# 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 (NO x) from electric utility boilers. Tocomply with these regulatory requirements, it is increasingly important to implement state-of-the-art NO x con

trol technologies on coal-fired utility boilers. This paper reviews NO x control options for these boilers. It discussesthe 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 NO x controls. The popular pri

mary control technologies in use in the United States are low-NO x burners and overfire air. Data reflect that average NO x reductions for specific primary controls have rangedfrom 35% to 63% from 1995 emissions levels. The secondary NO x 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 NO x 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-NO x emissions reflect that in 2003, these units achieved NO x emission rates between 0.04 and 0.07 lb/10 6 Btu.

INTRODUCTION Emissions of nitrogen oxides (NO x) are associated with a variety of environmental concerns, including increasing ground-level ozone, formation of acid rain, acidificationof 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 theseemissions in the United States and elsewhere. To implement controls efficiently, it is important to determine which sources are significant emitters of NO x . Shown in Figure 1 is the contribution to NO x 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 NO x emissions and com

prised 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 NO x emissions inven

tories can be higher than that on a national basis. Recent IMPLICATIONSTo comply with recent regulatory requirements, it is increasingly important to implement state-of-the-art NO x control technologies on coal-fired utility boilers. This paper reviews NO x 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 NO x controls. The paper is expected to be a state-of-the-art reference on NO x control technologies for regulators, utility industry per

sonnel, 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 1367data reflect that electricity-generating sources are an important source of NO x in many of the states. 3 For example, in 2001, an estimated 754,446 t of NO x 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 NO x 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 NO x emissions from stationary combustion sources have recently been taken in the United States. These actions include the Acid Rain NO x regulations, 4,5 the Ozone Transport Commission NO x Budget Program, 6 revision of the New Source Performance Standards for NO x 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 NO x from stationary combustion sources establishes a need to review current information on pertinent control technologies. This paper reviews the technologies for controlling NO x from coal-fired power plants. The review not only includes the established commercial technologies that are being used in theUnited States but also examines those that can be considered to be relatively new or in an advanced stage of development. NO x Formation in Combustion Before examining the control technologies, it is helpful to review the mechanisms of NO x formation in combustion. These mechanisms form the basis for practical NO x control strat

egies, particularly those based on modification of the combustion process. NO x is formed during most combustion processes by one or more of the following three chemical mechanisms: 10 –12 (1) “thermal” NO x resulting from oxidation of molecular nitrogen in the combustion air, 13 (2) “fuel” NO x resulting from oxidation of chemically bound nitrogen in the fuel, and (3) “prompt” NO x resulting from reaction between molecular nitrogen and hydrocarbon radicals. Thermal NO x can typically represent up to 20% of the NO x emitted during pulverized coal combustion in utility boilers. 14 Its rate offormation 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 NO x areproduced through dissociation and oxidation of molecular nitrogen from the combustion air. 14 Formation of thermal NO x can be controlled by reducing oxygen con

centrations in the furnace, combustion zone temperatures, and residence time of flue gas in high-temperatureareas of the boiler. For coal-fired boilers, practical methods include the following: (1) increasing the size of thecombustion zone for a given thermal input and (2) reducing the rate of combustion and, consequently, peak flame temperatures with specially designed burners. The size ofthe 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 NO x contributes significantly to total NO x emissions, depending on the weight percent of nitrogen in the fuel. 16 In pulverized coal combustion in a utility boiler, fuel NO x may typically contribute up to 80% of the NO x emissions. 14 Formation of fuel NO x depends on the nitrogen content in the fuel and the amount of oxygen available to react with the nitrogenduring coal devolatilization in the early stages of combustion. Accordingly, fuel NO x formation can be re

duced by switching to, or cofiring with, fuel with lower nitrogen content and/or by limiting oxygen availability during the early stages of combustion. Methods forreducing oxygen availability include lowering the excess air level and/or controlling the rate at which the Figure 1. U.S. sources of NO x 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 thecombustion process but has sufficiently low temperature to minimize thermal NO x production. Prompt NO x contributes a relatively minor fraction of total NO x emissions for coal-fired boilers. 12

NO X CONTROL TECHNOLOGIES In general, NO x control technologies may be placed in twocategories: primary control technologies and secondary control technologies. Primary control technologies reduce the amount of NO x produced in the primary combustion zone. In contrast, secondary control technologies reduce the NO x 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 NO x control, othertechnologies have also been developed to provide simultaneous reduction of more than one pollutant. These multipollutant technologies reduce NO x along with other pollutants, including sulfur dioxide (SO 2), mercury (Hg), particulate matter (PM), and/or air toxics.

Primary Control TechnologiesIn the United States, popular primary control technologies are low-NO x burners (LNB) and OFA. These technol

ogies use staged combustion techniques to reduce NO x 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 NO x reduc

tion requirements.

LNB. A LNB limits NO x formation by controlling thestoichiometric 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 NO x forma

tion; (2) reduced flame temperature, which limits thermal NO x formation; and (3) reduced res

idence time at peak temperature, which limits thermal NO x formation. In general, LNBs at

tempt to delay the complete mixing of fuel and air as long as possible within the constraints of furnace design. This is why the flames fromLNBs are usually longer than those from conventional burners. Conceptually, working of an LNB with gradual mixing of combustion air to a fuel-richflame core is shown schematically in Figure 2. The hardware used to influence the fuel/air mixing varies from manufacturer to manufacturer. LNBs can provide NO x reductions of 50% or more from uncontrolled levels, withhigher 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 NO x formation in pulverized coal combus

tion. Of these properties, coal rank and volatile matter content have a more significant impact on NO x 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 NO x 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. NO x formation is inhibited because of enhanced fuel nitrogen release in a locally fuel-rich environmentavailable in a LNB, thereby leading to greater conversion of fuel nitrogen to N 2 , and reduced fuel nitrogen retention in the char, which limits the NO x 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 avoidflame impingement on the furnace walls facing the burners. In a retrofit situation, this may require LNB adjustments, affecting the NO x reduction capability of the sys

tem in some cases. In certain situations, LNB retrofits mayresult in changed heat transfer patterns within the furnace, increased corrosion of the furnace walls, and increased furnace fouling.

Figure 2. Schematic of a low-NO x burner. 

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Volume 55 **September 2005** Journal of the Air & Waste Management Association 1369Unburned carbon (UBC) levels typically increase when a boiler is converted with a low-NO x firing system. In gen

eral, the extent of this increase depends on coal properties, design of burners and air registers, size of the furnace, firingconfiguration 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 UBClevels 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 UBCcan 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 NO x 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 injectedthrough 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 NO x 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. Theseapplications use OFA in three different configurations: closecoupled to the burner, separated from the burner, or both. Reductions with OFA range from 20% to  60% dependingon the initial NOx levels of a boiler, fuel combustion equipment design, and fuel type. 23 However, while reducing (substoichiometric) conditions result in significant NO X reduc

tion, increased levels of UBC and CO can occur. The extent of these increases is dependent on the design of the OFAsystem and fuel properties. Waterwall wastage can also occur with the extent dependent on factors such as degree ofstaging, 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 NO x reductions in excess of 50%, with moderate (25–35% from baseline) increases in UBC levels and CO emissions of

 50 ppm (corrected to 3% O 2). 23 Primary control technologies, described above, have been widely implemented on U.S. coal-fired utility boilers to comply with the NO x emissions reduction require

ments of the Title IV NO x 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 NO x reduction. These advances are described below.

Table 1. NO x reduction performance of primary control technology applications on coal-fired boilers.

Boiler Type a Coal Type Primary Control Technology 1995 Average Baseline NO x Emission (lb/10 6 Btu) 2003 Average Controlled NO x Emission (lb/10 6 Btu) Average NO x Reduction Efficiency (%) Range of NO x 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-NO x 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. aAll 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 withmultilevel OFA is now available for tangentially fired boilers. This combustion technology has achieved NO x emis

sions  0.15 lb/10 6 Btu, equating to  60% reduction, while firing PRB subbituminous coal, 26 which reflects the potential for achieving low-NO x emissions with this tech

nology. Note, however, that for other coals with lowerfuel-volatile contents than PRB coals (e.g., eastern bituminous coals), relatively higher NO x emissions may be ex

pected 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, lesstemperature variation across the furnace, and less excess air needed for complete combustion. The technology has been installed on one U.S. and six Swedishboilers, firing a variety of fuels (coal, wood waste, municipal waste, and heavy residual oil). 28 On Swedish installations, NO x 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 notchange 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 NO x 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 NO x emission level. 35–37 To comply with Title IV NO x regulations, some cy

clone boilers currently use OFA, but some of these boilers may want to further lower NO x emissions to comply with additional emission reduction requirements (e.g., ozone transport rulemakings). Achieving lower NO x through ad

ditional 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 injectioninto cyclone boilers offers a possibility of not only decreasing NO x but of also increasing barrel temperatures to prevent frozen slag. 38Computational 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 NO x reduction performance, determine the location(s) of OFA, optimize its application with regard to reducing NO x, avoiding boiler wall corrosion, and provide in

sights 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-NO x emissions to comply with existing or future NO x regulations by using primary control technolo

gies 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 NO x to formhydrogen cyanide (HCN), isocyanic acid (HNCO), isocyanate (NCO), and other nitrogen-containing species. These species are ultimately reduced to N 2 . Finally, completion air is added above the reburn zone to complete burnout of reburning fuel. 40 –43 The reburning process is shown sche

matically in Figure 3. 

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Volume 55 **September 2005** Journal of the Air & Waste Management Association 1371Furnace 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 NO x reduction kinetics in the reburning zone, and forcomplete combustion in the burnout zone. Given sufficient time in the reburn zone, reburn zone stoichiometry is another critical parameter that influences NO x reduc

tion. This stoichiometry is directly related to the heat input split between the primary and reburn zones. Ingeneral, 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 NO x 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 NO x 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 NO x because of reformation of thermal NO X . In general, these consider

ations 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 upperfurnace to achieve adequate carbon burnout. Because carbon burnout can be a constraint limiting the amount ofreburn 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 NO x reduction and car

bon 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 recirculatedflue 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 MW e Ladyzhin plant in Ukraine. This application demonstrated that 50% NO x reduction was achievable with NGR technology onwet-bottom, wall-fired boilers. In general, reburn technology has demonstrated  50% NO x 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 NO x control technology. 46 The NO x reduc

tions 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 oncurrently operational reburning applications on coal-fired U.S. electricutility boilers shown in Table 2 reflect that in 2003, these units achieved NO x emission rates between 0.277 and 0.385 lb/10 6 Btu.

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

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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 NO x to reduce it to N 2 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 NH 3 SNCR are:

 NH 2 2 CO  2NO  1/2O 2 3 2 H 2 O  CO 2  2N 2 (1)

2NH 3  2NO  1/2O 2 3 2N 2  3H 2 O (2)

In general, NH 3 may reduce NO X, oxidize to form NO x, or remain unreacted and pass through the stack. This unreacted portion is referred to as “NH 3 slip.” Inad

equate flue gas temperature and/or reaction time for SNCR kinetics and mixing of the reagent with flue gas can contribute to an increase in NH 3 slip. Relatively high concentrations of NH 3 slip can react with SO 2 and sulfur trioxide (SO 3 ) in the flue gas and form ammonium sul

fates and bisulfates, which, in turn, can cause plugging of the air preheater (APH) passages. Furthermore, NH 3 slip can also reduce the marketability of fly ash by making it odorous. For these reasons, NH 3 slip is normally wellcontrolled through proper specification, design, and operation of an SNCR system.Although the dominant reactions in the SNCR process result in the reduction of NO x to N 2, a significant competing reaction is the oxidation of the SNCR reagent to form NO x . This oxidation reaction becomes more sig

nificant at relatively higher temperatures. Because of this competing oxidation reaction, there is not a one-to-one relationship between reagent injected and NO x reduced. It typically requires more urea or NH 3 to reduce NO x 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 NO x Rate (lb/10 6 Btu) NO x 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-NO x 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 1373boilers. 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 NO x concentrations cause the reduc

tion 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, theSNCR 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 NO x reduction with low levels of NH 3 slip. Urea reagent is injected as an aqueous solution. NH 3 can be injected as a gas (anhydrous NH 3 ) or as an aqueoussolution. In general, mixing of flue gas with injected aqueous solution of NH 3 or urea is better than that with injected anhydrous NH 3 . This is because aqueous droplets penetrate farther into flue gas than gaseous anhydrous NH 3 . Furthermore, because a urea solution is less volatile than a NH 3 solution, its droplets generally penetrate far

ther into the flue gas. Because of somewhat poorer mixing in SNCR systems with NH 3 injection compared with those using urea, the former require more elaborate injection schemes in the boiler. 50 Boiler load changes can impactthe 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 usuallyincluded 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-followingboiler 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 NH 3 , throughout the furnace volume maydiminish, which, therefore, may negatively impact NO x 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 NO x 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% NO x reduction, larger boilers (e.g., 500 MW Cardinal Unit 1) may be capable of achieving reductions of only

30%.

SCR. SCR is a postcombustion NO x reduction technology in which NH 3 is added to the flue gas, which then passes through layers of a catalyst. 41,54 The NH 3 and NO x react on the surface of the catalyst, forming N 2 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 NO x reduction, ranging from 80% to  90%. The overall stoichiometric SCR reactions are:

2NH 3  2NO  1/2O 2 3 2N 2  3H 2 O (3)

4NH 3  2NO 2  O 2 3 3N 2  6H 2 O (4)

Note that the NO X reduction reactions above are thesame 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. 

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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 economizerbypass 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 afterthe 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 costconsiderations, the majority of SCR installations on utility units are of the high-dust type. 55 An NH 3 injection grid is located upstream of the SCR catalyst. As the flue gas with NH 3 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 [V 2 O 5 –TiO 2]) where the NH 3 and NO x reduction reactions take place. At the temperature where this reduction occurs, the competing NH 3 oxidationreaction is not significant. This results in two advantages over SNCR: much lower outlet NO x concentra

tions are possible and NH 3 slip can be reduced. Because most of the NO x isin the form of NO in coal-fired boilers, the ratio of NH 3 added to NO x reduced is typically close to 1:1 (see eq 4). The local molar ratio of NH 3 to NO x in the flue gas has a great impacton SCR performance. This process parameter becomes more critical forSCR systems designed for high-reduction efficiencies. If appropriate distribution of this parameter is not possible, then additional catalyst is needed to ensure adequate performance. Gasvelocity and spatial temperature distribution at the catalyst face aresomewhat less critical but are still important. Achieving both proper NH 3 : NO x ratio throughout the flow field and proper gas flow and temperaturedistribution are addressed in the design stage through flow modeling and through optimization of the NH 3 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 catalystmaterial 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 layerwhile 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 systemsare equipped with soot blowers that are periodically cycled to clean the SCR catalyst and the APH. 61Comprehensive 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 NO x reduction desired, and the level of NH 3 Table 3. SNCR performance for electric utility coal-fired units.

Plant Name a Unit a Unit Size (MW) a 2003 NO x Rate (lb/10 6 Btu) b NO x 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 Rocheste r 7 - Russell Station 1 47 0.389 15 - 27.5 Rocheste r 7 - Russell Station 2 65 0.382 15 - 27.5 Rocheste r 7 - Russell Station 3 65 0.294 15 - 27.5 Rocheste r 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

aThe 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; bAll 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?objectId  090007d480271c93. 

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Volume 55 **September 2005** Journal of the Air & Waste Management Association 1375slip desired. For example, a plant may want to extend thetime 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 NO x in an emissions-trading framework. However, in

creased NO x reduction would come at a price of increased NH 3 consumption, increased frequency of catalyst re

placement, increased catalyst loading, or increased pressure loss. Similarly, a plant may consider tolerating a higher NH 3 slip from its SCR system than originally en

visioned. This can provide benefits of reduced catalyst loading, extended time periods between catalyst replacement events, or increased NO x 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% ofthe 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 wellknown. Most operators of these facilities add limestone to their coal as aslag-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). 41,63,64In the United States, low-sulfur, high-calcium subbituminous PRB coals are used at many power plants to comply with SO 2 regulations. Because these coals are unique to the United States, there was no experience with SCR on facilities firing these coals until recently. There issome 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 rateof 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% NO x removal with a maximum of 3 ppm NH 3 slip. 66Another issue is catalyst arsenic poisoning on drybottom boilers firing coals from Western Pennsylvania and West Virginia. These coals do not have unusuallyhigh 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 permanentlypoisoned. To address this issue, some facilities have accelerated their catalyst management plans, and others areadding 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 (NH 4 HSO 4) forma

tion downstream of the catalyst leading to fouling of APHbaskets over time. Several units appear to have experienced this impact. 60,68 APH fouling by NH 4 HSO 4 is driven by the following: (1) the presence of sufficient SO 3 and NH 3 and favorable conditions (e.g., temperature) for the NH 4 HSO 4 formation to occur; and (2) APH operationaland design characteristics that are favorable for deposition of the formed NH 4 HSO 4 . The SCR catalyst will en

hance the concentration of SO 3 in the flue gas by oxidiz

ing a portion of the SO 2 in the flue gas into SO 3 . Consequently, SO 3 will react with any NH 3 slip from the SCR reactor to form the ammonium sulfate (NH 4) 2SO 4 and/or bisulfate as follows:

2NH 3  SO 3  H 2 O 3 (NH 4) 2SO 4 (5)

NH 3  SO 3  H 2 O 3 NH 4 HSO 4 (6)

Normally, dry (NH 4) 2SO 4 does not create a fouling problem. However, NH 4 HSO 4 combined with fly ash con

stituents forms a moist and sticky material that will tendto 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 NH 3 slip levels between 2 and 5 ppm. 70 Other methods to reduce this potential include: 60 sootblower additions, modification of airheater 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 NO x from hundreds of utility and industrial boilers in Japan andGermany 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 NO x reductions of 80%, sometimes as much as 90% reduction, with  2 ppm NH 3 slip. 73 It is informative to examine the extent of NO x reduc

tion being achieved by SCR installations. The performance of 20 SCR systems operating in the United States with low-NO x emissions is shown in Table 4 . The data in this table reflect that in 2003 these units achieved NO x emission rates between 0.04 and 0.07 lb/10 6 Btu, likely with NO x reduction efficiencies  85%.

Enhancements in Secondary Control Technologies Recent enhancements in secondary control technologies have been aimed at providing large NO x reductions, usingreagents more efficiently, and addressing any public concerns with the transport and handling of the NH 3 reagent

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

Plant Name a Unit a Unit Size (MW) a NO x Rate (lb/10 6 Btu) Third Quarter 2003 b NO x 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

aThe units shown are those that achieved NOx emission rates  0.07 lb/10 6 Btu, asreflected in the EPA emissions database at http://www.epa.gov/airmarkets/emissions/raw/index.html; bThe 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 reli

able SCR inlet NOx data, the SCR efficiencies are estimated using an inlet NOx level of 0.5 lb/10 6 Btu, assuming this level can be achieved with primary controls. 

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

Advanced Gas Reburning. With advanced gas reburning (AGR), a nitrogen compound (typically urea or NH 3 ) is added downstream of the reburning zone. The reburning system is adjusted for somewhat lower NO x reduction to produce free radicals that enhance SNCR NO x reduc

tion. 41 AGR systems can be designed in the following twoways: (1) nonsynergistic, which is essentially the sequential application of NGR and SNCR (i.e., the nitrogen agent [urea or NH 3] 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 NO x reduction and minimum NH 3 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 MW e Greenidge Unit 6 in New York to reduce NO x emissions by 68 –76%. However, it could not reduce NH 3 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 NO x . 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 NO x control using  10% gas heat input and no burnout air. FLGR has been demonstrated to reduce NO x 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 NO x 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, theSNCR reagent participates with natural gas (or other hydrocarbon fuel) in a NO x reduction reaction, which is believed to be different than the reaction that occurs when NH 3 or urea is used in SNCR. In SNCR, the NO x reduction occurs in an oxidizing environment, whereas in AEFLGR, the NH 3 or urea is injected into a locally reduc

ing zone. High reductions are possible because, with the local low-oxygen environment, the AEFLGR NO x reduc

tion reaction does not have to compete as much with the Zeldovich thermal NO x reaction that limits SNCR perfor

mance. AEFLGR has been tested at Carolina Power and Light 198 MW Ashville Unit 1 to achieve NO x emissions of

 0.28 lb/10 6 Btu at all loads. Average NH 3 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% NO x reductions using 7–10% natural gas heat input, with NH 3 slip maintained at  5 ppm. 78

Hybrid-Selective Reduction. In hybrid-selective reduction (HSR), a SNCR system is used to achieve some NO x reduc

tion and to produce a controlled amount of NH 3 slip that is used in a downstream in-duct SCR reactor for additional NO x reduction. 41,79 The HSR technology has lower capitalcosts than SCR, allows installation to be phased in, provides better reagent utilization than SNCR, and can provide very good NH 3 slip control. A test conducted using this hybrid system on a full-scale boiler showed 95% NO x reduction with  5 ppm NH 3 slip and 55% reagent utili

zation.

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 didnot 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 MW e boiler and follows a commercially operating SNCRsystem that treats all of the boiler gases. This unit demonstrated between 85% and 90% NO x reduction with  10 ppm NH 3 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% NO x re

moval with a 10 ppm NH 3 slip. 81To 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 andreplaced with baskets coated with a catalyst. These catalystcoated baskets may be used separately or in addition toin-duct SCR. Testing at Mercer Generating Station and experience in Europe demonstrate that this approach is capable of providing some additional NO x reduction and, more importantly, can be very effective in controlling NH 3 slip.For example, the catalytic air-heater baskets installed at Mercer Station provided sufficient NH 3 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 NH 3 slip limit. 80 However, catalytic air heater technology generally will not provide sufficient reduction of NO x to be a stand-alone technology. 82

Urea-to-NH 3 Processes. Typically, anhydrous (pure lique

fied) or aqueous (19 –29% solution in water) NH 3 has been used as the reagent in SCR applications. However, public concerns with transport and handling of NH 3 and associ

ated Occupational Safety and Health Administration requirements have led to the development of processes in which a NH 3 reagent is produced from urea at the SCR application site. 83 On the basis of equivalent NH 3 delivered, anhydrous NH 3 is less expensive than urea. However, urea is generally lower in cost than aqueous NH 3 , especially more dilute solutions of aqueous NH 3 . There are several alterna

tive urea-to-NH 3 processes being offered commercially. Typ

ically, these processes use on-site hydrolysis to produce NH 3 reagent from urea.

Emerging NO x Control Technologies In response to the environmental concerns of NO x emis

sions 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 ExistingPlants Program. This effort focuses primarily on enhancing the efficiency and environmental performance of theexisting fleet of fossil fuel-fired power systems by developing new technologies capable of controlling NO x emis

sions to a level  0.15 lb/10 6 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. NO x control technologies under development by DOE-NETL include layered NO x control for cyclone boil

ers, oxygen-enhanced combustion, refinements for lowNO x 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 NO x emissions, typically  1.2 lb/10 6 Btu. These units, which account for only 8% of the U.S. generating capacity, emit nearly 20% of the coal-fired NO x emissions. Research has shown that the injection of NH 3 or urea into the high-temperature region of the boiler can lead to significant noncatalytic NO x reduc

tions. This concept, when applied to staged cyclone-firedfurnaces, uses the nitrogen-containing additive to increase the NO x reduction rate in the lower furnace. Field testing has confirmed that this technology can reduce NO x emissions by 25–30% beyond OFA levels with  1 ppm NH 3 slip. 84 The inclusion of SNCR can be used for an additional 35% NO x reduction with  5 ppm NH 3 slip. 84Commercial scale tests at the Conectiv 138 MW B.L. England Unit 1 and the AmerenUE 500 MW Sioux Unit 1 have demonstrated that NO x emissions of 0.25 lb/10 6 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 NO x . Experimental work using a burner fired at 24 million Btu/hr with high-volatile and medium-volatile bituminous coals demonstrated that NO x concentrations as low as 0.11 lb/10 6 Btu are achiev

able. Data from the experiments show that even when the baseline (without oxygen) NO x emissions are very low, oxygen addition can reduce the NO x even further andthat the reductions are relatively independent of the initial NO x concentration. In addition to the reduction in NO x, 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 NO x 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 re

cently completed comprehensive study identified lowcost, efficient NO x control refinements for pulverized coal tangential-fired boilers. 87 The testing evaluated a number of low-NO x 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 auxiliaryair 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 NO x 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 

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Volume 55 **September 2005** Journal of the Air & Waste Management Association 1379subbituminous coal showed the lowest NO x (0.08 lb/10 6 Btu) followed by the moderately reactive, high-volatile bituminous (0.12 lb/10 6 Btu) and least-reactive, mediumvolatile bituminous (0.17 lb/10 6 Btu) coals. Many of the firing system components described in the study abovecan be retrofitted to an existing system, resulting in improved NO x emissions without significantly impacting the carbon in fly ash levels. Nineteen commercial boilersfiring subbituminous coal that use aspects of the technologies demonstrated in this study are achieving NO x emis

sions  0.15 lb/10 6 Btu.

Preheat Combustion System. The preheat combustion system, also known as Methane de-NO x, uses gas-fired coal preheating to destroy NO x precursors and prevent NO x 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 N 2 rather than NO x . Testing with a 3-million Btu/hr burner has achieved NO x levels

 0.15 lb/10 6 Btu without postcombustion flue-gas cleanup technology.

MULTIPOLLUTANT CONTROL TECHNOLOGIES The technologies addressed up to this point are those applied exclusively for NO x control. A number of multi

pollutant technologies that control NO x along with otherpollutants from coal-fired sources and are in more advanced stages of development commercialization are described below.

Electron Beam ProcessThe Electron Beam (E-Beam) Process provides simultaneous removal of NO x and SO 2 . 89 –91 The process equipment is located downstream of the plant PM controldevice (ESP or baghouse). The first component is an evaporative spray cooler, where flue gas is cooled down to 140 –150 °F. Gaseous NH 3 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 wateris added to counteract the temperature rise. The irradiation generates hydroxyl radicals and oxygen atoms, which oxidize NO x and SO 2 . These oxidized species mix with water present in the flue gas to form sulfuric and nitric acids, which are neutralized by NH 3 .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 collectiondevice. A combination of ESP and baghouse has been proposed as being more effective. In addition, the use of aninert 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 NO x reductions as high as 90% and SO 2 reductions of 95%. NO x removal primarily depends on the E-beam dosage. A dose of

0.3– 0.6 mrad is required to achieve 50% NO x reduction, whereas 90% NO x removal requires 2.7 mrad. Also, higher NO x removals are obtained at higher flue-gas tem

peratures. In contrast, SO 2 removal requires smaller Ebeam dosages and is promoted by lower gas temperatures. NO x removal is also aided by higher flue-gas SO 2 concen

trations, 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 NO x reduc

tion being sought. For low-NO x reductions (

10%), theauxiliary power is generally limited to 2% of the plant output; however, for NO x 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 Nm 3 /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 NO x and 85% and 92% for SO 2 . After a suc

cessful 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 NO x 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 NH 3 has been used in the ROTAMIX for NO x control and limestone and trona for SO 2 control. Future plans include injection of sorbents for the removal of heavy metals, including Hg. ROFA and ROTAMIX systems together can provide greater NO x reduction levels and simultaneous removal of SO 2 . 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 

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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 adequateresidence 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 plantperformance 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 MW e Cape Fear Unit 5 and 175 MW e Cape Fear Unit 6 have achieved

 70% NO x 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 SO 2 and Hg reductions at low capital and operating costs. Stable SO 2 reductions of 69% were achieved with trona and 64% with limestone. Hg reductions of 89% were achieved withlimestone 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 NO x and SO 2 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, SO 2 reactor vessel, and a glass-tube con

denser, installed in that order. The baghouse removes PMto minimize cleaning frequency of the downstream catalysts. The heat exchanger transfers heat from the hotter gases exiting the SO 2 reactor to the gas stream entering the SCR vessel, thereby reducing the external energy use. NH 3 is injected upstream of the SCR vessel to remove NO x, which is converted to nitrogen and water by the reactions taking place in the vessel. The SO 2 reactor consists of a burner and a catalyst to oxidize SO 2 to SO 3 . Flue gases exiting the SO 2 reactor passthrough the above heat exchanger and then to the glasstube condenser (wet gas sulfuric acid [H 2SO 4] condenser) that allows SO 3 to hydrolyze to concentrated H 2SO 4 . Am

bient air is used as the cooling medium in the condenser. The heated air is recirculated to the burner in the SO 2 reactor and to a heater installed to reheat flue gases discharging to the stack from the condenser. The SO 2 reactor also oxidizes any NH 3 slip from the SCR operation, elim

inating 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 NO x reduction efficiencies. The NO x and SO 2 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 plantperformance include increased auxiliary power consumption and introduction of NH 3 as a consumable. The tech

nology produces a salable H 2SO 4 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-MW e equivalent slipstream of flue gas from the Ohio Edison Niles Unit 2, firing a 3.4% sulfur coal. At this plant, an average NO x reduction of 94% and SO 2 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% NO x and 94% SO 2 removal at this petroleum coke-fired facility.

SO x-NO x-Rox-Box The SO x-NO x-Rox-Box (SNRB) technology provides simul

taneous removal of NO x, SO 2, and PM in one unit–a high-temperature baghouse. 91,98 NO x removal is achieved by injecting NH 3 into the flue gas stream ahead of a SCRcatalyst, which is placed on the baghouse high-temperature ceramic filters. SO 2 removal is achieved by injectingeither 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% NO x reduction and 80 –90% SO 2 reduction. Increased aux

iliary power consumption and introduction of NO x and SO 2 control reagents are the major related impacts on plant performance. Experience with the SNRB technology is restricted to a 5-MW e slipstream demonstration at the Ohio EdisonBurger Unit 5, a 156-MW unit burning high-sulfur bituminous coal. Additional demonstrations and commercial experience are required to confirm full-scale NO x/SO 2 re

duction effectiveness and operating life of the ceramic bag filters. A 3800-hr test was conducted in 1992 on three 

### Srivastava et al.

Volume 55 **September 2005** Journal of the Air & Waste Management Association 1381filters 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 NO x, SO 2,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, SO 2 is removed by adsorption into the activated coke, where it forms H 2SO 4 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 adsorbersecond stage, activated coke acts as a catalyst in the decomposition of NO x to nitrogen and water after the injection of NH 3 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, SO 2, 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 fiveyears and, once spent, it must be disposed of in a hazardous waste facility. Other methods of Hg removal have been considered (e.g., H 2SO 4 plant off-gas, SO 2 -rich gas off-gas, etc.), but none have been tested. Two of the possible byproducts for the activated coke process are elemental sulfur and H 2SO 4 . Additional equip

ment (e.g., a reduction column, Claus unit) must be, incorporated to obtain these byproducts. The demonstrated NO x and SO 2 control efficiencies for this process have ranged from 60 to 80% and 90 to 98%, respectively. Higher NO x reduction efficiencies can be obtained with lower flue-gas SO 2 concentrations. Also,based on pilot test results, 90 –99% Hg removal is projected for this process. The impacts of the activated coke process on theplant performance include increased auxiliary power consumption and use of activated coke and NH 3 . Activatedcoke 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 NO x and/or SO 2 re

moval. At present, no commercial installations with Hg control exist. Also, there are no demonstrations of this process in the United States thus far.

Electrocatalytic OxidationThe electrocatalytic oxidation (ECO) process provides simultaneous removal of NOx, SO 2, 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 NO 2, nitric acid, and mercuric oxide, whereas a relatively small amount of SO 2 oxidizes to H2SO4 . The BDR uses a dielectric discharge, which is formed by placing a dielectric insulating material between twodischarge 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 alsohouses the WESP. The AT is a two-stage process with an absorption stage for absorbing the pollutants (mainly unoxidized SO 2 and NO 2) and a concentrating stage at the bottom. An aqueous NH3 solution and certain vendor-proprietary chemi

cal are used as scrubbing agents in the AT. These react with thepollutants 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 treatedin 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 avariety 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 NO x, 98 –99% for SO 2, 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 SO 2 :NO X 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 NO x reduc

tion. Other impacts of the ECO process include both the use of NH 3 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 SO 2 and NO x 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; SO 2 and NO x are adsorbed by the sorbent, which consists of sphericalbeads of high-surface-area alumina impregnated with sodium carbonate. Cleaned flue gas then passes through a baghouse to the stack. The NO x is desorbed from the NOXSO sorbent when heated by a stream of hot air to 1200 °F. The desorbed NO x is recycled to the boiler where equilibrium processes cause destruction of the NO x . The adsorbed sulfur is re

covered from the sorbent in a regenerator where it reacts with methane at a high temperature to produce an off-gas with high concentrations of SO 2 and hydrogen sulfide. This off-gas is processed to produce elemental sulfur, which can be additionally processed to produce liquid SO 2, a higher-valued by-product. The process is expected to achieve SO 2 reductions of 98% and NO x 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 atthe 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 SO 2 and reducing NO x from flue gas of a conventional coalfired boiler. 106 CuO takes advantage of the chemical absorption of SO 2 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 NO x in the presence of NH 3 . 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 SO 2 can be reduced to elemental sulfur, a marketable by-product.

Figure 6. Locations of NO x 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 1383The 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, SO 2 is absorbed by the sorbent, and NO x is reduced by injecting NH 3 into the incoming flue gasstream. 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 targetreaction temperature for regeneration. This is accomplished by contacting the sorbent with the hot combustion gas of the combustor fired on natural gas. Theheated spent copper sulfate sorbent enters the regenerator, where it is reduced with natural gas to regeneratethe copper. The regeneration step results in a concentrated stream of SO 2 that can be processed in a sulfur recovery plant. From the regenerator, the sorbent is Table 5. A summary of NO x control technologies.

Technology NO x 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 CaCO 3 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. 

### Srivastava et al.

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 SO 2 removal and NO x reduction have been at 90%.

CONCLUSIONS Recently, a number of regulatory actions have been taken in the United States that are focused on reducing NO xemissions from stationary combustion sources, particularly electric utility boilers. As a result of these regulations, state-of-the-art NO x control technologies have been ap

plied 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 NO x control tech

nologies discussed in this paper, relative to power planthardware and other emission control equipment. Additionally, Tables 5 and 6 summarize emission reductionperformance, 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 NO x emissions reduction requirements of the Title IV NO x Program. Data reflect that average NO x re

ductions 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 NO x reduction and include LNB with multilevel OFA, ROFA, and combustion improvement techniques. The secondary NO x 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 NO x control technology. The NO x 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 NO x emission rates between 0.277 and 0.385 lb/10 6 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 NO x reductions of 80%, sometimes as much as 90% reduction, with  2 ppm NH 3 slip. Data on the performance of 20 SCR systems operating in the United States with low-NO x emissions reflect that in 2003 Table 6. A summary of multipollutant control technologies.

Technologya NO x Removal Efficiency (%) a Potential Plant Impacts Comments

E-Beam SO 2 :  95 NO x :  90 Hg: zero Extensive byproduct treatment required Auxiliary power requirements may reach 5% for NO x

reduction  60 % Nitrogen fertilizer concept has not been demonstrated

ROFA/ROTAMIX SO 2 : 64–69 NO x :  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 SO 2 :  90 NO X :  90 Hg: zero Increased auxiliary power requirements Ammonia storage issues Concentrated sulfuric acid byproduct

SNRB SO 2 : 80–90 NO x :  90 Hg: zero Reliability of fabric filter bags may deteriorate Technology has not been demonstrated

Activated coke SO 2 : 90–98 NO x : 60–80 Hg: 90–99 NO x reduction depends on SO 2 reductionLong time needed to reach operating temperature of deNO x process Limited mercury removal data; Quality of activated coke is critical for performance

ECO SO 2 : 98–99 NO X :  90 Hg: 95 3% auxiliary power requirement Cooling water required for wet ESP Technology in demonstration

— NOXSO SO 2 :  98 NO x : 75–90 Hg: zero NO x desorption with hot air required High temperature reaction with methane required for

processing of SO 2 Limited experience (proof of concept tests and a combined heat and power plant at the University of Denmark)

Copper-oxide SO 2 :  90 NO x :  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 1385these units achieved NO x emission rates between 0.04 and 0.07 lb/10 6 Btu.Recent enhancements in secondary control technologies have been aimed at providing large NO x reductions, using reagents more efficiently, and addressing any public concerns with the transport and handling of the NH 3 reagent used in SCR applications. These enhancements include variants of reburning and SNCR, in-duct SCR, HSR, and urea-to-NH 3 processes. DOE-NETL is conducting a comprehensive research and development effort focused primarily on developing new technologies capable of controlling NO x emissions to a level  0.15 lb/10 6 Btu at a cost significantly lower than SCR. NO x control technologies under development by DOE-NETL include layered NO x control for cyclone boil

ers, oxygen-enhanced combustion, refinements for lowNO x tangential firing systems, and preheat combustion. In addition to the above control technologies used exclusively for NO x removal, a number of other technol

ogies are becoming available that can be applied to control NO x in conjunction with other pollutants, including SO 2, Hg, and PM. In general, experience with these mul

tipollutant 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. 

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