1 

Innovative Low-Load Supplemental Heating for the 

F. B. Culley Unit 3 SCR System 

Paper # 127 

Ron Bradford, John Minnette, and B. J. Reynolds 

Vectren Corporation 

20 N.W. Fourth Street 

Evansville, Indiana 47741 

Mark J. Chapin and James P. Walawender 

Black & Veatch Corporation 

11401 Lamar 

Overland Park, Kansas 66211 

ABSTRACT 

To maintain emissions compliance at low boiler loads, many SCR systems have included 

provisions to maintain the flue gas above the minimum SCR operating temperature. 

Historically, SCR designers have employed systems requiring some degree of 

modifications to the boiler such as economizer gas-side bypass or a split economizer to 

raise the flue gas temperature at the SCR and allow the SCR to remain in service during 

low load operation. Typically, these alternatives have had a very high capital cost to 

install due to the limited space available to retrofit the SCR system and its auxiliaries. 

An innovative application of gas-fired supplemental heating system was commissioned in 

2003 at Vectren’s F. B. Culley Station Unit 3. This unit is primarily base-loaded during 

the ozone season, and therefore low load supplemental heating will not be required for 

the majority of the operating hours. This design basis allows the higher cost of operation 

(when required) to be justified over the other alternatives because of the considerably 

lower installed cost. 

This alternative controls the flue gas temperature entering the ammonia injection grid and 

the SCR reactor by adding supplemental heat from the combustion of natural gas with 

ambient air. The two flue gas streams are then thoroughly mixed and the resulting 

temperature is controlled to achieve the minimum required SCR operating temperature. 

Versatility and flexibility provided by this alternative are proving very beneficial. This 

alternative provides an opportunity to develop startup processes which minimize NOx 

emissions. This method of supplemental heating can tolerate considerable more variation 

in coal fuel sources than the traditional low load heating systems. 

Installation of this system however does introduce some additional design challenges that 

are not present in the other alternatives, which required special attention during the 
2 

project to ensure safe and reliable operation. In particular, special attention was given to 

the design of the downstream mixing devices, to the requirements of NFPA 85 and the 

development of the control software. This software was developed in-house by Vectren. 

This system has been demonstrated to be able to elevate and maintain the flue gas 

temperature entering the SCR system. Additionally, this system can be used to reduce 

the time required to warm the SCR reactor during startup. This paper presents an 

overview of the economics, design, and operating results for the Unit 3 low-load 

supplemental heating system. 

PLANT DESCRIPTION 

F. B. Culley Station Unit 3 is owned and operated by Vectren and is located on the Ohio 

River near Evansville, Indiana. The unit began operation in 1973 and has a B&W dry 

bottom, opposed wall fired boiler. The unit was converted to balanced draft and 

retrofitted with low NOx burners in 1990. Unit 3 fires a variety of local and Illinois 

Basin coals ranging in sulfur content up to 51⁄2 percent. In addition to the low NOx 

burners, existing pollution control equipment at the time of the SCR retrofit included 

cold-side electrostatic precipitators (ESPs) and a wet limestone spray tower flue gas 

desulfurization system (scrubber). 

Figure 1 shows the south side of the unit prior to the installation of the SCR system. Flue 

gas exited the economizer through two ducts; one located on each side of the boiler, and 

flowed down into one Ljungstrom type air heater per train. Downstream of the air 

heaters, each flue gas train passed through an ESP and induced draft (ID) fan before 

being combined with the flue gas from Unit 2 and passed to the flue gas scrubber. 

The original chimney (which was abandoned after installation of the flue gas scrubber) 

was located between the ESPs and ID fans. Immediately south of the scrubber inlet ducts 

is the Ohio River. 

The basis of design for the SCR system is shown in Table 1. This design basis was 

developed by Black & Veatch (B&V) and Vectren during the preliminary engineering 

phase of the project. 
3 

Figure 1

South Side of F. B. Culley Station Before SCR System Installation 

Table 1: Design Basis for the F. B. Culley Unit 3 SCR 

Parameter Value 

Unit Size, MW 287 

Required Operating Load Range, percent 40 to 100 

Typical / Maximum Coal Sulfur Content, percent 3.75 / 5.48 

Uncontrolled NOx Emissions (Typical), lb/MBtu 0.45 

Required SCR Outlet NOx Emissions, lb/MBtu 0.06 

Required SCR Outlet Ammonia Slip, ppmvd at 3 percent O2 2 

SCR SO2 to SO3 Oxidation Rate, percent 0.5 

SCR SYSTEM DESCRIPTION 

B&V provided engineering, procurement, and construction management services as agent 

for Vectren. The design of the SCR and plant interfaces was established during 

preliminary engineering, which served as the basis for the execution phase of the project. 

During both preliminary engineering and project execution phases, Vectren engineers and 

management worked closely with B&V to develop designs and solutions that were both 

cost-effective and ideally suited for the particular unit. 
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In designing the SCR reactor and ductwork, B&V took advantage of the unique site 

characteristics to develop a compact and economical SCR system layout. Figures 2 and 3 

show the plant arrangement in the SCR area after installation of the SCR system. Figure 

4 shows an isometric view of the SCR reactor. 

Figure 2

SCR System Elevation 
5 

Figure 3

SCR System Plan Arrangement 

Figure 4 

Isometric View of SCR System 
6 

System Layout 

The SCR system consists of a single reactor housing up to four (4) layers of catalyst. 

Flue gas exiting the boiler is directed through two new economizer outlet ducts which are 

now located to the south of the boiler. Once past the boiler support steel, the two ducts 

are combined into a single duct and flue gas passes through flow correction devices and 

an ammonia injection grid (AIG) before entering the SCR reactor. 

Demolition of the abandoned Unit 3 chimney provided a clear and open location for the 

installation of the SCR and afforded the opportunity to lower the SCR compared to the 

traditional system location above the unit air heater(s). As a result, the top of the Unit 3 

SCR is located at the economizer outlet elevation and the SCR reactor extends downward 

to grade. Flue gas exiting the SCR reactor turns vertically upward and is directed into 

two ducts, one serving each air heater. Figure 5 shows the completed installation. 

An SCR bypass is included for catalyst protection during unit startup or when the SCR 

system is not required to be in operation. In addition to inlet/bypass diverter and outlet 

isolation dampers, high temperature guillotine dampers are installed at the inlet and outlet 

of the SCR reactor. Seal air systems are provided on the dampers to maintain reactor 

isolation. Secondary air is supplied as seal air to the inlet/bypass diverter and outlet 

isolation dampers and ambient air is supplied as seal air to the guillotine dampers. 
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Figure 5 

Completed SCR System Installation 

SCR Catalyst 

Homogenous honeycomb SCR catalyst was supplied by CERAM-Frauenthal GmbH. 

The catalyst is composed of a porous metal oxide (catalyst support) and active metals 

which facilitate the reduction of nitrogen oxides in the presence of ammonia. The 

catalyst support is TiO2 and the active metals are V2O5 and WO3. 

Major catalyst design parameters are shown in Table 2. 

Table 2: Catalyst Design for the F. B. Culley Unit 3 SCR 

Parameter Value 

Catalyst Volume per layer, m3 177 

Pitch, mm > 6.0 

Wall Thickness, mm 1.0 

Catalyst Operating Temperature, oF 590 – 850 
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Ammonia System 

Nineteen percent aqueous ammonia is used as the reagent. Ammonia is received by truck 

and unloaded into a single, 35,000 gallon ammonia storage tank that provides three days 

of onsite storage. Redundant fans supply dilution air to a gas-fired dilution air heater. 

Heated dilution air flows into a vaporization chamber where the required flow of 

ammonia is mixed and evaporated into the dilution air. The air/ammonia mixture flows 

to a multi-zone adjustable ammonia injection grid. The grid is designed to ensure 

uniform mixing between the ammonia stream and main flue gas stream. This provides 

Vectren with the flexibility to field balance the NH3/NOx distribution during initial 

commissioning and long-term operation. Each zone is equipped with a manually 

adjustable valve for regulating the flow of the ammonia/air mixture into the grid and a 

flow orifice which displays an indication of branch line flow on a digital indicator. 

Balance of Plant 

In addition to erection of the SCR and related ductwork, the plant required several other 

modifications to complete the installation. The project team also performed the 

following balance-of-plant modifications. 

Air Heater 

The existing Ljungstrom air heaters were converted from three-layer to two-layer design 

in which the cold end consists of enamel coated steel baskets. Enameling of the air 

heater’s cold end baskets not only provides corrosion protection of the impacted area of 

the heat exchanger, but also significantly reduces the corrosion rate should water washing 

ever become necessary. 

ID Fans 

The ID fans required replacement to accommodate the additional draft losses of the SCR 

and the wide range of operating conditions and draft losses imposed by the addition of 

SCR. 

Chimney Demolition 

As noted previously, the abandoned chimney was demolished to provide room for the 

SCR installation. 

ESP and Duct Stiffening 

The existing design pressure of the ESPs and the ductwork downstream of the air heater 

was not sufficient for the new modified design. These components were analyzed and 

reinforced. 
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Control System 

SCR system control was implemented in the existing Honeywell TPS DCS system. B&V 

provided the engineering design and control narrative descriptions, and Vectren 

performed the control system programming and implementation. 

Emissions Monitoring 

In addition to NOx monitoring for the SCR, Vectren elected to install ammonia 

monitoring at the SCR outlet to provide a gross assessment of ammonia slip from the 

SCR. 

LOW-LOAD SUPPLEMENTAL HEATING SYSTEM 

As shown in Figure 6, the economizer exit temperature falls below the minimum SCR 

operating temperature at loads below approximately 200 MW. Furthermore, an analysis 

of the air heater design characteristics and expected operating conditions leaving the 

boiler indicated that the flue gas temperature leaving the air heaters would fall below the 

calculated acid gas dew point with an air heater leakage of 10 percent. 

450

475

500

525

550

575

600

625

650

675

0 50 100 150 200 250 300

Unit Load (MW)

Economizer Exit Temperature (F)

Catalyst Minimum 

Operating Temperature

Figure 6 

Economizer Exit temperature vs. Unit Load 
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Evaluation of Alternative Methods of Supplemental Heating 

Although the catalyst minimum operating temperature was established by the supplier as 

590 F, the minimum design flue gas temperature entering the SCR was initially 

established at 605 F to allow margin for potential temperature mal-distribution during 

low load operation and to account for any difference between the measured temperature 

and the minimum temperature within the duct. As operational experience becomes more 

known and predictable, this value will be adjusted as appropriate. Since the normal 

operating economizer outlet flue gas temperature drops below 590 F at loads below 

approximately 70 percent of full load, a method of maintaining this minimum 

temperature across the unit operating load range was required. On previous SCR retrofit 

projects, this flue gas temperature control has been accomplished by bypassing a portion 

of the flue gas stream entering the boiler economizer and mixing this flue gas with gas 

exiting the economizer, resulting in elevated flue gas temperatures at the SCR inlet. This 

flue gas bypass system has been a relatively high capital cost system for the hightemperature ductwork, dampers and boiler wall penetrations needed to provide the source 

of high temperature flue gas. Somewhat unique to the Culley Unit 3 site, footprint 

limitations and the minimal gap between the primary superheater and the economizer 

would have required lowering the entire economizer to accommodate economizer bypass. 

To avoid the high capital cost and maintenance costs of the bypass system, the use of 

natural gas fired burners was evaluated. 

Operation of an economizer bypass system would result in lower boiler efficiency and a 

higher coal fuel burn rate compared to the existing unit performance. Either the bypass 

system or the supplemental gas-fired heater system would be expected to require the 

same fuel heat input (MBtu/hr basis) to maintain the same SCR flue gas inlet temperature. 

Additional coal would be required for the bypass system or natural gas would be required 

for the gas-fired heaters. Due to the use of higher cost fuel for the natural gas fired 

heaters, the operating cost of this system would be higher than that of the economizer 

bypass system by the difference between the cost of coal and the cost of natural gas on a 

$/MBtu basis. 

The operating load profile for Unit 3 indicates that the majority of operating hours occur 

near full unit load conditions and fewer operating hours occur at reduced loads, where the 

normal economizer outlet flue gas temperature is below the minimum temperature for 

SCR operation. The unit generation records were reviewed, indicating that the unit 

operated above 70 percent unit load 90 percent of the time. Because of this high average 

unit load characteristic the lower capital cost gas-fired flue gas reheating system was 

evaluated to be economically advantageous compared to the higher capital cost 

economizer bypass system. 
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Table 3: Comparative Economics of Alternative Methods of Supplemental Heating 

Economizer 

Bypass System 

Gas Fired 

Duct Burner 

Capital Cost 

Differential Maintenance Cost 

Differential Fuel Cost, Capitalized 

$ 1,020,000 

-- 

Base 

Base 

(No Credit) 

$ 450,000 

Differential Evaluated Cost $570,000 Base 

Although no credit was given in the analysis for the anticipated maintenance savings 

associated with the gas fired duct burner system, the comparative economics indicate that 

the gas fired duct burner system was expected to provide life-cycle cost reductions in 

excess of $500,000. 

Additional Benefits Provided by Supplemental Heating 

In addition to providing a cost-effective method of low-load supplemental heating to 

support SCR system operation, the Unit 3 duct burner system provides several benefits to 

unit operations. 

Boiler Operations 

Use of the supplemental heating system does not impact normal boiler operations as 

would the traditional methods for supplemental heating. Additionally, the duct burners 

reduce the demand on the steam coil air heaters during cold weather compared to 

traditional methods for supplemental heating. Furthermore, the duct burners can lessen 

the impact of episodes of feedwater heater limitations and backpass fouling and can be 

individually controlled to balance gas temperature gradients at the economizer outlet, 

minimizing the energy input. 

Unit Startup 

The supplemental heating system provides the capability to raise SCR temperature earlier 

during startup compared to the traditional methods for supplemental heating, allowing the 

SCR to be placed in service earlier in the unit startup process. 

SCR Operating Load Range 

Since the heat source is independent of furnace temperature, the supplemental heating 

system can maintain the required minimum SCR operating temperature at all loads down 

to minimum stable unit load. Additionally, because the multi-zone adjustable ammonia 

injection grid does not rely on flue gas velocity to develop the proper ammonia 

distribution within the duct, the Unit 3 SCR provides the capability to substantially 

reduce NOx emissions at all unit operating loads. 
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Acid Dew Point Corrosion Mitigation 

The sulfur content of the coal for Unit 3 results in the potential for acid condensation at 

temperatures below approximately 280 F. Since the supplemental heating system raises 

the flue gas temperature downstream of the boiler exit, the air heater exit temperature is 

sustained during supplemental heating system operation. This provides the opportunity 

to maintain the air heater exit temperature above the acid dew point at all boiler loads, 

minimizing corrosion in downstream ductwork and equipment. 

Challenges in Implementing Supplemental Heating 

Careful attention was paid to several issues regarding the gas-fired supplemental heating 

system during the design, startup, and initial operation of the Culley Unit 3 SCR system. 

Flue Gas Mixing 

The unique configuration of the Unit 3 SCR resulted in a much shorter length of 

ductwork between the economizer outlet and the SCR inlet than is typical of more 

common arrangements. In addition to installing the inlet/bypass and inlet isolation 

dampers and the AIG in this limited area, the arrangement required that the dispersion 

and mixing of the duct burner exit gases be accomplished as well. Special attention was 

paid to the mixing devices during the model study to ensure that the gas streams could be 

thoroughly mixed and gas temperatures maintained between the minimum and maximum 

catalyst operating temperatures. Model study results indicate that the temperature 

distribution could be maintained within ±30 F (±2.7 percent RMS) at the AIG and ±20 F 

(±1.4 percent RMS) at the first layer of catalyst, which were within the design objectives. 

Figure 7 shows a plan view of the airfoil type mixers that were implemented to distribute 

the supplemental heating gases within the flue gas duct. 

Figure 7

Plan View of Duct Burner Mixing System 
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Combustion Hazards 

The use of gas-fired duct burners for supplemental heating presented two operating 

scenarios that required special attention. 

The first operating scenario is the potential hazard created if a duct burner fails to light 

off during startup and the burner management system failed to detect that failure and 

close the gas valve. Under this scenario, methane would be injected into the main flue 

gas stream and carried downstream to other equipment, particularly the ESP. Detailed 

design analyses showed that there would be insufficient oxygen and insufficient methane 

to create a hazard, even should both burners fail to light. 

The second operating scenario is the possibility that the duct burner and/or dilution air 

heater gas valves could leak methane gas into the SCR ductwork and reactor when the 

SCR is in bypass mode. To ensure that any potentially hazardous conditions in the SCR 

are safely neutralized, the duct burners and dilution air heater are not fired until the entire 

SCR ductwork and reactor are purged with flue gas by the ID fans and the dilution air 

heater and associated piping is purged with ambient air from the dilution air fans. 

Additionally, positive means for isolation of the duct burner natural gas supply is 

provided in order to maintain system purge credit during SCR bypass. 

Commissioning Issues 

In addition to ordinary mechanical and instrumentation commissioning problems which 

were resolved by the vendor, two issues were identified and solved during system startup. 

Duct Burner Purge 

Normal startup of the duct burners requires purging the burners before light-off. It was 

found during system startup that the burner purge air flow would cool the economizer 

exit flue gas below the required minimum ammonia injection temperature. The purge air 

flow was found to depress the gas temperature by 30 to 60 degrees, depending on unit 

load and ambient temperature. Operational modifications, including reduced volumetric 

flow rate for the purge and coordinating the fan start and damper opening, were 

implemented which successfully resolved the issue. 

Duct Burner Fan Damper 

The duct burner fans were initially equipped with an air operated discharge damper. 

Since the SCR inlet ductwork operates under negative pressure, the quick-opening 

characteristic of the damper created a sudden inrush of ambient air which required 

compensation by the variable speed ID fans. The damper movement was also jerky, 

alternately binding and jumping during travel. Occasionally, the damper limit switch 

failed to make contact, causing the damper to quickly close just after opening. The 

elimination of the air inflow through the burner resulted in furnace pressure fluctuations. 
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The vendor’s air operator was replaced with a linear electric operator, which proved 

successful in resolving the issue. 

Duct Burner Control 

As initially conceived and installed, the duct burner operated with a constant air flow, and 

fuel gas flow was modulated to control gas exit temperature. Although this method of 

operation performed acceptably, system operating costs could be reduced by operating 

the duct burner at maximum allowable discharge temperature, thus reducing the volume 

of air that must be heated. 

After system startup, the burners were retrofitted with modulating inlet guide vanes 

(IGVs) for the duct burner fans. In order to successfully implement this approach, 

accurate and reliable measurement of both duct burner air flow and fuel flow was needed 

so that flame buoyancy can be maintained within the desired range. Because an accurate 

air flow measurement was not available, the IGVs were characterized to establish a 

correlation between IGV position, fuel flow, and burner gas exit temperature. However, 

because the air density varied according to changes in ambient temperature and furnace 

pressure, this system was further refined by implementing a feedback loop based on the 

burner gas exit temperature. 

Ash Accumulation 

During initial operation of the SCR system when supplemental heating was not required, 

ash accumulation in the duct burner and fuel gas piping was noted. A purge system 

utilizing ambient air was implemented but ultimately resulted in ash agglomeration in the 

burner from the moisture in the purge air. A method to potentially resolve the ash 

accumulation would be to retrofit isolation dampers at the discharge connections of the 

burners. 

OPERATING RESULTS 

The F. B. Culley Station Unit 3 SCR was ready for final commissioning and checkout in 

May/June 2003 as scheduled. System tuning was conducted in July 2003 and the system 

was put into commercial operation during fall 2003. Performance testing was conducted 

on November 5-7, 2003. The results of initial tuning, performance testing, and SCR 

system load following capability are as follows. 

Initial Tuning 

Prior to performance testing, the AIG was tuned to ensure acceptable NOx and ammonia 

distribution at the catalyst outlet. A fixed tuning grid consisting of 24 sampling points 

was installed at the outlet of the reactor to allow measurement of NOx across the entire 

cross-section of the reactor. NOx was measured at each point in the testing grid. It 
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should be noted that NOx was used to perform tuning instead of ammonia because NOx 

can be more easily and accurately measured. 

A handheld NOx analyzer was used to perform the AIG tuning at both high and low unit 

loads. Figure 8 shows the results of the system tuning. 

1

2

3

4

1

2

3

4

5

6

0

20

40

60

80

100

NOx (ppm) at Tuning Grid

Figure 8 

Results of Ammonia Injection Grid Tuning 

Performance Testing 

Performance tests were conducted at full and low load. Table 4 shows the test results and 

compares them to the SCR system design requirements. This comparison shows that the 

SCR performance fulfilled the design basis requirements. 

Table 4: Summary of Performance Test Results 

Parameter Design Basis 

Full Load 

Test Results 

Low Load 

Test Results 

SCR Inlet NOx Emissions, lb/MBtu 0.48 0.49 0.38 

SCR Outlet NOx Emissions, lb/MBtu 0.06 0.059 0.054 

Ammonia Slip, ppmvd at 3 percent 

O2

2 0.86 0.73 
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Parameter Design Basis 

Full Load 

Test Results 

Low Load 

Test Results 

SO2 to SO3 Oxidation Rate, percent 0.5 0.09 Inconclusive 

System Pressure Drop, in. w.g. 7.3 5.7 3.55 

Load Following Capability 

As discussed previously, the operating flexibility afforded by the supplemental heating 

system increased the operating load range of the Unit 3 SCR compared to conventional 

approaches. Figure 9 shows the demonstrated results of the system to maintain SCR inlet 

temperature and NOx reduction capability during unit load reductions. 

530.0

550.0

570.0

590.0

610.0

630.0

650.0

18:43 19:17 19:52 20:26 21:01 21:36 22:10 22:45 23:19 23:54 0:28 1:03 1:37

Time

Temperature (F)

0.0

100.0

200.0

300.0

400.0

500.0

600.0

Unit Load (MW)

NOx Concentration (ppm)

SCR Inlet Temperature

Economizer Outlet Temperature

Unit Load

SCR Inlet NOx

SCR Outlet NOx

Figure 9 

Load Following Operation 

During the period of time shown on Figure 9, the unit load was decreased from about 265 

MW to 175 MW with intermediate periods of operation at 225 MW and 200 MW. As the 

unit load decreased, the economizer outlet temperature decreased from approximately 

640 F to 585 F, but the supplemental low-load heating system maintained the SCR inlet 

temperature at 620 ±3 F. During the same period, the SCR inlet NOx varied from 220 

ppm to 135 ppm and outlet NOx was maintained between 10 ppm and 38 ppm, quickly 

stabilizing at 30 ppm after each load change. 
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CONCLUSIONS 

In addition to providing cost-effective and economical supplemental low load heating, the 

application of gas-fired duct burners offers reduced retrofit requirements compared to 

conventional alternatives, increases unit operating flexibility, and can be used to mitigate 

the impact of acid condensation downstream of the air heater. This improved air heater 

outlet temperature control becomes more important for high sulfur coal fueled units that 

are moving toward fabric filters to reduce particulate emissions. 

The lessons learned during the Unit 3 project are being applied by Vectren and B&V to 

the Warrick Station Unit 4 and A. B. Brown Station Units 1 and 2 SCR projects. 

Additional refinements on subsequent applications include the use of dedicated 

combustion air and tempering air fans to separate these functions and facilitate 

modulation of burner air flow. 

As a result of Vectren’s positive participation and cooperative commitment to 

successfully implementing the gas-fired duct burner system for low-load supplemental 

heating, this concept was successfully matured at the F. B. Culley Station Unit 3 SCR 

installation. 

KEY WORDS 

Black & Veatch 

Culley 

Duct Burner 

Heating 

Low Load 

NOx 

Selective Catalytic Reduction (SCR) 

Vectren