Appendix D 

BUSINESS CONFIDENTIAL INFORMATION 

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Appendix L.8 - 198

January 18, 2008
 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, Suite 135 1007 Market Street 

Houston, TX 77062 Wilmington, DE 19898 

September 18, 2007

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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 Options 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 (Subregional 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 Size Basis (1.88% Sulfur Coal)............................................. 46 

Table 6-5 PM Speciation Basis (1.5% Sulfur Coal)..................................................... 47 

Table 6-6 – PM Particle Size Basis (1.5% Sulfur Coal)............................................... 48 

Table 6-7 PM Speciation Basis (1.0% Sulfur Coal)..................................................... 49 

Table 6-8 – PM Particle Size Basis (1.0% Sulfur Coal)............................................... 50 

Table 6-9 PM Speciation Calculations for 1.88% Sulfur Coal Cases.......................... 51 

Table 6-10 PM Speciation Calculations for 1.5% Sulfur Coal Cases.......................... 52 

Table 6-11 PM Speciation Calculations for 1.0% Sulfur Coal Cases.......................... 53 

Table 6-12 Monthly f(RH) Values for Each Class 1 Area........................................... 54 

Figure 6-1 Old Hickory Location and Class 1 Area Distances.................................... 55 

Figure 6-2: DuPont Old Hickory Plant Geo-Referenced Air Photo ............................. 56 

Figure 6-3 VISTAS 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 Control 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 SO2 Scrubbers Using Coal with Various Sulfur Contents........................ 73 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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 SO2 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 Economic 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 SO2 and NOx Emissions Reductions and 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 Environmental Impacts of Compliance.............. 82 

8.8 Conclusions Relative to SO2 and NOx Controls for Boilers 20 and 24............ 83 

Table 8-1 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at 

Maximum Combined Daily Emissions......................................................................... 87 

Table 8-2 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at 

Average Firing Rate & Average Coal Quality.............................................................. 88 

Table 8-3 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Combined 

Maximum Daily Emissions........................................................................................... 89 

Table 8-4 BART Economic Analysis for DuPont 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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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

1 Executive Summary 

The modeling results in this report were analyzed using the old IMPROVE Equation. 

The Interagency Monitoring of Protected Visual Environments (IMPROVE) protocols 

are the basis for evaluating visibility 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, based on the old IMPROVE Equation, show a minor 

visibility impact on Mammoth Cave and a negligible impact on the other Class 1 areas 

within 300 km of the DuPont Old Hickory Plant. These results were high enough to 

trigger an economic and engineering analysis of the options to establish Best Available 

Retrofit Technology (BART) to reduce emissions of visibility impairing species (SO2 and 

NOx) from the Old Hickory Plant. This analysis is presented in this report and shows 

that while the visibility impact can be reduced via BART control technology, the 

reductions are small. Basically, the control options available to be considered as BART 

can make a small impact smaller. In our view, the control options are 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 results 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 report 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 (insignificant) using the 

analysis methods in the Modeling Protocol. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

2 Background & Introduction 

The DuPont Old Hickory Plant Title V Air Permit includes the following information 

relative to the two BART-eligible 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 standby 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 standby fuel- No.2 Fuel 

Oil 

Mass and Visible Emission Standards and Operating Schedule Limitations

• Boilers 20 and 24- visible 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 

PM10 77.4 1858 339.1 

SO2 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 

PM10 54.8 1315 240.1 

SO2 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 CFR 75, Subpart H, NOx Budget Trading 

Program. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

• 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 Plant 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 emissions 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 April, 2007 modeling was with use of a single 

pseudo-stack that was used to represent overall annual operation of both Boilers 20 and 

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

boilers that were indicative of typical operation during 2005 and 2006. Those years were 

subsequent to shutdown of the DMT production facilities. That shutdown significantly 

reduced site steam demand and the Boiler 24 operating rate (it was dedicated 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 demand (winter). The annual capacity factor 

assigned to Boiler 20 was 80% and the annual capacity factor assigned to Boiler 24 was 

20%. These figures provided an operating 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 lineup was changed and both boilers were on line 

for a short period. The pseudo-stack, therefore, 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 Visibility 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 which 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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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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 

SO2 lb/hr 815.4 1129.1 1082.7 

PM10 lb/hr 14.8 13.49 13.68 

NO2 lb/hr 156.7 241.3 228.8 

SO2 ton/yr 4742.3 

NO2 ton/yr 59.9 (Note 1) 

SO2+NO2 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 should 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 feet) represent good engineering 

practice stack heights since the actual heights are less than 213.2 feet (65 m) (all stacks 

are 200 feet tall). If the stacks were greater than good engineering practice stack height, 

the stack heights (for modeling) would be reduced to the good engineering 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 visibility impact and these results triggered the 

need for an engineering control evaluation. The draft Engineering Control modeling 

results and the engineering control evaluation were submitted to the TNDEC and the 

Nashville Metro Health Department on April 4, 2007. The base case for this modeling 

work was changed slightly from the February 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 

SO2 lb/hr 179 1013 1192 

PM10 lb/hr 14.8 13.49 13.68 

NO2 lb/hr 36 193 229 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

SO2 ton/yr 5223 

NO2 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 use of the AP-42 correction factor to convert 

from fuel sulfur to SO2 and a change in the stack gas flow rate and temperature based on 

a review of the data compared to emissions test results. As explained in the note for the 

February emission modeling parameters, the ton/yr NOx emissions were changed due to 

a math error. The lb/hr data for NOx, which 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 predicted to either contribute to or cause 

visibility impairment at these Class 1 Areas. 

2. The visibility impact from DuPont sources at Mammoth Cave is predicted to be 

greater than 8 days above 0.5 dV. None of the 98th percentile modeled values are 

predicted to be greater than 1 dV. Based on this modeling result, the emissions 

from DuPont’s Old Hickory Plant have the potential to contribute to visibility 

impairment at Mammoth Cave. Because the 98th percentile modeled values are 

predicted to be less than 1 dV, the emissions are not predicted to cause visibility 

impairment. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Based on these results, we proceeded to conduct an engineering evaluation of control 

options to mitigate the DuPont, Old Hickory Plant contribution to visibility impairment at 

Mammoth Cave. 

2.1 Revised Modeling Basis for the Current Assessment 

The April 4th work was reviewed with TN DEC and the Nashville Metro Health 

Department at a meeting on April 24th. 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 4th 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 that grossly overstates actual emissions from 

Boilers 20 and 24. However, data was obtained 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 prior 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 technology 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 conservative 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 building and process heating demands that do not 

occur in the summer. Boiler shutdowns for annual inspection/overhaul 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 significant in the summer due to the higher SO2

emissions impact on visibility compared to the winter when visibility impact is more 

sensitive to NOx emissions. See Appendix 3 (Section 7) for detailed information on data 

used to determine the emission rates on the highest 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 Visibility Modeling for DuPont, Old Hickory 

Modeled at the 24 hour Maximum Emission Rate

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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 course 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 analysis is provided in this section. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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 result in reasonable further progress towards 

this goal. Reasonable further progress for Mammoth 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

Year

Haziness 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 degree of reduction needed for sources that are 

predicted to either contribute to or cause visibility 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 

90th 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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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

These data can be used as a benchmark to estimate the percentage contribution by 

DuPont Old Hickory BART eligible sources to visibility impairment 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 Final 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) change 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 following conditions which represent the 

combined annual average capacity factor firing rate conditions. In fact, as shown in the 

chart below, this model basis is essentially equal to the 2006 maximum monthly average 

total heat input condition which is still significantly higher than actual operation of 

Boilers 20 and 24 during summer months: 

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

 SO2 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 the base case currently fired coal at the 

conditions which represent the maximum 24 hour combined emission rate for Boilers 20 

and 24, including use of coal quality data for that day (1.88% S, 11,428 Btu/lb): 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 3-2 – Summary of Modeling Results @ Maximum 24 hr Firing Rate 

SO2 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 (monthly maximum average firing rate). When 

modeled at the maximum 24 hour emissions over the entire year, the number of days 

above 8 days is 27, 20 and 19 for the 2001 – 2003 period. In terms of percentage of 

DuPont’s predicted 98th percentile visibility value for 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 98th percentile value occurred during the 20 % 

worst days at Mammoth Cave. Further, these percentages, if they coincided with the 20 

% of worst days at Mammoth Cave, only would be predicted to occur for 16, 12 and 15 

days or an average of roughly 14 days per year. The results for 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 noted, 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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Appendix L.8 - 213

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

The differences between the heat input rates over the year for 2006 are shown in Figure 

3-2. The maximum daily emission rate case overstates emissions over the year. Further, 

the site firing pattern is typical of a steam supply system primarily providing heat and not 

for electricity generation (e.g., electric utility emission pattern with a summer peak). The 

maximum rates occur in the winter and the minimum rates occur in the summer. For the 

24 hour maximum emission rate, the actual emission rate in the summer is roughly 50 % 

of the 24 hour maximum rate. 

Figure 3-2 Boiler Monthly 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

Jan06Feb06Mar06Apr-06 May06Jun06Jul-06 Aug06Sep06Oct06Nov06Dec06

Month

MMBtu/Month Coal Heat Input

Maximum Daily Emissions Case- 375,410 MMBtu/Month Annual 

Average

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 within 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: 

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Appendix L.8 - 214

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 3-3 Day Count Greater than 0.5 dV – Monthly & 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 maximum 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. The maximum day counts are predicted to occur 

in the months when the actual combined firing rate is lower, thus control strategies 

selected based on these data are not representative 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 analysis 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 displayed in these tables are: 

1. For the data modeled at the annual average capacity factor (monthly maximum) 

firing rate, the $/ton of SO2 removed ranges from $1039/ton to $4547/ton. For the 

lowest cost/ton an improvement of 0.254 dV is predicted for the 98th percentile 

value. In terms of the percent contribution to Mammoth Cave (as measured by 

the percent of the current 20 % highest day 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. 

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Appendix L.8 - 215

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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 perceptible since it’s less than a 5 % change. 

2. For the data modeled at the daily maximum firing rate, the $/ton of SO2 removed 

ranges from $897/ton to $4031/ton. For the lowest cost/ton an improvement of 

0.349 dV is predicted for the 98th percentile value. In terms of the percent 

contribution to Mammoth Cave (as measured 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 extinction is not perceptible since it’s less 

than a 5 % change. These data were modeled at the maximum daily firing rate, 

which, in our view is ultra conservative and overstates both the reductions and the 

magnitude of the possible visibility impact. 

3. For the data modeled at the annual average capacity factor (monthly maximum) 

firing rate, the maximum dV reduction capable of being achieved for the 98th

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 SO2. 

4. For the data modeled at the daily maximum emissions, the maximum dV 

reduction capable of being achieved for the 98th percentile day is predicted to be 

0.657 dV. This corresponds to an incremental 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, would only be predicted to be achieved 

roughly 30 days of the year. This reduction is achievable at a cost of $2635/ton of 

SO2’

5. NOx reductions for the data modeled at both the daily maximum and the annual 

average capacity factor (monthly maximum) firing rates are not predicted to 

achieve significant improvements in visibility impairment. For the annual 

average capacity factor (monthly maximum) data, the maximum case evaluated 

reduces visibility impairment by 0.131 dV for the 98th percentile day which 

corresponds to an incremental 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 emission caps at cost levels corresponding to 

roughly $1700/ton for NOx and $1800/ton for SO2. 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 

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Appendix L.8 - 216

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

dV improvement on the 98th percentile day. In light extinction terms, these 

improvements correspond to a 0.6 to 0.7 % reduction in light extinction. 

For SO2, 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 incremental 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 are predicted to occur 

between June and November, the modeling requirement to assess the impacts at daily 

maximum firing rates assumed to occur throughout the year is overly conservative. The 

emission rates in the summer are much less (as much as 50 %), thus the actual 

improvements achieved will be less than those predicted by this modeling effort. 

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Appendix L.8 - 217

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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 Mammoth Cave, the incremental improvements are 

small as measured by the percent of the 20 % worst days visibility at Mammoth Cave. In 

general, the $/ton controlled values are greater 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 the year represented by the highest daily 

emissions rate conditions includes compounded conservatism that grossly overstates 

visibility impact compared to actual boiler operation during the course of the year. 

Based on this analysis, DuPont believes that our overall visibility contribution to 

Mammoth Cave is minor and incremental improvements, while possible, are very small. 

We do not believe these improvements are cost effective. 

We, therefore, are proposing the status quo (no changes) as BART for the boilers at 

DuPont’s Old Hickory Plant. . 

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Appendix L.8 - 219

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 3-4 - Summary of the Control Scenario Visibility & Cost Impacts @ Annual Average 

Capacity Factor (Monthly Maximum) Rate and Average Coal Quality

Case Description Expected Emission 

rate

Expected 

Emission 

Rate

Total Annualized 

cost of control

Tons 

Removed

Average cost 

Effectiveness

Greatest 

Change in 

Modelled 

98 % day 

from 

baseline

% 

Change in 

Light 

extinction

% of 31.37 

dV (the 

starting 

point for the 

Mammoth 

Cave Glide 

Path)

I

I

SO2 Cases T/yr lb/hr $ t/yr $/ton removed dV % % 

A. Baseline Case Using Current Coal

5,223 1,192 0.679 6.79 2.16

F. 1.5% Sulfur Coal with No Scrubbing

4,451 1,016 $1,561,889 772 $2,023 -0.082 0.82 1.92 

K. 1.0% Sulfur Coal with No Scrubbing

2,968 678 $2,342,834 2,255 $1,039 -0.254 2.54 1.36 

E. Current Coal with Sodium Wet Scrubber on Boiler 20 Only 1,007 230 $13,543,003 4,216 $3,212 -0.431 4.31 0.80 

J. 1.5% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 858 196 $10,280,090 4,365 $2,355 -0.452 4.52 0.73 

O. 1.0% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 572 131 $11,085,953 4,651 $2,384 -0.469 4.69 0.67 C. Current Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 261 60 $22,560,847 4,962 $4,547 -0.497 4.97 0.58 H. 1.5% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 223 51 $15,880,219 5,000 $3,176 -0.499 4.99 0.58 M. 1.0% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 148 34 $16,690,492 5,075 $3,289 -0.507 5.07 0.55 P. Current Coal with 50% Natural Gas Cofiring on Both Boilers 2,611 596 $11,561,886 2,612 $4,426 -0.284 2.84 1.27 

NOx Cases

A. Baseline Case Using Current Coal

1,002 229 0.679 6.79 2.16

D1. LNB on Boiler 20 Only

664 152 $548,242 338 $1,622 -0.059 0.59 1.99 

D2. SNCR on Boiler 20 Only

664 152 $748,051 338 $2,213 -0.059 0.59 1.99 

B1. LNB on Both Boilers 20 & 24

601 137 $938,886 401 $2,341 -0.073 0.73 1.94 

B2. SNCR on Both Boilers 20 & 24

601 137 $995,834 401 $2,483 -0.073 0.73 1.94 

E. LNB Plus SCR on Boiler 20 Only

259 59 $3,024,491 743 $4,071 -0.127 1.27 1.77 

C. LNB Plus SCR on Both Boilers 20 & 24

120 27 $5,303,771 882 $6,013 -0.131 1.31 1.76 

B3 Current Coal with 50% Natural Gas Cofiring on Both Boilers 601 137 $11,561,886 401 $28,865 -0.284 2.84 1.27 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 3-5 - Summary of the Control Scenario Visibility & Cost Impacts @ Daily Max

 Emission Rate and Highest Day Coal Quality 

Case Description Expected Emission 

rate

Expected 

Emission 

Rate

Total Annualized 

cost of control

Tons 

Removed

Average cost 

Effectiveness

Greatest 

Change in 

Modelled 

98 % day 

from 

baseline

% 

Change in 

Light 

extinction

% of 31.37 

dV (the 

starting 

point for the 

Mammoth 

Cave Glide 

Path)

Incre

Imp

of % 

Impa

of 3

SO2 Cases T/yr lb/hr $ t/yr $/ton removed dV % % 

A. Baseline Case Using Current Coal

7,040 1,607 0.929 9.29 2.96

F. 1.5% Sulfur Coal with No Scrubbing

5,617 1,282 $1,970,962 1,423 $1,385 -0.15 1.5 2.50 

K. 1.0% Sulfur Coal with No Scrubbing

3,745 855 $2,956,443 3,295 $897 -0.349 3.49 1.86 

E. Current Coal with Sodium Wet Scrubber on Boiler 20 Only 1,690 386 $14,222,449 5,351 $2,658 -0.508 5.08 1.35 

J. 1.5% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 1,348 308 $11,196,391 5,692 $1,967 -0.532 5.32 1.27 O. 1.0% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 899 205 $12,211,479 6,142 $1,988 -0.597 5.97 1.07 

C. Current Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 352 80 $23,566,812 6,688 $3,524 -0.624 6.24 0.98 

H. 1.5% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 281 64 $17,033,708 6,759 $2,520 -0.638 6.38 0.93 

M. 1.0% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 187 43 $18,056,198 6,853 $2,635 -0.657 6.57 0.87 

P. Current Coal with 50% Natural Gas Cofiring on Both Boilers 3,520 804 $14,190,215 3,520 $4,031 -0.369 3.69 1.80 

NOx Cases

A. Baseline Case Using Current Coal

1,233 282 0.929 9.29 2.96

D1. LNB on Boiler 20 Only

843 192 $572,769 391 $1,466 -0.033 0.33 2.87 

D2. SNCR on Boiler 20 Only

843 192 $821,184 391 $2,102 -0.033 0.33 2.87 

B1. LNB on Both Boilers 20 & 24

740 169 $963,413 493 $1,953 -0.055 0.55 2.80 

B2. SNCR on Both Boilers 20 & 24

740 169 $1,105,732 493 $2,241 -0.055 0.55 2.80 

E. LNB Plus SCR on Boiler 20 Only

374 85 $2,904,607 859 $3,380 -0.13 1.3 2.56 

C. LNB Plus SCR on Both Boilers 20 & 24

148 34 $5,081,539 1,085 $4,682 -0.178 1.78 2.41 

B3 Current Coal with 50% Natural Gas Cofiring on Both Boilers 740 169 $14,190,215 493 $28,759 -0.369 3.69 1.80 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 3–6 Summary - Baseline Visibility Modeling Results @ Annual Average Capacity Factor (M

Rates 

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

Modeled 98th 

perentile Value 

(dV)

ex

SO2 Cases

A. Baseline Case Using Current Coal

0.647 16 0.658 12 0.679 15 0.647 

F. 1.5% Sulfur Coal with No Scrubbing

0.568 11 0.576 9 0.607 12 0.567 

K. 1.0% Sulfur Coal with No Scrubbing

0.393 1 0.423 6 0.455 3 0.408 

E. Current Coal with Sodium Wet Scrubber on Boiler 20 Only 0.23100.23110.24800.295 

J. 1.5% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 0.21900.22100.22700.271 

O. 1.0% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 0.19 0 0.197 0 0.21 0 0.193 

C. Current Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 0.17 0 0.192 0 0.182 0 0.236 

H. 1.5% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 0.164 0 0.188 0 0.18 0 0.233 

M. 1.0% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 0.15100.18100.17200.165 

P. Current Coal with 50% Natural Gas Cofiring on Both Boilers 0.36310.40240.43720.371 

NOx Cases

A. Baseline Case Using Current Coal

0.647 16 0.658 12 0.679 15 0.647 

D1. LNB on Boiler 20 Only

0.637 16 0.599 12 0.654 15 0.806 

D2. SNCR on Boiler 20 Only

0.637 16 0.599 12 0.654 15 0.806 

B1. LNB on Both Boilers 20 & 24

0.637 16 0.585 11 0.654 15 0.805 

B2. SNCR on Both Boilers 20 & 24

0.637 16 0.585 11 0.654 15 0.805 

E. LNB Plus SCR on Boiler 20 Only

0.604 15 0.531 10 0.65 15 0.797 

C. LNB Plus SCR on Both Boilers 20 & 24

0.594 15 0.527 9 0.644 13 0.794 

B3 Current Coal with 50% Natural Gas Cofiring on Both Boilers 0.36310.40240.43720.371 

2001 2001 - 20

Case Description

2002 2003

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 3–7 Summary - Baseline Visibility Modeling Results @ Daily Maximum Ra

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

Modeled 98th 

perentile Value 

(dV)

N

exce

SO2 Cases

A. Baseline Case Using Current Coal

0.87 35 0.898 28 0.929 27 0.867 

F. 1.5% Sulfur Coal with No Scrubbing

0.72 28 0.749 21 0.792 22 0.741 

K. 1.0% Sulfur Coal with No Scrubbing

0.521 10 0.549 11 0.599 12 0.526 

E. Current Coal with Sodium Wet Scrubber on Boiler 20 Only 0.374 0 0.39 3 0.439 2 0.486 

J. 1.5% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 0.338 0 0.367 2 0.398 1 0.445 O. 1.0% Sulfur Coal with Sodium Wet Scrubber on Boiler 20 Only 0.288 0 0.329 2 0.332 1 0.321 C. Current Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 0.27 0 0.313 1 0.305 0 0.357 

H. 1.5% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 0.258 0 0.304 1 0.291 0 0.349 M. 1.0% Sulfur Coal with Sodium Wet Scrubber on Both Boilers 20 & 24 0.242 0 0.283 1 0.272 0 0.253 P. Current Coal with 50% Natural Gas Cofiring on Both Boilers 0.501 8 0.564 11 0.605 11 0.522 

NOx Cases

A. Baseline Case Using Current Coal

0.87 35 0.898 28 0.929 27 0.867 

D1. LNB on Boiler 20 Only

0.865 33 0.865 26 0.917 27 1.131 

D2. SNCR on Boiler 20 Only

0.865 33 0.865 26 0.917 27 1.131 

B1. LNB on Both Boilers 20 & 24

0.849 33 0.843 26 0.917 26 1.124 

B2. SNCR on Both Boilers 20 & 24

0.849 33 0.843 26 0.917 26 1.124 

E. LNB Plus SCR on Boiler 20 Only

0.841 32 0.768 23 0.902 25 1.101 

C. LNB Plus SCR on Both Boilers 20 & 24

0.836 30 0.72 22 0.89 23 1.086 

B3 Current Coal with 50% Natural Gas Cofiring on Both Boilers 0.501 8 0.564 11 0.605 11 0.522 

2001 2001 - 2003

Case Description

2002 2003

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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 Using 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 Scrubbing 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

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Appendix L.8 - 224

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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 Scrubbing 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 Only 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 Only 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 Only 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

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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 

Cofiring 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

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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 Only 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 Only 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 listing is provided at the beginning of Table 3-8 

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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

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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 Only 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

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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

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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., “BART 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., “Results of BART Modeling and Engineering 

Analysis for E. I. DuPont de Nemours & Company Old Hickory Plant, April 4, 

2007. 

5. VISTAS (Visibility Improvement and Tribal 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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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 Engineering Technology 

1007 Market Street 

Wilmington, DE 19898 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

6.1 Introduction 

The objectives of this modeling report are to describe the methodology 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 Hickory plant, located in Old Hickory, TN. This 

modeling analysis consisted of a base case modeling analysis conducted at all of the Class 1 areas 

within 300 km of the Old Hickory Plant (see table below) to assess the current impact on visibility. 

Subsequently, additional modeling of SO2 and NOx 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 for 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. Section 2.2 presents the source – Class 1 area geometry. 

Section 2.3 presents the emissions inventory modeled 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, particulate matter speciation, and background light 

extinction. 

6.2 Source/Class I Area Geometry 

The distances to the four Class 1 areas within 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 within each of these Class 1 areas were taken from 

the National Park Service (NPS), Air Resources Division website, which lists all of the modeling 

receptors for all of the Class 1 areas in the conterminous U. S. Figure 6-1 shows these distances. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

6.3 Emissions Inventory 

The following emission inventory information for the 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 (provided in a scaled plot plan) 

 7. Emission rates 

All of the “base case” stack parameters are presented 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 strategies that either lowered the SO2

emission rate or lowered the NOx emission rate. The SO2 and NOx 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 model used in this study is the VISTAS 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 output files generated in that modeling as input 

to CALPUFF. These versions contain enhancements funded by the Minerals Management Service 

(MMS) and VISTAS. 

6.4.1 CALMET Modeling Configuration (Subregional 4-km runs conducted by 

VISTAS and EarthTech (now TRC) 

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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 IWAQM guidance (EPA, 1998; Pages A-1 through A6)(3), except as noted below. 

The basic features of the CALMET modeling 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, except as follows: diagnostic terrain blocking 

and slope flow algorithms used for 2003 simulations (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 modeling 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 mixing height field, but without 

excessive noise. 

• Geophysical data for regional runs: SRTM-GTOPO30 30-arcsec terrain data, Composite 

Theme Grid (CTG) USGS 200m land use dataset. References for these and other 

CALMET datasets can be found on the CALPUFF data page of the official CALPUFF site 

(www.src.com). 

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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 regional 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 Modeling Protocol guidance(6) on p. 

43. For particulates, we used the speciation profile guidance provided from the VISTAS web 

site. The speciation procedure is presented in section 2.4.2.1 below. 

• Species modeled: SO2, SO4, NOx, HNO3, NO3 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 direction. 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 Figure 6-3. The east-west 

dimension of this modeling domain is approximately 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 discussed in Section 2.4.2.2 below. 

• Base case emission rates were modeled at the maximum 24 hour coal firing rate for 2005. 

Emission rates for the other 13 cases vary as shown 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 with plant-wide emissions less than de minimis 

levels (40 tons per year for SO2 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 computed 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, integrated puff sampling methodology. 

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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 implemented since the nearest Class 1 area is 

greater than 50-km from the Old Hickory Plant. 

6.4.2.1 Particulate Matter Speciation 

Particulate matter in size categories of <0.625 μm, 0.625-1.0 μm, 1.0-1.25 μm, 1.25-2.5 μm, 2.5-6.0 

μm and 6-10 μm aerodynamic diameters were considered in the CALPUFF modeling. 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 particulate matter or “soil” (< 2.5 μm in diameter), coarse 

particulate matter (PMC) (between 2.5-10 μm in diameter) and organics (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 stated, 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 specific 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 this information, the calculations presented in 

Table 6-9 are made, resulting in particle size categories corresponding to the appropriate categories 

for the visibility analysis. All of this information 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 the visibility statistics, as explained in Section 

2.4.3 below. 

The particulate matter speciation for the 1.5% sulfur coal cases are presented 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 website 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 total of 1507 receptors for the five Class 1 areas were 

obtained from this website. The receptors were converted to the Lambert Conformal (LCC) 

coordinate system. The receptors grids can be seen in Figures 6-4 through 6-8. 

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Appendix L.8 - 238

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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 employed with the following configuration:

• Visibility Method 6 was used. 

• Species considered in visibility analysis: SO4, NO3, elemental carbon (EC), soil, coarse PM 

(PMC) and secondary organic 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. These 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 evaluated using the following relationship: 

bback = 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 Visibility Conditions Under the Regional Haze Rule 

(2003)”(7). For Mammoth Cave NP, HI = 3.85 dv. Inserting this value into the above equation results 

in bback equaling 14.696 Mm-1. If all of the background particulates are conservatively assumed to be 

SOIL, and the value of 10 Mm-1 is assumed for Rayleigh scattering, then the relationship becomes: 

BB

back = bray + bsoil, or 

14.696 Mm-1 = 10 Mm-1 + bsoil

bsoil = 4.696 Mm-1

Since the extinction efficiency for soil is 1 ug/m3/Mm-1, bsoil becomes 4.696 ug/m3. This value is then 

used in CALPOST. The 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. 

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Appendix L.8 - 239

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6.5 Modeling References 

(1) VISTAS (Visibility Improvement and Tribal 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. 

(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 the CALPUFF Model for Analyses of Best Available 

Retrofit Technology (BART)”, p. 49. 

(5) U. S. EPA, IWAQM Phase 2, Summary Report and Recommendation for Long Range 

Transport Impacts, Pages B-1 through B-8. 

(6) VISTAS “Protocol for the Application of the 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 Service, U. S. Fish and Wildlife Service; Federal Land 

Managers’ Air Quality Related Values Workgroup (FLAG) Phase I Report, December, 2000. 

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Appendix L.8 - 240

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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 

 SO2 lb/hr 321 1286 

 PM10 lb/hr 14.8 13.7 

 NO2 lb/hr 59 223 

 SO2 ton/yr 1408 5632 

 NO2 ton/yr 257 977 

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Table 6-2 BART Control Cases 

CASE SO2 Emissions NOx

Emissions

 (lb/hr) (lb/hr) 

SO2 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 

NOx Cases: 

A. Baseline (same as SO2 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 85 

 

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Table 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 of 11428 Btu/lb and a sulfur content of 1.88 % and an ash content of 8 % and f(RH) = 1

Controlled PM10 Emissions (Bold values from Table 1.1-5.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/ton) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. 

PC-DB 0.1769 0.0189 0.0105 0.6 0.0084 0.0081 1 0.00031 10 0.158 0.126 SO4 3*f(RH) 

Controlled PM10 Emissions (Bold Values from Table 1.1-6.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/ton) (lb/ton) (lb/ton) Coef. (lb/ton) (lb/ton) Coef. (lb/ton) Coef. (lb/ton) (lb/ton) Type Ext.Coef. 

PC-DB 4.043 0.432 0.240 0.6 0.192 0.185 1 0.0071 10 3.611 2.889 SO4 3*f(RH) 

Controlled PM10 Emissions

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (% of Total) (% of Total) (% of Total) Coef. (% of Total) (% of Total) Coef. (% of Total) Coef. (% of Total) (% of Total) Type Ext.Coef. 

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) 

If you are given Total PM10 emissions in lb/hr:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. 

PC-DB 14.8 1.6 0.9 0.6 0.7 0.7 1 0.0 10 13.2 10.6 SO4 3 

Weighted Extinction 0.5 0.7 0.3 31.7

If you are given Total PM10 emissions in lb/mmBtu:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. 

PC-DB 0.10 0.01 0.01 0.6 0.00 0.00 1 0.0002 10 0.09 0.07 SO4 3 

If you are given Filterable PM10 emissions:

Controlled PM10 Emissions (Bold values from Table 1.1-5 and from Table 6 of EPA’s January 2002 DRAFT “Catalog of Global Emissions Inventories and Emission Inven

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (% of Total) (% of Total) (% of Filterable) Coef. (% of Filterable) (% of Filterable) 1 (% of Filterable) Coef. (% of Total) (% of Condensible) Type Ext.Coef. 

PC-DB 100% 10.7% 55.6% 0.6 44.4% 42.8% 1 1.6% 10 89.3% 80.0% SO4 3 

(% of Fine) Coef. (% of Fine) Coef.

96.3% 1 3.7% 10

If you are given Filterable PM10 emissions in lb/hr:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.Coef. 

PC-DB 14.8 1.6 0.9 0.6 0.7 0.7 1 0.0 10 13.2 10.6 SO4 3 

If you are given Filterable PM10 emissions in lb/mmBtu:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.Coef. 

PC-DB 0.10 0.01 0.01 0.6 0.00 0.00 1 0.0002 10 0.09 0.07 SO4 3 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 6-4 – PM Particle Size Basis (1.88% Sulfur Coal) 

PC with ESPfrom AP-42 Table 1.1-6(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range in Size Range

(um) ESP (%) (um) (lb/hr)

10 67% 100% 10-6 0.4

6 50% 75% 6-2.5 0.5

2.5 29% 43% 2.5-1.25 0.3

1.25 17% 25% 1.25-1.0 0.1

1 14% 21% 1.0-625 0.0

0.625 12% 18% 0.625-0 0.3

CALPUFF

Particle Particle Fraction Emissions Extinction Emissions

Size Size Range of PM10 in Size Range Coef. in Size Range

(um) (um) (%) (lb/hr) (g/sec)

8 10-6 25% 0.4 0.6 0.05

4.25 6-2.5 31% 0.5 0.6 0.06 57% Coarse >/

1.88 2.5-1.25 18% 0.3 1 0.04 43% Fine Soil <

1.25 1.25-1 4% 0.1 1 0.01

0.813 1.6-25 3% 0.0 1 0.01

0.625 0.625-0 18% 0.3 1 0.03

100% 1.6 10 0.00 3.7% of Fine So

0.20

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 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 of 11428 Btu/lb and a sulfur content of 1.5 % and an ash content of 8 % and f(RH) = 1

Controlled PM10 Emissions (Bold values from Table 1.1-5.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/ton) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.C

PC-DB 0.1389 0.0189 0.0105 0.6 0.0084 0.0081 1 0.00031 10 0.120 0.096 SO4 3*f(

Controlled PM10 Emissions (Bold Values from Table 1.1-6.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/ton) (lb/ton) (lb/ton) Coef. (lb/ton) (lb/ton) Coef. (lb/ton) Coef. (lb/ton) (lb/ton) Type Ext.C

PC-DB 3.175 0.432 0.240 0.6 0.192 0.185 1 0.0071 10 2.743 2.194 SO4 3*f(

Controlled PM10 Emissions

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (% of Total) (% of Total) (% of Total) Coef. (% of Total) (% of Total) Coef. (% of Total) Coef. (% of Total) (% of Total) Type Ext.C

PC-DB 100% 13.6% 7.6% 0.6 6.0% 5.8% 1 0.2% 10 86.4% 69.1% SO4 3*f(

If you are given Total PM10 emissions in lb/hr:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.C

PC-DB 14.8 2.0 1.1 0.6 0.9 0.9 1 0.0 10 12.8 10.2 SO4 3 

Weighted Extinction 0.7 0.9 0.3 30

If you are given Total PM10 emissions in lb/mmBtu:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.C

PC-DB 0.10 0.01 0.01 0.6 0.01 0.01 1 0.0002 10 0.09 0.07 SO4 3 

If you are given Filterable PM10 emissions:

Controlled PM10 Emissions (Bold values from Table 1.1-5 and from Table 6 of EPA’s January 2002 DRAFT “Catalog of Global Emissions Inventories and Emissio

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (% of Total) (% of Total) (% of Filterable) Coef. (% of Filterable) (% of Filterable) 1 (% of Filterable) Coef. (% of Total) (% of Condensible) Type Ext.C

PC-DB 100% 13.6% 55.6% 0.6 44.4% 42.8% 1 1.6% 10 86.4% 80.0% SO4 3 

(% of Fine) Coef. (% of Fine) Coef.

96.3% 1 3.7% 10

If you are given Filterable PM10 emissions in lb/hr:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ext.C

PC-DB 14.8 2.0 1.1 0.6 0.9 0.9 1 0.0 10 12.8 10.2 SO4 3 

If you are given Filterable PM10 emissions in lb/mmBtu:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Particle 

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ext.C

PC-DB 0.10 0.01 0.01 0.6 0.01 0.01 1 0.0002 10 0.09 0.07 SO4 3 

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Table 6-6 – PM Particle Size Basis (1.5% Sulfur Coal) 

PC with ESPfrom AP-42 Table 1.1-6(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range in Size Range

(um) ESP (%) (um) (lb/hr)

10 67% 100% 10-6 0.5

6 50% 75% 6-2.5 0.6

2.5 29% 43% 2.5-1.25 0.4

1.25 17% 25% 1.25-1.0 0.1

1 14% 21% 1.0-625 0.1

0.625 12% 18% 0.625-0 0.4

CALPUFF

Particle Particle Fraction Emissions Extinction Emissions

Size Size Range of PM10 in Size Range Coef. in Size Range

(um) (um) (%) (lb/hr) (g/sec)

8 10-6 25% 0.5 0.6 0.06

4.25 6-2.5 31% 0.6 0.6 0.08 57% Coarse >/

1.88 2.5-1.25 18% 0.4 1 0.05 43% Fine Soil <

1.25 1.25-1 4% 0.1 1 0.01

0.813 1.6-25 3% 0.1 1 0.01

0.625 0.625-0 18% 0.4 1 0.04

100% 2.0 10 0.00 3.7% of Fine So

0.25

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 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 of 11428 Btu/lb and a sulfur content of 1 % and an ash content of 8 % and f(RH) = 1

Controlled PM10 Emissions (Bold values from Table 1.1-5.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/ton) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ex

PC-DB 0.0889 0.0189 0.0105 0.6 0.0084 0.0081 1 0.00031 10 0.070 0.056 SO4 3

Controlled PM10 Emissions (Bold Values from Table 1.1-6.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (lb/ton) (lb/ton) (lb/ton) Coef. (lb/ton) (lb/ton) Coef. (lb/ton) Coef. (lb/ton) (lb/ton) Type Ex

PC-DB 2.032 0.432 0.240 0.6 0.192 0.185 1 0.0071 10 1.600 1.280 SO4 3

Controlled PM10 Emissions

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (% of Total) (% of Total) (% of Total) Coef. (% of Total) (% of Total) Coef. (% of Total) Coef. (% of Total) (% of Total) Type Ex

PC-DB 100% 21.3% 11.8% 0.6 9.4% 9.1% 1 0.3% 10 78.7% 63.0% SO4 3

If you are given Total PM10 emissions in lb/hr:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ex

PC-DB 14.8 3.1 1.7 0.6 1.4 1.3 1 0.1 10 11.7 9.3 SO4 

Weighted Extinction 1.0 1.3 0.5 

If you are given Total PM10 emissions in lb/mmBtu:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ex

PC-DB 0.10 0.02 0.01 0.6 0.01 0.01 1 0.0003 10 0.08 0.06 SO4 

If you are given Filterable PM10 emissions:

Controlled PM10 Emissions (Bold values from Table 1.1-5 and from Table 6 of EPA’s January 2002 DRAFT “Catalog of Global Emissions Inventories and Emiss

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (% of Total) (% of Total) (% of Filterable) Coef. (% of Filterable) (% of Filterable) 1 (% of Filterable) Coef. (% of Total) (% of Condensible) Type Ex

PC-DB 100% 21.3% 55.6% 0.6 44.4% 42.8% 1 1.6% 10 78.7% 80.0% SO4 

(% of Fine) Coef. (% of Fine) Coef.

96.3% 1 3.7% 10

If you are given Filterable PM10 emissions in lb/hr:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (lb/hr) (lb/hr) (lb/hr) Coef. (lb/hr) (lb/hr) Coef. (lb/hr) Coef. (lb/hr) (lb/hr) Type Ex

PC-DB 14.8 3.1 1.7 0.6 1.4 1.3 1 0.1 10 11.7 9.3 SO4 

If you are given Filterable PM10 emissions in lb/mmBtu:

Controlled PM10 Emissions (Bold Value is Input by user.)

Boiler Total PM10 Filterable Coarse Ext. Fine Fine Soil Ext. Fine EC Ext. Condensible CPM IOR Parti

Type (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Coef. (lb/mmBtu) Coef. (lb/mmBtu) (lb/mmBtu) Type Ex

PC-DB 0.10 0.02 0.01 0.6 0.01 0.01 1 0.0003 10 0.08 0.06 SO4 

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Table 6-8 – PM Particle Size Basis (1.0% Sulfur Coal) 

PC with ESPfrom AP-42 Table 1.1-6(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range in Size Range

(um) ESP (%) (um) (lb/hr)

10 67% 100% 10-6 0.8

6 50% 75% 6-2.5 1.0

2.5 29% 43% 2.5-1.25 0.6

1.25 17% 25% 1.25-1.0 0.1

1 14% 21% 1.0-625 0.1

0.625 12% 18% 0.625-0 0.6

CALPUFF

Particle Particle Fraction Emissions Extinction Emissions

Size Size Range of PM10 in Size Range Coef. in Size Range

(um) (um) (%) (lb/hr) (g/sec)

8 10-6 25% 0.8 0.6 0.10

4.25 6-2.5 31% 1.0 0.6 0.12 57% Coarse >/

1.88 2.5-1.25 18% 0.6 1 0.07 43% Fine Soil <

1.25 1.25-1 4% 0.1 1 0.02

0.813 1.6-25 3% 0.1 1 0.01

0.625 0.625-0 18% 0.6 1 0.06

100% 3.1 10 0.01 3.7% of Fine So

0.40

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 6-9 PM Speciation Calculations 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. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 6-10 PM Speciation Calculations 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. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 6-11 PM Speciation Calculations 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. 

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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 

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Appendix 6 - Results of BART Control Strategy Engineering Analysis DuPont Old Hickory Plant, Old 

Hickory, TN 

Figure 6-1 Old Hickory Location and Class 1 Area Distances 

105 km

254 km

249 km 

233 km 

220 km 

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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) 

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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

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Figure 6-4: Mammoth Cave NP Receptors 

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Figure 6-5: Cohutta Wilderness Receptors 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Figure 6-6: Great Smokey Mountains NP Receptors 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Figure 6-7: Joyce Kilmer Wilderness Receptors 

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Figure 6-8: Sipsey Wilderness Receptors 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

7 Appendix 2 - Model Input and Output Files on CDs 

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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 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

8.1 Background 

TN and METRO requested information from the DuPont Old Hickory Plant relative to 

potential emissions reductions from the 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, the State must take into consideration the 

technology available, the costs of compliance, the energy and nonair quality 

environmental impacts of compliance, any 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 relative to these requirements. This analysis 

does not include a rigorous engineering analysis of the installation 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 required, additional time and resources would be 

necessary. 

8.2 Existing Boiler Design, Arrangement, and Operation 

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

Each boiler utilizes two coal pulverizers. Boiler 20 was installed in 1968 and is 445 

MMBtu/hr design heat input capacity; Boiler 24 was installed in 1966 and is 315 

MMBtu/hr design heat input capacity. Both boilers are equipped with natural gas burners 

capable of backup full load gas firing. 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 produces superheated 550 psig steam. Boiler 24 now produces 

550 psig saturated steam as a backup to Boiler 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 additional steam output is required. Each boiler 

is equipped with its own 200 ft tall stack. 

Each boiler is equipped with its dedicated hot side Electrostatic Precipitator (ESP) for 

particulate matter and opacity control. The ESPs were retrofit installations in the late 

1970s, and that retrofit included removal of the original multiclone mechanical dust 

collectors. The ESP designs incorporate parallel collecting plates and weighted wire 

electrodes. The Title V Air Permit requires operation of at least five of the eight installed 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

fields on each boiler to achieve 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 boilers. Any additional emissions control 

equipment would need to be located at the far side of the Powerhouse near the existing 

coal storage area, necessitating a long breeching 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 equipment 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 operation 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 anticipated that alternative 

steam supply opportunities would arise that would eliminate the need for the two coal 

fired boilers, but if that did occur, the overall 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 maintenance and proper operation are practiced. 

However, if fuel characteristics or regulatory requirements significantly change, or 

maintenance problems arise, it is possible that an internal rebuild 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 addressed for each option evaluated and explained 

below. 

8.2.1 Basis for Engineering Analysis 

TN DEC indicated the desire for visibility impacts to be evaluated 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 

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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, Boiler 24 now serves to supply 550 psig saturated steam as a backup 

to Boiler 20 and thus operates at a much lower annual capacity factor than prior to DMT 

shutdown. Boiler 20 is the primary site boiler that is supplemented as needed by Boiler 

24 and the other smaller site boilers. Therefore, 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 daily (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 peak steam demands (and hence SO2 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 scheduled for Boiler 20. The day in which the 

maximum SO2 and NOx emissions occurred was February 18, 2006, during which both 

Boilers 20 and 24 were on line firing coal. Total 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 equivalent monthly average basis, that is 375,410 

MMBtu/month. Total natural gas heat input during 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 Heating Value (HHV) of 

11,428 Btu/lb. Coal sulfur value averaged 1.76% in 2005 and 1.85% for 2006. Use of 

the coal quality (percent sulfur and HHV) for the maximum daily emissions day for this 

analysis is, therefore, conservative compared to long term average coal quality. 

In addition, conducting visibility impact determinations and economic comparisons of 

alternative controls on the basis of the maximum daily emissions grossly overstates the 

actual impact of these boilers on Class 1 area visibility and overstates the control cost 

effectiveness (lowers the apparent $/ton removed). This overstatement can be seen by 

viewing the monthly average total combined boiler heat input on coal only and for both 

coal and gas for Boilers 20 and 24. The figures 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 indicating the highest emission day equivalent heat input being used 

as the basis for the modeling (375,410 MMBtu/month for coal only; 378,392 

MMBtu/month for all fuels). 

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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 Feb05Mar-05 Apr-05 May05Jun-05 Jul-05 Aug05Sep05Oct-05 Nov05Dec05

Month

MMBtu/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

Jan05Feb05Mar05Apr05May05Jun05Jul-05 Aug05Sep05Oct05Nov05Dec05

Month

MMBtu/Month- Boilers 20 & 24

Maximum Daily Emissions Case- 378,392 MMBtu/Month Annual Average

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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

Jan06Feb06Mar06Apr-06 May06Jun06Jul-06 Aug06Sep06Oct06Nov06Dec06

Month

MMBtu/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 Feb06Mar06Apr-06 May06Jun-06 Jul-06 Aug06Sep06Oct06Nov06Dec06

Month

MMBtu/Month- Boilers 20 & 24

Maximum Daily Emissions Case- 378,392 MMBtu/Month Annual Average

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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

associated SO2 and NOx emission rates for Boilers 20 and 24 used for determining the 

visibility impacts grossly overstates actual emissions, especially during the summer 

months when visibility is most sensitive to SO2 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 below are calculated on two bases: 

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

baseline condition. 

• Using annual average coal firing 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 options considered for emissions reductions 

from Boilers 20 and 24. The focus is on both SO2 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 case for the control options and for evaluating 

potential emission reductions. The permitted coal 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 SO2 emission rate of 3.13 lb/MMBtu. There is no additional cost for 

using the current coal. 

The modeled loading and emission rates on Boilers 20 and 24 for modeling and economic 

analysis purposes was set as follows: 

1. Total SO2 and NOx emissions on an hourly average basis for the highest emission 

day were determined. Those emissions were 1607 lb/hr of SO2 and 282 lb/hr of 

NOx; those are equivalent to an annualized emission rate of 7040 TPY of SO2 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 Boiler 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 basis and this proportioning 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 SO2

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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 SO2, 

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 results 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 boilers are tangentially fired dry bottom units 

firing bituminous coal. The boiler and associated equipment design places limitations on 

the type of coal that can be fired, so that PRB coal, for instance, is not an easily viable 

option. Coal choices would be limited to bituminous coal. In addition, the boilers are 

subject to 40CFR Part 63, Subpart DDDDD (Boiler MACT Rule) requirements with a 

current compliance date of September 13, 2007. Plans are to use coal specifications with 

existing boiler and PM control equipment to demonstrate compliance with the emission 

limits. The Health Based Compliance Alternative (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 compliance. Therefore, the availability of coal 

supplies will be somewhat limited based on the required specifications. There will be a 

cost increase in coal delivered to the site due to lower sulfur requirements. The estimated 

additional cost per ton based on today’s coal availability and cost differentials is included 

in the options analysis. Two levels of lower sulfur content are evaluated- 1.5% S (Coal 

2) and 1.0% S (Coal 3). In both cases, the 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 firing coal with a sulfur level as low as 1.0% might cause ESP 

performance degradation due to ash resistivity 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 analysis. 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 weighted wire electrodes with 

rigid rod electrodes, installing new rappers, and installing new power supplies and TR 

sets with controls is estimated to be at least $4.0MM for Boiler 20 and $3.2MM for 

Boiler 24 based on recent rebuild experience. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

8.3.3 SO2 Scrubbers Using Coal with Various Sulfur Contents 

The most practical types of SO2 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 existing 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 higher capital cost of the limestone wet scrubber 

systems for smaller units is not justified compared 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 results shown at the end of 

this section indicate. Three cases are evaluated for scrubbing- using the current coal, 

using 1.50% S coal, and using 1.00% S coal. With a downstream scrubber of either typespray dry absorber or sodium wet scrubber- 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 cases were analyzed assuming installation of 

an individual scrubber train on each of the boilers so that boiler uptime can be optimized 

and use of backup natural gas firing will be minimized. In addition, alternative cases 

were evaluated assuming scrubber installation 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 use 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 boilers 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 these 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 consistently be in an optimum range for SCR. 

However, the economic impact and visibility modeling was also conducted for that 

option for comparison purposes. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

8.4 SO2 Emissions Reductions and Economic Comparison of Options 

Using the Highest Emission Day Basis 

Emissions control equipment cost estimates are determined primarily from RTP 

Environmental, Inc. database information modified 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 average 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 attached spreadsheet ($6.00/MMBtu differential 

assumed). 

Cost details are provided in the attached tables: 

The results for the case using highest day heat 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 SO2 per AP-42 using 11,428 

Btu/lb As-Received HHV). Annual costs would increase approximately $1.97MM per 

year over current coal cost for increased coal purchase price. (Recognize that coal price 

increases are based on current coal pricing differential estimates, and that future price 

differentials could vary from those levels depending on the supply and demand for those 

higher quality coals). SO2 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 SO2 removed. It is believed that coal with the sulfur level of Coal 2 could 

be found which also meets the Boiler MACT limits, so that firing this should be 

technically feasible. Actual coal test burn 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 SO2 per AP-42 using 11,428 

Btu/lb As-Received HHV). Annual costs would increase approximately $2.96MM per 

year over current coal cost for increased coal purchase price. SO2 reductions vs. Baseline 

highest emission day Coal 1 (3.13 lb/MMBtu) would be 3295 TPY with resultant 

incremental cost effectiveness of $897/ton SO2 removed. If compared to Coal 2 (2.49 

lb/MMBtu), the incremental SO2 reduction would be 1872 TPY with an incremental cost 

effectiveness vs. Coal 2 of $526/ton SO2 removed. As indicated above, use of Coal 3 

without an SO2 scrubber could negatively impact ESP performance, so that use of Coal 3 

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is not considered technically feasible at this time without extensive coal test burn and 

emissions testing. If rebuilding the ESP would be required, the total annualized cost 

increase would be $3.75MM and the cost effectiveness vs Coal 1 would rise to $1138/ton 

SO2 removed and $950/ton SO2 compared to Coal 2. 

8.4.3 Spray Dry Absorber with Downstream Baghouse 

Application of a spray dry absorber with downstream baghouse is assumed to provide 

85% SO2 reduction. While it is possible to achieve 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 the need to place any new emissions control 

equipment on the opposite side of the Powerhouse 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 annual cost including capital recovery is 

$5.8MM/yr for Boiler 20 and $4.5MM/yr for Boiler 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 assumed, 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 boiler for installation of a scrubber. 

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

both Boilers 20 and 24 in the individual boiler tables, as well as for installation on only 

Boiler 20 for cases using the three coals. As indicated 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. Therefore, the combined Boiler 20 and 24 table only considers the 

scrubbing cases with utilization of sodium wet scrubbers. 

8.4.4 Sodium Wet Scrubber Installation 

Application of a sodium wet scrubber is assumed to provide 95% SO2 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 place any new emissions control 

equipment on the opposite side of the Powerhouse along with a new stack raise the cost 

of this option. This cost is within the range 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 scrubber installation is 

assumed, 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 boiler for 

installation of a scrubber. 

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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 SO2 reduction vs. Baseline Coal 1 firing alone would be 6688 TPY with 

an average cost effectiveness of $3524/ton SO2 removed. 

• Installation on Boiler 20 Only 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 5351 TPY with 

an average cost effectiveness of $2658/ton SO2 removed. 

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

• Installation on Both Boilers 20 and 24 

Overall SO2 reduction vs. Coal 2 firing alone would be 5336 TPY with an 

incremental cost effectiveness of $2823/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 6759 TPY 

with an average cost effectiveness of $2520/ton SO2 removed. 

• Installation on Boiler 20 Only 

Overall SO2 reduction vs. Coal 2 firing alone would be 4269 TPY with an 

incremental cost effectiveness of $2161/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 5692 TPY 

with an average cost effectiveness of $1967/ton SO2 removed. 

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

• Installation on Both Boilers 20 and 24 

Overall SO2 reduction vs. Coal 3 firing alone would be 3558 TPY with an 

incremental cost effectiveness of $4244/ton SO2 removed. 

Overall SO2 reduction vs. Coal 2 firing alone would be 5430 TPY with an 

incremental cost effectiveness of $2962/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 6853 TPY 

with an average cost effectiveness of $2635/ton SO2 removed. 

• Installation on Boiler 20 Only 

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Overall SO2 reduction vs. Coal 3 firing alone would be 2846 TPY with an 

incremental cost effectiveness of $3252/ton SO2 removed. 

Overall SO2 reduction vs. Coal 2 firing alone would be 4718 TPY with an 

incremental cost effectiveness of $2170/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 6142 TPY 

with an average cost effectiveness of $1988/ton SO2 removed. 

8.4.5 50/50 Coal/Gas Cofiring 

As indicated above, the existing boilers are capable of coal/gas cofiring. In order to 

determine the relative cost effectiveness, it was assumed that a 50/50 ratio of coal and gas 

could be fired. If that was done on an annual basis, total SO2 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 SO2 removed 

compared to current Baseline Coal 1 operation. 

8.5 NOx Emissions Reductions and 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 required 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 likely that a NOx reduction of 40% 

could be achievable with retrofit 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 installation on both boilers is estimated to be approximately 

$5.2MM. Including incremental additional natural gas cost for 4 weeks of downtime for 

Boiler 20 only results in a total 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 retrofit to Boiler 20 only would be 391 TPY. 

The cost for retrofit LNB installation on Boiler 20 only is estimated to be approximately 

$2.6MM. Including incremental additional natural gas cost for 4 weeks of downtime for 

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Boiler 20 only results in a total 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 retrofit to both boilers would be 493 TPY. 

The cost for retrofit SNCR installation on both boilers is estimated to be approximately 

$3.1MM. Including incremental additional natural gas cost for 4 weeks of downtime for 

Boiler 20 only results in a total 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 retrofit to Boiler 20 only would be 391 TPY. 

The cost for retrofit SNCR installation on Boiler 20 only is estimated to be approximately 

$1.9MM. Including incremental additional natural gas cost for 4 weeks of downtime for 

Boiler 20 only results in a total cost effectiveness of $2102/ton NOx removed compared 

to current operation. 

8.5.3 Selective Catalytic Reduction (SCR) 

Retrofit of SCR to these boilers would be extremely difficult, 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 installation 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 incremental 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. 

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8.5.4 50/50 Coal/Gas Cofiring 

As indicated above, the existing boilers are capable of coal/gas cofiring. In order to 

determine the relative cost effectiveness, it was assumed that a 50/50 ratio of coal and gas 

could be fired. If that was done on an annual basis, total NOx reduction compared to 

current operation would be 493 TPY ( 40% reduction). At an incremental cost 

differential of $6.00/MMBtu for gas over coal, the cost effectiveness would be 

$28,762/ton SO2 removed compared to current Baseline Coal 1 operation. 

8.6 SO2 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 emission rate day as the basis for economic 

comparison overstates the emissions reductions actually achievable and understates 

(lowers) the apparent emission reduction cost effectiveness. In order to determine cost 

effectiveness on a more reasonable and appropriate 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 quality (1.76% S and 11,750 Btu/lb). As indicated above, this 

would result in annual total SO2 emissions of 5223 TPY and NOx emissions of 1002 

TPY. Equivalent total boiler monthly average 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 appropriate, it is still 

conservative. Results for this average annual 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 $1.56MM per year over current coal cost for 

increased coal purchase price. SO2 reductions vs. average coal (Coal 1) burned at the site 

(2.85 lb/MMBtu) would be 772 TPY with resultant incremental cost of $2024/ton SO2

removed. 

8.6.2 Coal 3 Fired in Boilers 20 and 24 

Annual costs would increase approximately $2.34MM per year over current coal cost for 

increased coal purchase price. SO2 reductions vs. average coal (Coal 1) (2.85 lb/MMBtu) 

would be 2255 TPY with resultant incremental cost effectiveness of $1039/ton SO2

removed. If compared to Coal 2 (2.43 lb/MMBtu), the incremental SO2 reduction would 

be 1484 TPY with an incremental cost effectiveness vs. Coal 2 of $526/ton SO2 removed. 

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If rebuilding the ESP would be required, the total annualized cost increase would be 

$3.13MM and the cost effectiveness vs Coal 1 would rise to $1390/ton SO2 removed and 

$1060/ton SO2 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 SO2 reduction vs. Baseline Coal 1 firing alone would be 4962 TPY with 

an average cost effectiveness of $4547/ton SO2 removed. 

• Installation on Boiler 20 Only 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 4216 TPY with 

an average cost effectiveness of $3212/ton SO2 removed. 

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

• Installation on Both Boilers 20 and 24 

Overall SO2 reduction vs. Coal 2 firing alone would be 4229 TPY with an 

incremental cost effectiveness of $3386/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 4229 TPY 

with an average cost effectiveness of $3176/ton SO2 removed. 

• Installation on Boiler 20 Only 

Overall SO2 reduction vs. Coal 2 firing alone would be 3593 TPY with an 

incremental cost effectiveness of $2426/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 4365 TPY 

with an average cost effectiveness of $2355/ton SO2 removed. 

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

• Installation on Both Boilers 20 and 24 

Overall SO2 reduction vs. Coal 3 firing alone would be 2819 TPY with an 

incremental cost effectiveness of $5089/ton SO2 removed. 

Overall SO2 reduction vs. Coal 2 firing alone would be 4303 TPY with an 

incremental cost effectiveness of $3516/ton SO2 removed. 

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Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 5075 TPY 

with an average cost effectiveness of $3289/ton SO2 removed. 

• Installation on Boiler 20 Only 

Overall SO2 reduction vs. Coal 3 firing alone would be 2395 TPY with an 

incremental cost effectiveness of $3650/ton SO2 removed. 

Overall SO2 reduction vs. Coal 2 firing alone would be 3879 TPY with an 

incremental cost effectiveness of $2455/ton SO2 removed. 

Overall SO2 reduction vs. Baseline Coal 1 firing alone would be 4651 TPY 

with an average cost effectiveness of $2384/ton SO2 removed. 

8.6.4 50/50 Coal/Gas Cofiring 

If a 50/50 coal/gas ratio was used on an annual basis, total SO2 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 SO2 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 would 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 retrofit 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 retrofit 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 

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Total NOx emission reduction from SNCR retrofit 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 would 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 would 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 annual basis, total NOx reduction compared to 

current operation would be 401 TPY ( 40% reduction). At an incremental cost 

differential of $6.00/MMBtu for gas over coal, the cost effectiveness would be 

$28,835/ton NOx removed compared to current Baseline Coal 1 operation. 

8.7 Energy and Non-Air Quality Environmental Impacts of Compliance 

This analysis does not provide detailed quantification of energy and non-air quality 

environmental impacts for each compliance option since this is a high level analysis. 

However, those impacts and be described qualitatively. 

Use of lower sulfur alone coal would not entail 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 coal ash-only condition by the quantity of 

calcium sulfite/sulfate formed in the scrubber. This can be estimated based on removal 

percent and expected calcium/sulfur stoichiometric ratio. Costs for that disposal are 

included within the estimated O&M cost estimates. 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 baghouse, including, for 

example, lime transport, slurry preparation and injection, baghouse pulse air, ash and 

spent sorbent handling, and increased fan power to compensate for increased flue gas 

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pressure drop. Increased purchased electricity would result in increased emissions of 

SO2, NOx, CO2, and other emissions from the electric utility generators providing that 

power, which could in fact, be units that themselves impact Class I areas with their SO2

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

Use of a sodium wet scrubber would require use of caustic as the reagent. Liquid waste 

disposal would increase for disposal of the scrubber blowdown stream. The existing 

plant waste water treatment facility likely does not have adequate capacity for that waste 

stream directly, but some form of neutralization and oxidation would be required prior to 

transfer to the waste treatment system. Costs 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 SO2, NOx, CO2, and other emissions 

from the electric utility generators providing that power, which could in fact, be units that 

themselves impact Class I areas with their SO2 and NOx emissions. Water would also be 

consumed for the scrubber solution. 

Use of LNB would result in increased unburned 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 electricity 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 sulfur and chloride species in 

the flue gas forming ammonium salts which increase the concentration of fine 

particulates (PM2.5) in the flue gas, potentially increasing stack opacity. On-site storage 

of ammonia would create its own set of safety issues. Disposal of spent catalyst would 

be a long term solid waste issue for SCR. 

8.8 Conclusions Relative to SO2 and NOx Controls for Boilers 20 and 24 

Appropriate control options were evaluated in this high level analysis and those are 

discussed above. Use of the current coal already 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 current 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 utilization, but significant investigation would need 

to be conducted. As indicated above, there is a possibility that ESP rebuilding would be 

required in order to fire coal with very low sulfur content, such as 1.0%. 

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Installation of spray dry absorbers with downstream baghouses or sodium wet scrubbers 

both show a high cost per ton of SO2 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 SO2

and NOx emissions reduction levels at points that were considered highly cost effective. 

The marginal cost curves for SO2 and NOx abatement from the CAIR docket (letter from 

EPA Clean Air Markets Division to the Docket, Analysis of the Marginal Cost of SO2

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

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CAIR SO2 cap 2.5 

MM Tons 

CAIR NOx cap 

1.30 MM Tons 

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As indicated in the charts, the CAIR SO2 and NOx caps (lines added) provided emissions 

reductions at marginal costs of less than $1800 per ton of both SO2 and NOx. Therefore, 

reasonable cost effectiveness for smaller BART-eligible emission sources should not 

exceed those figures. All SO2 scrubbing cases evaluated exceed that cost effectiveness 

value. The only option that provides highly cost effective reductions is the use of lower 

sulfur coal for these boilers. The degree of visibility improvement discussed above 

would need to be considered regarding the potential need to use that coal for either full or 

part year operations. 

In addition, the low capacity factor for Boiler 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 applicable to both Boilers 20 and 24 in any case. 

Application of LNB to only Boiler 20 is marginal 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. However, if there are particular days where 

visibility might be most impacted by SO2 and NOx emissions, it might be possible to 

cofire on those days to achieve some visibility improvement if that is shown to be 

justified. 

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Appendix 6 - Results of BART Control Strategy Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN 

Table 8-1 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at Maximum CombiEmissions 

BART For SO2 and NOx for Both Boilers 20 & 24 Based on Maximum Emissions Day for 2005-06

SO2 Model Case Identifier--> A F KM H C P O 

Boilers 20 & 24 Boilers 20 

SO2 ECONOMIC PARAMETERS BASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 using Co

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 Coal 2 Coal 3 using Coal 3 using Coal 2 using current Coal using current Coal Boiler 20 O

Control Option --> No FGD No FGD No FGD 95% WSS 95% WSS 95% WSS 50% Gas Cofiring 95% WS

Coal Percent Sulfur--> 1.88 1.50 1.00 1.00 1.50 1.88 1.88 1.00 

A&E Emission Rate, lb/MMBtu --> 3.13 2.49 1.66 0.08 0.12 0.16 3.13 0.08 

SO2 Emission Rate at DHI, lb/hr--> 2,375 1,895 1,264 63 95 119 1188 561 

Annual SO2 Emissions, TPY--> 7,040 5,617 3,745 187 281 352 3520 899 

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 1,607 1,282 855 43 64 80 804 205 

A&E Total Capital Requirement: $63,365,423 $63,365,423 $63,365,423 $35,425,1

O&M Costs @ 8% + reagent + waste disposal: $7,778,324 $7,741,314 $16,245,380 $5,001,2

Range: +50/-30 +50/-30 +50/-30 +50/-3

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $10 $0 $0 $15 

Coal Change Annual Additional Cost : $1,970,962 $2,956,443 $2,956,443 $1,970,962 $0 $2,956,4

Natural Gas Cofiring Incremental Cost Increase: $14,190,215

Capital Recovery Costs: $6,957,183 $6,957,183 $6,957,183 $3,889,4

Total Annual Costs Excluding Coal Change: $14,735,506 $14,698,497 $23,202,562 $8,890,7

Annual Emissions Reduction vs Baseline Current Coal: 1,423 3,295 6,853 6,759 6,688 3,520 6,142 

Annual Emissions Reduction vs Coal 2: 1,872 5,430 5,336 5,265 2,097 4,718 Annual Emissions Reduction vs Coal 3: 3,558 3,464 3,393 225 2,846 

Downtime at Gas Fuel Price Difference: $3,317,550 $3,317,550 $3,317,550 $3,317,5

Amotized Downtime at Gas Fuel Price Difference: $364,249 $364,249 $364,249 $364,24

Total Annualized Cost: $1,970,962 $2,956,443 $18,056,198 $17,033,708 $23,566,812 $14,190,215 $12,211,4

Cost Effectiveness Relative to Baseline Current Coal, $/Ton Removed: $1,385 $897 $2,635 $2,520 $3,524 $4,031 $1,988 

Cost Effectiveness Relative to Coal 2, $/Ton Removed: $526 $2,962 $2,823 $4,102 $5,827 $2,170 Cost Effectiveness Relative to Coal 3, $/Ton Removed: $4,244 $4,064 $6,075 $49,997 $3,252 

NOx Model Case Identifier--> A B1 B2 C B D1 D2 E

NOx ECONOMIC PARAMETERS BASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boiler 24 As-Is & Boiler 24 As-Is & Boiler 24 As

FACTORED ESTIMATE FROM RTP DATABASE using current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler 20 O

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring LNB SNCR LNB+SC

NOx Emission Rate at DHI, lb/hr--> 421 252 252 50 252 324 324 208

Annual NOx Emissions, TPY--> 1233 740 740 148 740 843 843 374

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 282 169 169 34 169 192 192 85

A&E Total Capital Requirement: $5,215,728 $3,122,793 $31,225,760 $2,607,864 $1,856,689 $17,355,3

O&M Costs: $208,629 $580,742 $1,470,994 $104,315 $435,205 $816,96

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-3

Natural Gas Cofiring Incremental Cost Increase: $14,190,215

Capital Recovery Costs: $572,659 $342,866 $3,428,421 $286,329 $203,854 $1,905,5

Total Annual Costs Excluding Downtime Gas Cost: $781,288 $923,608 $4,899,414 $390,644 $639,059 $2,722,4

Annual Emissions Reduction: 493 493 1,085 493 391 391 859

Downtime at Gas Fuel Price Difference: $1,658,775 $1,658,775 $1,658,775 $1,658,775 $1,658,775 $1,658,7

Amotized Downtime at Gas Fuel Price Difference: $182,125 $182,125 $182,125 $182,125 $182,125 $182,12

Total Annualized Cost: $963,413 $1,105,732 $5,081,539 $14,190,215 $572,769 $821,184 $2,904,6

Cost Effectiveness Relative to Baseline Current Equipment, $/Ton Removed: $1,953 $2,241 $4,682 $28,762 $1,466 $2,102 $3,380

Incremental Cost Effectiveness Relative to LNB on Boiler 20 Only, $/Ton Removed: $3,803 $5,189 $6,490 $132,585 $4,974

A

C 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Date: September 18, 2007 Page 88 of 92 

Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 8-2 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at Average Firing RCoal Quality 

BART For SO2 and NOx for Both Boilers 20 & 24 Based on Actual Average Operation & Average Coal Quality 

SO2 Model Case Identifier--> AFKM H C P O 

Boilers 20 & 24 Boilers 20 

SO2 ECONOMIC PARAMETERS BASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 using Co

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 Coal 2 Coal 3 using Coal 3 using Coal 2 using current Coal using current Coal Boiler 20 On

Control Option --> No FGD No FGD No FGD 95% WSS 95% WSS 95% WSS 50% Gas Cofiring 95% WS

Coal Percent Sulfur--> 1.76 1.50 1.00 1.00 1.50 1.76 1.76 1.00 

A&E Emission Rate, lb/MMBtu --> 2.85 2.43 1.62 0.08 0.12 0.14 2.85 0.08 

SO2 Emission Rate at DHI, lb/hr--> 2,163 1,843 1,229 61 92 108 1081 545 

Annual SO2 Emissions, TPY--> 5,223 4,451 2,968 148 223 261 2611 572 

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 1,192 1,016 678 34 51 60 596 131 

A&E Total Capital Requirement: $63,365,423 $63,365,423 $63,365,423 $35,425,1

O&M Costs @ 8% + reagent + waste disposal: $7,075,278 $7,045,950 $15,288,468 $4,538,4

Range: +50/-30 +50/-30 +50/-30 +50/-30 

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $10 $0 $0 $15 

Coal Change Annual Additional Cost : $1,561,889 $2,342,834 $2,342,834 $1,561,889 $0 $2,342,8

Natural Gas Cofiring Incremental Cost Increase: $11,561,886

Capital Recovery Costs: $6,957,183 $6,957,183 $6,957,183 $3,889,4

Total Annual Costs Excluding Coal Change: $14,032,461 $14,003,133 $22,245,651 $8,427,9

Annual Emissions Reduction vs Baseline Current Coal: 772 2,255 5,075 5,000 4,962 2,611 4,651 

Annual Emissions Reduction vs Coal 2: 1,484 4,303 4,229 4,190 1,840 3,879 Annual Emissions Reduction vs Coal 3: 2,819 2,745 2,706 356 2,395 

Downtime at Gas Fuel Price Difference: $2,870,784 $2,870,784 $2,870,784 $2,870,7

Amotized Downtime at Gas Fuel Price Difference: $315,197 $315,197 $315,197 $315,19

Total Annualized Cost: $1,561,889 $2,342,834 $16,690,492 $15,880,219 $22,560,847 $11,561,886 $11,085,9

Cost Effectiveness Relative to Baseline Current Coal, $/Ton Removed: $2,024 $1,039 $3,289 $3,176 $4,547 $4,427 $2,384 

Cost Effectiveness Relative to Coal 2, $/Ton Removed: $526 $3,516 $3,386 $5,011 $5,435 $2,455 Cost Effectiveness Relative to Coal 3, $/Ton Removed: $5,089 $4,932 $7,470 $25,888 $3,650 

NOx Model Case Identifier--> ABBC B D D E

NOx ECONOMIC PARAMETERS BASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boiler 24 As-Is & Boiler 24 As-Is & Boiler 24 As

FACTORED ESTIMATE FROM RTP DATABASE using current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler 20 On

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring LNB SNCR LNB+SC

NOx Emission Rate at DHI, lb/hr--> 421 252 252 50 252 324 324 208

Annual NOx Emissions, TPY--> 1,002 601 601 120 601 664 664 259

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 229 137 137 27 137 152 152 59

A&E Total Capital Requirement: $5,215,728 $3,122,793 $31,225,760 $2,607,864 $1,856,689 $17,355,3

O&M Costs: $208,629 $495,370 $1,717,752 $104,315 $386,598 $961,37

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $11,561,886

Capital Recovery Costs: $572,659 $342,866 $3,428,421 $286,329 $203,854 $1,905,5

Total Annual Costs Excluding Downtime Gas Cost: $781,288 $838,236 $5,146,173 $390,644 $590,453 $2,866,8

Annual Emissions Reduction: 401 401 882 401 338 338 744

Downtime at Gas Fuel Price Difference: $1,435,392 $1,435,392 $1,435,392 $1,435,392 $1,435,392 $1,435,3

Amotized Downtime at Gas Fuel Price Difference: $157,598 $157,598 $157,598 $157,598 $157,598 $157,59

Total Annualized Cost: $938,886 $995,834 $5,303,771 $11,561,886 $548,242 $748,051 $3,024,4

Cost Effectiveness Relative to Baseline Current Equipment, $/Ton Removed: $2,342 $2,484 $6,012 $28,835 $1,622 $2,213 $4,067

Incremental Cost Effectiveness Relative to LNB on Boiler 20 Only, $/Ton Removed: $6,209 $7,114 $8,741 $175,058 $6,104

A

C 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Date: September 18, 2007 Page 89 of 92 

Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 8-3 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Combined Maximum D

SO2 Model Case Identifier--> A FKM H CP O J 

CF as annual 

operating rate= 80%

BASES --->

CF as annual

average % of 

max daily 

emissions=

92% Coal HHV, Btu/lb As-Received= 11,428 Per Boiler MMBtu/hr = 445 Per Boiler SCFM = 107,453 Natural Gas Price Differential Over Coal, $/MMBtu= $6.00

SO2 ECONOMIC PARAMETERS BASELINE+ Coal 2 Coal 3 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Bo

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using c

Control Option --> No FGD No FGD No FGD 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 50% Ga

Coal Percent Sulfur--> 1.88 1.50 1.00 1.00 1.00 1.50 1.50 1.88 1.88 1

A&E Emission Rate, lb/MMBtu --> 3.13 2.49 1.66 0.25 0.08 0.37 0.12 0.47 0.16 3

SO2 Emission Rate at DHI, lb/hr--> 1391 1110 740 111 37 166 55 209 70 

Annual SO2 Emissions, TPY--> 5632 4494 2996 449 150 674 225 845 282 2

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 1286 1026 684 103 34 154 51 193 64 

A&E Total Capital Requirement: $52,388,658 $35,425,148 $52,388,658 $35,425,148 $52,388,658 $35,425,148

O&M Costs @ 8% + reagent + waste disposal: $5,057,064 $5,001,297 $5,019,522 $4,971,689 $10,010,512 $9,968,709

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $15 $10 $10 $0 $0 

Coal Change Annual Additional Cost : $0 $1,576,779 $2,365,168 $2,365,168 $2,365,168 $1,576,779 $1,576,779 $0 $0

Natural Gas Cofiring Incremental Cost Increase: $11,

Capital Recovery Costs: $5,751,993 $3,889,491 $5,751,993 $3,889,491 $5,751,993 $3,889,491

Total Annual Costs Excluding Coal Change: $10,809,057 $8,890,788 $10,771,515 $8,861,180 $15,762,505 $13,858,200

Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3: $4,245 $3,124 $4,639 $3,198 $7,328 $5,106

Annual Emissions Reduction vs Baseline Current Coal: 1,138 2,636 5,183 5,482 4,958 5,408 4,787 5,351 2

Annual Emissions Reduction vs Coal 2: 1,498 4,044 4,344 3,820 4,269 3,649 4,212 1Annual Emissions Reduction vs Coal 3: 2,546 2,846 2,322 2,771 2,151 2,714 

8 Weeks Downtime at Gas Fuel Price Difference: $3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550

Amotized Downtime at Gas Fuel Price Difference: $364,249 $364,249 $364,249 $364,249 $364,249 $364,249

Cost Effectiveness Relative to Baseline Current Coal: $1,385 $897 $2,612 $2,120 $2,564 $1,998 $3,369 $2,658 $4

Cost Effectiveness Relative to Coal 2: $526 $2,958 $2,312 $2,915 $2,161 $3,987 $3,002 $5Cost Effectiveness Relative to Coal 3: $4,388 $3,252 $4,457 $3,045 $6,398 $4,369 $4

NOx Model Case Identifier--> A BBC B DD E

NOx ECONOMIC PARAMETERS BASELINE+ Boiler 20 Boiler 20 Boiler 20 Boiler 20

FACTORED ESTIMATE FROM RTP DATABASE using current Coal

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring

A&E Emission Rate, lb/MMBtu --> 0.542 0.325 0.325 0.065 0.325

NOx Emission Rate at DHI, lb/hr--> 241 145 145 29 145

Annual NOx Emissions, TPY--> 977 586 586 117 586

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 223 134 134 27 134

A&E Total Capital Requirement: $2,607,864 $1,856,689 $17,355,321

O&M Costs: $104,315 $435,205 $816,962

Range: +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $11,352,241

Capital Recovery Costs: $286,329 $203,854 $1,905,521

Total Annual Costs: $390,644 $639,059 $2,722,483

Cost Effectiveness w/o Gas Cost: $1,000 $1,636 $3,168

Annual Emissions Reduction: 391 391 859 391

4 Weeks Downtime at Gas Fuel Price Difference: $1,658,775 $1,658,775 $1,658,775

Amotized Downtime at Gas Fuel Price Difference: $182,125 $182,125 $182,125

Overall Cost Effectiveness: $1,466 $2,102 $3,380 $29,059

ESTIMATE USING USEPA REFERENCES LOW LNB SNCR LNB+SCR

Emission Rate, lb/MMBtu --> 0.54 0.325 0.325 0.065

Total Capital Requirement: $400,500 $1,112,500 $2,562,142

O&M Costs: $44,500 $222,500 $199,674

Range: LOW HIGH NA

Capital Recovery Costs: $43,973 $122,147 $281,309

Total Annual Costs: $88,473 $344,647 $480,983 Annual interest rate (fractional): 0.07

Cost Effectiveness: $226 $882 $560 Controlsystem life (years): 15

Annual Emissions Reduction: 391 391 859 C apital recovery factor (system ): 0.110

BART FOR SO2 & NOX BOILER # 20 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-06

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Date: September 18, 2007 Page 90 of 92 

Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 8-4 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Average Firing Rate & Average Coal Qualit

BART for SO2 & NOX Boiler # 20 Based on Actual Average Operation & Average Coal Quality

SO2 Model Case Identifier--> A FKM H CP O J E

CF as annual 

operating rate= 80%

BASES --->

CF as annual

average % of max 

daily emissions 

rate=

92% Coal HHV, Btu/lb As-Received= 11,750 Per Boiler MMBtu/hr = 445 Per Boiler SCFM = 107,453 Natural Gas Price Differential Over Coal, $/MMBtu= $6.00

SO2 ECONOMIC PARAMETERS BASELINE+ Coal 2 Coal 3 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current Coal

Control Option --> No FGD No FGD No FGD 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 50% Gas Cofiring

Coal Percent Sulfur--> 1.76 1.50 1.00 1.00 1.00 1.50 1.50 1.76 1.76 1.76

A&E Emission Rate, lb/MMBtu --> 2.85 2.43 1.62 0.24 0.08 0.36 0.12 0.43 0.14 2.85

SO2 Emission Rate at DHI, lb/hr--> 1266 1079 720 108 36 162 54 190 63 633

Annual SO2 Emissions, TPY--> 4438 3782 2521 378 126 567 189 666 222 2219

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 1013 863 576 86 29 130 43 152 51 507

A&E Total Capital Requirement: $52,388,658 $35,425,148 $52,388,658 $35,425,148 $52,388,658 $35,425,148

O&M Costs @ 8% + reagent + waste disposal: $4,869,357 $4,538,431 $4,837,761 $4,513,513 $9,659,091 $9,338,316

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $15 $10 $10 $0 $0 $0

Coal Change Annual Additional Cost : $0 $1,327,047 $1,990,570 $1,990,570 $1,990,570 $1,327,047 $1,327,047 $0 $0

Natural Gas Cofiring Incremental Cost Increase: $9,823,464

Capital Recovery Costs: $5,751,993 $3,889,491 $5,751,993 $3,889,491 $5,751,993 $3,889,491

Total Annual Costs Excluding Coal Change: $10,621,350 $8,427,922 $10,589,754 $8,403,004 $15,411,084 $13,227,807

Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3: $4,956 $3,518 $5,419 $3,603 $8,305 $5,752

Annual Emissions Reduction vs Baseline Current Coal: 656 1,916 4,059 4,312 3,870 4,249 3,772 4,216 2,219

Annual Emissions Reduction vs Coal 2: 1,261 3,404 3,656 3,215 3,593 3,116 3,560 1,563Annual Emissions Reduction vs Coal 3: 2,143 2,395 1,954 2,332 1,856 2,300 303

8 Weeks Downtime at Gas Fuel Price Difference: $2,870,784 $2,870,784 $2,870,784 $2,870,784 $2,870,784 $2,870,784

Amotized Downtime at Gas Fuel Price Difference: $315,197 $315,197 $315,197 $315,197 $315,197 $315,197

Cost Effectiveness Relative to Baseline Current Coal: $2,024 $1,039 $3,184 $2,490 $3,160 $2,364 $4,169 $3,212 $4,427

Cost 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 $25,888

ESTIMATE USING USEPA APCTFS LOW FGD HIGH FGD LOW FGD HIGH FGD LOW FGD HIGH FGD

Emission Rate, lb/MMBtu --> 0.24 0.08 0.36 0.12 0.43 0.14

Total Capital Requirement: $11,769,718 $66,750,000 $11,769,718 $66,750,000 $11,769,718 $66,750,000

O&M Costs Including Coal Change Cost: $2,346,570 $2,791,570 $1,683,047 $2,128,047 $356,000 $801,000

Range: LOW HIGH LOW HIGH LOW HIGH

Capital Recovery Costs: $1,292,252 $7,328,791 $1,292,252 $7,328,791 $1,292,252 $7,328,791

Total Annual Costs: $3,638,822 $10,120,361 $2,975,299 $9,456,838 $1,648,252 $8,129,791

Cost Effectiveness vs Baseline Current Coal: $896 $2,347 $769 $2,226 $437 $1,928

Annual Emissions Reduction vs Baseline Current Coal: 4,059 4,312 3,870 4,249 3,772 4,216

NOx Model Case Identifier--> A BBC B DD E

NOx ECONOMIC PARAMETERS BASELINE+ Boiler 20 Boiler 20 Boiler 20 Boiler 20

FACTORED ESTIMATE FROM RTP DATABASE using current Coal

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring

A&E Emission Rate, lb/MMBtu --> 0.54 0.325 0.325 0.065 0.325

NOx Emission Rate at DHI, lb/hr--> 241 145 145 29 145

Annual NOx Emissions, TPY--> 845 507 507 101 507

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 193 116 116 23 116

A&E Total Capital Requirement: $2,607,864 $1,856,689 $17,355,321

O&M Costs: $104,315 $386,598 $961,372

Range: +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $9,823,464

Capital Recovery Costs: $286,329 $203,854 $1,905,521

Total Annual Costs: $390,644 $590,453 $2,866,892

Cost Effectiveness w/o Gas Cost: $1,156 $1,747 $3,855

Annual Emissions Reduction: 338 338 744 338

4 Weeks Downtime at Gas Fuel Price Difference: $1,435,392 $1,435,392 $1,435,392

Amotized Downtime at Gas Fuel Price Difference: $157,598 $157,598 $157,598

Overall Cost Effectiveness: $1,622 $2,213 $4,067 $29,059

ESTIMATE USING USEPA REFERENCES LOW LNB SNCR LNB+SCR

Emission Rate, lb/MMBtu --> 0.54 0.325 0.325 0.065

Total Capital Requirement: $400,500 $1,112,500 $7,439,363

O&M Costs: $44,500 $222,500 $417,242

Range: LOW HIGH NA

Capital Recovery Costs: $43,973 $122,147 $816,802

Total Annual Costs: $88,473 $344,647 $1,234,044 Annual interest rate (fractional): 0.07

Cost Effectiveness: $262 $1,020 $1,659 C ontrolsystem life (years): 15

Annual Emissions Reduction: 338 338 744 C apital recovery factor (system ): 0.110

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Date: September 18, 2007 Page 91 of 92 

Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 8-5 BART Economic Analysis for DuPont Old Hickory Boiler 24 at Maximum Combined D

SO2 Model Case Identifier--> A FKM H CP O J E

CF as annual 

operating rate= 20%

BASES --->

CF as annual

average % of 

max daily 

emissions=

33% Coal HHV, Btu/lb As-Received= 11,428 Per Boiler MMBtu/hr = 315 Per Boiler SCFM = 81,478 Natural Gas Price Differential Over Coal, $/MMBtu= $6.00

SO2 ECONOMIC PARAMETERS BASELINE+ Coal 2 Coal 3 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 2

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using curren

Control Option --> No FGD No FGD No FGD 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 50% Gas Co

Coal Percent Sulfur--> 1.88 1.50 1.00 1.00 1.00 1.50 1.50 1.88 1.88 1.88

A&E Emission Rate, lb/MMBtu --> 3.13 2.49 1.66 0.25 0.08 0.37 0.12 0.469 0.156 3.13

SO2 Emission Rate at DHI, lb/hr--> 985 786 524 79 26 118 39 148 49 492

Annual SO2 Emissions, TPY--> 1408 1123 749 112 37 169 56 211 70 704

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 321 256 171 26 9 38 13 48 16 161

A&E Total Capital Requirement: $41,319,616 $27,940,275 $41,319,616 $27,940,275 $41,319,616 $27,940,275

O&M Costs @ 8% + reagent + waste disposal: $3,522,056 $2,777,027 $3,512,670 $2,769,625 $7,018,208 $6,276,670

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $15 $10 $10 $0 $0 $0

Coal Change Annual Additional Cost : $0 $394,183 $591,274 $591,274 $591,274 $394,183 $394,183 $0 $0

Natural Gas Cofiring Incremental Cost Increase: $2,837,9

Capital Recovery Costs: $4,536,672 $3,067,692 $4,536,672 $3,067,692 $4,536,672 $3,067,692

Total Annual Costs Excluding Coal Change: $8,058,727 $5,844,719 $8,049,342 $5,837,317 $11,554,880 $9,344,362

Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3: $12,659 $8,215 $13,868 $8,426 $21,488 $13,771

Annual Emissions Reduction vs Baseline Current Coal: 285 659 1,296 1,371 1,240 1,352 1,197 1,338 704

Annual Emissions Reduction vs Coal 2: 374 1,011 1,086 955 1,067 912 1,053 419Annual Emissions Reduction vs Coal 3: 637 711 580 693 538 679 45

Downtime at Gas Fuel Price Difference: $0 $0 $0 $0 $0 $0

Amotized Downtime at Gas Fuel Price Difference: $0 $0 $0 $0 $0 $0

Cost Effectiveness Relative to Baseline Current Coal: $1,385 $897 $6,676 $4,696 $6,812 $4,610 $9,655 $6,986 $4,031

Cost 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 $49,99

NOx Model Case Identifier--> A B B C B

NOx ECONOMIC PARAMETERS BASELINE+ Boiler 24 Boiler 24 Boiler 24 Boiler 24

FACTORED ESTIMATE FROM RTP DATABASE using current Coal

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring

A&E Emission Rate, lb/MMBtu --> 0.57 0.342 0.342 0.068 0.342

NOx Emission Rate at DHI, lb/hr--> 180 108 108 22 108

Annual NOx Emissions, TPY--> 257 154 154 31 154

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 59 35 35 7 35

A&E Total Capital Requirement: $2,607,864 $1,266,104 $13,870,439

O&M Costs: $104,315 $145,537 $654,032

Range: +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $2,837,974

Capital Recovery Costs: $286,329 $139,011 $1,522,900

Total Annual Costs: $390,644 $284,548 $2,176,931

Cost Effectiveness w/o Gas Cost: $3,803 $2,770 $9,634

Annual Emissions Reduction: 103 103 226 103

Downtime at Gas Fuel Price Difference: $0 $0 $0

Amotized Downtime at Gas Fuel Price Difference: $0 $0 $0

Overall Cost Effectiveness: $3,803 $2,770 $9,634 $27,632

ESTIMATE USING USEPA REFERENCES LOW LNB SNCR LNB+SCR

Emission Rate, lb/MMBtu --> 0.57 0.342 0.342 0.068

Total Capital Requirement: $283,500 $787,500 $2,063,784

O&M Costs: $31,500 $157,500 $157,419

Range: LOW HIGH NA

Capital Recovery Costs: $31,127 $86,463 $226,592

Total Annual Costs: $62,627 $243,963 $384,011 Annual interest rate (fractional): 0.07

Cost Effectiveness: $610 $2,375 $1,699 C ontrolsystem life (years): 15

Annual Emissions Reduction: 103 103 226 C apital recovery factor (system ): 0.110

BART FOR SO2 & NOX BOILER # 24 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-06

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Date: September 18, 2007 Page 92 of 92 

Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 8-6 BART Economic Analysis for DuPont Old Hickory Boilers 24 at Average Firing Rate & Quality

BART for SO2 & NOX Boiler # 24 Based on Actual Average Operation & Average Coal Quality

SO2 Model Case Identifier--> A FKM H CP O J E

CF as annual 

operating rate= 20%

BASES --->

CF as annual 

average % of max 

daily emissions rate=

33% Coal HHV, Btu/lb As-Received= 11,750 Per Boiler MMBtu/hr = 315 Per Boiler SCFM = 81,478 Natural Gas Price Differential Over Coal, $/MMBtu= $6.00

SO2 ECONOMIC PARAMETERS BASELINE+ Coal 2 Coal 3 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current Coal

Control Option --> No FGD No FGD No FGD 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 50% Gas Cofiring

Coal Percent Sulfur--> 1.76 1.50 1.00 1.00 1.00 1.50 1.50 1.76 1.76 1.76

A&E Emission Rate, lb/MMBtu --> 2.85 2.43 1.62 0.24 0.08 0.36 0.12 0.427 0.142 2.85

SO2 Emission Rate at DHI, lb/hr--> 896 764 509 76 25 115 38 134 45 448

Annual SO2 Emissions, TPY--> 785 669 446 67 22 100 33 118 39 393

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 179 153 102 15 5 23 8 27 9 90

A&E Total Capital Requirement: $41,319,616 $27,940,275 $41,319,616 $27,940,275 $41,319,616 $27,940,275

O&M Costs @ 8% + reagent + waste disposal: $3,425,599 $2,536,847 $3,420,008 $2,532,437 $6,837,108 $5,950,152

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $15 $10 $10 $0 $0 $0

Coal Change Annual Additional Cost : $0 $234,843 $352,264 $352,264 $352,264 $234,843 $234,843 $0 $0

Natural Gas Cofiring Incremental Cost Increase: $1,738,422

Capital Recovery Costs: $4,536,672 $3,067,692 $4,536,672 $3,067,692 $4,536,672 $3,067,692

Total Annual Costs Excluding Coal Change: $7,962,271 $5,604,539 $7,956,679 $5,600,129 $11,373,780 $9,017,844

Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3: $20,994 $13,222 $23,009 $13,568 $34,634 $22,160

Annual Emissions Reduction vs Baseline Current Coal: 116 339 718 763 685 752 668 746 393

Annual Emissions Reduction vs Coal 2: 223 602 647 569 636 552 630 277Annual Emissions Reduction vs Coal 3: 379 424 346 413 328 407 54

Downtime at Gas Fuel Price Difference: $0 $0 $0 $0 $0 $0

Amotized Downtime at Gas Fuel Price Difference: $0 $0 $0 $0 $0 $0

Cost Effectiveness Relative to Baseline Current Coal: $2,024 $1,039 $11,574 $7,807 $11,960 $7,761 $17,039 $12,087 $4,427

Cost 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 $25,888

ESTIMATE USING USEPA APCTFS LOW FGD HIGH FGD LOW FGD HIGH FGD LOW FGD HIGH FGD

Emission Rate, lb/MMBtu --> 0.24 0.08 0.36 0.12 0.43 0.14

Total Capital Requirement: $8,363,868 $47,250,000 $8,363,868 $47,250,000 $8,363,868 $47,250,000

O&M Costs Including Coal Change Cost: $604,264 $919,264 $486,843 $801,843 $252,000 $567,000

Range: LOW HIGH LOW HIGH LOW HIGH

Capital Recovery Costs: $918,308 $5,187,796 $918,308 $5,187,796 $918,308 $5,187,796

Total Annual Costs: $1,522,572 $6,107,060 $1,405,150 $5,989,639 $1,170,308 $5,754,796

Cost Effectiveness vs Baseline Current Coal: $2,119 $8,004 $2,052 $7,967 $1,753 $7,714

Annual Emissions Reduction vs Baseline Current Coal: 718 763 685 752 668 746

NOx Model Case Identifier--> A B B C B

NOx ECONOMIC PARAMETERS BASELINE+ Boiler 24 Boiler 24 Boiler 24 Boiler 24

FACTORED ESTIMATE FROM RTP DATABASE using current Coal

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring

A&E Emission Rate, lb/MMBtu --> 0.57 0.342 0.342 0.068 0.342

NOx Emission Rate at DHI, lb/hr--> 180 108 108 22 108

Annual NOx Emissions, TPY--> 157 94 94 19 94

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 36 22 22 4 22

A&E Total Capital Requirement: $2,607,864 $1,266,104 $13,870,439

O&M Costs: $104,315 $108,772 $756,381

Range: +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $1,738,422

Capital Recovery Costs: $286,329 $139,011 $1,522,900

Total Annual Costs: $390,644 $247,783 $2,279,280

Cost Effectiveness w/o Gas Cost: $6,209 $3,938 $16,467

Annual Emissions Reduction: 63 63 138 63

Downtime at Gas Fuel Price Difference: $0 $0 $0

Amotized Downtime at Gas Fuel Price Difference: $0 $0 $0

Overall Cost Effectiveness: $6,209 $3,938 $16,467 $27,632

ESTIMATE USING USEPA REFERENCES LOW LNB SNCR LNB+SCR

Emission Rate, lb/MMBtu --> 0.57 0.342 0.342 0.068

Total Capital Requirement: $283,500 $787,500 $5,890,875

O&M Costs: $31,500 $157,500 $317,174

Range: LOW HIGH NA

Capital Recovery Costs: $31,127 $86,463 $646,786

Total Annual Costs: $62,627 $243,963 $963,960 Annual interest rate (fractional): 0.07

Cost Effectiveness: $995 $3,878 $6,964 C ontrolsystem life (years): 15

Annual Emissions Reduction: 63 63 138 C apital recovery factor (system ): 0.110

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
 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, Suite 135 1007 Market Street 

Houston, TX 77062 Wilmington, DE 19898 

September 18, 2007

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Appendix L.8 - 291

January 18, 2008
 Date: September 18, 2007 Page 2 of 10 

Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

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Appendix L.8 - 292

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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 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

1. Summary 

The BART (Best Available Retrofit Technology) Modeling results presented in this 

report show that the emissions from the DuPont Old Hickory Plant are not predicted 

cause or contribute to visibility impairment at any of the nearby 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 Visual Environments (IMPROVE) protocols for 

reconstructing ambient light extinction from measured aerosol species are the basis for 

evaluating light extinction from BART modeling 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 Rates Using the Old IMPROVE Equation”. As 

stated in the report title, the companion report provides the modeling results as analyzed 

using the old IMPROVE equation. 

The same BART modeling results are analyzed in this report using the new IMPROVE 

equation. The modeling protocol and the modeling results were not changed. The 

modeling was done per the protocol described and used in the companion report. Only 

the two base cases were re-analyzed. The two 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 for these firing rates is described in the 

companion report. 

3. Description of the Old and New IMPROVE Equations 

The Interagency Monitoring of Protected Visual Environments (IMPROVE) protocols for 

reconstructing ambient light extinction from measured aerosol species are the basis for 

evaluating light extinction from BART modeling 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 (ba,g) is 

zero, that Rayleigh scattering (bs,g) is 10Mm-1 for each monitoring site regardless 

of site elevation and meteorological condition, and that particle scattering and 

absorption (bs,p and ba,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 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

sulfate), nitrate (assumed to be ammonium nitrate), organic compounds (based on 

measured organic carbon mass), elemental or black carbon (directly measured), 

fine soil (crustal elements plus oxides) and coarse mass (the difference between 

PM10 and PM2.5 mass concentrations). The component extinction efficiency 

values are constants, except for the sulfate and nitrate extinction efficiency terms 

that include a water growth factor that 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 humidity monitoring. Expressed as 

an equation, the current algorithm for estimating light extinction from IMPROVE 

data takes the following form where the particle component concentrations are 

indicated in the brackets. The formulas for the composite components are 

available elsewhere (IMPROVE web site). 

[ ]

[ ]

[ ]

[ ]

[ ]

[ ]

10

6.0

1

10

4

)(3

)(3

+

×+

×+

×+

×+

××+

≈ × ×

Coarse Mass

SoilFine

Elemental Carbon

Organic Mass

RHf Nitrate

RHfb Sulfate ext

The units for light extinction and Rayleigh scattering are inverse megameters 

(1/106

m usually written Mm-1); component concentrations shown in brackets are 

in microgram per meter cubed (μg/m3); dry efficiency terms are in units of meters 

squared per gram (m2/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 Committee developed a new algorithm for 

estimating light extinction from particulate matter component concentrations. 

This algorithm (the ‘new IMPROVE algorithm’) provides a better correspondence 

between the measured visibility and that calculated from particulate matter 

component concentrations. The new algorithm 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 identical, although the new 

hygroscopic scattering enhancement factors applied to them are the same. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

• The concentration of particulate organic 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 light extinction has been added, and is 

accompanied by its own hygroscopic scattering enhancement factor, 

fss(RH). 

• The light scattering by air itself (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:

bext = 2.2•fS(RH)•[small sulfate] + 4.8•fL(RH)•[large sulfate] 

+2.4•fS(RH)•[small nitrate] + 5.1•fL(RH)•[large nitrate] 

+2.8•[small organics] + 6.1•[large organics] 

+10•[elemental carbon] 

+1•[fine soil] 

+1.7•fSS(RH)•[sea salt] 

+0.6•[coarse matter] 

+Rayleigh scattering (site specific) 

+0.33•[NO2(ppb)] 

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

follows: 

[large sulfate] = {[total sulfate]/20}•[total sulfate] if [total sulfate] < 20 μg3 

[large sulfate] = [total sulfate] if [total sulfate] ≥ 20 μg/m3 

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

Identical formulas, with changes 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” particles with their own extinction efficiency 

and fS(RH), while high concentrations (approaching 20 μg/m3) are mainly in the 

form of “large” particles with a different 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 Processor 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 CALPUFF modeling results 

using the new IMPROVE equation. 

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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 BART 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

dV

Modeled 98th

 percentile

Value

(dV)

No Days 

exceeding 0.5

dV

This is a significant reduction in predicted visibility impact for the boilers at the DuPont 

Old Hickory Plant compared to the analysis 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 the 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 emissions and further evaluation is 

not necessary. 

The results in Table 4-1 were estimated using the maximum 24 hour firing 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 results using the monthly 

maximum firing rates are more representative of the firing patterns for the Old Hickory 

Boilers. 

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

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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 using 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. 

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

Table 4-3 – Top 8 Modeled dV Results for Mammoth Cave for DuPont, Old Hickory using the NeEquation 

2001 2002 2003 2001 

Baseline Modeling 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

AveDelRanor > 

Baseline Case @ 24 hr Max Firing Rate 1 0.64 1.16 1.07 0.527 

2 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 0.50

Baseline Case @ Monthly Max Firing Rate 1 0.42 0.84 0.76 0.375 

2 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

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Results of BART Modeling & Engineering Analysis DuPont Old Hickory Plant, Old Hickory, TN

5. References 

1. IMPROVE technical subcommittee for algorithm 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/Publications/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/Publications/GrayLit/gray_literature.htm

3. Dr. Ivar Tombach. “Instructions: A Postprocessor for Recalculating CALPOST 

Visibility Outputs with the New IMPROVE 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 Processor 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 & Nashville Metro Health Dept, Sept. 18, 2007. 

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Appendix L.8 - 300

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Appendix L.8 - 301

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Appendix L.8 - 302

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