p.1 

OAR Box 1778 

Prepped by Ollie Stewart 

Document Number: 

190)11-1-22 

Docket Number: 

A-90-06 

Printed 10/28/2008 9:51:00 AM Sheet 190 of 276 
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,• W 

II-I-22 

a 

NOTE: This item is missing attachments. 
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kA'J<M6-90 THU 8 = 25 

Wisconsin 

Electric 

POWER COMPANY 

FAX NO. OOOOOOOOOOOOOOOOOOOO P. 02 

231W. MichiQan, RO. Box 2CM6. MiKvoukeo. Wl 53201 (414)221-2345 

July 13, 1990 

Mr. Paul 0. Yeung 

Environmental Engineer 

Wisconsin Department of Natural Resources 

Bureau of Air Management 

P.O. Box 7921 

Madison, WI 53707 

Dear Mr. Yeung: 

.-."V 

i^;H— — 

EPAA£ 

S'-'U 

COMMENTS ON THE PROPOSED AIR POLLUTION CONTROL PERMIT FOR PORT WASHINGTON 

POWER PLANT (PERMIT NO. 90-POY-037) 

Wisconsin Electric Power Company (WE) has the following comments on the 

proposed conditions for an air pollution control permit at the Port Washington 

Power Plant, dated June 8, 1990. 

p.2. Sec. I.A and p.3. Sec. l.D: SO, Emission Limitations 

The proposed permit language on Units 1 and 4 sets forth a maximum lb S02/MBtu 

limit, and also requires a minimum S02 removal rate by sorbent injection. 

Wisconsin Electric agrees that post renovation S02 emission rates on Units 1 

and 4, at maximum unit loads as measured by feedwater flow, must be reduced by 

22% and 13%, respectively. However, S02 removal by sorbent injection should 

not be necessary at lower loads where emissions are below the maximum hourly 

emissions achieved during the fall 1989 capacity testing. The emission rates, 

achieved during that testing, represent the baseline S02 emission rates, 

which, under the net-out provisions of NSPS, cannot be exceeded after the 

renovation project. 

Pursuant to 40 CFR Part 60.14 and EPA's previous determinations, a 

modification for NSPS purposes is defined as any physical or operational 

change to an existing facility which results in an increase in the emission 

rate, 1n terms of pounds per hour, to the atmosphere of any pollutant to which 

a standard applies. The emission rate before and after the physical change 1s 

evaluated by comparing the hourly emissions under current maximum capacity to 

emissions at maximum capacity after the change. Accordingly, to avoid 

triggering NSPS for S02 on Units 1 and 4, Wisconsin Electric proposes to 

install additional air pollution control equipment to offset the potential 

emission increase, such that no increase would occur in hourly emissions at 

maximum capacity. The concept of no net increase in hourly emissions to avoid 

triggering NSPS has been further reinforced in EPA's June 8, 1990 letter from 

William 6. Rosenbefg to John W. Boston: 
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July 13, 1990 

Page 2 

"To the extent that the controls are federally enforceable, and no 

increase 1n hourly emissions would occur at maximum capacity, 

WEPCo can use these options to avoid triggering NSPS for PM and 

S02 at Units 1 and 4." 

Wisconsin Electric understands the department's concern that potentially 

slightly lower sulfur fuel could be burnechat Port Washington thus requiring 

less S02 removal from the control equipment to achieve the pre-renovation 

baseline emissions limit. Wisconsin Electric suggests the following permit 

conditions that are based on feedwater flows achieved by Units 1 and 4 during 

the Fall 1989 capacity testing. S02 removal by the control equipment will 

occur at progressively higher removal rates whenever the feedwater flow 1s 

above the baseline feedwater flows independent of the coal being burned on 

Units 1 and 4. 

Accordingly we request that the S02 limits for Units 1 and 4 be revised as 

follows: 

Unit 1 

For feedwater flows greater than 534rs$0-lb/hr, the minimum SO, removal 

by the pollution control equipment shall be determined by the following 

relationship: 

% Removal - (1.325 x IO"4) (Y E^&jQM) 

where: 1.325 x 10"4 units are % Removal/lb feedwater flow/hr 

Y = measured feedwater flow, lb/hr 

This relationship results in ?Sieving a 22% S02 removal rate at a 

feedwater flow of 690,000 Ifc/hr. 

For feedwater flows equal to or less thafr^rOO^'lb/hr, the SO, 

emission rate will be no greater than 2.44>otmds per million Btu heat 

input, without S02 removal equipment required to be in operation. 

For feedwater flows greater than 580,000 lb/hr, the minimum SO, removal 

by the pollution control equipment shall be determined by the following 

relationship: 

% Removal - (1.733 x 10**) (Y - 580,000); _ 

where: 1.733 x IO"4 units are % Removal/lb feedwater flow/hr 

Y » measured feedwater flow, lb/hr 

This relationship results in achieving a 13% S02 removal rate at a 

feedwater flow of 655,000 lb/hr. 
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July 13, 1990 

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• For feedwater flow equal to or less than 580,000 lb/hr, the S02 emission 

rate will be no greater than 2.44 pounds per million Btu heat Input, 

without S02 removal equipment required to be in operation. 

If, however, the department wishes to impose a pound per million Btu 

limit on Units 1 and 4, the limit should be reworded to change "and" to 

with at the reduction percentages stated, and to change "sorbent 

injection1' to a SO* control technology. The permit conditions should 

not restrict the S02 control technologies that may be used by WE to 

comply with the air permit given potential advances 1n S02 control 

technology and future S02 reduction legislation. 

p. 2-3. Sec. IA-D. and p. 4-5. Sec. I.F.: N0]C Emission Limitations 

The department has determined that the existing arch fired Port Washington 

boilers as presently configured are Best Available Control Technology for N0X 

emissions. The boilers' full load actual NO. emissions are below the existing 

NSPS emission rate of 0.6 Ib/MBtu. Their inherent design includes a delayed 

combustion process which essentially duplicates the design features of current 

low N0X burners. However, a N0X emission limit which would be applicable to 

each boiler of 0.4 Ib/MBtu (based on a 30 day average) has been Included In 

the proposed permit. Wisconsin Electric believes that the proposed boiler 

specific limit is unreasonably restrictive and does not properly reflect 

Information concerning the plant's NOx emissions. 

NOx emission testing was performed on Port Washington Units 2-5 in October 

1978 by KVB under contract by EPRI for the purpose of establishing N0X 

emission rates representative of arch fired boilers. The baseline NO testing 

was performed at constant, steady load conditions, and did not attempt to 

document N0X emission levels under varying unit load conditions. The average 

N0X level measured on the four boilers was approximately 0.4 lb/MBtu. The 0.4 

Ib/MBtu emission rate was then used as a facility average in the preparation 

of the BACT request, and has subsequently been used by the department 1n 

establishing PSD and NSPS limits for N0X. 

However, during the testing under similar operating conditions, the NOx 

emission rates varied among the four units tested, with several units measured 

at more than the 0.4 lb NOx/MBtu level. N0X levels also varied significantly 

on all boilers as a function of boiler operating conditions. 

Based on the variability of N0X emission rates among the four boilers, and 

upon the dependance of N0X emissions on boiler operating conditions, WE 

requests that the N0X emission limits be revised as shown below. It should be 

noted that even with this change, these emission limits represent the most 

stringent N0X limits which WE believes have been imposed in PSD permits for 

pulverized coal fired boilers in the United States. 

NSPS Limit: 0.60 lb N0x/MBtu (maximum acceptable level averaged over any 

consecutive 30 days on any of the four boilers) 
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July 13, 1990 

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PSD Limit: 0.50 lb N0x/MBtu (facility average over any consecutive 30 day 

period) 

p. 3. Sec. I.E 

The fugitive dust rule citation is NR 415.04(1) Instead of NR 415.05(1). 

p.4. Sec. I.F: Metals Emission Limitations^ 

The department has proposed PSD related emission limits for arsenic, beryllium 

and mercury based on the fact that these substances are contained in trace 

amounts in coal. For the reasons given below the company does not believe It 

should be subject to any limits for these substances, especially arsenic. 

Arsenic Limits 

Wisconsin Electric does not believe it should be subjected to any arsenic 

emissions limits. We have demonstrated that we will not emit significant 

amounts of arsenic following plant renovation. Albeit regulated under 

NESHAPS, the arsenic regulations exclude fossil fuel fired steam generators as 

a source category subject to emission limitations. Therefore the arsenic 

emission limit should be deleted from the final permit. 

Beryllium. Arsenic and Mercury Limits 

Based on the data supplied to the department in the permit application and 

subsequent submittals, the department has determined that the emissions of 

beryllium, arsenic and mercury after the proposed renovation project will not 

exceed the sum of the emissions of these trace metals in the years 

representative of plant operation prior to the project (1983/84) plus EPA's 

PSD significance levels. Wisconsin Electric concurs with this analysis, and 

believes that since future post-renovated plant operation does not result in 

an emissions increase in these substances, PSD is not applicable. Since PSD 

is not applicable, PSD related emission limits are neither applicable nor 

required. 

The imposition of trace element limits 1n the permit requires control over 

emissions through the use of control equipment or fuel trace element content, 

either of which 1s not practicable. Although certain control equipment such 

a:; ;*ecipitators will reduce arsenic and beryllium emissions as a side effect 

or .articulate removal, arsenic and beryllium emissions cannot be specifically 

controlled. However for mercury, since it 1s assumed that 100% of the mercury 

in coal is volatilized, even non-specific control via precipitators is 

unavailable. _ 

The other means of emission control consists of selecting and using coal with 

low levels of these trace metals. Control over the level of these metals in 

the coal is, however, not available. It must be realized that these 

substances, arsenic, beryllium and mercury, are contained in coal in trace^ 

amounts, I.e. less than 0.01%. Coal mines do not analyze their coal for these 
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July 13, 1990 

Page 5 

parameters as it is mined or handled, nor do they analyze in-ground future 

coal resources for these metals. 

Even if analysis were performed by the mines on as-mined, or as-shipped 

samples of coal, the several weeks required for even a rapid metals analysis 

prevents the use of the data in controlling deliveries of coal to a power 

plant, or in meeting a specification for allowable levels of these metals. In 

fact, a significant amount of the coal could be consumed by a facility prior 

to notification by the mine of the level of trace metals. Without this 

measure of control over the level of trace metal in the fuel source, it is 

virtually impossible to guarantee meeting the proposed emission levels over 

periods of time. Wisconsin Electric is unaware of any existing coal contract 

which sets specifications for these trace metals. 

Therefore, Wisconsin Electric requests that the emission limits for beryllium, 

mercury and arsenic be removed from the permit. If the department is 

Interested in documenting the level of these metals in coal without the 

imposition of limits, we would agree to perform a monitoring program involving 

analysis of our as-fired coal for these metals. 

If, however, the department insists on imposing these trace metal emission 

limitations in this permit, Wisconsin Electric believes that the limits 

proposed in the draft permit are inappropriate given the variability of these 

metals experienced both in the baseline, pre-renovat1on years, or in the 

future, post renovation operation of the facility. The existence of 

variability in metals levels within coal, consisting of natural source and 

analytical variability, needs to be recognized and accounted for in the 

development of any emission limits. 

A. Source Variability 

In preparing the air permit application, Wisconsin Electric did not have 

(nor did data exist) as-fired data on metals levels in the specific coal 

used in the PSD baseline operating years prior to renovation. Instead, 

the average level of these metals reported in typical eastern 

Appalachian coal ("Trace Elements In Coal, Occurrence And Distribution". 

EPA-600/7-77-064), ref. (1), were used to approximate emissions for the 

actual coal fired. DNR has used this data, in conjunction with the fuel 

burned for those baseline years, in determining the proposed limits 

contained in the permit. Use of the average levels of trace metals 1n 

coal for the establishment of "not to be exceeded" plant emission limits 

does not take into account the historic or future natural variability of 

those metals in coal. Metal levels have and will continue to vary 

within the range reported in the literature for that source of coal. 

Establishment of emission limits for these metaTs must take into account 

that natural variability. 
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B. Analytical Variability 

In addition to the natural variability observed within coal, significant 

variability in the measured level of metals in coal is caused by the 

lack of analytical precision and accuracy in the approved methods of 

analysis. The analytical methods employed consist of burning a sample 

of coal in a controllhj manner, collecting volatile and non-volatile 

products of combustion, and analyzing these residues for the particular 

metals. A number of approved analytical methods are available to 

analyze the metals in the residue, each having a different level of 

precision and accuracy. The variability observed due to the lack of 

analytical precision applies directly to the data used to determine past 

metals emissions, and will apply to the calculation of future metals 

emission rates. 

A recent publication (attached) entitled "Interlaboratory Variability 

and Accuracy in Trace Element Analysis of Coal" by Messrs. J. Lengyel 

and E. Obermiller of the Consolidation Coal Company, dated October, 

1987, ref. (2), provides information on laboratory variability and 

accuracy for a number of metals in coal, including beryllium, arsenic, 

and mercury. The variability and accuracy levels reported were 

determined by sending out an NBS coal standard and other coal samples to 

five reputable commercial coal testing labs, using a number of approved 

analytical methods for metals analysis. A summary of the data on the 

analysis of eastern bituminous coal is provided on Table 2 of the 

attached, ref. (2). In that table, the overall mean, standard deviation 

and coefficient of variation are provided for each metal. This data 

shows that substantial variability exists in the analysis of these 

metals in coal, reflecting the level of uncertainty in the entire 

procedure. This analytical variability must be factored into the 

development of any emission limit in order to protect against "false 

positive" analysis due to analytical reasons which would suggest false 

excessive emission rates* 

C. Impact of Variability on Proposed Emission Limits 

The effect of analytical variability in determining the levels of metals 

in coal is to create an overall "error band" in the calculated 

concentration. The effect of the natural variability in metals content 

within the coal data used to calculate the proposed emission limits is 

to create a range in metals emissions both before and after the 

renovation. In the event that the department wishes to impose limits on 

beryllium, arsenic, and mercury 1n the final permit, the limits 

developed must reflect these two sources of natural variation - neither 

of which can be controlled by Wisconsin Electric or the supplier of the 

fuel. Accordingly, the baseline, pre-renovat1on levels of these metals 

in coal should be revised as follows: 
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July 13, 1990 

Page 7 

1. Arsenic 

Average level in coal for years 83/84: 25 ppm, ref. (1) 

Maximum level in coal for years 83/84: 100 ppm, ref. (1) 

Calculate natural variability factor by: 

Maximum level 83/84 = 100 ppm . 

Average level 83/84 25 ppm

 = * 

Calculate analytical variability factor by: 

Reported coefficient of variation «= 42.6%, ref. (2) 

Combine natural and analytical variability by: 

(25 ppm)(4)(1.426) = 142.6 ppm As 

This value represents a reasonable level of arsenic emissions from 

the pre-renovation coal source, considering both natural and 

analytical variability. 

2. Mercury 

Average level in coal for years 83/84: 0.20 ppm, ref. (1) 

Maximum level in coal for years 83/84: 0.47 ppm, ref. (1) 

Calculate natural variability factor by: 

Maximum level 83/84 = 0.47 oom « ,g 

Average level 83/84 0.20 ppm 

Calculate analytical variability factor by: 

Reported coefficient of variation = 33.3%, ref. (2) 

Combine natural and analytical variability by: 

(0.20 ppm)(2.35)(1.333) = 0.63 ppm 

3. Beryllium 

Average level in coal for years 83/84: 1.3 ppm, ref. *(1) 

Maximum level in coal for years 83/84: 2.6 ppm, ref. (1) 

Calculate natural variability factor by: 
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July 13, 1990 

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Maximum level 83/84 - 2.6 pom _ 7 

Average level ?L "'- 1.3 ppm 

Calculate analv liability factor by: 

Reported coefficient .. variation - 85.5%, ref. (2) 

Combine natural and anaijtlcal^variability by: 

(1.3 ppm)(2)(1.855) * 4.82 oom 

These revised pre-renovation baseline metal levels were then used 

to recalculate the allowable emission limits for future operation 

of Units 1-4 as shown on Table 1, attached. 

D. Monitoring Techniques 

The draft permit requires: 1) that coal samplinq ana ^ilyses for these 

metals be routinely performed to document comp: snce the proposed 

emission limits and; 2) that initial compliance and - quent 

compliance (every I years) be determined by sampling •-*.. flue gas 

(Section II.4.1). Wisconsin Electric objects to the requirement for the 

gas emissions testing for these metals on the basis that he levels of 

the trace elements in the flue gas downstream of the ES? are predicted 

to be extremely low (IO"5 to 10"7 lb/MBtu) and that it is doubtful 

whether the unapproved analytical method referenced in the proposed 

permit would be capable of reliably measuring these low levels. 

E. Averaging Time 

In addition to modifying the proposed limits as shown above, Wisconsin 

Electric requests that the averaging time for showing compliance with 

any metals emission limit be changed from the proposed 90 day period to 

an annual period. This longer averaging time will more accurately 

reflect long term variability in the metals content in the coal. 

In the event the Department wants to retain an arsenic emissions 

limitation, it should read 6.23 x 10'5 pound per million BTU heat input. 

p. 6. Sec. II.2 

"Initial operation" is defined as the first time a unit is put back into 

commercial operation after renovation. 

p.7-8, Sec. II.6.. 9.. 10.. and 11 

These conditions should be clarified with respect to determining electrical 

operating data for the precipitators. During the source performance tests, a 

range for each of the electrical operating parameters will be obtained which 

will demonstrate effective operation of the ESPs. The allowable variances 
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July 13, 1990 

Page 9 

expressed as percents in the proposed permit should then be applied to this 

range for each parameter. Also it should be stated that the expected 

variances apply at the performance test load, i.e., at or near full load. 

p. 8.. Sec. 11.14 

We do not understand the need to have a CO monitor on each boiler. We should 

have the option of installing a monitor on each stack. 

p. 9. Sec. 11.17 

The term "at the end of each day" should be removed from this condition. We 

will report excess emissions in accordance with NR 439.03(4)(a), WAC. 

p. 9. Sec. II.18.a 

We do not understand the need to report daily average opacities. We will 

report each measured 6 minute average opacity value greater than 20% in 

accordance with NR 439.07(3)(h)2.a., WAC and condition 19.a. 

p. 10. Sec. 11.20 

This condition should state specifically the NR 440.20 requirements applicable 

to N0X emissions from Units 1 and 4. 

p. 10. Sec. 11.21 

WE requests this condition be deleted because we are required to meet 

pollutant emission limits, as opposed to fuel type restrictions. 

p. 10. Sec. II.22.C 

Any reference to total fluorides and lead should be deleted as there are no 

emission limits for these substances in the permit. 

n. 11. Sec. 11.23 

The renovation work being performed is not phased construction. As we stated 

in Mr. Steinberg's May 7, 1990, letter, "(W)e want to clarify, however, that 

commencement of construction, as defined in 40 CFR 52.21, will begin at or 

near the start of the project on a number of boiler related systems which are 

common to all four units (e.g., boiler water makeup system, boiler water 

chemistry upgrades, and structural steel modifications to accommodate 

removal/replacement of rear steam drums). Work on these and other common 

activities related to all four units will continue during the entire threeyear renovation project." This condition should be accordingly deleted. 
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Page 10 

NO^ BACT Comments 

In a May 2, 1990 memo from Mr. Allen Hubbard (DNR) to Don Theiler (DNR), he 

concluded "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 archfired boilers." Wisconsin Electric agrees with this conclusion. However, we 

have the following technical comments on that determination. 

Pages 6, 7, 8 - Technical Feasibility of Control Alternatives for Port 

Washington's Boilers - Selective Catalytic Reduction (SCR). 

Mr. Hubbard concludes, as of May 2, 1990, "that SCR is technically feasible 

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

Washington Power Plant." In making that determination, we believe that Mr. 

Hubbard underestimated the adverse impact of one. of the primary technical 

reasons for excluding this technology for Port Washington - that being the 

potential for SCR fires. 

Wisconsin Electric adequately described the high potential for an SCR catalyst 

fire 1n a previous submittal dated February 14, 1990. Expanding upon that 

submittal, deposition of unburned fuel or fuel carbon 1n Selective Catalytic 

Reduction (SCR) reactors presents a serious hazard to personnel and equipment 

due to a high risk of fire or explosion. 

During operation of any coal fired boiler, small amounts of coal and evolved 

carbon will pass through the combustion chamber. In the presence of an 

ignition source and oxygen, these materials will combust, or in an enclosed 

space, produce an explosion. 

SCR reactors provide a receptacle in which combustible material may collect, 

via impingement on catalyst and structural surfaces or by dropping out in 

areas of lower velocity. Sufficient localized collections of combustible 

material has occurred at operating SCR systems to produce fires with 

subsequent damage to equipment, personnel injury, and apparently at least one 

fatality. Japanese experience with SCR fires was sited in our February 1990 

SCR review (reference Number 10). This fire occurred on a unit which, to our 

knowledge, has lower carbon levels in the flue gas than Port Washington. 

SCR reactors operate at or very near the ignition temperature of fixed carbon 

in coal, and above the ignition temperature for volatiles evolved from coal. 

During off-line periods, isolating the reactor to maintain its temperature and 

heating of the reactor has been recommended to preserve the functional life of 

the catalyst by inhibiting both thermal cycling of tha,catalyst and moisture 

borne migration of catalyst poisons. Although control schemes and damper 

closures would attempt to isolate the reactor from air (20% oxygen) flows on 

unit trips, and start-up, occasions would still arise wnen n r to support 

combustion would be available in isolated pockets or en masse. The presence 

of the combustion ingredients of fuel, heat and air would make fire possible 

and probable. 
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July 13, 1990 

Page 11 

In our February 1990 review of SCR technology, we stated that the fire hazard 

for SCR reactors, if applied at Port Washington Power Plant would be 

particularly acute. We outlined that the combination of relatively high 

levels of carbon released by the low NOx arch fired boilers (600 lb. 

coal/hour), small amounts of raw fuel (250 lb. coal/hour) and volatiles (1000 

ppm methane) discharged from the mill ventage system, variable gas flows and 

numerous starts and stops from cyclic opeieation would bring the combustion 

ingredients into the reactor on a frequent basis. The quantity of combustible 

material available made application of SCR arrangements clearly outside the 

bounds of good engineering practice. 

In fact, the risk of a fire in the SCR reactor would be significantly greater 

than in air heater or ESP. Unlike the air heater or ESP, which are allowed to 

cool down during off-line periods, the SCR reactor must be maintained at the 

elevated temperatures to preserve catalyst life. Therefore, the time period 

that the SCR reactor is exposed to heat for combustion is significantly 

greater than that of the air heater and ESP. 

In addition, SCR reactors are more prone to ash and carbon accumulation than 

that of air heaters or ESP's. Air heaters and ESP's are constructed with 

simpler vertical surfaces than that of the SCR's honeycomb design. Also, 

means are typically provided on air heaters and ESP's to maintain adequate gas 

velocities to prevent material fallout and to remove ash and carbon from the 

ESP plates and hoppers prior to removing the generating unit from service. To 

our knowledge, not one SCR manufacturer provides an SCR with plate rappers, 

hoppers and an evacuation system to remove materials that may accumulate in 

the SCR. 

Slow oxidation, or more commonly "spontaneous combustion", is the likely 

outcome, with results similar to the Japanese experience with fires. This 

clear and present hazard to personnel, equipment and reliable operation makes 

SCR application at Port Washington Power Plant unacceptable. 

Pages 8, 9 - Technical Feasibility of Control Alternatives for Port 

Washington's Boilers - Selective Non-Catalytic Reduction (SNCR) 

In his determination, Mr. Hubbard indicated "as of May 2, 1990, that SNCR is 

technically infeasible for controlling NOx emissions at Port Washington." Mr. 

Hubbard, however, suggests that one of the firms that provides a license for 

SNCR technology (Exxon) believes that their process may be applicable to Port 

Washington. 

Wisconsin Electric has reviewed Exxon's May, 1990 submittal to the Department 

regarding applying the DeNOx Selective Non-Catalytic deduction process at Port 

Washington Power Plant (ref. 1). Wisconsin Electric remains convinced that 

Selective Non-Catalytic Reduction (SNCR) is not, nor will be a viable NOx 

control technology for the Port Washington Power Plant boilers and that such 

an application cannot be effectively installed, operated or commercially 

guaranteed. This position is maintained based on uncertainties in development, design and performance of SNCR systems which remain unresolved, even in 
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July 13, 1990 

Page 12 

light of Exxon's unfounded assertions. The following discussion is offered to 

S.T? * Pr e y

1ou s ^formation supplied by Wisconsin Electric on this NOx 

removal technology. 

DEVELOPMENT 

Application of SNCR at Port Washington Power Plant would be the first use of 

SNCR on a U.S. coal-fired boiler. As shown in their May, 1990 submittal, 

Exxon s SNCR experience, worldwide, includes only four coal-fired utility 

boiler configurations. These installations were on cyclone furnace, fluidized 

bed, tower and European designs each distinctly different from the Port 

Washington boilers. The remaining 71 installations of Exxon SNCR technology 

are on oil and gas fired equipment. Although applications have grown, 

parametric data for SNCR involving coal firing in complicated heat transfer 

equipment has only a limited and exclusive base. 

DESIGN 

No design for DeNOx application at Port Washington has been produced. As 

Exxon indicated in their submittal, each application requires their specific, 

detailed engineering review to determine 1) Application of DeNOx to the 

furnace configuration, 2) Process parameters such as injector design, process 

control, reagent use and expected performance. In Port Washington Power 

Plant's case, all this would be based on the performance of the existing four 

dissimilar boiler designs and the use of mathematical models predicting the 

mixing and reaction of flue gas and ammonia. 

According to their submittal, Exxon would provide (and license) only the basis 

for the NOx control process. Actual detailed mechanical, electrical and 

control engineering, as well as installation, would be left to others. Without 

a comparable experience base for the designers and Installers, optimism and 

confidence in the success of the final system is not apparent, and certainly 

is not guaranteed. 

PERFORMANCE 

Ultimately, the amount of NOx removal and ammonia (NH3) slip are linked to the 

furnace configuration and operation. Exxon reports performance 1s Influenced 

during injection and reaction by temperature, mixing, flue gas constituents, 

and the nature of the local and downstream surfaces (ref.1,2). These 

conditions vary widely from application to application and during operation on 

any specific application. Reportedly, only in the most optimal process 

configurations, where maximum NOx removal occurs will minimum NH. pass-through 

be obtained (ref. 2). — 

The Port Washington furnaces operate at or above the upper temperature limit 

of the SNCR process during full load operation and have closely spaced tubing 

immediately downstream. At low load, the desired injection temperature may 

occur in the upper furnace. Without significant and costly boiler 
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July 13, 1990 

Page 13 

modifications, no existing injection area is available for the process to 

operate reliably over the range of loads experienced by the generating unit. 

Temperature has the greatest influence on the DeNOx process. In their 

submittal, Exxon suggests ammonia injection into the upper portion of the 

furnaces would be required at two different elevations. The Port Washington 

boilers, however, will routinely cycle through a 4:1 load range and will not 

operate steadily at only two load points. Performance concerns still exist 

for operation over the entire load range. 

In the upper load range, where temperatures throughout the furnace are high, 

exceeding the SNCR acceptable range would result in oxidation of the NH3 and 

production of additional NOx. Although Exxon asserts the tube surfaces 

immediately downstream of the furnace might not foul, the relatively cool 

surfaces would have an impact on effectiveness and are Identified by Exxon as 

Increasing NH3 slip (ref. 2) . 

During load changes, and even at steady load, temperature variations will 

occur across the plane of injection. Strong variation in performance tending 

toward lower NOx removal and increasing NH3 emissions has been reported for 

DeNOx SNCR (ref. 3) . In that reference, low load NOx removals of less than 

20% occurred, accompanied by NH-, emissions of 20-50 ppm. For Port Washington, 

that level of performance would result in no net reduction in the emission of 

total nitrogen compounds. 

To address performance at lower loads, Exxon may intend to inject additional 

"enhancer" agents. Methanol, hydrogen and proprietary hydrocarbons have been 

investigated to expand the lower temperature limit for the reduction process 

for NH3and Urea injection schemes (ref. 4,5). Exxon's May, 1990 submittal 

includes hydrogen in the list of process design criteria. Hydrogen is highly 

explosive, and is difficult to handle and store in large quantities. 

Maintaining leaktlght systems, where temperature changes and relative growth 

of components occur, is especially difficult; witness the recent concerns with 

space shuttle delivery hydrogen systems. 

Ideally, significant NOx removal should be accomplished without producing 

other detrimental impacts. As noted in our previous reports and above, the 

SNCR inherently produces a slip stream of ammonia (NH3), which passes through 

the reduction reaction. The NH3 subsequently interacts with other flue gas 

products or is emitted to the environment. Nationally, ammonia is listed as 

"Extremely Hazardous" by the U.S. EPA. In Wisconsin, ammonia Is identified as 

an air toxic by the Department. 

Exxon acknowledges the likelihood of unreacted NH3 pass4ng out of the process 

(ref.l). They suggest that process performance may be tailored to pass NH, in 

concentrations either less than 5 ppm or in fairly large concentrations of 20 

to 50 ppm (ref. 1,2). These ranges are selected to inhibit formation of 

ammonia salts in and on downstream equipment. 
P.16 

AUG-16-90 THU 8:54 FAX NO. OOOOOOOOOOOOOOOOOOOO 'P.T5 

July 13, 1990 

Page 14 

Although the high/low NH3 slip technique may have been practical in some instances, and as Exxon asserts, no detrimental equipment impacts have been 

incurred so far with solid fuel firing (Including short term results for a 

1.5% sulfur coal installation in Germany), :ie wide variation in fuel 

characteristics, especially sulfur/ash alkalinity concentrations will effect 

ammonia salt production. The coals currently used and planned for Port 

Washington consumption are relatively low in Hcalinlty relative to municipal 

waste, wood and European coals and thus the pocsntial for salt formation would 

be significantly greater. 

As mentioned above, control to 5 ppm NH3 slip is very unlikely except in the 

best of circumstances, nd, as stated in our earlier reports, is difficult to 

measure and control au^natically. Generally, the high slip configuration 

should be expected. Indeed, an operator's tendency would be to "overblow" NH3 

to maintain NOx compliance levels if downstream equipment were not affected. 

The bulk of higher NH3 concentrations would be emitted to the atmosphere. 

DeNox application to Port Washington Power Plant would be technically 

unprecedented and would require performance in compliance with legally 

enforceable limits. This step requires a high degree of certainty and 

confidence in the system technology on the part of the designer, installer, 

operator and mandating regulator. We note that although Exxon extended 

options for additional engineering support in design, installation and startup, no performance guarantee was described in the base or optional offerings. 

Ultimately, of course, the operator is responsible for compliance and 

workability of the system. Wisconsin Electric believes the application of 

SNCR is not viable at the Port Washington Power Plant, and the nascent technology does not remove our concerns. The technology remains unproven for this 

application and is, therefore, unacceptable. 
P.17 

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July 13, 1990 

Page 15 

REFERENCES 

1. THERMAL DeNOx ESTIMATE FOR FIVE 80 MW ARCH FIRED PC BOILERS. 

May, 1990. Proposal and accompanying memo of Jan. 4, 1990. 

W. D. Fellows, Exxon Research and Development Co. to A. Hubbard, 

Wisconsin Department of Natural Resources. 

2. THERMAL DeNOx TECHNOLOGY UPDATE. Boyd^E. Hurst, Engineering Associate, 

Exxon Research and Engineering Co., EPRI 1985 Symposium on Stationary 

Combustion NOx Control. 

3. THE THERMAL DeNOx DEMONSTRATION PROJECT. Henry T. Dziegiel, 

Tyrone B. Aure, David W. Anderson, Los Angeles Department of Water and 

power, Power Design and Construction Division, EPRI 1982 Symposium on 

Stationary Combustion NOx Control. 

The following were included in WEPCO's May, 1989 SNCR Review as Bechtel 

References 6 and 8: 

4. NOx CONTROL IN A BROWN COAL-FIRED UTILITY BOILER. J. Hoffman, 

J. Bergmann, D. Bokenbring, EPA/EPRI Joint Symposium on Stationary NOx 

Control, San Francisco, March 6-9, 1989. 

5. METHANOL INJECTION-A NEW METHOD FOR NOx AND S03 CONTROL. R. Lyon, 

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

Francisco, March 6-9, 1989. 
P.18 

AUG-16-90 THU 8:57 FAX NO. OOOOOOOOOOOOOOOOOOOO 'P: 17: -

July 13, 1990 

Page 16 

We would appreciate if you would consider these comments and incorporate the 

changes into the final permit conditions. If you have any questions 

concerning these comments you can contact me at (414) 221-2174. 

Sincerely, 

Roger/D. Dodds 

Air Qbility Engineer 

Environmental Department 

RDD/kmo 

Attachments 

cc: Wolf Klassen - DNR/SED