# Section 4

NO x 

# Controls EPA/452/B-02-001i 

# Section 4.2

NO x 

# Post- Combustion EPA/452/B-02-001ii 

### Introduction Nitrogen oxides (NO x ) are gaseous pollutants that are primarily formed through combustion process. While flue gas is within the combustion unit, about 95% of the NO xexists in the form of nitric oxide (NO). The balance is nitrogen dioxide (NO 2 ), which is unstable at high temperatures. Once the flue gas is emitted into the atmosphere, most of the NO xis ultimately converted to NO 2 . NO xin the atmosphere reacts in the presence of sunlight to form ozone (O 3 ), one of the criteria pollutants for which health-based National Ambient Air Quality Standards have been established. Since ozone formation requires sunlight and high temperatures, ozone formation is greatest in summer months. NO x is generated in one of three forms; fuel NO x , thermal NO x , and prompt NO x . Fuel NO xis produced by oxidation of nitrogen in the fuel source. Combustion of fuels with high nitrogen content such as coal and residual oils produces greater amounts of NO x than those with low nitrogen content such as distillate oil and natural gas. Thermal NO xis formed by the fixation of molecular nitrogen and oxygen at temperatures greater than 3600  F (2000  C). Prompt NO x forms from the oxidation of hydrocarbon radicals near the combustion flame and produces an insignificant amount of NO x . Selective Noncatalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR) are post-combustion control technologies based on the chemical reduction of nitrogen oxides (NO x ) into molecular nitrogen (N 2 ) and water vapor (H 2 O). The primary difference between the two technologies is that SCR utilizes a catalyst to increase the NO x removal efficiency, which allows the process to occur at lower temperatures. The technologies can be used separately or in combination with other NO xcombustion control technologies such as low NO xburners (LNB) and natural gas reburn (NGR). SNCR and SCR can be designed to provide NO xreductions year-round or only during summer months, when ozone concerns are greatest. This section presents design specifications and a costing methodology for SNCR and SCR applications for large industrial boilers (greater than 250 MMBtu/hr). Its primary purpose is to provide study-level cost estimates. These estimates can be used to compare the approximate costs of SNCR, SCR, and alternative NO xcontrol technologies. The costing methodologies are based on cost estimations for SNCR and SCR applications to utility boilers, which were developed by the Office of Research and Development (ORD), U.S. Environmental Protection Agency (EPA), Research Triangle Park, NC. As a prelude to the cost methodology, the section describes the process chemistry, performance parameters, and system components of SNCR and SCR. In addition, impacts to the boiler performance and facility operations resulting from the installation of SNCR and SCR are presented. The section also estimates important underlying design parameters including the normalized stoichiometric ratio, catalyst volume, and reagent consumption. Lastly, it presentsiii assumptions and equations for estimating capital costs, annual operation and maintenance costs, and annualized costs. SNCR and SCR are discussed in separate chapters, however, the chapter on SCR builds on the concepts discussed in the SNCR chapter. Information on key aspects of the design of SNCR and SCR systems is considered proprietary by vendors, including methods for estimating certain design parameters and costs. This information is not available to develop cost methodologies for SNCR and SCR. In order to obtain estimates of the proprietary design parameters and costs, it is necessary to develop mathematical correlations from available data using regression and curve fitting techniques. These expressions are derived in EPA reports prepared by The Cadmus Group, Bechtel Power, Inc. and SAIC in SNCR and SCR References [1, 2 and 3] from documented comprehensive SNCR and SCR performance data and costs based on quotations provided by suppliers and facilities.1-1 

# Chapter 1 Selective Noncatalytic Reduction

Daniel C. Mussatti Innovative Strategies and Economics Group Air Quality Strategies and Standards Division Office of Air Quality Planning and Standards U.S. Environmental Protection Agency Research Triangle Park, NC 27711 Dr. Ravi Srivastava Office of Research and Development U.S. Environmental Protection Agency Research Triangle Park, NC 27711 Paula M. Hemmer and Randy Strait E. H. Pechan & Associates, Inc. 3622 Lyckan Parkway, Suite 2002 Durham, NC 27707

October 2000 EPA/452/B-02-0011-2 Contents

1.1 Introduction .............................................................................................................. .............................. 1-3 1.2 Process Description ....................................................................................................... ......................... 1-4 1.2.1 Reduction Chemistry

..................................................................................................... ............... 1-5 1.2.2 Reagents

................................................................................................................ ....................... 1-5 1.2.3 SNCR Performance Parameters ..................................................................................................... 1-7 1.2.4 SNCR System .............................................................................................................................. 1 -13 1.2.5 Other Considerations ....................................................................................................

.............. 1-19 1.3 Design Parameters

......................................................................................................... ....................... 1-21 1.3.1 Design Parameters for Study Level Estimates ............................................................................ 1 -21 1.3.2 Design Parameters for Detailed/Performance Specifications

...................................................... 1-27 1.4 Cost Analysis ............................................................................................................

.......................... 1-30 1.4.1 Total Capital Investment

................................................................................................ ............. 1-31 1.4.2 Total Annual Costs ...................................................................................................... ............... 1-33 1.5 Example Problem

............................................................................................................................... ... 1-39 1.5.1 Design Parameter Example

.......................................................................................................... 1-40 1.5.2 Cost Estimation Example

............................................................................................................. 1-42 References .....................................................................................................................

............................. 1-451-3 

### 1.1 Introduction SNCR is currently being used for NO xemission control on industrial boilers, electric utility steam generators, thermal incinerators, and municipal solid waste energy recovery facilities. Its use on utility boilers has generally been limited to units with output of less than 3,100 MMBtu, but large-scale applications of SNCR have been successfully tested such as Cardinal Plant Unit 1, a 600 MW (5,700 MMBtu/hr) utility boiler located in Brilliant, Ohio [11]. SNCR can be applied as a stand-alone NO x control or with other technologies such as combustion controls. The SNCR system can be designed for seasonal or year-round operations. SNCR can achieve NO xreduction efficiencies of up to 75 percent (%) in selected shortterm demonstrations [5]. In typical field applications, however, it provides 30% to 50% NO x reduction. Reductions of up to 65% have been reported for some field applications of SNCR in tandem with combustion control equipment such as low NO x burners (LNB) [11]. SNCR systems applied to large combustion units (greater than 3,000 MMBtu/hr) typically have lower NO x reduction efficiencies (less than 40%), due to mixing limitations [11]. Figure 1.1 presents the NO x reduction efficiency of SNCR for various utility boiler sizes.

0 10 20 30 40 50 60

0 1000 2000 3000 4000 Boiler Size (MMBtu/hr)NOx Reduction Efficiency (%)

Figure 1.1: SNCR NO xReduction Efficiency for Various Boiler Sizes [8]
The hardware associated with an SNCR installation is relatively simple and readily available. Consequently, SNCR applications tend to have low capital costs compared to LNB and SCR. Installation of SNCR equipment requires minimum downtime. Though simple in concept, it is challenging in practice to design an SNCR system that is reliable, economical, simple to control, and meets other technical, environmental, and regulatory criteria. Practical application of SNCR is limited by the boiler design and operating conditions.1-4 The costing algorithms in this report are based on retrofit applications of SNCR to existing coal-fired, dry bottom, wall-fired and tangential, balanced draft boilers. There is little difference between the cost of SNCR retrofit of an existing boiler and SNCR installation on a new boiler [10]. Therefore, the cost estimating procedure is suitable for retrofit or new boiler applications of SNCR on all types of coal-fired electric utilities and large industrial boilers. 

### 1.2 Process Description SNCR is based on the chemical reduction of the NO xmolecule into molecular nitrogen (N 2 ) and water vapor (H 2 O). A nitrogen based reducing agent (reagent), such as ammonia or urea, is injected into the post combustion flue gas. The reagent can react with a number of flue gas components. However, the NO x reduction reaction is favored over other chemical reaction processes for a specific temperature range and in the presence of oxygen, therefore, it is considered a selective chemical process. The SNCR process occurs within the combustion unit which acts as the reaction chamber. Figure 1.2 shows a schematic of a boiler interior with SNCR. Reagent is injected into the flue gas through nozzles mounted on the wall of the combustion unit. The injection nozzles are generally located in the post-combustion area, the upper area of the furnace and convective passes. The injection causes mixing of the reagent and flue gas. The heat of the boiler provides the energy for the reduction reaction. The NO xmolecules are reduced and the reacted flue gas then passes out of the boiler. More detail on the SNCR process and equipment is provided in he following sections.

PLATEN SECONDARY SUPERHEATER SECONDARYSUPERHEATER PENDANT REHEATER

PRIMARY SUPERHEATER CONVECTION PASS

ECONOMIZER HORIZ. REHEATER

FURNACE UREA INJECTORS

BURNERS UREA INJECTORS

Figure 1.2: Boiler Gas Path Configuration1-5 1.2.1 Reduction ChemistrySNCR is a relatively simple chemical process. The process begins with an ammoniabased reagent, ammonia (NH 3 ) or urea (CO(NH 2 ) 2 ), being vaporized either before injection by a vaporizer or after injection by the heat of the boiler. Within the appropriate temperature range, the gas-phase urea or ammonia then decomposes into free radicals including NH 3 and NH 2 . After a series of reactions, the ammonia radicals come into contact with the NO xand reduce it to N 2 and H 2 O. The global representation of these reactions is given below for both urea and ammonia. Note that the NO xis represented as NO since it is the predominant form of NO x within the boiler. The ammonia reaction equation is given by:


### 2 2 2 3 3 1 2 2 2 2 

### NO + NH +→+ O N HO (1.1) The reaction for urea is given by:
2 2 2 2 2 1 2 2 2 2 2 NO + CO(NH ) O N CO H O +→ ++ (1.2) The primary byproduct formed during either ammonia or urea SNCR is nitrous oxide (N
2 O). N 2 O is an ozone depletor and a greenhouse gas but is currently not regulated. Urea based reduction generates significantly more N 2 O than ammonia-based systems. Up to 30% of the NO x can be transformed into N 2 O. Proprietary additives are available for the urea-based SNCR process to reduce the formation of N 2 O. [10]

1.2.2 Reagents Both ammonia and urea have been successfully employed as reagents. The cost of the reagent is a large portion of the annual costs of operating an SNCR system. Ammonia is generally less expensive than urea. However, the choice of reagent is based not only on cost but on physicalproperties and operational considerations. The properties of urea and ammonia in aqueous solutions are shown in Table 1.1. Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at normal atmospheric temperature. It must be transported and stored under pressure which presents safety issues. Aqueous ammonia is generally transported and stored at a concentration of29.4% ammonia in water. At concentrations above 28%, storage of ammonia may require a permit, therefore some recent applications of SNCR are using a 19% solution [1]. Decreasing the concentration, however, increases the required storage volume. Ammonia is generally injected as a vapor. Providing sufficient ammonia vapor to the injectors requires a vaporizer, even though the 29.4% solution has substantial vapor pressure at normal air temperatures. The injection system equipment for vapor systems is more complicated and expensive than equipment for aqueous systems (see Section 1.2.4 SNCR System)1-6 Table 1.1: Urea and Ammonia Reagent Properties, [6] Property Urea Solution Aqueous Ammonia Chemical formula CO(NH 2 ) 2 NH 3 Molecular Weight of reagent 60.06 17.03 Liquid or gas at normal air Liquid Liquid temperature Concentration of reagent 50% by weight 29.4% by weight normally supplied Ratio of NH 3 to solution 28.3% by weight of NH 3 29.4% by weight of NH 3 Density of solution @ 60 o F 71 lb/ft 3 56 lb/ft 3 (58 lb/ft 3 for 19%) Vapor pressure @ 80 o F < 1 psia 13.9 psia [8] Crystallization temperature 64 o F - 110 o F Flamability limits in air Non-flammable Lower explosion limit = 16% NH 3 by volume; Upper explosion limit = 25% NH 3 by volume. Threshold limit value (health Not Specified 25 ppm effects) Odor Slight (ammonia-like) Pungent odor @ 5 ppm or more Acceptable materials for Plastic, steel, or stainless Steel tank, capable of handling storage steel (no copper or copper- at least 25 psig pressure (no based alloys or zinc/aluminum copper or copper-based alloys, fittings) etc.)

Urea is generally utilized in a 50% aqueous solution [1]. At this concentration, the urea solution must be heated and circulated in cold climates due to its low freezing point, 17.8EC (64EF). Higher-concentrations of urea solutions are available which decrease the storage volume but require extensive heating to prevent freezing. Urea is injected into the boiler as an aqueous solution and vaporized by the heat of the boiler. Urea can also be transported in pellet form which minimizes transportation requirements. However, to produce aqueous urea for use in the SNCR system, the urea must then be mixed with water at the facility. This mixing process is generally cost prohibitive except for remote sites, large facilities, or facilities where chemical mixing processes are already being performed [13]. Urea based systems have several advantages over ammonia based systems. Urea is a nontoxic, less volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets can penetrate farther into the flue gas when injected into the boiler. This enhances mixing with the flue gas which is difficult on large boilers [1]. Because of these advantages, urea is more commonly used than ammonia in large boiler applications of SNCR systems.1-7 1.2.3 SNCR Performance Parameters The rate of the reduction reaction determines the amount of NO x removed from the flue gas. The important design and operational factors that affect the reduction of NO x by an SNCR system include: • Reaction temperature range; • Residence time available in the optimum temperature range; • Degree of mixing between the injected reagent and the combustion gases • Uncontrolled NO xconcentration level; • Molar ratio of injected reagent to uncontrolled NO x ; and • Ammonia slip. T

emperature The NO xreduction reaction occurs within a specific temperature range where adequate heat is available to drive the reaction. At lower temperatures the reaction kinetics are slow and ammonia passes through the boiler (ammonia slip). At higher temperatures the reagent oxidizes and additional NO xis generated. The temperature window is dependant on the reagent utilized. Figure 1.3 shows the NO x reduction efficiency for urea and ammonia SNCR at various boiler temperatures. For ammonia, the optimum temperature is from 870EC to 1100EC (1,600EF to

Figure 1.3: Effect of Temperature on NO x Reductio n 0 10 20 30 40 50 60 70 80 90 100

1200 1400 1600 1800 2000 Temperature ( o F)NOxReduction Efficiency (%)

Urea Ammonia1-8 2,000EF) [1]. Its optimum temperature range can be reduced by injecting hydrogen gas with the ammonia. For urea, the optimum temperature range is between 900EC to 1150EC (1,650EF to 2,100EF) [1]. Additives to the urea reagent may be used to widen the effective temperature window. These additives are generally proprietary (see Section 1.2.4 Other Considerations). The reagent is injected into the boiler in regions where the combustion gas temperature is within the specified range. Since reaction temperatures are high, the injection takes place in the boiler itself. In general, the reagent is injected within the boiler superheater and reheater radiant and convective regions, where the appropriate temperature range is typically available [1]. Proper placement of the injection ports results in higher NO xreduction efficiency.Flue gas temperature within the boiler depends on the boiler design and operating conditions. These are generally set to meet steam generation requirements and are not always ideal for the SNCR process. Flue gas temperatures in the upper furnace through the convective pass may vary by ±150EC (300EF) from one boiler to the next [1]. In addition, fluctuations in the boiler load profile affect the temperature within the boiler. At lower load profiles, the temperature within the boiler is lower. Variations in the flue gas temperature make the design and operation of an SNCR system more difficult.

Residence T ime Residence time is the amount of time the reactants are present within the chemical reactor, the upper area of the furnace and convective passes. Before the reactants exit the boiler, all the steps in the SNCR process must be complete, including: • Mixing of the injected urea with the flue gas; • Evaporation of water; • Decomposition of urea to NH 3 ; • Decomposition of NH 3 to NH 2 and free radicals; and • NO xreduction reaction chemistry. Increasing the residence time available for mass transfer and chemical reactions generally increases the NO xremoval. In addition, as the temperature window for the reaction is lowered, greater residence time is required to achieve the same NO xreduction level. Residence time can vary from 0.001 to 10 seconds [1]. However, the gain in performance for residence times greater than 0.5 seconds is generally minimal [10]. Figure 1.4 shows the effect of residence time and temperature on NO xreduction.1-9 The amount of residence time depends on the dimensions of the boiler gas path and thevolumetric flow rate of the flue gas along the boiler gas path. These design parameters are optimized for boiler operations, not the SNCR process. The boiler residence time is set to meet steam generation requirements while maintaining a flue gas velocity to prevent erosion of the watertubes in the boiler. Because of these boiler design requirements, the residence time in the boiler is not always ideal for the SNCR process. Degree of Mixing For the reduction reaction to take place, the reagent must be dispersed and mixed throughoutthe flue gas. The dispersion must occur rapidly due to the volatility of ammonia. The mixing requirements are generally boiler specific and dependant on the air flow profiles through the boiler [1]. Areas of stagnation or high flow must be accommodated. Dispersion and mixing of the reagent and flue gas is more difficult on large boilers due to their size and flow patterns. Mixing is performed by the injection system. The injectors atomize the reagent and control the spray angle, velocity, and direction of the injected reagent. These systems are boiler and reagent specific. Numeric modeling of the flue gas and reagent flow optimizes the design of the injection system. (See Section 1.2.5 Other Considerations). Figure 1.4: Effect of Residence Time on NO xReduction 0 10 20 30 40 50 60 70 80 90 100

1200 1400 1600 1800 2000 2200 Temperature ( o F)NOxReduction E fficiency (%)

500 ms 100 ms1-10 To assist in dispersion of aqueous urea, the reagent is atomized into droplets by specially designed nozzles which optimize the droplet size and distribution. Evaporation time and trajectory are a function of the diameter of the droplet. Larger droplets have more momentum and penetrate farther into the flue gas stream. However, they require a longer time to volatilize, increasing the required residence time. [1] Inadequate mixing results in insufficient NO x reduction. Mixing patterns can be improved by several methods: • Increase the energy imparted to the droplets; • Increase the number of injectors; • Increase the number of injection zones; and• Modify the atomizer nozzle design to improve the solution droplet size, distribution, spray angle, and direction. Uncontrolled NO x The concentration of the reactants also affects the reaction rate of the NO x reduction process. The reaction kinetics decrease as the concentration of reactants decreases. This is due to thermodynamic considerations which limit the reduction process at low NO xconcentrations [1]. For lower NO xinlet concentrations, the optimum temperature for the reaction is lower, hence, the percent NO xreduction is lower. Figure 1.5 shows the NO x reduction efficiency as a function of temperature for several uncontrolled NO xlevels.

Figure 1.5 : Effect of Uncontrolled NO X Level on NO X Reduction Efficiency 0 10 20 30 40 50 60 70

1500 1600 1700 1800 1900 2000 2100 Temperature ( o F)NOxReduction Efficiency (%) 30 ppm 70 ppm 200 ppm1-11 Normalized Stoichiometric Ratio The Normalized Stoichiometric Ratio (NSR) defines the amount of reagent needed to achieve the targeted NO x reduction. Based on reaction equations (1.1) and (1.2), theoretically two moles of NO xcan be removed with one mole of urea or two moles of ammonia. In practice, more than the theoretical amount of reagent needs to be injected into the boiler flue gas to obtain a specific level of NO xreduction. This is due to the complexity of the actual chemical reactions involving NO x and injected reagent and mixing limitations between reagent and flue gas (rate kinetics). Typical NSR values are between 0.5 to 3 moles of ammonia per mole of NO x [10]. Because capital and operating costs depend on the quantity of reagent consumed, determining the appropriate NSR is critical. The factors that influence the value of NSR include: • Percent NO xreduction; • Uncontrolled NO xconcentration in the flue gases; • Temperature and residence time available for the NO xreduction reactions; • Extent of mixing achievable in the boiler; • Allowable ammonia slip; and • Rates of competing chemical reactions. Section 4-1.1.3 Design Parameters provides further discussion of these influences and a method for estimating the NSR. Figure 1.6 shows the NO x reduction as a function of the NSR. Note that as the NSR increases, the NO X reduction increases. However, as the NSR increases, the increment of NO x reduction decreases exponentially. Rate kinetics limit the possible NO xreduction to much less than the theoretical value. Increasing the quantity of reagent does not significantly increase the NO X reduction for NSR values over 2.0.

0 5 10 15 20 25 30 35 40 45 50

0 0.5 1 1.5 2 2.5 3 NSRNOxReduction Efficiency (%)

Figure 1.6: Effect of NSR on NO xReduction1-12 Ammonia SlipTypical NSR values require significantly more reagent to be injected in practice than required by the theoretical stoichiometric ratio. In addition, the amount of NO xremoved is generally much less than the amount of uncontrolled NO x . This leaves a large portion of the injected reagent unreacted. Most of the excess reagent used in the process is destroyed through other chemical reactions. However, a small portion remains in the flue gas as ammonia slip. Figure 1.7 shows an example of the NO x reduction efficiency which can be achieved for an uncontrolled NO xlevel of 120 ppm and various ammonia slip levels. Ammonia in the flue gas stream has several negative impacts. As shown in Table 1.1, ammonia has a detectable odor at levels of 5 ppm or greater and poses a health concern at levels of 25 ppm or greater. It can cause a stack plume visibility problem by the formation of ammoniumchlorides which occur when burning fuels containing chlorine compounds. Furthermore, ammonium bisulfate and ammonium sulfate form when burning sulfur-cotaining fuels. Ammonia-sulfur salts can plug, foul, and corrode downstream equipment such as air heater, ducts, and fans. Lastly, the ability to sell the fly ash as a secondary product is affected by its ammonia concentration. Ammonia slip impacts are discussed further in Section 4-1.1.2.4 Other Considerations.

Limits on acceptable ammonia slip, imposed by either regulatory limits or by design requirements, place constraints on SNCR performance. Injection of urea at higher NSR values can improve NO xreduction, but may also increase ammonia slip. In addition, variation in the temperature profile of the boiler during operations can increase ammonia slip. In general, current SNCR Figure 1.7: NO x Reduction for Various Ammonia Slip Leve ls

0 10 20 30 40 50 60 70 80

0 5 10 15 20 Ammonia Slip (ppm)NoxReduction Efficiency (%)1-13 systems control ammonia slip between 5 to 10 parts per million (ppm) [12]. Instrumentation for monitoring ammonia slip is currently being developed but not commercially available [11]. One method to quantify ammonia slip is to determine the ammonia concentration in collected fly ash . 1.2.4 SNCR System There are two basic designs for the application of SNCR. The first is an ammonia based system known as Thermal DeNO x® that was developed and patented by Exxon Research and Engineering Company in 1975. The second system was developed and patented by The Electric Power Research Institute (EPRI) in 1980. It is a urea-based process known by the trade name NO xOUT®. The technology was licensed to Fuel Tech, which holds several additional patentsthat claim improvements and enhancements to the basic process. Fuel Tech has several sublicensees authorized to supply and install SNCR technology in several industrial sectors. An SNCR system has four basic steps to accomplish: • Receiving and storage of the reagent; • Metering, dilution, and mixing of the reagent; • Injection of diluted reagent at appropriate locations in the boiler; and • Mixing of the reagent with flue gas. These steps are common to both urea and amonia SNCR. However, the design and equipment specifications for the two systems are different, since ammonia is injected as a vapor while urea is injected as an aqueous solution. Urea is typically used in large boiler applications of SNCR because it is safer to store and has better dispersion properties. A discussion of the SNCR equipment is given below. Figure 1.8 presents a simplified system flow schematic and Table 1.2 lists the equipment requirements for urea-based SNCR. Urea-based systems typically employ a modular design to allow for boiler-specific design requirements while minimizing capital costs. Modular shops assembly of pumps, valves, internal piping, instruments, and controls reduces field insallation time and relatied costs while providing flexibility for future expansion [1]. The components are assembled into functional units and mounted on stainless steel skid modules. These modules can then be transported o the site and installed directly. The skid modules shown in Figure 1.8 will be discusses futher in the next sections.1-14 DILUTION WATER PRESSURE CONTROL MODULE

SUPPLY/CIRCULATION MODULE BOILER

50% UREA SOLUTION
CIRCULATION PUMPS ELECTRIC HEATER UREA STORAGE TANK STATIC MIXER

INJECTION ZONE METERING MODULES DISTRIBUTION MODULES

METERING

PUMPS INJECTORS10% UREASOLUTION M COMPRESSOR

WATER AIR COOLING AIR

WATER PUMP ATOMIZING AIR

WATER PUMP

UREA UNLOADING PUMP
Figure 1.8: Urea SNCR Process Flow Diagram1-15 Item Description/Size Urea unloading skid Centrifugal pumps with hoses to connect to rail tank car or truck Urea storage tanks Vertical, insulated fiberglass reinforced plastic (1 or more tanks) (vinyl ester resin) tank, atmospheric pressure design, and equipped with a vent, caged ladder, manway, and heating pads Circulation module Skid-mounted circulation module consisting of: - Circulation pumps, - Electric heaters, - Insulated/heat traced piping - Isolation valves for pumps and heaters, - Instrumentation for flow, pressure, temperature, and a control panel Injection zone metering (IAM) Skid mounted metering modules consisting of: modules (1 to 5 modules) - Metering pumps, hydraulic diaphragm type equipped with a variable speed motor drive, - Water booster pumps, turbine type, - Insulated/heat traced piping - Isolation and control valves for pumps, - Instrumentation for flow, pressure, temperature, and a control panel Air compressor Rotary type Distribution modules Urea solution distribution module consisting of: (1 to 5 modules) - Valved connections for urea and atomizing air, - Isolation valve and a pressure control valve for the air/urea supply to each injector, - Pressure indicator for air/urea supply to each injector, - Flow indicator for urea supply to each injector IInjectors (4 to 12 per distribution Wall-type: Dual-fluid type wall injector, with modules) furnace wall panels, and hoses for air and urea supplies Lance-type: Dual-fluid type lance injector, with furnace wall panels, and hoses for air and urea supplies Piping Between urea unloading skid and urea tank; urea tank and circulation module; and circulation module and IZM modules(s). Insulate/heat traced piping, stainless steel Piping Between IZM module(s) and distribution modules. Insulated/heat traced tubing, stainless steel Tubing Between distribution modules and injectors. Insulated/heat traced tubing, stainless steel Dilution water piping Insulated/heat traced piping, carbon steel, with isolation and pressure reducing valves Miscellaneous piping Piping/tubing and valves for flushing water, atomizing air, and control air Piping supports Structural support steel, including a pipe bridge, for supporting all piping Economizer outlet emission monitors Monitor NO x and O 2 in the flue gas and provide a feedback signal for urea injection control Instrumentation and controls Instrumentation and stand-alone, microprocessor-based controls for the SNCR system with feedback from the plant controls for the unit load, NO x emissions, etc. Enclosures Pre-engineered, heated and ventilated enclosure for the circulation and metering skids Foundations Foundations and containment walls for the tank and equipment skids, enclosure, and piping support steel, as required Platforms/stairways Platform/stairway modifications and additions for access to injectors Asbestos removal Asbestos removal and reinsulation, for a retrofit installation Table 1.2: Urea-Based SNCR System Equipment1-16 from 10,000 to 20,000 gallons per tank to maintain sufficient volume for 1 to 3 weeks of SNCR operations. A closed top, flat bottom, vertical tank is used for urea storage. These tanks are usually constructed of fiber- reinforced polyester and have a corrosion barrier coating on the inside made of premium-grade vinyl ester resin. The tanks are equipped with level and temperature indicators, a manway, vent, and access ladder, and other appurtenances. The applicability of heat tracing, insulation, and seismic design criteria are determined based on site-specific conditions. The tank should be mounted on a concrete pad and surrounded by a spill containment structure such as a dike. Circulation Module The circulation module maintains continuous circulation of the stored urea and supplies high-flow, high-pressure urea to the injection system. The circulation module pumps the urea from the storage tank to the components on the module. The urea solution is filtered to avoid clogging of the injectors and heated to prevent the solution from freezing. The urea is then returned to the tank or sent to the injection system. The module also provides a local/remote control and monitoring station for the storage tank and circulation system. This module contains multistage stainless steel centrifugal pumps, in-line duplex strainers, electric heaters, and instrumentation and controls for reagent pressure, flow, temperature, and quantity. [1] Dilution, metering, and mixing of the reagent Dilution Water Pressure Control Module The dilution water pressure (DWP) control module provides filtered plant water at the proper pressure for reagent dilution. The plant water is filtered to less than 50 milligrams per liter (mg/l) of suspended solids and low dissolved solids. The DWP typically consists of two full-flow multistage stainless steel centrifugal pumps, an in-line duplex strainer, pressure control valves, andthe required pressure/flow instrumentation. Through the use of backpressure controllers and multistage pumps, this system maintains a constant supply of dilution water, at the design pressure, in response to the changing SNCR process demand signals. [1] Injection Zone Metering Module The injection zone metering (IZM) module meters and controls the reagent concentration and flow to each zone of injection in the boiler. The aqueous urea generally requires dilution before injection to achieve the correct NSR between the reagent and flue gas NO x . The reagent is diluted using filtered plant water from the DWP module. Each IZM module includes a chemical metering pump, a water pump, an in-line static mixer, a local control panel, zone isolation valves, and magnetic flow1-17 meters and control valves for chemicals and water. The module design generally incorporates independent chemical flow and zone pressure valves which respond to signals from the control systems, the master control module and local programmable logic controller (PLC). Through the control system, the module adjusts solution flow rates and activates or deactivates injection zones in response to changes in outlet NO xconcentration, boiler load, or fuel quality. Urea-based SNCR systems typically employ one to five IZM modules, depending on the boiler size, configuration, the uncontrolled NO xconcentration, and desired NO x removal efficiency. Several IZM modules can be combined onto one skid-mounted system. [1] Injection of diluted reagent at appropriate locations in the boiler Reagent Distribution Module The mixed and diluted urea solution is transported from the IZM to the distribution modules, which are typically located adjacent the boiler. The distribution modules control the flow of the solution to each injector. Each of the distribution modules consists of flow meters, balancing valves, and regulators connected to an automatic control system. The control system accurately controls and displays the reagent and atomizing air or steam flow to each injector. The modules also include Manual ball valves, gauges, and stainless steel tubing to adequately control the urea injection process. There is one distribution module for each IZM module providing reagent to multiple injectors. [1] Injection Locations The urea solution flows from a given distribution module to a set of injectors. For large boiler applications, multiple injectors are located within several different zones of the boiler and can be operated independently or in groups (sub-zones) via the IZM. Controlling the amount andlocation of reagent injection gives the system flexibility to respond to variation in the boiler operating conditions and to maintain ammonia slip levels.The number and location of the zones is determined by the temperature and flow patterns of the boiler. The locations are optimized using numeric modeling of flow and chemical reactions (see Section 1.2.5 Other Considerations). Typical designs employ between one and five injection zones with 4 to 12 injectors per zone [1]. Injectors are located in open areas of the boilersuch as the region between the superheater and reheater sections. Figure 1.2 illustrates this configuration. For SNCR retrofit of existing boilers, optimal locations for injectors may be occupied by boiler equipment such as the watertubes. Removal or relocation of this equipment increases the installation costs. Installation in sub-optimal boiler areas decreases the NO xreduction efficiency which can be achieved by the system while maintaining the required ammonia slip level.1-18 Mixing of the reagent with flue gas and reduction of NO x Injectors The injectors assist in dispersion and mixing of the reagent with the flue gas. There are two types of injectors, wall and lance. Wall injectors are attached to the inner wall of the boiler at specified locations. There is generally one nozzle for each injector location. Wall injectors are used in smaller boilers and urea based systems, where short-range injection is sufficient to mix the reagent with the flue gas. They have a longer operating life than lance injectors since they are not directly exposed to hot flue gas. Lance injectors consist of a small pipe which protrudes from the boiler wall into the flue gas pathway. Nozzles are located along the pipe directly in the flue gas pathway. Lance injectors are used for ammonia gas systems and in large boilers where mixing of the flue gas and reagent is more difficult. In some designs, the lance extends across the entire width of the boiler pass. Lance injectors can be single or multi-nozzle designs. Multi-nozzle lances are more complicated design, therefore, they are more expensive than single-nozzle lance or wall injectors [1]. SNCR systems may employ one or both types of injectors.Injectors are subject to high-temperatures and to flue gas impingement which cause erosion, corrosion, and structural integrity degradation. Therefore, injectors are generally constructed of stainless steel and designed to be replaceable. In addition, injectors are often cooled with air, steam, or water. Lance injectors and some wall injectors are also designed to be retractable when not in use. This minimizes their exposure to the hot flue gas when the SNCR system is not beingoperated because of seasonal operations, boiler startup or shutdown, or other operational reasons. The reagent is injected under pressure and atomized by specially designed nozzle tips to create droplets of the optimum size and distribution. The spray angle and velocity of the injection control the trajectory of the reagent. Urea systems often inject a carrier fluid, typically air or steam, along with the urea through a dual-fluid atomizer nozzle. The reagent can be injected with a lowenergy or high energy system. A low-energy system uses little or no pressurized air while a highenergy system uses large amounts of compressed air or steam to inject and vigorously mix the solution with the flue gas. Lance injectors in large boilers typically use high-energy systems. High energy systems are more expensive to build and operate since they require a larger compressor, a more robust injection system, and consume more electric power.1-19The reagent injection systems used for ammonia-based systems are generally more complicated and expensive than those used in urea-based systems [1]. These systems inject gas phaseammonia rather than an aqueous solution. For this reason, ammonia-based systems often use highenergy lance systems with multiple injectors. The lances are placed in a grid formation across the width and height of the boiler passes. 1.2.5 Other Considerations Retrofit The difficulty of SNCR retrofit on exiting large coal-fired boilers is considered to be minimal. The primary concern is adequate wall space within the boiler for installation of injectors. The injectors are installed in the upper regions of the boiler, the boiler radiant cavity and convective cavity. Movement and/or removal of existing watertubes and asbestos from the boiler housing may be required. In addition, adequate space adjacent to the boiler must be available for the distribution system equipment and for performing maintenance. This may require modification or relocation of other boiler equipment such as ductwork. Retrofit installation of the SNCR system generally calls for additional expenditures in the range of 10% to 30% of the SNCR system cost. [10] Ammonium Sulfate Deposition Sulfur trioxide (SO 3 ) forms during the combustion of fuels which contain sulfur. It reacts with ammonia in the flue gas downstream of the boiler (ammonia slip) to form ammonium bisulfate and ammonium sulfate. The amount formed depends on the sulfur content of the fuel and the amount of ammonia slip. Ammonia-sulfur salts can plug, foul, and corrode downstream equipment such as the air heater, ducts, and fans. Depending on the rate of ammonia-sulfur salt deposition ondownstream equipment more frequent acid washing of this equipment may be warranted. Increased acid washing generates additional wastewater which must be disposed or treated by theplant. Ammonia slip limits are generally imposed as part of the design requirements to avoid impacts on downstream equipment.Ammonia sulfates also deposit on the fly ash that is collected by particulate removal equipment. The ammonia sulfates are stable until introduced into an aqueous environment with a elevated pH levels. Under these conditions, ammonia gas can release into the atmosphere. This results in an odor problem or, in extreme instances, a health and safety concern. Plants that burn alkali coal or mix the fly ash with alkali materials can have fly ash with high pH. In general, fly ash is either disposed of as waste or sold as a byproduct for use in processes such as concrete admixture. Ammonia content in the fly ash greater than 5 ppm can result in off-gassing which would impact the salabilty of the ash as a byproduct and the storage and disposal of the ash by landfill. [10]1-20 Computational Fluid Dynamics and Chemical Kinetic Modeling Each boiler unit has a unique temperature and flow gradient with areas of high flow and stagnation. In addition, temperature and flow profiles vary according to the load capacity under which the boiler is operating. A mathematical model is developed to describe this stratification and variation of important species such as NO xand SO 3 in the flow stream. To develop the model, theflue gas temperature and velocity within the boiler are measured at many locations. These measurements are used in a computational fluid dynamics (CFD) model for the convective passes of the boiler. The model predicts the temperature and gas flow within the boiler for various operating conditions and injection scenarios. The residence times and temperatures predicted by the CFD model are input into a chemical kinetic model (CKM). CKM defines the chemical reactions associated with the SNCR process in the boiler. Analysis of the fuel and flue gas constituents are required to develop thismodel. The model predicts the reactions and rates of reactions within the boiler in order to estimates the NO xreduction along the flue gas pathway. Modeling optimizes the SNCR design for the boiler of concern to obtain the maximum NO x reduction within acceptable ammonia slip limits. It determines design parameters such as the NSR, injector locations, and optimum droplet size and distribution. In general, SNCR vendors obtain the required measurements and develop the models. The cost of model development is generally included in the purchased equipment cost for SNCR. [1] Additives/Enhancers Additives to the reagents are called enhancers and can be used to lower the temperature range at which the NO xreduction reaction occurs. During low-load operation, the location of the optimum temperature region shifts upstream within the boiler. This shift requires the injection point of the reagent to be moved upstream. The use of an enhancer reduces the need for additional injection locations which are required to compensate for variable load operation. Fewer injection locations decrease capital costs and the need for modifications to the boiler. In addition, the larger temperature range available with enhancers increases the available residence time for the reduction reaction, further reducing NO x emissions. Additional reagent is injected with the enhancer to maintain the same NO xreduction efficiency since some of the reagent reacts with the enhancer as opposed to the NO x . This can increase the reagent usage by up to 10%. In addition, enhancers can result in increased levels of CO and N 2 O in the stack effluent. Enhancers require additional storage, distribution, and control system equipment. The increase in annual cost from the usage of additional reagent and enhancer can be significant. Enhancer formulations are generally proprietary. [10]1-21 Energy Consumption An SNCR process reduces the thermal efficiency of a boiler. The reduction reaction uses thermal energy from the boiler, which decreases the energy available for power or heat generation.As a result, additional energy is required for the boiler to maintain the same steam output. Pretreatment and injection equipment, pumps, compressors, and control systems, also require electricity. This increased usage of fuel and electricity increases the annual costs required to operate the boiler [1]. Section 1.4.2 Total Annual Costs presents a method for estimating the additional fuel and electricity usage. 

### 1.3 Design Parameters SNCR system design is a proprietary technology. Extensive details of the theory and correlations that can be used to estimate design parameters such as the required NSR are not published in the technical literature [5]. Furthermore, the design is highly site-specific. In light of these complexities, SNCR system design is generally undertaken by providing all of the plant- and boiler-specific data to the SNCR system supplier, who specifies the required NSR and other design parameters based on prior experience and computational fluid dynamics and chemical kinetic modeling. [1]The procedure given below in Section 1.3.1 Design Parameters for Study-Level Estimates is a step-by-step approach to estimate design parameters based on a procedure developed in the draft EPA report Selective Noncatalytic Reduction for NO xControl on Coal-fired Boilers [1]. This procedure assumes SNCR system size and cost are based on three main parameters: the boiler size or heat input, the required level of NO xreduction, and the reagent consumption. Data requirements for obtaining vendor cost estimates based on design specifications or performance specifications are outlined in Section 1.3.2.
1.3.1 Design Parameters for Study Level Estimates Boiler Heat Input The primary cost estimation parameter in the methodology presented in Reference [1] is the maximum potential heat released by the boiler or heat input rate, Q B , expressed as million British thermal units per hour (MMBtu/hr). It is obtained from the high heating value, HHV , of the1-22 fuel in Btu per pound (Btu/lb) multiplied by the maximum fuel consumption rate in pounds per hour (lb/hr), Q HHV m B fue l =  (1.3) where Table 1.3 gives the HHV for various coals and a conversion of 10 -6 MMBtu/Btu is reequired.

Table 1.3: High Heating Values for Various Coals Type of Coal Energy Content (Btu/ lb) Lignite 5000-7500 Subbituminous 8000-10,000 Bituminous 11,000 - 15,000 Anthracite 14,000

If the boiler produces electricity, then its heat input can be estimated using the boiler net plant heat rate, NPHR in Btu per kilowatt-hour (Btu/kWh): Q B NPH R

B MW = (1.4)
where B MW is the boiler megawatt (MW) rating at full load capacity. Note that if NPHR is not known (e.g., a cogeneration unit), a value of 9,500 Btu/kWh can be used as a reasonable estimate conversions of 1,000 kW/MW and 10 -6 MMBtu/Btu are required. Using this value, the heat input rate, Q B , is: 

# ( ) ( ) ( ) Q .

B M M Btu h r 

### = 9 5 M M Btu MWh M W 

### B MW (1.5) System Capacity Factor The total system capacity factor, CF total , is a measure of the average annual use of the boiler in conjunction with the SNCR system. CF total is given by:

CF CF CF total plant SNCR = × (1.6)1-23 For industrial boilers, the capacity factor of the boiler, CF plant , is the ratio of actual quantity of fuel burned annually to the potential maximum quantity of fuel burned annually in pounds (lbs). CF plant is given by: C F actual m maximum m plant fuel fuel = (1.7) SNCR can be operated year-round or only during the specified ozone season. The capacity facor for the SNCR system, CF SNCR , is the ratio of the actual number of SNCR operating days, t SNCR , to the total number of days per year, 365 days:

C F t SNCR SNCR = 365 days (1.8)
Uncontrolled NO xand Stack NO x Uncontrolled NO x , represented as NO xin , is the NO xconcentration in the flue gas after any reductions provided by combustion controls, but prior to the SNCR system. The uncontrolled NO x concentration, obtained from analyzing the boiler flue gas stream, is generally given in pounds per MMBtu (lb/MMBtu) of NO 2 [2]. The stack NO x , represented as NO xout is the required NO x emission limit at the stack outlet. It is generally set by the plant or regulatory limits and also given in pounds per MMBtu (lb/ MMBtu) of NO 2 .
NO x Removal Efficiency The NO x removal efficiency, represented as  NOx , is determined from the uncontrolled NO xlevel of the boiler at maximum heat input rate, CF plant = 1.0, and the required stack emission limit using the following equation: η N O x x

x x in out

in N O N O N O = − (1.9)

Normalized Stoichiometric Ratio The Normalized Stoichiometric Ratio, NSR , indicates the actual amount of reagent needed to achieve the targeted NO x reduction. The actual quantity of reagent is greater than the theoretical1-24 quantity due to reaction kinetics (See Section 1.2.3 Performance Parameters). The NSR is defined as:

NSR = moles of e quivalent N H injected moles of u ncontrolle d NO 3

x (1.10) For estimating purposes, the moles of NO x are equivalent to the moles of NO 2 . Note that the moles of equivalent NH 3 in Equation (1.10) are the moles of NH 2 that will be released from the reagent. The actual stoichiometric ratio, ASR , is defined as:

ASR = moles of r eagent inj ected moles of u ncontrolle d NO x (1.11)
ASR can also be calculated from the NSR using the following equation:

ASR NSR S R T = (1.12)

where SR T is the ratio of equivalent moles of NH 3 per mole of reagent injected. From the chemical formula for ammonia (NH 3 ) and urea (CO(NH 2 ) 2 ) given in the reaction equations (1.1) and (1.2), SR T is 1 for ammonia and 2 for urea.
Reagent utilization is the ratio of moles of reagent reacted to the moles injected. This indicates how much reagent is being reacted versus how much reagent is passing through as ammonia slip. Utilization of reagent can be calculated from the NSR and the NO xreduction efficiency as follows:

Utilizatio n NSR N O x = η (1.13) The derivation for this equation is presented in Reference [1]. Methods for estimating NSR are considered proprietary. A simplified NSRestimation procedure was developed by The Cadmus Group, Bechtel Power, Inc. and SAIC in the EPA draft report, Selective Noncatalytic Reduction for NO xControl on Coal-fired Boilers [1]. This procedure was developed using linear regression and NSR data from References [2] and [3]. The values of NSR derived using this approach should not be used for equipment design or guarantee purposes.1-25 The NSR estimation equation is valid from 0 to 50 percent NO xreduction [1]. The equation used to estimate the NSR for urea reagent is where Noiu is given in lb/MMBtu. 

# [ ] NSR N O N O x NO x

x in

in = + 2 0 7

. η (1.14)
Figure 1.8 provides a graphical representation of this NSR estimation method. Generally, the value of the NSR ranges between 0.5 and 2.0 in industrial and utility boilers with utilization ranging between 25 and 50 percent.

0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0

0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 Uncontrolled NOx, lb/MMBtuPredicted NSR 50% 45% 40% 35% 30% 25% NOx Reduction

50% 45% 40% 35%

25% 30%

Figure 1.8: Approximate NSR Estimation for Urea1-26 In a design developed by a system supplier, the NSR would be adjusted to account for several parameters that are not included in the NSR estimation equation. The following parameters are used by the system supplier to more accurately predict the NSR for a given boiler: Reaction temperature range available within the boiler superheater (radiative and convective section) and primary reheater (convective section or cavity) region. If the required temperature window occurs in the radiant section of the boiler, theNSR could decrease. However, if the temperature window occurs in the convective section, the NSR may increase. Residence time available in the desirable temperature range. The required NSR decreases as the available residence time increases. Degree of mixing between the injected chemical and the flue gases. The NSR decreases as the degree of mixing increases. Ammonia slip vs required NO x reduction. Tighter constraints on ammonia slip would dictate lower NSRs, thereby limiting the achievable NO xreduction.
Estimating Reagent Consumption and T ank Size Once the NSR is estimated, the rate of reagent consumption or mass flow rate of the reagent,  m reagen t expressed as pounds per hour (lb/hr), can be calculated using:

 m NO Q NSR M M SR x B N O x reagent
NO T in

x reagent = η (1.15)

where the M reagent is the molecular weight of the reagent (60.06 grams per mole for urea, 17.07 grams per mole for ammonia) and M NOx is the molecular weight of NO 2 (46.01 grams per mole). The molecular weight of NO 2 is used because the NO xemissions, NO xin , are given in lb/MMBtu of NO 2 . As stated previously, SR T is the ratio of equivalent moles of NH 3 per mole of reagent (1 for ammonia and 2 for urea). For urea or ammonia, the mass flow rate of the aqueous reagent solution is given by:

  m m C

sol reagent sol = (1.16) where C sol

is the concentration of the aqueous reagent solution by weight.1-27 The solution volume flow rate q sol , generally expressed as gallons per hour (gph), is given by:

q m sol sol sol =  ρ (1.17)
where  sol is the density of the aqueous reagent solution inlb/ft 3 A conversion of 7.4805 gal/ft 3 is required to correct the units. given in Table 1.1, 71.0 lb/ft 3 for 50% urea and 56 lb/ft 3 for 29% ammonia. The total volume stored in the tank, or tanks, is based on the volume that the SNCR system requires for operating a specified number of days. The volume stored on site for the number of operating days, t storage , is :
V q t tank sol storag e = (1.18)
where V

t ank is in gallons, q sol is in gph and a conversion of 24 hr/day is required. Note that the tank volume is typically based on the maximum annual heat input rate, so the capacity factor is not included in Equation 1.18. A common on site storage requirement is for 14 days of SNCR operation.
1.3.2 Design Parameters for Detailed/Performance Specifications Cost Estimates Based on Detailed SpecificationsThis subsection is included to describe the information that must be assembled and furnished to a supplier to prepare design specifications, particularly that component information with the greatest influence on system cost. SNCR capital and operating costs can be estimated if the major cost items are identified and the system is defined in adequate detail, [1]. The following data are provided to the system supplier for SNCR system design: • The boiler capacity in terms of heat input rate (MMBtu/hr); • Boiler capacity profile – percent of time the boiler operates at a given heat input rate; • Type of combustion unit – dry/wet bottom boiler, wall-fired, tangentially-fired, cyclone fired, other (e.g., stoker-fired); year built, and manufacturer;1-28 • Boiler Dimensions – sectional side view; sectional front view; plan section through furnace (width × depth); furnace height (floor to furnace exit); firing zone height; sections through radiant and connective heat transfer cavities (zones); other unique features, e.g., division wall/panels, etc., in the furnace or backpass; • Locations of boiler furnace overfire air ports; • Locations and sizes of boiler observation ports, temperature probe ports, sootblower openings, and other locations for potential new ports; • Air preheater design and operational data, including sootblower data; • Fuel Data – proximate and ultimate analyses and high heating value (HHV) for primary and secondary fuels; • Fuel firing rates at full and partial loads (e.g., 100 percent, 70 percent, and 30 percent); • Test Data or Combustion Calculations - flue gas flow rate at design or actual conditions; excess air rate at full and partial loads; flue gas composition including O 2 , NO x , CO, SO 2 , and HCl;. • Flue gas temperature profile from furnace exit to economizer (i.e., where temperature drops to about 1,400  F) at various loads; • Flue gas residence time – available flue gas residence time in the upper furnace and convective pass within the temperature window for urea at various loads; • Existing or planned uncontrolled NO xand CO emission data in ppm or lb/MMBtu without the proposed SNCR system, including any change in emissions related to other installed or planned technologies (e.g., low-NO xburner, gas recirculation). This should be specified for boiler operations at full load and selected partial loads; • Minimum expected NO xreduction or permit requirement for stack NO x emission level (ppm or lb/MMBtu). This should be specified for boiler operations at full load and selected partial loads; and • Allowable byproduct emission rates for regulated emissions such as ammonia and nitrous oxide.1-29 The boiler supplier/manufacturer can furnish most of this information for existing or planned new units. For fuel data, the designer needs typical or design values, as well as the expected range. To define the temperature and flue gas velocity profiles in existing boilers, it is preferable to obtain actual measurements. To obtain a representative cost quotation from an SNCR system supplier, the request should contain sufficient details to minimize design assumptions by the supplier. The request for quotation (RFQ) should include the technical specifications, as well as commercial terms and conditions. Two important parts of the specification are work included in the scope of the supplier and work not included (i.e., work performed by the owner/operator). The more precise and detailed the specification of the work, the more accurate the overall system design and cost. For a turnkey scope (design, supply, and erect all equipment, and demonstrate commercial operation while meeting all performance criteria), the excluded work is minimal. Cost Estimates Based on Performance Specifications Preparation of detailed specifications involves significant time and effort (for both ownerand supplier) and is not critical for budgetary cost estimates. To simplify the process, a performance specification approach may be used in the RFQ. In this approach, the basic required plant and fuel data are provided along with the required SNCR system performance requirements, excluding equipment-related details (e.g., materials of construction, equipment redundancy, and level of instrumentation and controls) [1]. The performance specification should include a description of the system and components in enough detail to understand the type and quality of system proposed by the supplier. A cost breakdown of major components and subsystems also should be obtained from the supplier to enable independent assessment, deletion, or addition, and to compare other bids on an equitable basis. The SNCR performance specification typically should request the following items regarding NO X emission control performance, chemical consumption, and other consumption rates at full and partial loads: • Guaranteed and expected NO xemission rates in units of lb/MMBtu and lb/hr with averaging period as defined in the air quality permit of the facility; • Guaranteed and expected NH 3 slip, ppm (other conditions such as dry basis, percent O 2 , per the air permit); • Guaranteed and expected N 2 O emissions (guarantees needed if it is a permit condition);1-30 • Other emission limits as specified (or anticipated) in the permit. • Normalized stoichiometric ratio (NSR) proposed to achieve the required NO x reduction; • Guaranteed and expected reagent consumption rate; • Guaranteed and expected dilution air, steam, or water consumption rate; • Atomizing and cooling air (or steam) pressure and consumption rate; and • Guaranteed and expected electrical power consumption. 

### 1.4 Cost Analysis The cost estimating methodology presented here provides a tool to estimate study-level SNCR capital and annual costs. Actual selection of the most cost-effective option should be based on a detailed engineering study and cost quotations from system suppliers. The costs are presented in 1998 dollars. The cost estimating equations presented in this section are based on equations developed in the draft EPA report Selective Noncatalytic Reduction for NO x Control on Coal-fired Boilers[1]. These equations follow the costing methodology used by the Electric Power Research Institute (EPRI) [7]. In the EPRI method, both the purchased equipment cost (PEC) and direct installation cost are estimated together. This methodology is different from the EPA Air Pollution Control Cost Manual methodology, which estimates equipment costs and installation costs separately. Due to the limited availability of equipment cost data and installation cost data, the equations for SNCR capital costs were not reformulated. The capital and annual cost equations were developed for coal-fired wall and tangential utility and industrial boilers with heat input rates ranging from 250 MMBtu/hr to 6000 MMBtu/hr. The SNCR system design used for the cost estimate is an urea-based system . An ammoniabased system would have different storage, distribution and injection equipment costs. The cost equations are sufficient for NO xreduction efficiencies up to 50%. Allowed ammonia slip for the SNCR system ranges from 2 to10 ppm. [1]The cost equations are applicable to retrofit of SNCR on existing boilers. The cost estimating procedure, however, is suitable for retrofit or new boiler applications of SNCR on all types of coal-fired electric utilities and large industrial boilers. The increased cost due to retrofit is approximately 10% to 30% of the cost of SNCR applied to a new boiler [10].1-31 1.4.1 T otal Capital InvestmentTotal Capital Investment (TCI) includes direct and indirect costs associated with purchasing and installing SNCR equipment. Costs include the equipment cost (EC) for the SNCR system itself, the cost of auxiliary equipment, direct and indirect installation costs, additional costs due to installation such as asbestos removal, costs for buildings and site preparation, offsite facilities, land,and working capital. In general, SNCR does not require buildings, site preparation, offsite facilities, land, and working capital. A more detailed discussion of capital costs can be found in Section 1, Chapter 2 of this Manual. Direct Capital Costs The direct capital cost equation developed in Reference [1] is based on data for one representative boiler. This data is used to develop an equation for the boiler size range of interest by applying a scaling methodology from the EPRI T echnical Assistance Guide (TAG) [3]. The equation assumes that performance parameters vary in direct proportion to the boiler size. The costs are adjusted to 1998 dollars using the Chemical Engineering Cost Index.
The direct capital cost estimate includes PEC such as SNCR system equipment, instrumentation, sales tax and freight. This includes costs associated with field measurements, numerical modeling and system design. It also includes direct installation costs such as auxiliary equipment (e.g., ductwork, compressor), foundations and supports, handling and erection, electrical, piping,insulation and painting. In addition costs such as asbestos removal are included. Table 1.2 presents a list of the equipment and installation requirements for a urea-based SNCR system. The direct capital cost equation is a function of both boiler heat input rate QB in MMBtu/ hr, and the NO xremoval efficiency

- η

NOx . The boiler heat input rate indicates the size of the boiler and the flue gas flow rate, which directly influence the size of the SNCR system. The NO x removalefficiency effects both the required urea flow rate and associated urea-related equipment. Increases in the NO xremoval efficiency will require higher urea flow rates and increase the size and/ or number of the urea related equipment such as storage tanks. The equation for direct capital cost (DC) of urea-based SNCR in dollars is: 

# ( ) ( ) D C M M Btu M M Btu h r M M Btu h r M M Btu

h r ($) $

. . . = +       
      
      950 2375 0 6 6 0 8 5 0 577 Q Q B B N O x η (1.19)

where 950 $/(MMBtu/hr) is the direct capital cost for a 2375 MMBtu/hr boiler at 40% NO z removal efficiency [1].1-32 Indirect Capital Costs Indirect installation costs include costs such as; construction and contractor fees, startup and testing, inventory capital, and any process and project contingency costs. As explained in the Manual Section 1 Introduction, average values of indirect installation factors are applied to the direct capital cost estimate to obtain values for indirect installation costs. These costs are estimated as a percentage of the TCI. The equations for indirect installation costs are presented in Table 1.4. Table 1.4: Capital Cost Factors for an SNCR Application

Boiler Size (MMBtu/hr) Q B NO x Removal Efficiency n NOx Cost Y ear 1998 Total Direct Capital Costs ($)

Indirect Installation Costs General Facilities ($) 0.05 A Engineering and Home Office Fees ($) 0.10 x A Process Contingency ($) 0.05 x A Total Indirect Installation Costs ($) B = A x (0.05 + 0.1 + 0.05) Project Contingency ($) C= 0.15 x (A + B) Total Plant Cost ($) D= A + B + C Allowance for Funds During Construction ($) E = 0 (Assumed for SNCR) Royalty Allowance ($) F = 0 (Assumed for SNCR) Preproduction Cost ($) G = 0.02 x (D + E) Inventory Capital* ($) H = Vol reagent (gal) x Cost reagent ($/gal) Initial Catalyst and Chemicals ($) I = 0 (Assumed for SNCR) Total Capital Investment (TCI) ($) TCI = D + E + F + G + H + I * Cost for urea stored at site, i.e., the first fill of the reagent tanks Description Data or Formula

D C MMBtu h r Q M MBtu

h r B ($) $

. . .

=           +       950 2375 0 6 6 0 8 5 0 577 Q B N O x η1-33 1.4.2 Total Annual Costs Total annual costs (TAC) consist of direct costs, indirect costs, and recovery credits. Direct annual costs are those associated or proportional to the quantity of waste gas prodent of the operation of the control system and would be incurred even if it were shut down. No byproduct recovery credits are included because there are no salvageable byproducts generated from the SNCR [1]. Each of these costs is discussed in the sections below. A more detailed discussion of capital costs can be found in Section 1, Chapter 2 of this Manual. Design parameters are estimated using the maximum annual heat input rate of the boiler to ensure adequate sizing of the SNCR system. Annual costs are calculated using the average heat input rate of the boiler and SNCR system using CF total . This ensures that annual costs are based on the actual operating conditions rather than the design case. Direct Annual Costs Direct annual costs (DAC) include variable and semivariable costs. Variable direct annual costs account for purchase of reagent, utilities (electrical power and water), and any additional coal and ash disposal resulting from the operation of the SNCR. Semivariable direct annual costs include operating and supervisory labor and maintenance (labor and materials).

DAC = Annual M aintenance Cost + Annual
Cost + Annual Electricity

Cost + Annual W ater Cost Annual Coal Cost Annual Ash Cost         

       

       

       

       

       + + Reagent (1.20)
Operating and Supervisory LaborIn general, no additional personnel is required to operate or maintain the SNCR equipment for large industrial facilities. Therefore, the cost of operating or supervisory labor is assumed be negligible. Maintenance The annual maintenance labor and material cost, including nozzle tip replacement for the injectors, is assumed to be 1.5% of the Total Capital Investment, TCI , in dollars. The equation is for annual maintenance cost in $/hr, AMC , given by:
Annual mai ntenance c ost TCI = 0.015 (1.21)1-34 Utilities The electrical power consumption in kilowatts (kw) estimated for SNCR operations is derived in Appendix B of the draft EPA report, Selective Noncatalytic Reduction for NO xControl on Coal-fired Boilers [1]. It is based on linear regression of electrical power consumption data correlated to the uncontrolled NO xconcentration in lb/MMBtu, NO xin , the NSR and the boiler heat input in MMBtu/hr, Q B .

P NO NSR Q x in B = 0 4 7 9 5 .

. (1.23)

Using the estimated power consumption, Power , the annual cost of electricity is estimated from the following equation: Annual electricity cost =P Cost t elect o p (1.24)
where Cost elect is the cost of electricity in dollars per kW ($/kw) and t op is defined in equation 1.22a. Reagent Consumption The annual cost of reagent purchase in $/yr is estimated using the aqueous reagent volume flow rate in gph q sol , the total operating time t op in hours.

op total t C F h r yr = 8760 (1.22a) Annual reagent cost q Cost t sol reag o p = (1.22)

were Cost reag is the cost of reagent in dollars per gallon ($/gal) and t op in hours can be calculated using the total capacity fuel or CF total :1-35 W ater Consumption

The volumetric flowrate of water for diluting the urea is calculated from the aqueous urea mass flow rate in lb/hrand the concentration of the aqueous urea during storage, C urea sol stored and the average percent concentration of the injected urea, C urea sol inj . The flowrate, q water, in gallons per hour (gph)is:

q m C C water sol
water urea sol
urea sol inj stored =  ρ −         1 (1.25)

where water is the density of water, 8.345 lb/gal. For urea dilution from a 50% solution to a 10% solution, Equation (1.25) becomes:
q m

water sol = water 4  ρ (1.26) Using this estimate for the volume flow rate of water (gph) the annual cost of water consumption in $/yr is given by: Annual water cost q Cost t water water o p = (1.27)
where Cost water is the cost of water in dollars per gallon ($/gal) and t op is given by equation 1.22a. Coal and Ash The additional coal required as a result of the heat used to evaporate the water in the injected solution (water in the stored urea solution and the dilution water) is estimated using the following equation: 

# ( ) ( ) ( ) ∆

Coal = Hv m Btu h r Btu lb reagent × × −          lb h r urea sol inj C 1 1 (1.28)

where C urea sol inj is the percent concentration of the injected aqueous urea agent and  m reagent is the mass flowrate in lb/hr. H V

, the approximate heat of vaporization of water at 310  F, is 900 Btu/lb, which is a representative temperature for flue gas exiting the air heater.1-36 The cost of the additional coal in $/yr required to maintain the same boiler steam output is:
A n n u a l C o a l co st C o a l C o st t coal o p ∆ ∆ = (1.31)
where Cost coal is the cost of coal in dollars per MMBtu ($/MMBtu) Coal is in lb/hr, and t op is given in equation 1.22a.Although the water from the urea solution is evaporated in the furnace at higher temperatures (due to urea injection in the furnace zones at over 1,500  F), the temperature at the air heater exit is used because it is the thermodynamic end point of the combustion process. The quantity of fuel burned in the boiler depends on the boiler efficiency, which, in turn, depends on the air heater exit temperature and the moisture in the air heater exit gas. The boiler is fired to maintain the required steam flow (e.g., for the steam turbine). Because the water from the urea solution evaporates in the boiler, the boiler efficiency decreases. Consequently, more fuel needs to be burned to maintain the required steam flow. With urea as the reagent, injected as a 10% solution and H V = 900 lb/Btu, Equation (1.28) in MMBtu per hour becomes: 

# ( ) ( ) ( ) ( ) ∆ Coal = m 1 0 M M Btu

h r reagent lb h r 6 900 9 Btu lb Btu M M Btu  (1.29)

As a result of burning additional coal, additional ash is generated. This ash must be disposed or sold as byproduct. This cost methodology assumes that the ash is disposed. The estimated additional ash to be disposed in lb/hr is given by:

∆ ∆

Ash Coal ash produc t HHV = (1.30)
where ash product is the fraction of ash produced as a byproduct of burning a given type of coal to and HHV is the high heating value of the coal in Btu/lb as given in Table 1.3.1-37 The cost of additional ash disposal due to the addition fuel usage is given by:
Annual Ash cost Ash Cost t ash o p = ∆ ∆ (1.32)
where Cost ash is the cost of ash disposal in dollars per ton ($/ton). Ash is in lb/hr and t op is given equation 1.22a. A conversion of 2,000 lb per ton is required to convert $/ton to $/lb.

Indirect Annual Costs In general, indirect annual costs (fixed costs) include the capital recovery cost, property taxes, insurance, administrative charges, and overhead. Capital recovery cost is based on the anticipated equipment lifetime and the annual interest rate employed. An economic lifetime of 20 years is assumed for the SNCR system. (The remaining life of the boiler may also be a determining factor) In many cases property taxes do not apply to capital improvements such as air pollution control equipment, therefore, for this analysis, taxes are assumed to be zero [9]. The cost of overhead for an SNCR system is also considered to be zero. An SCR system is not viewed as risk-increasing hardware (e.g., a high energy device such as a turbine). Consequently, insurance on an SNCR system is on the order of a few pennies per thousand dollars annually [9]. The administrative charges, covering sales, research and development, accounting, and other home office expenses, incurred in operation of an SNCR system are not significant for the cost estimation procedure presented here. Finally, there are two categories of overhead, payroll andplant. Payroll overhead includes expenses related to labor employed in operation and maintenance of hardware; whereas plant overhead accounts for items such as plant protection, control laboratories, and parking areas. Because this procedure assumes that no additional labor is needed to operate an SNCR system, payroll overhead is zero and plant overhead is considered negligible. Using these assumptions, indirect annual costs in $/yr, IDAC , can be expressed as:
IDAC = CRF TCI (1.33)

where TCI is the total capital investment in dollars and CRF is the capital recovery factor.1-38 Capital recovery factor was defined in Section 1 as: 

### ( ) ( ) CRF i i n

n = +

− 1 1 1

+ i (1.34)

where i is the assumed interest rate and n is the economic life of the SNCR system.

T

otal Annual Cost The total annual cost, TAC , for owning and operating an SNCR system is the sum of direct and indirect annual costs as given in the following equation:

TAC = DC + IDAC (1.35)

The tons of NO xremoved annually are: NO Removed NO Q t x x in B o p = N O x η (1.36)

where NO xin is given as lb/MMBtu, Q B as MMBtu/hr and top in hours and a conersion of 2,000 lb/ton is required. The cost in dollars per ton of NO xremoved per year, cost efficiency is:

Cost Efficiency TAC NO Removed x = (1.37)1-39 

### 1.5 Example Problem An example problem, which calculates both the design parameters and capital and annual costs, is presented below. The design basis is a retrofit SNCR system being applied to a1000 MMBtu/hr, wall-fired, industrial boiler firing subbituminous coal. The following assumptions are made to perform the calculations: Fuel High Heating Value 10,000 Btu/lb Maximum Fuel Consumption Rate 1.0 x 10 5 lb/hr Average Annual Fuel Consumption 4.38 x 10 8 lb Number of SNCR operating days 155 days Uncontrolled NO xConcentration 0.46 lb/MMBtu Required Controlled NO x Concentration 0.30 lb/MMBtu Percent Fuel Ash Weight 7.5% Stored Urea Concentration 50% urea solution Injected Urea Concentration 10% urea solution Number of Days of Storage for Urea 14 days
In addition to these assumptions, the estimated economic factors required to perform the calculations are taken from References [2] and [3]. These estimates are: Cost Year December, 1998 Equipment Life 20 years Annual Interest Rate 7% Coal Cost, Eastern Bituminous 1.60 $/MMBtu Ash Disposal Cost 1 1.28 $/ton 50% Urea Solution Cost 0.85 $/gal Water Consumption Cost 0.0004 $/gal1-40 1.5.1 Design Parameter Example The boiler annual heat input rate, Q B , is calculated from the High Heating Value for subbituminous coal given in Table 1.3 and the maximum fuel consumption rate,  m fue l :

Q B Btu lb lb h r Btu M M Btu M M Btu lb = ×
=

1 0 000 100 000 1 0 1 000

6 , ,
,

The plant capacity factor is calculated from the maximum and annual average fuel consumption: 

# ( ) C F plant lb h r = × × × = = 4 3 8 1 0 1 1 0 8760 0 5 50% 8 5 .

. lb hr yr The SNCR system capacity factor is calculated from the months of SNCR operation, 5 months:

C F SNCR = == 1 365 0 4 2 42%

55 days days . The total capacity factor including both plant and SNCR capacity factors is given by:

C F toal =× = = 0 5 0 4 2 0 2 1 21%

. . .
The NO xremoval efficiency, NOx , is calculated from the inlet NO x concentration and the required stack NO xconcentration:

η N O lb M M Btu lb M M Btu lb M M Btu x = − = = 0 4 6 0 3 0 0 4 6 0 3 5 3 5 . .

. . %
The equation derived in Reference [1] is used to estimate the NSR for the SNCR system. The estimate is given by: 

# ( ) NSR lb M M Btu lb M M Btu = × +

      ×

= 2 0 4 6 0 7 0 3 5 0 4 6 1 2 3 . . .

. .1-41 The reagent utilization can then be calculated based on the required NO x removal efficiency and NSR value using:

U tilization = 0 3 5 1 2 3 0 2 8 28%

.

. = = . The value of the the NSR indicates that 1.23 moles of NH 3 are required per mole of uncontrolled NO xto reduce the NO xlevel by 35%. This translates to a reagent utilization of 0.28, the ratio of moles of reagent reacted to the moles injected. This indicates that 28% of the injected reagent is being utilized for NO x removal. The remainder of the reagent is being destroyed or passing through as ammonia slip. The mass flow rate of the reagent is calculated using the molecular weight of the reagent, 60.06 g/mole and NO 2 , 46.01g/mole and the SR T for urea, 2. For an NSR of 1.23, the reagent mass flow rate is given by:

 . .. .

. m reagent = × ××× × = 0 46 1000 0 35 123 60 06 2 46 01 130 lb M M Btu M M Btu h r g mole g mole lb h r The flow rate of the diluted solution, where the concentration of the aqueous solution is 50% urea, is given by:



. m sol lb h r lb h r = =

130

0 5 0 260

The solution volume flow rate can then be calculated where  is the density of the aqueous reagent solution,71.0 lb/ft 3 for 50% aqueous urea solution at 60  F.

q gp h

sol lb h r gal ft lb ft = ×

=

260 7 481 7 1 0 2 7 3

3 .

. The total volume stored in the tank, or tanks, is based on the volume that the SNCR system requires for 14 days of operation. The on site storage requirement is given by:

Volume gph days gal tank = × ×= 2 7 1 4 2 4 9072 h r day1-42 The on site storage requirement for urea is 9,072gallons per 14 days. This shows that for a large boiler, 1000 MMBtu/hr with 35% NO x removal efficiency the volume of urea required to operate an SNCR system for155 days during summer months is approximately 10,500 gallons. An estimates for power consumption is given by:

Power = kW lb M M Btu 0 4 7 0 4 6 1000 9 5 2 3 . .

. M M Btu h r × ×
=Water consumption, assuming a 50% urea solution stored and a 10% urea solution injected, is:

gp h gal lb hr lb 125 1 10

. 0 5

. 0 345

. 8 260 q water =      

− × =
The estimated additional coal and ash required to maintain the same net heat output are given by:

∆ Coal lb h r Btu lb Btu M M Btu M M Btu h r = × × −       = 260 900 1 0 1 0 1 0 1 2 6

.

∆

Ash M M Btu h r Btu M M Btu Btu lb lb h r = × ×
=

2 0 077 1 0 6 1 0 000 1 5

.

, 1.5.2 Cost Estimation Example Once the SNCR system is sized, the capital and annual costs for the SNCR system can be estimated. The direct capital costs are estimated using: 

# ( ) ( ) 

## [ ] D C M M Btu MM Btu h r MM Btu h r MM Btu

h r = × × ×+× =             $950

. . . $ 1 , , . 1000 2375 1000 0 6 6 0 8 5 0 3 5 498 152 0 5771-43 Indirect capital costs are estimated from the direct capital costs using the following equations:
Indirect Installation Costs General Facilities ($) $1,498,152 x 0.05 = $74908 Engineering and Home Office Fees ($) $1,498,152 x 0.10 = $149,815 Process Contingency ($) $1,498,152 x 0.05 = $74908 Total Indirect Installation Costs ($) $74908 + $149,815 + $74908 = $299,630 Project Contingency ($) ($1,498,152 + $299,630) x 0.15 = $269,667 Total Plant Cost ($) $149,815 + $299,630 + $269,667 = $719,112 Preproduction Cost ($) $719,112 x 0.02 = $143,82 Inventory Capital* ($) 9072 gal x 0.85 $ / gal = $7,711 Total Capital Investment (TCI) ($) $ 719,112 + $143,82 + $$7,711 = $741,205 Annual costs are based on the economic factors listed above. In addition, the SNCR system is assumed to operate for 5 months of the year with a boiler loading of 65%, resulting in a total capacity factor of 27%. The annual variable costs are given by:

yr , $ = , $

. = cost e maintenanc Annual 118 11 205 741 015 0 ×
Annual reagent cost gph $ gal . = × ×× =           2 7 0 8 5 0 2 1 8760 218

. h r yr yr $42 ,

Annual ele ctricity c ost = $ kW hr yr 2 3 0 0 5 0 2 1 8760 115

kW yr × ×       = . . $ 2 ,

Annual wat er cost hr yr = × ××       = 125 0 0004 0 2 1 8760 gph

. $ gal . yr $92 

# [ ] Annual = M M Btu $ M M Btu hr ∆ Coal cost h r . yr yr 2 1 6 0 0 2 1 8760 887 × ×× =
. $ 5 , 

# [ ] Annual . yr lb hr yr ∆

Ash cost = $ ton hr
lb ton 1 5 1 1 2 8 0 2 1 8760 2 000 × ××

= .

, $1561-44 The total variable direct annual cost, the sum of the cost of the reagent, electricity, water, coal and ash, is given by:

and the total direct annual cost is given by the sum of the maintenance and variable cost:

Total indirect annual costs assumes that the property tax factor, F tax , and the overhead factor, F

ovhd , are both zero. The capital recovery factor, CRF, is defined by: 

### ( ) ( ) CRF . . + = +

− =

0 0 7 1 0 0 7

1 0 0 7 1 0 09439 2 0 2 0

. . and the indirect annual costs (IDAC) are calculated by:

IDAC

. $ , yr = 0 09439 741 205 962 × = , $69
The total annual cost is the sum of the direct annual and indirect annual costs given by:

TAC = $ , yr + $ yr yr 8 2 216 6 9 962 178 , $152 , =
The annual cost in terms of NO xremoved can be calculated using the total annual cost and the tons of NO xremoved annually by:

N O . x lb MM btu M M Btu hr yr lb ton hr Removed tons = ×× ×      

= 0 4 6 0 3 5 1000 0 2 1 8670 2000 147 . .
and

N O . x lb MM btu M M Btu hr yr lb ton hr Removed tons = ×× ×      

= 0 4 6 0 3 5 1000 0 2 1 8670 2000 147 . . Total Dire ctAnnual C ost (DAC) , yr yr = yr

$31 $50 , $82 , 748 468 216 + = 

### ( ) Total Vari able Cost yr yr = + ++ + = 4 2 218 2 115 9 2 5 887 156 468

, , , $ $50 ,1-45 

### References [1] Selective Noncatalytic Reduction for NO xControl on Coal-fired Boilers, Draft Report, prepared for the U.S. Environmental Protection Agency by The Cadmus Group, Inc., Bechtel Power Corporation, and Science Applications International Corporation. May 1998. [2] Investigation of Performance and Cost of NO xControls as Applied to Group 2 Boilers. Revised Draft Report, prepared for the U.S. Environmental Protection Agency by TheCadmus Group, Inc., Bechtel Power Corporation, and Science Applications International Corporation. August 1996. [3] Cost Estimates for Selected Applications of NO x Control Technologies on Stationary Combustion Boilers, Draft Report and Responses to Comments on the Draft Report. prepared for the U.S. Environmental Protection Agency by The Cadmus Group, Inc., and Bechtel Power Corporation. June 1997.[4] Analyzing Electric Power Generation Under the CAAA. EPA Office of Air and Radiation. March 1998. [5] Committee of the Institute of Clean Air Companies, Inc. White Paper, Selective Non-Catalytic Reduction (SNCR) for Controlling NO xEmissions. SNCR. October 1997. [6] Tanner Industries, Inc. Storage & Handling of Ammonium Hydroxide. Philadelphia, PA. October 1995.[7] Electric Power Research Institute (EPRI). Technical Assessment Guide, Vol. 1. Revision 7, 1993. [8] Northeast States for Coordinated Air Use Management (NESCAUM). Status Report on NO xControl Technologies and Cost Effectiveness for Utility Boilers. June 1998.[9] United States Patent, Method for the Reduction of the Concentration of NO In Combustion Effluents Using Ammonia. Inventor: Richard K. Lyon, Patent Number 3,900,554. August 19, 1975. [10] Rini, M.J., J.A. Nicholson, and M.B. Cohen. Evaluating the SNCR Process for Tangentially-Fired Boilers. Presented at the 1993 Joint Symposium on Stationary Combustion NO x Control, Bal Harbor, Florida. May 24 - 27, 1993. [11] Institute of Clean Air Companies, (ICAC). Proceedings from ICAC Forum: Cutting NO x Emissions. March, 2000. [12] State and Territorial Air Pollution Program Administrators (STAPPA) and Association1-46 of Local Air Pollution Conrol Officials (ALAPCO). Controlling Nitrous Oxides. July 1994. [13] Personal communication with Mike Knenlein of Fuel Tech to Paula Hemmer (PechanAvanti) on April 2, 2000. [14] Majors, Russ K., Dr. Russell Hill, Robert McMurry, and Scott Thomas, A Study of theImpact of Ammonia Injection on Marketable Fly Ash Including Quality Control Procedures.TECHNICAL REPORT DATA (Please read Instructions on reverse before completing) 1. REPORT NO. 452/B-02-001 2. 3. RECIPIENT'S ACCESSION NO.

4. TITLE AND SUBTITLE The EPA Air Pollution Control Cost Manual 5. REPORT DATE January, 2002 6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S) Daniel Charles Mussatti 8. PERFORMING ORGANIZATION REPORT NO.

9. PERFORMING ORGANIZATION NAME AND ADDRESS U.S. Environmental Protection Agency Office of Air Quality Planning and Standards Air Quality Standards and Strategies Division Innovative Strategies and Economics Group Research Triangle Park, NC 27711 10. PROGRAM ELEMENT NO.

11. CONTRACT/GRANT NO.

12. SPONSORING AGENCY NAME AND ADDRESS Director Office of Air Quality Planning and Standards Office of Air and Radiation U.S. Environmental Protection Agency Research Triangle Park, NC 27711 13. TYPE OF REPORT AND PERIOD COVERED Final

14. SPONSORING AGENCY CODE EPA/200/04

15. SUPPLEMENTARY NOTES Updates and revises EPA 453/b-96-001, OAQPS Control Cost Manual, fifth edition (in English only)

16. ABSTRACT In Spanish, this document provides a detailed methodology for the proper sizing and costing of numerous air pollution control devices for planning and permitting purposes. Includes costing for volatile organic compounds (VOCs); particulate matter (PM); oxides of nitrogen (NOx); SO2, SO3, and other acid gasses; and hazardous air pollutants (HAPs).
17. KEY WORDS AND DOCUMENT ANALYSIS a. DESCRIPTORS b. IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group Economics Cost Engineering cost Sizing Estimation Design Air Pollution control Incinerators Absorbers Adsorbers Filters Condensers Electrostatic Precipitators Scrubbers
18. DISTRIBUTION STATEMENT Release Unlimited 19. SECURITY CLASS (Report) Unclassified 21. NO. OF PAGES 1,400
20. SECURITY CLASS (Page) Unclassified 22. PRICE

E PA Form 2220-1 (Rev. 4-77) E PA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE