### EPA Report Number Month and Y car ofPublication 

# Selective Noncatalytic Reduction for NOx 

# Control on Coal-fired Boilers
by Gajendra H. Shroff 

### Mitchell J. 

### Krasnopoler Bechtel Power Corporation

Gaithersburg, MD 20878 

### Charles W. Young Shreedhar Kanetkar The Cadmus Group, Inc.

Waltham, MA 02452 Contract Number 68-D7-0061 Task Order 000I



### Project Officer Mr. Andy DuPont 

### Acid Rain Division Office ofAirand Radiation

Washington, DC 2000I



### Laboralory ?? 

### Office ofResearch and Development U.S. 

### Environmental Protection Agency Research Triangle Park, NC 27711

### FonvardINotice 

### Ravi

-According to the guidelines (p.9). aforwardissimilarto an author'spreface, but is providedby 

### the sponsoring laboratory. A notice may include apeer-reviewnotice, a disclaimer, ora copyright. It'syourcall. Apparently, we can include neithero/them, one, orboth.

Abstract This report illustrates amethodology for developing screening costestimates for installation and operation ofselective noncatalytic reduction (SNCR) technology for control ofNOx emissions from coal-tired boilers. Screening cost estimates are approximate and are used as adecision tool during planningto compare optional technologies. They help system owners achieve an important initial step in the process ofconceiving and selecting emission control technology. Costs are presented in 

### terms of 1998 dollars in this report. As a prelude to the costing methodology, the report describes SNCRtechnology, the chemistry ofthe process, factors that affect performance, and componentequipment. The costing methodology uses an innovative approach to estimate important underlying design parameters, including the normalized stoichiometric ratio and reagent consumption. Traditionally, system suppliers use proprietary methods to estimate these parameters. Having the reported methodology available expedites the process for screening purposes and gives the plant owner added freedom in 

### selecting an emissions control process. The mathematical approach uses fundamental engineering relationships and equations developed with regression and curve fitting techniques. The methodology is tested by comparing estimated costs with published cost data for existing plants. This methodology, though highly cost-effective for its intended purpose, is not meant to be 

### a substitute for traditional design practices that would apply after screening decisions are made.

IIContents 

### FOr\\lard/Notice II 

### Abstract II Tables .........................................•................•............ v 

### Figures v 

### Abbreviations and Symbols vi Acknowledgment

_ viii Chapter I Introduction .........................................•............ I 

### Control ofNOx Using Selective oncatalytic Reduction I 

### Purpose and Organization ofReport I Chapter 2 Description ofSNCR Technology ........................•....•....... 3 

### Overview 3 SNCR Chemistry ...........................................•....•....... 3 SNCR Reagent ...........................•.............................. 3 

### Factors Affecting SNCR Performance

_ _ _ _ 4 

### Temperature Windo\v 4 

### Residence Time 6 

### Normalized Stoichiometric Ratio 7 

### Degree ofMixing 9 

### Ammonia Slip 10 SNCR Equipment .............•.......................•.........•...... 10 Chemical Storage ..................................•....•............ 12 Skid-Mounted Modules ............................•.....•....•....... 12 Injectors .........................................•....•....•....... 14 Preparing SNCR System Performance Specifications ..................•........ 14 

### Data Furnished to System Supplierfor Design 15 Budgetary Estimates Based onPerformance Specifications 17 

### NOx Emission Control Performance 18 

### Chemical and Other Consumption Rates

_ 18 Chapter 3 Estimation ofSNCR Screening Costs 19 

### EstimatingtheNormalized Stoichiometric Ratio

_ 

### 20 Example oftheNSR Estimation Procedure ..................•....•........ 21 

### OtherFactors Involved in 

### NSR Estimation

_ 21 Estimating Reagent Consumption and Tank Size 21 Estimatingthe Total Plant Capital Requirement

_ 23 Equipment Costs ......................................•....•........ 26 Installation Costs 26 Total Plant Capital Requirement ........•.....•.....•....•....•......... 26 Estimating Total Annual Costs 26 DirectAnnual Costs ..................•.....•.....•.........•......... 26 Operating and Supervisory Labor 26 

### Maintenance
. _ _ 26 Reagent ........................•.....•.....•................... 26 Utilities 28

111Coal and Ash ..............•....•....•....•.....•................ 28 

### IndirectAnnual Costs 29 Tota! Annua! Cost ..................................•....•.....•..... 30 Chapter4 Summary ofEquations .................•.....................•..... 32 

### Design Factors foran SNCRApplication 32 Annual Costs for an SNCR Application 33 

### DirectAnnual Costs 33 IndirectAnnual Costs , .. 34 Total Annual Costs ...........•........••....•................•...... 34 Chapter 5 An Example Calculation 35 Design Basis ..............................•............................ 35 

### Equipmentand Consumables Data

_.. _ 35 Total Capital Requirement 37 Total Annual Costs ..................................•.....•....•....... 38 References

_ 42 Appendices A DesignIPerformancc Data for SNCR Retrofit on a 250 MW Wall-Fired Boiler ............................•....••....•....... 44 B Development ofSNCR Related Equations 46 C Comparison ofResults from Methodology with Industry Case Studies 50

IVTables 

### Table2-1. Ureaand Ammonia Reagent Properties 

### 5 Table3-1. Major Equipment List for an SNCR Application .........•.....•.....•..... 24 Table 3-2. Capital Cost Factors for an SNCR Application ............•................ 27 Table 5-1. Design Data .............................................•.......... 36 

### Table 5-2. Economic Factors 37 Table 5-3. SNCR Capital Costs 38 Table 5-4. Direct Costs ...............•...............•.....•.....••....•...... 40 Table 5-5. Indirect Annual Costs 40 Table 5-6. Total Annual Costs 41 Figures 

### Figure2-1. Boiler Gas Path Configuration 6 Figure 2-2. Urea SNCR Process Flow Diagram 13 

### Figure 3-1. Approximate NSR Estimation for Urea 22

vAbbreviations and Symbols AAsh additianallblhr ofash generated in the boiler 

### Ash = 

### percentash in the coal AC Ash disposal cost, $/shart ton C = 

### the percent ofweight ofthe 

### reagent in the solution (e.g., 

### C = 

### 50% for urea. 19 or29.4% for ammonia) CF = 

### capacity factor, percent ACaal MMBtu / hrofadditional coal CC Cost ofCoal, $/MMBtu Density ofwater, gallons per 

### It' 7.481 EC Electricity Cost, $/kWh 

### F

TAX = 

### Indirect annual cost in S/yr F

OVHn = 

### indirectoverhead HHV = Coal higher heating value, Btu/lb Heat ofvaporization ofwater 900 Btu/lb 

### lAC = 

### Indirectannual cost in S/yr 

### MW = 

### equivalent megawattelectric poweroutputcapability at full load MR molecular weight ofthe reagent**(~60.6** for urea; 17.03 for ammonia) Molecularweight ofNO, (i.e, NOJ 46.01 NPHR Net Plant Heat Rate (BtulkWh) 

### NSR = 

### Normalized Stoichiometric Ratio

VIf)NOx = 

### percentNOx 

### reduction NOXb uncontrolled (baseline) NO
.. IblMMBtu 

### p = 

### density ofthe 

### solution, Iblftl (e.g., 71 for a50% urea solution; 58.0 for a 19% aqueous ammonia; and 56.0 fora29.4% aqueous ammonia) 

### Q. = boilerheat input, MMBtulhr, 

### Q. = 9.5 x MW RC Reagent Cost, $ per gallon ofsolution (e.g., SO percentby weight) 

### TNOx = 

### shorttons ofNOx

### removed peryear SRT = 

### theoretical stoichiometry (= 

### 2 for urea, 1for ammonia) 

## we = 

### watercost, $ 

### per gal

VII

### Acknowledgment The authors express theirthanks to the EPA Task OrderManager, Dr. Ravi SrivastavaofEPA's Office ofResearch and Development, for his technical insight and advice during the preparation ofthis report. We also wish to thank others at EPA who provided valuable reviewcomments as the report was developed. They include Mr. SamNapolitano ofEPA's Office ofAtmospheric Programs and Mr. William Vatavuk ofEPA's Office ofAir Quality Planning and Standards.

YillChapter 1 

### Introduction
Control ofNO, Using Selective Noncatalytic Reduction Nitrogen oxides (NOJ are gaseous airpollutants that are fonned when fuels are burned in combustion devices. While the flue gas is within the unit, about 95 percent ofthe NOli: exists in the form ofnitric oxide (NO) [1,2]. The balance is nitrogen dioxide (NO,), which is unstable at high temperatures. Once the flue gas is emitted from the stack, most ofthe NO is ultimately converted to N020 Scveraltcchnologies are available to control NO, emissions from stationary sources. These include combustion modification controls (e.g., low·NO" burners, Qverfirc air, reduction of excess air, flue gas recirculation, taking burners out ofservice, rcburning, etc.) and postcombustion controls (selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR». SNCR technology is being used for NO" emission control on industrial boilers, electric utility stcam gencrators, thermal incinerators, and municipal solid waste energy rccovery facilities. In this technology, a chemical reagent is injected into hot flue gas. Urea is usually used, or ammonia can be chosen. The reagent reacts with NO" in the gas stream, forming products such as nitrogen and watervapor. SNCR technology can be used alone or in combination with other NO.: control technologies. The hardware associated with an SNCR installation is relatively simple and readily available. Consequently, SNCR applications tend to have relatively low capital costs. 

### Purpose and Organization ofReport Th..is report describes the importantfeatures ofSNCR technology and aspects ofsystem design and operation that factor into the cost estimating methodology presented. Its primary purpose is to provide a methodology for estimating initial, screening-level, study costs for an SNCR application on aboiler. A step-by-step procedure is presented for s.izing system components and estimating screening-level capital and annual costs for a urea-based SNCR system. Fora specific facility, such estimates can be used to compare the approximate cost ofSNCR with alternative NO.: control technologies. Costs are presented in terms of Deccmber 1998 dollars.The capital costs and cost equations were developed based on the cost estimates and equations presented in References [3] and [4]. The capital costequations in this report were derived to correspond to the costequations for wall-fired and tangentially-fired boilers in Reference [4]. In addition, however, the capital costequations in this report include the effect ofNOxremoval, a factorthat was not characterized in Reference [4]. The direct annual costs include the annualized cost ofcapital and the variable costs related to operating the SNCR. The annualized cost of capital was developed using the estimated capital cost and acapital recovery factor (similarto a 

### capital charge factor in Reference [8]). The variable costs related to operating the SNCR were developed by predicting the reagent and utility consumption rates and changes to the coal consumption and ash generation rates. Thcse ratcs and typical unit costs were used to prcdict the annual costs. Information on certain key aspects ofthe design ofan SNCR system is considered proprietary by SNCR vendors. Thus, some ofthe mathematical design correlations used in this cost methodology are derived from documented comprehensive SNCRpcrfonnance data and costs based on quotations provided by SNCR suppliers [3.4]. Although the costing algorithms in this report are 

### based on retrofit applications ofSNCR on existing coal-fired, dry bottom. wall-fired, balanced draft boilers, the costestimating procedure presented is suitable for retrofit or greenfield applications ofSNCR on all types ofelectric utility and large industrial boilers firing 

### coal. Certain approximations are relied on to make the procedure useful for screening studies ofSNCR at specific facilities. To estimate the costs ofbroad applications ofSNCR on large populations ofboilers, the procedure described in Reference 5 is appropriate. Some supporting infonnation is presented in appendices. The basic SNCR design and perfonnance data used to develop the cost-estimating methodology are presented in Appendix A. Several equations were derived to develop the methodology. Three ofthe derivations, equations (5) for reagent utilization, (7) forthe nonnalized stoichiometric ratio, and (14) for electrical power consumption, are shown in Appendix B. Finally, Appendix C shows the costestimating results predicted using the methodolo'gy in comparison with SNCR cost data reported in the literature for nine facilities.



### 2

### Chapter2 Description ofSNCRTechnology
Overview 

### Inthe SNCRprocess, achemical reducing agent, such as ureaorammonia, is mixed with 

### flue gas. The reagent reacts with Oue gas NOll, generating molecular nitrogen. carbon dioxide, and water vapor. 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. This description focuses on a urea-based SNCR system because urea has been the reagent ofchoice in most recent SNCR system installations. In general, an ammoniabased system is similar to a urea-based system, with the primary difference being the method of reagent injection, as discussed later. 

### SNCRChemistry In the SNCR process, NOxreacts with injected reagent within an optimum temperature range of 1,600 to 2,100 ofwhen using urea, or 1,500 to 2,000 of when using ammonia. Reaction products include nitrogen (NIl, carbon dioxide (COJ, and water (H20). The net reactions that are basic to the SNCR process using urea or ammonia are:

or 2NO+ Co{NH,), 

### + 0, 

### -+ 2N, 

### + CO, 

### +2H,O 2NO+ 2NH, 

### +

### ~O, -+ 2N, 

### + 3H,O (I) (2) Reactions 1 and 2 are global representations ofthe actual complex chemical mechanisms. At the appropriate temperatures in the boiler, the ammonia (either injected orresulting from thennal decomposition ofurea) converts to free radicals that ultimately react withNO
... In general, the boilerthennal conditions are designed for steam generation, but not necessarily otherreactions. The residence time and flue gas temperatures may not 

### be ideal for the mass transferand chemical reaction steps ofthe SNCR process. Such practical limitations need to be taken into account in implementing SNCR system design and operation. 

### SNCR Reagent Urea and ammonia are acceptable, proven reagents based on considerations ofcost, storage and handling, safety, byproducts generated, and demonstrated capability. Ammonia may be received 

### 3in aqueous or anhydrous form. Anhydrous ammonia, a gas at normal atmospheric temperature, is transported and stored under pressure. Aqueous ammonia is a solution ofammonia in water. Generally, a concentration of29.4 percent ammonia is used in SNCR applications, though some recent applications are using a 19-percent solution. The 29.4 percent solution has substantial vaporpressure at nonnal air temperatures. Urea solution is less volatile than ammonia solution. Consequently, urea solution droplets generally penetrate farther into the flue gas when injected into the system. Therefore. in large boilers. the use ofurea reagent helps ensure good mixing with the flue gas. The properties of urea and aqueous ammonia (29.4 percent solution) arc shown in Table 2-1. Because ofthe advantages ofurea, it is more commonly used than ammonia in SNCR systems. Therefore, this report focuses on urea as the SNCRreagent. 

### Factors Affecting SNCR Performance SNCRtechnology has been shown to achieve NOll reduction efficiencies ofup to 75 percent in selected short-term demonstrations [6]. In typical applications, however, it is considered to be capable ofproviding 30 to 50 percentNOll reduction, depending on a numberoffactors. The importantdesign and operational factors that affect NOll reduction using an SNCR system include:

• mixing ofreagent and combustion gases within the required reaction temperature range (window), which is typically available within the boiler superheater and reheaterradiant and convective regions;

• residence time available in the desirable temperature range;

• uncontrolled NOll concentration level;

• molarratio ofinjected reagent (urea or ammonia) to uncontrolledNOll;

• degree ofmixing between the injected reagent and the NOll-containing combustion gases; and

• ammonia slip. Furtherdiscussion ofeach ofthese factors is providedbelow. Forreference, a simplified process flow schematic is shown in Figure 2-1. 

### Temperature Wi"dow For SNCRtechnology to work effectively. the urea must 

### be injected and allowed to react with NOll in the boilerregions where the combustion gas temperature is within a specific range. As 

### 4

### Table2-1. Urea and Ammonia Reagent Properties Property 

### Urea Solution Aqueous Ammonia Chemical formula COCNH,), NH, Molecular Weight of 60.06 17.03 

### reagent Liquid orgas atnormal air Liquid Liquid 

### temperature Concentration ofreagent 50% by weight 29.4% by weight nonnally supplied (19% is .Iso 

### used) 

### Ratio ofNH) to solution 28.3% by weight ofNH, 29.4% by weight ofNH, Density ofsolution 

### @ 60 7llb/ft' 56 Ib/ft' of (581b1ft' for 19%) 

### Vapor pressure 

### @80 of < 

### 1psia 13.9 psi. [8] 

### Crystallization temperature 64 of -110°F 

### Lowerexplosion limit Flammability limits in air Non-flammable 16% NH, by volume; 

### Upper explosion limit = 25% NH, by·volume. 

### Threshold limitvalue Notspecified 25 ppm (health effects) Odor Slight (ammonia-like) Pungent odor @ 5 ppm 

### ormore 

### Plastic, steel, orstainless Steel tank, capable of 

### Acceptablematerials for steel (no copperor handling at least 25 psig 

### storage copper-based alloys or 

### pressure (no copperor zinc/aluminum fittings) copper-based alloys, etc.)


### noted earlier,NOll reduction is effectivein the temperature range ofapproximately 

### 1,600 - 2,100 

### OF when using urea. Attemperatures belowthe minimum, the reaction kinetics are slow. At temperatures above the maximum, the urea reagentoxidizes and additional NOx

### is generated.
5PLATEN SECONDARY SUPERHEATER UREA INJECTORS

SECONDARYSUPERHEATER CONVECTION PASS PENDANT REHEATER

HORIZ. REHEATER
UREA .-::-t---L_....J._J INJECTORS 

# i PRIMARY SUPERHEATER 

# I ECONOMIZER

# l~ __l,----------+.

FURNACE BURNERS



### Figure 2-1 BoilerGas Path Configuration

Residellce Time Adequate residence time within the temperature window is required to accomplish the necessary 

### steps in the 

### SNCRNOli: reduction process. Residence time varies from 0.001 to 10 seconds [10, 11]. depending on the factors addressed laterin Chapter

### 2. The steps accomplished are:
6• mixing ofthe injected urea with the flue gas;
• evaporation ofwater;
• decomposition ofsolid urea to NI-lJ; • decomposition ofNHJ to NH2and free radicals; and
• NOli: reduction reaction chemistry. The amount ofresidence time that is available for the reaction depends on:

• the dimensions ofthe boiler gas path (from the upper furnace region through the superheater/reheaters to the convective backpasslprimary reheater region), and

• the volumetric flow rate ofthe flue gas along the boiler"gas path. The effectiveness ofSNCR technology depends on the flue gas temperature range and on the mass flow within the boiler in the area ofurea injection. Both variables, flue gas temperature and the mass flow, depend on boiler design, which is set to meet steam generation requirements while maintaining a flue gas velocity to prevent tube bank erosion. Because ofthese boiler design requirements, the gas velocities and residence times in the boiler are not always ideal for the SNCR process. Flue gas temperatures in the region from the upper furnace through the convective pass may vary by ±300 

### offrom one boiler to the next. Furthennore, residence time could vary from the ideal value for optimum NOli: reduction. In general, with more residence time available for the mass transferand chemical reaction steps, more NOli: is removed. 

### NormalizedStoichiometric Ratio TheNormalized Stoichiometric Ratio (NSR) indicates the amount ofreagent needed to achieve the targeted NOxreduction. Because capital and operating costs depend on reagent use, NSR is an important parameter in SNCR system design. Based on reaction equations (1) and (2), theoretically two moles ofNOxcan be removed with one mole ofurea or two moles ofammonia. However, in practice, because ofthe complexity ofthe actual chemical reactions involving NOx and injected urea and limitations ofmixing between urea and flue gas, more than the theoretical amount ofreagent needs to be injected into the boilerflue gases to obtain a specific level ofNOx reduction. The theoretical amount ofreagent is related to the theoretical stoichiometric ratio, defined as the ratio ofmoles ofreagent reacted to the moles ofNOx reacted (orremoved) according to Equations (I) and (2). (For urea, the theoretical stoichiometric ratio is 0.5.) The NSR, however, is the ratio ofthe moles ofreagent injected to the moles ofuncontrolled NOx' Because the moles ofNOxremoved are much less than the uncontrolled NOx and because ofthe limitations discussed above, typical NSR values require significantly more urea to 

### be injected in practice than the urea reacted according to the theoretical stoichiometric ratio. Most ofthe excess urea used in the process is destroyed through otherchemical reactions. However, a" small portion remains in the flue gas as ammonia slip, which is described separately below.



### 7

### The same factors that influence the extent ofthe reaction between NOx

### and achemical reagent in an SNCR system also affect the value ofNSR. These factors include:

• PercentNOx

### reduction,

• Uncontrolled NOx

### level in the flue gases.

• Temperature and residence time available within the optimum temperature window for the NOx 

### reduction reactions.

• Extent ofmixing achievable in the boiler,

• Allowable ammonia slip, and

• Rates ofcompeting chemical reactions. Because most available SNCRtechnology was developed on aproprietary basis, the open technical literature does not document extensive details ofthe theory and correlations that can be 

### used to estimate the required NSR. The publicly-available technical literature provides only qualitative indications ofthe effects ofvarious factors (temperature, residence time, etc.) [6]. Furthermore, the NSR is highly site-specific because the controlling factors are site-specific (e.g., temperature profile, fuel, fluid dynamics. chemical kinetics, and the effectiveness ofthe boileras achemical reactor). In light ofthese complexities, SNCR system design is generally undertaken by providing all ofthe plant- and boiler-specific data to the SNCR system supplier, who specifies the required NSR based on priorexperience and computational fluid dynamic and chemical kinetic modeling. Such modeling is used to define the flue gas temperatures. velocities. densities, and chemical compositions associated with the SNCRprocess in the boiler. Further, modeling provides estimates ofNOx

### reduction along the flue gas pathway from the furnace exit to the economizer. The modeling assists the system supplier in determining the available residence time and reaction rates so that urea injectors can be sized and located appropriately. In this way, the SNCRdesign can 

### be optimized forthe boiler ofconcern to obtain the maximum NOx

### reduction while maintaining acceptable ammonia slip. This optimization is accomplished by modeling several cases while varying importantparameters. Once the design is optimized., the system supplier selectsthe corresponding NSR. The normalized stoichiometric ratio (NSR). is defined as:


### moles ofequivalent 

### NH, injected 

### NSR = ----'---...,,---':-"":-- 

### moles ofuncontrolled 

### NOx


### 8 (3)Forestimating purposes, the moles ofNO)!; are taken as moles ofN02• Note that the moles of equivalent NH) in Equation 3 are the moles ofNH2 that will be released from the reagent. The actual stoichiometric ratio is the ratio ofthe moles ofreagent injected to the moles ofNO)!;
. The equation for the actual stoichiometric ratio is:

SRTis the ratio ofequivalent moles ofNH) per mole ofreagent. As shown in Equations (1) and (2), SRTis 1 for ammonia and 2 for urea. The utilization is defined as the ratio ofmoles ofreagent reacted to the moles injccted. Utilization ofreagent can be calculated from the NSR and the NO)!; reduction efficiency as follows: 

### NOx 

### reduction (%) 

### Utilization = "-'-'-":":===--'.:2 100x NSR (5)
The derivation ofEquation (5) is shown in Appendix B. The quantity ofreagent actually used is substantially higher than the stoichiometric amount for the reasons discussed above. Higher NSR values generally result in increasedNO)!; reduction. Generally, NSRs range between 

### 0.5 and 2.0 in industrial and utility boilers with utilization ranging between 25 and 50 percent, as shown subsequently in the discussion ofthe estimation of SR. 

### Degree of Mixing For efficientNO)!; reduction, the injected urea must mix rapidly with the combustion gases. Two types ofequipment are used for urea injection, including wall injectors or lance injectors which protrude into the flue gas pathway. The urea solution is atomized under pressure or with air or stearn in a dual-fluid atomizernozzle. There are two ways ofdispersing the solution droplets. A low-energy system uses little or no pressurized air or steam for atomization. In contrast, in a high-energy system, large amounts ofcompressed air or stearn are used to inject and vigorously mix the solution with the flue gas. Lance injectors are used in high-energy systems to ensure thorough mixing between reagent droplets and flue gas in large boilers. More electrical power (forcompressed air) or steam is consumed ifa high-energy system is used. The reagent injection systems used for ammonia-based systems are generally more elaborate than those 

### used in urea-based systems. In ammonia-based systems, high-energy lance injectors are used to ensure thorough mixing ofammonia droplets throughout the cross section ofthe flue gas pathway. Iflow-pressure injection were used, the ammonia droplets would evaporate in the vicinity ofthe atomi7..ertip owing to the high volatility ofammonia. Mixing would be inadequate and NOli: removal less efficient. 

### 9

### AmmoniaSlip In SNCR applications, limits on acceptable ammonia slip place constraints on NOxreduction performance. Injection ofurea at higherNSR values can improveNOx reduction, but may also increase ammonia slip. Ammonia slip limits are imposed by permitting authorities because anunonia released into the atmosphere above certain concentration levels is considered to be harmful to public health. Furthermore, prudent design practice limits ammonia slip to avoid impacts on downstream equipment. Depending on the fuel sulfur content and sulfur trioxide (SOl) generated, ammonia slip could also cause plugging, fouling, and corrosion problems in downstream equipment (airheater, ducts, fans, etc.) due to formation and deposition of anunonia-sulfur salts (sticky and corrosive ammonium bisulfate and ammonium sulfates). In general, ammonia slip can 

### be controlled to less than 25 ppm at the stack [6]. SNCR Equipment The Electric Power Research Institute (EPRI) developed and patented urea-based SNCR technology in 1980. The technology was licensed to Fuel Tech 

### (FT), which holds several additional patents that claim improvements and enhancements to the basic process. Fuel Tech has several sub-licensees that are authorized to supply and install SNCR technology.in several industrial sectors. Equipment is used to accommodate four main steps in the application ofurea-based SNCR technology, including:

• Step 1 - Receiving, storage, and recirculation ofthe urea solution (50 percent urea by weight),

• Step 2 - Metering, dilution, and mixing ofurea solution,
• . Step 3 - Injection ofdiluted urea solution (e.g., 10 percentby weight) at locations in the boiler with temperatures between 1,600 to 2,100 

### OF, and

• Step 4 - Mixing/dispersion ofurea in the flue gas, evaporation ofwater, decomposition ofurea, and reduction ofNOxThese steps are described in further detail below.**~.** A simplified process flow schematic is presented in Figure 2-2. Aqueous urea (50 percentby weight) is received via a tank-truck orrail car and pumped into one or more storage tanks. More highly-concentrated urea solutions are available, but their freezing temperatures arc too high for this application. A 50-percent solution, with a freezing point of64

### of. is typically selected. The urea solution is then pumped to the circulation module where the solution flows through an**in~line** electric heater (to prevent freezing in cold climates) and duplex strainerto the
10

### injection zone metering (lZM) module. Filtered plant water(with less than 50 mgll ofsuspended solids and lowdissolved solids) is mixed with ametered amount ofurea solution to deliver a diluted urea solution (typically 10 percenturea by weight) to the ureadistribution module, which is typically located close to the boiler. Step 2. Each IZM module precisely meters and independently controls the concentration ofurea to each zone ofinjection in the boilerbased on signals received from the mastercontrol module and local programmable logic controller (PLC). The module can adjust solution flow rates, and activate ordeactivate injection zones in response to changes in outletNOx

### concentration, boiler load, or fuel quality. There arc approximately one to five lZM modules [12], depending on the boiler size, configuration, the uncontrolled NOx

### concentration, and desired NOx

### removal efficiency. Several IZM modules can be 

### combined onto one skid-mounted system. Dilutedurea solution is transported from the IZM modules to the distribution modules, which direct the solution to each injector. Each distribution module contains flow meters, balancing valves, gauges, and regulators to control the solution injection process. There is one corresponding distribution module for each IZM module [12]. Each distribution module provides urea solution to approximately four to twelve injectors [12]. Step 3. The diluted urea solution is injected at several zones (between onc and five [12]) in the boiler at within the appropriate temperature window. The injectors may be 

### ofthe pressureatomized ordual-fluid (air or steam) atomizertype. The injectornozzles are specially designed to meet plant-specific conditions. Step 4. The solution is dispersed and the wateris vaporized. The urea decomposes to NHJ, 

### NH2, 

### and otherfree radicals that react with NOx 

### and reduce itto N2, 

### CO2, 

### and water. The boiler radiant cavity (secondary superheater and reheaterregion) and convective cavity (primary superheater and reheaterarea), where urea is injected, serve as chemical reaction chambers. In an existing boiler, the injectors are located in available open areas such as the region between the superheater and reheater sections. These conditions are illustrated in Figure 2-1. Mixing ofthe reagent with the flue gas is important for properperformance ofSNCR, and is generally ofgreaterconcern in applications on large boilers. Ifmixing and distribution ofthe reagent throughout the flue gas is inadequate, the umeacted ammonia (and ammonia slip) increases. The following techniques are employed to ensure adequate mixing.

• Use ofseveral injectors at several locations within the boiler's optimum flue gas temperature window. To ensure proper system design forexisting boilers, temperature and velocity measurements are made and the supplieruses computational fluid dynamic (CFD) modeling to determine the optimum number ofinjectors, locations, and otherdetails.


### 11

### • Use ofmore than the normal amount ofair for atomization ofthe reagent solution. There are two types ofmixing modes-low-energy mixing with the normal amount ofatomization air, and high-energy mixing with substantially more than the normal amount ofatomization air. The extra air in the high-energy mixing option acts as a transport medium to induce betterdispersion ofthe reagent solution throughout the flue gas.

• Use ofbetter atomizer nozzle designs to obtain optimum solution droplet size distribution, spray angle, and direction. The equipment used to accommodate these steps is discussed below, with reference to applicable alternatives. 

### ChemicalStorage Forurca-based systems, urea solution is received by tank trucks orrail car and pumped into onc or more storage tanks. Aclosed top, flat bottom, vertical storage 

### tank is used for urea storage. Such tanks are usually made offiber- reinforced polyester and have a corrosion barriercoating on the inside made ofpremium-grade vinyl esterresin. The tanks are equipped with level and temperature indicators, a manway, vent, and access ladder, and other appurtenances. The applicability ofheat tracing, insulation, and seismic design criteria are detennined based on sitespecific conditions. The tank. should be surroundedby a spill containment structure (usually a 

### dike). Skid-MoulltedModules 

### The dilution waterpressure control module, urea supply/circulation module, IZM module, and distribution module, shown in Figure 2-2, are skid mounted on stainless steel bases. This modular approach, with shop assembly ofpumps, valves, internal piping, instruments, and controls, reduces field installation time and related costs while providing flexibility for future expansion. These modules are described below:

• Dilution WaterPressure Control Module

- 

### Ifplant water is not available at the properpressure, adilution waterpressure (DWP) control module is used. It 

### typically consists oftwo full-flow multistage stainless steel centrifugal pumps, inline duplex strainer, pressure control valves, and the required pressure/flow instrumentation. lbrough the use ofbackpressure controllers and multistage pumps, this system is designed to maintain a constant supply ofdilution water, at the design pressure, in response to the changing SNCR process demand signals.

• Circulation Module

- The supply/circulation modulejs a fully equipped highflow, high-head urea solution delivery system designed to supply filtered urea solution to the IZM module. This module contains multistage stainless steel centrifugal pumps, in-line duplex strainers, electric heater, and pressure, Oow, 

### 12COOLING AIR AIR 

## f 

# r .'T>. INJECfORS-- 

# 0£1 ATOMIZING AIR _'T>_ 

## S-S:! COMPRESSOR 

## « Z 

# <... UJ 0 DISTRIBUTION MOOULES 0: 

### >- ::J ::J -' 

## • 0 BOILER 0 (/) 

### )< srA-,e METERING 

### _4V' MIXER PUMPS**WAT~**

## ~~ 

## '>----< 

# l:::::' WA-kR"PUMP WATER PUMP INJECTION ZONE METERING MOOULES DILUTION WATER PRESSURE CONTROL MODULE 50010UREA 

# Jillt SOLUTION
UREA STORAGE CIRCULATION HEATER TANK PUMPS SUPPLY/CIRCULATION MODULE 

### ) go 

## ------. H UNLOADING PUMP 

### Figure 2-2 Urea SNCR Process Flow Diagram
13temperature, and level instrumentation and controls. The main purpose ofthis module is to maintain continuous circulation ofthe stored urea. Its operational functions include filtering the solution to avoid clogging ofthe injectors and electric heating to preventthe solution from freezing. It also provides a locaUremote control and monitoring station for the storage tank and circulation system.

• Injection Zone Metering Module

- Each lZM module includes a chemical metering pump, a water pump, an in-line static mixer, a local control panel, zone isolation valves, and magnetic flow meters and control valves for chemicals and water. The mixed and diluted urea solution is transported from the IZM to the distribution modules, which direct the solution to each injector.

• Distribution Module

- Each ofthe distribution modules consists offlow meters, balancing valves, and regulators which accurately control and display the chemical and atomizing air flow to each injector. The modules also include manual ball valves, gauges, and stainless steel tubing to adequately control the urea injection process. The urea solution flows from the distribution modules to the injectors. 

### Injectors Wall-mounted injectors, ratherthan lance-type injectors, are generally used in cases where shortrange injection is necessary to mix reagent droplets with the flue gas stream. Ifthe droplets arc large, they have greater momentum and penetrate longer distanccs, but it also takes longerto evaporate the water. Since urea does not decompose and react with NOli until the water in the urea solution evaporates, optimization ofthe droplet size and injector locations is required for maximum NO" reduction. Even with droplet size optimization, however, the wall-mounted injectors are better suited for small boilers because the distance from the wall to the center ofthe gas flow path is smaller. They may 

### be applicable for large boilers ifthe targeted NOli reduction is low. The main advantage ofthe wall-mounted injectors is that they are not fully exposed to the hot flue gases from the boilerfurnace and, thus, have relatively long lives. Lance-type injectors can 

### be used in large industrial or utility boilers. They can 

### be fixed or retractable, and can include several nozzles. Lance-type injectors (both fixed orretractable) are generally cooled by air (or steam) to maintain structural integrity underhigh-temperature conditions. Some multi-nozzle lances for the convective pass are water-cooled. 

### Preparing SNCRSystem Performance Specifications As introduced above, an SNCR system supplieris generally involved in the design ofan SNCR systembecause ofthe proprietary nature ofthe technology. This subsection is included to provide perspective on the information that is generally needed by a supplierfor SNCR design.
14

### The costestimating methodology described in succeeding sections purposely avoids interaction with the supplier. It 

### does so specifically to expedite the development ofa screening-level cost estimate. When a supplier is involved in the process, it is done so specifically for system design purposes, resulting in system specifications and development ofan accompanying costestimate sufficiently accurate tojudgethe acceptability ofcompetitive bids. Thus, this section describes the information that must 

### be assembled and furnished to a supplierto prepare design specifications, particularly that component information with the greatest influence on system cost. SNCRcapital and operating costs can 

### be**estimate~** 

### ifthe major cost items are identified and the system is defined in adequate detail. As part ofthe design process, the SNCR system supplierwill provide acostquotation for his scope ofwork. To determine total projectcosts, the boilerowner will add certain cost items, such as system integration/interface engineering, supervision, and direct and indirect overhead. 

### Data Fumislledto SystemSupplier forDesigll The following data are provided to the system supplier for SNCR system design:

• The boiler capacity in tenns ofheat inputrate (MMBtulhr). Ifthe boilerproduces 

### electricity, then its heat input can 

### be estimatedusing the boilernetplant heat rate (NPHR): 

### Heat inplll role (MMBtulhr) (MW x 1,000

### kW x 

### NPHR (Btll/kWh)) 11,000,000 (6) Note that ifNPHR is not known, a value of9,500 BtulkWh can be used as a 

### reasonable estimate. Using this value, the heat input rate, Qa, is: 

### Q. (MMBtu/hr) = 

### MW x 

### 9.5 (6A)

• Boiler load profile

- percent oftime the boileroperates at 100percent load, and at various partial loads.

• Type ofcombustion unit

- dry/wet bottomboiler, wall-fired, tangentially-fired, 

### cyclone fired, other(e.g., stoker-fired); yearbuilt, and manufacturer.

• Existing orplanned uncontrolled NO" and CO emission data in ppm orIbIMMBtu without the proposed SNCR system, including any change in emissions related to other installed orplanned technologies (e.g., low-NO" burner, gas recirculation, overfire air, etc.).



### 15•

•

•

•



### •

•

•

•



### •

• Air preheaterdesign and operational data, including soothlowcrdata. 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 Dataor Combustion Calculations

- flue gas flow rate at design oractual conditions; excess air rate at full and partial loads; flue gas composition including 

### 0" NO" CO, SO" and HCI; full-load net plantheat rate (Btu/kWh). BoilerDimensions

- sectional side view; sectional front view; plan section through furnace (width x 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 walVpanels, etc.) in the furnace or backpass. Locations ofboiler furnace overfire airports. Locations and sizes ofboilerobservation ports, temperature probe ports, sootblower openings, and other locations for potential new ports. Flue gas temperature profile from furnace exit to economizer (i.e., where temperature drops to about 1,400 

### OF) 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. Minimum expected NOxreduction orpennit requirement for stack NOxemission level (ppm or IbIMMBtu). The boiler supplier/manufacturer can furnish most ofthis infonnation for existing or planned new units. For fuel data, the designer needs typical ordesign values, as well as the expected range. To define the temperature profile in existing boilers, it is preferable to obtain actual data from temperature measurements (rather than predictions). Also, flue gas velocity measurements, combined with upper furnace and convective pass dimensions, are used to determine residence times available for NOxreduction reactions. To obtain a representative cost quotation from an SNCRsystem supplier, the request should contain sufficient details to minimize design assumptions by the supplier. The request for



### 16quotation (RFQ) should include the technical specifications, as well as commercial tenus and conditions. The uncontrolled and desired NO" emission levels should 

### be provided at fuHload and selected partial loads, (i.e., loads at which the boileris expected to operate for significant time periods). It is also critical to specify the allowable byproductemission rates, especially the anunonia slip. Some penuitting authorities may also impose emission limits on nitrous oxide, N20, a greenhouse gas. The boiler owner should specify the preferred NO" reducing reagent. In special situations, a small percentage ofadditive chemicals may 

### be rccommended by the SNCR system supplierto improve perfonnance orreduce scaling and corrosion. The supplier should be asked to document the costs and benefits ofthese proprietary chemicals. Once the basic plant and other data have been collected, the SNCR specification can be prepared. Two importantparts ofthe specification are work included in the scope ofthe supplierand work not included (i.e., work done by the owner orhis architect-engineer/constructor). The more precise and detailed the specification ofthe work, the more accurate the overall system design and cost. However, forthe purpose ofa study costestimate, it is sufficient to provide general specifications for majoritems. Items ofwork excluded from the supplier's scope also should 

### be clearly defmed in the RFQ forthe same reason. For aturnkey scope (design, supply, and erect all equipment, and demonstrate commercial operation while meeting all perfonnance criteria), the excluded work is minimal. In general, the excluded scope can vary significantly depending on the owner's preference to perfonn several items ofwork (e.g., installation/erection ofequipment) through his own engineering andlor construction team. 

### BudgetaryEstimates Based 011 

### PerformallceSpecificatiolls Because preparation ofdetailed specifications involves significanttime and effort (forboth ownerand supplier) and is not critical for budgetary costestimates, an optional perfonnance specification approach may 

### be used in the RFQ. In this approach, the basic required plant and fuel data arc provided along with the required SNCR system perfonnance requirements, excluding equipment-related details (e.g., materials ofconstruction, equipment redundancy, and level ofsophistication in instrumentation and controls). This approach enables the supplierto respond quickly. Using aperfonnance specification approach, the RFQ should ask for a description ofthe system and components in enough detail to understand the type and quality of systemproposed by the supplier. A costbreakdown ofmajor components and subsystems also should 

### be obtained from the supplierto enable independent assessment, deletion, oraddition, and to compare otherbids on anequitable basis.



### 17The SNCR performance specification typically should ask for the following items regarding NOx emission control performance, chemical consumption, and otherconsumption rates at full and 

### partial loads: NO" Emission Control Performance

• Guaranteed and expected NO" emission rates in units ofIblMMBtu and Iblhr with averaging period as defined in the air quality pernlit ofthe facility.
• Guaranteed and expected NH) slip, ppm (other conditions such as dry basis, percent 02' perthe air permit).

• Guaranteed and expected N20 emissions (guarantees needed ifit is a pennit condition).

• Otheremission limits as specified (or anticipated) in the pennit. Chemical and Other Consumption Rates

• Normali7..ed stoichiometric ratio (NSR) proposed to achieve the required NO" reduction.

• Guaranteed and expected urea consumption ratc.

• Guaranteed and expected dilution water consumption rate.

• Atomizing and cooling air (or steam) pressure and consumption rate.

• Guaranteed and expected electrical power consumption. To obtain reasonably competitive costestimates, the RFQ should 

### be sentto at leastthree suppliers. Afterreceiving bids, the designs and costs should 

### be adjustcd, ifnecessary, so that they are comparable.



### 18Chapter 3 Estimation ofSNCR Screening Costs The cost estimating methodology presented here provides atool that can 

### be used to estimate screening-level SNCR costs, thus allowing for comparison with other**NO~** reduction technologies. Actual selection ofthe most cost-effective option should 

### be based on a detailed engineering study and cost quotations from system suppliers. as acquired using the rationale described immediately above in Chapter2. Although the report discusses two reagents, urea and armnonia. the costing procedure is based on the more common and preferred reagent, urea. The capital costs and cost equations were developed based on the cost estimates and equations presented in References [3] and [4]. The capital cost equations developed for this report were derived to correspond to the cost equations for wall-fired and tangentially-fired boilers in Reference [4]. In addition, however, the capital cost equations in this report include the effect of NOx removal, a factor that was not characterized in Reference [4]. The mathematical relationship between capital costs andNOxremoval was developed based on the changes in urea flow rate that accompany different levels ofNOxremoval and associated changes in the urcarelated equipment. With NOxremoval accounted for mathematically, the procedure predicts capital costs that correspond well with the Reference [3] boiler cases. Direct annual costs include the annualized cost ofcapital and the variable costs related to operating the SNCR
.. The annualized cost ofcapital was developed using the estimated capital cost and a capital recovery factor (similar to a capital charge factor in Reference [8]). The variable costs related to operating the SNCR. were developed by predicting the reagent and utility consumption rates and changes to the coal consumption and ash generation rates. These rates (e.g., tons/year) and typical unit costs (e.g., $/too) were used to predict annual costs. Equations for the variable costitems shown in the report were developed from fundamental principles and from correlations ofdata from References [3] and [4]. The correlations are described in Appendix B. The following list summarizes how each variable cost item was developed:



### •

• Reagent consumption rate
- Data correlations were used to develop the NSR and fundamental principles were used to calculate the reagent rate from the NSR. Electrical powerconsumption rate
- Data correlations were used for this factor.



### 19• Water consumption rate and increased coal consumption rate· Fundamental principles were used to calculate these factors based on the reagent ratc.

• Increased ash generation rate
- Fundamental principles were used to calculate this factor based on the increased coal consumption rate. To usc the step-by-step procedure presented in this section for study cost determination, the following data are needed:

• BoilerMW rating,
• Uncontrolled**NO~,** and
•**NO~** removal efficiency. Ifthe boilerMW rating is not known (e.g., an industrial boiler or a cogeneration unit), the equivalent MW rating can 

### be estimated from: 

### MW 

### Q. (MMBlufhr) / 9.5 (68) Use ofthe procedure first involves estimation oftheNSR, ureaconsumption, and urea storage tank size, as described immediately below. Total plant capital and annual costs are estimated in succeeding steps according to the procedures that are outlined subsequently. Estimating the Normalized Stoichiometric Ratio A simplified NSR estimation procedure was developed for this report and is presented below. To implement this cost estimating methodology, this estimating technique is necessary because the actual method used by suppliers to establish anNSR is nol publically available. TheNSR estimating procedure was developed using linearregression and NSR data from References [3] and [4]. Though this NSR estimation procedure is approximate, it is appropriate in this application ofdeveloping study cost estimates. The simplified procedure can 

### be used to estimate anNSRthat is functional, but not necessarily precise, considering the complexity ofSNCR chemistry and the significant effect ofsite-specific factors. The values ofNSR derived using this approach should not 

### be used for equipment design or guarantee purposes. 

### As a first step in estimatingNSR, the required percentageNOxreduction is determined based on the uncontrolled and pennitted stack emission limit values for full load orbase load, using Equation (7): T/Nfb> % 

### IIncontrolledNOx.(/b/MMB/II)- slackNOx(lb/MMB/II) 

## = x 

### 100 NOu(lb/MMBIII)

### 20 (7)Next. Equation 

### (8) is used to estimate the NSR for urea reagent. Its derivation is shown in Appendix B. Equation 

### (8) is valid from 0 to 50 percent NOli reduction: (0.7 

### +2 x 

### NQ»(/b / MMBtu)) x 

### (qNO 

### (%) /100) 

### NSR 

## = ' NQ»(/b / MMBtu) Figure 3·1 provides a graphical representation ofthis NSR estimation method. 

### Example of the NSR Estimation Procedure: (8)

Estimate the NSR for an uncontrolled NO, level of0.46 IblMMBtu and arequired NO, reduction of40 percent: 

### NSR= [(0.7 +2 x 0.46) x (40/ 100»)/0.46= 1.41 

### OtherFactors InvolvedillNSR Estimation: In adesign 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 supplierto more accurately predictthe 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 ofthe boiler, the NSR could decrease. However. ifthe temperature window occurs in the convective section, theNSR may increase.

• Residence time available in the desirable temperature range. The required NSR decreases as the available residence time increases.

• Degree ofmixing between the injected chemical and theNOv-containing combustion gases. TheNSR decreases as the degree ofmixing increases.

• Ammonia slip. Tighter constraints on ammonia slip would dictate lowerNSRs, thereby limiting the achievableNOli reduction.

Reagent 

### Estimating Reagent Consumption and Tank Size Once the NSR is estimated. the reagent consumption rate can 

### be calculated using: 

### cN.:.O,-,xo!,-,,(I.:-b.:.'.::M.::M:::B:::tc::u!.-)x:::=Q""<,,M:::A:::l=B.::tu:..:'.:.":::r!.-) x:::.:-N=S:..:R.:.x.:.MI=l':.!!.R (Ibthr)=- 46.01 x SRT 

### 21 (9)50% 45% 40% 35% 30% 25% 

# , I I 

# I' I 

# I e uc ,on 

## ! 

# I I 

# I 

# I: , 50% 

# I \' I I I 

# I I ---- 45% 

# '.\ I I I I I I ' - _40% 

# I\'..l' 

# 1 I I I 

# I 1-

__ 35% 

# _\ -_"'" I I I 

# I I 

# I 30% \ " _, '

_ _ _ 25%



# .- ' I I 

# 1\-,_" , .......... 1 

# I I ' 

# I 

# \"'-"**,,~'** 

# -·f·-.-_' I 

# I I 

# ','- -.J... 

# I -I'

__ . --... - I

................. 1·-,-... I 

### ---L.._ - .... _-.-.- ...**-.~** 

### '"

_ r:=-::::I 

# I --I - - . L 

# L - - - -. --- 

# - --- 

# -- I ' --, .---

__ - I I I
.. - - - .. - -



# - .,--,----____ I 

# I I

# --I Ir 0.4 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, IblMMBtu 3.0 2.8 2.6 2.4 2.2 It: 2.0 

# '" z 1.8 

# .., .!l .51 1.6 

# .., " Q. 1.4 1.2 1.0 0.8 0.6



### Figure 3-1 Approximate NSR Estimation for Urea 22The molecular weight ofN02 in the denominator, 46.01, is used because the N0 lt emissions, NO"" are given in IblMMBtu ofNO, [2]. Using the estimate forboilerheat input, 

### Q. 9.5 x MW, Equation (9) becomes: Reagent 

### (Iblhr) = 

### NO,.•(Ibl MMBtl/) X 95x 

### MWx NSRx M, 46.01 x 

### SR, (9A)
Forurea, Equation (9A) becomes: 

### I/rea (Iblhr) 6.20 x 

### Nan x 

### MW x 

### NSR Forurea or ammonia solutions, the solution flow rate is: 

### Soll/tion (Ib/hr) = 

### Reagent (Ib/hr) x I 

### ODie("/0) Soll/tion (gph) = 

### Soll/tion (Iblhr) x 7.481 

### (gallft') I p (Ibljt') The total volume stored in the tank, ortanks, is based on the number ofdays ofoperation required: 

### Vol. (gaQ Soll/tion (gph) x 

### No. ojdays x 24 

### hdday (98)
(10) (II)

(12) Note that the tank volume is typically based on full-load operation, so the capacity factor is not included in Equation (12). 

### Estimating theTotal Plant Capital Requirement A procedure for estimating total plant capital requirement forurea-based SNCR systems is presented in this section. The cost estimate for an ammonia-based SNCR systemrequires changes to account for differences in reagent storage and delivery systems and the injectors. (See Chapter 2 for a description ofthe differences in reagent injectors.) The Total Plant Capital Requirement (TPCR) for a urea-based SNCR system includes eosts for the urea tank; circulation, metering, and distribution modules; injectors; new boilerports; and the direct and indirect costs associated with installing orerecting new control equipment. Table 3-1 presents a list ofthe major equipment for a urea-based SNCR system. The most accurate method for obtaining the TPCR is to develop a detailed specification (sec Chapter2), request quotes from SNCR suppliers, and develop a complete cost estimate that accounts for equipment provided by the SNCR supplier and other applicable equipment and appurtenances not within the scope ofthe SNCR supplier's quoted costs. The intent ofthis section, however, is to present a procedure that can be used to develop screening level, study capital-costestimates for SNCR technology. Such 23Table 3-1. Major Equipment List for an SNCR Application Quantity Item Description/Size 

### 1 Urea unloading skid Centrifugal pumps with hoses to connect to rail tank car or truck 

### 1 or more Urea storage tanks Vertical, insulated fiberglass reinfofced plastic (vinyl esterresin) tank, atJ,TIospheric pressure design, and equipped with a vent, caged ladder, roanway, and heating pads I Circulation module Skid-mounted circulation module consistingof: 

### • Circulation pumps
• 

### Electric heaters


### • Insulaled/hcattraced piping and isolation valves for pumps and heaters, instrumentation for now, pressure, and temperature, and a local control panel 

### 1 to 

### 5 Injection zone metering Skid mounted metering module consisting of: (IZM) modules Metering pumps, hydraulic diaphragm type, equipped with a variable speed motordrive 

### • Water boosterpumps, turbine type
• Insulatcdlheattraced piping and isolation and control valves for pumps, instrumentation for flow, pressure, and temperature, and local control panels I Air compressor Rotary type 

### I to 

### 5 Distribution modules Urea solution distribution module consisting of valved connections for urea and atomizing air, an isolation valve and a pressure control valve for the air/urea supply to each injector, a pressure indicator for air/urea supply to each injector, and a flow indicatorfor urea supply to each injector 1 Lot Wall-type injectors Dual-fluid type wall injector, 

### with furnace wall (Consisting panels, and hoses for airand urea supplies of4-12per Lance-type injectors Dual-fluid type lance injector, with furnace wall distribution module) panels, and hoses for airand urea supplies I Lot Piping Between urea unloading skid and urea tank; between urea tank and circulation module; and between circulation module and IZM module(s). Insulatelhcat traced piping, stainless steel
24

### Table 3-1. Major Equipment List for au SNCR Application Quantity Item Description/Size 

### I Lot Piping Between 12M module(s) and distribution modules. Insulatedlheat traced tubing, stainless steel 

### I Lot Tubing Between distribution modules and injectors. Insulatcdlheat traced tubing, stainless steel 

### I Lot Dilution water piping Insulatedlheat traced piping, carbon steel, with isolation and pressure reducing valves 

### I Lot Miscellaneous piping Piping/tubing and valves for flushing water, atomizing air, and control air 

### I Lot Piping supports Structural support steel, including a pipe bridge, for supporting all piping 

### I Lot Economizer outlet MonitorNOu and O2 in the flue gas and provide a emission monitors 

### feedback signal for urea injection control I Lot Instrumentation and Instrumentation and stand-alone, microproccssorcontrols 

### based controls forthe SNCR system with feedback from the plant controls for the unit load, NOx emissions, etc. 

### I Enclosure Pre-engineered, heated and ventilated enclosure for the circulation and metering skids 

### 1 Lot Foundations FOWldations and containment walls for the tank and equipment skids, enclosure, and piping support steel, as required 

### I Lot Platforms/stairways Platform/stairway modifications and additions for access to injectors 

### I Lot Asbestos removal Asbestos removal and reinsulation, for a retrofit installation
estimates can be used t6 compare or screen alternative technologies withoutengaging an SNCR supplier to obtain system cost quotes. This study cost estimating methodology and associated costs, in December 1998 dollars, I are described in the following subsections. The cost estimating

I For infonnation on adjusting these cost estimates to other time periods, refer to the EPA report, Escalation Indexes for Air Pollution Control Costs, and updates thereto, all ofwhich are 

### installed on the OAQPS Technology TransferNetwork (CTC Bulletin Board). Alternatively. the ChemicalEngineeringPlantCostIndex"Equipment"componentpublishedinChemicalEngineering magazine can 

### be used. 

### 25procedures presented follow the recommendations in the 1993 Electric Power Research Institute (EPRI) Technical Assessment Guide [8). 

### Equipment Costs The total process capital cost factors for an SNCR application on a boilerare presented in Table 3-2. These factors arc used to estimate direct and indirect costs. 

### hrstal/alion Costs Direct and indirect installation costs are included in the process capital costs in Table 3-2. 

### TotalPlant CapitalRequirement The total plant capital requirement is estimated using several factors applied to the total process capital cost. These factors follow the EPR! cost estimating methodology and are presented in Table 3-2. 

### EstimatingTotal Annual Costs Total annual costs, including direct and indirect annual costs. arc discussed in this section. No byproductrecovery credits were included because there are no salvageable byproducts generated from the SNCR. 

### DirectA""ualCosts Direct annual costs include variable and fixed costs. Variable direct annual costs account for reagent purchase, utilities (electrical power and water). and any additional coal and ash disposal resulting from the operation ofthe S CR. Fixed direct annual costs include operating and supervisory labor and maintenance (labor and materials). These costs are discussed individually below. Operating and Supervisory Labor Forthe purpose ofthis cost estimate. operation ofthe SNCR is assumed not to require any additional operating or supervisory labor. Maintenance The annual maintenance labor and material cost is assumed to be 1.5 percent ofthe Total Plant Capital Requirement (TPCR). This includes annual replacementofthe injector nozzle tips: 

### Maintenance Cast ($/yr) 0.015 x 

### (TPCR, S/kW) x 

### MW x 1,000

### kWIMW (13) Reagent The annual cost ofreagent purchase is estimated using the urea flow rate calculated above and the following equation: 

### Reagent Cost (Slyr) = 

### (Reagent, gph) x 8,760 

### (hr/yr) x 

### (CF/IOO) x 

### RC(Sigal) (14) 

### 26

# I Description 

### Table 3-2. Capital CostFactors for an SNCR Application
1 Data or Formula Boiler Size (MW) Cost Year 

### !MW

... .



# i December 1998



### ....................................................................................r- .

Direct Costs:**··Totai"·P~ocess··Cap·{tafCo·sts··{$ikw)'·············r···** 

## . 

# I A = 9.0(SlkW) x (25:;:V)O.S17 x (0.66 + 0.0085 x TJNO x) Indirect Costs:

........................................................................................................................................................................................................



### ..

## ~.~~~:.~~ ..

## ~~.~.~~.i.~~.~.~..

## ~.~.~.~? 

# .L
..**~:.~.?.~** 

# 1
.

Engineering and Home Office Fces : 0.1 0 x A Process Contingency (SIkW) 0.05 x A Total Plant Cost Without Pcoject :'. B

## =A 

### +(0.05 

### +0.1 0

### +0.05), A 

## = 1.2, A Contingency ($/kW)

.....................................................................................; .

Project Contingency (S/kW) 0.15 x B Total Plant Cost(TPC) ($/kW) : C Bx 115

.................................................................................... 

## :

.

Allowance for Funds During Construction! 

### AFDC = 0 (typical for SNCR) Total Plant Investment (TPI) ($/kW): 

### TPI = C 

### +AFDC

..........................................................................................................................................................................................................

## ~~~alty~lI~:":~n~c(~I!<""!iO(typi~alf~,~~~~!**~~cr.~""uction~~st(~I!<""!.L?O?~T~L**

# :::i;,t~~~;:;:~:~:::~~i~i$IkW)··~~;;~;~~if~;SNCR) Total Plant Capital Rcquicemcnts ($/kW) 

# i TPCR 

### = TPI x 1.02

### + IC


# • Cost for urea stored at site, Le" the first fill ofthe reagent tanks, using Equation (11) fo,the volume: IC [ Volume (gal) x Cost ($Igal) 

## JI(MW x 1000)



### 27Utilities The estimated electrical power consumption is predicted using equation (15). The equation is derived in Appendix B and shown below: kW 0.47 x 

### NO.", (lbIMMBIlI) x 

### NSR x MW (IS) The annual cost ofelectricity is estimated from the following equation: Eleclriciry Cost ($Iyr) = kWx 8,760 (hr/yr) x (CFIIOO) x EC ($lkW) The annual cost ofwater for diluting the urea is calculated from the water flow rate: (16)

{ Urea 50% (lblhr)} 

# {% urea solution stored Water,gph= x 8.345 (Iblgal) % urea solution injected (17)

For urea dilution from a 50-percent to a IO-percent solution, Equation (17) becomes: Water (gph) [ Urea 50% (Iblhr) 18.345 (Iblgal) 

## 1x 

### 4 Waler COSI ($Iyr) = (Water, gph) x 8,760 (hrlyr) x (CFIIOO) x WC($Igal) (17A) (18) Coal and Ash The additional coal required as aresult ofthe 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. lJ,Coal (MMBtlllhr) Reagent (fbi hr) x 900 (BIllI Ib) ( 100 )

= 1,000,000 (BtllI MMBtll) x % IIrea Sollllion injected 1 (19)
The approximate heat ofvaporization ofwaterat 310°F is 900 BtuIlb, which is arepresentative temperature for flue gas exiting the air heater. 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 OF), the temperature at the airheater exit is used because it is the thennodynamic end point ofthe combustion process. The quantity offuel burned in the boilerdepends on the boiler efficiency, which, in turn, depends on the air heaterexit 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


### 28

### turbine). Becausethe water from the urea solutionevaporates in the boiler, the boilerefficiency decreases. Consequently, more fuel needs to be 

### burned to maintain the required stearn flow. With ureaas the reagent, injected as a 10percentsolution. Equation (19) becomes: 6Cool (MMBllllhr) {[Reagenl (Ib/hr) x 

### 900 (Bll/llb)]/ 

### [1,000,000 (BIl/IMMBIII)]}x9 

### The estimated additional ash to bedisposed ofas aresultofburningadditional coal is: flAsh (Iblhr) 

### (19A)

{ [6Coal (MMBlu/hr) x (Ash(%)1100)]/[HHV(Blu/lb)] } x 

### 10' (BIl/IMMBIl/) (20) 

### Simplifying, flAsh(lb/hr) 6Coal (MMBIII/hr) x [Ash!,,';;) IHHV(Blllllb)] x 

### 10,000 

### The costs ofthe 

### additional coal and additional ash disposal are: Casl aJ additionalcoal 

### ($/yr) 6Coal (MMBlu/hr) x 

### 8,760 (hrlyr) x (CF/IOO) x 

### CC (SIMMBIl/) COSIojadditional ash disposal (Slyr) 

### (20A)

(21)
[flAsh (Ib/hr) x 

### 8,760 (hrlyr) x (CFIIOO) xAC(Sllon)] 

### /2,000 (Ibllon) 

### (22) Combining Equations (20A) and (22): COSIojadditionalash disposal (Slyr) 

### [438 x 6Coal (MMBlu/hr) x Ash% x CFx AC]/HHV 

### (22A) IndirectAnllualCosts 

### In general, indirectannual costs include the capital recovery cost, property taxes, insurance, administrative charges, and overhe3;d. Capital recovery cost is based on the anticipated equipment lifetime and the annual interest rate employed. A system lifetime of20 years is typical for SNCR systems. 29Total indirect annual costs can be expressed as: ( F TAX ) F OV 1/D
. 

### lAC ($

### Iyr) 

## = CRF+ -- x 

### TPCR x 

### MJVx 1,000

### + x Mamtenance 

### 100 100 The capital recovery factor, CRF, is defined by: 

### i(1 

## + if 

### CRF

- --'--'-- (1 

## +i)"

- I (23)

(23A)
As discussed in Reference [9], in many cases property taxes do not apply to capital improvements such as air pollution control equipment. Therefore, FlAX is zero. Further, an SNCR system is not viewed as risk-increasing hardware (e.g., a high energy device such as a boiler or aturbine). Consequently, insurance on an SNCR system is on the order ofa few pennies perthousand dollars annually [9]. The administrative charges, covering sales, research and development, accounting, and otherhome office expenses, incurred in operation ofan SNCR system are relatively insignificant forthe cost estimation procedure presented here. Finally, there are two categories ofoverhead, payroll and plant. Payroll overhead includes expenses related to labor employed in operation and maintenance ofhardware whereas plant overhead accounts for items such as plantprotection, control laboratories, and parking areas. Because this procedure assumes that no additional laboris needed in operation ofan SNCR system, payroll overhead is zero and plant overhead is considered to 

### be negligible. Thus, for the purposes oflhis methodology, FlAX = FOVIlD = 0 and Equation (23) reduces to lAC ($Iyr) = CRF x TPCR x MW x 

### 1,000 (233) 

### TotalAII"ualCost The total annual cost for owning and operating an SNCR systemis the sum ofdirect and indirect annual costs. Annual costs (S/year) can be converted to S/kW-year (S/kWyr) by the following equations. For variable costs (reagent, utilities, coal, and ash), the conversion is: $/kWyr ($Iyr) / [MWx 1,000 x (CFIlOO) 

## 1 Forfixed costs (maintenance and all indirect annual costs), the conversion is: $/kWyr = ($Iyr) / [MW x 

### 1,000)
30 (24)
(24A)

### The tons of

### NO. removed annually are: TNo. = 

### NO" (lbIMMBIII) x('1"""'IOO) xQ. (MMBtulhr) x(CFllOO) x(8,76012000) (25) Or, T NO' 0.000438 x 

### NOx , (lbIMMBIII) X '1NO' x CFx 

### Q" (MMBtulhr) 

### Using aheatrate of9500 BtulkWh, boilerheat input is estimated as 

### QH = 

### 9.5 xMW. Substitutingfor 

### QB. equation (25A) becomes: T

NO> 0.004161 x

### NO" (lblMMBtu) x '1""" x MWx CF 

### The cost in dollars perton of

### NO
.. removed per year is: $Iton NO, Annual Costs ($Iyear) IT NO'

31 (25A)

(258)
(26)

### Chapter4 Summary ofEquations


### Themathematical expressions presented in this report, and associated equation numbers, are summarized below. The summary serves as a reference guide thatcan 

### be used to estimate the cost ofan 

### SNCR system, as illustrated 

### by the example provided in Chapter 5. Design Factors for an SNCR Application 

### (0.7 

### + 2 

### x NOxb(lb / MMBtll» 

### x (TlNO 

### /100)**N~=** x 

### NOXb

### (Ib / MMBIII) Reagent (lb/hr) = 

### [NO", (lbIMMBIlI) X 

### Q. x 

### NSR X MW. 

## 1/(46.01 x 

### SRr ) SO/lltion (lb/hr) = 

### Reagent (lb/hr) x 1000e

### ("A;) So/lIlion (gph) = 

### So/Iltion (lb/hr) x 

### 7.481 / P 

### Vol. (gal) = 

### So/Iltion (gph) x 

### No. of doys x 24 

### hrlday



### 32 (8)
(9) 

### (10) (11) (12)Capital Cost Factors for an SNCR Application 

### Direct Costs: Total Process Capital Costs ($/kW): 

### Indirect Costs: Total Plant Cost Without Project Contingency ($/kW) Totnl Plant Cost (TPC) ($/kW): Total Plant Investment (TPI) ($/kW): Inventory Capital- ($/kW) 

### Total Plant Capital Requirements

Annual Costs for SNCR Application 

### DirectAmmolCosts 

### Maintenance:**B~1.2xA** C=BxI.15 TP/=C+AFDC 

### Volume in gallons x 

### cost per gallon IC

- -----';----....,-''---''--

- (MW x 1,000) TPCR = TP/ x 

### 1.02

### + IC

Maintenance Cost ($/yr) 0.QJ5 x TPCR ($/kW) x MWx 1,000 

### Reagent: Reagent Cost ($/yr) (Reagent, gph) x 8,760 (hr/yr) x (CFIlOO) x RC 

### Utilities: kW 0.47 X NOXh x NSR x MW Electricity Cost ($/yr) kWx 8,760 (hr/yr) x (CFIlOO) x EC 

### (13)
(14)
(15) (16)

Water. { Urea

# 50% (lb /hr)} 

# {% urea solution stored } gph= x -I 

### 8.345 (Ib /gal) 

### % urea solution injected 

### 33 (17)Water Cost ($Iyr) (Waler, gph) x 8,760 (hr/yr) x (CFIIOO) x WC Coal and Ash: !>.Coal (MMBlulhr) Reagenl (lb 1 hr) x 900 (Btu lib) ( 100 )

= 1,000,000 (Btu 1 MMBtu) x % urea Solulion injected

- 

### 1

Cost of additionalcoal ($/yr)

= !>.Coal (MMBlulhr) x 8,760 (hr/yr) x (CFIIOO) x 

### CC ($IMMBtu) Cosl of additionalash disposal ($Iyr) [438 !>.Coal (MMBtulhr) xAsh x CFxAC] IHHV
I"directAllllualCosts lAC($Iyr) CRF x TPCR x MIll x 1,000 

### TotalAlIllualCost (18)

(19)

(21)
(22A)

(236)



### Thetotal annual cost is the sum ofdirectannual costs and indirect annual costs. These annual costs (S/year) can be converted to $/kWyr according to:**$lkWyr~** ($Iyr) I[MIll x 1,000 x (CFIIOO)] (24) T

NO' 

### NO", (IblMMBtu) x(1]No/I00) XQ8 (MMBtulhr) x(CFIIOO) x(8,76012000) (25) $lIon 

### NO, = Annual Cosls ($/year) I TNo.

34 (26)

### Chapter S An Example Calculation

In this example, cost estimates are developed for retrofitting a 500 MW wall-fired boiler with a urea-based SNCR system. The example uses the equations summarized in Chapter 4. The methodology also was used to estimate costs for existing S CR installations. Appendix C shows how these estimated costs compare with costs reported in the literature for several installations. Design Basis A summary ofthe design basis for the 500 MW boilerretrofitted with an SNCR system is presented in Table 5-1. The economic factors for this example are presented in Table 5-2. Most ofthese factors are from References [3] and [4]. However, ifapplicable, other values may 

### be chosen for these factors and used in the cost estimating procedure. 

### Equipment and Consumables Data Based on Equation (8), the estimated normalized stoichiometric ratio, NSR, for 35 percent NOx reduction is: 

### 3S (0.7+2x0.46 

### IblMMBtu) x 100 

### NSR =**------,,"77~=~---=..::-'­** 

### 0.46 IblMMBtu The urea consumption rate using Equation (9B) is: = 1.23



### Urea, lblhr 6.200 x 

### 0.461b1MMBtu x 500 

### MWx 1.23 

### Urea, lblhr= 

### 1,754lblhr The 50% urea solution flow rates using Equations (10) and (II) are:

35

### Table 5-1. Design Data Design Parameters 500 MW Boiler Full load Boilerheat input, MMBtuJhr' 4,750 

### Uncontrolled NOx, 

### IblMMBtu 0.46 

### Required NO x

### reduction, % 35 Fuel HHV, Btullb 12,696 

### Fuel ash weight, % 7.7 

### Annual NO x

### removed, tons/year·· 2,177 

### Stored Urea Reagent 50% aqueous solution Injected Urea Reagent 10% aqueous solution Numberofdays ofurea storage 14 

### Plant Capacity Factor, % 65 ' 'Boilerheat input 9.5 x 

### 500MW = 

### 4,750 MMBtu/h 

### "The annual NO, removed is calculated by Equation (24B).


### 1,754 lblhr Urea 50% 

### solution, lblhr =**"',...",..-.....:7,:;.....:~;;.,--..,..,.,.-** = 

### 3,508 

### lblhr 0.5 /b ureal/b of

### 50% sO/lIIion
Urea solution, gph = 

### 3,508 lblhr x 

### 7.481 

### gallft' 

## = 369.6 

### gph 71 Iblft3 

### The total volume for 14-days ofureastorage using Equation (12) is: Vol 369.6

### gph x 

### 14

### days x 

### 24 

### hr/day = 

### 124,186

### gallons

J 

### This capacity factor is ameasure ofthe average annual use ofthe boilerand SNCR. It 

### accounts for the time when the plantis notoperatingand when itoperates at partial loads. A 65- percent capacity factor is typical ofaload-following plant with an annual outage. A base-loaded plant would have ahighercapacity factor, forexample, 90 percent. 36

### Table 5-2. Economic Factors Cost Year December 1998 Equipment Life 20 years Annual Interest Rate 7% Electrical Power Cost $0.05IkWh Coal Cost, Eastern Bituminous $1.601MMBtu Ash Disposal Cost SIt.28/short ton Urea Cost (50% solution) $0.85/g.lIon Water Cost $0.0004/g.lIon


### The estimated electrical powerconsumption using Equation (15) is: Electricalpowerconsumption 0.47 x 

### 0.46 Ib/MMBIU x 1.23 x 

### 500 MW 133 

### kW 

### The dilution water flow rate using Equation (17A) is: 4.0 x 

### 3,508 Iblhr urea solution Water, gph 

## =**-"'--~~~,--;;=-i-':":"'_'---** 

## = 1,681 

### gph 8.345 Iblgal 

### Theestimatedadditionalcoal requiredtoaccountfortheheatusedtoevaporatewaterintheinjected urea solution using Equation (19A) is: 900 Btullb tJ.Coa/ 

## = 1,754 

### Iblhr urea x**,,=:';;;""~-i.c;;-;;=** 

### 1,000,000 Btu/MMBtu Using Equation (20A), the addition.l ash to be disposed ofis: x 

### 9 

## = 14.21 

### MMBtulhr

tJ.Ash 

## = 14.21 

### MMBwllb x 7.7 x 10,000 = 86 

### Iblhr 12,696 Bwllb Total Capital Requirement 

### The total capital requirement for this example is presented in Table 5-3.


### 37

### Table 5-3. SNCR Capital CosIs

Total Process Capital Costs ($IkW): 9.0 x (:>o.sn x (0.66 + 0.0085 x 35) '" 5.78 

## GencraJi'iiciiiiies(SikW)·····T···o:osxs:iii:;;
..ii:29· 

## ··Eng"iii:ec;·rlIig·ancfHo·m·e·offi(;e··Fees···················r ··· _--_

__ . ($IkW)
. 0.10 x 

### 5.78 0.58 

## Process·Coiiiingeiicy(SikW)······O:oSxs:iii;;;029··· TotalPlant Cost Without Project 1.2 x 

### 5.78 6.94 Contmgency ($/kW)
. 

### ......................-

__ - -_··············

__····

__···

__············t············ _-_

__ .

ProjectContingency ($IkW) , 0.15 x 

### 6.94 1.04 Total PlantCost (TPC) 

### ($IkW): 1.15 x 

### 6.94 7.98**··Aito·wance'fo~··F·un(rs·jjurrng·C·onsiiUci·io·n··T·········** 

# . ($/kW) 0 Total Plant Investment (TPI) ($/kW): 7.98 

## RoyiiiiYAiiowance(SikWjTo" 'PrcprQdociionCost($ikWjT'o:ofxi:9ii;;;Oiir'"

............................................................................................... .

Inventory Capital' ($/kW) 

### 124,186 gals x 

### $0.85Igal = 

### $0.21IkW 500MW x 

### I,OOOkWIMW

...............................................................................................j.
.



### Initial Catalyst and Chemicals ($IkW) , 0 Total Plant Capital Requirement ($IkW): $7.98 

### +$0.16 

### + $0.21

- $8.35



# • Costfor urea stored atsite, i.e. the first fill ofthe ureatanks: Volume in gallons x

### cost per gallon 

### IC($IkW) = -----"------'-----''--- MWx 

### 1,000

Total Annual Costs 

### The 

### annual costs are converted to $IkWyr and $/ton NO, 

### removed by Equations (24), (24A), and (26).
38

### Annual maintenance labor and material costs are calculated belowusing Equation (13) : Maintenance, Slyr 

### = 0.015 x 

### S8.35 x 

### 500 kW x 

### 1,000= S62,625 Iyr Maintenance, SlkWyr 

### = S62,625 = SO.13lkWyr 500 MW x 

### 1,000 kWIMW



### . S62625 

### Mamtenance, Siton NO x removed = ' = 

### S291ton NO x 2,177 ton NO x 

### The total variable direct annual cost (urea, electricity, water, coal, ash disposal) associated with applying SNCRto a 500 MW bailetis detemlined from Equations (14) through (22A): 

### Annual Reagent Cost:

= 

### (369.6 gph) x 

### 8,760 hrlyr x (65/100) x 

### 0.85 (Sigal) = SI,788,8271yr 

### Annual electricity cost:

= 

### 124 kW x 

### 8,760 hrlyr x 

### (65/100) x 

### 0.05 (SlkWh) = S35,3031yr 

### Annual watercost:

= 

### 1,681 gph x 

### 8,760 hrlyr x 

### (65/100) x O.OOO4(S/gal) = S3,829/yr 

### Annual costofadditional coal:

= 

### 14.21 MMBtu/hr x 

### 8,760 hrlyr x (65/100) x 1.60(SIMMBtu) = SI29,4591yr 

### Annual costofadditional ash disposal:

= 

### (438 x 

### 14.21 MMBtulhr x 

### 7.7 x 

### 65 x 

### 11.28 (S/shtan)) 112,696)= S2,7681yr 

### Total Variable DirectAnnual Cost:

= Sl,788,8271yr 

### + S35,3031yr 

### + S3,8291yr 

### + SI29,4591yr 

### + S2,7681yr

= SI,960,1861yr 

### In terms ofS/kWyr, the total variable direct annual cost for the 500 MW boileris caleulated from Equation (24): SI,960,I861yr 

## =**=--,-;--;;;;,;,-,,-'=~** 

### 500 x 

### 1,000 x 65/100 = S6.031kWyr


### In terms of S/ton NOx 

### removed, the annual total variable direct annual cost for this boiler is calculated from Equation (26):
39

## =-:<-S-;:I,9",6.:.:0,-:...18...:,6",lyr" 2,177 Ion NO 

### x = 

### S900 IronNO x


### The total directcosts are summarized in Table 5-4. Table 5-4. Direct Costs 

### Boiler Size 500MW Uncontrolled NO" IblMMBtu 0.46 

### Maintenance 

### $62,6251 yr 

### SO.131 kW-yr 

### S291 ton NO, 

### Total Variable DirectAnnual Costs SI,962,748/yr S6.04IkW-yr S902 

### 1ton NO, 

### Total Direct Cost 

### $2,025,3731 yr $6.17IkW-yr S931 

### 1ton NO,


### With 

### aplant life of20 years and an interestrate of7% (see Table 5·2), the capital recovery factor is 0.09439 (see Chapter 2). Using this factor, the indirectcosts calculated using Equations (23B), (24), and (26) are:

= 

### 0.09439 x 

### S8.35IkW= SO.791kWyr

= 

### SO.791kWyr x 

### (500

### MWx 

### 1,000 

### kW/MW) = 

### S395,0001yr

=S395,000/2, 177 = 

### S181 

### 1tonNOx

### removed/ kWyr These costs are summari7...cd in Table 5-5. Table 5-5. IndirectAnnual Costs 

### BoilerSize 500MW UncontrolledNO" IblMMBtu 0.46 

### Total Indirect Costs S395,000 

### 1yr SO.79 

### 1kW-yr 

### SI81/ton NO,

40

### The Total Annual Costs, presented in Table 5-6 for the example, are the sum ofthe direct and indirectannual costs. Table 5-6. Total Annual Costs 

### BoilerSize 500MW UncontrolledNO
.. IblMMBtu 0.46 Tntal Annual Cost $2,420,373/yr $6.96 kW-yr $l,ll21tonNO



### 41

### References
I. 

### Compilation of AirPollutantEmission Factors, 

### EPA DocumentNo. AP-42, Vol. 1. U.S. Environmental Protection Agency, 1995. 2. Stultz, S.C. and lB. Kitto (cd.) Steam: Its Generation and Use. 

### 40th edition, The Babcock & Wilcox Company, Barberton, Ohio, 1992. 

### 3. Investigation a/Performance and Cost o/NOx 

### Controls asAppliedto Group 2 

### Boilers. 

### Revised Draft Report, The Cadmus Group, Inc., Bechtel PowerCorporation, and Science Applications International Corporation) August 1996. 4. Cost Estimates/orSelectedApplications of NOt Control Technologies onStationary Combustion Boilers, DraftReport andResponses to Comments on the Draft Reporl. 

### The Cadmus Group, Inc., and Bechtel PowerCorporation, June 1997. 5. Analyzing Electric Power Generation Under the CAM. 

### EPA Office ofAir and Radiation, March 1998. 

### 6. SNCRCommittee ofthe Institute ofClean Air Companies, Inc. White Paper, Selective Non-Catalytic Reduction (SNCR)for ControllingNOx 

### Emissions. 

### October 1997. 7. TannerIndustries, Inc. Storage & 

### Handling of Ammonium Hydroxide. 

### Philadelphia. PA, October 1995. 

### 8. Electric PowerResearch Institute. TechnicalAssessment Guide, 

### Vol. 1, Revision 7. 1993. 

### 9. NESCAUM. Status Reporton NOx Control Technologies andCostEffectivenessfor Utility Boilers. 

### June 1998. 10. United States Patent, Method ForThe Reduction Of The Concentration OfNO In CombustionEffiuents Using Ammonia. Inventor: Richard K. Lyon, PatentNumber 3,900,554, August 19, 1975.

42

.'

### 11. Rini, MJ., 

### J.A. Nicholson, and M.B. Cohen. Evaluating the SNCR Processfor Tangentially-FiredBoilers. 

### Presented atthe 1993 Joint Symposium on Stationary Combustion NOx Control, Sal Harbor, Florida, May 24

- 27, 1993. 

### 12. Personal Communicationwith Alex DainofTand Dale Pfaff

### ofFuel Tech on Tuesday, March 16, 1999.

43

## Appendix A.
1.0 FUELS 

## Design/Performance Data for SNCR Retrofiton a 250 MW Wall-Fired Boiler

Eastern Bituminous Coal
Ultimate Analysis (% By Weight) Coal for 250 MW Plant Carbon 72.8 Hydrogen 4.20 Nitrogen 1.34 Oxygen (by difference) 4.76 Sulfur 0.80 

### Moisture 8.40 Ash 7.70 TOTAL 100.00 Higher Heating Value, Btullb 12,696



### 2.0 SNCRSYSTEM DESIGN BASIS 2.1 Boiler


### Boiler Steam Output, percent 100% 

### 70% 30% offull load 

### Boilerheat input, MMBtu/hr 2,604 1,919 885 Flue gas flow ateconomizer 2,658,500 1,960,400 903,500 outlet, Ib/hr Uneontrolled NOx at 0.46 0.46 0.46 economizeroutlet, IbIMMBtu

44

### 2.2 Flue Gas Composition 

### Flue Gas Composition % Vol. Dry 

## N, 80.83 

### CO, 14.97 

### 0, 4.14 

### SO, 0.062 

### Moisture 7.81


### 2.3 Typical Flue Gas Temperature Profile 

### Location 100% Load 30% Load 

### Entering high temperature secondary 2,270 1,970 

### superheater Leaving high temperature secondary 2,030 1,730 

### superheater Entering low temperature secondary 2,030 1,730 

### superheater Leaving low temperature secondary 1,810 1,510 

### superheater Enteringhigh temperature rcheater 1,810 1,510 

### Leavinghigh temperature reheater 1,540 1,240 

### Entering low temperature reheater 1,540 1,240 

### Leaving low temperature reheater 1,420 1,200

45

## Appendix B. 

## Development ofS CR Related Equations
This appendix illustrates the methodology used to develop two ofthe equations presented in this report. They include equations (5) for reagent utilization, (8) for normalized stoichiometric ratio, and (15) for electric power consumption. 

### EQUATION (5)

- Reagent Utilization Because the urea injected into the furnace thermally decomposes to produce ammonia. equation (5) is derived in temlS ofammonia, NH). However, the equation is valid for urea. The definition ofreagent utilization is the ratio ofmoles ofreagent reacted to the moles injected, both in terms 

### ofammonia: Utilization = 

### (moles ofNH J

### reacted) / (actual molesNfl] injected) (B1) According to the chemical reaction shown in Equation (2), the moles ofNH) reacted are the same as the moles ofNO" removed. (Equation (1) shows two moles ofurea per mole**ofNO~** removed. However, the moles ofNH] reacted are also the same as the moles ofNOll removed because two moles ofammonia are released by the urea.) Equation (Bl) becomes: 

### Ulilization = 

### (moles**NO~** 

### removed) I(actual molesNH J

### injected) The moles ofNOll removed are: (B2)



### Moles NO, 

### removed = 

### (moles uncontrolledNO) x (NO, 

### reduction, %)

### /1 00 (83) Substituting Equation (B3) into 

### (82): Utilization = 

### (mQles uncontrolledNO.> x (NOT

### reduction, %) 

### 100 x 

### (actual moles NH, 

### injected) (B4) Rearranging Equation (3), the definition ofNSR, to solve for the moles ofuncontrolled NOx, 

### Moles uncontrolled**NO~** = 

### moles of equivalentNH J/ 

### NSR Substituting Equation (85) into (84): 

### Utilization = 

### (moles of equivalentNH,) x 

### (NO. reduction, %) 

### 100 x 

### (actual males NH, 

### injected) x NSR



### 46 (B5)



### (86)The term, actual moles ofNHJ injected, is the same as the tenn, moles ofequivalentNHJ• used in Equation (3). Therefore, Equation (B6) becomes Equation (5):
NOx reduction (%) Utilization 

## = 100x NSR 

### EQUAnON (8)

- Normalized Stoichiometric Ratio (NSR) (5)

Equation (8) is derived from data in References 2 and 3. The form ofthe NSR equation was selected to nonnalize the data with NOxefficiency by dividing the reported NSR by NOx efficiency. Therefore, the correlation was performed on NSR divided by 

### (NOx efficiency/IOO) versus lI(NO, inlet Ib/MMBtu). The table below shows the data from References 2 and 3 and the calculated values**ofNSR/(~NoJIOO)** and lINO,. 

### NO! in, IINOx

### in NSR NO,**NSR/(~No/IOO)** 

### Reference Ib/MMBtu 

### removal, % lAO 0.714 0.900 35.000 2.571 2 lAO 0.714 0.900 34.615 2.600 2 0.95 1.053 0.900 34.737 2.591 2 0.92 1.087 0.900 34.783 2.588 2 1.20 0.833 0.900 35.000 2.571 2 1.20 0.833 0.900 35.000 2.571 2 

### 0045 2.222 1.750 50.000 3.500 3 0.50 2.000 1.750 50.000 3.500 3
The <"NSRJ(TlNo/l00)" and 

### "IINOx" were correlated using a linearregression. The results ofthe regression (using Microsoft Excel's Data Analysis Tool) are:

• Slope 0.7
• Intercept = 2
• Correlation coefficient, r = 0.969 The equation is: 

### -:-_N._SR,..,.-,-:c-

## =2

## +0.7 x ( 1 )**(~/l00)** 

### NOXb(lbl MMBtll) NOX 47 (31)Multiplying both sides ofthe equation by 11"";100 and multiplying the right hand side by 

### (NOxt! NOXb) yields Equation (8): (2x NO
.. (/bl MMBlu)

### +0.7) x (qNO 1100) NSR = ., NOxh(/bl MMBtlI) 

### EQUAnON (15)

- Electrical Power Consumption (8)

Equation (15) is derived from data in References 2 and 3. The table below shows the data from these references and the calculated constant, 

### (N0Xb x 

### NSR x MW). Boiler 

### NO.b,

### NO. in, 

### NSR MW kW (NO.a! XNSR x Ref. IblMMBtu MW) 100MW 0.95 0.90 100 25 85.50 3 wet bottom IIOMW 1.20 0.90 110 51 118.80 3 vertical 150MW lAO 0.90 150 67 189.00 3 cyclone 259MW 0.92 0.90 259 109 214.45 3 wet bottom 220MW 1.20 0.90 220 95 237.60 3 vertical 348MW 0045 1.75 348 157 274.05 4 

### tangentially -fired 381 MW 0.50 1.75 381 193 333.38 4 wall-fired 400MW lAO 0.90 400 205 504.00 3 cyclone
The terms "(NOXb x NSR x MW)" and "kW" weTC correlated using a linear regression stipulating that the intercept is zero. An intercept ofzero is used so that kW equals zero 

### ifthe (NOXt, x NSR x MW) term is zero. The term. (NOXb x NSR x MW), was used in the correlation because the 

### urea now ratc depends on it 

### (see Equation 9) and the powerconsumed is related to the urea flow rate. The results ofthe regression (using Microsoft Excel's DataAnalysis Tool) arc:

48Slope 0.47 

### Correlation coefficient, r= 

### 0.930 

### The equation from the correlation is:**kJV~** 0.47 x N0x> (/b/MMBtu) x NSR x 

### MJV (15)



### 49

## Appendix C. Comparison ofResults from Methodology with Industry Case Studies Using the methodology ofthis report, this appendix presents calculated results for existing SNCR installations. The calculated results are compared with the case studies in Chapter4 of Reference C-I. i.e, data reported for these SNCR installations by the Northeast States for Coordinated Air Usc Management (NESCAUM) and the Mid-Atlantic Regional Air Management Association (MARAMA). Variables from the example case (Chapter 5) were used in the methodology for these calculations. These variables are defined in Table C-I. Other input data were based on data reported for the facilities considered. These input data, predicted NSRs. and the comparison ofpredicted costs with reported costs are shown in Table C-2.
Table C-t. Variables from the Example Case Used in Table C-2 Fuel HHV, Btu/lb 12,696 Fuel ash weight, % 7.7 Number ofdays ofurea storage 14 Annual Interest Rate 7% Electrical Power Cost $0.05/kWh Coal Cost, Eastern Bituminous $1.60IMMBtu Ash Disposal Cost $11.28/shorl ton Urea Cost (50% solution) $0.85/gallon 

### WaterCost $0.0004/gallon


### Thepredictedcosts shown interms ofS/too ofNOxremoved are based on an assumed discount rate of7 percentto be consistentwith the methodology presented in this report. 1b.is assumption is necessary because the referenced report [C.1] did not indicate the discount rate used by each utility. Although the representativeness ofthese comparisons is uncertain because ofthis assumption, they provide the readerwith some indication ofhowpredicted values may compare with reported ones.

50

### Table C-2. Comparison ofNESCAUM Data [Reference C·ll with Results Estimated Using the Urea-Based SNCR Costing Methodology Parameters Salem Montaup Bl England 1 Bl England Bl England 3 Seward Mercer 1 Mercer 2 Harbor2 Somerset 2 Input Data Boiter Size, MW 84 112 130 160 160 147 321 321 Uncontrolled NOx, 0.6 0.8 1.2 1.2 0.3 Design: 0.75 1.8 1.8 Ib/MMBtu Operating: 0.7 NOx Reduction, % 50 53 29 29 33 Design: 40 33 33 Operating: 36 Predicted NSR 1.58 1.51 0.75 0.75 1.44 Design: 1.17 0.8 0.8 Operating: 1.08 Capacity Factor, gO gO 50 50 10 70 43 48 % Project Life, Yrs 5 15 15 15 15 5 20 20 (assumed) Capital Recovery 0.2439 0.1098 0.1098 0.1098 0.1098 0.2439 0.09439 0.09439 Factor Comparison of Predicted Values with Those Reported in Reference C-1 (in 1996 Dollars) TPCR, $/kW Predicted 26 22 17 15 15 17 11 11 Reported in (C-1 J 18 -16 15.4 12.5 9.37 -23 14 14 Total Annual Costs, $/ton 

### NOx Removed Predicted 1,242 771 816 786 5,427 1,224 603 593 Reported in IC-1] 670 900-1000 No data No data No data -1,775 -800 -800 5\Notes for Table C-2: 1. The input data in Table C-2 are from Reference C-l, with the following exceptions:
• The capital recovery factor is calculated using the 7% interest rate and the pertinent 

### project life.

• The project life for Montaup is assumed. See Note S. 2. The costs predicted using this report's methodology have been adjusted to 1996, the approximate year ofthe Reference C·l costs. The downward adjustment was based on the Cbemical Engineering Plant Cost Index, reported to be 390.4 for December 1998 and 381.7 for 1996. 

### 3. The Capital Recovery Factor is based on an assumed interest rate of7%. 4. SNCR 

### systems were installed on Salem Harbor Units 1,2, and 3. Only Unit 2 is included in Table C-2 because the costs reported for Units 1 and 3 included other technologies, such as Jow-NOx burners, Qverfire air, and burner management systems. The Unit 2 costs are representative ofSNCR alone. 5. ForMontaup, the project life was assumed to be 15 years. This is equal to the period used in the methodology sections ofReference C-l (Chapters 

### 1to 

### 3). However, Chapter 

### 4 ofReference C-I (the case studies) does not state that control costs in S/tonNOx reported for Montaup are based on a IS-year project life. 6. The SNCR at Seward has a more complex injection system than other installations. This results in a higher actual capital cost [C-I]. 

### 7. SNCR systems were installed on Mercer Units 

### 1 and 

### 2. Although there is a shared 250,000 gallon urea 

### tank, the two units have independent SNCR systems. Any reduction in capital and levelizcd costs because ofthis shared tank should 

### be minimal. Reference C-l J. E. Staudt, "Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers", published by Northeast States for Coordinated AirUse Management (NESCAUM) and Mid-Atlantic Regional Air Management Association (MARAMA), June 1998.



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