p.1 

OAR Box 1778 

Prepped by Ollie Stewart 

Document Number: 

227) 11-1-7 

Docket Number: 

A-90-06 

Printed 10/28/2008 9:51:02 AM Sheet 227 of 276 
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iTCD-fii'-SU lil t i.'i£ fHA r 

Wisconsin 

Electric 

POWER COMPANY 

231 W Michigan, RO. Box 2046. MRwouted. Wl W2C1 

January 11, 1989 

Mr. Dale Ziege 

Bureau of Air Management 

Wisconsin Department of Natural Resources 

P. 0. Box 7921 

Madison, Wl 53707 

Dear Mr. Ziege: 

PORT WASHINGTON POWER PLANT RENOVATION PROJECT 

PSD PERMIT BACT ANALYSIS 

II-1-7 

(414)221-2345 

i^jili-Bs 

Available Control Technology 

lead emissions from the Port 

We have enclosed our analysis of the Best 

(Attachments 1 and 2) for NO , beryllium and 

Washington plant. You had agreed at our October 27, 1988, meeting to review 

and respond to this information before you draft a PSD permit. You will also 

recall that we plan to keep annual particulate and SO- emission increases to 

less than PSD significance levels through negotiated permit conditions for the 

renovated plant. 

We have concluded that the burner design and configuration of the plant 

boilers represents the Best Available Control Technology (BACT) for NO 

emissions. This is based on information provided by Mr. Hubbard, and Mr. 

McDowell of EPA, showing higher NO emission limits in permits issued for 

construction of pulverized coal-firedrelectric utility steam generators and an 

independent inquiry I made with EPA Region IX. The economic and energy 

analysis of post-combustion NO reduction technologies installed on the plant 

boilers for comparison was provided by the Bechtel Corp. Also Attachment 3 to 

this submittal, which was informally left with you on October 27, 1988, along 

with the EPRI report of NO emission tests conducted on the plant boilers, 

provides additional information to support our conclusion. 

Rehabilitation of the plant's electrostatic precipitators, included in the 

scope of the Port Washington Renovation Project, is expected to yield ESP 

particulate removal efficiencies of 99.2 to 99.5 percent. We believe that 

these expected control efficiencies constitute BACT for emissions of lead and 

beryllium based on the relatively minimal projected emission rates presented 

in Attachment 2. 

Please let me know if you have any questions concerning this submittal. 

Rogerr D.. Dodd uds j 

Air SJ/jalit Qjuality tngirjee Er r 

Environmental Department 

dmp 

Attachments 

cc: J. Paisie-EPA Region V 
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.'"•••. Attachment 1 

PORT WASHINGTON POWER PLANT 

UNITS 1-5 

BACT FOR NOx EMISSIONS 

NITROGEN OXIDES CONTROL 

The five Steam Generators at Port Washington Power Plant are 

pulverized coal fired, dry bottom furnace, natural circulation boilers with superheat and reheat circuits. 

The steam generators at Port Washington inherently incorporate combustion features which inhibit NOx formation. The 

burners are mounted on the furnace arch and fire downward. 

The long flames emitted from the burners receive the bulk of 

combustion air perpendicular to and along the length of the 

flame jet, producing staged combustion. The water-cooled 

furnace front walls and bottom, along with relatively low 

combustion air temperatures, aid in achieving a low bulk combustion temperature thus inhibiting NOx formation. Consequently, Nitrogen Oxides (NOx) are emitted in a nominal range 

of 0.34 to 0.47 lb/MMBtu for these units. 

A. BEST AVAILABLE CONTROL TECHNOLOGY - BACT 

A clearinghouse search was conducted in cooperation with 

Wisconsin Department of Natural Resources and EPA Regions 

V and IX to determine lowest achieved emissions from a 

pulverized coal fired electric utility steam generator 

which has been permitted, constructed and demonstrated. 

The search revealed no pulverized coal installations with 

permitted NOx emission levels lower than 0.49 lb/MMBtu. 

Those installations which achieve the NSPS NOx emission 

limit of 0.6 lb/MMBtu or less do so by applying burner 

design and boiler operation techniques to limit NOx 

formation during combustion. None of the permitted 

sources, which are newly construced boilers, apply 

post-combustion gas treatment. There have been no 

determinations made to date on what constitutes BACT for 

NOx emissions from renovated coal fired utility boilers 

similar to those at Port Washington. 

B. BACKGROUND - NOx CONTROL MEASURES 

Control technologies to reduce NOx emissions fall into 

two categories, combustion controls and post-combustion 

controls. Combustion controls seek to optimize firing 

conditions to minimize thermal NOx formation during the 

combustion) process, while post-combustion controls seek 

to remove NOx from the flue gas. 
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Available combustion controls to minimize thermal NOx 

formation do so by control of the combustion 

stoichiometry, limiting free oxygen present by staged 

admission of air during the combustion process, thus 

inhibiting,NOx formation. An additional strategy is to 

minimize the temperature of the combustion process to 

suppress reactions which form NOx. 

Post-combustion NOx controls utilize a reducing agent, 

typically ammonia or urea, to convert NOx to elemental 

Nitrogen and water vapor. If a catalytic surface or 

reactor is employed, the process is called Selective 

Catalytic Reduction (SCR), while without a catalyst the 

process is often called Thermal De-NOx. 

1. Selective Noncatalytic NOx Reduction 

The use of ammonia without a catalyst is most effective 

when it is injected into an area where the flue gas is 

maintained at 1750°F. The Port Washington units are 

subject to cyclic and load following duty. During 

operation, load changes and furnace slagging would cause 

the gas temperature to vary at the injection location. 

This would result in variable removal effectiveness and 

excess ammonia slipping through unreacted. Current test 

Installations indicate a typical ammonia slip of 

35-65 ppm in the flue gas. This ammonia emission would 

be in exchange for a potential NOx removal of 30-100 ppm 

for the Port Washington units. 

2. Selective Catalytic Reduction 

Catalytic NOx reduction is accomplished at flue gas temperatures of 700-750°F, which is the temperature at the 

flue gas inlet of the existing Port Washington air 

heaters when the units are at operating conditions. 

Removal effectiveness during start-up periods would be 

significantly reduced until operating temperatures are 

reached. 

Application of catalytic reduction would require 

relocation of air heaters, I.D. fans, precipitators and 

ductwork in addition to the siting and installation of 

the large volume catalyst beds themselves. 

3. Other Issues of Concern with Post-combustion Controls 

There is limited European and Japanese experience with 

SCR on utility boilers firing low sulfur coals of 1.2* 

sulfur content or less. The uncertainty in translating 

this international experience into predicted performance 

in the U.S. lies in the higher sulfur content and 

different ash constituents of American coals. The Port 

Washington coal will have a sulfur content of 1.5* or 
rcD-ci-% iijt b*' i8 

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c. 

more. The higher levels of SO, and S03 produced will 

react with the ammonia to form ammonium sulfates 

resulting in pluggage of the catalyst bed and air 

heaters. Trace elements present in American coals are 

expected to accelerate deactivation of the catalyst bed, 

hastening its replacement. 

JUSTIFICATION THAT THE PORT WASHINGTON STEAM GENERATORS 

CONSTITUTE BACT 

As stated above, the steam generators at Port Washington 

Power Plant produce NOx emissions of 0.34 -

0.47 lb/MMBtu. For the reasons discussed in this 

section, it is the Owner's judgement that the equipment 

and operations which produce this emission level 

constitutes Best Available Control Technology, BACT. 

1. MOST STRINGENT CONTROL IN PRACTICE 

As evidenced by a search conducted by WEPCo, WDNR and EPA 

Regions V and IX, there are no pulverized coal fired 

electric utility steam generators operating under any 

permits requiring NOx emissions less than 0.49 lb/MMBtu. 

2. TECHNICAL LIMITATIONS 

Port Washington Units 1-5 original design features 

incorporate contemporary combustion controls to minimize 

thermal NOx formation. As applied in other 

installations, these techniques have resulted in NOx 

emissions of 0.4-0.6 lb NOx/MMBtu, no better than current 

Port Washington performance. 

Post-combustion technologies for NOx removal have not 

been developed or demonstrated at a commercial level for 

pulverized coal fired units. Their removal effectiveness 

and overall impact on emissions and plant operations are 

very uncertain. 

3. ECONOMIC IMPACT 

To potentially lower NOx emissions through the 

installation and operation of Non-catalytic (Thermal 

De-NOx) or Selective Catalytic Reduction (SCR) systems 

for NOx removal would result in significant additional 

costs. 

Estimated costs, based on a recent study conducted for 

WEPCo, for a single unit operating at optimistic removal 

levels are summarized in table l, attached. It is 

important to note that the estimated installed cost of 

SCR systems for five units alone exceeds the entire 

current renovation budget by 50*; the initial cost of 

five Thermal De-NOx systems would increase the current 
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renovation budget by 20*. Additionally, this cost 

estimate does not include the cost impact of relocation, 

replacement or resizing of existing affected equipment 

such as air heaters, precipitator and I.D. fans. 

4. ENERGY IMPACT 

Lowering the NOx emission rate through the use of 

post-combustion controls would result in degradation of 

the unit heat rates and an increase in plant auxiliary 

electrical.load, reducing net unit output by an estimated 

0.5*. The,combustion of additional fuel would be 

required to meet electrical demand. 

5. ENVIRONMENTAL IMPACTS 

The potential for reducing NOx emissions below current 

levels is uncertain. If additional reductions are 

possible with post-combustion controls, the environmental 

impacts would include emissions of ammonia and, if SCR is 

used, disposal of spent catalyst beds containing toxic 

metals. Catalyst replacement will be required on a 1-3 

yr/unit frequency. Currently, there are no programs with 

the catalyst manufacturers for return or refurbishment of 

the spent catalyst beds. 

The application of further emission controls for NOx 

would not produce a significant difference in air quality 

impacts following repair of the plant. The ambient air 

quality standard of 100 micrograms of NOx per cubic meter 

is 60 times greater than the post-repair maximum 

predicted average annual ground level concentration of 

about 1.65 micrograms of NOx per cubic meter. This 

predicted concentration is at or below the level of 

detection of the reference method for measurement of NOx 

concentrations in the ambient air. Therefore, any 

further reduction in NOx emissions through flue gas 

treatment Methods will have an undetectable effect on the 

ambient air quality. 

6. CONCLUSION 

Taking into consideration all of the factors discussed 

above, it is our opinion that operating Port Washington 

Units 1-5 at a NOx emission limit consistent with current 

emission rates will constitute BACT. 
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Table 1 

PORT WASHINGTON POWER PLANT 

THERMAL DE-NOx OR SCR TECHNOLOGIES 

COST ESTIMATE PER UNIT 

Thermal De-Nox SCR 

NOx removal 30* 80* 

NOx Removal @ MCR - 90 240 

(Lb/Hr) 

Installed Cost $K 3,637 25,059 

Annualized Installed Cost $K 313 2,155 

Fixed Annual OfiM Cost $K 103 415 

Variable O&M Cost of 200 1000 

NOx Removed ($/Ton) 

NOx Removed Annually * 

11* Capacity Factor (Tons) 43 116 

46* Capacity Factor (Tons) 181 484 

Annual Cost $K 

11* Capacity Factor 425 2,690 

46* Capacity Factor 452 3,055 

| 

Annual Cost ($/Ton NOx Removed) 

11* Capacity Factor 9,883 23,190 

46* Capacity Factor 2,493 6,310 

* Annual Capacity Factors For Port Washington Units are ex-. 

pected to range from a minimum of ll* to a maximum of 46* 

for the remaining life of the units. 
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- ' • Attachment 2 

PORT WASHINGTON POWER PLANT 

EMISSION CONTROL OF 

NON-CRITERIA PM-RELATED POLLUTANTS 

The trace amounts of lead and beryllium in coal are 

volatilized during combustion and subsequently condense on 

the flyash being emitted. So the emissions of these elements 

are controlled by the particulate control device employed. 

Units 1-5 at Port Washington Power Plant are each equipped 

with an electrostatic precipitator (ESP) for particulate removal . Renovation work at Port Washington includes rehabilitation of the ESP's to allow them to perform at their 

original design particulate removal efficiencies of 

99.2-99.5*. This will be accomplished via physical repair of 

the ESP components, including straightening of collector 

plates, and replacement of existing controls with modern microprocessor based controls. Additionally, appropriate sizing of replacement air heaters (Units 1-4) and the planned 

application of a flue gas conditioner, such as S03, will optimize the flue gas temperature and resistivity for particulate removal. 

The amounts of trace materials contained in coals vary with 

the source of coal. For the current and anticipated Port 

Washington coal, typical concentrations have been developed. 

Based on these concentrations, the precipitator collection 

efficiencies and the plant utilization, or capacity factor, 

the annual expected emissions of Beryllium and Lead are 

tabulated below. * 

ANNUAL EMISSIONS 

CAPACITY FACTOR PM Be Pb 

YEAR (*) (Ton) (Ton) (Ton) 

1993 11 34 0.0007 0.03 

2009 46 141 0.003 0.13 

The particulate control devices with collection efficiencies 

comparable to the upgraded ESP's are baghouses and high 

efficiency wet scrubbers. However, the use of these devices 

were not evaluated with respect to control of the trace lead 

and beryllium emissions because it is intuitively obvious 

that they are not cost effective for retrofitting to the Port 

Washington plant boilers. The existing ESP's upgraded to 

design particulate removal efficiencies of 99.2-99.5* then 

represent BACT for lead and beryllium emissions. 
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Attachment 3 

/ 

NOx EMISSIONS 

PORT WASHINGTON POWER PLANT 

Further reduction in the emission rate of nitrogen oxides 

(NOx) from Port Washington Power Plant is currently not 

practical. As discussed below, the emission rates for the 

Port Washington boilers are already less than required for 

NSPS. Current combustion-based NOx control technologies 

are already incorporated into the boilers, as they are 

inherent to the burner/furnace design. Flue gas NOx removal 

technologies have neither yet been commercially developed 

nor successfully demonstrated for coal firing. 

The Fort Washington boilars employ "Arch Firing" in which 

pulverized coal is introduced downward along the front wall 

of the furnace. This results in a long downward flame, 

turning at the bottom in a U-shaped pattern. The bulk of 

combustion air is introduced through the furnace front wall 

along the length of the flame, perpendicular to the flame 

jet. This inherently generates staged combustion conditions 

which inhibit NOx formation. The water-cooled front wall 

and furnace bottom additionally inhibit NOx formation 

through reduction of the bulk furnace temperature. 

The design and function of arch firing and its impact on NOx 

formation is further described in the attached EPRI report 

CS-2813. Test results cited in the report show the Port 

Washington units produce NOx emissions in the range of 

0.3-0.5 lb/MStu, well below the NSPS reouirement Of 

0.6 lb/MBtu. 

Retrofit control technologies to reduce NOx emissions fall 

into two categories, combustion controls and post combustion 

controls. Combustion controls seek to optimize firing 

conditions tq minimize thermal NOx formation during the 

combustion process, while post-combustion controls seek to 

remove NOx from the flue gas. 

Available combustion controls consist of low excess air/low 

NOx burners, staged combustion, burner/furnace wall 

re-orientation and flue gas recirculation (FGR). The 

replacement burner and staged combustion techniques reduce 

NOx formation by maintaining the air/fuel ratio initially at 

sub-stoichiometric levels, then increasing the proportion of 

air as the combustion process continues. Burner/furnace 

orientation limits NOx formation by minimizing the 

temperature of the combustion process through radiation to 

the furnace walls. Flue gas recirculation also minimizes 

the combustion temperature, through dilution of the fuel/air 

mixture in the combustion zone with low oxygen content 

exhaust gas. 
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With the exception of FGR, all of these combustion control 

features are already inherently employed at Port Washington 

in the design and arrangement of the arch fired furnaces. 

Additionally, the cited retrofit technologies result in NOx 

emissions of approximately 0.4 lb/MBtu, offering no expected 

improvement beyond current Port Washington performance. 

Flue gas' recirculation may not be applicable to Port 

Washington due to the small primary air admission area at 

the burners where the flue gas would be re-introduced. 

However, since the unique bin and feeder firing system at 

Port Washington does not require hot air for coal drying, 

combustion air is delivered at a relatively low temperature 

(less than 600 F) and combustion temperatures are therefore 

minimized in a manner analogous to FGR. 

Post combustion controls involve the addition of a reducing 

agent, typically ammonia (NH3), to the flue gas stream to 

reduce NOx to elemental nitrogen (N2) and water (H20). A 

catalytic reactor or surface may additionally be employed to 

enhance removal effectiveness. There are no commercial 

installations in the U.S. utilizing catalytic systems on 

coal fired boilers. Limited European and Japanese 

experience has shown that the catalyst is subject to both 

plugging and erosion in addition to poisoning by trace 

metals in the ash. No monitoring method exists to detect 

excess NH3 passing into the catalyst where in combination 

with S03, sulphate plugging may occur. During cycling 

operation, amounts of NH3 equal to the NOx removal may be 

emitted. Further development of post combustion controls is 

required before practical applications can be made. 
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24-May-89 

SITE-SPECIFIC APPLICATION OF SELECTIVE NON-CATALYTIC 

REDUCTION TECHNOLOGY TO PORT WASHINGTON UNITS 1-5 

A. INTRODUCTION 

A site specific study of Selective Non-Catalytic Reduction 

(SNCR) technology as a possible BACT for Nitrogen Oxides 

(NO ) emissions at Port Washington Power Plant has been made 

in Response to the February 28, 1989 letter of Mr. Dale 

Ziege, Wisconsin Department of Natural Resources, Bureau of 

Air Management. The results of this study, which are 

discussed below, provide site-specific information to 

supplement the initial BACT analysis submitted by Wisconsin 

Electric, dated January 11, 1939. 

B. CONCLUSION 

Wisconsin DNR's letter of February 28, 1989 stated that the 

department concurred with WEPCo1s judgement (in WEPCo's 

January 11, 1989 BACT analysis) that SCR was inappropriate 

and net consistent with BACT for Port Washington. WEPCo had 

stated in the analysis that application of SCR would require 

equipment relocation, result in plugging of components during 

operation and cost an estimated $6,000-$23,000 per ton of NO 

removed.

 x 

This subsequent study of SNCR concludes that like SCR, SNCR 

application to Port Washington Power Plant will also require 

significant equipment relocation, result in plugging during 

operation, and cost an estimated $15,000-$62,000 per ton of 

NO, removed, 

*•% 

t 

Installation of SNCR on the five Port Washington Units, with 

the required modifications, is estimated to cost 

approximately $72 million in addition to the $80 million 

total estimated renovation cost stated in Wisconsin 

Electric's Certificate of Authority application of July, 

1987. It is incongruous that application of BACT would 

require changes to the plant as extensive as the work 

originally proposed by the company, work which the EPA 

contends triggered the PSD review in the first place. SNCR 

is, therefore, not BACT for Port Washington Power Plant. 

C. SUMMARY OF FINDINGS 

SNCR for NO emission reduction cannot simply be added at the 

Port Washington Power Plant. The existing configuration of 

the Port Washington boilers does not provide the proper 

combination of temperature, opportunity for mixing, and time 

for reaction necessary for effective NO reduction utilizing 

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SNCR chemical processes. Extensive and costly modification 

of the boilers, auxiliary equipment and boiler house 

structure is required to install the necessary reaction 

zones. As shown in Table 1, this effort is estimated to 

result in costs of $15,000 to $62,000 per ton of NO removed 

at capacity factors of 46-11*, respectively. SNCR is 

therefore, not cost effective when compared to our earlier 

estimates of $2,000-$10,000 per ton of NO removed for direct 

applications on boilers not requiring modifications. 

Application of SNCR without the required boiler modifications, will have significant adverse impacts on the boiler 

and auxiliary equipment caused by SNCR by-products, while 

resulting in only minimal reductions in NO emissions. 

Extensive modification of equipment and operation would be 

required to mitigate the detrimental effects. Inefficient 

use of the SNCR chemicals with the existing boiler configuration will also produce additional gaseous emissions whose 

characteristics are not clearly identified by the suppliers 

of SNCR systems or the technical literature at this time. 

The technical problems, limitations, and the level of commercial development of SNCR systems, demonstrate that SNCR is 

not BACT for NO emissions at Port Washington Power Plant. 

D. CHARACTERISTICS OF PORT WASHINGTON UNITS . 

Arrangement of Heat Transfer Surfaces and Resultant Flue Gas 

Temperatures 

The five Port Washington boilers are basically of the same 

unique natural circulation arch-fired design shown in Figure 

1, consisting of a furnace and a three drum Stirling convection boiler with a convection superheater. This convection 

area is confined in a compact space at the apex of the boiler 

(Areas C-F), adjacent to a small volume vestibule (Area B) 

located at the top of the furnace (Area A). The furnace 

walls are constructed largely of superheater and reheater 

surfaces, with only the front wall and a small portion of the 

rear wall containing water circuits. 

Coal is fed downward into the furnace from 20 individual 

burners with primary air, forming a fuel rich region. The 

resultant flame descends approximately 25 ft. along the front 

wall, through which additional combustion air is supplied. 

This arrangement results in staged combustion and low NO 

formation. The flame then turns and travels upward through 

the furnace, where heat is absorbed into the walls and 

burnout is completed. 

The hot gases leave the furnace and pass through a small 

tapering transition area (vestibule) from approximately 12 to 

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2'deep x 60' wide x 20' high into the convection passes. The 

variation in furnace heat transfer surface temperatures and 

rapid transition to the convection area results in a 

non-uniform upper furnace temperature profile. 

Gas temperature measurements were recently taken to document 

the actual gas temperatures and temperature profile 

(reference 6). The results illustrated on Figure 1 were 

taken from Unit 3 at full load (80 MW ) and low load (24 MW ) 

conditions, typical of all the units,edaily load following 

cyclic operation. At full load, furnace exit gas temperatures were 2000 - 2150°F. Full load gas temperatures 

drop to approximately 1250 F after the second pass of the 

convection section (Area D), 860°F after the third pass 

(Area E) and 750 - 800°F at the boiler gas outlet (Area G). 

At low load, gas temperatures taken at the same points ranged 

from approximately 1450°F at the furnace exit to 700 - 750 F 

at the boiler gas outlet. 

The Port Washington boilers are designed with comparatively 

tight tube spacing of both the steam and water tubes located 

in the convection area to maximize heat transfer and minimize 

the use of space and materials. The spacing between the 

tubes in the first convection pass is oniy 3 inches, as compared with other more typical designs which have tube 

spacings in similar areas of from 7 inches to 27 inches for 

boilers firing U.S. eastern and western coals, respectively. 

Tube spacing in subsequent passes of the Port Washington 

boilers reduces to a 1-7/8" clearance between tubes in the 

last passes (Areas E&F). The surfaces of the water-cooled 

first pass tubes are up to 400°F cooler than tubes in similar 

locations on more typical units. The cool surfaces, in 

combination with the tight tube spacing, result in slagging 

and pluggage whenever increases in ash loading occur. 

Slagging of the heat transfer surfaces is partially 

controlled through the use of first pass sootblowers. Any 

increase in solids loading, such as material deposited from 

the SNCR process, increases the slagging potential in this 

area which further exacerbates the pluggage problem and interferes with operation of the units. 

E. APPLICATION OF SELECTIVE NON-CATALYTIC REDUCTION (SNCR) 

TECHNOLOGY TO PORT WASHINGTON 

Technical Impediments and Impacts 

Effective application of SNCR requires specific and critical 

combinations of temperature with opportunities for unimpeded 

mixing and reaction to occur. As stated in the Bechtel report on SNCR technology (reference 3), the primary require-

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P.M 

r. 14 

ment for application of SNCR is that the reagents be injected 

into a temperature regime of 1600-2200°P, and remain in such 

regime for 0.2-0.5 seconds for effective NO reduction. 

.-rV 

The requisite temperature zones for SNCR in the existing Port 

Washington boilers occur in or near the first convection 

passes, where unimpeded mixing and the necessary reaction 

time are not available and cannot be provided through simple 

boiler modifications, making the application impractical. 

The literature (reference 5) and experiences reported from 

SNCR suppliers (references 3 and 7), show that not all 

boilers have suitable areas for the SNCR process. 

Modification of the Port Washington boilers to provide 

sufficient volumes for evaporation, mixing and reaction in 

the appropriate temperature range would involve relocation 

and reconstruction of virtually the entire boiler, and 

therefore is not economical for the Port Washington units. 

For the Port Washington boilers at full load, injection of 

SNCR reagents into or immediately after the first convection 

passQ(Area C, fig. 1) would be required to meet the 1600 -

2000 F gas temperature criteria. Injection of the reagent 

into the convection passes is unsuitable, however, because 

the chemicals would be injected directly onto the heat exchanging surfaces. The literature (reference 5), 

specifically states that the reagents should not be injected 

directly onto heat exchanging surfaces. In the West German 

brown coal application (reference 7), injection within five 

feet of heat transfer surfaces was eliminated after it resulted in poor reagent utilization and resultant pass-through 

of unreacted ammonia, called slip. Injection into the convection passes will result in limited NO reduction, tube 

surface fouling, pluggage of gas paths, fow reagent utilization and high ammonia slip. 

Injection into higher temperature locations in the vestibule 

(Area B) or nearer the furnace (Area A) would result in significant thermal decomposition of either urea or NHg and 

oxidation to NO^, thus increasing total NO emissions. Injection downstream of the boiler gas outlet (Area G) would be 

ineffective due to the low gas temperature and would result 

in minimal N0x reduction with a large portion of ammonia and 

the other unreacted reagents passing out of the boiler. 

Another significant requirement cited by Bechtel for effective use of SNCR is to provide an appropriate volume within 

the temperature range where evaporation (aqueous urea 

solution), mixing and reaction of the reagents can occur and 

the chemical reactions can proceed to completion. Whereas 

successful prior demonstration of these processes were 

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characterized by injection into large furnace volumes or 

other cavities (without interfering structures) which allowed 

effective mixing and reactions to occur, the Port Washington 

boilers are characterized by compactness and lack the 

required cavities in the appropriate temperature range. The 

necessary cavity to provide a mixing and reaction time of 0.2 

to 0.5 seconds is not provided in the convection area, where 

only 1-1/2• maximum clearance, or a residence time of less 

than 0.05 second, exists between tube banks. 

During low and moderate loads, flue gas temperatures decrease 

and the effective temperature "window" for SNCR would move 

out of the convection area into the vestibule and upper 

furnace (Areas A and B) . Multiple injection points have been 

used in prior applications (reference 3) to follow changes in 

load, however, the variety of heat transfer surfaces in the 

furnace yields a non-uniform horizontal temperature profile 

of the gas in this region. Uniform temperature in the plane 

of the injection points is essential for effective NO 

reduction (reference 3). Injection into this area at low and 

moderate loads will result in poor reagent utilization, high 

ammonia slip and limited NO reduction. 

X 

Additional Consequences of SNCR 

The application of SNCR to Port Washington without extensive 

boiler reconfiguration would produce a number of serious 

side-effects resulting from the production of various 

ammonium sulfate compounds in the boiler. These side 

effects will include boiler, economizer (Unit 1), and air 

heater pluggage, reduced precipitator performance, ash 

handling equipment corrosion, increased wastewater treatment 

requirements and increases in ultimate gaseous emissions. 

Associated with the anticipated low NO reduction and low 

utilization of reagents for SNCR application at Port Washington is ammonia slip. The reactions of ammonia with S03 

present in the flue gas are of particular concern. 

The fuel used at Port Washington is currently a coal containing approximately 1.5* sulfur by weight, and only a 

slight reduction in sulfur is anticipated in future coals. 

The Port Washington fuel sulfur content is three to eight 

times that of the fuels used in prior applications of 

chemical NO reduction techniques (reference 3) . The quantity of S03 in the flue gas and subsequent reactions with ammonia to form ammonium sulfate and bisulfate will be proportionately greater than in past applications. The sulfates 

will deposit on the boiler, air heater, I.D. Fan, ductwork 

and precipitator surfaces. 

At the gas temperatures in the existing Port Washington 

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economizer and air heater, ammonium bisulfate is a sticky 

liquid which will collect on the heat transfer surfaces with 

flyash, forming deposits which may only be removed effectively with off-line water washing, as determined during review of SCR technology and applications (reference 4). The 

current plate-type air heaters have insufficient provisions 

for cleaning and narrow (5/8" design) gas passages, which 

would quickly plug with deposits. Conversion of the Port 

Washington plate-type air heaters to Ljungstrom-type air 

heaters, with specially constructed baskets and washing 

provisions is required to address the increased fouling 

(reference 4) in this area. 

Consumption of flue gas S03 by excess NH3 will lead to higher 

flyash resistivity and reduced precipitator performance. 

This, combined with additional particulate loading from ammonium sulfate production would require an increase in precipitator surface area to maintain precipitator collection 

capability and meet current particulate emission and opacity 

requirements. 

Although the exact quantities and distribution of deposition 

of ammonium sulfates throughout the gas path can not be determined from the current literature, these corrosive deposits would nonetheless require frequent removal by water 

wash-down. The resultant drainage would have to be routed to 

the existing wastewater treatment facility, increasing the 

influent total dissolved solids (TDS) and total suspended 

solids (TSS) to the facility. In response, additional 

equipment for pH neutralization, solids coagulation, 

flocculation, and sludge handling would be required. 

Discharge TDS levels are expected to increase, despite 

additional treatment equipment. 

Ammonium sulfates collected in the precipitator with the 

flyash will adversely affect plant ash handling and transport 

equipment through pluggage and corrosion, and upon disposal 

will modify the characteristics of the flyash landfill 

leachate. 

Ultimate SNCR gaseous emissions have not been characterized 

in past industry demonstrations. Therefore, potential 

emissions from an application to Port Washington are unknown. 

Little information exists in the literature on the fate of 

unreacted ammonia or urea and enhancer combinations. The 

information which is available indicates that flue gas 

emissions of ammonia (slip) and CO- (from urea decomposition) 

will increase. 

Measurement of ammonia slip is an important function. As 

described above, control of the slip represents control of 

the entire process for efficiency and mitigation of 

- 6 -
P.17 

rtti-dl-W TUE 9:4o riiX Nu. uuUuUUUUUUuUUUUUUUUU r. 1 ( 

downstream effects. Importantly, Bechtel's report (reference 

3 ) , cites that no commercially accepted continuous emission 

monitor for ammonia is available. Therefore, automatic 

control of the SNCR system to minimize ammonia slip in 

response to changes in the process environment is not 

available. Without monitoring and automatic control, changes 

in operating conditions such as fuel characteristics, ambient 

temperature, excess air, and furnace slagging will result in 

uncontrolled ammonia slip. 

F. COMMERCIAL READINESS 

Our review of the current state of the art in NO removal 

technology confirms that there have been no applications of 

SNCR on U.S. pulverized coal boilers or on any boiler using a 

fuel containing more than 1* sulfur by weight. All prior 

successful applications have been on boiler and furnace configurations with volumes and temperatures conducive to the 

process in combination with low sulfur fuels which minimize 

downstream problems with ammonia slip and ammonium sulfates. 

As an example, the West German application, (reference 7} was 

fueled with "Brown Coal" containing 0.2* Sulfur and 60* 

moisture. Combustion of this fuel requires large furnace 

volumes. The combination of the large furnace and high 

moisture fuel resulted in a maximum furnace temperature of 

2 200 F, which is relatively low, and making most of the 

furnace volume available as the SNCR reaction zone. 

For the Port Washington boilers, SNCR experience and development has not yet reached the point of commercial availability 

wherein a contract can be entered into with enforceable performance warranties necessary and prudent to assure the 

operator's confidence that air permit conditions can be routinely met. This technology is therefore, not available as a 

technique to comply with NO emission limitations. 

G. COST 

There is no experience with SNCR on U.S. pulverized coal 

fired boilers. This, coupled with extensive reconstruction 

of these unique boilers and consequential modification and 

relocation of auxiliary equipment necessary to accommodate 

SNCR technology, requires order cf magnitude estimates, We 

have, however, endeavored to identify and estimate the 

potential installed and operation costs. 

On the following pages. Table 1 summmarizes the estimated 

cost per boiler for SNCR at Port Washington Power Plant. 

Included is the estimate for SNCR equipment and installation 

alone, as contained in our January, 1989 submittal, and the 

estimated costs for process development and testing, and 

modification of the boiler and ancillary equipment, to adapt 

- 7 
P.18 

:D-ci~A[i iU_ c3*4b FAX Nu. uuuGGGGuGuGGGGGuGGuU r. 10 

the facility for SNCR operation. In areas where SNCR 

modifications coincide with planned renovation projects, the 

additional cost (differential) above the estimated renovation 

cost is shown. Tables 2 and 3 provide more details of the 

costs which comprise the estimate. 

- 8 -
I rv 

TABLE 1 

PORT WASHINGTON POWER PLANT 

SNCR TECHNOLOGY 

COST ESTIMATE PER UNIT, 1990$ 

rr 

cr 

NOx removal 

NOx Removal @ MCR 

(Lb/Hr) 

Installed Cost 

Annualized Installed Cost 

Fixed Annual O&M Cost 

Variable O&M Cost of 

NOx Removed ($/Ton) 

NOx Removed Annually * 

11* Capacity Factor (Tons) 

46* Capacity Factor (Tons) 

bote 

Annual Cost 

11* Capacity Factor 

46* Capacity Factor 

L>o% 

Annual Cost ($/Ton NOx Removed) 

11* Capacity Factor 

46* Capacity Factor 

6tffo 

1/8 9 Submitta l 

SNCR Onlv 

3 0 * 

90 

3,637,00 0 

313,00 0 

103,00 0 

200 

Modification s and 

Ancillar y Equipment 

3 0 * 

9 0 

14,433,00 0 

1,283,00 0 

979.00 0 

_ 

SNCR, 

Tota l 

Modification s & 

Ancillar y Eauipmen t 

18,070,00 0 

1,596,00 0 

1,082,00 0 

2 0 0 

4 3 

181 

>30» 

425,00 0 

452,00 0 

Ho l, °°o 

> 

9,88 0 

2.50 0 

t,1t»* 

4 3 

161 

230 

2,262,00 0 

2,262.00 0 

2 it * ot>o 

52,60 0 

12,50 0 

Vtrsr 

2 

2 

4 3 

181 

3-^6 

,687,00 0 

,714,00 0 

62,48 0 

15,00 0 

-x. 

cr: 

* Annual Capacity Factors For Port Washington Units are expected to range from a 

minimum of 11* to a maximum of 46* for the remaining life of the units. 
iable i 

PORT MASIilNGTON PGUHR PLANT 

SNCR MODIFICATIONS FOR NQK RfcMOVAL 

ESTIMATE!! COSTS PER UNIT, MX COST'S IN S 1990 May 11, 1989 

D 

a 

c 

Ljungsti-c-m Air Heater 

Fans and Duct Mods. 

Precipitator Mods. 

Wastewater Modifications 

CEM'a 

Development 

it Modelling 

Mashdowns 

forced Outages 

Boiler and Boilerhouse 

Modifications 

TOTALS 

INSTALLED 

COST 

$2,100,000 

$2,100,000 

$809,000 

$50,000 

$150,000 

$9,224,000 

$14,433,000 

ANNUAL 

OSM 

$30,000 

$110,000 

$800,000 

SI6,500 

$8,000 

$14,600 

$979,100 

(Differential Coat, replacement with Ljungstrc-ro 

vs Plate-type replacement air heater) 

(One-fifth of estimate for a five unit facility) 

(Differential cost, boiler & bollerhouse modifications 

versus planned replacement of rear steam dram) 

c 

n 

AMORTIZED INSTALLED COST. AT 6.5* 

18 YEARS = > $1,203,381 / YEAR 

At ao Mw. NQ K Produced = (8B0 M-Ktu/Hr, x <0.34 lb N0x/M4Btu) 299 lb/lir 

CAPACITY 

FACTOR 

60% 

50% 

46% 

20% 

11* 

10% 

NOXCOST 

EFFECTIVE 

HOURS AT BO l-W 

5,256 

4,380 

4,030 

1.7S2 

964 

876 

KOX (TOM 

PRODUCED 

(0.34 LB/WlBtu) 

786 

655 

603 

262 

144 

131 

S/YR) 

REM3VED 

(30% REM.) 

236 

197 

181 

79 

43 

39 

ANNUAL 

FIXED OSM 

$979,100 

$979.100 

$979,100 

$979,100 

$979,100 

$979,100 

18 YEAR 

ANNUALIZED 

INST. OOST 

$1,283,381 

$1,283,381 

$1,283.3B1 

$1,283,381 

$1,283,381 

$1,283,381 

TOTAL 

AMUUAL COST 

$2,262,481 

$2,262,481 

$2,262,481 

$2,262,481 

$2,262,481 

$2,262,481 

$/T0M 

NOX REMOVED 

$9,691 

$11,510 

$12,510 

$28,774 

652,316 

$57.S4B 

3: 

c 

c 

cr 

c 

c 

c 

•c 

c 

c 

c 

CZ 

c 

c 

c 

c 

c 

c 

c 

c 

c 

c 
P.21 

i i_u c i ou i U L o • -*o THA NU. UUUUUUUUUUUUUUUUUUUU r. di 

Table 3 

PORT WASHINGTON POWER PLANT 

ESTIMATE FOR BOILER MODIFICATIONS 

TO ACCOMODATE SNCR 06/22/89 

Activity 

Estimated 

Cost $K 

Redesigned Convection 

Superheater and Boiler 

$10,000 

Boiler Support 

Structural Revisions 

$500 

Building Modifications 

Found., Facade, Struct, 

$500 

Coal Conveyor Relocation 

Coal Bunker Revision 

Lighting & Fire Protect. 

Subtotal 

A/E @ 8* 

Total M&L 

Contingency @ 15* 

Total For Modifications 

Current Estimate Boiler 

Drum Replacement Unit 3 

Differential Cost 

$200 

$150 

$150 

$11,500 

$920 

$12,420 

$1,863 

$14,283 

$5,059 

$9,224 

For Boiler Modifications 

BLREST -11-
rcD-dz-au m t y.^a FAX NO. OOOOOOOOOOOOOOOOOOOO P, 71 

P.22 

FIGURS 1 

TYPICAL PORT WASHINGTON BOILER CROSS-SECTION 

FLUE GAS TEMPERATURES AT FULL LOAO 

I-gCESP 

A - FURNACE 

B - VESTISUtB 

C - CONVECTION AREA FIRST PASS 

D - CONVECTION AREA SECOND PASS 

E - CONVBCTICN AREA THIRD PASS 

P - CONVECTION AREA FOURTH PASS 

G - BOILER GAS OUTLET 
P.23 

rttr^-yu lUt o'.fd FAX NO. OOOOOOOOOOOOOOOOOOOO P.23 

-,» 

References 

1. "Port Washington Power Plant Units 1-5 BACT for NO 

Emissions", attachments 1 and 3, memo, Roger Dodds*, 

Wisconsin Electric to Dale Ziege, Wisconsin Department 

of Natural Resources, January 11, 1989. 

2. Memo, Dale Ziege, Wisconsin Department of Natural 

Resources, to Roger Dodds, Wisconsin Electric Power 

Company, Memo No. 4530, February 28, 1989. 

3. Evaluation of Selective Non-Catalytic Reduction 

Technologies for Wisconsin Electric Power Company, 

Bechtel Power Corporation, May, 1989. 

4. Updated Technical and Economic Review of Selective 

Catalytic NO Reduction Systems, J. E. Damon, P. A. 

Ireland and D. V. Giovanni, EPRI/EPA Symposium on 

Stationary Combustion Nitrogen Oxide Control, New 

Orleans, March 1987. 

5. U.S. Patent 4,777,024, Multi-stage Process for Reducing 

the Concentration of Pollutants in an Effluent, Epperly 

et al, October 1988. 

6. Temperature Measurements of Port Washington Unit 3, Te9t 

Data taken by V. Ashtemenko, Wisconsin Electric Power 

Company, March 21, 1989. 

7. NO Control in a Brown Coal-Fired Utility Boiler, .J. 

Horfman, J. Bergmann, D. Bokenbrink, EPA/EPRI Joint 

Symposium on Stationary Combustion NO Control, San 

Francisco, March 6-9, 1989. 

_ 13 _