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Selective catalytic reduction (SCR) has been applied to stationary source fossil fuel-fired combustion units for emission control since the early 1970s and ...
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John L. Sorrels Air Economics Group Health and Environmental Impacts Division Office of Air Quality Planning and Standards U.S. Environmental Protection Agency Research Triangle Park, NC 27711 David D. Randall, Karen S. Schaffner, Carrie Richardson Fry RTI International Research Triangle Park, NC 277 09 June 2019
This document includes references to specific companies, trade names and commercial products. Mention of these companies and their products in this document is not intended to constitute an endorsement or recommendation by the U.S. Environmental Protection Agency.
Selective catalytic reduction (SCR) has been applied to stationary source fossil fuel-fired combustion units for emission control since the early 1970s and is currently being used in Japan, Europe, the United States, and other countries. In the U.S. alone, more than 1,000 SCR systems have been installed on a wide variety of sources in many different industries, including utility and industrial boilers, process heaters, gas turbines, internal combustion engines, chemical plants, and steel mills [ 1 ]. Other sources include fluid catalytic cracking units (FCCUs), ethylene cracker furnaces, nitric acid plants, catalyst manufacturing processes, nitrogen fixation processes, and solid/liquid or gas waste incinerators [2, 3 ]. In the U.S., SCR has been installed on more than 300 coal-fired power plants ranging in size from less than 100 megawatt equivalent (MWe) to 1,400 MWe [1, 4 ]. Other combustion sources with large numbers of SCR retrofits include more than 50 gas-fired utility boilers ranging in size from 147 MWe to 750 MWe, more than 50 industrial boilers and process heaters (both field-erected and packaged units), and more than 650 combined cycle gas turbines [ 1 ]. SCR can be applied as a stand-alone nitrogen oxides (NOx) control or with other technologies, including selective non-catalytic reduction (SNCR)^1 and combustion controls such as low NOx burner (LNB) and flue gas recirculation (FGR) [ 2 ]. SCR is typically implemented on stationary source combustion units requiring a higher level of NOx reduction than achievable by selective non-catalytic reduction (SNCR) or combustion controls. Theoretically, SCR systems can be designed for NOx removal efficiencies up close to 100 percent. In practice, commercial coal-, oil-, and natural gas–fired SCR systems are often designed to meet control targets of over 90 percent. However, the reduction may be less than 90 percent when SCR follows other NOx controls such as LNB or FGR that achieve relatively low emissions on their own. The outlet concentration from SCR on a utility boiler is rarely less than 0.04 lb/million British thermal units (MMBtu) [1].^2 In comparison, SNCR units typically achieve approximately 25 to 75 percent reduction efficiencies [ 5 ]. Either ammonia or urea may be used as the NOx reduction reagent in SCR systems. Urea is generally converted to ammonia before injection. Results of a survey of electric utilities that operate SCR systems indicated that about 80 percent use ammonia (anhydrous and aqueous), and the remainder use urea [ 4 ]. A survey of coal-fired power plants that control NOx emissions using either SCR or SNCR found anhydrous ammonia use exceeds aqueous ammonia use by a ratio of 3 to 1. Nearly half of these survey respondents also indicated that price is their primary consideration in the choice of reagent; safety is the primary consideration for about 25 percent of the operators [ 6 ]. SCR capital costs vary by the type of unit controlled, the fuel type, the inlet NOx level, the outlet NOx design level, and reactor arrangement. Capital costs also rose between 2000 and 2010 (at least for utility boiler applications), even after scaling all data to 20 11 dollars (2011$). (^1) A hybrid SNCR/SCR system was demonstrated at the AES Greenidge Power Plant in 2006. However, no hybrid SNCR/SCR systems are currently known to be operating as of February 2016. (^2) Data in the Clean Air Markets Division (CAMD) database also suggest SCR units rarely achieve emissions less than 0.04 lb/MMBtu.
from pyritic sulfur found in the raw materials used by U.S. cement plants. The SO 3 could react with calcium oxide in the flue gas to form calcium sulfate and with ammonia to form ammonium bisulfate. The calcium sulfate could deactivate the catalyst, while the ammonium bisulfate could cause catalyst plugging. There have been concerns expressed about the potential for catalyst poisoning by sodium, potassium, and arsenic trioxide. Finally, other concerns expressed are that dioxins and furans may form in the SCR due to combustion gases remaining at temperatures between 450 degrees Fahrenheit (°F) and 750°F. These and other concerns regarding the implementation of SCR to the cement industry are discussed in detail in “Alternative Control Techniques Document Update – NOx Emissions from New Cement Kilns” [ 10 ]. Due to the small number of SCRs installed at cement plants, information on capital and operating costs for SCRs at cement plants is limited. The installation and operating costs for the SCR installed at the U.S. plant in 2013 are not publicly available at this time. In general, we expect the capital and operating costs would be higher than for low-dust applications due to the need to install catalyst cleaning equipment for SCR systems installed in high-dust configurations and for heating the flue gas in low-dust, tail-end configurations.
Table 2.1a: Summary of SCR Cost Data for Utility Boilers Source Category Unit Size Fuel Type Capital Cost Min Avg Max $ Year Comments Reference Electric Generating Units NAa^ NA $55/kW $140/kW <2000$b^ Retrofit costs. [ 13 ] ~300-1, MW NA ~$70/kW ~$120/kW <2000$b^ Retrofit costs. Six boilers. No economy of scale. [ 13 ] 150 – 1, MW Coal $80/kWnetc^ $160/kWnetc^ 2002$ Retrofit costs. Author of referenced document scaled original costs to 2002 dollars. More than 20 boilers. Little to no economy of scale. [1 4 ] NA Coal $60/kW $100kW $200/kW <2004$b^ Retrofit costs [1 5 ] <300 MW Coal $167/kW $186/kW <2004$ Costs for 26 boilers. [1 6 ] 301 – 600 MW Coal $148/kW $192/kW <2004$ Costs for 15 boilers. [1 6 ] 601 – 900 MW Coal $124/kW $221/kW <2004$ Costs for 22 boilers. [1 6 ]
900 MW Coal $118/kW $195/kW <2004$ Costs for 9 boilers. [1 6 ] 100 – 399 MW Coal $70/kW $123/kW ~$175/kW <2004$b^ Costs for 5 boilers. [1 7 ] 400 – 599 MW Coal $73/kW $103/kW ~$160/kW <2004$b^ Costs for 8 boilers. [1 7 ] 600 – 899 MW Coal $56/kW $81/kW ~$100/kW <2004$b^ Costs for 9 boilers. [1 7 ] 900 MW Coal ~$80/kW $117/kW ~$190/kW <2004$b^ Costs for 10 boilers. [1 7 ] 191 MW Coal $149/kW 2006$ Retrofit costs. [1 8 ] ~100 MW- ~800MW NA ~$125/kW $275/kW ~$440/kW 2008$ Retrofit costs for 15 boilers installed in 2008 to 2010. Most costs between $200/kW and $350/kW. Slight economy of scale—regression average about $340/kW for 100 MW to $250/kW for 800 MW. [ 8 ] ~400 MW to ~800 MW NA ~$270/kW ~$420/kW ~560/kW 2011$ Retrofit costs for 8 boilers either installed in 2012 or projected to be installed by
[7] a (^) Not Available. b (^) Year of reference. c (^) Net kilowatts.
Source Category Unit Size Fuel Type Capital Cost: average (range) $ Year Actual, Vendor Quote, or Estimated? Comments Reference 10 MMBtu/hr Gas or refinery fuel gas/NG combo $19,200/MMBtu ($12,000– $26,500/MMBtu) 1999 b^ Vendor/ Estimated Costs are based primarily on quotes from two vendors (and additional discussions). Authors of the referenced report added costs for fan, motor, and ductwork costs based on procedures in the Control Cost Manual. [ 24 ] 50 MMBtu/hr Gas or refinery fuel gas/NG combo $5,140/MMBtu ($4,020– $6,280/MMBtu) 1999 b^ Vendor/ Estimated Same comment as above. [ 24 ] 75 MMBtu/hr Gas or refinery fuel gas/NG combo $4,190/MMBtu ($3,440– $4,950/MMBtu) 1999 b^ Vendor/ Estimated Same comment as above. [ 24 ] 150 MMBtu/hr Gas or refinery fuel gas/NG combo $2,730/MMBtu ($2,570– $2,880/MMBtu) 1999 b^ Vendor/ Estimated Same comment as above. [ 24 ] 350 MMBtu/hr Gas or refinery fuel gas/NG combo $1,550/MMBtu ($1,520– $1,570/MMBtu) 1999 b^ Vendor/ Estimated Same comment as above. [ 24 ] 68 MMBtu/hr (Two 32 MMBtu/hr) Refinery fuel gas NA ($22,100/MMBtu) 1991 Actual Retrofit costs. [1 9 ] Petroleum Refining – FCCU 70, barrels/str eam day (bbl/strea m day) NA NA ($9. 0 million) 2004$c^ Vendor Estimated cost by vendor (for 90 percent reduction). [ 3 ] 27, bbl/stream day NA NA ($8-$12 million) 2009 Estimated [2 5 ]
Source Category Unit Size Fuel Type Capital Cost: average (range) $ Year Actual, Vendor Quote, or Estimated? Comments Reference <20,000-
100, bbl/stream day NA NA (order of magnitude range; low end higher than two entries above) 2005 to 2010 Actual Costs reported by 6 petroleum refining companies for 7 FCCUs in responses to EPA ICR. One new, 6 retrofits. [2 6 ] NA NA NA ($20 million) 2006 Actual Approximate average cost for SCR retrofits at several refineries [2 7 ] Portland Cement (dry kilns) 1.0 9 million short tpy clinker NA NA ($6.9 per short ton clinker) 2006 a^ Estimated Retrofit cost. Estimate based primarily on SCR procedures for boilers in fifth edition of the Control Cost Manual. Clinker capacity obtained from the second reference. [ 28 ,2 9 ]
million short tpy clinker NA NA ($5.9 per short ton clinker) 2006 a^ Estimated Same comment as above. [ 28 ,2 9 ]
million short tpy clinker NA NA ($3.9 per short ton clinker) 2006 a^ Estimated Same comment as above. [2 8 ,2 9 ] 1.4 million short tpy clinker NA NA ($5.9 per short ton clinker) 2004 Not clear Retrofit cost for European kiln. Cost in euros converted to dollars assuming a ratio of $1.3/euro. [ 30 ]
million tpy clinker NA NA ($4. 4 per short ton clinker) 2004 Estimated Cost for new kiln. [ 31 ]
million short tpy clinker NA NA ($4.4 per short ton clinker) 2011 Estimated Cost for new kiln. Cost based on quote for the SCR equipment, and standard installation factors from the Control Cost Manual for other types of control devices. [ 32 ] Portland Cement (wet kilns) 0.3 million short tpy clinker NA NA ($17.5 per short ton clinker) 2006 a^ Estimated Retrofit costs for 4 kilns. Rated clinker production capacity obtained from the second reference. [ 28 , 33 ]
million short tpy clinker NA ($15.6-$16.6 per short ton clinker) 2006 a^ Estimated Retrofit costs for 3 kilns. Rated clinker production capacity obtained from second reference. [2 8 ,2 9 ]
Like SNCR, the SCR process is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR employs a metal-based catalyst with activated sites to increase the rate of the reduction reaction. The primary components of the SCR include the ammonia storage and delivery system, ammonia injection grid, and the catalyst reactor [ 2 ]. A nitrogen-based reducing agent (reagent), such as ammonia or urea-derived ammonia, is injected into the post-combustion flue gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx into molecular nitrogen (N 2 ) and water vapor (H 2 O). The use of a catalyst results in two primary advantages of the SCR process over SNCR. The main advantage is the higher NOx reduction efficiency. In addition, SCR reactions occur within a lower and broader temperature range. However, the decrease in reaction temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs. The capital cost increase is mainly due to the large volumes of catalyst required for the reduction reaction. Operating costs for SCR consist mostly of replacement catalyst and ammonia reagent costs, and while historically, the catalyst replacement cost has been the largest cost, the reagent cost has become the most substantial portion of operating costs for most SCR [ 7 ].^4 Figure 2.1 shows a simplified process flow schematic for SCR. Reagent is injected into the flue gas downstream of the combustion unit and economizer through an injection grid mounted in the ductwork. The reagent is generally diluted with compressed air or steam to aid in injection. The reagent mixes with the flue gas, and both components enter a reactor chamber containing the catalyst. As the hot flue gas and reagent diffuse through the catalyst and contact activated catalyst sites, NOx in the flue gas chemically reduces to nitrogen and water. The heat of the flue gas provides energy for the reaction. The nitrogen, water vapor, and any other flue gas constituents then flow out of the SCR reactor. More detail on the SCR process and equipment is provided in the following sections. There are several different locations downstream of the combustion unit where SCR systems can be installed. Flue gas temperature and constituents vary with the location of the SCR reactor chamber. SCR reactors located upstream of the particulate control device and the air heater (“high-dust” configuration) have higher temperatures and higher levels of particulate matter. An SCR reactor located downstream of the air heater, particulate control devices, and flue gas desulfurization (FGD) system (“low-dust” or “tail-end” configuration) is essentially dust- and sulfur-free but its temperature is generally below the acceptable range. In this case, reheating of the flue gas may be required, which significantly increases the SCR operational costs. Section 2.2.3 discusses the various SCR system configurations. (^4) Several cost analyses in recent years have shown the largest operating cost is for reagent usage rather than for catalyst costs. For example, for the Navajo Generating Station in Arizona, a 2010 BART analysis report on an 812 MW gross coal-fired unit estimates annual operating costs for ammonia reagent of $1,035,000 (based on $465/ton) and for catalyst replacement of $672,000 (based on $8,000/m^3 ) [34].
Figure 2.1: SCR Process Flow Diagram [ 35 , 36 ] 2.2.1 Reduction Chemistry, Reagents, and Catalyst The reducing agent employed by the majority of SCR systems is gas-phase ammonia (NH 3 ) because it readily penetrates the catalyst pores. The ammonia, either in anhydrous or aqueous form, is vaporized before injection by a vaporizer. Within the appropriate temperature range, the gas-phase ammonia then decomposes into free radicals, including NH 3 and an amide (NH 2 ). After a series of reactions, the ammonia radicals come into contact with the NOx and reduce it to N 2 and H 2 O. Since NOx includes both nitrogen monoxide (NO) and nitrogen dioxide (NO 2 ), the overall reactions with ammonia are as follows: NO NH 3 O 2 catalyst 2 N 2 3 H 2 O 2 1 2 + 2 + ⎯⎯⎯ → + (2.1a)
catalyst
The equations indicate that one mole of NH 3 is required to remove one mole of NO and two moles of NH 3 are required to remove one mole of NO 2. However, Equation 2.1a is the predominant reaction because 90 to 95 percent of NOx in flue gas from combustion units is NO. Hence, about one mole of NH 3 is required to remove one mole of NOx. The catalyst lowers the
system cost is 2 to 5 percent higher when using a urea reagent system instead of an anhydrous ammonia system [1 4 ]. Relative to anhydrous ammonia, one reference estimated annual operating costs for 1 9 percent aqueous ammonia are 50 percent higher, costs for 29 percent aqueous ammonia are 33 percent higher, and costs for urea are 25 percent higher [ 40 ]. Another reference stated that as a general rule, operating costs for urea systems are about 50 percent more than the operating costs for anhydrous ammonia [3 9 ]. One reference estimated energy costs for an unspecified application to be $167,000 for a urea system, $73,000 to $117,000 for aqueous ammonia systems, and $16,000 for anhydrous ammonia [ 41 ]. This presentation is valid for anhydrous or aqueous ammonia; the capital cost procedures are based on the typical mix of systems actually in operation, while the procedures for estimating annual costs apply to any ammonia system (the examples in section 2.5 illustrate the procedures for a system using 29 percent aqueous ammonia as the reagent). Table 2.2: Ammonia Reagent Properties Property Anhydrous Ammonia [ 42 , 43 ] Aqueous Ammonia Liquid or gas at normal air temperature Liquid at high pressure; gas at atmospheric pressure Liquid Concentration of reagent normally supplied 99.5 percent (by weight) 29.4 percent (by weight of NH 3 ) Molecular weight of reagent 17.03 17.03 (as NH 3 ) Ratio of ammonia to solution 99.5 percent (by weight of NH 3 ) 29.4 percent (by weight of NH 3 ) Density of liquid at 60°F 5.1 lb/gal 7.5 lb/gal Vapor pressure at 80°F 153 psia 14.6 psia [ 43 , p. 3] Flammability limits in air 16 – 25 percent NH 3 (by volume) 16 to 25 percent NH 3 (by volume) Short-term exposure limit 35 ppm 35 ppm Odor Pungent odor at 5 ppm or more Pungent odor at 5 ppm or more Acceptable materials for storage Steel tank, rated for at least 250 psig pressure (no copper or copper-based alloys, etc.) Steel tank, rated for at least 25 psig pressure (no copper or copper- based alloys, etc.) Catalyst SCR catalysts are composed of active metals or ceramics with a highly porous structure. Within the pores of the catalyst are activated sites. These sites have an acid group on the end of the compound structure where the reduction reaction occurs. As stated previously, after the reduction reaction occurs, the site reactivates via rehydration or oxidation. Over time, however, the catalyst activity decreases, requiring replacement, washing/cleaning, rejuvenation, or regeneration of the catalyst. Catalyst designs and formulations are generally proprietary. Both the catalyst material and configuration determine the properties of the catalyst. Originally, SCR catalysts were precious metals such as platinum (Pt). In the late 1970s, Japanese researchers used base metals consisting of vanadium (V), titanium (Ti), and tungsten (W), which significantly reduced catalyst cost. In the 1980s, metal oxides such as titanium oxide (TiO 2 ), zirconium oxide (ZrO 2 ), vanadium pentoxide (V 2 O 5 ), and silicon oxide (SiO 2 ) were employed to broaden the reaction temperature range. Zeolites, crystalline alumina silicates, were also introduced for high temperature (675 to 1 ,000°F; 360 to 540°C) applications; however, zeolites tended to be cost prohibitive. From 1980 to 2008 , the cost of catalyst has dropped from
approximately $34,000/m^3 to a range of $5,000 to $6,000/m^3 (costs are in 2011 $) [ 7 ].^5 This reference also reported that catalyst prices remained in the approximate range of $5,000 to $6,000/m^3 through 2012. Improvements to the catalyst formulations over time have decreased unwanted side reactions such as sulfur oxide conversions (sulfur dioxide (SO 2 ) to SO 3 ) and increased the resistance to flue gas poisons, and newer catalysts can oxidize metallic mercury (Hg) into ionic forms (for easy removal downstream in wet scrubbers and wet electrostatic precipitators [ESPs]) [ 44 ]. Improved catalyst designs have also increased catalyst activity, surface area per unit volume, and the temperature range for the reduction reaction. As a consequence, there is a corresponding decrease in the required catalyst volumes and an increase in the catalyst operating life. For coal-fired boiler applications, SCR catalyst vendors typically guarantee the catalyst for an operating life ranging from 8,000 to 24,000 hours [ 1 ]. Applications using oil and natural gas have a longer operating life, typically greater than 32,000 hours [ 45 ]. In addition, operating experience indicates that actual catalyst deactivation rates are lower than the design specifications [ 37 ]. The latest demands on catalyst technology for both higher and lower sulfur coal-fired boilers include design NOx removal of 90 percent; control of residual NH 3 to 2 parts per million (ppm) (i.e., ammonia slip); guarantees for SO 2 oxidation to less than 1 percent, and in many cases, to less than 0.5 percent; being able to withstand washing/cleaning and regeneration procedures; and guarantees for mercury oxidation [ 41 ]. Catalyst formulations include single component, multi-component, or active phase with a support structure. Most catalyst formulations contain additional compounds or supports to give thermal and structural stability or to increase surface area [ 46 ]. Catalyst configurations are generally ceramic honeycomb and pleated metal plate (monolith) designs in a fixed-bed reactor, which provide high surface area to volume ratio. Pellet catalysts in fluidized beds are also available. Pellets have greater surface area than honeycombs or pleated plates but are more susceptible to plugging. This limits the use of pellets to clean-burning fuels such as natural gas. Catalyst elements placed in a frame form a catalyst module. The modules stack together in multiple layers to create a reactor bed of the total required catalyst volume. A typical module is 3.3 ft × 6.6 ft in area (1 m × 2 m) and 3.3 ft (1 m) in height. A crane hoists the large catalyst modules into the reactor from either the interior or exterior of the reactor, depending on the reactor design. Catalysts greatly accelerate the NOx reduction reaction rate, but some catalysts have more favorable properties for a given application. Performance requirements that drive the choice of catalyst include reaction temperature range, flue gas flow rate, fuel source, catalyst activity and selectivity, SO 2 oxidation, and catalyst operating life. In addition, the design must consider the cost of the catalyst, including disposal costs [ 37 ]. In the past, the initial charge of catalyst costs accounted for 20 percent or more of the capital costs for an SCR system [ 37 ], however, as catalyst unit cost has declined over time, this catalyst cost is a smaller percentage of the capital costs [ 8 ]. (^5) An earlier reference shows that from 1980 to 2006 , the cost of catalyst dropped by 75 percent from approximately $16,000/m^3 to less than $4,000/m^3 [41]. These costs are for the cost year reported and are not adjusted for escalation to current year.
spend approximately $2,000,000^6 on a single layer of new catalyst [ 54 ]. The cost for regenerated catalyst for this same facility would be approximately $1,000,000 for a single layer of catalyst [ 54 ]. Disposal costs when replacing a spent catalyst could be $50,00 0 to $200,000 per layer, and these costs are avoided with regenerated catalysts [ 48 ]. Regenerated catalyst typically costs 40 percent less than new catalyst [53, 54. 55]. 2.2.2 SCR Performance Parameters The rate of the reduction reaction determines the amount of NOx removed from the flue gas. The major design and operational factors that affect the NOx removal performance of SCR are similar to those presented in Chapter 1, SNCR. The factors discussed previously for SNCR include the following: ▪ Reaction temperature range; ▪ Residence time available in the optimum temperature range; ▪ Degree of mixing between the injected reagent and the combustion gases; ▪ Molar ratio of injected reagent to inlet NOx; ▪ Inlet NOx concentration level; and ▪ Ammonia slip. The majority of the discussion regarding SNCR design and operational factors is valid for the SCR process, except for small variations due to the use of a catalyst and the reaction chamber being separate from the combustion unit. Additional design and operational factors to consider that are specific to the SCR process include the following: ▪ Catalyst activity; ▪ Catalyst selectivity; ▪ Pressure drop across the catalyst; ▪ Ash management (i.e., mitigating large particle ash (LPA) impacts on the catalyst) and dust loading; ▪ Catalyst pitch; ▪ SO 2 and SO 3 concentrations in gas stream; ▪ Catalyst deactivation; and ▪ Catalyst management. The major differences between SNCR and SCR are discussed below. Temperature The NOx reduction reaction is effective only within a given temperature range. The use of a catalyst in the SCR process lowers the temperature range required to maximize the NOx reduction reaction. At temperatures below the specified range, the reaction kinetics decrease, and ammonia passes through the boiler (ammonia slip), but there is little effect on nitrous oxide (^6) Cost year not available; data are from 2008 article [Reference 54 ].
(N 2 O) formation. At temperatures above the specified range, N 2 O formation increases and catalyst sintering and deactivation occurs, but little ammonia slip occurs. In an SCR system, the optimum temperature depends on both the type of catalyst used in the process and the flue gas composition. For the majority of commercial catalysts (metal oxides), the operating temperatures for the SCR process range from 480 to 800°F (250 to 430 °C) [ 50 ]. Figure 2.2 is a graph of the NOx removal efficiency as a function of temperature for a typical metal oxide catalyst [ 50 ]. The figure shows that the rate of NOx removal increases with temperature up to a maximum between 700 and 750°F (3 70 to 400°C). As the temperature increases above 750°F (400°C), the reaction rate and resulting NOx removal efficiency begin to decrease. Figure 2.2: NOx Removal versus Temperature [ 50 ] As flue gas temperature approaches the optimum, the reaction rate increases and less catalyst volume achieves the same NOx removal efficiency. Figure 2.3 shows the change in the required catalyst volume versus temperature [ 56 ]. There is approximately a 40 percent decrease in the required catalyst volume as flue gas temperature increases from 600°F (320°C) to the optimum range, 700 to 750°F (370 to 400 °C). This decrease in catalyst volume also results in a significant decrease in capital cost for the SCR system. Less catalyst also results in a decrease in annual operation and maintenance costs. For example, the system pressure drop would be lower, which would reduce the additional electricity needed to run the induced draft (ID) fan. The net effect on catalyst replacement costs is uncertain; although the volume of catalyst replaced would be smaller, deactivation may occur more frequently since the quantity of materials in the emission stream responsible for plugging and poisoning would not be reduced.
