p.1 

OAR Box 1778 

Prepped by Ollie Stewart 

Document Number: 

234) 11-1-14 

Docket Number: 

A-90-06 

Printed 10/28/2008 9:51:02 AM Sheet 234 of 276 
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C©SSSI^@KI©l^]C^/Jv]I^©^AWDMM 

Fihfof: ^530-1 D„9: May 2, 1990 

To: Donald F. Theiler - AM/3 

From: Allen J . Hubbard - AM/3 

sub/ecu Best Available Control Technology (BACT) for WEPCO-Port Washington N0X 

Emissions 

Wisconsin Electric'Power Company (WEPCO) has submitted a permit application to 

the Department pursuant to WEPCO's planned renovations at its Port Washington 

Power Plant. This application is the culmination of nearly two and a half 

years of study by WEPCO and others with respect to how such a project can be 

permitted in accordance with the requirements of the Clean Air Act. To make a 

long story short, WEPCO's application assumes that only the post-renovation 

nitrogen oxides (NOx) emissions will be subject to the PSD rules, and 

therefore to continuous application of best available control technology 

(BACT). WEPCO will, through the use of enforceable permit conditions, be able 

to "net out1' of NSPS requirements for particulates and S02. 

It is important to note that WEPCO could net out of PSD for NO^ if the Port 

Washington facility controls some moderate amount of NO . bevond current plant 

practice, in the very same way that WEPCO is netting out of NSPS for 

particulates and SO.. 

The attached analysis of the BACT portion of the application considered 

information from three sources: 

1. Bechtel, acting on behalf of the applicant 

2. Vendors (Exxon and Hitachi) of N0X control equipment 

3. The literature (N0X conferences, journal articles, BACT/LAER 

Clearinghouse, etc.) 

This analysis concludes that the existing combustion techniques and operating 

practices employed at the Port Washington Power Plant represent the best 

available control technology (BACT) for the NOx emissions from this facility's 

arch-fired furnaces. The Department further determines that the appropriate 

emission limit for;each of the boilers at the Port Washington Power Plant, 

consistent with BACT, is 0.4 lb NO/MMBTU. Compliance with this emission 

limit shall be determined on the basis of a Method 7 of 40 CFR Part 60, 

Appendix A stack test for at least one of the four boilers to be permitted 

(Units 1-4). 
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Best Available Control Technology (BACT) 

for 

Emissions of Nitrogen Oxides (NOx) 

from 

Wisconsin Electric Power Company's 

Port Washington Power Plant 

Mav 2. 1990 

Background 

Wisconsin Electric Power Company (WEPCO) plans to renovate the existing coalfired arch-fired boilers at its Port Washington Power Plant. The U.S. EPA and 

the courts have decided that the proposed project will be subject to the NSPS 

and PSD rules for the emissions of nitrogen oxides (NOx) following the 

renovations at the plant. This analysis will focus on the PSD issue of 

applying the best available control technology (BACT) to the renovated plant's 

N0X emissions. 

Control Alternatives 

In order to consider the possible NOx control strategies for a coal-fired 

arch-fired boiler, which is the only type of boiler at the Port Washington 

Power Plant (PWPP), the Wisconsin Department of Natural Resources (the 

Department) and WEPCO identified a number of technologies which might be 

successfully applied to control NOx emissions from PWPP's boilers. Those 

technologies are: 

1. Advanced Coal Pulverizing 

2. Combustion Modifications 

3. Selective Catalytic Reduction (SCR) 

4. Selective Non-Catalytic Reduction (SNCR) 

1. Advanced Coal Pulverizing 

In August of 1989, the Department identified advanced coal pulverizing as a 

potential M L emission reduction technology for application to arch-fired 

furnaces. WtPCO subsequently evaluated a representative system, Mitsubishi's 

MRS Pulverizer, which has been successful in Japan under certain conditions at 

reducing NOx emissions from coal-fired power plants. 
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As early as 1973, Mitsubishi began to develop low-NOx burners and combustion 

systems in response to new emission regulations from the Japanese government. 

The MRS Pulverizer is a new-generation coal pulverizer with an integral rotary 

particle size classifier. With a significantly enhanced ability to control 

both the degree and consistency of fuel particle fineness, roughly a 10% 

reduction in NOx emissions can be achieved relative to conventional 

pulverization techniques. However, the much larger potential for N0x emission 

reduction comes from the ability to operate a coal-fired furnace equipped with 

the MRS Pulverizer at significantly lower levels of excess air. That is, the 

use of the MRS Pulverizer in conjunction with 33 or more percent less excess 

air will result in a 40-50% NOx reduction. 

2. Combustion Modifications 

The applicant's BACT analysis considered several types of potentially 

applicable combustion modification techniques for application to the PWPP 

arch-fired furnaces. Those techniques are: low excess air operation, low-NOx 

burners, staged combustion, burner/furnace wall re-orientation, and flue gas 

recirculation (FGR). The analysis states: 

The replacement burner and staged combustion techniques reduce N0X 

formation by maintaining the air/fuel ratio initially at substoichiometric 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. 

3. Selective Catalytic Reduction (SCR) 

The investigation of selective catalytic reduction (SCR) as a potential NOx 

emission reduction technology for the arch-fired furnaces at PWPP has spanned 

virtually the entire two and a half years of the development of BACT for this 

project, Both the applicant and the Department have invested considerable 

time and effort into the evaluation of SCR applicability to the renovated Port 

Washington boilers. This BACT determination reflects the state-of-the-art of 

SCR with respect to its retrofit application to coal- fired arch-fired 

boilers, as of May 2, 1990. 

SCR 1s a post-combustion N0X control technology involving the injection of 

some ammonia (NH3) into the flue gases, in the presence of a catalyst 

(typically vanadium pentoxide). Under these conditions, a gas phase reduction 

reaction occurs wherein the ammonia combines with flue gas nitric oxide (NO), 

nitrogen dioxide (N02), and oxygen (O2) to yield molecular nitrogen and watar: 

4NH3 + 4NO + 02 

4NH3 + 2N02 + 02 

> 4N2 + 6H^0 

> 3N2 + 6H^0 
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SCR catalysts generally perform best when they see flue gases having 

temperatures in the range of 610 - 750 *-?, although vendors such as Hitachi 

and Mitsubishi have developed specialized catalysts to operate effectively 

(under certain conditions) at temperatures as low as 400 °F or as high as 

800 °F. In addition, Mitsubishi is oresently developing "high-temperature" 

catalysts, for use with 950 - 1050 °f flue gases. 

Ammonia is supplied to the flue gases upstream of the SCR reactor 1n an amoun 

roughly stoichiometric to the level of NOw present. The reactor is designed 

fjOv reduction reactions to 

Common SCR design 

J X t.u.ii_rui ttiiu a maA i IIIUIII aiiniuii i a *>ilp (i.e. , the 

unreacted ammonia in the gas stream) of 5 ppm. 

roughly stoichiometric to the level of NOx present. The re; 

to have enough surface area to allow the f)ox reduction read 

extensively occur and to scavenge most of the residual NH*. 

criteria are 80 - 90% NOx control and a maximum ammonia $Ti| 

Two SCR configurations are applied in practice: a "hot-side" arrangement, in 

which the reactor is inserted upstream of the air heaters to take advantage of 

the 600 - 750 T flue gas temperatures generally available at such locations, 

and a "cold-side" arrangement, in which the reactor is located downstream of 

the air heater and (usually) other emission control devices to take advantage 

of flue gas particulate and/or S02 clean-up. 

NH3 

N 

Air 

Heater 

Bciler 

SCR ESP 

Hot-Side, High Dust SC R 

Stack 

Air 

Heater 

Sj |J~. 

Soiler 

ESP 

Cold-Side SC R GGH = gas-to-gas heat exchanger 

4, Selective Non-Catalytic Reduction 

Early in the development of N0X BACT for Port Washington's boilers, WEPCO 

considered the application of selective non-catalytic reduction (SNCR) to this 

plant's arch-fired furnaces. In May, 1989, Bechtel finalized a report to 

WEPCO entitled "Evaluation of Selective Non-Catalytic Reduction Technologies 

for Wisconsin Electric Power Company." That report concluded that "the 

effectiveness of these (SNCR) processes has not been established", so that 
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Bechtel believed that SNCR was not yet ready for successful commercial 

application to "pulverized coal-fired boilers in the United States." 

In August, 1989, the Department responded to WEPCO's May 1989 submittal, w,. 

paragraph essentially agreed with WEPCO's assessment of SNCR feasibility for 

the PWPP boilers: 

While the selective non-catalytic reduction (SNCR) 

techniques evaluated in your BACT analysis, urea 

injection and ammonia injection, are promising 

technologies for NO« control, we agree with your 

conclusion that SNCR is not yet ready for commercial 

application to pulverized coal, arch-fired utility 

boilers such as the units at Port Washington. It 

appears that the existing firing configurations make 

application of SNCR problematic for these particular 

sources, if for no other reason than excessive 

retrofit costs. 

In April, 1990 the Department received new information from Exxon regarding 

the feasibility of Exxon's Thermal DeNOX (ammonia injection) process for 

controlling N0X emissions from Port Washington's arch-fired furnaces. As a 

result of this new information, the Department will now re-consider SNCR in 

the development of BACT for WEPCO's plant renovation project at Port 

Washington. 

There are two principal types of SNCR available today to control NOx 

emissions: ammonia injection (Thermal DeNOX) and urea injection (NQJDut), In 

both cases, a reagent is injected into the flue gas stream and reacts with 

available NOx to form molecular nitrogen and water vapor. In addition, urea 

injection produces carbon dioxide: 

NO + NH3 + 1/4J ----> N2 + 3/2^0 (DeNOX) 

2NO + C0(NH2)2 + 1/2-g ----> 2N2 + C02 + 2H£ (NO^ut) 

A carrier gas, typically steam or air, introduces the ammonia or urea into the 

flue gas stream. The design and placement of the injection nozzle is a 

crucial element in the system, since the process depends on the injection 

momentum for complete mixing of reagent and NOx. In situations where flue gas 

temperatures vary substantially with daily levels of operation, multiple 

injection locations are used to ensure that the reagent 1s always injected 

into flue gases with the right temperatures. Common design criteria for SNCR 

are 50 - 70% N0X control and a 5 ppm ammonia slip. 
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Technical Feasibility of Control Alternatives for Port Washington's Boilers 

The Department believes that neither advanced coal pulverizing nor combustion 

modification is technically feasible for application to arch-fired furnaces, 

such as those at WEPCO's Port Washington Power Plant. And while there has yet 

to be a single commercial demonstration of either the SCR or SNCR technology 

on a coal-fired boiler in the United States, the Department believes that both 

of these technologies will soon be successfully applied to control N0X 

emissions from existing pulverized coal boilers in the U.S. In fact, SCR is, 

as of May 2, 1990, technically feasible for application to WEPCO's Port 

Washington Power Plant. On the other hand, SNCR does not yet appear to be 

feasible for WEPCO's potential application. 

1. Advanced Coal Pulverizing 

The Department concurs with Bechtel's assertion that advanced coal pulverizing 

bv itself is technically infeasible for Port Washington's arch-fired furnaces. 

Although this technology can reduce N0X emissions by about 10% by itself, it 

is really intended to be used as a technique to allow a boiler to operate at 

reduced excess air levels, usually in conjunction with new generation low-N0x 

burner technology. 

Bechtel's analysis of the applicability of MRS Pulverizers to Port 

Washington's arch-fired furnaces concludes that "although the MRS pulverizer 

may provide greater control of coal fineness than the existing pulverizers, 

the use of the MRS pulverizer with the existing boilers will not reduce the 

alraedy low N0X emissions at Port Washington Power Plant, but instead would 

likely increase NOx emissions." This conclusion is based on the observation 

that the coal fineness and fuel/air distribution required for arch firing 

differs from the low-NOx burner - overfire air configuration for which the MRS 

Pulverizer was developed and apparently requires. 

Arch firing is characterized by a long, delayed combustion flame which 

represents a kind of staged combustion. Bechtel notes that "appropriate heat 

transmission in the furnace requires the marriage of a boiler with a burner 

and flame pattern which distributes the heat necessary to produce desired 

steam conditions without producing local overheating. For the Port Washington 

boilers, the long, delayed combustion flame is the appropriate match for the 

furnace." 

WEPCO's long operating experience with arch firing has resulted in welldefined inges for such interrelated operating variables as coal fineness, 

excess _,r, and individual burner firing rates to maintain the proper flame 

shape and heat distribution in the furnace. As a result, Bechtel believes 

that "operating changes to further reduce N0X formation, such as a significant 

reduction in excess air or coal fineness, will alter the flame shape and/or 

intensity. A shorter more intense flame will adversely effect heat absorption 

and steam '•.-T-perature control, and would likely increase N0X emissions." 

The Department finds these arguments to be persuasive. We agree that the MRS 

Pulverizer technology appears to be incompatible with Port Washington's arch-
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fired furnaces. Consequently, the Department concludes that such pulverizers 

are technologically infeasible for controlling NOx emissions from the existing 

Port Washington Power Plant. 

2. Combustion Modifications 

All of the combustion modification strategies reasonably applicable to archfired boilers, that 1s low excess air operation, low-NOx burners, staged 

combustion, burner/furnace wall re-orientation, and flue gas recirculation 

(FGR), are already (at least to some extent) inherently employed at Port 

Washington in the design and configuration of its arch-fired furnaces. 

Furthermore, these combustion modification techniques applied to conventional 

boilers rarely, if at all, result in lower NOx emissions than the typical N0X 

emission rate of 0.4 lb/MMBTU experienced by the Port Washington boilers. 

Therefore, the kinds of combustion modification strategies that would 

significantly reduce N0X emissions from most conventional boiler types simply 

would not be effective when applied to arch-fired furnaces such as those at 

Port Washington. 

The delayed combustion flame which characterizes arch firing is a form of 

staged combustion. The existing burners, their arrangement, and excess air 

requirements are all matched to the existing furnace to produce the best 

combustion pattern for the furnace. In addition, the primary combustion air 

is delivered to the furnace at a relatively low (for pulverized coal firing) 

temperature (less than 600 °F) because the plant's unique coal feeding system 

does not require hot air for coal drying. The effect of this "lowtemperature" combustion air on the furnace combustion is very much the same as 

the effect of FGR, which also minimizes the combustion temperature (through 

dilution of the fuel/air mixture in the combustion zone with low-oxygen 

content flue gas). 

The Department concludes that combustion modifications to Port Washington's 

arch-fired boilers would prove to be ineffective at reducing the N0X emissions 

below current levels. In that sense, such modifications appear to be 

technically infeasible for the renovation project. 

3. Selective Catalytic Reduction (SCR) 

WEPCO's BACT analysis argues very strongly that SCR technology is not yet 

technically feasible for application to pulverized coal boilers in the United 

States. Unresolved concerns about flue gas unburned carbon content (WEPCO 

refers to this phenomenon as loss of ignition, or LOI), chemical properties of 

U.S. coal combustion product gases, air heater pluggage, and catalyst disposal 

(among other things) appear to make the successful application of SCR at Port 

Washington problematic. On the other hand, SCR vendors (Hitachi, for example) 

believe that the technology is ready for commercial application in the U.S. 

For Port Washington in particular, the high carbon carryover in the flue gases 

presents an additional roadblock for successful SCR application. In the 

absence of careful planning, the hot surfaces of the SCR could ignite the 

carbon in the flue gas. A resulting fire would be clearly undesirable, but 

Por^ Washington experiences fires from time to time in "downstream equipment", 
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including air heaters and precipitators. The Department is unconvinced that 

the likelihood of a fire in an SCR is any greater than it is in an air heater 

or ESP, since all of these devices contain hot surfaces and high-carbon flue 

gas streams. Port Washington has and will continue to control particulate 

emissions, with or without an occasional control device fire. Analogously, 

the Department will not rule out the application of SCR technology to Port 

Washington on the basis of fire potential alone. Among other mitigating 

techniques, the SCR inlet temperature could be limited to some temperature 

"safely" below the ignition temperature of fixed carbon in a coal combustion 

products gas stream. 

Because there has yet to be a single commercial demonstration of the SCR 

technology on a coal-fired boiler in the United States, the Department 

recognizes the hesitation of the applicant to simply transfer the successes of 

SCR in Japan and Germany to PWPP. It is true that the coals burned in Japan, 

Germany, and the U.S. can differ significantly, especially with respect to the 

contents of certain trace elements and sulfur. Such fuel differences result 

in different flue gas characteristics, which may lead to the premature fouling 

or corrosion of downstream equipment, SCR plugging, or other operational 

difficulties. However, the Department believes that in the very near future 

SCR advocates will be able to show that U.S. coals and boilers, including 

those at the Port Washington Power Plant, are in fact compatible with SCR 

technology. 

At the same time, the Department is unconvinced by the Bechtel SCR assessment 

that the successful demonstrations of SCR in Japan and Germany are not 

sufficiently transferable to PWPP to allow this technology to represent BACT. 

The lack of data from the application of the SCR technology to U.S. coal 

firing also means that this technology has not been dempnstrated to be 

infeasible for Port Washington's boilers. Clearly, SCR has been successful in 

a wide variety of coal firing situations in Japan and Germany, and that is 

encouraging for the potential application of the technology to coal-fired 

boilers in the U.S. In other words, the Department believes, as of May 2, 

1990, that SCR is technically feasible for controlling N0X emissions from the 

arch-fired furnaces at WEPCO's Port Washington Power Plant. 

4. Selective Non-Catalytic Reduction (SNCR) 

As is the case with SCR, the potential application of selective non-catalytic 

reduction (SNCR) to the arch-fired furnaces at PWPP is not straightforward. 

Early in the development of BACT for PWPP's NOx emissions, WEPCO noted that 

the best flue gas temperatures for SNCR control most often occur somewhere in 

the convective passes of the PWPP boilers. This statement has two important 

implications for the liklihood of successful SNCR application at PWPP: the 

reagent would have to be injected within or close to superheater tube banks 

and possibly at several different locations from time to time to respond to 

boiler load shifts. It 1s Exxon's April, 1990 assertion to the Department 

that these latter concerns have been successfully addressed that formed the 

basis for the Department's re-consideration of SNCR as a potential BACT 

candidate for PWPP's arch-fired boilers. 
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Other potential problems associated with SNCR include high (more than 20-30 

ppm) ammonia slip and air heater plugging from ammonium sulfate or bisulfate 

deposition. Since there has not yet been a commercial demonstration of the 

SNCR technology applied to a pulverized coal-fired boiler in the U.S., the 

jury is still out on whether SNCR would be successful at controlling N0X 

emissions from the arch-fired boilers at PWPP. 

On the other hand, Exxon indicates that its Thermal DeNOX technology has 

demonstrated the ability to control 50-60% of the NOx emitted from a German 

wet bottom boiler firing a 1.5% sulfur coal and has shown similar success in 

Japan controlling N0X from the combustion of a 3-4% sulfur petroleum coke. 

According to Exxon, the 50% NOx reduction observed at these units was achieved 

without downstream ammonium sulfate or ammonium bisulfate deposition 

problems. Exxon has found that two techniques appear to prevent this 

deposition: designing for less than 5 ppm NH3 slip (to prevent bisulfate 

formation), or providing excess ammonia at injection (3:1 NH3:S03 mole ratio) 

to preferentially form ammonium sulfate, which is a dry precipitate and passes 

through boiler system components "fairly easily" without the deposition 

problems associated with the bisulfate. 

While Exxon's experiences mentioned in the previous paragraph are encouraging, 

the fact remains that neither Thermal DeNOX nor NO^ut has been commercially 

applied or even tested on pulverized coal-fired boilers in the U.S. It is 

certainly true that the ultimate success of these technologies is directly 

related to specific boiler system parameters, including boiler configuration, 

flue gas chemistry, uncontrolled NOx concentration, reagent reaction time, and 

flue gas temperature. Finally, as of May 2, 1990, the Department does not 

possess any documentation to demonstrate the successful application of SNCR to 

more than one or two coal-fired boilers anywhere in the world. 

We understand that Exxon is preparing a report for us which will argue that 

Thermal DeNOX can be successfully applied to control 50% of the NOx emissions 

from the renovated boilers at PWPP, and perhaps that report will be 

persuasive. But at present, the Department concludes that the successful 

demonstrations of SNCR in Germany are not sufficiently transferable to PWPP to 

allow this technology to represent BACT. In other words, the Department 

believes, as of May 2, 1990, that SCR is technically infeasible for 

controlling N0X emissions from the arch-fired furnaces at WEPCO's Port 

Washington Power Plant. 
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Economic Feasiblitv of Control Alternatives for Port Washington's Boilers 

The Department finds that the costs associated with the only technically 

feasible control technology for controlling the NOx emissions from PWPP's 

boilers, selective catalytic reduction, prohibit this technology from 

representing BACT. Whether WEPCO would install and operate a hot-side or. a 

cold-side SCR, the economic impact is the same: roughly $8,300 - $8,500 per 

ton of N0X controlled. The Department believes that this level of control 

cost is well in excess of the range of costs appropriate for N0XBACT. 

At the present time, the Department has no reason to alter Bechtel's economic 

evaluation of the application of SCR to a boiler at the Port Washington Power 

Plant. The results of Bechtel's investigations are summarized below. 

Cold-Side SCR 9 80% N0X Removal 

Installed Costs (per Unit, 1989 dollars) 

SCR System (Bechtel estimate) 17,674,525 

WEPCO Costs (engineering & overhead) 1,704,719 

SARA Study 3,000 

NH3 & Air Heater Enclosures 90,600 

Auxiliary Power (flue gas reheating) 400,000 

Baghouse (control of increased PM from SCR) 4,700,000 

Wastewater Treatment Expansion (component wash) 809,000 

TOTAL INSTALLED COST $25,381,844 

2. Annual Cost (per Unit, 1989 dollars, 60% capacity factor) 

VARIABLE COSTS 

Ammonia 64,386 

Electricity 104,188 

Catalyst Replacement 1,700,000 

Catalyst Disposal 25,000 

Steam 7,250 

Bag Replacement 766,667 

Heat Rate Penalty 235,460 

SUBTOTAL $2,902,951 
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FIXED COSTS 

Labor 620,321 

Material 30,400 

CEM Contractor 15,000 

Washdown 8,000 

Wastewater Treatment 800,000 

SUBTOTAL $1,473,721 

ANNUALIZED INSTALLED COST (amortized @ 5.5%, 18 years) $2,256,951 

TOTAL ANNUAL -COST $6,633,623 

3. Annual NOx Reduction (80% x 973 tons) 779 tons 

4. COST PER TON OF NOx CONTROLLED $8516/ton 
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Hot-Side SCR 0 80% NO^ Removal 

1. Installed Costs (per Unit, 1S39 dollars) 

SCR System (Bechtel estimate) 19,847,000 

WEPCO Costs (engineering & overhead) 1,914,256 

SARA Study 3,000 

NH3 & Air Heater Enclosures 90,600 

Economizer Addition (to control SCR inlet Temp.) 945,000 

Baghouse (control of increased PM from SCR) 4,700,000 

TOTAL INSTALLED COST $27,499,856 

2. Annual Cost (per Unit, 1989 dollars, 60% capacity factor) 

VARIABLE COSTS 

Ammonia 64,386 

Electricity 104,188 

Catalyst Replacement 2,300,000 

Catalyst Disposal 45,000 

Steam 7,250 

Bag Replacement 766,667 

Heat Rate Penalty 78,487 

SUBTOTAL $3,365,978 

FIXED COSTS 

Labor 620,321 

Material 30,400 

CEM Contractor 15,000 

Washdown 8,000 

SUBTOTAL $673,721 

ANNUALIZED INSTALLED COST (amortized $ 5.5%, 18 years) $2,445,285 

TOTAL ANNUAL COST $6,484,254 

3. Annual NOx Reduction x 973 tons) 77'. to-s 

4. COST fr OF NOx .ED $8325/ton