United States
Environmental Protection
Agency
Office of Research and
Development
Washington DC 20460
EPA/625/R-96/001
February 1996
&EPA Summary Report
Control of NOX Emissions by
Reburning
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EPA/625/R-96/001
February 1996
Summary Report
Control of NOX Emissions by Reburning
Center for Environmental Research Information
National Risk Management Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, Ohio 45268
Printed on Recycled Paper
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Notice
The information in this document has been funded wholly, or in part, by the U.S. Environ-
mental Protection Agency (EPA). This document has been subjected to EPA's peer and
administrative review and has been approved for publication as an EPA document. Mention
of trade names or commercial products does not constitute endorsement or recommenda-
tion for use.
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Foreword
The U.S. Environmental Protection Agency (EPA) is charged by Congress with protecting
the Nation's land, air, and water resources. Under a mandate of national environmental
laws, the Agency strives to formulate and implement actions leading to a compatible bal-
ance between human activities and the ability of natural systems to support and nurture life.
To meet this mandate, EPA's research program is providing data and technical support for
solving environmental problems today as well as building the science knowledge base nec-
essary to manage our ecological resources wisely, understand how pollutants affect our
health, and prevent or reduce environmental risks in the future.
The National Risk Management Research Laboratory (NRMRL) is the Agency's center for
investigation of technologies and management approaches for reducing risks from threats
to human health and the environment. NRMRL's research program focuses on methods for
the prevention and control of pollution to air, land, water, and subsurface resources; protec-
tion of water quality in public water systems; remediation of contaminated sites and ground
water; and prevention and control of indoor air pollution. The goal of this research effort is to
catalyze development and implementation of innovative, cost-effective environmental tech-
nologies; develop scientific and engineering information needed by EPA to support regula-
tory and policy decisions; and provide technical support and information transfer to ensure
effective implementation of environmental regulations and strategies.
This publication has been produced in support of NRMRL's strategic long-term research
plan. It is published and made available by EPA's Office of Research and Development to
assist the user community and to link researchers with their clients.
E. Timothy Oppelt, Director
National Risk Management Research Laboratory
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Acknowledgments
This report was prepared by Radian Corporation (now Radian International LLC) as a sub-
contractor to Eastern Research Group, Inc. under EPA contract 68-C3-0315, Work Assign-
ment 24. Michael L Meadows, P.E., was principal author with assistance from Benjamin P.
Kuo, Anna Roberts, and Suzette M. Puski. Greg Asbury served as Radian's Project Man-
ager. This work was done under the direction of Justice A. Manning, P.E., EPA's Center for
Environmental Research Information, with substantial assistance from Robert E. Hall, Chief,
Combustion Research Branch, National Risk Management Research Laboratory. Peer re-
viewers included Mr. Hall and Andy Miller, EPA; John M. Pratapas and Dr. Steven F. Free-
man, Gas Research Institute. Sincere appreciation is expressed to each of these persons
for their interest, time and energy put into this report.
Appreciation is expressed to Combustion Engineering, Inc. and the Babcock & Wilcox Co.
for allowing us to use copyrighted material from their classic publications, "Combustion
Fossil Power Systems," 4th Edition, Joseph Singer, Editor, and "Steam, Its Generation and
Use," 40th Edition, S.C. Stultz and J.B. Kitto, Editors, respectively.
IV
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Contents
Foreword iii
Acknowledgments iv
Chapter 1 Introduction 1
Background 1
Organization 2
Chapter 2 Theories of NO, Formation and Control by Reburn 3
NOX Formation 3
Thermal NOx Formation 3
Fuel NO, Formation 6
Prompt NOx Formation 7
Factors that Affect NO, Emissions 8
Boiler Designs 8
Tangentially-Fired Boilers 9
Wall-Fired Boilers 11
Cyclone-Fired Boilers 14
Theory of NOX Emission Control by Reburn 16
Three-Stage Combustion 16
Main Burner Zone Heat Release Rate 17
Lower Nitrogen Content of Reburn Fuel 17
Operational Parameters 18
Reburn Fuels 18
Flue Gas Recirculation 18
O2 Stoichiometry 19
Residence Time 19
Temperature 20
Controls and Instruments 20
Potential Application Problems 20
Fuel Combustion Problems 20
Boiler Operating Problems 20
Reburn Fuel Availability and Cost 21
Physical Constraints 22
Particulate Control Device Constraints 22
Boiler Safety 22
Load Dispatch Range 22
Ancillary Benefits 23
Chapter 3 Example Full-Scale Demonstrations 25
Introduction 25
Public Service of Colorado - Cherokee Unit 3 25
Illinois Power Company - Hennepin Unit 1 31
City Water, Light, and Power - Lakeside Unit 7 34
Wisconsin Power & Light Company - Nelson Dewey Unit 2 39
Ohio Edison - Niles Unit 1 41
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Contents (continued)
Ladyzhin Power Station - Unit 4 43
Chapter 4 Process Economics 51
Costing Methodology 51
Capital Costs 51
Operating and Maintenance Costs 53
Busbar Cost and Cost-Effectiveness 54
Cost Analysis 54
Model Plants 55
Sensitivity Analysis 55
Chapter 5 Integrated NOx Control Technologies 63
Reburning with Low NOx Burners 63
Reburning with SNCR 63
Reburning with SCR 64
Chapter 6 References 67
Chapter? Bibliography 70
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Figures
2-1 Effect of Equivalence Ratio on NOx Formation 4
2-2 Effect of Equivalence Ratio on Adiabatic Combustion Temperature 5
2-3 Conversion of Fuel-Bound Nitrogen in Practical Combustors 6
2-4 Sources of NOx Emissions from Coal 7
2-5 Fuel-Bound Nitrogen-to-Nitrogen Oxide in Pulverized Coal Combustion 8
2-6 Firing Pattern in a Tangentially-Fired Boiler 9
2-7 Burner Assembly of a Tangentially-Fired Boiler 10
2-8 Single-Wall and Opposed-Wall Type Wall-Fired Boilers 12
2-9 Typical Circular Burner 12
2-10 Cell Burner 13
2-11 Flow Pattern in an Arch-Fired Boiler 14
2-12 Cyclone Burner 15
2-13 Firing Arrangements Used with Cyclone-Fired Boilers 15
2-14 Conventional Firing and Gas-Fired Reburn Applied to a Wall-Fired Boiler 17
3-1 Cherokee Unit 3-LNB-Gas Reburn System Schematic 26
3-2 Cherokee Unit 3-Short-Term NOx Emission Data 27
3-3 Cherokee Unit 3-LNB-Gas Reburning Data 28
3-4 Cherokee Unit 3-Effect of Excess Air on NOX Emissions 29
3-5 Cherokee Unit 3-Effect of Gas Input on NOx Emissions 30
3-6 Cherokee Unit 3-Effect of Unit Load on NOx Emissions 31
3-7 Cherokee Unit 3-Long-Term NOK Emission Data 32
3-8 Hennepin Unit 1-Stacked Burners of Tangentially-Fired Boiler 33
3-9 Hennepin Unit 1-Gas Reburning Data with Coal as the Primary Fuel 35
vii
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Figures (continued)
3-10 Hennepin Unit 1-Long-Term Gas Reburning Data 35
3-11 Lakeside Unit 7-GR-SI System Schematic 36
3-12 Lakeside Unit 7-Effect of Gas Heat Input on NOx Emissions 37
3-13 Lakeside Unit 7-Effect of Reburn Zone Stoichiometry on NOx Emissions 37
3-14 Lakeside Unit 7-Effect of Flue Gas Recirculation on NOx Emissions 38
3-15 Lakeside Unit 7-Long-Term Operation Results for NOx Reductions 39
3-16 Nelson Dewey Unit 2-Coal-Fired Reburn System Schematic 40
3-17 Nelson Dewey Unit 2-NOx Emissions vs. Unit Load - Illinois Basin Coal 41
3-18 Nelson Dewey Unit 2-NOx Emissions vs. Unit Load - Powder River
Basin Coal 42
3-19 Niles Unit 1-Schematic of Reburn Process 44
3-20 Niles Unit 1-Variation of NOx with Reburn Stoichiometry 45
3-21 Niles Unit 1-NOX Emissions as a Function of Boiler Load 45
3-22 Ladyzhin Unit 4-Schematic of Reburn Design Arrangements 48
3-23 Ladyzhin Unit 4-NOx Emissions vs. Reburn Fuel Percentage 49
3-24 Ladyzhin Unit 4-NOx Emissions vs. Flue Gas Oxygen Content 50
3-25 Ladyzhin Unit 4-NOx Emissions vs. Boiler Load 50
4-1 Impact of Plant Characteristics on Reburn Cost Effectiveness and
Busbar Costs for Wall-Fired Boilers 52
4-2 Impact of NOx Emission Characteristics and Heat Rate on Reburn Cost
Effectiveness"for Wall-Fired Boilers 58
4-3 Impact of Plant Characteristics on Reburn Cost Effectiveness and Busbar
Costs for Tangentially-Fired Boilers 59
4-4 Impact of NOx Emission Characteristics and Heat Rate on Reburn Cost
Effectiveness for Tangentially-Fired Boilers 60
4-5 Impact of Plant Characteristics on Reburn Cost Effectiveness and Busbar
Cost for Cyclone-Fired Boilers 60
4-6 Impact of NOx Emission Characteristics and Heat Rate on Reburn Cost
Effectiveness"for Cyclone-Fired Boilers 61
Vill
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Tables
3-1 Summary of Example Reburn Installations 25
3-2 Hennepin Unit 1-Fuel Analysis Comparison 34
3-3 Nelson Dewey Unit 2-Summary of Effects of Reburning on Unit
Operating Parameters 43
3-4 Ladyzhin Unit 4-Fuel Analyses 46
3-5 Ladyzhin Unit 4-Flow Diagram for Boiler Combustion Performance
Model 47
3-6 Ladyzhin Unit 4-Furnace Thermal Performance Summary 47
4-1 Capital and Operating Cost Components 52
4-2 Variable O&M Unit Costs 54
4-3 Costs for Natural Gas-Fired Reburn Applied to Coal-Fired Boilers 56
5-1 Costs for SNCR Applied to Coal-Fired Boilers 65
5-2 Costs for SCR Applied to Coal-Fired Boilers 66
IX
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Chapter 1
Introduction
Background
The Clean Air Act Amendments of 1990 require re-
duction in emissions of nitrogen oxides (NOx) because
of NOx's contribution to acid rain formation and identifi-
cation as a precursor to ozone formation. This report
covers NOx control employing reburning technology: a
new, effective method of controlling NOx emissions from
a wide range of stationary combustion"sources includ-
ing large, coal-fired, utility boilers. Although reburning
potentially is applicable to either new or existing units,
this report focuses on retrofit applications on utility boil-
ers.
NOx emission control technologies that are capable of
achieving NOX emission reductions frojn a coal-fired
boiler can be classified as either combustion modifica-
tions or post-combustion flue gas treatment. Combus-
tion modification techniques prevent the formation of NOx
during combustion or destroy the NOx formed during pri-
mary combustion. These techniques include the use of
low-NOx burners (LNBs), overfire air (OFA), and boiler
combustion optimization. Post-combustion flue gas treat-
ment reduces the NOx content of the flue gas through
techniques such as selective catalytic reduction (SCR)
and selective noncatalytic reduction (SNCR).
Reburning, as described in this report, is a combus-
tion modification since the formation of NO is minimized
in one portion of the boiler and a portion of the NOx that
does form, is destroyed in another.
Unlike some other NOX control approaches, reburning
technology is applicable to a wide variety of the boilers
and, in many cases, can be implemented within a rela-
tively short period of time. Reburning is ideal for wet-
bottom (i.e., slagging) boilers. The only other commer-
cially available NOx control alternative for this type of
boiler is flue gas treatment, which is more costly per ton
of NO reduction achieved. Because of reburning's ap-
plicability to a wide variety of coal-fired combustion
sources, several demonstration projects have been un-
dertaken to gather data on reburning. As a result of such
projects, reburning technology is offered commercially
by several firms including ABB Combustion Engineer-
ing, Babcock & Wilcox (B&W), and Energy and Environ-
mental Research Corporation (EER).
Reburning reduces NOx emissions by completing com-
bustion in three stages. In the first stage, NO formation
due to interactions between the fuel and combustion air
at high temperatures is controlled by reducing the burner
heat release rate and the amount of oxygen present. In
the second stage, additional fuel is added under reduc-
ing (oxygen-deficient) conditions to produce hydrocar-
bon radicals that react with the NOx formed in the first
stage to produce nitrogen gas (N2). Additional combus-
tion air is added in the lower-temperature third stage and
combustion is completed. In retrofit applications such as
discussed in Chapter 3, reburning has achieved up to
60% reduction from baseline NOX emissions.
The concept for "reburning" was developed in the late
1960s by Dr. J.O.L. Wendt, and was first presented in
1973 at the Fourteenth Symposium (International) on
Combustion (Wendt et. al., 1973). Japanese investiga-
tors (Y. Takahashi, et. al.) followed up on the concept
and performed pilot-scale tests that showed promising
results, e.g., a 50% NOX reduction. Following those re-
sults, which were presented at the U.S.-Japan NOx In-
formation Exchange in Tokyo in May 1981 (Takahashi
et. al., 1981), U.S. researchers began an intensive in-
vestigation of reburn technology. W.S. Lanier, J.A.
Mulholland, and R.E. Hall of the U.S. Environmental Pro-
tection Agency (EPA) performed research on natural gas-
and oil-fired reburn systems (Mulholland and Lanier,
1985; Mulholland and Hall, 1987). At the same time EPA
sponsored tests at EER on natural gas-, oil-, and coal-
fired systems (U.S. EPA, 1985a; U.S. EPA, 1987; U.S.
EPA, 1989). This research, performed by S. B. Greene,
S. L Chen, W. D. Clark, J. M. McCarthy, B. J. Overmoe,
M. P. Heap, D. W. Pershing, and W. R. Seeker, was later
supplemented by the Gas Research Institute (GRI).
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As a result of this early research, full-scale demon-
strations of natural gas reburn technology were initiated.
The first reburn demonstration, co-sponsored by EPA,
GRI, the Electric Power Research Institute (EPRI), U.S.
Department of Defense (DOE), and the Ohio Coal De-
velopment Office, was performed by ABB Combustion
Engineering on Ohio Edison's Niles No. 1 cyclone-fired
boiler. Closely following the Niles start-up, EER began a
reburn demonstration under DOE's Clean Coal Technol-
ogy Program (CCTP) on the Illinois Power's Hennepin
No. 1 tangentially-fired boiler. This was followed by other
EER CCTP demonstrations on the City Water, Light, and
Power's Lakeside No. 7 cyclone-fired boiler and Chero-
kee No. 3 wall-fired boiler. EPA also sponsored a gas-
fired reburn demonstration on the Ladyzhin No. 4 wet-
bottom boiler in Ukraine. This project was performed by
ABB Combustion Engineering and, to date, is the larg-
est boiler on which reburning has been demonstrated.
Another CCTP demo was performed by B&W on Wis-
consin Power & Light's Nelson Dewey No. 2 boiler. This
was the first coal-fired reburn system demonstration.
Each of these tests will be described in more detail later
in this report.
Organization
This report serves as a summary of reburning tech-
nologies that are being tested on coal-fired, utility boil-
ers and reflects on-going work in the field of reburning
systems. The data presented in this report represent an
overview of the tests occurring within the U.S. as well as
abroad. This report includes results of demonstrations
performed through mid-1994 and, necessarily, is not all-
inclusive. In Chapter 2, the chemistry of NOX formation
in coal-fired boilers is presented along with the theoreti-
cal basis for NOx emission control through reburning.
Also in Chapter 2, an overview of various types of coal-
fired boilers to which reburning may be applied is pro-
vided. Representative case studies and test data for a
range of boiler types are summarized in Chapter 3. The
process economics of retrofitting reburning to an exist-
ing boiler is discussed in Chapter 4. The potential for
combining reburning with other NOx emission control
techniques is examined briefly in Chapter 5. A list of the
references cited in this report is contained in Chapter 6.
Finally, a bibliography of other available reports of inter-
est is presented in Chapter 7.
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Chapter 2
Theories of NOx Formation and Control by Reburn
NOX Formation
NOX emissions from combustion devices commonly are
considered to be comprised of nitric oxide (NO) and ni-
trogen dioxide (NO2). For most combustion systems, in-
cluding coal-fired boilers, significant evidence exists to
show that NO is the predominant NOx species (over 95%
of the total). In recent work, other forms of nitrogen ox-
ides, e.g., N2O, have been identified and are being re-
searched to characterize their contribution and their im-
portance to the need to control total NOx. N2O is of con-
cern primarily because of its impact on ozone reduction
in the stratosphere. However, for purposes of emissions
control, NOx is defined as the sum of NO and NO, fully
converted to NO2. This corresponds to tne output of a
chemiluminescence instrument, the most widely ac-
cepted NOX measurement technique.
The formation of NOx from a specific combustion device
is determined by a complex interaction between chemi-
cal, physical, and thermal processes occurring within the
device. To help simplify the understanding of NOX for-
mation and assist in identifying control strategies, NOx
typically is considered to form through three mechanisms:
Thermal NOX - formed by the oxidation of atmo-
spheric nitrogen by free oxygen atoms in the higher-
temperature regions of the combustion flame;
Fuel NOX - formed from chemical reactions involv-
ing nitrogen atoms chemically bound within the fuel
component species; and
Prompt NOX - formed by chemical reactions between
atmospheric nitrogen and fuel-derived hydrocarbon
radicals and subsequent oxidation.
Thermal NOX Formation
Thermal NO results from the oxidation of atmospheric
nitrogen in the higher-temperature and air-rich regions
of a combustion system. Dependent upon the type of
fuel and the air mixing profiles within the combustion
device, these regions can be a distinct fuel/air flame
(mixing) front, turbulent eddies of near-stoichiometric
composition, or a premixed* near-stoichiometric condi-
tion. With the complex combustion processes occurring
in coal-fired boilers and their wide range of design types,
each of these situations is feasible and, in fact, may oc-
cur even within different regions of the same boiler.
The basic chemical mechanism occurring in each of
these situations has been well characterized in sub-scale
research studies and proven in full-scale combustion
systems. During combustion at high temperatures in air-
rich regions, oxygen radicals are formed from the disso-
ciation of atmospheric oxygen by thermal and chemical
means. These atoms react with nitrogen molecules to
start the reactions that comprise the thermal NOX forma-
tion mechanism:
0,7! 20
O + N, 2 NO + N
N + O2 ^ NO + O
N + OH ^ NO + H
(2-1)
(2-2)
(2-3)
(2-4)
Reaction 2-2 is highly temperature dependent and oc-
curs to an appreciable extent in combustion devices of
all types but only at significant rates at temperatures
above 3200°F. The principal source of O atoms for this
reaction is dissociation of O2 (reaction 2-1), although
other hydrocarbon/oxygen reactions can also contribute
O atoms. Reactions 2-2 and 2-3 produce approximately
the same amount of NO, with the first reaction being the
only significant source of N atoms for the reactions 2-3
and 2-4. Reaction 2-4 is generally of lower significance
in the formation scheme.
'A premixed flame exists when the reactants are mixed prior to chemical reac-
tion.
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The major factors that influence thermal NO formation
are temperature, O atom concentrations, and residence
time. However, the mixing history of hydrocarbons from
coal with the combustion air and flue gas products con-
trols the actual profiles of temperature, stoichiometry, and
residence time distributions. If these parameters can be
changed dramatically, thermal NOx formation is sup-
pressed or "quenched." This quenching is the basis for
several well-proven NOx control strategies.
For these reactions and the related reactions controlling
temperatures, O and O species concentrations have
been studied using thermochemical equilibrium and
chemical kinetic digital computer programs. The results
from these programs, showing the importance of time,
temperature, and stoichiometry (oxygen availability), are
shown in Figures 2-1 and 2-2 (Bagwell et al., 1971).
Calculated NOx concentration as a function of the equiva-
lence ratio* and time for 650°F combustion air preheat
* Equivalence ratio is defined as the actual fuel/oxidizer ratio divided by the sto-
ichiometric fuel/oxidizer ratio, and is given the symbol of 0
is depicted in Figure 2-1. The NOx formation rate is a
maximum for slightly air-rich mixture ratios and decreases
rapidly as the mixture becomes increasingly fuel rich.
The rate of NO formation decreases for increasingly fuel-
rich mixtures. The principal reason is that the available
oxygen will react much more readily with the hydrogen
and carbon than with the nitrogen. The decrease in oxy-
gen atom concentration is more important than the sec-
ondary effect of the decreasing temperature. The tem-
perature decay is relatively slow because the excess fuel
contributes little to the total mass.
The NOx formed in coal-fired combustion devices is pri-
marily a burner phenomenon, since the temperature of
the bulk gas is too low to support significant N0x forma-
tion. The type of burner utilized has a predominate role
in the quantity of NO^ formed during combustion. Higher-
intensity burners typically generate more NO than lower-
intensity, delayed-mixing burners. Rapid mixing (produc-
ing flame zones that are closer to an equivalence ratio
of 1 and of higher temperature) affects the rate of NOx
formation. This effect of mixing on NOx formation rate is
illustrated in Figure 2-2.
1000 -
I
0.6 0.7
Air Rich
A/F Stoichiometric = 16.3
0.8 0.9 1.0
Equivalence Ratio
1.1
1.2 1.3
Fuel Rich
Air Preheat = 650° F
Figure 2-1. Effect of Equivalence Ratio on NOt Formation (Bagwell, et al. 1971).
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3.80
3.75
3.70
§
1 3.65
I
o
1
JD
O
O
3.60
3.55
£ 3.50
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rates that research and development efforts are attempt-
ing to alleviate.
Fuel NOX Formation
The oxidation of fuel-bound nitrogen very often is the
principal source of NOX emissions in combustion of coal
and some fuel oils (natural gas contains negligible quan-
tities of fuel-bound nitrogen compounds). The heterocy-
clic-ring nitrogen compounds of pyridine, piperidine, and
quinoline are the most common ones found in fuel oil.
Both chain and ring nitrogen-bearing compounds are
found in coal. The reactions involved are not so clear cut
as are reactions forming thermal NOX. One theory pro-
poses cyanide (CN) as an intermediate step, while an-
other proposes that atomic N is released as the bonds
are broken. The rate of conversion of the fuel-bound ni-
trogen to NO is dependent on the properties of the nitro-
gen-bearing compounds as well as their rate of evolu-
tion during combustion.
Numerous studies have been conducted to determine
the percent of the total fuel-bound nitrogen converted to
NO. Figure 2-3 contains data on the sensitivity of fuel-
bound nitrogen conversion to stoichiometry (oxygen
availability) for equivalence ratios ranging from 0.6 to
1.4 (Pohl and Sarofim, 1976). Other studies have con-
firmed this sensitivity and also have shown that the con-
version is relatively insensitive to temperature variations.
During coal combustion, the burning of coal particles
takes place as either volatiles released from the coal
particle or as char burnout of the remaining solid mate-
rial. Fuel NO can be formed in both combustion phases
and is described as either volatile NO or char NO. Re-
cent research data on coal and char oxidation show that
the devolatilized nitrogen compounds amount to the
major fraction of the NO produced from fuel-bound ni-
trogen. The char-nitrogen contribution, however, cannot
be neglected.
The results of one research program (Pershing and
Wendt, 1976) are shown in Figure 2-4, which illustrates
the relative proportions of thermal NO and fuel NO (vola-
tile NO + char NO) produced in the combustion of coal.
The findings of the program indicate that the fuel NO
comprises approximately 80% of the total NO formed in
coal combustion. This illustrates the reason reducing the
peak flame temperature (control of thermal NO) is rela-
tively ineffective in reducing coal-fired NO emissions. The
stoichiometry has a substantial impact on fuel NO for-
mation. The conversion of fuel nitrogen to NOx is reduced
by delaying the addition of O2 required to complete the
combustion until after the fuel-bound nitrogen has re-
acted and/or until the combustion temperature has de-
X
o
1
8
-------
1400
1200
1000
Q.
Q.
"o"
"5 800
g
o
"o
52. 600
O
400
200
Total NO
FuelNO(AR/O2/C02)
Calculated - NO Addition
Calculated - NH3 Addition
I .... I .... I .... I . i
1.00 1.05 1.10 1.15 1.20 1.25 1.30
Stoichiometric Ratio
Figure 2-4. Sources ofNOt Emissions from Coal (Pershing and Wendt, 1976).
creased. In this manner the fuel-bound nitrogen oxida-
tion occurs under fuel-rich conditions that favor the for-
mation of N2 and lower the conversion rate to NOx
During one study (Singer, 1991), fuel NOx was measured
in a large tangentially-fired coal utility boiler. Fuel N0x
formation correlated well with the fuel oxygen-to-nitro-
gen ratio (Figure 2-5), suggesting that fuel oxygen (or
some other fuel property that correlates well with fuel
oxygen) influences the percentage of fuel nitrogen con-
verted to fuel NOX. This corresponds to previous obser-
vations that greater levels of NOx are found in air-rich
combustion environments.
In spite of a detailed understanding of the mechanisms
for fuel-bound nitrogen conversion to NOx, the ap-
proaches used to control thermal NOx work as well or
better on the fuel-bound nitrogen, i.e., oxygen stoichi-
ometry has a significant effect on NOx formation and tem-
perature has a lesser, but still important, effect. Thus,
two forms of NOx (fuel NOx and thermal NOx) are con-
trolled by the same methods, but for different reasons,
as explained in the preceding discussion.
Prompt NOX Formation
Prompt NOx results from the reactions of atmospheric
nitrogen and hydrocarbon radicals during combustion.
As opposed to the slower thermal NOx formation, prompt
NOX formation is rapid and occurs on a time scale com-
parable to the energy release reactions (i.e., within the
flame). Thus, prompt NOx formation cannot be quenched
in the manner by which thermal NOX formation is
quenched. However, the contribution of prompt NOx to
the total NO emissions of a system is not significant
(Bartok and Sarofim, 1991).
Although some uncertainty exists in the detailed mecha-
nisms for prompt NOx formation, the principal products
of the initial reactions, hydrogen cyanide (HCN) or CN
radicals, are believed to be generated during combus-
-------
o
16
14
12
10
o
O
C Q
0) O
a> 6
I
I
10 15 20
Ratio of Coal Oxygen to Coal Nitrogen
25
30
Figure 2-5. Fuel-Bound Nitrogen-to-Nitrogen Oxide in Pulverized Coal Combustion (Singer, 1991).
tion of the fuel, and the presence of hydrocarbon spe-
cies is considered to be essential for the reactions to
take place (Glassman, 1987). The following reactions
are the most likely initiating steps for prompt NOx:
CH+N, HHCN
CH5+N, ^HCN +
(2-5)
(2-6)
HCN is then further reduced to form NO and other nitro-
gen oxides.
Measured levels of prompt NOx for a number of hydro-
carbon compounds in a premixed flame show that the
maximum prompt NO level is reached on the fuel-rich
side of stoichiometry (Glassman, 1987). On the fuel-lean
side of stoichiometry, few hydrocarbon fragments are
available to react with atmospheric nitrogen to form HCN,
the precursor to prompt NOx. With increasingly fuel-rich
conditions, an increasing amount of HCN is formed, cre-
ating more NOx. However, above an equivalence ratio
of approximately 1.4, not enough oxygen radicals are
present to react with HCN and form NO, so NO levels
decrease.
Factors That Affect NOX Emissions
The formation of thermal, fuel, and prompt NO in com-
bustion systems is controlled by the interplay of equiva-
lence ratio with combustion gas temperature, residence
time, and turbulence (sometimes referred to as the "three
Ts"). Of primary importance are the localized conditions
within and immediately following the primary flame zone
where most combustion reactions occur. In utility boil-
ers, the equivalence ratio and the three Ts are deter-
mined by factors associated with burner and furnace
design, fuel characteristics, and boiler operating condi-
tions. Subsequent sections of this report contain a dis-
cussion of how furnace design, fuel characteristics, and
boiler operating characteristics can influence baseline
(or uncontrolled) NOx emission rates.
Boiler Designs
A number of different furnace configurations are utilized
in coal-fired, utility boilers. Reburn NOx emission con-
trols have been applied to tangentially-fired boilers, wall-
fired boilers, and cyclone-fired boilers. Boilers can also
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be categorized as dry-bottom (non-slagging) boilers and
wet-bottom (slagging) boilers.
The majority of utility boilers in the U.S. are of the dry-
bottom design. In this design, the temperature in the lower
part of the furnace is kept below the initial deformation
temperature of the coal ash (from 2000°F to over 2500°F
depending upon the coal ash chemical composition and
the oxygen stoichiometry through which the ash passes)
and the ash is collected as a dry particulate. Typically,
only 20 to 30% of the total ash production is collected in
the bottom of the furnace as bottom ash; the remaining
70 to 80% leaves the boiler as fly ash entrained with the
flue gas.
In wet-bottom boilers, the temperature in the lower part
of the furnace is maintained above the fluidization tem-
perature of the ash. This temperature also depends on
the chemical composition of the ash but is typically
greater than 2400°F. The majority of the ash (60 to 80%)
is collected in the bottom of the furnace as molten slag.
This slag is removed from the furnace and quenched in
a slag tank. The remaining ash is entrained with the flue
gas leaving the boiler and is removed by particulate con-
trol equipment. Wet-bottom boilers are most frequently
used for coals with low ash fusion temperatures that
would result in ash entering the convection portion of
the boiler in a molten condition, creating severe slagging
conditions.
The characteristics of the boiler designs determine the
uncontrolled NOx emissions of the boiler. In particular,
the design furnace temperature and heat release rate
affect the formation of thermal NO, and fuel NO..
Tangentially-Fired Boilers
The tangentially-fired boiler is a dry-bottom boiler based
on the concept of a single flame zone within the furnace.
As shown in Figure 2-6, the fuel-air mixture in a tangen-
tially-fired boiler projects from the four corners of the fur-
nace along a line tangential to an imaginary cylinder lo-
cated along the furnace centerline (Singer, 1991). As
shown in Figure 2-7, the burners in tangentially-fired
boilers are incorporated into stacked assemblies that in-
clude several levels of primary air/fuel nozzles inter-
spersed with secondary air supply nozzles and warmup
guns. The burners inject stratified layers of fuel and sec-
ondary air into a relatively low-turbulence environment.
The stratification of fuel and air creates fuel-rich regions
in an overall fuel-lean (i.e., air-rich) environment. Before
the layers are mixed, ignition is initiated in the fuel-rich
region. Near the turbulent center fireball, cooler second-
ary air is quickly mixed with the burning fuel-rich region,
ensuring complete combustion.
The delayed mixing of fuel and combustion air reduces
local peak temperatures and thermal NO formation. In
Main Fuel Nozzle
Secondary-Air
Dampers
Burner Assembly
Figure 2-6. Firing Pattern in a Tangentially-Fired Boiler (Singer, 1991).
-------
<§
M
I
I
-------
addition, the delayed mixing provides the fuel-nitrogen
compounds a greater residence time in the fuel-rich en-
vironment, thus reducing fuel NOx formation.
In a tangentially-fired boiler, the fuel and air nozzles tilt
vertically in concert. This tilting allows the fireball to be
moved up and down within the furnace to control the
furnace exit gas temperature and provide superheated
steam temperature control during variations in load. Tilt-
ing the nozzles downward also reduces NOx formation
by producing more effective heat transfer to the boiler's
waterwalls.
Wall-Fired Boilers
Wall-fired boilers are characterized by multiple individual
burners located on a single wall or on opposing walls of
the furnace. These boilers can be of either the wet-bot-
tom or dry-bottom design depending on the heat release
rate in the boiler. In contrast to tangentially-fired boilers
that produce a single flame envelope, or fireball, each of
the burners in a wall-fired boiler has a relatively distinct,
high-intensity flame zone. Theses flame zones interact
with each other due to combustion gas recirculation re-
gions set up between them. Depending on the design
and location of the burners, wall-fired boilers can be
subcategorized as either single-wall, opposed-wall type
boilers. Other variations include cell burner, vertical-fired,
arch-fired, and turbo-fired type boilers.
Single-Wall and Opposed-Wall Type Wall-Fired
Boilers
The single-wall design consists of several rows of circu-
lar-type burners mounted on either the front or rear wall
of the furnace (Figure 2-8). Opposed-wall units have cir-
cular burners on the front and rear walls and have a
greater furnace depth.
Circular burners introduce a fuel-rich mixture of fuel and
primary air into the furnace through a central nozzle (Fig-
ure 2-9) (Stultz and Kitto, 1992). Secondary air is sup-
plied to the burner through separate adjustable inlet air
vanes. In most circular burners, these air vanes are po-
sitioned tangentially to the burner centerline and impart
rotation and turbulence to the secondary air. The de-
gree of air swirl, in conjunction with the flow-shaping
contour of the burner throat, establishes a recirculation
pattern extending several burner throat diameters into
the furnace. The high level of turbulence between the
fuel and secondary air streams promotes rapid coal vola-
tilization and creates a nearly stoichiometric combustion
mixture. Under these conditions, combustion gas
temperatures are high and contribute to thermal and fuel
NOx formation. In addition, the high level of turbulence
causes the amount of time available for fuel reactions
under reducing conditions to be relatively short, thus in-
creasing the potential for formation of fuel NOx.
Unlike tangentially-fired boiler designs, the burners in
wall-fired boilers do not tilt. Superheated steam tempera-
tures are instead controlled by excess air levels, heat
input, flue gas recirculation, and/or steam attemperation.
Cell-Burner Type Wall-Fired Boilers
Cell-burner type units consist of two or three vertically
aligned, closely spaced burners, illustrated in Figure 2-
10 (Stultz and Kitto, 1992). The cell burners are mounted
on opposing walls of the furnace. Cell-burner furnaces
have highly turbulent, compact combustion regions. This
turbulence promotes fuel-air mixing and creates a near-
stoichiometric combustion mixture. As described above,
these conditions promote the formation of both fuel and
thermal NOX. The close spacing of the fuel nozzles gen-
erates hotter, more turbulent flames than the flames in
more widely spaced burners of other wall-fired designs.
A higher heat release rate is achieved, but at relatively
higher NOx emission levels. The high heat release rate
causes local temperatures to increase even further, caus-
ing thermal NOX to increase due to its dependency on
local temperature.
Vertical-, Arch-, and Turbo-Fired Boilers
Vertical- and arch-fired boilers have burners that are ori-
ented downward. These boilers were developed prima-
rily to burn solid fuels that are difficult to ignite, such as
anthracite. They have more complex firing and operat-
ing characteristics than the previously discussed boiler
types. Anthracite burned in conventional boilers would
require supplemental fuel for ignition. These types of
boilers eliminate that requirement.
Pulverized coal is introduced through the nozzles, with
heated combustion air discharged around the fuel
nozzles and through adjacent secondary ports (Figure
2-11) (Singer, 1991). Tertiary air ports are located in rows
along the front and rear walls of the lower section of the
furnace.
The units have long, looping flames directed into the
lower furnace. Delayed introduction of the tertiary air
provides the necessary air to complete combustion. The
long flames allow the heat release to be spread out over
a greater volume of the furnace, resulting in locally lower
temperatures. The lower turbulence allows the initial
stages of combustion to occur in fuel-rich environments.
As a result, fuel NOx and thermal NOX are reduced.
Turbo-fired units have burners on opposing furnace walls
firing downward into a highly turbulent combustion cham-
ber. The turbo burners themselves are angled downward
and typically are less turbulent than the circular burners
in opposed-wall units. The lower combustion chamber
has highly recirculating flows that exit to the main boiler
region through a throat. The high-intensity, nearly adfa-
batic, combustion chamber region leads to high NOx for-
11
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Burner
Zone
Single-Wall Fired
Figure 2-8. Single-Wall and Opposed-Wall Type Wall-Fired Boilers.
Opposed-Walled Fired
Secondary
Air
Windbox Spin Vanes
Lighter
Furnace Wall Tube
Pulverized Coal
and Primary Air
from Pulverizer
Sliding Air Secondary _.. _ ._
Damper Air Pilot Tube Impeller
Grid
Furnace
Swirled Air
Flow Pattern
Figure 2-9. Typical Circular Burner (Stultz and Kitto, 1992).
12
-------
Figure 2-10. Cell Burner (Stultz and Kitto, 1992).
13
-------
High Pressure
Jet Air
Primary Air and
Pulverized Coal
Secondary Air
Arch
Tertiary Air
Admission
"U" - Shaped
Vertical Pulverized-
Coal Flame
Furnace Enclosure
(Refractory Lined)
Flgure2-11. Flow Pattern in an Arch-Fired Boiler (Singer, 1991).
mation for coal firing but provides for good carbon utili-
zation (burnout).
Cyclone-Fired Boilers
The cyclone-fired boiler is a wet-bottom boiler design
that burns crushed, rather than pulverized, coal. Fuel
and air are burned in horizontal cylinders, producing a
spinning, high-temperature flame (Figure 2-12) (Farzan
et at., 1991). Only a small amount of wall surface is
present in the cylinder and this surface is partially insu-
lated by a molten slag layer. Thus, burners in cyclone-
fired boilers have a combination of high heat release rate
and low heat absorption rates, which results in very high
flame temperatures and the conversion of ash in the coal
into a molten slag. Slag collected on the burner cylinder
walls flows out of the burners, down the furnace walls,
and into a water-filled slag tank located below the fur-
nace. The combination of high heat release rate, high
combustion temperatures, and near stoichiometric fuel/
air mixtures encourages formation of both thermal and
fuel NOx.
Because of their slagging design, cyclone-fired boilers
are almost exclusively coal-fired, except for some units
that were designed to also fire oil and natural gas (or
have been converted to do so). The single-wall firing and
opposed-wall firing arrangements used for cyclone fir-
ing are illustrated in Figure 2-13 (Stultz and Kitto, 1992).
For smaller boilers, sufficient firing capacity usually is
attained with cyclone burners located in only one wall.
For large units, furnace width often can be reduced by
utilizing an opposed-fired configuration.
14
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Tangential
Secondary
Air Inlet
Crushed Coal and
Primary Air
Tertiary Air
Scroll Burner
Cyclone Barrel
Slag Spout Opening
Slag Tap
Figure 2-12. Cyclone Burner (Farzan, et al, 1991).
Reheater/Superheater
UUUL
Cyclon
Burners
Reheater/Superheater
Opposed-Wall
Firing
Slag Tap
Tl
\
Cyclone
Burners
Single-Wall Firing
V
Slag Tap
Figure 2-13. Firing Arrangements Used with Cyclone-Fired Boilers (Stultz and Kitto, 1992).
15
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Theory of NOX Emission Control by
Reburn
Three-Stage Combustion
Reburn is a combustion hardware modification in which
the NO produced in the main combustion zone is re-
duced downstream in a second combustion zone (the
reburn zone). Up to 20% of the total fuel input (on a Btu
per hour basis) is diverted from the main combustion
zone and introduced above the top row of burners to
create reducing (sub-stoichiometric) conditions in the
reburn zone. The reburn fuel (which may be natural gas,
oil, or pulverized coal) is injected to create a fuel-rich
zone where the NOx formed in the main combustion zone
is reduced to nitrogen and water vapor. The reburn fuel
may be injected alone (natural gas or oil) or with either
air or recirculated flue gas to improve reburn fuel distri-
bution in the furnace. Combustion of the fuel-rich com-
bustion gases leaving the reburn zone is completed by
injecting overfire air (called "completion air" when refer-
ring to reburn) in the burnout zone. Figure 2-14 is a sim-
plified diagram of conventional firing and gas reburning
as applied to a wall-fired boiler (GRI, 1991).
In reburning, the main combustion zone operates at rela-
tively low oxygen stoichiometry (about 0.9 to 1.1), and
receives the bulk of the fuel input (80 to 90% of total
heat input). The balance of the heat input (10 to 20%) is
injected above the main combustion zone through
reburning injectors. The stoichiometry in the reburn zone
is in the range of 0.85 to 0.95. To achieve this, the reburn
fuel is injected at a stoichiometry of up to 0.4. The tem-
perature in the reburn zone must be above 1,800°F to
provide an environment for the decomposition of the
reburn fuel.
Any unburned fuel leaving the reburn zone is then burned
to completion in the burnout zone, where completion air
(15 to 20% of the total combustion air) is introduced.
The completion air ports are designed for adjustable air
velocities to optimize the mixing and complete burnout
of the fuel before it exits the furnace.
The kinetics involved in the reburn zone to reduce NOX
are complex and not fully understood at the present time.
The chemical reactions involved in the reburning pro-
cess were first proposed by J.O.L. Wendt in the late
1960s (Wendt et al, 1973). The following discussion,
derived from a recent report on reburn published by the
U.S. Department of Energy (Farzan and Wessel, 1991),
is based on the concepts introduced in this work. The
major chemical reactions are the following:
CH^_heat&OjLdeficiencL_>.CHj + >H (hydrocarbon radicals) (2-7)
The reaction process shown in Equation 2-7 is hydro-
carbon radical formation in the reburn zone. These hy-
drocarbon radicals are produced due to the pyrolysis of
the fuel in an oxygen-deficient, high-temperature envi-
ronment. The hydrocarbon radicals then mix with the
combustion gases from the main combustion zone and
react with NO to form CN radicals, NH2 radicals, and
other stable products (Equations 2-8 to 2-10).
+ NO->HCN + H
N2+.CH3
NH2+HCN
+ HCN->-CN+H,
(2-8)
(2-9)
(2-10)
The CN and NH radicals and other products can then
react with NO to form N2, thus completing the major N0x
reduction step (Equations 2-11 to 2-13).
-NH2->N2+H2O
NO + CN -> N2 + CO
NO + 2CO->N
(2-11)
(2-12)
(2-13)
An oxygen-deficient environment is critical to these re-
actions. If O2 levels are high, the NOX reduction mecha-
nism will not occur and other reactions will predominate
(Equations 2-14 and 2-15).
CN + O2 -> CO + NO
NH + O
H2O
NO
(2-14)
(2-15)
To complete the combustion process, air must be intro-
duced above the reburn zone. Conversion of HCN and
ammonia compounds in the burnout zone may regener-
ate some of the decomposed NOx by the reactions shown
in Equations 2-16 and 2-17:
HCN + 5/4O2->NO + CO
NH3 + 5/4 O2 -» NO+ 3/2 H20
(2-16)
(2-17)
Although some additional NOx may be formed in the
burnout zone through these reactions, the net effect of
the reburning process is to significantly reduce the total
quantity of NOx emitted by the boiler.
The NOx may continue to be reduced by the HCN and
NH3 compounds by the reactions shown in Equations 2-
18 and 2-1 9:
HCN + 3/4O2 -» 1/2N2 +CO + 1/2H2O
(2-1 8)
16
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Reheater/
Superheater
Primary Fuel-Coal
100%
UULd
Conventional Coal Firing
Reheater/
Superheater
Overfire Air
Reburn Fuel-Gas
~ 20%
Primary Fuel-Coal
- 80%
*
1^
r
>
^
V.
1
1
<
-<
_**
s
y
J
\
/
/
C
_i
Burnout Zone
Normal Excess Air
Reburn Zone
Slightly Fuel Rich
NOX Reduced to N2
Primary Combustion Zone
Reduced Firing Rate
Low Excess Air
Lower NOX
Gas-Fired Reburning
Figure 2-14. Conventional Firing and Gas-Fired Reburn Applied to a Wall-Fired Boiler (GRI, 1991).
NH3 + 3/4 02 -> 112 N2 + 3/2 H2O (2-19)
Main Burner Zone Heat Release Rate
In addition to the chemical reactions resulting from three-
stage combustion, reburning also reduces the formation
of thermal NO^ due to the reduced fuel firing rate in the
main combustion zone. As discussed previously, boilers
with higher heat release rates generate relatively more
thermal NOX. By diverting 10 to 20% of the fuel to the
reburn zone", the heat release rate and resulting thermal
NO production are reduced. This effect is most notice-
able in boilers with high burner heat release rates such
as cyclone-fired boilers, and in any type of boiler at high
unit load where the heat release rate is at its peak.
Lower Nitrogen Content of Reburn Fuel
The reburn fuel need not be the same as the fuel used in
the primary combustion zone, although coal-fired reburn
is under active evaluation at several installations and
has been demonstrated at the Wisconsin Power & Light
Company's Nelson Dewey Unit 2 (see Section 3) (Yagiela
et al., 1991). To date, natural gas has been most fre-
17
-------
quently used as a reburn fuel for retrofit applications to
coal-fired boilers. One major advantage of natural gas
as a reburn fuel is that it has no significant nitrogen con-
tent. Fuel oil (especially distillate oil) also has a lower
nitrogen content than coal, but to date has not been stud-
ied extensively as a reburn fuel. Because of the reduced
nitrogen contents, substituting either natural gas or dis-
tillate fuel oil for a portion of the fuel input from coal (also
called "co-firing") results in a proportional reduction in
fuel NOx emissions.
Operational Parameters
Operational parameters are those factors related to
implementing the reburn N0x control theory into an op-
erational system. The most significant operational pa-
rameters that affect the performance of a reburn system
are:
Reburn fuel type;
Flue gas recirculation (FGR);
Fuel/O2 stoichiometry;
Reburn zone residence time and temperature; and
Controls and instrumentation.
Reburn Fuels
Theoretically, the reburn fuel can be any of three basic
fossil fuel types: coal, natural gas, or oil, without regard
to the type of primary boiler fuel being fired. However,
as stated earlier, use of a fuel with a low nitrogen con-
tent is advantageous in minimizing fuel NOx generation.
Natural Gas
Natural gas is typically the most attractive reburn fuel
because it is effectively nitrogen-free and, therefore, pro-
vides a greater potential NOX reduction than a reburn
fuel with a higher nitrogen content. The replacement of
10 to 20% of the fuel input to the boiler with a nitrogen-
free fuel results in a comparable reduction in the fuel-
bound nitrogen component of the total boiler NOX emis-
sions. Natural gas also reacts very rapidly in the reburn
zone compared to the alternative fuels. However, be-
cause of the relatively lower mass of natural gas, achiev-
ing good mixing of it with the flue gas in the reburn zone
is difficult. For this reason, a carrier gas such as recircu-
lated flue gas is often used to enhance mixing while main-
taining a low O2 stoichiometry.
If it is already present onsite, natural gas is the most
logical reburn fuel for existing gas-fired boilers. The rela-
tive ease of handling natural gas and installing gas-fired
reburn injectors make this an obvious candidate for boil-
ers burning other primary fuels as well. Natural gas must
be supplied via pipeline and many plants with coal-fired
or oil-fired boilers utilize natural gas as an ignition or
startup fuel, space heating, or for firing other units. How-
ever, if natural gas is not available onsite or not avail-
able in sufficient quantity, the cost of installing a new
gas pipeline for the purpose of supplying a reburn fuel
may be economically prohibitive. Even if natural gas is
already available, the cost of natural gas may be higher
than alternative fuels on a per energy unit basis. In these
cases, an alternative reburn fuel must be evaluated.
Coal
Coal has a higher fuel-bound nitrogen level content than
natural gas but is the primary fuel at a very large num-
ber of utility boilers. Pulverized coal also has the lowest
cost per million Btu of any of the available reburn fuels
and mixes well with the flue gas in the reburn zone. Vola-
tile coals are more effective as a reburn fuel than low-
volatile coals.
While coal may seem an obvious selection, especially
at coal-fired boilers, the use of coal as a reburn fuel may
have some significant disadvantages. The use of coal
can be difficult if the routing of coal supply pipes to the
reburn zone is restricted by work space constraints and/
or maximum fuel flow rates would be exceeded. The coal
particle size must be minimized to achieve rapid com-
bustion in the reburn zone. Some boilers, such as cy-
clone-fired boilers, would require the addition of coal
pulverizers for the reburn fuel. Firing with pulverized coal
also requires the use of a carrier medium, which is typi-
cally heated air. This conflicts with optimizing NOX re-
ductions in the reburn zone which are achieved by mini-
mizing oxygen concentrations in this zone. Oxygen con-
centrations could be minimized by utilizing FGR instead
of air as a carrier gas for coal-firing in the reburn zone.
The additional costs associated with using FGR as a
carrier medium are discussed in a later section.
Fuel Oil
Fuel oil also has a higher fuel-bound nitrogen level than
natural gas but is available at a very large number of
utility boilers. Distillate fuel oil is more desirable than
heavy fuel oil since it has a lower fuel-bound nitrogen
content. Many coal-fired boilers have fuel oil available
as a supplemental or startup fuel. No full-scale utility
demonstration of NOx emission control by reburn using
fuel oil has been performed as of the writing of this docu-
ment.
Flue Gas Recirculation
Flue gas taken from just ahead of the air heater may be
injected into the reburn zone in conjunction with the
reburn fuel. The recirculated flue gas, in lieu of combus-
tion air, can be utilized as a carrier medium for the reburn
fuel to increase the penetration and mixing of the reburn
18
-------
fuel in the boiler and to cool the reburn fuel injectors.
Using FGR in the reburn zone minimizes the oxygen
concentration in the reburn zone of the boiler, which fa-
cilitates the control of O2 levels in the primary combus-
tion and burn-out zones of the boiler. FGR is also a tem-
perature-quenching strategy in which the recirculated flue
gas acts as a thermal diluent to reduce combustion tem-
peratures in the reburn zone.
The use of FGR in a reburn system differs from the tra-
ditional uses of FGR in boilers. In some coal-fired boil-
ers operating at peak boiler capacity, flue gas commonly
is readmitted through the furnace hopper or above the
windbox to control the superheated steam temperature.
However, this method of FGR does not reduce NOx emis-
sions. Windbox FGR has only a minor effect in reducing
thermal NOx and is not effective for NOx emission con-
trol on boilers in which fuel NOx is a major contributor.
The degree of FGR in reburn systems is variable and
depends upon the output limitation of the forced draft
(FD) fan and minimum furnace temperatures. To maxi-
mize NOx reduction, FGR is routed through the windbox
to the reburn injectors, where temperature suppression
can occur within the reburn zone. The effectiveness of
the technique depends on the reburn fuel and flow rate.
When burning heavier fuel oils or coal, less NOX reduc-
tion would be expected than when burning natural gas
because of the higher nitrogen content of the fuel.
Retrofit hardware modifications to implement FGR in-
clude new ductwork, a flue gas recirculation fan, devices
to mix flue gas with combustion air, and associated con-
trols. In addition, the FGR system itself requires a sub-
stantial maintenance program due to the high tempera-
ture environment and erosion from entrained fly ash.
Research and development is underway to determine
the NOx capabilities of reburn without FGR in order to
reduce the capital cost of the plant modifications needed
to implement a reburn system. These efforts are directed
toward improved reburn fuel injection methods.
O2 Stoichiometry
Typically, boilers operate at a furnace O2 Stoichiometry
in the range of 1.2 to 1.3 as measured at the air heater
inlet. This oxygen-rich environment facilitates higher
boiler temperatures and more complete carbon burnout
in the furnace. A major factor in reducing NOx through
reburning is the precise control of stoichiometries at each
stage in a reburn system. While the stoichiometries are
different in each of the combustion zones of a boiler
employing a reburn system, the overall Stoichiometry as
measured at the air heater remains roughly the same.
With implementation of a reburn system, the primary
combustion zone excess air is lowered to the minimum
level required to maintain flame stability. Lower primary
combustion zone stoichiometries minimize the amount
of reburn fuel necessary in the reburn zone to create a
fuel-rich condition. Low excess air in the primary com-
bustion zone also minimizes thermal NOx formation by
lowering the zone temperatures. Tests have shown that
stoichiometries in the primary combustion zone should
be maintained in the range of 1.05 to 1.15.
Considerations that limit the reduction of excess air in
the primary combustion zone include flame stability, fuel
type, burner type, and boiler rating. Primary combustion
flames can become unstable whenever stoichiometries
are lowered. Coal ash fusion temperatures are lower
under reducing (sub-stoichiometric) conditions, and if
combustion temperatures in a dry-bottom boiler falls
below the initial softening temperature of the ash, ex-
cessive slagging or fouling of the furnace walls occurs.
Slagging burners, such as cyclone-fired burners, have
minimum combustion temperature requirements in or-
der to prevent solidification (freezing) of the molten slag
in the burner and lower portion of the furnace. Without
sufficient O2 in the primary combustion zone, slagging
burners are unable to maintain adequate burner tem-
peratures due to incomplete combustion. Each furnace
should conduct a parametric testing program in order to
determine the minimum levels of excess air in the pri-
mary combustion zone required to sustain good boiler
operation.
The reburn zone is designed to operate in a fuel-rich
environment. By injecting the remainder of the fuel input
with little or no additional combustion air, O2 stoichiom-
etries of 0.85 to 0.95 are achievable in this zone. Reburn
fuel flow rates can be affected by constraints in injector
capacity and combustion profiles in the furnace.
The final burnout zone, or completion air zone, receives
the remainder of the combustion air for the furnace. Typi-
cally, O2 stoichiometries in this zone are 1.2 or greater to
facilitate complete carbon burnout. The completion air
flow rate is often dependent on the stoichiometric condi-
tions in the previous two combustion stages.
Residence Time
A controlling factor in reducing NO emissions with reburn
is the flue gas residence time in the reburn and burnout
zones. The reburn fuel and combustion gases from the
primary combustion zone must be mixed thoroughly for
NOx reduction reactions to occur. The furnace size and
geometry determine the placement of reburn injectors
and completion air ports, which will ultimately influence
the residence time in the reburn and burnout zones. The
typical minimum residence times in the reburn and burn-
out zones for a well-mixed boiler is 0.5 second, which is-
dependent on the degree of mixing achieved in these
zones.
19
-------
Temperature
The flue gas temperature in the burnout zone is an im-
portant factor for the regeneration or destruction of NOx
in this area. High flue gas temperature promotes the
conversion of N0x compounds to N2.
Controls and Instruments
Generally the retrofit of a reburn system to an existing
boiler will require some modifications to the boiler con-
trol system. However, investigators have shown that, with
approximate modifications, the control of that reburn sys-
tem can be automated and made fail-safe.
Additional safety sensors are required to monitor the
reburn zone. Safety equipment for burners generally rely
on flame sensing; however, the reburn injectors do not
produce a visible flame because of the low combustion
temperature and limited O2. Natural gas combustion also
does not produce a strong visible flame, which may fur-
ther contribute to the lack of a visible flame in the reburn
zone. Therefore, a reburn safety system consists of a
comprehensive system of permissives and trips.
The permissives are a set of conditions that must be
satisfied for startup and continued operation of the reburn
system. Trips are critical boiler conditions that will trig-
ger a shut-down of the reburn system. Most of the sen-
sors required for the permissive and trip systems gener-
ally are already in place. These sensors monitor fan op-
erating status, boiler pressure, and primary combustion
flame. Some temperature sensors may need to be added
to the reburn zone. Boiler insurance companies have
reviewed this safety system and have determined it to
be acceptable.
Potential Application Problems
Boiler manufactures rely on a vast body of design data
in the design of a coal-fired boiler. Many interrelated pro-
cess factors must be weighed in arriving at an optimum
boiler design for a given fuel and set of operating char-
acteristics. Existing boilers generally were not designed
with the anticipation of a future reburn system installa-
tion. As a result, the application of NOx emission control
through reburn presents some characteristic problems
that must be considered and overcome. The problems
include the following:
Fuel combustion problems;
Boiler operating problems;
Reburn fuel availability and cost;
Physical constraints;
Paniculate control device problems; and
Unit inflexibility.
While many of these concerns are present primarily in
retrofit application of reburn technology, they must also
be addressed in any application to a new boiler.
Fuel Combustion Problems
The existing configuration, spacing, and location of fuel
burners were designed by the boiler manufacturer to
optimize the efficiency of converting a fossil fuel's chemi-
cal energy into usable thermal energy in the steam. The
process changes required by the installation of a reburn
system can affect the thermal efficiency of the boiler by
affecting the combustion characteristics of the fuel in a
boiler. The thermal efficiency of fuel combustion can be
measured by several parameters including unburned
carbon in the fly ash (coal-fired boilers), hydrocarbon
levels in the flue gas (oil and gas-fired boilers), and the
carbon monoxide (CO) level in the flue gas. If insuffi-
cient CX, is added in the burnout region of the boiler or if
insufficient time is available for the completion of com-
bustion, the levels of these parameters would rise. This
rise would represent a loss of thermal efficiency in the
boiler and necessitate increased operating costs.
Boiler Operating Problems
In addition to loss of thermal efficiency, the boiler may
experience other operating problems including the fol-
lowing:
Steam temperature control problems;
Increased fly ash production in slagging boilers;
Boiler tube corrosion;
Increased boiler tube slagging and fouling; and
Slag tapping problems.
The following is a brief overview of the characteristics of
these problems and some of the steps that can be taken
to mitigate them.
Steam Temperature Control Problems
The design of the heat transfer surfaces and of their lo-
cations in a boiler (tube walls, superheaters, and
reheaters) are based on specific conditions in the boiler
such as radiation, convection, and conduction from the
primary combustion flame and hot flue gas. The installa-
tion of a reburn system can result in a major change in
these conditions.
20
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For example, diversion of 10 to 20% of the fuel from the
main combustion zone to the reburn zone reduces the
amount of heat transfer in the lower portion of the boiler
and increases the amount of heat transfer in the upper
portion. The ratio of heat transfer by radiation and con-
vection can change as well. Less heat will be transferred
to the boiler wall tubes while more heat will be trans-
ferred in the superheat and reheat areas. This results in
changes to the superheater and reheater attemperator
flows and may destabilize steam temperature control in
the boiler.
Increased Fly Ash Production
Increased fly ash production is a particular problem for
slagging boilers such as cyclone-fired boilers that use
coal as the reburn fuel. Typically, only 20% of the coal
ash from a cyclone-fired boiler leaves the boiler as fly
ash. The rest is collected as slag in the bottom of the
boiler. The diversion of coal from the cyclone burners to
the reburn injectors results in the production of a higher
percentage of fly ash. This fly ash will increase the ero-
sion of tubes in the convection passes of the boiler and
of the air heater surfaces. It also increases the fly ash
load on the particulate control device, as discussed later.
Boiler Tube Corrosion
Waterwall tubes and superheater/reheater tubes may
experience increased erosion and corrosion for reasons
similar to those identified for steam control problems.
Reducing conditions in the reburn zone can increase
wastage or corrosion of tubes in this area. Extensive
measurements of furnace tube wall conditions before and
after reburn operation at Ohio Edison's Miles Unit 1 (114
MW, cyclone-fired boiler) and at Illinois Power Company's
Hennepin Unit 1 (71 MW, tangentially-fired boiler) have
shown tube wastage to be within normal ranges; how-
ever this issue is repeatedly raised.
Current theory holds that the tube wastage in reducing
zone of coal-fired boilers is principally due to hydrogen
sulfide (H2S) attack from organic sulfur in the coal. In
reburn, the coal is burned in a net-oxidizing atmosphere
and all of the sulfur is oxidized. If low-sulfur fuel oil or
natural gas is used as the reburn fuel, little or no sulfur is
available to form H2S in the reburn (substoichiometric)
zone. In test at the two units identified above, the com-
bustion products near the furnace wall were tested and
no H2S was found.
Increased Boiler Tube Slagging and Fouling
Increased flue gas temperatures in the convection
passes, operation in reducing (substoichiometric) con-
ditions, and increased fly ash production are all factors
contributing to increased boiler tube slagging and foul-
ing conditions. Ash will adhere to boiler tube surfaces if
its temperature is above the ash softening temperature.
As stated earlier, the ash softening temperature is a func-
tion of the ash chemical composition and is lower under
the reducing conditions found in the reburn zone.
In a dry-bottom boiler, oxidizing (above stoichiometric)
conditions and temperatures below the ash softening
temperature are maintained at the boiler walls and in
the convection passes to minimize slagging and fouling.
Ash which does accumulate in these areas is removed
with soot blowers. The reducing conditions in the reburn
zone and the completion of combustion later in the boiler
could result in slagging and fouling too severe for soot
blowers to handle. The potential problem of tube slagging
and fouling may occur in the convection passes of wet-
bottom boilers as well.
While these problems remain a possibility, the tests de-
scribed in Section 3, which were conducted on full-scale
boilers, reported no discernable increase in slagging
during reburn operation.
Slag Tapping Problems
In a wet bottom boiler, the temperatures in the lower fur-
nace must be maintained above the ash melting tem-
perature so that the ash can be collected as a molten
slag. Reduced temperatures in the lower furnace can
cause the slag to solidify before it can be removed. This
problem can be compounded at reduced furnace loads
when gas temperatures in the boiler are already reduced.
The combination of lower excess air and diversion of a
portion of the fuel to higher in the boiler can reduce the
primary combustion temperatures which in turn can re-
sult in slag solidification. Generally, slag tap plugging
results in a lengthy unit outage to remove the pluggage.
While such changes in slag behavior are possible, ad-
equate slag fluidity was maintained during the full-scale
tests on cyclone-fired boilers at Miles Unit 1 and at City
Water, Light, and Power's Lakeside Unit 7. These tests
are summarized in Section 3.
Reburn Fuel Availability and Cost
Typically, natural gas is economically feasible as a reburn
fuel only at facilities that either already have a sufficient
natural gas supply at the site or have a gas pipeline in
very close proximity. In comparison with other NOx con-
trol alternatives, the incremental cost of utilizing a natu-
ral gas-fired reburn system can be unfavorable unless
one of these situations exist. Also, natural gas prices
and availability are seasonally dependent, with higher
costs and more restricted availability occurring during
the winter months. However, NOX control for ozone pre-
cursors may also be seasonally dependent, with the high-
est level of control needed during the summer months.
To determine the economic feasibility of natural gas as a
reburn fuel, the potential user must discuss annual prices
and availability with the local natural gas supplier.
21
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Limited testing has occurred with coal as a reburn fuel;
however implementation of a reburn retrofit does not af-
fect the total quantity of coal fired significantly, only its
distribution in the furnace. If coal is used as the reburn
fuel, in some cases, reburning will require a finer coal
particle size than produced by the existing coal prepara-
tion equipment. The fine coal particle size is required to
ensure complete fuel combustion during the limited flue
gas residence time available in the reburn and burnout
zones. This could require additional capital cost for the
installation of new or additional pulverizers.
Physical Constraints
While not many limitations exist on the installation of the
equipment needed for retrofitting a reburn system on a
coal-fired boiler, some physical constraints do exist, in-
cluding:
Sufficient boiler height for installation of the needed
reburn injectors and completion air ports and for ad-
equate flue gas residence time in the reburn and
burnout zones;
Sufficient room around the boiler for routing of reburn
fuel lines, combustion air lines, reburn injectors, flue
gas recirculation fans and ducts (if required), and
other auxiliary equipment; and
Soot blowers capable of handling increased boiler
tube slagging and fouling.
Such physical constraints must be identified and quanti-
fied early in evaluating the feasibility of retrofitting a
reburn system on an existing boiler.
Particulate Control Device Constraints
The production of sulfur trioxide (SO ) during combus-
tion of coal is a major contributor to the conductivity of
the fly ash. When a lower sulfur fuel such as natural gas
is used as the reburn fuel, less SO3 is produced and the
resistivity of the fly ash produced generally will increase.
This increase may result in reduced particulate collec-
tion efficiency in an electrostatic precipitator. Offsetting
this effect is the reduction in ash resistivity resulting from
the higher moisture content of the flue gas produced by
combustion of natural gas. The magnitude of each ef-
fect depends on several factors including the sulfur con-
tent of the coal and the amount of reburn fuel as a frac-
tion of the total fuel input. Therefore, predicting the over-
all effect on ash resistivity that would result from a natu-
ral gas-fired reburn system is difficult prior to pilot test-
ing. However, data from the full-scale, gas-fired reburn
tests reported in Section 3 showed precipitator perfor-
mance was maintained throughout the test programs.
Thus coal-fired reburn systems, a larger percentage of
the total ash production of the boiler may leave the boiler
as fly ash. This may be especially true for slagging boil-
ers since they typically produce a relatively smaller
amount of fly ash than dry-bottom boilers. The additional
fly ash generation presents an increased load on the
particulate control device (electrostatic precipitators or
fabric filters). Modification of the particulate control de-
vice may be necessary to maintain the particulate emis-
sions and stack opacity within permit limits. Likewise,
the increased volume of fly ash collected may require
modification of the fly ash handling equipment.
Boiler Safety
Current boiler safety equipment relies heavily on flame
sensing to automatically cut off fuel flow when critical
conditions occur in a boiler. Reburn fuel injectors do not
introduce combustion air, which eliminates the stable
visible flames that are present with the primary combus-
tion zone burners. Pulverized coal-fired reburning might
utilize air injection as a carrier media for the coal, which
may or may not produce a stable visible flame. A system
of "trips and permissives," as was discussed earlier, is
necessary to ensure safety in the reburn zone.
Load Dispatch Range
The boiler's operating load cycle is a major operating
parameter that affects the overall reduction of NOx emis-
sions resulting from installation of a reburn system. Gen-
erally, reburn systems operate more stably and achieve
greater NOx reductions at higher load conditions. Typi-
cally, utility boilers do not operate at peak loads con-
stantly. Loads vary in accordance with electrical demand.
The diversion of 10 to 20% of the fuel from the lower
furnace to the reburn injectors can result in flame insta-
bility and an increase in the unburned carbon content of
the ash. Wet-bottomed boilers will have minimum tem-
perature constraints based on ash fusion temperatures
that may limit the use of the reburn system at reduced
loads. At low loads, the amount of reburn fuel injected
may also be reduced, which could impede fuel/flue gas
mixing at the lower reburn fuel velocity and momentum.
Factors such as these may limit the turndown range of
the boiler or the applicability of reburn for controlling NOx
emissions. Automation of the reburn system controls*
primary fuel choice (based on ash fusion temperature),
and operation with burners out of service (BOOS) can
minimize the problems associated with boiler load swings
and low-load operation.
During the full-scale demonstration tests of reburning
discussed in Section 3, the utilities' boiler operators have
been able to find safe and acceptable boiler control con-
ditions throughout the load ranges tested.
22
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Ancillary Benefits
The installation and operation of a natural gas-fired
reburn system for NOx control has some ancillary ben-
efits in addition to NOX reductions including:
Reduced emissions of acid gases (SO2 and HCI);
Reduced emissions of carbon dioxide;
Reduced fly ash loading on the particulate control
device; and
Reduced production of ash for disposal.
In comparison with coal, natural gas contains negligible
quantities of nitrogen, chlorine, and sulfur, reduced car-
bon content, and reduced incombustible material (ash).
Therefore, the replacement of 10 to 20% of the total heat
input to the boiler by natural gas would achieve a pro-
portional reduction in the emissions of pollutants related
to these fuel components regardless of whether a reburn
system is utilized.
In addition to the environmental aspects of reducing these
constituents, the reduction in fly ash content of the flue
gas leaving the boiler would reduce the load on the par-
ticulate control device, the erosion of boiler tubes and
air heater elements, and the power consumption of coal
handling and preparation equipment.
23
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Chapter 3
Example Full-Scale Demonstrations
Introduction
This chapter contains five examples of full-scale dem-
onstrations of reburning to control NO emissions from
utility boilers. Including both U.S. and foreign installa-
tions, the examples cover a wide range of boiler designs
and sizes, and two reburn fuels: natural gas and coal.
The design parameters for the example applications are
summarized in Table 3-1.
Public Service of Colorado - Cherokee
Units
Public Service of Colorado's Cherokee Unit 3 is the site
of a Round 3, Clean Coal Technology Project sponsored
by the DOE, the GRI, Colorado Interstate Gas, the EPRI,
and EER. The project sponsors tested the effectiveness
of LNBs and LNBs combined with natural gas-fired
reburning (LNB gas reburn) retrofit technologies in re-
ducing NOX emissions on a wall-fired boiler. The project
objective was to demonstrate that the combination of
gas reburning and LNB would achieve 70 to 75% NOx
reduction. Parametric testing was completed in 1993 and
the unit is currently undergoing long-term testing. The
information presented in this report on the testing at
Cherokee Unit 3 was compiled from papers titled "Low
NOx Burners & Gas Reburning -An Integrated Advanced
NO Reduction Technology" (Sanyal et al., 1993) and
"NO Control by Gas Reburning in a 172 MWe Boiler"
(Rindahl et al., 1994).
The Unit 3 boiler is a balanced draft, 172-MW, front wall-
fired unit that typically burns Colorado, low-sulfur (-0.4%
S), subbituminous coal. Three other units are at the
Cherokee Station. The capacity factors of the four units
and swing-load conditions allowed a wide range of op-
erating conditions to be tested. Originally equipped with
Table 3-1. Summary of Example Reburn Installations
Utility Unit Name Unit Size
Boiler Type
Primary Fuel
Springfield, IL
City Water, Light
& Power
Lakeside Unit 7
Wisconsin Power & Nelson Dewey Unit 2
Light Co
33 MW Single-wall cyclone,
wet bottom
100 MW Single-wall cyclone,
wet bottom
Medium sulfur, Illinois
bituminous coal
Reburn Fuel
Public Service
of Colorado
Illinois Power Co
Cherokee Unit 3
Hennepin Unit 1
172MW
71 MW
Single-wall-fired,
dry bottom
Tangentially-fired,
dry bottom
Western U.S., low sulfur,
subbituminous coal
High sulfur, Illinois
bituminous coal and
and natural gas
Natural gas
Natural gas
Natural gas
Medium sulfur, Illinois Pulverized Coal
bituminous coal and Powder
River Basin subbituminous
coal
Ohio Edison
Vinnitsaenergo,
Ukraine
Niles Unit 1
Ladyzhin Unit 4
114 MW
300 MW
Single-wall cyclone,
wet bottom
Opposed-wall-fired,
wet bottom
Eastern U.S. bituminous
coal
Ukrainian bituminous coal,
and Siberian lignite and
natural gas
Natural gas
Natural gas
25
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Babcock & Wilcox (B&W) circular-type PL burners in a
four-by-four array, Unit 3 had a total design heat input of
1650 million Btu per hour (MMBtu/hr). The air pollution
control equipment included a baghouse for particulate
emissions control.
Sixteen Foster Wheeler, Internal Fuel Staging, LNBs
replaced the original burners for the project. The boiler
had a full division wall and a radiant zone of 24 ft deep
and 42 ft wide. A schematic of the LNB-gas reburn sys-
tem tested is shown in Figure 3-1.
The LNB-gas reburn system involved a 3-stage burning
process at various stoichiometries with the first zone as
the primary burner zone. This zone was operated at 80
to 90% of the total heat input, with minimized excess air.
Approximately 2.4 m above this zone, eight 14-cm di-
ameter natural gas injectors were installed for the
reburning zone. Natural gas was injected through nozzles
with 3.4% of the flue gas recycled to facilitate adequate
mixing, cool the natural gas injectors, and disperse the
reburn fuel. The stoichiometry in the boiler becomes fuel-
rich at this point. Nozzle velocities ranged from 27.5 m/s
at 50% load to 55 m/s at full load. The flow rates of the
reburn fuel ranged from 10 to 25% of the total heat input
of Unit 3. The final zone was a burnout zone, with six 52-
cm diameter injectors for OFA. The OFA injectors were
tilted 10 degrees down to facilitate dispersion and mix-
ing. The design of the OFA system facilitated carbon
burnout in an air-rich environment.
I
8 Gas Reburning
Injectors
Burnout
Zone
(SR3)
10'
5.5m
6 Overfire Air
Injectors
2.4m
8 Gas Reburning
Injectors
16LowNO}
Burners
Figure 3-1. Cherokee Unit 3-LNB-Gas Reburn System Schematic (Sanyal et al., 1993).
26
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Parametric tests were used to evaluate emission reduc-
tion sensitivity to operating parameters including zone
stoichiometries, gas flow rate, OFA flow rate, flue gas
recirculation rate, and load. Absolute NO emissions were
measured for each firing configuration (Figure 3-2). The
use of LNBs alone produced NOX emission reductions
of 31 % from the baseline. The minimum NO emissions
with LNB-gas reburn corresponded to reductions of 72%
from baseline and 60% reduction from LNBs alone.
NOx emissions increased linearly with increasing zone
stoichiometry, with slopes varying for each case (Figure
3-3). The LNB-gas reburn tests operated at a much lower
percentage of theoretical air than the baseline and LNB
tests, resulting in lower NOX emissions. The stoichiom-
etry target for the baseline and LNB cases was an over-
all stoichiometry, while for the reburn case it was the
LNB-gas reburn zone stoichiometry. The baseline and
LNB data were obtained at about 20% excess air (120%
theoretical air). For LNB-gas reburn, the minimum NO
level occurs at a reburning zone stoichiometry of 88%
theoretical air. At this point, the reburn fuel firing rate
was 20% of the total heat input to the boiler, and the
overall stoichiometry was normal.
The parametric tests showed that overall excess air could
be lower in the LNB-gas reburn cases than in either the
baseline or the LNB cases, as seen in Figure 3-4 (Sanyal
et al., 1993). Slagging, carbon loss, and corrosion were
expected unless the stoichiometry in the primary burner
zone (designated as SR, in Figure 3-1) was maintained
above 1.05. This was accomplished by adjusting the sto-
ichiometry in the reburn zone (SR2) and the reburn fuel
input (Rindahl et al., 1994).
In all cases, NOx emissions had a linear correlation with
oxygen content. Note that the sensitivity to oxygen con-
tent decreased for both the LNB and LNB-gas reburn
cases, with LNB-gas reburn exhibiting the lowest sensi-
tivity. Minimum NOX emissions were achieved at a reburn
zone stoichiometry of 0.88 and overall stoichiometry in
the range of 1.2 to 1.3 (Sanyal et al., 1993).
0.8
CQ
2
S
o
0.6
0.4
0.2
Baseline
LNB
Firing Configuration
GR-LNB
Figure 3-2. Cherokee Unit 3-Short-Term NOt Emission Data (Sanyal et al., 1993).
27
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X
o
0.8
0.6
0.4
0.2
I
Cherokee Station Unit #3
147-152 MW Net
Baseline (Pre-LNB)
D
LNB
LNB-Gas Reburn
16-23% Gas
" i i i i I i i i i I i i i i I i i i i I i i i i I
80 90 100 110 120 130
Zone Stoichiometry (% of theoretical air)
430
344
258
172
86
x
O
140
Figure 3-3. Cherokee Unit 3-LNB-Gas Reburning Data (Sanyal et a/., 1993).
28
-------
0.8
0.6
ffi
X
O
0.4
0.2
Cherokee Station Unit #3
147-152 MW Net
I I I I
Baseline (Pre-LNB)
p
LNB
LNB-Gas Reburn
16-23% Gas
I
I i I
I i
430
344
258
172
86
X
O
1234
O2 Dry at Boiler Exit (%)
Figure 3-4. Cherokee Unit 3-Effect of Excess Air on NOt Emissions (Sanyal et al., 1993).
In general, NOX emissions decreased with increasing gas
heat input. The greatest incremental reductions in NO
emissions occurred at natural gas input values up to 10%
of the total fuel input to the boiler. With 10 to 20% input
from natural gas, the additional reductions in NO,, emis-
sions were marginal. The correlation between natural
gas input and NOX emissions is shown in Figure 3-5.
Natural gas also reduced SO2 and CO emissions. With
the low-sulfur coal typically used at Cherokee, typical
SO emissions are 0.65 Ib/MMBtu. A gas heat input of
20%, resulted in a SO2 emissions decrease of 20% to
0.52 Ib/MMBtu, as expected by fuel substitution with
natural gas essentially free from sulfur. CO2 emissions
also are reduced because natural gas has a lower car-
bon/hydrogen ratio than coal. At a gas heat input of 20%,
the CO2 emission was reduced by 8% (Rindahl 1994).
A linear correlation was observed between unit load and
NOx emissions for all three cases (Figure 3-6). Again the
sensitivity appeared to decrease in the LNB and LNB-
gas reburn configurations, with LNB-gas reburn show-
ing the lowest sensitivity to unit load.
Overall, the parametric tests did not reveal any prob-
lems with the reburn retrofit. Even though carbon loss,
flame stability, ash fusion temperature, and steam tem-
perature control are parameters that are dependent on
the overall excess air, the short-term tests at Cherokee
Unit 3 demonstrated that these parameters were not
adversely affected by the LNB-gas reburn retrofit.
One concern in retrofitting the LNB-gas reburn system
was boiler derating. Boiler heat rate is dependent on
carbon loss, auxiliary power needs, dry gas loss as a
result of excess air and temperature, and latent heat loss
through additional water vapor in the flue gas. Due to
the higher hydrogen content in natural gas, its combus-
tion generates more water vapor than coal combustion
for the same heat input.
Carbon and dry gas losses were unchanged as a result
of the testing. A minimal increase in auxiliary power oc-
curred; however, this was offset by the reduced coal mill
power consumption due to reduced coal throughput. The
station staff predicted that there would be no net change
in power needs. Boiler efficiency for 20% natural gas
29
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1
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
Baseline
150 MW, 3.4 - 3.8% 02 ; SR = 1.01 -1.20
I .... I i i i . I .... I .
0 5 10 15
Gas Input (%)
Figure 3-5. Cherokee Unit 3-Effect of Gas Input on NO, Emissions (Sanyal et at., 1993).
20
344
301
258
215
172
129
86
43
25
X
O
30
-------
0.8
S
2
X
O
0.6
0.4
0.2
1 I ' ' ' ' I ' ' ' ' I ' ' ' '-
Cherokee Station Unit #3
3.4-4.1% Qz
Baseline (Pre-LNB)
a
i.... i....i
LNB-Gas Reburn
I . t . i I i i i i I i i i i
430
344
258
172
86
x
O
80 90 100 110 120 130
Load (MW)
140
150
160
Figure 3-6. Cherokee Unit 3-Effect of Unit Load on NOt Emissions (Sanyal et ai., 1993).
firing was reduced by about 1 % due to the latent heat of
the additional flue gas moisture while the steam tem-
perature was maintained through attemperation.
Long-term testing started in April 1993. The objective of
the testing is to obtain operating data over an extended
period of time when the unit is under routine commercial
service. The long-term NO, data obtained in the first nine
months of operation are shown in Figure 3-7. The op-
eration was load-following and operated under the fol-
lowing conditions:
82 to 159 MW net unit load;
5 to 19% gas heat input; and
2 to 6% dry O2 concentrations.
The average NOX concentration during the gas reburning-
LNB operation was 0.26 Ib/MMBtu, compared to 0.5 Ib/
MMBtu as the standard emission limit for dry bottom wall-
fired boilers (Rindahl 1994).
The gas reburning system on Cherokee Unit 3 has been
modified to eliminate flue gas recirculation to reduce
system complexity, lower furnace exit temperature, re-
duce operating cost, and reduce slagging. Thd OFA ports
have been modified to optimize overfire air at low gas
inputs. Additional tests will be conducted to verify the
performance of the modified system. A final report on all
testing is expected in early 1997.
Illinois Power Company - Hennepin Unit 1
Hennepin Unit 1 is a Combustion Engineering, tangen-
tially-fired, balanced draft, single furnace boiler with a
capacity of 71 MW. The unit is capable of achieving full
load on either coal or natural gas. Unit 1 was the site of
a Round 1, Clean Coal Technology Project sponsored
by DOE, GRI, the Illinois Department of the Environment
and Natural Resources, and EER. The objective of this
project was to test the NOX reducing efficiencies of sev-
eral retrofit technologies including:
Natural gas as a reburn fuel (both with coal and natu-
ral gas as the primary fuel);
Bias coal/natural gas firing;
31
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0.8
0.7
0.6
As found NOX Full load @ 3.5% excess O.
Average GR-LNB NOX 0.26 lb/106 Btu
82-159 MWe Net, 5-19% Gas, 2-6% O2
i n ii i nim n I nil ii n i nil II M i nun ii iiiiiiiiiini ii MI i li
Date
Apr 27, 1993
Jan 20,1994
Figure 3-7. Cherokee Unit 3-Long-Term NOt Emission Data (Sanyal et al., 1993).
Coal/gas co-firing; and
Gas reburn combined with sorbent injection to re-
duce SO2 emissions on coal-fired boilers.
The full test matrix also consisted of several baseline
performance tests for coal, gas, coal/gas co-firing, burner
turndown, and coal mill turndown. Parameters were de-
veloped from pilot-scale tests.
The burner arrangement for the Hennepin boiler is typi-
cal of many tangentially-fired boilers. Fuel and air are
admitted from the furnace corners in horizontal layers.
In each corner of the furnace are three pulverized coal
burners and two gas burners in an alternating stack (Fig-
ure 3-8), with the air distribution being controlled by
dampers at each compartment. This stacked arrange-
ment allows for various configurations of fuel choice (pul-
verized coal or natural gas) and staged combustion. Each
of the corners has two levels of natural gas-fired igniters
and warm-up guns capable of supplying 1% and 5% of
the heat input, respectively (Angello et al., 1992).
Historically, the unit has burned Illinois bituminous coal
that was moderately high in sulfur (3% S), with 10% ash,
15% moisture, and a heating value of approximately
10,600 Btu/lb. Fuel analyses comparing the design fuel
characteristics with pre- and post-testing averages are
presented in Table 3-2 (Angello et al., 1992).
Bench- and pilot-scale studies were conducted to de-
velop fuel compositions and operating parameters, as
well as to evaluate their potential effectiveness in reduc-
ing NOx emissions. These studies showed that major
parameters of interest included oxygen stoichiometries,
furnace gas temperatures, furnace residence times, and
fuel/air mixing. Natural gas was reported as the most
effective reburn fuel, with respect to low baseline levels
of NOx and limited residence time in the reburn zone.
Parametric testing began in 1991 with natural gas as
well as coal for primary combustion fuels. The informa-
tion presented in this section is the result of the para-
metric testing conducted with coal as a primary com-
bustion fuel. Data on natural gas as the primary com-
bustion fuel is also available (May et al., 1994).
Baseline, uncontrolled NOx emissions firing 100% coal
were approximately 550 ppm (0.75 Ib/MMBtu). Under
optimum conditions for NOx control, emissions were re-
duced by as much as 77%"from the coal-fired baseline.
A graph of NOx emissions and reduction versus the per-
centage of gas heat input is shown in Figure 3-9 at the
conditions that produced the best balance of performance
for commercial operation. Gas reburning with 18% gas
firing reduced NOx emissions by 60 to 70% down to 0.23
to 0.30 Ib/MMBtu. Even with only 10% gas firing, emis-
sions were reduced by 55% to 0.34 Ib/MMBtu (Folsom
etal., 1993).
32
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Main Gas Burner and
Warm-up Guns
Coal Burner
Ignitor, Gas
Coal Burner
Main Gas Burner and
Warm-up Guns
Ignitor, Gas
Coal Burner
Figure 3-8. Hennepin Unit 1-Stacked Burners of Tangentially-Fired Boiler (Angello et at., 1992).
The data from parametric testing were analyzed to de-
termine the optimum operating conditions for achieving
the target emissions. Several parameters were estab-
lished and the nominal operating conditions for long-term
testing were:
Coal zone stoichiometric ratio = 1.10;
Reburning zone stoichiometric ratio = 0.90;
Burnout zone stoichiometric ratio = 1.20; and
Gas heat input = 18% (Keen et al., 1993).
Long-term tests were conducted in 1992, during normal
commercial service. The unit was load-cycled daily, pro-
viding a particularly severe test of the process. NOx emis-
sions measured from January 1992 to October 1992 (no
tests in May or June) showed an average reduction of
67.3% to 0.245 Ib/MMBtu (Figure 3-10) (Folsom et al.,
1993).
A significant reduction in CO2 emissions was also mea-
sured, due to partial replacement of coal with natural
gas. The use of 18% natural gas resulted in a theoreti-
cal CO2 emissions reduction of 7.9% from the coal-fired
baseline (Keen et al., 1993).
The effect of gas reburning on the durability of the unit
was also evaluated during the long-term test. As de-
scribed earlier, the reburning zone operates in oxygen
deficient conditions, raising concerns that tube wastage
might be accelerated due to the presence of reduced
sulfur species or fluctuating oxidizing and reducing con-
ditions. Durability evaluations were conducted through-
out the test program, including both baseline and gas
reburn-sorbent injection (GR-SI) operating periods. The
33
-------
Table 3-2. Hennepin Unit 1 - Fuel Analysis Comparison
Parameter
Units
Original
Design
Pre-Test
Average
Post-Test
Average
Coal
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Moisture
Ash
HHV
Theoretical
Air Demand
%
%
%
%
%
%
%
Btu/lb
Ib air/
Ibcoal
59.16
3.97
7.46
1.04
2.82
15.99
9.56
10,632
7.999
63.14
4.28
8.50
1.21
3.05
9.06
10.76
11,353
8.510
58.52
4.06
7.65
1.11
2.97
15.07
10.18
10,583
7.955
Natural Gas
CH4
C2H6
C3H8
C4H10
C5H12
-------
0.8
0.6 -
|
O
0.4 -
0.2 -
8 12
Gas Heat (%)
- 20
#
40 7T
o
o
-------
Overfire
Air
Natural Gas
15-25% of _
Total Heat Input
Primary
Combustion
Zone
Burnout
Zone
Reburn
Zone
Sorbent
Combustion Air
Coal
75-85% of
Total Heat Input
Figure 3-11. Lakeside Unit 7-GR-SI System Schematic (Folsom era/., 1994).
Optimum NOX reduction was achieved at a reburn fuel
input level of 22 to 23% and reburn zone stoichiometries
between 0.90 and 0.92, as shown in Figures 3-12 and
3-13 (Folsom, 1994). The optimum NO^ reduction var-
ied between 55 and 62% depending on unit load. At all
unit loads, a reburn fuel heat input fraction of 20% or
greater resulted in NO emissions of less than 0.4 Ib/
MMBtu.
As a result of the testing, a lower limit on burnout zone
stoichiometry of 1.30 was established. Under some op-
erating conditions, burnout zone stoichiometries lower
than 1.30 resulted in flue gas CO levels exceeding 200
ppm, indicating incomplete combustion.
FOR was used to enhance the mixing of the reburn fuel
with the flue gas in the reburn zone. Within the range
tested, increasing the FGR rate improved the reduction
of NOx as shown in Figure 3-14 (Folsom, 1994).
The reburning optimization parametric testing was fol-
lowed by a series of sorbent injection parametric tests
designed to determine the optimum reagent ratio and
sorbent injection velocity. At the conclusion of these tests,
the GR-SI optimization tests were conducted to integrate
the two technologies. One modification to the initial reburn
system implemented during these tests was the replace-
ment of the fuel nozzles used in the parametric tests
with smaller nozzles. These smaller nozzles increased
36
-------
1 2 . . __
1>£ IIII IIII IIII IIII IIII IT
33 MW
-0- 25 MW
A- 20 MW
0.0 5.0 10.0 15.0 20.0 25.0 30.0
Gas Heat Input (Percent)
Figure 3-12. Lakeside Unit 7-Effect of Gas Heat Input on NO Emissions (Folsom et a/., 1994).
13
m
O
-S- 33 MW
-O- 25 MW
20 MW
0.0 I'll I I I I I I I I I I I I
Reburn Zone Stoichiometry
Figure 3-13. Lakeside Unit 7-Effect of Reburn Zone Stoichiometry on NOM Emissions (Folsom et al, 1994).
37
-------
m
§
1.2
1.0
0.8
0.6
0.4
0.2
0.0
lilt
_
m
1 1 1 1
1 1 1
1 1 1 1
1 1 1 1
D 33 MW, 23-25% Gas, SR1 =1 .1 5
O 25 MW, 22-25% Gas, SR1 =1 .1 3
A 20 MW, 22-25% Gas, SR1=1.13
-x
nrsa©
TJ^3
1 1 1 1
">
1 1 1 1
^
1 1 1 1
1 1 1 1
-1.18
-1.18
-1.18
-
1 1 1 1
0.0 2.5 5.0 7.5 10.0 12.5 15.0
Flue Gas Recirculation, %
Figure 3-14. Lakeside Unit 7-Effect of Flue Gas Recirculation on NOx Emissions (Folsom et al., 1994).
38
-------
the reburning; fuel penetration into the boiler and im-
proved the mixing of the fuel with the primary combus-
tion zone products. The decreased nozzle diameter re-
sulted in an additional 3 to 5 % reduction in NOx emis-
sions at all unit loads.
The results obtained during the long-term tests confirmed
that the results of the earlier tests could be maintained
during normal unit cycling service. NOX emissions mea-
sured from October 3, 1993 to June 3, 1994 show an
average reduction of 62% (Figure 3-15) (Fplsom, 1994).
The average NO emission during the period of June 5,
1993 to April 4, 1994 was 0.344 Ib/MMBtu.
Operation of the GR and GR-SI systems resulted in a
small (0.8%) drop in the thermal efficiency of the boiler.
This drop was attributed to higher moisture of flue gas
produced by combustion of natural gas, and to a small
increase in flue gas exit temperature due to sorbent depo-
sition on the back pass heat transfer surfaces. No other
boiler operational problems associated with reburning
were experienced during the test program.
The test program team concluded that the results of the
Lakeside Unit 7 demonstration test confirmed that natu-
ral gas reburning in a cyclone-fired furnace could main-
tain 60% NOX reduction, consistently and reliably, with-
out significant thermal impacts on boiler performance.
Wisconsin Power & Light Company -
Nelson Dewey Unit 2
Wisconsin Power & Light Company's (WP&L's) Nelson
Dewey Generating station was the site of a Round 2,
Clean Coal Technology Program sponsored by DOE,
EPRI, and State of Illinois Department of Environmental
and Natural Resources. B&W was the prime contractor
and project manager for the project. The information pre-
sented in this section was compiled from a paper titled
"Update on Coal Reburning Technology for Reducing NOx
in Cyclone Boilers" (Yagiela et al., 1991). The project is
a unique example of the application of reburn technol-
ogy using pulverized coal as a reburn fuel. Cyclone-fired
boilers represent nearly 50% of WPL's coal capacity, and
are responsible for almost 75% of the utility's NOx emis-
sions. The objective of the project was to demonstrate
that reburn could reduce NOx emissions by 50% without
disrupting the reliability and operability of the boiler.
The station has two 100-MW, B&W, cyclone-fired boil-
ers, and each boiler has three 9-ft diameter front-wall
cyclones. Steam temperatures are 10OOT at the super-
heater outlet (1500 psig) and 1000T at the reheater
outlet. The baseline fuel fired in the demonstration was
a medium-sulfur, Illinois bituminous coal. Additional tests
were fired with low-sulfur, western coal from the Powder
River Basin, which is now the primary fuel at the station.
80
70
60
o
t5
I 50
cc
40
30
20
v
V.'
NOX Reduction Goal 60%
Long Term GR and GR-SI Test Results
22-24% Gas Heat Input
Oct4, 1993
JuneS, 1994
Figure 3-15. Lakeside Unit 7-Long-Term Operation Results for NOf Reductions (Folsom et al., 1994).
39
-------
A pulverized coal-fired reburn system was retrofitted to
Unit 2 for the project. This installation was the first time a
full-scale unit has been retrofitted with a coal-fired reburn
system. The reburn system was developed from math-
ematical modeling of the boiler and pilot-scale testing
conducted in B&W's Small Boiler Simulator (6 MMBtu/
hr). Results of these initial tests characterized the boiler
and were used to configure the number and locations of
reburn burners and OFA ports in Unit 2 (Farzan et al.,
1991). Four "S" type burners and four OFA ports were
retrofitted to Unit 2. A B&W MPS-67N pulverizer with a
dynamic classifier, rotating throat, and automatic spring
adjustment system was installed to provide the pulver-
ized coal for the reburn system (Newell et al., 1993). A
schematic of the reburn system is presented in Figure
3-16.
Cyclone-firing was reduced from 100% of the total fuel
input to a range of 65 to 80%, and the remaining coal
was introduced in the reburn zone downstream at sub-
stoichiometric conditions. Temperatures in the reburn
zone were approximately 2500°F to minimize the forma-
tion of atmospheric NOx from the addition of excess air.
NOx reductions for the firing of Illinois Basin coal ranged
from 33 to 50% over loads ranging from 40 MW to full
load at 110 MW (Figure 3-17). The test objective of 50%
reduction in NOx emissions was met at full load; how-
ever, emissions "reductions diminished at loads below
80 MW. At the minimum test conditions of 40 MW, the
reduction in NOx emissions was only 33%. The lower
reduction at low loads was attributed to flame instability
of the Illinois coal at a reburn zone stoichiometry of 0.9
Furnace Enclosure
Reburn Burners Flue
Gas Recirculation Duct
Hot Primary Air
Fan and Motor
B&W Dual Zone
Overfire Air Ports
B&W S-Type
Reburn Burners
B&W Cyclone Furnaces
Gravimetric Feeder
B&W MPS Pulverizer
Figure 3-16. Nelson Dewey Unit 2-Coal-Fired Reburn System Schematic (Newell et al., 1993).
40
-------
or less. With the returning system in operation, NOx emis-
sions as low as 250 ppm (0.34 Ib/MMBtu) were achieved.
The fuel input from the pulverized coal burners was at
34% and the reburn zone stoichiometry was 0.89.
NO reduction was enhanced when burning Powder River
Basin coal. The overall NOx reduction was greater (62%),
which was achieved at a'lower reburn fuel heat input
(30%) and a higher reburn zone stoichiometry. The re-
ductions were consistent over the full range of loads
tested (Figure 3-18). This insensitivity to load was attrib-
uted to the flame stability when burning Powder River
Basin coal, even at lower unit loads with a sub-stoichio-
metric environment.
Several parameters were evaluated during this reburn
retrofit demonstration to determine the effect of reburning
on the overall power plant. These parameters included
precipitator opacity, slagging and fouling, corrosion, tube
temperatures, exit gas temperatures, carbon burnout,
and hazardous air pollutants. A summary of the effects
of the reburning retrofit on the various parameters is pre-
sented in Table 3-3. None of the evaluated parameters
were severely upset as a result of the retrofit. In some
cases, boiler performance was actually improved due to
retrofit conditions, such as a reduction in slagging and
fouling. More importantly, the reburn system was oper-
ated automatically and the boiler controls could com-
pensate for cases of a pulverized coal reburn system
shutdown.
As of July 1994, the pulverized coal reburn system had
been in service for more than 2500 hours. Only two forced
outages had occurred as a result of the retrofit. WP&L
plans on continuing the firing of Powder River Basin coal
in the reburn system. This system allows WP&L to meet
NOX emission reduction goals while maintaining the
boiler's rating and burning low-sulfur coal to meet SO2
emissions guidelines.
Ohio Edison - Niles Unit 1
Ohio Edison's Niles Generating Station was the site of a
reburn system demonstration sponsored by Ohio Edison,
EPA, GRI, EPRI, DOE, Ohio Coal Development Office,
East Ohio Gas, and ABB Combustion Engineering. The
information presented in this section was compiled from
a paper titled "Long Term N0x Emissions Results with
Natural Gas Reburning on a Coal-Fired Cyclone Boiler"
(Borio et al., 1993). Parametric and long-term testing
were conducted as part of this research and develop-
ment project on the feasibility of utilizing natural gas
reburning to reduce NOx emissions from a cyclone-fired
utility boiler.
£
"8
8
i
I
700
600 ~
500 -
400 -
300 =
200
'
Baseline Operation
'Reburn Operation
I T
50% Redufction @ Full Ldad
i
, , , I , , , I , , ,
0.95
- 0.78
- 0.61
1
X
i
- 0.44
0.27
20
40
60 80
Unit Load (MW)
100
120
Figure 3-17. Nelson Dewey Unit 2-NO, Emissions vs. Unit Load - Illinois Basin Coal (Newell et at., 1993).
41
-------
ouu
525
_f 450
CO
0
S> 375
d
1
5 300
X
o
225
150
f
. ' ' '
Baselir
. . . j , . ,
i j
e Operation
r T
i i
__ ,_ i
Reburn Operation
.
!»- <
i
',,,!.,.
- ' 50% Re
, , ,
' ' '
i -j
i n
i i
duction @ Full
*rr.-:v_
, , ,
. i
_
_
_______
_
_
.oad z
*
-
, , ,
>0 40 60 80 100 12
Unit Load (MW)
0.82
- 0.66
- 0.51
- 0.36
0.2
Figure 3-18. Nelson Dewey UriA2-NOl Emissions vs. Unit Load - Powder River Basin Coal (Newell et a/., 1993).
Unit 1 is a 114-MW, cyclone-fired, pressurized, natural-
circulation boiler. The four cyclone burners fire eastern
bituminous coal in a single-wall fired furnace. A sche-
matic of the boiler is shown in Figure 3-19. Combustion
products from the cyclone burners pass down through
the primary furnace-pass screen tubes. Five natural gas
injectors were installed in the lower portion of the sec-
ondary furnace. Reburn fuel is injected under sub-sto-
ichiometric conditions and allowed to react with the com-
bustion products. OFA is injected toward the top of the
secondary furnace to ensure carbon burnout. The flue
gas then enters the boiler's convective passes.
The original design for this demonstration utilized FGR
to facilitate mixing in the reburn zone. However, during
parametric field testing, ash deposits on the furnace's
back wall were found to be up to four times thicker than
in normal boiler operation. Although NOx emission re-
ductions were not affected, the thicker ash deposits were
an unacceptable furnace condition, and the reburn sys-
tem was redesigned to operate without FGR. "Proof-of-
performance" testing showed that operating the reburn
without FGR eliminated the ash deposition problem. The
N0x emissions were slightly higher for the modified sys-
tem", but remained within an acceptable range of the para-
metric test results.
The original design for the reburn system operation was
for a reburn fuel heat input of 16% of total boiler heat
input at loads of 80 MW or greater. For loads of less
than 80 MW, the reburn heat input was to be proportion-
ally reduced, reaching 0% at loads of 65 MW or less.
These design considerations for reburn fuel heat input
for loads less than 80 MW were not applied because of
the need to maintain above the minimum furnace tem-
perature requirements for slag tapping in the cyclone
burners. During the long-term testing, the reburn sys-
tem was utilized only at loads of 80 MW or greater due
to "operator judgment" on the basis of slag tapping re-
quirements.
During this testing, the reburn section heat input was at
16% of total heat input for approximately 50% of the tests,
with the remaining tests run at between 3% and 16% of
total heat input. The reburn zone was operated with a
stoichiometry of approximately 0.94. Absolute NOx emis-
sions increased linearly with increasing reburn stoichi-
ometries for tested load ranges (Figure 3-20). The gen-
eral trend of greater absolute NOx emissions at higher
loads is offset by greater reductions from the baseline at
higher loads. The reburning system effectively capped
the level of NOx emissions to 0.26 tons/hr for all loads
tested (Figure 3-21).
42
-------
Table 3-3. Nelson Dewey Unit 2 - Summary of Effects of
Reburning on Unit Operating Parameters
Parameter
Anticipated Results
Actual Results
NO, Emissions (Full
Load) Illinois Basin
Coal
NO, Emissions (Full
Load) Powder River
Basin Coal
Reduced 50% or more
Reduced 50% or more
Precipitator Opacity Up 5 to 10%
Slagging/Fouling
No Change
Furnace Corrosion No Change
Header/Tube Temps Higher 25 to 50°F
Furnace Exit Gas
Temp
SH i RH Sprays
Carbon Carry-over
Illinois Basin Coal
Carbon Carry-over
Powder River Basin
Coal
Hazardous Air
Pollutants*
Higher by 50 to 75°F
Higher by 30%
Higher by 10 to 15%
Higher by 10 to 15%
No change
Nominal 55%
reduction
Nominal 61%
reduction
No increase
from base
Cleaner than
normal
No change
No increase
from base
Reduced by
100to150°F
50% of base
Higher by 10
to 15%
No change
No change
'Arsenic, beryllium, cadmium, chromium, lead, nickel, manganese, selenium,
mercury, benzene, toluene, HF, and HCI.
Source: Newell et a!., 1993
As mentioned above, the original reburn system design
involved the use of FGR to improve mixing of the reburn
fuel and combustion gases and to cool the reburn fuel
burners. The eventual long-term testing design did not
utilize FGR. As a result of this redesign, significant sav-
ings were gained in capital cost.
The original design with FGR required a windbox pen-
etration of 6 ft2 for each of the five injectors, as well as
the bending of 12 tubes out of plane. The redesign with-
out FGR required a windbox penetration of only 0.2 ft2
for each of five injectors, and the bending of two tubes
out of plane. Water was chosen as the reburn injector
cooling medium in place of the flue gas. In addition, vari-
ous equipment such as a recirculation fan, controls, sec-
tions of ductwork, and a motor were no longer needed
for the retrofit. Elimination of FGR from the reburn sys-
tem would result in an estimated reduction in required
capital of 30%. While this retrofit was successful in re-
ducing NOx emissions without the use of FGR, boilers
with different flow patterns in the reburn zone may re-
quire FGR for adequate mixing in the reburn section.
Because some NOX reduction efficiency was lost in the
removal of the recirculated flue gas, attempts were made
to return to the original reduction levels. It was thought
that the natural gas reburn fuel potentially was forming
soot as it was injected into the reburn zone without dilu-
tion by recirculated flue gas or combustion air. Soot for-
mation does not reduce NOx as well as the hydroxyla-
tion reaction which forms CH radicals. Water was injected
with the reburn fuel to minimize soot formation and pro-
mote the hydroxylation reaction in the reburn zone. No
changes in NOx emissions reduction performance were
achieved, thus water was eliminated from the reburn fuel
injection.
Waterwall tube thicknesses were measured ultrasoni-
cally before and after the test program to detect any
wastage. No significant increase in wastage was ob-
served. Ultrasonic measurements indicated that corro-
sion in the upper areas of the secondary furnace were
similar to its normal patterns. The superheater did show
signs of increased wastage with the higher temperatures.
Corrosion was lowest for those metal areas with in-
creased concentrations of chromium.
The test program has been completed and the reburn
system was removed in August 1992. Based on the load-
cycle history of Unit 1, the annual reduction in NOX emis-
sions would be much less than the 47% achieved during
the 3-1/2 months of testing. The facility reported that the
actual NO^ emissions reduction over the 3-1/2 month
testing period, when accounting for all hours of opera-
tion with or without reburning, was approximately 10%.
A major factor in the overall low average was minimum
ash fusion temperatures that impeded load following for
the reburn system (Kanary, 1993). Suggestions for em-
ploying the reburn technology included (Borio et al.,
1993):
Accurately control the air/fuel mixtures to the cy-
clones;
Eliminate the need for FGR by increasing the num-
ber of natural gas (reburn fuel) injectors;
Use stainless in water-cooled reburn fuel guidepipes
to prevent the corrosion that was experienced; and
Use a lower fusion temperature coal to increase the
load range at which the reburn system could oper-
ate.
Ladyzhin Power Station - Unit 4
Under a joint program sponsored by EPA, and the na-
tions of Russia and Ukraine, a 300-MW, opposed-wall
fired, wet-bottom boiler was retrofitted with a natural gas
reburn system. The objective of the test was to deter-
mine the effectiveness of reburn technology in reducing
NO emissions by at least 50% while minimizing any
43
-------
Superheat/Reheat
Corrective Passages
Gas
Recirculation
Fan
Upper Fuel
Injectors
Screen Tubes
Figure 3-19. Niles Unit 1-Schematic of Reburn Process (Bono etat., 1993).
44
-------
800
700
600
OJ
0 500
CO
X
O
400
300
200
June 1-June 12, 1992
0.8
0.9
1.0 1.1
Reburn Zone Stoichiometry
Figure 3-20. Niles Unit 1-Variation ofNOx with Reburn Stoichiometry (Borio et a/., 1993).
1.2
1.3
CN
O
CO
co
0.6
0.5 ~
0.4 -
& 0.3 -
co
o
'co
to
E
ULJ
O
0.2 -
0.1 -
35 45 55 65 75 85 95 105 110
Load ( MW Gross)
Figure 3-21. Niles Unit 1-NOt Emissions as a Function of Boiler Load (Borio et a/., 1993).
45
-------
detrimental impact from the retrofit. The information pre-
sented in this section was compiled from a paper titled
'Three-Stage Combustion (Reburning) Test Results from
a 300 MWe Boiler in the Ukraine" (LaFlesh et al., 1993).
The boiler that was chosen as a host site is typical of at
least 300 other units in Russia and Ukraine. The boiler,
Unit 4, was located at the Ladyzhin Power Station near
Vinnitsa, Ukraine. The boiler typically fires a high vola-
tile, high ash, Ukrainian, bituminous coal (25 to 35% ash
content); a low-ash, Siberian, brown lignite coal (4 to
10% ash content); or a blend of these fuels. An analysis
of the coals is shown in Table 3-4.
Baseline NOX emissions ranged from 370 to 730 ppm
depending on various operating factors. ABB Combus-
tion Engineering, under contract to EPA, provided a con-
ceptual reburning system design, with the Russian and
Ukrainian teams completing all other portions of the fab-
rication and testing. ABB Combustion Engineering's de-
sign was based on cold-flow modeling, computer mod-
eling, analysis of engineering drawings, and results of
the Ohio Edison Niles Unit I demonstrations program
(cited previously).
Table 3-4. Ladyzhin Unit 4 - Fuel Analyses
Parameter
High Volatile
Bituminous C -Donetz
Siberian Lignite
Kansko-Achinski
Proximate Analysis
Moisture, %
Volatile Matter, %
Fixed Carbon, %
Ash, %
12.0
22.2
30.6
35.2
33.0
29.9
32.4
4.7
Ultimate Analysis
Moisture, %
Carbon, %
Hydrogen, %
Sulfur, %
Oxygen, %
Nitrogen, %
LHV, Btu/lb
12.0
40.1
3.0
2.9
6.0
0.8
6,864
33.0
43.7
3.0
0.2
13.5
0.6
6,738
Critical Temperatures
Initial Deformation, °F
Softening, °F
Fusion, °F
2,190
2,440
2,520
2,320
2,350
2,398
Source: LaFlesh etal., 1993
The Ladyzhin Power Station has six 300-MW, TPP-312
boilers. These supercritical steam pressure units (3625
psig) each have 16 opposed-wall, swirl-stabilized burn-
ers and operate under slagging conditions. The slag
makes up 20 to 30% by weight of the total ash, and is
tapped at the bottom of the furnace. The fly ash is re-
moved from the flue gas by electrostatic precipitators.
A1/16-scale model was used to conduct isothermal flow
modeling of the Ladyzhin unit. The model was used to
optimize parameters such as configuration, size, loca-
tion, number, and operating values for the reburn burn-
ers and OFA injectors. Burners and OFA injectors were
assumed to be located on either the front or back wall
due to equipment obstructions on the side walls. In ad-
dition, estimates were made on the potential flue gas
velocities within the furnace.
Preliminary design configurations were modeled on a
computer in two parts. First, a reburn configuration was
evaluated independent of OFA considerations. Then, the
selected reburn configuration was tested with varying
OFA configurations. The input parameters are shown in
Table 3-5.
Parameters of interest in the analysis included exit gas
temperature, furnace hopper gas temperature, and fur-
nace heat absorption profile. The output of the computer
model included furnace gas temperature profiles and
furnace absorption profiles. Operational parameters such
as excess air, FGR rate, and reburn heat input were ana-
lyzed for optimal thermal performance. The values se-
lected from the computer modeling are presented in Table
3-6. A schematic of the preliminary design is shown in
Figure 3-22.
One change was made to the system after the reburn
system was designed and, thus, was independent of
considerations for the reburn retrofit. An aerodynamic
"nose" was fitted to improve a problem with heat trans-
fer in the boiler's convective section. This change does
not appear to have had any significant effect on the
reburn retrofit.
Prior to the retrofit, NOx emissions averaged 600 ppm
while at a load of 300 MW (4% O2 at economizer outlet)
and firing a blend of 90% Ukrainian coal and 10% Sibe-
rian lignite. Parametric tests were able to reduce NO
emissions to as low as 240 ppm at a reburn heat input of
15%. NOx emissions decreased as reburn heat input
percentage increased (Figure 3-23). Decreasing excess
air (shown as flue gas O? content after the economizer)
also reduced NOX emissions (Figure 3-24). The reburn
system was operated over a load range of 200 MW to
300 MW. Absolute values of NOx emissions had a linear
relation to increasing load as shown in Figure 3-25. Para-
metric testing showed that at loads of 200 MW to 300
MW, the reburn system generally was able to reduce
NO emissions by 40 to 60% (240 to 360 ppm) from a
46
-------
Table 3-5. Ladyzhin Unit 4 - Flow Diagram for Boiler Combustion Performance Model
Inputs
Mathematical
Model
Source: LaFlesh et al., 1993
Table 3-6. Ladyzhin Unit 4 - Furnace Thermal Performance Summary
Outputs
Fuel Information
Particle Size Distribution
Apparent Density
Chemical Characteristics
Ash Characteristics
Drop Tube Furnace System Information
Char Activation Energy
Char Frequency Factor
Fuel Swelling Factor
Fuel Volatile Matter
Boiler Information
Operating Conditions
Proprietary
Computer
Code
Temperature/Time History
Efficiency
% Carbon Heat Loss
Profile
Performance Variables Units
Reburn Fuel Ratio %
Total Excess Air %
Burner Zone Excess Air %
Total FGR %
Reburn FGR %
Upper Furnace FGR %
Furnace Exit Gas Temp °F
Furnace Heat Absorption MMBtu
Baseline as
Found
NA
20
20
18
NA
3.2
2,028
606
Preliminary
Rebum
Case
20
20
20
18
10
3.2
2,028
609
Optimum
Reburn
Case
12
20
5
21
7.5
8.7
1,949
625
Source: LaFlesh etal., 1993
47
-------
±25°
Tilt
±25°
Tilt
FGR Nozzles (6)
Terciary Air
(Burnout) Nozzles
(6 Front, 6 Rear)
Reburn Fuel and
FGR Injectors
(6 Front, 6 Rear)
Main Coal Burners
(8 Front, 8 Rear)
Preliminary Proposal
15° X
Fixed
-15°
Fixed
^ rvjn iiU£.£.ieo ^o;
.< Burnout Air Nozzles (5)
(5 Front, 5 Rear)
^... Reburn Fuel and
FGR Injectors
(5 Front, 5 Rear)
>Main Coal Burners
(8 Front, 8 Rear)
Final Design Arrangement
Figure 3-22. Ladyzhin Unit 4-Schematic of Reburn Design Arrangements (LaFlesh et at., 1993).
48
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CM
o
o
O
O
400
350
300
250
200
150
100
50
0
300 MW
Baseline NOX - 600 ppm
I I I I I I I I I I I I I I I I I I I I I I I I I
4 8 12
% of Total Heat Input as Reburn Fuel
16
Figure 3-23. Ladyzhin Unit 4-NOM Emissions vs. Reburn Fuel Percentage (LaFlesh et at., 1993).
baseline of 600 ppm, with an average NOx reduction of
just over 59%.
As a slagging boiler, Ladyzhin Unit 4 experienced some
problems with maintaining fluid slag at reduced loads
when a significant fraction of the total heat input to the
boiler was directed to the reburn burners. At Ladyzhin,
slag tapping was affected at loads below 200 MW. Slag
tapping was unaffected at loads between 200 and 300
MW. Furnace operators commented that the boiler was
"more controllable" after the retrofit.
FGR was used as a carrier gas for the reburn fuel, and
to maintain burner metal temperature at 1472°F or less.
Unburned carbon in the fly ash increased 1 % after the
retrofit. CO levels were maintained at 250 ppm or less,
with additional reductions expected with long-term test-
ing.
Unit 4 is operating the reburn system for long-term test-
ing to optimize operational parameters and evaluate vari-
ous primary fuel compositions. Consideration is being
given to installing multi-fuel reburn fuel injectors in a new
reburn system design for Ladyzhin boiler No. 6. The de-
sign is being done by EER, under contract to the EPA.
Partners include U.S. AID, and the U.S. Department of
Energy. The multi-fuel system will be capable of firing
natural gas, oil, or coal. This capability would be very
important in Ukraine due to potential fuel shortages.
Ladyzhin plant personnel would like to install reburn ca-
pability on all six units, as funding is available.
49
-------
CO
o
400
350
300
250
,3 200
Q.
a.
x 150
O
100
50
300 MW
12% of Total Boiler Heat
Input as Reburn Fuel
All Burnout Air and Reburn FGR
Dampers 100% Open
234
02% After Economizer
Figure 3-24. Ladyzhin Unit 4-NOt Emissions vs. Flue Gas Oxygen Content.
500
400
S 300
o
s
o
a 200
X
o
100
I
I
I I I I
200
220
240 260
MW
280
300
Figure 3-25. Ladyzhin Unit 4-NOf Emissions vs. Boiler Load.
50
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Chapter 4
Process Economics
Costing Methodology
Estimates of the capital and operating costs of using the
reburning process to reduce NOx emissions are pre-
sented in the following section. A synopsis of the proce-
dures by which these costs were converted to busbar
and cost-effectiveness estimates is also provided. The
cost estimation methods closely follow the procedures
used in the EPA Alternative Control Techniques (ACT)
Document NOx Emissions from Utility Boilers (U.S.
EPA, 1994), the general methodology contained in the
EPRI Technical Assessment Guide (TAG) (EPRI, 1986),
and the EPA's Office of Air Quality Planning and Stan-
dards (OAQPS) Costing Manual (U.S. EPA, 1990). The
general framework for handling capital and annual costs
is shown in Table 4-1. All costs, except where noted, are
presented in 1991 dollars.
Because of the limited economic data on coal-fired reburn
systems, the quantitative cost analyses are limited to gas-
fired reburn installations; however, discussions of cost
factors related to coal-fired reburn systems are also pre-
sented.
Capital Costs
The estimated total capital cost of a reburn system in-
cludes both direct and indirect costs. Direct costs include
both costs for the basic system installation and for the
retrofit needs. Indirect costs are based on a percentage
of the direct costs and include several costs associated
with the design and engineering of the system.
Typical capital costs for the installation of a reburn sys-
tem involve reburn fuel equipment, boiler modifications,
and particulate control device modifications (if required).
If the reburn fuel is coal, significant adjustments may be
required for the handling and preparation of the fuel, in-
cluding the addition of a pulverizer. Fuel preparation costs
are not required for natural gas-firing; however, installa-
tion of new gas supply lines can be extremely costly if
no existing gas line to the plant is available or if the exist-
ing line has inadequate capacity. Boiler modifications
include the penetration of boiler walls to install reburn
fuel injectors and OFA ports. Modification or replacement
of existing burners typically is not necessary, but may be
included in an overall NOx emission reduction program.
Additional fans and ductwork are also necessary for flue
gas recirculation and overfire air systems. Installation of
reburn systems also often includes upgrade of the boiler
control systems to include the new fuel and combustion
air controls to ensure safe start-up, shut-down, and trip
conditions. Modifications to the particulate control de-
vices may be necessary to control the increased amount
of fly ash produced when coal is used as a reburn fuel in
a wet-bottom boiler.
Basic System Cost
The basic reburn system cost is the cost of purchasing
and installing the system hardware directly associated
with the control technology. This cost reflects the costs
of the basic system components for a new application,
but does not include any site-specific upgrades or modi-
fications to existing equipment that may be required to
implement the control technology at an existing plant
(e.g., new igniters, new burner management system, and
waterwall or windbox modifications). Any reburn system
start-up/optimization tests are also included in basic sys-
tem cost. Note: The costs of purchasing and installing
any continuous emission monitoring (CEM) equipment
that may be required for determining compliance with
state and federal emission limits are not included in the
analysis.
The data used to estimate basic system cost were com-
piled in the ACT document (U.S. EPA, 1994) from utility
questionnaires, vendor information, published literature,
and other sources. These cost data were then compiled
in a data base, examined for general trends in capital
cost versus boiler rating, and statistically analyzed us-
ing linear regression to fit a functional form of:
BSC = a MWb
(4-1)
51
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Table 4-1. Capital and Operating Cost Components
Total Capital
Cost
Total O&M
Cost
Direct Cost
Basic System
Cost
Retrofit Cost
Indirect Cost
Fixed O&M Cost
Variable O&M Cost
Basic equipment
Initial chemicals/
catalyst
Installation
Start-up/optimiza-
tion testing
Scope adders
Work area
congestion
General facilities
Engineering
Royalty fees
Project contin-
gency
Process contin-
gency
Operating labor
Maintenance labor
Supervisory labor
Maintenance
materials
Energy penalty
Chemicals/catalyst
Electricity
Water
Waste disposal
where:
BSC = Basic system cost ($/kW)
a = Constant derived from regression analysis
MW = Boiler size (MW)
b = Constant derived from regression analysis
The basic system cost was then derived using Equation
4-1 and the calculated values of "a" and "b".
Retrofit Cost Factor
In comparison with installation on a new unit, installation
of NOx controls on an existing boiler typically involves
additional cost categories. These additional cost catego-
ries comprise the system retrofit cost. Retrofit costs are
related to upgrades and modifications to the boiler that
are required for the NOx control system to operate as
designed. These modifications and upgrades can in-
clude:
Igniters modification or replacement;
Waterwall modifications;
Flame scanners;
Coal pulverizer modifications;
Boiler control modifications;
Burner management modifications;
Coal piping modifications;
Windbox modifications;
Structural modifications;
Asbestos removal;
Insulation modifications;
Electrical system modifications;
Flue gas recirculation fan modifications; and
Demolition.
Additional costs are incurred when accessibility is re-
stricted or work space is limited by the existing equip-
ment configuration. All of these factors are included in a
retrofit factor that is based as a percentage of the basic
system cost as presented below in Equation 4-2.
RC
BSC
(4-2)
where:
RF = Retrofit factor (dimensionless);
RC = Retrofit cost ($/kW); and
BSC = Base system cost ($/kW).
For example, a retrofit factor of 1.3 indicates that the
retrofit cost is 30% of the basic system cost. Retrofit fac-
tors were developed based on cost data for planned or
actual reburn installations on existing utility boilers. The
cost data were also used to estimate low, medium, and
high retrofit factors for the model boiler analysis, which
are listed below:
A low retrofit factor of 1.0 is used for a new unit or a
retrofit that requires minimal or no upgrades or modi-
fications, and if no difficulties are associated with
accessibility;
A medium retrofit factor is used for moderate equip-
ment upgrades or modifications and/or if some diffi-
culties exist that are associated with accessibility;
and
A high retrofit factor indicates that extensive scope
adders are required and/or limited accessibility and/
or work space also may be available.
Gas-fired reburn retrofit costs are primarily due to modi-
fications and upgrading of existing equipment. Require-
ments for accessibility and work space are minimal for a
52
-------
gas-fired reburn retrofit since burners and overfire air
ports typically can be installed from inside the boiler. Coal-
fired reburn retrofits can incur significant costs associ-
ated with greater accessibility and work space require-
ments than required for gas-fired retrofits. Gas-fired
reburn systems typically are estimated with a low to me-
dium retrofit factor while coal-fired reburn systems typi-
cally are estimated with a medium to high retrofit factor.
The total direct cost was estimated by multiplying the
basic system cost by an appropriate retrofit factor.
TDC = BSC RF
(4-3)
where:
TDC = Total direct cost ($/kW);
BSC = Basic system cost ($/kW); and
RF = Retrofit factor (dimensionless).
Indirect Cost Factor
The indirect cost includes the costs of general facilities,
engineering expenses, process royalty fees (if any), and
contingencies. General facilities include offices, labora-
tories, storage areas, or other facilities required for in-
stallation or operation of the control system. Examples
of general facilities required by installation of a reburn
system include expansion of the boiler control room to
house new computer cabinets for the boiler control sys-
tem and expansion of an analytical laboratory.
Engineering expenses include the utility's internal engi-
neering efforts as well as an architect/engineer (A&E)
contractor. Engineering costs incurred by the technol-
ogy vendor are included in the equipment cost and are
considered direct costs.
A process royalty fees is a fee paid to the developer of a
patented process technology in return for permission to
use this technology. For example, a company may hold
a patent on a unique process for reducing the volume of
flue gas recirculation gas required to attain adequate
mixing of the reburn fuel and combustion gas in the
reburn zone, and the patent-holder may charge a fee for
use of this technology. In some cases, especially where
the patent is for a specific piece of equipment, this fee
may be included in the capital cost of the equipment.
Contingencies are factors that account for the uncertainty
associated with cost estimation (project contingency) and
the maturity of the technology (process contingency).
Project contingency is assigned based on the level of
detail in the cost estimate. The total capital cost must
include the costs of miscellaneous equipment and ma-
terials not included in the direct cost estimate. Project
contingencies range from 5 to 50% of the direct costs,
depending on the level of detail included in the direct
cost estimate, with lower contingencies associated with
more detailed cost estimates. Process contingency is
based on the maturity of the technology and the number
of previous installations. Process contingency represents
unforeseen expenses potentially incurred because of
inexperience with newer technologies. Process contin-
gencies range from 0 to over 40% of the direct costs,
with higher contingencies associated with less mature
technologies.
As shown in Equation 4-4, an indirect cost factor accounts
for the indirect costs as a percentage of the total direct
cost:
ICF =
1C
(4-4)
BSC + RC
where:
ICF = Indirect cost factor (dimensionless);
1C = Indirect costs ($/kW);
BSC = Basic system costs ($/kW); and
RC = Retrofit costs ($/kW).
For example, an indirect cost factor of 1.3 indicates that
the indirect costs are 30% of the total direct cost (basic
system cost plus retrofit cost). The indirect cost factors
are based on cost data from planned and actual installa-
tions of reburn systems on various boilers.
Finally, the total capital cost is calculated by multiplying
the total direct cost by the ICF.
TCC = (BSC + RC) ICF (4-5)
where:
TCC = Total capital cost ($/kW);
BSC = Basic system cost ($/kW);
RC = Retrofit cost ($/kW); and
ICF = Indirect cost factor (dimensionless).
Operating and Maintenance Costs
Operating and maintenance (O&M) costs include fixed
and variable O&M components. Fixed O&M costs include
operating, maintenance, and supervisory labor; mainte-
nance materials; and overhead. Fixed O&M costs are
assumed to be independent of the boiler capacity factor
(i.e., the magnitude of these costs are the same at 50%
unit load and 100% unit load). Variable O&M costs are
dependent on the boiler capacity factor and include any
costs incurred from energy penalties (e.g., boiler effi-'
53
-------
ciency losses associated with the use of natural gas as
a reburn fuel), electrical power consumption, and waste
disposal.
Fixed costs were not included in the analysis under the
assumptions that:
Very few moving parts are needed for gas-fired
reburning; and
Operating labor and maintenance requirements are
expected to be very low for gas-fired reburning.
Cost rates for variable O&M cost estimates are listed in
Table 4-2. The prices listed for coal and natural gas are
estimated national average prices for the year 2000,
based on the reference case analysis in the DOE's 1992
Annual Energy Outlook (U.S. DOE, 1992). Prices for solid
waste and electricity are listed in 1989 dollars.
The primary factor when determining variable O&M costs
for reburn systems is the cost of the reburn fuel com-
pared to the cost of the primary fuel it replaces. This cost
is a major concern with gas reburn, as the cost of natu-
ral gas is typically $1 to $1.50 per million Btu (MMBtu)
greater than the price of coal. A small heat rate penalty
also is associated with gas reburn. However, this pen-
alty may be offset by energy savings in other areas, such
as a reduction in the energy needed to process the coal
that has been replaced by gas. The additional fuel costs
were calculated with the fuel prices listed in Table 4-2.
Variable O&M costs also include the savings gained from
sulfur dioxide (SO2) credits because of lower SO2 emis-
sion levels when using natural gas-fired reburn on a coal-
fired boiler. The SO., emissions were calculated with typi-
cal sulfur and calorific content of coal (U.S. EPA 1994)
and an average AP-42 emission factor for bituminous
and subbituminous coal (U.S. EPA, 1985b). The SO2
credit was assumed to be $200/ton of SO2 (Sanyal et
al., 1992). The equation to determine savings from SO2
credits is:
Savings = EF* Sulfur -MW-HR- (4-6)
CF-Credit- Reburn-2.19
where:
Savings = Savings due to SO2 credits ($/yr)
EF = AP-42 SO Emission Factor (Ibs SO^ton
coal/% sulfur in coal);
Sulfur = Sulfur (%);
MW = Unit size (MW);
HR = Boiler net heat rate (MMBtu/kWh);
CF = Annual capacity factor (decimal fraction);
Credit = SO2 credit ($/ton);
Reburn = Heat input of reburn fuel fired divided by to-
tal boiler heat input (decimal fraction); and
2.19 = Unit conversion factor.
Table 4-2. Variable O&M Unit Costs
Fuel
Coal
Natural gas
Solid Waste
Electricity
Cost
1.74
3.27
9.50
0.05
Unit
$/MMBtu
$/MMBtu
$/ton
$/kWh
Reference
U.S. DOE 1992
U.S. DOE 1992
EPRI 1986
EPRI 1986
Busbar Cost and Cost-Effectiveness
Busbar cost (mills/kWh) is defined as the sum of annu-
alized capital costs and total O&M costs ($/yr) divided
by the annual electrical output of the boiler (kWh/yr),
which provides a direct indication of the cost of the reburn
system to the utility and its customers. To convert total
capital cost to an annualized capital charge, the total
capital cost is multiplied by an annual capital recovery
factor (CRF). The CRF is based on the economic life
over which the capital investment is amortized and the
cost of capital (i.e., interest rate). The CRF is calculated
using the following equation:
CRF =
(4-7)
i = Interest rate (decimal fraction) [assumed to be
0.10 (i.e., 10%)]; and
n = Economic life of the equipment (years);
Cost-effectiveness values indicate the total cost of a con-
trol technology per unit of NOX removed and are calcu-
lated by dividing the total annualized capital charge and
O&M expense by the annual reduction in tons of N0x
emitted from the boiler.
Cost Analysis
Cost estimates for a gas-fired reburn system are pre-
sented in this section. These estimates are based on.
systems installed on wall-, tangential-, and cyclone-fired
boilers burning coal as the primary fuel. Limited cost
data on natural gas-fired reburn for coal-fired boilers
54
-------
were obtained from vendor and utility responses to a
questionnaire. In response to this questionnaire, Illinios
Power submitted cost data for the reburn retrofit on the
75-MW Hennepin Unit 1 boiler; and EER provided in-
stallation costs for retrofitting the reburn systems on the
33-MW City Water, Light, and Power Lakeside Unit 7
boiler and the 172-MW Public Service of Colorado Chero-
kee Unit 3 boiler (U.S. EPA, 1994). A regression analy-
sis of the data showed a high degree of scatter and no
obvious costing trend. Reburn costs were based on the
Cherokee Unit 7 cost data because this unit is most in-
dicative of a typical small utility boiler. Sufficient data were
not available to perform a cost analysis for coal-fired
reburn systems.
The economy of scale was assumed to be 0.6 for the
gas-fired reburn basic cost algorithm. With this assump-
tion, the cost coefficients in Equation 4-1 for reburn are:
a = 229; and
b = -0.40.
The cost of installing a natural gas pipeline was not in-
cluded in the analysis because it is highly dependent on
site-specific parameters such as the unit's proximity to a
gas line and the difficulty of installation.
In their response to the questionnaire, EER indicated
that the retrofit of a gas-fired reburn system would cost
10 to 20% more than a reburn system applied to a new
boiler. With this assumption, the retrofit factor was as-
sumed to be 1.15 (Jensen, 1993). However, for the sen-
sitivity analysis, the retrofit factor was varied from 1.0 to
1.6 to account for different retrofit difficulties on specific
boilers.
The indirect costs were estimated to be 40% of the total
direct cost, resulting in an indirect cost factor of 1.40 (U.S.
EPA, 1994).
Annual O&M costs included both additional fuel costs
from the higher price of natural gas versus coal, and
utility savings on SO2 credits from lower SO2 emission
levels when using natural gas-fired as the reburn fuel on
a coal-fired boiler. The analysis was conducted assum-
ing 18% of the total heat input was from natural gas. The
SCX credit was assumed to be $200 per ton of SO2, equal
to $0.24/MMBtu based on a coal-sulfur content of 1,5%
(U.S. EPA, 1994).
Model Plants
To estimate the capital cost, busbar cost, and cost-ef-
fectiveness of natural gas-fire reburn, a series of model
plants were developed. These model plants reflected the
projected range of size, duty cycle, retrofit difficulty, eco-
nomic life, uncontrolled NOX emissions, and controlled
NO emissions for each major boiler type.
The capital cost, busbar cost, and cost-effectiveness for
the 15 wall-, tangentially-, and cyclone-fired model boil-
ers are listed in Table 4-3. An economic life of 20 years
and a NOx reduction efficiency of 55% were assumed
for all of these boilers. The fuel price differential between
coal and natural gas was varied from $0.50 to $2.50/
MMBtu. For the 600-MW, basefoad, wall-fired boiler, the
estimated cost-effectiveness ranges from $480 to $2,080
per ton of NOx removed. For the 100-MW, peaking, wall-
fired boiler, the estimated cost-effectiveness ranges from
$3,010 to $4,600 per ton.
Cost per ton of NOX removed with reburn was highest for
the tangentially-fired units because of the lower baseline
NOx emissions produced by this boiler type. Cost-effec-
tiveness for the tangentially-fired units ranged from $615
per ton to $2,680 per ton for the 600-MW, caseload unit,
and $3,870 per ton to $5,930 per ton for the 100-MW,
peaking unit.
Cost per ton of NOx removed was lowest for cyclone-
fired boilers because this boiler type produces the high-
est baseline NOx emissions. For the 600-MW, baseload,
cyclone boiler, cost-effectiveness ranged from $290 to
$1,250 per ton and for the 100-MW, peaking boiler, cost-
effectiveness ranged from $1,810 to $2,720 per ton.
Sensitivity Analysis
In addition to the model plant analysis, sensitivity analy-
ses were conducted to examine the effect of varying eight
selected plant design and operating characteristics on
busbar cost and cost-effectiveness. The results of these
analyses are presented in two graphs for each of the
three boiler types. The eight characteristics and their ref-
erence values are:
Retrofit factor (RF) -1.3;
Fuel price differential - $1.50/MMBtu;
Boiler size - 400 MW;
Capacity factor - 40%;
Economic life - 20 years;
Uncontrolled NOx emission rate:
- Tangentially-fired boilers - 0.7 Ib/MMBtu,
- Wall-fired boilers - 0.9 Ib/MMBtu, and
- Cyclone-fired boilers -1.5 Ib/MMBtu;
NOX reduction - 55%; and
Unit heat rate -11,000 Btu/KWh.
55
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Table 4-3. Costs for Natural Gas-Fired Reburn Applied to Coal-Fired Boilers
Plant Identification Total Capital Cost, $/kW Busbar Cost, mills/kWh
Cost-Effectiveness, $/ton
Fuel Price Differential
($/MMBtu)
Wall-Fired Boilers1
1 00 MW, Peaking"
100 MW, Baseload"
300 MW, Cycling"
300 MW, Baseload
600 MW, Baseload
Tangentially-Fired Boilers0
1 00 MW, Peaking
100 MW, Baseload
300 MW, Cycling
300 MW, Baseload
600 MW, Baseload
Cyclone-Fired Boilers"
1 00 MW, Peaking
1 00 MW, Baseload
300 MW, Cycling
300 MW, Baseload
600 MW, Baseload
0.50
58.0
58.0
38.0
38.0
29.0
58.0
58.0
38.0
38.0
29.0
58.0
58.0
38.0
38.0
29.0
1.50
58.0
58.0
38.0
38.0
29.0
58.0
58.0
38.0
38.0
29.0
58.0
58.0
38.0
38.0
29.0
2.50
58.0
58.0
38.0
38.0
29.0
58.0
58.0
38.0
38.0
29.0
58.0
58.0
38.0
38.0
29.0
0.50
8.44
1.69
2.22
1.26
1.07
8.44
1.69
2.22
1.26
1.07
8.46
1.71
2.23
1.28
1.09
1.50
10.7
3.49
4.20
3.06
2.87
10.7
3.49
4.20
3.06
2.87
10.7
3.51
4.21
3.08
2.89
2.50
12.9
5.29
6.18
4.86
4.67
12.9
5.29
6.18
4.86
4.67
13.0
5.31
6.19
4.88
4.69
0.50
3,010
753
898
562
478
3,870
968
1,150
722
615
1,810
456
543
342
291
1.50
3,800
1,560
1,700
1,360
1,280
4,900
2,000
2,190
1,750
1,650
2,290
938
1,020
823
773
2.50
4,600
2,360
2,500
2,170
2,080
5,930
3,030
3,220
2,790
2,680
2,770
1,420
1,510
1,300
1,250
Uncontrolled NO, levels of 0.90 Ib/MMBtu and a rebum NO, reduction of 55% were used for wall-fired boilers.
"Capacity Factor: Peaking - 10%, Baseload = 65%, and Cycling - 30%.
'Uncontrolled NO, levels of 0.70 Ib/MMBtu and a reburn NO, reduction of 55% were used for tangentially-fired boilers.
"Uncontrolled NO, levels of 1.5 Ib/MMBtu and a reburn NO, reduction of 55% were used for cyclone-fired boilers.
In each figure, the effects of the design and operating
characteristics on cost-effectiveness and busbar cost are
illustrated. Each of the curves emanating from the cen-
tral point illustrates the effect of changes in the individual
parameter on cost-effectiveness and busbar cost, while
holding the other seven characteristics constant. Thus,
each curve isolates the effect of the selected character-
istic on cost-effectiveness and busbar cost.
The effects of changes in these reference plant charac-
teristics on cost-effectiveness and busbar cost of natu-
ral gas-fire reburn applied to wall-fired boilers are shown
in Figures 4-1 and 4-2. The reference boiler's cost-effec-
tiveness and busbar cost are approximately $1,400 per
ton of NOx removed and 3.8 mills/kWh.
Of the five parameters shown in Figure 4-1, the varia-
tion of capacity factor from 10 to 70% and variation of
fuel price differential from $0.50 to $2.50/MMBtu have
the greatest impact on cost-effectiveness and busbar
cost. The cost-effectiveness value and busbar cost are
inversely related to capacity factor, and thus, as capac-
ity factor decreases, the cost-effectiveness value and
busbar cost increase. This relationship is especially no-
ticeable at low capacity factors where a decrease of 75%
in the reference plant's capacity factor (from 40% to 10%)
resulted in an increase in the cost-effectiveness value
and busbar cost of approximately 100%.
The cost-effectiveness value and busbar cost are linearly
related to fuel price differential. An increase or decrease
of $1.00/MMBtu in the fuel price differential compared to
the reference plant changed correspondingly the cost-
effectiveness and busbar cost by approximately 50%.
Variations in economic life and boiler size follow a trend
similar to capacity factor; however, cost-effectiveness and
busbar cost are not as sensitive to these variations. For
56
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X
o
3000
2500
500
Retrofit Factor 1.0
Fuel Price Diff.
($/MMBtu)
Boiler Size (MW)
Capacity Factor (%)
Economic Life (yr)
Reference Boiler Parameters
Uncontrolled NOX = 0.9 Ib/MMBtu
NOX Reduction = 55%
Heat Rate = 11000 Btu/kWh
1.1
8.17
6.81
1.36
1.6
0.50
100
10
5
0.83 1.17
200 300
20 30
10 15
Retrofit Factor B
i Capacity Factor »
1.50 1.83
400 500
40 50
20 25
Fuel Price Diff. A
Economic Life
2.17 2.50
600 700
60 70
30 35
Boiler Size
Figure 4-1. Impact of Plant Characteristics on Reburn Cost Effectiveness and Busbar Costs for Wall-Fired Boilers (U.S. EPA, 1994).
57
-------
2200'
2000
\
1000.-
Uncontrolled NOx
(Ib/MMBtu)
NOX Reduction (%)
Heat Rate (Btu/kWh)
Reference Boiler Parameters
Retrofit Cost = 1.3
Fuel Price Diff. = 1.5 $/MMBtu
Boiler Size = 400 MW
Capacity Factor = 40%
Economic Life = 20 yrs
0.6
45.0
920C
0.7
48.3
9800
Uncontrolled
0.8
51.7
10400
NOX -
0.9
55.0
11000
*- NOX
1.0
58.3
11600
Reduction
1.1
61.7
12200
A Heat Rate
1.2
65.0
12800
Figure 4-2. Impact of NOt Emission Characteristics and Heat Rate on Reburn Cost Effectiveness for Wall-Fired Boilers (U.S. EPA, 1994).
example, a decrease of 75% in economic life (from 20 to
5 years) resulted in an increase in the plant's cost-effec-
tiveness value and busbar cost by nearly 45%. Similarly,
a decrease of 75% in the boiler size (from 400 to 100-
MW) resulted in an increase in the plant's cost-effective-
ness value and busbar cost by nearly 25%.
Variation in the retrofit factor from 1.0 to 1.6 resulted in
the smallest relative percent change in cost-effective-
ness and busbar cost. Increases of 0.1 in the retrofit fac-
tor resulted in a linear increase of approximately 6% in
the cost-effectiveness value and busbar cost.
Of the parameters shown in Figure 4-2, the variation of
uncontrolled NOX from 0.6 to 1.2 Ib/MMBtu has the great-
est impact on cost-effectiveness. Uncontrolled NOx lev-
els exhibit an inverse relationship with the cost-effective-
ness value. A 30% decrease in the reference plant's un-
controlled NOx level (0.9 to 0.6 Ib/MMBtu) resulted in an
increase in the cost-effectiveness value by 50%. Varia-
tions in the NOx reduction from 45 to 65% and heat rate
from 9,200 to *12,800 Btu/kWh have less than a 6%
change in cost-effectiveness.
The effects of the eight reference plant characteristics
on cost-effectiveness and busbar cost of natural gas-
fired reburn applied to tangentially-fired boilers are pre-
sented in Figures 4-3 and 4-4. The reference boiler's cost-
effectiveness and busbar cost are approximately
$1,800 per ton of NO removed and 3.8 mills/kWh. The
cost-effectiveness value for natural gas-fired reburn ap-
plied to tangentially-fired boilers is somewhat mislead-
ing in that it is generally higher than for a similar retrofit
to wall-fired boilers. This is the result of the lower uncon-
trolled NOx levels produced by tangentially-fired boilers
(i.e., the fixed capital costs must be distributed over fewer
tons of N0x). The sensitivity curves follow the same gen-
eral trends"as the same retrofit for wall-fired boilers.
The effects of eight plant characteristics on cost-effec-
tiveness and busbar cost of natural gas-fired reburn ap-
plied to cyclone-fired boilers are presented in Figures 4-
5 and 4-6. The reference boiler's cost-effectiveness and
busbar cost are approximately $840 per ton of NOx re-
moved and 3.8 mills/kWh. The cost-effectiveness value
for natural gas-fired reburn applied to cyclone-fired boil-
ers is lower than a similar retrofit on wall-fired and tan-
58
-------
4000
3500
2 3000
o
0)
I
!
LU
O
2500
1000
500
Retrofit Factor 1.0
Fuel Price Diff.
($/MMBtu)
Boiler Size (MW)
Capacity Factor (%)
Economic Life (yr)
Reference Boiler Parameters
Uncontrolled NOx = 0.7 Ib/MMBtu
NOX Reduction = 55%
Heat Rate = 11000 Btu/kWh
1.1
1.4
1.5
8.47
7.41
6.35
1.06
1.6
0.50 0.83 1.17
100 200 300
10 20 30
5 10 15
Retrofit Factor e
i Capacity Factor
1.50 1.83 2.17
400 500 600
40 50 60
20 25 30
Fuel Price Diff. * Boiler Size
-* Economic Life
2.50
700
70
35
Figure 4-3. Impact of Plant Characteristics on Reburn Cost Effectiveness and Busbar Costs for Tangentially-Fired Boilers (U.S. EPA, 1994).
gentially-fired boilers because of higher uncontrolled NOx
levels in cyclone-fired boilers. The sensitivity curves fol-
low the same general trends as the same retrofit for wall-
fired boilers.
59
-------
1
oann _
"o
O 9400 -
1
js onno -
1 2
*- 1 pnn -
ffinn -
i4nn~
1200-
i
\
\
\
N>
*=*==H
\
\
s
jt .
I
-------
1400'
1300'
1200
500
I
I
Reference Boiler Parameters
Retrofit Cost = 1.3
Fuel Price Diff. = 1.5 $/MMBtu
Boiler Size = 400 MW
Capacity Factor = 40%
Economic Life = 20 yrs
Uncontrolled NO
(Ib/MMBtu)
NOv Reduction (%)
HeatRate (Btu/kWh)
0.
4J
9J
9
>00
-
1.1
48.3
9800
Uncontrolled
1.3
51.7
10400
NOX -*
1.5
55.0
11000
1.7
58.3
11600
NOX Reduction A
1.9 2.1
61.7 65.0
12200 12800
Heat Rate
Figure 4-6. Impact of NOX Emission Characteristics and Heat Rate on Reburn Cost Effectiveness for Cyclone-Fired Boilers (U.S. EPA, 1994).
61
-------
Chapter 5
Integrated NOX Control Technologies
The examples cited in Chapter 3 demonstrated that as a
"stand alone" technology, reburning can reduce NOx
emissions from coal-fired boilers by 40 to 60%. How-
ever, the desired degree of NOx emission reduction may
be greater than can be attained by reburning alone in
some cases. These situations may be candidates for
implementation of an integrated NOX emission control
approach that combines reburning with another control
technology. These other NOX emission control technolo-
gies include LNBs, SNCR and SCR.
SNCR involves injecting ammonia or urea into the flue
gas to yield nitrogen and water. The ammonia or urea
must be injected into specific high-temperature zones in
the upper furnace or convective pass for this method to
be effective. SCR involves injecting ammonia into the
flue gas in the presence of a catalyst. Selective catalytic
reduction promotes the reactions by which N0x is con-
verted to nitrogen and water at lower temperatures than
required for SNCR.
Reburning With Low NOX Burners
The LNB-gas reburn retrofit at Public Service of
Colorado's Cherokee Unit 3 is an example of the poten-
tial for lowering NOx emissions by combining the reduc-
tions achieved through the use of low NOx burners and
reburn. As discussed in detail in Section 3, the LNBs by
themselves were able to reduce NOX emissions by 31%
from baseline conditions. The combined LNB-gas reburn
system reduced NOx emissions by 72% from baseline
emissions."
Reburning With SNCR
The SNCR process involves injecting ammonia (NH3) or
urea (CO(NH2)2) into boiler flue gas at specific tempera-
tures. The ammonia or urea reacts with NOx in the flue
gas to produce N2 and water.
For the ammonia-based SNCR process, ammonia is in-
jected into the convection passes of the boiler where the
flue gas temperature is 1,750 ± 90°F. Even though large
quantities of O^are present in the flue gas, NO is a more
effective oxidizing agent, so most of the NH3 reacts with
NO by the following mechanism:
6NO->5N
(5-1)
For Equation 5-1 to predominate over competing am-
monia reactions, the NH3 must be injected into the opti-
mum temperature zone and the ammonia must be ef-
fectively mixed with the flue gas. Even under optimum
conditions, an excess of ammonia must be provided to
achieve a high level of NOx reduction within a reason-
able time. The amount of unused ammonia is referred to
as "ammonia slip." Typical ammonia slip values, mea-
sured in the flue gas at the stack exit, are 5 to 20 parts
per million (ppm), and the maximum value usually is lim-
ited by local or state air emission regulations.
In the urea-based SNCR process, an aqueous solution
of urea is injected into the flue gas at one or more loca-
tions in the upper furnace or convective passes. The urea
reacts with NOx in the flue gas to form nitrogen, water,
and carbon dioxide (CO2). Aqueous urea has a maxi-
mum NO reduction activity at approximately 1,700 to
1,900°F. the exact reaction mechanism is not well un-
derstood because of the complexity of urea pyrolysis and
the subsequent free radical reactions; however, the over-
all reaction mechanism is:
CO(NH2)2
2NO + -O2
2N
CO
2H2O
(5-2)
Tests of urea-based SNCR on coal-fired boilers have
demonstrated reductions in baseline NOx emissions of
40 to 70% depending on the boiler type and urea feed.
stoichiometry (Hunt et al., 1993; Hoffman et al., 1993;
Nalco Fuel Tech ,1992).
63
-------
Hardware requirements for SNCR processes include
reagent storage tanks, air compressors, reagent injec-
tion grids, and an ammonia vaporizer (NH3-based SNCR).
Injection equipment such as a grid system or injection
nozzles is needed at one or more locations in the upper
furnace or convective passes. A carrier gas, such as
steam or compressed air, is used to provide sufficient
velocity through the injection nozzles to ensure thorough
mixing of the reagent and flue gas. For units that vary
loads frequently, multi-level injection is used.
To date, no full-scale demonstrations have occurred of a
combination of reburning and SNCR on utility coal-fired
boilers. The capital cost of the combined system antici-
pated to be approximately the sum of the costs of indi-
vidual technologies. The capital cost, busbar cost, and
cost effectiveness of stand-alone SNCR systems for 15
wall-, tangentially-, and cyclone-fired boilers are listed in
Table 5-1 (U.S. EPA, 1994). These are the same 15 boiler
models that were used previously in Table 4-3 as the
examples of reburn costs. The principal benefit to be
derived from combining SNCR and reburn technologies
would be to increase the overall NOx reductions with a
side benefit of reducing the total ammonia/urea consump-
tion.
Reburning With SCR
The SCR process involves injecting NH3 into boiler flue
gases in the presence of a catalyst to reduce NOx to N2
and water. The catalyst lowers the activation energy re-
quired to drive the NOx reduction to completion, and,
therefore, decreases the temperature at which the reac-
tion occurs. The overall SCR reactions are:
4NH, + 4NO + O, -» 4N0
6NO2->7N2
6H20
(5-3)
(5-4)
Undesirable reactions can occur in an SCR system, in-
cluding the oxidation of NH3 and SO2 and the formation
of sulfate salts. The reaction rates of both desired and
undesired reactions increase with increasing tempera-
ture. The optimal temperature range depends upon the
type of catalyst.
The SCR process has been demonstrated on U.S. utility
coal-fired boilers only at the pilot plant scale (Janik et
al., 1993; Huang et a!., 1993). These pilot plants treated
fuel gas from a slipstream equivalent to approximately 1
to 2 MW of generating capacity. The results indicate that
75 to 80% NOx reductions are possible with less than 20
ppm of ammonia slip.
The hardware for an SCR system includes the catalyst
material; the ammonia systemincluding a vaporizer,
storage tank, blower, valves, indicators, and controls; the
ammonia injection grid; the SCR reactor housing (con-
taining layers of catalyst); transition ductwork; and a con-
tinuous emission monitoring system. Anhydrous or di-
lute aqueous ammonia can be used; however, aqueous
ammonia is safer to store and handle.
The capital cost of a combination of reburning and SCR
is anticipated to be approximately equivalent to the sum
of the costs of the individual technologies. The capital
cost, busbar cost, and cost effectiveness of stand-alone
SCR systems for 15 wall-, tangentially-, and cyclone-
fired boilers are listed in Table 5-2 (U.S. EPA, 1994). The
principal benefit of combining SCR and reburn technolo-
gies would be a higher percentage reducing the ammo-
nia reduction of NOX emissions with a side benefit of
ammonia consumption relative to ammonia used in the
SCR system. Because SCR requires rigid operating con-
ditions on flue gas temperature and gas flow rate, the
operation of the SCR system could impose operating
restrictions on the reburn system that would limit its ef-
fectiveness. The ability of the combined systems to
produce a reduced NOx emission rate has been tested
only in Japan and is not being actively promoted by any
vendor at this time.
64
-------
Table 5-1. Costs for SNCR Applied to Coal-Fired Boilers
Plant Identification Total Capital Cost, $/kW
Busbar Cost, mills/kWh
Cost-Effectiveness, $/ton
Urea cost, $/ton
Wall-Fired Boilers'
1 00 MW, Peaking"
100MW, Baseload"
300 MW, Cycling"
300 MW, Baseload
600 MW, Baseload
Tangentially-Fired Boilers'
1 00 MW, Peaking
1 00 MW, Baseload
300 MW, Cycling
300 MW, Baseload
600 MW, Baseload
Cyclone-Fired Boilers"
1 00 MW, Peaking
1 00 MW, Baseload
300 MW, Cycling
300 MW, Baseload
600 MW, Baseload
140
14
14
10
10
9
14
14
10
10
g
14
14
10
10
9
200
14
14
10
10
9
14
14
10
10
9
14
14
10
10
9
260
14
14
10
10
9
14
14
10
10
9
14
14
10
10
9
140
5.47
1.54
1.78
1.25
1.14
5.23
1.35
1.57
1.06
0.95
6.18
2.10
2.40
1.81
1.71
200
5.86
1.85
2.12
1.56
1.45
5.53
1.59
1.83
1.29
1.19
6.84
2.63
2.98
2.34
2.23
260
6.25
2.16
2.46
1.86
1.76
5.83
1.83
2.09
1.53
1.43
7.50
3.16
3.56
2.87
2.76
140
2,160
760
800
610
560
2,660
860
910
670
610
1,460
620
650
540
510
200
2,320
910
950
770
720
2,810
1,010
1,060
820
760
1,620
780
800
690
660
260
2,470
1,070
1,100
920
870
2,960
1,160
1,210
970
910
1,780
940
960
850
820
Uncontrolled NO, levels of 0.90 Ib/MMBtu and a SNCR NO reduction of 45% were used for wall-fired boilers.
"Capacity Factor: Peaking . 10%, Baseload - 65%, and Cycling - 30%.
"Uncontrolled NO, levels of 0.70 Ib/MMBtu and a SNCR NO, reduction of 45% were used for tangentially-fired boilers.
"Uncontrolled NO, levels of 1.5 Ib/MMBtu and a SNCR NO, reduction of 45% were used for cyclone-fired boilers.
Source: U.S. EPA, 1994
65
-------
Table 5-2. Costs for SCR Applied to Coal-Fired Boilers
Plant Identification Total Capital Cost, $/kW
Busbar Cost, mills/kWh
Cost-Effectiveness, Si/ton
Catalyst life (yr)
Wall-Fired Boilers'
1 00 MW, Peaking"
100MW, Baseload"
300 MW, Cycling"
300 MW, Baseload
600 MW, Baseload
Tangentially-Fired Boilers'
1 00 MW, Peaking
1 00 MW, Baseload
300 MW, Cycling
300 MW, Baseload
600 MW, Baseload
Cyclone-Fired Boilers'1
1 00 MW, Peaking
1 00 MW, Baseload
300 MW, Cycling
300 MW, Baseload
600 MW, Baseload
2
110
110
86.0
86.0
75.0
106
106
83.0
83.0
72.0
117
117
90.0
90.0
78.0
3
110
110
86.0
86.0
75.0
' 106
106
83.0
83.0
72.0
117
117
90.0
90.0
78.0
4
110
110
86.0
86.0
75.0
106
106
83.0
83.0
72.0
117
117
90.0
90.0
78.0
2
43.4
7.16
13.1
6.34
6.02
42.6
6.97
12.8
6.18
5.88
44.5
7.53
13.5
6.65
6.31
3
37.1
6.19
11.0
5.36
5.04
36.3
6.00
10.7
5.21
4.90
38.3
6.56
11.4
5.68
5.34
4
33.9
5.70
9.91
4.88
4.56
33.1
5.51
9.66
4.72
4.42
35.0
6.07
10.3
5.19
4.85
2
9,650
1,990
3,300
1,760
1,670
12,200
2,490
4,160
2,210
2,100
5,940
1,260
2.040
1,110
1,050
3
8,250
1,720
2,770
1 ,490
1,400
10,400
2,140
3,480
1,860
1,750
5,090
1,090
1,720
947
890
4
7,540
1,580
2,500
1,360
1,270
9,470
1,970
3,140
1,690
1,580
4,670
1,010
1,560
866
809
Uncontrolled NO, levels of 0.90 Ib/MMBtu and a SCR NO, reduction of 80% were used for wall-fired boilers.
"Capacity Factor: Peaking = 10%, Baseload - 65%, and Cycling - 30%.
"Uncontrolled NO, levels ol 0.70 Ib/MMBtu and a SCR NO, reduction of 80% were used for langentially-fired boilers.
"Uncontrolled NO, levels of 1.5 Ib/MMBtu and a SCR NO, reduction of 80% were used for cyclone-fired boilers.
Source: U.S. EPA, 1994
66
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Chapter 6
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