—6/5/2015 – Draft for Public Comment

Chapter 1

Selective Noncatalytic Reduction

John L. Sorrels

Air Economics Group 

Health and Environmental Impacts Division 

Office of Air Quality Planning and Standards 

U.S. Environmental Protection Agency 

Research Triangle Park, NC 27711

David D. Randall, Carrie Richardson Fry, and Karen S. Schaffner

RTI International

Research Triangle Park, NC 27709

June 2015
Contents

1. Selective Noncatalytic Reduction ............................................................................................. 3

1.1 Introduction...................................................................................................................... 3

1.2 Process Description........................................................................................................ 10

1.2.1 Reduction Chemistry ......................................................................................... 11

1.2.2 Reagents............................................................................................................. 12

1.2.3 SNCR Performance Parameters......................................................................... 14

1.2.4 SNCR System .................................................................................................... 20

1.2.5 Other Considerations ......................................................................................... 25

1.2.6 New SNCR Approaches .................................................................................... 27

1.3 Design Parameters ......................................................................................................... 30

1.3.1 Design Parameters for Study-Level Estimates .................................................. 30

1.3.2 Design Parameters for Detailed/Performance Specifications............................ 38

1.4 Cost Analysis................................................................................................................. 40

1.4.1 Total Capital Investment.................................................................................... 41

1.4.2 Total Annual Costs ............................................................................................ 48

1.5 Example Problem........................................................................................................... 53

1.5.1 Design Parameter Example................................................................................ 54

1.5.2 Cost Estimation Example................................................................................... 57

References............................................................................................................................... 61
Chapter 1 – Selective Noncatalytic Reduction

1-3

1. SELECTIVE NONCATALYTIC REDUCTION

1.1 Introduction

Selective noncatalytic reduction (SNCR) is a post combustion emissions control

technology for reducing NOx by injecting an ammonia type reactant into the furnace at a properly 

determined location. This technology is often used for mitigating NOx emissions since it requires 

a relatively low capital expense for installation, albeit with relatively higher operating costs. 

Japan originally developed SNCR for oil and gas units in the 1970’s; Western Europe followed 

by applying the science to coal fired units in the late 1980’s and the U.S electric power sector 

began installations on coal plants in the early 1990’s. More than 45 gigawatts of coal-fired power 

capacity in the U.S. now have SNCR.

1 SNCR is now used beyond the electric power industry, 

and is currently being used for NOx emission control a multitude of combustion sources, 

including industrial boilers, electric utility steam generators, thermal incinerators, cement kilns, 

pulp and paper process units, steel industry process units, refinery process units, and municipal 

solid waste energy recovery facilities [1, 2, 3]. It is being used on industrial boilers covering a 

wide range of sizes from <50 MMBtu/hr to more than 800 MMBtu/hr [2]. SNCR is also being 

used on a wide range of sizes of utility boilers from <50 MW to more than 900 MW. More than 

half of utility boilers with SNCR are relatively small (<50 – 200 MW) but about 24 percent are 

larger than 300 MW.

1 Over 70 percent of the utility boilers using SNCR burn coal as the primary 

fuel and most of the others burn biomass, but the other types of combustion sources are burning a 

wide range of materials [2].1 SNCR can be applied as a standalone NOx control or with other 

technologies such as combustion controls. The SNCR system can be designed for seasonal or 

year-round operations.

Reported SNCR reduction efficiencies vary over a wide range. Temperature, residence 

time, type of NOx reducing reagent, reagent injection rate, uncontrolled NOx level, distribution of 

the reagent in the flue gas, and CO and O2 concentrations all affect the reduction efficiency of 

the SNCR [2]. Tables 1.1 and 1.2 and Figures 1.1a, 1.1b, and 1.1c summarize emission 

reductions for SNCR applications in a variety of industries [2]. Findings based on review of 

these data are as follows:

 Although installation of urea-based systems is more common than ammonia-based

deployments, operating data reveal higher NOx reductions occur with ammonia reagent. 

Table 1.1 shows the median reductions for urea-based SNCR systems in various industry 

source categories range from 25 to 60 percent, while median reductions for ammoniabased SNCR systems range from 61 to 65 percent. Note that most of the boilers with 

ammonia-based SNCR systems that are fired with solid fuels are fired with wood or 

municipal solid waste. Figure 1.1b shows nearly all ammonia-based systems have 

reduction efficiencies greater than 40 percent, while several urea-based systems have 

lower reduction efficiencies.

 

1 Spreadsheet of information provided to EPA's Clean Air Market Division from query of SNL Energy data on 

1/22/2015.
Chapter 1 – Selective Noncatalytic Reduction

1-4

Table 1.1: Summary of NOx Reduction Efficiencies Obtained Using SNCR on Different

Types of Boilers in the U.S. [2]

Type of source 

category Fuel

NOx

reduction 

reagent

Average boiler 

size

Median NOx

reduction (%)

Electric utility Coal Urea 320 MW 25

Co-generation Primarily wood, some coal, biomass, and 

tires

Urea 360 MMBtu/hr 50

Pulp & paper (P&P) Primarily bark and wood waste, 

supplemented with a variety of other fuels

Urea 410 MMBtu/hr 50

Municipal waste 

combustion (MWC)

Municipal solid waste (MSW) Urea 270 MMBtu/hr 37

Refinery CO boilers Typically refinery fuel gas Urea 320 MMBtu/hr 60

Miscellaneous 

combustion units

Primarily wood, MSW, or coal Ammonia 400 MMBtu/hr 65

Miscellaneous 

combustion units

Primarily crude oil or gas Ammonia 110 MMBtu/hr 61

Table 1.2: SNCR NOx Reduction Efficiency by Industry and Reagent Type [2, 4]

Industry and Units

% Reduction

Ammonia-Based Urea-Based

Cement Kilns 12-77 25–90

Chemical Industry NAa 35–80

Circulating Fluidized and Bubbling Bed Boilers 76–80 NA

Coal, Wood and Tire Fired Industrial and IPP/Co-Generations Boilers NA 20–75

Coal-Fired Boilers 38–83 NA

Gas- and Oil-Fired Industrial Boilers 30–75 NA

Glass Melting Furnaces 51–70 NA

Steel Products Industry NA 42.9–90

Municipal Solid Waste Incinerators 45–70 NA

Municipal Waste Combustors NA 16–87

Oil- and Gas-Fired Heaters 45–76 NA

Process Units NA 40–85

Pulp and Paper Industry NA 20–62

Refinery Process Units and Industrial Boilers NA 20–75

Stoker-Fired and Pulverized Coal-Fired Boilers 50–83 NA

Stoker-Fired Wood-Fueled Boilers 40–75 NA

Utility Boilers NA 20–66

Vapor, Sludge and Hazardous Waste Incinerators 65–91 NA

aNA means not available.
Chapter 1 – Selective Noncatalytic Reduction

1-5

Figure 1.1a: SNCR NOx Reduction Efficiency for Various Utility Boiler Sizes [2]

Figure 1.1b: SNCR NOx Reduction Efficiency for Boilers in Various Industry Sectors [2]

0

10

20

30

40

50

60

70

0 100 200 300 400 500 600 700 800

NOx Reduction Efficiency (%)

Boiler size (MW)

SNCR Reductions for Utility Boilers

Coal-fired Boilers

0

20

40

60

80

100

0 200 400 600 800 1000

NOx Reduction Efficiency (%)

Boiler size (MMBtu/hr)

SNCR Reductions for Industrial Boilers

Various Industry Sectors

P&P (bark & other wood fuel) MWC (MSW fuel)

Refineries (fuel gas fuel) Misc (various solid fuels)

Misc (various G/L fuels)

urea reagent: solid square, diamond, 

and triangular markers

ammonia reagent: "+" and "x" markers
Chapter 1 – Selective Noncatalytic Reduction

1-6

Figure 1.1c: SNCR NOx Reduction Efficiency Versus Baseline NOx Levels for Coal-fired 

Utility Boilers [2]

 Figure 1.1a shows the efficiencies for utility boilers range from 20 percent to over 

60 percent with most between 20 percent and 35 percent. Figure 1.1a also shows the 

efficiencies for the larger utility boilers are comparable to those for smaller utility boilers.

 Although there is significant scatter, Figure 1.1c shows a trend of increasing reductions 

with increasing baseline NOx levels for utility boilers. Specifically, the reductions range 

from 20 percent when the baseline NOx concentration is about 0.2 lb/MMBtu to 35 

percent when the baseline NOx concentration is about 0.8 lb/MMBtu. This plot excludes 

4 data points that had baseline NOx concentration over 1 lb/MMBtu and 5 additional data 

points with reductions over 50 percent because such conditions are significantly outside 

the range of the other available data. Similar plots for boilers in other industry source 

categories showed no trends. 

 Data indicates average reductions for industrial boilers surpass average reductions for 

utility boilers (see Table 1.1, Fig. 1.1a, and Fig. 1.1b). Figure 1.1b shows reductions for 

industrial boilers range from about 25 percent to 80 percent, which is a slightly higher 

range than for coal-fired utility boilers in Figure 1.1a. Table 1.1 shows the median 

reductions for industrial boilers equipped with urea-based SNCR in various industry 

source categories range from 37 percent to 60 percent, while the median reduction for 

utility boilers is 25 percent.

y = 22.554x + 16.725

R2 = 0.46

15

20

25

30

35

40

45

0 0.2 0.4 0.6 0.8 1

NOx Reduction, %

Inlet NOx Emissions, lb/MMBtu

SNCR Reduction vs "Inlet" NOx Level 

for Coal-fired EGUs

(Subset of all data)
Chapter 1 – Selective Noncatalytic Reduction

1-7

 Table 1.2 presents the range of reductions for numerous source categories. It also 

includes data for facilities outside the U.S. For most source categories, the range bounds 

are represented by facilities in the U.S. However, most of the reductions over 80 percent 

are for facilities outside the U.S. The only exception is the Steel Products Industry2 where 

the greatest reduction of 90 percent is at a U.S. facility.

Available information from 7 Best Available Retrofit Technology (BART) analyses in 

which SNCR was designated as BART for 11 cement kilns indicates estimated NOx reductions 

for SNCR systems that are between 35 percent and 58 percent with a median reduction of 40 

percent [5]. Two of these kilns have proposed BART emission limits--one at 5.5 lb NOx/ton 

clinker and the other at 8.0 lb NOx/ton of clinker. Also, SNCR was determined as BART in 2014 

for a lime kiln in Arizona. NOx reductions of 50 percent were estimated for the SNCR 

application, and the final BART emission limits were 3.81 lb NOx/ton of clinker for one kiln and 

other at 2.61 lb NOx/ton of clinker for the other, with a combined limit of 3.27 lb NOx/ton of 

clinker on a 30-day rolling average [6].

SNCR utilizes ammonia or urea as a NOx reduction reagent. An information collection 

request for data from electric utilities indicated that based on 132 SNCR units, approximately 

67% (or 88 units) used urea and 33% (44 units) used ammonia; of those units listed as using 

urea, 11 units indicated use of urea to ammonia conversion [7].

The mechanical equipment associated with an SNCR system is simple compared to an 

SCR, semi-dry FGD, or wet scrubber and thereby requires lower capital costs ($/mmBtu/hr 

basis). Installation of SNCR equipment requires minimum downtime. Although simple in 

concept, it is challenging in practice to design an SNCR system that is reliable, economical, and 

simple to control and that meets other technical, environmental, and regulatory criteria. Practical 

application of SNCR is limited by the boiler design and operating conditions.

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

existing coal-fired utility boilers [8]. In the 1990's there was little difference between the cost of 

SNCR retrofit of an existing boiler and SNCR installation on a new boiler [9]. Over the years 

SNCR has begun to be applied to existing sites that are more difficult to retrofit which means the 

gap between average retrofit and new installation costs may be greater than it used to be, but is 

not expected to be substantial. Therefore, the cost estimating procedure in this report is suitable 

for both retrofit and new boiler applications of SNCR on all types of coal-fired electric utilities 

and large industrial boilers. For other sources, this methodology is somewhat less applicable and 

calculations should be developed more specific to the source being controlled. The cost 

methodology incorporates certain approximations; consequently, it should be applied to develop 

study-level accuracy (+-30%) cost estimates for SNCR applications. 

Based on applications in operation, capital costs for SNCR installations are generally low 

due to the small amount of capital equipment required, and the cost per unit of output decreases 

as the size of the source increases. For example, Figure 1.2 shows the installed capital cost of 

SNCR technology for industrial boilers, on a $/MMBtu/hr basis, decreases as the size of the 

boiler (and therefore the gross heat input in MMBtu/hr) increases. In addition, the installed 

 

2 In the referenced study, this source category is called the “Industrial/Steel Industry”.
Chapter 1 – Selective Noncatalytic Reduction

1-8

capital cost of SNCR applications ranged from $5–20/kWe (kilowatt) in $2008 for power 

generation units [2]. The installed cost represents the cost of the capital equipment plus the 

associated installation expenses, but does not include the operation, maintenance, or reagent 

costs [1]. Table 1.3 contains a summary of average capital costs for SNCR applications on 

various size units in several source categories.

Most of the cost of using SNCR is operating expense. A typical breakdown of annual 

costs for utilities is 25% for capital recovery and 75% for operating expense [2]. The primary 

operating expense is for the NOx reduction reagent. Thus, the total annual costs vary directly 

with the NOx reduction requirements. For industrial boilers, typical cost effectiveness values for 

annual operation of SNCR are less than $3,000 per ton of NOx removed, and typical cost 

effectiveness values for ozone season operation are less than $4,000 per ton of NOx removed

[1].

3

Figure 1.2: Actual SNCR Installed Capital Costs on Industrial Sources 

Used with permission from ICAC [1]

 

3 The cited study reported cost-effectiveness values for more than 30 boilers. However, the study did not report the 

year to which costs were normalized or the applicable year dollars for the individual values.
Chapter 1 – Selective Noncatalytic Reduction

1-9

Table 1.3: Summary of SNCR Cost Data

Source 

Category Unit Size Fuel Type Capital Cost: average (range)a

$ Year Reference

Electric 

Generating 

Units

NA Coal NA ($10–$20/kW) [R] 2005$b[10]

NA NA NA ($5-$20/kW) 2008$b[2]

NA NA NA ($10-$30/kW) 2006$b[11]

IndustrialCommercial 

Boilers

>100 MMBtu/hr NA NA ($900–$2,500/MMBtu/hr 

or $9,000-$25,000/MW)

2006$ [12]

21–844 MMBtu/hr NA See Figure 1.2 2006$b[2, 13]

89–285 MMBtu/hr Wood NA ($0.924–$1.786 million) 2006$b[13]

>250 MMBtu/hr NA NA ($0.5-$1.0 million) 2000$b[14]

100–1,000 MMBtu/hr Coal NA ($2,600–

$5,300/MMBtu/hr) [R]

1999$ [15]

100–1,000 MMBtu/hr Gas NA ($2,100–

$4,200/MMBtu/hr) [R]

1999$ [15]

100–1,000 MMBtu/hr Oil NA ($2,000–

$4,100/MMBtu/hr) [R]

1999$ [15]

350 MMBtu/hr Gas and paper 

sludge

NA ($0.775 million) [N]

[$0.50-0.75 million]e

1997$ [14]

155 MMBtu/hr Medium 

Density 

Fiberboard 

waste and 

wood waste

NA ($0.24 million) [N] 1996$ [14]

900 MMBtu/hr Wood NA ($1.1 million) 1999$b[14]

475 MMBtu/hr Wood NA ($0.70 million) 1999$b[14]

300 MMBtu/hr Wood NA ($0.60 million) 1999$b[14]

245 MMBtu/hr Wood NA ($0.39 million) 1999$b[14]

Portland 

Cement

1.095 million short 

tpy clinker

NA NA ($1.154 million or $1.05 

per short ton clinker) [N]

2011$b[16]

1.09 million short tpy 

clinker

NA NA ($2.3 million or $2.1 per 

short ton clinker) [R]

2006$b[17, 18]

1.13 million short tpy 

clinker

NA NA ($2.3 million or $2.0 per 

short ton clinker) [R]

2006$b[17, 18]

2.16 million short tpy 

clinker

NA NA ($2.3 million or $1.1 per 

short ton clinker) [R]

2006$b[17, 18]

1.4 million short tpy 

clinker

NA NA ($1.153 million or $0.8 

per short ton clinker)

2004$ [19]

NA NA NA ($1.4 million) [N] 2003$ [20]

<150 ton/hr 

(precalciner kiln)

NA NA ($0.40–$0.80 million)e 1999$b[14]
Chapter 1 – Selective Noncatalytic Reduction

1-10

Source 

Category Unit Size Fuel Type Capital Cost: average (range)a

$ Year Reference

100 ton/hr 

(precalciner kiln)

NA NA ($0.08/ton clinker or 

$0.90 million)

1994$b[14]

0.3 million short tpy 

clinker (wet kiln)

NA NA ($1.4 million or $4.7 per 

short ton clinker) [R]

2006$b[17, 21]

0.320 million short 

tpy clinker (wet kiln)

NA NA ($1.2 million to $1.4 

million or $3.8 to 4.4 per 

short ton clinker)

2006$b[17, 18]

Petroleum 

Refinery–

Process 

Heater

350 MMBtu/hr Gas/refinery 

fuel gas or 

refinery oil

NA ($0.706–$2.59 million) 

[R]d

2004$c[22]

Petroleum 

Refinery–

Boiler

650 MMBtu/hr Gas or refinery 

fuel gas

NA ($1.31–$4.80 million) 

[R]d

2004$c[22]

Pulp and 

Paper–

Boilers

300,000 lb/hr Wood or 

wood/coal/oil

NA ($1.5 million) [R] 2004$b[10]

a Costs are for both new SNCR and retrofit SNCR, unless otherwise noted. [R] indicates costs are for retrofit only. 

[N] indicates costs are for new only, NA indicates the data are not available.

b Year of reference.

c Year analysis was conducted (assumed vendor contacts were made that year).

d Costs are for SNCR only, that is part of combination control including LNB plus SNCR.

e Cost does not include installation cost; installation would add 20–30% to the cost shown here.

1.2 Process Description

The basis of SNCR technology is a non-catalyzed chemical reaction utilizing an ammonia 

based reagent (such as urea or ammonia) for reducing NOx into nitrogen (N2) and water (H2O) by 

injecting this reagent into the post combustion gas stream at temperatures ranging from 1600-

2400°F (870–1320°C) [23]. 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 conventional SNCR process occurs within the combustion unit, which acts as the 

reaction chamber. Figure 1.3 shows a conventional SNCR process schematic for an electric 

power boiler with injection nozzles mounted through the wall and penetrating the combustion 

unit. The injection nozzles are located in the post-combustion area in the upper area of the 

furnace near the 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 NOxmolecules are reduced 

and the reacted flue gas then passes out of the boiler. More details on the SNCR process and 

equipment are provided in the following sections.

Single- and multi-level injection systems for SNCR installations can be effective for NOx

reduction. Using different injector configurations can increase efficiency and reduce capital and 

operating costs. Several new approaches are currently being used in addition to conventional 

SNCR installations, including SNCR Trim, Rich Reagent Injection, NOxSTAR, and ROTAMIX. 
Chapter 1 – Selective Noncatalytic Reduction

1-11

Figure 1.3: Boiler Gas Path Configuration

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 because it is the predominant form of NOx within the 

boiler. The ammonia reaction equation is:

2NO  2NH3 

1

2 O2  2N2  3H2O

(1.1)

The overall reaction for urea is:
Chapter 1 – Selective Noncatalytic Reduction

1-12 2NO CO(NH2

)

2 

1

2 O2  2N2 CO2  H2O

(1.2)

The primary byproduct formed in either ammonia- or urea-based SNCR systems is 

nitrous oxide (N2O). N2O is an ozone depletor and greenhouse gas.4 Urea-based reduction 

generates significantly more N2O than ammonia-based systems; up to 30% of the NOx can be 

transformed into N2O [9, 24]. In one study, N2O emissions were measured at 0 to 7 μmol/mol in 

ammonia-based SNCR, and as high as 27.8 μmol/mol in urea-based SNCR [25]. The amount of 

N2O formed depends on the reagent feed rate and temperature, and increased N2O formation 

correlates with increased NOx reductions [24, 26]. Proprietary additives are available for the 

urea-based SNCR process to reduce the formation of N2O [9].

1.2.2 Reagents

Reagent costs currently account for a large portion of the annual operating expenses 

associated with this technology, and this portion has been growing over time. Ammonia is 

generally less expensive than urea since urea is derived from ammonia. However, the choice of 

reagent is based not only on cost but also on physical properties and operational considerations. 

The properties of urea and ammonia in aqueous solutions are shown in Table 1.4.

Table 1.4: Urea and Ammonia Reagent Properties [27]

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 

temperature

Liquid Liquid

Concentration of reagent normally 

supplied

50% by weight 29.4% by weight

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

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

(58 lb/ft3for 19%)

Vapor pressure @ 80°F <1 psia 14.8 psia [28]

Crystallization temperature 64°F −110°F

Flammability limits in air Non-flammable Lower explosion limit = 16% NH3

by volume

Upper explosion limit = 25% NH3

by volume.

Threshold limit value (health 

effects)

Not specified 25 ppm

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

Acceptable materials for storage Plastic, steel, or stainless steel (no 

copper or copper- based alloys or 

zinc/aluminum fittings)

Steel tank, capable of handling at 

least 25 psig pressure (no copper 

or copper-based alloys, etc.)

 

4 EPA issued a final rule on November 29, 2013 as part of a notice of data availability concerning the Mandatory 

Greenhouse Gas Rule that indicates the global warming potential (GWP) of N2O is 298. The November 29, 2013 

notice can be found in the Federal Register at http://www.gpo.gov/fdsys/pkg/FR-2013-11-29/pdf/2013-27996.pdf

.
Chapter 1 – Selective Noncatalytic Reduction

1-13

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

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

presents safety issues and increases transportation cost [23]. 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 [29]. Decreasing the concentration, however, increases the required storage

volume and associated transportation costs. 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). 

Urea is generally stored in a 50% aqueous solution [2, 29]. At this concentration, the urea 

solution must be heated and circulated in cold climates due to its low freezing point, 64°F 

(18°C). Higher concentrations of urea solutions are available that 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, or can be transported at a higher concentration, 

which reduces the transportation cost due to the lower weight and volume of the solution. 

However, to produce aqueous urea for use in the SNCR system, the urea must then be mixed 

with water at the facility to dilute it to the 50% aqueous solution [23]. For urea pellets, this

dissolving, diluting, and mixing process is generally cost prohibitive except for remote sites, 

large facilities, or facilities where chemical mixing processes are already being performed, due to 

the additional capital requirements associated with this process [23, 30]. Urea solutions become 

more cost effective as the transported concentrations increase; the cost to transport a 70% 

solution by rail to a third-party facility is 65% less than the cost to transport a 50% urea solution 

and is 58% less than the cost to transport a 60% urea solution [23].

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 [29]. Because of these 

advantages, urea is more commonly used than ammonia in large boiler applications of SNCR 

systems.

Generally, anhydrous ammonia, which is typically used in conventional SNCR, is the 

least costly reagent, with a nominal cost one-half that of 50% urea. A 29.4% aqueous ammonia 

solution costs 150% more than anhydrous ammonia, and 70% urea costs 175% more than 

anhydrous ammonia. However, the reagent characteristics associated with ammonia and urea 

must also be taken into consideration. At any level of dilution, ammonia will flash evaporate 

upon contact with flue gas; therefore, a physical distribution grid must be used, or in some 

instances, an alternative high-energy lance injection system, such as the NOxSTAR or Rotamix, 

must be used. These alternative SNCR technologies are discussed in Section 1.2.6 below. These 

injection systems increase the overall capital cost, countering some of the cost savings associated 

with dilution of anhydrous ammonia. Although urea is a more costly reagent, the vapor pressure 

of urea is much lower than that of ammonia. Because urea is most efficiently introduced into the 

system as a droplet, allowing for additional mixing with the flue gas and tailoring of the release 
Chapter 1 – Selective Noncatalytic Reduction

1-14

location, it is also a more flexible process than ammonia injection and is also typically more cost 

efficient over time. In general, the use of 70% urea solution shipped by rail and diluted to 50% 

onsite results in the lowest cost SNCR process for most applications, with a savings of 20% 

compared to delivered cost of a 50% urea solution [23].

1.2.3 SNCR Performance Parameters

The design and operational factors affecting NOx reduction are:

 Reaction temperature (sp.: furnace temp)

 Residence time (reagent injection location)

 Degree of mixing 

 Uncontrolled NOx concentration (starting NOx)

 Ratio of injected reagent to uncontrolled NOx (amount of reagent injected); and

 Ammonia slip (which is strongly influenced by the ratio of injected reagent to uncontrolled 

NOx)

Figures 1.4 through 1.8 in this section present graphical representations of the effect of 

these factors on SNCR reductions. The plots are intended to illustrate trends and relative effects 

of the factors as discussed in the text, but they are not based on test data.

Temperature

The NOx reduction reaction occurs within a specific temperature range for a selected 

reagent - at lower temperatures, the reaction kinetics are slow: at higher temperatures, the 

reagent oxidizes and additional NOx is generated. Figure 1.4 shows the NOx reduction efficiency 

for urea and ammonia at various boiler temperatures. For ammonia, the optimum temperature 

range is 1600–2000°F (870–1100°C), with peak removal usually occurring at 1750°F (950°C) 

[23, 29]. For urea, the optimum temperature range is 1650–2100°F (900°–1150°C), with peak 

removal typically occurring at 1850°F (1010°C) [23, 29]. 
Chapter 1 – Selective Noncatalytic Reduction

1-15

Figure 1.4: Effect of Temperature on NOx Reduction

During the engineering phase, designers locate the injection points based on: the furnace 

operating conditions, the owner-selected reagent (urea or ammonia), and reaction rate curves 

(similar to those above) to optimize reagent consumption for a pre-determined NOx reduction 

rate. Typically, the reagent is injected between the boiler superheater and reheater or the radiant 

and convective regions, where the appropriate temperature range is typically available [29]. 

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, which are established to meet steam generation requirements – these design 

parameters are not always ideal conditions for SNCR. Flue gas temperatures in the upper furnace 

through the convective pass may vary by ±300°F (150°C) from one boiler to the next [29]. 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

By definition, residence time is the amount of time the reactants are present within a

chemical reactor. The longer the residence time, the greater conversion achieved. The upper area 

of the furnace is the reaction area for the SNCR process with flue gas velocity determining 

residence time within this fixed area; however, boiler design establishes flue gas velocity. 

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 [29]. However, the gain in performance for residence times 

greater than 0.5 seconds is generally minimal, and performance degradation is observed for 

residence times less than 0.2 seconds [9, 23]. Figure 1.5 shows the effect of residence time and 

temperature on NOx reduction.
Chapter 1 – Selective Noncatalytic Reduction

1-16

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

volumetric flow rate. These design parameters are optimized for steam generation and prevent 

watertube erosion. Consequently, the residence time in the boiler is not always ideal for the 

SNCR process.

Figure 1.5: Effect of Residence Time on NOx Reduction

Degree of Mixing

For optimal reaction rates and decreased reagent consumption, the reagent is properly 

mixed with the flue gas via a multi-point injection grid situated within the furnace. The mixing 

requirements are unit specific and depend on the air flow profiles through the furnace [29]. 

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).

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

designed nozzles that 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 [29].

Inadequate mixing results in insufficient NOx reduction. Mixing patterns can be improved 

by several methods:
Chapter 1 – Selective Noncatalytic Reduction

1-17

 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 that limit the reduction process at low NOx concentrations [29].

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

the percent NOx reduction is lower. Figure 1.6 shows the NOx reduction efficiency as a function 

of temperature for several uncontrolled NOx levels.

Figure 1.6: Effect of Uncontrolled NOx Level on NOx Reduction Efficiency

Normalized Stoichiometric Ratio

The normalized stoichiometric ratio (NSR) defines the amount of reagent needed to 

achieve the targeted NOx reduction. Theoretically, based on reaction equations 1.1 and 1.2, 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 and 3 moles of ammonia per mole of NOx [9].
Chapter 1 – Selective Noncatalytic Reduction

1-18

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 the following:

 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 1.3, Design Parameters, provides further discussion of these influences and a 

method for estimating the NSR.

Figure 1.7 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.

Figure 1.7: Effect of NSR on NOx Reduction

Ammonia Slip

Ammonia slip results from excess reagent injection to overcome inherent natural system 

limitations to obtain the desired level of NOx reduction. In operational terms, reagent injection 

rate establishes NOx reduction and ammonia slip; consequently, ammonia slip results from 
Chapter 1 – Selective Noncatalytic Reduction

1-19

operational settings. Typical NSR values require significantly more reagent to be injected in 

practice than is required by the theoretical stoichiometric ratio Figure 1.8 shows an example of 

the NOx reduction efficiency that can be achieved for an uncontrolled NOx level of 120 parts per 

million (ppm) and various ammonia slip levels.

Figure 1.8: NOx Reduction for Various Ammonia Slip Levels

Ammonia in the flue gas stream has several negative impacts. As shown in Table 1.4, 

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-containing 

fuels. Ammonia-sulfur salts can plug, foul, and corrode downstream equipment such as air 

heaters, 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 later in this chapter in 

Section 1.2.5, Other Considerations.

Limits on acceptable ammonia slip, imposed by either regulatory limits or 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 systems control ammonia slip between 2 and 10 ppm [31]. Ammonia slip monitoring 

instruments are commercially available and are in place and operating at a number of coal-fired 

units. Facilities typically install ammonia slip monitors between the SNCR and the air heater and 

may measure at one or several points. These systems monitor ammonia slip and help the unit 
Chapter 1 – Selective Noncatalytic Reduction

1-20

maintain slip levels of 2–3 ppmv or less. The capital cost for one ammonia slip monitoring 

instrument is estimated to be $40,000 for a single measurement point and up to $70,000 in 

capital cost for three measurement points [32]. Ammonia slip can also be controlled by 

establishing a feedback control loop to adjust the reagent injection feed rate according to the 

ammonia slip level measured by the monitor [23]. Another method of quantifying 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 sub-licensees 

authorized to supply and install SNCR technology in several industrial sectors.

An SNCR system has four basic steps to accomplish:

 Receiving and storing the reagent;

 Diluting, metering, and mixing the reagent;

 Injecting diluted reagent at appropriate locations in the boiler; and

 Mixing the reagent with flue gas.

These steps are common to both urea and ammonia SNCR; however, the design and 

equipment specifications for the two systems are different, because 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 1.9 presents a simplified system flow 

schematic and Table 1.5 lists the equipment requirements for urea-based SNCR.
Chapter 1 – Selective Noncatalytic Reduction

1-21

Figure 1.9: Urea SNCR Process Flow Diagram [29]

Table 1.5: Urea-Based SNCR System Equipment

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, and

 Instrumentation for flow, pressure, temperature, and a control panel

Injection zone metering (IZM) 

modules (1 to 5 modules)

Skid mounted metering modules consisting of

 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
Chapter 1 – Selective Noncatalytic Reduction

1-22

Item Description/Size

Air compressor Distribution 

modules (1 to 5 modules)

Rotary type

Urea solution distribution module consisting of,

 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

Injectors (4 to 12 per 

distribution module)

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 wall panels, 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 and 

oxygen in the flue gas and providing a feedback signal for urea injection control

Economizer outlet emission 

monitors

Monitors NOx and O2 in the flue gas and provides a feedback signal for urea 

injection control

Instrumentation and controls Instrumentation and standalone, 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

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

requirements while minimizing capital costs. Modular shop assembly of pumps, valves, internal 

piping, instruments, and controls reduces field installation time and related costs while providing 

flexibility for future expansion [29]. The components are assembled into functional units and 

mounted on stainless steel skid modules. These modules can then be transported to the site and 

installed directly. The skid modules shown in Figure 1.9 will be discussed further in the next 

sections.

It is typical for large industrial sources employing urea-based SNCR systems to store 

10,000–20,000 gallons per tank to maintain sufficient volume for 1–3 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 
Chapter 1 – Selective Noncatalytic Reduction

1-23

applicability of heat tracing, insulation, and seismic design criteria are determined based on sitespecific 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, inline duplex strainers, electric heaters, and 

instrumentation and controls for reagent pressure, flow, temperature, and quantity [29].

Diluting, Metering, and Mixing of the Reagent 

Dilution Water Pressure Control Module

The dilution water pressure 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 dilution water pressure module 

typically consists of two full-flow multistage stainless steel centrifugal pumps, an inline 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 [29]. The 50% solution from storage is diluted for injection, typically to either 5% or 

10%. [8, 29]

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 dilution water pressure module. Each IZM module 

includes a chemical metering pump, a water pump, an inline static mixer, a local control panel, 

zone isolation valves, and magnetic flow 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 the local

programmable logic controller. 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 and configuration, the uncontrolled NOx

concentration, and the desired NOx removal efficiency. Several IZM modules can be combined 

onto one skid-mounted system [29].
Chapter 1 – Selective Noncatalytic Reduction

1-24

Injecting 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. One distribution module for each IZM module provides reagent to 

multiple injectors [29].

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 1–5 injection zones

with 4–12 injectors per zone [29]. Injectors are located in open areas of the boiler, such as the 

region between the superheater and reheater sections. Figure 1.3 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 suboptimal boiler areas decreases the NOx reduction efficiency 

that can be achieved by the system while maintaining the required ammonia slip level.

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 because they are not 

directly exposed to hot flue gas.

 Lance injectors consist of a small pipe that 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
Chapter 1 – Selective Noncatalytic Reduction

1-25

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. 

Multinozzle lances are a more complicated design; therefore, they are more expensive than 

single-nozzle lance or wall injectors [29].

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- 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 because they require a larger 

compressor and a more robust injection system, and consume more electric power.

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

complicated and expensive than those used in urea-based systems [29]. These systems inject gasphase ammonia rather than an aqueous solution. For this reason, ammonia-based systems often 

use high-energy 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 existing 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 the convective cavity. Existing watertubes and asbestos may need to be moved or removed 

from the boiler housing. 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. The methodology 

presented in section 1.4 estimates SNCR capital costs that model actual costs for typical SNCR 

retrofits at existing boilers. The estimated costs on a $/kW basis increase sharply for small 

boilers (<50 MW) due to both economies of scale and to account for the more difficult 

installation conditions that are often encountered for the small boilers. As such, estimates based 

on this methodology typically should not include an additional retrofit factor for existing boilers. 
Chapter 1 – Selective Noncatalytic Reduction

1-26

Little data are available regarding the cost of new installations versus retrofits. One study 

suggested retrofit installation of the SNCR system generally calls for additional expenditures in 

the range of 10–30% of the SNCR system cost [9], a minimal increase. Based on this study, costs 

for installation at new facilities may be 9 to 23 percent lower than the costs for retrofits at 

existing sources.

Ammonium Sulfate Deposition and Fly Ash Considerations 

Sulfur trioxide (SO3) forms during the combustion of fuels that 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 that must be disposed of 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 

an elevated pH level. Under these conditions, ammonia gas can be released 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 ability to sell the ash as a byproduct and the storage and disposal of the ash by 

landfill [9, 33].

Ammonia slip mitigation (ASM) technology exists to treat fly ash that is contaminated 

with ammonia. The technology consists of blending a chemical oxidizer such as calcium 

hypochlorite with the dry fly ash. When combined with water the calcium hypochlorite reacts 

with some of the ammonia in solution to form chloramines. Overtreatment, however, can result 

in the release of chlorine gas when the fly ash is mixed with water. Treatment for typical 

operating conditions has reportedly reduced ammonia levels by roughly 30 to 50 percent. The

total annual cost for one electricity generating unit was estimated to be $5.61 per ton of ash 

treated [33].

Computational Fluid Dynamics (CFD) 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 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.
Chapter 1 – Selective Noncatalytic Reduction

1-27

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

chemical kinetic model, which defines the chemical reactions associated with the SNCR process 

in the boiler. Analysis of the fuel and flue gas constituents is required to develop this model. The

model predicts the reactions and rates of reactions within the boiler in order to estimate the NOx

reduction along the flue gas pathway.

Modeling such as this 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 [29].

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 because 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 N2O in the stack effluent. Enhancers require additional storage, distribution, and control 

system equipment. Enhancer formulations are generally proprietary [9].

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 [29]. Section 1.4.2, Total Annual Costs, presents a method for estimating the 

additional fuel and electricity usage.

1.2.6 New SNCR Approaches

Several advances to conventional SNCR technology have been made. The alternative 

approaches include systems such as SNCR Trim, Rich Reagent Injection (RRI), NOxSTAR and 

ROTAMIX. These systems use different injector configurations to improve efficiency and 

reduce costs. The costs presented in this discussion are from 2004 to 2006 and thus should not be 

considered current. However, it is expected that the trends or ranking have not changed.
Chapter 1 – Selective Noncatalytic Reduction

1-28

SNCR Trim. The SNCR Trim technology is a simple, low-cost, low-energy single-level 

injection system with injectors located approximately five feet apart along the front wall of the 

upper furnace. By using upper furnace injection, the droplet trajectory can be optimized for 

penetration into the bulk turbulent mixing in the furnace. SNCR Trim has been applied to more 

than 21 coal-fired utility boilers and has been demonstrated for utility boilers ranging from 35 to 

720 MW. Typical NOx reductions of 25–35% are achieved. Capital costs for SNCR Trim 

installations are typically projected to be half what would be incurred for a conventional SNCR 

in the same application, approximately $5-10/kW for a single level of injectors [23].

Rich reagent injection. RRI involves the injection of urea or ammonia into a hightemperature, fuel-rich environment with a residence time of 0.5–1 seconds. The efficiency of 

RRI depends on the extent of overall mixing, and is typically in the range of 30-40% NOx

reduction. Ammonia slip with the RRI process is minimal because any unreacted urea or 

ammonia is oxidized to nitrogen oxide (NO) in the upper furnace. RRI has been demonstrated to 

achieve 30% NOx reductions in two existing cyclone-fired boilers with overfire air. For a 500-

MW cyclone boiler with a single level of injectors, the capital cost for RRI alone is 

approximately $8-12/kW. RRI can be combined with SNCR Trim to achieve an overall NOx

reduction efficiency of 55% when operated during ozone season, for an additional capital cost of 

$4/kW and an overall cost effectiveness of $1,447 per ton of NOx removed [23].

NOxSTAR. NOxSTAR uses an injection grid to provide NOx control by injecting 

ammonia and a hydrocarbon into a utility boiler within the flue gas path at a temperature in the 

range of 1800–2000°F (980–1090°C). The hydrocarbon serves to reduce the ammonia slip, 

enabling higher reagent injection rates, resulting in NOx reductions twice as high as could be 

achieved with conventional SNCR. Full-scale demonstrations have achieved 45–50% NOx

reduction on a long-term basis, although reductions as high as 70–80% are probably attainable 

for some applications. In particular, applications with higher flue gas temperatures will see a 

greater NOx reduction and lower hydrocarbon usage requirements. Capital costs for the 

NOxSTAR system are high, ranging from $60–75/kW; however, for higher NOx baseline 

concentrations, the removal efficiency can prove cost effective [23].

Rotamix®. The Rotamix® technology introduces urea or ammonia in the upper furnace, 

typically in conjunction with a form of boosted (i.e., high pressure) overfire air called rotating 

opposed fired air (ROFA). ROFA is a patented process in which the rising combustion gases 

through the furnace (or bulk flow in a fluidized bed combustor) are set in rotation, using customdesigned, asymmetrically-placed air nozzles. ROFA consists of a boost fan, insulated ductwork, 

modulated dampers, air nozzles, and a control system. Like typical overfire air systems, ROFA 

stages the primary combustion zone to burn overall fuel rich. The remaining excess secondary air 

is added through the ROFA injection nozzles high in the furnace to complete burnout. In a 

combined ROFA/Rotamix system, a NOx reducing reagent is introduced downstream of the 

ROFA injection nozzles into a well distributed, turbulent zone that allows for the effective 

mixing of the NOx reducing reagent with the combustion gases. Although many of the early 

installations used ammonia as the NOx reducing reagent, urea is now the preferred reagent 

(particularly for large boilers) because it vaporizes more slowly than water and has a broader 

reaction window than ammonia.
Chapter 1 – Selective Noncatalytic Reduction

1-29

The Rotamix system consists of a small ambient-air Rotamix fan placed on deck. On 

grade is the reagent delivery system, including: reagent storage tank, reagent pump skid, dilution 

water pump skid, and humidification water pump skid. The delivery lines supply pressurized 

water and reagent to the Rotamix cabinet, located near the Rotamix injector boxes at the upper 

furnace. The water and reagent are mixed inside the Rotamix cabinet and are delivered to 

individual injectors. A humidification cabinet, located beside the Rotamix cabinet, provides 

humidification to the Rotamix air nozzles to condition the air flow to optimize chemical 

utilization. The Rotamix injectors use air-boosted nozzles and thus less water than conventional 

SNCR reagent injectors. The locations of both the ROFA and Rotamix ports are determined from 

CFR modeling and field test data.

As of early 2010, Rotamix was installed on 24 boilers in the US. All but 3 of the 24 

installations also include ROFA. Boiler capacities range from 17 MW to 570 MW, and 3 of the 

boilers (13 percent) are larger than 260 MW. Half of the current installations are on tangentialfired boilers; most of the others are on wall-fired boilers, but there is also a grate unit and small 

wood fired bubbling fluidized bed combustor. All of the boilers fire coal, except for one small 

wood-fired combustor and another that burns landfill gas. Together, ROFA and Rotamix can 

achieve 60–80+% total NOx reduction at a capital of cost of $24-32/kW for a 250 MW boiler and 

$40-55/kW for a 150 MW boiler. Reductions for Rotamix alone are reported to be 25 to 40 

percent. Cost effectiveness for one facility was reported at $550/ton of NOx reduced, but this 

facility had relatively high baseline emissions of about 0.6 lb/MMBtu. In general, the cost 

effectiveness of combined ROFA and Rotamix technology is likely to be higher [23, 34, 35, 36, 

37, 38].

Hybrid SNCR/SCR. SNCR and SCR may be combined in a “hybrid” manner by 

installing a small layer of SCR catalyst in ductwork downstream of the SNCR system. Such a 

system can achieve a higher NOx reduction than is possible with SNCR only but at lower capital 

cost than with a full SCR system. A hybrid system also can achieve better reagent utilization 

than an SNCR system because the SNCR reagent can be injected into cooler temperatures (i.e., 

adjusting the placement of injectors in the boiler) than in a stand-alone SNCR system. This 

increases the NOx reduction achieved with SNCR while also increasing ammonia slip. The 

ammonia slip then provides reagent to a relatively small SCR that reduces ammonia while also 

achieving additional NOx reductions [39, 40].

Hybrid technology has been evaluated extensively in modeling and pilot-scale studies 

[40, 41, 42, 43]. Commercial applications in the U.S., however, have been rare. At least three 

coal-fired utility boilers have been equipped with hybrid technology for demonstrations or shortterm commercial operation, though none are still operating [11, 40]. As of 2005, two hybrid 

systems were operating in the steel industry [40]. In the early 1990’s a gas-fired utility boiler 

also was equipped with a hybrid system [41].

Hybrid systems on two coal-fired utility boilers have achieved reductions up to more than 

90 percent, depending on operating conditions; for example, performance is better at low load 

than at high load [11, 44]. A gas-fired utility boiler equipped with a hybrid system also achieved 

reductions up to 90 percent [41]. On other utility boilers, hybrid systems have achieved or been 

designed to achieve reductions between 40 percent and 75 percent [11, 40]. 
Chapter 1 – Selective Noncatalytic Reduction

1-30

Capital costs for a hybrid system that was installed on a 107 MW coal-fired utility boiler 

were about $114/kW in 2005 dollars [39]. In 2006, capital costs for hybrid systems were 

estimated to be $35/kW to $80/kW, while SCR capital costs were estimated to be $70/kW to 

$200/kW, and SNCR capital costs were estimated to be $10/kW to $30/kW [11].

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 [45]. Furthermore, the design is highly site-specific. In light 

of these complexities, SNCR system design is generally undertaken by providing all of the plantand 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 [29].

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 U.S. Environmental Protection Agency (EPA) report Selective 

Noncatalytic Reduction for NOx Control on Coal-fired Boilers [29]. This procedure assumes that 

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 methodology presented in Reference [29] is the maximum potential heat released by 

the boiler or heat input rate, QB, expressed as MMBtu/hr. It is obtained from the higher heating

value, HHV, of the fuel in Btu per pound (Btu/lb) multiplied by the maximum fuel consumption

rate in pounds per hour (lb/hr):

6

10

1

QB HHV m

fuel 

(1.3)

Where:

QB = maximum heat rate input to the boiler, MMBtu/hr

HHV = higher heating value of the fuel, Btu/lb

ṁfuel = maximum fuel consumption rate of the boiler, lb/hr

1/106 = conversion factor of 1 MMBtu/106 Btu

Table 1.6 provides the HHV for various coals.
Chapter 1 – Selective Noncatalytic Reduction

1-31

Table 1.6: Higher Heating Values for Various Coals

Type of Coal Energy Content (Btu/lb)

Lignite 5,000–7,500

Subbituminous 8,000–10,000

Bituminous 11,000–15,000

Anthracite 14,000

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

net plant heat rate, NPHR in MMBtu per Megawatt-hour (MMBtu/MWh):

QB Bmw NPHR

(1.4)

Where:

BMW = boiler MW rating at full load capacity. 

NPHR = net plant heat rate, MMBtu/MW

Note that if NPHR is not known (e.g., a cogeneration unit), a conversion value for coal of 10,000

Btu/kWh (or 10 MMBtu/MWh) can be used as a reasonable estimate; a conversion value for 

petroleum of 11,000 Btu/kWh (11 MMBtu/MWh) and for natural gas of 8,200 Btu/kWh 

(8.2 MMBtu/MWh) can be used [46].

5 Using this value, the heat input rate, QB, for a coal-fired 

unit is:

QB BMW 10

(1.5)

Where:

10 = estimated NPHR for coal, MMBtu/MWh.

Heat Rate Factor

The heat rate factor (HRF) is the ratio of actual heat rate of the boiler, in terms of the 

boiler NPHR in MMBtu/MWh, compared to a typical heat rate of 10 MMBtu/MWh. The 

developers of the cost estimation methodology presented in section 1.4.1 determined that using 

this ratio in the equation for capital costs helped account for observed differences in actual costs 

for different coal-fired boilers. To maintain consistency with that approach, the same ratio (i.e., 

with 10 in the denominator) also has been used in the equations for oil and gas fired boilers in 

section 1.4.1. The NPHR is simply the amount of fuel energy that a boiler consumes to generate 

1 MWh of electricity, and is determined based on measurements of the electricity generation and 

 

5 In recent years (2003 to 2010), the average NPHR for coal has increased slightly (likely due to aging of 

equipment), and the average NPHR for natural gas has decreased slightly (likely due to the increased use of 

natural gas fuel and the installation of new equipment).
Chapter 1 – Selective Noncatalytic Reduction

1-32

fuel consumption over the same period of time. As noted above, if it is not known for a particular 

boiler, use 10 MMBtu/MWh.

10

NPHR HRF 

(1.6)

Where:

HRF = Heat rate factor

NPHR = net plant heat rate of the system to be costed, MMBtu/MWh

10 = in MMBtu/MWh, is the NPHR that is the basis of the SNCR base 

module capital cost.

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:

CFtotal = CFplant × CFSNCR (1.7)

Where:

CFtotal = total system capacity factor

CFplant = boiler capacity, which is the ratio of the actual quantity of fuel burned 

annually to the potential maximum quantity of fuel burned annually

CFSNCR, = SNCR system capacity factor, which is the ratio of the actual days of 

SNCR operation annually to the total number of days per year (i.e., 

365 days).

For industrial and utility 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:

fuel

fuel

plant maximum annual m

actualannual m

CF 

(1.8)

Where:

actual annual mfuel = annual actual fuel consumption rate of the boiler, lb

maximum annual mfuel = annual maximum fuel consumption rate of the boiler, lb
Chapter 1 – Selective Noncatalytic Reduction

1-33

SNCR can be operated year-round or only during the specified ozone season (usually 5 months in length). 

The capacity factor for the SNCR system, CFSNCR, is the ratio of the actual number of SNCR 

operating days, tSNCR, to the total number of days per year, 365 days:

365

SNCR

SNCR

t

CF 

(1.9)

Where:

tSNCR, = actual days of SNCR operation annually, days

365 = number of days in a year, days.

Uncontrolled NOx and Stack NOx

Uncontrolled NOx, represented as NOXin, is the NOx emission level in the flue gas exit

stream from a boiler prior to the SNCR system. Note that NOXin also accounts for combustion 

controls if the boiler is equipped with such controls. The uncontrolled NOx emission level, 

obtained from analyzing the boiler flue gas stream, is generally given in lb/MMBtu of NO2 [47].

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

outlet. It is generally set by regulatory limits and also given in lb/MMBtu of NO2.

NOx Removal Efficiency

The NOx removal efficiency, represented as ηNOx, 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:

in

in out

x

x

x x

NO NO

NO  NO

 

(1.10)

Where:

ηNOx = NOx removal efficiency, fraction

NOxin = uncontrolled NOx level from the boiler, i.e., inlet NOx rate to the 

SNCR, lb/MMBtu (at maximum heat input rate, CFplant = 1.0)

NOxin = outlet NOx rate from the SNCR, lb/MMBtu

NOx Removal Rates

The tons of NOx removed annually are:

NOx Removed/yr = NOxin NOx QB top/ 2,000 (1.11)

Where:

NOx Removed/yr = annual mass of NOx removed by the SNCR, tons/yr
Chapter 1 – Selective Noncatalytic Reduction

1-34

QB = maximum potential heat input rate of the boiler, MMBtu/hr

top = operating time per year (CFtotal x 8760), hr/yr

2000 = conversion factor for lb/ton.

The pounds of NOx removed per hour (lb/hr) are:

NOx Removed/hr = NOxin NOx QB (1.12)

Where: 

NOx Removed/hr = hourly mass of NOx removed by the SNCR, lb/hr

NOxin = uncontrolled NOx of the boiler, lb/MMBtu (at maximum heat input 

rate, CFplant = 1.0)

NOx = NOx removal efficiency of the SNCR, expressed as a fraction

QB = heat input rate, MMBtu/hr.

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 quantity due to reaction kinetics (see Section 1.2.3, Performance Parameters). NSR is 

defined as:

NOx moles of uncontrolled

moles of equivalent NH injected NSR 3



(1.13)

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

moles of equivalent NH3 in Equation 1.13 are the moles of NH2 that will be released from the 

reagent.

The actual stoichiometric ratio, ASR, is defined as:

NOx moles of uncontrolled

moles of reagent injected ASR 

(1.14)

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

SRT

NSR ASR 

(1.15)

Where SRT is the theoretical stoichiometric ratio, the ratio of equivalent moles of NH3 per mole 

of reagent injected. From the chemical formulas 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 
Chapter 1 – Selective Noncatalytic Reduction

1-35

ammonia slip. Utilization of reagent can be calculated from NSR and the NOx reduction 

efficiency as follows:

NSR

Utilization

 NO x



(1.16)

The derivation for this equation is presented in Reference [21].

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 [29]. This 

procedure was developed using linear regression and NSR data from References [47] and [48]. 

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

guarantee purposes.

The NSR estimation equation is valid from 0 to 50% NOx reduction [29]. The equation 

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

 

in

in x

x

X NO

NO

NO

NSR

[2  0.7]



(1.17)

Figure 1.10 provides a graphical representation of this NSR estimation method. Generally, the 

value of NSR ranges from 0.5 to 2.0 in industrial and utility boilers with utilization ranging from

25 to 50%.
Chapter 1 – Selective Noncatalytic Reduction

1-36

Figure 1.10: Approximate NSR Estimation for Urea [29]

In a design developed by a system supplier, 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 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, NSR could decrease.

However, if the temperature window occurs in the convective section, 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. 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. In addition, ASM 

equipment may need to be installed as ammonia slip constraints become tighter.

Estimating Reagent Consumption and Tank Size

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

mreagent



expressed as lb/hr, can be calculated using:
Chapter 1 – Selective Noncatalytic Reduction

1-37

NO T

x B NO reagent

reagent M SR

NO Q NSR M

m

x

in x



   





 (1.18)

Where:

ṁreagent = mass flow rate, or consumption rate, of the reagent, lb/hr

Mreagent = the molecular weight of the reagent (60.06 grams per mole [g/mole] 

for urea, 17.03 g/mole for ammonia)

MNOx = the molecular weight of NO2 (46.01 g/mole).

In this equation, 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:

sol

reagent

sol C

m

m



 

(1.19)

Where:

ṁsol = mass flow rate of the aqueous reagent solution, lb/hr

Csol = the concentration of the aqueous reagent solution, by weight fraction.

The solution volume flow rate qsol, generally expressed as gallons per hour (gph), is given by:

  7.4805

sol

sol

sol

m

q





(1.20)

Where:

qsol = solution volume flow rate, gph

 sol = the density of the aqueous reagent solution, lb/ft3

7.4805 = conversion factor of 7.4805 gal/1 ft3

The density is 71.0 lb/ft3for 50% urea and 56 lb/ft3for 29% ammonia.

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

system requires to operate for a specified number of days. The volume stored onsite for the 

number of operating days, tstorage, is:

Voltan k  qsol t

storage 24

(1.21)

Where:

Voltank = total volume of aqueous solution stored in the tank(s), gallons (gal)
Chapter 1 – Selective Noncatalytic Reduction

1-38

tstorage = number of operating days the SNCR is required to operate between 

solution delivery, days

24 = conversion factor of 24 hr/1 day.

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

capacity factor is not included in Equation 1.21. A common onsite storage requirement is for 

14 days (or 1–3 weeks) of SNCR operation.

1.3.2 Design Parameters for Detailed/Performance Specifications 

Cost Estimates Based on Detailed Specifications

This subsection describes the information that must be assembled and furnished to a 

supplier to prepare design specifications, particularly the 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 [29]. 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;

 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) in the furnace or backpass;

 Locations of boiler furnace overfire air ports;

 Locations and sizes of boiler observation ports, temperature probe ports, soot blower 

openings, and other locations for potential new ports;

 Air preheater design and operational data, including soot blower data;

 Fuel data – proximate and ultimate analyses and HHV for primary and secondary fuels;

 Fuel firing rates at full and partial loads (e.g., 100%, 70%, and 30%);

 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 1400°F [760°C]) 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., LNB, gas recirculation). This should be specified for boiler operations 

at full load and selected partial loads;
Chapter 1 – Selective Noncatalytic Reduction

1-39

 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.

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 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 study-level cost estimates. To simplify the process, a 

performance specification approach may be used in the request for quotation. 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) [29].

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);

 Other emission limits as specified (or anticipated) in the permit;

 NSR proposed to achieve the required NOx reduction;

 Guaranteed and expected reagent consumption rate;

 Guaranteed and expected dilution air, steam, or water consumption rate;
Chapter 1 – Selective Noncatalytic Reduction

1-40

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

 Guaranteed and expected electrical power consumption.

1.4 Cost Analysis

The presence of different boiler configurations, fuel use, and various site-specific 

conditions produces variability in the cost and cost-effectiveness of SNCR. For utility boilers 

with capacity of 100 MW, the capital cost ranges from $35 to $44/kW, for 400 MW boilers the 

capital cost ranges from $9 to $13/kW, and for 700 MW boilers ranges from $4 to $7/kW [49].

6

For industrial boilers, cost data are provided in Table 1.3. For coal-fired industrial boilers of 100 

to 1,000 MMBtu/hr, the capital cost ranges from $2,600 to $5,300/MMBtu/hr, and for gas and 

oil-fired industrial boilers, ranges from $2,000 to $4,200/MMBtu/hr [15].

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 costing 

methodology was developed to estimate capital costs in 2012 dollars.

The capital cost equations are based on the EPA Clean Air Markets Division (CAMD) 

Integrated Planning Model [8]. In the costing method for SNCR from the IPM, the purchased 

equipment cost, the direct installation cost, and the indirect installation cost are estimated 

together. This methodology is somewhat different from the EPA Air Pollution Control Cost 

Manual methodology, which estimates equipment costs and installation costs separately.

The capital cost equations are applicable to utility boilers with full load capacities greater 

than or equal to (≥) 25 MW. The capital costs estimated by the equation represent typical costs 

for retrofits at existing boilers, however, these equations are appropriate for both new units and 

retrofit units [8]. The cost equations are sufficient for NOXout emission reductions of 25% for 

Pulverized Coal and 50% for Fluidized Bed [8]. The SNCR system design used for the cost 

estimate is a urea-based system. An ammonia-based system would have different storage, 

distribution, and injection equipment costs. Allowed ammonia slip for the SNCR system ranges 

from 2–10 ppm [29].

Capital cost equations are provided for coal-fired units. Capital cost equations are 

provided for fluidized bed (FB) boiler units and for other boiler types (i.e., non-FB boiler units 

such as cyclone, wall-fired, tangential-fired, etc.). In general, SNCR units for FB boilers are less 

expensive than for other boiler types. The cost equations are sufficient for NOXout emission 

levels as low as 0.08 lb/MMBtu for FB and 0.1 lb/MMBtu for nonFB [8]. 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 minimal; approximately 10–30% 

of the cost of SNCR applied to a new boiler [9].

 

6 Cost years for these data range from 2005 to 2007. 
Chapter 1 – Selective Noncatalytic Reduction

1-41

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 for the SNCR 

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

costs due to installation, costs for buildings and site preparation, offsite facilities, land, and 

working capital. In general, SNCR does not require buildings, site preparation, offsite facilities, 

land, or working capital. A more detailed discussion of capital costs can be found in Section 1, 

Chapter 2 of this Manual. The total project cost or TCI for the SNCR is based on the approach 

used by EPA CAMD in the Integrated Planning Model version 5.13 (IPM v5.13) [8], and this 

approach includes both the direct capital costs and the indirect capital costs for coal-fired utility 

boilers. Cost estimates are available for different size categories of coal-fired utility boilers. 

Costs for oil- and gas-fired utility boilers have also been included in this SNCR section. While 

the IPM v5.13 approach does not include capital cost equations for utility oil- and gas-fired units, 

it was assumed that the costs for utility oil- and gas-fired units are slightly less than costs for FB 

coal-fired units.7 For oil- and gas-fired units, the appropriate NPHR value for oil (average value 

of 11 MMBtu/MWh) and for natural gas (average 8.2 MMBtu/MWh) should be used. Cost 

estimates are available for different size categories utility oil- and gas-fired units.

In addition, costs for different size categories of industrial boilers8 have been included in 

this SNCR section. IPM v5.13 does not contain cost procedures for industrial boilers; however, 

based on analysis of data in Table 1.3, costs for industrial boilers (in the 100 MMBtu/hr to 1000 

MMBtu/hr range) appear to range between significantly less than costs for utility boilers to 

essentially the same as the cost for utility boilers. Thus, the procedure described in this document 

assumes the costs for industrial boilers are essentially the same as for utility boilers for the same 

design heat input. On average, this costing approach may result in a slight overestimate of costs 

for industrial boilers.

The SNCR costs are impacted by the unit’s elevation with respect to sea level. These cost 

calculations have been developed for SNCR systems located within 500 feet of sea level. For 

SNCR systems located at higher elevations, the base cost should be increased based on the ratio 

of the atmospheric pressure between sea level and the location of the system, i.e., atmospheric 

pressure at sea level divided by atmospheric pressure at elevation of unit. [8] ]. The elevation 

factor is calculated as follows:

PELEV

P

ELEVF 0

(1.22)

Where:

 ELEVF = elevation factor

 

7 When using the IPM v3 procedures, capital costs for non-fluidized bed coal-fired boilers were approximately 1.5 

times higher than the costs for oil- and gas-fired boilers. The procedure described here maintains approximately 

the same ratio.

8 By “industrial,” the reference is to industrial, commercial, and institutional (or ICI) boilers. 
Chapter 1 – Selective Noncatalytic Reduction

1-42

 P0 = atmospheric pressure at sea level, 14.7 pounds per square inch absolute 

(psia)

 PELEV = atmospheric pressure at elevation of the unit, psia (see Table1.7 for 

atmospheric pressures for various elevations).

Table 1.7 presents atmospheric pressures for elevations up to 6000 feet above sea level.

Table 1.7. Atmospheric Pressure at Different Elevations.

Elevation above sea 

level, ft

Atmospheric pressure, 

psia

0 14.7

500 14.4

1000 14.2

1500 13.9

2000 13.7

2500 13.4

3000 13.2

3500 12.9

4000 12.7

4500 12.5

5000 12.2

6000 11.8

1.4.1.1 Utility Boilers, Coal-fired Units

Utility, coal-fired units ≥25 MW. The capital cost equation for coal-fired units ≥25 MW 

is as follows:

  TCI  3 SNCRCost  APHCost  BOPCost 1.

(1.23)

Where:

TCI = total capital investment for a SNCR on a boiler, $

SNCRCost = cost of the SNCR, $

APHCost = air pre-heater cost, $

BOPCost = balance of plant costs, $.
Chapter 1 – Selective Noncatalytic Reduction

1-43

This TCI includes engineering and construction management costs, installation, labor adjustment

for the SNCR, and contractor profit and fees. The owner’s costs (for owner activities related to 

engineering, management, and procurement) and costs such as allowance for funds used during 

construction (AFUDC) are capital cost items that are not included in the EPA Control Cost 

Manual methodology and are inconsistent with the overnight cost method9 that is a basis for the 

Control Cost Manual methodology, and thus are not included in the TCI estimates in this section

or in other Control Cost Manual chapters.

SNCR costs, utility, coal-fired units ≥25 MW. The capital costs for the SNCR base unit 

includes costs for the injectors, blowers, distributive control system (DCS), and the reagent 

system [27]. The SNCR costs are calculated as follows:

SNCRCost BMW  HRF CoalF  BTF 0.4 2 220,000

(1.24)

Where:

SNCRCost = SNCR unit costs, $

220,000 = constant in the equation

BTF = boiler type factor (BTF=1 if non-FB boiler; BTF=0.75 for FB boiler)

BMW = boiler MW rating at full load capacity for the unit being costed, MW

HRF = heat rate factor

CoalF = coal factor (CoalF=1 if bituminous; CoalF=1.05 if PRB; CoalF=1.07 if 

Lignite)

The boiler type factor, BTF, is based on the type of boiler unit. Boiler types may be fluidized bed 

or non-fluidized bed. Non-FB units include cyclone, tangentially-fired, wall-fired boiler units. 

Fluidized bed units include circulating, bubbling, atmospheric, and pressurized units. The BTF is 

1 for non-FB boilers and is 0.75 for FB boilers. The CoalF is 1 for bituminous coal, is 1.05 for

powder river basin (PRB) coal, and is 1.07 for lignite coal.

Air Pre-Heater Modification costs, utility, coal-fired units ≥25 MW. Air pre-heater 

modification costs are included only where SO3 control is necessary. An air pre-heater

modification is necessary for the control of SO3 for boilers that burn bituminous coal where the 

SO2 content of the coal is 3 lb/MMBtu or greater. Such modifications can include the use of 

steels resistant to corrosion, sootblowers and nozzles specifically designed to minimize SO3

formation. If other coal types are used, then no air pre-heater modification is needed. The air 

pre-heater modification costs are calculated as follows:

APHCost BMW  HRF CoalF  AHF 0.7 8 69,000

(1.25)

 

9 The overnight cost estimation method presumes costs are incurred as if the project in question incurred no interest 

during construction, or was built “overnight.” Another description of this method is the present value cost that 

would have to be paid as a lump sum up front to completely pay for a construction project. For more information, 

see “Conducting Technical and Economic Evaluations – As Applied for the Process and Utility Industries,” 

Recommended Practice 16R-90, American Association of Cost Engineering International. April, 1991. 
Chapter 1 – Selective Noncatalytic Reduction

1-44

Where:

APHCost = Air pre-heater cost, $

69,000 = constant in the equation

AHF = air heater factor (AHF=1 if bituminous coal and SO2 ≥3 lb/MMBtu; if 

not true, AHF=0).

The AHF is 1 for bituminous coal and where the SO2 content of the coal is 3 lb/MMBtu or 

greater. If the boiler burns other coal types, then the AHF is 0 and this term drops out of the 

overall SNCRCost equation.

Balance of plant (BOP) costs, utility, coal-fired units ≥25 MW. The BOP costs include 

cost items such as ID and booster fans, new wet chimneys, siting, piping, ductwork, auxiliary 

power modifications, and other electrical and site upgrades that are typically necessary as part of 

the installation of the SNCR unit [27]. The BOP costs are calculated as follows:

BOPCost BMW  NOx

  BTF 0.3 3 0.1 2 320,000 Removed/hr

(1.26)

Where:

BOPCost = Balance of plant costs, $

320,000 = constant in the equation

NOx Removed/hr = hourly mass of NOx removed by the SNCR system, lb/hr.

1.4.1.2 Utility boilers, Oil- and gas-fired units

Utility, oil- and gas-fired units ≥25 MW. The capital cost equation for oil- and gas-fired

boilers ≥100 MW is based on the utility boiler equations for fluidized bed boilers. Because oil 

and natural gas are the fuel inputs and not coal, it is assumed that no modifications are needed 

for the air pre-heater. The capital cost equation for oil- and gas-fired units is as follows:

  TCI  3 SNCRCost  BOPCost 1.

(1.27)

Where:

TCI = total capital investment for a SNCR on a boiler, $

SNCRCost = cost of the SNCR, $

BOPCost = balance of plant costs, $.

This TCI includes engineering and construction management costs, installation, labor adjustment 

for the SNCR, and contractor profit and fees.

SNCR costs, utility oil- and gas-fired units ≥25 MW. The capital costs for the SNCR base 

unit includes costs for the injectors, blowers, distributive control system (DCS), and the reagent 

system [27]. The SNCR costs are calculated as follows:

 

0.4 2 SNCRCost

147,000 BMW  HRF

(1.28)
Chapter 1 – Selective Noncatalytic Reduction

1-45

Where:

SNCRCost = SNCR unit costs, $

147,000 = constant in the equation

BMW = boiler MW rating at full load capacity for the unit being costed, MW

HRF = heat rate factor

Balance of plant (BOP) costs, utility oil- and gas-fired units ≥25 MW. The BOP costs

include cost items such as ID and booster fans, new wet chimneys, siting, piping, ductwork, 

auxiliary power modifications, and other electrical and site upgrades that are typically necessary 

as part of the installation of the SNCR unit [27]. The BOP costs are calculated as follows:

   

0.3 3 0.1 2 BOP 213,000 B NO Removed / hr Cost

  MW 

x

(1.29)

Where:

BOPCost = Balance of plant costs, $

213,000 = constant in the equation

NOx Removed/hr = hourly mass of NOx removed by the SNCR system, lb/hr.

1.4.1.3 Industrial Boilers, Coal-fired Units

Industrial, coal-fired units ≥250 MMBtu/hr. The capital cost equation for industrial coalfired boilers ≥1,000 MMBtu/hr is as follows:

  Cost APHCost BOPCost TCI 1.3 SNCR  

(1.30)

Where:

TCI = total capital investment for a SNCR on a boiler, $

SNCRCost = cost of the SNCR, $

APHCost = air pre-heater cost, $

BOPCost = balance of plant costs, $.

This TCI includes engineering and construction management costs, installation, labor adjustment 

for the SNCR, and contractor profit and fees.

SNCR costs, industrial, coal-fired units ≥250 MMBtu/hr. The capital costs for the SNCR 

base unit includes costs for the injectors, blowers, distributive control system (DCS), and the 

reagent system [27]. The SNCR costs are calculated as follows:

SNCRCost  QB  HRF CoalF  BTF 0.4 2 220,000 0.1

(1.31)

Where:
Chapter 1 – Selective Noncatalytic Reduction

1-46

SNCRCost = SNCR unit costs, $

220,000 = constant in the equation

QB = maximum heat rate input to the boiler, MMBtu/hr

HRF = heat rate factor

CoalF = coal factor (CoalF=1 if bituminous; CoalF=1.05 if PRB; CoalF=1.07 if 

Lignite)

BTF = boiler type factor (BTF=1 if non-FB boiler; BTF=0.75 for FB boiler).

The boiler type factor, BTF, is based on the type of boiler unit. Boiler types may be fluidized bed 

or non-fluidized bed. Non-FB units include cyclone, tangentially-fired, wall-fired boiler units. 

Fluidized bed units include circulating, bubbling, atmospheric, and pressurized units. The BTF is 

1 for non-FB boilers and is 0.75 for FB boilers. The CoalF is 1 for bituminous coal, is 1.05 for

powder river basin (PRB) coal, and is 1.07 for lignite coal.

Air Pre-Heater Modification costs, industrial, coal-fired units ≥250 MMBtu/hr. Air preheater modification costs are included only where SO3 control is necessary. An air pre-heater 

modification is necessary for the control of SO3 for boilers that burn bituminous coal where the 

SO2 content of the coal is 3 lb/MMBtu or greater. If other coal types are used, then no air preheater modification is needed. The air pre-heater modification costs are calculated as follows:

APHCost  QB  HRF CoalF  AHF 0.7 8 69,000 0.1

(1.32)

Where:

APHCost = Air pre-heater cost, $

69,000 = constant in the equation

AHF = air heater factor (AHF=1 if bituminous coal and SO2 ≥3 lb/MMBtu; if 

not true, AHF=0).

The AHF is 1 for bituminous coal and where the SO2 content of the coal is 3 lb/MMBtu or 

greater. If the boiler burns other coal types, then the AHF is 0 and this term drops out of the 

overall SNCRCost equation.

Balance of plant (BOP) costs, industrial, coal-fired units ≥250 MMBtu/hr. The BOP costs

include cost items such as ID and booster fans, new wet chimneys, siting, piping, ductwork, 

auxiliary power modifications, and other electrical and site upgrades that are typically necessary 

as part of the installation of the SNCR unit [27]. The BOP costs are calculated as follows:

BOPCost  QB

 NOx  BTF 0.3 3 0.1 2 320,000 0.1 Removed/hr

(1.33)

Where:

BOPCost = Balance of plant costs, $

320,000 = constant in the equation

NOx Removed/hr = hourly mass of NOx removed by the SNCR system, lb/hr.
Chapter 1 – Selective Noncatalytic Reduction

1-47

1.4.1.4 Industrial Boilers, Oil- and Gas-fired Units 

Industrial, oil- and gas-fired units ≥250 MMBtu/hr. The capital cost equation for 

industrial oil- and gas-fired boilers ≥1,000 MMBtu/hr is based on the utility boiler equations. 

The capital cost equation for oil- and gas-fired units is as follows:

  Cost BOPCost TCI 1.3 SNCR 

(1.34)

Where:

TCI = total capital investment for a SNCR on a boiler, $

SNCRCost = cost of the SNCR, $

BPCost = balance of plant costs, $.

This TCI includes engineering and construction management costs, installation, labor adjustment 

for the SNCR, and contractor profit and fees.

SNCR costs, industrial, oil- and gas-fired units ≥250 MMBtu/hr. The capital costs for the 

SNCR base unit includes costs for the injectors, blowers, distributive control system (DCS), and 

the reagent system [27]. The SNCR costs are calculated as follows:

0.4 2

147,000 











   HRF

NPHR

Q

SNCR B

Cost

(1.35)

Where:

SNCRCost = SNCR unit costs, $

147,000 = constant in the equation

QB = maximum heat rate input to the boiler, MMBtu/hr

NPHR = net plant heat rate, MMBtu/MWh (use 11 for oil-fired units and 8.2 for 

gas-fired units, if actual values are not available)

HRF = heat rate factor.

 

Balance of plant (BOP) costs, industrial, oil- and gas-fired units ≥250 MMBtu/hr. The 

BOP costs include cost items such as ID and booster fans, new wet chimneys, siting, piping, 

ductwork, auxiliary power modifications, and other electrical and site upgrades that are typically 

necessary as part of the installation of the SNCR unit [27]. The BOP costs are calculated as 

follows:

 

0.1 2

0.3 3

213,000 Removed/hr x

B

Cost NO

NPHR

Q

BOP  











 

(1.36)
Chapter 1 – Selective Noncatalytic Reduction

1-48

Where:

BPC = Balance of plant, $

213,000 = constant in the equation

NOx Removed/hr = hourly mass of NOx removed by the SNCR system, lb/hr.

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 processed by 

the control system. Indirect (fixed) annual costs are independent 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 [21]. Each of 

these costs is discussed in the sections below. A more detailed discussion of annual costs can be 

found in Section 1, Chapter 2 of this Cost 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). These costs are 

discussed individually below.





































































































































Cost

Ash

Annual

Cost

Coal

Annual

Cost

Water

Annual

Cost

Electricit y

Annual

Cost

Reagent

Annual

Cost

Maintenance

Annual

DAC

(1.37)

Operating and Supervisory Labor

In general, no additional personnel are required to operate or maintain the SNCR equipment 

for large industrial facilities. Therefore, the cost of operating or supervisory labor is assumed to 

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 TCI in dollars. This is a fairly standard percentage for 

maintenance on control devices, but for SNCR it may be conservative (i.e., overstate the cost) 

because one study indicates that a lower percentage is reasonable [8]. The equation for annual 

maintenance cost in $/hr, AMC, is given by:
Chapter 1 – Selective Noncatalytic Reduction

1-49

Annual maintenance cost = 0.015 × TCI (1.38)

Reagent Consumption

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

volume flow rate in gallons per hour (gph,) qsol ,and the total operating time, top, in hours, and 

Costreag is the cost of reagent in dollars per gallon ($/gal):

Annual reagent cost = qsol × Costreag× top (1.39)

The operating time per year, top, is estimated using the capacity factor, CFtotal

:

yr

hr

t CF 8,760 op total 

(1.40)

For pelletized urea or anhydrous ammonia, the 

m



reagent calculation would need to be 

adjusted according to the cost of the reagent and Equation 1.18 above; however, since these are 

not the least costly reagent choices, these costs are not addressed here.

Utilities

The electrical power consumption, P, 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 [29]. It is based on a linear regression of electrical power 

consumption data correlated to the uncontrolled NOx emission level in lb/MMBtu, NOXin, the NSR 

and the boiler heat input in MMBtu/hr, QB:

NPHR

NO NSR Q

P



xin

  B



0.47

(1.41)

Where:

P = electrical power consumption of the SNCR, kW

0.47 = constant in the equation

NPHR = net plant heat rate, MMBtu/MWh

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

from the following equation:

Annual electricity cost =P × Costelect × top (1.42)

Where:

Costelect = cost of electricity in dollars per kWh ($/kWh).
Chapter 1 – Selective Noncatalytic Reduction

1-50

Water Consumption

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

mass flow rate in lb/hr and 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, qwater, in gallons per 

hour (gph) is:

















 1

inj urea sol

stored urea sol

water

sol

water C

m C

q





(1.43)

Where:

qwater = flowrate of water necessary for diluting the reagent solution, gph

water = the density of water, 8.345 lb/gal.

Curea sol stored = concentration of the aqueous solution as stored, weight fraction

Curea sol inj. = concentration of the aqueous solution as injected, weight fraction

For urea dilution from a 50% solution to a 10% solution, Equation 1.43 becomes:

water

sol

water

m

q



4 



(1.44)

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 = qwater × Cost water × top (1.45)

where Costwater is the cost of water in dollars per gallon ($/gal) and top is given by equation 1.40.

Additional Fuel to Vaporize Water in Reagent Solution

The additional fuel 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:

















    1

1

inj urea sol

reagent C

Fuel Hv m (1.46)

Where:

ΔFuel = fuel required to evaporate the injected solution water, Btu/hr

HV = the heat of vaporization of water, Btu/lb
Chapter 1 – Selective Noncatalytic Reduction

1-51

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

m



reagent is the 

mass flowrate in lb/hr. The approximate HV at 310°F (150°C) is 900 BTU/lb, 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 1500°F [820°C]), 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 Btu/lb, Equation 1.46

in MMBtu per hour becomes:













 











 











 













MMBtu

Btu

hr

lb

m

lb

Btu

hr

MMBtu Fuel

reagent

6

10

900  9

(1.47)

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

is:

Annual ∆Fuel cost = ∆Fuel × Costfuel × top (1.48)

Where:

Annual ∆Fuel cost = annual cost of the fuel required to evaporate the water in the injected 

aqueous solution, $

Costfuel = the cost of fuel, $/MMBtu

Coal Ash Disposal

For a coal-fired boiler, additional ash is generated from burning the additional coal to 

vaporize water in the reagent solution. This ash must be disposed of or sold as byproduct. This 

cost methodology assumes that the ash is disposed of. The estimated additional ash to be 

disposed of in lb/hr is given by:

6

10   

HHV

Fuel ash product Ash

(1.49)

Where:

ΔAsh = mass of ash product that is generated and must be disposed, lb/hr
Chapter 1 – Selective Noncatalytic Reduction

1-52

ash product = the fraction of ash produced from the coal burned

106 = conversion factor of 106 Btu/1 MMBtu.

The ash product is the fraction of ash produced as a byproduct of burning a given type of coal. 

The HHV is given in Table 1.6.

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

Annual ∆Ash cost = ∆Ash × Costash× top x (1 / 2000) (1.50)

Where:

Annual ΔAsh cost = annual cost to dispose of the ash generated, $

Costash = the cost of ash disposal, $/ton. 

2000 = conversion factor of 2,000 lb/ 1 ton.

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. As mentioned earlier in 

this chapter, SNCR control systems began to be installed in Japan the late 1980’s. Based on data 

EPA collected from electric utility manufacturers, at least 11 of approximately 190 SNCR 

systems on utility boilers in the U.S. were installed before January 1993 [7]. In responses to 

another ICR, 3 petroleum refiners estimated SNCR life at between 15 and 25 years [3]. Thus, an 

equipment lifetime of 20 years is assumed for the SNCR system in this analysis. (The remaining 

life of the controlled unit may also be a determining factor).

10

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 [50]. The cost of 

overhead for an SNCR system is also considered to be zero. An SNCR 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 cents per thousand dollars annually [50]. 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, consist of both administrative 

charges and capital recovery, which can be expressed as:

IDAC = AC + CR (1.51)

 

10 Equipment lifetime is defined in the Control Cost Manual as design or operational life for control equipment. For 

more detail on the definition, please refer to Section 1, Chapter 2 of the Control Cost Manual (Control Cost 

Methodology). 
Chapter 1 – Selective Noncatalytic Reduction

1-53

where AC represents the administrative charges and CT represents the capital recovery cost. 

Administrative charges may be calculated as:

AC = 0.03 × Annual maintenance cost (1.52)

Capital recovery is estimated as:

CR = CRF × TCI (1.53)

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

Capital recovery factor was defined in Section 1 as:

(1 ) 1

(1 )

 





n

n

i

i i

CRF

(1.54)

where i is the assumed interest rate and n is the equipment 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 = DAC + IDAC (1.55)

Cost Effectiveness

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

NO Removed yr

TAC Cost Effectiven ess

x

/



(1.56)

Where:

Cost Effectiveness = the cost effectiveness, $/ton

NOx Removed/yr = annual mass of NOx removed by the SNCR, ton/yr

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 

120 MW, wall-fired, utility boiler firing bituminous coal. The following assumptions are made to 

perform the calculations:

Fuel High Heating Value, HHV 12,000 Btu/lb

Maximum Fuel Consumption Rate, ṁfuel 1.0 × 105lb/hr

Heat Rate, NPHR 10.0 MMBtu/MWh

Average Annual Fuel Consumption, actual ṁfuel 4.38 × 108lb
Chapter 1 – Selective Noncatalytic Reduction

1-54

Number of SNCR operating days, tSNCR 155 days

Plant Elevation, PELEV <500 feet 

Uncontrolled NOx Emission Level, NOXin 0.46 lb/MMBtu

Required Controlled NOx Emission Level, NOXout 0.30 lb/MMBtu

Percent Fuel Ash Weight, ash product 7.5%

Stored Urea Concentration, Curea sol stored 50% urea solution

Injected Urea Concentration, Curea sol inj 10% urea solution

Number of Days of Storage for Urea, tstorage 14 days

In addition to these assumptions, the estimated economic factors for the cost calculations are:

Cost Year 2012

Equipment Life 20 years

Annual Interest Rate 7%

Coal Cost, Bituminous11 [51] 2.30 $/MMBtu

Ash Disposal Cost [52, 53, 54, 55] 15 $/ton

50% Urea Solution Cost [vendor quotes] 1.62 $/gal

Water Consumption Cost 0.0065 $/gal12

Electricity Cost [55] 0.067 $/kwh

1.5.1 Design Parameter Example13

The boiler annual heat input rate, QB,is calculated from the HHV for bituminous coal 

given in Table 1.6 and the maximum fuel consumption rate, 

mfuel



using Equation 1.3:

hr

MMBtu 1,200

MMBtu

Btu 10

hr

lb 100,000

lb

Btu 12,000

Q

6

B 





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

using Equation 1.8:

 

11 This value represents the 2011 Bituminous coal price scaled to 2012 dollars using the CE Plant Index.

12 The water rate is based on industrial water rates for users with greater than 15,000 gal monthly usage who 

purchase water from a municipality. Industrial users that have their own water source or supply with likely have 

lower water rates [57]. 

13 Note: Results of all parameter calculations are shown rounded to an acceptable number of significant figures. 

However, the full, unrounded value is used in subsequent parameter and cost calculations that use the parameter 

as an input. Thus, the results shown for subsequent calculations often differ from what would be calculated using 

the shown rounded inputs. The use of extra significant figures in the subsequent calculations does not imply 

greater accuracy of the numbers. 
Chapter 1 – Selective Noncatalytic Reduction

1-55 0.5 50%

1 10 8,760

4.38 10

5

8

 



































yr

hr

hr

lb

lb CFplant

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

assumed to be only for the ozone season (5 months in this example), using Equation 1.9:

0.42 42%

365

155

  

days

days CFSNCR

The total capacity factor including both plant and SNCR capacity factors is calculated using 

Equation 1.7:

CFtotal = 0.5× 0.42 = 0.21 = 21%

The total operating time per year of the SNCR is calculated using Equation 1.40:

yr

hr

yr

hr

t

o p

 0.218,760 1,860

The NOx removal efficiency, NOx, is calculated from the inlet NOx emission level and the

required stack NOx emission level using Equation 1.10:

0.35 35%

0.46

0.46 0.30

 





MMBtu

lb

MMBtu

lb

MMBtu

lb

N Ox



−

The NOx removed per hour (lb/hr) is calculated from the inlet NOx emission level, the NOx

removal efficiency, and the maximum heat rate to the boiler using Equation 1.12:

hr

lb

lb

MMBtu

MMBtu

lb NO moved hr x Re /  0.46 0.351,200 192

The equation derived in Reference [29] is used to estimate NSR for the SNCR system. The 

estimate is given by using Equation 1.13:

1.22

0.46

2 0.46 0.7 0.35















 















MMBtu

lb

MMBtu

lb

NSR

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

NSR value using Equation 1.16:
Chapter 1 – Selective Noncatalytic Reduction

1-56 0.28 28%

1.22

0.35 Utilization   

The value of the NSR indicates that 1.22 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 1.22, the reagent 

mass flow rate is given by Equation 1.18:

hr

lb

mole

g

mole

g

hr

MMBtu

MMBtu

lb

mreagent 154

2 46.01

0.46 1,200 0.35 1.22 60.06





   

 

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

urea, is given by Equation 1.19:

hr

hr lb

lb

msol 307

0.50

154

  

The solution volume flow rate can then be calculated using Equation 1.20where  is the density 

of the aqueous reagent solution, 71.0 lb/ft3for 50% aqueous urea solution at 60° F:

32.3 / ( )

71.0

307 7.481

3

3

gallons hr gph

ft

lb

ft

gal

hr

lb

qsol 





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 onsite storage requirement is given by Equation 

1.21:

gal

day

hr V gph days k

10,900 24 32.3 14 tan   

The onsite storage requirement for urea is 10,900 gallons per 14 days. This shows that for 

the example boiler (1,200 MMBtu/hr design, 50% actual loading, and 35% NOx removal efficiency),

the volume of urea solution required to operate an SNCR system for 155 days during the ozone 

season is approximately 60,000 gallons.
Chapter 1 – Selective Noncatalytic Reduction

1-57

An estimate for power consumption is given by Equation 1.41:

hr k W

MMBtu

MMBtu

lb

P 31.8

10

0.47 0.46 1.22 1,200



  



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

injected, is calculated using Equation 1.43:

gph

gal

lb

hr

lb

qwater 1 147

0.10

0.5

8.345

307

 











  

The estimated additional coal consumption and ash disposal required to maintain the 

same net heat output are given by Equations 1.47 and 1.49, respectively:

hr

MMBtu

MMBtu

Btu

lb

Btu

hr

lb

Fuel 1 1.24

0.10

1

10

154 900

6

 











 



 

hr

lb

lb

Btu

MMBtu

Btu

hr

MMBtu

Ash 7.77

12,000

1.24 0.075 106



 

 

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 total capital investment costs are estimated using Equation 1.23:

TCI SNCR APHC BPC 1.3 Cost  

The SNCR capital costs are estimated using Equation 1.23:

SNCRCost BMW  HRF CoalF  BTF 0.4 2 220,000 220,000 120 1 1 1 $1,643,156 0.4 2 SNCRCost

     

The sulfur content is assumed to be low enough that the SO2 emission rate is less than 3 

lb/MMBtu; thus, as described in the discussion accompanying Equation 1.25, no air preheater 

modifications are needed:
Chapter 1 – Selective Noncatalytic Reduction

1-58 APHCost

 BMW  HRF CoalF  AHF 0.7 8 69,00069,000 120 1 1 0 0

0.7 8 APHCost

     

The BPC can be calculated using Equation 1.26:

BOPCost BMW  NOx

  BTF 0.3 3 0.1 2 320,000 Removed/hr 320,000 120 192 1 $2,919,281 0.3 3 0.1 2 BOPCost

    

The total capital investment can be calculated using the values above: 

  Cost APHCost BOPCost TCI 1.3 SNCR  

TCI 1.3$1,643,156  0  $2,919,281  $5,931,168

The SNCR system is assumed to operate for 5 months of the year with a boiler loading of 

50%, resulting in a total capacity factor of 21%. The annual variable costs are given by

Equations 1.38, 1.39, 1.42, 1.45, 1.48 and 1.50, respectively:

Annual maintenance cost = 

yr

$88,968 0.015$5,931,168 

yr yr

hr

gal

$

Annual reagent cost 32.3 gph 1.62 $97,466 1,860 











  

yr yr

hr

k W

$

Annual electricit y cost 31.8 k W 0.067 $3,960 1,860 











 

yr yr

hr

gal

$

Annual water cost 147gph 0.0065 $1,771 1,860 











  

yr yr

hr

hr MMBtu

MMBtu Annual Fuel $5,323 1,860 $

cost 1.24 2.30 











   

yr

ton

lb

yr

hr

hr ton

lb

Annual Ash cost

$108

2,000

1,860 $7.77 15















 

 
Chapter 1 – Selective Noncatalytic Reduction

1-59

The total direct annual cost (DAC), the sum of the cost of the maintenance, reagent, electricity, 

water, coal and ash disposal, is given by the sum of the annual costs, using Equation 1.37:

yr yr yr yr yr yr yr

DirectAnnualCost $88,968 $97,466 $3,960 $1,771 $5,323 $108 $197,597      

As discussed in section 1.4.2, property taxes and overhead are both assumed to be zero, 

and insurance costs are assumed to be negligible. Thus, administrative charges and capital 

recovery are the only components of indirect annual costs estimated in this analysis. 

Administrative charges are calculated using equation 1.52 as:

AC = 0.03 × 88,968 = $2,669/yr

The capital recovery factor, CRF, is defined in Equation 1.54 as:

0.0944

(1 0.07) 1

0.07 (1 0.07)

2 0

2 0



 



CRF 

and the capital recovery is calculated using Equation 1.53 as:

CR = 0.0944 × $5,931,168 = $559,860/yr

The total indirect annual costs (IDAC) are calculated in Equation 1.51:

yr

IDAC $562,529 $2,669 $559,860 

The total annual cost is the sum of the direct annual and indirect annual costs given in Equation 

1.55:

yr yr yr

TAC $197,597 $562,529 $760,126  

The total amount of NOx removed can be calculated using Equation 1.11:

yr

tons

ton

lb

yr

hr

hr

MMBtu

MMBtu

lb

NO Removed yr x 179

2,000

0.46 0.35 1,200 1,860

/ 













  



And the annual cost in terms of NOx removed, or cost effectiveness, is calculated using Equation 

1.56:

tons ton

Annual Cost Effectiven ess

$4,260

179

$760,126

 
Chapter 1 – Selective Noncatalytic Reduction

1-60
Chapter 1 – Selective Noncatalytic Reduction

1-61

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