project Officer: J. S. McSorley
Task Officer: R. E. Hall
Control Systems Division
National Environmental Research Center
Research Triangle Park, N. C. 27711
Prepared for
OFFICE OF RESEARCH AND MONITORING
U.S. ENVIRONMENTAL PROTECTION AGENCY"
WASHINGTON, D. C. 20460
September 1972
-------
EPA REVIEW NOTICE
This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or comnercial products constitute
endorsement or recommendation lor use.
ii
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ACKNOWLEDGEMENTS
Many Individuals and several organizations have been helpful In
developing this study. For these contributions, Catalytic, Inc. ex-
tends Its sincere gratitude. The following individuals deserve par-
ticular credit for their contributions:
Pacific Gas and Electric
Mr.
W.
Barr
Mr.
E.
Johnson
Southern California Edison
Mr.
D.
Felgar
Los Angeles Power and Light
Mr.
H.
Sonderllng
KVB Engineers
Mr.
N.
Bayard de Volo
Esso Research and Engineering
Dr.
W.
Bartok
Riley Stoker Company.
Mr.
A.
Rawdon
Foster Wheeler Corporation
Mr.
R.
Sommerlad
Combustion Engineering
Mr.
C.
Blakeslee
American Boiler Manufacturing Assn.
Mr.
W.
Axtman
Tennessee Valley Authority
Dr.
G.
Hoilenden
Bureau of Mines
Mr.
D.
Bienstock
-Hi-
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TABLE OF CONTENTS
pa&e
LIST OF FIGURES Vii
LIST OF TABLES IX
SUMMARY I
INTRODUCTION 3
SOURCES OF NO* 5
FORMATION OF NITROGEN OXIDES 10
A. Equilibrium and Kinetics 10
B. Factors Effecting Utility Boiler Emissions 14
1. Combustion Temperature 14
2. Availability of Combustion Air 14
3. Mixing of Fuel, Air and Combustion Products 14
4. Heat Release and Removal 14
5. Fuel Type 14
DISCUSSION (Combustion Modification for NOx Emission Control) ..15
A. Combustion Operating Modification 16
1. Load Reduction 16
a. Effect of Boiler and Fuel Type 16
b. Load Reduction Effects and Cost 19
2. Low Excess Air (LEA) Firing 20
a. Low Excess Air Gas-Fired Boilers .21
b. Low Excess Air Oil-Fired Boilers 25
c. Low Excess Air Coal-Fired Boilers 30
3. Load Reduction with Low Excess Air.. 35
Preceding page blank
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Page
4. Two-Stage Combustion 36
a. Two-Stage Combustion: Gas-Fired Boilers 38
b. Two-Stage Combustion: Oil-Fired Boilers 49
c. Two-Stage Combustion: Coal-Fired Boilers 55
d. Cost and Effectiveness: Two-Stage Combustion 60
5. Two-Stage Combustion with Low Excess Air and/or
Reduced Load 63
6. Reduced Preheat Temperature 66
7. Flue Gas Recirculation 67
a. Flue Gas Recirculation: Gas-Fired Boilers 71
b. Flue Gas Recirculation: Oil-Fired Boilers 76
c. Flue Gas Recirculation: Coal-Fired Boilers 78
d. Cost and Cost; Effectiveness of Flue Gas
Recirculation 79
8. Steam and Water Injection 81
9. Fuel Substitution ' 83
B. Combustion Equipment Design Modifications 86
1. Equipment Design 86
2. Burner Design and Configuration.. . t...90
3. Burner Location, Spacing and Tilt .93
C. Flue Gas Treatment 95
APPENDICES 97
Appendix A: Scattergood Unit No. 3:
Los Angeles Power and Light 97
REFERENCES 99
BIBLIOGRAPHY . .103
_vi-
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
7
11
13
18
26
26
32
41
59
68
70
72
75
77
87
88
LIST OF FIGURES
Caption
Total Estimated Oxides of Nitrogen Emitted from
Stationary Installations in the U. S. by Type of
Use and Tonnage, 1968
Nitrogen Oxide Equilibrium Concentrations
Kinetic (NO) Formation for Combustion of Natural
Gas at Stoichiometric Mixture Ratio - Atmospheric
Pressure
NO^ Load Reduction by Oil and Gas Fired Boilers
Effect of Excess Air on NOx Emissions from Oil-
Fired Boilers
N0X Emissions from Oil-Fired Boilers at Low
Excess Air
Effect of Lowering Excess Air and Two-Stage Com-
bustion on N0X Emission from Coal Combustion
N0X Concentration Obtained for Off-Stoichiometric
Burner Operation on a 220 MW Power Plant
Two-Stage Combustion: Coal-Fired Boiler
Effect of Combustion Air Preheat on NO Formation
Effect of Gas Recirculation on NO Formation
Gas Recirculation with Natural Gas Firing: 320
MW Corner Fired Unit
N0X Emissions from 320 MW, Tangential, Gas-Fired
Boiler
Recirculated Gas and Air Duct System for Oil or
Gas Fired Units
Gas-Fired Boilers Uncontrolled NOx Emissions Per
Furnace Firing Wall
Oil-Fired Boilers Uncontrolled N0X Emissions Per
Furnace Firing Wall
-vii-
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Figure Caption Pa^e
17 Coal-Fired Boilers Uncontrolled NOx Emissions
Vs. Gross Load Per Furnace Wall Firing 89
18 Effect of Burner Turbulence Natural Gas Firing 9?
19 Predicted Nitric Oxide Emission Vs. Mode of
Operation as Compared to Rule 67 98
-viii-
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LIST OF TABLES
Table Caption Page
1 Estimates of Nitrogen Oxide Emissions in the
United States, by Source, 1968. 5
2 Estimates of Tons of N0X in the United States,
1968 6
3 Average N0X Emissions from Utility Boilers fa
4a Electric Power Generation by Fuel, 1968 8
4b Contributions of N0X Emissions by Electric
Utilities for Each Fuel 8
5 N0X Reduction by Load Reduction 17
6 Nitrogen Oxide Emissions (ppm NOx) from Coal-
Fired Boilers 19
7 Reduction.in N0X by Low Excess Air Firing in
Gas-Fired Boilers 22
8 Cost of LEA Conversion (Gas-Fired Boilers) 24
9 Reduction in N0X Control by Low Excess Air in
Oil-Fired Boilers 2',
10 Low Excess Air Modification Costs: Oil-Fired
Boilers 30
11 500 lb/hr. Pulverized Coal-Fired Combustor 34
12 LEA Modification Costs - Coal-Fired Boilers 35
13 NOx Reduction Through Load Reduction and Low
Excess Air 36
14 Two-Stage Combustion - Gas-Fired Boilers 47
15 N0X Emissions: 320 MW Tangential Boilers 53
16 NO Reduction - Oil-Fired Boilers - Two-Stage
ana Off-Stoichiometric Combustion f<,
17 Two-Stage Combustion - Coal-Fired Boilers 56
-ix-
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Table Caption Page
18 NOx Reduction: Two-Stage Firing Test - Coal
Fired Furnace 58
19 Two-Stage Combustion Costs 62
20 Two-Stage Combustion with Low Excess Air and/or
Reduced Load 64
21 Summary of Emission Data from 320 MW, Tangential,
Gas-Fired
22 Cost of Flue Gas Recirculation 80
23 Cost of Water Injection 82
24 Fuel Costs by Region, 1970 85
-X-
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SUMMARY
Utility boilers fired by gas, oil or coal contribute 19.A per cent of
N0X to the atmosphere. The N0X is generated by thermal conversion of
nitrogen contained in the atmosphere and by conversion of fuel nitroger
The oxides of nitrogen can be controlled by combustion modification or
flue gas treatment. Because of the ease and quickness of adaptability
and lower cost, combustion modification is more viable and it has beer,
performed with different degrees of success in controlling N0X. The
work in reducing N0X from oil- and gas-fired boilers has been demon-
strated extensively both experimentally and commercially. The N0X
control from coal-fired boilers is still in the experimental stage, an<
thus far data are scarce. The following controls of N0X have been re-
ported by combustion modifications:
A. Boiler load reduction reduces N0X effectively in gas- and
oil-fired boilers and has been demonstrated in some coal-
fired boilers but this has the disadvantage of de-rating
the boiler.
B. Low excess air firing reduces NC^, along with improving
boiler performance. The limit of low excess air is gov-
erned by the tolerability limits of CO and hydrocarbons in
all boilers and slagging in coal-fired boilers.
C. The combination of low excess air at low load further reduces
N0X.
D. The off-stoichiometric firing and two-stage firing accom-
plished by firing some burners "fuel rich" and others on air
-1-
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alone or "air rich" reduce N0X up to 72 per cent in gas-fired
boilers and 50 - 60 per cent in oil- and coal-fired boilers.
E. The combination of two-stage combustion, low excess air and
load reduction has reduced the levels of N0X up to 90 per
cent and has in most gas-fired boilers reduced N0X to EPA
limits of 0.2 lb N0x/million BTU.
F. Reducing the peak combustion temperature by reducing air pre-
heat reduces N0X emissions, but at the penalty of reducing com-
bustion efficiency.
G. Recirculating a portion of flue gases through the burners, or
wind box reduces peak flame temperature, oxygen availability,
and hence N0X. The degree of N0X reduced is directly dependent
on the amount of flue gas recirculated to about 30% recircula-
tion.
H. Other techniques reported effective in NOx reduction ares
steam or water injection,in boilers; fuel switching; burner
design and configuration changes; and burner spacing, location,
and tilt.
I. The. cost of combustion modifications varies with the fuel
burned. The two-stage firing effected by overfire ports
costs between $0.15 - $0.25 for gas- and coal-fired boilers
where as complete equipment design change costs up to $3.30/KW.
The cost of flue gas recirculation for a 600 MW oil-, gas-,
and coal-fired plant is $1.65, $2.65 and $3.50 per kilowatt
respectively.
-2-
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INTRODUCTION,
The Clean Air Act of 1967 (Public Law 90-148 as amended) and the
Clean Air Amendment of 1970 (Public Law 91-604) assigned to the Envi-
ronmental Protection Agency (EPA) the responsibility of developing
emission standards for existing sources that are to be enforced by
the states, and setting performance standards for new.sources to be
enforced by the EPA.
Under the provisions of these laws, the EPA published the ''National
Primary and Secondary Ambient Air Quality Standards" on April 30, 1971,
in Federal Register, Volume 36, No. 84.
The National Primary and Secondary Ambient Air Quality Standards
for nitrogen oxides is 100 micrograms per cubic meter (0.055 parts per
million), annual arithmetic mean measured as nitrogen dioxide.
The EPA also published guidelines to the states for preparation,
adoption and submittal of implementation plans for enforcement of Na-
tional Ambient Air Quality Standards (Federal Register, Volume 36, No.
158, August 14, 1971) and the Performance Standards for New Stationary
Sources (Federal Register, Volume 36, No. 247, December 23, 1971).
The nitrogen oxides emissions from existing and new fuel burnxng
sources based on EPA published standards are as follows:
Fuel Burning Equipment
(Pounds per Million BTlQ
Gas Oil Coal
New Sources
0.2
0.3
0.7
Existing Sources
0.2
0.2
(Recommended in Implementation Plans) (175 ppm) (230 ppm)
-3-
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Both stationary as well as mobile sources contribute to N0X concen-
trations in the atmosphere. The objective of this report is to identify
the "State of the Art" of N0X emission reduction from stationary sources
through combustion modification. The first of the two part report deals
with the control of N0X from utility boilers. The Second segment of the
report deals with the control of NOx from industrial, commercial anc re-
sidential boilers.
-4-
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SOURCES OF NOx
Source estimates for nitrogen oxides emissions for the U. S. were
(1)
developed by the National Air Pollution Control Administration (now
the Environmental Protection Agency). Shown in Table 1, these estimates
of pollutant emission rates are based on emission factors developed by
past stack, sampling data, material balances and engineering appraisals
of other sources similar to the listed sources.
(1) (2)
Table 1
ESTIMATES OF NITROGEN OXIDE EMISSIONS IN
THE UNITED STATES, BY SOURCE 1968
Source NOx Emissions, Tor.s,Yr.
Mobile fuel combustion
Motor vehicles
Gasoline 6,600,000
Diesel 600,000
Aircraft 40,000
Railroad 400,000
Vessels 300,000
Non-highway users 300,000
Stationary fuel combustion
Coal 4,000,000
Fuel oil 1,110,000
Natural gas 4,640,000
Wood 230,000
Solid waste
Open burning 450,000
Conical incinerators 18,000
Municipal incinerators . 19,000
On-site incinerators 69,000
Coal waste banks 190,000
Forest burning 1,200,000
Agricultural burning 280,000
Structural fires 23,000
Industrial processes 200,000
Total 20,669,000
-5-
-------
Another independent source analysis has shown that stationary
sources contribute 9,790,000 tons/yr. of N0X, as shown in Figure 1
(1)
and Table 2.
Table 2
ESTIMATES OF TONS OF N0X IN THE UNITED STATES BY INSTALLATION, 1963
(1)
Type of Installation NOx (as HO2) Tons/Yr.
Electric utility 4,000,000
Industrial combustion 2,485,OOG
Pipelines and gas plants 2,280,000
Domestic and commercial 825,000
Non-combustion 200,000
U. S. Total 9,740,000
Electric utilities represent 19.4 per cent of the total nitrogen
oxide emissions from all sources. A comparison between coal, oil and
gas for these utilities is given in Table 3, which lists average emis-
sion factors on a uniform BTU basis for ready comparison.
(3)
Table 3
AVERAGE NOx EMISSIONS FROM UTILITY BOILERS
Lb. NOx/109
Fuel Calculated ds.-^Z
Natural gas 373
Fuel oil 693
Coal 842
-6-
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Figure 1. Total Estimated Oxides of Nitrogen Emitted From
Stationary Installations in U. S. by Type of-Use
And Tonnage, 1968
-7-
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Electric power generation by fuel for 1968 is shown in Table 4a:
(4)
Table 4a
ELECTRIC POWER GENERATION BY FUEL - 1968
Total KWH Produced, % *
27 .8
5.5
62.7
100.0
Fuel
Natural gas
Fuel oil
Coal
Total
* Nuclear power generation excluded.
Table 4b represents contributions of each type fuel to NO* emis-
sions, assuming a constant power generating efficiency (heat rate) in
BTU/KWH.
Table 4b
CONTRIBUTIONS OF NO EMISSIONS BY
ELECTRIC UTILITIES FOR EACH
; FUEL
Average KOx
Fraction of
Emissions
Portion of
Electric
Fraction of
Lb. NOX/109 BTU
Total KWH
Utility N0X
Total N0X
Fuel Calculated as N02
Produced, %
Emissions, %
Emissions, /
Natural gas 373
27.8
17.5
5.6
Fuel oil 693
9.5
11.2
2.2
Coal 842
62.7
71.3
13.8
Total
100.0
100.0
19.6
-8-
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In addition to man-made nitrogen oxides, there is a natural nitro-
gen cycle that generates 500,000,000 tons of N0X per year. N0X is re-
moved from the atmosphere by hydrolysis to form nitric acid, which is
then precipitated as nitrates in rainfall or dust. The residence time
(5)
of N0X in the atmosphere is only a few days. N0X is an essential
part of the natural nitrogen cycle of organic growth, decomposition
into the atmosphere and return to the soil as natural fertilizer.
The problem is one of local high concentrations since the urban
(6)
areas of the U. S. average 40 to 50 parts per billion (ppb), which
is much greater than the natural background level of 1 ppb. This has
led to approaches based on the total quantity of nitrogen oxides emit-
ted by individual sources.
Los Angeles County, California, is an example. The electric power
plants in Los Angeles County constitute the largest stationary source
of nitrogen oxide emissions and are clustered in discrete 'source areas'
where high ambient levels of NOx are recorded. The problem is j oroached
on the basis of pounds per hour of nitrogen oxide emissions in order to
lower the local concentrations. This results in increasingly stringent
requirements on boilers as a direct function of size. The result is a
(7)
much greater restriction for large boilers than small boilers.
-9-
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FORMATION OF NITROGEN OXIDES
A. Equilibrium and Kinetics
High temperature reaction of molecular nitrogen and oxygen
present in the combustion air in accordance with the following
chain-reaction mechanism forms most of the NO.
0 2 + 0 + 0.
0 • + N2 = NO + N*
n- + o2 = no + o.
In these high temperature processes the atmospheric nitro-
gen and oxygen perform the dominant role. The nitrogen in fuel
has a secondary effect in N0X formation.
NO is the major oxide of nitrogen formed in combustion pro-
cesses. The other oxides of nitrogen, such as NO2, N2O3, etc.
(8)
are formed from the NO. Typically, from Figure 2 , the con-
centration of nitrogen oxides formed at 3,000°F with natural gas
combustion at six per cent excess air is as follows: *
NO: 1,000 ppm
NO2: 1 ppm
N20^: 1 x 10 ^ ppm.
Spectroscopic studies of typical power plant gases also con-
(9)
firm that most of nitrogen oxides are in the form of NO.
The formation of NO is temperature-time-concentration de-
pendent. The reaction is controlled by a forward and reverse
equilibrium constant, as follows:
N2 + 02 2N0
At the rate of reaction (r)
r r r
net = forward - reverse
-10-
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Concentration of Nitro- Concentration of Xitro-
gen Oxides, % by Volume gen Oxides, ppm by Vol-
Temperature °F
Figure 2. Nitrogen Oxide Equilibrium Concentrations. Natural Gas Burned
with 6% Excess Air. (8)
-11-
-------
The rate and extent of the reaction increases rapidly with
increased temperature. The thermodynamic equilibrium constant
(3)
of reaction is given by
k = 21.9 e(~43,400/RT)_
The equilibrium concentration of NO at flame temperature and
(10)
stoichiometric mixture is 3,000 ppm. The NO levels found in
stacks are generally less than the equilibrium concentration cor-
responding to flame temperature, but higher than those correspond-
ing to stack gas temperature. This results in the prediction that
the NO concentration is determined by the time-temperature-compo-
siLion history of gases as they move through the combustion system.
A typical expression of the NO formation for combustion of
natural gas at stoichiometric mixture, showing time-temperature
(11)
behavior, is shown in Figure 3. Consequently, any technique
that can lower the flame temperature or reduce the time the gases
are at high temperatures will reduce the NO formation.
The concentration of various components influence equally
i
NO equilibrium. The equilibrium concentration is expressed as
k =
(n2) (o2)
and rforward = xi <02>
rreverse = *2 (NO)2 (O^-*5
where (NO) (02) (N2) are mole fractions of the respective
components and and X2 are temperature dependent con-
stants.
This expression leads to the conclusion that lower oxygen and
nitrogen concentration at high temperature will lead to lower NO
-12-
-------
TEMPERATURE °F
Figure 3. Kinetic (NO) Formation for Combustion of Natural Gas at
Stoichiometric Mixture Ratio - Atmospheric Pressure. ^
-13-
-------
formation.
B. Factors Affecting Utility Boiler Emissions
The major factors affecting the formation of nitrogen oxides
in combustion processes based on previous kinetic theory and in
actual practice are, as follows:
1. Combustion temperature. NO formation equilibrium and
kinetics are extremely dependent upon peak combustion
temperatures, with higher peak temperatures favoring
higher emissions.
2. Availability of combustion air. NO formation is depen-
dent upon the availability of air for the "fixation" re-
action .
3. Mixing of fuel, air and combustion products. Internal
recirculation or "backmixing" of combustion products in-
to the combustion zone dilutes the fuel and air, lowers
the flame temperature and thereby reduces N0X emissions.
Distribution of the fuel and air so as to achieve most
of the combustion under fuel-rich conditions also re-
duces N0X emissions. Slow diffusion of the fuel and air
streams can also accomplish this objective.
4. Heat release and removal. Low heat-release rates and high
heat-removal rates reduce NO formation, because lower peak
temperatures and shorter residence times at high tempera-
tures are achieved.
5. Fuel type. On an equivalent heat-input basis, using modi-
fied combustion techniques, coal firing usually emits the
most N0X; oil emits less; and gas the least.
-14-
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DISCUSSION
Combustion Modification for N0X Emission Control
NOx emissions from boilers can be reduced by two methods; com-
bustion modification and flue gas treatment.
Combustion modification appears to be the quicker and possibly
the more economical method to control NO* emissions to desired levels.
Combustion modification can be further divided into two major cate-
gories; combustion operating modification and combustion equipment
design modification.
The major combustion operating modifications are:
1. Load reduction
2. Low excess air firing
3. Load reduction with low excess air
4. Two-stage combustion
5. Two-stage combustion with low excess air and/or load
reduction.
6. Reduced preheat temperature
7. Flue gas recirculation
8. Water or steam injection
9. Fuel substitution
The major combustion equipment design modifications are:
1. Furnace design
2. Burner design/configuration
3. Burner tilt, location, spacing.
The details of the "State of the Art" of the above modifications
and their effects are discussed individually for different fuels
-15-
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(coal, oil and gas) in the following section.
A. Combustion Operating Modification
1. Load Reduction
a. Effect of Boiler and Fuel Type
Operating most boilers at a reduced load lowers N0X
emissions. The reduction of the N0X is dependent on the
fuel being used in the boiler. Gas-fired boilers re-
spond with greater N0X reduction than oil- and coal-
fired. (12)
Load reduction in various gas- and oil-fired units
(13)
were tested by ESSO. The results of N0X reduction
by load reduction for various types of boilers are sum-
marized in Table 5. The same results are also shown in
Figure 4 to illustrate the relative degree of N0X con-
trol in oil- and gas-fired boilers.
-16-
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Table 5
N0X REDUCTION BY LOAD REDUCTION
Boiler Type and Operating
Size Load, MW
Load Re-
duction,%
NOx Emis-
sion, ppm
NOx Re-
duction^
Reference;
180 MW Front Wall,
180
0
390
0
(13)
Gas-Fired
120
33
230
41
(13)
7.0
61
116
70
(13)
80 MW Front Wall,
82
0
497
0
(13)
Gas-Fired
50
39
240
52
(13)
20
76
90
82
(13)
480 MW Horizontally
450
0
236
0
(13)
Opposed, Gas-Fired
220
51
166
30
(13)
600 MW Horizontally
560
0
560
0
(13)
Opposed, Gas-Fired
410
27
335
40
(13)
335
42
253
55
(13)
220 MW All Wall,
220
0
675
VJ
(13)
Gas-Fired
190
14
550*
19
(13)
125
43
313
54
(13)
180 MW Front Wall,
180
0
367
0
(13)
Oil-Fired
120
33
322
12
(13)
80
56
266
28
(13)
80 MW Front Wall,
82
0
580
0
(13)
Oil-Fired
50
39
361
38
(13)
21
74
258
54
(13)
350 MW Horizontally
350
0
457*
0
(13)
Opposed, Oil-Fired
154
56
264*
42
(13)
480 MW Horizontally
455
0
246
0
(13)
Opposed, Oil-Fired
365
20
219
11
(13)
(13)
* Estimated values reported by ESSO for comparison.
-17-
-------
x gas
o oil
LOAD REDUCTION %
Figure 4. N0X reduction at reduced loads - oil- and gas-fired boilers
-18-
-------
has shown a decrease in NO emissions
(12)
In general, the load reduction in coal-fired boilers
The Combustion
Engineering work reports 25 per cent decrease of NO
emission with a 25 per cent load reduction. The results
of Cuff and Gerstle (1967) work on coal-fired boilers as
(14) (15)
summarized in the literature is presented in
Table 6.
Type of Firing
Table 6
NITROGEN OXIDE EMISSIONS (ppm N0X) FROM
(14) (15)
COAL-FIRED BOILERS
Full Load, Mean of 3 or
4 Tests at Each Unit
Partial Load, Mean of 2
Tests at Each Unit
Before Fly- After Fly- Before Fly- After Fly-
ash Collector ash Collector ash Collector ash Collector
Vertical
221
310
161
171
Corner
526
413
393
325
Front Wall
416
606
500
453
Horizontally
Opposed
393
350
395
328
Spreader Stoker
431
437
430
!y'J
Cyclone
1,204
1,160
742
784
b. Load Reduction Effects and Cost
Boiler load reduction reduces fuel input and, hence,
other pollutants, such as CO, SO2 and hydrocarbons, are
also reduced relative to fuel reduction.
-19-
-------
There are no capital costs involved in load reduction;
however, it is an undesirable option for utilities to re-
duce boiler capacity. The load reduction increases the
boiler efficiency but decreases turbine efficiency with a
net result in decrease in overall efficiency. The loss of
capacity has to be compensated by starting other power
generating equipment which may be idle, or by increasing
the capacity by installation of additional equipment.
2. Low Excess Air (LEA) Firing
The amount of air relative to fuel fed to the combustion
process had an effect on the level of nitrogen oxides emitted.
The rate equation for NO formation is written as follows:
X (16)
N0X Formation Rate = K
Other factors being equal, an increase in oxyfen concen-
tration (excess C^) will increase both the rate of formation
and its equilibrium concentration.
The effects of low excess air firing on oil- and gas-fired
boilers are well documented, but the effect on coal has been
limited to laboratory scale and few full scale tests. "Low
excess air firing" is a relative term, because of the boiler-
to-boiler variation in the normal level of excess air, as
established by boiler operators, depending on fuel type,
boiler design and operating conditions.
The effects of low excess air by fuel types reported in
the literature and practice are described in the following
sections.
-20-
-------
a. Low Excesa Air Gas-Fired Boilers
Gaseous fuels are "burned at a normal 10-15 per cent
excess air and have a Tesultant NOx emissions range from
200 to 1,500 ppm, depending on type and size of the boil-
er. The lower limit of excess air is determined by the
need to limit the emissions of unburned combustibles
(CO, hydrocarbons) to control operating problems. The
ease of fuel and air mixing in gas-fired boilers facili-
tates lowering the excess air to very near the stoichio-
metric amounts with proper instrumentation.
The lower excess air conversion is achieved by prac-
tically no major modification to the boiler; however,
an instrument control system to give a precise method
for proportioning fuel and air is required to provide
safe and efficient operation.
Effect of LEA on Gas-Fired Boilers
LEA in gas-fired boilers has shown to produce a 15-
(13)
23 per cent decrease in N0X in tests run by ESSO.
In the Pacific Gas and Electric Moss Landing 750 MW
boilers, the lowering of excess air from ten to five
per cent reduced the N0X from 1,475 ppm to 1,000 ppm,
(17)
a reduction of 33 per cent.
With proper technique and instrumentation, LEA does
not result in any boiler problem or other pollutant in-
crease, but improper control can result in higher CO
emissions and possible boiler vibration. A detailed list
of tests results is given in Table 7 to show the reduction
in N0X by low excess air firing in gas-fired boilers.
-21-
-------
Table 7
N0X REDUCTION BY LOW EXCESS AIR- GAS-FIRED BOILERS
NOx Emission ppm NOx Emission ppm
Normal Excess Air Excess Air Low Excess Air
Boiler Type and Size (3% 0? Dry Basis) % 02 (3% O2 Dry Basis) % O2
Excess Air N0X Re-
duction^ Reference
1
KJ
NJ
I
180 MW, Front Wall
80 MW, Front Wall
350 MW, Horizontally
Opposed
450 MW, Horizontally
Opposed
600 MW, Horizontally
Opposed
220 MW, All Wall
750 MW, Front Wall
250 MW», Tangential
390
497
946
236
560
675
1,475
375
2.75
4.18
2.6
4.0
2.3
3.3
3.9
332
421
783
198
478
519
1,000
250
1.1
2.59
1.6
3.0
1.2
1.7
.6
15
15
21
16
15
23
23
37
(13)
(13)
(13)
(13)
(13)
(13)-
(17)
(18)
-------
Cost and Cost Effectiveness of LEA on Gas-Fired Boilers
The costs for conversion to low excess air firing
are estimated on the basis that instruments would, be
required for precise combustion control. It is assumed
that 1,000 MW plants would require no capital charges,
10 per cent of 750 MW plants, 25 per cent of 500 MW
plants, 50 per cent of 250 MW plants and 90 per cent
of 120 MW plants will require capital investment for
modification to improve fuel distribution and rest'
(3)
would be converted at no cost.
It is also assumed that low excess air would result
in a one per cent improvement in efficiency and, hence,
reduce the annual operating and fuel cost of the boiler.
(3)
A detailed breakdown of costs is given in Table 8.
-23-
-------
(3)
Table 8
COST OF LEA CONVERSION (GAS-FIRED BOILERS)
Plant Size
Capital Cost
Annual
Capital
Costs
Annual
Maintenance
Costs
Other
Operating
Costs*
Total
Annual.
Costs*
1,000 MW
$120,000
$17,000
$21,000
($102,000)
($95,000)
750 MW
$119,000
$15,300
$18,900
($120,000)
($68,000)
500 MW
$106,000
$12,500
$15,400
($' 62,900)
(¦?35,000)
250 MW
$ 82,000
$ 8,600
$10,800
($ 23,400)
($ 4,000)
120 MW
$ 63,000
$ 6,200
$ 7,600
($ 3,800)
$10,000
* Figures in
parentheses
indicate operating savings.
Where, annual
capital cost
is calculated as 14% of
fixed cost.'
' This
covers depreciation interest and other fixed cost.
Annual maintenance cost is the total cost of maintenance supplies and
overhead. The maintenance is estimated at 10% of fixed cost for instrur-
ments, 5% of fixed cost for modifications having moving parts and 1% of
fixed cost for modifications having no moving parts. Supplies are at
15% of maintenance and overhead is 50% of maintenance plus supplies.
Other operating cost is the cost due to increase or decrease in the
operating efficiency of the boiler.
Total annual costs are the additions of annual capital costs, annual
maintenance cost and other operating costs.
-24-
-------
b. Low Excess Air, Oil-Fired Boilers
Low excess air boiler operation in oil-fired units
was developed in the United-Kingdom in the 1950's to
overcome undesirable operating conditions such as low
temperature corrosion and air heater plugging. It is
now standard practice in oil-fired boilers to operate
at low excess air, generally below five per cent. Pre-
viously the normal excess air in oil-fired units was
(19) (20)
13 to 20 per cent.
Low excess air in oil-fired units is. achieved by
re-adjusting the air flow to burners without major mo-
dification to the boiler itself. N0X reduction of 36
per cent in a horizontal oil-fired boiler and 28 per
cent in a tangential fired unit were obtained as flue
gas oxygen (excess air) was reduced from 3.5-4 per
cent to 2 per cent. A further reduction of excess air
(0.4 - 0.6 per cent oxygen) reduced NOx up to 67 per
(21) (22) .
cent. The results of NOx reduction are
documented in Figures 5 and 6.
The results of N0X control in oil-fired boilers is
tabulated in Table 9.
-25-
-------
Figure 5: Effect of Excess Air on N0V Emis-
(21)
sion from Oil Fired Boilers
£
Q.
a
x
o
z
700
1
1
V* 1
600
-
/ Horizontal
-
500
J
f Firing
-
400
X
_
300
-
Tangential
Fired
-
200
-
-
100
'
1
.l_ -.1
12 3 4
Oxygen in Flue Gas, %
Figure 6: N0X Emissions from Oil Fii e '
(22)
Boiiers at Low Excess Air
2 3 4
Oxygen in Flue Gas, %
-26-
-------
Table 9
N0V CONTROL BY LOW EXCESS AIR-,OIL-FIRED BOILERS
N0„ ppm
NOx ppra
(LEA)
Boiler Type and (Normal Air) Excess Air (LEA) Excess Air NOx Re—
Size (3% O? Dry Basis) 02% (3% 0? Dry Basis) 0?% ductlon,% Reference
180 MW, Front Wall
367
3.9
238
1.7
35
(13)
80 MW, Front Wall
580
3.65
470
2.2
19
(13)
i
to
—J
I
350 MW, Horizontally
Opposed 457
*3.0
442
1.4
(13)
480 MW, Horizontally
Opposed 246
220 MW, All Wall 291
180 MW, Front Wall 621
4.7
3.9
2.5
223
235
452
3.6
2.6
0.5
23
27
(13)
(13)
(19)
* Estimated
-------
(19)
A study by Los Angeles Power and Light ' shows
that the average heat rate was reduced by 60 BTU/KWH.
The control of low excess air in oil-fired units is
achieved by instruments to detect unburned combustible
material; however, visible smoke is a good indicator
of the limit of low excess air.
Low excess air firing in oil-fired units has shown
an increase in ash generation, but a decrease in corro-
sion due to a possible reduction in the formation of
so3. (3)
Cost and Cost Effectiveness of Low Excess Air in Oil-
Fired Boilers
Low excess air operation in oil-fired units, as in
the gas-fired units, is achieved without incurring in-
vestment costs for alterations or redesign, especially
in larger units. In preparation of cost estimates in
(3)
Table 10, it is assumed that 10 per cent of 750 MW,
25 per cent of 500 MW, 50 per cent of 250 MW and 90 per
cent of 120 MW plants will require alteration in design
to achieve low excess air operation, and the remainder
could be converted at no cost. The required cost in-
volves modifying the burner windbox by addition of
division plates and isolating dampers to the air to
each burner for individual control. Also, a sophisti-
cated combustion control instrument system would be re-
quired to provide safe operation at low excess air.
-28-
-------
As pointed out by Los Angeles Power and Light
and other sources, the low excess air provides a fuel
saving and corrosion and maintenance reduction. A
net two per cent increase in efficiency is assumed for
cost estimates.
The fuel savings are calculated by net heat rate re-
duction in BTU/KWH. Los Angeles Power and Light showed
a heat rate reduction by low excess air of 60 BTU/KWH
(19)
in test data. The fuel savings in Los Angeles
Power and Light were calculated as:
Fuel dollars saved per year =
Dollars x Heat Rate Reduc- x Net Generator x
Million BTU tion BTU/KWH Load, KW
(Plant (Oil Burning
(Operating Hours) x Load Factor) x Time Factor)
where dollars per million BTU is the cost of fuel;
heat rate reduction is calculated experimentally before
and after low excess air; net generator load, operating
hours and plant loading factors are regular plant opera-
ting parameters; and oil burning time factor is the
fraction of time the boiler is on oil-firing if the
boiler is designed for multi-fuel burning. These cal-
culations produced a new fuel savings of $9,676 for a
173 MW plant burning 0.335 dollars per million BTU oil,
42 per cent of the 8,280 operating hours at 0.8 load
factor for 60 BTU/KWH fuel rate savings.
More generalized savings from oil-fired boilers are
given in Table 10, based on two per cent increase in
-29-
-------
(3}
the efficiency of the boiler.
Table 10
(3)
LOW EXCESS AIR MODIFICATION COSTS: OIL-FIRED BOILERS
Boiler
Size
Capital
Cost
Annual
Capital
Charges
Annual Main-
tenance Cost
Other Opera-
tion Costs *
Total Cost
Per Year *
1,000
$120,000
$17,000
$21,000
($335,000)
($297,000)
750
$119,000
$15,300
$18,900
($260,000)
($226,000)
500
$106,000
$12,500
$15,500
($150,000)
($132,000)
250
$ 82,000
$ 8,700
$10,800
($ 52,500)
($ 33,000)
* Figure in paranthesis Indicates operating savings.
c. Low Excess Air, Coal-Fired Boilers
Low excess air in coal-fired installations has not
been commercially applied or the application has not
been documented. Coal, of all the fuels, requires the
highest excess air for good combustion generally, 20
to 50 per cent excess air. Tests on a laboratory unit
(23)
with a single burner have indicated that low ex-
cess air lowers NOx in pulverized coal combustion the
same as in oil and gas combustion. The laboratory study
showed a 62 per cent NOx reduction by lowering excess air
from 22 to five per cent.
It appears that low excess air application in coal
combustion would be more difficult than in oil- and gas-
fired boilers. Furnace slagging is also increased with
decrease in excess air, thus causing operating" problems
and increased maintenance. Regulation of uniform coal
streams to burners from a single pulverizer is difficult.
-30-
-------
Introducing lew excess air to each burner and maintain-
ing the same combustion conditions are even greater
problems.
Laboratory scale experiments in coal combustion with
lower excess air showing an N0X decrease are documented
in Figure 7.
The data obtained by Bienstock et al. from a
laboratory furnace show the following N0X reduction by
lower excess air.
Excess Air, % N0x» PPm Carbon in Ash, %
0 105 42.3
5 210 13.8
22 550 2.0
The above data also indicate that, as the N0X was
lowered by reducing excess air, the combustion effi-
ciency was adversely affected. The heat transfer in
larger boilers will probably be similarly affected.
Further experiments with low excess air firing
were performed on a four-burner 500 lb/hr. pulverized
coal-fired boiler by Bienstock et al. The results
show a decrease of N0X from 570-580 ppm at a 25 per
cent excess air, a 70 per cent decrease. The combus-
tion efficiency dropped from 99.5 per cent to 92.3
per cent under the same conditions. The sulfur cxides
emission is lowered by low excess air, and the sulfur
in ash increased correspondingly. Details of these
-31-
-------
280 0 240 0 2000 1600 1200 800 4 00 0
TEMPERATURE °F
Figure 7: Effect of Lowering Excess Air and Two-Stage Combustion
on N0X Emission from Coal Combustion.
-32-
-------
(24)
results are outlined In Table 11.
The short-term full-scale experiments by ESSO
with low excess air in a 175 MW front wall, coal-fired
power plant reduced N0X emissions by 14 per cent, and
in a 300 MW tangential coal-fired plant by less than
10 per cent. In recent ESSO tests, NO reductions of
up to 40 per cent have been achieved. However, the long-term
effect on corrosion and tube corrosion under these
test conditions is still being investigated.
-33-
-------
(24)
Table 11
500 LB/HR. PULVERIZED COAL-FIRED COMBUSTOR
Excess Carbon Effi- S02 Furnace S in Ash
Air,% NOx» ppm ciency, % Outlet:, ppm % by Wgt.
25.7 571 99.5
25.0 583 99.5
23.5 - 99.3
21.A 567 98.2 1,415 7
20.7 - 98.4 1,449 6
20.1 527 98.4 1,459 3
19.4 570 99.2
16.2 481 98.4
10.8 412 96.6 1,520 5
9.1 376 96.3
8.5 383 96.7
6.9 338 96.7
5.4 382 95.7 1,651 1
4.8 329 95.7 1,657 4
4.3 ~ 96.7
3.8 303 96.2 1,785 4
2.4 - 92.3
1.4 174 92.3
-34-
-------
Cost and Cost Effectiveness of LEA in Coal-Fired. Boilers
The cost incurred in applying low excess air in
coal-fired boilers will result from addition of divi-
sion plates and isolation dampers to control air in
each burner. In addition, some means of insuring uni-
form distribution of the coal to all burners served by
the same pulverizer will be required. It is assumed
that a 50 per cent increase in cost over the oil- and
gas-fired units will cover the additional costs required
(3)
by coal-fired units. The savings in efficiency in the
coal-fired units at low excess air are estimated at 1.5
(3)
per cent. The results of cost and cost effectiveness
(3)
for various size plants are estimated, as follows:
Table 12
(3)
LEA MODIFICATION COSTS, COAL-FIRED BOILERS
Boiler
Size, MW
Total *
Capital
Cost
Annual
Capital
Cost
Annual Main-
tenance Cost
Other
Annual
Costs
Total
Annual
Costs
1,000
$480,000
$67,000
$52,000
($198,000)
($79,000)
750
$385,000
$54,000
$42,000
($155,000)
($59,000)
500
$275,000
$38,500
$30,000
($ 95,500)
($27,000)
250
$159,000
$17,500
$17,500
($ 39,500)
0
120
$ 88,000
$12,300
$10}000
($ 11,300)
$11,000
* Also assumed that all the coal-fired boilers require investment for
modification.
3. Load Reduction with Low Excess Air
Load reduction in low excess air combinations tested
in gas, oil and coal units resulted in lower N0X emissions,
-35-
-------
than either alone. The techniques and costs involved with
these systems are the net combined effects of the two modi-
fications; individually, however, the results obtained in
NOx reductions are not additive. The results are summarized,
as follows:
Table 13
(13)
NOx REDUCTION THROUGH LOAD REDUCTION AND LOW EXCESS AIR
N0X (? Reduced
Reduced NOx Without Load & Low Ex- % of Re-
Boiler Type Operating Controls, ppm cess Air, ppm duction
and Size Load (MW) (3% 0? Dry Basis) (3% 0? Dry Basis) (Overall)
180 MW, Front Wall 120 390 188 52
Gas-Fired 70 390 108 72
80 MW, Front Wall 50 497 170* 65*
Gas-Fired
480 MW, Horizontally
Opposed 220 236 120 49
600 MW, Horizontally 410 560 271 51
Opposed 325 560 185 67
180 MW, Front Wall 120 367 241 33
Oil-Fired 80 367 190 4S
80 MW, Front Wall 50 580 318 45
Oil-Fired 21 580 185 68
350 MW, Horizontally 150 457* 228 50
^Opposed, Oil-Fired
480 MW, Horizontally 365 246 183 25
¦Opposed 228 246 163 34
* Estimated Values.
4. Two-Stage Combustion
Two-stage combustion was developed by Southern California
Edison and Babcock and Wilcox Company in a cooperative effort.
The application of delayed mixing of air and fuel and operation
-36-
-------
of burners with less than the normal amount of combustion air
led to a reduction in N0X emissions. The application led to
Investigation of burners operating with about 95 per cent of
the stoichiometric air admitted through the burner throat and
the remainder of the air to complete combustion through ports
(referred to as NO ports) located above the burners.
Additional work by Southern California Edison and KVB engi-
(25)
neers produced the technique referred to as "Off-Stoichio-
metric Firing." This technique involves firing some burners
"fuel rich" and others "air rich" or in staggered configuration
with some burners supplying air only.
The off-stoichiometric firing and NO ports for two-stage
combustion have been proven commercially successful in' oil-
and gas-fired units and have been demonstrated in laboratory
and full-scale in coal-fired units.
The effect of two-stage combustion on N0X emissions may
(3)
be explained by a combination of following factors: (a) there
is a lack of oxygen available for N0X formation in the first-
stage operated under sub-stoichiometric air conditions;
(b) the flame temperature may be lower in the first-stage
than in normal combustion; (c) to the degree that the heat is
removed between stages, the maximum flame temperature in the
second-stage is lower than for single-stage combustion; (d) the
effective residence time available for NOjj formation at the
peak temperature reached in the second-stage may be reduced.
-37-
-------
a. Two-Stage Combustion; Gas-Fired Boilers
The reduction in NQc in two-stage combustion is
achieved by adding NO ports to admit secondary air or
by operating the burners "air rich" and "fuel rich" in
a staggered manner. The optimum arrangement is achieved
by experimenting with each boiler. As a general rule,
the boilers with more than four horizontal rows of bur-
ners are easy to control by air alone in top row or rows
and fuel-air in other rows of burners. Several experi-
ments were conducted by utilities and their consultants
in reduction of N0X by two-stage combustion. The stag-
ger arrangements and results are listed under "Effects of
Two-Stage Combustion: Gas-Fired Boilers" in the following
section.
Effects of Two-Stage Combustion: Gas-Fired Boilers
To facilitate discussion of off-stoichiometric firing,
a term, "Equivalence Ratio," defined as the ratio of
stoichiometric air/fuel to actual air/fuel, is used.
Operation of top row/rows of burners on air alone repre-
sents two-stage combustion, whereas zig-zag patterns of
"air alone" burners or "air rich," "fuel rich" combination
firing represents off-stoichiometric combustion. Sometimes
the pattern has little effect on NO emission; however, in any
given pattern, a boiler may be limited by high CO. The
optimum operation of off-stoichiometric combustion is ob-
tained by operating in a pattern which produces the least
-38-
-------
NO at no significant increase in CO (generally below 50
ppm). The result of KVB-Southern California Edison and
ESSO and other tests on gas-fired boilers are as follows:
(i) Huntington Beach Unit 2: In a 220 MW wall-fired
unit with four horizontal rows of six burners each
for a total of 24 burners, the first series of taste
were run operating some top row burners on air alone
and the rest "fuel rich" to simulate two-stage com-
bustion. With four burners on air alone (17 per
cent air by-pass), and the remaining burners operat-
ing at an Equivalence Ratio of 1.2, the NO concen-
tration decreased from 470 ppm to 230 ppm. With six
burners on air alone (25 per cent air by-pass), and
"fuel rich" burners at an Equivalence Ratio of 1.33,
(11)
the NO concentration decreased to 180 ppm.
The same off-stoichiometric conditions have been
successfully tried and incorporated at Mandalay
(26)
units.
The burner configurations in the Huntington Beach
units are as follows:
0 A 0 A 0 A
0 0 0 0*00 A: Air only
A 0 A 0 A 0 0: Fuel rich
0 0 0 0 0 0
-39-
-------
and in Mandalay units as follows:
0
A
0
A
0
A
A
0
A
0
A
0
0
0
0
0
0
0
0
0
0
0
0
0
(ii) In a second test on a boiler similar to the above,
some burners were operated "air rich" and the re-
maining "fuel rich." The air and fuel "richness"
were achieved by terminating fuel in every other
spud on selected burners ("air rich") and increas-
ing the fuel flow on the remaining burners ("fuel
rich"). In the tests with six and twelve "air rich"
burners respectively, the N0X was reduced from the
original 470 ppm to approximately 250 and 180 ppm,
respectively. The CO and unburned hydrocrabons were
lower than in test (i) because of the more uniform
(11)
injection flow across the entire boiler face.
The results of tests (i) and (ii) are both plotted
in Figure 8.
(iii) In tests on four 480 MW front wall fired units,
"NO port" openings permitted reduction of NC^from
700-750 to 390-400 ppm. Further reduction of NC^to
200 ppm (reduction of 70 per cent) was obtained by
applying off-stoichiometric firing techniques by oper-
ating "fuel" and "air rich" burners in conjunction
with open "NO ports." In two of the four units
-40-
-------
Gas Burners Equivalence Ratio,
I I I J I
24 2 2 20 18 16
Burners on Gas
Figure 8. N0X Concentration Obtained for Off-Stoichiometric Burner Operation
on a 220 MW Power Plant. (H)
-41-
-------
tested, division wall failures due to over-heating
were experienced. Although the contribution of
off-stoichiometric firing to the failure was incon-
clusive, this method of firing was temporarily sus-
(26)
pended.
(iv) A 180 MW front wall fired boiler with four rows of
four burners each was tested for N0X reduction with
staged firing. At normal load and excess air the
emissions of N0X were reduced from the original 390
ppm without staged firing to 190 ppm with staged
(13)
firing. The pattern of staged firing was as
follows:
0
0
0
0
A
0
0
A
A: Air only
0
A
A
0
0: Fuel rich
0
0
0
0
Hydrocarbon content showed no increase, and CO
measurements were inconclusive at full load operation.
(v) In an 80 MW front wall fired boiler with two rows
of six burners each, the NOx reduced from a normal
(13)
500 ppm to 376 ppm in staged firing. The burner
arrangement for "fuel rich" and air only was as
follows:
0 A 0 0 A 0 A: Air only
0 0 0 0 0 0 0: Fuel rich
-42-
-------
Other pollutants at staged firing conditions
(13)
showed no significant increase. The authors
predicted that the following alternate burner
patterns could further reduce NO :
0 A 0 0 A 0 0 A 0 A 0 A
or
0 0 A A 0 0 A 0 A 0 A 0
However, no data were obtained on these patterns.
(vi) A 350 MW horizontally opposed unit equipped with
"NO ports" was tested under normal condition with
"NO ports" closed, two-stage combustion with "NO
ports" open and off-stoichiometric combustion with
(13)
"NO ports" open. During the series of tests, the
NOjj emissions were reduced from 950 ppm at normal
condition to 515 ppm with "NO ports" open and to
275 ppm with "NO ports" open in combination with
(13)
off-stoichiometric firing. The off-stoichiometric
conditions were achieved by changing the burner firing
configuration, as follows:
0 0 0 AAA
0 0 0 0 0 0
0 0 0 0 0 0
to
0 0 0 0 0 0
0 0 0 0 0 0
0 0 0 0 0 0
(vii) In a 480 MW horizontally opposed boiler, the boiler
(13)
is permanently in the following staged configuration:
-43-
-------
A A A A
(front and rear furnace faces)
0 0 0 0
0 0 0 0
0 0 0 0
In addition, it also has eight "NO ports" for additional
effect of two-stage combustion. The initial NO^ levels
were not known. The N0X emissions at off-stoichio-
metric conditions are 236 ppm with the "NO ports"
open. The CO levels did not change appreciably under
the changed conditions.
(viii) The 220 MW All wall boiler has the following con-
(13)
figuration of burners.
Rear Division WalI
12 II
Left
End
9
8 7
12 II
3
2 1
6 5
10,
Right
End
Front
At full load and all turners under normal firing,
the N0X emissions were 675 ppm. With staged fir-
ing of 18 burners, "fuel rich," and six burners,
air only (Nos. 9, 10, 10), N0X emissions were re-
duced to 286 ppm. Converting the firing to opposed
-44-
-------
wall and providing air alone to eight burners <3, 4,
9, 10), N0X emission were 359 ppm. The boiler was
capable of generating a maximum load of 190 MW. CO
measurements were always less than 100 ppm and hydro-
carbons less than one ppm. In two further experiments
to simulate boilers with corner firing, burners 1, 3,
5, 7, 9, 11 were operated with air only and with no
air or fuel. In both cases, the maximum power out-
put lowered to 125 MW. The N0X emissions were 130
ppm in cases where burners were on air alone and
350 ppm when the corner burners had no air or fuel,
(ix) In 1959, two 175 MW front wall fired Southern Cali-
fornia Edison units at El Segundo were converted to
two-stage combustion by the addition of "NO ports."
The boilers with 16 burners were supplemented with
four auxiliary air ports ("NO ports"). The N0X
emissions were reduced from 520 ppm normal to 305
ppm in two-stage combustion. The units have since
been operating also with off-stoichiometric firing.
(28)
No results are available from this operation,
(x) In the tests run by Combustion Engineering on a 250
MW tangentially fired unit, staged combustion by
overfire simulation (operating three rows of burners
"fuel rich" and top row on air alone) reduced the
(18)
N0X emissions from 330 ppm to 90 ppm at full load.
-45-
-------
Overall Summary of Two-Stage Combustion on Gas-Fired .
Boilers
Several tests reported in the preceding section and
others reported in literature have resulted in a reduction
of NO^ from gas-fired boilers. The reduction of N0X from
the base-line levels with no controls have ranged from 25
to 72 per cent reduction. The results in tests discussed
above and others reported are summarized in the following
table.
-46-
-------
Table 14
TWO-STAGE COMBUSTION. GAS-FIRED BOILERS
NOx
Emissions
Two-Stage NOx Emissions
Combustion Two-Stage Total
N0X
or
Combustion and
NOx
Emissions
"NO Ports"
Off-Stoichio-
Reduc-
Boiler Type
(No Control)
Alone
metric Firing
tion
and Size
(3% 02 Basis)
(3% 0?Basis)
(3% 02 Basis)
7.
Referent
220 MW Front
470
230 (17% air
51-
(26)
Wall
by-pass)
180 (25% air
62
(26)
by-pass)
47
470
-
250 (burners
(26)
air-rich)
180 (12 burners
62
(26)
air-rich)
480 MW Front
700-
390-400
200
72
(11)
Wall Fired
750
180 MW Front
390
_
190
51
(13)
Wall
80 MW Front
500
—
376
25
(13)
Wall
300 MW Hori-
950
515
275
71
(13)
zontally
Opposed
480 MW Hori-
-
236*
145
38
(13)
zontally
Opposed
220 MW All
675
-
286
58
(13)
Wall
175 MW Front
520
—
305
31
(28)
Wall
250 MW Tan-
330
_
90
73
(IS)
gential
175 MW B&W
450
330
245
45
(26)
450
330
300
33
(26)
-47-.
-------
Table 14
TWO-STAGE COMBUSTION, GAS-FIRED BOILERS
(Continued)
Boiler Type
and Size
78 MW Tan-
gential
160 MW Tan-
gential
230 MW Tan-
gential
418 MW Tan-
gential
N0X
Emissions
(No
Control)
140
280
N0X
Emissions
Two-Stage
Combus-
ion or
"NO Ports"
Alone
70
120
200
250
90
140
N0X Emissions
Two-Stage
Combustion and
Off-Stoichio
metric Firing
Total
N0X
Reduc-
tion
%
50
57
55
44
References
(12)
(12)
(12)
(12)
* The 480 MW unit is permanently equipped with off-stoichio-
metric burning air ports and auxiliary "NO ports" that can be
opened or closed.
-48-
-------
b. Two-Stage Combustion; Oil-Flred Boilers
The two-stage combustion in oil-fired boilers is
achieved the same as in gas-fired boilers by adding
"NO ports" and/or by operating some burners "air
rich" and the remaining "fuel rich". The control of
off-stoichiometric combustion with oil-fired boilers
is more difficult than with gas-fired boilers. Un-
balanced two-stage combustion could produce smoke in
oil-fired boilers and result in increased unburned
hydrocarbon emissions. Some boilers are equipped
with extra fuel guns, making it easier to offer
"fuel rich", "air rich" operation.
Effects of Two-Stage Combustion on Oil-Fired Boilers
Several oil-fired boilers are being tested and
operated on two-stage combustion and/or off-stoichio-
metric combustion. The test results are as follows:
(i) In a 180 MW front wall fired plant having 20
burners, but operating only 16 burners, the
normal NOx was 367 ppm. The same boiler at the
two-stage combustion condition with the follow-
ing burner arrangement of aip alone and air-
fuel produced 253 ppm NO , a 31 per cent
(13) .
reduction.
Burner Patterns
0
0
0
0
A
0
0
A
0
A
A
0
0
0
0
0
-49-
-------
(ii) In an 80 MW front wall fired unit, N0X was
reduced from 580 ppm at normal conditions to
404 ppm in staged firing. The burner patterns
during normal firing and staged firing were as
(13)
follows:
Normal Staged
000000 0 A 0 0 A O
000000 000000
CO concentration did not increase appreciably,
(iii) A 350 MW horizontally opposed Babcock and Wil-
cox boiler, equipped with "NO ports" for two-
stage combustion, was tested under normal condi-
tions with "NO ports" closed, two-stage combus-
tion "NO ports" open and off-stoichionrtrie fir-
ing with "NO ports" open. Three successive an-
alysis gave 457 ppm N0x during normal firing, 308
ppm (33 per cent reduction) with "NO ports"
open and 297 ppm (35 per cent reduction) during
off-stoichioraetric firing. The burner configura-
(13)
tion for the latter condition was as follows:
Front Face Rear Face
0
0
0
0
0
0
A
0
A
A
A
A
A
A
0
A
0
0
0
0
0
0
0
0
CO concentration in all three cases remained be-
low 100 ppm.
(iv) A 480 MW horizontally opposed boiler in two-
stage combustion tests reduced N0X emissions
-50-
-------
from 246 ppm to 200 ppm (a reduction of 19 per
cent) by operating with "NO ports" closed and
(13)
open.
(v) A 220 MW all wall Babcock. and Wilcox boiler has
the following burner configuration in normal
The boiler was not quite flexible enough for
tests because of high water-tube-wall tempera-
ture developed during tests. A gradual approach
of two-stage firing was successful, however, by
first achieving three burners, then four burners
(9 and 10 pairs) and ultimately six burners
(9, 10 and 12 pairs) on air alone in three dif-
ferent tests. The N0X in the above tests de-
creased from an original 267 to 234 ppm (3
burners on air only) to 199 ppm (4 burners on
air only) and 183 ppm (6 burners on air only),
respectively. CO concentration in all cases
remained at 15 ppm and hydrocarbons less than
one ppm.
(vi) In a 320 MW tangentially fired boiler, operating
at 220 MW with all 24 burners operating in the
(13)
operation.
Rear Division Wall
Left
End
Fro nt
-51-
-------
normal case, the top 16 burners firing fuel/air
and bottom rows on air alone for staged combus-
tion, the N0X was reduced according to Table 15
for different damper settings, burner tilt and
(13)
flue gas recirculation. (The boiler was
equipped with primary secondary air dampers and
flue gas recirculation). The average N0X overall
burner tilt settings and damper settings was
reduced to 180 ppm at staged conditions from 219
(13)
ppm at normal conditions.
(vii) In a 400 MW cyclone boiler with simulated staged
combustion firing six of eight cyclones at re-
duced loads of 260 - 275 MW, the N0X increased
from 206 ppm to 310 ppm. This is assumed to be
from higher intensity firing of the six fur-
(13)
naces.
(27)
(viii) Test data reported in the literature for
operating with a Babcock Wilcox unit in El
Segundo 90-95 per cent air through burners and
15 to 20 per cent through auxiliary "NO ports"
showed N0X was reduced from 685 to less than
350 ppm under the same fuel and load conditions.
The boiler is a front wall fired unit with 175 MW
capacity. A conversion cost of $45,000 was re-
(28)
quired to accomplish the two-stage combustion.
Modifications included replacement of tube sec-
tions to provide furnace wall openings, connections
-52-
-------
(13)
Table 15
NO* EMISSIONS: 320 MW TANGENTIAL BOILERS
NOx Emissions ppm
Normal
Firing
Staged Firing
D1
D2
D1 D2
Normal
ri
244
171
139 136
Excess
Air
r2
161
143
156 139
T1 - Burners tilted down.
T2 - Burners tilted up.
D1 - Primary air dampers at maximum open;
Secondary air dampers at minimum open.
D2 - Primary air dampers at minimum open;
Secondary air dampers at maximum open.
-53-
-------
to air port dampers and damper control modifi-
0
cation. The results of all the above tests and
other reported with fewer details are summarized
in Table 16.
Table 16
NOy REDUCTION, OIL-FIRED BOILERS - TWO STAGE AND
OFF-STOICHIOMETRIC COMBUSTION
Boiler Type and Size
180 MW Front Wall
80 MW Front Wall
450 MW Horizontally
Opposed
480 MW Horizontally
Opposed
220 MW All Wall
320 Tangential
(at 220 MW)
400 MW Cyclone
(260 - 275 MW)
175 MW Front Wall
78 MW Tangential
180 MW Tangential
378 MW Tangential
400 MW Tangential
NOy ppm (3% 02 Basis)
Normal Two-Stage
Firing Firing
367
580
457
246
267
180
206
685
310
290
200
175
308
200
350
205
130
160
110
Off-Stoichio- Net Re-
metric Firing duction % Reference
253
404
297
183
142
310
31
30
35
19
31
21
(-50)
49
33
55
20
37
13
13
13
13
13
13
27
12-
12-
12
12
-54-
-------
c. Two-Stage Combustion; Coal-Fired Boilers
Two-stage combustion in coal-fired boilers has
(24)
been demonstrated in laboratory scale tests
as well as a few large boiler tests and proven to
be successful in reducing N0X. In most instances
the simulated two-stage combustion is achieved by
removing the coal pulverizer supplying the upper
level of burners from service.
Results of Two-Stage Combustion in Coal-Fired Boilers
The full scale tests in coal-fired boilers have
reduced N0X. In some cases, because of removing bur-
ners from service, the desired load was not achieved,
and the boilers operated at reduced loads. The N0X
reduction did not indicate any effects on steam tem-
perature characteristics, furnace slagging or unit
efficiency. Solid combustibles and CO were virtually
unaffected. The N0X reductions are documented in the
following Table 17 for different boilers.
-55-
-------
Table 17
TWO-STAGE COMBUSTION COAL-FIRED BOILERS
NOv PPM (3% 0? BASIS)
Top Row Not Top Row Not
Normal Firing Firing Net Re-
Boiler Type and Size Firing No Overfire Overfire duction % Reference
100 MW Tangential
(80 MW-Load
Reduced)
400
220
160
60
12
170 MW Tangential
(157 MW-Load
Reduced)
550
440
270
51
12
215 MW Tangential
(158 MW-Load
Reduced)
450
480
230
49
12
250 MW Tangential
250 MW Tangential
265 MW Tangential
530
400
600
370
200
400
30
50
33
12
12
12
565 MW Tangential
(395 MW-Load
Reduced)
480
'410
280
42
12
576 MW Tangential
(80% Load Operation)
405
246
39
13
-56-
-------
The Bureau of Mines coal-fired furnace (500 lb/
hr.)> designed to simulate a wall-fired dry bottom
boiler, has been tested for two-stage combustion by
supplying 95, 100 and 105 per cent stoichiometric
air through the burners and the rest of the air to
the secondary stage to give a total excess air of
(24)
10 - 20 per cent.
The greatest reduction in N0X was obtained by fir-
ing 95 per cent of stoichiometric air through burners
and the rest of the total excess air (16 per cent) to
(24)
the secondary stage. The combustion efficiency
of the coal remained above 98 per cent in all cases,
and no increase in particulate loading Oi. slagging
was observed at different conditions. The detailed
results of N0X reduction are summarized in Table 18
and Figure 9.
-57-
-------
Table 18
N0X REDUCTION: TWO-STAGE FIRING - TEST - COAL-FIRED FURNACE
(24)
Excess
Air %
21.4
20.1
20.1
16.8
15.5
15.5
9.1
8.0
21.4
19.4
19.4
17.4
16.2
16.2
10.3
8.0
8.0
21.4
18.7
15.5
15.5
12.6
11.3
First Stage
Air, % of
Stoichiometric
105
105
105
105
105
105
105
105
100
100
100
100
100
100
100
100
100
95
95
95
95
95
95
Combustion
NOx Emission Efficiency
ppm Lb. NO2/10° BTU Wt. %
257
448
444
447
437
428
397
307
358
372
355
354
348
342
308
301
294
333
315
290
287
266
260
0.64
.62
.62
.60
.58
.57
.49
.45
.50
.50
.49
.48
.46
.45
.39
.37
• 37.
.46
.43
.38
.38
.34
.33
99.2
99.2
99.2
99.1
99.0
99.0
98.9
93.7
99.0
99.0
99.0
98.9
93.3
98.3
98.4
98.2
98.2
99.0
98.9
98.3
98.3
98.2
98.2
-58-
-------
One stage
combustion
'A^i
Two
stage
combustion
Distribution of combustion air,
percent of stoichiometric
in first stage
I
I
~ - 95 %
O- 100 %
A- 105 %
5 10 15 20
EXCESS AIR, percent
Fig. 9 Two Stage Combustion - Coal Fired Boilers
-59-
25
(24)
30
-------
d. Cost and Cost Effectiveness: Two Stage Combustion
The cost of two-stage combustion is based on
two different cases. In the first case, as ex-
perience of Pacific Gas and Electric (30)
others has shown , simulated two-stage combus-
tion by introducing air alone in upper burners and
air-fuel in other burners does not involve any capi-
tal cost. In the second case, where simulation is
not possible due to burner configuration or other
operational reasons, capital cost is required to
increase the size of windbox, to install separate
auxiliary air ports ("NO ports") above the top row
of burner^ and to connect ducts from the windbox to
each port with a separate control damper in' each
duct. A typical cost to install overfire "NO ports"
in the El Segundo 175 MW unit was $45,000. In
another source (3) the costs of conversion to two-
stage firing for a 100 MW and a 750 MW unit are esti-
mated at $3.30/KW and $2.08/KW, respectively.
The cost investment analysis as estimated by Com-
bustion Engineering for two-stage combustion
based on simulated operation at no cost for alteration
or redesign of equipment except addition of overfire
ports is: $0.25/KW for coal-fired boilers; $0.20/KW
for oil-fired boilers and $0.15/KW for gas-fired
boilers. These costs are based on new 600 MW boiler.
-60-
-------
The retrofit operation is estimated to cost 50 per cent
more.
The cost investment analysis performed by ESSO in
1969 (3)(30)
is given in Table 19. It is based on the
assumption that larger units would be suitable for two-
stage combustion or would be able to simulate two-stage
combustion more readily than smaller units. The costs
in Table 19 are also based on estimates of capital ex-
penditures required to alter or redesign equipment as
discussed above.
-61-
-------
Table 19
TWO-STAGE COMBUSTION COST
(3)
Plant Size Investment Cost Annual Cost
Fuel
1,000 MW
Gas 0 0
Oil 0 0
Coal 1,900,000 299,000
750 MW
Gas 153,000 24,000
Oil 153,000 24,000
Coal 1,530,000 240,000
500 MW
Gas 280,000 44,000
Oil 280,000 44,000
Coal 1,120,000 176,000
250 MW
Gas 330,000 52,000
Oil 330,000 52,000
Coal 660,000 103,000
120 MW
Gas 342,000 54,000
Oil 342,000 54,000
Coal 380,000 60,000
-62-
-------
5. Two-Stage Combustion with Low Excess Air and/or
Reduced Load
It is demonstrated by data in previous sections
that two-stage combustion, low excess air and load
reduction are effective in reducing N0£ by varying
degrees. If higher N0X reduction is required by any
of the above individual controls, a combination of
two-stage combustion with low excess air and/or re-
duced load was tested as a possible choice. The
combination of two-stage combustion with low excess
air is achieved by either using "NO ports" or some
burners on air alone, the rest as fuel-burners but
at a constant total excess air. Load reduction
along with two-stage combustion and low excess air,
is achieved by sealing off completely some of the
burners.
Two-stage combustion with low excess air and re-
duced load has been demonstrated in tests summarized
in Table 20.
-63-
-------
Two-Stage Combustion with Low Excess Air and/or Reduced Load
Table 20
Boiler Type and Size
NOy Emissions ppm (3% 0?, Dry Basis)
Two Stage and LEA
Operating Normal at Two-Stage at Full Operating
Load MW Full Load Operating Load Load Load
Maximum N0X
Reduction %
Reference
180 MW Frontwall
Gas-Fired
120
70
390
390
133
81
156
156
88
66
78
83
13
13
80 MW Frontwall
Gas-Fired
50
20
497
497
200
311
311
65
60
87
13
13
480 MW Horizontally
Opposed
Gas-Fired
220
236
95
140
70
70
13
CTN
¦p-
I
600 MW Horizontally
Opposed
Gas-Fired
325
560
120
77
86
13
220 MW All Wall
Gas-Fired
190
125
675
675
359
313
270
270
284
107
58
84
13
13
750 MW Frontwall
Gas-Fired
750
1,475
140
90
17
180 MW Frontwall
Oil-Fired
120
367
241
201
185
50
13
80 MW Frontwall
Oil-F ired
50
21
580
580
290
207
314
314
252
203
56
65
13
13
-------
Two-Stage Combustion with Low Excess Air and/or Reduced Load
Table 20 (Continued)
NOy Emissions ppm (3% 02> Dry Basis)
Two-Stage and LEA
Boiler Type and Size
Operating Normal at Two-Stage at Full Operating
Load MW Full Load Operating Load " Load Load
Maximum N0X
Reduction %
Reference
ON
Cn
1
350 MW Horizontally
Opposed
Oil-Fired
\
480 MW Horizontally
Opposed
Oil-Fired
575 MW Tangential
Coal-Fired
(80% Load Operating)
150
365
228
460
457
246
246
139
164
155
294
118
163
405
(at 460 MW)
204
74
34
37
50
13
13
13
13
175 MW Frontwall
Coal-Fired 140 660 - - 260 60 13
(at 140 MW Load)
315 MW Frontwall
Coal-Fired 190 1,480 1,280 - 1,190 20 13
(Full Load 275)
315 MW Frontwall
Coal/Gas Fired 194 - 830 - 630 - 13
(Full Load 280 MW)
-------
6. -Reduced Preheat Temperature
N0X emissions are influenced extremely by the effec-
tive peak temperature of the combustion process. Any
modification that lowers these temperatures is expected
to lower N0X emissions. One alternate to achieve lower
temperature has been predicted to be air preheat tempera-
ture reduction.
The approach is not very practical because the air
preheat in existing boilers can only be varied in a
narrow range without upsetting the thermal balance. It
has only been demonstrated in gas-fired plants. In view
of plant efficiency problems and other disadvantages, it
(13)
is preferable to apply other methods for N0X control.
In oil- and coal-fired boilers, nitrogen emitted by
the fuel has a major influence on N0X formation. Lower
air preheat would not affect the N0X from fuel nitrogen.
Also, it would increase particulate emissions in oil- and
coal-fired boilers.
Preheated air is required for the pulverizer operation
on the coal-fired boilers. Higher exit temperatures re-
sulting from elimination of preheat would require addition-
al water spray if a scrubber system is incorporated in the
design. Electrostatic precipitation and induced draft fans,
(12)
if required, would become larger and more expensive. v '
The test results reported on effects of air preheat
reduction on N0X emission are as follows:
-66-
-------
(i) In a test and kinetic analysis prediction, reported
by KVB-SCE (25)^ 200°F reduction in air preheat re-
duced N0X by 50 per cent. (25) results of tests
and predictions are shown in Figure 10. The authors
reported the thermal efficiency reduced with the
changes, and concluded this method of reducing N0X
to be undesirable from an operational standpoint,
(ii) In tests reported by Combustion Engineering (1®) with
the Ljungstrom air heater rotor stopped, air preheat
temperature was reduced from 522°F and 466°F (at 75
per cent and 50 per cent loads respectively) to 80°F.
N0X levels were reduced from 200 ppm to 100 ppm at
comparable operating excess air. A load reduction to
75 per cent was required to protect air heater exit
ducts and stack from excessive temperature. At 75
per cent load, exit temperature increased from a
normal value of 220°F with the air preheater running
to a value of 5A0°F with the air preheater rotor
stopped.
7. Flue Gas Recirculation
Flue gas recirculation is a technique for recycling
a portion of flue gases produced back to the combustion
chamber, using either forced or natural draft. In addi-
tion to recycling flue gases for steam temperature control,
the recirculation is used to control N0X emission from util-
ity boilers.
The control of N0X by flue gas recirculation results
-67-
-------
TIME (sec)
Figure 10. - Effect of Combustion Air Preheat on NO Formation. 0 = 0.95
-68-
-------
from two factors: the temperature of the flame zone is
reduced by circulating cool flue gases; the concentration
of oxygen available for NO formation is reduced. Of
these two, the thermal effect is generally accepted to be
(3)
more important.
Flue gas recirculation into the bottom of the furnace
is standard design in some utility boilers to control
steam temperature. Normally, as boiler load decreases,
steam temperature tends to decrease unless some method
of control is employed. By recirculating an increasing
portion of the flue gas as the boiler load decreases, it
is possible to maintain steam temperature at a constant
level over a wider load range. Where this type cf con-
trol is used, the flue gases are injected to reduce the
effectiveness of the furnace heat absorption surface with-
out interfering with the combustion process. Tests made
during the California joint between B and W and SCE project
N0X investigation in 1960-62 concluded that recirculation
for steam control was relatively ineffective in suppressing
N0X. Recent data, however, indicated that recirculation of
20 per cent of the gases into combustion zone in a gas-fired
boiler equipped with recirculation steam temperature control
( 3)
reduced emissions by 20 per cent.
The flue gas recycled for NOx control requires recycle
into the primary combustion zone. The effect of gas recir-
culation on NOx control is shown in Figure 11 (25) which
is based on kinetic analysis predictions of the reduction in
-69-
-------
-------
NO formation for various flue gas recirculation rates.
Flue gas recirculation has shown a reduction in CO con-
centration from normal operation because of increased mixing
and decreased CO2 dissociation accompanying the decreased
temperature. Gas recirculation does not significantly
reduce plant thermal efficiency, but it can influence boiler
operation. Radiation heat transfer is reduced in the furnace
because of lower gas temperatures. Convective heat transfer
is increased in the convective sections because of the great-
er gas flow.^^
The extent of applicability of this modification remains
to be investigated. The quantity of recirculated gas nec-
essary to achieve the desired effect in different installa-
tions is important and can influence the feasibility of
applications. For instance, recycling large quantities of
flue gas in utility boilers poses gas handling problems in
addition to increased investment and operating coste.
a. Flue Gas Recirculation: Gas-Fired Boilers
Flue gas recirculation tests in gas-fired tangen-
tial utility boilers were run by Southern California
Edison ^5) Combustion Engineering Company.
(i) The Southern California tangential fired boilers
are equipped with"flue gas recirculation into
combustion air. Tests of these 320 MW units
showed a substantial NOx reduction as the rate
of gas recirculation increased. The test results
of the units at full load are shown in Figure 12.^^
-71-
-------
400
350
300
250
«
5
Q-
0_
200
150
100
50
Data from
different units
of same type.
A
A
il
—El
10 20
% Recirculation
30
40
50
Figure 12. Gas Recirculation with Natural Gas Firing: 320 MW Corner
Fired Unit.<25>
Dry Basis 3% Excess O2
-72-
-------
(ii) In a test on a 320 MW tangential fired boiler,
(13)
ESSO reports that flue gas recirculation
at low excess air levels provides a practical
and effective means of reducing N0X emissions
from this boiler. The use of flue gas recir-
culation at adjusted burner tilt and with air
dampers to avoid higher water tube metal tem-
perature reduced N0X from 340 ppm to 110 ppm
at full load and to 65-85 ppm at lower loads.
The levels of low excess air used were limited
by the CO emission. Complete analysis of the
data is presented in Table 21 and Figure 13.
-73-
-------
Boil
: Loai
MW
320
320
320
320
320
315
280
280
320
320
240
240
240
240
240
240
240
240
320
320
240
160
120
80
60
CO
175
50
50
80
100
200
80
50
50
60
2100
50
50
50
100
50
160
100
150
50
600
50
50
50
50
Table 21
(13)
SUMMARY OF EMISSION DATA FROM 320 MW.
TANGENTIAL,
GAS FIRED
% Flue Gas
Burner
Pr imary/Secondar y
%02
Staging
Recirculation
Tilt
Air Dampers
Dry Basis
No
0
Normal
Normal
3.3
No
0
+Max. (up)
Normal
2.7
No
30
Normal
Normal
2.2
No
16
Normal
Normal
2.7
No
0
Normal
32%100%
2.7
Yes
0
Normal
Closed
5.5
Yes
0
Normal
Closed
5.6
No
35
Normal
Open
2.5
No
27
Normal
Open
2.9
No
17
Normal
Open
2.4
No
0
Normal
Normal
5.0
No
0
Normal
Normal
7.5
No
0
+Max. (up)
Normal
6.0
No
39
Normal
Normal
2.9
No
21
Normal
Normal
4.1
Yes
0
Normal
Open
6.2
Yes
0
Normal
Open
5.7
No
41
Normal
Normal
2.7
Yes
21
Normal
Open
2.2
No
18
Normal
Normal
2.0
No
23
Normal
Normal
2.2
No
32
Normal
Normal
2.9
No
37
Normal
Normal
5.5
No
43
Normal
Normal
8.9
No
43
Normal
Normal
11.0
-------
Figure 13. N0X Emissions fro..; 320 MW, Tangential, Gas Fired.
% Flue Gas Recirculation
* Emission date supplied by boiler operator.
-------
(iii) Combustion Engineering reports a 60 per cent N0X
reduction with 30 percent flue gas recirculation
(12)
on a 320 MW tangential fired boiler.
(iv) Pacific Gas and Electric reports installing a flue
gas recirculation system on a 750 MW front wall-
fired Babcock and Wilcox unit at a cost of $850,000.
The unit, equipped with off-stoichiometric firing
and operating at low excess air after addition of
15 per cent flue gas recirculation, is reported to
have reduced N0X from 1,350-1,450 ppm uncontrolled
to 100 ppm under controlled conditions. The unit
has reported problems with heat transfer due to
(30)
increase in mass flow,
b. Flue Gas Recirculation: Oil-Fired Boilers
Flue gas recirculation in the windbox or in the com-
bustion air in oil-fired utility boilers reduces the N0„.
J X
However, since the N0X in oil-fired boilers is both from
fuel and thermal nitrogen, the reduction of thermal N0X
is much greater than reduction of fuel N0X.
Flue gas recirculation in oil-fired boilers has been
tested both on front wall-fired and tangentially fired
boilers. Typical gas recirculation system in oil- or
(12)
gas-fired tangential' boilers is shown in Figure 14.
The recirculated gas is mixed with air in the two outer
channels of the duct from the air preheater to the wind-
box. The center channel contains air only, which flows
-76-
-------
I
•vl
I
• RECIRCULATED GAS
(12)
Fig. 14: Recirculated gas and air duct system for oil or gas fired units
-------
to the fuel and overfire air compartments. Figure 14
also shows a device installed in the duct work to insure
thorough mixing of the recirculated gas and air to pre-
(12)
vent stratification.
The reported test results on all types of oil fired
boilers are, as follows:
(i) In a 250 MW twin furnace, front wall boiler, flue
gas recirculation, along with staged firing and low
excess air, reduced N0X by more than 50 per cent at
full load (from about 340 ppm to less than 150 ppm)
and about 50 per cent at two-thirds load (from 300
(13)
ppm to 155 ppm).
(ii) In a 320 MW tangential oil-fired boiler, equipped
with flue gas recirculation, the N0X was reduced
from 180 ppm to 158 ppm by switching from minimum
gas recirculation to maximum gas recirculation at
(12)
normal firing and normal excess air.
(12)
(iii) In a Combustion Engineering test on a 320 MW
tangentially fired twin furnace boiler, tested on
both sides (160 MW each), N0X was reduced from 500
ppm to 300 ppm in one and from 330 ppm to 215 ppm in
the other compartment (a reduction of about 40 per
cent in both cases). .
c. Flue Gas Recirculation: Coal-Fired Boilers
There is presently- no commercial coal-fired unit
(13)
equipped with flue gas recycle into the windbox to test.
-78-
-------
Flue gas recycle is, however, predicted as a favorable
means of future control of thermal N0X from coal-fired
(33)(34)
boilers. It is predicted that increasing the
mass flow through the boiler system, along with properly
designed superheat recovery systems, may help maintain
boiler tubes cleaner and reduce slagging. These effects
require exploration in pilot and simulated studies. A
study also is needed to indicate the effect of flue gas
recycle on particulate emissions.
The costs incurred with flue gas recirculation are
in the addition of duct work and recycle fans, enlarging
the windbox for additional combustion air, addition of
dampers, and proper instrumentation to vary flue gas
recirculation as required for operating conditions and
loads.
d. Cost and Cost Effectiveness of Flue Gas Recirculation
The costs incurred with flue gas recirculation are:
addition of duct work and recycle fans, enlarging the
windbox for additional combustion air, and addition of
dampers and proper instrumentation to vary flue gas
recirculation as required for operating conditions and
loads.
In an actual case, a 750 MW front wall boiler was
equipped with flue gas recirculation for $850,000. This
cost does not include any steam temperature adjustment
alterations.
-79-
-------
The cost of flue gas recirculation on a per unit
power output capacity basis has been quoted by Esso in
1969 as $0.656/KW for a 750 MW unit to $1.033/KW for a
100 MW unit. Based on these factors, the cost of equip-
ping and operating flue gas recirculation for different
sized gas, oil and coal-fired boilers is, as follows:
Table 22
(29)
COST OF FLUE GAS RECIRCULATION
Size of Capital Cost of Annual Cost
Boiler MW FGR Installation Capital + Operating
1,000 $600,000 $202,000
750 $490,000 $160,000
500 $360,000 $109,000
250 $210,000 $ 58,000
120 $120,000 $ 30,000
In a more recent publication, the flue gas recir-
culation costs are estimated at $2.65/KW for large gas-
(10)
fired boilers.
The cost of flue gas recirculation estimated by
(40)
Combustion Engineering recently is: $3.50/KW for
coal fired boilers, $1.50 for oil fired boilers and
$2.65/KW for gas fired boilers, based on a 600 MW new
boiler. The costs for existing boiler conversions are
estimated to be 50 per cent higher.
Because of the lack of actual thermal efficiency
data, no cost effects on boiler operation could be
developed.
-80-
-------
8. Steam and Water Injection
Flame temperature, as discussed earlier, is one of the
important parameters affecting the production of N0X. One
of the several ways to control N0X by lower flame tempera-
ture is to inject steam or water into boilers. Water injec-
tion was found to be preferred over steam in many cases,
due not only to its availability and lower cost, but also
to its potentially greater thermal effect. In gas- and coal-
fired units equipped for standby oil firing with steam at-
omization, the atomizer offers a simple means for injection.
Other installations require special rigging, and a systema-
tic study to determine the degree of atomization and mixing
required with the flame, the optimum point of injection and
the quantities of water or steam necessary to achieve the
desired effect.
The use of water or steam injection may entail some un-
desirable operating conditions, such as decreased efficiency,
increased corrosion, etc. These factors require evalua-
tion before selection of this control technique for N0X
control can logically be made.
Use of the water or steam injection technique is limited
to gas units for practical reasons. It does not reduce fuel
nitrogen conversion, and even in gas boilers, it is un-
economic to use water or steam injection over the amount
that will reduce the boiler efficiency by more than one
per cent. The N0X reduction at that injection rate is about
-81-
-------
10 per cent. Based on this concept, the water injection is
only used to trim peak NOx emissions.
pie following test result has been reported on N0X
control by water or steam injection.
On a 250 MW gas-fired unit water injection tests,
using existing oil guns as atomizers, reduced the
NOx emission level from 330 ppm to 110 ppm at full
load. Boiler efficiency decreased five per cent at the
(18)
maximum water injection rate of 45 lb/10 BTU fired,
a. Cost of Steam and Water Injection
The use of water in water injection requires an
injection pump and attendant piping. Cost estimates of
water injection systems based on installing an atomizer
in each burner together with required piping are esti-
mated as $0.0238/KW for a 750 MW unit and $0.0363/KW for
(3)
a 100 MW unit. The costs based on one per cent oper-
ating efficiency losses and annual expenses are, as
follows:
Table 23
(3)
COSTS OF WATER INJECTION
Annual Cost by Fuel
(Operating and Efficiency Loss and Capital)
Boiler Size Capital Cost Gas , Oil Coal
1,000 MW $23,000 $144,000 $179,000 $143,000
750 MW $19,000 $114,000 $141,000 $113,000
500 MW $14,000 $ 71,000 $ 87,000 $ 70,000
250 MW $ 8,000 $ 29,000 $ 36,000 $ 21,000
120 MW $ 5,000 $ 9,000 $ 11,000 $ 9,000
-82-
-------
9. Fuel Substitution
Fuel type affects N0X formation both through the theoreti-
cal flame temperature attainable (coal> oil>gas) and rate of
radiative heat transfer (coal> oil»-gas). In general, the
NQx by fuel type can be ranked as coal>-oil>^gas, but in
limited cases in large boilers this order is reversed, pre-
sumably due to the shift in heat release/heat removal ratios.
Oil and coal contain fuel nitrogen which is converted to
NQt by fuel combustion. The average fuel nitrogen reported
(36)
in coal is 1.1 to 2.1 per cent. Nitrogen contained in
crude oil ranges by states averages from 0.056 per cent to
0.49 per cent and ranges by field averages from 0.01 per
cent to 0.94 per cent. The data on conversion of fuel nitro-
gen to NO are limited. The reported conversion varies between
(36)
20-70 per cent. The conversion of fuel nitrogen to N0X
is influenced by other combustion modifications such as
flue gas recirculation.
It is desirable to switch to low nitrogen fuels, along
with implementing other combustion modifications reported
earlier to reduce the NOx from utility boilers.
The fuel switching from coal to oil or gas involves
combustion equipment design changes; however, if the boiler
is equipped with a multi-fuel firing system, the costs
involved are simply costs of fuel.
The coal-fired to oil-fired conversion involves addition
of oil tanks, oil heaters and modification to boilers. The
-83-
-------
cost of these conversions is estimated as $2-3/KW. The
conversion of oil-fired or coal-fired to gas fired does not
involve any storage cost; however, cost of pipeline gas and
change in burners is estimated to be $.50/KW. The fuel costs
for various fuels by regions are reported in Table 24.
-84-
-------
(37)
Table 24
FUEL PRICES BY REGIONS, 1970
Fuel Cost c/million BTU
Regions Coal Oil Gas
NEW ENGLAND 34.9 35.6 31.2
Maine, New Hampshire, Vermont,
Massachusetts, Rhode Island,
Connecticutt
MID-ATLANTIC
New York, New Jersey,
Pennsylvania
EAST NORTH CENTRAL
Ohio, Indiana, Illinois,
Michigan, Wisconsin
WEST NORTH CENTRAL
Minnesota, Iowa, Missouri,
North Dakota, South Dakota,
Nebraska, Kansas
36.9 42.6 39.4
30.4 63.7 36.9
29.5 65.1 25.6
SOUTH ATLANTIC 36.0 34.8 35.5
Delaware, Maryland, D. C.,
Virginia, West Virginia, North
Carolina, South Carolina,
Georgia, Florida
EAST SOUTH CENTRAL
Kentucky, Tennessee, Alabama
Mississippi
WEST SOUTH CENTRAL
Arkansas, Louisiana, Texas
Oklahoma
MOUNTAIN STATES
Montana, Wyoming, Colorado, Utah,
New Mexico, Arizona, Nevada
PACIFIC STATES
Washington, Oregon, California
ALASKA
HAWAII
23.5 50.5 25.2
38.9 44.9 20.9
19.1 28.5 29.5
15.1 39.0 32.6
67.7 146.6
39.2
-85-
-------
B. Combustion Equipment Design Modifications
1. Equipment Design
Boilers are referred to by their firing type e.g.,
front wall-fired, horizontally opposed, all wall, cyclone
tangential. The boilers generate different amounts of N0X
per their type of firing. An analysis of uncontrolled N0X
by types of boilers is given in Figures 15, 16 and 17.
Tangential firing units usually generate the least N0X.
The fuel is admitted at the corners of the combustion
chamber through alternate compartments. Distribution dam-
pers proportion the air to.the individual fuel and air
compartments. Thus, it is possible to vary the distribu-
tion of the air over the height of the windbox, vary the
velocity of the air stream and change the rate oi mixing of
the fuel and air. Fuel and air nozzles tilt in unison to
raise or lower the flame in the furnace to control furnace
heat absorption in the superheater and reheater sections.
The fuel and air streams from each corner of the furnace
are aimed tangent to the circumference of a circle in the
center of the furnace. In operation, a large swirl is
created in the furnace.
The impingement of each stream on the adjacent stream
provides a source of ignition energy and promotes bulk gas
mixing. Since the entire furnace acts as a burner, precise
proportioning of fuel and air at each of the individual fuel
admission points is not required. Locally "fuel rich" or
"air rich" streams are blended in passing through the furnace
-86-
-------
Gross Load per Furnace Firing Wall, MW
Figure 17. Coal Fired Boilers. Uncontrolled N0X Emissions vs. Gross
Load per Furnace Firing Wall. (13)
-89-
-------
resulting in complete combustion of the fuel. A large
amount of internal recirculation of bulk gas, coupled
with slower mixing of fuel and air, provides a combustion
system which is inherently low in N0X production for all
fuel types.
2. Burner Design and Configuration
The specific design and configuration of a burner
has an important bearing on the amount of N0X formed.
Certain types of burner designs have been found to give
greater emissions than others. Among the three types
of gas burners, spud, radial spud and ring, the ring
type generates minimum and spud type maximum N0X.
The spray angle in oil atomizers effects N0X con-
centration. Narrower spray angle, producing proper
atomization, has been reported to provide lower NO
(3) X
emissions as opposed to the results of Barnhart
(35)
and Diehl tests.
The cyclone and vortex type burners operate under
highly turbulent, high intensity conditions. In field
adjustment of these burners to decrease turbulence to a
minimum, N0X was reduced AO per cent but this resulted
in an unsatisfactory flame conditon. Throttling the
burner registers to increase windbox pressure and turbu-
lence increased N0X by more than 15 per cent. Foster
(33)
Wheeler reports that burner turbulence is produced
by swirling combustion air. When firing natural gas. the
flame color is an index of flame turbulence. Bright
-90-
-------
blue flames with good definition are considered highly
turbulent flames. Yellow, lazy flames have low turbu-
lence . Figure 18 vividly demonstrates the NOy formation
as a function of turbulence alone.
Removal of approach cone vanes resulted in NOx level
(35)
reduction from 300 ppm to 285 ppm in a test. The
throat diameter of the burners has no effect on NO*
(35)
formation.
In the late 50's, a two-stage burner was developed in
California. In this burner, about 85 - 95 per cent of
the stoichiometric air needed for combustion is admitted
to the flame through the burner throat. The remainder of
the air required for complete combustion is injected
through ports above the burner to complete the burn-out
of the initial combustion phase. With 95 per cent of
stoichiometric air passing through the burner throat,
N0X reduction of 30 per cent was observed. With 90 per
cent stoichiometric air supplied into the primary zone,
the N0X content was reduced by 47 per cent. This
technique is successfully used in oil- and gas-fired
boilers.
A further modification of an off-stoichiometric
firing burner is used by Pacific Gas and Electric. In
the boiler with a matrix of three rows vertically, each
boiler tube is divided by a triangular cut to supply
air and fuel air mixture in the following arrangement
-91-
-------
EFFECT OF BURNER TURBULENCE
natural gas firing
a.
a.
o
z
X
1400
1200
1000
800
600
400
200
YELLOW COLOR
(hazy)
i
BLUE COLOR
(clear)
I 1
BURNER TURBULENCE INDEX
Figure 18. Effect of Burner Turbulence. Natural Gas Firing.
(33)
-92-
-------
and ratios:
A: Air Alone
F: Fuel/Air Mixture
(Fuel/Air)
(Fuel/Stoichiometric Air)
1.51
The N0X reduced from 450 - 500 ppm to 140 ppm.
3. Burner Location, Spacing and Tilt
Although data are scarce regarding the effect of
burner spacing and location on N0X concentrations,
potentially these items are important variables. The
interaction between closely spaced burners, especially
in the center of a multiple burner installation, could
be expected to increase flame temperature at these
locations. The tighter the spacing and the lower the
ability to radiate to cooling surfaces, the greater the
tendency towards increased N0X emissions. This effect
is illustrated by higher N0X emissions from larger
boilers with greater multiples of burners and tighter
spacing. In the course of the California investigations
in the early 1960's, tests were conducted on large
boiler units where the number and spacing of burners
in use were varied. It was reported that, when the
-93-
-------
barriers in operation were closely grouped or when more
burners were in use, more N0X was produced than when the
same amount of fuel was burned using fewer burners with
wider spacing. These results were attributed to the
relative amount of cold waterwall surface "seen" by
each burner. Less N0X is formed when more cooling
surface is available to absorb radiant heat from each
(3)
individual burner flame.
Tilting burners is a design feature used in tangen-
tially fired boilers for superheat temperature control.
This additional flexibility in combustion operations was
exploited, where possible, in planning and conducting
(3)
tests in the ESSO Boiler Test Program.
Varying burner tilt away from the horizontal position
can to some extent "enlarge" or "constrict" the effec-
tive furnace combustion zone. Thus, depending on flame
patterns and transport effects, a longer effective
residence time may be available for N0X formation, or
conversely, a lower combustion intensity may prevail in
the enlarged combustion zone, leading to lower N0X
emissions. The first one of these two alternatives was
expected to be more likely because of the diffuse,
swirling fireball pattern prevailing in tangentially
(13)
fired boilers.
Tangential boilers capable of ± 30° tilt from hori-
zontal position generally produce the least NOx at
(12)
horizontal positions.
-94-
-------
C. Flue Gas Treatment
Flue gas treatment is an alternate method for control of N0X.
This method of control is applied after the N0X has formed and can
be used either by itself or following combustion modification.
To-date no N0X flue gas treatment has been demonstrated commer-
cially on a power plant, however, aqueous scrubbing, catalytic re-
duction, adsorption by solids and catalytic re-composition se< r.i to
be candidates for development. Flue gas treatment methods are
discussed briefly as follows:
1. Absorption of Nitrogen Oxides
Nitrogen oxides can be absorbed by various liquids within
specific limits and conditions. Aqueous alkali seems to be the
most promising method of N0X absorption. The method would be
(42)
most successful on an equimolecular mixture of NO and NO2,
however this mixture is not found in combustion stacks.
(43) (44)
Combustion Engineering and UOP report 20% N0X re-
moval by caustic scrubbing in their SO2 removal experimentation.
Among other aqueous absorption liquids proved experimentally
(45)
are: (a) molten alkali metal carbonates (less than 15%
(3)
removal efficiency in presence of CO2), (b) sulfuric acid
(very uneconomical because of high fuel use for regeneration),
(3)
(c) solutions of complex forming salts and (d) organic
solutions.
2. Adsorption of NOx by Solids
Common adsorbents such as silica gel, alumina, char,
molecular sieves and metal oxides and hydroxides are used to
-95-
-------
separate NOx by adsorption from gas streams. Adsorption
processes at low concentrations of NOx in combustion sources
have shown very limited success.
3. Catalytic Decomposition
NOx can be decomposed to and O2 by decomposition in the
presence of catalysts, however, a very high temperature is re-
quired to achieve decomposition. There is no experimental data
available to show catalytic decomposition at the N0X concentra-
tions that are found in power plant stacks.
4. Catalytic Reduction
Catalytic reduction of N0X to N2 by a reducing agent such as
ammonia requires a sulfur resistent catalyst if coal or cil are
used as the fuel source. Space velocity and catalyst life also
limit this method at present. Available information Js insuf-
ficient to assess the potential of this method for control of
N0X.
5. Other Methods
NOx removal from flue gas based on differences in physical
factors such as molecular size, condensation temperature and
(3)
magnetic susceptibility of components appears very improbable.
-96-
-------
APPENDICES
(38)
Appendix A: Scattergood Unit 3: Los Angeles Power and Light
Scattergood No. 3 unit rated at 460 MW is scheduled to
go into operation in 1974. It is a tangentialy fired Combustion
Engineering unit. The boiler is equipped with flue gas re-
circulation, provisions for over fire operation and for operation
with selected burners out of service for off-stoichiometric
combustion.
The unit as designed can operate with an N0X emission of
30 ppm based on Los Angeles County Air Pollution Regulation
Rule 67.
A use of 30 per cent gas recirculation combined with upper
four burners out of service (33 per cent off-stoichiometric)
combustion would lower the N0X to about 70 ppm.
A combined chart of N0X reduction by various operations of
the burners and allowable NO emission at various loads is
(38)
plotted in Figure 19. The Figure shows that this unit can
be operated in compliance with Los Angeles N0x regulations at
315 MW emitting 42 ppm when operating with 33 per cent off-
stoichiometric combustion and 30 per cent gas recirculation.
The power company management has received Los Angeles County
permit to operate the boiler at these conditions.
-97-
-------
110
1^0
90
30
70
60
50
40
30
20
10
0
100
NITRIC OXIDE LIMIT FOR
COMPLIANCE WITH LA/A PCD RULE 67.
UPPER 4 BURNERS OUT OF
SERVICE OR OVERFIRE AIR
PORTS OPEN AND UPPER 2
BURNERS OUT .
(33% OFF - STOICHIOMETRIC)
200 300 400
LOAD MEGAWATTS
500
Figure 19. Predic.ted N0X Emissions vs. Mode of Operation as Compared
to Rule 67. (38)
-98-
-------
REFERENCES
1. "Control Techniques for Nitrogen Oxide Emissions from Stationary
Sources." U. S. Department of Health, Education and Welfare,
National Air Pollution Control Administration, Washington, D. C.:
March, 1970.
2. "National Air Pollution Control Administration, Reference Book of
Nationwide Emissions." U. S. Department of Health, Education and
Welfare, N.A.P.C.A., Durham, North Carolina.
3. Bartok, W., et. al. "Systems Study of Nitrogen Oxides Control
Methods for Stationary Sources, Vol. II." Esso Research and
Engineering, Linden, New Jersey. Report GR 2-N0S 69, prepared
for Division of Process Control Engineering, National Air Pollution
Control Administration, under Contract PH 22-68-55: November 20,
1969.
4. "Statistical Year Book of the Electric Utility Industry for 1970."
5. Robinson, E., and R. C. Robbins. "Source Abundance and Fate of
Gaseous Atmosphere Pollutants." Stanford Research Institute, Menlo
Park, California. Fianl Report, SRI Project PR-6755: February,
1968. p. 75.
6. Duprey, R. L., "Compilation of Air Pollutant Emission Factors."
National Center for Air Pollution Control, PHS Publication 99-
AP-42: 1968. p. 67,.
7. Chass, R. L., W. B. Kranz, J. S. Nevitt and J. A. Danielson. "Los
Angeles County Acts to Control Emissions of Nitrogen Oxides from
Power Plants." Presented at Air Pollution Control Association 64th
Annual Meeting, Atlanta, Georgia: June, 1971.
8. James, D. W., "Nitric Oxide Control for Oil and Gas-Fired Utility
Boilers." Presented at Air Pollution Control Association, Houston,
Texas: April 13, 1972.
9. LaMantia, C. R., and E. L. Field. "Tackling the Problem of Nitrogen
Oxides." Power Vol. 113, No. 4: April, 1969. pp. 63-66.
10. "Abatement of Nitrogen Oxides Emissions from Stationary Sources."
National Academy of Engineering, Washington, D. C.: 1972.
11. Bagwell, F. A., K. E. Rosenthal, B. P. Breen, N. Bayard de Volo
and A. N. Bell. "Oxides of Nitrogen Emission Reduction Program for
Gas and Oil-Fired Utility Boilers." Presented at 32|j»Annual Meeting
of American Power Conference: April 21-23, 1970.
-99-
-------
12. Blakeslee, C. E., and H. E. Buback. "Controlling N0X Emissions
from Steam Generators." Paper 72-75, Presented at 65th Annual Air
Pollution Control Association Meeting, Miami, Florida: June 18-23,
1972.
13. Bartok, W., et. al. "Systematic Field Study of N0X Emission Control
Methods for Utility Boilers." ESSO Research and Engineering Company
Linden, New Jersey. Report GRU 4 GNO 570, prepared for Office of
Air Programs, Environmental Protection Agency, Researah Triangle
Park, North Carolina: December 31, 1971.
14. Smith, W. S., and C. W. Gruber. "Atmospheric Emissions from Coal
Combustion. An Inventory Guide." U. S. HEW, P.H.S., Publication
No. 999 AP 24, Cincinnati, Ohio, April 1966.
15. Shaw, J. T., "Oxides of Nitrogen: Their Occurrence and Measurement
in Flue Gas from Large Coal-Fired Boilers." BCURA Monthly Bulletin,
Vol. 34, No. 10, pp. 252-259. October 1970.
16. Crynes, B. L., and R. H. Maddox, "Status of N0X Control from Com-
bustion Sources." Chem. Technology, 1971: pp. 502-509, August
1971.
17. Barr, W. H., "Control of N0X in Power Plant Operation." Presented
at West Coast section of the Air Pollution Control Association in
San Francisco, California. October 8-9, 1970.
18. Blakeslee, C. E., "Reduction of N0X Emissions by Combustion Modifi-
cations to a Gas Fired 250 MW Tangential-Fired Boiler," presented
at AGA, IGT Conference, Atlanta, Georgia. June 6, 1972.
19. Cooper, D. R., "Low Excess Air Firing Towers Heat Rate at Large
Utility": Combustion, Vol. 36, pp. 28-34, August 1964.
20. Smith, W. S., "Atmospheric Emissions from Fuel Oil Combustion." U. S.
HEW, P.H.S., Division of Air Pollution, Cincinnati, Ohio. Publica-
tion No. 999 AP 2, November 1962.
21. Sensenbaugh, J. D., and J. Joankin, "Effects fo Combustion Conditions
on Nitrogen Oxide Formation in Boiler Furnaces." ASME Paper 60-WA-
334, 1960.
22. Fernendes, J. H., J. D. Sensenbaugh, and D. G. Peterson, "Boiler
Emissions and their Control," Mexico City, April 28, 1966.
23. Bienstock, D., R. L. Amsler and E. R. Bauer, Jr., "Formation of
Oxides of Nitrogen in Pulverized Coal Combustion," Journal of Air
Pollution Control Association, Vol. 16, No. 8, pp. 442-445, August
1966.
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24. McCann, C. R., J. J. Demeter, A. A. Orning, and D. Bienstock, "NOx
Emissions at Low Excess Air Levels in Pulverized - Coal Combustion,"
ASME Paper 70-WA/APC-3 presented at ASME Winter Annual Meeting,
November 29 - December 3, 1970, New York, New York.
25. Bagwell, F. A., K. E. Rosenthal, D. P. Teixeira, B. P. Breen, N.
Bayard de Volo, and S. Kehro, "Utility Boiler Operating Modes for
Reduced Nitric Oxide Emissions," Journal of Air Pollution Control
Association, Vol. 21, No. 11, pp. 702-708, November 1971.
26. Southern California Edison Limits N0X with Firing Modifications
Dispatching Technique." Electrical World, 174 (9), pp. 32-35,
November 1, 1970.
27. Austin, H. C., and W. L. Chadwick, "Control of Air Pollution from
Oil Burning Power Plants." Mechanical Engineering, Vol. 82, No. 4,
pp. 63-66. April 1960.
28. Austin, H. C., and P. Seeler, "Combustion Scheme Cuts Power Flant
Smog Conference," Electrical World, No. 8: pp. 51-53, February 19,
1962.
29. Bartok, W., A. R. Crawford, A. R. Cunningham, H. J. Hall, E. H.
Manney, and A. Skoop, "Stationary Sources and Control of Nitrogen
Oxide Emissions," Proceedings of the Second International Air Con-
gress. Academy Press, New York, 1971, pp. 801-818.
30. Pacific Gas and Electric, Private Communication.
31. McCann, C. R., J. J. Demeter, J. Dzubay and D. Bienstock, "NO
Emissions from Two-Stage Combustion of Pulverized Coal." Presented
at 65th Annual Meeting of the Air Pollution Control Association,
Miami Beach, Florida, June 18-22, 1972.
32. Martin, G. B., and E. E. Berkau, "Preliminary Evaluation of Flue Gas
Recirculation as a Control Method for Thermal and Fuel Related Ni-
tric Oxide Emission," Presented at Western States Combustion Insti-
tute Fall Meeting, University of California Irvine, Irvine,
California, October 25, 1971.
33. Sommerlad, R. E., R. P. Welden, and R. H. Pai, "Nitrogen Oxide Emis-
sion, an analytical evaluation of test data", presented at the 33rd
annual meeting, American Power Conference, Chicage, Illinois, April
22, 1971.
34. Riley-Stoker Corporation, personal communication.
35. Barnhart, D. H., and E. K. Diehl, "Control of Nitrogen Oxides in
Boiler Flue Gases by Two-Stage Combustion." Journal of Air Pollution
Control Association, Vol. 10, No. 5, pp. 397-406, October 1960.
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36. Martin, G. B., and E. E. Berkau, "An Investigation of the Conversion
of Various Fuel Nitrogen Compounds to Nitrogen Oxides in Oil Com-
bustion." A.I.Ch.E. Meeting, August 30, 1971, Atlantic City, New
Jersey.
37. "Analysis of Fuel for Electric Generation by the Electric Utility
Industry." Edison Electric Institute, 90 Park Avenue, New York,
New York: August 1971.
38. Sonderling, H. H,, W. W. Pepper, B. P. Breen and A. W. Bell, "How
L. A.'s Tough NOx Limit is Met at Scattergood." Electric Power
and Light, January 1972.
39. R. E. Hall, Environmental Protection Agency, Research Triangle,
North Carolina, private communication.
4G. Combustion Engineering, private communication.
41. Kaufmen, F. and J. R. Kelso, "Kinetics of Decomposition of Nitric
Oxide," J. Chem. Phys., Vol. 21, No. 4, 1953. p. 751.
42. Garcia, L. H., "Absorption Studies of Equimolecular Concentrations
of NO and NO2 in Alkaline Solution", Division of Control Systems.
Environmental Protection Agency, Research Triangle Park, N. C.
43. Plumley, A. L., J. Jonakin, 0. D. Whiddon and F. W. Shutko", Removal
of Sulfur Dioxide and Dust from Stack Gases", Proc. Amer. Power Conf.,
Vol. 29, pp. 592-614, 1967.
44. Pollack, W. A., J. P. Tomany and G. Freiling, "Sulfur Dioxide and Fly-
ash Removal from Coal Burning Power Plant", Air Eng., Vol. 9, No. 9,
pp. 24-28, 1967.
45. "Development of Molten Carbonate Process for Removal of Sulfur Dio-
xide from Power Plant Stack Gases", North American Rockwell, Atomics
International Div., Contract Ph86-67-128-Modification 8- Nitrogen
Oxide Studies, Monthly Progress Report, August 1969.
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BIBLIOGRAPHY
Alphabetical list of additional references on N0X Control not
cited in the report.
Altwicker, E. R., P. E. Fredette, and T. Shen. "Pollutants from Fuel
Oil Combustion and the Effect of Additives." Presented at Air
Pollution Control Association 64th Annual Meeting, Atlantic City, New
Jersey, June 27, 1971.
Bartok, W., V. S. Engleman, R. Goldstein, and E. G. del Valle.
"Basic Kinetic Studies and Modeling of Nitrogen Oxide Formation in
Combustion Processes." Presented at Symposium on Combustion Processes
and Air Pollution Control, AICHE 70th Annual Meeting, Atlantic City,
September 29, 1971.
Bartok, W., A. R. Crawford and G. J. Piegari. "Reduction of Nitrogen
Oxide Emissions from Electric Utility Boilers by Modified Combustion
Operation." To be presented at the 14th International Symposium on
Combustion, State College, Pennsylvania, August 1972.
Bartok, W., "Status of EPA-Sponsored Studies of Stationary NOx Control
Methods at ESSO Research and Engineering Company." Presented at ASME
Winter Meeting November 28 - December 2, 1971, Washington, D. C.
Bartok, W., A. R. Crawford, and A. Skoop. "Control of N0X Emissions
from Stationery Sources," Chemical Engineering Progress Vol. 67,
No. 2, February, 1971, pp. 64-72.
Bartok, W., A. R. Crawford, and G. J. Piegari. "Systematic Investi-
gation of Nitrogen Oxide Emission and Combustion Control Methods for
Power Plant Boilers." Presented at AICHE 70th Annual Meeting, Atlantic
City, New Jersey, August 29, 1971.
Bartok, W., A. R. Crawford, and A. Skoop. "Control of Nitrogen Oxide
Emissions from Stationary Combustion Sources," Combustion, Vol. 42,
October, 1970, pp. 37-40.
Berkau, E. E. "Nitrogen Oxides from Industrial Sources." Presented
at Industrial Air Pollution Control Short Course, Bessemer State
Technical Institute, Bessemer, Alabama, May 26, 1971.
Breen, B. P., A. W. Bell, N. Bayard de Volo, F. A. Bagwell, and K.
Rosenthal. "Combustion Control for Elimination of Nitric Oxide
Emissions from Fossil-Fuel Power Plants." Presented at 13th Symposium
on Combustion by Combustion Institute, Salt Lake City, Utah, August
23-29, 1970.
"Boiler Emissions and Their Control." Combustion Engineering, Inc.,
Windsor, Connecticut.
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BIBLIOGRAPHY (Continued)
Coates, N. H., P. S. Lewis, and J. W. Eckerd. "Combustion of Coal
in Fluidized Beds." Trans. AIME Vol. 247, No. 3, pp. 208-210,
September, 1970.
"Coming the Pressure to Cut Nitric Oxides," Modern Power Engineer-
ing, Vol. 65, No. 6, June, 1971, pp. 68-69.
Cuife, S. T., R. W. Gerstle, A. A. Orning, and C. H. Schwartz. "Air
Pollutant Emissions from Coal Fed Power Plants Report No. 1," APCA
Journal Vol. 14, No. 9, September, 1964, pp. 353-362.
DLehl, E. K., and E. A. Zawadzki. "Contaminants in Flue Gases and
Methods for Removal." Coal Age, pp. 70-74, December, 1965.
Diehl, E. K. "Reduction of Emission of Oxides of Nitrogen, Present
and Future Prospects." Presented at international Conference on
Air Pollution, December 13, 1966.
Ehrlich, S., Pope, Evans, and Robbins. "Air Pollution Control
Through New Combustion Processes." Combustion, July, 1971.
Engleman, V. S., R. B. Eldeman, W. Bartok, and J. P. Longwell.
"Experimental and Theoretical Studies of N0X Formation in a Jet
Stirred Combustor." To be presented at the 14th International
Symposium on Combustion at Penn State, State College, Pennsylvania,
August, 1972.
Finzer, E. Z. "Fuel Oil Additives for Controlling Air Contaminant
Emissions." APCA Journal Vol. 17, No. 1, pp. 43-45, January, 1967.
Gasiorowski, K. "Energineerzeugung aus fluessigen Brennstoffen."
Gesundheits - Ingenieur, Vol. 86, No. 4, pp. 116-122, April, 1965.
George, R. E., and R. L. Chass. "Control of Contaminant Emissions
from Fossil Fuel-Fired Boilers." APCA Journal Vol. 17, No. 6, pp.
392-395, June 1965.
Gerstle, R. W., S. T. Cuffe, A. A. Orning, and C. H. Schwartz.
"Air Pollutant Emissions from Coal-Fired Power Plants, Report No. 2,"
APCA Journal Vol. 15, No. 2, February 1965, pp. 59-64.
Godel, A. Cosar, and P. Cosar. "The Scale-Up of a Fluidized Bed
Combustion System to Utility Boilers." Activity Paris (France) and
Babcock Atlantique, Paris (France), 31 pp., 1971.
Griswold, S. S., R. L. Chass, R. E. George, and R. E. Holmes. "An
Evaluation of Natural Gas as a Means of Reducing Industrial Air
Pollution." APCA Journal Vol. 12, No. 4, pp. 155-163, 208.
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BIBLIOGRAPHY (Continued)
Hall, H. J., and W. Bartok. "N0X Control from Stationary Sources,"
Environmental Science and Technology Vol. 5, No. 4, April, 1971,
pp. 320-326.
Hammons, G. A., and A. Skoop. "A Regenerative Limestone Process for
Fluidized Bed Coal Combustion and Desulfurization." ESSO Research
and Engineering Company, Linden, New Jersey, Government Research
Division, APCO Contract CPA-70-19, APTD-0669, 115 pp., February 28,
1971. NTISrPB 198822.
James, D. W. "Coping with N0X, A Growing Problem." Electrical World
Vol. 175, No. 3, February 1, 1971, pp. 44-47.
Jefferies, G. C., and J. D. Sensenbaugh. "Effect of Operating
Variables on the Stack Emission from a Modern Power Station Boiler."
Presented at ASME Meeting, Atlantic City, New Jersey, November 29,
December 4, 1959, Paper No. 59 A-308.
Jonke, A. A., E. L. Carls, G. J. Vogel, L. J. Anastasia, R. L. Jarry,
and M. Haas. "Reducing Pollution from Fossil Fuel Combustion."
Instrument Control Systems, Vol. 44, No. 7, pp. 95-98, July, 19/1.
Lee, G. K., F. D. Friedrich, and E. R. Mitchell. "Control of
Pollutant Emission and Sulfuric Acid Corrosion from Combustion of
Residual Fuel Oil. Part I: Low-Pressure Heating Boilers with
Mechanical Atomizing Burners." Dept. of Energy, Mines, and Resources,
Ottawa (Ontario), Canadian Combustion Research Lab. RR-195, 50 pp.
December, 1968.
Lee, G. K., F. D. Friedrich, and E. R. Mitchell. "Control of SO3
in Low-Pressure Heating Boilers by an Additive." Journal Institute
of Fuel Vol. 42, No. 337, pp. 67-74, February, 1969.
Lee, G. K., E. R. Mitchell, F. D. Friedrich, and R. G. Draper. "Fire-
side Corrosion and Pollutant Emission from Crude Oil Combustion."
Preprint ASME, New York, 5 pp., 1971.
Meyers, S. "Air Pollution and the Electric Utility Industry."
Presented at Engineering and Operations Workshop of the American
Public Power Association, February 9, 1971, New Orleans.
Mourik, J. K. C. Van. "The Formation of Nitrous Fumes in Gas Flames."
Ann. Occup. Hyg. Vol. 10, No. 4, pp. 305-315, Pergamon Press Ltd.,
1967, Printed in Great Britain.
Oya, M. "N0X Emission Control Method for Stabilized Combustion
Systems." Kogai (Hakua Shobo) (Pollution Control), Vol. 6, No. 5,
pp. 2-11, September, 1971. (Text in Japanese).
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BIBLIOGRAPHY (Continued)
Oya, M. "Studies on Control Technique of N0X from Stabilized Com-
bustion System." Preprint, Industrial Public Nuisance Council,
Tokyo (Japan), 7 pp., 1971. (Text in Japanese).
Pesterfield, C. H. "Literature and Research Survey to Determine
Necessity and Feasibility of Air Pollution RESEARCH PROJECT on Com-
bustion of Commercially Available Fuel Oils." APCA Vol. 14, No. 6,
pp. 203-207, June, 1964.
Plumey, A. L. "Fossil Fuel and the Environment—Present Systems and
their Emissions." Combustion, Vol. 43, No. 4, pp. 36-43, October,
1971.
Rawdon, A. H. "Progress in Reducing N0X." Presented at the
Committee on Power Generator, The Association of Edison Illuminating
Companies, Hartford, Connecticut, April 29, 1971.
Sanders, C. F., D. P. Teixeirs, and N. Bayard de Volo. "The Effect
of Droplet Combustion of Nitric Oxide Emission by Oil Flames."
Presented at Western States Combustion Institute, Seattle,
Washington, April 24, 1972.
Seabrook, H. H., and B. P. Breen. "A Practical Approach to NOx
Reduction in Utility Boilers." Presented at American Powe.: Con-
ference, Chicago, Illinois, April 18-20, 1972.
Segeler,- C. G. "The Gas Industry and It's Contribution to Air
Pollution Control." Presented at APCA 54th Ann. Meeting June 14,
1961.
Sonderling, H. H. , W. W. Pepper, B'. P. Breen, and A. W. Bell.
"Operation of Scattergood Steam Plant Unit No. 3." Presented at
1971 Intersociety Energy Conversion Engineering Conference, Boston,
Massachusetts, August 6, 1971.
Stezhenskii, A. I., and 0. A. Zagorovskii. "Pollution of the Urban
Atmosphere by Nitrogen Oxides." Gas Institute of the Academy of
Sciences of the Ukrainian S.S.R., Kiev. VDC 614.72:661.98.
Tomany, J. P., R. R. Kopping, and H. L. Burge. "A Survey of Nitrogen
Oxides Control Technology and the Development of a Low N0X Com-
bustor," Journal of Engineering for Power, Vol. 93, July, 1971,
pp. 293-299.
Tow, P. S. "Consideration of the Feasibility of Control of Oxides
of Nitrogen," APCA Vol. 7, No. 3, November, 1957, pp. 234-240.
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BIBLIOGRAPHY (Continued)
Turner, D. W., R. L. Andrews, and C. W. Siegmund." Influence of
Combustion Modification and Fuel Nitrogen Content on Nitrogen Oxides
Emission from Fuel Oil Combustion." Presented at AICHE meeting,
San Francisco, November, 1971.
Wasser, J. H., E. E. Berkau, and D. W. Pershing. "Combustion
Intensity Relationship to Air Pollution Emissions from a Model Com-
bustion System." EPA, Division of Control Systems, Combustion
Research Section.
Watanabe, S. "Abatement Methods for Combustion Products." Nenryo
Oyobi Nensyo (Fuel and Combustion) Vol. 38, No. 10, pp. 1-8,
October, 1971. (Text in Japanese).
Yamada, T., S. Sakabe, M. Kawai, K. Hirasawa, K. Miyajima, and H.
Oya. "Studies of NO2 Control Technique of Stabilized Combustion
System." Preprint, The Japan Society of Chemical Engineers,
Tokyo, pp. 75-76, 1971.
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