Electronic Filing - Received, Clerk's Office, 08/15/2012 

EXIDBITl 
Electronic Filing- Received. Clerk's Office. 08/15/2012 

URS Air Quality Control Technology 

Selection for E. D. Edwards Station 

Final Report- Draft 

Revision: B 

Date: 25 May 2011 

Table ES-4; Capital and Operating Cost Summary- Including Unit 1 

Control 

Systems Capital Raqulrement'· 4 

(Units 1-3) $1,000 $/kW 

LSFO- $377,180 $530 rellned5 

LSFO- new5 $412,600 $580 

Advatech6 NIA NIA 

LSD+FF $410,460 $580 

CFB+FF $399,440 $560 

DSI+FF $280,440 $400 

SCR (U 1) ! $45,660 $390 

Mobotec (U2) $11,260 $40 

1 -Cost - based on des~ coaL $lkW based on 707 nel M'N. 

2. = Cost based on ope~og coal. 

First-Year Costs Levelized Fixed Variable Fixed Costl 

O&M' O&M1 Charges' 

$1,1100/yr $1,000/yr $1,000/yr $/ton rem. 

$16,600 $720 $78,260 $4,250 

$17,110 $720 $85,610 $4,580 

N/A N/A NIA N/A 

$14,140 $1,620 $85,170 $4,640 

$12,060 $1,950 $82,880 $4,360 

$7,210 $8,910 $58,190 $5,610 

$670 $910 $9,470 $11,610 

$380 $840 $2,340 $4,790 

3 =Total First Year end 'Tolal Levelized cost is the sum of Rx.&d charges~ fix&d O&M cost, and Vilrlable O&M cosL ~ons removea~ 

Is based on -operating coal and ere for S02 for all cases ex-cepl SCR and fJobolec, which is based on N{h:. LaveJlzed cost 

represent an ennualized cost over lha life of the plan I. 

4 =.capital costs-include a new chimney for Unit 1 for all FGD tec:hoologles. 

5 :=:Relined Unit 3 ct\imney tCt discharge flue gas from Units 2 enC 3. New chimney fa discharge tiue gas from Units: 2 and 3. 

a e Advated'l did nol st..ppfy cast for all three: units. 

5 

; 
URS 

Electronic Filing - Received, Clerk's Office, 08/15/2012 

A.K Quality Conirol ie.chnology & 

Repowering OptiCKlB for Jo.ppa St.tlon 

Final Rapor1 ~Draft 

R:sviaion: c 

Dats: 14 Feb 2011 

Table ES-4: Capttal iltld Op&llfting ¢ol!ll Summary for 8-Unft AQCS Options 

' Alternative 

Total C.apittl Firtl Year Flnt Y .. r I F1rst Y-.r I Tot<! Flnt I ToW 

FJxed Levellud .Requ!remt.nt1 

Ch.argesl Fb:td O&M1 V~~':~e ' Year CMtl i c .. r' 

51000 I SikW SlOOO SlOOO SIMWb S!too $/ton 

i ' rem.o~ed. rema"'ed i 

Cost Year Bru:i."s 2011 2011 2011 2011 lOll 2011 2Q Ye.r Life \ 

LSFO; Pre-gnd 6Unlto $404,500 $400 $n,soo $18,000 $0.62 $3,390 sl,Bo I 

LS.FO: Cnu:btd liUnlto $418,600 $410 $80,500 $18,500 S0.37 £3,420 $3,200 

I Advatec.b '6 Uultr 

SDA+FF 6 Uo!IJ $459,300 $4-50 $88,400 $18,700 $0.99 $3,980 $3,690 

CFB+FF 6Unltl $415,100 $4!0 $79,900 $15,100' $!.08 : $3,510 $3,270 

FDA+FP 16 Unlu $392,600 $380 $75,500 $13,600 $1.00 $3,440 $3,230 

DSI+FF ! 6 tJaits $344,500 $300 $66,300 $9,000' $3.50' $6,500 $6,390 

i ReACT 6Unla $410,000 $400 $18,900 $18,200 $0.90 $3,400 $3,200 

SCR ~Untts $271,800 $270 $52,300 $3,800 $0.% $20,800 $!8,300 

1) Cost ba!ed ® Des1gn Coal 

2) Cost baaed on O~g Coat 

3) Tou.l Fim Yw-md Tou:l LeYCitzcd doll.an; ill sum ofFLw.uJ·~fixod-wl VariilblcO&M oost~.. ions renmvcd is-~ oa.OpcmingCoal oondiciobJ (mShoo rc:ma~¢11 c&lcuWK:m. FO'f .a.ll a.:ept Sat. basod Qfi.!Otd of SO:! n::rn\WQi, SCR baied 1m (ens ofNOx reroollcd, 

8 

' 
i 

Electronic Filing- Received, Clerk's Office, 08/15/2012 

URS Air Quality Control l'aehnology & 

REipowuing Optlorua for Joppa stat!~ 

Tabla ES--2: Capltal and Openrting Coli Summary for Wnit AQCS Options 

! Fint Year : Tot.ll Capital Pint Veur Fixed Requb-emeot1 'Fixed0&M1 

Altenutive Chtrgea.• 

SlOOO I I!kW SlOOO $10(10 

C(lst fegr BtJSJ.s :Ull.l 2011 2011 :Ul11 

LSFO: P!"t-grull.JWI 3 Units $228,300 $450 $43,900 $10,500 

LSFO: Cruthe<1 3 Units $236,500 $460 $45,500 $10,900 

Aclva.tec.b 3 On:h::s 

i 

SDA .. FF 3 Tlnibl .'U28,000 $450 $43,900 • $10,000 

I 

CFB .. FF 3 0Dlt1 $204,100 S400 $39,300 $8,200 

FDATFP J Unltl $195,100 $380 $37,500 I $7,400 

ReACT i :3. Onits $218,700 $430 S42,100 $10,400 

SCR lUaltr $101,000 1300 $19,500 $1,500 

J) Cart-"" Dos.gn Coal 

2) CD£t ba.::lo!l on Opcreting Q)&.t 

First Yt:llr 1 Varil:ble 

O&.Ml 

SIMWh 

2011 

$0.60 

$0.35 

$0.97 

$1.06 i 

$1.00 

$0.90 

$0.46 

Flnal Report~ Orsft 

RBvls.lon: C 

Date: 14 Feb 2011 

Total TotAl Fint Leveliud YearCJ Coot' 

S/ton Siron 

removed r:emo:ved 

1011 20 Ye.ar Life 

i 

$3,&20 $3,570 i 

$3,880 ~,570 

I 

$4,010 $3,760 

$3,500 $3,300 

$3.480 $3,260 . 

I 

$3,650 $3,470 

$23,400 $20,600 

3) To!al Pim Year and: Tota1 Levcliz.ed dollm l.!. sum of Fixed Charge!. Flxed and Variable O&M ~. Tott5" removed is ~&ed (Ill. Oporalffig Coal conditions 

f@l' Slton ranovod calculation. Por an ex:upt SCR., based on tans ofS~ removoo.. SCR hued on tons afNOx removed. 

6 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

EXHIBIT2 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

:.!=~I: 

Electric Energy, Inc. 

Joppa Generating Station 

The Shaw Group InC:" 

EEl 

Joppa 

Generating 

Station 

Dry Sorbent 

Injection Test 

Program 

Draft Final Report 

September 8, 2010 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Table of Contents 

EXECUTIVE SUMMARY ................................................................................................................. ES-1 

1 INTRODUCTION ............................................................................................................................ 1 

1.1 JOPPA STATION .......................................................................................................................................... 1 

1.2 DIVISION OF RESPONSIBILITY ..................................................................................................................... 2 

2 CONDUCT OF THE STUDY .......................................................................................................... 3 

2.1 EXPERIMENTAL DESIGN ............................................................................................................................ 3 

2.2 REAGENT CHARACTERISTICS........................................... .......... ..... .......... ......... ....... ......... .. . .......... . .. 6 

2.2.1 Trona.... .. ... ......... ..... ... .......... .... . .... 6 

2.2.2 Sodium Bicarbonate (SEC) .............. . ...................................... . 

2.3 NOL TEeDS! FEED EQUIPMENT... .......... ...... ................ ..... ..... ..... . ................ . 

2.4 COAL .................................................................................................................................... . 

. ....... 7 

······· 7 

······ 8 

3 TESTPROGRAMRESULTS ........................................................................................................ 11 

3.1 AIREMISSIONSTESTRESULTS ............................................................................................................... 14 

3.1.1 Baseline program................. ................. .................. 14 

3.1.2 Trona, Un-milled Upstream of the Air Heater.. ................. ..15 

3.1.3 Trona, Milled Upstream of the Air heater.... ................... 17 

3.1.4 Trona, Milled Downstream of the Air Heater...................... ............... . 19 

3.1.5 Sodium Bicarbonate Downstream of the Air Heater. ......... ......... . .. 20 

3.1.6 Sodium Bicarbonate Upstream of the Air Heater Testing.... . ................................................... 21 

3.1. 7 Sodium Bicarbonate Downstream of the Air Heater Parametric Testing .................... 22 

3.1.8 Sodium Bicarbonate Downstream of the Air Heater Units 5 and 6 Steady State Testing ........... .... 24 

3.1.9 Cont. Sodium Bicarbonate Downstream of the Air Heater Units 5 and 6 Steady State Testing ...... 24 

3.1.10 Comparison of Certain Metals Emissions, Dwing Baseline and SBC Injection.......... .. ... 26 

3.1.11 Comparison of Acid Gas Emissions, During Baseline and SBC Injection.......... .. ............ 26 

3.1.12 DSI Impacts onNOx Emissions............... .................... ................ .. ....... 27 

3.2 COMPARISON OF DRY SORBENT UTILIZATION .......................................................................................... 27 

3.2.1 D1y Sorbent Utilization versus S02 Removal.... .................... ............... . ................. 27 

3.2.2 Impacts of Dry Sorbent Utilization on Particulate Emissions ................... . 31 

3.2.3 Impacts ofDSI Utilization on Mercury Emissions........... .......................... .. 32 

3.3 BYPRODUCT CHARACTERIZATION ............................................................................................................. 33 

3.3.1 Current Byproduct Operations ....................... .................. ................ ................... . ....... 33 

3.3.2 Byproduct Charaderization Testing................. ................. .................... . 33 

3.3.3 Highlights of Laborato1y Results................... .... ............. . .............. .............. . 34 

3.4 IMPACTS ON OPERATION .......................................................................................................................... 37 

3. 4.1 Utilization of DSI at Joppa........ ................... .......... ..... .............. . ................... 3 7 

3.4.2 Air Permit Considerations.......... ............... ..................... .. ................. 3 7 

3.4.3 ESP Upgrade Considemtions.... ........... .................... . 42 

3.4.4 B)product Handling and Lancifil/ Considerations... ............... .. ....... 49 

3.4.5 General Impacts on Plant Operation. .... .... ......... ............ ....... . .. ... 50 

3.5 COST ISSUES ............................................................................................................................................. 51 

3.5.1 Capital Cost Issues....................................................................................... .. .............. 51 

3.5.2 Operating Cost Considerations............................................................ .. ................................... 51 

4 CONCLUSIONS AND RECOMMENDATIONS ......................................................................... 53 

4.1 CONCLUSIONS ........................................................................................................................................... 53 

4.1.1 Plant Emissions Impacts.......... .................. .................... ............ . 53 

4.1.2 Plant Operatianallmpacts ............ ............... .. ...................................... 54 

4.1.3 By-Product Handling Impacts.......... ................ .. ..... 54 

4.2 RECOMMENDATIONS .................................................................................................................................. 55 

Q Sliaw'llm~<'>'~' <>o~ 1 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

List of Tables 

Table 2-1 - DSI Test Program .................................................................................................................. 4 

Table 2-2- Trona Characte1istics as Delivered ........................................................................................ 6 

Table 2-3 - Coal Analyses Results ................................................ , ........................................................... 9 

Table 3-1 -Average Dry Sorbent Injection Rates Per Test Event.. ............................... c •••••.••••••••••.•••••••• 12 

Table 3-2- Baseline Summary S02 Data ................................................................................................ 14 

Table 3-3 -Baseline Summary Particulate Matter Data .......................................................................... 15 

Table 3-4- Baseline Smmmry Mercury (Total) Data ............................................................................. 15 

Table 3-5 - Smnmary S02 Data, Un-milled Trona Injection Upstream of Air Heater ............................ 17 

Table 3-6 - Smmnary Particulate Matter Data, Un-milled Trona Injection Upstream of Air Heater.. .... 17 

Table 3-7- Summary Mercury (Total) Data, Un-milled Trona Injection Upstream of Air Heater.. ....... 17 

Table 3-8- Smnmary S02 Data, Milled Trona Injection Upstream of Air Heater. ................................. 18 

Table 3-9- Smnmary Particulate Matter Data, Milled Trona Injection Upstream of Air Heater.. .......... 18 

Table 3-10- Summary Mercury (Total) Data, Milled Trona Injection Upstream of Air Heater ............ 19 

Table 3-11 -Summary S02 Data, Milled Trona Injection Downstream of Air Heater. .......................... 20 

Table 3-12- Summary S02 Data, SBC Injection Downstream of Air Heater.. ....................................... 21 

Table 3-13 - Smmnary S02 Data, SBC Injection Upstream of Air Heater ............................................. 21 

Table 3-14- Smmnary Particulate Matter Data, SBC Injection Upstream of Air Heater ....................... 22 

Table 3-15- Summary Mercury (Total) Data, SBC Injection Upstream of Air Heater.. ........................ 22 

Table 3-16- Smnmary S02 Data, SBC Injection Downstream of Air Heater. ........................................ 23 

Table 3-17 - Summary S02 Data, SBC Injection Downstream of Air Heater.. ....................................... 24 

Table 3-18 - Smmnary S02 Data, SBC Injection Downstream of Air Heater.. ....................................... 25 

Table 3-19 - Summary Particulate Matter Data, SBC Injection Downstream of Air Heater .................. 25 

Table 3-20 - Smnmary Mercury (Total) Data, SBC Injection Downstream of Air Heater ..................... 26 

Table 3-21 - Comparison of Acid Gas Emissions ................................................................................... 27 

Table 3-22- S02 Removed Versus DSI Utilization (1) ........................................................................... 29 

Table 3-23 -Comparison of Total Particulate Emissions ........................................................................ 31 

Table 3-24- Review of Average Particulate Emissions versus DSI on Unit 6 ....................................... 32 

Table 3-25 -Particulate Significant Net Emissions Increase .................................................................. 38 

Table 3-26- Scenario 1 PSD Analysis Results··································'···················································· 40 

Table 3-27- Scenario 2 PSD Analysis Results ....................................................................................... 41 

Table 3-28 - General List of Concepts for Existing Generic Cold-Side ESP Upgrades ......................... 44 

Table 3-29- Estimated Annual Cost of Dry Sorbent .............................................................................. 52 

List of Figures 

Figure 3-1- Umnilled Trona Injection Utilization ................................................................................. 16 

Figure 3-2- SBC Utilization, Injection After the Air Heater ................................................................. 23 

Figure 3-3- Efficiency ofS02 Removal Using SBC After The Air heater. ........................................... 30 

11 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Attachments 

Attachment 1 -Source Emissions Sampling Report For Units 5 and 6 at Electric Energy, Inc. Joppa 

Station Project Number: 139424 

Attachment 2- Treatability Testing Report- Fly Ash/Sodium Bicarbonate mixture 

Attachment 3-NolTec System Infonnation 

Attachment 4- Notes of Team Members 

Attachment 5 -Dry Sorbent Quality Certifications 

Attachment 6- Dry Sorbent Feed Rate Data 

Attachment 7 -Plant PI Data 

Attaclnnent 8- Dry Sorbent MSDS Sheets 

Attaclnnent 9- Joppa Station ESP Information 

lll 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

AH 

ASTM 

Btu 

CEM 

CFR 

co, 

CPM 

CTM 

d.d. 

DI 

dNm3 

DSI 

ESP 

ft3 or cu ft 

h orbr 

HCl 

HF 

Hg 

HgOHM 

HgAppK 

Hgp 

Hg' 

Hg'+ 

HN03 

H20 2 

H,so. 

ICR 

KCI 

KMn04 

lb 

LCS 

M5 

mg 

mm 

mL 

mm 

mmacf 

Abbreviations and Acronyms 

Air heater 

American Society for Testing and Materials 

British Thennal Units 

Continuous emission monitor 

Code of Federal Regulations 

Carbon dioxide 

Condensable particulate matter 

Conditional Test Method 

Duct diameter 

Distilled or deionized 

Dry nonnal cubic meter 

Dry sorbent injection 

Electrostatic precipitator 

Cubic foot 

Hour 

Hydrochloric acid 

Hydrogen fluoride 

Mercury 

Mercury Ontario hydro method 

Mercury appendix K (method) 

Particle-bound mercury 

Elemental mercury 

Oxidized mercury 

Nitric acid 

Hydrogen peroxide 

Sulfuric acid 

Infonnation collection request 

Potassium chloride 

Potassium permanganate 

Pound 

Laboratory control sample 

Test Method 5 

Milligram 

Minute 

Milliliter 

Millimeter 

Million actual cubic feet 

IV 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, I11C, Draft Fi11al Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

MMBtu 

MWhorMW-hr 

cum or m3 

ug 

NaOH 

NCASI 

NH3 

N02 

o, 

PAC 

PJFF 

PM 

PMlO 

PM2.5 

pprnv 

PRE 

QC 

reps 

RPD 

SEC 

ShawE&I 

so, 

so, 

TAL 

TCLP 

TM 

tsf 

MillionBTUs 

Megawatt hour 

Cubic meter 

Microgram 

Sodium hydroxide 

National Council for Air and Stream Improvement 

Annnonia 

Nitrogen dioxide 

Oxygen 

Powdered activated carbon 

Pulse-jet fabric filter 

Particulate matter 

Particulate matter with an aerodynamic diameter less than or 

equal to a nominal 10 microns as measured by applicable test 

or monitoring methods 

Particulate matter with an aerodynamic diameter less than or 

equal to a nominal2.5 microns as measured by applicable 

test or monitoring methods 

Parts per million by vohnne 

Powder River Basin (coal) 

Quality control 

Replicates 

Relative percent difference 

Sodium bicarbonate 

Shaw Environmental & Infrastructure, Inc. 

Sulfur dioxide 

Sulfur trioxide 

Target analyte list 

Toxic characteristic leaching procedure 

Test method 

Ton per square foot 

v 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Executive Summary 

Electric Energy, Inc (EEl) commissioned The Shaw Group (Shaw Power and Shaw 

Environmental & Infrastructure, collectively Shaw) to determine whether Dry Sorbent 

Injection (DSI) in front of the existing electrostatic precipitators (ESP)s would be 

successful in removing 50% or more of the S02 in the gas stream without detrimentally 

impacting the operation of the ESPs and fly ash handling system. 

The scope of work presented a 10 day test program to determine the optimum location of 

DSI (before or after the air heaters), the condition the DSI (Trona or sodium bicarbonate) 

should be injected as (milled or un-milled), and the DSI rate (lbs/hr needed to achieve 

50% S02 removal). 

Study objectives included: 

• whether continuous 50% or better S02 reduction and continuous 90% mercury 

removal can be achieved during normal plant operations including turn down of 

the units due to market demands; 

• whether the use of a dry sorbent will impact the level of acid gases and heavy 

metals in the flue gas; 

• whether there is an impact to the air heaters if the selected DSI point was located 

upstream of the air heaters; 

• whether there is an impact to the ESP from either DSI reagent 

• whether there is an impact to the operation of the fly ash handling system, and; 

• whether there are any issues in the handling ofDSI that would cause undue 

hardship on the plant operation. 

The study was a collaborative effort among several entities. Overall direction was 

provided by EEI with support from Shaw who provided flue g"as testing, solids testing, 

program coordination support, and data analyses and reporting. Solvay provided the dry 

sorbent, and No!Tec provided the dry sorbent unloading and feed equipment and 

equipment operators. 

The conduct of the study occurred over a three week period from June 1-16,2010. 

Changes to the original program design were made as the program progressed in the 

field. Changes were judged necessary given data as it was reviewed, or in some cases 

changes were made because it was judged that results would not be meaningful. These 

changes are highlighted in the report. 

ES-1 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

From the data collected the following general conclusions can be made: 

• S02 removal of 50% can be achieved using DSI 

o Greater than 50% S02 removal was obtained with un-milled Trona and milled 

Trona before the air heater and with sodium bicarbonate (SBC) before or after 

the air heater. 

o 50% removal was not seen with milled Trona injecting after the air heater. 

• SBC was more efficient than Trona for removing S02 

o SBC had a better utilization efficiency than Trona whether milled or unmilled with a 0.158lbs S02 removed per lb of dry sorbent versus 0.100 lbs 

S02 removed per lb of dry sorbent for milled Trona when injection was 

before the air heaters. 

o Milled Trona was marginally more efficient than un-milled Trona in S02 

removal (ratio averagesO.lOO vs. 0.093, lbs S02 removed per lb of dry 

sorbent respectively) when injected before the air heater. 

• Injection upstream of the air heaters improves sorbent utilization 

o The injection location (whether before or after the air heater) impacts the 

efficiency of Trona and SBC utilization, with injection before the air heater 

having a greater utilization efficiency. 

o When using SBC for 50% S02 removal, a utilization rate of about 0.12 lbs 

S02 removed per lb of SBC is needed with injection after the air heater and 

a significantly greater utilization (>0.158lbs S02 removed per lb of dry 

sorbent) if injection is before the air heater. 

0 

• DSI will reduce acid gases but no impact on heavy metals was seen 

o About 80% removal was seen for HCl and HF 

• DSI will trigger PSD 

o The addition of a dry sorbent to the flue gas trains will result in an increase 

in the particulates (both total PM and PMlO) leaving the stack, to the point 

that Prevention of Significant Deterioration (PSD) regulations would be 

applied to the plant modification due to exceeding the "significant net 

emission" threshold for particulate emissions. Upgrades to the plant ESPs 

would be required to offset this increase in particulates. 

• DSI by-product can be Iandfi!Ied but will require system upgrades 

o The increase in fly ash generated with DSI will require increased capacity 

of the fly ash handling system's daily operation, and/or additional storage. 

o The by-product handling operation and landfill operation will require the 

following: 

• The by-product should be wetted in a two stage approach where a 

portion of the water is added at the dustless unloader for dust 

ES-2 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

control and the remaining water needed for optimum compaction be 

added at the landfill via a water truck or like conveyance system. 

• The runoff pH will likely be high enough to require neutralization 

of the landfill pond runoff prior to discharge. 

• The landfilled material will need to be managed (covered) to 

minimize standing water on the by-product due to its potential 

dissolution. The dissolution will increase the total dissolved solids 

in the landfill runoff potential to a point impacting its discharge 

permit and potentially the landfill integrity over the life of the 

landfill. 

• No significant impact on the air heaters or ESPs observed 

o No increase in air heater pressure drop was observed when injecting either 

SBC or Trona upstream of the air heaters. 

o ESP % removal performance and stack opacity did not change when 

injecting either sorbent and firing East Thunder coal. Some affect was 

observed when firing Belle Ayr coal. Due to increased inlet loading, the 

additional outlet loading was enough to trigger PSD. 

• DSI will significantly increase O&M costs 

Notes: 

o Based on a delivered cost of$175/ton for Trona and $200/ton for SBC the 

annual reagent cost assuming that the plant were to operate at 90% capacity 

factor burning a 0.61 lb/MMBtu S02 coal with 50% S02 removal and DSI 

before the air heater is about $16,000,000/yr. See the summary cost table 

below for relative cost of Trona and alternative injection locations. 

1. Based on 50% S02 removal with plant burning PRB coal with 0.61 lbs of 

S02/MMBtu and a yearly plant capacity factor of 0.90 

2. The data for milled Trona injection after the air heater is minimal. This utilization 

rate achieved an average of 42.6% S02 removal. The utilization rate would 

likely be higher to achieve 50% removal, so the yearly estimated cost would 

likely be higher than shown to achieve 50% S02 removal. 

ES-3 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, 

Joppa Generating Station 

Joppa, Illinois 

Draft Final Report 

Dry Sorbent Injection Test Program 

3. The data for SBC injection before the air heater is minimal. This utilization rate 

achieved an average of 67% S02 removal. The utilization rate would likely be 

lower to achieve 50% removal, so the yearly estimated cost would be lower than 

shown to achieve 50% S02 removal 

The following recommendations can also be made: 

• Estimate the cost of particulate control upgrades for DSI options 

o Evaluate unmilled Trona injected before the air heater with ESP upgrades 

to address current regulations and not trigger P SD (high risk alternative), 

since un-milled Trona may have less of an impact on particulate emissions 

than other dry sorbents. 

o Evaluate other DSI options and address future utility MACT rules by 

adding a helper ESP or a fabric filter downstream of the existing ESP. 

• Perform economic engineering evaluation of 802 control technologies for the 

Joppa Station 

o Design criteria in line with expected utility MACT regulations for 

evaluating different options: 

• DSI with helper ESPs and fabric filters 

• Wet flue gas desulfurization 

• Dry flue gas desulfurization 

• ReACT 

If the use ofDSI at Joppa is still viable after the review of ESP efficiency upgrades, then 

additional testing is warranted that would include: 

o Prolonged injection of each reagent upstream of the air heaters to 

determine potential long term impacts 

o Testing on both Units 5 and 6 so that the stack CEMs can be utilized 

versus induct sampling. 

o Additional mercury testing should be included 

• It would be beneficial for Joppa to conduct a full PSD analysis at the conclusion of 

CY20 10 operation using the latest emission data. 

ES-4 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

1 Introduction 

Electric Energy, Inc (EEl) commissioned The Shaw Gronp (Shaw Power and Shaw 

Environmental & Infrastructure, collectively Shaw) to determine whether Dry Sorbent 

Injection (DSI) in front of the existing electrostatic precipitators (ESP)s would be 

successful in removing 50% or more of the S02 in the gas stream without detrimentally 

impacting the operation of the ESPs and fly ash handling system. 

The scope of work developed jointly by EEI and Shaw was a high level test program. It 

presented a 10 day test program to determine the optimum location ofDSI (before or 

after the air heaters), the condition the DSI (Trona or sodium bicarbonate) should be 

injected as (milled or un-milled), and the DSI rate (lbs/hr needed to achieve 50% S02 

removal). 

At the completion of parametric testing on Unit 6, Units 5 and 6 were tested with flue gas 

testing being performed in the combined stack. This performance testing was to last up 

to 5 days on a continuous 24 hour basis to determine: 

• whether continuous 50% or better S02 reduction and continuous 90% mercury 

removal can be achieved during normal plant operations including turn down of 

the units due to market demands; 

• whether there is an impact to the air heaters (if upstream of the air heaters was the 

selected DSI point); 

• whether there is an impact to the ESP from either DSI reagent 

• whether there is an impact to the operation of the fly ash handling system, and; 

• whether there are any issues in the handling of DSI that would cause undue 

hardship on the plant operation. 

1.1 Joppa Station 

The Joppa Generating Station is a six unit coal fired power plant located at 2100 Portland 

Road, in Joppa Illinois. The station is located on the Ohio River. Each unit is rated for 

181 MW. The plant was commissioned between 1953 and 1955. The plant is currently 

burning various Powder River Basin Coals. 

The Joppa station is operated by Electric Energy Inc., an independent power producer, 

and is owned by Ameren (80%) and Kentucky Utilities (20%). 

The plant's capacity factor is historically greater than 92% inclusive of all planned and 

forced outages. Normally, all six units are continuously operating at or near their 

capacity. Therefore, it is imperative that any backend environmental controls 

implemented at the site are robust and the designs are redundant so as to be highly 

reliable and not cause forced outages of the plant technology. 

1 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

The plant is currently equipped with a S03 injection systems for flue gas conditioning 

(fly ash resistivity treatment) and activated carbon injection systems for mercury 

removaL (The S03 injection system was not active during this test program.) 

1.2 Division of Responsibility 

The study was a collaborative effort among several entities. Overall direction was 

provided by EEI with support from Shaw, Solvay, and NolTec. The general Division of 

Responsibilities was as follows: 

EEl 

• Overall program management 

• Plant operations 

• Obtain permits I approvals from IEP A 

• Obtain reagents and arrange delivery 

• Obtain experimental injection equipment and operating services 

• Provide plant tie-ins including injection sites, electrical power and trailer space 

• Provide office space, conference room and sanitary facilities 

• Obtain coal and byproduct samples 

• Provide PI data output 

Shaw (Shaw Power and Shaw E&D 

• Assist EEl with test program development 

• Perform flue gas testing 

• Obtain laboratory analysis of solid media 

• Perform a characterization study of byproduct materials 

• Provide assistance with overall coordination 

• Data analysis 

• Draft and final reports 

NolTec Systems 

• Provide, install and demobilize DSI storage, milling and injection equipment 

• Provide operators for their equipment 

• Record feed rates 

• Analyze reagents 

Solvay Chemicals 

• Arrange for the procurement and delivery of reagents 

• Provide consultation on use of reagents 

2 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

2 Conduct of the Study 

2.1 Experimental Design 

The study objectives were: 

• demonstrate 50% S02 removal using DSI 

• determine effect of DSI on mercury removal 

• determine effect on ESP performance and outlet particulate emissions and 

opacity 

• quantify any changes in certain pollutants including acid gases and some metals 

• determine byproduct characteristics to assist with landfill operations; and 

• assess the impact of overall operation on plant equipment and infrastructure. 

The conduct of the study as it was perfonned over portions of three weeks is shown in 

Table 2-1. Some changes were made from the original design as the program progressed 

in the field. Changes were judged necessary given data as it was reviewed or in some 

cases, changes were made because it was judged that results would not be meaningful. 

Sample point locations consisting of single point sampling included the following 

locations: 

• Economizer Outlet- consisted of two parallel ducts (Duct A & B) each with a 

cross sectional area of 230 square feet at the sampling location. 

• ESP Inlet- consisted of two parallel ducts (Duct A & B) each with a cross 

sectional area of 23 0 square feet at the sampling location. 

• ESP Outlet- consisted of two parallel ducts (Duct A & B) each with a cross 

sectional area of 25 0 square feet at the sampling location. 

• Common #3 Tall Stack- single annular stack with an 18 foot diameter at the 

sampling location. 

Selection of the sampling point at each location was based on first traversing each 

location taking flow and temperature readings and selecting the point most representative 

for that location. This sampling methodology, though not totally consistent with EPA 

sampling protocols, was chosen based on cost considerations and the comparative 

analyses needed for this engineering study. 

All CEMS (e.g. 0 2, C02, NOx) measurements were conducted at a single point centrally 

located inside Duct A of each designated sampling location, simultaneously with each 

wet chemistry method (e.g. PM, Hg). Wet chemistry sampling trains were located at the 

common #3 Tall Stack and a single centralized location inside Duct B of each sampling 

location. 

3 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, 

Joppa Generating Station Joppa, Illinois 

mobilization, 

Setup injection and 

test 

June4 I I I Baseline testing. F1iday 

June 5 12 I Baseline testing. Saturday 

June 7 13 I Un-milled Trona Monday mJectwn 

June 8 4 Milled Trona 

Tuesday injection 

June 9, 5 Milled Trona 

Wednesday Injection 

.I::J. SHaw· nm l:hwv 

NA None 

INA I None 

I Upsh·eam of I Trona 

air heater 

Upsh·eam of Trona 

air heater 

Down- Trona 

stream of air 

heater 

4 

Dry Sorbent Inje

Two runs. Unit 6. CEMs in/out; Test 

OHM in/out; PM in/out; stack- S02/

OHM, TM29, TM26A, TM8A; AC/M

TM30B. Coal 

. 

-- I Two runs. Unit 6. CEMs in/out; 

OHM in/out; PM in/out; stackOHM, TM29, TM26A, TM8A; 

TM30B. 

- I Tiwee runs. CEMs in/out; Dete

OHM in/ant; PM in/out. Tron

50% 

Three runs. CEMs in/out; Deter

OHM in/out; PM in/out. injec

reduc

Morning runs. CEMs (only) Deter

in/out injec

reduc
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, 

Joppa Generating Station 

Joppa, Illinois 

injection 

Jlme 10 16 I Pre-milled SBC 

June 11, 17 I Pre-milled SBC Friday injection 

June 14, 18 I Pre-milled SBC Monday mJeCtton 

J1me 15 

19 

I Pre-milled SBC 

Tuesday injection 

Jm1e 16, I 

Wednesday 

I Testing terminated 

due to Unit 5 tube 

leak 

Stiiiiw' l!w a-QIT)\jf) 

I stream of air I 

heater 

I Upstream of SBC 

air heater 

I After air SBC 

heater 

I After air 

heater 

ISBC 

I After air SBC 

heater 

I I 

5 

D

Dry Sorbent Inject

Determ

I in/out I rate for 

Three nms. CEMs in/out; Determ

OHM in/out; PM in/out. rate for 

Units 5 & 6. Three runs. CEMs Parame

(only) in/out determ

at vary

Units 5 & 6. Three mns. CEMs Determ

(only) in/out (stack CEMs) rate for 

two un

Three nms. Unit 5&6. CEMs 

in/out; OHM in/out; PM in/out; 

stack-OHM, TM29, TM26A, 

TMSA; TM30B. TMS and 202; 

Coal, ash, byproduct (5 x 5 

I gallons}. 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dty Sorbent Injection Test Program 

Joppa, Illinois 

2.2 Reagent Characteristics 

2.2.1 Trona 

Trona is derived from sodium sesquicarbonate rock. Its formula is 

Na2C03.NaHC03 .2H20. The rock is typically milled and delivered at a fineness of30-

35 microns. Typical moisture of delivered product is 0.03%. (SOLVAY, 2010). 

Delivery sheets are found in Attachment 5. 

Trona materials were secured from Solvay Chemicals, tnc, Houston, Texas. The product 

is identified as: SOLVAir Select 200 BULK (Material Code 60178). Customer 

Specification Number is SS200-0108. Characteristics of Trona as delivered comes from 

truck invoices, as follows: 

6 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

On certain days, onsite milled Trona was used for injection. Particle size analysis was 

conducted by Sturtevant from samples provided by NolTec. Laboratory data are 

provided in Attachment 5. The "as delivered" Trona had a D50 of39 microns. The 

milled Trona had a measured D50 of 26 microns. 

2.2.2 Sodium Bicarbonate (SBC) 

Sodium bicarbonate is a downstream product made from Trona. Its formula is NaHC03. 

Pre-milled materials are delivered at D90 of< 40 microns. In literature, Solvay 

recommends onsite milling to <20 microns prior to injection (Solvay, 2010. Dry Sorbent 

Injection of Sodium Sorbents. Emissions Control and Measurement Workshop. March 

24-25, 2010). 

The pre-milled SBC materials were secured from Solvay Chemicals, Inc, Houston, 

Texas. The product is identified as: BIR SOLV AIR SELECT 350 HNM BULK (Solvay 

Material Code 65591) also known as SOLV AIR 350 BULK. The trucks delivering the 

productwere loaded from bulk bags which had been storing the pre-milled SBC. 

Material Certifications provided with each delivery had descriptions -

Customer Material Specification: 

Sodium, aS Na>= 27.00% 

Sodium Bicarbonate, as NaHC03 = 99.0- 100.50% 

Screen Analysis %Retained ... 

US 200 (75 micron) 20- 100% 

US 325% (45 micron) 60- 100% 

It should be noted that much of the delivered SBC had clumps of material within the 

delivered bulk causing unloading problems. These clumping and unloading problems 

were not seen with the delivered un-milled Trona. Certifications are provided in 

Attachment 5. 

2.3 No/Tee DSI Feed Equipment 

The DSI system was "Sorb-N-Ject" provided by NolTec Systems, Lino Lakes, MN. 

(Drawings and additional information on the No!Tec provided system can be found in 

Attachment 3.) The system had one portable free standing storage silo. The silo capacity 

was 1450 cu ft. The silo had load cells for monitoring weight loss of materials. Weight 

loss as a function oftinre was used in the field to quantify the feed rate. When filling, a 

bin vent filter controlled dust from displaced air and material transport air. Feed was 

controlled by dual-speed adjustable rotary feeders. The silo was filled, as needed, by 

bulk carrier trucks. Trucks generally contained 45,000-50,000 pounds of material. Silo 

fill time was about one hour when there was no reagent clumping. 

7 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

A portable blower trailer was also provided. The design capacity of the sorbent feed 

system was 20,000 lb/hr. The blowers were positive displacement rotary blowers driven 

by a 40 HP motor. Each blower was capable of providing 500 scfm at 11.5 psig. The 

system included a heat exchanger, conveying piping and injection lances. The trailer also 

housed control and electric supply equipment and operator space. 

The in-line milling system was designed for use with Trona. The Sturtevant Simpactor 

was a centrifugal, pin-type impact mill. The system had dual plate rotor with one row of 

pms. 

NolTec provided lances were inserted above the air heater (one unit) and below the air 

heater (two units). They were straight pipes with flat, cutoff ends. Lances were inserted 

at staggered lengths before the air heater The lances after the air heater were all the same 

length .. 

2.4 Coal 

During the performance ofthe test program, the plant burned two Powder River Basin 

(PRB) coals; East Thunder (Jacobs Ranch) and Belle A yr. The significant difference 

between these two coals was sulfur content with the Jacobs Ranch coal having almost 

twice the sulfur content with 1.07 lbs/MMBtu S02 versus 0.58 lb/MMBtu S02 for the 

Belle Ayr coal. The mercury concentration in the Jacobs Ranch coal was also higher. 

Table 2-3 presents the analyses of the daily samples of the coals. It should be noted that 

for coal utilization, the sample was taken near the end of that day's testing.· 

8 
Electric Energy, Inc, 

Joppa Generating Station Joppa, Illinois 

Ranch , 612110 I 8420 I 5.96 I 

Jacobs I 6/3/10 I 

Ranch 9150 I 6.79 I 

Jacobs I 6/4/10 I 

Ranch 

8420 I 5.85 I 

Jacobs 

I 6/5/10 I 8370 I 5.5 I 

LC11 I 6/6/10 8710 5.64 

Jacobs [ 617110 Ranch 8630 5.7 

Jacobs I 6/8/10 I 

Ranch 7840 I 5.17 I 

Jacobs I 6/9/10 I 

Ranch 8390 I 6 I 

Jacobs 6/10/10 I 8470 I 5.63 I ch 

Jacobs 6111110 I 8430 I 5.79 I Ranch 

Comb- I 6/12/Hl I 

matwn? 8390 I 5.02 I 

Belle 

Ayr I 6113/Jo I 8380 I 5.04 I 

Electronic Filing- Received, Clerk's Office, 08/15/2012 

14.16 I 0.48 I 1.14 I 0.02 I 3.0 I I 302 I <1 

14.84 I 0.49 I 1.07 I 0.02 I 2.48 I 307 I <I 

13.90 I o.s I 1.19 I 0.01 I <2 I 308 I <I 13.14 I 0.48 I 1.15 0.02 <2 315 <I 12.95 0.44 1.01 0.02 <2 300 <I 13.21 0.49 1.14 O.Dl 2.21 344 <1 13.19 I o.35 I 0.89 I 0.01 I <2 I 377 I <I 

14:30 I 0.43 I 1.03 I 0.02 I <2 I 321 I <1 

13.29 I 0.45 I 1.06 I 0.02 I <2 I 311 I <I 13.74 I 0.45 I 1.07 I 0.02 I <2 I 330 I <I 11.97 I 0.36 I 0.86 I <0.01 I <2 I 307 I <I 

12.03 I o.24 I 0.57 I <o.o1 I <2 I 355 I <I 

9 

Dry Sorbent 

I 6.65 I 3.16 I <2 I 6.5 I 2.43 I <2 

I 6.21 I 2.14 I <2 

6.0 3.2 <2 

5.91 1.65 <2 

5.92 2.29 <2 

I 6.54 I 2.61 I <2 

I 6.38 I 2.27 I <2 I 6.24 I 2.72 I <2 I 5.9 I 2.49 I <2 

I 5.52 I 2.05 I <2 

I 4.94 I !.66 I <2 
Electric Energy, Inc, 

Joppa Generating Station 

Joppa, lllinois 

6/14110 8350 

6/15110 8510 

5.11 

4.59 

Jacobs I I 8483 I 5.80 I Ranch 

Belle 

I I 

8413 I 4.91 I 

Ayr 

Percent Belle 

Ayr of I I 99.18 I 84.7 I 

Jacobs 

6 SliaW#Ilmlhw 

Electronic Filing- Received, Clerk's Office, 08/15/2012 

12.24 0.23 0.55 

10.79 0.26 0.61 13.67 I 0.46 I 1.07 

11.69 I 0.24 I 0.58 

85.5 I 53.4 I 53.84 

0.02 <2 319 <1 

0.01 <2 295 <1 

I 0.011 I <2.17 I 322 I <1 I <0.013 I <2 I 323 I <1 

4.63 4.31 

Dry Sorben

1.72 <

2.19 <

I 6.23 I 2.50 I <I 4.63 I 1.86 I <

I 76.47 I 92.2 I 1oo.s I 100 I 74.3 I 74.4 I 10

10 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, IllC, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

3 Test Program Results 

The experimental design for the program is described in Section 2.1. The program 

considered two reagents, Trona and Sodium Bicarbonate (SBC). Trona was injected into 

duct work at as delivered particle size and after onsite milling. SBC was injected as 

received. SBC was milled prior to shipping to the site. However, there was some 

clumping of the SBC in the bulk delivery vehicles. Trona was injected both upstream 

(un-milled and milled) and downstream (milled) of the air heater (AH). SBC was also 

injected both upstream and downstream of the air heater. The feed rates of the DSI were 

varied throughout the test program with the general intent to achieve 50% S02 removal 

and to determine DSI utilization trends versus S02 removaL Table 3-1 provides the 

average DSI feed rates used throughout the tests. These average feed rates are based on 

the NolTec DSI storage cell load cell readings which are provided in Attachment 6. It 

should be noted that during some of the test runs DSI was added to the storage cell 

resulting in unusable load cell readings. During these occasions airlock speeds were used 

to estimate average DSI rates based on available data near the time of the silo feeding 

event.. 

11 
Electric Energy, Inc, 

Joppa Generating Station Joppa, Illinois 

4-Jun I I 

5-Jun I I 

I I 

7-Jun I I I 12:oo I 

7-Jun I 2 I 15:15 I 7-Jun I 3 I 18:00 I 

8-Jun 1 9:45 

8-Jun 2 12:29 

8-Jmt I 3 I 15:21 I 

9-Jllll 1 10:52 9-Jun 2 15:27 

10-Jun 1 10:00 

10-Jmt 2 12:45 

'!1)0 Sl\'ffl" 

Electronic Filing- Received, Clerk's Office, 08/15/2012 

I None I NA 

I None NA 

13:oo I Unmilled Before air heater Trona -Unit' 

17:oo I Unmilled Before air heater I Trona -Unit 6 

18:34 I Unmilled Before air heater 'T'rona -Unit 6 10:47 Milled Trona Before air heater T L 

13:35 Milled Trona Before u.u .u ....... u ..... ._ I -Unit 6 

16:21 I M"ll d T I Before air heater I I e rona - Unit 6 

12:31 Milled Trona After air heater I -Unit" 

16:00 Pre-milled After air heater I SBC -Unit 6 

11:03 Pre-milled _, UV-.VL I SBC -Unit 6 

13:50 Pre-milled Before air heater I CODE' -Unit 6 

12 

NA 

NA 

5,971 

11,659 10,219 

8,838 8,561 8,688 

14,237 11,643 

7,733 7,275 

Dry Sorbent I

BaseBase
Electric Energy, Inc, 

Joppa Generating Station Joppa, Illinois 

10-Jun I 3 I 15:20 

11-Jun I I I 11:23 11-Jun I 2 I 12:14 11-Jun I 3 I 16:14 

14-Jun I I I 9:53 

14-Jtm I 2 I 13:05 

15-Jmt I I I 8:50 

15-Jun I 2 I 12:15 

15-Jmt I 3 I 14:59 

l:l. Snaw•·nm t>rK•wGIIl<+> 

I 

I 

I I 

I I 

I I 

I 

Electronic Filing- Received, Clerk's Office, 08/15/2012 

16:27 I _I_ J.V-.l.l.U.l_I_VY- Before air heater I -Unit 6 

II :52 I Pre-milled After air heater - I SBC Units 5 and 6 

13:31 I Pre-milled After air heater - SBC Units 5 and 6 

17:31 I Pre-milled After air heater - SBC Units 5 and 6 

12:38 I Pre-milled After air heater - SBC Units 5 and 6 

17:07 I Pre-milled After air heater - SBC Units 5 and 6 

9:50 I Pre-milled After air heater - SBC Units 5 and 6 

13:33 I Pre-milled After air heater - Units 5 and 6 

16:08 I Pre-milled After air heater - SBC Units 5 and 6 

13 

6,921 

5,882 

11,077 14,665 

9,284 9,683 

10,200 

9,956 

10,438 

D1y Sorbent Inj

SBC added to si

estimates were 

s

added to si

estimates were 

s

SBC added to si

estnnato;s were 

s

SBC added to si

estnnates were 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

3.1 Air Emissions Test Results 

This section presents summary results of air emissions test data. Details of the test 

performed are found in Attachment 1. The plant's S03 injection flue gas conditioning 

system was taken out of service for all tests. Trona, like S03, is also used to increase the 

conductivity of fly ash for removal in ESPs. Trona would also remove the S03 before it 

would be effective. The plant's PAC injection mercury control system remained in 

operation. PAC was injected at a minimum of Sib ofPAC/mmacf. At the time of the 

DSI Test Program, PAC was injected upstream of the air heaters on Units 5 and 6. Plant 

PI data records were secured during all tests to document plant loads and performance 

during the test date. 

3.1.1 Baseline program 

The purpose of the base line program was to document emissions and plant operating 

characteristics prior to reagent injections. The results from the test injections are 

compared to the baseline as appropriate. 

Baseline testing occurred June 4 and 5. Two test runs were performed on each of the two 

days. The plant was burning Powder River Basin (PRB) coal with approximate 0.9 to 1.2 

lb S02/MMBtu content (East Thunder- Jacobs Ranch coal). This is a somewhat higher 

sulfur content than what the plant normally fires. 

At Unit 5, particulate and mercury were measured before the ESP. At Unit 6, S02, 

mercury and particulate were measured before the ESP and particulate, mercury, S02 

after the ESP. At the combined stack, particulate, mercury, metals, acid gases and S03 

were measured. Coal was sampled during baseline testing and a five gallon ash sample 

was secured for comparison to mixed ash/spent reagent. 

Plant PI data records were secured during all tests to document plant loads and 

performance during testing. 

Summary S02 data are shown in Table 3-2. The values presented are the averages of 

four runs taken over two days. 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

These results were compared to the #3 Tall Stack (units 5 and 6) CEMs data for 

continuation. The average S02 emission from #3 Tall Stack during these test runs was 

3,756lb!hr or based on the assumption that emissions from Unit 5 equal Unit 6 the 

emission from Unit 6 would be 1,878 lblhr or about 12% higher than what was read at the 

ESP outlet. The difference in the results is likely the result of non-uniformed sampling in 

the duct due to stratification of the flue gas path. Because of this apparent bias between 

CEMs readings a decision was made to compare sulfur dioxide removal against the stack 

CEMs readings. 

Particulate matter emissions data are shown in Table 3-3. The values presented are the 

averages of four runs taken over two days. Data indicate overall ESP efficiency of 98.88 

percent. The removal efficiency is used in comparing baseline operation with operation 

during DSI. 

Total mercury emissions data are shown in Table 3-4. The values presented are the 

averages of four runs taken over two days for #3 Tall Stack (units 5 and 6). Data indicate 

overall removal efficiency of 93 percent (based on coal mercury concentration) using the 

plant's installed PAC injection system. The removal efficiency is used in comparing 

baseline operation with operation during DSI. 

3.1.2 Trona, Un-milled Upstream of the Air Heater 

The purpose of this program segment was to document emissions and plant operating 

characteristics injecting un-milled (D50 of39 microns) (not milled on site) Trona 

upstream of the AH. The Trona size analysis is shown in Section 2.2. 

The test occurred on 7 June. Three test runs were performed on the test date. The plant 

was burning coal from the East Thunder (Jacobs Ranch) mine with an approximate 0.9-

1.2 lb S02/MMBtu content. During the performance of the tests one of the DSI blowers 

15 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

tripped on overheat for about 20 minutes (15:35 -15:55) which reduced the injection of 

Trona by one/half for that period of time. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances into 

the plant ductwork. 

In accordance with the test pro gram no measurements were made on Unit 5. On Unit 6, 

S02 and mercury were measured at the economizer outlet "before injection". Particulate 

matter (TM5) was measured before the ESP and fme particnlate (PM10 and PM2 5), 

mercury and S02 after the ESP. Coal was sampled during testing. 

Summary S02 data are shown in Table 3-5. Un-milled Trona was injected from 8:45 to 

18:55 at varying rates (-3,000 - > 13,000 lblhr). The Trona injection information was 

compared to the Stack CEMs data to discern a trend. The Unit 6 S02 concentration 

before DSI was estimated based on the S02 concentration in the stack before and after 

DSI with one half of the S02 assumed to come from Unit 6. The results were graphed 

and are shown in Figure 3-1. 

I "' " 0 

!= 0,3 "C 

Un-milled Trona Utilization 

• • v~- -0.1216x+ 0.1559 Injected Before Aar heater w~o.1?ss 

,!!! 

'E a.zs 

t: 

::> 0.2 c;., 

.<>!! 

~ u 0.15 ~ 

.. -"' c.£: 

.., 0.1 .. 

> 

0 0.05 E 

" "" N 0 

0 

"' 0.00% -" 10.00% 20,00% 30,00% 40.00% 50.00% 60.00% 70.00% ~ 

PercentS02 Removal 

Figure 3-1- Unmilled Trona Injection Utilization 

The results indicate an overall removal efficiency range of 13- 59% percent and with an 

efficiency ratio of 0.093 lb S02 removed per lb of sorbent injected at 50% S02 removal. 

16 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

removal 

Summary particulate matter emissions data are shown in Table 3-6. The values presented 

are the averages of three one-hour runs. Data indicate overall ESP efficiency of 99.44 

percent, somewhat better than the baseline efficiency. 

Total mercury emissions data are shown in Table 3-7. The values presented are the 

averages of three runs. Calculations, discussed in Attachment 1, indicate overall removal 

efficiency of 87.7 percent (based on coal mercury concentration). This removal 

efficiency is not necessarily comparable to the baseline since this is based on Unit 6 only 

and a comparison requires the assumption that unit 6 equals Unit 5 in emissions. 

3.1.3 Trona, Milled Upstream of the Air heater 

The purpose of this program segment was to document emissions and plant operating 

characteristics injecting milled (D50 of26 microns) (milled on site) Trona upstream of 

the AH. Laboratory size analysis for the milled Trona can be found in Attachment 5. 

17 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

The test occurred on 8 June. milled Trona was injected from 9:10 to 16:40 at an average 

uniform rate of 8600 lblhr+/-. The plant was burning coal from the East Thunder (Jacobs 

Ranch) mine with an approximate 0.9- 1.2 lb S02/MMBtu content. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances into 

the plant ductwork. 

In accordance with the test program no measurements were taken on Unit 5. On Unit 6, 

S02 and mercury were measured at the economizer outlet "before injection". Particulate 

matter (TM5) was measured before the ESP and fme particulate (PM10 and PM25), 

mercury and S02 after the ESP. Coal was sampled during testing. 

Summary S02 data are shown in Table 3-8. The Trona injection information was 

compared to the Stack CEMs data. The Unit 6 S02 concentration before DSI was 

estimated based on the S02 concentration in the stack before and after DSI with one half 

of the S02 assumed to come from Unit 6. The values presented are the average ofthe 

injection throughout the day. The values indicate an overall removal efficiency of 52.6 

percent and with an efficiency ratio of 0.10 1b S02 removed per lb of sorbent injected. 

The ratio shows an improvement in removal efficiency over un-milled Trona. 

Average S02 Units 5 and 6 Before Lb/hr 3273 

DS test 

Average S02 (Unit 6), before DSI Lb/hr 1637 

Surmnary particulate matter emissions data are shown in Table 3-9. The values presented 

are the averages of three one-hour runs. Data indicate overall ESP efficiency of 98.68 

percent, not quite as good as the baseline efficiency or that for un-milled Trona. 

18 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dty Sorbent Injection Test Program 

Joppa, Illinois 

Total mercury emissions data are shown in Table 3-10. The values presented are the 

averages of three runs. Calculations, discussed in Attachment 1, indicate overall removal 

efficiency of 84.1 percent (based on coal mercury concentration). This removal 

efficiency is not necessarily comparable to the baseline since this is based on Unit 6 only 

and a comparison requires the assumption that unit 6 equals Unit 5 in emissions .. 

3.1.4 Trona, Milled Downstream of the Air Heater 

The purpose of this program segment was to document the S02 emissions and plant 

operating characteristics injecting milled (D50 of26 microns) (milled on site) Trona 

downstream of the AH. 

The test occurred on morning of9 June. milled Trona was injected from 8:50 to 12:30 at 

an average injection rate of 14,493 lb/hr once the injection rate was stabilized. The plant 

was burning coal from the East Thunder (Jacobs Ranch) mine with an approximate 0.9-

1.2 lb S02/MMBtu content. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances. into 

the plant ductwork. 

In accordance with the test program no measurements were taken on Unit 5. On Unit 6, 

S02 was measured at the economizer outlet "before injection", and after the ESP. Coal 

was sampled during testing. 

Summary S02 data are shown in Table 3-11. The Trona injection information was 

compared to the Stack CEMs data. The Unit 6 S02 concentration before DSI was 

estimated based on the S02 concentration in the stack before and after DSI with one half 

of the S02 assumed to come from Unit 6. The values presented are from the morning 

run. The values indicate an average removal efficiency of 42.6 percent and with an 

efficiency ratio of 0.049 lb S02 removed per lb of sorbent injected. The ratio shows this 

scenario, injecting downstream of the AH, to be the least efficient of the Trona test 

alternatives. 

19 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Lb/hr 1,670 

It was anticipated that this test scenario would be no be better, and probably worse than 

the injection before the AH due to the lower temperature of the flue gas. Thus no 

additional parameters were sampled. This was a CEMs only test. 

3.1.5 Sodium Bicarbonate Downstream of the Air Heater 

The purpose of this program segment was to document the S02 emissions and plant 

operating characteristics injecting SBC downstream of the AH. 

The test occurred on afternoon of9 June. SBC was injected from 14:40 to 16:00 with the 

feed rate ramping up from about 7000 lb!hr up to 11,750 lb/hr. The plant was burning 

coal from the East Thunder (Jacobs Ranch) mine with an approximate 0.9- 1.2 lb 

S02/MMBtu content. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances into 

the plant ductwork. 

In accordance with the test program no measurements were taken on Unit 5. On Unit 6, 

S02 was measured at the economizer outlet "before injection" and after the ESP. Coal 

was sampled during testing. 

Summary S02 data are shown in Table 3-12. The SBC injection information was 

compared to the Stack CEMs data. The Unit 6 S02 concentration before DSI was 

estimated based on the S02 concentration in the stack before and after DSI with. one half 

of the S02 assumed to come from Unit 6. The results indicate an overall removal 

efficiency of 60 percent and with an efficiency ratio of 0.084 lb S02 removed per lb of 

sorbent injected. The ratio and removal efficiency values were based on average 11,750 

lb/hr reagent injection. 

20 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Lb/hr 1,644 

Percent 

3. 1.6 Sodium Bicarbonate Upstream of the Air Heater Testing 

The purpose of this program segment was to document emissions and plant operating 

characteristics injecting SBC upstream of the AH. 

60 

The test occurred on 10 June. SBC was injected from 8:30 to 16:55 at an average 

injection rate of7,380 lb/hr The plant was burning coal with an approximate 0.9- 1.2lb 

S02/MMBtu content. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances into 

the plant ductwork. 

In accordance with the test program no measurements were taken on Unit 5. On Unit 6, 

S02 and mercury were measured at the economizer outlet "before injection". 

Particulate matter (TM5) was measured before the ESP and fine particulate (PM10 and 

PM25), mercury and S02 after the ESP. Coal was sampled during testing. 

Summary S02 data are shown Table 3-13. The SBC injection information was compared 

to the Stack CEMs data. The Unit 6 S02 concentration before DSI was estimated based 

on the S02 concentration in the stack before and after DSI with one half of the S02 

assumed to come from Unit 6. The results indicate an average removal efficiency of 

67.1 percent and with an efficiency ratio of 0.16 lb S02 removed per lb of sorbent 

injected. The ratio shows an improvement in removal efficiency over Trona and SBC 

injection after the air heater. 

SfiiW'.,..,~'~re~ ~ "'·· 21 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Summary particulate matter emissions data are shown Table 3-14. The values presented 

are the averages of three one-hour runs. Data indicate overall ESP efficiency of 97.80 

percent, not quite as good as the baseline efficiency. 

Total mercury emissions data are shown Table 3-15. The values presented are the 

averages of three runs. Data indicate overall removal efficienc¥ of 85.8 percent (based 

on coal mercury concentration. This removal efficiency is not necessarily comparable to 

the baseline since this is based on Unit 6 only and a comparison requires the assumption 

that Unit 6 equals Unit 5 in emissions. 

3.1.7 Sodium Bicarbonate Downstream of the Air Heater Parametric 

Testing 

The purpose of this pro gram segment was to document emissions and plant operating 

characteristics injecting SBC downstream of the AH. The amount of SBC added was 

adjusted throughout the day (9:10- 19:35) to obtain a trend between S02 removal and 

SBC injected. The SBC was added to both Units 5 and 6 from 3500 to about 16,000 

lbs/hr (or from 1,750- about 8,000 lblhr/unit) 

The test occurred on I I June. The plant was burning coal from the East Thunder (Jacobs 

Ranch) mine with an approximate 0.9- 1.2 lb S02/MMBtu content. During the 

performance of the tests Both units 5 and 6 had temporary coal feeder issues that resulted 

in temporary minor reductions in plant output. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances into 

the plant ductwork. 

22 

I 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

In accordance with the test program no measurements were taken on Unit 5. On Unit 6, 

S02 was measured at the economizer outlet "before injection" and after the ESP. Coal 

was sampled during testing. 

The SBC injection information was compared to the Stack CEMs data to discern a trend. 

The Unit 5 and 6 S02 amount before DSI was estimated based on the S02 concentration 

in the stack before and after DSI. The results were graphed and are shown in Figure 3-2. 

SBC Utilization . . . Aft h A" H v" -o.1971x + o.2199 Injection er t e 1r eater R'•0.2979 

03 

u 

"' "' 

• •··-·-··· ..••....•..... --- ----~-.---• ---------···---.,-···········-···· • ·············-··-·-·· 

0.2 ········----------~~--=---······------···-·--···-·-··· 

': 0.15 ~ ~ .... ~ f!i . • -~ -;r-..,.., < 

0 

"' 0 :l . ·········--·····-·····-·-·····-····--····---·-··--·-··--···-·-······-·----~----------··-----·-·-·--···--·-- "' _. ~ I • -~ o :05 r--------· -···-···-····-··---·---··-·---·----·---------·-----·-···---------··--··-·-·---------··--

0 0 ·················-················-· ....................................................................... . 

"' :3 0.00% 10.00% 2.0.00% 30.00% 40.00% 60.00% 

PercentSOZRemoved 

Figure 3-2- SBC Utilization, Injection After the Air Heater 

Summary S02 data are shown Table 3-16. The removal efficiency range of 16- 53 

percent was seen and with an efficiency ratio of 0.121 lb S02 removed per lb of sorbent 

injected at 50% S02 removal. 

Average S02 Before DS Injection 

test 

Lb S02Removed!Lb Sorbent at 50% Ratio 

removal 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

3.1.8 Sodium Bicarbonate Downstream of the Air Heater Units 5 and 

6 Steady State Testing 

The purpose of this pro gram segment was to document emissions and plant operating 

characteristics injecting SBC downstream of the AH on a continuous basis. 

The test occurred on 14 June. The plant was bnrning coal from the Belle Ayr mine with 

an approximate 0.6lb S02!M:MBtu content. This is a coal with a lower sulfur content 

than what the plant was bnrning during earlier test days. SBC was injected into both 

Units 5 and 6 from 10:00- into June 15 at an average injection rate of9,980 lb/hr after 

initial ramp up. The operation of the ESPs were impacted by the combination of the 

Belle Ayr coal and the SBC injection with lower power levels and an initial increase of 4-

5% in opacity. This spike stabilized and the opacity trended down as the tests continued. 

Attachment 3 shows the arrangement of the NolTec injection equipment and lances into 

the plant ductwork. 

CEMs measurements were taken on Unit 5 and Unit 6, at the economizer outlet, before 

injection. The plant CEMs in #3 Tall Stack was used to measure S02 emissions. Coal 

was sampled during testing. 

Summary S02 data are shown Table 3-17. The results indicate an overall removal 

efficiency of 54.7 percent and with an efficiency ratio of0.112lb S02 removed per lb of 

sorbent injected. 

3.1.9 Continued Sodium Bicarbonate Downstream of the Air Heater 

Units 5 and 6 Steady State Testing 

The purpose of this program segment was to to continue to document emissions and plant 

operating characteristics injecting SBC downstream of the AH on a continuous basis. 

The test occurred on 15 June and into 16 June. The plant was bnrning coal from the Belle 

Ayr mine with approximate 0.6 lb S02!M:MBtu content. This is a coal with a lower 

sulfur content than was burned in the first two weeks oftests. 

24 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

SBC was injected into Units 5 and 6 for all ofJune 15 and into June 16. Full load 

operation of Units 5 and 6 begao about 6:25. The average SBC injection rate was about 

9,960 lblhr for both units during full load operation. This testing was curtailed when Unit 

5 developed a tube leak resulting in the unit being taken out of service around 5:00. 

Attachment 3 shows the arrangement of the No!Tec injection equipment aod lances into 

the plant ductwork. 

On Unit 5 aod Unit 6, CEMs measurements and mercury were sampled at the economizer 

outlet. On both units, particulate matter (TM5) was used at the ESP inlet. Mercury, 

metals, acid gases, S03 aod particulate were measured atthe common #3 Tall Stack. 

Summary S02 data are shown Table 3-18. The values indicate an overall removal 

efficiency of 54.7 percent aod with ao efficiency ratio of0.113 lb S02 removed per lb of 

sorbent injected. This feed rate aod removal efficiency continued into June 16 until Unit 

5 was brought down at about 5 am. SBC injection continued at a reduced rate with just 

Unit 6 in operation with ao average feed rate for Unit 6 of 4,950 lblhr, with 52.9% S02 

removal efficiency aod a 0.109 Lb S02Removed/Lb Sorbent utilization. 

Average S02 Units 5 and 6 Before 

DS r,.,;,.ct;,,., 

Lb/hr 

Summary particulate matter emissions data are shown Table 3-19. The values presented 

are the averages of three one-hour runs. Data indicate overall ESP efficiency of 99.02 

percent, better thao baseline efficiency. Although the efficiency is somewhat better thao 

the baseline, the real problem is the total particulate is 75 lblhr more than measured with 

the baseline testing. 

25 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

Total mercury emissions data are shown Table 3-20. The values presented are the 

averages of three runs. Data indicate overall removal efficiency of93.7 percent (based 

on coal mercury concentration), which is consistent with the baseline efficiency. The 

removal efficiency represents the combined removal of the DSI and PAC injection 

system. 

3.1.10 Comparison of Certain Metals Emissions, During Baseline 

and SBC Injection 

Ten metals were measured in the stack during the baseline sampling and again when 

injecting SBC on the final day of testing. Different coals were burned between the two 

test days. Table 2-3 shows the analyses of the two coals during the test period .. From a 

visual review of the data, it is not evident that SBC had an impact on metals emissions, 

either positive or negative. There is some indication that SBC may have decreased the 

amount of nickel or selenium in the emissions .. 

3.1.11 Comparison ofAcid Gas Emissions, During Baseline and 

SBC Injection 

Hydrochloric acid and hydrofluoric acid gases were measured in the stack during baseline 

sampling and when injecting SBC on the fmal day of testing. The average emission rates 

are shown in Table 3-21. Different coals were burned between the two test days. Table 

2-3 shows that the Jacobs Ranch coal had on average slightly greater concentrations of 

chlorine than Belle Ayr coal, however, on the days tested the chlorine concentrations 

were similar. Fluorine concentrations were not sampled. 

Assuming the Belle Ayr coal had similar concentrations of chlorine and the same or 

higher concentrations of fluorine, a minimum of about 80% removal ofthe acid gases 

when comparing the baseline test results with the SBC injection results. 

26 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

heater 

Notes: 

1. Burned East thnnder (Jacobs Ranch) PRB Coal 

2. Burned Belle Ayr PRB Coal 

3. Based on the assumption that the two coals have the same concentrations of 

chlorine and fluorine 

3.1.12 DSIImpacts on NOx Emissions 

The NOx emissions between the baseline sample dates and the DSI dates were reviewed 

to see ifthere was a discemable impact of DSI on NOx emissions. The data is included 

in Attachment I. Little to no reduction in NOx emissions was seen with the injection of 

dry sorbent. 

3.2 Comparison of Dry Sorbent Utilization 

3.2.1 Dry Sorbent Utilization versus 502 Removal 

A comparison of the amonnt of S02 removed against the amount and type ofDSI was 

made to delineate the utilization efficiency of each of the dry sorbents used. Since the 

S02 concentration in the flue gas varied with time over the test runs a comparison of the 

dry sorbent utilized needs to be compared on an amonnt of S02 removed to amount of 

dry sorbent used. It should be noted that the SBC utilized during the test program was 

pre-milled. However, when it arrived portions of the SBC had clumped together 

resulting in nnloading problems. This clumping may be indicative of a general 

degradation in the particle size (increase in particle size from the milled state) that could 

impact the SBC performance. 

Table 3-22 provides a tabular comparison of the dry sorbent injected versus S02 

removed. 

The test results for SBC injection were graphed as provided in Figure 3-3 below. 

27 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Some general conclusions can be made from reviewing tbe comparisons provided in 

Table 3-22 a11d in Figure 3-3: 

• Greater than 50% S02 removal was obtained with un-milled Trona, and milled Trona 

before tbe air heater and witb SBC before or after the air heater 

• 50% removal was not seen with milled Trona after tbe air heater 

• SBC had a better utilization efficiency than Trona whether milled or un-milled 

with a 0.158lbs S02 removed per lb of dry sorbent versus 0.100 lbs S02 removed 

per lb of dry sorbent for milled Trona when injection was before tbe air heaters 

• Milled Trona was more efficient than un-milled Trona in S02 removal (ratio 

averages 0.100 vs. 0.093, lbs S02 removed per lb of dry sorbent respectively) 

when injected before the air heater 

• The injection location (whetber before or after the air heater) impacts tbe 

efficiency of Trona and SBC utilization, with injection before the air heater having 

a significa11tly greater utilization efficiency 

• The trend line for SBC utilization shows tbat tbe SBC utilization efficiency 

decreases witb increased % so2 removal 

• Wben using SBC for 50% S02 removal, an utilization rate of about 0.12 lbs S02 

removed per lb of SBC is needed with injection after the air heater and a 

significantly greater utilization(>O.l58 lbs S02 removed per lb of dry sorbent) if 

injection is before tbe air heater 

• Dry sorbent injection will reduce acid gases; 80+% removal was seen in these tests 

28 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, 

Joppa Generating Station 

Joppa, Illinois 

7-Jtm I 8:45- 18:35 I Unmilled 

Trona 

8-Jtm I 9:10-16:40 I Milled Trona 

9-Jnn I 8:50- 12:30 I Milled Trona 

9-Jnn I 14:40- 16:00 I 

10-Jun I 8:30-16:55 I 11-Jun I 9:10-19:35 I 14-Jun I 10:00-24:00 I 

5- 6:25-4:55 Pre-milled 

16-Jtm (6-16) SBC 

16-Jtm 5:35-6:30 Pre-milled 

t lht\l SilfWI! 

Before air heater- 1 

Unit 6 

Before air heater - I 

Unit6 

After air heater - I 

Unit 6 

After air heater -

Unit 6 

Before air heater -

Unit 6 

After air heater -

Units 5 and 6 I 

After air heater - I Units 5 and 6 

After air heater -

Units I 5 and 6 

After air heater -

TT ., / I 

3,000- > 13,000 I 

8,600 +/- I 

14,493 I 11,750 I 

7,380 I 

3,500- 16,000 I 

9,980 I 

9,960 I 

4,950 I 

29 

13-59 

52.6 

42.6 

60 

67.1 

16-53 

54.7 

54.7 52.9 

Dry Sorbent Injec

I 0.093 @ 5

I 

I I 

I 0.121 @5

I 

I I 
Electric Energy, Inc, 

Joppa Generating Station 

Joppa, Illinois 

, 

.. 

.... 

.., 

f 

w 

"' ... "' 0 

:!l 

" a. ., " 

" "' .... 

0 

V) 

.0 

_, 

a Snaw' n\IJ SlWI r!ill'..w 1rx:· 

0.3 

0.25 

0.2 . 

0.15 

0.1 

0.05 

0 

Electronic Filing - Received, Clerk's Office, 08/15/2012 

Sodium Bicarbonate Utilization Rate 

Injection After Air Heater 

• 

·'II' 

Dry Sorbent Inj

fl' 0.2238 

0.00% 10,00% 20,00% 30.00% 40.00% 50.00% 60,00% 70,00% 80,00% 

Percent 502 Removal 

Figm·e 3-3- Efficiency of 802 Removal Using SBC After The Ait· heater 

30 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

3.2.2 Impacts of Dry Sorbent Utilization on Particulate Emissions 

A comparison of the Unit 5 and 6 stack total particulate emissions during baseline testing 

(June 4-5, 2010) versus total particulate emissions during steady state SBC injection 

(June 15, 2010) are shown in Table 3-23. This comparison shows an increase in total 

particulates of 74.83 lbs/hr with the injection of my sorbent. This equates to increase in 

total particulates of 295 tons/yr from Units 5 and 6 ass=ing a 90% capacity factor. 

Baseline NA 

6/15/2010 Steady- Down 

(2) State SBC Stream of 

@ 10,159 Air 

Heater 23,116 227.70 99.01% 0.060 

Deltas 9,431 74.83 0.13% 0.014 

Notes: 

1. East Thunder PRB Coal burned 

2. Belle Ayr PRB coal with approximately 15% lower ash than the East Thunder 

average bumed on 6/4-5/2010 

The type of dJ.y sorbent utilized also affected the type of particulate emissions from the 

existing ESPs. Table 3-24 provides a comparison ofthe particulate emissions by size of 

particulate versus the J1111e 4-5 baseline test data. In all cases the Unit was burning 

Jacobs Ranch coal. Table 3-24 also provides the average DSI rate. 

31 
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Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

6/5/10 Base 

Test NA NA 81.32 13.48 67.84 17 

Un- Upstream 

6/7/10 milled 8,502 of Air 84.7 5.14 79.56 13.63 

Trona Heater 

6/8/10 Milled 

Trona 8,696 

Upstream 

of air 163.99 9.14 154.85 31.75 

heater 

Pre- Down 

6/10/10 milled 7,150 Stream of 228.96 8.61 220.35 20.69 

SBC Air Heater 

Reviewing the results provided in Tables 3-23 and 24 show that the addition ofDSI to the 

flue gas stream increases the total particulates leaving the ESP with the majority of 

increase being PM<lO microns. Injecting milled dry sorbent has the most impact on the 

increase of fine particulates with the pre-milled SBC having a greater impact than the 

milled Trona, though the results from the testing on June 10 are suspect since they are 

greater than what was measured on June 15 for the combined Unit 5 and 6 emissions with 

SBC injection. The least impact on particulate emissions was the injection of un-milled 

Trona which had the largest particle size of all of the test runs. It should be noted that 

with the addition of dry sorbent no impacts on the operation of the ESP or opacity were 

observed when firing Jacobs Ranch coal. The Opacity and ESP performance (i.e. spark 

rates, secondary current, etc.) did change with SBC injection when firing the Belle Ayr 

coal with an increase in opacity of several percent. This increase did not cause the plant 

any issues with meeting theplant's opacity limits. 

3.2.3 Impacts of DSI Utilization on Mercury Emissions 

The removal efficiency of mercury during injection of DSI was reviewed and is included 

in Attachment 1. The results indicate a baseline removal efficiency of 93% with the 

injection of a minimum of 5 lbs activated carbon per million acf. During DSI the 

mercury removal varied from 84.1-93.7% with 93.7% removal occurring during SBC 

injection to both units. This removal efficiency is based on the concentration of mercury 

in the coal burned. Throughout the DSI test the activated carbon injection rate was 

unchanged. Based on the low values of mercury analyzed and the 10% variability of 

removal during injection, it is difficult to state whether DSI had any real impact on 

mercury removal. 

32 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

3.3 Byproduct Characterization 

The characterization of the DSI by-products is included in Attachment 2. 

3.3.1 Current Byproduct Operations 

On 15 June, a Shaw and EEl representative went to the ash handling area approximately 

Y, mile north of the plant. The current operation is contracted. 

An interview with the operators indicated ash production over a 60 hour operating 

weekend was approximately 1500 tons for the six units. The ash handling area has 

storage for 1800 tons in three silos. This calculates to approximately 4.16 tph per unit of 

ash produced (PRB coal). 

Ash is pneumatically blown into the silos. Ash is dropped into trucks using a dustless 

unloader, supplied by DustMaster, Turbin Mixer XL Series II (Pewaukee, WI). The 

operators currently add approximately 10.5 to 10.7% water (lb ofwater/lb of water plus 

ash). Mixed byproduct loading rates were 77- 81 tous/hour. For the DSI testing, EEl's 

contracted ash plant operator processed the ashlsorbent mix in the DustMaster. The 

waste material was shipped to a municipal landfill approximately an hour distant. At this 

time, EEl is in the process of completing the development of a dedicated nearby landfill. 

Plans would be to add the new mixed byproduct to the new landfill. 

EEl (17 June) reported an increase in LOI with DSI. Ash materials were generally 

reported at a LOI near 2.0% when injecting activated carbon, but LOI increased to up to 

8.1% with DSI. The mixed byproduct also had a slightly higher moisture in the silo. 

During the test program, the operators reported that when wet, the mixed byproduct 

generated considerable heat. This finding is consistent with the Shaw E&I materials lab 

results, discussed below. 

On the day of the interview, 25 gallons of mixed byproduct were secured in plastic 

shipping containers. The mixed byproduct was sent to the Shaw E&I materials 

laboratory in Knoxville TN for characterization testing. 

3.3.2 Byproduct Characterization Testing 

At the Shaw E&I materials laboratory, a number of tests and characterization studies 

were performed. The work was performed to describe for operators the expected 

characteristics of mixed byproduct. 

Among the byproduct characterization tests performed were: 

• Bulk density, percent solid content, pH 

• Dry sieve particle size analysis to 7 5 micron 

• Atterberg limits 

• Screening Moisture Addition 

33 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

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Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

• Dissolution in water 

• Total and toxic characteristic leaching procedure (TCLP) Analyzed for Expanded 

EPA target analyte list (TAL) 

• Harvard Miniature Proctor Test 

• Standard Proctor Test 

• Temperature rise with water addition 

• 7-Day Unconfmed Compressive Strength (UCS) 

• Dissolution of 7-day cured material at approximately optimum water content, 2 

point ANSI 16.1 

• Permeability of7 -day cured material at approximately optimum water content 

with ICP analysis of effluent 

• Direct Shear, N ormai/Residual 

• California Bearing Ratio (CBR) 

• Consolidation, One-Dinlensional 

• Triaxial Shear, Unconsolidated, Undrained 

3.3;3 Highlights of Laboratory Results 

When comparing of SBC byproduct vs. baseline ash, the reader should remember that the 

plant was burning different coals when the samples were collected. The physical 

characteristics of the two products are likely more comparable, than metals content or 

leachate. 

Densities - Bulk density testing indicated that the densities of the two bypro ducts are 

sinlilar. The bulk densities ofthe dry, as received baseline fly ash and the SBC 

byproduct were 69.0 and 61.9 lb/ft3

, respectively. When water was added to the 

byproduct samples, the densities increased to a maximum of 126 Ib/ft3 with 15 percent 

water addition for the baseline fly ash. Sinlilarly, the SBC byproduct density generally 

increased to a maximum of 120 lb/ft3 with water addition of up to about 25 percent. 

During screening water addition tests, the SBC byproduct freely released water after 

reaching 25% water addition. At 26 % water addition the SBC ash became a flowable 

paste. The maximum density measured :in the Harvard Miniature proctor tests was at 

about 25% water addition; however, liquid was released when pressure was applied at the 

optinlum moisture addition rate. 

Sieve Analysis. Analysis of the dry sieve results shows that the SBC byproduct is mostly 

fine sand and silt size particles. Analysis of the Atterberg results shows that ash behaves 

like slightly cohesive silt. The fmes become cohesive and liquefy at 22 and 26 percent 

geotechnical moisture content (w/d), respectively. 

Characteristics with Water Addition- From initial SBC byproduct screening water 

addition tests, when ali the water was added at once and the wetted byproduct is 

compacted, it will rapidly adsorb water into the compacted samples beyond its ability to 

hold the liquid when pressure :is applied. With many of the formulations, when the 

34 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

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Joppa Generating Station Dq Sorbent Injection Test Program 

Joppa, Illinois 

standing water was removed and the material allowed to cure for about 48 hrs, a friable 

crust on top of the compacted material was formed (water was only removed for testing, 

then added back to the sample; therefore any free water remained on the sample for the 

whole testing period). 

At lower water addition rates, the SBC byproduct set and self hardened at a slightly 

slower rate than the baseline ash. The rate ofSBC byproduct setting, self hardening and 

heat release can somewhat be controlled by the amount of water added to it. The baseline 

ash hardened to> 4.5 tsfresistance at all moisture addition rates within 30 minutes. The 

SBC byproduct hardened to> 4.5 tsfwith 2: II percent moisture addition rates within 30 

minutes. At< 9 % water addition rates to the SBC ash, the product is harder to mix 

(water into the ash). 

As a compromise between rate of set, rate of heat released, ease of mixing, compacted 

wet density, liquid release and liquefaction, water additions were separated into two 

steps. First 9% water was added to simulate dust control processes at the site. In this 

step about 60% of the heat was released. The remaining water was added and the wetted 

ash compacted which simulates water addition and compaction at the landfill. At a total 

water addition rate of 19, 21 and 23 percent, the densities were slightly lower than at 

optimum moisture content of25%; however, at theselower water addition rates the 

compacted samples did not release liquid or liquefy. The UCS, modified ANSI ANSI 

16.1, leaching tests and permeability tests used this two step water addition and 

compaction process. In addition, at 21 and 23 percent water additions, the amount of 

water that would adsorb into the compacted SBC byproduct was limited when compared 

to lower water addition rates. 

At the three selected total water additions, the SBC byproduct, after compaction, self 

hardened to UCS values in excess of 98 psi at 7 days. This is well in excess of the 

commonly recommended UCS values for landfills of 10, 25 or 50 psi. The duplicate UCS 

results vary more than is normally seen for soils that are treated with pozzolonic materials 

or Portland cement. Submersion in water for 7 days caused about a 10% loss in UCS 

strength for the 21% water addition sample. This loss may be within the accuracy of the 

tests for SBC byproduct. 

Even though the monolithic material maintained its physical shape and UCS values, 

about 16% of its mass dissolved during the 7 day immersion study. The pH remained 

high(> 12.5) during the immersion test. Thus, the soluble components of the byproduct 

material may dissolve if water is allowed to set on top of it and percolate through the 

treated material. 

PH- The high pH of SBC byproduct is likely the result of CaO, Ca(OH)2, CaC03, 

NaOH, Na2C03 and NaHC03 contents. The leachate pH values exceed typical site 

discharge criterion of about 8.5. The pH of the baseline sample is similarly high and, 

therefore, any leachate from the landfill may need to be neutralized or flow diluted with 

other precipitation to lower the pH to meet discharge requirements. It should be noted 

35 
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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

that leachate at the landfill will pumped to two above-ground steel tanks. The liquid will 

then be transported off-site for treatment and disposaL 

Temperature- Samples at varying water additions were subjected to monitoring for heat 

increase. With total water added between 9 and 23 %(weight basis), temperature rise 

between 4 7 and 60 °F occurred. Time elapsed to arrive at a maximum temperature was 

29 to 88 minutes. Byproduct heat generation upon addition of water is consistent with 

observations of EEI during the test program. 

Stabilization Testing- SBC byproduct was mixed with other materials to test for 

enhanced stabilization characteristics. The byproduct was mixed with Portland Cement, 

Blast Furnace Slag and Terrabond. Results indicate a greater UCS value where Portland 

Cement is added in as little as 5% by weight. 

Metals Analysis - Total·metal analyses show that most metals concentrations in the SBC 

byproduct range from 65 to 78% of that of the baseline ash. Notable exceptions include 

sodium and sulfur which are, understandably at much higher concentrations in the SBC 

byproduct. Mercury and selenium are somewhat higher in the SBC byproduct. Barium 

was an order of magnitude higher in the baseline ash. As mentioned above, the coals used 

in baseline tests and used in SBC tests were different and their metals content are not 

directly comparable. 

Leachate Testing- Leachate testing was run on both the base line ash and the ash/SBC 

byproduct. The results of this testing show: 

• That both the baseline and SBC ashes do not exceed the US EPA Toxicity 

Characteristics criteria for RCRA hazardous waste. 

• It is expected that the landfill leachate will need pH neutralization before 

discharge. The leachate, based on the lab resnlts, should also have high TDS. 

• Even though the landfill water will not be discharged to groundwater, the leachate 

values were analyzed against the IL groundwater standard as a point of reference. 

Several metals and an anion sulfate (based on the sulfur results) exceed the state 

groundwater standards. 

Permeability Testing - Permeability testing was performed on the water treated and 

compacted SBC ash and the solidified and stabilized SBC ash formulations. After greater 

than 30 days, permeability results could not be obtained due to gas generation within the 

permeable chamber. GC analysis indicates the gas is hydrogen gas when the SBC ash is 

contacted with water for sufficient time. 

Following permeability testing sample specimens were tested for changes in UCS and 

dimensional degradation. These tests indicated no reduction in strength or degradation 

due to short term water permeation into the sample matrices. 

36 

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··Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Effluent testing of the permeation liquids indicated elevated pH of permeate waters, 

containing high levels of sodium and sulfur as well as lower levels of various metals. 

3.4 Impacts on Operation 

3.4.1 Utilization of DSI at Joppa 

From this set of tests the decision of whether to use Trona (milled on-site) or SBC (milled 

on-site) would become one of economics if injection before the air heater is not 

considered an issue. One point for consideration is if SBC addition after the air heater is 

selected; what is the temperature of the flue gas during partial load operation. If the air 

heater gas outlet temperature drops to below the recommended Solvay low temperature 

for SEC utilization of 275 °F the utilization efficiency will drop. The PI data provided as 

part of this study showed the lowest temperature measured over the eight days was 284.7 

°F in Unit 5 which occurred in the morning during the ramp up from partial load to full 

load. All of the SBC runs feeding SBC after the air heater were at temperatures in the 

330 °F range. Partial loads at night or for an extended period of time with a resultant low 

temperature out of the air heaters may adversely impact the utilization rate of SBC 

especially when that temperature approaches 275 °F and given the spread of temperatures 

across air heater outlet due to rotary design. 

As seen in the results, the addition of DSI adversely impacts the amount of particulates 

that leaves the ESP. This increase in particulates would impact the plant's air permit as 

discussed below. The least impact on particulate emissions resulted from the use of unmilled Trona though there still was an increase in PMI 0. Significant modifications to the 

plant's ESPs would be required to limit the additional particulate emissions. 

3.4.2 Air Permit Considerations 

The Joppa Generating Station operates of six ( 6) coal-fired boilers for. electric generation 

and is a "major" source under the Clean Air Act (CAA) Title V operating permit 

program. The boilers also have the ability to burn fuel oil or natural gas. As discussed 

above, the injection of dry sorbent would increase particulate emissions. The Station 

would like to retain tl1e existing electrostatic precipitators (ESP) for particulate control. 

The Station would also like to avoid applicability of Prevention of Significant 

Deterioration (PSD) due to exceeding the "significant net emission" threshold for 

particulate emissions. 

Shaw conducted a preliminary PSD analysis for this project. This is not intended as a 

complete and fmal PSD analysis for the project due to several assumptions that had to be 

made to complete the analysis. 

An existing major stationary source (i.e. the facility) is applicable to PSD if it undergoes 

a major modification. Major modifications are physical or operational changes at an 

existing major stationary source that causes a significant "net emissions increase". Table 

3-25 below lists the signification net emissions increase thresholds for particulate 

i'\ 

~· Sliaw'illi>S'l'>"~ 37 
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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

emissions. The PSD analysis is based on total particulate emissions which is the stnn of 

filterable (Method 5) plus condensable (Method 202) emissions. 

PM 25 

PM10 15 

PM2.5 10 

A netting analysis is done to determine if any pollutants trigger the significant net 

emissions increase. The netting analysis includes all changes to the pollutant in the 

facility. For this preliminary analysis, Shaw considered the changes to the boilers 

emissions based on the DSI and material handling of the DSI only. For a full PSD 

analysis, all changes in pollutant emissions across the facility are included in the netting 

analysis. 

Shaw conducted a netting analysis to determine the various options that would not trigger 

PSD for the Joppa facility due to DSI. The netting analysis included comparing the 

baseline emission prior to the modification to the projected actual emissions after the 

modification. The baseline emission was determined as the representative actual 

emission over a 5 year look back period. Projected actual emissions after the 

modification were based on the projected comparable particulates with SBC injection and 

associated material handling operations. The SBC injection data generated in these tests 

were used assuming a 50% S02 removal. 

Shaw conducted several different PSD analyses based on different baselines and emission 

factor sources. These analyses were done on Unit 5 and Unit 6 only since those are the 

only boilers that were tested during the SBC injection. In a full scale PSD analysis, all 

other units expected to use SBC injection will need to be included in the calculations. 

These analyses assme the plant will operate in the future as it has operated in the past. 

Not reviewed are alternate scenarios such as reduced load operation or replacement of a 

portion of the coal with alternate fuels such as natural gas. 

The analyses and results are discussed in the following sections. 

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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Scenario 1: PSD Analvsis Using the Most Recent Baseline Period (03-04 2009 and 

01-02 2010) 

For this analysis, Shaw considered the baseline period to be equal to the last four quarters 

of operation (Q3-Q4 of2009 and Ql-Q2 of2010), The baseline emissions from Q3-Q4 

2009 were calculated based on the Unit 5 and Unit 6 emission factors and hours of 

operation reported in the CY2009 air emission inventory. The baseline emissions from 

Ql-Q2 2010 were calculated based on the average emission factor measured during the 

June 4-5,2010 test (Run I was omitted as an outlier). The total particulate emissions 

were measured at the stack during the baseline test for Unit 5 & 6. This emission rate 

(152.87lb/hr) was divided in half to obtain the individual emission factor for Unit 5 and 

Unit 6, considering the fact that the two units were similar in capacity. PMIO and PM2.5 

were not measured at the stack, but were measured at the Unit 6 ESP outlet. Shaw 

assumed that the speciation of the filterable particulate fraction for Unit 5 was the same 

as that measured for Unit 6. The June 4-5, 2010 baseline test (i.e. without injection of 

SBC or Trona) on Unit 6 ESP outlet showed that 83% of filterable particulate was PMIO 

and 21% was PM2.5, which was considered in the analysis. 

The future projected actual emissions included the emissions from material handling of 

the DSI and the increase in particulate emissions from the boilers emissions. For the 

material handling, Shaw assumed that DSI would be pneumatically conveyed within the 

facility and one storage silo would be required for Unit 5 & 6 stack. The storage silo was 

assumed to be controlled by a baghouse with 99.7% efficiency. No other material 

handling emissions were considered. It may be noted that in a full PSD analysis, the 

increase in emissions resulting from the increase in fly ash and spent DSI handling would 

have to be included. 

The projected future emissions of Unit 5 and Unit 6 boilers were calculated based on the 

emissions measured from the June 15,2010 SBC injection test. It was· assumed that the 

boilers would operate the same amount of hours as was reported during the baseline 

period (i.e. no increase in capacity factors over baseline). The total particnlate emissions 

were measured at the stack during the SBC test for Unit 5 & 6. This emission rate (228 

lb/hr, 155.llb/hr filterable and 72.7lb/hr condensable) was divided in half to obtain the 

individual emission factor for Unit 5 and Unit 6 for reasons mentioned earlier. PM! 0 and 

PM2.5 were not measured at the stack, but were measured at the Unit 6 ESP outlet. The 

results of the test conducted on June 10, 2010 (SBC injection) at the ESP outlet did not 

seem to be consistent with other results. PM! 0 and PM2.5 were also measured at the 

Unit 6 ESP outlet for a Milled Trona injection test. Shaw assumed that the particulate 

speciation for the Milled Trona would be similar to the SBC. Shaw also assumed that the 

particulate speciation for Unit 5 was the same as that measured for Unit 6. The June 8, 

2010 Milled Trona test on Unit 6 ESP outlet showed that 94% of filterable particulate 

was PMIO and 19% was PM2.5, which was considered in the analysis. 

The results of the Scenario 1 analysis are shown in Table 3-26. 

39 
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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Future 

Projected 

Emissions 

Unit 5 and 6 

Notes: 

PM2.5 ton/yr 123.06 17.29 10 y 

(1) This is the total plant threshold limit. If all six boilers are retrofitted then this 

limit would be reduced to a third of what is shown for the emissions from Units 5 

and 6. 

The analysis showed that the facility could trigger PSD due to increase in particulate 

emissions over the significant emission rates threshold. The main reason for the increase 

was the higher emission from the ESP as a consequence of SBC loading. The material 

handling emissions were not significant in the calculations when compared to the 

increase in emissions from the boilers. 

One option for Joppa to avoid triggering PSD would be to improve the efficiency of the 

existing ESP such that there will be no net significant increase in particulate emissions. 

There is no data available to speciate the inlet particulate, so Shaw assumed that the inlet 

particulate speciation was equal to the outlet particulate speciation. Considering the 

assumed future hours of operation, inlet particulate loading (from the June 15,2010 Unit 

5 and 6 ESP inlet test), and the assumed particulate speciation, Shaw calculated that the 

control efficiency would have to be 99.515% (based on PM10). The PM10 emissions 

would then be: 

Unit 5: 10,294lblhr * (1-0.99515) * 8381 br/yr /2000 lb/ton * 94% (ratio filterable PM 

to PM10) * 155.1/228= 133.78 tonlyr 

Unit 6: 12,822lblhr * (1-0.99515) * 8008 br/yr /2000 lb/ton * 94% (ratio filterable PM 

to PMlO) * 155.1/228 = 159.22 ton!yr 

Total emissions will be approximately 293.0 tpy from the two boilers and the net 

emissions increase from the boilers would be close to zero (accounting for rounding). 

40 
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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dty Sorbent Injection Test Program 

Joppa, Illinois 

Scenario 2: PSD Analysis Assuming CY2010 as the Baseline Period 

For this analysis, Shaw considered the baseline period to be equal to calendar year 2010 

as ifthe PSD application was being submitted sometime in 2011. Shaw obtained the 

operating data from Joppa for the first two quarters of2010. Shaw assumed that the total 

hours of operation for CY20 10 would be equal to the total hours of operation for the 

baseline period of Q3-Q4 2009 through Q l-Q2 2010. The baseline emissions were 

calculated based on the average emission factor measured during the June 4-5, 2010 test 

(Run 1 was omitted). The total particulate emissions were measured at the stack during 

the baseline test for Unit 5 & 6. This emission rate (152.87lb!hr) was divided in half to 

obtain the individual emission factor for Unit 5 and Unit 6. PM10 and PM2.5 were not 

measured at the stack, but were measured at the Unit 6 ESP outlet. Shaw assumed that 

the particulate speciation for Unit 5 was the same as that measured for Unit 6. The June 

4-5,2010 baseline test on Unit 6 ESP outlet showed that 83% of particulate was PM10 

and 13% was PM2.5. 

The future projected emissions from material handling of the SBC and the increase in 

particulate emissions from the boilers does not change from Scenario 1. The results of 

the Scenario 2 analysis are shown in Table 3-27. 

Emissions 

UnitS and 6 PM2.5 ton/yr 117.66 

Future 

Projected y 

Emissions 

Unit 5 and 6 PM2.5 ton/yr 123.06 5.40 10 NN(2) 

Notes: 

(1) This is the total plant threshold limit. If all six boilers are retrofitted then this 

limit would be reduced to a third of what is shown for the emissions from Units 5 

and6. 

(2) If all six units were retrofitted this increase would exceed the threshold in total 

plant emissions. 

41 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, lllinois 

Although the facility would still trigger PSD in Scenario 2, the baseline emissions are 

higher because the emission factors measured during the baseline test are higher than the 

emission factors used for the previous year's emission inventories. Joppa may consider 

improving the efficiency of the particulate control so that there is no change in emissions 

due to the SBC loading. The same analysis that was done for Scenario I was done for 

this scenario. Since the baseline emissions are higher in this scenario, the control 

efficiency required to avoid PSD is 99.34% (based on PM). The PM emissions would 

then be: 

Unit 5: 10,294lblhr * (1-0.9934) * 8381 hrlyr I 2000 lblton) = 284.70 tonlyr 

Unit 6: 12,822lblhr * (1-0.9934) * 8008 hrlyr I 2000 lb/ton) = 338.84 tonlyr 

Total emissions from the two boilers will be approximately 623.54 tpy and the net 

emissions increase from the boilers would be zero. 

3.4.3 ESP Upgrade Considerations 

The following presents a discussion of the existing electrostatic precipitators (ESP) at the 

Joppa Station, and a discussion of generic methods typically considered to reduce 

particulate matter (PM) emissions from generic existing ESPs when Trona or sodium 

bicarbonate (SBC) sorbent is injected upstream of an ESP to reduce sulfur dioxide (S02) 

ermsswns. 

Joppa Existing ESP Description 

Attachment 9, provided by EEI Joppa Station, presents information concerning the 

existing ESPs at the Joppa Station. As shown, in Attachment 9, the units burn PRB coals, 

and each unit employs a cold-side ESP, originally provided by Research-Cottrell (R-C), 

and subsequently modified by Environmental Elements and BRA in the 1990's, with a 

total specific collection area (SCA) of approximately 170 (ft2/kacfm, based on flue gas at 

- 330 deg F avg). Each ESP has two chambers, plate to plate spacing of 9 inch, with five 

electrical fields, three mechanical fields, five transformer rectifier sets (TRs), operating at 

60Hz, with R-C TRs on the first three fields, and NWL TRs on the last two fields, 

smooth wire discharge electrode, and Magnetic Impulse Gravity Impact (MIG!) type 

rappers (plate and wire). The ESPs employ flue gas conditioning (FGC) based on 

injection of sulfur trioxide (S03) in the flue gas upstream of the ESP. The ESP hoppers 

arrangement is first row (under fields 1 &2) and second row (under fields 3 to 5) 

configuration, with a primary fly ash removal system of the dry pressure pneumatic type 

(United Conveyor Company, UCC Dry, Nuva Feeder Pressure Pneumatic) and a 

secondary fly ash removal of the wet vacuum type (UCC, Wet Vacuum). As described in 

Attachment 9, the total secondary power to ESP is typically consistent within the range of 

249 to 269 kW, with consistent total secondary current density within the range of 44 to 

48 mA/1000 ft2. Per Attachment 9, typically, all the TRs are functioning properly, which 

is indicative of good operations and maintenance procedures. It has been reported that the 

ESP are routinely inspected and maintained properly during plant outages. As described 

in Attachment 9, ESP fields 1 and 2 employ Variable Inductance-Current Limiting 

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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Reactors (VI-CLRs). Also, the ESPs employ BHA provided SQ-300 controllers, which 

are a type of automatic voltage control, that typically also includes performance 

monitoring and/or enhancement features, based on microprocessors, computing, and 

other techniques. As indicated, the existing ESPs employ a combination of original 

components plus relatively recent upgrades. 

As shown in Attachment 9, the ESP systems typically achieve 99+% PM removal, which 

is considered an impressive high value, considering the aforementioned relatively low 

SCA value of the ESPs (i.e. 170), and the highly resistive fly ash from PRB coals. The 

use of the FGC system (S03 injection) has been found useful in minimizing stack PM 

emissions and stack opacity. 

It is apparent that much successful work has already been done on the design and the 

modifications of the ESPs to achieve the currently good levels of PM removal at Joppa 

Station. Since modifications have already been performed on the ESPs, along with high 

standards of operation and maintenance (O&M), with routine inspections and repairs that 

have maximized the efficiencies of the existing ESPs, future improvements in the 

performance of the existing ESPs will require additional upgrades. The following is a 

list and description of potential improvements/replacements to the existing ESPs. It is 

likely that many of these potential changes will not be teclmically or commercially 

suitable for Joppa. 

Generic ESP Upgrade Considerations 

With regard to upgrading a generic existing cold-side ESP that is to employ Trona or 

SBC dry sorbent injection upstream of the ESP for S02 reduction, this section provides 

wide-range of concepts that are generally considered. Typically in a site specific ESP 

analysis, this general list is evaluated technically and economically to develop a shorter 

list that may be applicable for a given ESP. 

As discussed earlier in the report, the use of Trona or SBC injection upstream of an ESP 

represents a significant amount of sorbent solids increased loading (lb/hr) relative to the 

normal amount of PRB coal fly ash that enters an ESP. Typically, the use of Trona or 

SBC would increase the electrical conductance of the total solids entering the ESP (flyash 

plus sorbent), which in general is good for ESP performance (up to a point), but to high 

of particle conductance is not considered good for overall ESP performance. Other 

potential negative attributes of Trona or SBC sorbent injection with regard to potential 

degraded ESP performance typically include the relatively large quantity of sorbent 

solids injected (lb/hr sorbent), the possible influence on particle size distribution of solids 

entering the ESP, the possible mal-distribution of sorbent injection across the inlet face of 

the ESP, and other factors. Therefore, it is possible that as a result of Trona or SBC 

sorbent injection (for the purpose of S02 reduction) the net result on ESP performance 

could be an increase in ESP outlet mass flow (lb/hr) of total PM and possible increase in 

fine PM emissions. 

43 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Table 3-28 presents a typical list of generic categories of concepts that could be 

considered for technical and economic attribute evalnation, at a generic ESP that is to 

employ Trona and/or SBC sorbent injection for S02 reduction. These ideas are not 

presented in order of preference, since it is shown as examples for a generic ESP 

scenario. Additional study is required to determine applicability or specific costs of these 

concepts for a given ESP. Later in this section, generic rough budgetary cost estimates 

are provided for some of these concepts at a generic 180 MW cold side ESP with PRB 

coal and Trona/SBC sorbent injection for S02 reduction. 

B 

c 

Upgrading 

Standard TRs to 

High Frequency 

Power Supplies 

Additional 

Sectionalization 

Additional 

Rapping 

In certain cases, high frequency power supplies increase 

average power into the ESP, and have a faster control 

response. For an example, in a generic ESP, some or all 

TR's can be replaced by high frequency power supplies to 

improve performance in all fields. This approach employs a 

source power and controls with a much higher frequency 

than line frequency. These supplies rectify the 60 Hz line 

voltage, filter it to DC, then convert the DC power to a much 

higher frequency before it passing through the high-voltage 

step-up transformer. This conversion to a higher frequency 

allows for a smaller transformer and core, saving weight and 

size, which could avoid or minimize the need to increase the 

capability of the foundation during a rebuild of a generic 

ESP. High-frequency power supplies are presented here for 

information; whether they improve ESP performance would 

need to be determined. In some applications, it may produce 

improved performance because the average voltage 

approaches the peak voltage; and hence, these supplies may 

increase the effective level in the ESP. 

By sectionalizing a generic ESP, individual electrical fields 

are able to operate at an optimal level required for that 

section. In general more electrical sectionalization allows a 

generic ESP to react better to various flue gas conditions. 

This concept includes additional sectionalization along with 

new high frequency power supplies to further improve 

ofa . ESP. 

If required, for a generic ESP, additional rapping may 

help clean the plates which will fill up faster due to the 

higher inlet loading caused by the Trona/SBC sorbent 

injection. Obviously, evaluation and/or internal inspection 

may be required to determine the required rapping density. 

44 
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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

E 

F 

G 

H 

Discharge 

Electrode Design 

Rebuild ESP with 

Wide Space 

Spacing 

Rebuild ESP -As 

Is 

ReBuild ESP with 

Increased 

Collecting 

Electrode Area 

through a generic ESP can be performed. A model study of 

an existing generic ESP could indicate areas of possible reentrainment, high velocity, and non-uniform flow 

distribution. Correcting these issues with vaning and 

perforated plate modifications could improve generic ESP 

Retrofit of new discharge electrodes with custom 

configuration could be considered. Various discharge 

electrode designs are available for evaluation to potentially . . E~. 

Conversion of a generic ESP from 9 inch to plate 

spacing to wider spacing such as 12 inch and/or 16 inch 

spacing could be considered. This can be coupled with a 

change in discharge electrode design to optimize 

performance. Generic advantages may include reduced 

weight of the ESP internals; improved plate alignment 

because allowable tolerances are greater; more uniform 

current density distribution; and possible improvement in 

collecting high-resistivity particles. In some cases, rebuilding 

with wider plate spacing may not require replacing the 

foundation. The high-voltage distribution system must be . . 

Rebuilding an ESP is a generic concept that may be 

considered if the ESP was originally well-designed and is 

now in need of a re-build. Often, this concept alone may not 

be chosen, because typically an upgrade of the ESP is also 

required for generic scenarios. Obviously, this would be a 

Rebuilding a generic ESP with increased collecting electrode 

area could be considered, through installing taller collecting 

plates and/or adding an extra collecting field. Even though 

some original generic ESP designs may have included space 

to install an extra field in the original casing and accounted 

for the extra weight this would entail, a rebuild for increased 

collection efficiency will usually require a major overhaul 

possibly including a new foundation for the new portion of 

the generic ESP and auxiliary equipment as needed. 

Obviously, this is a major project. 

45 
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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

I 

J 

K 

ESP downstream 

of Existing ESP 

Agglomerator 

Concept 

Pulse or 

Intermittent 

Energization 

Concepts 

Building an additional ESP downstrean1 of the existing 

generic ESP could be considered. Obviously, this is a major 

project. The new additional ESP would be tied-in during a 

unit 

Particulate matter particle agglomerator concepts, such as 

provided by Indigo or others, could be considered. The 

Indigo Agglomerator technology uses a combination of 

electrostatic and fluidic processes to remove the fine 

particles from the gas stream immediately prior to entering 

an ESP. The fine particles are attached to the larger particles, 

which are more easily collected in the generic ESP. The 

Indigo Agglomerator has two sections, the bipolar charger 

followed by the mixing section. The gas flow is split into a 

number of streams, each of which enters a passage in the 

charger section of the Agglomerator. Alternate passages are 

positive or negative charging. That is, the even passages may 

be positive and the odd passages negative, or visa versa. 

Following the charger a mixing process takes place, such 

that the fine particles leaving the positive passages are 

diverted into the stream of large particles leaving the 

negative passage and the fme particles from the negative 

passage are diverted into the stream oflarge particles leaving 

the positive passage. Thus the oppositely charged particles 

are brought within close proximity of each other causing 

them to electrostatically attach to each other. These 

agglomerates then enter the generic ESP where it is 

collected. This would be considered a ect. 

concept or 

energization (IE) could be considered for a generic ESP. PE 

and IE energization are intended to provide the highest value 

for the product of the peak and average value of electric field 

at the permissible current density allowed by the ash 

resistivity when the resistivity is relatively high. PE provides 

for a more uniform current density distribution along the 

corona (discharge) electrode, but would require an extra 

power supply for each electrical field. IE does not provide a 

more uniform current density distribution; rather, IE applies 

one cycle of the input waveform, then skips several cycles on 

a repetitive basis to yield a product of peak and average 

voltages that is greater than for conventional full wave or 

double half-wave PC-based 

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Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, lllinois 

L 

M 

N 

0 

p 

Convert ESP 

(COHPAC) 

Build Wet ESP 

Downstream of 

Existing ESP 

Replace Existing 

ESP with a Larger 

Cold Side ESP 

Build a Fabric 

Filter System 

Downstream of 

ESP 

Convert the 

Existing ESP to a 

Fabric Filter 

prclgr;amme:d to operate 

is may be investigated for highly resistive ash, and may or 

may not be considered for the more conductive ash resulting 

from Trona/SBC · · 

Conversion of a generic ESP to a Compact Hybrid 

Particulate (COHPAC) design could be considered. Tllis 

EPRI-developed technology uses a small pulse-jet fabric 

filter (PJFF) as a polishing unit downstream of the ESP. The 

low ash loading to the baghouse allows it to use a higher gas 

velocity than is needed for a baghouse operating alone. 

There are two ways to apply the concept. CORP AC I retains 

the existing ESP and adds the PJFF downstream on its own 

foundation, whereas CORP AC II replaces the outlet field of 

the ESP with the PJFF. Obviously, these are considered . . 

ects. 

Building a wet ESP (WESP) downstream of the existing 

generic cold-side dry ESP could be considered. WESP 

employs a flowing sheet of water to entirely cover the 

collecting plates in the ESP. Since the film of water serves as 

the collecting electrode, there is no significant reentrainment and the detrimental effects of high resistivity are 

eliminated. The collected material flows down the plate with 

the water film to a drain system. The wet system can be 

installed either as a conversion of the outlet field of the 

generic existing ESP or as a separate housing downstream 

from the primary generic ESP collector. If the wet unit is 

installed in the existing housing, the existing dry field will 

have to be removed and replaced with a field made of 

corrosion-resistant materials. WESP could be considered as a 

unit. this is a ect. 

The demolition and replacement of the generic existing ESP 

could be considered if site conditions are limited. Again, 

this is a ect. 

Building a pulse jet fabric filter (PJFF) downstream of the 

existing generic ESP could be considered. The PJFF would 

be tied-in during unit outage. This would be a major project. 

Conversion of the existing generic ESP to a PJFF could be 

considered. This would require a major unit outage and 

would be a significant project. 

47 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

It is possible that other generic concepts could be conceived 

to improve the performance of a generic ESP associated with 

Trona or SBC sorbent , , for reduction, 

As a means of developing rough cost estimates for some of the Table 3-28 ESP 

improvement concepts, Shaw contacted Hamon Research Cottrell to obtain their typical 

rough budgetary indicative cost estimates, expressed on an installed basis, for a generic 

180 MW cold side ESP (not for any specific ESP application) that will employ Trona or 

SBC injection for S02 reduction. The client name, power plant name, or location were 

not identified to the ESP vendor, but instead described as a confidential generic study 

scenano. 

Concept A - Upgrading Standard TRs to High Frequency Power Supplies 

As discussed, in certain cases, high frequency power supplies may increase average 

power into the ESP, and have a faster control response. For an example, if all the TR's 

are assumed replaced by high frequency power supplies to improve performance in all 

fields, the budgetary indicative price could be approximately $100,000 per high 

frequency power supply installed. For a generic 180 MW unit existing cold-side ESP 

with a total of five TR sets, the ESP vendor generic price may be $500,000 per ESP 

(installed basis), not including generic Owner costs, or contingency. 

Concept B- Additional Sectionalization 

As indicated in Table 3-28, by sectionalizing a generic ESP, individual electrical fields 

may be able to operate at an optimal level required for that section. In.general more 

electrical sectionalization allows a generic ESP to react better to various flue gas 

conditions. This concept includes additional sectionalization along with new high 

frequency power supplies to further improve performance of a generic ESP. For example, 

the budgetary indicative cost estimate could be approximately $80,000 pr high frequency 

power supply installed. For a generic 180 MW unit existing cold-side ESP, desiring to 

employ two new smaller high frequency power supplies (per each original larger TR set) 

for the sectionalization, there could be a total of ten high frequency power supplies 

installed, resulting in a ESP vendor generic price of approximately $800,000 per ESP 

(installed basis) for sectionalization with new high frequency power supplies, not 

including generic Owner costs, or contingency. 

Concept C- Additional Rapping 

If required, at a generic ESP, additional rapping points may help clean the plates which 

will fill up faster due to the higher inlet loading caused by the Trona!SBC sorbent 

injection. As indicated, evaluation and/or ESP internal inspection may be required to 

determine the required rapping density. Depending on the specifics of generic ESP, 

depending on the exact rapper configuration and the envil beam arrangement, the 

48 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

budgetary indicative price could be approximately $3,000 per rapper, depending on 

control requirements. For an example of a generic "maximum case scenario", one could 

assume doubling the number of existing rappers. For a generic 180 MW existing coldside ESP, with 100 plate rappers and 30 wire rappers, the ESP vendor generic price could 

between $300,000 per ESP if only the plate rappers are doubled in quantity or if wire 

build-up is indentified as a potential issue, it could be approximately $390,000 per ESP 

if both the plate and wire rappers are doubled in quantity. This does not include generic 

Owner costs, or contingency. 

Concept D - CFD Modeling 

As discussed in Table 3-28, Computational Fluid Dynamic (CFD) model studies of flow 

through a generic ESP can be considered. A model study of an existing generic ESP 

could indicate areas of possible re-entrainment, high velocity, and non-uniform flow 

distribution. Correcting these issues with vaning and perforated plate modifications 

could improve generic ESP performance. A generic ESP vendor price for such an initial 

CFD model could be approximately $40,000 per generic cold-side ESP sized at 

180MW, depending on the complexity of the CFD model. As indicated, this does not 

include generic Owner costs, contingency, or potential follow-up work. 

As stated, this section has presented a typical list of generic categories of concepts that 

could be considered for technical and economic attribute evaluation, at a generic ESP that 

is to employ Trona and/or SBC sorbent injection for S02 reduction. Additional study is 

required to determine applicability, degree of improvement (if any), or specific costs of 

these concepts for a given ESP. 

3.4.4 Byproduct Handling and Landfill Considerations 

Information from the current plant ash handling contractor indicates that approximately 

4.1 tons of ashlhr/plant is typically received in silos over a 60 hour weekend period. That 

equates to approximately 1500 tons of ash accumulated in the silos with a maximum 

current facility capacity of 1800 tons. If, for example, a DSI rate of 5000 lblhr is chosen, 

then an additional2.5 tons of by-product would be generated per hour per plant. Thus up 

to an additional 900 tons per weekend need to be planned for in the by-product area. One 

large silo or two of current size would possibly need to be added. Alternately, the 

byproduct handling operation would need to expand to a six day week for disposal. 

We note that during the testing with up to 12,000 lb/hr being injected into one unit, there 

were no reports of adverse impact on the pneumatic by-product transport system. 

The characterization of the resultant ash/DS mixture indicates that the ash produced with 

DSI should be suitable for disposal at the new station landfill. Care will need to be taken 

concerning the addition of water for dust suppression at the dustless unloader and 

additional water added at the landfill to obtain the desired mechanical properties of the 

compacted ash. 

49 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

The pH of the runoff from the Ash/SBC byproduct will likely be higher than what is 

acceptable for discharge so that a pH neutralization system may be required to treat 

landfill runoff prior to discharge. 

Dissolution of a p01iion of the compacted flyash/SBC mixture was seen during the 

testing. Dissolution of the product will result in higher total dissolved solids (primarily 

sodium and sulfate) in the landfill runoff and possibly loss of structural integrity of the 

landfill over the long term. Adequate cover of this material will be required to minimize 

this dissolution in the landfill so that it maintain its structural integrity. Continued 

contact of the ash/SBC mixture with water produced hydrogen gas. Gas generation 

would be controlled with adequate cover of this material. 

3.4.5 General Impacts on Plant Operation 

The injection of DSI did not have any discernable impacts on the operation of Units 5 and 

6. One of the questions that this study wanted to address was the potential impacts DSI 

would have on the air heater if injected before the air heater. However, the majority of 

DSI was after the air heater. No impact to the air heater performance from the limited 

amount of dry sorbent injected upstream of the air heater could be discerned from 

available data. 

An inspection of A side of Unit 5 ESP after the testing was completed showed a lighter 

shade of ash on the internals, but no operational problems. 

Though the plant did not have problems with the increased amount of ESP ash during the 

tests, the ESP ash removal equipment is likely undersized. The plant could not have 

continued dry sorbent injection around the clock for an extended period oftime due to the 

buildup of ash within the ESP hoppers. Based on the time required to evacuate the ESP 

hoppers, the plant would have fallen behind based on the existing system capacity. 

The delivery of pre-milled SBC did have unloading problems due to the clumping of the 

SBC caused by humidity and age of the pre-milled SBC. If SBC were to be used, on-site 

milling should be considered. 

The operation of a DSI system would likely result in the plant needing additional 

personnel to off-load the rail delivered dry sorbent and to maintain the operation of the 

injection systems. 

50 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

3.5 Cost Issues 

3.5.1 Capital Cost Issues 

Ifthe plant were to install a D SI system at Joppa, installed equipment would likely 

include: 

• A rail car unloading system potentially with additional trackage required to accept 

rail delivery oftl1e Dry sorbent located on the north side of the plant with a 

pneumatic feed system to transfer the DSI to Unit-pair specific storage silos 

• Upgrade of the ESP ash handling systems 

• Three dry sorbent feed systems, one for each set of two units including: 

o Storage silo 

o 2- 100% (unit basis) mills located in a sound enclosure 

o 3- 100% (unit basis) feed valves (one spare per pairofunits) 

o Compressed air system located in a sound enclosure 

o Cross connection piping within each system to feed the units for 

redundancy 

o Injection piping and lances 

Additional capital costs would be required to increase the efficiency of the ESPs to 

control particulate emissions or to add additional particulate removal systems so that the 

plant does not trigger PSD. 

3.5.2 Operating Cost Considerations 

The major operations and maintenance costs for a DSI system will be the purchase of 

DSI. 

Based on the following economic factors the annual costs for the 6 unit plant associated 

with DSI purchase was estinlated for the various Dry Sorbent options examined in this 

study; the results are shown in Table3-29: 

• Plant capacity factor of 90% 

• Average coal S02 content of0.61lb S02/MMBtu 

• 50% S02 removal required 

• Trona delivered price of $17 5/ton, SBC delivered price of $200/ton 

51 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Notes: 

1. Based on 50% S02 removal with plant burning PRB coal with 0.61 lbs of 

S021MM:Btu and a yearly plant capacity factor of 0.90 

2. The data for milled Trona injection after the air heater is minimal. This utilization 

rate achieved an average of 42.6% S02 removal. The utilization rate would likely 

be higher to achieve 50% removal, so the yearly estimated cost would likely be 

higher than shown to achieve 50% S02 removal. 

3. The data for SBC injection before the air heater is minimal. This utilization rate 

achieved an average of 67% S02 removal. The utilization rate would likely be 

lower to achieve 50% removal, so the yearly estimated cost would likely be lower 

than shown to achieve 50% S02 removal. 

Additional O&M costs will occur for additional plant personnel, the lost revenue of fly 

ash sales, the additional costs associated with disposal of the mixed ash/DSI product and 

additional electrical parasitic load. 

52 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

4 Conclusions and Recommendations 

As stated in the beginning of this study there were several key issues that this study tried 

to answer. These included: 

• whether continuous 50% or better S02 reduction and continuous 90% mercury 

removal can be achieved during normal plant operations including tum down of 

the units due to market demands; 

• whether the use of a dry sorbent will impact the level of acid gases and heavy 

metals in the flue gas; 

• whether there is an impact to the air heaters (if upstream of the air heaters was the 

selected DSipoint); 

• whether there is an impact to the ESP from either DSI reagent; 

• whether there is an impact to the operation of the fly ash handling system, and; 

• whether there are any issues in the handling of DSI that would cause undue 

hardship on the plant operation. 

4.1 Conclusions 

4.1.1 Plant Emissions Impacts 

• Greater than 50% S02 removal was obtained with un-milled Trona, milled Trona 

before the air heater and with SBC before or after the air heater. 

• 50% removal was not seen with milled Trona after the air heater 

• SBC had a better utilization efficiency than Trona whether milled or un-milled 

with a 0.158 lbs S02 removed per Ib of dry sorbent versus 0.100 lbs S02 removed 

per Ib of dry sorbent for milled Trona when injection was before the air heaters 

• Milled Trona was more efficient than un-milled Trona in S02 removal (ratio 

averages 0.100 vs. 0.093, lbs S02 removed per lb of dry sorbent respectively) 

when injected before the air heater 

• The injection location (whether before or after the air heater) impacts the 

efficiency of Trona and SBC utilization, with injection before the air heater 

having a significantly greater utilization efficiency 

• Dry sorbent injection will reduce acid gases; 80+% removal was seen in these 

tests 

• For mercury emissions, baseline testing showed a greater than 90% mercury 

removal. Mercury removal in the final SBC testing on Units 5 and 6 was also 

greater than 90%. However, mid 80% mercury removals were seen during other 

portions of the test program, which results in uncertainty regarding the effects of 

DSI on mercury removal 

• The addition of DSI will increase the amount of particulate matter leaving the 

stacks. The Joppa facility will trigger PSD due to injection of the dry sorbent and 

DSI material handling unless the control efficiency of the existing particulate 

control is increased. 

53 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

• There was also a slight increase in opacity when bnming Beiie Ayr coal, but the 

increase did not affect the plant's permit compliance. 

4.1.2 Plant Operational Impacts 

• The majority ofDSI occurred after the air heaters. The limited amount ofDSI 

before the air heaters did not cause any noticeable operational impact. Whether 

long term injection of dry sorbent before the air heaters will cause degradation of 

plant performance is unknown. Visual inspection of a portion of the Unit 5 ESP 

after the tests did not show any issues with DSI. Long term effects on the ESPs 

that may result from DSI are unknown. 

• The only operational issue concerning the handling of the DSI was the clumping 

of the pre-milled SBC which caused extended unloading durations. If SBC were 

to be used in a future DSI system, then the on-site system should include a milling 

operation. 

• Iti addition to capital cost requirements to instaii the DSI system and supporting 

infrastructure and to increase the efficiency of the existing ESPs or install new 

particulate control measures, the annual cost for the dry sorbent will be at least 

$16,000,000 per year and possibly higher depending on dry sorbent selected 

4.1.3 By-Product Handling Impacts 

• The increase in fly ash generated with DSI will require increased capacity of the 

fly ash handling system's daily operation, and/or additional storage 

• The resultant byproduct is landfiiiable. However the fly ash handling operation 

and landfiii operation will require the following: 

o The by-product should be wetted in a two stage approach where a portion 

of the water is added at the dustless unloader for dust control and the 

remaining water needed for optimum compaction be added at the landfill 

via a water truck or like conveyance system 

o The runoff pH will likely be high enough to require neutralization of the 

landfill pond runoff prior to discharge 

o The landfilled material will need to be managed (covered) to minimize 

standing water on the by-product due to its potential dissolution. The 

dissolution will increase the total dissolved solids in the landfiii runoff 

potential to a point impacting its discharge permit and potentiaiiy the 

Iandfiii integrity over the life ofthe landfiii 

o The increase in total byproduct produced by the plant wiii reduce the life 

of the landfi.Il (use up available capacity faster) 

54 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Electric Energy, Inc, Draft Final Report 

Joppa Generating Station D1y Sorbent Injection Test Program 

Joppa, Illinois 

4,2 Recommendations 

The following recommendations can be made: 

• Estimate the cost of particulate control upgrades for DSI options 

o Evaluate umnilled Trona injected before the air heater with ESP upgrades 

to address current regulations and not trigger PSD (high risk alternative), 

since un-milled Trona may have less of an impact on particulate emissions 

than other dry sorbents, 

o Evaluate other DSI options and address future utility MACT mles by 

adding a helper ESP or a fabric filter downstream of the existing ESP. 

• Perform economic engineering evaluation of S02 control technologies for the 

Joppa Station 

o Design criteria in line with expected utility MACT regulations for 

evaluating different options: 

• DSI with helper ESPs and fabric filters 

• Wet flue gas desulfurization 

• Dry flue gas desulfurization 

• ReACT 

• If the use ofDSI at Joppa is still viable after the review of ESP efficiency upgrades, 

then additional testing is warranted that would include: 

o Prolonged injection of each reagent upstream of the air heaters to 

determine potential long term impacts 

o Testing on both Units 5 and 6 so that the stack CEMs can be utilized 

versus induct sampling. 

o Additional mercury testing should be included 

• It would be beneficial for Joppa to conduct a full PSD analysis at the conclusion of 

CY20 I 0 operation using the latest emission data. 

55 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Electric Energy, I11c, Draft Final Report 

Joppa Generating Station Dry Sorbent Injection Test Program 

Joppa, Illinois 

Attachment 1 

Draft Report 

Source Emissions Sampling Report 

For Units 5 and 6 at Electric Energy, Inc. 

Joppa Station 

Project Number: 139424 

ShawE&I 

56 
Electronic Filing- Receiv(~!erk's Office, 08/15/2012 

Stiaw·' 

a wor!d of Solutions' 

September 1, 2010 

Mr. Bruce McCampbell 

Shaw Power, Fossil and Renewables 

100 Tec1mology Center 

Stoughton, MA 02072 

Subject: Source Emissions Sampling Report for EEl at Joppa Station 

Dear Mr. McCampbell: 

Shaw Environmental, Inc. (Shaw) is pleased to submit this source emission sampling report to Shaw 

Power- Fossil and Renewables for emissions testing of the Unit 5 and Unit 6 emission sonrce(s) at the 

Electric Energy, Inc. Joppa Station facility. The enclosed report details the results of the emission testing 

for this identified emission source, and also contains all pertinent backup field data to support the results 

and/or conclusions. 

We appreciate the opportunity to provide our services to Shaw Power- Fossil and Renewables, and we 

look forward to continuing to work closely "~th you. If you hav~ any questions or concerns regarding the 

contents of this proposal, please contact me at your convenience at 865-690-3211, or by email at 

russell.brvson!ii!.shawgrn.com. 

Sincerely, 

Russell D. Bryson, PE 

Project Manager 

Shaw Enviromnental, Inc. 

312 Directors Drive, Knoxville, TN 37923 

865-690-3211/ FAX: 865-694-7497 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

Final Report 

Source Emissions Sampling Report 

For Units 5 and 6 at Electric Energy, Inc. 

Joppa Station . 

Project Number: 139424 

Submitted to: 

Mr. Bruce McCampbell 

Project Manager 

Shaw Power - Fossil and Renewables 

100 Technology Center 

Stoughton, MA 02072 

Date: September 1, 2010 

Submitted by: 

Integrated Emissions Solutions Development (IESD) 

312 Directors Drive 

Knoxville, TN 37923 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Source Emissions Sampling Report 

For Sources Units 5 and 6 

Electric Energy, Inc. Joppa Station 

Draft Report 

Certification 

September 1, 2010 

s wuriG 0f Solutio-ns 

I certify that this document and all attaclrments were prepared under my direction or supervision in 

accordance with a system designed to assure that qualified pers01mel properly gather and evaluate the 

information submitted. Based on my inquiry of the person or persons who manage the system, or those 

persons directly responsible for gathering the information, tl1e information submitted is, to be the best of 

my knowledge and belief, true, accurate, and complete. 

Russell D. Bryson, PE 

Project Manager 

Shaw Envir01rmental, h1c. 

September I, 2010 

Date 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Table of Contents 

1. 0 h1troduction .. 

1.1 Testing Matrices ................. . 

1.2 Facility Description. 

1.3 Sampling Locations . 

1. 4 Operating Conditions 

2.0 Sll1IllllaryofResults ........ 

2. 1 Sulfur Dioxide (SOz) 

2. 1.1 Observations ... 

2.2 Oxides of Nitrogen (NOX) .... 

2.3 Total Particulate Matter .................. .. 

2.3.1 Observations ......... . 

2.4 Speciated Particulate Matter (PM10/PM2.5) .......... .. 

2.4.1 Observations ................................ . 

2.5 Condensable Particulate Matter (CPM). 

2.5.1 Observations ..... 

2.6 Speciated and Total Mercury [HgT, Hg0

, and Hg+2

]. 

2.6.1 Observations ................................................. . 

2.7 Halogens and Hydrogen Halides (C]z, HCl, HF) ... 

2.8 Air Toxic Metals .................... .. 

2.9 Sulfur Trioxide (SO,) .. 

2.9.1 Observations ........................ .. 

2.10 Mercury Material Balance ............... .. 

Appendices: 

Appendix A - Sampling Methodologies 

Appendix B - Calculations 

Appendix C - Laboratory Analytical Data 

Appendix D - Equipment Calibration Data 

Appendix E -Field Data Records 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

a worki ot Solutions"" 

··········· ······· . 1 

. ....... 1 

. ... 2 

. ........ 3 

...... 4 

. ..... 6 

............... ··········· 6 

. ............... 9 

.. ....... 9 

.. ..... 11 

... 12 

. ................. ,, .... ,,.,,,,,,, '' 12 

.. ....... 12 

.. ............... 13 

. ..... 13 

.. ...... 14 

.. ................... 15 

... 16 

.. 18 

...22 

.. ....... 22 

..22 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

a :rvorid of SoiuUons' 

List of T abies 

Table 1-1 

Table 1-2 

Table 1-3 

Table 1-4 

Table2-1 

Table 2-2 

Table 2-3 

Table 2-4 

Table 2-5 

Table 2-6 

Table 2-7 

Table 2-8 

Table 2-9 

Table 2-10 

Table 2-11 

Table 2-12 

Table 2-13 

Test Schedule Matrix 

Reference Sampling and Analytical Methods 

Emissions Sample Train Location Matrix 

Units 5 and 6 Operating Conditions (PI Data) 

S02 Concentrations, Mass Emission Rates and Removal Efficiency 

NOx Concentrations and Mass Emission Rates 

Total Particulate Matter (TPM) Mass Emission Rates 

Total Particulate Matter (TPM) Removal Efficiency 

Speciated Particulate Matter (PM1 O/PM2.5) Mass Emission Rates 

Condensable Particulate Matter (CPM) Mass Emission Rates 

Speciated Mercury (HgO & Hg2

+) and Total Mercury (HgT) Concentrations and Emission 

Rate 

Total Mercury (HgT) Removal Efficiency 

Halogens and Hydrogen Halides (CI 2 , HCI, HF) Concentration and Mass Emission Rate 

Air Toxic Metals Emissions Summary 

S03 Emission Summary 

Estimated Total Mercury (HgT) Material Balance 

Coal Feed Properties 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

List of Chemicals I Elements 

SYMBOLS AND ELEMENT, CHEMICAL,R 

ABBREVIATIONS CHEMICAL CONSTITUENT 

AI Aluminum 

Ag Silver 

As Arsenic 

Ba Barium 

Be Beryllium 

c Carbon 

Cd Cadmium 

Cr Chromium 

Cl Chlorine 

Co Cobalt 

CO I CO, Carbon monoxide I dioxide 

Cu Copper 

F Fluorine 

Fe Iron 

H Hydrogen 

Hg Mercury 

Hg2+ Oxidized mercury 

HgT Total mercury 

I Iodine 

K Potassium 

Mg Magnesium 

Mo Molybdenum 

Mn Manganese 

Na S.odium 

Ni Nickel 

NO Nitric Oxide 

NOx Nitrous Oxides 

0 Oxygen 

p Phosphorus 

Pb Lead 

s Sulfur 

Se Selenium 

Sn Tin 

so,t so, Sulfur dioxide I sulfur trioxide 

Tl Thallium 

Zn Zinc 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

a world of Solutions·· 

Common Acronyms 

ACRONYM DEFINITION 

A Amps 

AA Atomic Absorption 

ACI Activated Carbon Injections 

AF Atomic Fluorescence 

APCD Air Pollution Control Device 

APH Air Pre-Heater 

ASTM American Society of Testing & Materials 

AQS Air Quality Services 

GEMS Continuous Emiss1ons Monitoring Systems 

CFR Code of Federal Regulations 

CPM Condensable Particulate Matter 

CVAAS Cold-Vapor Atomic Absorption Spectroscopy 

CVAFS Cold-Vapor Atomic Fluorescence Spectroscopy 

EHS Environmental Health & Safety 

EPA Environmental Protection Agency (U.S.) 

ESP Electrostatic Precipitator 

FFBH Fiber-Filter Baghouse 

FGD Flue Gas Desulphurization 

GFAA Graphite Fum ace Atomic Absorption 

I CAP Inductively Coupled Argon Plasma 

IESD lnte.grated Emissions Solutions Development 

IC I on Chromatography 

LOI Loss on Ignition 

M30B EPA Test Method 30B 

NCASI National Council for Air & Stream Improvement 

OHM Ontario Hydro Method 

PM Particulate Matter 

PSA PS Analytical 

QAJQC Quality Assurance/Quality Control 

RATA Relative Accuracy Test Audit 

RCRA Resource Conservation & Recovery Act 

RFP Request for Proposal 

SCEM Semi-Continuous Emissions Monitor 

SCR Selective Catalytic Reduction 

Sl Sorbent Injections 

sow Scope/Statement of Work 

TAP Toxic Air Pollutant 

TCLP Toxicity Characteristics Leaching Procedure 

TAT Turn-Around Time (analytical) 

v Volt 

voc Volatile Organic Compound 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

1.0 Introduction 

Shaw Power, Fossil and Renewables, contracted Shaw Em~romnental and Infrastructure (E&I) to perfonn 

emissions testing associated with pem1itted emission sources. This report presents the results of the tests 

conducted on June 4th through 15th, 2010 at the Electric Energy, h1c. (EEl) facility located in Joppa, 

Illinois. The primazy objective of the testing was to determine the emissions of target air pollutants and to 

ascertain removal efficiencies across the air pollution control system during baseline and parametric 

testing conditions. Section 2.0 of this report provides the detailed emissions su=aries for the target 

pollutants. 

1.1 Testing Matrices 

Emissions sampling was performed under the following conditions: 

• Baseline: Emissions sources (Units 5 and 6) operating at normal maximum production 

• Parametric: Emission sources continuing to operate at normal maximum production, with the 

addition ofthe follo"~ng dry sorbent injection materials: 

- Trona (milled and mnnilled) 

- Pre-Milled SodiUlll bicarbonate (SBC) 

The testing matrix for each condition is shown in Table 1-1. Field sampling of the measured parameters 

conformed to the reference test methods cited in the governing regulations listed in Table 1-2. 

. - . - 'l)J:rte Task 

6/4/2010 Test1ng 

6/5/2010 Testing 

6/6/2010 No Testing 

6f7/201 0 Testing 

6/8/2010 Testinq 

6/9/2010 Testing 

6/10/2010 Testina 

6/11/201 0 Testing 

6/12/2010 No Testinq 

6/13/2010 No Testing 

6/1.4/2010 Testino 

6/15/2010 Testing 

6/16/2010 No Testing 

6/17/2010 

6/18/2010 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

Table 1-1 

Test Schedule Matrix . . Trona liijE>dion SBC lnjecliQtt 

· Type l..ocaffun Ldc:rtirm . 

cotiifrt!Qjj Milled !Jnmilled: U6 us . U6 

Basel1ne No InJeCtions 

Baseline I No Injections 

Weekend - EEl off 

Parametric X Before Air Heater 

Parametric X Before Air Heater 

After Air 

Parametric After Air Heater- Heater 

GEMS Only X (a.m. only) (p.m. only) 

Before Air 

Steady-State Heater 

Steady-State After Air After Air 

GEMS Only Heater Heater 

Weekend- EEl off 

Weekend- EEl off 

Steady-State After Air After Air 

GEMS Onlv Heater Heater 

After Air After Air 

Parametric Heater Heater 

Unit 5 down due to steam tube malfunction EEl halted testing . 

Packing and demobilization 

Return travel 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

a world of Solutions· 

Table 1-2 

Sampling was performed on the individual combustion exhaust gas streams from Units 5 and 6 and the 

shared exhaust stack (Stack 3). Table 1-3 (follo\\~ng page) details the sampling matrix for each sample 

location. 

1.2 Facility Description 

Units 5 and 6 of the EEl Joppa Station are both 180 MW pulverized coal (PC) boilers that are fueled by 

Powder River Basin (PRB) coal. During the testing, the mtits use either Thmtder River (Jacobs Ranch) 

or Belle Ayr PRB coal. A separated over-fire air system (SOFA) is used to control NOx, and particulate 

is controlled with an electrostatic precipitator (ESP). The layout of the process equipment at the Joppa 

Station is sho\\~1 in Figure 1-1 (see page 3). 

The combustion gas stream from each unit exhausts from the boiler, through the economizer section, and 

through the air pre-heater prior to entering the electrostatic precipitator. The inlet duct after the 

economizer splits into nvo parallel gas streams entering the ESP. The ESP outlet consists of parallel 

dncting then recombines before entering the induced draft fan. The gas streams from Units 5 and 6 are 

combined to exit through a common shared stack. 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

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650. ± 25•f 35() ± 25"f 

{320"C) (lllO'C) 

32:0±2YF 

{um•CJ 

Figure 1-1 General Arrangement for Units 5 and 6 

Notes: 

(1)- Actual arrangement consists of two J.D. fans per unit prior to entering the common stick 

(2)- Vertical flow through eachAPH 

1.3 Sampling Locations 

All single point sampling was conducted on each unit at the following locations: 

• Economizer Outlet- consisted of two parallel ducts (Duct A & B) each 'vith a cross sectional area 

of 230 square feet at the sampling location. 

• ESP Inlet - consisted of nvo parallel ducts (Duct A & B) each with a cross sectional area of 230 

square feet at the sampling location. 

• ESP Outlet - consisted of nvo parallel ducts (Duct A & B) each "'~th a cross sectional area of 250 

square feet at the sampling location. 

• Common Stack - single annular stack \\~th an 18 foot diameter at the sampling location. 

All CEMS (e.g. 0 2, C02, NOx) measurements were conducted at a single point centrally located inside 

Duct A of each designated sampling location (see Table 1-3), simultaneously \\~th each wet chemistry 

method (e.g. PM, Hg). Wet chemistry sampling trains were located at the common stack and a single 

centralized location inside Duct B of each sampling location (see Table 1-3). 

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Project No: 139424 

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a wurid of Solutlorts1.4 Operating Conditions 

During the testing program, the facility operated under the following conditions, and noted in Table 1-4 

(see page 5). 

617/201 0 Unit 6 

6/8/2010 Unit 6 

6/9/2010 Unit 6 

6/9/2010 Unit 6 

6/10/2010 Unit 6 

6/11/2010 

.6/14/2010 

6/15/2010 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

Table 1-3 

TronaMilled 

SBC 

SBC 

SBC 

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Table 1-4 

Units 5 and 6 Operatin Conditions (PIOata) 

' ' ' 

" 

" iUmt s " 

" " Gate "" :Run# 

6/4/2010 1 

6/4/2010 2 

6/5/2010 3 

6/5/2010 4 

6/7/2010 1 

6/7/2010 2 

6/7/2010 3 

6/8/2010 1 

6/8/2010 2 

6/8/2010 3 

6/9/2010 1 

6/9/2010 2 

6/10/2010 1 

6/10/2010 2 

6/10/2010 3 

6/11/2010 1 

6/11/2010 2 

6/11/2010 3 

6/14/2010 1 

6/14/2010 2 

6/15/2010 1 

6/15/2010 2 

6/15/2010 3 

Shaw Power/EEl Testing 

Project No: 139424 

August2010 

U<:>ad"' 

JIJJW 

174.5 

175 

171.2 

174.1 

172.5 

172.5 

171.1 

180.4 

179.8 

176 

177.6 

177.7 

175.6 

176.4 

178.5 

173.3 

173.7 

173.7 

173 

173 

175.5 

175.6 

174.3 

ubi~ 'Total 

JJmtll 5&6'Total flow@ 

l..oall !..<:lad Stacl( ' Mw MW mmscffi DSlType 

181.91 356.4 54.18 Baseline 

182.4 357.35 54.43 Baseline 

180.56 351.75 53.68 Baseline 

180.46 354.54 53.91 Baseline 

unmilled 

181.86 354.38 53.94 Trona 

unmilled 

182.28 354.82 53.94 Trona 

unmilled 

182.5 35363 53.73 Trona 

183.51 363.89 54.63 milled Trona 

183.58 363.38 54.88 milled Trona 

183.9 359.9 54.11 milled Trona 

185.14 362.79 54.45 milled Trona 

184.63 362.31 54.29 SBC 

182.67 358.22 53.91 SBC 

182.06 358.49 53.99 SBC 

182.13 360.63 54.21 SBC 

181.74 355.06 54.01 SBC 

178.42 352.14 53.61 SBC 

180.96 354.64 53.84 SBC 

181.43 354.4 53.95 SBC 

181.21 354.21 53.77 SBC 

182.21 357.89 53.1 SBC 

182.15 357.71 . 54.12 SBC 

183.28 357.62 54.36 SBC 

" 

" 

"~eciion 

t.ocal:ion 

N/A 

N/A 

N/A 

N/A 

before air 

heater 

before air 

heater 

before a1r 

heater 

before air 

heater 

before air 

heater 

before air 

heater 

after air 

heater 

after air 

heater 

before air 

heater 

before air 

heater 

before air 

heater 

after air 

heater 

after air 

heater 

after air 

heater 

after air 

heater 

after air 

heater 

after air 

heater 

after air 

heater 

after air 

heater 

" 

" 

Average 

ltljection 

Rate " 

(lblfit) ' 

N/A 

N/A 

N/A 

N/A 

5,971 

11,659 

10,219 

8,838 

8,561 

8,688 

14,237 

11 ,643 

7,733 

7,275 

6,921 

5,882 

11,077 

14,665 

9,284 

9,683 

10,200 

9,956 

10,438 

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2.0 Summary of Results 

As noted in Section 1.0 of this report, the primary objective of these tests was to determine the emission 

rates of target air pollutants and to ascertain removal efficiencies across the air pollution control system 

during baseline and parametric testing conditions. Therefore, emissions sampling was perfonned under 

the following conditions: 

o Baseline: Emissions sources (Units 5 and 6) operating at normal ma.ximum production 

o Parametric: Emission sources continuing to operate at normal maximum production, with the 

addition of the following dry sorbent injection materials: 

- Trona (milled and mnnilled) 

- Sodilllll bicarbonate (SBC) 

The specific pollutants and data parameters determined from the testing were: 

o Sulfur dioxide/sulfur trioxide (SO,JS03) -mass emission rates, removal efficiency 

o Oxides of nitrogen (NOx) -mass emission rates 

o Total particulate matter (PM), speciated PM (PM10/PM2.5), and condensable particulate matter 

(CPM)- mass emission rates, removal, and control efficiency 

o Mercury speciation [total mercmy (HgT), elemental mercmy (Hg0), and oxidized mercury (Hg+0)] 

-mass emission rates, removal efficiency 

o Halogens and hydrogen halides (CJ,, HCl, HF)- mass emission rates and concentrations 

• Air toxic metals -mass emission rates 

The following sections provide pollutant-specific results and obsen,ations. 

2.1 Sulfur Dioxide (S02) 

Using EPA Method 6C, sulfur dioxide (S00) concentrations were measured in the gas stream at the 

selected sample location. The S02 emission rates were calculated and are reported here in mtits of lblhr 

and lb/MMBtu. Gas stream concentrations are reported in parts per million by volllllle, dry basis (ppmvd). 

In addition to the mass emission rates, the test data was used in conjmtction with the dry sorbent injection 

(DSI) feed rates to determine removal efficiencies in units of pounds of S02 removed per pomtd of DSI 

Ob SO,/lb DSD. Secondary removal efficiency was estimated based on the mass emission rates 

determined from the economizer (ECON) outlet, electrostatic precipitator (ESP) outlet, and stack. Table 

2-l shows the S02 test results. 

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Project No: 139424 

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Table 2-1 

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2 .. 1.1 Observations 

so2 removal efficiencies were calculated as follows: 

A 

Sliaw· ~ 

a worid of Solutions~ 

l. Using data generated in procedure above, S02 removal efficiency is calculated as follows, except 

as noted: 

?itmo<•si Efi%= (s02 W£5 r.te ~E~QN,':~,~~:;~>O~ ~H:s ~~~ (25? OUT ~ !) 

.0" on~". ,t. ,_~CO.< OUTE) 

2. On 6/14 and 6/15, one of the Shaw CEMSs was relocated to the Unit 5 ECON OUT position. 

Therefore, S02 removal was calculated as follows: 

. -· 'b· . 'b; 'b - (_UrJt 6 502msss r.ste l ECON mJT.f::j + Unlt 5 502l:!La..~ ratt (ECON OUTlirJ- 502 m::;ss t'.ste (S.taC'i, lir:J) 

(unit 6 S02mss:: ~te (ECONOVT~) +UnitS S02r.:Hss r;te (:=CON OUT,;[~}) \ ~ -•~·· '<_ ~H~j 

2.2 Oxides of Nitrogen (NO X) 

Using EPA Method 6C, oxides of nitrogen (NOx as NOo) concentrations were measured in the gas stream 

at the selected sample locations. The NOx mass emission rates were calculated and are reported in units 

of lblhr and lb/MMBtu. Gas stream concentrations are reported in ppmvd Table 2-2 shows the S02 test 

results. 

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Table 2-2 

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2.3 Total Particulate Matter 

Emissions data for the specific subsets of particulate matter (PM) were acquired as noted below. Detailed 

emissions results are shom1 in Table 2-3. 

Using either one or a combination of EPA Method 5, Other Test Method 27 (OTM-27), and/or Method 

202, particulate matter (PM) data were acquired per the testing matrix schedule. PM mass emission rates 

were calculated in m1its of lb/hr and lb/MMBtu. EPA Method 19's published fuel factors for subbitmninous coal were used in calculating the mass emission rate in lb!MMBtu. Based on the calcnlated 

emission rates for total PM, Shaw estimated the net changes in emission rates by comparing the baseline 

and parametric data. The estimated total PM removal efficiency of the air pollution control (APC) system 

(ESP) is shown in Table 2-4. 

Table 2-3 

Table 2-4 

Total Particulate Matter (TPM) Removal Efficiency 

• · · ' Total PJ\11 Mass I . . Emission Rate 

Uni* Sampling Location Test Conditl-Oil Pate (lbfhr) 

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Baseline 

I 

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2.3.1 Observations 

On June 4, 2010, Shaw conducted a Method 5 train at sample location Unit 6 ESP Inlet and observed an 

outlier result for Run 2. Based on the re-views, specific actions were taken to remove/modify outlier data 

points. Specifically, the resulting PM mass emission rate appeared low compared to the other three 

sample rm1s. Shaw reviewed all archived samples and data with no observed inconsistencies. Per standard 

EPA practices, Shaw discarded tins data point from the average. 

2.4 Speciated Particulate Matter (PM10/PM2.5) 

Emissions data for the specific subsets of particulate matter (PMlO and PM2.5) were acquired as noted 

below. Detailed emissions results are shown in Table 2-5. 

The speciated PM for PMIO and PM2.5 was determined using EPA OTM-27. Mass emission rates were 

calculated in units of lb/hr and lb/MMBtu. EPA Method 19's published fuel factors for sub-bituminous 

coal were used in calculating the mass emissio!l rate in lb/MMBtu. Based on the calculated emission rates 

for each type of PM, Shaw estimated the net changes in emission rates by comparing the baseline and 

parametric data. 

Table 2-5 

~ 

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

So'Jben1 

Injection Mass Emission R:ate 

Unit SamplirJQ Rate Unit Load PM>10 PM-:10>2.5 PM<2.5 

# Location T:est COndition DalE lblhr MW lb/hr lblhr )b/bf 

Unit 6 ESP Outlet Baseline 6/4-5/2010 NIA 181.45 13.48 50.84 17.00 

Unit 6 ESP Outlet Trona - Unmilled 617110 9,283 182.21 5.14 65.93 13.63 

Unit 6 ESP Outlet Trona -Milled 618110 8,696 183.65 9.14 123.10 35.85 

Unit 6 ESP Outlet Sodium Bicarbonate (SBC) 6/10110 7,310 182.30 8.61 199.66 20.69 

-~ ~-------

---- ~ ~-

So men! Est~mated Mass Emiss1on Rate 

1njection Comb•ned Change from Baselme 

S:ampflng Rate Unit Load PM>10 PM<10>Z5 PM<2.5 

Unit# Location T'est COndition Date lblhr MW tblhr lblhr lb.fhr 

Umt 6 ESP Outlet Basehne 6/4-512010 NIA 181 45 - -

Unit 6 ESP Outlet Trona- Unmilled 6/7110 9,283 182.21 -8.3 15.1 -3.4 

Unit 6 ESP Outlet Trona- Milled 618110 8,696 183,65 -4.3 72.3 18.9 

Unit 6 ESP Outlet Sodium Bicarbonate (SBC) 6110110 7,310 182.30 -4.9 148.8 3.7 

- - :E;;,t;;-atedMassEm•s,;,o;;~Rale- d Change fmrn Basehne 

Sampling Rate Unn L:Oad PM >10 PM<10>25 PM<2.5 

Unit# Location Test Cond itfon Date lb/hr MW tonlyr tonfyr 

Un1t 6 ESP Outlet Baseline 614-512010 NIA 181 45 - - Unit 6 ESP Outlet Trona- Unmilled 617110 9,283 182.21 -33.4 60.4 

Unit 6 ESP Outlet Trona - Milled 6/8/10 8,696 183.65 -17.4 289.1 

Unit 6 ESP Outlet Sodium Bicarbonate SBC) 6110110 7,310 182.30 -19.5 595.3 

2.4.1 Observations 

Dming the performance of particulate testing, the following obsen,ations were made by Shaw. Based on 

the reviews, specific actions were taken to remove/modify outlier data points: 

tonfy-r 

-

-13.5 

75.4 

14.8 

Shaw Power/EEl Testing 12 

Project No: 139424 

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o During June 4, 2010, OTM-27 train Run 2 at sample location Unit 6 ESP Outlet, the resulting PM 

mass emission rate appeared significantly higher compared to tl1e other tlrree sample runs. Shaw 

reviewed all archived samples and data and concluded that possible contamination was picked up 

from the inside surface of the sample port. Per standard EPA practices, Shaw discarded this data 

point from tl1e average. 

o During June 7, 2010, OTM-27 train Run 3 at sample location Unit 6 ESP Outlet, the resulting PM 

mass emission rate appeared significantly higher compared to the other tlrree sample runs. Shaw 

reviewed all archived samples and data and concluded that possible contamination was picked up 

from the inside surface of tl1e sample port. Per standard EPA practices, Shaw discarded tl1is data 

point from the average. 

2.5 Condensable Particulate Matter (CPM) 

Emissions data for condensable particulate matter (CPM) were acquired as noted below. Detailed 

emissions results are shown in Table 2-6. 

The CPM data was determined using EPA Method 202. Mass emission rates were calculated in units of 

lb/hr and lb/MMBtu. EPA Metl10d 19 published fuel factors for sub-bituminous coal were used in ' 

calculating the mass emission rate in lb/MMBtu. Based on the calculated emission rates for CPM, Shaw 

estimated tl1e net changes in emission rates by comparing the baseline and parametric data. 

Table 2-6 

Condensable Particulate Matter (CPM) Mass Emission Rates . . ' " ' ~ " 

" ~ ~ "" , ' Coti:iJ;l:in:eif Mass Emiss1on Rate 

::: - Test " DSl Unit 'ti:iat;l 1:<Jta! ParticUlat-e FilteraD:te PM CPM 

Unit Lbcat10n Ctindilton Test-date Jb':thr MW: 1blhr lbfh-r lblh-T - ----------------- ---

Unit 5 & 6 Stack Baseline 6/4-5/2010 N/A 354.52 152.87 137.37 15.5 

Unit 5 & 6 Stack SBC 6/15/10 9135 357.67 227.70 155.08 72.62 

2.5.1 Observations 

During the performance of particulate testing on June 4, 2010, Method 5/202 train Run I at Unit 5 & 6 

stack sample location, Shaw observed that the resulting PM mass emission rate appeared significantly 

higher compared to the other three sample runs. Shaw reviewed all archived samples and data and 

Shaw Power/EEl Testing 

Project No: 139424 

August2010 

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~· SHaw'' 

a worid of Solutio-ns· 

concluded that possible organic material contamination. Based on the reviews, specific actions were taken 

to remove/modify outlier data points. 

2.6 Speciated and Total Mercury [HgT, Hg0

, and Hg+2

] 

Emissions data for speciated and total mercury were acquired as noted below. Detailed emissions results 

are sho"~' in Tables 2-7 and 2-8. 

Emissions of mercury (total and speciated) were determined using ASTM Method D6784-02. Mass 

emission rates for total mercury (HgT) were calculated in units of lblhr and lb/TBtu. In addition to the 

emission rates, the removal efficiency ofthe air pollution control system during baseline and parametric 

testing was also determined. 

Table 2-7 

Speciated Mercury (HgO & Hg2

•) and 

Total Mercury (HgT) Concentrations and Emission Rate 

OxidiZed Mercury - Hg'z+ E!ernmtat Mercury-1-190 

Sotberit Mass COne. Cone . Mass Cooc- at . . lrt~on qQnc. at Emission atSTP, at EmisSion ST.P, 

Samp:Jing Test Rate Unlt.L:.oad STP, Rate, 3%0Z STP, Rate, 3%02, 

_IJl1il_______l-ocaffi:& 

Unit 6 ECON Outlet 

_____(Condition 

Baseline 

(lblh_r)~ate 

N/A 181.45 6/4-5/10 

-~~ 

1.38 0.00140 1.42 6.60 0.00666 6.80 

Unit 6 ESP Outlet Baseline N/A 181.45 6/4-5/10 0.25 0.00042 0.34 0.81 0.00139 1.14 

Units 

5&6 Stack Baseline N/A 355.27 6/4-5/10 0.32 0.00104 0.43 0.69 0.00226 0.93 

Trona w 

Unit 6 ECON Outlet Unmilled 9,283 182.21 6/7/10 0.09 0.00012 0.09 0.20 0.00025 0.21 

TronaUnit 6 ESP Outlet Unmilled 9,283 182.21 6/7/10 0.20 0.00031 0.25 1.69 0.00242 2.04 

TronaUnitS ECON Outlet Milled 8,696 183.65 6/8/10 0.08 0.00012 0.08 0.49 0.00053 0 50 

TronaUnit 6 ESP Outlet Milled 8,696 183.65 6/8/10 0.38 0.00064 0.56 3.25 0.00551 4.77 

Untt 6 ECON Outlet SBC 7,310 182.30 6/10/10 0.27 0.00033 0.28 4.12 0.00502 4.26 

UnitS ESP Outlet SBC 7,310 182.30 6/10/10 0.20 0 . .00033 0.24 2.49 0.00422 3.02 

Unit5 ECON Outlet sse 10,198 182.61 6/15/10 0.42 .0.00074 0.43 7.55 0.01385 7.79 

Unit 6 ECON Outlet SBC 10,198 182.61 6/15/10 0.75 0.00064 0.77 1.90 0.00251 1.97 

Umts 

5&6 Stack SBC 10,198 357.67 6/15/10 0.07 0.00023 0.09 0.66 0 . .00211 0.82 

---------------------------------------------------------

Total Mercury - HgT 

Cone. 

Sorbeht Cone. Mass at Elemental Total 

lojecHon Un1t at Emiss10n STP, HgO HgT 

Sampling Rale iliad STP, Rate, 3%02, EmissiOn 'Rate: Emlss10n Rate 

Unit Location Test Condition (lbl~r) --~~~". _ ullfm3 lblhr ugim3- (lb/T~tu) ~-

Unit 6 ECON Outlet Baseline 

Unit 6 ESP Outlet Baseline 

Units 5 & 6 Stack Baseline 

Unit 6 

Unit 6 

Unit 6 

Unit 6 

UnitS 

ECON Outlet Trona -Unmilled 

ESP Outlet Trona- Unmilled 

ECON Outlet Trona- Milled 

ESP Outlet Trona- Milled 

ECON Outlet SBC 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

N/A 181.45 

N/A 181.45 

N/A 355.27 

9,283 182.21 

9,283 182.21 ~ 

8,696 183.65 

8,696 183.65 

7,310 182.30 

6/4-5/10 7.98 0.00806 8.21 4.84 5.86 

6/4-5/10 1.06 0.00181 1.48 0.81 1.05 

6/4-5/10 1.01 0.00330 1.36 0.66 0.97 

6/7/10 0.29 0.00037 0.30 0.16 0.23 

6/7/10 1.90 0.00273 2.29 1.02 1.16 

6/8/10 0.56 0.00066 0.58 0.30 0.37 

6/8/10 3.63 0.00615 5.32 3.40 3.80 

6/10/10 4.39 0.00535 4.53 3.04 3.23 

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a world of Solutio11s· 

Table 2-8 

6/4-5/2010 0.00327 93.0% 

6/7/2010 0.00545 87.7% 

84.1 

6/10/2010 0.00909 

2.6.1 Observations 

During the performance of speciated mercury testing, the following observations were made by Shaw. 

Based on the reviews, specific actions were taken to remove/modify outlier data points: 

• During June 8, 2010, OHM train Run 1 at sample location Unit 6 ESP Ontlet, the resulting gas 

stream moisture was observed to be significantly lower compared to the other sample runs. Shaw 

reviewed all archived samples and data and concluded that limited physical access to the sample 

point may have resulted in a non-typical sample probe location. Discnssions with EEl persmmel 

in conjunction with standard EPA practices resulted in discarding this data point from the 

average. 

• During June 10, 2010, OHM train Run 1 at sample location Unit 6 ECON Outlet, the resulting 

gas stream moisture was observed to be significantly lower compared to the other sample runs. 

Shaw reviewed all archived samples and data and concluded that limited physical access to the 

Shaw PoweriEEI Testing 

Project No: 139424 

August 2010 

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a worid of Solutions 

sample point may have resulted in a non-typical sample probe location. Discussions with EEI 

persmmel in conjunction with standard EPA practices resulted in discarding this data point from 

the average. 

• During June 10, 2010 OHM train Run I at sample location Unit 6 ESP Outlet, the resulting gas 

stream moisture was observed to be significantly lower compared to the other sample rm1s. Shaw 

re,~ewed all archived samples and data and concluded that limited physical access to the sample 

point may have resulted in a non-typical sample probe location. Discussions with EEl persmmel 

in conjunction with standard EPA practices resulted in discarding this data point from the 

average. 

• Shaw performed OHM sampling at the ECON outlet location, but observed that the resulting Hg 

data was lower tl1an tl1e corresponding ESP outlet or stack data. Shaw concluded that possible 

interference from the PAC injection system contributed to tl1e low ECON outlet data. Mercmy 

removal efficiencies were calculated using the Hg inlet rate from the coal feed, and the stack or 

ESP Outlet OHM train measurements. 

2.7 Halogens and Hydrogen Halides (C/2, HCI, HF) 

Emissions data for chlorine, hydrogen chloride, and hydrogen fluoride were acquired as noted below. 

Detailed emissions results are sho""' in Table 2-9. 

Emissions of chlorine, hydrogen chloride and hydrogen fluoride were determined using EPA Method 

26A. Mass emission rates were calculated in units of lb/hr, and concentrations are reported in ppmvd. 

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Notes: 

Table 2-9 

Halogens and Hydrogen Halides (CI2, HCI, HF) 

Concentration and Mass Emission Rate 

(1) with a"<" qualifier are repot1ed as below the Repm1able Detection Limit (RDL)- Conesponding concentrations and mass emission rates have bee

reported RDL as the minimum mass 

(2)- The total mass for each metal is the sum of the front half and back half resulls. Standard reporling practice for data with a "<'' qualifier includes the RDL 

sample and qualifying the Total as "<" the repm1ed quantity 

(3)- NIA Applicable 

(4)- June 4-5,2010- Fuel fired was East Thunder (Jacobs Ranch) PRB Coal 

(5)- June 15,2010- Fuel fired was Belle Ayr PRB Coal 

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2.8 Air Toxic Metals 

Emissions data for targeted air toxic metals were acqnired as noted below. Detailed emissions results are 

shown in Table 2-10. 

Emissions of the specific air toxic metals were determined using EPA Method 29. Mass emission rates 

were calculated in units of lb/hr, and concentrations are reported in milligrams per cubic meter (mg/m 3

). 

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Table 2-10 

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0.0009 

0.6052 

<0.0002 

<0.0007 

<0.0013 

<0.0002 

<0.0007 <0.0007 <0.0007 

0.0034 0.6505 

<0.0002 <0.0002 <0.0002 

0.6682 

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0.0016 

0.0190 

0.0007 0.0008 

0.0112 0.0127 

0.0009 

0.0013 0.0009 

0.0053 0.0052 

0.0008 0.0003 

0.0014 

/\._ 

~ Sliaw'' 

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0.0055 

0.0010 

0.0015 

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a worlil of S.oMim1s· 

Notes: 

(1)- Data with a 10<11 qualifier are reported as below the Reportable Detection Limit (RDL)- Corresponding concentrations and 

mass emission rates have been calculated using the reported RDL as the minimum mass 

(2)- The RDL for the Front Half (nozzle/probe/filter) and Back Half (back of filter housing/all impingers) varies for each metaL 

(3)- The total mass for each metal is the sum of the front half and back half results. Standard reporting practice for-data with a 

"<"qualifier includes the RDL in the TOTAL sample and qualifying the Total as"<" the reported quantity 

(4)- June 4-5,2010- Fuel fired was East Thunder (Jacobs Ranch) PRE Coal 

(5)- June 15,2010- Fuel fired was Belle Ayr PRB Coal 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

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2.9 Sulfur Trioxide (503) 

I ,·\ 

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Emissions data for S03 was acquired as noted below. Detailed emissions results are shown in Table 2-11. 

Emissions of the specific air toxic metals were determined using NCASI Method 8A. Mass emission rates 

were calculated in units of lblhr, and concentrations are reported in milligrams per cubic meter (mg/m3). 

Table 2-11 

2.9.1 Observations 

Shaw performed S03 sampling at the common stack during the baseline condition only. Shaw laboratory 

personnel performed onsite titrations of the samples in accordance with the procedures in the reference 

test method. Shaw persmmelnoted that starting with the second test run, the titration procedures did not 

reach the reference endpoint for comparative data and the results in the field were inconsistent. 

The samples were archived and submitted to the Shaw TDL laboratory npon return to the Knoxville 

office. The laboratory performed ion chromatography (IC) analysis, with the results as shown in Table 

2-11. Shaw's review of the data shows that extremely high sulfite concentrations were obsen•ed from the 

condenser catch samples for Run 2 through Run 4. The sulfite concentrations appeared to be outside the 

normal range for coal fired boiler operations and inconsistent with known regulatory data. 

Shaw did not observe any physical irregularities in the samples. Therefore, Shaw recommends that these 

runs be discarded from consideration. 

2.10 Mercury Material Balance 

A material balance across the Unit 5 and 6 was estimated as shown in Table 2-12. The material balance 

was calculated using the coal fuel analyses (ultimate, proximate, and mercury mass) in conjunction "~th 

OHM sample train data acquired at either the stack or Unit 6 ESP outlet. The fly ash data was determined 

by Shaw's TDL laboratory, but was limited to baseline and SEC injection testing days. For the mercury 

mass in fly ash during Trona injection, Shaw used the average of the baseline and SEC analytical data to 

Shaw Power/EEl Testing 

Project No: 139424 

August 2010 

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perform the material balance calculations on June 7-8, 2010. The estimated coal feed properties are 

shown in Table 2-13. 

Table 2-12 

Estimated Total Mercury (HgT) Material Balance . . , . . . . . ; . . - . . . ,~ ~ ~ 

. . , . . - . . . . .. . , 1-Mffli , , , . . . . . . . . ®81 Hg ln • ; ' !"lll '0111- !f!l: ®f , 'lfolilf.Hg .• -~ntea FOi • . . , . . , , !!"'>ill. , ll!.Y~.I {stli$11} pijt - i;l}!l'"d -$a!!.!I!Ie - . ... . • - . ,-:0~ . <>on~ , gll\lbl: giillllt !!'!lfl"ll" {Fd) gllllfir!FdJ '% Pf-!i!lln. 

6/4/2010 Baseline 21.71 12.22 1.56 13.78 63% 

6/5/2010 Baseline 20.77 10.87 1.46 12.33 59% 

6171201 ol11 Trona-Unmilled 20.16 14.19 2.87 17.07 85% 

6/8/201 0(1

) Trona-Milled 35.10 13.86 5.59 19.45 55% 

6/10/2010 SBG 29.11 15.32 4.12 19.44 67% 

6/15/2010 SBG 16.88 11.52 1.07 12.59 75% 

Notes: 

(1)- Fly ash mercury data determined by average of baseline and SBC analytical data 

Table 2-13 

Coal Feed Properties -- ------~-.:------ -------~-

' C~ Sampt¢ ; · - • • • - • ~ ".Ash Molsb tl9 • H!j- . ' !COli! Fetid~ 

.. . . ~ . . ~ _ -~qri ___ '_ .BI:Wlb,_; ~!:ll. · ')'. · JpJi!l11\111}. "!Pi>~ !lblnr) . !91ilht" 

6/4/2010 Baseline 8,420 7.95 26.40 0.098 943 359,396 180 

6/5/2010 Baseline 8,370 7.54 27.10 0.099 943 337,105 169 

6/7/2010( 11 Trona-Unmilled 8,630 7.77 26.60 0.081 1000 402,716 201 

6/8/201 0(1

) Trona-Milled 7,840 7.72 33.00 0.131 1000 395,801 198 

6/9/201 0(1

) Trona-Milled- GEMS only 8,390 8.32 27.90 0.103 1000 380,580 190 

6/10/2010 SBG 8,470 7.80 27.80 0.113 1056 410,037 205 

6/11/2010 SBG- GEMS only 8,430 8.02 27.80 0 164 1056 374,687 187 

6/14/2010 SBG- GEMS only 8,350 7.16 28.60 0.083 1056 377,582 189 

6/15/2010 SBG 8,510 6.41 28.40 0 071 1056 375,298 188 

Notes: 

(1)- Fly ash mercury data determined by average of baseline and SBC analytical data 

The fly ash data was determined by Shaw's TDL laboratory, but was limited to baseline and SBC 

injection testing days. For the mercury mass in fly ash during Trona injection, Shaw used the average of 

the baseline and SBC analytical data to perform the material balance calculations on June 7-8,2010. 

Shaw Power/EEl Testing 

Project No; 139424 

August 2010 

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Appendix A 

Sampling Methodologies 
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Sampling Methodologies 

Test Methods Used 

Location of Traverse Points 

A 

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To ensure representative measurement of gas velocity and volumetric flow rates, the cross section of the 

gas ducts and stack were di'~ded into discrete sampling points according to the procedures described in 

40 CFR 60, Appendix A, Method I. The stack gas characteristics (i.e., velocity pressures and 

temperature) were measured at each of the traverse locations during each test run. 

Velocity and Volumetric Flow Measurement 

Velocity measurements were performed during each test rm1 at each traverse point to characterize the gas 

stream velocities and flow characteristics using the procedures outlined in 40 CFR 60, Appendix A, 

Metl10d 2. Velocity pressures were measured using an "S"-type or standard Pilot tnbe and standard oil 

filled manometers. Data was recorded for each traverse point location. 

Temperature Measurement 

The temperature of the stack gas was recorded at each sample traverse point using K-type tl1ermoconples 

and dedicated digital temperature readouts. Temperatures were recorded on fue sampling data sheet for 

each traverse point location. Gas duct and stack temperatures were aritlnnetically averaged and used to 

calculate fue volumetric flow rates at standard and dry standard conditions. 

Moisture Determination 

The moisture content oftl1e stack gas was determined using procedures outlined in 40 CFR 60, Appendix 

A, Metl10d 4. Mefuod 4 sampling was incorporated into each sampling train. The moisture weight gain of 

tl1e chilled inlpingers was determined gravimetrically for each sampling train. 

Carbon Dioxide {C02) Determination (Instrumental Method) 

The C02 concentrations were sampled and determined using a dedicated non -dispersive infrared (NDIR) 

analyzer. The C02 sampling conformed to procedures presented in 40 CFR 60, Appendix A, Mefuod 3A. 

The C02 monitor was calibrated using EPA Protocol gases prior to and after fue completion of fue test run 

series. Zero and midJhigh point calibration bias checks were performed prior to the beginning and at fue 

completion of each test rm1 to ensure fue integrity of the sampling train system. The concentration of C02 

is reported in percentage of carbon dioxide (% C02) by volume on a dry basis. 

Access to fue gas stream was tlrrough a shared sample line. A heated and filtered stainless steel probe was 

nsed to extract the gas sample from fue ducts. A heated, 3/8" Teflon® line transported the sample from tl1e 

point of extraction to fue non-contact gas conditioning chiller system. The moisture was condensed and 

removed from fue gas stream, while fue pollutant passed furongh to fue analytical equipment.· The 

analyzer was located in a temperature-controlled area to mininlize thermal affects on fue calibration of the 

instrument. 

Oxygen (Oz) Determination (Instrumental Method) 

The 02 concentrations were sampled and determined using a paramagnetic 02 analyzer. The 02 sampling 

conformed to procedures presented in 40 CFR 60, Appendix A, Method 3A. The 0 2 monitor was 

calibrated using EPA Protocol gases prior to and after fue completion of fue test run series. Zero and 

mid/high point calibration bias checks were performed prior to fue beginning and at tl1e completion of 
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each test run to ensure the integrity of the sampling train system. The concentration of 0 2 is reported in 

percentage of m:ygen (% 0 2) by volume on a dry basis. 

Access to the gas stream was through a shared sample line. A heated and filtered stainless steel probe was 

used to extract the gas sample from the ducts. A heated, 3/8" Teflon® line transported the sample from the 

point of extraction to the non-contact gas conditioning chiller system. The moisture was condensed and 

removed from the gas stream, while the pollutant passed through to the analytical equipment. The 

analyzer was located in a temperature-controlled area to minimize thermal affects on the calibration of the 

instrmnent. 

Sulfur Dioxide (S02) Determination 

The gas stream was sampled separately for sulfur dioxide (S02) concentration using an ultraviolet S02 

gas analyzer. S02 sampling conformed to procedures presented in 40 CFR 60, Appendix A, Method 6C. 

Access to the stack was through a shared sample line. A heated and filtered stainless steel probe was used 

to extract the gas sample from the gas ducts at the required traverse points in accordance "~th 40 CFR 60, 

Appendix B, Performance Specification2. A heated, 3/8" Teflon® line transported the sample from the 

point of extraction to the non-contact gas conditioning chiller system. The moisture was condensed and 

removed from the gas stream, while the pollutant passed through to the analytical equipment. The 

analyzer was located in a temperature-controlled area to minimize thermal affects on the calibration of the 

instrument. 

The concentration and mass emissions of S02 in the gas stream are reported in the units of the appropriate 

standard. Concentrations were recorded in parts per million by volume (ppmv) on a dry basis. The 

emission rate was calculated using the specific run-time average concentration in ppmv, the dry standard 

volumetric flow rate, the Ideal Gas Law, and the sampling time. 

Nitrogen Oxides (NOx) Determination 

NOx sampling conformed to procedures presented in 40 CFR 60, Appendix A, Method 7E. Access to the 

gas stream was through a shared sample line. A heated and filtered stainless steel probe was used to 

extract the gas sample from the gas ducts. A heated, 3/8" Teflon® line transported the sample from the 

point of extraction to the non-contact gas conditioning chiller system. The moisture was condensed and 

removed from the gas stream, while the pollutant passes through to the analytical equipment. The 

analyzer was located in a temperature-controlled area to minimize thermal affects on the calibration of the 

instrmnent. 

The stack gases were sampled separately for oxides of nitrogen (NO,) concentrations using a 

chemiluminescent NO-NO, gas analyzer. The chemiluruinescent reaction of NO and ozone (03) takes 

place as follows: 

NO+ 0 3 ----'>- N02 + 0 2 + h, 

where h, = light 

As the electronically excited NO, molecules revert to their ground state, a photon particle (as light) is 

emitted. The NO gas sample concentration is blended with 0 3 in a reaction chamber. The resulting photon 

emission (chemiluminescence) is detected by in the optical filter by a highcsensitivity photomultiplier 

detector located at the end of the reaction chamber. The detector responds to light in a narrow-wavelength 

band m1ique to the above reaction. The output from the photomultiplier is linearly proportional to the NO 

concentration. 

To measure the total NOx concentrations as N02 (i.e., NO plus NO,), the sample gas flow passes through 

an N02-to-NO converter. The detector response in the reaction chamber to the converted effluent is 
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linearly proportional to the NOx concentration entering the converter. The instrument is operated in the 

NOx mode during all test and calibration and all resnlts are reported as N02. 

The concentration and mass emissions of NO, in the gas stream are reported in the m1its of the 

appropriate standard. Concentrations were recorded in parts per miiiion by volume (ppmv) on a dry basis. 

The emission rate was calculated using the specific nm tinle average concentration in ppmv, the dry 

standard volumetric flow rate, the Ideal Gas Law, and the sampling time. 

Sulfur Compound Sampling Procedures (Method SA) 

The gas stream was sampled for sulfur trioxide (S03) using an NCASI Method 8A sampling train. The 

sampling train coilected approximately 3 0 cubic feet of gas during each sampling nn1. The sampling train 

used in this method is sinlilar to the EPA Method 8, with several exceptions accounted for in the sample 

filtration method and the inlpinger reagents. The sampling train inlpingers were preceded by a heated 

sampling probe, a heated quartz filter holder, and a heated H2S04 condenser. 

The probe liner was constructed of quartz, which was heated using a controlled heating element to 

maintain the gas stream above the acid dew point, and encased in a 304 stainless steel jacket. The sample 

probe was collllected directly to a insulated sulfuric acid sampling box that contained a quartz filter holder 

and a 37-mm diameter quartz filter. The filter holder was maintained at temperatures greater than 500'F 

by a cylindrical heating mantle. 

The filter holder was then directly attached to tl1e H2S04 condenser. The condenser was a Modified 

Gral1am condenser, witl1 a Type C glass frit and 200 cm of 5-mm ID glass tubing for condenser coil. TI1e 

condenser was fiiled witl1 water and maintained at a temperature between 167 and 185'F with a 

cylindrical heating mantle. 

The condenser was attached to the four reagent impingers. The first two inlpingers contained 

approximately 100 m1 of a 3% peroxide solution to facilitate capture and retention of tl1e S03. The third 

inlpinger contained approximately 100 ml of distilled Dl water. The fourth impinger contained 

approximately 200 g of indicating silica gel as a final moisture trap. 

At the completion of each sample nn1 tl1e probe was discollllected from tl1e sample train. Clean dry 

ambient air was pulled through the train for 15 minutes. Mter the purge was completed tl1e sample train 

was recovered as follows: 

Container 1- The probe, quartz filter holder and tl1e H2S04 condenser were rinsed separately 

with deionized water using mnltiple rinse teclmiques described in Method 8A. The rinsate was 

collected in a clean sample jar, sealed with a Teflon lined lid, and sealed with Teflon tape. The 

sample was labeled and transferred to the onsite sample chemist for analysis per Metlwd 8A. 

Container 2- The inlpingers were externally dried and gravinletrically weighed to determine the 

moisture gain. The reagents in inlpingers one and two were volumetrically measured. The 

reagents were collected in a clean sample jar, sealed with a Teflon lined lid, and sealed with 

Teflon tape. The sample was labeled and transferred to the onsite sample chemist for analysis per 

Method 8A. 

Reagent blanks of tl1e peroxide solution were collected and analyzed per Method 8A. 

Particulate Matter Sampling Procedure 

The sampling for PM was performed using the sampling procedures described in 40 CFR 60, Appendix 

A, Methods 5. To measure the particulate emission rates, a slipstream was withdrawn isokinetically from 

tl1e stack. Particulate matter was coilected on a heated filter, and the stack gas moisture was collected in a 

series of chilled impingers containing water and silica gel to facilitate capture of the gas stream moisture. 
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The equipment used to perform the sampling has the approval, and meets the standards, of calibration 

accuracy as set forth by U.S. EPA. Copies of the calibrations are appended to this document. 

The sampling equipment consisted of three main units: the pmnp, control units, and sampling train. The 

pmnp was a lubricated fiber vane rotary pump altered for leak-free operation. The pump was cmmected to 

the controlm1it that contained a calibrated dry gas meter, dual incline manometers, and a calibrated 

orifice system designed to enable isokinetic sampling. The sampling train was cmmected to the control 

console by means of a flexible umbilical cord. The sampling train contained the inlpinger case, filter oven 

and probe. 

The nozzle was constructed of stainless steel and connected to the end of the probe with a stainless steel 

union. The probe was constructed with glass wrapped with a heating element and encased in a 304 

stainless steel tube. The heating element maintained the gas sample temperature inside the probe above 

the gaseous dew point preventing condensation of moisture in the probe. The probe was rigidly mounted 

to the filter heater box and directly connected to a heated glass filter holder tl1at contained a pre-weighed 

glass fiber filter supported with a Teflon® frit. The filter oven temperature was maintained between 225 

and 275 'F during tl1e tests. . 

The filter holder was cmmected directly to tile impinger train that contained a series of four ball top 

inlpingers in an ice bath. The inlpinger train was prepared by placing I 00 ml of distilled water in each of 

tl1e first and second impingers. The third inlpinger was initially empty. The fourtl1 impinger contained 

approximately 200 grams of indicating silica gel as a final moisture trap. The impinger train was· 

assembled in a dedicated clean area prior to being taken to the stack where the probe and filter were 

attached to the train. 

The stack sample was drawn isokinetically tlrrough the nozzle, the heated probe and into the heated filter 

assembly, where the particulate matter was collected on the pre-weighed filter. The gas sample stream 

then passed through the inlpinger train, which condensed the moisture from tile sample stream. The gas 

then passed through the umbilical cord to the dry gas meter, orifice and pump. 

The gas stream velocity and temperature were monitored at each sampling point to insure that isokinetic 

. sampling rates was being maintained. Leak checks were performed on the sampling train to insure the 

integrity of the sample collected prior to begirming the test and again at the conclusion of the test. 

At the conclusion of each particulate test, a recovery was conducted on the sampling train. The recovery 

procedure was as follo\vs: 

Probe Wasb - The nozzle, probe and front half of the ftlter holder were rinsed and brushed six 

tinles with acetone into a leak-free jar. The rinsate was subsequently placed ir1to a pre-weighed 

contair1er and evaporated to dryness. The container was then desiccated and weighed to a constant 

weight to the nearest 0.1 mg. 

Impingers- Each impinger was weighed separately to the nearest milligram to determine the 

moisture gain for the test. The contents and rinsate from these impingers were used in the analysis 

of CPM determination. 

Particulate Filter- The particulate filter was removed from the glass filter holder and placed 

back into its origir1al glass petri dish, then sealed with Teflon® tape. The filter was later placed 

into a desiccator and dried for 24 hours. The filter was then weighed to a constant weight to the 

nearest 0.1 mg. 

Blank Reagents -A sample of the acetone used in the train clean up was collected as a reagent 

blank The blank was analyzed in the same manner as the otl1er wash samples. 
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Condensable Particulate Matter Determination (Method 202) 

The CPM was collected in the impinger portion of Method 5 (Appendix A, 40 CFR 60) type sampling 

train. The impinger contents were immediately purged after the rm1 with nitrogen (N2) to remove 

dissolved sulfur dioxide (S02) gases from the impinger contents. The impinger solution was then 

extracted with methylene chloride. The organic and aqueous fractions were taken to df)11ess and the 

residues weighed. The total of both fractions represented the CPM. 

All sample recovery was performed at the test site IaboratOT)' by the test crew. All fmal particulate sample 

analyses were performed by the test team in accordance to USEPA Method 202, 40 CFR 51, Appendix 

M. Copies of all sample analysis sheets, explanations of nomenclature and calculations, and raw field data 

sheets are appended to tilis document. 

PM10 and PM2.5 Sampling Procedures 

The sampling for PMIO and PM2.5 was performed using the sampling procedures described in USEPA 

OTM 27. To measure the particulate emission rates, a slipstream was withdrawn at a constant rate from 

tile stack. Filterable particulate matter was collected in-stack with PMlO and PM2.5 cyclone heads, and 

the stack gas moisture was collected in a series of chilled impingers containing water and silica gel to 

facilitate capture of ti1e gas stream moisture. 

The sampling equipment consisted of three main units: ti1e pump, control milts, and sampling train. The 

pump was a lubricated fiber vane rotary pump altered for leak-free operation. The pump was coilllected to 

tile control unit that contained a calibrated dry gas meter, dual incline manometers, and a calibrated 

orifice system. The sampling train was cmmected to the control console by means of a flexible umbilical 

cord. The sampling train contained the impinger case, filter oven, probe and cyclones. 

The impinger train was prepared by placing l 00 nil of distilled water in each ofti1e frrst and second 

impingers. The third impinger was initially empty. The fourth impinger contained approximately 200 

grams of indicating silica gel as a fmal moisture trap. The impinger train, along with the cyclones were 

assembled in a dedicated clean area prior to being taken to the stack where ti1ey were connected to the 

probe. 

The stack sample was drawn at a constant rate tirrough a staiuless steel nozzle and PMlO cyclone head, 

which collected PM greater than 10 microns. The gas sample then passed through a stainless steel PM2.5 

cyclone, which collected PM less ilian 10 microns and greater ti1an 2.5 microns. Upon exiting the PM2.5 

cyclone, ti1e gas sample was dra\\~1 tirrough an in-line quartz-filter, which collected PM less than 2.5 

microns. The gas sample stream then passed through the impinger train, which condensed the moisture 

from the sample stream. The gas ti1en passed tlrrough the umbilical cord to ti1e dry gas meter, orifice and 

pump. 

The gas stream velocity and temperature were monitored at each sampling point. Leak checks were 

performed on ti1e sampling train to insure the integrity of the sample collected prior to beginning the test 

and again at ti1e conclusion of the test. 

At the conclusion of each particulate test, a recovery was conducted on the sampling train. The recovery 

procedure was as follows: 

Particulate Filter- The particulate filter was removed from the filter holder and placed back 

into its original glass petri dish, then sealed witi1 Teflon® tape. The filter was later placed into a 

desiccator and dried for 24 hours. The filter was then weighed to a constant weight to the nearest 

0.1 mg. 
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PMlO Cyclone- The particulate matter from the PMIO cyclone cup was removed and placed in 

a dedicated container. The nozzle, cyclone cup, and cyclone intemal snrfaces were then rinsed 

and bmshed with acetone into the dedicated container and sealed. The rinsate was subsequently 

placed into a pre-weighed container and evaporated to dr)~1ess. The container was then desiccated 

and weighed to a constant weight to the nearest 0.1mg. 

PM2.5 Cyclone- The particulate matter from the PM2.5 cyclone cup was removed and placed in 

a dedicated container. The cyclone tumarom1d cup, inside of the downcomer line, and cyclone 

intemal surfaces were then rinsed and brushed with acetone into the dedicated container and 

sealed. The rinsate was subsequently placed into a pre-weighed container and evaporated to 

~1ess. The container was tl1en desiccated and weighed to a constant weight to tl1e nearest 

0.1 mg. 

Particulate Filter Holder- The exit of the tube of the PM2.5 cyclone and the front half of the 

filter holder where rinsed and brushed with acetone into a dedicated container and sealed. The 

rinsate was subsequently placed into a pre-weighed container and evaporated to ~1ess. The 

container was then desiccated and weighed to a constant weight to tl1e nearest 0.1 mg. 

Impingers- Each impinger was weighed separately to tl1e nearest milligram to determine the 

moisture gain for the test The contents from these inlpingers were discarded at tl1e conclusion of 

the recovery process. 

Blank Reagents -A sample of the acetone used in the train clean up was collected as a reagent 

blank. The blank was analyzed in tlw same mamwr as the other wash samples. 

HF, HCI, and Cl 2 Sampling Procedures 

The HF, HCl and CJ, sampling was performed using the sampling procedures described in 40 CFR 60, 

Method 26A. The equipment has tlw approval, and meets the standards, of calibration accuracy as set 

forth by U.S. EPA. The sampling equipment consisted of three main llllits: tl1e pump, controlllllits, and 

sampling train. The pump was a Teflon® coated rotary pump connected to tl1e controlm1it that contained 

a calibrated dry gas meter, heat controllers and sampling rate flow controllers. The sampling train, which 

contained the impinger case, filter oven and probe, was co1mected to the control console by means of a 

flexible umbilical cord. 

The probe was constructed with a glass tube wrapped w~th a heating element encased in a 304 stainless 

steel tube. The heating element maintained the gas sample temperature inside the probe above the gaseous 

dew point preventing condensation of moisture in the probe. The probe was rigidly mollllted to tl1e 

inlpinger box and directly connected to a heated Teflon® filter holder, which contained a quartz filter. 

The filter oven temperature was maintained between 225 and 275 °F during the tests. 

The impinger train was prepared by leaving the f'rrst impinger empty and placing 100 ml of 0.1N sulfuric 

acid into tl1e second and third impingers. The fourth and fifth impingers contained 100 ml of sodium 

hydroxide. Impinger six contained indicating silica gel as a final moisture trap. All fittings were ground 

glass to glass with Viton o-rings to prevent leakage. At tl1e beginning and end of each test rm1 a leak 

check was performed on the entire test train to insure tl1e integrity of the sample collected. 

At the conclusion of each test, a recover was conducted on the sampling train. The recover procedure was 

as follows: 

Impingers -The impinger train were weighed separately to the nearest milligram to determine 

the moisture gain for the test The contents of impingers one tlrrongh tlrree were transferred into a 

glass storage container and rinsed witl1 DI water. The rinse was added into the sample container. 

The contents of impingers four and five were transferred into a sample container rinsed with DI 
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water. The rinse was added into the sample container. The silica gel impinger was weighed for 

moisture gain determination and the contents were then discarded. 

Blank reagents -A sample of the sulfuric acid and sodimn hydroxide absorbing solutions used in 

the impingers were collected and analyzed in the same manner as the aetna! stack samples. 

At the conclusion of the fieldwork, the samples were delivered to an offsite laboratory for subsequent 

analysis. 

Multi-Metals Sampling Procedures 

During the test, the stack emissions were sampled and analyzed for the multiply metals. The sampling 

procedures implemented followed 40 CFR 60, Appendix A, Method 29. 

The sampling train was based on the standard EPA Method 5 configuration with modifications to the 

sampling reagents placed in the impingers and the use of a glass nozzle. The stack gas was isokinetically 

extracted from the stack and pulled through a heated probe and filter assembly. The filtered gas passed 

through the impinger train consisting of four impingers. The first and second impingers each contained a 

100 ml mixture of 5% HN03 and 10% H20 2 solution. The third impinger remained empty as a moisture 

knockout. The fourth impinger contained 200 grams of indicating' silica geL The impinger section of the 

train was assembled in a dedicated clean area prior to being taken to the stack where the filter and probe 

were attached to the trains. All fittings were grom1d glass to glass to prevent leakage. Leak checks were 

performed on the sampling train at the begim1ing and end of each test run. 

At the conclusion of each MMT test, the probe and filter holder were removed and sealed with Teflon® 

tape. The test train components were retnmed to the clean room for disassembly. The clean -up procedures 

were as follo\vs: 

Probe Wash- The nozzle, probe and front half of the filter holder were rinsed and brushed three 

times with acetone, then rinsed with 0.1N HN03 into a leak-free jar. The rinsates were 

subsequently placed into sample collection jars. 

Impingers- each impinger was weighed separately to the nearest 0.1 gram to determine the 

moisture gain for the test. The liquid contents of the impingers were transferred to separate 

sample containers, labeled and logged into the sample collection records. After transferring tl1e 

contents of each impinger, they were rinsed along with all connecting glassware with 0.1N nitric 

acid. The rinsate was collected into a separate sample container. 

Particulate Filter- The particulate filter was removed from the glass filter holder and placed 

back into its original glass petri dish, tl1en sealed with Teflon® tape. 

Blank reagents- Samples of the impinger reagents and cleaning solutions used in the MMT 

train were collected as reagent blanks for the performance test runs. 

Total Mercury, Elemental Mercury, Oxidized Mercury Sampling Procedures 

Sampling for elemental mercury Hg0

, oxidized mercury Hg2

+ and total mercury was performed in 

accordance with the "Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury 

in Flue Gas Generated from Coal-Fired Stationary Sources (The Ontario Hydro Method)", ASTM D6784-

02. This method is applicable to the det=ination of elemental mercury Hg0

, oxidized mercury Hg2

+, and 

total mercury emissions from stationary sources. 

The probe was constrocted with a glass tube wrapped "~th a heating element encased in a 304 stainless 

steel tube. The heating element maintained the gas sample temperature inside the probe above tlte gaseous 

dew point preventing condensation of moisture in tl1e probe. The probe was rigidly monnted to the 

impinger box and directly cmmected to a heated Teflon® filter holder, which contained a quartz filter. 

The filter oven temperature was maintained between 250°F and 275°F during the tests. 
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A sample was drawn at a constant rate from ti1e flne gas stream through a heated (maintained@ 248°F) 

probe/filter system, followed by a series of impingers located in an ice bath. The oxidized mercury was 

collected in the first set of impingers containing chilled aqueous potassium chloride (KCl) solution. The 

elemental mercury was collected in subsequent impingers (one containing chilled aqueous acidic solution 

of hydrogen peroxide and tirree impingers containing chilled acidic solutions of potassium 

permanganate ). 

The OH train samples were collected as follows: 

• Mter sampling was completed, ilie sample train was leak-checked, dismantled, sealed with 

Teflon tape and transported to the sample recovery area. 

• The particulate filter was removed from ti1e filter bell, placed into ti1e original petri dish, sealed 

witi1 Teflon tape, and placed in a plastic bag. No analysis was conducted on the filter. 

• The intemal surfaces of ti1e probe and front half of the filter bell were cleaned by rinsing and 

brushing drree times witi1 a 0.1N HN03 rinse. The sample was collected in an amber sample jar 

and sealed with a Teflon lid and Teflon tape. 

• The contents ofimpingers one, two, and tirree were weighed to the nearest 0.5 gram to determine 

moisture gain. Small amounts (I ml increments) of 5% KMn04 solution were added to each of 

ti1e tlrree KCl impingers. The KMn04 addition was continued m1til a purple color was maintained 

in ilie inlpingers. The contents were composited in a common sample container. Each impinger, 

and all connecting glassware, was rinsed with 10% HN03, and the rinsate was added to ti1e 

composite sample container. Small amounts of 5% KMn04 solution were added to the sample 

composite until a purple color was maintained. The sample was collected in an amber sample jar 

and sealed wifu a Teflon lid and Teflon tape. 

• The contents of impingers four and five were weighed to the nearest 0.5 gram to determine 

moisture gain. The contents were ti1en placed in a dedicated sample container. These impingers 

were fuen rinsed wiili 0.1N HN03 and incorporated into fue sample container. The composite 

sample was collected in an amber sample jar and sealed with a Teflon lid and Teflon tape. 

• Impingers six, seven, and eight were weighed to the nearest 0.5 gram to determine moisture gain. 

The contents were composited in a co=on sample container. The impingers were rinsed twice 

with 0.1N HN03, and once with 0.1N HN03 mixed with a few drops oflO% hydrm.:ylamine 

solution to remove residual KMn04 solution. 

• The rinsates and solutions were collected in an amber sample jar and sealed witi1 a Teflon lid and 

Teflon tape. Impinger nine was weighed to ti1e nearest 0.5 gram to determine moisture gain. The 

spent indicating silica gel was then placed in an appropriate container for transport back to the 

equipment staging area. No analysis was conducted on fue silica gel. 

• Quality control samples for ilie OR trains consisted of blanks for ilie filter, water, and all sample 

and recovery reagents used in the sample train. 

Because of fue highly quantitative aspect of the mercury analysis, special precautions were taken to avoid 

potential sample contamination. All key glassware components were ilioroughly washed, rinsed \\~ili 01 

water and ilien soaked in a 10% nitric acid solution for four hours prior to ilie test program. All liquid 

samples were placed into acid washed glass bottles equipped wifu Teflon-lined caps. 
Electronic Filing - Received, Clerk's Office, 08/15/2012 

;;; worid f Sofutior~s 

Equipment Calibration 

Equipment Calibration Overview 

Proper equipment calibration is essential in maintaining the desired data quality leveL All calibrations of 

the equipment nsed in the stack sampling portion of the testing conformed to the guidelines outlined in 

the EPA quality assurance handbook, Quality Assurance Handbook for Air Pollution Measurement 

Systems, Volume III, Stationary Source Specific Methods (EPA/600/R-94/038c). The following sections 

give a synopsis of the calibration procedures for the main components of the stack sampling systems. 

Calibration Procedures 

Dry Gas Meters/Orifice Meters 

The dry gas meters and orifice meters in each control box used during the testing were calibrated 

before the test in order to ensure accurate measurements of the sample gas volUilles. The dry gas 

meters and orifice meters are normally housed as a set inside each control box and were 

calibrated as such. These sets of meters were calibrated against a primary calibration standard, a 

spirometer. 

The dry gas meter/orifice meter sets were calibrated at predetermined nominal volume flow 

settings. For each of these flow rates, au accuracy ratio factor to the calibration standard (Yi) was 

computed for the indi>~dual dry gas meters. A successful calibration for a particular dry gas meter 

would be achieved if each value of Yi was "~thin 2 percent of the average value of Yi (Yi ~ Y 

±0.02Y). 

In order to establish calibration for the orifice meter, a calibration coefficient ( H@I) was 

calculated for each flow rate. This coefficient is the orifice pressure differential (in inches H20) 

at a distinct orifice manometer setting that gives a flow of 0.75 ft3/min of air at standard 

conditions. The desired tolerance for this coefficient is ±0.2 of the average value of the four 

values of H@I ( H@ ±0.2). If any of the pre-test calibration coefficients for a particular meter 

'~olated the acceptance criteria, the meter in question would be adjusted and recalibrated. 

Thermocouples and Thermocouple Readouts 

All thermocouples used during the stack sampling tests were calibrated to ensure accurate 

temperatnre measurements. All of the sensors utilized were type "K" thermocouples, which have 

a working range of approximately -300 °F to approximately 2500 °F. These sensors were used in 

the measurement of stack gas temperature, organics trap temperature, probe sheath temperature, 

filter box temperature, and impinger temperature. The thermocouples were calibrated against au 

NJST traceable mercury-in-glass th=ometer at predetermined temperatures. h1 order to obtain 

the calibration data from each sensor a single, recently calibrated thermocouple readout was used. 

The tl1ermocouple readouts used during tl1e testing were calibrated using a thermocouple 

simulator. This calibration apparatus generates a voltage signal that mimics tl1e signal au ideal 

"K" type thermocouple would exhibit at a particular temperature. The signal can be changed via a 

slide switch. The readouts were calibrated at ten different points from 200°F through 2000°F, at 

increments of 200°F. 

Barometer 

The field barometer used during the test was an aneroid type barometer. This barometer was 

calibrated by comparing it to a standard mercury colu11111 barometer and adjusting it if any 

deviation existed between it and the standard. This exercise was performed both before and after 

the testing activities. 
Electronic Filing- Received, Clerk's Office, 08/15/2012 

Analytical Balance 

The field analytical balance was calibrated before the test with certified standard weights_ The 

balance was adjusted for any deviation from the standard weights_ In the field, periodic checks 

were made to insure data validity. This balance was used to measure the impinger weight changes 

due to moisture gain during the stack sampling (determination of stack moisture content). 

Pitot Tubes 

The S-type Pilot tubes used on each isokinetic sampling train were calibrated based on geometric 

considerations_ The basis for the calibration is described in 40 CFR, Part 60, Appendix A, 

Method2. 

Continuous Emission Monitors 

Quality control procedures to be implemented during the testing included three-point calibrations, 

calibration drift tests, bias tests, and response time tests for each CEM monitor. A three-point 

calibration was conducted daily before and after each test burn run. These calibrations consisted 

of introducing pre-purified nitrogen as a zero gas and three kno·wn concentrations of each specific 

gas to the appropriate analyzer. EPA Protocol! calibration gases were used to perform these 

calibrations. Bias checks were also performed as part ofthe monitor calibrations. These checks 

were performed by introducing calibration gas at the point of sample extraction on the stack Tltis 

allowed calibration gases to travel through each complete monitoring system. 

Response time tests were performed in conjunction with the bias checks. Alternating the 

introduction of span and zero calibration gas during the bias checks three times and recording the 

time required for the monitor to reach 95 percent of the fmal stable value enabled the 

determination of mean upscale and downscale response times. 

Zero and calibration drift was also determined during each run of the tests. This was 

accomplished by comparing zero and upscale calibrations from before and after a test run.