srivastava.ravi@epa. 03:04 PM 5/29/98 , draft SNCR chapter
To: srivastava.ravi@eparnail.epa.gov From: Chuck Young <cyoung@cadmusgroup.com> Subject: draft SNCR chapter Cc: mkrasnop@bechtel.com Bcc: Attached: C:\Eudora\Attach\sncr-wp.doc; Ravi, The text of the draft SNCR chapter is attached. Although the draft is very thorough, there are a few items where we noted that contents would be included in the final chapter (or revised draft, whichever terminology you prefer). I have also included blank pages so that you can drop in the figures and the page numbering will be consistent with the table of contents. As you know, I converted a Word document to generate the Word Perfect document. Some of the resultant formatting is not ideal, but we will fix that in the next version. I hope you are pleased with the draft and I look forward to working with you and Bechtel in completing the document. Chuck

Printed for Chuck Young <cyoung@cadmusgroup.com> 1

### To: 

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### Waltham. MA 02154 Telephone: (781) 894·9830 Tclcrax: (781) 894-7238
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### Figure 11.2-1 Urea SNCR Process Flow DiagramUrea Injectors

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### Figure 11.4-2 Total Process Capital Multiplier for NOx Reduction Efficiency

## Chapter 11 (Draft 

### May 29, 1998) 

## SELECTIVE NONCATALYTIC REDUCTION FOR NOx 

## CONTROL

May 1998

SNCR 11-1 file date 

### 29-May-98

## Contents
11.1 INTRODUcrION 

### 3 11.l.! SNCR SYSTEM EFFICIENCIES AND PERFORMANCE ......•.....•.....•.......... 4 11.1.2 FACfORS AFFEC11NG SNCR PERFORMANCE ..........••.....•.........•..... 5 

### 11.2 PROCESS DESCRIPTION ...............................•..•. 7 11.2.1 UREA-BASED SNCR PROCESS .........•.....•....••....•................ 7 11.2.2 SNCR EQUIPMENT ..............•...••....••....••...•............... 10 

### 11.3 DESIGN PROCEDURES 13 11.3.1 STEP I: DETERMINING DESIGN INPUT DATA AND SELECfING SYSTEM PARAMETERS 13 11.3.2 STEP 2: REAGENT SELECfION 14 11.3.3 STEP 3: SELECfING THE NORMALIZED STOICHIOMETRIC RATIO (NSR)
. . . . . . . . . .. 16 11.3.4 PREPARING SNCR SYSTEM PERFORMANCE SPECIFICATIONS 20 

### 11.4 ESTIMATING THETOTALPLANT CAPITALREQUIREMENT
. 22 11.4.1 EQUIPMENT COST 23 11.4.2 INSTALLATION COSTS ...........................•...••....••....••..... 24 11.4.3 TOTAL PLANT CAPITAL REQUIREMENT ..................•.....•.....••..... 24 

### 11.5 ESTIMATINGTOTAL ANNUAL COSTS •..•.............•.... 27 11.5.1 DIRECfANNUAL COSTS .............................•.....•.....•..... 27 11.5.2 INDIRECfANNUAL COSTS .....••...••....•.....••...••••...••....•...... 29 11.5.3 RECOVERY CREOITS ....................•.....•....••....•.....••...... 30 11.5.4 TOTAL ANNUAL COST .............•....••....•.....•................... 30 

### 11.6 EXAMPLE PROBLEMS 30 11.6.1 DESIGN BASIS INPUT DATA .........•..........•....••.....•............ 31 11.6.2 EQUIPMENT DATA ...............•.....•.....•....••....••.....•...... 31 11.6.3 TOTAL CAPITAL REQUIREMENT ....••...••••..••••..•••...••••..••••..... 32 11.6.1 TOTAL ANNUAL COSTS ...........•....•.....•.....•.....•.....••....... 34 

### 11.7 ACKNOWLEDGMENTS .•......•...•......•..•.....•....... 40 11.8 REFERENCES 40 Anpendix A DesignIPerfonnance Data for SNCR Retrofit on a 250 MW and 750 MW Wall-Fired 

### Boiler [To beprovidedinjinal version of chapter.]

SNCR 11-2 file date: 

### 29-May-98

## 11.1 Introduction
Selective noncatalytic reduction (SNCR) technology has been used commercially to control nitrogen oxides (nitric oxide, NO, and nitrogen dioxide, NOb together referred to as NOJ emissions from several sources burning various fuels, including industrial boilers, electric utility steam generators, thermal incinerators, and municipal solid waste energy recovery facilities. Several factors affect the design, performance, and costs ofSNCR systems. This chapter on SNCR technology provides a step-by-step approach for developing order-of-magnitude capital 

### and operating cost estimates that can be 

### used to compare SNCR with 

### alternative NOxcontrol techniques. The Electric Power Research Institute (EPRl) developed and patented the urea-based SNCR technology in 1980. Ithas been licensed to NALCO Fuel Tech (NFT), which holds several additional patents that claim improvements and enhancements to the basic process. NFT has several implementers 

### (as sub-licensees) authorized to supply and install the system in several industry sectors. NOxis one ofthe major air pollutants emitted when fuels are burned in combustion devices with high flame-zone temperatures. There are mainly two modes ofNOx**generatio~thermal** NOx and fuel NOx' Chemical combination ofnitrogen and oxygen 

### in the combustion 

### air at high flame temperatures generates thermal NO

### x ' Thermal NO

### xis generated even iffuel-bound nitrogen is absent or negligible. This is the case when natural gas, which has almost no fuel-bound nitrogen, is fired in a boiler. The second mode ofNOx generation involves the chemical combination (at low 

### as well as high temperatures) offuel-bound nitrogen with oxygen 

### in the combustion air. NOxemissions to the atmosphere arc regulated under two titles ofthe Clean Air Act 

### Amendments of 1990:

• Title IV

- Acid Rain

• Title 

### I - Ozone Non-attainment Various control technologies such 

### as 10w-NO

### xburners, combustion modifications, selective 

### catalytic reduction (SCR), and SNCRhave been developed to comply with these requirements. Several industrial sources are using these technologies, either individually, or in combination to reduce NOx emissions. 

### This chapteraddresses SNCR tcchnology with emphasis on developing order-of-magnitude cost estimates. The approach presented here should be used as an initial screening ofalternative NOx control technologies. In selecting a control technology or a combination oftechnologies, several criteria are usually applied:

• Remaining life ofthe facility or combustion device

• Degree ofNOx reduction required

• Uncontrolled or baseline NOx concentration 

### SNCR 11-3 file date: 29-May-98

### • Available space

• Reliability ofthe 

### technology

• Demonstrated experience in that particular industry sector with its specific fuel and combustor type



### • Capital and operating costs. The main objective ofthis 

### chapter is to describe important features ofSNCR technology, including process design methodology, and to present an order-of-magnitude cost estimation approach to compare SNCR with alternative NOx

### control techniques. This chapter is based the usc ofureaas the SNCR reagent. The design and costs are similar for an ammonia-based SNCR. 

### 11.1.1 SNCR System Efficiencies and Performance In the SNCR technique, NO, reacts with injected urea (CO(NH,),), or ammonia (NH,) within a temperature range of 1,600

- 2,1 00 of to produce nitrogen (N,), carbon dioxide (CO,), and water (H,O): 2NO 

### + CO(NH,), 

### + Y, 0,

- 2N, 

### + CO, 

### + 2H,O 2NO, 

### + CO(NH,), 

### + 0,

- 3N, 

### + 2CO, 

### + 4H,0 

### Note that most (over 95 

### percent) ofthe 

### NOxemitted in utility boilers is NO; therefore, Equation I 

### governs the actual reduction process. (Eq. I) (Eq.2)



### Equation I 

### is asimplified representation ofthe 

### actual, quite complex series ofover40 

### chemical reactions. The process is further complicated because the boiler is designed to generate steam and is not ideal for the mass transfer and chemical reaction steps ofthe 

### SNCR process. Therefore, eventhough Equation I 

### indicates that ahalfmole ofurea is required to remove one mole 

### ofNO, 

### in practice, over two times that amount is needed to achieve ahigh degree 

### ofNO

### x reduction in a

### boiler. The uncontrolled orbaseline NOxemissions from large boilers with heat inputs greater than 100 million Btulhour (MMBtu/hr) firing coal range from about 0.5 to 2.1 Ib NOxlMMBtu heat input, or about 300 to 1,260 parts per million (ppm by volume), depending on several factors such as 

### boilertype, burnerdesign and operation, fuel composition, and excess air. The costs in this chapter 

### arc based on retrofitting existing coal-fired, dry bottom, wall-fired, balanced draft boilers 

### with SNCR equipment. However, the general cost estimation approach is applicable to other types ofboilers 

### and other fuels, with appropriate adjustments. The uncontrolledNOx 

### emissions from older coal-fired, dry bottom, wall-fired boilers 

### arc generally in the 0.45 to 0.6 IblMMBtu range, i.e., 270 to 360 ppm. 

### The SNCR technique has been shown to achieveNOx

### reduction efficiencies ofup to 80 

### percent in selected short-tenn demonstrations. but typically is considered to 

### be capable of30 to 50 percentNO

### xreduction, depending on anumber offactors. The following is 

### alist ofmajor SNCR 11-4 file date: 

### 29-May-98design, operational, and other factors that affect the NOx reduction perfonnancc ofthe SNCR system:

• Reaction temperature range (window) available within the boiler superheater (radiative and convective section) and primary reheater (convective section or cavity) region.

• Residence time available in the desirable temperature range (1,600

- 2,100 OF).

• Ratio ofinjected chemical reducing reagent (urea, ammonia) to baseline NOx.
• Degree ofmixing between the injected reagent and the NOx-containing combustion gases.

• Uncontrolled NOx concentration level.

• Allowable ammonia slip, i.e., NH3 concentration in the treated flue gas exiting the boiler. Other factors that affect NOx reduction using SNCR include plant load variation and its effect on the location in the boiler ofthe proper temperature window, use ofchemical additives and enhancers to broaden the temperature window, and the concentration ofcarbon monoxide (CO) 

### in the flue gas. 

### 11.1.2 Factors Affecting SNCR Performance Further discussion ofeach ofthe factors affecting SNCR pcrfonnance is provided below. 

### Iemnerature Window The NOx reduction reaction with urea is effective in a narrow temperature range (window) of approximately 

### 1,600 to 

### 2,100 OF. At temperatures below 

### 1,600 OF, the reactions are very slow and generate mainly ammonia. At temperatures above 

### 2,I00 of, however, NOx is generated. The NOx reducing agents (urea, ammonia) have to 

### be injected in the boiler where the combustion gases are within this narrow temperature range. Compared to urea, ammonia injection requires a temperature window that is about 

### 100 OF lpwer. 

### Resjdence Time Ayailable Adequate residence time within the temperature window is required for the SNCR process to work effectively. Time is required for the injected urea solution to 

### mix with the flue gas; for water to evaporate; for the solid urea to decompose to NH2, CO, and free radicals; and for the NOxreduction reactions to occur. Thus, with more residence time available for the various mass transfer and reaction steps, more NOx is removed. The boiler gas path dimensions (from the upper furnace region through the superheater/reheaters to the convective backpasslprimary reheater region) and flue gas velocities through these regions affect the available residence time.



### SNCR 11-5 file date: 29-May-98

### Stoichiometric Ratio Based on Equation I, theoretically, two moles ofNOx can be removed with one mole ofurea. However, in practice, substantially more urea has to be injected to obtain a specified degree of NOxreduction. The excess urea overthe stoichiometric amount is destroyed, mostly through otherchemical reactions. A small portion remains in the flue gas as unrcacted ammonia (also commonly referred to as ammonia slip, usually 5 to 50 ppm in the boiler exit flue gas). One byproduct ofthe chemical reactions is nitrous oxide, N2

### 0, which typically ranges from 10 to 20 percent ofthe NOxremoved with limiting values up to 30 to 40 percent. With higher temperatures and longer reaction times N2

### 0 emissions will 

### be under about 10 percent. Forease ofcomparison, the normalized stoichiometric ratio, NSR, is defined as: NSR = actual mole ratio ofurea to uncontrolled NOx theoretical mole ratio to reduce I mole ofNOx 

### (Eq 3)
Because, theoretically, 

### it takes a halfmole ofurea to reduce I mole ofNOx' the above definition can be rewritten as: NSR = actual mole ratio ofurea to uncontrolled NOx 

### 0.5

= 2 x actual mole ratio, ureaINOx 

### (Eq.4)

The utilization ofurea can 

### be calculated from the NSR and the NOxreduction efficiency: Utilization = 

## NUx reductiQn. % 100 x NSR 

### (Eq.5)
Thus, the quantity ofurea actually used is substantially higher than the theQretical or ideal urea requirement due tQ practical limitations on available residence time, inadequate mixing, nonideal temperatures, and loss ofurea to side reactions. Higher NSR values generally result in increased NOxreductiQn, but incremental efficiency gains diminish as the NSR increases. Generally, NSRs range between 0.5 and 1.8 for urea injection in large industrial and utility boilers. 

### Det:rec ofMjxjnt: ForefficientNOxreduction, the injected urea solution must rapidly mix with the combustion gases. There arc two main types Qfequipment used for urea injection:

• Wall injectors (e.g., for small boilers)

• Lance injectors which protrude into the flue gas flQW The urea solutiQn may 

### be pressure atomized or air/steam atQmized in a dual-fluid atQmizer nozzle. There arc two ways ofdispersing the solution droplets. A IQw-energy system uses little
SNCR 11-6 fiJ,

## "at" 29-May-98

"

### orno pressurized air or steam for atomization. Otherwise, a high-energy system provides large amounts ofcompressed air or steam to the injectors to inject and mix the solution. When combined with the lance-type injectors, these high-energy mixing systems impart adequate momentum to the solution droplets to penetrate large distances for thorough mixing in large boilers. Obviously, more electrical power (forcompressed air) or steam is consumed using the high-energy system. 

### Baseline NOx Concentration NOx 

### reduction performance ofan SNCR system depends on the uncontrolled (baseline) NOx 

### concentration. With otherconditions constant, the percent ofNOx reduction decreases as uncontrolled NOx

### concentration decreases. This is especially true when the uncontrolled NOx 

### levels approach 100 

### ppm or lower. 

### Allowable Ammonia Slip In the SNCR technique, the limitation on allowable ammonia slip places a constraint on NO

### x reduction performance. Ammonia slip limits are imposed by permitting authorities because 

### ammonia released into the atmosphere above certain concentration levels is considered hannfuI 

### to public health. Furthermore, prudent design practice limits ammonia slip to avoid problems in the downstream equipment. Injection ofurea at higher NSR values can improve 

### NOxreduction, but may also increase the unreacted ammonia releases. Depending on the fuel sulfurcontent and sulfur trioxide (SO) 

### generated, ammonia slip could also cause plugging, fouling, and corrosion problems in the downstream equipment (air heater, ducts, fans, etc.) due to formation and deposition ofammonia·sulfur salts (sticky and corrosive ammonium bisulfate and ammonium sulfates). In recent years, several state regulators have allowed only 2 

### to 5 

### ppm ofNH) slip (compared to 

### 10-20 ppm allowed earlier), thus limiting SNCR system performance. 

## 11.2 Process Description
Reduction ofNO

### xfrom flue gas, using the SNCR technique, involves 

### arelatively simple concept-use ofa chemical reducing agent such as urea (or ammonia) to selectively react 

### with NOx 

### and generate otherproducts such as elemental nitrogen, carbon dioxide, and water vapor: Urea 

### + nitrogen oxides 

### + oxygen (air)

- nitrogen 

### + carbon dioxide 

### +water vapor (at 

### 1,600-2,100 OF) In practice, though, it is challenging to design an SNCR that is reliable, economical, simple to control, and meets othertechnical, environmental, and regulatory criteria. 

### 11.2.1 Urea-based SNCR Process In large industrial and utility boilers. the uncontrolled or baseline 

### NOx 

### concentration levels are relatively low -{in hund.rcds ofppm). Further reduction ofthese low levels created engineering challenges for the industry. Alternative NOx

### control technologies available include combustion SNCR 

### 11-7 file date: 

### 29-May-98

### modifications (e.g., reduction ofexcess air, flue gas recirculation, staged combustion, burnersout-of-seIVice). use oflow-NOxburners, and SCR. The SNCR process can be used alone or as a supplement to the other processes. The main advantages ofSNCR include:

• Relative simplicity

• Ease ofretrofit

• Avoidance ofcostly catalyst consumption in the SCR system However, the NOx reduction capabilities ofSNCR are limited compared to the SCR system. These limitations are explained below. There are four main steps involved in the operation ofthe urea-based SNCR process:

• Receiving, storage, and recirculation ofthe urea solution (50 percent urea)

• Metering, dilution, and mixing ofthe urea solution (50 percent urea)

• Injection ofthe diluted urea solution (e.g., 10 percent urea) in the boiler radiative and convective regions (1,600 (0 

### 2,100 OF)



### • Mixing/dispersion in the flue gas, evaporation ofwater, decomposition ofurea, and reduction ofNOx Step I. A simplified process flow schematic is presented in Figure 11.2-1. Urea (50 percent by weight) is received via a tank-truck or rail car and is pumped into a storage tank or a few tanks. Higher strengths ofurea solution are available, but their freezing temperatures are lower, so a 50 percent solution with 64 

### OF freezing point is typically selected as a good compromise. (Ammonia may be received as aqueous ammonia or anhydrous NH3.) 

### The urea solution is then pumped to the circulation module where the urea solution flows through an in-line electric heater (to prevent freezing ofthe solution in cold climates) and duplex strainerto the injection zone metering (lZM) module. Filtered plantwater (less than 50 mg/l suspended solids and low dissolved solids) is mixed with the metered amount ofurea solution so that after mixing, the final urea solution is delivered as a 10 percent solution (or other selected dilution level) to the urea distribution module, which is typically located close to the boiler. Step 2. Each 12M 

### 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). It 

### can adjust solution flow rates, and activate injection zones ordeactivate them in response to changes in outletNOxconcentration, boiler load, or fuel quality. Diluted urea solution is finally transported from the 12M 

### modules to the distribution modules, which direct the solution to each injector. Each module contains flow meters, balancing valves, gauges, and regulators to control the solution injection process. 

## SNCR 11-8 file date: 

### 29-May-98

### Blank page for Figure 11.2-1



### SNCR 11-9 file date:: 

### 29-May-98Step 3. Next, the diluted urea solution is injected at one or several zones in the boiler at appropriate temperature levels (within the temperature window). The injectors may be ofthe pressure atomized or dual-fluid (air or steam) atomized type. The injector nozzles arc specially designed to meet plant-specific conditions. Step 

### 4. Finally, the solution is dispersed, and the water is vaporized so that urea can decompose to produce NH3, NH2, and other free radicals. They, in tum, react with NOx and reduce it to N2, CO2, and water. The boiler radiant (secondary superheater and rcheater region) cavity and convective cavity (primary superheater and reheater area) act as a chemical reaction chamber. Thus, NOx reduction in the SNCR process occurs entirely within the boiler. Since the boiler is not designed for the SNCR process, this design aspect presents a unique challenge. It is especially challenging to design for retrofit cases because the design flexibility is substantially reduced compared to that for new boilers. In an existing boiler, the injectors must be located in available open areas, for example, between the superheater and reheater sections. These conditions are illustrated in Figure 11.2-2. Mixing ofthe reagent is critical to proper perfonnance ofSNCR, and is especially challenging in large boilers. Ifmixing and distribution ofthe reagent throughout the flue gas is inadequate, the unreacted anunonia and ammonia slip increase. There are several ways to ensure adequate mIxmg:

• Use ofseveral injectors at several locations within the boiler's optimum flue gas temperature window (I ,GOO
- 2,100 

### OF). For existing boilers, temperature and velocity measurements should be made along with computational fluid dynamic (CFD) modeling to detennine the optimum number ofinjectors, locations, and other details.

• Use ofmore than the nonnal amount ofair for atomization ofthe reagent solution. There are two types ofmixing-low-energy mixing with the nonnal amount of atomization air, and high-energy mixing with substantially more than the nonnal amount ofatomization 

### air. The extra air 

### in the high-energy mixing option acts as a transport medium to induce better dispersion ofthe reagent solution throughout the flue gas.

• Use ofbetter atomizer nozzle design to obtain optimum solution droplet size distribution, spray angle, and direction. 

### 11.2.2 SNCR Equipment Types ofequipment used for each ofthe four majorprocess steps involved in the SNCR system, their function, and alternatives (ifapplicable), are briefly presented below. 

### Chemical**StQra~e** For urea-based systems, the urea solution (50 percent by weight) is received by 

### tank trucks or rail car and pumped into a storage 

### tank. The closed top, flat bottom, vertical 

### tank is usmllly made of 

## SNCR 11-10 file date: 29-May-98

### Blankpage for Figure 11.2-2

SNCR 11-11 file dale: 

### 29·May-98

### fiber reinforced polyester and has a corrosion barriercoating on the inside made ofpremium grade vinyl ester resin. The tank should have level and temperature indicators, roanway, vent, access ladder, and other appurtenances. The need for heat tracing, insulation, and seismic design criteria are determined based on site-specific conditions. The tank(s) should 

### be surrounded by a 

### spill containment structure (usually dikes). Skid Mounted Modules Thedilution water pressure cootrol module, urea supply/circulation module, IZM module, and distribution module are skid mounted on stainless steel bases. 1b.is 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. The circulation module is a fully equipped high-flow, high-head reagent solution delivery system designed to supply filtered urea solution to the IZM module. The main functions ofthis module include filtering the solution to avoid clogging ofthe injectors, electric heating to preventthe solution from freezing, maintaining continuous circulation ofthe stored reagent, and having a local/remote control and monitoring station for the storage 

### tank and circulation system. This module contains:

• Two full-flow multistage SS centrifugal pumps

• In-line duplex strainers

• Electric heater

• Pressure, flow, temperature, and level instrumentation and controls If

### plant water is not available at the properpressure, a dilution water pressure (DWP) control module, typically consisting oftwo full-flow multistage SS centrifugal pumps, in-line duplex strainer, pressure control valves, and the required pressurelflow instrumentation is used. Through 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 SNCRprocess demand signals. Each IZM module includes a chemical metering pump, a water pump, an in-line static mixer, a local control panel, chemical and water magnetic flow meters, zone isolation valves, and chemical and watercontrol valves. The mixed and diluted urea solution is transported from the IZM to the distribution modules, which direct the solution to each injector. 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 SS tubing to adequately control the urea injection process. The urea solution flows from the distribution modules to the injectors. Considering the two types ofreagent injectors, the wall-mounted injectors generally have a shorter range for the injected urea solution droplets to penetrate the boiler interior and 

### mix with 

### SNCR 11-12 fil, du, 

### 29-May-98NOx than do the lance-type injectors. Ifthe droplets are big, they have greater momentum and penetrate longer distances, but the droplets also take longer to evaporate the water. Since urea does not decompose and react with NOx until the water in the urea solution evaporates, optimization ofthe droplet size and injector locations is required for maximum NOx reduction. However, even with droplet size optimization, the wall-mounted injectors arc better suited for small boilers (or low NOx reductions 

### in larger boilers) since the distance from the wall to the center ofthe gas flow path is smaller. For electric utility boilers, the corresponding size range may be about 50 to 80 MWe. The main advantage ofthe wall-mounted injectors is that they arc not fully exposed to the hot (1,600 to 2,100 

### OF) fiue gases from the boiler furnace. Lance-type injectors overcome the limitation ofthe wall-mounted injectors so that these injectors can 

### be used in large industrial or utility boilers. They can be fixed type or retractable type, and can include several nozzles. The lance-type injectors (both fixed or retractable) are generally cooled by air 

### (or steam) to maintain structural integrity under high-temperature conditions. Some multi-nozzle lances for the convective pass are water cooled. 

## 11.3 Design Procedures
A general approach to the conceptual design ofa urea-based SNCR system is presented here to generate and illustrate adequate system design input parameters and 

### data to allow preparation of system perfonnance specifications and order-of-magnitude cost estimates. These estimates should 

### be 

### used to compare urea-based SNCR with similarestimates for otherNOx reduction options, thus allowing for screening ofseveral options. Selection ofthe most cost-effective option should 

### be based on a detailed engineering study and quotations from the system suppliers. Detailed process and equipment design is not the objective oftms section. 

### 11.3.1 Step 1: Determining Design Input Data and Selecting System Parameters The following data are needed to initiate the SNCR design process: Plant Data-

• The boiler capacity 

### in tenns ofheat input rate (MMBtuIhr), or ifan electric utility boiler, then its equivalent MW (electric power) output capability can be used to estimate the boiler heat input. Heat input = MW x 1000 kW/MW x NPHR, where NPHR Net Plant Heat Rate, BtulkWh (ifnot known, 10,000 is a reasonable estimate).

• Boiler load profile

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

• Type ofcombustion unit

- dry/wet bottom boiler, wall-ftred, tangentially-fired, cyclone fired, other; year built, and manufacturer.

SNCR 11-13 file date: 29-May-98• Existing or planned baseline NOx emission data without the proposed SNCR system, ppm or Ib/MMBtu ofNOx and CO. including the impact ofother installed or planned technologies (e.g.,low-NOxburner, gas recirculation, overfire air, etc.).

• Air preheater design and operational data, including sootblower data.

• Fuel Data

- primary and secondary fuel, analysis, and high heating value 

### (illIV); fuel firing rates at full and panialloads (e.g., 100 percent, 70 percent, and 30 percent).

• Test Data or Combustion Calculations

- flue gas flow rate at design (or actual) excess airrate at full and partial loads. flue gas composition including 02. NOx, CO, SO" and HCI; net plant heat rate (BtulkWh).

• Boiler Dimensions

- sectional side view; sectional front view; plan section through fumacc (width x depth); furnace hcight (floor to furnace exit); firing zone height; sections through radiant and connective heat transfer cavities (zones); other unique features

- e.g.• division walVpancls. etc., in the furnace or backpass.

• Locations ofboiler furnace overfire air ports.

• Locations and sizes ofboiler observation ports. temperature probe ports, sootblower openings, and other locations for potential new ports.

• Flue gas temperature profile from furnace exit to economizer (Le.• 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 (temperature window 1.600 to 2,100 OF) at various loads.

• Minimum expected NOx reduction orpermit requirement for stackNOx emission level (ppm or IblMMBtu). The boiler supplier/manufacturer can furnish most ofthese items for existing orplanned new units. For fuel data, the designer needs typical and/or design values as well as the expected range. For temperature profile in existing boilers, it is preferable to obtain actual data from temperature measurements (ratherthan predictions). Also, flue gas velocity measurements. combined with boiler upper furnace and convective pass dimensions, will yield residence times available for NOxreduction reactions. 

### 11.3.2 Step 2: Reagent Selection Urea and ammonia are acceptable proven reagents in terms ofcost, storagelhandling, safety, byproducts generated, and proven capability. Although several years ago, ammonia use for SNCR systems was common, some state permitting authorities have recently discouraged the use ofammonia because ofhealth and safety concerns. Anhydrous ammonia, a gas at nonnal atmospheric temperature, is transported and stored under pressure. Aqueous ammonia is a solution ofammonia in water (usually 30 percent ammonia strength), which 

### has substantial vapor pressure at nonnal air temperatures, as shown 

### in Table 11.3.1. SNCR 11-14 fiI' dat" 29-May-98The optimum temperature window for the SNCR process with ammonia is about 100 

### OF lower than with urea (1,500 to 2,000 

### of for ammonia instead of 1,600 to 2,100 

### of for urea). Depending on the location ofthe proper temperature window in the boiler, this temperature difference could reduce the reaction rates and residence time available in the boiler. Because ammonia is highly volatile, low-energy atomizers cannot be relied upon for thorough mixing of the injected ammonia and the flue gas. Ammonia droplets vaporize rapidly in the vicinity ofthe atomizer tip without entraining much flue gas. Thus, more elaborate injection systems are usually required with ammonia. Urea solution, however, does not vaporize rapidly and 

### can usually be used with low--energy atomizers. Ammonia usc has certain advantages over urea. First, ammonia is generally known to produce less N2 

### 0 (nitrous oxide, a greenhouse gas) than urea. It is also less expensive than urea. Properties ofurea are listed in Table 11.3-I. Many utilities on the east coast have selected urea because ofits better health and safety properties in transportation, handling, and storage, and because the approval from permitting authorities is simplified. 

### Table 11.3-1. Urea and Ammonia Reagent Properties Property Liquid or gas at normal air temperature 

### Concentration ofreagent normally supplied Molecular weight ofreagent Ratio ofNHJ to solution Density ofsolution 

### @ 60 

### OF Vapor pressure 

### @ 80 

### OF Crystallization temperature Flammability limits in air Threshold limit value (health effects) Odor Acceptable materials for storage 

### Urea Solution Liquid 50% (by weight) 60 (as NH,CONH,) 28.3% (by weight ofNH,) 9.5 Ib/gal. 

### < I psia 64 

### OF Non-flammable Not specified Slight (ammonia-like) Plastic, steel, or stainless steel 

### (no copper or copper-based alloys or zinc/aluminum fittings) 

### Aqueous Ammonia Liquid 29.4% (by weight of NH,) 17 (as NH,) 29.4% (by weight of NH,) 7.5lb/gal. 13.9 psia' -110 

### OF 16-25% NH, (by volume) 25 ppm Pungent odor 

### @ 5 ppm or more Steel tank, capable of handling at least 25 psig pressure 

### (no copper or copper-based alloys, etc.)

SNCR 11-15 file date: 29·May-98

### 11.3.3 Step 3: Selecting the Normalized Stoichiometric Ratio (NSR) Because capital and operating costs are dependent reagent usc, 

### it is an important parameter in SNCR system design. As described earlier. because ofthe complexity ofthe actual chemical reactions involving NOx and injected urea (or anunonia), significantly more urea needs to be injected into the boiler flue gases to obtain a specific level ofNOx reduction. Thus, the actual NSR is much morc than the ideal value ofthe NSR. Several factors affect the value ofNSR, including:

• Percent NOx reduction.



### • Uncontrolled or baseline NOx level in the flue gases.

• Temperature and residence time available within the optimum temperature 

### window (1,600

- 2,100 

### OF) for the NOxreduction reactions.

• Extent ofmixing achievable in the boiler.

• Allowable ammonia slip.

• Rates ofcompeting chemical reactions. Given this complexity and the fact that most available SNCR technology 

### was developed on a proprietary basis, open technical literature does not provide details ofthe theory and correlations that can 

### be used to estimate the required NSR on a quantitative basis. The publicly-available technical literature provides some qualitative indication ofthe effects ofvarious factors (temperature, residence time, etc.). Adding to this complexity is the fact that NSR is highly site·specific because the controlling factors (temperature profile, fuel, fluid dynamics, chemical kinetics, and the boiler as a chemical reactor) arc site-specific. The current prevailing design approach is to provide all ofthe plantlboiler-specific data 

### (as described above in Section 11.2.1) to the SNCR system supplier,**~ho** uses prior experience, Computational Fluid Dynamic (CFD) and Chemical Kinetic 

### Modeling (CKM) to derive the required NSR. CFD and CKM are computermodels thaI simulate the operation ofan SNCR in a boiler. CFD includes a finite element model ofthe 

### boiler's physical dimensions as well as the fluid dynamics ofthe flue gas. CFD and CKM together define the flue gas temperatures, velocities, densities, and chemical compositions ofthe SNCR process in the boiler. They model the NO

### xreduction 

### as the flue gas flows from the furnace exit to the economizer. These models assist the system supplier in detennining the available residence time and reaction rates 

### so that 

### urea injectors can be sized and located. The SNCR design can be optimized by running several cases, varying the important parameters. 

### Once optimized, the syslem supplier 

### can predict the expected NSR. 

### In lieu ofthis detailed approach, a simplified approach is presented below which 

### can be used for rough order-of-magnitude cost comparisons between alternative NOx control methods. The purpose ofthis procedure is to develop an estimate for the NSR that is functional, but not necessarily precise, considering the complexity ofthe series ofchemical reactions and the site

### SNCR 

### 11·16 file date: 29-May-98

### specific factors. The values ofNSR derived using this approach are not to 

### be used for equipment design or guarantee purposes. NSR Estimate. Step 1 

### First, estimate percentNOxreduction required based on the Wlcontrolled and permitted stack outlet emission limit values (in lb/MMBtu units) 

### for full load (or base load) ofthe boiler: 

### %

### NOxreduction required = 

### uncontrolled NOx - stack N0x- x 100 (Eq.6) Wlcontrolled NOx Next, use Equation 7to estimate the NSR for abascline NOx

### of0.5 

### lb NOxIMMBtu. Equation 7 is valid from 0 

### to 50 

### percentNOxreduction: NSR(0.5 Ib /MMBtu) = 

### 0.010 x**~NO'** 

### + 0.00055 x**~NO/** 

### (Eq.7) 

### where "NOx = 

### %

### NOxreduction NSR Estimate. Step 2 The NSR value obtained in Step I (for a baseline NOx

### of0.5 IblMMBtu) is adjusted for the actual baseline NOx

### by multiplying it by the factor, M. defined in 

### Table 11.3-2. NSR NSR(0.5 IblMMBtu) x 

### M 

### (Eq. 8)

Table 11.3-2 

### NSR Multiplier (for NOx 

### baseline from 0.2 to 2.0 IblMMBtu) NOx, 

### IblMMBtu Less than 0.5 

### Greater than 0.5 

### Multiplier, M 

### (0.5/N)°" (0.5/N)°·1l where N 

### baseline NOx, 

### Ib/MMBtu 

### Figure 11.3-1 provides agraphical representation 

### ofthis NSR estimation method. NSR Estimation Examples:



### 0.00055 x 

### 40' 1.28 NSR (0.5 lb/MMBtu) = 

### 0.01 x 

### 40 

### + Multiplier (0.5/0.46)°·· 1.03 Estimated NSR = 

### 1.28 x 

### 1.03 = 

### 1.32 Estimate the NSR for a baseline NOx

### of0.46 IblMMBtu and a required NOx

### reduction of 40 percent: I. 

### 2.

SNCR 11-17

### Blank page for Figure 11.3-1

SNCR 11-18 filo
.....,

### 29-May-98

### 0.00055 x 

### 30' = 

### 0.80 NSR (0.5 IbIMMBtu) 0.01 x 

### 30 

### + Multiplier (0.511.5)'·" 0.85 Estimated NSR = 

### 0.8 x 

### 0.85 = 

### 0.68 NSR (0.5 IblMMBtu) 0.01 x 

### 50 

### + 0.00055 X 

### 50' = 

### 1.88 Multiplier (0.5/0.2)°·' 1.44 Estimated NSR 1.88 x 

### 1.44 = 

### 2.71 Estimate the NSR for abaselineNOxof1.5 IblMMBtu and a!cquired NOx reduction of 30 percent: 1. 

### 2. Estimate the NSR for a baseline NOx of0.2 IblMMBtu and arequired NOxreduction of SO percent: 

### 1. 

### 2.

In practice, the NSR sbould be 

### adjusted by the design parameters ofthe boiler and other variables, such as:

• 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, if

### the window occurs in the convective section, the

### NSR may increase.



### • Residence time available in the desirable (1,600 - 2,100 

### OF) temperature range. The required NSRdecreases as the available residence time increases.

• Degree ofmixing between the injected chemical and the NOxcontaining combustion gases. For thorough mixing, the NSR decreases.

• Allowable ammonia (NH)) 

### slip. Lowerpennitted values ofammonia slip require lower NSRs and could limit the achievable NOx reduction. Estjmatim: Urea Consumntion and Tank Size 

### Once the NSR is estimated, the ureaconsumption rate can be calculated: Urea, lblhr = 

## N..1!Sl0 x 

### NSR x 

### 60,06 46 x 2 

### (Eq.9)
where N 

### baseline NOx, IblMMBtu 

### Q. boilerheat input, MMBtu/hr 60.06 = 

### molecular weight ofurea 46 molecularweight ofNO, (i.e., NO,J. 2 = 

### factor for a50% solution

'* 

### Although mostNOx is NO, the molecular weight ofNO] is used 

### in the calculation ofmoles of NOx· 

### SNCR 11-19 file ""., 29-May-98Urea 50% solution, lb/hr (Urea, Ib/hr) 

### 10.5 (Eq. 10) (Note: For concentrations otherthan 50 percent, usc the proper factor 

### in the denominator ofEquation 10.) Urea solution, gph

- (Urea 50% solution, Ib/hr) x 7.481 

### 17\ where 7.481 gallons per 

### ft' 71 = density ofa 50% urea solution, Ibltt' 

### (Eq.ll)

The total volume stored 

### in the tank ortanks is based on the number ofdays ofoperation required: Vol. (gal.) (Urea solution, gph) x (No. ofdays) x 24 hr/day (Eq. 12) Note, the volume is typically based on full-load operation and so the capacity factor is not included in Equation 12. 

### 11.3.4 Preparing SNCR System Performance Specifications To estimate capital and operating costs for an SNCR system, the system should be 

### defined in adequate detail. This, in tum. requires care in system design so that major cost items are isolated and can be estimated. As stated earlier, the objective ofthis chapter is to enable development of rough order-of-magnitude cost estimates for the SNCR system. The system design, therefore, need not 

### be detailed, but all major aspects must be adequately defined. SNCR systems are usually designed by an SNCR system supplier based on boiler owner-provided design input data and specifications
.. The supplier quotations help provide realistic design and system costs. The owner then adds its cost items (system integration/interface engineering, supervision, direct and indirect overhead) to estimate total costs. These costs can be used to compare SNCR with other NO,; control options. This supplier design approach is especially appropriate with the SNCR system, due to the proprietary nature ofthe process and resulting lack ofpublicly accessible design data and correlations. 

### SNCR System Specification Considerations This subsection describes issues that should be considered in preparing SNCR system perfonnance specifications used to request cost quotations from SNCR system suppliers. To obtain a good quotation from the SNCR system suppliers, it is imperative that the request contains sufficient details to minimize design assumptions by the supplier. The request for quotation (RFQ) includes the technical specification, as well as commercial tenns and conditions. Section 11.3.1 lists design input data. The uncontrolled and desired NO, emission levels should 

### be provided at full load and selected partial loads at which the boiler is expected to operate for significant time periods. It is also


### SNCR 11-20 file date: 29-May-98critical to specify the allowable byproduct emission rates, especially the ammonia slip. Some permitting authorities may impose emission limits on N20 as well. The hoiler owner should specify thc preferred NOx reducing reagent-generally urea. In special situations, a small percentage ofadditive chemicals may be recommended by the SNCR system supplier to improve performance or reduce scaling and corrosion. The supplier should be requested 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 important parts ofthe specification describe the scope ofsupply:

• Work included in the scope ofthe supplier

• Work not included (i.e., work done by the owner or his architectengineer/constructor) The more precise and detailed the specification ofthe work included, the betterthe overall system design and cost. However, for the purpose ofan order-of-magnitude cost estimate, it is sufficient to provide broad specifications for major items. Items ofwork excluded from the supplier's scope should also be clearly defined in the RFQ for the same reason. For a turnkey scope (design, supply, and erect all equipment, and demonstrate commercial operation while meeting all performance criteria), the excluded work is minimal. In general, the excluded scope can vary significantly depending on the owner's preference to perform several items ofwork (e.g., installation/erection ofequipment) through his own engineering and/or construction team. Since preparation ofdetailed specifications involves significant time and effort (for both owner and supplier) and is not critical for order-of-magnitude costestimates, a second option is to use a performance specification approach in the RFQ. In this approach, the basic required plant and fuel data are provided along with the required SNCR system performance requirements, excluding equipment-related details (e.g., materials ofconstruction, equipment redundancy, and level ofsophistication in instrumentation and controls). 

### This approach enables the supplierto respond quickly. The RFQ underthis perfonnance specification approach should ask for a description ofthe system and components 

### in reasonable detail to know the type and quality ofthe system proposed by the supplier. 

### A cost breakdown of major components and subsystems also should be obtained from the supplier to enable independent assessment, deletion, or addition, and to compare other bids on 

### an equitable basis. The SNCRperformance specification should typically ask for the following items: NO
.. Emission Control Performance

• Guaranteed and expected 

### NOxemission rates in units ofIblMMBtu and lb/hr with averaging period 

### as defined in the air quality permit ofthe facility. 

## SNCR 11-21 file date: 29-May-98• Guaranteed and expected NH3 slip, ppm (other conditions such as dry basis, percent O2, perthe air pennit).

• Guaranteed and expected 

### N 2

### 0 emissions (guarantees needed ifit is 

### apennit condition).

• Other emission limits as specified (or anticipated) in the pennit. 

### Chemical and Other Utilities Consumntion Rates

• Nonnalized stoichiometric ratio (NSR) proposed to achieve the required NOx reduction.

• Guaranteed and expected urea consumption rate.

• Guaranteed and expected dilution water consumption rate.

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

• Guaranteed and expected electrical power consumption. The above-stated data and guarantees should be requested for full and partial loads. To obtain reasonably accurate cost estimates, the RFQ should be sent to at least three suppliers. After receiving bids, the designs and costs should be adjusted, ifnecessary, so that they are comparable. 

## 11.4 Estimating the Total Plant Capital Requirement The Total Plant Capital Requirement (TPCR) for an SNCR system includes costs for the urea tank, circulation, metering, and distribution modules, injectors, new boiler ports, and the direct and indirect costs associated with installing or erecting new control equipment. Table 11.4-1 presents a list ofthe major equipment for an SNCR system. These costs, in first-quarter 1998 dollars, are described in the following subsections.· The costs presented in this chapter are based on the Electric Power Research Institute (EPR!) Technical Assessment Guide. Consequently, they differ in some respects from the way costs are presented in other chapters ofthis manual:

• The "purchased equipment cost" and "direct installation cost" in this chapter will be presented as one cost, "total process capital" in the EPRl fonnat.

• For infonnation on escalating these cost estimates to more current dollars, refer to the EPA report, 

### Escalation IndexesforAirPollution Control Costs, and updates thereto, all ofwhich arc installed 

### onthe OAQPS Technology TransferNetwork (CTC Bulletin Board). Alternatively, the Chemical Engineering Plant CostIndex published in 

### Chemical Engineering magazine can be used to escalate these cost estimates.


### SNCR 11-22 file date: 29-May-98• The costs for the instrumentation (part ofthe cost manual's purchased equipment cost) and all ofthe items under the cost manual's "Direct Installation Cost" (foundations, erection, electrical, piping, insulation, and painting) will be estimated based on thc engineering quantities and scope ofwork (and adjusted ifnecessary for completeness) instead ofusing the cost manual's percentage. These arc included in EPRI's total process capital. The indirect installation costs are similar for the two methods except for the following:

• The cost manual's "construction and field expenses" arc included in EPRI's total process capital.

• Under the EPRI method, contingencies are percentages ofthe total process capital instead ofthe cost manual's purchased equipment cost.

• EPRJ's general facilities, a percentage ofthe total process capital, is similar to the cost manual's site preparation and buildings.

• The cost manual's startup and perfonnance tests are included in EPRI's preproduction costs, which are a percentage ofthe total plant investment (i.e., total process capital 

### + indirect costs).

• EPRJ's method includes Inventnry Capital, the cost to fill the urea tank for the first time.

• The cost manual includes 3% sales tax on purchased equipment. Using the EPRI method, sales taxes are included in process capital.

• Maintenance, both materials and labor, will be taken as 1.5 % ofthe total capital investment per year Table 11.4-1 SNCR Major Equipment List 

### [This table will 

### beprovidedin thefinal version of the chapter.] 

### 11.4.1 Equipment Cost The Total Process Capital Costs for wall-fired boilers are presented in Table 11.4-1. These costs are based on the 250 MW and 750 MW cases presented in Section 11.5. Process capital includes purchased equipment cost and direct installation cost. The Total Process Capital (TPC) can be estimated by the following equations: TPC($/kW) 10.87 x (250/MW)0.27 x NOx",j x Eff"' j (Eq. 13) where: MW = equivalent MW electric power output capability at full load 

### NOl<",j is a multiplier for the 

### NOxbaseline above 0.5 IbIMMBtu, using the following equation, valid from 0.5 to 2.0 IbIMMBtu. ForNO

### xbaselines below 0.5 IblMMBtu, the multiplier is 1.0. For NOx baselines above 0.5 IblMMBtu, the multiplier is: 

### NOxodj = 0.89 

### + 0.24 

### x NO"",

- 0.040 

### x (NOx",)' (Eq. 14) SNCR 11-23 

## m, dol, 29-May-98Eff adj is a multiplier for the NOxreduction using the following equation, valid 

### from 25 

### to 50%: 

### EIT,,; 0.66 

### + 0.0085 x (NOx reduction, %) These equations are graphically depicted in Figures 

### 1104-1 and 1104-2. 

### 11.4.2 Installation Costs (Eq. IS)

The direct installation costs are included in the Process Capital Costs in Table 1104-1. The indirects are also presented in Table 

### 1104-1. 

### 11.4.3 Total Plant Capital Requirement The total plant capital requirement is estimated from several factors applied to the total process capital cost. These factors follow the EPRI cost estimate methodology and are presented in Table 11.4-1. 

### TABLE 11.4-1. CAPITAL COST FACTORS FOR SNCR ON DRY-BOTTOM BOILERS

Boiler Size (MW) 

## i MW 

# CostVearTChemicafEngioeeringpi;;;;iCosi TiQ9S7388 Index 1 Djrect Costs: f

### :foiaiProcessCapiiaiCosis($ikwY:1A;;jo87~(2507MWjoi;xNO~:; : (Eq. 13) x Eff",; (Eq. 14)

# 1~d.jE~~q:;~~t~:mmmmGeneraiFaeifiiies(SikWj+O:05xAmmmmm.mm........m 

# ·EngineeringandHomeOffice·Fees·($ikWjTo:joxX· ·processConiiligeneY·(SikWjToo5 xX· Total Plant Cost Without Project Contingency ($/kW) 

### i B - 1.2 x A 

# ··projeeiconiingeneYC$ikWj··!oTS-x·i3·· Total Plant Cost (TPC) ($/kW): 

## i C

- B x 1.15 

# Aiio;;;;;;;ecforFundsDuiiogConstruciionCSikWjTAFDC:;;O(iypieaiforSNCR) Total Plant Investment (TPI) ($/kW): 

### ! TPI- C 

### + AFDC 

# RoyaiiyAiio;;;;;;;ceCSikw)!oCiypieaiforSNCR) preproduci·ion·CostC$ikWj···To·oixti'j fnvenioi:;;Capiiilj·($ikWjjjc······· fniiiafcaiaiysianifci1eiiiieais($ikWjTO(iYiiieaiforSNCR) Total Plant Capital Requirements ($/kW): : TPCR

- TPI x 1.02 

### + IC *Cost for urea stored at site, i.e., the first fill ofthe urea tanks: SNCR 11-24 file dale: 29-May-98Blank page for Figure 11.4-1

SNCR 11-25 fit, <!at, 

### 29-May-98

### Blank page for Figure 11.4-2

SNCR 

### 11-26 m'daIe,29-May-98

### IC Volume in gallons x cost per gallon (e.g., SO.85/gal.) + (MW 

### x 1,000). As shown in Table 11.4-1, the total process capital is adjusted by the factors in Equations 14 and 15. 

## 11.5 Estimating Total Annual Costs The total annual costs presented in this chapterare based on the economic factors in Table 11.4-2. However, 

### ifdesired, othervalues for these factors can 

### be used in the procedure. 

### TABLE 11.4-2 

### ECO OMIC FACTORS Cost Year 3'" Quarter 1998 Chemical Engineering Plant Cost Index 388 Useful Life 20 years Plant Capacity Factor 

### 65% 

### Carrying Cbarges 9.439% Lcvelization Factors 1.0 Maintenance Cost 1.5% (ofcapital) Electrical Power Cost SO.05/kWb Coal Cost: Western Subbituminous SI.06IMMBtu Eastern Bituminous 

### SI.60IMMBtu Ash Disposal Cost Sl1.28/short ton Urea Cost (50% solution) 

### SO.85/gallon Operator Cost S24.82/person hour Water Cost SO.0004/gallon Numberofdays ofurea storage 14 

### 11.5.1 Direct Annual Costs Direct annual costs include operating and supervisory labor, reagent, maintenance (labor and materials), utilities (electrical power and water), and any additional coal and ash disposal 

### resulting from the operation ofthe SNCR. These costs are discussed individually below. 0ncratiOl: and 

### SuncrvisoO' Labor Forthe purpose ofthe cost estimate, operation ofthe SNCR does not require any additional operating or supervisory labor.

SNCR 11-27 file date: 

### 29-May-98Rcaccnt 

### The annual cost ofurea is estimated using the urea flow rate calculated in Section 11.3.3 and the following equation: Annual Urea cost = 

### (Urea, gph) x 8,760 hr/yr

### x CF/IOO x UC 

### where Urea. gph is urea 

### solution flow rate from Equation II. CF = 

### capacity factor, % 

### UC = 

### Urea cost, S per gallon ofsolution (e.g., 

### 50'10 by weight) Maintcnancc 

### (Eq.16)



### The annual maintenance labor and material cost is assumed to 

### be 1.5 

### percent ofthe 

### Total Plant Capital Requirement (fPCR). This includes replacing the injector nozzle tips annually: Maintenance 0.015 x (fPCR, S/kW) x MW x 1,000 Utilities 

### (Eq.I7)



### The estimated electrical power consumption is predicted using the following equation: kW 0.9 x Nx NSR x MW where N baseline NOx, IblMMBtu NSR = 

### normalized stoichiometric ratio from Equations 7 

### and 8 

### MW = 

### equivalent 

### MW electric power output capability at full load 

### The annual cost ofelectricity is estimated fTom the following equation: Annual electricity cost = 

### kW x 8,760 hr/yr x 

### CF/lOO x EC 

### where CF = 

### capacity factor, % 

### EC Electricity cost, S per kWh (Eq.18)

(Eq.19)



### The annual cost ofwater for diluting the urea is calculated from the water flow rate: Water, gph = 

### 4,0 x (Urea 50%, lblhr) 8.345Ib/gal. (Eq.20) 

### where the 

### factor of4.0 accounts for diluting from 50% to 10%. Forother percentages, the factor is:
% 

### Urea solutioo stored - 1 

### % urea solution 

### injected SNCR 11-28 file date: 

### 29-May-98

### Annual water east (Water, gph) x 8,760 

### hr/yr x 

### CF/IOO x WC 

### where 

## we = 

### Water cost, $ per gal. 

### CQal and Ash (Eq.21)



### The estimated additional coal required as aresult ofthe 

### heat used to evaporate the water is estimated using the following equation:**~Coal** 

### 9 x 

### (Urea, Iblh) x 

### 900 Btullb 

### 11,000,000 (Eq.22) where**~Coal** = 

### MMBtulh ofadditional coal 

### Urea, IbIhr the solid urea flow rate from Eq. 9. 

### 9 = 

### factor for a 50% 

### stored urea solution and a 10% injected solution (9 accounts 

### for the total water injected, both the water in the 50% solution and in 

### the dilution water). For other percentages, the factor is: 1/ 

### (% urea solution injected) -1. 

### 900 = 

### approximate 

### heat ofvaporization ofwater, Btullb The costs afthe additional coal and additional ash disposal are: Annual 

### cost ofadditional coal**~Coal** 

### x 8,760 

### hr/yr x 

### CFIlOO x CC wherc CC is the cost ofcoal, SIMMBtu 

### Annual cost ofadditional ash disposal = ACoal x 1,000,000 Btu/MMBtu x Ash/l00 )( 8.760 brlyr x CF/IOQ x AC HHV x 2000 

### Ib/ton OR

= 438)( ACoal x Ash x CF x AC HHV 

### where Ash = 

### %

### ash in the coal HHV Coal higherheating value, Btullb AC Ash disposal cost, 

### S/short ton 

### 11.5.2 Indirect Annual Costs (Eq.23)

(Eq.24)



### Indirect 

### Annual Costs include the capital recovery cost, which is based on the anticipated equipment lifetime and the annual interest rate employed. (See Chapter2 for athorough discussion ofthe 

### capital recovery cost and the variables that determine 

### it.) For SNCRs, asystem lifetime of20 years is typical. The capital recovery factor of0.09439 is based on a 20-year life 

### and a 7 percent annual interest rate. As Chapter 2 indicates, a suggested factor of4 percent ofthe Total Plant Capital Requirements is
SNCR 11-29 fiJ'dat,29-May-98

### used for annual property taxes, insurance. and administrative charges. Finally. the overhead is calculated as 60 

### percent ofthe maintenance laborand materials estimated by Equation 17. 

### 11.5.3 Recovery Credits There 

### are no recovery credits that apply to S CRoperation. 

### 11.5.4 Total Annual Cost The total annual cost for owning and operating an SNCR system is the sum 

### ofthe components listed below:



### • Direct annual costs

• Indirect annual costs These annual costs (S/year) can 

### be converted to S/kW-yearand S/ton NOx 

### removed by the following equations: S/kW-yr

- S/yr I (MW x 1,000 x CF 1100)**TNO<~Nx** 

### 'lNO</IOO x 

### Q. x 1,000,000 x CF 1100 x 8,76012000 Or 

### TNOx = 

### 438 x N x TlNOx 

### XQB x 

### CF

where MW = 

### equivalent MW electric power outputcapability at [uHload CF = 

### capacity factor T

NOx = 

### short tons 

### ofNOxremoved per year N= baseline NOx, IblMMBtu TlNOx = 

### %

### NOxreduction Q. = boilerheat input, MMBtulh 

## 11.6 Example Problems (Eq.25) (Eq.26)

(Eq.27)

The examples that follow illustrate the procedures deseribed above. They inelude the 250 MW 

### and 750 MW base cases used to develop the procedure, as well as two 250 MW sensitivity cases at 0.3 and 1.5 IblMMBtu NOx baseline. 

### The examples use the equations presented in Section 11.2, 11.3, and 11.4.
SNCR 11-30 file date: 

### 29-May·98

### [Thefinal version o/the chapter will incorporate all units in the equations.] 

### 11.6.1 Design Basis Input Data A summary ofthe 

### design input data for two boilers ofdifferent capacity retrofitted with SNCR systems is presented in Table 11.6-1. The economic parameters are as previously presented in Table 11.4-2. Table 11.6-1 SNCR Example Design Data
Full load Boiler beat input, MMBtuIbr Uncontrolled 

### NOx , IblMMBtu 

### Required NOxreduction, % Fuel HHV, Btullb 

### Fuel ash weight % 

### Annual NOxremoved, tons/year·
·The annual NOxremoved is calculated by Equation 27. 

### 11.6.2 Equipment Data Normalized Stoichiometric Ratio 

### The estimated nonnalizcd stoichiometric ratio, NSR, is: 250MW 2,604 0.46

40 12,696



### 7.7 1,364 

### 750MW 8,275 0.46

40 8,020

6.4 4,335

I. NSR (0.5 IblMMBtu) 0.01 x 40 

### + 0.00055 X 40' 1.28 (Equation 7) 2. Multiplier = 

### (0.5/0.46)°' = 1.03 (Table 11.3-2) Estimated NSR 1.28 x 1.03 = 1.32 (Equation 8) 

### Estimating Urea Consumvtjon and Tank Size 

### The urea consumption rate for the 250 MW boiler using Equation 9 is: Urea, Iblh 0.46 Ib/MMBtu x 2.604 MMBlulh x 1.32 x 60.06 Iblmole urea 46 Ib/mole 

### NOx x 2 1,032 Ib/h 

### The urea solution flow rates for the 250 MW boilerusing Equations 10 and 11 are: Urea 50% solution, Ib/h 1,032lblh

### 10.5 2,064 Ib/h Urea solution, gpb 2,0641b/h x 7.481 galJft' 1711b1ft' = 217.5 gpb

SNCR 11-31 m, dat" 29-May-98The total volume for 14-days ofurea storage for the 250 MW boiler using Equation 12 is: Vnl. 217.5 gph x 14 days x 24 hlday 73,100 gallons 

### The urea consumption ratc for the 750 MW boiler is: Urea, Iblh 0.46 x 8,285 x 1.32 x 60,06 46 x 2 3,280 

### Iblh The urea solution flow rate for the 750 MW boiler is: Urea 50% solution, 

### Iblh = 3,280/ 0.5 6,560 

### Iblh Urea solution, gph 6,560 x 7.481 /71 691.2 gph 

### The lotal volume for 14-days ofurea 

### storage for the 750 MW boiler is: Vol. 691.2 x 14 x 24 hlday 232,200 gallons 

### 11.6.3 Total Capital Requirement The total capital requirements for the 250 M\V and 750 MW wall-fired boilers described in Appendix A (DesignIPcrfonnance Data for SNCR Retrofit on a 250 MW and 750 MW Wall

### Fired Boiler), are presented in Table 11.6-2. Note that abreakdown ofthe 

### costs that comprise the total process capital is presented here, although this breakdown is not part ofthe 

### procedure. This breakdown was developed for the base cases. However, the procedure only estimates the total process capital. For further study, abreakdown can be 

### obtained when requesting supplier quotations.

SNCR 11-32 file date: 

### 29-May-98

### Table 11.6·2 SNCR Capital Costs for Base Cases (0.46 IblMMBtu NO,.) Boiler Size (MW) ! 

### 250 750 NOx

## Bascli;;e·;·iii7MMBtU·--· ···-···········-t· 0.46 --.-- 0.46 

### NOx 

### Reduction, % ._. ····_·_·

__

### ·······_·_·······r·_········ 40

-- 

### 4-0---. -=-",..

_ .•.•..

_ .•

_ •....•........•_---_._._-.----_..•.

_ .......•...........•.

_ •.

_•._ .



### Cost Year 

### 1Chemical Engineering Plant enst Index 

## ! IQ98/388 IQ98/388 Direct Costs; 

# I -riinkS;Pump;andlii]ecto·;:s(S!kWl·---·····-j······4:5r··----··-·--362---··· ···-6iiicrMechiii1icili·(S/kWi···········r··o36······oT§·**jij~iVaivcSiHciltfriiCi;;ii($/kWi···········r33i·26§** 

## EicciriciiiiP[c(sikWi·TT74···076 ·piilti'ormifiisuiiliioiliDcmoiirion·(S/kWir··o9s·············o.8i Total Process Capital Costs (S/kW): 10.87x (2501250)°·27 

### 10.87)( (250nsoy>.21 )( 1.0 x (0.66 + )( 1.0 )( (0.66 + 0.0085 x 40) := 0.0085 )( 40) ., 

### Indirect
. 10.87 8.08

_ _ _ _ _._ _.__._._- -._.._ _._.__._+.----"---_._._._

_ _._ _._ _._ _ .._._._ . 

### General Facilities (SIkW) 

### l 0.54 0.40 f--------.--. ---..- ..- -"- - - ..- ..--.----- . 

### Engineering and Home Office Fees (SIkW) 

## ! 1.09 0.81



### ..

## _._..

## _.

# __._..

# _._..

# __._..

## _.

# __._.. 

# ------------_._..

# _-_.



# __. 

# __._-_._.- Process Contingency (SIkW) 

### i 0.54 0.40



### ·Cost for ureastored at site, i.e. the flrst fill ofthe 

### urea

### tanks: IC (SIkW) 

### Volume in 

### gallons x cost per gallon (e.g. SO.85/gal) + 

### (MW 

### x 1,000). For the 250 MW boiler,lC 73,100 gal. x SO.85/gal + 

### (250 x**I,OOO)~** 

### SO.25IkW Forthe 750 MW boiler,lC 232,200 gal. x SO.85/gal + 

### (750 x 1,000)= SO.26IkW

SNCR 11·33 file dale: 

### 29-May-98Table 11.6-3. SNCR Capital Costs for Sensitivity Cases (0.3 and loS IblMMBtu NOJ

1O.87x (250/250)"7 x

1.0 x (0.66 

### + 0.0085 x 40) = 10.87 Total Process Capital 

### Costs ($/kW):**Indj[ect~** 

### Direct Costs;**Boil_e:..~~~~,** ..,_.,._ ; 250 250 NOx Baseline, IblMMBtu 

## -j--·---O:3---·'----I:'s---

.. NOx Reduction, % ·······...·...

## ·-··-··-·-·------·-···1··-·--·-···-·-40---·················_·-40 

# Cost Yearl

# CIie;;;'iciifE;]gineeriligplantCostTiidex--'j---fQ98/388
......--'-TQ98T38S'-·
i 1O.87x (2501250),·77 x (0.89 

### + 0.24x1.5

- 0.04x 

### 1.5') x (0.66 

### + 0.0085 x 40) 12.61 

# OenerniFaciiities·(SiiWj········-r"ii34
........ ··_·.. ··06'3·'· 

# '--Engfnee;;ng·an,Hfo;;;eot'ficeFees·(SikWj'··-·-r-·-·'TOg",··
..·-"-1:26""-



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

## -..

## -..•...•..

## -.-..•..•..

## _._ _._._ _ _._._.-.


# __..

## _._._-_._

_ ..•..•..



### _ .•..•..•..•..



### _ . Process Contingency ($/kW) 

## ! 0.54 0.63



### ·Costfor urea stored at site, Le. the first fill ofthe urea tanks: IC Volume in gallons x costper gallon (e.g. $0.85/gal)';- 

### (MW x 1,000).


### 11.6.4 Total Annual Costs Direct Costs The example calculation is for the base cases with a NOx baseline of0.46 IblMMBtu. Only the results for the sensitivity study are presented, not the results. The annual costs are converted to $/kW-year and $/too NOxremoved by Equations 2S and 27.

SNCR 11-34 file date: 

### 29-May-98Reagent 

### The annual cost ofurea 

### for the 250 MW boilerusing Equation 6 is: Annual Urea cost = 

### 217.5 gph x 8,760 hr/yr x 65/100 x $0.85/gal. $1,053,000 

### In tenus ofSIkW-year. the cost for the 250 MW boiler is: Annual Urea cost ($IkW-year) $1,053,000 

### I(250 x 1,000 x 

### 65/100) $6.48IkW-year 

### In tenus ofS/ton

### NOx

### removed, the cost for the 250 MW boiler is: Annual Urea cost 

### ($/ton NOxremoved) = 

### $1,053,00011 ,364 $772/ton NOxremoved 

### The costs for the 750 MW boiler are: Annual Urea cost = 

### 691.2 x 8,760 hr/yr x 

### 65/100 x $0.85 = 

### $3,345,000 Annual Urea cost ($IkW-yr) = 

### $3,345,000 

### I (750 x 1,000 x 65/100) = 

### $6.86IkW-year Annual Urea cost ($/ton NOx removed) $3,345,000 

### 14,335 = 

### $7721ton NOxremoved Maintenance 

### The annual maintenance labor

### and material costs using Equation 

### 17 are: Maintenance for the 250 MW 0.015 x $15.55 x 250 x 1,000 = 

### $58,300 Maintenance ($IkW-yr) $58,300 

### I (250 x 1,000 x 65/100) $0.36IkW-year Maintenance ($/ton NOxremoved) $58,300 

### I I,364 $43 

### I ton NOx removed Maintenance for the 750 MW 0.015 x $11.64 x 750 x 1,000 = 

### $131,000 Maintenance ($IkW-yr) $131,000 

### I (750 x 1,000 x 65/100) $0.27IkW-year Maintenance ($iton NOxremoved) 

### $131,000/4,335 = 

### $30 

### Iton NOxremoved Utilities 

### The estimated electrical power consumption 

### and annual costs for the 250 MW boilerusing Equations 18 and 19 are: Electrical power consumption for the 250 MW 0.9 x 0.46 x 1.32 x 250 136 kW Forthe 250 MW boiler: Annual electricity cost = 

### 137 kW x 8,760 hr/yr x 65/100 x $0.05 $39,000 Annual electricity cost ($IkW-yrr $39,000 

### I (250 x 1,000 x 65/100) = 

### $0.24IkW-year 

### SNCR 11-35 file date: 

### 29-May-98Annual electricity cost (S/ton 

### NO.) S39,OOO 

### 11,364 S291 ton 

### NOx removed Electrical powerconsumption for the 750 MW boiler 0.9x 0.46 x 1.32 x 750 410 kW For the 750 MW boiler: Annual electricity cost = 410 kW x 8,760 hr/yr x 

### 65/100 x SO.05 SI16,700 Annual electricity cost (SIkW-yr) SI16,700 

### I (750 x 1,000 x 651100) SO.24IkW-year Annual electricity cost (Slton 

### NO.)
- S116,700 

### 14,335 S271 ton 

### NOx removed 

### The dilution water flow ratc and annual water cost for the 250 MW boiler using Equations 20 and 21 are: Water, gph = 4.0 x 2,064 lblh urea solution 

### 18.345 Ib/gal 989 gph Annual water cost = 989 gph x 8,760 hr/yr x 651100 x 

### SO.00041 gal S2,300 Annual water cost (SIkW-yr) S2,300 

### I (250 x 1,000 x 651100) = SO.014IkW-year Annual water cost (S/ton 

### NO.) S2,300 

### 11,364 = S1.70 

### Iton 

### NOx removed 

### The dilution water flow rate and annual water cost for the 750 MW boiler arc: Water, gph 4.0 x 

### 6560/8.345 Iblgal 3,144 gph Annual water cost 3,144 x 8,760 x 651100 x 0.0004 S7,2oo Annual water cost (SIkW-yr) 

### S7,2001 (750 x 1,000 x 651100) SO.015IkW-year Annual water cost (S/ton 

### NO.) = S7,200 

### 14,335 SI.70 

### Iton 

### NOx removed Coal and Ash 

### The estimated additional coal required to account for the heat used to evaporate the water for the 250 MW boiler using Equation 22 is:**~Coal** 9 x 1,032 Iblhr urea x 900 Btullb 

### 11,000,000 8.4 MMBtuIh 

### Thecosts ofthe 

### additional coal and additional ash disposal for the 250 MW boiler using Equations 23 and 24 

### arc: Annual cost ofadditional coal 8.4 MMBtuIh x 8,760 hr/yr x 

### 65/100 x Sl.60IMMBtu S76,500

SNCR Annual cost ofadditional coal (SIkW-yr)

= S0.47IkW-year
11-36 = S76,500 

### I (250 x 1,000 x 651100)

file date: 

### 29-May-98Annual cost ofadditional coal 

### ($/ton NOx ) = $76,500 

### 11,364 = 

### $561 ton NOxremoved 

### Annual cost ofadditional ash disposal = 8.4 x 7.7 % ash x 65 x 

### $11.28/ton ash x 438 

### I 12,696 Btu/lb $1,600 Annual cost ofadditional ash disposal $1,600 

### I(250 x 1,000 x 

### 65/100)

= $O.OIO/kW-year

= $1,600 

### 11,364 = 

### $1.21 ton 

### Ox removed 

### The estimated additional coal for the 750 MW boiler is: "'Coal 9 x 3,280 x 900 Btullb 

### II,000,000 26.6 MMBtuIh The costs ofthe additional coal and additional ash disposal for the 750 MW boiler 

### are: Annual cost ofadditional coal 26.6 MMBtulh x 8,760 hr/yr x 

### 65/100 x $1.061MMBtu $160,500

= $160,500 

### I (750 x 1,000 x 651100) $0.33/kW-year $160,500 

### 14,335 $371 ton NOx removed 

### Annual cost ofadditional ash disposal = 26.6 x 6.4 x 65 x $11.28 x 

### 438/8,020 $6,800

= $6,800 

### I (750 x 1,000 x 

### 65/100) $0.014/kW-year $6,800 

### 14,335 $1.60 

### I ton NOx removed 

### Total Direct Costs 

### The total direct costs are summarized in Table 11.6-4. Table 11.6-4 Direct Costs for the Base Cases



### SNCR NOx Baseline, IblMMBlU Reagent


### Maintenance

11-37 2S0MW 0.46 

### $1,053,000 

### Iyr 

### $6.481 kW-yr 

### $772 Iton NOx



### $58,300 Iyr 

### $0.361 kW-yr $43 

### I ton NOx
file dale: 

### 29-May-98 7S0MW 0.46 

### $3,345,000 I yr 

### $6.861 kW-yr $772 

### I ton NOx



### $131,000/yr $0.27IkW-yr $30 

### I ton NOx

### Electricity

Water

Additional coal



### Additional ash disposal

Total Direct Cost $39,000 Iyr 

### $0.24/kW-yr $29 

### I ton NOx



### $2,300 Iyr 

### $0.0141 kW-yr 

### $1.70Iton NOx 

### $76,500 Iyr 

### $0.47IkW-yr 

### $561 ton NOx



### $1,600 Iyr 

### $0.010 IkW-yr 

### $1.20 Iton NOx 

### $1,230,700 Iyr 

### $7.57 IkW-yr 

### $9021 ton NOx 

### $116,700/yr $0.241 kW-yr $27 

### I ton NOx



### $7,200 Iyr 

### $0.015/kW-yr $1.70 Iton NOx



### $160,500 Iyr 

### $0.331 kW-yr 

### $37Iton NOx



### $6,800 Iyr 

### $0.0141 kW-yr 

### $1.60 Iton NOx 

### $3,767,200 Iyr 

### $7.731 kW-yr 

### $869 Iton NOx 

### The results ofthe sensitivity study at differentNOx 

### baselines are presented in Table 11.6.5 Table 11.6-5 Direct Costs for the Sensitivity Cases



## SNCR NOx Baseline, IblMMBtu 

### Reagent
Maintenance Electricity
Water

Additional coal



### 11-38 250MW 0.3 

### $816,400/yr $5.021 kW-yr 

### $917Iton NOx 

### $58,100 Iyr 

### $0.361 kW-yr 

### $65/ton NOx 

### $30,200 Iyr $0.19 

### IkW-yr $34 

### I ton NOx 

### $1,700 Iyr $0.011 kW-yr 

### $2/ton NOx



### $59,700 Iyr 

### $0.37IkW-yr $67 

### I ton NOx

file date: 

### 29-May-98 750MW 1.5 

### $2,834,100 Iyr 

### $17.441 kW-yr 

### $637Iton NOx 

### $69,300 Iyr 

### $0.431 kW-yr 

### $16/tonNOx $104,700/yr $0.641 kW-yr 

### $24/ton NOx 

### $6,100/yr $0.041 kW-yr $1 

### I ton NOx



### $206,500Iyr 

### $1.27IkW-yr 

### $461 ton NOx

### Additional ash disposal
Total Direct Cost

Indirect Annual Costs 

### SI,3oo 

### Iyr 

### SO.Ql1 kW.yr SII ton NOx 

### S967,400 

### I yr S5.95 

### I kW-yr SI,087 

### Iton NOx 

### S4,400 

### I yr 

### SO.031 kW.yr Sl/ton NOx S3,225, I00 

### I yr 

### S19.851 kW-yr S725 

### Iton NOx



### The capital recovery costs arc 0.09439 times the capital cost. A factor of4 percent ofthe 

### Total Plant Capital Requirements is used for annual property taxes, insurance, and administrative charges. The overhead is calculated as 60 percent ofthe maintenance labor and materials. These costs are summarized in Table 11.6-6. Table 11.6-6 Indirect Annual Costs for tbc Base Cases (0.46 IblMMBtu NOxl

NOx 

### Baseline, IblMMBtu 

### Capital recovery
Annual property taxes, insurance, and administrative charges Overhead

Total Indirect Costs 250MW 0.46 S367,000 

### I yr S2.26 

### I kW·yr S269/ton NOx



### SI 55,500 

### I yr SO.96 

### IkW-yr S114/ton NOx



### S35,000 

### Iyr SO.22 

### I kW-yr S261 ton NOx 

### S557,400 

### Iyr S3.441 kW·yr 

### S4091 ton NOx 

### 750MW 0.46 S824,000 

### I yr SI.69 

### I kW·yr SI90 

### Iton NOx



### S349,300 

### I yr SO.72 

### I kW-yr S81/ton NOx



### S78,6OO 

### I yr SO.16/kW·yr 

### SI8/tonNOx SI,251,900/yr S2.57 

### I kW·yr S289 

### Iton NOx
Table 11.6-7 Indirect Annual Costs for the Sensitivity Cases [This table will be incorporatedin thejinal version o/the chapter.] Total Annual Costs 

### The Total Annual Cost are presented in Table 11.6·8.

SNCR 11·39 fiJ, dat' 

### 29·May·98

### Table 11.6-8 Total Annual Costs for the Base Cases (0.46 IblMMBtu NO,)
Total Annual Cost 

### 2S0MW $1,788,1001 

### yr $11.01 kW-yr $1,311/10n NOx 

### 7S0MW $5,019,1001 

### yr $10.301 

### kW-yr $1,158/tonNOx 

### Table 11.6-9 Total Annual Costs for the Sensitivity Cases [This table will be incorporated in thefinal version of the chapter.] 

## II.7 Acknowledgments [To beprovidedinfinal version of chapler.] 

# u.s References

I, 

### Perry, Robert H., et. 

### AI" Perry's Chemical Engineers' Handbook 

### (6''' edition), 

### McGraw-Hill Book Company, New York, 1984. [More tofollow infinal version of chapter.]



### SNCR 11-40 file date: 

### 29-May-98