•

NOx BEST AVAILABLE CONTROL TECHNOLOGY

ANALYSIS STUDY

10'

Miltan R. Young Station Unit 2

Minnkota Power Cooperative, Inc.

Operating Agent for

Square Butte Electric Cooperative

Owner

Revised Final Report

October 2006

31777

MinnkotaPower

IMPel COOPERATIVE, INC.

Your Touchstone Energy® Partner ~;~

-

NO., UACT A,wly,i, SLuuy

NOx Best Available

Control Technology

Analysis Study

for

Milton R. Young Station Unit 2

prepared for

Minnkota Power Cooperative, Inc. and

Square Butte Electric Cooperative

October 2006

Project No. 31777

Revised Final Report

prepared by

Burns & McDonnell Engineering Company, Inc.

Kansas City, Missouri

Tuble ofComelllS

COPYRIGHT 2006 '0 BURNS & McboNNELL E:-IGlNEERTNG COMPANY, lNC.

Cha.pler

Number

INDEX AND CERTIFICATION

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperat1VB-m~~

Milton R, Young Slation Unil2 f~.SfJ713 S 'OJ

No,; Best Available Control Technology Analysis Study ; ...~' .0 'Z~.

Project 31777 fj "';

\~ (:

\'f~ '. /

Report Index ~>c"<.. ..v~y ";~

Chapter Tille Number

ofPages

o

1

2

3

Appendix A

Appendix C

Execulive Summary

Inlroduction

NOx BACT Analysis Sleps

NOx BACT Analysis, BACT Recommendalions

Pennit Lirnit Recornrnenualions

Technical Details for NOx Controls AI-A2

Cost Details for NO>:: Controls CI-C3

11

2

6

50

81

23

Certificalion

I herebyccrtify, as a Professional Engineer in !he slale ofNorth Dakota, that the informalion in

this document was assembled under my direcl personal charge. This report is not intended Or

represented 10 be suitable for reuse by Minnkola Power Co~peralive, Inc. and Square Bulte

Electric Cooperative or oLhers withoul specific verificalion or adaptation by the Engineer. This

certification is made in accordance with the provisions ofllie laws and rules of the North Dakota

Slale Board ofRegislration underTiUe 28 Administrative Code.

NO" BACT Anolysi; Study

-_.__ ..._-_. -----

TABLE OF CONTENTS

EXECUTIVE SUMMARY ES-l

1.0 INTRODUCTION 1

2.0

2_1

"

,.,

"

,.;

3.0

3.0.1

3_0.2

,.,

3_LI

3_1.2

"

3_2_1

3_22

B

3.3. I

3.3.2

,.,

3.4. I

3.4.J.1

3.4-1.2

3.4-1.3

3.4.2

3_4_2_1

3_4_2.2

3.4.3

3.4.3.1

3.4.3.2

"TOP-DOWN" NO" BACT ANALYSIS APPROACH 2_!

STEP I _lDEN1'lFY ALL CONTROL TECHNOLOGIES__ _ 2_1

STEP 2 - ELIMINATE TECHNICALLY INFEASIBLE OPTIONS__ . . .2_3

STEP 3 -RAl\'K REMAINING CONTROL TECHNOLOGIES DY CONTROL EFFECTIYh"lESS .2·4

STEP 4 - EVAI.UATEWE MOST EFFECllVE CONTROLS AND DOCUMENT RESULTS 2_5

STET'S _SELECTRACT............................ . _.... 2-6

BACT ANALYSIS forMRY STATION UNIT 2 NO"EMISSIONS 3-1

EMlSSIONUNITDESCRlPTION .. _. . _ .3_1

:NITROGEN OXIDES EMISSION FOR,\{ATlON .- _ 3·3

IDENTTFICATION OFNOx CONTROL OPTIO:NS FOR MILTON R_ YOUNG STATION 3·3

REVIEW OF RETROFIT INSTALLAnONS.. .. __ __ 3-4

POTENTIALLY FEASIBLE NOx CONTROL OPTIONS FOR MILTON R_ YOUNG STATION 3-5

FEASIBIUTY ANALYSIS. __ __ _ 3-6

SUMMARY OF RETROF1T INSTALLATIONS OF NOx CONTROL TECHNOLOGIES ..3-8

SUMMARY OF FEASIBLE NOx CONTROL TECHNOLOGIES l'ORl\my STATION _.. -3_9

RANK Of TECHNICALLY FEASIBLE NO:.:: CONTROL OPTIONS BY EFFEC11Vh"lESS. --3_13

ESTABLISHING BASELINE NOx EMISSIONS FOR RANIUNG CONTROL OPTIONS 3·14

ESTiMATING CONTROL-EFFECTTVEi'>lESS OFNO" CONTROL OPTIONS 3_15

NOxCONTROLSEVALUATION AND IMPACTSANALYS1S._ _ 3_20

NO" CONTROL ECONOMIC IMPACTS FORMRY STATION UNIT L .. __ . 3·20

CAPITAL COST ESTIMATES FOR NOx CONTROL ALTERNA'fIVES . .. _.. 3-20

OPERATING AND MAINTENANCE COSTF.-STIMATES FOR MRY sTATION NO, CONTROLS 3-22

LEVELlZD TOTAL ANNUAL COST EsTIMA1ES FOR MRY STATION NOx CONTROLS .3_24

ENERGY HvlPAcrs OF MRY STATION NOx CONTROLS.___ _ .3_31

ENERGYh\1PACTS Of SOFA TECHNOLOGY__ ... .- 3_31

ENERGY IMPAcrS OF SNCR TECHNOLOGY 3-32

ENVIRONMENTAL IMPACTS OFNOx CONTROLS - MRY STATION 3_35

ENVIRONMENTAL IMP-"crs OF SOFA TECHNOLOGY . 3-35

ENVIRONMENTAL IMPACTS OF SNCR TECHNOLOGY___ . 3_36

Squan: Bulle Electric CoC~OoC,"""',"o----- TOC-I Dums & McDonnell
NOx BACT All"l)'sJS STUdy Tohle of COnlen!,

3.4.4 SUMJl-1ARY OJ- J:CU~OM1C, ENLRGY Al':D E?\VIR()t'-:~JlNTAL l~lPACTS OF :vIRY SI'ATION

NU,CONTIl.OLS. . ,-'.-' -. ,,3_37

3.5 BACT RECOM),-JENDATJON Al\D C();\ITROL LEVEI~~ . MRY SIATION Ul':IT 2 ._ 3-39

3.5.1 WJT2NO,IHCT.

J.~.2 L"USSJON RATE LTh·IITATlON RECOM!l.Ill':DA']'jON.. _

APPENDIX A

Technical Fea5ibility A5se55ment Detail5 for NOx Conlrols (A1)

U.S. Coal Cyclone NOx Reduction Projects Summary and

Relroflt NOx Conlrol Projects' Technical Literature Summary (A2)

APPENDIX B

EERC Reporl- Ash Impact5 on SCR CatalY5t Performance (8)

APPENDIX C

Cost Methodology (C1)

Capital Cost Estimate Delails for NOx Controls (C2)

O&M cosl EsI;male Delalls for NOx Controls (C3)

_ _,--'10

nun" & McDonndl TOC_' Sq"'", B"lI~ Eleclric Cooper",i\',
NOxBACf Analysis Sn,dy

LIST OF TABLES

Table ofConlrnlg

r:.;

Table 3-1- Unit Design Parameters

Table 3~2 - Historical Avernge Lignite Coal Analysis

Table 3-3 -Potentially Available NOx Control Technologies Idcntifj~d for BACT An~lysis

Table 3-4 - Identified NO" Control System Retrofits on Cyclone Coal-fired Boilers

Table 3-5 - Technioally Feasible Potential NOx ConlrOl Tcchnologios for M.R. Ymmg Station Unit 2

Cyclone Boiler

Table 3-6 - Technioally Infeasible Potential NOx Control Technologies for M.R. Young Sl"tion Unit 2

Cyclone Boilers

Tablc 3-7 - Ranked NOx Control Options l'easible for MRY Sta~on Unit 2 Bojlerwi~l ExpeCICd Control

Pcnorm:moe

Table 3-8 - ExpectEd Annual NOx Control Perfonnance for M:RY Station Unit 2 Allcm~livcs

Table 3-9 - Unit Capital Cost Factors ofFcasiblc NOx Control Option for MRY Slalion Unit 2

Table 3_10_ Eslimated Capital Cosls for NOx Control Allerrmlives - MRY Station Unil 2

Table 3-11 - ESlimated 0&111 Cosl for NOx Control Altemalives- MRY Station Unit 2

Table 3-l2-Estimaled Annual Emissions a.nd Levelized Tot:ll AnnU"-1 Cost for NOx Conlrol

Alternatives- MRY Slation Unil 2

Table 3-13 - Dominanl Coolrols Cosl Curve Points for Feasible BACT NOx Alternalives - MRY Station

Unit 2

Table 3-14- Estimaled Emissions and Economic ImpacLs Sommary for NOx Control AIlernative..,-

MRY Station Unit 2

Table 3-15 - ExpcctcdAuxiliary Ekotrical Power Impacts for NOx Controls - MRY Stalion Unit 2

Table 3-16 -Expected Electrical Power Generation Availability and Capacity Imp~cls for NOx Conlro]s

- Jl,:lRY Stalion Unit 2

Table 3-17 - Expected Tolal Electrical Power Generntionlmpacts for NOx Controls -MRY Slation

Unit 2

Table 3-18 - Sumnmry ofTop-Down BACT bnpaclAnalysis ResulLs for Dominant NOx Control

A1lerna!ives -:MRY Slalion Unil2

Table 3-19 - NOx Emission ConlrOl Technology and Rale Recommended as BACT for Mil!onR. Young

Slation Unil 2

Table 3-20 - Recommended NOx BACT ConlrOl Method and JO-Day Rolling Avernge NOx Emission

Rate Limil Withoul StamlpS

Table 3-21 - Recommended NOx BACT Control Mcthod and 30-Day Rolling Average NOx Emission

Rate Limil Wilhout Startups

Table 3-22 - Recorrnnended 24-Hour Rolling Avcrnge NOx Emission Rale Limit During Startups

Sq=Bune Electric Coupcralivc TOC-3 Burns & McDonnell
NOxBACT Analysis SlUdy

LIST OF FIGURES

Table ofCnnlenls

Figure 3-1 - NOx Control Cost EiIectiven<:ss - MRY Station Unit 2

Figure 3-2 - Mll.Y Station Unil2 NOx Control Alternatives Dominant Controls Cost Crnve

AppendixA1

Figure A.I-l - Pulverized Coal Reburn Application Oll Cyclone Boiler With Overfire Air

Figure A. 1-2 - Natural Gas Reburn Applioation on Wall-Fired Pulverized Coal Boiler with OverJjre Air

Figure A.I-3 _ Hydrocarbon-enhanGoo SNCR Applioation on PC-fired Boiler

Figure A.I-4 -Rich Reagentlnjeotion Applioation On Boiler With Overfire Air

Figure A.1-5 - Conventional High-Dll5t SCR AIY3ngement with FGD Scrubber Oullet Reheat

Figure A_I-6 - Tail-Gas SCRAmmgemCIlI

Figure A_I-7 - Eleotro-Catalyrio Oxidation (ECO":> Prooess Flow Diagram

Bums & McDonneR TOC_4 Square Butlc Ekcbio Cooperalive
EXECUTIVE SUMMARY

The Milton R. Young Slation ofMirmkoln PowerCoopera~ve,Inc. (Minnkola) and Square Butte Electric

Cooperative (Square Butte) includes two cyclone-furnace, lignite-fired steam-electric genera~ng units

(SEGUs). The units both Hre North Dakola lignite supplied from the adjacent mine, near Center, North

Oakola. Unitl has a nomirml235 MW net design output capacityraling, is typically capable ofsuslained

output oCapproximately 250 MW, (gross), and has a gross design output capacity ra~ng of257 MW.-

Unit I is owned and operaled entirely by Minnkol!'. Unit 2 has a norninal439 MW neldesign output

capacity rating, is capable ofsustained output ofapproximalely 460 MW, (gross), and has a gross design

output capacityraling of477 MW•. Unit 2 is owned by Square Butte Electric Cooperative (Square

Butte), and opel1l1ed by Minnkola_

A Nolice ofViolation (NOV) from the Uniled StaleS Euvironmental Proteclion Agency (US EPA or

EPA) was issued 10Minnkota Pow",: Cooperative on June 21, 2002. The NOV alleged that modifications

bad been made at the Milton R, Young Slalion thal would have required a oonstru~lion permil under New

Sourcc Review (Code ofFoocrnl Regulations 40 CFR 52.21, and NorthOakola Administrative Code

NDAC 33-15)_ N; a resnll of this allegation, a civil oornplainl was filed by the United States ofAmerica

and the State ofNorth DakOla against Minnkota Power Coopel1ltive Inc. ("Minnkola'l and Square Butte

Eleclric CO<JP""'l-tive ("Square Butte") in the United States District Court for the Dislrict ofNorth Dakola.

A ConS","1 Decree (CD) has been approved !hal rcpTCsents a final negotiated settlement oflhe United

Slates' and North Dakola 's claims against Minnkota and Square Butle. The Consent Decree requires

Minnkota and Square Butle to perform a "NO~ Top-Down Besl Available Control Technology (BACf)

Analysis" 10 descnlle lhe emission limits for NOx ilial will be required at Units I and2, expressed as a

30-Day Rolling Average No" Emission Rate [Consent Decree paragraph 24, page 7, and paragraph 5,

page4].

Bums & McDonnell was retained to conduct a Top-Down BACf Analysis for nitrogen OJ;ides (N0x) al

lhe Milton R. Yeung Station. The results cfthc BACT analysis are presenled in this stucy report

TheprocedllTes mandated by !he ConsentDecrce forperfonninga Top-Down BACT Analysis are

outlined in Chapler B oftha U.S. EPA's New Source Review Workshop Manual: Prevention of

Significant Deterioralion and Nonattainment Area Pennitting, Draft. October 1990 ("EPA's NSR

Manual'l The MRY SlationBACT analysis was performed in accordance with this procedure_ The

Square BUlle Elcclric Coopemive ES-l Bums & McDonnell
Execurive SnmmaTy NOx BACf Analy,is Study

EPA's NSR Manual outline, five basi~ steps that are Lo be followed in this BACT analysis. These hasie

steps for such a BACr analysis are summarized as follows:

Step 1 - Identify All Control Technologies

Step 2 - Eliminate Technically Infeasible Options

Step 3 - Rank Remaining Conlrol TeGhnologies by Control ElTeGliveness

Stcp 4 - Evuluale Mo,l ElTeGlive Controls Jnd Document Resull'

Step 5 - Select BACT

A BGsl Available Control Tedmology (BACT) analysis was performed for Millon R. Young Unil2 for

NOx using the EPA's '"top_down" approach_ Rest Avaikoble Control Technology is defined as "an

emi"ion, limitation (indmling" visible emission standard) based on lhe maximum degree ofreduclion

for c~ch pollutant subject to regulation under AGtwhich would be emitted from any propose,l major

staliomrry SOillGe or major modjfiGation which the Admini'lmtor, on a Gase-bY-Gase basis, taking into

account energy, cnvironmenrnl, and economic impacls and other costs, determines is achievable for such

source or modification through application ofproduclion processes or available methods, systems, and

techniques, including fud c1c.ning or treatment or innovative fuel oomlmslion teGhniques for control of

such pollutant" (40 CFR 52.21, NSR Manual Kll_

Unit 2 alMiltonR. Young Station is a cyclone-fired boilerthathurns North Dakota ligniLe_ Themelhod

offiring is very signifioant in analyzing ~ontrol options for NOx emissions. A cyclone boilerproduoes

inherently higher un~ontronedNOx levels Ihan pulverized-cool and circulating fluidized bed boilers.

There have been nO new cool-burning cyelone-fircd boilers built and installed in the United States sinco

the early 1980's. Consequently, there are no examples ofBACT eOnlrol options Iisled in Ihe

RACTfBACTILAER Clearinghouse datab~se for eonsid~·roLion and direcl applicalion ofpubJished NOx

emission permit limits On the Millon R. Young cyclone-fired boilers_

Step I IdenlifY All Conrro] TcchnoloLries

The ConsenL Decree requires lhallhe NO" Top-Down BACT ALlalysis for Lhe MillOn R. Young Station

··inclnde an evaluation of Selective Ca~1lylie Reduction (SCRl, Selective Non--eatalytio Reduction

(SNCR). Overfire Air (OFA), Rioh Reagent Injection (RRI), as well as other NO" control technologies"

polenliallyapplicable for lignite-fired eydone boilers [Consent Decree paragraph 65, page 19]. Olber

idenlified control teohniques, such US fuel switching and fud de"ning, rnd combustion-related emis..,ion

GOntro] lechnologlcs, such as fuel reburn and oxygen--enhanced combustion, wcre also ~onsidcrcd.

Bums & McDonnell ES-2 Sq""re Butte Hemic Cooperative
NOll BACT AIIillysi, Study Executive Summary

Step 2 Eliminate Technically Infeasible Options

The BACf evaluation detennined tbatnot allthc teclmologies identified were considered available and

applicable_ The technically infeasible alternatives were eliminated from further evaluation, along with

feasible technologies willi economic impacts that were unreasonable compared to other cost-efficient

allemetivcs to control NOx emissions for MRY Station Unit 2.

The technical feasibility ofapplying NOx emission reduction techniques and technologies alMilton R_

Young Station is dominaled by the composition and combustion characteristics of the North Dakota

lignite supplied solely from a surface miue adjacent to the plant. This mine is the only supplier ofsolid

fuel for this station, as there are no railroad fucilities provided to servioe the Millon R Young plant.

North Dakota lignite has high moisture and high sodium content, moderate higher heating values, and can

have a widely variable "nd high "sh content comp..-cd to other coals. Those characteristics create

difficulties in promoting consistent, steady combustion and slag formation in the cynlone burners. It also

results in produning a :Oyash that has severe deposition oharacLeristics.

Both boilers inclnde a unique coal conditioning system (drying, crushing, and feeding) for each cyclone

furnace specifically designed to aid in proper combustion ofthe lignite fuel. This method offiring solid

fuel significantly influences the resulting nitrogen oxide concentration ofthe flue gases emitted from the

boilers.

Ash deposition in each boiler and air preheater is a significant operational challenge for !he facility.

Significant equipment and manpower resources are devoted to on-going-removal offireside ash

accumulations. Unit outages must be conducted at regular inle:rvals to clean each boiler (approximately

every 80-120 days). There are a number ofissues that make selective catalytic reduclion (SeR)

tedrnically infeasible fer NOx emission control for Millon n. Young Unit 2. The consistent long-term

operation ofSeR teclmology on lignite_fired cyclone boilers will be drastically inhibited by the

susceptibility ofthe SCR catalyst to severe [ouling, deactivation, and erosion resulting from the actions ofthe emitted fiue gases and lly"sh, and ash deposit removal operations_ SCR technology is considered

techninally infeasible for application on the cyclone boilers allhe Millon R. Young Station.

Rich Rea.gent Injection has been demonstmted on boilers burning bilumiuous ami subbituminous coo.L

However, it has not been cornm=ially installed and placed in continuous operation on a cyclone-fIre<l

boiler burning lignite coal wilh high fouling and slag temperature sensitivities associated and a highly

SquaTc BUlle E1ecrrk Cooperative Bum< & McDonnell
Executive Surrumry No"BAcr Analysis Srudy

variable heat conlent. RRI adds urea rcagerrl to lhe hot furnace ~"'$CS near the cyclones, whi~h must be

devoid of free oxygen in onlcr to avoid oxidllliorr of the urea, and thus ~reating No",. While RRl is

speoifi~aHy intended for NOx emissions control on cyclone boilcr" RRI is oonsidered teohnieally

infca,ibl~ for applicmiorr Orr lhe lignite fired cyclone boilers at the Milton R. Young Stalion due to Ihe

variable he~1 conlcnl of lbe 1ignile fuel which allows lhe ~realion ofoxygen-rich conditions in the boiler.

The application o[ separ~ted overfire air (SOFA) [or NOx emissions ~onlrol on Milton R. Young Unil2's

boiler was evalualed as part ofthe BACT 3n~lysis. A version ofseparated ovemre air specifically

designed [or increased NOx emission redu~tionperform_nee for lignit~~firedeyelone bOllers, referred 10

as "Advauced SOFA" in this ~nalysis, can be inslalled on both unils at M.R. YOlmg Slation. This

highest-performing form of SOFA cUI! bc npplied alone and in combinalion with olher lechnologies. Key

aspecls ofsuccessfully applying and operaling a sopamte<! overfiro air ,)'Stom On a cyclone-fired boiler

ore the abilily 10:

• Aecuratelymeasure lhe fuel he"l inpul ratc (BUTs) and ~ombuslion air inputs on a real-lime,

individu_1 cyclone by cyclone basis, to allow the ability to determine and controllhe desired airffuel

ratio, especially when '·sl"rved air" (i.e. subsloichiomelric) combuSlion conditIons are required.

• Maintain adequate mol ten coal a"h (slag) formalion und Dow wilbin thc bmrels and slag taps.

The degree '0 which the individual cyclone firmaoes can be operated with lcos"lhan-lheoretioal

(,ubsloiehiom~lric) combustion air, which corresponds to operation ofa SOFA sy"cm, direclly

~olltribnles to less combustion-relaled NOx formation and fUrll,er in-furnace emission reduction but also

risks solidifiealion of lbe molten ooal ash. This places great emphasis on aehic\~ng tight conlrol over lhe

air/fuel <alios on each cyclone during air-Slaged ~ombustion operalion w-iLh SOFA in order [or uir·slaged

combustion to be suc~essfulin producing significant addilional NOx emissions reduction on lignite-fired

cyolone boilers.

In the C"se ofMRY Station Unil2's boiler, air-staged oombustion musl be sufficient 10 reduce NOx

emissions while releasing enough heat to continue to mell the fuel"m so that it Dows effectively within

amI from The ~yclone bllIIT~TS. Due to the short"tenn variability oflhe combustible amI ash componenls of

NorlhDakota ligni1e supplied from the currenl mine near Cenler, ND, and The complex behavior oflignite

ash when exrosed to high lemperatures, the exlenI of air-SlUl,rlng andlhus lhc level ofNOx control while

op<:raling thc highest-performing version of SOFA system is expected to be modest.

. ,

,>

Durns & McDonnell ES-4 Square Bune Electric Coop=!ivc
NO" BACr Analysi, Study Executive Summary

i".., ,.

Selective Non-Catalytic Reduction (SNCR) technology has been used to reduce NO" emissions on

numerous utility boilers bumiog eastern bituminous coal, midwestern bitumino\Js coal, and, to a l=er

extent, western subbituminous cool. SNCR has also l>een used on fuel oil and natural gas-fired units.

SNCR does not appear to be dependent directly on the type ofbumers (wall-fired, tangentially-fired, and

cyclone-frrccl) employed in the boilers where it has been installed, with or without air-staged combustion

with overfire air in full operation.

There are significant conocmS associated with effective long-term SOFA operation for Millon R. Young

Station Unit2's boiler_ The ability o£hasic combustion equipment:md improvements to precisely

measure the boiler's heat input rate in real-time on an individual cyclone by cyclone basis with

compensation for the short-term variability of the combustible content of the Center lignite to consistenlly

mainmin subsloichiomcmc operation o[evcry cyclone during air-staged combustion is unproven.

Severnl other techniques and teohnologies were considered technically feasible for NOx emissions control

at MRY Station: Fuel Blending/Switching; Basi~ Comhmtion Control Improvement,>; and various forms

ofFuel Rebum. Fuel swilchinglblending wa, not evaluated further becuuse ofexpected unreasonably

high capital and operating costs and no additional emission reduotion compared to continued lignite

firing.

Oth~rNOx emissions controltechniqucs and technologies for MRY Station that Wore evaluated and

determined to be teohnically infCilsible were: Fucl Cleaning; Low NOx Burners (LNB); Flue Gas

Recirculation; Oxygen-enhanced Combustion (OEC); Water/steam injection {combustion tempering}; and

Electro-Catalytic Oxidation (ECO"'),

Step 3 Rank Remaining Control Technologies by Control Effectiveness

The third step in the "top-down" BACT evaluation ranked the remaining control technologies by

effeetivene.'<S_ The purpose of ranking the control technologies was to establish a hierarchy that places at

the "top" the control technology that achieves the lowest emission leveL The technologies in order of

their effectiveness, from highest to lowest, are: SNCR with ASOFA; Gas Reburn with ASOI'A; Lignite

Reburn with ASOFA; Fuel Lean Gas Rebum with ASOFA; and Advanced Separated Overfrre Air

(ASOFA). None of these control options has been installed on a cyclone-fIred boiler burningNorth

Dakota lignite. k;such, the expressed control percentages reflect the use of enginceringjudgmen~based

on the listed technique or technology application_·

Squam Bull<: Eloctric Cooperalive Burns & MdJonndl
Executive SmmnaIY NOx BACT A11lIJy,;s Sluuy

SleD 4 Evaluate Mos! Effective Controls ~nd Document llesulls

Additional criteria besides technical feasibility were utilized for technology selection in this BACT

analysis, These included estimates of control effectiveness (i.e. PLTC~"Ilt pollutant removed), capital plus

operating and maintenance cosLs, annual emission reduction (tons per year), energy impacts, avernge ~m]

imremental cost effec~veness ($/ton), and environmental impacts (other media and emissions of toxic

and hazardous air pollut:lnLs)_

The economic analysis examined the capital cost ofeach fea.<ible BACT ahemative evaluated and:my

otherpowcrplant upgrade costs necessary 1.0 implem"Ut the altcm~live_ In addition, the economic

analysis examined the operating and maintenance cost associated with the highest-performing forms of

each feasible BACT aHemative evaluated. These costs were then combined into a leveliud tolal annual

cost [or a comp~rntivc ~sscssmCJlt of the lotal implementation eost of eaoh aHem~li"e. Finally, as part of

the lop-do'Ml analysis, a domimmt controls cost curve was plotted JIld the unit control cost for each

alternative was evaluated.

Two alternatives were on the dominant controls cost curve and thus were identified as the more cost

dIccti ve 3ltcrlwtiva. The two BACT NOx cuntrol nlternntives evalunteu for incrementnl cosl, energy,

and environmental impacts applicable to Millon R. Young Station Unit 2were:

• Selective Non-Catalytic "Reduction (SNCR) combined with a special form ofseparated ovcrfirc

,iT (SOFA) specifically for lignite-fired cyclone boiler.; (referred to as Advanced SOFA or

ASOFA); and

• ASOFA alone.

The two most cost-effective reasible control altemat ives [or reduction (lfNOx emissions wcre reviewed to

delcrminc ifthc USe ofthe technique or tcchnology would resull in any significant or unusunl energy

penslLies 01' benefits_ Potential inerea<e in power plant energy consumption or net generation reductions,

for ASOFA alone, Or ASOFA with SNCR were relativcly small.

The prcdict<:d ~"Ilvironm"T1lal impacl.5 from impl~'IIlen!ntionof the two most cost-effeGtive feasible NOx

emissions control alternatives from slighllyhigher unburned carbon in Ihe emitled fly ash, carbon

monoxidc, and exccss anmlOnia ("slip") emissions WdS expected to be small in comparison with the

Burn. & McDonnell ES·6 SquaTO Butte Electric Cooperative
NO" BACT Analysis Study Execulive Summary

.'-'

significant antioipaled reduction in far-field ozone and improvement in atmospheric visibility as a result

oflhe overall NO" emission reduction.

Slep 5 Selecl BACT

Taking inlo account technical feasibility, energy, environmenml, and economic imp3cts and other eOSl5,

the recornmen<!C<1 Bcst Available Control Technologies and associated emission rates for nitrogen oxides

emissions produced hy Millon R. Young Slation Unit2 boiler-are provi<!cd in the table below.

NOx Emission Control Technology and Rate Recommended as BACT

Control TechnoloQV and Emission Rate Recommended as BACT

12-Month Rolling Average

Unit Pollutant Control Method NOx EmISSlon;~~le

(Ibl million Btu

Selective Non-Catalytic

, NO, Reduction with Advanced 0.330

Separn.ted Overflre Air (ASOFA)

This recommended BACT 12_monthNO" emissiou rate is based upon a historic pre--eontrol 12-montb

baseline average atmual NO" emission rate used in the control and c05t--effl.'Cuvencss analysis of0.786

IbfrrunBtu for Unit2. The baseline emission was determined from the t2 consecutive monlh period with

the highest historic summation ofNOx mass emissious (pounds) reported for actual operntion between

January 1,2001 and December J I, 2005.

To complete the BACf delennination process, the Consent Decree (CD) requires that "spccific ~outrol

teohnologie:s to be installed and a specific Phase II 30-day Rolling Average NO" Emission Rate limitation

(lbs/MMflru)" mual be establisbed for each subject emission Unit [CD Parngraph 66, pg 20]. Because

lhere are expected to be minorshort term variations inopernling conditions where Minnkota has not, in

fact, materially changed any oflheir nonnal daily operatingpractices, a margin betwcen the 12-monlh

average operating conditions and the 30-day pennitiimit is proposed This recommended ernBsion rate

should be suitably highersueh lbat operation consistent with the technologicallimiLalions, manufaoturer's

specifioations, and good engineering and maintenance prnctices to the extent practic"ble for the

recommended NOx BACT alternative wonld no! result in an exceedarrce (violation) oran enforceable

emission permit limit.

Square Dune Electric Cooperative ES_7 BlUm & MoDonnell
Ex.cu~ve Summary NOx BACT Analysis Slndy

The Consenl Decree also requires that the North Dakota Departmeot ofHealth's (NDDH) NO, BACT

Determination ad<lrcss specific ~-mis"ion limitatiOlls during Unit startups at Milton R_ Young- Station [CD

Paragraph 66, pg 20]_ "The type and duration offiring dnring startups, and the limited ability ofavailable

and feasible technologies to conlrol startup NOx emissiOlls, both significantly influence the 30-lIay rolling

average BACT NOx emiS'lon rate limit recommended for Millon R. Young Station boilers. A 24-hour

rolling ~v~"'gc NOx emission rate limit applied 10 startup periods is also recommended for Milton R.

Young .'ltation hoiler<_

The SEGU startup operatmg period is usually not defined io emission permits. However, for Ihepurpose

ofthis NOx BACT analysis, DnH startup was defined as thc period from initial fud combustion to the

point in time when:

• the measured Heat Input to the boiler on a 6-hour rolling average basis is grealer lhun or equ3lto

4800 million BTUIhr for Unit 2; Or

• Ihe 3mount of time reported for the longest individual Unit 2 startup period during actual operution

hetween January 1, 200111I1d December 31, 2005 elapses, whichever occurs first; or

• fuel.firing is discontinued prior to satisfying either previom criteria_

For IMRYS Unit 2, the recommended 30-day rolling average NO" emission permit limitraLe 1hal includes

the impaot of.,tartllps is based upon recognized operational faclorS and C<juipment design, that influence

whether the startup emissions rcsull in high~"r 30..lfay emissions compared to normal continuous operation

excluding such startup periods:

• The uncontrolled emission I'ate (i.e. without separated OFA or SNCR in op~-ration) .nd its variability

during operatiOll from a cold startup up to and including maximum continuous rated output;

• The operating conditions thal are required to exist for the seJected NOx BACT controlledmiqucs 10

be initiated and be effective; and

• The elfectivem:ss of llicse two particular contmltcchnique, ifinvoked at less-than-MeR steadY_slale

operating conditions.

6 The number ofstartups ana Iheir range of typical dumlions per 30-day period time frame.

TIle Consent Dccrec and thc EPA's NSRManual do not describe the method for determining a 30-day

Rolling Average NOx Emission Rate pennillimitalion (CD Phase II) thai rclkcl< BACT applied to

Millon R. Young Slation Unit 2. The approach taken in this analysis was to establish a historic pre_

control 3D_day baseline avcrage NOx emission rate (lbfmmBtu) from the ~O-consecutivc day period with

Bll"'" & McDonnell ES_8 Square nune Eleotric Cooperalive
NO" BACT Analy,i, Study EXeaIlivc Sununary

the high""t historic unit NOx mass emissions (pounds) reported fbr actual operation between January

1,2001 and December 31, 2005. This re[\ecls unit NOx emissions that W~'re generaled during periods of

high unil operations, nut alTected byunit shuldowns, startups, or malfunctions. This'was then compared

to the 12-monlh hi,toric pre-control baseline average NOx emission rale (lbfmmBru) from the 12-

conseculive nlOnth period with the highest historio unit NOx mass emissions (pounds) reported fur actual

operation during the same 5-yearlook-haekperiod. An estimate ofNOx emission reductiuu forthe

proposed BACT NO" alternalive operating at the ~is[oric pre-control 30·day baseline average NO"

emission rate (lblrnmBtu) was made. This rale eoru:ideredreoognized uperational faotors and equipment

designs applied 10 "swady state" conditions with sustained oUlput close to JrUlXimum continuous capacity

ratings. The potenlial impact ofstartups, Tecognizing; operalional and leclmicallimilations on NO"

emission control performance, was then applied to lhe steady-slate rate, to eslablish a recommended 30-

day Rolling; Average NO~ Emission Rate permit limitation (CD Phase II) that reflects BACf for Millon

R. Young Slation Unit 2. This is summarized below.

.•. " Recommended NOx BACT Control Method and

JO-Day Rolling Average NOx Emission Rate Limit Without Startups

30-day Rolling Average NOx

Unit Pollutant Control Method Emission Rate limit

Excluding Startups

(lbfmllUon Blu)

Seleotive Nou-Calalytic

2 NO, Reduction with Advanced 0.350

Separated Ove:rfrre Air (ASOFA)

This recommended BACT 30-<iayNOx emission rate limit jg based upon a historic pre-contro130_day

basehne average NOK emission rate of0.874 lb!mmBtu- for Uuit 2_ The baseline emission was

determined from the 30-consecutive day period with the highest historic unit NOx emissions rate reported

for actual opel:ation between Jan",,-r)' 1,2001 and December 31, 2005.

An inoremental adjustment to the proposed 30-<iay rolling average sleady_state unil NOx BACT emissicn

rale wlthcut slartups of0.35 IbfmmBtu forUnit2 is recommended for the 30-day roUing average NOx

emissicn permit limit periods as dermed and applied tu Milton R_ Young Station. This is .untIrulrized in

the table below.

Square Bullo Elcctrie Cooperative E8-9 Durn< & MoDonneil
NO~ BACT Analy.,i, SLudy

Ro"i,od IGil 7/2006

Recommended BACT 3D·Day Rolling Average

NDx Emission Rate Limit and Startup Impact

30-day Roiling Average NOl( Impact on 30-day Roiling

Unit EmissIon Rat" Limil Average NOx Emission Rate

Excluding Startups Limit Due 10 Slartups

(Ib/million Btu) (lb/mlllJon Blu)

, 0.)50 +0.102 perslartup

Thi~ recmnrnenued .djushnent to the propo,ed 30-day rolling: avcra.Bc sloOlly-state NOx BI\CT orni"io[l

ral~ limil t"ilho,,1 ,("rlup" is ba,ed upon average hismrie pro-control NOx em is:;ion "'lOS of 0.959

lb/mrnllru for ULlil 2 rcport~d for I no lungesl in,liviulml Unit 2 starrup period doring nemal operation

belween January 1,2001 al\d December 31, 2005. Tnc,e omi"iollS occurred during the lil-ho,lr Oember

25-30,2001 'larrup fo[ Unit2.

A 2'~-hoLLr rolling avcntge BACT NOx omission rate limit applle<! lO 51al1Up r~riotl; i, ~15o rceOlllll\cndcu

tor eaeh of the I1--lillon R. You<\g SLalioJl b"ll"".

Thi, i, ,umm"[ized ill rhe lable below.

Recommended 24·Hour Rolling Average

NOx Emission Rate Umit During Startups

24-hour Rolling Average NOx

Unit Emission Rate Limit

During Startups

(lblmillion Btu)

, 1.064

The;;~ elll«,lon, "c""mod during- lhe ll5-hour October 25-30, 2001 'tartup for Unir 2.

Compliance wrrh (h0.'~ ~,ni"siOL\ [HlC wou 1,1 b" m",,,,un;,1 "I the ,mck of the Uni[, verifLeU wilh

Can\iLllloUS Emi"s;oLl M"Jlitori"g- (eEM) ,y,IGnl, in ""ouru"ncc with Ihe rder~nce melhods ,pc"if1e<l in

40 C-F,[t. P"rl 7j. and woul<l he determine<! on a 30 CO"'~"Uljve Or"ntling I);,y ,md 24·""n5""utiv~ hour

wiling ;I\'''nt)':e lJa,;is, r",p~otivdy

ES_IO Rllm, & \kJ)onndl
NOx BACT Analysis Study Executive Summary

A trial demonstration period oflB months after the completion ofConsent Decree Phase II NOxemission

rednclion system Installation oommissioning al Millon R. Young Stalion is recommended. It is proposed

10 allow Minnkota (for Square Dutte) to demonstrate the actlml control syslem capabilities oflhe

combined NOx BACT emissions reduction syslem. Operating experience during the trial period will:

• confirm steady...state control performance ofthe combined NOx BACT emissions reduction system;

• allow deterrninntion of the ability to further eonlrol Unit start-up emissions;

• allow lhe detennination of the permitted 30-<lay rolling average NOx emission limit including

slartupS, shutdowns, and malfunctions; and

• address the specific emission limilations during Unil starlups at Milton R_ Young Slation and their

Impact on lhe proposed 30-day rolling average emission rate limit (wilhoul slartups).

Based upon tho informalion obtaIned during the !rial period, final emission limits can then be detennined.

The means that will be employed 10 minimize emissions during st:lrtup will primarily be based on

operntingprocedures, both before and after lhe level ofupper furnace gas temperat\IrCs and/or heat inpul

raT>: are considered sufficient to slart the NOx controls and opernling conditions are conducive for

effective emissions reduction. These could be similar lo Minnkola's current MRYS practices, or could be

different, depending upon the capabilities of the NOx controls and lheir impacts On Unil opcrations_

Square Bulle Eloolrlc Coopemlive ES_ll Bums & McDcnnel1

NOx BACT An.ly,is Srudy

1.0 INTRODUCTION

Introduction

The Milton R. Young Slalton ofMinnkota Power Cooperative, Inc. (Minnkola) and Sqllllre Butte Electric

Cooperative (Square Butte) includes two cyclone-fum.ce, Iignile-ftred boilers producing sleam for

electric generation. Bo!h unils fire North Dakola J\gnile 5llpplied from an adjacenl mine, near Center,

North Dukola.

A Notice ofViolation (NOV) from Lhe Uniled Slates Environmental Proteclion Agency (US EPA or

EPA) was issued 10 Minnkota on Jlllle 21, 2002. The NOV allcged that modificalions have been made at

the MillonR. Young Station lhut would rcquire a conslrnction permit under New Source Review (Code of

Federal Regulations 40CFR52.21. and North D.kota Adminislr.l.tive Code NDAC 33-15). A!iJ. result of

this allegation,' civil compl.int was filed hy!he United Stales ofAmerioa and the Sl:Ile ofNorthDakol•

• gainst MiIUlkota Power Cooperative Inc. ('"'Minnkota') and Square Butte Electric Cooperative ('"'Square

Butte") in thc United Sl:Iles District Court for lhe District of North Dakota_ A Consent Decree' has been

entered that represents a final negoliated settlement of the United Stales and North Dakota's claims

allainsl Minnkota and Square Bulle. The Consenl Decree requires Minnkota and SquarcBultc 10 perform

3 NOx "Top-Down" Best Available Control Technology (BACI) Analysis 10 describe lhe emission

limits fOT NOx thatwiH be required atUnits I and 2, expressed as a 30-Day Rolling Average Emission

Rale (lb!<lmilJion Btu)'.

Bums &MeDonnell was retained by MiIUlkola 10 conduct a "Top-Down" Best Available Control

Technology (BACT) Analysis for nitrogen oxides (NO,,) at lhe Millou R. Young Sllltion. Bums &

McDonnell is a full service engineering, archilcclUr1ll, eonslTuction and environmental firm. The

company plans, desigtls and constructs electric generating facililies and has been providing environmental

services sinee!he 1970s. As part oflhose services, Bums & McDonnell has extensive experience in

pennitting, Besl Available Control Technology (BACT) shIdies and control lcchnology analysis. The

results of lhe BACT analysis are presented in lhis repon.

1In lhe Uoiled SI<lles Di'trict Court For The Di'triot OfNorth Dakota. Uni<ed Stales OfAmerica and Slllie Of

North Dakota, Plaintiff.. y_ Minnkota Power Cooperative, Ino. and Square Butw Electrio Cooperative, Defeod.o".

Civil Aotion No. I,06·CV_034

2 !bid _ foolnole number I, CD paragraph 65, page 19_

Square Bulle Electric Cooperative Bums & McDonnell
Introdnclion NOx BACT Analysis Slndy

The primary guidance ulilized in preparation urthis IlAC[ analysis is lhe U.S. EPA's New Soure"

Review Workshop~Manua]: Prevention orSignitjcanlDeterioralion and NonatUtinmcni Area PenniUing,

prafL Octoher 1990' ("NSRManual").

Tn Ihe nexl seelion oflhe report, lhc approach 10 the BACT Analysis is de'crihed. Following lhal, a quick

sunumry orlhe planl eondilions alld repon basis i. given and then lhe BACT Analysis begins. The

impact portion of the rcpon is broken down inlo "'parJle subsections. Within the last section, lhe results

Olan oflhe BACT Analy.is sleps ~rc "uuunarized forNOx conlrol oplions for Unjt 2's boiJerat the

Mihon It. Young Slation.

J ChaplITB nflhe U.S. EPA's New Sourc~ ReviewWork,hop Monu.l: Prevention ofSignilio.nt Delmorationand

NonaH"jnrnonl Aroa Porrnitting, Draft, Oolobor 1990.

Born. & McDonnell Square Dune Elootric CoopcTative
NOxBACf Analysis SlIldy ''Top.Down''NOxBACf Analysis Approaoh

2.0 "TOP·DOWN" NOx BACT ANALYSIS APPROACH

Best Available Control Technology (BACf) is an emissions limitation for each pollutant from a source

detennined to be achievable using controltedmologics(s) thaI provide l11e '"maximum degree ofemission

rcduclion. _.taking into accollllt energy, environmental, and economic iIIlJXlcts''''. A BACT revicw docs

not resull in an emissionsremoval efficiency requircmcul. The generany accepled procedures for

performing a BACf analysis are outlined in the EPA's draft NSR Manual. The BACf analysis for

Milton R. Young Statiou Unit 2's boiler NOx emissions was performed in ac:cord"nce with this

procedure. The EPA'a draft NSRManu"1 outlines five basic steps that are to be followed in the "topdown" BACf evalUlition_ These steps are as follows:

Step 1 .- IdentifY All Control Technologies

Step 2 - Eliminate Technically Infeasible Options

Step 3 -RaukRemaining Control Teohnologies by Control Effectiveness

Step 4 - Evaluate Most Effective Controls and Document Results

Step 5 - Select BACT

The predefined steps ofa BACT analysis are described in this section, and results presented. Available

NOx control techniques and le~hnologies are defined, identified, and a technical desoription of the

emission reduction process and capabilities are reviewed in the following section. Subsequently, those

teohniques and technologies deemed feasible for retrofit application are mnked aocorrnngto nominal NOx

control capability. An engineering analysis reviews the estimated capital aud operations and m"intenance

(O&M) coSts for each feaslble alternative, including taking a look at Balance ofPlant (BOP)

requirements. Following thc cost impact determination, the energy and environmental impacts are

reviewed for each feasible technology. Finally, the rC5lllts of the engineering analyses are tabulated and a

NOx BACT selection isrecommencied for each unit.

2.1 STEP 1 -IDENTIFY ALL CONTROL TECHNOLOGIES

The first step in" ·'\op-<lown" NOx BACT analysis is to identify, for the emissions unit in question, a

comprehensive list ofall ~available" conlTol options. In the EPA's draft NSRManual,

"available control options are those air pollutiou control technologies or techniques with a

practical potential for application to the emissioTlS unit and the regulaled pOHulaullffider

evaluation. Air polJution oontrol technologies and techniques include the application of

• lliid foomore tmmb<r 2, NSR Manual B.t

Square Bun. Electrie Cooperative ,., Borns & McDonnell
'Top_Down" NOx BACT AnalysisApplOad. NOxBACT Analy,is Stnrly

production process or available melhods, systems, und technique." including fuel cleaning

or trcalrncnl Or innovative fuel combustion technjque~ for control of lhe affected

poHulant'" .

According; to lhe liPA's amft NSR MmJual, "a teclmology is considered "available" if it call be obtained

by the applicant througl1 commerc ial ~hannels or is Olhcrwi~c "v"ilablc wilhiu lhe common sen~e

mcaniug; oflhc tcrm''''. Also, "a coutrollechniqne i. con.idered available, within the GOntellt presented

above, ifil has reached [he licen~ing ana commercial sales slllge ofdevelopment"'.

In order to idenlify available NOx emission control technologie., and techniques appropriate for potenlial

application to MRY Slalion lUlits, lhe following information sources were reviewed for coal-fired elcctric

generating unit powerplanls:

• EPA's RACTIBACTILAER Clearinghouse (RBLC) database and Control Technology Cenler

(websile)_

• Federal (TiPA) and Slal~, inc1llding North Dakola Department ofHealth internet web~ilcs for air

emISsion permits and recenlly-.nhmitted applications, inGluding; BACT Ev"lnutiOlls following;

New Source Review pro~edurcs.

• Federal (EPA ami Department ofJu.tice) and State, including No.ih DakOlll Dcparlment of

Heallh internet website, for COnsem Decrecs issucd a~ a rc,"lt of Icgal actions takell by lhe

United States goVcmmclll for alleged violations of the Preventioll of Signili~anIDelCIioralion

(PSD) provisions "ml Ncw Source Review provisions ofthe Clean Air Acl, amllor fr:derallyapproved and enforceable State Tmplcmcnlatiou Plans.

• Control technology vendor informalioll_

• Publishcd and ~vailable infonnatioll from technioal, engilleerlng, ana enviroumcnlal oonsul1ants_

• Technical literature found in journals, reports, internet websites, newsletters, proceedings of

technical seminars aud conferences pertaining 10 sludies, engineering, designs, and testing of air

pollution controls_

, Ibid, NSR Morn"l B.5

'Ibid, NSRMauual B.17

, Ibid, NSR MornlOl D,13

BurR< & McDonnell SqLJllIC Bu~c Eleenic Coopcrnlive
NOxBACf Anal,!,is Study ''Top-Down'' NOlI BACf Analysis Approach

2.2 STEP 2 - ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

The second slep of the "lop-<lown" BACT process is lo cvaluate the availahle NO", eonlrol technologies

nnd techniques iden~fied in Slep I in lerms oflhe specific factors that apply lO lhe emissions unit in

question. In accord;;mc~wilh EPA's draft NSR Manual, "an available teclmology is "applicahle" if it can

be reasonably installed and operated on the source type under consideration. A technology lhat is

available and applicable i8 ledmicully feasible'''.

The EPA's NSR Manual slales a technology maybe determined lo be not applioable if"a technical

assessment considering phY8ical, chemical and engineering principles and/or empirical data showinlllhe

lechnology would not work on the emissions unil under review Or lhal unsolvable leclmical difficulties

would preclude the successful deployment of the technique"·. Also, a "showing ofunresolvable technical

difficulty wilh applying the control would constitute a showing ofteclmioal infeasibility (e.g., size of lhe

unit, localion oflhe proposed siLe, and operating problems related 1.0 specific circumstanoes oflhe

source)"l'. Ailc:r a determination is IIUldc lhat tmy oflhc processes are teclmically infeasible, options are

eliminaled iftechnical challenges would preclude orprevenl lhe su=fullong-tenn use oftile control

option or technique on lhe emission unit under consideration_ This is perf=d prior (0 any economic

analysis.

However, lhe EPA's NSR Manual also stales .....control oplions incapable ofmeeling an applicable New

Source Perfonnance Slandard (NSPS) or State Implemenlation Plan (SlP) limil would not meet the

defmition ofBACf lIndcr any circumsLances. The :lpplicant does not need to consider them in lbe BACT

analysis"". Also, it states uAn NSPS simply defines lhe minimum1cvel ofcontrol Lo be considered in lbe

BACT analysis"". The NSR Manual further stales "When developing 0 list ofpossible BACT

alternatives, lbe only reason for comparing control oplions to an NSPS is to determine whether the oontrol

oplion would resuIL in an emission level less stringent than the NSPS. Ifso, lhe oplion is unacccplnble"".

New Source Perfonnance Slandards (NSPS) forNOx emissions from EGUs firing Norm Dakola lignile

are O.8IblmmBlu_ The EPA Acid Rain Program's Title IV No" cmission limit for Group 2, cyclonefIred coal boilers wilh outputs greater than 155 MWe is O.86IbfmmBtu.

, Ibid, NSR M'lIU.l B.17

, Ibid, NSR M.m,.l B.20

'"Ibid, NSR Manual B.I9

11 Ibid, NSR Manual B.12

'2 Ibid, NSR Manual B.12

" Ibid. NSR Manual B.12

Squarc Bull" Eloolric Cooperative Bums & McDonneU
'Top-Down" NOx BACT AnaIy,I' Appro"ch NOx BACT Annl}'sI, Siudy

EPA's drnft NSR Manual also slale" "A Source wonld not be required to experience exlended lim" delays

or resource penallies 10 allow re,earch to bo con<luclo,l On a noW loohnique. Noilher is il expecled that an

applicant wuuld bc required to experience extended tri~ls to learn how to apply a lochnology on a loja]]y

new and dissimilar ~OllICC typo. Consequently, lechnologies in the pilot scale testing stages of

deyelopmenl would not be considered available for BACT rcyicw"l<.

Also in lhe EPA'5 draft NSR Manual i:; a 'lu"lilicalion for technic"l fc"sibilily,"s described by lhe

slalemenl "Commercial availability by itself, howeyer, is nol necessarily a sufficient basis for concluding

a lechnology to bo applicable "nd therefore teclmioal1y feasible. Technical fca:;,bilily, as delermined in _,.

Step 2, also means a control option may Tca"onably be dcployed on or "applicable" to the souree type

under considcralion"".

2.3 STEP 3 - RANK REMAINING CONTROL TECHNOLOGIES BY CONTROL

EFFECTIVENESS

The lhird s(~"p in the "lop-down"' DAC[ evaluation is to rank the eomrol technologics rem"inillg aller th"

feasihiliry analysis hy conlrol effeclivoncss. The purpose ofranking the control technologies is lo

eslablish a hienrrchy that ')Jlaces at the '~op", lhc conLrollc~hnologymat achieves the lowest emission

leyel"".

Selecling common units in order to compare cmissions pc::rformancc kvel" rtrnongst options is onC of the

two key issues that must he addressed in a BACT analysis. EPA's draft NSRManual states "it is

generally most effective 10 express ~TIlissions perfonnanoe as an average steady state emissions level per

unit ofproduct produced or processed"'''_ For fossil fuel-fired boilers, poond:; ofnitrogen oxides por unit

offuel he"l input (i.e. IbJrrmilltu), is a COmmOn mCanS of cumparing ;md calculating NOx emissions.

Many oontrol techniques, inclnding bolh add"on control" and inherently lower polluting processos can

perfonn at a wide range aflevels. The EPA's ~ft NSR Manual slales "It is nol the EPA's Intention 10

require "".lysis ofeach possible level ofefficiency for a contro!1echniqne, as su~h an analysis would

" Ibid, NSR MallU'! D.18

" Ibid, NSR MOllU'! B.J8

"Ibid, NSR Ma"",,! B.25

17 Ibid, NSR Manual B.22

Doms & McDon:nell Square BUlle Ele"trie Cooperative
NO"BACf Analysi' Srudy "Top-Down"NO"BACT Analysi' Approach

result in a large number ofoplions"". Also, "manufacturer's data, engineering estimales, and lhe

experience ofother S"urces provide the basis for determining achievable limits"".

2.4 STEP 4- EVALUATE THE MOST EFFECTIVE CONTROLS AND

DOCUMENT RESULTS

The fourth step of a "top-d"wn" BACT review is 10 eVJluale the technically-feasible emission controls,

beginning wilh the most eITeetive_ Economic, energy, and environmental impaols are to be assessed and

quuntified, where possible, in lhe control teelmology analysis_ The purpase of the evaluation is to

delerminc iflhere are any idenlified impacts that would eliminale lhe top controllechnology from

c"nsiderntion_ In the case where the most effective control alternative is determined to incur or produce

adverse energy, economic or environmental impacts, the basis of the determination is documenled, and

the next most stringent control allerrmlivc is eVllluated_ This analysis proeess conlinues untillhe control

technology under eonsideration carnlOl be eliminated by idenlifioation ofany source-speci lIe adver1;e

energy, eeonomic or environmental impacts.

The eeonomic impacts are based on estimales ofeapilal equipment pricing, procuremenl, inslallation and

estimated operating and mainlenance costs. The total installed eapital cools along with the operating COSts

for each controllechnology are summarized in the eeonomics ofcaeh respeetive section. The Levelized

Total Annual Cost (LTAC) represents the levelized cost ofprocuremcn~eonstroction, operation and

maintenance overan assumed service life. Cost effectiveness (S/l"n) ofa eontroltechnique "r technology

is calculuted by dividing the LTAC ($/yr) by the aruma! amount ofNO" removed (tons/yr). Baseline precontrol emissions are ealeulaled using realistic npper houndary operating assumptions, considering

inherent physi<:al or operational constrainls on the source. Plotting of the annual amount ofNOXremoved

(lons/yr) versus the levelized lolal annuul control eost ($/yr) for the various control options on an )l-y

graph allows l'isua b-zal'-on oflhe cost-effectiveness. A "lcast-cost envelope" can be readily identified 10

indieatethe inferior control options which should nol be considered in lhe subsequenl analyscs_ The

inoremental COSl-effectiveness (difference in S/toJ;i) between eontrol techniques or technologies can also

be oalculaled and compared This allows evaluation ofthe dominant controls indnded on the lea.st-cost

envelope (curve).

" !bid, NSR Manual B.23

,. Ibid, NSR Manual B.24

Squam BUlle Electric Cooperative Burm & McDonneU
"Top.DO\,nnNO~ BACT Anal}";,; Approaclt

2.5 STEP 5 - SELECT BACT

NOxBALT Amlysis S\o~y

The final step in lbe ·'top..<Jown" evaluation process is to seJeGl BACT for [he applicable poHutam ami

emission ,miL Per the EPA guidanee document, BACT is "the most effeclive eonlrollechnology not

eliminated in Step 4"". The methodology described almve waS applied to the Millon R Young Station

Unil2', boiler for emissions ofnitrogen oxides_

*****

"Ibid, NSR Manual 8.53

R11ms & McDonnell SqlJllTI: Butte Electric Coo",,"'li'"
NOxBACT Analysis Sludy BACT Analysis for MRY Slalion Unil2 NOx Emissions

3.0 BACT ANALYSIS for MRY STATION UNIT 2 NOx EMISSIONS

The approach lnkcn in this BACT analysis for Milton R. Young Station included a technical analysis of

demonstrated conlro] allematives forNOx emissions_ This approac"h followed the predefined steps of a

BACT analysis process "s generally descnbed in Section 2. Potential No", control techniques and

technologies were identified, and a technical description ofthe emission reduction process and

capabilitie" Were provided_ Subsequenl]y, those techniques and technologies deemed available and

feasible for retrofit application wcremnkcd according to nominal NOx control capabillty. The

engineering analysis lhcn developed the estimated capital and O&M costs for each alternative, including

Inking" look at Bahmce ofPlanI(BOP) requirements. Finally, the cost effectiveness points for each

feasible technology were plotled, and those thai comprise the dominant ""ntrols curve were identified.

For the feasible techniques amI technologies considered for determining No", control cost-effectiveness

for the two steam electric generating units at the MRY Station, estimates were produced forpredicted

NOx reductions thai represent "chievable long-tonn expect<ltions ofthe alternative reduction techniques

and technologies being presented in ilie technic"l analysi". Each were tabulated and graphed_

3.0.1 EMISSION UNIT DESCRIPTION

Milton R. Young Unit 2 is a Bubcockand Wilcox steam generator installed in 1977_ Thc sleam generator

is U lignite-fired boiler with multiple cyclone-furnaces installed in polI1lllel using balanced-drnft and

natural circulalion assisted with circulation pumps. Originulllllit design steam generating capacity i" 3.20

million lbslhr at 2,620 psi witl1 a fuel heal input of4,696 mmHtuJhr_ The boiler is fired by twdve ten-fOOl

diameter cyclone burners, arranged "three over three" acroSS the front and rear wall" of the lower furnace.

The unit has a tubular "ir heater installed between the boiler and tho fiuo gus ductwork leading to tho ESP.

Exhaust gase" leave the air heater and pass lhrough an ESP for particulate collection and removal

followed by the two inducod draft fans (installed in parn.llel) prior to a welilue gas desulfurization (FGD)

system which discharges 10 the stack. The currenl air poilulion control system's configuration allows a

portion ofthe low dusl flue gas to reheal the Slack gas, thus hypassing the FGD system. Unil2 has a

nominal 439 MW net design output capacity rating, is capable ofsuslained outpul ofapproximately462

MW gross, and has an ultimate short-term maximum gross outpul (URGE) of512 MW.

Square Bu~e Electric Cooperative ;., Bums & McDonnell
BACT AfUlly,i.. for MRY Slolion Unil2 NO"Emis.'ions NOx BACT ATIolysis Smdy

The EPA's Technical Support Documcnl22 lisL<; n"mcplalc slcam turbine-generalor capacity ofMRY

Stalion Unit 2 as 477 MVl (gro",s), which was assumed for cal~ula~ng capital cost estimates for control

allematives.

The Unit 2 boiler at M.R. Young Station ineludes a unique coal conditioning syslcm (drying, crushing,

and feeding) ror each cyelone furnace specifically designed 10 aid in proper combustion of the lignilc fuel.

"Ibis melh",1 offiriug solid fuel signifJcanLly influences the re,ultmg nitrogen oxide concentration of the

Hue gases emitted from lhe boilers.

Milton R. Y",mg Smiion Uni1 2'5 boiler design, combustion perfonnance, and NOx emissions are

dominated by the composition und combn'lion characteristics of lhe North DakOla hgnile supplied solely

from a surface mine adjacent to the plant This mine is the only supplier ofsolid fuel for Ihis slaliou, as

lhere are nO railroad facililies provided to service the Millon R. Young plant. North Dakola lignite has

high moisture and high sodium conlenl, moderale higher he:lling values, and can have a widely variable

and high ash content compared to olher coals. These ch"mclcnstics "r~';lle difficulties in promotiug

consistent. 'lcHdy combustion and slag formation in [he cyclone burners_ It also results in produ~ing a

flyash lhal has severe deposition characloristics.

1be design unit operuting conditions forthis study are presented in Table 3-1. The historical average

lignilc cool analysis is shown in Table 3-2_

Table 3-1 - Unit Design Parameters

lJnil2

Dosi n {lnit 0 oratiTI ChH,<led.,li<. nes] n

Builor Typ< SubcriliC'lII'l

CumbUSlioTI System Cyclone

Number ofCycIOllOS; arraTIgemen~ lQca~Qn 12; 3 OVor 3, opposed

Unit Dc,i n Co .cil Ekctric.l Dutcut"!, MW (TIell""oss) 439/477

(I) Balanced dran, SlOgiC drum. superhealed sleam w,th slOgle sroge ofsleam reheat.

(2) - ·These valu,,", W",e "'labli.hc<! by the original equipmeill IlLlmlrncnncers, prior to

COllStruolioTI.

"'Ibid

Burns & McDonnell Square Bnrre Eleclric Cooperative.
NO" BACT AnalYEis Study BACT AnalYEls for MRY Sla,ion Uni, 2 NO" Emissions

3.0.2

Table 3-2 - Historical Average Lignile Coal Analysis

Lignite - Cenrer Mine Average

Ultimate Coal Analvsis: (<IS received) % bv m<L<'

Moisture 37.29

Carbon 38.69

Hydrogen 2.50

Nitrogen 0.57

'""" 0.81

"'" 8.74

Oxygen 11.40

To'" 100.00

Higher Healing Value, Btullb 6,661

NITROGEN OXIDES EMiSSiON FORMATION

Nitrogen oxides (NO,.) are produced when nitrogen in the fuel and combustion air arC exposed 10 high

temperntures. There are two primary sources ofNO" emissions., referred to as "themml" No" and "fuel"

NO".. Thermal NO" emissions are produced when elemenlal nitrogen in lhe combustion air is admitted 10

ahigh lcmpcroture zOne and oxidized. Fuel NO" emissions arc created during the rapid oxidalion ofthe

fuel containingnilrogen compounds. Formost coal-fIred units, thermal NO" emission typically

represents appro"imately 20% and fuel NO" about 80% ofthe total NO" formed_ Nitrogen oxide (NO) is

typically the most prcdominnnl form ofNO" emissions fromfossil fuel combustion, along wilhnitrogeu

dioxide (No,). The formatiou ofthcse compounds in ulilily poweIplanl boil= is sensitive to lhemethod

offiring and combustiou controls utilized. The techniques employed for mixing the combustion air and

fuel, which creates flames and high tempernture combustiou products, results from the rapid oxidization

of "arbon, hydrogen, and other exothennic reactions. Cyclone-fired boilers, by design, create intense heal

release mtes to mell and fluidize !he coal ash introduced into the barrel-sbaped furnaces. This produces

high ternpernture flue gases and resultsin very high uncontrolled NO" emissions. The amount oftherrnal

NOx emissions produced by cyclone boilers can be considerably higher than fuel NOx emissions_

3.1 IDENTIFICATION OF NOx CONTROL OPTIONS FOR MILTON R. YOUNG

STATION

The first step in the BACf evaluation is to identify aJl"'demon5lrated and potentially applicable control

technology ahemativesn20 according to the EPA's draft NSR J\.1anual. ill identifying control technologies,

"the applicant needs to survey the range ofpolentially available control options'''''.

" Ibid, [MlnOle numbcr 2, NSR Manual page 8.11

Square Bulle Electric Cooper'live BlJITl.< & McDonnell
BACT Analysis for MRY S"'~OTI [hut 2 NOx EnlissioTIS NOx BACf ATIoiysis Study

3.1.1 REVIEW OF RETROFIT INSTALLATiONS

The BACT delenninations listed in the EPA's RACTIBACTILAEll ClearinghollSe (RBLe) clnLabasc are

for new lacil ities. Thc Millon R. Young Slation is an existing powerplant [~ciliLy "Iilh two COJI-fired

EGUs. A BACT evaluation for retrofitting control equiprru:nllo coal-fired EGUs in an exiSling facility

will he suhslanlial1y djrf~Tl.'n1 limn an un"ly,is forinstaIling control equipm,,"l On eoul-fired EGUs io a

new f"cility. Consequently, in perlorming lhe BACT analysis for existing boilers at Milton R. Young

Stalion, it is imporlanl to review powcrplanl facilities, especially cyclone·fircd coal bOllcrs, which havc

retrofiNed NOx control equipment in recentyear._

In 1998, EPA issued a NOx SIP (SLate Implcmentalion Plan) call. Under the SIP call, ulility boilers in Ihe

easlern United St~lcs were required to subatantially reduce NOx emissions during the "ozone season".

Thc compliance dale for lhe NOx SIP call is May 31, 2004. Ahigh percentage of the fired electric

generalion facilities in Lhc cast~-m Unilcd States Imve or are in the process ofretrofitting NOx controls [0

comply "lith lhc NO" SIP call. The £1'A's NOx SIP call was noL appliG"ble 10 North Dakota ulility

boiler>_

Therc arc" number offossil fuel-fired JiGU powerpl~nl.s "round the United Stales that have implemented

or are planning to implement modifications Lo reduce NUx emisSJoos. The NOx emission control system

inslallaLions are in response to Acid Rain requirements, EPA's NOx SIP call, lhe Clean Air InterSlate

Rule (CAill), the RcgionJI Haze Rule (RJIR), and local regulUlion8.

In addilion to the facilities Lhal have had 10 retrofit emissions controls as ure,lIlt oILhe Title IV Parl 76

Acid Rain requiremenls and/or EPA's NOx SIP call, a few installations have had 10 retrofitcontmls in

recent year>; a8 lhe result ofcourt decisions resui Ling; from litigation and regulalory action_ None of the

boilers associated with id~"IItified consent decrees are cyclone-fired. They are also located in a region

requiring compliance wiLh an £1'A-approved State hnplemcnlation Plan for nitrogen oxides emissions

controls (i_e. NOx SIP call). As mentionc<l ubovc, North DakOla utility boilers w~7C not subject to lhe

EPA's NOx SIP call.

" Ibid, NSR Manll.i poge n. il

Bllrn, &. McDonnell Square BUlle Eloclno CooperJri"".
NOx BACr Analysis Study BACf Afioly,i. forMRY Stalion Unit 2 NOx Emis.<iorn

3.1.2 POTENTIALLY FEASIBLE NOx CONTROL OPTIONS FOR MILTON R.

YOUNG STATION

A review ofavailable information on retrofit installations performed at utility and industrial coal-fired

powerphmls during the past fifteen years was undertaken. NOx emission conll:oll.echnologies and

technique.s with potenli"l applic"tion 10 Millon R. YOlmg Station boilers were identified, and are listed in

Table 3-3.

TABLE 3-3 - Potentially Available NOx Control Technologies

Identified for BACT Analysis

." - .

NOx Control Technology

Pre-Combustion Controls

Fuel CleoningIBlendinglSwilching

Combustion Controls

Basic Combustion Control Improvements

LowNOx Burnm (LNB)

Separa,ed Overfire Air (SOFA)

Flue Ga, Recirculation

Fuel Reburn

Oxygen-enhaDced combustion (OEC)

Walcr/"e3rn injection (combus,ion tempering)

Post-Combustion Controls

Selective Non.Catalytic Roducliou (SNCR)

Selective C.talytic Reduction (SCR)

Elcctro-Catalytic Oxidation (Eoo )

NoleS: Lhese are basic forms oflhe idenrified te<hni uc>.

Not .1II'ari1ltion, or combi,.tion, are included_

(1) - SOFA l<chnologics ioclude Boosted SOFA and RoWing Opposed Fi,ed Ai' (ROFA)

(Z) _ SNCll Lochnologi'" indOOe Rich R~ent lojoctloo. and HydroclDbon-enhanced SNCR,

commoreio-lly avaJlable as ''NOXStOl, _

(3) _ Molo.pollolant control tccJmology ourrrnl1y uOOor c"nunerda] development by Powerspon Co",.

A comprehensivelitel'lture searcb, with sources including technical pupcrs and presentations made at

conferenc.es by nationally-recognized teclmical organizations, utilities and othe' parties involved with

design, coostruction, and testing ofNO" control techniques, plus lrurdware supplier experience lists, Was

perfonned_ The results ofthis search are presented In Appendix Al, which includes a sUJIlIIIlIryof

various selcctcd U.S. No" cmissionrcduclion rctrofil projecl'_

SqoaTe Bnlte EleCtric Coope"'tive B\ImS & McDonnell
BAd' Analy,i' It" MRY S!ariou Uuil 2 NOx Emi"inm

3.2 FEASIBILITY ANALYSIS

NOx IlACT Molysi. S~,dy

Th~ second siep oflhe ~top-.down" BACT process is to eV"lllate the control proce...,es lhat havc been

ideLlti fled and dclennine ifnny of the processe.' are tecbnical1y mfeasible.

An avnilable tcchnolob'Y is "applicable" ifit can be reason~bly be inst~lled nnd operated on the Source

type under consideralion. Also, Uconlrollechnique is considered available ifit h~s reached the st>lgc of

licensing and commercial availability_ For lhe purposes ofthis analysis, thc term "commercia]" is further

defined lo mean "capable of,,--,tablishmg a full conlrnclual agreement with comme,cJal and perfonnance "

guarantees rupported by nppropri~lefinancial bad:;ng" for lhe imp1emenlation of full--sc~le. full-time

systems ofthe technique or technology applicalion. A technology !hal is avuilable and applicable is

lCehnically fcasible.

There are three basie e~legorics ofNO" emission oontrol techniques and technologies:

• Pre-combuslion controls;

• Combus~on controls; .nd

• l'ost--combustion controls

Uneon!rollc(l NO" ~missions from a coal-lire<! dCclrie generating unit are highly dependent On type of

firing method, amount ofsolid fuel fired per unil time ffild furnace volume, and ihe fuel's h.sic

combustion propelti"" and elemcnWI composition. The basic meilinds for reduclion ofsuch emissioru;:

• either prevenl pollulion, i.e. use inhe,enlly ]nwer·emitlm1; proccs>csJpraclices which proouce

fewer NO" emissions during lhe power generation process; or

• involve improvements 10, Or provide new add'flll controls lhat, reduce emissions aJ1er lhey arc

produeed before lhey are emitted Irorn!he facility; or

• are combinations ofinherently lower-emitting-processes and add-on comrols.

Most of the iden~fied conlrol opLions havc been commercially-available, installcd, lITId operating in many

full_scale, permanent coal-fired utility boiler installations in the United St.tes for five years or more.

Pre--oombllstion controls, such as fUel switching, fuel blending, amI fud clc.ning have been prneticed and

perfunned at numerous ntility power p),mls, typically rur operational and sulfur emissions control

reasonS.

Burn' & McDonnell SGuare BUlle EIc"ClJic Cooperative.
NO" BAcr Analysis Study BACf Analysis forMRY Station Unit2 NOx Emissions

Combustion controls, such as low-NO" burners (LNBs) and overfire air systems, = very commonly

applied 10 reduce NOx emissions from fossil fuel-fired powerplants. Low-NOxBumers are typically

applied to pulverized coal, gaseous and liquid fuel-frred boilers. They are not applicable to cyclonc-frred

boilers. Flue gas recirculation (FOR) has been practiced and perfonned at nUmerOUS nallrnll gas and fuel

oil_fired utility and industrial powerplants for NO" emissions control reasons_ On large coal·fired utility

boilers, FGR has primarilybcen applied for steam temperature control purposes, not foremissions

control. Conventional Gas Rebnm (CGR) wilh ovcrfire airhas been installed and placed in commercial

operation on several cyclone-frred boilers, primarily in the c:ls(em region ofthe United Slates. Coal

Reburn (CR) with oVcrfire air bas been suocessfully.demonstrated on two cyclone-fired boilers and

commercially installed on three pulverized coal-fired boilers in the United Sffite5. Combustion tempering

(water/slcam injection) has been tested but has not been continuously praclicccl on cyolone-fired coal

hoilers_ Oxygen-enhanoed combustion has only been demonstrated andJorinslalled On a limited number

ofpulverized coal-fired powerplants, not on any coal-fIred cyclone boilers.

Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR) are post-oombustion

technologies that have been applied predominantly On eastern or midwestern bituminous coal-fired

boilers. Others, mostly comprised ofa combination ofav"ilable emission reduction technologies, "'"

.. ol1.co referred to as "hybrid" or "layered" controls_ Variations of SNCR., such as Rich Reagent Injection

(RID) with and without SNCR, have only been inslaUed or demonstrated on a limited number ofcyclonefired boilers. Other technologies, suoh as Fuel Lean Gas Rebumnl with SNCR, Irydrocurbon-enhanced

SNCR (oommereially avail~ble (IS NOxSlarTM), aIld Conventional Gas Rebum with SNCRhave only been

demonstrated and/or installed On a limited number ofpulverized coal-fIred power plants.

Emerging post-combustion mulli-pollularl Icon trol technologies, such as Pow""'J!an's Electro.-Catalytic

Oxidation (ECa'"), which ineludcNO" control, were also identified. These are typica1Jy in the large

pilot-scalc commercial development phase, and have not been suocessfullydemonstrated on a full scale

basis on any pulverized co~l, cyclone, or circulating fluid bed boilers.

In most of the combination or "layered" and emerging oontrol cases, the NO" controltedmology has been

demonstrated to be capable ofcontroUingthe targeted pollutant(s) on eitha;

• a fuJl-soale basis, but only with temporary equipment; or

• a full-scale basis, with pennanent equipment but in a limitcd number of installations; or

Square Burte Electric Cooperative Burns & McDonnell
DACT Aualysi, rOT MR.Y StaTion Unil2 NO~ Emissions NOxBAc:r Analysis Sludy

• with less than fulI·scale and full-lime applicntion.

3.2.1 SUMMARY OF RETROFIT INSTALLATIONS OF NOx CONTROL

TECHNOLOGIES

Th~'TC = a numher or facllilics around lhe counlry that have implemenled or ~re planning to implement

modifications lo reduce NUx emissions. Table 3-4 summ~rize5 lhe various NOx emission control "y5tem

installations cWTently iUbl"Hed, or that have been demonstrated on a fldl-seulc. short-term busis, in

response to Aeid Rain requiremenlS, EPNs NOx SIP cull and local regulations, Or a utility investigating

Ihe Il"Clmology_

TABLE 3-4 _Identified NOx Conlrol System Retrofits

on Cyclone Coal-fired Boilers

1'\<>. ofUnits(I) C)'c1oDe NOx Conlrol T""hnology Des<dplion

, Foel Swirching/Blonding

'"' - - Separated Overfue Air (SOFA)

._. . , - Selectivo Non-COI.lyric Reduction, wilh or wiilJout SOFA

" Rich Il.e,genllnj~"Ction,wilh SOFA

" - Convonlional fuel rebum (pulveri?ed or micronized coal, gas), wi SOFA

,' . Fuel lean ga, rebmn, with Or with<lUt SOFA

" High-duST Or low_dusl SCR, wilh or without olhor leohnologies

,, TaiJ.gas SCR, wilh or withonl oilier leohnologies

, , () TIll, 1,,1 ofknown NOx conlrol retrofil mstlllallons IS pnm8I11y fOCllSOd on nml' LIl II,. Uml<:<! SL""".

There may be oLher inSiallalions lhOl "'" simil;or bul we", nor iden'ified.

(2) _ In,"'lIed ror NO~ oonrrol (wiLhom ruel "bum). A l,sL orknown cyclone boiler SOFA insLallalions is indudeJ in

Appendix A2,

(J) - RR1 has only bee" demon,tral<:<! wi'h tempOrOTy <:qui~mom fur Ie"ing. See teohnie,llilcr.uu", referonec:; iu

Apl'eo,hx Al "d A2 for d,,,,ik

(4) - Sevcr.ll convenLion,1 coal and gas ,ebum relrofils h,ve disCOIItinned rebmn demon'I"'tiou or 'online opcr:Ulon.

Se, Techn;cal Liter,tu", Ref",ence liS! amI Appendix A3 for furth'" details.

(5) - Only one CXllrnple offuel lean sas "bum reL",fi, (WiLhoul OFA) on a oyclone·fired oo,ler has been de""'u,rraLed.

This sy:stcrn was in,"'lled [or shon·lCm, ,ebnm "'"ling ,00 has been removed.

(6) - H'gh-<lu" ~CR leohnology has heen '.-trofilled OU ,ixteen U.S. cydon<-JiH:d boilers, all helieved 10 have ~OFA.

Luw-<lu'l SCRs m U.S. hal'< only b<:cn inSl:lHed ooly un pulverized coal_rired ooiler>, uone on eyelo""" One 'ail_

gas SCR in,,,,llalion on a c:oal·fi"d cyclone boiler fonnd in Gennany; nuno in lh. U..s. ~ee lechnieallileralurc

"r«eno« in Awrndix A I ,"d A~ [or d=;l,.

A more detailed description of,he VllriOU5 control "technology retrofits and their claimed effecliveness is

inclndc<l in the t"dmical descrip~onsand reference lilcrature in Ihe lcchnical feosibilily ~ssessment of

Burns &. McDonneU Sqnace Bullo Eleclric Coop=ti,'o.
NOx BACT Analysi. Study BACT Analysis for MRY Sbtion Unitl NOx Emissions

Appendix AI, amI Appendix A2, which includes a summary of various selected U.S. No", cmission

reduction retrofil projeots.

3.2.2 SUMMARY OF FEASIBLE NOx CONTROL TECHNOLOGIES FOR MRY

STATION

One example offuel switching applied to a cyclone-fired boiler was identified. Ottertail's Big Stone Unit

I was originally designed lo bum North Dakota lignite and was switched lo western subbituminous (PRE)

Goal for reasons unrelated to NOx emissions reduotion. Big Slone Unit I and M.R. Youug Station Unil2

have similar boiler deSigns. Thus, conversion ofMillon R. Young Station Unit 2's boiler to fire PRB coal

or a lignitelPRB blend is t""hniGally possible. Thcre are no railroad facilities provided to service the

Millon R. YoungplanL Additional operational and capItal costs to bring in large quantities ofPRB ooal

will be significant. Based on a comparison ofavailable emission dam between OUertail's Big Stone Unil

I and M.R. Station YOImg Unit 2, there is no expented reduntion in baseline (i.e. unwmrolJed) No",

,_" omissions from switching to PRE.from lignik at Millon R. Young Station. Although:fuel switching nt

Milton R. Young Station is tenhnioally feasible, this alternative wiH not be cconomiGa1Jy competiti~'e with

other NOx nontroltechnologies thai oITerbetterresulls for a munh lower combination of capital and

operational costs. For these reasons, it has not been considered further as an effective NO" emissions

.control option for MRY Station Unit 2 boiler.

Sep=tcd Overfire Air(SOFA) is the most wmmonly-applied, nombustion-related No", cmission

reduction teclmology that has been proven effective on cyclone-fired boilers, A version ofseparnted

overfire air specifieally designed for increased NOx emission reduction pcrformarJ"" for lignite-fired

cyclonc boilers, referred to as "AdvannedSOFA" in this analYSis, can be installed on both units atM.R.

Young Stauon. The potential operationallimi tations mentioned in the detailed feasibility discussions

included in Appendix AI for deeply air-stnged cyclones associated with separated overfire air are

expecled [0 limit the control cifeotivcness ofthis teclmique, alone and in combination willi other feasible

NOx control options.

Solective Non-Catalytic Reduction (SNCR) technology is a fOrm ofpost--combustion NOx emission

control thal has been successfully applied on numerOUS utility boilers burning ea.'<tem bihIminous coal,

midwestern bituminous coal, and, to a lesser e;xtenl, western subbitominous coal 10 reduce NOx

emissions. SNCR has also bcen used on fuel oil and natural gas-fired units. SNCRdoes not appear to be

dependent directly on the type ofbumers (wall-fired, langentially-fircd, and cydone-fired) employed in

SqUllre Butre Eleclrie Cooper.live Bums & McDormell
BACT An"ly,~, lorMRY Smuon Uuil2 NOx Emissions NOx BACT Analy,i. Stndy

the boil~'TS wh~rc it has been inslalled, ,,~lh or wilhoul air_slaged combustion with overfire air in full

operalion_ This GonlrolleGhnology adds urea (or ammonia) reagent to the hot furnaee gases in the upper

furnace to chemically rcduce nilrogen oxjdes. SNCR W"S Gonsidered technically feasible for application

On bolh umls at M.ll. Yonng Stalion. SNCR can be operated wilh amI without SOFA. Vmulion. of

SNCR technologies such asHydrocarbon-enham:~dSNeR (HE-SNCR) and "RolllInix" have been

i"'I"lIed (ffi pulverized coal-fired boilers but are no! proVCll On cyclone boilers_ This is dc,;cribed in uclail

in Appendix AI.

Rich Reagent Injeclion (RRI) is a fonn of SNCR under developmenl specifiGally jnlo..'Ilded for NOx r~

emissions conlrol on cyclone boilers. As of Oclober 2006, RRI has been d<:mun,trnted bul has not been

commercially installed and placed in continuous opef'ltion On a cyclone-fired boiler, especially one

burning coal with high fouling and slag lemperalurc sensitivilies associated with I ignite supplied from lhe

Center mine_ RRI o.dd, aqueous urea reagenllo the hot fumace gases near the cyclones, which must he

devoid offree oxygen in order lo avoid oxidalion oflhe ure<t which will increase NOx emissions. RRI is

~onsidered lechnically infeasible for application On lhe cyclone boilers al the Mllton R. Young .slalion at

lhe present time_ Thi, is described in dei<lil in Appendix AI.

Various [OnTIS offuel reburn with and without uverfrrc air are types of combustion-relaled teclmologies

that ha"e been demon,trnled and commercially installed on I'ulverir-ed coal, fucl oil-fired, and cyclone

utility and industrial boilers. N"ltIr.ll gas-Gonsuming v"rialions such as Convenlional Gas Rehum (CGR)

and Fuel-Lean Ga, Reburn (FLGRn,,) have been applied 10 cyclone hoilers hurning bituminous and

subbitumjnous couls. High capital costs expc"<:led for installing a natuml gas pipeline and high operating

costs from consumplion oflarge volumes oflmch fuel m~ke these alternatives economieullyunfavornble

for both unils al M.R. Young Stalion. Pulverized or micronized coal rebum, in combination with SOFA,

are technically feasible but will require cXlCnsive capilal, operaling and mainlenance oosts for fud

grinding equipment and facililies when installed and GpCIilled for both units al M.R. Young Stalion. This

is described in delail in App~'Ildix AI.

Fuel cleaning is a lechnique nOlmally applied lorcuuce lhe sulfur or ash conlenl ofa fossil fucl prior to

eomb\lstion. No examples offuel cleaning ofNorthDakola lignite or weslern subbituminous coal striclly

for NO" emissions reduction w~'TC found in available lechnicalliterature_ This technique i., Gonsidered

infeasible Jor NOx emissions control of M.R. Young Stalion boilers at Ihc pn:seal lime.

Bums & McDonnell 3_10 Square Ilulle Ekctric Coop=~ve.
NO~ BA.CTT Analysis Study BAcr Analysis forMRY Station Uoil2 NO~ Emis.sions

High-dus~ low-dusl, und tail-gas variations of ""loctivc call1lytic ",duclicn (SCR) technology have been

applied on pulverized coal and cyclone boilers as a post-combustion type ofNOx cmission control

throughout ilie world and in !he UUilCd Stales, except on unils .frring Norili Dakota lignile. 'Ibe severity

ofcalalysl blinding and pluggage from particulate matter and flue gases emitted from cyclone-frred

boilers burning North Dakota lignite precludes the tedmical feasibility for successful application ofsuch

SCR lochnology on lhe EGUs at the Milton R. Young Sllltion. 11Ii5 is doscribe<l in detail in Appendix Al

with supporting docwnenllllion in Appendix B.

The rcsulls ofStep 2 of the NOx BACT Analysis for detennining the technical fC<lSlbility ofpolenlial

control t«:hm'logies, including various ·'Iayered" oombination5, are listed in Tables 3-5 and 3-6.

TABLE 3·5 - Technically-Feasible Potential NO)( Control Technologies for

M.R. Young Station Unit 2 Cyclone Boiler

In Perm.aQen~Full·

SC31e S.nic. Dn

Exining Ca31_Fired

Cyclan. Utillty Technically F...,ible on M.R. Young

Control T.chnolo '" Boilers? Stallon Unil2 boiler?

Selective Nou-Ca~lytic

Reduction (SNCR) Yesm Yo " Conventionol Gas Rebum Yes uiresSOFAorASOFA Q! Yo

CoaiRebum Yes' Yo> ; R nile, SOFA or ASOFA

Fuel Leon Gas Rcburn N" Y" (wI or W/OUl SOF~SOFA)

Advanced SOFA No' , Yo> . Inc1ud<:s relocaled' ',e dryin vcnt om

So anted OFA sicSOFA Yes' ) Yo>

Combustion 1m roVcmOulS Yo> Yo> " icall included with se orated OFA

flue Gas Reeirculatiou No, for NOx cOOlIol Yo> uote ..,lcd to rcduce NO" further)

Fucl Switehing I Blcndin y" Yo> (nol e ..,lcd 10 reduce NOx further) .. S.. tecllIlleal feJlSJb,hty demil, and hterillIIrc Rcr.:rrnccs In Append,. A for del.a1ls.

(1) - All pnlrnb',l ,0rnblOOlion, nf I,chnologi", no' li...,d, Bee di><n",ion of"J.yer<d" Lsemologies.

(2)- A.sSllmes use Dfurea f<rr reagrnl. LintilOd IlIr1tl1>cr of'c[ivc instlliations on cydou'-fired bailen; burn;ns wesLern

subblluntin01lS (i.e. Powder River &s;u Dr PRB) ""aI.

(3) _ LintilOd nlODbor ofactive oonventional gas rebum (COR) insWlations on cyclone-fired boilers burning PRB coal.

(4) - Lintired number of dcmouslf3tious 0' aclive iM,U"l":" ofpulverized or microni=l 00.1 "burn on cyclone-fired boile".

One dcrnonslnolion ofpulveri7.<'li coal rebnminswilh PRB cool has b= pc:rfonned on 0 cyclon,.liT,d hoiler. nD longer

oc[ive, Ocly ono '<li>e pcrmenen' coal rebum inslOllalion on cyclone-fired boiler bumil18 e"I'm bilUminou, 00.1, nOne

b"mjns PRB cool or ligoit<.

(5) - Ocly one ""OIl_Ls"" ,,," demonslraJiou ofFLGRTH on aeyclone.f!IOd hoij" buroing cool with s"p""l<:d ov<rfire air,

(6) - No cyclono bo;lers firing North Ds.ko.. Hgnltc h.ve ie,Wlled basjc Ot" odvanced SOFA. Be< Appendl" A.

(7) - Con,idered p:ut ofSOFA installation fOt" ""al hollers wilhoul oombu,tiou ooo[rois fDr NO. rednetion.

(g"j _ No ""ample, of using reciroula1ed flue gas on coal-fired boilers for NOx emission, ,oulrol w,,,, found in o""jl.ble

"choi,oll;tcnllUre. Zero .ddiliocaJ No,. n:dcetion pnLential c;pc"ed from [his 'echnlqIIe alone for MRY Station Un;l 2.

POLential NO. reduction improvcmo:nt oU MRY Unill considered p:ut oC"advanced" BOFA.

(9) - Zero .Mitioaal NOx reduction poLsntial e.pecl<d lium lhi, t,cbllique ("",i[ehing from Hgnile 10 Iignilell'Rll blend, or

IOO%PRB) sloue fo, MRY SI'lion UUlI2,

Square Bn~c Electric Cooporati>e 3-11 Burns & MeDonneU
BACT Analysis for MllY Station Unil2 NUx Emi"ion, ~Ox BACT An.ly,is SluJy

TABLE 3-6 - Technically Infeasible Potential NOx Control Technologies for

M.R. Young Station Unit 2 Cyclone Boiler

-....

(I) _ All pQLeIltiol combina,ion, o of",chnologies nollistod. See" di,ou",iou o["layered" lechnologies.

(2) _ LimiLod numher of "",ive in,",ll.ti"", oa oyclone-fired bOller, burning wesLern ,ubbiruminollS root

(3) - No i,leIl'ifiod io,I.H"io05 on ooal·fiTCd ooil.,. io ti,e Un;Led ~"tate,. One Lail_end SCR 00 'yolonc boil", iu Gormany.

(4) - See discossioa orSeR fcosibiliry rOT NO lisnite io Appen<l" Al "IIU ApP"ndix B.

(5) _ Ilyd<oca,bon""uhancod SNCR b.. not bc"" dcrnonstrat<d on 0 cyclQno-fired boiler, uor any boiler firing Wc,lcm

,ubbiluminou, 0001 or!,gmLo.

(6) - Rota'iug Opposed_FIred Air with or wilhouI SNCR ba, nol beeu demonsn-a'cd on a cyclon.·fired boile,. No "pp,rcnl

significanl odvon"'ge, nve, SOFA on cydouc.rm:d boil"".

(1) - Ricll R~gc:nllTIjo<'i"" bas been SIlccessfully demon""'''''' [or hrier""rioo' wllh SOFA wilb Olld wilbou' SNCR al Iwo

")I<lon, powerplOllLs. ·Ih,re are no perman'ul RRJ m,l.n,lion, oompktoo and opcnrional as ofMay 200fi. Oiilioulrics in

m,mtoioing "" o,ygon-frcc furrnlcC environmeIl' in MRY SIaIi"" boil,,,, wl1<re lhe urea T"'I.:oul woold bo injacled duo 10

oy<:lono .irlfud imb,lancos during air_slarVed oombo,1ion woold in=,c NOx <missions.

(8) _ No kn""n demo",,,,,,iou, or pe'ma"eol in'I,Il.tio", o[Advauced ""uveuLionaf gas r.tum (CGR) or FLGR'" or

pulv<ri?erllmicrolli,-od c('I,1 rc:b"", (PCRhnCR) ill combiooLion wiLh sNCR ou e)'Clouo-firc~ boile,.. CGR and PCRlmCR

IT'Juirc ,,,!,,,al,d ",,,rfiro air. FLGR'" ilas boon ,pplic~ 10 pulV<rizoo coal firing wilb ...d wiLhoUL SOFA, wilh ""d wiL/Ullfl

SNCR; FU)R"" "mh SNCR JS 01'0 callod ""ino_enhanced fuel lean g"S rcbum (AEHAJR"').

(9) - No known uOIIIon'I"'lioo, or permanenl in'I,U'lion" ofO'ygOlXnbilIlOro oombustion (OEC) on oydoue_","" boil"",.

(10) - No pemlOTleTlLly iustlilled ""ample< oru,iug this '«hniquo eon'inuomly On ""ai_fired boiler> =0 rO"n~ in availahle

Leclmkal lit""'01re. NOI ,oil.blc [or high_moisture lis"i'e rue Is.

(11) - No know" <I'mo".'''''lion, orpern"",onl illSl,lIaliou' of u'ing lhi, teo<:hniquc conLmuously on eool_fi,od iloiler> [or NOx

cmi""ions control wcre found m aVallablo leclmkallllcrature.

Tn Pormancnl, FullSc.le Sorvice on

Existillg Coal_Fired

Cyolone ()'illiy 1'erbnioally ~'e",ible 00 M.R. Young

COlllr,,1 Tcchnolo 0') Boilers? Slaliull IJnit 2 boiler?

Seloctivc Calalylic Rcduction No'" - Unresolvable fouiing and ",,"'lyst

(SCR): convenlional (higil deaclivation.~~~efmsc;o;pcclcd- See disClIssion

du,I); Lnw"du,~ Tail-gas Yes[2) / No I y.,'1

) ofSeR ftllSlbilil fnr ND hgmlc.

Elcctrn-f".alalytio Oxidalion No, has nol been demnnstralod full-scale nor

(ECO"') N, ","chod commercial availability

HE-SNCR (mm ammonia) No' , No' '. Hll'l nOl been demon,tralod 00 cyclone.

Rolamix ROFA+SNCR) No'" NoW Has nol b<=l domon,trolod 00 cyclone.

Ricb Reagent lnjcctioo (RR)) N~~:~~~qUire,o"}1;on.[Tcc Jilrnaco Cllvirorunent,

w;lbASOFA No('1 var in air/fuel would incrcasc NOx emissioIlS.

RRI + SNCR willi ASOFA No' , No' '. See [ooluole .aJ fcaSlbilily disoussion.

Advann"';~ Conventional Gas

Reburn ACOR) + SNCR Nol') No. Ilas nol been uemonstrated 00 cyclone.

Coal Rclrum + SNCR No"! " Has nol bem dClllomITaLed on cyclone.

Fuel LeaTI Gas Rohum + SNCR Nol" N,. Has TIQt bom dClllOTIstrated on C}'C1on~.

Rom 0 osed Fired Air N,' N,. Has not been demOilSlraled on c cione.

Oxygen Enh.noed Combustion No(' No. Has not ho"" demonstraled on c donc.

Warer lnjecIioll No('" No'

Fuel Cleauin Nol rOTNOx control N,' (nol ex or€<! (0 ",duce NO,,- furlher

Soo toclmicfll feasibll[ delail, anu lil=lure Refe",uo" iu A ,ndi, A ror del>1Is.

Burns & McDonn~U 3_12 Sqt,are BUlle Electric Coop=tive_
NOxBACT Analysis Study BAct' Analysis fu,-MRY Station Unh2 NOxEmissions

Additional criteria besides technical feasibility are lItili7...ed fo,- technology selecllon in "- BACT analysis

have been included in the following sections summarizing conlrol effectiveness estimates, ""pital plus

operating and maintenance cost eslimates, ene,-gy impacts, ami environmenIal impacts:

• Control effectiveness (i.e. percent polllltant removed)

• Expecloo emission T1lLe (see Tables 3-7, 3-8) and emission redUClion (tons pe,- year)

• Economic impaels (Ictal cost and incremental cost effectiveness)

• Energy impa~ls

• Environmental impacts (olln.-'[ mcdia and emissions oftoxic and hazardous air pollutanls)

3.3 RANK OF TECHNICALLY FEASIBLE NOx CONTROL OPTIONS BY

EFFECTIVENESS

The third slep in the '"top-down" BACT evaIuationis to rank thcremaining control tcclmologies by

effectivencss_ The pmpose ofrnnking the controlleclmologics is to eSlablish a hierarchy that "places al

the '1op" the eontrol technology that achieves the lowest emis>;ion level."

. TIle' emission reduction (control effectiveness) percentages developed for ranking the ~vailableNO"

emission control options considered feasible for Milton R. Young Station Unil2 are shown in Table 3-7.

"', , The.., are estimales hased upon engineering judgments with considerations 0[:

-. Boiler heal input rales associated with realislic upper boundary operating assumplions;

• baseline emission rales corresponding to the realistic upper boundary operating assumptions;

• the general combustion properties ofNorth Dakota lignite;

• published and available emission reduction perfOlmance achieved at other similar utility

powerplants (cyclone-fired boilers);

• compute,--derived predictions; and

• inclusion ofperformance margins to allow for varialions in fuel, weather, equipment condition,

and other factors that prevenl lhe ultimate peak short-term performance from being reliably

sustained over the course of long-term oPCT1Ilion.

These NOx emission level and reduction percentage eslimales include adjustments ofpreviously

demonstrated orprcdicted perfonnance lhatrefiect diJIerences between North Dakota lignile and eastern

Or midweslern bituminous and westem subbituminous coals.

Square Bune Elecltic Cooperative 3_13 Burns & McDonnell
BAcr Analysis for MRY Slation Unil2 NOx Emi~,ious NOx BACT Arully.is Sludy

The numbers assume lhe estimaled capability ofthe employed Lechnique is achievable and sustainable

(long-term) and that polential operalional limilalions menlioned in the feasibility discussions allow lhe

succe3Sful praclice of lhu teclmique or teclmology. None of lhe remaining control OptiOIlS has been

installe<i on a cyclone-1ire.:] boiler burning N0I1h Dakot.a ligniLe. At; such, the expressed control

percentages refJcollhe USe ofengineeringjudgment, b~,cd on lhe Iis!ed tedmique or technology

applicalion. "fhis is partienlarly pertinent to an eonlrol options Lh"l involve "ir-staged combustion

associaled wilh vmous forms ofseparajed overfire air. SOFA-based controls for cyclone-fired coal_

burning boilers h"ve typically reduccd NOx emissiollievels signifjoanLly from the precontrol b""e1ine,

JIld which allow or enhanec furthcrreduclions when combined wilh other oontrol techniques und

teohnologies_

3,3.1 ESTABLISHING BASELINE NOx EMISSIONS FOR RANKING CONTROL

OPTIONS

Beforc Lhe various feasible NOx emis,ion control alternatives eun be eSlimaled and rant:ed in ord~'T of

effectiveness, the precontrol baseline level of emissions am) its basis must be delennine<.1. The EPA's

NSR Manuul provides general guidsnce for cslablishing estimaled baseline emissions to be used for Lhe

pmpose of calculating and comparing the conlrol and cost_effecliveness ofa control option:

"The basel ine emissions rate repre.lenls a realistic scenario ofupper boundary uncontrolled

cnnssions from the source. The NSPSfNESllAP reqnirements Or Lhe application ofcontrols,

including other con(rols necessary to comply wilh Siale or local mr pollution regula lions, are

not considered in calculaling lhe bsseline ~'IIlissions. In olher words, baseline emissions are

essCIllialIy llncontrolled emissions, calculated using reali,tic upper bournJary operaling

assunlp~ons_ When ealeuJuting the CO.lt effecliveness uf added post-proce" emissions

control, to certain inherently lower pollming processes, baseline emissions may be assumed

10 be the emissions from the lower poiluling process itself In other words, ~"TIlission

reduction credit Can be taken for the use of inherently lower polluling prooesses'~5.

Also stated in lhe EPA's N.'lR Manual:

"Kllimaling rcslis!ie upper bound case scenurio clocs nol mean lbat the SOUrCe operales in an

ab,;olule worst-case manner allihe lime. For example, in devcloping a realistic upper

boundary case, baseline emissions calculations can also consider inherent physical or

operational constraints on the source. Such eonstrdints should aceura1cly reflect tbe true

"Ibid, NSR Manual B.37

B\Il'IlS & McDoIlIlell

'" SqUaTO Butle Elecnic Coopernliw.
NOx BAer AruJlysi, Study BACT Analysis for MRY Station Unit2 NOx Emissions

upper boundary ofthe soun;e's ability to physically operate and the applicant should submit

docUmentation to verify these constrainls·"·.

Eslablishing estimated baseline NOx emissions for a new or existing source involves determining the

design or operational basis ofthe emission rale. A useful means ofcomparing such emission rales is [0

establish the unit emission rate, expressed in pounds ofponutant per unil of process output. For processes

such as slearn-electric generating p<Jwerp]lIIlts utilizing combustion in boilers, lhe desired process output

(kilowatts or megawalts) can be reluted to thepollulant-bearing flue gas crealed by lhe combustion of

fuel. Unil>: offuel heat inpul (millions ofBWs) required 10 create a unit of desired electrical outpul (leW)

and tlms the efficiency of converting the fuel heat to sueh clcctrlcal output (unit heat rote, BtulkW-hr) are

important

A review of reported hourly NOx emissions for MRY Slalion Unit 2 boiler, including unit mass rates

(IbhnmBlu and lblhr), hoilerheat input (nnnBtu/hr), and gross electrical output in megawatts (MWJ, was

performed for the OpCrllting periods in years 200!-2005 inclusive. A realistic upper bound emission case

.scenario for each boiler's baseline emissions at Milton R. YOImg Station detennined the highest

summation of anyroHing 12-monlhperiod No" mass emissions (pounds), along with the summation of

ll1e gross heat input (mmRtus) and the boiler operating hours forthe same rolling 12-monlh.period

corresponding 10 the highest NOxpounds, Dividing the summation ofthe rolling 12-month NO", pounds

hy heat input results in a average unit emission rales (Ib/rnmBtu). Likewise, lhe summation of the rolling

12-momh gross heat input (mrnBtus) divided by the boiler operalinghours yields an avr:rage gross heat

inpul rate (mmBtu/lnl This emission evaluation revealed thal:

• Unit 2 al Milton R. Young Station is typically operated in a base_loaded manner;

• :MRYS Unil2's highest 12-consecutive month NOx mllSs emissions summation divided by the

surnnmlion ofthe same 12-month period's heat inpul aVeraged 0, 7861b/rnmBtuata

corresponding average unit heal input rate of4,885 rnmBtulhr and unit gross electrical outpul of

440MW•.

3.3.2 ESTIMATING CONTROL·EFFECTIVENESS OF NOx EMISSIONS

CONTROL OPTIONS

The degree ofsucccss in operalionofscparalCd overfire air alone and in combination with lhe other

selected feasible alternatives is important to the arnmml ofNOx emission reduction achieved. The

"Ibid, NSR Manual B.37

Square Butto Electric Cooperalive 3-15 Bnms & McDonnell
BACT Aoaly,i, for MRY SmlioJl Unil2 NOx EnllSsiQllS NOxDACT Analysis Srucly

emiSSIOn control perfonnanee from lhe advanoed version ofsC{Xlnlled ovcrfire air (ASOFA) is highly

dependent on lhe degree ofsuccess in ~<lmil1ing combustion air insufJIcicnt for oomplete combustion in

the cyclones wilhout causing related negnlivc in,pacls. The control pel'c~nlagc, cslimated for frring North

Dakol£llignile in the MRY Smlion boilers ref]~c1 tbe bchcf that operaling lhe exisling cyelones much

below an average cyclone sloichiometric nHio of approximately 0.95 (95% oflhe lheoretical amount of

oombuslion ~iT required for complclc oomlmftlion) will not be successfuL This is ,luc primanly Lo lhe

expected ·'starved air" combuslion causing. reduclion in cyclonc fumac~ gas lemperaturc~. thus c,calmg

a strong potential for molten slag solidifying in the cyclone barrcls, slag laps, and lower furnace floor

openinr;s. This would imposc a great intermption Lo sleam production since forced outages would be i':~-

required to remove this physical obstruction before full load boil~T opera lion conld be reeslllblished. The

EPA's draf! NSR Manual states "II is not the EPA's inlention 10Tequire analysis of each possihle level of

e1T!ciency for a controllechnique, as such an analy,is would result in a large number ofoptions"".

The potenti.l opcrationallimiLarions for deeply air-.'laged cyclones aseociated wilh separaled overfire air

and coalrebum allematives are expected to limillhc amount of NOx control pOlential possihle from

successful practioe oflhe particular leohnilluc or technology. This is dc"~Tibed in the dctaik-d feasibility

discussions included in AppeJldlX AI.

The advanced form ofscp=ted overlJrc air is expected 10 be effcctive in NOx emission reduction aud

Can bo combined wilh olher f""sible combustion-relaled and post-combusrion control alternatives for

Iho", lignile-fired cyclone boilCTS_ The ba.,io fonn of SOFA in oombillation wilh coal rebum, ~s rebum

options, and SNCR, was not ineluded in lhc detailed controi effeclivencss analysis ill ord~T 10 limit lhe

number of options that were evaluated.

Using an advanced formofSOJo-A system, M.R. YOlmg Sialion's Unit2'" boiler operating atMCR is

cxpcclcdlo achieve a NOx emission level of0-49 ib!mrnBtu when operaling modestly air_stagcd cyclone

furnaces with suitable oombUSlion controls_ This lcvel ofNOx reduclion fromASOFA operation,

approximately lhirty eighl percent, is based on Ihe expected abilily 10 reduce emissions wilhout incurrin g

polenlial significant negative impacLs ofthis lechnique_ This reduclion cslimale includes !he addition.l

.mounts ofcontrol potenlial available from operaling willi relocaled lignite drying syskm vent ports (and

}'GR ports for Unit 2) associaled wilh ASOFA operalion with modestly air-sLagcd cyclone fumaoes_

"Ibid, NSRManual B.37

Rums & MtDmmdl 3_16 S~uare Butte Electric C""pcTIllive.
NO" BACT Analysis Srudy BACT Analysis for MRY Slation Unit2 NOxErnissioIlS

Co~l reburn with ASOFA is estimaled to reduce NOx emissions for M.R. Young Station's Unit 2's !>oiler

operating atMCR slightly more than 54 percent nOm the pre-control baseline NOx emissionrnte,

considering similar control levels demonslrnlcd by previous cool-reburn retrofils On cyclone-fired boilers

and limilations previously discussed wilb ASOFA.

Conventional Gas Rebum and Fuel Lean Gas Rebum options were bolh assumed to be installed wilh

ASOFA. NO" rednction from COR with ASOFA operation is expected to be approximately 55.4 percent.

FLOR wilhASOFA is expecLcd 10 reduce NOx emissions appro"iJllillely forty fi~e percent. Eslimales for

NO" emissiollS for MR Young SllItion's Unit 2's boiler considered similar control levels demonstrated

by previous gas-rebumretrofils on cyclone"fired boilers Wilh modestly air-slaged cyclone furnaoes and

limitations previously diSmISsed with ASOI'A.

The NOx emissionmle for Selective Non-Catalylic Reduction (SNCR) (using urea) with ASOFA is

expecled to be ~pproxiIlliltely0.355 / 0.33, resulting from a reduction in NO" emissions ofapproximately

5S percent from the 12-month avernge pre-<oontrol baseline NOx emission mte.

Included in the fcasiblecontrol option ranking ofTable 3_7 are layered alternatives that were shown in

Table 3-5_ The highesl-performing NO" control allemalivcs remaining in consideration are rnnked in

.declining order ofexpected emission reduction. These combined control oplioru; refer to "adv:mccd"

SOFA, which is cxpccte<:l to have significanlly 10werNOx emissions than a typical SOFA system as

applied to the Millon R Young cyclone boilers.

Square Bune Elecuic Cooper-Hivc )-17 Bums & MoDonneli
BAcr Anal}";, [o,/>,fRY Slalioo Unit 2 NO~ F~nis,iollS NOx BACT /In.,!}'si, SI~<.1y

TABLE 3-7 - Ranked NOx Control Options Feasibla for MRY Station

Unit 2 Boiler with Expected Control Performance

( ) gnatJ gn

(2) • Control perce"!2ges aco ,,],live 10 an av'rnge pre-control emi"lOn boscline ofO.78G IMmn~L~ "">Cd on ann~al o""r.lioo or

h;ghe,! pr<o--<;ooiroi 12·monLh rolling NO' "'romal;on 01= em;"io", divJded oy L~e l2-01onlh heaL inpu' so""n.tion.

~,. Emi'sion ~,~c Conlrol

Labell') NUx CanlTol Tcchoi "' (lblmmBlu Pereenla ."

, SNCR(using urea) wI ASOF/I 0.330 58.0 .. -'. - ._-,,'-

D c",-, Raburn wilh ASOFA 0.350 55,4 .. C LiguiLeRobum wI ASOFA 0.360 54_2

. , Fuel Lean Gas Reborn wiiJl ASOFA 0,432 45.0 . - A Advanoed Sep0raled OYecfuc Air (/ISOFA) 0,489 37.7

. Baseline 0.786

, _AII='livede>i onassi ed room high"'L 10 low""l uniL NOx emi,"on "'e.

The annual ~,nission levels developed fOT Table 3-7's ranking the feasible aliernatives ""mille thol the

highest 12-month average pre-retrofit level ofunil NOx emissions fOT M.R. Young SLatlOn's Unit 2's "_""'r~ ,.. boiler is a baseline of 0.786 Ib/mrnBtu. This W"S detelmined from the highest Te]lorted rolling 12

conseculivc rnonlh period's summalion ofhourly NOx emis,jons (lbs).

The hourly gmss fuel heat input (mrnBlu) was summed over Ihat wme 12-month lime period, and divided

by Ihe numlJ<,r ofboiler operating hours to yield an annual average gross fud heat inpnt rate (mmlltnlhrl_

Multiplying 'he 12-monih aven,!,,,, heat input rale (mrnBlu!lrr) by the baseline or eoncrol alternative's 12-

monlh aV~TJge unit emission rale (lb/mmBlU) equals a 12-month average hourly NO" emissions rale

(lbilrr). Annual NO" emissions (tons) fOl" Ihe baseline pre--control condition WeTe calculated by

multiplying the 12-monlh summation fOT boiler operating homs during ~Ie same period as Ihe highesL

NOx ~missions by the 12-month average emission rate (Iblhrl. The annual tons for Ihe conlrol options

were calculated by mnlliplying the ~lIcrnalive's average anmml emission rate (1b/yJ") by u reduction faetOI"

(if appl icable) for heal inpul OT running plant enpacily and adjn.ting boiler opcrnling houn; by a n urmual

l,plirnc (availability) factor. Del:lils for Ihese adjusiments a«: included in Appendix 0. B"sed on these

c"lcuJations, the annual emissions fOl" M.R_ Young Station's UnilZ's boiler are sho"l11 in 'fable 3-8.

Bums & McDonnell Square Bune Eleclric Co<lper:uh'e.
,j•i,,£Jg•1J,,,

NO" BAcr Analysis Sltldy BAcr Analysis [orMRY Station Unil2 NOx EmissiollS

-----------------

3.4 NOx CONTROLS ANALYSIS AND IMPACTS EVALUATION

The fourth step of a ''1op-<!own'' BACT review is to """Juate the most effective cmission controls.

Energy, economic, and environmental impacts are to be coru;idcred in the control technology evaluation.

The purpose ofthe evaluation is to determine jrthere are any energy, economic or CIlvimnmenlal impacts

l1111t would eliminale the top conlrol technologies from consideralion.

3.4.1 NOx CONTROL ECONOMIC IMPACTS FOR MRY STATION UNIT 2

An evaluation wasperfonncd 10 detenninc lhc various cost impacts ofinstalling feasible NOx oonlroJ

alLcmatives on Mihon R. Young Unil 2. This evaluation includes estimated:

• Capitaloosls;

• Fixed and variable operating and maintenance cosLs; Bnd

• Levelized toW annual costs

to engineer, procure, conslruct, install, sloItup, lesl, and place into commercial op""'tion the particular

controllcchnology. The resulLs ofthis evaluation aIe summarized in Tables 3-9 through 3-13.

3.4.1.1 CAPITAL COST ESTIMATES FOR NOx CONTROL ALTERNATIVES

The capital costs to implemcm the various NOx control technologies were largely estimated from unit

output capital cost factors (SIkW) published in technical papers discussing those control technologies. In

the caSeS of SNCR, preliminary vendor budgetary cost information' was obtained and used in place of, or

to adjust, the publishcd unit output COgt factors. These cost estimates were considered to be 5tudy grade,

which is + or -30% accmacy.

The unit rnImcplale output capacity (gross electrical output in megawatts) assumcd for the NOx control

technologies capital costestimatc basis was 477:MW, for MRY Station Unit 1"'.

A review ofthe unil capital cost factor l<lnge and single point factors applicable to MRY Station Unit 2

NOx control technologies are presented in Table 3-9. The estimated installed and levelized capital costs

for thc highest-performing form of the various feasible NOx emission reduction technologies evaluated

for cost-effectiveness are showlI in Table 3.10. These are listed in order ofcoutrol effectiveness, with the

highest ranked option at the top.

20 Ibid fooUlole IDImber 23.

Square Bulle Elecrric Cooperalive 3·20 Burns & MoDonn.ll
BACT Analysis for MRY Slalion Unit2 NOx Emi.sion, NO~ BACT Analysi, Study

TABLE 3-9 - Unit Capital Cost Factors of

Feasible NOx Control Options for MRY Station Unit 2

Slogle Point

Unit Capital Cost I1adorPJ,

"". R.ngell) (SlkW)

Label"] NOx Conlrol Techni "' ,""W) MRYS Unill

, SNCR (usiug urea) wi ASOFA 20_35)6) 35.9(').1') _.0.

D Gas Rebmn wI ASOFA 15_JO(O) 74.4(5).1').(1)

C Liguile Rebum wi ASOFA 30_60(') j70.2~W)

---- B Fuol Loan G.. Rebum wi ASOFA ••(OJ 45_-r'M5),M . A Advanced Separal<:d Ovcrlim Air (ASOFA) 5_10(') II(')

(I) A11crnahvo dCSlgnahou has been ass'gJled ffUm h,gh",,' 1o 10w",I\lml NO. <JIIl'Slon rat<.

(2) - UniL capilol oosL factors (S/kW) of Ihese iul!ividu,llecimologi" oombincd by simple oddilio". Aclillli in'l.n,d co.lI, m,y

differ Lhis due 10 po,;';,'e or n<g,'iv, symrgi,lic effw~ Range ba>ed on publi,hed vaJ"" or vondOTproposals.

(3) - Single poiol '-0'1 f",lor is b"" ",rimate for dete,mi".Hnn of LOlal capil,1 <oS! [or' partieul,r Lechnology or combinatioll,

assuming moximnm IlJU' o:lJ"o,I)' ;s bo>«i OIl <"'>ling n,meplate mring. Single poin< rosL "Bure.' in 2006 doll.rs.

(4) _ E"''''''',d "'pHal "",1 [or fu'lCR poinl ",lim.Lo ",d fLOR point e>l,m"', ",,;ved f'om D",,,,,bor 2004 budgelary

propo"l by Fud T",h. Soc APl"'odix C2 for deLaiL<.

(5) - The single poinL uniL oapilal '0.'1 [oclOr 'ho\\ll Ior Ihc ",dv,nced" version ofSOFA derived ffUm Bum' & McDonnell

int'm.1 dalOb"", "nd ,ml osLIIrullo [or Nonh Daknla lign;'e_n"d 'yclono \K"iers

(6) - NESCAUM 2005 Technicall'oper, po.<led al Ihoir wobSlI<. S", Ic,bmc,l Te[mncos in Appendix Al for del,ils.

(7) - 'l'be ,ingle ]>Oi"l nLliL "'pi"l ,",I [."00- ,hoWll [or. ooo",nLional gas rebum system I"dudos Ibo ",'irnaloo oapilal "os! '0

in>I.JI " bi~b-p,,,,uro n,ru",1 gas ,upply pipeill," (ll A S/kWj, and lb,' bulh boikr, shore Iho copiOll cost ;n pro]>Ortion to

their resl"'ctive raled ~1W gross oulpul ,"V'citic,.

(8) - The ';nBlo r->inl Llnil ClIpilal cost [,clor sbov.lI for. Jigo,'e rehum ,yst'm is higbly silo-,pc,i['c, and asSUOle' lh'l new

pulvcriz<:", and building enclDsures "" requ;reo. n" gon"'''1 rost Iango [00- pulv<:rizoo ,,,,,l,fired boile" is indLKled in

'he NESCAUM 2005 Techni,al Pap'" [01" eyclono boilors is induded ll\ me 2005 WRAP Drafi Ropurt, ]>OsLed '" Lneir

web';I". The sins!o poinl unil copilal coS! factor roc ,hi, .1L"n"i"e fOr mere.sed PM collecrion <::lpaoity iocluded in

hgni'o rcbum option" 75.5 S/kW. See I<choi""l rclCrcrlo<S in Appendlx AI for de""I,.

(9) - The Llnil "'p,Lal ro'l [a,lor r,ngo [or fLGR opplkaLion, 0" boiler, wiL~out an exi'ling a ~igb-prc"urc n.=1 sao supply

"'oo nol [uund in .""il,bl, te,hoioollilelature. °fl,e ,i"Ble poi"l nOli '"pil,l ,0,1 [,<101" ,hoWll for a fuel I",," S'" Tebum

,ySl<m indudo, Iho cstirnlltcd capllal ro" 10 install a high-p",sstlI, nan,,,l gas supply pipehDe (15.1 SIl::Wj, and tho! holh

00;1,,,., ,hare ~Ie oapi'a1 '0>' iu pro]>Ol1ion Lo Lbcir resp,crive ,"'ed MW S'OSS "U'PUl c'p'cili""

Bum> & McDoundl 3_ll Square B~~o Electric Cooperative
NO" BACf Aoaly.i., ShIdy BACf Analysis for MRY Si;llion Unit 2 NO" Emissions

TABLE 3-10 - Estimated Capital Costs for

NOJ( Control Alternatives • MRY Station Unit 2

~" • In=lled eapJlal cost;s ,,,im.ted fur determination oflol.1 c.pital cUS! for. paIli,u1or technology or

oombmation, as""ming 477 MWg nnil eopadty 'llling. All cost ngures in 2006 dollars.

• AnO".I;lod ,opila! 00" [1151a1lod capilol «)Sf x O.OS71S """ualized capital ""Ifu:tor.

- Co,tsfor go< robum options iod"dc high_pro"""" ""lural gas ,upply pipeline i.,..llod eap;ta1 CO" of

SI~,98S,OOO for CGR ""d 57,4\14,000 ror FWR: and unnu,lizi:d ""pi..1""" on 1,307,ooO/yr for COil.

und $6,J,ooo for !'LOR. Soc fuOlnol" 11-8 and 10 "ndc:rTable 3-9.

• Cm", fo; in<:ml5,d PM ,oll,ctioo cap",ily moloded in lignile rebum opli.o at, S36,0I3,O!)O rOT in,tlll'"

"'p;ta! ""st. and SJ,I4Q,OOIllyr "",""Iizrd capilOt oo,~

()

")

(',

«)

. (5)

Insl.U.d Allllnali~.d

Capilal Capital

All. NOx Control A.lIematl~e

Co,tV) Custl')

Labelll) $1,000 $1,000

, SNCRwlASOFA 17,125 1,493

0 Go. Rebum wI ASOFA' 35,490 3,094

Lignile Reburn wi ASOfA'

, C 51,167 7.077

, Fuel Lean Gas Reburn wI ASOFA' 21,BI7 1,9ll2

A Ad~anced SOfA (ASOFA) 10,008 .n

Baseline 0 0

, - A!I'llUlbvc label has been ""i ed rrnmbi Lto lowest unit NCb; emission me.

"'

3.4.1.2 Operating and Maintenance Cost Estimates for MRY Station NOx

Controls

TIle operational and maintenance OO/lts to implement the variOllS NOx control tecMologies were largely

estimated from cost fuctors (percrnrnges of installed capital costs) established in the EPA's Air Pollution

Control Cosl:MunuaJ (OAQPS) for SNCR"', and from published in techllical papers discussing those

controltechllologies. ill the cases including various fonns ofSNCR, preliminary vendor qnotes were

obtained and used in pille< of, Or to adjust tbe OAQPS eost factors, Thcse cool esliJrul!es were cousidered

to be study grade, which is +or-30% uccnrncy.

Fixed and variable operating and maintenance costs eonsidered and included in each NOx control

tecMology's aruma1 Q&M costs are estimates of:

• Auxiliary etoclrical power cousumption for operating the additional eonlrol equipment;

• Reagent consumption, and reagent unit cost for SNCR alternatives; and

• Reagent dilution walerconsumption and unit cost for SNCR alternatives.

'" EPA Offico ofAir Quality Planning and Standards (OAQPS) publioalion EPA!~S2fB-.02.001, Sec,iou 4.2, NOx Coulrols- NOx Po5l-Cotnbuslion, Chapter 1 - Seloctive Nun·Catalytic Rcduction, daled Octol>er 2000, posted at

their website: http://www.epa.gov/rrnlcalo/dirl/''-'4_2 ohLpdf

&jure BUlIo Electrio Cuoper.otivo J·22 BllInS & McDotlIlOll
lJACT AlUll}'"i., rur .\1lI Y SI"IL"" t;" il 2 NO" Elni"i~,,,

RO\'i'cd 1011712006

• [n~(~a"cs or ,m'ings in "uxili,,'Y d"clrical puwcr consumplion for chang", in cu"l prepamlion

etluirmenl a"d lund Lng-, prilnnrilJ' ror fLLel r"bum "a,c<;

• Gene",1 operaling I~hur, pill' mainlonallco bhor ;l[\(lm"lori"ls tI~\'otC(IIO lhc addition~1 ~lllission

comrol equipment anti ilS iLnpacl un "xiSlillg hoiler e4uiplll~"'.

• Roducliorr' in r"\'cnue expected m L.",ull from I"s" or- unit avaibhility, i.c. "\'ta!>~, altributabl~ to

lhe cuntrol "plion, which reduce annual nel elilctrical gcne",tion availahle for s~1e (revenue).

For economic evalualion purpose." an annual ~vemgc runrriug p[~nt e3p~dly f"elm of 95.2 percent

~ompared to a !luminal unit oulput capacity of 462 MWg combined WLlh all avcrage ~nnual av;,ibbility

(uplime) or~,229 opcr"ling hou", (9].9 percem of8760 hours per ycar) resulling 111 an annual unil

capacity lactor of ~9_5% were "",ulncd for Unil 2'" pre-conlrol ba'eline annual opemlion. A heat input

mte of 4,885 mrntltlJhr and a NUx emission role of 0.786 Ib/mLnHlU ",e", assumed ror ~"ku["ling control

nod co'l_effecl; ,en~SS rrom pro-conlrol maximum rolling 12 momh summ"tion of nilrogen LlxiLlcs' m""

cmi"ion' for MRY St"lin" Unil 2.

T"ble ]-11 ,how Ih" ",Iim"leu annual operating and m~inLcn"n"c co'l< and icI'"lizod ~"n,,~1 O&M cosl

v"luc, for lbe hig"c"-p~r["onning fonn of,he various '",",'ible NOx emi.,ioLl reduction tcchLl<llog-io$,

These are liSIed in order OfCOLllrol ~ffcClivcno", wilh Ihe hig-he'l mnk~d uplions "Ilbo lOp. The co,t

m~lhodo[ogysummarized in Appendix Cll"ovi<los lnon: tlol:,ils I,'r the 1~\'e1i~cd ;Inn",;] O&M co,t

ea[~llbtions 'llld ~()sl faclors.

TABLE 3-11- Estimated O&M Costs for

NOK Control Alternatives - MRY Station Unit 2

,\nn",1 [.e,',liz,d ,Annn'[

O&M CO'I'" 0&1\1 CU'I'"

All. label'" ;~Ox CUlltrul Allemaltve Sl,OOO Sl,OOO

, SNCR ",I ASOFA ~, lOR 10,125

D Ga, Rcbum "i ASOFA ~8.63S 60,703

C LigLlilo Robum wi ASOFA Y,n~ 12,J~8

" !'lGI{ wi ASOFA 21,90'" D,~II

A Atlvallm[ SOFA (ASOfA) 2,~U5 J.5OJ

Ba<olino

,

" " - AI,c'[llilwc lobo! "OS b"'on ""i ,«fif " . ( ) g cu,n b'oh"l '0 10"",,"nLl I'iO, "n">lOU "'\e.

(2) . ,Innu,t opcrnling 'LL~ L"a;nL,na,," 0051 [0(' p,nkub, Lcduwlogy 0' ,ombiLL"i," ;, "''''l,aced L" ""i'

b",lin' op<mlian al "",,,;".1 "oi' ,ap,oity (462 tIWg) aud ,,,,um,, " ~J.9% "'''ago ,,,,,u,1 'I'a;bh,IIl"

wbich L! bighest <o"",,eUul" l2-munLh, of ope",Lion from 200 1·2@'. All ,"0." rigu"" in ,O[}l; Jolt"",,

Bum., & MOOOlllldl J-n Squ"ro Uullc fledrio C"opOmL;\'O
NOx BACT Analysis Smdy BACT Analysis for MRY Slation Unil2 NOx Emissions

(4) •Co,,,, for inoroa'od PM ",ll"'lion <.pacity included in ligmlc rebum oplion ore ~J,35~,OOOfyr for annull!

. o&M 'OS~ and M, T94,OOOlyr annuali,.ed o&M ""I.

3.4.1.3 LEVELIZED TOTAL ANNUAL COST ESTIMATES FOR MRY STATION

NOll: CONTROLS

In order to compare a particular NOx emission reduction allcmative during the initial engineering analysis

portion of the BACf selection process, the SUm of estimated annualizel! installed capital plus levelized

:mnual operating:md maintenance eosls, which is referred to as "Levelized Total Annual Cost" (LTAC).

ofexpected pollutant removal by implementing that alLernative was calculated. TheLTAC for all NOK

eonlrol alternatives was cal""lated based on the same economic condilions and a 20 year project life (see

Appendix Cl formcthodology). The unit control cost was then determined as the LTAC divided by

annual tons ofpoilutantemissiOIls that would be "voided by implemcnbtion oftbe respective altemative_

The control alternatives Were also compared by calculating thc change in llIlit cost (incremental cost) per

incremental ton removed for the next most stringent allemative. This identified whieh alternatives

produoed the highest increment ofexpecled pollutanlrcduction for the estinmted lowesl average annual

cost increment compared with the baseline cmi"sion rate_ The e:<pcded annual number ofmus of

pollutant removed versus estimated LTAC for each remaining oontrol allcrnalive was then plotled. .

The comp,ui<;on of the cost·effectiveness of the remaining NOx cmi,,-,ion reduetiOIl teclmologics was

made and is shown in Table 3-12 ~nd Figures 3-1 and 3-2 for MRY Stalion Uuit 2. These figures plol

estimated annual amount ofNOx removal (emi"-'ion reducLIon) in tons per-year on the ordinate

(horizontal axis) and the estimated levelized total annual eOlll in thousands ofU.S. d01lam per year on the

abscissa (vertical axis), for eaoh of [he remaining NOx oontrol technologies. PoinlS on the graph that are

furthest to thc right and closest to the hori7.onl<l1 axi" are deemed more co"l-effective, sinoe they repr=nt

oonlrols that achieve more NO" removal per dollar required for lotal annual oools ofoperalion.

maintenance, Qnd capilal recovery (depreciation).

Although the NSRManual repeatedly pre"cribes f91lowing a "lOp down" analysis approach for BACT

determin~tion, the development ofa least cost envelope wilh dominant conlrols (ns,;un in NSR Manual

Figure B-1, page B.42) clearly labels points with lower emi"sions reductions and total annual costs fir"t.

i.e. "A". '"B", etc. then prooeeding wilh labeling and connecting points plotted further nway from the zero

emission reduction point. TIlls "bottom·up" approach is for plotting the le..,t--coot (dominant) control

curve. The labeling ofoach unit's NO" control tcclmiqne allemalive has followed this approach.

Square Butte Eleelri.e Cooporative 3-24 BlllIls & McDonnell
8.\.CT .",""Iy'" for .lfl(Y SI''',(,n [T"'L 2 NO, F,,,i";"lL>

[(e"ised 1011712006

------ ~----

TABLE 3-12 - Estimated Annual Emissions ii1nd Levelized Totiill Annual Cost

for NOx Control Alterniiltives - MRY Station Unit 2

(i) ,\ILcrn"LVO 10 ",,,gn," from hLghe.;L Lo low,., ","L Nil ,

(2) _ E"i'''''L,d ,""""I omission 'om nS>llme a" """,,"1 u,,;1 av"iM.ili'y [,,'ur ,p",ili, 10 c,eil ,1"maLh",; 9J.9% W,,,

,,,"m,d Ii" Lloe "",ehne ",c,

(3) _E,tlm,l,d ,"""I 'om of omi.,,;ol\ "'d"'II"" i, th, <1if[erc",e 1>I;,,,,,,,,n ,nn",1 b"e1m' Lo", ,nd 'aeh ,,11""'''li''o', nnn",l

'm''''o", (LC"'),

(4) • Lc"oIi"d 1DLal Anl\"" 1'"." = Anm"li;ood '",,,,lIed Ca~i",1 Co.,L , L<voli'eu ,\,,,,,,,,1 D.H[ co", S,," noLe~] r""

I'ooks J _10 OJtd J_II 1\'''"m",]",,1 '"'" [,,,Ior>, omis"o"' or. "kolaL,d ,jom "niL ,,,,i,,i,," ,"'e" 'on'rol

~"'''"'''g<, 1><,,,,ly heal iopol, ,nd a""",1 h,,~', "rom'io" comp.",d Lo ~"_"''''LO'' "'",elm, b"e<J on ,,",ml "l',mL;un

" high,,, ,llowab[o p'<-c""lrol NO, cmi"ion "IC.

(S) _ Mor's< 1'"",,,,1 CosL EIT",,'i"'"'" (S.'LO,,) " 'he l.e,'e1i",,1 Tol,1 1."""01 Co>' (IOUOS')T) Ji,idou 0)' ,\'n,,"1 Gom,io"

R,ducL;"" (L"","y,j, All "">l ligllfos ;n 1006 dolla"

(0) _ I.TAC fur ga' «oum Op,iOLl< .,,01"'[0 ni~h-J'''''''''' "''''lfal g" ,upply ~ip,lio, onl\",Ii,,<d o'l,iL,1 ""I "I :> 1,3U7,U!J!),'yr

for CGR "",I Sf,5J,UOO ~Iu, I", fLl;R. S,,, [o"Lno,", ¥3 'TId 10 "n"or I,blo J·9

(7) ,Ll'M: 'br in,.-ea.,ee[ PM collc"io" c,p",~' melud'd in liS";'" ",,""" opLic'" '"' 'ppn",,,,,,'e!y SJ, HO.IJLJO fo,

''',mali'-"d ,apiL,1 eo,L pi", S4, 19',OOUlyr Ibr ann",li,.«1 O&~I ,0,L, [0" LTAC "'010,,1 of ~7,JJj_OUU,y',

L.,-e1i,.d

._\n,,"al NOx TOl"1 Aver"g"

A""ual NO., [,;Il,i"ion, Annnal Cont,..,!

Alt, Cmi"'o",m Rcd"cllo,,'" Co'l'" CIl,t!iJ

Lab.lll' NO., COnIc"! Alt"rna~v. T"ml T Ton"Ye SI,OOU Silon

, SNCR wi ASOFA 6,421 9,372 I 1,618 1,240

0 Ga, Rcbum wi ASOFA 6,~~2 R,910 (i3,3n'" 7,17 i

C Ligolle Rebum wi ASOFA 6,96-1 S,S29 19,475'" 2,2M

, FLGR wi ASOFA ~,490 7,]03 29,J 17"') 4,014

A AJvoncen SOFA (ASUFA) 9,621 6,172 ~,J76

Baseline

'"

15,793

" "

0,1 1",-, h,,," . <"",i.«io", r:lIe.

3-25
NO,- BACT ,\nolysi' $louy

Reviseu 10/171200fi

BACT Anoly,is for MRY $101;011 Un;ll NOxEmi.,i""s

Figure 3-1 - NO~ Control Cost Effectiveness _ MRY Station Unit 2(1)

1-------

Millon R. Young Station Unit2 NO~ Control

Annual Ramoval Vi lavalized Total Annual Cosl

70000

60000

SOOOCl

40000

30000

20000

10000

A' Ad"'"""d S.p.",ted Overti"' p,jr (ASOFA)

e• Fuel Lean Goo Reoum wiASOFA

G • lignite Reb"", wi PiOOFA

O. G., Rel>"", wlASOFA

E • SNell wi PiOOFA

, .

•

o •

c

•

,

•

"L~~~ __

() 100() 2()OO 3000 4000 5000 6000 7000 SOOO 9000 10000

Annual NOx Removal, tonsiyr

1_- _

([ I - All emL FLg""'" i" 2006 dolla". Numb<" "" li,t<d 'nd ~u,li(im ''" oorod in Taole J_12_

The purpose ofFigurc J_I is to show Ihc mnge ofconlrol and cost for all feasible NOx rc,luetion

allemotives evoluated. A dominant set of conlrol alteIllillives were delermined by generating whnt is called

[he "envelope of leo,t-cost alternative.'"_ The dominant eonlrols cost curve is the best fit line through [he

paine' Forming the righlmo~t boun<lol)' ofthe data zooe 00 0 <cacrer plo[ of[he anmml NOx [cmov,d tonooge

versus LTAC for the various remainiog IlACT sl!emaHves_ Following a "bottom-up" grnphical comporison

approach, eoch of[he NOx contra] technologies represented by a dam point 'a tbe len of and above the least

eOSl envelope are inferior oontrol allema'ioes pel the NStt Mannal and should be excluded ,rom fu[ther

analysi~ on n COs! efficienoy basis_

Squ",c BOI[e Electric Coop"rative 3-26 Bum' & M"Dolllldl
BACT Allaly.", I'K "IRY SL"LJ"" lini, , N(h FIll;.,',i,,,,,

Revised [Oil JI~006

-----------------

0(" Lh~ Ic",lmic"Uy ,ea,iblc NO.. conlrol altoJ native, consi,lorcd [or MRY Shlliull Unil 2, dala point, for

tn""c~Liom,1 ga, [~blLm (POillt OJ and fuel-looJl gos ",b~n, (Ppilll 8) wiLh "dv'lIlced separJted over",e ui[,

ond ligni(C ,chum wilh i\SOFA (Poim C). lay dislLnelly [en and obO\'~ Lh~ olher poinl' of the colltrol e<>SI

point,' scutter plm of FJgmo 3- t. Thcse conlrol op~ons a[e inferior and lherefore woro elimillated Irom

("urthe[ control cost-o[fecti,'en~'" amolysi,.

Average and mcremcallli "Jlnu~1 costs and NO, emission re,hlO,iollS (o[ Ihe dominant le,,-,,-co't comrol

allernalives remaining ,,["ter the climilllllion of Ihe ohviou;;ly inferior oplions arc li,led in Tobie 3-13. The

"nmml NOx cOlllrollons per year, dividcd by Ihe tomllevelized annual CO"" yields an aver,IJ;C unil cost

(S/ton). lncremeulnl eosl effecliveness i, a measure oflhc illerea,e iu margin"i eost el1cclivcnes<

be/weeLl lWO specifio ~Ilc[n"li,c,. The addilio,,"1 TOll' per year of NO, en~lrul rdalivo to the previous

apparent lea,l-cost ClliVC l>oiLll, divi,kd by ti,e increase in le"e1ized anLlual CO", y,eld,; an inc[emcnlul unit

eo,l (Shon). Allerll"ti,"ely, lhe incremenlal cosl eCCeelive"e"" an"lysis identifie, tile mle or chan~o uCco,l

~ffee[ivc"e,.' IVJ III re'ped lu [emoval beLlel'lS {i.c., ,h~ slope uJ" tile ~nvd()pe of le"st-cost control

al,e",ati,·e,. "1'0 callc<l 1],0 dllmin"nt <;<muol;; co,t clll've or DCCq belween I,,<:ecssi,cly more efrective

allernatives "hieh ",e "oll,idcre<llechnie"lly feasible for "'Ii[,on R. Young SrnllO[] hoilcrs.

TABLE 3-13 - Dominant Controls Cost Curve Points for

Feasible BACT NOx Alternatives - MRY Station Unit 2

() """ 0 n P (SOA)uh,gh,,1

J.12. ,nd oa Lho S"pIOl 'h., ""unlpnay thi, ",ble (I'oin" lJ. C. ",d D "'"" el;m;m"d),

(2) All ,ost liguro, in 20[1'; ,loll,,,,

(l) . AllJlUal e",l",ion red,,"i,," "od belj"d OOJ1lrot ,"os[ oruo"", al'om,L;'o, " T<I.tLVo <0 «'ITO", oom 'o1d pro.Gonlfol uniL

MCR bmlinc emission "Ie.

lq) - IncremenL b,,,"{] "11Ol' """p,,,i,on bel",c" ,0m","tLv, ,1«maLh'", (p";n") r,,,,,, lowo>, '" high"", CJlocpL " no"~.

Incrcmenl,,1

L.,·.]iLe~ LCVC][lOd Incremenl,,]

'1'01"1 Annual Tnt"l Ann".[ Inoremenl,,1

Annu,[ !CUlls,loll Annu,,] E",i"iu" Con,,"ol Co,t

,\It. NO, Cu.'l""" ne~ud]()n'H Cost'''''' ({'duelio"'" IW,,"(j,"em.~'

Lobel'" Conlrol T,chni~u. (SI,OOOlyr) (Ip.") (51,000l)r) (lp)) (S/tonJ''''''

, SNCR wi ASOFI\ 11,61~ 9,]72 7,~42 3,2UO 2,26]

A ,\<i"o1llced SOFA 4.376 (,,172 4,376 6, I72 (ASOE'A) ," , D" "" '" "" b '051 cur", ol""\ r,."", [,,,,,,, A C , ., 'SNCK wl ..\sOJ-A ar, labele~ Lh, ~",.e", in T.010

The incrcmcnlill "",l """ly;is indicatcs lhllL from a co'l dlccti,'c'\eS< viewpoinl, Lho SNCR Willl "SOFA

alteTImtive ioo",s " significant allllll:l I (levclized) incre",o,llol eusl "omp,,,e,1 to the ASOFA NO., COL\I",I

Bl1m, & McD"nndl J·1'1 Sql10re Ilullo Eb:lt1C Coop"ral'\'<
NO~ IlACT Anoly.,;., Swdy

Revi,ed 1O!l7nUU6

BIICT Al1aly,i., LDr MRY Slolion UI1il2 NOx Em;«i(lLl,

tcchnique (slop" lrom zero baseliue to ASOFA, Point A was $709/tou for MRYS Unil 2; the incremental

cost (slope) from ASOFA, Point A to SNCR with ASOfA, Point E wu< $2,263/ton for MRYS Unil 2.

Figure 3-2 oOn\ains a rcpcLition of lhc lcvcli2Cd tom] annual cmt and NOx control information from

Figure J-I for MRY Station Unj, 2, wj!h Poinl B (FlGRTM wilh ASOFA), Point C (Ugnilc Rcbum wilh

ASOFA) and Point D (convcntional gas rebum with ASOl'A) remove<l This is Ihc dominant controls

oost curve for MRY Station Unit 2 NOx emissions alternatives.

Figure 3-2 - MRY Station Unit 2 NOx Control Alternatives

BACT Dominant Controls Cost Curve!l)

Milton R, Young Stalion Unit2 NOx Control

Dominant Controls Cost Curve

\ -' .. _.-

B,OOO

2,000

5,000

4,000

10,000

14,000 ,-------------------C,-,

Slop. = Inorern"n"'l SI"'"

(poi"" B. G. ond 0 rornowdl

12,000 A. Ad",",.d S.poro!Od O""fire Air (ASOFA)

E_5NGRwIASOFA -

o 1,000 2,000 3,000 4\000 5,000 6,000 7,000 3,000 9,000 10,000

Annual NO. Removal, tons/yr

(1) - All ,osl flgufCS in 200G doll,,,, Numb", oro li"oo ""j qua[;LLm ""' "o"d in T.bl" J-ll

In ih~ U.S. EPA'. NSR Manual, the EPA docs no! ,pecify .cccptubic or unaccoptable range. for average

(unit control costs) and increment"l cost efl"ctiv~ncss valucs. A, can be secn lrom" review of T"ble 3-

Squa,e [lulle Eleolric Cooper.,ivc J_2~ !:Iurn, & MeDonnell
8.\('T AO\,d,.,i, Ie" MRY Slali,," L",,"! NO, F",i"i""1

Revi,~d 10117/2006

NO, UACT r\llalv.'" S!lIdy

14, the ~vomg. levelized conlml cO.<l cCll;cli"eness (called lhe ullil CQl\lrol co,l in loi, reporr) ml\g:c, from

"pproximmcly S709/loo 10 $7 ,1711ton ofMRYS Unit 1', NO, cmi"iom removed. Ir slluultl be nOled,

however, that Iho highe,t e,timmed aver"gc eOlllwl co,t, involve gas rebum technologio, that wcn;

shown 10 be inferior option, (nOl all rhe domJJl~nt conlrols Co,l cmve) aod thus wc"e eliminated from

[urlher impucls analy.;,.

Thc incremcolul oo,t cffe<ori"cne" i. a measure of lhe increa,c in margin" I eost ~nectivenc"s belwe~n

two -,pecific alternalivc,. Alternat;vely, the incremenl"l cosl efl""tivenc,,", analysis ideotifie, the ralC of

change of cosl eft"ccliVCness wilo rcspeCl IO rcmo"al bencfits (i.e., th~ .Iope ot· the lcast_to,t cDv~lo[1e of

dominant oontrol alrernaIive, Or dominant control, cO.,t curvc) bolwcen successively more effeclive

alternaIives. The economic impact analysis in,lioales Ihat from a eo.,t cffecliveno" viewpo;nl, Ihe highe,t

per[bl1ning alrernativc is SNell.. "iro ASOFA (Polnl E). This oumrul oplion is considered tec~icarry

fC;lSible for Milton R. Yoong "lalion Uoit 2 boiler 11m incur,; ,1 ,ignilic,mt "nlllml (levelizc(1) incremental

cost rclat; vc 10 lhe ne.'l oighesr t'ea."bk NOx conlrol technique, A"OFA (roinl A) "hen ASOFA is

compared against ;hc pre-o"nlrol ba,elinc. Tlte l\d\'llTlo~d SepJm!ed Overtire Air nltcrnuli\'~ I", aLl

uver"ge ul1it conlrol enSl (~709lIun) upproximolely 5R% ol-th~ higheST performing leasiole "hema(;ve 0[1

the uom;rumt conlrols co'l Clm'" (SNell with ASOl'A, $1 ,:'40110n). ASOFA al,o has a mu"o lower

incremental oO.'l pcr lon r"bli,'e TO lhc l'J'c-coIIl",1 b",elil1" (,lope from zero tn Poinl i\, 5709/lon)

compJJ'ed 10 SNCR willt ASOFA (Point [) vcroU, ASOFA (Point A); Ihe <lore I""" Point A to 1'0"11 E

was 52,26]/toO\.

The other elcmcnL< "r 100 rounh srep of a BACT ',lm1ly5i< following economic i",pooLs ',Ir" to ~V"lualc thc

following impact, ol"lea,ibl<: omission controls:

Too el1<rgy impacl'.

• Thc cllvironL11"l1lal impact,.

Bum' & Mcl)onncll ]-2')
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NOxBACT Analy.is Study BACT Anoly,i. forMRY Station Unit 2 NOxErnissinn.

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3.4.2 ENERGY IMPACTS OF MRY STATION NOx CONTROLS

Operation of the mosl oost-effective NOx controllechnologies considered feasible for potential

application at the Millon R_ Young Station Impose direct impads on the C<lIlsumption of energy required

for the production of electrical power nt the facility. The details ofestimated energy usage and costs for

the various NOx control a][ematives are snmmarized in Appendix C3.

Control alternatives for reduction ofNOx emissions were reviewed to detmrnne ifthe use ofthe

tcchnique or technology will result in any significant or unusual energy penalties or benefits. There are

severnl basic kinds ofenergy impacts for NOx emissions controls:

• Potential increase or de<:rease in power plant energy consumption rcsulting from a change in

thermal (heat) energy to net eleclriC<l1 output conversion effioiency of the unit, usually expr=ed

as an hourly unit heal rate (Btu/kW-hr) or the inverse ofpounds ofpollutant per unit e1ectrio.a1

power output (MW-hr). This may ormaynot ohange the net electrical output (MW) ",,-paoity of

the EGU, depending On ifthere are physical or imposed limits on the lotal heat input to the boilcr

or elecTrical power outpul.

Potential increase or decrease in net electrical output oflhe unit, resulting from changes in

physical operational limitations imposed on the, ability to sustain a fuel heat input rate

(rrunBtuIhr) which results in a potentially lower or higher unit nel elcotrical output (MW)

capacity. This i. elTcc\ively a changc in net electrical output (MW) capacity of the EGU.

Potential increase or decrease in net elccTricai output ofthe unit, resulting from changes in

auxiliary electrical power demand and usage (kW, kW·hrs). This is effectively a change innci

ele<:lricul output (NlW) capacity oflhe EGD.

• Polential increase or decrease in reliability and availability to generate elecTrical power. This

t.., results in a change to the number ofhours ofaIUlual opel1ltion, not nece.'<SlIlily a change in net

eledrical output (MW) capacity ofthe EGU.

3.4.2.1 ENERGY IMPACTS OF SOFA TECHNOLOGY

There should not be a major impact on energy consumption resulting .from the operation of the advanced

variation ofa separllle<l ovedirc air system. SOFA does not signifiCllUtly change the total amount oEair

introduced into the boiler, only the location where il is introduced. Damper resistance and supply

pressure Impacls ofthe SOFA system on fan power consumption should be insignificant. The arnOlUlt of

ilyash cmitted from the boiler is expected to be reduced (less than five percent) from the baseline level

SqllMC BUllo Elcrmo CO<lp<:rative ~.~ I Bums & McDonodl
BACT Aualysis for MRY Slal;on Urul2 NOx Emi..ions NOx BACT Analysis Study

when Ihe SOFA sySlcm is in full operation. Slightly higher levels ofunbllmcd curbon in ~,e f1yash may

oocUr with lhe operation ofa SOFA system. This could have a small negative impact on the plant heat

rate (higher BtuIkw-hr). These changes are expected 10 be wilhin thc typioal runge of Gurrent operalion.

Th~.c is a pOlential reduction in re]i~bility and availabilily ofa lignite-fired cyclone b<Jiler 10 generate

sleam lor produotion of e1cotrioal pmver as a result of insl~lling and opcr"ling a separuted overfuc air

system. Typical SOFA opera lion on bituminous or we..,lern subbituminous coal-fired cyclone hoilers

docs not carry a signifioant additional riSK ofcausing imufficicrlt or excessive accumulalion ofslag

wilhin the cyclone barrels or furnace boHom compared with non air-staged combustion. Reliable boiler

operation depends On avoiding suoh adverse conditions in (he cyclones and lower furnaoe, whieh oould -'.

require a forced oulage to remove lhe .olidified slag prior 10 returning the boiler 10 genernlion produclion

service.

The challenges ofmain!nining adequate slag layer developmenl nnd now while firing lignite in MRY

Unit 2's cyclones under excess air oondilions have been significanl dUling the operating histOly ofthe

powe'l'lant. Minimizing forccd outages resultmg from cyclrme slag issues havc largely been .uccessful

lhrough op~·mtional practices that do not affeot d~Y"lo--day boill' reliability and availobility. Due 10 the

""riability of combustion characleristics oflignite supplied from the Center mine, and the dependency of

the slog now Oll the lemperaturc "filhin the cyclone barrels or furnace bOllom, ~ondilionslllay O"Cur

dming ASOFA opcrntion that exceed the ability 10 adjust opelllLional practioes sufficienl1y to avoid foreed

outages to remove lhe solidified slag.

The polcnli~l impuel On annual unil operating lime doc to cyclone slag issues associated \Vith nir-staged

cydoneslASOFA system operalion W"S estimated to be approximately 2% reduction from lhe assumed

pre_control baseline avallabilily, i,e. 0.94-0.02=0.92_ The eSlimated electrical b'ellCration produclion lost

dm: to the reduction in IvlRY Unit 2's annual availubilily is shown in Table 3-16.

3.4.2.2 ENERGY IMPACTS OF SNCR TECHNOLOGY

Fur SNCR, (he injection ofa diluted urea solution will require some addilional mn:ilial}'powerfor

heating and pumping the liquid and using compres.o;ed air for atomizalion and cooling lhe reagenl

injection nOZ7.1esflances, on lhe order oflOO to 300 kW. The injection of waler (used for urea dilution)

inlO lhc boiler nuc go' also will have a small negative impact on the plant heat rale (high~. BtuIkw_hr),

although the vandor ofSNCR "J'Slems advises thallhc heat released from the oxid.tion ofa portion of the

Bul'Jls & McDonnell 3_32 Squaro Bu~e Electrio Cnnpemlve
NO~ BACT Analysis Study BACT Analysis for MRY Slallon Unitl NOx Emissions

,-- ,

,

,

,

1

, ,

,

injecled urea compensates for lhis impuct. The impact ofadditional flue gas oreated by operation ofan

SNCR-related system On fan poweroonsumption should be small.

There is a potential redUClion in reliability and availability of a lignite-fired cyclone boiler to generale

steam for production of electrical power as a result ofinstnlJing and operating a SNCR-rclalcd system.

Typical SNCR operation with low anunonia slip when firing low-sulfurwestem subbiturninollS coal in

cyclone-fired boilers does nol cnrry a significant addilional risk ofcausing excessive fouling of the

tubular air prehealer oompared with non-SNCR opemtion. Reliable boiler operation depends on avoiding

adverse fouJing condillons in the air preheater, whioh could require a forced oubge to remove the ash

deposits prior to return.ing the boiler to generation production service.

The challenges of maintaining open passages througb the airprehentc:r tubes while (Iring lignile in MRY

Unill's cyclones unlJer typical conditions have been minor during the operating history of the_

powerplant. Minimizing fore;ed outages resulting from ash deposiLs within the air preheatcr have largely

been successfullhrough operalional praotices that do not affect day-to-day boiler reliability and

availability. Due to the variability offouling characteriSlics oFlignite supplied from the Center mine, and

,_the dependency ofthe Conling within the air prehealCTon sodium, sulfur, nnd ammonia slip emission

,_levels,' conditions may occur during SNCR operation that exceed the ability to adjust opel1lHcnai practices

_sufficiently 10 avoid foroed oUlages lo remove !he air preheater deposits_

The-p~ienHal impact On annual noit cperating time due to air preheater fouling and o!her polential issucs

associated withSNCRsyslcm op=tion was estimated to be an incrcmenlall% rcdudion from the

assumed pre--oonlTol baseline or ASOFA availability_ The estimated elecll:ioal generation production lost

due 10 lhe reduction in MRY Unil2's annual aV3ilability is shown in Table 3-16.

Square Bune Electric Cooperntive J-JJ Burm & McDonoO]l
BACT ALlLlly"i, (or MltY St,,,ion ULlil " NOx ELlli5S10Ll3

Revised 10/1712006

NO~ [lAC I' ,\ual,.,", SLLtdy

TABLE 3-15 - Expected Auxiliary Electrical Power Impacts

for NOx Controls - MRY Station Unit 2

pr 0 pg

(l) - The APC NO~ eq"ipmCllI gross ,u,moLy do"'i""l p"wer do""nd o[,!LemaLi"e.< j, II" "'''' n[indi,i<lll,1 Icdmologic,

""",bi""l by ,imple ,ddiLion AcLual row", demdml, ""'y diff<r [rom Lhl, du, (0 ~",ilivo ur neg.,liv< ,ynergi,nc ,!fuel<_

(JJ - Th" "n",,"1 chong< in APC "Ux equipm"nL "uxili,TY o,,"<lrioal powo, "emat.! oh'nmLy ""ge '" kW-hrslyr [or Iho,"

"l"'maLi,'o,,, Inc neL po",,, demand mulupli." by Ihe ",ILmated OI\Ill"( o!,ornLh,s Lim, ""I running pl,nl e,p,eity loeLor

wbien "'~cc" <he adjll!ll\lenL [Dr any "pc<",,1 rcli,bilLty ,nd ,",p,eily ill'p>cL, f'om lhe lmplcmcnullion of the o<Inl<ol

',chnLq"o, A n<g"iv, rc'l!ucLio", il\ g,n"""Lm i, an incro",e ;n ,nn"al ,,'w de,"io,1 po"or ,,,,ilablo for ,01,. '

E,Umale~ AnnuLlI AYcrn~c '\Ilxiliary

EI.ct,·ical rowor Domond and C"n.<lImplion

0(1'10. Cnnlrol E ., mcnt

Geo_"

Alt_ D,mund(!1 rower U"a<(l)

Lnb.I(I) NOx Con(rol TechniQLle 'W kW-hrs/;'r

, SNCR wi ASOFA 133 I,OOR,774

A Adyanced SOFA (AS01'A) , 7,(,(>'1

'" AILem'li,'" "uml:>cr h", beo" oviornly ,doned fn,," ic.,t «mnl',1 Lo h;.he." ""'<lVill "'",nt, '<,

TABLE 3-16 - Expected Electrical Power Generation Availability and CapaciLy

Impacts for NO;.: Controls - MRY Station Unit 2

( ) n"mo" _ g [",m I""" ",mm..1Lo 0 ( ,I p<ITcnlage.

(2) ~,""Ii", ''''d;ldbility i, ",ume<! " 9J 9I"""nl The," v,I"e:; "'~CCL '_I,i",a"~ ""'ollnl> uf neg<LL"-< rciinDiILty lLU~"L

e'p,<I,'I! [rom Lho imp('''''"L,li,," ,,[Ih< individual NO, ,0nLrul '""hn;~uc,

(J) _ Annwllu" np"rnL1J\g L;m, ,,-,<"ILi,g fcum Ihe impkmen"Lioll OrLllo i,,~i,iu",,1 NO, eon'rol Lochnlquc i, Ihe dln;,c<o,"

b<I\;c<o the b,,,lio' and expc<I..1onn,,,1 olll,ge Om".

(4) _ 0"",1>,< ","ning ~lal\L C.l"'dly fa""c i, ,,,"umed ,I 95,1 perceill. Tho"" v,I""" ",~oe< csLim"cd atUOU"" o'-"'g:lli.e

",Ii"bili<y Lmpa" ,,-,p,,',,1 r",,,, <he imple",ou"Lion o[ Lh, io~lviclual NQ. ccnlrollCcluuquo_

(5) _ An""ol dC<lricil}' geoe,",i"" t."h"Lio" i, "nnu,1 ,,-"dUCIJO" uf 01"'ruLin~ lime mLLI(lph,d by LIl, .0"",1 ",,,,,i"g ~I,m(

e,p'city faeLM ,o>lliling [rom the imploll\o"",jo" orlho i"Ji"d",,1 NO, eonLrollod"'iq"" H",IL;pli,J by <ho MCR e'p,my

"'Ling of ~bl Mil' IMCR gro>s lIniL ek<:LfJe,1 OU'pUL c"~,cily)_

Estimalod £,Ullla(,~ E,timal<d

Annllal A"nll~1 ,\nJlllal

A,'o;"go AV<l-a~. Avorogo

£s(in"llC~ Oporal[n~ RLilinillg Elodridt)-

Ann"al Ti,ne Pl,llt (:cooratioll

Alt, ""'mge ll.oducljoll, Cap.city ll.edll"inn

L"bel(L) NOx Cnnlrol Tecnni, no rI ",il,bililyL!) h,-,I>r(" FLlctort<J kW-brslvr<~

, SNCR, wi ASOFA O_90~ '" (J_9'; I liO,176,095

A Advallce<J SOFA (ASOFA) 0,919 '" O,95l 75,859,855

, ,11"''"''-''0 h"" be," ""';ou-<lv",,i 'ood .. hiollN rem ,n

8ums & Md.l"LlIldl H-I Sqllar< Hulle ~k'Clr;c CuupcTOll\'c
NOx B",CT Anoly,i, Study

Rcvi;cd 10}[712006

BACT ,\nalysi, for MRY SIano" Doil 2 NOx Emissioos

TABLE 3-17 - Expected Total Electrical Power Generation Impal:ts for

NOx Controls • MRY Station Unit 2

(I) A[rem,L, 0 numb,r ba, boca prevlOu,ly a"\gn,d from 1.0>1 removal to hLghesl removal pe""ntaso.

(2) _ The ,""utll ,hang, io APC No,; cquipmcnl ,uxi[i,ry cleolrioa[ powc, dem,nd olec<rlcity usoBo in kW_hrsiy, [0' tho",

,I"",allvo, ;, 'h, ncl POW" dc,,",nd mU[I;p[ied by Ib, c.s!im,tcd "onu,1 opcmlirlg Limo ,nd ruJ,"lng pl,nl cop,clty [""Lo,

,vhkh ",ne,," lhc ,dju,"",nl [0' nny ""pe'led re[iaiJility nnd ""p"eiiy impaots [rom tho imp[e"",nlallon Dflhe conLrol

l<Chnlquo. A nogalivc reduolion in ge,",,,,lio" is ,n ino","", in ""nnal now el",rioo[ pOlver ovailah[e Ib, ,,[e.

P) - 1\nnnal ,lc,lrioiiy generanon reduction is ,no",1 rcducri"u of operaLing ,ime mulLiplied hy ,ho ""ou,1 fUllnin'g p[anL

'"l"'Oily f",hJr ",,"['iog from <h. ;rn~[emooloLio" of,he i"di,idnal NOx rontrol techniqu" mulli~llod by the MeR copadty

"Ling of 462 MW (MCR gross u"iL .[ecLric,1 <>UtpUL cafl'lcily).

(4) _ Annu.l ,h,ngo i" "cl.[o,lrica[ power g,nc,,",ion .v,lbh[, forsolo is ",I<hm..i, oum of annu:>J pow« seno,,"lon «JuClion

~no I" • ch,ng, in Ihc "mili,ry cl"lricol power c"ruomcd p[u, <he ,"nUllI g,nemLion reduction 11"0L" a doc",,," In an"",[

opOl"'i,g 'im ,nd ,vc"'go ,nnnal mnning p[anL ,apodty f"CLO, re,u[,lng lrom the Iml,lernoo",li"" ortho i"~i";~nol NO'

'onlro[ I,ohniqu', ooml"'red w[<h boselin"

I'stimaled

Anoual Avera~. Est. Annnal

I'leelridty Change in

PGwor Geo'rotiun Net I'Ieelrlc.l Po.. er

AU. Us"!!e!!) Reduction'" Generation Availab[e ro<

Lab.l'll NO, CGmrol Tocho[ "' k.W_hr'" r kW_hrsh< So[.'" kW-hrsl r

, SNCR w! ASOFA [.00~,774 [ 10,176,095 [11,[84.869

A Advanced SOFA (ASOFA) 7,664 75,359.855 75,R67,520

" .

3.4.3 ENVIRONMENTAL IMPACTS OF NOx CONTROLS - MRY STATION

Nitrogen oxides reaci wilh oxygclI ill th~ almosphc,,", 10 produec demen~11 nitrogen and ozone (OJ). This

is on.e_\If the common CallSeS ofvisible pollu[icLl in the atmosphcrc ,ercrrcd 10 as "smog;". Opcro!ion of

thc -:arions NOx cOn[m!lechnologies cO.ll5idered for potenti"! application "t Ihe Milton R. Young Station

impose direct and indircet impacts 00 [he environment. The most pronounced direot environmen["l

impact e"pee[e<! from operalion of any oflhc NO, conlrO! option~ considered is the reduction ofozone

and improvement in atmospheric visibility (i.e. reduced visibility imrairmcnt) downwind oftbc f~dlity.

3.4.3,1 ENVIRONMENTAL IMPACTS OF SOFA TECHNOLOGY

The operaliOLl of" ~ep"rntcd overfire nir system is e"peoled to sligh[ly increase oa,bo" monoxid~

concentrations in lh~ slnck fluo !idS. The ;ldvanee<i fonn ofSOFA alternative is expected [0 sligluly lowcr

[he "mount of particuln[o mallcr omitled frum tho boil<:r ond may rai"" [he amount ofunburned carbon in

Ihe El.ynsh colleeted for I"nd disposal ond emilted (0 the atmo<phcr~ by snloli ineremen[s. AiLcrnntives

involving fonns ofga, rebum should ~xpcrience lower palticulate emi,.,ions, .nd ;1 reduetiun in [he

umount of boiler bottom aod (lyash rc4uiring: disposal.

Sq""", lIullo Elcclric Cooperative J-J5 Bum, & McDoollell
BACT Aual}"I,' fur MRY Stalion Unill NOx Emi«iOlL' NO_, BACT Analysis Study

The enviTonmental impacl from potential redllction ofannual unit op~TIlling time by approximalely two

percent due Lo cyclone slag issues associaled with air-staged cyclones!ASOpA system operalion will be to

reducc thc annual amount (tons) of nitrogen oxides emilted, and tllerefor~ lhe annual number ofNOx tons

removed will increa,e, by approximately two percenl.

3.4.3.2 ENVIRONMENTAL IMPACTS OF SNCR TECHNOLOGY

Operation of a oonventional SNCR syslem is nol expected 10 .,ign i[ieantly impact emissions of CO or

volatile organic compounds (VOCs).

Operalion of an SNCRsystem will normally creale a small amounl ofunreaoled nrea Or ammonia to be

~mitted. The amount ofarnrnonla slip produced by SNCR depends on the amOUnt ofreagenl ulilizalion

and localion ofthe injeclion points_ Higher SNCR NOx reduclion rerforrn.nce involves grealer umonnts

ofreagenl usage und arrunonia slip. This i, typically wntrollell (0 less than 10 ppmvd, especially whcn

the possible fonnalion of ~ulfalcs such as ammoni\lm s,llfate [(NH,),SO,j and ammonium bisulfale

[NIl,USO,] w,lI be more problematic at highe, slip levels. Sul[ur trioxide (SO,) formed during

cumbu;tion in the boilcr can combine with ammonia during pa8~agc through Lhe flue gas dUClwork to

form the sulfates.

Some of the unreae1.<:d ammonia from SNCR op~"Talion wm he onllCClcd with the !1yash in the

e1ectroslaIie precipitator_Any rcnmining anuuonia slip lhat is not collecled Or condensed in the air

pollulion control syslem will be ~"UIitted from the srack as an aerosol or condensable particulale. This ha~

the polenlial to iner.:a.>:c "tmosph~ric visibility impairment downwind of the fucility compared with a

pris~n~ oondition. Allhough thc predicted amount ofsuch potential impact !Tom ammonia slip emission.

has not bcen d~termincd, it is expected to b~ small in comparison wil1l1hc significant anlicipated

reduelion in far-ficlll ozone and improvem~-ntin atmospheric visibilil y as a result of lhe overall NOx

emission reduc~oLl.

Delivery of the urea reagent 10 lhc powerplant facility Jnd slorage ofaqueous urea r~agent on-site creates

the potential for uCGiden15, leaks, ~nd subsequent relea:;es 10 3ir, ground. and surface waler irrunedia1.<:ly

surrounding the facility. Urea is muehless volalile th.n anhydrous or aqucous ammonia, and these risks

are expected 10 be manageable. Emergcncy pl=ing and communily communicalions urc part of the

management plan rcquirements for such reagent llsage.

'.,

[1= & McDonnell J-36 SqLlllre Bulle Blccl,;c Cooperative
NOx BI\cr Analysis Study BAcr An<tlysis forMRY Sl:l~on Unit2 NOx Emi..ions

3.4.4

The environmenlal impact from potential reduction ofannual unit operating lime by approximately one

percent due La air preheater fouling issues associated with SNCR system operation will be 10 reduce the

annual amount (tons) ofnitrogen oxides emitted, and therefore the annual number ofNOx tons climinutccl

relative to the constant pre-control emission baseline will increasc by approximately one percent.

SUMMARY OF ECONOMIC, ENERGY AND ENVIRONMENTAL IMPACTS

OF MRY STATJON NOx CONTROLS

The economic, energy, and environmental impacts ofeach feasible BACT alternative evaluated forfhis

study is summarized in this Section_ Table 3-18 summarizes the various impacts discussed in Sections

3.4.1 through 3.4.3. The economic analysis examined the capital costofeuch feasible BACT allcmative

evaluated and any otherpowerplant upgrade costs necessary to implement the alternativc. Tn addition, the

economic analysis examined the operating and lIIllinl.enance cost associated with the highest-performing

forms of each feasible BACT allernative evaluated. These costs were then combined into the levelized

tolal annual cost for a comparative assessment of the toml implementation cost ofeach alternative_

----!<'mally, as pari oTThetop-down analysis,adOm.nant controls cost curve was ploUcd-ancnlie unifcoiitrol---- --- ---

cost fOr each alternative was evaluated. Two alternatives were on the dominant controls cost curve and

thus were identified as the more cost effective alternatives. The two BACT NOx control alternatives

evaluated for incremental cost, energy, and environmental impacts applicable (0 Milton R. Young Station

Vnid were:

• Selectivc Non-Catalytic Reduction (SNCR) combined with a special form ofseparated overlire

air (SOFA) specifically for lignite-fired cyclone boilers (:referred to as Advanced SOFA or

ASOFA); and

• ASOFAalone.

Squaro Butte Electric Coopel<l~ve 3-37 Burm & McDonnell

BAcr Analysis [or MRY Sl:llion Um, 2 NOx.Emission< NOx.BAcr Analysis Study

3.5 BACT RECOMMENDATIONS AND CONTROL LEVELS - MRY

STATION UNIT 2

This report pres.nts thc analysis ofcontroltoclmologies for nitrogen oxides (NOil for Minnkota

Power Cooperative's (MPC's) Millon R. Young Station UnH 2 using lhe EPA's '~op·doWJl" BACT

approach. BACf is an emissions limitation roreach pollulant from a source determined to be

achievable using conlrol tecb.nologies(s) lhal provide the '·maximum degrce ofemission

reduclion .,laking into account energy, environmental, and economic impacts"'". A BACT review

does nOlresull in a percent removal efficiency requirement. The generally accepled procedures for

performing a BACT analysis are outlined in Ihe EPA's draft NSRManuaL The BACf analysis for

Millon R. Young Station NO" emissions was performed in accordance with this procedure. The

EPA's dr.:lft NSRM.nua] oullines five bJsic steps that are to be followed in the "top-<lown" HACr

evaluation. These steps were as follows:

Step I -Identify All Control Tcclmologies

Step 2 -Eliminate Technically Infeasible Options

Step 3 - Rank Remaining Control Teclmologies by Control Effectiveness

Slep 4 - Evaluate Most Effective Controls and Document Rcsulls

Step 5 - Select BACT

The final result ofthis analysis is a recommendation of the BACT alternative and the associated

NOx emissiOIlrate for Square Bulle Eleclric Cooperative's Milton R. Young Station Unil2. The

emission limitationa for a generation fucility = expressed in a pounds per million British ThennJl

UnHs (lblnunBtu) basis.

3.5.1 UNIT 2 NOx BACT

In Slep one of the teclmolog)' evaluation, three basic catcgories ofNOx controls for EGUs wereidenlified; prc-combustion, combustion, and posl--combustion. Eleven basic types ofNOx control

processes were identified wi'bin tbese three categories. Twenty four variations of lhc"Sc cleven

processes were reviewed for aV<lilability and applicability to cyclone-fired EGUs burning North

Dakola lignite. An ··advanced" form of Separated Overfire Air, alone and in various combinations

with Lignite Reburn, Selective Non-Cmalylic Reduction (SNCR), Conventional Gas Reburn and

.,

, Ibid, NSR Manual B.l

Bum' & McDonneli 3-39 Sq=Bulle Electric Cooperative
NOx BACT Anaty.,is Study BACT Analysis for '"illY Sllltion Unit 2 NOx Euri.<sions

fuel Leun Gus ReburnThr. wus "valuated for cost-effectiveness. The cost-effectivenes.., analysis

indicated lhul ASOFA alone, und ASOFA with SNCR were costeffeelive "llematives for MRY

Stalion Unit 2 NOx control.. The energy and environmental impacts analysis for MRY Station Unit

2's cost-eiTcc!ive NOx conlrol oJ(cm3lives were genemlly insignificant..

Based wpon the definition ofBACf und the results of the BACT analysis, Scleclive Non-Catalytic

Reduction lSNCR) in combination wiIh a speci·.l form ofseparalcd overflre air (SOFA) specifically

for lignilc-fircd cyclone boilers (referred to as Advanced SOFA or ASOFA) i" recommended as the

Bcs! Available Conlrol Tcchnology for nitrogen oxides emissions from Square Butte meclric

Cooperative's Milton R. Young Staliou Unit 2. The unit BACT NOx emissions rule for .M.RYS

Unil2 i" 0.330 Ih/mmBlu, determined as a rolling 12-month averagc. Thi" is shown in Tabk 3-]9.

TABLE 3-19 - NOx Emission Control Technology and Rate Recommended as

BACT for Milton R. Young Slation Unit 2

Control Technolor:rv and Emission Rate Recommended as BACT

12-Month Rolling Average

Unit Pollutant BACT Control Method BACT NOli Emis~~on Rate

(lbfmmBtu

Selective Non-Catalytio

2 NO, Rcduclion with Advanced 0.J30

Separated Ovcrfrre Air (ASOFA)

3.5.2 EMiSSION RATE LIMITATION RECOMMENDATION

To complete the BACT detenmnation process, the Consenl Decree (CD) reqwircs that "specific

control lechnologies to be installe~ and a specific Phase II ~O-day Rolling Average NOx Emission

Rate limitulion (lbsIMMBtu)"Jl (pounds per million Btu) must be e.slablirned for each subjcct

emission Unit.. TIle CD also siates that "a "3D-day Rolling Average Emission RatO" "hall be

determined by calculating an arithmetic average ofall hourly emis.sion rates in Ibs/MMBtu for the

~urrenl Operating Day an~ thc previous 29 Op=ting Days. A new ~I)..day Rolling Average

Emission Rale shall be calcwluted [or each new Opera ling Day. Each 3D-day Rolling Averag;~

Emission Rate shall include startup, shutdown. and Malfunction periods wiIhin euch Operating

Day',]'.

}] Ibid footnote number I, Paragraph 66. p.ge 20.

" Ibid footnole number I, Paragraph 5, page 4.

Square Autte Electric COOP"",tivo Bums & MoDoonell
BACI' An.lysis [orMRY S\.alion Unil2 NOx Emissions NOx BACT An.lysis Smdy

•

The Consent Decree also states lhat the North Dakota Department ofHeallll's (NDDH) No"

''BACT Delermination shall address specific emission limitalions during Unit startups"" al Milton

R_ Young Sla~on_ The type and durntion offuing during startnps, and the limited ability of

available and fe.sible technologies to control startnp NOx emissions, bolh significantly influence

Ihe 30-d.yrolling overage BACTNOx emissionr.le limit recommended forMillon R. Young

Stalion boilers_ A 24-hour rolling average NOx emission rale limit applied to startllp pcriods is also

recommended [or Milton R. Young Station boilers.

The Consenl Decree and the EPA's NSR Mauual donoldcscribc the method fordetennining a 30-

day Romng Average NOx Emission Rate permit Iimitalion (CD Ph..,e II) lhatrefleels BACT

applied to Millon R_ Young Slalion Unit 2_

In keeping with the establishmenl ofa speoific CD Phase II 30-day Rolling Average NOx Emission

Rate limitation, a relevant preeontrol baseline level ofemissions and its basis mllst be determined.

.-,,:The EPA's NSR Manual states:

'The baseline emissiollsratc rcprescnlS a realistic sccuario of upper boundary

uncontrolled emissions from the sour<:c. The NSPSJNESHAP requirements or the

applicalion ofcontrols, including other controls neoessary 10 comply wilh Slate or 10001

air pollution regulations, are nat considered in calaulating the baseline emissions. In

other words, baseline emissions are essentially uncontrolled emissions, calculated using

reaJis~c upper boundary operating a~smuptions"J4.

Also slaled in the EPA's NSRManUllJ:

''Estimating realistic upper bound case scenario does not mean that the source operates

in an absolute worst-case mannCI all the time. For examplc, in developing a realistic

upper boundary case, baseline emissions calculations can also consider inherent

physical or operational constrnints on the source. Such constrainls should accuralely

reflect Ihe true upper boundary of Ihe source's .bility to physically operate and lhe

applicunl should submil documenlalion 10 verilY these constraints"".

"Ibid r""toole numbor I, Paragrapb 66, page 20_

" Ibid foolnole uumbor 2, NSR M3rnJIl1 pago B.37

"Ibid foelnole numbor 2, NSR MlUIual pago 8.37.

BllTIIS & McDonneU Square BUlle me<tric Cooperalive
NOx BACf Analysis Silldy BACT Analysis for MRY Slation Unil2 NOx Emissions

The 13ACT Analysis was conduded based upon the highcsl histOlical 12-monlh rolling NOx

emission summalion opcraling condilions for Milton R.. YOUllg- Sl.liun Imikr" during years 2001-

2005. However, n bnsdine relle<:ting a realistic upper bound case scenario based upon the highest

hislorical 3D-day rolling NOx emission opera ling conditions during years 2001-2005 was

cSl.blished prior 10 recommending enforceable permit condi~ons for BACT I" be applied 10 each

Millon R_ Young Slalion boiler.

The approach taken in Ihis an~lysis was to idmtify pre-mntrol 30_day baseline operoting conditions

from lhe 3D-consecutive day period with lhe highesl historic unil NOx mass emissions (pounds)

n..-ported for actual operation hetween January I, 2001 and Deoember 3l, 2005_ TIllS reflects unil

NOx emission, lh"t were b'CIlernkd during periods ofhigh ullit opera lions, nol "ffcclcd by unit

shuldowna, s~,rtups, or malfullctions_ MRYS Unit 2's high~,l reported 3D-day rolling avernge NOx

unil emission rate during year, 2001-2005 was 0.874 Ib/mmBtu forilie period ending Apnl5, 2002.

The corresponding MRYS Unit 2 30-day average hourlyNOx mass emission mtc was 3,726Ibfhr.

Thc aV~"Tage unit heat input rate torMRYS Unil2 was 4,264 rrunHtu!hr, and the average gross unit

electrical power oulput wns 450.2 MW, for the same JO-<lay period.

The opera~ng condi~on,during lhe highcst hislorical 3D-day roning NOx emission for yc.rs 2001-

2005 were lhen compared (0 lhe highest l2-monlh hiSlorie pre-conlrol baseline conditions. The

aV~TJgc unit NOx emission rate (lbfmmBtu) from the highest historic pre--control 3D_day baseline

period was compared wim lhe avcr~gc NO" emission rale (lb1mmBlIl) from the 12--consccutivc

month period wilh the highest hisloric unit NOx mass emissions (pounds) reported for actual

operation during the same 5-year look-back period. An eslim.tc ofNOx emission reduction for lhe

proposed BACT NOx allemalive opernting al thc histuric pre--col1trol JO_day bnseline average NOx

emission rnte (lblmmBtu) was made. This rale considered recognized operntional faelors al1d

equipmenl designs nppliod to "sleady stale" condition, wilh sust.med outpul close to maximum

conlinuous capacity ralings.. The polonlial impact ofstartups, recognizing operolionul amlleclmical

limitations on NOx emission control performance, was lhen applied 10 the steady-slate rate, 10

eSlabliah a rcc"nunended 30-day RoJling Average NOx Emission Rate permit limitati"n (CD Phase

U) lhat reflccts BACf for Milton R. Young Slation Unil2. This is explained below_

NOx emissions for cyclone-fired boilers are typically higher in poundspcrmillion BTUs during

start up event, than during slc;uly"slate operntion at maximwn eonlinuous rating (MeR) conditions.

Thi~ is bee.usc hourly heal and combustion air inpul rulea reqnired to eslablish adequate molten

.".

SqUllTC Butte Electrie CAopemtive 3-42 Burn' & McDonnell
BACf An.ly,is fo,-MRYSlalioD Unit 2 NOxEIni..ions NOx BACf An.lysis Srudy

slag [ormation wiLhin the cydone barrels and promote slag tapping lire typically produced from

firing conditions tha( create high flame temperatures. NOx emissions lire sensitive to peak furnace

gas temperatures, IhllS uncontrolled NOx emissions can be high during cydone boiler startups.

Furnaoe exit flue gas temperatures (FEGTs) during oyclone boiler startups are less than those

occurring during conditions ofsteady slate MeR firingrares due to lhe high heat absorption oflhe

boiler metal and water being raised from ambient or nf':llr-ambient temperaLurCS. Until sufficient

FEGT exists fora feasible and availablepost-combustion lcchnology, such as SNCR, to be

cITeclive, NOx emissions will be basically uncontrolled. There is a praclicallower limit ofboilcr

heat input [or conventional combusLion-based NOx emission coutrol lcchniques, SUGh as the

advanced ven.ion ofseparaled overnre air, to be operaled beyond the amounlrcquired for (;{Joling

the SOFA injeotion nozzles when it can be diverted from lhG cyclone burners and significantly

control NOx emissions. These limitalions ofthe effectiveness ofBACf controls on Millon R.

Young Slalion boilers during slartups and other reduoed-load operating periods influenc:e the

reoommended 24-hour aud 30-dayrolJing average NOx emission rate limits.

'OSlartup prooednres for sleam elcetric generating units (SEGUs) oomprising a fossil fuel-fired boiler

and steam lurbinc-g.:neralor are specified by lhe original equipmenl nmnufncLurers to follow

guidelines for heaL and pressure inoreases Lo provide protection ofloiler and turbine equipment.

-- Inj~al slart up duration after lin oUblge may be dictlted by the n""d 10 gradually warm up burner

por1lcyelone refractory malerials, steam drum shell, sLeam headers. amI other boiler metal surfaoes

exposed dirceLly or indirecLly Lo furnace g;lSCS, and !he sleam turbine's multiple casings and rotor

shafts. This is uormally accomplished with easy-lo-ignite fossil fuel firing (such as natuml gas,

distillate fuel oil, or propaue) of the boiler combined with coal 10 gmduaJly increase .firing until

reoommended boiler steam outlellemperature and pressure arereaohed, This is followed by

supplying Lhe steam turbine with wflioicnt inletslearn flow to reneh condilions lhat allow the

coupled generator to be synchronized ami electricity to be generated above zero megawatts. From

this point, boiler fuel fIriug is increased within prescribed roles until the desired operaling load is

achieved,

The SEGU startup operatillg period is usually lIot defined in emission permits. Startup is lhe period

beginning with initiation of LUel ignition, amI cantinui~g unLil the powerplaul equipment has

r.achcd operaling conditions Lbal include continuous fuel firing und sustained operating sleom

pressure and temperalure levels withill the guidelines o[ the designs for the boiler and turbine and

lheir auxiliary sysLems for miuimum sustainable levels wilhOUt causing damage 10 the equipment

Burns & McDonnell SquaTe BUlle Elecrrie Coopern~ve
NOxBAcr Analysis Sn1dy BACT Anolys,s fuTMRY S!nllon Uuil2 NUx Emissions

A recent SEGU pwposcJ PSD permit has induded u definition ofstartup a5 '~he period beginning

with ignilion and lasLing until Lhc equipment has reached a continuolL" operating level and operating

permit limits"". Similorly, a shutdoWllis defiued os '1he period beginning with the lowering of

equipment fTom base load and lasting until fuel is no longer added to the boiler and oombllstion hus

oea.,ed,,17. Bas~d on lhe reterenced defmitions ofa startup period and a "huldown period, lhe

amount of lime required for a SEGU's load (boiler steam output or generalor electrical output) to

increase beyond such minimum ,uslainablc opcmLmg levels ca'i be considered pilrt ofslaltup ~vents

iflhc SEGU is typicallybase-lo.ded al full load orMCR OlltpUt. This is the case with bolh MRY

Slation SEGUs.

Startups ofl'lEGUs m"y be labeled as cold, wann, and hot to accounl for lhe amount ofresidual

lleat remaining in the boiler and steam Lurbine equipment. The vurious typC" ofstarts are depemlenl

upon !he amounl of time 'he SEGUh.s been out-of-servicc (i.~. wilhoutboiler fuel ~ring Or

~enerator megaw"lL output). Cold "tarts have been dcfiued as start, after thc boiler has been

withoul fuel firing formore lhan 72 hours, warm slarts are more lhan 8 hours and less than 72

hour", and hot starts arc Icss Lhun 8 hours"_

Allhough the definition ofa s~rtllp event and the corresponding "tartup period is nOl rC'JuiTed by

the Consent Decree, defining slart-ups is recommended. This help' 10 uddrcss!he speeifio emission

limitalions dllring Unit ,tartups al :Millon R. Young Station aud determine the Impact ofsuoh

upcmlions on 30-dayrolling av~"[age NUx emissions. For lhe purpose of this NOx BACT analysis,

a Unit startup was defmed as the period from initial fuel combusLion 10 the point in ~me when;

• lhe measured Heatlnpullo U,e boiler On a 6-hourroJling average ba"is is greater than or equal

104800 million BTIJibr for Unit 2; or

• !he amount of Lime reported for the longesL individual Unit 2 slal1up period during actual

operation between J3Iluary I, 200 laud Th,'"Cember ) I, 2005 cl~p"e", whiohever ocours first; or

• fuellirillg is disconliuued prior to satisfying ei!her previous criteria.

This sl>lTlup definition for ]VlRY SlatilHL Unit 2 accounLs for coudilions where cycloue rcfraotory

materials replaced during hailer overhauls must be oured by extended low-firing heating eyclcs,

." De,erL Rock Energy Cente!' (AZP04-01) Proprrsed PSD PenniL Conditions, page 7.

Ilmp"fwww_CJ1:Lgovfregiou09/.iTfpermitlde,ertrock/#pennitj

, lbiu, pago 7.

" Applioation [or Prevention ofSignir,eonl De1el'ioralion Penrrit ror lh. DeSe11 Rock Energy Facilily,

Docomcnl Number 09417_360_250Rl, May 2004, page 5_1.

Squ,re DUlle Electric Cooperative 3-44 Bums & McDonndl
BACT Analysis [orMRY S",lion Unit2 NOx Emissions NOx BACT Analysis Study

,-,

un il conlrols arc upgraded md musl be adjusted during low-load operation, or for boiler feedwater

quality to improve after boiler maintenance has been perfonned thaI aITecls the insides ofthe

wale"",,]] and superheated sleam tubes. II also allow~ [or a failed or interrupted start sequence

which can require considerably loss orruore lime to elapse lhan an average slartup duration.

Analysis or:MRY Stalion Unit 2 operations data from 2001 through 2005 rev""led:

• There were 62 tolal startups in the five year period;

• Minimum startup waS 14 hours for a "hoI" start following a boiler master fuel iUlerruption

(Unit "trip");

• Maximum startup with an exlended ramp-up period lllltil full load was reached was 115

hours.

Unit 2 had a start-up thaI began on O<:lober 25, 20011hallasled for 115 hours. This Startup

included initial firing in the 20'" hour of 10/25 (2000 hours being the beginuiug of lhe st>rrtup

period), aud which ended allhe end ofthe 14"'hour (i.e. at 1500 hours) on October 30, 2001, upon

reaching451 MW (gross) outpuL The criteria ofa 6-hour average heut input rate ofmOre Iban

4800 million Btu per hour was not reuched during this startup.

. There are certain boiler operating condilions thaI need to exist before the BACT NOx control

techniqucs and technologies cau be effectively opcralc<l:

1. The furnace gas tempemture in the region where a urea reagent solulion is injected for

SNCR_based NOx control must be between 1700"F and 2100"1'. This region is expected to

be in the vicinity ofthe furnace exil, which is commonly defined as cilher the horizontal

plane cxtending from thc furnace rear wall arch (''nose') to lhe front wall of the boiler, or

the vertical plaue from the nose up to lhe furnace roof, upstream of the gas inlet to the

superheater tube banks. The gas temperature (FEGT) range in this furnace region is

dependent on boiler heat input rate and cleanliness ofthe firesidcs of lhe furnace walls,

which alTects the lITnounl ofradianl energy absorbed by the wall tubes and transferred 10

the water within.

2. The numbers or active cydones and continuous coal firingmles must be enough 10

establish sufficient

a. coverage ofmollen slag on the actively-fired cyclone barrel surfaces and drainage of

the slag from the bollom o[(he boiler; and

Burns & McDonnell Square Bultc Electric Coopcrati\'e
NOxBACT Analysis SluJy BACT Analysis [or Jl,fRY Station Unil2 NOx E!ni,simL'

b. combuslion airflow through the actively_fIred cyclones 10 allow a portiou to be diverted

to lhe S~'JlaI"Jled overfire air system above !he amount required for idlc cyclone cooling

and SOFA n02:7.le cooling.

As previously discussed, fiIm~ee exit flllc gas temperature' (FEGTs) will need 10 be measurcd or

delermined empirically during operation oflhe MRY Station boikrs in order 10 be able to

~IT~cLively control NOx emissions using SNCR Lcehnology. The design and operation ofthe SNCR

systems al MRYS for CD Phase 11 emissions control should inclUde features thai accormnodate

cyclone boiler startups and low-load operalion wilh "ClcilIl" or "dirty" boiler heat transfer S"'faccs

as soon as conditions occur lh~l are lcclmically praclicable, i.e. within the SNCR syslcm vendor's .

rccolIllllended operaling guidelines, as well as fulJ.load eondilions in order to minimize NO~

eJlllSSIOns.

The amounl aud duration ofsustained boiler heat inpuL reqllired 10 e,o;lablish the operating

conditions described in item 2 above is more difficult to precisely delermlne. Lignile heal content

varinbilily and inability to accuralely detennine the actual nirlfllcl ralio on a cyclone-by-cyclone

b1lsis in real-lime, and the slagging and fouling chHmctcristics of lhe lignite ash, cause (and arC

expecled [0 conlinllc 10 c"use) difficulties with stable coLnbustion performance. The minimum

firing ralos of lhe MllY Slalion boilers required 10 suecr;>sfully iniliale lhe effective operaUon of lhe

SOFA sy.'lem are specifIc to each individual boiler, and are not eUlTentlylmoWD. D"~ 10 such

operating problem, and emission control limitations, the ability w cfI~clivdy limit NO, emissions

during startup periods and low-load operaLion following implerrumtation ofadvanced SOFA (CD

Phase I control) and/or an SNCR sysLem (CD Phasc II control) is uncertain.

Because lhOle arc expected 10 be minor short term variations in opemting condllions during startups

where Mirmkola has nol, in fac~ malerially changed any oftheir nOllllilJ startup opel'lting praclices

and criteria, a margin belwCCJI [he 30-day rolling average sleady-sLate NOx emission rale (which

docs not include the impacts ofstartups) and Lhe propo!cd 30-<iayrolling average NOx emission

pennit limit lhat includes startup cmi,sions is recolIllllended.. This rote consid~TCd r~...,ognized

operalional13ctors and equipment designs ~pplicd Lo steady state conditions with sustained oUfput

close to rna'limum continuous capacity ralings. The recOlIllllcndcd 30-d"y Rolling Avemge NOx

Emission Rale permit limitation excluding the impael o[,larlups thai refleels BACT fm Milton R.

Young SLatiou Unit 2 is sho"n in the table below.

Square Butle Electric Coopemlive Burns & McDoIlJlcli
BACT Analysis for MRY Slol100 UlIit2 NO~ Emissions NOx BACT Analy'is Slndy

1

TABLE 3·20 - Recommended NOx BACT Control Method and

3D-Day Rolling Average NO" Emission Rale Limit Without startups

JO-day Rolling Average NOx

Unit Pollutant Control Method Emission Rate Limit

Excluding startups

(Iblmillion Btu)

Selective Non-ealalytic

, N"" Reduction with Advanced 0.350

Se araled Over1rrc-Air fASOFA)

ThIs recommended BACf 30-day NOx emission rale limit is bastxlllPon a hislorio pre-control 30-

day baseline average NO" emission rale ofO_8741blmmBlu for Unit 2_ The baseline emission was

determined from the JO-consccutive day period with the highest historic unit No", emi.-sions "'Ie

reporled for actual operation belWeen Jau\llU1' 1,2001 and December 31, 2005_

ArecommendedBACf 30-day NOx emission rate limillhat includes the impact ofstartup

~')lis5Ions should be suitably higher suoh that operation oonsislent wilh lhe lechnological

limitations, manufaoturer's specificalIoru;, and good engineering and maintenance practices to the

extent praclicable for the MRY Stalion boilers would not resnlt in an excecclance (violation) ofan

enror".able JO-day rolling average NOx emission permit limit.

Eor MRYS Unit 2, lhe recommended 30-dayrolling average NOx emission permit limit rate lhat

indudes the impact ofslartups is bosed upon recognized operalional fadors and equipmenldesigns

that influence whether the startup emissions r","ult in higher 30-day emissions compared 10 normal

oontinuous operation wilhout or excluding such startup pcriods:

L The uncontrolled emission rate (i_e. wilhout sepuraled OFA or SNCR in operation) and its

variability during operation from a cold, worm, or hot startup up to and indurling=imum

cotJIinuollS rated outpu~,

2. Thc operaling conditions lhat are required lo cXisl for lhe selccted NOx BACf conlrol

teclmiqucs 10 be initialed and be ei1i:ctive; and

3_ The effectiveness ofthese two pnrticlliar control techniqucs ifinvoked at less_lhan_MCR

steady-Slale operating condllion>.

4_ The number o[startups and their range of typical durations per 30-<!ay period lime frame.

Burns & McDcnnell J·47 Square Butte Eleclric Cooperative
NOx BACT Analy<i, SLlIdy

Rev;.,od I(lIII/200l>

F1ACr A""lyo!' lul' MRY S'alion lJn" 2 NOx ~mi."io""

Th~ Oe(obe[ 25-30, 2001 stnrlup \Va.' chosen fDr addilional evaluation a.' Ih~ Slnrt.up for MRY

SI1l1ion Unit 2.

An incremental adjustment 10 the propo,ed ,10.day rolling "v~mg~ stcady-<mtc unit NOx llACT

emi,,-,ion Me without slJrtups of0.]5 lbimmlllu ror Unit2 i, recommended for th~ 30-d"y rolling

avemgc NO, emi,;""n pcnnillimit peri"Js JS defined and applieJ to Millon R. Yout\g SI"lion.

This is snmmarized in the lable bduw_

TABLE :l-21 - Recommended BACT :lO-Day Rolling Average

NOx Emission Rate Limit and Startup Impact

30-day Rolling Average NOx Impact on 3D-day Rolling

Uni t Emission Rate Limit Average NOx Emission Rate,

ExcludIng Startups Limit Due to Startups

(Ib/million Btu) (lb/million Btu)

, 0.350 IO. I02 pcr SLa'lUp

Thl> re~olTllTlended adjllstm~llt TO lhe pfOpo,cd 30.day wUing ,"vemge ,teady-mue NOx DACT

emission rate limilwithoUl slartups is based u~on overage historic pre-control NO., cmis.,iGn rotc<

ot· 0,959 Ib/mLl18Lu for Unil ! reporlcd for the longe,' lIldindual lIltil 2 sULrlup period during actual

ope"'t;on between January 1,200 I and December 31, 2005. Thes~ emi.«io".' ,"ceurn:(1 during lile

liS-hom Oclober 25-30, 2001 startup For lJ"il 2.

A 24-hour rolling average BACT NOx emi,<iun note limit applJcd to Sl;lrlLlp pe,iod, i, a[su

,",commended for each of [h~ ",Iill"" R. Y"ung St"lioll boilers. Thi.' i.' <ulIlLt""izc,,1 in the Ltl blo

below.

TABLE 3-22 - Recommended 24-Hour Rolling Average

NOx Emission Rate limit During Startups

24·hour Rolling Average NOx

Unit Emission Rate Limit

During Startups

(Iblmillhm Btu)

, 1.06'1

:3

3

,

",

Square [IUlI~ Eicclric C"0p"cJli, e Gums & !cicDolladl
BAC[ Analysis [orMRYSlation Unit2 NO" Emi""ions NO" BACT Analysis Srudy

These emissions occurred during lire li5-hour October 25-30, 2001 startup for Unit 2.

Compliance with lhese emission rotes would be measured at the slack oflhe Uni~ verified with

Conlinuous Emission Moniloring(CEM) syslems in acoordance with !he reference methods

specified in ~O Cl'.R- Part 75, and wonld be determined 00 a 30 consecutive Operaling Day and

24-consecutive hourrolling average basis, respectively.

A lrial demonslration operating period of 18 months aller lhe completion ofCoosenlDccrce Phase

II NO" emission rc<1uclion system installatiou commissioning at Milton R. YoUllg Slation is

recommended. It is proposed to allow MinnkOla (for Square Butte) to demonstrate the actual

control system oapabilities oflhe combined NO" BACT emissions reduction syslem. Op=ting

experience during the trial period will:

• confirm steady-slale conlrol pertbnnance of the combined NO" BACT emissions reduction

system;

..• allow delerminalion ofthe ability 10 further conlrol Unit start-up emissions;

• allow the determinalion ofthe permitted 30-dayrolJing av=geNo" emission limit including

startups, shutdowns, and malfunctions; and

• address the specific emission limitations during Unit startups al Milton R_ Young Station and

their impact on the proposed 30_day rolling average emission ralC limit (withoutslartups).

Based upon lhe information obtained during lhe trail period, fmal emission limits can then be

delermined.

Themeans lhat will be employed 10 minimize emissions during startup will primarily be based on

operating procedures, both before and after lhe level ofupper furnace gas temperalUICs and/or heat

input mle are considered sufficient to slm the NOx controls and operaling conditicns are conducive

for effective emissions reduction_ These could be similar to Minnkota's current MRYS practices, or

could be different., depending upon the capabilities ofthe NOx controls and lheir impacls on Unit

op=tions.

Burns & McDonnell ;~, Square Butte Electric Coopcrali,,,
NUx BACT Analysis Srudy

RererenGes;

BACT Analysis forMRY SWlion Unit 2 NOx Emissions

1. Tn the Uniled States District Court f'or The District OfNorth Dakota, Uniled States Of

Amerioa and State Of North Dukola, Plainliffs, v_ Minn!wta Power CoopCTi1tivc, Inc. and

Square Butte Electric Cooper~tjve, De[end~nl.'l, Civil Aclion No.1 :06-CV-034.

2. EPA New SourGe Review Workshop Manual, Prevenlion o[Significanl Deterioralion and

Nonattainment Area Permitting, Dran Ootober 1990 (The "NSR Manoul")_

3. EPA Docket OAR-ZOOZ-OU76-0446 Technical SupportDoelJIJl~TII [or BART NUx Limits far

Electric Generating Units Excel Spn;,,<Ishpcl 611512005, posted on lheir website: from

EDOCKE1"at

http://d''''ketepa.llov/edkpubfdoJEDKSlaffitemDetailView?objeond~090007d4B0B4S6Zb;

lhis is associated with EPA Acid Rain Prol,'Tam Clean Air Markets Division, Tcchnie~l

Support Doeum~'IlI- Melhodology For Developing BART NO, Presumptive Limits, Juoe 15,

200S,OAR-Z002-0076_0445.

4_ EPA Office of Air QUality PlaJIlling und Stundards (OAQPS) publication EPA/452iB-02-001,

Seclion 4.2, NOx COlllrols- NOxPosl-Cambustion, Chapter I - Selective Non·Cataly~e

Reduolioo, dated Oclob~"r 2000. posted al lheir weh.,ile, hltp:llwww.qm,govfttn!caloldirllcs4_

2 Gh1.pdf

Square Bulle Elcctrie ('",operative Bum., & McDOItIldl
'-'1

APPENDIX A

Technical Feasibility Assessment Details for NOx Control Technologies (A1)

U.S. Coal Cyclone NOll Reduction Projects Summary

With Retrofit NOx Control Projects' Technical literature Summary (A2)

APPENDIX Al

Technical Feasibility Assessment DeIil~s for NO" Coolfol Technologie'

NO"BACT Analysis Study

A.1

A.1.1

Technical Feasibility Assessment of NOx Control Alternatives

Pre-Combustion Fuel Treatment/Switching

Fuel switehing can be a viable melbod ofNOx emission reduclion in cerLain situations. Often, coal

combustion facililics are construcled to take maximum advantage or!he particular combustion

characleris~cs of a specific fuel. In lhe case of:MRY Station, the Unit I and 2 boilers were designed and

constructed specifically for firing North Dakola lignite, whieh has a fuel higher heating value (Blullb)

approximately 20% lower than typical Powder River Basin (pRB) coaL A cyclone-fired boiler

(Ottertail's Big Slone Unit 1) lhal is similar in geometry and steam generation design to MRY Station

Unit 2 fires PRE coal. Based on a comparison ofavailable emission data between Big Stone Unit I and

MR Young Unit 2, lhere is no expected reduction in baseline (i.e. uncontrolled) NOx emissions from

switching loPRB from lignite at Mtlton R. '{oung Station.

Conversion ofMilton R. Young Station Unit 2 boiler to fire PRE coal is technically possible. II is

expected lhat major plant modifications will be reqnired. Rail service is not presently inst<llled at this silo,

so !he addilional operational and capital cosls to bring in large quanlities ofPRB coal will be significant.

Investigalion of the specific source, distance, and costs for supplying necessnry q~anti1ies ofPRB coal via

,-ail or trocks to MR. Young stalion has not been perfonned. Wilh zero baseline NOx Cffiissions

reduclion expected from application offud switching, lhis alternative will not be economically

competitive with olherNOx controlleclmologies that offer betlerresulls fora much lower combination of

capital and operational costs. Although fuel swilching is technically fe~sible, it has not been oonsidered

furlhcr as on effective NOx emissions conlIol option for MRY Station Unit 2 boiler.

A.1.2 Combustion Controls

Combustion controls comprise lhe most numerous category ofNOx emission reduction technologies.

These !eelmiques employ methods lhat reduce!hc amount ofNOx emissiollS created in !he combustion

zone oflhe boilcrprior to exhausting the flue gases .from lhe furnace (upslIoamoflhe convective heal

transfer zones). These controls resull in fewer emissions 10 atmosphere or thaI may require subsequent

redudion from additional applicable oombustion and/or post-combusLion teohniques.

lIB !hc boilers in question were designed for firing North Dakota Jigllite fuel, they were furnished with

suitably_sized furnaces and limited back-end economizer heattrnnsfersurfaces upsLream oIlhe air

preh...ters. This provides high temperature air 10 aid the evaporation ofexcess moisture from the crushed

coal particles in !he prc-<:ombuslion drying systems, and long residence limes for solid and gaseous fuel

Square Bulle Elcctric Cooperativc Al-l Bums & McDonnell
NOx BACT Anoly,i., StlJdy APPENDIXAl

Technical F=lbilily Assossmenl Detail5 rnr NOx Contr<>l Technologies

particles to burn essentially 10 completion prior to leaving the furnaces. The laUer feature is especially

advanlageous for applying various fbrms of combustion modifiCillions which are oonducivc in reducing

NOx emissions.

A.1.2.1 Basic Combustion Improvements

Combuslion improvements are commonly-applied leohniques which may produce modesl incremental

NOx emissions reduolion•. Tn their mosl b"sic form. the.'e typically provide impl'ovemenlS 10 comhustion

air flow distribulion, meaSuK'ffienl. ""d pre""ure, logethcr with fuel now measurement aud metering, to

promole consis(cnl combu.lion perj'ormllIlce by burning fuel with more accuracy in mainlaining a desirctl

fuel/air ralio.

These improvcments may allow, or he oombined with, the prac~cc ofseveral otherNOx oontrol

teohniqucs. Separaled ovcrfirc"ir (diseussed below), wilh or without "Iow exoess oir" (LEA), hUffiC'"

uut-of--service (BOOS) and biased firing (BF) opcr"tion of lhe cyclom;s, .couse a decrease in Ih~ ratio of

combuslion "ir to fuel snpplied to the cyclones (burne,,,), lhus reducing the amoum of them,"l NOx

emi<s'tons produced during combustion. The aLlIount ofpotential NOx emission reduc~on achievable

from these basic ledmiques is highly-uop~71uent on the speeilio Lypo of liring, fuel, a~d conditio~s whieh

apply to the bOller(s) being reviewed.

Making lignile drying system ai[ adjustments md adding improvements to the bOllcr oombuslion conlrols

and reducing comhustion air inpuls have already reduccdllncontrolled NOx emissions at Milton R.

Young Station Unit 2 boilerapproxim"tely 27%. Further incremental improvements from additional

combuslion oontrols lhal allow operation with modest amounts of cyclone "irslaging, similar to the effccl

of a separated overfire air sysICm, are possible. Inoremental NOx emissions re(1uctions are expected from

such improvements being incorporaled into another feasible alternalive, suoh as separated [lverfirc aiL

This allern"tive WaS not considered as a sll1ntl-alonc option for additional NOx reduction at Millon R.

Young Stalion for the Unit2 boiler_

A.1.2.2 Low NOx Burners (LNB)

Low NOx burners (LNBs) of various designs have be~TI oommonly applioolo pulverized coal,lired utility

and industrial boilcr>: for more than ten years. However, they= nol inslalled on cyclone_fired boiler._

This lec1mology is infeasible on cyclone boikrs', and was eliminalcd from considerntion for addiliOTIal

NOx reduction at Milton R_ Young Si<ltion Unit 2', boiler.

Hurl" & McDonnell At_2
APPENDlX AI

Technical F=ib~ity Assessmen, netails for NO" Control Technologies

A.1.2.3 Separated Overfire Air (SOFA)

NO" BACT An.ly,is Study

S"l'arnted overfire air (SOFA) is ;l combustion-related NOx emission reduction technology frequentlyapplied wilh ond wilhoutlow NO" bumers to utility and industrial boilers for more lhan twenty five

years. Separnled OverfIre Air (SOFA) is an air-staging NOx emission reduclion combustion lechnique

iliat is typically based on withholding 15 to 20 peroent of lhe loW combustion air conventionally supplied

10 lhe firing zone. 'The diverted combustion air is lhen injcoled in the upper furnace, where combustion is

completed. For typical cyclone coal-fired boilers, this involves diverting approximately 20 percenl ofthe

secondary combustion air, forcing lhe cydones to operale fuel_rich. Starved..i, combustion causes fewer

NOx emissions to be produced.

At least thirty nine existing cyclone-fired boilers, fIriug eastem bituminous, midwestern bitumiuous, and

western subbiturniuous ("Powder River Basin") coals in unils ranging in size from 50 to 1150 MW, have

beenretrolilted wilh commercial SOFA since 1998. A s\llIlmary ofseveral oflhe first SOFA (and rebum)

retrofits to cydone-fired boilers is described in published lechnical papers',z. Cyclone boiler retrofit

SOFA installations are included in lhe EPA's BART technical support document' and listed later in

_,AppendixA2.

A basic form ofseparnted overfire air (SOFA) Can be applied and installed on MRY Station Units 2.

There are polential impacls and limitations unique 10 the firing ofNorth Dakota lignile iu cyclone-fired

, ' boilers lhat should be recognized as part oflhis emission reduclion lechnology applicalion.

Key aspects ofsuccessfully applying llI1d opemling a separated overfire air syslem on a cyclone-frred

boiler are the ability to'

• Aecurnle]y measure ilie fuel heal input rate (BTUs) and combustion air inputs on a real-time,

individual cyclone by cydone basis, 10 allow the ability 10 delerrnine and controllhe desired air/fuel

ratio, especially when "starved air" (i.e. swsloichiometric) combustion conditions are required.

• Maintain adequate mollen coal ash (slag) formalion and flow wilhin the barrels aud slag taps.

The degree to which the cyclone furnaces can be operated with less lhan lheoretical (substoichiometric)

combustion air directly contributes 10 less NO", fonnalion and fUrther in-furnace emission reduclion but

also risks solidification of lhe mollen coal ash. In lhe ease ofMitY Station Unit 2 boiler, cyclone

combustion must be sufficiently air-staged to reduce NO", emissions while releasing enough hea!lo

continue to melt lhe fuel ~sh so that it flows effectively wilhin and from the cyclone burners.

Sq=re Butte Electric Cooperelive Burm & McDOJlDell
NOx BACT Analy'i., Study APPENDIX Al

Technical Feasibility Assessment Dclail; for NO" Control Teclmologies

In Ihe case ofMRY Slation boilers, there is a signifioant amount oIvariability in t1,e omnbUSlible and ash

oomponents ofNorth Dakota lignite supplied from the current mine near Center, NO. Analysis ofseveral

hundred "Oal feed samples Laken simultaneou.ly from multiple cyclones ofMRY Station Unit 2's b011~T

revealed that the maximum differen~al of the lignite heating values from cyclone-to-cyclone wasjust

ovcr 12% or tho overage hcaling v~lue or all the samples. Assuming: an oper~ting ease oeeurrC<! whore

the maximum cyclone-to-cyclone differential heating value was for two cycloues at the opposile ends of

the fud hoa! eontent rango, lherc would bc n plus pr minus 6% variation in fuel heat content forcithcr of

the individual cyclones from the overall average. Ifthe desire<:! average cyclone air/fuel (stoichiometric)

ratio was 0_95 when operating with air-staged cyclones associated with separated overlire air, and the

amount ofsccomJ"ry comb uslion ~ir to eaeh eyelone was equal, lh~Te wonlcl be n s!oichiomeLrie ratio of

approximately 1_0 I in one cyclone and" stoichiometric ratio around 0.89 in another cyclone at the same

lime. The modestly uir-staged eyclon~ would produce highor than average NOx emissions. The deeply

sLagcd cyclone wonld produce les" than avcrage NO,,- ~'ITli",ions and pOloutiaJly insuffieienL amounts of

heal release, and raise the risk ofsolidifying the fuel ash so that it accumulates within the cyclone 00rre1.

This coold TCsull in firing auxili"T)' fuel 011 in Lhe decply-st~gcd eyclonc Or taking the boiler out-of-service

to remove the pluggage. Neither of these conditions is desirable becanse they result in lower emis.,ions

removal pcrforrrumce amI highcr opera ling costs. Thus, due to the variabiliry of Lho fuel heat conlent and

lhe complex behavior of lignite ash when exposed to high temperatures, the extenl of air-slaging and thus

lhe level of NOx control in MRY Slation boilers is expected lo be modesl while firing lignite coals.

Jn order 10 potenlially achieve lower NOx emissiou rates with modestly air-staged combustion forMRY

Station boilers, additional combustion improvements can be installed. One pOlential improvemenl is to

Implement a unique form ofSOl'A for North Dakota_lignile-fired cyclone boilers. This Inoludes

reloc:ated lignile drying syslem venl ports, and in Unit 2's C"se. also involves blocked or relocated lower

furnace fine gas recirculalion ports. This will be referred to as "Advanced SOFA" (ASOFA). 'There are

severnl design challenges antioipaled for implementing the advanced version (with the described port

reloWilioru;) ofseparated Ol'A. These are believed lo be solvable_

Both forms ofsepnmlC<! ovcrfire air us a combuslion-reMed NOx controllcchniqne arc eon>ridered

feasible for application to MllLon R Young StaLion eyclone builcrB. Since Lhe advancecl SOFA is the

highest-performiug form oflhis lechnology, only lhis ASOFA version ofthe alternative W"S considered

for additional NOx reduetion at Milton R. Young Stalion boiler,.

Bum, & McDonnell Square lllllte Electric Cooperative
APPENDIX Al

Technical Feasibilily As,<ssmenl Delalls for NOx Control Technologies

NO~ BACT An.lysis Srudy

Another fonn ofseparated overfire uir being marketed commercially is "Rotating Opposed Fire Air"

(ROFA). For utility applications in the United States, lhis has only been applied to pulverized coal-fired

boilers, primarily tangentially-fired lIDits<. It is different than basic SOFA in that it includes a hot air

booster fau, aud iujecls the ovemre air in an offset fashion from opposite sid"" ofthe furnace at high

velocities, with multi-pori uozzles located at high elevations relative to the top burner row. The vendor

(Moholec USA) clairru; ROFA maximizes air-staged in_furnaoe combustion NOll reduction while

minimizing-negative impacts on osmon monoxide. and llyash unhurned carbon.

While this variation ofseparamd ovcrfire air could potentially be applicable to cyclone boilers, it has not

been marketed to serve such spplic.tions. Because cyclone bcilers do uot require the addition of hot air

booster fans for SOFA, this tedmique is not distinct enough from basic SOFA from functional and airstaged qdone NOxreductiou performance standpoinls to wammtindividual consideration. ROFA

technology lacks demonstrated cyclonc-fired boiler experience, and thus was considered infeasible and

not included in the control effectiveness amI cost_effectiveness sections of the main report.

A.1.24 Oxygen_Enhanced Combustion

A supplier ofliquld oxygen (praxair) has developed a method ofreplaoing some ofthe combustion air

supplied to the burners with pure oxygen_ Combustion air, which is nonnally input through the sccond:lry

airsystem du~twork downstream of the forced draft (FD) fan and air h~ater, is supplemented withpure

ollygen directly injected into the burners. Oxygen-enhanced combustion (OEC) can reduoe boiler NOx

emissions resulting from" therm.1 NOx", a reaction ofthe nitrogen in the combustion air admitted to the

burners with the available oxygen in the air in the flame or peale temporalure regions of the fuel

rombustion process, The use of pure oxygen mst...d of air reduces the availability ofnitrogen from the

air to be oxidized in the high lCmpermure regions, thus reducing formation ofthennal NOx. This

lechnlque has only been demonstrated in a boiler with pulverized fuel burners firing bituminous coal'.

The lack ofadequate expericnce on any qclone-fired coal-burning boiler, on a lemporarydemonslnltion

or permanent full-scale basis, and for a coal-fired facility of this size, precludes consideration of oxygenenhanoed ~ombustion at:MRY Station Unit 2's boiler. This is deemed to be infeasible technology at this

locution at the present time.

Squ.re Butte Eloclric Coop=tive AI_5 Burns & McDonnell
NOx BACT An,lysis Sluuy APPENDIX A I

Technical F""sibility Assessmenl DelaHs for NO,,- Conlml Technologies

A.1.2.5 Flue Gas Recirculation

Flue gas recirculation (FOR) bas been wmmonly applied to wal-fired boilers, primarily \0 inject inlo lbe

lower fumaoe, j~t abovo lbe burners, supplied from the boiler's economizer nue gas olltlet via a hot gas

Imoster fan. Tbis modifies the amount and tempera lure ofhot furnace gas eilner in lhc lower-middle Or

upper fumace and convection heat transfer zones. As this nue gas typically haS"n oxygen conlenl around

2-5%, illimits the availability o[oxygen in a high temperature, possibly fuel-rioh lower Iltmace zone.

Flue g"S recirculation [or NOx control is mOst cO!Jlll1only applied with gaseous or liquid fos"il fucls to

reduce the high lemperatures which convert nitrogen in the combustion air to nitrogen oxides. No

examples ofusing or installing FOR On cyclone-fired hoil= striclly for NOx emissions control werc

[Olmd in available tcchnicalliteraturc.

FOR i~ .Iready pracliced ntMRY Station in lhe Unit 2 boiler, primarily forfurnncc gas lemperature lint!

lower wall slaggingreduction re.asOns. For this boiler, FOR could aid in potentially providing some small

additional NOx emissions control ifit were modifie<1.from its current confignfJtion, n~ part ofan

advunoed fonn ofsep"mlcd ovemre air. Complete elimination of the ~e ofFOR could ahm slightly

reduce NOx emis"iQJl5 fiOin Unit 2's boiler during air-slaged cyclone combustion with s(-parated overfire

air system operalioll. There is lUlcertainty whether eliminalion of the use ofFGR in the lower furnace of

:MRY Stalion'sUnil 2 boiler could be sllcoe,.,ful in conlrolling lower furnace wall fireside ash depo,ilion_

A.1.2.6 Water/Steam Injection (Combustion Tempering)

When applied 10 older gas-fired and oiI,fired ulilily .nd industriallmilers, waler and/or sleam injection

adds moislure into lhe lower furnace, COllourrent with or near (to the side or slighlly above) lhe burners,

supplied from the boiler's trealed feodwater or auxiliary Sleam syslems via a metering pump or valve_

There has be~." some limited lesling ofwater injeclion for NOx emis,o;ions conlrol on nnturnl gas-fired and

coal-tired cyclone Imilers"'. For roal-fired eydunes. lhis lechnique is most effective on hOllers burning

biluminous coal; howcver, it has not been permanently irullalled and eonlinuously opcralc<1 in such

applications. Successfullong-lcrm operatjon ofwater injection would be difficult for lignite-fired

oyclonc boil=. dne to lhe bigh moisture levels in lhe coal and lhe need to re~dily ignile and suslnin stable

combustion and molten sIng [onnation in the cyclone furnaoes. For these reasons, waler/steam injeotion

is considered leohnicnlly infeasible for NOx control applicalion al Millon R. Young Station.

..,..

Bum, &McDonndl SqurlTe Buno Eloctri cCooptTati,e
APPENDIX Al

Technical Feasibili<y Assessment Do,"ilsfor NOx Control Technologies

A.1.2.7 Fuel Reburn

NOxBACf Analysis Study

Another combustion teohnology that maybe applicable to control NOx emissions from the Milton R.

Young Stalion unil. is fuel reburn. In a similar manner thatoverfire air diverts a portion orthc

combustion air inpullo the main firing zone, the reburning process involves supplying a portion of the

fuel heat input 10 the boiler ala higher elevation in lhe furnace. This creates !Ill upper furnace atmosphere

where lhe rebum fuel's ~mbustionproducts causes some of the NO" fonned in the main bumer

combustiou zOnc u.od rebum zone to be converted,inlo moleculm-nitrogen. Depending on the amount of

reburn fuel added and lhe amount o[oxygen available in the furnace gases to combine with the reburn

fuel introduced, addilional combustion air may be supplied as supplemental or overfire air. DO"ffistream

ofthe air injection clcvulion, the intention isto complele lhe reaction ofany remaining carbon monoxide

(CO) to carbon dioxide (CO,), plus reduce the amount ofcornbuslible maUerremaining in the entrained

.flyash.

The most common forms ofreburn technology applied 10 ulility powerplant boilers arc:

• Pulverized or micronized coal reburn (PCR or MiCR); and .. ,.

• Gas reburn (GR).

Pulverized coal reburning !IIldmicronized coal rebnminghave been applied to pulverized ~a1 and

cycloue-fired boilers. No" reduclion effieienClcs of 50 to 60 peroent have been demonstrnted on castern

·bituminous coal and midwestern bituminous and Powder River Basin (pRB) western subbituminons coals

while supplying up to approxiJIDltely 20--30% of the boiler's total fuel heat input to the reburn zone'·'.

For utility powerpmnt boiler applications, naturnl gas has been utilized as reborn fuel most often,

demonstraled in two basic approache.:

• Conventional gas rebum (CGR); and

• Fuel-lean gos reborn (FLGR"").

Eilher natural gas Or pulverized coal (lignite) cm be used as the reburn fuel. A sufficient qmmtity of

natural gas is not currently available at the Millon R Young Station plant sileo Supplying enough natural

gas to provide I'> to 25% of the total heat input to either or both boilers atMRY Station is cxpeeted to bc

technically feasible, although trnnsport pipeline instanalion capit:ll costs, and current and predicted nnit

natural gas costs and opCTating economics, are likely 10 be unfavorable.

Square Bulle Eleclric Coop=tive Burns & McDonruoll
NOx BACT An.lysi, Sludy APPEND[X A[

Teclmical FeasibiUry A,sessment De[.il, for NOx COlllrol Technologies

Various forms offuel rebuming have been demonstrated and operated routinely on "Ydone boilers for

NOx emission conlrols. This has been applied [0 unil_ firing eastern bituminons coal, and western

"ubbilUminollS or PRBlbltuminous coal blends, usingpulveriz.d or mieromzed eoal or natural gas as the

most common rebum fueL Rebuming for NOx emissions reduction has notheen demorutrnted on a unit

firing high moislure, low h",,[ content North Dakota ligllite. Pulverized/micronized coal, along: with

oonventional and fuel lean gas Tcburn lcclmologies, are discwsed below_

A.1.2.7.1 Coal Reburn

In [he case ofapplying conventional coal rebum to cyclone boilers, the exis~ng eycloncs are supplied

with the majority ofthe fuel, with either natural gus Or pulverizcd coal (lignite) ll.,ed as the rebum fuel

sueh [hat the towl hent inpUI to the boiler is essentially [he same as without fucl rcbuITI_ Separnted OrA

ports are located above the rebum fuel injection section of the furnace. '1hese SOFA porls provide

sufficIent oxygen in a conven~onal fuel rehurn installalion lO complete the combustion proce"" [hat

begins in the Irnlin comb uS lion zone and is supplemen[ed in the reburn and burnoul zones. TIlis is shown

schema[ically for a pulverized coal reburn upplicalion On a cyclone_fired boiler with SOFA in Figure A_I1.

Fi~lIre A,I-I Pulvcrized Coal Rebllrn Application 011 Cyclone Boilcr Witb Overfire Airs

BURNOUT

ZONE ElECTRoSTAllC

PRECiPITATOR

,-

PREHEIITER

'"

ECONllJIRY

j AIR

LTEN SLAG

REBURN '00' ,-- 'l i

- '

OVERFIRE - ""

-.-.

COAL REBURN[N(;

BURNERS '_ "'

, "-

PULVERIZED ---~ 00" _.

,

"'

MAlN_ ____

COMBUSTION. ~,

SLAG TO

"

DISPOSAL

BmIL< & McDonnell AI-~ Squoro BUlle Eleclric COUPLTdtiVO
APPENDIXAl

Technical FeasibUiry Assessment Detail. rOT NO" COlllrol Teclmologics

NO"BACl' Analysio Study

In lhe Uniled Slates, pulverized coal reburning and micronized coal reburning techniques for utility

powerplant NOx emissioru; reduction have been applied on a very limiled full_scale, full-time basis to

cyclone-fired boilers in Geld demonstration tests and longer-term demonstration opemtion, respectively.

There have been only two known pulverized or mioronized coal rebum installations in Ihe Unlled S~lCs

on cyclone boilers, one on a utilily boiler in Wisconsin, and one On a small industrial-size cyclone boiler

in Ncw York state7~,•.1O,11.",D."_ NOx emissions n;:duction efficiencies of 57 percent have been

demonstrated on cyclone boilers firing eastern bituminous coal, or midwcstern bimminous and Powder

River Basin (pRB) weslern subbituminous coals while supplying up to approximalely 20-30% oflhc

boiler's total fuel heat input 10 lhereburn zOnC. With the exception oflhe V_So Department ofEncrgy's

(DOE) Clean Coal Technology Program demonstralion projects7.0", nO known eormnercially-available

coal rebum syslcms have been installed and are routinely operaled on cyclonc boilers in the United States

10 dale. The DOE-CCTP projects for coal reburn applied to cyclone boilers are described below.

Pulverized coal reburning for NOx emissioru; reduction in a cyclone-fired boiler was demlJIlStraled on the

110 MWNe1son Dewey Unit 2 for Wisconsin Power& Lighl in 1991-1992. Rebum fuel preparation and

'handling, reburn burners with fluc gml recirculalion, and a separaled overfrre air syslem were added. Coal

reburn tests were conducted on lhis unit while firing bituminous and PRB coals. NOx emission control

efficiencies of50 to 60 percent, with reductions from 0.75-0.83lbhmnBtu baseline, 10 around 0.38

:lb/mmBtu, bu{ as low as 0.29 to 0.32 Ib/mmBtu, wilhl'RB coal at fun load with approximately 25-30%

of!he lotal fuel heal inpmfrom rcbum fuel were demonstrated",1I·12. The reburn systern is nO longeroperaled on Nelson DeweyUnil2.

Microni7-"d coal rebnming has been demonstrated in 1997-1998, and continues to operate year_round on a

=11 industrial cyclone boiler (400,000 lblhr steam oUlput, 50 MW gross equivalent) forEastmanKodak

Company at theiT Kodak Park facility in Rochester, NY_ This unit (Boiler #1 5) achieves a NOx reduotion

efficiem,y of approximately 57 percenl on eastern bituminous coal, involving limiled cyclone air.staging

(cycloncs belicved to be slightly above 0% excess air) and a mouest amount of OverfITC air injection

downstream ofthe micronized reb<IIIl fuel input noz:;:les_ Approximately 17% ofthe boiler's 10101 fuel

heat inpm is typically suppEed to Lbe reburn wne. This coal reburn syslem continues lO operalc routinely

allhis facility. This installation is reportC<! to use a Fuller MioroMilllo produce micronized mal with

80% passing lhrough a 325 mesh screen7,••,,_

SquaTe Bulle Electric Cooperative 1\1-9 Bums & McDunndl
NOx BAcr Analy,j, Study APPENDIX At

Technical rca,wili!)' A"ossm~,,' Delails for NOx Control Teclmologies

Ifa coal rebnm system was applied (0 MRY Slation boilers, the exiSling cyclones would be supplied with

the majorily oflhe fuel in the form of crushed ooal, and the balance offuel would be supplied to a pair of

dedicaled pulveri7..ers 1<> feed Ihe rebum i<>jection ports, such Ihal the tolal heat input 10 the boiler is

cssenlially the same as without fuel reburn. In a conventional fuel rebum insl"lIation, OFA ports 10Galcd

above (he reburn section of the fllrnacc provide sufficient oxygen 10 complele the oombust;on process that

bc~rjJlS in the mJin Gombustion zone and is supplemenled in the rebum and burnout ZOnCS.

Similar 10 the Jpplication ofseparated overfire air, Ihere are potenliallmpacls and limilutiuns uniqne to

the firing ofNm1h Dakota lignite in cyclone_fired boilers !hat should be recognized as part ofthis

emission reduction I...:cimology ~ppJication. As a rcbum fuel, lignile is expected 10 behave appropriulely

upon introduction in the lower middle furnace to help reduce NOx cmissions. Thc ConcCms ure Ihallhe

diversion ofa signiJjc~ntamount ofhcat inpul from lhc cyclone barrels to use as a SOllfGe ofrehurn fuel in

the form ofpulvcnzed or micronized lignite may reduce cyclon~ temp~ratures "l1ough lo inhibil sbg

fornlalion and flow, ~specially a, bo;l~rload is rednced_ Air-slaging: lhc cyclones with the nse of

separated overlire air to further complement combustion NOx reduction as part of this rebnm rechnique

will further risk slag" freezing" in Ihe barrels and low~r furnace. Re..lueing thc number of ;,cliv~ cyclones

which are air_ and fuel-slnged 10 accommoda~c Tc..luccd firing rates while operating a coal-fir~d boiler

wilh rcburn and separnted ovedi.re air is the typical approaGh to aVOid slag lapping problems.

Pot~ntial NO" ~missions reduction performance is exp~"Ct"d to b~ limited on lignite-fired cyclon~ boilers

wilh" basic form ofseparaled overfire air syslem, sinGe Ihe rcburn fwel mjcclion localion is expecled to

coincide with the existing lignite pre-<1rying system v~nl porrs. Thc amounl ofoxygen introduced by th~

vent ports "I,ll be disruptiv~ to any conventional rebum process in that il would reqnire much higher

rebum fuel Injeclion r"lcs 10 ~r~ale a subsloichiomelric ahnosphere in the ]ow~r secondary furnace that is

couducive to promoting in-furnace NOx reduction.

Signilicanl addiliom; 10 Ihe fuel preparation equipment in Ih~ ~xisting plant f~eihli~s will be requir~d_

The coal rcblJrn syslem expected 10 b~ appli~d 10 MRY Sialion boik7S m.y use two new fine-grind

pn]veri7..ers and dYllamic classifiers to aehicvc the kvel of coal particle size distribution require<!,

Higher unburnC<l carbon levels in Ihe ilyash exhausted from Ihe boiler muy occur, cspeciaHy when the

rebum fuel is coal, and the regular burners are fired wilh less Ihan theoretical amonnts Of combustion air

commonly practiced with th~ use of ov~rfire air_ Lnw~ring (he rcb"m fuel injection elevation, decreasing

Rurru; & MoDonneH Al-IO Square Butte Electric Coopcrolive
APPENDIX Al

l'ecllnical Feasibilily Assessment Delail' for NOx Control Technologies

NOx BACf Allllljl5is Study

,

lhe aJll(}unl ofrebum fuel, and grinding lherebum coal to a greater degree offineness can hclp to offset

some oflbe increase in flyasn Ill1burned carbon content. Flue gas opacily from Ihe stack may increase if

the particulale removal equipment is ~n cleclrmtalie precipitator, due priJrulrily 10 reduced resistivily ond

smaller particlo sizes oflhe flyash.

An issue lhal affects the feasihilily oflignite reburning is the uptime required [or the lignite rebum fuel

pUlverizing system, and impaclofthe rebum systel)l on elTecliveness in reducing NOx emissions during

load changes and lower loads_ Typically, one new pulverizer is dedicated 10 prepare reborn fuel in

exisling pulverized fuel-fired boiler applications. Cyclones may be fired wilh less fuel or deactivated

during boiler operalion in order to accommodate chnngcs in fuel combuslion charocteristics, boiler load,

and for scheduled or unscheduled individual crushermainlenance. Milton R. Young Station Unit 2 bas

lwelve crushers [or cyclone coal grinding, cach dedicated 10 one o[the twelve cyclone furnaces.

Diverting as much as 30''/0 of lhe Lotal heal iuput as rebum fuel could require four existing cyclones to be

deactivalCd, and two new MPS-89 pulverizers to be dedioated 10 reburn fuel preparation. As eaoh of

these mills requires periodic maintenance, boiler emissions and/or load could be negatively impucled

during individualrebum mill outage periods while lbe boiler remained in service. A high level of

---.fiucness ofcoal particles from lbe reburn mills is important to achieve and maintain in order to limil

increases in f1yash combustibles. A minimum of6O peroent passing lhrough 200 mesh fineness is

reoormnemlcd by one ofthereburn tcclmology vendors (B&W) for pulverized lignite rebum. Micronized

'coal reburn requires even greater fmeness: 70_80 percenlpassing through a 325 mesh screen.

Pulverized or micronized coalrebum wilh the udvanced fonn ofsepari11ed overlire air (ASOFA) can be

applied and installed on MRY Station Unil2's boiler_ These combined tcelmiques are expected to reduce

NO" emissions approximately 54% from current pre-control baseline levcls (down to 0.36IbhnmBtu) for

the MRY Stalion Unit 2 boiler. These levels ofNO"reduelion depend on lbe advanced form ofseparillcd

overfire air leclmique to achieve the expecled NOx reduction percenlages when applied 10 lignite-fired

cyclone boilers, which maynol be suocessful given the conoerns expressed aboullhe potential impacts of

lhis tcclmiquc. Using finely pulverized lignite forrebum fuel is considered leclmicaJ1y feasible for NOx

emissions control under evaluation for application to MRY Stalion UnilZ's boiler.

Square Bulle Electric Cooperative AI_II Burn'l &MoDonnell
NOxBACT Analysis Sluuy APPENDIX Al

Technical feasibility ,\,.e"ment DelaUs for NOx Comrol Technologies

A.1.2.7.3 Fuel Lean Gas Reburn

Another ~pproaoh to gas rebuming is "fuel-lean gas reburn" (FLGRTM) lechnology, which injects limited

amounts ofnatural gas (approximately 3-10 percenl ofthe total fuel heat input) ahove the hurners (OT

cycloues) wilh or wimoul 'igmficanl air-stabrllg of lhc burners (cyclone") or lhe addition ofoverlire air

upstream oflhe fuel injeetion elevalion. FLOR's first field-tesl on a cyclone-fired boiler was at

Commonwc"hh E,lison'" Joliet Unil6 (327 MW), a 9-eyclouc-furnocc boiler". NOx emis~ions reduction

with FLOR (wilhoul SOFA) was believed to be approximately 35-40% with 7% of the boiler's tolal tuel

heal input supplied in lhe rebum zone. This te.st yielded 0_59lblmmBtu No" emissions from" baseline

of0.981<5. One olher cyclone boiler hos been modeled using compulational fluid dynamics (CFD) as part

ofa study looking al applying FLGR at Owensboro Municipal Utililies' "Elmer Smith Smtion Unil I (150

MW single-wall, eaSlem bituminous coal-fired boiler). This model prediclcd lhat No" emissions could

be reduced by 25-30% over lhal achievable from overfrre air and SNCR"_

More commonly, FLGR"IM ha" been applied on medium to large pulverized coal wall-fired boilers

burning eastern bituminous or western subbituminous coak On Wisconsin Electric Power Company's

(WEPCO's) PI=nlProirie Unit 1, a 620 MWg Riley tUIbo-fiTc~ wet-bollom (olagging) boileT, FLGRfl'-1

alone was predicted to reduce NOx emissiotL'< by 35_39 percent at a gas rebum rate 0£7-8 percenl bm only

achieved 20% from a baseline ofO.~5 IbfrnmBtu"·". This ispresum~blywithoul burner ~ir-slllgingor

SOFA. It has "ho been "ppliell in combination wilh SNCR at tbis WEPCO site.

A potential advanlage ofFLGR"IM over conventional gas rebum is that lhe Fonner is generaily compatible

with, but does not require, the installation and operation of SOFA- The staged reburn DICl isintroduced

inlo an oxygen-rich atmosphere downstream ofthe burners and any OFA injeclion poinls. 'TI,e amount of

reburn fuel injected is typieally limited by acceptable carbon monoxide levels in lbe hoiler exil flue gas.

There are potential impaots and limilation. unique 10 the firing ofNol1h Dakola lign ite in cyclone-fired

boilers that should be recognized as pari of this emission reduction ledmology applieation_ This is

signilicant, especially for alternatives with FLGR'J>J lechnology when combined wilh basic or advanced

SOFA to allow lherulcurnl gus inlrOduee~ Hbuvc me SOFA paris (0 bum complerelyprior to lhe fum"ce

exit plane. ill either case, lhe amount ofadditional potential NOx reduolion pOSSlble with FLGR= is

limited, since the rcburn fuel injection location is cxpccte~ to coincide with the existing lignite pre-drying

syslem vent porK The amount of oxygen introduoed by the vent rorls will be <lisruptive to the fuel-lean

'. ,

Bums & MeD~nnen Al14 Square Bulle Elewie Cooperative
APPENDlXAI

Technical Feasibility Assessment Detail, for NO" Control Tcdmologics

NO"BACT Analysis Study

reburn process in that it would require much higher rebum fuel injection fIltes in tbe lower secondary

furnace to promote in-furnace No", reduction. There are reduced eoneerns thai the withholding ofa

modest amOlmt ofheat input from the eyclone barrels to use natural gas as a source ofrebum fuel may

reduce cyclone temperatures enough to inhibit slag formatiOn and flow, especially as boiler load is

reduced. Air-staging the cyclones with the use ofseparated overfire air to further complement

combllition NOx reduction is an optional part oflhis rebum technique which will further risk slag

"freezing" iu thc barrels and lower furnace.

Fuel lean gas reblIDl can be applied and installed on MRY Station Unit 2·s boiler with or without

SOFAIASOFA_ This te<:lmique is considered technically feasible for application to MRY Station Unit 2·s

boiler. Expected NOxTCdueliou will be modest for FLGRTM without SOFA and FLGRTM with a basic

form of SOFA. Unit operatiug and oapital costs to supply large quuntitics of gaseous fuel not currently

available at this site are economic disadvantages. Because ofthese factors, these variaticns ofthis

technology wi]] not be COSl-effective compared to other alternatives with similar control effectiveness.

FLGR'Thl without SOFA ami FLGRTM with a hasic form ofSOFA were nol ineluded in the control

e.ff<:ctiveuess and cost-effectiveness sections ofthe main report.

Oth.erdemonstraled [0= offuelle:m gas rebuming 1O combination withposl-combustiou technologies,

such as amine--enhauced fuel lean gas.reburn (l'LGRTM with SNCR), are discussed under the layered

technclogies section.

A.1.2.7.4 Fuel Oil Reburn

Fuel oil has been SIlbstituted for natural gas in a conventional rebum applioaticn_ This is much less

common in the United States than using natural gas as a rebum fuel, due to the geneml lack ofdemand

and djfficulties in supplying the volume offuel oil which would be required. Ilhas been installed

commercially on three 350 MW oil-fired boilers in NewBrunswick(Canada) at the Coleson Cove plant.

NO", emissions reduction with rebum and SOFA was 78% with 25% oflhe boiler's tolal fuel heat input

supplied in the reburn ZOue. This yielded 0.22 lblrrunBtu NO", emissions from a baseline of 1.0

IbhumBtu". No examples of conventional fuel oil rebum applied \0 a coal-firedcydone boiler were

found in available lilcrnlure.

Fuel oil rebum could potentially be oonsidered for application to MRY Station Unit 1 and Unit 2 boilers.

Investigatiou of the specific source, dislance, and costs for supplying significantly increased quantities of

fuel oil via transport trucks hauling lanker tmilers or underground pipeline to M_R. Young st:3lion has not

Squam Butte EJoclric Cooperative AI-Ij Burm & McDoJlIleH
NOx BACT Analy,i, Oilndy APPENDIX Al

Teclmic.l Feasibility Assessment Delails for NOx Control TechnologIes

been performed. The unit operating and capital costs to supply large quanlities of high-volume liquid

f05sil fuel at Ihis ,ite arc econumic disadvanlages. The COncerns regarding potential impacls and

]imilations unique to the firing ofNorth Dakota lignile in cyclone-fired boilers !hal should b. reoogni:zed

as pa11 of this emission reduction lcchnology application are similar 10 Ihose expressed for convc'1ltional

gas rcbum. II is believed thai potential NO" Gontrol wilh oil rehnrn would be shghtly les5 tban

Gnmparable convenlional gas rGbum syslems.

Although fuel oil reburn could pOlentiully bc considcrcd fur applic",ion 10 MRY Slation Unit2's boiler,

the laGk ofany distinct l'0tential NO" reduGtion advanlag.s and demollBtr"tion on Gyelone-fircd boilers

doc, not appeur Lo support iLs consideration. TIlis alternative wa.' not included in the NO" Gontrol and

cost-effectiveness analysis.

A.1.3 Post-Combustion Controls

Posl-combustion controls deal with techniqnes thattherrnally or chemically-treat the flue gases to reduGe

NO" emissions after they have Gxited the boiler's lower fllmacc: In the cas" ofMillon R. Young Stulion

Unit 2, this primanly involves fonns ofseleGlive GatalytiG reduction (SCIl) and seleGtive non-calalytic

reduclion (SCR) lcdmologics. AnOlher emerging tedmology that has TeGenlly entered 11,e commercial ..,-;

market is Powerspan's Electro Catalytic Oxidation"', which treats utility boiler flue gas for removal of

nitrogen oxides, sulfur OX ides, and mercury. Another emerging teGhno]ogy thar has recently entered the

wrnmercial uLility air polllltion control market is Powerspan's Electro CumlyllC Oxidation", whioh lr~~ls

boiler flue gas for removal ofnitrogen oxides, sulfur oxides, and mercury.

A.1.3.1 Selective Non-Catalytic Reduction (SNCR)

Selective Non_Catalytic Reduction (SNCR), and variations such as hydrOGarbon-enhanGed SNCR (.old

\Jnder Lhe mde name ofNOxSt",""), alld Rich ReagentlnjeGtion (RRJ), are all post-combustion types of

boiler NOx emission Gontrols. While Lhe"c technologies UTG inscositivc to the spcGific fucllypcs whose

combusLion produGls are being treated, the large majority ofboiler appliGa1 ions to date have been on

pulverized Goal·fired lOuIS burning easlcrn bituminous fuels. SNCR has been uoed to reduce No",

emissions on numerous ulilityboiler.\ burning eastern bituminol1' Goal, midwestern bihIminous coal, and,

to a lesser extent, western subbituminoos coaL SNCR has also been us_d wi!h fud oil and naluml gasfired units. SNCR (and hydrOGarbon-enhanGed SNCR) tedmologie, can each be applied to Gyclone

boiler> with or without the use ofa SOFA system. SNCR does not appear to be dependent dircoLly on the

type of blJIIM" (w"ll-Iired, tangCllIially-lircd, and cyclone-fired) employed in Ihe boilers where it has

Durns & McDoonell AI_L6 Square D\1tte Eloctrie Cool,crali,'o
APPENDlXAI

Technical Feasibility Assessment Details for NO" CoutIol Teohno1ogies

NO" BACT Anal,!"" Study

,~,

'.', -.."

been insmlled, with or wilhout overfue air iu full operation. Operation at ilicse planLs has demonstraled

lhat SNCR com decrease No", emissious as much as 15-40% at full load, rnosl typically between 25-35

percent!'.

In the conventional SNCRprocess, urea orarnmonia is injected inlo the boiler in a region where the

oombustion gus lemperature is in the 1700 to 2100 degrees F nrnge_ Under lhese lemperature comlilions,

the urea reagent [CO(NH,j, ] or ammonia [NH, 1rcacLs with the NOx, forming N, and waler, reducing

NOx emissions_

I_ong-lerm examples where SNCR has been used lo reduce NOx emissions on two cyclone'fired boiler:;

are on a 138 MW unil and 160 MW unit b1UUing eastern bituminous coal at Conectiv's B.L England

Station (Units 1 and 2) since 1995 and 1996, respectively. Tests at these plants demonstrnted thal SNCR

can decrease NOx emissions as much as 30·36% at full load, from ~round 1.3-L41b/mmBtu respoolively

to as low as 0.85 lblmmBtu (wiLhout overfire air)l~",,,_ These boilers, looated near ALlautic City, New

. J=cy, conlinue to operale SNCR (with OFA) for annual NOx emissions around 0.55 and 0.451b/rnmBUl,

.respeclivcly.

SNCR Can be applied and installed on MRY SUi-lion hoilers. Estimalcd NOx emission rales for using

SNCR with NorthDakola lignite considered published levels aChieved by cyclone-fired units firing

western subbituminous coal, and vendor predictions. SNCR alone is expected to reduce NO~ emissions

approxirnatcly 37% Itom MCR bascline levels (downlo around O.5Ib/mnilltu) forthc.MRY Slalion Unit

2 boiler with ammonia slip limited to approximately 5 ppmvd_ BeCiluse oflhe operating costs ofthe

consumed reagenl, lhis technology will not be cost_effective compared to oilier alternatives with similar

control effectiveness (i.e. SOFA), SNCR alonc w.lS not included in the control effectiveness and cost·

effectiveness seolions of the main report.

Olher demonstratcd forms ofSNCR-related technologies, such as Rich Rcagenl Injection with SNCR, and

aminc-cnhanced fuel lean gas rcburn (FLGR~M with SNCR), are discussed under Lhc layered lechnologies

section,

A.1.3.2 Hydrocarbon-enhancEld SNCR (NOxStarTM)

Hydrocarbon-enhanced SNCR technology, commercially markelcd as NO"StarThl, is olTercd by a single

vendor (Milsui Babcock) as a post-combustion type ofenhanced SNCR technology, whereby an

SqulIIe Bune Elecrric Co",cmive Al 17 B= & McDonnell
NOx BALI Analysis Smdy APPENDlXAl

Technioal fe..ibili<y Ass~ssmenl Delails for NOx Control Technologies

ammonia-ba5ed reagent i" coni inuously injocled into the "uperheaterlreheater pass of Un operating boiler

WiIh small amounts of g~SC(}US hydrocaroon (typically either nalural gas err propane) and air Or steam to

pmvide lancc cooling and aid reagenl dispersion. The targele<i GornllUstion gas tempera lure range is

between l500"F amI2000"f. -n,e amounl ofg.,eous hydrocarbon introduced is small enough (0.1 to

0.2% oftotal fuel heat iopuI) lhallhis is not intended 10 UCI as UJom' ofreburn Or ,laged fuel combuslion.

An array ofpcrrnnncntly-installed injeclion lnnccs are located within thc boiler convection pnss, divided

in Lo numCrous discrete ,.ones ueroSl; the full widtl) and height of lhe duct. TIlC hydrocarbon auto-ignilcs,

Jmming hydroxyl (OH) radicals which reacl wllh lh~ NO" and ammoniu 10 produce elemental nitrogen

(N,) and wat"rvapor (H20).

NOxStarTM was dcmollStraled at Tennessee Valley Authority's Kingston Power Station Unil9

(tangenli"lly-iired 200 MW twln_flJrn",:e boileI firing eastcrn bitl1rninol1' coal) in 2002". 11ris

lechnology wa> subsequCIltly pemmnenlly-installed at TVA's Colhen: SUllion Unit4 in late 2003 on a 192

MW wall-Dred boil.r burning eastern bilurninous coal"'. NO" rCduclion was "tated as 68-80% for these

applicmions, which inclnded Ihe impact of overfire air nnd air-staged combustion upstream of the

nmmonia and pl'Opnnc injection locations.

An ."ample of a hydrocarbon-enhanced SNCR installation on a wall-fired pulverized fuel boiler is shown

"s a sectional side elevation view oflbe upper [urna"e in Figure A.1·3. .;

Burns & McDonncll AI-18 Square Bulle EleelIic Cooperalive
APPENDIX Al

Technical Feasibility A,,,,,.,ment Delails for NOK Conlml Technologies

NOK BACT Analy,is Sludy

NO"Starn ,

3mmooiaihydrocarbonfsleam

injeclion lance' (vertical

lance' bciJind 'ecoodary

superheater inlet lubes

Figure A.1-3 Hydrocarbon-enhanced SNCR Application on PC-fired Boiler2

-The snpplicr (Mitsui Babcock) of hydrocarbon-enhanced SNCR technology claims !.here is lillIe

sensilivily to lhe lype fuel (coal) or burners this lechrliqnc can be polentially applied to in order to rednce

NOx emissions. The chemical reagent injeclion for hydrocarbon--enhanced SNCR (NOxStlIrnt) NOx

conlrol technology must be preci,ely 10CIIle<l and carefully controlled 10 bc effectivc. Opcration oUlside

ofthc required operating ranges can even result in incre"--Sed NOx emissions. Extensive C<lmputationnl

fluid dynamic (CFD) model simulations arc ~eedcd to detennine the optimum injection poinls and spray

patterns_ lloiler operaling; comliliorl.'l change with unil load and varying fuel characlcristics_ The

NOxSlarTM process conlrol system must be able to adjUSl for lhese changing conditions in order 10 be

effeclive lhroughout lhe intended load rangc and [iring condilions encountered. Non-retractablc ammonia

injeclion lances nmmged in a parallel-.eries marmer are pennanenlly mounled inside the upper furnace

zone, attached to co~vcctive lube clcments. Different scclion, of!he injection "grid" can be turned olf or

on, depending On load and firing condilions and amount of NOx reduction required. lnjedion nozzles are

continuously purged and cooled by extraeled superhcated sleam from lhe boiler's main steam outle~

whclhcr ammonia reagenl is being inlroduccd into lbe -oue gas s~am or ~ot. Ammonia slip can be

minimized by injecting Ie" reagenl, al!hough NO" control perfonnance will be reduced.

Square Burte E1eClr;e CooperaLi\'e 1\1-19 Bums & MeDooUlcli
APP.ENDlX Al

Tochnicol Fca"bllity A",e."mrnl Vel"j], [or NOx Control Toch.nologies

-------

Ther" are a nwmbcr or issuos wilh /iring North Daku!" hgnite that make the "pplioabi Iit)' (If by<h-ocarbon_

enhan""d SNCR infeasible compared to previous experience in olher "ouI-firod powerplant,. 'll,ese

i.sues inc1",lc:

• HydrocarboIl-~Wmnccd SNCR (NOxS"(arTM) tcchnology ha._ norheen applied to cyclone boilers

(with or without the u,e ofa SOFA system). Hhas been only "pph~<.I (0 dale on p"lverized coalfired boilurs bUl1ling caSl~TI1 b,IUmlnOUS fuels.

There is ~o successful demonstraled llin_scale experience in continuOlli ,elVice ofhydrocarbon-

"nhallced SNCR (NOxStar"") tedmology on units firing high-olugl,'lng couls suoh", western

suhbiluminous (PRB) and llgnile. TI,e heat I.rans[~r surface" in lhe conl'eclive heat transfer 20ne

where lh" reagenl mixlur" is inj"~led arc prune 10 severe foul ing fL'OLn 11 yash consliluenls

common iLl Norlh DakOls lignite coals_ l'Iyash depo:;iL accumulalion on the oulside ofthe

NOxSlarT" l"ncc" in Millon R. Young Sl:llion Unit 2 boiler's upper fum~ce is expeeLed (0 be

signific~n~ potentially occWTing within a m~tter ot- a few weeks from slmlup and nearly

impo'>Sihle to prcl'cnl Or remove eHecl ively during boiler operation_ Such buildup is expccled to

Cause rnaldistribution of the NOx redllclion chemic~l re~gent lium the injeelion nozzle'.

Effective on-lme reLllov~1 ofthese deposils from lhc injccllon nozzles is amicip~ted 10 he

iIIsoffieienl 10 Tflllinluin dr~~liv~ injc'Cliun dislribution and volume eOn lrot It IS anlieipaled that

lhis would sigmficantly reduce the NOx emission ,eduction performance consistenlly aclliewd On

a slIslainahle basis_

Th. lack ofezperience wi'h cydoLle boilers. especially those firing co"l with severe deposition

characteristics suelt as Norlh Dakota lign Ite, make.' lhis lechnolog;y technically infe"sible for application

on the Milton R_ Young; SlSlion UniL 2 boiler.

A.1.3.3 Rich Reagent Injection (RRI)

Rich Reagent fnj.e~on (RRl) is a NOx control process that bas 1>-""'n developed and dmlOnstraled

specifically 10r usc On cyelonc boilers. Rich Rcagonl fnj~elion is an SNCR proce" th~t involves lh~

injeot'on ofaqUCOU5 Ufc" inlo the lowcr fumuce b.lwoen lile cyclones and the SOfA porK Rill l"rgels"

hig;h l~,"pcmlure, fuel-'"ich wne w, thin the hailer-furnace envirunm~lll irrunediatcly "djacenl 10 tbe

oyclone hllmer", m,d require, temperutllTcs in lhe 'Jnge of2400 to 3100 dcgrec, F.

The three ZOnC:; of a Wch Reagenl lnjcdion SNCR applicalJOn Oil a boiler ,vilh "q",ml~<1 ovcTfire uir Un;

sbown ~s a seclionul ,ide dcv"liun view ofthe [um"ce ill Figure A_l-4_

===-----""',------c==c=c== l'lmllS & McDouuell AI 20 Square nutte Elemic CoopLTIllivc
APPENDIX Al

Technical F=ibility A."",srnCTII Delails for NOll Connol Tecbnologie,

OFA

phemicalt/!l

Injection

Fuel

NO" BACf Analysis Study

Burnout Zone

Fuel Rich Zone

Staged

Combustion

Zone

Figure A.1-4 Rich Reagent Injection Application on Boiler With Overfire Air3

The Rich Reagent frljection (RRI) process has been successfully demonstrated on aL least two cyclonefired boilers, wilh lhe mosl recent installation at Ameren's Sioux Unit I, a 500 MWboilerfiring a blend

ofPRll and midwestern bilurninous coals_ Generally, lhe heat content of these coals typically varies very

little. Short·lerm testing oflhe RRIprocess has beenperfarmed alone and in combination with SNCR on

BL England Unit I in 1999"''''', and more recently at Amcren's Sioux Unit I in 2002""', in 2004"

(alone), and in the firsthalfof200S" (alone, and wilh SNCR).

The RRI proress is intended 10 be used ouly with air-starved (subsLoichiometrie staged_air) cyclone

combustion, in eoujunclion with the installation and operation ofun OFA system_ The RRI process has

uot been demonstrated on anyunill1lal fires North Dukota lignite. As ofOclober 2006, no commercial

installation of pem1anenl Rich Reagent Injeclion system has been made at any cyclone-fired boiler_

Square Bulle Elecnic Cooperelive AI 21 llurns & McDonnell
NO" BAG[ An.lysis Study Al'I'ENDIXAI

Technical Feasibility Assessment Deloils for NO" Control Technologie,

There is only one holder ofa oommereiallicense for modeling; and conccptu"lIy designing RRI (Reaction

Engineering International), witil two vendors sub-Iiccw;ed to design and sell RRl equipment (Fuel Tech

and Combustion Components Associates). Since these license agreements are in place, and considering

that successful dcmonstmtion Icsting; h"" been performed al two cyclone-tired boiler powerplants, lIri~

Icchnology is cOllsidered to be applicable and commercially ~vail~blc for potenli"l application on cyclone

boilers whioh bum coals wilh heal conlents Lhut me relatively constant However, due to the variable heat

content of lignile coal, RRI is considered to he te.;lmieally-in feasible [or applicalion on North Dakota

lignite-lire<! boilers. Technie.l f=ibility and e"pccted NO" eIllissiolls from RRT for applioation on!hc

Millon R. Young Station Unit 2 boiler are included in the ··Layered NO" Redllction Technologies"

'ecrion.

A.1.3.4 Selective Catalytic Reduction (SCR)

n,e lowesL NO:>: emi&sion levels from coal-fIred utility boilers are typically achieved by inst:lHing uud

opcrating selective catalytic reduction (SCR) technology. In tile SCR proecs~, the gas sITeom is pa"-<ed

through a catalyst bed in !he presence oIummoni. to reduce NOx to molecular nilrogen and water. The

process is lcrmcd "selective" because the ammonia preferentially reacts with !he NOx ruth~"I than with the

oxygen in the flue ga,. A catalyst is used to enhance NOx reduction and ammonia utilization at

~ppropriuteflue gas temperatures. SCR is usually applied to flue gas in Ihe 600°F to 750'F temperature

runge. There are vari.tiolL' in the SCR process 101' coal-fired boilers thal mostly involve locations in the

flue gas path where the caLu]yst is placed in order 10 promote the desired NOx emission reduotion effeeL

These are desc"ribed below.

,..

A.1.3.4.1 High·Dust Selective Catalytic Reduction (HD-SCR)

For coal-fired boilers. a conventional SCR reactor utilizes readily-available catalyst materials and reagenL

in the form of anuuonia. A convenlional SCR reactor is commonly installed in a high-dust, hot-side

arrangement, locaLed between !he ceonomiZL'r outlet and "ir heater inle1, wbere the flue gas lempernture is

within the desired opefJting rnnge for Ihe SCR calalysL The conwntioml SCR reactor arrangement is

preferred for mosl coal-fired applications in olility boilers beea'-'-'" it avoids the added expense of

reheating the flue g"s ifplaced arter the air heaters which cool thc flue gas, and downstream ofany flue

gas treatment Lo n.'TI10vc ucid gases. Conventional SCR tednology uses an anunoni~ injecLion grid

(AIG), which consists of multiple nozzles, for distributing !lIe reagent into the flue g"s at the boiler's

economizer flue gJS outlet.

Burn, & McDonndl AI-22 SqlJllre Bulle Electric C""l'cmli,,"
APPENDlXAI

Technical Feasibility A,,,,ssmelll Dc,"jl, for NOx Qmllol Technologies

----------------

NOx BACT Analysis Smdy

A schematic graphic diagram for a conventional high-dust, hot-side SCR system on a boiler with a nue

gas dcsulfurization system and stack gas reheat is provided in Figure A 1-5_

Figure A.l-S Conventional Higb-Dust SCR Arnmgement

with FGD Scrubber Oullet Reheat

High Dust Arrangement

CD Steam generator

® Regenerating heal rxchanger

® A;,

@ Electrostatic precipitator

® 501 - Scrubber ®

® SCR - Reactor

o Catalyst

® Vaporizer

® Ammonia / Air· Mixer

@ Ammonia storage tank

(ftgJJre copied from Wheelabralor Ai,- Pollution Conlrolliteratllre)

Conventional high-dnst, hot-side SCR technology has becn instnlled On several pulverized coal and

cyclone boilcrs firing bitnminolls and ,ubbilllminolls coal in the United States. Thero are also a limited

nllmberofEuropcan SCR installations on steam electric generating units (SEGUs) firing lower grade

(brown) coal. There are, however, no existing full-scale SCR installations on units that fire North Dakota

Square BIlllC Electric Cooperative Al-23 Burn, & McD~IUlell
NOx bl\CT ;'.r"ly;l, ~wd)' APl'JiNDlX AI

Tcchmc"l Foa>ibiTi<y M.sc"men, De",I., for NOx Control Technologies

------._-

lib'Illlc. TkTC ar~ approximately 50 cyclone-fired units localed in tne 5tal~s aff<X:icd hy EPA', NOx SrP

call. Over halr ofIhe"" unils are planning 10 inslall conveniiOrull hig-h-dusI, hoi-,ide SCR systems in

response 10 the SiJ' call. "I11e inslall"lion of oonv~nLional high-dust, hoi-side SCR sy~lems has been

compJcI~d On approxmmtd)' 22 of lhese uniK Appendix A2 Jists ,eveml convClllional hig-h-dus; hot-side

IJ.S. SCR ins",nations On p~lverized coal and cyclone-fired uliliry boilers, along WIth mea'W"ed No"

clnlssion,. Inili"l dalu from Ihe,c uniIS indicnte that convcnlion"l high-du'I, hol-sidc SCR ,ystems

operated on suilable cycJonc.[ired unil' may be able to reduce NOx emi,sions 10 as low .., 0.07

Ib,;/mmBlu. Several SCR iostallalions h"ve beCll rclrofiL On exisling cyclone-fired boilers burning

we,tern subbitmninous coal (or PRB blended with midwestern bitummous coal). For cyclone coal_lired

uillily b"ikru rctrufiUed with SCR leehnology, all were origin.lly designcd 10 blJITl bituminow, e""l.

The EPA NOx SIP cull only applies 10 unils m Ihe ea,tern Uniled Slales. There are nO faoiliIies Iiring

North Dakola lignite m the EPA NOx SIP call regIon. SCR sy,lem opera lion is currenlly unly needed

dUring the ozone seawn (June - Seplemher) for llIlit.> in'lalling conlrol equipmem solely to meet the EPA

NOx SIP call requirements. Limil~d <lIlllual opernlion is a Slgnilic"nt facLor wiLh n"l'ccllo SCR

equipmel11 reliahility, mainlenance, operalional costs, and catalyst 11 fe. TI,e demands 011 the SCR syslcm

are much more SCV~"[" iflhe ~"(luipmont IS required to operato on a full-timo, annuul basis.

Two byproducl, from iho high_du't, hot-side SCR process are ammnnia slip and SO,:

• A"'m"ma Slip; Shp i, ununonia that is ULlreacted in the NOx emi,,;on rodu~liOll prooess.

Maximum ammonia slip for a gas fired unit is usually 10 ppmvd whereas, on a coal fired unit,

anmlOnia slip helow j rpm is desired. For certain applications, Ihis concentration can be

problemalic, thorefore rcquiril\g more catalyst to reduce slip_ Mosl neW SCR application., have

arrunonia slip guaranteed at a 2 ppmvd n:lllx;mum f"r an initial operaling period.

• SOl: Due 10 the composiIion of typical SCll cataly,ls, a small peroentage of inherent SO, will be

oxidi7.ed 10 SO,. Th,. oxidation can he oontrolled by oatalyst selection and oaLl be les.s Ihan OnC

percent. S02 to SO; oxidation must be carefully controlled to avoid creating SO] levels sufficiently

high to rai'" the posSibiliry ofair heater fouling. A mlit tiring high_1;ulfu,' coal with SCR

lechn"logy is especially vulnerable 10 SOJ m.idalion and ammonia slip-relaled f"ulin~ problems_

The dcposilion and fouling i, duc 10 formation ofsolid ammonium wlIuIC (NH'hSO,) and Eqllid

ammonium blsul fate (NH,I [SO,). 11,e most important design variable is oplimizing the catalyst

s~leotion and am"unt of calalysL Ihat will reduce NO" ~"llli""i"ru;, "ontrol alnmonia slip, and

mmimi7.e SO, oxidulion.

nams & McDonnell Al 24 Square Butte Electric Cooperatj;/e
APPENDlXAl

Technical Fe"ibiUty Assessrru:nl De~i1s for NOx Control Technologic,

NO" BACT Analysis Study

Recent technology has allowed catalyst suppliers 10 make more rigorous and lengthy guarantees. A

Teasonnblc initial operating period for conventional catalysIs in high-rlusl reaclor nmmgements on boilers

firing eastern or midwestern bituminous coal is aronnd 24,000 active operating hours (i.e. when anunonia

reagenl is being injecled). Factors lhat need to be taken into account in design ofa high-rlust, hot-side

SCR application lhat affect the need for calalyst replacement are:

6 Pr=ure drop: The amount ofrestriction 10 .flue gas flow through the scn inlet, anunonia injeclion

grid, SCRrcaclOI. and downslream ductwork directly increases induced draftfrn horsepower

required 10 mainlain adequate boiler draft. This is an important parameler 10 consider and minimize

during the desigu slage_ Pressure drop is a function oflhe average and maximum SCRreaclorduct

velocities, the amount of restriclion caused by flow distribution correction devices (baffles or

vanes), and ihe number and geometrical asfl"cts orlhe catalyst layers_ Manyretrofil SCR

installalioru; require a boosler fan or opgradcd induced droit fan to overcome the added flow

resistmce. This increases operating cost for !he increase in auxiliary power- eonswnplion and loss

ofsaleable electric power_The type and pilch of the calalyst are factors most influential in

determining !he amount ofpressure drop.

)- Catalyst type: The most common types or fonus of catalystm,terial are honeycomb orplate.

The former offen; more surface area per-volume, but can be more restrictive and prone to

pluggage from ash deposils. The laner is usuany If'SS restrictive but requires more catalyst

per layer Or mOre layers 10 achieve the active surface needed to achieve the intended NO"

emission reduction.

'" Catalysl pilch: The pilch oIlhe catalyst, a term used 10 describe the size of Ute gas path

openings through the catalyst, varies depending on the manufacturer and design dust loading_

Pitch is gene."lly on lhe order- of 5 to 7 millimelers. Potenlial pluggage offlow channels

within the calalysts layers is therefore an issue that must be dea\( willi during design.

• Calalyst performanoe: The amount of NO" emission reduction expected is a ftmclion ofthe

specific activity level of the catalysl material and the amount ofcalalyst installed, over a given

period of time. Catalysl formulation selel:lion and features ofconstruolion have a significant

Impact on long-I.errn NO" emission reduction and snbsequent costs for reagent and catalysts

replacement. The frequency ofcutalyslreplacemenl is influenced strongly hy:

l> Catalyst erosion: Erosion oflbe catalyst material in coal fired units from Clltraincd f1yash or

sootblowing action reduccs the amount ofactive surface available for reacting with lhe

reagent and flue gas, and can oause distortions in gas distribution ("channeling'') through lhe

SquaTC BUlle Electric Coope""ive Al-25 Burns & McDonnen
NOx BACI An.lysis Study APPENDlXAI

Tcdmieal Fea,ibilily AssessmeTlt Details for NOx Control Technologic,

SCR reaclOL C"'lnlyst material is fragile and ellIl be casily damaged_ Some catalyst is

provided with erosion-resi"lant lop edges 1o mitigate this tcmkncy.

}- Moisture absorplion: Many types of oalalysl are damaged by absorption of moi"ture. The

rcaclormus( be kept ahove ambient dewpoint lemperatures orproleded from freczing during

outages in order to prO[eclthc ealalysl from moisture damage_ Spare oatalyst must be

carefully packaged 10 keep it dry and must be hnndlcd delicately 10 prevenl damage_

}- Th<;r:m~l degradation: The speoific a~livc elements of the catalyst surfaoe, or the matrix

stnlcture itself upon whioh the catalysl malerial is applied, cun degr"dc when exposed to flue

gas lcmpcrolures grealer than lhe intended design oflhe formulalion. High flue gas

lemperatures within lhu r~"\lulOr CnuSCS sintering, leading 10 a permanent loss of calalyst

activity due 10 a change in the pore structure ofthe cataly"l. ProP~T sclcclion aLld

manufacturing conlrol of the catalyst struoture and formulalion can minimizc lhermal

degradation.

>- Cat3lys[ poisoning, The loss ofperformance or activity of the catalyst over limc Can be due

10 ohemioal damage or poisoning. Two elcments espeoially detrimental to lhe life of common

litanium-supported vanadium penloxide SCR catalyst are arsenic and zinc_

Vanadialtungslen-buscd ca Lalysts are pari iou]arJy susoeptible 10 rapid deactivation due 10

gaseous arsenio poiwning. Jn some German SC"R imlallalions, a 50% loss ofactivity has

been reported within 10,000-15,000 operating houIS. Addition ofmolybd~l1l1mIII Uvanadiulilamum SCR c"I"lyst On similar applications shows relative activity reductions of20-25%.

Progressive Joss of SCR NO" reduction performance from caluly"l dcactivation due [0

poisoning is not possible 10 restore without effeclive deaning lo R"TIIOVC the deposits, or

cvenluul replacement.

» Calalyst fouling: The ,,,rfaoe area pOK"lllially exposed 10 Ihe reagent (ammonia) and nitrogen

oxides in the flue gas oan become fouled with flyush or sulfur-relaled oompounds_ The

presenoc of excess <:a1cium oxide in lhe presenoe ofsulfur in the flue gas con form a culcium

.ulfale surfuoe coating that can be extremely den,c, Irulsking lhe pores tlr lhe catalyst.

Progressive loss of SCR NOx reduction performanoe from catalyst deaclivalion duc to

fouling is difficull ltl rest<m: wilhoUl cffeelive cleaning to remove the deposils, or eventual

replacement.

SCR leclmology hu" bccn inslalled on numerous ooal-fired utility boiler fad1i ties around the world und

there arc a huge number of manufacturers lhat market the oalalyst". The question is whether SCR is a

Hum, & McDonnoll AI-26 S~u.re Butte Electrio C,.<lOp"",tive
APPENDlXAI

Technical Feasibility A"es,menI DemUs for NOx Control Technologies

NOxBACT Analysis Study

feasible tedmology for a unit firing North Dakota lignile_ There are serious concerns whetl1er instanation

ofSCR technology on a North DakolD.lignite-fired unit can be successful, especially in a convcntional

·'hot-side, high..<Jusl" configuratiolL The effectiveness of the SCR process is highly depe~dent upen the

~bility ofthe nitrogen oxides in the flue gas being able 10 contllct the active sites within microscopic pores

of!hc catalysl in the presence of ammonia reagent with minimal interference from conlaminants.

A recent technical paper "Ash and Mercury Behaviorin SCR Catalysts When Firing Subbituminous and

Lignite Coaisn by the Energy & Environmental Research Center (EERC) of the University ofNorth

Dakota was published in the February 2005 issue ofFuel Processing Technologymagazine". This paper

summarized the results ofSCR slipslre3lIllCsting attwo PRB-fm:d plants and one Norlh Dakota lignitefired powerplanl. The cvaluation included dclcrminaliou ofirnpacts of ash on SCRplugging and

blimling. Flue gas was isokinetically extracted from the convective pass of Lhe boiler upslream o( Lbe air

heater. Pressurc drop aero"" the catalyst was measured during the initial two-mouth lest period. and the

two consecutive lwo-month testperiods following the initial trial, while holdiug flue gas flow and

temperatures constant. Ammonia was injecled clownstream ofa scre~"U, upstream ofa flow straightener

and an-pulse section. Compress<.-d an- was injected ahead of lhe reactor, and was periodically pulOO<llo

-simulate sootblowing to minimize ash deposit accumulation_

, .' This slipstream SCR testing cxamined the significance ofash accumulations on SCRcamlysl on boili the

"mao;roscopic and mio;roscopic levels_ Very small flyush particles were fOWld bonded together by a malTix

ofsodium-, ca]crum_, andsulfur·richmalerials, likely in lhe form of calcium sulfal.e. North Dakota

lignite coal contains many alkali and alkaline-earth elements, and sulfur. The firing oflignite coal which

produces fine ( less than 5-l.lm diameter) llyash particles creates conditions that enter thc pores of the

catalyst, react with SO, -in the Oue gas, and form sulfates which bind other ash particles into Lbe malrix_

As posted on Elecbic Power Reseilrch Institute me. 's (EPRI's) website regarding the impactofcoal type

On SCRcalalyst life and performance, a recent EPRJ study'" produced (ield data analyzed from an '·InSitu Mini SCR Reactor" system instaJ1ed in a typical "hign-dust" location at seven diITerenllcsl sitcs,

including four firing PRB coal, one firing Texas lignile, oue fuing high-sulfur eastern bituminous coal,

and one (iring a PRBteastern bituminous coal blend. The PRBfbituminous coal blend test was perfurmed

at ArnerenUE's Sioux Station, on one of1.he two 500 MW cyclone-fired bOllers. This study fouud lhal

lhe cyclone unit firing the PRBfbiluminoU5 coal blend exhibited thc fastest rale ofcatalyst activity

degradatiou. Also, the higher deactiwtion I1ltes """" at lhis site were due to economizer cxit_flue gas

Square BntIe Electric Coopo:rative AI-27 Bum' & McDonnell
NUx BACT A..Ilalysis Study

------

APPENDIX AI

Technical Feasibility Assessmenl Dclail5 for NOx Control Technologie,

lemporatures being signilicanlly higher lhan at thc other sites. A comparison oIlhc Tcxas lignite and One

ofthe PRE-fircd sites wilh two different catalysIs, deactivation W;ls more a function of trnce e1emenls in

thc flue gas aud flyash than thc sp::cilie catalyst type Or formulation.

North Dakota lignite produces an ash lhat is very slicky "nd creales severe ush deposition problems.

There havc been no installations ofSeR systems (full-,cale) 011 ullits lhal fire North DakOI;'C lignile. A

tcohnical assessment was collllueted for the instaljation of SCIl technology On a North Dakota lignilo unil.

In order to further evaluate the feasibility ofinst"lling a convelltional SCR system on a North Dakola

lIgnitc fired unit, the Energy & Enviromnental Research Center (EERC) at the Univcrsity ofNorth

Dakota was consuHed. EERC has e:xtensive expCriCIICO investigating rhc dcposition characteriSlics of

North Dakola lignite ash.

l'eclmical dilficullics and anticipated operating problems that are unresolved with respect 10 inslulling

convcnLional sell lechnology at Milloll R. Young Stalion include the impacts of erosion, severe ash

deposilion, and "popcorn ash" on lhe catalysl. According the EERC's study (see Appendix Il), "thc mosl

si gIlificant problems that prohibit lhe succc,sful operation of SCR c"lalysts to lignite coal is tho fonnation

oflow-temperatul'e sodium-calcium-magnesium sulfates and phosphates that will form on lhe surfaccs of

calalysts and lhc carryover of deposils thar will plug the calalyst opening" resulting in inc,eased pressure

drop and dC~Teased efficiency". For these reasons, applicalion of "vailable conven~onal high-dust SCR

technology is considered lcchnicully infeasible for Milton R. Voong Slation Unit I and Unit 2 boilers.

'These concerns Can be divided inlo foul' calcgories. Each categ<Jry is addressed below. An explanation of

lhe factors lhal mako conventional SCR technology infeasible for thesc boilers follows:

1. Ash Deposition: North Dakota lignite contains a variable and complex variety ofinorganio

compounds that cOlltribule 10 ash dcpo,ilion. This fuel produces ash with severe d"Po~ition

cffilmcleristies that are nOllypioal with other coals. When e:<posed to thc hCal ofthe combustion

process insidc lhe cyclone burne,s, lhe rruljOrity of the fuel ash becomes molten and flows inlo the

bOllom oflhe fwnaee. A significunt portion of the fuel ash is entrained into the lluc gas exiting

the cyclone barrels at high velocity, where il COmes inlo contucl with lhe lower furnace

watelWalls. Theportion that is carned with thc rising flue ga. cools and some is deposlted on

beal lr.:msfcr surfaces in the upper furnacc and boiler convection pass. Ash depositioll 011 heat

transfer surfaces is a substantial problem for units thaI fire North Dulwta lignite. 'The problem i,

so scven: at Milton R... Young thn! the Unit 2 boiler must be shul down al 80 Lo 90-<lay inlervals 10

Durn, & McDonnell AI-28 Square B l~tc Electric C(}{Jptra~vo
APPENDIXAl

Technical FeaSlbi~ly Aascssrnenl Detail. for NOx Control Technologic.

NOlo BACT Analysi. Srudy

.'~

allow for cleaning ofO5"h deposits from the boiler heal transfer surfaces in order 10 reslore

reasonable furnace exit gas velocities and lernpero.tures_

Sodium is a significant contributor to the "stickiness" of the ash produced from firing North

Dakota lignite. Sodium cOn lent oft"he lignite ash averages approximately 4.4%, and can nearly ',--' .

double l"his value for Some of the lignile produced from the Center mine. PRE coal typically

"'

averages around 1.5% sodium content. Boilers firing Nort"h Dakota lignile typically have a 2_5%

hig"her heat rnte (million Btu. per ]ciIOWlltl of electric generation) than a typical boiler firing PRB

coal, thus requiring mOre heat input and firing more fuel per megawatt ofeleGtricity output A

cyclone boiler Gring North Dakola lignite also converts approximately 50% ofthe fuel ash to

fiyash, compared with a 35% conversion rnte for PRB cllal_fired cyolone boilers. Ovelllll,lhis

results in an amount ofsodimn emitted from a cyclone boiler firing North Dakota lignite of

approximately 7.3 lbs/MW-hr compared with O.9IbsIMW-hrfor a PRB_fired oyelllne blliler.

The calalysts in cnal-fired boiler SCR reactors are highly susceptible 10 ash deposition. In a

typi""l oonventional higb-dust SCR reactor, the flue gas typically passes through two 10 filar

layers ofcatalystmodulcs. The catalyst modules have numerous nalTlIW passages to provide

intimnte contact between the flue gas, arrunonia and cataly.;t The c1e=nce (pitch) in these

pa.o>sages is typioally 6_10 millimelers_ A typical catalyst layer is approximately I to 1.5 meters

deep. The catalysts in coal-fired boiler SCR reactors must be cleaned frequently using sool

blowers and/or sonic horns. This is true even on units firing fuels that do nllt prnduce a~lioky ash

Ihal contribules to ash deposition. Ash deposition on Ihe catalyst in a high-dust SCR applicalion

would be severe for a unil firing North Dakota lignite_

Sulfur in the coal is oxidized during excess air combustion to form sulfur dioxide (SO,), and a

amaH amount ohuifur trioxide (SO,). Some IIf Ihe ammonia-based reagent injected upstream of

the SCRreaclor will combine with SO;, to form ammonium bisulfate. The o:ataly.;! in the SCR

reactor will also oxidize a portion of the So, to SO,. Excess unreaoled ammonia reagent

carryover ("anunonia slip") from the SCR reactorwHl also react with these sulfuric acid

compounds in a similar fushion. The deposition charaoleristics for a Illlitbuming North Dakota

lignile will creale difficult-Io-remove ash depoails and pluggage of a conventional high-dust

catalys!, llJId inorease the prohability that the air preheater downstream and flue gas ductwork will

be prone to accumulations whioh could be :;everc. High-dust SCR performance and oatalysl life

Sqoare Bune EJeclric COOpCIlllivc AI_29 Bums & McDoarn:lI
NOx BACT Aualysis SlI1dy APPENDIX AI

Technical F"",ibility Assessment Details ror NOx Control Technologies

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

will be severely impacted. It is anticipated Ihat a high-dust SCR's cataly,;t life win be shortened

from ),6 years (typical) to as liti;le 11S 2-12 months, requiring cXlended, frequent outages for

II.'pIUGL"1I1cnL

HoI-side 11ir prehealers are susceptible to fou]jng_ Tubular air pre healers originally supplied with

all cyclone boj]ers 11lso lolcra to modcralc dust loadings, since (hcir heighl and size make them

difficult to JlliIiulaiu cleanliness. Leak lightness of the air preheater is important on cyclonc-fIred

boilers willi relalively high forced dl1lfi [an discharge (combustion air supply) prc,surcs. A highdust SCR insl11IMion will be pronc to air prehe,ler tube fonling and pluggage, requiring

e"-Iended, frequenl outages for cleaning_

2. "Popcorn Ash": A sceomJ considemtion in lhe application of conventional high-dnst SCR

ledmology on a lignile-fired unit is the potenlial ofthe SCR reactor catalyst plnggage Tesulling

fmm carry over of "popcorn ash" from Lhe boiler. Boil~'rS fIring North Dakot, lignite have severe

problems wilh ash deposition on boiler surfaces. North Dakola lignite has a high propensity to

form deposits on lhe bOller's furnace and convection pass fireside surfuces. For lignitc-fIred

nnil', the boiler's heat tronsfcrsurfuces must bc cleaned by soolblowing and other methods (e.g.

wal~T bmces) freqnenlly to maintain satisfactory boiler operation_ Some oflhe removed deposils

released by lhe cleaning action withinlhe boiler and convection p=es form ''popcorn u8h",

which will be entrained in Lhe lluc gas. Curry "vcr ofboiler ash deposits will contribule 10

pluggage of the ·'popcorn ash" screen ahead ofthe lop layer of SCR reactor catalyst. This can

cauSe distortions in gas distribution ('"channeling") through the SCR reactor, which will uggravate

erosion in the high velooity areas and ineffeclive performancc oflhe catalyst

3. TemperatuTc: A third issuc that imp,els lhe feusibility of inslalling bigh.dnst SCR techuology on

lhe North Dakota lignite-fired nnils is calalyst operating temperature. The pcr[ormunce ofany

SCR calalyst is highly d~'pcn<l~'llt on the lempcrnlure ofthe flue gas passing through the reactor.

Typically, a lemperature of600 - 750 degrees F is required to obtain salisfactoTy oper~lion ofan

SCR reactor. Opcl1ltion ofcommonly suppliC<l calalyst suilable for a high-<1nst SCR reaotor at

lempcrnture.s above 750 degre"S resulLs in severe and rapid llclc:riomtion oflhe call1lyst and SCR

reactor's NOx cmission reduction p~'[fmmanec. For bituminous and sub-bituminous coal_fired

llIlits, boiler flne gas p"-<sing between [he economizer o"Llct and air healer inlel is gencrally

Bums & McDonnell AI-30 SqnaTc Ilulto E1cctTic Cooptlaliyc
APPENDIX Al

TeclmiC<l1 Feasibilily Assessment Detail, for NOx Control Technologics

NOxBACf Analysis SlIldy

within a temperature rnnge acceptable for convenllonal SCR calalysls without additional healing

or eoolingoflhe now stream.

North DakOla lignite-fired cyclone boilers, including those at Milton R, Young Stalion, have high

lemperatures at the economizer's nue gas oullet by desIgn. The highest gas temperatures

down>tream of Ihe convection pans economizer sections and upstream ofthe air heater inlcts in

.MiltonR. Young Unit 2's boiler are mucQ. higher than 7511 degrees.

High gas temperatures al Ihe air heater inlet are required 10 produce the high air temperatures

(711110j7) needed for the pre-combustion lignite drying system, along with primary and second;rry

combustion airsupplied to the cyclones. Such air prehealer arnmgemenls and capabilities have

been taken into accmml in thc design ollhe North Dakota IIgnile-fired cyclone boilers. Reducing

Ihis high gas temperature 10 accommodale conventional catalysts for a conventional high.<Jusl

SCR reaclor would result in pre--<:ombustion air lemperatures Ihat are too low to provide

satisfactory dryIng and rapid ignition of Ihe high_moisture fuel. This will seriously impact

reliable combustion, slag formation and lapping in Ihc eyelone burners. Consequently, it is not

fe~ib]e to modify the Milton R. Young Unil2's boiler 10 operale wilh the lower economizer

outlet Due gas temperature.

Ollalysts for n conventional high-dusI, hoi-side SCR system have nol been Installed nor

successfully demonstrated in a full"cale installation oIan OPerilting solid fucl-frred unit lhal are

designed 10 continuously operate al the high 1>:mperatures (above 750 degrees F) thaI exist

between the convection pass economizer and air heater on the Milton R. Young Unil2's boiler.

4. Ero,ion; A£inal consideration on wheth~Thol"lde, high-dust SCR teclmology can be successfnl

on a North Dakola Iignile-fired unit is Ihepolen~a1for erosion of the SCR calalysL North Dakola

lignite supplied from the Center mine has an avernge fuel ash conlent of I0.5%, and can have an

ash content up 10 25.5 percenL PRB coal fuel aohcontcnt typically averages approximately 5

perrent. As previously stated, a cyclone boiler firing North Dakota lignite converts a

significanlly grealer amount offlyash than a PRB-frred cyclone boiler. Overall, this results in a

nyssh output rate rrom a cyclone boiler firing North Dakola lignile ofapproximalely 831bs/MWIn- C<lmpared with21lbsIMW-hr for a PRB-fired cyclone boiler. High ash con!cnts in the Due gas

stream can resull in physical erosion ofthe catalyst. 10 addition, effective on-line cleaning or the

Squ"o Butte Electric CoopCTlllive A1-31 BulIlS & McDOIlIlCll
NOx BACT Analysis Stwly APPENDlXAJ

Technical Feasibility Assessment Del<lils for NOx Control Technologies

high-dust catalysl will likely require Sleam or compressed airsoolblowing. Clconing oyoles of

the catalyst will be required much more frequenlly LImn a typical conventional SCR installalion

duc to the ash deposilion characLcristics of the North Dakola ligniLc amI lhc cxpecled buildup and

pluggoge resulting from the oarry over of"popcom ash" _ Frequent soolblowing of Lhc oalalyst to

remove fouling dcpo,ito "ml ush ,cculllulatioll'> will conlribule lo ero,iou ornJ decreased cataly"t

life. There is sonle Europe,n experience wirh high ash brown coals that cotalysl manufaoluren;

will be ohle to draw upon. This c"perien~e, however, will nol bc directly oppJicable to these

Unilw SMcs units becouse ofthe severe deposilion char,cteristios ofthe North DakOlfl lignile

~sh compared lo brown co~L

The EPA's NSR M,nual slates that for a lechnology 10 be fcasible it must '"ava,lahle and applicable"_

SCR tedmology is an available leclmology whioh has been m,;jal1ed on nUmorouS powerplant facilitics

arolll1d the world and lh~Te ,re a large number ofmanufacturers th,lJIllirkel the technology_ The qucstion

is whdh~"I SC'R leclmology is "'applicable" lor a unit fInng North Dakota lignite_

In accordance wim EPA's NSIl Manual, a technology is "applicable" ifit has been inSlalled On , "similar

unit". Hot-side, high-dnll SCR leehnology h" been retrofit on cosl-fjred nmls fe' luring cyclone boik-rs.

However, there are nO SCi{ inslallalions in operation or planmil onllJlils lhat include cyclone burners

firing Norlh D<lkota lignite with severe .>Iagging and 10\lling tendencies combined with such high boiler

economizer outlet gas lemperarures (o~cr 750'F) required for high-moisLure fuel prc-drying syslems and

tubular air preheulors.

The EPA's NSR Manua! al.>o slales a tec1mology JIlliy be detennined to be nol upplio"blc if ~a technical

assessmenl considering physicul, ohemioal and engineering principles and/or empirical data showing the

teclmology would not work on the emissions unil under review or !hat tuloolvable technical diffioulties

would prccludc the successful deploymenI ofibe lcclmique_" In this SCR technology upplioation, it

appears that a facil ity ulility powcrplant firing North Dakola lignite would experience ""tende<llime

delays or he r"'luircd 10 devote significanlinremal reSOUrces "nd engage outside research, followed by

exlCllded field trials to learn how to apply a conventional high_dusl, hot-side SCi{ teohnology On a snoh a

fuel source.

Based upun this lechnieal assessment thaL looked at the v,rious design and operation"l issues "-SSoeiatcd

with the in.>1aIMion of hot-side, high-dust SCR technology on a North Dakota lignile-fired sLcam--eleclric

-- :,

Bl1rn, & McDl1l1ncll Al-32 Squaro Bulle Ekcrrie CoOPCTIltive
APPENDlXAI

Technical P",sibility Assessmen' Det:lils for NO" Conuol Technologic'

NO"BACT Analysi' Study

generating unit, this control option is considered technically infeasible for Unit 2's boiler at Millon R.

Y,mng Station.

A.1.3.4.2 Low-Dust Selective Catalytic Reduction (LO-SCR)

Low-dust SCR (LD SCR) technology could potentially be applicable to North Damta lignite-fmd boilers

for NO" emi,sion c"ntroL Low-dust SCR refers to the location ofthe SCR system d"wnstream ofa

particulate collection system, such as an electrostatic precipitator or a fabric (iller. rfthe low-dust SCR is

downstream of a hot-side electrostatic precipitator and prior to lhe air preheater, flue gas reheating is

nnnecessary. This has been ~le prevalent form ofallemative retrofit SCRs in the United Slates for coal"

fired utility boilers. There are ten known hot_side Jow-dust SCR installations (without flue gas reheat)

operating in the United Stales as ofJuly 2005. These ore listed in Appendix A2. rfapplied to MRY

Station UnitZ's boiler, the low-dusl SCR equipment would be downstream ofa eold-side electrostatic

precipitator; flue gas reheat prim to the ill SCR reactor inlet would be required for proper No", emission

reduction performance,

f'or a wId-side ill SCR, the ESP outlct flue gas passes through a low-<lust gas-to-gas heat exchanger (ill

'GTG_HE), prior to passing to lhe low-dust SCRreaclor. After the LD GTG-HE, the flue gas wj]] travel

through the new duet; receiving hot flue gases from a direct-fired gas burner or set ofhigh-pressnre stearn

coils, leading to an annnonia.injcction grid, turning Vanes and lllen into the LD SCR reactor. The flue gas

• enlering lhe inlet to the LD GTG HE is expected 10 be ne:Jr lhc nir healer outlet temperature (330-3~0"F)

in a oold-side LD SCR application. The supplcrnenl<ll heal added downstream oIllie LD GTG-HE can be

supplied from high temperature steam eoils (indirect heal =hange) m directly from ualural gas-fired

duct burners. The flue gas must be heated to a minimum of approximately 600"F for the ill SCRNO"

annnonia reaction 10 be effeclive, The LD gas-to-gas heat exchanger is used 10 recover part of that

supplied heat, prior to exlmusting 10 the FGD syslem (if applicable) and slack The use ofrotary

regenerative-type heat exchangers has been applied in European ill SCRs. With this design, there will

be leakage between lhe untreated and treated gas streams such that the exit flue gas has higherNOx

concentrations lhan lhe LD 3CR outlet g;ls. The direct-fired flue gas rencat duct burners will also create

No", emissions, whien will add to the amount emitted from the boiler and input inlo the ill 3CR reactor.

The ill SCR reactor, GTG HE, and connecting ductworkwiJl increase the pressure drop through lhe flue

gas system. This nonnally requires an induced draft fun upgrnde m a booster Ian addition.

Square Blltle Electric Coop.rojj"e Al_33 Burns & McDonnell
NOx BACT Analysis Sluuy APPENDIX Al

Teehni""l Feasibility A."""men[ Detail, for NOx Control Technologies

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

The [~eLon; lhat make low·dnst SCR technology infeasible for !he Millon R Young Slalion Unil 2's

hoiler with existing purticulute collcclion via electrOSt'llic precipitators are as follows:

• Catalyst Fouling and Deactivatioo: An existing electrostatic precipitalor upslream of a low dusl SCR

reaclor will slill expose the enluly,tlo Lhe acid gas conlent ami fine particulale conlaioing l,~ce merals

and the high ~]kali mincral conlent of lhe entraiued lignilc llyash not removed by the ESP up.,tream.

Although the lola] amolJTIl offly",h carryover into the LD_SCR reactor is greally reduoed oompared

with a high·dust design, ir is anlicipaled lh~l Ihe low-dust SCR catalyst Ii Fe will slill be unacceptably

short. The small particle flyash passing inlo lhe reactor will he sufficient 10 cause pluggage of[he

catalyst pores, resulling in de"otivation of!.he catalyst. The firing of lignite coal produces fine (Ie",

than 5-j.lm diameter) flyash p"rticks, wh ich are ~Iso leasl likely to be removed by lhe existing

parnculale collection equipmenl (e.g. ESP) upstream of a low-dusl SCR. This creates conditions lhat

allow these small ilynsh particles lo enter the pores O(-lhe euLalyst, react with ,,0-, in the flue gas, and

form suillito< which bind orher ash panicles into a mulTix ofsodium-, cakium-, and sulfur-rich

materials nikely in a fom:: ofculeium sulfale). Once suoh a matrix. forms within Lhe catalys~ il can be

extremely krmoious and difficult 10 remove_ One c·,tulysl vendor's has 'latcrl il is !h~';r "experiellCC

lhat low-dust catalyst is morC difficul! to clean than that [rom high-dus~'''. Low-du,t SCR .,

performanoe und catalyst life could be severely neg.lively impacted_ Shortened lJfespans of the LD

SCR ea lalys! will require premature, eXlcndC<!, frequent outages for replaccm~"[]l.

• Sile Space Constraints: The insmllalion of" low-dust SCR syslem with flue gas reheat requires"

subslantia] amount ofspace for installalion and operalion. A low-dust SCR sysrcm will likely use a

regenerative gas_lo_gas heat exchanger (renearer) (0 raise lhe temperature of lhe flue g.s al lhe SCR

inlcl. A GTG HE win trn.nslerheal from lhe flue gas at lhe SCRrcaclor outlello lhe flue gas enkring

the SCR reactor in onkrlo minimize the supplemenlal SCR energy usage_ The gas-to-gus heat

exchanger dicla(e~ the footprint of lhe cold_side low-dust SCll system_ Space is required for the GTG

HE and for ductwork in and oul orlhe rChenl<.T. Sufficient free space around the reheater and SCR is

also required for maintenance.

The area around Unils I and 2 allhe MJL Young slation is cxtremely congesled in the areas where

low-dusl SCR systems musl bc localcd. The situalioll is parricularly severe for Unit No_ 2.

Equipmenl Ihul impacts the feasibility of inslalling a low·dusl SCR system on Unic' 1 and 2 includes

lhe Unit 2 absorbers, Unit2 flue g~s desulfurization (I'GD) dcwakring equipment, fly ash hsndliog

equipmcnl, fuel storage and transfer equipmenl, slrleks, fans and ductwork- II wouhl be extn..mely

Bum' & McDonnell AH1 Square Bullo Eloolrio Cooperarive
APPENDIX Al

Technical Feaslbilily Assessmenl Details for NO" Control Tecbnologic,

NOx BACT Analysis Srudy

disruptive 10 the continued economic operation of bolh boilers to relocate alllhe mentioned

equipment to creale space for the low-dust SCR systems at the M.R_ Young Slalion. Stacks, fans and

ductwork and lhe Unil2 FGD system eannOl bereadilyrelocated due to adjacent strucLures and lhe

need to eonlinue operation while construoling lhe retrofit inslallaLions. The fuel handling equipment

indudes a cool stornge bam and the main conveyors supplying lignite 10 lhe unils. Relooating the

coal handling equipment currently occupying space needed for the low dust SCR system:; would be

quite difficult given the site configuration. It i~ conceivable that the fly ash equipm.nllooated west

ofUnit I could be relocated to provide some oflhe spaoe needed for lhe low-dusl SCR. However, the

uvailabilily ofthis space is doubtful, since avoiding the likelihood ofsevere SCR calalyst sulfale

fouling will require a new Unil I FGD system to be installed. Ifa new FGD syslem is installed for

Unit 1, lhe FGD sysLcm would need to occupy the space that can be Illilde available by re!oc:ating a,h

handling equipment This space subsequently would nOl be available for low-dust SCR sysLcm.

Based upon a teclmical ass(\gsmcnt lhallooked at the various design and opemtional issues associated

wilh lhe installation of low-dust SCR technology on a Norlh Dakota lignile-fired slcam-clectric

generating uni~ this control option is considered lechnically infeasible for the MiHon R_ Young Station

Unit 2's boil~T.

A.1.J.4.3 Tail-Gas Selective Catalytic Reduction (LO-SCR)

A tail,gas (TO) SCR is a low-dusl SCR system where the LD SCR reactor is installed downslrcam oIa

FOD scrubber. The FGD outlel flue gas passes througb a gns-to-gas heatexchnnger (GTO·HE), prior to

passing 10 the tail-gas SCR reactor. The flue gas will travel through new or modified ductwork leading 10

Un nnnnonia injection grid, turning vanes and lhen into lhe TG SCRrcaclor. The TG SCR reactor, GTG

HE, and connecting ductwork will increase lhc pressure drop lhrough the flue gas syslem. This norrnully

requires an induced draft fun upgrade or a booster fun addition_

A schemalic grnphic diagram for a low dust aITilngement is shown in Figure A.I"6.

Square Butte Electric Cooper,live AI-35 Burl" & McDonnell
APPENDlXAJ

Techni,,1 f~",ibility A"c"mcnllJelails Fo,· NO" Conlrol Tech'JQlogies

Figu.c A.1-6 Tllil-Gas SCR Arrangemelll

Low Dust Arrangement

(1·\ S[eam genC"rator u

I,,~) Il.cgemralillg heat e,xchangcr

,-,

(:3,) Air

o F.lcctrostatic precipitator

(5) 502 - Scrubber

(6) Burner! Heat behang" ~~

® SCR ReaClor

(figure copied from Wheelabrdlor AU- PollUTion Conlrol lilcmlure)

TlJe flue gas from a wet FGD scmboor ouUel enlering the inlcl 10 the gas-to-gas hcal e~changcr i,

~xpe<:ted 10 be n~~r lhe saluralioo temperature (140"1') in cold_side TG SCR applicalion. The

supplemental h"ul udded downstream ofthc TG GTG-HE can be ,uJl!llied Imm high temperalure sleam

eoib (indirect heal exchange) or direclly From natural gas-lired tlucl bumer.<. The f1o~ !':"' fUu,1 be heated

[0 a minimum of appro~imalcly600"1' fQr Ihe TG SCR NO" anHnonia rctlclion tQ be elTectivc. Thc TG

gas-la-gas heat e~c1wnger is used 10 recover pari of thftl sLipplicd heal. prior 10 exh~u'1ing to Ih" 'l"ck.

Wilh a rol"!)' regencrative-lype gilS-IO-gas hal exchangcr, Ihere ""ill be illlem~lleakage hetwccn Ihe

unlreated "nd Ir~aled gas slreJJl1s such lhat lhe stack exit flue gas has higher NOx coneenlmlions than ti,e

Bum' & McDonnell 1\1-36 5",,,. Duer. Eleclric C(]U [>Cralwo
APPENDIX AI

TechniC<l1 FeasibiliTY Assessment Details for NOx Control Technologios

NOx BACT Analysis Study

TO SCR reactor oullet glls. Using direct-fired llue gas reheat duct burners will also creale NOx

emissions, which will add lo the amount emilled from!hc boiler and input into the TO SCRreactor.

There is limited leclmical infonnation publisheli in English for coal-fired steam-electric generating units

(SEGU) wilh low-dust/tail-gas SCR technology in applications requiring full flue gas reheat prior lo lhe

reaclor inlet. There is nO experience with TO SCR on eastern bituminous, western subbituminous coal or

lignite-fired SEGUs in the Uniled Stules. As of1997, there was one low-dustllail-gas SCRon a 220

MWe German cyclone-fired boiler wilh ;l 1988 retrofiL installalion. This boiler was reported to be

operating; wilhout combustion controls or FOD, burning low sulfur, low ash, model"-te moi5ture

bituminous coal with an averagc pre-SCR NOx emission rate ofapproximalely 1.07lblmmBtu, and was

meeting a 30-dayrolling average emission limit ofapproximately O.16lblmmBtu (85% reduction)".

Milton R. Young Station Unit 1 does not currenLly incorporate any flue gas desulfurizalion eqnipmenL,

which would place the reactor calalyst in a low-dust SCR confignration, which is considered infeasible

when burning North Dakola lignite. A new FOD system for Unit I wonld be required in order to avoid or

signlficanLly reduce exrected sulfate formation wilhin the catalyst and gas-to-gas heal exchanger when

combined wilh ammonia required for the TO SCR. Unit 2 currenLly employs a wet scrubber which

,currently tIcats upproximaLely 83% of lhe tolall1ue gas flow from lhe boiler. Flue gas reheat is currently

provided by lhe FOD hypass (i.e. wann, unlreated flue gas is mixed with the cool scrubbed gas).

The faclors that make lJIil-gas SCR technology infeasible for both Milton R Young Stalion boilers with

existing particulate collection vIa eleotrostatic precipitators are as follows:

• CaLalyst Fouling and Deactivation: TheTO SCR reactor downstream ora flue gas desulfurization

(FGD) scrubber "'ill still be susoeptible 10 fouling, contaminalion, pluggllge, and calJllysl

deaclivation.

o An existing electrostatic precipItator (ESP) upstream of" tail-gas SCR reaclor win still expose

lhe calJllyst to fine particulale containing trace mctals and the high alkaE mineral conlent of the

entrained lignite Dyam nolremoved by lbe ESP upstrealIL Allhough lhe total amount offlyash

carryover inlo lhe TG-SCR reaclor is greally reduoed compared wilh a high-dust design, it is

anticipated Ihatlhe lail-gas SCR <:alalysllife will still be uIDIcceplubly shorl.

o The firing oflignlte coal produces fine (less than 5-l-!m diameter) J1ya,h particles, which are also

least likely 10 be removed by lhe existing particulale collection equipment (e_g. ESP) upstream of

Square Btlne Electric Cooperative AI_37 Bums & McDolUlen
NO" BACT Analysis Snldy APPENDIX Al

Tcchnical Fcasibilhy Assessmenl Details for NO~ Control Tedmologies

~---~~---

a TG-SCR. Flue gas wilh entr"im<l finc particulale matter, including some involving sodium and

sulfur-containing compounds, will pass lhrough and be earried-over from a weI FGD scrubber.

This tIculed g;Js "ITeam will carry souium sulllllC particles, formed by homogCIlous condensation

after exiting lhe boiler and nol removed by the FGD syslem, inlo the ealn]ysllayers ofthc TGSCllreaclor. A dry FGD sy"lem followed by a fabric filter up.o;tream of the TG-SCH will still

allow sulfur-bearing nue gas and tine particles to enler lhe catalyst. There is seriolL' concern lhat

fine parlicles pas"ing inlo the TCuclor willuccumulale within the catulysl, and be resislanl 10

removal by conventional sootblowers and oilier cleaning technologies. This creates conditions

!hat allow these small flyush particles to enter 'he pores ofthe caWysl, react with SO, and/or So,

in the flue gas, and form sulfa Ie" which bind other a"h particles inlo a matrix of "odium-,

calcium-, and sulfur-rich material~ (likely in a form of calcium sulfate)_ Once such a malrix

forms within Ihe catalysl, il can be extremcly tCIlacious and difficulllo remove. Calalysl thaI is

exposed to such conditions will be ineITective al maintaining adequate aClivity upon which the

performance of !he TG-SCR's No" removal is based.

o These cntrained particles will al"o deposil on me gas-lo-ga" heal exchanger ahead oflhe tail gas

SCR reactor. TIlis depo.<ition will decrease heat transfer between the Illcoming (cool) nue gas

an<llhc outgoing (warm) fiuc gas. Sootblowcrs could be used loremove lhe accumulated

deposits from the GTG HE, but lhe SCR reactor could still suITer catalysl fouling from lhe

deposits dislodged from the GTG]-JE cleaning cycle becoming reentrained in the reheated nne

gas. Tail-g;Js SCR performance amI G;ltalysl life could be sewrely ncgatively impacted.

Shortened lifespans ofthe TG SCR catalyst will require premature, eXlended, frequent oUlages

for replacemenL

• Site Space Constraints; Thc Installation of a tail_ga., SCR syslem Wilh fiuc gas reheat requires a

substantial amounl ofspace for installation und operation. A tail-gas SCR system will likely use a

regenerative gas-to-gas heat exchanger (reheater) to raise ilie lempero.ture of lhe nue ga., at the SCR

inlet. A GTG HE willlnlllsfcr heal from thc nue gas althe TG SCRrc.cloroutlello the "crubbed

flue ga" enlering the SCIl reactor in order to minimize the supplemental SCR energy usage. The ll"""

to-ga~ heat exchanger diclales the roolprinl ofthe TG SCR system_ Space is required rorlhe GTG

HE anu for duclwork in and out oflhe rehealer. Sufficient free space around lhe rehealL"- and SCR

system is also reqllired for rrulinieffilllcc.

The:trea uround Unils lund 2 allhe M.R- Young stalion is extremely eongesled in the nrea., where

TG SCR sy~lems mustbe located_ A flue gas desulfurization sy"lem will be needed forUml 1 in the

Burns & McDOJlllell AI-38
APPENDlXAI

Technical FeaslbHi,y Assessment Details'for NO~ ConlroJ Tcclmologies

NOx BACT AllilJysis Study

near future to comply wilh lhe ConsentDecree. When a new FGD syslem is installed for Unit I, the

FGD syslem would n""d to occupy the space thaI can be made available by relocating ash handling

equipment. This spa"" subsequently would nol be available for a tail-gas SCR system. Thus, the

availability ofadequale space for aU the new FGD and TG-SCR system cquipment and slructure5

while accommodaling exis~ng cool storage and handling needs for both el<i5ting boilers at Millon R.

y ollllg Sta~on is douhtful.

The challenges for install"tion of new ductwork, SCR reactors, and fluc gils reheating equipment aud the

Jaok orpertinent experience with all aspects ofdesign, construction, operation and maintenanoe of lail-gas

SCRs on such high-fouling coals as North Dakola lignite are signifioant. The flue ga5 condition5 that the

TG-SCR calalysl will be exposed [0 will create unresolvable fouJing anll blinding U1a1ll'Ulkes successful

application of this technology difficult, expensive, and uneertain_

The risk offailure and uncertainty ofsuccessfully applying low-dusl, l"il-gas SCR leclmology 10 a

oydon~-[lfed utility powerplant firing Nonh Dakota lignite appe.ar substantiaL

Based upon a tedmical assessmenllhat looked at the various design and operalional issues associalC<l

with lhc installation of tail-gas SCR teclmology on a North DakOla Iignite-fired steam-electric gC1leraling

unit including a cyclone boiler, this control option is con,illere<11cchnically infeasible for lhe Milton R.

Young.Stalion Unit 2'5 boilerA.1.3.5 Eleetro-Catalytie Oxidation (ECO~

Powerspan's Eleolro-Calalytic Oxidation (ECO'") system is a multi_pol1utlmtteclmology dcsigncd to

oontrol emissions ofNOx, SO" fine particulate, mercury and certain Hll7.llroous Air PoliulanlS (HAPs).

The ECO" process has two main process vessels, a barrierllischarge reaclor, and a mulli.level wet

sombber. The barrier discharge reaclor ulilizes an eleetncal discharge to create oxygen and hydroxide

radicals whioh then reael with NOx, and olher constituents in the flue gas stream. The flue gas stream

then enters the bottom ofthe ECO" scrubber where the lower loop cools the flue gas and removes a

portiou ofthe acid gasses [sulfur trioxlde (SO,), sulfurio acid (H,SO,), nilric acid (ANa,)] produced in

the balTier re.actor and oxidi7.ed melals such as mercury, with a low pH aque<Jus ammonia reagent. A

second scrubbing loop is then enlered where additional SO" NO" acid gases and oxidized melals are

n:movcd with an aqucous ammonia reagent, (hough at a higher pfL Above the second scrubber loop is an

absorber section for absorbing fugilivc ammonia from the first and second scrubbing loops. The final

Square Bune Eleclric Coopel1\live AJ-39 BUIIlS & McDonnell
NOx 3/\CT Ar.~lysis Sludy APPEND1XAI

Technic,1 Feos;bility Asse'SLnenllJetails for NOx Control Ttthnologies

step ill lhe liCO'" process is a wet declrostatic pC<cipitntor (W ESP) which OOnCCIS n~e p"rticulale In~\(er,

aero;;ols gencraled in tl:te scrubhcr and ~ddilional mercury. An upd~jed schemalic process tlow diugmm

for the b",ic ECO~ process is shown i~ I'igur~ 1\.1-7.

Figure A.1-7 - Electro-Catalytic Oxidation (ECO®) Process Flow Diagram

(,"piou from "l'p'II,",",".'"' vuv!app,dw\Vwla"IM'PA600Rm I10 od~

ECO" Process Flow

r"rl""'~i" __ ~r~r" IJ'.,,----,:~_

r",""

~.r"

. . ~-

l'.\~J '

~"' .'

,i·o ;

," .

LJ

,:r\:!,~ -""'" ,,~ ,~

.. ---- -_." I ~f)" /11""'''' ·'1 ,",,,, - - h

ffU R"~UDr I ".' , ,

Ab."r.. VOI",I i .....~" ,,,;," (';.;'N

WetE~P L r----;;::

'L%,'

Co·Pm'lI:l ROOlV1ry' "orr•• _. ... '"

l'owerspan htlS been involved in an extended ECO'" process dcmonslmlio~ lL,i~g a 28 MW Commercial

Demonstration Unil (CDlJ) at R.I'.. Burger Station Unit<; 4&5. 'lbe ECO<!l CDU project treated

slipslream and demonSll"alCd performance, reliability and economics for approximalely on~ year. The

demonSlraliun program ,larled in Janllaoy, 2004. NOx removal i" ,taled to be up IO 90% wilh a c1aimcd

0.05 lb NOxfmmBlu out1~r eomlilio~ achievabl~ lor the front-end orthe ECa" pmcc.'.'. I'mthec su,lained

operation"1 tesls orille ECO''' CDU are underway during lhc second a~d lhird quarter' 0[2005.

As Ihis is a post_combustion muiti-pollulllni conlrol technolugy, il is claimed thal there i, little ;;cll.iti vily

to the 'Ype boilel' or burners lhal l'owerspan'< Elcciro-Catlllytic Oxida(io~ CECO") process can be

BIH'ns & McDonnell A 1-40 Square Dune Iij~c!l;c C"nrerotive
APPENDIX AI

Technical Feasibility Assessment Details for NOx Coolrol Technologies

NOx BACT Aoalysis Study

potentially applied to in order 10 reduce NOx emissions. Tho effectiveness ofthis ECO'" process for NOx

control has been demonstraled on a slip.slream commercial dernonslr"ation unil (CDU) associated with

pulvcrizc<l fud boil= firing midwestern oreastern biluminous coaL

Powerspan's published data from tne commercial demonSlration unit'sperforrnance ofup 10 90% when

treating l1uo gas wilh an inlet NOx concentralion around 0.5 IblrnrnBlU. This would resulL in a stack NOx

emission around 0.05 IbfmmBtu.

The ECO'" process has nOl been demonslr"ated in a full-scale configuration on any unit, nor tesled in a

slipstream configuration on any boiler lhat fires weslern subbiLurnlnoliS coals or North Dakota lignite. Il

has also noL been applied 10 emissions .from a cyclone-fired boiler. According lhe EPA's DmfiNSR

Manual, ',echnologies which have not been applied to (or peffilitted for) full scale opernlionsneed not be

consiclered available: an applicant sbould be ablew purchase or construct a process or wntrol devicetbat

has already been demonstrated in practice".

There are a number ofissues wilh firing North Dakota lignite lhat make the applicability oflhe ECO'"

process lcchnically infeasible forMRY Station boiler,. These issues include:

• DeposiLs and Plnggage: The l1yash deposition characleristics ofthe NorLbDakota lignite lire

extremely severe. Anything that contributes 10 J1yash deposition and pluggage wilhin the barrier

reactor is expec[Cd to have a detrimenLal impact on the multi_pollulant control perfonnance oflhe

ECO'" proccss, and lhus could have a serious impacLon MRY Station operations. The lack of

demonstraled operntion en lreatingthe emissions from a boiler firing coal with a high slagging

index precludes the use oftheECO"'prooess as technically feasible for BACT as applied to a

boiler firing NOI1h Dakota lignite.

• Reliability and Availnbility: MiUonR. Young Station's major planned outages foreach unit are

scheduled to occur once every three years. Any NOx conrrol technology selecLed as BACf will

need to operaLeycar-round, year in and yearout, on a routine basis, while performing at high

levels ofpclluLant reduction. The Powerspan ECO'" system is a new technology and Is nOL as

highly developed as olher more common NOx and SOo control teclmologies suoh as SCR or

SNCR plus wet or semi-dry flue gas desulfurizalion (FGD). It is expecled to require a full-time,

full-scale applicalion wilh sustained conlinuous operation to confirm levels ofcurrently

demonsln!led reliability and availability from lhe ECO" COU are acceptable 10 meet the

Square Durte Electric Cooperative AlAI BIlfIl' & McDonnell
NO"BACf Anal}"'i' Study APPENDIX Al

Teohnicnl Feasibility Assessment Dotail' for NO" Control Teclmologies

expectuLion ofinfrequent m~jor OUl"gcs OV~T long time periods while maintaining high levels of

control.

lbere are addillooal futon; that make Ihe appliealiOn of the ECO'" process potenlially more difficnl t !han

oIher cSlabli,hc<! cmission control technologies available for coal_fired powerplanls:

6 Thcrc is a lackofc"pcricnoc with lhe ECO'" downstream ammonia scrubber's coprodnct

crystallization and grannli7.ation equipment design, opcmtion, and m"intenanoe, whioh was not

inclnded with thc initlal commercial demonstmtion unit. The coproduct stream thst wonld

nOTlll"lly feed into the cryslallizalion and granulatiOLl prooesses w,", colleded and tr.msported

offsile for this process slep dnring CDU operaliun. Bcoausc cryslalIiza~onand gr.mula~on of

ammonium sulfale from an ammonia scrubber solu~on is not a new technological process, this

was nol considered a teclmical feasibility deficiency_ For instance, Ihe Dakot~ Gasilic"tlOn

Company (DGC) in Beulab, ND cnrrCnlly operntc~ an So, scrubberntilizing ammonia as a

reagen!. Following the generation ofammonium sulfale, DGC crystallizes and granuMes a

fertilizer product on sile_ I[owever, at.MRY Slrllion, eon,iderable costs wonld be incurred for

inlcrimstorngc Hnd shipmmt ofthe ECO"'process >emhber'sliquid bleedstrelm unlil ~ufficieut

experience has idenlified and eliminated potential failures and rcP"ir5 for the oryslallization and

granulation equipment should it prove to be unrcli"blc.

• Size ofthe barrier re"ctor: Powerspan recenlly indicared that they 'Vonld scale lhe reaelor for

optimum cost and spaoe arrangement based upon k~~uns learned from the CDU plant operation.

The nnmber of individual passages within a barrierreaclor sized for eithe,· ofMRY Slation

boikn;' maximum fiue g<lS flow and gas stream oonstitnenls is expCClCd 10 r~'"<Iuirc a crossseolional area comparable to half ofa large eleelroslalie prccipillolor. Although this has nol been

dosely examined lor all aspects ofdesign, eon~truc~on, operation and mainleoance, the amounl

ofphysi""l space reqnired to hold the barrier reactor and inlet and oulle! ductwork is believed to

not be available for potential retrofit to MRY Station units. Sile space oonslmints are considered

to be a barrier 10 tec!mical feasibility for potential appljca~on of the ECO"'prucess al Millon R_

Young Slalion for Unit] and Unit2's boil""s.

6 Additionalstalion auxiliary power consumption: The barrier reactor, pins the mnmonia s~'rubber

and wet electroSlalic precipitator additions by ~n ECQDl syslem, require an increase in station

,

,

Bums & MoDOlUle]j AI-42 Square Butte E1ectrio Cooperalive -
APPENDIX Al

Technieal Foa'ibility Asses.,ment Detail, Cor NOx Control Teclmologie.s

NOx BACT Analysis Srudy

auxiliary power consumption. ForNOx control, (his includes more horsepower required by thc

booster fun needed to cOIIIpCI!sate for the flue gas pressure drop created across the barrier reactor.

It also includesthe power consumed by the electrodes ofthe barrier reactor itself.

Because of the technical feasibility issues and lack of wmmercial availability and full-scole experience,

especial\y on such high fouling coals, the ECO" system was considered teohnically infeasible as a BACT

nllematiw for Milton R. Young Station for Unit2's boiler.

A.1.4 "Layered" NOx Reduction Technologies

~'"'

Many ofthe NOx emission reduction teclmologies which involve furnacc or convection pIlss arcos for

their inlroduction into the flne gos stream have been, or can potentially be, oWEed in combinations so os

to resnll in an overall higher level ofremoval. Separated overlire oir, various types offuel reburn, and

various fonns ofSNCR could polentially be combined in series to reduce NOx emissions prior to boiler's

flue gas exit. However, alllhe possible NO" control technology combinations have not been installed on

"Goal-fired poweIplants, so acmol feasibility ofsome combinations hove not been demonstmled as viable,

-particularly in considemtion of the special challenges posed by cyclone boilers firing lignite coaL

A.1.4.1 SOFA Combined With Other NOx Reduction Technologies

Scparated OverfIre Air COIl be favorably combined willi every other mcthod in order to reduce the amount

ofreagenl nrrebum fuel required to achieve the resulting level ofNOx emission reduction. Some wntrol

teclmologies, especially conventional fuel rebum systems, require overfue air (0 complote the combustion

of the staged fuel admitted to ~le upper furnace. Fuel lean gas reborn can be applied with or without

SOFA, as this limited amount ofstaged fuel is introduced into an oxygen-rich atmosphere downstream of

tile cycl(Jj1e burners and any ovemre air injection points_

A.1.4.1.1 SOFA with SNCR

Selective non catalytic reduction teclmologies are post--combustioll, iu-furnace NOx control alternatives

thal have been installed in nUmerous boilers ofvarious designs, fuel types, with and without overfire air.

It is usually advantageous to apply overlire air so thai the amount ofchcmieal reagent consumption can

be miuimized in order to nchicve the largcled NOx emission mte from the boiler outlet.

Square B~tlo B<:clrie Cooperative AI_43 BlITIlS & McDonnell
NO"BACT Analysis Study APPENDIX Al

Technical Fca'ibili<y Assessmenl Delails for NO" Control Technologic,

Tesls at Conectiv's B.L England Slation (Units I nnd 2) demonstrated lhat SNCRcnn decrease NOx

emissions as much us 31% ut full loud, from 0.55 to 0.38 lb!mmBtu, over and above the reduction

possible from overfire air alone (approximately 60% drop, [rom I.J to 1.4 downlo 0.55) in full operation.

This is an overall NOx emission reduction of72% from pre-retrofil baseline".

SNCR can be "pplied alone Of combined wilh either the baaic or the advanced forms ofsepamted ovcrfire

air (ASOl'A) on MRY SLalion boilers. Air-slaginz thc cyclones wilh lhe use ofseparaled ovemre air 10

further complement combustion NOx reduclion is an optional part ofthis lechnique. However, as

previously explained in the discussion of SOFA allemal ives, Ihis Will risk slag "freczing" in lhe burrels

and lower furnace. Estimated NOx emission rote.s for using SNCR lechniques with North D"kota lignire

considcred publiahcd levels achieved by cyclone-fired units firing we.,tern subbituminous coal, and

vendor ealimates. SNCR with ASOrA is expected to reduce NO:.: emissions approximately 32.6% below

NOx levels predictccl for ASOFA opcmlion, nnd pOl~"Illi"Jly 5B% overall from current baseline level [or

the MRY Slalion Unil 2 boiler with nmmonia slip limited to approximalely 5 ppmv<!. Ths highcst

performing basic SNCR system is polcnlinlly able to uehicvc n NOx emisaion rale ofO_330 IblmmBlu,

whcn combincd with!hc "dvanccd form of SOFA on MRY Slation Unit, 2 bDiler during operullon at lhe

pre-mntrol baseline (near MCR load)_ These levels ofNOx rc<!uclion d.p<-nd on the advanced [om, nf

scpnroted over-fire.ir technique lo achieve lhe expected NOx reduction percentages when applied (0

lignite-frrcd cyclone boilcrs_

Anolher- [orm ofSNCR is combined with sepamted overfire air_ This is currenlly being mar"kelcd

commcrcially as "Rotating Mwug" (Rotamix). In the Uniled States' utililies industry, lhis has only been

"ppli.d lo pulverized coal-fired boilers. It is different lban basin SNCR iu thal itiucludcs" hot air booster

fall and a small ambien Lair fan, and injccts lhc mrrnonia (or urea) Te"gent into the high-pressure ovcrfrrc

air now stream ahead o[lhe ROFA nozzles' outlels. This mixture is imparted into lhe boiler in an olTset

fashion from opposite sides of the furnace at high velocitie.', wilh mul ti-porl nozzles loculCd nl high

elevations relative 10 lhe lop bumcr row. Ths vendor (M:obolec USA) claims lhal Rotamix (rOLaLing

opposed fire air or ROFA +SNCR) helps 10 distribute the reagent across the furnace cross scdion. which

maximizes in-furnace NOx reduction while minimizing neg;ltive impacts on carbon monoxide and flya<;h

unburned carbon_ Three tangenlially-fired ulillty boilers burning eastern bituminous coal ur TIlinois

biluminous coal were retrofil1ed wilh Rotamix, each achieving a NOx reduction of approximalely 7-"ro to

55 percent beyond the levels produced by ROI'A alone, frompre-SNCR baselincs ofO.22 10 0.28

lbfnnuBtu down lO 0.10 10 0.23 lb!mmBtu wilhout low-NO" hl1mers<'''~'~·.

Bum., & McDrmmll ,1.1-44 Squaro Bullo Elcelric Cooporalive
APPENDIXAl

Technical Feasibility Asses,ment Delails for NO" Control Technologie,

NOx BACT Analysis Study

While this variation ofSNCR combined with separated overfrre air could polcnlially be applicabie to

cyclone boilers, it has nor been IIIllTkcled (0 servc such applications_ Since cyclone boilers do nol require

!he addition ofhot air booster fans for SOFA, and optimum inj~"Ction locations forbolh SOFA and SNCR

reagent may not coincide, Rotami" may not perform as well as, or significantly better than, a weBdesigned combination of convenlional SOFA and SNCR. This ledmiqu~ is not distincl enongh from

basic SNCR from fimctionaJ and air-staged cyclonc NOx rednotion performance standpoints to warrant

individual consideration for Mihon R. Young Stalion boilers. Because of a lack of cyclone-fired boiler

experience wiili ROFA and Rotarni", the latter wos considered inf~a51ble and thus was not included in the

control effectiveness and cost-effectiveness sections ofthe main report.

A.1.4.1.2 SOFAwithRRJ

Rich Reagent Injection must be used in an oxygen-deprived atmosphere in order to effectively r.duoe

nitrogen oxidc emissions. This requires air-staged cycloncs and scparatedovertire air opemtion_

.The NOx emission reduction reagent injection for RRl prooesses must be precisely located andcarefuHy

controlled to be effective. Operation outside oflhe reqnired opernting ranges can even TCSU]( in increasod

NO" emissions_ Extensive oomputationall1uid dynamic (Cl'D) simulations are needed 10 determine the

oplimum injection points. Boiler operating conditions wIll chang<: wilh unit load and varying fuel

chamcteristies. The RRI process control systeJI15 must be able to adjust for lhesc changing conditions.

RRlhas the potential to provide a moderate degree ofNOXreduction on coal-fIred boilers. Data from

B.L England and Sioux plants show this tedmology can reduce NOx emissions betwe~n zero and 39

pereent bcyond lhe amount attributable to overIlie airsyslcm operation"~',2<"~,,. During initial

demonstration testing ofRRI at Arnerell's Sioux Unit I boiler, a 500 MW unil fIring a blend ofPRB and

midwestern bituminous ooals (wiilioul SNCR), with SOFA in August2001 at a lower furnaoe SR of

approximately 0_99, NOx emissions Were rodueedapproxirnately 55% to 0.55 Ib/mmBtu wI SOFA only,

with =0 to 15% additional NOx reduction fromRRI (down to 0.47Ib/mrnBtn) wilh zero ammonia slip",

Results of this initial RR1 testing ot Sioux plant were poor at cyclone stoichiometric rtllios elose Lo 0.99

beoause ineonsisten~ sporadic, and non-repeatable NOx emissions reductions between zero and 15% were

m=ed. SubsequentRRI testing at Sioux Unit 1 in March 2002 with SOFA at an average cyelone

stoichiornetrio mtio aroood 0.95 showed NOx emissionsreduction of29 percent (down to 0.27 lb!mmBtn)

beyond those achieved with a modest amount ofcyclone air-stagingwiili SOFA (68% drop down to 0.38

IbfmmBm from SOFA alone), for an 80% overnll decrease from Illlcontmlled baseline; RRI CFD model

Square BUlle Electrio Cooperative Al--45 Buros & McDonnell
NUx BACT Analysis Sludy APPENDlX AI

Technical Feasibility Assessment Details [or NUx Conlfol Technologies

predictions for these eondiLions were NOx emissions reduclion of31% wilh FGR and 37% withont FGR

operalion. TesLed NOx emissions with RIU+SOFA in 2002 were with a reag",",1 nonnalized

stoiehiomelric ralio (NSR) on (lbs NH) pcr Ib NOx)"_

Purametrie lesting al Sioux. DniL 1 in May 2005 reduced NOx emissIOns between 15-38% with RRI, down

to 0_15 10 0.20 IbfmmBlu. Reagent NSR l,etween 1.0 and 4.0 and low ammonia slip level~ less lhan 2

ppm from an estublished baseline eondilion of0.2.0 to 0.2851bfmmBtu level achieved NOx emissiom as

low as 0.12 Ib/mmBlu with deep cyclone air-slaging and SOfA opera~on Ilring an 80;20 PRBlIllinOl'

coal blend at 480 MWgunit outpUl"-

"lbe intent offhe RRIprocess for NOx reduction is that il musL be used in conjunotion wiih nir-sLarved

(substoiehiDmetric staged_air) cyclone oombuslion re""lting from the mslallnlion and operation of an

OFA system, wilh or without SNell The cyclones' air/fuel :;Ioiehiomctry mustbe carefully conlrolled to

maintain fuel-rich condilions for the RR[ prooess IO be eITeGlive. The combll:;lion goJSCS in the vicmity of

Ihe RRI Ure" injection ports mu:;l be essentially devoid offree oxygen, in order to avoid oxidizing the

nitrogen "ontuined in Ihe injeoled reagent, which wilJ increase NOx emissions_ for 1ignite-fired cyclone

bOJlers, Lhe ba"ic form ofseparated ovedirc ~ir (wilhoul relocated Ugnite drying system ve"t port,) "

inconlpatible with RRJ. Reagent injection will be near 'he elevation of lhe existing lignite drying system

vent ports in the lower front and rear walls ofa lignite_fired cyclone boiler located immedialdy above Lhe

top row:; ofcyclones. These vent ports are located conGuITenlly with the existing flue gas recircula~on

(FOR) poris on Unit 2's boiler. The oxygen introdnced with the lignite drying system's venled moisture_

laden airstream, will cau:;c lhe urea 10 be oxidized, creating NOx emissions.

The advanccd fornl of SOfA relocates Lhesc lignite drying system vent ports from the lower to lhe middle

fUIrulce, enhancing lhe desired in-fum~ecnitrogen oxides reduction process. Therelore, in order for RRI

10 be even moderately clIcc\i ve in red llcing NOx emissionB from a lignile-flred cyclone boiler, this

ledmology mlls! be combined with an ndvanced form of separat~d overfire air, whether instal1ed with or

wilhout SNCR.

As mentioned in the feasibility disclL<sion of applying ~~1>'ffilted overfire air IO ligrritc-[=-cl cycloae

boilers, lhe degree to whioh each and ~very individual cyclone furnaoe Con bo suocessfully opernted wilh

less than theorelical (substoichiomctric) combustion air dircclly im]Xlcts polential NOx formation ""d

further in-furnace emission roouclion. Becausc the heat content ofJigrrilc from the Center mine i:; not

'. "

Burns & MoDonnen /I lAC, SG"OTe Bl1~e Eleclrie Coop,,,,,ive
APPENDIX Al

Technical Feasibility Assessment Details fot NOx Control Tech~ologies

NOx BACf Analysi, Study

L.

consistem from hour to hour, there can be sub5tan~al deviations in nirffue1 ratios for individual cyclones

from the overall average.

In the case ofMRY Station boilers, Minnkota has simullllncously sampkd 1he unprepared lignile feed 10

several cyclones' lignite drying systems in order to detelllline lhe variability in (he combustible and ash

componenls ofNorth Dakola lignite. This invesligation found that fuel qualily variaLions can resull in

individual samples' heating values to have a maximum differential ofover 12% of!.hc lignite samples'

average.

TABLE A1-1 - Lignlle Heating Values and Variations for

Milton R. Youn Station Unit2

M.R. YonngSllltion Differences Betwren Individual

Individual Cvclone Lignite Samples Cvclone Limite Samoles

Higher Heating Values, Percentage of HHV Differen~al, Percentage of

Brullb Average lillV Brullb Avera eHHV

Minimum HHV: 5,852 88.9% Minimum: 4 0.06%

-- MuximumHHV: 7,101 1.08% Maximum: 797 12.1%

AverageHHV: 6,584 100% Avernge: ] 65 2.51%

_..'-

When operating with air-slaged conditions associated with separatcd overfrre air, any individual cyclone

with lignite heat inpnt Jowerthan average can allow significant amounts ofoxygen 10 oxidize the urea

c;,._ reagent at high lemperatures, lhll5 increasing NOK emissions in that zone al that time. Cyclones with

lignite hent inputs higher than average would produce lower stoichiometric air/fuel ralios and less NOx

emis..,ions. Less complete combustion in the deeply staged cyclones may release insufficient nmoUIlts of

hcal, lhll5 lllising the risk ofsolidiJYing lhe fuel ash so that it aceumulales within lhe cyclone barrel. This

could result in firing auxiliary fuel oil or taking the boiler out-of-serviee to remove the pluggage. Nellhcr

ofthese conditions is ~esirnble becanse they result in increnscd emissions, lower perfonnance, and higher

operating costs.

The MRY Station Unil 2 boiler's cyclone air/fuelrntios vary in real·time ba>ed on significant changes in

combuslible coment on an individnal cyclone by cyclone basis. Adjustment ofindividual cyclone

combustion air inputs 10 compensate for lhe variability in individual oyclone 1ignile heal input rales for

Unil 2's boiler would be neoessary to maintain consislent substoichiometrio opernLion of overy cyclone

during air-staged combustion. This places greal emphasis on achieving tight control over the air/fuel

Square Bulle Electric Cooperative AI-47 Burns & McDounell
NO"BACT Au.ly';, Slmly APPENDlXAI

Technical Feasibilily A"c.."IlCnl Delalls for NOx Control Technologies

r"Lio.< on each cyclonc during air-sUlgcd combustion opcmLion in order for ASOFA 10 bc suoces..,ful in

producing ,ignificanl additlOnal NOx emiS5ions reducLion on lignite-fired cyclone boilers.

Tl,ere lS no eqll1pmenl a\'flilabk for ooal-fired bOIlers Lhul e"n measuTC the fucl heat mput at the prepared

feed injection poin! on such a ",riahle fuel 10 allow the determinalion of rea,onably occur.llc air/file!

ratios on individual cyclones in rcaltime. Wilhoul being able to m~aSurc the cyclone air and heat inputs

Lo allow for conLrul ofair/fuel proportioLls and emissions, the sLoichiometric ratios ofindividu"l cyclones

can not be eslablished accuraLely 10 produce combuslion proUlICts e",cnti"lly devoid offree oxygen_ This

TCqujr~mentis e-<:pecially necessary when employing RRI to avoid increasing, ralher than reducing, NOx

emissions on thc MilLon R.. Young Slalion ULlit 2 boiler.

Rue g~s re~iT~lIla!ion in MRY Stalion Unit 2 boiler's lower furnace could increase NOx emissions by

admitling oxygen·be~ring nue gas in the ,-icinity ofl.he injected urea ifRRI were appJioo with basic or

advanced forms of SOFA_ To avoid this negutivc unpocl, FGR in (he lowcr furnace would need to be

discon tinued. T1,ere i, uncer1aimy whelher modification or elimination of lhe lise ofFOR in the lower

fumac~ ofMRY SL~tion's Unit 2 boiler could be successful in controlling lower furnace wall fIrcside ash

deposi~oll and gas temperature".

Because oflhe significanl msumlOunlable problems discu,-",d above which would increase NOx emi,-,ion

rates, Rltl is cilllsidered tec1mical1y infeasible for applio"~on On (hc Uni, 2 cyclone boiler at the Milton R.

Young Station.

A.1.4.1.3 SOFA with RRJ and SNCR

Wheo RRI is combined wiU, separated overfire air and SNCR, it hJS demonslrated very high NOx

emissiol1s reduclion at Conecliv'" RT_. England UniL I boiler cluring shon-Icrm lesling firing e"-SLem

bituminous coal, on the ordcr of80% from an uncontrolled 1Ja.eline around 1.21bhnmBlu". InMay

2005, testing RRI+SNCR+SOFA at Ameren's Sioux Unit I boiler firing a high PRB·blcnd coal

demonstr.lted NO" emission. as Iowa. D. 12 lb/rrnnBlu. This W3" from an eslablished baseline oon<lition

of0.20 Ib/mmBtu level achieved wilh deep cyclone air-staging and SOFA operation. Thesc lesting

resulls when firing- M 80%:20% PRBJlI1inois coal blend at ~80 MWg unit output wilh a reagenl NSRof 4

Md ammonia slip limited to Jess Ulan 5 ppmvd, showed M overall 90% reduction with no apparent

ndvcrse ,horHerm impacts ofdeeper air-staged combustion lO!,'CLherwiih overfrrc air, Rlti and SNCR

applications"_

Bums & McDonnell AI--4~ SGu.re Ilune Eleclrie Cooperative
APPENDIX Al

Technical Feasibili,y Assess"",nl Details for NO" Control Teclmolog;e'

NO" BACT Analysis Study

_.

Be"ause ofthe significanl insurmounlable problems regarding RRI as mentioned above, RRIwith SNCR

and ASOFA is considered lechnicaJlyinfeasible for arrlica~on on the Unit 2 cyclone boiler at thc Millon

R.. Young Slation due to lhe variable heat content of the lignite fuel l'lhich allows thc creation ofoJ(ygenrich conditions in thc boiler.

A.1.4.2 SNCR and Reburn

SNCR could polentiaJlyhe installed downstream ofseparaled overfrrc air nud various types offuel

reburn, to reduce NOx emissions prior to a boiler's flue gas exit. Several of lhese examples were already

dcseribed'~"·IO,II,l"'.l<. Conventional gas (CGR) or coal reburn syslems, by and large, havc uol been

combincuwith forms ofSNCR, although alleast one vendor (GE Energy) has promoted a combination of

conventional gas rebum with SNCR and overfirc air systems as "advanced" gas rcbum. Duly one

example ofpermanenI installation ofSNCR wilhconventional gas rebum (and ovemre air) on a

tangentially-fired boiler was found in available technical literahIrelO and vendor experience lists". The

vendor (GEEncrgy) that provided the advanced gas rehurn system at 120 Jl,.fWNRG Somersel Stalion

claimed NO" emissions were reduced by ~~% from a baselinc of0.45 down to 0.25 IbJrmnBtu with

overfrre air alone; an addilional reduction of 20% resulting from conventional gas rebum with overfrrc

air, down to 0.20 IbfmmBtu; and further decrease of45% down to 0.11 Ib/rmnBtu using gas rebum wilh

SNCR with an unstalcd amount ofanunonia slip, for an overa]] reduction of75% from uncontrolled

baseline".

No examples ofactual demonstmlion orpeTIrulnenl installalion ofSNCR wilh conventional gas or coal

rebum (and ovcrfirc air) on cyclone-fired boilers were found in a search ofpublished and proprictary

technicalliterahIre. The lack ofexperience wilh lhesc combinations on a cyclone-frred boiler, especiolly

for lignile·firing, makes lhe application for :MRY Station's boilers infeasib1e_

FLGRY>< has been inslalled with SNCR forNOx emission reduction on several pulverized coal boilers, as • discussed in the following subsection_ A polential advanlage ofFLGRTM over conventional coal or gas

rebum lechniques is Umllhe fonrrer is genemJ1y companole with, but does not require, the installation and

operation of SOFA.

Rich Reagent Injection would appear 10 be less capable ofbeing combined wilh fuel rebum, especially

conventional fuel reburn alternalives with high amounts ofrebum fuel injection. This is due to lhe

Square Butte Electric Coopomuve AI-49 Burns &-McDollUclJ
NOx llACT A~,lyslS Smdy APPENDIX Al

Technical Feas1biliIjl Assessment Delails for NOx Control Technologio,

expected need 10 idle (e.g. not fire) up 10 four orlhe twclve cyclones when operating lherebum syslem al

fUll boiler lo~d. In this case, Ihc cooling nir inlroduced inlo lhe idle cyclones, nmJ ~ny conveying air

injected with pulveflzcd ,eburn coal (or if natnral gas is injected with recirculaled nue gas), are expected

10 cOlmlnact the fuel-rich c{)nditions ofthe air_and fuel--staged cyclones operating sub'lo;chiomelrically.

This will couse a porlion oflhe "mine reagent to be oxidizcd in Ihe low~T f"m"~e, crcating NO"

emissions instC<ld of converting them 10 nitrogen ann water. No example ofactual demonSlrnlion or

permanent in,tallation ot·RRI wilh rcbnm (and overfil-e air) on cyclonc-firet] boilers wus fOlmd in

"v"il"blc lcchnical Jitcntllre or vendor eXjJel'lence lisLI. This oombination is considered infeasible due 10

lhe location ofinjeclion and variable heat contenr of Ihe lignitc rebum. fucl whioh allows the creation of

oxygen-rich conditions in vicinilY ofRRI injcctor,; in the lower flml"CC ofUmlZ's boiler.

Hydrocarbon-enhanced SNCR (e.g. NOxSiar"") may potentially be combined with alllypes and forms of

rebum previously dj,o\lSse<!, sinoc thc location ofmc cnh"ncoo ammonia injeclion nozzles will be above

(hcyonu) the clevation in thc middlu fumace where any rebum fuel should be reaoted. No example of

actual demonstralion or pennanent in.<tallation ofHE-SNCR wilh rebum (aLld overfire air) On "ny coa1_

fired ulihty boilers, especially oyGlone-fircd unils, '"D" found in a voolablc lcclmical htCIll(ure or vendor

UXP~TIcncc lists. Thc adv"nlab'C th"l HE-SNCR presents is the potenlial for grealer-than-SNCR_levels of

NOx reduclion without siguificant amounts of gaseous hydrocarbon being required. Because of a Jack of ,""

experience wilh HE SNCR applied to cyGlone boilen;, ~ml nun" with significnnl mIlOlmls offuel rehum,

this combination has not been invcsligaleJ further, and was not included in the control and cosleffectiveness analysi, for NO" control>.

A.1.4.2.1 Amine-Enhanced FLGRTM (AEFLGRT"') or FLGRT'" + SNCR

Fuel_lean gas rebum has been combined wilh SNCR as" hybrid form of "mine reagent teclmologics on al

leasl fivc pulvcrized coal-fired lllility powerpJants retrofit inslallatious within the United Stat",. This

combination oflechnologies allows the boiler to be operated with l'LGR""" alone, FLGRTM and SNCR

simullm1eously, or SNCR only (wilhout SOFA) for the specific level of control desired or required.

No examples ofactual deffionstralion orp~TIrulDcnl insl"lIaliun ofFLGRThl +SNCR (with or withoul

overfrrc air) applicdlO" cyclone-fired boiler were found in available leohnicallllcrature Or vendor

experi<'-"TICe lisls. The vendor Wuel Tech) that provided the AEFLGRThI syslem at M<'-TCeT Sl,tion claimed

NO" emissions were reduccd by 60% (from a baseline of 1.4 d01NIlio 0.56 IbJmmBru) with 5 ppm

ammonia slip wilhoUl over-fire ,ir. A technical p"pcrprovide, more details". Another Icclmic"l paper

Burn, & MoDormdl i\ I 50 Square Bu~o Eloemo CoOper.l~ve
APPENDIX Al

Technical FeaslbiIi<y As,essmenl Details for NOx Control Technologie,

NOx BACf Analy,is Sludy

slated Ihatl'LGRThl alone only reduced NO" emissions approximately 27% from the IA lb/mmBlu

baseline, down to L031b/mmBlu".

An AEFLGRrM system (with or without SOFA or ASOFA) may be potentially applied to a cyclone-fIred

boiler_ The high capital and operating cosl, associated with applying fuel lean gas rebum is expected to

make lhis economically unattractive, and the exisling lignite pre--<lrying vent ports wiillikely limitlhc

NO" emission reduction potential of the FLGR'M componenl ifinslalled wilhoutlhe advanced fonn of

SOFA_ The lack ofexpeIience with this combination on any cyclone-fired boiler, especially for EgnilefIring, makes this combination infeasible for:MRY Station Unit 2 boiler.

Square BUIle Electric Cooperalive AI-51 Bmn, & McDonnell
NOx BACT Aualysis Smdy

Technical Literalure References:

APPENDIX Al

Technical FeaSIbility Assessmenl Detail, for NOx Control Technologies

I "B&W's Advances on Cyclones NOx Control Via Fuel and Air Staging Technologies", by F.rllm,

H., Mmingo, G., Johnson, D. W., and Wung, D.K. (Babcock & Wilcox, Co.), Beard, C.T. (EastTruln

Kodak Company), nnd Brcw't~T, S.E. (T~"IIllcssce Valky Authority), presented at lhe EPRI-DOEEPA Combined UtiliLy Air Pollu",n! Conlrol Symposi"m, Allnn1a, GA, August 16-20, 1999.

Available at B&W's intemet websile: http://~~b~!?.cock£Q.mLp-E-r1ttlpdJ1BRJ683.ndf

2 'The State o[,hc Art in Cyclonc Boiler NOxRcu\1Clion", by O'Connor, Dave, Himes, Rick, ;md

1'3cchi3no, Tony (Electric Power Re.,earch Institute), pre.,ented at the EPIll-DOE-EPA Combined

U~lity Air Pollut.nt Control Symposium, Atlanta, GA, August 16-20, 1999.

3 EPA Docket OAR-2002--0076-0~46Techmcal Support Document for BARTNOx Limits for Elecrrie

Gencra'ing Unils Excel SprcadsheeI6/1512005, pow:d On lhcirwebsite: from EDOCKET at

http://docket.epa.gov/edkpub!dolEDKl'ltaffItemDetaiIView?objectld=090007d~ 8084562b; this is

m;:;oeiatcd with HPA Aei(l Rain ProgrJm Clcun Air ]V!arkcLs Division, Technical Support DocumentMethodology For Developing BART NO, Presumptive Limits, June 15,2005, OAR-2002--0076_0445.

4 MobotecUSA experience list and tedmology explanations, av.ilable from their website at

htip;Ifwww.m.)bole~u>a..~omiprojcel:;liLlslalbtion•.1l1m ;md

hltp:/Iwww.mobote...-.-.a.com/technology/rofa.htLn

5 "NOx Reduction From A ~4_]I,.fW Wall_Fired Boiler U~]jzing Oxygen Enhanced Comhustion",

PIaxair, by Bool, L!wrence E.lli, JIld Bradley, hurou, presented at Thcl'vlEGA Symposium,

Washington D.C, May 20, 2003.

6 "Combuslion Tempering in ConjuncllOn Wiih SNCRRcJuecs NOx Emissions Nearly 60% on a

Natnral Gas Fired Cyclone Boiler", posted at ,heir internet website:

http://ww,,,.rimcoro.comfD<Jl7Mld3ICAC.pdf

7 "Clean Coal Tcchnology: Reburn Technologies forthe Control ofNilrogen Oxides Emissions From

Coal-Fired Boilers, Topical Report Number 14, May 1999"', U.s. Department ofEnergy (DOE).

Posted at thc intcrnet website:

hll]):Jf",",,'W.fo.,,' iI.energy.gov/pro gmmsJpO\',icrwskmslv ubIica Ii 0LlsiClean Coa1 TOD iCa1 RqJOr);;/topi

';;1J,14.ndfg "Clean Coal Technology Programs: l'roject Fact Sheets 2003, Includes Clean Co.l Technology

Dcmonstnllion Progrum, as ofM.y 2003, Octob<.-"I 2003", U.S_ DepaTirnenl ofEn~Tgy (DOE).

Available to the public from llie National Energy Technology Laboratory's Clean Coal Technology

Compendium: htto;!/www.l.nLeov!projects!cele/index.html.

9 "RebumingProjccls in Ihe Dep;rrtment ofEnergy's Clean Coal Teohnology Demonstration Program",

by Munn, Al and Ruppel, Tom (parsoD~ Corporation), aud Sarku:>, Tom (N.tioJlllI Energy Technical

Laboratpry), presented at the 2U04 DOE-NETL Conference on Rebuming forNOx Control,

Morgantown, WV, May 18, 2004. A reburn-related document (an updated version ofa poster from

the May 18 Conference) is titled "Scorecard on Rebuming 6I112004"by Al Mann and Tom Ruppel,

Farnom Corporation, available on-line at:

ll!!l1:!!www.netl.doe.govLoublicationslproceeding:;104lNOx/nostersffiebuming%20Scorecar.d.pdf

.";

Burn, & McDonnell AI_52 Squa", Bulle Electric Coopenlu,""
APPENDlXAI

Technical Feasibilily Assessment Det>ils fur NOx Control Technologies

NOx BACf Analysis Study

••

I'J.

10 "Experience wilh Rebum for NOx Emissions Control", Engelhardt, Don, Payne, Roy, Moyeda,

David, Folsom, Blair, GE Encrgy, presented allhe 2004 DOE-NETL Conference onRebuming for

NOx Control, MOTglInlown, VIV, May 18, 2004.

11 '"B&W's Rebuming &perience", by Farzan, H., Maringo, G., Yagiela, A., Kokkinos, A. (Babcock&

Wilcox, Co,), presenled al Ihe 2004 DOE-NETL Conference on Rebuming for NOx Control,

Morganlown., WV, May 18, 2004.

12 "B&W Cyclone Rebum Leads 10 No,. Reduclion, Wisconsin Powcr & Light Co.. Nelson Dewey Unit

No. T' (case history from B&W's inlernel websile

http://www.babcook.comlpgglpslcasehislories.html.dated 1997).

B ''Rebum Technology Application Guidelines", Moyeda, David, Hartsock, Don, and Payne, Roy, GE

Energy, presented allhe 2004 DOE-NETL Conference onReburning for NOx Control, Morganlown,

WV,May 1&,2004.

14 GE-EER experience lisl, Scplember29, 2005. ForwaJl-fued coal reburn, and gas rebum with SNCR,

see "Powerplant mosaics: paving the way 10 O.l1lbIMMBlu without SCR", by Folsom, Blair GE

Energy, published in the March 2004 issue ofModem Power Systems.

15 "Predictions ofFLGR at Commonwealth Edison's Joliel Unit 6" by NGB Technologies, posled on

their website: http://'mVW.ngbtech.com/subpageslurojfjo]jet results html

16 ''FLGRAdvisor '"": ABollerEvaJuation Tool for FLGR-Based NOxReduction Syslems by NGB

Technologies Inc., posted on their websHe: http://www.ngbtech.eomlsubpageslprojll1gr advisor.pdf.

"h 17 "CFD Evaluation ofFuel Lean Gas Rebum (FLGRThl) and Selective Non_Catalytic Reduction in

OwensboroMunieipai Utilities' Elmer SmithStnlion", by Wang, David H., Cremer, Mare A., Adams,

Bradley R. (Reaction Engineering International); Frizzell, Kn. (Owensboro Municipal Utilities);

Dusatko, G.c. (Sargent & Lundy), presented at the 2001 US EPA!DOE MEGA Symposium on SCR

and SNCRs, Chicago,lL, August 20-23, 200 L

18 Fuel Tech experienoe list dated 112812005.

19 SNCR "While Paper", Inslitute ofClean Air Companies, Ino. (ICAC), SNCR Committee, May 2000,

Fuel Tech website http://www.fueltechnv.comlpdIiTPP-534.pdf.

20 RJM: experience list, September 3, 2004.

21 ''NOxStar'" PlanlDemonslration, Octoher2Q{)J", by Morris, K.W. and Hesselman, G., Mitsui

Babcock (US), presented at the 200J U.S. DQE Conference on SCR and SNCR for NOll Control,

Pittsburgh, PA, October 29-30, 2003.

22 "InSlllllation ofNOxStarTM System at TVA Colbert", by Morris, Keith W., Milsui Babcock (US),

pre&ented at tbe Coal-Gen 2004 Conference, July 28-30, 2004, Overland Park, KS.

23 "Improved Rich Reagent Injection (RRJ) Perfonnance ForNOx Conlrolltl Coal Fired UlililyBoilers"

by Cremer, Mare A. and Wang, Huafeng D. (Reaction Engineering International), Boll, David E.

(AmerenUE), Schindler, Edmund (RIM Corporation), and Vasquez, Edmundo RMT, Ino, (A11iant

Square Du~e Electric Cooperative AI_53 Burns & MoDOIlIleil
NOx BACT Analy'is Study APPUNDlXAl

Toohnioal Foasibilily A,'t""1Ilenl Details fOT NOx Control Technologios

Energy Corp.), pre.,enled al2003 U.S. DOE Conferencc on SCR ami SNCR for NOx Control,

Pitlsburgh, PA, October 19_30,2003.

24 "Design and Demom;tralion ofRich Reagent Injections (RRI) Pcrforrrumec For NOx Reduclion at

ConnecIiv's BL England Sl<llion" by Cremer, Marc A. und Adums, Brucllcy R. (Reaclion

Engineering Intema~onal);O'Connor, DJvid C. (Electric Power Research "lnslilule); Bhamidiputi,

Venka i<l (Conccliv BL England S Inlion), ,me Brodcliek, R. Oi ffol"d (RJM C'-Orpomlion), presenled at

the 2001 US EPAJDOE/EPRI MEGA Symposium On SCR ~nd SNCRs, Chicago, IL, AugUSl 20-23,

2001. (available from REI's in[ernel web.ile http://\''iww.reaclion-cn~.eornldOl:!.);~loadslrrime.a.pdjJ

25 "Delllon,tr.:ltion ofRich Reugenl blJection for NOx Conlrol in AmerenUE'. Sioux Unit 1"by

Cremer, Marc A. and Adam" BrndJcy R. (Reaclion Engineering IntemallonaI), Boll, David E.

(AmerenUE), and O'Connor, David C (EJeelrie Power Research Institnle), pre,ented M lhe US DOE

Conference on SCRI.sNCR for NOx Conlrol, Pittshurgh, PA, Muy 15-16,2002.

26 "Evaluation ofCos! Erfeclive Non-SCR Options fOl"NOx Conlrol in PRB Fired Cyclone Boilers" by

Cremer, Marc A., Wong, David l-L and Adam!, Brodley It. (Reaction Engineering Imcrnat;onal);

Boll, David E. and Stuclaneyer, KCIlIle1h B. (Ame,enUE), presenled at the Western Fnels

Symposium, 19ib Internalional Confercnee On Lignite, BroWll, and Subhirumino\ls Coals (formcrly

Low-Rank Fnels), Oclober 12"14, 2004, Bil1ing." ML

27 "NOx Emi.<sions Bolow 0.15 lb/Mbtn Achieved in a Cyclone-Fired Boiler Usmg Tn_Furnoce

Control", by Cremer, M., Adams, E., und Chiodo, A., (Reaction ELlgineering International);

Giesmann, c., StnekmeY~T, K., and Boyle, J. (Am="llUE), presenled at the Powergcn Inlemalionul

2005 conference, December 6-8, 2005, Las Vegas, Nevada.

28 "Ash and Mercury Behavior in SCR CatJlysl' When Firing Subbituminous and Lignile COJls",

Energy & Environmental Research Center (EERC) ofLhe Universily of North Dak(}la", Benson,

Steven A., Laumb, Jason D., Crocker, (]larlehe R, ~nd Pavlish, John H. snbmitted for publicalion by

Fuel Proccs;ing Te<:hllology magazinc, 2004.

An edited version o[this pJper wa, pnblishcd as:

"SCR Cafa[ysl Performance in FIne Gases Dcri\'ed froln Subbituminou. 2nd Lignite CoalS" by

fud Processing Teclmulogy, Volume 86, Issue 5, 25 February 2005, Pages 577-6]]

Sleven A. Benson, Jason D. Lonmh, Charleue R. Crocker and 10hn H. Pavlish.

29 "In-Situ Mini SCR Reactor" stndy, available (for purchase from) Elecrrle Power Research Institnle

lllC.'S (EPR!'s) imernet websile at

hllp:!/WWW.wri.comln_ewslette•.asp?issucid=297305&ma.ketL.id-270619&1iITgefnid--=270677&\'.alne=

OST073.0

30 "Recent Experience With Hilachi Plale Type SCR Catalysl", Morita, lsato, Ogasahara, Toru

Franklin, lloward N., Babcoek"Hiluchi HK. and Hitachi Amerieu lechnical paper, pres~"Dled 10 The

In,lilu!e ofCIcun AirCompanie", Forum '02,February 12-13, 2002, Washington,D.C.

3\ "Perfonnance OfSe1eelivc Call1lylic Reduction On Coal·Fired Steam Generaling UnilS"U.S. EPA

Oroce ofAir and Radiation Aeid Raill Program Fin"l Report, (6204-J), Jnne 25, 1997.

J2 "Rolaling Opposed Fire Air (ROFA) and SNCR·" by Shilling, Mark ond Tonamaker, Gary (Carolina

Powel" & Light Co.), pr~smlCd at the 2002 DOE-NETL Conferellce on Unhurned Carbon On Utility

Flyash, May 14, 2002" I'itfsbnrgh, PA.

Burns & McDunn.a Al-54 Square Bulle Ele~rric Cooporative
APPENDIXAJ

Tochnical Feasibility Assessmenl Details rOTNOx Conlrol Technologies

NO" BACT A.oal~si, Sludy

33 "Injection ofUrea lhrough the Rotamix System to Obtain bnprovcd NOx Reduction~, by Ralston,

John and Haddad, Edwin (11obotee USA, Inc.), presented allhe 2003 UK DOE Conference on SeR

and SNCR for NO" Control, Pittsburgh, PA, October29-30, 2003.

34 "SCR Levels ofNOxRedudion wilh ROFA and Rotamix (SNCR) at Dynegy's Vermillion Power

Sta~on"_ by Coombs, Kristopher A. Sr. (Dynegy Midwest Generalion), and Crilley, Jay S., Shilling,

Mark and Haddad, Edwin (Mobolec USA, Inc.), presented at the 2004 Slack Emissions Symposium,

C]earwa"r Beach, FL, July 28--30,2004.

35 "First Commercial Installation ofAmIne Enhanced Fuel Lean Gas Rebum On Unils I and2 at Public

Service Electric & Gas Mercer Station", by Gomez, Andrew F. (Public Service Electric & Gas

Company (PSE&G) Mercer Generating Stlllion), Dainoff, Alexander S. and O'Leary, John H. (Fuel

Tech, Inc.), and Schrecengost, Robert (Energy Systems Associales), pr",enloo al the 2000 DOE·

NElL Conference on SCR and SNCRforNOx Conlrol, Pittsburgh, PA,:May 17-18, 2000.

Sqwrrc Butt<: EJoctric Cooperative AI_55 BtIJI\S & McDOIIIIeH

APPENDIXA2

u.s. NOx Control Retrofil Projects

A.2.1 • U.S. Cyclone NOx Reduction Projects Summary

NOx BACT Alllllysis Srudy

1962 vintage

eaSlOrn biluminous coal

-.-

SELECTIVE NON-CATALYTiCREDUCTIONIRICHREAGENTINJECHON

CYclone-Fired Boilers

Conectiv (formerly Al1antic Electric)

BLEngland Unil I Crushed Coal. single-wall cyclone-fired

138 MW B&W boiler aqueous urea SNCR, 1995 startup

Boiler has only 3 cyclone burners, arranged "lover 2" style.

RJM: implemented commercial Fuel Tech urea-based SNCR system installation in 1995 after short-lerm

(3-month demonstralion test) in 1993-1994_ 31 % NOx reduction claimed, from 1.311b1mmBlu NOx

baseJine(') for SNCR only; RJM: claimed 35%:reduclion from 1.311blmmBlu down 10 0.851blmmBtu

(withoul overfuc air) with urea_lo_NOx NSR = 0_85 (RJNr experience list).

Added eight lemporary RRI porls (three nozzles on each lower sidewall, and lwonozzles on the upper

rear wall, and performed one month demonstration pMameLric lcslIng ofoverfire air only (without SNCR

or RRI), at 120 MW nominal boiler load and cyclone S.H... = 0.90 in 1999. REI claimed 55% NOx

reduction from a 1.21bfmmBm uncontrolled NOx baseline to 0_551b1mrnBlu with OFA only, with sloek

CO emissions below 50 ppm_ For Rich Reagenl Injection; REI claimed 25-30% NOx reduction forRRI

down to 0.38lblmrnBtu fromconlrolled baseline wI OFA alone of0.55 IbJrrunBtu NOx and a IUU oreat<>-NOx NSR = 2; also showed RRl+SNCR wi OFA reduced NOx 55% [0 0.251b1mmBtu (34% beyond

RRI wi OFA), for an ovcrall79% NOx reduction with a SNCR urea-to-NOx NSR = 1. Measured less

than I ppm ammonia slip during Rill lesling, < 5 ppm slip for Rill + SNCR. No significant inorease in

CO emissions during RRI lCslin!?').

Source: ('JlCAC \¥hile Paper; RJM: experience list; (2)REI 2001 Technical Pap<::r.

Conecliv (formerly Atlantio Electric)

BL England Unit 2 Crushccl Coal, eyclone-lrrcd, single-wall-fired 1964 vinlage

160 MW B&Wboiler SNCR, 1996 startupeaslern bituminous coal

RIM implemenled commerc:iul Fuel Tech oren-based SNCR syslem in 1996, claimed 36% reduction from

1.361b1inmBlu down to 0.85 IbJrnniBtu, urea-to-NOx NSR= 0.85 (wilhout overfirc air)(l)_

An OFA system was acldcd in 1998, resulting in NOx emissions of 0.33 IblnunBtu, for an overall

NOx rccluclion of76%.

Source: RJM experience lis\. (Also lisled in ('JlCAC White Paper).

AmerenUE (formerly Union Eleclrie Co_)

Sioux Unil I Crushed Coal, opposed_wall cyclone-fud 1969 vinlage

S(){I MW B&Wboiler Rich R""genlInjection demonstration testing in 2001

Boiler h,s 10 cyclone burners, arranged "2 over 3" style, on opposite walls, and fires a blend of85% to

50% western subbituminous (PRE) coal, with Illinois bituminous coal, petroleum coke, and lire-dcrived

fuel.

installed twenty temporary RRI ports (six nozzles on each lower sidewall, and four no=les on each fronl

and reaT wall), and performed one monlh demonslr':ltion parnmetrie testing ofoverfire air only and inilial

teslingwith RRl in August2001, followed by additionallCSling inMareh 2002, and Ibe second qnarter of

2004. Added 8 RRI ports (I in each sidewall, 4 in each front and rear wall) and 14 SNCRpons (5 on

upper front wall, 9 on upper TeaT wall) to lhe furnace in early 2005, followed by lhree weeks ofparametric

tesling and 3 dnys ofcontinuous testing ofRRl wilh SNCR and deeper-staged OFA.

Tested in Augusl2001 at lower furnace SR approx_=LO, 0.551bJrnmBlu wI OFA only, only 15% NOx

reduction wi RRI, zero smmonia slip.

Square Bune E1e<:lric Cooper.l.~ve Bums & MoDonnell
NOx DI\CT Afialys;s STUdy APPENDIX 1\2

U.S. NOx COfilrol Relrofil Pmjeol'

Tcslcd inMareh 2002 at lower f"mu~o SR upprox.~.95,from 0_J81h/mmBtu baseline wi OrA only,

achieved 29% NOx reduclion wi RRI <1o\'>'Il [0 0.27lhlrrnnBtu, NSR=J, zero mmnonia slip(3).

(assume blend o£PRB and Illinois bituminous coal w/lire-dcrivcd fuel nnd pelro!eum coh)PJ.

Operation in the .,econd qum-ln2004 showed actual stuck NOx '''''roged around 01'0.30 Ib/mmEtu with

O:rA ooly and lower furnace aL u cyclone SR around 0.88 hurning a 85% PRB, 15% minois #6

bituminous coal blend, presumably at 440 MW. Tbjg is a 75% NOx reduction from a 1_19 IblmmBtu pre_

conlrol b"sclinc. REI using CFD modellOgpredietc<l NO;,: <lown to 0.18 lblmmBlu wilh lUU+Ol'A, "nd

below 0.15 WiIh RR1+SNCR under similar deep cyclone air-SIaging (1.19 to 0_28 lbfmmBtu is 76%

reduction, 0.18 v., 0.28 i.' an addiiional3G% reduction wi RIU, and 0.14 vs 0.28 is a 50% reduction wi

RRI+SNCR, for un ovemH reduclion 01"88%)1').

Te.'t~d in May 2005 at 480 MWgwilh lower furnace SR approx. 0_85_0.88, 76-83% reduotion froln 1.2

Ib/mmBtu baseline down to a' low as 0.20 lb/rrnnBlu wi SOFA only firing 80% PRll, 20% U1inois 116

bimminous coal blend; addiliorulI15-J9% NOx reducjion w/RRI, to as low ns 0.15lb/mrnBtu from 0.20-

0.28 lblmmBtu baseline wi SOFA only al urea NSR varied between 1 and 4, wilh ooe ppm ammonia slip;

~chicvcd additional NOx reduction wi RRI +SNCR down lO O.121b1mmBlu, NSR=I, anunonia slip10

ppm or less. RR1+SNCR wi SOfA NO" reduction percentage vaned from 15% to 50% below SOFAonly kvcls, with NSRs between 1 and 4.5. SNCR alone had 13% (NSR~l) to 32% (NSR=1) NOx

reduclion willi ammonia slip around 1-2 ppm*-.

Source: (3) REI 2002 and 2003 Technical Papers; (')REI 2004 Tedmicul paper;*- REI2005 Technical

paper.

REBURN- GAS, CONVENTIONAL

Cyclolle.-Fired Boilers

ConslclMion Energy (formerly Baltimore Go, & Electric)

C.P_ Crane Slation, Units 1 & 2 (MD) Crushed Coal. cyclone-lJred, eaSIem bituminous coal

2 X 200 MW B&W boilers ([our cydoncs ""ch) 1%1, 1963 vintage

GE-EER Convenlional G"-S Reburn, 1999 startup

Ad<led gas ,upply piping, metering, haogers, supporlo; r~blJlll injc~lor" and cooling air ductwork, OFA

duclwork, injection noz:lles and wnll ports, field (assume ea,tern bituminous cool)

GE-EER olaimed Gas Rehurn willi OFA 10w=<1 NOx bcLween (,(J% and 65% from ba>elines of1.50

Ib/rrunBlu to b~lwcen 0.60 and 0.52 lb/mmBtu, at full load withrcbum operation. No claims ofperccnt

rebum fuel or percent OFA included in GE-EER's experience li,t

Another lechnical paper sho"lcd this inslallation ofCGR operated wiLh 25 p,,"ccnl rcbum [lid').

Source: Sept. 2005 GE-EER experience list; (S)DOE_NETL Scorecard on Reburning 6/1/2004 (from 2004

Rebum ClIlucrcncc).

City Wntcr, Light & Power

Lakeside Unil 7 Crushed Coal, front-wall cyclone-fired, midwestern bituminous coal

300,000 Ib/hr steam B&W boiler (approx. 33 MWG equivalent, two cyclones) 1961 vinlage

Springfield, II. DOE Clean Coal demonstralion projcct (includcd sorbent injection)

GE-EER conventional gas rehum wi OFA 1992 startup (CGR not currently operating)

Vendor c1aimcd to 10"lcr NOx by 66% from 0_95 lb/mmRju baseline to 032lbfmmBlu. A GE-EER 2004

technical paper ,howed 25% rebum fuel yieldcd minimum NOx emissioo"l.).

A DOE NEIL lechnical paper showed Ihis demonstration ofCGR from 5/93-10/94 (assume with OFA)

with 23 percenl rebum fuel rcdu~ed NOx 60% from 0.97 10 0_39IbfmmBLu ls).

Source: Sept. 2005 GE-EER experience lisl; (6]GE_EER 2004 Technical paper; (5)DOE_NETL 2004

Rcbum Conference Technical p"per.

E"slmanKoduk Company

Kodak Park Boilers 41 & 42 Crushed Coal, [runt-wall oyclone,fired, 1964 & 1966 vinl"ge

BOTII'l & McDUllJlcll A2-2 Square Butle Eleotric Coopcm(ive
APPENDIX A2

U.S_ NO~ Control Reuofil Projects

NOx BACf Analysis Srudy

~OO,OOO Iblhr steam B&W bQilers (approx. 50 MWe equivalenl, tWO 8-ft dia_ cyclones)

Rochester, NY eastern bituminous coal

B&W convenlionul gas reburn wi OFA December 1998, July 1998 slartups (still operating)

Corrnnercial installation ofCOR, with (I) gas burner added 10 each sidewall + (2) large and (2) small

OFA ports added to front wall above cyclones, utilizing higher rebum gas pressure (vs_ Boiler#43)

requires uo flue gus recirculatiou; (Very smull furnace wi cyclone SRnot <1.0J.

B&W claimed rebum with OVA lowered NOx by 50% from L20 IblrnrnBtu baseline to 0_6IblmrnBlu.

B&W graph shows 10-12% percentrebum fuel to achieve 0.61b1mmBtu and 23-24% reburn gas input to

reach O.33lb1rnmBtu NOll. (73% reduetion)(7).

Anolher lechnical papershowed NO~ lowered by 52% from 1.25 lbIrnmBtu baseline 10 0.60 IblmmBlu

with 18 penoentreburn fuel(i).

Source' (

1JB&W Tedmical Paper; (;lODE_NETI.. Scorecard on Rebuming 61112004 (from 2004 Reburn

Conference).

REBURN- GAS, CONVENTIONAL

CYclone-Fired Boilers, continued

EastmanKodak Company

KodakParkBoiler 43 Crushed Coal, front-wall cycloue-fired 1968 vintagc

600,000 Iblhrslcam B&Wboilcr (approx. 60:MWe equivalent., two cyclones)

Rochester, NY eastern bituminous coal

B&W couvent.ional gas rebum 1995 stllrtup (still operating)

Commercial installation ofCOR., with fiue gas reciroulation (FOR) for injection mass momentum wI (1)

FOR fan; (1) gas burner added to eaoh sidewall + (2) OFA ports added frout wall abovc cyclones. {Very

small fumacellow reaidence time wi oyclone SR not<l.O}

B&W claimed rcbum wilh OFA & FOR lowered NOx by 50% from 1.20 IblmmBlu baseline 10 0.6

lb!mrnBtu_ B&W graph shows 18% pcrcontrebumIucl 10 achicve 0.6 IblmrnBtu and 29% reburn gas

inp~llo reach 0-36Ib/mmi3tu NOx (70% reduclion)t7

)

Anollier teclmioal papershowed NOx lowered by 56% from 1.351bhrrmBtu baseline 10 0.60 IblmrnBlu

with 18 percent reburn [uellS).

So,u.;,e, [7j B&W Teohnical Paper; (5) OOE·NETI.. Scorecard on Rebuming 61112004 (from 2004 Reburn

Conferenoe).

Tennessee Valley AUlhority (TVA)

Allen Station Unit 1 erN) Crushed Coal, cyclone-fired (seven cyclones) 1959 vintuge

300 MW B&Wboilor PRB &westem bituminous coal blend fired

OE-EER Conventional Gas Reburn, 1998 slartup

Corrnnercial inSlalialion added gas supply piping. metering. hangers, supports; reburn injectors and

cooling air piping, OFA dnctwork, injection nornea and wall ports, field I&C devices.

Reburn with OFA claimed to lower NOx 65% from baseline 1.20 Ib/mmBtu 10 0.421b1mmBtu) at full

load wilh rebum operation_ No clailll5 ofpercenl rebum fuel included. (IVA also inslalled duplicate

OFA syslems on Allen Uuits 2 & 3 boilers). •

Another technical p"pershowed NOx lowered by 65% from 0.861b1rnmBtu baseline (to 0.30 IblrnrnBtu)

willi 7 percent rebum fud(5).

Source: Scpl 2005 GE-EER experienoe list; (5)OOE_NETI. Score<:ard on Rebuming 6/1/2004 (from 2004

Reburn Conference).

REBURN~ COAL, CONVENTIONAL

Cyclone-Fired Boilers

Alliant Energy (fonner1y Wisoonsin Power & Light)

Nelson Dewey Station Unil2 Crushed Coal, cyclone-fired, PRB coal

Square Bu~e Eleotric Cooperalive

1962 vinlage

Durns & McDonnell
NOxDACT An.lysis Study il.PPENDIX A2

U.S. NOx Contrul RctroJil ProjeCIS

110 MW 8&'1'.' bajjer ].cyclones across front wall, 4rebuffi hurners +

4 0[1A paris across rear wall, aligned verticany in co]urrm,.

US DOE Clean Coal DemonslrJlion projcct ofB&W's Conventional Coal Reburn, 1991 startup (since

disconlinued) added coal supply piping, reb\lm burners with fluc gas recircul~lion, OFA ductwork -I- duul

zone pOrls; coal feeder, pulverizer & PA fm, lcslcd withPRB nml biluminolls coals. (western

slIbbi!uminolls coal)

B&W tluimcd rebllm opCTulion lowered NOx by 57% from baseline of 0.83 mm81llto 0.J81blmmBtll at

flln 10ad(1). Approx_ 30% peroent oftolal fuel inpul oupplicd u, rcbum fuel. Inorcuscd Mil outpul by 10

MW, increased f1yash IlIlhurned c~rbnn by 4% (13·22% vs 9-18%), dccreased furnace exit gas

lempe,alure (FEGT), OFA ports lisled in B&W experience list.

B&W shows full load NOx "I/o reb\lm was 0.75 Ib/mmBtu, und 0.29-0.321bfrmnBlu wf PRB fuel during

reburn operation (57% decrease). At 75% 10~d, 0.64 vs 0.29·0.321b/rnrnBru. At 55% lood, 0,62 vs 0.29_

0.311b/mmBlu wilhout and with rcbum Jc1ivated(1).

Anoilier lechnical paper showed NOx lowered by 52-55% from 0,821bJrnmBlll baseline (10 0.~9-0.34

lb/rnmBlu) "'ilh 25-30 pe'Iccnlrebulll fud5).

Source: (7]2004 B&W Technical Paper; 1

5

)OOE·NETL 2004 Rebum Confcrcnee Tcchnical poper;

(')B&W casc hlOtory (from wcbsite, ,bled 1997).

REBURN- COAL, MICRONIZED, CONVENTIONAL

Cyclone-Fired Boil..s

£"slmJn Kodak Comp~ny

Kodak Park :I 15 BOller Crushcd Co~l, front-wall cyclone-fired, 1956 vinlage

400,000 lbJhr ste.m B&W boiler (approx_ 50 MWe equivale"" two cyclon",)

Roehcslcr, NY caslcm bituminous coal

GE-EER micronized coal rebum 1996 inilial Sla.rtllp (operolling since 1997)

DemOOSlI1llion projcc1 performcd with Dept. ofEnergy's US Clean Coal Technology Progralll- Project

added nue gas rec,cculatlOn for injection mass momentum, FGR [on and lWo micronized coal pulverIzers;

(6) rcburn coal injcclors addcd lo roar wall + (I) rebmn coal injector on each ofthe ,idewalls, wilh (4)

OFA ports added across rrontwaH above cycloncs(OJ. GE-EERdesigned Jnd fabricoted lhe coal injeclors

amI OFA porls. [E}(tremcly sm.ll furnace and low residence lime]_

GE-EER claimed rebum + OFA wi FGR reduced NOx by 50% from 1.20 lb/mmBtu baselineio 0.6

lb/mmBtu. No cl.ims ofpercent reburn fuel included_

Another lechnical papershowed lhi.'; demonsIra lion ofmicronized cool reburn from4N7-l0/98 10wCTC<l

NOx by 57% from 1.361bhnmBlu baseline (to 0.59 lhlmmBtn) with 17 percent rcburn fucl(5).

Source: (l')DOE TopIcal Reporl Number 14 (May 1999); GE-EER experience list;(;)DOE-NETL 2004

Rebllm Conference Technical paper.

REBURN- FUEL LEAN GAS REBORN

Cyclone-Fircd Boilers

Midwesl Geoemtion (formerly Commonwcahh Edisnn)

Joliet Station 9, Unil 6 Crushed Coal, opposed-wall cyclone·fired (nine cyclones)

340:M:W B&W boiler 1959 vinlagc, 1997 ,IJrtup (FLGR has since been decommis..,ioned)

Energy Syslem, N;soci.les dernomtr.ted 25-30% NO;;; reducllon using 5-10% ofto!al beal inpnt as

reburn naturJl g;lS injcclc<l (wilhou! OFAl5).

Another teclmical paper showed this demonslralion in colbborolion witb Gas Researcb Institule ofFLGR

lowered NO>:. by 28·43% from U61bJrnmBtu baseline (to O.59lbJrnmBlo) wilh 7 percent rcbum fud'Ol.

Source: ('J DOE-NhlL Scorecard on Rebuming 61112004 (from 2004 Rebum Conference);

(10) NGB Tcclmologies Technical Pupcr.

"'.

Bum' & Md)onncll Sq= Bune Elct:lrio Cooper.live
APPENDIXA2

u.s. NO~ Coniiol Retrofit ProjeclS

NO>: BACT Analysis Study

1965 vintage

Crushed Coal, front-wall cyclone-fired

(lhree cyclones)

REBURN-FUEL LEAN GAS REBURNwlSNCR continued

Cyclone-Fired Boilers

Owensboro Municipal Utilities (KY)

Elmer Smilh Unit 1

150 MW B&W boiler

CFD model study only predicted NOx reduclions from 1.59 to 0.39lbfmmBtu with OFA only (75%

reduction, 0.90 SR); 25-30% NOx reduclion using 6% oftolal heat input as rebum natural gas injected

above OFA; 40-45% NO" reduclion from SNCIl with <5 ppm ammonia slip(Il).

Source; (11) REI Technical paper.

Separated OVERFlRE AIR

Cyclone-Fired Boilers

Tennessec Valley Authority (TVA) Crushed Coal, <:ydone-fJrcd, 1959 vintage

Allen StHtion Unils 2 & 3 (TN) (seven cyclones)

300 MW B&W boilers PRB &we,;lern bituminous coal blend

GE_EER OverfJrc air (duplicale ofAllen I), 1999 slartup

GE-EERciaimed 10 lower NO" with OFAalonc lip to 29% from baseline 1.20 IbfmrnBtll to 0.85

IblrmnBtu on Units #2 and 3 at full load.

Source: Sept. 2005 GE-EER experience lis!.

, ,

AmerenUE (formerly Union Electric Co.)

Sioux Unit 1 Crushed Coal, opposed-wall cyclone_fired 1969 vinlage

500 MW B&W boiler PRBflllinois Coal blend

Bol1erhas 10 <:yclone burners, arranged ''2 over r style, onoppooite walls, and fires a blend 0[g5% 10

50% western subbituminou5 (pRB) coal, wilh Illinois bituminous coal, petroleum coke, and lire-derived

fuel.

A lco-port OFA system (five ports on each front and rear wall) began opcr.ltion in mid_2001, which

reduced NO" emissions appro". 40-50% reduclion from 1.1-1.3 (assume average of 1.19) down to 0.7

IbJrmnBlu wilh moderate cyclone air-staging (cyclone SR from 1.19 10 1.0).(') Subsequentte.sting and

full load operation at deeper <:yc1one air-staging (SRs :s0.90) has dropped NOx with SOFA aloue 10

around 0.3lbfmmBtu in 2004<).

Source: (:l) REI 2002 and 2003 Technical Papers; «)REI 2004 TeChnical paper;* REI 2005 Technical

paper

Coal burning cyclone-fired utility boilers in the Uuited Stales thai have been retrofJtted with Separaled

Overfire Air CR technology are listed in Table A.2_I, A large majority of111e cycloue-flred boilers listed

burn western subbitumiuollS coal (or PRE blended with midwestern bitumiuous coal).

Square Bu~e Eleetric Cooperative BllIIIS & McDonnell
l\'O~ BACf Aualysis S~cly APPENDlXA2

U,S, NOx Control Retrofit Projects

TABLE A.2-1 - Cyclone-Fired Boiler Overfire Air Retrofit Installations(")

Facility Name Installalion Dale Comment.

SCR relrofit 511112004

SCR retroI1t 5/0 112003

Similar to Joliet 9 Unil6

SNCR demo May 2005

SCR rctroli( 5/011200I

SCR reLIofi15!01l2000

SCR relroill 311012004

SCR Tclrufil 1211712002

SCR Tctrofil6/0712002

OFA wi CGRretrol1l: has SCR

(Similar to Unit I. wlo CGR) h,ve SCR

(SinlilaTto Unit I, wlo CGR) h,ve SCR

Empire Di,trie~ BART-eligIble

SCR 10 be ,"smned in 2006-7

SCR retrofit 5/1112004

SCR retrofit 412312003

SCR rerron, 4/12/2002

part of conversiolllo PRE

previous SNCR ,elrolil in 1996

OFA wi COR relrolit

SCR retrofil 412112003

SCR lelront 410912002

Alkn Station Unils I Iasialled 199R·

Allea Smtion Un;l 2 Imlalkcl 1999±

Allea Slation Unit 3 Inslalled 1999*

Asbury Uoil I In,[,lled 5/10/1999

BaUly Unil 7 Insl,lled 2003(IJ)

Bailly Unll 8 [ru;l,lled 5!J112000

Baldwin Unil 1 .lru;lalled 12/31/1999

Baldwin Unil 2 Inslalled 5/&/2000

Big Slm,o UniI I l.JlSlall~...J 10/22/1997

BL England Unil2 InslaUed 1998~

CP Crane Unit 2 luslalhl2/111999

Colleen Unill Insmlled2f1l2001

Coffeen Unit 2 Inslalled 21912000

Edgowatcr Unit 3 Iuslalled 1112001''')

Edgewater Uni,4 Installed 61 j 9/2001

JoJiel9 Unil6 Installed 2000°>1

Kiaoaid Unil 1 Imirllled 412812000

Kiacaid Unil 2 Jnstallod 5/24/2000

Allea S. King Unll1 Jmlalled 1Jl30/1999

LaCygne Unit I Jmtalled 212812000

Lake Road Unil6 Imlal1ed 6/0112002

Michigon City Unit 12 Imlalkd 4/1998(ll)

Nelson Dewey Unit I lmlaJlcd 2002(llj

Nelson Dewey Uuir 2 Imlallcd 2002(ll)

Pal.dise Unit I Imlal1ed 11/14/1993

Paladise Uui, 2 1rrslancd 1218/1999

P310dise Uuit J lnslallcJ 5/412000

Powenon Unit 5-1 lru.lallccl 61112003

Powerton Ullit 5-2 lnstalJe<.l6/112003

Powerton Unit 6-1 In'tlIUed 61112002

Powertnn Unit 6_2 Inslalled 51411999

Schahfcr Unil14 InsmJIed early 2000(1J)

Siblcy Unil2 blSlalled 512412()()2

Siblcy Unit3 Inslalled 5/4/1999

SiollX Unit I Inslolled 4/301200 I

Sioux Uuil2 Inslolled 4130/1997

Slale Line Unil4 Installed 1112001(lJ)

Tannen: CrcdL Unil4 Installed 5/1212002

'l11oma, Hill Unil 1 bl5lalled Jnne 2004(1))

.lllOma, HiJJ Unil2 lusmlled Novembc.,- 2oocf")

NOle: 11tis lable does not include ovory m,irlJled U.S, coal_frred eyclone bmlcr OFA retrofit project.

Sonrce: (")US EPA Docket OAR-2002·0()76·0446 Technical Support Documentfor BARTNOx Limils for Ekctric

Generatiu£ Unils Excel Spreadsheel 611512005 (except OS uOled below)

Vendor eKpene""e IlSI (GE Encrgy lor Allen Station Unu, 1-3; RJI\1 rOT BL Engl.nd Unit 2)

(lJ) BlIttlS & McDollI1ell in!<:mal dalab,,,"_

Coal burning cycione-fired utiliry boilers in !he United Slales thai hnvc bcen retrofitted wilh SCR

lcchnology arc lisled in Tuble A.1-2. This lis! ineludes utlcas! eighleen eyeJone-fircd lmilors bwning

weslern subbilurninous ooal (or PRE blended with midweslern bituminous coal). Tho highest emission

Bums & McDonneU A2_6 SqO<lfe Bnne Elcetrio C".<lopenllive
APPENDIXA2

us. NOx Control Rctrnfil Projee!s

NOxBACT Analysis Study

....

reductions listed in Table A.l-l for SCR syslems arc for clean reactor catalyst and ideal opemting

conditions.

TABLE A.2·2 - Cyclone-Fired Boiler High-Dust SCR Installations

2003 Ozoue Se.,on

Unit AverageNOx

Size',M Tested Outlet NOxEmi"ion Rate'

F.ellily' W Tested CO':$OI Efl~SIOn Rate (lblmmBtu)

Emcien bltnnIlllu)'

Anenl.2.&3'~ 330 ea. 91.1iNAD'/88.7 0.07O!NAD'/0.088 0.088/0.071/0,086

Baldwin 1,,6 600' S2.9 0.072 0.238

Baldwin 2''- 605' 83.5 0.067 0.2a6

Bailly 8'" m NAD' NAD' 0.84

Coffeen I'" ,W NAD' NAO' 0.114

ColTeen2'" on NAO' NAO' 0.120

Dallman 3t & 32 ,~ NAD' NAD' 0,149/0.146

Kincaid I & 2'" 660' ea 89/89 0.079/0.079 Q t81/Ll9S

Marion4 m 94.3 0,067 0.252

Merrimack l'~ '" 50.5' 0.148 0.158

Merrimaok 2 ". 513' 0.155 0.171

MiclJigan Ci<y 12',,· "" 84.2 0.109 0.4 I 8

New Madrid t &2"" 600 ea, 87.4/88.1 0.149/0.147 0.31911.172

P=dise I & 2~' 704 ea, 87.7/87.7 0.10210.101 0.12410,113

Paradise 3'" 1150 89.1 0.088 0.658

&hahfcr 14,,'0 ''" S3.5 0.106 0.478

ongmal deSIgn fuel for all h,ted eyclone bOll"", waS b,lUInlUOUS coal

, - Generator nameplale rating, Marcb 2002 Energy Infonnalioo Administration :report

DOElEIA-0095(2000). Actual unitMW output rating may be higher or low",- lhan nameplate.

'- Bun1< & McDoDJIeU internal c.labase.

• - as reported to US EPA, available from their websile al hllp:/icfpub.epa.gov/gdmlindex.dm

, - includes applieation ofscparn.lccl overlrre air for combustionNOx control

, - cuneo! fuel believed lc be a blend of,ubbiluminous and bituminous ooal.

'-NAD no p~blisbed dola rrom SCR cmissio;' resting found 0.0 iliese unill;.

, - original air prelle.t",-, were tubular_type; changed 10 rolaI)'-~ during SCR retrofit

• - DesignNo,. removal elIiciency is higher, approx. 90%.

LO _ ourrenl fuel beJiovoo to be ,ubbitumincU-' coal

For MemmaokUnit I's SCR, inlet (i.e. uncontrolled) NOx was 134lblmmBtu, for a blend <>f

high sulfur biluminous and medjlJl1l. or low sulfur bituminous coals, arid requires year-round

SCR operation for compliance. The catalyst was designed for 88.9% NOx removal efficien~y

8qUBrC Butte Electric CooperatIve A2_7 BllTIlS & M~Donnell
NO"IlACT Analysis Shldy APPb"'NDIX A2

U.S. NO~ Conrrol Relrolil Frojocl,

and 5 ppm ammonia slip. SCR comm~Tcial5Crvicedate July 20, 1999. [(l<) Bahcock Borsig

Power 2000 tecbnical paper on SCRs].

For Merrimack Unil2's SCR, inlet (i.e. uncontrolled) NO:< was 2.66IblmmBtu, for a blend of

hillh sulfur hituminous anu :rm:uium or low sulfur bituminous coals, al1d reauires ycar-rolmd

SCll operalion for comrlian~e. Inilial lcsling demonstraled 70% removal(! ), which ex~ceu"d

!he 65% requircmenllo aehieve a 0.92 Ib/mrnBlu permit limit The cal.lyst was designed for

85-95% NO" removal efficiency and 5 ppm ammonia slipl"}

C"lNETL_DOE Clean Coal Technology 1997 kchnical paper on SCRs; (10 1997 ICAC Whilc

Paper on SCRs.

Northern lndiana Pobli" Service Company (NIPSCO)

Bailly Unit 8 Crushed Coal, cyclone-fired, oppo.,ed-wall-fired 1968 vinlage

360 MW B&Wboilcr Urea/ammonia ~onversion for high-dust SCR, 2004 startup

Boiler fires a blend of 85% western subbilllffiinous (PRB) coal, with ll1inOis bituminous ~oa1.

Commercial Fuel Tech urea-based syslem installed in 2004 to convert urea!o ammonia for injec~ng

reagent ahead ofboiler economizer outlet ~nd high-dust SCR. An OFA system was retrofit1ed in 2000(U!.

Source; Fuel Tech o:xperience lis! dated 1/28/2005; C'-'~ums &MeDonncll internal database.

Northern lndian. Public Service Company (Nll'SCO)

Michigan CiryUnil 12 Crushed Coal, cyclone"fired, opposed-wal1-fired 1974 viutage

520 MW B&W boiler Urea/ammonia eonvcn;ion for high-dusl SCR, 2003 startup

Boib fires w<;g[CTII subbnuminous (PRB) coaL

Commeroial Fuel Teoh nrea-hased syslem insl~lled in 2003 to convert urea to ammoni"- for injecling

reagent ah<:;ld ofboiler economizer oullet and high-d~sL SCR. An OFA sYSlcm was retrofitted in 1998CJ 3).

Source: Fuel Tech experience list da!cd 112812005;(Il)Bums & McDonnel1 internal dambasc.

Northern Indiana Public Service Compony (NIPSCO)

Schahfer Unit 14 Crushed Coal, cyclone-fIre<!, opposed-wall-fired 1975 vinlage

520 MWB&W boiler Urea/ammonia conversion for high-dust SCR, 2004 slartup

Boiler fires weslern sub bituminous (PRE) cooL

Commeroial Fuel Tech ure;l.-bascu syslem installed in 2004 to convert urea !o ammoni. for injecting

reagent ahead ofboiler economizer outlet and high-dus! SCIL An OFA system was retrofitkd in 2(){)0(\Jl.

Source: Fuel Tcch c.~pcricncelisl dated 1128/2005; (l'~ums & McDOIUlCU internal dolaha'e_

Bum' & MoDonncl1 A2_8 SquaTC Blitre Elemio Coopcrative
APPENDIXA2

US. NO" Conlrol Retrofit Projects

NOllBACf Analysis Study

,,"

TABLE A-3 - Low-Dust Pulverized Coal-Fired Boiler SCRInstallations

'CR Unit Size',

OpecalocIFaoj][ty',2 S[ac(np Ave"'gc NO" Emission MW

Oat.' Ral"" (IblmmBlu)

AEP/Cardinal Uni13' 5101103 0.74/0.34 I 0.135

""

CarolIna P&LiM.yo Unil 1

7 "/(0.36)/NIA 368,,2

Carolina P&URoxboro Uo1,4'" 5107101 0.57/0.26/0.081 372" 2

CinergylEasl Bend Unit 1 410J/02 _/(0.28)/0.067 M'

ConSlellatiun/Bnmdon Shores Unir I' (2001) OA7/0.33 10.126

'"

ConslelialionJBr.mdon Shores Unit 2' (2000) OA5/0.3110.094 '"

Dayton P&UKillen Station Unit 2 11101/03 _/(0.48)/0.06 ,..

DynegyMidwesl Gen/HavaTlU Unit 6" (2000) 0.46 10.20 / 0.102

'""

PSEG Power liC/ Mercer Uni, I" (2005) _/(0_63)/NIA ,,"

PSEG Power LLC / MeTCOT Unit 2" (201)4) _/(0_16)/NIA ,,"

BIlIIIS & McDonnell mlernal database.

2 Currenl fuel is eastern or midweslern bituminous coal, ""cept Ha"ana

] _ US EPA Docket OAR-2002-0076-ll446 Teohnical Support DooUIueOl for BART NOll Limits for

Elecrr:io Geoerating Unit.<; Excel Sp,-eadshee1 611512005, o"""PI where oored. Dales in 0 are believed

10 be occuralo bul have not been confirmed.

<_ The three values aro "Prc-control avorngc·', "2004 3nIlIlsl average", and "2003 07;:)ne .,eason av"",ge~

NO" emission TOlo" as n:por1<:d to US EPA. Pre..:oulrOl and year 201)4 UIJIlua! average data as 'hown

in US EPA Dode' OAR_2002·0076-0446 Technical Support Dooument fin BART NO,- Limits fo'

Electric GL"Ilmlting Unil'l Excel Spreedshee, 611512005, posled 00 their website:

http://dockeLepa,gov/edkpubldo!EDKStafl''emDetailView?objectld~0007d48084562b.

Values shown 10 pareotheses are year 2003 OIIIIual avenoge whe", 201)4 data i' DO' Rvall.ble. Year

2003 and 2003 ozone seawn data is available from lhe EPA'. web'ite "'

http;/Icfpub.ep;!.gov/gdmlinde".clin.iIIcludesapplication o[separnlcd overfire air for oOUlbustion No",

control where applicable.

, - Generalor namepl,'e rating, Mnn:h 2002 EneTID' InforrnaLion Admioislr3tion repon DOElEIA0095(2000). Aotual unit MW outpul rating may be higher or lower Ihan oameplate.

, _ This boil., has low_NO>< burno'" for combustion controls.

, _ Carolina POWCl '!< Lighl plants li:<tcd bore have lwo boilus per unJ" rolal nameplole fo' Mayo is 736

MW, Roxboro i.145 MW; emission numbo", arc the .verage ofboth boilers.

• _ This boil., has low_NO,- bum." and ove:rfrre .ir for oombu'tion control,.

, _ Ths is preliminary data reported 10 lhe US EPA for 201)4 ozone season overage emission note.

10 _ Thi' OOilOT's ourrem fuel is belIeved to be SIIbbituminons ooa1.

" _ Mercer hoilas li'ted have 10w_dllS' SCR wilh,flue gas rehear. Unit size is approximate, nol nameplale.

N/A compJolc 2004 owne seasOn dal3. is "'" avaiJRble. and 2003 ozone ,eason d'ta is not'epleseotative

of the po"_SCR installation emissioo rate.

Square BUlle Elcolrio Cooperative A2_9 Burns & McDonnell
NOxilACT Anal}'si, Srudy APPENDTXA2

U.S. NOx ConlrOl Retrofit ProjeCIS

SELECTIVE NON-CATALYI1CREDUC110N

Pnlverizell coal_fired boilen;

American Elcclrie POl'lcr (AEP) Pulverized Coal, cell-burner, opposed wall-fired B&W boiler

CardiI1lll Unit I 1967 vinLage; Low NO, burners imlallctl in OolobLT 1998

600 MW (nominal) Brilliant, Ohio

Fuel Tech urea-ba,ed SNCR installed in Oclober 19?8.

Fuel Tech, DOE, EPRI-mcmber ulililies SNCR demonstration project. Te,ted in March_Al'riI1999,

claimed 65% reduclion with LNRs + SNCR w/S ppm NH, slip, (from prc-LNB rclrofil basdine of 1.20

Ih/mmiltu*) down to 0.52 lb/mmBtu at 610 MW (100% MCR). SNC'Rrcduced NOx 31% below LNRs

alone (0.75 IbfnunB!u ba"eline), al 610 MWg (100% MCR), 34% reduction at 75% MeR (450 MWg),

and 41% reduction at minimum load (340 MWg, 55% MCR) ,,;5% ammonia slip("!, burning eastern

bituminous coaL Urea-to-NOx NSR not staled.

Source: Fud Tech experience lisL ,Iuled 112812005; (l)lCAC White Paper, (17) 2000 Fuel Tech technic~1

paper, *Riley Power (Babcook Power Illo) experience lisl 8116/04.

Carolina Power & Light (Progress Energy)

Asheville Unil I Pnlverized Coal, front wall fired

200 MWe nB RileybOller 1964 vintage, easlcrn biluminous coal, June 2000 SNCR starlup

fuel Tech commercial SNCR inslJllation claimed 25% NOx reduction from low-NOx burne, 1'1/0 OFA

baseline of0.58lb/mmlltu (down to OA41b/rrnnBLu on SNCR ulonc). Urcu-lo-NOx NSll nol stated.

(Also see FLGR + SNCR in"l.lIution summaries for pulveriud wal boilers).

Source: Fucl Tteh experience 11Sl dale(] 1/28/2005.

CJrolinu Powcr & Lighl (progrcss En~"Tgy) Pulverized Coal, Tangentially-fired

Cape Fear Unit 5 1956 vinlage; caSlern bituminous coal

154 MW CE boik"T SNCR startup in 2002

Mobotec USA "Rotamix" ammoma-hased SNCR oy,km injects aqucous ammonia liquid into a high

velocity boo"tc~ "cparalcu ovcrfrre air (ltOFA) system at the boiler.

CP&L !cohnioal paper daimed to lower NOx fromO.28lbfnunBtu bJSeline by43% to 0.16 Ib/mmBlu in

2002 with 5 ppm NIl, slip following the installation ofROFA in 2000.

Overall rcduclion 73% from full-load pre·ROFA bJseline 0.60 Ib/mmBtu to 0.16IblmmBtulLOJ.

Mobolec claimed further NOx reduction was possible by injecting urea in place of ammonia, ~chieving

0.13 lbfmmBtu inslead of0.18 lbfLnmBtu, which would bc 54% deereose from 0.28 IbJmmlltu with

ROFA alone, or 78% overall decrease("). Ammonia-to-NOx NSRnot staled.

Source: (18) CP&L 2002 Technicul poper; (l9) Mobotec 200J technical paper.

Curolina POW~T & Light (Progress Enerb'Y) l'ulverized Coal, Tangen~ally-lJred

Cape FearUnit 6 twin_furnaoe (clght comer), ]958 vinlagc; eaSlern bilurninou" coal

175 MW CE boiler SNCR ",",tup in 2001

Mobolcc USA "Rotamix" ammonia-bused SNCR syslcm, injecls aqueous ammonia liquid into a high.

velocity boo"ted separated overfire air ("ROFA") syslem at rbe boiler.

CP&L lechnioal paper claimed 10 lo\'lCT NOx from 0.23 Ib/rrnnBtu baseline by 22% 10 0.18 IblmmBlu

with 5 Wm NIl, slip following the mstal1alion ofROFA+SNCR in 2001(j,). Presentalioll slide graph

shows no reduclion [or Rornmix beyond ROFA alone al full load NOx emission raLe ofO.231b1rrnnlltu.

Ammonia·lo-NOx NSR nol slaled.

Overall reduction 67% from full-load prc-ROFA baseline 0.54lb/rrnnBlu to O_IS IbhnrnBLu.

Mobotec daimed further NOx reduclion was pO&liblc by injecting urea in place ofammonia, achieving

0.10 Ibfmnilitu inslcJd of 0.18 IbirrunHlu, which would be 56% decrcase from 0.23 lblrrmilltu with

ROFA alone, or 81% overall deoreaselL9l_ Urc,Ho-NOx NSR no! Slaled.

Source: tl8) CP&L 2002 Technical paper; (!OJ Moboteo 2003 technical paper.

Burns &. McDoQ/lell A2_10 Square BUlle Elocbic Cooperarlve
APPENDIXA2

u.s. NOx Control Retrofil ProjecL'

NOx BACf Analysis Study

Pulverized Coal, Tangentially-fired,

196D vintage; startup prior 10 20DO

'"

SELECTIVE NON-CA TALYTlCREDUCTIONcOlltinued

Pulverized cool fired boilers

Cinergy (fonnerly Cincinnati G&E)

Miami FortUnil6 (Ohio)

163 MW CE boiler

Fuel Tech urea_based SNCR syslem, claimed to ]owerNOx hy 35% from 0.55 IbJmmBtu

baseline(I).(assume eastern bituminous ooal). Urea-lo-NOx NSR nol slaled.

Source: Fucl Te~h experience list dated 1/2812005, (J) ICAC While Paper.

Conectiv (fonnerly Delmarva Power & Light)

Edgemoor Unit 3 Pulverized Coal, Tangentially-fired, 1954 vinlage

84 MW CE boiler mid-March 1996 startup; (assume eastern bituminous coal)

Hamon Research-Cottrell supplied a urea_based SNCRsyslem. HRC ~Iaimed 35% NOx reduction with

lessthan 10 ppm ammonia slip. Urea-lo-NOxNSRnot stilted.

AnOlher source shows a 30% reduction from 0_541b1mmBtu baseline(I),

Source: Hamon experience lisl (nollisled by Fuel Tech); (I) ICAC Whilc Paper_

Concetiv ([orm~rly Delmarva Power & Light) Pulverized Coal

Indian River Units 3 & 4 (Millsboro, DE) Unil3 is fronl wall-fired, 1974 vintage

178MW and440 MW Unit 4 is turbo·fired opposed-won, 1980 vintage

B&W, DB Riley boilers Spring 2000 startup (eastern bituminous coal)

HlIITlon Research-Cottrell supplied a lJrel-baood SNCR system (not lisle<! by Fuel Tech) on both units_

HRC claimed 35% NOx reduction with Jess than 5 ppm ammonia slip_ Urea_lo-NOx NSR not staled.

An-REI 1999 technical paper shows a pre-SNCR baseline of0.37 and O.44lbJmmBtu, respectively_ I>OJ

Another source lisled these unils as having a pre-control NOx baseline of0_97 and 0.57 IbJmmBtu, and

2004 post-SNCR startup average of0.32 and 0_33lbfmrnBlu, respeclively. (1')

SoUrce: Hamon experience list (nct listed by Fuel Tech); ('0) REI 1999 teohnical paper;

(12) US EPA Do~kcl OAR-2002-0076-0446 Exoel Spreadsheet 6fl 5/2005.

Dominion Generalion (Virginia E&P Co.) Pulverized Cool, Tangentially-frred

Clover Station, Units 1 & 2 (VA) ARB/CE boilers, 1995, 1995 vintage

2 .. 465 MW (easlern bituminous coal)

Urea_based SNCR(Fuel Tech system) 1995, 1996 slartup (initial oommercial)

Fuel Tech cluimcd NOx reduced by 25% from 0.321bfrnmBtu baseline (10 0.24 IbJmmBm).

Sour",,: Fuel Tech experience list daled 1/28/2005. Urea-to-NOx NSR not stated_

Dynegy Midwcst Generation (formerly Illinois Power) Polverized Coal, Tangentially-frred

Vennillion Station, Unit 1 1955 viIi.lllge

82 MW CE boiler, bituminous lllinois coal

Mobolec USA "Rotamix" urea_based SNCR syslem with rotating opposed fired air (ROFA).

Mobotec 2004 technical paper claimed to lower NOx.by 55% from 0221bJmmBtu baseline to 0.10

IbhnmBtu in April 2004 wilh urea-based RolaJnix SNCR and <:; 5 ppm CO. NH, slip nmmentioned

Overall reduction 83% [rom full-load pre-ROFA baseline 0_581bJrnmBtu to 0.10 lb/mmBtu(211. Urea-to_

NOx NSR notstaled,

Sour",,: (") Mobolec 2004 lechnical paper_

Square BUlle Eleclrio Co0p0,"llve BUIn'l & McDonnell
NOx BACT Analysis Study AP:PENDlX A2

U.S, NOx Control Retrofil Projecl'

Pulverized Coal, from wall-fIred,

1952,1952, 1958 vinlilge (easlern bil. coal)

SNCR slamp prior 10 2000

Sh'LECTIVE NON-CA 1'ALYJ1CREDUCTIONcORln/ue"

Pulverized ~OJd-fired boHers

Easlern Ulilitic< A"su~i~lcs, Pulverized Coal, T<lJ1genlially"fircd

Munl"llp El~clric Company 1959 vinlage

Somcrsct Uni1 8 (Massaohusetl.s) Summcr 1995 <IUIIUp

112 MW CE bOller (caslem biluminous coal)

Hamon Research-Coltrell supplied a urea-based SNCR (Fuel Tech system), claimed to lower NOx below

O.38lblmmBlu (Mass_ MCT). Urea-lo-NOx NSRnol slatcd.

Another :;ource listed 2R-IiO% NOx reduotion from n 0.49-0.89Ib/nmllllu \xlsclinc(1 ).

Source: llamon expelience jj,t, Fuel Tech experience list daled 1/28/2005, ll)lCAC "While Paper.

First Energy Pulverized Coal, TangeoliaUy-lired,

Easllake Unil3 (Ohio) 1954 vinlage

130 MW CE boiler (wI division wall) (easlern biluminous conI)

Urea-based SNCR (Fuel Tech system) SNCR startur prior to 2000

Fu~l Tech claimed to lower NOx fmm 20-32.5% from 0-34-0.40 lb/mmBlu ba:;elinc(l). UrcHo-NOx

NSR notstated.

Source: Fuel Tech experience list dalcd 112812005, [I) lCAC While Puper.

Fiml En~Tgy Pulverized Coal, waH-fired,

Sammis Unit 2 (Ohio) 1960 vinlage

lSO MW Fosler "Wheckr boiler SNCR slartup Fall 1999

Urea-based SNCR (Fuel Tech system) (easlern hituminous cnal)

Fuel Tech claimed to lower NOx from 25-30% from 0.45 lb/mmlltu baseline(l). Urea-ta-NCb, NSR nOI

S~lICd.

Snillee: Fuel Tech experience Jist dated 1/28/2005, (l)ICAC White Paper_

First Energy Pulver;7.ed Cmll, wall-fired,

Sammis Onils 6 & 7 (Ohio) 1969 & 1971 vinlage

680 MW B&W Universal Pressure boilers (c~stcm bituminous coal)

Urea-based SNCR (Fuel Tech syslem) SNCR startup after 1999

Fuel Tech claimed to lower NOx fmm 25% from 0-381b/mmllm baseline. Urea-10·NOx NSR nol slated.

SOllIce: fuel Tech cxperienc~list dated 112812005.

New Eogland Power Company (NEPCO)

Salem Harbor Station

UnllSl,2&3

84 MWe x 2. &. 15G MWo B&W bailors

Urea-based SNCR (Foel Tec" system)

Fuel Tech claimed 6G% (50-75%) NOx reduction from baseline of 1.0 ± 0.1 (range 0,85-1.12) lbfmmlJlu, (which

wonld lowerNO~ to aroood 0.34±0.071b/mmBtu). Urea-lo-NOxNSR nol slaled. {These NOxrednclioo

pen:emages may indudc imp"ol orlnw_NOx bumers). '

Source: F\lel Tech experience list dolod 1/28/2005, (lJ:iCAC Whir. Paper.

(Also see L"Nll iIlS",natiOO summaries for pulverized eool boile:r.;).

Northe"st Ulililies (formerly Public Service ofNew Hampshire)

Schiller Units 4, 5, & 6 Pulverized CoaV#6 Fuel oil, front_waH_fired

50 MWc X3FO:;lerWheeler boilers 1952, 1955, 1957 vinl"""

Urea.hased SNCR (Fuel Tech system) Colombian bituminous coal

August 1999 startup

RJM: implemented Fucl Tech urea-based commercial SNCR inslallalion on all three boilers.

Burn, & McDonnell A2-12 Square Bnu~ Eleclric Cooperalive
APPENDIXA2

U_S. NOx Control Retrofit Projeots

NOx BACT Analy,i, Study

"-

RJM claimed 50% reduction namO.50 IblnunBlu pre-SNCR baseline 10 0251bImmBlu for SNCRcoalfiring operation; NOx baseline 0.82 IblmmBtu prior to RJM's LNB modifications installed in 1994, 1992,

& 1994 (39% Tedllelion); Urea-lo-NOx NSR not slated.

Fuel Tech claimed 30% NO" reductimJ for SNCR from baseline of 153 ppm firing #6 fuel oil on Units 4

& 6 only,

Source: R1M experience list, Fuel Tech experience list dated 1/28/2005.

SELECTIVE NON-CATALYfICREDUCTION co",inuetl

Pulverized coal fired bollers

Owensboro Municipal Utilities (KY) Pulverized Coal, Tangentially-fired,

Elmer Smith Unit 2 1974 vinlage

300 MW CE boiler eastern biluminous coal

HomonResearch-Cottrell supplied an ammonia-based SNCR system but slaled nO claims for NO"

reduction; (this project is nollisted in lCAC White Papd'~. Annnoola-to-NOx NSR not stated.

Source: Homon experience list.

PECO Energy (formerly Philadelphia Electric Company)

Cmmby Unit I Polverized Coal, frontWlllI-fired divided furnace

160 MWe B&Wboiler 1954 vintage eastern bitmninous coal

RJM installed Fuel Tech urea-based SNCR with lowNOx burner modifioations & OFA in 1999, June

1999 startup.

RlMclaimed 29"/0 SNCR NOx reduction from baseline ofO.351b/rnmBtu, down to 0.25 lbJrnmBtu wi!h

urea NSR = 0_8; RJM provided burner modifications ofB&W XCL 10w-NOx. burners inslalled in 1994 +

OFA; !his reduced NOx from 0.50 to 0.351blmmBtu (30% reduction) ,vithoul SNCR. Urea-to_NOx NSR

not statedSource: RJM experience list; (lJ:[CAC White Paper.

Exelon (fonnerly PECO Energy! Pennsylvania Electric Company)

Eddystone Unils 1 & 2 Pulverized Coal Tangentially-fired,

318,333 MW each CE boilers 1999 SNCR startup, eastern bituminous coal

Fuel Tech claimed 30% NOx. reduction from baseline 0[0.26 JbJnunBtu.

Source: Fuel Tech experience list daled 112SJ2005.

1954 vintage

Public Servioe Enlerprise Group (pSEG) Power LLC [formerly Public Service Eleotric & Gas ofNew

Jersey (PSE&G)]

Hudson Stalion, Uolt2 Pulverized Coal, opposed-wall-fired, 1968 vintage

660.MWe Fosler Wheelerboilereastem bituminoUs coal March 1999 SUlrtllp

Fuel Tech urea-based commercial SNCR inslallation claimed 25% (inilial)NOx. reduction for SNCR

alone from baseline ofO_651b/mmBtu (do"'ll to 0.49lb1mmBtu)_ Urea-lo-NOxNSRnol slated.

Source, Fuel Tech experience list dated 1/2812005, also listed in (llJCAC White Paper. (Also see

FLGR+SNCR inslllllalion summaries for pulverized coal boilers).

Public Service Enterprise Group (pSEG) Power LLC [formerly Public Service Electric & Gas ofNew

Jersey (PSE&G)]

Mercer Station (2) twin-fum~ce boilers, 320.MWe each, DB Riley turbo-fired

Unil I and Unil2 frontwalJ PC, wet-bottom (slagging ash) eastern bituminous coal

Furnace #11 & #12 1960 vintage April 1999 slJrrtup

Fumace #21 & 22 1961 vintage May 1999 slartup

Fuel Tech urea-based commercial SNCR inslallation claimed ]0-35% NOx reduction from baseline 0[2.0

lbfmmBtu on SNCR alone, down 10 1,4IbJrrunBtIl_ Urea-to-NOx NSR not staled,

Sql1llrC Butte Eloclrio Cuoporalive A213 Bums & McDonnell
NO"BACT Aualysis Sluuy APPENDTXA2

u.s. NO" Control RelrOfil ProjeClS

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

S'llIrcc: Fuel Tech experi""ce list ualed 1/2&'2005; also lisled in ('1CAC White Paper. (Also sec

f'LGR+SNCR installalion summaries forpulvt.TIzcd cunl boilers)

SELECl1VE NON-CATALYTIC REDUCTION wlI/inued

.Pulveri~ed conl-fiHd builen

Reliant Energy (formerly GPU Genco) Pulverized Coal

(formerly Silhe, formerly l'enelec) Tnngcnlially-fired

Seward:; 15 (PA) mid.1990's SNCR startujl

Units 4 & 5 eastern hituminou, coal

62 & 156 MW CE boilers 1950 & 1957 vinlage

Urea-buseJ SNCR (F\lcJ Tcch syslem), later installed an in_duct SCR Lo reduce NH, slip.

Fuel Tech claimed 10 10werNOx 35% for SNCR only (55% for combined SNCRISCR from 0.78

lb/nnnB Lu b,,,cline). Boilers have since been demolished and r~l'laced wilh CFBs. Urea-lo-NOx NSR not

stated.

Source: Fuel T~"Ch experience lisl dated 1/21::12005, (l)rCAC While Paper.

Roohest~'T Gas & Ek,,!ric Pulverizcll Coal, Tangentially-fired

Ru"ellStation, Unils 1-4 (NY) 1948,1950,1953,1957 vintage

1 x 50 MW, 2 x 65 MW, 1 x 85 MW cn boilers e"stern bitnminous coal

Urea_based SNCR (Fue) Tech system) SNCR startup prior to 2000

Vendor claimed to lower NUx by 15-27.5% h-om 0.28 - 0.42lblrruuBlu basdines. Urea-to-NOx NSRnot

stated.

Source: fuel Tech experience list dated 1/2812005.

HYDROCARRON-ENHANCElJ AMMONIA SNCR (NO;rSIQrT")

Pulverized coal-fired boilers

TClUlessee Volley Authon ty (TVA) Pulverized Cnal hvin-fumacc, l:1ngentially-fired,

Kingston Power Sl<llion (rN) 1955 vinwgc castern bituminom coal

Unil9, 200 MWe CE boiler NOxStar"" sLllrlup Junuary 2002

DenlO",lra~on ofNOxStarTM hydrocarbon--cnhaneed ammonia-based SNCR installation.

Milsui Babcock clairne1l68% NOx reduction from baseline of 0.55 IbJrrunBtu down to 0.171b/mmBlu

with boosted OFA and NOxSlarTM wilh <: 5 ppm ammonia slip; NOxStarTM alone reduced NOx by

53%!2l1; boosted OFA only reduee<l NOx from 0.55 to 0.45 lbJmmBlu (18% reduction). Anunollia_Lo_

NO>: NSR not staled.

TVA's websile reportcd thaI "'an earlier "ernion ofNO"Star W"S inslolled at Kingston Fossil Plant Unit 9

in 2002 wirh mixed !'eSulls. NOx reductions were achieved, hut the boiler was damaged"

(hltp:/lwww.lva.gov/environmentlrepolrs!envreporlslaer12003/cnv_compliance.hlm)

Source: (U) Mil,ui Babcock Teehnie~l p"JPcr, October 200J.

Tennessee VaHey Authority (TVA) Pulverizcll Co"l, w"ll"fired

Colbert Station (AL) 1955 vintage

Unit 4, 192 MWe twin_furnace B&W bojlerwl FGReUSlern biluminous coal

First commercial in.tallation ofNOxStarTM hydrocaroon,enhanced anunonia-basell SNCR technology.

M;ISlli llabeockshowed 80% NOx reducLion from baseline ofO.50 10 O.iO 11)/mmBto; u,'ing< 0.1 % of

lot:ll boiler hear input for propune inpul and 1% ortolal steam now generated inlhe boiler for lance

cooling(2J); lOrN SNCR system startup. Ammonia-lo-NOx NSR nolstated.

Source: (Z)) Mitsui Bahcock 2004 Technical paper.

Burns & McDonnell A2-14 Square Bune Eleclrie Coop<rntive
APPENDIXA2

us. NOx CoolIol Retrofil Project.

NOx BACT Aoaly,is Srudy

Pulverized Coal, opposed wall-fired

cell-burner, 1969 & 1972 vintage

eastern bituminous coal

REBURN- GAS, CONVENTIONAL

Pulverized coal Hrcd boilers

Allegheny Power (formerly West Pennsylvania Power)

Hatfield's Feny Sta~on

Units 2 & 3, 600:MW (nominal) each (B&W boilers)

GE-EER Gas Rebum; 1999 5tartup (Unit 2) & 2003 (Unil3)

GE-EER Low NOx burners, boosled OFA, gas rebum system.

GE-EER claimed to 10werNOx up to 67% from ba,eline of 0.60 lblmmBtu 10 0.20 lb/mmBtu at fuJI load

with rebum operation on Unit 2, 68% from 0.62lb/uunBlU 10 0.20 lb!mmBlu on Unil 3. No claims of

percenlreburn fucl inclucled.

GE-EER lec/mical paper shows approx. 35% NOx rcduction al600 MW load with LNB + OFA wlo

rcbum fucl, and an addilional50% reduction to 0.20 IblrnmBtu wilh rebum fuel!2').

B&W added 20 OFA ports in 1994 per B&W's experience list. No NOx reducliou claims. SOUTce: Sept.

2005 GE-EER experience lisl; (2<) GE-EER 2004 Technical paper. Unit 2 and Unit3 Jjsted in 1')DOE_

NETL Scorecard on Rebuming 611/2004 (from 2004 Reburn Conference).

REBURN- GAS, CONVEN170NAL cOrlfi"""a

Pulverized coal-fired boilers)

Conectiv (formerly Delmarva Power & Light) Pulverized Cool, Tangentially-fired

EdgemoorUnit 4 1966 vintage, eastern bituminous coal

160 MW CE boilcr 1999 startup

GE-EER Gas Reburn projecl added gas supply piping, metering, hangers, supports, reburn injeclors und

cooling air piping; OFA ductwork, injection nozzles and waH ports, field instrumClltation. No FOR or

OFA boosIer fans.

Vendor claimed 10 lower NOx up 10 48% from baseline ofO.321bfmmBtu to 0.16 lbfuunBtu) al full load

with rebum operation. No claims ofpereCllt rcbum fuel included.

GE-EEIl. teclmical paper shows approx. 32% NOx reduction for gas rebtlm with4-mill operation al 160

MW load from 0.31 Ib/nunBtu LNB + OFA baseline wlo reburn fuel (down to 0.21 Ib/mmBtu),;rnd 48%

NOx reduction for gas rebum with 3-mil1 operation, to 0.161b/uunBtu (2<).

Source: Sept. 2005 GE-EER experience list: [2<) GE-BER 2004 TecJmical paper. Listed in (')OOE-NETL

Scorecard on Rebuming 6fl12004 (from 2004 Reburn ConfCTCncc)

Dynegy (formerly Illinois Power) Pulverized Cool, Tangentially-fud

Hcnnepin Unit 1 1966 vintage

71 MW CE boiler easlcm bituminous coal

GE"EER Gas Reburn, 1990 startup (nO! eurrenlly opemling); GE-EER Orimulsion Reborn, 1997.

DOE Clean Coal demoru;!ralion project (included sorbenl injcction).

Vendor claimed gas reburn wI OFA lowered NOx up 10 67% from baseline of 0.75 lbfnunBlu 10 0.25

IbfmmBtu) al full load; 65% reduction from baseline ofO.75lb/mrnBtu down to 0.26 lblrnmBtu with

subsequent Orimulsion reburn operation.

GE-EER 2004 technical paper shows 18% gas rebumfuel yielded minimum NOx emissions(6).

Another leclmical paper showed this 80 MW US DOE Clean Cool demonstration project in January 1991-

January 1993 lowered NOx by 67% from 0.75 IbfnunBtu baseline (10 0,25 lblmrnBtu) with 18 percent

rebum fuel(5).

Source: Sept. 2005 OE.EER experience list; (6) GE-EER 2004 Technical paper; I') DOE-NETL 2004

Rebum Conference technical paper, and DOE-NETL Seoreeard on Reburning 61112004 (from 2004

Reburn Conference). (Also see Conventional Oil reburn instaHation summaries for pulverized coal

boilers).

Square Bune Electric CoOI"'I1ltivc Bums & MeDmmell
NO" IlACf Analysis Srudy Al'PENDlXA2

U.s. NO" Control Retrofit Projects

RERURN·- GAS, CONVEN110NAL cOllli1l11ed

PQlverized coal_fired boilers)

AES (formerly New York Stme Gas & Electric (NYSEG)

Greenidg.e #6 (NY) Pulvcrizetl Coal, Tangcntially-fired, 1953 vinlage

100 MW cn boiler GE-EER Convcnlionnl Gas Rcbum, 1996 slnrlup

Vendor claimed 10 lower NO" 55% li'om 0.63 IhlmmBtu baseline 10 0-28lb/mmBtu al fulllond with

,-cbum operation buniing c",lern bituminous coaL OJ< Research In,titute predicted would achieve 76%

(down to 0.15 lb/mmBtu) "II advanced gns ,-cbllm.

GE-EER 2004 ledmica1 paper ,hows 23% ,-cbum fucl yic1<kd minimllm NO" emis~ion,"""md 0.23

Ib/rnmBt,i6).

EPA's "Sooreoard on Rebuming 6/1/2004" shows a 109 MW t-fired boiler (listcd as Greenidge Unil4)

lowered NOx by 50% from 0.50 IblmmBlu baseline (10 0.251blmmBlu) wllh 10 percenl robum fuel (no

longcr op"mling-) I').

Source: Sept. 2005 OE-EER experienoe list; ("l GE-EER 2004 Tcdmical pnpor; r')DOE_NETL Scorecard

on Reburning 6/112004 (from 200411ebum Conference).

Polomac Ekctric Power (formerly West Pennsylval1ia Power)

Chalk Point Slalion Pulver;z~d Coal opposed w"Il-[rrc(I B&W boilers

Units I & 2 1964, 1965 vinla.ge eastern bituminollS coal

360 MW (nominal) GE-EER Gas Reburn, 2000 startup

Vendor claimed 10 lower NO.~ up 10 43% and 45% from 0.60 Ib/mnilltu baseline to 0.34 and 0.33

Ib/mmBlU) at lull load wilh rebum op~'ration, respectively. No claims ofpercel11 rebum fuel included.

Source: 2002 GE-EER experience list. Listed in {')POE-NETL Scorecard on Rehuming 6/J/2004 (from

2004 Rebum Confcrcn~c).

Xeel Energy (formerly Pnblic Service Company ofColorado)

Cherokee Unit 3 Pnlverizcd co.l, wall"fircd, 1962 vinl"ge

175 MW B&Wboikr western. bituminous coal

DOE Clean Coal demonstmtion proj~cl November 1992-January 1995

Gas reburn demmlslrntion performed with Dept. ofEl1ergy and Gas Research Inslitute 1992-1995.

Existing boikT wilh 16 burners was retrofitled ,vilh low NO", burners and GE-EER gas rebum OFA,

FGR, and reburn injeclors. Added OFA boo,ler fan, 800 hp flue ga, recirculalion fan for inj"<:lion mass

mom~'TIturn, for inGreased gas injeclion JTlliSS momentum (which was subs"<]u""11y removed). TI,e CGR

installation portion has since been decommissiOl1ed.

Vendorclairned 10 low~r NO" up 10 64% from baseline of 0.73 Ib/mmBlu to 0.26 lb/mmBlu) at full load

WiIh rebum operalion.

GE-EER2004 l~~hnical pape"" "hows 15-20% rebum fuel yielded minimum NO" emissions{'J.

A 2004 DOE-NETL technical paper showcd thisprojecl achieved 0.46lblrrunBw NOx emissions wilh

]owNO", burners alone (31% reduction), furtl1er rc<1uced NOx by 44% wilh 12.5 perccnl,-cburn fud').

A2001 DOE-NEIL leohnical pap"T claimed a NO" reduction of65% at an average reburn gas heal inpul

of 18% of total boiler fuel inpu~ with and wilhout FGR- DemollSrralcd 70% NO" reduclion al higher

rebum inpul r"les. R~feITc<1lo lechnology as GR-LNB. FGR was added for gas injection mmnemUm bul

was subsequently removed to reduce fuel input. P'I

Source: SepL 2005 GE-EER experience lisl; I') (iE-EER 2004 Technical paper; (') DOE-NETI 2004

Rebum Conference lechnical paper:ll1d DOE-NETL Scorecard on Rebuming 6/1/2004 (from 2004

Rebum Conference);{''lDOE-NETL 2001 Technioal paper; also in (9) DOE 1999 Topical Report Number ".

BllIn' & McDonnell A2-16 Squ.re BUlle Electric Cooperalive
APPENDIX A2

U.S. NOx Control RClrofil ProjeClS

NOx BACT AnalYSis Study

""

REBURN-OIL, CONVENTIONAL

Pulverized coal-fired boilers

Dynegy (fonnerly JIlinois Power) Pulveri~edCoal, T3Ilgentially-fired

Hennepin Unit 1 1966 vintage, eastern bituminous coal

71 MW CE boiler 1997 slartup

GE-EER Orimulsion Rebum system wi OFA, claimed orimulsion rebum lowered NOx up (0 65% from

baseline ofO.751b/mmBtu 10 0,261blmmBtuat full load with Orirnulsion rcbum operation (installed after

gas rebum was <IemooslI1lted in early 1990's). No claims forpcrcent reburn fuel indnded.

GE-EER 2004 technical paper shows ro"J6reduction withsubs"'luent Orimnlsion reburn (6),

Source: GE-EER experience list; (0) GE-EER2004 Technical paper. Orimulsion not mentioned in (l)

DOE-NETL 2004 Rebum Conference technical paper orDOE-NEfL Score<:ard on Reburning 611/2004

(from 2004 Reborn Conference). (Also Sec Conventional Gas Rebum installation summaries for

pulverized coal boilers).

New BrunswiCk Power

Coleson Cove, Bunker CIOrimuision-lired, opposed-wall

St. John, New Brunswick, Con.da

3x 350MWB&WBoilcrs

Sixteen new low-NO;.; oil/Orimnlsion burners, eigbtrebum burners, nine SOFA ports, two combustion air

booster funs, reburn and OFA waH penelI1ltion openings, OFA windboxes, ductwork, dampers, and

accessories were added(1).

Another technical paper showed this reburn system lowered NOx by 78% from 1.0 lblmmBtu baseline to

0.22 IblmmBtu at 25 percent rebum fuel input(l).

Source: (7) B&W 2004 Tcclmieal Paper;(') DOE-NETL Scorecard on Rebuming 61112004 (from 2004

Reburn Conference).

Georgia Power Pulverized Coal, Tangentially_fired

Scherer Unit I 1982 vintage

887 MW CE boiler 2000 oil rebum slartlJp

GE-EER Oil Rebum syslem, claimed to 10werNOx from baseline ofO.361blnnnBtu.

GE-EER 2004 Teelmical paper shows reduction up to 48% (to 0.19 lblmmBrn).t 800 MW load with oil

rebum opemtion. No claims ofperoent reburn fuel included(2<J.

Source: Sepl2005 GE-EER experience list shows this as a coal reburn project with eastem bituminous

coal, reducing NOx emissions 33% from 0.36 to O.24Ib1mmBtu;

(2<J GE-EER 2004 Technioal paper. Not listed in (') DOE_NETL Scorecard on Reburning 61112004 (from

2004 ReblUU Conference).

REBURJIl- COAL, MICRONlZEiJ, CONVENTIONAL

Pulveri~ed coal_fired boilers

AES (fonuerly New York Stale Electric and Gas MlIliken Slation Unit I)

Cayuga tangentially-fired, pulverized coal, 1956 vintage

148 MWe, CE boiler eastern bituminous coal

GE.EER mioronized coal rcbumsyslem 1996 startup (still operating)

US DOE Clean Coal demonstmtion project fromMarcb 1997-Apri1199910weredNOx with this reburn

system by 29% from O.3S1bhnmBtu baselineto 0.2SlblmmDtu at 14 percentrebum fuel input(l). Not

listed in GE-EER's experience list nor in their 2004 technical paper.

Source: (» DOE_NETL 2004 Reborn Conference technical paper and DOE-NETL Scorecard on

Rebuming 611/2004 (from 2004 Reborn Conference).

Square Bune Electric Cooperative A2-17 Burns & McDoIIDeJ(
NOx BACT Analysis Smdy APP£NDLXA2

U.S. NOx Control Rerrofil Projects

LOW NO~ BURNERS (ReplacemeJ.t 01' modijicllliOJls) wim,d wlo OVERFJRE AIR conrfnued

Pulverized c,,~I-fired hoilers

DynegyMidwest Gelleration (fOJIDCrly Illinois Power) Pulverized Coal, wall-fired

Hav~na StallOll, Un;' 6 J978 vrnt"ge

~60 MW B&W builer, bituminous lllinois coal

GE-EERprovided mo<li.fiealions to the origm"l B&W dual_register bUffier" nnd an OFA syslcm in 2000.

VClldor claimed fun load NOx was unchanged Irom 0.381blmmBtu b.,clillo.

Source: GE"EER Experience list 211102. (Also sec low-dust SCR insLallation lisl for pulverized coal

boilers)

Dynegy Ml<Jwest Generation (formerly Jl1inois 1'0W~T) Pulverized Coal, Tangcnlial1y-fired

Vermillion Station, Unill 1955 vinlage

82 MW CE boiler, bituminou., Illinois coal

Tl,;S rolaling opposed fire"ir (Mobotec USAROFA) syslem w"s insLalled inJuly 2002, as part ofa

''RoLamixnSNCR + ROl'A system, wilhoullow-NOx burners.

Mobotec 2004 technical paper claimed to lower full10ad NOx by 62% from 0.581blmmlltu baseline to

0.221b!mmlllu in July 2002 (wilhollt LNB Qr SNCR). (21)

SOUlce: (2]) Mohotec 2004 tcchnLcal paper. (Also see SNCR ITIsta]1ation summaries fOJ pulverized coal

boik-rs).

Georgia Power Pulwrized ooal, opposed wall-fired,

Harlee Branoh Uni' [ 250 MW B&W boiler, 1965 vintago 2003 startup

Harleo Branoh Uml2 ]59 MW Riley boiler, 1967 vintage 1998 startup

B&W provided 24 DRB-4Z low NOx bumel'" for Unit 1 B&W bOller, 24 DRll-XCL low NOx hurner<

for Unit 2 Riley boiler (believe .,outheast eo"sllignite IS primary fuel).

Source: B&W's experience list. No NOx reduction claims.

Kansas City 1'0W~"f & Light Pulwri'l.<:d coal, opposed wall-fired, 600 MW B&W boiler

Hawthoffi Unit 5 30 bumers, 2001 vml<lge, (powder River Basin coal)

B&W provided 30 DRB-4Z low NOx burners and II OrA ports wirh thc ncw boiler.

Source: B&W's experience list. No NOx reduction claims.

- New EngJaml Power Company (NEPCO)

Salem Harbor Station Pulverized Coal, fronr waU-fired,

Units 1, 2 & 3 1952, 1952, 1958 vintage (eastern bil. coal)

84 MWe x 2, & 156 MWe B&W boilers LNBs slartup in 1995, 1995, and 1993

Riley claimed Unil 1 LNlls reduced NOx emissioru by 57% trom bascline of 1.10 Ib/nnl1Blu down [0

0.42 lb!mmBtu; Unit Ts LNBs achieved 42% NOx reduction from a baseline of 0.95 lb/mmBtu down to

0.55 lb!mmBtu; Unit 3'" LNBf; achieved 60% NOx reduction from a baseline of 1.051b!mmBtu down 10

0.421b/mmBtu.

Source: Riley Power (Babcock Power InG.) 8116104 experience lise

(Also see SNCR im:taHation summaries for pulverized coal boilers).

Northeast Utililies (formerly Public Service oINew Hampshire)

Shiller Station Pulverized CoalJ#6 Fuel oil, front-wall-Dred

Units 4, 5, & 6 1952, 1955, 1957 vintage

50 MWe x 3 Fosler Wheeler bol1e'"

RJM provided (6) Low NO, burner modifications per boiler in 1994, 1992, & 1994 respectively;

LNBs reduced NOx 43% from 0.85 10 0.48, 50% from 1.0 10 050, and 51% from 0.82 10 0.40 Ib!mmBtu.

Source: lUM experience lis!

BllIlIS & MeDonndl A2_22 Square Bulle Electric Cooperative
APPENDIX A2

US_ NOx ConlmJ Relrofit Projects

NOx BACf AnalY";" Study

LOWNO., BURNERS (Replacement or modifications) wialld wit> Of/ERFlREAIR confi'lUed

Pnlverlzed coal_fired boilors

Potomac Eleotrio Power (fonnerly West Pennsylvania Power)

Chalk Point Station Pulveriud Coal opposed wall_fired

Units 1 & 2 1964, 1965 vinlage eastern bituminous cool

360"M\V (nominal) B&W boilers

DB Riley (now BaboookPower) CCV type low NOx burnersretrofitted in 1993 and 1994, rcspectiveJy_

Vendor claimed 10 lower NOx up 10 52% and 50% from 1.35 and 1.40 lbhnmBtu baselines (1o 0.65;md

0.70 lblmmBtu, assumed at full load).

Source: Riley Power (Babcock Power Inc.) 8/16104 experience list. (Also see Conventional Gas Rebum

inslallation summaries for pulvcrized coal boil=).

Xcd Energy (fonnerly Public Service Company of Colorado)

Cherokee Unit 3 PuJveri:zed coal, wan-fired, B&W boiler, 16 burners, 1962 vintage

175 MW Oclober 1992 baseline lesling sl.arled (western bituminous coal)

Inslalled (16) Foster Wheeler Controlled Flow/SplitFI3IIle low NO, replacement burners as part ofa

DOE Clean Coal Technology gas rebum demonstralion performed with Gas Research Institute 1992-

1995.

Uncontrolled NOx wi original B&W flare-type burners was 0.73IblmmBtu. ReplacementLNBs

(assuming OFA included) reduced NOx 37% 10 0.46IblmmBtu(2..lJ.

Source: (lSI DOE NETL 2001 Technical paper.

A.2:2 Technical Literature References fot U.S. NO" Control Retrofit Projeets:

(I) SNCR While Paper, Institule ofGean Air Companies, Inc. (ICAC), SNCR Committee, May 2000,

Fnel Tech website httv:/lwww.fueltechnv.comlpdllTPP 534.pdf

l'lREI 2001 Teclmical Paper ·'Design and Demonstra~onofRich ReagenlInjections (RRI) Perfonnance

ForNOx Reduction al Conneoliv's B.L England Station" by Marc A. Cremer and Bradley R_ Adams,

Reaclion Engineering Inlemational, David C. O'Connor, Electric Power Re5earch Institule, Venkala

Bhamidipall, ConectivRL England Station, and R. Gifford Broderick, RIM C0'll0ralion, p~esented at

the 2001 US EPAJDOFJEPRHv:lEGA Symp05inm on SCRand SNCRs, Chicago, IL, AUglJ5l20·23, 200!.

(REI website htlp:/fW'iVW_reaction-eng_comidonwloads/rri mega.pM

P)REI 2002 Technical Paper "Demonslrlltion ofRich Reagent Injection CorNOx Conlrolln AmerenUE's

Sioux Unit I" by Marc A. Cremer and Bradley R. Adams, Reac~on Engineering International, David E.

Boll, AmerenUE, and David C. O'Connor, Electric Power Reseurch Institute, presenled atthe US DOE

Conferenoe on SCRJSNCR for NUx Control, Pinsburgb, PA, May 15-16, 2002; and

REI 2003 Technical Paper "Improved Rich Reagent Injection (RRI) Performance ForNOx Control In

Coal Fired Utility Boilers" by More A_ Cremer and Hnafeng D. Wang, Reaction Engineering

International, David E. Boll, ArncrenUE, Edmillld Schindler, RJM CorpOIlllion, and Edmundo Vasquez,

RMT, Inc., Alli""t Energy C0'll_, presented al2003 U_S. DOE Conference on SCR and SNCR forNOx

Control, Pittsburgh, PA, October 29-30,2003.

(dJ RET 2004 Technical paper, '·Evalua~on of Cos! Effective Non-SCR Options forNOx Control In PRB

Fired Cyclone Boilers" byMarc A. Cremer and David H. Wang, and BraclleyR. Adams, Reaction

Engineering Inlermtional, David E. Boll and Kermelh R Stnckmeyer, AmerenUE, presenled at lbe

Western Fuels-SympOSium, 19"' International Conference on Lignite, Brown, and Subbituminous Coals

(fonnerly Low-llimkFuels), Oclober 12-14, 2004, Billings,:MT_

Square Bull<: Elecme CoOV'mnive AW BIlIIIS & McDonneU
NOxBACf A~aly,i5 Study APPENDlXA2

U.S. NOx Control Rerrolll Projccl'

* REJ 2005 Technical paper"NOx Emissions Below 0.151h/Mblu Achieved in a Cyclone-Fired Boiler

Using In-Furnacc Control" by M. C'rcm~T, B. Adams, and A Chiodo, Reaction Engineering lntemalional;

C. Giesmann, K. Stucloneyer, and J. Boyle, AmerenUE, presenled at the PowerGen InlematlonJ12005

conference, December 6-H, 1005, r.as Vegas, Nevada.

('lDOE-NETL 1004Tedmical Paper "Rcbuming l'rojects in the Department of Energy's Clean Coal

Technology Demonstration Program", by Al Mann and Tom Ruppel, Parsons Corporation, and Tom

Sarkus, National Energy Technical Laboratory, presented at the 2004 DOE·NETT. Conference On

Reburning for NOx Control, Morganlown, WV, May IS, 2004. A rebnnHelated doenment (an updated

version of a po>1er lrom lhe May 18 Conference) is titled ·'Scorecard on Rebuming 61112004" by Al

MJnn and Tom Ruppel, Parsons Corl'oflltion, availabk on-line ~l:

http;l/www.n~ll.doe,govfpubliculiomjproceedings/04iNOxiposterslRebumillg%20Scorecard.lldf

(6) GE Energy 2004 TcdmicJI paper "Reburn Techllology Applioation Gnideli",:,,", by David Moyeda,

GE Enermr, presented atthe 2004 DOE-NETL Conference on Reburning for NOx Control", Morgantown,

WV, May IS, 2004.

('l B&W 2004 Teclmical Paper ·'B&W's Rebnming Experience", by H. Farzan, G. Maringo, A. Yagiela,

A. Kokkinos, Babcock & Wilcox, Co., presmted at the 2004 DOE-Nb~ILConference on Rebnrning for

NOx Control, Morguntown, WV, May lS, 2004. (This da.ta is n duplicate ofa more detailed lechnical

paper published earlier, ·'B&W's Advance On Cyclone NOx Control Via Fuel and Air Staging

Technologies", by H. Farzan, G. Maringo, D.W. Johnson, and D.W. Wong, Bubcock& Wilcox, Co., C-T.

Bcuro, Eastman Kodak Company, anu S.E. Brewster, Tennessee Valley Authority, presented at thc EPRIDOE-EPA Combined Urility AJr Pollntant Control Symposium, Atlanta, GA, Aub'Ust 16--20, 1999).

('jB&W case history "ll&W Cyclone Rebum Leads to NOx Reduction, Wisconsin l'ower & Light Co.

Nelson Dewey Unit No.2" (from website http://www.baboockcomipgg/ps/casebislorics.hlml, dated

1997).

(9) DOE Topicnl Reporl Number 14 '"Rebuming Technologies forlhe ContIol OfNitrogen Oxides

EmiSSions from Coal-Fired Boilers", conduoled under separate cooperative "greements between the U.S.

Dcpllrtmont of Energy, the Bubcook & Wilcox Company, Energyand Environmental Re,earch

Corporation, and New York State Electric & Gas Corporalion, May 1999.

IlO)Technical Paper "Predictions ofFLGR al Conunonwealth Edison·s Joliet Unit 6"' by NGB

Technologies, posted on their website: http://www.ngbteoh.comlsnbmt-gos/proJljoliel rcsults,hlml

(ll) REI 2001 Technical puper "CFD Evalnation ofFuel Lean Gas Rcbum (I'LGRTM) "nd Sclective NOll_

Catalytic Reduction in Owensboro MlITlicipal Utilities' Elmer Smilh Slation"', by DavidH. Wang, Marc

A. Cremer, and Bradley R. Adams, Reaction Engineering International, K.D. Frizzell, Owensboro

Municipal Utilities, and G.C. Dusatko, Sargent & LlITldy, 2001 US EPAIDOE MEGA Symposium on

SCR and SNCRs, Chicago, IL, Angust 20-23, 2001.

l"lUS EPA Docket OAR-2002·0076-0446 Technical Support DllCnment for BARTNOx Limits for

Electric Generaling Units Excel Spreadsheet 6/15/2005, poslcd on their website:

h!!P:lldocket.epa.gov/edkpnb/do/EDKStaffilcmDetaiIView?objectTd-090007d48084562b

(lJ!Bums & McDOImdl internal databJse.

Burns & McDonnell Al-24 Square Bu~e EleCirlc Coopcram'e
APPENDIXA2

u.s. NOx Control Retrofit Projects

NOx BACT Analysis Srudy

I") Technioal paper "Operating Experienoe and Future Challenges With SCR Applioations", by Gerd

Beckmann and Clayton A. Erickson, Babcook Borsig Power, Inc., presented atPowcr-Gcn International

2000, November 14, 2000, Orlando, FL.

(I') DOE NEll Technical paper "Control ofNitrogen Oxide Emissions: Selective Catalytic Reduction

(SCRl", Clean Coal TechnologyTopical Report Number 9, July 1997, posted on lheir weooile:

h®:I/www.nell.dce.govfpublicationsfolhersflopicalsftomcaI9.pdfs.

('0 SCR White Paper, Institute ofClean Air Companies, lnc. (ICAC), SCR Commillee, November 1997,

htlp:/Iwww.annnoniapm.comlArnmonia%20LibrorvINOx%20RcduolionfInslituleo/0200:£%20

Clean%20Air"/o20Co SCR.pdf, linked to R...M. Teohnologies websile hUp:l/'-V\VW.rmteoh.nctiartlcakhtm

(l1] Technioa1 paper "Cardinal Unit I Large Scale Selective Non-Catalytic Rcduction Dcmonstration

'" Project", by PatrickM. Malone, American Elcctric PowerScrvicc Corp, and Dr. William H. Sun, Fuel

Tech, presented at the lCAC Forum 2000, March 23-24, 2000, Rossyln, VA.

(l')CP&L 2002 Teclmical Paper "Rotating Opposed Fire Air (ROFA) ami SNCR", by :Mark Shilling and

Gary Tonamakcr, Carolina Power & Light Co., presented atthe 2002 DOE-NETL Conference on Unburned

Carbon on Utility Byash, May 14, 2002" Pittsburgh, PA.

(lO)Mobotec 2003 Technical Paper "Injeclion of Urea through IhcRotamix System to Obtain TmprovcdNOx

RcductiOIl'':'.by John Ralston and Edwin Haddad, Mobolec USA, Ino., presented at the 2003 U.S. DOE

Conference on SCR and SNCR for NOx Control, Pittsburgh, PA, October 29-30, 2003.

(l°iREI 1999 Technical Paper "CFD Modeling of SNCR Performance in Conecliv's Indian River Units 3

and 4~, by M. Cremer andM. Heap, Reaction Engineering International, M. Zoccola, Conectiv, and V.

Ciar1ante, .~hmon-Research Cottrell, presenled al DOE Conference OIl SCR and SNCR for NOx Control,

May 20-21, 1999, Pittsburgh, PA.

(21)Mobotec 2004 Technioal Paper "SCR Levels ofNOx Reduction with ROFAand Rotamix (SNCR) al

Dy!1egy's Vermillion Power Station", by Kristopher A. Coombs, Sr., DyncgyMidwC1ll Generation, and Jay

S. Crilley, Mark Shilling, and Edwin Haddad, Mobotec USA, Inc., presented at the 2004 Slack Emissions

Symposium, Clearwater Beach, FL, Jnly 28-30, 2004.

(21) Milsui Babcock 2003 Tei:lmical paper, "NOxSlarrM Plant Demonstration, October 2003~, by K.W.

Morris and G. Hcssc1man, Milsui Babcock (US), presented at the 20(l3 U.S. DOE Conference on SCR

and SNCR for NOx Control, Pillsburgh. PA, October 29-30, 2003.

("') Milsui Babcook 2004 Technical paper, "Installation ofNOxStarTM SystematlVA Colbert", by Keith

W. Morris, Mitsui Babcock (US), presenled at the Coal-Gen 2004 Conference, July 28_30, 2004,

Overland Park, KS.

(") GE Energy (fonnerly GE-EER) 2004 Teclmical paper "Experience with Reburn forNOx Emissions

Control", by Don Engelhardt, Roy Payne, David Moyeda, Blair Folsom, GE Energy, presented al the

2004 DOB-NEIL Conference On Rebuming for NOx Control, Morgantown, WV, May 18, 2004,

('S)DOE NEIL Technical paper "Evaluation oIGas Reburning and Low-NOx Bnrners on a Wall-Fired

Boiler ADOE Assessment", dated February 2001. DOEINEfL_200l/l143, posled on theirwehsite;

hlro:/lwww.netl.doe.govfcclclresourcesfpdfsfeercolGRLNBPPA.pdf.

Square Bune Electric Coopomtive Burm & MoDonneU
NO" BACT Analysi, Sludy

----~ .~. ~---~

APPE.,"DIX AI

U.S. NOx Control Relrofil Projecl'

1"1 GE Energy (formerly GE-EER) 2004 Technieal paper "Powerplaol mosaics: paving lhe way to 0.11

IblMMBlu withoul SCR", by B1~ir Folsom, GE Euergy, published inlhe March 2004 issue of Modem

Power Syslerru;.

1'7) NGB Technical P'lper ''Fuel Lean Gas Rebmn (FLUW"') Tedmology Jor Achieving NOx Emi"ions

Compliance: Application to a Tnngenli"lly-Fired Boiler", by Richard D_ Frederiksen, Werner J.A. Dalrrn,

and GrelarTryggvason, NGll Technologies, Inc., Bernan] P. Bre,,", RogerGlickert, andJosepb A. Urieh,

Energy Systems Assoemtcs, and John M. Pratapa' and Rohert V. Serauskas, Gas Research In,litute

(GRl), presenLcd allhe 1998 Joinl AmericmlJapane,e l'lame Research Committee InLemalionul

Symposium Environmental Control ofCombuslion Processes: Innovative TechnologyTowards [he 21~

Cmturv, Maui, Hnwnii, October] 1-15, 199R.

(")2001 Technical Paper "Application ofl'ud Leau G~s Rcbum Wilh SNCR On A 198 MW Coal-Fired

Ulility Boiler" by David Killen, Carolina Power & Light Co., John M_ Boyle and John H. O'L:ary, Fuel

Tech Inc., presented at the 2001 US EPAfDOEJEPRI MEGA Symposium on sca and SNCR" Chicago,

IL, Augnsl 20-23, 200 J_

!"'rcdmical paper ''First Commercial Jru;tallation ofAmine Enhanced Fuel Lean Gas Rebum On Unils [

and 2 at Public Service El,.,tric & Gas Mcrc~T Station", by Andrew F. Gomez, l'ublic Service m,.,lric &

Gas Company (PSE&G) Mercer Generaling Station, Alexander S. DainoFf and John H. O'Lcory, Fuel

Tech, hlC., and Robert Schrecengost., Energy SyS1CIIlS Associates, presented al the 2000 DOE-NETL

Conference on SCR nnd SNCR for NOx Control, Pittsburgh, FA, May 17-18, 2000.

Bums & McDonnell A2-26 Squore Bu~e Electric Coopermive
APPENDIXB

EERCREPORT

Ash Impacts on SCR Catalyst Performance

ASH IMPACTS ON SCR CATALYST

PERFORMANCE

f'Tepared by:

Sleven A. Benson, Ph.D.

Energy & Environmental Research Cenler

Universily "fNonh Dokota

POBox9018

Grand Forks, ND 58202·9018

00101><,2005

,

TABLEOFCOI\'TENTS

LIST OF FIGURES II

LIST OF TABLES III

EXECUTIVE SUI.\1I\iARY ES-l

INTRODUCfION 3

INORGANIC COMPOSITION OF LOW-RANK COALS .4

INORGANIC TRANSFORMATIONS AND ASH FORMATION .5

ASH DEPOSITION ON HEAT-TRANSFER AND OTHER SURFACES EXPOSED TO

ASH AND FLUE GAS 6

ASH-RELATED EXPERIENCES AT MRY FACILITY 7

History ofFurnacc Sbg-;:ingIFonling 9

Advanced Boiler Perform.nce Indice, _ , ' '.H.. _ , 9

ASH-RELATED IMPACTS ON SCR CATALYST PERFORMANCE 16

FuJl·Scale Slipslream Tesling _. .... _ __ .._ _ _ _16

SCRAsh Deposit Characterization __ . . 19

SCR Deposit Formation Mechanisms __ .. . _ _ 20

Low-Temperature Pyrosulf.tes _ _ _ 31

Condllsion: SCRIs Not feasible FOR NOx REDUCTION at M. r. yonog .34

REFERENCES 36
LIST 0" "[GORES

Figure I. Variability ofseleclc'tl comlitucnts in COTC analy," datooose p~vi<1ed by

ENI Coal, LId.•nd Minnkola co.1 Jalab"," _ _ . ________-._ 3

Figure 2_ OveraH processes of ash dcpo~ition typical ofa lignite- or

subbitumillolls-fircd boiler__ __ _ _ _.. .... ._ 6

Figure 3_ T'50 frequency dislribution for all Coal Quality Management System

(CQMS) dala, of _ _ _ .._ _ _ _ _ _ __ .. .._ .12

Figure 4. T", dislnbu1ion for HA Seam coal .. _ .

FiguTc 5. T"o dislTibution [or HE se.m coal

FlgIlTC 6_ T ~IO distribution fur KC seam coal ..

.. .. __ IJ

.... .......... 13

_____________.._..... 14

Figure 7. Vmiations in the delivered coal quality during a test bum period ..

Figure 8. Weight changes for PRB-blend coal ash exposed to Hue gases and

ammonia at three temperatures .. __ .. .. _ _

.. _ 14

_ _ 21

Figure 9. Weight changes for PRB-blend coal ash exposed [0 flue gases and

ammonia with and wilhout SCR catalyst presenl_ _ _..... .... .._ .. 22

Figure 10. Catalyst pres""re drop atB"I<lwin Station at 0 !o 2 montllS of operation 22

Figure II. C.lalysl pTe'5Ilre drop at Columbia Slation al 0 10 2 mo"ths ofopermloll ..... ...__.. ........ 23

Figure 12. Cata1y.,t I'r",,,ure drop .1 Coyole Stalion at 0 10 2 moutbs ofoper.rion ..

Figure 13. Pictures of eala]y~l inlet after abOlll 2 monlhs oflesling at each plant _.. _24

Figure 14. Pictures ofealalyst inlet afler about 4 months of expnsure [0 nue gas

andparliculate__ _ _ _.. __ _ __ .. _..25

Figure 15_ SEM iII1flges of...,h colleoted Oll c,ulysrsurfilee al thc Baldwin Slation

.fief 6 monlhs of exposure .. ._................... .. _ 26

FigUTI: 16_ SEM iII1flge, of",h collected on c,mlysl sllrface al ihe Coyole SLlInon

.1lcT 4 monlb, of e"po'UTI: _ __ .. _......................... . 28

Figure 17. Compari,on of eulT.inoo ",1, and deposiled ash on calaly'l for Culumbia Siallon _.. .. JO

Figure IS_ Medklnism ofSCR catal}"lt blinding vi' lhe formatIon ofsulf"lc" and

carbonalc' (modifiod arLer Pritohard .nd othe" POD 31
>

LIST OF TABLES

Table 1. Characteristics and Indices Calculated for Selected Center Lignite Samples

Table 2. Advanced Index Values fOr Other Coals (12)

iii

12

13
'-.'
ASH IMPACTS ON sca CATALYST PERFORMANCE

EXECUTIVE SUMMARY

The ash deposition behavior ofthe.lignites from North Dakota is the most complex and

severe ofany coals in the world, and installation of catalysts for NO, reduction is going to be

plagued with problems. The Center lignite fired at the MillonR. Young (MRY) Power StatIon is

highly variable in abundance ofvarious types of ash/slag-fonning components. Ash-forming

components consist ofinorganic elements (sodiwn, magnesium, calcium, and potassium)

associated with oxygen functional in the organic matrix and mineral grains (quartz, clays,

carbonates, sulfates, and sulfides). Upon combustion, the inorganic components undergo

chemical and physical transformations that produce intermediate inorganic species in the fonn of

inorganic gases, liquids, and solids. The alkali and alkaline-earih elements combine with

minerals during combustion, resulting in low-melling-point phases that cause a wide range oJ

fIreside deposition problems. In addition, the alkali and alkaline-earth elements also fonn very

small particles that are carried into the backpasses ofthe combustion system ITlld react with fiue

gas to form sulfates that can cause deposition, blinding, and plugging problems in selective

catalytic reduction (SCR) systems. This report analyzes these problems, and concludes that SCR

is not a feasible option to control NOx emissions at MRY Power Station because ofthe high

sodium levels present in the coal.

Following is a list of the key problems thal are associated with Center lignitc which have

not been overcome and, in our opinion, make the inslallation of SCR at lhe :MRY plant

technically infeasible [or NOx control.

» Blinding ofCatalyst Pores by High Sodium Compounds

X High levels of alkali aud alkaline-earth elements present in the coal flred at the MRY

plant produce small particles tbat reaclto fonn sulfates thal blind the catalyst pores_ The

high levels ofsodiurn in the coals combined with calcium will produce lowmelting-poinl eutectic sulfate compounds that win form and melt inside the pores ofthe

catalyst.

• Alkali and alkaline earth sulfates are enhanced by cyclone fired system. The cyclone

fIring results in partitioning ofthe ash between bottom slag and the body ofthe boiler.

The sulfate forming materials are more concentrated in the ash as a a result of cyclone

firin~

• Sulfule fonnalion is enhanced by lhe presence ofan SCR catalyst; this accel~tes the

sulfation reactions, causing blinding oflhe catalyst.

• The sulfate reactIons arc more severe at:MRY because ofthe high temperature where

an SCR would be installed. The higher temperature increases the rate offonnation of

sulfates and rate ofpore plugging.

• The testing conducted by the GelTIlans found catalyst deactivation ITllu blinding occurs

when firing coals with lignIte or brown coals that have ashes that are rich in alkali and

alkaline-earth elements..
• The findings by the Germans were confirmed by recent SCR ealalysl slipstream

lesting that showed significant evidence ofsodium and calcium-rich sulfate formalion

Ulat fill and ping the ealalyst at both lignile- and snbbitumiuous-coal-fired power

plants. The resulls oflhis fCcentlesting showed Ihal the presence ofsodium

signilicanlIy enhanced Ihe fOlllialion of bonding ofpartides and more rapid sulfalion,

filling ofpoTes, and rapid incrcage in pressure drop across Ihe calalyst.

• Deposit carryover, or "popcorn ash," plugging Ihe lop oflhe SCR cal.<llyst is a

signilieHlll problem because ofibe extremely high deposition rates ofme Cenler coaL

When firing Center coal, deposil..'l fOTm ,on various parts of the boilerrequiring

continuous sooiblowing_ The soolblowing ofupsIream heat-exchange equipment-...vill

cnuse deposil fragments 10 be camed back to the SCR calalyst., resulting in plugginl;-

In nddition, l!uring sootblowing ofthe SCR ealalyst, Ibe entralmnent ofdeposit

fragmenl.s along with the soolblowing media will result in significant erosion orlhe

catalysl surfaces.

• Recent lesting wilh subbituminous and lignitic conls indicaled a significanlly higher

level ofpore filling anl! plugging in the calalyst exposed 10 lignile ash as compare to

subbituminous coal ash. The catalyst pores as well as Ihe calolyst surface in the lignile

tests were completely coaled with a sodimn calcium sulfate material, while only pore

filling was found in the subbilnminous coal testing, The pressure drop across Ihe

cal.<llyst exhibited tor lignite was 4 10 5 limes greater Illan Ibat fonnl! fo, a catalyst

exposed 10 subbituminous coal osh. The plugging occurred over a 1000 hour test

period.

l> Cold Side SCR Installation

High-sodium lignite coal from the Cenler Mine Hagel A and B scam coal produces

significant levels ofhomogeneously condensed sodium sulfale Ihat pass through the ESP

nnd wei scrubber.

• TIlese small particles have been shown to pass through a wet scrubber and will

accumulate on surfaces oflail-end SCR systems. The accnmulated malerials require

sootblowing to remove the particulate and will result in incfCaged opacily.

• Liquid pyrosullate malerials lit temperatures as low as 535°F from sodium snlfale malerials

occurs in coal-fIred power systems and is well documented. Pyroslilfates will fann and

cause blinding oflail-end SCR devices_ Tn addition, SCR systems are known 10 calalyze

the formation of SO] from SOl_ The presence orso, signilicanlly enhances the

formation ofIhe pyrosulfitles.

,
",

ASH IMPACTS ON SCRCATALYST PERFORMANCE

INTRODUCTION

Ash produced during combustion of coal in conventional power systems is a major

problem that results in decreased efficiency, unscheduled oulages, equipment failures, and

increased cleaning. The many ways in which the detrimental effects of ash manifest themselves

in a boiler systcm include fireside ash deposition on heat-transfer surfaces, corrosion and erosion

ofboilerpmts, poor slag flow, and production offine particulates that are difficullto collect.

Decades ofresearch have been conducted to develop a bellerunderslnnding of the chemical and

physical processes ofash fOmJation and deposition in combustion systems. Overviews of ash,

related issues and compilations ofwork by many investigaLars can be found by referring to the

work ofMehta md Benson (1), Schobert (2), Baxter and DeSollar (3), Couch (4), Williamson

and Wigley (5), Benson and others (6), Benson (7), Bryers and Vorres (8), Raask (9, 10), and

Benson (11). This work has led 10 a detailed understanding of ash fOmJation and behavior in

combustion systems as well as thc development ofpredictive methods (12, 13).

The chemical composition and physical characteristics ofash-fonning or inorganic

components (mineral and organically associated elemenls) ofthe fuel(s) fired have an influence

on the following processes in the combustion systems:

• Firing conditions such as cyclone, pulverized coal, and low-NO, burners

• Transforrnatious of coal inorganic compouents to ash particulate and vapor-phase

SPCCles

Boiler design characteristies, including number oIburners, radiant seetion area, tube

bank spacing, access for cleaning, and number ofsootblowers

• Ash transport to henl"transfer surfaces in utility boilers

• Erosion wear and sticking

• Ash deposit growth and impact ou heat transfer

• Ash blinding and plugging ofselective catalytic reduction (SCR) catalysts

• Ash deposit removability

The ash deposition in North Dakota lignite-fired power pIa.uts is amajor problem that

impacts all fireside surfaces oIthe power plant. The ash problems are due 10 the variable and

complex nature ofinorganic components associated with lignite coals (2). Upon combustion, the

inorganic compouents undcrgo chemical and physical transfoJlI1ations !hat produce inl.ennediate

inorganic species in the fonn. ofinorganic gases, liquids, and solids. Duriug the gas-eooling

processes in the boiler, the gas-phase species condense and the liquid-phase materials solidify.

The abundance ofthese gas-phase and liquid materials entrained in tbe bulk gas flow is highly

dependent upon coal composition and system operating conditions. The inorganic materials are

traIlsported La heat-transfer and catalyst surfaces by diffusion, electrophoresis, thermophoresis,

,
and inertial impaclion. The particle sticking amI accumulntion rates are dependent upon the

quantity of ash and the abundance and viscosity of the liquid-phase components. In hightemperatnre regions ofthe boiler, high-Iemperalnre sodium--caIeium-aluminosilieale liquid

phases ad as the slicky material, causing deposit initiation, growth, IDld development ofdeposit

strength. As the temperalure ofIhe flue gases decreases, the condens.1tion and reaction of namevolatilized species playa nlllra significanl roJa in the fonnation of deposiL~ fi:um li!>'rile conIs.

The fOlllmtion ofsodium mdlor calcium magnesium sulfales dominales the deposit

accumul~tion mechanisms allower temperatures. The aluminosilicatc phases arc dominant above

aboul 1800"F- Below about 1800"F, Ihe slilfate phases become slable, with <In optimum

tempcrahlre offornmlion of about 1400°F, and Can fonn at lemperaturcs as low as 300°F.

The mosl significant problems thal prohibillhe successful operation ofSCR catalysts to

lignile coal is Ihe formalion oflow-temperature sodimn--calcium-magnesium sulfates and

phosphales Ihal will form on the surfices of catalysts and the carryover of deposils that will plug

the catalyst opening:;, resulting in increased pressure drop and decreased efficiency (14--16)_

INORGANIC COMPOSITION OF LOW-RANK COALS

lnorganic elements in coal occur as discrete minerals, organically associnted calions, and

calions dissolved in pore water. Thc fraelion ofinorganic componenls thaI are organically

associntcd varies with coal rank. Lowcr-ranhd ~llbbilUmino\lSand lignilic coals have high lcvels

of oxygen, which act a3 bonding sites for calions such as sodium, m<lguesiu\Jl, calcium,

potassium, strontium, and barium (other minor and trace elements may also be present in U1i~

form). In higher-ranked coals, bituminous and anthrncitc, inorganic componcnts consisl mainly

ofminerals. Mineral grains are usually Ihe mosl abundanl inorgnnie eomponenl in coaL The

major mineral groups found in coals include silicates, aluminosilicnles, carbonales, sulfides,

suIfales, phosphalcs, nnd some oxides.

The behavior of ash produced during coal combustion is related to the abundance, size, and

associalion ofmineral grains in the coal. In addition, Ihe association ofthe mineral grain with the

coal maLrix influenCES the temper~ture and gaseous environment Ihe mineral is cxposcd to during

combustion. A mineral associated with the organic part of a coal particle is said 10 be included. A

minerallhat is not associated with organic malerinl is referred 10 as excluded. The behavior of

Ibe organically associalcd clements, those elements thal are alomically dispersed in the coal

malrix, mnsl also be measured as 10 Iheir abundance in the coal. The organically associated

elements will reael and interact with the other ash-forming conslituents during eombuslion.

The Cenler lignile is higWy variable in abundance ofvarions types of ash/slag-fonning

constituents. Ash-fonning components In the Center lignile are oftwo lypes. TIle firsl fonn may

constitule up 10 50% oEU1c ash and is derived from inorganic elements (sodium, n13gJlesium,

calcium, and pOlassium) associaled with oxygen functional in the organic malrix onhe coal. The

second type consisls of mineral grains (sand, clay, limestone, and pyrilc). The minerals are

discrete particles ofash-fomring species and the sources ofsilicon, aluminum, iron, titanium, and

minor amounts ofthe clllcium and potassinffi_ The Cenlar lignite fired at the Milton R. Young

(MRY) plant has been examined eXlensively because oEilS problem wilh ash behavior. Analyses
'"

of as-fired and drill core samples have been conducted. The mean and the range ofselected

components are sho'IVII. in Figure 1. The results iudicate that both the abundance of ash and the

abundance ofmajor oxides in the ash vary significanUy. In addition, the abundance ofalkali and

alkaiine-e:Jrth elements (Na and Cal varied dramatically. Variations in Si were found to be the

most significant. High levels ofCa andlor Na were found for lower-ash coals as compared to

high levcls ofAl and Si associated with higher-ash coals (17, 18)_

00 -

c 00 •

<

0 ;0 --- - - - ---- - -- - -

• 00

00 -------- - - --- '" - ..-

"

00 - ---- ----- - -

2 00 f-- - - -- -- --- --- --t-I-- 0 1--

w

•

00

'" I I • ~- ~- AI,o, - ~- ~. ~.-

- -- SiD,- .- """,I:,,,,e _. .- •• d,,,,I>0,,, da"''''''''

'"

Figure 1. Variability ofash and selected constituents in core analysis database provided by

BNi Coal, Ltd. and Minnkota as fired coal analysis database,

The variability ofthe ash-forming components has been examined for the approximately

5000 samples characterized to date. Wide variations in ash contents and the major ash-fonning

constituents are observed. During lhe mining processes, !he inorganic components are mixed,

and some ofthe extreme characteristics are diluted (17).

INORGANIC TRANSFORMATIONS AND ASH FORMATION

The inorganic coal components Wldergo complex chemical and physicallransformations

during combustion to produce intermediate ash species. The inorganic species consist ofvapors,

liquids, and solids. The partitioning ofthe inorganic components during combustion to fonn ash

intermediates depends upon the association and chemical characteristics oftbe inorganic

components, ilie physical characteristics ofthe coal particles, the physical clurracteristics oflhe

coal minerals, and the combustion conditions.

The physical transformation ofinorganic constituents depends on the inorganic

composition ofthe coal and combustion condItions_ The inorganic components can consist of

organically associated cations, mineral grains lhat are included in coal particles, and excluded

mineral grains. There is a wide range ofcombinations ofmineral-mineral, mineral---coaJ,
mineml--cation--coal, and mincral-mincrnl- cation--coal assoc;alions in coal. Thcsc assoeialions

are unique to each coal sample.

The physical tmnsfOimations involved in fiyash Jonnation include 1) coalesccnce of

individual mineral grains within a char particle, 2) shedding ofthe ash particles from !he snrfaee

ofthe ch~rs, 3) incomplete coalescence due to disintegration of the char, 4) convective lnmsport

of ash from the char surface during devolatilization, 5) fragmentation oflhe inorganic mineral

particles, 6) [onnation o[ cenospheres, and 7) vaporizalion and subsequenl condensation ofthe

inorganic components upon gas cooling. As a result ofthese intcractions, lhe ash has a bimodal

size distribution. The submieron componenl is largely a re~llll 0 f the condensation offlamevolatilized inorganic componenls. The mass mean diameter orthe lllTger particles is

approximately 12 to J5 j.1m, depending upon the COol and combustion conditions. The larger-size

particles have been called the residual ash by some investigators (19) because these ash particles

:resemble, to a limited degree, the original minerals in the coal. Processes such as ash mineral

coalescence, partial cOi1lescence, ash shedding, and char fragmentation during char combuslion

and mineral fragmenlalion, all play an important role in the size and composition ofthe final fly

ash. Loehden and others (20) and Zygarlieke and others (21) indicate lhatlhree potentialmodcs

for fly ash gcncration can bc used to deserihe fly ash particle-si~.e and composilion evolutiou.

TI1C first, ·'Jine Emit," assumes that each mineral grain forms a fly ash particle and that the

organically associated elements Jom] fly ash particles ofless than 2 !-lIn. The second, ''total

coale8cence," assumes one fly ash pmticle forms per coal particle. "The third, "partial

coalescence," suggesls that the fly ash composition and particle size evolve beeausc ofparlial

coalescence.

The transfonnations of exclnded minerals m-e dependent upon !he physical characteristics

ofthe mineraL Excluded minerals such as qUoltz (Si02) can be carried through the combustion

sySlem with i[8 angular slruclUre still intact. Excluded clay minerals can fragment duriug

dehydration, mel!, and fonn cenosphercs. TIIC behavior of cxcluded pyritc depends npon its

morphology. Some ofthe pyrite maybc present as framboids. Frnmboidal pyrite may fragmcnt

more easily lhan massive pyrite particles_ Iu additiou, the decomposilion ofpyrile is very

cxothermie, and it transfonns to pyrrhotite and oxidizes to FeO, Fe30" and Fe20J during

combustioll_

ASH DEPOSITION ON HEAT-TRANSFER AND OTHER SURFACES EXPOSED TO

ASH AND FLUE GAS

TIle characteristics ofa deposit depend upon the chemical and physical characteristics of

the intermediate ash species, gcometry ofthe system (gas Ilow patterns), gas lemperature, gas

composition, and gas vcloeity_ Figure 2 ilJu8trale8 the ash deposition phenomena in utility

boilers. A8h panicle accumulations occur via transport of particles to the fireside surfaces (heat

u·mlsfer, ceramic materials, Sllpport materials, SCR catalysts, baghouse materials, and ESP wires

and plates) and sticking ofthe particles. The transport mechanisms important for ash deposition

includc small-particle mechanisms for particles less than 10 ).1m thal involve !hermophorcsis,

electrophoresis, and vapor-phase and small-particle diffusion; and large-particle mechanisms for

particles greater than 10 ).lIn thal involve inertial impaction. The ability oflarger particles to stick

depends upon the quantity and viscosity oflhe liquid phase on thc particle surface.
'" ...,,'cI: ,,~,.

C.'--"A''',

'" "c.. "y,.--

Thermophoresis is a phenomenon thaL involves Lhe transport of very small particles as a

result of a Ibermal gradient from hot gases Lo cooler surfaces. Electrophoresis is the lransport of

particles because ofa difference in charge. Vapor-phase and small-particle diffusion occurs in

lhe boundary layer next 10 the surface and resulLs in lransport of ash lo the surface. Inertial

impaction is a larger-particle phenomenon where the particles are ofa sufficient size and density

lo leave airflow patterns around the tube and impinge upon the surface ofa lube or deposit.

DeposIls thal fonn in high-lemperature regions ofthe boiler, such as the radiant secllon, are

called slag deposils. Deposits thal fOlm in lowcr-lempcrature regions ofLhe boiler, such as in the

convective pass on steam tubes and lower-lemperature surfaces such as SCR ClItalYSts, are called

fouling deposits. Slag deposits are usually associliled wilh a high level ofliquid-phase

components and are exposed to radiation from the llame. This is a description that many

researchers usc lo aid in classification of deposits since some engineers caH any type ofdeposit

"slag"" Slag deposits are lypically dominated by silicale liquid phases, but may also conlain

moderate to high levels ofreduced iron phases such as FeD and FeS. The liquid characleristIcs of

the silicates are highly dependent upon the quantities ofNa, Mg, Ca, K, and Fe ash on the

silicates_ In addilion, the inilialing layers ofslag deposits may consist ofvery fine particulate and

can produce areflective ash layer_ This phenomenon is especially evident when high organically

associated calcium subbituminous coal is fired. These coals produce small CaO particles that

usually fonn the initiating layers_

. -Fouling deposits fonn in Lbe lower-temperature regions of the boilers and, in most cases,

do not conlain the high levels ofliquid phases thal are usually associated with slagging-type

deposits_ Fouling deposits contain lower levels ofliquid phases as compared to slag deposils.

The fouling deposit liquid phases usually consist mainly ofsulfaLes thal bind lhe particles

together_ Fouling deposits typically form as a result ofthe reaction of gas-phase sulfur oxide

species with particles rich in alkali and alkaline-earth elemenls.

H-1!&.iL-'> :;,,-'_!J~ R I y"L':' Iltd...lD -;;=.,..~ - ;.;., c' '-'-~ -;,-01 ..;;;:;:;:: -_. - ,.\ -""'~" ", DO I-,~"_-r-,,,_ - ,_~7~""""" I,"," .."-

ASEt-RELATED EXPERIENCES AT MRY FACILITY

The MRY is a minemouth electrical generating plant located near Center, North Dakota

The station consisls oftwo units: Unit I, rated at 276 MWg, began produclion in J970; Unit 2,

rated at 506 MWg, began production in 1977. Both Dnits I and 2 are equipped with B&W

cyclone-fired boilers; lhe Dult 1 boiler has seven cyclones, lIIld the Unit 2 boiler has lwelve

cyclones. Annual station gross generalion is approximately 5.5 million MWh.

BN! Coal Ltd. is the sole coal supplier for the MRY Slalion_ Coal is mined from the ncarby

Ceotermine, which cOIlsisls ofthree dislinct scams varying from 2V.-9 feet thick. Coal is stripmined using two draglines and is loaded with front-end loaders and dclivered to lhe planl with

bottom-dump haul trucks. Annual coal production is 4_3 million tons per year.
, ,

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,

o

j

,

8

"

i

"

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"
History of Furnace SlaggingIFouling

Prior to 1991, besides annual mn.intenance outages, load reductions and forced outages due

to furnace slaggingjfonling were the largest cause ofproduction loss. In 1985, operating

guidelines were established that reduced furnace slaggingjfouling, including deslagging outages

scheduled every six months.

In 1991, a 3-month boiler cleaning cycle was proposed and initiated... The goal ofthis

program was to increase annual generation bynJ.Jining the units at higher sustained loads and

scheduling boiler-cleooing oUlages at3-monlh intervals_ However, furnace slagginglfouling

continued to have a significant impact ou plant operalions_ Success was measured in the number

ofproduction days between boiler-cleaning oulages_

During the mid-1990s, a major outage every third year was scheduled for each unit. In

addition, Unit 1 cleaning outages were scheduled for So-90-day runs (four cleaning outages per

year), and Unit 2 cleaning outages were scheduled for 65-75-day runs (five clcaning outages per

year). The problem was that furnace and conveetiou-pass surfaces gradually become coated with

ash deposits, which, over time, sootblowers cannot remove. Some ofilie contributors to the ash

deposits were as follows:

• Organically associated sodium is a primary contributor to deposition problems. Sodium

is vaporized in the cyclones and condenses on other ash particles, causing them to

become sticky and deposit at the furnacc exit. The problem is associated with sulfaie

fonnation and occurs in the convective pass, including the economizer_ Samples show

that sodium in the ash varies from 0_6'Yo-13_0%_

• Organically associated calcium is another component that causes deposition

problems. Unlike sodium, calcium does not produce a vapor-phase component.

Calcium does react with silicate (derived from clays) to cause low-melting-point phases

that produce wall deposits and deposits in the high-temperature regions ofthe

convective pass. Calcium also produces very small particles that will be transported to

heat-transfer surfaces, resulting in the formation ofthin, light-colored layers ClIlIed

reflective lIllh. These small particles of ash are carried through to the back passes where

they are sulfated and can combine with sodium to cause the formation ofstrongly

bonded sulfate-based deposits. Samples show lhar calcium in the·ash varies from 6_8'%-

24.0%.

• Clay minerals and quartz - Center lignite can contain high levels ofiJlite, which has a

J:3 AI;Si ratio and high levels ofpolassium, both ofwhich cause wall slagging and

high-temperature fouling. Quartz and other clays can significantly contribute to the

mass ofthe deposits. Samples show that ash content varies from 5.00/.,-25.5%.

Advanced Boiler Performance Indices

Advanced indices are used to relate the coal characteristics as detennined hy complltercontrolled scanning electron microscopy (CCSEM) and chemical fractionation to nsh behavior in

a coal-fired utility boiler (12), Fuel performance is estimated in terms ofslag flow behavior,

,
abrasion amI erosion wear, wall slagging, high-temperature silicate-based convective pass

fouling, lind low"tcmperature sulfate-based convective pass fouling. The following indices arc

used to assess the eITects of ash behavior on utility boilerperfonmlllCe:

• Convective-Pass Fouling Indices

Sulfation Index: Indicates the propensity ofdeposit to fonn in the convective pass ofthe

utility boilerin Ihe lemperature range from 1000°_1 750"F. This index is based On the

availability of alkali (Na and K) and alkaline-earth (ea and Mg) elements 10 react with S02

and SO, to form sulfates_ The sulfates are the primary materials Urnt cause particlc-toparticle bonding iII high·calcium coals. The sulfates are Ihennodynamieally stable at

temperatures below abontl650Q

F. Index values range from 1 (low) to 10 (severe).

Silicate Index: Indicates the propensity of deposits to fonn from 1600o_2400°F. This

index is related to the fonnatiou ofdeposits in which the silicate material is the primary

component that bonds the deposits together. The in/ormation used to derive the index

iucludes the size ofthe minerals such as quartz and clay minerals, availability ofalkali and

alkaline-earth elements, and viscosity ofthe silicate liquid phase.ludcx values range from

I (low) to 200 (severe).

• WaterwalJ Slagging

Slagging Index: Indicates the propensity of a deposil to fonn on the radiant walls from

2000" 3000"F. The basis oIthe slagging index is the size ofthe minerals (especially the

illite, quartz, and p)Tite), association oflhe calcium (calcite can contribute lo slagging),

and viscosity ofthe silicate-based liquid phase. Index values range from 1 (low) to 20

(severe).

• Wear Indices

Abrasion Index: This index indicates the potential for wear offuel preparation and

handling equipment. The wear is related to the hardness ofminerals in the coaL The

primary minerals of concern include quartz and pyrite. The index values range from 0.1

(low) to JO (severe).

Erosion Index: This index indicates the potential for wear of boiler parts due to the

impaction offly ash panicles_ "The erosion indelt is dependent npon the size of tbe

ash/mineral particle, size ofthe particle, and velocily oIthe particle. The index values

range from 0.1 (Jaw) to 1.0 (severe).

• Cyclone Slagging Index: 'illis index provides infolllmtion on the slag [low hehavior in

cycloues_ The factors that arc included in this index include the partitioning ofthe ash in

the cyclone based on size and association ofthe ash-fanning components in the coal.

The partitioning ofthe ash between the slag and enlnuned ash can significantly

influence Ihe .flow behavior oIthc slag. Standard panitioning eriteria have been

developed to provide the composition ofthe slag. The composition is used to estimate

the viscosity ofthe slag as a function oflemperaturc. The index values have several

ranges as follows: I (low viscosity), 1.5--2.5 (optimum viscosity), >3.0 (slag freezing).

W
• Strength Development Index: The strength index is based on the ability ofthe deposited

materia] to develop strength. Strength development is primarily dependent upon the

abundance and viSCOSity ofthe liquid-phase components in the deposits. Index values

less than 0_25 indicate tilatthe material will produce weak: deposits; index values of

0.25-0.34 indicate weak-to-moderate-strength deposits; index values of0.34-0.41

indicate high-strength deposits; and index values >0-41 indicate flowing slag.

Indices were calculated for a range of coals from the Centermine, and the propensity Ior

ash deposition in various portions of the boiler indicates wide variations, as shown in Table 1_

The BNI numbers indicate the location in the seams where the coal origiuated: Kinneman Creek

seam (KC), Hagel A (HA), and Hagel (BB). Each seam has a different distribution ofminerals

and organically associated elements that can have a significant impact on the formation of

deposits in the system. Comparison ofCenter lignite to subbituminous and bituminous coals

ITom other regions ofthe UnIted Slates, shown in Table 2, indicates significant differences in the

potentiallo form deposits in the boilers. In all cases, the lignite (not the worst coal from Center

mine) from the Center mine has n high propensity to produce deposi ts as compared to lhe other

coals_

Anotherindicalion ofthe variabIlity oflignites can be illustrated based on the calculation

of the temperature where the slag flow would occur. This is defIned as the T250 temperature,

where the slag viscosity is 250 poise. Frequency distributions ofthe T150 values for alllhe dala

for coals analyzed are illustrated in Figure 3_ Calculations ofT250 values for 1212 samples

obiained,.!i:om the Center mine database (J7J were made using empirical relations derived from

CCSEM and chemical fractionation data and knowledge ofhow ash partitions in the cyclone.

Figure 3 shows a bimodal distribution in the T250 based on the Urbain equation calculations.

The primary mode was at a value of2000°F. The secondary mode was at about 2700"F. The

results indicate that many ofthe coals have a sufficiently low T250 for good slag (]ow_ However,

coals with T250 at 2700°F are nol suitable for maintaining good slag flow_

Figures 4 through 6 illustrate the variations in T250 for the various seams of coals

characterized_ The HA and HE seam coals appear to have large numbers ofsamples, with T250

values at or near 2000"F. The KC seam coal, as illustrated in Figure 6, has extremely high T250

values. Based on these data, the KC coals are not favored relative to the slag flow behavior oflhe

~h.

Frequency distributions ofcyclone slagging index values indicated signifIcant variations in

slagging potentials ofcoals mined from the three seams, KC, HA, and HE. This information

proved particularly nseful in planning the mining and firing ofcoal from the KC seam.

During a July 1999 test bum, the composition ofthe cores was used to examine and

illustrnte the variability ofthe delivered coal quality based on basc-to-acid mtio calculated from

the ash composition. Figure 7 shows the variation in the base-to"aeid-ratio and the scam where

the coal was loaded.. The base-la-acid ratios were calcula!ed from core data that corresponded to

the location In the seam where the coal was mined. There is a significant variation in the baseto-acid mtio for the coals. The coals that have the highest base-to-acid ratio are typically from

the HA seam. HB seam coals generally have an intermediate base-to-acid ratio. KC or top-seam

coal has the lowest base-to-acid ratio. Lower base-to-acid-ratio coals typically produce slag wIth

high viscosities.

"
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,

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-0--

,

,

0 ," 0 , , 0 , , ,0 ,0 , co 0 0 0 , 5 !1 , 0

"

, , ;:; 0 , , e 0 , , , - , ,0 " , , ,, , , 0 0

" - " - " , " 0 0 0

- 0 0" 0 0

- ,, , , , -0

, 0 , , ,0 ,- -~"' ,

-0 0

" "- "" 0

" -, ,,, , , ,

-" , , , , , , 0

-, , ci " 0

_

- - - - , , -- 0 " - ::l , , , , - , -

, - , , -" -, 0

g -0

- -

0 , , , , " " , ", 0

--

,- • , " • • - ci - 0

-0

- , 0 - " --0

, ~~

,, 0 g , , 0

, ,,,,

J , , ,, - 0 0 0 - -, , ,, , " , , , - ,, 0 , 0 0 , • - , " 0

-0 , 0 - 0

-- " -- ,• , " , 0 0 • - • 0

, , 0 0 , 0 c,, g , , , 0

, - -

, 0 0 • , " - ," , , - , -• -0 " ,, • -- •• " - -- _

0 0 0 -- - " 0

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-.- .-" ci -

_

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Table 2. Advanccd Index Values for Olher Coals (12)

Advanced ltldices

Cyclooe SI.ggiog lodex

Conveclive Pas, Fouling

Silicale

Sulf.te

won Slagging Index

Erosion Index

Abrasion Index

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,

Lignite

NorthD.kota

,.•

61.8

4.09

9.28

0.15

0.71

Powder Rive{ Basin

"

23.99

2.88

1.85

0.17

1.96

Temperature, OF

Bituminous

Winots

10.36

•

1.53

0.14 ,."

Bituminous

Appalochian

"

14,21

o

1.66

0.17

1.96

FigureJ. T"o ireqnency distribution for all Cool QualiLy Management SysLcm (CQMS) data, "F.
"

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C

ill

, , rr

,l' ,

3 .-

,

't •

0 , a a a a a a a a

a a a a g a a a , ill ill , ill a - - - - - N N

Temperature, of

Figure 4. T,s,] distribution for HA scam coaL

'E"G sa",,,,I."'"

a

g

a

--<

"

,

,

,

0 , C

ill

, , rr

•

,

,

,

,

0

<Feo "",,,,,, GOO

0 0 0 0 a a 0 0 0 0 a a 0 0 0 0 0 a

0 0 g 0 a a 0 0

"

0 a a 0 0 0

"

0 a • ill , ill ill a N a v ill ill , ill 0 - - - - N N N N N N N N N a a

Temperature, DF

Figure 5. 1'", distnbulion for HB ,cam coaL
" '-,:,~; <'ii' n ,•,

Frequency

0

""

•

••

,

•

00

Base/Acid

"

" 1400

0b

'"

0

7/6/99iI

,

•

I

,

I 1500

,°

7/6/99

7/6/99I rl

.

I 1600

7/6199 1700

° 7/6/99

0, 7/6/99 ° 1800 °" 7/7/99 " 5' • 1900 7/7/99

7/7/99 :;;•

•0 2000

7!7(g9

,

mm ;:01 2100

•

"

3

"0

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,

u 2200

00'Om

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.

2300 'Om , 0,_

~7f8/99

"-

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0 2600

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[

! 7/12199 0 7/12/99 "OOf' fl.'!'!

Ii

7/12/99 3100 0 " • • • 0 " •

Coal 3-KC,2·HB, 1-HA
Figure 7 shows the sequence of deliveries beginning on July 6 ami ending on July 12,

2004. During Lhis peliod, the majority ofthe coal delivered was from the IrA scam, followed by

KC, and HB. Most ofthe deliveries alternated between KC and HA. Figure 6 shows several

instances where significant quantities ofKC coal were delivered, on July 6 through July 9. The

quanlity ofKC coal delivered will have the pOlentialto increase the viscosity oftlm slag and

result in poor slag flow from the cyclones.

ASH-RELATED IMPACTS ON SCR CATALYST PERFORi"lANCE

Ash-related impacts On SCR catalyst pcr[ommnee will depend upon the composition ofthe

coal, Lhe t}'Pe offiring systems, Due gas temperature, and catalyst design (14-16, 22)_ The

problems currenlly being experienced on SCR catalysts includc the following:

• Formation ofsulfate- and phosphate-based blinding materials on the surface of

catalysIs.

• Carrying ofdeposit frdgments, or popcorn ash, from other parts ofthe boiler and

depositing on lop ofthe SCR eatalysL._

Licata and others (14) eonducled tests on a SouLh African and German Ruhr coal and

found that the Gernlan Ruhr coal significantly increased the pressure drop across the catalysi .;::;

because ofthe acctunulalion of ash. They found that the Gennan coal produced a highly adhesive

ash consisting ofalkali (K and Na) sulfates_ In addition, thcy reporled that thc alkali elements are '!

in a water-soluble fonn and highly mobile and will migmte throughout thc catalyst material,

reducing aCLIve Sites. The water-soluble fonn is typical oforganically assoeiatel! alkali elements

in coals. The Gennan Ruhr Valley coal has about 9.5% ash and 0.9 % S On an asreceived basis, and the ash consisls mainly orSi (38_9%), A1 (23.2%), Fe (11.6%), and Ca

(9_7%), with lower levels ofK (1.85%) and Na (0.85%) (IS). Cichanosicz and Muzio (16)

summari7:ed the experience in Japm and Gennany aud indicated lbat the alkali elements (K aud

Na) reduced the acidity ofthe catalyst sites for tolal alkali contenl (K+Na+Ca+Mg) of80/0-15%

oftlle ash in Enropean power plants. They also found that alkaline-earth elements such as

calcium react wi th S03 on the catalyst, resulting in plnggillg ofpores and .1 decrease in the ability

ofNI-b to bond to catalyst sites. The levels of calcium in the coals that caused blinding rangel! >';

from 3%--5% of the ash.

The mcclmnisrns forthis t}'Pe onow-temperature deposition bave been examined and

modeled in detail at the Energy & Environmental Research Center (EERC) in work termed

Project Sodium and Project Calcium in the early 1990s; however, the focus ofthose projects was

specific to primary superheater and economizcr regions ofboiJers and not SCR systcms (22, 23).

Deposit buildup 0 r this type can effcctively blind or mask the catalyst, diminishing its reactivity

for converting N02 to N2and water aud potentially creating increased ammonia slip (14).

Arsenic and phosphates, which are not UnCOmmOn in low-rank coals, may also pl~y a rolc ill

caLalyst degeneration_ Arsenic is a known calalyst poison (14) in applications such as calalytic

oxidation for pollution control. Phosphotes can occnr in 10w-lemperahIrc ash <lep(lSits to creatc

blinding effects, and they also oecur with arsenic and can cause catalyst. poisoning (23).
".

.,

"

Lignite and subbiturninous coals produce ash that plugs and blinds catalysts (25-28). The

problems currently experienced with SCR catalysts include the formatiou ofsulfate- and

phosphnte-based blinding materials on the surfnce ofcatalysts and the c,arrying ofdeposit

fragments, or popcorn nsh, from other parts ofthe boiler and depositing them on top ofthe SCR

catalysts (14)_ The most significant problem tilat limits the successful applIcation ofSCR

catalysts to lignite coal is the formatiou oflow-temperature sodimn--calcium-magnesium

sulfates, phosphates, and possibly carbonates that will form au the surfaces of catalysts and the

carryover ofdeposits that wi1l plug the catalyst openings, resulling iu iucreased pressure drop

and decreased efficiency (14-16, 27-28)_ The-degree ofthe ash-related impacts on SCR catalyst

performance depends upon the composition ofthe coal, the type offiring systems, flue gas

temperature, and catalyst design (15-16, 24, 27-28).

In studies (7) the impac15 oftemperalUTB and the presence of catalyst on the ability ofash

to sulfate were examined. The tests were conducted using a thermogravimetric analyzer (TGA).

TGA testing was conducted using a <5-l'-m-size fraction of ash produced from Powder River

Basin (PRE) coals and lignites and exposing lhem to vapor-phase sulfur dioxide with and

without catalyst at several temperatures. The aim ofthe testing was to determine the potential of

the formation ofsulfates to cause particle-to-partlcle bouding that leads to the formation of

deposits in the temperature range where SCR catalysts are used. The TGA testing is focused on

-determining the reactivity ofllie <5-J.lm ash produced from selected PRB and blends 10 sulfur

dioxide mid gas-phase phosphorus species ns a function oftemperature_ Testing was conducted

';,to determine the weight gain with fiue gas containing armnonia. The impact temperature on the

weight gain due to the formation ofsulfates for a PRE blend is shown in Figure 8. The rates of

"sulfation were found to increase willi increased temperature_ The results show an increase in the

weig,ht gains when llllllllonia and phosphorus were added. Ground catalyst was mixed with PRB

and placed in the TGA. Increases in weight gain were observed when catalyst was added as

compared to baseline cases for 100% PRB, as shown in Figures 8 and 9, respectively. The

presence of catalyst enhauces the formation ofsulfates_

Full-Scale Slipslream Testing

More recently (8), the behavior of ash and mercury in flue gas produced from the

combustion oflignite and subbituminous COllis from the United States ofAmerica in selective

catalytic reduction (SCR) systems for nitrogen oxide removal has been examined. Typically,

these coals conlaln ash-forming components lh.at consist ofinorganic elements (sodiwn,

magnesium, calcium, and potassium) associated with the organic matrix and minernl grains

(quartz, clays, carbonates, sulfates, and sulfides), Upon combustion, these coals produce ash tbat

has an abundance ofalknli and allmline-eartb-rich oxide particles «5 !1m) that are carried into

the backpasses ofthe comhustion system and react with .flue gas to form sulfates and possibly

carbonates. The forms of mercury in the fiue gas produced from the lignite and subbituminous

coals are dominated by the elemental form. Slipstream testing was conducted at two

suhbituminous-fired power plants and one lignite-fired power plant to determine the impacts of

ash on SCR plugging, blinding, and mercury oxidation.
The SCR slipstream system consists oftwo pllmary componenls: the conlrol room and the

SCR reaclor. The reactor section consists ofa cotalyst section, [lJl ammonia injection system, [lfjd

sampling ports for NO, al the inlet and exit ofthe calalyst section. The conlrol room houses a

computer system th:Illogs dala and eonlrols the gas now rales, tempcratures, pressure drop

ncross Ihe calalyst, and soolblowing cycics_ The computer is progrmnmed to maintain constant

temperature oftlIe catalyst, gas Ilow rates, sooLblowing cycles, and ammonia iojeelioll_ The

computer is equipped with a mouem that allows for downloading ofdata and modilication ofthe

opcration of the reactor from a remote computer located allhe EERCl'lue gas is isokinetIealIy extmeled from the convective pass oflhe boiler upslream ofthe

air hcater_ The temperatllre is t)1lically about 790"F. Thc nue gases pass through a 4-inch pipe

equipped with sampling, Lhennocouple, and pressure ports. Ammonia is injected into the piping

upstream ofthe reacLor section. The reactor consists ofa sleeI housing that is approximately

8.5 inches squore and 8 feet long. The reaclor section has three components, including allow

straightener, a pulse sectIon Or sootblower, and a catalyst test section. A mctnl honeycomb is

used as a flow straightcner upstream ofthe catalyst section and is about 6 Inches long. A purge

scction was instn]]ed ahead ofthe catalySL test section to removc accumulated dust and deposits.

The catalyst test section is locaLed downstre3lll ofthe pnrge seclion_ The enlire catalyst section is

insulated and equipped with strip heaters for temperature conlroL The catalyst test section is

3.28 ft (1 m) in length and houscs threc catalyst seclions. Thennocouple and pressure taps are

located inthc purge sections for measnrements before and after cach section_

The induced-draft fan is used to extract approximately 400 acfin (200 sc.fm) offine gas

from the convective pass ofthe utilIty boiler to achi",ve an approach velocity of5.2 mls ',-'j'

(17.0 ltIs). The gas velocity is similar to that found in full-scale applications. The tolal gas flow

through the rcactor represents a thennalload of approximately 300 kW.

The range of operdting conditions for the reactor is listed below:

X Gas temperatllre: _700"_800°F

X Gas flow rate: 400-500 acfm

X Approach velocity range: 5.0-5.5 mlscc

X Ammonia injection rate: 0.5:1 with NO, level

X Tempering air for fan: - 50-200 scfm

X Calalysl dP, 0.5-1.0 inches water column

X Fan sizcd for up to 30 inches water coluum

The catalyst installed at the Baldwin aud Coyote Stations was the Haldor Topsoe catalyst.

Topsoc's DNX-series of calalysts comprises SCRDENOX catalysts tailored to suit a

comprehensive rimge ofproccss rcquirements_ ONX-series catalysts arc based on a corrugated,

fibcr-reinforced titanIum dioxide (TiO:!) carrier impregnated wilh the active componenlS

vanadium pentoxide (VI05) and tungsten trioxide (WO,). The catalysl is shaped to a monolithic

slructure with a large nllmber of parallel channels. The lJIlique catalyst design provides a highly

porous stnlctmc with a large surface area and an enstliug large numher ofae/ive silcs_ The pilch

ofthe catalyst was approximately 6 Illln_
The catalyst installed at the Columbia Station was a Babcock Hitachi plate-type catalyst.

This catalyst is a Ti02-based plate catalyst, developed and manufactured by Hitachi. The pitch of

the catalyst was approximately 10 rnm.

The coals produced ash that had significant accumulations ofash on the catalyst on both

macroscopic and microscopic levels. On a macroscopic level, there were significant observable

accumulations that plugged the entrance as well as the exit ofthe catalyst sections. On a

microscopic level, the ash materials filled pores in thc catalyst and, in many cases, completely

masked the pores within 4 months of operation.

The deposits on the surfaces and within the pores oflhe catalyst consisted ofmainly alkali

and alkaline-earth element-nch phases that have been sulfated- The resullE of this testing found

that the <5-flill ash rich in alkali Md alkaline-earth elements is captured on the surface and

within the catalyst pores. These materials react with S02/S0J in the flue gas, resulting in Ihe

formation ofa continuous phase that blinds the catalyst. The ability of elemental mercury to be

oxidized across the SCR catalyst was investigated at a North Dakota lignite-fired plant. These

rcsults showed no oxidation ofmercury across the SCR catalyst.

The reactor was installed at lheBaldwin Station and operated for a 6-month time period on

the HaJdor Topsoe catalyst. The information obtained from testing included pressure drop,

_sootblowing cycles, and reactor temperntures. Figure LO show lhe pressure drop across the

catalyst test periods from 0 to 2 months. During lhe fiISt two monibs ofoperntion, the pressure

was about 0.5 inches ofwater; at the end ohwo months, the pressure drop was about 0.8 inches

ofwater, indicating plugging had occurred. The air was pulsed a minimum ofevery 8 hours in an

attempt to maintain cleanliness. The reactorwllS monitored on adaily basis, and adjustmenlE in

pulsing cycles were made in order to minimize deposit accumulation. However, for the first two

months, the pressure drop steadily increased. There are several periods where the unit was taken

off-line; during those times, the temperature oflhe catalyst was maintained. At 2-month

intervals, a section of catalyst was removed and replaced with a new one.

For Months 2 through 4, the pressure drop was highly variable initially butwas ahout

0.8 inches ofwater. From Months 4 lhrough 6, the pressure drop was maintained between

0.6 and 0.8 inches ofwater. This is due to thc installation ofa fresh catalyst section and leaving

two thirds ofllie catalysts in place that were partially plugged. The gas velocity in the single

section ofnew, clean catalyst was high because of channeling, and the resull of the high gas flow

was less deposition and accumulation. Gas velocity has a significant impact on the potential for

deposits to form. However, at high gas velocity, low NO, conversion is likely.

The reactor was installed at the Columbia Stalion and operated for a 6-month period of

time with the Babcock Hitachi calalysL The infonnation obtained from the testing included

pressure drop infonnation, sootblowing cycles, and reactor temperature. Figure 11 shows lhe test

periods from 0 to 2 months. The pressure drop across the SCR upon installation was ahout

0.4 inches of water and increased to an average ofabout 0.5 inches ofwater, but ranged from

less than 0.4 to greater lhan 0.8 inches of water. The pressure drop for Months 2 to 4 iucreased

from about 0.5 10 0.7 inches ofwater because of accumulation of ash. Alter cleaning the reactor

and replacing one catalyst scclion, the pressure drop was about 0.3 but increased to over
0.6 inches o[water IIp to about4100 hOlIrS_ There was.1Il outage at the plant, aud aggressive

pulsing o[ the reactor was conduded; the pressure drop w>ls brought back dOWllto 0.3 but

rapidly increased to over 0.5 inches ofwater within 500 hours.

The snme reador that was installed allhe Baldwin Stalion was moved and installed at the

COyOle Statiou. In addilion, the same Haldor Topsoe catalyst lype WfiS used iu the reador_ The

reador was operated for a 6-month period oftime, Figure 12 shows the test periods from 0 to

2 months. As this papcris being prepared, the reactor is still operating on-site_ The pressure drop

across the catalyst lIpOn installation WfiS about 0.4 inches ofwaleL After only 750 hours, the

pressure drop was 1.5 inches ofwater, indicating significant plugging and blinding. Vcry

aggressive air pulsing was conducted, with lillle success in removing the deposits_ The pressure

drop for the catalyst was over two times greater than the pressure drop observed [or the Baldwin

Station utilizing the Same reactor and same catalyst. At about 1700 hOlies, the reador was

cleancd, and a sedion of catalyst was removed for characterization. The pressure drop after

cleaning was aboul 0.8 to 1.0 inches ofwatcr. The pressure drop did nol increase as mpidly

because of the higher velocities through the clean section ofthe catalyst.

The tops ofthc catalysts Were photographed during inspection and sampling ofthe catalyst

sections_ Figure 13 shows the ash materials that IIccumulated on the catalyst inlel afler 2 months

ofoperation_ The most significant accumulation was noted for the Coyote Stalion, followed by

Columbia and Baldwin. The Coyote Station had SOme larger pieces ofllsh deposit matcrial on the

surface as well as plugging,ofthe catalyst passages_ The Baldwin Station showed SOme obvious

deposition along the walls ofthe reactor and some accumulation on the inlet scctions_ The

Columbia Station showed more significanl accumulation and plngging than the llaldwin Statiou_

After 4 months, the tops ofthe catalysts were photographed during inspection aud

sampling oflhe catalyst scctions, as shown in Figure l4_ The most significant accumulation was

noted for the Coyote Station and SOme accumulation for the Baldwin Station_

SCR Ash Deposit Characterization

The characteristics ofthe ash malerials that collected on the catalyst surfaecs and pores

were charaderi7.ed by SEM and x-my microanalysis and, in selected cases, XRD WIlS used to -,-

determine (he crysmlline phases present. The catalysts were sampled afler 2, 4, and 6 monlhs_

The sections were sampled, and approximately 2.5,cm squares were mounted [or SEM analysis

011 double-stick tape and in epoxy resin. The double-stick tape samples allowed for

characterization of the external morphology ofthe particles and catalySl surface_ 111e samples

mounted in resin were cross-sectioned and polished, which allowed for more detailcd and

quantitative analysis ofthe bondirrg materials 'llld materials that accumnlated irr the pores ofthe

catalyst. Delailed infoml'llion on all the samples can be found elsewhere (add FPT reference).

Examples oftwo deposit and catalyst analysis are presented here.

The 6-morrth sample [rom the Baldwin Station showed extensive sllifation ofthe alkalincC<lrlh elements presenl in the deposits. Figures 15a and l5b show regions of the catalyst where all

the pores were blocked and a minimal amount ofdeposit on the surface ofthe catalyst. Figure
';>'

I . <>i ,

.

•--i

,'

15c shows a higher-magnification view oflhe deposilthat is filling the catalysl pore. The deposil

consists ofparticles offIy ash bonded logelher by a matrix ofcalcium- and sulfur-rich malerial,

lIkely in Ihe fonn ofcalcium sulfate. The chemical compositions ofselected points that indicate

Ihepresence ofhigh levels of calcium and sulfur are listed in Table 3. There is much more

extensive bonding ofthe materials with the sulfute matrix as compared to the 2-montlt sample. In

addition, there are some regions ofhigh levels ofcalcium, aluminum, and sulfur present. The

calcium alumimun materials are likely derived from the calcium aluminum phosphale minerals

found in Ihe coal fired allhis plant.

The 4-month sample from the Coyote Slation showed particles adhering to the surface and

filling pores in the call1lysl. Figure 16 shows Ihe 4-monlh sample from !be Coyote Station. The

catalyst showed partieles adhering lo the surface and complelely filling and masking the pores in

the calalyst. The exlernal morphology ofthe catalysl surface shows the masking ofthe catalysl

surface. Chemical compositions ofselected poinls are shown in Table 4, The 4-monlh sample

shows more sulfalion than the two months of exposure samples. Figures 16b and l6c shows a

higher"magnificalion view oflhe deposit that is filling the calalyst pore. The deposil consIsts of

particles of fly ash bonded togclher by a malrix ofsodium-, calcium-, and sulfur-rich material,

likely in the fonn ofcalcium sulfalc. Significant sodium was fOWld in the deposits, as shown in

Table 4. The sample shows significanl evidence ofsulfation after 4 months of exposure lllld was

much more pronounced lhan Ihe samples [or Ihe Baldwin and Columbia Stations that are fired on

PRRc'oais. The presence ofsodium enhances Ihe bonding and sulfation o[lhe particles to form a

strongly bonded matrix (22).

SCR Deposit Formation Mechanisms

.The mechanism for the formation ofdcposils that blind SCR calalysls involves Ihe

lnmsport of very SInali particles rieh in alkali and alkaline-earth elements, the surface ofthe

catalysl, and reactions wilh SO,/SOJ 10 form sulfates. The formation ofS0:I from SO. is

catalyzed by [he SCR; Ihis, in turn, increases the reaclion rate ofSO] to form sulfales_ In some

cases, the alkali and alkaline-earth elements will also reacl with Co, 10 form carbonales. XRD

analysis identified caSo~ as a major phase and Ca,Mg(SiO.), and CaC01 as minor phases.

lignite and subbituminous coals contaIn high levels oforganically associated alkali and

alkaline-earth elements including sodium, magnesium, calcium, and potassium, in addilion 10

mineral phases. The primary minerals present in Ihese coals include quartz, clay mInerals,

carbonates, sulfates, sulfides, and phosphorus-conlaining minerals (6).

During combustion, the inorganic components in the coal arc partitioned into various size

fraclions based on the type ofinorganic componenl, Iheir associalion In the coal, and combustion

system design and operating condilions. Significant research has been conducted on ash

formalion mechanisms and relationships to impacts on power plant performance (1--6, 9-13, 19-

21,29). During combustion, the inorganic componen1s associated with western subbituminous

and lignite coal typically are distributed inlo various size [raclions orash. The smaller size

fraclions of ash arc dominated by partially sulfaled alkali and alkaline-earth e1ements_ These ash

particles are largely derived from!bc organically associated calioIlS in the coal. The larger size

"
fraction has higher levels o[ alumimun and silicon derived from the mineral [mclion ofthe ashfonning component ofthe coaL Entmined ash was extHlctcd from the Columbia Station at the

point ofthe inlelto the SCR reaclor and was aerodynamically classified and analyzed. The

composilion ofthe size fractions was compared to the chemical composition of !he ash <.leposited

on and in thc catalyst., a~ ~hown in Figure 17. The comparison shows lhal the composition ofthe

particle caplured in the SCR catalysl is very similar to the <5-'.lln size [metion. The deposited

material shows significantly more sulfation lhanthe entwined-ash size fraetioIl, indicating that

the sulfation process occurs after the particles arc deposited in the cnmlysL

The mechanism ofSCR calalysl blinding when firing lignite or snbbituminous coals is

shown in Figure 18 (30). The requirements for the formation of deposits that blind SCR catalyst

include firing a coal that produces significant levels of <5-!-Im-sized particles. The particles are

trnnsportcd. into the pores o[(he catalyst and subsequenlly react with SOj lo form sulfates. The

snlfate [onns a matrix that hond~ olher ash particle~. The SCR catalyzes the formalion of S03

and thereby increases the ,dte ofsuI fation (24, 25). The sulfation ofCaO increases the molar

volume, resulting in the filling ofthe pore. For coals thal have high sodium contents, formation

ofJow-melling-point phases such as pyrosulfates is possible (31). Pyrosulfatc materials Can melt

at tempeIQtures as low as 535"1' in coal-fIred power systems.

..;.

'" FR , , , , Weight Gain lor LSUS-PRB Blend

/80Q"F

I

r 700"F

600°F

/ /'

V

c 0.015 '.

"5, 0,010

en 0,020

E

o

o

0.025

0.030

0.005

Time, min

Figure 8. Weight changes for PRB-blend coal ash exposed to flue gases and ammonia allhree

temperatures.

"
= OM

Baseline and Catalyst Tests lor PRB

PRB + Catalyst

P~ Baseline

,

/

,

~/

0.00

0.007

0.008

gj 0.006

rni 0.005

c 0.004

(!J

•

J::. 0.003

.Q>

0.002

o

o "

Time, min

'"

Figure 9. Weight changes for PRB-blend coal ash exposed to nue gases und ammonia willI and

without SCR catalyst present.

"

"

0, '"

I ",

c

'0

u

-w 0.'

..

•

0.'

0

'"

0.'

00

0 '00 600 BOO 1000

Run Time, hr

"00 ,."

Figure 10. Catalyst pressure drop at Baldwin Station at 0 to 2 months of operation.
'2 ,---------------- ~"'.~~~""-""

LO-l-------------------_j

QI O.B1,------

c

U 0.6;'----+-

_~ 0.4

o

02+--:'.-~----.J--~----+_If__j

1000 1500

o.o-l-------~-----~----""'-_j

o

Run Time, hr

Figure 11. Catalysl preSSl"" drop at Columbia Station at 0 to 2 months of opcrotion.

'.0,-------,------"'1--""\

0

I "

c ,.,

TI , .0

"

;:;

"

0

1000

o.o-l-- -----~-.JL-.L-_j

o

Run lime, hr

Figure 12. Cal.lyst pressure drop JT CoyNe Slalion al 0 10 2 month, ofoperntion.
Bllidwin Stlltion after 2 months

Coyote Station after2 montbs

Columbia Station after 2 months

Figure 13. Pictures of catalyst inlel after about 2 months oftesting at each plant.
,

,

.'

"

:1

r: II9f Il' lOOl

."----------~----'

-i;

",.,

Baldwin Station ane.. 4 months

Coyote Station after 4 months

.·'gure l4. PiclIl'c., uf- comly,( hold aller "bollt 4 monlhs of .'posu,e La !lue gas "od parlieDI"",.
·'.-.

A

•

c

Figure 15. SEM images of ash collccte<l on calalyst surface at lhe Baldwin Station after

6 monlhs of exposure. A) and B) low-magnification images of ash deposit on ealalyst surface
amI C) high-magnification image ofpolished cross section showing particles in a matrix of

calcium- and sulfur-rich materials.

Table 3. Ch~mic"l Composition of Selecled Poiol. and Areas in Figure 15

Cllemical composilion (norrmli?ed wl% equivalCTll oxide)

Oxide POinl I Point 2 Poinl3 Point4 Poiul5 Poinl6

1.1.1

"' '.0" 03 0' ,.,

Na,O U

" •., 0.' ,.

M,O 14.8 16.0 15.6 15.5 H.7 .,

"

AI,O, B

" 19.9 57.7 ,., 47.3SiO, " U 0' o. u 0.0

P,O, 30.7 20A 17.7 0.' 29.0

'0, .,

"'

"" " 0.'

"' 0.'

K,O 28.8 28.7 28.1 22.5 34.9 28A

""0 '.0 U

" '0 U U

TiO, 11.4 12.9 ., 00 ,.

Fo,O, U

" " " '.0 0.' '0 ,,0

T~' W. W.

'"" wo '"" '""

Oxide Poinl7 Poja! 8 Poinl9 Poinl 10 Point 11 Poinl 12 ',;'

1.1.2

u OA "0 " U

N.,O ,. ., "

" 5.0 H •., ~,

MgO .0 ,., '" 19.2 10.8 3.g

111,0, 'A 18.4 18.5 31.0 17.9 16.7

SiO, U ., '" 0.' U

" " P,O, 37.9 U 5.3 0.'

'" 13.9

'0, ., '.0 0.' "., 0.' O.

K,O 3\.4 52,G 49.0 28.9 30.6 45.4

0.0 " •• " " ,.• U

TiO, H n

" " ., '0

Fe,O, •• ,.. 3.5 ,., '" B

',0

Total WO W" wo '"" w. W.
A

B

c

Figure 16. SEM imngcs orash collected on catalyst surface at the Coyote Station after 4 months

ofexposlire. A) low-magnific3iioll image of ash deposit on catalyst surface, B) low-
magnification image ofpolished cross section showing particles in a matrix ofcalcium- and

sulfur-rich materials. and C) higher-magnification image of bonding.

1.1.2.1 Table 4. Chemical Composition of Selected Polnls and Areas in Figure 16

TOlai '00 wo '00 '00 W,

Oxide Poinl6 Point7 Point 8 Point 9 Poinl 10

1.1.4 i0 ", '" lOA ,. <A

N.20 U ,. U '0 U

M,O " " ,., ,.• 10.6 i~

Al,O, U 18.2 10.5

" 28.9

SiO, 0.' ,. 0.0 0.' 0.'

r,o, 41.8 28.4 44.9 44.5 23.4

'0, n

" u " 3.8

K,O 245 <A 22.5 12.8

C,O 0.'

"

" U" " TiO, " ., ,. •• 13_2

Fe,O) " m 0' ,. "0

"

Total wo '00 wo
o

EEM

f2!<lpm

rn 1 104.6pm

4.6 10 22pm 1---------

m>22pm

EE Cala.lyst Ash

Figure 17. Comparison of entrained ash and dcposi,ed ash on catalyst for Columbia Station.
Particles -

Silicates ~.

Small Particles tf---...... ••

Na, Mg. Ca, K ~.

Pore

SUIJur Oxides

,,--Carbon Dioxide

No Delerloration Yet

(NHJ and NO. can react in

mlcropore on catalyst sUrface)

__ Reactions with SO:!

and CO2

>- PaI1iclos _ Sille'll., and other Ry Ash P""iclos

_____ Motel, Moleri" ., Parliolly Sulf~\.d AlKali and

Alk.line.Eanh Oxldos

14% Expansion

,---MalrixMalorial - Fully $ul!al.d Alkel; and

Alkallne_Ea<1l.O:<id""

'-- P.~loles - SiIIcal"s and Olh~r Ay Ash Feniclos

DeterioratIon

(NH, and NO, cannot react in

micropore on catalyst sUrface)

Figure 18. Mechanism ofSeR catalyst blinding via the formation ofsulfates and carbonates

(modified after Prilch:lrd and others [30])_

Low-Temperalure Pyrosulfates

The presence ofsodium sulfate in the flue gas exiting n scrubber will cause problems to

low-dust lind tail-end devices such as sc1edive catalytic reduclion (SCR) syslcms for NO,

reduction. There are two problems associaled willi the line particulate rich in sodium sulfat<} On

downslream devices. These include accumulalion offine particles On the SCR that, when

soolblown, will cause opacity problems, and lh~l the.fine partIcles on lhe SCR will fonn

pyrosuJfatcs such as (KLsNa o.s)S,Oj thal have meJtingpoinls as low as 535QF (31) lhal wiD

blind lhe calalyst. The presence ofthese compounds in low-temperature corrosion deposit<; is

well known (32). In addition, lhe presence of SO) enhances lhe formation oflhe low-mellingpoint pyrosulfales (31). The sodium sulfale malerials will cause opacily and SCR catalyst

-:-,
" w

" w

"

"

blinding problems thai limit the feasibility ofthe low-dust or tail-end SCR technology for use

wIlli high-sodium lignite coals.

The sodium sulfate materials will be transported to the catalyst surfaces by diffusion,

electrophoresis, and, possibly, inertial impaction. The particles are held in place by weak

electrostatic and van der Waals forces. Once accumulation takes place, the sodium sulfate

particles will react with flue gas components, resulting in the formation ofpyrosulfates_ The

formation ofpyrosulfates involves the following processes (31):

1. Formation ofsulfates such as Na,SO~ lind KlS04

2. Conversion 0[S02 to SO, in the bulk gas phase- catalytically active surface such as an

SCR catalyst - SOl + O2----t Sal

3. Pyrosulfate formation - Na,S04 + SO) ----t NazS2o,

The melling points ofselecled pyrosulfatc phases are shown in Table 5.

Table 5. Mellin Points of Selected P rm;ulfale Comnounds

Componnd Temperature, QC Teropet:ature, OF

K:J'e(S04)l 61~ 1144

KlAl(S04)l 654 1209

KFe(S04)1 694 1281

Na]Fe(S04)~ 624 1155

Na,Al(SO.)~ 646 1195

NaFe(SO,), 690 1274

Na,S207 401 754

K1S,O, 300 572

(Kl.~Nao.5)S,O, 279 535

Melting points for pyrosulfates between 535" and 770"F have been reported in the

literature. Much ofthe pas! work has focused on [he formation oftbese phases on tube surfaces_

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

exacl melting point depends on the relative lIIIlounts ofsodium and/or potassium_

There is significant evidence for the formation ofsodium-rich fine particulate in full-scale

power plards when firing high-sodium-containing coals. For example, l'vUnnesola Power's

Boswell Energy Station found that when it fired high-sodilUll, lower-ash subbituminous coal, it

experienced increases in opacity. Hurley and Katrinak (33) conducted a field-testing project on

Unit No.4, a pulverized coal-fired boiler equipped wilh an electrostatic precipitator and a wet

scrubber, to beUerundersland the reasons for the opacity problems. During the field testing,

sampling ofthe coals, flue gases, and scrubber materials was comlucLed_ The particulate in flue

gases downstrellIIl ofthe scmbberwas aerodyr13mically classified using an impactor and
multicyclOTIe. The sizcd fractions were analyzed to determine the composition ofthc submicronsized fmction.

The resulls ofthe study indic~led that the particulate collected downstre~m ofthe scrubber

was co~l-rejated and caused by the high sodium content ofOne ofthe coals. Vapor-phase sodium

condenses in the convective pass to Jorm fine sodium sulfate particles or other Na species that

later react with ash particlcs_ Pure NalSO~ particles are too sm~lI to be removed by scrubbing_

CONCLUSION: SCRIS NOT FEASIBLE FOR NOx REDUCTION AT j\ULTON R

YOUNG

The ash deposition behavior of the lignites from North D~kota is the most complex and

severe of any coals in the world, ~nd installation of catalysts for NO, reduction is going to be

jmpos~ible because oJthe fonnation ofsodium calcium sul£1tcs in the pores ofthe catalyst

Following is a list ofthe key roadblocks associated with lignites which have not bcen overcome

>lIld, in our opinion, make the installation ofSCR catalyst at the MRY plant technically infeasible

for NO, control.

High alkali and nlkaline-earth clements present in the coal fired ~t the MRY plant form

sulfates l1k'lt blind the catalyst.

Cyclone-fIring partitions the ash during combustion. As a result the Icvelot"

sodium and calcium in the fiy ash is enhanced and will increase the SCR

catalyst blinding.

Su]Jil.te reactions increase with increasing tcmperalure, and thc suggested

temperature ofinstallalion al the MRY fncilily is higher than typical

installations; therefore, salfation problellls are enhanced.

Sulfate fonnation is also enhanced by the presence ofan SCR catalyst; this

accelerates the sulfation re~ctions, C<lll.>ing blinding ofthe ealalyst

The high levels ofso(\iwn in thc coals combined with calcium produces lowmelting-point eutectic compounds that will mclt On the surface.

Sulfates form on the surfaces of catalysts firing PRB coals. Lignites will be

several orders ofmagnitude worse because orthe higher levels ofsodiulll.

• The ash componcnts to impact SCR perfOmlaHCe in Japan nod Europe (14--16) Include

alkali and nlkaline-earth elements that result in sul£1te formation. The total calcium

content and the sum oflhe calcinm, magnesium, potassium, and sodium provide an

indication of the problems that occur. For the coals fired at the:MRY power plant, lhe

CaO content ranges from 6.8% ··19.99%, mJd the sum oflhe alkali and alkaline-e~r1h

elements range from 9.33%-29.87% ofthe ash. The levels ofcalcium in Center Iiguite

arc 2 to 4 limes higher than the problematic coals in Japan and Europe_

• The fmding or wolk conducted in Germany nnd Japan were confirmed by recenl SCR

catalyst sIipslreom testing that showed significant evidence ofsodInm aod calcium-
rich sulfate formation lhat fill and plug the catalyst at both lignite (North Dakota)- and

subbituminous-coal-iired power plants. The results oflJJis recent testing showed lJJat

the presence ofsodium significantly enhanced the foonation ofbornling ofparticles

and more rapid sulfation, filling ofpores, and rapid increase in pressure drop across the

catalyst.

Deposit carryover, orpopcom ash, plugging the top ofthe SCR catalyst with deposit

fragments, is a significant problem because ofthe extremely high deposition potential

ofthe coal. The foonation ofdeposits in various parts ofthe boiler requires continuous

sootblowing. The deposit fragments are likely going to be carried with the bulk gas flow

to the SCR catalyst, resulting in plugging.

The variability of the lignite is a problem ofunique cOncern at "MRY. The deposition

potentIal of the coal is always changing rapidly, resulling in rapid growth and foonation

ofdeposits io various sections of the boiler. Aggressive sootblowing of all fireside

surfaces is already required to maintain full-load operalion_ The soolblowing of

upstream heat exchange equipment will cause deposit fragments to be carried back to

the SCR catalyst, and during sootblowing ofthe SCR catalyst, the entrairunent of

deposit fragments along with the sootblowing media will result in significant erosion of

the catalyst surfaces.

The ash-related impacts ofthe lignites from North Dakota are the most complex and severe

ofany coals in the world, and installation oftail-end SCR systems for NO, reduction will not be

possible. The key problems associated with lignites that have not been overcome and, in our

opinion, make tho installation oftaj]-end SCR systems at the"MRY plant technically infeasible

. for NO, conLIol at MRY's Units 1 and 2 are listed below:

X High-sodium lignite coal from the Center Mine Hagel A and B seam coal produces

extreme levels ofhoillogeneously condensed sodium sulfate that pass through the wet

scrubber_ In addition, the cyclone-firing system captures much ofthe ash as slag,

resulting in a decrease in ash that is available for providing condensation sitcs for vaporphase sodium compounds upon gas cooling. This results in an increased homogeneous

condensation ofsodium sulfate.

X These 5mall particles pass through a wet scrubber and will accumulate on surfaces oftnilend SCR systems, The accumulated materials cannot feasibly be resolved through

conventional sootblowing and cleaning technologies to remove the particulate.

X Recent testing with subbituminous and lignitic coals imlicated a significantly higher level

ofpore filling and plugging in the catalyst exposed to lignite ash as compare 10

subbituminous coal ash. The catalyst pores as well as the catalyst surface in the lignite

tcsts were completely coated with a sodium calcium sulfatc matcrial, while only pore

filling was found in thc subbituminous coal testing. The pressure drop across the catalyst

exhibited for lignite was 4 to 5 times greater than that found for a catalyst exposed to

subbitnminous coal ash. The plugging occurred over a 1000 hour lest period.
The formation ofliqui<1 pyrosulfate materials allemperalures ns low ns 535°F from sodium

sulfate materials Occu,s in coal-fired power systems and is well documented_ Pyrosulfates will

form and CaUSe blinding of mil-end SCR devices. Tn addition, SCR systems catalyze the

formation oISO] from SOl. The presence or SO) significantly enhances the fonnation ofthe

pyrosulfates at MRY to an extreme level that cannot be deall with effeclively using cleaning

technologies thal exist today_

REFERENCES

1. Mehta, A.; Benson, S., Eds. Effects ofCoal Quality on Power Planl Management: Ash

Problems, Managemenl. and Solutions; UniLed Engineering Foundations Inc.: New York and

EPRl: Palo Alto, CA: 2001.

2_ Schobert, RR [.ignites ofNorth America; Coal Science ond Technology 23; Elsevier:

New York, 1995.

3_ Baxter, L.; DeSolJar, R., Eds. Applications ofAdvanced Technology to A.,lJ-Related Problem.'·

In Boilers,- Plenum Press: N",,, York, 1996.

4. Couch, G_ Underswndlng Slagging and Fouling During pfCombuslion; lEA Coal Research

Report",1994.

5. Williamson, J.; Wigley, F., Eds. 1Mimpaci ofAsh Deposition on Coal Fired Plants:

Proceedings ofthe Engineering FOl/ndation Conftrence; Taylor & Francis: London, 1994.

6_ Benson, S.A.; Jones, M.L.; Harb, J.N. Ash Fomlallon and Deposition-Chapter 4. In

Fundamemals ofCoal Combustion for Clean and Efficienl Use: Smool, L.D., Ed.; Elsevier:

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

7. Benson, SA., Ed. inorganic Transformations andAsh Deposition During Comlmslioll.

Ameriean Society ofMechanical Engineers for the Engineering Foundation: New York,

1992.

8. Bryen;, R-W_; Vorres, K.S., Eds. Proceedings of/he EllgineeringFoundation Conference On

Mil/era! Malter and Ash Depositionfrom Coal, Santa Barbara, CA, Feb 22-26, 1988; United

Engineering Trustees Tne", 1990.

9. Raask, E. Erosion Wear In Coal Utility Bailers; Hemisphere: Washington, 1988.

10. Raask, E. Millerolimpurities il! Coal Combu.stioJl; Hemisphere: Washington, 1985.

11. Benson, S.A., Ed_, Ash Chemislry__ Phase Relationships ill Ashes am! Slags, Special Issue of

Fl/el Frec,,"".,·. Teclmo!_; EI5evier Science Pnblisbcr:s: AmslenJarn, 1998; Vol. 56, Nos. 1-2,

168 p_
12, Laumb, M_; Benson, S_A.; Laumb, J_ Ash Behaviorin Utility Boilers: ADecade ofFuel and

Deposit Analyses. Presented allhe United Engineering Foundation Conference on Ash

Deposition and Power Production in the 21sl Century, Snowbird, UT, Oct 28 - Nov 2, 2001.

13. Benson., S_A.; Hurley, J.P_; Zygarlieke, C.L; Steadman, E.N.; Erickson, T.A. Predicting Ash

Behavior in Utilily Boilers, Energy.Fuels 1993, 7 (6),746-754.

14. Licata, A; Hartenstein, H.D.; Gutberlel, H. Utility Experience wilh SCR in Gennany. 161h

Annual Inlernational Pittsburgh Coal Conference, Pittsburgh, PA. Oel 1I-IS, 1999.

15. Cicbanovicz, J_E.; Broske, D.R. AnAssessmenl ofEuropean Experience with Seleclive

Catalytic Rednclion in Germany and Denmark. EPRl-DOE-EPA Combined Utility Air

Pollution Control Symposium: The MEGA Symposium, Atlanta, Georgia, Aug 16-20, 1999.

16. Ciehanovicz, JE; Muzio, LJ_ Twenly-Five Years ofSCR Evolution: Implications for US

Applications and Operation. EPRI-DOE--EPA Combined Utility Air Pollution Control

Symposirun: The MEGA Symposium, AWMA, Chicago, IL, Aug 20--23, 2001.

17. Benson, S_A.; Kong, L.; Katrinak, K.; Schumacher, K_ Coal Quality Managemenr System,-

Final Report for North Dakota Industrial Commission; Sept 1997_

18. Katrina!<, K-; Benson, S.A.; Laumb, J.; Schwalbe, R.; Peterson, W. Matching Lignite

Characteristics andBoiler Operation,- Final Report for North Dakota Industrial Commission;

Aug 2000.

19. Saro.lim, AF.; Howard, J.B.; Padia, AS_ The Physical Transformations ofMincrnl Maller in

Pulverized Coal Under Simulated Combustion ConditioDs_ Combust, Sci_ Techno/. 1977, 16,

187.

20. Loehden, D_; Walsh, P.M.; Sayre, A.N.; Beer, J.M.; Sarofim, AF. Generalion and Deposition

ofFly Ash in lhe Combuslion ofPulverized Coal. J. Inst. Energy 1989, 119-127.

21. Zygarlicke, C_J_; Toman, D.L; Benson, SA Trends in the Evolution ofFly Ash Size During

Combuslion Prepr. Pap_-Am. Chem. Soc_, Div. Fuel Chern. 1990,35 (3), 621--636.

22. Benson, S_A.; Fegley, M.M.; Hurley, J.P,; Jones, M.L.; Kalmanovilch, D.P.; Miller, B.G.;

Miller, S.F.; Steadman, E.N.; Schobert., H.B-; Weher, BJ.; WeInmann, J.R.; Zobeck, RJ.

Project Sodium: A Detaifed Evaluation ofSodium Effects in. Low Rank Coal Combustion

Systems; Final Technical Report; EERC publication, July 1988.

23. Hurley, J.P.; Erickson, T.A.; Benson, SA.; Brobjorg, J,N.; Sleadman, E.N.; Mehta, A.K.;

Schmidl, c.B- Asb Deposition at LowTempenltures in Boilers Firing Western U.S. Coals_

Inlernational Joinl Power Generation Conference; Elsevier Science, 1991; pp 1--8,
24. Laurnb, J_D_; Benson, S.A Bench- and Pilot-Scale Studies ofSCR Catalyst Blinding_ In

Proceeding ofPower Production in the 21s1 Ceutury: Impacts ofFuel Quality and

Operations; United Engineering Foundation: Snowbird, UT, Ocl2001.

25. Crocker, C.R-; Benson, SA.; UlUlllb, J.D. SCR Catalyst Blinding Due to Sodium and

Cnlciulll Sulfate Formalion, Prepr_ Pllp_-Am. Chen!. Soc.. Vivo Fuel Chem. 2004 49 (1),169_

26. Benson, S_A.; Laumb, J.D.; Crocker, C.R- Blinding ofthe SCR Catalysts in Lignite ami

Subbitumluous Coal-Fired Power Plants, Presented at The Clearwater Conference on Coni

Utilization & Fuel Systems, CIC<lrwater, FL, April 18-22,2004.

27. Senior, C.L.; Linjewile, T_; Denison, M_; Swensen, 0_; Shino, D.; Boekelie, M_; Baxter, L;

Bartholonew, c.; Hecker, W.; GllO, X.; Nackos, A.; Whitty, K.; Eddings, E. SCR

Deactivation Mechanisms Related to Alkali and Alkaline Earth ElemenL., 2003 Conference

on Selective Catalytic Reduction (SCR) aud Selective Non-Catalytic Reduction (SNCR) for

NOx Control, Pittsburgh, PA, Oc129-30, 2003_

28. Rigby, K.; Johnson, R; Neufort, R-; Gunther, Po; Hums, E.; Klatt, A.; Sigling, R. SCR

Catalyst Design Issue:; and Operating Experience: Coals with High Arsenic Coneentmtions

and Coals from the Powder River Basin, Presen1ed allhe International Joint Power

Generation Conference, IJPGC2000-15067, July 23-26, 2000_

29. ASTM MeLhou. D6784-02, "Slandard Tesl Method for Elemental, Oxidized, Particle-Bound

and Tolal Mercury in Flue Gas Genemted from Coal-Fired Slalionary Sources (OnLario ;'>~

Hydro Method);' at http://wwlV.astm.org/cgi-biniSoItCart_exeIDATABASE-CART/PAGES/

D6784.htm?E+mystorc_

30. Pritchard, So; Hellard, D_; Cochran, J_ Catalyst Design Experience for 640 MW Cyclone

Boiler Fired with 100% PRB Fuel, http://www.cormctech.comftechdataiindex_hLmL

31. Singer, J.P_ Combustion, Fossil Power Syslems, ComblJ.Stion Engineering Ine_: Windsor, CT,

1981.

32. Chemislry oJCoal Utilization, Second Supplemenlary Volume. Elliol, M.A., Ed.; Wiley

lntcrseience: New York, 1981.

33. Hurley, J_P.; Katrinak, K.A. Determination ofAsh Fonnalion and Deposition Mechanisms at

Minnesota Power Clay Boswcll Station; DOElMC/I 0637-3365, July 1992.
APPENDIXC

COST METHODOLOGY

CAPITAL COST ESTIMATE DETAILS FOR NOx CONTROLS

O&M COST ESTIMATE DETAILS FOR NOx CONTROLS

APPENDlXCI

Co,t Melhodology

C.1 METHODOLOGY FOR ESTIMATED COSTS

NOll BACf Analy,is Sludy

i -.

The summary economic evaluations ofeach allernative >lrC presented in the cost impact sections oflhe

main report. Capilal and O&M cost eslimales for-each allemalive are presented individually. The

Levelized Total Annual Cost (LTAC) for all the alternatives for control ofa single pollulanl (i.e. NOx)

from a single llIlit is lhen presenled logelher with Unil Control Costs. The Levelized Total AnnUllI Cosl

(LTAC) represents the levelized annual cost ofprocurement, construclion and operalion over a 20 year

design life, again in curren! (2006) clallam. As a minimum, the design life for any allernative was taken 1.0

be lhal recommended by '"lne EPA Air Pollulion Control Cost Manual", Sixth Edilion, January2002,

EPN4521B.Q2-00I'.

The LTAC is alw used lo calculate the ave""ge annual and incremenlal cost elTcctivcness ofeach

~ltemative. The LTACrepresents an mmual paymenl in current day dollam sufficient to finance ilie

project over its enlire life.

In detennining the LTAC a Capiml Recovery Factor and an O&M LevelizationFactor were calculated

from lhe project economic condilions and then npplied separately to the estimaled capital and O&lv:\ costs.

The equalion used is shown below.

LACCINPV "'((:~~~)' I) = CRF

Where,

LACC Levelized Aruma! Capital Cost

NPV = Net Presenl Value oflhe capital investments required.

i discount rate

n '" design life in years

CRF Capilal Recovery Faclor

Therefore:

LACC '" CRF Jl NPV

For lite economic conditions descnoed in Table C.I-I the CaPll::lJ Recovery Factor"",s calculaled lo be

0.08718.

1n delermining the levelized annUllI O&M cost the estirrutled annual O&M eosl, the inflalion rale, the

discounl TIlte, and the equiprnenllife are rnken inlo accounL The O&M Levelization Factor (OMLF) was

calculated as follows.

Sq~.re B~rte Eloolric CoopOT.tiva Cl-l Burns & McDonnell
NOx BAC[ Analysis Sruuy

Wh~TC.

A LevcIiz"<l Annuul O&M Cost (LAOMC)

A] = Total annual Q&M cost in current dollars

i, = discounl rale

i; inflation rate

n design life in ycms

Thereforc:

LAOMC~OMLFxA,

APPE1\'DlX Cl

Cosl Melhodology

For lhe economic conditions described ill Table C-l-I the Operating and Maintenance Lcvdizalion l'aclOr

was calculated lo be 1.24873.

The Levelized TOlal Annual Cosl, or LTAC is the sum ofthe levelized oapital cost und the l.veli2ed

O&M cost. Therefore:

LTAC LACC + LAOMC= (CRF XP) + (OMLF x Aj ) 0.08718 x P + 1.24873 x Aj

The differences bCIwcen ull':rn"lives are also presenled graphically in the lorm of a plot of the annual

emissions reduction (tpy) versus Ihe LTAC for cuch alLemative. "fill" form ofplot graphical1y depicls the

cost effectiveness 01· Unil Control COSI (in Silon ofpollutIDlt reduction) ofeach alternative relativc lo all

ofthe others. TI,e oost effcctiv':m:&< i" also refen."d to as the Unit Control Co.,t and defined as the LTAC

divided by the annual emissions reduction (tonlyr). The arcu on lhc plot indiculed by the various dula

poinls repre"ents the cosl effecliveu,,"s envelope for !he alternatives under consideration. A smooth line

is drawn on this plot connccling the righlmost poinls (those with the lowest co.,t for a given level of

emissions reduction). This line is referred lo as the Dominant Control Curve (DCC). The DeC defmes

lhe right hand boundary ofLhe envelope encomP'!""ing all oflhe alternalives considered_ The DCC is

used as a screening 1001 bcl""''''' considered allemativ,,". Those aHcmalives whose ploltcd posilion is

above and/or lo the left oflhe DCC nrc not as cost effective as those fonning the line and thus can be

eliminated from further analysis if desired_

In order to compare various pollu\anl control alternati,-es, lhe Unil Conlrol Cost and the incremental Unil

Control Cost ofeach alternative were also calculaled and tabulalCd for comparison purposes. The Unit

Burn' & McDonnell Cl-2 Square Dune Eleclric Cooperalive
APPENDlXCI

Capit.l Cost Estimales

NO~ BACT Analysis Study

Control Cost compares control technologies on a basis of doll= expended per Ion ofpollutmt reduced

($/ton). This reMionsl1ip is graphically depicted in the DCC chllrl.

To more accurately compare between alternatives with different costs and control efficiencies, the

incremental cost effec~venes:s is also determincd forthosc alternatives on the DCC_ The incremental cost

effecli"cuess is dcfincd as the LTAC of~ given eontrol option minns the LTAC ofan aHCIrultive, divided

by the difference between !.he ammal emissions reduction (lpy) oflhe given contT,,1 option and thc

alternative being evaluated. The CQrnbination ofthese two economic analyses Can be used as un argument

for lhe elimination ofcontrol technologies with significantly greater marginal control cos!.'; than the given

case. The equation used for the incremental cost effectiveness is shown below.

Where,

fCF (LTAC,-LTAC,)

(AE, AE,)

ICF = Incremenlal cost effectiveness ($Iincremental ton rem"ved)

LTAC, = Levelizcd Total Annual Cost ofcontrol alternative No_ I ($/yr)

LTAC,= LeveJized Tolal Annual Cost ofcontrol alternative No.2 ($Iyr)

AEj Control "ption No_ I Annual Emissions Reduction (tonlyr)

M= Control op~on No_ 2 Annual Emissions Reduction (tonlyr)

(The higher cost, more effective control oplion is subscript I in this equation_)

The economic analysespIcsented in lhis report not only include the esLimatedcapital and O&M COSls for

cueh allemative, but also the LTAC for economic comparison of the various alternatives. Tn addition, the

Unit Control Cosl or cost effectiven= is presenled for each alternative. Finally, a comparison between

alternatives, in the fonn of LIIe murginul cost effectiveness, is presented in both numerical and grn.phical

form. Thus a comprehensive comparison of LIIe economic impacts ofeach aHcmalive, as well as the

differences in cconomic impaet between alternatives is clearly presented_

s~u:rre Bulle Eleotric Coope<alivo CI-3 Bums & MoD"nncll
NOxDACT Analysi> Study

Table C.1-1 - Economic Faclors(1),(2)

TOlal Possible Operaling Hours per Year

Amurtization Life, Yea"

Cost ofMoney

Propeny Taxes, Insuranc~, %

Conversion Tax (in lieu ofproporty tax)

Amortizalion Rate fm APC Capilal Cosls

Intere,l During Construolioo (IDC)

Disoount Rate (used to CaJeUlole NPV)

Conslrue!ion Co,t Escalalion

Non_Fuel 0&]1/\ Es",,]ation

Fud (coal and natural gas) Escalation

Auxiliary Electric Power COSI, ${II.{W-hr

Uroa Cosl, ($l1on de1iveTed, 50% aquem" solution)

Na[ural G"" (SlmrnBtu)

(1) • All financial pere<olllges ao,1 "nil ""~iliary eke"" power 00" were pro\';~e,j loy MPC-

(2) _All 00'," are in 2006 dull"" IInles< noted oUlerwi"".

APPENDIX Cl

CoslMelhodology

8,760

<%

'"

NA

NA

6%

6%

6%

",

2.5%

2_5%

$35.00

S)80.00

$7.98

Burns&McDonneJl Cl-4 Square B~tle Electric OJopef31ivo
APPENDIXC2

Capi",) Cost EsliTllllle,

NOx BACf Analysis Study

C.2 NOx CONTROLS· CAPITAL COST ESTIMATES

The capital costs 10 implement the various NOx eontrolledmoJogies were largely estimaled from lll1it

outpul capillll cost factors ($IkW) published in ledmical papers discussing lhose control technologies. In

lhe cases ofSNCR and FLGR., preliminary vendor budgetary cost information was obtained and used in

plaoe of, or to adjust, the published unit output oost factors. These oost e1Ilimales were considered 10 be

study grade, which is + or- 30% accuracy, or bcUcr.

The limitations ofthese ""pHa] cost eSlimales developed from lll1it capital cosl fuctors multiplied by unil

output"",:

• Scope basis Ill1certainty - inability 10 precisely delermine whatscope ofsupply, inclucliug such

lhings as baJance-of-plant (BOP) systems and equipment improvements were required, assumed,

or accounted for when developing the unitcosl fuctors. Some ahematives may have higher

indired or BOP capiml costs than others. Similarly, the inclusion ofgeneral facililies,

preproduclion ~ud invenlory costs, and other indirect cosls is not known_ II is likely that thc

un1ity owner·s final total expenditure for the implemenlatiou of the allemallvcs, especially

options that are mosl capital oost-intensive, will be greater than the calculaloo coot estimates_

• Locallon·specifio influences- most NOx control techniques have been applied primarily to

eastern bituminous coal-fired plants localed near large metropolitan areas, not in largely rural,

upper midwestern United SIal"" locales_ The amolll1t ofspare available is dependrnt on the

exisllng powerplant equipment and building layout and property plot area, versus what is

expected to be required forimplemcnting various control technologies. T=porlation and

Jo<:allregionallabor costs are also variables.

•

•

•

•

Sizio influences- some lechnologies' capital costs "'" more sensitive to "ceouomies ofscale"

!han others_

Capacity maTgins - some technologies' may require higher cupueitymargins 10 allow sustained

operation atoigh throughput rales over exlended periods oftime.

Reliability concerns - some !eehnologies' have bcen refined to a nigher degree, and others may

require more component redundancy toan others in omerto avoid porfmmance reductions and

potential outages for failures and repairs or replacements.

fnfiallonary influences -the significant increases in 2004-2005 for raw malerial oosts, especiaJly

steel and aHoys ror fabrication ofstructural and mechanical components, has occurred aflermany

of these tec1mologie,o; were inslalled in projects upon which the referenced unit capital oost

factors Were b.sed.

Square Bu~e Electric Coopcrative ~., Bums & McDonnell
APPENDIXCl

Capilal Co'l Estimales

• M"rket condilions -as demand increases [01' emission controls, some allCmalives become more

eosl-competilivc, while olhers do not. Tbis can be inflnenced by lhe relative supply and demand

for lhe tedmology and number ofsuppliers who CUn furnish iL Thc d~'rrumd for some

ullenmli"", can also be strongly innuenced by the slringency of the local, SIHIC, Hnd nationul

regulatory requirement,. Schedule for implementation and a,,"ilability nf1ocaJ!rel,,;OIml bbor lor

installalion conlmctors ore a1.,o market_driven f~dors.

The eSlim~led NOx conlrol cosls are in addition 10 Capil;]l cost.>; 10 provide normal repbeemenls of lhe

existmg Millon R. Young Station's majorpowCT generating equipment.

C.2.1 Separated Overfire Air Capital Cost Estimates

InSlallalion ofseparaled overiire air systems tyrically includes windbox an<J!or secondary combustion air

supply duel modificatious. boiler waterwalll.ube openings, air.oow distribution device,

(dampers/registers), airllow conlrols and me"surernent instrumentation, and relaled siruelurnl ""d

electrical lie-ins l.o lhe exisling plant faeil ilies_ A basie separaLed overfirc air relrofit syslem inSlilllcd 011 a

lignile-frred cyclone boiler includes poru ~cro," lhe front and rear walls of the upper fumace. The w,il

eapital co,t faclor is expeeLed to bc ubove the high end o[the lypieal publ ished eOSl range of$5-1 0/k\V';

($1 1.5/kW or $5.500,000' for MRYS Unit 2), due to the lurgc ducl.'l, rdutivdy lall fllTrulee (compared 10

typical bituminous eoal-fired eyclone boilers), und the need to "void existing obstructions wilhin the

boiler llOuse_

An adv""ced form of SOl'A unique to North Dakot~ lignite-fired boilers will include relocation of lhe

existing lignite drying sysLem vent port openings from lhe lower primary lilmace 10 the upper furn~ce, 10

be pluced ~t 'he same clcvation as lhe new SOFA ports. This requircs exlension of the exisling cyclones'

lignite drying syslems' vent piping 10 supply Ihc nCw boiler fllTllilce ports. This retrofit will also c1115e-<lff

the existing FGR ports in lhe lower front and rear fumaee walls ofUnit 2, eurrcnUy coinciding wllh the

cAislmg pre-dry velll ports_ These FOR ports may be blocked, or relrn:ated to the lower portion of lhe

upper(sGCondary) furnace, across the lronl ""d refIT \V.lls. This is expeeted 10 eost In Ihe UTe_ of

+$9.5/kW or $4,500,000 lor Unit 2's additional eapiml eost over ""d above the basie SOl'A system.

Overall, Ihe advanced version o[separated oV~TflTe.ir technology is estimated 10 have an installed capil:ll

cost ofapproxim"lely $lO_O Million ($21.0/kW) for MRYS Unil2_

Borns & McD""nell Sqll",~ Bulle Eleelric Cooperalive
APPENDlXCZ

C.pilrll Cost E,~maleS

NOxDACf Analysis Study

C.2.2 Reburn Capital Cost Estimates

C.2.2.1 Coal Reburn Capital Cost Estimates

There is one ahemative that inclu~cs u neW cool rebum syslem. Capital coste.,timates for coal rebum

systems are highly dependent on the requirements for rebunI fuel Jlf"I'"Jl1Ition and feC<1ing lo the boiler.

For the purposes of this analysis, thc application ofn pulverized coal rebum system "<Slimed the need to

make extensive additions 10 the existing fuel preparation eqnipment in the existing plant facilities "nd

feeding to new furnace injectors. At l""st two neW fine-grind pulverizers, or MPS"89 stand"rd

pulverizers followed by dynamic classifiers are expected to supply the amOUnI of finely ground reburn

coal for ll1is method.

Addition ofnew c1cclricolloads for the pulverized coal preparation equipment 10 the existing plant

facilities will be required. For the purposes of this prelirnirurry sludy, it is assumed ll1at additionnl plJIlt

auxiliary electrical power will be available for powering the new pulverizernlmicro-mills nnd related new

coal rebum eqnipment, but this has not been conl'irmed.

_The existing crusher b,ys do not have £loorspace avaibble to nllow thcnew milling equipment forrebum

fuel preparation to be located adjacent 10 the existing coal cnJ.-'bers. This will require a separate building

,,~r addition to the existing powerhouse to be buill 10 provide sufficient space to enclose !he new milling

and coal silolhandling equipmenL Separate modified pulverized coal-style burners or coal injectors will

he installed tlrrough new openings ill the upper furnace front and rear waterwalls at Or above the elevation

ofthe existing lignite drying system vent ports, along with new overfire air porls located at a higher

elevatioIl, above the reburn fuel injectors. Ibis would have the capacity to supply approximately up to

thirty percent of the IOtal full load fuel heat input to the boiler through the coal rebnm injectors. This coal

reburn system design was not expected to change the existing cyclone silo/feeder ammgcmenl, such thar

nll cyclones wonJd remain operational. To achieve ll1llXimum NO" emission CAlTltrol, only the adVlloced

fonn ofSOFA for pulverized coal reborn was included. Confirmation ofthese concepts and COst

estimates requires more detailed eqilipment design and plant layoIlllhan has been performed for the

purposes ofthis BACT analysls.

The installed capital cost ofpulverized coal rebum for the cyclone boilers at Milton R. YOUIlg Station

used in this cost effectiveness analysis Was estimated based upon a Clean Air Markets Division [CAMP]

of the US EPA dollar per kilowatt unit capital cost factor for cyclones. The installed capital cost estimate

of$40.65 Million for MRYS Unit2's pulverized coal rebum alternative used in this cost effectiveness

analysis was estimated based upon applying a 3.5% assumed inllalion cost adjustment to ll1e CAMP unit

Square Butte Electric Coopera~ve C2-3 Bums & McDonnell
NO~ BACT A~alysis Study APPENDlXC2

Olpilal COSI Eslima!as

capital costfaclor for cyclones of $82.33/kW (x 1.035 = 585.2/kW) included in a WRAP (Wc'lern

Rcgional AIr Parlncr,hip) draft repod' published on lheir website, dated April 26, 200S. 1be cost 10

relocate the lignile drying .'yslem venl ports and FGR ports was added [0 the inflalion·adjuslc<! CAMD

number ($85.2 +$9.5/kW = $94.7/kW), since coal rehum IS expected to include .,eparated overfire air hut

not lhe exira costs for 1hc special improvements identilied for air-slaged lignite-liring in cycloLle boilers.

This increased the installed capital cost by S4.M [or MRY Station Unit2's coal reburn systcmlo a lotal of

S45,154,000. This docs noL include the additional paJticulate matter collection capaciry consid~'rCd

necessary to limit the expected negative imp~cl on opaclLy from 1his option.

To conlrol pnrticul~lc malto.'T (PM) emissions ~lat would be expected to increase irom insmllalion and

operalion of polverized or micronized coal (cburn, adt!ilional PM collcction capacity ",ill be requil'ed. A

hybrid fmnl of PM collection Ihat snpplemems lhc CJ\isting clcclrosl~tic prccipilalor's pcrfornlanoe,

referred to as COHPAC (COmpact Hybrid PArticublc Collector). This was es~nmted in 2002 doll"rs al

330,200,000 [or MRYS Unil2's CUllPAC'. Adjmted by an esoalation mctor of 1.2623, ilie installed

cap' tal cost of the COlIPAC addil ion was c;stim~te<l 10 b~ ~36,013,000 [or MRYS Unit 2 in 2006 dollars,

When thc COHPAC add,lion w~< combined with the Lignile lleburn and ASUFA allemalives, tim

resulting tolal cstimalcd capilal cost, were $81,167,000 for MRYS Unit 2 (£94.7 + 375.5 S170.2fkW).

C.2.2.1 Gas Reburn Capital Cost Estimates

Convenlional gas ",bum oplions assume lImt seventeen percent of the tolal fuel heal input 10 Ih~ boiler is

through the neW gas reburn injectors to be located in lhe lower secondary furnacc abovc the lop rows o[

cyclones. Eighl to twelve gas rehUffi injeclors would bc cXp<'cted 10 bc rO(jllircd in lhis case. Seven

percenl ofthe total fuel heat inpul lO the boiler lhrough the gas rebmn injeclors is a,mmed 10 bc supplied

for the fucllClm gasrcbum alternatives. Fonr to eight ga, rebum injeolors could be assumed in FLGRTh<

cases. Gas rebum OptiOIlS assume that a new high"prcs'IITC gus pipeline woult! b~ brought from ncar

Bism~rck, ND approxirnulely Iwenty six miles. The pipeline diameter is prop<Jrtional to lhc amonnl of

:fuel required for the speeific alternalive, ranging from 24 inches for convcntional gas reburn to 12 inches

for fuel lean gas rebmn cases. A station gas man;., "Iilh new gas lrJins, consisting ofvalves, metering,

anu safcly shutofrvalves [or Ihe front and rear hoiler for the gas injeclors' supply, woulll be furnished and

installed.

The c~pllal oos[s for conventional ga, rebnm allemalives wel'e eSlimale<1 consid~'ring unit capital cosls

pnblished in published lechnical litera lure. One vendor lhallms supplied numerous domestic utility boiler

BIllllS & MoDOIU\ell Square DUlle Ekclrio C.ooperalivc
APPENDIXC2

C.pilal Co,t Estimates

NOxBACl' Analysis StlJdy

'."

gas rcbum systems (GE Energy, formerly GE-EER) published $IOIkW for gas reburn in a 2001 technical

paper'. Anothersource published a 2005 technical paper'" that provided a unit c~pital cost range for gas

reburn of5l15lkWto 5I30IkW. Neither source ineludcd a detailed scope description norcosl breakdown

[or engineering, equipmeIl~ materials, and labor to install a gas reburn system.

Site-specific needs and challenges identified for ~pplying conventional gas reburn to Milton R Young

Slation, and lack of defailed gas reburn project scope and equipment desoriptions avail"ble in published

technicalliterarure leads to a muoh greater degree ofuncertainty with regards to an aCCIrnlte capital cost

estimate for this alternative_ For the purposes of U1is study, the estimated instal1ed capital cost for a

conventional gas reburn system \vith advanced SOFAonMRYS Unit2 is expected to be approximately

$20.5M (S43/kW), which is above the lOp end ofthe previously stated rnnge. before adding the new

\!IIderground gas pipeline capital costs. This study assumed an average unit capaoity capital cost factor of

$22/kW forcouventional gas reburn, plus the additional CoSls for the adv""ced fonn nfSOFA Over basic

SOFA +$4.5M ($9_5/kW), and the new high-pressure gas pipeline. This results in a an estimated installed

capital cost for conventional gas reburn system with adv"nced SOFA on MRYS Uni! 2 of$20.5M

($43/kW) plus the new high-pressure gas pipeline costs. Confirmation of these conoepts and <:(1st

C estimates requires more detailed equipment design and planllayout than has been perfonned forthe

purposes of this BACT analysis_

Fuel lean gas reburn (without SOFA) capital cosleslimales were based upon a lale 2004 budgetary

proposal"" by a vendor (Fuel Tech) wilhexpcricnee in supplying FLGRTM equipment, typically combined

with an SNCRsystem. Estimated capital costs of$JM inclnde budgetary numbers for the equipment

installalion, including inslallation managemen~ material and labor, with a +6_0% price adjustment

assumed for477 vs 450 MW for a fuel lean gas reburn system without SOFA on MRYUnil2, uot

including the capi1lll cosl for the gas supply pipeline. Costs for work oUlside the vendor's scope, such as

balance-of-plant additions plus other indirect oosls were eSlimated lo add approximalely $l.IM (25% plus

10% contingency) lo the adjusled vendor's estimated inslallcd cosl 0£$3.2M for U1eir soope ofsupply_

These udjustrnents result in a lotal installed capilal cost for FLGR (without SOFA) estimated to be $4.3M

plus the capital cost for the gas supply pipeline. Adding the incremental costs for the ndvanccd from of

SOFA over nO SOFA (+SIOM ($2l/kW) results in an estimated installed capilal cost for a fuel gas reburn

system with advanced SOFA on MRYS Unit 2 of$14.3M ($30.01kW) plus the newhign-pressure gas

pipeline costs.

Square Bune El""trio Cooporalive Bums & McDonnell
NO"IlACT Analysis Srudy APPENDIXC2

('''pllol CO'1 Estimalo'

The capi",] oost eslimares for the new high-pressure underground gas supply pipeline assumed $7 per

ineh of diameler peT foot oflength_ This WaS calculaled 10 be approximately $23M for conventional ga'

rebuming ~nd SI1.5M [or FLGRTM_ The cosl analysi., for eaeh NO" control allernative im,-olving a

parlicular fuml of gas rcbum assumed lhal both hoilers at MJlton R_ Yrmng Sialion select the same

allerLlaj ive 1J,at burns natural gJs. There[ore, the eslimated capilal cosls fOT gas rebum alternatives rdlecl

a capacily-based proportional share of the cas pipeline capital oosts, avoiding double-oounting. Thi,

rcsulls in nn eSlimaled inotal1eu capital cost for MRYS Unit 1'sshare of the ga, pipeline to he $15M for

the conventional gas rebum al teroative al,d $7..IM for fucl-lc'm gus rcbum allcrnalives.

The (ut.1 insl<llled Cilpital cus(s fur conventional ~s reburn (with ASOFA) witb MRYS Unit 2's share of

the total capital cost for the gas supplypipe1ine eSlima(cd 10 be S35-5M (S7~AIkW). The lotal ;ustal1<0

capilal cOSlS for FLGKrM (Wilh ASOFA) with MRYS Unit 2's share oflhe total capital cosl for the gas

supply pipeline were eslimated to he $2J_8M ($45.7fkW). Conlirmmion oflhese conoepts ami co,l

eSlimates requires more detailed equipmcnt dC'lgn and piJnt byuullhan has been performed for lhe

purpus,,", of this BACT analysis_

C.2,3 SNCR Capital Cost Estimate

The allcrnal;vcs that includo sclective nou-calalytic reduclion s)'stems assume the use ofurea unless noted

otherwise. The SNCR systems' prelimina,y design and estimated capital cosls were based upon a 450

MW lignite-fired cyclone boiler in Mo 2004 blldgelary propusal' by a vmdor (Fuel Tech) with

expcricnoe in supplying SNCR equipment. Circulation, metering, dilutiun, control, Jrld injec~on

equipment 1S inclUded. A 180,000 gallon field-erected ,,-taioless steel slorage tank will hold lhc 50% urea

solution (as delivered by truck). Individual and multiple nozzle lances wilh mulliple levels ofurea

r<:agent injeclion will he designed and localed to uptimize distribution and aecumruodale various builer

load condihons. EsLimaloo capilal cllSls ofS4_9 Million include hudgetary numhers for equipmCIlI

instal1alirll!, including installation manngom~~l, malorial anrllabor assumed for a SNCR syslem applied tu

a ~50 MW boiler. Costs fur work uulside the vendor's scope, such as ouldoor reagent ,torage tank and

building enclosure/equipment frrundalions and containment, and halance-oj~phll1taddilions plus other

indireet costs were estimated lu add approximalely $1.9 Million (25% plus 10% contingency) 10 the

vendor's estimated installed cost for lheir scope ofsupply_ This results in an eSlima Lcd lollli capital COSl

for 5NCR (withoul SOFA) of$6_8M for a450 MW lignile-fired eyclone boilcr.

Bums & McDouueU C2_6 Sguare Ilu"e Electric Coope",tive
APPENDIXCl

Capital COSl Estimates

NOx BACT Analysis Slody

.- .~

Applying these adjustmenls 10 a 477 MW boiler results in an eSlimated total installed capital "osl for

SNCR 0[$7,120,000 [or MRY Stalion Unit 2 (SI4.9/kW).

C2.5 Layered Technology Capital Cost Estimates

Capital costs were general]y estimated based upon simple arilhmelic addi~on of individual nnil oUlpul

capilal cosl faclors [or combinalions of available NOx reduction leclmologics, such as SNCR wilh

ASOFA. An advanced form ofseparaled overfjre air system included !he lignile_fired cyclone boiler

cquipmenl changes within !he eslimatcd unit capilnl cosl [aclors.

Adding the advanced SOFA capilal CAlst of $10.0 Mi11lon 10 the previons estimaled installed capilal cosl

of$7.12 Million yields a tolal estimated inslalled capital cost of$17.12S Million ($35.9/kW) for the

SNCR with ASOrA altemaLive [or MRYS Unit 2.

As previously discussed, Lignile (coal)Teburn (CR) was assumed to be combined \vith "dvanced SOFA

and a COHPAC addition considered necessary to limil the exrected negative impact on opacity from !his

option. The installed capilal cost of the COHPAC addition WaS estimated 10 be $36,013,000 [or MRYS

Unit 2. When thc COHPAC addition Was combined with theLignile Rcbum and ASOFA allematives,

the reruJ~ng total estimated capital costs were $EI,167,OOO for MRYS Unil2 ($94_7 + S75.5 =

SI70.2/kW)_

Square BUlle ElecLric Cooperalive eM Bums & McDonnell
I
APPENDIXC3

O&M CostEslimates

NO"BACT Anaiysis Study

,

",. .., 0

"

0

;.-:

C.3 Operating and Maintenance Cost Estimales for MRY Station NOx Control

An evaluation was performed 10 delermine the eslimaled operating and maintenance cost impacts of

installing and continuously opcr~ling various feasible NO" controllechnologies on Millon R. Young

Stalion Unit 2. These were estimated to be in addition to existing O&M COSls 10 operate and maintain the

:MRY SUllion cquipmcm.

The expected loss of elcctrical power sales from the operalion ofthe specific NO", control altomalive was

included os an annualized cost, assuming $35 per megawatt-hour. This was determined (0 indude

estimates for:

• Reduclion in annual unit OUlput due to an expecLed negative reliability (i.e_ uptime availability)

impact for each alternative. This generalion reduction was calculaled by mulliplying the

esliIllilted additional numbers of outage hours per year by thc averagc running plant capacity

factor for that specifio altemalivc, mu\(ipli~-d by the historic 12-month average unit gross

electrical power output (MWJ dd.rrnined during lhe same period as the highest 12-monlh rolling

summation NO;.: pounds.

Net adclitional auxiliary e1ectrio power demand for the added control cquipment for each specific

alternative based on assumplions for b'rOsS horsepower, plus additional power demand for existing

funs caused by flue gas prcssare drop (COHPAC for additional PM oo11""tion e;apacity), with

adjuslment for expecled reductions in power demand (such as a d""rcusc in existing coal crusher

and feeder electric demand for the pulverized coal rebum casc).

The averuge rulllling plant capacity f,,-cLor for each alternative, which may ,,-Iso inclUde an

expecLed negalivc impact on the unit capacity from operalion oftheieelmology. This assumes

that the control technique limit. the gross electrical power output of the Unit (such as causing an

increase in flue gas flow) such lhal thc fuing TIlle ofthe boiler C31U1OI be lllilinlained or Illised 10

compensate for lhe load impact. Examples are lower boiJertbermal efficiency (highcrunitheat

rale) when firingnatllml gas (due to higher moisture conlenlofthe fluc gas).

For llic SNCR allcmalive!h:lt involve. a ehemic~l reagent injeoled forNOx control, such as urea, lhe

annual reagenl COJ15umption based on an assumed aclual sloichiometric ratio (ASR) ofmoles of

equivalent NH, injected per mole ofuncontrolled NO", emission estimaled !rt llie point ofinjcction,

converted lo a mass rale (lb&Ihr) by multiplying by the eslimaied annual nl1IIlber ofhours ofoperalion and

thc eslimaLed NO!!: reduction m.clion, and then multiplied by unit reagenl cost (for a specific inlet NO"

concentration, cmission reduction percentage and ammonia slip level).

Squmc BurLe Electric Cooperative BIlIJIS &MeDonnoii
NOx BACT Analysis Sludy APPENDIX C3

O&M Cost l'..stimalc,

Gener,,] annual maintenance cos1s W~TC assumcu 10 be 1.5 perccnt ofihe eslim~lcd inslullC<! capital cost

for each alternative, except for the coal conveying and grinding equipmenl portion oflhe coal rebllIn

altemalive. which was assumed to be 3 pelcenL The periodic bag replaccmenl costs and other COHPAC

sy>lcm m~inlenaTlce cosls were cotimalcu 10 be approximately 5.3% oflh~ inswlIed eupilal cost ofthe

additional particulate malter col1e~tion equipment.

Additional nperating lab",· costs directly allribulnbk 10 co~h olt=alive were assumed [0 b~ zeTO for ,n

alternalives.

Olher operating costs include:

• Reagenl dilution waler for Ihose oltcma1ives [hal involvc a chemical reagcnL injcctcd for NOx

control, typic<\lly four times the amount ofurea consumption (assumes urea is a 50% solulion os

delivered and is injected a, a 10% solution); this follows EPA OAQPS convenlion' .

• Heal rcquired for Urea fCagent sloragc, for those "hcrn"tives Ihal involvc a chemical re"gen I

injected for NOx control; Ihe source ofheat is aS5umed to be auxiliary electrical power, but could

be auxiliaty steam (depending On heal sOurce "vailHbility Hnd plant prefe'r~'Il"c).

• Additional coal consumption for thos~ alternatives that involve a chemical reagent injecled for

NOx control to compen,ate for Ihe heal ofvaporiza.tion ofthe reagel\t dilution waLer;

This follows EPA OAQPS convention', but is not accepted practiec by an experienced SNCR

vendor (Fuel Tech) who claim, that the heat produced from the exothenllic reaction ofur." and

NOx is approximately eqnal to tile heJl required l(> evaporate the dilution water. For lhe purposes

of this study, this addirional coal eOnlurnption has been ineluded in Ih~ annual O&M cost._

The sum ofthe estimated "nnual O&M cost, was multiplied by the O&M leveli7.alion factor (1.2487J) for

each alLernahve to yield ]evcli:I.Cd tot;,1 annual 0&]1,( oosls.

C.3.1 Separated Overfire Air O&M Cost Estimate

Opcmtion of SOFA is expected 10 add u small amountofO&M cost, primarily electricity consumed by

the c(mventioruJl SOFA damper electric drive actuator and airflow measuring system transmitter on each

port. Using the exisling forced draft, induced dlllft, and flue gas reciroulation fans is not expected to

change the overall amount offun horsepower demand to be snpplied by those fans' electric motors.

Maintenance ofIhe new overiire air poris and relocated lignite drying system vent ports (and FGR port,

Burn, & McDOlmell Square Dune E1eclric Co"l'erolive
APPENDlXO

O&M Cost Estimate'

NO" BACT Analysi, Study

, .

1*

i

'" i--§

I .~.

for Unit 2) is included, assumed to be 1,5 percent ofthe installed eapilal COSI. This is included in every

control alternative's estimatcd O&M cost.

SOFA is not expected to significantly reduce unit reliabilit)l and availabi\i1y lo generate electrical power,

assuming consistent combustion and continuous slag tapping under substoichiometTIc air/fuel operating

conditio"" for MRYS boilers cm be routinely established. A Unit uvailabilit)l reduction of 2.2% (I B1

hours per year), fot M_R. Young Station Unit 2 was assumed, which allows for forced or extended

scheduled boiler outagcs tbat may result from problematic cyclonc slag tapping opemtional conditions

encountered during substoichiometric cyclone operation with SOFA. Thc expected loss of electrical

power sales from the reduction in mnual electrical power output due to a decrease in expected Unit

availabiJjt)l from ASOFA opemtion is included in every control alternative's estimated O&M cost.

Boiler fumaoe wmcrwalltube maintenance may increase slightly as a result ofmore fireside oorrosion

due to suhstoichiometric cyclone opemtion with SOFA. There may be some changes in the degradation

rale ofthe boiler's furnace waterWali tubes resulting -from exposure ofmore area of the furnace waJ1s to

slightly air-lltarved conditions during SOFA operation. Such conditions can promote corrosion from

sulfur compounds in the furnace gases being created above the cyclones and below the SOFA injection

porK Due to the relatively moderate arnOlUlt5 ofsulfur content in the lignite, modestamounl ofairstagingofthe existing cyclones dUTing SOFA operation, and the potential use ofrecirculated flue gas

along_the lower furnace walls, the cxpected change in corrosion rate oflhe boiler tubes should be minor.

TIlls degmdalion is expected to occur over many years ofoperation, andnorrnallyrequires periodic

replacement of the deterioraled sections ofboiler furnace walerwaJl tubes to avoid forced oUlages to

repair tube leaks or failed secllOllS_ The additional cosU> assooiated with potential ohange in the fi:eqUCllC)l

offurnace wall lube fililures and chang.outs are difficult 10 eslimate, and have nol been qlllmtificd.

C.3.2 Reburn O&M Cost Estimates

The allemali~'esthat include a new coal rebum syslem assume lhe use ofnew equipment for preparing lhc

rebum fuel toreplace 25% of!he MRY Station Unit 2 boiler's lolal fuel heat inpuL Two additional

lignile sil"" with coal feeders and fine-grind pulverizeJ"s followed by dynamic classifier(s), are assumed

to be located in a new separate building or powerhouse enclosure_ Booster fanes) addition was locluded

becausc!he existing forced dro.n fans Were assumed to be incapable supplying the additional amount of

primary air to the fiue-grind pulverizers and dynamic elassifier(s) for processing and conveying the

rebum fuel. Using the existing forced draft, induced drnfl, and flue gas recirculation fans is not expected

Square Bulte Electric Cooperative C3-3 Burns & McDonnell
NOx BACT Analysis Sludy APPENDIXC3

O&M COSIEslimalos

to .<ignincant]y ohange lhc overall amount offan horsepower dcmand to be supplicd by those faJ18'

cl"clric molors. The expecled loss of ekelricul power suks from lhe additional auxilisry eleotric power

demand for lhe rehurn millmg equipment from an e.,timaled 05% (25 MW) redl1clion in net oUlput WHS

induded as a eo,t, a,"uming $35 p~"r megawatt-hour for MRY Slatioll Unit 2. EIcclrieal power cO<lSumcd

by Ihe inGrc"'ed lo"d on boiler failS to Ov~rcome the higher flue gas system pre;;sure drop, plus lhe

COlIPAC pan:ieulale colleclion ,)'Stem support equipment was eSlnnalcd 10 b~ a 1.2% (5.~ MW)

reduction in net output for Unil 2.

M"inlcnanee oflhe separate rehum coal injeclors, fuel "nd primary air piping, and relJum fuel milling

equipment is expected to bc similar to lhe expenses a.'''''ciated with Iypical pulvcrized coal burners. The

eSlimated additional annual maintenanoe cost!; for a nCW micronized eo.l rebum system was assumed to

be 3.0 pcrccm of thc installed capital cost, or roughly $1,355,000 per year, for MRY Stalion Unit 2_ The

eslilllilted additional annual maimemmcc co,l, (inflation adjusted from 2002 to 2006 $) for lhe COIJPAC

system wa;; appmximale]y SI,938,OOO per year for MRYS Unil 2. Boiler f\lm~cc waterwaII tube and

5uperhealcr/rehealer tube maintenance may incrcooc slightly as a result ofmore erosion due 10 increased

particulate emiS3ions or IQuling by fly".m deposits resulting from coal reburn openllion with ASOl'A.

The additional costs associnlcd with potential change in the frc,!ucncy ofbOllcr tube failures and

changeouts are difficult to estimate, ~nd h.vc nut been quantified.

The estimated impads On opCl1l1ion and maintellanoe costs for Ihe co~l rcbum allemalive lhat include a

new pulverized or micronized coal rebllITl system ore approximate. The twelve (Unir 2) exisling coal

crushers for preparing lhe main (oyclone) fuel .fraction will have slightly lower eleolrical lk"mand. This

wa., estimated a;; -0.45 MW (-0.09%) for MRYS Unit 2_ Addition oInow c1eelrie.1 loads for the

micronized co"l preparation equipment 10 Ihc exi5ting plant facililies will be required. For the purposes

of ~lis preliminary study, it lS assumed that addilional plant am:iJialj' electrical power will be availablo [or

powering the new pol veriV'rSJclassiflers and rei aled new coal rebum cquipmenl, but tlJis has not been

confirmed.

Coal Rellnm with ASOFA is nOl expected 10 ,ignificanlly reduce unit reliubility and availabil ity 10

gencralc electrical power, ",,"uming consi,1CIlt combustion and conlinuous 81ag tapping under

sub51oiehiomelrie uir/fuel operaling conditions for MRYS boil= ean bc roulindy established. A Unil

availability reduction of3.7% (3.8% (3 13 hours perycur), for M.R. Young Station Unil 2 wns uS3umed,

which allows for forced or extended scheduled hoiler outages Ihat may rcsull [rom problematio

operalional condilions encountered during coal rehum operation wilh ASOFA. This reduction in allllual

Bums & McDonnell C3_4 Square Bull<: Electric ("oope-rali\'"
APPENDIXC3

O&M Cosl Estimate,

NOx BACf An.lysis Study

<,.'

'~

"."

electrical power output due to a decrease in expected Unit availability is included in the cnal rebum

oontrol alternalive's estimated O&M: cosL

A Running Planl Capacity FaclorreduGtion of0.5% of annual gros. electrical output was assumed for the

cool rebum alternative. This would result in an estimated 22MW average load deorease forM_R- YOlmg

Slolion Unit 2_ This expecled loss ofelectrical power sales from the reduction in net output due to lhis

plant ""pacily impact was included in the estimaled annual O&M costs.

Conventional and fuel-lean gas rebum options will involve higher operating wsts compared with the

existing operalion ofM.R. Young Station_ Nalurnl gas supply was assumed 10 he available near

Bismarck, ND, butiliis has notb",," confinned The eslimaled unit cost oflhisnaturaJ gas was assumed

10 average $7.9S1million Btu on a levclized annual co.thasis, with a "credit" of$0.71 permrnBlu for

avoided cost of oonsumption ofJignite cool reduccd by ihenatural gas heat input. The estimated annuai

cosE ofnatural gas for the conventional gos rebuming aUemativc appljed 10 MRYS Unil2 is

approximately S50_3M pe.ryear. The estimated annnal cost ofn.luml glls for the FLGR'IM alternativc

applied to MRYS Unit2 is approxirrultcly $20.BM per year.

Thcnc\\' gas reburn injectors, station gas m.in and injector gas trains would Slid a minor amount of

expense 10 current maintenance requirements, assmned to be 1.5 percenE of the installed capilal cost.

Mainle~ce Ofsep'file<! overfire airnozzlcs is expected 10 be simiiarto the expenses associated with

Unit 2's existing flue gas recirculation ports.

C.3.3 SNCR. O&M Cost Estimate

The alternatives that include selective non--catalytic reductiou syslems will involve higher operating cosLs

compared with the existing operalion ofMRY Station Unit 2_ Urea reagent supply was confirmed to be

,vailable regionally. The estimated unit cost of this 50"/0 aqueous urea solution WlIS assumed to average

approximalely $379!lon delivered (2006$)_ Consumption ofurea reogent for SNCR wilh ASOFA was , based upon preliminary uumbers aHowing for a boiler nue gas exit armnonia slip of 5 ppmvd. These

were estimaled as approximately 286 gph for SNCR when applied 10 MRY Station Unit 2 with ASOFA.

New electrical loads arc requircd for high now urea circulalion, in-line and slorage tank heating, water

di.lution, and reagent metering equipment. ·These ,uxiliary electrical demands and reagent dilution waler

usage were oaloulated based upon equations published in EPA Office ofAir QualilyPlanning;md

Square Butte Eleotric Coope""ive C3_5 Bum, & McDonnell
NO,,13Acr Analy,is Snldy APPENDlXC3

0&0\1 Co'l Eslimates

S~"nllunJs (OAQPS) publication EPN4521B-02-00J. Seclion 4.2, NOx Conlrols - NOx POol-Combustion,

Chapter I _Selective Non-Cutalytic OxidationI. Compressed nif for reagent atomi&llion and lance

purging anll couling, as well as lllulLiple nozzle lance wal", cooling are allJilional demand, on the

existing pl~nt l~eililie". These powerhouse bUllaing scrviee supplies were a,slImcll 10 be available, but

thi, has not been confirmed. The new llfea reagent injection nozzle lances, reagenl p"rnps, dilution wuter

pumps, anll Jlstribulion piping/valve 1rains wOllIll "<1l1 " minor amount ofexpense to ourrenl mainlenanoe

requJremenb';, asslImed to be ].5 perceLlt of the installed capiwl cos!.

SNCR wilh ASOFA is not cxpecled 10 significan~y reduce un;' reIiabihty and availability 10 generalC

c1eclrical power, as""ming urea lIljection does nol impact lhe abilily 10 maintain consi,lent combustion

and conlinuous slag tapping undcr SWbsloiohiometric airlfuel operaling conditions lor MRYS boile". A

Unit availability reduction 00_2% (263 hours per year), for M.R. Young StatIOn Unil 2 was assomed,

which allows for forced or cxtended scheduled boiler outages lM Lmay rcswll from problematic

openltional eonJitions encountered during SNCR·rclalcll opEmtion withASOFA. Thi. reduelion in

annual electrical power outpu Lawe to a decrease in ""peeted Unit availability is inclwded in the these

control allemalivcs' cSlimJlod O&M costs. ~!:

A Running Planl Capacily FJctor reduclion ofO. 15% of annual gross elcelrioal output was assumcll [or

Ihe SNCR wilh ASOFA alternative. ·Thi., would reswlt in an c,limu(ell 0.66 MW avemge load clccrease

for M.R. Young Slation Unil 2. This cxpcclCd loss of eleemoal power sales ii'om tbe reallClioll in net

omput due to this plant capncity impact was induded in the cslimalcd annunl O&lVl costs.

C.3.4 Layered Technology O&M Cost Estimates

Operating and mo;nlenance cosl_ for combinations ofavailable NOx reduc~on technologies Were

estlmated based upon simple ariihmclie addition of individual cosl eslimales_ SNCR was comhined with

advanced SOFA, as previOl18ly shown. Pulverizcd coal rcbwm wos assumed to he combinccl with

advJnced SOFA (and a COHPAC addilion for PM controJ)_ The auxiliary electrical Jcmands and reagent

dilulion water uSJge for SNCR "11th ASOFA were calculaled based npon eqwaliOJls pwblished in EPA

Orrice of AirQu~]ily Plunning and Slandards (OAQPS) publication El'Al45211J-Q2_001, Scc~on 42,

NOx Conlrols - NOx Post-Combwslion. Chapter 1- Seleclive Non-Calalytic OxiJation' .

Bums & McDonucll C3-6 Sqoare Burte ElecTric Cooperntive
APPENDlXC3

O&M Co,t Estima,es

NOx BACf Analysis Study

C.3.5 Summary of O&M Costs Estimates for MRY Station NOx Control

The results o[this evaluation for estimated variable operating and maintemmco cosls for lhe individual

NOx control allematives arc summarized in lhis section. lbe expected reduclions in Unit availability

(nptime) and capacity are included in Tables C.3-1 through C.3_7 [or MRYS Unit 2_ Tables C.3-5 and

C-3-6 for MRYS Unil2 include the eslimaled urea reagent and dilution walerusage rates and cosls for tho

ahenmlivcs !hal involve SNCR \vith ASOFA NO" control lechnologies.

TABLE C.3-1 - Expected Availability Reductions for MRY Unit 2 NOx Controls

( ) p y go g pcrccn oge

(2)-,- 12·montb baseline availahHity i< ",umed at 93.9 perC<nt. Thes. values re.Oeol c<lima,ed """,un'" ofneg:nive

·reliabiJjty impact e~pe,l<:d from tho implomenlalion 01 L~O individual NOx <:ontrol teclmiq"o,

(3) - Annual opCIaling lime l. annual ,.orage availability 1IIllllipliod by &760 hr~yr ofpo"';bl< uplime.

(4)- Ann""l ou,"go lime i< S7@hrslyrpo"ibleoperaLing Limo minu, <:stimaled .nnual oper.mng ume.

('i) _ Annual op=ling time m1uc'ion ,,,uhing liom the implementaLion orth. individu"l NO" control ,,,,~nique i, tbo

difference between lho basc1ino and e:<pc<:!cd annu,l onWgo limes.

E,timalell Annual Average Unit Operating Time

Unit Unit Unit

Operating Outage Operating

All.

UUi\tyf'l TimeD) Time'<) TIme Reduclion'5l, Label~) , NOi Control Teeltoique AvaUabitit brsIVr' - ltrslvr

E SNCR wi ASOFA 0.909 7965

D Gas Reburn wi ASOFA 0.919 8048

'"

m

'"

'"

C CoaIReburn wi ASOF/\ 0.904 ?916 "" m

B FLGR wI ASOFA 0.919 8048 m '"

A AdV3I\COO SOFA (ASOFA) 0.919 8048 m

Basclino

'"

0.939 8229 m

,

"

i'Jlem.,ive number has be<n =iou,l as,i cd from Ie"t n:movalto I\i l\esL removal ,

S~uare Bulin Electric Cooperative B~ms &McDorrnclj
NOx BACr Analy,is Study APPENDJXeJ

O&M Cost !'.slim.les

TABLE C.3-2 - Expected Capacity Reductions for MRY Unil2 NOx Controls

() Spy gh P g

(2) _ I~_moolh b_Iioo TLBmiog plam e:\l",'ily r,elor is assum,d aL 95.2 perc'nL The,e ,"diu,> reflecl ostimOl<d aLM<mlS of

negarive rehabiliry irnpacL c>pcelod from the implem'nLal'"O oflhc individu,1 NOx conool Lechnique.

(J) _ Annual el'clTicily gon,r.tion ro:Iuction i, aM",1 up<:TIIting Lime ro:IuClion muluplied by the 'Mu"l r\lnning planL

""p"ciLy faolorre,ulling from ~" jmplemcnlallOn afLIJe individual NO, conlroll,chniq"c multipli,d by ,he 12-monLIJ

av,,~ge gross OU'!'UL or440 MW.

(4) _ Annual ol<omcily goncr;mon reduction <:<)sl i> Lhc annu,,] clccnio;ry geneLa/io" redu<:t,Oll (kW-hrsl,T) rcs~l""g from

rho implomcntl'ion of,l,e indiVJdu,1 NOx cOlloQI Lechnique multipliod by 11.0 inrrcrncnt.1 \'ol"e of dw"cily

genera/iOrl, a""mod 10 bo SJS.OOfMW-llr. All w<I figu= in 2006 doliars.

ESLim.led AllIlU.1 A,'er~ge Unil Electric.l Power Gener"lion

Reduciion from 0 cr~lill Time Reduction

IlniL

lInH Geoer~LiDn Unit Gener~Lion

AIL. Rllllllillg Pl~nll" Rel!nc(inn~) Reduclion Co,t{'!,

L~bd') NOx Conlrol Technique c. adL I'actor kW hrsJ)'r 160D ,

, SNCRw/ASOFA 0.951 110,176,095 3,856

D GasRebum wi "'SOFA O.94~ 31,416,590 2,850

C CoalRebnm wi ASOFi\. 0.948 I30,n5.506 4,563

D FLGR wi ASOFA 0.9~9 XI,91O,OH 2,867

A Advanced SO:FA (ASOFi\) 0.952 75,859.855 2,655

Baseline 0.952 0 0

,.. AILe,"a'ive de<i n"ion has bern reviousl ,,-«i,,""<1 from le.,L rerooval TO hi esL removal eree"I' e.

B or", & McDonneU u-s Sqn.rc Bnlle Eleclric Conperalivo
APPENDlXCJ

O&M Cosl ESlimates

NOx AACT Analy,is Sludy

Revised 1011712000

TABLE C,3-3 _ Expected Auxiliary Electrical Power Demalld Challges

for MRY Unit 2 NOx Controls

(2) - The APC NO, ",,<ripm,nl S"''' "u,iiin'l' eiectrk01

•

powcrd,mand of alten,"i""" i, Iho sum of Indjvidu,j Icciulolo~i,..,

combjned by 'implo addirio,,- Ac'o,1 power de,.,,"", m,y diIT.. from ~\i, duo 10 po,;ti", ar neg,uiv. ,yo",gisii~ .ITo,".

Co'; ""urn jndud" 2,4~~ kW for fci:d p"'!"'ra,ion 'nd oonv,yiag 'quip,"e'l d'm"TId plu, 5.35] kW for Iho COl [PAC

,ystem ,driili"n for PM comm!.

(3) - j he AI'C NOx "'!uipment ,",ilb'Y ek",ricnl pow" dcm,od ""dit afconI rel>um altom,li,,'" Ihe ""m,l,d resul, of

lawer cyclo"o "",I prep",'io" 'no fcoder rowe, "'m,nd due 1o iowar boihey",,,"e ,onl equjpmen' lu<\ding. >\C1",l powor

dem,,,d, '""y <liffer from the, due 10 ne<uracy or""lim.te, for",-,um,d ,mounl of ol"lRlin.g ho""p"",,,, redoctio".

(4) _ The 10",111<' nll~lr",'Y ,I""";,,j powor demand ;, th, ,urn of~le gro~< <lem,,,,! ,nd ,redi!.

(5) - no on""ol ,·h'TIgc in APe NO, equjpmem aW<;lj"'Y cle,lri,"1 power ~",n,tu1 dec'rieily u"ge in kW-h""yr [0'

lhe", ,Iremal;v,," ;s lhe n,1 p""o' d,maru:i mul'irH"~ oy lhe "limale<! an",",1 opcrd'iog lime aud nJ"ning pbm

cnp,dty lactor whi,h reHeel< !he "dju"menllor any e,pe<red reliaoilily and e'p"ci'y impacl' fm,n Ih,

illlplemonta,ion oflhe cOillmllccoo;que.

(6) _ The :th"uoj ehoog, In APC NO~ equipmeu' '",ili,'Y decrnc,Il""'I<"I,m'nd otcclridly eo,' i.< I~o aanu,j ehon~o

in kW_hr.;/yr for 10"" an.mol;ves ""ulling rmm In, lmpi,men"'ti,," o['he indjviduol NO, e"nlrollerbnjqu,

mUI!;pliO<l by lhe inerem'n,"1 ",Iu, of,u,Hj, 'Y clCdr''''lly 1eoo,an,,", .",um<XI 10 be Sl'.OOIMW-hr, All co"

liguro, in 2006 doH"",.

Eslimaled Annua' A'.rage APC NOx Equipment

Auxlllar, meetrioal Pon'er Dema"d ond U,a""

Gro" Toto! Nel Power Power Usoge

A" Demond'" Credir') Demond'" Usage'" Co'll'!,

L.bel") NOx Conlrol T""hnique 'W 'W .W kW-h.,.r r 100051 r

, SNCRw!ASOPA 13J_2 0 13J.2 1,008.774 "

D Ga' Rebum wI ASOFA , (228) (227) (i,724,42B) (60)

C Co.l Rcbum wi ASOFA 8,J42 (4'i8) 7,394 59,217,554 2.073

0 PLGR wI ASOFA , (12S) ( 124) (949,051) (lJ)

A Ad""ced SOPA (ASOFA) , 0 , 7,664 0;

,,> Alternauvo do,i~_tion has beon pr<viou,ly ""j e" [rom Ie," removal 10 high.,.' ",mowl p""en"'il".

i :kli$-

, "

,.

lfI;

SguafC BUlle Eledrio COUpcr,lI;ve CJ_9 Borns & McDonacli
:-10, SAC r A",dys;; Slud,

Re\'i,ou 10; 17nOO()

AI'f'~NOIXCJ

O&]I,J Cu,l E"in"'lo,

TABLE C.J-4 - Expected AUl(iliary Electrical Power Demand and Generation

Reduction Cost Changes for MRY Unit 2 NOx Controls

,

(I) AI'em",,", ,!e"gn"LOn hos b,en prc"Y,ou<ly "'''good hum 1••,1 ""TI","'! L" h,gh.,,;L "'ltIo,,1 p,rc,n"'~o,

(2) _ Tho an"uol ,hong<: in A~C NOx 'qwpmenL 'll,!I;a,y d,,,"·'""[ 1'"w", ,[eman,! 'k"rieily "lOg' ill kW.lmlyr I",

LO"'o ..llemallVcs;•• h.n".powerd.m...~mul.;1.li".lhy.he...im...<1 oonuol opomILng 'imo ,ed runniog pi.."

C"p,,,,iLy r",lor whioh "'~"l< LfI, ,djll<"n'''L Ii",ny "'Po,,',,1 ",Ii,blhly :lml o"p:o,ily imp"ll frolll Lilo

,olplomO"','ion of lh, eom",1 L,'Chnlque.

[ll - An"",1 <lc"ri'ily g,ner"ioLl "ducolo" i' ",10",1 "per,ling 'im< ",<lu"io" m"llI~li<~ by L!\e ,rum,1 mnning 1,I,m'

c'p",ity r,eror r<,ulLing from ,ho im~lo"""','ion "rlbo ",li,',Llu,! 1'0, con"nl 'CChnoqllO LUulLipll'd oy U" 11._

LUon,h ,\'c,,~o gro" oULpUL 01'4411 MW.

H) - Tho 10,,1 uni, 01."",,1 po",e, £"'''C.''''" '~"ng, i, Ih, ,urn ortho "mu,,1 eh,eg' in A['e .~O>. cq";j>'ne,,' ,""Ii,')'

,lcelri,,1 po\V<c dem'J\J ,I""rioi,y ","go ~I", 'Il< ,nnua! d",rrlCJly ~,n,",lion r"dncLiO'l ""uI'iLLg liom 'he

implcm,n"'[on of Lho In~i\'iuu,' "Ih «m'1\1! ,,01\0;<IUC.

(5) - Tho Lotal unLl okwic-al 1"'''''' £""e"""" ,'h,"~" '0" is Ih, '0101 g,nCfilLion oh,n~o {kw hr~',.r) "H""pl,,~ oy Ih,'

inm,m,n'al ,",1"0 01" el,W;"i'y g<n"""Qn, "'LLmcd lo 00 SJ5.0Ui.\III'·hr. _\11 00" ligUle' i" 20m; dolld".

E,lIm'lod AnIlLl.1 CJ,,,,,g" i" Un]1 C,mralion Dne 10 ·\PC Nth

Eqnipmont Auili.c.v Pone, Electcicil]' Oom."d "lid G,ner"tion

R,dlloli"n

M'C TOlol Unil Tot.! Ulli!

Elmric.1 Unit Electric.l Powor Illee,";c.1 Po"ec

Poner Generalinn Genec.lion Geoeratinn

,\lI. U,ago'" ROdlltl::,:~' Cban~e'" Chonge Co,~"

Lllbotl" NO~ Cnntrol Tecl'niq". klV_b"!vc kW·hrs! r kW hr'!I'r IOOO$!vr

, SNCR wi ASOFA 1,008.774 110,176,0'15 111,1~4,869 J.891

" (los Rchllrn wi ASOFA (1,724.423) &1,4[6590 79,692.162 2.7~9

, CoallU:burn wi ASOFA .19.217,554 IJO,3J5,506 189,59J,059 6,636

, rLGR wi ASOFA (949,05 I) ~1,910,02A ~O.9()O,9n Z,~3.1

A Adv.need SOFA{ASOFA) 7,664 75,R59.~55 75,867,:;20 2,6:;5

.

Bum, & MoDO<ll,dl C.1_IO
ArPENDIXCJ

O&M CoS! Esiimale,

NOx BACT An"ly.,j, SlUdy

Revised 10/1712006

TABLE C.3-5 - Expllcled NOx Reagent Usage and Cost Estimates

for MRY Unit 2 NOll. Controls·

NO~ ReduClioo NO. Redo<lion

Reagen' Urea U,agel

" Rcogont D11~liDn

Watcr UsagelJ)

All.

Lobelll) N01 Conlrol T""llIIlque lbslhr lonsl -r 10OO'l:lvr 1000

"" , 1000S! ,

, SNCR wi ASOFA 2.7\3 10,276 J,898 9,M51 "

(1) AlLerI'""VO dos'gnauon ha, oeeo pre.,ously "-',,go,d [rom 10... romo.,i to hLghesl removal pe"'eJl,"~e.

(2) - All "OS[ flgol"OS i" 2006 doll,,,.

(J) _ Re.~O"' dilUli"" ""'''', ""<aBo ""Umo. p"\>oble wnlO[;' add,d '0 ereaLe. 10% "reo co1\O,",,,[io.

(4 p,rts WOlO[ 10 1 pall ureo ,",,1;0" ,I 50% ,""","'",Iion) prio, '0 injoo'ioJL OilUlio" '"''''' uni, "." ",,",oed

'0 be SI.OO ror Lho"-",nd g>Jlon'.

TABLE C.3-6 - Expected Heat Input and Equivalent Coal Cost to Evapqrate

Aqueous Urea for MRY Unit 2 NOll. Controls

() g p y g 0 r s

(2) - H"l ""lU;n:<! '" <"!'O,,,'e un:, ""gonl d;i",ion ,",te, "",urn", 900 BLnllo ""luin:<! h,,-,ed "" , too/, "",a

con,cn'",!;on (4 p.rt, ,",lor 10 ] p,rt urea ,olu';on ,,50% ,00,e"',,,I;oo) ;njoc"'d [0' the ,..,litnoreJ amOu"1 of

u,e, "sage. Co,] he" coote"l of6,662 !lrulln. uoit <OS! oUO.71ImmBlu.

[,timOled ADnuol Average Unit Equinlent Co.l

Con'umption Co,t ror A ucous Veea Ev. ocati."

no.1 Rcquieed to ['1ui"al.ul Co.1

E,'aporate Consumption ror Cool Co",umption

'" Aqueous Vre.Pl, He"dll"puf", Cu,II')

Label'" NOx Coolrol Techuique mmDlul r Too,;", IOOOS/;e

, SNCR \\'1 ASOFA 7J,986 5,55J

,

"

AII,m,';vo d",j o'l;on nos boo" rcviou,[ ,,,; nod from ic",l n:mo"'] '0 hi"",,, ",mo",' or,,,,,,,. e

,~

'"

Square !lulle Elcctrio Cooperali"e eJ_[ I D",m & M~Duuncll
NOx B'\cr ,\nolysi. Study

Appendix C Rcfcrcllce~:

APPENDIX CJ

O&M Cost E"imales

i EPA Ofljce of Air Qurrlily Planning and Slandards (OAQPS) publioation EPA/452iJ3·02·00 1, Section

4.1, NOx Controls - NOx POIll-Combuslion, Chapter I _SelectIve Non-CataI}1ic Reduction, (bled

October 2000, posted at their websile: hltp:ffwww.q)u.gov/ltnl9!!~4j~\ks'l-Ld)l2df, Chapltt 2-

Scle<:Live Calalytic Reduction, daled Oclobcr 2000, pO'le<!"l lhL>ir websile;

http://www.epa.gov/tln!ealdclirljcs4-2ch2.pM.

;; ·'Stalionary Source NO" ;md I'M Emissions io lJ1e WRAP Region: An Initial Assessment ofEmi,sions,

Controls. ami Air Quality Impacts", October I, 200] Western Regional Air Partnership Final Repon of

the WRAP Markd Trading Forum, Section VI: SUIIIIIIDIY of-Emission Controls Available for Large

Stationary Sources ofNOx ancl PM (by Reaction EngiLleering In1ernalional), available at

hltp:/Il"ww.WInDair.om1for,-!mf<1Lnl(lnO}(-pm.hlm!

i, "Analysis ofCombuslion Controls for Reducing NO" Emissions From Coal-fIred EGU's in the WRAP

Regiun" WRAP Draft Repon: EGR ContraolNumber 30204-101, prepared by Easlern Research Group,

Inc., dated April 26, 2005, po,ted at their website:

bttp-lIwww.wralli!ir&rWforllInsls'i (I,loeument~ei.ctlsINOxEGUl050426Coalfired%20EGUs in "WRAP Region-mart.pdf

• "Combustion Modification -1m Eoonomic Alternative tor BOller NOx Control" GER-4192 (04/01),

Folsom, Bluir A, Tyson, Thomas J_ GE Pow"" SyslolIl5, Schenectady, NY, (1001) poslerl al their websi",:

hn~:lj~'Y.~p'oweL·.comlm'ocl scrv.'pro(!.u~eJs!Iecb dQcs/enJdownload&lger~ 192,udf

"; "Assessment ofConlrol Technology Optiom for BART-Eligible Source" Steam Eleelno Boilers,

Imluslrial Boilers, Cement Plants and Paper rmcl Pulp Facilities", dated March 2005, posted aL ~leir

website: http://bron~~_ne,oaLlm. orgkommitIe e.e1ha:zeffiART Contl'DI AssessmenI.] ojf

~; Budgetary Proposal, Fuel Tech, InD. NO"OlJT" SNCK and SNCIUFLGR'" Systems, for One 450 MW

cyclone-fired unit, date,] December 9, 1004.

Durll-' & McDunIlell C3_12 Square Butte Eleclric Couporoliu¢
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