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 

Burns & McDonnell (B&McD), and their SCR consultant, Tackticks LLC, along with the 

Energy & Environmental Research Center (EERC) of the University of North Dakota, have 

reviewed the EPA’s comments(U.S. EPA, 2008), those of the Department of Justice’s 

commenter, Hans Hartenstein (Hartenstein, 2008), and Plains Justice (Plains Justice, 2008). 

These are responses regarding selective catalytic reduction (SCR) technology feasibility and 

non-SCR concerns 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 North 

Dakota Department of Health (“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. 

 

• General Regulatory Considerations 

• Corrections, Clarification and Omissions of Hartenstein and EPA’s comments 

• SCR Technology Review and Update 

• Variability of Lignite 

• Results of Coyote Pilot Testing 

• Soluble Sodium 

• Differences in Flue Gas Composition 

• Catalyst Poisoning, Blinding, and Plugging 

• Applicability of SCR Development for Texas Lignite 

• SCR Catalyst Erosion 

• Pilot Testing for SCR Catalyst 
Responses to Comments 2 September 22, 2008 

• Vendor Guarantees for TESCR 

• Temperature Variations for HDSCR 

• Burns & McDonnell’s SCR Experience 

• Comments by Sargent and Lundy on SCR Experience 

• Comments on Hans Hartenstein’s Qualifications for SCR Expert Opinions 

• Fuel Switching 

• Non-SCR Controls 

• Conclusions 

General Regulatory Considerations 

In determining BACT, the limits placed on MRYS will be required for the plant’s lifetime. In 

order for the units to run, emission rates will need to be met. Any emissions limit exceedance 

can result in a violation subject to significant financial penalties, injunctive relief and possible 

unforeseen equipment changes or plant outages. Many of the boilers referenced in EPA’s report 

are not subject to New Source Review but some other form of regulation such as the NOx State 

Implementation Plan (SIP) Call program. There is a significant difference in NOx SIP and NSR. 

The NOx SIP Call is a seasonal (May to October) cap and trade program. Under this program, a 

utility’s NOx emissions are capped to a level below historic emissions. The utility has the option 

to apply pollution controls and/or buy offsets from other utilities. Under the NOx SIP program, a 

problem with the pollution control equipment can be overcome by buying allowances while 

continuing to operate their units. NSR requires the controls be operating continuously and 

properly during plant operation. 

 

1. EPA is deviating from a case-by-case BACT analysis by casting a wide net over SCR and 

insisting that it will work on all fuels and boiler types. Based on their comments, and those 

of DOJ’s expert, in essence, “any problem can be overcome, SCR has been used successfully 

everywhere and no long term problems exist”. However, as detailed later, our experts have 

found many instances where SCR was not used as a reduction strategy, or was unsuccessful. 
Responses to Comments 3 September 22, 2008 

In Minnkota’s case, the combustion process from cyclone boilers and the North Dakota 

lignite makes application of SCR infeasible. Our specific combustion issue revolves around 

the size and type of combustion products produced in a cyclone-fired boiler when firing a 

high-sodium-containing lignite. The cyclone combustion process occurs at higher 

temperatures and different air distributions than other boiler types. Cyclone firing 

combustion products are partitioned between the slag that flows out of the bottom of the 

furnace and the flue gas containing impurities. The flue gas impurities are enriched in alkali 

(sodium and potassium) species relative to other boiler types. These species are known to 

blind and poison the SCR catalyst. The impurities of concern are vaporized during the 

cyclone combustion process to form a gas and upon gas cooling these gas phase impurities 

will condense to form aerosols or small particles that will deposit on the surface and in the 

pores of SCR catalysts. Once deposited, these alkali-rich materials will react with other gas 

phase species and deposited particles causing blinding or can react with active sites in the 

catalyst causing poisoning. This is well documented by Tackticks (see Appendix A) as well 

as by the DOJ’s expert (Hartenstein). In a TESCR system, the flue gas passes through a 

precipitator and scrubber prior to reaching the SCR system. Large particles can be removed 

from the precipitator and scrubber. However, the removal of aerosols and small particulate 

(less than 2 microns in diameter) is dependent on the aerosol and small particle size and 

composition. Sodium, potassium and alkali aerosols are not easily removed from the 

precipitator and scrubber and no vendors will guarantee removal rates. In a TESCR 

application for a high-sodium lignite fired cyclone, the TESCR catalyst is likely to be 

exposed to appreciable concentrations of sodium, potassium and alkali concentrations. The 

second part of this case-by-case BACT evaluates the fuel used. North Dakota lignite is 

known to have a much higher levels of catalyst poisoning constituents than other lignite 

types. The lethal combination of the high temperature cyclone firing combustion process and 

high levels of catalyst poisoning constituents present in the lignite make this specific 

application technically infeasible. 

2. Some catalyst vendors have “guaranteed catalyst operation” for the Minnkota units, according 

to DOJ’s expert. EPA has taken a “guarantee” as a demonstration that the SCR application 

for North Dakota lignite is commercial. From the discussion above, EPA would lead us to 
Responses to Comments 4 September 22, 2008 

believe that the high sodium levels and the cyclone combustion processes resulting in an 

abundance of SCR blinding and poisoning alkali species in the flue gas are inconsequential 

since a vendor will provide equipment to Minnkota. However, Minnkota has to evaluate a 

guarantee on the long term viability of meeting an emissions limit, including catalyst 

maintenance and replacement requirements, and therefore we must question the vendor on 

numerous issues. 

 

• Does the vendor look at the long term compliance obligations that Minnkota will be 

subject to? The vendor guarantees and contractual language will vary from project to 

project. For example, a vendor could guarantee a one time performance of their product 

and meet their obligation. However, the end user is stuck with a product that does not 

provide long term compliance. Some vendor language may guarantee a product for a 

longer period but assumes that certain operational conditions are met during that time 

period. If the operating conditions deviate, the vendor is no longer responsible. It is not 

unusual for vendors to guarantee performance then have to settle claims or change offer. 

Yet, Minnkota will still need to meet emission limits for the plant’s lifetime. 

 

• The only test data (Coyote) for a cyclone boiler burning North Dakota lignite 

resulted in significant catalyst blinding and plugging in a short time period. How 

does a vendor resolve this issue? Burns & McDonnell and EERC contacted Haldor 

Topsoe (HT) about this issue (B&McD and EERC, 2007). HT participated in the Coyote 

test that showed catalyst blinding and plugging was so severe that they could not make 

catalyst reactivity measurements. HT suggested that they would increase the pitch of the 

catalyst but had no solution for severe blinding and plugging of the catalyst pore 

structure. HT indicated that there were no catalyst designs available that would alleviate 

the severe blinding and plugging of the pore structure due to the high levels of sodiumrich aerosols present in flue derived from the cyclone-fired combustion of ND lignite. 

3. EPA has claimed the Coyote pilot-scale SCR test to be completely invalid and no conclusions 

can be made. The Coyote test was developed by a consortium of Cormetech (catalyst 

vendor), Haldor Topsoe (catalyst vendor), Hitachi (SCR system provider), EPRI (research 
Responses to Comments 5 September 22, 2008 

agency), US. DOE, Alliant Energy, Otter Tail Power, Ameren, Dynegy, and Lignite Energy 

Council. This pilot test was intended to evaluate the fouling potential of SCR on lignite coal. 

DOJ’s expert claims the test was fatally flawed, yet the participants in the test included 

vendors that design and install SCR systems as well as end-user utilities that have applied 

SCR on their boilers. This team was competent and, like many pilot tests, it is meant as a 

learning opportunity. Certainly, further testing may change some of the testing parameters, 

but the intent was to evaluate the system. Minnkota believes this testing was valid for its 

intended purpose and from this sole test, it was determined that there are significant 

impediments to using SCR on MRYS. The test results showed catalyst blinding and 

plugging due to sodium and potassium rich species. Peer reviewed literature written by 

many authors have verified that sodium and potassium species are fatal to the catalyst life. 

Corrections, Clarifications and Omissions of Hartenstein and 

EPA Comments 

The EPA’s SCR technology comments (U.S. EPA. 2008) rely heavily on their interpretation of 

information mostly repeated from earlier comments to Minnkota and opinions expressed by the 

Department of Justice’s (DOJ) commenter (Hartenstein, 2008), Many of these comments need 

to be clarified for the record. 

 

1. Hartenstein implies that lignite-fired boilers are significantly represented among the 30,000 

MW of SCR systems installed in Europe. This is misleading and substantially incorrect. 

Very few of the many SCRs retrofit in Europe were installed on lignite-fired utility boilers. 

Tackticks has advised that to the best of their knowledge, they are aware of SCR being 

originally installed at only two plants, and neither of these plants is operational today. 

2. The EPA argues that NDDH’s preliminary BACT Determination does not properly compare 

the emissions from other coal-fired boilers with high fuel sodium content to other boilers that 

successfully operate SCRs firing Powder River Basin (PRB) coal with high dust SCRs in the 

United States and are comparable to the Young Station boilers for their flyash alkali contents. 

The EPA ignored the Department’s supporting detailed information by EERC that explains 
Responses to Comments 6 September 22, 2008 

why SCRs are not able to tolerate the higher levels of alkali species contained in flue gas 

such as exhausted from the MRYS boilers as compared to the PRB coal fired boilers.. 

3. In addition, the EPA and Hartenstein did not provide any substantial technical information 

that demonstrates that effective solutions to prevent or remove pore pluggage and blinding of 

SCR catalyst from sodium- and potassium-rich species present in the flue gas stream 

exhausted from a North Dakota lignite-fired cyclone boiler, whether installed in a 

conventional hot-side or cold-side application downstream of a wet scrubber, have been 

developed by catalyst vendors. 

4. Hartenstein did not demonstrate he had an understanding of Center lignite characteristics and 

variability issues. Specifically, he did not understand how soluble sodium is used to define 

the abundance of organically associated sodium in lignite and how sodium will vary because 

of the abundance of other ash forming components in the coal. The abundance of sodium 

and other ash forming components vary dramatically and uniquely in North Dakota (Fort 

Union region) lignite coal and result in operational challenges. Hartenstein does not 

understand the differences between Fort Union lignite and Texas lignite. He indicates that 

the installations of SCR on Powder River Basin (PRB) subbituminous coal and testing on 

Texas lignite indicate feasibility for SCR on ND lignite even though the levels of sodium in 

typical PRB coal and Texas lignites are very low (0.7 to 1.5% Na2O) as compared to 4.4 % 

Na2O for Center lignite. 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 of the fly ash. The size and composition of the 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. 

5. Hartenstein did not address the issue of the partitioning of ash-forming species 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. These flame-volatilized species will 

condense homogeneously to produce abundant sodium and potassium-rich aerosols because 
Responses to Comments 7 September 22, 2008 

of the lower level of entrained solid ash particles in cyclone combustion-derived flue gases 

relative to pulverized coal combustion derived flue gas.

6. Hartenstein did not address the formation of aerosols and how that can impact SCR 

performance. The key issue for high sodium Fort Union (North Dakota lignite) coals fired in 

cyclone-fired boilers is the abundance of alkali-rich aerosols in the flue gas that can penetrate 

into the pores of SCR catalyst, causing blinding and poisoning. This is an issue for high dust 

and low dust / tail-end SCR applications. He appears to not be familiar with the diffusion 

mechanism of transport of aerosols deep into the SCR catalysts that can cause poisoning and 

plugging. Hartenstein appears to confuse the importance of catalyst pitch relative to pore 

plugging and blinding. He incorrectly suggests that catalyst pitch will solve the pore 

plugging and blinding problem. Using wider pitch catalyst does not eliminate the penetration 

of alkali-rich aerosols deep into SCR catalyst causing pore plugging and blinding problems. 

The impact of such aerosols that pass through the electrostatic precipitator (ESP) on the 

performance of low dust SCR applications was not discussed by Hartenstein. This fine ash 

that escapes from the ESP is finer than the bulk flyash and has a higher catalyst plugging 

potential due to a higher tendency to agglomerate. In addition, Hartenstein did not consider 

information provided on Powerspan barrier discharge reactor pilot slipstream testing that 

showed alkali rich accumulations downstream of the Unit 1 ESP at the MRY station. 

7. Hartenstein’s knowledge of gas-solid reaction mechanisms to form sulfate and pyrosulfate 

phase in situ in SCR catalysts appears to be very limited and was not adequately addressed. 

8. Hartenstein did not discuss the recent literature on catalyst poisoning studies in Europe 

associated with cofiring high alkali (Na and K) containing biomass. This testing has showed 

significant poisoning of catalysts due to alkali aerosol penetration into catalysts and the 

subsequent reaction with catalyst active components causing poisoning. 

9. Hartenstein did not offer information that more than 20,000 MW of lignite fired units in 

Germany were not required to install SCR in order to comply with the national regulation, or 

that even new lignite-fired units being installed today in Germany are not equipped with SCR 
Responses to Comments 8 September 22, 2008 

of any type. He did not state that Germany had only one cyclone-fired boiler operating with 

a LDSCR (Walsum Unit 7), or that the unit burns bituminous coal; nor did he advise that 

Voitsberg Unit 3, a boiler in Austria firing lignite coal, only ran for a short time with a highdust SCR and was subsequently shutdown and demolished. He states that TESCR 

technology was “generally adopted as a universally applicable SCR solution for all types...” 

but failed to mention that there has never been another TESCR built after Siersdorf, (which 

was finished in early 1991 and has subsequently been decommissioned), in the United States 

or Europe. To the best of our knowledge, there is no TESCR anywhere in the world on a 

lignite-fired utility boiler. He cites “Ceram’s extensive experience with lignite..”, but fails to 

report that this consists of only one plant with Ceram catalyst having operated for a short 

period of time on lignite and a few pilot programs, so that it is dubious to say that this vendor 

has extensive experience on lignite fired boiler SCR plants (see Appendix A). There are 

numerous other instances of missing or factually incorrect information attributed to Mr. 

Hartenstein discussed in Appendix A. 

10. Again, the EPA fails to recognize conclusively that ash chemical and physical properties of 

the Texas lignite (Wilcox formation) that TXU proposes to burn at the new Oak Grove 

powerplant where SCR is being installed (but has not yet begun operation) do not represent 

what is fired in North Dakota, and therefore technical feasibility and expected performance in 

a Texas lignite-fired pulverized coal boiler SCR application is not transferable to North 

Dakota lignite-fired cyclone burner units due to the significant differences in flue gas and ash 

chemical and physical properties. The composition of the Texas lignite fired at Martin Lake, 

where SCR mini-SCR pilot testing has been conducted, is typical of the composition of 

lignite fired at Sandow, with sodium oxide levels in the Texas lignite ash equal to 0.7%. The 

levels of sodium oxide in Center lignite average 4.4% and can be as high as 13% in as-fired 

samples. Hartenstein (2008) does not provide information on chemical composition of any 

fuels that are comparable to high sodium ND lignite where SCR installation have been 

installed and tested or successfully operated. 

 
Responses to Comments 9 September 22, 2008 

11. No examples were provided of on-line cleaning methods nor catalyst that would prove 

resistant to damage from such methods that would be effective in removing surface blinding 

and pore plugging deposits such as those seen in the Coyote pilot test catalyst even with the 

suggested edge erosion prevention measures in place. Hans Hartenstein does not address this 

issue in his comments. Hartenstein implies in his report (2008), that catalyst that has been 

poisoned by sodium compounds can be regenerated in-situ, and that this technique is well 

developed. There is extremely limited experience with in-situ catalyst cleaning on coal-fired 

units. It has never been used for blinded or chemically poisoned catalyst, but only for 

mechanically plugged catalyst (see Appendix A). 

The following discussion will provide information on the following topics relevant to the EPA’s 

comments: an SCR technology review and update; the variability of lignite; results of Coyote 

pilot testing; soluble sodium; differences in flue gas composition; catalyst poisoning, blinding 

and plugging; applicability of SCR development for Texas lignite; SCR catalyst erosion and 

cleaning; pilot testing for SCR catalyst; vendor guarantees for TESCR; temperature variations 

for HDSCR; Burns & McDonnell’s SCR experience; comments by Sargent and Lundy on SCR 

experience; comments on Hans Hartenstein’s qualifications for SCR expert opinions; fuel 

switching/blending/cleaning; non-SCR controls; and conclusions. 

SCR Technology Review and Update 

The literature provided by Hartenstein in his expert report (Hartenstein, 2008) did not provide 

any new information that would indicate the SCR technology is feasible for NOx reduction at the 

MRY plant. Much of the information Hartenstein provided was reviewed earlier by the Energy 

& Environmental Research Center (EERC) and Burns and McDonnell. In addition, the reports 

provided by Hartenstein were not peer reviewed and were derived primarily from companies 

who have vested interests in the SCR technology and typically do not discuss problems and 

challenges. The reports from EPRI provided more useful information on the characteristics of 

the Texas lignite. 

Hartenstein (2008) provided little information indicating that he is familiar with blinding and 

poisoning processes involving alkali (sodium and potassium). A demonstrated understanding of 
Responses to Comments 10 September 22, 2008 

the blinding, plugging, and poison due to firing alkali-rich fuels is vital in determining the 

feasibility of SCR technologies. Much of this background information has been provided in 

EERC’s previous comments (2007 and earlier). In addition, a significant amount of work has 

recently been conducted in Europe on blinding and poisoning of SCR catalysts associated with 

firing biomass alone and with coal. Much of the discussions are focused on the impact of alkalirich aerosols on catalyst deactivation. 

Since Hartenstein does not adequately address key mechanisms of catalyst deactivation and 

poisons, it is appropriate to provide a summary of the technical information. Guo (2006) who 

conducted testing of catalyst deactivation studies described the mechanisms of catalyst 

deactivation as shown in Figure 1. There are four primary types of catalyst deactivation. 

• The first is channel plugging and is impacted by so called “popcorn ash” or in many cases 

typical of ash deposit fragments. Channel plugging is largely driven by the size of the 

ash materials carried back into the flue gas treatment system and can typically be 

controlled by the use of large particle ash screens to remove the ash, or by providing 

larger pitch catalyst. 

• The second type is pore plugging by small fly ash particles. Small particles sometimes 

become lodged in the openings to the catalyst pore system and can cause plugging. 

These particles are typically not bonded and can be removed by various cleaning 

technologies. 

• The third type is masking of the macrosurface by a dense phase. These phases that form 

are typically sulfates. The sulfates have formed as a result of in-situ sulfation of 

deposited alkali and alkaline earth materials. 

• The fourth type is poisoning of the active sites in the catalyst. The active sites in SCR 

catalyst can be poisoned by the diffusion of various types of aerosols. The aerosols will 

diffuse into the pores and react with the active components of the catalyst. 
Responses to Comments 11 September 22, 2008 

Figure 1. General mechanisms of SCR catalyst deactivation (Guo, 2006). 

High sodium lignites are prone to form abundant levels of aerosols when fired in a cyclone 

burner. Aerosols are formed as a result of the homogenous condensation of flame-volatilized 

species in combustion systems. During combustion of lignite, sodium, potassium, sulfur, and 

other components will vaporize and upon gas cooling these components will condense to 

form aerosols and other particles. As a result of these interactions, the resulting ash 

composition and mass distribution as a function of size is also shown in Figure 2. Typical 

ash derived from coal combustion has a bimodal to multimodal size distribution that consists 

of a submicron and supermicron size fraction as shown in Figure 3. The submicron 

component is largely a result of the condensation of flame-volatilized inorganic components. 

The intermediate size mode at about 2 micrometers is derived from the more refractory 

organically associated elements such as calcium and magnesium. The larger particles at 

approximately 12 to 15 μm are derived from the mineral grains present in the coal. The 

larger-size particles have been called the residual ash by some investigators (Sarofim and 

others, 1977) because these ash particles resemble, to a limited degree, the original minerals 
Responses to Comments 12 September 22, 2008 

in the coal. Sodium and other flame-volatilized components are concentrated in the finer size 

fractions of ash 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 

content of the 3rd stage (1–3 micrometer size cut) of the sampling train approached 20% 

Na2O. 

 

Figure 2. Transformation of inorganic components present in coal during combustion. 
Responses to Comments 13 September 22, 2008 

Figure 3. Final size distribution of ash particles produced upon combustion of lignitic coals 

(Benson and Laumb, 2007). 

Figure 4. Composition distribution of ash particles during combustion of North Dakota 

Lignite (Benson and others, 1983). 

The transport of intermediate ash species (i.e., inorganic vapors, liquids, and solids) is a function 

of the state and size of the ash species and system conditions such as gas flow patterns, gas 

velocity, and temperature. Several processes are involved in the transport of ash particles. These 

processes have been described by Raask (1985) and Rosner (1986). The primary transport 

mechanisms are illustrated in Figure 5. For larger particles inertial impaction and eddy 

impaction in turbulent regions are the dominant mechanisms. The aerosols (small particles 

<1 μm) and vapor-phase species are transported by the vapor phase and small particle diffusion. 

The inorganic materials are transported to heat-transfer and catalyst surfaces by diffusion, 

electrophoresis, and inertial impaction. 
Responses to Comments 14 September 22, 2008 

Figure 5. Scanning electron microscope secondary electron image of SCR surface structure 

before exposure to flue gases. 

Recent work conducted by Zheng and others (2008) in a paper entitled “Deactivation of V2O5-

WO3-TiO2 SCR catalyst at biomass fired power plant entitled “Elucidation of mechanisms by 

lab- and pilot-scale experiments” described the diffusion of aerosols and their ability to cause 

catalyst poisoning. Figure 6 shows a plot of the aerosol concentration as a function of size, 

catalyst pore size, and the diffusion coefficient with size. These result show that diffusion of the 

submicron aerosol is highly likely since potential for diffusion increases with the smaller size 

fraction of particles and that the mechanism will be active for particulate from upstream and 

downstream of the particulate control device such as an ESP. These efforts followed earlier 

studies where Zheng and others (2005) biomass-derived alkali rich aerosols caused a drop in 

NOx reduction activity by 52% after about 1140 hours of operation. 
Responses to Comments 15 September 22, 2008 

a. Comparison to ESP inlet size distribution of fly ash. 

 

b. Comparison to ESP outlet size distribution of fly ash 

Figure 6. Comparison of the size distribution of the aerosol produced during combustion with 

the diffusion coefficient and catalyst pore size (Modified after Zheng and others (2008) with data 

from Linak and Wendt (1994)). 

The association of alkali and alkaline earth elements in Center lignite is similar to the 

associations found in biomass. In both Center lignite and biomass materials the alkali and 

alkaline earth elements are largely organically associated. An analysis of a wood residue 

biomass material that is similar to lignite is shown in Table 1. The total alkali (Na2O+K2O) 
Responses to Comments 16 September 22, 2008 

calculated on a lb/mmBTU basis for the wood residue is 0.10. The total alkali for the average 

Center lignite was determined to be 0.84 lb/mmBTU. Compositions of various biomass types 

were compiled by Miles and others (1995) and they found the total alkali ranged from 0.06 to 

1.15 lb/mmBTU. The overall chemical compositions for the biomass are listed in Tables 2 

through 5 along with the water soluble alkali. Miles and others (1995) conducted chemical 

fractionation, a procedure that determines the abundance of alkali and other elements that is 

soluble (associated as soluble species and with the fuel organic fraction), on the biomass and 

found that the alkali were mainly organically associated. 

Because of the organic association alkali species vaporize upon combustion and condense to 

form aerosols upon gas cooling. This vaporization of alkali during biomass combustion resulting 

in the formation of aerosols has been investigated by numerous researchers. One of the most 

recent paper is by Hindiyarti and others (2008). 

Table 1. Example of a wood residue biomass composition. 

 Wood Residue Biomass 

Proximate Analysis, as received, wt% 

Moisture 7.30 

Volatile Matter 76.82 

Fixed Carbon 15.25 

Ash 0.6 

Ultimate Analysis, as received, wt% 

Hydrogen 6.1 

Carbon 46.85 

Nitrogen 0.1 

Sulfur 0.1 

Oxygen 46.05 

Ash 0.63 

Heating Value, Btu/lb 8274 

Ash Composition, wt% equivalent oxide 

SiO2 27.7 

Al2O3 11.0 

Fe2O3 10.0 

TiO2 0.5 

P2O5 1.4 

CaO 28.4 

MgO 5.9 

Na2O 4.9 

K2O 7.6 

SO3 2.5 

Lb alkali (Na2O+K2O)/mBtu 0.10 
Responses to Comments 17 September 22, 2008 

Table 2. Wood Fuel Blends: Alkali Deposit Investigation Samples (Miles and others 1995).
Responses to Comments 18 September 22, 2008 

Table 3. Wood Fuel Blends: Various (Miles and others 1995). 
Responses to Comments 19 September 22, 2008 

Table 4. Urban Waste Fuels and Residues (Miles and others 1995). 
Responses to Comments 20 September 22, 2008 

Table 5. Wood Fuel: Energy Crops (Miles and others 1995). 
Responses to Comments 21 September 22, 2008 

Hartenstein (2008) indicated that “sodium is not a poison at SCR operating temperatures.” This 

statement is inconsistent with Hartenstein’s past claims, where he makes the following statement 

(Hartenstein and Licata, 1996) “...elements such as sodium and potassium, are known to cause 

permanent irreversible disactivation of SCR catalysts.” There is literature information indicating 

that sodium is a poison at SCR operating temperatures. The poisoning mechanisms of alkali and 

alkaline earth oxides on vanadia catalysts were investigated by Chen and others (1990). Their 

work found that the deactivation is directly related to the basicity of the poisons. The ranking of 

the strengths of the poisons are listed as follows: Cs2O > Rb2O > K2O > PbO > Na2O > LiO > 

CaO > P2O5. Figure 7 shows the activities of the catalyst with various elements added. The 

testing was conducted at 300°C. In addition, Guo (2006) conducted a study on the intrinsic SCR 

activity for NO with NH3 reaction and found that the additions of K, Na, and Ca greatly decrease 

the NO reduction activity of 1% V2O5 – 9% WO3/TiO2 as illustrated in Figure 8. 

Figure 7. Rate constants for a V2O5/TiO2 combined with different amount of oxide poisons 

(Chen and others, 1990). 
Responses to Comments 22 September 22, 2008 

Figure 8. Impact of NOx reduction rate constant as a result of poisoning by sodium, potassium, 

and calcium (Guo, 2006). 

The mechanisms of catalyst deactivation due to alkali components are currently being 

investigated in depth. Several studies are being conducted in Europe because of poisoning of 

catalysts due to biomass firing and co-firing. The diffusion of alkali (Na and K) vapor has been 

ruled out as was correctly stated by Hartenstein (2008) because it will be in the condensed form 

at SCR temperatures. However, the presence of alkali aerosols does contribute to the 

deactivation of catalysts (Zheng and others 2008, Zheng and others 2005). The rates of 

deactivation in full-scale and laboratory studies were about 1% per day. They indicated that the 

in-situ formation of liquid potassium-vanadium-pyrosulfates could be one of the possible 

mechanisms. However, testing showed that the deactivation reactions also take place in the 

absence of SO2 due to aerosol penetration into the catalyst. 

The exact form of the alkali aerosol (hydroxide, sulfate, or other) that contributes to poisoning is 

not known. Zheng and others (2008) indicate the possible mechanism of deactivation occurs by 

the diffusion of aerosol particles rich in alkali into the catalyst pores followed by reaction with 

the V–OH groups producing –V–O–K (Na). These observations are consistent with the work 

conducted by Kling and others (2007) who investigated deactivation of SCR catalysts in three 
Responses to Comments 23 September 22, 2008 

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 resulted in decreased the NOx reduction 

catalytic activity as shown in Figure 9. 

Figure 9. Reduction in catalytic activity as a function of accumulation of alkali in the catalyst 

(Kling and others (2007). 

Recent testing conducted by 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. The components responsible for the deactivation were sodium, 

potassium, and calcium sulfate-based materials. Alkali components (sodium and potassium) 

were found deep inside the catalyst. 

Broske (2003) in an EPRI report indicated that for analysis of spent catalysts from medium 

sulfur bituminous (Appalachian) coal found that the concentration of sodium and potassium 

species accumulated to over 100 times the levels found in new catalysts. The levels reached in 

the catalyst were between 4000 and 6000 ppm. This is for an Appalachian coal that typically has 
Responses to Comments 24 September 22, 2008 

low levels of sodium in the ash. In this particular catalyst, arsenic was found to be the primary 

contributor to poisoning but the alkali (sodium and potassium) also contributed. 

The impact of aerosols on the performance of low dust SCR applications was not discussed by 

Hartenstein (2008). The impacts have been identified by Copolo and others (2003). They 

indicated in their paper that “The ash however, that escapes from the precipitators is finer than 

the ash in general ..... Although less likely to cause erosion, it does have a higher plugging 

potential as finer ash has been found to have a higher tendency to agglomerate.” In addition, 

Hartenstein (2008) did not consider information provided on ash accumulations downstream of 

the ESP at the MRY station. Testing of Powerspan’s barrier discharge reactor (Tolbert and 

Benson, 2008) was conducted to determine the potential application of the Powerspan 

technology for new power generation firing high sodium ND lignite. The barrier discharge 

reactor is placed downstream of particulate control systems to enable the oxidation of NO to NOx

species that will allow for capture in an ammonia-based scrubbing system. A slipstream barrier 

discharge reactor system was designed by Powerspan and the EERC and installed downstream of 

the ESP on Unit 1 at the MRY Station. The gas temperature was approximately 300°F. 

The primary concern regarding the success of the Powerspan technology was that sodium-rich 

aerosols exiting the ESP would accumulate on the quartz rod resulting in decreased performance 

of the barrier discharge reactor. At two week intervals during the testing campaign, the reactor 

was inspected and rods were removed for analysis. The ash accumulation resulted in decreased 

nitrogen oxide (NO) oxidation due to accumulations of alkali and alkaline earth sulfate rich ash 

layer on the rods. An example of the ash accumulation on the rod after exposure to flue gases 

downstream of the ESP is illustrated in Figure 10. The exposed quartz rods were mounted in 

epoxy resin and cross-sectioned for scanning electron microscopy and x-ray microanalysis. The 

image in Figure 10 shows a highly bonded ash coating on the surface of the quartz rod. The red 

line represents the line analyzed across deposit and the quartz rod. The length of the line is 

22μm. The abundance elements were determined along the red line shown in Figure 10. The 

levels of sodium and potassium in the bonded ash layer were greater than 10 percent. 
Responses to Comments 25 September 22, 2008 

Figure 10. SEM image of quartz rod exposed to flue gas downstream of the ESP at MRY Unit 1 

with element composition line scan across the deposit and quartz rod (Tolbert and Benson, 

2008). 

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 exposed to flue gas 

downstream of the ESP for 20, 48, and 107 days. The bulk composition summarized in Table 6 

shows significant levels of sodium, calcium, and potassium along with sulfur. 
Responses to Comments 26 September 22, 2008 

Table 6. Bulk composition of ash removed from electrode samples obtained from rod 

removed at 20, 48, and 107 days. 

In the 1999 technical paper, Mr. Hartenstein (1999) and his co-authors reported SCR catalyst 

deactivation due to sodium at the RWE Staudinger plant in Germany. Specifically, it is reported 

on page 5 of the referenced paper that “...the fly ash from the German coal formed highly 

adhesive deposits, while the portion of South African coal contributed to the formation of a 

liquefied fly ash. The reason for this was determined by a chemical analysis of the fly ash. It 

can be seen that the content of the alkali sulfate, which adheres to the surface of the fly ash 

particles, favors the tendency to agglomerate. A phase analysis of the deposits revealed 

crystalline sodium aluminum sulfate and potassium aluminum sulfate (NaAl(SO4)2;KAl(SO4)2).” 

This information supports the Department’s opinion related to the formation of sodium–related 

deposits on the SCR catalyst that accelerate the deactivation of the catalysts. This information 

conflicts with Mr. Hartenstein’s statement, on page A-28 of his expert report, that the “...the 

intrusion of liquid pyrosulfates is no major concern with respect to a severe, rapid catalyst 

deactivation.”
Responses to Comments 27 September 22, 2008 

Variability of Lignite 

North Dakota lignite or lignite from the Fort Union Region of North America has very unique 

properties. The Fort Union lignite coals are unique because of the extraordinarily high levels of 

alkali and alkaline earth elements that are associated with the organic or combustible fraction of 

the coal. The constituents that are organically associated are considered ion exchangeable or 

soluble sodium. The association of the sodium in Fort Union lignites is similar to the association 

of sodium and potassium found in biomass. In addition, the coal contains mineral grains 

consisting of mixed clays, quartz, and sulfides that vary significantly in abundance. The form of 

the element influences their form in the flue gas. For example, organically associated sodium 

will vaporize during combustion and form an aerosol upon gas cooling, while mineral associated 

sodium (sodium in a clay) is less likely to vaporize and will be retained with the clay-derived 

particle. The sodium associated with the aerosol is much more reactive than sodium associated 

with a melted clay-derived particle. 

The organically-associated elements are prone to vaporize during combustion. These organically 

associated elements will condense homogenously to form submicron sized aerosols or ultrafine 

particles. In addition, the organically associated elements will react with aluminosilicates 

producing low-viscosity (low melting point silicate-based liquids) phases and with sulfurproducing sulfates and pyrosulfate. These elements contribute to the formation of deposits on 

ceramic/refractory surfaces, cyclones, heat-transfer surfaces, SCR catalysts, and gas filters. 

Formation of these deposits will lead to operability problems, with the potential to shut down the 

system. Lignite composition is highly variable and, therefore, will contribute to a range of 

challenges. As a result of these challenges and efforts to identify problematic species, a 

significant database of selected North Dakota lignites, specifically Center lignite, has been 

developed to provide the basis for understanding the behavior of lignite and to project potential 

challenges. The variability of the Center mine lignite characteristics are summarized in Table 7. 
Responses to Comments 28 

Table 7. Center lignite composition (moisture, ash, sulfur, and heating value expressed on an as-received basis; 

expressed as weight percent equivalent oxide of the ash produced at 750 °C). Moisture,% Ash, % Sulfur% Btu/lb Al2O3 BaO CaO Fe2O3 MgO P2O5 K2O 

Average 37.13 9.64 0.98 6578 11.68 0.52 13.15 8.90 3.99 0.12 1.33 Max 39.37 25.46* 2.55 7101 15.62 1.22 23.96 24.72 7.09 1.00 2.30 Min 33.56 4.97 0.47 5852 6.31 0.20 6.80 5.38 2.30 0.01 0.16 90th Perc. 38.10 12.51 1.29 6820 14.23 0.84 19.92 12.20 5.68 0.41 1.92 10th Perc. 35.95 7.06 0.72 6359 9.58 0.37 9.73 7.08 3.00 0.04 0.645th Perc. 37.17 9.33 0.90 6552 11.62 0.47 12.15 8.34 3.81 0.09 1.36 55th Perc. 37.37 9.75 0.94 6592 11.97 0.50 12.74 8.68 3.97 0.10 1.44 * High value may be an analysis or reporting error. Sample could not be reanalyzed to verify. 
Responses to Comments 29 September 22, 2008

Hartenstein (2008) indicated that “I am not aware of a single case where high variability of heat 

and ash contents of the coals and/or of the constituents that make up the ash preclude the 

principles of the SCR technology from being technically feasible and applicable.” Hartenstein 

did not indicate how he would identify a design coal for the catalyst design for high dust SCR 

based on the lignite characteristic. In addition, Hartenstein incorrectly assumes that over the 

range of fuel properties the performance of the particulate control systems will not be impacted, 

thus avoiding impact on a low-dust or tail-end SCR. In cases where there is high sodium and 

low ash contents, the abundance of aerosol particles increases dramatically. These particles can 

make their way through particulate control devices and can impact the performance of low dust 

and tail-end SCR as discussed previously. 

Hartenstein (2008) does not provide information on chemical composition of the fuels that are 

comparable to high sodium lignite where SCR installation have been installed and tested or 

successfully operated. The composition of the Texas lignite fired at Martin Lake is typical of the 

composition of lignite fired at Sandow and is shown in Table 8. The sodium oxide levels in the 

Texas lignite ash is 0.7%. The levels of sodium oxide in Center lignite average 4.4% and can be 

as high as 13% in as-fired samples. 

It is surprising that Hartenstein did not discuss his experience with German Ruhr Brown coal as 

described in a paper by Hartenstein and others (1999) where they found that ”... the pressure 

drop across the catalyst layers rapidly increased....” when they fired German Ruhr coal alone. 

The problem was associated with the highly “adhesive” fly ash bonded with an alkali sulfate 

phase. They were unable to fire 100% lignite and had to rely on blending with a South African 

coal to reduce the problem. He also stated that “We have also learned that we had to analyze not 

only for sodium (Na) and potassium (K) content of the coal but also we need to know if the Na 

and K compounds are water-soluble. In a water soluble form, these alkaline metals are highly 

mobile and will migrate throughout the catalyst material reducing active sites.” 
Responses to Comments 30 September 22, 2008

Table 8. Average Texas Lignite Coal and Ash Composition (Ulvog and Wiemuth, 2003)

Results of the Coyote Pilot Testing 

Hartenstein stated “The HDSCR Coyote pilot testing was ill-designed and fundamentally 

flawed.” Hartenstein based this statement on his flawed interpretation of the Coyote testing. 

Hartenstein (2008) incorrectly interpreted the testing at Coyote Station as follows: “Admittedly, 

the Coyote Pilot Testing results seem to indicate worse pluggage than the Baldwin Pilot Testing 

results. However, it must be noted that the same pilot test reactor and the same catalyst, which 

had been already used (and plugged) at Baldwin was subsequently used at Coyote. The well 

known fact that catalyst that had been plugged and only mechanically cleaned is more likely to 

quickly plug again than new, unused catalyst was simply ignored.” 

Hartenstein (2008) described the reactor as being “ill-designed.” The reactor system initial 

design was based on a design provided by Cormetech. The final design was reviewed and 

approved by the project team that included Cormetech, Haldor Topsoe, Hitachi, EPRI, US. 

DOE, Alliant Energy, Otter Tail Power, Ameren, Dynegy, and Lignite Energy Council. In 
Responses to Comments 31 September 22, 2008

addition, the selection of catalyst for the testing at Coyote was based on the recommendations of 

Haldor Topsoe. The testing protocols including the soot blowing media and frequency as well as 

all operating conditions were reviewed and approved by the aforementioned project team. 

The following describes how the testing was conducted and is clearly described in Benson and 

others (2005). 

1. The same reactor system used at Baldwin station was moved to the Coyote Station and 

installed. 

2. The system was completely cleaned prior to operations at the Coyote Station. 

3. Fresh catalyst was installed in reactor prior to testing at the Coyote Station. 

4. At approximately two month intervals, the reactor was inspected and sections of the 

catalyst were removed for analysis, and fresh catalyst replaced the catalyst section that 

was removed. 

5. The catalyst sections were analyzed for pore plugging and Haldor Topsoe was going to 

conduct activity measurements. 

6. Haldor Topsoe indicated that the catalyst was too plugged to measure reactivity. 

The slipstream reactors worked well at the Baldwin Station (cyclone PRB fired) and Columbia 

(pulverized coal tangential PRB fired) with minor to moderate fouling. The same reactor used at 

Baldwin was used at the Coyote Station. The pitch of the catalyst used at Coyote Station was 

6mm as recommended by Hansen at Haldor Topsoe. A comparison of the first 500 hours with 

both systems using fresh catalysts is shown in Figures 11 and 12 for Baldwin and Coyote 

Station, respectively. 
Responses to Comments 32 September 22, 2008

Baldwin SCR Reactor

First 500 hours

0

0.2

0.4

0.6

0.8

1

1.2

0 100 200 300 400 500

Runtime (hours)

CAT DP (" of H20)

Figure 11. Pressure drop across SCR reactor during first 500 hours of testing at Baldwin 

Coyote SCR Reactor

First 500 Hours

0

0.2

0.4

0.6

0.8

1

1.2

0 100 200 300 400 500

Runtime (hours)

CAT DP (" of H20)

Figure 12. Pressure drop across SCR reactor during first 500 hours of testing at Coyote 

Initially, at Baldwin there were some problems with start up and operation of the reactor because 

of plant outages. The pressure drop at the end of 500 hours averaged about 0.6 inches of water. 

The pressure drop for Coyote Station is shown in Figure 12, and at the end of 500 hours the 

pressure drop averaged about 0.85 inches of water. The plugging and blinding of the catalyst 

was severe. 
Responses to Comments 33 September 22, 2008

Soluble Sodium 

Soluble sodium is used to describe the form of sodium in the coal as well as forms of sodium in 

ash. The soluble form of sodium in coal is used to describe the abundance of sodium associated 

with the water soluble and organic fraction of the coal. During combustion the soluble sodium 

(organically associated) in the coal is much more likely to vaporize than an insoluble form. This 

is especially true for a cyclone-fired boiler. Upon gas cooling the alkali vapors will condense to 

form aerosols or sometimes called ultrafine particles. These ultrafine particles can diffuse into 

the pores of the catalyst and react with V-OH groups forming V-O-K(Na) rendering the site 

inactive (Zheng and others 2008). Hartenstein’s following interpretation is inconsistent with the 

work by Zheng and others (2008) which is co-authored by one of the lead scientists from Haldor 

Topsoe. 

”Unfortunately, the Department fails to realize what was pointed out by one of the most 

experienced catalyst suppliers, namely that “sodium is not a poison to catalyst at SCR 

operating temperatures.” Thus, the elaborate comparison of emission factors of sodium, 

potassium, calcium, and magnesium emission factors with the fly ash may have some 

academic value but is effectively meaningless for the correct prediction of catalyst 

deactivation, since particle bound sodium, potassium, calcium and magnesium in the fly 

ash are not mobile and therefore are not catalyst poisons.” 

The abundance of alkali aerosols in the flue gas as depicted by emission factor will have an 

impact on the rate of catalyst deactivation by the formation of aerosols that directly poison sites 

or produce pyrosulfates. The impact of the abundance of alkali (sodium and potassium) is 

clearly illustrated by the recent work conducted by (Kling and others (2007). 

The formation of pyrosulfates as described earlier (EERC and Burns and McDonnell) is 

consistent with recent investigations of alkali poisoning of catalyst (Zheng and others 2008, 

Zheng and others 2005). They indicated that the in situ formation of liquid potassium-vanadiumpyrosulfates could be one of the possible mechanisms. Hartenstein (2008) states “Alternatively, 

these pyrosulfate compounds would have to be present in a liquid so that their dissociated ions 

(i.e. Na+, K+) would be mobile in order to enter the catalyst pores and react with the catalyst’s 
Responses to Comments 34 September 22, 2008

active sites.” He does not consider their in-situ formation as a result of the reaction of 

accumulated Na or K-rich aerosols with SO3 and vanadium in the pores of the catalyst. 

Vanadium and iron compounds are know to catalyze the formation of pyrosulfates. Hartenstein 

(2008) also incorrectly states the range of melting points of the pyrosulfate phases (650 to 

750oF). The melting points of selected pyrosulfates are listed in Table 9 and have a range of 

(535 to 1281oF). 

Table 9. Melting Points of Selected Pyrosulfate Compounds 

Compound Temperature, °C Temperature, °F 

K3Fe(SO4)3

K3Al(SO4)3 

KFe(SO4)2

Na3Fe(SO4)3

Na3Al(SO4)3

NaFe(SO4)2

Na2S2O7

K2S2O7

(K1.5Na0.5)S2O7

618 

654 

694 

624 

646 

690 

401 

300 

279 

1144 

1209 

1281 

1155 

1195 

1274 

754 

572 

535 

Differences in Flue Gas Composition 

The flue gas derived from the cyclone combustion of high sodium lignite contains an abundance 

of alkali-rich aerosols. This is well known and has been published by Benson and others (1983) 

as well as other investigators. The abundance of alkali rich aerosols is similar to that found in 

biomass combustion systems. Recently, work conducted by Zheng and other (2008) point out 

the importance of the aerosol particles and catalyst poisoning. 

Hartenstein again makes the incorrect claim that “sodium is not a catalyst poison at SCR 

operating temperature” and dismisses the uniqueness of the flue gas derived from high sodium 

lignites. However, he provides no example of a coal fired in a boiler that produces a flue gas that 

is characteristic of flue gases produced from North Dakota lignite where SCR has been installed 

and successfully operated. 
Responses to Comments 35 September 22, 2008

Catalyst Poisoning, Blinding and Plugging 

The pores of the catalyst exposed to the alkali-rich flue gas derived from the cyclone-fired 

combustion of ND lignite at the Coyote pilot test were plugged. Penetration into the pores was 

extensive. Sulfation of the alkali components resulted in filling and plugging of the pores of the 

catalyst. Cyclone firing increases the abundance of alkali and other flame-volatilized species in 

the flue gas stream. The more refractory components end up in the slag. The alkali-rich flue gas 

stream is deficient in larger entrained ash particles derived from quartz and clay mineral in the 

flue gas stream. Upon gas cooling the alkali components will largely condense homogeneously 

to form alkali-rich aerosols because of the low abundance of larger ash particles for 

heterogeneous condensation. This results in a flue gas with higher alkali aerosol content than 

produced by pulverized coal fired systems. 

The aerosols diffuse into the catalyst pores and are subsequently sulfated or interact with catalyst 

active sites resulting in plugging/blinding and deactivation, respectively. There does not appear 

to be a catalyst material that has shown significantly improvement over the past catalyst relative 

to the performance in high sodium containing system. The specific question was asked to 

Flemming Hansen of Haldor Topsoe (Hansen, 2007) as to whether improvements have been 

made in catalysts over the ones tested at Coyote Station that warrant further testing. He 

indicated that no formulation or design changes have been made to improve their performance in 

high sodium containing flue gases. 

Applicability of SCR Development for Texas Lignite 

EPA provided several comments regarding future application of high-dust SCR at TXU’s Oak 

Grove facility as an example that it should not be eliminated as technically infeasible (at MRYS) 

on the basis of catalyst plugging and deactivation. The EPA mentioned catalyst vendors’ beliefs, 

and an opinion by Electric Power Research Institute (EPRI) issued on September 7, 2006 and 

determinations by the Texas Commission on Environmental Quality. The EPA also states that 

“while the properties of North Dakota and Texas lignite might not be the same...” that the “same 
Responses to Comments 36 September 22, 2008

basic principle applies that the accelerated catalyst replacement requirements are a matter of 

economics and not technical feasibility” (U.S. EPA, 2008, Enclosure 2). 

As responses to previous EPA opinions on this subject have been presented elsewhere 

(Minnkota, 2007A, 2007B, 2007C, 2008), the EPA fails to recognize conclusively that ash 

chemical and physical properties of Texas lignite (Wilcox formation) that TXU proposes to burn 

at the new Oak Grove powerplant do not represent what is fired in North Dakota, and its 

technical feasibility and expected performance in an SCR application is not transferable to North 

Dakota lignite-fired cyclone burner units due to the significant differences in flue gas and ash 

chemical and physical properties. 

The EPA also fails to recognize and acknowledge that significant pilot testing has been 

conducted at several power plants in Texas that fire lignite supplied from various locations in 

Texas, and that there are no cyclone-fired boilers in Texas. The EPA has gone down the same 

path that tried to compare German SCR applications which lack significant cyclone boiler 

experience and is not currently required for lignite-fired boilers to be appropriate and comparable 

to North Dakota lignite-fired cyclone burner units. These are misleading statements and contrary 

to the presentation of the body of information submitted in support of the NDDH’s preliminary 

BACT determination for MRYS. 

SCR Catalyst Erosion and Cleaning 

Various means of resolving catalyst erosion have been previously discussed in earlier comments 

and responses (Minnkota, 2007A and 2007B). While hardened leading catalyst surfaces may be 

resistant to erosion from entrained flyash, the more important issues to consider are effectiveness 

and damage from on-line catalyst cleaning methods. Hans Hartenstein (2008) does not address 

this issue in his comments. 

Effective on-line cleaning of catalyst deposits seen in the Coyote pilot testing, especially with the 

micropores plugged with sodium-sulfur compounds, does not appear to be achievable. 
Responses to Comments 37 September 22, 2008

No examples of on-line cleaning methods nor catalyst that would prove resistant to damage from 

such methods that would be effective in removing surface blinding and pore plugging deposits 

such as those seen in the Coyote pilot test catalyst even with the suggested edge erosion 

prevention measures in place have been identified. It is difficult to compare current experience 

with lower fouling coals with a hypothetical installation on a cyclone boiler firing North Dakota 

lignite, without having pilot or full-scale testing experience on the subject fuel to expected 

surface blinding and pore plugging deposits and cleaning operation conditions. 

Hartenstein implies, on page A-36 of his report, that catalyst that has been poisoned by sodium 

compounds can be regenerated in-situ, and that this technique is well developed. ENBW in 

Germany developed this technique, but it has never had a commercial success. Regarding the 

contention of Hartenstein, there is extremely limited experience with in-situ catalyst cleaning on 

coal-fired units. It also has never been used for blinded or chemically poisoned catalyst, but only 

for mechanically plugged catalyst (see Appendix A). 

Pilot Testing for SCR Catalyst 

In many cases where SCR technology has been applied to fossil fuel-fired boilers located 

throughout the world burning a variety of coals and solid petroleum byproducts, extensive pilot 

testing programs have been performed prior to the implementation on full-scale utility boilers: 

Germany in the 1980’s, the United States in the 1980’s for low sulfur and high coals, and in 

Texas since year 2000 on Texas lignite. The application of SCR technology to coal-fired boiler 

in Germany has been almost exclusively on non-lignite fired units. Both in Germany and in the 

United States, it has been demonstrated that it is very difficult to solely rely on SCR catalyst 

suppliers’ experience with similar coals and pulverized coal-fired boilers when developing SCR 

system designs and understanding process issues that are important to the successful deployment, 

operation, and maintenance of such emissions reduction technology in strict compliance with 

regulatory and subsequent permit requirements. 

Many pilot test programs have been conducted to implement SCR technology when new and 

unknown process issues have been raised. There have been multiple pilot tests and research and 

development programs involving application of SCR technology to fossil fuel-fired utility boilers 
Responses to Comments 38 September 22, 2008

in Germany. Several are described in Appendix A by Burns & McDonnell’s SCR technology 

consultant assisting in these responses, who participated in them. 

These described pilot SCR test programs include a high dust SCR on a wet bottom boiler before 

the first high dust SCRs were built in Germany, and a TESCR application. The first tests 

determined that the catalyst deactivated rapidly, which contradicted what the catalyst suppliers 

believed, which was that such testing was unnecessary. The HDSCR pilot test revealed the fact 

that arsenic was unknown as a strong catalyst poison. Most of the German utilities decided not 

to retrofit wet bottom boilers that had fly ash recirculation with a HDSCR so that arsenic 

poisoning could be avoided (see Appendix A). 

Utilities built tail-end SCRs in Germany that included a wet scrubber ahead of the reactor to 

avoid the arsenic poisoning problems with the catalyst. Again, pilot testing led to the discovery 

of a new catalyst poison (SiF4) which caused the first catalyst layer to lose more than 50 % 

activity in less than 2,000 hours. This demonstrates that SCR catalysts can be severely 

deactivated even when boilers burn coals with a SCR configuration that were not expected to 

cause such problems (see Appendix A). 

A recent pilot SCR test program in the Southeast United States involving eastern bituminous 

coal, Venezuelan coal and pet coke at a utility boiler was performed to account for the influences 

of the fuel on the NOx activity and SO2 oxidation rates of the catalyst. With limited worldwide 

experience on such a range of fuels, the Utility decided to conduct an extensive pilot program to 

assess impacts on the catalyst (see Appendix A). Following completion of the pilot testing, the 

catalyst vendors found it necessary to significantly modify and/or completely withdraw the 

guarantees they had offered prior to the testing. 

Mr. Hartenstein and his co-authors support pilot programs for those SCR applications in which 

new and uncertain process considerations are encountered. In the referenced technical paper 

(Hartenstein, 1999), Mr. Hartenstein states: “In principle, the reduction of NOx emissions with 

SCR catalysts is a mature technology, which was developed many years ago. Nevertheless, 

experience has shown that in many applications, special features were required that necessitate 
Responses to Comments 39 September 22, 2008

further optimization of the DeNOx system. In particular, standard solutions were often not 

possible or optimal when retrofitting existing power plants.”

In the case of Milton R Young, the uncertainty associated with the high sodium concentration 

and the presence of sodium aerosols in the flue gas raise serious concerns pertaining to catalyst 

performance. The potential application of any SCR technology at Milton R. Young suggested by 

the EPA and Mr. Hartenstein is not standard, and is very unique, due to the special 

considerations pertaining to the lignite, boiler operating temperatures, flue gas reheating, among 

others. Pilot testing is certainly warranted before any claims that this technology is feasible at 

M.R. Yong Station can be confirmed. The pilot testing must utilize new concepts and designs 

that alleviate the problems associated with alkali aerosols. These new concepts and designs do 

not appear to be currently available from the vendors. 

We disagree with catalyst vendors and Mr. Hartenstein that pilot testing is not required for 

HDSCR, LDSCR, or TESCR prior to application to the boilers at MRYS. They have not cited 

any substantiated data that show successful SCR experience from coal-fired boilers with similar 

boiler- and fuel-specific conditions as present on North Dakota lignite-fired cyclone boilers that 

make this technology infeasible at Young station. The lack of evidence shown to prove that such 

factors have been solved such that any form of SCR technology would not require extensive pilot 

testing and design development for these applications is significant and important in supporting 

the NDDH’s arguments against adopting SCR technology as BACT for MRYS boilers. 

As we have stated previously, the application of emission reduction technology that requires 

such extensive pilot testing and design development should not be considered as available and 

technically feasible for the purposes of a BACT determination (U.S. EPA, 1990). 

Vendor Guarantees for TESCR 

Burns & McDonnell’s consultant (Tackticks LLC) has significant experience in dealing with 

SCR system suppliers and catalyst vendors involving their initial willingness to offer guarantees 

and what they will actually agree to sign in the form of a contract. Mr. Hartenstein (2008) 
Responses to Comments 40 September 22, 2008

frequently states that various catalyst and SCR system vendors would be willing to offer 

performance guarantees for the Milton R. Young Station TESCR. 

Examples of cases where SCR vendors have initially said they would guarantee performance 

without hesitation then subsequently changed their offer or settled a claim by the utility for 

failure to meet guarantees are described in Appendix A. 

It is typical for vendors to do this in the absence of a detailed technical specification and contract 

with commercial conditions and liquidated damages. Actual performance guarantees that the 

SCR vendor intends to agree with for the purpose of a entering a binding contract will only be 

offered once all technical issues and challenges have been identified and addressed in the system 

specification. The vendors will not present performance guarantees for negotiation without 

having assessed their risk mitigation strategy. As the cost of potentially having to provide one or 

several levels of replacement catalyst in order to make it through the guarantee and warranty 

periods is significantly less than 10 percent of the total installed cost for a typical coal-fired SCR 

project, and the total liquidated damages should such replacement be required prematurely are 

only a fraction of the utility’s potential actual and consequential damages, the supplier’s financial 

exposure is decidedly much less than the buyer’s (utility) should such failure to meet guarantees 

and warranties occur. 

Temperature Variations for HDSCR 

Hans Hartenstein’s comments agree with the NDDH’s position that such large boiler flue gas 

exit temperature variations, as shown in Minnkota’s April 2007 response letter (Minnkota, 

2007B), would not be tolerable for a high dust SCR at MRYS. Mr. Hartenstein (2008) went 

further to state this would not be tolerable for any HDSCR installed after any type of firing 

system burning any type of fuel. The ability to successfully control SCR reactor inlet 

temperatures in a high-dust SCR application at MRYS without impairing lignite pre-drying has 

not been confirmed. 

The EPA’s, Plains Justice’s, and Hans Hartenstein’s comments (2008) all assume that the SCR 

catalyst system suppliers (boiler original equipment manufacturers) will solve the stated 
Responses to Comments 41 September 22, 2008

temperature problems. None of the catalyst vendors queried offered to guarantee their catalyst’s 

performance with the current situation of too low and excessively high operating temperatures on 

these boilers under various operating conditions. The SCR system suppliers queried did not 

offer any examples of successful application of proven solutions to the conditions existing at 

MRYS (B&McD and EERC, 2008). It is speculative and would be inappropriate to assume 

these challenges have been or will be solved or to expect meaningful responses from vendors 

knowing the nature of the conditions involved have not been resolved. 

Mr. Hartenstein states, on page A-9 of the referenced opinion report (2008), that no flue gas reheating is typically required for HDSCR (and LDSCR). This is incorrect. The majority of coalfired boilers with HDSCR technology cannot maintain minimum operating temperature over the 

entire load range, therefore reheating with economizer bypass, split economizer or 

supplementary heat input from duct burners is necessary (see Appendix A). Because of the 

unique arrangement of economizers in the flue gas ductwork from Minnkota’s boilers, and lack 

of a natural gas pipeline serving the plant, this has already been dismissed in previous responses 

to the EPA’s comments (Minnkota, 2007A, 2007B, 2007C, 2008). 

Burns & McDonnell’s SCR Experience 

The NDDH’s Preliminary NOx BACT Determination included a statement attesting to the 

“extensive experience with the design and operation of SCR systems” of Burns & McDonnell, 

which was refuted by the DOJ’s commenter (Hartenstein 2008). A brief summary of Burns & 

McDonnell’s size, years in business as an engineering firm and both general and specific areas of 

experience and technical expertise, particularly in regards to utility powerplant boiler NOx 

emissions control was presented to the NDDH and EPA in May, 2007 (B&McD and EERC, 2007). 

The issue of experience with SCR systems in this response is a question of relevance. It will be 

helpful to first discuss what typical phases a project may go through from start to completion. 

These are: 

• Preliminary study and investigation 

• Conceptual Design 
Responses to Comments 42 September 22, 2008

• Detailed design 

• Procurement 

• Fabrication and delivery 

• Construction 

• Commissioning 

• Startup and tuning 

Project execution involves all phases listed above and, depending on the project and the 

contracting strategy; the architectural and engineering (A&E) firm’s role may involve all of the 

above or selected portions of the listed phases while remaining portions are delegated to other 

entities such as technology suppliers, system vendors, or the owner. 

Is Burns & McDonnell’s SCR Experience even a relevant factor at this stage of the project? 

Burns & McDonnell’s role in this project has been to perform the BACT analysis, not to design 

two SCR systems for Units 1 and 2 at Milton R. Young Station. Our experience on performing 

BACT for utility powerplant units located in the United States is relevant and extensive. Some 

engineering firms only work on the environmental permitting and study aspects of pollution 

control and emissions reduction projects while others focus more on the implementation and 

construction. Burns & McDonnell has successfully worked in both areas and continues to 

provide these services to our clients. Mr. Hartenstein seems confused as to the role of an 

engineering firm and from that lack of understanding has made some irrelevant commentary. 

What constitutes “SCR Experience”? 

Relevant experience in various aspects of a project and specifically a retrofit air pollution control 

project has to be considered. Burns & McDonnell’s role in an air pollution control retrofit 

project does not typically include the “process design” portion but there are many aspects of 

retrofit projects that are not specific to just an SCR retrofit project. For example, our structural 

engineers that are experienced at ductwork arrangement, detailed design of hot flue gas ducts, 

foundation design, structural steel design, consideration for wind, snow, seismic as well as 

component thermal expansion and movements all contribute to the project. None of those 

aspects are specific to SCR process design but all are relevant for SCR system design and Burns 
Responses to Comments 43 September 22, 2008

& McDonnell has successfully provided these engineering and design efforts on many projects 

including SCR retrofit projects. 

The specific issue discussed in the EPA’s comment document on NDDH’s Preliminary BACT 

Determination (NDDH, 2008) is in regard to SCR process design and catalyst design. In this 

type of retrofit emissions control project, Burns & McDonnell’s role is to serve the Owner’s 

needs and gather the data, resources, and expertise needed to execute the project. Burns & 

McDonnell would develop and specify the operating conditions, fuel, and flue gas parameters 

and values that form a basis of design which the catalyst supplier relies on, along with their 

expertise and proprietary knowledge of their products, to offer a proposed catalyst type, pitch 

and volume required to meet certain performance guarantees and warranty requirements. The 

catalyst supplier is in the best position to determine how they propose to meet the specified 

performance responsibility, understand how that offer fits their business’ commercial/financial 

impact, and whether this may impair or enhance the long term supply of their product. 

It is within Burns & McDonnell’s ability to assess the relevance of the various catalyst suppliers’ 

offers, their experience, and their level of understanding of the site, the project, the fuel and other 

system concerns in order to advise the owner as to which vendors are deemed qualified for 

bidding and executing the pertinent portions of an SCR retrofit project. Many utility owners are 

not comfortable with performing such technology and vendor assessments alone, nor do they 

maintain the in-house resources that have expertise to do such tasks to a level that significantly 

reduces their risk of selecting a vendor to provide a product that ultimately does not meet their 

requirements nor satisfy their expectations. 

As has been pointed out in NDDH’s Preliminary BACT Determination (NDDH, 2008) and other 

supporting documents (Minnkota, 2007A, 2007B, 2007C, 2008; B&McD and EERC, 2007 and 

2008; Appendix A), significant concerns exist about the unique characteristics of the fuel burned, 

type of firing, and flue gas and ash constituents and their influence on the viability of SCR 

application on these units. We recognize this site-specific situation falls outside the current 

knowledge and experience base of the potential catalyst suppliers. Additionally, some of the 

significant concerns on this project have nothing to do with what the catalyst supplier can 
Responses to Comments 44 September 22, 2008

address, such as the boiler exit temperature. This concern and ways to address it are rightly 

placed in the boiler design firm’s realm of expertise. Burns & McDonnell’s role in this phase of 

the project is to gather, manage, and assess the technical information and advise the owner based 

on what these entities claim and what has been done elsewhere as well as to investigate publiclyavailable technical data that is relevant. 

Burns & McDonnell’s SCR Experience can be categorized in four distinct areas: 

• Preliminary studies 

• Conceptual designs and cost estimates 

• Engineering management of project implementation 

• Detailed design engineering duties 

Each of these roles serves an important function during the overall project timeline. We can 

elaborate and provide more details on each category of specific experience on various projects. 

This is considered business proprietary information and will only be made available if needed. 

We do not feel this project-specific information is relevant to the current issue raised by the 

Hartenstein (2008), and have not included these details at this time but can if required. A 

summary of the roles and experience is provided below as we feel it will suffice to demonstrate 

our capability and viability for the role we have served thus far on this effort. 

• Preliminary studies 

Burns & McDonnell has performed studies for utility clients for many years. The level of 

detail in what is deemed a preliminary study can be described as typically evaluating various 

alternatives. In a pollution control retrofit study, various compliance scenarios are evaluated 

in a screening analysis where technologies are reviewed with regard to several criteria: 

whether or not the technology is commercially available or under development, the level of 

experience of the technology, what suppliers are qualified, an evaluation of regulatory 

impact, very rough screening level cost estimates of the project, discussion of contracting 

alternatives, and schedule. In some cases when there is uncertainty or a range of alternatives 

and compliance scenarios, where more than one pollutant is involved, and more than one 

unit, possible variable levels of control for each pollutant, a matrix of alternatives and 
Responses to Comments 45 September 22, 2008

potential outcomes is developed to help narrow the focus of the overall strategy. Burns & 

McDonnell has performed many studies as described that have involved a wide range of 

complexity. This experience includes studies for utility clients with multiple unit sites and 

multiple sites covering SO2, NOx, Hg, and particulate emissions along with some current 

work that includes CO2 control as potential regulatory impacts are being assessed. Other 

studies have been specific single unit evaluations of SCR application only that were done to 

provide the owner a relative cost and impact on the utility operation. In summary, Burns & 

McDonnell has performed numerous studies of these types over the past thirty plus years, of 

which SCR technology retrofit was included in nearly every one of them over the past five 

years. 

• Conceptual designs and cost estimates 

Typically after the screening level or preliminary study has been performed, many owners 

need a more definitive and site specific evaluation of the retrofit project for their unit at the 

site. Burns & McDonnell has performed these evaluations for SCR retrofits; particulate 

control retrofits including new pulse jet or reverse air fabric filters; electrostatic precipitator 

projects including rebuilds, upgrades, conversion to fabric filter, and hot side to cold side 

conversions; and various SO2 control alternatives including wet flue gas desulfurization 

(FGD) or semi-dry FGD, including spray dryer scrubbers, and circulating fluidized bed 

(CFB) dry scrubbers. FGD technology studies have included processes based on various 

reagents such as wet lime, wet limestone, ammonia, lime spray drying, and a few of the more 

developmental proprietary processes that are fairly new to the market. Also, we have 

performed evaluations of upgrades to existing particulate and SO2 removal systems where 

upgrade and refurbishment is being evaluated along with new equipment system retrofits to 

look for the best solution comparing capital cost, arrangement, operating costs, outage 

requirements, and construction constraints. The level of detail required or desired by an 

Owner on this type of project can vary. Some of these projects can extend over 12 months in 

duration and can involve 20-30% of the design effort being complete whereas others are less 

detailed and can involve 4-8 months of engineering and evaluation. 
Responses to Comments 46 September 22, 2008

The main point here is that Burns & McDonnell’s experience and expertise is relevant to our 

role in providing BACT Analysis study reports, additional information and responses as 

inputs to the NDDH’s BACT Determination process. It includes retrofit and new utility and 

industrial powerplant air pollution control projects involving SCRs and other technologies, 

and involves individuals who apply process design and operating knowledge, whether they 

exist within Burns & McDonnell or are available through technology suppliers or 

consultants, to the specific conditions involved. To suggest that A/E firms provide no value 

to clients for these projects (Hartenstein, 2008) is personal opinion not based on an informed 

understanding of project roles and responsibilities nor utility owner perspectives. 

Comments by Sargent and Lundy on SCR Experience 

On page A-31 of Mr. Hartenstein’s report, Hartenstein calls into question the SCR experience of 

Sargent and Lundy (S&L). The following response to Mr. Hartenstein’s comments has been 

prepared by Mr. William Depriest of S&L (Depriest, 2008): 

“S&L's involvement in the U.S. Power Industry's SCR program in the late 1990's 

and 2000's as presented to the NDDH in May 2007 represents NOx reduction 

activities associated with the NOx SIP CALL and various projects related to NOx 

non-attainment areas in the U.S. These NOX reduction programs represent the 

vast majority of SCR work in the U.S. during that time frame but it does not 

include any new unit work or any gas fired combined cycle work which we would 

classify in a different category of experience. Specifically, we were involved in 

53 of 113 units in-service or near to in-service at the time of May 2007 to the best 

of our knowledge. Again, it is important to note that these NOx programs 

represent by-far the vast majority of SCRs in progress in the U.S. at that time and 

that S&L was clearly a leader in this area. 

In regard to Mr. Hartenstein's claims to S&L's role on these projects, I have the 

following comments: 
Responses to Comments 47 September 22, 2008

• S&L provided all of the process design on the vast majority of our SCR 

projects. In some cases (6) we "teamed" with another entity with SCR 

expertise and shared in the process design role. 

• S&L specified the process design criteria for the catalyst on all of our projects 

short of the actual formulation chemistry which is typically proprietary to 

the catalyst supplier. 

• S&L has never made claims to either an S&L guarantee position regarding 

catalyst performance or direct operating experience with SCR systems.” 

Comments on Hans Hartenstein’s Qualifications for Expert 

SCR Opinions 

Enclosure 1 of the EPA’s referenced letter (EPA, 2008) included descriptions of relevant work 

experience, and the resume Mr. Hans-Ulrich Hartenstein in Appendix D. Mr. Hartenstein also 

made numerous statements in his comments regarding the NDDH’s Preliminary NOx BACT 

Determination attesting to his considerable technical knowledge and personal experience with 

the design and operation of SCR systems (Hartenstein, 2008). 

According to Burns & McDonnell’s consultant assisting in these responses to Mr. Hartenstein’s 

and the EPA’s comments on SCRs, Hartenstein’s claimed personal experience and technical 

expertise on the design of German SCRs, especially of the tail-end variety, is not what it appears 

to be (see Appendix A). It is difficult to determine the true extent of Mr. Hartenstein’s SCR 

technical experience, but his qualifications state that his direct involvement with SCR technology 

on coal-fired boilers has largely occurred since 1999 in the United States, not in Germany during 

the majority of the mentioned SCR retrofits. Mr. Hartenstein’s involvement with SCR 

technology seems to be mostly business development related. 

As Mr. Hartenstein states himself on page A-6 of the referenced opinion report (2008), he was 

not involved in SCR retrofits for utility boilers until 1993. Experience claimed with waste-toenergy LDSCR systems, which are completely different and not comparable to LDSCR systems 
Responses to Comments 48 September 22, 2008

on fossil fuel fired boilers, does not transfer effectively to the North Dakota lignite cyclone-fired 

units in question. 

Fuel Switching 

While clean fuels may be considered to meet BACT requirements, clean fuels may only be 

considered when the permit applicant proposes to meet BACT using clean fuels. See Pub. Law 

No. 101-549, § 403(d), 104 Stat. at 2631 (1990) (U.S. Senate Report of the Committee on 

Environment and Public Works to Accompany S. 1630 (Dec. 20, 1989) discussing the addition 

of “clean fuels” to the definition of BACT in the 1990 Clean Air Act Amendments).

Fuel switching/blending/cleaning was mentioned in the EPA’s comments (EPA, 2008, Enclosure 

2) but only fuel cleaning was questioned as a potential technique that was not fully considered in 

the NDDH’s analysis. Fuel cleaning has typically been practiced where removal of sulfur, 

typically as inorganic pyrite form (FeS), is performed by simple density separation methods (“air 

jigging” in a classifier separate from or within coal pulverizers which reject the heavier pieces). 

This reduces the amount of sulfur introduced into the furnace and potentially emitted to the 

downstream gas cleaning equipment. 

In Minnkota’s NOx BACT determination case, fuel cleaning would presumably not be 

attempting to remove nitrogen from the fuel, for reduction of the formation into NOX, as this 

would be impractical from a solid fuel. Nitrogen oxides are also created from nitrogen in the 

combustion air being exposed to high temperatures in the cyclone burners. So the issue of fuel 

cleaning is really one of trying to remove elements in the lignite besides nitrogen, for the purpose 

of mitigating other problems associated with those specific elements. Thus, it appears that the 

EPA and Plains Justice are raising this issue in trying to use fuel cleaning as an “enabling 

technique” so that SCR technology could be deployed without resolving the problems associated 

those problem elements. 

Ash is included in the Center lignite supplied from the adjacent mine. Some ash comes from the 

mineral layers that are above and below the lignite seams as a result of the practical inability to 

completely separate the lignite from the burden material during mining. The remainder and 

majority of ash in the lignite is bound within the coal particles. Reducing the amount of bound 
Responses to Comments 49 September 22, 2008

ash in the lignite prior to introduction to the boiler would not be practical with known methods of 

fuel cleaning. 

In cyclone boilers, ash is not normally problematic if it melts within the cyclone burner barrel 

and drains out to become bottom ash. In the case of North Dakota lignite-fired cyclone boilers, 

there is a high amount of ash that is not captured and drained from the cyclones and lower 

furnace as bottom ash. Thus, a higher than typical 70:30 bottom ash: flyash ratio for cyclone 

boilers occurs at MRYS, closer to a 50:50 split. This means that a significant amount of ash is 

released from the burners as flyash, where these particulates escape and become entrained in the 

flue gases rising up through the furnace. 

As previously discussed in earlier responses, it is sodium and potassium-related elements that 

would cause SCR catalyst deactivation. These troublesome elements are mostly in forms where 

they are organically-bound within the coal particles, so simple “air jigging” classification 

methods are believed to be ineffective. 

The arguments for coal cleaning also do not cite specific examples where minerals such as 

sodium and potassium have been removed economically and would not require pilot testing in 

order to demonstrate that the technology is developed sufficiently to be successful for this 

application 

Non-SCR NOx Controls 

Plains Justice implies that because various non-SCR NOX reduction technologies have been 

demonstrated or pilot-tested on any utility boiler, the control technology would be technically 

feasible at MRYS. This ignores the differences in specific conditions at the MRYS boilers 

compared with where the technology has been demonstrated that are pertinent to whether the 

technology is appropriate and could be successful at MRYS. 

Successful implementation of NOX controls is highly dependent on the specific configuration 

and process conditions that lend themselves to be compatible within the limits of 

constructability, survivability, and effectiveness. Just because a control technology is 
Responses to Comments 50 September 22, 2008

“technically feasible” based on Plains Justice’s interpretation of the NSR Manual (U.S. EPA, 

1990) does not mean it will work effectively at MRYS to reduce NOx emissions. Many 

comments by Plains Justice give the impression that they did not review Minnkota’s BACT 

Analysis study reports (B&McD, 2006), or understand the technical reasons why such non-SCR 

NOx control technologies were not evaluated for MRYS. 

An example of this is Plains Justice’s suggestion that injection of a fluxing agent to increase 

melting of solid combustion products will reduce catalyst poisoning due to a reduced amount of 

flyash. Superficially, this sounds plausible, but where fluxing agents have been added to coal for 

reduction of impact on SCR catalyst, it is due to the practice of flyash reinjection or firing of 

bituminous coal with low calcium-to-arsenic ratio. For the cyclone boilers firing North Dakota 

lignite, the fuel and its response to melting is more complex than other coals where the use of 

fluxing agents has been demonstrated as described. These cyclone boilers are designed 

specifically to melt the fuel ash in the cyclone burners as part of the combustion process. Flyash 

reinjection is not practiced, and arsenic is not significant in North Dakota lignite-fired cyclone 

boilers; however, sodium is a known catalyst poison and is present in abundance in ND lignite. 

The problem with Plains Justice’s argument is that the use of the fluxing agent mentioned would 

not prevent melting of sodium compounds which creates a fine fume that does not get captured 

in the molten slag. Sodium, in fact, is preferentially released from the slag that forms in the 

cyclone burners and lower furnace and is then exhausted where it is available to react with sulfur 

and calcium to foul and deactivate SCR catalysts. This is the main source of sodium that ends up 

in the boiler’s exhausted flue gas instead of remaining in the slag. This has been explained in 

numerous ways by EERC in previous responses to EPA comments (Minnkota, 2007A, 2007B, 

2007C, 2008; B&McD and EERC, 2007 and 2008). 

Most of the “commercially available solutions” to facilitate the use of SCR that Plains Justice 

lists involve coal cleaning and drying or beneficiation. MRYS already has cyclone lignite drying 

systems, which are required for preparing the fuel for proper combustion in the cyclone burners. 

The arguments for coal cleaning also do not cite specific examples where minerals such as 

sodium and potassium have been removed economically and would not require pilot testing in 
Responses to Comments 51 September 22, 2008

order to demonstrate that the technology is developed sufficiently to be successful for this 

application. 

Minnkota’s BACT Analysis reports and previous responses to EPA comments (Minnkota, 

2007A, 2007B, 2007C, 2008; B&McD, 2006; B&McD and EERC, 2007 and 2008) have 

explained that other non-SCR technologies, such as various forms of enhanced selective noncatalytic reduction (SNCR) with natural gas or coal reburn, low NOx burners, and flue gas 

recirculation are not appropriate for the operating conditions experienced inside the boilers at 

MRYS. Plains Justice appears to ignore the arguments previously presented regarding the 

expected limitations of effective NOX reduction at MRYS with modest cyclone air-staged 

combustion compared with lower NOX emissions demonstrated at Ameren’s Sioux plant with 

deeply staged cyclones using lower furnace urea reagent injection. Oxygen-enhanced 

combustion, NOx adsorption from flue gases using activated coke, and various chemical 

treatment processes have not been demonstrated on cyclone boilers or lignite fuels, and thus 

would require extensive pilot or full-scale testing in order to assess their potential performance 

and economics. The interpretation of the NSR Manual (U.S. EPA, 1990) noting that requiring 

extensive pilot or full-scale demonstration of the technology is outside the BACT process 

beyond step 2 has already been presented in previous responses (Arfmann and others, 2007). 

Conclusions 

In the end, EPA’s objections to NDDH’s Preliminary BACT Determination may be reduced to 

disputing NDDH’s characterization of the gas stream characteristics and the impacts of those 

characteristics on boiler and emissions control operations. EPA and Hartenstein suggest that 

these impacts can be resolved by the use of TESCR, and that TESCR technology will work at 

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

significance of these facts: 

• There is no prior experience with full-scale SCR on any unit firing North Dakota lignite. 

• Results from the only known example of simulating SCR catalyst exposure to high-alkali 

containing flue gases produced from firing North Dakota lignite in a cyclone boiler 

showed severe catalyst blinding and plugging due to sodium and potassium rich species 
Responses to Comments 52 September 22, 2008

(Benson, 2005). Coyote pilot-scale SCR test was intended to evaluate the fouling 

potential of SCR on lignite coal results. The Coyote test was developed by a consortium 

of three 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 

team was competent and Minnkota believes this testing was valid for its intended 

purpose. From this sole test, it was determined that there are significant impediments to 

using SCR on MRYS. Peer-reviewed literature written by many authors has verified that 

sodium and potassium species are fatal to the catalyst life. 

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

HDSCR 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 cyclonefired, the fuel burned was much lower in sodium than North Dakota lignite, and the units 

are no longer in operation (see Appendix A). 

• There have never been, to the best of our knowledge, any tail-end SCRs applied to coalfired utility boilers burning lignite, whether in Europe or North America (see Appendix 

A). 

• There have not been, to the best of our knowledge, any TESCRS installed on any coalfired utility boiler anywhere in the world since 1991, when the TESCR on the Siersdorf 

power station in Germany was placed into service. Siersdorf did not burn lignite, did not 

have a Wet FGD system, and has since been decommissioned (see Appendix A). This 

17-year span since the last TESCR installation on a coal-fired utility boiler belies EPA’s 

contention that TESCR has been universally applied and represents BACT for NOx 

control on a North Dakota lignite-fired cyclone boiler. 

• Contrary to statements made by Mr. Hartenstein (2008), there are no currently active or 

planned TESCR installations in the U.S. on coal-fired utility boilers. PSEG Mercer 

Station does not have TESCR configuration (it is LDSCR), and the SCR systems at South 

Oak Creek Station for WE Energies will also be LDSCR, not TESCR as stated by 

Hartenstein. The change in SCR type at South Oak Creek was made due to the technical 

incompatibility of full scrubbing Wet FGD and the type of gas-to-gas heat exchanger 
Responses to Comments 53 September 22, 2008

(GGH) required for TESCR. Neither of these plants burn (or will burn) high-sodium 

lignite (see Appendix A). 
Responses to Comments 54 September 22, 2008

REFERENCES (sorted in alphabetical order) 

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

Appropriateness of Conducting 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.; Laumb, M.L., Ash Behavior in Combustion Systems, Energy Generation 

Conference, Bismarck, ND, 2007. 

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

North Dakota Fly Ash; Prepr. Pap.—Am. Chem. Soc., Div. Fuel Chem. 1983, 28 (2), 213–222. 

Broske, D., Operation and Maintenance Guidelines for Selective Catalytic Reduction Systems, 

1004145, EPRI Final Report, Dec 2003. 

Burns & 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. 

Burns & McDonnell and Energy & Environmental Research Center (EERC), Information 

Request (SCR Vendor Query and Attachments), April 2007. 

Burns & McDonnell and Energy & Environmental Research Center (EERC) presentation, 

Summary of Responses 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 of Air Quality, and United States Environmental Protection Agency, May 23, 

2007. 

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

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

1403–1409. 

Copolo, T.K.; Killen, D.C, Gretta, W.J.; Franklin, H.N.; Mukai, M., Low-Dust SCR System 

Experience for Coal Fired Boilers. Presented at the Electric Power Conference, Mar 4–6, 2003. 

Depreist, W., Personal Communication, September 2008. 

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

Department of Chemical Engineering, Brigham Young University, August 2006. 

Hansen, F. Personal Communication, Feb 2007. 

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

Hartenstein’s Expert Opinion Report Feasibility of SCR Technology for NOx Control 

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

States Department of Justice, July 2008. 
Responses to Comments 55 September 22, 2008

Hartenstein, H-U.; Gutberlet, H.; Licata, A. Utility Experience with SCR in Germany. In 

Proceedings of the 16th Annual International Pittsburgh Coal Conference; Pittsburgh, PA, Oct 

11 – 15, 1999. 

Hartenstein, H-U; Licata, A., The Application of a Low Temperature Selective Catalytic 

Reduction System for Municipal & Hazardous Waste Combustors. In Proceedings of the 17th 

Biennial Waste processing Conference, ASME, 1996. 

Hindiyarti, L.; Frandsen, F.; Livbjerg, H.; Glarborg, P.; Marshall, P., An Exploratory Study of 

Alkali Sulfate Aerosol Formation During Biomass Combustion. Fuel 2008, 87, 1591–1600. 

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. 

Linak, W.P.; Wendt, J.O.L., Trace Metal Transformation Mechanisms During Coal Combustion, 

Fuel, 1994, 39, 173–198. 

Miles, T.R.; Miles, T.R.; Baxter, L.L.; Bryers, R.W.; Jenkins, B.M.; Oden, L.L., Alkali Deposits 

Found in Biomass Power Plants. A Preliminary Investigation of Their 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 of Vendor 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 of Nitrogen Oxides for M.R. Young Station Units 1 and 

2, June 2008, released for public comment June 3, 2008. 

Plains Justice letter by Nicole Shalla to Terry L. O’Clair, Director, Division of Air Quality, 

North Dakota Department of Health, Re: Comments on the Preliminary BACT Determination for 

Control of Nitrogen Oxides for M.R. Young Station Units 1 and 2, July 30, 2008. 
Responses to Comments 56 September 22, 2008

Raask, E. Mineral Impurities in Coal Combustion; Hemisphere Publishing Company: 

Washington, 1985. 

Rosner, D.E. Transport Processes in Chemically Reacting Flow Systems, Butterworths, Boston, 

MA 1986. 

Sarofim, A.F.; Howard, J.B.; Padia, A.S. The Physical Transformation of the Mineral Matter in 

Pulverized Coal under Simulated Combustion Conditions. Combust. Sci. Technol. 1977, 16, 

187–204. 

Strege, J.R.; Zygarlicke, C.J.; Folkedahl, B.C.; SCR Deactivation in a Full-Scale Cofired Utility 

Boiler. Fuel 2008, 87 (7), 1341–1347. 

Tolbert, S.G.; Benson, S.A. JV Task 117 – Impact of Lignite Properties on Powerspan’s NOx 

Oxidation System; Final Report (May 1 – Dec 31, 2007) for U.S. Department of Energy 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 (U.S. EPA or EPA) Region 8 letter by Andrew 

M. Gaydosh, Assistant Regional Administrator, Office of Enforcement, Compliance and 

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

Department of Health, Re: Transmittal of EPA’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). 

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Preliminary BACT Determination.

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Nonattainment Area Permitting, Office of Air Quality Planning and Standards, Research 

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

Ulvog, P.; Wiemuth, B. Impacts of Texas Lignite Coal on SCR Catalyst Life and Performance 

Field Data from TXU’s Martin Lake Plant, 1004732, EPRI Final Report, Dec 2003. 

Zheng, Y.; Jensen, A.D.; Johnsson, J.E. Deactivation of V2O5-WO3-TiO2 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, J.E.; Thøgersen, J.R. Deactivation of V2O5-WO3-TiO2 SCR 

Catalyst at Biomass Fired Power Plants: Elucidation of Mechanisms by Lab- and Pilot-Scale 

Experiments; Applied Catalysis B: Environmental. 2008, 83, 186–194. 
Responses to Comments September 22, 2008

APPENDIX A 

Tackticks, LLC Report 

“Comments to Enclosure 1 Hans Hartenstein’ Expert Opinion Report” 

Tackticks, LLC General Company Information 

Resume for Volker Rummenhohl 

Resume for Robert E. Johnson 

Tackticks LLC SCR Consulting and Process Engineering Reference List, June 2007 
Minnkota 

Milton R. Young Station 

NOx BACT 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion 

Report 

Prepared for 

Burns & McDonnell Engineers 

by: 

Tackticks, LLC 

Volker Rummenhohl, Principal Author 

Robert Johnson 

September, 2008 
- 2 - 

Introduction 

Mr. Volker Rummenhohl, Tackticks, LLC, has prepared the following comments to Mr. 

Hans Hartenstein’s Expert Opinion Report pertaining to the “Feasibility of SCR 

Technology for NOx Control Technology for the Milton R. Young Station, Center, North 

Dakota (July 2008).” 

The following comments address five general topics rather than a point by point rebuttal 

of Mr. Hartenstein’s statements. These five general topics are: Mr. Hartenstein’s 

qualifications, information not reported by Mr. Hartenstein, incorrect information 

presented by Mr. Hartenstein, vendor guarantees and catalyst poisons / pilot tests. 

In general, Mr. Hartenstein mainly reports the opinion of third parties and not his own. In 

some cases where his own opinion is offered, significant materially-related information is 

either missing or the information he presents is incorrect. For instance, he mistakenly 

refers to the SCR systems at PSEG Mercer Station as tail end systems. Mr. Hartenstein 

does not have hands on experience with the design, commissioning, operation or 

maintenance of tail end SCR systems (TESCR) for coal fired boilers. He also does not 

have experience with design or commissioning of Low Dust SCR systems (LDSCR) for 

coal fired boilers. 

In his report, Mr. Hartenstein focuses entirely on the catalyst and ignores problems that 

have occurred with the subsystems of a SCR plant. 

Qualifications 

As Mr. Hartenstein states himself on page A-6 of the referenced opinion report, he was 

not involved with SCR retrofits for utility boilers until 1993. His direct involvement with 

SCR technology on coal-fired boilers has largely occurred since 1999 in the United States, 

not in Germany during the majority of the mentioned SCR retrofits. Mr. Hartenstein’s 

involvement with SCR technology seems to be mostly business development related. 

Experience claimed with waste-to-energy LDSCR systems, which are completely 

different and not comparable to SCR systems on fossil fuel fired boilers, does not transfer 

effectively to the units in question. The size is much smaller and this allows the use of 

different pre heat equipment. All waste-to-energy plants in Europe have either activated 

carbon injection or fixed bed activated carbon plants. Those take out all poisons such as 

all acidic components, arsenic etc. from the flue gas. 

The dead line for the retrofit of SCR systems for fossil fired units was January 1, 1990 in 

Germany. All but one TESCR system was built and commissioned by that date. The last 

TESCR system was installed in 1991 at the 170 MW Siersdorf power station, firing 

bituminous coal, equipped with a dry circulating fluidized bed scrubber and electrostatic 

precipitator with natural gas-fired duct burners ahead of the TESCR reactor. Mr. 

Hartenstein was not involved with that project. The author was responsible for process 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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design and commissioning for the Siersdorf power station’s SCR system constructor. 

This power station has since been decommissioned and dismantled. 

Missing information 

On page A-11, Mr. Hartenstein references the high dust SCR system (HDSCR) that was 

installed in 1990 at the Voitsberg Power Station in Austria. This paragraph concludes 

with the implication that lignite-fired boilers are among the 30,000 MW of SCR systems 

installed in Europe. However, Mr. Hartenstein does not offer the information that more 

than 20,000 MW of lignite fired units in Germany were not required to install SCR in 

order to comply with the national regulation. These units were exempted from the 

regulation despite the fact that they would not achieve the required emission limit of 200 

mg/Nm3

. It should be noted that high dust SCR systems were installed and operated at 

the lignite-fired Bayernwerk Schwandorf plant in Germany. The units fired a Czech 

lignite and were decommissioned in the late 1990s. Voitsberg Unit 3 and the units at the 

Bayernwerk Schwandorf plant in Germany, which were not cyclone-fired, have been the 

only SCRs ever to operate on European lignite, and the fuel they burned was much lower 

in sodium than contained in North Dakota lignite. To the best of my knowledge, there 

have been no TESCRs built nor are any currently operating anywhere in the world on 

lignite-fired utility boilers. 

Mr. Hartenstein also did not state in his report that Germany had only one cyclone-fired 

(slag tap) unit with a SCR system. This unit is Walsum 7, the NOx emissions control 

system is a LDSCR, and the unit does not burn lignite. 

Mr. Hartenstein also did not explain that the Voitsberg lignite-fired dry-bottom 

pulverized coal unit operated only for a very short period of time with high dust SCR, 

before the boiler was taken out of business and decommissioned. The power station does 

not exist any longer. 

Mr. Hartenstein also fails to explain that on utility boilers you cannot send saturated gas 

from the scrubber to the gas-gas heat exchange (GGH) for the TESCR. The gypsum in 

the flue gas will deposit on the SCR GGH surface and lead to a fast pressure drop 

increase. It is extremely difficult or impossible to clean this during an outage. The FGD 

GGHs are frequently washed with liquid water during operation, which keeps them clean. 

Mr. Hartenstein, on page A-10 of his report, displays a diagram purporting to be the 

configuration of a TESCR downstream of a wet FGD system. What he fails to explain is 

that there is no TESCR on any utility boiler anywhere in the world that uses this 

configuration successfully downstream of a wet FGD. For the reasons noted above, the 

GGH of the TESCR cannot accept the flue gas immediately from the FGD without reheat. 

This diagram offered by Mr. Hartenstein represents an infeasible configuration. 

Mr. Hartenstein reports on page A-50 regarding the “We Energies South Otter (sic) Creek 

Generating Station” and implies that this SCR project proves the viability of TESCR. He 

fails to explain that for this project, which is located at the South Oak Creek plant, 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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Alstom and Howden, which are the main GGH suppliers for the SCR market, both 

required that the flue gas be free of moisture droplets and preheated to allow the use of 

TESCR. Otherwise they would not offer performance guarantees. This particular project 

has now changed the SCR system to a LDSCR due, in part, to issues related to the GGH. 

In the German TESCR installations, a rotary GGH could be used because the required 

FGD removal efficiency was about 80% , and the flue gas leaving the FGD could be 

reheated with bypass or by other means prior to entering the GGH for the TESCR. This 

is confirmed by the data shown in the boiler process flow diagram from an operating 

utility boiler plant shown by Mr. Hartenstein on page A-49 of his report. It is clearly 

seen that the flue gas temperature entering the GGH for the TESCR is 87 °C, or more 

than 30 degrees C above the saturated flue gas temperature at the FGD absorber outlet 

(typically 55 °C). Obviously, although not shown on his diagram, the flue gas at this 

plant has been reheated prior to the inlet to the TESCR GGH. The FGD systems in 

Germany typically use an “FGD GGH” to accomplish this reheat. However, leakage 

across the FGD GGH makes a rotary GGH infeasible for TESCR systems following high 

SO2 removal efficiency FGD systems, as required in the U.S. 

Mr. Hartenstein references several times the “ill-designed” pilot test plant that was 

conducted at the Coyote Station. However, he does not offer a single reason why the 

pilot plant was “ill-designed”. 

Incorrect Information 

Mr. Hartenstein states, on page A-9, that no flue gas re-heating is typically required for 

HDSCR and LDSCR. This is incorrect. The majority of the units cannot maintain 

minimum operating temperature over the entire load range, therefore reheating with 

economizer bypass, split economizer or duct burners is necessary. Vectren installed duct 

burners on four units. 

Denmark and the Netherlands did not have SCR by the end of the 80s, as stated by Mr. 

Hartenstein on page A-11. 

While rotary, tubular and plate type heat exchangers have been used for re-heating flue 

gas, as noted by Mr. Hartenstein on page A-12, not a single coal fired unit with a LDSCR 

or TESCR system has a heat exchanger other than rotary. As discussed above, this poses 

a problem with fouling and leakage when located directly downstream of a wet scrubber 

without reheat. 

Mr. Hartenstein states on page A-12 for turbine limited units: “In this case, the heat rate 

penalty of the unit may be eliminated completely”. This is complete nonsense. There 

will still be a penalty since more heat input is necessary for the same electrical output. 

Mr. Hartenstein states on page A-13 that it can reasonably be assumed that the retrofit 

cost today would be the same as stated in an EPRI report from 1989. The cost for rotary 

heat exchangers for LDSCR and TESCR are much higher today. 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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Further, Mr. Hartenstein states on the same page that TESCR technology was “generally 

adopted as a universally applicable SCR solution for all types...” There has never been 

another TESCR built after Siersdorf, which was finished in early 1991, in the US or 

Europe. 

The following is an excerpt from page A-19 of Mr. Hartenstein’s report concerning 

minimum operating temperature: 

“As a matter of fact, the only thing that dictates the minimum SCR operating temperature 

are the residual SO2 and SO3 concentrations in the flue gas, which determine the ABS 

reaction equilibrium and thus the probability for ABS deposition on the catalyst and in 

the gas/gas heat exchanger. This, however, is not an irreversible catalyst poisoning issue 

but rather a reversible fouling problem not related to the SCR catalyst per se but simply 

to the reaction chemistry between H2O, SO3 and NH3 in the flue gas at various 

temperatures.” 

It is factually incorrect that the temperature depends only on the SO2 and SO3

concentration of the flue gas. It is independent of the SO2 concentration. Minimum 

operating temperature depends primarily on the SO3, ammonia and moisture 

concentrations in the flue gas. Catalyst fouling is only reversible if no calcium has 

reacted with the ammonium bisulfate. Once that has happened it becomes irreversible. 

On page A-19, Mr. Hartenstein states: 

“The reaction equilibrium between ammonium sulfate ((NH4)2SO4) and ammonium 

hydrogen sulfate (NH4HSO4), which is often incorrectly referred to as ammonium 

bisulfate or ABS, in the flue gas. Both ammonium sulfate and ammonium hydrogen 

sulfate are products of the inevitable reaction of gaseous sulfur trioxide (SO3) and 

ammonia (NH3) contained in the flue gas upstream of the SCR catalyst.” 

Ammonium hydrogen sulfate is a different name for ammonium bisulfate. 

Mr. Hartenstein discusses, on page A-22, “Ceram’s extensive experience with lignite..” 

With only one plant with CERAM catalyst having operated for a short period of time on 

lignite and a few pilot programs, it is impossible to say that CERAM has extensive 

experience on lignite fired plants. 

Mr. Hartenstein devotes an entire section to soluble sodium (Section 6.3, page A-27). He 

notes in the second paragraph a statement from one of the catalyst suppliers that sodium 

is not a catalyst poison at SCR operating temperatures. 

Yet, on page 5 of the technical paper, “Utility Experience with SCR in Germany,” 

presented at the Sixteenth Annual International Pittsburgh Coal Conference in October, 

1999, Mr. Hartenstein and his co-authors reported SCR catalyst deactivation due to 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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sodium at the RWE Staudinger plant in Germany. Specifically, it is reported on page 5 

that “...the fly ash from the German coal formed highly adhesive deposits, while the 

portion of South African coal contributed to the formation of a liquefied fly ash. 

The reason for this was determined by a chemical analysis of the fly ash. It can be seen 

that the content of the alkali sulfate, which adheres to the surface of the fly ash particles, 

favors the tendency to agglomerate. A phase analysis of the deposits revealed crystalline 

sodium aluminum sulfate and potassium aluminum sulfate (NaAl(SO4)2;KAl(SO4)2).” 

This information would tend to support the Department’s opinion related to the formation 

of sodium–related deposits on the SCR catalyst and accelerate the deactivation of the 

catalysts. This information would also tend to conflict with Mr. Hartenstein’s statement, 

on page A-28 of his expert report, that the “...the intrusion of liquid pyrosulfates is no 

major concern with respect to a severe, rapid catalyst deactivation.” 

Mr. Hartenstein states on page A-29: 

“...of less than seventy two (72) hours, SCR reactors are typically “buttoned up hot,” 

which means the SCR reactor is isolated from the flue gas path during shut down by 

means of putting it in a bypass mode while the SCR is still at its design operating 

temperature. The cooling rate of such a “buttoned up hot” SCR reactor is known to be 

extremely slow. Unless forced cooled with ambient air no “buttoned up hot” SCR 

reactor loses more than approximately 50-100 degrees and therefore gets nowhere near 

the sulfuric acid or even the moisture condensation temperature in a seventy two (72) 

hour period.” 

This is a statement, which is incorrect and must be based on the lack of practical 

experience. I have been involved in several measurements of cool down rates for SCR 

units. The rate differs in a range between five and ten degree Fahrenheit per hour 

depending on the quality of the dampers and the insulation, the unit size, catalyst volume 

installed and the ambient conditions. It must also be considered that the boiler is 

operated at low loads before during the shut down phase. This means the starting 

temperature is already very low. Almost all units are below the acid dew point after 72 

hours and most of them at the water dew point. 

Mr. Hartenstein takes exception to the Department’s statement on page A-29, as 

excerpted below: 

“The Department concludes that “the flue gas generated at M.R. Young Station is 

different from the flue at any plant where SCR technology has been applied.” The 

absoluteness of this statement, which is not even limited to power plans, is quite amazing 

as it indubitably implies that the Department has complete detailed knowledge not only of 

the flue gas composition of every other power plant in the world equipped with an SCR 

system but also of every other plant in the world where the SCR technology is applied. 

Even though theoretically possible, the lack of any data from all these other plants 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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strongly suggests that this may be highly questionable and largely overreaching. As a 

matter of fact, I am sure that I could easily present to the Department several plants 

where the SCR technology has been applied successfully that the Department doesn’t 

even know that these plants existed.” 

The statement of the Department can be easily supported since there is not a single SCR 

system in operation on a lignite fired boiler in the United States, nor in Europe, at this 

time. 

The statements on pages A-31 and A-32 that Burns & McDonnell never has given a 

guarantee and never provided process design are incorrect. 

On page A-32, Mr. Hartenstein states: 

“As a matter of fact, all catalyst related performance guarantees (NOx removal 

efficiency or activity, SO2/SO3 conversion rate, catalyst life or deactivation rate, etc.) are 

never provided by anyone other than the catalyst manufacturers. Even the SCR 

equipment suppliers only pass through the catalyst performance guarantees obtained 

from the catalyst manufacturers to the end customer. And at least two (2) of these 

catalyst manufacturers, namely Haldor Topsoe and CERAM were clearly willing to 

provide industry standard type performance guarantees for their catalyst.” 

This statement can only be explained by a lack of involvement in the design of SCR 

plants. Catalyst performance guarantees are not always a pass through from the system 

supplier. Depending on the contract, there are a lot of other issues that are not done by 

the catalyst supplier. Distributions, pop-corn ash screens, control system, and analyzer 

system all impact the performance of the SCR catalyst but may not be guaranteed by the 

catalyst supplier. These are typically warranted by the system supplier. 

On page A-39, Mr. Hartenstein states: 

“Yet, the most successful SCR retrofits in the U.S. were done as turn-key installations 

without the use of an A/E.” 

There are certainly many examples of successful SCR projects which were executed on 

different contractual conditions. 

Mr. Hartenstein states on page A-50 that the SCR systems at PSE&G Mercer Generating 

Station are TESCR. This is incorrect. Both SCR systems at this plant are LDSCR with 

flue gas re-heating. Mr. Hartenstein also states that the SCR systems at WE Energy 

South Oak Creek Station will be TESCR. This is also incorrect. South Oak Creek started 

out as TESCR, but technical difficulties have forced the change to a LDSCR. 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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Vendor Guarantees 

Mr. Hartenstein frequently states that various catalyst and SCR system vendors would be 

willing to offer performance guarantees for the Milton R. Young Station SCR. It is 

typical for vendors to do this in the absence of a detailed specification and contract with 

commercial conditions and liquidated damages. Performance guarantees will only be 

offered once all technical issues and challenges have been identified and addressed in the 

system specification. The vendors will not present performance guarantees for 

negotiation without having assessed their risk mitigation strategy. 

A recent example of this occurred on the retrofit of SCR systems on two units in Florida. 

Three catalyst vendors provided totally different sets of preliminary guarantees at the 

beginning of the project. All three suppliers changed their guarantees after a 2,000 hour 

pilot test significantly identified the effects of various fuels on the expected performance 

of the catalyst. 

Another example occurred several years ago on three SCR units in Pennsylvania. Two 

catalyst suppliers (Haldor Topsoe and CERAM) provided guarantees based on their 

experience with similar coals, but were very surprised about the rapid deactivation of the 

catalyst. These companies are those most cited in Mr. Hartenstein’s paper. The money 

the utility received in a settlement with the turn key supplier was a very small fraction of 

the long term operating costs absorbed by the Utility to maintain SCR system operation. 

Catalyst Poisons and Pilot Projects 

In many cases where SCR technology has been applied to fossil fuel-fired boilers located 

throughout the world burning a variety of coals and solid petroleum byproducts, 

extensive pilot testing programs have been performed prior to implementation on fullscale power plants: Germany in the 1980’s, United States in 1980’s, and in Texas since 

year 2002. 

There are two pilot tests and one R&D program in which the author was involved with in 

Germany. The results of these programs emphasize the importance of understanding 

design and process issues for certain applications. These also demonstrated that it is very 

difficult to solely rely on experience with similar coals and boilers. 

The first was a pilot program for a high dust SCR on a wet bottom boiler at the Franken 

power station in Germany. This was before the first HDSCRs were built in Germany. 

All catalyst suppliers said that it would be unnecessary to conduct a test program, since 

these companies had sufficient experience basis from the units in Japan. It turned out that 

the catalyst deactivated rapidly. Some catalyst types lost almost all of their activity in 

just 200 hours. At this time, arsenic was not known to be an issue for the catalyst 

because it had not been observed in the Japanese SCR systems. The pilot test revealed 

the fact that arsenic is a heavy catalyst poison. Most of the utilities decided not to retrofit 

wet bottom boilers that had fly ash recirculation with a HDSCR so that arsenic poisoning 

could be avoided. 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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The second pilot program was in the Reuter power station in Berlin. The author was 

involved in a pilot plant that included a wet scrubber and a TESCR. The result was that it 

is impossible to have saturated flue gas going to the GGH of the TESCR without drying 

and pre heating it. The gypsum in the flue gas plugged the TESCR GGH with no means 

to clean it. The temperatures are too high to clean it with liquid water as it is frequently 

done on the FGD GGHs. 

Utilities built TESCRs in Germany to avoid the arsenic problems. Everybody thought 

that an indefinite catalyst lifetime could be expected. It was even more surprising to see 

that the first layer on which activity was measured lost more than 50 % activity in less 

than 2,000 hours. Again, a new catalyst poison was detected. It was SiF4, a gaseous 

component which forms on the plates of the FGD rotary heat exchanger in a reaction of 

SiO2, H2SO4 and HF. It was an R&D project of several million dollars to detect the 

poison, the formation mechanism and the solution. Lime was injected upstream of the 

FGD, which bound the sulfuric acid on the GGH plates. The capital cost of the lime 

system is certainly not included in the EPRI cost reports referenced by Mr. Hartenstein. 

See: 

German Experience Sheds Light on SCR O&M Issues, September 1992 issue of Power

magazine, Coauthor. (attached). 

The author also participated in a more recent pilot test program for a Southeast U.S. 

Utility. At this particular plant, a proposed SCR system had to be designed for three very 

different fuels: Eastern bituminous, Venezuelan coal and pet coke. Due to very stringent 

permit conditions related to NOx, NH3 and SO3 emissions, the SCR system and catalyst 

had to account for the influences of the fuel on the NOx activity and SO2 oxidation rates 

of the catalyst. With limited worldwide experience on such a range of fuels, the Utility 

decided to conduct an extensive pilot program to assess impacts on the catalyst. All three 

suppliers changed their guarantees after a 2,000 hour pilot test identified significant 

effects of the various fuels on the expected performance of the catalyst. This SCR is not 

yet operational. 

The EPA also fails to recognize and acknowledge that significant pilot testing has been 

conducted at two power plants in Texas that fire lignite supplied from various locations in 

Texas, and that there are no cyclone-fired boilers in Texas. The EPA has gone down the 

same path that tried to compare German SCR applications, which lack significant cyclone 

boiler experience and is not currently required for lignite-fired boilers, to be appropriate 

and comparable to North Dakota lignite-fired cyclone burner units. These are misleading 

statements and contrary to the presentation of the body of information submitted in 

support of the NDDH’s preliminary BACT determination for MRYS. 

These examples emphasize the importance of understanding the intricate process design 

issues that will influence SCR performance. The industry has benefitted from the many 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 
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pilot test programs that have been conducted to implement SCR technology when new 

and unknown process issues have been raised. In the case of Milton R Young, the 

uncertainty associated with the high sodium concentration and the presence of sodium 

aerosols in the flue gas raise questions pertaining to catalyst performance. Pilot testing is 

certainly warranted. 

Mr. Hartenstein and his co-authors support pilot programs for those SCR applications in 

which new and uncertain process considerations are encountered. On page 2 of the 

technical paper, “Utility Experience with SCR in Germany,” presented at the Sixteenth 

Annual International Pittsburgh Coal Conference in October, 1999, Mr. Hartenstein 

states: “In principle, the reduction of NOx emissions with SCR catalysts is a mature 

technology, which was developed many years ago. Nevertheless, experience has shown 

that in many applications, special features were required that necessitate further 

optimization of the DeNOx system. In particular, standard solutions were often not 

possible or optimal when retrofitting existing power plants.”

Mr. Hartenstein implies, on page A-36 of his report, that catalyst that has been poisoned 

by sodium compounds can be regenerated in-situ, and that this technique is well 

developed. Regarding the contention of Hartenstein, there is extremely limited 

experience with in-situ catalyst cleaning on coal-fired units. ENBW in Germany 

developed this technique, but it has never had a commercial success. It also has never 

been used for blinded or chemically poisoned catalyst, but only for mechanically plugged 

catalyst. 

The possible application of any SCR technology at Milton R. Young is not standard, due 

to the special considerations pertaining to the lignite, boiler operating temperatures, flue 

gas reheating, among others. 

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report 

Prepared by Tackticks, LLC (September 2008)

 


1

 

 
2

General Company Information: 

Principal Company Address: 

Tackticks, LLC 

247 Booth Meadow Lane 

Durham, NC 27713 

Phone #: 919 – 484 – 1500

Fax#: 919 – 484 – 1544

President: Volker Rummenhohl 

vrummenhohl@tackticks.com

Regional: Robert E. Johnson 

rjohnson@tackticks.com

913 – 897 – 0727 
3

Tackticks, LLC 

1.1 General Company Description 

Tackticks, LLC has a broad range of engineering experience with SCR systems 

and related power plant operations. Tackticks, LLC was formed in 2001 by Volker 

Rummenhohl after working within the SCR industry for almost twenty years, first 

in Europe then in the US. Tackticks has been involved with SCR’s using gas, 

coal, oil and all types of waste fuel used in boilers, simple cycle and combined 

cycle systems and incinerators. 

The company’s primary focus is optimizing process design, catalyst selection and 

performance of SCR systems on coal-fired boilers. The company’s clients are 

Electric Utilities, Independent Power Producers, Architect & Engineers, OEM's 

and component suppliers. Tackticks has also been involved in the design of SCR 

systems, start ups, ammonia injection grid tuning, performance testing, trouble 

shooting and O & M support. 

Tackticks, LLC has special experience with the design, operation and 

maintenance support of operating units with generation exceeding 15,000 MW. 

The company’s services are targeted to minimize the operating costs of the SCR 

system, to diagnose operating problems, to enhance overall performance and to 

assist Clients in managing the most comprehensive catalyst strategies. 

The involvement in the SCR strategy contracts enables Tackticks, LLC to be at 

the front of technology advancement and development. 

Tackticks, LLC also currently owns seventy five percent of the flow modeling 

company FlowTack, LLC. FlowTack, LLC performs CFD and physical flow 

models for all kind of technologies. Among those technologies is of course also 

the SCR technology. FlowTack also designs ammonia injection grids for SCR 

systems. 
4

General Description of Services 

The following is a general description of Tackticks’ services: 

Process Design

Tackticks can assist Clients define the appropriate SCR design parameters. 

Historical boiler operating data will be reviewed and assessed to determine unit 

process data at full, mid and low loads. Tackticks can assist Clients in selecting 

SCR catalyst performance requirements so that the Client’s NOx emission 

control strategy is effectively met with minimum negative impact due to ammonia 

slip and SO2 oxidation. 

Tackticks will help define process distribution requirements so that long term 

performance and operational demands are met. 

SCR Arrangement 

Tackticks can assist Clients in determining preliminary SCR arrangements and 

reviewing initial design criteria. With the use of Computational Fluid Dynamics 

modeling, Tackticks can recommend optimal arrangements of duct configuration 

and flow correction devices in order to maintain appropriate flue gas velocities, 

velocity distribution, fly ash distribution and ammonia to NOx distribution within 

the SCR system. 

Specification Review & Preparation

Tackticks can assist Clients by reviewing turnkey specifications with special 

attention paid to, but not limited to, design data, guarantees, process design, 

equipment, catalyst design, potential impacts on boiler and unit operation. 

Tackticks can also prepare technical specifications for Clients. Our company 

focus is generally applied to catalyst selection, ammonia injection grid design, 

flow modeling and flow correction requirements, reagent system requirements 

and performance guarantees. 

Proposal Evaluation

Tackticks has also evaluated proposals for Clients. The company’s assistance in 

this area can range from a complete technical assessment of a proposed design 

and its compliance with the specification to an analysis of a specific technical 

issue. Tackticks will assist in the development of evaluation criteria, preparation 

of questions to the suppliers, and recommendation of the most qualified supplier. 
5

SCR Troubleshooting and Optimization

Tackticks can assist Operators in solving current operational issues and 

suggesting improvements to the SCR system in order to enhance overall 

performance. Services include systems audits, ammonia injection grid tuning, 

catalyst testing and system inspections. 

Requirements for Annual SCR Operation

Tackticks can review SCR operational procedures to ensure appropriateness for 

annual operation. This includes all operating sub-systems of the SCR system. 

Tackticks can evaluate seasonal catalyst performance and update for year-round 

operation. Catalyst management plans can be updated accordingly to coincide 

with unit outage schedules. 
6

Volker Rummenhohl 

247 Booth Meadow Lane 

Durham, NC 27713-5810 

Work Experience: 

FlowTack, LLC 

Manager 

January 2004 – Present 

Mr. Rummenhohl manages FlowTack, LLC a flow model and computational fluid dynamics 

company. 

Tackticks, LLC 

 President 

February 2001 - Present 

Mr. Rummenhohl is currently the president of Tackticks, LLC, a consulting firm located in 

Durham, North Carolina. Tackticks provides process consulting for air quality control systems 

and specializes in SCR systems. Consulting work includes review of arrangement drawings, 

writing and reviewing air quality specifications, general process consulting, training, and support 

during project startup. Mr. Rummenhohl continues to consult with Black & Veatch on the 

evaluation and design of SCR projects.

STEAG AG 

Manager, North America 

September 1993 – February 2001

Mr. Rummenhohl was the Manager of STEAG AG’s liaison office in Durham, North 

Carolina. His responsibilities include marketing and implementing the company’s 

experience and expertise in designing, engineering, startup, commissioning, and 

performance testing of Selective Catalytic Reduction (SCR) systems in North 

America. During his time in this position, Mr. Rummenhohl has consulted for a 

number of U.S. utilities, architectural and engineering firms, and manufacturers, 

conducted seminars, and presented oral and written testimony for regulatory 

agencies. He was located in the United States to consult with Black & Veatch on the 

evaluation and design of domestic SCR projects. 

STEAG AG 

Division Manager, Environmental Engineering Group 

January 1990 - August 1993

Duties included the maintenance and continued improvement / optimization of SCR systems for 

over 5,300 MW of coal fueled electric and cogeneration capacity owned and operated by 

STEAG. These systems have now been in operation for in excess of 600,000 cumulative 

hours. Additionally, Mr. Rummenhohl was responsible for the design and engineering of SCR 

plants. This includes the three SCR plants for the residual oil fired power station Leuna. 
7

Lentjes AG 

Project Engineer and Manager 

1983 – 1990 

Lentjes AG is one of Germany’s largest designers, engineers, and constructors of 

SCR systems. In the position of project engineer and manager, Mr. Rummenhohl 

was involved in the design, engineering, procurement, construction, and 

commissioning of over $600 million of SCR systems throughout Germany. 

Responsibilities included supervision of the startup and commissioning of SCR 

retrofit systems for 2,200 MW. 

University of Dortmund 

1981 - 1983

Mr. Rummenhohl is a 1981 graduate engineer with an advanced degree in chemical 

engineering (“Diplom Ingenieur,” comparable to a U.S. Master of Science degree) 

from the University of Dortmund. After graduation, Mr. Rummenhohl taught as an 

Assistant Professor for a period of two years at the University. 

U.S. Technical Papers 

Pre Heater Pluggage Issues, presented at the 2006 NOx Round Table, Charlotte, 

NC, January, 2006, Author. 

Start-Up and Shutdown of SCR Systems Impact on the Lifetime of the Systems, 

presented at the 24th Annual Electric Utility Chemistry Workshop at the University of 

Illinois, May 11-13, 2004, Author. 

Effective Catalyst and SCR System Management, presented at the 24th Annual 

Electric Utility Chemistry Workshop at the University of Illinois, May 11-13, 2004, 

Coauthor. 

SCR Experience on High Sulfur Fuel, presented at the 2003 NOx Round Table, 

Birmingham, AL January 28-30, 2003, Author. 

Design & Initial Start Up Results from the New Madrid SCR Retrofit Project,

presented at the ICAC Forum 2000, Washington, DC March 20-24, 2000, Coauthor. 

Economic Alternatives for Effective NOx Emissions Reduction, presented at the DOE 

SCR and SNCR NOx Emission Controls Conference, Pittsburgh, Pennsylvania, May 

15-16, 1997, Coauthor. 

Helping the Utility Compete and Comply: Lessons Learned Lead to Informed 

Decision-making for NOx Emissions Reductions, presented at the PowerGen 

Americas Conference Anaheim, California, December 5-7, 1995, Coauthor. 

Effects on Catalytic Activity and SO2 / SO3 Conversion of DeNOx Catalytic Converters 

Downstream of Oil-Fired Power Plants: Causes and Remedial Measures, presented 

at EPRI/EPA 1993 Joint Symposium on Stationary NOx Control, Miami, Florida, May 

24-27, 1993, Coauthor. 

SNCR, SCR and Hybrid Systems Capabilities, Limitations, and Cost, presented at 

EPRI/EPA 1995 Joint Symposium on Stationary Combustion NOx Control, May 16-

19, 1995, Coauthor. 

The Impact of SCR and SNCR Systems on Plant Equipment and Operations, 

presented at the ICAC NOx Emissions Control Conference, Arlington, Virginia, 

November 2, 1994, Coauthor. 
8

Relating the German DeNOx Experience to U.S. Power Plants: Lessons Learned 

from More Than 30,000 MW of DeNOx Retrofits, presented at the ASME Joint 

International Power Generation Conference, Phoenix, Arizona, October 3, 1994 

Coauthor. 

The Effects of Various Parameters on SCR System Cost, presented at the PowerGen 

Americas ’93 Conference, Dallas, Texas, November 17, 1993, Coauthor. 

Alternative NOx Emission Reduction System Comparison, presented at the 1993 

USDOE Coal-Fired Power Plant Upgrade Conference, Warsaw, Poland, June 17, 

1993, Coauthor. 

German Experience Sheds Light on SCR O&M Issues, September 1992 issue of 

Power magazine, Coauthor. 
9

ROBERT E. JOHNSON 

PROFESSIONAL EXPERIENCE 

Mar 2007 – Present Tackticks, LLC – Durham, NC 

Air Pollution Control Consultant -- Specific focus on Selective Catalytic 

Reduction (SCR) technology and applications. Principal responsibilities 

include SCR process design analysis and recommendations, Flow 

Modeling Analysis, SCR performance evaluation, ammonia injection grid 

design and tuning, SCR system inspections. 

2003 – Feb 2007 Burns & McDonnell Engineers – Kansas City, MO 

SCR Program Manager – Responsible for promoting BMcD’s SCRrelated activities within the Power Industry. Provided technical 

consultation on in-house projects to Clients and Project Teams as well 

as assisting Clients with operating performance evaluations. 

Major Accomplishments

• Member of the Team that secured a major SCR design engineering 

project from a major Midwestern Cooperative. 

• Lead technical advisor for ten (10) SCR projects. 

1996 – 2003 C & I Ceramics USA – Alpharetta, GA 

(formerly Siemens Power Generation) 

 

Vice-President, Sales – Responsible for Sales of Siemens’ SCR 

Catalysts to the Power Industry 

Major Accomplishments

• Negotiated systemwide agreements with three U.S. Utilities for the 

supply of SCR catalyst for SIP-related compliance projects. 

• Successfully negotiated contracts with other Utilities for similar 

projects. 

• Total Sales in excess of $300 million. 

1989 – 1996 Wahlco Environmental Systems – Leawood, Kansas 

Vice President of New Technologies – Responsible for the 

commercialization and market development of Wahlco’s NOx emission 

control technology. Coordinated technology assessment and research 

activities. 

Major Accomplishments

• Sold Wahlco’s first commercial Staged NOx Reduction System on a 

gas-fired boiler. 

• Negotiated partnerships with key participants in demonstration 

programs for Staged NOx Reduction System. Instrumental in 

selecting customers for demonstration sites; successfully negotiated 

first demonstration on a coal-fired boiler. 
10

• Negotiated first commercial flue gas conditioning installations on a 

coal-fired cogeneration plant, a hot-side electrostatic precipitator, 

and the industry’s first baghouse application. 

1983 – 1989 Belco Technologies Corporation – Parsippany, New Jersey 

Regional Manager – Directed air pollution control equipment sales for 

special projects involving new accounts and existing customers with 

emphasis on flue gas conditioning and microprocessor based control 

systems. 

Major Accomplishments

• Sold Company’s first flue gas conditioning system, first precipitator 

rebuild on a cement kiln, and first new precipitator installation on a 

cement kiln. 

• Sold $2 million of equipment upgrades, control systems and parts. 

1983 Israel Electric Company – Independent Consultant 

1977 – 1982 Apollo Technologies, Inc. – Regional Manager, Technical Services 

EDUCATION Bachelor of Science, Fairleigh Dickinson University, 1976 

 Bachelor of Arts, University of Notre Dame, 1975 

Technical Papers & Presentations 

"Selective Catalytic Reduction Performance Project at Public Service Electric and Gas 

Company's Mercer Generating Station Unit No. 2;" Wallace, Gibbons et al., presented at 

EPRI/EPA 1995 Joint Symposium on Stationary Combustion NOx Control, May 16-19, 1995, 

Kansas City Missouri 

"Selective Catalytic Reduction: Successful Commercial Performance on Two U.S. Coal-Fired 

Boilers;" Wagner, Bullock et al; presented at EPRI-DOE-EPA Combined Utility Air Pollutant 

Control Symposium, The Mega Symposium, August 25-29, 1997, Washington, D.C. 

"SCR For a 460 MW Coal Fueled Unit: Stanton Unit 2 Design, Startup, and Operation;" Cochran, 

Scarlett et al; presented at EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, 

The Mega Symposium, August 25-29, 1997, Washington, D.C. 

"Current Practices for Monitoring Ammonia Slip from SCR Processes;" Sigling, Johnson; 

presented at FETC 1998 Conference on SCR and SNCR for NOx Control, May, 1998, Pittsburgh, 

Pennsylvania 

"Powder River Basin (PRB) Coal and High Arsenic Concentrations: Catalyst Specific Issues and 

Operating Experience;" Rigby, Hums et al.; presented at EPRI Workshop on Selective Catalytic 

Reduction, April 18-21, 2000, Memphis, Tennessee 

"SCR Catalyst Design Issues and Operating Experience: Coals with High Arsenic 

Concentrations and Coals from the Powder River Basin;" Rigby, Sigling, et al; presented at The 

International Joint Power Generation Conference, July 23-28, 2000, Miami Beach, Florida 
11

"U.S. Utility Coal-Fired Selective Catalytic Reduction Applications: SCR Catalyst-Specific Issues 

and Operating Experience;" Sigling, Johnson; presented at EPRI 2001 Workshop on Selective 

Catalytic Reduction, November 13-15, 2001, Baltimore, Maryland 

"U.S. Utility Coal-Fired SCR Applications: SCR Catalyst-Specific Issues and Operating 

Experiences;" Sigling, Johnson; presented at ICAC Forum 2002, February, 2002, Houston, Texas 

"SCR Catalyst Performance: New Information for U.S. Operators;" Sigling, Johnson; presented 

at EPRI 2002 Workshop on Selective Catalytic Reduction; October 16, 2002, Atlanta, Georgia 

"Peak SCR Performance Requires Consolidated Program Management;" presented at Electric 

Power 2004, April 1, 2004, Baltimore, Maryland 

"SCR Update for Simple Cycle Gas Turbine Applications;" presented at Power Gen International 

2004, December, 2004, Orlando, Florida 

"Selective Catalytic Reduction System Design Considerations;" presented at Power Gen 

International 2004, December, 2004, Orlando, Florida 

“Selective Catalytic Reduction System Design Considerations;” presented at the 110th Plant 

Design and Operating Committee, January, 2005, Fort Worth, Texas 

“SCR Program Management;” presented at the 110th Plant Design and Operating Committee, 

January, 2005, Fort Worth, Texas 

“How Can You Maximize Results from Your SCR Catalyst Replacement?” presented at Burns & 

McDonnell 2006 Coal Symposium, April, 2006, Kansas City, Missouri 

“SCR Program Management: A Powerful Program to Enhance Plant Operations;” presented at 

the 57th Annual Generation Conference, Association of Rural Electric Generating Cooperatives, 

June, 2006, Cincinnati, Ohio 

“Thomas Hill Unit 3 SCR Retrofit Design Approach Avoids Increases in Draft Loss;” presented at 

Coal Gen 2006, August, 2006, Cincinnati, Ohio 

“SCR Technology for Coal Fired Boilers: Design Considerations for Proper Performance;” 

presented at Power Gen Asia, September, 2006, Hong Kong 

“Environmental Controls Retrofit Project at AECI Thomas Hill Energy Center;” presented at EPRI 

2006 Workshop on SCR, November, 2006, Dearborn, Michigan 

“Thomas Hill Unit 3 SCR Retrofit Design Approach Avoids Increases in Draft Loss;” presented at 

Power Gen International 2006, November, 2006, Orlando, Florida 
12

Tackticks LLC SCR Consulting and Process Engineering Reference List 

June, 2007 

Plant Size MW Fuel Utility/IPP Time Service 

Provided 

R

New Madrid 1 600 PRB Coal AECI 2001 HStuart 1-4 4*600 Bit. Coal Dayton Power & Light 2001 - HKillen 2 600 Bit. Coal Dayton Power & Light 2001 - Low DCully 3 265 Bit. Coal VECTREN 2001 - 2003 HWarrick 4 325 Bit. Coal VECTREN 2001 - HBrown 1 265 Bit. Coal VECTREN 2002 - HBrown 2 265 Bit. Coal VECTREN 2001 - HDesert Basin (Trouble Shooting) 180 Gas Reliant Energy 2001 Michigan City 12 540 PRB/Bit. Blend NIPSCO 2001 - 2003 HShafer 14 540 Bit. Coal NIPSCO 2001 - HBailly 8 420 High Sulfur Coal NIPSCO 2002 - HDallman 31 & 32 2 * 85 High Sulfur Coal CWLP Springfield 2001 - 2003 HDallman 33 150 High Sulfur Coal CWLP Springfield 2001 - 2003 HLambton 3 & 4 2 * 500 High Sulfur Coal Ontario Power Generation 2001 - 2003 HNanticoke 7 & 8 2 * 500 PRB/ Bit. Blend Ontario Power Generation 2001 - HE.D. Edwards 3 365 Bit. Coal Ameren Current HDuck Creek 440 Bit. Coal Ameren Current HMercer 1 & 2 2 * 325 Bit. Coal PSE&G 2002 - Low DPowerton (project delayed) 2 * 700 Bit. Coal MidWest Gen 2001 – 2002 Low DHomer City 1 & 2 (upgrades) 2 * 600 Bit. Coal MidWest Gen 2002-2005 HBrandon Shores 1 & 2 (upgrades) 2 * 650 Bit. Coal Constellation Energy 2002 Low Canal 1 & 2 (upgrades) 2 * 600 Oil MIRANT 2001 - H
13

Plant Size MW Fuel Utility/IPP Time Service 

Provided 

R

Lovett 3,4,5 435 Bit. Coal MIRANT 2002 - HHarding Street 470 Bit. Coal AES 2003-2004 HWeston 600 Bit. Coal Wisconsin Public Service 

Corp. 

2004 - H

Prairie State 2*750 High Sulfur Coal Peabody Energy 2004 - HThoroughbred 2*750 High Sulfur Coal Peabody Energy 2004 - HHomer City 3 (upgrades) 650 Bit. Coal MidWest Gen 2002-2005 HThomas Hill 1,2,3 1135 PRB AECI 2005-2010 HElmer Smith PS Unit 1 (Trouble Shooting) 

150 Bit. Coal OMU 2005 H

St. Johns River Power Plant 2* 660 Petcoke, Bit. 

Coal 

SJRPP 2005-2009 H

Northport Unit 3 150 Oil Key Spann Energy 2005- HLa Cygne Unit 1 800 PRB Kansas Power & Light 2005 HSibley Unit 3 420 PRB Aquila Current HSouthwest Unit 1 194 PRB City Utilities Springfield 

MO 

Current H

Oak Creek Units 5 - 8 1,200 PRB WE Energy Current TTrimble County Unit 2 900 Bit. Coal LGE Energy Current HSouthern Company (Various Plants) 

 PRB, Bit. Coal Southern Company Current H

Total > 28,300 MW