FP A/600/A-96/11 3
Summary of the 1995 Joint Symposium on Stationary Combustion NOx Control
C. Andrew Miller
Charles B. Sedman
U.S. Environmental Protection Agency
National Risk Management Research Laboratory
Research Triangle Park, NC 27711
Abstract
The 1995 EPRI/EPA Joint Symposium on Stationary Combustion NOx Control was held May
16-19, 1995, in Kansas City, Missouri. A total of 65 presentations were made during the 4 days,
covering a wide range of topics related to the control of nitrogen oxide (NOx) emissions from
stationary combustion sources. The major areas discussed were regulatory development and
planning, coal combustion, reburning, tuning and control, oil and gas combustion, selective non-
catalytic reduction, selective catalytic reduction, and fundamentals and modeling. This paper
presents a summary of the information presented at the Symposium concerning application of NOx
control technologies to full- and pilot-scale systems.
Introduction
Emissions of nitrogen oxides (NOx) are important because of their role in a number of
pollution problems, including acid precipitation, formation of tropospheric ozone, visibility
reduction, and ambient concentrations of both nitrogen dioxide (NO2) and fine particulate matter
(fine PM). Stationary combustion sources are responsible for approximately half of the total NOx
emissions in the U.S.,1 and considerable efforts have been made to reduce these emissions,
primarily through the development and application of NOx control technologies. Since the late
1970s, the U.S. Environmental Protection Agency (EPA) and the Electric Power Research Institute
(EPRI) have cosponsored a series of biannual symposia dedicated to reporting the latest
information concerning NOx control technology development and application. In 1995, the 10th of
these symposia was held in Kansas City, Missouri, and attracted participants and attendees from
across the U.S., as well as from Europe and Japan. A total of 65 papers were presented during the
4-day meeting, covering a range of topics from fundamental chemistry to regulatory development,
with the majority of presentations focusing on the application and demonstration of full scale NOx
control technologies to coal fired utility boilers. Discussions of NOx control technologies for oil
and gas fired systems, industrial units, and tuning and optimization were also presented. This
paper provides a summary of the information presented at the 1995 Joint Symposium on Stationary
Combustion NOx Control.
Regulatory Development and Planning
The EPA's Office of Air Quality Planning and Standards is charged with development of
updated New Source Performance Standards (NSPS) for emissions of NOx from utility boilers.
This program process requires the gathering and analysis of information and the subsequent
development of the revised standards. Issues such as control technology effectiveness, annualized
costs, and cost per ton of pollutant removed are considered in the Agency's decision making. For
new units, combustion controls such as low NOx burners (LNBs) and overfire air (OFA) can
result in NOx removal costs of between $30 and $180/ton* of NOx removed, while selective
catalytic reduction (SCR) may cost as much as $1700 to $2700/ton of NOx removed.2
The availability of a number of NOx control technologies and the potential for trading
emissions between units give a utility a large number of choices to make regarding which control
strategy best suits their operating requirements in a cost effective manner. EPRI has supported the
* A table of English to metric conversion factors is provided in the Appendix.

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development of the Clean Air Technology (CAT) Workstation to provide computerized compliance
planning support to their member utilities.3 The CAT Workstation allows a utility to evaluate
emissions trading options, impacts of system expansion or outages, fuel switching, and other
options for a wide number of scenarios, providing the user with the capability to examine a much
more complete set of compliance choices.
Coal
A number of presentations were made on the topic of full-scale experience with LNB or other
NOx control system retrofits. Included was the retrofit of a LNB/SNCR (selective non-catalytic
reduction) system retrofit at two coal fired boilers, one rated at 86 MWe and the other at 155
MWe.4 Both units were wall-fired, and the second unit was also retrofit with a two-level OFA
system. On the small unit, NOx reductions from the LNBs were approximately 50%, with the
SNCR system providing an additional 40% reduction. The large unit showed maximum NOx
reductions with the LNB/OFA system of 42%, and an additional 33% reduction from the SNCR
system. In both cases, NOx reductions were lower at lower loads, and carbon in fly ash levels
ranged from 16 to 35%.
In one case, the retrofitting of new burners did not result in improved performance or lower
NOx emissions without the appearance of serious operational problems.5 Within 8 weeks of
beginning operation, one boiler suffered catastrophic nozzle failure on a 600 MWe tangentially
fired boiler. Investigation of the problem revealed that internal recirculation zones were occurring
under certain conditions, which led to accumulation of ash and eventually to fires inside the nozzles
themselves. A redesign of the nozzles eliminated the problem, and the system had operated over a
4-month period with little or no adverse damage to the nozzles, with adequate NOx reduction (over
50%) and boiler performance.
Not only does burner design provide low NOx emissions, but improved auxiliary system
design can also yield better performance. Such improvement was noted when steps were taken to
minimize "coal roping," which is the tendency for pulverized coal to concentrate in "ropes" within
the coal distribution piping rather than to be uniformly dispersed across the pipe,6 Minimizing the
roping in one tangentially fired unit resulted in a 60% decrease in the level of unburned carbon in
the fly ash. In addition, improvements in NOx reduction were noted in a tangentially fired system
by ensuring the attachment of the flame to the nozzle. NOx reductions of up to 50% were
demonstrated with this system, while maintaining pre-retrofit unburned carbon levels.
Another approach to low NOx combustion on tangentially fired boilers is to use burners
originally developed for wall fired boilers in the comers of the tangentially fired unit. The
Tangential Low NOx Burner (TLNB) system was demonstrated on a 310 MWe tangentially fired
unit, and resulted in a 44% NOx reduction compared to baseline conditions, with a slight reduction
in unburned carbon from 9.2 to 8,0%.7
Advanced utility combustion systems were discussed, including the TFS 2000R system
offered by ABB-Combustion Engineering.^ This system has been demonstrated on a 390 MWe
utility boiler using an eastern U.S. bituminous cod, and NOx emission rates of 0.25 lb/106 Btu
were demonstrated with no increase in unburned carbon. This was achieved using the TFS 2000R
system windboxes, which employ two levels of separated overfire air and one level of
close-coupled overfire air. Additional improvements to the plant included improved pulverizers
and classifiers to eliminate large (+50- or +70-mesh) particles. Potential minimum NOx emission
rates as low as 0.16 lb/106 Btu were noted during parametric testing.
A new approach to tangentially fired units was reported by Mitsubishi Heavy Industries
(MHI). MHI has tested a concept called Circular U-shaped Firing (CUF) as an improvement over
traditional tangential firing.9 CUF moves the fuel and air nozzles inward from the furnace comers,
and fires in such a manner to create a single swirling furnace flame, but within a much tighter
confinement. In combination with 40% OFA, CUF can produce NOx emissions as low as 70
ppmv at 4% oxygen (O2), with unburned carbon as low as 2%. This is in comparison to a
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conventional tangentially fired unit with 25% OFA, which emitted 130 ppmv NOx at 4% O2 and
had 8% unbumed carbon, using the same coal,
A further improvement in tangentially fired combustion systems was reported, specifically the
use of a new burner nozzle. The RI (Rapid Ignition) -Jet low NOx burner was developed by IVO
International, and relies on rapid ignition of the fuel near the nozzle tip to achieve NOx reductions
of between 50 and 75%, while maintaining unbumed carbon levels of below 5%.'0 The nozzle
modifications allow increased NOx reduction compared to a conventional tangentially fired burner
due to the high temperature reducing zone near the nozzle tip. The remaining combustion air is
provided by the secondary and tertiary air flows.
Rather than purchase new burners, modification of existing burners has also been evaluated for
cost and performance. Three wall-fired units, each 50 MWe in size, were used to evaluate burner
modifications.il The addition of staged flame stabilizers, staged coal spreaders, and modification
of the coal pipe to provide more uniform coal distribution were the primary modifications made. In
combination with air flow balancing, these modifications resulted in NOx emissions reductions of
up to 50% with no notable change in unbumed carbon. With the addition of OFA, NOx reductions
of up to 54% were demonstrated.
Information on the development and application of a low NOx burner for boilers using cell
burners was presented. Cell burner boilers were developed in the 1960s as an economic
improvement over previous boiler designs. However, these burners also resulted in high NOx
emissions. The Low NOx Cell Burner (LNCB) was developed by Babcock & Wilcox as a
replacement for these systems, and NOx reductions of 44 to 50% were demonstrated using the
LNCB design. 12 The LNCB used a close-coupled overfire air port in the same cell as the fuel port
to avoid the requirement for additional pressure part modification. In another approach, similar
NOx reductions were achieved through the use of a different burner design that does not employ
overfire air, but achieves the necessary staging through aerodynamic control of the air and fuel
flows. 13 Optimized operation with this unit maintained NOx at approximately 50% of the baseline
level while also reducing the level of carbon in the fly ash by 30% or more.
In addition to NOx reduction costs, utilities are also faced with the costs of other environmental
regulations, including disposal of solid and liquid wastes. One utility is evaluating the use of
coal-water slurries as a means of reducing NOx emissions while disposing of coal cleaning plant
waste coal. A coal-water slurry with 40-50% solids by weight was burned in a 32 MWe wall fired
boiler, using low NOx burners that can bum up to 40% of their fuel input as slurry. NOx
emissions reductions of up to 20% were noted with 35% slurry co-firing, with little or no
degradation in boiler performance.'4
The issue of contaminants in fly ash was a topic of considerable interest. Not only is the
carbon in fly ash important from a boiler efficiency perspective, it is also important in terms of the
salability of the fly ash. Excessive levels of carbon or other contaminants either significantly
reduce the value of the ash, or prevent its use as a raw material altogether.
One paper presented an approach for separating carbon from utility fly ash by the use of
electrostatic separation. 15 The described process produced cleaned ash at a rate of between 15 and
25 tons/hr, while reducing the average loss-on-ignition from 8.2 to 2.3%, resulting in an average
recovery of 83%.
Additional studies evaluated the absorption of ammonia (NH3) onto utility fly ash as a result of
NH3 and/or urea injection during SNCR or SCR operation. A parametric study was conducted of
NH3 absorption as a function of ash type, exposure time, temperature, and gas-phase NH3
concentration. 16 The most definitive results from this study showed that oil ashes were found to
absorb substantially more NH3 than coal ashes. A study of fly ash contaminated with NH3 found
that dry fly ash did not present any odor or other handling problems, and that product quality did
not suffer from ammonium concentrations of up to 300 10-6 lb/lb of ash. Products tested included
artificial gravel, concrete mortar, and concrete floors. The study did find that the presence of
moisture and mixing the ash led to increased odor problems.'7
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Reburning
In certain applications, the use of reburning is an attractive option for NOx control on both
utility and industrial boilers. Some operators have chosen reburning as a key NOx control
technology to avoid the installation of post-combustion systems such as SNCR or SCR.
Reburning has been applied to oil-, gas-, and coal-fired units, using various combinations of main
and reburning fuels.
In Italy, demonstrations of oil reburning over oil main fuel, gas reburning over oil main fuel,
and gas reburning over gas main fuel have been reported with successful results.'8 Two 320
MWe units were tested, and plans were described for a reburning application on a 660 MWe utility
unit. In all tests, reburning provided adequate reductions to meet the emission limit of 200
mg/Nm3, corrected to 3% O2.
New fuels and process enhancements have expanded the range of reburning application and
performance. Pilot-scale tests were reported for NOx reductions of up to 95% compared to
baseline emissions, using two injection stages for reburn fuel and additional reagents such as
urea.19 Reburning in combination with SNCR reagents can expand the SNCR temperature
window and reduce ammonia slip problems while improving the NOx control performance.
Additional work related to the use of coal and coal-water slurry as reburn fuels was also
presented.20 Different coal types and properties can result in significantly different NOx reduction
performance. Fuel nitrogen contents and volatilities were found to be particularly important to
reburning performance, with subbituminous and lignite coals showing better NOx reductions than
bituminous coals in general.
Field demonstrations of reburning were presented for a variety of utility boilers, including a
tangentially fired boiler, a cyclone boiler, and a wall-fired boiler, each with coal as a main fuel.21
Long term testing of these units demonstrated NOx reductions of 64 - 67% from the baseline
emissions. When using natural gas as the main fuel in combination with reburning, NOx
emissions reductions of up to 93% were demonstrated. In each case, flue gas recirculation was
used in combination with 10 -15% gas injection to achieve these reductions.
For industrial boilers, a reburning system was designed for a small coal-fired cyclone boiler
rated at 550,000 lb/hr of steam (approximately equivalent to 60 MWe) to reduce NOx emissions.
Design objectives were to reduce NOx emissions by at least 47% while maintaining carbon burnout
and low emissions of carbon monoxide (CO). Pilot-scale testing and computer modeling provided
the detailed design conditions, and long term performance testing is under way.22
Tuning and Control
A number of papers were presented on the topic of improving plant performance, including
NOx reductions, through system tuning and control. One method of performance optimization is
the use of constrained sequential optimization, which sequentially adjusts a set of boiler operating
parameters to achieve improved performance levels.23 In one unit, a 28% reduction in NOx
emissions was achieved with a simultaneous increase in the boiler efficiency of 3%.
Another approach to optimization uses artificial intelligence methods, specifically artificial
neural networks. The Generic NOx Control Intelligent System (GNOCIS) developed under EPRI
sponsorship has a goal of providing 10-35% reductions in NOx while maintaining or improving
other operational constraints.24 This system is designed to operate on a stand-alone workstation to
provide operating recommendations to the operator, or connected directly to the plant digital control
system in a closed-loop mode. The system is currently being tested at a 500 MW(e) wall-fired
boiler to determine its effectiveness.^ Neural networks have also been used to predict NOx
emissions from utility boilers based on design and operating parameters and coal properties.26
This system can help evaluate NOx control options at the preliminary design stage.
Relationships between various operating parameters, NOx emissions, fly ash loss-on-ignition
(LOI) levels, and heat rate were evaluated at Potomac Electric Power Company's Morgantown
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Station, also using artificial neural networks.2"? Key parameters affecting NOx and heat rate
include average OFA opening, economizer O2 level, burner and OFA tilt angles, mill loading
pattern, windbox pressure, and boiler cleanliness. Waterwall cleanliness was found to have a
substantial effect on both NOx and heat rate. The neural network is intended to provide plant
personnel with information for optimizing boiler operation. A similar system was also used at a
different Potomac Electric Power Company plant to provide operating information on optimum
performance of the combustion system.2§
Other advanced control techniques include the use of computers to evaluate the flame scanner
signals for indications of changing combustion conditions.The fluctuating component of the
flame scanner signal is highly sensitive to changes in combustion conditions, and can be used as an
input to a combustion control system. Such a control scheme can be used to ensure proper long
term performance of equipment following upgrades or repairs.30
In some cases, improved burner performance is achieved by going beyond the
recommendations of manufacturers. In many cases, burner manufacturers avoid modulation of the
air registers. In one series of tests, burner air registers were modulated to follow burner fuel flow
and OFA registers modulated to respond to NOx levels.31 These tests confirmed that responsive
and effective control of NOx, LOI, and heat rate could be maintained at acceptable levels using air
register control.
Oil and Gas Combustion
The approaches to NOx emissions reductions in oil- and gas-fired facilities differ in several
respects from those taken at coal fired plants. Allowable emission limits for oil- and natural-gas-
fired units are typically much lower than for coal. In addition, a key approach for gas fired units in
particular is the reduction of peak flame temperature to reduce the formation of thermal NOx. For
gas fired units, the use of flue gas recirculation (FGR) is a relatively common approach to flame
temperature reduction.
One burner which uses FGR as a fundamental part of its design is the Radian Rapid Mix
Burner, which has demonstrated NOx emissions below 10-ppmv (at 3% O2) in commercial
installations ranging in size from 5x106 to 130x106 Btu/hr. For one unit fitted with a 130xl06
Btu/hr burner, the use of 23-28% FGR resulted in NOx emissions of less than 9 ppmv (corrected
to 3% O2) over the full load range. CO emissions were maintained at less than 1 ppmv, and a
burner turndown ratio of 6:1 was demonstrated.32
Many utilities operate boilers that are capable of firing either oil or gas. An approach to lower
NOx emissions for such units without the use of either FGR or OFA was presented by AUS
Combustion Company and Hamworthy Combustion Engineering. Their AUS-DFL burner uses
aerodyamic staging of the burner fuel and air flows to create internal fuel staging and lower NOx
emissions. Full load NOx emissions from a 30 MWe unit during natural gas operation ranged
from 78 ppmv at full load to 45 ppmv at low load (both at 3% O2).33 These values represent
reductions of between 60 and 70% from the uncontrolled baseline emissions. No data were
presented for oil firing.
For oil units, NOx emissions can also be reduced by refinements to the oil atomization system
and flame stabilizer. By improving atomization and inducing a stable internal flame recirculating
zone, NOx emissions were reduced by between 23 and 43% from baseline levels.34 In some
cases, OFA and/or FGR were also necessary to achieve allowable emission limits; however, in all
cases the level of OFA and FGR required were significantly reduced using the optimized
equipment. Current designs use steam atomization, with mechanical atomizers currently being
tested.
A separate program developed an advanced steam atomizer for heavy fuel oil which resulted in
NOx emission reductions of up to 25% with no increase in particulate matter emissions.35 The
design has been demonstrated for burners with thermal ratings of up to 75 MW, and requires no
modifications to the burner or boiler beyond the installation of the new atomizer.
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For oil- and gas-fired units, there are a number of different approaches to reducing NOx
emissions. While many of these approaches are also available for coal fired units, they have been
more widely applied to oil- and gas-fired units due to a large degree to the lower allowable
emission limits and the closer proximity of oil- and gas-fired units to nonattainment areas. The
variety of approaches can make it difficult to identify the most cost effective methods of NOx
reduction. An Italian utility utilized computer modeling and cost analysis to evaluate the
effectiveness of a variety of NOx reduction approaches for both emissions reductions and cost
effectiveness.36 For a 320 MWe opposed-wall-fired unit burning either oil or natural gas, NOx
reductions of nearly 80% at fall load were required to meet the allowable emission limits. To meet
these limits, a number of approaches were evaluated, including FGR, OFA, gas rebuming, LNBs,
low NOx fuel atomizers, and SCR, as well as combinations of these technologies. Predicted
performance of various combinations determined that LNBs, FGR, and gas rebuming would
provide the most cost effective NOx control capable of meeting the allowable limits.
A further study of alternative approaches to NOx emissions for an oil/gas fired unit showed that
modified burners and the use of burners out of service (BOOS) would provide the most cost
effective NOx reductions at a 600 MWe tangentially fired unit.37 BOOS is achieved by supplying
only air through the upper row of burners, while operating the lower levels of burners in a fuel rich
manner. This results in a fuel rich combustion zone (which prevents the formation of fuel NOx
and reduces thermal NOx), then adding the necessary air to complete combustion through the upper
burners . In many cases, this results in a lower operating capacity, and may also increase
emissions of CO and particulate matter. However, substantial reductions of NOx may also be
v achieved, and proper tuning and operation can minimize adverse impacts. In combination with
new fuel atomizers and flame stabilizers, the use of BOOS is expected to bring NOx emissions to
below the 0.25 lb/106 Btu emission limit from the baseline rate of 0.3 lb/106 Btu.
Selective Non-Catalytic Reduction
Selective non-catalytic reduction (SNCR) is a post-combustion NOx control technology that
has been applied primarily in the past to incinerators and small industrial boilers, although stricter
emissions regulations have resulted in its application to utility boilers in recent years. SNCR
utilizes the injection of a nitrogen-based reagent into the post-combustion region of the furnace to
reduce the nitrogen oxide (NO) produced in the combustion zone to form molecular nitrogen.
SNCR is most often applied to units where combustion technologies such as LNB or rebuming
either cannot be applied or are too expensive due to unit-specific conditions, or to achieve lower
NOx emissions.
Wet-bottom boilers are a type of system where LNBs cannot be effectively applied. An
evaluation of SNCR to two coal-fired wet-bottom boilers showed NOx emission reductions of
between 30 and 40% from the baseline levels of 1.1-1.6 lb/106 Btu.38 Due to concerns over
potential heater fouling and the need to maintain low levels of NH3 in the fly ash for salability
purposes, NH3 slip targets were set at between 5 and 10 ppmv. A 163 MWe cyclone boiler
experienced fouling only during SNCR system startup, while the second unit, a 321 MWe wall-
fired wet-bottom boiler, experienced frequent air heater fouling. Optimization of the SNCR
systems is continuing in preparation for commercial operation.
Because the SNCR process is highly temperature dependent, the NOx reduction effectiveness
and NH3 slip can vary significantly with load. As a means to reduce performance variability,
retractable reagent injection lances can be used. By automatically rotating the injection lances in
response to furnace exit gas temperature, NOx reductions of between 30 and 50% can be achieved
while maintaining NH3 slip at levels below 10 ppmv.39 Although design optimization is required
for specific boilers, this technology has been successfully demonstrated at a 100 MWe wet-bottom
boiler and a 120 MWe cyclone unit.
A further improvement to application of the SNCR process is the addition of an NH3 analyzer.
This instrument provides real-time information to minimize NH3 slip by reducing reagent injection
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if NH3 slip is detected.40 Such a system reduces heater fouling, improves fly ash salability, and
prevents excessive NH3 slip, which can reduce the amount of reagent injected and ultimately the
cost of operation.
In addition to the use of NH3, aqueous urea can also be used as an SNCR reagent. A full-scale
demonstration of a urea-based SNCR system showed NOx reductions of greater than 50% with
NH3 slip levels of less than 20 ppmv. Reductions to 0.3 lb/106 Btu from a baseline of 0.7 lb/106
Btu were also demonstrated during short term testing, with an NH3 slip of less than 10 ppmv>1
Selective Catalytic Reduction
Selective catalytic reduction (SCR) is a post-combustion NOx control technology that is in
commercial use in the United States, Japan, and Western Europe on gas-, oil-, and coal-fired
boilers and a few municipal incinerators. With SCR, NH3 is added to the flue gas over a fixed
catalyst bed, wherein NOx is reduced to nitrogen and water vapor. Despite widespread use, SCR
applications to U.S. coals are hindered by uncertainties about costs and technical performance,
including:
(1)	potential catalyst deactivation by trace metal species in U.S. coals either not present, or
present at lower concentrations, in non-U.S. coals.
(2)	effects of higher sulfur dioxide (SO2) and sulfur trioxide (SO3) concentrations on SCR
performance and downstream plant equipment.
(3)	effects of catalyst composition, geometry and manufacturing method on ultimate SCR
performance.
To answer these questions, a number of SCR pilot plants have been constructed and test
programs initiated, as discussed in the following summaries.
Southern Company Services, Inc. and the U.S. Department of Energy (DOE) jointly
constructed and tested nine SCR reactors, three 2.5 MWe and six 0.2 MWe, on slipstreams from a
tangential boiler firing 3.0% sulfur coal.42 Test variables and ranges are:
Preliminary results show that N2O formation is negligible, but SO2 oxidation, NH3 slip, and
NOx reduction are strongly temperature and flow dependent. Of the seven catalysts tested, no
significant loss of activity was noted.
EPRI sponsored similar (1 MWe) slipstream pilot SCR tests at three U.S. locations, with the
following characteristics:43
Temperature, °F
NH3/NOx molar ratio
Space velocity, % of design flow
620-750
0.6-1.0
60-150
Flow Rate, scfm:
2.5 MWe reactor
0.2 MWe reactor
3000-7500
240-600
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Shawnee
Kintigh
Oswego
Fuel
2.5-5.0%S Coal
High Dust
1.5-2.5%S Coal
Low Dust
1.5%S Oil
Hot Side
Configuration
Flue gas flow, scfm
Reactor Temperature, °F
Inlet NOx, ppmv
Inlet SO2, ppmv
Inlet SO3, ppmv
Particle Cone., gr/dscf
2100
700
450
2000
20
3.0
2000
650
300
150
5
0.0012
200-1000
800
23
0.091
2000
700
For the TVA pilot SCR, both vanadium and zeolite catalysts showed significant loss of
activity, the zeolite catalyst failing to meet performance criteria after 5000 hours operation. The
vanadium catalyst activity dropped 36% after 22,000 hours due to plugging of pores by sulfated
fly ash deposits.
The Kintigh pilot SCR had operated for 21,000 hours, with both extruded and composite
vanadium-based catalysts showing minimal activity loss at 600-700 °F. Heat exchanger fouling
was alleviated by water washing of internal surfaces. Acid corrosion of heat exchangers was
identified as a concern.
The Oswego SCR unit operated 4800 hours. Catalyst activity increased with time, owing to
deposition of fresh vanadium on catalyst surfaces from the flue gas. Severe plugging and
deposition was observed. The composition of deposits points to magnesium compounds formed
as a result of magnesium oxide additive used in residual fuel oil to reduce SO3 formation.
Another study discussed results from an oil-fired 3 MWe slipstream SCR pilot unit, featuring
both catalyst bed and catalyst-coated air preheater SCR operation.44 The catalyst preheater
performed at 54% NO reduction and 24 ppmv NH3 slip at NH3/NO of 1.0. Catalyst plugging and
pressure drop were unacceptable without sootblowing. Sootblowing was judged adequate for
maintaining acceptable performance as long as SO3 and NH3 slip are maintained below 20 ppmv.
Visible plumes were not formed when SO3 and NH3 were below 10 ppmv.
SCR design using combined cold-flow modeling with an SCR process model was
discussed.45 SCR vendor design philosophies and operating experience were presented by
Siemens46 and Mitsubishi-Corning (Cormetech)4? in subsequent papers. The use of static mixers
and fluid dynamic models to solve SCR problems was also discussed by Siemens.4^
The last SCR paper4^ discussed troubleshooting of a commercial 110 MWe gas turbine, with
SCR designed to reduce NO from 30 to below 7 ppmv at 15% O2, but having excessive NH3 slip
of 47 ppmv. The problem was found to be inadequate mixing of NH3 upstream of the catalyst, and
was solved be relocating a redesigned NH3 delivery system farther upstream.
Hybrid SCR systems include either a combination of in-duct and air heater SCR or SNCR and
SCR. Six papers50-54 discussed various aspects of these technologies which can offer cost
savings on a very site specific basis. One such study compared in-duct SCR to air heater SCR and
hybrid SNCR/SCR on a 321 MWe coal fired facility.50 The in-duct SCR system was initially
found to remove 88% NO at 10 ppmv NH3 slip. By adding air heater SCR, performance was
improved to >95% NO control at 5 ppmv NH3 slip. The hybrid SNCR/SCR system achieved
90% NO reduction at <2 ppmv NH3 slip, but with NH3 injection at both furnace and catalyst. '
Additional details of the hybrid SNCR/SCR performance and system impacts were presented in a
subsequent paper.51 Mitsubishi reported similar experiences on two hybrid SNCR/SCR
applications.52
Smaller-scale results of SNCR/SCR research were reported on a 590 kW package firetube
boiler firing natural gas. At an NH3/NO of 2.0, the hybrid system removed 85% NO at 6 ppmv
NH3 slip.53
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References
1.	National Air Pollutant Emission Trends, 1900-1992, U.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC, EPA-
454/R-93-032 (NTIS PB94-152097), October 1993.
The remaining references are papers presented at the 1995 EPRI/EPA Joint Symposium on
Stationary Combustion NOx Control, May 16-19, 1995, Kansas City, MO.
2.	J. Eddinger, "Status of EPA Regulatory Development Program for Revised NOx New
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3.	W.A. Rosenquist, T. Facchiano, J. LeDuc, and R. Rhudy, "Phase II Positioning: Evaluating
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4.	G. Quartucy, A. Sload, G. Fynan, and R. Alfonso, "Lovr-NOx Burner and SNCR Retrofit
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5.	D.W. Forney, D.G. Murray, and P.R. Beal, "An Evolution of Nozzle Design: The Low
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6.	J.W. Allen and P.R. Beal, "Advanced Tangential Low NOx Systems - Development and
Results."
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Burner System on a Tangentially Fired Boiler."
8.	T. Buffa, D. Marti, and R.C. LaFlesh, "In-Fumace, Retrofit Ultra-Low NOx Control
Technology for Tangential, Coal-Fired Boilers: The ABB-CE Services TFS 2000 R
System."
9.	S. Kaneko, K. Tokuda, S. Sato, T. Gengo, and K. Sakamoto, "Low NOx Firing
Technology of Mitsubishi Heavy Industries."
10.	K. Savolainen and P. Demjatin, "Rl-Jet Burner for Reducing NOx Emissions in Tangentially
Fired Boilers."
11.	B. Owens, M. Hitchko, and R.G. Broderick, "Low NOx Modifications on Front-Fired
Pulverized Coal Fuel Burners."
12.	E. Mali, T. Laursen, and J. Piepho, "Commercialization of Low NOx Cell Burner (LNCB)
Technology."
13.	C.A. Penterson and S.A. Vierstrak "Alternative Solutions for Reducing NOx Emissions from
Cell Burner Boilers."
14.	T. Sommer, R. Ashworth, B. Folsom, T. Melick, and J. Battista, "Co-Firing Coal-Water
Slurry in Low NOx Burners: Experience at Penelec's Seward Station."
15.	D.R. Whitlock, "Separation and Recycling of Carbon in Ash."
16.	L.J. Muzio, E.N. Kim, M.A. McVickar, G.C. Quartucy, M. McElroy, and P. Winegar,
"Ammonia Absorption on Coal and Oil Fly Ashes."
17.	F.W. van der Brugghen, C.H. Gast, W.H. Kuiper, J.W. van den Berg, and R. Visser,
"Problems Encountered During the Use of Ammonium-Contaminated Fly Ash."
18.	G. De Michele et al., "Development and Industrial Application of Oil-Reburning for NOx
Emission Control in Utility Boilers."
19.	B. Folsom, R. Payne, D.K. Moyeda, V. Zamansky, and J. Golden, "Advanced Reburning
with New Process Enhancements."
20.	R. Payne, D.K. Moyeda, P. Maly, T. Glavcic, and B. Weber, "The Use of Pulverized Coal
and Coal-Water-Slurry in Reburning NOx Control."
21.	B. Folsom et al., "Three Gas Reburning Field Evaluations: Final Results and Long Term
Performance."
22.	H. Farzan et al., "Gas Reburn Retrofit on an Industrial Cyclone Boiler."
23.	R.J. Boyle, J.W. Pech, and P.D. Patterson, "Reducing NOx While Maintaining Boiler
Performance at TVA's Johnsonville Steam Plant Using Constrained Sequential
9

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Optimization."
24.	R. Holmes, I. Mayes, R. Irons, J.N Sorge, and J.W. Stallings, "GNOCIS: An Update of
the Generic NOx Control Intelligent System."
25.	J.N. Sorge, J.S. Allison, J.G. Noblett, and S.M. Smouse, "Wall-Fired Combustion
Demonstration Project - Advanced Digital Control/Optimization Phase Update,"
26.	D. Wildman and S. Smouse, "Estimation of NOx Emissions from Pulverized Coal-Fired
Utility Boilers."
27.	P. Maines et al., "Combustion Optimization of Low NOx Burners at PEPCO's Morgantown
Station."
28.	J. Pfahler et al., "NOx Advisor: Intelligent Software for Combustion Optimization."
29.	S.A. Johnson, C.L. Senior, M. Khesin, and A. Zadiraka, "Advanced Instrumentation for the
B&W Low Emission Boiler."
30.	S.A. Johnson and M.J. Khesin, "Maintaining Low NOx Emissions After Your Burner
Retrofit,"
31.	B.L. Smith and E.D. Kramer, "Modulating Control of Low NOx Burners."
32.	R.C. Christman, S.J. Bortz, D.E. Shore, and M. Brecker, "The Radian Rapid Mix Burner
for Ultra-Low NOx Emissions."
33.	M.E. Drumm, et al., "Introducing European Low NOx Burner Technology to the U.S.
Market."
34.	D.V. Giovanni, M.W. McElroy, and S.E. Kerho, "REACH: A Low-Cost Approach to
Reducing Stack Emissions and Improving the Performance of Oil-Fired Boilers."
35.	P. Baimbridge, M. Garwood, and A.R. Jones, "Development and Application of a Low
NOx, High Efficiency Atomiser for Oil and Emulsion Fuels,"
36.	P. Baimbridge, M. Garwood, A. Facchiano, and R. Pozzi, "Evaluation of the NOx
Reduction Potential of Various NOx Control Techniques on a 320 MWe Oil/Gas Fired
Boiler."
37.	A.E. Paschedag et al., "Reductions of NOx Emissions on Oil and Gas Firing at Bowline Unit
1"
38.	R. Himes, D. Hubbard, Z. West, and J. Stallings, "Summary of SNCR Applications to Two
Coal-Fired Wet Bottom Boilers."
39.	D.G. Jones et al., "Design Optimization of SNCR DeNOx Injection Lances."
40.	M.B. Frish, S.A. Johnson, J.M. Comer, R.F. Alfonso, and A. Sload, "Integrated NOx
Control at New England Power, Salem Harbor Station."
41.	J.E. Staudt, R.P. Casill, T.S. Tsai, and L.J. Ariagno, "Commercial Application of Urea
SNCR for NOx RACT Compliance on a 112 MWe Pulverized Coal Boiler."
42.	W.S. Hinton, J.D. Maxwell, and A.L. Baldwin, "Demonstration of Selective Catalytic
Reduction (SCR) Technology for the Control of Nitrogen Oxides (NOx) Emissions from
High Sulfur Coal-Fired Utility Boilers at Plant Crist SCR Test Facility."
43.	A.J. Mechtenberg et al., "Status of Testing of SCR Pilots: A Review of Current
EPRI-Sponsored Events."
44.	D.P. Texiera, F.J. Lorie, T.C. Fang, T.A. Montgomery, and K.D. Zammit, "Results of
Catalyst Tests at the PG&E/EPRI ASCR Pilot Plant."
45.	L.J. Muzio, T.D. Martz, T.C. Fang, and D.P. Texiera, "A New Design Tool for SCR
Systems."
46.	R. Sigling, A. Klatt, and H. Spielmann, "Various Types of SCR Plants Under Consideration
of Achievable NOx Removal Rate and Cost-Effectiveness of Catalyst Use."
47.	S. Pritchard et al., "Optimizating SCR Catalyst Design and Performance for Coal-Fired
Boilers."
48.	K. Hauenstein, W. Herr, and R.Sigling, "Fluid Dynamic Optimization of SCR Plants by
Modeling Demonstrated by the SCR Plant Logan Generating Plant."
49.	E.A. Mazzi and J.E. Johnson, "SCR Performance Evaluation and Troubleshooting on a
Natural Gas-Fired Source."
10

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50.	A.J. Wallace et al., "Selective Catalytic Reduction Performance Project at Public Services
Electric and Gas Company's Mercer Generating Station Unit No.2."
51.	A.J. Wallace et al„ "Evaluation of Combined SNCR/SCR for NOx Abatement on a Utility
Boiler."
52.	T. Fujino, S. Kaneko, K. Suyama, and T.R. Von Alten, "Experience and Condiseration of
SNCR-SCR Hybrid System."
53.	P.W. Groff and B.K. Gullett, "Industrial Boiler Retrofit for NOx Control: Combined
Selective Non-Catalytic Reduction and Selective Catalytic Reduction."
54.	T. Jantzen and K. Zammit, "Hybrid SCR."
Appendix
English Engineering to Metric Conversion Table
(°F - 32) x 0.5556 =	
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1MR MR T -PTD- P-i/i TECHNICAL REPORT DATA
iNrxivixxJ-^ rx x. r sr l<± o (Please rend ImUuctions on the reverse before completing
—
1. REPORT NO. 2.
EPA/600/A-96/113
3. RE
A. TITLE AND SUBTITLE —	
Summary of the 1995 Joint Symposium on Stationary
Combustion NOx Control
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C. Andrew Miller and Charles B. Sedman
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
See Block 12
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
NA (Inhouse)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Published paper: 5/16-19/95
14. SPONSORING AGENCY CODE
EPA/600/13
16,supplementary notes appcd priject officer is C. Andrew Miller, Mail Drop 65, 919/
541-2920. Presented at The First U. S.-Ukrainian Conference on Thermal Power Sta-
tion Air Pollution Control Technology, Kiev, Ukraine, 9/9-10/96.
16. abstract paper summarizes the 65 presentations at the May 16-19,1995, Joint
Symposium on Stationary Combustion NOx Control, in Kansas City, MO. The presen-
tations covered a wide range of topic related to the control of nitrogen oxide (NOx)
emissions from full- and pilot-scale stationary Combustion sources. The major
areas discussed were regulatory development and planning, coal combustion, rebur-
ning, tuning and control, oil and gas combustion, selective noncatalytic reduction,
selective catalytic combustion, and fundamentals' and modeling.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. descriptors
b.identifiers/open ended terms
c. COSATl Field/Gioup
Pollution Catalysis
Nitrogen Oxides Mathematical Model-
Emission ing
Coal
Fuel Oil
Natural Gas
Combustion
Pollution Control
Stationary Sources
Reburning
Tuning and Control
13 B 07D
07B
14G 12A
21D
21R
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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