EPA Report Number

Month and Ycar of Publication

Selective Noncatalytic Reduction for NOx

Control on Coal-fired Boilers

by

Gajendra H. Shroff

Mitchell J. Krasnopoler

Bechtel Power Corporation

Gaithersburg, MD 20878

Charles W. Young

Shreedhar Kanetkar

The Cadmus Group, Inc.

Waltham, MA 02452

Contract Number 68-D7-0061

Task Order 000 I

Project Officer

Mr. Andy DuPont

Acid Rain Division

Office of Air and Radiation

Washington, DC 2000 I

Laboralory ??

Office of Research and Development

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711
FonvardINotice

Ravi - According to the guidelines (p.9). aforward is similar to an author's preface, but is

provided by the sponsoring laboratory. A notice may include a peer-review notice, a disclaimer,

or a copyright. It's your call. Apparently, we can include neither o/them, one, or both.

Abstract

This report illustrates a methodology for developing screening cost estimates for installation and

operation ofselective noncatalytic reduction (SNCR) technology for control ofNOx emissions

from coal-tired boilers. Screening cost estimates are approximate and are used as a decision tool

during planning to compare optional technologies. They help system owners achieve an

important initial step in the process of conceiving and selecting emission control technology.

Costs are presented in terms of 1998 dollars in this report.

As a prelude to the costing methodology, the report describes SNCR technology, the chemistry

ofthe process, factors that affect performance, and component equipment. The costing

methodology uses an innovative approach to estimate important underlying design parameters,

including the normalized stoichiometric ratio and reagent consumption. Traditionally, system

suppliers use proprietary methods to estimate these parameters. Having the reported

methodology available expedites the process for screening purposes and gives the plant owner

added freedom in selecting an emissions control process. The mathematical approach uses

fundamental engineering relationships and equations developed with regression and curve fitting

techniques. The methodology is tested by comparing estimated costs with published cost data

for existing plants. This methodology, though highly cost-effective for its intended purpose, is

not meant to be a substitute for traditional design practices that would apply after screening

decisions are made.

II
Contents

FOr\\lard/Notice II

Abstract II

Tables .........................................•................•............ v

Figures v

Abbreviations and Symbols vi

Acknowledgment _ viii

Chapter I Introduction .........................................•............ I

Control of NOx Using Selective oncatalytic Reduction I

Purpose and Organization of Report I

Chapter 2 Description ofSNCR Technology ........................•....•....... 3

Overview 3

SNCR Chemistry ...........................................•....•....... 3

SNCR Reagent ...........................•.............................. 3

Factors Affecting SNCR Performance _ _ _ _ 4

Temperature Windo\v 4

Residence Time 6

Normalized Stoichiometric Ratio 7

Degree of Mixing 9

Ammonia Slip 10

SNCR Equipment .............•.......................•.........•...... 10

Chemical Storage ..................................•....•............ 12

Skid-Mounted Modules ............................•.....•....•....... 12

Injectors .........................................•....•....•....... 14

Preparing SNCR System Performance Specifications ..................•........ 14

Data Furnished to System Supplier for Design 15

Budgetary Estimates Based on Performance Specifications 17

NOx Emission Control Performance 18

Chemical and Other Consumption Rates _ 18

Chapter 3 Estimation of SNCR Screening Costs 19

Estimating the Normalized Stoichiometric Ratio _ 20

Example ofthe NSR Estimation Procedure ..................•....•........ 21

Other Factors Involved in NSR Estimation _ 21

Estimating Reagent Consumption and Tank Size 21

Estimating the Total Plant Capital Requirement _ 23

Equipment Costs ......................................•....•........ 26

Installation Costs 26

Total Plant Capital Requirement ........•.....•.....•....•....•......... 26

Estimating Total Annual Costs 26

Direct Annual Costs ..................•.....•.....•.........•......... 26

Operating and Supervisory Labor 26

Maintenance . _ _ 26

Reagent ........................•.....•.....•................... 26

Utilities 28

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

Indirect Annual Costs 29

Tota! Annua! Cost ..................................•....•.....•..... 30

Chapter 4 Summary of Equations .................•.....................•..... 32

Design Factors for an SNCR Application 32

Annual Costs for an SNCR Application 33

Direct Annual Costs 33

Indirect Annual Costs , .. 34

Total Annual Costs ...........•........••....•................•...... 34

Chapter 5 An Example Calculation 35

Design Basis ..............................•............................ 35

Equipment and Consumables Data _.. _ 35

Total Capital Requirement 37

Total Annual Costs ..................................•.....•....•....... 38

References _ 42

Appendices

A DesignIPerformancc Data for SNCR Retrofit on a

250 MW Wall-Fired Boiler ............................•....••....•....... 44

B Development of SNCR Related Equations 46

C Comparison of Results from Methodology with Industry Case Studies 50

IV
Tables

Table 2-1. Urea and Ammonia Reagent Properties 5

Table3-1. Major Equipment List for an SNCR Application .........•.....•.....•..... 24

Table 3-2. Capital Cost Factors for an SNCR Application ............•................ 27

Table 5-1. Design Data .............................................•.......... 36

Table 5-2. Economic Factors 37

Table 5-3. SNCR Capital Costs 38

Table 5-4. Direct Costs ...............•...............•.....•.....••....•...... 40

Table 5-5. Indirect Annual Costs 40

Table 5-6. Total Annual Costs 41

Figures

Figure 2-1. Boiler Gas Path Configuration 6

Figure 2-2. Urea SNCR Process Flow Diagram 13

Figure 3-1. Approximate NSR Estimation for Urea 22

v
Abbreviations and Symbols

AAsh additianallblhr of ash generated in the boiler

Ash = percent ash in the coal

AC Ash disposal cost, $/shart ton

C = the percent of weight of the reagent in the solution (e.g., C = 50% for urea. 19 or 29.4% for

ammonia)

CF = capacity factor, percent

ACaal MMBtu / hr of additional coal

CC Cost ofCoal, $/MMBtu

Density ofwater, gallons per It' 7.481

EC Electricity Cost, $/kWh

FTAX = Indirect annual cost in S/yr

FOVHn = indirect overhead

HHV = Coal higher heating value, Btu/lb

Heat of vaporization of water 900 Btu/lb

lAC = Indirect annual cost in S/yr

MW = equivalent megawatt electric power output capability at full load

MR molecular weight ofthe reagent (~60.6 for urea; 17.03 for ammonia)

Molecular weight ofNO, (i.e, NOJ 46.01

NPHR Net Plant Heat Rate (BtulkWh)

NSR = Normalized Stoichiometric Ratio

VI
f)NOx = percent NOx reduction

NOXb uncontrolled (baseline) NO.. IblMMBtu

p = density ofthe solution, Iblftl (e.g., 71 for a 50% urea solution; 58.0 for a 19% aqueous

ammonia; and 56.0 for a 29.4% aqueous ammonia)

Q. = boiler heat input, MMBtulhr, Q. = 9.5 x MW

RC Reagent Cost, $ per gallon ofsolution (e.g., SO percent by weight)

TNOx = short tons of NOx removed per year

SRT = theoretical stoichiometry (= 2 for urea, 1 for ammonia)

we = water cost, $ per gal

VII
Acknowledgment

The authors express their thanks to the EPA Task Order Manager, Dr. Ravi Srivastava of EPA's

Office of Research and Development, for his technical insight and advice during the preparation

ofthis report. We also wish to thank others at EPA who provided valuable review comments as

the report was developed. They include Mr. Sam Napolitano of EPA's Office of Atmospheric

Programs and Mr. William Vatavuk of EPA's Office ofAir Quality Planning and Standards.

Yill
Chapter 1

Introduction

Control of NO, Using Selective Noncatalytic Reduction

Nitrogen oxides (NOJ are gaseous air pollutants that are fonned when fuels are burned in

combustion devices. While the flue gas is within the unit, about 95 percent ofthe NOli: exists in

the form of nitric oxide (NO) [1,2]. The balance is nitrogen dioxide (NO,), which is unstable at

high temperatures. Once the flue gas is emitted from the stack, most ofthe NO is ultimately

converted to N020

Scveraltcchnologies are available to control NO, emissions from stationary sources. These

include combustion modification controls (e.g., low·NO" burners, Qverfirc air, reduction of

excess air, flue gas recirculation, taking burners out ofservice, rcburning, etc.) and postcombustion controls (selective catalytic reduction (SCR) and selective noncatalytic reduction

(SNCR».

SNCR technology is being used for NO" emission control on industrial boilers, electric utility

stcam gencrators, thermal incinerators, and municipal solid waste energy rccovery facilities. In

this technology, a chemical reagent is injected into hot flue gas. Urea is usually used, or

ammonia can be chosen. The reagent reacts with NO" in the gas stream, forming products such

as nitrogen and water vapor. SNCR technology can be used alone or in combination with other

NO.: control technologies. The hardware associated with an SNCR installation is relatively

simple and readily available. Consequently, SNCR applications tend to have relatively low

capital costs.

Purpose and Organization of Report

Th..is report describes the important features of SNCR technology and aspects ofsystem design

and operation that factor into the cost estimating methodology presented. Its primary purpose is

to provide a methodology for estimating initial, screening-level, study costs for an SNCR

application on a boiler. A step-by-step procedure is presented for s.izing system components and

estimating screening-level capital and annual costs for a urea-based SNCR system. For a

specific facility, such estimates can be used to compare the approximate cost ofSNCR with

alternative NO.: control technologies. Costs are presented in terms of Deccmber 1998 dollars.
The capital costs and cost equations were developed based on the cost estimates and equations

presented in References [3] and [4]. The capital cost equations in this report were derived to

correspond to the cost equations for wall-fired and tangentially-fired boilers in Reference [4]. In

addition, however, the capital cost equations in this report include the effect of NOx removal, a

factor that was not characterized in Reference [4]. The direct annual costs include the annualized

cost of capital and the variable costs related to operating the SNCR. The annualized cost of

capital was developed using the estimated capital cost and a capital recovery factor (similar to a

capital charge factor in Reference [8]). The variable costs related to operating the SNCR were

developed by predicting the reagent and utility consumption rates and changes to the coal

consumption and ash generation rates. Thcse ratcs and typical unit costs were used to prcdict the

annual costs.

Information on certain key aspects of the design of an SNCR system is considered proprietary by

SNCR vendors. Thus, some ofthe mathematical design correlations used in this cost

methodology are derived from documented comprehensive SNCR pcrfonnance data and costs

based on quotations provided by SNCR suppliers [3.4]. Although the costing algorithms in this

report are based on retrofit applications of SNCR on existing coal-fired, dry bottom. wall-fired,

balanced draft boilers, the cost estimating procedure presented is suitable for retrofit or

greenfield applications of SNCR on all types of electric utility and large industrial boilers firing

coal.

Certain approximations are relied on to make the procedure useful for screening studies of SNCR

at specific facilities. To estimate the costs of broad applications ofSNCR on large populations

of boilers, the procedure described in Reference 5 is appropriate.

Some supporting infonnation is presented in appendices. The basic SNCR design and

perfonnance data used to develop the cost-estimating methodology are presented in Appendix A.

Several equations were derived to develop the methodology. Three ofthe derivations, equations

(5) for reagent utilization, (7) for the nonnalized stoichiometric ratio, and (14) for electrical

power consumption, are shown in Appendix B. Finally, Appendix C shows the cost estimating

results predicted using the methodolo'gy in comparison with SNCR cost data reported in the

literature for nine facilities.

2
Chapter 2

Description of SNCR Technology

Overview

In the SNCR process, a chemical reducing agent, such as urea or ammonia, is mixed with flue

gas. The reagent reacts with Oue gas NOll, generating molecular nitrogen. carbon dioxide, and

water vapor. Though simple in concept, it is challenging in practice to design an SNCR system

that is reliable, economical, simple to control, and meets other technical, environmental, and

regulatory criteria. This description focuses on a urea-based SNCR system because urea has

been the reagent ofchoice in most recent SNCR system installations. In general, an ammoniabased system is similar to a urea-based system, with the primary difference being the method of

reagent injection, as discussed later.

SNCR Chemistry

In the SNCR process, NOx reacts with injected reagent within an optimum temperature range of

1,600 to 2,100 of when using urea, or 1,500 to 2,000 of when using ammonia. Reaction

products include nitrogen (NIl, carbon dioxide (COJ, and water (H20). The net reactions that

are basic to the SNCR process using urea or ammonia are:

or

2NO+ Co{NH,), + 0, -+ 2N, + CO, +2H,O

2NO+ 2NH, + ~O, -+ 2N, + 3H,O

(I)

(2)

Reactions 1 and 2 are global representations ofthe actual complex chemical mechanisms. At the

appropriate temperatures in the boiler, the ammonia (either injected or resulting from thennal

decomposition ofurea) converts to free radicals that ultimately react with NO... In general, the

boiler thennal conditions are designed for steam generation, but not necessarily other reactions.

The residence time and flue gas temperatures may not be ideal for the mass transfer and chemical

reaction steps ofthe SNCR process. Such practical limitations need to be taken into account in

implementing SNCR system design and operation.

SNCR Reagent

Urea and ammonia are acceptable, proven reagents based on considerations of cost, storage and

handling, safety, byproducts generated, and demonstrated capability. Ammonia may be received

3
in aqueous or anhydrous form. Anhydrous ammonia, a gas at normal atmospheric temperature,

is transported and stored under pressure. Aqueous ammonia is a solution of ammonia in water.

Generally, a concentration of29.4 percent ammonia is used in SNCR applications, though some

recent applications are using a 19-percent solution. The 29.4 percent solution has substantial

vapor pressure at nonnal air temperatures.

Urea solution is less volatile than ammonia solution. Consequently, urea solution droplets

generally penetrate farther into the flue gas when injected into the system. Therefore. in large

boilers. the use of urea reagent helps ensure good mixing with the flue gas. The properties of

urea and aqueous ammonia (29.4 percent solution) arc shown in Table 2-1.

Because ofthe advantages of urea, it is more commonly used than ammonia in SNCR systems.

Therefore, this report focuses on urea as the SNCR reagent.

Factors Affecting SNCR Performance

SNCR technology has been shown to achieve NOll reduction efficiencies of up to 75 percent in

selected short-term demonstrations [6]. In typical applications, however, it is considered to be

capable of providing 30 to 50 percent NOll reduction, depending on a number offactors. The

important design and operational factors that affect NOll reduction using an SNCR system

include:

• mixing ofreagent and combustion gases within the required reaction temperature

range (window), which is typically available within the boiler superheater and

reheater radiant and convective regions;

• residence time available in the desirable temperature range;

• uncontrolled NOll concentration level;

• molar ratio ofinjected reagent (urea or ammonia) to uncontrolled NOll;

• degree ofmixing between the injected reagent and the NOll-containing

combustion gases; and

• ammonia slip.

Further discussion of each ofthese factors is provided below. For reference, a simplified process

flow schematic is shown in Figure 2-1.

Temperature Wi"dow

For SNCR technology to work effectively. the urea must be injected and allowed to react with

NOll in the boiler regions where the combustion gas temperature is within a specific range. As

4
Table 2-1. Urea and Ammonia Reagent Properties

Property Urea Solution Aqueous Ammonia

Chemical formula COCNH,), NH,

Molecular Weight of 60.06 17.03 reagent

Liquid or gas at normal air Liquid Liquid temperature

Concentration of reagent 50% by weight 29.4% by weight

nonnally supplied (19% is .Iso used)

Ratio ofNH) to solution 28.3% by weight ofNH, 29.4% by weight ofNH,

Density ofsolution @ 60 7llb/ft' 56 Ib/ft'

of (581b1ft' for 19%)

Vapor pressure @80 of < 1psia 13.9 psi. [8]

Crystallization temperature 64 of -110°F

Lower explosion limit

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

Upper explosion limit =

25% NH, by ·volume.

Threshold limit value Not specified 25 ppm (health effects)

Odor Slight (ammonia-like) Pungent odor @ 5 ppm

or more

Plastic, steel, or stainless Steel tank, capable of

Acceptable materials for steel (no copper or handling at least 25 psig

storage copper-based alloys or pressure (no copper or

zinc/aluminum fittings) copper-based alloys, etc.)

noted earlier, NOll reduction is effective in the temperature range of approximately 1,600 - 2,100

OF when using urea. At temperatures below the minimum, the reaction kinetics are slow. At

temperatures above the maximum, the urea reagent oxidizes and additional NOx is generated.

5
PLATEN

SECONDARY

SUPERHEATER

UREA

INJECTORS

SECONDARY

SUPERHEATER

CONVECTION

PASS

PENDANT

REHEATER

HORIZ.

REHEATER

UREA .-::-t---L_....J._J

INJECTORS

i

PRIMARY

SUPERHEATER

IECONOMIZER

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

FURNACE

BURNERS

Figure 2-1 Boiler Gas Path Configuration

Residellce Time

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

steps in the SNCR NOli: reduction process. Residence time varies from 0.001 to 10 seconds [10,

11]. depending on the factors addressed later in Chapter 2. The steps accomplished are:

6
• mixing ofthe injected urea with the flue gas;

• evaporation of water;

• decomposition ofsolid urea to NI-lJ;

• decomposition ofNHJ to NH2 and free radicals; and

• NOli: reduction reaction chemistry.

The amount ofresidence time that is available for the reaction depends on:

• the dimensions of the boiler gas path (from the upper furnace region through the

superheater/reheaters to the convective backpasslprimary reheater region), and

• the volumetric flow rate ofthe flue gas along the boiler"gas path.

The effectiveness of SNCR technology depends on the flue gas temperature range and on the

mass flow within the boiler in the area of urea injection. Both variables, flue gas temperature

and the mass flow, depend on boiler design, which is set to meet steam generation requirements

while maintaining a flue gas velocity to prevent tube bank erosion. Because of these boiler

design requirements, the gas velocities and residence times in the boiler are not always ideal for

the SNCR process. Flue gas temperatures in the region from the upper furnace through the

convective pass may vary by ±300 of from one boiler to the next. Furthennore, residence time

could vary from the ideal value for optimum NOli: reduction. In general, with more residence

time available for the mass transfer and chemical reaction steps, more NOli: is removed.

Normalized Stoichiometric Ratio

The Normalized Stoichiometric Ratio (NSR) indicates the amount of reagent needed to achieve

the targeted NOx reduction. Because capital and operating costs depend on reagent use, NSR is

an important parameter in SNCR system design. Based on reaction equations (1) and (2),

theoretically two moles of NOx can be removed with one mole of urea or two moles of ammonia.

However, in practice, because ofthe complexity ofthe actual chemical reactions involving NOx

and injected urea and limitations of mixing between urea and flue gas, more than the theoretical

amount ofreagent needs to be injected into the boiler flue gases to obtain a specific level ofNOx

reduction. The theoretical amount of reagent is related to the theoretical stoichiometric ratio,

defined as the ratio of moles ofreagent reacted to the moles of NOx reacted (or removed)

according to Equations (I) and (2). (For urea, the theoretical stoichiometric ratio is 0.5.) The

NSR, however, is the ratio ofthe moles ofreagent injected to the moles of uncontrolled NOx'

Because the moles ofNOx removed are much less than the uncontrolled NOx and because ofthe

limitations discussed above, typical NSR values require significantly more urea to be injected in

practice than the urea reacted according to the theoretical stoichiometric ratio. Most ofthe

excess urea used in the process is destroyed through other chemical reactions. However, a" small

portion remains in the flue gas as ammonia slip, which is described separately below.

7
The same factors that influence the extent of the reaction between NOx and a chemical reagent in

an SNCR system also affect the value ofNSR. These factors include:

• Percent NOx reduction,

• Uncontrolled NOx level in the flue gases.

• Temperature and residence time available within the optimum temperature

window for the NOx reduction reactions.

• Extent of mixing achievable in the boiler,

• Allowable ammonia slip, and

• Rates of competing chemical reactions.

Because most available SNCR technology was developed on a proprietary basis, the open

technical literature does not document extensive details ofthe theory and correlations that can be

used to estimate the required NSR. The publicly-available technical literature provides only

qualitative indications of the effects of various factors (temperature, residence time, etc.) [6].

Furthermore, the NSR is highly site-specific because the controlling factors are site-specific (e.g.,

temperature profile, fuel, fluid dynamics. chemical kinetics, and the effectiveness of the boiler as

a chemical reactor). In light ofthese complexities, SNCR system design is generally undertaken

by providing all of the plant- and boiler-specific data to the SNCR system supplier, who specifies

the required NSR based on prior experience and computational fluid dynamic and chemical

kinetic modeling. Such modeling is used to define the flue gas temperatures. velocities.

densities, and chemical compositions associated with the SNCR process in the boiler. Further,

modeling provides estimates ofNOx reduction along the flue gas pathway from the furnace exit

to the economizer. The modeling assists the system supplier in determining the available

residence time and reaction rates so that urea injectors can be sized and located appropriately. In

this way, the SNCR design can be optimized for the boiler of concern to obtain the maximum

NOx reduction while maintaining acceptable ammonia slip. This optimization is accomplished

by modeling several cases while varying important parameters. Once the design is optimized.,

the system supplier selects the corresponding NSR.

The normalized stoichiometric ratio (NSR). is defined as:

moles of equivalent NH, injected NSR = ----'---...,,---':-"":--

moles of uncontrolled NOx

8

(3)
For estimating purposes, the moles ofNO)!; are taken as moles ofN02• Note that the moles of

equivalent NH) in Equation 3 are the moles ofNH2 that will be released from the reagent. The

actual stoichiometric ratio is the ratio ofthe moles ofreagent injected to the moles of NO)!; . The

equation for the actual stoichiometric ratio is:

SRTis the ratio of equivalent moles ofNH) per mole ofreagent. As shown in Equations (1) and

(2), SRT is 1 for ammonia and 2 for urea.

The utilization is defined as the ratio ofmoles ofreagent reacted to the moles injccted.

Utilization ofreagent can be calculated from the NSR and the NO)!; reduction efficiency as

follows:

NOx reduction (%) Utilization = "-'-'-":":===--'.:2

100x NSR (5)

The derivation of Equation (5) is shown in Appendix B. The quantity of reagent actually used is

substantially higher than the stoichiometric amount for the reasons discussed above. Higher

NSR values generally result in increased NO)!; reduction. Generally, NSRs range between 0.5 and

2.0 in industrial and utility boilers with utilization ranging between 25 and 50 percent, as shown

subsequently in the discussion ofthe estimation of SR.

Degree ofMixing

For efficient NO)!; reduction, the injected urea must mix rapidly with the combustion gases. Two

types of equipment are used for urea injection, including wall injectors or lance injectors which

protrude into the flue gas pathway. The urea solution is atomized under pressure or with air or

stearn in a dual-fluid atomizer nozzle. There are two ways of dispersing the solution droplets. A

low-energy system uses little or no pressurized air or steam for atomization. In contrast, in a

high-energy system, large amounts of compressed air or stearn are used to inject and vigorously

mix the solution with the flue gas. Lance injectors are used in high-energy systems to ensure

thorough mixing between reagent droplets and flue gas in large boilers. More electrical power

(for compressed air) or steam is consumed if a high-energy system is used.

The reagent injection systems used for ammonia-based systems are generally more elaborate than

those used in urea-based systems. In ammonia-based systems, high-energy lance injectors are

used to ensure thorough mixing of ammonia droplets throughout the cross section ofthe flue gas

pathway. Iflow-pressure injection were used, the ammonia droplets would evaporate in the

vicinity ofthe atomi7..er tip owing to the high volatility of ammonia. Mixing would be

inadequate and NOli: removal less efficient.

9
Ammonia Slip

In SNCR applications, limits on acceptable ammonia slip place constraints on NOx reduction

performance. Injection of urea at higher NSR values can improve NOx reduction, but may also

increase ammonia slip. Ammonia slip limits are imposed by permitting authorities because

anunonia released into the atmosphere above certain concentration levels is considered to be

harmful to public health. Furthermore, prudent design practice limits ammonia slip to avoid

impacts on downstream equipment. Depending on the fuel sulfur content and sulfur trioxide

(SOl) generated, ammonia slip could also cause plugging, fouling, and corrosion problems in

downstream equipment (air heater, ducts, fans, etc.) due to formation and deposition of

anunonia-sulfur salts (sticky and corrosive ammonium bisulfate and ammonium sulfates). In

general, ammonia slip can be controlled to less than 25 ppm at the stack [6].

SNCR Equipment

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

technology in 1980. The technology was licensed to Fuel Tech (FT), which holds several

additional patents that claim improvements and enhancements to the basic process. Fuel Tech

has several sub-licensees that are authorized to supply and install SNCR technology. in several

industrial sectors.

Equipment is used to accommodate four main steps in the application of urea-based SNCR

technology, including:

• Step 1 - Receiving, storage, and recirculation of the urea solution (50 percent urea

by weight),

• Step 2 - Metering, dilution, and mixing of urea solution,

• . Step 3 - Injection of diluted urea solution (e.g., 10 percent by weight) at locations

in the boiler with temperatures between 1,600 to 2,100 OF, and

• Step 4 - Mixing/dispersion of urea in the flue gas, evaporation of water,

decomposition of urea, and reduction of NOxThese steps are described in further detail below.

~. A simplified process flow schematic is presented in Figure 2-2. Aqueous urea (50

percent by weight) is received via a tank-truck or rail car and pumped into one or more storage

tanks. More highly-concentrated urea solutions are available, but their freezing temperatures arc

too high for this application. A 50-percent solution, with a freezing point of 64 of. is typically

selected. The urea solution is then pumped to the circulation module where the solution flows

through an in~line electric heater (to prevent freezing in cold climates) and duplex strainer to the

10
injection zone metering (lZM) module. Filtered plant water (with less than 50 mgll ofsuspended

solids and low dissolved solids) is mixed with a metered amount of urea solution to deliver a

diluted urea solution (typically 10 percent urea by weight) to the urea distribution module, which

is typically located close to the boiler.

Step 2. Each IZM 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). The module can adjust solution flow rates, and

activate or deactivate injection zones in response to changes in outlet NOx concentration, boiler

load, or fuel quality. There arc approximately one to five lZM modules [12], depending on the

boiler size, configuration, the uncontrolled NOx concentration, and desired NOx removal

efficiency. Several IZM modules can be combined onto one skid-mounted system.

Diluted urea solution is transported from the IZM modules to the distribution modules, which

direct the solution to each injector. Each distribution module contains flow meters, balancing

valves, gauges, and regulators to control the solution injection process. There is one

corresponding distribution module for each IZM module [12]. Each distribution module

provides urea solution to approximately four to twelve injectors [12].

Step 3. The diluted urea solution is injected at several zones (between onc and five [12]) in the

boiler at within the appropriate temperature window. The injectors may be ofthe pressureatomized or dual-fluid (air or steam) atomizer type. The injector nozzles are specially designed

to meet plant-specific conditions.

Step 4. The solution is dispersed and the water is vaporized. The urea decomposes to NHJ, NH2,

and other free radicals that react with NOx and reduce it to N2, CO2, and water. The boiler

radiant cavity (secondary superheater and reheater region) and convective cavity (primary

superheater and reheater area), where urea is injected, serve as chemical reaction chambers. In

an existing boiler, the injectors are located in available open areas such as the region between the

superheater and reheater sections. These conditions are illustrated in Figure 2-1.

Mixing ofthe reagent with the flue gas is important for proper performance ofSNCR, and is

generally of greater concern in applications on large boilers. Ifmixing and distribution ofthe

reagent throughout the flue gas is inadequate, the umeacted ammonia (and ammonia slip)

increases. The following techniques are employed to ensure adequate mixing.

• Use ofseveral injectors at several locations within the boiler's optimum flue gas

temperature window. To ensure proper system design for existing boilers,

temperature and velocity measurements are made and the supplier uses

computational fluid dynamic (CFD) modeling to determine the optimum number

of injectors, locations, and other details.

11
• Use ofmore than the normal amount of air for atomization ofthe reagent solution.

There are two types of mixing modes-low-energy mixing with the normal

amount of atomization air, and high-energy mixing with substantially more than

the normal 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 designs to obtain optimum solution droplet size

distribution, spray angle, and direction.

The equipment used to accommodate these steps is discussed below, with reference to applicable

alternatives.

Chemical Storage

For urca-based systems, urea solution is received by tank trucks or rail car and pumped into onc

or more storage tanks. A closed top, flat bottom, vertical storage tank is used for urea storage.

Such tanks are usually made offiber- reinforced polyester and have a corrosion barrier coating

on the inside made of premium-grade vinyl ester resin. The tanks are equipped with level and

temperature indicators, a manway, vent, and access ladder, and other appurtenances. The

applicability of heat tracing, insulation, and seismic design criteria are detennined based on sitespecific conditions. The tank. should be surrounded by a spill containment structure (usually a

dike).

Skid-Moullted Modules

The dilution water pressure control module, urea supply/circulation module, IZM module, and

distribution module, shown in Figure 2-2, are skid mounted on stainless steel bases. This

modular approach, with shop assembly of pumps, valves, internal piping, instruments, and

controls, reduces field installation time and related costs while providing flexibility for future

expansion. These modules are described below:

• Dilution Water Pressure Control Module - If plant water is not available at the

proper pressure, a dilution water pressure (DWP) control module is used. It

typically consists oftwo full-flow multistage stainless steel centrifugal pumps, inline duplex strainer, pressure control valves, and the required pressure/flow

instrumentation. lbrough the use 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.

• Circulation Module - The supply/circulation modulejs a fully equipped highflow, high-head urea solution delivery system designed to supply filtered urea

solution to the IZM module. This module contains multistage stainless steel

centrifugal pumps, in-line duplex strainers, electric heater, and pressure, Oow,

12
COOLING AIR

AIR f r

.'T>.

INJECfORS--

0£1 ATOMIZING AIR

COMPRESSOR _'T>_ S-S:!

«

UJ 0

Z

DISTRIBUTION MOOULES <...

0: >- ::J ::J

-' •

0 0 BOILER (/)

)<

srA-,e METERING

_4V' MIXER PUMPS

WAT~

~~ '>----<

l:::::' WA-kR"PUMP

WATER PUMP INJECTION ZONE METERING MOOULES

DILUTION WATER

PRESSURE

CONTROL MODULE

50010 UREA Jillt SOLUTION

UREA STORAGE CIRCULATION HEATER

TANK PUMPS

SUPPLY/CIRCULATION MODULE

)

go

------.

H

UNLOADING

PUMP

Figure 2-2 Urea SNCR Process Flow Diagram

13
temperature, and level instrumentation and controls. The main purpose ofthis

module is to maintain continuous circulation ofthe stored urea. Its operational

functions include filtering the solution to avoid clogging ofthe injectors and

electric heating to prevent the solution from freezing. It also provides a

locaUremote control and monitoring station for the storage tank and circulation

system.

• Injection Zone Metering Module - Each lZM module includes a chemical

metering pump, a water pump, an in-line static mixer, a local control panel, zone

isolation valves, and magnetic flow meters and control valves for chemicals and

water. The mixed and diluted urea solution is transported from the IZM to the

distribution modules, which direct the solution to each injector.

• Distribution Module - Each of the distribution modules consists of flow meters,

balancing valves, and regulators which accurately control and display the

chemical and atomizing air flow to each injector. The modules also include

manual ball valves, gauges, and stainless steel tubing to adequately control the

urea injection process. The urea solution flows from the distribution modules to

the injectors.

Injectors

Wall-mounted injectors, rather than lance-type injectors, are generally used in cases where shortrange injection is necessary to mix reagent droplets with the flue gas stream. Ifthe droplets arc

large, they have greater momentum and penetrate longer distanccs, but it also takes longer to

evaporate the water. Since urea does not decompose and react with NOli until the water in the

urea solution evaporates, optimization ofthe droplet size and injector locations is required for

maximum NO" reduction. Even with droplet size optimization, however, the wall-mounted

injectors are better suited for small boilers because the distance from the wall to the center of the

gas flow path is smaller. They may be applicable for large boilers ifthe targeted NOli reduction

is low. The main advantage ofthe wall-mounted injectors is that they are not fully exposed to

the hot flue gases from the boiler furnace and, thus, have relatively long lives.

Lance-type injectors can be used in large industrial or utility boilers. They can be fixed or

retractable, and can include several nozzles. Lance-type injectors (both fixed 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.

Preparing SNCR System Performance Specifications

As introduced above, an SNCR system supplier is generally involved in the design of an SNCR

system because of the proprietary nature ofthe technology. This subsection is included to

provide perspective on the information that is generally needed by a supplier for SNCR design.

14
The cost estimating methodology described in succeeding sections purposely avoids interaction

with the supplier. It does so specifically to expedite the development ofa screening-level cost

estimate. When a supplier is involved in the process, it is done so specifically for system design

purposes, resulting in system specifications and development of an accompanying cost estimate

sufficiently accurate to judge the acceptability of competitive bids.

Thus, this section describes the information that must be assembled and furnished to a supplier to

prepare design specifications, particularly that component information with the greatest influence

on system cost. SNCR capital and operating costs can be estimate~ if the major cost items are

identified and the system is defined in adequate detail.

As part ofthe design process, the SNCR system supplier will provide a cost quotation for his

scope ofwork. To determine total project costs, the boiler owner will add certain cost items,

such as system integration/interface engineering, supervision, and direct and indirect overhead.

Data Fumislled to System Supplierfor Desigll

The following data are provided to the system supplier for SNCR system design:

• The boiler capacity in tenns of heat input rate (MMBtulhr). Ifthe boiler produces

electricity, then its heat input can be estimated using the boiler net plant heat rate

(NPHR):

Heat inplll role (MMBtulhr)

(MW x 1,000 kW x NPHR (Btll/kWh)) 11,000,000 (6)

Note that ifNPHR is not known, a value of9,500 BtulkWh can be used as a

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

Q. (MMBtu/hr) = MW x 9.5 (6A)

• Boiler load profile - percent oftime the boiler operates at 100 percent load, and at

various partial loads.

• Type of combustion unit - dry/wet bottom boiler, wall-fired, tangentially-fired,

cyclone fired, other (e.g., stoker-fired); year built, and manufacturer.

• Existing or planned uncontrolled NO" and CO emission data in ppm or IbIMMBtu

without the proposed SNCR system, including any change in emissions related to

other installed or planned technologies (e.g., low-NO" burner, gas recirculation,

overfire air, etc.).

15
•

•

•

•

•

•

•

•

•

•

Air preheater design and operational data, including soothlowcr data.

Fuel Data - proximate and ultimate analyses and high heating value (HHV) for

primary and secondary fuels.

Fuel firing rates at full and partial loads (e.g., 100 percent, 70 percent, and 30

percent).

Test Data or Combustion Calculations - flue gas flow rate at design or actual

conditions; excess air rate at full and partial loads; flue gas composition including

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

Boiler Dimensions - sectional side view; sectional front view; plan section

through furnace (width x depth); furnace height (floor to furnace exit); firing zone

height; sections through radiant and connective heat transfer cavities (zones);

other unique features, e.g., division walVpanels, etc.) in the furnace or backpass.

Locations 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 (i.e., where

temperature drops to about 1,400 OF) at various loads.

Flue gas residence time - available flue gas residence time in the upper furnace

and convective pass within the temperature window for urea at various loads.

Minimum expected NOx reduction or pennit requirement for stack NOx emission

level (ppm or IbIMMBtu).

The boiler supplier/manufacturer can furnish most ofthis infonnation for existing or planned

new units. For fuel data, the designer needs typical or design values, as well as the expected

range. To define the temperature profile in existing boilers, it is preferable to obtain actual data

from temperature measurements (rather than predictions). Also, flue gas velocity measurements,

combined with upper furnace and convective pass dimensions, are used to determine residence

times available for NOx reduction reactions.

To obtain a representative cost quotation from an SNCR system supplier, the request should

contain sufficient details to minimize design assumptions by the supplier. The request for

16
quotation (RFQ) should include the technical specifications, as well as commercial tenus and

conditions.

The uncontrolled and desired NO" emission levels should be provided at fuHload and selected

partial loads, (i.e., loads at which the boiler is expected to operate for significant time periods). It

is also critical to specify the allowable byproduct emission rates, especially the anunonia slip.

Some penuitting authorities may also impose emission limits on nitrous oxide, N20, a

greenhouse gas.

The boiler owner should specify the preferred NO" reducing reagent. In special situations, a

small percentage of additive chemicals may be rccommended by the SNCR system supplier to

improve perfonnance or reduce scaling and corrosion. The supplier should be asked to document

the costs and benefits ofthese proprietary chemicals.

Once the basic plant and other data have been collected, the SNCR specification can be prepared.

Two important parts ofthe specification are work included in the scope of the supplier and work

not included (i.e., work done by the owner or his architect-engineer/constructor). The more

precise and detailed the specification ofthe work, the more accurate the overall system design

and cost. However, for the purpose of a study cost estimate, it is sufficient to provide general

specifications for major items. Items ofwork excluded from the supplier's scope also should be

clearly defmed in the RFQ for the same reason.

For a turnkey scope (design, supply, and erect all equipment, and demonstrate commercial

operation while meeting all perfonnance criteria), the excluded work is minimal. In general, the

excluded scope can vary significantly depending on the owner's preference to perfonn several

items ofwork (e.g., installation/erection of equipment) through his own engineering andlor

construction team.

Budgetary Estimates Based 011 Performallce Specificatiolls

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

owner and supplier) and is not critical for budgetary cost estimates, an optional perfonnance

specification approach may be used in the RFQ. In this approach, the basic required plant and

fuel data arc provided along with the required SNCR system perfonnance requirements,

excluding equipment-related details (e.g., materials of construction, equipment redundancy, and

level ofsophistication in instrumentation and controls). This approach enables the supplier to

respond quickly. Using a perfonnance specification approach, the RFQ should ask for a

description ofthe system and components in enough detail to understand the type and quality of

system proposed by the supplier. A cost breakdown ofmajor 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.

17
The SNCR performance specification typically should ask for the following items regarding NOx

emission control performance, chemical consumption, and other consumption rates at full and

partial loads:

NO" Emission Control Performance

• Guaranteed and expected NO" emission rates in units of IblMMBtu and Iblhr with

averaging period as defined in the air quality pernlit ofthe facility.

• Guaranteed and expected NH) slip, ppm (other conditions such as dry basis,

percent 02' per the air permit).

• 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 Consumption Rates

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

reduction.

• Guaranteed and expected urea consumption ratc.

• Guaranteed and expected dilution water consumption rate.

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

• Guaranteed and expected electrical power consumption.

To obtain reasonably competitive cost estimates, the RFQ should be sent to at least three

suppliers. After receiving bids, the designs and costs should be adjustcd, if necessary, so that

they are comparable.

18
Chapter 3

Estimation of SNCR Screening Costs

The cost estimating methodology presented here provides a tool that can be used to estimate

screening-level SNCR costs, thus allowing for comparison with other NO~ reduction

technologies. Actual selection of the most cost-effective option should be based on a detailed

engineering study and cost quotations from system suppliers. as acquired using the rationale

described immediately above in Chapter 2. Although the report discusses two reagents, urea and

armnonia. the costing procedure is based on the more common and preferred reagent, urea.

The capital costs and cost equations were developed based on the cost estimates and equations

presented in References [3] and [4]. The capital cost equations developed for this report were

derived to correspond to the cost equations for wall-fired and tangentially-fired boilers in

Reference [4]. In addition, however, the capital cost equations in this report include the effect of

NOx removal, a factor that was not characterized in Reference [4]. The mathematical

relationship between capital costs and NOx removal was developed based on the changes in urea

flow rate that accompany different levels of NOx removal and associated changes in the urcarelated equipment. With NOx removal accounted for mathematically, the procedure predicts

capital costs that correspond well with the Reference [3] boiler cases.

Direct annual costs include the annualized cost of capital and the variable costs related to

operating the SNCR.. The annualized cost of capital was developed using the estimated capital

cost and a capital recovery factor (similar to a capital charge factor in Reference [8]). The

variable costs related to operating the SNCR. were developed by predicting the reagent and

utility consumption rates and changes to the coal consumption and ash generation rates. These

rates (e.g., tons/year) and typical unit costs (e.g., $/too) were used to predict annual costs.

Equations for the variable cost items shown in the report were developed from fundamental

principles and from correlations of data from References [3] and [4]. The correlations are

described in Appendix B. The following list summarizes how each variable cost item was

developed:

•

•

Reagent consumption rate - Data correlations were used to develop the NSR and

fundamental principles were used to calculate the reagent rate from the NSR.

Electrical power consumption rate - Data correlations were used for this factor.

19
• Water consumption rate and increased coal consumption rate· Fundamental

principles were used to calculate these factors based on the reagent ratc.

• Increased ash generation rate - Fundamental principles were used to calculate this

factor based on the increased coal consumption rate.

To usc the step-by-step procedure presented in this section for study cost determination, the

following data are needed:

• Boiler MW rating,

• Uncontrolled NO~, and

• NO~ removal efficiency.

Ifthe boiler MW rating is not known (e.g., an industrial boiler or a cogeneration unit), the

equivalent MW rating can be estimated from:

MW Q. (MMBlufhr) / 9.5 (68)

Use ofthe procedure first involves estimation ofthe NSR, urea consumption, and urea storage

tank size, as described immediately below. Total plant capital and annual costs are estimated in

succeeding steps according to the procedures that are outlined subsequently.

Estimating the Normalized Stoichiometric Ratio

A simplified NSR estimation procedure was developed for this report and is presented below. To

implement this cost estimating methodology, this estimating technique is necessary because the

actual method used by suppliers to establish an NSR is nol publically available. The NSR

estimating procedure was developed using linear regression and NSR data from References [3]

and [4]. Though this NSR estimation procedure is approximate, it is appropriate in this

application of developing study cost estimates. The simplified procedure can be used to estimate

an NSR that is functional, but not necessarily precise, considering the complexity of SNCR

chemistry and the significant effect ofsite-specific factors. The values ofNSR derived using this

approach should not be used for equipment design or guarantee purposes.

As a first step in estimating NSR, the required percentage NOx reduction is determined based on

the uncontrolled and pennitted stack emission limit values for full load or base load, using

Equation (7):

T/Nfb> %

IIncontrolled NOx.(/b/MMB/II)- slack NOx(lb/MMB/II)

= x 100 NOu(lb/MMBIII)

20

(7)
Next. Equation (8) is used to estimate the NSR for urea reagent. Its derivation is shown in

Appendix B. Equation (8) is valid from 0 to 50 percent NOli reduction:

(0.7 +2 x NQ»(/b / MMBtu)) x (qNO (%) /100)

NSR = ' NQ»(/b / MMBtu)

Figure 3·1 provides a graphical representation ofthis NSR estimation method.

Example ofthe NSR Estimation Procedure:

(8)

Estimate the NSR for an uncontrolled NO, level of 0.46 IblMMBtu and a required NO,

reduction of 40 percent:

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

Other Factors Involved ill NSR Estimation:

In a design developed by a system supplier, the NSR would be adjusted to account for several

parameters that are not included in the NSR estimation equation. The following parameters are

used by the system supplier to more accurately predict the NSR for a given boiler:

• Reaction temperature range available within the boiler superheater (radiative and

convective section) and primary reheater (convective section or cavity) region. If

the required temperature window occurs in the radiant section ofthe boiler, the

NSR could decrease. However. ifthe temperature window occurs in the

convective section, the NSR may increase.

• Residence time available in the desirable temperature range. The required NSR

decreases as the available residence time increases.

• Degree of mixing between the injected chemical and the NOv-containing

combustion gases. The NSR decreases as the degree ofmixing increases.

• Ammonia slip. Tighter constraints on ammonia slip would dictate lower NSRs,

thereby limiting the achievable NOli reduction.

Reagent

Estimating Reagent Consumption and Tank Size

Once the NSR is estimated. the reagent consumption rate can be calculated using:

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

21

(9)
50%

45%

40%

35%

30%

25%

, I I I' I I e uc ,on

! I I I I: , 50%

I\' I I I I I ---- 45%

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

I\'..l' 1 I I I I 1- __ 35%

_\ -_"'" I I I I I I 30%

\ " _, ' _ _ _ 25%

.- ' I I

1\ -,_" , .......... 1 I I ' I

\ "'-" ,,~' -·f·-.-_' I I I

','- -.J... I -I' __ . --... - I ................. 1·-,-... I ---L.._ - .... _-.-.- ... -.~

'" _ r:=-::::I I --I - - . L L - - - -. --- - --- --

I

__ - I

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

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

I I--I Ir

0.4

0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0

Uncontrolled NOx, IblMMBtu

3.0

2.8

2.6

2.4

2.2

It: 2.0

'"

z

.., 1.8

.!l

..,

.51 1.6

Q.

"

1.4

1.2

1.0

0.8

0.6

Figure 3-1 Approximate NSR Estimation for Urea

22
The molecular weight ofN02 in the denominator, 46.01, is used because the N0lt emissions,

NO"" are given in IblMMBtu ofNO, [2]. Using the estimate for boiler heat input, Q. 9.5 x

MW, Equation (9) becomes:

Reagent (Iblhr) = NO,.• (Ibl MMBtl/) X 95x MWx NSRx M,

46.01 x SR, (9A)

For urea, Equation (9A) becomes:

I/rea (Iblhr) 6.20 x Nan x MW x NSR

For urea or ammonia solutions, the solution flow rate is:

Soll/tion (Ib/hr) = Reagent (Ib/hr) x IODie ("/0)

Soll/tion (gph) = Soll/tion (Iblhr) x 7.481 (gallft') I p (Ibljt')

The total volume stored in the tank, or tanks, is based on the number of days of operation

required:

Vol. (gaQ Soll/tion (gph) x No. ojdays x 24 hdday

(98)

(10)

(II)

(12)

Note that the tank volume is typically based on full-load operation, so the capacity factor is not

included in Equation (12).

Estimating the Total Plant Capital Requirement

A procedure for estimating total plant capital requirement for urea-based SNCR systems is

presented in this section. The cost estimate for an ammonia-based SNCR system requires

changes to account for differences in reagent storage and delivery systems and the injectors.

(See Chapter 2 for a description ofthe differences in reagent injectors.)

The Total Plant Capital Requirement (TPCR) for a urea-based SNCR system includes eosts for

the urea tank; circulation, metering, and distribution modules; injectors; new boiler ports; and the

direct and indirect costs associated with installing or erecting new control equipment. Table 3-1

presents a list ofthe major equipment for a urea-based SNCR system. The most accurate method

for obtaining the TPCR is to develop a detailed specification (sec Chapter 2), request quotes from

SNCR suppliers, and develop a complete cost estimate that accounts for equipment provided by

the SNCR supplier and other applicable equipment and appurtenances not within the scope ofthe

SNCR supplier's quoted costs. The intent ofthis section, however, is to present a procedure that

can be used to develop screening level, study capital-cost estimates for SNCR technology. Such

23
Table 3-1. Major Equipment List for an SNCR Application

Quantity Item Description/Size

1 Urea unloading skid Centrifugal pumps with hoses to connect to rail tank

car or truck

1 or more Urea storage tanks Vertical, insulated fiberglass reinfofced plastic (vinyl

ester resin) tank, atJ,TIospheric pressure design, and

equipped with a vent, caged ladder, roanway, and

heating pads

I Circulation module Skid-mounted circulation module consisting of:

• Circulation pumps

• Electric heaters

• Insulaled/hcat traced piping and

isolation valves for pumps and heaters,

instrumentation for now, pressure, and

temperature, and a local control panel

1 to 5 Injection zone metering Skid mounted metering module consisting of:

(IZM) modules Metering pumps, hydraulic diaphragm type, equipped

with a variable speed motor drive

• Water booster pumps, turbine type

• Insulatcdlheat traced piping and

isolation and control valves for pumps,

instrumentation for flow, pressure, and

temperature, and local control panels

I Air compressor Rotary type

I to 5 Distribution modules Urea solution distribution module consisting of

valved connections for urea and atomizing air, an

isolation valve and a pressure control valve for the

air/urea supply to each injector, a pressure indicator

for air/urea supply to each injector, and a flow

indicator for urea supply to each injector

1 Lot Wall-type injectors Dual-fluid type wall injector, with furnace wall

(Consisting panels, and hoses for air and urea supplies

of4-12per Lance-type injectors Dual-fluid type lance injector, with furnace wall distribution

module) panels, and hoses for air and urea supplies

I Lot Piping Between urea unloading skid and urea tank; between

urea tank and circulation module; and between

circulation module and IZM module(s). Insulatelhcat

traced piping, stainless steel

24
Table 3-1. Major Equipment List for au SNCR Application

Quantity Item Description/Size

I Lot Piping Between 12M module(s) and distribution modules.

Insulatedlheat traced tubing, stainless steel

I Lot Tubing Between distribution modules and injectors.

Insulatcdlheat traced tubing, stainless steel

I Lot Dilution water piping Insulatedlheat traced piping, carbon steel, with

isolation and pressure reducing valves

I Lot Miscellaneous piping Piping/tubing and valves for flushing water,

atomizing air, and control air

I Lot Piping supports Structural support steel, including a pipe bridge, for

supporting all piping

I Lot Economizer outlet Monitor NOu and O2 in the flue gas and provide a

emission monitors feedback signal for urea injection control

I Lot Instrumentation and Instrumentation and stand-alone, microproccssorcontrols based controls for the SNCR system with feedback

from the plant controls for the unit load, NOx

emissions, etc.

I Enclosure Pre-engineered, heated and ventilated enclosure for

the circulation and metering skids

1 Lot Foundations FOWldations and containment walls for the tank and

equipment skids, enclosure, and piping support steel,

as required

I Lot Platforms/stairways Platform/stairway modifications and additions for

access to injectors

I Lot Asbestos removal Asbestos removal and reinsulation, for a retrofit

installation

estimates can be used t6 compare or screen alternative technologies without engaging an SNCR

supplier to obtain system cost quotes. This study cost estimating methodology and associated

costs, in December 1998 dollars,I are described in the following subsections. The cost estimating

I For infonnation on adjusting these cost estimates to other time periods, refer to the EPA

report, Escalation Indexes for Air Pollution Control Costs, and updates thereto, all of which are

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

Chemical Engineering Plant Cost Index"Equipment"componentpublishedinChemicalEngineering

magazine can be used.

25
procedures presented follow the recommendations in the 1993 Electric Power Research Institute

(EPRI) Technical Assessment Guide [8).

Equipment Costs

The total process capital cost factors for an SNCR application on a boiler are presented in

Table 3-2. These factors arc used to estimate direct and indirect costs.

hrstal/alion Costs

Direct and indirect installation costs are included in the process capital costs in Table 3-2.

Total Plant Capital Requirement

The total plant capital requirement is estimated using several factors applied to the total process

capital cost. These factors follow the EPR! cost estimating methodology and are presented in

Table 3-2.

Estimating Total Annual Costs

Total annual costs, including direct and indirect annual costs. arc discussed in this section. No

byproduct recovery credits were included because there are no salvageable byproducts generated

from the SNCR.

Direct A""ual Costs

Direct annual costs include variable and fixed costs. Variable direct annual costs account for

reagent purchase, utilities (electrical power and water). and any additional coal and ash disposal

resulting from the operation ofthe S CR. Fixed direct annual costs include operating and

supervisory labor and maintenance (labor and materials). These costs are discussed individually

below.

Operating and Supervisory Labor

For the purpose ofthis cost estimate. operation ofthe SNCR is assumed not to require any

additional operating or supervisory labor.

Maintenance

The annual maintenance labor and material cost is assumed to be 1.5 percent ofthe Total Plant

Capital Requirement (TPCR). This includes annual replacement ofthe injector nozzle tips:

Maintenance Cast ($/yr) 0.015 x (TPCR, S/kW) x MW x 1,000 kWIMW (13)

Reagent

The annual cost ofreagent purchase is estimated using the urea flow rate calculated above and

the following equation:

Reagent Cost (Slyr) = (Reagent, gph) x 8,760 (hr/yr) x (CF/IOO) x RC (Sigal) (14)

26
I Description

Table 3-2. Capital Cost Factors for an SNCR Application

1 Data or Formula

Boiler Size (MW)

Cost Year

!MW ... .

i December 1998 ....................................................................................r- .

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

I A = 9.0(SlkW) x (25:;:V)O.S17 x (0.66 + 0.0085 x TJNOx)

Indirect Costs: ........................................................................................................................................................................................................

..~.~~~:.~~ ..~~.~.~~.i.~~.~.~ ..~.~.~.~? .L..~:.~.?.~ 1 . Engineering and Home Office Fces : 0.1 0 x A

Process Contingency (SIkW) 0.05 x A

Total Plant Cost Without Pcoject :'. B = A +(0.05 + 0.1 0 + 0.05), A =1.2, A

Contingency ($/kW) .....................................................................................; .

Project Contingency (S/kW) 0.15 x B

Total Plant Cost (TPC) ($/kW) : C B x 115 .................................................................................... : .

Allowance for Funds During Construction! AFDC = 0 (typical for SNCR)

Total Plant Investment (TPI) ($/kW): TPI = C + AFDC ..........................................................................................................................................................................................................

~~~alty~lI~:":~n~c(~I!<""!iO(typi~alf~,~~~~!

~~cr.~""uction~~st(~I!<""!.L?O?~T~L

:::i;,t~~~;:;:~:~:::~~i~i$IkW)··~~;;~;~~if~;SNCR)

Total Plant Capital Rcquicemcnts ($/kW) i TPCR = TPI x 1.02 + IC

• Cost for urea stored at site, Le" the first fill of the reagent tanks, using Equation

(11) fo,the volume:

IC [ Volume (gal) x Cost ($Igal) JI (MW x 1000)

27
Utilities

The estimated electrical power consumption is predicted using equation (15). The equation is

derived in Appendix B and shown below:

kW 0.47 x NO.", (lbIMMBIlI) x NSR x MW (IS)

The annual cost of electricity is estimated from the following equation:

Eleclriciry Cost ($Iyr) = kW x 8,760 (hr/yr) x (CFIIOO) x EC ($lkW)

The annual cost of water for diluting the urea is calculated from the water flow rate:

(16)

{

Urea 50% (lbl hr)} {% urea solution stored Water,gph= x 8.345 (Ibl gal) % urea solution injected (17)

For urea dilution from a 50-percent to a IO-percent solution, Equation (17) becomes:

Water (gph) [ Urea 50% (Iblhr) 18.345 (Iblgal) 1x 4

Waler COSI ($Iyr) = (Water, gph) x 8,760 (hrlyr) x (CFIIOO) x WC ($Igal)

(17A)

(18)

Coal and Ash

The additional coal required as a result ofthe heat used to evaporate the water in the injected

solution (water in the stored urea solution and the dilution water) is estimated using the following

equation.

lJ,Coal (MMBtlllhr)

Reagent (fbi hr) x 900 (BIll I Ib) ( 100 )

= 1,000,000 (Btll I MMBtll) x % IIrea Sollllion injected 1 (19)

The approximate heat of vaporization ofwater at 310°F is 900 BtuIlb, which is a representative

temperature for flue gas exiting the air heater. Although the water from the urea solution is

evaporated in the furnace at higher temperatures (due to urea injection in the furnace zones at

over 1,500 OF), the temperature at the air heater exit is used because it is the thennodynamic end

point ofthe combustion process. The quantity offuel burned in the boiler depends on the boiler

efficiency, which, in turn, depends on the air heater exit temperature and the moisture in the air

heater exit gas. The boiler is fired to maintain the required steam flow (e.g., for the steam

28
turbine). Because the water from the urea solution evaporates in the boiler, the boiler efficiency

decreases. Consequently, more fuel needs to be burned to maintain the required stearn flow.

With urea as the reagent, injected as a 10 percent solution. Equation (19) becomes:

6Cool (MMBllllhr)

{[Reagenl (Ib/hr) x 900 (Bll/llb)]/ [1,000,000 (BIl/IMMBIII)]}x9

The estimated additional ash to be disposed of as a result of burning additional coal is:

flAsh (Iblhr)

(19A)

{ [6Coal (MMBlu/hr) x (Ash(%)1100)]/ [HHV (Blu/lb)] } x 10' (BIl/IMMBIl/) (20)

Simplifying,

flAsh(lb/hr)

6Coal (MMBIII/hr) x [Ash!,,';;) I HHV (Blllllb)] x 10,000

The costs ofthe additional coal and additional ash disposal are:

Casl aJadditional coal ($/yr)

6Coal (MMBlu/hr) x 8,760 (hrlyr) x (CF/IOO) x CC (SIMMBIl/)

COSI ojadditional ash disposal (Slyr)

(20A)

(21)

[flAsh (Ib/hr) x 8,760 (hrlyr) x (CFIIOO) x AC (Sllon)] /2,000 (Ibllon) (22)

Combining Equations (20A) and (22):

COSI ojadditional ash disposal (Slyr)

[438 x 6Coal (MMBlu/hr) x Ash% x CF x AC]/ HHV (22A)

Indirect Anllual Costs

In general, indirect annual costs include the capital recovery cost, property taxes, insurance,

administrative charges, and overhe3;d. Capital recovery cost is based on the anticipated

equipment lifetime and the annual interest rate employed. A system lifetime of20 years is

typical for SNCR systems.

29
Total indirect annual costs can be expressed as:

( FTAX ) FOV1/D . lAC ($ I yr) = CRF + -- x TPCR x MJV x 1,000 + x Mamtenance

100 100

The capital recovery factor, CRF, is defined by:

i(1 +if CRF - --'--'--

(1 +i)" - I

(23)

(23A)

As discussed in Reference [9], in many cases property taxes do not apply to capital

improvements such as air pollution control equipment. Therefore, FlAX is zero. Further, an

SNCR system is not viewed as risk-increasing hardware (e.g., a high energy device such as a

boiler or a turbine). Consequently, insurance on an SNCR system is on the order of a few

pennies per thousand dollars annually [9]. The administrative charges, covering sales, research

and development, accounting, and other home office expenses, incurred in operation of an SNCR

system are relatively insignificant for the cost estimation procedure presented here. Finally,

there are two categories of overhead, payroll and plant. Payroll overhead includes expenses

related to labor employed in operation and maintenance of hardware whereas plant overhead

accounts for items such as plant protection, control laboratories, and parking areas. Because this

procedure assumes that no additional labor is needed in operation of an SNCR system, payroll

overhead is zero and plant overhead is considered to be negligible.

Thus, for the purposes oflhis methodology, FlAX = FOVIlD = 0 and Equation (23) reduces to

lAC ($Iyr) = CRF x TPCR x MW x 1,000 (233)

Total AII"ual Cost

The total annual cost for owning and operating an SNCR system is the sum of direct and indirect

annual costs. Annual costs (S/year) can be converted to S/kW-year (S/kWyr) by the following

equations.

For variable costs (reagent, utilities, coal, and ash), the conversion is:

$/kWyr ($Iyr) / [MW x 1,000 x (CFIlOO) 1

For fixed costs (maintenance and all indirect annual costs), the conversion is:

$/kWyr = ($Iyr) / [MW x 1,000)

30

(24)

(24A)
The tons ofNO. removed annually are:

TNo. = NO" (lbIMMBIII) x('1"""'IOO) xQ. (MMBtulhr) x(CFllOO) x(8,76012000) (25)

Or,

TNO' 0.000438 x NOx, (lbIMMBIII) X '1NO' x CF x Q" (MMBtulhr)

Using a heat rate of9500 BtulkWh, boiler heat input is estimated as QH = 9.5 x MW.

Substituting for QB. equation (25A) becomes:

TNO> 0.004161 x NO" (lblMMBtu) x '1""" x MW x CF

The cost in dollars per ton ofNO.. removed per year is:

$Iton NO, Annual Costs ($Iyear) I TNO'

31

(25A)

(258)

(26)
Chapter 4

Summary of Equations

The mathematical expressions presented in this report, and associated equation numbers, are

summarized below. The summary serves as a reference guide that can be used to estimate the

cost ofan SNCR system, as illustrated by the example provided in Chapter 5.

Design Factors for an SNCR Application

(0.7 + 2 x NOxb(lb / MMBtll» x (TlNO /100) N~= x

NOXb (Ib / MMBIII)

Reagent (lb/hr) = [NO", (lbIMMBIlI) X Q. x NSR X MW. 1/ (46.01 x SRr)

SO/lltion (lb/hr) = Reagent (lb/hr) x 1000e ("A;)

So/lIlion (gph) = So/Iltion (lb/hr) x 7.481 / P

Vol. (gal) = So/Iltion (gph) x No. ofdoys x 24 hrlday

32

(8)

(9)

(10)

(11 )

(12)
Capital Cost Factors for an SNCR Application

Direct Costs:

Total Process Capital Costs

($/kW):

Indirect Costs:

Total Plant Cost Without Project

Contingency ($/kW)

Totnl Plant Cost (TPC) ($/kW):

Total Plant Investment (TPI) ($/kW):

Inventory Capital- ($/kW)

Total Plant Capital Requirements

Annual Costs for SNCR Application

DirectAmmol Costs

Maintenance:

B~1.2xA

C=BxI.15

TP/=C+AFDC

Volume in gallons x cost per gallon IC - -----';----....,-''---''--

- (MW x 1,000)

TPCR = TP/ x 1.02 + IC

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

Reagent:

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

Utilities:

kW 0.47 X NOXh x NSR x MW

Electricity Cost ($/yr) kW x 8,760 (hr/yr) x (CFIlOO) x EC

(13)

(14)

(15)

(16)

Water. {

Urea 50% (lb / hr)} {% urea solution stored } gph= x -I

8.345 (Ib / gal) % urea solution injected

33

(17)
Water Cost ($Iyr) (Waler, gph) x 8,760 (hr/yr) x (CFIIOO) x WC

Coal and Ash:

!>.Coal (MMBlulhr)

Reagenl (lb 1 hr) x 900 (Btu lib) ( 100 )

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

Cost ofadditional coal ($/yr)

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

Cosl ofadditional ash disposal ($Iyr)

[438 !>.Coal (MMBtulhr) x Ash x CF x AC ] I HHV

I"direct Allllual Costs

lAC ($Iyr) CRF x TPCR x MIll x 1,000

Total AlIllual Cost

(18)

(19)

(21 )

(22A)

(236)

The total annual cost is the sum ofdirect annual costs and indirect annual costs. These annual

costs (S/year) can be converted to $/kWyr according to:

$lkWyr~ ($Iyr) I [MIll x 1,000 x (CFIIOO)] (24)

TNO' NO", (IblMMBtu) x(1]No/I00) XQ8 (MMBtulhr) x(CFIIOO) x(8,76012000) (25)

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

34

(26)
Chapter S

An Example Calculation

In this example, cost estimates are developed for retrofitting a 500 MW wall-fired boiler with a

urea-based SNCR system. The example uses the equations summarized in Chapter 4. The

methodology also was used to estimate costs for existing S CR installations. Appendix C

shows how these estimated costs compare with costs reported in the literature for several

installations.

Design Basis

A summary ofthe design basis for the 500 MW boiler retrofitted with an SNCR system is

presented in Table 5-1.

The economic factors for this example are presented in Table 5-2. Most of these factors are from

References [3] and [4]. However, if applicable, other values may be chosen for these factors and

used in the cost estimating procedure.

Equipment and Consumables Data

Based on Equation (8), the estimated normalized stoichiometric ratio, NSR, for 35 percent NOx

reduction is:

3S (0.7 +2x0.46 IblMMBtu) x 100

NSR = ------,,"77~=~---=..::-'­ 0.46 IblMMBtu

The urea consumption rate using Equation (9B) is:

= 1.23

Urea, lblhr 6.200 x 0.461b1MMBtu x 500 MW x 1.23

Urea, lblhr = 1,754lblhr

The 50% urea solution flow rates using Equations (10) and (II) are:

35
Table 5-1. Design Data

Design Parameters 500 MW Boiler

Full load Boiler heat input, MMBtuJhr' 4,750

Uncontrolled NOx, IblMMBtu 0.46

Required NOx reduction, % 35

Fuel HHV, Btullb 12,696

Fuel ash weight, % 7.7

Annual NOx removed, tons/year·· 2,177

Stored Urea Reagent 50% aqueous solution

Injected Urea Reagent 10% aqueous solution

Number ofdays of urea storage 14

Plant Capacity Factor, % 65 '

'Boiler heat input 9.5 x 500MW = 4,750 MMBtu/h

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

1,754 lblhr Urea 50% solution, lblhr = "',...",..-.....:7,:;.....:~;;.,--..,..,.,.- = 3,508 lblhr

0.5 /b ureal/b of 50% sO/lIIion

Urea solution, gph = 3,508 lblhr x 7.481 gallft' = 369.6 gph

71 Iblft3

The total volume for 14-days of urea storage using Equation (12) is:

Vol 369.6 gph x 14 days x 24 hr/day = 124,186 gallons

J This capacity factor is a measure ofthe average annual use of the boiler and SNCR. It

accounts for the time when the plant is not operating and when it operates at partial loads. A 65-

percent capacity factor is typical of a load-following plant with an annual outage. A base-loaded

plant would have a higher capacity factor, for example, 90 percent.

36
Table 5-2. Economic Factors

Cost Year December 1998

Equipment Life 20 years

Annual Interest Rate 7%

Electrical Power Cost $0.05IkWh

Coal Cost, Eastern Bituminous $1.601MMBtu

Ash Disposal Cost SIt.28/short ton

Urea Cost (50% solution) $0.85/g.lIon

Water Cost $0.0004/g.lIon

The estimated electrical power consumption using Equation (15) is:

Electrical power consumption 0.47 x 0.46 Ib/MMBIU x 1.23 x 500 MW 133 kW

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

4.0 x 3,508 Iblhr urea solution

Water, gph = -"'--~~~,--;;=-i-':":"'_'--- = 1,681 gph 8.345 Iblgal

The estimated additional coal required to account for the heat used to evaporate water in the injected

urea solution using Equation (19A) is:

900 Btullb

tJ.Coa/ = 1,754 Iblhr urea x ,,=:';;;""~-i.c;;-;;= 1,000,000 Btu/MMBtu

Using Equation (20A), the addition.l ash to be disposed of is:

x 9 = 14.21 MMBtulhr

tJ.Ash = 14.21 MMBwllb x 7.7 x 10,000 = 86 Iblhr

12,696 Bwllb

Total Capital Requirement

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

37
Table 5-3. SNCR Capital CosIs

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

GencraJi'iiciiiiies(SikW)·····T···o:osxs:iii:;;..ii:29· ··Eng"iii:ec;·rlIig·ancfHo·m·e·offi(;e··Fees···················r

··· _--_ __ .

($IkW) . 0.10 x 5.78 0.58

Process·Coiiiingeiicy(SikW)······O:oSxs:iii;;;029···

Total Plant Cost Without Project 1.2 x 5.78 6.94

Contmgency ($/kW) . ......................- __ - -_··············__····__···__············t············ _-_ __ . Project Contingency ($IkW) , 0.15 x 6.94 1.04

Total Plant Cost (TPC) ($IkW): 1.15 x 6.94 7.98 ··Aito·wance'fo~··F·un(rs·jjurrng·C·onsiiUci·io·n··T········· .

($/kW) 0

Total Plant Investment (TPI) ($/kW): 7.98

RoyiiiiYAiiowance(SikWjTo"

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

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

Inventory Capital' ($/kW) 124,186 gals x $0.85Igal = $0.21IkW

500MW x I,OOOkWIMW

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

Initial Catalyst and Chemicals ($IkW) , 0

Total Plant Capital Requirement ($IkW): $7.98 + $0.16 + $0.21 - $8.35

• Cost for urea stored at site, i.e. the first fill of the urea tanks:

Volume in gallons x cost per gallon IC($I kW) = -----"------'-----''---

MWx 1,000

Total Annual Costs

The annual costs are converted to $IkWyr and $/ton NO, removed by Equations (24), (24A), and

(26).

38
Annual maintenance labor and material costs are calculated below using Equation (13) :

Maintenance, Slyr = 0.015 x S8.35 x 500 kW x 1,000= S62,625 Iyr

Maintenance, SlkWyr = S62,625 = SO.13lkWyr

500 MW x 1,000 kWIMW

. S62625 Mamtenance, Siton NOx removed = ' = S291ton NOx 2,177 ton NO

x

The total variable direct annual cost (urea, electricity, water, coal, ash disposal) associated with

applying SNCR to a 500 MW bailet is detemlined from Equations (14) through (22A):

Annual Reagent Cost:

= (369.6 gph) x 8,760 hrlyr x (65/100) x 0.85 (Sigal) = SI,788,8271yr

Annual electricity cost:

= 124 kW x 8,760 hrlyr x (65/100) x 0.05 (SlkWh) = S35,3031yr

Annual water cost:

= 1,681 gph x 8,760 hrlyr x (65/100) x O.OOO4(S/gal) = S3,829/yr

Annual cost of additional coal:

= 14.21 MMBtu/hr x 8,760 hrlyr x (65/100) x 1.60(SIMMBtu) = SI29,4591yr

Annual cost of additional ash disposal:

= (438 x 14.21 MMBtulhr x 7.7 x 65 x 11.28 (S/shtan)) 112,696)= S2,7681yr

Total Variable Direct Annual Cost:

= Sl,788,8271yr + S35,3031yr + S3,8291yr + SI29,4591yr + S2,7681yr

= SI,960,1861yr

In terms ofS/kWyr, the total variable direct annual cost for the 500 MW boiler is caleulated from

Equation (24):

SI,960,I861yr = =--,-;--;;;;,;,-,,-'=~ 500 x 1,000 x 65/100 = S6.031kWyr

In terms of S/ton NOx removed, the annual total variable direct annual cost for this boiler is

calculated from Equation (26):

39
= -:<-S-;:I,9",6.:.:0,-:...18...:,6",lyr"

2,177 Ion NOx

= S900 IronNO

x

The total direct costs are summarized in Table 5-4.

Table 5-4. Direct Costs

Boiler Size 500MW

Uncontrolled NO" IblMMBtu 0.46

Maintenance $62,6251 yr

SO.131 kW-yr

S291 ton NO,

Total Variable Direct Annual Costs SI,962,748/yr

S6.04IkW-yr

S902 1ton NO,

Total Direct Cost $2,025,3731 yr

$6.17IkW-yr

S931 1ton NO,

With a plant life of20 years and an interest rate of7% (see Table 5·2), the capital recovery factor

is 0.09439 (see Chapter 2). Using this factor, the indirect costs calculated using Equations (23B),

(24), and (26) are:

= 0.09439 x S8.35IkW= SO.791kWyr

= SO.791kWyr x (500 MW x 1,000 kW/MW) = S395,0001yr

=S395,000/2, 177 = S181 1ton NOx removed / kWyr

These costs are summari7...cd in Table 5-5.

Table 5-5. Indirect Annual Costs

Boiler Size 500MW

Uncontrolled NO" IblMMBtu 0.46

Total Indirect Costs S395,000 1yr

SO.79 1kW-yr

SI81/ton NO,

40
The Total Annual Costs, presented in Table 5-6 for the example, are the sum of the direct and

indirect annual costs.

Table 5-6. Total Annual Costs

Boiler Size 500MW

Uncontrolled NO.. IblMMBtu 0.46

Tntal Annual Cost $2,420,373/ yr

$6.96 kW-yr

$l,ll21tonNO

41
References

I. Compilation ofAir Pollutant Emission Factors, EPA Document No. AP-42, Vol. 1. U.S.

Environmental Protection Agency, 1995.

2. Stultz, S.C. and lB. Kitto (cd.) Steam: Its Generation and Use. 40th edition, The

Babcock & Wilcox Company, Barberton, Ohio, 1992.

3. Investigation a/Performance and Cost o/NOx Controls as Applied to Group 2 Boilers.

Revised Draft Report, The Cadmus Group, Inc., Bechtel Power Corporation, and Science

Applications International Corporation) August 1996.

4. Cost Estimates/or SelectedApplications ofNOt Control Technologies on Stationary

Combustion Boilers, Draft Report and Responses to Comments on the Draft Reporl. The

Cadmus Group, Inc., and Bechtel Power Corporation, June 1997.

5. Analyzing Electric Power Generation Under the CAM. EPA Office ofAir and

Radiation, March 1998.

6. SNCR Committee ofthe Institute of Clean Air Companies, Inc. White Paper, Selective

Non-Catalytic Reduction (SNCR) for Controlling NOx Emissions. October 1997.

7. Tanner Industries, Inc. Storage & Handling ofAmmonium Hydroxide. Philadelphia. PA,

October 1995.

8. Electric Power Research Institute. Technical Assessment Guide, Vol. 1, Revision 7.

1993.

9. NESCAUM. Status Report on NOx Control Technologies and Cost Effectivenessfor

Utility Boilers. June 1998.

10. United States Patent, Method For The Reduction Of The Concentration OfNO In

Combustion Effiuents Using Ammonia. Inventor: Richard K. Lyon, Patent Number

3,900,554, August 19, 1975.

42

.'
11. Rini, MJ., J.A. Nicholson, and M.B. Cohen. Evaluating the SNCR Processfor

Tangentially-Fired Boilers. Presented at the 1993 Joint Symposium on Stationary

Combustion NOx Control, Sal Harbor, Florida, May 24 - 27, 1993.

12. Personal Communication with Alex DainofTand Dale Pfaff of Fuel Tech on Tuesday,

March 16, 1999.

43
Appendix A.

1.0 FUELS

Design/Performance Data for SNCR Retrofit on a

250 MW Wall-Fired Boiler

Eastern Bituminous Coal

Ultimate Analysis (% By Weight) Coal for 250 MW

Plant

Carbon 72.8

Hydrogen 4.20

Nitrogen 1.34

Oxygen (by difference) 4.76

Sulfur 0.80

Moisture 8.40

Ash 7.70

TOTAL 100.00

Higher Heating Value, Btullb 12,696

2.0 SNCR SYSTEM DESIGN BASIS

2.1 Boiler

Boiler Steam Output, percent 100% 70% 30%

of full load

Boiler heat input, MMBtu/hr 2,604 1,919 885

Flue gas flow at economizer 2,658,500 1,960,400 903,500

outlet, Ib/hr

Uneontrolled NOx at 0.46 0.46 0.46

economizer outlet, IbIMMBtu

44
2.2 Flue Gas Composition

Flue Gas Composition % Vol. Dry

N, 80.83

CO, 14.97

0, 4.14

SO, 0.062

Moisture 7.81

2.3 Typical Flue Gas Temperature Profile

Location 100% Load 30% Load

Entering high temperature secondary 2,270 1,970

superheater

Leaving high temperature secondary 2,030 1,730

superheater

Entering low temperature secondary 2,030 1,730

superheater

Leaving low temperature secondary 1,810 1,510

superheater

Entering high temperature rcheater 1,810 1,510

Leaving high temperature reheater 1,540 1,240

Entering low temperature reheater 1,540 1,240

Leaving low temperature reheater 1,420 1,200

45
Appendix B. Development of S CR Related Equations

This appendix illustrates the methodology used to develop two ofthe equations presented in this

report. They include equations (5) for reagent utilization, (8) for normalized stoichiometric ratio,

and (15) for electric power consumption.

EQUATION (5) - Reagent Utilization

Because the urea injected into the furnace thermally decomposes to produce ammonia. equation

(5) is derived in temlS of ammonia, NH). However, the equation is valid for urea. The definition

ofreagent utilization is the ratio ofmoles of reagent reacted to the moles injected, both in terms

of ammonia:

Utilization = (moles ofNHJ reacted) / (actual moles Nfl] injected) (B1)

According to the chemical reaction shown in Equation (2), the moles ofNH) reacted are the same

as the moles ofNO" removed. (Equation (1) shows two moles of urea per mole ofNO~ removed.

However, the moles ofNH] reacted are also the same as the moles of NOll removed because two

moles of ammonia are released by the urea.) Equation (Bl) becomes:

Ulilization = (moles NO~ removed) I (actual moles NHJ injected)

The moles of NOll removed are:

(B2)

Moles NO, removed = (moles uncontrolled NO) x (NO, reduction, %) /1 00 (83)

Substituting Equation (B3) into (82):

Utilization = (mQles uncontrolled NO.> x (NOT reduction, %)

100 x (actual moles NH, injected) (B4)

Rearranging Equation (3), the definition ofNSR, to solve for the moles of uncontrolled NOx,

Moles uncontrolled NO~ = moles ofequivalent NHJ / NSR

Substituting Equation (85) into (84):

Utilization = (moles ofequivalent NH,) x (NO. reduction, %)

100 x (actual males NH, injected) x NSR

46

(B5)

(86)
The term, actual moles ofNHJ injected, is the same as the tenn, moles of equivalent NHJ• used in

Equation (3). Therefore, Equation (B6) becomes Equation (5):

NOx reduction (%)

Utilization = 100 x NSR

EQUAnON (8) - Normalized Stoichiometric Ratio (NSR)

(5)

Equation (8) is derived from data in References 2 and 3. The form ofthe NSR equation was

selected to nonnalize the data with NOx efficiency by dividing the reported NSR by NOx

efficiency. Therefore, the correlation was performed on NSR divided by (NOx efficiency/IOO)

versus lI(NO, inlet Ib/MMBtu). The table below shows the data from References 2 and 3 and

the calculated values ofNSR/(~NoJIOO)and lINO,.

NO! in, IINOx in NSR NO, NSR/(~No/IOO) Reference

Ib/MMBtu removal, %

lAO 0.714 0.900 35.000 2.571 2

lAO 0.714 0.900 34.615 2.600 2

0.95 1.053 0.900 34.737 2.591 2

0.92 1.087 0.900 34.783 2.588 2

1.20 0.833 0.900 35.000 2.571 2

1.20 0.833 0.900 35.000 2.571 2

0045 2.222 1.750 50.000 3.500 3

0.50 2.000 1.750 50.000 3.500 3

The <"NSRJ(TlNo/l 00)" and "IINOx" were correlated using a linear regression. The results ofthe

regression (using Microsoft Excel's Data Analysis Tool) are:

• Slope 0.7

• Intercept = 2

• Correlation coefficient, r = 0.969

The equation is:

-:-_N._SR,..,.-,-:c- =2 +0.7 x ( 1 )

(~/l00) NOXb(lbl MMBtll) NOX

47

(31)
Multiplying both sides ofthe equation by 11"";100 and multiplying the right hand side by (NOxt!

NOXb) yields Equation (8):

(2x NO..(/bl MMBlu) +0.7) x (qNO 1100) NSR = .,

NOxh(/bl MMBtlI)

EQUAnON (15) - Electrical Power Consumption

(8)

Equation (15) is derived from data in References 2 and 3. The table below shows the data from

these references and the calculated constant, (N0Xb x NSR x MW).

Boiler NO.b, NO. in, NSR MW kW (NO.a! X NSR x Ref.

IblMMBtu MW)

100MW 0.95 0.90 100 25 85.50 3

wet bottom

IIOMW 1.20 0.90 110 51 118.80 3

vertical

150MW lAO 0.90 150 67 189.00 3

cyclone

259MW 0.92 0.90 259 109 214.45 3

wet bottom

220MW 1.20 0.90 220 95 237.60 3

vertical

348MW 0045 1.75 348 157 274.05 4

tangentially

-fired

381 MW 0.50 1.75 381 193 333.38 4

wall-fired

400MW lAO 0.90 400 205 504.00 3

cyclone

The terms "(NOXb x NSR x MW)" and "kW" weTC correlated using a linear regression stipulating

that the intercept is zero. An intercept of zero is used so that kW equals zero ifthe (NOXt, x NSR

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

urea now ratc depends on it (see Equation 9) and the power consumed is related to the urea flow

rate. The results ofthe regression (using Microsoft Excel's Data Analysis Tool) arc:

48
Slope 0.47

Correlation coefficient, r= 0.930

The equation from the correlation is:

kJV~ 0.47 x N0x> (/b/MMBtu) x NSR x MJV (15)

49
Appendix C. Comparison of Results from Methodology with

Industry Case Studies

Using the methodology ofthis report, this appendix presents calculated results for existing

SNCR installations. The calculated results are compared with the case studies in Chapter 4 of

Reference C-I. i.e, data reported for these SNCR installations by the Northeast States for

Coordinated Air Usc Management (NESCAUM) and the Mid-Atlantic Regional Air

Management Association (MARAMA). Variables from the example case (Chapter 5) were used

in the methodology for these calculations. These variables are defined in Table C-I. Other input

data were based on data reported for the facilities considered. These input data, predicted NSRs.

and the comparison of predicted costs with reported costs are shown in Table C-2.

Table C-t. Variables from the Example Case Used in Table C-2

Fuel HHV, Btu/lb 12,696

Fuel ash weight, % 7.7

Number of days of urea storage 14

Annual Interest Rate 7%

Electrical Power Cost $0.05/kWh

Coal Cost, Eastern Bituminous $1.60IMMBtu

Ash Disposal Cost $11.28/shorl ton

Urea Cost (50% solution) $0.85/gallon

Water Cost $0.0004/gallon

The predicted costs shown in terms of S/too ofNOx removed are based on an assumed discount

rate of7 percent to be consistent with the methodology presented in this report. 1b.is assumption

is necessary because the referenced report [C.1] did not indicate the discount rate used by each

utility. Although the representativeness of these comparisons is uncertain because ofthis

assumption, they provide the reader with some indication of how predicted values may compare

with reported ones.

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Table C-2. Comparison ofNESCAUM Data [Reference C·ll with Results Estimated Using the Urea-Based SNCR Costing

Methodology

Parameters Salem Montaup Bl England 1 Bl England Bl England 3 Seward Mercer 1 Mercer 2

Harbor 2 Somerset 2

Input Data

Boiter Size, MW 84 112 130 160 160 147 321 321

Uncontrolled NOx, 0.6 0.8 1.2 1.2 0.3 Design: 0.75 1.8 1.8

Ib/MMBtu Operating: 0.7

NOx Reduction, % 50 53 29 29 33 Design: 40 33 33

Operating: 36

Predicted NSR 1.58 1.51 0.75 0.75 1.44 Design: 1.17 0.8 0.8

Operating: 1.08

Capacity Factor, gO gO 50 50 10 70 43 48

%

Project Life, Yrs 5 15 15 15 15 5 20 20

(assumed)

Capital Recovery 0.2439 0.1098 0.1098 0.1098 0.1098 0.2439 0.09439 0.09439

Factor

Comparison of Predicted Values with Those Reported in Reference C-1 (in 1996 Dollars)

TPCR, $/kW

Predicted 26 22 17 15 15 17 11 11

Reported in (C-1 J 18 -16 15.4 12.5 9.37 -23 14 14

Total Annual Costs, $/ton NOx Removed

Predicted 1,242 771 816 786 5,427 1,224 603 593

Reported in IC-1] 670 900-1000 No data No data No data -1,775 -800 -800

5\
Notes for Table C-2:

1. The input data in Table C-2 are from Reference C-l, with the following exceptions:

• The capital recovery factor is calculated using the 7% interest rate and the pertinent

project life.

• The project life for Montaup is assumed. See Note S.

2. The costs predicted using this report's methodology have been adjusted to 1996, the

approximate year ofthe Reference C·l costs. The downward adjustment was based on

the Cbemical Engineering Plant Cost Index, reported to be 390.4 for December 1998 and

381.7 for 1996.

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

4. SNCR systems were installed on Salem Harbor Units 1,2, and 3. Only Unit 2 is included

in Table C-2 because the costs reported for Units 1 and 3 included other technologies,

such as Jow-NOx burners, Qverfire air, and burner management systems. The Unit 2

costs are representative ofSNCR alone.

5. For Montaup, the project life was assumed to be 15 years. This is equal to the period

used in the methodology sections of Reference C-l (Chapters 1to 3). However, Chapter

4 of Reference C-I (the case studies) does not state that control costs in S/ton NOx

reported for Montaup are based on a IS-year project life.

6. The SNCR at Seward has a more complex injection system than other installations. This

results in a higher actual capital cost [C-I].

7. SNCR systems were installed on Mercer Units 1 and 2. Although there is a shared

250,000 gallon urea tank, the two units have independent SNCR systems. Any reduction

in capital and levelizcd costs because of this shared tank should be minimal.

Reference

C-l J. E. Staudt, "Status Report on NOx Control Technologies and Cost Effectiveness for

Utility Boilers", published by Northeast States for Coordinated Air Use Management

(NESCAUM) and Mid-Atlantic Regional Air Management Association (MARAMA),

June 1998.

52