MinnkotaPower

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. of Health, 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 of the Province of Manitobachallenged a North Dakota Pollutant Discharge Elimination System ("NDPDES") permit

that NDDH issued under the Clean Water Act. 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 of the 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. of Health, 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 together for 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 if the court can discern no rationale for the decision. Under this 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 of the impact of fuel

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 of the 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 of those

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 & Water in Pueblo and Southern Colorado v. Colorado Dep't ofPublic Health

and Envt., 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 proof that NDDH acted arbitrarily, capriciously, or

unreasonably. The Consent Decree expressly provides that "The Court shall sustain 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 of the 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 of the 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 or the 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 SCR consultant, Fuel Tech1

, along with Steve Benson of

the Department ofChemical Engineering at the University ofNorth Dakota2

, have reviewed the

October 2008 remarks ofthe United States' Department ofJustice's (DOl's) commenter, Hans

Hartenstein (Hartenstein, 2008), provided by the United States Environmental Protection Agency

(U.S. EPA or EPA) 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

Preliminary NOx 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 Best Available Control Technology for electric generating units that utilize cyclone

burners firing North Dakota lignite. The following sections address specific topics mentioned in

the EPA's comments and other issues in greater detail.

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

• Biomass Firing Impacts on SCR Catalyst as Surrogate for North Dakota Lignite

• General Regulatory Considerations

• Corrections, Clarification and Omissions of Hartenstein's Remarks

o Responses to General Remarks

o Responses to Specific Comments

• Conclusions

1 formerly Tackticks LLC.

2 formerly employed by 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 September 22, 2008 comments and responses (Burns &

McDonnell and others, September 2008), the catalyst in any configuration of SCR application

for a high-sodium North Dakota lignite-fired cyclone boiler is 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 guaranteed removal

rates ofsuch particles and aerosols. These materials react with other gas phase species and

deposited particles that will cause blinding or can react with active sites in the catalyst pores,

causing poisoning and deactivation, thus rendering the NOx reduction capability ineffective.

Lignite coals contain high levels elements such as sodium, magnesium, and calcium that are

associated with the organic or combustible 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 boiler upon gas cooling. Sodium will condense heterogeneously on the surfaces ofother

fly ash particles or homogeneously to aerosols. In addition, the high temperature cyclone-firing

ofthese coals increase the level of aerosols 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 and potassium. These sodium and potassium-rich

aerosols are very reactive with gas phase constituents and other materials 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 dependent upon the ash

content ofthe coals. Typically, coals that contain high levels of organically associated elements

and lower levels of ash-typically less than 15% (dry basis)-have the potential to produce high

levels ofthe submicron, homogeneously condensed sodium and potassium-rich aerosol.

Combined Responses to NDDH (11-17-2008 final).doc 2 November 17, 2008
As indicated by 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 power plants when firing high-alkali-containing fuels. An

example is a biomass fired system using a tower type scrubber where the removal efficiency of

the smaller size fraction of ash is low, as shown in Figure 1 (Ohlstrom and others, 2006).

• Wood, grate boiler, scrubber inlet I

-- -- I ....... -_..... Wood, grate boiler, scrubber outlet I

I

~- • - I

..... I

-.-

/""\ ·I

- I

- I \ I

I

- I

- I r.\. I

- l • I

- I • \\, • I • ...... , '. 105O=-3um

- I I

\\ , • , I .a.. , • .,..

/ .!/ ~. .-

-- /. ,. ~...... .... I. "-- •• .... 0 •."!tI/I- •..L......

I ' r r

0.01 0.1 1

Dp~

10 100

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 Powder River 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-fired boiler equipped with a venturi wet scrubber, to better understand the

reasons for the opacity problems. During the field testing, sampling ofthe coals, flue gases, and

scrubber materials was conducted. The particulate in flue gases downstream ofthe scrubber was

aerodynamically classified using a multicyclone followed by an impactor and a Nucleopore

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, 2008
plotted in Figure 2, showing that the scrubber is quite effective in removing the larger particles.

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

-r

]

j 0.01

0.001 ............-;;;~

Blend-Inlet Blend - outlet ColI A-Inlet CGel A-outlet

B D50=- U mlcJons mOSO- 2.5 microns

111050- 0.7 micrOnS 11050<0:1 microns

Overa- mass sIZe distributionsfor ....nedash .mptes.

Figure 2. Mass loadings and size for particulate collected upstream and downstream ofthe wet

venturi scrubber at Clay Boswell (Hurley and Katrinak, 1992).

The results ofthe study indicated that the particulate collected downstream ofthe scrubber was

coal-related and caused by the high sodium content ofthe coals. Vapor-phase sodium condenses

in the boiler's convective pass to form fine sodium-rich aerosols or other Na species that later

react with ash particles. Pure NaZS04 particles are too small to be removed by such scrubbing,

despite the fact that they 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 impactor plates represent the <0.7 micrometer aerosols are shown in Table 1.

Combined Responses to NDDH (11-17-2008 final).doc 4 November 17. 2008
Both samples are dominated by sodium and sulfur that are likely in the form ofsodium sulfate.

These sulfate materials exhibit highly cohesive tendencies.

Figure 3. Scanning electron microscope images ofspikes formed on impactor plates 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

(weight percent 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

K20 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 impactor were further

characterized on a particle-by-particle basis with a scanning electron microscopy and x-ray

Combined Responses to NDDH (11-17-2008 final).doc 5 November 17, 2008
microanalysis (Hurley and Katrinak, 1992). The chemical analysis of particles collected on the

filter downstream ofthe scrubber when 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 diameter could not be determined because ofparticle

agglomeration.

Table 2. Elemental compositions ofmixed submicron particles collected during the combustion

ofCoal A (high sodium subbituminous coal) at the scrubber outlet. Particles sorted by diameter

in micrometers. The chemical composition is reported as elemental weight percent (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 of high sodium lignites in a pulverized coal (PC) fired

system shows significant enrichment of sodium in the smaller size fractions as shown in Figure

4. This figure illustrates the increase in the sodium content in the finer size fractions of ash as a

result of firing 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, 2008
size 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 of ash particles during combustion ofNorth Dakota Lignite

(Benson and others, 1984).

The abundance ofsulfate aerosols was measured at the MRY by Markowski and others, 1983.

The results ofthe measurements of aerosol capture are illustrated in Figure 5. The results show

Combined Responses to NDDH {11-17-2008 final).doc 7 November 17, 2008
that aerosols less than one micrometer in 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 of particle size. The penetration is the outlet size distribution divided by

the inlet size distribution. (Penetration = 1- efficiency). The results showed that the "metallic"

sulfate aerosols (sodium sulfate) penetrated the FGD much more effectively than the larger

particulate.

10 10

I

-

Q

J

i

G.01o...,""""""".......-........_ .........-..............-...................-.................................._-_.........om

,.0 1. 'tOO

ACTUAL DIAMITU·tMICRQMmRS)

Figure 5. Penetration of aerosols through the MRY Unit 2 wet scrubber (Markowski and others,

1983).

Combined Responses to NDDH (11-17-2008 final).doc 8 November 17,2008
Sodium and potassium rich aerosols are present in the flue gases entering the FGD as evidenced

by the recent work conducted by Tolbert and others (2008). Testing of Power Span's barrier

discharge reactor being developed for new power generation was conducted to determine the

impact ofsodium rich aerosols on the performance ofthe PowerSpan ECO Technology for flue

gases from boilers fIring high sodium ND lignite. The barrier discharge reactor is placed

downstream of particulate control systems to enable the oxidation ofNO to N03 species that will

allow for capture in an ammonia based scrubbing system. A slip stream barrier discharge 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 barrier reactor was 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 decreased performance ofthe barrier discharge reactor. The ash accumulation

resulted in decreased NO oxidation due to accumulations of alkali and alkaline earth sulfate rich

ash layer on the rods. The bulk composition of ash 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 17,2008
Table 3. Bulk composition of ash removed from electrode samples obtained from rod removed

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

Fe203 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

K20 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 and biomass materials have similar associations of alkali elements. The

bonding sites for alkali elements such as sodium and potassium in biomass and lignite coals are

organic acid sites. The alkali elements are present in coal and biomass as salts of organic acid

groups, such as carboxylic acids. The associations of alkali and alkaline earth elements have

been extensively studied by the EERC (Benson and Holm, 1983 and Benson and others, 1994).

The alkali elements associated with biomass have been extensively studied by Sandia National

Laboratory (Miles and others, 1995). Both studies conclude that alkali and alkaline earth

elements are bonded to the organic matrix ofthe lignite or biomass. 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. 2008
vaporize 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 measured relative 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 of poisoning of catalysts in a CFB boiler fIring forest residues, and in a

PC fIring pulverized wood (Khodayari, 2001).

Khodayari found that the degree ofdeactivation was related to the abundance of potassium and

sodium that accumulated in the catalyst and not related to ash loading. In the CFB boiler

exposed catalyst, the level ofpotassium accumulated in the catalyst was 0.27% and the relative

reactivity ofthe catalyst decreased to about 78%, or 22% deactivation. For the PC case in fIring

wood, the build up of potassium in the catalyst was 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 of highly reactive alkali (potassium and sodium)

aerosols in the flue gas. The PC system produced more highly-reactive alkali aerosols because

Combined Responses to NDDH (11-17-2008 final).doc 11 November 17, 2008
of higher firing temperatures causing an increase in the vaporization of alkali and low ash

content ofthe wood that reduces the sites for condensation of alkali 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 higher particle loading in a CFB as

compared to the PC system. The alkali in the CFB system reacts with bed materials and ash

particles during circulation decreasing the abundance of alkali aerosols. The reactive alkali

aerosols diffuse into the catalyst and are adsorbed chemically and physically on the catalyst

surfaces resulting in deactivation. Higher temperatures such as those found in cyclone fired

system will cause an increase in vaporization of alkali species and exacerbating the formation of

reactive alkali aerosols.

Numerous investigations have shown that alkali (sodium and potassium) rich aerosols degrade

catalyst performance 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) examined the poisoning mechanisms of alkali and alkaline earth

oxides on vanadia catalysts and found that the 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 of SCR catalysts in three biomass and

peat fired 100 MW-scale combustion systems. They found that the increased levels of

sodium and potassium accumulated in the SCR catalyst was derived from the ultra fine

particles (aerosols). These accumulations of aerosols decreased the NOx reduction

catalytic activity by over 40% in testing ranging from 100 to 3000 hours.

• Strege and others (2008) at a stoker-fired utility boiler firing a blend of biomass and

Powder River 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 after being exposed to flue gas

derived from firing wood for about 1400 hours.

• Zhang and others (2008) investigated the operation offull-length monolith catalysts

installed at a straw-fired power plant and found a high deactivation rate of about 1% of

the relative activity per day was observed when the power plant ran continuously.

General Regulatory Considerations

Comments regarding the EPA's regulatory approach submitted by Minnkota Power Cooperative

(Minnkota) made in September 2008 (Burns & McDonnell and others, September 2008) appear

to have been mostly ignored by 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-fired utility boilers at Milton R. Young Station. Minnkota, as

owner and operator ofthe lignite-fired cyclone boilers at Milton R. Young Station, is providing

these comments as a party subject to the requirements ofthe Consent Decree (2006).

It is indisputable that there are no SCR installations in operation or planned on units that include

cyclone burners firing North Dakota lignite. In fact, to the best ofour knowledge, there have

been no previously built, and there are not any currently operating, tail-end SCRs installed on

full-scale, full-time lignite-fired utility boilers anywhere in the world. This has not been refuted

by the EPA or their experts.

The arguments regarding technical infeasibility of SCR technology for the reduction ofNOx

emissions at M.R. Young Station have beenstated previously (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 of cyclone

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, 2008
tail-end SCR configurations. Thus, it has been demonstrated that SCR technology has not been

deployed on a "same or similar source type". Accordingly, the NDDH has a reasonable basis

upon which to conclude that SCR is not applicable for BACT at Young Station.

Statements of SCR catalyst vendors being willing to guarantee their product 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 based upon

the premise that exposure ofthe catalyst to suitable operating conditions will occur; whether it is

possible to achieve such conditions is not their responsibility. Regarding tail-end SCR, one of

the queried vendors stated "the fly ash constituents that can poison the catalyst will have been

removed from the flue gas stream by 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 of a tail-end SCR is largely

ineffective at removing such aerosols.

The infeasibility of SCR 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 of organically associated sodium that is prone to

form aerosols when fired, especially in slagging-type boilers

• Heat transfer surface configuration required for fuel drying and heat recovery results in

high temperature issues for high-dust SCR

• Highly cohesive and reactive sodium rich ash that blinds, plugs, and poisons high-dust

SCR catalyst

• ESP and scrubbers do not remove reactive submicron aerosols that blind, plug, and

poison low dust and tail end SCR catalyst. No tail-end SCRs have been installed on any

full-scale, full-time lignite-fired utility boilers anywhere in the world.

There is no demonstrated evidence that these infeasibility issues have been overcome. Recent

literature supports conclusions that high dust, low dust, and tail end SCR are not feasible because

ofthe presence ofsodium- and potassium-rich aerosols in the flue gas stream. No SCR catalyst

Combined Responses to NDDH (11-17-2008 final).doc 14 November 17, 2008
designs 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 of enduring or modifying such challenging flue

gas conditions that exist at the units at M.R. Young Station should be considered as technically

feasible, without having been successfully installed, operated, and maintained on similar boilers

and fuels. It is an invalid response to suggest that Minnkota is required to conduct an extended

pilot test program or full-scale experimental construction and testing project for the purposes of

supporting a BACT determination, when the EPA's own draft NSR Workshop Manual's

definition of a technically feasible control excludes those projects.

EPA's previous comments (U.S. EPA, July 2008) suggest that the BACT decision should tum 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. It has been previously demonstrated

(Arfmann et aI, August 2007) that SCR is-under the definitions provided in the NSR Workshop

Manual relating to availability and applicability-technically infeasible in this case. EPA's

suggestion that the hypothetical application of a technically infeasible technology could

potentially be a cost-effective emissions control method that constitutes BACT is at odds with

the NSR Workshop Manual.

The EPA and the DOl's commenter continue to argue that this is a case where hypothetical fullscale or demonstrated pilot-scale SCR technology performance data must be quantified for a

BACT analysis in order to refute the EPA's position that SCR is technically proven for NOx

reduction on all fossil fuels, not excluding North Dakota lignite, while ignoring the severe pore

plugging documented for the Coyote Station pilot SCR catalyst 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) October 2008 remarks need to be clarified and

corrected for the administrative record.

RESPONSES TO GENERAL REMARKS:

1. The lack of catalyst deactivation data for high-dust, low-dust, or tail-end SCR technology, if

it were to be applied to the boilers at MRYS, supports the argument that an extended pilot

test program or full-scale experimental construction and testing projects would need to be

conducted in order to compare with other pilot-scale or full-scale catalyst experience on

cyclone boilers firing other coals before confirmation oftechnical feasibility can be

confirmed. It is erroneous to assume that the fine sodium sulfate aerosols in MRYS boiler

flue gas that will deactivate SCR catalyst will be sufficiently removed by the ESP and wet

scrubber systems upstream of a tail-end SCR, and therefore are unlikely to pose a rapid

deactivation threat. ESPs and wet scrubbers are not highly efficient at removing fine

submicron particles 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 catalyst by 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, September 2008;

Arfmann and others, August 2007).

Recent work conducted by Zheng and others (2008) described the diffusion of aerosols and

their ability to cause catalyst poisoning. These efforts followed earlier studies where Zheng

and others (2005) found that biomass derived alkali rich aerosols caused a drop in NOx

reduction activity by 52% after about 1140 hours ofoperation. SCR vendors were

specifically requested (Burns & McDonnell, April 2007, May 2008) to provide data that

would support the EPA's arguments that high-sodium North Dakota lignite would not be

infeasible for full-scale, full-time cyclone boiler SCR applications. The details of any

estimates of catalyst life and deactivation rates offered by vendors were not made available

for review.

Combined Responses to NDDH (11-17-2008 final).doc 16 November 17, 2008
2. Hartenstein remarked that because Bums & McDonnell's SCR Consultant (Tackticks) did

not actually state that SCR is technically infeasible at Milton R. Young Station, that their

opinions do not support this same conclusion expressed by B&McD and EERC. Hartenstein

has drawn this conclusion without recognizing the arguments Tackticks made that

correspond to the previously stated position and interpretation (Arfmann and others, August

2007) of "technical feasibility" as described in the EPA's 1990 NSR Workshop Manual. It is

our collective position, based on valid arguments provided by Minnkota, Bums &

McDonnell, Steve Benson, Volker Rummenhohl, and several SCR system suppliers, that

successful application of SCR technology on this fuel at this powerplant has not been

sufficiently demonstrated by actual relevant pilot- or full-scale experience to confirm its

technical feasibility as stated previously with our interpretation ofthe definition ofthose

terms.

Volker Rummenhohl was responsible for the process design of 26 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 Volker Rummenhohl that it is extremely imprudent to apply SCR to a utility

boiler with such differences in firing type and fuel burned compared to those situations that

have been proven successful without first performing extensive pilot testing and achieving

acceptable results, followed by confirming the feasibility ofthe full-scale design. One

cannot look just at the bulk flyash loading and average concentrations ofthe trace elements

and other poisons in the fuel to decide whether SCR technology will work. It is incorrect to

make a blanket statement such as made by Hans Hartenstein in his October 2008 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

higher levels of alkali species, especially in aerosol form, contained in flue gas such as that

exhausted from the MRYS boilers as compared to PRB coal-fired boilers that have applied

Combined Responses to NDDH (11-17-2008 final).doc 17 November 17, 2008
high-dust SCRs. Hartenstein incorrectly states that Coyote pilot-scale SCR testing in a highdust configuration does not "properly represent the types of deactivation mechanisms or the

rate of catalyst deactivation that can be expected in a TESCR".

As described previously, fly ash produced upon combustion ranges in size from submicron

aerosols to particles greater than 10 ~m. The very small sodium and potassium enriched

particles diffuse into the pore of catalyst no matter ifit is low-dust or tail-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 and potassium sulfates and other

compounds when generated from firing North Dakota lignite. Combustion ofNorth Dakota

lignite in the cyclone-fired boilers at Milton R. Young Station promotes the vaporization of

sodium and potassium and the production ofsubmicron particles and aerosols through

homogeneous condensation ofthe vaporized species. These fine materials, which are

comprised of highly-concentrated sodium and sulfur containing compounds, are entrained in

the flue gas stream. Submicron particles and aerosols are not effectively removed from the

gas stream by the high-efficiency electrostatic precipitators nor by 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 of ash deposits

fragments. Channel plugging is largely driven by the size ofthe ash materials carried

back into the system and can be controlled by the use ofscreens to remove the ash or

larger pitch catalyst.

• Masking ofthe surface by a dense phase. The phases that form are typically sulfates that

cause bonding of other particles (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 SCR blocking 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 catalyst by the diffusion of various types ofreactive

aerosols such as those rich in sodium and potassium. The aerosols will diffuse into the

pores and react with the active components ofthe catalyst.

The latter two 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 wet FGD scrubber for a tail-end SCR, there will still be a large number of very

small and reactive particulate and aerosols that will severely affect the catalyst. Because

these residual aerosols and fine particulate are not totally removed by the upstream gas

treatment equipment, they are not negligible as the DOl's commenter suggests.

As Volker Rumrnenhohl (see Appendix A) and others have stated in the cited references, the

concentration of certain elements such as alkali and other species (arsenic and sulfuric acid

aerosol), do not have to be large in magnitude before they will cause significant catalyst

deactivation or become visible. In cyclone-fired system the ash is partitioned between

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 enriched in fine particulate

and vapors that will have high levels offlame-volatilized species such as sodium, potassium,

and sulfur relative to the molten slag. The molten slag-related has a higher abundance of

lower volatility material. The fly ash is enriched in the volatile elements that are in the form

ofsubmicron particles and aerosols. The submicron particles and aerosols are not removed

sufficiently by an ESP and wet scrubber to eliminate their blinding, 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 greater than 1.0 flm in diameter, however

they are generally ineffective collection devices for submicrometer «1 flm) particles."

2. The main power boiler with an SCR (Unit 2) at the Avedore utility powerplant mentioned by

Hartenstein (Hartenstein, October 2008) is a multiple-fuel fired system, and is not

continuously fired with 100% biomass as may be implied. A smaller Avedore boiler

Combined Responses to NDDH (11-17-2008 final).doc 19 November 17, 2008
associated 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, or bituminous coal.

The SCR for the main boiler is exposed to a reduced concentration of co-fired wood

biomass-related emissions. The first bar graph in the cited reference 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 winter months (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 paper by Haldor Topsoe (White,

2007) cited by 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 other paper (Noppenau, 2006), it is

apparent that a significant portion ofthe annual operating time for the main Avedore Unit 2

boiler does not involve co-firing ofbiomass. Based on the data provided, the actual rate of

catalyst deactivation could be much more significant than the above numbers imply.

Substantial, rapid deactivation is indicated, requiring catalyst maintenance activities on the

order of approximately every 1000 hours of estimated biomass co-firing operation.

Volker Rummenhohl considers this frequency of catalyst washing excessive, and believes

this is not indicative of a successful SCR installation. Of course, catalyst vendors and other

companies provide catalyst washing services, so this is good for such businesses. Mr.

Hartenstein himself has been employed as the president ofsuch a company (Hartenstein, July

2008), so his opinion on this subject may be influenced by his previous personal

involvement.

3. Hartenstein discounts the silicon tetrafluoride blinding problems from firing bituminous coal

in certain German utility TESCRs as isolated and very 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, 2008
rapid TESCR blinding and decreased removal 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 catalyst vendor said (Burns & McDonnell and others,

May 2008): that the Coyote Station SCR slipstream pilot testing demonstrated that 6 mm

pitch catalyst is not suitable for a high-dust SCR application featuring highly adhesive flyash.

At least one important point can be made from these and other situations showing rapid

catalyst deactivation. The published experience base for catalyst designs suitable for coalfired boiler applications or coal additives that are available and been proven to tolerate or

alleviate the severe blinding and plugging ofthe catalyst pore 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 subject to the same blinding and deactivation mechanisms

regardless of catalyst pitch.

The most important catalyst deactivation mechanism to recognize is diffusion of aerosols into

the pores ofthe catalyst followed by reaction ofthe alkali (sodium and potassium) with

active sites in the catalyst and/or the reaction of gas phase S02 and S03 to produce sulfates

and pyrosulfates. Recently testing was conducted by Strege and others (2008) at a stokerfired utility boiler firing a blend ofbiomass and Powder River Basin coal (PRB) using the

same reactor that was used at the Coyote Station. The main difference in the recent testing as

compared to the Coyote tests was that the nozzle normally used to isokinetically extract the

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, 2008
relative to SCR applications. The typical levels of ash and sodium in typical wood as cofired in power boilers is lower than the range indicated in the comparison table provided in

Mr. Hartenstein's October 2008 remarks. The amount and form of alkali 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 catalyst passages and in

pores and cause plugging, blinding, and poisoning.

6. Hartenstein did not refute the formation of aerosols or the mechanism ofpartitioning between

the slag and fly ash components in cyclone-fired systems that result in an enrichment of

sodium and other flame-volatilized species in the flue gas.

7. Hartenstein apparently agrees that penetration of alkali-rich aerosols in the flue gas from high

sodium Fort Union (North Dakota lignite) coals fired in cyclone-fired boilers into the pores

of SCR catalyst will cause significant blinding and poisoning in high dust SCR applications.

He also seems to believe that this will not be the case for tail-end SCR applications, which he

assumes will see flue gases cleaned and scrubbed of harmful elements removed by the

upstream treatment equipment.

8. Hartenstein's discussion did not include statements of catalyst vendor guarantee experience

associated with European coal-fired utility boilers cofiring high alkali (Na and K) containing

biomass. Based on recent contacts, Volker Rummenhohl has learned that many catalyst

vendors are reluctant or unwilling to guarantee catalyst performance 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 that the contract

to retrofit a TESCR on the Rudow unit was signed prior to 1990, it fired bituminous coal, not

lignite, and was placed into cold standby in 1998 (and has since been decommissioned).

Assuming the execution ofthe project was delayed until completion occurred in 1994, it does

not change the fact that no other tail-end SCRs have been designed and installed for

operation on coal-fired utility 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, 2008
10. The statement that the Walsum Unit 7 boiler burning bituminous coal cited in previous

comments (Bums & McDonnell et aI, September 2008) as operating with a LDSCR, not a

TESCR, was not refuted by Hans Hartenstein; the remarks indicate this unit not being

cyclone-fired is also debatable, as there are other references that indicate the unit employs

cyclone burners.

11. Out ofthe hundreds ofEuropean SCRs installed on coal-fired power plants, experience at

lignite-fired utility boilers has been very limited and dissimilar to 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 at the Bayernwerk Schwandorf plant 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 can be resolved by the use ofTESCR, and that TESCR technology will work at

MRYS (July, 2008). We believe their arguments are flawed because they fail to recognize the

significance ofthese facts:

• There is no prior experience with full-scale SCR of any 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 catalyst blinding and plugging due to sodium and potassium rich

species (Benson and others, 2005). The Coyote pilot-scale SCR test was intended to

evaluate the fouling potential of SCR on lignite coal. It was developed by a consortium

Combined Responses to NDDH (11-17-2008 final).doc 23 November 17. 2008
ofthree catalyst vendors, EPRI, U.S. DOE, and other participants that design and install

SCR systems as well as end-user utilities that have applied SCR on their boilers. This

experience demonstrated the generation of alkali-sulfate compounds that plugged every

micropore ofthe test catalyst when examined under a scanning electron microscope.

This catalyst blinding and plugging was so severe that the catalyst vendor who supplied it

was unwilling to analyze it for deactivation.

• European SCR experience at lignite-fired utility boilers has been very limited and

dissimilar to 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 at the

Bayernwerk Schwandorfplant in Germany. These units were not slagging-type (cyclonefired), 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.

• There has never been, to the best of our knowledge, any tail-end SCRs applied to coalfired utility boilers burning lignite in Europe. There have been no full-scale TESCRs

downstream of a wet FGD scrubber and electrostatic precipitator installed on any coalfired utility boilers in North America (see Appendix A). Aerosols will still get through

the ESP and wet FGD scrubber, so catalyst deactivation problems will occur similar to or

worse than those experienced by 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 of ash, and specifically the sodium and potassium fraction ofthe

lignite coal ash, is not relevant to whether low-dust or tail-end SCR catalyst will become

rapidly plugged, blinded, and deactivated. Combustion ofNorth Dakota lignite in the

cyclone-fired boilers at Milton R. Young Station promotes the production ofsubmicron

particles and aerosols. These fine materials comprised of highly-concentrated sodium

sulfate, are produced from the condensation offlame volatilized species and are entrained

in the flue gas stream. Submicron particles and aerosols are not effectively removed

from the gas stream by the high-efficiency electrostatic precipitators nor by wet limebased flue gas desulfurization systems (scrubbers).

• Statements of SCR catalyst vendors being willing to guarantee their product resulting

from a Bums & McDonnell query and follow-up (2007, 2008), and subsequent claims by

Combined Responses to NDDH (11-17-2008 final).doc 24 November 17, 2008
the DOl's commenter (July 2008) are based upon the premise by these vendors that

exposure ofthe catalyst to suitable operating conditions will occur; whether it is possible

to achieve such conditions is not their responsibility.

• There can be no substantiated basis established such that the performance and longevity

ofsuch hypothetical solutions could be estimated without performing extensive pilot

scale testing that proves that SCR catalyst 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, and proven to be capable of enduring or modifying such

challenging flue gas conditions that exist at the units at M.R. Young Station should be

considered as technically feasible, without having been successfully installed, operated,

and maintained on similar boilers and fuels. It is an invalid response to suggest that

Minnkota is required to conduct an extended pilot test program or full-scale experimental

construction and testing project for the purposes ofsupporting a BACT determination,

when the EPA's own draft NSR Workshop Manual's definition of a technically feasible

control excludes those projects.

• Because ofthe unique boiler configurations and firing characteristics employed by these

boilers and the fuel they burn, there is no substantive certainty of how all the documented

temperature issues for high-dust SCR and the submicron aerosols and flue gas conditions

for any SCR configuration, would be favorably resolved for the boilers at MRYS. As far

we are aware, there have been no high-dust SCRs installed on cyclone-fired boilers that

have the kind offuel drying and heat recovery systems employed at MRYS.

• Volker Rummenhohl is an experienced SCR process design engineer who has been

responsible for the process design of26 tail-end and 7 low-dust SCRs with re-heat

system. Volker has stated, and we concur, that it is extremely imprudent to apply SCR to

a utility boiler with such differences in firing type and fuel burned compared to those

situations that have been proven successful without first performing extensive pilot

testing, achieving acceptable results, followed by confirming the feasibility ofthe fullscale design. One cannot look just at the bulk flyash loading and average concentrations

ofthe trace elements and other poisons in the fuel to decide whether SCR technology will

Combined Responses to NDDH (11-17-2008 final).doc 25 November 17. 2008
work. It is incorrect to make a blanket statement such as made by Hans Hartenstein in his

October 2008 remarks that implies it is always feasible to install TESCR.

• Based upon all the evidence presented to date, it is technically infeasible to apply any

form of SCR technology (high-dust, low-dust, or tail-end SCR) to the lignite-fuel

cyclone-fired boilers at the Milton R. Young Station.

REFERENCES (sorted in alphabetical order)

Arfmann, D.; Benson, S.A.; Weilert, C.V. prepared for Minnkota Power Cooperative, Inc.,

Appropriateness ofConducting Pilot Testing of Selective Catalytic Reduction (SCR) Technology

at Milton R. Young Station Units 1 and 2, For Use In A NOx BACT Analysis, August 14, 2007.

Benson, S.A.; Laumb, J.D.; Crocker, C.R.; Pavlish, J.H., SCR Catalyst Performance in Flue

Gases Derived from Subbituminous and Lignite Coals. Fuel Process. Technol. 2005, 86, 577-

613.

Benson, S.A.; Holm, P.L. Comparison ofInorganic Constituents in Three Low-Rank Coals. Ind.

Eng. Chern. Prod. Res. Dev. 1985, 24, 145.

Benson, S.A.; Rindt, D.K.; Montgomery, G.G.; Sears, D.R. Microanalytical Characterization ofa

North Dakota Fly Ash. Industrial and Engineering Product Research and Development 1984,

23,252.

Benson, S.A.; Jones, M.L.; Harb, J.N. Ash Formation and Deposition. In Fundamentals ojCoal

Combustion for Clean and Efficient Use; Smoot, D.L., Ed.; Coal Science and Technology 20

Series; Elsevier: Amsterdam, 1993; Chapter 4, pp 299-373.

Buecker, Brad, How Pollutants are Formed During Combustion (And How It Affects Control

Methods), Power Engineering magazine, April 2008, accessed on-line at:

http://pepei.pennnet.com/display_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 Best Available

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 (SCR Vendor 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 Dakota Department of Health, Environmental Health

Section, Division ofAir Quality, and United States Environmental Protection Agency, May 23,

2007.

Combined Responses to NDDH (11-17-2008 final).doc 26 November 17, 2008
Bums & McDonnell and Energy & Environmental Research Center (EERC), Additional

Information and Discussion of Vendor Responses 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), September 22,2008.

Chen, J.P.; Buzanowski, M.A.; Yang, R.T.; Cichanowicz, J.E., Deactivation ofthe Vanadia

Catalyst in the Selective Catalytic Reduction Process. J. Air Waste Manage. Assoc. 1990,40,

1403-1409.

Consent Decree filed in the United States District Court For The District OfNorth Dakota,

United States OfAmerica and State OfNorth Dakota, Plaintiffs, v. Minnkota Power

Cooperative, Inc. and Square Butte Electric Cooperative, Defendants, Civil Action No.1 :06-CV034, filed April 24, 2006.

Fisia Babcock SCR Installation Reference List, accessed on 11/3/2008 at http://www2.fisiababcock.eu/references.php?list=5.

Guo, x., Poisoning and Sulfation on Vandia SCR Catalyst. Doctor of Philosophy Dissertation,

Department ofChemical Engineering, Brigham Young University, August 2006.

Hartenstein, H.-U., Enclosure 1 to U.S. EPA Region 8 July 31, 2008 letter to NDDH: Hans

Hartenstein's Expert Opinion Report Feasibility ofSCR Technology for NOx Control

Technology for the Milton R. Young Station, Center, North Dakota on Behalf ofthe United

States Department ofJustice, July 2008.

Hartenstein, Hans, Enclosure to U.S. EPA Region 8 October 17, 2008 letter to 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 Preliminary NOx BACT

Determination for Milton R. Young Station (MRYS)" dated September 22, 2008, on behalf of

the United States Department ofJustice, October 2008.

Hurley, J.P.; Katrinak, K.A., Determination ofAsh Formation and Deposition Mechanisms at

Minnesota Power Clay Boswell Station; DOE/MC/l0637-3365, July 1992.

lEA Coal Research book "NOx control installations on coal-fired plants" (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, 2008
Khodayari, R, Selective Catalytic Reduction ofNOx: Deactivation and Regeneration Studies

and Kinetic Modeling of Deactivation, Ph.D. Thesis, 2001, Dept. ofChemical Engineering II,

Lund, Sweden.

Kling, A.; Andersson, c.; Myringer, A.; Eskilsson, D.; Jaras, S.G., Alkali Deactivation of HighDust SCR Catalysts Used for NOx Reduction Exposed to Flue Gas from 100-MW-Scale Biofuel

and Peat Fired Boilers: Influence of Flue 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 ofTheir Extent and Nature;

Summary Report for National Renewable Energy Laboratory Subcontract No. 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

SCR Technical Feasibility March 15,2007 (re: U.S. EPA Region 8 letter January 8, 2007),

March 19,2007. (2007 A)

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses To NDDH

and EPA Comments Regarding SCR Technical Feasibility and Non-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 letter January 26,2007), April 23, 2007. (2007

B)

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Comment and

Response To EPA Region 8's October 4,2007 Comment on NDDH BACT Determination at

Milton R Young Station, (re: U.S. EPA Region 8 letter October 4,2007), November, 2007.

(2007 C)

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Additional

Information and Discussion ofVendor Responses on SCR Technical Feasibility North Dakota's

NOx BACT Determination for Milton R. Young Station Units 1 & 2, May 8, 2008.

ND Department of Health, Division of Air 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, Cleaner Fossil 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, and Tissari, 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, 2008
Strege, lR.; Zygarlicke, C.l; Folkedahl, RC.; SCR Deactivation 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-Dakota Utilities Co., Minnesota Power, Basin Electric Power Cooperative, North

Dakota Industrial Commission, and Minnkota Power Cooperative, 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 letter by 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 Dakota Department of

Health's Preliminary NOx BACT Determination for Milton R. Young Station, date stamped July

31,2008 (with Enclosures).

Enclosure 2 to US. EPA Region 8 July 31, 2008 letter to NDDH: EPA's Comments on NDDH

Preliminary BACT Determination.

United States Environmental Protection Agency (US. EPA or EPA) Region 8 letter by Andrew

M. Gaydosh, Assistant Regional Administrator, Office ofEnforcement, Compliance and

Environmental Justice to Terry L. O'Clair, Director, Division of Air Quality, North Dakota

Department ofHealth, Re: Transmittal ofEPA's Response to Minnkota's Letter on Public

Comments Received for the North Dakota Department ofHealth's Preliminary NOx BACT

Determination for Milton R. Young Station, date stamped October 17, 2008 (with Enclosure).

U.S. EPA New Source Review Workshop Manual, Prevention of Significant Deterioration and

Nonattainment Area Permitting, Office ofAir Quality Planning and Standards, Research

Triangle Park, N.C. 27711 (the Draft October 1990 "NSR Manual")

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 Power Plant; 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, 2008
APPENDIX A

Volker Rummenhohl's Report

"Catalyst Poisoning"

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

By

Volker Rummenhohl,

Fuel Tech, Inc.

November 17, 2008

Selective Catalytic Reduction (SCR) Catalyst can be rapidly deactivated (poisoned) by

fuel impurities. Some ofthese impurities are present at trace levels. These impurities

can either plug the pores physically or react with the active centers in the pores

chemically on a permanent basis and reduce the number of active 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 other more abundant elements, such as sodium (Na), potassium (K), and phosphorus

(P) will vaporize during combustion and condense on the surfaces oflarger entrained

particles or be emitted as elemental aerosols. The larger solid trace element-containing

particles are too large to penetrate the pores. They will remain on the surface ofthe

catalyst and are neutral regarding the activity, but may mask or blind the pores so that

ammonia and NOx molecules cannot reach the active sites to react. Particulate loading is

not of concern when the cause ofthe catalyst deactivation is due to aerosols. The

aerosols are less than a micrometer in diameter and can be in a liquid or solid state. The

condensed aerosols can penetrate into the pores ofthe catalyst by 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 and potassium produce aerosols and

liquid phase mixtures that will blind and poison catalysts. As previously discussed by

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 catalyst pores and cause physical plugging ofthe catalyst pores and poisoning

ofthe active sites. Arsenic in bituminous coal is an example ofa well-known catalyst

deactivation mechanism involving a trace element in vapor form that penetrates the

micropores, reacts with the active sites during SCR operation, and causes rapid

deactivation by permanently poisoning the catalyst.

The relevant catalyst poisons in the case ofM)'RS are sodium and potassium. Both

elements are known catalyst poisons in case biomass is co-fired with the primary fuel in

utility boilers!. Since widespread use of biomass co-firing in utility power boilers

equipped with SCR catalysts is relatively recent, specific published knowledge ofthe

successful methods of avoiding or mitigating the negative effects on SCR catalyst

deactivation is limited. For this reason, we will use arsenic as an example to demonstrate

catalyst vendors' initial lack of awareness and the subsequent understanding ofthe

deactivation mechanism.

Catalyst Poisoning, Volker Rummenhohl November 17, 2008
- 2 -

The application ofSCR technology 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 and pilot plants. Arsenic was

not known to be a catalyst poison at that time. One German utility insisted on a pilot

plant despite the fact that all Japanese catalyst licensors were willing to provide all

guarantees without pilot testing. The result ofthe pilot test in the power station Franken

was that the catalyst supplied by four different suppliers significantly deactivated in 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 development to identifY causes and solutions2

•

Arsenic in a gaseous form is a strong catalyst poison. 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

of arsenic trioxide in the flue gas entering the SCR reactor is between 10 and 50 Jlg/Nm3.

Longevity of catalyst exposed to an arsenic concentration over 50 Jlg/Nm3in the flue gas

at the inlet ofthe SCR will not be guaranteed by the catalyst supplier without 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, a high sulfur bituminous coal

contained 30 ppm As by weight in the coal. This would result in 3850 JlglNm3if all fuel

arsenic would become gaseous. This demonstrates that a very small fraction ofthe fuel

arsenic - less than 0.1 ppm by weight for bituminous coal, is the limit for SCR operation

without problems.

There are several factors determining the amount of gaseous arsenic that is produced

during combustion of arsenic-containing coal. The free calcium oxide (CaO) content in

coal is the most important factor. Calcium binds arsenic in the solid form [calcium

arsenate, Ca3(As04h]. German experience showed that ifthe free CaO concentration in

the fuel is above 2 to 2.5% by weight ofthe ash, arsenic is not a problem for the catalyst.

Addition oflimestone into the furnace (boiler combustion zone) is required ifthe free

CaO in the fuel is insufficient to 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 must be higher ifthe sulfur content is higher. The reason for

this is the increased amount ofsulfur trioxide (S03) found in the furnace. S03 reacts

faster with CaO than arsenic does, so the sulfur binds with the available calcium

preferentially, leaving less for binding with arsenic.

Other factors in the formation of gaseous arsenic are furnace temperature, burner type,

total excess air and chlorine concentration. "Arsenic-resistant" catalyst has been

developed by making the catalyst surface inactive to arsenic oxide, and by modification

ofthe active sites. Because ofthe abundance of calcium in North Dakota lignite, catalyst

Catalyst Poisoning, Volker Rummenhohl November 17,2008
- 3 -

deactivation due to arsenic poisoning is not likely to be significant if SCR technology in

such cases were not technically infeasible for other reasons. The reasons for technical

infeasibility ofSCR technology on North Dakota lignite-fired boilers 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 of preventing its negative effects does not exist for the

formation of gaseous 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 and potassium concentrations that would

be of concern for causing accelerated catalyst deactivation. The vendors' responses show

that both companies don't know how high the gaseous sodium and potassium

concentrations can be to ensure proper catalyst performance.4

,5

In Mr. Hartenstein's remarks dated October, 2008, in the second paragraph of page 4:

"Initially, isolated events ofsilicon tetra fluoride (SiF4) blinding in bituminous coal-fired

units were reported, but persisted only for a very short period oftime." His reference for

this statement is personal discussions with plant personnel.

Volker Rummenhoh1 was the project manager for 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 of STEAG (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 if not." It took more than two years to find the

reason and implement the 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 that point, it was generally accepted that tail-end SCR catalyst would not rapidly

deactivate because of all the flue gas cleaning taking place in the upstream electrostatic

precipitator would 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, other equipment issues can impact the feasibility of a tail-end

SCR. In a project in Wisconsin, the owner has been forced to change from a tail-end to a

low-dust SCR design for those other reasons. Differences to German tail-end

Catalyst Poisoning, Volker Rummenhoh1 November 17, 2008
- 4-

applications were the much higher S02 removal efficiency requirements ofthe Wisconsin

plant's wet FGD scrubber and the fact that the plant is a "zero-discharge" site.

Mr. Hartenstein refers to the catalyst case history at Avedore Power Station in Denmark

as indicative ofsuccessful catalyst performance on a biomass fired boiler. Two

presentations 6,7 have been mentioned that provide relevant information on the plant

operation. Close examination ofthose and other references previously mentioned by

UND refute Mr. Hartenstein's point that SCR catalyst will be effective on units with

sodium, potassium and other elements present as an aerosol in the flue gas.

It should be noted that the referenced Avedore unit that uses SCR technology is not a

100% biomass fired boiler, as stated in Mr. Hartenstein's October 2008 remarks and in

the referenced catalyst washing presentation by Haldor Topsoe. The boiler fires natural

gas and other fuels. The referenced Elsam presentation does not show that the flue gas

from the small, biomass fired boiler is mixed with that ofthe larger boiler prior to the

SCR system. The smaller boiler does not exhaust its flue gas through any SCR.

In addition, it is noted in the referenced Haldor Topsoe catalyst washing presentation that

the entire catalyst loading on Avedore Unit 2 was replaced after 30,000 hours of

operation. During the initial 30,000 hours of operation, the catalyst was washed nine

times. This frequency of catalyst washing is excessive and not indicative of a successful

SCR installation. The Elsam presentation includes a bar 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 per day year-round, we would expect this

catalyst to show a rapid, severe decline in catalyst activity.

The referenced H-T presentation shows a graph of catalyst 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" over time. This graph is misleading, as it shows a linear decay 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 of deactivation 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-fired utility boilers that co-fire biomass (or plan to do so). Meetings

and discussions with all ofthe catalyst vendors except one reveal great reluctance or

refusal to offer such guarantees.

Hans Hartenstein mentioned Marl as an example ofTESCR without an FGD gas/gas

heater upstream ofthe induced draft fans following a wet scrubber. It does, however, use

scrubber bypass gas to reheat the scrubber outlet gas above saturation. Marl is not on the

official Evonik website. Maybe Mr. Hartenstein can explain whether it is a waste

Catalyst Poisoning, Volker Rummenhohl November 17, 2008
- 5 -

incinerator or boiler. Mr. Hartenstein should have this information since, based on his

email address used in communicating with the SCR catalyst vendors, he is obviously an

employee ofEvonik. He also claimed that a plate-type gas/gas heat exchanger from

Ba1cke-Durr was used in the Marl plant. A look at Ba1cke-Durr's internet website

indicates they have discontinued this product and are now offering a rotary (e.g.

Ljungstrom)-type instead.

Another plant that has a "wet" booster draft fan following a wet scrubber with an FGD

gas/gas heater before a tail-end SCR is Herne. When asked ifhe would ever want to see

this arrangement repeated, the plant engineer at Herne said "never in 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 clear that statements made

by Hans Hartenstein about the feasibility oftail-end SCRs on utility boilers burning

North Dakota lignite are personal opinion and are not based on relevant technical

expertise in this field.

Volker Rummenhohl was responsible for the process design of 26 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.

It is extremely imprudent to apply SCR to a utility boiler with such differences in firing

type and fuel burned compared to those situations that have been proven successful

without first performing extensive pilot testing and achieving acceptable results, followed

by confirming the feasibility ofthe full-scale design. One cannot look just at the bulk

flyash loading and average concentrations ofthe trace elements and other poisons in the

fuel to decide whether SCR technology will work. It is incorrect to 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 Cleaner Fossil Fuels for Sustainable Development Co-firing Coal and Biomass, Henrik

Noppenau, ENERGI E2 (Until 01.07.2006) Denmark

2 Development and Commercial Operating Experience of SCR DeNOx Catalysts for Wet

Bottom Boilers, Isato Morita, Masayuki Hirano, and Gregory T. Bielawski, presented to

Power-Gen International '98, Orlando Florida, December 9-11, 1998.

3 SCR Catalyst - five years of operating experience with all types of SCR plants and the

conclusions and measures developed as a result, Presented at VGB Congress "Power

Stations 1992"

4 Personal correspondence via email from Argillon, November 2008.

Catalyst Poisoning, Volker Rummenhohl November 17, 2008
- 6-

5 Personal correspondence via email from CERAM, November 2008.

6 Noppenau, Henrik, Cleaner Fossil 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, Volker Rummenhohl November 17, 2008