Prepared for: Prepared by: 

TransCanada AECOM 

Ravenswood, NY Westford, MA 

60158987 

Environment

Five Factor BART Analysis for 

TransCanada Ravenswood 

Generating Station 
Environment

Five Factor BART Analysis for 

TransCanada Ravenswood 

Generating Station

____________________________________________________________________

Prepared By Olga Kostrova

_________________________________

Reviewed By Robert J. Paine 

Prepared for: Prepared

TransCanada AECOM

Ravenswood, NY Westford, 

60158987

Environment

Five Factor BART Analysis for 

TransCanada Ravenswood 

Station

______________________________________________

Robert Hall Seemantini 

_________________________________

Prepared by: 

AECOM

Westford, MA 

60158987

_________________________________________________________ 

Seemantini Deshpande 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010

i

Contents 

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

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

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

1.2 Organization of Report Document ....................................................................................... 1-1

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

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

2.2 Existing Control Technologies ............................................................................................. 2-1

2.3 Baseline Emissions .............................................................................................................. 2-1

3.0 Emission Control Alternatives ..................................................................................... 3-1

3.1 Candidate SO2 Emissions Control ...................................................................................... 3-1

3.2 Candidate NOx Emission Controls ...................................................................................... 3-1

3.2.1 Effectiveness of Technically Feasible NOx Controls ........................................... 3-2

3.2.2 Analysis of Alternative NOx Controls ................................................................... 3-3

3.3 Candidate PM Emission Controls ....................................................................................... 3-5

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

4.1 Elements of the Refined Analysis ....................................................................................... 4-1

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

5.1 CALPUFF Modeling Domain and Receptors ...................................................................... 5-1

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 Modeled Control Scenarios ................................................................................................. 6-1

6.2 Modeling Results for Baseline Emissions ........................................................................... 6-1

6.3 Modeling Results for the Advanced Combustion Control Case ......................................... 6-3

6.4 Conclusions and BART Recommendation ......................................................................... 6-3
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010

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

List of Appendices 

Appendix A Cost Effectiveness Calculations

Appendix B Quotation from Fuel Tech for LNB/SOFA and SNCR

Appendix C Modeling Archive

List of Tables 

Table ES-1 Summary of BART Analysis............................................................................................ ES-4 

Table 2-1: Ravenswood Baseline Emissions (100% Oil-Firing) ......................................................... 2-3

Table 2-2: Ravenswood Stack Parameters ........................................................................................ 2-3

Table 3-1: Control Efficiency of Technically Feasible NOx Control Options ...................................... 3-3

Table 3-2: Total Capital and Annual Costs Associated with LNB/SOFA SNCR, SCR, and Fuel 

Switching for Ravenswood Units, 10, 20, and 30 ............................................................. 3-3

Table 3-3: Summary of Non Air Quality Environmental Effects ......................................................... 3-4

Table 3-4: Control Efficiency of Technically Feasible PM Control Options........................................ 3-7

Table 3-5: Cost Effectiveness of Technically Feasible PM Control Options ...................................... 3-7

Table 3-6: Ravenswood NOx Advanced Combustion Controls Emissions (Control Case 1) ........... 3-8

Table 4-1: Comparison of the AECOM and VT DEC CALMET User-Defined Settings .................... 4-3

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

Table 6-1: Regional Haze Impacts due to Baseline Emissions ......................................................... 6-2

Table 6-2: Regional Haze Impacts due to Advanced Combustion Controls (Control Option 1) ....... 6-3

Table 6-3: Cost Effectiveness and Visibility Improvement Associated with Control Option 1 ........... 6-4

List of Figures 

Figure 1-1: Location of the Class I Areas in Relation to the Ravenswood Generating Station .......... 1-2

Figure 4-1: Ravenswood CALMET Modeling Domains ....................................................................... 4-2
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

ES-1

Executive Summary 

TransCanada, LLC owns the Ravenswood Generating Station (“RGS”) in Queens, New York. The 

Ravenswood Generating Station is a 2,480 megawatt (MW) power plant that consists of multiple units, 

including boilers. It supplies electrical generating capacity to meet 26% of New York City’s demand. 

As such, Ravenswood must also meet a reliability requirement as per the New York Independent 

System Operator, Inc. (NYISO)1 for standby fuel oil firing in order to prevent a system impact in the 

event that the natural gas supply is interrupted. 

Both Unit 10 and Unit 20 commenced commercial operation in 1963 and Unit 30 in 1965, thus 

meeting the in-service date for BART eligibility. Over the past several years, the plant has had 

emissions exceeding 250 tons per year of sulfur dioxide (SO2) and nitrogen oxide (NOx). Therefore, 

the plant is BART-eligible. All three units are tangential-fired boilers manufactured by Combustion 

Engineering. Units 10, 20, and 30 are fired with natural gas and/or No.6 fuel oil and have maximum 

heat input rates of 4,204, 4,171, and 9,379 MMBtu/hr, respectively. The plant burns primarily natural

gas, but also uses residual fuel oil as indicated by NYISO’s reliability requirements (I-R3, the 

“Minimum Oil Burn Rule”). The No.6 fuel oil has a maximum sulfur content of 0.3%. 

The New York State BART rules require that sources that are subject to BART perform a site-specific 

BART analysis including a control technology review and CALPUFF modeling to assess the visibility 

impact of the emission units. Additionally, for large Electric Generating Units (EGUs) affected by the 

rule, the source is required to meet presumptive control levels for NOx and SO2 unless it is 

demonstrated that alternative control levels are justified or equivalent in effectiveness. 

The BART analysis was conducted for the 100% oil-firing case since this condition reflects the highest

emission case for all haze-causing pollutants. The presumptive BART limit for NOx emissions for the 

Ravenswood units is 0.15 lb/MMBtu for NOx as a 24-hour average, based on NYSDEC policy. This 

presumptive BART limit is dictated by the New York Reasonably Achievable Control Technology or 

RACT rule. For SO2, the NYSDEC BART guidelines indicate that limiting the sulfur content of the fuel 

burned to 1.0% or less constitutes BART for SO2. The plant already has a fuel sulfur limit well below 

this level (0.3% sulfur). 

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

from Units 10, 20, and 30. This analysis addresses the five statutory factors required by Section 169A 

(g) (7) of the Clean Air Act that States must consider in making BART determinations: 

(1) the costs of compliance, 

(2) the energy and non-air quality environmental impacts of compliance, 

(3) any existing pollution control technology in use at the source, 

 

1

 New York Independent System Operator, Inc., Docket No. ER07-748-000, Issued May 11, 2007 by the Federal 

Energy Regulatory Commission. 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

ES-2

(4) the remaining useful life of the source, and, 

(5) the degree of improvement in visibility which may reasonably be anticipated to result from the 

use of such technology. 

The following emission scenarios were evaluated for the Ravenswood BART analysis: 

• Baseline Case (2005-2009 period – the most recent 5 years): maximum daily emissions of 

SO2, NOx as well as particulate matter were provided by TransCanada. The maximum daily 

heat input rates were based on the Part 75 monitoring data for the period of 2005-2009. 

Condensable particulate matter emissions for the three units were based on AP-42 emission 

factors for No.6 oil-fired boilers. 

• NOx Control Case involves combustion control optimization. This option would include 

installation of low NOx burners (LNB) and separated overfire air (SOFA) and other 

combustion modifications. These retrofit controls are capable of achieving a NOx emissions 

level of 0.17 lb/MMBtu which will limit NOx emissions to 3,018 lb/hr for all three units 

combined on a 24-hour rolling average basis. 

Additional NOx and PM10 control cases were considered for cost effectiveness and feasibility and they 

are discussed in Section 3. Based on either an excessively high cost (NYSDEC considers a cost of 

$5,000 per ton as excessive), physical space constraints, infeasibility of the controls, or legal 

contractual conditions making the option infeasible, other NOx and PM10 emission control cases were 

dismissed as not applicable for BART. Consequently, they were not modeled for determining visibility 

impacts. In general, non-sulfate-related PM10 visibility impacts are marginally higher than the 0.1 

delta-dv threshold and were hence dismissed from further consideration. Moreover, post-combustion 

control equipment for oil-fired units is generally not feasible. 

As noted above, Ravenswood Units 10, 20, and 30 burn fuel oil with the maximum sulfur content of 

0.3%. Per NYSDEC guidance, fuel oil with a sulfur content of 1.0% or less meets BART requirements 

for SO2 and, therefore, no further BART review is necessary for this haze-causing pollutant. However, 

we present a cost analysis in Section 3 that indicates that the control cost associated with fuel 

switching to an even lower sulfur fuel oil is well above $5,000 per ton removed for NOx and PM10. 

CALPUFF modeling of baseline emissions indicates that the maximum visibility impact from each unit 

exceeds the 0.1 delta-deciview (delta-dv) significance threshold at one or more Class I areas. 

Therefore, a BART analysis was conducted. CALPUFF modeling results due to application of the 

advanced combustion NOx controls (low NOx burners and separated overfire air) showed modest 

visibility improvements at the Class I areas modeled. The most heavily affected Class I area is the 

Brigantine Wilderness. The NOx control costs for advanced combustion controls are approximately 

$1,600/ton NOx removed and the visibility improvement costs are at least $22,000,000/deciview. 

NYSDEC has noted that control costs above $5,000 per ton are excessive and can be used to 

dismiss BART candidate options from further consideration. 

This BART option of installing advanced combustion controls on the units is not cost effective with 

regard to visibility (dollars/dv is excessively high). However, advanced combustion controls are 

proposed as BART by TransCanada for controlling NOx emissions based on NY RACT requirements 

and the dollars/ton cost effectiveness. 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

ES-3

As can be seen in Table ES-1, switching to low sulfur distillate oil has associated costs well in excess 

of the NYSDEC guideline of $5,000 per ton removed for NOx and PM10 control. Furthermore, the 

incremental cost of retrofitting the units with an SNCR or an SCR post application of the advanced 

combustion controls are found to be excessive. We conclude as a result of this BART analysis that 

none of the additional retrofits considered beyond advanced combustion controls (including switching 

to distillate oil fuel) are cost-effective for NOx.
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station Table ES-1: Summary of BART Analysis 

Step 1 Step 2 Step 3 Step 4a Step 4b Step 5 

Identify 

Control 

Technologies

Feasible 

Control 

Technology?

Evaluate 

Control 

Effectiveness 

for Technically 

Feasible 

Control 

Technologies 

Calculate Cost 

Effectiveness for 

Control 

Technologies 

Determine 

Non-Air Quality 

Environmental 

and Energy 

Impacts 

Evaluate 

Visibility 

Changes of 

Controls vs. 

baseline 

Identify BART 

Resu

NOx Controls:

Advanced 

Combustion 

Controls: Low 

NOx burners, 

separated 

overfire air 

Yes 

NOx Outlet = 

0.17 lb/MMBtu, 

~30% NOx 

reduction from 

baseline levels 

of 0.24 

lb/MMBtu 

Annualized cost = 

$2.62 MM; 

$1,612/ton removed 

based on potential 

emissions 

No significant 

impacts 

Average 

visibility 

improvement 

=0.06 delta-dv 

Installation of 

(NOx = 0.17 lb

BART for Raven

10, 20 a

NOx Controls:

SNCR Yes 

NOx Outlet = 

0.15 lb/MMBtu, 

~ 10-15% NOx 

reduction from 

post LNB/SOFA 

levels of 0.17 

lb/MMBtu

Annualized cost = 

$7.7 MM; 

$10,924/ton removed 

based on potential 

emissions 

Modest energy 

impacts, 

ammonia 

emissions 

n/a 

Costs for this o

high; not consid

for BA

NOx Controls:

SCR Yes 

Estimated NOx 

Outlet = 0.025 

lb/MMBtu, ~ 

85% NOx 

reduction from 

the post 

LNB/SOFA 

levels of 0.17 

lb/MMBtu 

Annualized cost = 

$90 MM; $25,829/ton 

removed based on 

potential emissions 

Transporting 

ammoniaI in 

NYC; addition of 

ammonia 

storage and 

handling 

systems, 

ammonia 

emissions, 

increases 

sulfuric acid mist 

n/a 

Costs for this o

high; not consid

for BA
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station 

Step 1 Step 2 Step 3 Step 4a Step 4b Step 5 

Identify 

Control 

Technologies

Feasible 

Control 

Technology?

Evaluate 

Control 

Effectiveness 

for Technically 

Feasible 

Control 

Technologies 

Calculate Cost 

Effectiveness for 

Control 

Technologies 

Determine 

Non-Air Quality 

Environmental 

and Energy 

Impacts 

Evaluate 

Visibility 

Changes of 

Controls vs. 

baseline 

Identify BART 

Resu

emissions 

NOx Controls:

Switch to 

lower sulfur 

No. 2 oil 

Yes 

NOx Outlet = 

0.10 lb/MMBtu, 

~ 58% NOx 

reduction from 

residual oil NOx 

level of 0.24 

lb/MMBtu 

Annualized cost = 

$104 MM, 

$62,000/ton removed 

No significant 

impacts n/a 

Costs for this o

high; not consid

for BA

NOx Controls:

100% Natural 

Gas

No; Minimum Oil Burn Rule 

for reliability 

rules out this 

option 

n/a n/a n/a n/a Infeasible o

considered furth

BART for NOx for Ravenswood Unit 10, 20 and 30 

Installation of 

(NOx = 0.17 lb

BART for Raven

10, 20 a

SO2 Controls:

Switch to 

lower sulfur 

No. 2 oil

Yes, but 0.3% 

sulfur is below 

the NYSDEC 

SO2 BART 

threshold of 

1% sulfur 

content 

n/a n/a n/a n/a 

Since combus

with a sulfur 

<=1% is consid

for SO2 and 

incremental co

distillate oil is 

high, this opti

considered 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station 

Step 1 Step 2 Step 3 Step 4a Step 4b Step 5 

Identify 

Control 

Technologies

Feasible 

Control 

Technology?

Evaluate 

Control 

Effectiveness 

for Technically 

Feasible 

Control 

Technologies 

Calculate Cost 

Effectiveness for 

Control 

Technologies 

Determine 

Non-Air Quality 

Environmental 

and Energy 

Impacts 

Evaluate 

Visibility 

Changes of 

Controls vs. 

baseline 

Identify BART 

Resu

BART for SO2 for Ravenswood Unit 10, 20 and 30 

Combustion 

residual fuel oi

SO2 for Ravens

10, 20 a

PM10

Controls:

Install Fabric 

Filter 

No n/a n/a n/a n/a Not feasible f

units

PM10

Controls:

Install Dry 

ESP 

Yes 

Engineering 

estimate – 

99.9% control 

Annualized cost = 

$166 MM, 

$178,000/ton removed 

Utilizes electricity 

adding to the load 

on the facility 

n/a 

Costs for this o

high; not consid

for BA

PM10

Controls:

Install Wet 

ESP 

Yes 

Engineering 

estimate – 

99.9% control 

Annualized cost = 

$229 MM, 

$246,000/ton removed 

Utilizes electricity 

adding to the load 

on the facility, 

wastewater 

treatment issues 

n/a 

Costs for this o

high; not consid

for BA

PM10

Controls:

Switch to 

lower sulfur 

No. 2 oil 

Yes 

PM10 Outlet = 

0.014 lb/MMBtu, 

~ 65% NOx 

reduction from 

residual oil PM10

level of 0.04 

lb/MMBtu 

Annualized cost = 

$104 MM, 

$175,000/ton removed 

n/a n/a 

Costs for this o

high; not consid

for BA
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station 

Step 1 Step 2 Step 3 Step 4a Step 4b Step 5 

Identify 

Control 

Technologies

Feasible 

Control 

Technology?

Evaluate 

Control 

Effectiveness 

for Technically 

Feasible 

Control 

Technologies 

Calculate Cost 

Effectiveness for 

Control 

Technologies 

Determine 

Non-Air Quality 

Environmental 

and Energy 

Impacts 

Evaluate 

Visibility 

Changes of 

Controls vs. 

baseline 

Identify BART 

Resu

BART for PM for Ravenswood Unit 10, 20 and 30 

Combustion 

residual fuel 

current config

BART for 

Ravenswood U

and 3
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

1-1

1.0 Introduction 

The Ravenswood Generating Station (Ravenswood), operated by TransCanada, has been identified 

by NYSDEC as a source that is eligible for consideration of BART controls for SO2, NOx, and PM10. 

This document describes the procedures by which a modeling analysis and a BART engineering 

review have been conducted for the BART-eligible Ravenswood Units 10, 20, and 30. 

1.1 Location of Source vs. Relevant Class I Areas 

Figure 1-1 shows the location of the Ravenswood Generating Station relative to the seven Class I 

areas to be considered for New York BART reviews. The BART modeling analysis has been 

conducted for each of the seven Class I areas in accordance with the NYSDEC guidance. The seven 

Class I areas are as follows: 

1. Brigantine National Wildlife Refuge (NJ), located about 143 km from Ravenswood; 

2. Lye Brook Wilderness Area (VT), located about 250 km from Ravenswood; 

3. Presidential Range Dry River Wilderness (NH) , located about 425 km from Ravenswood; 

4. Great Gulf Wilderness (NH), located about 450 km from Ravenswood; 

5. Dolly Sods Wilderness Area (WV), located about 500 km from Ravenswood; 

6. Otter Creek Wilderness Area (WV). located about 515 km from Ravenswood; 

7. Acadia National Park (ME), located about 570 km from Ravenswood. 

1.2 Organization of Report Document 

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

from Units 10, 20, and 30 at the Ravenswood Generating Station. Section 2 provides a description of 

Ravenswood Units 10, 20, and 30 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 

improvement modeling using CALPUFF are presented in Section 6. References are listed in 

Section 7. 

 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

1-2

Figure 1-1: Location of the Class I Areas in Relation to the Ravenswood Generating Station 

 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

2-1

2.0 Background Data 

2.1 Overview of BART Emission Units 

The BART-affected emission units at the Ravenswood Generating Station are the three No. 6 

oil/natural gas fired boilers designated as Units 10, 20, and 30. Units 10 and 20 commenced 

commercial operation in 1963 and Unit 30 became operational in 1965. Since all three units began 

operation during the time period (1962-1977) targeted by the Regional Haze BART Rule, they are 

subject to this rule. Units 10, 20, and 30 are tangential-fired boilers manufactured by Combustion 

Engineering. 

2.2 Existing Control Technologies 

Units 10, 20, and 30 has dual-fired capability with either a natural gas and/or No.6 fuel oil and have

rated heat input rates of 4,204, 4,171, and 9,379 MMBtu/hr, respectively. The plant burns primarily 

natural gas, with occasional use of residual fuel oil as requested by NYISO’s reliability requirements (IR3, the “Minimum Oil Burn Rule”). The No.6 fuel oil has a maximum sulfur content of 0.3%. 

Ravenswood Units 10, 20, and 30 are equipped with Close Coupled Over Fire Air (CCOFA) systems 

to control NOx emissions. All three units currently burn natural gas and No. 6 oil with a maximum 

sulfur content of 0.3% to control SO2 emissions. Currently, there are no PM controls on the units. 

2.3 Baseline Emissions 

For the purposes of determining BART eligibility, the SO2, NOx, and PM filterable baseline emissions 

for the 100% oil firing case were determined using maximum daily emissions during the most recent 

5-year period (2005 through 2009). For Units 10, 20, and 30, the maximum NOx emission rates were 

668 lb/hr, 526 lb/hr, and 1,449 lb/hr, respectively. 

Speciation of the particulate matter emissions into filterable and condensable PM10 components was 

determined 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 was calculated as the total filterable PM * 0.52. 

The coarse PM10 was calculated as the difference between the total PM10 and the fine PM10. 

• Elemental carbon or black carbon was estimated to be 7.4% of fine PM10 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 condensible PM emission factor was based on AP-42 Table 1.3-2 (1.5 lb/1000 gal) for #6 

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

component). 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

2-2

Table 2-1 provides a summary of the SO2, NOx, and PM baseline emissions that were used in the 

modeling analysis. Table 2-2 provides the stack parameters that were used in the baseline and 

advanced controls conditions modeling analysis. 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station 

Table 2-1: Ravenswood Baseline Emissions (100% Oil-Firing) 

Table 2-2: Ravenswood Stack Parameters 

Unit No. 

Source 

Latitude 

(deg) 

Source 

Longitude 

(deg) 

Base Elevation 

(m) 

Stack Height 

(m) 

Stack Diameter 

(m) 

Flue Gas Temperatur

(°K) 

10 40.76 -73.95 0.0 152.1 4.1 399.8 20 40.76 -73.95 0.0 152.1 4.1 399.8 30 40.76 -73.95 0.0 152.1 7.2 405.4 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station

3-1

3.0 Emission Control Alternatives 

The visibility impairing pollutants discussed in this section include NOx, SO2, and PM. Information on 

control of these pollutants through application of a control device, combination of devices, and/or 

operational change is provided. 

3.1 Candidate SO2 Emissions Control 

SO2 emissions are directly related to the sulfur content of the fuel burned. Natural gas inherently has 

low sulfur content, so only the oil firing scenario is subject to BART review for SO2 emissions 

reductions. Reducing the amount of sulfur in the fuel oil, or switching entirely to natural gas is the only 

practical way to reduce SO2 emissions. However, the Minimum Oil Burn rule prevents a switch to 

exclusively firing natural gas when the NYISO invokes the rule. The guidance put forth by NYSDEC 

regarding presumptive BART for SO2 indicates that burning fuel with a sulfur content of 1% or less 

constitutes BART. Ravenswood generating station burns residual oil with a sulfur content of 0.3% and 

hence satisfies the BART requirements for SO2. Therefore, no further analysis was required for this 

pollutant. 

3.2 Candidate NOx Emission Controls 

Several emission control options for NOx are discussed below. The current NOx controls for the three 

BART-eligible boilers consist of close-coupled overfire air systems and low NOx burners. 

Combustion Controls: Firing Configuration and Firing Practices 

Firing configuration and firing practices can result in a reduction in NOx formation, with the reduction 

percentage being very boiler-specific. Firing configuration is a design characteristic of the boiler. 

Firing practices include such things as low excess air, staged combustion, low NOx burners, and fuel 

substitution/alteration. Ravenswood Units 10, 20 and 30 are currently equipped with these controls. 

Operating at low excess air involves reducing the amount of combustion air to the lowest possible 

level while maintaining efficient and environmentally compliant boiler operation. NOx formation is 

inhibited because less oxygen is available in the combustion zone. These methods may change the 

normal operation of the boiler and the effectiveness is boiler-specific. Implementation of these 

techniques may also reduce operational flexibility; however, they may reduce NOx by 10-20% from 

uncontrolled levels. 

Low NOx burners are designed to control fuel/air mixing and increase heat dissipation. These 

alternative burners can be installed on new boilers or retrofitted on older units, and this is an option 

being considered for the BART analysis. 

Fuel substitution requires burning fuel with a lower nitrogen content to inhibit the production of fuel 

NOx. The lower the content of nitrogen in a fuel, the lower the resultant NOx emissions will be. One

candidate option for this control is the use of lower-nitrogen fuel oil. A switch to natural gas firing only 

is not allowed due to the need for Ravenswood to be available for system reliability and the Minimum 

Oil Rule. 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station

3-2

Overfire Air 

Overfire air involves injecting a portion of the total combustion air above the burners. Overfire air

limits NOx by (1) suppressing thermal NOx by partially delaying and extending the combustion 

process resulting in less intense combustion and cooler flame temperatures; (2) a reduced flame 

temperature that limits thermal NOx formation, and/or (3) a reduced residence time at peak 

temperature which also limits thermal NOx formation. Overfire air can reduce NOx emissions for both 

oil and natural gas firing by 20-30%. Separated overfire air systems introduce the injected 

combustion air some distance above the burners, while close-coupled overfire air systems (currently 

installed) introduce the air immediately above the burners. 

Selective Non-Catalytic Reduction (SNCR) 

SNCR is a post-combustion technique that involves injecting ammonia or urea into specific 

temperature zones in the upper furnace or convective pass. The ammonia or urea reacts with NOx in 

the flue gas to produce nitrogen and water. The effectiveness of SNCR depends on the temperature 

where reagents are injected; mixing of the reagent in the flue gas; residence time of the reagent within 

the required temperature window; ratio of reagent to NOx and the sulfur content of the fuel that may 

create sulfur compound that deposit in the downstream equipment. In general, SNCR results in NOx 

reductions on the order of 25-40% from high uncontrolled emission rates. 

Selective Catalytic Reduction (SCR) 

SCR is another post-combustion technique that involves injecting ammonia into the flue gas in the 

presence of a catalyst to reduce NOx to nitrogen and water. The SCR reactor can be located at 

various positions in the process including before an air heater and particulate control device, or 

downstream of the air heater, particulate control device, and flue gas desulfurization systems. 

The performance of SCR is greatly influenced by flue gas temperature, fuel sulfur content, ammonia 

to NOx ratio, inlet NOx concentration, space velocity, and catalyst condition. NOx emission 

reductions of 75-90% have been achieved through the use of SCR on oil-fired boilers operating in the 

U.S. 

Use of Distillate Oil 

Distillate oil has inherently less fuel-bound nitrogen than residual oil. The resultant NOx emission rate 

for switching to distillate oil is about 0.10 lb/MMBtu (with the use of Low NOx Burners). 

3.2.1 Effectiveness of Technically Feasible NOx Controls 

Based on information provided by equipment vendors, it is estimated that LNB/SOFA will reduce NOx 

emissions to a 24-hour averaged emission level of approximately 0.17 lb/MMBtu. Due to the lower 

inlet NOx concentrations, it is estimated that the addition of SNCR will reduce NOx emissions by 

another 15% (post advanced combustion controls), which corresponds to a NOx emission level of 

approximately 0.15 lb/MMBtu. SCR is estimated to reduce NOx emissions to approximately 0.025 

lb/MMBtu. Table 3-1 presents the control efficiencies of the technically feasible NOx control options. 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station

3-3

Table 3-1: Control Efficiency of Technically Feasible NOx Control Options 

Control 

Option 

Control 

Technology 

Inlet NOx 

(lb/MMBtu) 

Outlet NOx 

(lb/MMBtu) 

Control Efficiency 

(%) 

1 LNB/SOFA 0.24 0.17 29% 

2 LNB/SOFA and 

SNCR 0.17 0.15 12% from 0.17 lb/MMBtu 

3 LNB/SOFA and 

SCR 0.17 0.025 85% from 0.17 lb/MMBtu 

4 Low sulfur 

distillate fuel oil 0.24 0.1 58% 

3.2.2 Analysis of Alternative NOx Controls 

The alternative control technologies available to control NOx emissions from Units 10, 20, and 30 are 

LNB/SOFA, SNCR, SCR, and switching to distillate fuel oil. This section documents the economic, 

non-air environmental, and energy impacts associated with applying LNB/SOFA, LNB/SOFA and 

SNCR as well as LNB/SOFA and SCR to Ravenswood Units 10, 20, and 30. Incremental annual 

operating costs associated with switching to distillate oil are also reviewed in this section. 

3.2.2.1 Control Costs 

Table 3-2 summarizes the total capital and annual costs associated with applying LNB/SOFA, SCR, 

and SNCR to Units 10, 20 and 30 together. The costs presented in this section were provided by 

TransCanada, 

Table 3-2: Total Capital and Annual Costs Associated with LNB/SOFA SNCR, SCR, and Fuel Switching 

for Ravenswood Units, 10, 20, and 30 

3.2.2.2 Non Air Quality Environmental Issues 

One of the most significant consequences of retrofitting SCR at the facility is the addition of 

ammonia storage and handling systems. An accidental release of ammonia would pose a risk to 

workers and the public (especially in a highly urbanized area, as around the Ravenswood plant 

vicinity), and is reportable to local, state, and federal agencies. If ammonia at a concentration 

greater than 19% is stored at the site, Ravenswood would need to develop, implement, and 

Control 

Option

Control 

Technology

Total 

Capital Cost 

($)

Annual Fixed 

Costs 

($/yr)a

Annual O&M 

Costs 

($/yr)

Total Annual 

Costs 

($/yr)

NOx 

Controlled 

(tons/year)

Overall Cost 

Effectiveness 

($/ton removed)

Incremental Cost 

Effectiveness from 

Option 1 ($/ton 

removed)

1 LNB/SOFA $13,808,000 $2,518,000 $102,000 $2,620,000 1,626 $1,612

2

LNB/SOFA 

and SNCR $24,527,000 $4,473,000 $3,244,000 $7,717,000 2,092 $3,688 $10,924

3

LNB/SOFA 

and SCR $458,808,000 $88,193,326 $1,796,341 $89,989,666 5,008 $17,968 $25,829

4

Low sulfur 

distillate fuel 

oil

--- --- $104,338,496 $104,338,496 3,266 $31,947 $62,009

(a) Annualized capital costs based on a CRF of 0.1424, assuming an interest rate of 7% and amortization period of 10 years.
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Five Factor BART Analysis for TransCanada Ravenswood Generating Station

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maintain a Risk Management Plan (RMP) and Process Safety Measures (PSM) Program. Risk 

communication to the general public typically includes a worst-case analysis with potential effects 

possible at up to a mile from the facility. 

Theoretically, one mole of ammonia will react with one mole of NOx, forming elemental nitrogen and 

water in both SCR and SNCR. In reality, not all the injected reagent will react due to imperfect mixing, 

uneven temperature distribution, and insufficient residence time. These physical limitations may be 

compensated for by injecting a larger amount of ammonia than stoichiometrically required and 

essentially achieving lower NOx emissions at the expense of ammonia slip (unreacted ammonia). 

Typically, the average guaranteed ammonia slip associated with SCR is approximately 2 to 10 ppmvd 

at 3% O2, while that associated with SNCR is approximately 5 ppmvd to 20 ppmvd at 3% O2. This 

excess ammonia may react with SO3 or H2SO4 in the flue to form ammonium bisulfate ((NH4)2HSO4) 

and ammonium sulfate ((NH4)2SO4). These ammonium salts may condense as the flue gases cool 

and can lead to increased emissions of both PM10 and PM2.5. Furthermore, in SCR systems, the 

catalyst promotes partial oxidation of SO2 to SO3, which in turn increases the formation of ammonium

bisulfate and ammonium sulfate. The enhanced formation of these ammonia salts further increases 

the potential emissions of PM10 and PM2.5. 

Table 3-3 summarizes the non-air quality environmental effects associated with the proposed BART 

control options. 

Table 3-3: Summary of Non Air Quality Environmental Effects 

Control Alternative Summary of Non-Air Quality Environmental Effects

LNB/SOFA • No significant impacts. 

SNCR • Deliveries of the reagent will result in NOx, VOC, CO, CO2, and PM10

air emissions. 

• Excess ammonia slip reacts with SO3 or H2SO4 in the flue to form 

ammonium bisulfate (NH4)HSO4 and ammonium sulfate (NH4)2SO4

resulting in increased PM10 emissions. 

• Ammonium bisulfate and ammonium sulfate in the flue gas can cause 

various power plant operating and maintenance problems including 

fouling and corrosion of heat transfer surfaces in the air pre-heater. 

SCR • Addition of ammonia handling systems. Ammonia is considered 

dangerous to human health, and accidental releases must be 

reported to local, state, and federal agencies. 

• SCR will increase sulfuric acid mist emissions. 

• Excess ammonia slip reacts with SO3 or H2SO4 in the flue to form 

ammonium bisulfate (NH4)HSO4 and ammonium sulfate (NH4)2SO4

resulting in increased PM10 emissions. 

• Ammonium bisulfate and ammonium sulfate in the flue gas can cause 

various power plant operating and maintenance problems including 

fouling and corrosion of heat transfer surfaces in the air pre-heater. 

• The site must develop, implement, and maintain a Risk Management 

Plan (RMP) and Process Safety Measures (PSM) Program. 

• Deliveries of ammonia will result in NOx, VOC, CO, CO2, and PM10 air 

emissions. 

 
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3.2.2.3 Energy Impacts 

SCR would consume significantly more electrical energy than any of the other BART options, 

including SNCR. The higher electrical energy consumption for SCR is primarily due to the increased 

fan static pressure required to overcome the pressure drop across the catalyst bed, as well as for 

pumps and evaporator blower. For example, assuming a pressure drop of 14 inches water gauge 

(W.G.) across new duct work and the catalyst bed, SCR applied to all three units could consume 

approximately 1% of the total power generation of the plant for each hour of operation. The increased

emissions of pollutants required to maintain the net electrical output is a negative aspect of SCR 

deployment. 

3.2.2.4 Remaining Useful Life 

TransCanada anticipates that the Ravenswood Units 10, 20 and 30 will remain in operation for at 

least the next 10 years. A 10-year amortization period was used for purposes of the cost 

effectiveness for the BART analysis which is consistent with the procedures outlined in NYSDEC’s 

Air Guide 20 (Economic and Technical Analysis for Reasonably Available Control Technology). 

Note that for an SCR, the catalyst has a shorter useful life of 5 years. Hence, the catalyst 

replacement cost was amortized over a 5 year period. 

Emissions of NOx post LNB/SOFA (Control case 1) are presented in Table 3-6. 

3.3 Candidate PM Emission Controls 

The PM control technologies identified as available for retrofit to the Ravenswood Units 10, 20, and 30 

are: 

• Fabric Filter (Baghouse) 

• Dry Electrostatic Precipitator (ESP) 

• Wet Electrostatic Precipitator (WESP) 

• Switching to Low Sulfur Distillate Oil 

These control technologies are reviewed below in the context of their effectiveness in further reducing 

PM emissions. 

Fabric Filter 

In a fabric filter, flue gas passes through a tightly woven or felted fabric, causing particles in the gas to 

be collected on the fabric by sieving, electrostatic attraction, and other mechanisms. Fabric filters may 

be in the form of sheets, cartridges or, most commonly, bags. The dust cake that forms on the filter 

from the collected PM can significantly increase collection efficiency. Fabric filters are frequently

referred to as baghouses because the fabric is usually configured in cylindrical bags. Groups of bags

are placed in isolable compartments to allow cleaning of the bags or replacement of some of the bags 

without shutting down the entire fabric filter. 

Because of the sticky and hygroscopic nature of residual oil fly ash, fabric filters have never been 

applied to oil-fired units, unless the bags are first pre-conditioned by means of dry sorbent injection 

upstream of the baghouse for SO2 control. A fabric filter baghouse, therefore, is not considered 

technically feasible for application to the Ravenswood BART units. 
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Five Factor BART Analysis for TransCanada Ravenswood Generating Station

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Dry Electrostatic Precipitator 

An ESP uses electrical forces to move particles entrained within the exhaust stream onto collector 

plates. The entrained particles are given an electrical charge when they pass through the corona, a 

region where gaseous ions flow. Electrodes in the center of the gas stream are maintained at high 

voltage and generate the electrical field that forces the particles to the collector plates. The collector 

plates are periodically knocked or "rapped" by various mechanical means to dislodge the particulate, 

which slides downward into a hopper and is collected. The collection hopper is evacuated 

periodically, as it becomes full. The particulate is removed through a rotary valve into an ash-handling 

system, such as a pneumatic conveyor, and is then disposed of. 

Although dry ESPs have been attempted for application to oil-fired utility boilers, they routinely 

experience problems in dislodging the particles from the collection plates because of the sticky and 

hygroscopic nature of the fly ash. Ash generated by residual oil combustion is rich in elemental 

carbon (soot) which has a low resistivity. As a result, the ash particles do not adhere to the plates as 

well and re-entrainment issues occur. Furthermore, the high capital and operating costs of this control 

technology make it economically infeasible (see Table 3-4). 

Wet Electrostatic Precipitator 

A wet ESP collects particles based on the same theory as a dry ESP, where negatively charged 

particles are collected on positively charged surfaces. In a wet ESP, however, the collecting surfaces 

are wet instead of dry and are flushed with water to remove the particulate. Typically, a wet ESP is 

installed downstream of an existing wet flue gas desulfurization (FGD) system where the flue gas is 

already saturated to minimize water consumption. The particulate collection efficiency is enhanced by

preventing re-entrainment after contact with the wet walls, compared with re-entrainment due to 

rapping on a dry ESP. Due to this feature, wet ESPs are well suited for the removal of fine particulate 

or acid mist from the gas stream. 

Several major hurdles exist with the use of a wet ESP. First, the flue gas must be saturated with 

moisture prior to entering the wet ESP to allow the unit to work as desired. This requires that a 

quenching system be installed to add water to the flue gas to reduce the flue gas temperature to the 

saturation point. Without the presence of a wet FGD system, the wet ESP adds additional cost, 

increases water demand on the plant, and generates a visible moisture plume at the stack outlet. The 

removed particulate would also be contained in a wastewater stream that is generated by the wet 

ESP. In addition to this issue, the capital and operating cost of a wet ESP is very high as compared to 

other technologies due to the high cost of the alloy materials required. A higher grade of material is 

required to withstand the highly corrosive conditions presented by the wet and acidic flue gas stream 

(Table 3-5). 

Because the flue gas must be saturated before entering a wet ESP, these devices are usually applied 

to combustion installations equipped with either a Venturi scrubber for PM control or a wet FGD 

system for acid gas control. Consequently, wet ESPs have never been applied to oil-fired boilers as 

standalone units. 
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Switching to Distillate Fuel Oil 

Distillate oil has a much lower sulfur content that residual oil and consequently has lower PM 

emissions as compared to those resulting from residual oil combustion. This option is technically 

feasible for the control of PM emissions from the Ravenswood units. 

Table 3-4 presents the control efficiencies of the technically feasible PM control options. Table 3-5

presents the cost effectiveness ($/ton) of the technically feasible PM control options. 

Table 3-4: Control Efficiency of Technically Feasible PM Control Options 

Control Option Control Technology Control Efficiency (%) 

1 Dry Electrostatic Precipitator (1) 99% 

2 Wet Electrostatic Precipitator (2) 99% 

3 Switching to Distillate Fuel Oil (3) 65% 

(1) Control efficiency of Dry ESPs based on EPA's Air Pollution Control Technology Fact Sheet (EPA452/F-03-028). 

(2) Control efficiency of Wet ESPs based on EPA's Air Pollution Control Technology Fact Sheet (EPA452/F-03-029). 

(3) Based on AP-42 PM Emission Factors for residual oil combustion and distillate oil combustion (Table 

1.3-1). 

Table 3-5: Cost Effectiveness of Technically Feasible PM Control Options 

Control 

Option 

Control 

Technology 

Control 

Efficiency (1) 

(%) 

Annual Cost 

($/year) 

Tons PM 

Controlled 

(tons/year) 

Cost 

Effectiveness 

($/ton) 

1 Dry Electrostatic 

Precipitator (2) 99% $122,071,000 920 $132,650 

2 Wet Electrostatic 

Precipitator (3) 99% $166,831,200 920 $181,280 

3 Switching to 

Distillate Fuel Oil (4) 65% $109,338,500 596 $174,970 

(1) For the dry and wet ESPs, a conservatively high control efficiency of 99% was assumed for conducting the cost 

effectiveness analysis. 

(2) Annualized cost of Dry ESPs (all three units combined) based on EPA's Air Pollution Control Technology Fact 

Sheet (EPA-452/F-03-028). Detailed calculations presented in Appendix A. 

(3) Annualized cost of Wet ESPs (all three units combined) based on EPA's Air Pollution Control Technology Fact 

Sheet (EPA-452/F-03-029). Detailed calculations presented in Appendix A. 

(4) Annual incremental cost of using distillate oil based on Annual Energy Outlook 2010, Report No. DOE/EIA-0383 

2010, Reference Case, http://www.eia.doe.gov/oiaf/aeo/index.html. Detailed calculations presented in Appendix A. 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station Table 3-6: Ravenswood NOx Advanced Combustion Controls Emissions (Control Case 1) 
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4.0 Meteorological Data used in Visibility Improvement 

Modeling 

This section discusses two meteorological CALMET databases for year 2002 that were used for the 

Ravenswood BART modeling. The first CALMET database was prepared by AECOM and the second 

was prepared by the Vermont Department of Environmental Conservation (VT DEC). Both databases 

are approved by NYSDEC and the Federal Land Managers (FLMs). NYSDEC requires that visibility 

impacts from BART eligible units are predicted using both CALMET databases. 

The extents of the two CALMET domains are shown in Figure 4-1. Table 4-1 summarizes major 

differences between two databases. 

4.1 Elements of the Refined Analysis 

AECOM has recently developed a more refined CALMET database than the VT DEC CALMET 

database. 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”, including a choice of the model critical settings, meteorological stations, geophysical and Fifth 

Generation Mesoscale Model (MM5) data. The VT DEC CALMET database is described in Appendix 

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

Source Attribution Studies in the Northeast U.)”. The document is available on the web at 

http://www.nescaum.org/documents/contributions-to-regional-haze-in-the-northeast-and-midatlantic--united-states/. 

AECOM database has several major improvements over the VT DEC database, such the grid size 

resolution, vertical levels, and inclusion of the prognostic MM5 data. CALMET database produced by 

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. This area covers the entire eastern and part of central United 

States, but its large size limits the horizontal resolution of each grid element to 36 km. This coarse 

grid resolution, without further refinement, can be deemed appropriate for a screening-level analysis,

but it would not be considered appropriate for a more refined analysis. 

AECOM developed a refined meteorological database that included a modeling domain 

encompassing the seven Class I areas (required by NYSDEC) and the appropriate buffers around 

Class I areas for puffs recirculation. This domain covers approximately a 1,052 km (east-west) by 

1,300 km (north-south) area, has a grid resolution of 4 km (9 times better than the VT DEC database 

in both east-west and north-south directions), and contains 11 vertical levels. In addition, the refined 

AECOM database utilizes the 12-km MM5 data and uses the latest official USEPA-approved CALMET 

Version 5.8, developed in year 2007. In contrast, VT DEC CALMET was run with the older version of 

the model, developed in year 2003. 

Table 4-1 summarizes critical CALMET settings used in the two databases. 

 
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Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

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Figure 4-1: Ravenswood CALMET Modeling Domains 

 
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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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5.0 CALPUFF Modeling Procedures 

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

analysis conducted for the Ravenswood Generating Station. 

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. 

The extents 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 emissions, 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 the 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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Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

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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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6.0 CALPUFF Modeling and BART Determination Results 

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

emissions and visibility improvement as a result of BART controls on Ravenswood Units 10, 20, and 

30. It also presents the results of the recommended BART determination. 

6.1 Modeled Control Scenarios 

Both the AECOM and VT DEC CALMET databases were used to model the baseline emissions 

along with the advanced combustion control emission case. Tables 2-1 and 3-6 present the 

emissions associated with the baseline and one BART control case, respectively.

6.2 Modeling Results for Baseline Emissions 

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

Table 6-1. Modeling was conducted with two CALMET databases for year 2002. For each Class I 

area and CALMET database, Table 6-1 lists the number of days above 0.1, 0.5 and 1.0 delta-deciview 

due to plant baseline emissions as well as the maximum and the 8th highest delta-deciview. Table 6-1 

indicates that the higher visibility impacts occur at Brigantine Wilderness and they are due to that 

park’s relative proximity to Ravenswood. The results also show that the visibility impacts predicted 

with the VT DEC CALMET database are much higher than with the AECOM CALMET database. As 

discussed in Section 4.1, VT DEC CALMET database is not as refined as the AECOM database. We 

conclude that the visibility impacts predicted with the AECOM database are more realistic. 

In general, however, even the AECOM database regional haze impacts using CALPUFF are 

overstated, for the reasons noted below. 

1) The CALPUFF base case modeled scenario is always a worst-case emission rate which is 

assumed to occur every day. The actual emissions are often lower, and so the modeled 

improvement is an overestimate. 

2) The manner in which the daily haze predictions are accounted for in the CALPOST output 

overstates the impact for even a perfect model. The way CALPOST works is that the peak 

24-hour prediction anywhere in a Class I area is the only information saved for each predicted 

day. 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. For very small Class I 

areas, this is not as big of a concern as for large Class I areas. 

3) It is well known that CALPUFF is not a perfect model, and that transport during a full diurnal 

cycle (or especially during evenings) in which significant wind direction shear can occur (and 

is not properly accounted for by CALPUFF) can result in plumes that are too compact. 

4) We know that nitrate predictions are often overstated, especially in winter, unless 

appropriately low ammonia background values are selected for the currently approved 

version of CALPUFF. 
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5) The rate of plume dispersion default option is technically flawed. A better option for 

CALPUFF is the “turbulence-based” dispersion. There are many reasons why it is technically 

superior, but the older Pasquill-Gifford dispersion provides higher impacts because the plume 

reaches the ground in stable conditions much faster, so it is therefore preferred by EPA and 

the FLMs. 

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 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 

8

th highest day at each modeled Class I area. 

The results of the baseline emissions analysis indicate that each Ravenswood unit and all three units 

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

at least one Class I area. Therefore, the Ravenswood Generating Station is presumed to be subject 

to BART because its emissions may reasonably be anticipated to cause or contribute to visibility 

impairment at a relevant Class I area. Candidate BART controls are discussed in Section 3. The 

results of the visibility improvement modeling for the candidate controls are discussed in the next 

section. 

Table 6-1: Regional Haze Impacts due to Baseline Emissions 

 

 
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6.3 Modeling Results for the Advanced Combustion Control Case 

Maximum daily CALPUFF modeling results for the BART control option at the seven Class I areas 

due to emission from Ravenswood Units 10, 20, and 30 separately and combined are presented in 

Table 6-2. Consistent with the baseline results reported above, modeling was conducted with 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 summarized in Table 6-2. 

Emission rates that were used in this modeling are presented in Table 3-1. 

The results show that with the installation of LNB/SOFA controls, the maximum visibility improvement 

would be about 0.12 delta-deciview (relative to the baseline case, at Lye Brook Wilderness). The 

maximum change in visibility (for each Class I area and over the two CALMET databases) from the 

current operations was combined with the cost impact of controls relative to current operations to 

calculate the dollars per deciview cost. These results are presented in Table 6-3. 

Table 6-2: Regional Haze Impacts due to Advanced Combustion Controls (Control Option 1) 

6.4 Conclusions and BART Recommendation 

Table 6-3 presents the visibility improvements offered by LNB/SOFA at the seven Class I areas and 

the associated costs of applying the control technology (dollars/deciview). 
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Table 6-3: Cost Effectiveness and Visibility Improvement Associated with Control Option 1 

Installation of LNB/SOFA offer modest visibility improvements at the seven Class I areas. Even 

though retrofitting the boilers with LNB/SOFA is not cost effective, this option is accepted by 

TransCanada for controlling NOx emissions based on NY RACT requirements and the reasonable 

$/ton cost effectiveness. Therefore, BART for NOx is installation of advanced combustion controls 

(LNB/SOFA) to limit emissions to 3,018 lb/hr (0.17 lb/MMBtu) for all three units combined on a 24-

hour rolling average basis., 

BART for SO2 is burning residual oil with a sulfur content of 0.3% which is well below the NYSDEC 

BART guideline which is 1.0% S. 

BART for PM is burning residual oil with a sulfur content of 0.3% and the current permit limit. 

Class I Area Control Option Max Deltadeciview

Annualized 

Cost for Units 

10,20,30 

($/year)

Deciview Reduction 

Relative to Baseline 

(dv)

Cost Effectiveness 

Relative to 

Baseline ($/dv)

Baseline 3.82 - $ - -

LNB&SOFA 3.75 2,620,000 $ 0.07 35,890,411 $ 

Baseline 3.11 - $ - -

LNB&SOFA 3.07 2,620,000 $ 0.04 74,857,143 $ 

Baseline 3.14 - $ - -

LNB&SOFA 3.02 2,620,000 $ 0.12 21,652,893 $ 

Baseline 3.30 - $ - -

LNB&SOFA 3.27 2,620,000 $ 0.04 67,179,487 $ 

Baseline 2.02 - $ - -

LNB&SOFA 1.99 2,620,000 $ 0.03 77,058,824 $ 

Baseline 1.98 - $ - -

LNB&SOFA 1.94 2,620,000 $ 0.03 77,058,824 $ 

Baseline 4.08 - $ - -

LNB&SOFA 4.02 2,620,000 $ 0.06 46,785,714 $ 

Acadia National Park

Dolly Sods 

Wilderness

Brigantine 

Wilderness

Great Gulf 

Wilderness

Lye Brook 

Wilderness

Presidential Range - 

Dry River Wilderness

Otter Creek 

Wilderness
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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. 

EPRI. Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, EPRI, Palo Alto, CA: 

2008. 1016384. 

New York Independent System Operator, Inc., Docket No. ER07-748-000, Issued May 11, 2007 by 

the Federal Energy Regulatory Commission. 

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 TransCanada Ravenswood Generating Station September 2010 

Appendix A 

Cost Effectiveness 

Calculations 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

Appendix B 

Quotation from Fuel Tech for 

LNB/SOFA and SNCR 
AECOM Environment 

Five Factor BART Analysis for TransCanada Ravenswood Generating Station September 2010 

Appendix C 

Modeling Archive