# Minnkota Power I!YIPg 

# coo P E A T I V E, INC.

1822 Mill Road, P.O. Box 13200 • Grand Forks, NO 58208-3200 • Phone (701) 795-4000 

### Nov 17, 2008

Mr. Terry O'Clair Director, Division of Air Quality North Dakota Department of Health 918 

### E. Divide Avenue, 2nd 

### FI Bismarck, NO 58501-1947 Your Touchstone Energy" Partner 

# -

Re: Response to EPA's October 17, 2008 Response to Minnkota's Letter on Public Comments Received on the North Dakota Department of Health's Preliminary NOx BACT Determination for M.R. Young Station

Dear Mr. O'Clair: Enclosed, please find Minnkota's response to EPA's October 17, 2008 comments. In addition to the response enclosed, Minnkota also makes the following comments. The North Dakota Department of Public Health ("NDDH") has led an intensive, two-year process designed to determine what constitutes Best Available Control Technology ("BACT") at Minnkota's Young Station. NDDH has collected an administrative record that spans over a thousand pages of highly detailed, deeply technical engineering analyses. NDDH has also managed a highly-transparent, public decision-making process that has solicited the input of EPA at numerous times during the administrative decision-making process, arid has also solicited public comment. NDDH itself has engaged in a vigorous and challenging exchange with Minnkota over engineering reports and analyses. We believe NDDH has more than satisfied its responsibilities under the July 2006 consent decree and its own regulatory BACT requirements. We find the October 2008, comments of EPA's "expert witness" to be mostly redundant of earlier comments by EPA that NDDH fairly addressed previously. We do not believe EPA's October 17, 2008, comments warrant any modification to NDDH's BACT Determination. We have set forth in the following sections in more detail the grounds in support of our response. 

### NDDH's Decision is Reasonable (Not Arbitrary nor Capricious), Supported by the Record, and Entitled to Substantial Deference

### Terry 

### O'Clair November 17, 2008 Page 2 of 3 From EPA's comments, it is evident that there exists a difference in opinion regarding what constitutes BACT at Young Station: NDDH has concluded that SCR is technically infeasible; EPA insists that it is technically feasible. In such disputes, the North Dakota Supreme Court's opinion in People to Save the Sheyenne River, Inc. v. North Dakota Dept. 

### ofHealth, 

### 697 N.W.2d 319 (N.D. 2005) describes the standard of review applied to challenges of NDDH permitting decisions. In that case, the plaintiffs-including the government ofthe Province of Manitobachallenged a North Dakota Pollutant Discharge Elimination System ("NDPDES") permit that NDDH issued underthe Clean WaterAct. 1 

### Plaintiffs disputed NDDH's findings and decisions on technical matters ranging from phosphorus loading, to anti-degradation of water quality, to the presence and potential impacts ofthe parasites gyrodactylus hoffmani 

### and ligula intestinalis. 

### The court held that NDDH's permitting decision would be set aside only if it was "arbitrary, capricious, or unreasonable." Id. 

### at 329. See also People to Save the Sheyenne River, Inc. v. North Dakota Dept. 

### ofHealth, 

### 744 N.W.2d 748, 753 (N.D. 2008) (applying arbitrary, capricious, and unreasonable standard to NDDH modification of NDPDES permit). The court more fully described the standard of review as follows: "A decision is arbitrary, capricious, or unreasonable if it is not the product of a rational mental process by which the facts and the law relied upon are considered togetherfor the purpose of achieving a reasoned and reasonable interpretation." People to Save the Sheyenne River, 

### 697 N.W.2d at 329; see also Little v. Traynor, 

### 565 N.W.2d 766,773 (N.D. 1997). And an administrative record is "adequate if it enables [a reviewing court] to discern the rationale for the decision." Id. 

### Moreover, the North Dakota Supreme Court has held "[t]hat deferential standard is particularly applicable where, as here, the subject matter is complex or technical and involves agency expertise." People to Save the Sheyenne River, 

### 697 N.W.2d at 329. The court upheld NDDH's permitting decision on every ground, finding sufficient evidence in the record to support NDDH's determinations, and holding that the determinations were not arbitrary, capricious, or unreasonable. Id. 

### at 333. Here too, NDDH's BACT Determination is entitled to substantial deference, and may only be overturned-regardless of EPA or others' comments-if NDDH's decision was arbitrary, capricious, or unreasonable.2 

### That is, NDDH's decision may only be set aside if-based on the record before it-NDDH's decision was the product of an irrational mental process or ifthe court can discern no rationale for the decision. Underthis deferential standard of review, it is relatively unimportant that EPA may very well have interpreted the Coyote Station pilot project results differently, or have a different interpretation ofthe impact offuel variability on control performance, or have a different view on whether or not a TESCR will work, or a different view on any of a dozen other issues. The question is whether NDDH engaged in a rational mental process based on evidence in the record. And here, the record is replete with extremely detailed technical materials that are sufficient to support

1 NDDH has delegated authority to implement the federal NPDES program, much like NDDH also as SIPapproved authority to implement the federal PSD program. The use ofthe arbitrary and capricious standard of review is accordingly equally as applicable to NDDH's PSD program as it was to its NDPDES program.
2 The Consent Decree standard of review is not inconsistent with the North Dakota reqUirement that administrative decisions not be unreasonable and that they must find support in the administrative record. See Consent Decree 147(c) ("The Court shall sustain the decision by NDDH unless the Party disputing the BACT Determination demonstrates that it is not supported by the state administrative record and not reasonable in light of applicable statutory and regulatory provisions.").

### Terry O'Clair November 17 2008 Page 3 of3 NDDH's conclusions, EPA's own views to the contrary notwithstanding. For example, NDDH challenged Minnkota's initial submissions relating to the BACT Determination, and certainly considered EPA comments on interim drafts, as well as the opinions ofthose other than Minnkota. These factors are quite useful in determining that an agency acted reasonably in making a decision based on the record before it. See, e.g., Citizens for Clean Air

### & Waterin Pueblo and Southern Colorado v. Colorado Dep'tofPublic Health andEnvt., 181 P.3d 393, 398 (Col. App. 2008), cert. denied, 2008 WL 2581591 (Colo. June 30, 2008) (citing as evidence of rational decision-making a state's challenge and disagreement with a source's BACT input, as well as its examination of other sources of information). The extensive record here-and NDDH's careful treatment of it-is evidence that NDDH engaged in a rational mental process in reaching its BACT Determination. Furthermore, EPA bears the burden of proofthat NDDH acted arbitrarily, capriciously, or unreasonably. The Consent Decree expressly provides that "The Court shallsustain the decision by NDDH unless the Party disputing the BACT Determination demonstrates that it ·is not supported

.... " See Consent Decree 147(c) (emphases added). EPA carries a very heavy burden in seeking to overturn NDDH's reasonable BACT Determination. Technical Disagreements do not Render NDDH's Decision Arbitrary, Capricious, or Unreasonable With the proper legal standard firmly in mind, it is clear that none ofthe comments by EPA or the DOJ's consultant prove that NDDH has acted arbitrarily, capriciously, or unreasonably. Mere disagreement regarding the interpretation of data, or alternative exercises of engineering judgment simply do not disqualify NDDH's BACT Determination. In summary, with the additional ofthe enclosed response to EPA's October 17, 2008 comments, the administrative record is replete with sophisticated engineering and technical information upon which NDDH can make a defensible and rational BACT Determination. While EPA may disagree with NDDH's decision, mere disagreement is no ground for disturbing its decision. We urge NDDH to finalize its BACT Determination as currently drafted so that Minnkota get on with the work of installing BACT controls to reduce nitrogen oxides emissions at Milton R. Young Station. Should you have any questions concerning the above orthe enclosed, please contact me at 701-795-4221.

Yours truly, MI,yTA**POW~** 

### COOPERATIVE, INC.

# £~Z~ John T. Graves, P.E. Environmental Manager C: David Sogard Luther Kvernen Plant file

## Responses to Hans Hartenstein's October 2008 Remarks to September 22, 2008 Comments & Responses on NDDH Preliminary NOx BACT Determination for Milton R. Young Station (MRYS)

November 17, 2008 Burns & McDonnell (B&McD), and its SCRconsultant, Fuel Tech1

, along with Steve Benson of the Department ofChemical Engineering at the University ofNorth Dakota2

, have reviewed the October2008 remarks ofthe United States' DepartmentofJustice's (DOl's) commenter, Hans Hartenstein(Hartenstein, 2008), providedby the United States Environmental Protection Agency (U.S. EPA orEPA) Region 8 Office ofEnforcement, Compliance, and Environmental Justice and forwarded by the North Dakota Department ofHealth (NDDH). These are responses regarding selective catalytic reduction (SCR) technology feasibility pertaining to the NDDH's PreliminaryNOx BACT Determination for Nitrogen Oxides for Milton R. Young Station Units 1 and 2, dated June 2008 (NDDH, 2008).

We continue to believe that the administrative record fully supports a finding by the NDDH that separated over-fire air (SOFA) in conjunction with selective non-catalytic reduction (SNCR) technology is BestAvailable Control Technology for electric generating units thatutilize cyclone burners firing North Dakota lignite. The following sections address specific topics mentioned in the EPA's comments and other issues in greaterdetail.

• Mass Particulate Loading Irrelevantto SCR Catalyst Deactivation from Aerosol Poisons

• Biomass Firing Impacts on SCR Catalyst as Surrogate for North DakotaLignite

• General Regulatory Considerations

• Corrections, Clarification and Omissions ofHartenstein's Remarks
o Responses to General Remarks
o Responses to Specific Comments

• Conclusions

1 formerly Tackticks LLC. 2 formerly employedby Energy & Environmental Research Center (EERC) ofthe University ofNorth Dakota. Combined Responses to NDDH (11-17-2008 final).doc 1 November 17, 2008

## Mass Particulate Loading Irrelevant to SCR Catalyst Deactivation from Aerosol Poisons

As previously described in the September22, 2008 comments and responses (Burns & McDonnell and others, September2008), the catalyst in any configuration ofSCR application for a high-sodium North Dakota lignite-fired cyclone boileris expected to be exposed to appreciable concentrations ofsodium, potassium, and other alkali-rich aerosols. These constituents are released from the combustion cyclones and are not effectively removed from the flue gas streams by the electrostatic precipitator and flue gas desulfurization systems ("scrubbers"). Air quality control equipment vendors have historically not guaranteedremoval rates ofsuchparticles and aerosols. These materials react with other gas phase species and deposited particles thatwill cause blinding orcan react with active sites in the catalystpores, causing poisoning and deactivation, thus rendering the NOx reduction capability ineffective.
Lignite coals contain high levels elements such as sodium, magnesium, and calciumthat are associated with the organic orcombustible fraction ofthe coal. These elements are prone to form gas phase species and very small particles during combustion and gas-cooling processes. Specifically, sodium will vaporize during coal combustion and condense in the convective pass ofthe boilerupon gas cooling. Sodiumwill condense heterogeneously on the surfaces ofother fly ash particles orhomogeneously to aerosols. In addition, the high temperature cyclone-firing ofthese coals increase the level ofaerosols downstream in the combustion system. This is because the high operating temperature increases vaporization and also some ofthe ash available for heterogeneous condensation downstream is removed as slag. The resulting aerosol produced upon gas cooling is enriched in sodium andpotassium. These sodium and potassium-rich aerosols are very reactive with gas phase constituents and othermaterials with which they come into contact. The form ofsodium in the submicron particulate phase is as oxides, hydroxides, and sulfate. In addition, the abundance ofthe submicron fraction is dependentupon the ash content ofthe coals. Typically, coals that contain high levels oforganically associated elements and lower levels ofash-typically less than 15% (dry basis)-have the potential to produce high levels ofthe submicron, homogeneously condensed sodium andpotassium-rich aerosol.

Combined Responses to NDDH (11-17-2008 final).doc 2 November 17, 2008As indicatedby EPA (Woodward, 1998), scrubbers do not effectively remove particulate less than Illm in diameter. There is significant evidence that sodium-rich aerosols penetrate ESPs as well as scrubbers at full-scale powerplants when firing high-alkali-containing fuels. An example is a biomass fired systemusing a towertype scrubberwhere the removal efficiency of the smaller size fraction ofash is low, as shown in Figure 1 (Ohlstrom and others, 2006).



## • Wood, grate boiler, scrubberinlet I



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Figure 1. Removal offine aerosols using a scrubber on a wood fired combustor (Ohlstrom and others, 2006).

Minnesota Power's Boswell Energy Station found that when it fired high-sodium, lower-ash northern PowderRiver Basin subbituminous coal (7% NazO 

### in the ash), it experienced increases in opacity. Hurley and Katrinak (1992) conducted a field-testing project on Unit No.4, a pulverized coal-firedboilerequipped with a venturi wet scrubber, to betterunderstand the
reasons for the opacity problems. During the field testing, sampling ofthe coals, flue gases, and scrubbermaterials was conducted. The particulate 

### in flue gases downstream ofthe scrubber was aerodynamically classifiedusing a multicyclone followed by an impactor and aNucleopore filter. The sized fractions were weighed and analyzed to determine the abundance and composition ofthe submicron-sized fractions. The mass loadings in the various size bins are Combined Responses to NDDH (11-17-2008 final).doc 3 November 17, 2008plotted in Figure 2, showing thatthe scrubber is quite effective in removing the largerparticles. However, the scrubber is not very effective in removing the aerosols less than 1 micrometer in diameter for both the blended coal and the high sodium coal (Coal A). 

### 1



### 0.1


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## 0.001

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## Blend-Inlet 

## Blend- outlet 

## ColIA-Inlet CGel

## A-outlet 

# B D50

# =-U 

### mlcJons 

# mOSO- 2.5

### microns 

# 111050- 0.7

### micrOnS 

# 11050<0:1

### microns 

## Overa-masssIZedistributions

## for....nedash.mptes. Figure 2. Mass loadings and size for particulate collectedupstream and downstream ofthe wet venturi scrubber at Clay Boswell (Hurley and Katrinak, 1992).

The results ofthe study indicatedthat the particulate collected downstream ofthe scrubberwas coal-related and causedby the high sodium content ofthe coals. Vapor-phase sodium condenses in the boiler's convective pass to form fine sodium-rich aerosols orotherNa species that later react with ash particles. Pure NaZS04 particles are too small to be removed by such scrubbing, despite the fact thatthey are highly soluble in water. Figure 3 shows the spikes ofthe ash material collected on Stage 10 ofthe impactor. This impactor accumulation represents the 0.7 to 2.5 micrometer size fraction ofthe aerosol. The spikes are made up offine particulate matter, and the chemical analyses ofthe spikes and ash particles collected on the Nucleopore filters downstream ofthe impactorplates represent the <0.7 micrometer aerosols are shown in Table 1.

Combined Responses to NDDH (11-17-2008 final).doc 4 November 17. 2008Both samples are dominated by sodium and sulfurthat are likely in the form ofsodium sulfate. These sulfate materials exhibithighly cohesive tendencies.

Figure 3. Scanning electron microscope images ofspikes formed on impactorplates when highsodium subbituminous coal is combusted (the picture on the right is a close-up ofthe spike) (Hurley and Katrinak, 

### 1992). Table 1. Chemical Composition ofthe Spike Shown in Figure 

### 3 and the Nucleopore Filter (weightpercent expressed as equivalent oxide). 

### 100% Coal A Spike Filter 

### Oxide Na20 

### 35.1 

### 17.3 MgO 

### 1.4 7.8 

### Ah0 3 

### 2.0 9.8 Si02 

### 9.1 10.6 P20S 

### 0.4 0.2 S03 

### 39.7 

### 28.0 K2 0 

### 2.6 1.5 CaO 

### 6.2 15.7 Ti02 

### 0.2 1.8 Cr203 

### 1.4 0.1 Fe20 3 

### 0.9 2.9 BaO 

### 0.5 2.6
The ash particles collected on the Nucleopore filters downstream ofthe impactorwere further characterized on aparticle-by-particle basis with a scanning electron microscopy andx-ray
Combined Responses to NDDH (11-17-2008 final).doc 5 November 17, 2008microanalysis (Hurley and Katrinak, 1992). The chemical analysis ofparticles collected on the filter downstream ofthe scrubberwhen firing 100% Coal A (high sodium coal) are shown in Table 2. The individual particles have sodium levels as high as 63%. The particles with 0 diameter were particles where the exact diametercould notbe determinedbecause ofparticle agglomeration.
Table 2. Elemental compositions ofmixed submicronparticles collected during the combustion ofCoal A (high sodium subbituminous coal) atthe scrubber outlet. Particles sortedby diameter in micrometers. The chemical composition is reported as elemental weightpercent (Hurley and Katrinak, 1992).
Ptcl # Na Ma AI Si P 5 CI K Ca Fe Sa Ti Diameter 1 16 35 3 29 0 0 0 0 3 3 0 12 0 2 41 24 0 0 14 0 0 10 0 0 1 10 0 3 0 32 0 28 0 10 0 4 22 4 0 0 0.1 4 0 17 43 0 2 0 5 18 5 2 8 0 0.1 5 0 21 0 26 15 0 7 21 0 3 7 0 0.3 6 28 28 0 26 0 0 0 1 14 0 3 0 0.3 7 57 0 0 11 0 0 6 12 0 0 0 14 0.3 8 24 0 0 24 0 8 0 11 20 2 0 11 0.3 9 16 14 12 31 10 3 3 0 1 2 8 0 0.3 10 0 18 2 27 6 9 0 11 21 2 4 0 0.4 11 23 0 12 25 6 0 0 9 12 2 6 5 0.4 12 44 17 0 0 9 9 4 0 5 1 6 5 0.5 13 63 19 0 14 3 0 0 0 0 0 1 0 0.5 14 9 30 0 9 4 9 0 6 13 2 8 9 0.5 15 25 9 1 26 12 5 0 0 11 2 2 8 0.5 16 38 0 0 38 0 12 1 2 1 3 0 5 0.5 17 50 0 32 9 4 0 0 0 0 3 0 4 0.6 18 20 0 26 15 0 12 10 9 0 3 5 0 0.6 19 21 0 33 31 0 0 0 9 3 2 0 0 0.6 20 28 0 13 13 11 12 0 5 5 2 5 5 0.6 21 38 0 10 10 11 14 0 7 6 0 3 2 0.7 22 21 5 13 21 10 8 8 0 9 0 3 3 0.7 23 31 6 14 21 7 3 0 3 6 1 4 4 0.7 24 51 0 2 15 10 10 5 1 0 1 0 7 0.7 25 29 3 17 21 15 11 0 0 0 0 3 3 0.7 26 42 21 0 0 0 12 7 0 9 3 0 5 0.7 27 37 0 38 0 4 3 0 0 13 0 7 0 0.8 28 40 0 0 23 0 6 13 5 0 2 6 5 0.8 29 42 13 0 33 0 6 0 0 6 2 0 0 0.8 30 49 0 0 8 1 11 8 7 3 2 5 4 0.8 31 47 8 14 8 9 7 0 3 0 1 4 0 0.9 32 43 0 4 10 13 15 8 4 0 1 0 2 0.9
Fly ash produced upon the combustion ofhigh sodium lignites in a pulverized coal (PC) fired system shows significant enrichment ofsodium in the smaller size fractions as shown 

### in Figure 4. This figure illustrates the increase in the sodium content in the finer size fractions ofash as a result offiring high sodium lignite. The sodium and sulfur content ofthe less that 3 micrometer

Combined Responses to NDDH (11-17-2008 final).doc 6 November 17, 2008size fraction of the sampling train approached 20% NazO, and 25% 

### 803. The form of the sodium is likely sodium sulfate.


### 96

## OxIde



# o >10 

### 10.3 

### <3 

## Mul1lcydone_fractions, pm Figure 4. Composition distribution ofash particles during combustion ofNorth Dakota Lignite (Benson and others, 1984).
The abundance ofsulfate aerosols was measured atthe MRY by Markowski and others, 1983. The results ofthe measurements ofaerosol capture are illustrated in Figure 5. The results show

Combined Responses to NDDH {11-17-2008 final).doc 7 November 17, 2008that aerosols less than one micrometerin diameter are not effectively captured in the ESP and wet FGD at the MRY facility. The graph also indicates the penetration ofthe particles through the FGD as a function ofparticle size. The penetration is the outlet size distribution divided by the inlet size distribution. (Penetration = 1- efficiency). The results showedthatthe "metallic" sulfate aerosols (sodium sulfate) penetratedthe FGD much more effectively than the larger particulate.



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Combined Responses to NDDH (11-17-2008 final).doc 8 November 17,2008Sodium andpotassium rich aerosols are present in the flue gases entering the FGD as evidenced by the recent work conductedby Tolbert and others (2008). Testing ofPower Span's barrier discharge reactorbeing developed for new powergeneration was conducted to determine the impact ofsodiumrich aerosols on the performance ofthe PowerSpan ECO Technology for flue gases from boilers fIring high sodiumND lignite. The barrierdischarge reactor is placed downstream ofparticulate control systems to enable the oxidation ofNO to N03 species that will allow for capture in an ammoniabased scrubbing system. A slip streambarrierdischarge reactor system was designed by PowerSpan and the EERC and installed downstream ofthe ESP on Unit 1 at the MRY station. The gas temperature entering the barrierreactorwas approximately 300 of. The primary concern regarding the success ofthe technology was that sodium-rich aerosols present in the flue gas stream would diffuse to the surface ofthe quartz rod and become bonded to it, resulting in decreasedperformance ofthe barrierdischarge reactor. The ash accumulation resulted in decreasedNO oxidation due to accumulations ofalkali and alkaline earth sulfate rich ash layer on the rods. The bulk composition ofash scraped from selected quartz rods was determined by x-ray fluorescence (XRF). The rods sampled were from three electrodes that
were sampled at 20, 48, and 107 days. The bulk composition summarized in Table 3 shows signifIcant levels ofsodium, calcium, and potassium along with sulfur.

Combined Responses to NDDH (11-17-2008 final).doc 9 November 17,2008Table 3. Bulk composition ofash removed from electrode samples obtained from rodremoved at 20, 48, and 107 days.

Oxides Elemental (wt.%) (a) (b) (c) (wt.%) (d) (e) Si02 '10.3 10.8 22.0 Si 9.6 15.8 AI203 4.1 4.3 8.8 AI 4.4 7.2 Fe2 0 3 4.3 4.5 9.2 Fe 6.0 9.8 Ti02 0.2 0.2 0.4 Ti 0.2 0.4 P20S 0.1 0.1 0.2 P 0.1 0.2 CaO 10.5 11.0 22.5 Ca 15.1 24.7 MgO 2.1 2.2 4.4 Mg 2.5 4.1 Na20 '11.7 12.3 25.1 Na 17.4 28.5 K

2 0 3.4 3.6 7.3 K 5.7 9.3 S03 48.5 51.0 S 39.0 Total 95.0 (a) Oxide concentrations (wt.%) on an ash basis. (b) Oxide concentrations normalized to a closure of 100%. (c) Oxide concentrations renormalized to a S03-free basis. (d) Elemental concentrations (wt.%) on an ash basis. (e) Elemental concentrations renormalized to a S-free basis. Comments: BaO

# = 0.87% Unknowns

# = 3.54% 

### srO= 0.34%



## Biomass Firing Impacts on SCR Catalyst as Surrogate for North Dakota Lignite
North Dakota lignite andbiomass materials have similar associations ofalkali elements. The bonding sites for alkali elements such as sodium andpotassium in biomass and lignite coals are organic acid sites. The alkali elements are present in coal and biomass as salts oforganic acid groups, such as carboxylic acids. The associations ofalkali and alkaline earth elements have been extensively studiedby the EERC (Benson and Holm, 1983 and Benson and others, 1994). The alkali elements associated with biomass have been extensively studiedby SandiaNational Laboratory (Miles and others, 1995). Both studies conclude that alkali and alkaline earth elements are bonded to the organic matrix ofthe lignite orbiomass. In addition, the behavior during combustion and gas cooling is similar. Organically associated alkali elements will

Combined Responses to NDDH (11-17-2008 final).doc 10 November 17. 2008vaporize during the combustion process and produce highly reactive vapors and aerosols (Benson and other, 1984 and Ohlstrom and others, 2006).
Khodayari (2001) exposed catalysts to flue gases in a PC unit fIring a low ash wood and in a CFB unit fIring high ash forest residues and measuredrelative reactivity as illustrated in Figure 6.



# IICFB .6.CFB 

# eCFB CPe 

# OPe OPe**~.PC** 

# e

500 

# .-o 1000 1500 

# aoo .. .. .. 4OGO 4500 

# soao or-adDn1lme

## lhJ Figure 6. Comparison ofpoisoning ofcatalysts in a CFB boiler fIring forest residues, and in a PC fIring pulverized wood (Khodayari, 2001). Khodayari found thatthe degree ofdeactivation was related to the abundance ofpotassium and sodium that accumulated in the catalyst and notrelated to ash loading. In the CFB boiler exposed catalyst, the level ofpotassium accumulated in the catalystwas 0.27% and the relative reactivity ofthe catalyst decreased to about 78%, or22% deactivation. Forthe PC case in fIring wood, the buildup ofpotassium in the catalystwas 0.8 % after 1400 hours and the relative reactivity decreased to 20%, or 80% deactivation. The higher deactivation exhibited for the PC
case fIring wood was due to the presence ofhighly reactive alkali (potassium and sodium) aerosols in the flue gas. The PC systemproduced more highly-reactive alkali aerosols because
Combined Responses to NDDH (11-17-2008 final).doc 11 November 17, 2008ofhigher firing temperatures causing an increase in the vaporization ofalkali and low ash content ofthe wood that reduces the sites for condensation ofalkali vapors. Lower levels of highly-reactive alkali aerosols are produced in the CFB case because ofthe lower operating temperatures, higher ash content ofthe forest residue, and higherparticle loading in a CFB as comparedto the PC system. The alkali in the CFB system reacts with bed materials and ash particles during circulation decreasing the abundance ofalkali aerosols. The reactive alkali aerosols diffuse into the catalyst and are adsorbed chemically andphysically on the catalyst surfaces resulting in deactivation. Highertemperatures such as those found in cyclone fired system will cause an increase in vaporization ofalkali species and exacerbating the formation of reactive alkali aerosols.
Numerous investigations have shown that alkali (sodium and potassium) rich aerosols degrade catalystperformance as follows:

• Zheng and others (2005) biomass derived alkali rich aerosols caused a drop in NOx reduction activity by 52% after about 1140 hours ofoperation.

• Chen and others (1990) examinedthe poisoning mechanisms ofalkali and alkaline earth oxides on vanadia catalysts and found thatthe deactivation is directly related to the basicity ofthe poisons and found a decrease in NO reduction rate constant from 10 to 2.5
cm3 /g s for sodium oxide.

• Guo (2006) conducted a study ofthe intrinsic SCR activity for NO with NH3 reaction and found that the additions ofK, Na, and Ca greatly decrease the NO reduction activity of 1% 

### V20S- 9% 

### W03/Ti02. A decrease in NO reduction rate constant from 18 to 5 cm3 /g s for potassium oxide was measured.

• Kling and others (2007) investigated deactivation ofSCR catalysts in three biomass and peat fired 100 MW-scale combustion systems. They found that the increased levels of sodium andpotassium accumulated in the SCRcatalyst was derived from the ultra fine particles (aerosols). These accumulations ofaerosols decreased the NOx reduction catalytic activity by over40% in testing ranging from 100 to 3000 hours.

• Strege and others (2008) at a stoker-firedutility boiler firing a blend ofbiomass and PowderRiver Basin coal (PRB) found that the catalyst deactivation rate was about 18% per 1000 hours.

Combined Responses to NDDH (11-17-2008 final).doc 12 November 17. 2008• Khodayari and others (2000) lost 80% ofreactivity afterbeing exposed to flue gas derived from firing wood for about 1400 hours.

• Zhang and others (2008) investigatedthe operation offull-length monolith catalysts installed at a straw-firedpowerplant and found a high deactivation rate ofabout 1% of the relative activity perday was observed when the powerplantran continuously.



## General Regulatory Considerations Comments regarding the EPA's regulatory approach submittedby Minnkota Power Cooperative (Minnkota) made in September2008 (Burns & McDonnell and others, September2008) appear to have been mostly ignoredby the EPA. We encourage the NDDH to make those comments, and the ones in this document, part ofthe administrative record for the fmal NOx BACT Determination for the lignite coal-firedutility boilers atMilton R. Young Station. Minnkota, as
owner and operatorofthe lignite-fired cyclone boilers atMilton R. Young Station, is providing these comments as aparty subjectto the requirements ofthe ConsentDecree (2006).



### It is indisputable thatthere are no SCR installations in operation orplanned on units that include cyclone burners firing North Dakota lignite. In fact, to the best ofourknowledge, there have been no previously built, and there are not any currently operating, tail-end SCRs installed on full-scale, full-time lignite-firedutility boilers anywhere in the world. This has not been refuted by the EPA ortheir experts.

The arguments regarding technical infeasibility ofSCRtechnology for the reduction ofNOx emissions at M.R. Young Station have beenstatedpreviously (BACT, 2006; Minnkota, 2007A, B, C; Bums & McDonnell and others, May 2007;Arfmann and others, August 2007; Burns & McDonnell and others, May 2008; Bums & McDonnell and others, September 2008). Examination ofthe physical and chemical characteristics ofthe pollutant-bearing gas stream and comparison to the gas stream characteristics ofthe source types to which the technology has been previously successfully applied has been presented in detaiL The characteristics ofcyclone boilers firing North Dakota lignite, whose sodium-rich ash-forming constituents, combined with slagging-type firing methods, create flue gases containing reactive aerosols that are unique. These conditions will cause catalyst fouling, blinding, and poisoning in high-dust, low-dust, and

Combined Responses to NDDH (11-17-2008 final).doc 13 November 17, 2008tail-end SCR configurations. Thus, it has been demonstrated that SCRtechnology has notbeen deployed on a "same or similar source type". Accordingly, the NDDH has areasonable basis upon which to conclude that SCR is not applicable for BACT at Young Station.

Statements ofSCR catalyst vendors being willing to guarantee theirproduct resulting from a Bums & McDonnell query and follow-up (Bums & McDonnell and others, April 2007 and May 2008), and subsequent claims by the DOl's commenter (Hartenstein, July 2008) are basedupon the premise that exposure ofthe catalystto suitable operating conditions will occur; whetherit is possible to achieve such conditions is nottheirresponsibility. Regarding tail-end SCR, one of the queried vendors stated "the fly ash constituents that can poison the catalystwill have been removed from the flue gas streamby the existing ESPs". This statement fails to recognize that submicron aerosols will pass through the electrostatic precipitator (ESP) and further ignores that
a wet flue gas desulfurization ("scrubber") system upstream ofatail-end SCR is largely ineffective atremoving such aerosols.

The infeasibility ofSCR technologies at the MRYS is related to the following issues:

• Cyclone boiler firing characteristics

- high temperature slag formation and removal increases production ofreactive sodium and potassium rich aerosols

• High sodium lignite contains high levels oforganically associated sodium that is prone to form aerosols when fired, especially in slagging-type boilers

• Heattransfer surface configurationrequired for fuel drying and heatrecovery results in high temperature issues for high-dust SCR

• Highly cohesive and reactive sodium rich ash thatblinds, plugs, and poisons high-dust SCRcatalyst

• ESP and scrubbers do notremove reactive submicron aerosols thatblind, plug, and poison low dust and tail end SCR catalyst. No tail-end SCRs have been installed on any full-scale, full-time lignite-firedutility boilers anywhere in the world.

There is no demonstrated evidence thatthese infeasibility issues have been overcome. Recent literature supports conclusions thathigh dust, low dust, and tail end SCR are not feasible because ofthe presence ofsodium- and potassium-rich aerosols in the flue gas stream. No SCRcatalyst

Combined Responses to NDDH (11-17-2008 final).doc 14 November 17, 2008designs have been developed that can avoid blinding and deactivation by highly-concentrated alkali aerosols in the flue gas. Therefore, it is wrong to assume that SCR systems that have yet to be tested, designed, and proven to be capable ofenduring ormodifying such challenging flue gas conditions that exist atthe units atM.R. Young Station shouldbe considered as technically feasible, withouthaving been successfully installed, operated, and maintained on similarboilers and fuels. It is an invalid response to suggest that Minnkota is required to conduct an extended pilot testprogram or full-scale experimental construction and testing project for the purposes of supporting a BACT determination, when the EPA's own draft NSRWorkshop Manual's definition ofa technically feasible control excludes those projects.

EPA's previous comments (U.S. EPA, July 2008) suggestthatthe BACT decision shouldtum on cost-effectiveness considerations. This argument puts the cost-effectiveness "cart" before the technical feasibility "horse". The top-down BACT process very clearly eliminates technically infeasible alternatives from the cost-effectiveness analysis. Ithas beenpreviously demonstrated (Arfmann et aI, August 2007) that SCRis-underthe definitions provided in the NSRWorkshop Manual relating to availability and applicability-technically infeasible in this case. EPA's suggestion that the hypothetical application ofa technically infeasible technology could potentially be a cost-effective emissions control method that constitutes BACT is at odds with the NSRWorkshop Manual.

The EPA and the DOl's commentercontinue to argue that this is a case where hypothetical fullscale ordemonstratedpilot-scale SCRtechnology performance data mustbe quantified for a BACT analysis in orderto refute the EPA's position that SCR is technically proven forNOx reduction on all fossil fuels, not excluding North Dakota lignite, while ignoring the severe pore plugging documented for the Coyote Stationpilot SCRcatalyst testing experience (Benson and others, 2005) along with boiler firing method-specific and fuel-specific technical reasons for the technology's infeasibility.

Combined Responses to NDDH (11-17-2008 final).doc 15 November 17, 2008

## Corrections, Clarifications and Omissions of Hartenstein's Remarks The DOJ commenter's (Hans Hartenstein's) October2008 remarks need to be clarified and corrected for the administrative record.

RESPONSES TO GENERAL REMARKS: 1. The lackofcatalyst deactivation data for high-dust, low-dust, ortail-end SCRtechnology, if itwere to be applied to the boilers atMRYS, supports the argument that an extendedpilot testprogram or full-scale experimental construction and testing projects would need to be conducted in orderto compare with otherpilot-scale or full-scale catalyst experience on cyclone boilers firing other coals before confirmation oftechnical feasibility canbe confirmed. It is erroneous to assume thatthe fine sodium sulfate aerosols in MRYS boiler flue gas that will deactivate SCRcatalystwill be sufficiently removed by the ESP and wet scrubber systems upstream ofa tail-end SCR, and therefore are unlikely to pose a rapid deactivation threat. ESPs andwet scrubbers are nothighly efficient atremoving fine submicronparticles and aerosols that contain high levels ofsodium, potassium, and sulfuric acid (Buecker 2008; Ohlstrom and others, 2006, Hurley and Katrinak, 1992). These submicron species have been shown to penetrate the micropores ofthe catalystby diffusion processes, as previously described by EERC (Benson and others, 2005; Minnkota 2007A, B, C; Burns & McDonnell and others, April 2007, May 2007, May 2008, September2008; Arfmann and others, August 2007).

Recent workconductedby Zheng and others (2008) describedthe diffusion ofaerosols and their ability to cause catalystpoisoning. These efforts followed earlier studies where Zheng and others (2005) found thatbiomass derived alkali rich aerosols caused a drop inNOx reduction activity by 52% after about 1140 hours ofoperation. SCRvendors were specifically requested (Burns & McDonnell, April 2007, May 2008) to provide data that would support the EPA's arguments thathigh-sodium North Dakota lignite would notbe infeasible for full-scale, full-time cyclone boiler SCR applications. The details ofany estimates ofcatalyst life and deactivation rates offeredby vendors were not made available for review.

Combined Responses to NDDH (11-17-2008 final).doc 16 November 17, 20082. Hartenstein remarked thatbecause Bums & McDonnell's SCR Consultant (Tackticks) did not actually state that SCR is technically infeasible atMilton R. Young Station, thattheir opinions do not support this same conclusion expressedby B&McD and EERC. Hartenstein has drawn this conclusion without recognizing the arguments Tackticks made that correspond to the previously statedposition and interpretation (Arfmann and others, August 2007) of"technical feasibility" as described in the EPA's 1990NSRWorkshop Manual. It is
our collective position, based on valid arguments providedby Minnkota, Bums & McDonnell, Steve Benson, VolkerRummenhohl, and several SCR system suppliers, that successful application ofSCR technology on this fuel atthis powerplanthas notbeen sufficiently demonstrated by actual relevantpilot- or full-scale experience to confirm its technical feasibility as statedpreviously with ourinterpretation ofthe definition ofthose terms.

VolkerRummenhohl was responsible for the process design of26 tail-end and 7 low-dust SCRs with re-heat systems. The first one started in Germany in 1987, and the last ended in 2008 (but was not subsequently approved for implementation). Mr. Rummenhohl was also responsible for the commissioning often tail-end SCRs and the O&M performance ofsix tail-end and one low-dust SCRs with reheat.

We agree with VolkerRummenhohl that it is extremely imprudentto apply SCRto a utility boilerwith such differences in firing type and fuel burned comparedto those situations that have been proven successful without first performing extensive pilottesting and achieving acceptable results, followed by confirming the feasibility ofthe full-scale design. One cannot lookjust at the bulk flyash loading and average concentrations ofthe trace elements and otherpoisons in the fuel to decide whether SCRtechnology will work. It is incorrect to make ablanket statement such as made by Hans Hartenstein 

### in his October2008 remarks that implies it is always feasible to install TESCR.



### RESPONSES TO SPECIFIC COMMENTS: 1. EERC has provided detailed information that explains why SCRs are not able to tolerate the higherlevels ofalkali species, especially 

### in aerosol form, contained in flue gas such as that exhausted from the MRYS boilers as compared to PRB coal-firedboilers that have applied
Combined Responses to NDDH (11-17-2008 final).doc 17 November 17, 2008high-dust SCRs. Hartenstein incorrectly states that Coyote pilot-scale SCRtesting in a highdust configuration does not "properly representthe types ofdeactivation mechanisms orthe rate ofcatalystdeactivation that canbe expected in a TESCR".

As describedpreviously, fly ash producedupon combustion ranges in size from submicron aerosols to particles greaterthan 10**~m.** The very small sodium andpotassium enriched particles diffuse into the pore ofcatalystno matter ifit is low-dust ortail-end SCR catalyst causing rapid plugging, blinding, and deactivation. These small particle are very cohesive and reactive. EERC has described the fine particulate and aerosols released from cyclone boiler combustion are especially enriched with sodium andpotassium sulfates and other compounds when generated from firing North Dakota lignite. Combustion ofNorth Dakota lignite in the cyclone-firedboilers atMilton R. Young Station promotes the vaporization of sodium and potassium and the production ofsubmicronparticles and aerosols through homogeneous condensation ofthe vaporized species. These fine materials, which are comprised ofhighly-concentrated sodium and sulfurcontaining compounds, are entrainedin the flue gas stream. Submicronparticles and aerosols are not effectively removed from the gas streamby the high-efficiency electrostatic precipitators norby wet lime-based flue gas desulfurization systems (scrubbers).

SCR catalyst can be become ineffective in the following ways:

• Plugging channels by so called "popcorn ash" or in many cases typical ofash deposits fragments. Channel plugging is largely driven by the size ofthe ash materials carried back into the system and can be controlledby the use ofscreens to remove the ash or largerpitch catalyst.

• Masking ofthe surface by a dense phase. The phases that form are typically sulfates that
cause bonding ofotherparticles (silicates and aluminosilicates) on the surface. The sulfates have formed as a result ofin situ sulfation ofdeposited alkali and alkaline earth materials.

• Diffusion ofsmall particles and aerosols into the pores ofthe SCRblocking the diffusion ofNOx and ammonia to the active sites.

Combined Responses to NDDH (11-17-2008 final).doc 18 November 17. 2008• Poisoning ofthe active sites in the catalystby the diffusion ofvarious types ofreactive aerosols such as those rich in sodium andpotassium. The aerosols will diffuse into the pores and react with the active components ofthe catalyst.

The lattertwo mechanisms do not rely on the bulk loading offlyash present in the gas stream. While the majority ofthe bulk flyash mass will have been removed by the upstream ESP and wetFGD scrubber for a tail-end SCR, there will still be a large number ofvery small and reactive particulate and aerosols that will severely affectthe catalyst. Because these residual aerosols and fine particulate are nottotally removedby the upstream gas treatment equipment, they are not negligible as the DOl's commenter suggests.

As VolkerRumrnenhohl (see Appendix A) and others have stated in the citedreferences, the concentration ofcertain elements such as alkali and other species (arsenic and sulfuric acid aerosol), do nothave to be large in magnitude before they will cause significant catalyst deactivation orbecome visible. In cyclone-fired system the ash is partitionedbetween fraction that leaves the cyclone with the bulk gas flow and the materials that are retained in the slag. The fraction leaving the cyclone with the hot gases are enrichedin fine particulate and vapors that will have high levels offlame-volatilized species such as sodium, potassium, and sulfurrelative to the molten slag. The molten slag-related has a higher abundance of lowervolatility material. The fly ash is enriched in the volatile elements that are in the form ofsubmicronparticles and aerosols. The submicronparticles and aerosols are notremoved sufficiently by an ESP and wet scrubberto eliminate theirblinding, plugging, and deactivation tendencies for SCR catalyst in a TESCR configuration. The removal efficiency for fine particles and aerosols less than 1 flm (micron) is documented in EPA's report entitled "Stationary Source Control Techniques Document for Fine Particulate Matter" (Woodward, 1998). The authors reported the following on page 209: "Most conventional scrubbers can achieve high collection efficiencies for particles greaterthan 1.0 flm in diameter, however they are generally ineffective collection devices for submicrometer «1 flm) particles."

2. The main powerboilerwith an SCR (Unit 2) at the Avedore utility powerplantmentionedby Hartenstein (Hartenstein, October2008) is amultiple-fuel fired system, and is not continuously fired with 100% biomass as may be implied. A smallerAvedore boiler
Combined Responses to NDDH (11-17-2008 final).doc 19 November 17, 2008associated with Unit 2 is fIred with 100% wood pellets and/or straw biomass, which does not exhaust its flue gas through any SCR. The main boiler's flue gases are significantly dominated by the main fuel, which can be natural gas, heavy fuel oil, orbituminous coal. The SCR for the main boiler is exposedto areduced concentration ofco-fired wood biomass-related emissions. The first bargraph in the citedreference presentation (Noppenau, 2006) shows that 100% natural gas was fired for three continuous months (July, August, September), and straight fuel oil was fired during the three wintermonths (January-March). It appears that wood pellets were co-fired with fuel oil during April-June and OctoberDecember. So the catalyst exposure to biomass-related flue gases at Avedore is not as drastic
as Hartenstein implied.
According to the catalyst washing technical presentation paperby HaldorTopsoe (White, 2007) citedby Hans Hartenstein, the main boiler's SCR catalyst at Avedore Unit 2 has required rejuvenation nine times and replacement once within the first 30,000 hours of operation. When reviewed in combination with the otherpaper (Noppenau, 2006), it is apparentthat a significantportion ofthe annual operating time for the main Avedore Unit 2 boiler does not involve co-firing ofbiomass. Based on the dataprovided, the actual rate of catalyst deactivation couldbe much more significant than the above numbers imply. Substantial, rapid deactivation is indicated, requiring catalyst maintenance activities on the order ofapproximately every 1000 hours ofestimatedbiomass co-firing operation.

VolkerRummenhohl considers this frequency ofcatalystwashing excessive, and believes this is not indicative ofa successful SCRinstallation. Ofcourse, catalystvendors and other companies provide catalyst washing services, so this is good for such businesses. 

### Mr. Hartenstein himselfhas been employed as the president ofsuch a company (Hartenstein, July 2008), so his opinion on this subjectmay be influencedby his previous personal involvement.

3. Hartenstein discounts the silicon tetrafluoride blinding problems from firing bituminous coal in certain German utility TESCRs as isolatedandvery short in duration. Volker Rummenhohl was in charge ofthe investigation ofthis phenomena and it was very serious for the supplier and utility (Steag) that was experiencing the rapid catalyst deactivation. If
Combined Responses to NDDH (11-17-2008 final).doc 20 November 17, 2008rapid TESCRblinding and decreasedremoval performance were to occur at a site such as MRYS, the 3D-day rolling average emission requirements would still need to be met continuously.

4. Hans Hartenstein repeats what one catalystvendor said (Burns & McDonnell and others, May 2008): thatthe Coyote Station SCR slipstreampilot testing demonstrated that 6 mm pitch catalyst is not suitable for a high-dust SCR application featuring highly adhesive flyash. At least one importantpoint can be made from these and other situations showing rapid catalystdeactivation. The published experiencebase for catalyst designs suitable for coalfired boiler applications orcoal additives that are available and been proven to tolerate or alleviate the severe blinding and plugging ofthe catalystpore structure due to the high levels ofsodium-rich aerosols present in flue gases derived from the cyclone-fired combustion of ND lignite is extremely small. As EERC has stated in previous comments, catalyst exposed to sodium sulfate aerosols are subjectto the same blinding and deactivation mechanisms regardless ofcatalystpitch.

The most important catalyst deactivation mechanismto recognize is diffusion ofaerosols into the pores ofthe catalyst followed by reaction ofthe alkali (sodium and potassium) with active sites in the catalyst and/orthe reaction ofgas phase S02 and S03 to produce sulfates and pyrosulfates. Recently testing was conductedby Strege and others (2008) at a stokerfired utility boiler firing a blend ofbiomass and PowderRiver Basin coal (PRB) using the
same reactorthat was used atthe Coyote Station. The main difference in the recenttesting as comparedto the Coyote tests was that the nozzle normally used to isokinetically extractthe flue gas was pointed in the same direction ofthe gas flow to minimize the extraction oflarge particles from the flue gas stream into the reactor. The exposed catalyst was tested for reactivity and they found that the catalyst deactivation rate was about 18% per 1000 hours. The components responsible for the deactivation were sodium, potassium, and calcium sulfate based materials. Alkali components (sodium and potassium) were found deep inside the pores ofthe catalyst.

5. The abundance ofsodium and other ash forming components vary dramatically in various types ofbiomass cited as examples ofsimilarity to North Dakota lignite-fired cyclones
Combined Responses to NDDH (11-17-2008 final).doc 21 November 17, 2008relative to SCR applications. The typical levels ofash and sodium in typical wood as cofired in powerboilers is lowerthan the range indicated in the comparison table provided in Mr. Hartenstein's October2008 remarks. The amount and form ofalkali species in the coal along with combustion processes influence their ability to be enriched in the aerosol and fine particle fraction ofthe fly ash. The size and composition ofthe particle along with gas velocity determines their ability to penetrate and deposit on SCR catalystpassages and in pores and cause plugging, blinding, and poisoning.

6. Hartenstein did notrefute the formation ofaerosols orthe mechanism ofpartitioning between the slag and fly ash components in cyclone-fired systems thatresult in an enrichment of sodium and other flame-volatilized species in the flue gas.

7. Hartenstein apparently agrees thatpenetration ofalkali-rich aerosols in the flue gas from high sodium FortUnion (North Dakota lignite) coals fired in cyclone-firedboilers into the pores ofSCR catalystwill cause significantblinding andpoisoning in high dust SCR applications. He also seems to believe thatthis will notbe the case for tail-end SCR applications, which he
assumes will see flue gases cleaned and scrubbed ofharmful elements removed by the upstream treatment equipment.

8. Hartenstein's discussion did not include statements ofcatalystvendor guarantee experience associated with European coal-firedutility boilers cofiring high alkali (Na and K) containing biomass. Based onrecent contacts, Volker Rummenhohl has learnedthat many catalyst vendors are reluctant orunwilling to guarantee catalystperformance in such applications.

9. There is conflicting information regarding the startup date ofthe tail-end SCR at Rudow Unit 2 (Fisia Babcock, IEA Coal Research). The important issue to understand is thatthe contract to retrofit a TESCRon the Rudow unit was signedpriorto 1990, it fired bituminous coal, not lignite, and was placed into cold standby in 1998 (andhas since been decommissioned). Assuming the execution ofthe projectwas delayeduntil completion occurred in 1994, it does not change the fact that no othertail-end SCRs have been designed and installed for operation on coal-firedutility boilers for more than a decade, either in the United States or Europe.
Combined Responses to NDDH (11-17-2008 final).doc 22 November 17, 200810. The statement thatthe Walsum Unit 7 boilerburning bituminous coal cited in previous comments (Bums & McDonnell et aI, September2008) as operating with a LDSCR, not a TESCR, was notrefuted by Hans Hartenstein; the remarks indicate this unit not being cyclone-fired is also debatable, as there are otherreferences that indicate the unit employs cyclone burners.

11. Out ofthe hundreds ofEuropean SCRs installed on coal-firedpowerplants, experience at lignite-firedutility boilers has been very limited and dissimilarto the conditions atMilton R. Young Station. One high-dust SCR installation was at Voitsberg Unit 3 (Austria) and there
were HDSCRs on three units at the Bayernwerk Schwandorfplant in Germany. These units
were not slagging-type (cyclone-fired), the fuel burned was much lower in sodium and other alkali elements than contained in North Dakota lignite. These units are no longer in operation.


## Conclusions

In the end, EPA's objections to NDDH's Preliminary BACT Determination may be reduced to disputing NDDH's characterization ofthe gas stream characteristics and the impacts ofthose characteristics on boiler and emissions control operations. EPA and Hartenstein suggest that these impacts canbe resolvedby the use ofTESCR, and that TESCRtechnology will work at MRYS (July, 2008). We believe their arguments are flawed because they fail to recognize the significance ofthese facts:

• There is no priorexperience with full-scale SCR ofany type on any utility boiler firing North Dakota lignite.

• Results from the only known example ofsimulating SCR catalyst exposure to high-alkali containing flue gases produced from firing North Dakota lignite in a cyclone boiler showed severe, rapid catalystblinding and plugging due to sodium and potassiumrich species (Benson and others, 2005). The Coyote pilot-scale SCRtest was intendedto evaluate the fouling potential ofSCRon lignite coal. It was developed by a consortium

Combined Responses to NDDH (11-17-2008 final).doc 23 November 17. 2008ofthree catalystvendors, EPRI, U.S. DOE, and otherparticipants that design and install SCR systems as well as end-userutilities thathave applied SCR on theirboilers. This experience demonstrated the generation ofalkali-sulfate compounds thatplugged every micropore ofthe test catalyst when examinedunder a scanning electron microscope. This catalystblinding andplugging was so severe that the catalystvendor who supplied it
was unwilling to analyze it for deactivation.

• European SCRexperience at lignite-firedutility boilers has been very limited and dissimilarto the conditions at Milton R. Young Station. One high-dust SCR installation
was at Voitsberg Unit 3 (Austria) and there were HDSCRs on three units atthe Bayernwerk Schwandorfplant in Germany. These units were not slagging-type (cyclonefired), the fuel burned was much lowerin sodium and other alkali elements than contained in North Dakota lignite. These units are no longerin operation.

• There has neverbeen, to the best ofourknowledge, any tail-end SCRs applied to coalfired utility boilers burning lignite in Europe. There have been no full-scale TESCRs downstream ofa wetFGD scrubber and electrostatic precipitator installed on any coalfired utility boilers inNorth America (see Appendix A). Aerosols will still getthrough the ESP and wet FGD scrubber, so catalyst deactivation problems will occur similarto or worse than those experiencedby SCRs fitted to boilers co-fired with large amounts of alkali-producing biomass. We do not know ifthese problems will be successfully solved.

• The gross amount ofash, and specifically the sodium andpotassium fraction ofthe lignite coal ash, is notrelevantto whether low-dust ortail-end SCR catalyst will become rapidly plugged, blinded, and deactivated. Combustion ofNorth Dakota lignite in the cyclone-firedboilers atMilton R. Young Station promotes the production ofsubmicron particles and aerosols. These fine materials comprised ofhighly-concentrated sodium sulfate, are produced from the condensation offlame volatilized species and are entrained in the flue gas stream. Submicronparticles and aerosols are not effectively removed from the gas stream by the high-efficiency electrostatic precipitators norby wet limebased flue gas desulfurization systems (scrubbers).

• Statements ofSCRcatalystvendors being willing to guarantee theirproductresulting from a Bums & McDonnell query and follow-up (2007, 2008), and subsequentclaims by

Combined Responses to NDDH (11-17-2008 final).doc 24 November 17, 2008the DOl's commenter (July 2008) are basedupon the premise by these vendors that exposure ofthe catalyst to suitable operating conditions will occur; whether it is possible to achieve such conditions is nottheir responsibility.

• There canbe no substantiatedbasis established such thatthe performance and longevity ofsuchhypothetical solutions couldbe estimated withoutperforming extensive pilot scale testing thatproves that SCRcatalyst can avoid blinding and deactivation by the alkali aerosols in the flue gas, and developing detailed designs ofworkable, effective solutions to the existing conditions. It is wrong to assume that SCR systems that have yet to be tested, designed, andproven to be capable ofenduring ormodifying such challenging flue gas conditions that exist at the units atM.R. Young Station shouldbe considered as technically feasible, withouthaving been successfully installed, operated, and maintained on similarboilers and fuels. It is an invalidresponse to suggestthat Minnkota is required to conduct an extendedpilottestprogram orfull-scale experimental construction and testing project for the purposes ofsupporting a BACT determination, when the EPA's own draftNSRWorkshop Manual's definition ofa technically feasible control excludes those projects.

• Because ofthe unique boilerconfigurations and firing characteristics employedby these boilers and the fuel they burn, there is no substantive certainty ofhow all the documented temperature issues for high-dust SCR and the submicron aerosols and flue gas conditions for any SCR configuration, wouldbe favorably resolved for the boilers atMRYS. As far
we are aware, there have been no high-dust SCRs installed on cyclone-firedboilers that have the kind offuel drying and heat recovery systems employed at MRYS.

• VolkerRummenhohl is an experienced SCRprocess design engineerwho has been responsible for the process design of26 tail-end and 7 low-dust SCRs with re-heat system. Volkerhas stated, and we concur, that it is extremely imprudentto apply SCRto
a utility boilerwith such differences in firing type and fuel burned comparedto those situations thathave beenproven successful without first performing extensive pilot testing, achieving acceptable results, followed by confirming the feasibility ofthe fullscale design. One cannot lookjust at the bulk flyash loading and average concentrations ofthe trace elements and otherpoisons in the fuel to decide whether SCRtechnology will

Combined Responses to NDDH (11-17-2008 final).doc 25 November 17. 2008work. It is incorrectto make ablanket statement such as made by Hans Hartenstein in his October 2008 remarks that implies it is always feasible to install TESCR.

• Basedupon all the evidence presented to date, it is technically infeasible to apply any form ofSCRtechnology (high-dust, low-dust, ortail-end SCR) to the lignite-fuel cyclone-firedboilers at the Milton R. Young Station.

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_article/326581/6/ARTCL/none/none/1/How-PollutantsAreFormed-During-Combustion-(And-How-It-Affects-Control-Methods)/ Bums & McDonnell, NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 1 Minnkota Power Cooperative, Inc. and a separate NOx BestAvailable Control Technology Analysis Study for Milton R. Young Station Unit 2 Square Butte Electric Cooperative, October 2006. Bums & McDonnell and Energy & Environmental Research Center (EERC), Information Request (SCRVendor Query and Attachments), April 2007. Bums & McDonnell and Energy & Environmental Research Center (EERC) presentation, Summary ofResponses to EPA/DOH Questions on Minnkota Power's NOx BACT Analysis for Milton R. Young Units 1 & 2, to North DakotaDepartment ofHealth, Environmental Health Section, Division ofAir Quality, andUnited States Environmental Protection Agency, May 23, 2007.

Combined Responses to NDDH (11-17-2008 final).doc 26 November 17, 2008Bums & McDonnell and Energy & Environmental Research Center (EERC), Additional Information and Discussion ofVendorResponses on SCR Technical Feasibility North Dakota's NOx BACT Determination for Milton R. Young Station Units 1 & 2, May, 2008. Bums & McDonnell, Energy & Environmental Research Center ofthe University ofNorth Dakota, and Tackticks, Comments and Responses to NDDH Regarding U.S. EPA Region 8's July 31,2008 Comments and Plains Justice July 30, 2008 Comments on NDDH Preliminary NOx BACT Determination for Milton R. Young Station (MRYS), September22,2008.
Chen, J.P.; Buzanowski, M.A.; Yang, R.T.; Cichanowicz, J.E., Deactivation ofthe Vanadia Catalyst in the Selective Catalytic Reduction Process. J. AirWaste Manage. Assoc. 1990,40, 1403-1409. ConsentDecree filed in the United States District Court ForThe District OfNorth Dakota, United States OfAmerica and State OfNorth Dakota, Plaintiffs, v. MinnkotaPower Cooperative, Inc. and Square Butte Electric Cooperative, Defendants, Civil ActionNo.1 :06-CV034, filed April 24, 2006. Fisia Babcock SCRInstallation Reference List, accessed on 11/3/2008 athttp://www2.fisiababcock.eu/references.php?list=5. Guo, 

## x., Poisoning and Sulfation on Vandia SCR Catalyst. Doctor ofPhilosophy Dissertation, Department ofChemical Engineering, BrighamYoung University, August 2006.
Hartenstein, H.-U., Enclosure 1 to U.S. EPA Region 8 July 31, 2008 letterto NDDH: Hans Hartenstein's Expert Opinion Report Feasibility ofSCRTechnology for NOx Control Technology for the Milton R. Young Station, Center, North Dakota on Behalfofthe United States Department ofJustice, July 2008. Hartenstein, Hans, Enclosure to U.S. EPA Region 8 October 17, 2008 letterto NDDH: Remarks to the "Comments and Responses to NDDH Regarding U.S. EPA Region 8's July 31, 2008 Comments and Plains Justice July 30, 2008 Comments on NDDH PreliminaryNOx BACT Determination for Milton R. Young Station (MRYS)" dated September22, 2008, on behalfof the United States Department ofJustice, October2008. Hurley, J.P.; Katrinak, K.A., Determination ofAsh Formation and DepositionMechanisms at Minnesota Power Clay Boswell Station; DOE/MC/l0637-3365, July 1992. lEA Coal Research book "NOx control installations on coal-firedplants" (Rudow Unit 2 TESCR startup listed as 1990). Khodayari, R., Andersson, C., Odenbrand, C.U.I., Andersson, L.H., in: Proceedings ofthe Fifth European Conference on Industrial Furnace and Boilers, vol. II, 11-14 April 2000, Espinho, Porto, Portugal, 2000.

Combined Responses to NDDH (11-17-2008 final).doc 27 November 17, 2008Khodayari, R, Selective Catalytic Reduction ofNOx: Deactivation and Regeneration Studies and Kinetic Modeling ofDeactivation, Ph.D. Thesis, 2001, Dept. ofChemical Engineering II, Lund, Sweden. Kling, A.; Andersson, 

### c.; Myringer, A.; Eskilsson, D.; Jaras, S.G., Alkali Deactivation ofHighDust SCR Catalysts Used for NOx Reduction Exposed to Flue Gas from 100-MW-Scale Biofuel and Peat Fired Boilers: Influence ofFlue Gas Composition. Applied Catalysis B: Environmental 2007,69,240-251. Markowski, G.R., Downs, 

### lL., and Woffinden, GJ., Sulfate Aerosols from Western Low-Rank Coal-Fired Boilers with FGD: Summary ofTests at Coal Creek, Clay Boswell, Milton R Young, and San Miguel Stations, DOE/FC/I0182-tl5 (DE83014539), May 1983. Miles, T.R; Miles, T.R; Baxter, 

### L.L.; Bryers, RW.; Jenkins, B.M.; Oden, 

### L.L., Alkali Deposits Found in Biomass Power Plants. A Preliminary Investigation ofTheirExtent andNature; Summary Report for National Renewable Energy Laboratory SubcontractNo. TZ-2-1-1226-1, April 1995.

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses To EPA Comments NOx BACT Analysis Study Milton R Young Station Unit 1 and Unit 2 Regarding SCRTechnical Feasibility March 15,2007 (re: U.S. EPA Region 8 letterJanuary 8, 2007), March 19,2007. (2007 A) Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses To NDDH and EPA Comments Regarding SCRTechnical Feasibility andNon-SCR Concerns Milton R Young Station Unit 1 and Unit 2 NOx BACT Analysis Study April 18, 2007 (re: NDDH letter February 1,2007 including U.S. EPA Region 8 letterJanuary 26,2007), April 23, 2007. (2007 B) Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Comment and Response To EPA Region 8's October4,2007 Comment on NDDH BACT Determination at Milton R Young Station, (re: U.S. EPA Region 8 letter October4,2007), November, 2007. (2007 C) Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Additional Information and Discussion ofVendor Responses on SCRTechnical FeasibilityNorth Dakota's NOx BACT Determination for Milton R. Young Station Units 1 & 2, May 8, 2008. ND Department ofHealth, Division ofAir Quality Preliminary Best Available Control Technology Determination for Control ofNitrogen Oxides for M.R. Young Station Units 1 and 2, June 2008, released for public comment June 3, 2008. Noppenau, Henrik, CleanerFossil Fuels for Sustainable Development Co-firing Coal and Biomass, Accessed 10/2812008 at http://www.usea.org/CFFS/CFFSNeptun/Co-firing%20- (WEC-CFFS)%20Neptun%20June%2013%202006.pdf Ohlstrom, Mikeal, Jokiniemi, Jorma, Hokkinen, Jouni, Makkonen, Pasi, andTissari, Jarkko, Combating Particulate Emissions in Energy Generation and Industry, Tekes, VTT Technical Research Centre ofFinland, 2006.

Combined Responses to NDDH (11-17-2008 final).doc 28 November 17, 2008Strege, lR.; Zygarlicke, C.l; Folkedahl, RC.; SCRDeactivation in a Full-Scale Cofired Utility Boiler. Fuel 2008, 87 (7), 1341-1347. Tolbert, S.G.; Benson, S.A. N Task 117

- Impact ofLignite Properties on Powerspan's NOx Oxidation System; Final Report (May 1 - Dec 31, 2007) for U.S. Department ofEnergy National Energy Technology Laboratory Cooperative Agreement No. DE-FC26-98FT40321, Powerspan, Montana-DakotaUtilities Co., Minnesota Power, BasinElectric PowerCooperative, North Dakota Industrial Commission, and Minnkota PowerCooperative, Inc.; EERC Publication 2008- EERC-03-09; Energy & Environmental Research Center: Grand Forks, ND, April 2008. United States Environmental Protection Agency (US. EPA or EPA) Region 8 letterby Andrew M. Gaydosh, Assistant Regional Administrator, Office ofEnforcement, Compliance and Environmental Justice to Terry L. O'Clair, Director, Division ofAir Quality, North Dakota Department ofHealth, Re: Transmittal ofEPA's Comments on North DakotaDepartment of Health's PreliminaryNOx BACT Determination for Milton R. Young Station, date stamped July 31,2008 (with Enclosures). Enclosure 2 to US. EPA Region 8 July 31, 2008 letterto NDDH: EPA's Comments on NDDH Preliminary BACT Determination. United States Environmental Protection Agency (US. EPA orEPA) Region 8 letterby Andrew M. Gaydosh, Assistant Regional Administrator, Office ofEnforcement, Compliance and Environmental Justice to Terry L. O'Clair, Director, Division ofAir Quality, North Dakota Department ofHealth, Re: Transmittal ofEPA's Response to Minnkota's Letter on Public Comments Received for the North Dakota DepartmentofHealth's Preliminary NOxBACT Determination for Milton R. Young Station, date stamped October 17, 2008 (with Enclosure). U.S. EPA New Source Review Workshop Manual, Prevention ofSignificant Deterioration and Nonattainment Area Permitting, Office ofAir Quality Planning and Standards, Research Triangle Park, N.C. 27711 (the Draft October 1990 "NSRManual") White, Nathan, Washing Your Own Catalyst, NOx Round Table 2007, Cincinnati, Ohio, February 5-6, 2007. Woodward, K. , Stationary Source Control Techniques Document for Fine Particulate Matter, EPA-452/R-97-001, October 1998. (http://www.epa.gov/ttncatcl/dirl/fmepmtech.pdf) Zheng, Y.; Jensen, A.D.; Johnsson, lE. Deactivation ofV205-W03-Ti02 SCR Catalyst at a Biomass-Fired Combined Heat and PowerPlant; Applied Catalysis B: Environmental 2005 60, 253-264. Zheng, Y.; Jensen, A.D.; Johnsson, lE.; Th0gersen, lR. Deactivation ofV205-W03-Ti02 SCR Catalyst at Biomass Fired Power Plants: Elucidation ofMechanisms by Lab- and Pilot-Scale Experiments; Applied Catalysis B: Environmental. 2008, 83, 186-194.

Combined Responses to NDDH (11-17-2008 final).doc 29 November 17, 2008APPENDIX A VolkerRummenhohl's Report "CatalystPoisoning"

Combined Responses to NDDH (11-17-2008 final).doc November 17, 2008CatalystPoisoning By VolkerRummenhohl, Fuel Tech, Inc. November 17, 2008 Selective Catalytic Reduction (SCR) Catalyst canbe rapidly deactivated (poisoned) by fuel impurities. Some ofthese impurities are present attrace levels. These impurities can eitherplug the pores physically or react with the active centers in the pores chemically on apermanentbasis and reduce the number ofactive cells. The impurities can interact with the catalyst in three phases: solid, liquid, and vapor (gas). Many trace elements such as arsenic (As), selenium (Se), lead (Pb), cadmium (Cd), antimony (Sb), and othermore abundant elements, such as sodium (Na), potassium (K), and phosphorus (P) will vaporize during combustion and condense on the surfaces oflarger entrained particles orbe emitted as elemental aerosols. The larger solidtrace element-containing particles are too large to penetrate the pores. They will remain on the surface ofthe catalyst and are neutral regarding the activity, butmay mask orblindthe pores so that ammonia andNOx molecules cannotreach the active sites to react. Particulate loading is not ofconcern when the cause ofthe catalyst deactivation is due to aerosols. The aerosols are less than amicrometer in diameter and can be in a liquid or solid state. The condensed aerosols can penetrate into the pores ofthe catalystby diffusion processes and can accumulate and react within the catalyst, plugging and poisoning active sites. In addition, trace elements in a liquid solution can further penetrate the pores. In Minnkota's case, major elements such as sodium andpotassiumproduce aerosols and liquidphase mixtures that will blind and poison catalysts. As previously discussedby EERC, combinations ofsodium-potassium-pyrosulfate salts can have liquid (i.e. melting point) temperatures as low as 535°F. Submicron sodium- and potassium-rich aerosols penetrate catalystpores and cause physical plugging ofthe catalystpores and poisoning ofthe active sites. Arsenic in bituminous coal is an example ofa well-known catalyst deactivation mechanism involving a trace element in vaporform thatpenetrates the micropores, reacts with the active sites during SCR operation, and causes rapid deactivation by permanently poisoning the catalyst. The relevant catalystpoisons in the case ofM)'RS are sodium andpotassium. Both elements are known catalystpoisons in case biomass is co-fired with the primary fuel in utility boilers!. Since widespread use ofbiomass co-firing in utility powerboilers equipped with SCRcatalysts is relatively recent, specific publishedknowledge ofthe successful methods ofavoiding ormitigating the negative effects on SCRcatalyst deactivation is limited. Forthis reason, we will use arsenic as an example to demonstrate catalystvendors' initial lack ofawareness and the subsequentunderstanding ofthe deactivation mechanism.

Catalyst Poisoning, VolkerRummenhohl November 17, 2008

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The application ofSCRtechnology to utility boilers was first performed in 1975 on a utility boiler in Japan. The second country using the technology on powerplants was Germany. It started in the mid 1980s with demonstration andpilotplants. Arsenic was notknown to be acatalystpoison atthattime. One German utility insisted on apilot plant despite the fact that all Japanese catalyst licensors were willing to provide all guarantees withoutpilottesting. The result ofthe pilot test in the power station Franken was that the catalyst suppliedby four different suppliers significantly deactivatedin 200 hours due to arsenic poisoning. Since this occurred, there has been significant and lengthy investigations, pilot and full-scale catalyst testing at utility powerplants and product developmentto identifY causes and solutions2• Arsenic in a gaseous form is a strong catalystpoison. The critical concentration of gaseous arsenic trioxide (As20 3 ) is 10 Jlg/Nm. Almost all catalyst suppliers have this standard. The suppliers add catalyst volume to meet guarantees when the concentration ofarsenic trioxide in the flue gas entering the SCRreactoris between 10 and 50 Jlg/Nm3

. Longevity ofcatalystexposedto an arsenic concentration over 50 Jlg/Nm3in the flue gas at the inlet ofthe SCR will notbe guaranteedby the catalyst supplierwithout subsequent arsenic mitigation as described below. The art ofthe catalyst design in such cases is to decide how much gaseous arsenic will be in the flue gas based on the fuel specification. In one case, ahigh sulfurbituminous coal contained 30 ppmAs by weight in the coal. This would result in 3850 JlglNm3ifall fuel arsenic would become gaseous. This demonstrates that a very small fraction ofthe fuel arsenic

- less than 0.1 ppmby weight for bituminous coal, is the limit for SCR operation withoutproblems. There are several factors determining the amount ofgaseous arsenic that is produced during combustion ofarsenic-containing coal. The free calcium oxide (CaO) content in coal is the most important factor. Calciumbinds arsenic in the solid form [calcium arsenate, Ca3(As04h]. German experience showedthat ifthe free CaO concentration in the fuel is above 2 to 2.5% by weight ofthe ash, arsenic is not aproblem for the catalyst. Addition oflimestone into the furnace (boiler combustion zone) is required ifthe free CaO in the fuel is insufficientto prevent arsenic poisoning ofthe catalyst. The sulfur content ofthe German bituminous coals involved with arsenic catalyst poisoning was approximately 1% by weight. Experience in the U.S. demonstrated that the free CaO concentration mustbe higherifthe sulfurcontent is higher. The reason for this is the increased amount ofsulfurtrioxide (S03) found in the furnace. S03 reacts faster with CaO than arsenic does, so the sulfurbinds with the available calcium preferentially, leaving less for binding with arsenic. Other factors in the formation ofgaseous arsenic are furnace temperature, burnertype, total excess air and chlorine concentration. "Arsenic-resistant" catalysthas been developed by making the catalyst surface inactive to arsenic oxide, and by modification ofthe active sites. Because ofthe abundance ofcalcium in North Dakota lignite, catalyst Catalyst Poisoning, VolkerRummenhohl November 17,2008

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deactivation due to arsenic poisoning is not likely to be significant ifSCRtechnology in such cases were not technically infeasible for otherreasons. The reasons for technical infeasibility ofSCR technology onNorth Dakota lignite-firedboilers are because ofthe sodium, potassium, sulfur, and other elements that will be present in aerosol form in the flue gas and rapidly deactivate the catalyst. Most coals commonly fired in utility boilers do not contain the high levels ofsodium as North Dakota lignite, and the fuels that do have significantly high alkali contents are not typically fired in boilers that are fitted with SCRs. The same extensive knowledge and operating experience that exists for bituminous coal that may cause arsenic poisoning of SCR catalyst and the means ofpreventing its negative effects does not exist for the formation ofgaseous or aerosol forms ofsodium and potassium. Two catalyst suppliers, Argillon and CERAM, provided a briefresponse to general questions seeking information about their experience with sodium andpotassium concentrations that would be ofconcern for causing accelerated catalyst deactivation. The vendors' responses show thatboth companies don'tknow how high the gaseous sodium and potassium concentrations can be to ensure propercatalystperformance.4,5 In Mr. Hartenstein's remarks dated October, 2008, in the secondparagraph ofpage 4: "Initially, isolated events ofsilicon tetra fluoride (SiF4) blinding in bituminous coal-fired units were reported, butpersisted only for a very shortperiod oftime." His reference for this statement is personal discussions with plantpersonnel. VolkerRummenhoh1 was the project managerfor the project to find the cause and solution for 50% catalyst deactivation in 2,000 hours in tail-end SCRs resulting from unknown reactions. The president ofSTEAG (today, the company is known as Evonik) used to start meetings about this matter with the statement: "We must find the reason and a solution. The company will be at risk ifnot." It took more than two years to find the reason and implementthe solution. It also took several million dollars for research and implementation. It was also not isolated. All six STEAG tail-end SCRs were impacted. Up to thatpoint, it was generally accepted that tail-end SCR catalystwould not rapidly deactivate because ofall the flue gas cleaning taking place in the upstream electrostatic precipitatorwould remove practically all the significant dusts and flue gas desu1furization systems would remove a high percentage ofthe sulfur dioxide. The cause ofthe rapid TESCR catalyst deactivation turned out to be silicon tetrafluoride. Silicon (introduced as part ofthe coal ash) reacted with hydrogen fluoride (HF, produced during combustion) and condensed sulfuric acid (H2S04) on the plates ofthe FGD gas/gas heater (GGR) to form silicon tetrafluoride (SiF4), SiF4 at the TESCR operating temperature is gaseous and therefore penetrated the pores ofthe cata1yse. This was completely unexpected. Everyone assumed an extremely long catalyst lifetime for a catalyst in a tail end plant. Besides the catalyst issues, otherequipmentissues can impact the feasibility ofa tail-end SCR. In a project in Wisconsin, the ownerhas been forced to change from a tail-end to a low-dust SCR design for those otherreasons. Differences to German tail-end

Catalyst Poisoning, VolkerRummenhoh1 November 17, 2008- 4- applications were the much higher S02 removal efficiency requirements ofthe Wisconsin plant's wet FGD scrubber and the fact thatthe plant is a "zero-discharge" site. Mr. Hartensteinrefers to the catalyst case history at Avedore Power Station in Denmark as indicative ofsuccessful catalystperformance on abiomass fired boiler. Two presentations 6,7 have been mentioned thatprovide relevant information on the plant operation. Close examination ofthose and otherreferences previously mentionedby UND refute Mr. Hartenstein's point that SCR catalystwill be effective on units with sodium, potassium and other elements present as an aerosol in the flue gas. It shouldbe noted that the referenced Avedore unit thatuses SCR technology is not a 100% biomass fired boiler, as stated in Mr. Hartenstein's October 2008 remarks and in the referenced catalyst washing presentationby HaldorTopsoe. The boiler fires natural gas and other fuels. The referenced Elsampresentation does not show that the flue gas from the small, biomass fired boileris mixed with that ofthe largerboilerpriorto the SCR system. The smallerboiler does not exhaust its flue gas through any SCR. In addition, it is noted in the referenced HaldorTopsoe catalystwashing presentation that the entire catalyst loading on Avedore Unit 2 was replaced after 30,000 hours of operation. During the initial 30,000 hours ofoperation, the catalystwas washed nine times. This frequency ofcatalystwashing is excessive and not indicative ofa successful SCR installation. The Elsampresentation includes abar graph for "fuel combination

- 12 month" and "fuel combination

- 24 hours -April" that show that cofiring wood with heavy fuel oil (50:50 ratio) during April was only 25% ofthe total fuel, and apparently co-firing occurred during only half(12 hours) ofthe daily operating time. Ifthe boiler were continuously co-fired with wood 24 hours perday year-round, we would expectthis catalyst to show a rapid, severe decline in catalyst activity. The referenced H-T presentation shows a graph ofcatalyst relative activity versus time includes Avedore Unit 2's catalyst exposure time when no biomass cofiring occurred. "Line B" in the presentation represents "average wood-fired high dust catalyst deactivation" overtime. This graph is misleading, as it shows a lineardecay in catalyst activity for Avedore Unit 2's biomass co-firing experience compared with a linear curve fitted to data for "average coal fired, high dust deactivation". "Line B" on the graph is also misleading in that it does not show the cyclic effects ofdeactivation and washing on catalyst activity for the biomass case until it reached 90% deactivation in 30,000 hours. It is interesting that Hans Hartenstein portrays the catalyst vendors as willing to guarantee performance on coal-firedutility boilers that co-fire biomass (orplan to do so). Meetings and discussions with all ofthe catalystvendors except one reveal great reluctance or refusal to offer such guarantees. Hans Hartenstein mentioned Marl as an example ofTESCR without an FGD gas/gas heaterupstream ofthe induced draft fans following a wet scrubber. It does, however, use scrubberbypass gas to reheat the scrubberoutlet gas above saturation. Marl is not on the official Evonik website. Maybe Mr. Hartenstein can explain whether it is a waste Catalyst Poisoning, VolkerRummenhohl November 17, 2008- 5 -
incineratororboiler. Mr. Hartenstein should have this information since, based on his email address used in communicating with the SCR catalystvendors, he is obviously an employee ofEvonik. He also claimedthat a plate-type gas/gas heat exchanger from Ba1cke-Durrwas used in the Marl plant. A look atBa1cke-Durr's internet website indicates they have discontinued this product and are now offering a rotary (e.g. Ljungstrom)-type instead. Anotherplant that has a "wet" boosterdraft fan following a wet scrubberwith an FGD gas/gas heaterbefore atail-end SCR is Herne. When asked ifhe would everwantto see this arrangement repeated, the plant engineer at Herne said "neverin his lifetime". This brings me to Hans Hartenstein's credibility problem. He has absolutely zero handson experience with tail end SCRs on utility boilers. It is very clearthat statements made by Hans Hartenstein aboutthe feasibility oftail-end SCRs on utility boilers burning North Dakota lignite are personal opinion and are notbased on relevant technical expertise in this field. VolkerRummenhohl was responsible for the process design of26 tail-end and 7 low-dust SCRs with re-heat systems. The first one startedin Germany in 1987, and the last ended in 2008 (but was not subsequently approved for implementation). Mr. Rummenhohl was also responsible for the commissioning often tail-end SCRs and the O&M performance ofsix tail-end and one low-dust SCRs with reheat. It is extremely imprudentto apply SCRto autility boilerwith such differences in firing type and fuel burnedcomparedto those situations thathave been proven successful without first performing extensive pilot testing and achieving acceptable results, followed by confirming the feasibility ofthe full-scale design. One cannot lookjust atthe bulk flyash loading and average concentrations ofthe trace elements and otherpoisons in the fuel to decide whether SCRtechnology will work. Itis incorrectto make a blanket statement such as made by Hans Hartenstein in his October 2008 remarks that implies it is always feasible to install TESCR.

References:

I CleanerFossil Fuels for Sustainable Development Co-firing Coal and Biomass, Henrik Noppenau, ENERGI E2 (Until 01.07.2006) Denmark

2 Development and Commercial Operating Experience ofSCRDeNOx Catalysts for Wet BottomBoilers, Isato Morita, Masayuki Hirano, and Gregory T. Bielawski, presentedto Power-Gen International '98, Orlando Florida, December9-11, 1998.

3 SCRCatalyst

- five years ofoperating experience with all types ofSCRplants and the conclusions and measures developed as a result, Presented at VGB Congress "Power Stations 1992"

4Personal correspondence via email from Argillon, November 2008. Catalyst Poisoning, VolkerRummenhohl November 17, 2008

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5 Personal correspondence via email from CERAM, November 2008.

6 Noppenau, Henrik, CleanerFossil Fuels for Sustainable Development Co-firing Coal and Biomass, Accessed 10/28/2008 at http://www.usea.org/CFFS/CFFSNeptun/Cofiring%20-(WEC-CFFS)%20Neptun%20June%2013%202006.pdf

7 White, Nathan, Washing Your Own Catalyst, NOx Round Table 2007, Cincinnati, Ohio, February 5-6, 2007.

Catalyst Poisoning, VolkerRummenhohl November 17, 2008