# Appendix D

BUSINESS CONFIDENTIAL INFORMATION

# DuPont Research and Engineering Technology



# Final Report - Results of BART Modeling & Engineering Analysis @ Maximum 24-hour Firing Rates Using the Old IMPROVE Equation

For



# E. I. duPont de Nemours and Company. Old Hickory Plant

1002 Industrial Road Old Hickory, TN 37138

For submission to:

TN Department of Environment
and Conservation
Division of Air Pollution Control 9th Floor, L & C Annex
401 Church Street Nashville, TN 37243-1531 Metro Public Health Department

of Nashville
Pollution Control Division Office
Lentz Public Health Center

Room 208

311 23rd Avenue North Nashville, TN 37203

Prepared by:

Bruce C. Davis Charles J. Zarzecki & John C. deRuyter DuPont Engineering Technology DuPont Engineering Technology 140 Cypress Station Drive, Su ite 135 1007 Market Street Houston, TX 77062 Wilmington, DE 19898



# September 18, 2007

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# Table of Contents

1 Executive Summary .................................................................................................... 5

2 Background & Introduction ........................................................................................ 7

2.1 Revised Modeling Basis for the Current Assessment ....................................... 11

3 Data Analysis of Control Opti ons Modeling and Cost Analysis .............................. 13

4 Conclusions ............................................................................................................... 21

5 REFERENCES ......................................................................................................... 33

6 Appendix 1 - BART Control Strategy Modeling Analysis ...................................... 35

6.1 Introduction ....................................................................................................... 36

6.2 Source/Class I Area Geometry .......................................................................... 36

6.3 Emissions Inventory .......................................................................................... 37

6.4 Visibility Modeling Methodology .................................................................... 37

6.4.1 CALMET Modeling Configuration (Subr egional 4-km runs conducted by VISTAS and EarthTech (now TRC) ......................................................................... 37

6.4.2 CALPUFF Modeling Configuration ......................................................... 39

6.4.3 CALPOST and POSTUTIL Configuration ............................................... 41

6.5 Modeling References ........................................................................................ 42 Table 6-1 Old Hickory Emissions Parameters ............................................................. 43

Table 6-2 BART Control Cases ................................................................................... 44 Table 6-3 PM Speciation Basis (1.88% Sulfur Coal) ................................................... 45

Table 6-4 – PM Particle Si ze Basis (1.88% Sulfur Coal) ............................................. 46 Table 6-5 PM Speciation Basis (1.5% Sulfur Coal) ..................................................... 47

Table 6-6 – PM Particle Si ze Basis (1.5% Sulfur Coal) ............................................... 48 Table 6-7 PM Speciation Basis (1.0% Sulfur Coal) ..................................................... 49

Table 6-8 – PM Particle Si ze Basis (1.0% Sulfur Coal) ............................................... 50 Table 6-9 PM Speciation Calculations for 1.88% Sulfur Coal Cases .......................... 51 Table 6-10 PM Speciation Calculat ions for 1.5% Sulfur Coal Cases .......................... 52 Table 6-11 PM Speciation Calculat ions for 1.0% Sulfur Coal Cases .......................... 53 Table 6-12 Monthly f(RH) Va lues for Each Class 1 Area ........................................... 54 Figure 6-1 Old Hickory Loca tion and Class 1 Area Distances .................................... 55 Figure 6-2: DuPont Ol d Hickory Plant Geo-Referenced Air Photo ............................. 56 Figure 6-3 VIST AS Subdomain #3 ............................................................................. 57 Figure 6-4: Mammoth Cave NP Receptors .................................................................. 58 Figure 6-5: Cohutta Wilderness Receptors .................................................................. 59 Figure 6-6: Great Smokey Mountains NP Receptors .................................................. 60

7 Appendix 2 - Model Input and Output Files on CDs ............................................... 63 8 Appendix 3 - Results of BART Cont rol Strategy Engineering Analysis .................. 65

8.1 Background ....................................................................................................... 66

8.2 Existing Boiler Design, Arrangement, and Operation ...................................... 66

8.2.1 Basis for Engineering Analysis ................................................................. 67

8.3 Description of Feasible Options ........................................................................ 71

8.3.1 Baseline Case Using Coal Currently Burned (Coal 1) .............................. 71

8.3.2 Burn Lower Sulfur Coal ............................................................................ 72

8.3.3 SO 2 

# Scrubbers Using Coal with Various Sulfur Contents ........................ 73

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# 8.3.4 Cofire Coal and Natural Gas in each Boiler at a 50/50 Ratio ................... 73

8.3.5 Install Low NOx Burners (LNB) or Selective Non-Catalytic Reduction (SNCR) 73

8.3.6 Install Selective Catalytic Reduction (SCR) ............................................. 73

8.4 SO 2 

# Emissions Reductions and Economic Comparison of Options Using the Highest Emission Day Basis ......................................................................................... 74

8.4.1 Coal 2 Fired in Boilers 20 and 24 ............................................................. 74

8.4.2 Coal 3 Fired in Boilers 20 and 24 ............................................................. 74

8.4.3 Spray Dry Absorber with Downstream Baghouse .................................... 75

8.4.4 Sodium Wet Scrubber Installation ............................................................ 75

8.4.5 50/50 Coal/Gas Cofiring ........................................................................... 77

8.5 NOx Emissions Reductions and Economi c Comparison of Options Using the Highest Emission Day Basis ......................................................................................... 77

8.5.1 Low NOx Burner (LNB) Retrofit ............................................................. 77

8.5.2 Selective Non-catalytic Reduction (SNCR) .............................................. 78

8.5.3 Selective Catalytic Reduction (SCR) ........................................................ 78

8.5.4 50/50 Coal/Gas Cofiring ........................................................................... 79

8.6 SO 2 

# and NOx Emissions Reductions a nd Economic Comparison of Options Using the Annual Average Capacity Factor and Average Coal Quality Basis ............. 79

8.6.1 Coal 2 Fired in Boilers 20 and 24 ............................................................. 79

8.6.2 Coal 3 Fired in Boilers 20 and 24 ............................................................. 79

8.6.3 Sodium Wet Scrubber Installation ............................................................ 80

8.6.4 50/50 Coal/Gas Cofiring ........................................................................... 81

8.6.5 Low NOx Burner (LNB) Retrofit ............................................................. 81

8.6.6 Selective Non-Catalytic Reduction (SNCR) ............................................. 81

8.6.7 Selective Catalytic Reduction (SCR) ........................................................ 82

8.6.8 50/50 Coal/Gas Cofiring ........................................................................... 82

8.7 Energy and Non-Air Quality Enviro nmental Impacts of Compliance .............. 82

8.8 Conclusions Relative to SO 2 

# and NOx Controls for Boilers 20 and 24 ............ 83 Table 8-1 BART Economic Analysis for Du Pont Old Hickory Boilers 20 & 24 at Maximum Combined Daily Emissions ......................................................................... 87 Table 8-2 BART Economic Analysis for Du Pont Old Hickory Boilers 20 & 24 at Average Firing Rate & Average Coal Quality .............................................................. 88 Table 8-3 BART Economic Analysis for Du Pont Old Hickory Boiler 20 at Combined Maximum Daily Emissions ........................................................................................... 89 Table 8-4 BART Economic Analysis for Du Pont Old Hickory Boiler 20 at Average Firing Rate & Average Coal Quality ............................................................................ 90 Table 8-5 BART Economic Analysis for DuPont Old Hickory Boiler 24 at Maximum Combined Daily Emissions ........................................................................................... 91 Table 8-6 BART Economic Analysis for DuPont Old Hickory Boilers 24 at Average Firing Rate & Average Coal Quality ............................................................................ 92

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# 1 Executive Summary

The modeling results in this report were analyzed using the old IMPROVE Equation. The Interagency Monitoring of Protected Vi sual Environments (IMPROVE) protocols are the basis for evaluating vi sibility modeling results. The old IMPROVE equation was the basis used in the Visibility Improvement State and Tribal Association of the Southeast (VISTAS) Modeling Protocol (ref 5) which was used as the basis for the modeling work presented in this report.

The results presented in this report, base d on the old IMPROVE Equation, show a minor visibility impact on Mammoth Cave and a ne gligible impact on the other Class 1 areas within 300 km of the DuPont Old Hickory Plant. These result s were high enough to trigger an economic and engineer ing analysis of the options to establish Best Available Retrofit Technology (BART) to reduce emissions of visibility impairing species (SO 2 

# and NOx) from the Old Hickory Plant. This analys is is presented in th is report and shows that while the visibility impact can be reduced via BART co ntrol technology, the reductions are small. Basically, the control op tions available to be considered as BART can make a small impact smaller. In our view , the control options ar e not cost effective.

Upon review of this analysis with TN DEC at a meeting on August 30, 2007 the option was presented to evaluate the modeling resu lts using the new IMPROVE equation. This analysis has been completed and is presented in a separate report to avoid confusion. The analysis using the new equation is presented in a companion re port entitled: “Results of BART Modeling & Engineering Analysis @ Maximum 24-hour Firing Rates Using the New IMPROVE Equation”.

The results using the new IMPROVE Equation show a lower impact in the uncontrolled base case. The impact is so low that it is considered diminimus (i nsignificant) using the analysis methods in the Modeling Protocol.

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# 2 Background & Introduction

The DuPont Old Hickory Plan t Title V Air Permit includes the following information relative to the two BART-eligi ble boilers, Boilers 20 and 24:

Source Description:

• Boiler 20- Rated capacity- 445 million Btu/hr ; installation date- 1968; tangentially fired; primary fuel- coal; #1 standby fuel - natural gas; #2 st andby fuel- No.2 Fuel

Oil

• Boiler 24- Rated capacity- 315 million Btu/hr ; installation date- 1966; tangentially fired; primary fuel- coal; #1 standby fuel - natural gas; #2 st andby fuel- No.2 Fuel

Oil

Mass and Visible Emission Standards and Operating Schedule Limitations

• Boilers 20 and 24- visibl e emission standard- 20%

• Boilers 20 and 24- operating schedule limitations- 24 hrs/day, 8,760 hr/year

• Boiler 20 (Emission Point 009) mass emission standards:

Pollutant Lb/hr Lb/day Rolling 12 Month

Tons

PM 10 

# 77.4 1858 339.1

SO 2 

# 1295.2 31,086 5673

NOx 241.2 5789 1056.4

CO 10.4 251 45.7

VOC 2.4 57 10.51

• Boiler 24 (Emission Point 011) mass emission standards:

Pollutant Lb/hr Lb/day Rolling 12 Month

Tons

PM 10 

# 54.8 1315 240.1

SO 2 

# 916.9 22,004 4015.8

NOx 179.6 4309 786.4

CO 7.4 177 32.4

VOC 1.7 41 7.45

• Boilers 20 and 24 are subject to MCL 10.56.200 which limits the maximum sulfur content of any solid or liquid fuel to 2.0% sulfur by weight. The above standards are based on a maximum sulfur content of 0.05% by weight for No.2 Fuel Oil.

• Boilers 20 and 24 are subject to 40 CF R 75, Subpart H, NOx Budget Trading Program.

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# • All boilers are subject to 40 CFR 63, Subpart DDDDD, Industrial, Commercial,

and Institutional Boilers and Process Heaters with a compliance date of September 13, 2007. The two Boilers at DuPont’s Old Hickory Pl ant in Old Hickory, TN are BART eligible based on their installation date and design heat input as indicated above. These Boilers are designated Boiler 20 and Boiler 24. The em issions from these boilers were modeled to determine the possible visibility impact on nearby Class 1 areas. This work was submitted to TN DEC and the Nashville Metro Health Department on February 12, 2007.

The basis for both the February, 2007 and Apr il, 2007 modeling was w ith use of a single pseudo-stack that was used to represent overall annual operation of both Boilers 20 and

24. Emission rates were determined usi ng annual average capacity factors for both

boilers that were indicativ e of typical operation during 2005 and 2006. Those years were subsequent to shutdown of the DMT production facilities. That s hutdown significantly reduced site steam demand and the Boiler 24 ope rating rate (it was de dicated to providing steam to DMT). Boiler 24 now serves as a backup boiler to Boiler 20 and to provide supplemental steam in periods of high de mand (winter). The annual capacity factor assigned to Boiler 20 was 80% and the annual ca pacity factor assigned to Boiler 24 was 20%. These figures provided an operati ng margin above actual 2005-06 average coal firing capacity factor (Boiler 20 was 70.3% and Boiler 24 was 15.2%). The capacity

factors included times when the boiler line up was changed and both boilers were on line for a short period. The pseudo-stack, theref ore, allowed modeling of total composite emissions representative of both boilers’ operation.

A summary of the results of the February 12 modeling study are provided in this table:

Table 1-1 Summary of Prior Visibili ty Modeling for DuPont, Old Hickory

Modeled 98th perentile Value ( dV ) No Days exceeding 0.5

dV Modeled 98th perentile Value ( dV ) No Days exceeding 0.5

dV Modeled 98th perentile Value ( dV ) No Days exceeding 0.5

dV

Mammoth Cave

0.603 12 0.605 10 0.64 14

Cohutta Wilderness

0.139 1 0.161 0 0.241 2 Great Smoky Mountains National Park

0.162 3 0.152 0 0.319 2 Joyce Kilmer Wilderness

0.131 1 0.119 0 0.26 1 Sipsey Wilderness

0.272 1 0.286 2 0.397 2 2001
Class 1 Area 2002 2003



# The February modeling report submittal upon which these modeling results are based used the following emission parameters wh ich utilized average fuel quality data:

Parameter Units Boiler 24 Boiler 20 Pseudo

Stack Stack Stack

Stack Height ft 200 200 200

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## Base Elev. Ft above MSL 523 525 525

Diameter ft 7 9.5 9.5

Stack Flow Rate acfm 112606 171467 171467 Exit Temp. Deg. F 333 353 353 Coal Burned (2005) tons 15010 119900

Sulfur Content % 1.76 1.76 Hours/year operated hours 1296 7476 8760

Sulfur lb/hr 407.7 564.5

SO 2 

## lb/hr 815.4 1129.1 1082.7

PM 10 

## lb/hr 14.8 13.49 13.68

NO 2 

## lb/hr 156.7 241.3 228.8

SO 2 

## ton/yr 4742.3

NO 2 

## ton/yr 59.9 (Note 1)

SO 2 

## +NO 2 

## ton/yr 4802.3 Q/D 42.1

Pseudo is hourly weighted average of 2005 actual hours.

Note 1 - This figure was a math error in the first modeling- the lb/hr figure used in the model was correct, just the TPY calculation was incorrect; the value shou ld be 1002.1 TPY. This was corrected with the revised data used for the April modeling



# The actual stack heights used in this analysis (200 f eet) represent good engineering practice stack heights since the actual height s are less than 213.2 f eet (65 m) (all stacks are 200 feet tall). If the stack s were greater than good engineering practice stack height, the stack heights (for modeling) would be reduced to the good engi neering practice stack height. Since the stacks are less than good engineering practice stack height, this adjustment is not necessary.

These emission parameters are explained in the modeling report in Appendix 1 (Section 6).

The February modeling results showed a visibi lity impact and these results triggered the need for an engineering control evaluati on. The draft Engineer ing Control modeling results and the engineering control evaluation were submitted to the TNDEC and the Nashville Metro Health Department on Apr il 4, 2007. The base case for this modeling work was changed slightly from the Februa ry work and the following stack and emission parameters were used for the April study:

Parameter Units Boiler 24 Boiler 20 Pseudo

Stack Stack Stack

Stack Height ft 200 200 200

Base Elev. Ft above MSL 523 525 525

Diameter ft 7 9.5 9.5

Stack Flow Rate acfm 141886 180351 180351 Exit Temp. Deg. F 365 348 348

Sulfur Content % 1.76 1.76 1.76 Hours/yr operated hours 1752 7008 8760

SO 2 

## lb/hr 179 1013 1192

PM 10 

## lb/hr 14.8 13.49 13.68

NO 2 

## lb/hr 36 193 229

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## SO 2 

## ton/yr 5223

NO 2 

## ton/yr 1002



# The changes were due to a change in the heat content of the coal to reflect an average value compatible with the air permit, the us e of the AP-42 correction factor to convert

from fuel sulfur to SO 2 

# and a change in the stack gas fl ow rate and temperature based on a review of the data compared to emissions te st results. As explai ned in the note for the February emission modeling parameters, the t on/yr NOx emissions were changed due to a math error. The lb/hr data for NOx, whic h was modeled, was correct for both studies.

These changes in the modeling results are reflected for the Mammoth Cave location

below. The other cases for the other Class 1 areas were not re-modeled.

Table 1-2 Summary of Prior Visibility Modeling for DuPont, Old Hickory with Emission Parameter Changes

Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV

Mammoth Cave

0.647 16 0.658 12 0.679 15

Cohutta Wilderness

0.139 1 0.161 0 0.241 2 Great Smoky Mountains National Park

0.162 3 0.152 0 0.319 2 Joyce Kilmer Wilderness

0.131 1 0.119 0 0.26 1 Sipsey Wilderness

0.272 1 0.286 2 0.397 2 2001 2002 2003

Class 1 Area



# The conclusions from the April 4 modeling work were:

1. The visibility impact at Cohutta Wilderness, Great Smoky Mountains, Joyce Kilmer Wilderness and Sipsey Wilderness as measured by the number of days predicted to be above 0.5 dV is less than 8 days for each of these areas for the model years 2001, 2002 and 2003. Based on this modeling result, further evaluation of impacts at these areas is not necessary. The emissions from DuPont’s Old Hickory Plant are not predic ted to either contribute to or cause visibility impairment at these Class 1 Areas. 2. The visibility impact from DuPont sour ces at Mammoth Cave is predicted to be greater than 8 days abov e 0.5 dV. None of the 98 th 

# percentile modeled values are predicted to be greater th an 1 dV. Based on this m odeling result, the emissions from DuPont’s Old Hickory Plant have th e potential to contribute to visibility impairment at Mammoth Cave. Because the 98 th 

# percentile modeled values are predicted to be less than 1 dV, the emissi ons are not predicted to cause visibility impairment.

### Date: September 18, 2007 Page 11 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Based on these results, we proceeded to c onduct an engineering evaluation of control options to mitigate the DuPont, Old Hickory Pl ant contribution to visibility impairment at

Mammoth Cave.

2.1 Revised Modeling Basis for the Current Assessment

The April 4 th 

# work was reviewed with TN DE C and the Nashville Metro Health Department at a meeting on April 24 th 

# . At the review meeting, the comment was made that the modeling and control evaluations need to be based on the maximum 24 hour period of emissions during the prior three years. As indicated above, the basis used in the April 4 th 

# work was the emission rate based on annual average capacity factor for both boilers. The request for use of maximum 24 hour period emissions in the prior three years was a significant shift in approach th at grossly overstates actual emissions from Boilers 20 and 24. However, data was obtaine d from plant records to determine the new modeling basis. Since DMT production was shut down during 2004 and current operation is not representative of that pr ior operation, the highest day emissions during 2005 and 2006 were determined and used for the this modeling effort.

This report provides a modeling analysis and a control technol ogy evaluation based on the maximum 24 hour emissions basis. The assessment was performed assuming that the boilers would be fired at this rate year round. This is an ultra cons ervative basis and it is not possible to fire the boilers at this rate year round. The maximum firing rates occur in

the winter and are associated with buildi ng and process heating demands that do not

occur in the summer. Boiler shutdowns for annual inspection/overhau l also occur in the summer. Data showing monthly total Boiler 20 + 24 heat input compared to the highest 24 hour firing rate are provided in Appendix 3 (Section 7). As will be shown in the analysis, our visibility impacts are more si gnificant in the summer due to the higher SO 2 

# emissions impact on visibility compared to th e winter when visibility impact is more sensitive to NOx emissions. See Appendix 3 (S ection 7) for detailed information on data

used to determine the emission rates on the hi ghest day and how that relates to actual boiler operation.

The modeling results using the maximum daily emissions for the Class 1 Areas within 300 km of the Old Hickory site are summarized in this table.

Table 1-3 Summary of Current Visibili ty Modeling for DuPont, Old Hickory

Modeled at the 24 hour Maximum Emission Rate

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Mammoth Cave

0.87 35 0.898 29 0.929 27

Cohutta Wilderness

0.189 1 0.239 0 0.304 4 Great Smoky Mountains National Park

0.234 3 0.196 3 0.404 5 Joyce Kilmer Wilderness

0.182 3 0.19 2 0.341 3 Sipsey Wilderness

0.404 2 0.41 3 0.581 10 2003

Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV Modeled 98th perentile Value (dV) Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV No Days exceeding 0.5

dV Class 1 Area 2001 2002



# The major visibility impact is still predicted to occur at Mammoth Cave. A slight

increase is noted at the other Class 1 areas. Sipsey is noted to be above 8 days greater

than 0.5 dV for 2003. When the modeled data at Sipsey is examined in detail, the top 10 days for 2003 are predicted to occur in August (4 ), September (3), May (2) and July (1). As will be explained later in this report, summer time firing rates are approximately 50 % of winter firing rates. The day counts above 0.5 dV are all predicted to occur between May and September. Since it is not possible in the summer to fire the boilers at the

maximum rate that occurs in the winter due to reduced summer site steam demand, we do not believe that the modeled day count result is representative of our operations. Fuel quality (sulfur and heating value) do not vary significantly over the c ourse of the year due to use of consistent coal suppliers and the coal purchase specification and NOx emission rates do not vary over the course of the year. Thus, we believe that our day count impact above 0.5 dV is in reality less than 8 days, given that the firing rates in the summer cannot approach the 24 hour daily maximum rates.

For this reason, we have concentrated our engineering evaluation on options to reduce our modeled visibility impact on Mammoth Cave.

The modeling results for the control options evaluated in this Study are provided in Appendix 1 (Section 6). The control options and the cost estimates are provided in Appendix 3 (Section 8). The data anal ysis is provided in this section.

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# 3 Data Analysis of Control Options Modeling and Cost Analysis

The objective of the visibility improvement program underlying the BART rules is to improve the visibility at Federal Class 1 areas to natural conditions in the year 2064. In order to enable the attainment of this goal, the BART rules require the States to submit a State Implementation Plan (SIP) which will re sult in reasonable further progress towards this goal. Reasonable further progress for Ma mmoth Cave is represented graphically in Figure 3-1.

31.37 30.02

26.65

23.28

19.91

16.54

13.17

11.15 25.84



### 0 5 10 15 20 25 30 35

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064



### Yea rHaziness Index (Deciviews)



### Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction 

# Figure 3-1 Uniform Rate of Reasonable Further Progress Glide Path for Mammoth Cave – 20 % Worst Days

This “Glide Path” defines the pace and degr ee of reduction needed for sources that are predicted to either contribute to or cause vi sibility impairment at Mammoth Cave. The numbers on this glide path are based on the 24 hour daily average visibility measurements expressed as haze index with units of deciviews. The data set used is the

90 th 

# percentile of the annual distribution of 24 hour average values. This value corresponds to the average value of the 24 hour daily average of the 20 % highest days for the year. The goal, to be achieved in 2064, is for the average of the 20 % highest days to be at or below 11.15 deciviews. The goal in 2018 is to reduce the haze index to 26.65 dV. This corresponds to a change of 31.37 – 26.65 or 4.72 dV.

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# These data can be used as a benchmark to estimate the percentage contribution by DuPont Old Hickory BART eligib le sources to visibility im pairment at Mammoth Cave. The starting point for the glide path is the average of the 20 % worst days for the period of 2000 – 2004. For Mammoth Cave, this value is 31.37 dV.

EPA, in the July 6, 2005 FR where the Fi nal rule for BART determinations was published, notes on p. 39120 that a 0.5 deciview change corresponds to a 5 % change in light extinction and that this magnitude of change in visibility “will evoke a just noticeable (visibility) cha nge in most landscapes.”

The following are the modeling results for the base case currently fired coal (average quality- 1.76% S, 11,750 Btu/lb) for the follo wing conditions which represent the combined annual average capacity factor firing rate conditions. In fact, as shown in the chart below, this model basis is essentia lly equal to the 2006 maximum monthly average total heat input condition which is still signi ficantly higher than actual operation of Boilers 20 and 24 during summer months:

Table 3-1 Summary of Modeling Results @ Average Capacity Firing Rate

SO 2 

# Emission Rate – 1192 lb/hr

NOx Emission Rate – 229 lb/hr Coal Firing Rate – 419 MMBTU/hr Coal firing rate – 35,660 lb/hr

Coal % S – 1.76

2001 baseline 16 0.098 0.647 2.06 0.31

2002 baseline 12 0.089 0.658 2.10 0.28

2003 baseline 15 0.092 0.679 2.16 0.29

2001 - 2003 baseline 43 0.093 0.647 2.06 0.30 Average baseline 0.093 0.661 2.11 0.30 % of

Current

20% worst Days Avg as %

of 20%

Worst Days 98 percentile

dV value Case Defintion Count > 0.5 dV Days Avg Annual

DuPont dV



# The following are the modeling results for th e base case currently fired coal at the conditions which represent the maximum 24 ho ur combined emission rate for Boilers 20 and 24, including use of coal quality data for that day (1.88% S, 11,428 Btu/lb):

### Date: September 18, 2007 Page 15 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3-2 – Summary of Modeling R esults @ Maximum 24 hr Firing Rate

SO 2 

# emission rate – 1607 lb/hr

NOx Emission Rate – 282 lb/hr Coal Firing Rate – 514.2 MMBTU/hr Coal firing rate – 44,999 lb/hr

Coal % S – 1.88

2001 baseline 35 0.137 0.870 2.77 0.44

2002 baseline 28 0.127 0.898 2.86 0.41

2003 baseline 27 0.130 0.929 2.96 0.41

2001 - 2003 baseline 91 0.131 0.867 2.76 0.42 Average baseline 0.131 0.899 2.87 0.42 % of

Current

20% worst Days Avg as %

of 20%

Worst Days 98 percentile

dV value Case Defintion Count > 0.5 dV Days Avg Annual

DuPont dV



# This information represents a measure of the contribution of the DuPont Old Hickory sources to visibility impairment at Mammoth Cave. The deminimus value in terms of day count above 0.5 dV is considered to be 8 days per year. DuPont’s predicted contribution is 8, 4, and 7 days above this value for 2001 – 2003 data, when modeled at the average annual capacity factor (monthl y maximum average firing rate). When

modeled at the maximum 24 hour emissions ove r the entire year, th e number of days above 8 days is 27, 20 and 19 for the 2001 – 2003 period. In terms of percentage of DuPont’s predicted 98 th 

# percentile visibility value fo r the year, DuPont’s predicted percent ranges from 2.06 – 2.16 % for the average annual capacity factor (monthly maximum average) firing rate and 2.77 – 2.96 % of the current value (31.37 dV) for the maximum 24 hour emissions for the 2001 – 2003 period. These percentages would only be approached if DuPont’s contribution 98 th 

# percentile value o ccurred during the 20 % worst days at Mammoth Cave. Further, these percentages, if they coincided with the 20 % of worst days at Mammoth Cave, only w ould be predicted to occur for 16, 12 and 15 days or an average of roughly 14 days per year. The results fo r the maximum 24 hour emissions are not considered representative of actual emissions in the summer, so the day counts using this data are overstated. As not ed, 8 days above 0.5 dV are allowed, so on average, DuPont’s impact above 0.5 dV is predicted to occur 6 days per year.

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# The differences between the heat input rate s over the year for 2006 are shown in Figure 3-2. The maximum daily emission rate case ove rstates emissions over the year. Further, the site firing pattern is typical of a steam supply system primaril y providing heat and not for electricity generation (e.g., el ectric utility emission pattern with a summer peak). The

maximum rates occur in the winter and the mi nimum rates occur in the summer. For the 24 hour maximum emission rate, the actual emi ssion rate in the summer is roughly 50 %

of the 24 hour maximum rate.

Figure 3-2 Boiler Monthl y Average Firing Rates

2006 Boilers 20 & 24 Total Monthly Coal Heat Input

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000

Jan06 Feb06 Mar06 Apr-06 May06 Jun06 Jul-06 Aug06 Sep06 Oct06 Nov06 Dec06

MonthMMBtu/Month Coal Heat Input Maximum Daily Emissions Case- 375,410 MMBtu/Month Annual

A v

er ag e 

## April, 2007

model basisannual average capacity factor



# To summarize, DuPont is a relatively minor contributor to visibility impairment at

Mammoth Cave and the other Class 1 areas wi thin 300 km. Further, the choice of the maximum daily firing rate as a basis for this assessment leads to an over prediction of our impacts as the seasonal variation of our firing rate is not accounted for.

In terms of the day counts greater the 0.5 dV , the predicted distribution of these day counts by month is summarized in the following table:

### Date: September 18, 2007 Page 17 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3-3 Day Count Great er than 0.5 dV – Monthl y & Seasonal Distribution (2001-2003) for the Maximum Daily Emissions Case

Month Day Count >

0.5 dV % Distribution Day Count Subtotal by

Season % Subtotal by

Season

Jan 6 6.6

Feb 4 4.4 16 17.6

Mar 7 7.7 Apr 1 1.1 May 9 9.9 17 18.7

Jun 9 9.9

Jul 11 12.1 Aug 11 12.1 31 34.1 Sep 7 7.7

Oct 13 14.3

Nov 7 7.7 27 29.7

Dec 6 6.6

These data are presented for the daily maxi mum emissions case. As can be seen, 63.7 % of the days counts > 0.5 dV are predicted to occur from June – November. 36.3 % are predicted to occur in December – May. Th e maximum day counts are predicted to occur

in the months when the actual combined firi ng rate is lower, thus control strategies selected based on these data are not represen tative of the actual day counts which might

occur.

The modeling and cost data are summarized in Tables 3-4 and 3-6 for the annual average capacity factor (monthly maximum) firing rate case and in Tables 3-5 and 3-7 for the daily maximum emissions case.. Modeling was performed for Cases A – P and these results are reported in Appendix 1. Cost anal ysis was not performed on all these options. Cost analysis was performed on a subset of the options to reflect a range in removal efficiency and a judgment on the viability of the option. Cost data is presented for options C, E, F, H, J, K, M, O, and P

Observations about the data disp layed in these tables are:

1. For the data modeled at the annual aver age capacity factor (monthly maximum) firing rate, the $/ton of SO 2 

# removed ranges from $1039/ton to $4547/ton. For the lowest cost/ton an improvement of 0.254 dV is predicted for the 98 th 

# percentile value. In terms of the percent contri bution to Mammoth Cave (as measured by the percent of the current 20 % highest da y value), the percentage contribution is reduced by in increment of 0.8 %. In terms of a percent change in light extinction, 0.254 dV corresponds to a 2.5 % improvement in light extinction.

### Date: September 18, 2007 Page 18 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# This is the maximum improvement that is predicted. The percent change in light extinction is not perc eptible since it’s less than a 5 % change. 2. For the data modeled at the daily maximum firing rate, the $/ton of SO 2 

# removed ranges from $897/ton to $4031/ton. For the lowest cost/ton an improvement of 0.349 dV is predicted for the 98 th 

# percentile value. In terms of the percent contribution to Mammoth Cave (as measur ed by the percent of the current 20 % highest day value), the percentage contribution is reduced by in increment of 1.1 %. In terms of a percent change in light extinction, 0.349 dV corresponds to a 3.5 % improvement in light extinction. This is the maximum improvement that is predicted. The percent change in light exti nction is not perceptible since it’s less than a 5 % change. These data were m odeled at the maximum daily firing rate, which, in our view is ultra conservative and overstates both th e reductions and the magnitude of the possible visibility impact.

3. For the data modeled at the annual aver age capacity factor (monthly maximum) firing rate, the maximum dV reduction capable of being achieved for the 98 th


# percentile day is predicted to be 0.507 dV. This corresponds to an incremental improvement in the percent contribution to the current 20 % highest day value of 1.6%. In light extinction terms, this corresponds to a 5.1 % improvement. This is the maximum improvement predicted and as is noted would only be predicted to be achieved roughly 14 days of the year. This reduction is achievable at a cost of
$3289/ton of SO 2



# . 4. For the data modeled at the daily maximum emissions, the maximum dV reduction capable of being achieved for the 98 th 

# percentile day is predicted to be 0.657 dV. This corresponds to an incr emental improvement in the percent contribution to the current 20 % highest day value of 2.1 %. In light extinction terms, this corresponds to a 6.6 % improvement. This is the maximum improvement predicted and, as is noted, w ould only be predicted to be achieved roughly 30 days of the year. This reducti on is achievable at a cost of $2635/ton of

SO 2’ 

# 5. NOx reductions for the data modeled at both the daily maximum and the annual average capacity factor (monthly maximu m) firing rates are not predicted to achieve significant improvements in visi bility impairment. For the annual average capacity factor (monthly maximu m) data, the maximum case evaluated reduces visibility impairment by 0.131 dV for the 98 th 

# percentile day which corresponds to an incremen tal percent improvement of the current 20% highest day value of 0.4 %. In light extinction terms, a 0.13 dV change corresponds to a 1.3 % change in light extinction which is below the perception limit of 5 %. For the daily maximum firing rate data, a 0.13 dV change and 0.4 % of the 20 % highest day value is noted.

In terms of the significance of the cost of control numbers and the reductions achieved, the Clean Air Interstate Rule (CAIR) set em ission caps at cost levels corresponding to roughly $1700/ton for NOx and $1800/ton for SO 2 

# . For NOx, some of the alternatives in this study are estimated to be less than $1700/ton however the improvement achieved is very minor ranging from 0.09 to 0.4 incremental percent improvements or 0.059 to 0.073

### Date: September 18, 2007 Page 19 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# dV improvement on the 98 th 

# percentile day. In light extinction terms, these improvements correspond to a 0.6 to 0.7 % reduction in light extinction.

For SO 2 

# , only one of the options is less than $1800/ton for the annual average capacity factor (monthly maximum) firing rate data. Two options are less than $1800/ton for the daily maximum firing rate data. For these options an incrementa l percent improvement (as a percent of the current 20 % worst days) ranges from 0.5 to 1.1 %. In light extinction terms, the change ranges from 0.15 to 0.349 dV which corresponds to a percent improvement ranging from 1.5 to 3.5 % which is below the perception limit of 5 %.

Given that 64 % of the yearly day counts greater than 0.5 dV ar e predicted to occur between June and November, the modeling re quirement to assess the impacts at daily maximum firing rates assumed to occur through out the year is overl y conservative. The

emission rates in the summer are much le ss (as much as 50 %), thus the actual improvements achieved will be less than t hose predicted by this modeling effort.

### Date: September 18, 2007 Page 20 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



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### Date: September 18, 2007 Page 21 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 4 Conclusions

To summarize, while control options for the DuPont boilers at the Old Hickory Plant can reduce the visibility impairment at Mammo th Cave, the incremental improvements are small as measured by the percent of the 20 % wo rst days visibility at Mammoth Cave. In general, the $/ton controlled values are greate r than the CAIR $/ton values. CAIR level

controls are declared BART level controls by the EPA in their rulemaking package.

In addition, modeling for all periods of th e year represented by the highest daily

emissions rate conditions includes com pounded conservatism that grossly overstates visibility impact compared to actual bo iler operation during the course of the year.

Based on this analysis, DuPont believes th at our overall visibility contribution to Mammoth Cave is minor and incremental improve ments, while possible, are very small. We do not believe these improve ments are cost effective.

We, therefore, are proposing the status quo ( no changes) as BART for the boilers at DuPont’s Old Hickory Plant. .Date: September 18, 2007Page 22 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 3-4 - Summary of the Control ScenarioVisibility & Cost Impacts @ Annual AverageCapacityFactor(MonthlyMaximum)RateandAverageCoalQualityCase DescriptionExpectedEmissionrateExpectedEmissionRateTotal Annualizedcost of controlTonsRemovedAverage costEffectivenessGreatestChange inModelled98 % dayfrombaseline%Change inLightextinction% of 31.37dV (thestartingpoint for theMammothCave GlidePath)Incremental %Improvementof % visibilityImpact as a %of 31.17 dVSO2CasesT/yr lb/hr$t/yr $/ton removed dV % %%A. Baseline Case Using Current Coal5,223 1,1920.679 6.79 2.16F. 1.5% Sulfur Coal with No Scrubbing4,451 1,016 $1,561,889 772 $2,023 -0.082 0.82 1.920.25K. 1.0% Sulfur Coal with No Scrubbing2,968 678 $2,342,834 2,255 $1,039 -0.254 2.54 1.360.80E. Current Coal with Sodium Wet Scrubber onBoiler 20 Only1,007 230 $13,543,003 4,216 $3,212 -0.431 4.31 0.801.37J. 1.5% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only858 196 $10,280,090 4,365 $2,355 -0.452 4.52 0.731.44O. 1.0% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only572 131 $11,085,953 4,651 $2,384 -0.469 4.69 0.671.49C. Current Coal with Sodium Wet Scrubber onBoth Boilers 20 & 24261 60 $22,560,847 4,962 $4,547 -0.497 4.97 0.581.58H. 1.5% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 24223 51 $15,880,219 5,000 $3,176 -0.499 4.99 0.581.59M. 1.0% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 24148 34 $16,690,492 5,075 $3,289 -0.507 5.07 0.551.61P. Current Coal with 50% Natural Gas Cofiringon Both Boilers2,611 596 $11,561,886 2,612 $4,426 -0.284 2.84 1.270.90NOx CasesA. Baseline Case Using Current Coal1,002 2290.679 6.79 2.16D1. LNB on Boiler 20 Only664 152$548,242 338 $1,622 -0.059 0.59 1.990.18D2. SNCR on Boiler 20 Only664 152$748,051 338 $2,213 -0.059 0.59 1.990.18B1. LNB on Both Boilers 20 & 24601 137$938,886 401 $2,341 -0.073 0.73 1.940.22B2. SNCR on Both Boilers 20 & 24601 137$995,834 401 $2,483 -0.073 0.73 1.940.22E. LNB Plus SCR on Boiler 20 Only259 59$3,024,491 743 $4,071 -0.127 1.27 1.770.39C. LNB Plus SCR on Both Boilers 20 & 24120 27$5,303,771 882 $6,013 -0.131 1.31 1.760.41B3 Current Coal with 50% Natural GasCofiringon Both Boilers601 137 $11,561,886 401 $28,865 -0.284 2.84 1.270.90Date: September 18, 2007Page 23 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 3-5 - Summary of the Control ScenarioVisibility & Cost Impacts @ Daily MaximumEmission Rate and Highest Day Coal QualityCase DescriptionExpectedEmissionrateExpectedEmissionRateTotal Annualizedcost of controlTonsRemovedAverage costEffectivenessGreatestChange inModelled98 % dayfrombaseline%Change inLightextinction% of 31.37dV (thestartingpoint for theMammothCave GlidePath)Incremental %Improvementof % visibilityImpact as a %of 31.17 dVSO2CasesT/yr lb/hr$t/yr $/ton removed dV % %%A. Baseline Case Using Current Coal7,040 1,6070.929 9.29 2.96F. 1.5% Sulfur Coal with No Scrubbing5,617 1,282 $1,970,962 1,423 $1,385 -0.15 1.5 2.500.46K. 1.0% Sulfur Coal with No Scrubbing3,745 855 $2,956,443 3,295 $897 -0.349 3.49 1.861.10E. Current Coal with Sodium Wet Scrubber onBoiler 20 Only1,690 386 $14,222,449 5,351 $2,658 -0.508 5.08 1.351.61J. 1.5% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only1,348 308 $11,196,391 5,692 $1,967 -0.532 5.32 1.271.69O. 1.0% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only899 205 $12,211,479 6,142 $1,988 -0.597 5.97 1.071.90C. Current Coal with Sodium Wet Scrubber onBoth Boilers 20 & 24352 80 $23,566,812 6,688 $3,524 -0.624 6.24 0.981.98H. 1.5% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 24281 64 $17,033,708 6,759 $2,520 -0.638 6.38 0.932.03M. 1.0% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 24187 43 $18,056,198 6,853 $2,635 -0.657 6.57 0.872.09P. Current Coal with 50% Natural Gas Cofiringon Both Boilers3,520 804 $14,190,215 3,520 $4,031 -0.369 3.69 1.801.16NOx CasesA. Baseline Case Using Current Coal1,233 2820.929 9.29 2.96D1. LNB on Boiler 20 Only843 192$572,769 391 $1,466 -0.033 0.33 2.870.09D2. SNCR on Boiler 20 Only843 192$821,184 391 $2,102 -0.033 0.33 2.870.09B1. LNB on Both Boilers 20 & 24740 169$963,413 493 $1,953 -0.055 0.55 2.800.16B2. SNCR on Both Boilers 20 & 24740 169 $1,105,732 493 $2,241 -0.055 0.55 2.800.16E. LNB Plus SCR on Boiler 20 Only374 85$2,904,607 859 $3,380 -0.13 1.3 2.560.40C. LNB Plus SCR on Both Boilers 20 & 24148 34$5,081,539 1,085 $4,682 -0.178 1.78 2.410.55B3 Current Coal with 50% Natural GasCofiringon Both Boilers740 169 $14,190,215 493 $28,759 -0.369 3.69 1.801.16Date: September 18, 2007Page 24 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 3–6 Summary - Baseline Visibility Modeling Results @ Annual Average Capacity Factor(Monthly Maximum)RatesModeled 98thperentile Value(dV)No Daysexceeding 0.5dVModeled 98thperentile Value(dV)No Daysexceeding 0.5dVModeled 98thperentile Value(dV)No Daysexceeding 0.5dVModeled 98thperentile Value(dV)No Daysexceeding 0.5dVSO2CasesA. Baseline Case Using Current Coal0.647160.658120.679150.64743F. 1.5% Sulfur Coal with No Scrubbing0.568110.57690.607120.56732K. 1.0% Sulfur Coal with No Scrubbing0.39310.42360.45530.40810E. Current Coal with Sodium WetScrubber on Boiler 20 Only0.23100.23110.24800.295 1J. 1.5% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only0.21900.22100.22700.271 0O. 1.0% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only0.1900.19700.2100.1930C. Current Coal with Sodium WetScrubber on Both Boilers 20 & 240.1700.19200.18200.2360H. 1.5% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 240.16400.18800.1800.2330M. 1.0% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 240.15100.18100.17200.165 0P. Current Coal with 50% Natural GasCofiring on Both Boilers0.36310.40240.43720.371 7NOx CasesA. Baseline Case Using Current Coal0.647160.658120.679150.64743D1. LNB on Boiler 20 Only0.637160.599120.654150.80643D2. SNCR on Boiler 20 Only0.637160.599120.654150.80643B1. LNB on Both Boilers 20 & 240.637160.585110.654150.80542B2. SNCR on Both Boilers 20 & 240.637160.585110.654150.80542E. LNB Plus SCR on Boiler 20 Only0.604150.531100.65150.79740C. LNB Plus SCR on Both Boilers 20 & 240.594150.52790.644130.79437B3 Current Coal with 50% Natural GasCofiring on Both Boilers0.36310.40240.43720.371 72001 - 20032001Case Description20022003Date: September 18, 2007Page 25 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 3–7 Summary - Baseline VisibilityModeling Results @ Daily Maximum RatesModeled 98thperentile Value(dV)No Daysexceeding 0.5dVModeled 98thperentile Value(dV)No Daysexceeding 0.5dVModeled 98thperentile Value(dV)No Daysexceeding 0.5dVModeled 98thperentile Value(dV)No Daysexceeding 0.5dVSO2CasesA. Baseline Case Using Current Coal0.87350.898280.929270.86791F. 1.5% Sulfur Coal with No Scrubbing0.72280.749210.792220.74171K. 1.0% Sulfur Coal with No Scrubbing0.521100.549110.599120.52633E. Current Coal with Sodium WetScrubber on Boiler 20 Only0.37400.3930.43920.4865J. 1.5% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only0.33800.36720.39810.4453O. 1.0% Sulfur Coal with Sodium WetScrubber on Boiler 20 Only0.28800.32920.33210.3213C. Current Coal with Sodium WetScrubber on Both Boilers 20 & 240.2700.31310.30500.3571H. 1.5% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 240.25800.30410.29100.3491M. 1.0% Sulfur Coal with Sodium WetScrubber on Both Boilers 20 & 240.24200.28310.27200.2531P. Current Coal with 50% Natural GasCofiring on Both Boilers0.50180.564110.605110.52230NOx CasesA. Baseline Case Using Current Coal0.87350.898280.929270.86791D1. LNB on Boiler 20 Only0.865330.865260.917271.13186D2. SNCR on Boiler 20 Only0.865330.865260.917271.13186B1. LNB on Both Boilers 20 & 240.849330.843260.917261.12485B2. SNCR on Both Boilers 20 & 240.849330.843260.917261.12485E. LNB Plus SCR on Boiler 20 Only0.841320.768230.902251.10180C. LNB Plus SCR on Both Boilers 20 & 240.836300.72220.89231.08675B3 Current Coal with 50% Natural GasCofiring on Both Boilers0.50180.564110.605110.522302001 - 20032001Case Description20022003

### Date: September 18, 2007 Page 26 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN 

# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate

2001 2002 2003 2001 2002 2003



### SO2 Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV

A. Baseline Case Usin g Current Coal 1 1.156 2.063 1.943 0.729 0.797 0.832

2 1.026 1.448 1.427

3 0.973 1.416 1.159

4 0.94 1.265 1.098

5 0.93 1.086 1.012

6 0.915 0.946 0.977

7 0.888 0.926 0.933

8 0.87 0.898 0.929

9 0.85 0.772 0.92

10 0.848 0.742 0.867

11 0.819 0.735 0.853

12 0.761 0.734 0.813

13 0.737 0.731 0.779

14 0.724 0.728 0.769

15 0.711 0.688 0.744

16 0.704 0.658 0.668

17 0.692 0.63 0.662

18 0.689 0.621 0.662

19 0.689 0.61 0.657

20 0.686 0.597 0.604

21 0.674 0.572 0.602

22 0.647 0.568 0.6

23 0.618 0.557 0.594

24 0.597 0.553 0.575

25 0.592 0.531 0.553

26 0.591 0.523 0.543

27 0.588 0.513 0.519

28 0.584 0.504

29 0.574 0.5

30 0.569

31 0.568

32 0.568

33 0.511

34 0.506

F. 1.5% Sulfur Coal with No Scrubbin g 1 0.977 1.741 1.636 0.769 0.921 0.907

2 0.865 1.21 1.187

3 0.833 1.175 0.972

4 0.817 1.053 0.924

5 0.755 0.893 0.83

6 0.754 0.86 0.825

7 0.748 0.787 0.807

8 0.72 0.749 0.792

9 0.716 0.665 0.754

10 0.701 0.656 0.75

11 0.696 0.64 0.741

12 0.648 0.624 0.668

13 0.606 0.62 0.659

14 0.603 0.614 0.63

15 0.599 0.604 0.622

16 0.585 0.563 0.6

17 0.574 0.526 0.584

18 0.568 0.522 0.571

19 0.564 0.514 0.549

20 0.561 0.51 0.544

21 0.558 0.506 0.51

22 0.536 0.5 0.504

23 0.529

24 0.522

25 0.514

26 0.507

27 0.505

28 0.502

### Date: September 18, 2007 Page 27 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN 

# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate Cont’d)

2001 2002 2003 2001 2002 2003



### SO2 Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV
K. 1.0% Sulfur Coal with No Scrubbin g 1 0.729 1.295 1.214 0.601 0.786 0.741

2 0.648 0.881 0.856

3 0.64 0.842 0.714

4 0.634 0.761 0.681

5 0.568 0.734 0.633

6 0.544 0.629 0.619

7 0.526 0.598 0.615

8 0.521 0.549 0.599

E. Current Coal with Sodium Wet

Scrubber on Boiler 20 Onl y 1 0.486 0.827 0.737 0.425 0.534 0.503

2 0.478 0.648 0.518

3 0.461 0.553 0.499

4 0.43 0.497 0.468

5 0.393 0.479 0.463

6 0.39 0.47 0.453

7 0.385 0.404 0.448

8 0.374 0.39 0.439

J. 1.5% Sulfur Coal with Sodium Wet

Scrubber on Boiler 20 Onl y 1 0.445 0.734 0.654 0.391 0.484 0.456

2 0.436 0.621 0.47

3 0.42 0.485 0.453

4 0.384 0.456 0.433

5 0.377 0.43 0.429

6 0.372 0.41 0.41

7 0.353 0.368 0.404

8 0.338 0.367 0.398

O. 1.0% Sulfur Coal with Sodium Wet

Scrubber on Boiler 20 Onl y 1 0.398 0.604 0.542 0.339 0.414 0.390

2 0.362 0.573 0.424

3 0.355 0.415 0.395

4 0.35 0.387 0.381

5 0.347 0.335 0.359

6 0.315 0.335 0.356

7 0.298 0.334 0.333

8 0.288 0.329 0.332

C. Current Coal with Sodium Wet

Scrubber on Both Boilers 20 & 24 1 0.357 0.573 0.421 0.316 0.387 0.361

2 0.354 0.473 0.405

3 0.347 0.415 0.394

4 0.33 0.342 0.359

5 0.307 0.332 0.343

6 0.286 0.33 0.339

7 0.274 0.319 0.324

8 0.27 0.313 0.305

### Date: September 18, 2007 Page 28 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate Cont’d)

2001 2002 2003 2001 2002 2003



### SO2 Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV
H. 1.5% Sulfur Coal with Sodium Wet

Scrubber on Both Boilers 20 & 24 1 0.349 0.562 0.401 0.306 0.377 0.351

2 0.347 0.45 0.395

3 0.34 0.405 0.386

4 0.315 0.333 0.351

5 0.293 0.325 0.333

6 0.281 0.322 0.332

7 0.268 0.313 0.316

8 0.258 0.304 0.291

M. 1.0% Sulfur Coal with Sodium Wet

Scrubber on Both Boilers 20 & 24 1 0.334 0.533 0.373 0.288 0.354 0.330

2 0.33 0.413 0.372

3 0.325 0.381 0.367

4 0.285 0.311 0.33

5 0.269 0.308 0.314

6 0.267 0.301 0.314

7 0.253 0.298 0.296

8 0.242 0.283 0.272

P. Current Coal with 50% Natural Gas

Cofirin g on Both Boilers 1 0.719 1.258 1.172 0.594 0.774 0.731

2 0.64 0.861 0.836

3 0.638 0.82 0.705

4 0.636 0.752 0.677

5 0.565 0.744 0.627

6 0.534 0.609 0.62

7 0.519 0.586 0.606

8 0.501 0.564 0.605

### Date: September 18, 2007 Page 29 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate Cont’d)

2001 2002 2003 2001 2002 2003



### NOx Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV
D1. LNB on Boiler 20 Onl y 1 1.131 2.006 1.876 0.724 0.808 0.810

2 1.017 1.432 1.419

3 0.963 1.408 1.149

4 0.93 1.255 1.091

5 0.913 1.084 1.008

6 0.869 0.887 0.94

7 0.868 0.886 0.925

8 0.865 0.865 0.917

9 0.846 0.748 0.881

10 0.817 0.731 0.846

11 0.792 0.727 0.812

12 0.743 0.718 0.795

13 0.736 0.685 0.765

14 0.72 0.681 0.748

15 0.706 0.658 0.715

16 0.704 0.644 0.656

17 0.689 0.629 0.636

18 0.688 0.594 0.633

19 0.686 0.594 0.604

20 0.68 0.592 0.603

21 0.668 0.567 0.59

22 0.646 0.552 0.584

23 0.604 0.527 0.572

24 0.589 0.521 0.56

25 0.586 0.513 0.519

26 0.58 0.512 0.518

27 0.575 0.503

28 0.573

29 0.557

30 0.552

31 0.548

32 0.547

33 0.516

D2. SNCR on Boiler 20 Onl y 1 1.131 2.006 1.876 0.724 0.808 0.810

2 1.017 1.432 1.419

3 0.963 1.408 1.149

4 0.93 1.255 1.091

5 0.913 1.084 1.008

6 0.869 0.887 0.94

7 0.868 0.886 0.925

8 0.865 0.865 0.917

9 0.846 0.748 0.881

10 0.817 0.731 0.846

11 0.792 0.727 0.812

12 0.743 0.718 0.795

13 0.736 0.685 0.765

14 0.72 0.681 0.748

15 0.706 0.658 0.715

16 0.704 0.644 0.656

17 0.689 0.629 0.636

18 0.688 0.594 0.633

19 0.686 0.594 0.604

20 0.68 0.592 0.603

21 0.668 0.567 0.59

22 0.646 0.552 0.584

23 0.604 0.527 0.572

24 0.589 0.521 0.56

25 0.586 0.513 0.519

26 0.58 0.512 0.518

27 0.575 0.503

28 0.573

29 0.557

30 0.552

31 0.548

32 0.547

33 0.516 

# Note: Baseline Case A using current coal list ing is provided at the beginning of Table 3-8

### Date: September 18, 2007 Page 30 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate Cont’d)

2001 2002 2003 2001 2002 2003



### NOx Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV
B1. LNB on Both Boilers 20 & 24 1 1.124 1.99 1.859 0.720 0.802 0.816

2 1.015 1.427 1.417

3 0.96 1.406 1.146

4 0.929 1.252 1.089

5 0.913 1.084 1.008

6 0.864 0.885 0.931

7 0.864 0.875 0.924

8 0.849 0.843 0.917

9 0.845 0.741 0.866

10 0.807 0.728 0.841

11 0.784 0.725 0.811

12 0.738 0.715 0.778

13 0.735 0.671 0.764

14 0.719 0.667 0.74

15 0.705 0.65 0.708

16 0.704 0.641 0.654

17 0.689 0.629 0.627

18 0.688 0.594 0.626

19 0.686 0.587 0.603

20 0.678 0.587 0.589

21 0.666 0.566 0.588

22 0.646 0.551 0.579

23 0.603 0.518 0.571

24 0.587 0.51 0.55

25 0.585 0.507 0.518

26 0.577 0.507 0.51

27 0.569

28 0.562

29 0.555

30 0.549

31 0.543

32 0.535

33 0.501

### Date: September 18, 2007 Page 31 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate Cont’d)

2001 2002 2003 2001 2002 2003



### NOx Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV
B2. SNCR on Both Boilers 20 & 24 1 1.124 1.99 1.859 0.720 0.802 0.816

2 1.015 1.427 1.417

3 0.96 1.406 1.146

4 0.929 1.252 1.089

5 0.913 1.084 1.008

6 0.864 0.885 0.931

7 0.864 0.875 0.924

8 0.849 0.843 0.917

9 0.845 0.741 0.866

10 0.807 0.728 0.841

11 0.784 0.725 0.811

12 0.738 0.715 0.778

13 0.735 0.671 0.764

14 0.719 0.667 0.74

15 0.705 0.65 0.708

16 0.704 0.641 0.654

17 0.689 0.629 0.627

18 0.688 0.594 0.626

19 0.686 0.587 0.603

20 0.678 0.587 0.589

21 0.666 0.566 0.588

22 0.646 0.551 0.579

23 0.603 0.518 0.571

24 0.587 0.51 0.55

25 0.585 0.507 0.518

26 0.577 0.507 0.51

27 0.569

28 0.562

29 0.555

30 0.549

31 0.543

32 0.535

33 0.501

E. LNB Plus SCR on Boiler 20 Onl y 1 1.101 1.938 1.795 0.715 0.821 0.809

2 1.007 1.413 1.409

3 0.95 1.4 1.137

4 0.929 1.242 1.082

5 0.911 1.082 1.004

6 0.86 0.875 0.921

7 0.846 0.838 0.914

8 0.841 0.768 0.902

9 0.782 0.719 0.821

10 0.78 0.717 0.819

11 0.758 0.717 0.81

12 0.735 0.704 0.76

13 0.721 0.628 0.725

14 0.716 0.628 0.71

15 0.704 0.626 0.681

16 0.701 0.623 0.649

17 0.687 0.623 0.604

18 0.686 0.591 0.602

19 0.685 0.571 0.598

20 0.67 0.562 0.585

21 0.661 0.561 0.568

22 0.644 0.55 0.563

23 0.601 0.502 0.533

24 0.58 0.517

25 0.58 0.512

26 0.566

27 0.555

28 0.545

29 0.534

30 0.524

31 0.523

32 0.502

### Date: September 18, 2007 Page 32 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 3–8 Summary Listing- Values > 0. 5 dV @ Daily Maximum Firing Rate Cont’d)

2001 2002 2003 2001 2002 2003



### NOx Cases Rank No Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV Average

Delta dV

Ranks 1 - 8

or > 0.5 dV
C. LNB Plus SCR on Both Boilers 20 & 24 1 1.086 1.903 1.757 0.722 0.822 0.823

2 1.001 1.403 1.405

3 0.944 1.395 1.131

4 0.929 1.236 1.077

5 0.91 1.081 1.003

6 0.857 0.869 0.919

7 0.838 0.814 0.913

8 0.836 0.72 0.89

9 0.758 0.712 0.809

10 0.742 0.711 0.809

11 0.739 0.703 0.785

12 0.734 0.697 0.758

13 0.714 0.628 0.692

14 0.709 0.62 0.688

15 0.704 0.604 0.664

16 0.698 0.596 0.645

17 0.686 0.594 0.602

18 0.685 0.59 0.59

19 0.684 0.561 0.583

20 0.665 0.559 0.577

21 0.657 0.549 0.566

22 0.643 0.547 0.551

23 0.6 0.516

24 0.578

25 0.575

26 0.558

27 0.547

28 0.539

29 0.525

30 0.511

### Date: September 18, 2007 Page 33 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 5 REFERENCES

1. Environmental Protection Agency, 2003: Guidance for Estimating Natural Visibility Conditions under the Regional Haze Rule . EPA-454/B-03-005. U.S. Environmental Protection Agency, Research Triangle Park, NC 2. E. I. DuPont de Nemours, & Co., “B ART Phase 2 Exemption Modeling Analysis

for the E. I. DuPont de Nemours & Company Old Hickory Plant”, February 12,

2007. 3. E. I. DuPont de Nemours, & Co., “Protocol for BART Phase 2 Exemption Modeling for the E. I. DuPont de Nemours & Company Old Hickory Plant, June 27, 2006 4. E. I. DuPont de Nemours, & Co., “Res ults of BART Modeling and Engineering Analysis for E. I. DuPont de Nemour s & Company Old Hickory Plant, April 4,

2007. 5. VISTAS (Visibility Improvement and Trib al Associations of the Southeast). “Protocol for the Application of the CALPUFF Model for Analyses of Best Available Retrofit Technology (BART) ” December 22, 2005, revised March 9,

2006

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# This page intentionally left blank.

### Date: September 18, 2007 Page 35 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# DuPont Research and Engineering Technology



# 6 Appendix 1 - BART Control Strategy Modeling Analysis

For

E. I. duPont de Nemours and Company Old Hickory Plant

1002 Industrial Road 

# Old Hickory, TN 37138

Prepared by:

Charles J. Zarzecki

DuPont Research and En gineering Technology
1007 Market Street Wilmington, DE 19898

### Date: September 18, 2007 Page 36 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 6.1 Introduction

The objectives of this modeling re port are to describe the methodol ogy that was used to assess the potential visibility impacts of various BART control strategies hypothetically implemented at the E. I. duPont de Nemours and Company Old Hic kory plant, located in Old Hickory, TN. This modeling analysis consisted of a base case modeling analysis conducte d at all of the Class 1 areas within 300 km of the Old Hickory Pl ant (see table below) to assess th e current impact on visibility. Subsequently, additional modeling of SO 2 

# and NO

x 

# control scenarios focused on the Mammoth Cave Class 1 area which showed the greatest impact from the Old Hickory BART eligible boilers. This visibility impact assessment was conducted fo r the BART eligible emission sources at the Old Hickory Plant. Two documents, the VISTAS BART modeling protocol (1) 

# , issued on December 22, 2005, and revised as of March 9, 2006, as well as the Protocol for BART Phase 2 Exemption Modeling (2) 

# submitted to TDEC on June 27, 2006 are also references used to establish the methodology used for the Old Hickory BART control strategy assessment. Additionally, on-going correspondence and meetings between DuPont and TDEC provided valuable guidance with the conduct of the modeling analyses.

The general location of the facility can be seen in Figure 6-1. The following sections describe the CALPUFF modeling methodology. S ection 2.2 presents the source – Class 1 area geometry. Section 2.3 presents the emissions inventory mode led in the analysis. The configuration of CALMET, CALPUFF, POSTUTIL, and CALPOST are described in Section 2.4, along with a discussion of the Class 1 receptor grid, part iculate matter speciation, and background light

extinction.



# 6.2 Source/Class I Area Geometry

The distances to the four Class 1 areas with in 300 km of the Old Hickory Plant are:

Class 1 Area Distance from Old Hickory – km Great Smokey Mountain Natl. Park 249 km Joyce Kilmer Slick Rock Wilderness Area 254 km

Cohutta Wilderness Area 233 km Sipsey Wilderness Area 220 km

Mammoth Cave Natl. Park 105 km

These distances are based on the distance from the Old Hickory stacks to the closest Class 1 area receptor. The actual receptor locations modeled with in each of these Class 1 areas were taken from the National Park Service (NPS), Air Resources Di vision website, which lists all of the modeling receptors for all of the Class 1 areas in the cont erminous U. S. Figure 6-1 shows these distances.

### Date: September 18, 2007 Page 37 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 6.3 Emissions Inventory

The following emission inventory information for th e BART-eligible sources at Old Hickory has been

assembled in order to conduct the air quality modeling:

1. Stack locations 2. Stack heights

3. Stack diameters 4. Stack gas exit temperatures 5. Stack gas flow rate or exit velocities 6. Detailed plant layout (p rovided in a scaled plot plan)

7. Emission rates

All of the “base case” stack parameters are pres ented in Table 6-1, which also shows the source representation for modeling purposes.

The modeled base case for this study represents the maximum daily coal firing rate for calendar year 2005. This is explained in further detail in Section 7.2.

In addition to the base case presented in Table 6-1, thirteen (13) other BART control cases were evaluated in this study. All of these control cases involved strate gies that either lowered the SO 2 

# emission rate or lowered the NO

x 

# emission rate. The SO 2 

# and NO

x 

# emission rates for all of these alternate cases (including the base case) are presented in Table 6-2.



# 6.4 Visibility Modeling Methodology

The modeling methodology employed for the DuPont Old Hickory Plant BART exemption analysis follows the methodology outline in the December 22, 2005 revision 2 (3/9/06) (1) 

# protocol prepared by VISTAS, as well as the Protocol for BART Phase 2 Exemption Modeling (2) 

# submitted by DuPont to TDEC on June 27, 2006. As such, the following description of the modeling methodology follows these documents very closely.

The version of the CALPUFF mode l used in this study is the VI STAS version of the CALPUFF model obtained from the TRC Atmospheric Studies Group (formerly EarthTech) web site ( http://www.src.com ). The version number is: Version 5.756. VISTAS used CALMET Version 5.7. in their CALMET simulations, and we used the out put files generated in that modeling as input

to CALPUFF. These versions contain enhancemen ts funded by the Minerals Management Service (MMS) and VISTAS.



# 6.4.1 CALMET Modeling Conf iguration (Subregional 4-km runs conducted by VISTAS and EarthTech (now TRC)

### Date: September 18, 2007 Page 38 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Earth Tech (now TRC), under contract to VISTAS , defined the CALMET model configurations for the regional CALMET simulations in collaboration with the VISTAS States. The basic model configuration followed the recommended IW AQM guidance (EPA, 1998; Pages A-1 through A6) (3) 

# , except as noted below.

The basic features of the CALMET mode ling simulation were the following:

• Modeling period: 3 years (2001-2003)

• CALMET grid resolution: 4-km (same Lambert Conformal coordinate system and grid cells as the 12-km 2001/2002 MM5 simulations)

• CALMET vertical layers: 10 layers. Cell face heights (meters): 0, 20, 40, 80, 160, 320, 640, 1200, 2000, 3000, 4000.

• CALMET mode: Hybrid mode – MM5 data used for initial guess field and meteorological observational data used in the step 2 calculations.

• Diagnostic options: IWAQM default values, exce pt as follows: diagnostic terrain blocking and slope flow algorithms used for 2003 si mulations (using 36-km MM5 data), but no diagnostic terrain adjustments in 2001 and 2002 simulation (using 12-km MM5 data) For the 4 km data, a domain specific set of m odeling parameters was defined for each sub regional domain. The details are discussed on p. 49 of the VISTAS modeling protocol. (4)



# • CALMET options dealing with radius of influence parameters (R1, R2, RMAX1, RMAX2, RMAX3), BIAS, ICALM parameters were used in the-Observations mode.

• TERRAD (terrain scale) is required for runs with diagnostic terrain adjustments (i.e., the 2003 simulations).

• Land use defining water: JWAT1 = 55, JWAT2 = 55 (large bodies of water). This feature allows the temperature field over large bodies of water such as the Atlantic Ocean and the Great lakes to be properly characterized by buoy observations.

• Mixing height averaging parameter (MNMDAV) was determined by Earth Tech (TRC) for the regional simulations based on sensitivity tests. The purpose of the testing was to optimize the variable to allow spatial variability in the mixi ng height field, but without

excessive noise.

• Geophysical data for regional runs: SRTM-G TOPO30 30-arcsec terrain data, Composite Theme Grid (CTG) USGS 200m land use data set. References for these and other

CALMET datasets can be found on the CALPUFF da ta page of the official CALPUFF site ( www.src.com)

.

### Date: September 18, 2007 Page 39 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 6.4.2 CALPUFF Modeling Configuration

The CALPUFF model configuration for the region al 4-km CALPUFF simulations followed the recommended IWAQM guidance (EPA, 1998; Pages B-1 through B-8) (5) 

# , except as noted below:

• Chemical mechanism: MESOPUFF II module.

• Pasquill-Gifford (PG) dispersion coefficients were used as per U. S. EPA guidance.

• All emissions data were characterized as per the VISTAS Modeli ng Protocol guidance (6) 

# on p. 43. For particulates, we used the speciation profile guidance provided from the VISTAS web site. The speciation pr ocedure is presented in section 2.4.2.1 below.

• Species modeled: SO 2 

# , SO 4 

# , NO

x 

# , HNO 3 

# , NO 3 

# and particulate matter.

• CALPUFF domain was configured to include the source and all Class I areas within 300km of the source plus 50km buffer zone in each di rection. The rectangular modeling domain shown in Figure 6-3 was used in the modeling analysis . This modeling domain is a subset of the VISTAS 4-km Subdomain #3, which is also shown in its entirety in Figu re 6-3. The east-west dimension of this modeling domain is approxi mately 490 km and the north-south dimension is approximately 430 km. The National Park Service (NPS) Class 1 receptor list was used as per VISTAS Modeling Protocol Guidance at p. 45 for all of the Class 1 receptors modeled. These receptor sets are discusse d in Section 2.4.2.2 below.

• Base case emission rate s were modeled at the maximum 24 hour coal firing rate for 2005. Emission rates for the other 13 cases vary as sh own in Table 6-2. Emission rate speciation and particle size data was estimated using the VISTAS spreadsheets for tangentially fired pulverized coal fired boilers equipped with an ESP.

• Excluded from the modeling are pollutants w ith plant-wide emissions less than de minimis levels (40 tons per year for SO 2 

# and NOx and 15 tons per year for PM10). De minimis levels are plant wide for each visibility-impairing pollutant, so individual units may be modeled even if they have emissions below de minimis if the plant total is greater than de minimis

.

• Ozone dataset: We used observed ozone data for 2001-2003 from CASTNet and AIRS stations. Only non-urban ozone stations were used in the OZONE.DAT file. Monthly average ozone (backup) background values were co mputed based on daytime average ozone concentrations from the OZONE.DAT file (6am -6pm average ozone concentrations computed by month).

• Background ammonia concentration: In CALPUFF, we used a constant (0.5 ppb) value for

ammonia.

• Puff representation, integrat ed puff sampling methodology.

### Date: September 18, 2007 Page 40 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# • The puff splitting option was enabled in the model.

• Building downwash: Building downwash was not impl emented since the nearest Class 1 area is greater than 50-km from the Old Hickory Plant.

6.4.2.1 Particulat e Matter Speciation

Particulate matter in si ze categories of <0.625 μ m, 0.625-1.0 μ m, 1.0-1.25 μ m, 1.25-2.5 μ m, 2.5-6.0

μ m and 6-10 μ m aerodynamic diameters were considered in the CALPUFF modeli ng. Initially, all of these particle size categories were modeled with unit emission rates. The particulate matter emissions by size category were combined into the appropriate species for the visibility analysis (i.e., elemental carbon (EC), fine pa rticulate matter or “soil” (< 2.5 μ m in diameter), coarse particulate matter (PMC) (between 2.5-10 μ m in diameter) and organi cs (OC) in the CALPOST postprocessor).

The methodology is better understood by referring to Tables 6-3 and 6-4, which are used for the

1.88% sulfur coal cases. As stat ed, the particulate size categories were initially modeled with 1.0 lb/hr emission rates. Then by referring to Table 6-3 (which is from the NPS at www2.nature.nps.gov/air/permits/ect/ectCoalFiredBoiler , and is derived from AP-42), the breakdown of particles in the specif ic size categories of interest can be determined. The proportion of particles in size categories necessary to assess visibility impacts is presented in Table 6-4 (from the same NPS website, based on AP-42). Using th is information, the calculations presented in Table 6-9 are made, resulting in particle size ca tegories corresponding to th e appropriate categories for the visibility analysis. All of this info rmation is input into CALPUFF’s POSTUTIL postprocessor, which re-apportions the particulate impacts among the four categories. CALPOST subsequently uses the POSTUTIL output to assess th e visibility statistics, as explained in Section

2.4.3 below.

The particulate matter speciation for the 1.5% sulfur coal cases are presen ted in Tables 6-5, 6-6, and 6-10. The particulate matter speciation for the 1.0% sulfur coal cases are presented in Table 6- 7, 6-8, and 6-11.

6.4.2.2 Receptor Grids

The Class 1 area receptor grids modeled in this analysis were obtained from the National Park Service (NPS) website (www2.nature.nps.gov/air/ Maps/Receptors), as recommended in the VISTAS Modeling Protocol document. This webs ite contains a database of modeling receptors

for all of the Class 1 areas in the conterminous U. S. The ground elevations of each of the receptors are also included. For this study, a tota l of 1507 receptors for the five Class 1 areas were obtained from this website. The receptors we re converted to the Lambert Conformal (LCC) coordinate system. The receptors grids can be seen in Figures 6-4 through 6-8.

### Date: September 18, 2007 Page 41 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 6.4.3 CALPOST and POSTUTIL Configuration

For post-processing, CALPOST Version 5.6393 was em ployed with the following configuration :

• Visibility Method 6 was used.

• Species considered in visibility analysis: SO 4, NO3, elemental carbon (EC), soil, coarse PM (PMC) and secondary or ganic aerosol (OC).

• Natural background light extinction: We used EPA values for 20% best days- Rayleigh scattering value: 10 Mm-1 (all Class I areas), with EPA Class I area-specific (centroid) monthly relative humidity (f(RH)) values. Th ese values are listed in the EPA publication “Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program” (7) 

# . The specific methodology used to assess background light extinction is presented in section 2.4.3.1 below.

• Light extinction efficiencies: We used default values as presented in the “Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) Phase I Report” (8)



# .

6.4.3.1 Background Light Extinction



# Background light extinction was evaluate d using the following relationship:

b back 

# = 10 * e HI/10



# Where HI is equal to the haze index, which is an annual average value. It is found in the EPA publication “Guidance for Estimating Natural Visi bility Conditions Under th e Regional Haze Rule (2003)” (7) 

# . For Mammoth Cave NP, HI = 3. 85 dv. Inserting this value into the above equation results

in b back 

# equaling 14.696 Mm -1 

# . If all of the background particul ates are conservative ly assumed to be SOIL, and the value of 10 Mm -1 

# is assumed for Rayleigh scatteri ng, then the relationship becomes:

B

B

back 

# = b ray 

# + b soil 

# , or

14.696 Mm -1 

# = 10 Mm -1 

# + b soil



# b soil 

# = 4.696 Mm -1



# Since the extinction effici ency for soil is 1 ug/m 3 

# /Mm -1 

# , b soil 

# becomes 4.696 ug/m 3 

# . This value is then

used in CALPOST. Th e values of f(RH) are listed in Table 6-12.

Detailed modeling input and output files are provided on CD’s, which comprise the Appendix to this modeling report.

### Date: September 18, 2007 Page 42 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 6.5 Modeling References

(1) VISTAS (Visibility Improvement and Tribal Asso ciations of the Southeas t). “Protocol for the Application of the CALPUFF Model for Analys es of Best Available Retrofit Technology (BART)” December 22, 2005, revised March 9, 2006.

(2) E. I. DuPont de Nemours, & Co., “Protocol for BART Phase 2 Exemption Modeling for the E. I. DuPont de Nemours & Company Old Hickory Plant, June 27, 2006

(3) U. S. EPA, Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2, Summary Report and Recommendation for Long Range Transport Impacts , EPA-454/R-98-019, December, 1998.

(4) VISTAS “Protocol for the Application of th e CALPUFF Model for Analyses of Best Available Retrofit Technology (BART)”, p. 49.

(5) U. S. EPA, IWAQM Phase 2, Summary Report a nd Recommendation for Long Range Transport Impacts, Pages B-1 through B-8.

(6) VISTAS “Protocol for the Application of th e CALPUFF Model for Analyses of Best Available Retrofit Technology (BART)”, p. 43.

(7) Environmental Protection Agency, 2003: Guidance for Estimating Natural Visibility Conditions under the Regional Haze Rule . EPA-454/B-03-005. U.S. Environmental Protection Agency, Research Triangle Park, NC.

(8) U. S. Forest Service, National Park Se rvice, U. S. Fish and Wildlife Service; Federal Land Managers’ Air Quality Related Valu es Workgroup (FLAG) Phase I Report , December, 2000.

### Date: September 18, 2007 Page 43 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 6-1 Old Hickory Emissions Parameters

Parameter Units Boiler 24 Boiler 20

Stack Stack

Stack Height ft 200 200

Base Elev. Ft above MSL 523 525

Diameter ft 7 9.5

Stack Flow Rate acfm 141886 180351 Exit Temp. Deg. F 365 348

Sulfur Content % 1.88 1.88 Annual Capacity % 20 80

SO 2 

## lb/hr 321 1286

PM 10 

## lb/hr 14.8 13.7

NO 2 

## lb/hr 59 223

SO 2 

## ton/yr 1408 5632

NO 2 

## ton/yr 257 977

### Date: September 18, 2007 Page 44 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 6-2 BART Control Cases



# CASE SO 2 

# Emissions NO

x 

# Emissions (lb/hr) (lb/hr)
SO 2 

# Cases:
A. Baseline 1.88% Coal 1607 282 C. 1.88% Coal, Wet Scrubber on Boilers 20 & 24 80 282 E. 1.88% Coal, Wet Scrubber on Boiler 20 Only 386 282 F. 1.5% Coal with No Scrubbing 1282 282 H. 1.5% Coal, Wet Scrubber on Boilers 20 & 24 64 282 J. 1.5% Coal, Wet Scrubber on Boiler 20 Only 308 282 K. 1.0% Coal with No Scrubbing 678 282 M. 1.0% Coal, Wet Scrubber on Boilers 20 & 24 43 282 O. 1.0% Coal, Wet Scrubber on Boiler 20 Only 205 282 P. 1.88% Coal with 50% Nat. Gas Co-firing Both

Boilers 804 282

NO

x 

# Cases: A. Baseline (same as SO 2 

# Case A above) 1607 282
B. LNB or SNCR on Boilers 20 & 24 1607 169
C. LNB Plus SCR on Boilers 20 & 24 1607 34 D. LNB or SNCR on Boiler 20 Only 1607 192 E. LNB Plus SCR on Boiler 20 Only 1607 85Date: September 18, 2007Page 45 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 6-3 PM Speciation Basis (1.88% Sulfur Coal)Controlled PM10 Speciation from AP-42 Tables 1.1-5 & 1.1-6Dry Bottom Boiler burning Pulverized Coal using only ESP for Emissions controlassumes heating value of11428Btu/lb and a sulfur content of1.88% and an ash content of8% and f(RH) =1Controlled PM10 Emissions(Boldvalues from Table 1.1-5.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/ton) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB 0.1769 0.0189 0.0105 0.6 0.0084 0.0081 1 0.00031 100.1580.126SO4 3*f(RH)0.032Controlled PM10 Emissions(BoldValues from Table 1.1-6.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/ton) (lb/ton) (lb/ton) Coef. (lb/ton) (lb/ton) Coef. (lb/ton) Coef. (lb/ton) (lb/ton) Type Ext.Coef. (lb/ton)PC-DB 4.0430.4320.240 0.60.1920.185 1 0.0071 10 3.6112.889 SO4 3*f(RH) 0.722Controlled PM10 EmissionsBoiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (% of Total) (% of Total) (% of Total) Coef. (% of Total) (% of Total) Coef. (% of Total) Coef. (% of Total) (% of Total) Type Ext.Coef. (% of Total)PC-DB 100% 10.7% 5.9% 0.6 4.7%4.6% 1 0.2% 10 89.3% 71.5% SO4 3*f(RH) 17.9%If you are given Total PM10 emissions in lb/hr:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr)(lb/hr) Type Ext.Coef. (lb/hr)PC-DB14.81.60.9 0.6 0.70.7 1 0.0 10 13.210.6 SO4 32.6Weighted Extinction 0.50.70.331.7If you are given Total PM10 emissions in lb/mmBtu:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB0.100.01 0.01 0.6 0.000.00 1 0.0002 10 0.090.07 SO4 30.02If you are given Filterable PM10 emissions:Controlled PM10 Emissions(Boldvalues from Table 1.1-5 and from Table 6 of EPA’s January 2002 DRAFT “Catalog of Global Emissions Inventories and Emission Inventory Tools for BlackBoiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (% of Total) (% of Total) (% of Filterable) Coef. (% of Filterable) (% of Filterable) 1 (% of Filterable) Coef. (% of Total) (% of Condensible) Type Ext.Coef. (% of Condensible)PC-DB 100% 10.7% 55.6% 0.6 44.4% 42.8% 1 1.6% 10 89.3%80.0%SO4 320.0%(% of Fine) Coef. (% of Fine) Coef.96.3% 13.7%10If you are given Filterable PM10 emissions in lb/hr:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr)(lb/hr) Type Ext.Coef. (lb/hr)PC-DB 14.81.60.9 0.6 0.70.7 1 0.0 10 13.210.6 SO4 32.6If you are given Filterable PM10 emissions in lb/mmBtu:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB 0.100.010.01 0.6 0.000.00 1 0.0002 10 0.090.07 SO4 30.02Date: September 18, 2007Page 46 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 6-4 – PM Particle SizeBasis (1.88% Sulfur Coal)PC with ESPfrom AP-42 Table 1.1-6(User inputsfilterableemission rate in lb/hr)Particle Cumulative Mass Fraction of PM10 Particle EmissionsSize < Stated Size < Stated Size Size Range in Size Range(um)ESP(%)(um)(lb/hr)1067%100% 10-60.4650%75% 6-2.50.52.529%43% 2.5-1.250.31.2517%25% 1.25-1.00.1114%21% 1.0-6250.00.62512%18% 0.625-00.3CALPUFFParticle Particle Fraction Emissions Extinction EmissionsSize Size Range of PM10 in Size Range Coef. in Size Range(um) (um)(%)(lb/hr)(g/sec)8 10-625%0.40.60.054.25 6-2.531%0.50.60.06 57% Coarse >/= 2.5 micron1.88 2.5-1.2518%0.310.04 43% Fine Soil </= 2.5 micron1.251.25-14%0.110.010.813 1.6-253%0.010.010.6250.625-018%0.310.03100%1.6100.00 3.7% of Fine Soil0.20Date: September 18, 2007Page 47 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 6-5 PM Speciation Basis (1.5% Sulfur Coal)Controlled PM10 Speciation from AP-42 Tables 1.1-5 & 1.1-6Dry Bottom Boiler burning Pulverized Coal using only ESP for Emissions controlassumes heating value of11428Btu/lb and a sulfur content of1.5% and an ash content of8% and f(RH) =1Controlled PM10 Emissions(Boldvalues from Table 1.1-5.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/ton) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB 0.1389 0.0189 0.0105 0.6 0.0084 0.0081 1 0.00031 100.1200.096SO4 3*f(RH)0.024Controlled PM10 Emissions(BoldValues from Table 1.1-6.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/ton) (lb/ton) (lb/ton) Coef. (lb/ton) (lb/ton) Coef. (lb/ton) Coef. (lb/ton) (lb/ton) Type Ext.Coef. (lb/ton)PC-DB 3.1750.4320.240 0.60.1920.185 1 0.0071 10 2.7432.194 SO4 3*f(RH) 0.549Controlled PM10 EmissionsBoiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (% of Total) (% of Total) (% of Total) Coef. (% of Total) (% of Total) Coef. (% of Total) Coef. (% of Total) (% of Total) Type Ext.Coef. (% of Total)PC-DB 100% 13.6% 7.6% 0.6 6.0%5.8% 1 0.2% 10 86.4% 69.1% SO4 3*f(RH) 17.3%If you are given Total PM10 emissions in lb/hr:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. (lb/hr)PC-DB14.82.01.1 0.6 0.90.9 1 0.0 10 12.810.2 SO4 32.6Weighted Extinction 0.70.90.330.7If you are given Total PM10 emissions in lb/mmBtu:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB0.100.01 0.01 0.6 0.010.01 1 0.0002 10 0.090.07 SO4 30.02If you are given Filterable PM10 emissions:Controlled PM10 Emissions(Boldvalues from Table 1.1-5 and from Table 6 of EPA’s January 2002 DRAFT “Catalog of Global Emissions Inventories and Emission Inventory Tools for BlackBoiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (% of Total) (% of Total) (% of Filterable) Coef. (% of Filterable) (% of Filterable) 1 (% of Filterable) Coef. (% of Total) (% of Condensible) Type Ext.Coef. (% of Condensible)PC-DB 100% 13.6% 55.6% 0.6 44.4% 42.8% 1 1.6% 10 86.4%80.0%SO4 320.0%(% of Fine) Coef. (% of Fine) Coef.96.3% 13.7%10If you are given Filterable PM10 emissions in lb/hr:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. (lb/hr)PC-DB 14.82.01.1 0.6 0.90.9 1 0.0 10 12.810.2 SO4 32.6If you are given Filterable PM10 emissions in lb/mmBtu:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB 0.100.010.01 0.6 0.010.01 1 0.0002 10 0.090.07 SO4 30.02Date: September 18, 2007Page 48 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 6-6 – PM Particle SizeBasis (1.5% Sulfur Coal)PC with ESPfrom AP-42 Table 1.1-6(User inputsfilterableemission rate in lb/hr)Particle Cumulative Mass Fraction of PM10 Particle EmissionsSize < Stated Size < Stated Size Size Range in Size Range(um)ESP(%)(um)(lb/hr)1067%100% 10-60.5650%75% 6-2.50.62.529%43% 2.5-1.250.41.2517%25% 1.25-1.00.1114%21% 1.0-6250.10.62512%18% 0.625-00.4CALPUFFParticle Particle Fraction Emissions Extinction EmissionsSize Size Range of PM10 in Size Range Coef. in Size Range(um) (um)(%)(lb/hr)(g/sec)8 10-625%0.50.60.064.25 6-2.531%0.60.60.08 57% Coarse >/= 2.5 micron1.88 2.5-1.2518%0.410.05 43% Fine Soil </= 2.5 micron1.251.25-14%0.110.010.813 1.6-253%0.110.010.6250.625-018%0.410.04100%2.0100.00 3.7% of Fine Soil0.25Date: September 18, 2007Page 49 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 6-7 PM Speciation Basis (1.0% Sulfur Coal)Controlled PM10 Speciation from AP-42 Tables 1.1-5 & 1.1-6Dry Bottom Boiler burning Pulverized Coal using only ESP for Emissions controlassumes heating value of11428Btu/lb and a sulfur content of1% and an ash content of8% and f(RH) =1Controlled PM10 Emissions(Boldvalues from Table 1.1-5.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/ton) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB 0.0889 0.0189 0.0105 0.6 0.0084 0.0081 1 0.00031 100.0700.056SO4 3*f(RH)0.014Controlled PM10 Emissions(BoldValues from Table 1.1-6.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/ton) (lb/ton) (lb/ton) Coef. (lb/ton) (lb/ton) Coef. (lb/ton) Coef. (lb/ton) (lb/ton) Type Ext.Coef. (lb/ton)PC-DB 2.0320.4320.240 0.60.1920.185 1 0.0071 10 1.6001.280 SO4 3*f(RH) 0.320Controlled PM10 EmissionsBoiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (% of Total) (% of Total) (% of Total) Coef. (% of Total) (% of Total) Coef. (% of Total) Coef. (% of Total) (% of Total) Type Ext.Coef. (% of Total)PC-DB 100% 21.3% 11.8% 0.6 9.4%9.1% 1 0.3% 10 78.7% 63.0% SO4 3*f(RH) 15.7%If you are given Total PM10 emissions in lb/hr:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. (lb/hr)PC-DB14.83.11.7 0.6 1.41.3 1 0.1 10 11.79.3 SO4 32.3Weighted Extinction 1.01.30.528.0If you are given Total PM10 emissions in lb/mmBtu:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB0.100.02 0.01 0.6 0.010.01 1 0.0003 10 0.080.06 SO4 30.02If you are given Filterable PM10 emissions:Controlled PM10 Emissions(Boldvalues from Table 1.1-5 and from Table 6 of EPA’s January 2002 DRAFT “Catalog of Global Emissions Inventories and Emission Inventory Tools for BlackBoiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (% of Total) (% of Total) (% of Filterable) Coef. (% of Filterable) (% of Filterable) 1 (% of Filterable) Coef. (% of Total) (% of Condensible) Type Ext.Coef. (% of Condensible)PC-DB 100% 21.3% 55.6% 0.6 44.4% 42.8% 1 1.6% 10 78.7%80.0%SO4 320.0%(% of Fine) Coef. (% of Fine) Coef.96.3% 13.7%10If you are given Filterable PM10 emissions in lb/hr:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. (lb/hr)PC-DB 14.83.11.7 0.6 1.41.3 1 0.1 10 11.79.3 SO4 32.3If you are given Filterable PM10 emissions in lb/mmBtu:Controlled PM10 Emissions(BoldValue isInputby user.)Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle CPM ORType (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. (lb/mmBtu)PC-DB 0.100.020.01 0.6 0.010.01 1 0.0003 10 0.080.06 SO4 30.02Date: September 18, 2007Page 50 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 6-8 – PM Particle SizeBasis (1.0% Sulfur Coal)PC with ESPfrom AP-42 Table 1.1-6(User inputsfilterableemission rate in lb/hr)Particle Cumulative Mass Fraction of PM10 Particle EmissionsSize < Stated Size < Stated Size Size Range in Size Range(um)ESP(%)(um)(lb/hr)1067%100% 10-60.8650%75% 6-2.51.02.529%43% 2.5-1.250.61.2517%25% 1.25-1.00.1114%21% 1.0-6250.10.62512%18% 0.625-00.6CALPUFFParticle Particle Fraction Emissions Extinction EmissionsSize Size Range of PM10 in Size Range Coef. in Size Range(um) (um)(%)(lb/hr)(g/sec)8 10-625%0.80.60.104.25 6-2.531%1.00.60.12 57% Coarse >/= 2.5 micron1.88 2.5-1.2518%0.610.07 43% Fine Soil </= 2.5 micron1.251.25-14%0.110.020.813 1.6-253%0.110.010.6250.625-018%0.610.06100%3.1100.01 3.7% of Fine Soil0.40

### Date: September 18, 2007 Page 51 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 6-9 PM Speciation Calculat ions for 1.88% Sulfur Coal Cases



# Fine Soil (EC) (1)



# 1.88 um: 0.3 lb/hr * 0.037 = 0.0111 lb/hr
1.25 um: 0.1 lb/hr * 0.037 = 0.0037 lb/hr
0.813 um: 0.0 lb/hr * 0.037 = 0.0 lb/hr
0.625 um: 0.3 lb/hr * 0.037 = 0.0111 lb/hr

Soil (SOIL) (1)



# 1.88 um: 0.3 lb/hr * 0.963 = 0.2889 lb/hr
1.25 um: 0.1 lb/hr * 0.963 = 0.0963 lb/hr
0.813 um: 0.0 lb/hr * 0.963 = 0.0 lb/hr
0.625 um: 0.3 lb/hr * 0.963 = 0.2889 lb/hr

Coarse (PMC) (1)



# 8.0 um: 0.4 lb/hr (directly from Table 6-3) 4.25 um: 0.5 lb/hr (directly from Table 6-3)

Secondary Organic Aerosols (OC) (2)



# 0.813 um: 2.6 lb/hr * 0.5 = 1.3 lb/hr
0.625 um: 2.6 lb/hr * 0.5 = 1.3 lb/hr

Notes to Table 6-9:

(1) Refer to Table 6-4. (2) Refer to Table 6-3. The total mass of OC was assumed to be evenly distributed between the two smallest particle size categories.

### Date: September 18, 2007 Page 52 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 6-10 PM Speciation Calculati ons for 1.5% Sulfur Coal Cases



# Fine Soil (EC) (1)



# 1.88 um: 0.4 lb/hr * 0.037 = 0.0148 lb/hr
1.25 um: 0.1 lb/hr * 0.037 = 0.0037 lb/hr
0.813 um: 0.1 lb/hr * 0.037 = 0.0037 lb/hr
0.625 um: 0.4 lb/hr * 0.037 = 0.0148 lb/hr

Soil (SOIL) (1)



# 1.88 um: 0.4 lb/hr * 0.963 = 0.3852 lb/hr
1.25 um: 0.1 lb/hr * 0.963 = 0.0963 lb/hr
0.813 um: 0.1 lb/hr * 0.963 = 0.0963 lb/hr
0.625 um: 0.4 lb/hr * 0.963 = 0.3852 lb/hr

Coarse (PMC) (1)



# 8.0 um: 0.5 lb/hr (directly from Table 6-6) 4.25 um: 0.6 lb/hr (directly from Table 6-6)

Secondary Organic Aerosols (OC) (2)



# 0.813 um: 2.6 lb/hr * 0.5 = 1.3 lb/hr
0.625 um: 2.6 lb/hr * 0.5 = 1.3 lb/hr

Notes to Table 6-10:

(1) Refer to Table 6-6. (2) Refer to Table 6-5. The total mass of OC was assumed to be evenly distributed between the two smallest particle size categories.

### Date: September 18, 2007 Page 53 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 6-11 PM Speciation Calculati ons for 1.0% Sulfur Coal Cases



# Fine Soil (EC) (1)



# 1.88 um: 0.6 lb/hr * 0.037 = 0.0222 lb/hr
1.25 um: 0.1 lb/hr * 0.037 = 0.0037 lb/hr
0.813 um: 0.1 lb/hr * 0.037 = 0.0037 lb/hr
0.625 um: 0.6 lb/hr * 0.037 = 0.0222 lb/hr

Soil (SOIL) (1)



# 1.88 um: 0.6 lb/hr * 0.963 = 0.5778 lb/hr
1.25 um: 0.1 lb/hr * 0.963 = 0.0963 lb/hr
0.813 um: 0.1 lb/hr * 0.963 = 0.0963 lb/hr
0.625 um: 0.6 lb/hr * 0.963 = 0.5778 lb/hr

Coarse (PMC) (1)



# 8.0 um: 0.8 lb/hr (directly from Table 6-8) 4.25 um: 1.0 lb/hr (directly from Table 6-8)

Secondary Organic Aerosols (OC) (2)



# 0.813 um: 2.3 lb/hr * 0.5 = 1.15 lb/hr
0.625 um: 2.3 lb/hr * 0.5 = 1.15 lb/hr

Notes to Table 6-11:

(1) Refer to Table 6-8. (2) Refer to Table 6-7. The total mass of OC was assumed to be evenly distributed between the two smallest particle size categories.

### Date: September 18, 2007 Page 54 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 6-12 Monthly f(RH) Values for Each Class 1 Area



# Month Cohutta Great Smoky Kilmer Mammoth Sipsey

January 3.3 3.3 3.3 3.4 3.4

February 3.1 3.0 3.1 3.1 3.1

March 3.0 2.9 2.9 2.9 2.9

April 2.8 2.7 2.7 2.6 2.8

May 3.4 3.2 3.3 3.2 3.3

June 3.8 3.9 3.8 3.5 3.7

July 4.0 3.8 4.0 3.7 3.9

August 4.2 4.0 4.2 3.9 3.9

September 4.2 4.2 4.2 3.9 3.9

October 3.8 3.8 3.8 3.4 3.6

November 3.4 3.3 3.3 3.2 3.3

December 3.5 3.4 3.5 3.5 3.4

### Date: September 18, 2007 Page 55 of 92 Appendix 6 - Results of BART Control Strategy Engi neering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-1 Old Hickory Locat ion and Class 1 Area Distances

105 km

254 km

249 km

233 km

220 km

### Date: September 18, 2007 Page 56 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-2: DuPont Old Hickory Plant Geo-Referenced Air Photo


# (UTM Coordinates, meters)

### Date: September 18, 2007 Page 57 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-3 VISTAS Subdomain #3

Modeling Domain

Old Hickory Class 1 Areas

### Date: September 18, 2007 Page 58 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-4: Mammoth Cave NP Receptors

### Date: September 18, 2007 Page 59 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-5: Cohutta Wilderness Receptors

### Date: September 18, 2007 Page 60 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-6: Great Smokey Mountains NP Receptors

### Date: September 18, 2007 Page 61 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-7: Joyce Kilmer Wilderness Receptors

### Date: September 18, 2007 Page 62 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Figure 6-8: Sipsey Wilderness Receptors

### Date: September 18, 2007 Page 63 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 7 Appendix 2 - Model Input and Output Files on CDs

### Date: September 18, 2007 Page 64 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# This page intentionally left blank.

### Date: September 18, 2007 Page 65 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# DuPont Research and Engineering Technology



# 8 Appendix 3 - Results of BART Control Strategy Engineering Analysis

For

E. I. duPont de Nemours and Company Old Hickory Plant

1002 Industrial Road Old Hickory, TN 37138

Prepared by:

John C. deRuyter DuPont Research and Engineering Technology

1007 Market Street Wilmington, DE 19898

### Date: September 18, 2007 Page 66 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 8.1 Background

TN and METRO requested information from th e DuPont Old Hickory Plant relative to potential emissions reductions from th e BART-eligible Boilers 20 and 24. In determining BART requirements, Section 51.308( e)(1)(ii)(A) of the Regional Haze Rule

states:

“The determination of BART must be based on an analysis of the best system of continuous emission control technology available and associated emissions reductions achievable for each BART-eligible source that is subject to BART within the State. In this analysis, t he State must take into consideration the technology available, the costs of compliance, the energy and nonair quality environmental impacts of compliance, an y pollution control equipment in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.”



# This submission provides DuPont’s input relati ve to these requirements. This analysis does not include a rigorous engi neering analysis of the inst allation and O&M costs of the various options, but rather uses available information to estimate the costs and impacts. If a higher level of detailed analysis is re quired, additional time and resources would be

necessary.

8.2 Existing Boiler Design, Arrangement, and Operation

Both Boilers 20 and 24 are tangentially fire d dry bottom pulverized coal fired boilers.

Each boiler utilizes two coal pulverizers. Boiler 20 wa s installed in 1968 and is 445 MMBtu/hr design heat input capacity; Bo iler 24 was installe d in 1966 and is 315 MMBtu/hr design heat input capacity. Both boile rs are equipped with natural gas burners capable of backup full load gas fi ring. The boilers also are able to fire No. 2 Fuel Oil as a secondary backup fuel. Gas and oil pilots are used for burner lightoff and flame stabilization. Boiler 20 produ ces superheated 550 psig steam. Boiler 24 now produces 550 psig saturated steam as a backup to Bo iler 20; it had provided 700 psig saturated steam during the time DMT was produced at the site. Average annual capacity factor for Boiler 20 is approximately 80% and Boiler 24 is 20%. Boiler 20 is the primary site boiler and is operated by itself most of the time. Boiler 24 is operated during periods when

Boiler 20 is down for maintenance or if additio nal steam output is required. Each boiler is equipped with its own 200 ft tall stack.

Each boiler is equipped with its dedicated ho t side Electrostatic Precipitator (ESP) for particulate matter and opacity control. The E SPs were retrofit installations in the late 1970s, and that retrofit included removal of the original multiclone mechanical dust collectors. The ESP designs incorporate pa rallel collecting plates and weighted wire electrodes. The Title V Air Permit requires opera tion of at least five of the eight installed

### Date: September 18, 2007 Page 67 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# fields on each boiler to achiev e required control efficiency. The ESPs were provided by Belco (currently owned by DuPont), which no longer markets power boiler ESPs. Due to the extremely congested arrangement, the ESPs are located above the roof of each boiler. There is no available ground area near the bo ilers. Any additional emissions control equipment would need to be located at the far side of the Power house near the existing coal storage area, necessitating a long breechi ng run to get to the additional equipment, including new booster fans and stack.

As indicated above, the six CAA statutory factors to be considered are:

• The technology available.

• Costs of compliance.

• Energy and non-air quality environmental impacts of compliance.

• Any pollution control equipmen t in use at the source.

• Remaining useful life of the source.

• The degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

The remaining useful life of both boilers is estimated to be at least 20 years providing adequate routine maintenance and proper operati on are practiced. That would result in an overall life of the boilers of about 50-60 years. DuPont has operated boilers with similar design and metallurgy for longer periods. It is not currently anticipat ed that alternative steam supply opportunities would arise that w ould eliminate the need for the two coal fired boilers, but if that did occur, the ove rall life of the units would be reduced.

The remaining useful life of the existing ESPs in their present service is also estimated to be at least 20 years providing adequate ma intenance and proper operation are practiced. However, if fuel characteristics or regul atory requirements significantly change, or maintenance problems arise, it is possible th at an internal rebuil d might be required. DuPont recently completed rebuilds on similar design and age ESPs at another facility, so cost impacts of such a change are understood and discussed below relative to fuel quality changes.

The degree of visibility improvement from the use of each technology evaluated was

discussed above.

Each of the other statutory factors is addr essed for each option evaluated and explained

below.



# 8.2.1 Basis for Engi neering Analysis

TN DEC indicated the desire fo r visibility impacts to be ev aluated based on maximum 24 hour emissions during the prior three years. In the case of the DuPont Old Hickory Plant, DMT production ceased during 2004, and Boiler 24 was primarily dedicated to providing

### Date: September 18, 2007 Page 68 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 700 psig saturated steam to that process. Since DMT has been shut down and the facilities removed, Boile r 24 now serves to supply 550 ps ig saturated steam as a backup to Boiler 20 and thus operates at a much lowe r annual capacity factor than prior to DMT shutdown. Boiler 20 is the prim ary site boiler that is supp lemented as needed by Boiler

24 and the other smaller site boilers. Ther efore, available data for calendar years 2005

and 2006 was used to determine the maximum 24 hour emissions period. Data is only

available for the boilers on a da ily (midnight to midnight) basis, therefore, daily data was used for determining the evaluation basis.

The Old Hickory site steam demand is seasonal in nature, dependent to a large extent on heating load so that the p eak steam demands (and hence SO 2 

# and NOx emissions) are in

the winter months. The summer months are periods of lower steam demand, and that is

when the annual shutdown/overhaul is sche duled for Boiler 20. The day in which the

maximum SO 2 

# and NOx emissions occurred was February 18, 2006, during which both Boilers 20 and 24 were on line firing coal. To tal coal heat input for both boilers during the maximum emissions day was 12,342 MMBtu, or an average of 514.3 MMBtu/hr combined coal heat input. On an equi valent monthly averag e basis, that is 375,410 MMBtu/month. Total natural gas heat input dur ing that same day was only an average of 4.1 MMBtu/hr, and is ignored for this economic analysis. However, for comparison on an equivalent monthly average basis, total combined coal and gas boiler heat input for both Boilers 20 and 24 is 378,392 MMBtu/month. Coal quality data recorded for that maximum day had a sulfur content of 1.88% and a Higher Heati ng Value (HHV) of 11,428 Btu/lb. Coal sulfur value averag ed 1.76% in 2005 and 1.85% for 2006. Use of the coal quality (per cent sulfur and HHV) for the maximum daily emissions day for this analysis is, therefore, cons ervative compared to long term average coal quality.

In addition, conducting visibility impact de terminations and economic comparisons of

alternative controls on the ba sis of the maximum daily emi ssions grossly overstates the actual impact of these boilers on Class 1 area visibility and overstat es the control cost effectiveness (lowers the apparent $/ton rem oved). This overstatement can be seen by viewing the monthly average to tal combined boiler heat input on coal only and for both coal and gas for Boilers 20 and 24. The figur es below show the total monthly average heat input to both boilers for coal only and for all fuels (coal and gas) for 2005 and 2006,

with the dotted lines indicati ng the highest emission day equi valent heat input being used as the basis for the modeling (375,41 0 MMBtu/month for coal only; 378,392 MMBtu/month for all fuels).

### Date: September 18, 2007 Page 69 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

2005 Boilers 20 & 24 Total Monthly Coal Heat Input

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000

Jan-05 Feb05 Mar-05 Apr-05 May05 Jun-05 Jul-05 Aug05 Sep05 Oct-05 Nov05 Dec05

MonthMMBtu/Month Coal Heat Input Maximum Daily Emissions Case- 375,410 MMBtu/Month Annual Average



### 2005 Boilers 20 & 24 Total Monthly Heat Input- All Fuels

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000

Jan05 Feb05 Mar05 Apr05 May05 Jun05 Jul-05 Aug05 Sep05 Oct05 Nov05 Dec05

MonthMMBtu/Month- Boilers 20 & 24 Maximum Daily Emissions Case- 378,392 MMBtu/Month Annual Average

### Date: September 18, 2007 Page 70 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

2006 Boilers 20 & 24 Total Monthly Coal Heat Input

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000

Jan06 Feb06 Mar06 Apr-06 May06 Jun06 Jul-06 Aug06 Sep06 Oct06 Nov06 Dec06

MonthMMBtu/Month Coal Heat Input Maximum Daily Emissions Case- 375,410 MMBtu/Month Annual Average



### 2006 Boilers 20 & 24 Total Monthly Heat Input- All Fuels

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000

Jan-06 Feb06 Mar06 Apr-06 May06 Jun-06 Jul-06 Aug06 Sep06 Oct06 Nov06 Dec06

MonthMMBtu/Month- Boilers 20 & 24 Maximum Daily Emissions Case- 378,392 MMBtu/Month Annual Average

### Date: September 18, 2007 Page 71 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# As is apparent from the above charts, th e combined maximum daily heat input and

associated SO 2 

# and NOx emission rates for Boilers 20 and 24 used for determining the visibility impacts grossly overstates actual emissions, es pecially during the summer months when visibility is most sensitive to SO 2 

# emissions. The above also indicate the low percentage of total heat input typically derived from natural gas firing for these

boilers.

The economic analysis cases belo w are calculated on two bases:

• Assuming the maximum daily emission rate a nd associated coal heat input as the

baseline condition.

• Using annual average coal fi ring capacity factors for Boiler 20 and 24 of 80% and 20%, respectively against the boiler design heat input, and average coal quality. This approach more closely approximates actual boiler operation conditions, but

still on a conservative basis.

8.3 Description of Feasible Options

The following provides a summary of the optio ns considered for emissions reductions

from Boilers 20 and 24. The focus is on both SO 2 

# and NOx emissions. As indicated above, particulate matter is already well controlled with the hot side ESPs.

8.3.1 Baseline Case Using Coal Currently Burned (Coal 1)



# The baseline case is used as a comparison cas e for the control options and for evaluating potential emission reductions. The permitted co al sulfur limit is 2.0% by weight. The current coal sulfur content averaged 1.76% in 2005 and 1.85% in 2006 in order to provide operating margin. The baseline maximum emissions day case uses the highest day coal quality for comparison purposes; that was 1.88% sulfur at 11,428 Btu/lb, equivalent to an SO 2 

# emission rate of 3.13 lb/MMBtu. There is no additional cost for using the current coal.

The modeled loading and emission rates on Bo ilers 20 and 24 for modeling and economic analysis purposes was set as follows:

1. Total SO 2 

# and NOx emissions on an hourly aver age basis for the highest emission day were determined. Those emissions were 1607 lb/hr of SO 2 

# and 282 lb/hr of NOx; those are equivalent to an annu alized emission rate of 7040 TPY of SO 2 

# and

1233 TPY of NOx. 2. That total emission rate was split between the two boilers based on an annual average capacity factor of 80% for Bo iler 20 and 20% for Boiler 24 because the boiler lineup on the highest emission day (both Boilers 20 and 24 in operation) cannot be accomplished on an annual ba sis and this propor tioning provides a more accurate evaluation and comparison emission control application to Boiler 20 only to cases imposing controls on both boilers. This resulted in baseline SO 2

### Date: September 18, 2007 Page 72 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# emissions using Coal 1 for Boilers 20 and 24 of 5632 TPY and 1408 TPY of SO 2 

# , respectively; and NOx emissions of 977 TPY and 257 TPY of NOx, respectively.

Those emission rates were modeled from each of the boiler stacks for the Baseline

case. 3. The following control cases provide resu lts for emission reductions from this

baseline condition.

8.3.2 Burn Lower Sulfur Coal



# Coal could be purchased with lower inherent sulfur content. As noted above, the boilers are equipped with hot side ESPs and the boi lers are tangentially fired dry bottom units firing bituminous coal. The boiler and associ ated equipment design places limitations on the type of coal that can be fired, so that P RB coal, for instance, is not an easily viable option. Coal choices would be limited to b ituminous coal. In addition, the boilers are subject to 40CFR Part 63, Subpart DDDDD (B oiler MACT Rule) requirements with a current compliance date of September 13, 2007. Pl ans are to use coal specifications with existing boiler and PM control equipment to demonstrate compliance with the emission limits. The Health Based Compliance A lternative (HBCA) provided in Subpart DDDDD is to be used for compliance with the MACT HCl limit. Both chorine and mercury coal specifications will be used to ensure complian ce. Therefore, the availability of coal supplies will be somewhat limited based on th e required specifications . There will be a

cost increase in coal delivered to the site du e to lower sulfur requirements. The estimated additional cost per ton based on today’s coal av ailability and cost differentials is included in the options analysis. Two levels of lower sulfur conten t are evaluated- 1.5% S (Coal 2) and 1.0% S (Coal 3). In both cases, th e coal HHV during the highest emission day

was used for calculations.

It is quite possible that coal with lower sulfur levels could negatively impact ESP performance due to ash resistivity effects. Therefore, while a lower sulfur level is included in the analysis, the lowest practical sulfur level is believed to be about 1.5% or slightly lower. However, actual performance and options would need to be thoroughly evaluated and test burns accomplished in order to firmly establish capability.

It is quite possible that firi ng coal with a sulfur level as low as 1.0% might cause ESP performance degradation due to ash resi stivity such that the Boiler MACT 0.07 lb/MMBtu PM limit and 20% opacity limit may not be achievable. This can only be determined with thorough testing and analys is. If low sulfur coal was mandated and performance was unacceptable, rebuilding of the ESPs could improve performance and probably allow use of the lower sulfur coal. As a reference case, the project cost for replacing the collecting plates and supports, replacing the wei ghted wire electrodes with rigid rod electrodes, instal ling new rappers, and installi ng new power supplies and TR

sets with controls is es timated to be at least $4.0 MM for Boiler 20 and $3.2MM for Boiler 24 based on recent rebuild experience.

### Date: September 18, 2007 Page 73 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



## 8.3.3 SO 2 

## Scrubbers Using Coal with Various Sulfur Contents



# The most practical types of SO 2 

# scrubbers that would be applicable to boilers of this size are lime spray dry absorbers with a downstream baghouse (fabric filter) or a sodium wet scrubber installed downstream of the existing ID Fan, in both cases leaving the existing ESPs in place. The spray dryer has an inherent advantage of providing a dry waste product that could be disposed of similarly to the existi ng coal ash. The sodium wet scrubber would require additional investment and O&M cost for treatment of a liquid waste stream prior to disposal in the plant’s waste water treatment system. Both of those types of scrubbers use higher cost reagents than limestone wet scrubbers typically used in electric utility systems. However, the hi gher capital cost of the limestone wet scrubber systems for smaller units is not justified comp ared to these two options. Since the spray dryer and sodium wet scrubber reagents have a significant cost, it is most appropriate to utilize them with lower sulfur coal, as the economic analysis result s shown at the end of

this section indicate. Three cases are eval uated for scrubbing- using the current coal, using 1.50% S coal, and using 1.00% S coal. W ith a downstream scrubber of either typespray dry absorber or sodium wet scrubbe r- the impact of lower sulfur level on ESP performance becomes less of an issue due to downstream PM capture capability in the scrubber. Economic and visibility modeling ca ses were analyzed assuming installation of

an individual scrubber train on each of the boilers so that bo iler uptime can be optimized and use of backup natural gas firing will be minimized. In addition, alternative cases were evaluated assuming scrubber installati on on only Boiler 20, since that is the boiler operated most of the year, and Boiler 24 has a low annual capacity factor. The cost evaluations include the requirement for us e of natural gas firing during scrubber installation, and that cost is amortized using the capital recovery factor.

8.3.4 Cofire Coal and Natural Gas in each Boiler at a 50/50 Ratio



# Since the existing boiler s have gas cofiring capability, one case was evaluated with use of cofiring coal and gas at a 50/50 ratio in order to determine cost effectiveness.

8.3.5 Install Low NOx Burners (LNB) or Selective Non-Catalytic Reduction (SNCR)



# Installation of replacement LNB was evaluated for both boilers. Furnace height could be adequate for SNCR, so that option was also evaluated. Emissions reductions are similar

for LNB and SNCR.

8.3.6 Install Selective Catalytic Reduction (SCR)



# Application of SCR to thes e boilers would be extremely difficult and might require replacement of the hot side ESPs with an SCR; but even with such an assumption, the boiler outlet flue gas temperature may not consis tently be in an optimum range for SCR. However, the economic impact and visibility modeling was also conducted for that option for comparison purposes.

### Date: September 18, 2007 Page 74 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 8.4 SO 2 

# Emissions Reductions and Economic Comparison of Options Using the Highest Emission Day Basis

Emissions control equipment cost estimat es are determined primarily from RTP Environmental, Inc. database information modi fied for these particular sources, with the LNB and SNCR costs based on escalated past proposal information for these boilers. Fuel differential costs are based on past av erage fuel use and coal price differential estimates from the DuPont coal purchaser. The assumed natural gas price differential over coal price is indicated in the att ached spreadsheet ($6.00/MMBtu differential assumed).

Cost details are provided in the attached tables: The results for the case using highest day h eat input and emissions basis are shown in

tables:

• BART for Boiler #20 Highest Day

• BART for Boiler #24 Highest Day

• Combined Blrs 20&24 Highest Day

8.4.1 Coal 2 Fired in Boilers 20 and 24



# Coal 2 is assumed to be coal with 1.5% S (2.49 lb/MMBtu SO 2 

# per AP-42 using 11,428 Btu/lb As-Received HHV). Annual costs w ould increase approximately $1.97MM per year over current coal cost fo r increased coal purchase pri ce. (Recognize th at coal price increases are based on current coal pricing di fferential estimates, and that future price differentials could vary from those levels depending on the suppl y and demand for those higher quality coals). SO 2 

# reductions vs. the Baseline highest emission day Coal 1 burned at the site (3.13 lb/MMBtu) would be 1423 TPY with resultant incremental cost
of $1385/ton SO 2 

# removed. It is believed that coal w ith the sulfur leve l of Coal 2 could

be found which also meets the Boiler MACT limits, so that firing this should be technically feasible. Actual coal test bur n and emissions testing would be required in order to confirm adequate performance, however.

8.4.2 Coal 3 Fired in Boilers 20 and 24



# Coal 3 is assumed to be coal with 1.0% S (1.66 lb/MMBtu SO 2 

# per AP-42 using 11,428 Btu/lb As-Received HHV). Annual costs w ould increase approximately $2.96MM per year over current coal cost for in creased coal purchase price. SO 2 

# reductions vs. Baseline highest emission day Coal 1 (3.13 lb/MMB tu) would be 3295 TPY with resultant
incremental cost effectiveness of $897/ton SO 2 

# removed. If compared to Coal 2 (2.49 lb/MMBtu), the incremental SO 2 

# reduction would be 1872 TPY with an incremental cost
effectiveness vs. Coal 2 of $526/ton SO 2 

# removed. As indicated above, use of Coal 3

without an SO 2 

# scrubber could negatively impact ESP performance, so that use of Coal 3

### Date: September 18, 2007 Page 75 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# is not considered technically feasible at this ti me without extensive coal test burn and emissions testing. If rebuilding the ESP w ould be required, the total annualized cost
increase would be $3.75MM and the cost effect iveness vs Coal 1 would rise to $1138/ton

SO 2 

# removed and $950/ton SO 2 

# compared to Coal 2.

8.4.3 Spray Dry Absorber with Downstream Baghouse



# Application of a spray dry absorber with downstream ba ghouse is assumed to provide

85% SO 2 

# reduction. While it is possible to ach ieve higher reduction levels, 85% is considered a reasonable long term average achievable removal rate. Total capital requirement is estimated to be $52MM for Boiler 20 and $41MM for Boiler 24. The congested nature of the facility and th e need to place any new emissions control equipment on the opposite side of the Power house along with a new stack raise the cost of this option. This cost is within the range of the EPA Air Pollution control Technology Fact Sheet (APCTFS) estimates. Total a nnual cost including cap ital recovery is $5.8MM/yr for Boiler 20 and $4.5MM/yr for Boil er 24 without the amortized installation period incremental gas cost. Since Boiler 20 is the primary boiler and supplemental steam generation would be required from other smaller non-BART eligible boilers, use of natural gas during scrubber installation is a ssumed, and that cost is amortized using the Capital Recovery Factor. Since Boiler 24 is a low capacity factor boiler, no supplemental gas firing cost is assumed for that bo iler for installation of a scrubber.

Costs and cost effectiveness are shown fo r use of SDA with downstream baghouse for

both Boilers 20 and 24 in the individual boile r tables, as well as for installation on only Boiler 20 for cases using the three coals. As i ndicated in the attached tables, in all cases, the costs for SDA with baghouse are significantly higher than the costs of a sodium wet scrubber application. Therefor e, the combined Boiler 20 and 24 table only considers the scrubbing cases with utilizati on of sodium wet scrubbers.

8.4.4 Sodium Wet Scrubber Installation



# Application of a sodium wet scr ubber is assumed to provide 95% SO 2 

# reduction. Total capital requirement is estimated to be $35MM for Boiler 20 and $28MM for Boiler 24. The congested nature of the facility and the need to pl ace any new emissions control equipment on the opposite side of the Power house along with a new stack raise the cost of this option. This cost is within the ra nge of the EPA APCTFS estimate. Since Boiler 20 is the primary boiler and supplemental steam generation would be required from other smaller non-BART eligible boilers, use of natural gas during scr ubber installation is assumed, and that cost is amortized using the Capital Recovery Factor. Since Boiler 24 is a low capacity factor boiler, no supplemental ga s firing cost is assumed for that boiler for

installation of a scrubber.

### Date: September 18, 2007 Page 76 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



## 8.4.4.1 Sodium Wet Scrubber Using Baseline Highest Emission Day Coal 1 (1.88% S)



# • Installation on Both Boilers 20 and 24

Overall SO 2 

# reduction vs. Baseline Coal 1 fi ring alone would be 6688 TPY with an average cost effectiveness of $3524/ton SO 2 

# removed.

• Installation on Boiler 20 Only

Overall SO 2 

# reduction vs. Baseline Coal 1 fi ring alone would be 5351 TPY with an average cost effectiveness of $2658/ton SO 2 

# removed.

8.4.4.2 Sodium Wet Scrubber Using Coal 2 (1.5% S)



# • Installation on Both Boilers 20 and 24

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 5336 TPY with an
incremental cost effectiveness of $2823/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 6759 TPY with an average cost e ffectiveness of $2520/ton SO 2 

# removed.

• Installation on Boiler 20 Only

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 4269 TPY with an
incremental cost effectiveness of $2161/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 5692 TPY with an average cost e ffectiveness of $1967/ton SO 2 

# removed.

8.4.4.3 Sodium Wet Scrubber Using Coal 3 (1.0% S)



# • Installation on Both Boilers 20 and 24

Overall SO 2 

# reduction vs. Coal 3 firing alone would be 3558 TPY with an
incremental cost effectiveness of $4244/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 5430 TPY with an
incremental cost effectiveness of $2962/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 6853 TPY with an average cost e ffectiveness of $2635/ton SO 2 

# removed.

• Installation on Boiler 20 Only

### Date: September 18, 2007 Page 77 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Overall SO 2 

# reduction vs. Coal 3 firing alone would be 2846 TPY with an
incremental cost effectiveness of $3252/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 4718 TPY with an
incremental cost effectiveness of $2170/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 6142 TPY with an average cost e ffectiveness of $1988/ton SO 2 

# removed.

8.4.5 50/50 Coal/Gas Cofiring



# As indicated above, the existing boilers are cap able of coal/gas cofiring. In order to determine the relative cost effectiveness, it wa s assumed that a 50/50 ra tio of coal and gas could be fired. If that was done on an annual basis, total SO 2 

# reduction compared to current operation would be 3520 TPY. At an incremental cost differential of $6.00/MMBtu for gas over coal, the cost effectiveness would be $4031/ton SO 2 

# removed compared to current Baseline Coal 1 operation.

8.5 NOx Emissions Reductions a nd Economic Comparison of Options Using the Highest Emission Day Basis

8.5.1 Low NOx Burner (LNB) Retrofit



# Uncontrolled NOx emissions from the boilers are 0.54 lb/MMBtu for Boiler 20 and 0.57

lb/MMBtu for Boiler 24 based on their re quired annual NOx SIP Call CEM RATA

Reference Method test results at high boiler load. Retrofit of LNB to these boilers (8 corner burners per boiler) is considered viable. It is lik ely that a NOx reduction of 40%

could be achievable with retrof it installation of LNB. The following are based on use of the highest emission day coal quality.

8.5.1.1 LNB Installation on Both Boilers 20 and 24



# Total NOx emission reduction from LNB retrofit to both boilers would be 493 TPY. The

cost for retrofit LNB instal lation on both boilers is esti mated to be approximately $5.2MM. Including incremental additional natu ral gas cost for 4 weeks of downtime for Boiler 20 only results in a to tal cost effectiveness of $1953/ton NOx removed compared to current operation.

8.5.1.2 LNB Installation on Boiler 20 Only



# Total NOx emission reduction from LNB retrof it to Boiler 20 only would be 391 TPY.

The cost for retrofit LNB installation on Boile r 20 only is estimated to be approximately $2.6MM. Including incremental additional natu ral gas cost for 4 weeks of downtime for

### Date: September 18, 2007 Page 78 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Boiler 20 only results in a to tal cost effectiveness of $1466/ton NOx removed compared to current operation.

8.5.2 Selective Non-catalytic Reduction (SNCR)



# Retrofit of SNCR to these boilers is considered viable. It is likely that a NOx reduction

of 40% could be achievable with retrofit installation of SNCR , which is the same as for

LNB installation.

8.5.2.1 SNCR Installation on Both Boilers 20 and 24



# Total NOx emission reduction from SNCR retrof it to both boilers would be 493 TPY.

The cost for retrofit SNCR installation on bot h boilers is estimated to be approximately $3.1MM. Including incremental additional natu ral gas cost for 4 weeks of downtime for Boiler 20 only results in a to tal cost effectiveness of $2241/ton NOx removed compared to current operation.

8.5.2.2 SNCR Installation on Boiler 20 Only



# Total NOx emission reduction from SNCR retrof it to Boiler 20 only would be 391 TPY.

The cost for retrofit SNCR installation on Bo iler 20 only is estimated to be approximately $1.9MM. Including incremental additional natu ral gas cost for 4 weeks of downtime for Boiler 20 only results in a to tal cost effectiveness of $2102/ton NOx removed compared to current operation.

8.5.3 Selective Catalytic Reduction (SCR)



# Retrofit of SCR to these bo ilers would be extremely di fficult, but the costs were

estimated for use of SCR in combination with LNB for comparison purposes. A NOx

reduction of 80% is assumed to be achievable with retrofit installation of SCR with LNB.

8.5.3.1 SCR with LNB Installation on Both Boilers 20 and 24



# Total NOx emission reduction from SCR and LNB retrofit to both boilers would be 1085

TPY. The cost for retrofit LNB and SCR inst allation on both boilers is estimated to be approximately $31MM. Including incremental additional natural gas cost for 4 weeks of downtime for Boiler 20 only results in a total cost effectiveness of $4682/ton NOx removed compared to current operation.

8.5.3.2 SCR with LNB Installation on Boiler 20 Only



# Total NOx emission reduction from SCR and LNB retrofit to Boiler 20 only would be

859 TPY. The cost for retrofit LNB and SCR installation on Boiler 20 only is estimated to be approximately $17MM. Including incr emental additional natural gas cost for 4

weeks of downtime for Boiler 20 only results in a total cost effectiveness of $3380/ton NOx removed compared to current operation.

### Date: September 18, 2007 Page 79 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 8.5.4 50/50 Coal/Gas Cofiring

As indicated above, the existing boilers are cap able of coal/gas cofiring. In order to determine the relative cost effectiveness, it wa s assumed that a 50/50 ra tio of coal and gas

could be fired. If that was done on an a nnual basis, total NOx reduction compared to current operation would be 493 TPY ( 40% re duction). At an incremental cost differential of $6.00/MMBtu for gas over co al, the cost effectiveness would be $28,762/ton SO 2 

# removed compared to current Baseline Coal 1 operation.

8.6 SO 2 

# and NOx Emissions Reductions and Economic Comparison of Options Using the Annual Average Capacity Factor and Average Coal Quality Basis

As indicated above, using the highest emi ssion rate day as the basis for economic comparison overstates the emissions reducti ons actually achieva ble and understates (lowers) the apparent emission reduction cost effectiveness. In order to determine cost effectiveness on a more reasonable and appropria te basis, calculations are also provided using emissions based on 80% annual capacity factor for Boiler 20 and 20% for Boiler 24 along with average coal quali ty (1.76% S and 11,750 Btu/lb). As indicated above, this

would result in annual total SO 2 

# emissions of 5223 TPY and NOx emissions of 1002 TPY. Equivalent total boiler monthly aver age heat input on this basis would be 301,680

MMBtu/month. That can be seen on the charts above to still be above the highest month heat input for 2006; thus, this approach is not only more approp riate, it is still conservative. Results for this average a nnual average capacity factor method are shown

in tables: BART for Boiler #20 Actual Avg BART for Boiler #24 Actual Avg Combined Blrs 20&24 Actual Avg

8.6.1 Coal 2 Fired in Boilers 20 and 24



# Annual costs would increase approximately $1.56 MM per year over current coal cost for increased coal purchase price. SO 2 

# reductions vs. average coal (Coal 1) burned at the site (2.85 lb/MMBtu) would be 772 TPY with re sultant incremental cost of $2024/ton SO 2 

# removed.

8.6.2 Coal 3 Fired in Boilers 20 and 24



# Annual costs would increase approximately $2.34 MM per year over current coal cost for increased coal purchase price. SO 2 

# reductions vs. average coal (Coal 1) (2.85 lb/MMBtu)

would be 2255 TPY with resultant increm ental cost effectiveness of $1039/ton SO 2 

# removed. If compared to Coal 2 (2.43 lb/MMBtu), the incremental SO 2 

# reduction would
be 1484 TPY with an incremental cost effectiveness vs. Coal 2 of $526/ton SO 2 

# removed.

### Date: September 18, 2007 Page 80 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# If rebuilding the ESP would be required, th e total annualized cost increase would be
$3.13MM and the cost effectiveness vs Coal 1 would rise to $1390/ton SO 2 

# removed and
$1060/ton SO 2 

# compared to Coal 2.

8.6.3 Sodium Wet Scrubber Installation
8.6.3.1 Sodium Wet Scrubber Using Baseline Current Average Coal 1 (1.76% S)



# • Installation on Both Boilers 20 and 24

Overall SO 2 

# reduction vs. Baseline Coal 1 fi ring alone would be 4962 TPY with an average cost effectiveness of $4547/ton SO 2 

# removed.

• Installation on Boiler 20 Only

Overall SO 2 

# reduction vs. Baseline Coal 1 fi ring alone would be 4216 TPY with an average cost effectiveness of $3212/ton SO 2 

# removed.

8.6.3.2 Sodium Wet Scrubber Using Coal 2 (1.5% S)



# • Installation on Both Boilers 20 and 24

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 4229 TPY with an
incremental cost effectiveness of $3386/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 4229 TPY with an average cost e ffectiveness of $3176/ton SO 2 

# removed.

• Installation on Boiler 20 Only

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 3593 TPY with an
incremental cost effectiveness of $2426/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 4365 TPY with an average cost e ffectiveness of $2355/ton SO 2 

# removed.

8.6.3.3 Sodium Wet Scrubber Using Coal 3 (1.0% S)



# • Installation on Both Boilers 20 and 24

Overall SO 2 

# reduction vs. Coal 3 firing alone would be 2819 TPY with an
incremental cost effectiveness of $5089/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 4303 TPY with an
incremental cost effectiveness of $3516/ton SO 2 

# removed.

### Date: September 18, 2007 Page 81 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 5075 TPY with an average cost e ffectiveness of $3289/ton SO 2 

# removed.

• Installation on Boiler 20 Only

Overall SO 2 

# reduction vs. Coal 3 firing alone would be 2395 TPY with an
incremental cost effectiveness of $3650/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Coal 2 firing alone would be 3879 TPY with an
incremental cost effectiveness of $2455/ton SO 2 

# removed.

Overall SO 2 

# reduction vs. Baseline Coal 1 firing alone would be 4651 TPY with an average cost e ffectiveness of $2384/ton SO 2 

# removed.

8.6.4 50/50 Coal/Gas Cofiring



# If a 50/50 coal/gas ratio was us ed on an annual basis, total SO 2 

# reduction compared to current operation would be 2611 TPY. At an incremental cost differential of $6.00/MMBtu for gas over coal, the cost effectiveness would be $4427/ton SO 2 

# removed compared to current Baseline Coal 1 operation.

8.6.5 Low NOx Burner (LNB) Retrofit

8.6.5.1 LNB Installation on Both Boilers 20 and 24



# Total NOx emission reduction from LNB retrofit to both boilers would be 401 TPY. The

total cost effectiveness woul d be $2342/ton NOx removed compared to current operation.

8.6.5.2 LNB Installation on Boiler 20 Only



# Total NOx emission reduction from LNB retrof it to Boiler 20 only would be 338 TPY.

The total cost effectiveness would be of $1622/ton NOx removed compared to current operation.

8.6.6 Selective Non-Catalytic Reduction (SNCR)

8.6.6.1 SNCR Installation on Both Boilers 20 and 24



# Total NOx emission reduction from SNCR retrof it to both boilers would be 401 TPY.

The total cost effectiveness would be $2484/ton NOx removed compared to current operation.

8.6.6.2 SNCR Installation on Boiler 20 Only

### Date: September 18, 2007 Page 82 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Total NOx emission reduction from SNCR retrof it to Boiler 20 only would be 338 TPY.

The total cost effectiveness would be $2213/ton NOx removed compared to current operation.

8.6.7 Selective Catalytic Reduction (SCR)

8.6.7.1 SCR with LNB Installation on Both Boilers 20 and 24



# Total NOx emission reduction from SCR and LNB retrofit to both boilers would be 882

TPY. The total cost effectiveness woul d be $6012/ton NOx removed compared to current operation.

8.6.7.2 SCR with LNB Installation on Boiler 20 Only



# Total NOx emission reduction from SCR and LNB retrofit to Boiler 20 only would be

744 TPY. The total cost effectiveness w ould be $4067/ton NOx removed compared to current operation.

8.6.8 50/50 Coal/Gas Cofiring



# If a 50/50 coal/gas ratio was used on an a nnual basis, total NOx reduction compared to current operation would be 401 TPY ( 40% re duction). At an incremental cost differential of $6.00/MMBtu for gas over co al, the cost effectiveness would be $28,835/ton NOx removed compared to current Baseline Coal 1 operation.

8.7 Energy and Non-Air Quality En vironmental Impacts of Compliance

This analysis does not provide detailed quantification of ener gy and non-air quality environmental impacts for each compliance opti on since this is a high level analysis. However, those impacts and be described qualitatively.

Use of lower sulfur alone coal would not en tail any significant changes to energy use or non-air quality environmental impacts.

Use of a spray dry scrubber would require use of lime as the reagent. Solid waste disposal would increase over the current co al ash-only condition by the quantity of

calcium sulfite/sulfate formed in the scrubbe r. This can be estimated based on removal percent and expected calcium/sulfur stoichiome tric ratio. Costs for that disposal are

included within the estimated O&M cost estim ates. As indicated above, the additional waste would be dry, so it would likely be disposed of in a landfill. Additional purchased electricity would be required for operation of the scrubber and ba ghouse, including, for example, lime transport, slurry preparati on and injection, baghouse pulse air, ash and spent sorbent handling, and increased fan power to compensate for increased flue gas

### Date: September 18, 2007 Page 83 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# pressure drop. Increased pur chased electricity would resu lt in increased emissions of

SO 2 

# , NOx, CO 2 

# , and other emissions from the electri c utility generators providing that power, which could in fact, be units that th emselves impact Class I areas with their SO 2 

# and NOx emissions. Water would also be consumed for slurry preparation.

Use of a sodium wet scrubber would require us e of caustic as the re agent. Liquid waste disposal would increase for di sposal of the scrubber blow down stream. The existing plant waste water treatment faci lity likely does not have adeq uate capacity for that waste stream directly, but some form of neutraliza tion and oxidation would be required prior to transfer to the waste treatment system. Cost s for that disposal are included within the

estimated O&M cost estimates. Additional purchased electricity would be required for operation of the scrubber, including, for example, liquid pumping power and increased fan power to compensate for increased flue gas pressure drop. Increased purchased electricity would result in increased emissions of SO 2 

# , NOx, CO 2 

# , and other emissions from the electric utility genera tors providing that power, which could in fact, be units that themselves impact Class I areas with their SO 2 

# and NOx emissions. Water would also be

consumed for the sc rubber solution.

Use of LNB would result in increased unburne d carbon in the flyash due to lower flame temperatures. This could impact the method of disposal of flyash in that beneficial reuse might not be possible, and landfill disposal might be the only option. The associated efficiency loss with increased unburned carbon would result in incremental increase in coal consumption and the associated electric ity for pulverization and fan power, as well as increased ash disposal overall.

SNCR and SCR would utilize ammonia or urea as reagents. Ammonia slip would occur with either control technology. Ammonia slip reacts with sulf ur and chloride species in the flue gas forming ammonium salts wh ich increase the concentration of fine particulates (PM2.5) in the fl ue gas, potentially increasing stack opacity. On-site storage

of ammonia would create its ow n set of safety issues. Dis posal of spent catalyst would be a long term solid waste issue for SCR.

8.8 Conclusions Relative to SO 2 

# and NOx Controls for Boilers 20 and 24

Appropriate control options we re evaluated in this high le vel analysis and those are

discussed above. Use of the current coal al ready provides a level of reduction compared to the permitted allowable level. Use of lower sulfur coals could be an appropriate, viable, and cost effective option compared to cu rrent state if the visibility impact warrants emissions reductions. It is most likely that a sulfur level in the 1.5% range (or possibly lower) could be viable for long term utiliza tion, but significant investigation would need

to be conducted. As indicated above, there is a po ssibility that ESP rebuilding would be required in order to fire coal with ve ry low sulfur content, such as 1.0%.

### Date: September 18, 2007 Page 84 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Installation of spray dry abso rbers with downstream baghouses or sodium wet scrubbers both show a high cost per ton of SO 2 

# removed compared to use of lower sulfur coal alone. Those high costs are not considered cost effective. For example, EPA has stated that CAIR for utility boilers is better than BART. The CAIR rulemaking established SO 2 

# and NOx emissions reduction levels at points that were consider ed highly cost effective. The marginal cost curves for SO 2 

# and NOx abatement from the CAIR docket (letter from EPA Clean Air Markets Division to the Docket, Analysis of the Marginal Cost of SO 2 

# and NOx Reductions , January 28, 2004) are shown below.

### Date: September 18, 2007 Page 85 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

CAIR SO2 cap 2.5

MM Tons

CAIR NOx cap

1.30 MM Tons

### Date: September 18, 2007 Page 86 of 92 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# As indicated in the charts, the CAIR SO 2 

# and NOx caps (lines added) provided emissions reductions at marginal costs of less than $1800 per ton of both SO 2 

# and NOx. Therefore,

reasonable cost effectiveness for smaller BART-eligible emission sources should not exceed those figures. All SO 2 

# scrubbing cases evaluated exceed that cost effectiveness value. The only option that provides highly co st effective reductions is the use of lower sulfur coal for these boilers. The degree of visibility improvement discussed above

would need to be considered re garding the potential n eed to use that coal for either full or part year operations.

In addition, the low capacity factor for Boile r 24 makes retrofit of any emissions control technology uneconomical on that boiler. Since all boilers use the came coal feed system, use of lower sulfur coal would be applicab le to both Boilers 20 and 24 in any case.

Application of LNB to only Boiler 20 is margin al compared to the CAIR utility values.

Use of that control would also need to be considered relative to the visibility improvement attainable.

As indicated in the economic analysis, use of coal/gas cofiring at a 50/50 ratio on a continuing basis is not cost effective. Ho wever, if there are particular days where visibility might be most impacted by SO 2 

# and NOx emissions, it might be possible to cofire on those days to achieve some visibility improvement if that is shown to be justified.Date: September 18, 2007Page 87 of 92Appendix 6 - Results of BART Control Strategy Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 8-1 BART Economic Analysis for DuPont OldHickory Boilers 20 & 24 at Maximum Combined DailyEmissionsBART For SO2 and NOx for Both Boilers 20 & 24 Based on Maximum Emissions Day for 2005-06SO2 Model Case Identifier-->AF KM H C P O J EBoilers 20 & 24Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24SO2 ECONOMIC PARAMETERSBASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 using Coal 3 using Coal 2 using current CoalFACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1 Coal 2Coal 3 using Coal 3 using Coal 2 using current Coal using current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler20 Only w/Control Option -->No FGDNo FGDNo FGD95% WSS95% WSS95% WSS50% Gas Cofiring95% WSS95% WSS95% WSSCoal Percent Sulfur-->1.881.501.001.001.501.881.881.001.501.88A&E Emission Rate, lb/MMBtu -->3.132.491.660.080.120.163.130.080.120.16SO2 Emission Rate at DHI, lb/hr-->2,3751,8951,264639511911885618411054Annual SO2 Emissions, TPY-->7,0405,6173,745187281352352089913481690Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->1,6071,282855436480804205308386A&E Total Capital Requirement:$63,365,423 $63,365,423$63,365,423$35,425,148 $35,425,148 $35,425,148O&M Costs @ 8% + reagent + waste disposal:$7,778,324$7,741,314$16,245,380$5,001,297$4,971,689$9,968,709Range:+50/-30+50/-30+50/-30+50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0$10$15$15$10$0$0$15$10$0Coal Change Annual Additional Cost :$1,970,962 $2,956,443 $2,956,443$1,970,962$0$2,956,443$1,970,962$0Natural Gas Cofiring Incremental Cost Increase:$14,190,215Capital Recovery Costs:$6,957,183$6,957,183$6,957,183$3,889,491$3,889,491$3,889,491Total Annual Costs Excluding Coal Change:$14,735,506 $14,698,497$23,202,562$8,890,788$8,861,180$13,858,200Annual Emissions Reduction vs Baseline Current Coal:1,4233,2956,8536,7596,6883,5206,1425,6925,351Annual Emissions Reduction vs Coal 2:1,8725,4305,3365,2652,0974,7184,2693,928Annual Emissions Reduction vs Coal 3:3,5583,4643,3932252,8462,3972,055Downtime at Gas Fuel Price Difference:$3,317,550$3,317,550$3,317,550$3,317,550$3,317,550$3,317,550Amotized Downtime at Gas Fuel Price Difference:$364,249$364,249$364,249$364,249$364,249$364,249Total Annualized Cost:$1,970,962 $2,956,443 $18,056,198 $17,033,708$23,566,812$14,190,215 $12,211,479 $11,196,391 $14,222,449Cost Effectiveness Relative to Baseline Current Coal, $/Ton Removed:$1,385$897$2,635$2,520$3,524$4,031$1,988$1,967$2,658Cost Effectiveness Relative to Coal 2, $/Ton Removed:$526$2,962$2,823$4,102$5,827$2,170$2,161$3,119Cost Effectiveness Relative to Coal 3, $/Ton Removed:$4,244$4,064$6,075$49,997$3,252$3,438$5,482NOx Model Case Identifier--> AB1B2CBD1D2ENOx ECONOMIC PARAMETERSBASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boiler 24 As-Is & Boiler 24 As-Is & Boiler 24 As-Is &FACTORED ESTIMATE FROM RTP DATABASEusing current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler 20 Only w/Control Option -->CCLNBSNCRLNB+SCR50% Gas CofiringLNBSNCRLNB+SCRNOx Emission Rate at DHI, lb/hr-->42125225250252324324208Annual NOx Emissions, TPY-->1233740740148740843843374Equivalent Annual Average Hourly NOx Emissions, lb/hr-->2821691693416919219285A&E Total Capital Requirement:$5,215,728 $3,122,793 $31,225,760$2,607,864$1,856,689$17,355,321O&M Costs:$208,629$580,742 $1,470,994$104,315$435,205$816,962Range:+50/-30+50/-30+50/-30+50/-30+50/-30+50/-30Natural Gas Cofiring Incremental Cost Increase:$14,190,215Capital Recovery Costs:$572,659$342,866 $3,428,421$286,329$203,854$1,905,521Total Annual Costs Excluding Downtime Gas Cost:$781,288$923,608 $4,899,414$390,644$639,059$2,722,483Annual Emissions Reduction:4934931,085493391391859Downtime at Gas Fuel Price Difference:$1,658,775 $1,658,775 $1,658,775$1,658,775$1,658,775$1,658,775Amotized Downtime at Gas Fuel Price Difference:$182,125$182,125$182,125$182,125$182,125$182,125Total Annualized Cost:$963,413 $1,105,732 $5,081,539 $14,190,215$572,769$821,184$2,904,607Cost Effectiveness Relative to Baseline Current Equipment, $/Ton Removed:$1,953$2,241$4,682$28,762$1,466$2,102$3,380Incremental Cost Effectiveness Relative to LNB on Boiler 20 Only, $/Ton Removed:$3,803$5,189$6,490$132,585$4,974Annualinterestrate(fractional):0.07C ontrolsystemlife(years):15C apitalrecoveryfactor(system ):0.110Date: September 18, 2007Page 88 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 8-2 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at Average Firing Rate & AverageCoal QualityBART For SO2 and NOx for Both Boilers 20 & 24 Based on Actual Average Operation & Average Coal QualitySO2 Model Case Identifier-->AFKM H C P O J EBoilers 20 & 24Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24SO2 ECONOMIC PARAMETERSBASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 using Coal 3 using Coal 2 using current CoalFACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1 Coal 2Coal 3 using Coal 3 using Coal 2 using current Coal using current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler20 Only w/Control Option -->No FGDNo FGDNo FGD95% WSS95% WSS95% WSS50% Gas Cofiring95% WSS95% WSS95% WSSCoal Percent Sulfur-->1.761.501.001.001.501.761.761.001.501.76A&E Emission Rate, lb/MMBtu -->2.852.431.620.080.120.142.850.080.120.14SO2 Emission Rate at DHI, lb/hr-->2,1631,8431,22961921081081545818960Annual SO2 Emissions, TPY-->5,2234,4512,96814822326126115728581007Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->1,1921,016678345160596131196230A&E Total Capital Requirement:$63,365,423 $63,365,423$63,365,423$35,425,148 $35,425,148 $35,425,148O&M Costs @ 8% + reagent + waste disposal:$7,075,278$7,045,950$15,288,468$4,538,431$4,513,513$9,338,316Range:+50/-30+50/-30+50/-30+50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0$10$15$15$10$0$0$15$10$0Coal Change Annual Additional Cost :$1,561,889 $2,342,834 $2,342,834$1,561,889$0$2,342,834$1,561,889$0Natural Gas Cofiring Incremental Cost Increase:$11,561,886Capital Recovery Costs:$6,957,183$6,957,183$6,957,183$3,889,491$3,889,491$3,889,491Total Annual Costs Excluding Coal Change:$14,032,461 $14,003,133$22,245,651$8,427,922$8,403,004$13,227,807Annual Emissions Reduction vs Baseline Current Coal:7722,2555,0755,0004,9622,6114,6514,3654,216Annual Emissions Reduction vs Coal 2:1,4844,3034,2294,1901,8403,8793,5933,444Annual Emissions Reduction vs Coal 3:2,8192,7452,7063562,3952,1091,960Downtime at Gas Fuel Price Difference:$2,870,784$2,870,784$2,870,784$2,870,784$2,870,784$2,870,784Amotized Downtime at Gas Fuel Price Difference:$315,197$315,197$315,197$315,197$315,197$315,197Total Annualized Cost:$1,561,889 $2,342,834 $16,690,492 $15,880,219$22,560,847$11,561,886 $11,085,953 $10,280,090 $13,543,003Cost Effectiveness Relative to Baseline Current Coal, $/Ton Removed:$2,024$1,039$3,289$3,176$4,547$4,427$2,384$2,355$3,212Cost Effectiveness Relative to Coal 2, $/Ton Removed:$526$3,516$3,386$5,011$5,435$2,455$2,426$3,479Cost Effectiveness Relative to Coal 3, $/Ton Removed:$5,089$4,932$7,470$25,888$3,650$3,763$5,713NOx Model Case Identifier-->ABBC B D D ENOx ECONOMIC PARAMETERSBASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boiler 24 As-Is & Boiler 24 As-Is & Boiler 24 As-Is &FACTORED ESTIMATE FROM RTP DATABASEusing current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler 20 Only w/Control Option -->CCLNBSNCRLNB+SCR50% Gas CofiringLNBSNCRLNB+SCRNOx Emission Rate at DHI, lb/hr-->42125225250252324324208Annual NOx Emissions, TPY-->1,002601601120601664664259Equivalent Annual Average Hourly NOx Emissions, lb/hr-->2291371372713715215259A&E Total Capital Requirement:$5,215,728 $3,122,793 $31,225,760$2,607,864$1,856,689$17,355,321O&M Costs:$208,629$495,370 $1,717,752$104,315$386,598$961,372Range:+50/-30+50/-30+50/-30+50/-30+50/-30+50/-30Natural Gas Cofiring Incremental Cost Increase:$11,561,886Capital Recovery Costs:$572,659$342,866 $3,428,421$286,329$203,854$1,905,521Total Annual Costs Excluding Downtime Gas Cost:$781,288$838,236 $5,146,173$390,644$590,453$2,866,892Annual Emissions Reduction:401401882401338338744Downtime at Gas Fuel Price Difference:$1,435,392 $1,435,392 $1,435,392$1,435,392$1,435,392$1,435,392Amotized Downtime at Gas Fuel Price Difference:$157,598$157,598$157,598$157,598$157,598$157,598Total Annualized Cost:$938,886$995,834 $5,303,771 $11,561,886$548,242$748,051$3,024,491Cost Effectiveness Relative to Baseline Current Equipment, $/Ton Removed:$2,342$2,484$6,012$28,835$1,622$2,213$4,067Incremental Cost Effectiveness Relative to LNB on Boiler 20 Only, $/Ton Removed:$6,209$7,114$8,741$175,058$6,104Annualinterestrate(fractional):0.07C ontrolsystemlife(years):15C apitalrecoveryfactor(system ):0.110Date: September 18, 2007Page 89 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 8-3 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Combined Maximum Daily EmissionsSO2 Model Case Identifier-->AFKM H CP O J ECF as annualoperatingrate=80%BASES --->CFas annualaverage % ofmax dailyemissions=92%Coal HHV, Btu/lbAs-Received=11,428Per Boiler MMBtu/hr = 445Per Boiler SCFM=107,453Natural Gas PriceDifferential Over Coal,$/MMBtu=$6.00SO2 ECONOMIC PARAMETERSBASELINE+ Coal 2Coal 3 Boiler 20Boiler 20Boiler 20 Boiler 20Boiler 20Boiler 20Boiler 20FACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current CoalControl Option -->No FGDNo FGDNo FGD85% SDA+FF95% WSS85% SDA+FF95% WSS85% SDA+FF95% WSS50% Gas CofiringCoal Percent Sulfur-->1.881.501.001.001.001.501.501.881.881.88A&E Emission Rate, lb/MMBtu -->3.132.491.660.250.080.370.120.470.163.13SO2 Emission Rate at DHI, lb/hr-->13911110740111371665520970695Annual SO2 Emissions, TPY-->5632449429964491506742258452822816Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->12861026684103341545119364643A&E Total Capital Requirement:$52,388,658 $35,425,148 $52,388,658 $35,425,148 $52,388,658$35,425,148O&M Costs @ 8% + reagent + waste disposal:$5,057,064 $5,001,297 $5,019,522 $4,971,689 $10,010,512$9,968,709Range:+50/-30+50/-30+50/-30 +50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0$10$15$15$15$10$10$0$0$0Coal Change Annual Additional Cost :$0$1,576,779 $2,365,168 $2,365,168 $2,365,168 $1,576,779 $1,576,779$0$0Natural Gas Cofiring Incremental Cost Increase:$11,352,241Capital Recovery Costs:$5,751,993 $3,889,491 $5,751,993 $3,889,491 $5,751,993$3,889,491Total Annual Costs Excluding Coal Change:$10,809,057 $8,890,788 $10,771,515 $8,861,180 $15,762,505$13,858,200Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3:$4,245$3,124$4,639$3,198$7,328$5,106Annual Emissions Reduction vs Baseline Current Coal:1,1382,6365,1835,4824,9585,4084,7875,3512,816Annual Emissions Reduction vs Coal 2:1,4984,0444,3443,8204,2693,6494,2121,678Annual Emissions Reduction vs Coal 3:2,5462,8462,3222,7712,1512,7141808 Weeks Downtime at Gas Fuel Price Difference:$3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550$3,317,550Amotized Downtime at Gas Fuel Price Difference:$364,249$364,249$364,249 $364,249$364,249$364,249Cost Effectiveness Relative to Baseline Current Coal:$1,385$897$2,612$2,120$2,564$1,998$3,369$2,658$4,031Cost Effectiveness Relative to Coal 2:$526$2,958$2,312$2,915$2,161$3,987$3,002$5,827Cost Effectiveness Relative to Coal 3:$4,388$3,252$4,457$3,045$6,398$4,369$49,997NOx Model Case Identifier-->ABBC B DD ENOx ECONOMIC PARAMETERSBASELINE+ Boiler 20 Boiler 20 Boiler 20Boiler 20FACTORED ESTIMATE FROM RTP DATABASEusing current CoalControl Option -->CCLNBSNCRLNB+SCR50% Gas CofiringA&E Emission Rate, lb/MMBtu -->0.5420.3250.3250.0650.325NOx Emission Rate at DHI, lb/hr-->24114514529145Annual NOx Emissions, TPY-->977586586117586Equivalent Annual Average Hourly NOx Emissions, lb/hr-->22313413427134A&E Total Capital Requirement:$2,607,864 $1,856,689 $17,355,321O&M Costs:$104,315 $435,205 $816,962Range:+50/-30+50/-30+50/-30Natural Gas Cofiring Incremental Cost Increase:$11,352,241Capital Recovery Costs:$286,329 $203,854 $1,905,521Total Annual Costs:$390,644 $639,059 $2,722,483Cost Effectiveness w/o Gas Cost:$1,000$1,636$3,168Annual Emissions Reduction:3913918593914 Weeks Downtime at Gas Fuel Price Difference:$1,658,775 $1,658,775 $1,658,775Amotized Downtime at Gas Fuel Price Difference:$182,125 $182,125 $182,125Overall Cost Effectiveness:$1,466$2,102$3,380$29,059ESTIMATE USING USEPA REFERENCESLOW LNBSNCRLNB+SCREmission Rate, lb/MMBtu -->0.540.3250.3250.065Total Capital Requirement:$400,500 $1,112,500 $2,562,142O&M Costs:$44,500 $222,500 $199,674Range:LOWHIGHNACapital Recovery Costs:$43,973 $122,147 $281,309Total Annual Costs:$88,473 $344,647 $480,983Annualinterestrate(fractional): 0.07Cost Effectiveness:$226$882$560Controlsystemlife(years): 15Annual Emissions Reduction:391391859C apitalrecoveryfactor(system ):0.110BART FOR SO2 & NOX BOILER # 20 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-06Date: September 18, 2007Page 90 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 8-4 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Average Firing Rate & Average Coal QualityBART for SO2 & NOX Boiler # 20 Based on Actual Average Operation & Average Coal QualitySO2 Model Case Identifier-->AFKM H CP O J ECF as annualoperatingrate=80%BASES --->CFas annualaverage % of maxdaily emissionsrate=92%Coal HHV, Btu/lbAs-Received=11,750Per Boiler MMBtu/hr = 445Per Boiler SCFM=107,453Natural Gas PriceDifferential Over Coal,$/MMBtu=$6.00SO2 ECONOMIC PARAMETERSBASELINE+ Coal 2Coal 3 Boiler 20Boiler 20Boiler 20 Boiler 20Boiler 20Boiler 20Boiler 20FACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current CoalControl Option -->No FGDNo FGDNo FGD85% SDA+FF95% WSS85% SDA+FF95% WSS85% SDA+FF95% WSS50% Gas CofiringCoal Percent Sulfur-->1.761.501.001.001.001.501.501.761.761.76A&E Emission Rate, lb/MMBtu -->2.852.431.620.240.080.360.120.430.142.85SO2 Emission Rate at DHI, lb/hr-->12661079720108361625419063633Annual SO2 Emissions, TPY-->4438378225213781265671896662222219Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->101386357686291304315251507A&E Total Capital Requirement:$52,388,658 $35,425,148 $52,388,658 $35,425,148 $52,388,658$35,425,148O&M Costs @ 8% + reagent + waste disposal:$4,869,357 $4,538,431 $4,837,761 $4,513,513 $9,659,091$9,338,316Range:+50/-30+50/-30+50/-30 +50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0$10$15$15$15$10$10$0$0$0Coal Change Annual Additional Cost :$0$1,327,047 $1,990,570 $1,990,570 $1,990,570 $1,327,047 $1,327,047$0$0Natural Gas Cofiring Incremental Cost Increase:$9,823,464Capital Recovery Costs:$5,751,993 $3,889,491 $5,751,993 $3,889,491 $5,751,993$3,889,491Total Annual Costs Excluding Coal Change:$10,621,350 $8,427,922 $10,589,754 $8,403,004 $15,411,084$13,227,807Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3:$4,956$3,518$5,419$3,603$8,305$5,752Annual Emissions Reduction vs Baseline Current Coal:6561,9164,0594,3123,8704,2493,7724,2162,219Annual Emissions Reduction vs Coal 2:1,2613,4043,6563,2153,5933,1163,5601,563Annual Emissions Reduction vs Coal 3:2,1432,3951,9542,3321,8562,3003038 Weeks Downtime at Gas Fuel Price Difference:$2,870,784 $2,870,784 $2,870,784 $2,870,784 $2,870,784$2,870,784Amotized Downtime at Gas Fuel Price Difference:$315,197$315,197$315,197 $315,197$315,197$315,197Cost Effectiveness Relative to Baseline Current Coal:$2,024$1,039$3,184$2,490$3,160$2,364$4,169$3,212$4,427Cost Effectiveness Relative to Coal 2:$526$3,408$2,573$3,392$2,426$4,620$3,431$5,435Cost Effectiveness Relative to Coal 3:$5,103$3,650$5,241$3,454$7,402$5,024$25,888ESTIMATE USING USEPA APCTFSLOW FGDHIGH FGDLOW FGDHIGH FGDLOW FGDHIGH FGDEmission Rate, lb/MMBtu -->0.240.080.360.120.430.14Total Capital Requirement:$11,769,718 $66,750,000 $11,769,718 $66,750,000 $11,769,718$66,750,000O&M Costs Including Coal Change Cost:$2,346,570 $2,791,570 $1,683,047 $2,128,047$356,000$801,000Range:LOWHIGHLOWHIGHLOWHIGHCapital Recovery Costs:$1,292,252 $7,328,791 $1,292,252 $7,328,791 $1,292,252$7,328,791Total Annual Costs:$3,638,822 $10,120,361 $2,975,299 $9,456,838 $1,648,252$8,129,791Cost Effectiveness vs Baseline Current Coal:$896$2,347$769$2,226$437$1,928Annual Emissions Reduction vs Baseline Current Coal:4,0594,3123,8704,2493,7724,216NOx Model Case Identifier-->ABBC B DD ENOx ECONOMIC PARAMETERSBASELINE+ Boiler 20 Boiler 20 Boiler 20Boiler 20FACTORED ESTIMATE FROM RTP DATABASEusing current CoalControl Option -->CCLNBSNCRLNB+SCR50% Gas CofiringA&E Emission Rate, lb/MMBtu -->0.540.3250.3250.0650.325NOx Emission Rate at DHI, lb/hr-->24114514529145Annual NOx Emissions, TPY-->845507507101507Equivalent Annual Average Hourly NOx Emissions, lb/hr-->19311611623116A&E Total Capital Requirement:$2,607,864 $1,856,689 $17,355,321O&M Costs:$104,315 $386,598 $961,372Range:+50/-30 +50/-30 +50/-30Natural Gas Cofiring Incremental Cost Increase:$9,823,464Capital Recovery Costs:$286,329 $203,854 $1,905,521Total Annual Costs:$390,644 $590,453 $2,866,892Cost Effectiveness w/o Gas Cost:$1,156$1,747$3,855Annual Emissions Reduction:3383387443384 Weeks Downtime at Gas Fuel Price Difference:$1,435,392 $1,435,392 $1,435,392Amotized Downtime at Gas Fuel Price Difference:$157,598 $157,598 $157,598Overall Cost Effectiveness:$1,622$2,213$4,067$29,059ESTIMATE USING USEPA REFERENCESLOW LNBSNCRLNB+SCREmission Rate, lb/MMBtu -->0.540.3250.3250.065Total Capital Requirement:$400,500 $1,112,500 $7,439,363O&M Costs:$44,500 $222,500 $417,242Range:LOWHIGHNACapital Recovery Costs:$43,973 $122,147 $816,802Total Annual Costs:$88,473 $344,647 $1,234,044Annualinterestrate(fractional): 0.07Cost Effectiveness:$262$1,020$1,659C ontrolsystemlife(years): 15Annual Emissions Reduction:338338744C apitalrecoveryfactor(system ):0.110Date: September 18, 2007Page 91 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 8-5 BART Economic Analysis for DuPont Old Hickory Boiler 24 at Maximum Combined Daily EmissionsSO2 Model Case Identifier-->AFKM H CP O J ECF as annualoperatingrate=20%BASES --->CFas annualaverage % ofmax dailyemissions=33%Coal HHV, Btu/lbAs-Received=11,428Per Boiler MMBtu/hr = 315Per Boiler SCFM=81,478Natural Gas PriceDifferential Over Coal,$/MMBtu=$6.00SO2 ECONOMIC PARAMETERSBASELINE+ Coal 2Coal 3 Boiler 24Boiler 24Boiler 24 Boiler 24Boiler 24Boiler 24Boiler 24FACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current CoalControl Option -->No FGDNo FGDNo FGD85% SDA+FF95% WSS85% SDA+FF95% WSS85% SDA+FF95% WSS50% Gas CofiringCoal Percent Sulfur-->1.881.501.001.001.001.501.501.881.881.88A&E Emission Rate, lb/MMBtu -->3.132.491.660.250.080.370.120.4690.1563.13SO2 Emission Rate at DHI, lb/hr-->98578652479261183914849492Annual SO2 Emissions, TPY-->14081123749112371695621170704Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->32125617126938134816161A&E Total Capital Requirement:$41,319,616 $27,940,275 $41,319,616 $27,940,275 $41,319,616$27,940,275O&M Costs @ 8% + reagent + waste disposal:$3,522,056 $2,777,027 $3,512,670 $2,769,625 $7,018,208$6,276,670Range:+50/-30+50/-30+50/-30 +50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0$10$15$15$15$10$10$0$0$0Coal Change Annual Additional Cost :$0$394,183 $591,274 $591,274$591,274$394,183 $394,183$0$0Natural Gas Cofiring Incremental Cost Increase:$2,837,974Capital Recovery Costs:$4,536,672 $3,067,692 $4,536,672 $3,067,692 $4,536,672$3,067,692Total Annual Costs Excluding Coal Change:$8,058,727 $5,844,719 $8,049,342 $5,837,317 $11,554,880$9,344,362Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3:$12,659$8,215$13,868$8,426$21,488$13,771Annual Emissions Reduction vs Baseline Current Coal:2856591,2961,3711,2401,3521,1971,338704Annual Emissions Reduction vs Coal 2:3741,0111,0869551,0679121,053419Annual Emissions Reduction vs Coal 3:63771158069353867945Downtime at Gas Fuel Price Difference:$0$0$0$0$0$0Amotized Downtime at Gas Fuel Price Difference:$0$0$0$0$0$0Cost Effectiveness Relative to Baseline Current Coal:$1,385$897$6,676$4,696$6,812$4,610$9,655$6,986$4,031Cost Effectiveness Relative to Coal 2:$526$8,165$5,563$8,429$5,469$12,235$8,500$5,827Cost Effectiveness Relative to Coal 3:$12,659$8,215$13,528$8,141$20,388$12,900$49,997NOx Model Case Identifier--> ABBCBNOx ECONOMIC PARAMETERSBASELINE+ Boiler 24 Boiler 24 Boiler 24Boiler 24FACTORED ESTIMATE FROM RTP DATABASEusing current CoalControl Option -->CCLNBSNCRLNB+SCR50% Gas CofiringA&E Emission Rate, lb/MMBtu -->0.570.3420.3420.0680.342NOx Emission Rate at DHI, lb/hr-->18010810822108Annual NOx Emissions, TPY-->25715415431154Equivalent Annual Average Hourly NOx Emissions, lb/hr-->593535735A&E Total Capital Requirement:$2,607,864 $1,266,104 $13,870,439O&M Costs:$104,315 $145,537 $654,032Range:+50/-30 +50/-30 +50/-30Natural Gas Cofiring Incremental Cost Increase:$2,837,974Capital Recovery Costs:$286,329 $139,011 $1,522,900Total Annual Costs:$390,644 $284,548 $2,176,931Cost Effectiveness w/o Gas Cost:$3,803$2,770$9,634Annual Emissions Reduction:103103226103Downtime at Gas Fuel Price Difference:$0$0$0Amotized Downtime at Gas Fuel Price Difference:$0$0$0Overall Cost Effectiveness:$3,803$2,770$9,634$27,632ESTIMATE USING USEPA REFERENCESLOW LNBSNCRLNB+SCREmission Rate, lb/MMBtu -->0.570.3420.3420.068Total Capital Requirement:$283,500 $787,500 $2,063,784O&M Costs:$31,500 $157,500 $157,419Range:LOWHIGHNACapital Recovery Costs:$31,127 $86,463 $226,592Total Annual Costs:$62,627 $243,963 $384,011Annualinterestrate(fractional): 0.07Cost Effectiveness:$610$2,375$1,699C ontrolsystemlife(years): 15Annual Emissions Reduction:103103226C apitalrecoveryfactor(system ):0.110BART FOR SO2 & NOX BOILER # 24 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-06Date: September 18, 2007Page 92 of 92Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 8-6 BART Economic Analysis for DuPont Old Hickory Boilers 24 at Average Firing Rate & Average CoalQualityBART for SO2 & NOX Boiler # 24 Based on Actual Average Operation & Average Coal QualitySO2 Model Case Identifier-->AFKM H CP O J ECF as annualoperatingrate=20%BASES --->CF as annualaverage % of maxdaily emissions rate=33%Coal HHV, Btu/lbAs-Received=11,750Per Boiler MMBtu/hr = 315Per Boiler SCFM=81,478Natural Gas PriceDifferential Over Coal,$/MMBtu=$6.00SO2 ECONOMIC PARAMETERSBASELINE+Coal 2Coal 3 Boiler 24Boiler 24Boiler 24 Boiler 24Boiler 24Boiler 24Boiler 24FACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current CoalControl Option -->No FGDNo FGDNo FGD85% SDA+FF95% WSS85% SDA+FF95% WSS85% SDA+FF95% WSS50% Gas CofiringCoal Percent Sulfur-->1.761.501.001.001.001.501.501.761.761.76A&E Emission Rate, lb/MMBtu -->2.852.431.620.240.080.360.120.4270.1422.85SO2 Emission Rate at DHI, lb/hr-->89676450976251153813445448Annual SO2 Emissions, TPY-->78566944667221003311839393Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->17915310215523827990A&E Total Capital Requirement:$41,319,616 $27,940,275 $41,319,616$27,940,275 $41,319,616$27,940,275O&M Costs @ 8% + reagent + waste disposal:$3,425,599 $2,536,847 $3,420,008 $2,532,437 $6,837,108$5,950,152Range:+50/-30+50/-30+50/-30 +50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0$10$15$15$15$10$10$0$0$0Coal Change Annual Additional Cost :$0$234,843 $352,264 $352,264$352,264$234,843 $234,843$0$0Natural Gas Cofiring Incremental Cost Increase:$1,738,422Capital Recovery Costs:$4,536,672 $3,067,692 $4,536,672 $3,067,692 $4,536,672$3,067,692Total Annual Costs Excluding Coal Change:$7,962,271 $5,604,539 $7,956,679 $5,600,129 $11,373,780$9,017,844Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3:$20,994$13,222$23,009 $13,568$34,634$22,160Annual Emissions Reduction vs Baseline Current Coal:116339718763685752668746393Annual Emissions Reduction vs Coal 2:223602647569636552630277Annual Emissions Reduction vs Coal 3:37942434641332840754Downtime at Gas Fuel Price Difference:$0$0$0$0$0$0Amotized Downtime at Gas Fuel Price Difference:$0$0$0$0$0$0Cost Effectiveness Relative to Baseline Current Coal:$2,024$1,039$11,574$7,807$11,960$7,761$17,039$12,087$4,427Cost Effectiveness Relative to Coal 2:$526$13,413$8,844$13,986$8,808$20,197$13,940$5,435Cost Effectiveness Relative to Coal 3:$20,994$13,222$22,670 $13,284$33,561$21,295$25,888ESTIMATE USING USEPA APCTFSLOW FGDHIGH FGDLOW FGDHIGH FGDLOW FGDHIGH FGDEmission Rate, lb/MMBtu -->0.240.080.360.120.430.14Total Capital Requirement:$8,363,868 $47,250,000 $8,363,868$47,250,000 $8,363,868$47,250,000O&M Costs Including Coal Change Cost:$604,264$919,264$486,843 $801,843$252,000$567,000Range:LOWHIGHLOWHIGHLOWHIGHCapital Recovery Costs:$918,308$5,187,796$918,308 $5,187,796$918,308$5,187,796Total Annual Costs:$1,522,572 $6,107,060 $1,405,150 $5,989,639 $1,170,308$5,754,796Cost Effectiveness vs Baseline Current Coal:$2,119$8,004$2,052$7,967$1,753$7,714Annual Emissions Reduction vs Baseline Current Coal:718763685752668746NOx Model Case Identifier-->ABBCBNOx ECONOMIC PARAMETERSBASELINE+ Boiler 24 Boiler 24 Boiler 24Boiler 24FACTORED ESTIMATE FROM RTP DATABASEusing current CoalControl Option -->CCLNBSNCRLNB+SCR50% Gas CofiringA&E Emission Rate, lb/MMBtu -->0.570.3420.3420.0680.342NOx Emission Rate at DHI, lb/hr-->18010810822108Annual NOx Emissions, TPY-->157 94 94 19 94Equivalent Annual Average Hourly NOx Emissions, lb/hr-->362222422A&E Total Capital Requirement:$2,607,864 $1,266,104 $13,870,439O&M Costs:$104,315 $108,772 $756,381Range:+50/-30 +50/-30 +50/-30Natural Gas Cofiring Incremental Cost Increase:$1,738,422Capital Recovery Costs:$286,329 $139,011 $1,522,900Total Annual Costs:$390,644 $247,783 $2,279,280Cost Effectiveness w/o Gas Cost:$6,209$3,938$16,467Annual Emissions Reduction:636313863Downtime at Gas Fuel Price Difference:$0$0$0Amotized Downtime at Gas Fuel Price Difference:$0$0$0Overall Cost Effectiveness:$6,209$3,938$16,467$27,632ESTIMATE USING USEPA REFERENCESLOW LNBSNCRLNB+SCREmission Rate, lb/MMBtu -->0.570.3420.3420.068Total Capital Requirement:$283,500 $787,500 $5,890,875O&M Costs:$31,500 $157,500 $317,174Range:LOWHIGHNACapital Recovery Costs:$31,127 $86,463 $646,786Total Annual Costs:$62,627 $243,963 $963,960Annualinterestrate(fractional): 0.07Cost Effectiveness:$995$3,878$6,964C ontrolsystemlife(years): 15Annual Emissions Reduction:6363138C apitalrecoveryfactor(system ):0.110

# DuPont Research and Engineering Technology



# Final Report - Results of BART Modeling & Engineering Analysis @ Maximum 24-hour Firing Rates Using the New IMPROVE Equation

For



# E. I. duPont de Nemours and Company. Old Hickory Plant

1002 Industrial Road Old Hickory, TN 37138

For submission to:

TN Department of Environment
and Conservation
Division of Air Pollution Control 9th Floor, L & C Annex
401 Church Street Nashville, TN 37243-1531 Metro Public Health Department

of Nashville
Pollution Control Division Office
Lentz Public Health Center

Room 208

311 23rd Avenue North Nashville, TN 37203

Prepared by:

Bruce C. Davis Charles J. Zarzecki & John C. deRuyter DuPont Engineering Technology DuPont Engineering Technology 140 Cypress Station Drive, Su ite 135 1007 Market Street Houston, TX 77062 Wilmington, DE 19898



# September 18, 2007

### Date: September 18, 2007 Page 2 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# This page intentionally left blank

### Date: September 18, 2007 Page 3 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table of Contents

1. Summary ..................................................................................................................... 4

2. Background and Introduction ..................................................................................... 4

3. Description of the Old and New IMPROVE Equations ............................................. 4

4. Modeling Results with New IMPROVE Equation ..................................................... 7

5. References ................................................................................................................. 10

### Date: September 18, 2007 Page 4 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 1. Summary

The BART (Best Available Retrofit Technol ogy) Modeling results presented in this report show that the emissions from the Du Pont Old Hickory Plant are not predicted

cause or contribute to visibil ity impairment at any of the n earby Class 1 areas within 300 km of the Old Hickory Plant.

Based on this analysis, no further evaluation is needed related to BART for the emission sources and the DuPont Old Hickory Plant.



# 2. Background and Introduction

The Interagency Monitoring of Protected Visu al Environments (IMP ROVE) protocols for reconstructing ambient light extinction from measured aerosol species are the basis for evaluating light extinction from BART mode ling results. The BART emission sources and the BART modeling effort for the DuPont Old Hickory Plant in Old Hickory, TN are described in the companion report entitled: “Results of BART Modeling & Engineering Analysis @ Maximum 24-hour Firing Rate s Using the Old IMPROVE Equation”. As stated in the report title, th e companion report provides the modeling results as analyzed using the old IMPROVE equation.

The same BART modeling results are analyz ed in this report using the new IMPROVE equation. The modeling protocol and the modeling results were not changed. The modeling was done per the protoc ol described and used in th e companion report. Only the two base cases were re-analyzed. The tw o base cases were at the 24 hour maximum firing rate, modeled to occur year round and at the monthly maximum firing rate, modeled to occur year round. The basis fo r these firing rates is described in the companion report.



# 3. Description of the Old and New IMPROVE Equations

The Interagency Monitoring of Protected Visu al Environments (IMP ROVE) protocols for reconstructing ambient light extinction from measured aerosol species are the basis for evaluating light extinction from BART mode ling results. The following discussion on the old IMPROVE equation was taken from Reference 1:

“The current IMPROVE algorithm for estimating light extinction from IMPROVE particle monitoring data assumes that absorption by gases ( b a,g 

# ) is zero, that Raylei gh scattering ( b s,g 

# ) is 10Mm -1 

# for each monitoring site regardless of site elevation and meteorological c ondition, and that particle scattering and absorption ( b s,p 

# and b a,p 

# ) can be estimated by multiplying the concentrations of each of six major components by typical component-specific light extinction efficiencies. The six major components are sulfate (assumed to be ammonium

### Date: September 18, 2007 Page 5 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# sulfate), nitrate (assumed to be ammoni um nitrate), organic compounds (based on measured organic carbon mass), elementa l or black carbon (directly measured), fine soil (crustal elements plus oxides) and coarse mass (the difference between

PM 10 

# and PM 2.5 

# mass concentrations). The component extinction efficiency values are constants, except for the sulfat e and nitrate extinction efficiency terms that include a water growth factor th at is a function of relative humidity (displayed as f(RH) ) multiplied by a constant dry extinction efficiency. Monthly averaged water growth terms for each site were developed because most monitoring sites don’t include on-site relative humid ity monitoring. Expressed as an equation, the current algorithm for es timating light extinction from IMPROVE data takes the following form where the particle component concentrations are

indicated in the brackets. The form ulas for the composite components are available elsewhere (IMPROVE web site).



# [ ] [ ] [ ]

[ ] [ ] [ ]

10 6.0 1 10 4 )(3 )(3

+ ×+ ×+ ×+ ×+ ××+ × × ≈

Mass Coarse SoilFine Carbon

Elemental Mass Organic Nitrate RHf Sulfate RHfb

ext



# The units for light extinction and Rayl eigh scattering are inverse megameters (1/10 6 

# m usually written Mm -1 

# ); component concentrations shown in brackets are in microgram per meter cubed ( μ g/m 3 

# ); dry efficiency terms are in units of meters squared per gram (m 2 

# /g); and the water growth terms, f(RH), are unitless.”

The values for the f (RH) term used in this equation are provided in Table 6-12 in the companion report for each of the Class 1 areas evaluated as part of this study.

The following discussion on the new IMPROVE equation is taken from reference 3:

“Recently, the IMPROVE Steering Committ ee developed a new algorithm for estimating light extinction from partic ulate matter component concentrations. This algorithm (the ‘new IMPROVE al gorithm’) provides a better correspondence between the measured visibility and th at calculated from particulate matter component concentrations. The new algorith m differs in several substantive ways

from the traditional one:

• The extinction efficiencies of sulfates , nitrates, and organics have been changed and are now functions of their concentrations. The extinction

efficiencies of sulfate and nitrate are no longer identic al, although the new hygroscopic scattering enhancement factors applied to them are the same.

### Date: September 18, 2007 Page 6 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# • The concentration of particulate or ganic matter (POM; variously also labeled OCM or OMC, and sometimes just called “organics”) is now taken

to be 1.8 times that of the measured organic carbon (OC) concentration.

• The contribution of fine sea salt to li ght extinction has been added, and is accompanied by its own hygroscopic scattering enhancement factor, fss(RH).

• The light scattering by air it self (Rayleigh scattering) now varies with site elevation and mean temperature. It is to be rounded off to the nearest one Mm-1 when used with the new algorithm.

• The light absorption by NO2 gas has been added.

The new IMPROVE algorithm is represented by the following formula :

b ext 

# = 2.2•f S 

# (RH)•[small sulfate] + 4.8•f L 

# (RH)•[large sulfate] +2.4•f S 

# (RH)•[small nitrate] + 5.1•f L 

# (RH)•[large nitrate] +2.8•[small organics] + 6.1•[large organics] +10•[elemental carbon] +1•[fine soil] +1.7•f SS 

# (RH)•[sea salt] +0.6•[coarse matter] +Rayleigh scattering (site specific) +0.33•[NO 2 

# (ppb)]

The concentrations of “large” and “sma ll” sulfate particles are calculated as

follows: [large sulfate] = {[total sulfate]/20}•[total sulfate] if [total sulfate] < 20 μ g 3 

# [large sulfate] = [total su lfate] if [total sulfate] ≥ 20 μ g/m 3 

# [small sulfate] = [total sulfate] – [large sulfate].

Identical formulas, with ch anges in component names, are used for nitrate and organics.

In effect, these formulas conclude that low concentrations of these components are mainly in the form of “small” partic les with their own extinction efficiency

and f S 

# (RH), while high concentr ations (approaching 20 μ g/m3) are mainly in the form of “large” particles with a differe nt extinction efficiency and fL(RH). The scaling factor [total sulfate]/20 sets the fraction of total sulfate that is small.”

Dr. Ivar Tombach, under contract to VISTAS, developed a CALPOST IMPROVE

Processor to enable the estimation of the CALPUFF-modeled source impacts on visibility using the new IMPROVE algorithm. The Pr ocessor is available from the weblink provided in reference 4 and operates as an Excel spreadsheet. This spreadsheet was used, together with the instructions (reference 3) to evaluate the CA LPUFF modeling results using the new IMPROVE equation.

### Date: September 18, 2007 Page 7 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 4. Modeling Results with New IMPROVE Equation

The modeling results using the new IMPROVE equation are presented in Table 4-1

Table 4-1 – DuPont Old Hickory B ART Modeling Results using the New IMPROVE Equation

Mammoth Cave @ 24 hr Max Rate

0.47 5 0.48 7 0.5 7 Mammoth Cave @ Monthly Avg Max Rate

0.35 0 0.35 3 0.36 3
Cohutta Wilderness @ 24 hr Max Rate

0.1 0 0.13 0 0.16 0 Great Smoky Mountains National Park @

24 hr Max Rate 0.12 0 0.11 0 0.22 1 Joyce Kilmer Wilderness @ 24 hr Max

Rate 0.1 1 0.1 0 0.19 0 Sipsey Wilderness @ 24 hr Max Rate

0.21 0 0.22 1 0.31 0 Class 1 Area 2001 2002 2003

Modeled 98th percentile

Value

(dV) No Days exceeding 0.5

dV Modeled 98th percentile

Value

(dV) No Days exceeding 0.5

d V Modeled 98th percentile

Value

(dV) No Days exceeding 0.5

d V



# This is a significant reduction in predicted vi sibility impact for the boilers at the DuPont Old Hickory Plant compared to the analys is using the old IMPROVE equation. These results were performed using the fine grid meteorological data files for the modeling domain. Based on these results, the day count above an impact of 0.5 dV predicted to be less than 8 days. The emissions from th e DuPont Old Hickory Plant are thus not predicted to cause or contribute to visibility impairment at Mammoth Cave, or any of the

other Class 1 sites evaluated. Further control of these emissi ons and further evaluation is

not necessary.

The results in Table 4-1 were estimated using the maximum 24 hour firi ng rate for all the

Class 1 areas assessed. For Mammoth Cave, the results for two firing rates are presented,

one at the maximum 24 hour rate and one at the maximum monthly firing rate. For reasons discussed in the companion report, we believe that the resu lts using the monthly maximum firing rates are more representative of the firing patterns for the Old Hickory

Boilers.

For purposes of comparison, the modeling resu lts using the old IMPROVE equation are:

### Date: September 18, 2007 Page 8 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# Table 4-2 DuPont Old Hickory BART Modeling Results at the 24 hour

Maximum Emission Rate usi ng the Old IMPROVE Equation

Mammoth Cave

0.87 35 0.898 29 0.929 27

Cohutta Wilderness

0.189 1 0.239 0 0.304 4 Great Smoky Mountains National Park

0.234 3 0.196 3 0.404 5 Joyce Kilmer Wilderness

0.182 3 0.19 2 0.341 3 Sipsey Wilderness

0.404 2 0.41 3 0.581 10 2003

Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV Modeled 98th perentile Value (dV) Modeled 98th perentile Value (dV) No Days exceeding 0.5

dV No Days exceeding 0.5

dV Class 1 Area 2001 2002



# The reasons for the differences are thought to be due to the changes in the handling of the fine and coarse sulfate and nitrate particles and the change in the Raleigh scattering term

with elevation.

The top 8 modeled values for both firing rate cases for Mammoth Cave are presented in

Table 4-3.Date: September 18, 2007Page 9 of 10Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TNTable 4-3 – Top 8 Modeled dV Results for Mammoth Cave for DuPont, Old Hickory using the New IMPROVEEquation2001 2002 2003 2001 2002 2003Baseline Modeling CasesRank NoDelta dVRanks 1 - 8or > 0.5 dVDelta dVRanks 1 - 8or > 0.5 dVDelta dVRanks 1 - 8or > 0.5 dVAverageDelta dVRanks 1 - 8or > 0.5 dVAverageDelta dVRanks 1 - 8or > 0.5 dVAverageDelta dVRanks 1 - 8or > 0.5 dVBaseline Case@24 hr Max FiringRate10.64 1.16 1.07 0.527 0.692 0.6482 0.56 0.80 0.793 0.53 0.78 0.634 0.52 0.69 0.605 0.51 0.59 0.566 0.50 0.52 0.527 0.49 0.51 0.518 0.47 0.48 0.50Baseline Case@MonthlyMax FiringRate10.42 0.84 0.76 0.375 0.487 0.4772 0.41 0.55 0.573 0.38 0.52 0.514 0.38 0.46 0.425 0.36 0.44 0.416 0.35 0.38 0.397 0.35 0.37 0.388 0.35 0.35 0.36

### Date: September 18, 2007 Page 10 of 10 Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN



# 5. References

1. IMPROVE technical subcommittee for al gorithm review. “Revised IMPROVE Algorithm for Estimating Light Extinction from Particle Speciation Data” Adopted for use by the IMPROVE Steering Committee, Dec, 2005. Available by web from: http://vista.cira.colostate.edu/improve/P ublications/GrayLit/gray_literature.htm

2. J.L. Hand and W.C. Malm. “Review of the IMPROVE Equation for Estimating Ambient Light Extinction Coefficients - Final Report” ISSN 0737-5352-71, March 1, 2006. Available by web from: http://vista.cira.colostate.edu/improve/P ublications/GrayLit/gray_literature.htm

3. Dr. Ivar Tombach. “Instructions: A Po stprocessor for Recalculating CALPOST Visibility Outputs with the New IMPR OVE Algorithm Version 2” October 14, 2006. Available by web from: http://www.vistas-sesarm.org/BART/CALPOSTIMPROVEWorkbook_InstructionsV2_16-Oct06.pdf

4. Dr. Ivar Tombach. “Post Processo r Tool” Available by web from: http://www.vistassesarm.org/BART/calpuff.asp

5. B. C. Davis, C. J. Zarzecki & J. C. DeRuyter. “Results of BART Modeling & Engineering Analysis @ Maximum 24-hour Firing Rates Using the Old IMPROVE Equation”. Submitted to TC DEC & Nas hville Metro Health Dept, Sept. 18, 2007.