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:

The Cadmus Group, Inc.

135 Beaver Slreel

Waltham. MA 02154

Telephone: (781) 894·9830 Tclcrax: (781) 894-7238

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Figure 11.2-1 Urea SNCR Process Flow Diagram
Urea

Injectors

Platen Secondary Secondary t.....~1 Super- Superheater heater

Pendant

Reheater

Convection

Pass

Furnace

Primary

Superheater

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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 THE TOTAL PLANT CAPITAL REQUIREMENT . 22

11.4.1 EQUIPMENT COST 23

11.4.2 INSTALLATION COSTS ...........................•...••....••....••..... 24

11.4.3 TOTAL PLANT CAPITAL REQUIREMENT ..................•.....•.....••..... 24

11.5 ESTIMATING TOTAL ANNUAL COSTS •..•.............•.... 27

11.5.1 DIRECf ANNUAL COSTS .............................•.....•.....•..... 27

11.5.2 INDIRECf ANNUAL 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 be provided injinal version ofchapter.]

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 of SNCR 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 NOx control

techniques.

The Electric Power Research Institute (EPRl) developed and patented the urea-based SNCR

technology in 1980. It has 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.

NOx is 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 of nitrogen and oxygen in the combustion air at high flame

temperatures generates thermal NOx' Thermal NOx is generated even if fuel-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.

NOx emissions 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-NOx burners, combustion modifications, selective

catalytic reduction (SCR), and SNCR have been developed to comply with these requirements.

Several industrial sources are using these technologies, either individually, or in combination to

reduce NOx emissions.

This chapter addresses SNCR tcchnology with emphasis on developing order-of-magnitude cost

estimates. The approach presented here should be used as an initial screening of alternative 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 of this 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 ofurea as 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 NOx emitted in utility boilers is NO; therefore,

Equation I governs the actual reduction process.

(Eq. I)

(Eq.2)

Equation I is a simplified representation ofthe actual, quite complex series of over 40 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, even though Equation I indicates that a half mole ofurea is required to remove one

mole ofNO, in practice, over two times that amount is needed to achieve a high degree ofNOx

reduction in a boiler.

The uncontrolled or baseline NOx emissions 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

boiler type, burner design 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 of boilers and other fuels, with appropriate adjustments. The uncontrolled NOx 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 achieve NOx reduction efficiencies of up to 80 percent

in selected short-tenn demonstrations. but typically is considered to be capable of 30 to 50

percent NOx reduction, depending on a number of factors. The following is a list of major

SNCR 11-4 file date: 29-May-98
design, 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 of mixing 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 of chemical 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 of each 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

NOx reduction 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 of urea.

However, in practice, substantially more urea has to be injected to obtain a specified degree of

NOx reduction. The excess urea over the stoichiometric amount is destroyed, mostly through

other chemical 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, N20, which typically ranges from 10 to 20

percent ofthe NOx removed with limiting values up to 30 to 40 percent. With higher

temperatures and longer reaction times N20 emissions will be under about 10 percent.

For ease of comparison, the normalized stoichiometric ratio, NSR, is defined as:

NSR = actual mole ratio of urea to uncontrolled NOx

theoretical mole ratio to reduce I mole ofNOx

(Eq 3)

Because, theoretically, it takes a half mole of urea to reduce I mole ofNOx' the above definition

can be rewritten as:

NSR = actual mole ratio of urea to uncontrolled NOx

0.5

= 2 x actual mole ratio, ureaINOx

(Eq.4)

The utilization of urea can be calculated from the NSR and the NOx reduction efficiency:

Utilization = NUx reductiQn. %

100 x NSR

(Eq.5)

Thus, the quantity of urea 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 of urea to side reactions. Higher NSR values generally result in increased

NOx reductiQn, 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 of Mjxjnt:

For efficient NOx reduction, the injected urea solution must rapidly mix with the combustion

gases. There arc two main types Qf equipment 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

"
or no pressurized air or steam for atomization. Otherwise, a high-energy system provides large

amounts of compressed 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 (for compressed 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 other conditions 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 NOx

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 of urea at higher NSR values can improve NOx reduction,

but may also increase the unreacted ammonia releases. Depending on the fuel sulfur content 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 of ammonia·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 ofNOx from flue gas, using the SNCR technique, involves a relatively simple

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

NOx and generate other products 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 other technical, 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 of excess air, flue gas recirculation, staged combustion, burnersout-of-seIVice). use oflow-NOx burners, and SCR.

The SNCR process can be used alone or as a supplement to the other processes. The main

advantages of SNCR include:

• Relative simplicity

• Ease ofretrofit

• Avoidance of costly catalyst consumption in the SCR system

However, the NOx reduction capabilities of SNCR 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 of urea,

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 of urea 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 strainer to the injection zone

metering (lZM) module. Filtered plant water (less than 50 mg/l suspended solids and low

dissolved solids) is mixed with the metered amount of urea 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 of urea

to each zone of injection in the boiler based on signals received from the master control module

and local programmable logic controller (PLC). It can adjust solution flow rates, and activate

injection zones or deactivate them in response to changes in outlet NOx concentration, 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-98
Step 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 of air 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 of atomization 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 of better atomizer nozzle design to obtain optimum solution droplet size

distribution, spray angle, and direction.

11.2.2 SNCR Equipment

Types of equipment used for each ofthe four major process steps involved in the SNCR system,

their function, and alternatives (if applicable), 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
Blank page for Figure 11.2-2

SNCR 11-11 file dale: 29·May-98
fiber reinforced polyester and has a corrosion barrier coating on the inside made of premium

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

The dilution 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 of pumps, 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 of the injectors, electric heating to prevent the

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

Ifplant water is not available at the proper pressure, 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 of backpressure controllers and multistage pumps, this system is designed to

maintain a constant supply of dilution water, at the design pressure, in response to the changing

SNCR process 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 water control 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-98
NOx 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 of the 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 of a 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 similar estimates for other NOx 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 of heat input rate (MMBtuIhr), or if an 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 of combustion 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 of other installed

or planned technologies (e.g.,low-NOx burner, 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 air rate 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 of boiler furnace overfire air ports.

• Locations and sizes of boiler observation ports. temperature probe ports,

sootblower openings, and other locations for potential new ports.

• 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 or permit requirement for stack NOx emission

level (ppm or IblMMBtu).

The boiler supplier/manufacturer can furnish most ofthese items for existing or planned 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 (rather than predictions). Also, flue gas velocity measurements.

combined with boiler upper furnace and convective pass dimensions, will yield residence times

available for NOx reduction reactions.

11.3.2 Step 2: Reagent Selection

Urea and ammonia are acceptable proven reagents in terms of cost, 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

of ammonia because of health and safety concerns. Anhydrous ammonia, a gas at nonnal

atmospheric temperature, is transported and stored under pressure. Aqueous ammonia is a

solution of ammonia 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-98
The 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 N20 (nitrous oxide, a greenhouse gas) than urea. It is also less expensive than urea.

Properties of urea are listed in Table 11.3-I. Many utilities on the east coast have selected urea

because of its 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 of NOx 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 NOx reduction reactions.

• Extent ofmixing achievable in the boiler.

• Allowable ammonia slip.

• Rates of competing 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 of various 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 of the

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 computer models thaI

simulate the operation of an 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 NOx reduction 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 of chemical reactions and the siteSNCR 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 percent NOx reduction required based on the Wlcontrolled and permitted stack

outlet emission limit values (in lb/MMBtu units) for full load (or base load) ofthe boiler:

%NOx reduction required = uncontrolled NOx - stack N0x- x 100 (Eq.6)

Wlcontrolled NOx

Next, use Equation 7 to estimate the NSR for a bascline NOx of 0.5 lb NOx IMMBtu. Equation 7

is valid from 0 to 50 percent NOx reduction:

NSR(0.5 Ib /MMBtu) = 0.010 x ~NO' + 0.00055 x ~NO/ (Eq.7)

where "NOx = %NOx reduction

NSR Estimate. Step 2

The NSR value obtained in Step I (for a baseline NOx of 0.5 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 a graphical representation ofthis NSR estimation method.

NSR Estimation Examples:

NSR (0.5 lb/MMBtu) = 0.01 x 40 + 0.00055 x 40' 1.28

Multiplier (0.5/0.46)°·· 1.03

Estimated NSR = 1.28 x 1.03 = 1.32

Estimate the NSR for a baseline NOx of 0.46 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
NSR (0.5 IbIMMBtu) 0.01 x 30 + 0.00055 x 30' = 0.80

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 a baseline NOx of 1.5 IblMMBtu and a!cquired NOx reduction of

30 percent:

1.

2.

Estimate the NSR for a baseline NOx of 0.2 IblMMBtu and a required NOx reduction 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. Ifthe required temperature window occurs in the radiant section

ofthe boiler, the NSR could decrease. However, ifthe window occurs in

the convective section, the NSR may increase.

• Residence time available in the desirable (1,600 - 2,1 00 OF) temperature range.

The required NSR decreases as the available residence time increases.

• Degree ofmixing between the injected chemical and the NOx containing

combustion gases. For thorough mixing, the NSR decreases.

• Allowable ammonia (NH)) slip. Lower pennitted values of ammonia slip require

lower NSRs and could limit the achievable NOx reduction.

Estjmatim: Urea Consumntion and Tank Size

Once the NSR is estimated, the urea consumption 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. boiler heat input, MMBtu/hr

60.06 = molecular weight of urea

46 molecular weight ofNO, (i.e., NO,J.

2 = factor for a 50% solution

'* Although most NOx is NO, the molecular weight of NO] is used in the calculation ofmoles of

NOx·

SNCR 11-19 file ""., 29-May-98
Urea 50% solution, lb/hr (Urea, Ib/hr) 10.5 (Eq. 10)

(Note: For concentrations other than 50 percent, usc the proper factor in the denominator

of Equation 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 or tanks is based on the number of days of operation required:

Vol. (gal.) (Urea solution, gph) x (No. of days) 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 of this 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 of publicly 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-98
critical 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 of additive 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 of the work included, the better the overall

system design and cost. However, for the purpose of an 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 of equipment) through his own engineering and/or

construction team.

Since preparation of detailed specifications involves significant time and effort (for both owner

and supplier) and is not critical for order-of-magnitude cost estimates, 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 of construction, equipment redundancy, and

level ofsophistication in instrumentation and controls).

This approach enables the supplier to respond quickly. The RFQ under this 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 SNCR performance specification should typically ask for the following items:

NO.. Emission Control Performance

• Guaranteed and expected NOx emission rates in units of IblMMBtu 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, per the air pennit).

• Guaranteed and expected N20 emissions (guarantees needed if it is a pennit

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, if necessary, 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 Indexes for Air Pollution Control Costs, and updates thereto, all ofwhich arc installed

on the OAQPS Technology Transfer Network (CTC Bulletin Board). Alternatively, the Chemical

Engineering Plant Cost Index 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 of work (and adjusted if necessary for completeness)

instead of using 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 be provided in the final version ofthe 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 NOx baseline above 0.5 IbIMMBtu, using the following

equation, valid from 0.5 to 2.0 IbIMMBtu. For NOx baselines 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-98
Effadj is a multiplier for the NOx reduction 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

Cost VearTChemicafEngioeering pi;;;;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 of the urea tanks:

SNCR 11-24 file dale: 29-May-98
Blank 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 chapter are based on the economic factors in

Table 11.4-2. However, if desired, other values 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% (of capital)

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

Number of days of urea 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

For the purpose ofthe cost estimate, operation ofthe SNCR does not require any additional

operating or supervisory labor.

SNCR 11-27 file date: 29-May-98
Rcaccnt

The annual cost of urea 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 N x 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 of electricity 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%. For other 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 a result 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 of additional 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 of vaporization of water, Btullb

The costs afthe additional coal and additional ash disposal are:

Annual cost of additional coal ~Coal x 8,760 hr/yr x CFIlOO x CC

wherc CC is the cost of coal, SIMMBtu

Annual cost of additional ash disposal =

ACoal x 1,000,000 Btu/MMBtu x Ash/l 00 )( 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 higher heating 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 Chapter 2 for a thorough

discussion ofthe capital recovery cost and the variables that determine it.) For SNCRs, a system

lifetime of20 years is typical. The capital recovery factor of 0.09439 is based on a 20-year life

and a 7 percent annual interest rate.

As Chapter 2 indicates, a suggested factor of 4 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 labor and materials estimated by Equation 17.

11.5.3 Recovery Credits

There are no recovery credits that apply to S CR operation.

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-year and 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 output capability at [uHload

CF = capacity factor

TNOx = short tons ofNOx removed per year

N = baseline NOx, IblMMBtu

TlNOx = %NOx reduction

Q. = boiler heat 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
[The final 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 NOx reduction, %

Fuel HHV, Btullb

Fuel ash weight %

Annual NOx removed, tons/year·

·The annual NOx removed 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 boiler using 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-98
The total volume for 14-days of urea 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 of urea 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 WallFired Boiler), are presented in Table 11.6-2. Note that a breakdown 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, a breakdown 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

NO

xBascli;;e·;·iii7MMBtU·--· ···-···········-t· 0.46 --.-- 0.46

NO

x

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 urea stored 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

For the 750 MW boiler,lC 232,200 gal. x SO.85/gal + (750 x 1,000)= SO.26IkW

SNCR 11·33 file dale: 29-May-98
Table 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

NO

x Baseline, IblMMBtu -j--·---O:3---·'----I:'s---.. NO

x

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

·Cost for urea stored at site, Le. the first fill ofthe urea tanks:

IC Volume in gallons x cost per 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 of 0.46 IblMMBtu. Only the

results for the sensitivity study are presented, not the results.

The annual costs are converted to $/kW-year and $/too NOx removed by Equations 2S and 27.

SNCR 11-34 file date: 29-May-98
Reagent

The annual cost of urea for the 250 MW boiler using 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 of S/ton NOx removed, the cost for the 250 MW boiler is:

Annual Urea cost ($/ton NOx removed) = $1,053,00011 ,364 $772/ton NOx removed

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 NOx removed

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 NOx removed) $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 NOx removed) $131,000/4,335 = $30 I ton NOx removed

Utilities

The estimated electrical power consumption and annual costs for the 250 MW boiler using

Equations 18 and 19 are:

Electrical power consumption for the 250 MW 0.9 x 0.46 x 1.32 x 250 136 kW

For the 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-98
Annual electricity cost (S/ton NO.) S39,OOO 11,364 S291 ton NOx removed

Electrical power consumption 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 I ton 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 I ton 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

The costs ofthe additional coal and additional ash disposal for the 250 MW boiler using

Equations 23 and 24 arc:

Annual cost of additional coal 8.4 MMBtuIh x 8,760 hr/yr x 65/100 x Sl.60IMMBtu

S76,500

SNCR

Annual cost of additional coal (SIkW-yr)

= S0.47IkW-year

11-36

= S76,500 I (250 x 1,000 x 651100)

file date: 29-May-98
Annual cost of additional coal ($/ton NOx) = $76,500 11,364 = $561 ton NOx removed

Annual cost of additional 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 of additional 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 of additional 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 of additional 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 I yr

$6.481 kW-yr

$772 I ton NOx

$58,300 I yr

$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

$0.27 I kW-yr

$30 I ton NOx
Electricity

Water

Additional coal

Additional ash disposal

Total Direct Cost

$39,000 I yr

$0.24/kW-yr

$29 I ton NOx

$2,300 I yr

$0.0141 kW-yr

$1.70 I ton NOx

$76,500 I yr

$0.47 I kW-yr

$561 ton NOx

$1,600 I yr

$0.010 I kW-yr

$1.20 I ton NOx

$1,230,700 I yr

$7.57 I kW-yr

$9021 ton NOx

$116,700/yr

$0.241 kW-yr

$27 I ton NOx

$7,200 I yr

$0.015/kW-yr

$1.70 I ton NOx

$160,500 I yr

$0.331 kW-yr

$37 I ton NOx

$6,800 I yr

$0.0141 kW-yr

$1.60 Iton NOx

$3,767,200 I yr

$7.731 kW-yr

$869 I ton NOx

The results ofthe sensitivity study at different NOx 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

$917 I ton NOx

$58,100 I yr

$0.361 kW-yr

$65/ton NOx

$30,200 I yr

$0.19 I kW-yr

$34 I ton NOx

$1,700 Iyr

$0.011 kW-yr

$2/ton NOx

$59,700 I yr

$0.37 I kW-yr

$67 I ton NOx

file date: 29-May-98

750MW

1.5

$2,834,100 I yr

$17.441 kW-yr

$637 I ton NOx

$69,300 I yr

$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

$206,500 I yr

$1.27 I kW-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 I ton NOx

S4,400 I yr

SO.031 kW.yr

Sl/ton NOx

S3,225, I00 I yr

S19.851 kW-yr

S725 I ton NOx

The capital recovery costs arc 0.09439 times the capital cost. A factor of 4 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 I kW-yr

S114/ton NOx

S35,000 I yr

SO.22 I kW-yr

S261 ton NOx

S557,400 I yr

S3.441 kW·yr

S4091 ton NOx

750MW

0.46

S824,000 I yr

SI.69 I kW·yr

SI90 I ton 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 I ton NOx

Table 11.6-7 Indirect Annual Costs for the Sensitivity Cases

[This table will be incorporated in 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 the final version ofthe chapter.]

II.7 Acknowledgments

[To be provided infinal version ofchapler.]

u.s References

I, Perry, Robert H., et. AI" Perry's Chemical Engineers' Handbook (6''' edition), McGraw-Hill

Book Company, New York, 1984.

[More to follow infinal version ofchapter.]

SNCR 11-40 file date: 29-May-98