CONTROL OF NO% EMISSIONS FROM
U.S. COAL-FIRED ELECTRIC UTILITY BOILERS
R.K. Srivastava and R.E. Hall
U.S. Environmental Protection Agency
Office of Research and Development
National Risk Management Research Laboratory
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
Prepared for:
All-Russian Thermal Engineering Institute (VTI) 80th Anniversary Conference
Moscow, Russia, October 9-10, 2001
ABSTRACT
Recently, several regulations have been promulgated in the U.S. requiring reductions in
emissions of nitrogen oxides (NOx) from electric utility boilers. To comply with these
regulations, state-of-the-art NOx control technologies have been applied to a large number of
coal-fired U.S. utility boilers. This paper reviews these technologies and their applications.
In general, NOx control technologies are categorized as being either primary control
technologies or secondary control technologies. Primary control technologies reduce the
formation of NOx in the primary combustion zone. In contrast, secondary control technologies
destroy the NOx present in the flue gas from the primary combustion zone. Primary control
technologies being used in the U.S. are low NOx burner (LNB) and overfire air (OFA). Data
reflect that these technologies have been used on 177 boilers and have resulted in NOx reductions
between 33 and 48 percent, on average, from 1990 emissions levels.
The secondary NOx control technologies in use on U.S. coal-fired utility boilers include
reburning, selective non-catalytic reduction (SNCR), and selective catalytic reduction (SCR).
More than 100 boilers either have used, or will use, these technologies to achieve the desired
NOx reductions. The NOx reductions achieved, or projected, at these applications range from 20
to more than 80 percent. In the last 3 years, SCR has been chosen as the preferred secondary
technology at numerous U.S. coal-fired utility boilers. Current data indicate that 79 boilers either
use, or will use, SCR for NOx control.
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INTRODUCTION
Emissions of nitrogen oxides (NOx) are associated with a variety of environmental
concerns including increasing ground level ozone, formation of acid rain, acidification of aquatic
systems, forest damage, degradation of visibility, and formation of fine particles in the
atmosphere.1 Such concerns have resulted in a need to reduce these emissions in the United
States (U.S.) and elsewhere. In order to implement controls efficiently, it is important to
determine which sources are significant emitters of NOx. Shown in Figure 1 is the contribution to
NOx emissions in 1997 from each of the applicable source categories in the U.S.2 It is evident
from these data that stationary combustion sources (electric utility, industrial, and other
combustion sources) accounted for a significant portion, about 45 percent, of these emissions.
Moreover electric utilities accounted for about 26 percent of NOx emissions and comprised the
largest emitting source category within stationary sources. Based on these data, reduction of NOx
emissions from stationary sources, particularly electric utility sources, needs to be considered in
efforts undertaken to address the environmental concerns associated with NOx.
Recently, a number of regulatory actions have been taken in the U.S., focused on
reducing NOx emissions from stationary combustion sources. These actions include the Acid
Rain NOx regulations3'4, the Ozone Transport Commission's NOx Budget Program5, revision of
the New Source Performance Standards (NSPS) for NOx emissions from utility sources6, and the
Ozone Transport rulemakings7.
Control technology applications necessarily play a key role in the formulation and
implementation of air pollution reduction strategies. The current focus on reduction of NOx from
stationary combustion sources establishes a need to review current information on pertinent
control technologies. This paper reviews the technologies for controlling NOx from coal-fired
power plants. The review not only includes the established commercial technologies that are
being used in the U.S., but also examines those that can be considered to be relatively new or in
an advanced stage of development. There are several reasons for focusing this review on coal-
fired power plants. First, data are available from technology applications at such plants. Second,
it is more cost-effective to control NOx from large sources and, as such, it is expected that the
technologies would be applied to such sources. Third, based on data in Reference 2, coal-fired
power plants account for approximately 90 percent of the NOx emissions from the U.S. electric
utility industry.
It is expected that this review will be useful to a broad audience including;(l) individuals
responsible for developing and implementing NOx control strategies at sources, (2) persons
involved in developing NOx and other regulations, (3) state regulatory authorities implementing
NOx control programs, and (4) the interested public at large. Moreover, persons engaged in
research and development (R&D) efforts aimed at improving the cost-effectiveness of controls
may also benefit from this review. Finally, this review will also be useful for technology
applications on large coal-fired industrial boilers, which are quite similar to electric utility
boilers.
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REGULATORY OVERVIEW
The 1990 Clean Air Act Amendments (CAAA)8 authorize EPA to establish standards for
a number of atmospheric pollutants, including NOx. Two major portions of the CAAA relevant to
stationary source NOx control are Titles I and IV. Title 1 established National Ambient Air
Quality Standards (NAAQS) for six criteria pollutants, including ozone. Title IV includes
provisions designed to address acid deposition resulting from emissions of NOx and sulfur
dioxide (S02) from electric power plants. Table 1 presents an overview of the regulatory actions
affecting NOx sources. NOx reduction requirements under Titles I and IV are discussed below.
Title I NOx Requirements
Title I of the CAAA of 1990 included provisions designed to address both the continued
nonattainment of the existing ozone NAAQS and the transport of air pollutants across state
boundaries. These provisions also allow downwind states to petition for tighter controls on
upwind states that contribute to their NAAQS nonattainment status. In general, Title I NOx
provisions require: (I) existing major stationary sources to apply reasonably available control
technologies (RACT); (2) new or modified major stationary sources to offset their new emissions
and install controls representing the lowest achievable emissions rate (LAER); and (3) each state
with an ozone nonattainment region to develop a State Implementation Plan (SIP) that, in some
cases, includes reductions in stationary source NOx emissions beyond those required by the
RACT provisions of Title I.
Ozone Transport Commission (OTC) NOx Budget Program5. Section 184 of the CAAA
delineated a multi-state ozone transport region (OTR) in the northeast and required specific
additional NOx and volatile organic compound (VOC) controls for all areas in this region.
Section 184 also established the OTC for the purpose of assessing the degree of ozone transport
in the OTR and recommending strategies to mitigate the interstate transport of pollution. The
OTR consists of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New
Jersey, New York, Pennsylvania, Rhode Island, Vermont, parts of northern Virginia, and the
District of Columbia. The OTR states confirmed that they would implement RACT on major
stationary sources of NOx (Phase I), and agreed to a phased approach for additional controls,
beyond RACT, for power plants and other large fuel combustion sources (Phases II and III). This
agreement, known as the OTC Memorandum of Understanding (MOU) for Stationary Source
NOx Controls was approved on September 27, 1994.9 All OTR states, except Virginia, are
signatories to the OTC NOx MOU.
The MOU establishes an emissions trading system to reduce the costs of compliance with
the control requirements under Phase II (which began on May 1, 1999) and Phase HI (beginning
on May 1, 2003). The OTC program caps summer-season (May 1 - September 30) NOx
emissions for all 13 OTC jurisdictions at approximately 219,000 tons in 1999, and 143,000 tons
in 2003, which represent approximately 55 and 70 percent reductions in NOx, respectively, from
the 1990 baseline emission level of 464,898 tons. The actual reductions during the 1999 season,
however, reflect participation by only 8 of the 13 jurisdictions. This subset includes Connecticut,
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Delaware, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, and Rhode
Island.
NOx SIP Call1. To address the long-range transport of ozone, in October 1998, EPA
promulgated a rule to limit summer-season NOx emissions in 22 Northeast states and the District
of Columbia that the Agency believes are significant contributors to ozone non-attainment in .
downwind areas. These states were required to amend their state implementation plans (SIPs)
through a procedure established in Section 110 of the CAAA. EPA finalized a summer-season
state NOx budget (in tons of NOx) and developed a state implemented and federally enforced NOx
trading program to provide for emissions trading by certain electric and industrial stationary
sources. The state N0X budget is based on the application of a population-wide 0.15 lb/106 Btu
NOx emission rate for large electricity generating units (EGUs) and a 60 percent reduction from
uncontrolled emissions for large non-EGUs. The NOx SIP call is projected to reduce summer-
season NOx emissions by 1.1 million tons in the affected 22 slates and DC. In response to
litigation, on March 3, 2000, the D.C. Circuit Court issued its decision on the NOx SIP call,
ruling in favor of EPA on all major issues, including the findings of significant contribution by
the 23 states and the emissions reductions that must be achieved. On August 30, 2000, the D.C.
Circuit Court extended the deadline for the full implementation of the NOx SIP call from May 1,
2003, to May 31, 2004.
Section 126 Petitions10 In addition to promulgating the NOx SIP call, EPA responded to
petitions filed by eight Northeastern states under Section 126 of the CAAA. The petitions request
that EPA make a finding that NOx emissions from certain major stationary sources significantly
contribute to ozone nonattainment problems in the petitioning states. The final Section 126 rule
requires upwind states to take action to reduce emissions of NOx that contribute to nonattainment
of ozone standards in downwind states. The findings affect large EGUs and both non-EGU
boilers and turbines located in 12 northeast states and the District of Columbia. Like the NOx SEP
call, EPA has finalized a federal NOx Budget Trading Program based on the application of a
population-wide 0.15 lb/106 Btu NOx emission rate for large EGUs and a 60 percent reduction
from uncontrolled emissions for large non-EGUs. The final Section 126 actions are projected to
reduce summer-season NOx emissions by 510,000 tons in the 12 affected states and D.C. The
compliance deadline is May 1, 2003.
Title IV NOx Requirements
Title IV of the CAAA authorized EPA to establish an Acid Rain Program to reduce the
adverse effects of acidic deposition on ecosystems, natural resources, materials, visibility, and
public health. Emissions of S02 and NOx from the combustion of fossil fuels are important
contributors to acidic deposition from the atmosphere. Title IV includes provisions designed to
address NOx emissions from existing power plants.
Acid Rain NOx Reduction Program3'4. Under Title IV of the CAAA, the Acid Rain
Program uses a two-phased strategy to achieve the required annual reductions in NOx emissions.
Effective January 1, 1996, Phase I established regulations for "Group 1" boilers, which include
dry-bottom, wall-fired boilers, and tangentially fired (T-fired) boilers. In Phase II, which began
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on January 1, 2000, lower emissions limits are set for certain Group 1 boilers, and regulations are
established for Group 2 boilers, which include cell-burner, cyclone, and wet-bottom, wall-fired
coal-fired boilers. The regulations allow for emissions averaging in which the emissions levels
established by EPA are applied to an entire group of boilers owned or operated by a single
company.
By January 2000, the Acid Rain Program required annual average emission rates of 0.46
lb/106 Btu for dry-bottom wall-fired boilers and 0.40 lb/106 Btu for tangentially fired boilers. The
limits are 0.68 lb/106 Btu for cell burners, 0.86 lb/106 Btu for cyclones greater than 155 MWC,
0.84 lb/106 Btu for wet-bottom boilers greater than 65 MWe, and 0.80 ib/106 Btu for vertically
fired boilers. The Phase I compliance results for 1996 show that, from 1990 to 1996, the overall
NOx emission reductions for the affected boilers totaled about 340,000 tons; i.e., a reduction of
33 percent. In Phase II, approximately 1.17 million tons per year of NOx reductions are projected
to result from the Acid Rain NOx Program requirements.
New Source Performance Standards (NSPS)6. Under the CAAA, new power plants are
subject to NSPS that represent maximum allowable emission rates and are based upon the best
adequately demonstrated technology. EPA promulgated a revised NSPS for fossil-fuel-fired
utilities in 1998. The new standards revise the NOx emission limits for steam generating units
and affect only units for which construction, modification, or reconstruction commenced after
July 9, 1997. The NOx emission limit in the final rule is 201 nanograms per joule (ng/J) [1.6
lb/megawatt-hour (MWh)] gross energy output regardless of fuel type. For existing sources that
become subject to regulation through modification or reconstruction, the NOx emission limit is
0.15 lb/106 Btu heat input. The estimated decrease in baseline nationwide NOx emissions is
25,800 tons per year, which represents about a 42 percent estimated reduction in growth of NOx
emissions from new utility and industrial steam generating units subject to NSPS.
NOx FORMATION IN COMBUSTION
Before examining the control technologies, it would be helpful to review the mechanisms
of NOx formation in combustion. These mechanisms form the basis for practical NOx control
strategies, particularly those based on modification of the combustion process. NO is formed
during most combustion processes by one or more of three chemical mechanisms' '12,13: (1)
"thermal" NOx resulting from oxidation of atmospheric molecular nitrogen14, (2) "fuel" NOx
resulting from oxidation of chemically bound nitrogen in the fuel, and (3) "prompt" NOx
resulting from reaction between atmospheric molecular nitrogen and hydrocarbon radicals.
Figure 2 depicts a simplified picture of the major reaction pathways for NOx formation and
reduction in combustion.
In fuel-lean combustion of nitrogen-free fuels, thermal NOx is the primary component of
NOx emissions. Thermal NOx formation is quite sensitive to temperature and can be controlled
by appropriately controlling peak temperature in the furnace. In fuel-lean combustion of fuels
containing nitrogen (e.g., coal), fuel NOx contributes significantly to total NOx emissions,
depending on the weight percent of nitrogen in the fuel.15 Formation of fuel NOx depends on the
availability of oxygen to react with the nitrogen during coal devolatilization and the initial stages
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of combustion. Under fuel-rich conditions, the formation of NOx may compete with the
formation of molecular nitrogen (N2) and may result in a reduction of NOx emissions. Prompt
NOx contributes a relatively minor fraction of total NOx emissions for both nitrogen-free and
nitrogen-containing fuels.
The factors identified above that dictate NOx formation (devolatilization of fuel-bound
nitrogen, oxygen concentration, and flame temperature) can all be adjusted by controlling the rate
at which the fuel and air mix or staging the combustion process such that an initial fuel-rich zone
is followed by a burnout zone that is high in oxygen to complete the combustion process, but low
enough in temperature to minimize thermal NOx production. Combustion modification NOx
controls utilize this combustion staging.
NOx CONTROL TECHNOLOGIES
In general, NOx control technologies may be placed in two general categories: primary
control technologies and secondary control technologies. Primary control technologies reduce
the amount of NOx produced in the primary combustion zone. In contrast, secondary control
technologies reduce the N0X present in the flue gas from the primary combustion zone. Some of
the secondary control technologies actually employ a second stage of combustion, such as
reburning.
Primary Control Technologies
In the U.S., popular primary control technologies are low NOx burners (LNB) and
overfire air (OFA). These technologies utilize staged combustion techniques to reduce NOx
formation in the primary combustion zone. LNB and OFA are described below.
Widely Used Primary Control Technologies
LNB16,17. A LNB limits NOx formation by controlling the stoichiometric and
temperature profiles of the combustion process. This control is achieved by design features that
regulate the aerodynamic distribution and mixing of the fuel and air, thereby yielding one or
more of the following conditions: (1) reduced oxygen in the primary flame zone, which limits
fuel NOx formation; (2) reduced flame temperature, which limits thermal NOx formation; and (3)
reduced residence time at peak temperature, which limits thermal NOx formation. In general,
LNBs attempt to delay complete mixing of fuel and air mixing as long as possible, within the
constraints of furnace design. This is why the flames from LNBs are usually longer that those
from conventional burners. The gradual mixing of the combustion air to a fuel-rich flame core is
shown schematically in Figure 3. The hardware used to influence the fuel/air mixing varies from
manufacturer to manufacturer. LNBs can provide NOx reductions in excess of 50 percent from
uncontrolled levels.
Overfire Air (OFA)16'17. OFA, also referred to as air staging, is a combustion control
technology in which a fraction, 5 to 20 percent, of the total combustion air is diverted from the
burners and injected through ports located downstream of the top burner level. OFA is generally
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used in conjunction with operating the burners at a lower-than-normal air-to-fuel ratio, which
reduces NOx formation. The OFA is then added to achieve complete combustion. OFA can be
used in conjunction with LNBs. The addition of OFA to LNB may increase the reductions by an
additional 10 to 25 percent.
Primary control technologies, described above, have been widely implemented on U.S.
coal-fired utility boilers to comply with the NOx emissions reduction requirements of Phase I of
the Title IV NOx Program. Table 2 provides a summary of primary control applications through
1998.18 These data reflect that primary control technologies have been applied on 177 boilers and
have resulted in reductions ranging from 33 to 48 percent, on average, from 1990 emissions
levels. In particular, applications of LNB resulted in reductions of greater than 40 percent, on
average, from 1990 levels.
Recently, advances have been made in primary control technologies aimed at providing
greater NOx reduction. These advances are described below.
Advances
LNB with Multi-level OFA. A concentric firing system with multi-level OFA is now
available for tangentially fired boilers. This system incorporates deep air staging to achieve
significantly lower NOx emissions. This combustion technology has achieved NOx emissions
under 0.15 lb/106 Btu while firing Powder River Basin (PRB) subbituminous coal19, which
reflects the potential for achieving low NOx emissions with this technology. Note, however, that
for other coals that are lower in fuel volatile content than PRB coals (e.g., eastern bituminous
coals) higher NOx emissions may be expected with this technology.
Rotating Opposed Fire Air (ROFA)20. The ROFA design injects air into the furnace first
to break up the fireball and then to create a cyclonic gas flow to improve combustion. The
difference between ROFA and conventional OFA is that ROFA utilizes a booster fan to increase
the velocity of air to promote better mixing and to increase the retention time in the furnace.
Specific advantages of ROFA include more even distribution of combustion products, less
temperature variation across the furnace, and less excess air needed for complete combustion.
The technology has been installed on a 175 MWC boiler, and NOx reduction obtained has been
over 50 percent.
For many coal-fired boilers, it may not be possible to achieve sufficiently low NOx
emissions to comply with existing or future NOx regulations by using primary measures alone.
These units may require additional primary controls and/or secondary controls for future NOx
compliance. Described below are the secondary control technologies applicable to coal-fired
electric utility boilers.
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Secondary Control Technologies
In the U.S., popular secondary control technologies are reburning, selective catalytic
reduction (SCR), and selective non-catalytic reduction (SNCR). These technologies are described
below.
Widely Used Secondary Control Technologies
Reburning 21'22. In reburning, between 15 and 25 percent of the total fuel heat input is
provided by injecting a secondary (or reburning) fuel above the main combustion zone to
produce a slightly fuel-rich reburn zone with a stoichiometry of about 90 percent theoretical air.
Combustion of reburning fuel at fuel-rich conditions results in hydrocarbon fragments, which
react with a portion of incoming NOx to form hydrogen cyanide (HCN), isocyanic acid (HNCO),
isocyanate (NCO), and other species. These species then pass through an amine (NHj) + carbon
monoxide (CO) step, and the NH, is ultimately reduced to N2. Finally, completion air is added
above the reburn zone to complete burnout of reburning fuel. Reburning reaction pathways are
shown in Figure 2, and a reburning application is schematically shown in Figure 4.
Boiler size, in particular furnace height, can have an impact on one of the key design
parameters - gas residence time within the reburn and burnout zones - responsible for a
successful reburning application. Sufficient residence time is required to achieve adequate flue
gas mixing and to accommodate the NOx reduction kinetics in the reburning zone, and for
complete combustion in the bumout zone. Given sufficient time in the reburn zone, reburn zone
stoichiometry is another critical parameter that influences NOx reduction. However, reburn zone
stoichiometry is directly related to the heat input split between the primary and reburn zones. In
general, an increase in the reburn heat input and a commensurate decrease in primary heat input
will decrease the stoichiometry in the reburn zone and improve the NOx reduction efficiency.
However, this heat splitting is constrained by flame stability considerations in the primary and
reburn zones, the potential for unacceptable levels of CO emissions resulting from addition of
relatively large amounts of reburn fuel, and the potential for increased boiler tube corrosion
within the reburn zone. In addition to the above considerations, the temperature at the point of
burnout air addition can place a lower limit on the achievable NOx due to reformation of thermal
NOx.
The choice of the reburning fuel is determined largely by fuel availability, a balancing
of operating costs versus capital costs, and the specifics of the boiler. If natural gas is available
on site, it may be used as the rebuming fuel, depending on the price of gas with respect to other
fuels such as coal and oil. Compared to natural gas reburning (NGR), coal reburning requires a
relatively longer residence time through the reburn zone and a larger upper furnace to achieve
adequate bumout. Further, coal reburning requires addition of dynamic pulverizers to produce
reburning fuel grade coal. Micronized coal (i.e., coal pulverized to a very high fineness) may be
used as a reburning fuel on some boilers that may not have enough volume for normal coal
reburning. However, micronized coal reburning requires specialized coal processing equipment,
which increases its cost over gas or conventional coal reburning. In addition, for any coal
reburning system it is necessary to use recirculated flue gas as the reburning fuel carrier.
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The first application of reburning technology to a wet-bottom, wall-fired unit was to the
300 MWC Ladyzhin plant in Ukraine. This application demonstrated that 50 percent NOx
reduction was achievable with natural-gas-based reburning technology on wet-bottom, wall-fired
boilers. In general, reburn technology has demonstrated greater than 50 percent NOx reduction on
several coal-fired boiler types such as cyclone-fired, dry-bottom wall-fired, and wet-bottom wall-
fired.23,24
Table 3 presents the reburning applications at coal-fired utility boilers. As seen in this
table, 16 utility boilers worldwide and 14 in the U.S. have either used, or will use, reburning as
their secondary NOx control technology. The NOx reductions at these boilers either achieved or
expected to be achieved range from 39 to 67 percent. The largest application of reburning is at
Southern Company's 818 MWe Shearer Unit 1, which utilizes coal rebuming. This application
started in 2001.25 The largest application of NGR is at Scottish Power's -600 MW,. Longannet
Unit 2.26 EPA is currently participating in a demonstration of a multifuel reburn system (gas, oil,
and/or coal) on a 300 MWe wet-bottom wall-fired boiler in Ukraine.
*70 "77 09,
SNCR . SNCR is a postcombustion technology in which a reagent (ammonia or
urea) is injected into the furnace above the combustion zone, where it reacts with NOx to reduce
it to N2 and water. In general, SNCR reactions are effective in the range of 980 to 1150 °C. The
high temperature necessary for the reaction to proceed requires that the reagent normally be
injected into the boiler's upper furnace region, as shown in Figure 5, Although the actual
reactions are more complex, the overall stoichiometric reactions for urea and ammonia SNCR
are:
(NH2)2CO + 2NO + 1/2 02 2H?0 + C02 + 2N2	(1)
2NH3 + 2NO +l/2 02-> 2N2 + 3H20	(2)
After being injected into hot flue gas, urea decomposes into ammonia, which participates
in SNCR chemistry. In general, ammonia may reduce NOx, oxidize to form NOx, or remain
unreacted and pass through the stack. This unreacted portion is referred to as ammonia slip.
Inadequate flue gas temperature and/or reaction time for SNCR kinetics, and mixing of the
reagent with flue gas can contribute to an increase in ammonia slip. Relatively high
concentrations of ammonia slip can react with S02 and sulfur trioxide (SO3) in the flue gas and
form ammonium sulfates and bisulfates which, in turn, can cause plugging of the air preheater
passages. Furthermore, ammonia slip can also reduce the marketability of flyash by making it
odorous. For these reasons, ammonia slip is normally well controlled through proper
specification, design, and operation of an SNCR system.
Although the dominant reactions in the SNCR process result in reduction of NO to
nitrogen, a significant competing reaction is the oxidation of the SNCR reagent to form NOx.
This oxidation reaction becomes more significant as temperature is increased. Because of this
competing oxidation reaction, there is not a one-to-one relationship between reagent injected and
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N0X reduced. It typically requires more urea or ammonia to reduce NOx than is suggested by the
stoichiometric equations above.
A common misunderstanding of the SNCR process is that the reagent must be injected
into the flue gas where the gas is between 980 and 1150 °C. Because of this misconception, in
the past it was believed that SNCR could not be used on cyclone- of wall-fired wet-bottom
boilers. However, commercial SNCR systems on these boiler types exist today.22 In fact, most
electric utility SNCR systems operate effectively with reagent injection where gas temperatures
are above 1150 °C. In such cases, sufficiently high initial NOx concentrations cause the reduction
kinetics to still dominate over the oxidation kinetics. Also, the reactions normally occur
downstream of the injection location, after some cooling of the flue gas. At the low end of the
SNCR temperature range, below 980 °C, the SNCR kinetics becomes slow. Nevertheless, there
are applications on fluidized bed combustors where sufficient mixing time is available at these
temperatures for the SNCR reactions to reach completion, and result in high levels of NOx
reduction with low levels of ammonia slip.
Urea and ammonia reagents require different injection approaches. Urea reacts over a
somewhat broader and slightly higher temperature range than ammonia (about 55-83 °C higher),
making it somewhat more compatible with the temperatures found in most utility furnaces.
Further, reagent droplets containing urea penetrate well into flue gas before complete
vaporization. In general, this results in improved mixing of the reagent in large flue gas volumes
compared to that possible with ammonia injection. Finally, safety associated handling of urea
handling may be more acceptable than that associated with handling of ammonia. For these
reasons, urea is the preferred reagent in current SNCR applications on utility boilers.
Boiler load changes can impact the performance of an SNCR application due to changes
in two key parameters: temperature of flue gas at the furnace exit and gas residence time in the
furnace. Two measures are usually included in the design of SNCR systems, namely :(1) a multi-
level injection system, and (2) an ability to change the amount of reagent to be injected. It is not
unusual for an SNCR system on a load-following boiler to have three injection zones, each with
several in jectors. Since each of these injection zones is switched on and off automatically by the
plant's control system, this does not add complexity to plant operation.
SNCR has been applied in the U.S. on a wide variety of boilers firing a range of fuels.
Table 4 shows SNCR applications on electric utility boilers in the U.S.29 As boiler size increases,
the capability to uniformly distribute a chemical reagent, urea or ammonia, throughout the
furnace volume may diminish, and, therefore, may negatively impact NOx removal efficiency.
Data in Table 4 show that, while smaller boilers (e.g., Salem Harbor) may be able to achieve
greater than 40 percent NOx reduction, larger boilers (e.g., Cardinal) may be capable of achieving
reductions of only 30 percent or less.
SCR22,30. SCR is a postcombustion NOx reduction technology in which ammonia is
added to the flue gas, which then passes through layers of a catalyst. The ammonia and NOx react
on the surface of the catalyst, forming N2 and water. SCR reactions are generally effective in a
temperature range of 350 to 400°C. In general, SCR is capable of providing high levels of NOx
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reduction, ranging from 80 to greater than 90 percent. The overall stoichiometric SCR reactions
are:
2NH3 + 2NO + 1/2 02-> 2N2 + 3H20	(3)
4NH3 + 2N02 + 02 -> 3N2 + 6H20	(4)
In most utility boiler applications, the catalyst is installed in a separate reactor positioned
downstream of the boiler economizer and immediately upstream of the air preheater (see Figure
6). Under low-load conditions, an economizer bypass is sometimes utilized to ensure proper flue
gas temperature at the SCR reactor inlet. The installation shown in Figure 6 is called a "hot-side"
and/or "high-dust" SCR installation. A "low-dust" application may be used at facilities with hot-
side ESPs. In this case, the SCR reactor would be installed immediately downstream of the ESP
and prior to the air preheater. An alternative is a "cold-side" or "tail-end" SCR installation in
which the SCR reactor is located after the FGD system. This installation requires reheating of
flue gas with auxiliary fuel or other means prior to entry into the SCR reactor. Because of cost
considerations, the majority of SCR installations on utility units are of the "high-dust" type.
An ammonia injection grid is located upstream of a titania-vanadia (T1O2-V2O5) catalyst.
Flue gas with ammonia passes through the catalyst, which may be of the ceramic honeycomb or
coated parallel metal plates type. The catalyst provides the active sites where the ammonia and
NOx reduction reactions take place. Because of the temperature at which this reaction occurs, the
competing ammonia oxidation reaction is not significant. This results in two advantages over
SNCR: (1) much lower outlet NOx concentrations are possible, and (2) the reagent is more
efficiently utilized. Since most of the NOx is in the form of NO in boilers, the ratio of ammonia
added to NOx reduced is typically close to 1:1 [see Eq. (3)].
The local molar ratio of ammonia to NOx in the flue gas has a great impact on SCR
performance. This process parameter becomes more critical for SCR systems designed for high
reduction efficiencies. If appropriate distribution of this parameter is not possible, then additional
catalyst is needed to ensure adequate performance. Gas velocity and spatial temperature
distribution at the catalyst face are somewhat less critical, but are still important. Achieving
proper ammonia/ NOx ratio throughout the flow field and proper gas flow and temperature
distribution are addressed in the design stage through flow modeling and through optimization of
the ammonia injection grid at SCR system start up and periodically thereafter.
Catalyst deactivation occurs as a result of impurities in the gas stream that can produce
poisoning of the catalyst material or blinding deposits. However, for coal-fired boilers, catalysts
have been developed that can tolerate coal impurities and provide reasonable catalyst lifetimes,
typically, in the range of about 14,000-32,000 operating hours before replacing a portion - about
25 or 35 percent ~ of the total catalyst loading.22
The cost of catalyst replacement has been addressed by developing catalyst management
plans, which minimize the cost of catalyst replacement over the projected lifetime of the SCR
system's operation. In such plans, the catalyst is usually installed in layers to permit periodic
11

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replacement of portions of the total catalyst loading. In this manner, the activity of the catalyst is
more fully utilized over the life of the installation. The time between catalyst layer replacements
is measured in years. At the dry-bottom coal-fired U.S. boilers equipped with full SCR, the
planned time between catalyst changes is typically about 24,000 operating hours and at one boiler
it is 32,000 hours, or 3 or more years of operation on a typical unit. The catalyst replacement
frequency for boilers that reinject fly ash may be on the order of 14,000 hours, or nearly 2 or
more years of operation. SCR operators and catalyst manufacturers periodically monitor the
activity of portions of the catalyst to ensure that the catalyst is maintaining the planned amount of
activity. With this testing, it is possible to predict future catalyst replacement schedules.
As mentioned before, difficulties with arsenic poisoning of SCR catalyst on wet-bottom
boilers that reinject their fly ash are well known. Most operators of these facilities add limestone
to their coal as a slag fluxing agent and also have an accelerated catalyst management plan. In
general, a high arsenic concentration in the flue gas in contact with the catalyst will increase
catalyst replacement frequency and/or increase catalyst loading compared to low arsenic
applications. For example, at Merrimack 2, a cyclone boiler with 100 percent fly ash reinjection,
the expected time between replacement of layers is 14,000 operating hours. However, this is less
than the typical time between replacement of catalyst layers for SCR systems on dry-bottom
pulverized-coal boilers (-24,000 operating hours).22,31,32
In the U.S., low-sulfur, high-calcium subbituminous coals from the Powder River Basin
(PRB) are used at many power plants to comply with S02 regulations. Since these coals are
unique to the U.S., until recently, there was no experience with SCR on facilities firing this coal.
There is some concern that firing of such coals may lead to deposits on SCR catalysts and
accelerated deactivation of these catalysts. According to one supplier, the rate of catalyst
deactivation is expected to be within an acceptable range for commercial use.33 Commercial
experience with PRB coal-fired electric utility boilers that have recently commenced operation
with SCR will shed more light on this issue.34
Another issue that has recently surfaced is catalyst arsenic poisoning on dry-bottom
boilers firing coals from western Pennsylvania and West Virginia. These coals do not have
unusually high arsenic contents (although higher than for European coals). However, these coals
sometimes have unusually low content of free calcium oxide (CaO) in the fly ash. CaO acts to
scavenge gaseous forms of arsenic to form calcium arsenide. If free CaO is too low (below about
2.5 percent by weight of the fly ash), it is possible that arsenic will not be scavenged and will
lead to poisoning of the catalyst. Note that arsenic oxide chemically bonds to the catalyst surface
so that the catalyst cannot be cleaned. As a result, the catalyst is permanently poisoned. To
address this issue, some facilities have accelerated their catalyst management plans, and others
are adding small amounts of pulverized limestone to their coal.35
SCR has been extensively used to control NOx from hundreds of utility and industrial
boilers in Japan and Germany, and several coal- and gas-fired utility boilers in the U.S. Table 5
shows a list of U.S. utility facilities where SCR is currently in operation, under construction, or
under agreement for installation.29 Many of these applications are designed to provide NOx
reductions of 80 percent or greater.29 This table also indicates those facilities at which SCR was
12

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in operation in 1998, Based on the data in Table 5, SCR has become a popular NOx control
technology in the U.S. in the last 3 years.
Recently, advances have been made in secondary control technologies aimed at providing
large NOx reductions, more efficient use of reagents, and eliminating any public concerns with
the transport and handling of the ammonia reagent used in SCR applications. These advances are
described below.
Advances
Advanced Gas Rebuming (AGR)12. With AGR, a nitrogen compound (typically urea or
ammonia) is added downstream of the rebuming zone. The reburning system is adjusted for
somewhat lower NOx reduction to produce free radicals that enhance SNCR NOx reduction.
AGR systems can be designed in two ways: (1) non-synergistic, which is essentially the
sequential application of NGR and SNCR [i.e., the nitrogen agent (urea or ammonia) is injected
downstream of the burnout air]; and (2) synergistic, in which the nitrogen agent is injected either
with or before the burnout air. To obtain maximum NOx reduction and minimum ammonia slip
in non-synergistic systems, the nitrogen compound must be injected so that it is available for
reaction with the furnace gases within a temperature zone around 1000 °C. A synergistic AGR
system was demonstrated on the 104 MWe Greenidge Unit 6 in New York to reduce NOx
emissions by 68-76 percent. However, it could not reduce ammonia slip to less than 10 ppm.35
Fuel-Lean Gas Reburning (FLGR)22. FLGR, also known as controlled gas injection, is a
process in which careful injection and controlled mixing of natural gas into the furnace exit
region reduces NOx. The gas is normally injected into a lower temperature zone than that in
NGR. Whereas NGR requires 15-20 percent of furnace heat input from gas and requires bumout
air, the FLGR technology achieves NQx control using less than 10 percent gas heat input and no
bumout air. Lower NOx reductions are achieved with FLGR when compared with NGR. FLGR
has been demonstrated to reduce NOx emissions by roughly 33-45 percent at full load, with less
than 7 percent of the heat input attributed to the re burn fuel. Table 6 lists FLGR applications.35
Amine-Enhanced Fuel-Lean Gas Reburn (AEFLGR)22. AEFLGR is similar to AGR,
except that bumout air is not used, and the SNCR reagent and rebum fuel are injected to create
local, fuel-rich NOx reduction zones in an overal 1 fuel-I ean furnace. The fuel-rich zone exists in
local eddies, as in FLGR, with the overall furnace in an oxidizing condition. However, the SNCR
reagent participates with natural gas (or other hydrocarbon fuel) in a NOx reduction reaction,
which is believed to be different than the reaction that occurs when ammonia or urea is used in
SNCR. In SNCR the NOx reduction occurs in an oxidizing environment, while in AEFLGR the
ammonia or urea is injected into the reducing zone. High reductions are possible because, with
the local low oxygen environment, the AEFLGR NOx reduction reaction does not have to
compete as much with the Zeldovich thermal NOx reaction that limits SNCR performance.
Preliminary results at a demonstration plant show approximately 73 percent reduction at about 40
percent load, 60 percent reduction at 60 percent load, and 30-40 percent reduction at full load.
13

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AEFLGR is in commercial operation at PSE&G's Mercer station units 1 & 2. PSE&G is
also planning a commercial AEFLGR system at Hudson, unit 2. AEFLGR was also commercially
demonstrated at Wisconsin Electric Power Company's Pleasant Prairie 1. Table 6 lists AEFLGR
applications.35
Hybrid Selective Reduction (HSR)22. HSR is a combination of SNCR and SCR that is
designed to provide the performance of full SCR with significantly lower costs. In HSR, an
SNCR system is used to achieve some NOx reduction and to produce a controlled amount of
ammonia slip that is used in a downstream in-duct SCR reactor for additional NOx reduction.
The HSR technology has lower capital costs than SCR, allows installation to be phased in,
provides better reagent utilization than SNCR, and has very good ammonia slip control. A test
done with this hybrid system showed 95 percent NOx reduction with less than 5 ppm ammonia
slip and 55 percent reagent utilization.
In-duct SCR, There has been one full-scale demonstration installation of In-duct SCR on
a coal-fired unit at PSE&G's Mercer Generating Station. The approach entailed installing the
catalyst in an expanded duct rather than a separate reactor and was selected because the site did
not have the necessary room for a full SCR and the associated ductwork; utilizing a full SCR
would have required substantial, costly modifications to the entire facility. At Mercer, the In-duct
SCR handles 25 percent of the total flow from a 320 MWe boiler and follows a commercially
operating SNCR system that treats all of the boiler gases. This unit demonstrated between 85 and
90 percent NQX reduction with under 10 ppm ammonia slip at the air heater inlet. At the outlet of
the catalytic air heater, 90 percent reduction was achieved with no measurable ammonia slip.36
To enhance the performance of In-duct SCR, some vendors offer catalyst-coated air
heater baskets for Lungstrom type air heaters. In these situations, the plant's existing hot-end
baskets are removed from the Lungstrom air preheater, and they are replaced with baskets that
are coated with catalyst. These catalyst-coated air heater baskets may be used separately, or in
addition to In-duct SCR. Testing at Mercer Generating Station and experience in Europe with
this catalyst in coal-fired systems demonstrate that this approach is capable of providing some
additional NOx reduction and, more importantly, can be very effective in eliminating ammonia
slip. For example, the catalytic air heater baskets installed at Mercer station provided sufficient
ammonia slip control so that an additional 20 percent reduction was achieved while maintaining
the ammonia slip limit.36 However, catalytic air heater technology generally will not provide
37
sufficient reduction of NOx to be a stand-alone technology.
Ammonia on Demand (AOD)n. In AOD, ammonia reagent for SCR application is
produced from urea through on-site hydrolysis. In this conversion process, urea pellets are mixed
with small amounts of deionized water. This mixture is then pumped to a pressure vessel (the
hydrolizer) where heat and pressure are applied and urea sublimates to ammonia and carbon
dioxide (CO2). Steam is then used to strip out the ammonia gas and the steam/ammonia mixture
is then supplied to the SCR system. AOD eliminates any public concerns with transport and
handling of ammonia and associated Occupational Safety & Health Administration (OSHA)
requirements. However, the incorporation of AOD into an SCR installation would add a small
14

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chemical manufacturing plant and associated complexities. To date it has only been demonstrated
at a large 565 MWe oil-fired utility boiler that slowly changes load.
SUMMARY
Recently, a number of regulatory actions have been taken in the U.S. focused on reducing
NOx emissions from stationary combustion sources, particularly electric utility boilers. As a
result of these regulations, state-of-the-art NOx control technologies have been applied to a large
number of coal-fired U.S. utility boilers. This paper reviews these technologies and their
applications.
In general, NOx control technologies may be placed in two general categories: primary
control technologies and secondary control technologies. Primary control technologies reduce
the amount of NOx produced in the primary combustion zone. In contrast, secondary control
technologies reduce the NOx present in the flue gas from the primary combustion zone.
The popular primary control technologies in use in the U.S. are LNB and OFA. These
technologies utilize staged combustion techniques to reduce NOx formation in the primary
combustion zone. Primary control technologies have been widely implemented on U.S. coal-fired
utility boilers to comply with the NOx emissions reduction requirements of Phase I of the Title IV
NOx Program. Data reflect that primary control technologies have been applied on 177 boilers
and have resulted in reductions ranging from 33 to 48 percent, on average, from 1990 emissions
levels. In particular, applications of LNB resulted in reductions of greater than 40 percent, on
average, from 1990 levels.
Advances in primary control technologies include LNB with multilevel OFA and ROFA
systems. The former system has been able to provide relatively low NOx emissions of 0.15 lb/106
Btu at a subbituminous coal-fired boiler. The latter system has been used to achieve NOx
reductions in excess of 50 percent at a utility boiler.
The secondary NOx control technologies being used on U.S. coal-fired utility boilers
include reburning, SNCR, and SCR. Of these boilers, 14 have used, or will use, reburning as
their secondary NOx control technology. The NOx reductions at these boilers, either achieved or
expected to be achieved, range from 39 to 67 percent. Twenty-two U.S. coal-fired utility boilers
either have used SNCR, or will use it in the future. NOx reductions achieved, or projected, at
these applications range from 20 to 62 percent. In the last 3 years, SCR has been the preferred
secondary technology at numerous U.S. coal-fired utility boilers. Current data indicate that 79
boilers either use, or will use, SCR for NOx control. Many of these applications are designed to
provide reductions in excess of 80 percent.
Advances in secondary control technologies include AGR, FLGR, AEFLGR, HSR, In-
duct SCR, and AOD. FLGR is a variation of NGR, focused on reducing gas usage. AGR and
AEFLGR are combinations of NGR and SNCR, focused on obtaining large NOx reductions.
AGR has been demonstrated on a 105 MWC utility boiler to reduce NOx emissions by 68-76
percent; however, it could not reduce ammonia slip to less than 10 ppm. FLGR has been applied
15

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at five coal-fired U.S. boilers to achieve NOx reductions ranging between 27 and -40 percent.
Also, four coal-fired U.S. boilers have used AEFLGR to achieve NOx reductions ranging
between 50 and 70 percent. HSR is a combination of SNCR and SCR that is designed to provide
the performance of full SCR with significantly lower costs. A test with HSR showed 95 percent
NOx reduction with less than 5 ppm ammonia slip and 55 percent reagent utilization. In-duct
SCR entails installing the catalyst in an expanded duct rather than a' separate reactor. This may be
an attractive option for plants with constrained footprints. An application of In-duct SCR, in
conjunction with SNCR, has demonstrated between 85 and 90 percent NQX reduction with under
10 ppm ammonia slip at the air heater inlet. In AOD, the ammonia reagent for SCR application is
produced from urea through on-site hydrolysis. AOD eliminates any public concerns with
transport and handling of ammonia and associated OSHA requirements. To date it has been
demonstrated only at a large 565 MWe oil-fired utility boiler that slowly changes load.
ACKNOWLEDGEMENTS/DISCLAIMER
The research described in this article has been reviewed by the U.S. Environmental
Protection Agency and approved for publication. The contents of this article should not be
construed to represent U.S. government policy nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
16

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http://www.sso.org/otc/Formal%20Actions/att2.HTM.
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Research Triangle Park, NC. Available at the web site
http://www.epa.gov/ttn/rto/126/index.html.
17

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11
12
13
14
15
16
17
18
19
20
21
22
23
Miller, J. A.; Bowman, C.T. Mechanism and modeling of nitrogen chemistry in
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Wendt, J.O.L. Fundamental coal combustion mechanisms and pollutant formation in
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Bowman, C.T. In Fossil Fuel Combustion: A Source Book; Bartok, E. and Sarofim, A.F.,
eds.; John Wiley & Sons, Inc., New York, NY, 1991; pp. 228-252.
Zeldovich, Y.B. The oxidization of nitrogen in combustion explosions, Acta
Physiochimica, U.S.S.R. 1946, 21, 577-628.
Pohl, J.H.; Sarofim, A.F. Fate of coal nitrogen during pyrolysis and oxidation, Proc. of
the Stationary Source Combust. Symp., Volume I, pp. 1-125 through 1-152, U.S.
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Research Triangle Park, NC, June 1976; EPA-600/2-76-152a (NTIS PB-256320).
Stamey-Hall, S. Alternative Control Techniques Document - NOx Emissions from Utility
Boilers', U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, Research Triangle Park, NC, March 1994; EPA^53/R-94-023 (NTIS PB94-
184165).
Analyzing Electric Power Generation Under CAM; U.S. Environmental Protection
Agency, Office of Air and Radiation, Washington, DC, March 1998. Available at the web
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Krolewski, M.J.; Migst, A.S. Recent NOx reduction efforts: an overview, ICAC Forum
2000, Cutting NOx Emissions, Roslyn, VA, March 2000.
Hoh, R.H.; Jennings, P. Reliant Energy, W.A. Parish 7 maintaining 0.15 LB
NOx/MMBtu, ICAC Forum 2000, Cutting NOx Emissions, Roslyn, VA, March 2000.
Ralston, J.; Fischer, E. Application of Mobotec ROFA technology on a 150 MW coal-
fired CE boiler, Electric Utilities Environmental Conference, Tucson, AZ, January 2001.
Wendt, J.O.L.; Sternling, C.V.; Matovich, M.A. Reduction of sulfur trioxide and nitrogen
oxides by secondary fuel injection, Proc. 14th Symp. (Int.) on Combustion, The
Combustion Institute, Pittsburgh, PA, 1973; p. 881.
Staudt, J. Status Report on NOx Control Technologies and Cost Effectiveness for Utility
Boilers, Northeast States for Coordinated Air Use Management, Boston, MA, 1998.
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B&W's advances on cyclone NOx control via fuel and air staging technologies, EPRI-
DOE-EPA Combined Utility Air Pollution Control Symposium: The MEGA Symposium,
Atlanta, GA, August 16-20, 1999; EPRITR-113187-V2.
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Engelhardt, D.; Folsom, B.; Latham, C.; Moyeda, D.; Payne, R.; Sommer, T.; Brocato,
H.; Maziarz, M. Updated experience using reburn technology for utility boiler NOx
emissions reduction, EPRI-DOE-EPA Combined Utility Air Pollution Control
Symposium: The MEGA Symposium, Atlanta, GA, August 16-20, 1999; EPR1TR-
113187-V2.
Personal communication between R.E, Hall of EPA (NRMRL-RTP) and R. Payne of GE-
Energy and Environmental Research Corp., Irvine, CA, July 2001.
Ghiribelli, L.; Pasini, S.; Benedetto, D,; De Santis, R.; Mainini, G. Results from the
application of a gas reburning technology on a 600 MW coal fired boiler, EPRI-DOE-
EPA Combined Utility Air Pollution Control Symposium: The MEGA Symposium,
Atlanta, GA, August 16-20, 1999; EPRITR-113187-V2.
Lyon, R.K. Method for the reduction of the concentration of NO in combustion effluents
using ammonia. U.S. Patent No. 3,900,554 (1975).
White Paper: Selective non-catalytic reduction (SNCR) for controlling NOx emissions;
SNCR Committee, Institute of Clean Air Companies, Inc., Washington, DC, 1997.
Personal communication between R.K. Srivastava of EPA (NRMRL-RTP) and D. Foerter
of Institute of Clean Air Companies, Inc., Washington, DC, June 2001.
White Paper: Selective catalytic reduction (SCR) control of NOx emissions, SCR
Committee; Institute of Clean Air Companies, Inc., Washington, DC, 1997.
Lauber, J.; Cohen, M.; Donais, R. The integration of low NOx control technologies at the
Southern Energy, Inc. Birchwood Power facility, EPRI/DOE/EPA 1997 Combined Utility Air
Pollution Control Symposium, Washington, DC, August 25-29, 1997; EPRI TR-108683-V1.
Cochran, J.R.; Scarlett, D.; Johnson, R. SCR for a 460 MW coal fueled unit: Stanton Unit 2
design, startup, and operation, EPRI/DOE/EPA 1997 Combined Utility Air Pollution Control
Symposium, Washington, DC, August 25-29, 1997; EPRI TR-108683-V1.
Pritchard, S.; Hellard, D.; Cochran, J. Catalyst design experience for 640 MW cyclone
boiler fired with 100% PRB fuel, EPRI-DOE-EPA Combined Utility Air Pollution
Control Symposium: The MEGA Symposium, Atlanta, GA, August 16-20, 1999; EPRI
TR-113187-Y2.
Cochran, J.; Hellard, D.; Rummenhohl, V. Design and initial startup results from the New
Madrid SCR retrofit project, ICAC Forum 2000, Cutting NOx Emissions, Roslyn, VA,
March 23-24, 2000.

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Personal communication between R.K. Srivastava of F.PA (NRMRL-RTP) and. J. Staudt
of Andover Technology Management, Andover, MA, June 2001.
Huhmann. A. Evaluation of retrofitted combustion NOx control technology on a wet bottom,
coal-fired utility boiler at Mercer Generating Station, First Annual DOE Conference on SCR
and SNCR, Pittsburgh, PA, May 21-23, 1997.
Huttenhofer, K.; Beer, J.K.; Smeets, H.; van der Kooij, J. The DeNOx air preheater
downstream of a coal-fired boiler, EPRI/EPA 1993 Joint Symposium on Stationary
Combustion NOx Control, May 24-27. 1993.
Slocomb, S.H.; Raczynski, D.T. Comparison of the cost effectiveness of new NOx
control technologies with conventional selective catalytic reduction for combined cycle
combustion turbine power plants, Air & Waste Management Association's 94th Annual
Conference & Exhibition, Orlando, FL, June 24-28, 2001.
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Table 1. NOx reduction regulations under Titles I and IV of the CAAA.

Regulatory
action
Affected regions
Compliance date
Control
period
NOx
reductions
Title I
OTC1 NO,
Budget
Program
12 States & DC: CT, DE,
ME, MD, MA, NH, NJ,
NY, PA, RI, VT, VA
Phase II: May I,
1999
Phase III: May 1,
2003
ozone
seasond
246,000 tons'
in 1999,
322,000 tons
in 2003

NOx SIPl>
Call
22 States & DC: AL, CT,
DE, GA, IL, IN, KY, MD,
MA, MI, MO, NJ, NY, NC,
OH, PA, RI, SC, TN, VA,
WI, and WV
May 31,2004
ozone
season
1.1 million
tons in 2007

Section 126
Rule
12 States & DC: DE, IN,
KY, MD, MI, NJ, NY, NC,
OH, PA, VA, and WV
May 1,2003
ozone
season
510,000 tons
in 2007
Title IV
Acid Rain
Program
nationwide
Phase I: January 1,
1996
Phase II: January 1,
2000
annual
340,000 tons
per year
2.06 million
tons/yr

NSPS'
nationwide
July 9, 1997
annual
25,800 tons/yr
a OTC = Ozone Transport Commission.
b SIP = State Implementation Plan.
c NSPS = New Source Performance Standards.
11 Ozone season = time period May 1 through September 30.
c Kg = tons *907.18.
21

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Table 2. Primary NOx control technology applications on boilers affected under Phase I
of Title IV NOx Reduction Program,


•
Boiler type
Technology
Number of
1998 average.
NOx reduction


boilers
emission rate,
from 1990 levels,



lb/106 Btub
percent
Dry-Bottom
LNB
66
0,45
44
Wall-Fired
LNB with OFA
21
0.47
48

LNB
44
0.36
43
Tangential
SOFA3
23
0.37
33

LNB with SOFA
23
0.36
45
* Separated ovcrfire air.
hng/J = lb/106 Biu *431.0017.
22

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Table 3. Reburning applications on coal-fired utility boilers (demonstration systems not
currently in operation shown in italics).
Boiler
Rating,
MWC
Furnace
Reburn fuel,
heat input
percent
FGR'1
Baseline
NOx,
lb/106 Btub
or (ppm)
Reduction,
percent
Chalk Point 1
350
Wall
Gas, c
No
0.80
c
Chalk Point 2
350
Wall
Gas, c
No
0.80
c
Edge Moor 4
160
Tangential
Gas, 23.5
No
0.31
39
Crane 1
200
Cyclone
Gas, 18
No
1.5
60
Crane 2
200
Cyclone
Gas, 18
No
1.5
60
Allen 1
330
Cyclone
Gas, c
No
1.20
65
Hatfield 2
600
Wall
Gas, c
No
0.60
c
Hennepin 1
71
Tangential
Gas, 18
Yes
0.75
67
Grecnidge 6
104
Tangential
Gas, 15
No
0.62
52
Longannet 2,
Scotland
600
Wall
Gas, -20
Yes
(-320 pprn)
50
Niles I
108
Cyclone
Gas
No
(650 ppm)
53
Nelson Dewey
2
100
Cyclone
Coal, 30
Yes
0.75
56
Lakeside 7
33
Cyclone
Gas, 26
Yes
0.95
66
Ladyzhin 6,
Ukraine
300
Wall, wet
Gas, 12
Yes
0.82
-50
Cherokee 3
158
Wall
Gas, 22
Yes
0.75
64
Shearer 1
818
Tangential
Coal, c
Yes
c
c
a FOR = flue gas recirculation.
b ng/I = lb/10 Btu * 431.0017.
c Currently, data are not available.
23

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Table 4, SNCR applications on U.S. coal-fired utility boilers, including commercial
demonstrations, systems in operation, or systems under contract.3
Plant
Rating,
MWe
Furnace
Baseline
NOx,
Ib/IO6 Btud
Reduction,
percent
NH3 slip,
ppm
Salem Harbor 1
85
Wall
0.42
30
<10
2
85
Wall
0.60
50
<10
3
150
Wall
0.43
30
<10
Somerset 8b
112
Tangential
0.5-0.92
24-62
<5
Mercer 1
320
Wall, wet
1.6-1.8
25-33c
<5
2
320
Wall, wet
1.6-1.8
25-33"
f
Hudson 2
620
Wall
0.65
25e
f
Edge Moor 3
84
Tangential
0.70
45
<5
Indian River 3
178
Wall
0.46
26
f
4
440
Turbo
0.44
34
Seward
with catalystc
150
Tangential
0.75
0.75
42
-55
<2
Cromby 1
160
Wall
0.35
25
<10
B, L. England 1
130
Cyclone
1.31
31
<5
2
163
Cyclone
1.40
36
<5
Schiller 4
50
Wall
0.4-0.45
43-55
<10
5
50
Wall
0.4-0.45
43-55
<10
6
50
Wall
0.4-0.45
43-55
<10
Miami Fort 6
150
Tangential
0.55
35
f
Cardinal 2
620
Wall
0.57-0.75
30
<5
East Lake 3
123
Tangential
0.40
20-32.5
f
Sammis 2
185
Wall
0.45
25-30
f
Ashe vi lie 1
207
Wall
0.58
25e
f
a All SNCR applications use urea as the SNCR reagent,
b Somerset controls to 0.25 lb/106 Btu during the ozone season and to 0.35 the rest of the year.
C Seward has added a layer of catalyst and operates at levels below 0.40 lb/106 Btu.
dng/J = lb/10A Btu *431.0017.
'These units are also being equipped with AEFLGR. Percent reduction shown here is that achieved with SNCR only.
fCurrently. data are not available.
24

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Table 5. SCR applications on U.S. coal-fired utility boilers. The applications include
systems in operation and systems that are planned. (Applications in italics were the only
ones in operation in 1998.)
Boiler
Rating,
MWC
Furnace
New or Retrofit
Gorgas 10
700
Tangential
Retrofit
Widows Creek 7
575
Tangential
Retrofit
Widows Creek 8
550
Tangential
Retrofit
Indiantown
330
Wall, dry
New
Stanton 2
460
Wall, dry
New
Bowen 1
805
Tangential
Retrofit
Bowen 2
788
Tangential
Retrofit
Bowen 3
952
Tangential
Retrofit
Bowen 4
952
Tangential
Retrofit
Hammond 4
578
Wall, dry
Retrofit
Wansley 1
950
Tangential
Retrofit
Wansley 2
950
Tangential
Retrofit
Baldwin 1
560
Cyclone
Retrofit
Baldwin 2
560
Cyclone
Retrofit
Baldwin 3
635
Tangential
Retrofit
Coffeen 1
390
Cyclone
Retrofit
Coffeen 2
617
Cyclone
Retrofit
E.D. Edwards 3
365
Wall, dry
Retrofit
Gibson 2
668
Wall, dry
Retrofit
Merom 1
490
Op/Turbo
Retrofit
Merom 2
490
Op/Turbo
Retrofit
Michigan City 12
520.9
Cyclone
Retrofit
R.M. Schahfer 14
511
Cyclone
Retrofit
East Bend 2
669
Wall, dry
Retrofit
Paradise 1
704
Cyclone
Retrofit
Paradise 2
704
Cyclone
Retrofit
Paradise 3
1150
Cyclone
Retrofit
Brandon Shores 1
620
Wall, dry
Retrofit
Brandon Shores 2
685
Wall, dry
Retrofit
Morgantown 1
626
Tangential
Retrofit
Morgantown 2
626
Tangential
Retrofit
Wagner 3
359
Wall, dry
Retrofit
Hawthorn 5
540
Tangential
Retrofit
latan
725
Wall, dry
Retrofit
New Madrid 1
600
Cyclone
Retrofit
New Madrid 2
600
Cyclone
Retrofit
Sioux 1
549.8
Cyclone
Retrofit
Sioux 2
549.8
Cyclone
Retrofit
Thomas Hill 2
285
Cyclone

(Continued)
25

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Table 5. (Cont.)
Boiler
Rating,
MWC
Furnace
New or Retrofit
Roxboro 3A
745
Wall, dry
Retrofit
Merrimack 1
122
Cyclone
Retrofit
Merrimack 2
330
Cyclone
Retrofit
Logan
218
Wall, dry
New
Carney's Point 1
187
Wall, diy
New
2
187
Wall, dry
New
Somerset 1
690
Wall, dry
Retrofit
Eastlake 5
680
Wall, dry
Retrofit
J. M. Stuart 1
610
Wall, dry
Retrofit
J. M. Stuart 2
610
Wall, dry
Retrofit
J. M. Stuart 3
610
Wall, dry
Retrofit
J. M. Stuart 4
610
Wall, dry
Retrofit
Killcn Station 2
612.5
Wall, dry
Retrofit
Miami Fort 7
557
Wall, dry
Retrofit
Miami Fort 8
557
Wall, dry
Retrofit
Zimmer 1
1300
Opposed
Retrofit
Beckjord 5
244
Tangential
Retrofit
Beckjord 6
460
Tangential
Retrofit
Bayshore 4
220
Wall, dry
Retrofit
Bruce Mansfield 1
913.8
Wall, dry
Retrofit
Bruce Mansfield 2
913.8
Wall, dry
Retrofit
Bruce Mansfield 3
913.8
Wall, dry
Retrofit
Homer City 1
660
Wall, dry
Retrofit
Homer City 2
660
Wall, dry
Retrofit
Homer City 3
692
Wall, dry
Retrofit
Montour 1
806
Tangential
Retrofit
Montour 2
819
Tangential
Retrofit
Allen 1
330
Cyclone
Retrofit
Allen 2
330
Cyclone
Retrofit
Allen 3
330
Cyclone
Retrofit
Bull Run 1
950
Tangential
Retrofit
Cumberland 1
1300
Wall, dry
Retrofit
Cumberland 2
1300
Wall, dry
Retrofit
Parish 5
734
Wall, dry
Retrofit
Parish 6
734
Wall, dry
Retrofit
Birchwood
240
Tangential
New
Chesterfield 6
694
Tangential
Retrofit
Harrison 1
684
Wall, dry
Retrofit
Harrison 2
684
Wall, dry
Retrofit
Harrison 3
684
Wall, dry
Retrofit
26

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Table 6. FLGR and AEFLGR applications on U.S. coal-fired utility boilers.
Demonstration systems not currently in operation shown in italics.




Rebum
nh3
slip,
Ppm
Initial

Boiler
Rating,
MWC
FLGR or
AEFLGR
Furnace
fuel, heat
input
NOx,
lb/106
Reduction,
percent




percent
Btuc

Joliet
340
FLGR
Cyclone
Gas, 6
b
1.106
38
Elrama 1
112
FLGR
Roof
Gas, 5
b
0.59
30-35
Elrama 2
112
FLGR
Roof
Gas, 5
b
0.59
30-35
Elrama 3
112
FLGR
Roof
Gas, 5
b
0.59
30-35
Riverbend
140
FLGR
Tangenti
al
Gas, ~5
b
0.45
-40
Mercer 1
320
AEFLGR
Wall
Gas, 6-7
< 5 ppm
1.5
50-70
Mercer 2
320
AEFLGR
Wall
Gas, 6-7
< 5 ppm
1.5
50-70
Hudson3
660
AEFLGR
Wall
Gas, b
<5 ppm
b
b
Asheville 1
207
AEFLGR
Wall
Gas, 5
b
b
50
Pleasant
Prairie
600
FLGR
AEFLGR
Turbo
Gas, ~5
b
0.46
0.46
27
57
* Hudson is already equipped with an SNCR system.
b Currently, data are not available.
c ng/'J = lb/106 Btu *431.0017.
27

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Transportation
11,595,000 tons
50%
Biogenic and
miscellaneous
346,000 tons
Industrial
processes
917,000 tons
4%

Electric utilities
6,178,000 tons
Industrial and other
combustion
4,546,000 tons
19%
Figure 1. Sources of NOx emissions in the U.S. in 1997. To convert emissions in tons to
kg, multiply by 907.18.
28

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Hydrocarbon
fuel
HCN
O, OH
i k
OH, O, H
HNCO
NCO
CH,
fixation
NH,
CH,
NH,
O, OH
NO
Figure 2. NOx formation and destruction pathways.
29

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Swirling
flow
Combustion product
recirculation 2one
Secondary air
Fuel and
primary air
(fuel-rich)
Fuel-rich axial
flame core
Gradual mixing of
partiaJly burned
products and
secondary air
Figure 3. Schematic of a low NOx burner.
30

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Burnout
Burnout
zone
Rebum
Reburn
fuel
zone
Pnmary
combustion
zone
Economizer
Airpreheater
Flue gas to
Main fuel
pnmary air
Secondary
Figure 4. Schematic of a reburning application.
31

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Reagent
Injection
Reagent
metering
and control
Boiler
Economizer
Air preheater
Flue gas to
\ stack
Main fuel
primary air
Secondary
air
From urea
or ammonia
storage
Figure 5. Schematic of an SNCR application.
32

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Ammonia
injection
SCR
reactor
§"
O a
Boiler
Economizer
Air p reheat er
Flue gas to
stack
Main fuel
and
primary air
Secondary
air
Ammonia
vaporizer
Air blower
Liquid ammonia
storage tank
Figure 6. Schematic of an SCR application.
33

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TECHNICAL REPORT DATA
N RMRL~ RTP~ P~ 622 (Please read Instructions on the reverse before completii
1- REPORT NO. 2.
EPA/600/A—01/115
3. RECIP
4 TITLE AND SUBTITLE
Control of NOx Emissions from U. S. Coal-fired
Electric Utility Boilers
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7. AUTHORS
R. K. Srivastava and R. E. Hall
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
U. S. EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Published paper; 6-7/01
14. SPONSORING AGENCY CODE
EPA/600/13
15 supplementary notes ^ppcd project officer is Ravi h. Srivastava, Mail Drop 65, 919/
541-3444. For presentation at the All-Russian Thermal Engineering Institute (VT1)
80th Anniversary Conference, Moscow, Russia, October 9-10, 2001.
16.abstract paper discusses the control of nitrogen oxide (NOx) emissions from U.S.
coal-fired electric utility boilers. (NOTE: In general. NOx control technologies are
categorized as being either primary or secondary control technologies. Primary
technologies reduce the amount of NOx produced in the primary combustion zone..
Secondary technologies reduce the NOx present in the flue gas from the primary
combustion zone.) Primary technologies in use in the U. S. are low NOx burner
(LNB) and overfire air (CFA). They utilize staged combustion to reduce NOx forma-
tion in the primary combustion zone. Data reflect that primary technologies, applied
on 177 boilers, have resulted in reductions of 33~48%, on average, from 1990 emis-
sions levels. In particular, applications of LNB resulted in reductions of > 40%, on
average, from 1990 levels. Secondary technologies used on U.S. coal-fired utility
boilers include reburning, selective noncatalytic reduction (SNCR), and selective
catalytic reduction (SCR). Of these boilers, 14 have used, or will use, reburning as
their NOx control technology. The NCx reductions achieved, or expected to be
achieved, at these boilers range from 39 to 67%. Of the U.S. coal-fired utility boil-
ers, 22 have used, or will use, SNCR. NOx reductions achieved, or projected, at
these boilers range from 20 to 62%. Data indicate that 79 boilers will use SCR.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution Boilers
Nitrogen Oxides Flue Gases
Emission
Coal
Combustion
Electric Utilities
Pollution Control
Stationary Sources
13 B 13A
07b
14G
2 ID
21B
18. DISTRIBUTION STATEMENT
19, SECURITY CLASS (This Report)
21. NO. OF PAGES
20. SECURITY CLASS (This Page)
22. PRICE
EPA Form 2220-1 (Rev 4-7? ) PREVIOUS EDITION IS OBSOLETE	forms/admin/lechrpt.frm 7/8/99 pad

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