Prepared for: Prepared by: 

 International Paper AECOM 

 Ticonderoga, NY Westford, MA 

 60156563 

 October 1, 2010

Environment 

Five Factor BART Analysis for 

International Paper Ticonderoga Mill 

September 2010 

Document No.: 60156563 
Prepared for: Prepared by: 

 International Paper AECOM 

 Ticonderoga, NY Westford, MA 

 60156563 

 October 1, 2010

Environment 

Five Factor BART Analysis for 

International Paper Ticonderoga Mill 

_______________________________________________________________________________ 

Prepared By Robert Hall Seemantini Deshpande Adrienne Kieldsing 

_________________________________ 

Reviewed By Robert M. Iwanchuk 

September 2010 

Document No.: 60156563 
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Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

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Contents 

Executive Summary ............................................................................................................ ES-1 

1.0 Introduction ...................................................................................................................... 1-1

1.1 Location of Source vs. Relevant Class I Areas .................................................................. 1-2

1.2 Organization of Report ......................................................................................................... 1-2

2.0 Background Data ............................................................................................................ 2-1

2.1 Overview of BART-Eligible Emission Units ......................................................................... 2-1

2.2 Description of BART-Eligible Sources ................................................................................ 2-2

2.2.1 Power Boiler .......................................................................................................... 2-2

2.2.2 Recovery Boiler ..................................................................................................... 2-2

2.2.3 Smelt Dissolving Tank .......................................................................................... 2-2

2.2.4 Lime Kiln ................................................................................................................ 2-2

2.2.5 Miscellaneous Sources ......................................................................................... 2-3

2.3 Baseline Actual Emissions .................................................................................................. 2-3

2.3.1 Power Boiler .......................................................................................................... 2-3

2.3.2 Recovery Boiler ..................................................................................................... 2-4

2.3.3 Lime Kiln ................................................................................................................ 2-4

2.3.4 Smelt Dissolving Tank .......................................................................................... 2-5

2.3.5 Miscellaneous Sources ......................................................................................... 2-5

3.0 Emission Control Alternatives for BART-Subject Sources ....................................... 3-1

3.1 Power Boiler Emission Control Alternatives ....................................................................... 3-1

3.1.1 SO2 Emissions ...................................................................................................... 3-1

3.1.2 NOx Emissions ..................................................................................................... 3-3

3.1.3 Filterable PM Emissions ....................................................................................... 3-5

3.2 Recovery Boiler .................................................................................................................... 3-5

3.2.1 SO2 Emission Controls ......................................................................................... 3-5

3.2.2 NOX Emission Controls ......................................................................................... 3-6

3.2.3 PM Emission Control ............................................................................................ 3-7

4.0 Meteorological Data used in Visibility Improvement Modeling ................................. 4-1

5.0 CALPUFF Modeling Procedures ................................................................................... 5-1

5.1 CALPUFF Modeling Domain and Receptors ...................................................................... 5-1
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5.2 Model Version ...................................................................................................................... 5-1

5.3 Background Air Quality Data ............................................................................................... 5-1

5.4 Light Extinction and Haze Impact Calculations .................................................................. 5-1

6.0 CALPUFF Modeling and BART Determination Results .............................................. 6-1

6.1 Exemption Modeling ............................................................................................................ 6-1

6.2 Modeled Control Scenarios ................................................................................................. 6-2

6.3 Modeling Results for Baseline Emissions ........................................................................... 6-2

6.4 Modeling Results for Power Boiler Guideline and Benchmark Emission Rates................ 6-4

6.5 Conclusions and BART Recommendation ......................................................................... 6-5

7.0 References ....................................................................................................................... 7-1

List of Appendices 

Appendix A Response to NYSDEC Letter January 2010

Appendix B NCASI Emission Factors and Retrofit Controls for Pulp Mill Sources

Appendix C NYSDEC BART Guidance Presentations

Appendix D Modeling Archive

List of Tables 

Table ES-1: Summary of BART Determinations ................................................................................. ES-3 

Table 2-1: Visibility Impacts of the BART-Exempt Sources at the Mill............................................... 2-1

Table 2-2: IP Ticonderoga Mill Baseline Emissions ........................................................................... 2-6

Table 2-3: IP Ticonderoga Mill Baseline Stack Parameters ............................................................... 2-7

Table 3-1: Comparison of Power Boiler SO2 Emissions to Guidelines and Benchmarks ................. 3-3

Table 3-2: Comparison of Power Boiler NOx Emissions to Guidelines and Benchmarks ................ 3-5

Table 4-1: Comparison of the AECOM and VT DEC CALMET User-Defined Settings .................... 4-2

Table 5-1: References to the New IMPROVE Equation CALPOST Inputs ....................................... 5-2

Table 6-1: Exemption Modeling of BART-Eligible Sources at the Mill ............................................... 6-1

Table 6-2: Regional Haze Impacts due to Baseline Emissions ......................................................... 6-3
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Table 6-3: Regional Haze Impacts for SO2 Emission Guidelines and Benchmarks for IP's Power 

Boiler ................................................................................................................................... 6-4

List of Figures 

Figure 1-1: Location of the Class I Areas in Relation to the Ticonderoga Mill .................................... 1-3

Figure 4-1: IP Ticonderoga CALMET Modeling Domains ................................................................... 4-3
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Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

ES-1

Executive Summary 

This report documents the key findings related to potential visibility impacts and emission control 

assessment for the BART-eligible emission units located at the International Papers (IP) Ticonderoga 

Mill. Six emission units at the Ticonderoga Mill began operation in the 15-year BART time window 

and are “BART- Eligible” units. 

Based on the visibility impairment criteria adopted by New York, modeling evaluations show that: 

 None of IP’s Bart-Eligible units cause visibility impairment in any Class I area; 

 Impacts from four units (Smelt Dissolving Tank, Lime Kiln, Starch Silo and Chip cyclones) are 

lower than de minimis levels and thereby determined to not contribute to degradation of 

visibility in any Class I area. 

 Impacts from IP’s Power Boiler and Recovery Boiler exceed the 0.1 deciview contribution 

criterion at the closest Class I area (Lye Brook Wilderness area) and therefore are subject to 

BART control evaluations. 

Conclusions from the Power Boiler and Recovery Boiler BART control options evaluation are outlined 

below: 

Power Boiler 

Filterable PM 

 PM controls currently in place achieve performance levels required under federal New Source 

Performance Standards for new boilers that were constructed prior to 2005. 

 New Maximum Achievable Control Technology (MACT) standards will require additional 

reduction of PM emissions. 

 Existing PM controls, supplemented by improvements required by Boiler MACT satisfy BART 

PM control requirements for the boiler. 

SO2

 SO2 controls currently in place achieve performance levels consistent with most presumptive 

BART benchmarks. 

 New MACT standards will establish emission requirements for acid gases. Operation and/or 

control enhancements to comply with these provisions will further serve to reduce SO2

emissions. 

 Existing SO2 controls, supplemented by improvements required by Boiler MACT satisfy BART 

control requirements for SO2. 

NOx 

 NOx controls are currently in place to ensure compliance with CAIR NOx Budget 

requirements. 
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 Future regulatory programs (such as RACT) are expected to periodically trigger requirements 

to review NOx emissions levels which will serve to identify new and emerging technologies. 

 Existing control systems and operational practices achieve NOx levels consistent with 

presumptive BART benchmarks and satisfy BART requirements for NOx. 

Recovery Boiler 

Filterable PM and SO2

 PM controls currently in place satisfy MACT standards for PM-HAPs and satisfy BART. 

 SO2 emissions from non-direct contact evaporation recovery furnaces are inherently low due 

to operating practices. 

 Existing design and operating practices satisfy BART for these pollutants. 

 Revisions to Subpart MM MACT standards may impact future emissions of these visibility 

impairing pollutants. 

NOx 

 Good operating practices are currently used to comply with NYSDEC’s NOx RACT 

requirements. 

 No technically-feasible alternatives have been identified for achieving additional NOx 

emission reduction from recovery boilers. 

 BART for NOx emissions from IP’s Recovery Boiler is use of three-level staged combustion 

air system with ESPs. 

The results of the case-by-case BART analysis for the BART-subject units are summarized in Table 

ES-1. 
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Five Factor BART Analysis for International Paper Ticonderoga Mill 

Table ES-1: Summary of BART Determinations 

Parameter Power Boiler Recove

Baseline Visibility Impacts (a)

Days > 0.1 deciview (b) 46 to 51 16Days > 0.5 deciview (b) 2 to 5 0 Days > 1.0 deciview (b) 0 0 Maximum Impact, deciview (b) 0.64 (sulfates = 0.2, nitrates = 0.34) to 0.73 (sulfates = 0.23, nitrates = 0.35) 0.28 (sulfates = 0.11, nitrate

0.18, nitra

Eighth Highest Impact, deciview (b) 0.34 to 0.40 0.16

PM Emissions 

Existing Control Technology Multicyclone & wet scrubber ES

Baseline Filterable PM Emissions 48 lb PM/hr 8.1 lb Proposed BART Determination Currently permitted emissions Compliance with the curren

lim

Basis and Other Considerations 

Filterable PM-HAP control that will be required in 2014/15 

timeframe by Boiler MACT may decrease emissions. 

The maximum PM visibility impact is close to 0.1 deciview 

and the eighth highest impact is less than 0.1 deciview. 

Filterable PM-HAP contr

2014/15 timeframe by 8-y

emiss

The maximum PM visibil

deciv

SO2

Emissions 

Existing Control Technology Wet scrubber with sodium hydroxide injection Low odor non-direct cont

provides very 

Baseline SO2 Emissions 274 lb/hr <1 Proposed BART Determination Currently permitted emissions based on wet scrubbing Continued good oBasis and Other Considerations 

Currently permitted emissions are less than MANE-VU 

presumptive BART and within the range of other 

benchmark emission rates. 

Potential lower SO2 emission rates show maximum visibility 

improvements less than 0.1 deciview 

The process results in in

Maximum SO2 visibility 

deci
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Five Factor BART Analysis for International Paper Ticonderoga Mill 

Parameter Power Boiler Recove

NOx Emissions 

Existing Control Technology Advanced combustion controls including TODD low NOx burners Staged combustion with 

primary, secondary an

Baseline NOx Emissions 178 lb/hr (maximum daily average occurred on 12/26/05 during the non-ozone season) 65 lProposed BART Determination Currently permitted emissions Currently permBasis and Other Considerations 

Currently emissions are well controlled. 

Lower NOx emissions would decrease the maximum 

visibility impact by no more than 0.18 deciviews and the 

eighth highest impact by no more than 0.07 deciviews. 

The Power Boiler will comply with the New York NOx RACT 

rule by July 1, 2014. In New York, compliance with the 

NOx RACT rule is the presumptive BART. 

Maximum visibility impacts 

close to 0.1 deciview and t

less than 0

There are no availab

(a) At the Lye Brook Wilderness area which is the closest Class I area and the location of the maximum predicted impacts. The range reflect

predicted using two meteorological data bases required by NYSDEC for visibility modeling. 

(b) The reported impact is the change (delta deciview) compared to visibility presumed to occur on days under the best natural background 

without influence from any man-made emission activity.
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1.0 Introduction 

The Ticonderoga Mill, owned and operated by International Paper Company, has been identified by 

NYSDEC as a source that is eligible for consideration of BART controls for the visibility impairing 

pollutants SO2, NOx, and PM10. This document describes the procedures by which a modeling 

analysis and a BART engineering review have been conducted for the units subject to BART at the 

Ticonderoga Mill. 

To protect visibility in national parks and wilderness areas, state and federal regulations require 

evaluation of the existing level of emission controls and visibility impacts associated with certain types 

of emission sources that began operation between 1962 and 1977. 

New York rules (6NYCRR§249.1) require sources with BART-eligible units to evaluate emissions and 

use modeling to determine if the emissions could reasonably cause or contribute to visibility 

impairment at one or more of the seven Class I areas in the northeastern U.S. 

“BART-Eligible” sources whose emissions are found to reasonably cause or contribute to visibility 

impairment at Class I areas are designated as “BART-Subject” units that must satisfy best available 

retrofit technology (BART) emission limitations. BART emission limitations are to be established at 

levels that reflect the degree of reduction achievable through application of the best system of 

continuous emission reduction for each visibility impairing pollutant 

Owners of BART-eligible units with modeled impacts below the NY “contribution” threshold of 0.1 

deciviews are exempt from requirements to apply BART limitations. Owners of units exceeding the 

impairment contribution threshold are required to submit BART control evaluations and control 

recommendations to the permitting authorities no later than October 1, 2010. 

International Paper secured the services of AECOM to conduct the required BART analyses for units 

at the Ticonderoga Mill. Analyses were conducted in accordance with NY BART regulations and the 

implementation guidelines (see Appendix C) and the procedures contained in the Final BART 

Guidelines published by the USEPA on July 6, 2005 (Federal Register Volume 70, No. 128). 

Consistent with the BART Guidelines, the five steps for a case-by-case BART analysis were followed: 

1. Step 1 – Identify all available control technologies for the affected units including 

improvements to existing control equipment or installation of new add-on control equipment. 

2. Step 2 – Eliminate technically infeasible options considering the commercial availability of the 

technology, space constraints, operating problems and reliability, and adverse side effects on 

the rest of the facility. 

3. Step 3 – Evaluate the control effectiveness of the remaining technologies based on current 

pollutant concentrations, flue gas properties and composition, control technology 

performance, and other factors. 
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4. Step 4 – Evaluate the annual and incremental costs of each feasible option in accordance 

with approved EPA methods, as well as the associated energy and non-air quality 

environmental impacts. 

5. Step 5 – Determine the visibility impairment associated with baseline emissions and the 

visibility improvements provided by the control technologies considered in the engineering 

analysis (Steps 1 – 4). 

The emission baseline period for this BART analysis is 2005-2009. 

1.1 Location of Source vs. Relevant Class I Areas 

Figure 1-1 shows the location of the Ticonderoga Mill relative to the seven Class I areas to be 

considered for BART visibility assessments in New York. The seven Class I areas are: 

1. Brigantine National Wildlife Refuge (NJ), located about 485 km from the Ticonderoga Mill; 

2. Lye Brook Wilderness Area (VT), located about 87 km from the Ticonderoga Mill; 

3. Presidential Range Dry River Wilderness (NH) , located about 164 km from the Ticonderoga 

Mill; 

4. Great Gulf Wilderness (NH), located about 171 km from the Ticonderoga Mill; 

5. Dolly Sods Wilderness Area (WV), located about 728 km from the Ticonderoga Mill; 

6. Otter Creek Wilderness Area (WV), located about 746 km from the Ticonderoga Mill; 

7. Acadia National Park (ME), located about 378 km from the Ticonderoga Mill. 

1.2 Organization of Report 

This report documents the case-by-case BART analysis conducted for SO2, NOx and PM10 emissions 

from the BART-subject units at the Ticonderoga Mill. Section 2 provides a description of Ticonderoga 

Mill’s BART-eligible units and their baseline emissions. Section 3 provides a discussion of SO2, NOx 

and PM control technologies. The available meteorological data and the CALPUFF modeling 

procedures are described in Sections 4 and 5, respectively. The results of the visibility modeling are 

presented in Section 6 along with recommendations and conclusions. References are listed in 

Section 7. 

 
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Figure 1-1: Location of the Class I Areas in Relation to the Ticonderoga Mill 
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2.0 Background Data 

2.1 Overview of BART-Eligible Emission Units 

BART-eligible emission units at the Ticonderoga Mill were identified by NYSDEC as being the Power 

Boiler, the Recovery Boiler, the Smelt Dissolving Tank, the Lime Kiln and miscellaneous PM 

emissions sources which include the Starch Silo and two Wood Chip Cyclones. Each of these 

emission units began operation in the 15-year time frame targeted by the BART regulations (1962-

1977). 

The Smelt Dissolving Tank, the Lime Kiln and the miscellaneous PM emission sources were 

determined through modeling to be exempt from any further BART analysis or control evaluation 

requirements based on modeling results showing that these units have less than 0.1 deciview impact 

(see Table 2-1) at any Class I area. 

Table 2-1: Visibility Impacts of the BART-Exempt Sources at the Mill 

Source Class I area Maximum dv Bext 

(1) 8th Highest dv Bext (1)

Lime Kiln Lye Brook 

Wilderness (2) 0.001 0.000 

Smelt Dissolving Tank 0.017 0.007 

Starch Silo/Chip 

Cyclones 

Great Gulf 

Wilderness (3) 0.008 0.003 

1. Deciview. A measurement of visibility impairment. A deciview is a haze index derived from calculated light extinction, 

such that uniform changes in haziness correspond to uniform incremental changes in perception across the entire 

range of conditions, from pristine to highly impaired. The deciview haze index is calculated based on the following 

equation (for the purposes of calculating deciview, the atmospheric light extinction coefficient must be calculated 

from aerosol measurements): 

 HI = 10 ln (b/10); 

 where b = the atmospheric light extinction coefficient, expressed in inverse megameters (Mm-1)”. 

 These values represent the changes in visibility from the 20% best natural background conditions. 

2. Results are presented for the Lye Brook Wilderness since the highest visibility impacts from the Lime Kiln and the 

Smelt Dissolving Tank occur at this Class I area. 

3. Results are presented for the Great Gulf Wilderness since the highest visibility impacts from the miscellaneous PM 

sources occur at this Class I area. 

The Power Boiler is currently permitted to burn No. 6 fuel oil, bark/wood, rejected digester wood knots, 

primary clarifier fiber, dried secondary biomass and waste fuel types “A” for the production of steam 

and electricity via a turbine generator. The Power Boiler also combusts the non-condensable gases 

(NCG) produced by the pulping and chemical recovery process. The fuel mix for the Power Boiler is 

typically approximately 20% wood/bark and ~80% residual oil on a heating value basis. The other 

fuels listed in the permit have not been fired or have been fired on a very limited basis over the last 

five years. 
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The Recovery Boiler is used to recover chemicals from spent pulping liquor and to produce steam for 

the mill. It consists of a low odor non-direct contact Kraft recovery furnace and a smelt dissolving tank. 

The Recovery Boiler at the mill processes black liquor solids (BLS) and fires No. 6 oil as an auxiliary 

fuel. 

 

2.2 Description of BART-Eligible Sources 

2.2.1 Power Boiler 

The Power Boiler is rated at 855 MMBtu/hr and is permitted to fire up to 450 wet tons per day of 

wood/bark with the remaining heat input from firing of low sulfur No.6 oil. It is equipped with advanced 

combustion controls including low NOx burners. Emissions of SO2 from the Power Boiler are currently 

controlled by an Entoleter wet-alkaline scrubber that was installed in 1996. Sodium hydroxide is 

injected into the scrubber recycle line to control SO2. The current permit limits for SO2 are 309 lb/hr as 

a 24-hr rolling average and 435 lb/hr as a 3-hour rolling average. Emissions of PM/PM10 from the 

Power Boiler are controlled by multicyclones and the dual purpose wet scrubber system. Filterable 

particulate emissions are limited by permit conditions to no more than 0.10 lb/MMBtu. NOx emissions 

from oil combustion are controlled using TODD Variflame Series 38 low NOx burners. Advanced 

combustion techniques are also employed to control NOx generated from the combustion of all fuel 

types. NOx emissions are limited by the permit to no more than 0.25 lb/MMBtu as a block daily 

average from May 1 through September 30 and 0.25 lb/MMBtu as a 30-day rolling average from 

October 1 through April 30. 

2.2.2 Recovery Boiler 

The Recovery Boiler is a Babcock and Wilcox straight fired, low odor, non-direct contact evaporation 

boiler that processes black liquor and may burn No. 6 oil (with a sulfur content of 1.5%) as an auxiliary 

fuel. No. 6 fuel oil use is restricted to less than 10% of the total fuel burned in the recovery boiler 

based on heat input. This unit is equipped with a three level staged combustion air supply system that 

reduces both NOx and total reduced sulfur (TRS) emissions and an electrostatic precipitator for 

control of PM emissions. Filterable particulate emissions from the Recovery Boiler are limited by the 

Subpart MM MACT standard to not more than 0.03 grains per dry standard cubic feet (gr/dscf) of 

exhaust gas at 8% O2. 

2.2.3 Smelt Dissolving Tank 

The sulfur and sodium chemicals recycled in the kraft process (smelt) flow from the bottom of the 

recovery boiler into the Smelt Dissolving Tank to form green liquor. The smelt is dissolved in water to 

form green liquor. It is then transferred to a recaustisizing tank where calcium oxide is added to 

convert the solution back to white liquor for return to the digester. Emissions from this unit are routed 

through a wet scrubber (∆P 6 – 9” water) with a demister. Filterable particulate emissions from the 

Smelt Dissolving Tank are limited by the Subpart MM MACT standard to not more than 0.15 gr/dscf at 

8% O2. 

2.2.4 Lime Kiln 

The Lime Kiln converts the lime mud to calcium oxide through a process called “calcining”. This unit is 

equipped with a venturi scrubber for control of PM emissions and total reduced sulfur emissions. NOx 

emissions from the Lime Kiln are permitted at 120 ppmv, wet, at 10% O2 based on NYSDEC’s NOx 
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RACT requirements. Filterable PM emissions from this unit are limited by the Subpart MM MACT 

standard to no more than 0.15 gr/dscf at 10% O2. 

2.2.5 Miscellaneous Sources 

The miscellaneous BART-eligible PM sources at the mill consist of a starch silo and two chip 

cyclones. The starch silo’s actual PM emissions are 6,832 lb/year whereas the two wood chip 

cyclones emit 19,803 lb PM/year. These PM emissions were obtained from the mill’s annual emission 

statements and are based on the material throughput rates for each miscellaneous source. 

2.3 Baseline Actual Emissions 

The highest daily emission rate, for each source, of SO2, NOx, and filterable PM emissions occurring 

between 2005 and the end of 2009 was identified from production records, monitoring data, and stack 

test reports, and used as the basis for the baseline modeling case for BART-eligible sources. This 

determination was made independently for each BART-eligible unit based on processing emissions 

records of only that unit. Maximum emissions are not necessarily expected to occur from all BARTeligible sources on the same day, and in fact downtime of one source may be the very reason for high 

production or emissions from another. This approach provides a conservative basis for determining if 

a BART-eligible unit, by itself causes or contributes to visibility degradation but does not necessarily 

allow informed decisions regarding the cumulative impact from all BART-eligible sources at the facility. 

Table 2-1 provides a summary of the SO2, NOx, and filterable PM emission rates used in the visibility 

modeling analysis of BART-eligible units. Table 2-2 provides the corresponding stack parameters that 

were used in the modeling analysis for baseline conditions. 

2.3.1 Power Boiler 

Baseline SO2 and NOx emissions from the Power Boiler were based on the maximum actual daily 

SO2 and NOx emission rates recorded by the CEMS during the period 2005-2009. The maximum 

daily NOx emission rate was found to occur on 12/26/2005 (during the non-ozone season). The 

baseline filterable PM emission rate was based on the maximum actual daily heat input rate of 16,762 

MMBtu/day (equivalent to daily average of 698.4 MMBtu/hr) and 0.068 lb/MMBtu (measured during a 

October 19, 2007 stack test). 

Since 80% or more of the heat input comes from No. 6 oil when the boiler is operated at the maximum 

baseline rates identified above, PM10 speciation was based on profiles for 100% oil firing. This 

assumption is conservative since oil firing results in higher visibility impacts, due to sulfate emissions, 

as compared to wood firing. Hence, speciation of the particulate matter emissions from the Power 

Boiler into filterable and condensable PM10 components was conducted using the following approach: 

 The total filterable PM emission rate was obtained from stack tests. 

 The filterable PM10 portion of the total filterable PM was calculated using the cumulative size 

distributions given in AP-42 Table 1.3-4 (uncontrolled size fractions). The total filterable PM10

is 71% of the filterable PM. The fine PM10 (i.e., PM2.5) was calculated as the 52% of total 

filterable PM. The coarse PM10 (particles with aerodynamic diameters between 10 m and 

2.5 m) was calculated as 19% of PM based on the difference between the total filterable 

PM10 and the fine PM10 (filterable PM2.5).
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 Elemental carbon or black carbon was estimated to be 7.4% of fine PM10 (PM2.5) based on 

the best estimates for industrial petroleum in Table 6 of “Catalog of Global Emissions 

Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, 

EPA Contract No. 68-D-98-046, January 2002. Fine soil is the difference between fine total 

and fine EC. 

 The condensable PM emission factor was based on AP-42 Table 1.3-2 (1.5 lb/1000 gal) for 

No.6 oil-fired boilers. All inorganic condensable PM10 was assumed to be sulfates (i.e. no soil 

component). 

2.3.2 Recovery Boiler 

The Recovery Boiler is equipped with two stacks (an old stack and a new stack). Baseline PM, SO2

and NOx emissions from this unit were based on the results of the stack tests conducted during the 

period 2005-2009. The total emissions from the Recovery Boiler were apportioned to each stack 

based on the flow measurements made during stack tests. 

Speciation of the particulate matter emissions from the non-direct contact Recovery Boiler into 

filterable and condensable PM10 components was conducted using the following approach: 

 The total filterable PM emission rate was obtained from stack tests. 

 For a non-direct contact evaporation furnace, as per AP-42 Table 10.2-3, 74.8% of filterable 

PM is PM10 for a recovery boiler. Coarse PM10 is 7.5% of total filterable PM10 and 67.3% of 

total filterable PM10 is fine PM10 (filterable PM2.5). 

 Elemental carbon or black carbon was estimated to be 7.4% of fine PM10 (PM2.5) based on 

the best estimates for industrial petroleum in Table 6 of “Catalog of Global Emissions 

Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, 

EPA Contract No. 68-D-98-046, January 2002. Fine soil is the difference between fine total 

PM10 and fine EC. 

 Condensable PM10 emission rates are based on NCASI emission factors (Particulate 

Emissions for Pulp and Paper Industry Specific Sources, February 9, 2006). This is a nondirect contact evaporation recovery furnace. The emissions factors are 0.53 lb/ton of BLS for 

CPM IOR and 0.104 lb/ton of BLS for CPM OR. Sulfates, based on ion chromatography, are 

34% of the CPM. 

2.3.3 Lime Kiln 

Baseline filterable PM, SO2 and NOx emissions from the Lime Kiln were based on the results of the 

stack tests conducted during the period 2005-2009. 

Speciation of the particulate matter emissions from the Lime Kiln into filterable and condensable PM10

components was conducted using the following approach: 

 The total filterable PM emission rate of the Lime Kiln was obtained from stack tests. 

 Total filterable PM is assumed to be equal to filterable PM10. Coarse PM10 emissions from the 

Lime Kiln are calculated as 98.3% of filterable PM10 based on AP-42 Table 10.2-4. Coarse 

PM10 is 2.3% of filterable PM and 96% of filterable PM is fine PM10 (filterable PM2.5). 

 There are no data on EC for this source type. PM10 emissions from smelt tanks and lime kilns 

are assumed to be all inorganic given the nature of the processes. Therefore, as a 
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conservative estimate, it is assumed that 2.5% of fine PM10 (1/3 of the percentage assumed 

for the recovery boilers) is EC. 

 Condensable PM10 emissions from Lime Kilns are based on NCASI emission factors 

(Particulate Emissions for Pulp and Paper Industry Specific Sources, February 9, 2006). The 

emissions factors are 0.0060 gr/dscf @10% O2 for inorganic CPM and 0.00030 gr/dscf @10% 

O2 for organic CPM. Sulfates, based on ion chromatography, are 21% of the inorganic CPM. 

Stack gas flow is calculated from the stack parameters assuming saturation and 10% O2 on a 

dry basis. 

2.3.4 Smelt Dissolving Tank 

Baseline PM and SO2 emissions from the Smelt Dissolving Tank were based on the results of the 

stack tests conducted during the period 2005-2009. Due to the nature of the process, this unit does 

not result in any NOx emissions. 

Speciation of the particulate matter emissions from the Smelt Dissolving Tank into filterable and 

condensable PM10 components was conducted using the following approach: 

 The total filterable PM emission rate of the Smelt Dissolving Tank was obtained from stack 

tests. 

 For a smelt dissolving tank, based on AP-42, Table 10.2-6, 88.5% of filterable PM is PM10, 

15.5% of filterable PM is coarse PM10, and 73.0% of filterable PM is fine PM10.There are no 

data on EC for this source type. PM10 emissions from smelt tanks and lime kilns are assumed 

to be all inorganic given the nature of the processes. Therefore, as a conservative estimate, 

it is assumed that 2.5% of fine PM10 (1/3 of the percentage assumed for the recovery boilers) 

is EC. 

 Condensable PM10 emissions from this unit are based on NCASI emission factors (Particulate 

Emissions for Pulp and Paper Industry Specific Sources, February 9, 2006). The emissions 

factors are 0.0192 lb/ton of BLS for inorganic CPM and 0.0044 lb/ton of BLS for organic CPM. 

Sulfates, based on ion chromatography, are 29% of the inorganic CPM. 

2.3.5 Miscellaneous Sources 

Miscellaneous material handling sources (starch silo and the two chip cyclones) are expected to have 

PM emissions only. The baseline PM emissions for these sources were based on the PM emission 

rates reported by the mill in its annual emission statement. Further, all PM is assumed to be PM10 and 

all PM10 is conservatively assumed to be fine PM10 (fine soil) for these sources. Based on their 

nature, these sources are not expected to emit EC or condensable PM10. 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga MIll 

Table 2-2: IP Ticonderoga Mill Baseline Emissions 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill 

Table 2-3: IP Ticonderoga Mill Baseline Stack Parameters 

EMISSION 

UNIT ID EMISSION UNIT DESCRIPTION 

Location in Lat/Long and 

Ground Elevation 

(ft) 

Stack 

Height 

from 

Ground 

(ft) 

Stack Exit 

Temperature

(F) 

V

(

00044 POWER BOILER 

43.8893 Lat., -73.3973 

Long 

 MSL=171 ft 

205 142 

00001 

RECOVERY BOILER, NON-DIRECT CONTACT EVAPORATION, OLD STACK 

43.8892 Lat., -73.3972 

Long 

MSL=170 ft 

205 407 

00103 

RECOVERY BOILER, NON-DIRECT CONTACT EVAPORATION, NEW STACK 

43.8895 Lat., -73.3970 

Long 

MSL=171 ft 

200 381 

00003 SMELT DISSOLVING TANK 

43.8891 Lat., -73.3975 

Long 

MSL=171 ft 

169 136 

00005 LIME KILN 

43.8879 Lat., -73.3963 

Long 

MSL=171 ft 

80 159 

--- 

OTHER MISCELLANEOUS SOURCES (Starch Silo and two Chip Cyclones) 

43.8874 Lat., -73.3963 

Long 

MSL=171 ft 

20 Ambient 
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3.0 Emission Control Alternatives for BART-Subject Sources 

As discussed previously, the Lime Kiln, the Smelt Dissolving Tank and the miscellaneous PM sources 

at the Ticonderoga Mill were found to have insignificant modeled impacts and were hence deemed to 

be exempt from BART requirements. This section discusses emission control alternatives for the two 

emission units determined to be subject to BART, the Power Boiler and the Recovery Boiler. 

 As discussed in greater detail below, emissions of both SO2 and NOx from the Power Boiler are 

currently well controlled with performance levels comparable to various benchmarks that have been 

previously used to define BART. Filterable PM emissions are also currently well controlled and 

expected to be reduced even further when the new Industrial Commercial Institutional (ICI) Boilers 

and Process Heaters MACT standard (40 CFR 63 Subpart DDDDD) becomes effective. 

For the Recovery Boiler, emission controls and operating practices currently in place satisfy BART 

requirements. As discussed in more detail below, there are no additional SO2 or NOx emission 

control technologies available to significantly improve performance levels currently being achieved. 

Filterable PM emissions from the Recovery Boiler currently meet BART requirements through 

compliance with the applicable MACT standard (40 CFR 63 Subpart MM). Section 3.1 presents 

emission control alternatives for the Power Boiler. The Recovery Boiler is discussed in Section 3.2. 

3.1 Power Boiler Emission Control Alternatives 

3.1.1 SO2 Emissions 

The fuel mix for the Power Boiler is typically 20% wood/bark and 80% residual oil (No. 6 fuel oil) on a 

heating value basis. Fuel sulfur for residual oil used at the IP Ticonderoga Mill is limited to a 

maximum concentration of 1.5%. Over the most recent 5 years, the actual fuel oil sulfur content has 

ranged from 0.81% to 1.48%. Before control, approximately 85% to 90% of the SO2 emissions are 

attributable to fuel oil combustion. 

Emissions of SO2 are controlled by an Entoleter wet-alkaline scrubber that was installed in 1996. 

Sodium hydroxide is injected into the scrubber recycle line to control SO2. The current permit limits for 

SO2 are 309 lb/hr as a 24-hr rolling average and 435 lb/hr as a 3-hour rolling average. The 24-hour 

average emission limit of 309 lb/hr is equivalent to 0.36 lb/MMBtu at the maximum rated capacity of 

855 MMBtu/hr and higher lb/MMBtu rates at lower operating loads. During the 2005 to 2009 period, 

the actual maximum 24-hr emission rate was 274 lb/hr. 

In general, the emission controls that might be available for this type of source are the combustion of 

natural gas or possibly lower sulfur fuel oil and/or wet or dry scrubbing. However, natural gas is not 

available for the IP Ticonderoga Mill because the distance to the nearest natural gas pipeline is 

approximately 70 miles. With regard to lower sulfur fuel oil and/or wet or dry scrubbing, the Power 

Boiler emissions and emission controls are already consistent with BART guidelines and policies as 

well as other available benchmarks as discussed below. In addition, as shown in Section 6, even if 

SO2 emissions were reduced, the resulting visibility improvements would not be significant. 
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NYSDEC policy is that the presumptive BART for residual oil fired utility boilers, with no add-on 

emission controls, is the use of fuel with no more than 1% S. For typical residual fuel oil, 1% S results 

in an SO2 emission rate of 1.05 lb/MMBtu. This policy would define BART for an oil fired utility boiler 

operating at 855 MMBtu/hr as an SO2 emission rate of 900 lb/hr as a 24-hr average. The current 

maximum permitted emission rate for IP’s Power Boiler is currently 309 lb/hr as a 24-hr average, 

which is well below NYSDEC’s presumptive BART emission rate for a similarly sized residual oil-fired 

utility boiler. Even at low loads, the SO2 emissions from IP’s Power Boiler are at or below the 

emission rate that would be achieved if 1% S oil was burned without emission controls. 

MANE-VU’s BART Workgroup Recommendations for presumptive SO2 control levels for industrial 

boilers list 90% control, compliance with the ICI Boiler MACT acid gas control level, or 0.55 lb/MMBtu 

(0.5% fuel sulfur limit).1

 IP will meet these presumptive BART requirements by complying with the ICI 

Boiler MACT acid gas control requirements when these are finalized. The 0.55 lb/MMBtu emission 

rate would result in SO2 emissions of 470 lb/hr at the Power Boiler’s maximum rating of 855 

MMBtu/hr. IP’s current permit limit of 309 lb/hr as a 24-hr average is well below the 470 lb/hr MANEVU presumptive BART guidance. 

The most stringent, relevant SO2 emission requirements in current NYSDEC rules is the Subpart 225-

1 limitations for residual fuel oil in New York City (0.3% S) and Nassau, Rockland, and Westchester 

Counties (0.37%S). These fuel sulfur limits are equivalent to 0.314 lb/MMBtu and 0.387 lb/MMBtu, 

respectively. At IP’s Power Boiler’s maximum rating of 855 MMBtu/hr these emission rates would 

result in SO2 emissions of 268 lb/hr to 331 lb/hr. The higher emission rate is above IP’s currently 

permitted emissions while lower emission rate is slightly below IP’s current permit limit. However, as 

shown in Section 6 of this report, the lower emission rate would result in an insignificant modeled 

visibility improvement of only 0.02 deciviews. 

The Federal New Source Performance Standard for industrial oil fired boilers built after February 28, 

2005 is 0.20 lb/MMBtu (40 CFR 60 Subpart Db). At IP’s Power Boiler’s maximum rating of 855 

MMBtu/hr this emission rate would result in SO2 emissions of 171 lb/hr which is lower than IP’s 

currently permitted emission rate (which is 309 lb/hr as a 24-hr average). However, as shown in 

Section 6 of this report, the lower emission rate would result in an insignificant modeled visibility 

improvement of only 0.07 deciviews. 

Table 3-1 summarizes the above guidance and benchmarks for SO2 emissions. The Power Boiler 

SO2 emissions are already well controlled and are within the range of the guidelines and benchmarks 

shown in Table 3-1. In addition, as shown in Section 6, the visibility benefits associated with reducing 

SO2 emissions to the lower benchmark levels are not significant. Therefore, the current SO2 emission 

limit of 309 lb/hr as a 24-hr rolling average and future compliance with the ICI Boiler MACT acid gas 

standard represent BART for IP’s Power Boiler. 

 

1

 Five-Factor Analysis of BART-Eligible Sources, prepared by NESCAUM for the MANE-VU Regional Planning 

Organization, June 1, 2007. 
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Table 3-1: Comparison of Power Boiler SO2 Emissions to Guidelines and Benchmarks 

Case Basis for SO2

Emissions 

SO2 Emissions 

No. Description lb/hr as 24-hr average 

 Base Case 

Base Baseline Actual with Wet Scrubbing Wet Scrubbing 274 

 SO2 Benchmark Cases at Maximum Design Capacity, 855 MMBtu/hr 

1 Current Allowable SO2 Case with Wet 

Scrubbing Wet Scrubbing 309 

2 MANE-VU Presumptive BART for 

Industrial Boilers, 0.55 lb/MMBtu 0.55 lb/MMBtu 470 

3 NYSDEC limit for Nassau, Rockland 

and Westchester counties, 0.37 % S 0.387 lb/MMBtu 331 

4* NYSDEC limit for New York City, 0.30 

% S 0.314 lb/MMBtu 257 

5* 

NSPS (40 CFR 60 Subpart Db) for 

industrial oil-fired boilers built after 

February 2005 

0.20 lb/MMBtu 171 

*Visibility modeling showed that SO2 benchmark cases 4 and 5 resulted in insignificant visibility 

improvements. 

3.1.2 NOx Emissions 

The fuel mix for the Power Boiler is typically 20% wood/bark and 80% residual oil on a heating value 

basis. NOx emissions are controlled using advanced combustion controls including TODD Variflame 

Series 38 low NOx burners for firing oil. The TODD burners limit NOx emissions by reducing the 

flame temperature and lowering the effective oxygen concentration. 

Primary and secondary air enters the burner from the windbox through an annular air gap. The air 

gap is designed to accelerate the primary and secondary air without flow disturbances from the lower 

velocity in the windbox. The air then turns 90 degrees and is further accelerated through a venturi. 

Near the exit of the venturi, the air splits into two distinct concentric streams. The primary air passes 

through a swirler while the secondary air passes outside the periphery of the swirler. 

The outward spin provided to the primary air, and to any combustion products formed in the vortex 

region, results in a low pressure region immediately in front of the swirler. Consequently, a portion of 

the combustion gases spinning outward from the swirler, along with a portion of the gases in the 

secondary air region, are drawn from a region several feet in front of the swirler. The gases are then 

recirculated back into this low pressure region. This “recirculation” of flue gases back into the area in 

front of the swirler provides flame stabilization and helps to reduce NOx emissions in the primary 
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combustion zone by reducing the flame temperature and lowering the “effective” oxygen 

concentration. 

The currently installed NOx emission controls limit NOx emissions to 0.25 lb/MMBtu. Maximum 

baseline emissions during the 2005 to 2009 period were 178 lb/hr as a 24-hr average. At the 

maximum design heat input of 855 MMBtu/hr, maximum permitted NOx emissions are 214 lb/hr. 

EPA’s study regarding the cost-effectiveness of NOx retrofit controls to oil-fired units was inconclusive. 

While advanced combustion controls were cost-effective for some units, there were several facilities 

for which NOx retrofit controls proved to be too expensive. Therefore, EPA decided not to issue a 

presumptive BART limit for oil-fired boilers (Federal Register, Vol. 70, No. 128, Page 39136, July 6, 

2005). EPA’s analysis indicates that they anticipated that BART emission control options for oil fired 

boilers would be limited to combustion controls. The IP Power Boiler currently uses modern 

combustion controls to limit NOx emissions. 

The Federal New Source Performance Standard for industrial oil fired boilers built after February 28, 

2005 is 0.20 lb/MMBtu (40 CFR 60 Subpart Db). At IP’s Power Boiler’s maximum rating of 855 

MMBtu/hr this emission rate would result in NOx emissions of 171 lb/hr which is lower than IP’s 

current maximum emission rate which is 214 lb/hr as a 24-hr average. However, as shown in Section 

6 of this report, if this lower emission rate could be achieved, it would result in insignificant modeled 

maximum and eighth highest visibility improvements of only 0.08 to 0.09 deciviews and 0.03 to 0.04 

deciviews, respectively. 

In lieu of site specific, case-by-case RACT analysis, new (2010) NYSDEC presumptive RACT 

requirement for oil fired industrial power boilers is a NOx emission rate of 0.15 lb/MMBtu. At IP’s 

Power Boiler’s maximum rating of 855 MMBtu/hr this emission rate would result in NOx emissions of 

128 lb/hr which is lower than IP’s current maximum permitted emission rate (which is 0.25 lbs/MMBtu 

as a 24-hr block daily average, equivalent to 214 lb/hr). As shown in Section 6 of this report, if this 

lower emission rate could be achieved, it would result in small modeled maximum and eighth highest 

visibility improvements of only 0.17 to 0.18 deciviews and 0.07deciviews, respectively. The NYSDEC 

NOx RACT rule allows emissions higher than the presumptive RACT requirement if the presumptive 

limit cannot be achieved or if it cannot be achieved in a cost effective manner. IP will be submitting a 

NOx RACT compliance plan, in accordance with the state regulation, by January 1, 2012. 

Table 3-2 summarizes the guidance and benchmarks for NOx emissions. The Power Boiler NOx 

emissions are already well controlled using advanced combustion controls including low NOx burners. 

In addition, as shown in Section 6, the visibility benefits associated with reducing NOx emissions are 

very small. Therefore, the current maximum NOx emission rate of 0.25 lb/MMBtu and future 

compliance with NYSDEC’s NOx RACT rule are proposed as BART for NOx emissions from the 

Power Boiler. 
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Table 3-2: Comparison of Power Boiler NOx Emissions to Guidelines and Benchmarks 

Case 

Basis for NOx 

Emissions 

NOx Emissions 

No. Description lb/hr as 24-hr 

average 

 Base Case 

Base 

Current Baseline NOx Case with advanced 

combustion controls including TODD low NOx 

burners 

Maximum actual 

daily emissions 178 

 NOx Benchmark Cases at Maximum Design Capacity, 855 MMBtu/hr 

1 

Current Allowable NOx Case with advanced 

combustion controls including TODD low NOx 

burners, 0.25 lb/MMBtu 

0.25 lb/MMBtu 214 

2* 

NSPS (40 CFR 60 Subpart Db) for industrial 

oil-fired boilers built after February 2005, 0.20 

lb/MMBtu 

0.20 lb/MMBtu 171 

3* Future NYSDEC Presumptive RACT, 0.15 

lb/MMBtu 0.15 lb/MMBtu 128 

*Visibility modeling showed that NOx benchmark cases 2 and 3 resulted in only small visibility 

improvements. 

3.1.3 Filterable PM Emissions 

Filterable PM emissions from the Power Boiler are controlled by a multicyclone and an Entoleter wetalkaline scrubber that was installed in 1996. Filterable PM emissions are limited to 0.10 lb/MMBtu. 

Additional PM reductions are expected to be required to meet new MACT standards. The proposed 

Industrial Commercial Institutional Boilers and Process Heaters MACT standard (40 CFR 63 Subpart 

DDDDD) that would apply to the Power Boiler is 0.02 lb/MMBtu. EPA’s analysis in the Federal EPA 

BART Guidelines states that “....you may rely upon MACT standards for purposes of BART.” (Federal 

Register, Vol. 70, No. 128, Page 39164, July 6, 2005). For compliance with the BART rule, IP will 

comply with the ICI Boiler MACT standard for PM emissions when it is finalized. 

3.2 Recovery Boiler 

A recovery boiler is used to recover pulping chemicals, evaporate residual moisture from the black 

liquor solids, and burn the organic constituents to produce steam. The IP Recovery Boiler processes 

black liquor and uses No. 6 oil as an auxiliary fuel. This unit is currently equipped with a three level 

staged combustion air control system with ESPs. 

3.2.1 SO2 Emission Controls 

In general, black liquor contains a significant amount of sulfur, nominally 3% to 5% by weight of the 

dissolved solids. SO2 emissions from recovery boilers occur due to the volatilization and subsequent 
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oxidation of sulfur compounds present in black liquor and the occasional use of auxiliary fuel (in this 

case No. 6 oil). Unlike conventional steam boilers, the vast majority of sulfur that is present in the 

liquor is not converted to SO2, since the primary objective is to recover and re-use the sulfur. Proper 

operation of the recovery boiler maximizes the conversion of sulfur compounds in the liquor to the 

principal constituents of pulping chemicals through capture of these compounds in the combustion 

zone of the boiler by sodium fume released from the smelt bed. Consequently proper operation of the 

recovery boiler itself results in inherent control of SO2 emissions. Moreover, the Recovery Boiler at 

the Ticonderoga Mill is a non-direct evaporation recovery furnace which, due to its design 

characteristics, inherently results in low SO2 emissions. 

The available retrofit technologies for control of SO2 from Kraft mill Recovery Boilers are: 

 Staged Combustion Systems 

 Wet Scrubbers 

The IP Recovery Boiler is currently equipped with a two-level staged combustion air control system 

which provides control over the boiler operating parameters that minimize SO2 emissions. 

The only available alternative to proper recovery boiler operation with a staged combustion air system 

for SO2 control is the addition of a wet scrubbing device downstream of the existing ESP. Dry 

scrubbing techniques, which seek to remove SO2 via direct injection of solid lime or limestone directly 

into the recovery boiler flue gas, are not technically feasible for recovery boilers. The reaction 

products from dry scrubbing (calcium sulfate and other calcium-based salts) would necessarily need 

to be collected in the PM control system (ESP), and thereby would contaminate the sodium sulfate 

(salt cake) that the ESP collects and recycles back to the pulping process. 

Only three recovery boilers in the U.S. are equipped with wet scrubbers in addition to ESPs. 

However, none of these scrubbers were installed to achieve SO2 removal: two of the units were 

installed for heat recovery reasons, and the third was installed on a unit that is equipped with a direct 

contact evaporator to prevent liquid droplets from being entrained and discharged to the atmosphere. 

Furthermore, the inherent SO2 control provided via proper operation of a recovery boiler results in a 

much lower SO2 concentration in recovery boiler flue gas than in the flue gas of emission units to 

which wet scrubbers are routinely applied (such as fossil fuel-fired steam generating units). The 

NCASI retrofit control technology assessment in Appendix B provides further details. 

Therefore, BART for SO2 emissions from the Recovery Boiler is the currently installed three-level 

staged combustion air control system with ESPs. 

3.2.2 NOX Emission Controls 

NOX emissions generally result from fuel NOX and thermal NOX. However, NOX formation in recovery 

boilers is believed to be primarily from fuel NOX because the temperatures in the combustion zone of 

the boiler are not high enough for significant thermal NOX formation. Fuel NOX emissions from 

recovery furnaces are typically low due to the low nitrogen content of black liquor solids. In addition, 

the Recovery Boiler operates as a staged combustion boiler with independently operating primary, 

secondary and tertiary air dampers. Total air and the distribution between the air stages can be 

adjusted to control the Kraft recovery sodium sulfite reactions, to assure complete combustion of 

organic compounds, and to control TRS, CO and NOX. 
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The available retrofit technologies for control of NOX from combustion sources are generally 

considered to be: 

 Staged Combustion Systems 

 SNCR 

 SCR 

 Low NOX burners 

 Flue Gas Recirculation 

Recovery boilers are complex systems, specifically designed for chemical recovery, that can not apply 

the types of NOX emission controls used on typical coal, oil, and natural gas fired boilers such as low 

NOX burner, flue gas recirculation, selective non-catalytic reduction, and selective catalytic reduction. 

Low NOX burners, which use staged combustion, have not been demonstrated on recovery boilers. 

Black liquor has a large percentage of water that requires specifically designed black liquor burner 

guns that provide long droplet trajectories for drying (see the NCASI retrofit control technology 

assessment in Appendix B). 

Flue gas recirculation is a technology used to control thermal NOX by reducing combustion 

temperatures. However, NOX emissions from recovery furnaces are a result of fuel NOX oxidation. 

Therefore, flue gas recirculation is not technically feasible for recovery furnaces. 

Selective non-catalytic reduction has not been demonstrated on recovery boilers. There are concerns 

that long term injection of ammonia or urea in a recovery furnace may adversely affect the chemical 

recovery process. In addition, large variations in gas temperatures due to fluctuating loads and black 

liquor quality would adversely affect the performance of selective non-catalytic reduction. Ammonia 

slip and increased plume opacity are also issues. 

Selective catalytic reduction is not technically feasible due to high particulate concentrations in the 

economizer region and catalyst poisoning by alkali metals such as sodium. 

In summary, there are no technically-feasible alternatives for control of NOX emissions from recovery 

boilers other than the controls that are currently in place. In particular, emission controls which have 

been demonstrated on conventional steam boilers (including low NOX burner, flue gas recirculation, 

selective non-catalytic reduction, and selective catalytic reduction) cannot be applied to or have not 

been demonstrated to be feasible on a recovery boiler. 

Therefore, BART for NOX emissions from IP’s Recovery Boiler is the currently installed three-level 

staged combustion air control system with ESPs. 

3.2.3 PM Emission Control 

Particulate matter emissions from the Recovery Boiler are currently controlled using a three-chamber 

electrostatic precipitator. 

The available retrofit technologies for control of particulate matter from Kraft mill Recovery Boilers are: 

 Electrostatic Precipitators 

 Wet Scrubbers 
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 Fabric Filters 

Recovery boilers are designed and operated so that sodium fume released from the smelt bed is 

present in the combustion chamber in order to capture the SO2 that is generated as a result of 

oxidation of the reduced sulfur compounds in black liquor. As a consequence, recovery boilers emit 

relatively low levels of SO2 emissions, but have higher levels of uncontrolled PM emissions. 

Nonetheless, economical operation of the chemical recovery cycle in the Kraft pulping process 

requires that the vast majority of this uncontrolled PM be captured in a control device and the 

collected sodium salts (primarily sodium sulfate) be returned to the process. 

Electrostatic precipitation is the only type of PM control technology used on modern recovery boilers 

at Kraft pulp mills. At one time prior to the promulgation of New Source Performance Standards for 

Kraft pulp mills, recovery boilers utilized venturi scrubbers for PM emissions control. However 

because ESPs are capable of a greater degree of emissions control at a lower operating cost, venturi 

scrubbers are no longer utilized. 

Fabric filters have been utilized on conventional coal-fired steam generating units and are generally 

considered to be equivalent to ESPs on these types of sources in terms of PM control efficiency. 

However, they have not been applied to recovery boilers at Kraft pulp mills and are thus not 

considered to be an available BART alternative. 

EPA’s analysis in the Federal EPA BART Guidelines states that “....you may rely upon MACT 

standards for purposes of BART.” (Federal Register, Vol. 70, No. 128, Page 39164, July 6, 2005). 

The IP Recovery Boiler currently complies with Chemical Recovery MACT standard (40 CFR 63, 

Subpart MM). Therefore, current PM emissions meet BART requirements and no additional controls 

are required. 
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4.0 Meteorological Data used in Visibility Improvement 

Modeling 

NYDEC requires that the meteorological data used for the BART visibility modeling be for calendar 

year 2002. The agency also requires that two different meteorological CALMET databases be used in 

the analysis, one developed by AECOM and the other developed by the Vermont Department of 

Environmental Conservation (VT DEC). The AECOM CALMET database is fully described in a 

separate document titled “Updated CALMET Modeling Procedures for BART Visibility Improvement 

Assessments in the MANE-VU RPO”. The VT DEC CALMET database is described in Appendix D of 

the document titled “Development of Parallel CALPUFF Dispersion Modeling Platforms for Sulfate 

Source Attribution Studies in the Northeast U.)”, available on the web at 

http://www.nescaum.org/documents/contributions-to-regional-haze-in-the-northeast-and-mid-atlantic--

united-states/. 

This section discusses the two meteorological CALMET databases for year 2002 and the basic 

differences between the two. A primary difference between the two is the grid size resolution as 

shown in Figure 4-1. The VT DEC has a domain that covers approximately a 2,664 km (east-west) by 

2,160 km (north-south) area with a 36-km grid resolution. In contrast, the AECOM domain covers an 

area approximately 1,052 km (east-west) by 1,300 km (north-south), has a grid resolution of 4 km and 

contains 11 vertical levels. The similarities and differences in the two databases are summarized in 

Table 4-1. 
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Table 4-1: Comparison of the AECOM and VT DEC CALMET User-Defined Settings 

Variable Description 

AECOM 

CALMET Critical 

Settings 

VT DEC 

CALMET Critical 

Settings 

Version No. CALMET model version number Version 5.8, Level 

070623 

Version 5.53 , Level 

030709 

MREG Technical options must conform to 

USEPA guidance 1 no 

DGRIDKM Domain grid spacing 4 36 

NX Number of X grid cells 263 74 

NY Number of Y grid cells 325 60 

NZ Number of vertical layers 11 8 

IPROG Use MM5 data as an input to diagnostic 

wind field 14 (MM5 used) 0 (MM5 not used) 

RMAX1 Max surface over-land extrapolation 

radius (km) 40 1000 

RMAX2 Max aloft over-land extrapolation radius 

(km) 40 1000 

RMAX3 Maximum over-water extrapolation 

radius (km) 100 1000 

TERRAD Radius of influence of terrain features 

(km) 15 100 

R1 Relative weight at surface of Step 1 field 

and obs 5 1000 

R2 Relative weight aloft of Step 1 field and 

obs 5 1000 
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Figure 4-1: IP Ticonderoga CALMET Modeling Domains 
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5.0 CALPUFF Modeling Procedures 

This section provides a summary of the modeling procedures that were used for the refined CALPUFF 

analysis conducted for IP’s Ticonderoga Mill. 

5.1 CALPUFF Modeling Domain and Receptors 

AECOM used the latest EPA-approved version of CALPUFF (Version 5.8, Level 070623) with both 

meteorological databases as discussed in Section 4. 

The extent of the AECOM and VT DEC modeling domains are shown in Figure 4-1. The CALPUFF 

modeling domains were made equal in size to the CALMET domain (as described in Section 4.1) and 

they have sufficient buffer around the source and Class I areas to account for puff re-circulations. 

The receptors used for each of the Class I areas are based on the National Park Service database of 

Class I receptors, available at http://www.nature.nps.gov/air/maps/Receptors/index.cfm. 

5.2 Model Version 

The EPA-approved version of CALPUFF was used to model the IP BART sources, POSTUTIL was 

used to combine impacts from all three units and CALPOST was used to process the regional haze 

impacts with Method 8 (New IMPROVE equation). CALPUFF Version 5.8, Level 070623; POSTUTIL 

Version 1.56, Level 070627; and CALPOST Version 6.221, Level 080724 were used. 

These programs are available for download from TRC website 

http://www.src.com/calpuff/calpuff1.htm. 

5.3 Background Air Quality Data 

CALPUFF modeling was conducted with the hourly background ozone data that was developed for 

MANE-VU BART modeling. Ozone data collection and processing is described in Appendix D, 

Section D.3.3.1 of the NESCAUM document titled “Development of Parallel CALPUFF Dispersion 

Modeling Platforms for Sulfate Source Attribution Studies in the Northeast U.S”. 

As for ammonia, AECOM followed the IWAQM Phase 2 report, where it is suggested to use a 

background ammonia concentration of 0.5 ppb in forested areas. Since most Class I areas and the 

surrounding region are mainly covered by forest, an ammonia concentration of 0.5 ppb was used in 

accordance with the recommendations in IWAQM Phase 2. 

5.4 Light Extinction and Haze Impact Calculations 

The FLAG 2008 document (dated June 26, 2008) provides guidance on the recommended new 

IMPROVE equation application. CALPOST Version 6.221 defines this application as Method 8, Mode 

5. The assessment of visibility impacts at the Class I areas used CALPOST Method 8. 

The CALPOST postprocessor was used for the calculation of the impact of the modeled source’s 

primary and secondary particulate matter concentrations on light extinction. In the new IMPROVE 

equation, the total sulfate, nitrate, and organic carbon compound concentrations are each split into 

two fractions, representing small and large size distributions of those components. New terms, such 
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as sea salt (important for coastal locations), absorption by NO2 (only used where NO2 data are 

available), and site-specific Rayleigh scattering have been added to the equation. The new 

IMPROVE equation for calculating light extinction is shown below. 

The FLAG 2008 document provides inputs to the new IMPROVE equation that are based on either 

the 20% best or annual average natural conditions. Per NYSDEC guidance, AECOM elected to use 

inputs that are based on the 20% best natural conditions. Inputs to the CALPOST Method 8 

calculations for each Class I area were obtained from the FLAG 2008 document tables referenced 

below. 

Table 5-1: References to the New IMPROVE Equation CALPOST Inputs 

Sea salt concentration FLAG 2008 Table V.1-1 

Raleigh scattering FLAG 2008 Table V.1-1 

Monthly fL (RH) FLAG 2008 Table V.1-3 

Monthly fS (RH) FLAG 2008 Table V.1-4 

Monthly fSS (RH) FLAG 2008 Table V.1-5 
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Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

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6.0 CALPUFF Modeling and BART Determination Results 

This section provides a summary of the modeled visibility impacts due to the current baseline 

emissions as well as visibility improvements that might result from lower SO2 and NOx emissions from 

the Power Boiler. This section also presents the recommended BART determination. 

6.1 Exemption Modeling 

Baseline emissions of the haze-causing pollutants were modeled using CALPUFF to determine if 

emissions from a given source at the Mill could reasonably be anticipated to cause or contribute to 

visibility impairment at one or more of the seven Class I areas in northeastern U.S.A. Table 6-1 

presents the results of this exemption modeling. As shown in Table 6-1, the visibility impacts from the 

Lime Kiln, the Smelt Dissolving Tank and the miscellaneous PM sources are less than 0.1 dv. 

Therefore, these sources are exempt from BART analysis. 

Table 6-1: Exemption Modeling of BART-Eligible Sources at the Mill 

Reasonably 

Anticipated to Cause 

or Contribute to 

Modeled Impact 

Compared to Natural 

Background Visibility

 

BARTEligible 

Emission 

Unit 

Cause 

(>1.0 dv) 

Contribute 

(>0.1 dv) 

8th highest 

impact (dv) 

Maximum 

single day 

impact (dv) 

Impacted 

Class I 

Areas (1)

Subject 

to 

BART 

Power 

Boiler No Yes 0.341 0.635 ANP, GGW, 

PRDRW, 

LBW

Yes 

Recovery 

Boiler 

No Yes 0.163 0.282 LBW Yes 

Lime Kiln (2) No No 0.000 0.001 None No 

Smelt 

Dissolving 

Tank (2)

No No 0.007 0.017 None No 

Starch Silo, 

Chip Bin 

Cyclones (2)

No No 0.003 0.008 None No 

(1) Class I areas: ANP – Acadia National Park, GGW – Great Gulf Wilderness, PRDRW – Presidential Range Dry 

River Wilderness, LBW – Lye Brook Wilderness 

(2) Impacts presented for the Lye Brook Wilderness (most heavily affected Class I area) 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

6-2

6.2 Modeled Control Scenarios 

Baseline emissions from the Power Boiler and alternative SO2 and NOx guideline and benchmark 

emission rates outlined in Tables 2-2, Table 3-1 and Table 3-2 were modeled using CALPUFF. 

Visibility impacts at each of the seven Class I areas are presented in Table 6-2 from each of the 

BART-eligible emission units at the Ticonderoga Mill. Reported impacts are the changes in visibility 

attributed to the Ticonderoga Mill emission sources as compared to natural background conditions on 

the days with most favorable visibility conditions (i.e., 20% best days for visibility). Table 6-2 also lists 

the number of days that the modeled impact from a source is predicted to be above 0.1, 0.5 and 1.0 

deciview. 

The following factors should be considered when evaluating CALPUFF visibility modeling results. 

Baseline modeling analysis always uses the worst-case emission rate from each BART-eligible unit 

and assumes it occurs every day of the simulated year. Actual emissions are always lower which 

means that the degree of visibility improvement predicted from any control action will always be 

overestimated. The manner in which the daily haze predictions are accounted for in the CALPOST 

output overstates the impact for even a perfect model. The only information saved in CALPOST for 

each day is the peak 24-hour prediction anywhere in a Class I area. The predicted impact for each 

day is effectively assumed to be a) always in the same place and b) in all portions of the Class I area 

simultaneously. In reality, for each individual receptor, there could be many days of very low or even 

zero concentrations that are not properly accounted for. Therefore, the 98th percentile day’s prediction 

is often comprised of impacts in 8 different places that are all assumed to be co-located. CALPUFF 

does not account for the full cycle of diurnal influences that affect plume transport and dispersion. 

Finally, the visibility impact associated with nitrates is generally believed to be overstated by 

CALPUFF, especially in winter. 

NYSDEC recommends that the maximum visibility impact from each source should be compared to 

the threshold of 0.1 deciviews to determine if a source significantly contributes to visibility impairment. 

NYSDEC also recommends using the maximum and 98th-percentile statistic for comparing visibility 

improvements due to BART control options. On an annual basis, the 98th percentile value implies the 

8th highest day at each modeled Class I area. 

6.3 Modeling Results for Baseline Emissions 

CALPUFF modeling results of the baseline emissions at the seven Class I areas are presented in 

Table 6-2. Modeling was conducted with the two CALMET databases for the year 2002. The highest 

visibility impacts from the Mill’s sources occur at the Lye Brook Wilderness due to its close proximity to 

the Mill. 

The results of the baseline emissions analysis indicate that only the Power Boiler and Recovery Boiler 

have predicted visibility changes relative to natural background exceeding 0.1 deciviews in at least 

one Class I area. Therefore, all other sources at the IP Ticonderoga Mill are exempt from BART, in 

accordance with NYSDEC policy (see Appendix C), because emissions from these other sources may 

reasonably be anticipated to not cause or contribute to visibility impairment at a nearby Class I area. 

The results of the visibility improvement modeling for the benchmark emission levels, which were 

discussed in Section 3, are discussed in the next section. 
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Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

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Table 6-2: Regional Haze Impacts due to Baseline Emissions 

 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

6-4

6.4 Modeling Results for Power Boiler Guideline and Benchmark Emission 

Rates 

The Power Boiler’s maximum daily visibility impacts are predicted to occur at the Lye Brook 

Wilderness Area. Therefore, the maximum potential visibility changes associated with the guideline 

and benchmark emission rates discussed in Section 3 were evaluated at Lye Brook Wilderness Area. 

Consistent with the baseline results reported in Table 6-2, modeling was conducted with the two 

CALMET databases for the calendar year 2002. Per NYSDEC recommendation, in addition to the 

highest visibility impacts, the 8th highest delta-deciview results were also reported. 

Table 6-3 summarizes the modeling results at the Lye Brook Wilderness Area for the SO2 guidelines 

and benchmark emission rates for the Power Boiler. The results show that current SO2 emissions 

from the Power Boiler, which are controlled by wet scrubbing, are comparable to the cited benchmark 

emission rates and that the modeled visibility improvements associated with the lower emission rates 

are not significant. Even if the most stringent emission rate could be achieved, the number of days 

with visibility impacts greater than 0.5 deciviews would only be reduced by 1 day. In addition, 

reduction in the modeled maximum impact would only be reduced by approximately 0.05 deciviews 

and the eighth highest impact would only be reduced by about 0.03 deciviews. 

Table 6-3: Regional Haze Impacts for SO2 Emission Guidelines and Benchmarks for IP's Power Boiler 

Table 6-4 summarizes the modeling results at the Lye Brook Wilderness Area for the NOx guidelines 

and benchmark emission rates for the Power Boiler. The results show that the advanced combustion 

controls including low NOx burners effectively limits visibility impacts due to NOx emissions. If the 

NOx emission rate could be reduced to 0.20 lb/MMBtu, the number of days with modeled visibility 

impacts greater than 0.5 deciviews would only be reduced by about 1 day. In addition, reduction in 

the modeled maximum impact would only be reduced by 0.08 to 0.09 deciviews and the 8th highest 

impact would only be reduced by 0.03 to 0.04 deciviews. At the most stringent NOx emission rate of 

0.15 lb/MMBtu, the number of days with modeled visibility impacts greater than 0.5 deciviews would 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

6-5

only be reduced by no more than 4 days. In addition, reduction in the modeled maximum impact 

would only be reduced by 0.17 to 0.18 deciviews and the eighth highest impact would only be reduced 

by 0.07 deciviews.

Table 6-3: Regional Haze Impacts for NOx Emission Guidelines and Benchmarks for IP's Power Boiler 

6.5 Conclusions and BART Recommendation 

Baseline modeling results show that only the Power Boiler and the Recovery Boiler are subject to 

BART. The Lime Kiln, Smelt Dissolving Tank, and other sources are exempt from BART because 

their maximum visibility impacts are less than 0.1 deciviews. 

IP’s proposed BART determination for SO2 emissions from the Power Boiler is the use of wet 

scrubbing to comply with the current emission limit of 309 lb/hr as a 24-hour rolling average. For NOx, 

the proposed BART determination is the use of advanced combustion controls including low NOx 

burners to limit emissions to 0.25 lb/MMBtu as a block 24-hour average from May 1 through 

September 30 and as a 30-day average from October 1 through April 30. In addition, IP will comply 

with NYSDEC’s revised NOx RACT rule which goes into effect July 1, 2014. For PM emissions, 

BART is compliance with the proposed Industrial, Commercial, Institutional Boiler MACT standard. 

Emissions from the Recovery Boiler are currently well controlled. No additional controls are available 

for SO2 and NOx emissions. PM emissions comply with the Subpart MM MACT standard. The 

current permit limits are proposed as BART for the Recovery Boiler. 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

7-1

7.0 References 

ENSR, Updated CALMET Modeling Procedures for BART Visibility Improvement Assessments in the 

MANE-VU RPO. April 2009. 

ERM, Development of Parallel CALPUFF Dispersion Modeling Platforms for Sulfate Source Attribution 

Studies in the Northeast U.S (Appendix D), ERM, May 2006. 

Environmental Protection Agency (EPA), AP 42, Fifth Edition, Compilation of Air Pollutant Emission 

Factors, Volume 1: Stationary Point and Area Sources, January, 1995. 

Environmental Protection Agency (EPA), Guidance for Tracking Progress Under the Regional Haze 

Rule, EPA-454/B-03-003, Appendix A, Table A-3, September, 2003a. 

Environmental Protection Agency (EPA), Guidance for Estimating Natural Visibility Conditions Under 

the Regional Haze Program, EPA 454/B-03-005, September 2003b. 

Environmental Protection Agency (EPA), Interagency Workgroup on Air Quality Modeling (IWAQM) 

Phase 2 Summary Report and Recommendations for Modeling Long Range Transport Impacts, EPA454/R-98-019, December, 1998. 

National Council for Air and Stream Improvement (NCASI), Particulate Emissions Data for Pulp and 

Paper Industry Specific Sources, February 9, 2006. 

National Council for Air and Stream Improvement (NCASI), Information on Retrofit Control Measures 

for Kraft Pulp Mill Sources and Boilers for NOx, SO2 and PM Emissions, June 9, 2006. 

Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations; Final Rule (FR Vol. 70, No. 128 published July 6, 2005). 

Regional Haze Regulations; Revisions to Provisions Governing Alternative to Source-Specific Best 

Available Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 71, NO. 198 published 

October 13, 2006). 
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

Appendix A 

Response to NYSDEC Letter 

January 2010



AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

Appendix B 

NCASI Emission Factors and 

Retrofit Controls for Pulp Mill 

Sources
 February 9, 2006 

Particulate Emissions Data for Pulp and Paper Industry Specific Sources 

The following tables contain summarized particulate emissions data for sources that are specific to the 

pulp and paper industry. The source categories addressed in this document are smelt dissolving tanks, 

lime kilns, and recovery furnaces. Boilers are not addressed since AP-42 emission factors for boiler 

emissions are well documented and readily available including in NCASI Technical Bulletin No. 884. 

Smelt Dissolving Tanks 

Data for smelt dissolving tanks were compiled from NCASI Technical Bulletins Nos. 884 and 898. This 

data set includes test results from the use of a dilution tunnel method which quantifies total PM10 and 

PM2.5 particulate matter. Total PM10 and PM2.5 particulate matter are the sum of filterable and 

condensible PM10 and PM2.5 particulate matter. All smelt dissolving tanks in the data set have wet 

particulate control devices. 

The filterable PM numbers are obtained from combining the data set of 36 sources listed in NCASI 

Technical Bulletin No. 884, Table A15c, and the data set of 6 sources listed in NCASI Technical Bulletin 

No. 898. The data for “Total PM10“ and “Total PM2.5” are from the 8 sources listed in NCASI Technical 

Bulletin No. 884, Table A15d. All of the CPM data was from the 6 sources listed in NCASI Technical 

Bulletin No. 898. The CPM data listed in Technical Bulletin No. 884 was not used as that data is an 

estimate of CPM and not results from EPA Method 202. All of the sulfate data is from the 3 sources 

tested by NCASI, and listed in Technical Bulletin No. 898. 

Table 1. Smelt Tank Data Summary 

 

Measurement No. of Range Mean 5

Mean 

Parameter Method Sources (lb/ton BLS) Percent of PM 

 

PM EPA Method 5 42 0.03 - 0.64 0.148 

6

Total PM10 Dilution Tunnel 8 10.031 – 0.666 20.154 6104 

6

Total PM2.5 Dilution Tunnel 7 10.027 – 0.570 20.132 689 

CPM MeCl2 Soluble EPA 202 6 1

0.0009 - 0.0192 20.0044 3 

CPM Water Soluble EPA 202 6 1

0.0039 - 0.0832 20.0192 13 

CPM EPA Method 202 6 1

0.0048 - 0.1024 20.0237 16 

Sulfate IC 3 3

0.0014 - 0.0297 40.0069 % of CPM = 

29 

 

1

Range values were determined by applying the mean percent of PM to the range of values for PM. 2Mean values 

were determined by applying the mean percent of PM to mean value for PM. 3

Range values for sulfate were 

determined by applying the mean percent of CPM to the range of CPM values. 4

Mean value for sulfate was 

determined by applying the mean percent of CPM to the mean value for CPM. 5

Mean percent of PM values are 

derived from individual data sets. 6

Values include filterable and condensible PM.
 February 9, 2006 

Recovery Furnaces 

The recovery furnace data are a compilation of data in NCASI Technical Bulletins Nos. 852, 884, and as 

yet unpublished NCASI data. All of the recovery furnaces in this data set use electrostatic precipitators 

(ESP) for particulate control. 

The PM data for DCE recovery furnaces is from the 23 sources listed in NCASI Technical Bulletin No. 

884, Table A11c. The PM10 data for the DCE recovery furnaces is from the 4 DCE sources listed in 

Technical Bulletin No. 884, Table A11d. The PM2.5 data for DCE recovery furnaces is from the 4 DCE 

sources listed in Technical Bulletin No. 884, Table A11d, plus a further two from as yet unpublished 

NCASI data. The DCE CPM data is from two sources listed in Technical Bulletins Nos. 852 and 884, 

and two sources from as yet unpublished NCASI data. 

The PM data for the NDCE recovery furnaces is from the 20 sources listed in NCASI Technical Bulletin 

No. 884, Table A12b. The PM10 data for the NDCE recovery furnaces is from the 13 NDCE sources 

listed in Technical Bulletin No. 884, Table A12c. The PM2.5 data for NDCE recovery furnaces is from the 

11 DCE sources listed in Technical Bulletin No. 884, Table A12c, plus a further source from as yet 

unpublished NCASI data. The NDCE CPM data is from 6 sources listed in Technical Bulletin No.884, 

and one source from as yet unpublished NCASI data.
 February 9, 2006 

Table 2. Recovery Furnace Data Summary 

Kraft DCE Recovery Furnace 

 Measurement No. of Range Mean 5

Mean 

Parameter Method Sources (lb/ton BLS) Percent of PM 

 

PM EPA Method 5 23 0.07 - 2.58 0.74 

PM10 EPA CTM-040 4 1

0.05 - 1.88 20.54 73 

PM2.5 EPA CTM-040 6 1

0.04 - 1.44 20.41 56 

CPM MeCl2 Soluble EPA 202 4 1

0.014 - 0.516 20.148 20 

CPM Water Soluble EPA 202 4 1

0.13 - 4.75 21.36 184 

CPM EPA Method 202 4 1

0.14 - 5.29 21.52 205 

Sulfate IC 3 3

0.05 - 1.85 40.53 % of CPM = 35 

 

Kraft NDCE Recovery Furnace

 Measurement No. of Range Mean 5

Mean 

Parameter Method Sources (lb/ton BLS) Percent of PM 

 

PM EPA Method 5 20 0.02 - 3.50 0.65 

PM10 EPA CTM-040 13 1

0.01 - 2.35 20.44 67 

PM2.5 EPA CTM-040 11 1

0.01 - 1.82 20.34 52 

CPM MeCl2 Soluble EPA 202 3 1

0.003 - 0.560 20.104 16 

CPM Water Soluble EPA 202 3 1

0.016 – 2.84 20.53 81 

CPM EPA Method 202 7 1

0.02 - 3.40 20.63 97 

Sulfate IC 2 3

0.007 - 1.16 40.21 % of CPM = 34 

 

1

Range values were determined by applying the mean percent of PM to the range of values for PM. 2Mean values 

were determined by applying the mean percent of PM to the mean value for PM. 3

Range values for sulfate were 

determined by applying the mean percent of CPM to the range of CPM values. 4

Mean value for sulfate was 

determined by applying the mean percent of CPM to the mean value for CPM. 5

Mean percent of PM values are 

derived from individual data sets. 
 February 9, 2006 

Lime Kilns 

The lime kiln data are a compilation of data from NCASI Technical Bulletins Nos. 852, 884, and 898. 

The emissions data are separated by control device type. The majority of lime kilns in this data set use 

wet control devices for particulate control. Two of the lime kilns in this data set use an ESP for 

particulate control, followed by a wet scrubber for SO2 control. The remainder use an ESP for particulate 

control. 

The PM data for lime kilns using wet control devices is from 30 sources listed in NCASI Technical 

Bulletin No. 884, Table A13c. The PM10 and PM2.5 data for lime kilns using wet control devices is from 

NCASI Technical Bulletin No. 884, Table A13d. The CPM and sulfate data for lime kilns using wet 

control devices is from Technical Bulletin No. 898. 

All of the PM, CPM, and sulfate data for lime kilns using an ESP followed by a wet control device is 

from two sources listed in NCASI Technical Bulletin No. 898. 

The PM data for lime kilns using an ESP alone are from the 7 sources listed in NCASI Technical Bulletin 

No. 884, Table A13c. The PM10 and PM2.5 data are from the 6 sources listed in Technical Bulletin No. 

884, Table A13d. The CPM and sulfate data are from 3 sources listed NCASI Technical Bulletin Nos. 

852 and 884. 
 February 9, 2006 

Table 3. Lime Kiln Data Summary 

Lime Kilns with Wet Particulate Control Devices 

 Measurement No. of Range Mean 5

Mean 

Parameter Method Sources (gr/dscf) @10% O2 Percent of PM 

 

PM EPA Method 5 30 0.014 - 0.346 0.0995 

6

Total PM10 Dilution Tunnel 6 10.014 - 0.349 20.100 101 

6

Total PM2.5 Dilution Tunnel 7 10.012 - 0.304 20.088 88 

CPM MeCl2 Soluble EPA Method 202 3 1

4.2E-5 - 0.0010 20.0003 0.3 

CPM Water Soluble EPA Method 202 3 1

0.0008 - 0.0208 20.0060 6 

CPM EPA Method 202 3 1

0.0009 - 0.0218 20.0063 6.3 

Sulfate IC 2 3

0.0002 - 0.0046 40.0013 % of CPM = 21 

*These data are the result of dilution tunnel testing, therefore the PM10 and PM2.5 values reflect the sum of 

filterable and condensible PM10 and PM2.5 particulate. 

Lime Kilns with a Dry ESP for Particulate Control Followed by a Wet Scrubber

 Measurement No. of Range Mean 5

Mean 

Parameter Method Sources (gr/dscf) @10% O2 Percent of PM 

 

PM EPA Method 5 2 0.003 - 0.004 0.004 

PM10 No Data No Data 

PM2.5 No Data No Data 

CPM MeCl2 Soluble EPA Method 202 2 0.0004 - 0.0081 0.0042 140 

CPM Water Soluble EPA Method 202 2 0.0038 - 0.0054 0.0046 131 

CPM EPA Method 202 2 0.006 - 0.012 0.009 271 

Sulfate IC 1 0.002 0.002 % of CPM = 34 

 

Lime Kilns with a Dry ESP for Particulate Control 

 Measurement No. of Range Mean 5

Mean 

Parameter Method Sources (gr/dscf) @10% O2 Percent of PM 

 

PM EPA Method 5 7 0.002 - 0.033 0.010 

PM10 EPA CTM-040 6 1

0.001 - 0.211 20.006 64 

PM2.5 EPA CTM-040 6 1

0.0005 - 0.0079 20.0024 24 

CPM MeCl2 Soluble EPA Method 202 3 1

0.0013 - 0.0208 20.0063 63 

CPM Water Soluble EPA Method 202 3 1

0.003 - 0.045 20.014 137 

CPM EPA Method 202 3 1

0.004 - 0.066 20.020 200 

Sulfate IC 3 3

0.0035 - 0.0581 40.0176 % of CPM = 88 

 

1

Range values were determined by applying the mean percent of PM to the range of values for PM. 2Mean values 

were determined by applying the mean percent of PM to the mean value for PM. 3

Range values for sulfate were 

determined by applying the mean percent of CPM to the range of CPM values. 4

Mean value for sulfate was 

determined by applying the mean percent of CPM to the mean value for CPM. 5

Mean percent of PM values are 

derived from individual data sets. 6

Values include filterable and condensible PM. 











AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

Appendix C 

NYSDEC BART Guidance 

Presentations
NYSDEC Guidance and Protoco

Visibility Assessment of BAR

Eligible Sources

Leon Sedefian and Margaret Valis

Impact Assessment and Meteorology

Section

518‐402‐8403

Federal Land Managers

• National National Park Service Service, U S. . Forest Servic

Servic

U.S. Fish and Wildlife Service

• CAA gives the FLM affirmative affirmative responsi

responsi

protect the Class I areas, especially visib

• A il bl Available guidance specific to Class I are

EPA‐ Interagency Workgroup on Air Quality M(IWAQM) (IWAQM)‐ Phase 2 revised revised draft May, 2009.

FLMs: Federal Land Managers Air Quality Rel

Values Work Group (FLAG). (FLAG). Latest revision revision 6/

6/
Visibility Scales

• Visual Range (V)‐ greatest distance at which a da

can be seen.

• Extinction coefficient(bext)‐the attenuation of lig

to scattering and absorption by particles and som

• V=3.91/bext• deciview or haziness‐

dv=10ln(bext/0.01km‐1) defined to be lin

fractional change in bext or perceived visual change. 

change is ab t ou 10% change in b t ex and is perceptib

change. Also, greater than 5% change in bext produNoticeable Change.
IMPROVE Algorithms

• New bext= 2.2fS(RH)[small sulfates] +

4 8fL(RH)[large 4.8fL(RH)[large sulfates]+2 sulfates]+2 4fS(RH)[sm

.4fS(RH)[sm

nitrates] + 5.1fL(RH)[large nitrates]+2.

organics] + 6 1[large .1[large organics]+10[elem

organics]+10[elem

carbon] +1[fine soil] +1.7fSS(RH)[sea

salt]+0 6[coarse salt]+0.6[coarse matter]+Rayleigh matter]+Rayleigh scat

scat

(site specific) +0.33[NO2(ppb)]
Protocol Default Recommendat

• Use CALPUFF/CALMET v5.8 (set to default) and CALPOST 

(Method 8, Mode 5‐ simulated by choosing FLAG option a(e.g. See John Notar’s 5/13/09 presentation at EPA R

Meteorologists Workshop‐SCRAM website).

• Receptors at seven Class I areas provided at NPS web

• Maximum of the actual 24 hour emission rate for NO

and PM (including (including condensibles condensibles‐per EPA AP42 or NP

webpage).

• 2002 “NWS‐only” and “hybrid” MM5/NWS AECOM

met lil eorological d t a a sets.

• Implicit in FLM’s acceptance of 1 year of data is the u

maximum impacts and 20% best natural background
Required Outputs and Thresho

Thresho

• For exemption exemption demonstration demonstration‐ use max

max

impacts for combined three pollutants 

• For BART demonstrations demonstrations provide: provide:

1) Max and 8th highest for pre and post 

control alternatives.

2) number of days of exceedences of 0.

and 1dv.

3) for f ili i facilities wi ht more than one unit

cumulative maximum impacts.
CALPUFF

• CALPUFF is the EPA recommended model for v

assessments and for long range transport appl

(> 50 km)

• Non‐st d ea y‐st t a e puff di i spers on mod l e• Capable of treating time‐varying point, area, lin

volume sources

• Includes algorithms for subgrid scale effects (su

terrain impingement), as well as longer range e

(such as pollutant removal due to wet scaveng

dry deposition, chemical transformation, and v

effects of particulate particulate matter concentrations). concentrations).

MANE‐VU CALPUFF Doma

Figure D‐13. Example midnight wind field a

meters for VT DEC CALMET.

Responses to Comments

 Timeframe:

 Retaining October 1, 2010 deadline for analysis

 Time is required for EPA, FLM review and public co

period prior to EPA’s Jan. 15 2011 deadline for approv

 Unable to delay for results of RNA or EPA initiatives

 Moving back date of compliance to January 1, 20

 P id rov es over three years from subii m ss on of anal 

ys 
Responses to Comments

 Cost threshold of controls:

 Intend to use threshold of $5,500 per ton reduc

 RACT value consistent with appl bl ica i ity to existing  Allows for one analysis to be used for RACT and BAR

NOx

 Should also consider a $/deciview reduced metric

 E ti xemp on th h ld threshold:

 Maintaining 0.1 dv threshold for unit exemption
Responses to Comments

 Modeling Issues:

 Department updating original NESCAUM mod

b tt e er represent EPA guidance and more recentemissions scenarios

 CAIR:

 Won’t be considered as sufficient for NOx and S EPA’s finding of CAIR being an equivalent prog

based on phases I + II. No guarantee re‐propos

program program will be as stringent stringent overall overall
Responses to Comments

 CAIR and ADRP:

 Controls installed under these programs will be take

account during analysis

 BART needed to reach Reasonable Progress goals as 

enforceable measure

 Small emission units with negligible impacts:

 Especially of concern for non‐EGU sources Use engi i neer ng j du gment to d id ec e what units to fo Document units which are technically eligible but to

for controls and provide basis for this determination

wi ht us (C O. . staff, RAPCE) up front on this d ii ec s on
Responses to Comments

 Accounting for ‘peaking’ operations:

 Cost effectiveness calculations based on maxim

emi i ss ons, b t u sh ld ou be suppl td emen ed with a of operating characteristics
“Guidelines for BART Determinati

Determinati

Under the Regional Haze Rule”

 Implementation guidance available at:

 40 CFR Part 51 Appendix Y, or 70 FR 39156 (July 6, 2005)
Considerations of Five‐Factor Ana

Case‐by‐case control analysis will weigh five factors:• Costs of Compliance• Energy and non‐air quality impacts of compliance

• Existing pollution control technology at the sourc

• Remaining Remaining useful life of the source• Degree of visibility improvement that can be antic

from the installation of controls
Steps of Five‐Factor Analysis

 Step 1: Identify all available retrofit control

technologies

 Step 2: Eli i m nate tech i ll n ca y i f ibl infeasible options Step 3: Evaluate control effectiveness of remain

control technologies

 Step 4: Evaluate impacts and document the res

 Costs of compliance; compliance; energy impacts; impacts; non‐air q

q

environmental impacts; remaining useful life

 Step 5: Evaluate visibility impacts
Ways to Avoid the Analysis

 Facility:

 Accept emissions cap for all BART‐eligible units 

b l e ow a combi d ne 250 tpy for each poll t t u an

 Individual Unit:

 Unit falls below the 0 1. dv contribution contribution thresho

thresho

 Utility boilers: accept presumptive SO2 or NOx 

 Analysis for other pollutants still required
Ways to A id vo the M d li o e ng Step for 

Particular Pollutant

(Complete & Document only Steps 1‐4)

 Accept the most stringent control option No control options found to be technically and

economically feasible

 For NOx, fulfill fulfill RACT requirement requirement under rece

rece

revised Part 220 (cement plants, glass plants) o

Subpart 227‐2 (combustion sources)
Controls/Limits for Utility Boilers

 SO2:

 Uncontrolled units >200MW at power plants > 

 Presumptive limit of 95 percent control or 0.15 lb/m

 Oil‐fired units, regardless of size:

 Evaluate Evaluate limiting limiting sulfur content content of fuel oil burned to 

or less, by weight

 For other units wi ht pre‐exi i st ng controls, guida

recommends construction/upgrade of scrubber
Controls/Limits for Utility Boilers

 NOx:

 Consider NOx RACT determination under rece

revi d se Sb t u par 227‐2 as meeting BART
Schedule

 Analysis of BART controls due to DEC by Octo

2010

 60‐day FLM review; EPA review 30‐day public comment period

 EPA approval by January 15, 2011 Approved controls to be installed & operating 

J y anuar 1, 2014.
AECOM Environment 

Five Factor BART Analysis for International Paper Ticonderoga Mill September 2010 

Appendix D 

Modeling Archive