Nitrogen Oxides Emission Control Options for Coal-Fired

Electric Utility Boilers

Ravi K. Srivastava and Robert E. Hall

U.S. Environmental Protection Agency, National Risk Management Research Laboratory,

Air Pollution Prevention and Control Division, Research Triangle Park, NC

Sikander Khan and Kevin Culligan

U.S. Environmental Protection Agency, Office of Air and Radiation, Clean Air Markets Division,

Washington, DC

Bruce W. Lani

U.S. Department of Energy, National Energy Technology Laboratory, Environmental Projects

Division, Pittsburgh, PA

ABSTRACT

Recent regulations have required reductions in emissions

of nitrogen oxides (NOx) from electric utility boilers. To

comply with these regulatory requirements, it is increasingly important to implement state-of-the-art NOx control technologies on coal-fired utility boilers. This paper

reviews NOx control options for these boilers. It discusses

the established commercial primary and secondary control technologies and examines what is being done to use

them more effectively. Furthermore, the paper discusses

recent developments in NOx controls. The popular primary control technologies in use in the United States are

low-NOx burners and overfire air. Data reflect that average

NOx reductions for specific primary controls have ranged

from 35% to 63% from 1995 emissions levels. The secondary NOx control technologies applied on U.S. coalfired utility boilers include reburning, selective noncatalytic reduction (SNCR), and selective catalytic reduction

(SCR). Thirty-six U.S. coal-fired utility boilers have installed SNCR, and reported NOx reductions achieved at

these applications ranged from 15% to 66%. Recently,

SCR has been installed at 150 U.S. coal-fired utility boilers. Data on the performance of 20 SCR systems operating

in the United States with low-NOx emissions reflect that

in 2003, these units achieved NOx emission rates between

0.04 and 0.07 lb/106 Btu.

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 and elsewhere. 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 2000

from each of the applicable source categories in the

United States.2 It is evident from these data that stationary combustion sources (electric utility, industrial, and

other combustion sources) accounted for a significant

portion, 39%, of these emissions. Moreover, electric

utilities accounted for 22% of NOx emissions and comprised the largest emitting source category within stationary sources. Plumes emitted from power plants can traverse regional distances and thereby contribute to

environmental impacts over large geographic regions.

Furthermore, the percentage of contribution from coalfired power plants to state or local NOx emissions inventories can be higher than that on a national basis. Recent

IMPLICATIONS

To comply with recent regulatory requirements, it is increasingly important to implement state-of-the-art NOx

control technologies on coal-fired utility boilers. This paper

reviews NOx control options for these boilers. In doing so,

it not only discusses the established commercial primary

and secondary control technologies, but also examines

what is being done to use them more effectively. Further,

the paper discusses recent developments in NOx controls.

The paper is expected to be a state-of-the-art reference on

NOx control technologies for regulators, utility industry personnel, and others stakeholders.

TECHNICAL PAPER ISSN 1047-3289 J. Air & Waste Manage. Assoc. 55:1367–1388

Copyright 2005 Air & Waste Management Association

Volume 55 September 2005 Journal of the Air & Waste Management Association 1367
data reflect that electricity-generating sources are an important source of NOx in many of the states.3 For example, in 2001, an estimated 754,446 t of NOx were emitted

in the state of Indiana, with 310,456 t, or 41%, of these

emissions attributed to electricity-generating sources.

Based on the above considerations, the reduction of NOx

emissions from stationary sources, particularly electric

utility sources, has been focused on recently to address

the associated environmental concerns. Accordingly, a

number of regulatory actions that are focused on reducing

NOx emissions from stationary combustion sources have

recently been taken in the United States. These actions

include the Acid Rain NOx regulations,4,5 the Ozone

Transport Commission NOx Budget Program,6 revision of

the New Source Performance Standards for NOx emissions

from utility sources,7 and the Ozone Transport rulemakings,8 and the Clean Air Interstate Rule.9

Control technology applications necessarily play a

key role in the formulation and implementation of air

pollution-reduction strategies. The current focus on the

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

United States but also examines those that can be considered to be relatively new or in an advanced stage of

development.

NOx Formation in Combustion

Before examining the control technologies, it

is 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. NOx is

formed during most combustion processes by

one or more of the following three chemical

mechanisms:10 –12 (1) “thermal” NOx resulting

from oxidation of molecular nitrogen in the

combustion air,13 (2) “fuel” NOx resulting

from oxidation of chemically bound nitrogen

in the fuel, and (3) “prompt” NOx resulting

from reaction between molecular nitrogen

and hydrocarbon radicals.

Thermal NOx can typically represent up

to 20% of the NOx emitted during pulverized

coal combustion in utility boilers.14 Its rate of

formation is directly proportional to the exponential of temperature and to the square

root of the oxygen concentration.13,15 As

combustion zone temperatures approach or

exceed 2800 °F, significant amounts of thermal NOx are

produced through dissociation and oxidation of molecular nitrogen from the combustion air.14 Formation of

thermal NOx can be controlled by reducing oxygen concentrations in the furnace, combustion zone temperatures, and residence time of flue gas in high-temperature

areas of the boiler. For coal-fired boilers, practical methods include the following: (1) increasing the size of the

combustion zone for a given thermal input and (2) reducing the rate of combustion and, consequently, peak flame

temperatures with specially designed burners. The size of

the combustion zone may be increased by using an overfire air (OFA) system with an existing boiler or by increasing the furnace dimensions in the burner area for a new

boiler.

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.16 In pulverized coal combustion

in a utility boiler, fuel NOx may typically contribute up

to 80% of the NOx emissions.14 Formation of fuel NOx

depends on the nitrogen content in the fuel and the

amount of oxygen available to react with the nitrogen

during coal devolatilization in the early stages of combustion. Accordingly, fuel NOx formation can be reduced by switching to, or cofiring with, fuel with lower

nitrogen content and/or by limiting oxygen availability

during the early stages of combustion. Methods for

reducing oxygen availability include lowering the excess air level and/or controlling the rate at which the

Figure 1. U.S. sources of NOx emissions in 2001 (to convert emissions in t to kg,

multiply by 907.18).

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1368 Journal of the Air & Waste Management Association Volume 55 September 2005
fuel and air mix (i.e., staging the combustion process)

such that an initial fuel-rich zone is followed by a

burnout zone. The flue gas in the burnout zone has

adequate oxygen concentration needed to complete the

combustion process but has sufficiently low temperature to minimize thermal NOx production. Prompt NOx

contributes a relatively minor fraction of total NOx

emissions for coal-fired boilers.12

NOX CONTROL TECHNOLOGIES

In general, NOx control technologies may be placed in two

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 away from the primary combustion

zone. Some of the secondary control technologies actually

use a second stage of combustion, such as reburning.

In addition to the primary and secondary control

technologies applied exclusively for NOx control, other

technologies have also been developed to provide simultaneous reduction of more than one pollutant. These

multipollutant technologies reduce NOx along with other

pollutants, including sulfur dioxide (SO2), mercury (Hg),

particulate matter (PM), and/or air toxics.

Primary Control Technologies

In the United States, popular primary control technologies are low-NOx burners (LNB) and OFA. These technologies use staged combustion techniques to reduce NOx

formation in the primary combustion zone. LNB and OFA

are described below. The optimum control system design

may incorporate one or both of these, selected based on

the capacity of the unit, fuels to be fired, and NOx reduction requirements.

LNB. A LNB limits NOx formation by controlling the

stoichiometric and temperature profiles of the combustion process.17,18 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 both thermal and 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 the complete mixing of fuel and

air as long as possible within the constraints of

furnace design. This is why the flames from

LNBs are usually longer than those from conventional burners. Conceptually, working of an

LNB with gradual mixing of combustion air to a fuel-rich

flame core is shown schematically in Figure 2. The hardware used to influence the fuel/air mixing varies from

manufacturer to manufacturer. LNBs can provide NOx

reductions of 50% or more from uncontrolled levels, with

higher reductions possible for boilers with more facilitating design features.

Certain coal properties and boiler characteristics may

have an impact on the effectiveness of a LNB. In general,

coal rank, fineness, volatile matter content, and nitrogen

content affect NOx formation in pulverized coal combustion. Of these properties, coal rank and volatile matter

content have a more significant impact on NOx formation

compared with typical variations in the nitrogen content

and pulverized coal fineness. However, boilers equipped

with pulverizers to provide a finer coal grind can achieve

greater NOx reductions with LNBs. Generally, lower rank

coals (e.g., subbituminous coals) are characterized by

higher volatile matter contents. The firing of such coals

results in greater volatile release in the near burner

zone. NOx formation is inhibited because of enhanced

fuel nitrogen release in a locally fuel-rich environment

available in a LNB, thereby leading to greater conversion of fuel nitrogen to N2, and reduced fuel nitrogen

retention in the char, which limits the NOx formed,

because the char is oxidized in a fuel-lean region away

from the burner.19 In addition to coal properties, boiler

characteristics, such as furnace size and volumetric and

planar heat-release rates, affect the flue gas temperature

and residence time in the combustion zone and thereby

impact the LNB effectiveness.

Longer LNB flames require deeper furnaces to avoid

flame impingement on the furnace walls facing the burners. In a retrofit situation, this may require LNB adjustments, affecting the NOx reduction capability of the system in some cases. In certain situations, LNB retrofits may

result in changed heat transfer patterns within the furnace, increased corrosion of the furnace walls, and increased furnace fouling.

Figure 2. Schematic of a low-NOx burner.

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Volume 55 September 2005 Journal of the Air & Waste Management Association 1369
Unburned carbon (UBC) levels typically increase when

a boiler is converted with a low-NOx firing system. In general, the extent of this increase depends on coal properties,

design of burners and air registers, size of the furnace, firing

configuration of the burners, and excess air level. An increase in UBC level affects boiler efficiency. For example,

combustion modifications on an eight corner tangentialfired unit resulted in a 2% increase in UBC, which corresponds to a 0.08% efficiency loss.20 Also, increase in UBC

levels in fly ash can make it unsuitable for cement replacement in ready-mix concrete and can thereby affect the salability of fly ash. ASTM C618 specification limits UBC content in fly ash to 6%, largely because higher levels of UBC

can cause discoloration, poor air entrainment, and segregation of mix components in the ready mix.21 Counter design

measures undertaken to improve UBC levels may be at the

cost of NOx reduction effectiveness. The most significant

impacts on UBC have been observed on smaller (cooler)

boilers, where baseline UBC levels were high (10%). In

such boilers, LNB retrofits can increase UBC by 2–5% points.

In some cases, however, the UBC levels did not change after

the retrofit, and it was possible to maintain these levels at

0.5% in Powder River Basin (PRB) coal-fired boilers, and

below 3–3.5% in the larger bituminous coal-fired units.22

OFA. OFA, also referred to as air staging, is a combustion

control technology in which a fraction, 5–20%, of the total

combustion air is diverted from the burners and injected

through ports located downstream of the top burner level.17,18 OFA is 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 on wall-fired boilers may increase the reductions by an additional 10 –25%.

OFA is an inherent part of all of the primary control

technology applications on tangentially fired boilers. These

applications use OFA in three different configurations: closecoupled to the burner, separated from the burner, or both.

Reductions with OFA range from 20% to 60% depending

on the initial NOx levels of a boiler, fuel combustion equipment design, and fuel type.23 However, while reducing (substoichiometric) conditions result in significant NOX reduction, increased levels of UBC and CO can occur. The extent

of these increases is dependent on the design of the OFA

system and fuel properties. Waterwall wastage can also occur with the extent dependent on factors such as degree of

staging, unit aerodynamics, heat release rates, coal composition (high versus low sulfur), UBC, and tube temperature.

These impacts can be minimized by an appropriately designed OFA system.24 Recent experience reflects that the

application of OFA on tangentially fired boilers can provide

NOx reductions in excess of 50%, with moderate (25–35%

from baseline) increases in UBC levels and CO emissions of

50 ppm (corrected to 3% O2).23

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 the Title IV NOx Program. Table 1 provides a

summary of primary control applications through 2003.25

These data reflect that primary control technologies have

resulted in average reductions for specific technologies

ranging from 35% to 63%, from 1995 emissions levels. In

particular, applications of LNB resulted in reductions of

35%, on average, from 1995 levels.

Enhancements in Primary Control Technologies

Recent advances in primary control technologies have

been aimed at providing greater NOx reduction. These

advances are described below.

Table 1. NOx reduction performance of primary control technology applications on coal-fired boilers.

Boiler Typea Coal Type

Primary

Control

Technology

1995 Average

Baseline NOx

Emission (lb/106 Btu)

2003 Average

Controlled NOx

Emission (lb/106 Btu)

Average NOx

Reduction

Efficiency (%)

Range of NOx

Reduction

Efficiencies (%)

No. of

Boilers

Wall-fired Bituminous LNB 0.71 0.41 39.2 8.6–70.1 62

Wall-fired Bituminous LNBO 0.81 0.35 53.3 32.7–71.9 16

Wall-fired Subbituminous LNB 0.59 0.28 45.5 19.4–80.3 16

Wall-fired Subbituminous LNBO 0.41 0.14 63.4 40.0–80.9 4

Tangential-fired Bituminous LNC1 0.62 0.39 35.0 17.2–65.4 26

Tangential-fired Bituminous LNC2 0.48 0.31 36.6 23.3–70.8 15

Tangential-fired Bituminous LNC3 0.56 0.25 54.9 38.1–72.2 19

Tangential-fired Subbituminous LNC1 0.38 0.21 45.4 11.3–74.4 18

Tangential-fired Subbituminous LNC2 0.43 0.23 45.6 33.9–65.4 3

Tangential-fired Subbituminous LNC3 0.35 0.14 60.5 48.2–77.2 23

Notes: LNB  low-NOx burner; LNBO  LNB with OFA; LNC1  LNB with close-coupled OFA; LNC2  LNB with separated OFA; and LNC3  LNB with both

close-coupled and separated OFA. a

All boilers are dry-bottom type.

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1370 Journal of the Air & Waste Management Association Volume 55 September 2005
LNB with Multilevel OFA. A concentric firing system with

multilevel OFA is now available for tangentially fired boilers. This combustion technology has achieved NOx emissions 0.15 lb/106 Btu, equating to 60% reduction,

while firing PRB subbituminous coal,26 which reflects the

potential for achieving low-NOx emissions with this technology. Note, however, that for other coals with lower

fuel-volatile contents than PRB coals (e.g., eastern bituminous coals), relatively higher NOx emissions may be expected with this technology. For impacts of coal properties on combustion staging, please refer to the LNB

section above.

Rotating Opposed Fire Air. The rotating opposed fire air

(ROFA) design injects air into the furnace first to break

up the fireball and then to create a cyclonic gas flow to

improve combustion.27 The difference between ROFA

and conventional OFA is that ROFA uses a booster fan

to increase the velocity of air to promote better mixing

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 one U.S. and six Swedish

boilers, firing a variety of fuels (coal, wood waste, municipal waste, and heavy residual oil).28 On Swedish

installations, NOx reduction in the range of 45– 60%

has been obtained.28 Based on changes in CO levels

experienced with ROFA application at four plants, the

impact of ROFA on the overall plant heat rate may vary

from a small increase to an actual reduction.29 These

data show that the UBC and/or excess air levels at the

economizer outlets of these plants either did not

change or decreased. Reductions in these operating parameters improved boiler efficiency and reduced the

draft fan duties, thereby more-than-compensating for

any increase in the auxiliary power consumption due to

the fan supplying high-velocity air to the OFA ports.

With improvements in the UBC and excess air levels,

the plant heat rate can be expected to improve. However, without such improvements, a small increase in

the heat rate may occur because of the additional power

consumption by the booster fan. Therefore, any impact

of ROFA on the plant heat rate can be site specific.

Combustion Improvement Techniques. Other than the application of control technologies described above, improvements in combustion conditions are also being undertaken at power plants as additional cost-effective

control measures.30,31 Imbalances in coal and airflow rates

to burners pose a constraint to reducing NOx emissions

from some pulverized coal boilers. Such imbalances are

being addressed by installing equipment to dynamically

monitor and control fuel flow32,33 and/or airflow to each

burner level and, if present, OFA.34 In addition, distributed control systems with state-of-the-art optimizing algorithms are being used to adjust boiler firing while maintaining the required NOx emission level.35–37

To comply with Title IV NOx regulations, some cyclone boilers currently use OFA, but some of these boilers

may want to further lower NOx emissions to comply with

additional emission reduction requirements (e.g., ozone

transport rulemakings). Achieving lower NOx through additional combustion staging on some units, however,

may be impractical, because cyclone boilers operate near

their slag-tapping limit. Additionally reducing the local

stoichiometric air-fuel ratio may lead to slag taps freezing,

especially on low-sulfur coal-fired units. Oxygen injection

into cyclone boilers offers a possibility of not only decreasing NOx but of also increasing barrel temperatures to

prevent frozen slag.38

Computational fluid dynamic modeling is increasingly being used at power plants to design and fine-tune

control technology applications. Such modeling can

help identify initial burner settings for desired NOx

reduction performance, determine the location(s) of

OFA, optimize its application with regard to reducing

NOx, avoiding boiler wall corrosion, and provide insights into potential combustion staging strategies for

uncommon boiler designs (e.g., a four-wall-fired

unit).39

Secondary Control Technologies

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 control technologies and/or combustion improvement techniques alone.

These units may require secondary controls (with or without

primary controls). In the United States, popular secondary

control technologies are reburning, selective noncatalytic

reduction (SNCR), and selective catalytic reduction (SCR).

These technologies are described below.

Reburning. In reburning up to 25% 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

90% 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 nitrogen-containing species. These

species are ultimately reduced to N2. Finally, completion

air is added above the reburn zone to complete burnout of

reburning fuel.40 –43 The reburning process is shown schematically in Figure 3.

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Volume 55 September 2005 Journal of the Air & Waste Management Association 1371
Furnace dimensions impact several key design parameters for reburning systems, including mixing of reburn

fuel and flue gas, gas residence time within the reburn and

burnout zones, and heat transfer in the burner zone and

the upper furnace. Sufficient residence time is required to

achieve adequate flue gas mixing, to accommodate the

NOx reduction kinetics in the reburning zone, and for

complete combustion in the burnout zone. Given sufficient time in the reburn zone, reburn zone stoichiometry

is another critical parameter that influences NOx reduction. This 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 the primary heat input will decrease the stoichiometry in the reburn zone and improve

the NOx reduction efficiency. However, this heat splitting

is constrained by: (1) flame stability considerations in the

primary burner zone and, if applicable, reburn zone; (2)

the potential for unacceptable levels of carbon burnout

(CO or fuel) that may result from the addition of relatively large amounts of reburn fuel needed to achieve the

desired NOx reduction; and (3) the potential for increased

boiler tube corrosion within the reburn zone. In addition,

the temperature at the point of burnout air addition can

place a lower limit on the achievable NOx because of

reformation of thermal NOX. In general, these considerations are site specific.

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 reburning fuel,

depending on the price of gas with respect to other fuels,

such as coal and oil. Compared with natural gas reburning

(NGR), coal reburning requires a relatively longer residence time through the reburn zone and a larger upper

furnace to achieve adequate carbon burnout. Because carbon burnout can be a constraint limiting the amount of

reburn fuel that can be injected, the reburning coal particle size distribution is a key parameter. In some applications, pulverizer improvements (e.g., addition of dynamic

classifiers) or replacement with micronized coal (i.e., coal

pulverized to a very high fineness) pulverizers may be

necessary to achieve acceptable NOx reduction and carbon burnout performance. Micronized coal may be used

as a reburning fuel on boilers that may not have enough

volume for normal coal reburning. However, micronized

coal reburning requires specialized coal pulverizers, which

increases its capital cost over gas or conventional coal

reburning. In addition, it is necessary to use recirculated

flue gas as the reburning fuel carrier for any coal reburning system.

The first application of reburning technology to a

wet-bottom, wall-fired unit was to the 300 MWe Ladyzhin

plant in Ukraine. This application demonstrated that 50%

NOx reduction was achievable with NGR technology on

wet-bottom, wall-fired boilers. In general, reburn technology has demonstrated 50% NOx reduction on several

coal-fired boiler types, such as cyclone-fired, dry-bottom

wall-fired, and wet-bottom wall-fired.44,45

More than 40 boilers worldwide have either used or will

use reburning as their secondary NOx

control technology.46 The NOx reductions at these boilers either achieved or

expected to be achieved range from 25

to 78%.

Table 2 reflects the status of reburning applications on U.S. coalfired boilers.46,47 As seen in this table,

many of the applications are not operational at this time, probably because of plant-specific economics associated with elevated natural gas

prices and other factors. The data on

currently operational reburning applications on coal-fired U.S. electric

utility boilers shown in Table 2 reflect that in 2003, these units

achieved NOx emission rates between

0.277 and 0.385 lb/106 Btu.

SNCR. SNCR is a postcombustion

technology in which a reagent (ammonia [NH3 Figure 3. Schematic of a reburning application. ] or urea) is injected into

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1372 Journal of the Air & Waste Management Association Volume 55 September 2005
the furnace above the combustion zone, where it reacts

with NOx to reduce it to N2 and water.48,49 In general,

SNCR reactions are effective in the range of 1800 –2100 °F.

The high temperature necessary for the reaction to proceed requires that the reagent normally be injected into

the upper furnace region of the boiler, as shown in Figure 4.

Although the actual reactions are more complex, the overall

stoichiometric reactions for urea and NH3 SNCR are:

NH22CO  2NO  1/2O2 3 2 H2O  CO2  2N2

(1)

2NH3  2NO  1/2O2 3 2N2  3H2O (2)

In general, NH3 may reduce NOX, oxidize to form

NOx, or remain unreacted and pass through the stack.

This unreacted portion is referred to as “NH3 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 NH3 slip. Relatively high

concentrations of NH3 slip can react with SO2 and sulfur

trioxide (SO3) in the flue gas and form ammonium sulfates and bisulfates, which, in turn, can cause plugging of

the air preheater (APH) passages. Furthermore, NH3 slip

can also reduce the marketability of fly ash by making it

odorous. For these reasons, NH3 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 the reduction of NOx to N2, a significant

competing reaction is the oxidation of the SNCR reagent

to form NOx. This oxidation reaction becomes more significant at relatively higher temperatures. Because of this

competing oxidation reaction, there is not a one-to-one

relationship between reagent injected and NOx reduced.

It typically requires more urea or NH3 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 1800 and 2100 °F. Because of this

misconception, in the past it was believed that SNCR

could not be used on cyclone or wall-fired wet-bottom

Table 2. Reburning applications on coal-fired U.S. boilers.

Technology Project Description Plant Unit

Unit Size

(MW)

2003 NOx Rate

(lb/106 Btu)

NOx Reduction

Efficiency (%) Status and Comments

Gas reburning  sorbent injection Hennepin 1 80 NA 67 Demo 1/91–1/93; not operating

Gas reburning  sorbent injection Lakeside 7 40 NA 60 Demo 5/93–10/94; not operating

Gas reburning  low-NOx burners Cherokee 3 172 NA 64 Demo 11/92–1/95; decommissioned

Coal reburning Nelson Dewey 2 110 NA Lamar 52, PRB 55 Demo 12/91–12/92; decommissioned

Micronized coal reburning Milliken 1 148 0.277 29 Demo 3/97–4/99; operating

Gas reburning Greenidge 6 109 NA 50 Setup 1996; not operating

Gas reburning Niles 1 108 NA 50 Installed and operated 1988; decommissioned

Gas reburning C.P. Crane 1 200 NA 65 Startup 1998; not operating

Gas reburning C.P. Crane 2 205 NA 68 Startup 1998; not operating

Gas reburning Allen 1 330 NA 65 1998; not operating

Gas reburning Edge Moor 4 177 NA 48 1999; not operating

Gas reburning Chalk Point 1 364 NA 55 2000; not operating

Gas reburning Chalk Point 2 364 NA 55 2000; not operating

Gas reburning Hatfield 2 576 NA 68 1999; brief test; successful; not operating

Gas reburning Hatfield 1 576 NA NA 2002; installed; never tested

FLGR Elrama 1–3 3x100 NA 25–30 Startup 1999; not operating

Amine-enhanced FLGR Mercer 1–2 2x320 NA 25–30 Startup 1999; not operating

Amine-enhanced FLGR Hudson 2 600 NA 25–30 Startup 2000; not operating

FLGR Riverbend 7 140 NA 25–30 Startup 1998; decommissioned

FLGR Joliet 6 340 NA 25–30 Startup 1997; decommissioned

Amine-enhanced FLGR Asheville 1 207 NA 25–30 Startup 2000; not operating

FLGR Pleasant Prairie 1 616 NA 25–30 Startup 1999; not operating

Coal reburning R.D. Green 2 250 0.385 44 2002; operating

Coal reburning R.D. Green 1 250 0.339 44 2004; operating

Gas reburning Scherer 1 870 NA 40 2001; not operating

Gas reburning  SNCR Somerset 8 115 0.277 57 (with reburning) 2003; operating

Note: NA  not available; FLGR  fuel-lean gas reburning.

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Volume 55 September 2005 Journal of the Air & Waste Management Association 1373
boilers. However, commercial SNCR systems on these

boiler types exist today.49 In fact, most electric utility

SNCR systems operate effectively with reagent injection

where gas temperatures are 2100 °F. 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, 1800 °F, 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 NH3 slip.

Urea reagent is injected as an aqueous solution. NH3

can be injected as a gas (anhydrous NH3) or as an aqueous

solution. In general, mixing of flue gas with injected aqueous solution of NH3 or urea is better than that with

injected anhydrous NH3. This is because aqueous droplets

penetrate farther into flue gas than gaseous anhydrous

NH3. Furthermore, because a urea solution is less volatile

than a NH3 solution, its droplets generally penetrate farther into the flue gas. Because of somewhat poorer mixing

in SNCR systems with NH3 injection compared with those

using urea, the former require more elaborate injection

schemes in the boiler.50

Boiler load changes can impact

the performance of an SNCR application because of changes in two key

parameters: temperature of flue gas at

the furnace exit and gas residence

time in the furnace.51 Therefore, the

following two measures are usually

included in the design of SNCR systems: (1) a multilevel injection system, and (2) an ability to change the

amount of reagent to be injected.52

An SNCR system on a load-following

boiler generally has two or three injection zones, each with several injectors. Because each of these injection zones is switched on and off

automatically by the plant control

system, this does not add complexity

to the plant operation.41 SNCR effectiveness may depend on the size of

the boiler. At larger boiler sizes, the

capability to uniformly distribute a

chemical reagent, urea or NH3,

throughout the furnace volume may

diminish, which, therefore, may negatively impact NOx removal efficiency.

SNCR has been applied in the United States on a wide

variety of boilers firing a range of fuels.53 A summary of

available SNCR performance data is shown in Table 3.

These data show that NOx reduction efficiencies of these

SNCR systems ranged from 15 to 66%. Data also show

that whereas smaller boilers (e.g., 78 and 76 MW Salem

Harbor units 1 and 2) may be able to achieve 60% NOx

reduction, larger boilers (e.g., 500 MW Cardinal Unit 1)

may be capable of achieving reductions of only 30%.

SCR. SCR is a postcombustion NOx reduction technology

in which NH3 is added to the flue gas, which then passes

through layers of a catalyst.41,54 The NH3 and NOx react

on the surface of the catalyst, forming N2 and water. SCR

reactions are generally effective in a temperature range of

650 –750 °F. In general, SCR is capable of providing high

levels of NOx reduction, ranging from 80% to 90%. The

overall stoichiometric SCR reactions are:

2NH3  2NO  1/2O2 3 2N2  3H2O (3)

4NH3  2NO2  O2 3 3N2  6H2O (4)

Note that the NOX reduction reactions above are the

same as the ones occurring in SNCR at higher temperatures, but the SCR catalyst makes them effective at lower

temperatures.

Figure 4. Schematic of a SNCR application.

Srivastava et al.

1374 Journal of the Air & Waste Management Association Volume 55 September 2005
In most utility boiler applications, the catalyst is installed in a separate reactor positioned downstream of the

boiler economizer and immediately upstream of the APH

(see Figure 5). Under low-load conditions, an economizer

bypass is sometimes used to ensure proper flue gas temperature at the SCR reactor inlet. The installation shown

in Figure 5 is called a “high-dust,” SCR installation. A

“low-dust” application may be used at facilities with hotside electrostatic precipitators (ESPs). In this case, the SCR

reactor would be installed immediately downstream of

the ESP and before the APH. An alternative is a “tail-end”

SCR installation in which the SCR reactor is located after

the flue gas desulfurization system. This installation requires reheating of flue gas with auxiliary fuel or other

means before entry into the SCR reactor. Because of cost

considerations, the majority of SCR installations on utility units are of the high-dust type.55

An NH3 injection grid is located upstream of the SCR

catalyst. As the flue gas with NH3 passes through the

catalyst, which may be of the ceramic honeycomb or

coated parallel metal plates construction, it provides the

active sites (typically vanadia–titania [V2O5–TiO2]) where

the NH3 and NOx reduction reactions take place. At the

temperature where this reduction occurs, the competing NH3 oxidation

reaction is not significant. This results in two advantages over SNCR:

much lower outlet NOx concentrations are possible and NH3 slip can be

reduced. Because most of the NOx is

in the form of NO in coal-fired boilers, the ratio of NH3 added to NOx

reduced is typically close to 1:1 (see

eq 4).

The local molar ratio of NH3 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 both proper NH3:

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 NH3

injection grid at SCR system start up

and periodically thereafter.56

Catalyst deactivation occurs as a result of impurities

in the gas stream that can cause poisoning of the catalyst

material or blinding deposits. Therefore, catalyst management plans are used at SCR installations to maintain the

needed catalyst activity while minimizing costs.57–59 In

such plans, the catalyst is usually installed in layers to

permit the periodic replacement of portions of the total

catalyst loading. In certain designs, an empty layer is

provided to allow the addition of catalyst to this layer

while maintaining the existing catalyst with reduced effectiveness in place over a longer period of time. Pressure

drop across most SCR systems is 6 – 8 in. water gage (w.g.),

and in some cases it may be 10 in. w.g.60 SCR systems

are equipped with soot blowers that are periodically cycled to clean the SCR catalyst and the APH.61

Comprehensive catalyst planning involves minimizing the costs associated with a catalyst in concert with

optimizing the operation of the plant to produce power at

minimum cost.58 To achieve these objectives, tradeoffs

are needed among catalyst loading, catalyst replacement

frequency, pressure drop associated with catalyst loading,

the level of NOx reduction desired, and the level of NH3

Table 3. SNCR performance for electric utility coal-fired units.

Plant Namea Unita

Unit Size

(MW)a

2003 NOx Rate

(lb/106 Btu)b

NOx Reduction

Efficiency (%)c

B L England 1 129 0.513 31.3

B L England 2 155 0.451 36

Cardinal 1 500 0.53 30

Clover Power Station 1 441 0.271 25

Clover Power Station 2 441 0.266 25

Cromby 1 144 0.306 25

Mercer Generating Station 2 321 0.755 35

Miami Fort 6 163 0.669 35

Rochester 7 - Russell Station 1 47 0.389 15 - 27.5

Rochester 7 - Russell Station 2 65 0.382 15 - 27.5

Rochester 7 - Russell Station 3 65 0.294 15 - 27.5

Rochester 7 - Russell Station 4 80 0.304 15 - 27.5

Salem Harbor 1 78 0.265 66

Salem Harbor 2 76 0.262 66

Salem Harbor 3 142 0.278 66

Schiller 4 47 0.317 30

Schiller 5 50 0.288 30

Schiller 6 48 0.274 30

Seward 15 136 0.384 35

Yorktown Power Station 2 167 0.335 25 - 30

a

The 20 units shown were selected from the list of 36 utility coal-fired units equipped with SNCR in the EPA emissions

database at http://www.epa.gov/airmarkets/emissions/raw/index.html. Because information on NOx removal efficiency

was not available for the remaining 16 units, these units are not shown in the table; b

All emissions data shown are from

the EPA emissions database at http://www.epa.gov/airmarkets/emissions/raw/index.html; c

NOx reduction efficiencies

were taken from the “Fuel Tech NOx Out Process Experience List,” available at http://docket.epa.gov/edkpub/do/

EDKStaffItemDetailView?objectId090007d480271c93.

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Volume 55 September 2005 Journal of the Air & Waste Management Association 1375
slip desired. For example, a plant may want to extend the

time between catalyst replacements by increasing the catalyst loading beyond the initial design level. However,

increased catalyst loading would add catalyst cost and

increases parasitic load because of the pressure drop across

the catalyst. Again, a plant may consider reducing more

NOx in an emissions-trading framework. However, increased NOx reduction would come at a price of increased

NH3 consumption, increased frequency of catalyst replacement, increased catalyst loading, or increased pressure loss. Similarly, a plant may consider tolerating a

higher NH3 slip from its SCR system than originally envisioned. This can provide benefits of reduced catalyst

loading, extended time periods between catalyst replacement events, or increased NOx reduction. Finally, a catalyst

management plan has to take into account a comparison of

costs associated with a new catalyst and a corresponding

regenerated catalyst.59

European experience with SCR reflects that 15% of

the catalyst is replaced annually. Similarly, recent experience at a U.S. coal-fired boiler reflects a catalyst replacement frequency of one-half layer annually or 16% of the

catalyst replaced annually.62 On dry-bottom, coal-fired

U.S. boilers equipped with full SCR, the planned time

between catalyst changes on a typical unit is typically

24,000 operating hours or 3 years of operation.41,60

The catalyst replacement frequency for

boilers that reinject fly ash may be on

the order of 14,000 hr, or nearly 2

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.

Difficulties with arsenic poisoning

of a 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 will increase catalyst replacement frequency and/or increase catalyst loading compared with

low-arsenic applications. For example,

at Merrimack 2, a cyclone boiler with

100% fly ash reinjection, the expected

time between the replacement of layers

is 14,000 operating hours, which is less

than the typical time between the replacement of catalyst

layers for SCR systems on dry-bottom, pulverized-coal

boilers (24,000 operating hours).41,63,64

In the United States, low-sulfur, high-calcium subbituminous PRB coals are used at many power plants to

comply with SO2 regulations. Because these coals are

unique to the United States, there was no experience with

SCR on facilities firing these coals until recently. There is

some concern that firing of such coals may lead to deposits on SCR catalysts, which, in turn, may experience accelerated deactivation. According to one supplier, the rate

of catalyst deactivation is expected to be within an acceptable range for commercial use.65 The operating experience of the first year for a SCR system on a PRB coal-fired

electric utility boiler has demonstrated the system to be

capable of 93% NOx removal with a maximum of 3 ppm

NH3 slip.66

Another issue is catalyst arsenic poisoning on drybottom boilers firing coals from Western Pennsylvania

and West Virginia. These coals do not have unusually

high arsenic contents (although higher than that of European coals). However, these coals sometimes have unusually low contents 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 2.5% by

weight of the fly ash), it is possible that arsenic will not be

Figure 5. Schematic of a SCR application.

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1376 Journal of the Air & Waste Management Association Volume 55 September 2005
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 and is permanently

poisoned. To address this issue, some facilities have accelerated their catalyst management plans, and others are

adding small amounts (1–2% of coal feed rate) of pulverized limestone to their coal.60 At two boilers in the United

States, a limestone addition to keep CaO level in fly ash at

3– 6% has been used to maintain the SCR catalyst deactivation rate at desired levels.67

One of the concerns with high-dust SCR systems is

the potential for ammonium bisulfate (NH4HSO4) formation downstream of the catalyst leading to fouling of APH

baskets over time. Several units appear to have experienced this impact.60,68 APH fouling by NH4HSO4 is driven

by the following: (1) the presence of sufficient SO3 and

NH3 and favorable conditions (e.g., temperature) for the

NH4HSO4 formation to occur; and (2) APH operational

and design characteristics that are favorable for deposition of the formed NH4HSO4. The SCR catalyst will enhance the concentration of SO3 in the flue gas by oxidizing a portion of the SO2 in the flue gas into SO3.

Consequently, SO3 will react with any NH3 slip from the

SCR reactor to form the ammonium sulfate (NH4)2SO4

and/or bisulfate as follows:

2NH3  SO3  H2O 3 (NH4)2SO4 (5)

NH3  SO3  H2O 3 NH4HSO4 (6)

Normally, dry (NH4)2SO4 does not create a fouling

problem. However, NH4HSO4 combined with fly ash constituents forms a moist and sticky material that will tend

to deposit on the APH in regions where the gas temperature falls below 450 °F.68,69 The potential for APH fouling

can be alleviated by maintaining NH3 slip levels between

2 and 5 ppm.70 Other methods to reduce this potential

include:60 sootblower additions, modification of air

heater hot-end surfaces to enhance cleaning, modification of air heater cold-end surfaces to minimize and isolate fouling (e.g., install enamel coated baskets), and more

frequent water washings at higher flows and pressures. It

is industry practice to install enamel-coated baskets on

the cold end of the air heater to prevent APH fouling, to

improve cleanability, and to protect the baskets from

corrosion.69

SCR has been extensively used to control NOx from

hundreds of utility and industrial boilers in Japan and

Germany and in several U.S. coal-fired and gas-fired utility boilers. Deployment of SCR at U.S. coal-fired plants for

new and retrofit applications initially took place in 1991

and 1993, respectively.71 Since then, 150 SCR systems

have been installed on utility coal-fired boilers.72 Many of

these applications are designed to provide NOx reductions

of 80%, sometimes as much as 90% reduction, with 2

ppm NH3 slip.73

It is informative to examine the extent of NOx reduction being achieved by SCR installations. The performance of 20 SCR systems operating in the United States

with low-NOx emissions is shown in Table 4. The data in

this table reflect that in 2003 these units achieved NOx

emission rates between 0.04 and 0.07 lb/106 Btu, likely

with NOx reduction efficiencies 85%.

Enhancements in Secondary Control

Technologies

Recent enhancements in secondary control technologies

have been aimed at providing large NOx reductions, using

reagents more efficiently, and addressing any public concerns with the transport and handling of the NH3 reagent

Table 4. SCR performance for electric utility coal-fired units.

Plant Namea Unita

Unit Size

(MW)a

NOx Rate

(lb/106 Btu)

Third Quarter 2003b

NOx Reduction

Efficiency (%)c

Allen 2 248 0.07 86

Bowen 1BLR 706 0.06 88

Bowen 2BLR 704 0.06 88

Bowen 3BLR 893 0.06 88

Bowen 4BLR 913 0.06 88

Chesapeake 3 156 0.07 86

Chesterfield 4 166 0.07 86

Cheswick 1 562 0.05 90

Dan E. Karn 2 260 0.05 90

East Bend Station 2 600 0.07 86

Gavin 2 1,300 0.07 86

Hammond 4 505 0.06 88

Keystone 1 850 0.04 92

Keystone 2 850 0.05 90

Miller 3 670 0.06 88

Miller 4 669 0.07 86

Montour 1 760 0.04 92

Montour 2 745 0.04 92

Mountaineer 1 1,300 0.06 88

Trimble County 1 435 0.07 86

Wansley 1 864 0.05 90

Wansley 2 868 0.05 90

a

The units shown are those that achieved NOx emission rates 0.07 lb/106 Btu, as

reflected in the EPA emissions database at http://www.epa.gov/airmarkets/emissions/raw/index.html; b

The NOx rates reported are for SCR systems installed and

operated only during the ozone season, as required under the Ozone Transport

Commission Budget Program. Emissions data are from the EPA emissions database

at http://www.epa.gov/airmarkets/emissions/raw/index.html; c

In the absence of reliable SCR inlet NOx data, the SCR efficiencies are estimated using an inlet NOx level

of 0.5 lb/106 Btu, assuming this level can be achieved with primary controls.

Srivastava et al.

Volume 55 September 2005 Journal of the Air & Waste Management Association 1377
used in SCR applications. These enhancements are described below.

Advanced Gas Reburning. With advanced gas reburning

(AGR), a nitrogen compound (typically urea or NH3) is

added downstream of the reburning zone. The reburning

system is adjusted for somewhat lower NOx reduction to

produce free radicals that enhance SNCR NOx reduction.41 AGR systems can be designed in the following two

ways: (1) nonsynergistic, which is essentially the sequential application of NGR and SNCR (i.e., the nitrogen agent

[urea or NH3] 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 NH3 slip in nonsynergistic

systems, the nitrogen compound must be injected so that

it is available for reaction with the furnace gases within a

temperature zone of 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%. However,

it could not reduce NH3 slip to 10 ppm.74

Fuel-Lean Gas Reburning. Fuel-lean gas reburning (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.41 The gas is

normally injected into a lower temperature zone than

that in NGR. Whereas NGR requires 15–20% of furnace

heat input from gas and requires burnout air, the FLGR

technology achieves NOx control using 10% gas heat

input and no burnout air. FLGR has been demonstrated to

reduce NOx emissions by 33– 45% at full load, with 7%

of the heat input attributed to the reburn fuel.75 The

technology has been installed at 12 U.S. boilers.76

Amine-Enhanced Fuel-Lean Gas Reburn. Amine-enhanced

fuel-lean gas reburn (AEFLGR) is similar to AGR except

that burnout air is not used, and the SNCR reagent and

reburn fuel are injected to create local, fuel-rich NOx

reduction zones in an overall fuel-lean furnace.41 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 NH3 or urea is used in SNCR. In SNCR, the NOx

reduction occurs in an oxidizing environment, whereas in

AEFLGR, the NH3 or urea is injected into a locally 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.

AEFLGR has been tested at Carolina Power and Light

198 MW Ashville Unit 1 to achieve NOx emissions of

0.28 lb/106 Btu at all loads. Average NH3 slip in this

testing was reported to be 3 ppm.77 The technology has

also been installed for commercial operation at Public

Service Electric & Gas (PSE&G) Mercer Station Units 1 and

2. In optimization testing on Unit 2, AEFLGR application

achieved 55–70% NOx reductions using 7–10% natural

gas heat input, with NH3 slip maintained at 5 ppm.78

Hybrid-Selective Reduction. In hybrid-selective reduction

(HSR), a SNCR system is used to achieve some NOx reduction and to produce a controlled amount of NH3 slip that

is used in a downstream in-duct SCR reactor for additional

NOx reduction.41,79 The HSR technology has lower capital

costs than SCR, allows installation to be phased in, provides better reagent utilization than SNCR, and can provide very good NH3 slip control. A test conducted using

this hybrid system on a full-scale boiler showed 95% NOx

reduction with 5 ppm NH3 slip and 55% reagent utilization.

In-Duct SCR. There has been one full-scale demonstration

installation of in-duct SCR on a coal-fired unit at the

PSE&G Mercer Generating Station. The approach entailed

installing the catalyst in an expanded duct rather than a

separate reactor, and it was selected because the site did

not have the necessary room for a full SCR and the associated ductwork; using a full SCR would have required

substantial, costly modifications to the facility. At Mercer,

the in-duct SCR handles 25% 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% NOx reduction with 10

ppm NH3 slip at the air-heater inlet.80 Another application on the natural gas/fuel oil-fired 530 MW Lake Hubbard Station Unit 2 boiler demonstrated 90% NOx removal with a 10 ppm NH3 slip.81

To enhance the performance of in-duct SCR, some vendors can offer catalyst-coated air-heater baskets for Lungstrom-type air heaters. In these situations, the existing hotend baskets are removed from the Lungstrom APH and

replaced with baskets coated with a catalyst. These catalystcoated baskets may be used separately or in addition to

in-duct SCR. Testing at Mercer Generating Station and experience in Europe demonstrate that this approach is capable of providing some additional NOx reduction and, more

importantly, can be very effective in controlling NH3 slip.

For example, the catalytic air-heater baskets installed at Mercer Station provided sufficient NH3 slip control so that an

additional 20% reduction was achieved while maintaining

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1378 Journal of the Air & Waste Management Association Volume 55 September 2005
the NH3 slip limit.80 However, catalytic air heater technology generally will not provide sufficient reduction of NOx to

be a stand-alone technology.82

Urea-to-NH3 Processes. Typically, anhydrous (pure liquefied) or aqueous (19 –29% solution in water) NH3 has been

used as the reagent in SCR applications. However, public

concerns with transport and handling of NH3 and associated Occupational Safety and Health Administration requirements have led to the development of processes in

which a NH3 reagent is produced from urea at the SCR

application site.83 On the basis of equivalent NH3 delivered,

anhydrous NH3 is less expensive than urea. However, urea is

generally lower in cost than aqueous NH3, especially more

dilute solutions of aqueous NH3. There are several alternative urea-to-NH3 processes being offered commercially. Typically, these processes use on-site hydrolysis to produce NH3

reagent from urea.

Emerging NOx Control Technologies

In response to the environmental concerns of NOx emissions and the corresponding regulations, the U.S. Department of Energy-National Energy Technology Laboratory

(DOE-NETL) is carrying out a comprehensive research and

development effort under its Innovations for Existing

Plants Program. This effort focuses primarily on enhancing the efficiency and environmental performance of the

existing fleet of fossil fuel-fired power systems by developing new technologies capable of controlling NOx emissions to a level 0.15 lb/106 Btu at a cost significantly

lower than state-of-the-art technology, SCR. The research

also addresses related issues, such as UBC and waterwall

wastage. NOx control technologies under development by

DOE-NETL include layered NOx control for cyclone boilers, oxygen-enhanced combustion, refinements for lowNOx tangential firing systems, and preheat combustion.

These are described below.

Layered NOx Control for Cyclone Boilers. Cyclone burners

create an intense flame that melts the ash to form slag.

The high temperature generated by this burner results in

higher uncontrolled NOx emissions, typically 1.2 lb/106

Btu. These units, which account for only 8% of the U.S.

generating capacity, emit nearly 20% of the coal-fired

NOx emissions. Research has shown that the injection of

NH3 or urea into the high-temperature region of the

boiler can lead to significant noncatalytic NOx reductions. This concept, when applied to staged cyclone-fired

furnaces, uses the nitrogen-containing additive to increase the NOx reduction rate in the lower furnace. Field

testing has confirmed that this technology can reduce

NOx emissions by 25–30% beyond OFA levels with 1

ppm NH3 slip.84 The inclusion of SNCR can be used for an

additional 35% NOx reduction with 5 ppm NH3 slip.84

Commercial scale tests at the Conectiv 138 MW B.L. England Unit 1 and the AmerenUE 500 MW Sioux Unit 1

have demonstrated that NOx emissions of 0.25 lb/106 Btu

are achievable.

Oxygen-Enhanced Combustion. This novel technology replaces a small fraction of the combustion air at the burner

with oxygen.85,86 By generating a higher-flame temperature, nitrogen compounds from the coal are released in

the lower sections of the boiler enabling air staging to be

more effective in reducing NOx. Experimental work using

a burner fired at 24 million Btu/hr with high-volatile and

medium-volatile bituminous coals demonstrated that

NOx concentrations as low as 0.11 lb/106 Btu are achievable. Data from the experiments show that even when the

baseline (without oxygen) NOx emissions are very low,

oxygen addition can reduce the NOx even further and

that the reductions are relatively independent of the initial NOx concentration. In addition to the reduction in

NOx, benefits are achieved in the areas of reduced UBC

and opacity, increased boiler efficiency, and reduced fan

limits. The data suggest that there is little or no impact of

oxygen purity resulting from current production methods

on the effectiveness of the technology. In achieving NOx

reductions of 50%, the parasitic load requirements for this

technology are estimated to be 1% of a plant output.

Demonstrations at two utility boilers have proven the

benefits of the technology. Preliminary economic analysis

indicates that cost savings of 40 –50% can be realized

when compared with SCR.

Refinements for Low-NOx Tangential-Firing Systems. A recently completed comprehensive study identified lowcost, efficient NOx control refinements for pulverized coal

tangential-fired boilers.87 The testing evaluated a number

of low-NOx subsystems under realistic boiler combustion

system conditions at a large-pilot scale of 50 – 60 million

Btu/hr. Among the technologies evaluated were finer coal

grinding, oxidative pyrolysis burners, windbox auxiliary

air optimization, and various burner zone-firing arrangements in concert with strategic deployment of OFA. Other

technologies, such as an advanced boiler control system,

coal and airflow balancing, and a Carbon BurnOut combustor, were also evaluated.

Testing of the refinements with three test coals

showed that both NOx and combustion performance are a

strong function of coal properties. From the standpoint of

combustibles in the flue gas, the subbituminous coal

showed the lowest combustibles (carbon in ash and CO),

followed by the high-volatile bituminous and mediumvolatile bituminous coals. Conversely, the more reactive

Srivastava et al.

Volume 55 September 2005 Journal of the Air & Waste Management Association 1379
subbituminous coal showed the lowest NOx (0.08 lb/106

Btu) followed by the moderately reactive, high-volatile

bituminous (0.12 lb/106 Btu) and least-reactive, mediumvolatile bituminous (0.17 lb/106 Btu) coals. Many of the

firing system components described in the study above

can be retrofitted to an existing system, resulting in improved NOx emissions without significantly impacting

the carbon in fly ash levels. Nineteen commercial boilers

firing subbituminous coal that use aspects of the technologies demonstrated in this study are achieving NOx emissions  0.15 lb/106 Btu.

Preheat Combustion System. The preheat combustion system, also known as Methane de-NOx, uses gas-fired coal

preheating to destroy NOx precursors and prevent NOx

formation.88 In this process, a concentrated pulverized

coal stream enters a preheat chamber where flue gas from

natural gas combustion (3–5% thermal input) is used to

rapidly heat the coal up to 1500 °F before coal combustion in the burner. This thermal pretreatment releases

coal volatiles, including fuel-bound nitrogen compounds,

into an oxygen-deficient atmosphere, which converts the

nitrogen compounds into N2 rather than NOx. Testing

with a 3-million Btu/hr burner has achieved NOx levels

0.15 lb/106 Btu without postcombustion flue-gas

cleanup technology.

MULTIPOLLUTANT CONTROL TECHNOLOGIES

The technologies addressed up to this point are those

applied exclusively for NOx control. A number of multipollutant technologies that control NOx along with other

pollutants from coal-fired sources and are in more advanced stages of development commercialization are described below.

Electron Beam Process

The Electron Beam (E-Beam) Process provides simultaneous removal of NOx and SO2.89 –91 The process equipment is located downstream of the plant PM control

device (ESP or baghouse). The first component is an evaporative spray cooler, where flue gas is cooled down to

140 –150 °F. Gaseous NH3 is injected into the flue gas

stream, either before or after the spray cooler. In the main

process vessel, which follows the spray cooler, flue gas is

irradiated by a beam of high-energy electrons, while water

is added to counteract the temperature rise. The irradiation generates hydroxyl radicals and oxygen atoms,

which oxidize NOx and SO2. These oxidized species mix

with water present in the flue gas to form sulfuric and

nitric acids, which are neutralized by NH3.

The byproducts of the E-Beam process are ammonium sulfate and ammonium sulfate-nitrate. These solids

are collected in either an ESP or a baghouse, located downstream of the main process vessel, and can be used as fertilizer after processing into a granular form. The solids are

small and sticky and may pose problems to the collection

device. A combination of ESP and baghouse has been proposed as being more effective. In addition, the use of an

inert material (e.g., diatomaceous earth) has been considered to make it easier to clean the bags in a baghouse.

The E-Beam process can achieve NOx reductions as

high as 90% and SO2 reductions of 95%. NOx removal

primarily depends on the E-beam dosage. A dose of 0.3–

0.6 mrad is required to achieve 50% NOx reduction,

whereas 90% NOx removal requires 2.7 mrad. Also,

higher NOx removals are obtained at higher flue-gas temperatures. In contrast, SO2 removal requires smaller Ebeam dosages and is promoted by lower gas temperatures.

NOx removal is also aided by higher flue-gas SO2 concentrations, making the process better suited for high-sulfur

applications.

A significant impact of incorporating the E-Beam process in a plant is its relatively high auxiliary power requirement. This requirement depends heavily on the NOx reduction being sought. For low-NOx reductions (10%), the

auxiliary power is generally limited to 2% of the plant output; however, for NOx reductions 60%, it can reach 5%.

The E-Beam technology is in an early commercialization stage with a number of demonstration projects, but

there are no operating commercial applications on coal. The

coal/oil demonstrations include a 1986 pilot-scale testing of

an 8-MW slipstream at the Indianapolis Power and Light

Stout Station, a 1992 pilot-scale testing of 12,000 Nm3

/hr

slipstream at Nishi-Nagoya Plant in Japan, and full-scale

testing at the 90 MW Chengdou Power Plant in China. The

demonstrated reductions at these sites were between 15%

and 60% for NOx and 85% and 92% for SO2. After a successful demonstration, the process was installed in the

Nishi-Nagoya Unit 1, which burns high-sulfur residual oil.

ROFA-ROTAMIX

This technology involves use of the ROTAMIX system in

conjunction with the ROFA system described earlier for

NOx control only.28,92 The ROTAMIX system is comprised

of lances and other supporting equipment for injection of

various chemicals or additional fuel (e.g., reburn gas). So

far, urea or NH3 has been used in the ROTAMIX for NOx

control and limestone and trona for SO2 control. Future

plans include injection of sorbents for the removal of

heavy metals, including Hg.

ROFA and ROTAMIX systems together can provide

greater NOx reduction levels and simultaneous removal of

SO2. The actual performance in each application would be

determined by key boiler features, including the height

between the top burner level and furnace outlet, furnace

Srivastava et al.

1380 Journal of the Air & Waste Management Association Volume 55 September 2005
dimensions, and top furnace-level temperature. The first

and second of these features determine whether adequate

residence time is available to ensure the complete combustion of unburned fuel particles that increase because of the

withdrawal of combustion air from the main burner region

(resulting from operation of ROFA). The second and third

features affect the penetration/mixing of injected air and

chemicals into the furnace flue gases and reaction of the

chemicals with the flue gas pollutants, respectively.

The major impacts of this technology on the plant

performance include increased auxiliary power consumption (1% of plant output) and introduction of new consumables (chemicals). Other minor impacts, which vary

with site-specific factors, may include a small increase in

UBC level and small reductions in steam temperatures

and boiler/plant efficiencies.

ROFA-ROTAMIX technology has 10 operating commercial applications in Sweden and 16 in the United

States.28 The Carolina Power and Light 150 MWe Cape

Fear Unit 5 and 175 MWe Cape Fear Unit 6 have achieved

70% NOx reductions with the technology.28 At present

in the United States, sorbent injection tests have been

conducted only at Cape Fear Unit 5.93 These tests used

limestone and trona to examine sustainable SO2 and Hg

reductions at low capital and operating costs. Stable SO2

reductions of 69% were achieved with trona and 64%

with limestone. Hg reductions of 89% were achieved with

limestone and 67% with trona. Slagging in the superheater section was found to be a major operational concern in the sorbent injection tests.

SNOX

The SNOX technology involves removal of both NOx and

SO2 in separate catalyst vessels.94 –97 In addition, reductions in PM and trace metals are also achieved with this

technology. The main components of the system are a

high-efficiency baghouse, gas-to-gas heat exchanger, SCR

catalyst vessel, SO2 reactor vessel, and a glass-tube condenser, installed in that order. The baghouse removes PM

to minimize cleaning frequency of the downstream catalysts. The heat exchanger transfers heat from the hotter

gases exiting the SO2 reactor to the gas stream entering

the SCR vessel, thereby reducing the external energy use.

NH3 is injected upstream of the SCR vessel to remove

NOx, which is converted to nitrogen and water by the

reactions taking place in the vessel.

The SO2 reactor consists of a burner and a catalyst to

oxidize SO2 to SO3. Flue gases exiting the SO2 reactor pass

through the above heat exchanger and then to the glasstube condenser (wet gas sulfuric acid [H2SO4] condenser)

that allows SO3 to hydrolyze to concentrated H2SO4. Ambient air is used as the cooling medium in the condenser.

The heated air is recirculated to the burner in the SO2

reactor and to a heater installed to reheat flue gases discharging to the stack from the condenser. The SO2 reactor

also oxidizes any NH3 slip from the SCR operation, eliminating concerns with the downstream equipment fouling by ammonium compounds and permitting SCR operation at higher-than-normal stoichiometry. These higher

stoichiometries allow the use of smaller catalyst volumes

and higher NOx reduction efficiencies.

The NOx and SO2 reduction capabilities of the SNOX

technology can exceed 90% each. Improved PM and trace

element removals are also obtained through the use of the

high-efficiency baghouse.

The major impacts of SNOX technology on plant

performance include increased auxiliary power consumption and introduction of NH3 as a consumable. The technology produces a salable H2SO4 byproduct.

The SNOX technology is in an early commercial development stage. Five demonstration projects have been

completed to date, one in the United States and the other

four in Europe and Japan. The U.S. demonstration was on

a 35-MWe equivalent slipstream of flue gas from the Ohio

Edison Niles Unit 2, firing a 3.4% sulfur coal. At this plant,

an average NOx reduction of 94% and SO2 reduction in

excess of 95% were demonstrated. The first commercial

application of the SNOX technology started operation in

1999 at the AGIP Petroli SAP Gela plant in Italy. The

system is designed for 90% NOx and 94% SO2 removal at

this petroleum coke-fired facility.

SOx-NOx-Rox-Box

The SOx-NOx-Rox-Box (SNRB) technology provides simultaneous removal of NOx, SO2, and PM in one unit–a

high-temperature baghouse.91,98 NOx removal is achieved

by injecting NH3 into the flue gas stream ahead of a SCR

catalyst, which is placed on the baghouse high-temperature ceramic filters. SO2 removal is achieved by injecting

either a calcium-based or sodium-based sorbent (e.g., hydrated lime, calcium bicarbonate, or sodium bicarbonate)

upstream of the baghouse. As its primary design function,

the baghouse also removes PM.

SNRB has been demonstrated to provide up to 90%

NOx reduction and 80 –90% SO2 reduction. Increased auxiliary power consumption and introduction of NOx and

SO2 control reagents are the major related impacts on

plant performance.

Experience with the SNRB technology is restricted to

a 5-MWe slipstream demonstration at the Ohio Edison

Burger Unit 5, a 156-MW unit burning high-sulfur bituminous coal. Additional demonstrations and commercial

experience are required to confirm full-scale NOx/SO2 reduction effectiveness and operating life of the ceramic bag

filters. A 3800-hr test was conducted in 1992 on three

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Volume 55 September 2005 Journal of the Air & Waste Management Association 1381
filters at a testing facility (Fabric Filter Development Test

Facility in Colorado) that showed no signs of failure.

Activated Coke Process

This process provides simultaneous removal of NOx, SO2,

and Hg and consists of the following three steps: (1) adsorption, (2) desorption, and (3) optional by-product recovery.99 –101 In the adsorption step, flue gases pass through a

bed of activated coke moving downwards in a two-stage

adsorber at a constant flow rate. In the first stage, SO2 is

removed by adsorption into the activated coke, where it

forms H2SO4 and is maintained on the coke inner surface at

temperatures ranging from 212 to 392 °F. More than 90% of

the PM is also removed in this first stage. In the adsorber

second stage, activated coke acts as a catalyst in the decomposition of NOx to nitrogen and water after the injection of

NH3 in the activated coke bed. This chemical reaction occurs

in the 212–392 °F temperature range.

Over time in operation, the adsorption capacity of

the activated coke bed declines. The spent bed material is

then conveyed by a bucket elevator to the desorber vessel,

where activated coke is regenerated in a reaction occurring between 572 and 932 °F. During this regeneration,

contaminants adsorbed previously in activated coke decompose to nitrogen, SO2, and water. After cooling, the

regenerated coke passes through a vibrating screen to

remove fines, and then it is returned to the adsorber. The

fines are conveyed to the boiler for combustion.

Hg is also removed by adsorption. Once adsorbed, Hg

must be collected in a form suitable for disposal. In one

method, a selenium filter is used, which absorbs Hg from

flue gases and forms HgSe, a chemically stable compound.

The selenium filter has an operating life of four to five

years and, once spent, it must be disposed of in a hazardous waste facility. Other methods of Hg removal have

been considered (e.g., H2SO4 plant off-gas, SO2-rich gas

off-gas, etc.), but none have been tested.

Two of the possible byproducts for the activated coke

process are elemental sulfur and H2SO4. Additional equipment (e.g., a reduction column, Claus unit) must be,

incorporated to obtain these byproducts.

The demonstrated NOx and SO2 control efficiencies

for this process have ranged from 60 to 80% and 90 to

98%, respectively. Higher NOx reduction efficiencies can

be obtained with lower flue-gas SO2 concentrations. Also,

based on pilot test results, 90 –99% Hg removal is projected for this process.

The impacts of the activated coke process on the

plant performance include increased auxiliary power consumption and use of activated coke and NH3. Activated

coke is a carbonaceous material with large porous innersurface area. One issue with the application of this process

is the high cost of this reagent.

The activated coke process is commercially available

in Europe and Japan. Several full-scale installations exist,

including coal-fired power plants (up to 600 MW). These

installations were designed for only NOx and/or SO2 removal. At present, no commercial installations with Hg

control exist. Also, there are no demonstrations of this

process in the United States thus far.

Electrocatalytic Oxidation

The electrocatalytic oxidation (ECO) process provides simultaneous removal of NOx, SO2, and Hg.102–104 The main components of this process include a barrier discharge reactor (BDR),

an absorber tower (AT), a wet ESP (WESP), and a coproduct

processing/Hg removal (CPMR) system. The BDR is located

downstream of the plant PM control device (ESP or baghouse).

Its main function is to oxidize the flue gas pollutants into

forms readily removable in the downstream equipment. Large

amounts of NOx and Hg present in the flue gas oxidize to NO2,

nitric acid, and mercuric oxide, whereas a relatively small

amount of SO2 oxidizes to H2SO4.

The BDR uses a dielectric discharge, which is formed

by placing a dielectric insulating material between two

discharge electrodes. High voltage is applied to these electrodes, causing the flue gas to breakdown and form gas

phase radicals, such as hydroxyl and atomic oxygen,

through the collision of electrons with water and oxygen

molecules present in the flue gas stream. These radicals

are responsible for the oxidation reactions taking place

within the reactor. These reactions can be made to occur

at relatively low gas temperatures (150 –300 °F).

Flue gases from the BDR are treated in the AT, which also

houses the WESP. The AT is a two-stage process with an absorption stage for absorbing the pollutants (mainly unoxidized

SO2 and NO2) and a concentrating stage at the bottom. An

aqueous NH3 solution and certain vendor-proprietary chemical are used as scrubbing agents in the AT. These react with the

pollutants to form ammonium nitrate and sulfate, which collect in the AT bottom. The WESP, located at the top of the AT,

captures acid aerosols, fine PM, and oxidized Hg, which are all

washed down into the tower bottom.

Liquid effluent from the bottom of the AT is treated

in the CPMR system. This system includes a filter to remove ash and an activated carbon filter to remove Hg.

The liquid effluent can be additionally processed to produce ammonium sulfate and nitrate fertilizer.

The reactor in the ECO process can be designed in a

variety of configurations, including coaxial cylinders, cylindrical electrodes with plates, and parallel plate electrodes. For retrofit installations, the reactor components

can also be installed in the last fields of an ESP if the

remaining ESP fields can provide adequate PM removal.

The emission reduction capabilities of the ECO process can be as high as 90% for NOx, 98 –99% for SO2, and

Srivastava et al.

1382 Journal of the Air & Waste Management Association Volume 55 September 2005
95% for Hg. In addition, high removal rates (up to 95%)

for fine particles are also achievable. The best efficiencies

are achieved when the SO2:NOX molar ratio is 3.

A relatively high auxiliary power consumption requirement is one of the main impacts of the ECO process

on the plant performance. The BDR, fans, and pumps are

the major power users. The power for the BDR is largely

determined by the amount of the required NOx reduction. Other impacts of the ECO process include both the

use of NH3 and certain vendor-proprietary chemicals as

scrubbing agents and the need for steam to provide heat

for by-product crystallization.

The ECO process is in the demonstration stage of development. The experience to date includes laboratory testing and pilot-scale (2000 std ft3

/min of gas flow) testing

conducted at the First Energy Burger Plant. Construction of

a 50-MW commercial slipstream demonstration (110,000

scfm of gas flow) has been recently completed at the Burger

Station (156 MW), and shakedown testing of the process has

been initiated in the fall of 2004.

NOXSO

The NOXSO process is a dry, regenerable system capable of

removing both SO2 and NOx in flue gas from coal-fired

utility boilers burning medium-to-high sulfur coals.105 In

the basic process, the flue gas passes through a fluidized-bed

adsorber located downstream of the precipitator; SO2 and

NOx are adsorbed by the sorbent, which consists of spherical

beads of high-surface-area alumina impregnated with sodium carbonate. Cleaned flue gas then passes through a

baghouse to the stack.

The NOx is desorbed from the NOXSO sorbent when

heated by a stream of hot air to 1200 °F. The desorbed

NOx is recycled to the boiler where equilibrium processes

cause destruction of the NOx. The adsorbed sulfur is recovered from the sorbent in a regenerator where it reacts

with methane at a high temperature to produce an off-gas

with high concentrations of SO2 and hydrogen sulfide.

This off-gas is processed to produce elemental sulfur,

which can be additionally processed to produce liquid

SO2, a higher-valued by-product.

The process is expected to achieve SO2 reductions of

98% and NOx reductions of 75–90%. Current experience

with the process has been limited to proof-of-concept (10

MW) evaluations at the Ohio Edison Toronto Station and at

the combined heat and power plant located at the University of Denmark. FLS miljo, a licensee of the technology, was

responsible for the installation in Denmark.

Copper-Oxide

The copper-oxide (CuO) process is a flue-gas treatment

process that is capable of simultaneously removing SO2

and reducing NOx from flue gas of a conventional coalfired boiler.106 CuO takes advantage of the chemical absorption of SO2 on 1/8-in. alumina spheres impregnated

with copper to form copper sulfate and the subsequent

ability of this sulfate to act as a selective reduction catalyst

of NOx in the presence of NH3. The process is uniformly

effective for various coals and is independent of the sulfur,

nitrogen, and ash content of the coal. Unlike wet scrubber

processes, no waste is generated. The captured SO2 can be

reduced to elemental sulfur, a marketable by-product.

Figure 6. Locations of NOx control processes relative to power plant hardware and other emission control equipment.

Srivastava et al.

Volume 55 September 2005 Journal of the Air & Waste Management Association 1383
The CuO process has four major processing elements:

absorber, regenerator, solids heater, and combustor. The

absorber is installed upstream of the boiler APH. In the

absorber, SO2 is absorbed by the sorbent, and NOx is

reduced by injecting NH3 into the incoming flue gas

stream. From the absorber, the treated flue gas is transported to the remaining portions of the flue gas train.

The spent sorbent is pneumatically transported

from the absorber to a solids heater. In the solids

heater, the sorbent temperature is elevated to the target

reaction temperature for regeneration. This is accomplished by contacting the sorbent with the hot combustion gas of the combustor fired on natural gas. The

heated spent copper sulfate sorbent enters the regenerator, where it is reduced with natural gas to regenerate

the copper. The regeneration step results in a concentrated stream of SO2 that can be processed in a sulfur

recovery plant. From the regenerator, the sorbent is

Table 5. A summary of NOx control technologies.

Technology

NOx Removal

Efficiency (%)a Potential Plant Impacts Comments

LNB Up to 50 Requires deeper furnaces

May increase corrosion of furnace walls

May increase furnace fouling

Greater reduction possible for boilers with more

facilitating design features

OFA Additional 10–25%

beyond LNB

May reduce boiler efficiency (increased UBC)

May affect fly ash quality

May be used in conjunction with LNB

LNB with multilevel OFA 50% with PRB coal Higher NOx emissions expected for coals with lower fuel

volatile content

—

ROFA 45–60 Uses booster fan Offers improved distribution of combustion products

and temperature variation across the furnace

Reburning 39–67 Flame stability

May increase CO emissions

Potential for increased boiler tube corrosion

Choice of reburning fuel affects plant design

SNCR 30–66 Efficiency higher for smaller boilers

May need multiple injection zones

Choice of chemical affects plant design

Effective operation even beyond 1150°C

SCR 80–90 Catalyst deactivation requires implementation of catalyst

management plans

As poisoning on wet-bottom boilers requires CaCO3 addition

and/or accelerated catalyst replacement

Good distribution of ammonia critical

PRB coals may cause accelerated catalyst

deactivation

AGR 68–76 Minimum ammonia slip of 10 ppm for synergistic design

Nitrogen compound must be injected 1000 °C for

nonsynergistic design

Natural gas reburning/SNCR synergistic and

nonsynergistic design options

FLGR 30–45 Careful injection and controlled mixing of natural gas

required

No burnout air required

Lower percent of heat input required from reburn fuel

than for reburning

AEFLGR 55–73 Nitrogen compound injected into reducing zone Design similar to AGR; NOx removal efficiency is load

dependent

HSR Up to 95 Lower capital cost than standalone SCR

Ammonia slip 5 ppm

Allows phased installation

Improves reagent utilization

In-duct SCR 85–90 Allows SCR installation on space constrained units

May supplement SNCR process

Catalytic air heater baskets add-ons available

Layered NOx control for

cyclone boilers

Additional 25–30%

beyond OFA

Ammonia slip 1 ppm

May be supplemented by SNCR for an additional 35%

reduction (5% ammonia slip)

Commercial scale tests conducted (138 MW)

Oxygen-enhanced combustion 50 Auxiliary power requirements 1%

Reduced unburnt carbon and opacity compared to baseline

conditions

Reductions relatively independent of the initial NOx

concentration. Demonstrations completed at two

utility boilers

Refinements for low-NOx

tangential-firing systems

76–84 Does not significantly affect unburnt carbon levels in ash

Combustion performance strong function of coal properties

May require finer grinding of coal

OFA may also be used

Preheat combustion system 42–67 3–5% thermal input used for preheating of coal Also known as Methane de-NOx

a

Possible or reported.

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1384 Journal of the Air & Waste Management Association Volume 55 September 2005
transported back to the absorber for reuse. Once sorbent enters the system from the regenerator, it is

quickly oxidized to copper oxide. Testing to date has

been limited to pilot scale tests in which efficiencies of

SO2 removal and NOx reduction have been at 90%.

CONCLUSIONS

Recently, a number of regulatory actions have been taken

in the United States that are 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 reviewed these technologies and their applications. Figure 6 shows the locations of NOx control technologies discussed in this paper, relative to power plant

hardware and other emission control equipment. Additionally, Tables 5 and 6 summarize emission reduction

performance, potential plant impacts, and benefits/drawbacks for each of these technologies.

Primary control technologies have been widely implemented on U.S. coal-fired utility boilers to comply

with the NOx emissions reduction requirements of the

Title IV NOx Program. Data reflect that average NOx reductions for specific primary controls have ranged from

35% to 63% from 1995 emissions levels. In particular,

applications of LNB resulted in reductions of 35%, on

average, from 1995 levels. Recent advances in primary

control technologies have been aimed at providing

greater NOx reduction and include LNB with multilevel

OFA, ROFA, and combustion improvement techniques.

The secondary NOx control technologies applied

on U.S. coal-fired utility boilers include reburning,

SNCR, and SCR. Of these boilers, 26 have either installed or demonstrated reburning as their secondary

NOx control technology. The NOx reductions achieved

at these boilers ranged from 25 to 68%. Many of the

reburning applications are not operational at this time,

probably because of plant-specific economics associated

with elevated natural gas prices and other factors.

In 2003, currently operational reburning applications

on coal-fired U.S. electric utility boilers achieved NOx

emission rates between 0.277 and 0.385 lb/106 Btu.

Thirty-six U.S. coal-fired utility boilers have installed

SNCR. Reported NOx reductions achieved at these applications

ranged from 15 to 66%. Data also show that whereas smaller

boilers may be able to achieve 60% NOx reduction, larger

boilers may be capable of achieving reductions of only 30%.

Recently, SCR has been installed at 150 U.S. coalfired utility boilers. Many of these applications are designed to provide NOx reductions of 80%, sometimes as

much as 90% reduction, with 2 ppm NH3 slip. Data on

the performance of 20 SCR systems operating in the

United States with low-NOx emissions reflect that in 2003

Table 6. A summary of multipollutant control technologies.

Technologya

NOx Removal

Efficiency (%)a Potential Plant Impacts Comments

E-Beam SO2: 95

NOx: 90 Hg: zero

Extensive byproduct treatment required

Auxiliary power requirements may reach 5% for NOx

reduction 60 %

Nitrogen fertilizer concept has not been demonstrated

ROFA/ROTAMIX SO2: 64–69

NOx: 80 Hg: 67–89

May increase erosion of boiler tubes

May increase in boiler slagging and fouling

Reduction in superheat and reheat temperatures have

been experienced

Performance of ROFA in large boilers may degrade

SNOX SO2: 90

NOX: 90 Hg: zero

Increased auxiliary power requirements

Ammonia storage issues

Concentrated sulfuric acid byproduct

SNRB SO2: 80–90

NOx: 90 Hg: zero

Reliability of fabric filter bags may deteriorate Technology has not been demonstrated

Activated coke SO2: 90–98

NOx: 60–80 Hg: 90–99

NOx reduction depends on SO2 reduction

Long time needed to reach operating temperature of deNOx process

Limited mercury removal data; Quality of activated coke is

critical for performance

ECO SO2: 98–99

NOX: 90 Hg: 95

3% auxiliary power requirement

Cooling water required for wet ESP

Technology in demonstration

—

NOXSO SO2: 98

NOx: 75–90 Hg: zero

NOx desorption with hot air required

High temperature reaction with methane required for

processing of SO2

Limited experience (proof of concept tests and a combined

heat and power plant at the University of Denmark)

Copper-oxide SO2: 90

NOx: 90 Hg: zero

Pneumatic transport of solids to regeneration unit required

High temperature regeneration of copper sulfate sorbent

required

Experience limited to pilot scale

a

Reported.

Srivastava et al.

Volume 55 September 2005 Journal of the Air & Waste Management Association 1385
these units achieved NOx emission rates between 0.04 and

0.07 lb/106 Btu.

Recent enhancements in secondary control technologies have been aimed at providing large NOx reductions,

using reagents more efficiently, and addressing any public

concerns with the transport and handling of the NH3

reagent used in SCR applications. These enhancements

include variants of reburning and SNCR, in-duct SCR,

HSR, and urea-to-NH3 processes.

DOE-NETL is conducting a comprehensive research

and development effort focused primarily on developing

new technologies capable of controlling NOx emissions to

a level 0.15 lb/106 Btu at a cost significantly lower than

SCR. NOx control technologies under development by

DOE-NETL include layered NOx control for cyclone boilers, oxygen-enhanced combustion, refinements for lowNOx tangential firing systems, and preheat combustion.

In addition to the above control technologies used

exclusively for NOx removal, a number of other technologies are becoming available that can be applied to control NOx in conjunction with other pollutants, including

SO2, Hg, and PM. In general, experience with these multipollutant control technologies is limited to test demonstrations, with only a few of them applied to date in

full-scale commercial installations.

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About the Authors

Ravi K. Srivastava, Project Manager, and Robert E. Hall,

Branch Chief, are at the U.S. Environmental Protection

Agency, National Risk Management Research Laboratory,

Air Pollution Prevention and Control Division, Research Triangle Park, NC. Sikander Khan, Environmental Engineer

and Kevin Culligan, Acting Branch Chief, are at the U.S.

Environmental Protection Agency, Office of Air and Radiation, Clean Air Markets Division, Washington, DC. Bruce W.

Lani, Project Manager, is at the U.S. Department of Energy,

National Energy Technology Laboratory, Environmental

Projects Division, Pittsburgh, PA. Address correspondence

to: R. K. Srivastava, U.S. Environmental Protection Agency,

National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle

Park, NC 27711; phone: 1-919-541-3444; fax: 1-919-

541-0554; e-mail: srivastava.ravi@epa.gov.

Srivastava et al.

1388 Journal of the Air & Waste Management Association Volume 55 September 2005