MinnkotaPower ~Pg COOPERATIVE, INC.

1822 Mill Road' P.O. Box 13200 • Grand Forks, ND 58208·3200 • Phone (701) 795-4000

August 16, 2007

Terry O'Clair, Director

Division of Air Quality

North Dakota Department of Health

918 East Divide Avenue, 2nd Floor

Bismarck, ND 58501-1947

Subject: SCR Pilot Testing

Dear Mr. O'Clair:

Your Touchstone Energy" Partner ~t'J;;

-

Enclosed, please find a report entitled "APPROPRIATENESS OF CONDUCTING

PILOT TESTING OF SELECTIVE CATALYTIC REDUCTION (SCR) TECHNOLOGY AT

MILTON R. YOUNG STATION UNITS 1 AND 2, FOR USE IN A NOx BACT ANALYSIS". This

report is submitted response to the Department's request that Minnkota consider a pilot test of

SCR catalysts, at Milton R. Young Station, to gather additional data for use in Minnkota's

previously submitted NOx BACT analysis. This report addresses three aspects that must be

considered when making a decision to pursue SCR catalyst pilot test. The aspects are: 1) the

legal basis for the testing; 2) is there a reasonable expectation that the results would be different

than the results of previous testing; 3) could the testing be accomplished in the required amount

of time.

Based upon the information presented in the enclosed report, Minnkota has decided not to

pursue SCR pilot testing at Milton R. Young Station, as elaborated in the document.

Should you have any questions concerning the above, or the enclosed document, please

contact me by telephone at 701-795-4221 or by email atjgraves@minnkota.com.

Yours truly,

...".....'r,.... POWER COOPERATIVE, INC.

;Z::~~ John T. Graves, P.E.

Environmental Manager

C: David Sogard

Luther Kvernen

Craig Bleth

Kevin Thomas

Stu Libby

Tom Anseth

Young Station File
APPROPRIATENESS OF CONDUCTING

PILOT TESTING OF SELECTIVE CATALYTIC

REDUCTION (SCR) TECHNOLOGY

AT MILTON R. YOUNG STATION UNITS 1 AND 2,

FOR USE IN A NOx BACT ANALYSIS

Prepared For

MINNKOTA PO\VER COOPERATIVE, INC

By

Dennis L. Arfmann

Hogan & Hartson

Steven A. Benson

Energy & Environmental Research Center

Carl V. Weilert

Burns & McDonnell

August 14, 2007
BACKGROUND

The North Dakota Department of Health (NDDH) has requested that Minnkota Power

Cooperative (Minnkota) consider performing a pilot test at the Milton R. Young Station (MRYS)

to investigate the technical feasibility of Selective Catalytic Reduction (SCR) technology for

control of emissions of nitrogen oxides (NOx) from the North Dakota lignite-fired cyclone

boilers at that power plant. The results of the pilot test would be used in the NOx BACT analysis

for MRYS. Technical feasibility of SCR application to utility boilers firing this fuel is a

principal issue in the determination of best available control technology (BACT) for NOx

emission control at MRYS. The determination of BACT for NOx emission control at MRYS is a

requirement of the Consent Decree (CD) filed in the case United States ofAmerica and State of

North Dakota v. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative.

Minnkota has evaluated NDDH's request and has decided not to pursue SCR pilot testing at

MRYS for three reasons as elaborated in this document, below. The reasons for not conducting

further pilot testing prior to the BACT determination are:

1. Pilot testing is specifically not required by the BACT determination procedures

established by the U.S. Environmental Protection Agency (EPA).

2. Previous research, including previous SCR pilot testing conducted at the Coyote Station,

indicates that there is not sufficient reason to believe that the pilot testing suggested by

NDDH will produce results any different from those obtained from the prior pilot test.

3. The compliance schedule for installation of NOx BACT technology at MRYS as

established by the CD cannot be met if pilot testing of SCR, followed by installation of

SCR, is selected as the basis for BACT.

Each of these points is explained further in the text that follows.

REGULATORY BASIS FOR MINNKOTA'S DECISION NOT TO CONDUCT PILOT

SCRTESTING

Minnkota's decision not to conduct pilot testing of SCR technology is supported on a regulatory

basis for the following reasons:

1. EPA Guidance Specifically Describes When an Emission Control Technology is "Technically

Feasible"

EPA has prepared a New Source Review Workshop Manual (Draft, October 1990) that explains,

in detail, the evidence and analysis necessary to support a BACT determination. This process of

defending a particular BACT recommendation is summarized in the Workshop Manual as

follows:

The applicant's role is primarily to provide information on the various control

options and, when it proposes a less stringent control option, provide a detailed

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rationale and supporting documentation for eliminating the more stringent

options. [t is the responsibility of the permit agency to review the documentation

and rationale presented and: (I) ensure that the applicant has addressed all of the

most effective control options that could be applied; and (2) determine that the

applicant has adequately demonstrated that energy, environmental, or economic

impacts justify any proposal to eliminate the more effective control options.

Where the permit agency does not accept the basis for the proposed elimination of·

a control option, the agency may inform the applicant of the need for more

information regarding the control option. However, the BACT selection

essentially should default to the highest level of control for which the applicant

could not adequately justify its elimination based on energy, environmental and

economic impacts. If the applicant is unable to provide to the permit agency's

satisfaction an adequate demonstration for one or more control alternatives, the

permit agency should proceed to establish BACT and prepare a draft permit based

on the most effective control option for which an adequate justification for

rejection was not provided. [Workshop Manual at 8.53.]

The Workshop Manual requires an applicant to "make a good faith. effort to compile appropriate

information from available information sources, including any sources specified as necessary by

the permit agency." [ld. at B.Il]. This analysis should at least identify technologies that may be

potentially transferable to the particular source, though later those technologies may prove

technically infeasible or economically cost-ineffective.

For each alternative emission control technique, the applicant should analyze whether the control

technique is feasible. EPA defines a technically feasible alternative as one that is available (i.e.,

commercially available for the application in question) and applicable (i.e., whether the

available controls may reasonably be deployed on the source in question). The Workshop

Manual provides a detailed analysis of the availability and applicability of a control technology,

which bears quoting at length:

In step 2, the technical feasibility of the control options identified in step I is

evaluated. This step should be straightforward for control technologies that are

demonstrated-if the control technology has been installed and operated

successfully on the type of source under review, it is demonstrated and technically

feasible. For control technologies that are not demonstrated in the sense indicated

above,. the analysis is somewhat more involved.

Two key concepts are important in determining whether an undemonstrated

technology is feasible: "availability" and "applicability." As explained in more

detail below, a technology is considered "available" if it can be obtained by the

applicant through commercial channels or is otherwise available within the

common sense meaning of the term. An available technology is "applicable" if it

can reasonably be installed and operated on the source type unGer consideration.

A technology that is available and applicable is technically feasible.

30f2~
Availability in this context is further explained using the following process

commonly used for bringing a control technology concept to reality as a

commercial product:

• Concept stage;

• Research and patenting;

• Bench scale or laboratory testing;

• Pilot scale testing;

• Licensing and commercial demonstration; and

• Commercial sales.

A control technology 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 the pilot scale testing stages 9fdevelopment would

not be considered available for BACT review. An exception would be if the

technology were propo1ied and permitted under the qualifications of an innovative

control device consistent with the provision of 40 CFR 52.2l(v) or, where

appropriate, the applicable SIP.

Commercial availability by itself, however, is not necessarily sufficient basis for

concluding a 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 construction.

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 to be deployed (e.g:, is specified

in a permit) on the same or a similar source type. Absent a showing of this type,

technical feasibility would be based on examination of the physical and chemical

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

stream characteristics of the source types to which the technology had been

applied previously. Deployment of the control technology on any existing source

with similar gas stream characteristics is generally sufficient basis for concluding

technical feasibility barring a demonstration to the contrary. [Ed. at 8.17-8.18]

(emphasis added).

The proper methodfor showing technical infeasibility is identified by the Workshop Manual as

follows:

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[T]he applicant should make a factual demonstration of infeasibility based on

commercial unavailability and/or unusual circumstances which exist with

application of the control to the applicant's emission units. Generally, such a

demonstration would involve an evaluation of the pollutant-bearing gas stream

characteristics and the capabilities of the technology. 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 as technically feasible. The economic feasibility

of a control alternative is reviewed in the economic impacts portion of the BACT

selection process.

A demonstration of technical infeasibility is based on a technical assessment

considering physical, chemical and engineering principles and/or empirical data

showing that the technology would not work on the emissions unit under review,

or that unresolvable technical difficulties would preclude the successful

deployment of the technique. Physical modifications needed to resolve technical

obstacles do not in and of themselves provide a justification for eliminating the

control technique on the basis of technical infeasibility. However, the cost of such

modifications can be considered in estimating cost and economic impacts which,

in turn, may form the basis for eliminating a control technology (see later

discussion at V.D.2). [ld. at B.19-8.20.]

Each of the elements of demonstrating technical infeasibility, along with background and

supporting information as necessary, must be decisively documented.

2. Following the Guidance from the Workshop Manual, Minnkota has Decisively Documented

that SCR is Technically Infeasible at Milton R. Young Station

SCR has not been demonstrated on any North Dakota lignite-fired cyclone unit. ill light of this

lack of demonstration, NDDH has asked Minnkota to consider conducting pilot testing of SCR to

determine the life expectancy of a particular SCR catalyst. However, the 1990 Workshop

Manual concludes that pilot testing of an undemonstrated technology cannot be required as a part

of a BACT analysis.

The Workshop Manual addresses technical feasibility in the context of both demonstrated

technologies (not applicable to Minnkota here) and undemonstrated technologies (Minnkota's

situation). As set forth in detail above, the key questions in determining whether the

undemonstrated technology is feasible are whether the technology is "available" and

"applicable." Most importantly, the Workshop Manual states:

"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.

50f2~
Consequently, technologies in the pilot scale testing stages of development would

not be considered available for BACT review." [ld. at B. 18].

As Minnkota has demonstrated in its previous filings, EERC and Burns & McDonnell have

demonstrated SCR cannot be reasonably installed and operated on the Milton R. Young Station.

SCR is therefore unavailable and inapplicable, and NDDH may not require Minnkota to conduct

extensive pilot testing as a part of a BACT analysis to experiment with the availability or

applicability of SCR to North Dakota lignite-fired cyclone boilers.

In conclusion, Minnkota has demonstrated that SCR is not technically feasible, that that SCR is

not "available" under the EPA guidance, that SCR is not "applicable" under the EPA guidance,

and that a pilot test is not allowed under the EPA guidance for BACT.

TECHNICAL BASIS FOR MINNKOTA'S DECISION NOT TO CONDUCT PILOT SCR

TESTING

In order to determine if additional pilot testing of SCR catalysts on lignite fueled cyclone-fired

boiler would produce similar or potentially different results from previous testing, the fouling

and poisoning mechanisms must be examined. This is necessary in order to evaluate design .

changes that could be made to reduce or eliminate the fouling and poisoning of the SCR

catalysts.

Fouling and poisoning of SCR catalysts are affected by the following:

• Lignite properties

• Combustion processes

• Partitioning of sodium and other elements during combustion

• SCR catalyst characteristics and properties

• Chemical and physical mechanisms of pore plugging

The primary concern for lignite coals from the Northern Great Plains of North America is

blinding and poisoning of SCR catalysts because of the presence of alkali and alkaline elements

in the coal and their fate upon combustion. Mussatti (2002) indicated in the "EPA Air Pollution

Control Cost Manual- Sixth Edition" the following primary mechanisms for catalyst

deactivation:

"Poisoning - 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."

"Blinding/Plugging/Fouling - 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

6of2~
of the number of sites available for NOx reduction and an increase in t1ue gas pressure loss

across the catalyst."

Based on research, development, and demonstration testing to date these challenges have not

been overcome. Significant fundamental research is required to further develop NOx reduction

technologies for lignite coals.

Lignite Properties

Lignite from the Center Mine in North Dakota is part of the Fort Union region. The Fort Union

region represents the lignite bearing reserves in North America. The age of lignite in the Fort

Union ranges from late Cretaceous through Eocene. The younger lignite coals have higher levels

of oxygen as compared to higher ranked coals. Lignites can contain as high as 20% oxygen on a

moisture and ash free basis. The most important oxygen containing group in lignite is the

carboxylic acid group accounting for up to 65% of the oxygen (Schobert, 1995). The carboxylic

acid groups act as bonding sites for various elements such as Ba, Ca, Mg, Na, and Sr and are

enriched in lignite coals as compared to bituminous coals (Schobert, 1995). As coal rank

increases the oxygen functional groups are lost due to the coalification process. The carboxylic

acids act as ion exchange sites for sodium and other elements such as Mg, Ca, Sr, and Ba that are

accumulated from ground water. The abundance of sodium and other elements that are

associated with the carboxylic acid groups in the coal are determined using chemical

fractionation (Benson and Holm, 1985). The chemical fractionation results for Center lignite

indicates that 76% of the total sodium is ion-exchangeable indicating an organic association in

the coal with the remaining in a water soluble form (Schobert, 1995). In addition to the organic

and water associated impurities, lignites contain significant levels of mineral grains. The types

of minerals present in lignite consist of pyrite, quartz, clay minerals, sulfates, carbonates, and

others (Benson and others, 1993).

Lignite fired at the Milton R. Young (MRY) plant is mined from three seams at the Center mine

of the Fort Union Region, the Kinneman Creek (KC), Hagel A (HA), and Hagel B (HB). The

coal fired in the Units 1 and 2 represent some blending of the coal through handling and delivery.

The variability selected coal quality components for the as-fired Center ligriite is shown in Table

1. The average, maximum, and minimum as well as the percentiles were derived from analysis

of the as-fired coal database. The database consists of 1316 samples of coal collected using

sampling systems on Unit 2. The elements that are largely organically associated as described

above are highlighted. These elements are largely organically associated and can contribute to

the formation of reactive fine particulate during combustion and gas cooling.

70f2~
Table l. Center lignite composition (moisture, ash, sulfur, and heating value expressed on

an as-received basis; and ash composition expressed as weight percent equivalent oxide of

the ash produced at 750 DC).

Moisture, Ash, Sulfur

% % % Btu/lb AI 20 3 BaO CaO Fe203 MgO P20 S K20 Si02 Na20 803

Average 37.13 9.64 0.98 6578 11.68 0.52 13.15 8.90 3.99 0.12 1.33 36.04 4.40 18.39

Max 39.37 25.46' 2.55 7101 15.62 1.22 23.96 24.72 7.09 1.00 2.30 55.98 13.03 34.50

Min 33.56 4.97 0.47 5852 6.31 0.20 6.80 5.38 2.30 0.01 0.16 12.30 0.55 8.12

90th

Perc. 38.10 12.51 1.29 6820 14.23 0.84 19.92 12.20 5.68 0.41 1.92 45.98 8.71 26.25

10th

Perc. 35.95 7.06 0.72 6359 9.58 0.37 9.73 7.08 3.00 0.04 0.61 22.70 1.99 14.35

45th

Perc. 37.17 9.33 0.90 6552 11.62 0.47 12.15 8.34 3.81 0.09 1.36 36.99 4.09 17.30

55th

Perc. 37.37 9.75 0.94 6592 11.97 0.50 12.74 8.68 3.97 0.10 1.44 38.36 4.61 18.02

* High value may be an analysis or reporting error. Sample could not be reanalyzed to verify.

Figures 1 - 3 show the frequency distributions with the lOth, 50th, and 90th percentile values for

sodium, base-to-acid ratio, and ash content in the as-fired database. In addition, the future

Center lignite characteristics in ten-year averages for % sodium oxide in ash, base/acid ratio, and

% ash are plotted on the frequency distribution diagrams in Figures l-3. The future Center

lignite characteristics are based on weighted averages of analysis conducted for drill cores. This

information was used to calculate the weighted averages for to-year spans. The frequency

distribution of the sodium content of the ash is shown in Figure 1. The projections for the future

have similar sodium levels to the upper mode of sodium contents. The sodium content of the

future coals appears to be decreasing initially from the upper mode and then increasing from

2036-2064. The base-to-acid ratio shown in Figure 2 indicates coals typical of lower ash

contents and high levels of sodium, calcium, potassium, and iron relative to silicon, aluminum,

and titanium. This information indicates that the future coals will have a higher propensity on

average to cause low-temperature fouling than coals fired over the past several years. Lower ash

content and higher base-to-acid ratio coals produce more low temperature fouling due to sulfate

formation. Figure 3 shows the projected ash values compared to the as-fired database. The data

from 2006-20 l5 show similar data to the as-fired database with decreasing levels of ash in the

latter years.

8of2~
350

300

I"'-

..... 250

('t)

.....

II

c: 200

:>.

0

c:

Q) 150

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u. 100

50

o-t-.......-....:.,.-"""'T""-"'T"""-,...;

EERC SB29240.CDR

2036-2045,2046-2055

Na20 in Ash

--- BNI Core Database

(2003-2006)

- - - 1O-year averages

90th Percentile:

6.74wt%

Figure 1. Sodium oxide in ash frequency distribution for as-fired database compared to 10-

year averages and weighted Core Database values.

600

500

I"'-

.....

('t) 400 .....

II

c:

:>. 300 0

c:

Q)

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u.

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0

~'Y

EERC SB29241.CDR

Base-ta-Acid

._---- BNI Core Database

(2003-2006)

- - - 10-year averages

90th Percentile:

1.26wt%

2006-2015,2026-2035

2046-2055

2016-2025

Figure 2. Base-to-acid ratio of ash frequency distribution for as-fired database compared

tolO-year averages and weighted Core Database values.

90f2~
350 EERC SB29238.CDR

50th Percentile: 9.53 wt%

300 2006-2015 %Ash

2016-2025

2036-2045 -- BNI Core Database ...... (2003-2006) T""" 250

(W')

T""" - - - 10-year averages 2026-2035

II 2056-2064

c 200 2046-2055

0

c

Q) 150 :::J

0'

u. 100

Figure 3. Ash frequency distribution for as-fired database compared to to-year averages

and weighted Core Oatabase values.

Combustion Processes and Partitioning

The inorganic coal components undergo complex chemical and physical transformations during

combustion to produce intermediate ash species in the form of inorganic vapors, liquids, and

solids. The partitioning of the inorganic components during combustion to form ash

intermediates depends upon the association and chemical characteristics of the inorganic

components, the physical characteristics of the coal particles, the physical characteristics of the

coal minerals, and the combustion conditions. The physical transformations involved in fly ash

formation illustrated in Figure 4 include 1) coalescence of individual mineral grains within a char

particle, 2) shedding of the ash particles from the surface of the chars, 3) incomplete coalescence

due to disintegration of the char, 4) convective transport of ash from the char surface during

devolatilization, 5) fragmentation of the inorganic mineral particles, 6) formation of cenospheres,

and 7) vaporization and subsequent condensation of the inorganic components upon gas cooling.

As a result of these interactions, the resulting ash composition and mass distribution as a function

of size is also shown in Figure 4. Typical ash derived from coal combustion has a bimodal to

multimodal size distribution that consists of a submicron and supermicron size fraction as shown

in Figure 5. The submicron component is largely a result of the condensation of flamevolatilized inorganic components such as sodium. The intermediate size mode at about 2

micrometers is derived from the more refractory organically associated elements such as calcium

and magnesium. The larger particles at approximately 12 to 15 ~lm are derived from the mineral

grains present in the coal. The larger-size particles have been called the residual ashby some

to of262e
investigators (Sarofim and others, 1977) because these ash particles resemble, to a limited

degree, the original minerals in the coal. During the gas-cooling processes in the boiler, the gasphase species condense and the liquid-phase materials solidify. The abundance of these gasphase and liquid materials entrained in the bulk gas flow is highly dependent upon coal

composition and system operating conditions.

Remain in Vapor Phase

- reactions with flue gas components

tion

."..J

0.1 10

Particle Size, J.Itrl

Submicron sodium -rich

aerosols

Particle

Fusion

o 0

oO~o Cenosphere

Fonnation

Reaction

Condensation i1

Coagulation

Nucleation

Char or Mineral

Fragmentation,

Shedding, and

Coalescence

Vaporization

Fuel

Particle

Reducing

Environment

Figure 4. Transformation of inorganic components present in coal during

combustion.

11 of2~
Condensed vapors

en

Q)

u

a.

'5

c:

o

....

u..

Organically associated

Inorganics

Coalesced minerals'other

inorganics

0.1 2 10 -15

Particle size, Micrometers

Figure S. Final size distribution of ash particles produced upon combustion of

lignitic coals (Benson and Laumb, 2007).

Cyclone fired systems enhance the partitioning of the inorganic components both by high

temperatures and cyclonic action. The partitioning of sodium between the slag and coal is shown

in Figure 6. The results show the sodium present in the as-fired coal ash presented with and

without S03. The retention of sulfur in the ash is an artifact of the ashing procedure. In

comparing the level of sodium in the slag to the coal fired for the high-sodium cases, only about

half of the sodium is retained in the slag. The slag samples were recovered from the slag tap for

the boiler. These slag samples include deposits that fall from the walls and the high-temperature

convective pass.

12 of2~
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Cl

a:s

(J) 12.00+----

-0

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(ij

o

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.5 8.00

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E

4.00

o

en

"#. 2.00

0.00

MRY MRY MRY MRY MRY MRY MRY MRY MRY MRY MRY MRY MRY MRY MRY

Coal Coal Slag Coal Coal Slag Coal Coal Slag Coal Coal Slag Coal Coal Slag

111222333444555

(S03-free) (S03-free) (S03-free) (S03-free) (S03-free)

Figure 6. Comparison ofsodium levels in Center lignite coal and slag samples.

The transport of intermediate ash species (Le., inorganic vapors, liquids, and solids) to surfaces

within a combustion system (combustion and air pollution control system) is a function of the

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

and temperature. Several processes are involved in the transport of ash particles to surfaces in

the combustion system. These processes have been described in detail by Raask (1985) and

Rosner (1986). The primary transport mechanisms are illustrated in Figure 7. For larger

particles inertial impaction and eddy impaction in turbulent regions are the dominant

mechanisms. The small particles « 1 /lm) and vapor-phase species are transported by the vapor

phase and small particle diffusion. The inorganic materials are transported to heat-transfer and

catalyst surfaces by diffusion, electrophoresis, and inertial impaction. Thermophoresis is not a

significant contributor to the transport of particles as it related to SCR materials. However,

thermophoresis is a contributor to particle transport on heat transfer surfaces because of the

temperature gradient.

13 of2~
WITH THERMOPHORES/S

bl DISTRIBUTION OF

PARTICLE MASS LOADING

10· 3 L.l.--'--'-....J.--,.J---'-........J.-::'".............u.-:"--'-L.J.J..':'""""-....,;;.,=

10.3 10.2 10·\ 100 10' 102

PARTICLE DIAMETER, dpCfLm)

Figure 7. Overview of ash transport mechanisms (Rosner, 1986); (a) particle size

dependence of captured fra~tion neap; (b) size distribution of the mainstream particle mass

loading. The accumulation rate will involve a combination of a and b.

a I FRACTION CAPTURED S :'00

The vapor phase and small particles are characteristically rich in flame-volatilized species that

condense upon gas cooling in the bulk gas or in the gas boundary layer next to the surface. The

diffusion mechanisms important with respect to the transport of vapor species and small particles

to the surface of SCR catalysts include:

l. Fick diffusion - molecular level.

2. Brownian diffusion - particles suspended by a host Liquid.

3. Eddy diffusion - turbulent systems.

SCR Catalyst Characteristics and Properties

SCR catalysts for coal combustion applications consist of ceramic material with high porosity

that contains imbedded active catalytic sites. The NOx reduction occurs on the active surface of

the catalyst. The active surface of the catalyst consists of flat surfaces and pores within the flat

surface of the catalyst. The flat surfaces and pores in the catalyst are designed to provide gas

contact with the active surface of the catalyst. The pores consist of open macropores and

micropores that occur on the surface of the catalyst structures.

The size of the openings in honey comb catalyst impacts the velocity of the gases flowing

through the catalyst. Pitch is the term used to describe the openings between the flat surfaces of

the catalyst. Figure 8 illustrates the pitch, p and the wall thickness, a. Lower gas velocities will

result for higher pitch numbers while small numbers will result in higher gas velocities through

the catalyst. Catalyst vendors have methods to identify the proper pitch for specific fuel types

and ash characteristics to minimize bridging or plugging where the dominant transport

mechanism is inertial impaction and eddy impaction for the large particles. Selecting a pitch that

140f26U
will minimize the transport of small particles and vapor phase species is not as straightforward.

High pitch catalysts will result in lower velocity gas flow through the catalyst and will create a

thicker boundary layer resulting in an increased potential for small particle transport. Catalyst

geometry plays a significant impact on gas flow patterns through the catalyst. Evaluation of the

literature and information provided by catalyst vendors indicate that the geometries of catalysts

have not been improved to minimize small particle and vapor phase deposition on the surface

and within the pores of catalyst (Hansen, 2007).

. Figure. 8. Catalyst pitch (Mussatti, 2002).

An example of the macropore structure is shown in Figure 9 for an actual surface for a

honeycomb type catalyst. The openings in the catalysts create porosity and surface area to

expose the reactive components of the catalyst to gas phase components. These openings are

prone to filling with small particles and large particles through the transport processes of

diffusion and impaction, respectively. Once these particles are transported to the surfaces they

will be held in place by weak electrostatic and van del' Waals forces and they will react with

vapor phase sulfur oxide species.

Chemical and physical mechanisms of pore plugging

The most significant problems that limit the successful application of SCRcatalysts to lignite

coal is the formation of low-temperature sodium-calcium-magnesium sulfates that will form on

the surfaces of catalysts and the carryover of deposits that will plug the catalyst openings,

resulting in increased pressure drop and decreased efficiency. Studies conducted at Coyote

station (Benson and others, 2005) found significant blinding and filling of the pores with small

particles as sQown in Figure 9. Rapid filling of the pores occurred with the catalyst pitch of 6

mm. These materials were subjected to air pulsing that did not remove the materials from the

catalyst. The characteristics of the materials filling the pore were rich in sodium and calcium

sulfates. A high magnification image of the materials coating the catalyst and filling the pore is

shown in Figure 10. This image shows the importance of the very small particles less than I

micrometer and their impact on the bonding of the deposited materials. These small particles

readily interact with gas phase S02 and SO} expanding to create a bonded matrix as shown in

Figure II that completely fills the pores of the catalyst with a continuous bonded phase. A high

magnification cross-section is shown in Figure 12 of a highly sulfated bonded matrix.

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Diffusion transport,

particles <5Jlm and vapors

Rebound

Diffusion transport,

particles <5Jlm and vapors

Inertial impaction transport,

Particles >5Jlm

Stick

Catalyst Surface

Inertial impaction transport,

Particles >5Jlm

Figure 9. Scanning electron microscope secondary electron image of the macropore

structure of an SCR catalyst with transport process descriptions.

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Figure 10. High magnification secondary electron image of ash filling pores and covering

catalysts.

Figure 11. Scanning electron microscopy image of ash materials filling the pores of

catalyst exposed to flue gases derived from the firing of Beulah lignite at Coyote Stations

(Benson and others, 2005).

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Figure 12. High magnification image of materials typical of ash filling pores that has

sulfated and bonded.

Pyrosulfates are present in ash deposits and will likely form in SCR catalysts. Melting points for

pyrosulfates between 535° and 770°F have been reported in the literature (Singer, 1981). Much

of the past work has focused on the formation of these phases on tube surfaces. These species

contribute to the corrosion of heat-transfer surfaces in coal-fired power plants. The exact

melting point depends on the relative amounts of sodium and/or potassium. The melting points

of selected pyrosulfate phases are shown in Table 2.

The formation of pyrosulfates involves the following processes

l. Formation of sulfates such as NaZS04 and KzS04

2. Conversion of SOz to S03 in the bulk gas phase - catalytically active surface such as an

SCR catalyst - SOz + V2 Oz -+ S03

3.Pyrosulfate formation - NaZS04 + S03 -+ NaZSZ07

A diagram depicting the physical and chemical reactions involved in the filling and plugging of

catalyst pores is shown in Figure 13 (Benson and others, 2005).

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Table 2. Melting Points of Selected Pyrosulfate Compounds

A. Compound Temperature, °C Temperature, of

K3Fe(S04h 618 1144

K3Al(S04h 654 1209

KFe(S04h 694 1281

Na3Fe(S04h 624 1155

Na3A1(S04h 646 1195

NaFe(S04h 690 1274

Na2S207 401 754

K2S20 7 300 572

(K1.5Nao.5)S20 7 279 535

Sulfur Oxides

Carbon Dioxide

Reactions with SO:3

and CO2

Deterioration

(NH3 and NOx cannot react In

mlcropore on catalyst surface)

No Deterioration Vet

(NH, and NOx can react In

mlcropore on catalyst surface)

__- Partides - Silicates and Other Fly Ash Particles

__- Partides - Silicates and Other Fly Ash Particles

'--_--Matrix Material - Partially Sulfated Alkali and

Alkaline-Earth Oxides

-+14% Expansion

~--Matrix Material - Fully Sulfated Alkali and

Alkaline-Earth Oxides

Particles -

Silicates

Small Particles.--...... _ : •

Nat Mg, Ca, K ~.

Figure 13. Overall mechanism of SCR Catalyst blinding (modified after Pritchard and

others (1995».

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Sodium-related catalyst deactivation mechanisms

Alkali elements such as sodium and potassium are known to cause catalyst deactivation. Prichard

and others (1995) indicate that the alkali elements can interact with the catalyst active sites and cause

them to lose their activity as shown in Figure 14. They indicate that the degree of deactivation is

dependent upon the concentration of alkali elements and the form of the alkali. Based on the

evaluations conducted and/or reported by Cormetech (Prichard and others, 1995), Topsoe (1999),

EPRI (Broske, 2005), and EPA (Mussatti, 2002) the water soluble form of the alkali is the

problematic form since these alkali species are highly mobile allowing them to migrate into the

catalyst. Cormetech (Prichard and others, 1995) incorrectly indicate the following:

"For the subject cataLyst in coaLjired applications, it is our experience that this type of

poisoning has a small impact, since most ofthe aLkaLine metaLs in the coaL ash are not water

soLubLe. ..

This comment is very surprising and is likely indicative of catalyst vendor's level of

understanding of lignite coals. Much work has been conducted for decades on the solubility of

alkali and alkaline earth elements in coal ash. Sodium in Center lignite is associated in the

groundwater and with the organic matrix of the coal (Benson and Holm, 1985; Schobert, 1995).

Very little of the sodium is associated with the mineral fraction of the coal such as clays. During

combustion, the sodium in the water soluble and organic association will vaporize and become

dispersed in the gas stream and react with sulfur oxides to form soluble sodium sulfates species.

Combustion Engineering conducted an analysis of the impact of soluble and organically

associated sodium with fouling potential (Singer, 198\). The results of the analysis are

summarized in Table 3. The soluble alkali shown for lignite and subbituminous coals is very

high, with North Dakota lignite and Montana high-sodium subbituminous coals having the

highest available sodium for low-temperature fouling processes.

H

I

? --Me-~O- -Me--

Fresh Catalyst

Na(K)

I

P

--Me--O- -Me--

Alkaline Deterioration

Figure 14. Alkaline (alkali) SCR catalyst deterioration mechanism (Prichard and others,

1995).

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Table 3. Comparative Alkali Content Analysis for U.S. Coals (Singer, 1981)

Rank Lignite Sub8 Lignite Lignite hv8b hvAb Lignite

Region NO MT TX (~egua) TX(Wilcox) UT PA TX(Wilcox)

HHV. Btu/lb, Dry Basis 10640 12130 7750 9710 12870 13200 8420

Ash Composition (0/0)

SiO. 20.0 33.9 62.1 52.3 52.5 51.1 57.9

AI.O, 9.1 11.4 15.1 17.4 18.9 30.7 21.8

Fep, 10.3 10.6 3.5 5.3 1.1 10.0 3.9

CaO 22.4 21.0 6.2 9.4 13.2 1.6 7.1

MgO 6.4 2.7 0.7 3.2 1.3 0.9 2.1

Nap 5.0 5.8 3.6 0.9 3.8 0.4 0.7

K.O 0.5 1.6 1.9 1.2 0.9 1.7 0.8

TiO 0.4 0.7 0.9 1.2 1.2 2.0 1.1

503 21.9 12.0 6.1 9.6 6.2 1.4 4.4

Fouling Potential Sllvllre High High Moderate Moderate Low Low

---- - ------.._---- ..._--

Lb Ash/106 Btu, Dry Basis 9.0 4.6 43.3 20.1 7.9 10.2 34.4

Acetic-Acid-Soluble

Sodium (Na. ppm) 3960 2660 9650 1030 1120 250 340

Potassium (K. ppm) 1230 85 85 no

Alkali in Ash. % WI.

Nap 5.0 5.8 3.6 0.9 3 ..8 0.4 0.7

K.O 0.5 1.6 1.9 1.2 0.9 1.7 0.6

Equiv. Sol. Alkali in Ash,

0/0 Wt. ofAsh

Nap 5.58 6.45 3.68 0.71 1.49 0.15 0.16

K.O 0.44 0.04 0.06 0.05

0/0 Sol. Alkali ofTotal

(Equiv. Sol. Na.O)/

(Na.O in Ash) 112 111 108 79 39 38 23

(Lbs Sol. Na)/

(106 Btu Fired) 0.374 0.221 1.245 0.106 0.087 0.018 .040

(Lbs Sol. Na)/(Ib Ash!

106 Btu Fired) 0.044 0.048 0.223 0.005 0.014 0.002 0.001

The following summarizes the state-of-the-art relative to the application of SCR for use in high

sodium lignite combustion systems such as at the MRY plant.

• Coal properties

o Center lignite coal contains organically associated sodium, magnesium and

calcium

o The levels of sodium in the Center lignite will remain constant and will likely

increase in the future years

• Ash formation

o Sodium vaporizes during combustion to form very small particles

o Sodium is in a soluble form

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• Catalyst properties

o Catalysts have high porosity in the form of macropores and micropores that have

active components dispersed within them allowing for NOx reduction reaction

o Pitch of the catalyst appears to be the only change in geometry available to

minimize deposition

o Catalyst are prone to deactivation because of the presence of soluble sodium

• Ash transport in SCR catalyst

o Ash particle transport mechanisms are dependent upon gas velocity

o Particles greater than approximately 10 micrometers are transported to the

surfaces of catalysts by inertial impaction mechanisms

o Vapor phase and small particles are transported through diffusion processes into

the pores of the catalyst across the stagnant gas boundary layer next to the surface

o Small ash particles rich in sodium, calcium, and sulfur infiltrate deep into the

catalyst pores causing blinding and plugging and possibly deactivation

The following are changes that could be made in future pilot testing and, based on the previously

presented information, the impacts of those changes that could reasonably be anticipated to

occur.

• Test catalysts with larger openings (greater Pitch)

Impacts: The current recommendation (for the coal-fired industry in general) by

catalyst vendors is to use catalysts that have a larger pitch. Using catalysts with a

larger pitch will likely decrease the velocity through the catalyst and decrease the

impaction rates of the larger particles. However, this does not address the key

problem of vapor phase and small particle diffusion into the pores of the catalysts that

is associated with the combustion of high sodium Center lignite. By decreasing the

velocity, the gas boundary layer may be larger resulting in an increase in the diffusion

processes resulting in increased deposition of the smaller particles into the pores. In

addition, decreasing gas velocity will decrease the scrubbing action of impacting

particles that aids in removing deposited ash particles.

• Test catalyst with modified pore structure that does not accumulate small particles

. Impacts: The use of these catalysts should have a positive impact on reducing

catalyst poisoning and pore plugging. However, discussions with catalyst vendors

and literature searches indicate that little or no work has been conducted on such

formulations. Most of the work being conducted by catalyst vendors is focused on

reducing S03 production and enhancements for mercury oxidation. As a result, these

catalysts are not available.

• Enhanced cleaning technologies for removal of particles in the pores of catalysts

Impacts: The use of acoustic horns appears to clean the surfaces as well as

sootblowers on subbituminous and bituminous fueled boilers. However, this

22 of2~
technology has not been demonstrated on lignite fueled boilers. There is significant

uncertainty in the ability of acoustic horns to clean the ash particles from the pores of

the catalyst.

There does not appear to be a catalyst material that has shown significantly improvement over

the past catalyst relative to the performance in high sodium containing system. The specific

question was asked to Flemming Hansen (Hansen, 2007) as to whether improvements have been

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

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

sodium containing flue gases.

The testing at Coyote station indicated that the macropores and the catalyst openings were

plugged. The blinding of the catalyst from the Coyote station testing was so severe that the

catalyst vendor could not make deactivation measurements. Cleaning the catalyst and measuring

deactivation was not performed based on recommendation of the catalyst vendor. The reason for

not cleaning and conducting the measurements were based on concerns expressed by the vendor

that the results of such deactivation testing after cleaning would not provide meaningful data on

deactivation rates.

At the present time, there is not sufficient evidence to indicate that further pilot testing, even

though it could be significantly reconfigured from previous testing, would yield significantly

different results from that of testing already conducted at the Coyote station. Additionally, there

is nothing to suggest that further testing would necessarily result in catalyst samples being made

available that would allow for the measurement of deactivation rates.

SCHEDULE BASIS FOR MINNKOTA'S DECISION NOT TO CONDUCT PILOT SCR

TESTING

The CD requires that compliance with the "3D-day RollingAverage NOx Emission Rate"

established as BACT in accordance with the CD be achieved for Unit 2 at MRYS not later than

December 31, 2010. For the hypothetical case in which an SCR pilot test Were conducted to

potentially establish the technical basis for SCR application to the Units at MRYS, the following

tasks would need to be completed prior to this date:

1. Design the SCR pilot test protocol and obtain concurrence of NDDH and EPA

2. Design·, procure and install the pilot SCR

3. Conduct the SCR pilot testing and evaluate the results

4. Conduct a technical feasibility analysis of the boiler modifications that would be

necessary for Units 1 and 2 to allow reduction of flue gas temperatures (which are

currently well above the required range for SCR operation, as previously documented in

Minnkota's submittals to NDDH) while maintaining the ability to dry the lignite as

required for combustion.

5. Revise the BACT analysis based on the results of Steps 3 and 4 (hypothetically assuming

that they concluded it was technically possible to install SCR) to establish the revised

"3D-day Rolling Average NOx Emission Rate" based on the hypothetical use of SCR.

23 of2~
6. Receive the final determination from NDDH regarding the "3D-day Rolling Average NOx

Emission Rate" representing BACT in accordance with the CD.

7. Incorporate the results of steps 3 through 6 (hypothetically assuming that they concluded

it was technically possible to install SCR and established an SCR-based value for the

"3D-day Rolling Average NOx Emission Rate") into a procurement specification for the

SCR system in accordance with RUS requirements.

8. Procure the SCR system on a "furnish and erect" basis, obtaining a vendor guarantee that

assured compliance with the BACT emission limit as set forth in Step 6.

9. Design, fabricate, and erect the SCR systems and the necessary boiler modifications,

using the Contractor selected in Step 8.

lO. Start-up and commission the SCR system for Unit 2 and achieve stable performance to

allow continuous compliance with the BACT emission limit as set forth in Step 6.

Based on Burns & McDonnell's evaluation, the time required to complete these tasks would be

approximately 65 months from initiation of Task 1. Thus it would not be possible to comply

with the CD date certain of December 31, 2D 10 for compliance with the "3D-day Rolling

Average NOx. Emission Rate" established as BACT in accordance with the CD.

The estimate of 65 months duration to complete this process is based on the following

assumptions for the duration of the individual steps:

Step 1 is assumed to require two months. It should be noted that the EPA and its consultants

have claimed that the previous SCR pilot testing at Coyote was fundamentally flawed. Thus it is

essential that this step be thoroughly and carefully conducted and documented in order to assure

the "buy in" of the interested parties.

Step 2 is estimated to require six months.

Step 3 is estimated to require 24 months. It is believed that the collection of 18 months of data

will be necessary to properly evaluate the technical feasibility of SCR at MRYS. Due to the

operating characteristics of the Units and based on prior experience with pilot testing, it is

believed that the duration of pilot testing needed to acquire 18 months of data will be 24 months.

Step 4 is estimated to require six months, based on consultation with the boiler OEM. It should

be noted that although Step 4 is assumed to be performed concurrently with Steps 1 through 3,

all other steps must be conducted sequentially. Also, it should be noted that the subsequent

sequence is based on the hypothetical assumption that the results of Steps 3 and 4 are favorable

to the technical feasibility of SCR.

Steps 5 and 6 are estimated to require two months each. Because no SCR vendor has experience

with SCR operation on North Dakota lignite, the determination of an emission rate

corresponding to the hypothetical use of SCR will require the dissemination of the pilot test

results from the catalyst vendors (which are assumed to be active participants in the pilot SCR

program) to the SCR system suppliers. This is because the establishment of a NOx. emission rate

representing BACT will require at least a preliminary indication from the system suppliers that

such a level can be guaranteed. It is assumed that the system suppliers will guarantee the

240f2~
emission rate established in Step 6, and will otherwise respond favorably to the procurement

process in Step 8.

The development of the technical specifications for the SCR procurement contract (Step 7) is

estimated to require two months. The specifications must incorporate not only the results of the

pilot SCR testing from Step 3 but the boiler modifications identified in the study conducted in

Step 4. Again, the sequence assumes that it will be possible to find a feasible way of mod~fying

the boilers to simultaneously achieve the flue gas temperature range required for SCR operation

while continuing to achieve proper pre-drying of the lignite.

The period for bidding and award of the SCR contract (Step 8) is estimated to be four months.

Typical bid period for a complex "furnish and erect" SCR retrofit contract such as this will be

three months. One month is assumed for evaluation and negotiation.

For Step 9 it has been assumed that the period from award of the SCR contract to the completion

of erection and tie-in will be 20 months. It is anticipated that the duration of constmction of an

SCR system in North Dakota will require somewhat longer than would be expected for other

parts of the country due to the severity of the winter. Also, depending upon the complexity of

the required boiler modifications, the constmction period can be expected to be extended

compared to a "typical" SCR project schedule which does not include the need for extensive

boiler modifications.

The startup, commissioning and tuning of the SCR system (Step 10) has been estimated to

require three months. It should be noted that concerns with the characteristics of the fly ash are

anticipated to extend the time that would routinely be required for this step. Also, unlike most

retrofit SCR projects completed to date in the U.S., this installation would be subject to a "not to

exceed" emission limitation on a 30-day rolling average. Assurance that the limit could be

continuously met would require more than the usual extent of operational tuning.

References

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

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

613.

Benson, S.A.; -Laumb, M.L., Ash Behavior in Combustion Systems, Energy Generation

Conference, Bismarck, NO, 2007.

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

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

Benson, S.A.; Jones, M.L.; Harb, J.N. Ash Formation and Deposition-Chapter 4. In

Fundamentals of Coal Combustion for Clean and Efficient Use; Smoot, L.D., Ed.; Elsevier:

Amsterdam, London, New York, Tokyo, 1993; pp 299-373.

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Broske, D., On-Line Guidelines for Operation and Maintenance of Selective Catalytic Reduction

Systems, 2005 Edition, EPRI, May 2005.

Hansen, F. Personal Communication, Feb 2007.

Mussatti, D.C., EPA Air Pollution Control Cost Manual- Sixth Edition. Section 4, Chapter 2,

Selective Catalytic Reduction., EPN452/B-02-001, 2002

Raask, E. Mineral Impurities in Coal Combustion; Hemisphere Publishing Company: Washington,

1985.

Rosner, D.E., Transport Processes in Chemically Reacting Flow Systems, Butterworths, Boston,

MA 1986.

Sarofim, A.F.; Howard, 1.8.; Padia, A.S. The Physical Transformation of the Mineral Matter in

Pulverized Coal under Simulated Combustion Conditions. Combust. Sci. Techno!. 1977, /6,

187-204.

Schobert, RR Coal Science and Technology 23: Lignites ofNorth America; Elsevier, 1995.

Singer, J.G. Combustion Fossil Power Systems; Combustion Engineering: Windsor, CT, 1981.

Topsoe. SCR Catalyst Improvements, 1999, www.netl.doe.gov/

publications/proceedings/99/99scr-sncr/enevolds.pdf (accessed in Feb 2007).

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