Transactions on Ecology and the Environment vol 1, 1993 WIT Press, ISSN

Transcription

1 Selective catalytic reduction for NO% emission control J.R. Cochran, A.W. Ferguson Black & Veatch, Power Division, Lamar, Overland Park, Kansas 64114* USA Abstract To meet the 1990 Clean Air Act Amendments (CAAA), US utilities will be required to reduce nitrogen oxides (NO%) emissions. Title IV of the CAAA have established allowable emission rates for Phase I dry bottom boilers based on the equivalent NO% emitted if low NO% burners were retrofitted on boilers. This method for calculating allowable NO* emissions does not preclude the use of postcombustion NO% control technologies. In addition, Title I of the CAAA could further reduce allowable NO% emissions (necessitating the use of postcombustion NO% controls) at facilities located in designated ozone transport regions. This emphasis is important because recent EPA investigations link high ambient ozone levels with localized NO% production, as well as with hydrocarbon and. volatile organic compound (VOC) emissions. This paper provides an overview of the various combustion and postcombustion NO% control technologies that can be used on coal fired boilers. Postcombustion NO% control systems have been used overseas for a number of years. This paper reviews the US utility industry experience with NO% emission control. In addition, this paper summarizes the balance-of-plant considerations associated with the postcombustion selective catalytic reduction NO% control technology. Introduction Control of NO% emissions is required by the US EPA in both Title I and Title IV of the CAAA. Title I deals with ozone nonattainment areas and ozone transport regions. It requires that reasonably available control technology (RACT) be applied to limit NO% emissions. All sources in the defined geographic areas are affected, not only utility units. Compliance with the requirements of Title I, however, does not assure that the unit will be in compliance with the requirements of Title IV, which places an emissions limit on affected units. The goal of Title IV is to limit emissions from affected coal fueled utility units without regard to their geographic location. The limit placed on Phase 1 dry bottom units is the emissions the unit would have if retrofitted with low NO% burners. The owner of the unit may choose to retrofit low NO burners or use another technology to achieve the

2 704 Air Pollution same emission rate. Either approach will satisfy the requirements of Title IV. In addition, Title IV has provisions to establish NO% emission limits for Phase 2 and Phase 1 wet bottom boilers that may necessitate the use of postcombustion NO% controls. NO% Control Technology Alternatives Nitrogen oxide emission controls are divided into two categories: infurnace NO% formation control (combustion control) and postcombustion NO% emissions reduction. In-fumace combustion control processes reduce the quantity of NO% formed during the combustion process. This is accomplished by using low NO% burners or staged combustion. Postcombustion NO% controls reduce a portion of the NO^ exiting the boiler to nitrogen and water. Two commercially available postcombustion nitrogen oxide emission reduction alternatives include selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) systems. The following summarizes these NO% emission control alternatives. Low NO% Burners The basic concept of low NO% burners is to separate combustion into a two-stage process. During the first stage, conversion of fuel-bound nitrogen to NO% is controlled by forcing the fuel nitrogen compounds into the gas phase using a fuel rich condition. Under this condition, there is a deficiency of oxygen and the intermediate nitrogen compounds decay at a maximum rate into molecular nitrogen. The remaining combustion air is admitted in the second stage. This slow burning rate reduces flame temperature, thereby limiting the amount of thermal NO% formed during latter stages of combustion. Several US manufacturers have designed low NO% burners for either wall fired or tangentially fired steam generators. The designs vary between the corner fired and wall fired configurations, and design variations exist among the available wall mounted low NO% burners. However, all low NO% burners share the requirements for much tighter control of the combustion process than was typically achieved with the previous generation of burner and combustion air system designs. This includes individual burner control of the primary air/fuel ratio, control of the total burner air-to-fuel ratio, and the method of introduction and mixing of secondary air in the burner zone. Early experience with low NO% burner installations indicates that particular attention must be given to the following balance-of-plant systems in retrofit installations:

3 # Windbox to furnace pressure drop. Burner control system. Air Pollution 705 Ash characteristics, distribution, and paniculate collection. Windbox-to-Furnace Pressure Drop. The additional secondary air control dampers typically associated with low NO% burners may increase the windbox-to-furnace pressure drop compared to the pressure drop in the original burner installation. Reduction of the margins for flow and pressure in the forced draft fan may be needed or modifications may be required. Burner Control System. Low NO% burners typically require additional air flow measurements at the burner and overfire air ports (if applicable). Additional modulating secondary air dampers also must be integrated with the burner control system. The burner control system must be designed for the extra inputs and outputs required in this system. Also the flame scanners will require adjustment or replacement because the characteristics of the low NO% burner flame are different from those of a "conventional" flame. Ash Characteristics, Distribution, and Particulate Collection. The use of low NO% burners may result in finer ash particles, a decreased proportion of bottom ash, an increased proportion of fly ash, and higher unburned carbon levels. This may not present a problem for a fabric filter particulate collection system, but it could overload a previously satisfactory precipitator system. Information regarding projected ash characteristics should be solicited as part of the low NO% burner proposal. NO% reductions of approximately 50 percent can be expected using low NO% burners in retrofit applications. Further reductions can be achieved if overfire air is used as described in the following section. Burner manufacturer claims of reductions to as low as 120 ppm (0.2 Ib/MBtu) have been stated for new installations. However, considering the geometry of many existing boilers (heat release rates) reduction of NO% emissions to new boiler levels is not expected. In most situations, existing boiler NO% emissions can be limited to levels of between 0.40 and 0.60 Ib/MBtu.

4 706 Air Pollution Air Staging The use of overfire air to reduce NO% is based on air staging for combustion. This technique can be used in conjunction with low NO% burners or independently. Individual vendors may or may not use overfire air in a particular retrofit situation. Overfire air ports, located above the coal burners, provide 15 to 30 percent of the total combustion air requirements. They reduce the combustion air flow through the burners, creating a fuel-rich primary flame zone around the burners. Formation of NO% from fuel-bound nitrogen is reduced because insufficient oxygen exists in the primary flame zone, and carbon species compete for what little available oxygen does exist. Additionally, overfire air reduces and delays the heat release in the primary flame zone. By releasing heat over a larger volume, a lower flame temperature and lower levels of thermal NO* formation result. The use of overfire air is normally a straightforward approach and can reduce NO* emissions up to 30 percent. Overfire air ports can be used on wall fifed, tangentially fired, or turbo furnace type steam generator design. The major problem with fitting overfire air ports is the requirement for sufficient furnace height to allow staged combustion to take place. Also, depending on the ash fusion temperature sensitivity to reducing and oxidizing combustion conditions, overfire air can increase slagging around the burners. Fuel Staging Fuel staging promotes in-furnace NO% destruction and is the basis for the reburning technique of NO% emission reduction. In reburning, additional fuel is injected with re circulated flue gas above the main burners and overfire air ports. The flue gas recirculation provides momentum to the additional fuel, which promotes instantaneous, complete, and uniform mixing with the main burner flame. Flue gas recirculation also prevents ignition of the additional fuel prior to entering the furnace and mixing with the main burner flame. The main burner combustion zone is supplied with the minimum air required to maintain oxygen concentrations at a level that allows fuel combustion.

5 Air Pollution 707 The NO% that is produced by the initial fuel firing is reduced to ^ and Oi by further reaction (oxygen scavenging) with hydrocarbon compounds introduced with the reburning fuel. This technique is feasible as long as careful attention is focused on residence time of the reburn fuel to ensure complete combustion. For retrofit applications, the requirement for ample upper furnace residence time will limit the applicability of reburning technology for pulverized coal units. For cyclone fired units the technology is more advanced, and extensive development continues. Selective Catalytic Reduction Selective catalytic reduction is a postcombustion process that reduces NO% to form nitrogen and water by chemically reducing NO% with vaporized ammonia (NHj) in the presence of a catalyst. SCR is the most effective postcombustion NO% control technology. SCR is capable of achieving NO% reductions of 80 to 90 percent with good reagent stoichiometry (approximately 1.0) and low ammonia slip (less than 5 ppm). Figure 1 illustrates the predominant SCR reactions. The SCR system consists of the following components: reagent storage and vaporization, reagent injection, catalyst (housed in a reactor module), soot blowers, and instrumentation. Figure 1 illustrates desired reactions as well as several undesired reactions. The potentially most deleterious reaction listed is the oxidation of SC^ to SOg. Sulfur trioxide can combine with unreacted ammonia to form ammonium bisulfate. Ammonium bisulfate will precipitate at air heater operating temperatures and can lead to equipment fouling and pluggage. Conversion of SC^ to SOg is accelerated at temperatures above 700 F. Therefore, in high dust and low dust applications where SC^ is present, ammonia injection (SCR operation) is limited to temperatures below 680 to 700 F. This limitation is necessary to minimize the conversion of SC^ to SOg and the subsequent conversion to ammonium bisulfate. In addition, catalyst configuration can minimize ammonia slip to levels as low as 2 ppm or less. Very low ammonia slip levels would reduce the potential for ammonium bisulfate fouling. For a typical vanadium pentoxide SCR catalyst, the optimum working temperatures range from 570 to 750 F. Based on these temperature requirements there are the following potential system locations. A high dust arrangement with the catalyst located at the outlet of the economizer before the air heater.

6 708 Air Pollution NHj Addition -* SCR Catalyst Flue Gas Temperature 550 F F - Desired Reactions 4NO + 4NH-, + CD; Catetyrt 4^ + 6H^O + Heat t 2NO + 4NHj + Oj 3Nj + 6HjO + Heat t Secondary Undesired Reactions 2 S0z + 02^^^2503 4NHg + SO; - 4NO + 6H]O 4NH, + 3C>2 -* 2N; + 6HJO Figure 1. Predominant SCR Reactions A low dust arrangement with the catalyst located after a hotside precipitator upstream of the air heater. A tail end arrangement with the catalyst located after paniculate and flue gas desulfurization operations. This arrangement requires reheat of the flue gas exiting FGD operations. All three configurations have been successfully used in pulverized coal fired applications in Japan and Europe. Catalyst life is maximized and more reactive catalyst formulations (reducing overall catalyst costs) can be used for tail end applications since the predominant catalyst degradents and poisons (paniculate, sulfur compounds, trace elements) are removed from the gas stream. However, reheating the flue gas is expensive possibly requiring a supplemental combustion source (and additional related permitting) or use of steam from the generating unit (derate). Low dust and high dust catalyst lives are similar, but the low dust catalyst can have a smaller pitch leading to more cost effective catalyst. Figure 2 illustrates a typical high dust SCR system configuration.

7 Air Pollution 709 <-Catalyst Evaporator Combustion -\ Air -V Ammonia Tank Figure 2. Selective Catalytic Reduction High Dust Arrangement A catalyst is generally configured in one of two manners: (1) supported extrudates (homogeneous honeycomb ceramic); or (2) catalyst coatings on mechanical supports (nonhomogeneous plate or ceramic). Most catalysts in coal fired service consist of a vanadia (active catalyst) and titania (used to disperse and support the vanadia) mixture. This is done as a catalyst coating on mechanical supports. Work is presently underway to lower catalyst cost through the use of supported extrudates. Tungsten is also used to inhibit oxidation of SC^. Since the cost of the catalyst can be up to 60 percent of the initial capital cost of an SCR unit, the catalyst's life expectancy is critical to the decision to purchase an SCR system for NO% emissions reduction. The five primary causes of catalyst deactivation include fouling, plugging, mechanical failures, poisoning, and thermal degradation.

8 710 Air Pollution Mechanical failures due to erosion can be minimized through the use of a dummy catalyst layer or grid. This grid or dummy catalyst layer will straighten flow vectors prior to gas entering the catalyst minimizing erosion and optimizing flue gas distribution. A large number of existing SCR installations on coal fired power plants use a bypass for startup, shutdown, and malfunction. Predominately bypass has been used to minimize the thermal shock to the catalyst during startup. Most of these plants justified the installation of a bypass due to frequent cycling of the units. With proper design and operation the most significant catalyst deactivation results from poisoning. A number of alkali metals and trace elements present in coal lead to catalyst poisoning. Dependent on catalyst composition and service (cycling or base loaded), catalyst deactivation rates, and the catalyst management plan used, effective catalyst lives can range between 3 and 10 years. Catalyst manufacturers have recently guaranteed the initial charge of catalyst for up to three years. Selective Noncatalytic Reduction Selective noncatalytic reduction is also a postcombustion process that reduces NO% to form nitrogen and water by chemically reducing NO% with vaporized ammonia (NH^). However, with SNCR the reaction is not promoted by a catalyst, but is instead promoted by appropriate thermal conditions. Either ammonia (Thermal DeNOx) or urea (NOxOUT) can be used as reagent. Since the reactions are very time and temperature dependent SNCR NO% reduction effectiveness is limited to between 30 and 60 percent. In addition to SCR reactions, Figure 1 illustrates the predominant SNCR reactions. The SNCR system consists of the following components: reagent storage and vaporization, reagent injection, and instrumentation. Figure 3 illustrates the dependency of an SNCR system NO% reduction to temperature. The optimum temperature range for injection of NHg is 1,500 F to 1,900 F. Operation on the back side of the curve (1,400 to 1,700 F) results in high ammonia slip. Operation on the front side of the curve (1,700 F to 2,000 F) results in high ammonia thermal decomposition rates (lost reagent). If a readily oxidizable gas, such as hydrogen, is injected, then the lower end of the optimum temperature range for NO% reduction can be lowered to between 1,300 F and 1,400 F. Residence times in excess of 1 second would yield optimum NO% reductions (70 percent or greater reduction). However, a minimum residence time of at least 0.3 seconds is desired to assure moderate SNCR effectiveness (30 to 50 percent reduction).

9 Air Pollution Flue Gas Temperature, F Figure 3. General SCNR NO* Reduction Curve SNCR reactions are relatively inefficient, requiring more than four times the theoretical amount of reagent to achieve NO% reductions as compared to SCR. The increased reagent consumption is due to reaction inefficiencies, reagent thermal decomposition, varying temperatures, and the lack of a true steady-state controlled environment and would, therefore, tend to increase ammonia slip levels (generally between 10 and 50 ppm). In coal fired applications with SOg present this can lead to downstream equipment fouling complications resulting from the formation of ammonium bisulfate. As compared to SCR there is not a great potential with SNCR to limit ammonia slip emissions to very low levels. It is difficult to maintain a constant temperature range for significant residence time at the reagent injection point for a large steam generator, because flue gas temperature varies across the boiler crosssection and with unit load. Accordingly, for large boilers it may be necessary to use water or steam cooled injection lances instead of the standard and more proven wall injectors. In addition, optimum SNCR temperatures in pulverized coal boilers at full load occur in tubed sections of the boiler. Heat transfer in these tubed sections occur quickly further compromising the potential effectiveness of SNCR. To cover the operating load range for a boiler it will also be necessary to

10 712 Air Pollution install multiple injection levels to follow optimum reaction temperatures. The complexity of this task for most existing boilers would be high and the effectiveness of SNCR may be marginal. The capital costs of SNCR systems are not as high as SCR systems, but a royalty fee must be paid to process developers. However, the patents for ammonia based systems will be expiring shortly. The operating cost for ammonia will be significantly higher for an SNCR system compared to SCR systems, but the SNCR system does not require catalyst replacement. However, operating experience with SNCR systems on pulverized coal fueled steam generators is very limited. Predominantly US experience has been with circulating fluidized bed boilers which provide an optimum reaction environment in the cyclones. Hybrid Technology The combination of SCR and SNCR technologies into a hybrid process offers several theoretical benefits. Injection of SNCR reagent at relatively high temperatures results in a large amount of ammonia decomposition, which wastes reagent. In a stand-alone SNCR system, this operation on the front side of the curve is necessary to minimize ammonia slip. Injection of the SNCR reagent at lower temperatures increases ammonia slip. However, installation of an SCR catalyst polishes these ammonia slip emissions while achieving a higher overall NO% reduction efficiency without all the reaction taking place in the catalyst bed. Use of SNCR injection on the back side of the curve (lower temperatures) results in some economic NO% reduction (20 to 30 percent), allowing the use of a downsized SCR system to achieve overall NO% emission objectives. Accordingly, the use of a hybrid system could become a cost effective way to improve NO% reductions at ammonia slip levels of less than 5 ppm. The reagent storage, preparation, injection, and design concerns for the hybrid system are identical to those for the base SNCR system. However, the SNCR part of the hybrid system would be designed for maximum NO% reduction without regard to ammonia slip. The SCR catalyst would be sized to use the ammonia slip from the SNCR system as reagent for further NO% reduction while limiting the overall system slip to less then 5 ppm. The SCR catalyst in a hybrid installation would be located in a high dust configuration, downstream of the economizer and upstream of the air heater. The catalyst design, life expectancy, and disposal

11 Air Pollution 713 concerns would be approximately the same as discussed previously, except that the catalyst would be smaller. The hybrid system involving SNCR injection and an in-duct SCR catalyst is currently in the development stage. Some demonstration testing of a hybrid system with an air heater catalyst is occurring in California. However, this configuration may not be the most economic. This technology is considered to be in the developmental stage, and its commercial viability has not yet been determined. Reagent Options Ammonia is required for both SNCR and SCR systems. There are two types of ammonia reagent available: Ammonia and urea. Urea is a different form of ammonia that decomposes at elevated temperatures to ammonia, water, and CC^. At present, urea is used only in SNCR systems. Reagent for SCR systems use can be either aqueous or anhydrous ammonia. Ammonia mixed with water is referred to as aqueous ammonia. Anhydrous (pure) ammonia is less costly than aqueous and requires less space because it is more concentrated. Anhydrous Ammonia. Anhydrous ammonia is clear when in the liquid state and boils at a temperature of -34 C (-28 F). Liquid anhydrous ammonia must be stored under pressure at ambient temperatures. With anhydrous ammonia, an invisible vapor or gas is formed as the liquid evaporates during depressurization or heating. The anhydrous ammonia system requires a pressurized, aboveground storage vessel. Anhydrous ammonia gas is a hazardous chemical, and stringent requirements for safety and fire protection must be considered in the design of an NO% reduction system which uses it. The storage vessel should have high and low temperature and pressure alarms as well as a liquid level monitor. The liquid anhydrous ammonia reagent can be delivered by truck or rail to the storage facility and transferred by a truck or railcar mounted pump to the storage tank. Liquid anhydrous ammonia must be heated by a vaporizer, causing a phase change from liquid to gas. The vaporization of ammonia typically is accomplished by a close coupled system, external to the storage tank. The location of the vaporization system should be in the immediate vicinity of the ammonia storage tank. The heated gaseous ammonia is piped to the SCR reactor area and diluted with carrier air to an approximately 5 percent ammonia concentration. The carrier air

12 714 Air Pollution provides bulk flow for more efficient distribution and mixing of ammonia with flue gas. Ammonia vapor is regulated through a flow control valve before being mixed with the carrier air from the blower. Aqueous Ammonia. When ammonia is diluted with water to between 20 and 30 percent by weight, aqueous ammonia is formed. Evaporation of ammonia gas from the aqueous ammonia is less of a concern at ambient conditions. As a result, the aqueous ammonia system requires only a nonpressurized, aboveground storage tank and feed pumps. The aqueous ammonia reagent is delivered by truck or rail to the storage facility, where it is transferred by unloading pumps located in the vicinity of the storage tanks. Aqueous ammonia is gravity fed from the storage tank to constant flow feed pumps. The aqueous ammonia can be vaporized before injection or evaporated in situ in the ductwork. Systems which evaporate aqueous ammonia prior to injection use an ammonia/air mixing chamber in which preheated air evaporates the ammonia. The systems typically consist of electric heaters, air blowers, and an ammonia/hot air mixing chamber. Aqueous ammonia systems which evaporate the reagent in situ use pumps to transfer the aqueous ammonia to the injection system, where atomization takes place, before the ammonia is injected into the flue gas stream. The aqueous ammonia is evaporated by the hot flue gas in the ductwork. The pumps are designed for constant flow, allowing excess aqueous ammonia to be recirculated to the storage tank by a pressure control valve. Automatic flow controls adjust the amount of ammonia injected into the flue gas duct. The in situ evaporation system will add some moisture to the flue gas, but the amount of additional moisture is not anticipated to affect plant operations. Worldwide Experience/Development Status Selective catalytic reduction systems were first used in Japan during the 1970s. Through 1990, 40 SCR systems were operating on 10,852 MW of coal fueled utility service. Japanese SCR systems were operated to achieve between 70 and 80 percent NO% reduction, with ammonia slip less than 10 ppm. Coals burned in the Japanese boilers have low sulfur (less than 1 percent) and low ash (less than 10 percent) contents. In response to nationwide legislation, SCR has been retrofitted to 129 German coal fueled boilers totalling 30,625 MW. Most of the Japanese and German SCR systems are generally operated to achieve 80 percent NO% reduction to meet an NO% emission limit of

13 Air Pollution mg/nnr* (approximately 100 ppm) while maintaining ammonia slip emissions to below 5 ppm. Similar to Japanese SCR experience, coals burned at German facilities have a relatively low sulfur (0.7 to 1.2 percent) content. However, some of the German SCR systems are installed on low rank brown coal boilers with low heating values and high ash contents. To date, there are no full-size coal fueled boilers using SCR systems in the United States. However, a number of new pulverized coal fired boilers in Florida and New Jersey require the use of SCR to meet NO% emission limitations. These facilities will not begin operation until The Electric Power Research Institute (EPRI) is currently conducting tests at TVA's Shawnee Station and at their high sulfur test center at NYSEG's Somerset Station. However, demonstration is in the early stages and no public data is available. Therefore, operational data is not available to fully evaluate the effectiveness of SCR at facilities burning US coals. Preliminary results have not shown any large problem areas in the application of SCR on boilers with US fuels. Two uncertainties remain regarding design, performance, operating parameters, and cost of SCR systems on US plants as compared to worldwide experience. First, US utility power plants operate under more variable loads. Second, the amounts of sulfur, ash, and trace elements in US coals are different from those in coals consumed in Japan and Europe. Combustion of higher sulfur US coals will result in the emission of larger quantities of SOg and a higher potential for ammonium bisulfate fouling. Higher levels of ash and trace elements may affect catalyst life and system cost. Ammonia and urea based SNCR processes have been commercially demonstrated in gas, oil, and coal fueled boiler applications, achieving NO% reduction efficiencies ranging from 30 to 60 percent with ammonia slip less than 20 ppm in some circumstances. The predominance of this coal fueled experience has been with circulating fluidized bed (CFB) boilers that have optimum residence times because these boilers recycle solids using cyclones operating at a relatively homogeneous temperature of 1,600 F for more than one second. SNCR systems have been installed on only four pulverized coal boilers, the largest being a 500 MW pulverized coal unit in Germany. This facility is subsequently being retrofitted with a SCR system. The other pulverized coal SNCR applications have been on boilers less than 150 MW. Overall, based on the anticipated requirements of the CAAA, the restrictions of existing boiler geometries, operational flexibility, good overseas experience, and improving economics it is anticipated that a number of SCR systems will be retrofitted in the next decade.

14 716 Air Pollution Balance-of-Plant Issues The following balance-of-plant issues must be considered when designing an SCR system retrofit: If the SCR reactor is to be located in a hot side, high dust location between the economizer outlet and the air heater inlet, the catalyst bed should be oriented in the vertically downward flow arrangement. A vertical flow catalyst bed tends to be more self-cleaning than a horizontal flow catalyst bed in coal fired applications. Accordingly, duct routing should permit the installation of a top entry, vertical flow SCR reactor. The SCR reactor should be configured with enough catalyst layers to meet initial emission objectives for the guaranteed operational period (two to three years) plus at least one spare empty layer to improve life cycle catalyst management. At the end of the guaranteed operational period the initial catalyst charge will not be completely deactivated. To benefit from this residual catalyst activity fresh catalyst would first be added to the spare empty layer. Subsequent catalyst additions would start by replacing original catalyst layers. Catalyst management plans such as this can extend effective comprehensive catalyst lives to between six and ten years. Use of an SCR system will increase the SO] content present in the flue gas downstream of the catalyst. Increased SO^ content concentrations lead to an increase in the acid dew point of the flue gas. Hence higher air heater outlet temperatures may be required and decreased boiler efficiency may result from the use of SCR if the oxidation of SC>2 is not limited to less than 1.0 percent. Air heater cold-end corrosion rates can increase due to increased SO^ emissions emanating from an SCR system. Accordingly cold-end baskets should be enameled to avoid attack. Air heater fouling by precipitated ammonium bisulfate is a concern for SCR use. Air heater operation should be examined to determine where ammonium bisulfate liquefaction temperatures (approximately 410 F) may occur. Should this temperature routinely occur between air heater basket levels modifications should be made to ensure that the liquefaction temperature occurs within baskets. It is

15 Air Pollution 717 possibly to modify the air heater design by converting a three layer basket design to a two layer basket design, without changing the total basket surface area. It is suggested that hot and cold end air heater soot blowers be installed for proper cleaning of ammonia bisulfate buildup during operation. In addition, the air heater will need to have high pressure low volume and low pressure high volume wash water systems for air heater cleaning while the unit is down. Wet bottom boilers that recycle ash and units burning relatively high arsenic coals may require special provisions to minimize the potential effect of arsenic poisoning. Care must be taken to minimize SCR system ammonia slip emissions below certain levels to maintain safe conditioning of alkaline fly ash or fixation of scrubber solids with fly ash. Retrofit of an SCR system will add between 4 and 6 inches water gauge (higher for tail end systems with gas to gas reheaters) to generating unit draft requirements. This does not include any margin to account for any pressure drop through the air heater due to modification or ammonia bisulfate buildup. Accordingly, fan capabilities will require assessment potentially requiring fan modification or replacement. The additional weight of an SCR system requires a foundation designed to accommodate the additional load. The SCR can be supported by the boiler building structural steel. The design of both vertical and horizontal bracing from the ground level to the roof elevation must be evaluated to determine the structural impact of an SCR system. Control of ammonia injection will predominately occur by feedforward of unit load and SCR inlet NO% concentration, and feedback of outlet NO% concentration. Ammonia slip monitors are not reliable at low concentrations and are not recommended for this service at this time. However, considering the importance for safe ash and scrubber solids disposal, it is recommended that ammonia slip be monitored on a regular basis by manually sampling the fly ash. This

16 718 Air Pollution frequent ash sampling will provide a good indirect measurement of catalyst deactivation rates. Installation of an SCR system could benefit precipitator performance since increased paniculate removal may result from the ammonia slip and the increase of SO^ concentration in the flue gas. Ammonium bisulfate particles, in a liquid-solid phase at typical flue gas temperatures, tend to cohere when mixed with fly ash. This reduces rapping losses without an adverse effect on ash handling. No detrimental effect should occur to FGD system operation from installing an SCR system. Conclusions US utilities can reduce their NO% emissions to meet some 1990 Clean Air Act Amendment requirements by retrofitting low NO% burners or another in-fumace combustion control process. However, retrofitting low NO% burners or other combustion controls can be expensive and may achieve dissimilar results for various combustor geometries. In addition, combustion controls may be sufficient to meet Title IV Phase 1 NO% emission requirements for dry bottom pulverized coal fired boilers, but may be insufficient to meet Title I or future Title IV requirements. Selective catalytic reduction and selective noncatalytic reduction technologies offer utilities a postcombustion alternative for NO% emissions control. Although these alternatives are likely to be more expensive than combustion controls the CAAA may necessitate their use. SCR is the more demonstrated of the two postcombustion NO% reduction technologies. Overall, based on anticipated regulatory requirements, the restrictions of existing boiler geometries, operational flexibility, good overseas experience, and improving economics it is anticipated that a number of SCR systems will be retrofitted in the next decade. With careful consideration of design, SCR systems can be retrofitted effectively to ensure achievement of overall NO% emission objectives without compromising unit availabilities.