Section 4

NO

x

 Controls

EPA/452/B-02-001
i

Section 4.2

NO

x

 Post- Combustion

EPA/452/B-02-001
ii

Introduction

Nitrogen oxides (NOx) are gaseous pollutants that are primarily formed through combustion

process. While flue gas is within the combustion unit, about 95% of the NOx

 exists in the form of

nitric oxide (NO). The balance is nitrogen dioxide (NO2

), which is unstable at high temperatures.

Once the flue gas is emitted into the atmosphere, most of the NOx is ultimately converted to NO2.

NOx in the atmosphere reacts in the presence of sunlight to form ozone (O3), one of the criteria

pollutants for which health-based National Ambient Air Quality Standards have been established.

Since ozone formation requires sunlight and high temperatures, ozone formation is greatest in

summer months.

NOx is generated in one of three forms; fuel NOx, thermal NOx, and prompt NOx. Fuel

NOx

 is produced by oxidation of nitrogen in the fuel source. Combustion of fuels with high nitrogen

content such as coal and residual oils produces greater amounts of NOx

 than those with low

nitrogen content such as distillate oil and natural gas. Thermal NOx is formed by the fixation of

molecular nitrogen and oxygen at temperatures greater than 3600F (2000C). Prompt NOx

forms from the oxidation of hydrocarbon radicals near the combustion flame and produces an

insignificant amount of NOx.

Selective Noncatalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR) are

post-combustion control technologies based on the chemical reduction of nitrogen oxides (NOx)

into molecular nitrogen (N2) and water vapor (H2O). The primary difference between the two

technologies is that SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the

process to occur at lower temperatures. The technologies can be used separately or in combination

with other NOx

 combustion control technologies such as low NOx burners (LNB) and natural gas

reburn (NGR). SNCR and SCR can be designed to provide NOx reductions year-round or only

during summer months, when ozone concerns are greatest.

This section presents design specifications and a costing methodology for SNCR and

SCR applications for large industrial boilers (greater than 250 MMBtu/hr). Its primary purpose is

to provide study-level cost estimates. These estimates can be used to compare the approximate

costs of SNCR, SCR, and alternative NOx control technologies. The costing methodologies are

based on cost estimations for SNCR and SCR applications to utility boilers, which were developed

by the Office of Research and Development (ORD), U.S. Environmental Protection Agency (EPA),

Research Triangle Park, NC.

As a prelude to the cost methodology, the section describes the process chemistry,

performance parameters, and system components of SNCR and SCR. In addition, impacts to the

boiler performance and facility operations resulting from the installation of SNCR and SCR are

presented. The section also estimates important underlying design parameters including the

normalized stoichiometric ratio, catalyst volume, and reagent consumption. Lastly, it presents
iii

assumptions and equations for estimating capital costs, annual operation and maintenance costs,

and annualized costs. SNCR and SCR are discussed in separate chapters, however, the chapter

on SCR builds on the concepts discussed in the SNCR chapter.

Information on key aspects of the design of SNCR and SCR systems is considered

proprietary by vendors, including methods for estimating certain design parameters and costs.

This information is not available to develop cost methodologies for SNCR and SCR. In order to

obtain estimates of the proprietary design parameters and costs, it is necessary to develop

mathematical correlations from available data using regression and curve fitting techniques. These

expressions are derived in EPA reports prepared by The Cadmus Group, Bechtel Power, Inc. and

SAICin SNCR and SCR References [1, 2 and 3] from documented comprehensive SNCR and

SCR performance data and costs based on quotations provided by suppliers and facilities.
1-1

Chapter 1

Selective Noncatalytic Reduction

Daniel C. Mussatti

Innovative Strategies and Economics Group

Air Quality Strategies and Standards Division

Office of Air Quality Planning and Standards

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

Dr. Ravi Srivastava

Office of Research and Development

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

Paula M. Hemmer and

Randy Strait

E. H. Pechan & Associates, Inc.

3622 Lyckan Parkway, Suite 2002

Durham, NC 27707

October 2000

EPA/452/B-02-001
1-2

Contents

1.1 Introduction ............................................................................................................................................ 1-3

1.2 Process Description ................................................................................................................................ 1-4

1.2.1 Reduction Chemistry .................................................................................................................... 1-5

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

1.2.3 SNCR Performance Parameters ..................................................................................................... 1-7

1.2.4 SNCR System.............................................................................................................................. 1-13

1.2.5 Other Considerations .................................................................................................................. 1-19

1.3 Design Parameters ................................................................................................................................ 1-21

1.3.1 Design Parameters for Study Level Estimates ............................................................................ 1-21

1.3.2 Design Parameters for Detailed/Performance Specifications ...................................................... 1-27

1.4 Cost Analysis ...................................................................................................................................... 1-30

1.4.1 Total Capital Investment ............................................................................................................. 1-31

1.4.2 Total Annual Costs ..................................................................................................................... 1-33

1.5 Example Problem .................................................................................................................................. 1-39

1.5.1 Design Parameter Example .......................................................................................................... 1-40

1.5.2 Cost Estimation Example ............................................................................................................. 1-42

References .................................................................................................................................................. 1-45
1-3

1.1 Introduction

SNCR is currently being used for NOx emission control on industrial boilers, electric utility

steam generators, thermal incinerators, and municipal solid waste energy recovery facilities. Its use

on utility boilers has generally been limited to units with output of less than 3,100 MMBtu, but

large-scale applications of SNCR have been successfully tested such as Cardinal Plant Unit 1, a

600 MW (5,700 MMBtu/hr) utility boiler located in Brilliant, Ohio [11]. SNCR can be applied as

a stand-alone NOx

 control or with other technologies such as combustion controls. The SNCR

system can be designed for seasonal or year-round operations.

SNCR can achieve NOx

 reduction efficiencies of up to 75 percent (%) in selected shortterm demonstrations [5]. In typical field applications, however, it provides 30% to 50% NOx

reduction. Reductions of up to 65% have been reported for some field applications of SNCR in

tandem with combustion control equipment such as low NOx

 burners (LNB) [11]. SNCR systems

applied to large combustion units (greater than 3,000 MMBtu/hr) typically have lower NOx

 reduction efficiencies (less than 40%), due to mixing limitations [11]. Figure 1.1 presents the NOx

reduction efficiency of SNCR for various utility boiler sizes.

0

10

20

30

40

50

60

0 1000 2000 3000 4000

Boiler Size (MMBtu/hr)

NOx Reduction Efficiency (%)

Figure 1.1: SNCR NOx Reduction Efficiency for Various Boiler Sizes [8]

The hardware associated with an SNCR installation is relatively simple and readily available. Consequently, SNCR applications tend to have low capital costs compared to LNB and

SCR. Installation of SNCR equipment requires minimum downtime. Though simple in concept, it

is challenging in practice to design an SNCR system that is reliable, economical, simple to control,

and meets other technical, environmental, and regulatory criteria. Practical application of SNCR is

limited by the boiler design and operating conditions.
1-4

The costing algorithms in this report are based on retrofit applications of SNCR to existing

coal-fired, dry bottom, wall-fired and tangential, balanced draft boilers. There is little difference

between the cost of SNCR retrofit of an existing boiler and SNCR installation on a new boiler

[10]. Therefore, the cost estimating procedure is suitable for retrofit or new boiler applications of

SNCR on all types of coal-fired electric utilities and large industrial boilers.

1.2 Process Description

SNCR is based on the chemical reduction of the NOx molecule into molecular nitrogen

(N2

) and water vapor (H2O). A nitrogen based reducing agent (reagent), such as ammonia or urea,

is injected into the post combustion flue gas. The reagent can react with a number of flue gas

components. However, the NOx

 reduction reaction is favored over other chemical reaction processes for a specific temperature range and in the presence of oxygen, therefore, it is considered a

selective chemical process.

The SNCR process occurs within the combustion unit which acts as the reaction chamber.

Figure 1.2 shows a schematic of a boiler interior with SNCR. Reagent is injected into the flue gas

through nozzles mounted on the wall of the combustion unit. The injection nozzles are generally

located in the post-combustion area, the upper area of the furnace and convective passes. The

injection causes mixing of the reagent and flue gas. The heat of the boiler provides the energy for

the reduction reaction. The NOx molecules are reduced and the reacted flue gas then passes out of

the boiler. More detail on the SNCR process and equipment is provided in he following sections.

PLATEN

SECONDARY

SUPERHEATER

SECONDARY

SUPERHEATER

PENDANT

REHEATER

PRIMARY

SUPERHEATER

CONVECTION

PASS

ECONOMIZER

HORIZ.

REHEATER

FURNACE

UREA

INJECTORS

BURNERS

UREA

INJECTORS

Figure 1.2: Boiler Gas Path Configuration
1-5

1.2.1 Reduction Chemistry

SNCR is a relatively simple chemical process. The process begins with an ammoniabased reagent, ammonia (NH3

) or urea (CO(NH2)

2

), being vaporized either before injection by a

vaporizer or after injection by the heat of the boiler. Within the appropriate temperature range, the

gas-phase urea or ammonia then decomposes into free radicals including NH3

 and NH2. After a

series of reactions, the ammonia radicals come into contact with the NOx and reduce it to N2 and

H2O. The global representation of these reactions is given below for both urea and ammonia. Note

that the NOx

 is represented as NO since it is the predominant form of NOx within the boiler. The

ammonia reaction equation is given by:

2 2 2 3 3

1 NO + NH +→+ 2 O N HO 2 2 2 (1.1)

The reaction for urea is given by:

2 2 2 2 2

1

NO + CO(NH ) O N CO H O +→ ++ 2 2 2 2 2 (1.2)

The primary byproduct formed during either ammonia or urea SNCR is nitrous oxide (N

2

O). N2O is an ozone depletor and a greenhouse gas but is currently not regulated. Urea based

reduction generates significantly more N2O than ammonia-based systems. Up to 30% of the NOx

can be transformed into N2O. Proprietary additives are available for the urea-based SNCR process to reduce the formation of N2

O. [10]

1.2.2 Reagents

Both ammonia and urea have been successfully employed as reagents. The cost of the

reagent is a large portion of the annual costs of operating an SNCR system. Ammonia is generally

less expensive than urea. However, the choice of reagent is based not only on cost but on physical

properties and operational considerations. The properties of urea and ammonia in aqueous solutions are shown in Table 1.1.

Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a

gas at normal atmospheric temperature. It must be transported and stored under pressure which

presents safety issues. Aqueous ammonia is generally transported and stored at a concentration of

29.4% ammonia in water. At concentrations above 28%, storage of ammonia may require a permit, therefore some recent applications of SNCR are using a 19% solution [1]. Decreasing the

concentration, however, increases the required storage volume. Ammonia is generally injected as

a vapor. Providing sufficient ammonia vapor to the injectors requires a vaporizer, even though the

29.4% solution has substantial vapor pressure at normal air temperatures. The injection system

equipment for vapor systems is more complicated and expensive than equipment for aqueous

systems (see Section 1.2.4 SNCR System)
1-6

Table 1.1: Urea and Ammonia Reagent Properties, [6]

Property Urea Solution Aqueous Ammonia

Chemical formula CO(NH2

)

2 NH3

Molecular Weight of reagent 60.06 17.03

Liquid or gas at normal air Liquid Liquid

temperature

Concentration of reagent 50% by weight 29.4% by weight

normally supplied

Ratio of NH3 to solution 28.3% by weight of NH3 29.4% by weight of NH3

Density of solution @ 60o F 71 lb/ft3 56 lb/ft3

(58 lb/ft3 for 19%)

Vapor pressure @ 80o

 F < 1 psia 13.9 psia [8]

Crystallization temperature 64o F - 110o F

Flamability limits in air Non-flammable Lower explosion limit = 16%

NH3 by volume; Upper explosion

limit = 25% NH3 by volume.

Threshold limit value (health Not Specified 25 ppm

effects)

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

Acceptable materials for Plastic, steel, or stainless Steel tank, capable of handling

storage steel (no copper or copper- at least 25 psig pressure (no

based alloys or zinc/aluminum copper or copper-based alloys,

fittings) etc.)

Urea is generally utilized in a 50% aqueous solution [1]. At this concentration, the urea

solution must be heated and circulated in cold climates due to its low freezing point, 17.8EC

(64EF). Higher-concentrations of urea solutions are available which decrease the storage volume

but require extensive heating to prevent freezing. Urea is injected into the boiler as an aqueous

solution and vaporized by the heat of the boiler. Urea can also be transported in pellet form which

minimizes transportation requirements. However, to produce aqueous urea for use in the SNCR

system, the urea must then be mixed with water at the facility. This mixing process is generally cost

prohibitive except for remote sites, large facilities, or facilities where chemical mixing processes

are already being performed [13].

Urea based systems have several advantages over ammonia based systems. Urea is a

nontoxic, less volatile liquid that can be stored and handled more safely than ammonia. Urea

solution droplets can penetrate farther into the flue gas when injected into the boiler. This enhances

mixing with the flue gas which is difficult on large boilers [1]. Because of these advantages, urea is

more commonly used than ammonia in large boiler applications of SNCR systems.
1-7

1.2.3 SNCR Performance Parameters

The rate of the reduction reaction determines the amount of NOx removed from the flue

gas. The important design and operational factors that affect the reduction of NOx

 by an SNCR

system include:

• Reaction temperature range;

• Residence time available in the optimum temperature range;

• Degree of mixing between the injected reagent and the combustion gases

• Uncontrolled NOx

 concentration level;

• Molar ratio of injected reagent to uncontrolled NOx

; and

• Ammonia slip.

Temperature

The NOx

 reduction reaction occurs within a specific temperature range where adequate

heat is available to drive the reaction. At lower temperatures the reaction kinetics are slow and

ammonia passes through the boiler (ammonia slip). At higher temperatures the reagent oxidizes

and additional NOx

 is generated. The temperature window is dependant on the reagent utilized.

Figure 1.3 shows the NOx

 reduction efficiency for urea and ammonia SNCR at various boiler

temperatures. For ammonia, the optimum temperature is from 870EC to 1100EC (1,600EF to

Figure 1.3: Effect of Temperature on NOx Reduction 

0

10

20

30

40

50

60

70

80

90

100

1200 1400 1600 1800 2000

Temperature (oF)

NOx Reduction Efficiency (%)

Urea

Ammonia
1-8

2,000EF) [1]. Its optimum temperature range can be reduced by injecting hydrogen gas with the

ammonia. For urea, the optimum temperature range is between 900EC to 1150EC (1,650EF to

2,100EF) [1]. Additives to the urea reagent may be used to widen the effective temperature

window. These additives are generally proprietary (see Section 1.2.4 Other Considerations).

The reagent is injected into the boiler in regions where the combustion gas temperature is

within the specified range. Since reaction temperatures are high, the injection takes place in the

boiler itself. In general, the reagent is injected within the boiler superheater and reheater radiant

and convective regions, where the appropriate temperature range is typically available [1]. Proper

placement of the injection ports results in higher NOx

 reduction efficiency.

Flue gas temperature within the boiler depends on the boiler design and operating conditions. These are generally set to meet steam generation requirements and are not always ideal for

the SNCR process. Flue gas temperatures in the upper furnace through the convective pass may

vary by ±150EC (300EF) from one boiler to the next [1]. In addition, fluctuations in the boiler

load profile affect the temperature within the boiler. At lower load profiles, the temperature within

the boiler is lower. Variations in the flue gas temperature make the design and operation of an

SNCR system more difficult.

Residence Time

Residence time is the amount of time the reactants are present within the chemical reactor,

the upper area of the furnace and convective passes. Before the reactants exit the boiler, all the

steps in the SNCR process must be complete, including:

• Mixing of the injected urea with the flue gas;

• Evaporation of water;

• Decomposition of urea to NH3

;

• Decomposition of NH3

 to NH2 and free radicals; and

• NOx reduction reaction chemistry.

Increasing the residence time available for mass transfer and chemical reactions generally

increases the NOx removal. In addition, as the temperature window for the reaction is lowered,

greater residence time is required to achieve the same NOx reduction level. Residence time can

vary from 0.001 to 10 seconds [1]. However, the gain in performance for residence times greater

than 0.5 seconds is generally minimal [10]. Figure 1.4 shows the effect of residence time and

temperature on NOx reduction.
1-9

The amount of residence time depends on the dimensions of the boiler gas path and the

volumetric flow rate of the flue gas along the boiler gas path. These design parameters are optimized for boiler operations, not the SNCR process. The boiler residence time is set to meet steam

generation requirements while maintaining a flue gas velocity to prevent erosion of the watertubes

in the boiler. Because of these boiler design requirements, the residence time in the boiler is not

always ideal for the SNCR process.

Degree of Mixing

For the reduction reaction to take place, the reagent must be dispersed and mixed throughout

the flue gas. The dispersion must occur rapidly due to the volatility of ammonia. The mixing requirements are generally boiler specific and dependant on the air flow profiles through the boiler

[1]. Areas of stagnation or high flow must be accommodated. Dispersion and mixing of the

reagent and flue gas is more difficult on large boilers due to their size and flow patterns.

Mixing is performed by the injection system. The injectors atomize the reagent and control

the spray angle, velocity, and direction of the injected reagent. These systems are boiler and

reagent specific. Numeric modeling of the flue gas and reagent flow optimizes the design of the

injection system. (See Section 1.2.5 Other Considerations).

Figure 1.4: Effect of Residence Time on NOx

 Reduction

0

10

20

30

40

50

60

70

80

90

100

1200 1400 1600 1800 2000 2200

Temperature (oF)

NOx Reduction E fficiency (% )

 500 ms

 100 ms
1-10

To assist in dispersion of aqueous urea, the reagent is atomized into droplets by specially

designed nozzles which optimize the droplet size and distribution. Evaporation time and trajectory

are a function of the diameter of the droplet. Larger droplets have more momentum and penetrate

farther into the flue gas stream. However, they require a longer time to volatilize, increasing the

required residence time. [1]

Inadequate mixing results in insufficient NOx

 reduction. Mixing patterns can be improved

by several methods:

• Increase the energy imparted to the droplets;

• Increase the number of injectors;

• Increase the number of injection zones; and

• Modify the atomizer nozzle design to improve the solution droplet size, distribution, spray angle, and direction.

Uncontrolled NOx

The concentration of the reactants also affects the reaction rate of the NOx reduction

process. The reaction kinetics decrease as the concentration of reactants decreases. This is due to

thermodynamic considerations which limit the reduction process at low NOx

 concentrations [1].

For lower NOx inlet concentrations, the optimum temperature for the reaction is lower, hence, the

percent NOx reduction is lower. Figure 1.5 shows the NOx reduction efficiency as a function of

temperature for several uncontrolled NOx levels.

Figure 1.5: Effect of Uncontrolled NOX Level on NOX Reduction Efficiency

0

10

20

30

40

50

60

70

1500 1600 1700 1800 1900 2000 2100

Temperature (oF)

NOx Reduction Efficiency (%)

30 ppm

70 ppm

200 ppm
1-11

Normalized Stoichiometric Ratio

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

achieve the targeted NOx

 reduction. Based on reaction equations (1.1) and (1.2), theoretically

two moles of NOx

 can be removed with one mole of urea or two moles of ammonia. In practice,

more than the theoretical amount of reagent needs to be injected into the boiler flue gas to obtain

a specific level of NOx reduction. This is due to the complexity of the actual chemical reactions

involving NOx and injected reagent and mixing limitations between reagent and flue gas (rate

kinetics). Typical NSR values are between 0.5 to 3 moles of ammonia per mole of NOx

 [10].

Because capital and operating costs depend on the quantity of reagent consumed, determining the

appropriate NSR is critical. The factors that influence the value of NSR include:

• Percent NOx

 reduction;

• Uncontrolled NOx

 concentration in the flue gases;

• Temperature and residence time available for the NOx

 reduction reactions;

• Extent of mixing achievable in the boiler;

• Allowable ammonia slip; and

• Rates of competing chemical reactions.

Section 4-1.1.3 Design Parameters provides further discussion of these influences and a method

for estimating the NSR.

Figure 1.6 shows the NOx

 reduction as a function of the NSR. Note that as the NSR

increases, the NOX reduction increases. However, as the NSR increases, the increment of NOx

reduction decreases exponentially. Rate kinetics limit the possible NOx reduction to much less than

the theoretical value. Increasing the quantity of reagent does not significantly increase the NOX

reduction for NSR values over 2.0.

0

5

10

15

20

25

30

35

40

45

50

0 0.5 1 1.5 2 2.5 3

NSR

NOx Reduction Efficiency (%)

Figure 1.6: Effect of NSR on NOx Reduction
1-12

Ammonia Slip

Typical NSR values require significantly more reagent to be injected in practice than required by the theoretical stoichiometric ratio. In addition, the amount of NOx

 removed is generally

much less than the amount of uncontrolled NOx

. This leaves a large portion of the injected reagent

unreacted. Most of the excess reagent used in the process is destroyed through other chemical

reactions. However, a small portion remains in the flue gas as ammonia slip. Figure 1.7 shows an

example of the NOx

 reduction efficiency which can be achieved for an uncontrolled NOx level of

120 ppm and various ammonia slip levels.

Ammonia in the flue gas stream has several negative impacts. As shown in Table 1.1,

ammonia has a detectable odor at levels of 5 ppm or greater and poses a health concern at levels

of 25 ppm or greater. It can cause a stack plume visibility problem by the formation of ammonium

chlorides which occur when burning fuels containing chlorine compounds. Furthermore, ammonium bisulfate and ammonium sulfate form when burning sulfur-cotaining fuels. Ammonia-sulfur

salts can plug, foul, and corrode downstream equipment such as air heater, ducts, and fans. Lastly,

the ability to sell the fly ash as a secondary product is affected by its ammonia concentration.

Ammonia slip impacts are discussed further in Section 4-1.1.2.4 Other Considerations.

Limits on acceptable ammonia slip, imposed by either regulatory limits or by design requirements, place constraints on SNCR performance. Injection of urea at higher NSR values can

improve NOx

 reduction, but may also increase ammonia slip. In addition, variation in the temperature profile of the boiler during operations can increase ammonia slip. In general, current SNCR

Figure 1.7: NOx Reduction for Various Ammonia Slip Levels

0

10

20

30

40

50

60

70

80

0 5 10 15 20

Ammonia Slip (ppm)

N

ox Reduction Efficiency (%)
1-13

systems control ammonia slip between 5 to 10 parts per million (ppm) [12]. Instrumentation for

monitoring ammonia slip is currently being developed but not commercially available [11]. One

method to quantify ammonia slip is to determine the ammonia concentration in collected fly ash .

1.2.4 SNCR System

There are two basic designs for the application of SNCR. The first is an ammonia based

system known as Thermal DeNOx ® that was developed and patented by Exxon Research and

Engineering Company in 1975. The second system was developed and patented by The Electric

Power Research Institute (EPRI) in 1980. It is a urea-based process known by the trade name

NOx

 OUT®. The technology was licensed to Fuel Tech, which holds several additional patents

that claim improvements and enhancements to the basic process. Fuel Tech has several sublicensees authorized to supply and install SNCR technology in several industrial sectors.

An SNCR system has four basic steps to accomplish:

• Receiving and storage of the reagent;

• Metering, dilution, and mixing of the reagent;

• Injection of diluted reagent at appropriate locations in the boiler; and

• Mixing of the reagent with flue gas.

These steps are common to both urea and amonia SNCR. However, the design and equipment

specifications for the two systems are different, since ammonia is injected as a vapor while urea

is injected as an aqueous solution. Urea is typically used in large boiler applications of SNCR

because it is safer to store and has better dispersion properties. A discussion of the SNCR

equipment is given below. Figure 1.8 presents a simplified system flow schematic and Table 1.2

lists the equipment requirements for urea-based SNCR.

Urea-based systems typically employ a modular design to allow for boiler-specific

design requirements while minimizing capital costs. Modular shops assembly of pumps, valves,

internal piping, instruments, and controls reduces field insallation time and relatied costs while

providing flexibility for future expansion [1]. The components are assembled into functional

units and mounted on stainless steel skid modules. These modules can then be transported o

the site and installed directly. The skid modules shown in Figure 1.8 will be discusses futher in

the next sections.
1-14

DILUTION WATER

PRESSURE

CONTROL MODULE

SUPPLY/CIRCULATION MODULE

BOILER

50% UREA

SOLUTION

CIRCULATION

PUMPS

ELECTRIC

HEATER UREA STORAGE

TANK

STATIC

MIXER

INJECTION ZONE METERING MODULES

DISTRIBUTION MODULES

METERING

PUMPS

INJECTORS

10% UREA

SOLUTION

M

COMPRESSOR

WATER

AIR

COOLING AIR

WATER PUMP

ATOMIZING AIR

WATER PUMP

UREA

UNLOADING

PUMP

Figure 1.8: Urea SNCR Process Flow Diagram
1-15

Item Description/Size

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

Urea storage tanks Vertical, insulated fiberglass reinforced plastic (1 or more tanks)

(vinyl ester resin) tank, atmospheric pressure design, and equipped

with a vent, caged ladder, manway, and heating pads

Circulation module Skid-mounted circulation module consisting of:

- Circulation pumps,

- Electric heaters,

- Insulated/heat traced piping

- Isolation valves for pumps and heaters,

- Instrumentation for flow, pressure, temperature, and a

control panel

Injection zone metering (IAM) Skid mounted metering modules consisting of:

modules (1 to 5 modules) - Metering pumps, hydraulic diaphragm type equipped with a

variable speed motor drive,

- Water booster pumps, turbine type,

- Insulated/heat traced piping

- Isolation and control valves for pumps,

- Instrumentation for flow, pressure, temperature, and a

control panel

Air compressor Rotary type

Distribution modules Urea solution distribution module consisting of:

(1 to 5 modules) - Valved connections for urea and atomizing air,

- Isolation valve and a pressure control valve for the air/urea

supply to each injector,

- Pressure indicator for air/urea supply to each injector,

- Flow indicator for urea supply to each injector

IInjectors (4 to 12 per distribution Wall-type: Dual-fluid type wall injector, with modules) furnace wall

panels, and hoses for air and urea supplies

Lance-type: Dual-fluid type lance injector, with furnace wallpanels,

and hoses for air and urea supplies

 Piping Between urea unloading skid and urea tank; urea tank and circulation

module; and circulation module and IZM modules(s). Insulate/heat

traced piping, stainless steel

Piping Between IZM module(s) and distribution modules. Insulated/heat

traced tubing, stainless steel

Tubing Between distribution modules and injectors. Insulated/heat traced

tubing, stainless steel

Dilution water piping Insulated/heat traced piping, carbon steel, with isolation and pressure

reducing valves

Miscellaneous piping Piping/tubing and valves for flushing water, atomizing air, and

control air

Piping supports Structural support steel, including a pipe bridge, for supporting all

piping

Economizer outlet emission monitors Monitor NOx

 and O2 in the flue gas and provide a feedback signal for

urea injection control

Instrumentation and controls Instrumentation and stand-alone, microprocessor-based controls for

the SNCR system with feedback from the plant controls for the unit

load, NOx emissions, etc.

Enclosures Pre-engineered, heated and ventilated enclosure for the circulation

and metering skids

Foundations Foundations and containment walls for the tank and equipment skids,

enclosure, and piping support steel, as required

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

Asbestos removal Asbestos removal and reinsulation, for a retrofit installation

Table 1.2: Urea-Based SNCR System Equipment
1-16

from 10,000 to 20,000 gallons per tank to maintain sufficient volume for 1 to 3 weeks of SNCR

operations. A closed top, flat bottom, vertical tank is used for urea storage. These tanks are usually

constructed of fiber- reinforced polyester and have a corrosion barrier coating on the inside made

of premium-grade vinyl ester resin. The tanks are equipped with level and temperature indicators,

a manway, vent, and access ladder, and other appurtenances. The applicability of heat tracing,

insulation, and seismic design criteria are determined based on site-specific conditions. The tank

should be mounted on a concrete pad and surrounded by a spill containment structure such as a

dike.

Circulation Module

 The circulation module maintains continuous circulation of the stored urea and supplies

high-flow, high-pressure urea to the injection system. The circulation module pumps the urea from

the storage tank to the components on the module. The urea solution is filtered to avoid clogging of

the injectors and heated to prevent the solution from freezing. The urea is then returned to the tank

or sent to the injection system. The module also provides a local/remote control and monitoring

station for the storage tank and circulation system. This module contains multistage stainless steel

centrifugal pumps, in-line duplex strainers, electric heaters, and instrumentation and controls for

reagent pressure, flow, temperature, and quantity. [1]

Dilution, metering, and mixing of the reagent

Dilution Water Pressure Control Module

The dilution water pressure (DWP) control module provides filtered plant water at the

proper pressure for reagent dilution. The plant water is filtered to less than 50 milligrams per liter

(mg/l) of suspended solids and low dissolved solids. The DWP typically consists of two full-flow

multistage stainless steel centrifugal pumps, an in-line duplex strainer, pressure control valves, and

the required pressure/flow instrumentation. Through the use of backpressure controllers and multistage pumps, this system maintains a constant supply of dilution water, at the design pressure, in

response to the changing SNCR process demand signals. [1]

Injection Zone Metering Module

The injection zone metering (IZM) module meters and controls the reagent concentration and flow

to each zone of injection in the boiler. The aqueous urea generally requires dilution before injection

to achieve the correct NSR between the reagent and flue gas NOx

. The reagent is diluted using

filtered plant water from the DWP module. Each IZM module includes a chemical metering pump,

a water pump, an in-line static mixer, a local control panel, zone isolation valves, and magnetic flow
1-17

meters and control valves for chemicals and water. The module design generally incorporates

independent chemical flow and zone pressure valves which respond to signals from the control

systems, the master control module and local programmable logic controller (PLC). Through the

control system, the module adjusts solution flow rates and activates or deactivates injection zones

in response to changes in outlet NOx concentration, boiler load, or fuel quality. Urea-based SNCR

systems typically employ one to five IZM modules, 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. [1]

Injection of diluted reagent at appropriate locations in the boiler

Reagent Distribution Module

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

modules, which are typically located adjacent the boiler. The distribution modules control the flow

of the solution to each injector. Each of the distribution modules consists of flow meters, balancing

valves, and regulators connected to an automatic control system. The control system accurately

controls and displays the reagent and atomizing air or steam flow to each injector. The modules

also include Manual ball valves, gauges, and stainless steel tubing to adequately control the urea

injection process. There is one distribution module for each IZM module providing reagent to

multiple injectors.[1]

Injection Locations

The urea solution flows from a given distribution module to a set of injectors. For large

boiler applications, multiple injectors are located within several different zones of the boiler and

can be operated independently or in groups (sub-zones) via the IZM. Controlling the amount and

location of reagent injection gives the system flexibility to respond to variation in the boiler operating conditions and to maintain ammonia slip levels.

The number and location of the zones is determined by the temperature and flow patterns of the boiler. The locations are optimized using numeric modeling of flow and chemical

reactions (see Section 1.2.5 Other Considerations). Typical designs employ between one and five

injection zones with 4 to 12 injectors per zone [1]. Injectors are located in open areas of the boiler

such as the region between the superheater and reheater sections. Figure 1.2 illustrates this configuration. For SNCR retrofit of existing boilers, optimal locations for injectors may be occupied

by boiler equipment such as the watertubes. Removal or relocation of this equipment increases the

installation costs. Installation in sub-optimal boiler areas decreases the NOx

 reduction efficiency

which can be achieved by the system while maintaining the required ammonia slip level.
1-18

Mixing of the reagent with flue gas and reduction of NOx

Injectors

The injectors assist in dispersion and mixing of the reagent with the flue gas. There are

two types of injectors, wall and lance.

Wall injectors are attached to the inner wall of the boiler at specified locations.

There is generally one nozzle for each injector location. Wall injectors are used in

smaller boilers and urea based systems, where short-range injection is sufficient to

mix the reagent with the flue gas. They have a longer operating life than lance

injectors since they are not directly exposed to hot flue gas.

Lance injectors consist of a small pipe which protrudes from the boiler wall into

the flue gas pathway. Nozzles are located along the pipe directly in the flue gas

pathway. Lance injectors are used for ammonia gas systems and in large boilers

where mixing of the flue gas and reagent is more difficult. In some designs, the

lance extends across the entire width of the boiler pass. Lance injectors can be

single or multi-nozzle designs. Multi-nozzle lances are more complicated design,

therefore, they are more expensive than single-nozzle lance or wall injectors [1].

SNCR systems may employ one or both types of injectors.

Injectors are subject to high-temperatures and to flue gas impingement which cause erosion, corrosion, and structural integrity degradation. Therefore, injectors are generally constructed

of stainless steel and designed to be replaceable. In addition, injectors are often cooled with air,

steam, or water. Lance injectors and some wall injectors are also designed to be retractable when

not in use. This minimizes their exposure to the hot flue gas when the SNCR system is not being

operated because of seasonal operations, boiler startup or shutdown, or other operational reasons.

The reagent is injected under pressure and atomized by specially designed nozzle tips to

create droplets of the optimum size and distribution. The spray angle and velocity of the injection

control the trajectory of the reagent. Urea systems often inject a carrier fluid, typically air or steam,

along with the urea through a dual-fluid atomizer nozzle. The reagent can be injected with a low

energy or high energy system. A low-energy system uses little or no pressurized air while a highenergy system uses large amounts of compressed air or steam to inject and vigorously mix the

solution with the flue gas. Lance injectors in large boilers typically use high-energy systems. High

energy systems are more expensive to build and operate since they require a larger compressor, a

more robust injection system, and consume more electric power.
1-19

The reagent injection systems used for ammonia-based systems are generally more complicated and expensive than those used in urea-based systems [1]. These systems inject gas phase

ammonia rather than an aqueous solution. For this reason, ammonia-based systems often use highenergy lance systems with multiple injectors. The lances are placed in a grid formation across the

width and height of the boiler passes.

1.2.5 Other Considerations

Retrofit

The difficulty of SNCR retrofit on exiting large coal-fired boilers is considered to be minimal. The primary concern is adequate wall space within the boiler for installation of injectors. The

injectors are installed in the upper regions of the boiler, the boiler radiant cavity and convective

cavity. Movement and/or removal of existing watertubes and asbestos from the boiler housing

may be required. In addition, adequate space adjacent to the boiler must be available for the

distribution system equipment and for performing maintenance. This may require modification or

relocation of other boiler equipment such as ductwork. Retrofit installation of the SNCR system

generally calls for additional expenditures in the range of 10% to 30% of the SNCR system cost.

[10]

Ammonium Sulfate Deposition

Sulfur trioxide (SO3) forms during the combustion of fuels which contain sulfur. It reacts

with ammonia in the flue gas downstream of the boiler (ammonia slip) to form ammonium bisulfate

and ammonium sulfate. The amount formed depends on the sulfur content of the fuel and the

amount of ammonia slip. Ammonia-sulfur salts can plug, foul, and corrode downstream equipment

such as the air heater, ducts, and fans. Depending on the rate of ammonia-sulfur salt deposition on

downstream equipment more frequent acid washing of this equipment may be warranted. Increased acid washing generates additional wastewater which must be disposed or treated by the

plant. Ammonia slip limits are generally imposed as part of the design requirements to avoid impacts on downstream equipment.

Ammonia sulfates also deposit on the fly ash that is collected by particulate removal equipment. The ammonia sulfates are stable until introduced into an aqueous environment with a elevated pH levels. Under these conditions, ammonia gas can release into the atmosphere. This

results in an odor problem or, in extreme instances, a health and safety concern. Plants that burn

alkali coal or mix the fly ash with alkali materials can have fly ash with high pH. In general, fly ash

is either disposed of as waste or sold as a byproduct for use in processes such as concrete

admixture. Ammonia content in the fly ash greater than 5 ppm can result in off-gassing which

would impact the salabilty of the ash as a byproduct and the storage and disposal of the ash by

landfill. [10]
1-20

Computational Fluid Dynamics and Chemical Kinetic Modeling

Each boiler unit has a unique temperature and flow gradient with areas of high flow and

stagnation. In addition, temperature and flow profiles vary according to the load capacity under

which the boiler is operating. A mathematical model is developed to describe this stratification and

variation of important species such as NOx and SO3 in the flow stream. To develop the model, the

flue gas temperature and velocity within the boiler are measured at many locations. These measurements are used in a computational fluid dynamics (CFD) model for the convective passes of

the boiler. The model predicts the temperature and gas flow within the boiler for various operating

conditions and injection scenarios.

 The residence times and temperatures predicted by the CFD model are input into a

chemical kinetic model (CKM). CKM defines the chemical reactions associated with the SNCR

process in the boiler. Analysis of the fuel and flue gas constituents are required to develop this

model. The model predicts the reactions and rates of reactions within the boiler in order to estimates the NOx

 reduction along the flue gas pathway.

Modeling optimizes the SNCR design for the boiler of concern to obtain the maximum

NOx

 reduction within acceptable ammonia slip limits. It determines design parameters such as the

NSR, injector locations, and optimum droplet size and distribution. In general, SNCR vendors

obtain the required measurements and develop the models. The cost of model development is

generally included in the purchased equipment cost for SNCR. [1]

Additives/Enhancers

Additives to the reagents are called enhancers and can be used to lower the temperature

range at which the NOx reduction reaction occurs. During low-load operation, the location of the

optimum temperature region shifts upstream within the boiler. This shift requires the injection point

of the reagent to be moved upstream. The use of an enhancer reduces the need for additional

injection locations which are required to compensate for variable load operation. Fewer injection

locations decrease capital costs and the need for modifications to the boiler. In addition, the larger

temperature range available with enhancers increases the available residence time for the reduction

reaction, further reducing NOx emissions.

Additional reagent is injected with the enhancer to maintain the same NOx reduction efficiency since some of the reagent reacts with the enhancer as opposed to the NOx

. This can

increase the reagent usage by up to 10%. In addition, enhancers can result in increased levels of

CO and N2

O in the stack effluent. Enhancers require additional storage, distribution, and control

system equipment. The increase in annual cost from the usage of additional reagent and enhancer

can be significant. Enhancer formulations are generally proprietary. [10]
1-21

Energy Consumption

An SNCR process reduces the thermal efficiency of a boiler. The reduction reaction uses

thermal energy from the boiler, which decreases the energy available for power or heat generation.

As a result, additional energy is required for the boiler to maintain the same steam output. Pretreatment and injection equipment, pumps, compressors, and control systems, also require electricity. This increased usage of fuel and electricity increases the annual costs required to operate

the boiler [1]. Section 1.4.2 Total Annual Costs presents a method for estimating the additional

fuel and electricity usage.

1.3 Design Parameters

SNCR system design is a proprietary technology. Extensive details of the theory and

correlations that can be used to estimate design parameters such as the required NSR are not

published in the technical literature [5]. Furthermore, the design is highly site-specific. In light of

these complexities, SNCR system design is generally undertaken by providing all of the plant- and

boiler-specific data to the SNCR system supplier, who specifies the required NSR and other

design parameters based on prior experience and computational fluid dynamics and chemical

kinetic modeling. [1]

The procedure given below in Section 1.3.1 Design Parameters for Study-Level Estimates is a step-by-step approach to estimate design parameters based on a procedure developed

in the draft EPA report Selective Noncatalytic Reduction for NOx Control on Coal-fired Boilers

[1]. This procedure assumes SNCR system size and cost are based on three main parameters: the

boiler size or heat input, the required level of NOx reduction, and the reagent consumption. Data

requirements for obtaining vendor cost estimates based on design specifications or performance

specifications are outlined in Section 1.3.2.

1.3.1 Design Parameters for Study Level Estimates

Boiler Heat Input

The primary cost estimation parameter in the methodology presented in Reference [1] is

the maximum potential heat released by the boiler or heat input rate, QB, expressed as million

British thermal units per hour (MMBtu/hr). It is obtained from the high heating value, HHV, of the
1-22

fuel in Btu per pound (Btu/lb) multiplied by the maximum fuel consumption rate in pounds per hour

(lb/hr),

Q HHV m B fue = l  (1.3)

where Table 1.3 gives the HHV for various coals and a conversion of 10-6 MMBtu/Btu is reequired.

 Table 1.3: High Heating Values for Various Coals

Type of Coal Energy Content (Btu/ lb)

Lignite 5000-7500

Subbituminous 8000-10,000

Bituminous 11,000 - 15,000

Anthracite 14,000

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

rate, NPHR in Btu per kilowatt-hour (Btu/kWh):

Q B NPH B MW = R (1.4)

where BMW is the boiler megawatt (MW) rating at full load capacity. Note that if NPHR is not

known (e.g., a cogeneration unit), a value of 9,500 Btu/kWh can be used as a reasonable estimate

conversions of 1,000 kW/MW and 10-6 MMBtu/Btu are required. Using this value, the heat input

rate, QB, is:

Q . ( ) ( ) ( ) B

M M Btu

h r = 9 5 M M Btu

MWh M W B MW (1.5)

System Capacity Factor

The total system capacity factor, CFtotal, is a measure of the average annual use of the

boiler in conjunction with the SNCR system. CFtotal is given by:

CF CF CF total plant SNCR = × (1.6)
1-23

For industrial boilers, the capacity factor of the boiler, CFplant, is the ratio of actual quantity of fuel

burned annually to the potential maximum quantity of fuel burned annually in pounds (lbs). CFplant

is given by:

C F

actual m

maximum m plant

fuel

fuel

= (1.7)

SNCR can be operated year-round or only during the specified ozone season. The capacity facor

for the SNCR system, CFSNCR, is the ratio of the actual number of SNCR operating days, t

SNCR, to

the total number of days per year, 365 days:

C F

t

SNCR

SNCR = 365 days (1.8)

Uncontrolled NOx and Stack NOx

Uncontrolled NOx, represented as NOxin, is the NOx concentration in the flue gas after any

reductions provided by combustion controls, but prior to the SNCR system. The uncontrolled

NOx

 concentration, obtained from analyzing the boiler flue gas stream, is generally given in pounds

per MMBtu (lb/MMBtu) of NO2 [2].

The stack NOx, represented as NOxout is the required NOx emission limit at the stack

outlet. It is generally set by the plant or regulatory limits and also given in pounds per MMBtu (lb/

MMBtu) of NO2

.

NOxRemoval Efficiency

The NOx

 removal efficiency, represented as NOx, is determined from the uncontrolled

NOx level of the boiler at maximum heat input rate, CFplant = 1.0, and the required stack emission

limit using the following equation:

η N O

x x

x x

in out

in

N O N O

N O = −

(1.9)

Normalized Stoichiometric Ratio

The Normalized Stoichiometric Ratio, NSR, indicates the actual amount of reagent needed

to achieve the targeted NOx reduction. The actual quantity of reagent is greater than the theoretical
1-24

quantity due to reaction kinetics (See Section 1.2.3 Performance Parameters). The NSR is defined

as:

NSR = moles of equivalent N H injected

moles of uncontrolled NO

3

x

(1.10)

For estimating purposes, the moles of NOx are equivalent to the moles of NO2. Note that the

moles of equivalent NH3

 in Equation (1.10) are the moles of NH2 that will be released from the

reagent.

The actual stoichiometric ratio, ASR, is defined as:

ASR = moles of reagent injected

moles of uncontrolled NO x

(1.11)

ASR can also be calculated from the NSR using the following equation:

 ASR NSR

S R T

= (1.12)

where SRT is the ratio of equivalent moles of NH3 per mole of reagent injected. From the chemical

formula for ammonia (NH3) and urea (CO(NH2)

2

) given in the reaction equations (1.1) and (1.2),

SRT is 1 for ammonia and 2 for urea.

Reagent utilization is the ratio of moles of reagent reacted to the moles injected. This indicates

how much reagent is being reacted versus how much reagent is passing through as ammonia slip.

Utilization of reagent can be calculated from the NSR and the NOx reduction efficiency as follows:

 Utilization NSR

N O x =

η

(1.13)

The derivation for this equation is presented in Reference [1].

Methods for estimating NSR are considered proprietary. A simplified NSR estimation procedure was developed by The Cadmus Group, Bechtel Power, Inc. and SAIC in the EPA draft

report, Selective Noncatalytic Reduction for NOx Control on Coal-fired Boilers [1]. This procedure was developed using linear regression and NSR data from References [2] and [3]. The

values of NSR derived using this approach should not be used for equipment design or guarantee

purposes.
1-25

The NSR estimation equation is valid from 0 to 50 percent NOx reduction [1]. The equation

used to estimate the NSR for urea reagent is where Noiu is given in lb/MMBtu.

[ ] NSR

N O

N O

x NO x

x

in

in

=

2 + 0.7 η

(1.14)

Figure 1.8 provides a graphical representation of this NSR estimation method. Generally, the

value of the NSR ranges between 0.5 and 2.0 in industrial and utility boilers with utilization ranging

between 25 and 50 percent.

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

2.6

2.8

3.0

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

Uncontrolled NOx, lb/MMBtu

Predicted NS

R

50%

45%

40%

35%

30%

25%

NOx Reduction

50%

45%

40%

35%

25%

30%

Figure 1.8: Approximate NSR Estimation for Urea
1-26

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

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

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

Reaction temperature range available within the boiler superheater (radiative and

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

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

NSR could decrease. However, if the temperature window occurs in the convective section, the NSR may increase.

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

as the available residence time increases.

Degree of mixing between the injected chemical and the flue gases. The NSR decreases

as the degree of mixing increases.

Ammonia slip vs required NOx reduction. Tighter constraints on ammonia slip would

dictate lower NSRs, thereby limiting the achievable NOx reduction.

Estimating Reagent Consumption and Tank Size

Once the NSR is estimated, the rate of reagent consumption or mass flow rate of the

reagent, m reagent expressed as pounds per hour (lb/hr), can be calculated using:

 m NO Q NSR M

M SR

x B N O x reagent

NO T

in

x

reagent = η

(1.15)

where the M

reagent is the molecular weight of the reagent (60.06 grams per mole for urea, 17.07

grams per mole for ammonia) and MNOx is the molecular weight of NO2 (46.01 grams per mole).

The molecular weight of NO2 is used because the NOx emissions, NOxin, are given in lb/MMBtu of

NO2

. As stated previously, SRT is the ratio of equivalent moles of NH3 per mole of reagent (1 for

ammonia and 2 for urea).

For urea or ammonia, the mass flow rate of the aqueous reagent solution is given by:

  m

m

C sol

reagent

sol

= (1.16)

where Csol is the concentration of the aqueous reagent solution by weight.
1-27

The solution volume flow rate q

sol

, generally expressed as gallons per hour (gph), is given

by:

q

m

sol

sol

sol

= 

ρ (1.17)

where sol is the density of the aqueous reagent solution inlb/ft3

 A conversion of 7.4805 gal/ft3 is

required to correct the units. given in Table 1.1, 71.0 lb/ft3

 for 50% urea and 56 lb/ft3 for 29%

ammonia.

The total volume stored in the tank, or tanks, is based on the volume that the SNCR

system requires for operating a specified number of days. The volume stored on site for the

number of operating days, tstorage, is :

V q t tank sol storag = e (1.18)

where Vtank is in gallons, q

sol

is in gph and a conversion of 24 hr/day is required.

Note that the tank volume is typically based on the maximum annual heat input rate, so the capacity

factor is not included in Equation 1.18. A common on site storage requirement is for 14 days of

SNCR operation.

1.3.2 Design Parameters for Detailed/Performance Specifications

Cost Estimates Based on Detailed Specifications

This subsection is included to describe the information that must be assembled and furnished to a supplier to prepare design specifications, particularly that component information with

the greatest influence on system cost. SNCR capital and operating costs can be estimated if the

major cost items are identified and the system is defined in adequate detail, [1]. The following data

are provided to the system supplier for SNCR system design:

• The boiler capacity in terms of heat input rate (MMBtu/hr);

• Boiler capacity profile – percent of time the boiler operates at a given heat input

rate;

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

cyclone fired, other (e.g., stoker-fired); year built, and manufacturer;
1-28

• Boiler Dimensions – sectional side view; sectional front view; plan section through

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

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

features, e.g., division wall/panels, etc., in the furnace or backpass;

• Locations of boiler furnace overfire air ports;

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

sootblower openings, and other locations for potential new ports;

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

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

primary and secondary fuels;

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

percent);

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

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

O2

, NOx, CO, SO2, and HCl;.

• Flue gas temperature profile from furnace exit to economizer (i.e., where

temperature drops to about 1,400F) at various loads;

• Flue gas residence time – available flue gas residence time in the upper furnace

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

• Existing or planned uncontrolled NOx

 and CO emission data in ppm or lb/MMBtu

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

other installed or planned technologies (e.g., low-NOx

 burner, gas recirculation).

This should be specified for boiler operations at full load and selected partial

loads;

• Minimum expected NOx

 reduction or permit requirement for stack NOx emission

level (ppm or lb/MMBtu). This should be specified for boiler operations at full

load and selected partial loads; and

• Allowable byproduct emission rates for regulated emissions such as ammonia and

nitrous oxide.
1-29

The boiler supplier/manufacturer can furnish most of this information for existing or planned new

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

define the temperature and flue gas velocity profiles in existing boilers, it is preferable to obtain

actual measurements.

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

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

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

conditions.

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

work not included (i.e., work performed by the owner/operator). The more precise and detailed

the specification of the work, the more accurate the overall system design and cost. For a turnkey

scope (design, supply, and erect all equipment, and demonstrate commercial operation while meeting

all performance criteria), the excluded work is minimal.

Cost Estimates Based on Performance Specifications

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

and supplier) and is not critical for budgetary cost estimates. To simplify the process, a performance specification approach may be used in the RFQ. In this approach, the basic required plant

and fuel data are provided along with the required SNCR system performance requirements,

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

level of instrumentation and controls) [1].

The performance specification should include a description of the system and components

in enough detail to understand the type and quality of system proposed by the supplier. A cost

breakdown of major components and subsystems also should be obtained from the supplier to

enable independent assessment, deletion, or addition, and to compare other bids on an equitable

basis. The SNCR performance specification typically should request the following items regarding

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

and partial loads:

• Guaranteed and expected NOx emission rates in units of lb/MMBtu and lb/hr with

averaging period as defined in the air quality permit of the facility;

• Guaranteed and expected NH3 slip, ppm (other conditions such as dry basis,

percent O2, per the air permit);

• Guaranteed and expected N2O emissions (guarantees needed if it is a permit

condition);
1-30

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

• Normalized stoichiometric ratio (NSR) proposed to achieve the required NOx

reduction;

• Guaranteed and expected reagent consumption rate;

• Guaranteed and expected dilution air, steam, or water consumption rate;

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

• Guaranteed and expected electrical power consumption.

1.4 Cost Analysis

The cost estimating methodology presented here provides a tool to estimate study-level

SNCR capital and annual costs. Actual selection of the most cost-effective option should be

based on a detailed engineering study and cost quotations from system suppliers. The costs are

presented in 1998 dollars.

The cost estimating equations presented in this section are based on equations developed

in the draft EPA report Selective Noncatalytic Reduction for NOx Control on Coal-fired Boilers

[1]. These equations follow the costing methodology used by the Electric Power Research Institute (EPRI) [7]. In the EPRI method, both the purchased equipment cost (PEC) and direct installation cost are estimated together. This methodology is different from the EPA Air Pollution Control Cost Manual methodology, which estimates equipment costs and installation costs separately.

Due to the limited availability of equipment cost data and installation cost data, the equations for

SNCR capital costs were not reformulated.

The capital and annual cost equations were developed for coal-fired wall and tangential

utility and industrial boilers with heat input rates ranging from 250 MMBtu/hr to 6000 MMBtu/hr.

The SNCR system design used for the cost estimate is an urea-based system. An ammoniabased system would have different storage, distribution and injection equipment costs. The cost

equations are sufficient for NOx

 reduction efficiencies up to 50%. Allowed ammonia slip for the

SNCR system ranges from 2 to10 ppm. [1]

The cost equations are applicable to retrofit of SNCR on existing boilers. The cost estimating procedure, however, is suitable for retrofit or new boiler applications of SNCR on all types

of coal-fired electric utilities and large industrial boilers. The increased cost due to retrofit is

approximately 10% to 30% of the cost of SNCR applied to a new boiler [10].
1-31

1.4.1 Total Capital Investment

Total Capital Investment (TCI) includes direct and indirect costs associated with purchasing and installing SNCR equipment. Costs include the equipment cost (EC) for the SNCR system

itself, the cost of auxiliary equipment, direct and indirect installation costs, additional costs due to

installation such as asbestos removal, costs for buildings and site preparation, offsite facilities, land,

and working capital. In general, SNCR does not require buildings, site preparation, offsite facilities, land, and working capital. A more detailed discussion of capital costs can be found in Section

1, Chapter 2 of this Manual.

Direct Capital Costs

The direct capital cost equation developed in Reference [1] is based on data for one

representative boiler. This data is used to develop an equation for the boiler size range of interest

by applying a scaling methodology from the EPRI Technical Assistance Guide (TAG) [3]. The

equation assumes that performance parameters vary in direct proportion to the boiler size. The

costs are adjusted to 1998 dollars using the Chemical Engineering Cost Index.

The direct capital cost estimate includes PEC such as SNCR system equipment, instrumentation, sales tax and freight. This includes costs associated with field measurements, numerical

modeling and system design. It also includes direct installation costs such as auxiliary equipment

(e.g., ductwork, compressor), foundations and supports, handling and erection, electrical, piping,

insulation and painting. In addition costs such as asbestos removal are included. Table 1.2 presents a list of the equipment and installation requirements for a urea-based SNCR system.

The direct capital cost equation is a function of both boiler heat input rate QB in MMBtu/

hr, and the NOx

 removal efficiency -η

NOx

. The boiler heat input rate indicates the size of the boiler

and the flue gas flow rate, which directly influence the size of the SNCR system. The NOx

 removal

efficiency effects both the required urea flow rate and associated urea-related equipment. Increases in the NOx

 removal efficiency will require higher urea flow rates and increase the size and/

or number of the urea related equipment such as storage tanks. The equation for direct capital cost

(DC) of urea-based SNCR in dollars is:

D C ( ) ( ) M M Btu

M M Btu

h r

M M Btu

h r

M M Btu

h r

($) $ . .

.

= + 



 

































950 2375

0 6 6 0 8 5

0 577

 Q

Q B

B N O x

η (1.19)

where 950 $/(MMBtu/hr) is the direct capital cost for a 2375 MMBtu/hr boiler at 40% NOz

removal efficiency [1].
1-32

Indirect Capital Costs

Indirect installation costs include costs such as; construction and contractor fees, startup

and testing, inventory capital, and any process and project contingency costs. As explained in

the Manual Section 1 Introduction, average values of indirect installation factors are applied to

the direct capital cost estimate to obtain values for indirect installation costs. These costs are

estimated as a percentage of the TCI. The equations for indirect installation costs are presented

in Table 1.4.

Table 1.4: Capital Cost Factors for an SNCR Application

Boiler Size (MMBtu/hr) QB

NOx Removal Efficiency n NOx

Cost Year 1998

Total Direct Capital Costs ($)

Indirect Installation Costs

 General Facilities ($) 0.05 A

 Engineering and Home Office Fees ($) 0.10 x A

 Process Contingency ($) 0.05 x A

Total Indirect Installation Costs ($) B = A x (0.05 + 0.1 + 0.05)

Project Contingency ($) C= 0.15 x (A + B)

Total Plant Cost ($) D= A + B + C

Allowance for Funds During Construction ($) E = 0 (Assumed for SNCR)

Royalty Allowance ($) F = 0 (Assumed for SNCR)

Preproduction Cost ($) G = 0.02 x (D + E)

Inventory Capital* ($) H = Volreagent (gal) x Cost reagent ($/gal)

Initial Catalyst and Chemicals ($) I = 0 (Assumed for SNCR)

Total Capital Investment (TCI) ($) TCI = D + E + F + G + H + I

* Cost for urea stored at site, i.e., the first fill of the reagent tanks

Description Data or Formula

D C

MMBtu

h r

Q M MBtu

h r B

($) $ . .

.

=



















 + 



 



 950 2375

0 6 6 0 8 5

0 577

 Q B N Ox

η
1-33

1.4.2 Total Annual Costs

Total annual costs (TAC) consist of direct costs, indirect costs, and recovery credits.

Direct annual costs are those associated or proportional to the quantity of waste gas prodent of the

operation of the control system and would be incurred even if it were shut down. No byproduct

recovery credits are included because there are no salvageable byproducts generated from the

SNCR [1]. Each of these costs is discussed in the sections below. A more detailed discussion of

capital costs can be found in Section 1, Chapter 2 of this Manual.

Design parameters are estimated using the maximum annual heat input rate of the boiler to

ensure adequate sizing of the SNCR system. Annual costs are calculated using the average heat

input rate of the boiler and SNCR system using CFtotal. This ensures that annual costs are based

on the actual operating conditions rather than the design case.

Direct Annual Costs

Direct annual costs (DAC) include variable and semivariable costs. Variable direct annual

costs account for purchase of reagent, utilities (electrical power and water), and any additional

coal and ash disposal resulting from the operation of the SNCR. Semivariable direct annual costs

include operating and supervisory labor and maintenance (labor and materials).

DAC =

Annual

M aintenance

Cost

+

Annual 

Cost

+

Annual 

Electricity

Cost

+ 

Annual

W ater

Cost

Annual

Coal

Cost

Annual

Ash

Cost































































































 Reagent + + (1.20)

Operating and Supervisory Labor

In general, no additional personnel is required to operate or maintain the SNCR equipment for large industrial facilities. Therefore, the cost of operating or supervisory labor is

assumed be negligible.

Maintenance

The annual maintenance labor and material cost, including nozzle tip replacement

for the injectors, is assumed to be 1.5% of the Total Capital Investment, TCI, in dollars.

The equation is for annual maintenance cost in $/hr, AMC, given by:

Annual maintenance cost = 0.015 TCI (1.21)
1-34

Utilities

The electrical power consumption in kilowatts (kw) estimated for SNCR operations is

derived in Appendix B of the draft EPA report, Selective Noncatalytic Reduction for NOx

Control on Coal-fired Boilers [1]. It is based on linear regression of electrical power consumption data correlated to the uncontrolled NOx

 concentration in lb/MMBtu, NOxin, the NSR and

the boiler heat input in MMBtu/hr, QB.

P

NO NSR Q x in B

= 0 4 7

9 5

.

. (1.23)

Using the estimated power consumption, Power, the annual cost of electricity is estimated

from the following equation:

Annual electricity cost =P Cost t elect o p (1.24)

where Costelect is the cost of electricity in dollars per kW ($/kw) and t

op

is defined in equation

1.22a.

Reagent Consumption

The annual cost of reagent purchase in $/yr is estimated using the aqueous reagent

volume flow rate in gph qsol , the total operating time t

op

 in hours.

t op total C F

h r

yr = 8760 (1.22a)

Annual reagent cost q Cost t = sol reag o p (1.22)

were Cost

reag is the cost of reagent in dollars per gallon ($/gal) and top

 in hours can be calculated using the total capacity fuel or CFtotal:
1-35

Water Consumption

The volumetric flowrate of water for diluting the urea is calculated from the aqueous urea

mass flow rate in lb/hrand the concentration of the aqueous urea during storage, Curea sol stored

and the average percent concentration of the injected urea, Curea sol inj . The flowrate, q water,

in gallons per hour (gph)is:

q

m C

C water

sol

water

urea sol

urea sol inj

stored

= 

ρ −















1 (1.25)

where water is the density of water, 8.345 lb/gal. For urea dilution from a 50% solution to a 10%

solution, Equation (1.25) becomes:

q

m water

sol

= water

4 

ρ (1.26)

Using this estimate for the volume flow rate of water (gph) the annual cost of water consumption

in $/yr is given by:

Annual water cost q Cost t = water water o p (1.27)

where Costwater is the cost of water in dollars per gallon ($/gal) and t

op

 is given by equation

1.22a.

Coal and Ash

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

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

following equation:

∆Coal ( ) = Hv ( ) m ( ) Btu

h r

Btu

lb reagent × × − 













  lb

h r urea sol inj C

1 1 (1.28)

where Curea sol inj is the percent concentration of the injected aqueous urea agent and m reagent

is the mass flowrate in lb/hr. HV, the approximate heat of vaporization of water at 310F, is 900

Btu/lb, which is a representative temperature for flue gas exiting the air heater.
1-36

The cost of the additional coal in $/yr required to maintain the same boiler steam output

is:

A n n u a l C o a l co st C o a l C o st t ∆ ∆ = coal op (1.31)

where Costcoal is the cost of coal in dollars per MMBtu ($/MMBtu) Coal is in lb/hr, and t

op

 is

given in equation 1.22a.

Although the water from the urea solution is evaporated in the furnace at higher temperatures (due to urea injection in the furnace zones at over 1,500F), the temperature at the air

heater exit is used because it is the thermodynamic end point of the combustion process. The

quantity of fuel burned in the boiler depends on the boiler efficiency, which, in turn, depends on

the air heater exit temperature and the moisture in the air heater exit gas. The boiler is fired to

maintain the required steam flow (e.g., for the steam turbine). Because the water from the urea

solution evaporates in the boiler, the boiler efficiency decreases. Consequently, more fuel needs

to be burned to maintain the required steam flow.

With urea as the reagent, injected as a 10% solution and HV = 900 lb/Btu, Equation

(1.28) in MMBtu per hour becomes:

( ) ( ) ( )

( ) ∆Coal =

m

1 0

M M Btu

h r

reagent

lb

h r

6

900 9 Btu

lb

Btu

M M Btu



(1.29)

As a result of burning additional coal, additional ash is generated. This ash must be disposed or

sold as byproduct. This cost methodology assumes that the ash is disposed. The estimated

additional ash to be disposed in lb/hr is given by:

∆

∆

Ash Coal ash product

HHV = (1.30)

where ash product is the fraction of ash produced as a byproduct of burning a given type of

coal to and HHV is the high heating value of the coal in Btu/lb as given in Table 1.3.
1-37

The cost of additional ash disposal due to the addition fuel usage is given by:

Annual Ash cost Ash Cost t ∆ ∆ = ash o p (1.32)

where Costash is the cost of ash disposal in dollars per ton ($/ton). Ash is in lb/hr and t

op

is

given equation 1.22a. A conversion of 2,000 lb per ton is required to convert $/ton to $/lb.

Indirect Annual Costs

In general, indirect annual costs (fixed costs) include the capital recovery cost, property

taxes, insurance, administrative charges, and overhead. Capital recovery cost is based on the

anticipated equipment lifetime and the annual interest rate employed. An economic lifetime of

20 years is assumed for the SNCR system. (The remaining life of the boiler may also be a

determining factor)

In many cases property taxes do not apply to capital improvements such as air pollution

control equipment, therefore, for this analysis, taxes are assumed to be zero [9]. The cost of

overhead for an SNCR system is also considered to be zero. An SCR system is not viewed as

risk-increasing hardware (e.g., a high energy device such as a turbine). Consequently, insurance

on an SNCR system is on the order of a few pennies per thousand dollars annually [9]. The

administrative charges, covering sales, research and development, accounting, and other home

office expenses, incurred in operation of an SNCR system are not significant for the cost

estimation procedure presented here. Finally, there are two categories of overhead, payroll 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 to operate an SNCR system, payroll overhead is zero and plant overhead is considered

negligible.

Using these assumptions, indirect annual costs in $/yr, IDAC, can be expressed as:

IDAC = CRF TCI (1.33)

where TCI is the total capital investment in dollars and CRF is the capital recovery factor.
1-38

Capital recovery factor was defined in Section 1 as:

( )

( )

CRF

i i n

n = +

−

1

1+ i 1 (1.34)

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

Total Annual Cost

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

and indirect annual costs as given in the following equation:

TAC = DC + IDAC (1.35)

The tons of NOx

 removed annually are:

NO Removed NO Q t x xin = N O B o p x η (1.36)

where NO

xin

 is given as lb/MMBtu, Q

B

 as MMBtu/hr and top in hours and a conersion of

2,000 lb/ton is required.

The cost in dollars per ton of NOx removed per year, cost efficiency is:

Cost Efficiency

TAC

NO Removed x

= (1.37)
1-39

1.5 Example Problem

An example problem, which calculates both the design parameters and capital and

annual costs, is presented below. The design basis is a retrofit SNCR system being applied to a

1000 MMBtu/hr, wall-fired, industrial boiler firing subbituminous coal. The following assumptions are made to perform the calculations:

Fuel High Heating Value 10,000 Btu/lb

Maximum Fuel Consumption Rate 1.0 x 105 lb/hr

Average Annual Fuel Consumption 4.38 x 108 lb

Number of SNCR operating days 155 days

Uncontrolled NOx

 Concentration 0.46 lb/MMBtu

Required Controlled NOx Concentration 0.30 lb/MMBtu

Percent Fuel Ash Weight 7.5%

Stored Urea Concentration 50% urea solution

Injected Urea Concentration 10% urea solution

Number of Days of Storage for Urea 14 days

In addition to these assumptions, the estimated economic factors required to perform the

calculations are taken from References [2] and [3]. These estimates are:

Cost Year December, 1998

Equipment Life 20 years

Annual Interest Rate 7%

Coal Cost, Eastern Bituminous 1.60 $/MMBtu

Ash Disposal Cost 11.28 $/ton

50% Urea Solution Cost 0.85 $/gal

Water Consumption Cost 0.0004 $/gal
1-40

1.5.1 Design Parameter Example

The boiler annual heat input rate, QB, is calculated from the High Heating Value for subbituminous coal given in Table 1.3 and the maximum fuel consumption rate,m fuel :

Q B

Btu

lb

lb

h r

Btu

M M Btu

M M Btu

lb = × = 1 0 000 100 000

1 0

1 000

6

, , ,

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

( ) C F plant lb

h r

= ×

× ×

= = 4 3 8 1 0

1 1 0 8760

0 5 50%

8

5

. . lb

 hr

yr

The SNCR system capacity factor is calculated from the months of SNCR operation, 5 months:

C FSNCR = == 1

365

0 4 2 42% 55 days

 days .

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

C Ftoal =× = = 0.5 0.4 2 0.2 1 21%

The NOx removal efficiency, NOx, is calculated from the inlet NOx concentration and the

required stack NOx concentration:

η N O

lb

M M Btu

lb

M M Btu

lb

M M Btu

x = − = = 0 4 6 0 3 0

0 4 6

0 3 5 3 5 . .

.

. %

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

estimate is given by:

( ) NSR

lb

M M Btu

lb

M M Btu

=

× + 

  ×

=

2 0 4 6 0 7 0 3 5

0 4 6

1 2 3

. . .

.

.
1-41

The reagent utilization can then be calculated based on the required NOx removal efficiency and

NSR value using:

U tilization = 0 3 5

1 2 3

0 2 8 28% .

. = = .

The value of the the NSR indicates that 1.23 moles of NH3 are required per mole of uncontrolled NOx

 to reduce the NOx level by 35%. This translates to a reagent utilization of 0.28, the

ratio of moles of reagent reacted to the moles injected. This indicates that 28% of the injected

reagent is being utilized for NOx

 removal. The remainder of the reagent is being destroyed or

passing through as ammonia slip.

The mass flow rate of the reagent is calculated using the molecular weight of the reagent, 60.06

g/mole and NO2

, 46.01g/mole and the SRT for urea, 2. For an NSR of 1.23, the reagent mass

flow rate is given by:

 . .. .

. m reagent = × ×××

× = 0 46 1000 0 35 123 60 06

2 46 01

130

lb

M M Btu

M M Btu

h r

g

mole

g

mole

lb

h r

The flow rate of the diluted solution, where the concentration of the aqueous solution is 50%

urea, is given by:

 . m sol

lb

h r lb

h r = =

130

0 5 0

260

The solution volume flow rate can then be calculated where  is the density of the aqueous

reagent solution,71.0 lb/ft3 for 50% aqueous urea solution at 60F.

q gph sol

lb

h r

gal

ft

lb

ft

=

×

=

260 7 481

7 1 0

2 7

3

3

.

.

The total volume stored in the tank, or tanks, is based on the volume that the SNCR

system requires for 14 days of operation. The on site storage requirement is given by:

Volume gph days gal tank = × ×= 2 7 1 4 2 4 9072 h r

day
1-42

The on site storage requirement for urea is 9,072gallons per 14 days. This shows that for

a large boiler, 1000 MMBtu/hr with 35% NOx removal efficiency the volume of urea required

to operate an SNCR system for155 days during summer months is approximately 10,500

gallons.

An estimates for power consumption is given by:

Power = kW

lb

M M Btu 0 4 7 0 4 6 1000

9 5

2 3 . .

.

M M Btu

h r × × =

Water consumption, assuming a 50% urea solution stored and a 10% urea solution injected, is:

gph

gal

lb

hr

lb

1 125

0.10

0.5

8.345

260

q water  =



 



 = × −

The estimated additional coal and ash required to maintain the same net heat output are

given by:

∆Coal

lb

h r

Btu

lb

Btu

M M Btu

M M Btu

h r = ×

× − 



 



 = 260 900

1 0

1

0 1 0

1 2

6 .

∆Ash

M M Btu

h r

Btu

M M Btu

Btu

lb

lb

h r = × × = 2 0 077 1 0 6

1 0 000

1 5 .

,

1.5.2 Cost Estimation Example

Once the SNCR system is sized, the capital and annual costs for the SNCR system can be

estimated. The direct capital costs are estimated using:

D C ( ) [ ] ( ) M M Btu

MM Btu

h r

MM Btu

h r

MM Btu

h r

= × × ×+× =

























$950 . . . $ 1, ,

.

1000

2375

1000

0 6 6 0 8 5 0 3 5 498 152

0 577
1-43

Indirect capital costs are estimated from the direct capital costs using the following equations:

Indirect Installation Costs

 General Facilities ($) $1,498,152 x 0.05 = $74908

 Engineering and Home Office Fees ($) $1,498,152 x 0.10 = $149,815

 Process Contingency ($) $1,498,152 x 0.05 = $74908

Total Indirect Installation Costs ($) $74908 + $149,815 + $74908 = $299,630

Project Contingency ($) ($1,498,152 + $299,630) x 0.15 = $269,667

Total Plant Cost ($) $149,815 + $299,630 + $269,667 = $719,112

Preproduction Cost ($) $719,112 x 0.02 = $143,82

Inventory Capital* ($) 9072 gal x 0.85 $ / gal = $7,711

Total Capital Investment (TCI) ($) $719,112 + $143,82 + $$7,711 = $741,205

Annual costs are based on the economic factors listed above. In addition, the SNCR

system is assumed to operate for 5 months of the year with a boiler loading of 65%, resulting in

a total capacity factor of 27%. The annual variable costs are given by:

yr

$ , Annual maintenance cost = . $ , = 11118 0 015× 741 205

Annual reagent cost gph $

gal

= × ×× = .





















2 7 0 8 5 0 2 1 8760 218 . h r

yr yr

$42 ,

Annual electricity cost = $

kW

 hr

yr

2 3 0 0 5 0 2 1 8760 115 kW

yr

× × 



 



 . . = $ 2 ,

Annual water cost 

 hr

yr

= × ×× 



 



 125 gph 0.0004 0 2 1 8760 = $

gal . yr

$92

[ ] Annual = M M Btu $

M M Btu

 hr ∆Coal cost

h r . yr yr 2 1 6 0 0 2 1 8760 887

× ×× = . $ 5,

[ ] Annual 

.

yr

lb

hr yr

∆Ash cost =

$

ton

 hr

lb

ton

1 5 1 1 2 8 0 2 1 8760

2 000

× ××

=

.

,

$156
1-44

The total variable direct annual cost, the sum of the cost of the reagent, electricity, water, coal

and ash, is given by:

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

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

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

 ( )

( )

CRF . .

+

= +

−

= 0 0 7 1 0 0 7

1 0 0 7 1

0 09439

2 0

2 0 .

.

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

IDAC . $ ,

yr = 0 09439 741 205 962

× = , $69

The total annual cost is the sum of the direct annual and indirect annual costs given by:

TAC = $ ,

yr

+ 

$

yr yr

8 2 216 6 9 ,962 $152 ,178 =

The annual cost in terms of NOx removed can be calculated using the total annual cost and the

tons of NOx

 removed annually by:

N O

.

x

lb

MM btu

M M Btu

hr yr

lb

ton

 hr

Removed = tons

×× × 



 





=

0 4 6 0 3 5 1000 0 2 1 8670

2000

147

. .

and

N O

.

x

lb

MM btu

M M Btu

hr yr

lb

ton

 hr

Removed = tons

×× × 



 





=

0 4 6 0 3 5 1000 0 2 1 8670

2000

147

. .

Total DirectAnnual Cost (DAC) ,

yr yr = yr

$31 748 $50,468 $82 ,216

+ =

Total Variable Cost ( )

yr yr

= + ++ + = 4 2 218 2 115 9 2 5 887 156 468 , , , $ $50,
1-45

References

[1] Selective Noncatalytic Reduction for NOx Control on Coal-fired Boilers, Draft Report,

prepared for the U.S. Environmental Protection Agency by The Cadmus Group, Inc.,

Bechtel Power Corporation, and Science Applications International Corporation.

May 1998.

[2] Investigation of Performance and Cost of NOx

 Controls as Applied to Group 2 Boilers.

Revised Draft Report, prepared for the U.S. Environmental Protection Agency by The

Cadmus Group, Inc., Bechtel Power Corporation, and Science Applications International Corporation. August 1996.

[3] Cost Estimates for Selected Applications of NOx

 Control Technologies on Stationary

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

prepared for the U.S. Environmental Protection Agency by The Cadmus Group, Inc.,

and Bechtel Power Corporation. June 1997.

[4] Analyzing Electric Power Generation Under the CAAA. EPA Office of Air and Radiation. March 1998.

[5] Committee of the Institute of Clean Air Companies, Inc. White Paper, Selective

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

1997.

[6] Tanner Industries, Inc. Storage & Handling of Ammonium Hydroxide. Philadelphia,

PA. October 1995.

[7] Electric Power Research Institute (EPRI). Technical Assessment Guide, Vol. 1. Revision 7, 1993.

[8] Northeast States for Coordinated Air Use Management (NESCAUM). Status Report

on NOx Control Technologies and Cost Effectiveness for Utility Boilers. June 1998.

[9] United States Patent, Method for the Reduction of the Concentration of NO In Combustion Effluents Using Ammonia. Inventor: Richard K. Lyon, Patent Number

3,900,554. August 19, 1975.

[10] Rini, M.J., J.A. Nicholson, and M.B. Cohen. Evaluating the SNCR Process for

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

Combustion NOx

 Control, Bal Harbor, Florida. May 24 - 27, 1993.

[11] Institute of Clean Air Companies, (ICAC). Proceedings from ICAC Forum: Cutting

NOx

 Emissions. March, 2000.

[12] State and Territorial Air Pollution Program Administrators (STAPPA) and Association
1-46

of Local Air Pollution Conrol Officials (ALAPCO). Controlling Nitrous Oxides.

July 1994.

[13] Personal communication with Mike Knenlein of Fuel Tech to Paula Hemmer (PechanAvanti) on April 2, 2000.

[14] Majors, Russ K., Dr. Russell Hill, Robert McMurry, and Scott Thomas, A Study of the

Impact of Ammonia Injection on Marketable Fly Ash Including Quality Control Procedures.
TECHNICAL REPORT DATA

(Please read Instructions on reverse before completing)

1. REPORT NO.

 452/B-02-001

2. 3. RECIPIENT'S ACCESSION NO.

4. TITLE AND SUBTITLE

The EPA Air Pollution Control Cost Manual

5. REPORT DATE

January, 2002 

6. PERFORMING ORGANIZATION CODE

7. AUTHOR(S)

 Daniel Charles Mussatti

 

8. PERFORMING ORGANIZATION REPORT NO.

9. PERFORMING ORGANIZATION NAME AND ADDRESS

 U.S. Environmental Protection Agency

 Office of Air Quality Planning and Standards

 Air Quality Standards and Strategies Division

 Innovative Strategies and Economics Group

 Research Triangle Park, NC 27711

10. PROGRAM ELEMENT NO.

11. CONTRACT/GRANT NO.

 

12. SPONSORING AGENCY NAME AND ADDRESS

 Director

 Office of Air Quality Planning and Standards

 Office of Air and Radiation

 U.S. Environmental Protection Agency

 Research Triangle Park, NC 27711

13. TYPE OF REPORT AND PERIOD COVERED

Final

14. SPONSORING AGENCY CODE

EPA/200/04

15. SUPPLEMENTARY NOTES

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

16. ABSTRACT

In Spanish, this document provides a detailed methodology for the proper sizing and costing of numerous air

pollution control devices for planning and permitting purposes. Includes costing for volatile organic

compounds (VOCs); particulate matter (PM); oxides of nitrogen (NOx); SO2, SO3, and other acid gasses;

and hazardous air pollutants (HAPs). 

17. KEY WORDS AND DOCUMENT ANALYSIS

a. DESCRIPTORS b. IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group

Economics

Cost

Engineering cost

Sizing

Estimation

Design

Air Pollution control

Incinerators

Absorbers

Adsorbers

Filters

Condensers

Electrostatic Precipitators

Scrubbers

18. DISTRIBUTION STATEMENT

 Release Unlimited

19. SECURITY CLASS (Report)

 Unclassified

21. NO. OF PAGES

1,400

20. SECURITY CLASS (Page)

 Unclassified

22. PRICE

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