Preliminary

Best Available Control Technology

Determination

for

Control of Nitrogen Oxides

for

M.R. Young Station

Units 1 and 2

June 2008

Division of Air Quality

ND Department of Health

918 E. Divide Avenue

Bismarck, ND
Table of Contents

I. Introduction

II. Summary of Decision

III. Methodology

IV. BACT Determination

1

4

9

13

A. Step 1: Identify All Control Technologies 13

B. Step 2: Eliminate Technically Infeasible Options 14

1. Fuel Switching/Blending with or without SNCR 14

2. Selective Catalytic Reduction 15

a. High Dust SCR 15

b. Low Dust and Tail Gas SCR 55

3. Electro-Catalytic Oxidation 57

4. Rich Reagent Injection (RRI) with 58

Advance Separated Overfire Air with

or without SNCR

5. SNCR and Fuel Reburn 59

6. Fuel-Lean Gas Reburn (FLGR) 60

Plus SNCR

7. Oxygen-Enhanced Combustion 60

8. Water/Steam Injection 61

9. Hydrocarbon Enhanced SNCR (HE-SNCR) 61

10. Other Technologies 62

C.

D.

E.

Step 3:

Step 4:

Step 5:

Rank Remaining Control Technologies

by Control Effectiveness

Evaluate Most Effective Controls

and Document Results

Select BACT

62

64

65

References

Appendix A -

Appendix B -

71

Minnkota BACT Analysis and Additional Information

Evaluation of Particulate Matter Emission Rate
I. Introduction

Minnkota Power Cooperative operates the M.R. Young Station near

Center, North Dakota. Unit 1 of the station is owned by Minnkota

and has a gross rating of approximately 250 MWe. Existing air

pollution controls consist of a cold side electrostatic

precipitator. Unit 2, which is owned by Square Butte Electric

Cooperative, has a rating of approximately 477 MWe gross. Existing

air pollution control equipment consists of a cold-side

electrostatic precipitator and a lime/flyash wet scrubber for

sulfur dioxide control. Unit 1 went online in 1970 while Unit 2

began operations in 1977. Both units are fired on lignite which is

obtained from BNI Coal Ltd. 's Center Mine which is adjacent to the

station.

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-CV-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 North Dakota Air Pollution Control rules (NDAC

33-15) including the Prevention of Significant Deterioration Rules

(NDAC 33-15-15). Section V, 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 ) top-down Best Available

Control Technology Analysis (BACT) for the two existing units at

the M.R. Young Station. The Consent Decree requires Minnkota to

evaluate various technologies including selective catalytic

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

air (OFA) and rich reagent injection (RRI). Minnkota is also

required to submit any additional information requested by the

Department or the U.S. Environmental Protection Agency (hereafter

EPA) which is pertinent to the BACT determination. The BACT

analysis must address both a normal operating scenario and a

startup scenario. The BACT analysis must specify the technology to

be installed and recommend an emission rate, on 30-day rolling

average basis, that is BACT for each of the units and for each

scenario evaluated.

1
On October 9, 2006,

analyses. A review of

the items required by

the

the

the

Department received the required BACT

analyses indicates Minnkota has included

Consent Decree.

Since the original analysis, the Department has received comments

on the BART analysis from the U.S. Environmental Protection (and

their consultant Roger Christman of Eastern Research Group, Inc.),

Minnkota's responses to the Department's and EPA comments, and

information from Basin Electric Power Cooperative (through their

consultant Sargent and Lundy, LLC). The following documents are

contained in Appendix A.

1. Minnkota letter providing reference material from presentation

on BART; March 14, 2006; attachments include:

a) SCR Catalyst Performance in Flue Gases Derived From

Subbituminous and Lignite Coals; Benson, Steven A, et al.

b) The Proceeding of the 27 th International Technical

Conference on Coal Utilization & Fuel Systems; Volume II

of II.

c) Twenty-five Years of SCR Evolution: Implications for US

Application and Operation; Cichanowicz, J. E.; Muzio, L. J .

d) Utility Experience with SCR in Germany; Hartenstein,

Hans-Ulrich; et al.

e) The Selective Catalytic Reduction of NOx Emissions from

Utility Boilers; Mukherjee, Arun B.

f) SCR Catalyst Design Issues and Operating Experience:

Coals with High Arsenic Concentrations and Coals from the

Powder River Basin; Rigby, Katuna; et al.

g) Optimizing SCR Catalyst Design and Performance for Coalfired Boilers; Pritchard, Scot; et al.

2
2. Minnkota's Best Available Control Technology Analysis Study

for Milton R. Young Station Unit 1; October 2006.

3. Square Butte Power

Technology Analysis

October 2006.

Cooperative's Best Available Control

Study for Milton R. Young Station Unit 2;

4. ERG Memorandum to Hans Buenning of EPA Region 8, et. al.

regarding review and critique of NOx BACT Analysis for M.R.

Young Station; January 8, 2007.

5. EPA Transmittal of Non-SCR concerns and additional information

required for Minnkota BACT analysis study; January 26, 2007.

6. Department letter to Minnkota providing comments on Best

Available Control Technology Analyses; February 1, 2007.

7. Minnkota Response to ERG review; March 19, 2007.

8. Minnkota Response to Department's February 1, 2007 Comments;

April 23, 2007.

9. "Summary of Responses to EPA/DOH Questions on Minnkota Power's

NOx BACT Analysis for Milton R. Young Units 1 & 2" Power Point

Presentation Slides by EERC, Burns and McDonnell, and Minnkota

Power Cooperative; May 23, 2007.

10. "Application of SCR Technology to North Dakota Lignite Fuels",

Power Point Presentation slides by Sargent and Lundy, LLC; May

2007.

11. Minnkota letter with report titled "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 Analyses"; August 16, 2007.

12. EPA letter in response to Minnkota' s March 19, 2007 and

April 23, 2007 letters; October 4, 2007.

3
13. Minnkota letter in response to EPA's October 4, 2007 letter;

November 9, 2007.

14. Minnkota letter regarding BART conference; November 29, 2007.

15. Additional information and Discussion of Vendor Responses on

SCR Technical Feasibility; North Dakota's NOx BACT

Determination for Milton R. Young Station Units 1 and 2;

May 8, 2008.

The information submitted by Minnkota, and their consultants Burns

and McDonnell and the Energy and Environmental Research Center

(EERC), suggests that SCR technology is not technically feasible

for the M.R. Young Station. EPA, and their consultant ERG, Inc.,

suggest that SCR technology is technically feasible. Information

from Sargent and Lundy indicates that not enough information is

available to determine whether SCR technology can be successfully

adapted to units burning North Dakota lignite.

II. Summary of Decision

The primary issue facing the Department in making its BACT

determination is whether SCR technology is technically feasible for

North Dakota lignite-fired cyclone boilers. The information

submitted by Minnkota, and their consultants Burns and McDonnell

and the Energy and Environmental Research Center (EERC), suggests

that SCR technology is not technically feasible for the M.R. Young

Station. EPA, and their consultant ERG, Inc., suggest that SCR

technology is technically feasible. Information from Sargent and

Lundy indicates that not enough information is available to

determine whether SCR technology can be successfully adapted to

units burning North Dakota lignite.

The Department has carefully examined all submissions to determine

the best available control technology to control NOxemissions from

Minnkota Units 1 and 2, and determines that SCR is not technically

feasible for North Dakota lignite-fired cyclone boilers. The

July 27, 2006, Consent Decree provides that the NOxTop-Down BACT

analysis will be carried out in accordance with the provisions of

4
Chapter B of EPA's "New Source Review Workshop Manual-Prevention of

Significant Deterioration and Nonattainrnent Area Permitting." In

Step 2 of the Top-Down analysis, the technical feasibility of the

control options identified in step 1 is evaluated. The fundamental

question for this BACT Determination is whether SCR is an available

technology for North Dakota lignite-fired cyclone boilers such as

Minnkota Units 1 and 2.

EPA states that "the Minnkota BACT analysis for SCR should begin

with the presumption that SCR is technically feasible, since the

technology has been widely demonstrated on utility boilers ... based

on the 'technology transfer' discussion in the NSR Workshop Manual

_ and the fact that hundreds of SCR systems have been successfully

installed on utility boilers worldwide." These technological fixes

are unproven to transfer to this boiler/fuel type, and the use of

SCR to control NOx has only been demonstrated for utility boilers

that have substantially dissimilar gas streams.

The NSR Workshop Manual provides that technical judgment of the

review authority must be exercised in determining whether a control

alternative is applicable to the source type under consideration.

The manual states that generally, "a commercially available control

option will be presumed applicable if it 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

of the gas stream characteristics of the source types to which the

technology had been applied previously."

SCR has not been demonstrated to be technically feasible for North

Dakota lignite-fired cyclone boilers (Le., SCR hasn't been applied

to this source type). In addition, the lignite fired boiler the

gas stream has unique qualities different than gas streams of other

coal-fired boilers that cause unique catalyst deposition, erosion,

poisoning, blinding (or fouling or surface masking) and plugging

that are unresolvable barriers in the ability of known SCR

5
technologies to control NOx stack emissions. This makes SCR an

ineffective NOx control system in this case.

By asserting that unproven technological fixes such as aggressive

on-line cleaning and/or frequent extended forced outages to replace

the catalyst will make SCR available in this case, EPA attempts to

thereby convert the issue to one of cost evaluation under step 4 of

the BACT analysis. But the available evidence indicates that the

gas stream from high sodium lignite causes catalyst plugging and

blinding, which is not solved by the proposed technological fixes.

EPA's contention that technological solutions will be developed for

effective SCR NOx control is speculative.

EPA asserts that there are many tools in the toolbox to address SCR

technical issues, including screens, soot blowing, and a high

catalyst pitch to accommodate a catalyst replacement of about once

a year. Again, such proposed technological fixes are unproven.

The Department finds that catalyst replacement would be required

more frequently than normal industry experience, and is

unreasonable.

The NSR Manual notes that a control technology \\ is considered

available if it has reached the licensing and commercial stage of

development. A source would not be required to experience extended

time delays or research 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 the pilot scale testing stages of

development would not be considered available for BACT review." SCR

has not reached this stage for North Dakota lignite-fired cyclone

boilers, and because of the difference in the gas stream, the

Department concludes that Minnkota need not experience extended

trials to learn how to apply the technology on such a dissimilar

source type. EPA's contention that technological solutions will be

developed is speculative.

6
The pilot testing at the Coyote Station did not provide much useful

data, and in hindsight, was ill-designed for a unit combusting

North Dakota lignite. Yet, the test did indicate a significant

difference between lignite and subbituminous coal, describing

blinding and plugging (deactivation) at the Coyote Station as

extremely rapid and severe as compared to testing at the Columbia

and Baldwin Stations. Because of the lack of deactivation data

from the pilot test at the Coyote Station, it is risky and

difficult to design an SCR system; the Department concludes that

design of an SCR system for North Dakota lignite would be different

from a unit burning subbituminous coal. In sum, additional

research and testing on the effects of the flue gas constituents

are required to design an SCR system for North Dakota lignite.

Besides catalyst deactivation, it is likely that a high-dust SCR

would experience plugging problems (deposition on the catalyst

surface) due primarily to the carryover of "popcorn ash" from the

boiler. The popcorn ash is generated during cleaning actions

within the boiler which are quite frequent due to the

characteristics of North Dakota lignite. The advances made in the

last few years for controlling popcorn ash are not shown to be

applicable to a cyclone boiler burning North Dakota lignite.

Extensive engineering analyses, and likely pilot scale testing,

will be necessary to determine if these advances can be applied at

the M.R. Young Station. The requirement for pilot scale testing or

additional research would eliminate SCR from further consideration

pursuant to the NSR Manual.

Additionally, SCR is technically infeasible due to erosion of the

catalyst. Because of the high ash content and frequent cleaning

cycles due to the deposition characteristics of North Dakota

lignite ash, erosion may be more of a concern than with a

bituminous or subbituminous coal-fired unit. Although pilot scale

testing is now underway at the Sandow Plant in Texas-which burns

Texas lignite-its results are not yet available. Additional design

work and pilot testing is required before a conclusion can be made

that SCR can be successfully applied as NOx control for North

Dakota lignite-fired units.

7
While EPA's expert, Roger Christman, supports EPA;S contention that

the wealth of experience in the utility industry applying SCR to

solid fuel utility boilers creates a presumption of technical

feasibility, the presumption does not take into account the

differences in the gas streams, and the conclusion is not

consistent with the experience of the most qualified experts. The

BACT assessment for Minnkota was prepared by Burns and McDonnell,

which has considerable experience with SCR systems, and the EERC,

which has extensive experience with North Dakota lignite. Sargeant

and Lundy, LLC (S&L) , another consulting firm, also made a

presentation to the Department on the application of SCR technology

to North Dakota lignite fuels. S&L, which is entirely dedicated to

the electric power industry, indicated it had designed 46% of the

SCR systems in the United States. Of the SCR systems, 39 were for

coal-fired units with 10 designed for Powder River Basin

subbituminous coal. While S&L provided possible solutions for

deactivation of the catalyst, they indicated there was no known

solution for deactivation due to soluble sodium compounds generated

by the combustion of North Dakota lignite. S&L speculated that

more catalyst and a larger reactor may be a possible solutions;

however, how much more catalyst or how much larger the reactor

would have to be to solve the problem was unknown. In sum, S&L

concluded that there are attributes of North Dakota lignite in an

SCR environment that are not well understood today and need more

investigation to predict its performance. S&L recommendations

included a parametric pilot test program.

Although the Department would have preferred a more complete record

that included more extensive pilot testing of SCR using North

Dakota lignite in cyclone boilers, the Department must make its

decision on the available information, which indicates that pilot

testing and redesign of the catalyst are necessary before SCR can

be shown to be a technically feasible technology in this case.

The Department has determined that BACT for both units at the M.R.

Young Station is represented by advanced separated over fire air

(ASOFA) and selective noncatalytic reduction (SNCR).

8
III. Methodology

The North Dakota Air Pollution Control Rules, Section 33-15-15-01.2

defines Best Available Control Technology as:

An emissions limitation (including a visible emission

standard) based on the maximum degree of reduction for each

pollutant subject to regulation under the Clean Air Act which

would be emitted from any proposed major stationary source or

major modification which the Department, on a case-by-case

basis, taking into account energy, environmental, and economic

impacts and other costs, determines is achievable for such

source or modification through application of production

processes or available methods, systems, and techniques,

including fuel cleaning or treatment or innovative fuel

combustion techniques for control of such pollutant. In no

event shall application of best available control technology

result in emissions of any pollutant which would exceed the

emissions allowed by any applicable standard under 40 CFR

Parts 60 and 61. If the Department determines that

technological or economic limitations on the application of

measurement methodology to a particular emissions unit would

make the imposition of an emissions standard infeasible, a

design, equipment, work practice, operational standard, or

combination thereof, may be prescribed instead to satisfy the

requirement for the application of best available control

technology. Such standard shall, to the degree possible, set

forth the emissions reduction achievable by implementation of

such design, equipment, work practice or operation, and shall

provide for compliance by means which achieve equivalent

results.

The steps for conducting a BACT analysis using the "top down"

approach are as follows:

Step 1: Identify All Control Technologies.

List is comprehensive.

9
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.

EPA's New Source Review Workshop Manual 1 (hereafter NSR Manual)

provides guidance for determining whether a control option is

technically infeasible. Two concepts are important in making this

determination, "availability" and "applicability". A technology is

considered "available" if it can be obtained through commercial

channels or is otherwise available within the common sense meaning

of the word. An available technology is "applicable" 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 Manual 1 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, technologies in a pilot scale testing stages of

development would not be considered available for BACT

review."

With respect to "applicability" the NSR Manual 1 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 if it has been or is soon

10
to be deployed (e.g., is specified in a per.mit) 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.

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 infor.mation to the contrary."

with regard to the types of control options to be considered,

the NSR Manual 1 states: "Each new or modified emission unit

(or logical grouping of new or modified emission unit(s»

11
subject to PSD is required to undergo BACT review. BACT

decisions should be made on the information presented in the

BACT analysis, including the degree to which effective control

alternatives were identified and evaluated. 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

Add-on Controls. For example, the application

combustion and post-combustion controls to reduce

emissions at a gas-fired turbine.

and

of

NOx

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 3: Rank Remaining

Effectiveness

Control

12

Technologies By Control
This includes:

control effectiveness (percent pollutant removed);

expected emission rate (tons per year) ;

expected emission reduction (tons per year);

energy impacts (Btu, KW-hr);

environmental impacts (other media and the emissions of

toxic and hazardous air emissions); and

economic impacts (total cost effectiveness and

incremental cost effectiveness).

Step 4:

Step 5:

Evaluate Most Effective Controls and Document Results

Case-by-case consideration of energy, environmental, and

economic impacts.

If most effective options 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.

IV. BACT Determination

Both units at the M.R. Young Station are cyclone fired units which

burn North Dakota (Fort Union) lignite from the Center Mine. Since

both units employ cyclone firing and are similar in many other

respects, the following discussion is applicable to both units.

A. Step 1: Identify All Control Technologies

Minnkota identified the following technologies or control

methods:

combustion Improvements

Fuel Switching/Blending/Cleaning

*High Dust Selective Catalytic Reduction (SCR)

*Low Dust SCR

13
*Tail-gas SCR

*Electro-Catalytic Oxidation (ECO)

*Selective Noncatalytic Reduction (SNCR) including Rich

Reagent Injection (RRI) and Hydrocarbon Enhanced SNCR (HESNCR)

*Flue Gas Recirculation

*Separated Overfire Air (SOFA) including Boosted SOFA Rotating

Opposed Fired Air (ROFATM) and Advanced Separated Overfire Air

(ASOFA)

*Fuel Reburn

Oxygen Enhanced Combustion

Water/Steam Injection

*Could be applied in combination with other technologies or

methods.

B. Step 2: Eliminate Technically Infeasible Options

1. Fuel Switching/Blending

The Milton R. Young Station was designed and has operated

for over 35 years as a mine mouth power plant. There is

no railroad access to the plant. The Department believes

the nearest rail line is approximately 10 miles away.

Switching to Powder River Basin (PRB) subbituminous coal

would not lower NOx emissions. The Big Stone Power Plant

in South Dakota is a cyclone boiler which burns PRB

subbituminous coal. A review of EPA's Acid Rain Database

indicated a 2005 annual average NOx emission rate of 0.83

Ib/106 Btu. This is compared to the baseline emission

rate for M.R. Young Unit 1 of 0.849 Ib/106 Btu and 0.786

Ib/106 Btu for Unit 2. Switching to PRB subbituminous

coal would have little effect on NOx emissions and may

actually increase emissions. Since combusting PRB coal

would have little effect on emissions, this option,

although technically feasible, is not considered further.

In August, 2007, the United States Court of Appeals for

the Seventh Circuit issued its decision in the Prairie

14
State Generating case (Sierra Club, et al. v. u. S.

Environmental Protection Agency and Prairie State

Generating Company, LLC at 499 F. 3d 653,654; 7th Cir.

2007) . The Department interprets this decision to

indicate that fuel switching is not required for a mine

mouth power plant such as M. R. Young Station. Therefore,

Minnkota is not required to consider switching coal or

bringing in other types of coal for blending to address

the characteristics of Center lignite that would affect

any of the control technologies.

2. Selective Catalytic Reduction (SCR)

a. High Dust SCR

Technical Review

The SCR process is based on the chemical reduction

of the NOx molecule using a metal based catalyst

with activated sites to increase the rate of the

reduction reaction. A nitrogen based reducing

agent (reagent), such as ammonia or urea, is

injected into the post combustion flue gas. The

reagent reacts selectively with the flue gas NOx

within a specific temperature range and in the

presence of the catalyst and oxygen to reduce the

NOx molecule into molecular nitrogen and water

vapor. 2

In order for SCR to be technically feasible, it

must be both uavailable" and uapplicable". SCR has

been applied to the many different types of coal

throughout the world. Based on its widespread

usage, it would initially appear to be available

for use at the M.R. Young Station.

As stated previously, the NSR Manual 1 states that

decisions regarding technical feasibility are made

by comparing the physical and chemical

characteristics of the exhaust gas stream from the

15
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. In

order to compare the flue gas at the M.R. Young

Station to gas streams where SCR has been

successfully applied, a comparison of the different

fuel (coal) characteristics is helpful.

EPA's Air Pollution Control Cost Manua1 2 states:

"Certain fuel constituents which are released

during combustion act as catalyst poisons.

Catalyst poisons include calcium oxide and

magnesium oxide, potassium, sodium, arsenic,

chlorine, fluorine, and lead. These constituents

deactivate the catalyst by diffusing into active

pore sites and occupying them irreversibly.

Catalyst poisoning represents the main cause of

catalyst deactivation.

Ammonia-sulfur salts, fly ash, and other

particulate matter in the flue gas cause blinding,

plugging or fouling of the catalyst. The

particulate matter deposits on the surface and in

the active pore sites of the catalyst. This

results in a decrease of the number of sites

available for NOx reduction and an increase in flue

gas pressure loss across the catalyst.

Impingement of particulate matter and high

interstitial gas velocities erode the catalyst

material. Catalysts with hardened leading edges or

increased structural strength are less susceptible

to erosion. Increasing catalyst strength through

16
hardening, however, reduces the number of active

pore sites."

Minnkota has indicated that the most significant

problem for the successful operation of SCR

catalysts on units that fire North Dakota lignite

is the formation of low temperature sodium-calciummagnesium sulfates and phosphates. Sodium is a

significant contributor to the Ustickiness" of the

ash produced from firing North Dakota lignite. The

sodium content of the Center Mine lignite ash

historically averages 4.4% and can more than double

this value for some of the lignite produced.

Powder River Basin (PRB) coal from wyoming

typically averages around 1.5% sodium3 •

A review was conducted to independently compare the

constituents of fuels for which SCR has been

successfully applied to that of North Dakota

lignite. Data was obtained from the U.S.

Geological Survey's U.S. Coal Quality Database3 •

The results are shown in Table 1.

17
Table 1

COAL CHARACTERISTICS

COMPARISON

Center Center

Ligniteb Ligniteb Texas Wyoming PA

(Historical) (Future) Lignitea PRBa Bituminousa

Avg. Heat Value (10 6 13.2 13.4 15.2 17.0c 25.5

Btu/ton)

Avg. Ash Content 9.6 7.8 12.6 5.0c 13 .0

Avg. Na2 0 (% of Ash) 4.4 5.6 0.5 1.6 0.3

Std. Deviation 2.2 3.4 0.6 1.3 0.2

Avg. CaO (% of Ash) 13.1 17.0 13.2 17.3 1.7

Std. Deviation 3.2 5.3 5.2 7.4 1.6

Avg. MgO (% of Ash) 4.0 5.1 2.3 3.8 0.6

Std. Deviation 0.8 1.2 1.1 2.1 0.3

Avg. K2 0 (% of Ash) 1.3 1.0 0.5 0.5 1.9

Std. Deviation 0.4 0.7 0.3 0.4 0.8

Na2O+CaO+MgO+K2O (% of 22.9 28.7 16.5 23.2 4.5

Ash)

a Heating values, ash content and ash constituents from the USGS National Coal

Database except as noted.

b From Minnkota's April 23, 2007 submittal.

c From University of Wyoming.

In order to properly compare flue gas conditions,

an estimate of the total emission rate of the

deactivation (fouling and poisoning) constituents

can be made. Although the catalyst deactivation

rate may not be directly proportional to the

emission rates of the various constituents, it does

provide a means of comparison of the flue gas

characteristics.

AP-42, Compilation of Air Pollutant Emission

Factors 4 , lists the following particulate matter

emission factors as shown in Table 2.

18
Table 2

AP-42 EMISSION FACTORS

combustion unit Type Fuel Emission Factor

Cyclone Lignite 6.7A

Cyclone Bit./Subbit. 2.0A

Wall/Tangential Bit./Subbit. 10.0A

Wall Lignite 6.5A

Tangential Lignite 5.1A

A = Ash content of the coal (%)

In its analysis, Minnkota indicated that

approximately 45 - 50% of the ash in the lignite

combusted at the M.R. Young Station is emitted from

the boiler. The Department reviewed the ESP

performance test for Unit 2 to verify this

assertion. The results of the review indicated an

average emission rate of 46.9% of the ash in the

lignite which yields an emission factor of 9. 4A

(lb/ton) . The results are shown in Appendix B.

Minnkota's assertion appears valid.

To assess whether the flue gas characteristics at

the M. R. Young Station are different from

characteristics at other generating stations where

SCR has been successfully applied, the emission

rate, or loading, of the various deactivation

constituents and the chemical form (organic or

inorganic) of these constituents must be evaluated.

Using the coal characteristics data from Table 1,

the emission factors from Table 2, and the results

of the review of Minnkota's emission factor, the

emission rate of the deactivation constituents were

calculated. Emphasis was given to the sodium oxide

(Na20) emission rate because North Dakota lignite

19
generally contains more Na20 than bituminous or

subbituminous coal. Since cyclone boilers firing

North Dakota lignite partition the ash, the sodium

is concentrated in the ash leaving the boiler. The

results of the following calculation will

underestimate the amount of sodium in the flue gas

for a cyclone boiler firing North Dakota lignite;

however, it does provide a conservative comparison.

The results of the calculation are provided in

Table 3:

20
Table 3

HISTORICAL COAL EMISSION RATE COMPARISON

CENTER TEXAS WYOMING PRB PA

LIGNITE a LIGNITE b SUBBITUMINOUS b BITUMINOUS b

Na20 (% of Ash) 4.4 0.5 1.6 0.3

CaO (% of Ash) 13.2 13 .2 17.3 1.7

MgO (% of ash) 4.0 2.3 3.8 0.6

K20 (% of Ash) 1.3 0.5 0.5 1.9

Na20+CaO+MgO+K20 (% of Ash) 22.9 16.5 23.2 4.5

Ash Content 9.6 12.6 5.0 13.0

Heat Value (10 6 Btu/ton) 13.2 15.2 17.0 25.5

PM Emission Factor (lb/ton/l% Ash) c.d

Cyclone Boiler 9.4 6.7 2.0 2.0

Wall/Tangentially-fired Boiler (Pulverized) 5.8 5.8 10.0 10.0

PM Emissions (lb/l06 Btu)

Cyclone Boiler 6.84 5.55 0.59 1. 02

Wall/Tangentially-fired Boiler (Pulverized) 4.22 4.81 2.94 5.10

Na20 Cyclone Boiler Emissions

lb/ton 3.97 0.42 0.16 0.08

lb/l06 Btu 0.3008 0.0278 0.0094 0.0031

lb/dscf 3.0507E-05 2.8164E-06 9.6235E-07 3.1276E-07

lb/wscf 2.5172E-05 2.3238E-06 8.8456E-07 2.8748E-07

Na20+CaO+MgO+K20 Cyclone Boiler Emissions

lb/ton 20.66 13 .93 2.32 1.17

lb/l06 Btu 1. 5655 0.92 0.14 0.05

lb/dscf 1. 5878E-04 9.2941E-05 1.3954E-05 4.6914E-06

lb/wscf 1.3101E-04 7.6686E-05 1.2826E-05 4.3123E-06

21
Table 3 Continued

CENTER TEXAS WYOMING PRB PA

LIGNITE a LIGNITE b SUBBITUMINOUS b BITUMINOUS b

Ratio of ND Lignite Cyclone Emissions to Other

Cyclones

Na2 0

lb/ton 9.4 24.8 50.9

lbll06 Btu 10.8 32.0 98.3

lb/dscf 10.8 31. 7 97.5

lb/wscf 10.8 28.5 87.6

Na20+CaO+MgO+K20

lb/ton 1.5 8.9 17.7

lbll06 Btu 1.7 11.5 34.1

lb/dscf 1.7 11.4 33.8

lb/wscf 1.7 10.2 30.4

Comparison of ND Lignite Cyclone to Pulverized Units

Na20 Emissions

lb/ton 3.97 0.37 0.80 0.39

lbll06 Btu 0.3008 0.0240 0.0471 0.0153

lb/dscf 3.0507E-05 2.4381E-06 4.8117E-06 1.5638E-06

lb/wscf 2.5172E-05 2.0117E-06 4.4228E-06 1.4374E-06

Na20+CaO+MgO+K20 Emissions

lb/ton 20.66 12.06 11. 60 5.85

lbll06 Btu 1.5655 0.7933 0.6824 0.2294

lb/dscf 1.5878E-04 8.0457E-05 6.9770E-05 2.3457E-05

lb/wscf 1. 3101E-04 6.6385E-05 6.41309E-05 2.15613E-05

Ratio of ND Lignite Cyclone Emissions to Pulverized

Units

Na20

lb/ton 10.9 5.0 10.2

lbll06 Btu 12.5 6.4 19.7

lb/dscf 12.5 6.3 19.5

lb/wscf 12.5 5.7 17.5

22
Table 3 Continued

CENTER TEXAS WYOMING PRB PA

LIGNITE a LIGNITE b SUBBITUMINOUS b BITUMINOUS b

Na20+CaO+MgO+K20

lb/ton 1.7 1.8 3.5

Ibll06 Btu 2.0 2.3 6.8

lb/dscf 2.0 2.3 6.8

lb/wscf 2.0 2.0 6.1

a Information from Minnkota's April 16, 2007 submittal.

b Data from the USGS National Coal Database and University of Wyoming.

c From AP-42, Compilation of Air Pollutant Emission Factors except for Minnkota which is based on actual stack

testing.

d Emission factor for tangentially and wall-fired units burning lignite is the average of the AP-42 emission

factors.

23
Minnkota has also provided data on core samples of

lignite in future mining areas. Using this data,

the calculated constituent emission rates area are

provided in Table 4.

24
Table 4

FUTURE COAL EMISSION RATE COMPARISON

CENTER TEXAS WYOMING PRB PA

LIGNITE a LIGNITE b SUBBITUMINOUS b BITUMINOUS b

NazO (% of Ash) 5.6 0.5 1.6 0.3

CaO (% of Ash) 17.0 13 .2 17.3 1.7

MgO (% of ash) 5.1 2.3 3.8 0.6

KzO (% of Ash) 1.0 0.5 0.5 1.9

NazO+CaO+MgO+KzO (% of Ash) 28.7 16.5 23.2 4.5

Ash Content 7.8 12.6 5.0 13.0

Heat Value (10 6 Btu/ton) 13.4 15.2 17.0 25.5

PM Emission Factor (lb/ton/l% Ash) c,d

Cyclone Boiler 9.4 6.7 2.0 2.0

Wall/Tangentially-fired Boiler (Pulverized) 5.8 5.8 10.0 10.0

PM Emissions (lb/l06 Btu)

Cyclone Boiler 5.47 5.55 0.59 1. 02

Wall/Tangentially-fired Boiler (Pulverized) 3.38 4.81 2.94 5.10

NazO Cyclone Boiler Emissions

lb/ton 4.11 0.42 0.16 0.08

lb/l06 Btu 0.3064 0.0278 0.0094 0.0031

lb/dscf 3.1076E-05 2.8164E-06 9.6235E-07 3.1276E-07

lb/wscf 2.5641E-05 2.3238E-06 8.8456E-07 2.8748E-07

25
Table 4 Continued

CENTER TEXAS WYOMING PRB PA

LIGNITE a LIGNITE b SUBBITUMINOUS b BITUMINOUS b

Na20+CaO+MgO+K20 Cyclone Boiler Emissions

lb/ton 21. 04 13 .93 2.32 1.17

lb/l06 Btu 1. 5704 0.92 0.14 0.05

lb/dscf 1.5927E-04 9.2941E-05 1.3954E-05 4.6914E-06

lb/wscf 1. 3141E-04 7.6686E-05 1.2826E-05 4.3123E-06

Ratio of ND Lignite Cyclone Emissions to Other

Cyclones

Na20

lb/ton 9.7 25.7 52.6

lb/l06 Btu 11.0 32.6 100.2

lb/dscf 11.0 32.3 99.4

lb/wscf 11.0 29.0 89.2

Na20+CaO+MgO+K20

lb/ton 1.5 9.1 18.0

lbll06 Btu 1.7 11. 5 34.2

lb/dscf 1.7 11.4 33.9

lb/wscf 1.7 10.2 30.5

Comparison of ND Lignite Cyclones to Pulverized

Units

Na20 Emissions

lb/ton 4.11 0.37 0.80 0.39

lbll06 Btu 0.3064 0.0240 0.0471 0.0153

lb/dscf 3.1076E-05 2.4381E-06 4.8117E-06 1.5638E-06

lb/wscf 2.5641E-05 2.0117E-06 4.4228E-06 1.4374E-06

Na20+CaO+MgO+K20 Emissions

lb/ton 21. 04 12.06 11. 60 5.85

lbll06 Btu 1. 5704 0.7933 0.6824 0.2294

lb/dscf 1. 5927E-04 8.0457E-05 6.9770E-05 2.3457E-05

lb/wscf 1.3141E-04 6.6385E-05 6.41309E-05 2.15613E-05

26
Table 4 Continued

CENTER TEXAS WYOMING PRB PA

LIGNITE a LIGNITE b SUBBITUMINOUS b BITUMINOUS b

Ratio ND Lignite Cyclone Emissions to Pulverized

Units

Na20

lb/ton 11.2 5.1 10.5

Ibl106 Btu 12.7 6.5 20.0

lb/dscf 12.7 6.5 19.9

lb/wscf 12.7 5.8 17.8

Na2O+CaO+MgO+K2O

lb/ton 1.7 1.8 3.6

Ibl106 Btu 2.0 2.3 6.8

lb/dscf 2.0 2.3 6.8

lb/wscf 2.0 2.0 6.1

a Information from Minnkota's April 16, 2007 submittal.

b Data from the USGS National Coal Database and University of Wyoming.

c From AP-42, Compilation of Air Pollutant Emission Factors except for Minnkota which is based on actual stack

testing.

d Emission factor for tangentially and wall-fired units burning lignite is the average of the AP-42 emission

factors.

27
The most useful emission rate calculation is that

in terms of pounds per wet standard cubic foot

(lb/wscf). This estimated emission rate represents

the actual concentration of the constituents in the

ductwork leaving the boiler at standard temperature

and pressure. The results for both the historical

and future (core sample data) scenarios are similar

for the total deactivation constituents and for

Na20. However, Minnkota has indicated that, based

on their experience, the actual ash content of

future coal could be 2 percentage points higher

than the average of the core samples. This would

increase the emission rates calculated previously

for the future scenario by approximately 25%.

Tables 3 and 4 show that the potential for

deactivation of the SCR catalyst is much greater

for a cyclone boiler combusting Center Mine

lignite.

In general, North Dakota lignite has a higher ash

sodium content than western subbituminous coal. An

exception is subbituminous coal from the Spring

Creek Mine near Decker, Montana. Department

records indicate the ash sodium content in Spring

Creek Mine coal can vary from less than one percent

to approximately nine percent. The Department

investigated the use of Spring Creek Mine coal by

power plants. Based on information supplied by Rio

Tinto Energy, operator of the Spring Creek Mine, it

was determined that the only power plant that

utilizes Spring Creek Mine subbituminous coal and

operates an SCR system is the Karn/Weadock

Generating Complex in Michigan.

The Department contacted Consumers Energy 14,15, the

operator of the Karn/Weadock Generating Complex.

The Dan E. Karn Units 1 and 2 burn coal and are

28
equipped with selective catalytic reduction for

nitrogen oxides control. Consumers Energy

indicated they purchase coal from several western

mines as well as eastern mines. They also

indicated that none of the coal obtained from the

Spring Creek Mine is fed to a unit equipped with an

SCR system1S • Based on this information, the

Department is not aware of any power plant that is

equipped with an SCR system and burns Spring Creek

Mine coal.

The Energy & Environmental Research Center (EERC)

at the University of North Dakota is recognized as

one of the world's leading coal research

facili ties. Since 1951, the EERC has focused on

research and development, technology demonstration

and technology commercialization. As part of the

BACT assessment, Minnkota submitted a report by the

EERC titled Ash Impacts on SCR Catalyst

Performances. In that report, it is stated: "The

ash deposition behavior of the lignites from North

Dakota is the most complex and severe of any coals

in the world, and installation of catalysts for NOx

reduction is going to be plagued with problems."

The report further states: "Alkali and alkaline

earth sulfates are enhanced by cyclone-fired

systems. The cyclone firing results in

partitioning of the ash between bottom slag and the

body of the boiler. The sulfate forming materials

are more concentrated in the fly ash as a result of

cyclone firing."

In reviewing the flue gas characteristics of plants

firing coal types where SCR has been applied with

those of the M.R. Young Station, it appears

comparison of the characteristics for cyclone fired

29
units alone is more appropriate because of the

enhanced sulfates formation in cyclone units. The

Department's review suggests that the sodium oxide

loading in the flue gas for the North Dakota

lignite-fired unit would be nearly 29 times (on a

lb/wscf basis) that of a cyclone unit burning PRB

subbituminous coal. This ratio is actually

conservative (expected to higher) because of the

partitioning of the ash that occurs in a cyclone

boiler firing North Dakota lignite. The estimated

combined loading of catalyst deactivation

constituents sodium oxide, calcium oxide, magnesium

oxide and potassium oxide is more than ten times

that of PRB subbituminous coal-fired cyclone units.

Although the deactivation of the SCR catalyst may

not be directly proportional to the emission rate,

it is evident that the concentration of various SCR

deactivation chemical constituents in the flue gas

of a North Dakota lignite-fired power plant is much

different from a cyclone unit firing PRB

subbituminous coal.

When compared to other types of combustion units,

the estimated emission rate of Na20 is approximately

six times that of a wall-fired or tangentially

fired unit burning subbituminous coal from

Wyoming's Powder River Basin. The estimated

emission rate of Na20, CaO, MgO and K20 combined is

double for the cyclone boiler burning Center Mine

lignite. These ratios of emission rates are based

on average coal. When Minnkota combusts lignite

with a higher ash or sodium content, the ratio will

be greater. As can be seen from Table 1, the Na20

concentration in Center Mine lignite is much more

variable than the other coals.

30
Gutberlet 6 in his technical paper on deactivation of

SCR catalyst states: "Alkaline metals chemically

attach to active catalyst pore sites and cause

blinding. Sodium (Na) and potassium (K) are of

prime concern especially in their water soluble

forms which are mobile and penetrate into the

catalyst pores." Minnkota, in its March 19, 2007

response to questions indicates that most sodium in

North Dakota lignite is organically associated.

Combustion of the organically associated sodium

produces soluble sodium compounds that are readily

available for reactions with catalysts and flue gas

species. Potassium is associated with clay

minerals. Minnkota also stated that in a

conversation with Fleming Hansen of Haldor Topsoe

(see Minnkota's November 9, 2007 response to

comments), Mr. Hansen indicated that sodium was a

major concern and that it causes deactivation,

especially in the organically associated form. It

is evident to the Department that the form

(soluble) of sodium present in the ash from the

combustion of North Dakota lignite will deactivate

an SCR much more quickly than the other types of

coals where SCR has been successful.

The next issue to address is whether the difference

in these characteristics would preclude the

successful operation of SCR technology on units

fired on North Dakota lignite.

The NSR Workshop Manual states: "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". The manual

31
also states: "A demonstration of technical

infeasibility is based on technical assessment

considering physical, chemical and engineering

principles, and/or emperical data showing that the

technology would not work on the emissions unit

under review, or that unresolved technically

difficulties would preclude the successful

deployment of the technique." The NSR Manual 1 does

not define "successful operation" of the control

device or "successful deployment" of the technique.

The EERC, several utilities and catalyst vendors

conducted pilot scale testing at the Coyote

Station, which is a cyclone fired unit that

combusts North Dakota lignite. The pilot scale SCR

deployed at the Coyote Station was plugged and the

catalyst pores deactivated after 2 months (approx.

143 a hours). The Department believes successful

operation is considerably more than a few thousand

hours of operation. For example, the EPA Air

Pollution Control Cost Manua1 2 states: "For coalfired boiler applications, SCR catalyst vendors

typically guarantee that catalyst for an operating

life ranging between 10,000 hours to 30,000 hours."

In the technical paper Nitrogen Oxides Emission

Control Options for Coal Fired Electric Utility

Boilers,9 it is stated: "On dry-bottom, coal-fired

u.s. boilers equipped with full SCR, the planned

time between catalyst changes on a typical unit is

typically 24,000 operating hours or 3 years of

operations." The paper also indicated that

Merrimack 2, a cyclone boiler with 100% flyash

reinj ection, the expected time between the

replacement of layers is 14, 000 operating hours.

It appears that 10,000 hours of operation would be

a minimum time for successful operation.

32
Pritchard? states in his paper on optimizing SCR

catalyst design: "Our experience show that coalfired SCRs are successful when the system impact

and catalyst deterioration factors are understood

and specific counter measures are implemented in

system and catalyst design." The Coyote Station

pilot test may not have provided much useful data

for designing an SCR system for plants firing North

Dakota lignitei however, it did indicate a

difference between lignite and subbituminous coal.

The pilot scale testing protocol was the same for

the Coyote Station, Columbia Station and Baldwin

Stationi however, the test at the Columbia Station

used a different catalyst. The Coyote Station

combusts lignite while the Columbia Station and

Baldwin Station fire subbituminous coal. The EERC

has described the blinding and plugging

(deactivation) at the Coyote Station as extremely

rapid and severe as compared to testing at the

Columbia and Baldwin Stations. This indicates to

the Department that design of an SCR system for

North Dakota lignite would be different from a unit

burning subbituminous coal. Because of the lack of

deactivation data from the pilot test at the Coyote

Station, it would appear to be extremely difficult

to design an SCR system that could be successfully

operated. Proceeding with installation of such a

design without engineering data collected during

appropriate pilot testing is subject to an extreme

risk. This suggests to the Department that

additional research and testing on the effects of

the flue gas constituents are required to design

the SCR system.

Besides catalyst deactivation, Minnkota believes

that a high-dust SCR would experience plugging

problems due to the deposition characteristics of

33
North Dakota lignite (sticky ash) and the carry

over of "popcorn ash" from the boiler. The

deposition characteristics of the ash from

combusting lignite will create difficult to remove

ash deposits and will increase deposition in the

air preheater downstream and flue gas duct work,

which could be severe. Popcorn ash is generated

during cleaning actions within the boiler which are

quite frequent due to the characteristics of North

Dakota lignite. Although there have been advances

made in the last few years for controlling popcorn

ash, these advances mayor may not be applicable to

a cyclone boiler burning North Dakota lignite.

Extensive engineering analyses, and perhaps pilot

scale testing, will be necessary to determine if

these advances can be applied at the M.R. Young

Station.

The flue gas temperature variation at the location

a high dust SCR would be placed is also a concern.

Minnkota indicates that the temperature generally

ranges from approximately 430°F to 960°F for Unit 1

depending on the unit's load. For Unit 2, it could

vary from 430-880 oF. However, temperatures as high

as l050 0 F at Unit 1 and 990°F at unit 2 have been

measured.

The EPA Air Pollution Control Cost Manua1 2 states:

"The NOx reduction reaction is effective only within

a given temperature range. The use of a catalyst

in the SCR process lowers the temperature range

required to maximize the NOx reduction reaction. At

temperatures below the specified range, the

reaction kinetics decrease and ammonia passes

through the boiler (ammonia slip). At temperatures

above the specified range, nitrous oxide (N20) for.ms

and catalyst sintering and deactivation occurs.

34
In an SCR system, the optimum temperature depends

on both the type of catalyst utilized in the

process and the flue gas composition. For the

majority of commercial catalysts (metal oxides),

the optimum temperatures for the SCR process range

from 480°F to 800°F (250°C to 427°C). The figure

shows that the rate of the NOx removal increases

with temperatures up to a maximum between 700°F to

750°F (370°C to 400°C)" (figure omitted here) .

The Control Cost Manua12 goes on to state: "The

relationships between flue gas temperature,

catalyst volume, and NOx removal are complicated

functions of the catalyst formulation and

configuration. The physical and chemical

properties of each catalyst are optimized for a

different operating conditions. For a given

catalyst formulation, the required catalyst volume

and/or temperature range can even change from one

manufacturer of the catalyst to another. The

selection of catalyst, therefore, is critical to

the operation and performance of the SCR system."

This complicated relationship suggests that

additional research, design and testing may be

required before the temperature problem could be

overcome. Minnkota has provided a "concept" for

solving the temperature problems; however,

engineering studies would have to be conducted

before it is known whether the temperature problem

(temperatures both below and above the optimum

temperature window) could be overcome.

The final reason Minnkota cited for technical

infeasibility was erosion of the catalyst. Because

35
of the high ash content and anticipated frequent

cleaning cycles due to the deposition

characteristics of North Dakota lignite ash,

erosion may be more of a concern than with a

bituminous or subbituminous coal-fired unit. pilot

scale testing is now underway at the Sandow Plant

in Texas. This facility also burns lignite. The

results of that testing may provide information

that Minnkota can apply to the design of an SCR

system to control erosion; however, the results are

not available at this time. Again, the Department

believes additional design work and testing may be

required for successful application of SCR

technology to North Dakota lignite-fired units.

The BACT assessment for Minnkota was prepared by

Burns and McDonnell, which has considerable

experience with SCR systems, and the EERC, which

has extensive experience with North Dakota lignite.

Sargeant and Lundy, LLC (S&L) , another consulting

firm acting on behalf of Basin Electric Power

Cooperative, also made a presentation to the

Department on the application of SCR technology to

North Dakota lignite fuels. S&L indicated it had

designed 46% of the SCR system in the United

States. Of the SCR systems, 39 were for coal-fired

units with 10 designed for Powder River Basin

subbituminous coal. S&L listed8 their "Keys to

Achieving Success" as:

• Understand deactivation mechanisms

• Understand ash behavior

• The "Understanding" establishes:

- Catalyst formulation

- Catalyst pitch

- Reactor velocity

- Catalyst surface and volume

36
• Results in reactor size and shape to match

catalyst management plan

• Physical model for:

- NH3 and NOx mixing

- Gas distribution and velocity profile

• CFD modeling:

- Identify and mitigate areas of potential ash

deposits

- Mixing gases of different temperatures

S&L also provided possible solutions for

deactivation of the catalyst. However/ they

indicated there was no known solution for

deactivation due to soluble alkalis such as the

soluble sodium compounds generated by the

combustion of North Dakota lignite. S&L speculated

that more catalyst and a larger reactor may be

possible solutions; however/ how much more catalyst

or how much larger the reactor would have to be to

solve the problem was unknown. S&L also pointed

out that some design issues for North Dakota have

not been addressed by Powder River Basin

experience. Some of these issues include:

• The high level of soluble alkali in North

Dakota lignite

• The particle size and sticky nature of high

alkaline North Dakota lignite

• Potential abrasive qualities of North Dakota

lignite ash

S&L concluded their presentation with the following

statement about North Dakota lignite: "There are

attributes of this fuel in an SCR environment that

are not well understood today and need more

investigation to predict its performance. /I S&L

37
recommendations included a parametric pilot test

program to:

Answer questions on:

• soluble alkalis

• ash characteristics

• size

• stickiness

• abrasive qualities

• Compare findings with PRB experience.

The NSR Manual 1 describes the process commonly used

for bringing a control technology concept to

reality as a commercial product as follows:

• concept stage

• research and patenting

• bench scale or laboratory testing

• pilot scale testing

• licensing and commercial demonstration

• commercial sales

"A control technique is considered available (and

thus technically feasible), 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 or dissimilar source

type."

"Commercial availability by itself, however, is not

necessarily sufficient bases for concluding a

38
technology to be applicable and therefore

technically feasible. Technical feasibility, as

determined in Step 2, also means a control option

may reasonably be deployed on or applicable to the

source type under consideration."

The NSR Manual 1 also states: "Vendor guarantees may

provide an indication of commercial availability

and the technical feasibility of a control

technique and could contribute to a determination

of technical feasibility or technical infeasiblity,

depending on circumstances. However, EPA does not

consider a vendor guarantee alone to be sufficient

justification that a control option will work.

Conversely, lack of a vendor guarantee by itself

does not present sufficient justification that a

control option or an emissions limit is technically

infeasible. Generally, decisions about technical

feasibility will be based on chemical and

engineering analyses (as discussed below) in

conjunction with information about vendor

guarantees."

Minnkota solicited information from SCR and

catalyst vendors via an SCR Vendor Query

Information Request (see Appendix A of Minnkota's

April 18, 2007 response to NDDH and EPA comments) .

On May 8, 2008, Minnkota provided additional

information and a discussion of the responses

received16 • Some of the vendor responses indicate

a higher degree of confidence about the successful

use of SCR at the M.R. Young Station while others

were less optimistic. However, all responses

indicated the following:

39
1) The need for addi tional testing to either

determine if there were any fatal flaws or to

obtain data for the design of a potentially

successful SCR system.

2) The temperature problem (both too low and too

high) had to be resolved for a successful

application of a high dust SCR.

3) "Make good" guarantees were not provided.

The vendors that were more optimistic included

Alstom Power, Haldor Topsoe and CERAM

Environmental, Inc. Alstom Power indicated they

would offer a guarantee of 16,000 hours between

catalyst changeout and Haldor Topsoe expects

greater than 60% deactivation over the first 10,000

operating hours. These estimates appears to be

based on their experience with wood-fired boilers

and that the SCR system would operate between 600-

750°F. Alstom Power suggested that up to 90% NOx

removal efficiency could be obtained; however, they

did not indicate any guarantee of removal

efficiency (performance guarantee). Minnkota

disputes the assertion that wood-fired ash is

comparable to the ash at the M.R. Young Station.

Minnkota indicates that the alkali in the lignite

flyash is in the form of oxide/hydroxide and

partially sulfated form while the alkali in the

flyash from wood would be in a different form, such

as chloride. The Department also questions whether

the loading of catalyst poisons would be

comparable. AP-42 4 , Section 1.6, provides emission

factors for wood residue combustion in boilers.

Table 1.6-4 lists as emission factor for sodium of

0.00036 lb/106 Btu as compared to Center lignite

burned in a cyclone boiler of 0.3008 lb/106 Btu (see

40
table 3). The factor in AP-42 4 is based on data

from boilers with and without particulate control

devices. Even if you assume 99% control efficiency

of sodium by the particulate control device (which

is very unlikely), the emission factor for Center

lignite is still more than eight times larger.

The Department believes the experience with woodfired boilers has questionable application to a

boiler firing North Dakota lignite.

CERAM Environmental (CERAM) initially provided a

design of an SCR system based on 85% NOx reduction

efficiency with a catalyst life guarantee of 16,000

hours. After further discussions with Burns and

McDonnell, CERAM stated "However, considering some

of the remaining uncertainties we would recommend

further testing to ensure a successful result."

The vendor information indicates to the Department

that additional testing will be required to:

1) Obtain design data to determine if SCR can be

successfully applied.

2) Obtain catalyst deactivation data.

3) Obtain data to predict the controlled NOx

emission rate (control efficiency data) .

In addition to the catalyst testing, the vendor

information indicates that the temperature problem

for a high dust SCR must be resolved in order to

have any chance of successfully applying this

technology to the M.R. Young Station. This will

require a detailed engineering study. Minnkota is

not required to do this testing or engineering

study as part of the BACT determination process.

41
Summary:

The characteristics of the exhaust, or flue gas

stream, after combustion of fuel by a boiler are

governed by the design and operating

characteristics of the boiler and the

characteristics of the fuel. In this scenario, the

boilers are cyclones and the fuel is North Dakota

(Fort Union) lignite. Minnkota concluded in its NOx

BACT analyses that available SCR catalysts are not

applicable for the M.R. Young Station (MRYS).

One foremost issue in the NOx BACT analyses is

whether any unique characteristics due to lignite

fired by cyclone boilers are cause for doubt that

known SCR technology lS not applicable and

technically infeasible. In words that parallel EPA

in its review of Minnkota supplied information,

does available information and data show that the

gas stream has unique qualities different than gas

streams of other coal-fired boilers. If so, does

this then cause unique catalyst deposition,

erosion, poisoning, blinding (or fouling or surface

masking) and plugging that are unresolvable

barriers in the ability of known SCR technologies

to control NOx stack emissions, which makes SCR an

ineffective NOx control system?

The written record following Minnkota's BACT

analyses contains substantial supplemental

information provided by Minnkota. We note that

plugging of a catalyst on its face due to

deposition of particles larger than the pitch of a

catalyst (a.k.a. catalyst channel blockage) and

plugging of pores on surfaces of a catalyst are

generally different physical interactions. Our

42
review of the supplemental information concludes

that the following facts are not disputed by EPA.

1) In cyclone firing of Fort Union lignite and

Center Mine coal, about 45 to 50% of the ash

forming components of the coal end up as fluegas ash. Unburned or partially burned organic

fraction of the Fort Union lignite, which

contains more sodium than other coals, reacts

with silicate particles causing a "stickiness"

quality of flue gas ash, which results in ash

deposits on heat transfer surfaces. Larger

particles from the deposits fracture on heattransfer surfaces (a.k.a. popcorn ash) at a

higher rate and enter the flue gas stream.

Consequently, due to the stickiness of the

lignite ash, a higher rate of deposition on

surfaces of catalytic reactors occurs compared

to other coal and boiler scenarios, as

reported by Minnkota.

2) Fort Union lignite, and the Center Mine coal,

has a higher moisture content and is oxygen

rich compared to other coal types. This

lignite also has a higher sulfur content

compared to PRB coal. Consequently, the flue

gas stream is rich in sulfur dioxide (3°2 ) and

sulfate (3°4 ) compared to other coal types.

3) Fort Union lignite, and the Center Mine coal,

has a higher organic matter content compared

to other coal types. This lignite contains a

higher proportion of alkali metal

constituents, especially sodium (Na). Cyclone

combustion of the coal produces ash, which is

partitioned as slag on high temperature boiler

surfaces due to cyclonic air circulation and

43
as flue gas vapor and fine particles (less

than 15 micrometers (microns)). About 75% of

total sodium in the lignite is associated with

the organic fraction of the lignite, the

remaining sodium is water soluble; so very

little of the sodium is associated with the

mineral fraction of the lignite such as clays.

During combustion, organic and water-soluble

sodium vaporizes. Consequently, combustion of

the coal leads to higher flue-gas

concentrations of alkali metals in vapor form.

4) Alkali vapors condense (homogeneous

nucleation) due to flue-gas cooling or react

(heterogeneous nucleation) with other flue gas

constituents, e.g., mineral silicates and

sulfate. Evidence for these reactions is

found in morphological data from filter

samples of flue gas taken at the MRYS. The

size distribution of flue gas particles is bimodel, relating to organically associated

inorganics in coal and coalesced minerals and

inorganics in flue gas; the size distribution

varies by coal type and combustion method.

5) NOx reduction occurs on the flat surfaces of a

catalyst and in pores within the flat

surfaces. The pores are open to the flue gas

passing through the catalyst reactor.

Condensed vapors, alkali sulfates and

alkaline-earth oxides and silicates are minute

particles (less than 1 or 2 microns), which

enter pores of the catalyst (a.k.a. plugging)

and prevent catalytic reaction with NOx •

Residual alkali vapors, Na, potassium (K) and

calcium (Ca) displace hydrogen (H) on fresh

catalyst, which prevents catalytic reaction

44
with NOx (a.k.a poisoning) and reacts with

sulfate to cause blinding of catalyst

surfaces. Pore condensation of sodium also

causes catalyst deactivation, which is a major

deactivation mechanism. The rate of catalyst

deactivation depends on the concentration and

form of alkali in the flue gas; higher Na and

K accelerate catalyst poisoning, blinding and

plugging, which requires more frequeneyt

catalyst maintenance.

6) There are no SCR systems planned, constructed

or operating in the flue gas stream of cyclone

boilers fired with Fort Union lignite. Fort

Union lignite has some coal characteristics

that are uniquely different than Gulf Coast

lignites, such as the larger proportion of

organic matter and association of alkali,

specifically sodium, with that organic matter.

7) Slipstream SCR reactors of the same design

were installed at two power plants to test SCR

for NOx emissions control. One of the plants

was cyclone fired with Fort Union lignite and

the other with subbituminous coal. Deposition

on the reactor surface after two months using

the lignite was significantly greater; the

deposits were rich in sodium, calcium and

sulfur. The tests confirmed catalyst blinding

and plugging, but did not provide rates for

catalyst deactivation. Tests also indicated

that the deposits causing blinding and

plugging of pores contained more sodium

compared to PRB coal.

8) There may be an engineering solution to reduce

deposition on the surface of catalytic

45
reactors. But there is no known in-reactor

engineering solution to:

(a) reduce deactivation rates caused by

heterogeneous reactions that form the

particles that cause pore blinding and

plugging, or

(b) to restore the catalytic reactions by

removing particles from catalyst pores.

9) There are no usable data for rates of

deactivation of SCR catalyst in the flue gas

of cyclone combustion of Fort Union lignite

and Center Mine coal. Catalyst pitch is the

only apparent catalyst geometric affecting ash

deposition; but pitch also affects flue gas

velocity through the reactor and, thus, times

of exposure of NOx for reduction to nitrogen

(N2 ) and water (H2 0).

10) There are several factors relevant to

Minnkota's MRYS, such as locations of

economizers and air pre-heaters, that require

engineering design solutions before SCR could

be considered as a viable control technology.

The NSR Manual! does not provide specific

numeric performance measures that an SCR NOx

control technology must achieve to satisfy the

manual's applicable (technically feasible)

criteria.

Companion issues include ammonia slip and

pyrosulfates emitted from a high-dust SCR will

exaggerate flue-gas particulate (ash) deposits on

low-temperature convective pass surfaces in the

economizer and the primary air pre-heaters.

46
Our review of the supplemental information

concludes that EPA generally disagrees with

Minnkota's perspective on some relevant issues

relating to cyclone boiler and heat exchanger

systems, and flue gas characteristics that can

impact SCR catalyst performance. In summary,

Minnkota asserts:

1) Center Mine coal fired in the Minnkota cyclone

units has important time variable ash content

and ash constituent concentrations that must

be included in the technical assessment of SCR

applicability and feasibility. An engineering

focus on single constituents alone or on

average constituents can cause significant SCR

design errors.

2) The flue gas ash characteristics of Center

Mine coal-fired cyclones and current catalyst

geometries are expected to create a required

aggressive on-line cleaning of the catalyst

and frequent catalyst replacement resulting in

forced boiler outages.

3) The geometries of catalysts have not been

improved to minimize vapor phase and small

particle deposition and plugging within the

pores of catalyst[s]. The pores are prone to

filling through the transport processes of

diffusion and impaction, and the flue-gas rich

in sodium, as well as other alkali, greatly

increases rates of catalyst deactivation.

Adjusting catalyst pitch alone to accommodate

the particulate in the flue gas does not

address the higher flue-gas sodium whether in

a high dust or low dust SCR application. A

larger pitch reduces flue gas velocity and

47
increases the sodium vapor phase and small

particle diffusion into pores of the catalyst.

4) SCR catalyst vendors are not willing to

guarantee performance of their respective

catalysts in a Center Mine coal-fired cyclone

boiler application. For example, there has

been no work by catalyst vendors that has

advanced SCR systems for high sodium

applications.

Our review of the supplemental information

concludes that Minnkota generally is concerned with

or disagrees with EPA's perspective on some

relevant issues relating to cyclone boiler and heat

exchanger systems and flue gas characteristics that

can impact SCR catalyst performance. In summary,

EPA asserts:

1) Minnkota has not provided information that

"shows that ... [deposition] and deactivation

of the SCR catalyst is an unresolvable

technical barrier and/or the ability of an SCR

to control NOx would be so limited that SCR

would be an ineffective control option." "A

lack of a full-scale long-term commercial SCR

installation at a facility with similar sodium

levels in the fuel is not evidence that SCR is

technically infeasible." The expected SCR

problems described by Minnkota are "more a

matter of cost than technical feasibility."

2) The success of SCR technology applied to

cyclone boilers as a source category is

demonstrated to be technically feasible for

coal types other than Fort Union lignite. And

successes and failures of PRB-fired cyclone

48
boilers provides uvaluable information for

designing an SCR system on a plant burning

North Dakota lignite." uThere are engineering

challenges with operating an SCR system at

MRYS, ... these would largely be a matter of

cost and should be examined under step 4 of

the Top-Down BACT analysis." For example, SCR

maintenance and downtime do Unot render the

technology technically infeasible".

Refinements of engineering solutions to the

affects of flue gas characteristics due to

Center Mine coal-fired cyclones on the

catalyst can been implemented following start

up of an SCR system.

Conclusions:

The Department has completed an extensive review of

all aspects of the application of SCR technology to

the M. R. Young Stat ion. Whether the probl ems

associated with adapting SCR technology to a

cyclone unit firing North Dakota lignite can be

overcome is highly speculative.

The Department makes the following conclusions:

1) Lignite from the Center Mine is extremely

variable in heat content, ash content, and in

the constituents that make up the ash. This

variability will affect the design and

operation of an SCR system.

2) The only pilot scale testing that has ever

been conducted on a unit firing North Dakota

lignite was at the Coyote Station. The pilot

scale SCR plugged after only 2 months and

little useful data was obtained. However, the

49
testing used the same protocol as testing at

the Columbia and Baldwin Station which had

fewer problems. The Columbia and Baldwin

Stations burn subbituminous coal. The Coyote

testing demonstrates to the Department that

North Dakota lignite firing will have more

severe effects (plugging and catalyst

deactivation) than units firing subbituminous

coal when the same design is employed.

Operation of an SCR system for only 2 months

between catalyst change out is much less time

than is normally expected (at least 10, 000

hours or 13.7 months) for power plants.

Operation of an SCR system for only 2 months

between catalyst replacement is not considered

successful operation of SCR technology.

Without pilot scale testing, the life of the

catalyst cannot be predicted with any

reasonable certainty.

3) North Dakota lignite contains primarily

organic sodium compounds. The combustion of

the lignite produces soluble sodium compounds

which causes more severe catalyst deactivation

problems than insoluble sodium compounds.

4) The flue gas constituents that cause SCR

catalyst deactivation at the M.R. Young

Station are significantly different from Texas

lignite, Wyoming PRB subbituminous coal, and

Pennsylvania bituminous coal. When cyclone

boilers combusting North Dakota lignite are

compared to any other type of combustion unit

burning the other types of coal, the

concentration of sodium compounds in the flue

gas is at least 6 times greater (based on

average coal and lb/wscf basis) than the other

50
types of fuel and the total primary alkali

constituents (CaO, Na 20, MgO and K20) are

approximately double. The flue gas generated

at the M.R. Young Station is different from

the flue gas at any plant where SCR technology

has been applied, primarily due to the high

concentration of soluble sodium compounds and

the total flue gas loading of catalyst

deactivation chemicals. This difference in

flue gas characteristics will preclude the

successful application of existing SCR

technology to the M.R. Young Station.

Additional pilot scale testing is necessary to

learn if the technology can be adapted.

5) Both Burns and McDonnell and Sargent and Lundy

have extensive experience with the design and

operation of SCR systems. Burns and McDonnell

has expressed concerns whether an SCR system

can be successfully designed and operated at a

cyclone boiler combusting North Dakota

lignite. S&L has indicated that certain

design issues have not been addressed by PRB

(subbituminous coal) experience. They have

also indicated that some important unanswered

questions pose significant risks for an SCR

design engineer and recommended pilot scale

testing before design takes place.

6) The NSR Manual! lists the stages in the

development of a commercial control system

from concept stage to commercial sales.

Experimentation with the SCR system takes

place during the bench scale/laboratory

testing or pilot scale testing stages.

Although adjustments of full scale (commercial

product) units is often necessary, the source

51
operator should not be required at this stage

to conduct experimentation in order to make

the equipment work. This could cause extended

time delays and resource penalties for the

source operator. To design and install an SCR

system for a cyclone unit firing North Dakota

lignite without obtaining additional data from

bench scale or pilot scale testing would be

experimentation.

7) The temperature variation of the flue gas

entering the SCR will adversely affect

performance and must be resolved for

successful application of this technology.

Engineering studies will be required to

determine if this problem can be resolved.

Minnkota is not required to experience

extended time delays or resource penalties to

allow research to be conducted. Neither is

Minnkota required to experience extended

trials to learn how to apply a technology.

The temperature problems for the SCR will

require extensive, and correspondingly

expensive, engineering studies to determine if

this problem can be resolved.

8) There are unresolved issues regarding catalyst

erosion from the ash generated at the M. R.

Young Station. The pilot testing being

conducted in Texas mayor may not resolve

issues regarding abrasion of the catalyst by

the ash in the flue gas. However, that data

is not available at this time. If it does not

resolve the abrasion issues, additional pilot

testing will be required to determine if SCR

technology can be successfully adapted to the

M.R. Young Station. Minnkota is not required

52
to conduct this pilot testing. This testing

may also prove that SCR technology is not

feasible for lignite combustion.

9) Poisoning, blinding and plugging of a catalyst

are affected by the geometries and properties

of the catalyst. Cyclone firing of Fort Union

lignite and Center Mine coal results in a flue

gas stream that highly accelerates poisoning,

blinding and plugging (of pores) due to the

rich sodium and potassium vapors, particles

and ammonia sulfates (due to ammonia

injection) in lignite-fired cyclone flue gas.

The engineering solutions of a larger SCR

reactor, more catalyst and larger pitch do not

resolve the rapid plugging of catalyst pores,

at least with some certainty to assure a

predictable useful life of catalyst before

change out. There is no catalyst vendor

solution to reduce or eliminate catalyst pore

plugging. The chemical and physical process

of pore plugging cannot be reversed, which

dictates catalyst change out.

10) Without pilot scale testing, the long term NOx

reduction efficiency, the volume of the

reactor, the catalyst pitch, life of the

catalyst, or even the type of catalyst to be

used cannot be predicted with a high degree of

confidence. Sargent and Lundy has pointed out

that to design an SCR system for a plant

burning North Dakota lignite without pilot

scale testing would present significant risks

for the SCR design engineer. Without these

design factors determined, any cost estimate

would be conjecture and any evaluation of cost

effectiveness or incremental cost in Step 4 of

53
the BACT analysis would be meaningless.

Minnkota is not required to conduct pilot

testing to obtain this data.

11) SCR technologies have not been installed fullscale on a boiler firing North Dakota (or

similar) lignite; In fact, vendors cannot

without further pilot testing, guarantee SCR

system performance for M.R. Young Station

boilers firing North Dakota lignite. Even the

most optimistic vendors don't offer true

guarantees of catalyst performance; rather,

the guarantee is limited to the contact value

and contract value is a small portion of a

typical full-scale SCR system installation.

All vendors admit that additional pilot

testing would be needed (the best estimates

that would take about one year), and the NSR

Manual notes that "technologies in the pilot

scale testing stages of development would not

be considered available for BACT review."

Some vendors have suggested that catalyst life

might be in the vicinity of 16,000 hours

between replacements (another has estimated

about 10,000 hours, but this is based on

boilers firing wood with SCR that has 5-10

times less fly-ash, and 70-80 times less

sulfur), but significantly these are guesses

rather than guarantees.

11) The NSR Manual 1 states: "In practice, decisions

about technical feasibility are wi thin the

purview of the review authority." The review

authority is the North Dakota Department of

Health.

54
Therefore, the Department has determined, based on

guidance in Chapter B of the NSR Manual 1 , that high

dust SCR technology is not technically feasible at

this time for both units at the M.R. Young Station.

b. Low Dust and Tail Gas SCR

Catalyst Deactivation:

The problems associated with a low-dust SCR or a

tail-gas SCR are similar. Minnkota's analysis list

them as:

Catalyst Fouling and Deactivation

Site Space Constraints

Reheat of Flue Gas

Catalyst deactivation would be primarily due to

alkali mineral compounds that are not removed by

the ESP or S02 scr~bbing system. These include

sodium and calcium sulfates that were discussed

previously. The Department has had some experience

with sodium compounds passing through air pollution

control devices. The Minn-Dak Farmer's Coop.

operates two coal-fired boilers that are equipped

with a mechanical collector and wet scrubber for

particulate matter and S02 control. Minn-Dak had

trouble complying with its particulate matter

emission limit (45.5 lb/hr which equates to 0.10

Ib/106 Btu) due to sodium compounds passing through

the air pollution control devices. In order to

maintain compliance, the ash Na20 content of the

coal combusted had to be limited to 2.8% (dry

basis) . This has been established as a fuel

restriction within Minn-Dak's Title V Permit to

Operate.

55
Minnkota, in its November 9, 2007 response to

comments, provided evidence of sodium and potassium

compounds that deposited downstream of the

electrostatic precipitator on Unit 1. This

indicates that the electrostatic precipitator will

not remove all of the submicron sodium particles

that are generated by the combustion of Center

lignite. Given the high expected emission rate of

sodium compounds (see Table 3), it appears a

significant amount of sodium compounds, a catalyst

poison, will enter a low dust or tail gas SCR

system.

The deactivation issue for low-dust and tail-gas

SCR remains as with the high-dust SCR. The

research, design and pilot testing needed to

develop an SCR system that will have reasonable

success makes this technology also not applicable

at this time.

Site Constraints:

The NSR Manual 1 states: "Also a showing of

unresolvable technical difficulty with applying the

control would constitute a showing of technical

infeasibility (e.g. size of the unit, location of

the proposed site, and operating problems related

to specific circumstances of the source). Where

the resolution of technical difficulties is a

matter of cost, the applicant should consider the

technology feasible."

Minnkota has not indicated that the site

constraints are unresolvable. Therefore, this

issue appears to be an economic consideration

instead of a technical feasibility issue.

56
Reheat of the Flue Gas:

Minnkota has not indicated there are any

unresolvable constraints to reheating the flue gas.

Again l this appears to be an economic issue instead

of a technical feasibility issue. One issue with

reheat is the generation of additional air

contaminant emissions. Depending on the fuel used

for reheat I emissions of NOxl S02 I particulate

matterl carbon monoxide and volatile organic

compounds could increase. This increase in

emissions would be an issue if low-dust for tailgas SCR were considered technically feasible.

In summary, the Department believes that catalyst

deactivation of a low-dust or tail-gas SCR due to

alkali compounds is an issue that will require

extensive research, design and pilot testing to

determine whether the technology can be

successfully applied to units fired on North Dakota

lignite. Therefore I these technologies are not

considered applicable and not technically feasible

at this time.

3. Electro - Catalytic Oxidation (ECO®)

Electro - catalytic oxidation (ECO®) is a multi-pollutant

central system that utilizes a reactor for oxidation of

pollutantsI an absorber vessel for S02 and NOx removal

and a wet electrostatic precipitator for removal of acid

aerosols I fine particulate matter and oxidized mercury.

The process has been demonstrated at First Energy/s R.E.

Burger Plant in Shadyside I Ohio. This demonstration was

a slipstream operation that was approximately equivalent

to 50 MWe. The boiler was a front wall-fired unit that

combusted eastern bituminous coal. A 215 MWe project is

scheduled for the Bay Shore Plant in Oregon l Ohio.

57
A pilot scale test of the ECO reactor was conducted at

M.R. Young Station starting in July, 2007. The system,

which was designed by Powerspan Corporation and the UND

EERC, was placed downstream of the Unit 1 electrostatic

precipitator. The final report11 for the testing

indicates that sodium-rich aerosols and small ash

particles accumulated and became bonded on the surface of

the silica electrodes. Within a two-week period, the

sodium and ash accumulation reduced the NOx conversion

efficiency from greater than 90% to less than 40%. The

use of an acoustic horn was ineffective in eliminating

the sodium and ash accumulation. There is no proven

method for cleaning the electrodes without removing the

electrodes from the reactor. The Department believes

that extensive testing would be required to determine a

method for in-situ cleaning of the electrodes or

reduction of the sodium/ash particles. Therefore, the

technology is not considered technically feasible at this

time.

4. Rich Reagent Injection (RRI) with Advanced Separated

Overfire Air with or without SNCR

Minnkota has indicated that the use of RRI has

insurmountable problems which makes it technically

infeasible. This is primarily due to the inability to

control the air/fuel proportions to ensure that a

stoichiometric ratio of under 1 is maintained at all

cyclones. If the stoichiometric ratio is too far below

1, fuel ash will be solidified in the cyclone barrel. If

the stoichiometric ratio is above 1, the oxygen in the

excess air will oxidize the reagent (urea) and produce

additional NOx emissions. The inability to control the

stoichiometric ratio is due to the highly variable

quality of the lignite combusted. Minnkota has provided

data which shows as much as 12% difference in heating

58
value between lignite fed to individual cyclones at the

same time.

The current configuration of the furnaces at the M.R.

Young Station is incompatible with RRI. The reagent

injection would be near the elevation of the existing

lignite drying system vent ports. The oxygen introduced

with the lignite drying systems air stream would cause

the reagent to be oxidized which would increase NOx

emissions.

Minnkota has operated the M.R. Young Station since 1970

using lignite from the Center Mine. Minnkota's

experience operating the plant with the quality of the

lignite supplied is persuasive in determining the

feasibility of this technology. RRI may not reduce NOx

emissions and could actually increase emissions.

Extensive testing would be required to determine if this

technology could be successfully applied to the M. R.

Young Station. The Department concurs with Minnkota's

determination that RRI is not technically feasible and

RRI will not be considered further.

5 . SNCR and Fuel Reburn

To the Department's knowledge, only one permanent

application of conventional gas reburn and SNCR is known.

It was applied to a tangentially fired boiler at the

Somerset Station. The Somerset Station fires eastern

bituminous coal and is a relatively small utility unit

rated at 120 megawatts. The Minnkota units are cyclonefired, more than twice as large as the Somerset boiler,

and fire North Dakota lignite. The NSR Manua12 states:

UFor 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

59
and other sources to which the technique had been applied

previously. II The lack of experience and the differences

between Minnkota and Somerset indicate that the

effectiveness of this technology when applied to the

units at the M.R. Young Station is unknown. Minnkota is

not required to experience extended trials to learn how

to apply this technology. Therefore, the Department

considers this technology not available for a cyclone

boiler burning North Dakota lignite and thus infeasible.

6. Fuel-Lean Gas Reburn (FLGR~) plus SNCR

No actual demonstration or permanent installations on

cyclone boilers were found. Minnkota's analysis stated

that a technical paper on FLGRTM indicated the technology

when used alone provided only a 27% reduction in NOx

emissions. This is less than other technologies such as

ASOFA (40%). Thus, ASOFA plus SNCR will be a superior

option for controlling NOx ' The combination of FLGR~

plus SNCR has not been demonstrated on a cyclone boiler.

Because of inferior expected NOx removal efficiency and

the lack of commercial application to a cyclone boiler,

this option was not considered further.

7. Oxygen - Enhanced Combustion

This technology has only been demonstrated on a

pulverized unit (non-cyclone) firing bituminous coal.

The testing indicated a reduction efficiency of

approximately 38% down to approximately 20% as the

stoichiometric ratio approached 1.0. 12 This technology

has not been demonstrated on either a temporary or

permanent basis for a cyclone boiler burning any type of

coal or on boilers as large as those at the M.R. Young

Station, and the NOx reduction is less than ASOFA (40%).

The Department believes the technology is not available,

60
is inferior to other options and will not be considered

further.

8. Water/Steam Injection

Because of the high moisture content of the lignite (35-

40%) combusted and the need to ignite and sustain stable

combustion and molten slag in the cyclones, this

technology is considered technically infeasible.

9. Hydrocarbon Enhanced SNCR (HE-SNCR)

HE-SNCR uses an ammonia-based reagent which is

continuously injected (through a grid) into the

superheater/reheater pass of an operating boiler with

small amounts of gaseous hydrocarbon (usually natural gas

or propane). Doosan Babcock Energy marketed a commercial

version of HE-SNCR as NOx Sta~M and claimed NOx

reductions up to 70%. Actual experience indicates NOx

reduction efficiencies of 68 80% when used in

combination with overfire air and air staged combustion.

There is no data for use of HE-SNCR alone.

NOx StarTM has been installed on a tangentially fired

boiler and a wall fired unit, both burning eastern

bituminous coal. It appears this technology has never

been applied to a cyclone boiler or any unit burning

subbituminous coal or lignite. Minnkota has indicated

that the fouling characteristics of their ash and varying

loads would create problems for the successful use of

this technology. The Department reviewed several BART

determinations for power plants in other states that are

burning western subbituminous coal. Several analyses did

not list this technology as being available, some listed

it as in the pilot scale stage for subbituminous coal and

one analysis indicated that it is currently not being

marketed. The Department contacted Doosan Babcock and

61
confirmed that they are not currently marketing the NOx

Star~ technology because it did not provide sufficient

NOx removal efficiency. 10

The fouling characteristics of Center lignite are well

documented. The variability of the Center lignite (which

affects load) has also been documented in Minnkota 's

responses to comments on its BACT analysis. These

problems and the lack of experience with cyclone boilers

and subbituminous coal/lignite will require extensive

testing and engineering analysis to determine if the

technology can be successfully applied to the boilers at

the M.R. Young Station. These issues plus the lack of a

commercial vendor indicates the technology is not

commercially available for this application and thus

technically infeasible.

10. Other Technologies

The following technologies are considered technically

feasible:

SNCR

SNCR w/SOFA or W/ASOFA

Conventional Gas Reburn

Coal Reburn

Fuel Lean Gas Reburn

ASOFA

SOFA

Combustion Improvements (included with SOFA)

Flue Gas Recirculation (not expected to reduce NOx )

C. Step 3: Rank 'Remaining Control Technologies by Control

Effectiveness

The top technologies are as follows:

62
Unit 1 Unit 2

Reduction Reduction

Technology (%) (%)

SNCR w/ASOFA 58 58

Gas Reburn w/ASOFA 56 55

Lignite Reburn 55 54

w/ASOFA

Fuel Lean Gas 46 45

Reburn w/ASOFA

ASOFA 40 38

Minnkota has indicated that ASOFA will achieve approximately

40% reduction of NOx emissions at Unit 1 and 38% at Unit 2.

They have also indicated that SNCR w/ASOFA will achieve an

overall efficiency of 58% at each unit. This equates to an

additional 31% removal for Unit 1 and 33% for Unit 2 by using

a combination of ASOFA and SNCR instead of just ASOFA. The

EPA Air Pollution Control Cost Manual 2 indicates that SNCR, in

typical field applications, provides 30-50% NOx reduction.

Al though the removal efficiencies for SNCR are lower than

expected at new facilities, it is still within EPA's expected

range.

Table 5

Emissions Reductions

Annual Average

Annual Average Controlled Emission

Baseline Emission Rate Rate

Unit Technology lb/l06 Btu Tons/Yr lb/l06 Btu Tons/yr

1 SNCR w/ASOFA 0.849 9934 0.355 4025

1 Gas Reburn w/ASOFA 0.849 9934 0.374 4275

1 Lignite Reburn 0.849 9934 0.385 4343

w/ASOFA

1 FLGR w/ASOFA 0.849 9934 0.460 5260

63
1 ASOFA 0.849 9934 0.513 5874

2 SNCR w/ASOFA 0.786 15792 0.330 6418

2 Gas Reburn w/ASOFA 0.786 15792 0.350 6883

2 Lignite Reburn 0.786 15792 0.360 6821

w/SOFA

2 FLGR w/ASOFA 0.786 15792 0.432 8441

2 ASOFA 0.786 15792 0.489 9651

D. Step 4: Evaluate Most Effective Controls and Document

Results

Minnkota has provided a detailed cost estimate of the various

options in Section 3.4 of each analysis. The costs are

summarized as follows:

Table 6

Costs

NOx Control

Reduction Annualized Cost

unit Alternative (tons/yr) Cost ($/ton)

1 SNCR w/ASOFA 5909 7,472,000 1265

1 Gas Reburn w/ASOFA 5659 37,334,000 6597

1 Lignite Reburn w/ASOFA 5591 11,388,000 2037

1 FLGR w/ASOFA 4674 16,999,000 3635

1 ASOFA 4060 2,490,000 613

2 SNCR w/ASOFA 9374 11,405,000 1217

2 Gas Reburn w/ASOFA 8909 63,883,000 7171

2 Lignite Reburn w/ASOFA 8871 19,475,000 2195

2 FLGR w/ASOFA 7351 29,313,000 3988

2 ASOFA 6141 4,376,000 713

Minnkota also evaluated the energy and environmental impacts

associated with each control alternative for both units. The

64
use of SNCR will cause increased emissions of ammonia (ammonia

slip) . However, the amount of emissions can generally be

limited to less than 10 ppm. Advanced separated over fire air

may cause a slight increase in carbon monoxide emissions.

Based on the analysis, the Department concludes that the

energy and environmental impacts would not preclude the

selection of any of the alternatives as BACT.

E. Step 5: Select BACT

Minnkota has proposed that the most efficient technically

feasible control alternative (SNCR w/ASOFA) is BACT and has

proposed emission limits. All of the analyses for the BACT

determinations were conducted using 12-month rolling average

emission rates. This was done for ease of conducting the

economic analysis which utilizes annual emissions. The

Consent Decree specifies in paragraph 66 that the BACT limit

must be on a 30-day rolling average basis. Minnkota has

proposed the following limits:

1

2

12-month

Rolling Average

(lb/106 Btu)

0.355

0.33

Proposed

BACT Limit

(lb/106 Btu-30.d.r.a.)

0.360

0.350

The Department has evaluated the continuous emissions monitor

data for 2004 and 2005 for both units at the M.R. Young

Station. The evaluation indicated that the maximum 30-day

rolling average was approximately 104% of the annual average

emission rate for unit 1 and approximately 106% for Unit 2.

Based on this evaluation, it appears the proposed 30-day

rolling average emission limits are appropriate based on the

annual average emission rates evaluated.

65
The proposed limits are based on continuous operation of the

boiler. Electric utility boilers are subj ect to malfunctions,

scheduled outages or other situations which require shutdown

and eventual startup. During startup, NOx emissions can be

significantly higher than during normal operations. Minnkota

has proposed the installation of SNCR with advanced separated

overfire air. The EPA Air Pollution Control Cost Manua12

states:

"The NOx reduction reaction occurs within a specific

temperature range where adequate heat is available to drive

the reaction. At lower temperatures the reaction kinetics are

slow and ammonia passes through the boiler (ammonia slip). At

higher temperatures the reagent oxidizes and additional NOx is

generated. The temperature window is dependent on the reagent

utilized. Figure 1.3 shows the NOx reduction efficiency for

urea and ammonia SNCR at various boiler temperatures. For

ammonia, the optimum temperature is from 870°C to 1100 0 C

(1600 0 F to 2000 0 F)."

66
---- // ~'

1/

II

f / \

/ / \

/ I

//

I~ -Urea

I-""'" --Arrm:mia

-

'100

90

.-.. 80

0

'-'"

>- 70 ()

c

<I)

'0 60

IE

UJ

c 50

0

t5

:;) 40

"0

(l)

0:: 30 x

0

z 20

10

o

'1200 1400 1600

Temperature (OF)

1800 2000

Figure 1.3: Effect ofTemperattu"e on NOx Reduction

"Flue gas temperature within the boiler depends on the boiler

design and operating conditions. These are generally set to

meet steam generation requirements and are not always ideal

for the SNCR process. Flue gas temperatures in the upper

furnace through the convective pass may vary by ±150oC (300°F)

from one boiler to the next [1]. In addition, fluctuations in

the boiler load profile affect the temperature within the

boiler. At lower load profiles, the temperature within the

boiler is lower. variations in the flue gas temperature make

the design and operation of an SNCR system more difficult."

It is clear to the Department that startup and shutdown of the

boiler will affect the SNCR system and perhaps the overfire

system also (see p. 3-42 to p. 3-46 of Minnkota's BACT

analysis). Minnkota has stated that startup has lasted up to

67
61 hours (2.5 days) for Unit 1 and 115 hours for Unit 2 (4.8

days). Including up to 4.8 days of start/shutdown emissions

within a 30-day rolling average emission rate calculation will

make compliance extremely difficult. In three recent PSD

application reviews for power plants, the Department has found

sufficient cause to provide alternative limits under BACT for

periods of startup and shutdown. The State of Montana in the

permit for the Highwood Generating Station, EPA Region 9 in

the proposed permit for the Desert Rock Energy Center and the

State of Nebraska in the Ag Soy Processing plant permit also

included alternative limits for NOx during startup and

shutdown. Section 66 of the Consent Decree requires Minnkota

to address in the BACT assessment specific NOx emission limits

during unit startups. Minnkota has evaluated the NOx emission

rates expected during startups. They evaluated the continuous

emissions monitoring data and determined (and verified by the

Department) the following maximum 24-hour average NOx emission

rates over the last five years:

Unit 1 -

Unit 2 -

0.980 Ib/106 Btu

1.064 Ib/106 Btu

Based on this data, Minnkota has indicated that the 30-day

rolling average emission limit for Unit 1 should be adjusted

by 0.041 Ib/106 Btu per boiler startup and unit 2' s limit

should be adjusted 0.102 Ib/106 Btu per boiler startup. The

Department believes adjustment of a 30-day rolling average

emission rate for each boiler startup is not appropriate.

Since most startups are relatively short (5 days or less), a

24-hour emission limit on a mass per unit of time basis is

more appropriate and easier to enforce. It also provides more

certainty of the environmental effects of emissions during

startup or shutdown. For unit 1, the Department proposes

2070.2 Ib/hr (24-hour rolling average). This is equivalent to

0.83 Ib/106 Btu/hr at a heat input of 2500 x 106 Btu/hr or

approximately the same as the steady state pre-control

emission rate of 0.85 Ib/106 Btu. For Unit 2, a limit of

68
3995.6 lb/hr (24-hour rolling average) is proposed.

equivalent to 0.83 lb/106 Btu at 4800 x 106 Btu hour.

also approximately equivalent to the pre-control rate

lb/106 Btu.

This is

This is

of 0.79

After considering all information, including the uncertainties

associated with certain control alternatives, the NOx removal

rates of the alternatives, the costs, additional energy usage

and environmental considerations, the Department proposes that

BACT for both units at M.R. Young Station is represented by

selective noncatalytic reduction (SNCR) operated in

conjunction with advanced separated overfire air (ASOFA) and

that BACT is the following emission limits:

unit 1 - 0.36 lb/10 6 Btu on a 30-day rolling average basis

except during periods of startup or shutdown.

During startup or shutdown, NOx emissions shall not

exceed 2070.2 lb/hr on a 24-hour rolling average

basis.

Unit 2 - 0.35 lb/10 6 Btu on a 30-day rolling average basis

except during periods of startup or shutdown.

During startup or shutdown, NOx emissions shall not

exceed 3995.6 lb/hr on a 24-hour rolling average

basis.

For purposes of this BACT determination, startup is defined

as:

The period of time from initial fuel combustion to the point

in time when the measured heat input to the boiler on a 6-hour

rolling average basis is greater than or equal to 2500 x 106

Btu/hr for Unit 1 and 4800 x 106 Btu/hr for Unit 2. For

purposes of determining compliance, startup cannot exceed 61

hours for Unit 1 and 115 hours for Unit 2.

69
Shutdown is defined as the period of time beginning when the

unit's generation is reduced in a continuous manner until

combustion has ceased.

70
References

1. EPA, 1990 New Source Review Workshop Manual, Prevention of

Significant Deterioration and Nonattainment Area Permitting,

Office of Air Quality Planning and Standards, Research

Triangle Park, NC 27711.

2. EPA, 2002 EPA Air Pollution Control Cost Manual, Sixth

Edition, EPA/452/B-02-001, Office of Air Quality Planning and

Standards, Research Triangle Park, NC 27711.

3. USGS U.S. Coal Quality Database; 2006

http://energy.er.usgs.gov/coalgual.htm

4. EPA, 1995 Compilation of Air Pollution Emission Factors Volume

1: Stationary Point and Area Sources, Office of Air Quality

Planning and Standards, Research Triangle Park, NC 27711.

5. Benson, Steven A., Energy and Environmental Research Center,

Ash Impacts on SCR Catalytic Performance, University of North

Dakota, Grand Forks, ND 58202-9018.

6. Gutberlet, H; Schluter, A.; Licata, A.; Deactivation of SCR

Catalyst.

7. Pritchard, S.; DiFrancesco, C.; Kaneko, S., Kobayashi, N.,

Suyama, K.; Optimizing SCR Catalyst Design and Performance for

Coal-Fired Boilers; Presented at EPA/EPRI 1995 Joint

Sumposium, Stationary Combustion NOx Control; May 16-19, 1995.

8. Sargent and Lundy LLC; Application of SCR Technology to North

Dakota Lignite Fuels; Power Point Presentation; May 2007.

9. Srivastra, Ravik; Hall, Robert E.; Khan; Sikander; Culligan,

Kevin; Lani, Bruce W.; Nitrogen Oxides Emission Control

Options for Coal-Fired Electric Utility Boilers; Journal of

the Air & Waste Management Association; September 2005.

71
10. Personal conversation between Tom Bachman of the NDDH and

Deepak Khajouria of Doosan Babcock Energy Ltd.; February 13,

2008.

11. EERC, 2008; JV Task 117 - Impact of Lignite Properties on

Powerspan's NOx Oxidation.

12. Thompson, David R.; Bool, Lawrence E.; Chen, Jack C.; Oxygen

Enhanced combustion for NOx control; Final Report, DOE Award

No. DE-FC26-00NT407456; March 2004.

13. Personal conversation between Tom Bachman of the NDDH and Bob

Green of Rio Tinto Energy America; May 5, 2008.

14. Personal conversation between Tom Bachman of the NDDH and Ken

Evans of Consumers Energy; May 6, 2008.

15. Email from Bradley Plummer of Consumers Energy to Tom Bachman

of the NDDH; May 13, 2008.

16. 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.

72
Appendix A

Minnkota BACT Analysis

and

Additional Information
Appendix B

Evaluation of Particulate

Matter Emission Rate