Optimizing Selective Non-Catalytic Reduction Systems for CostEffective Operation on Coal-Fired Electric Utility Boilers

by 

James E. Staudt, Ph.D. 

Andover Technology Partners

Keith Kehrer 

John Poczynec 

Delmarva Power

Roland Cote 

Robert Pierce 

Montaup Electric

Rui Afonso 

Allen Sload 

David Miles 

New England Power

Abstract 

Selective Non-Catalytic Reduction (SNCR) systems have been used to reduce NOx 

emissions from coal fired electric utility boilers. Experience has shown that the primary 

cost of reducing NOx with SNCR technology most often is the cost of reagent. It is 

therefore desirable to reduce the reagent cost to the lowest possible amount while not 

adversely impacting other aspects of plant operation. Adverse effects that need to be 

considered in any comprehensive evaluation include impacts on fuel cost as well as 

impacts of such things as ammonia slip. And, while the parameters that impact 

performance of an SNCR system are common among boilers, the behavior of these 

parameters will vary widely between units. Hence, the operators of plants using SNCR 

for reduction of NOx will frequently find different operating strategies most effective in 

minimizing the total operating cost associated with reducing NOx. 

This paper will discuss the operating experience and results of optimization programs at 

three different coal fired electric utility boilers, each one having different circumstances 

and each one using a different approach to minimizing the cost of NOx reduction while 

using SNCR. New England Power utilized advanced instrumentation and controls with 

changes to soot blower operation to reduce consumption of reagent by over 50% while 

minimizing adverse impact to heat rate and reducing ammonia slip. Montaup Electric 

carefully modified its furnace operations to reduce its reagent consumption by over 50% 

while maintaining design heat rate. Delmarva Power reduced its reagent consumption 

through modification of furnace operating settings and cofiring of natural gas under some

conditions, with a minimal impact to heat rate. This paper will discuss the approaches 

used at these facilities and will present operating data from the programs. 

Presented at ICAC Forum ’98, Raleigh-Durham, NC, March 18-20, 1998 

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Introduction 

Selective Non-Catalytic Reduction is a technology that is being used at sixteen electric 

utility boilers to reduce NOx emissions. It is expected to play a significant role in future 

U.S. electric utility NOx reduction programs. As with all control technologies, 

deployment and operation of SNCR will incur a cost. Capital cost is generally low 

compared to other techO$gies; however, the cost of reducing NOx through SNCR is 

driven primarily by variable operating costs - generally dominated by the cost of reagent. 

Hence, it is normally in the operator’s best interest to minimize the reagent consumption 

and any other costs associated with operating the SNCR system. 

Suppliers of SNCR technology generally provide systems designed to meet the 

guaranteed performance at the conditions where the operator historically runs the unit. 

Due to a shortage of time and information, the SNCR vendor generally cannot anticipate 

operating changes to the facility that may benefit the operator when using SNCR 

technology. Frequently, after the operators have gained some experience with the SNCR 

system they will discover improved methods of operating the unit. 

This paper will highlight successful SNCR optimization programs at three facilities 

equipped with urea-based SNCR, commonly referred to as NOxOUT. All three facilities 

are equipped with NOxOUT systems that were meeting or exceeding the expected system

performance prior to the optimization. In each case, after having some experience with 

the NOxOUT system on their unit, the facility operators identified methods of reducing 

the overall cost of reducing NOx while operating the NOxOUT system. In most cases, 

the operating adjustments discussed here would not have been considered were it not for 

the existence of the NOxOUT system at their facilities. The three facilities have three 

uniquely different situations that cause different approaches to be appropriate. 

 

Operating Cost - Discussion 

When reducing NOx through combustion controls, reburning, fuel switching, SNCR or 

another NOx control method, the facility's operating costs may be increased in several 

ways. Efforts to reduce any single operating cost component could favorably or 

unfavorably impact the other operating cost parameters. A detailed cost evaluation of 

NOx reduction technologies should include consideration of all of the effects so that 

trade-offs can be assessed and the system operation potentially optimized for lower 

overall cost operation. 

SNCR reagent consumption is driven primarily by the baseline NOx level, the controlled 

NOx level, the gas flowrate (boiler size), the furnace temperature and the effectiveness in 

distributing the reagent. The last two parameters - temperature and distribution - strongly 

influence chemical utilization, a measure of the efficiency of the urea in reducing NOx. 

The outlet NOx and the boiler size are either imposed requirements or fixed parameters. 

The operator does have the ability, however, to impact the baseline NOx, the temperature 

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of the SNCR reaction and the effectiveness in distributing the reagent. To the extent that 

the operator can manipulate these variables to reduce the amount of SNCR reagent that is 

consumed, the impact that these variables have on the plant operating costs need to be 

included when considering the cost of reducing NOx. 

Hence, when adjusting plant parameters in an effort to reduce overall NOx reduction 

costs, it is essential to capture all of the cost impacts so that the trade offs can be fully 

understood. The cost components that should be considered include the following: 

• The direct cost of operating the urea SNCR system, estimated to be equal to roughly 

$1.00 per gallon of NOxOUT reagent consumed. NOxOUT reagent, an SNCR 

reagent that is a 50% (by weight) aqueous urea solution with other additives, usually 

costs a little under $1.00 per gallon. However, $1.00/gallon was used in this analysis 

to generate the information presented in this report in order to make the math easy 

and cover the costs associated with other requirements for operating the system such 

as plant service air, electric power, maintenance, etc. 

• If, for the purpose of enhancing NOx reduction system performance, the furnace is 

operated at conditions where steam temperatures are not optimal, Heat Rate will be 

poorer. The additional cost of operating the unit at a particular load will be referred 

to as the Heat Rate Penalty. The operator can alter steam temperature by adjusting 

burner tilts, soot blowing or other means. The Heat Rate Penalty is specific to the 

boiler and is typically a function of superheat and reheat steam temperatures. 

• When a premium fuel, such as natural gas, is substituted for the primary fuel in order 

to reduce combustion NOx and urea consumption, the additional cost of this premium

fuel should be considered and balanced against the savings from reduced urea 

consumption. The Fuel Premium is determined by multiplying the cost difference 

between gas and coal in ($/MMBTU) times the heat input of the gas. 

• If the boiler is capacity limited as a result of operation of the NOx reduction system, 

the value of lost MW-hr incurred should be included in the costs. In most cases, a 

reduction in capacity is not necessary. But, a reduction may be necessary for some

facilities. The value of lost megawatt hours is determined by multiplying the lost MW

by the value of a MWhr for that day and time. It is important to recognize that during 

the summer months there are often high-demand days when the value of lost capacity 

could be very costly. For the purpose this analysis, capacity reduction was not 

considered as a means to optimize NOx reduction system operation. 

The aforementioned costs do not include the heat rate penalty that is associated with 

evaporation of water carrier or incomplete combustion as indicated by LOI. These are 

costs that have been considered by previous investigators and are acknowledged but not 

investigated in this paper. 

Costs that should be evaluated in a more comprehensive analysis include additional 

maintenance that might be associated with some of the operating conditions evaluated in 

these programs. 

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Effects of Process Variables

 

Baseline NOx level

To reduce chemical consumption it is generally most effective to first pursue a strategy of 

minimizing the NOx produced by the combustion of fuel, thereby reducing the amount of 

NOx that must be reduced. This can be done through some modification of the primary 

combustion process, changing of fuel to natural gas, or though the use of reburning prior 

to the SNCR system. However, once baseline NOx has been reduced, it is possible to 

make other process adjustments that can significantly improve the SNCR process 

economics. The adjustments generally focus on improving reagent utilization. 

Reagent Utilization

Reagent utilization is a measure of the effectiveness of the reagent in reducing NOx. It is 

the objective of the SNCR user to maximize utilization to minimize the cost of reagent. 

Utilization is mathematically equal to the percent reduction divided by the Normalized 

Stoichiometric Ratio (NSR, the stoichiometric ratio of reducing reagent to NOx, 

normalized with the balanced chemical equation). If the utilization is 50%, for example, 

then that means twice as much urea is being used as that predicted by a balanced 

chemical equation of the SNCR reaction for urea. Utilization is very strongly affected by 

initial NOx, controlled NOx, furnace temperature, ability to distribute the reagent, and 

the concentration of other species, such as CO and O2. In commercial SNCR systems, 

utilization is typically between 20% and 60%. 

For example, Figure 1 shows % NOx reduction and % utilization plotted against NSR for 

an SNCR system. NOx reduction will increase with NSR. However, the slope of the 

curve becomes shallow with increasing treatment rates, indicating that further NOx 

reductions are only possible with much higher treatment rates. This is also reflected in 

the utilization, which drops rapidly at first and then drops less rapidly to near 20%. 

Effects of Temperature on Utilization - It is well established that SNCR has a reasonably 

narrow temperature window in which to properly react the reagent. If the temperature is 

too high, poor NOx reduction and poor chemical utilization will result. If the 

temperature is too low, high ammonia slip will result. In the region where operation is 

best, operators will balance improved reduction or utilization against the risk of high 

ammonia slip (see Figure 2). Since a high furnace temperature generally means low 

utilization and low utilization means high chemical consumption, it is desirable to inject 

urea at the lowest possible temperature without incurring high ammonia slip levels. 

Figure 3 shows the relationship between utilization and Furnace Exit Gas Temperature 

(FEGT) at one facility tested under conditions where the process was being pressed for 

very high reductions. Chemical utilization was near 20% at the time and FEGT was 

adjusted to determine sensitivity of utilization to temperature. The relationship is very 

clear. In this case, a 20°F drop in FEGT resulted in nearly a 4% improvement in 

utilization. This relationship may be more or less pronounced for any particular facility. 

In some boilers, it may be desirable to operate the boiler under conditions where steam

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temperatures may be less than optimal for good heat rate because the value of the 

improved reagent consumption will more than compensate for the additional fuel cost. 

Injector Optimization - Distribution of urea plays a critical role in chemical utilization. 

Injector type and location are critical design decisions when a vendor engineers an SNCR 

system. SNCR technology vendors normally perform computer simulation with 

computational fluid dynamic modeling to select injector locations and type. The 

modeling is normally performed in conjunction with a test program where furnace 

temperature and gas species measurements are taken. Once installed, these injectors 

must be adjusted to ensure that atomization and distribution are optimal. Annual 

adjustment of the injectors with more frequent checking of injector set points is 

recommended for best performance. Figure 4 shows the results of injector optimization 

of a NOxOUT system that had been installed and operated intermittently for about 18 

months. The system had been optimized 12 months earlier. The NOx and flowrate values 

on Figure 4 are five-minute rolling averages. While maintaining the boiler conditions and 

SNCR injection steady, the liquid flowrate and atomization air setpoints were adjusted on 

the distribution modules. The objective during injector optimization is to improve NOx 

reduction and ammonia slip solely by improving reagent distribution through adjustment 

of atomization, injector orientation, or nozzle tip changes. Ammonia slip measurements 

were monitored continuously during these tests and there were no indications of high 

ammonia slip. As can be seen from Figure 4, an improvement in NOx of about 0.04 

lb/MMBTU was achieved simply through adjustments to nozzle atomization parameters. 

And, if we were to control at the original outlet NOx level, chemical consumption could 

be reduced. As a result of this work, new injector atomization set points were established 

at this facility. 

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Fig. 1. Red'n and Utilization vs. NSR

0%

10%

20%

30%

40%

50%

60%

70%

0 0.5 1 1.5 2 2.5

NSR

Red'n/Util.

% Red'n

Utilization

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Figure 2. Effect of Temperature on NOx Reduction and Ammonia Slip 

 1800F 

NOx 

REDUCTIO

N

NH3 SLIP 

HIGH NH3 SLIP 

LOW NOx REDUCTION

TEMPERATURE 

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Fig. 4. Urea Nozzle Optimization

0.00

0.10

0.20

0.30

0.40

0.50

0.60 20-Jun-97

08:20:00

20-Jun-97

08:30:00

20-Jun-97

08:40:00

20-Jun-97

08:50:00

20-Jun-97

09:00:00

20-Jun-97

09:10:00

20-Jun-97

09:20:00

20-Jun-97

09:30:00

NOx

urea flow/100

injector adjustment

5-minute rolling averages of NOx and urea flow

Fig. 4. Urea Nozzle Optimization

0.00

0.10

0.20

0.30

0.40

0.50

0.60 20-Jun-97

08:20:00

20-Jun-97

08:30:00

20-Jun-97

08:40:00

20-Jun-97

08:50:00

20-Jun-97

09:00:00

20-Jun-97

09:10:00

20-Jun-97

09:20:00

20-Jun-97

09:30:00

NOx

urea flow/100

injector adjustment

5-minute rolling averages of NOx and urea flow

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Fig. 3. Utilization vs. FEGT data

18.50%

19.00%

19.50%

20.00%

20.50%

21.00%

21.50%

22.00%

22.50%

23.00%

2160.0 2165.0 2170.0 2175.0 2180.0 2185.0

FEGT, deg F

Utilization, %

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Fig. 3. Utilization vs. FEGT data

18.50%

19.00%

19.50%

20.00%

20.50%

21.00%

21.50%

22.00%

22.50%

23.00%

2160.0 2165.0 2170.0 2175.0 2180.0 2185.0

FEGT, deg F

Utilization, %
9

Results of Optimization Programs 

 

Delmarva Power, Edge Moor #3 

Delmarva Power Company operates an 84 MWe (gross) tangentially-fired pulverized 

coal boiler (unit #3) at its Edge Moor generating station. The boiler is a natural 

circulation, single drum radiant boiler with a dry bottom. The furnace has four corners 

and four levels of tilting, tangentially fired coal buckets. The boiler can also fire oil or 

gas. Unit #3 operates on dispatch typically in a load following mode. 

In cooperation with the Delaware Natural Resource Environmental Control Agency, in 

1995 Delmarva voluntarily installed a NOxOUT urea-based Selective Non-Catalytic 

Reduction system to demonstrate this technology. Optimization during initial 

commissioning demonstrated that NOx could be maintained below 0.38 lb/MMBTU 

under all design operating conditions with low levels of ammonia slip and reagent 

consumption at expected design levels1

. The NOxOUT system has been operated 

intermittently during the Ozone Season since commissioning for the purpose of

demonstrating the operation of the system. Optimization of the furnace during the 

summer of 1996 demonstrated that NOxOUT reagent consumption could be improved 

from what was achieved during initial commissioning. However, Delmarva believed that 

further reductions in operating cost might be possible and another optimization program

was performed in the summer of 1997. 

Results of Optimization - 

In addition to injector optimization, during the Edge Moor #3 optimization program

several furnace firing conditions were evaluated against the conditions for original SNCR 

vendor optimization. The controlled NOx objective was 0.40 lb/MMBTU. Under the 

firing conditions that the SNCR was originally designed to operate at, the baseline NOx 

was 0.70 lb/MMBTU at full load (85 MWg) and 0.60 lb/MMBTU at mid load (65 MWg). 

The objective of modifying the firing conditions was to reduce baseline NOx while also 

considering the cost of impact on the plant heat rate. 

Under the varied firing conditions, data was collected to characterize the major cost 

components of operating the NOxOUT system at these different firing conditions. 

Full Load Testing - Figure 5 shows the operating cost breakdown of controlling NOx 

under different firing conditions expressed as a percentage of the total operating cost of 

controlling NOx at the baseline conditions for the SNCR system. Unfortunately, data on 

the heat rate penalty was not available for the baseline condition at 100% coal. 

Therefore, the total cost at the baseline condition might actually be higher. 

As shown, gas cofiring with vertical air staging in the primary combustion zone resulted 

in over 80% reduction in urea consumption with a moderate heat rate penalty. Also, the 

gas cofiring condition produces a substantial fuel premium cost that raises the total cost 

of controlling NOx with this firing condition to nearly the cost of the baseline urea cost. 

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During this test period it was not possible to operate at full load with 100% coal due to 

permit limitations. Therefore, testing the vertical air staging condition at 100% coal 

could not be performed. It is believed that this firing condition would produce a much 

more cost-effective method of operation than the baseline condition. For the same

reason, simulated Close-Coupled Over Fire Air (CCOFA) with 100% coal was not tested 

at this load. 

The furnace was also tested in a simulated close-coupled gas reburn mode (CCGR), 

which resulted in the lowest cost of any condition tested at this load. Coal mils B, C, and 

D were operating, gas was applied to the top gas burner, and air dampers were set for 

simulated CCOFA. Under this condition it was possible to achieve below 0.40 

lb/MMBTU without operating the SNCR system. A minimal heat rate penalty was 

experienced under this condition with a significant fuel premium. The fuel premium is 

based upon gas prices at the time of testing. The total operating cost of reducing NOx in 

this manner is just under 50% of the operating cost of the baseline SNCR. This condition 

shows that the operator can benefit from low gas prices when available by using gas to 

very effectively reduce the SNCR reagent cost. 

baseline

SNCR-orig.

vendor

optimization

gas cofiring,

air staging &

SNCR

CCGR

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

baseline

SNCR-orig.

vendor

optimization

gas cofiring,

air staging &

SNCR

CCGR

Fig. 5. Normalized Oper. Cost of Reducing NOx, Edge Moor #3, 85 

MW

Fuel Premium

HR Penalty

SNCR cost

Did not have heat rate data 

from original testing. Baseline 

SNCR costs might actually be 

higher with this included.

% of baseline cost

Mid Load Testing - Testing at 65 MW showed that simulated close-coupled over fire air 

(CCOFA) could be used to cut the urea consumption by 70%, as shown in Fig. 6. There 

is a modest heat rate penalty (~19% of baseline SNCR cost) so that, overall, operating 

cost of reducing NOx is cut by just over 50%. Testing of this condition at 85 MW was 

not possible due to operating limitations and due to fuel limitations discussed earlier. 

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baseline

SNCR-orig.

vendor

optimization

CCOFA &

SNCR

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

baseline

SNCR-orig.

vendor

optimization

CCOFA &

SNCR

Fig. 6. Normalized Oper. Costs of Reducing NOx, Edge Moor #3, 65 

MWg

Fuel Prem

HR Penalty

SNCR Cost

Did not have heat rate data 

from original testing. 

Original costs might

actually be higher with this

included.

% of baseline cost

Montaup Electric, Somerset Boiler #8 

Montaup Electric Company operates a 112 MWe tangentially-fired pulverized coal boiler 

(Boiler #8) at its Somerset, MA generating station. The boiler is a natural circulation, 

reheat, single drum radiant boiler with a dry bottom that is rated at 800,000 lbs/hr steam

flow at the superheater outlet at 1,975 psig and 1,000 F. The furnace has four corners 

and four levels of tilting, tangentially fired coal buckets. Between the four coal buckets 

in each corner are three oil guns. 

In 1994 and 1995, Boiler #8 operated on dispatch typically in a load following mode. 

During the day and during other high demand periods the boiler operated at or near full 

capacity. In the evening and on weekends the boiler was frequently reduced to 35% to 

55% MCR. In 1996, Boiler #8 has operated as a base loaded unit. 

In 1995 Montaup Electric installed a NOxOUT urea-based Selective Non-Catalytic 

Reduction system to reduce the NOx emissions to levels that comply with the 

Commonwealth of Massachusetts Reasonably Available Control Technology (RACT) 

regulations, which required NOx emissions from Boiler #8 to be controlled to below 0.38 

lb/MMBTU at all times. The system has successfully maintained NOx levels below 

required levels with low levels of ammonia slip. Experience with the operation is 

discussed in previous literature 2, 3. 

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Results of OptimizationDuring initial startup and during subsequent optimization, Montaup operators have 

always maintained an objective of not adversely impacting heat rate. Furthermore, 

adherence to the turbine manufacturer’s operating requirements regarding steam

temperature do not permit operating under conditions where heat rate can be adversely 

impacted in a significant way. This imposes a constraint on what can be done to 

optimize SNCR operations. Nevertheless, Montaup undertook an aggressive 

optimization program directed toward reducing their SNCR operating cost while not 

changing steam temperature. 

The fuel and furnace firing conditions of the Somerset #8 boiler are such that it is not 

necessary to operate furnace wall blowers. Occasional operation of soot blowers is 

necessary to maintain proper balance between turbine inlet and reheat steam

temperatures. Air in-leakage to the boiler is low. Moreover, Somerset #8 is equipped 

with an Automated Burner Management System (ABMS) and Distributed Control 

System (DCS). As a result of these features of the facility, Furnace Exit Gas Temperature 

(FEGT), furnace oxygen, baseline NOx, and other furnace conditions critical to SNCR 

performance can be maintained at a very consistent level. 

It was recognized that a reduction in NOx baseline would be beneficial to urea 

consumption. However, a reduction in baseline had to be achieved without capital 

expense and without adversely impacting steam temperatures. In order to reduce the 

NOx baseline, the furnace operation was modified for air staging with reduced oxygen to 

about 2.0-2.5% oxygen at the furnace exit. As expected, LOI and CO increased 

somewhat; however, they have been maintained within acceptable levels. To maintain 

steam temperatures, burner tilts were put in manual and raised. This raised the furnace 

slag level, and FEGT was raised to about 2,350°F immediately prior to the secondary 

superheater pendant. After a few weeks of manual control of burner tilts, the slag level 

increased sufficiently that the burner tilts could be put back in automatic. The facility has 

operated in this condition for over one year. It has maintained an uncontrolled full-load 

NOx baseline of about 0.45-0.49 lb/MMBTU as opposed to the original, uncontrolled, 

full-load baseline of 0.65 lb/MMBTU. 

Operation of the SNCR system to reduce emissions below 0.38 lb/MMBTU has 

substantially changed since implementing these changes to operation. First, injection at 

full load had previously been in zones 3 and 4 of this four-zone NOxOUT system. 

Current operation requires operation of only four of the zone 4 injectors at full load, 

which reduces the air and dilution water requirement by more than 60%. Recent 

characterization testing of this operating mode showed that FEGT is currently 2350 °F, 

approximately 150 °F higher than the FEGT under the original baseline SNCR 

conditions. Ammonia slip continues to be extremely low. The urea consumption has 

been reduced about 66% (see Figure 7), without an adverse impact to heat rate. 

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baseline

SNCR

with

optimized

furnace

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

baseline

SNCR

with

optimized

furnace

Fig. 7. Normalized Oper. Cost of reducing NOx, Montaup Electric, 

Somerset boiler #8

% of baseline cost

New England Electric, Salem Harbor #3

New England Power (NEP) operates four units at Salem Harbor. The three coal-fired 

units were the first commercial applications of SNCR on coal-fired utility units in the 

U.S. Salem Harbor #3 is a 150 MW, wall-fired dry-bottom boiler. It is equipped with 

urea SNCR (NOxOUT), Low NOx Burners (LNB) and Separated Over Fire Air (SOFA) 

for control of NOx to 0.30 lb/MMBTU. NEP installed the LNBs and SOFA after they 

installed the SNCR to SH #3. Prior to installation of the LNB’s and SOFA or NOxOUT, 

NOx emissions averaged 1.00 lb/MMBTU. The LNB’s and SOFA reduced NOx to the 

NOxOUT system from 1.00 to 0.43 lb/MMBTU. The site does not have natural gas. As 

a result, there are no additional options for further reducing NOx baseline to the SNCR 

system at SH #3. 

Unlike the previous two examples, the SH #3 furnace experiences significant slagging in 

the furnace with much FEGT variability. Furnace wall blowing was historically 

performed on a schedule for the purpose of controlling steam temperatures. Figure 8 

shows data taken over a six-hour period in 1994, prior to the recent optimization 

program. With this level of FEGT variability, and considering the general trends 

indicated on Figures 2 and 3, high chemical utilization with low ammonia slip would not 

be possible without a control system that could rapidly sense the changes in FEGT and 

adjust the injection rate and location accordingly. At the time the SNCR system was 

originally installed (1993), such a control system was not available. In order to avoid 

high ammonia slip conditions, the SNCR system was operated in a manner that produced 

lower reagent utilization than would be possible in a unit without the FEGT variability. 

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Fig. 8. Furnace Exit Gas Temperature (FEGT) at Salem Harbor over six hours4

. 

The SNCR system that was originally installed at Salem Harbor #3 incorporated the 

state-of-the-art for the technology at the time. Because sensors were not available for 

temperature or ammonia measurement, the original SH #3 NOxOUT system was 

controlled primarily in a feed-forward manner based upon the measured steam flow and 

the coal mills in operation. The NOx signal from the CEMS was compared with a 

setpoint for a slow-adjusting feedback trim. 

When the NOxOUT system was originally installed in 1993 - prior to the LNB and 

SOFA - the reagent consumption was rather high as a result of the need to reduce NOx 

from 1.00 lb/MMBTU to about 0.30 lb/MMBTU. About eight months after the 

NOxOUT system was installed, the LNB and SOFA retrofit reduced the baseline to the 

NOxOUT system to about 0.43 lb/MMBTU. This, of course, had the expected benefit 

with regard to reagent consumption, reducing reagent consumption about 60%. This also 

had a relatively minor impact on heat rate because it was more difficult to maintain steam

temperatures as a result of the combustion system retrofit. 

It was believed that there was still significant room to improve reagent consumption if a 

means to address the variable FEGT could be implemented.4

 However, a commercially 

available approach did not exist during the first years of system operation. In 1996, a 

new control system - implementing sensors and control methods previously unavailable 

for SNCR control - was installed and demonstrated at Salem Harbor #3. 

The new control system - provided by the original SNCR system vendor, Nalco Fuel 

Tech, - utilizes signals from optical FEGT instruments and steam flow to control the 

injection zones and injection rate.5

 Two FEGT instruments were supplied to monitor 

both sides of the split furnace. Piping modifications were also made to the NOxOUT 

system in order to provide the system independent injection zone control, which had not 

been provided on the original system. With the use of the FEGT instruments, the control 

system could more accurately track the proper injection point in the furnace and respond 

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15

to rapid system changes. With the piping changes, the NOxOUT system could 

effectively bias the reagent injection rate between levels in response to changes in 

temperature. Another feature of the control system is the use of a continuous ammonia 

slip signal that indicates transients of high ammonia slip. With this signal, the NOxOUT 

control system can detect and respond to conditions that would otherwise produce high 

ammonia slip. 

The benefits of this control system are presented in Figure 9, which shows the total 

operating cost of NOx reduction, including reagent consumption rate and heat rate 

penalty (normalized to the historical 1994, 1995 and early 1996 values). It is notable that 

the FEGT instrument was installed prior to placing the new control algorithms in 

operation. With the FEGT instrument, the operators modified their soot blowing 

operations, which created a benefit to the reagent consumption and eliminated the heat 

rate penalty that previously existed. With the full controls in place, reagent consumption 

was about 33% of the historical 1994, 1995, and early 1996 values. In addition to the 

improvement in reagent consumption, Salem Harbor #3 experienced a significant 

reduction in ammonia slip5

. 

LNB+SOFA+

NOxOUT

With FEGT With

FEGT+New

Controls

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

LNB+SOFA+

NOxOUT

With FEGT With

FEGT+New

Controls

Figure 9. Normalized Oper. Cost of Reducing NOx, Salem Harbor #3

Heat Rate Penalty

SNCR Cost

% of historical cost

Andover Technology Partners

112 Tucker Farm Road, North Andover, MA 01845 

phone: (978) 683-9599, fax: (978) 683-3843, website: www.andovertechnology.com
16

Summary 

 

In this report, operators of three different facilities equipped with urea SNCR (NOxOUT) 

found ways of operating the facility in a manner that significantly reduced the total 

operating cost of reducing NOx when using the SNCR system. In all cases the systems 

were initially providing the designed and guaranteed performance that the vendor 

originally promised. However, with experience, the operators found methods of 

improving on the performance of the system. And, although each situation involved the 

same technology on coal-fired boilers, significantly different methods were employed to 

improve the performance. Below, the key features of these programs and lessons learned 

are discussed. 

• Reducing the baseline NOx will usually produce the greatest improvement in urea 

consumption. This can be done through combustion adjustments, reburning, or fuel 

substitution. However, these methods will frequently increase other operating costs - 

most notably, fuel cost - which must be considered in any analysis. At Edge Moor, 

Somerset and Salem Harbor the operators found methods of operating the boilers that 

significantly reduced baseline NOx. In all cases, the improved reagent consumption 

was balanced against other costs, such as increased heat rate and/or the additional 

cost of firing a premium fuel. Edge Moor #3’s gas availability gives it certain 

flexibility during summer months when gas is less expensive. Somerset’s ABMS 

enables it to maintain furnace conditions that offer low NOx and good heat rate, 

enabling large reductions in reagent consumption. At Salem Harbor, the LNB + 

SOFA retrofit provided a substantial reduction in NOx with a small penalty to heat 

rate. 

• In cases where NOx has been minimized, efforts to improve reagent utilization should 

be taken. Of the parameters the operator can impact, reagent utilization is most 

affected by reaction temperature and distribution. Providing that distribution is 

optimized, the operator must optimize utilization with respect to temperature, which 

requires balancing reagent savings against the risk of high ammonia slip and/or 

increased heat rate. On furnaces such as at Salem Harbor #3 that have highly variable 

FEGT’s at any fixed load due to slagging, oxygen control, or other reasons, this 

balance can be very delicate. Newly developed instrumentation and control methods 

used at Salem Harbor offer the ability to maintain this balance and realize the dual 

benefits of reduced reagent consumption - lower operating cost with lower ammonia 

slip - while avoiding the risk of high ammonia slip during transients. In the cases of 

Edge Moor and Somerset, unlike Salem Harbor, FEGT is fairly stable. Therefore, at 

these facilities it is easier to optimize reagent injection with respect to temperature 

without additional instrumentation. At these two facilities the control system

improvements used at Salem Harbor - if implemented at Edge Moor or Somerset - 

would provide operating benefits, but not as great as those experienced at Salem

Harbor.

Andover Technology Partners

112 Tucker Farm Road, North Andover, MA 01845 

phone: (978) 683-9599, fax: (978) 683-3843, website: www.andovertechnology.com
Andover Technology Partners

112 Tucker Farm Road, North Andover, MA 01845 

phone: (978) 683-9599, fax: (978) 683-3843, website: www.andovertechnology.com

17

References 

 

1. Ciarlante, V, Zoccola, M. “Application of Urea SNCR on a Tangentially Fired 84 

MWe Pulverized Coal Boiler”, Conference on Selective Catalytic and NonCatalytic Reduction for NOx Control, May 15-16, 1997.

2. Staudt, J.E., Casill, R. P., Tsai, T. S., Ariagno, L. J., “Commercial Application of 

Urea SNCR for NOx RACT Compliance on a 112 MWe Pulverized Coal Boiler”, 

EPRI/EPA 1995 Joint Symposium on Stationary Combustion NOx Control, 

Kansas City, MO, May 16-19, 1995. 

3. Tsai, T.S., Ariagno, L., Cote, R., Staudt, J.E., Casill, R.P., “Living with Urea Selective 

Non-Catalytic NOx Reduction at Montaup Electric’s 112 MW PC Boiler”, ICAC 

Forum ’96, March 1996. 

4. Frish, M.B., Johnson, S., Comer, J., Afonso, R., Sload, A., “Integrated NOx Control at 

New England Power, Salem Harbor Station”, EPRI-EPA 1995 Joint Symposium

on Stationary Combustion NOx Control, May 1995 

5. O’Leary, J.H., Sun, W.H., Afonso, R., Sload, A., “SNCR Reagent Reduction Through 

Innovative System Controls at Salem Harbor Station Unit 3”, EPRI-DOE-EPA 

Combined Utility Air Pollution Control Symposium, August 25-29, 1997