### 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 Advatech 6 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&M 1 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 ofRx.&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&M 1**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 

## iReACT 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 forJoppa**stat!~**

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

! Fint Year 

### : Tot.ll Capital Pint Veur Fixed Requb-emeot1 'Fixed0&M 1 Altenutive Chtrgea.• SlOOO 

## I I!kW SlOOO $10(10 C(lst fegrBtJSJ.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 PimYear and: Tota1 Levcliz.ed dollm l.!. sum ofFixed 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 huedon 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 Baselineprogram.................
................. .................. 14 3.1.2 Trona, Un-milled Upstream of the AirHeater..

................. ..15 3.1.3 Trona, Milled Upstream of theAir heater....

................... 17 3.1.4 Trona, MilledDownstream of the AirHeater......................

............... . 19 3.1.5 Sodium Bicarbonate Downstream of the AirHeater.

......... ......... ... 20 3.1.6 Sodium Bicarbonate Upstream of the AirHeater Testing....

.................................................... 21 3.1. 7 Sodium Bicarbonate Downstream of the AirHeater Parametric Testing

.................... 22 3.1.8 Sodium Bicarbonate Downstream of the AirHeater Units 5 and 6 Steady State Testing

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

...... 24 3.1.10 Comparison of Certain Metals Emissions, DwingBaseline andSBCInjection..........

.. ... 26 3.1.11 Comparison of Acid Gas Emissions, DuringBaseline andSBC Injection..........

.. ............ 26 3.1.12 DSIImpacts 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 DSIat Joppa........

................... .......... ..... .............. . ................... 37 3.4.2 Air Permit Considerations..........

............... ..................... .. ................. 37 3.4.3 ESP Upgrade Considemtions....

........... .................... . 42 3.4.4 B)productHandling andLancifil/ 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 MatterData

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

............................................................................. 15 Table 3-5

- Smnmary S02 Data, Un-milled Trona Injection Upstream ofAir Heater

............................ 17 Table 3-6

- Smmnary Particulate Matter Data, Un-milled Trona Injection Upstream ofAir Heater..

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

....... 17 Table 3-8- Smnmary S02 Data, Milled Trona Injection Upstream ofAir Heater.

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

.......... 18 Table 3-10- Summary Mercury (Total) Data, Milled Trona Injection Upstream ofAir Heater

............ 19 Table 3-11 -Summary S02 Data, Milled Trona Injection Downstream ofAir Heater.

.......................... 20 Table 3-12- Summary S02 Data, SBC Injection Downstream ofAir Heater..

....................................... 21 Table 3-13

- Smmnary S02 Data, SBC Injection Upstream ofAir Heater

............................................. 21 Table 3-14- Smmnary Particulate Matter Data, SBC Injection Upstream ofAir Heater

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

........................ 22 Table 3-16- Smnmary S02 Data, SBC Injection Downstream ofAir Heater.

........................................ 23 Table 3-17

- Summary S02 Data, SBC Injection Downstream ofAir Heater..

....................................... 24 Table 3-18

- Smmnary S02 Data, SBC Injection Downstream ofAir Heater..

....................................... 25 Table 3-19

- Summary Particulate Matter Data, SBC Injection Downstream ofAir Heater

.................. 25 Table 3-20

- Smnmary Mercury (Total) Data, SBC Injection Downstream ofAir Heater

..................... 26 Table 3-21

- Comparison ofAcid Gas Emissions

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

........................................................................... 29 Table 3-23 -Comparison ofTotal Particulate Emissions

........................................................................ 31 Table 3-24- Review ofAverage 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 ofConcepts for Existing Generic Cold-Side ESP Upgrades

......................... 44 Table 3-29- Estimated Annual Cost ofDry 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 ofS0 2 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 ofTeam 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'+ HN0 3 H 20 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 ofFederal 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 NH 3 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 ofthe existing electrostatic precipitators (ESP)s would be successful in removing 50% or more ofthe S02 in the gas stream without detrimentally impacting the operation ofthe ESPs and fly ash handling system.
The scope ofwork 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 ofa dry sorbent will impact the level ofacid gases and heavy metals in the flue gas; • whether there is an impact to the air heaters ifthe selected DSI point was located upstream ofthe air heaters;
• whether there is an impact to the ESP from either DSI reagent
• whether there is an impact to the operation ofthe 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 ofthe 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 werejudged necessary given data as it was reviewed, or in some cases changes were made because it wasjudged 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 S0 2 

### 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 ofdry 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 ofTrona 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 ofabout 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 ofdry sorbent) ifinjection 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 ofa 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 ofthe 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 ofthe 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 runoffpH will likely be high enough to require neutralization ofthe landfill pond runoffprior 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 runoffpotential to a point impacting its discharge permit and potentially the landfill integrity over the life ofthe 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 ofthe 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 ofTrona 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 of0.90 2. The data for milled Trona injection after the air heater is minimal. This utilization rate achieved an average of42.6% 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 of67% 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 ofparticulate control upgrades for DSI options
o 

### Evaluate unmilled 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 ofan 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 ofthe 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
Ifthe use ofDSI at Joppa is still viable after the review ofESP efficiency upgrades, then additional testing is warranted that would include: o 

### Prolonged injection ofeach reagent upstream ofthe 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 ofthe existing electrostatic precipitators (ESP)s would be successful in removing 50% or more ofthe S0 2 

### in the gas stream without detrimentally impacting the operation ofthe ESPs and fly ash handling system.
The scope ofwork developedjointly 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 ofparametric 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 (ifupstream ofthe 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 ofthe fly ash handling system, and;
• whether there are any issues in the handling ofDSI 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 ofthe 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 S0 3 injection systems for flue gas conditioning (fly ash resistivity treatment) and activated carbon injection systems for mercury removaL (The S0 3 injection system was not active during this test program.) 

### 1.2 Division ofResponsibility 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 IEPA
• 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 ofbyproduct 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 ofreagents • Provide consultation on use ofreagents

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 ofDSI 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 ofoverall operation on plant equipment and infrastructure.
The conduct ofthe study as it was perfonned over portions ofthree weeks is shown in Table 2-1. Some changes were made from the original design as the program progressed in the field. Changes werejudged 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 oftwo parallel ducts (Duct A & 

### B) each with a cross sectional area of

### 230 square feet at the sampling location.
• ESP Inlet- consisted oftwo parallel ducts (Duct A & 

### B) each with a cross sectional area of

### 23 0 square feet at the sampling location.
• ESP Outlet- consisted oftwo parallel ducts (Duct A & 

### B) each with a cross sectional area of25 0 

### square feet at the sampling location.
• Common #3 Tall Stack- single annular stack with an 18 foot diameter at the sampling location.
Selection ofthe 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 ofeach sampling location.

3ElectronicFiling-Received,Clerk'sOffice,08/15/2012ElectricEnergy,Inc,JoppaGeneratingStationJoppa,Illinoismobilization,SetupinjectionandtestJune4IIIBaselinetesting.F1idayJune512IBaselinetesting.SaturdayJune713IUn-milledTronaMondaymJectwnJune84MilledTronaTuesdayinjectionJune9,5MilledTronaWednesdayInjection.I::J.SHaw·nml:hwvNANoneINAINoneIUpsh·eamofITronaairheaterUpsh·eamofTronaairheaterDown-Tronastreamofairheater4DraftFinalReportDrySorbentInjectionTestProgramTworuns.Unit6.CEMsin/out;TestcoalIlbOHMin/out;PMin/out;stack-S02/MMBtu. 5lbOHM,TM29,TM26A,TM8A;AC/Macf.NoDSI.NoTM30B.Coal.--ITworuns.Unit6.CEMsin/out;OHMin/out;PMin/out;stackOHM,TM29,TM26A,TM8A;TM30B.-ITiweeruns.CEMsin/out;Determineun-milledOHMin/ant;PMin/out.Tronainjectionratefor50%reduction.Threeruns.CEMsin/out;DeterminemilledTronaOHMin/out;PMin/out.injectionratefor50%reductioMorningruns.CEMs(only)DeterminemilledTronain/outinjectionratefor50%reduction.Onsitemilling.ElectronicFiling-Received,Clerk'sOffice,08/15/2012ElectricEnergy,Inc,JoppaGeneratingStationJoppa,IllinoisinjectionJlme1016IPre-milledSBCJune11,17IPre-milledSBCFridayinjectionJune14,18IPre-milledSBCMondaymJeCttonJ1me1519IPre-milledSBCTuesdayinjectionJm1e16,IWednesdayITestingterminatedduetoUnit5tubeleakStiiiiw'l!wa-QIT)\jf)IstreamofairIheaterIUpstreamofSBCairheaterIAfterairSBCheaterIAfterairheaterISBCIAfterairSBCheaterII5DraftFinalReportDrySorbentInjectionTestProgramDetermineSBCinjectionIin/outIratefor50%reductionThree nms.CEMsin/out;DetermineSBCinjectionOHMin/out;PMin/out.ratefor50%reduction.Units5 &6.Threeruns.CEMsParametricstudyto(only)in/outdetermineS02reductionatvaryingfeedrates.Units5 &6.Threemns.CEMsDetermineSBCinjection(only)in/out(stackCEMs)ratefor50%reduction,twounit·Three nms.Unit5&6.CEMsin/out;OHMin/out;PMin/out;stack-OHM,TM29,TM26A,TMSA;TM30B.TMSand202;Coal,ash,byproduct(5x 5Igallons}.

### 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 Na2

### C0 3 

### .NaHC03 

### .2H2

### 0. The rock is typically milled and delivered at a fineness of30- 35 microns. Typical moisture ofdelivered 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 ofTrona 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 of26 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 SOLVAIR SELECT 350 HNM BULK (Solvay Material Code 65591) also known as SOLVAIR 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 ofthe delivered SBC had clumps ofmaterial 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 ofmaterials. 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 ofmaterial. 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 ofthe 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 ofproviding 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, cutoffends. 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 Ayr. 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 ofthe daily samples ofthe coals. It should be noted that for coal utilization, the sample was taken near the end ofthat day's testing.·

8ElectricEnergy,Inc,JoppaGeneratingStationJoppa,IllinoisRanch,612110I8420I5.96IJacobsI6/3/10IRanch9150I6.79IJacobsI6/4/10IRanch8420I5.85IJacobsI6/5/10I8370I5.5ILC11I6/6/1087105.64Jacobs[617110Ranch86305.7JacobsI6/8/10IRanch7840I5.17IJacobsI6/9/10IRanch8390I6IJacobs6/10/10I8470I5.63IchJacobs6111110I8430I5.79IRanchComb-I6/12/HlImatwn?8390I5.02IBelleAyrI6113/JoI8380I5.04IElectronicFiling-Received,Clerk'sOffice,08/15/201214.16I0.48I1.14I0.02I3.0II302I<114.84I0.49I1.07I0.02I2.48I307I<I13.90Io.sI1.19I0.01I<2I308I<I13.14I0.48I1.150.02<2315<I12.950.441.010.02<2300<I13.210.491.14O.Dl2.21344<113.19Io.35I0.89I0.01I<2I377I<I14:30I0.43I1.03I0.02I<2I321I<113.29I0.45I1.06I0.02I<2I311I<I13.74I0.45I1.07I0.02I<2I330I<I11.97I0.36I0.86I<0.01I<2I307I<I12.03Io.24I0.57I<o.o1I<2I355I<I9DraftFinalReportDrySorbentInjectionTestProgramI6.65I3.16I<2I1.5I0.129I15.32I6.5I2.43I<2I1.5I0.097II0.60I6.21I2.14I<2I1.49I0.098I11.646.03.2<21.470.09911.835.911.65<21.80.11112.745.922.29<21.680.0819.39I6.54I2.61I<2I!.59I0.131I16.71I6.38I2.27I<2I1.46I0.103I12.28I6.24I2.72I<2I1.27I0.113I13.34I5.9I2.49I<2I1.7I0.164I19.45I5.52I2.05I<2I1.42I0.151I18.00I4.94I!.66I<2I1.4I0.085I10.14ElectricEnergy,Inc,JoppaGeneratingStationJoppa,lllinois6/1411083506/1511085105.114.59JacobsII8483I5.80IRanchBelleII8413I4.91IAyrPercentBelleAyrofII99.18I84.7IJacobs6SliaW#IlmlhwElectronicFiling-Received,Clerk'sOffice,08/15/201212.240.230.5510.790.260.6113.67I0.46I1.0711.69I0.24I0.5885.5I53.4I53.840.02<2319<10.01<2295<1I0.011I<2.17I322I<1I<0.013I<2I323I<14.634.31DraftFinalReportDrySorbentInjectionTestProgram1.72<21.62Io.083I9.942.19<21.42I0.071I8.34I6.23I2.50I<2I1.55I0.113I13.27I4.63I1.86I<2I1.48I0.080I9.47I76.47I92.2I1oo.sI100I74.3I74.4I100I95.7I70.75171.3410

### 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 ofthe SBC in the bulk delivery vehicles. Trona was injected both upstream (un-milled and milled) and downstream (milled) ofthe air heater (AH). SBC was also injected both upstream and downstream ofthe air heater. The feed rates ofthe 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 ofthe 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 ofthe silo feeding event..

11ElectricEnergy,Inc,JoppaGeneratingStationJoppa,Illinois4-JunII5-JunIIII7-JunIII12:ooI7-JunI2I15:15I7-JunI3I18:00I8-Jun19:458-Jun212:298-JmtI3I15:21I9-Jllll110:529-Jun215:2710-Jun110:0010-Jmt212:45'!1)0Sl\'ffl"ElectronicFiling-Received,Clerk'sOffice,08/15/2012INoneINAINoneNA13:ooIUnmilledBeforeairheaterTrona-Unit'17:ooIUnmilledBeforeairheaterITrona-Unit618:34IUnmilledBeforeairheater'T'rona-Unit610:47MilledTronaBeforeairheaterTL13:35MilledTronaBeforeu.u.u.......u......_I-Unit616:21IM"lld TIBeforeairheaterIIerona-Unit612:31MilledTronaAfterairheaterI-Unit"16:00Pre-milledAfterairheaterISBC-Unit611:03Pre-milled_,UV-.VLISBC-Unit613:50Pre-milledBeforeairheaterICODE'-Unit612NANA5,97111,65910,2198,8388,5618,68814,23711,6437,7337,275DraftFinalReportDrySorbentInjectionTestProgramBaselineTestingBaselineTestingElectricEnergy,Inc,JoppaGeneratingStationJoppa,Illinois10-JunI3I15:2011-JunIII11:2311-JunI2I12:1411-JunI3I16:1414-JunIII9:5314-JtmI2I13:0515-JmtIII8:5015-JunI2I12:1515-JmtI3I14:59l:l.Snaw•·nmt>rK•wGIIl<+>IIIIIIIIIElectronicFiling-Received,Clerk'sOffice,08/15/201216:27I_I_J.V-.l.l.U.l_I_VY-BeforeairheaterI-Unit6II:52IPre-milledAfterairheater-ISBCUnits5and613:31IPre-milledAfterairheater-SBCUnits5and617:31IPre-milledAfterairheater-SBCUnits5and612:38IPre-milledAfterairheater-SBCUnits5and617:07IPre-milledAfterairheater-SBCUnits5and69:50IPre-milledAfterairheater-SBCUnits5and613:33IPre-milledAfterairheater-Units5and616:08IPre-milledAfterairheater-SBCUnits5and6136,9215,88211,07714,6659,2849,68310,2009,95610,438DraftFinalReportD1ySorbentInjectionTestProgramSBCaddedtosiloduringtest,usageestimateswerebasedonfeedvalvespeedaddedtosiloduringtest,usageestimateswerebasedonfeedvalvespeedSBCaddedtosiloduringtest,usageestnnato;swerebasedonfeedvalvespSBCaddedtosiloduringtest,usageestnnateswerebasedonfeedvalve

### 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 ofair emissions test data. Details ofthe 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 S0 3, is also used to increase the conductivity offly ash for removal in ESPs. Trona would also remove the S0 3 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 ofthe DSI Test Program, PAC was injected upstream ofthe 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 ofthe 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 ofthe 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 S0 3 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 ofnon-uniformed sampling in the duct due to stratification ofthe flue gas path. Because ofthis 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 offour 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 offour runs taken over two days for #3 Tall Stack (units 5 and 6). Data indicate overall removal efficiency of93 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 ofthis program segment was to document emissions and plant operating characteristics injecting un-milled (D50 of39 microns) (not milled on site) Trona upstream ofthe 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 S0 2 

### /MMBtu content. During the performance ofthe tests one ofthe 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/halffor that period oftime.
Attachment 3 shows the arrangement ofthe NolTec injection equipment and lances into the plant ductwork.
In accordance with the test program 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 (PM 10 

### 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 S0 2 

### concentration in the stack before and after DSI with one halfofthe 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 

## " 

# "" 0 N 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 ofthree 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 ofthree 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 ofthis 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 ofthe 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 (PM 10 

### 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 S02concentration before DSI was estimated based on the S02 

### concentration in the stack before and after DSI with one half ofthe S02assumed 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 of0.10 1b S02removed 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 ofthree 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 ofthree 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 ofthis program segment was to document the S02 

### emissions and plant operating characteristics injecting milled (D50 of26 microns) (milled on site) Trona downstream ofthe 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 S0 2 

### /MMBtu content.
Attachment 3 shows the arrangement ofthe 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 ofthe S02 

### assumed to come from Unit 6. The values presented are from the morning
run. The values indicate an average removal efficiency of42.6 percent and with an efficiency ratio of0.049 lb S02 

### removed per lb of sorbent injected. The ratio shows this scenario, injecting downstream ofthe AH, to be the least efficient ofthe 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 ofthe flue gas. Thus no additional parameters were sampled. This was a CEMs onlytest. 

### 3.1.5 Sodium Bicarbonate Downstream of the Air Heater The purpose ofthis program segment was to document the S02 

### emissions and plant operating characteristics injecting SBC downstream ofthe 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 ofthe 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 S0 2 

### concentration before DSI was estimated based on the S02 

### concentration in the stack before and after DSI with. one half ofthe S02 

### assumed to come from Unit 6. The results indicate an overall removal efficiency of 60 percent and with an efficiency ratio of0.084 lb S0 2 

### 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 ofthis program segment was to document emissions and plant operating characteristics injecting SBC upstream ofthe 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 ofthe 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 (PM 10 

### 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 halfofthe 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 ofthree 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 ofthree 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 ofthis program segment was to document emissions and plant operating characteristics injecting SBC downstream ofthe 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 ofthe 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 ofthe 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 S0 2 

### 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 of0.121 

### lb S02 

### removed per lb of sorbent injected at 50% S02 removal.

Average S02 Before DS Injection test
Lb S02

### Removed!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 ofthis program segment was to document emissions and plant operating characteristics injecting SBC downstream ofthe 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 ofthe ESPs were impacted by the combination ofthe Belle Ayr coal and the SBC injection with lower power levels and an initial increase of4- 5% in opacity. This spike stabilized and the opacity trended down as the tests continued.
Attachment 3 shows the arrangement ofthe 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 S0 2 

### 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 ofthis program segment was to to continue to document emissions and plant operating characteristics injecting SBC downstream ofthe 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 ofUnits 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 ofthe 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 of54.7 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 withjust Unit 6 in operation with ao average feed rate for Unit 6 of4,950 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 ofthree 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 ofthree 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 ofthe 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 oftesting. Different coals were burned between the two test days. Table 2-3 shows the analyses ofthe two coals during the test period

.. From a visual review ofthe 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 ofnickel 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 oftesting. 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 ofchlorine and the same or higher concentrations offluorine, a minimum ofabout 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 ofDSI 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 ofthe amonnt of S02 removed against the amount and type ofDSI was made to delineate the utilization efficiency of each ofthe dry sorbents used. Since the S02 concentration in the flue gas varied with time over the test runs a comparison ofthe 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 ofthe SBC had clumped together resulting in nnloading problems. This clumping may be indicative ofa 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 ofthe 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% S02removal 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 ofdry 

### sorbent versus 0.100 lbs S02 removed per lb ofdry 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 ofdry 

### sorbent respectively) when injected before the air heater
• The injection location (whetber before or after the air heater) impacts tbe efficiency ofTrona 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 ofabout 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

28ElectronicFiling-Received,Clerk'sOffice,08/15/2012ElectricEnergy,Inc,JoppaGeneratingStationJoppa,Illinois7-JtmI8:45-18:35IUnmilledTrona8-JtmI9:10-16:40IMilledTrona9-JnnI8:50-12:30IMilledTrona9-JnnI14:40-16:00I10-JunI8:30-16:55I11-JunI9:10-19:35I14-JunI10:00-24:00I5-6:25-4:55Pre-milled16-Jtm(6-16)SBC16-Jtm5:35-6:30Pre-milledtlht\lSilfWI!Beforeairheater-1Unit6Beforeairheater-IUnit6Afterairheater-IUnit6Afterairheater-Unit6Beforeairheater-Unit6Afterairheater-IUnits5and6Afterairheater-IUnits5and6Afterairheater-IUnits5and6Afterairheater-ITT.,/3,000->13,000I8,600+/-I14,493I11,750I7,380I3,500-16,000I9,980I9,960I4,950I2913-5952.642.66067.116-5354.754.752.9DraftFinalReportDrySorbentInjectionTestProgramI0.093@50%so2removalI0.100.049I0.84I0.158I0.121@50%so2removalI0.112I0.113I0.109ElectricEnergy,Inc,JoppaGeneratingStationJoppa,Illinois,........,fw"'"'...0:!l"a..,"""'....0V).0_,aSnaw'n\IJSlWIr!ill'..w1rx:·0.30.250.2.0.150.10.050ElectronicFiling-Received,Clerk'sOffice,08/15/2012SodiumBicarbonateUtilizationRateInjectionAfterAirHeater•·'II'DraftFinalRep01tDrySorbentInjectionTestProgramfl'0.22380.00%10,00%20,00%30.00%40.00%50.00%60,00%70,00%80,00%Percent502RemovalFigm·e3-3-Efficiencyof802RemovalUsingSBCAfterTheAit·heater30

### 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 ofthe 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 of295 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 thetype ofparticulate 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

### 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

6/5/10 Base Test NA NA 81.32 13.48 67.84 17

Un- Upstream 6/7/10 milled 8,502 ofAir 84.7 5.14 79.56 13.63 Trona Heater

6/8/10 Milled Trona 8,696 Upstream ofair 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 offine 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 ofun-milled Trona which had the largest particle size ofall ofthe test runs. It should be noted that with the addition ofdry sorbent no impacts on the operation ofthe 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 ofmercury during injection ofDSI was reviewed and is included in Attachment 1. The results indicate a baseline removal efficiency of93% 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 ofmercury in the coal burned. Throughout the DSI test the activated carbon injection rate was unchanged. Based on the low values ofmercury 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 ofthe 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 ofthe 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 ofwater 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 ofcompleting the development ofa 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 ofthe interview, 25 gallons ofmixed 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 oftests and characterization studies were performed. The work was performed to describe for operators the expected characteristics ofmixed 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 Electric Energy, Inc, Draft Final Report 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 ofeffluent
• Direct Shear, Normai/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 ofthe two products are likely more comparable, than metals content or leachate.


### Densities

- Bulk density testing indicated that the densities ofthe two byproducts 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 ofup 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 ofthe dry sieve results shows that the SBC byproduct is mostly fine sand and silt size particles. Analysis ofthe 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 ofthe formulations, when the

34

### Electronic Filing - Received, Clerk's Office, 08/15/2012 Electric Energy, Inc, Draft Final Report 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 ofthe 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 selfhardened at a slightly slower rate than the baseline ash. The rate ofSBC byproduct setting, selfhardening and heat release can somewhat be controlled by the amount ofwater 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 ofheat released, ease ofmixing, 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% ofthe 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 of98 psi at 7 days. This is well in excess ofthe 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 ofthe tests for SBC byproduct.
Even though the monolithic material maintained its physical shape and UCS values, about 16% ofits mass dissolved during the 

### 7 day immersion study. The pH remained high(>12.5) during the immersion test. Thus, the soluble components ofthe byproduct material may dissolve ifwater is allowed to set on top ofit and percolate through the treated material.


### PH- The high pH of SBC byproduct is likely the result ofCaO, Ca(OH)2, CaC03, NaOH, Na2C03 and NaHC03 contents. The leachate pH values exceed typical site discharge criterion of about 8.5. The pH ofthe 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

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### 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
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 ofwater is consistent with observations ofEEI 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% ofthat ofthe 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 ofmagnitude 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 ofthis 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 ofreference. 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 

### '

### 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
Effluent testing ofthe permeation liquids indicated elevated pH ofpermeate waters, containing high levels of sodium and sulfur as well as lower levels ofvarious metals. 

### 3.4 Impacts on Operation 3.4.1 Utilization of DSI at Joppa

From this set oftests the decision ofwhether to use Trona (milled on-site) or SBC (milled on-site) would become one ofeconomics ifinjection 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 ofthe flue gas during partial load operation. Ifthe air heater gas outlet temperature drops to below the recommended Solvay low temperature for SECutilization of275 °F the utilization efficiency will drop. The PI data provided as part ofthis 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 ofthe SBC runs feeding SBC after the air heater were at temperatures in the 330 °F range. Partialloads at night or for an extendedperiod oftime with a resultant low temperature out ofthe air heaters may adversely impact the utilization rate of SBC especially when that temperature approaches 275 °F and given the spread oftemperatures across air heater outlet due to rotary design.
As seen in the results, the addition ofDSI adversely impacts the amount ofparticulates 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 ofunmilled Trona though there still was an increase in PMI0. Significant modifications to the plant's ESPs would be required to limit the additional particulate emissions.



### 3.4.2 Air Permit Considerations TheJoppa 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 ofdry 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 ofPrevention 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 ifit 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'\**~·**

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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 ifany 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 ofthe 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 ofthe coal with alternate fuels such as natural gas.
The analyses and results are discussed in the following sections.



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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 halfto 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 ofthe 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% offilterable 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 ofUnit 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 ofhours 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 halfto 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 ofthe 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 ofthe Scenario 1 analysis are shown in Table 3-26.

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### 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. Ifall six boilers are retrofitted then this limit would bereduced to a third ofwhat 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 ofthe 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 ofoperation, 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).

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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 ofoperation for CY20 10 would be equal to the total hours ofoperation for the baseline period of Q3-Q4 2009 through Ql-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 halfto 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% ofparticulate was PM10 and 13% was PM2.5.
The future projected emissions from material handling ofthe 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. Ifall six boilers are retrofitted then this limit would be reduced to a third ofwhat is shown for the emissions from Units 5 and6. (2) Ifall 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 ofthe 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 ofthe 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) ofapproximately 170 (ft2/kacfm, based on flue gas at

- 330 deg F 

### avg). Each ESP has two chambers, plate to plate spacing of9 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 ofthe 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 ofthe dry 

### pressure pneumatic type (United Conveyor Company, UCC Dry, Nuva Feeder Pressure Pneumatic) and a secondary fly ash removal ofthe 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 of44 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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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 oforiginal 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 ofthe ESPs (i.e. 170), and the highly resistive fly ash from PRB coals. The
use ofthe FGC system (S0 3 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 ofthe ESPs to achieve the currently good levels ofPM removal at Joppa Station. Since modifications have already been performed on the ESPs, along with high standards ofoperation and maintenance (O&M), with routine inspections and repairs that have maximized the efficiencies ofthe existing ESPs, future improvements in the performance ofthe existing ESPs will require additional upgrades. The following is a list and description ofpotential improvements/replacements to the existing ESPs. It is likely that many ofthese 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 ofthe ESP for S02 reduction, this section provides wide-range ofconcepts 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 ofTrona or SBC injection upstream ofan ESP represents a significant amount of sorbent solids increased loading (lb/hr) relative to the normal amount ofPRB coal fly ash that enters an ESP. Typically, the use ofTrona or SBC would increase the electrical conductance ofthe total solids entering the ESP (flyash plus sorbent), which in general is good for ESP performance (up to a point), but to high ofparticle conductance is not considered good for overall ESP performance. Other potential negative attributes ofTrona or SBC sorbent injection with regard to potential degraded ESP performance typically include the relatively large quantity ofsorbent 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) oftotal PM and possible increase in fine PM emissions.

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Table 3-28 presents a typical list ofgeneric categories ofconcepts 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 ofpreference, since it is shown as examples for a generic ESP scenario. Additional study is required to determine applicability or specific costs ofthese concepts for a given ESP. Later in this section, generic rough budgetary cost estimates are provided for some ofthese 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 ofthe foundation during a rebuild ofa 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. Ifrequired, 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.



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E

F

G



### H Discharge Electrode Design

RebuildESP with Wide Space

Spacing

RebuildESP -As Is

ReBuildESP with Increased Collecting Electrode Area through a generic ESP can be performed. A model study of an existing generic ESP could indicate areas ofpossible reentrainment, highvelocity, and non-uniform flow distribution. Correcting these issues with vaning and perforated plate modifications could improve generic ESP
Retrofit ofnew discharge electrodes with custom configuration could be considered. Various discharge electrode designs are available for evaluation to potentially

. .**E~.** 

### Conversion ofa 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 ofthe 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 ifthe ESP was originally well-designed and is
now in need ofa re-build. Often, this concept alone may not be chosen, because typically an upgrade ofthe 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 rebuildfor 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.

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I



### J

K 

### ESP downstream of Existing ESP Agglomerator Concept

Pulse or Intermittent Energization Concepts Building an additional ESP downstrean1 ofthe 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 ofwhich enters a passage in the charger section ofthe 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 oflarge 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 ofeach 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 ofthe 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 ofthe input waveform, then skips several cycles on a repetitive basis to yield a product ofpeak and average voltages that is greater than for conventional full wave or double half-wave PC-based

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L

M

N



### 0

p Convert ESP (COHPAC)

Build Wet ESP Downstream of

Existing ESP

Replace Existing ESP with a Larger Cold Side ESP Builda 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 ofa 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 ofthe 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. CORPAC Iretains the existing ESP and adds the PJFF downstream on its own foundation, whereas CORPAC II replaces the outlet field of the ESP with the PJFF. Obviously, these are considered



## . .ects. Building a wet ESP (WESP) downstream ofthe existing generic cold-side dry ESP could be considered. WESP employs a flowing sheet ofwater to entirely cover the collecting plates in the ESP. Since the film ofwater serves as the collecting electrode, there is no significant reentrainment and the detrimental effects ofhigh 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 ofthe outlet field ofthe generic existing ESP or as a separate housing downstream from the primary generic ESP collector. Ifthe 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 ofthe generic existing ESP could be considered if site conditions are limited. Again, this is a ect. Building a pulsejet fabric filter (PJFF) downstream ofthe existing generic ESP could be considered. The PJFF would be tied-in during unit outage. This would be a major project.
Conversion ofthe existing generic ESP to a PJFF could be considered. This would require a major unit outage and would be a significant project.



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### It is possible that other generic concepts could be conceived to improve the performance ofa generic ESP associated with Trona or SBC sorbent , , for reduction,

As a means of developing rough cost estimates for some ofthe 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. 

### ConceptA

- 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 offive TR sets, the ESP vendor generic price may be $500,000 per ESP (installed basis), not including generic Owner costs, or contingency. 

### ConceptB- AdditionalSectionalization 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 often high frequency power supplies installed, resulting in a ESP vendor generic price ofapproximately $800,000 per ESP (installed basis) for sectionalization with new high frequency power supplies, not including generic Owner costs, or contingency. 

### Concept C- AdditionalRapping Ifrequired, 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 berequired to determine the required rapping density. Depending on the specifics ofgeneric ESP, depending on the exact rapper configuration and the envil beam arrangement, the



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### 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 ofa generic "maximum case scenario", one could
assume doubling the number ofexisting 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 ifwire build-up is indentified as a potential issue, it could be approximately $390,000 per ESP ifboth the plate and wire rappers are doubled in quantity. This does not include generic Owner costs, or contingency. 

### ConceptD

- CFD Modeling As discussed in Table 3-28, Computational Fluid Dynamic (CFD) model studies offlow through a generic ESP can be considered. A model study ofan existing generic ESP could indicate areas ofpossible 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 ofthe 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 ofgeneric categories ofconcepts 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 ofimprovement (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 ofashlhr/plant is typically received in silos over a 60 hour weekend period. That equates to approximately 1500 tons ofash accumulated in the silos with a maximum current facility capacity of 1800 tons. If, for example, a DSI rate of5000 lblhr is chosen, then an additional2.5 tons ofby-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 ofcurrent 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 ofadverse impact on the pneumatic by-product transport system.
The characterization ofthe 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 ofwater for dust suppression at the dustless unloader and additional water added at the landfill to obtain the desired mechanical properties ofthe compacted ash.

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The pH ofthe runofffrom 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 runoffprior to discharge.
Dissolution ofa p01iion ofthe compacted flyash/SBC mixture was seen during the testing. Dissolution ofthe product will result in higher total dissolved solids (primarily sodium and sulfate) in the landfill runoff and possibly loss of structural integrity ofthe landfill over the long term. Adequate cover ofthis material will be required to minimize this dissolution in the landfill so that it maintain its structural integrity. Continued contact ofthe ash/SBC mixture with water produced hydrogen gas. Gas generation would be controlled with adequate cover ofthis material. 

### 3.4.5 General Impacts on Plant Operation The injection ofDSI did not have any discernable impacts on the operation ofUnits 5 and 6. One ofthe questions that this study wanted to address was the potential impacts DSI would have on the air heater ifinjected 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 ofdry sorbent injected upstream ofthe air heater could be discerned from available data.
An 

### inspection ofA side ofUnit 5 ESP after the testing was completed showed a lighter shade ofash on the internals, but no operational problems. Though the plant did not have problems with the increased amount ofESP 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 ofpre-milled SBC did have unloading problems due to the clumping ofthe SBC caused by humidity and age ofthe pre-milled SBC. 

### If SBC were to be used, on-site milling should be considered.
The operation ofa DSI system would likely result in the plant needing additional personnel to off-load the rail delivered dry sorbent and to maintain the operation ofthe 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 DSI 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 ofthe plant with a pneumatic feed system to transfer the DSI to Unit-pair specific storage silos
• Upgrade ofthe ESP ash handling systems • Three dry sorbent feed systems, one for each set oftwo 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 ofthe 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 of90%
• Average coal S0 2 

### content of0.61lb S02

### /MMBtu
• 50% S02 

### removal required
• Trona delivered price of $175/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% 

### S0 2 

### removal with plant burning PRB coal with 0.61 

### lbs of S02

### 1MM:Btu and a yearly plant capacity factor of0.90 

### 2. The data for milled Trona injection after the air heater is minimal. This utilization rate achieved an average of42.6% 

### 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% 

### S0 2 

### removal. The utilization rate would likely be lower to achieve 50% 

### removal, so the yearly estimated cost would likelybe lower than shown to achieve 50% 

### S02 

### removal.
Additional O&M costs will occur for additional plant personnel, the lost revenue offly ash sales, the additional costs associated with disposal ofthe 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 ofthis 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 ofa 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 (ifupstream ofthe 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 ofthe fly ash handling system, and;
• whether there are any issues in the handling ofDSI 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 ofdry sorbent versus 0.100 lbs S02 removed per Ib ofdry 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 ofdry sorbent respectively) when injected before the air heater
• The injection location (whether before or after the air heater) impacts the efficiency ofTrona 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 ofthe test program, which results in uncertainty regarding the effects of DSI on mercury removal
• The addition ofDSI will increase the amount ofparticulate matter leaving the stacks. The Joppa facility will trigger PSD due to injection ofthe dry sorbent and DSI material handling unless the control efficiency ofthe existing particulate control is increased.

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• 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 ofdry sorbent before the air heaters will cause degradation of plant performance is unknown. Visual inspection ofa portion ofthe 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 ofthe DSI was the clumping ofthe 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 ofthe 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 ofthe 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 ofthe 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 runoffpH will likely be high enough to require neutralization ofthe landfill pond runoffprior 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 ofthe landfi.Il (use up available capacity faster)

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- 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 ofparticulate 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 ofan 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 ofthe 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 ofESP efficiency upgrades, then additional testing is warranted that would include:

o Prolonged injection ofeach reagent upstream ofthe 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 CY20I0 operation using the latest emission data.

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### 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 ofthe Unit 5 and Unit 6 emission sonrce(s) at the Electric Energy, Inc. Joppa Station facility. The enclosed report details the results ofthe 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. Ifyou**hav~** any questions or concerns regarding the contents ofthis 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 ofthe 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 ofNitrogen (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

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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) S0 2 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 & Hg 2+) 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 aworld 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 ICAP Inductively Coupled Argon Plasma IESD lnte.grated Emissions Solutions Development IC Ion 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 ofthe tests conducted on June 4th through 15th, 2010 at the Electric Energy, h1c. (EEl) facility located in Joppa, Illinois. The primazy objective ofthe testing was to determine the emissions oftarget air pollutants and to ascertain removal efficiencies across the air pollution control system during baseline and parametric testing conditions. Section 2.0 ofthis 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 ofthe 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

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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 ofthe 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 ofthe 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 ofparallel 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 2

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# 6 Stiaw"

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 oftwo 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 oftwo parallel ducts (Duct A & B) each 'vith a cross sectional area of230 square feet at the sampling location.
• ESP Inlet

- consisted ofnvo parallel ducts (Duct A & B) each with a cross sectional area of 230 square feet at the sampling location.
• ESP Outlet

- consisted ofnvo 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 ofeach 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 ofeach sampling location (see Table 1-3).

Shaw Power/EEl Testing Project No: 139424 August2010 3

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# u Stiaw''

a wurid of Solutlorts

### 1.4 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

4

### Electronic Filing

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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

5

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### 2.0 

## Summary ofResults

As noted in Section 1.0 ofthis report, the primary objective ofthese 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 ofthe 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,JS0 3) -mass emission rates, removal efficiency

o Oxides ofnitrogen (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 (S0 0) 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 S0 2 removed per pomtd ofDSI 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.

Shaw Power/EEl Testing Project No: 139424 August 2010 6

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Shaw Power/EEl Testing Project No: 139424 August2010 Table 2-1 aworld of Sofutitms"

7

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Shaw Power/EEl Testing Project No: 139424 August 2010 awur!d ofSolutions

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2

.. 1.1 Observations 

## so2 removal efficiencies were calculated as follows: 

# A**~** 

# Sliaw·

aworid 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 ofthe 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 

### ofNitrogen (NO 

### X) Using EPA Method 6C, oxides ofnitrogen (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 inppmvd Table 2-2 shows the S02 test results.

Shaw Power/EEl Testing Project No: 139424 August2010 Table 2-2

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Shaw Power/EEl Testing Project No: 139424 August 2010 

# 6 SHaw"
8 world of Solutions10

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# f:J., Sliaw"

2.3 Total Particulate Matter Emissions data for the specific subsets ofparticulate matter (PM) were acquired as noted below. Detailed emissions results are shom1 in Table 2-3. Using either one or a combination ofEPA 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 ofthe 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)

Shaw Power/EEl Testing Project No: 139424 August 2010 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 ofparticulate 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 ofPM, 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**-~ ~-------**  ----**~ ~-**  Somen!**Est~mated** Mass Emiss1on Rate 1njection Comb•ned Changefrom 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 ofparticulate 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 August 2010

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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 ofthe 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 oftl1e 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 ofparticulate 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 13

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# ,,

....**~·** 

## SHaw''

aworid 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, Hg 0

, 

### 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 ofmercury (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 & Hg 2•) 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:& _____(Condition**(lblh_r)~ate -~~** 

Unit 6 ECON Outlet Baseline 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 0.21TronaUnit 6 ESP Outlet Unmilled 9,283 182.21 6/7/10 0.20 0.00031 0.25 1.69 0.00242 2.04TronaUnitS ECON Outlet Milled 8,696 183.65 6/8/10 0.08 0.00012 0.08 0.49 0.00053 0 50TronaUnit 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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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 15

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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 inppmvd.

Shaw Power/EEl Testing Project No: 139424 August 2010 16ElectronicFiling-Received,Clerk'sOffice,GworldofSOlutions"Notes:Table2-9HalogensandHydrogenHalides(CI2,HCI,HF)ConcentrationandMassEmissionRate(1)witha"<"qualifierarerepot1edasbelowtheRepm1ableDetectionLimit(RDL)-ConespondingconcentrationsandmassemissionrateshavebeencalculatedusingthereportedRDLastheminimummass(2)-Thetotalmassforeachmetalisthesumofthefronthalfandbackhalfresulls.Standardreporlingpracticefordatawitha"<''qualifierincludestheRDLintheTOTALsampleandqualifyingtheTotalas"<"therepm1edquantity(3)-NIAApplicable(4)-June4-5,2010-FuelfiredwasEastThunder(JacobsRanch)PRBCoal(5)-June15,2010-FuelfiredwasBelleAyrPRBCoalShawPower/EElTestingProjectNo:139424August201017

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

aworid ol**Solutions~** 

### 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 ofthe 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).

Shaw Power/EEl Testing Project No: 139424 August 2010 Table 2-10

18

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Shaw Power/EEl Testing Project No: 139424 August 2010 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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Shaw Power/EEl Testing Project No: 139424 August 2010 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''

aworld of Solutfons·

0.0055

0.0010
0.0015

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# 6 SHaw"

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 offilter housing/all impingers) varies for each metaL (3)- The total mass for each metal is the sum ofthe front half and back halfresults. 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

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2.9 Sulfur Trioxide (503 ) 

# I 

# ,·\ Stiaw''

a worid of Snlutktns·

Emissions data for S03 was acquired as noted below. Detailed emissions results are shown in Table 2-11. Emissions ofthe 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 ofthe 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 ofthe 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 ofthe baseline and SEC analytical data to

Shaw Power/EEl Testing Project No: 139424 August 2010 22

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# 6 Sliaw"

aworiu of SolutionS· 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 , , ,


## . . .. 

# . 

# . . . Hg ln • ; ' 

### !"lll '0111- 

### !f!l:®f , 'lfolilf.Hg .•**-~ntea** 

### FOi • ®81

. . , 

# .

. , , 

### !!"'>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 ofbaseline 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 ofbaseline 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 23

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# Appendix A Sampling Methodologies

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### Sampling Methodologies

Test Methods Used
Location of Traverse Points 

# A

# Sh~· aworld of Solutions··

To ensure representative measurement of gas velocity and volumetric flow rates, the cross section ofthe 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 ofthe 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 ofthe 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 C0 2 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 C0 2 monitor was calibrated using EPA Protocol gases prior to and after fue completion offue 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 ofthe sampling train system. The concentration of C0 2 is reported in percentage ofcarbon dioxide (% C0 2) 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 ofthe instrument. Oxygen (Oz) Determination (Instrumental Method) The 0 2 concentrations were sampled and determined using a paramagnetic 0 2 analyzer. The 0 2 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 offue test run series. Zero and mid/high point calibration bias checks were performed prior to fue beginning and at tl1e completion of

### Electronic Filing

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## /'\

# Sh~· ,:; worid .-:1f Solutions· each test run to ensure the integrity ofthe sampling train system. The concentration of0 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 ofextraction 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 ofthe instrmnent. Sulfur Dioxide (S0 2) 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 ofextraction 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 ofthe instrument. The concentration and mass emissions of S02 in the gas stream are reported in the units ofthe 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 ofextraction 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 ofthe instrmnent. The stack gases were sampled separately for oxides ofnitrogen (NO,) concentrations using a chemiluminescent NO-NO, gas analyzer. The chemiluruinescent reaction ofNO and ozone (0 3) takes place as follows: 

### NO+ 0 3 ----'>- 

### N0 2 

### + 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 ofthe 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 N0 2 (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

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

awor!d t:;f Solutions' 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 ofNO, in the gas stream are reported in the m1its ofthe 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 (S0 3) using an NCASI Method 8A sampling train. The sampling train coilected approximately 30 cubic feet ofgas 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 H 2S04 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 steeljacket. 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 oftl1e S03 . The third inlpinger contained approximately 100 ml of distilled Dl water. The fourth impinger contained approximately 200 g ofindicating 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 samplejar, 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 samplejar, 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 oftl1e 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 ofthe gas stream moisture.

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

# Q Stiaw·
8 wo:tl of Solutions' The equipment used to perform the sampling has the approval, and meets the standards, ofcalibration accuracy as set forth by U.S. EPA. Copies ofthe calibrations are appended to this document. The sampling equipment consisted ofthree 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 ofthe 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 ofmoisture 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 offour 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 ofindicating 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 ofthe sample collected prior to begirming the test and again at the conclusion ofthe 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 ofthe ftlter holder were rinsed and brushed six tinles with acetone into a leak-freejar. 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. BlankReagents -A sample ofthe 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.

### Electronic Filing

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

a wo:ti ot Solutions·

Condensable Particulate Matter Determination (Method 202) The CPM was collected in the impinger portion ofMethod 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 ofboth 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 ofnomenclature 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 ofti1e gas stream moisture. The sampling equipment consisted ofthree 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 ofindicating 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 ofthe sample collected prior to beginning the test and again at ti1e conclusion ofthe 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.

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

::l world eli' Solutions· 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 ofthe 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 ofthe tube ofthe PM2.5 cyclone and the front half ofthe 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 ofthe 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, ofcalibration accuracy as set forth by U.S. EPA. The sampling equipment consisted ofthree 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 ofmoisture 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 byleaving 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 entiretest train to insure tl1e integrity ofthe sample collected. At the conclusion ofeach 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 ofimpingers 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 ofimpingers four and five were transferred into a sample container rinsed with DI

### Electronic Filing

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

# /\, 

# Sh'aW"

awarid of Solutions'
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 ofthe 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 ofthe 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 offour impingers. The first and second impingers each contained a 100 ml mixture of 5% HN0 3 and 10% H20 2 solution. The third impinger remained empty as a moisture knockout. The fourth impinger contained 200 grams ofindicating' silica geL The impinger section ofthe 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 ofeach test run. At the conclusion ofeach 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 ofthe filter holder were rinsed and brushed three times with acetone, then rinsed with 0.1N HN0 3 into a leak-freejar. The rinsates were subsequently placed into sample collectionjars. Impingers- each impinger was weighed separately to the nearest 0.1 gram to determine the moisture gain for the test. The liquid contents ofthe 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 ofthe 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 Hg 0

, 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 ofelemental 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 ofmoisture 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.

### Electronic Filing

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

a V'iGri(j of Solutions 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 ofimpingers located in an ice bath. The oxidized mercury was collected in thefirst set ofimpingers containing chilled aqueous potassium chloride (KCl) solution. The elemental mercury was collected in subsequent impingers (one containing chilled aqueous acidic solution ofhydrogen peroxide and tirree impingers containing chilled acidic solutions ofpotassium 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 ofti1e probe and front half ofthe filter bell were cleaned by rinsing and brushing drree times witi1 a 0.1N HN03 rinse. The sample was collected in an amber samplejar 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 samplejar and sealed wifu a Teflon lid and Teflon tape.
• The contents ofimpingers 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 HN0 3 and incorporated into fue sample container. The composite sample was collected in an amber samplejar 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 samplejar 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 ofblanks for ilie filter, water, and all sample and recovery reagents used in the sample train. Because offue highly quantitative aspect ofthe 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 ofthe 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 ofmeters 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 ofthese 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 ifeach value of Yi was**"~thin** 2 percent ofthe 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 ofthe average value ofthe four values of H@I ( H@ ±0.2). If any ofthe 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 ofthe 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 ofintroducing 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 ofsample 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 ofthe fmal stable value enabled the determination of mean upscale and downscale response times. Zero and calibration drift was also determined during each run ofthe tests. This was accomplished by comparing zero and upscale calibrations from before and after a test run.