Selective Catalytic Reduction (SCR)

Technical Feasibility

For

M.R. Young Station

1. Introduction

On July 27, 2006 a Consent Decree was entered by the United States District Court for the

District of North Dakota for Civil Action No.1 :06-CY-034, United States of America and the

State of North Dakota versus Minnkota Power Cooperative, Inc. and Square Butte Electric

Cooperative. The Consent Decree resolved alleged violations of the Federal Clean Air Act and

the North Dakota Air Pollution Control Rules (NDAC 33-15) including the Prevention of

Significant Deterioration Rules (NDAC 33-15-15). Section Y, Paragraph 65, of the Consent

Decree required Minnkota Power Cooperative and Square Butte Power Cooperative (hereafter

Minnkota) to submit to the Department for review and approval, a nitrogen oxides (NOx) topdown Best Available Control Technology (BACT) analysis for the two existing units at the M.R.

Young Station. The Consent Decree required Minnkota to evaluate various technologies

including selective catalytic reduction (SCR), selective noncatalytic reduction (SNCR), over-fire

air (OFA) and rich reagent injection (RRI). Minnkota must also submit any additional

information requested by the Department or the U.S. Environmental Protection Agency

(hereafter EPA) which is pertinent to the BACT determination. On October 9, 2006, the

Department received the required BACT analyses.
Under Section III, paragraphs 23 and 24 of the Consent Decree, the BACT analysis must be

made in accordance with the provisions of Chapter B of EPA's New Source Review Workshop

Manuat9 (hereafter NSR Manual). As discussed in the NSR Manual, the steps for conducting a

BACT analysis using the "top down" approach are as follows:

Step 1: Identify All Control Technologies.

List is comprehensive.

Potentially applicable control alternatives can be categorized in three ways.

• Inherently Lower-Emitting Processes/Practices, including the use of materials and

production processes and work practices that prevent emissions and result in lower

"production-specific" emissions; and

• Add-on Controls, such as scrubbers, fabric filters, thermal oxidizers and other devices

that control and reduce emissions after they are produced.

• Combinations of Inherently Lower Emitting Processes and Add-on Controls. For

example, the application of combustion and post-combustion controls to reduce NOx

emissions at a gas-fired turbine.

2
The top-down BACT analysis should consider potentially applicable control techniques from all

three categories. Lower-polluting processes should be considered based on demonstrations made

on the basis of manufacturing identical or similar products from identical or similar raw

materials or fuels. Add-on controls, on the other hand, should be considered based on the

physical and chemical characteristics of the pollutant-bearing emission stream. Thus, candidate

add-on controls may have been applied to a broad range of emission unit types that are similar,

insofar as emissions characteristics, to the emissions unit undergoing BACT review.

Step 2: Eliminate Technically Infeasible Options.

A demonstration of technical infeasibility should be clearly documented and

should show, based on physical, chemical, and engineering principles, that

technical difficulties would preclude the successful use of the control option on

the emissions unit under review.

The NSR Manua19 provides guidance for determining whether a control option is technically

infeasible. Two concepts are important in making this determination, "availabilityll and

"applicabilityll. A technology is considered "availablell if it can be obtained through commercial

channels or is otherwise available within the common sense meaning of the word. An available

technology is "applicablell if it can reasonably be installed and operated on the source type under

consideration. A technology that is available and applicable is considered technically feasible.

Regarding "availability" the NSR Manuat9 states:

3
"A control technique is considered available, within the context presented above, if it has

reached the licensing and commercial sales stage of development. A source would not be

required to experience extended time delays or resource penalties to allow research to be

conducted on a new technique. Neither is it expected that an applicant would be required

to experience extended trials to learn how to apply a technology on a totally new and

dissimilar source type. Consequently, technologies in a pilot scale testing stages of

development would not be considered available for BACT review."

With respect to "applicability" the NSR Manual9 states:

"Technical judgment on the part of the applicant and the review authority is to be

exercised in determining whether a control alternative is applicable to the source type

under consideration. In general, a commercially available control option will be

presumed applicable ifit has been or is soon to be deployed (e.g., is specified in a permit)

on the same or a similar source type. Absent a showing of this type, technical feasibility

would be based on examination of the physical and chemical characteristics of the

pollutant-bearing gas stream and comparison to the gas stream characteristics of the

source types to which the technology had been applied previously. Deployment of the

control technology on an existing source with similar gas stream characteristics is

generally sufficient basis for concluding technical feasibility barring a demonstration to

the contrary.

4
Step 3:

For process-type control alternatives the decision of whether or not it is applicable to the

source in question would have to be based on an assessment of the similarities and

differences between the proposed source and other sources to which the process

technique had been applied previously. Absent an explanation of unusual circumstances

by the applicant showing why a particular process cannot be used on the proposed source

the review authority may presume it is technically feasible.

In practice, decisions about technical feasibility are within the purview of the review

authority. Further, a presumption of technical feasibility may be made by the review

authority based solely on technology transfer. For example, in the case of add-on

controls, decisions of this type would be made by comparing the physical and chemical

characteristics of the exhaust gas stream from the unit under review to those of the unit

from which the technology is to be transferred. Unless significant differences between

source types exist that are pertinent to the successful operation of the control device, the

control option is presumed to be technically feasible unless the source can present

information to the contrary."

Rank Remaining Control Technologies By Control Effectiveness

This includes:

control effectiveness (percent pollutant removed);

expected emission rate (tons per year);

5
Step 4:

Step 5:

expected emission reduction (tons per year);

.energy impacts (Btu, KW-hr);

environmental impacts (other media and the emissions oftoxic and hazardous air

emissions); and

economic impacts (total cost effectiveness and incremental cost effectiveness).

Evaluate Most Effective Controls and Document Results

Case-by-case consideration of energy, environmental, and economic impacts.

Ifthe most effective option is not selected as BACT, evaluate next most effective

control option.

Select BACT

Most effective option not rejected is BACT and establish emission limit or work

practice standard.

The Department solicited public comments on its preliminary BACT detennination for nitrogen

oxides (NOx) controls at the M.R. Young Station (MRYS). Comments from the Environmental

Protection Agency and several environmental groups disagreed with the conclusion that high

dust SCR (HDSCR), low dust SCR (LDSCR) and tail end SCR (TESCR) were technically

infeasible. Comments from other parties agreed with the Department's preliminary

detennination. The Department has evaluated the comments and has reaffinned its preliminary

6
detennination that HDSCR is technically infeasible. However, the Department now believes

LDSCR and TESCR are technically feasible.

This document explains the Department's current views on technical feasibility. This document

does not represent a final Department action. The Department will make its final BACT

detennination after the remaining steps for conducting a BACT analysis have been completed.

Minnkota will be required to submit additional infonnation necessary for the Department to

make its final BACT detennination including an evaluation ofthe cost of LDSCR and TESCR.

II. High Dust Selective Catalytic Reduction (HDSCR)

HDSCR, or conventional SCR, refers to an SCR system that is installed prior to any air pollution

control equipment and usually between the economizer outlet and air heater inlet. HDSCR has

been installed on many pulverized coal and cyclone boilers firing bituminous and subbitiminous

coal in the United States.

A. Public Comments

1. NDDH's Technical Feasibility Analysis of High Dust SCR is Incorrect and Based

Upon Flawed Data

The NSR Manual states "A demonstration of technical infeasibility is based on a

technical assessment considering physical, chemical and engineering principles,

7
and/or empirical data showing that the technology would not work on the

emissions unit under review, or that unresolvable technical difficulties would

preclude the successful deploYment ofthe technique."

The Department asked EPA's consultant, Mr. Roger Christmann, if he was aware

of any installation in the world where HDSCR had been applied to a facility with

as high of sodium loading as at MRYS. Mr. Christmann indicated no. This

indicates that there has never been a design established for a flue gas with the

chemical characteristics found at MRYS. Simple mathematics prepared by the

Department shows that the flue gas at MRYS is much higher in sodium and other

catalyst deactivation chemicals than other power plant flue gases. EPA seems to

ignore the fact that the sodium at MRYS is the soluble form (organically

associated) which is a more potent catalyst deactivation chemical than the

insoluble (inorganically associated) form found in other coals. EPA tries to

dismiss this showing by ratioing the loading of Powder River Basin (PRB)

subbituminous coal to bituminous coal without indicating the actual loading. The

Department showed the actual loading (lb/dscf and lb/wscf) as well as the ratio to

other facilities. When you start out with a very small loading, as is the case with

bituminous coal, a large ratio for subbituminous coal also gives you small

loading. As EPA's own consultant points out, SCR has never been applied to

sodium loading as high as at MRYS.

8
Minnkota and its consultants have documented very well the effect of soluble

sodium on an SCR catalyst. Although the Coyote testing did not provide any

deactivation rate data for high soluble sodium North Dakota lignite, it did show

that an HDSCR design for subbituminous coal will probably not work

successfully with North Dakota lignite. As Sargent and Lundy pointed out, there

is no known solution for the soluble alkalis such as the soluble sodium and

potassium found in North Dakota lignite. EPA ignores the chemical differences

between Texas lignite and North Dakota lignite.

With respect to the catalyst vendor "guarantees", all of the vendors that Minnkota

contacted indicated that pilot scale testing was either required or should be done

prior to applying high dust SCR technology to a North Dakota lignite-fired boiler.

Minnkota has provided information that indicates the potential for greatly reduced

catalyst life due to the chemical characteristics of the flue gas. Although two

vendors indicated a catalyst life which the Department would consider as a

"successful application" of HDSCR technology at MRYS, others did not give

such an indication. All vendors indicated the flue gas temperature problems (too

hot or too cold) must be resolved for the application of HDSCR to be successful.

No solution to this problem has been found at this time. EPA has indicated that

some of the vendors may have been prompted by Minnkota, or its consultants, to

indicate that pilot testing should be done. Even if some vendors may have been

"prompted" to make these statements, it is irrelevant since the vendors could have

chosen not to make the statement.

9
Although the Texas CEQ has determined that HDSCR is technically feasible for

Texas lignite, the chemical constituents of North Dakota lignite that affect the

feasibility of HDSCR are quite different. The State of Louisiana recently

determined that HDSCR was not technically feasible for an activated carbon plant

because ofthe flue gas characteristics ofthe lignite used in the process.

The NSR Manual9 indicates that an add-on control technology is only technically

feasible if it can lead to "successful operation" or "successful deployment." The

Department has indicated that anything less than 10,000 hours of catalyst life

would not be successful operation of the SCR system and thus technically

infeasible. Kling et. al? conducted pilot and bench sale testing of SCR catalysts

when subjected to flue gas from the combustion of biomass. The testing was

conducted using three different types of catalyst. Catalyst Type A was typical of

that used for coal-fired boilers, Type B was a "bio-optimized" catalyst with an

increased vanadium content and Type C had a very high vanadium content.

Kling2

, and later Zheng et. al3

, have concluded that it is the alkali aerosols that are

less than or equal to 0.1 micrometers that cause most of the catalyst deactivation.

In North Dakota lignite, the alkali metals are generally associated with the organic

matter of the lignite while in other coals the alkaline constituents are associated

with the inorganic portion of the coal (e.g. clays). The combustion of the

organically associated alkaline elements causes them to vaporize; when they

condense, they form submicron aerosols. The combustion of inorganically

10
associated alkalis causes only a small portion to vaporize. Minnkota has supplied

infonnation that indicates these condensed alkali aerosols have a mass mean

diameter of approximately 0.1 micrometers. Therefore, 50% of the aerosols

would be less than 0.1 micrometers in size on a mass basis. The average mass of

sodium oxide and potassium oxide emitted from the MRYS boilers was calculated

at 3.05 x lO-s lb/dscf (524 mgiNm3

) and 9.01 x 10-6 lb/dscf (155 mgiNm\

respectively.

Crespi6 has provided data that suggests potassium oxide is approximately twice as

potent a catalyst deactivation chemical on a molar basis (1.3 times on a mass

basis) than sodium oxide. The equivalent potassium oxide emission rate for

MRYS based on this data would be 558 mgiNm3

. The aerosols are most likely in

the sulfate fonn.s This would lead to an equivalent potassium sulfate emission

rate of 1034 mgiNm3

•

Kling2 found a deactivation rate of 21-52% over 1500 hours for fuel made up of

tree bark and 30% demolition wood waste. This fuel has a potassium chloride

loading of 16.7 mgiNm3 and a sodium chloride loading of 5.8 mgiNm3

• The

Kling2 results were for aerosols with an aerodynamic diameter of less than 0.1

micrometers. If all of the sodium and potassium in lignite vaporizes, 50% of the

total loading would be less than or equal to 0.1 micrometers or 517mgiNm3 of

equivalent potassium sulfate. Zheng3 has suggested that potassium chloride is

two and one half times more potent catalyst poison than potassium sulfate (0.4%

11
per day versus 1% per day). An equivalent loading ofsodium and potassium for a

HDSCR at MRYS as potassium chloride would be 207 mglNm3

. This loading is

nearly 10 times that ofthe Kling2 testing. The Kling2 results suggest 2,885-7,140

. hours until 100% deactivation. The higher loading at the North Dakota facilities

suggests a much higher deactivation rate and a shorter catalyst life.

Zheng et. al. 3 found a catalyst deactivation rate of 0.4% per day for a potassium

sulfate. The testing was conducted using a concentration of 20-30 mglNm3 of

potassium sulfate with a mass mean diameter of 0.55 micrometers. Although data

is not available to determine the loading of aerosols with a diameter less than 0.55

micrometers, a comparison to the fraction less than 0.1 micrometers indicates a

concentration 17-26 times larger than the concentration in Zheng's tests. The

0.4% deactivation rate per day is equivalent to 6000 hours at 100% deactivation.

For a HDSCR, the flue gas from the MRYS would likely produce a higher

deactivation rate.

The recent testing by Kling2 and Zheng3 indicate that it is unlikely that a HDSCR

will achieve 10,000 hours of catalyst life when combusting Center lignite at

MRYS. In fact, the catalyst life could be only a few thousand hours as suggested

by the pilot scale testing at the Coyote Station.

12
2. MRYS Temperature Variation Issue Related to HDSCR

EPA has indicated the temperature problems with HDSCR can be resolved.

Mr. Steve Moorman of Babcock and Wilcox in a July 18, 2007 email stated the

resolution of the temperature problem would require a technical feasibility

analysis of a "very complex nature" to determine if boiler modifications could

bring furnace exit gas temperatures into the range needed for compatibility with

operation of HDSCR. Modifications outside of the boiler may solve the

temperature problem; however, a study would be required. EPA's statement that

the technical issues with the temperature issue can be resolved appears to be

premature.

The email also states "Our budget estimate to complete this study is $275,000 to

$400,000 including the performance test, project management costs and travel

expenses. We project the study will require 20 to 24 weeks to complete including

the time to run the performance tests." The NSR Manual9 states: "A control

technique is considered available, within the context presented above, if it has

reached the licensing and commercial sales stage of development. A source

would not be required to experience extended time delays or resource penalties to

allow research to be conducted on a new technique. Neither is it expected that an

applicant would be required to experience extended trials to learn how to apply a

technology on a totally new and dissimilar source type. Consequently,

13
technologies in the pilot scale testing stages of development would not be

considered available for BACT review." The Department considers the time and

money necessary to detennine if the temperature problems can be overcome to be

excessive.

3. EPA's Conclusion on HDSCR

When considering application of HDSCR to a cyclone boiler burning North

Dakota lignite, the MRYS is considered a new source type. In the past, EPA has

recognized cyclone boilers, and more generally slag tap furnaces, that bum lignite

from North Dakota, South Dakota and Montana as a separate source category for

NOx emissions in the New Source Perfonnance Standards, Subparts D and Da.

This separate category was established primarily based on the use of high sodium

lignite. Not until EPA developed a fuel and furnace neutral standard was this

category replaced. The replacement ofthis category was apparently done without

an evaluation of the flue gas characteristics of North Dakota lignite. The NSR

Manual9 states "Add-on controls, on the other hand, should be considered based

on the physical and chemical characteristics of the pollutant-bearing emission

stream. Thus, candidate add-on controls may have been applied to a broad range

of emission unit types that are similar, insofar as emissions characteristics, to the

emission unit undergoing BACT review." (NSR Manual, Chapter B, Section

IV.A).

14
Minnkota has demonstrated that the flue gas characteristics at MRYS are different

from other coal-fired boilers where HDSCR has been applied. The NSR Manual

states "A source would not be required to experience time delays or resource

penalties to allow research to be conducted on a new technique. Neither is it

expected that an applicant would be required to experience extended trials to learn

how to apply a technology on a totally new and dissimilar source type." (Chapter

B, Section IV.B). Minnkota is not required to conduct extensive and expensive

feasibility analyses for modifying the boiler to correct temperature problems that

make HDSCR infeasible.

EPA has indicated that catalyst regeneration is a viable option (that is currently

used in practice) for restoring catalyst life either in-situ, on-site, or off-site water

washing. EPA cites a PowerPoint presentation at the 2007 NOx Round Table and

Expo by Reinhold Environmental Limited as evidence that this technique is

available. DOl's consultant, Mr. Hans Hartenstein, also made a presentation at

the referenced Expo. In Mr. Hartenstein's presentation the following statement is

made "Regeneration = Removal of catalyst poisons plus restoration of

catalytically active ingredients - can typically not be done in-situ or on-site, but

should be done off-site to ensure required close process control." EPA may be

referring to "rejuvenation" of a catalyst for which Mr. Hartenstein states

"Removal of catalyst poisons without the need for replenishing catalytically

active compounds - can sometimes [emphasis added] be done in-situ, but is most

commonly done either on-site or off-site." These statements were also made by

15
Ehrnschwender and Holsccher at the February 2008 Expo (Considerations for

Catalyst Deactivation and Regeneration When Firing Biomass). Minnkota and its

consultants hav~ addressed this issue by stating "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 has also never been used for blinded or chemically

poisoned catalyst, but only for mechanically plugged catalyst." There is no

evidence regarding the effectiveness of washing to rejuvenate an SCR catalyst on

the MRYS. Pilot scale testing would be necessary to determine the feasibility of

this catalyst maintenance technique.

4. The NDDH BACT Determination Incorrectly Applies the Concept of Pilot

Testing in EPA's NSR Manual to Conclude that SCR is not Technically Feasible

EPA states that "For determining whether a control option is available, EPA's

NSR Manual does not describe the comparison of gas stream characteristics

between the source under review and other sources."

There has never been SCR technology applied to a boiler that combusts North

Dakota lignite. EPA has recognized in the past, that cyclone boilers, such as

those at Minnkota, that bum lignite from North Dakota is a separate source

category for NOx emission limits under the New Source Performance Standards,

Subpart D and Da. Chapter B, Section IV.A, Identify Alternative Emission

16
Control Techniques (Step 1) [emphasis added] states "The top-down BACT

analysis should consider potentially applicable control techniques from all three

categories. Lower polluting processes should be considered based on

demonstrations made on the basis of manufacturing identical or similar products

. from identical or similar raw materials or fuels. Add-on controls, on the other

hand, should be considered based on the physical and chemical

characteristics of the pollutant-bearing emission stream. Thus, candidate

add-on controls may have been applied to a broad range of emission unit

types that are similar, insofar as emissions characteristics, to the emissions

unit undergoing BACT review." [emphasis added] Clearly, identification of

control options under Step 1 must take into account the flue gas characteristics. If

the flue gas characteristics can be shown to prevent successful application of the

technology to the source under view, the technology is not identified as

"potentially applicable" to the source in Step 1 and is therefore not commercially

available under Step 2. Minnkota has shown that the flue gas characteristics for a

HDSCR at MRYS are different from that at any other coal-fired power plant

where SCR has been installed. Mr. Roger Christmann, EPA consultant, stated

that he was not aware of any power plant where HDSCR had been applied with as

high ofsodium loading as MRYS.

HDSCR technology designed for other coal-fired power plants is not applicable to

a North Dakota lignite-fired unit and there is no commercially available design.

Pilot scale testing would be necessary to show whether HDSCR can work

17
successfully. As Sargent and Lundy (S&L) pointed out, there are no known

solutions for the catalyst surface masking and catalyst deactivation caused by the

soluble alkalis (Na20 and K20) found in North Dakota lignite. S&L indicated

that some thresholds or limits are yet to be defined for HDSCR involving ash with

greater than 2% Na20 and greater than 1% K20. Ash from MRYS contains an

average 4.4% Na20 and 1.3% K20. The Na20 can be as high as 13% and K20 as

high as 7%. Any pilot scale testing would be used to obtain data on the soluble

alkalis and ash characteristics and compare the findings with experience on

Powder River Basin Coal.

The pilot scale testing for a HDSCR would not be for optimizing an existing

applicable control technology. It would be for researching solutions for the high

soluble alkalis and possibly designing a new SCR system for a new and dissimilar

source category.

5. The NDDH BACT Determination Frustrates the Technology Forcing Function of

the BACT that was Intended by Congress.

MRYS is a different source category based on its flue gas characteristics at a

HDSCR location. The Department has taken the position that the flue gas

characteristics at the MRYS would preclude the successful application of existing

HDSCR technology. Decisions regarding technical feasibility are based on the

flue gas characteristics, not whether it has been applied to a coal-fired boiler or

18
some other general source category. We believe Congress never intended forcing

a technology on a source when there is a low probability of successful

deployment ofthat technology.

B. Conclusions

Recent testing by Kling2 and Zheng3 suggest a low probability of achieving successful

application of HDSCR technology by MRYS. The high concentration of sodium and

potassium in the flue gas will rapidly deactivate the catalyst. The results suggest much

less than 10,000 hours of catalyst life which the Department believes is necessary for

successful application of HDSCR.

Minnkota has supplied data indicating temperature problems (both too high and too low)

at the location of HDSCR which will affect the catalyst life. Babcock and Wilcox has

estimated that a study of the temperature problems could take up to 24 weeks and cost up

to $400,000. The NSR manual indicates that a company is not expected to experience

extended trials to learn how to apply a technology.

Based on the flue gas characteristics at the location of the high dust SCR and the

temperature problems (both too high and too low), the Department does not consider

HDSCR to be technically feasible for MRYS.

19
III. Tail End SCR and Low Dust SCR

A. Introduction

SCR systems placed between the particulate control device and sulfur dioxide control

equipment are called low dust SCR (LDSCR). Systems that are placed downstream of

the particulate matter (PM) and sulfur dioxide (S02) control systems are generally

referred to as tail end SCR (TESCR). This is in contrast to a HDSCR location where

none of the particulate matter and sulfur dioxide has been removed from the flue gas.

LDSCR and TESCR systems have been used on coal-fired and biomass fired boilers in

the United States as well as other countries. However, no SCR system including a low

dust or tail end SCR has ever been operated on a boiler firing North Dakota lignite. The

flue gas produced by the combustion of North Dakota lignite contains high

concentrations of alkali aerosols (primarily sodium and potassium). Cyclone boilers,

such as the two units at the M.R. Young Station, produce higher concentrations of

submicron aerosols than conventional pulverized or fluidized bed boilers. The higher

temperature in the cyclone boilers vaporizes the organically associated sodium and

potassium in North Dakota lignite. When these elements condense, they form submicron

aerosols. Minnkota1 (p. 12) has indicated that the condensed vapors have a mean

diameter of approximately 0.1 micrometers. Papers by Kling2 and Zheng3 have indicated

that the aerosols with a diameter less than or equal to 0.1 micrometers cause the greatest

catalyst deactivation.

20
The NSR Manua19 states that decisions regarding technically feasibility are made by

comparing the physical and chemical characteristics of the exhaust gas stream from the

unit under review to those of the unit from which the technology is being transferred.

Unless significant differences between the source types exist that are pertinent to the

successful operation of the control device, the control option is presumed to be

technically feasible unless the source can present information to the contrary.

Since no LDSCR or TESCR system has ever been applied to a boiler that combusts North

Dakota lignite, an evaluation ofthe flue gas characteristics was made to determine ifthey

were substantially different from facilities that have successfully applied SCR technology

or to determine if empirical data would indicate whether low dust or tail end SCR can be

successfully applied.

B.Flue Gas Characteristics

At the MRYS, both units use an electrostatic precipitator (ESP) to control PM emissions.

Unit 2 is equipped with a wet scrubber to control S02 emissions while a wet scrubber will

be constructed for Unit 1. Minnkota4 (p.20) has provided an analysis of the particulate

matter emitted from Unit 2 which can be used for evaluation of TESCR. The analysis

indicated the PM was 6.56% sodium (Na), 2.26% potassium (K), 5.71% sulfur (S),

57.52% oxygen (0) and the remaining other elements.

21
The sodium and potassium after the ESP and wet scrubber is most likely in sulfate forms

(p.32). If all of the sodium and potassium is in the sulfate form, sodium sulfate and

potassium sulfate would comprise approximately 25% of the total particulate matter

emitted from Unit 2 (see Appendix A). Minnkota has indicated that the sample of the

particulate matter that was analyzed was obtained while some flue gas was bypassing the

S02 scrubber. The amount of sodium, potassium and/or sulfur in the sample could be

biased high when compared to a sample when all flue gas passes through the wet

scrubber.

A review ofthe latest PM stack tests at M.R. Young Unit 2 (8/07 and 5/08) indicated an

average PM emission rate of 10.61 milligrams per normal cubic meter (mg/Nm3 at 6%

02 - see Appendix B). Based on 25% ofthe PM being sodium and potassium sulfate, the

combined emission rate of these two compounds is approximately 2.7 mg/Nm3

. This

indicates a sodium and potassium removal efficiency of greater than 99% by the ESP and

wet scrubber.

Minnkota has submitted data from a study by Markowskis (p.3l) which indicated that

approximately 81 % of the sulfate emitted after the Unit 2 wet scrubber is less than 1.1

micrometers in size and approximately 36% is less than 6.26 micrometers in size. Based

on the latest stack tests and the Markowski data, the submicron sodium sulfate plus

potassium sulfate emission rate would be less than 2.2 mgiNm3 and the emission rate of

sodium and potassium sulfate less than 0.26 micrometers in size would be approximately

22
1.0 mg/Nm3

. These values are similar to those Markowski reported which were 1.335

mg/m3 and 0.602 mg/m3 respectively.

C. Catalyst Deactivation

The two primary flue gas constituents that will cause SCR catalyst deactivation in a low

dust or tail end configuration are sodium and potassium, most likely in sulfate formS

(p.32-35). Crespi et.a1.6

, in their paper regarding the Arnager Station, presented a graph

which shows the effect of various poisons on the activity of vanadia - titania catalysts.

Minnkotal (page 21) provided similar information that indicates that potassiu~ oxide is a

more potent catalyst poison on a molar basis than sodium oxide. Although no actual data

is supplied, analysis of the graph indicates that potassium oxide is 1.77 - 2.08 times more

potent catalyst poison than sodium oxide (on a molar basis) up to a poison to

vanadium/titanium ratio of 0.5 (see Appendix C). Because potassium oxide has a larger

molecular weight than sodium oxide, the poisoning ratio is 1.1 - 1.3 on a mass basis.

As indicated earlier, Kling2 and Zheng3 have indicated that the aerosols less than or equal

to 0.1 micrometers cause the catalyst deactivation. Data are not available to calculate the

portions of the PM emissions from Unit 2 that would be less than or equal to 0.1

micrometers. A conservative assumption is that all of the sodium and potassium sulfate

less than 0.26 micrometers is less than or equal to 0.1 micrometers. Based on this

assumption and the PM analysis data, the total emission rate forsodiurn and potassium

23
sulfate combined that is less than or equal to 0.1 micrometers is size is estimated at 0.98

mg/Nm3 of which 0.78 mg/Nm3 is sodium sulfate.

KlingZ has provided catalyst deactivation rates for various biomass fuels which produce a

flue gas that contains sodium and potassium aerosols. The testing was conducted using

different types of honeycomb WzOs/TiOz SCR catalyst. Type A catalyst was catalyst

typically applied at coal-fired power plants, Type B was a "bio-optimized" catalyst with

increased vanadium content, and Type C had an even higher vanadium content.

For a mixture of peat and 15% wood, the flue gas contained 4.4 mg/Nm3 of potassium

and 0.8 mg/Nm3 ofsodium aerosols with an aerodynamic particle diameter less than 0.1

micrometers.

Potassium (mg/Nm3

)

Sodium (mg/Nm3

)

Peat + 15% Wooda

4.4

0.8

Center Ligniteb

0.20

0.78

a

b

As chloride

As sulfate

The maximum deactivation rate was 12% in 768 hours using Type A catalyst. Another

result indicated 15% deactivation in 1488 hours using Type B catalyst. The shorter test

24
result on peat plus 15% wood indicates 6400 hours to 100% deactivation while the longer

test result indicates 9920 hours to 100% deactivation. Regarding the deactivation rates,

Kling et.ae stated "Exposure of this kind of short samples gives a larger deactivation

compared to a full-length catalyst [1, 4] that is mainly a consequence ofturbulence ofthe

inlet ofthe catalyst, before laminar flow is attained."

The sodium concentration in the flue gas after the wet scrubber from Center lignite is

similar to that of the peat plus 15% wood; however, the potassium content is

approximately 17 times lower. It appears the catalyst life for an SCR at M.R. Young

Station should be substantially longer than that estimated for peat plus 15% wood.

Zheng et.a!.3 found a deactivation rate of 0.4% per day for potassium sulfate or 6000

hours to 100% deactivation. The testing was conducted at a loading of 20-30 mglNm3

.

The aerosols varied in size from 0.07 micrometers to 1.05 micrometers with a mass mean

diameter of 0.55 micrometers. The Markowski data indicates that approximately 53% of

outlet sulfate was less than or equal to 0.52 micrometers. Based on the latest stack tests

at M.R. Young Unit 2, this equates to·a total emission rate of approximately 1.4 mglNm3

for those sodium and potassium sulfate aerosols less than 0.52 micrometers. The

Minnkota emission rate is substantially less (14-21 times) than the Zheng testing.

The above results do not consider the fact that potassium is a more potent catalyst poison

than sodium and chlorides are more potent than sulfates. These facts make it even more

likely that the catalyst life will be longer than the testing indicated by Kling2 and Zheng3

25
since Center lignite combustion at MRYS produces primarily sodium sulfate aerosols

while biomass combustion produces primarily potassium chloride aerosols.

For a LDSCR application, the only air pollution control device prior to SCR will be a dry

electrostatic precipitator (ESP). Stack test results from the FINE Particles - Technology,

Environmental and Health Technology Programme 13 suggests that an ESP on a biomass

boiler will have a control efficiency of greater than 90% for submicron particles and can

achieve greater than 96% for particles less than 0.1 micrometers in size. This is

consistent with AP_42 12 data for Kraft recovery boilers which indicates an ESP can

remove more than 98% of the submicron particulate matter in the flue gas which is

primarily sodium sulfatel4. Similar results are reported for coal-firedlbiomass boilers by

Mohrl5 , Lindl6 and the Power Station Emissions Handbook17 . This indicates that most of

the submicron sodium and potassium aerosols, including those aerosols less than 0.1

micrometers in size, will be removed by the electrostatic precipitators at MRYS.

Minnkota has submitted data on the ash composition that accumulated on the electrodes

ofthe Power Span ECO electrodes during a pilot testll (p. 26). The data suggests that the

sodium and potassium concentration in the particulate matter downstream of the Unit I

ESP is higher than the concentration in the particulate matter downstream of the Unit II

wet scrubber. However, the concentration is less than a factor of two higher. The total

loading ofsodium and potassium, as indicated by the data submitted by Minnkota, would

still be considerably less than the loadings in the Kling2 and Zheng3 tests. This suggests

26
that the catalyst deactivation rate of a LDSCR at MRYS should be lower than in the

referenced tests.

D. Vendor Information

The U.S. Department of Justice, through their contractor Mr. Hans Hartenstein, has

provided emails from various catalyst and SCR system providerslO (Appendix D). Each

of the responses from the vendors indicated that tail end SCR is technically feasible for

the Milton R. Young Station.

The Department contacted three of the vendors, Ceram Environmental, Haldor Topsoe

and Babcock Power. The companies generally confirmed the information in the emails to

Mr. Hartenstein. Babcock Power indicated they had no worries about getting 10,000

hours of catalyst life at the M.R. Young Station. However, they recommended "coupon"

testing prior to design of the SCR. Ceram was convinced it was technically feasible;

however, their representative did acknowledge that if the sodium and potassium aerosols

are making it through the ESP and wet scrubber, catalyst deactivation could be a

problem. Haldor Topsoe indicated that the catalyst deactivation at M.R. Young would be

manageable if the catalyst is kept dry during outages. Although no written guarantees

have been provided by the vendors, it appears that vendors are willing to provide them

for a tail end SCR at the M.R. Young Station.

27
E. Biomass Facilities using LDSCRJTESCR

There are no boilers that combust North Dakota lignite and are equipped with SCR

technology. LDSCR and TESCR has been applied to coal-fired boilers in Europe, Asia

and the United States. However, in general, other U.S. coals are much lower in the

organically associated alkalis that cause SCR catalyst deactivation. Biomass fired boilers

have flue gas characteristics that more closely approximate those from North Dakota

lignite. At least four biomass boilers that are equipped with tail end or low dust SCR are

currently in operation in the United States. The boilers are spreader stoker design and use

an electrostatic precipitator as the primary particulate matter control device. These

include:

• Whitefield Power & Light, New Hampshire - Boiler uses whole tree chips and

has operated since October 2004.

• Bridgewater Power, New Hampshire - Boiler uses whole tree chips and has

operated since October 2007.

• Pine Tree Power, New Hampshire - Biomass combustion.

• Boralex Stratton, Maine - Boiler uses whole tree chips, waste wood, and

construction and demolition waste. The boiler has operated since December

2004.

28
The Department is also aware of proposed TESCR or LDSCR installations at the

Burlington Electric Plant in Vermont, Synterprise Global Solutions in Tennessee and the

Amager Heat and Power Plant near Copenhagen, Denmark. The Amager Station is also

allowed to bum coal and may not be required to operate the TESCR when combusting

biomass.

Although there are boilers that combust 100% biomass and utilize LDSCR for NOx

control, there is no information about the actual loading of potassium and sodium

aerosols at the inlet to the SCR. The New Hampshire Department of Environmental

Services (NHDES) was contacted regarding the biomass boilers that use LDSCR. The

Whitefield Power Plant is a 16 MWe spreader stoker that is equipped with a multiclone

and electrostatic precipitator for particulate matter control. The NHDES confirmed the

boiler had been operating for approximately four years. NHDES was not aware of any

catalyst dea~tivation problems at this facility. The plant has a NOx emission limit of

0.075 Ibll06 Btu. The other facilities in New Hampshire are similar; however, they have

not operated as long. No data was available regarding the loading of potassium and

sodium at the inlet ofthe SCR.

F. Conclusions

In the June 2008 Preliminary Best Available Control Technology Determination for

Control of Nitrogen Oxides for M.R. Young Station Units 1 and 2, the Department

29
concluded that an SCR system must have a catalyst life of at least 10,000 hours before

SCR technology could be deemed successfully applied to the source. The life of the

catalyst will depend on many factors including the reduction efficiency required, the

allowable ammonia slip, the volume of catalyst used, the plant load variability, the coal

flue gas characteristics, the makeup of the catalyst (e.g. high vanadium catalyst will last

longer than a catalyst with a lower vanadium content), the design of the reactor system,

the number of catalyst layers, the catalyst management plan, and other factors. The

catalyst could be replaced when deactivation has reached 50% or less or it could be

replaced at a higher deactivation point depending on the system's ability to meet the

regulatory requirements for the NOx emission rate and/or ammonia slip rate.

No data has been found from an actual operating facility which has similar flue gas

characteristics to M.R. Young Station that use high dust, low dust or tail end SCR.

However, experimental and pilot scale testing by Kling2 and Zheng3 provides empirical

data for comparison. The total sodium and potassium loading of aerosols less than 0.1

micrometers expected at the inlet of a TESCR at M.R. Young Station is expected to be at

least 5 times less than found in the Kling tests on peat plus 15% wood. Kling's data

indicated up to 9920 hours before 100% deactivation for catalyst type B. Zheng's3 data

suggested 6,000 hours before 100% deactivation when exposed to potassium sulfate

aerosols with an mean diameter of 0.55 micrometers at a concentration which is 14-21

times higher than the concentration of sodium and potassium aerosols of this size

expected after a wet scrubber at M.R. Young Station. The loading at a low dust location

would also be substantially less than the loading in the Kling or Zheng tests. Kling2 also

30
pointed out that the testing probably over estimates the deactivation rate because of

turbulence in the pilot scale inlet of the catalyst which would be more laminar in a full

scale SCR.

Existing biomass boilers are using LDSCR successfully. Although the boilers are not

cyclone fired units, the New Hampshire units use similar PM control devices as M.R.

Young Station (i.e. ESP). The potassium chloride emitted from the biomass boilers is a

much more potent catalyst poison than the sodium sulfate emitted at the MRYS. The

Whitefield Plant has operated for more than four years without deactivation problems.

Kling2 has referred to "bio-optimized" catalyst and higher vanadium catalysts that

appears to have a longer life than the typical coal-fired boiler SCR catalyst for a given

concentration of sodium and potassium aerosols. A bio-optimized catalyst (high

vanadium content) will be installed at the Amager Station6 (p. 13). Vendors believe that

TESCR is technically feasible and can be successfully applied at M.R. Young Station.

Based on the empirical data available at that time, vendor information that TESCR is

feasible at the M.R. Young Station and the use of low dust SCR on biomass fired boilers,

the Department concludes that tail end and low dust SCR appear to be technically

feasible at M.R. Young Station.

31
References

1. Minnkota Power Cooperative; 2008 Comments and Responses to NDDH Regarding U.S.

EPA Region 8's July 31,2008 Comments and Plains Justice July 30, 2008 Comments for

NDDH Preliminary NOx BACT Determination for Milton R. Young Station (MRYS)

September 22,2008.

2. Kling, Asa; Andersson, Chester; Myringer, Ase; Eskilsson, David; Jaras, Sven G.; Alkali

deactivation of higher dust SCR catalysts used for NOx reduction exposed to flue gas

from 100 MW-scale biofuel and peat fired boilers: Influence of flue ga;s composition;

Applied Catalysis; 2007.

3. Zheng, Yuanjing; Jensen, Anker Dega; Johnsson, Jan Erik; Thogersen, Jaokim Reimer;

Deactivation of V205 - W03 - Ti02 SCR catalyst at biomass fired power plants;

Elucicdation of mechanisms by lab - and pilot-scale experiments; Applied Catalysis;

2008.

4. 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.

5. Minnkota Power Cooperative, Inc.; Supplemental Information for Consideration

Regarding NOx BACT for M.R. Young Station Units 1 and 2: Technical Feasibility

Issues for TESCR and LDSCR Retrofit; February 20,2009.

6. Crespi, Mario; Porle, Magnus; Larsson, Dr. Ann - Charlotte; La Civita, Raffaela;

Nielsen, Anders Rooma; The influence of biomass burning in the design of an SCR

installation.

7. Hartenstein, Hans; Hans Hartenstein's Thoughts on Kling paper; April 9, 2009.

8. NDDH, Analysis ofthe potency of potassium oxide versus sodium oxide; May 1,2009.

9. EPA, 1990 New Source Review Workshop Manual, Preventing Significant Deterioration

and Non-attainment Area Permitting, Office of Air Quality Planning and Standards,

Research Triangle Park, NC 27711.

10. Hartenstein, Hans; Feasibility of SCR Technology for NOx Control Technology for the

Milton R. Young Station, Center, North Dakota; July 2008.

32
11. Minnkota Power Cooperative; 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.

12. EPA, 1995 Compilation of Air Pollution Emission Factors Volume 1: Stationary Point

and Area Sources, Office ofAir Quality Planning and Standards, Research Triangle Park,

NC 27711.

13. Ohlstrom, Mikael; Jokinieme, Jorma; Hokkinen, Joumi; Makkonen, Pasi; Tissari, Jakko;

Combating Particulate Emissions in Energy Generation and Industry; VTT Technical

Research Centre ofFinland; 2006.

14. Lind, T., Hokkinen, J.; Jokiniemi, J.K.; HiIlano; R; Makkonen, U; Raukola, A.;

Rintamen, J; Saviharju, K; Electrostatic Precipitator Performance and Trace Element

Emissions from Two Kraft Recovery Boilers; Environmental Science and Technology;

January 15, 2006.

15. Mohr, Martin; Yiatalo, Ni; Klippel, E.!.; Kauppinen, O. Riccius; Burtscher, H.;

Submicron Flay Ash Penetration Through Electrostatic Precipitators at Two Coal Power

Plants, Aerosol Science and Technology, 1996.

16. Lind, Terttaliisa; Hokkinen, Joumi; Jokinemi; Jonna K; Electrostatic Precipitator

Collection Efficiency and Trace Element Emissions from Co-Combustion of Biomass

and Recovered Fuel in Fluidized Bed Combustion; Environmental Science and

Technology; 2003.

17. Power Station Emissions Handbook; www.ccsd.biz/PSE Handbook/5/6/5 index.efrn

33
Appendix A

Analysis of Unit II

Stack Test Filter

34
MINNKOTA UNIT 2

FILTER ANALYSIS

ELEMENT % OF ELEMENT MOLECULAR MOLES a

ON FILTER WEIGHT

Na 6.56 23.0 0.285

K 2.26 39.1 0.058

S 5.71 32.1 0.178

0 57.52 16.0 3.595

a BASED ON 100 GRAMS OFPM

0.285 MOLES OF SODIUM AVAILABLE . .

NEED (0.285/2)*(1) MOLES OF SULFUR =0.142 MOLES

NEED (0.285/2)*(4) MOLES OF OXYGEN =0.570 MOLES

TOTAL wr. Na2S04 =(23)(0.285) + (32.1)(.142) + (16)(.570) =20.2 grams

POTENTIAL Na2S04 = 20.2 g/100 g *100% == 20.2%

0.058 MOLES OF POTASSIUM AVAILABLE

NEED (0.058/2)(1) MOLES OF SULFUR =0.029 MOLES

NEED (0.058/2)(4) MOLES OF OXYGEN =0.116 MOLES

TOTAL WEIGHT K2S04 =(39.1)(.058) + (0.029)(32.1) + (16)(.116) =5.05 grams

POTENTIAL K2S04 = 5.05%
the strands. These particles are rich in sodium and sulfur as compared to the filter materials.

Figure 18 shows a region ofthe filter that was not exposed to flue gas and the fiber stands do

not have particles bonded to the sUrfaces.

Table 5. Morphological analysis results for filter sample 001.

Results· expressed as wei~ht percent on an elemental basis.

Fig. J;»tIAr.~a ~escription Na Mg Al Si S Cl .K Ca Ti Fe Ba 0

14 " 1* Overallarea,-lOOx 5.98 1.83 2.62 to.85 3.80 0.00 2.29 lUO 0.00 2.31 0.00 59.21

2* Overall area - lOOx 5.95 2.40 2.82 lO.93 5.42 0.00 2.25 11.30 0.40 2.46 0.00 56.07

3* Overallarea-lOOx 7.311.992.238.737.380.002.289.860.001.11 0.0059.10

4* Overall area - lOOx 5.66 2.54 2.20 9.47 5.27 0.00 2.54 10.08 0,00 3.05 1.65 57.56

5 Light particle 1.21 3.33 5.47 7.65 1.38 0.00 1.40 13.44 0.00 6.76 1.85 57.52·

6 Dark particle 6.40 9.79 1.47 10.75.6.24 0.00 3.76 7.84' O~OO ·1.96 0.00 52.68

7 Light particle 0.57 3.99 7.49 8.94 1.74 0.19 U5 15.670.43 3.83 0.00 56.01'

8 Ovenill area - 100x 8.50 2.62 2.45 10.04 6.81 0.00 2.12 9.26 .0.50 2.40 0.00 55.30

9 Overall area - lOOx 5.95 1.97 2.64 11.03 5.58 0.00 .2.09 10.21 0,86 1.78 0.00 57.90

10 Light particle 0~78 4.20 6.78 11.26 0.00 0.00 1.24 15.37 0.00 3.70 5.10 51.56

11* Blank edge offilter 0.00 0.93 5.11 20.20 0.00 0.00·0.93 13.83 (}.OO ·,().OO 0.00 59.00·

12* Blank eqge offilter 0.00 1.19 4.95 19.69 0.00 0:00 i.l6 16.52 0.00 0.59 0:00 55.91

. 15 13 Small, light particles 3.00 3.30 3.10 7.72 2.91 0.00 1.40 1"1.02 0.00' 3.49 1.89 62.18

14 SmaIl bonded particles 2.93 1.25 1.02 10.04 6.99 0.00 4.0629.33 0.00 5.38 2.93 36.08

15 Largedarkpartic1e 10.25 9.68 0.00 1.41 22.60 0.00 3.74 2.16 0.00 0.00 0.00 50.15

. 16 Large dark particles 13.40 11.82 0.00 1.30 10.30 0.00 2.28 0.96 0.00 2,17 0.00 57.78

17 Small bonded particles 4.39 3.56 2.17 10.95 6.88 0.00 2.77 14.020.51 2.83 0.00 51.92

18 Smllil bonded particles 1.49 2.82 5.86 10.45 4.93 0.00 3.19 26.01 1.19 8.23 0.00 35.84

Overall areas 6.56 2.23 2.49 10.17 5.71 0.00 2.26 10.30 0.29 2.18 0.27 57.52

Light"particles 1.39 3.71 5.71 8.89 1.51 0.05 1.30 13.88 0.11 4.442.21 56.82

Average Dark particl~ 10.0210.43 0.49 4.49 13."OS O~OO :t26 3.65 0.00 1.08 0.00 53.54

Small bonded particles 2.94 Z.54 3.02 10.48 6.27 0.00 3.34 23.12 0.57 5.48 0.98 41.28

Filter edge 0.00 1.06 5.03 19.94 0.00 0.00 1.04 15.18 0.00 0.30 0.00 57.46

* = areas not speCifically noted or shown in electron micrograph Figure 14.

Minnkota Power Cooperative, Inc. 20 Bums & McDonnell
Appendix B

Calculation of Emissions Rate

For

M.R. Young Station

35
MINNKOTA

STACK TEST RESULTS

UNIT DATE OF TEST PM OXYGEN PM PM PM

EMISSION.RATE CONTENT EMISSION RATE EMISSION RATE EMISSION RATE

(gr/dscf) (%) (mg/m3

) (mg/Nm3

) • (mg/Nm3

)

at 6%02

1 6/9/2008 0.0026 8.6 5.95 6.39 7.74

1 8/29/2007 0.0031 5.9 7.09 7.61 7.56

AVERAGE 0.00285 7.25 6.52 7.00 7.65

2 5/7/2008 0.0042 7.4 9.61 10.32 11.38

2 08/28/2007 0.0039 6.4 8.92 9.58 9.84

AVERAGE 0.00405 6.9 9.27 9.95 10.61

a ADJUSTED TO 0 0 C

TAILENDSCR

FROM FILTER ANALYSIS Na =6.56% OF PM AND K =2.26%.

IF ALL Na AND KIS SULFATE FORM, Na2S04 =20.2% AND K2S04 =5.05% OF PM.

UNIT DATE OF TEST POTENTIAL Na2S04 POTENTIAL K2S04 EQ. K2S04 b EQ. K2S04 b,c EQ. KCI c,d

EMISSION RATE EMISSION RATE EMISSION RATE EMISSION RATE EMISSION RATE

(mg/Nm3 ) (mg/Nm3

) (mg/Nm3) < 0.52 um < 0.26 um

(mg/Nm3

) (mg/Nm3)

1 6/9/2008 1.56 0.39 1.59 0.85 0.23

8/29/2007 1.53 0.38 1.56 0.83 0.23

AVG. 1.55 0.39 1.57 0.84 0.23

2 5/7/2008 2.30 0.57 2.34 1.24 0.34

2 08/28/2007 1.99 0.50 2.03 1.08 0.30

AVG. 2.14 0.54 2.19 1.16 0.32

b BASED ON CRESPIDATA INDICA TING POTASSIUM IS1.3 TIMES MORE POTENTCATALYSTPOISON THAN SODIUM ON A MASS BASIS.

C BASED ON MARKOWSKI DATA THATINDICATES53.1% OFSULFATEIS LESS THAN 0.52 urn AND 36.5% ISLESS THAN 0.26 urn.

d BASED ONZHENG'S DATA THATINDICATED A DEACTIVA TION RA TE OF1% PER DA Y FOR KCfAND 0.4% PER DA Y FOR K2 SO4'

ZHENG TO MINNKOTA LOADING RATIO = (20-30 mg/Nm3)/(1.16 mg/Nm3

) = 17.2 TO 25.9

KUNG (PEAT + 15% WOOD) TO MINNKOTA LOADING RATIO = (4.4 + 0.8/1.3 mg/Nm3)/(O.32 mg/NmJ

) =15.7

NOTE: THISIS CONSERVATIVESINCE LESS THAN 36.S% OFSULFATEATMINNKOTA WILL PROBABLY HAVEA DIAMETER OF0.1 urn

OR LESS.
MINNKOTA POWER COOP.

UNIT 2

HIGH DUST SCR

AVG.

EMISSION RATE

(Ib/dscf)

AVG.

EMISSION RATE

(mg/Nm3

)

Na20

3.051E-05

524

K20

9.014E-06

155

EO. K20 a

3.248E-05

558

EO. K2S04 b

6.013E-05

1034

EO. KCI C

2.405E-05

413

EQ.KCL d

« 0.1 urn)

1.203E-05

207

i1 BASED ON CRESPI DATA WHICH INDICATESK 20 IS1.3 TIMES MOREPOTENT CATALYSTPOISON THATNa 20 ONA MASSBASIS.

/, BASED ONA MOLECULAR WEIGHTOF94FOR K 20AND 174 FOR K 2S04 AND ASSUMINGALL Na & K ISINSULFATEFORM.

C BASED ONZHENG'S DATA THATINDICATED A DEACTIVATION RATE OF1% PER FOR DAYFOR KCfAND 0.4% PER DA YFOR K 2S04'

d BASED OON SO% OFAEROSOLSLESS THAN 0.1 MICRONSINSIZE.

MINNKOTA TO ZHENG LOADING RATIO =(1034 mg/Nm3 )*0.50/(20-30 mg/Nm3 ) =25.9 TO 17.2

MINNKOTA TO KLING LOADINGRATIO (BARK + 30% DEMOLITION WOOD) = (207mg/Nm 3 ) / (16.7 + 5.8/1.3) =..£6
Appendix C

Analysis of NazO and KzO

Poisoning Potency

36
DEPARTMENT ANALYSIS

Na20 and K20 DEACTIVATION POTENCY

100

80,

20

0.5 1 1.5

Me: V molar ratio

2

CONTAMINANT RELATIVE MOLAR Na20jK2O

ACTIVITY RATIO MOLAR RATIO

Na20 30% 0.55

2.20

K20 30% 0.25

Na20 40% 0.42

2.00

K20 40% 0.21

Na20 60% 0.25

1.79

K20 60% 0.14

AVERAGE 2.00
Appendix D

Vendor Infonnation

Tail End SCR

37
Appendix B: SCR Vendor Query Correspondence

1. Vendor Correspondence with SCR system suppliers

1.1 E-Mail correspondence with Clay Erickson, Babcock Power (SCR System

Vendor - extensive tail-end SCR experience)

From: cerickson@babcockpower.com [mailto:cerickson@babcockpower.com]

Sent: Thursday, June 19, 2008 15:59

To: Hans Hartenstein·

Cc: jlangone@babcockpower.com; tlicata@babcockpower.com

Subject: Re: Tail-end SCR

Hans,

Babcock Power has reviewed the Milton Young plant in the past, based on these reviews Babcock

Power finds

o A tail-end SCR is technically and commercial feasible

o Babcock Power does not recommend or require additional pilot testing only proper flue gas

characterization as with any SCR system per performed

o Will provide commercial guarantees for the SCR and catalyst performance (activity,

pressure drop and SOz/S03conversion rate) and lifetime .

Babcock Power has the largest SCR experience list in the world; from this experience we are

completely confident in the application of a tail end system at Milton Young. If you have further

questions please let me know.

With best regards,

Clay

Clayton Erickson, PhD

Director, Process Engineering

Babcock Power Inc.

5 Neponset Street

Worcester, MA 01606

T: 508-854-4039 F: 508-854-1177

M: 508-245-2383

From: "HansHartenstein"<Hans.Hartenstein@Evonik-EnergyServices.us>

. Sent: 06/18/2008 12:16

To: <cerickson@babcockpower.com>

Subject: Tail-end SCR

Clay,

As discussed during our phone conversation today, during which you stated that Babcock Power

considers a high-dust SCR principally, technically feasible even though not without technically

resolvable challenges for Minnkota's Milton R. Young Station, I would also be interested in Babcock

Power's position' on the technical feasibility of a tail-end SCR (downstream of a wet scrubber including

A- 57
flue gas reheat) Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber)

and the fuel (NO lignite), would Babcock Power:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure

drop and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones built by your licensor Fisia Babcock

(most of which are on wet bottom boilers) went into operation in the late 1980s and most of them still

operate on the initial fill of catalyst after almost 20 years and up to 130,000 operating hours, I would

assume that Babcock Power 1Fisia Babcock has sufficient confidence in your tail-end SCR

experience to competently respond to these questions. Please let me know if you have any additional

questions. Thanks.

Best regards,

Hans Hartenstein

1.2 E-Mail Correspondence with Don TODn, Babcock & Wilcox (SCR System

Vendor - no tail-end SCR experience)

From: Tonn, Donald P [mailto:dptonn@babcock.com]

sent: Monday, June 23,2008 16:06

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans:

Please note my responses to your questions in the referenced email below.

Regards,

Donald P. Tonn

Babcock & Wilcox Power Generation Group

.AQCS Technology

Phone 330-860-1986

Cell 330-289-7795

From: Hans Hartenstein [mailto: Hans.Hartenstein@Evonik-Energy5ervices.us]

sent: Wednesday, June 18, 2008 13:25

To: Tonn, Donald P

Subject: Tail-end SCR

Don,

As discussed during our phone conversation today, during which you stated that Babcock & Wilcox

considers a tail-end SCR (downstream of a wet scrubber including flue gas reheat) principally

technically feasible for Minnkota's Milton R. Young Station, I would be interested in Babcock &

Wilcox's position on the following questions. Given your knowledge about the plant (cyclone-fired

B&W boilers, ESP, wet scrubber) and the fuel (NO lignite), would Babcock & Wilcox:

Consider a tail-end SCR technically feasible? Yes

Recommend or require additional pilot testing? Requires further discussion with catalyst

suppliers.

A- 58
Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be? While B&W has

considered tail-end SCR systems on other projects we have not had these commercial

guarantee discussions with the catalyst suppliers for the North Dakota lignite application.

Before consideration of providing these guarantees a comfort level would be required after

obtaining guarantees from catalyst suppliers.

Given the fact that tail-end SCRs in Germany went into operation in the late 1980s and most of them

still operate on the initial fill of catalyst after almost 20 years and up to 130,000 operating hours, I

would assume that Babcock & Wilcox has sufficient confidence in tail-end SCR systems to

competently respond to these questions. Please let me know if you have any additional questions.

Thanks.

Best regards,

Hans Hartenstein

2. Vendor Correspondence with SCR Catalyst Manufacturers

2.1 E-Mail Correspondence with Cindy Khalaf, Argillon (Cataiyst Manufacturerextensive tail-end SCR experience)

From: Khalaf Cindy R [mailto:cindy.khalaf@argillon.com]

Sent: Tuesday, June 24 2008 14:15

To: Hans Hartenstein

Subject: Re: Argillon Tail-end SCR

No problem.

Regards,

Cindy

From: Hans Hartenstein <Hans.Hartenstein@Evonik-EnergyServices.us>

Sent: Tuesday, June 24,2008, 16:45

To: Khalaf Cindy R

SUbject: RE: Argillon Tail-end SCR

Cindy,

Thanks a bunch for taking the time to respond. I greatly appreciate your answer. I'll keep you posted

where this thing is going.

Best regards,

Hans Hartenstein

http://www.evonik-energyservices.us

From: Sadler Randy (mailto:randy.sadler@argillon.comJ

Sent: Tuesday, June 24,200808:15 AM

A-59
To: Hans Hartenstein

Cc: Khalaf Cindy R

Subject: Argillon Tail-end SCR

Importance: High

On behalf of Cindy Khalaf -

Hans,

Further to our phone call, as far as I know, Argillon has more tail end experience than any other SCR

catalyst manufacturer and, as you noted, we also have experience with high dust, German lignite

SCRs. Argillon also won the first US lignite SCR catalyst project (Luminant Oak Grove 1 & 2) and

provided commercial guarantees. These units are not in service yet. So, yes, we consider ourselves

able to answer these questions competently.

Consider a tail-end SCR technically feasible?

Yes, we consider this configuration to be technically feasible. As you know, tail end SCRs are often

used when there are significant catalyst poisons in a flue gas stream. A wet scrubber can remove

most of these poisons, resulting in very low catalyst deactivation.

Recommend or.require additional pilot testing?

For a high dust configuration, we would say definitely. For a tail-end configuration, We would say no.

We would only like to see a flue gas analysis for conditions atthe inlet to the SCR in order to predict

deactivation rate.

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop and

S02/S03 conversion rate) and lifetime? If so what would these be?

Generally speaking, yes, we would provide guarantees for DeNOx & slip as specified (not to exceed

90% or 2 ppm), 24k hours life, S02 conversion rate - low but value TBD, pressure drop - value TBD.

Of course we would have to see the technic,al specifications before being more specific. In addition,

tail-end SCRs perform much longer, so depending on the application specifics, customer, etc., we

may decide to extend the operating life guarantees. This is a commercial decision and will be

reviewed on a case-by case basis. .

If you have any more questions, please let me know.

Regards,

Cindy

Cindy R. Khalaf

Argilloil LLC

President

Tel: 678.341.7520

Mobile: 770.331.9571

FAX: 678.341.7509

Email: cindy.khalaf@argillon.com

5895 Shiloh Road, Ste. 101

Alpharetta, GA 30005

From: Hans Hartenstein [mailto:Hans.Hartenstein@Evonik-EnergvServices.usJ

Sent: Thursday, June 19, 2008 16:29

A- 60
To: Khalaf Cindy R

Subject: Tail-end SCR

Cindy,

As discussed during our phone conversation today, during which you stated that Argillon considers a

high-dust SCR principally technically, feasible based on your high-dust SCR experience with lignite

fired units in Europe even though not without technically resolvable challenges for Minnkota's Milton

R. Young Station, I would also be interested in Argillon's position on the technical feasibility of a tail-

. end SCR (downstream of a wet scrubber including flue gas reheat). Given your knowledge about the

plant (cyclone-fired B&W boilers, ESP,wet scrubber) and the fuel (ND lignite), would Argillon:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalystperformance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones equipped with Argillon catalyst went

into operation in the late 1980s and most of them still operate on the initial fill of catalyst after almost

20 years and up to 130,000 operating hours, I would assume that Argillon has sufficient confidence in

your tail-end SCR experience to competently respond to these questions. Please let me know if you

bave any additional questions. Thanks.

Best regards, .

Hans Hartenstein

2.2 E-Mail Correspondence with John Cochran, CERAM Environmental (Catalyst

Manufacturer - extensive tail-end SCR experience)

From: John Cochran [mailto:John.Cochran@ceram-usa.com]

Sent: Wednesday, June 25,200815:14

To: Hans Hartenstein

Cc: Greg Holscher; Noel Rosha; OrehovskyKurt

Subject: RE: Request for Information

Hans,

CERAM certainly considers the use of a tail"end SCR on applications such as the Milton R. Young

Station as technically feasible provided a proper design approach is used. CERAM has the

experience from more than 100 tail-end and low dust applications dating from 1988 that would

substantiate our opinion. For a tail-end approach we see no need for additional pilot testing. As

such, we can provide full commercial guarantees for catalyst performance (activity or lifetime,

conversion rate, pressure drop, etc.).

The choice between high dust and tail-end processes certainly should consider capital costs,

operating costs and process risk. Based on our experience certainly process risk would favor a tailend approach, but albeit for most circumstances at a higher "all-in" cost. Should very high retrofit

factors be present for a high dust arrangement then the relative economic factors may even favor a

tail-end approach.

I hope this information is useful to your evaluation. Please advise should you have any further

A- 61
questions or information needs. Thanks.

Best Regards,

John Cochran

CERAM Environmental, Inc.

wwwJrauenthal.net

913.239.9896 (phone)

913.205.5615 (cell)

This e-mail and any attachments are confidential. If you have received this electronic transmission in error, please reply to the sender

regarding the error and permonently. delete the original message and any attachments.

~------------------------------------------------------------------------------------------------------------------------------------

From: Hans Hartenstein [mailto:Hans.Hartenstein@Evonik-EnergyServices.us]

sent: Tuesday, June 17, 2008 7:20

To: John Cochran

Subject: Request for Information

John,

As discussed during our phone conversation today, during which you stated that CERAM considers a

high-dust SCR principally technically, feasible even though not without technically resolvable

challenges for Minnkota's Milton R. Young Station, I would also be interested in CERAM's position on

the technical feasibility of a tail-end SCR (downstream of a wet scrubber including flue gas reheat)

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel

(ND lignite), wouid CERAM:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones equipped with·CERAM catalyst

(Herne 1, 2 and 3, Voerde (West) 1 and 2, LOnen 10 and 11 - all ofwhich are wet bottom boilers)

went into operation in the late 1980s and most of them still operate on the initial fill of catalyst after

almost 20 years and up to 130,000 operating hours, I would assume that CERAM has sufficient

confidence in your tail-end SCR experience to competently respond to these questions. Please let me

know if you have any additional questions. Thanks.

Best regards,

Hans Hartenstein

2.3 E-Mail Correspondence with Scot Pritchard, Cormetech (Catalyst

Manufacturer - no tail-end SCR experience)

From: Pritchard, Scot G. [mailto:PritchardSG@Cormetech.com]

Sent: Thursday, June 19, 2008 17:41

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans,

A- 62
I was thinking of if you put a coupon in the tailend location and it showed something weird then you

would have to do something more elaborate Le. A slipstream with longer hours, etc.. We do not

anticipate this - in fact you could probably do without the coupon test as well since I don't see any

reason why this system would be any different the primary tail end experience Le. Unlikely any

nasties make it through the lower temperature environment and scrubber process. The coupon is OK

but I really don't expect to see much. Finally, we have not done any specific coupon tests (because

slipstream has been the primary way to evaluate) so we would need to think through the best way to

do it - Le. holder, mounting arrangement, test method, hours of exposure, etc. If you already have

something in mind please let uS know.

Hope that helps with the clarification.

Scot

From: "Hans Hartenstein" <Hans.Hartenstein@Evonik-EnergyServices.us>

Sent: thursday, 6/19/08 4:26 pm

To: "Pritchard, Scot G." <PritchardSG@Cormetech.com>

Subject: RE: Tail-end SCR

Scot,

Thanks for the input from Cormetech, which is greatly valued. One question for clarification purposes

only, though. Coupon tests and/or flue gas analysis would only be performed in order to characterize

the flue gas going into the tail-end SCR as is needed for the design of any APC equipment. Obviously,

nobody could offer any performance guarantees concerning what's coming out of a tail-end SCR

without knowing. what's going into it. You state that in case coupon tests would show a significant

accumulation of catalyst poisons, a subsequent slip stream test, which is unquestionably more

accurate and representative of a full scale - in this case tail-end - SCR, would be recommended.

Stating this, do I understand you right that you would recommend this slip stream testing mainly for the

purpose of properly characterizing the flue gas composition at the inlet to the tail-end SCR in order to

provide a reliable basis for correct catalyst design? Do I assume correctly, that you would not require

extensive and long-term (12 - 24 months) pilot testing with a slip stream reactor because you have

serious doubts about the principal technical feasibility of a tail-end SCR for this application? Please

clarify. Thanks. .

Best regards,

Hans Hartenstein

From:Pritehard, Scot G. [mailto:PritchardSG@Cormetech.com]

Sent: Thursday, June 19, 2008 12:15

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans,

Please see my input below.'

As discussed during our phone conversation today, during which you stated that Cormetech considers

a high-dust SCR principally technically, feasible even though not without technically resolvable

challenges for Minnkota's Milton R. Young Station, I would also be interested in Cormetech's position

on the technical feasibility of a tail-end SCR (downstream of a wet scrubber including flue gas reheat)

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel

(NO lignite), would Cormetech:

Consider a tail-end SCR technically feasible? - yes

A- 63
Recommend or require additional pilot testing? - We generally do not consider coupon testing

an accurate representation of an SCR, however in order to minimize cost and provide basic

screening information we would suggest the potential use of a coupon sample test. If the

coupon shows significant accumulation of catalyst poisons, a subsequent slipstream type test

which is more representative of a full scale SCR i.e match velocity, AVs, etc. would be

recommended.

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and SOiS03 conversion rate) and lifetime? If so what would these be? Presuming the

coupon test does not sholN anything unusual (which we do not expect to see anything

unusual) we would be willing to provide commercial guarantees for a low dust application.

Basic guarantees would be associated with life (this would not include specific Ko and KlKo

as guarantees - the guarantee would be an efficiency and slip guarantee at a certain number

of operating hours ), S02 conversion, pressure loss.

As discussed, the high dust application needs additional due diligence testing (slipstream, ash testing,

etc.) as well as the practicality of the applicable operating temperature to establish the commercial

stance for a high dust application on North Dakota Lignite. We have done such work for Texas lignite

as well as other coal sources and other fuels/applications in the past and would expect to be able to

achieve the same for this application. The economics for any given application would be considered

on a case by case basis:

Let me know if you have any questions. Also I would appreciate anything of the final document that

you can share.

Thank you and regards,

Scot Pritchard

VP, Sales & Marketing

Cormetech

919-595-87080

919-815-2380 c

Frain: Hans Hartenstein [mailto:Hans.Hartenstein@Evonik-EnergyServices.us]

sent: Thursday, June 19, 2008 11:35 AM

To: Pritchard, Scot G.

Subject: Tail-end SCR

Scot,

As discussed during our phone conversation today, during which you stated that Cormetech considers

a high-dust SCR principally technically, feasible even though not without technically resolvable

challenges for Minnkota's Milton R.Young Station, I would also be interested in Cormetech's position

on the technical feasibility of a tail-end SCR (downstream of a wet scrubber inclUding flue gas reheat)

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel

(NO lignite), would Cormetech: .

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and SOiS03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany (most of which are on wet bottom boilers) went into

operation in the late 1980s and most of them still operate on the initial fill of catalyst after almost 20

years and up to 130,000 operating hours, I would assume that Cormetech has sufficient confidence in

tail-end SCR systems to competently respond to these questions. Please let me know if you have any

additional questions. Thanks.

A- 64
Best regards,

Hans Hartenstein

2.4 E-Mail Correspondence with Flemming Hansen, Haldor Topsoe (Catalyst

Manufacturer - extensive tail-end SCR experience)

From: Flemming Hansen [mailto:FGH@topsoe.com]

sent: Friday, June 27, 2008 12:56

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans,

Your understanding is what I meant to say.

Thanks

Flemming G. Hansen

Manager SCR DeNOx Catalyst

Haldor Topsoe, Inc.

281-228-5120 (office)

281-228-5129 (fax)

281-684-8820 (cell)

FGH@Topsoe.com

www.topsoe.com

"Hans Hartenstein"

<Hans.Hartenstein@EvonikEnergySerifices.us>

06/24/200804:16 PM

Flemming,

To "Flemming Hansen" <FGH@topsoe.com>

cc

Subject RE: Tail-end SCR

Thanks for your note. Just to make sure that I understand you correctly. Is it correct to state that

Haldor Topsoe feels fully confident that a tail-end SCR is technically feasible and would not

experience any accelerated catalyst deactivation? Therefore, you would be willing to guarantee

catalyst performance (NOx removal efficiency, pressure drop, S02/S03 conversion rate and catalyst

lifetime) without any need for further pilot testing. Please confirm. Thanks.

Best regards,

Hans Hartenstein

From: Flemming Hansen [mailto:FGH@topsoe.com]

Sent: Dienstag, 24. Juni 200816:44

To: Hans Hartenstein

A- 65
Subject: Re: Tail-end SCR

Hans,

Like you describe we have had very good operating experience with SCR in the clean environment

after a scrubber or bag filter. There appears to be practically no catalyst deactivation and with the low

amount of particulate the catalyst pitch can be small, which both leads to a compact SCR as

compared to a high dust SCR.

Based on the clean flue gas after the FGD we would not require any further testing in order to

guarantee a catalyst performance.

The actual guarantees would be as normally applied in a high dust installation and depend on the

catalyst volume and operating conditions. At the low operating temperature expected at the tail-end

position the S02 oxidation will be negligible.

I hope this confirmation will have your approval.

Flemming G. Hansen

Manager SCR DeNOx Catalyst

Haldor Topsoe, Inc.

281-228-5120 (office)

281-228-5129 (fax)

281-684-8820 (cell)

FGH@Topsoe.com

www.topsoe.com

"Hans Hartenstein" <Hans.Hartenstein@EvonikEnergyServices.us>

06/24/2008 10:24 AM

Flemming,

To <fgh@topsoe.com>

cc

Subject Tail-end SCR

As discussed during our phone conversation today, during which you stated that Haldor Topsoe

considers a high-dust SCR principally technically, feasible even though not without technically

resolvable challenges for Minnkota's Milton R. Young Station. I would also be interested in Haldor

Topsoe's position on the tecRl"licalfeasibilityof atail-em.l-SGR (downstream of awet scrubber

including flue gas reheat) Given your knowledge about the plant (cyclone-fired B&W boilers, ESP. wet

scrubber) and the fuel (NO lignite), would Haldor Topsoe:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rat~) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones equipped with your catalyst have

been in operation since the late 1980s and most of them still operate on the initial fill of catalyst after

almost 20 years and up to 130,000 operating hours, I would assume that Haldor Topsoe has sufficient

confidence in your tail-end SCR experience to competently respond to these questions. Please let me

know if you have any additional questions. Thanks.

Best regards,

Hans Hartenstein

A- 66