NRG Energy 

Oswego Power Station 

Reasonably Available Control Technology 

and 

Best Available Retrofit Technology 

Engineering Evaluation 

FINAL REPORT 

Prepared by: Sargent & Lundy LLC 

Chicago, Illinois

July 26, 2010 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

Approval and Certification Page 

NRG 

OSWEGO GENERTING STATION UNITS 5 & 6 

RACT / BART ENGINEERING EVALUATION 

ISSUE SUMMARY, APPROVAL AND CERTIFICATION PAGE

This is to confirm that the this report has been prepared, reviewed and approved in accordance with 

Sargent & Lundy’s Standard Operating Procedure SOP-0405, which governs the preparation, review 

and approval of Miscellaneous Engineering and Design Deliverables, which is part of our Quality 

Management System. 

Issue 

Purpose

Issue 

Date Prepared By Reviewed By Approved By

Record 06-16-2010 

 

D Helm 

G Dusatko 

 

K Snell 

 

S McHone 

FINAL 07/26/2010 

 

D Helm 

G Dusatko 

 

K. Snell 

 

S. McHone 

 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

ES-1 

EXECUTIVE SUMMARY 

NRG owns and operates the Oswego Power Station (Oswego Station) located on a 93-acre site in 

Oswego, New York, along the south shore of Lake Ontario. The station consists of two (2) oilfired steam electric generating units, four retired units, and the supporting ancillary equipment 

and operations needed for operation of the boilers, including an oil storage tank farm and 

associated rail facilities. 

Oswego Units 5 & 6 are Foster-Wheeler boilers designed to fire No. 6 fuel oil. The units are 

rated at 870 MW (gross) each with 6,300,000 lb/hr main steam flow at 2,480 psig pressure and 

1,005 o

F temperature, and a reheat flow of 5,722,000 lb/hr at 705 psig outlet pressure and 1,005 

o

F. Both units are equipped with an electrostatic precipitator (ESP) for particulate control. 

The federal Clean Air Act (CAA) requires states with nonattainment areas (i.e., areas that do not 

meet the federal national ambient air quality standards) to develop a State Implementation Plan 

(SIP) to “provide for the implementation of all reasonably available control measures as 

expeditiously as practicable (including such reductions in emissions from existing sources in the 

area as may be obtained through the adoption, at a minimum, of reasonably available control 

technology) and shall provide for attainment of the national primary ambient air quality 

standards.” (CAA §172(c)(1)). EPA’s rules implementing §172(c)(1) of the CAA require states 

to demonstrate, through a SIP submission, that their RACT requirements address emissions 

contributing to nonattainment, and effectively work toward achieving compliance with the 

applicable NAAQS. The New York RACT rules are located in 6 NYCRR 227-2. In general, the 

RACT rules limit NOx emissions from combustion sources and are designed to address ozone 

nonattainment. 

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the 

“Regional Haze Rule” 70 FR 39104). The Regional Haze Rule requires states to develop 

programs to assure reasonable progress toward meeting the national goal of preventing any 

future, and remedying any existing, impairment of visibility in Class I Areas. The Regional Haze 

Rule requires states to submit a plan to implement the regional haze requirements (the Regional 

Haze SIP). The Regional Haze SIP must provide for a Best Available Retrofit Technology 

(BART) analysis of any existing stationary facility that might cause or contribute to impairment 

of visibility in a Class I Area. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

ES-2 

BART is required for any BART-eligible source that emits any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. 

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 

“Guidelines for BART Determinations Under the Regional Haze Rule,” (the “Appendix Y 

Guidelines”). States are required to use the Appendix Y Guidelines to make BART 

determinations for fossil-fuel-fired generating plants having a total generating capacity in excess 

of 750 MW. Because the generating capacity of BART-eligible sources at the Oswego Station is 

greater than 750 MW, from a federal perspective, conformance with the Appendix Y Guidelines 

is required. 

The BART determination process described in the Appendix Y Guidelines includes the following 

steps: 

Step 1. Identify All Available Retrofit Control Technologies. 

Step 2. Eliminate Technically Infeasible Options. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 4. Evaluate Impacts and Document the Results. 

Step 5. Evaluate Visibility Impacts. 

This engineering report was prepared to support the Oswego Unit 5 & 6 RACT compliance 

evaluation and BART determination, focusing on the control of NOx emissions from both units. 

This evaluation follows the BART determination process described the Appendix Y Guidelines, 

and includes the information and evaluations required by Steps 1 through 4 of the BART 

determination process. The report reviews baseline NOx emissions from each units, identifies 

and evaluates the technical feasibility of potential NOx retrofit control options, and provides 

budgetary cost estimates and calculates the cost-effectiveness of each technically feasible NOx 

control technology. Tables ES-2 and ES-2 provide a summary of the technically feasible NOx 

control options, including: (1) annual emission reductions achievable with each technology 

(compared to baseline annual NOx emissions); (2) total annual costs associated with the 

installation and operation of each technology; and (3) the average cost-effectiveness of each 

technology. 

Based on the evaluation of capital costs, operating costs, and annual emission reductions included 

herein, none of the technically feasible and available NOx control options are cost effective on 

Oswego Units 5 & 6. Several site-specific factors contribute to this result. First, there are 

significant capital requirements associated with the post-combustion control systems, including 

selective catalytic reduction (SCR), fuel lean gas reburn (FLGR), and selective non-catalytic 

reduction (SNCR). Both equipment costs and retrofit challenges contribute to these capital costs. 

Capital costs of post-combustion control range from approximately $11.3/kW-gross (SNCR with 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

ES-3 

combustion control modifications) to as high as $122.8/kW-gross (SCR). Capital costs associated 

with combustion control system modifications are significantly less ranging from $2.8/kW-gross 

(with pressure atomization) to $7.0/ton (with steam atomization). 

More importantly, baseline annual NOx emissions from both units are only in the range of 

approximately 240 tpy. Baseline annual NOx emissions are low because of the low capacity 

factors achieved by both units during the baseline period. Both units have had capacity factors of 

3.2% or less during the baseline period, and, in fact, neither unit has had a capacity factor above 

10% since 2001. 

Finally, both units are currently equipped with low-NOx combustion controls, including LNREACH, overfire air (OFA), and flue gas recirculation (FGR) controls, and both units already 

achieve relatively low NOx emission rates (i.e., baseline NOx emission rates for Oswego Units 5 

& 6 are 0.22 lb/mmBtu and 0.19 lb/mmBtu, respectively). Low baseline NOx emission rates, 

coupled with the low unit capacity factors, result in baseline annual NOx emissions of only about 

240 tpy from each units. The low baseline NOx emission rates contribute significantly to the 

high cost-effectiveness of potential retrofit NOx control technologies. Assuming the units 

continue to operate at low capacity factors, none of the potential NOx control systems, including 

combustion modifications, would be cost effective. 

Table ES-1 

Summary of NOx BART Cost Effectiveness Analysis – Oswego Unit 5 

Control Technology 

Controlled 

Annual 

Emissions 

(tpy) 

Annual 

Emission 

Reductions 

(tpy) 

Total Annual 

Costs 

($/year) 

Average Cost 

Effectiveness 

($/ton) 

SCR 33.0 209.1 $15,288,000 $73,113 

LN-REACH (steam atomizer) plus 

modified OFA and FLGR 

132.1 110.0 $4,116,300 $37,421 

LN-REACH (steam atomizer) plus 

modified OFA plus SNCR 

143.1 99.0 $2,197,200 $22,194 

LN-REACH (pressure atomizer) plus 

modified OFA and FLGR 

143.1 99.0 $3,603,700 $36,401 

LN-REACH (pressure atomizer) plus 

modified OFA plus SNCR 

154.1 88.0 $1,684,400 $19,141 

LN-REACH (steam atomizer) plus 

modified OFA 

187.1 55.0 $900,500 $16,873 

LN-REACH (pressure atomizer) plus 

modified OFA 

198.1 44.0 $384,500 $8,748 

Optimize LNB/OFA/FGR with 

Neural Network Control System 

231.1 11.0 $470,900 $42,809 

Baseline LNB/OFA/FGR 242.1 -- -- -- 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

ES-4 

Table ES-2 

Summary of NOx BART Cost Effectiveness Analysis – Oswego Unit 6 

Control Technology 

Controlled 

Annual 

Emissions 

(tpy) 

Annual 

Emission 

Reductions 

(tpy) 

Total Annual 

Costs 

($/year) 

Average Cost 

Effectiveness 

($/ton) 

SCR 33.2 176.9 $15,288,000 $86,422 

LN-REACH (steam atomizer) plus 

modified OFA and FLGR 

132.7 77.4 $4,116,300 $53,182 

LN-REACH (steam atomizer) plus 

modified OFA plus SNCR 

143.8 66.3 $2,197,200 $33,140 

LN-REACH (pressure atomizer) plus 

modified OFA and FLGR 

143.8 66.3 $3,603,700 $54,354 

LN-REACH (pressure atomizer) plus 

modified OFA plus SNCR 

154.8 55.3 $1,684,400 $30,459 

LN-REACH (steam atomizer) plus 

modified OFA 

177.0 33.1 $900,500 $27,205 

LN-REACH (pressure atomizer) plus 

modified OFA 

188.0 22.1 $384,900 $17,416 

Optimize LNB/OFA/FGR with 

Neural Network Control System 

199.1 11.0 $470,900 $42,809 

Baseline LNB/OFA/FGR 210.1 -- -- -- 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

1 

1.0 INTRODUCTION 

1.1 NRG’s Oswego Power Station 

NRG owns and operates the Oswego Power Station (Oswego Station) located on a 93-acre site in 

Oswego, New York, along the south shore of Lake Ontario. The station consists of two (2) oil-fired 

steam electric generating units, four retired units, and the supporting ancillary equipment and 

operations needed for operation of the boilers, including an oil storage tank farm and associated rail 

facilities. 

Oswego Units 5 & 6 are Foster-Wheeler boilers designed to fire No. 6 fuel oil. The units are rated 

at 870 MW (gross) each with 6,300,000 lb/hr main steam flow at 2,480 psig pressure and 1,005 o

F 

temperature, and a reheat flow of 5,722,000 lb/hr at 705 psig outlet pressure and 1,005 o

F. Each 

unit has 32 burners located in the front wall of the furnace, arranged in four rows of eight. The 

burners are fed combustion air from a common windbox. Both units were designed for, and have, 

operational flue gas recirculation combustion control systems. Both units are equipped with an 

electrostatic precipitator (ESP) for particulate control. Unit 6 has the ability to co-fire natural gas, 

and is capable of generating up to 150 MW utilizing natural gas. 

Unit 5 was brought on-line in 1975. Unit 6 was brought on-line in 1980. Unit 6 is classified as a 

New Source Performance Standard (NSPS) unit, and was required, when it commenced operation, 

to meet the applicable standards in 40 CFR Part 60 Subpart Da. 

1.2 New York’s Reasonably Achievable Control Technology (RACT) Rule 

The federal Clean Air Act (CAA) requires states with nonattainment areas (i.e., areas that do not 

meet the federal national ambient air quality standards) to develop a State Implementation Plan 

(SIP) to “provide for the implementation of all reasonably available control measures as 

expeditiously as practicable (including such reductions in emissions from existing sources in the 

area as may be obtained through the adoption, at a minimum, of reasonably available control 

technology) and shall provide for attainment of the national primary ambient air quality standards.” 

(CAA §172(c)(1)). 

EPA’s rules implementing §172(c)(1) of the CAA require states to demonstrate, through a SIP 

submission, that their RACT requirements address emissions contributing to nonattainment, and 

effectively work toward achieving compliance with the applicable NAAQS. The New York RACT 

rules are located in 6 NYCRR 227-2. In general, the RACT rules limit NOx emissions from 

combustion sources and are designed to address ozone nonattainment. 
NRG Energy July 26, 2010 

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Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

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1.3 The Regional Haze Rule 

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the 

“Regional Haze Rule” 70 FR 39104). EPA issued the Regional Haze Rule under the authority and 

requirements of sections 169A and 169B of the Clean Air Act (CAA). Sections 169A and 169B 

require EPA to address regional haze visibility impairment in 156 federally-protected parks and 

wilderness areas (Class I Areas). As mandated by the CAA, the Regional Haze Rule requires 

certain large stationary sources to install the best available retrofit technology (BART) to reduce 

emissions of pollutants that may impact visibility in a Class I Area. 

The Regional Haze Rule requires states to develop programs to assure reasonable progress toward 

meeting the national goal of preventing any future, and remedying any existing, impairment of 

visibility in Class I Areas. The Regional Haze Rule requires states to submit a plan to implement 

the regional haze requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a 

BART analysis of any existing stationary facility that might cause or contribute to impairment of 

visibility in a Class I Area. To address the requirements for BART, New York must: 

3⁄4 Identify all BART-eligible sources within the State. 

3⁄4 Determine whether each BART-eligible source emits any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a 

Class I Area. BART-eligible sources which may reasonably be anticipated to cause or 

contribute to visibility impairment are classified as BART-applicable sources. 

3⁄4 Require each BART-applicable source to identify, install, operate, and maintain BART 

controls. 

The New York BART regulations are located in 6 NYCRR Part 249. 

1.4 Regulatory Applicability Review 

1.4.1 RACT Applicability 

The New York RACT Rules apply to owners or operators of major stationary sources listed in 6 

NYCRR 227-2.1, including large and very large boilers. The term “very large boiler” is 

defined to include boilers with a maximum heat input capacity greater than 250 mmBtu/hr. 

Both Units 5 & 6 meet the definition of a very large boiler, and are subject to the RACT 

requirements in 6 NYCRR 227-2. 
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Units 5 & 6 RACT/BART Engineering Study 

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1.4.2 BART Applicability Review 

BART-eligible sources include those sources that: 

(1) have the potential-to-emit 250 tons or more of a visibility-impairing air pollutant; 

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and 

(3) whose operations fall within one or more of the specifically listed source categories in 

40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 

mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input). 

Oswego Units 5 & 6 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. 

Both units were in existence, as that term is defined in 249.2(d) 1 prior to August 7, 1977, but 

not in operation prior to August 7, 1962. Based on baseline emissions data, summarized in 

Table 2-1, the units have the potential-to-emit more than 250 tons per year of visibility 

impairing pollutants. Therefore, both units meet the definition of a BART-eligible source. 

BART is required for any BART-eligible source that emits any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I 

Area. U.S.EPA has determined that an individual source will be considered to “contribute to 

visibility impairment” if emissions from the source result in a change in visibility, measured as 

a change in deciviews (∆-dv), that is greater than or equal to 0.5 dv in a Class I area. However, 

New York has determined that all BART-eligible sources are subject to the BART 

requirements without source-specific modeling demonstrating that the individual source causes 

or contributes to visibility impairment. Thus, Oswego Units 5 & 6 are subject to the New York 

BART determination requirements. 

1.5 Regulatory Requirements 

1.5.1 RACT Requirements 

The RACT control requirements applicable to Oswego Units 5 & 6 are included in 6 NYCRR 

Section 227-2.4. RACT requirements applicable to a particular emission source may fall into 

one of two categories: (1) presumptive RACT limits; or (2) case-by-case RACT determinations. 

Presumptive RACT limits are category-wide requirements based on NOx control capabilities 

 

1

 The term “in existence” is defined in subsection 249.2(d) as “the owner or operator has obtained all 

necessary preconstruction approvals or permits required by federal, state, or local air pollution emissions and 

air quality laws or regulation and either has (1) begun, or caused to begin, a continuous program of physical 

on-site construction of the facility or (2) entered into binding agreements or contractual obligations, which 

cannot be canceled or modified without substantial loss to the owner or operator, to undertake a program of 

construction of the facility to be completed in a reasonable time.” 
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Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

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4 

that are generally achievable within an emission source category. A case-by-case RACT 

determination sets a source-specific emission limit based on technical feasibility and economic 

impacts. 

The presumptive RACT limits applicable to Oswego Units 5 & 6 are included in subsection 

227-2.4(a): 

Prior to July 1, 2012

Gas/Oil Wall-Fired 0.25 lb/mmBtu 

On or after July 1, 2012

Gas/Oil Wall-Fired 0.15 lb/mmBtu 

In general, compliance with the presumptive RACT limits must be determined on a 24-hour 

average basis using a NOx continuous emissions monitoring system (CEMS); however, from 

October 1st to April 30th, a 30-day rolling average may be used to demonstrate compliance. 

For those sources for which the owner or operator demonstrates that the applicable presumptive 

RACT emission limit is not economically or technically feasible, the owner or operator can 

request NYDEQ to set a higher source-specific emission limit.2

 Economic or technical 

feasibility must be demonstrated through a case-by-case RACT analysis that includes, at a 

minimum, an evaluation of the use of fuel switching, the use of a system averaging plan, and 

implementation of any available control technologies. Each case-by-case determination that 

establishes source-specific RACT requirements must be submitted to the Administrator as a 

separate SIP revision. 

1.5.2 BART Requirements 

New York BART regulations are included in 6 NYCRR 249. Section 249.3 of the regulation 

requires that the owner or operator of a source that is determined to be BART-eligible3

 conduct 

an analysis to determine the appropriate emission limitation necessary to meet the BART 

requirements. A determination of BART must be based on an analysis of the best system of 

continuous emission control technology available and associated emission reductions 

achievable. The BART analysis must take into consideration: (1) technologies available; (2) 

costs of compliance; (3) energy and non-air-quality environmental impacts of compliance; (4) 

any pollution control equipment in use at the source; (5) the remaining useful life of the source; 

 

2

 See, 6 NYCRR subsection 227-2.5(c). 

3

 BART-eligible source are defined in Section 249.X as those units whose emissions of visibility-impairing 

pollutants result in a visibility impairment equal to or greater than 0.1 deciviews in any Federal Class I Area. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

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5 

and (6) the degree of improvement in visibility which may reasonably be anticipated to result 

from the use of such technology. 

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 

Guidelines for BART Determinations Under the Regional Haze Rule (the “Appendix Y 

Guidelines”). States are required to use the Appendix Y guidelines to make BART 

determinations for fossil-fuel-fired generating plants having a total generating capacity in 

excess of 750 MW. Because the generating capacity of BART-eligible sources at the Oswego 

Station is greater than 750 MW, from a federal perspective, conformance with the Appendix Y 

Guidelines is required. 

The Appendix Y guidelines for BART determinations identify the following five steps in a 

case-by-case BART analysis: 

Step 1. Identify All Available Retrofit Control Technologies. 

Step 2. Eliminate Technically Infeasible Options. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 4. Evaluate Impacts and Document the Results. 

Step 5. Evaluate Visibility Impacts. 

A brief description of each step, and its corresponding New York case-by-case RACT 

requirement, is provided below. 

Step 1. Identify all available retrofit control technologies. 

Available retrofit control options are those air pollution control technologies with a practical 

potential for application to the emissions unit and the regulated pollutant under evaluation (70 

FR 39164 col. 1). Step 1 of the BART determination requires applicants to identify potentially 

applicable retrofit control technologies that represent the full range of demonstrated 

alternatives. Potentially applicable retrofit control alternatives can include pollution prevention 

strategies, the use of add-on controls, or a combination of control strategies. Control 

technologies required under the New Source Review (NSR) program as Best Available Control 

Technology (BACT) or Lowest Achievable Emission Rate (LAER) are available for BART 

purposes and must be included as potential control alternatives. However, EPA does not 

consider BART as a requirement to redesign the source when considering available control 

alternatives. 

Step 2. Eliminate Technically Infeasible Options. 

In step 2 of the BART case-by-case determination, the technical feasibility of each potential 

retrofit technology is evaluated. Control technologies are considered technically feasible if 
NRG Energy July 26, 2010 

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Units 5 & 6 RACT/BART Engineering Study 

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6 

either (1) they have been installed and operated successfully for the type of source under review 

under similar conditions, or (2) the technology could be applied to the source under review. A 

demonstration of technical infeasibility must be based on physical, chemical and engineering 

principles, and must show that technical difficulties would preclude the successful use of the 

control option on the emission unit under consideration. The economics of an option are not 

considered in the determination of technical feasibility/infeasibility. Options that are 

technically infeasible for the intended application are eliminated from further review. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 3 of the BART determination involves evaluating the control effectiveness of all the 

technically feasible control alternatives identified in Step 2 for the pollutant and emissions 

under review. Control effectiveness is generally expressed as the rate at which a pollutant is 

emitted after the control system has been installed. The most effective control option is the 

system that achieves the lowest emissions level. 

Step 4. Evaluate Impacts and Document the Results. 

Step 4 of the BART determination involves an evaluation of potential impacts associated with 

the technically feasible retrofit technologies. The following evaluations should be conducted 

for each technically feasible technology: 

(1) costs of compliance; 

(2) energy impacts; and 

(3) non-air quality environmental impacts. 

Costs of Compliance

The economic analysis performed as part of the RACT/BART determination examines the 

cost-effectiveness of each control technology, on a dollar per ton of pollutant removed 

basis. Annual emissions using a particular control device are subtracted from baseline 

emissions to calculate tons of pollutant controlled per year. Annual costs are calculated by 

adding annual operation and maintenance costs to the annualized capital cost of an option. 

Cost effectiveness ($/ton) of an option is simply the annual cost ($/yr) divided by the 

annual pollution controlled (ton/yr). In addition to the cost effectiveness relative to the 

base case, the incremental cost-effectiveness to go from one level of control to the next 

more stringent level of control may also be calculated to evaluate the cost effectiveness of 

the more stringent control. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

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Energy Impact Analysis

The energy requirements of a control technology should be examined to determine whether 

the use of that technology results in any significant or unusual energy penalties or benefits. 

Two forms of energy impacts associated with a control option can normally be quantified. 

First, increases in energy consumption resulting from increased heat rate may be shown as 

total Btu’s or fuel consumed per year, or as Btu’s per ton of pollutant controlled. Second, 

the installation of a particular control option may reduce the output and/or reliability of 

equipment. This reduction would result in loss of revenue from power sales and/or 

increased fuel consumption due to use of less efficient electrical and steam generation 

methods. 

Non-Air Quality Environmental Impact Analysis

The primary purpose of the environmental impact analysis is to assess collateral 

environmental impacts due to control of the regulated pollutant in question. Environmental 

impacts may include solid or hazardous waste generation, discharges of polluted water 

from a control device, increased water consumption, and land use impacts from waste 

disposal. 

Impact analyses conducted in step 4 should take into consideration the remaining useful life of 

the source. For example, the remaining useful life of the source may affect the cost analysis 

(specifically, the annualized costs of retrofit controls). 

Step 5. Evaluate Visibility Impacts. 

Step 5 of the BART determination addresses the degree of improvement in visibility that may 

reasonably be anticipated to result from the use of the best control technology. CALPUFF 

modeling, or other appropriate dispersion modeling, should be used to determine the visibility 

improvement expected from the potential BART control technology applied to the source. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

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2.0 OSWEGO UNIT 5 & 6 RACT/BART DETERMINATION METHODOLOGY 

The BART determination process described in the Appendix Y Guidelines was used to identify 

RACT/BART controls for Oswego Units 5 & 6. This report was prepared to support the Oswego 

Unit 3 RACT/BART determinations, and includes an evaluation of technologies available to control 

NOx, PM and SO2 emissions from the units. This report is arranged to include the information and 

evaluations required by Steps 1 thorough 4 of the Appendix Y BART Evaluation Guidelines. 

Baseline operating parameters and emissions for Oswego Units 5 & 6 are summarized in Table 2-1. 

Baseline emissions from Oswego Units 5 & 6 are based on an evaluation of actual emissions from 

the units during the baseline years of 2007 – 2009. Baseline NOx emissions for both units were 

calculated using actual average NOx mass emissions (tons) and actual average heat input to each 

boiler (boiler) for the three year baseline period.4

 The operating parameters and emissions 

summarized in Table 2-1 form the basis for the Oswego PM and SO2 BART determinations, and 

the NOx RACT/BART determination. 

Section V of the Appendix Y guidelines specify that BART emission limitations for EGUs should 

be based on 30-day rolling averages; therefore, this engineering evaluation is based upon the 30-day 

rolling average emission rates achievable with each technically feasible retrofit technology. The 

RACT/BART cost effectiveness evaluations ($/ton, Step 4) are based on a comparison of total 

annual costs and annual emission reductions. Annual emissions associated with each retrofit 

technology were calculated using the 30-day rolling average emission rate and a representative unit 

capacity factor. 

 

4

 This approach is consistent with the approach used by U.S.EPA to calculate control technology costeffectiveness in the Four Corners and Navajo Power Plants’ BART determinations (see, 74 FR 44321, August 

28, 2009). 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

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Table 2-1 

Unit Operating Parameters for the Oswego Units 5 & 6 BART Evaluations

Parameter Oswego Unit 5 Oswego Unit 6 

Unit Configuration oil-fired boiler oil-fired boiler 

Firing Configuration wall-fired wall-fired 

Unit Output (gross) 870 MW 870 MW 

Boiler Heat Rate (Btu/kW-hr) 9,233 9,297 

Full Load Heat Input (mmBtu/hr) 8,033 mmBtu/hr 8,088 mmBtu/hr 

Primary Fuel fuel oil fuel oil 

Existing NOx Controls LNB/OFA/FGR LNB/OFA/FGR 

Existing SO2 Controls Fuel Sulfur Fuel Sulfur 

Existing PM10 Controls ESP ESP 

Baseline Annual Heat Input 2,201,269 mmBtu 1,155,655 

Baseline Emissions Baseline Actual Emissions Baseline Actual Emissions 

Pollutant 

Averaging 

Time lb/mmBtu tpy lb/mmBtu tpu 

NOx annual average 0.22 243 0.19 107 

PM (filterable) annual average 0.022 23.8 0.022 12.5 
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Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

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3.0 NITROGEN OXIDES (NOx) CONTROL EVALUATION 

New York regulations require that any case-by-case RACT evaluation include, at a minimum, the 

use of fuel switching, the use of a system averaging plan, and implementation of any available 

control technologies. This report does not include an evaluation of the feasibility of fuel switching 

or system averaging, but focuses on the implementation of available control technologies. 

The formation of NOx is determined by the interaction of chemical and physical processes 

occurring primarily within the flame zone of the boiler. There are two principal forms of NOx 

designated as “fuel” NOx and “thermal” NOx. Fuel NOx is formed by the oxidation of nitrogen in 

the fuel. Thermal NOx formation is the result of oxidation of atmospheric nitrogen contained in the 

inlet gas in the high-temperature, post-flame region of the combustion zone. 

Fuel oil properties will affect the formation of fuel NOx. For nitrogen containing fuels, such as fuel 

oil, the oxidation of nitrogen that is organically bound to the fuel molecule can become the primary 

source of total NOx emissions. As the fuel burns, the fuel nitrogen disassociates to form unstable 

nitrogen radicals. The nitrogen radicals will either be oxidized to form NOx, or bond with another 

nitrogen radical to form atmospheric nitrogen (N2). 

The major factors influencing NOx formation are temperature, the concentration of combustion 

gases (primarily nitrogen and oxygen) in the inlet air, and residence time within the combustion 

zone. Experimental measurements of thermal NOx formation have shown that NOx formation is 

exponentially dependent on temperature, and is proportional to nitrogen and oxygen concentrations 

in the flame. The formation of fuel bound NOx can also be reduced by delaying (or staging) 

mixing of stoichiometric air. Reducing the oxygen available to the nitrogen radicals favors the 

formation of N2. Advanced burner designs can regulate the distribution and mixing of the fuel and 

air to reduce flame temperatures and residence times at peak temperatures to reduce thermal NOx 

formation. 

NOx emissions from oil-fired boilers can be controlled by adjusting the combustion process and 

reducing NOx formation in the boiler, and/or installing post-combustion NOx control systems. 

3.1 Step 1: Identify Potentially Feasible NOx Control Options 

Potentially available control options were identified based on a comprehensive review of available 

information. NOx control technologies with potential application to Oswego Units 5 & 6 are listed 

in Table 3-1. 
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Table 3-1 

List of Potential NOx Control Options 

Control Technology 

Combustion Controls 

Low NOx Burners (LNB), Overfire Air (OFA), and 

Flue Gas Recirculation (FGR) 

(optimize existing NOx combustion controls) 

Low NOx Reduced Emissions and Advanced 

Combustion Hardware (LN-REACH) and Modified 

OFA Controls 

Neural Network Combustion Control Systems 

Gas Reburn Systems and Advanced Gas Reburn 

Fuel Lean Gas Reburn (FLGR) and Amine 

Enhanced FLGR (AEFLGR) 

Post-Combustion Controls 

Selective Noncatalytic Reduction (SNCR) 

Selective Catalytic Reduction (SCR) 

Innovative Control Technologies 

 Rotating Overfire Air (ROFA) 

 ROFA plus SNCR (Rotamix) 

 NOxStar Control System 

 Powerspan ECO Technology 

3.2 Step 2: Technical Feasibility of Potential Control Options 

Control technologies can be divided into two general categories: combustion controls and postcombustion controls. Combustion controls reduce the amount of NOx that is generated in the 

boiler. Post-combustion controls remove NOx from the boiler exhaust gas. The technical 

feasibility of each potentially available NOx control strategy, with respect to Oswego Units 5 & 6, 

is evaluated below. 
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3.2.1 Combustion Controls 

The rate of NOx formation in the combustion zone is a function of free oxygen, peak flame 

temperature and residence time. Combustion techniques designed to minimize the formation of 

NOx will minimize one or more of these variables. Currently, both Oswego Units 5 & 6 are 

equipped with low-NOx burners (LNB), overfire air (OFA), and flue gas recirculation (FGR) 

control systems. A description of the existing combustion controls is provided below. 

3.2.1.1 Oswego Units 5 & 6 – Existing Combustion Controls 

Oswego Units 5 & 6 are Foster-Wheeler boilers designed to fire No. 6 fuel oil. Each unit 

has 32 burners located in the front wall of the furnace, arranged in four rows of eight. The 

burners are fed combustion air from a common windbox. Both units are equipped with low 

NOx burners (LNB), flue gas recirculation (FGR), and overfire air (OFA) ports. 

Low NOx burners limit NOx formation by controlling both the stoichiometric and 

temperature profiles of the combustion flame in each burner flame envelope. Control is 

achieved with design features that regulate the aerodynamic distribution and mixing of the 

fuel and air, yielding reduced oxygen (O2) in the primary combustion zone, reduced flame 

temperature, and reduced residence time at peak combustion temperatures. The 

combination of these techniques produces lower NOx emissions during the combustion 

process; however, the mechanisms used to reduce NOx formation (e.g., cooler flame and 

reduced O2 availability) also tend to increase the formation and emission of carbon 

monoxide (CO). 

In the overfire air (OFA) process, the injection of air into the firing chamber is staged into 

zones, in which approximately 5% to 20% of the total combustion air is diverted from the 

burners and injected through ports located above the top burner level. Staging the 

combustion air reduces NOx formation by two mechanisms. First, staged combustion 

results in a cooler flame, and second the staged combustion results in less oxygen reacting 

with fuel molecules. 

The degree of staging (i.e., the percent of combustion air diverted from the burners) is 

limited by boiler-specific operational issues. As the amount of OFA is increased, the 

stoichiometry in the burner zone decreases, resulting in substoichiometric combustion in 

the primary burner zone (primary furnace S < 1.0). OFA systems are designed to provide 

the additional O2 needed to complete combustion; however, a point will be reached at 

which CO emissions become unacceptably high. The point at which this occurs is boilerspecific, and depends on the system’s ability to balance flows between the individual 
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burners. As the amount of OFA approaches 10 – 15%, the probability for individual 

burners operating under substoichiometric conditions increases, potentially forming pockets 

of high CO emissions and unburned carbon. 

Flue gas recirculation (FGR) controls NOx by recycling a portion of the flue gas back into 

the primary combustion zone. The recycled air lowers NOx emissions by two mechanisms: 

(1) the recycled gas, consisting of products that are inert during combustion, lowers the 

combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the 

primary flame zone. The amount of recirculation is based on flame stability. In general, 

FGR is more effective on natural gas-fired boilers because it reduces the formation of 

thermal NOx, which represents almost 100% of the NOx produced in a natural gas-fired 

boiler. In oil-fired boilers a majority of the NOx formed can be from fuel bound nitrogen; 

thus, the use of FGR will have a somewhat lower impact on overall NOx formation in oilfired applications. 

Oswego Units 5 & 6 are currently equipped with Low-NOx Reduced Emissions and 

Advanced Combustion Hardware (LN-REACH) high-pressure return nozzle systems. Each 

unit has two levels of eight OFA ports (total of 16 ports) directly in line with each burner 

column. 

Application of LN-REACH typically involves the custom design of retrofit oil atomizers 

and flame stabilizers. LN-REACH oil atomizers can be designed as mechanically atomized 

burners or steam-atomized systems. In either case, the atomizers are designed to provide 

more effective oil spray quality to promote fuel evaporation, as well as radial and 

circumferential staging of the fuel within the combustion zone. Flame stabilization and 

control of fuel and air mixing is required to produce the proper entrainment and swirl of 

combustion air at the discharge plane of the burner to match the oil spray of the atomizer. 

Staging within the combustion zone reduces the formation of both thermal and fuel NOx. 

The existing combustion control systems on Oswego Units 5 & 6 effectively reduce NOx 

emissions by reducing the delaying the introduction of stoichiometric air and reducing the 

primary flame temperatures. Boiler furnace stoichiometry levels on Unit 5 were calculated 

to be 0.87 to 0.91 for summer and winter operation, respectively, while boiler furnace 

stoichiometry levels calculated for unit 6 were somewhat lower at 0.81 to 0.84 for summer 

and winter, respectively. Boiler furnace stoichiometries were calculated based on firing 

No. 6 fuel oil and boiler operating O2 level at full load. These boiler stoichiometries limit 

the conversion of fuel bound nitrogen to NOx by limiting the availability of O2. 
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The existing OFA system is designed to provide the stoichiometric air necessary for 

complete combustion. OFA port velocities associated with the existing systems were 

calculated to be approximately 75 ft/second based on an OFA flow of 20%. This velocity 

is approximately 2-times the furnace flue gas flow rates calculated for both Oswego units 5 

& 6, and is below the recommended design OFA velocity of 5-times the furnace flue gas 

flow rate. Higher OFA velocities are required for to optimize jet penetration in the upper 

furnace and promote complete fuel burnout. Thus, modifications to the existing OFA ports 

may provide for better jet penetration and flue gas mixing in the upper furnace. 

During the baseline years of 2007 thru 2009, Oswego Units 5 & 6 achieved average 

controlled NOx emission rates of 0.22 and 0.19 lb/mmBtu (actual average), respectively. 

Unit 6 is able to achieve lower baseline NOx emissions because NRG is able to operate 

Unit 6 at somewhat lower boiler furnace stoichiometries. Annual emissions from Units 5 & 

6 during the baseline period, averaged 243 and 107 tpy, respectively. Both units currently 

meet the applicable NOx RACT emission limit of 0.25 lb/mmBtu; however, both units are 

above the proposed July 1, 2012 limit of 0.15 lb/mmBtu. 

3.2.1.2 Process Optimization Modeling System or Neural Network Control 

As discussed above, NOx formation in an oil-fired boiler is a function of a multitude of 

operating variables. NOx formation will fluctuate based on furnace cleanliness, air-to-fuel 

ratios, mixing, OFA jet penetration, and combustion air staging. It is extremely difficult to 

continually optimize the combustion and thermal efficiencies of an oil-fired boiler as 

operating changes lead to deviations from optimal combustion and can result in short-term 

increases in emissions. 

Neural network based combustion optimization systems have been developed to 

continually respond to changes in boiler operating variables. Neural control systems are 

capable of analyzing data from multiple sensors and, once trained, are able to recognize 

sub-optimal combustion conditions. Neural networks are designed to “learn” from 

observations made from operating data, and algorithms are used to determine optimal 

solutions based on user-defined objectives. 

Neural network combustion optimizers have been installed on a number of utility boilers in 

the U.S., including T-fired boilers with LNB/close-couple OFA; face-fired boilers with 

LNB/OFA, cyclone boilers, and opposed-fired boilers with LNB/OFA. Many of these 

systems have demonstrated the capability to operate greater than 90% of the time in 

supervisory modes, and have become a boiler operational tool. 
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Neural network control systems interface directly with the unit’s DCS control system to 

provide continuous combustion tuning. Neural network systems can tune up to 90 

manipulative variables (MV) simultaneously, with the goal of continuously optimizing 

selected control variables. The systems allow boiler operators to enable or disable 

individual control loops while keeping the total neural network operational, adding 

operational flexibility to the system. 

Neural network control systems and predictive dynamic controllers are a technically 

feasible and commercially available NOx control strategy. By installing a neural net-based 

control system, optimal combustion conditions can more readily be maintained over long 

periods of time, and the system should respond more rapidly to changing operating 

variables to minimize short-term emission excursions. 

Neural network based control systems are designed to provide continuous response to 

transient operating conditions. When used in conjunction with the existing LNB/OFA/FGR 

control systems, neural network control should reduce short-term NOx excursions and 

reduce the maximum 24-hour NOx emission rate. Installation of a neural network control 

system would be expected to reduce the 30-day average NOx emission rate from each 

boiler by approximately 5%. Assuming a 5% reduction in the 30-day average emission 

rate, installing a neural network based control system would achieve the following 

controlled NOx emission rates: 

Controlled NOx Emission Rate 

Control Option (lb/mmBtu 30-day average) 

Unit 5 Unit 6 

Existing Combustion Controls plus 

Neural Network 

0.21 0.18 

 

3.2.1.3 Combustion Optimization and Modified Overfire Air 

As discussed in section 3.2.1.1, Oswego Units 5 & 6 are currently equipped with LNREACH high-pressure return nozzles and OFA. However, as currently designed, OFA jet 

velocities using one level of OFA with 20% air flow, are approximately two-times the 

average boiler flue gas flow rate (significantly below the recommended design level of 5-

times the furnace flue gas flow rate). In addition, the average residence time in the furnace 

for both units, is 0.35 seconds from the centerline of the top row of burners to the centerline 

of the upper level of OFA ports, and 0.60 seconds from the centerline of the top row of 
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burners to the start of the convective sections, limiting the total time under 

substoichiometric conditions. 

One approach to reduce boiler NOx emissions is to take the upper burner level out of 

service (8 burners) and replace the lower three burner levels (24 burners) with oversized 

high-pressure return LN-REACH burners designed for maximum full load oil flow rates at 

the same operating pressure. This configuration would increase the residence time in the 

units by 0.27 to 0.63 seconds from the highest burner level centerline to the top level of 

OFA ports, increasing the total time under substoichiometric conditions and allowing for 

additional combustion staging. Finally, the existing FGR system could be used for both 

NOx control and superheat/reheat (SH/RH) temperature control throughout the boiler load 

range. 

As is the case for all low-NOx operations, it is very important to have balanced local air-tofuel (A/F) ratios to achieve minimum boiler O2 levels without generating high CO levels. 

Modifications to the existing OFA ports to increase the jet velocities from two-times the 

flue gas velocity to five-times the flue gas velocity would provide for better mixing and 

burnout in the upper furnace, keeping CO to acceptable levels. 

The LN-REACH system could be designed with mechanically-atomized burners or steamatomized system. Converting from high-pressure return mechanical atomizers to steam 

atomized burners results in smaller droplet size distribution, reducing the formation of 

carbonaceous particulates and CO formation. The steam atomizer concept involves fuelrich and fuel-lean sections in the near-zone of the burner, which reduces overall peak flame 

temperatures as well as changing the near-zone mixing characteristics (i.e., flame shape). 

Steam required for the steam atomizing system would be taken from the boiler system, and 

it is assumed that the existing auxiliary boiler would provide steam needed during unit 

startup. 

Although Oswego Units 5 & 6 are currently equipped with LNB and OFA combustion 

control systems, reconfiguring the firing systems and replacing the existing burners with 

oversized high-pressure return LN-REACH technology or steam atomized LN-REACH 

system, and modifying the exiting OFA system to provide better jet penetration would be 

technically feasible and commercially available retrofit NOx control strategies. These 

modifications would provide better mixing and increased residence time at 

substoichiometric conditions on both units. The combination of oversized LN-REACH and 

modified OFA systems should achieve controlled NOx emission rates on both units below 
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the baseline. Based on engineering judgment, it is anticipated that these modifications 

could achieve the following controlled NOx emission rates: 

Controlled NOx Emission Rate 

Control Option (lb/mmBtu 30-day average) 

Unit 5 Unit 6 

LN-REACH (pressure atomizers) + 

modified OFA 

0.18 0.17 

LN-REACH (steam atomizers) + 

modified OFA 

0.17 0.16 

3.2.1.4 Gas Co-Firing (Unit 6) 

NOx emissions from an oil-fired boiler can be reduced by co-firing the oil with natural gas. 

Natural gas is a low nitrogen fuel, thus, co-firing reduces the quantity of nitrogen available 

to form fuel NOx. In addition, FGR (which reduces NOx by recycling a portion of the flue 

gas back into the primary combustion zone) more effectively reduces the formation of 

thermal NOx, which represents almost 100% of the NOx produced from natural gas 

combustion. 

Oswego Unit 6 currently has the ability to co-fire natural gas; however, based on natural 

gas availability at the station, natural gas co-firing would be limited to approximately 1,500 

mmBtu/hr, or about 18% of the full load heat input to the boiler. Unit 6 does not currently 

co-fire natural gas for the following reasons. First, because Unit 6 operates in a cycling 

mode and does not provide baseload power, the quantity of natural gas consumed would 

vary significantly over time. To secure the gas needed to co-fire Unit 6, NRG would be 

required to secure a specific quantity of gas, whether the gas is actually consumed or not, 

and the facility cannot guarantee that it will consume a specific quantity of natural gas. 

Second, because of physical limits associated with the boiler design, co-firing natural gas 

above a total boiler generating capacity of approximately 400 MW is not possible due to 

the tightness of the primary furnace and the available residence time. 

Natural gas and oil flames do not have the same luminosity, and co-firing natural gas will 

increase the furnace exit gas temperature (FEGT) of the boiler. FEGT has a direct affect on 

the superheat (SH) and reheat (RH) steam temperatures, which are limited by boiler 

metallurgy. SH/RH temperatures cannot exceed specific maximum allowable limits, 

limiting FEGT and the quantity of natural gas that can be fired in a boiler. In order to cofire natural gas above the 300 to 400 MW load range would require major boiler pressure 
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part modifications to the SH/RH sections of the boiler. CFD modeling would be required 

to see if these major boiler modifications are technically feasible, and the SH/RH 

metallurgy would need to be evaluated for natural gas co-firing. 

Natural gas co-firing is not a technically feasible NOx control option on Oswego Unit 6 due 

to both technical and economic issues. As discussed above, co-firing at a boiler load above 

approximately 300 to 400 MW is not technically feasible due to boiler tightness and FEGT 

design limitations. Co-firing natural gas above this level would require significant 

modifications of the pressure parts of the SH/RH sections of the boiler. At lower loads, 

natural gas co-firing would require NRG to secure a specific quantity of natural gas from 

the supplier. Securing an adequate supply of natural gas would require the facility to 

subscribe to a specific quantity of natural gas (to ensure availability to all natural gas 

users). Because Unit 6 is operated as a load following unit, and has a low capacity factor, it 

would not be practical to subscribe to a given quantity of natural gas. Furthermore, cofiring at low loads does not address the boiler tightness issues, and would effectively limit 

maximum boiler load. 

Taking into consideration Unit 6 flue gas flow rates, boiler dimensions, residence times, 

and natural gas availability it was determined that natural gas co-firing would not be a 

feasible NOx control option. 

Controlled NOx Emission Rate 

Control Option (lb/mmBtu 30-day average) 

Unit 5 Unit 6 

Gas Co-Firing (150 MW) Unit 6 Not Available Not Feasible 

Gas Co-Firing (>150 MW) Unit 6 Not Available Not Available 

Gas Co-Firing Both Units Not Available Not Available 

3.2.1.5 Gas Reburn 

Gas reburn technology injects a secondary fuel into the furnace above the burner zone. 

The technology involves combustion in three distinct zones within the boiler: (1) a primary 

combustion zone where the primary fuel is fired using conventional burners; (2) a reburn 

zone where secondary fuel, typically natural gas, is introduced into the boiler; and (2) an 

overfire air burnout zone. 
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In the primary zone, oil would be fired utilizing low-NOx burners (described in section 

3.2.1.3) at a rate corresponding to approximately 80-90% of the total heat input. Natural 

gas reburn fuel would be injected above the primary combustion zone under fuel-rich 

conditions at a rate corresponding to approximately 10-20% of the total heat input. The 

fuel-rich reburn zone creates a reducing region within the boiler where the natural gas, 

principally methane (CH4), breaks down to produce hydrocarbon fragments (CH and CH2). 

The hydrocarbon fragments react with NOx produced in the primary combustion zone to 

reduce NOx to atmospheric nitrogen (N2). Gases exiting the reburn zone will contain 

considerable CO and unburned hydrocarbons; therefore, additional overfire air (referred to 

as completion air) is introduced above the reburn zone to complete the combustion process. 

Critical design parameters that affect the feasibility and performance of a gas reburn retrofit 

system include: (1) primary NOx concentration; (2) reburn zone temperature, residence 

time and stoichiometry: (3) overfire air burnout zone temperature and residence time; and 

(4) mixing of the reburn fuel and overfire air with the bulk flue gas. 

In reburning, the main combustion zone operates at a relatively low oxygen stoichiometry 

of 0.9 to 1.1, and receives a bulk of the fuel input (80 to 90% of total heat input). The 

balance of the heat input is injected after the main combustion zone through reburning 

injections. The stoichiometry in the reburn zone should be within a range of 0.85 to 0.95. 

Temperatures in the reburn zone must be above 1,800 o

F to provide an environment for the 

decomposition of the reburn fuel. These substoichiometric conditions add risk to the boiler 

operation due to high-temperature vanadium corrosion attack and H2S-accelerated tube 

corrosion that will occur under this reducing environment. These conditions can result in 

more forced boiler outages, boiler downtime, and increased O&M costs. 

Residence time in the furnace between the reburn fuel injection ports and the OFA ports is 

also an important design criteria. Typically, a residence time in the furnace between 0.5 

and 1.0 second is needed to allow for NOx reduction reactions to occur. There must also be 

sufficient residence time above the OFA ports to allow for complete combustion and 

minimize CO emissions. The residence time calculated for both units from the top row of 

burners to the start of the convective passages are in the range of 0.6 seconds. This 

residence time is indicative of a tight furnace, and would reduce the effectiveness of the 

reburn control option. Therefore, to be effective, the gas reburn technology would need to 

incorporate combustion modifications discussed in section 3.2.1.3. Those modifications 

would: (1) increase the furnace residence time between the top burner level and the OFA 

ports; (2) increase OFA jet velocities and penetration/mixing in the upper furnace to 
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complete burnout of natural gas fuel in the upper furnace; and (3) reduce CO levels exiting 

the furnace. 

However, the same natural gas supply issues, and FEGT issues discussed in subsection 

3.2.1.4 would apply to the gas reburn option. To secure the natural needed for gas reburn, 

NRG would be required to subscribe to a specific quantity of fuel. Because Unit 6 is not a 

baseload unit, it would be impractical to subscribe to a specific quantity of gas. In addition, 

natural gas reburn above a total boiler generating capacity of 300 to 400 MW is not 

possible due to the tightness of the primary furnace, residence time, and boiler metallurgy. 

To install natural gas reburn to the 18% heat input required for this technology to achieve 

effective NOx control, major boiler pressure part modifications to the SH/RH sections of 

the boiler would be required, and CFD modeling would be required to see if these major 

boiler modifications are even feasible. 

Taking into consideration Unit 6 flue gas flow rates, boiler dimensions, residence times, 

tightness of the primary furnace, and natural gas availability, natural gas reburn is not a 

technically feasible option for Unit #6. 

Controlled NOx Emission Rate 

Control Option (lb/mmBtu 30-day average) 

Unit 5 Unit 6 

LN-REACH (pressure atomizers) + 

modified OFA and Gas Reburn 

Not Available Not Feasible 

LN-REACH (steam atomizers) + 

modified OFA and Gas Reburn 

Not Available Not Feasible 

3.2.1.6 Fuel Lean Gas Reburn (FLGR) 

Like other gas reburn systems described in subsection 3.2.1.5, the fuel lean gas reburn 

(FLGRTM) process injects natural gas above the main combustion zone of the furnace to 

reduce NOx to N2. FLGR is designed to achieve comparatively moderate NOx reductions 

using much lower gas input than conventional reburn systems. Because less natural gas is 

used with the FLGR system, the FEGT issues discussed in subsection 3.2.1.4 become less 

critical, and the technology may be technically feasible without major modifications to the 

boiler pressure parts. 

Unlike more conventional gas reburn designs, FLGR is designed to avoid fuel-rich zones 

within the gas reburn section and maintain overall fuel-lean conditions. Maintaining a fuellean environment throughout the furnace eliminates the need for downstream overfire air to 
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complete combustion (i.e., burnout zone), and prevents formation of reducing conditions in 

the boiler. 

FLGR is an in-furnace NOx reduction technology, where natural gas (or another secondary 

fuel) acts as a reducing agent to convert NOx to N2. The natural gas injected for NOx 

reduction will replace approximately 3% to 7% of the total heat input to the boiler 

(compared to 10 to 20% with more conventional reburn). Secondary fuel is injected within 

a temperature window of 2,000 to approximately 2,400 o

F, which supports the chemical 

reactions that reduce NOx to N2. The temperature at the injection location should be as low 

as possible consistent with the requirement of the reburn fuel ignition and burnout. Lower 

gas injection temperatures with FLGR allow lower NOx levels without making the entire 

furnace cross-section substoichiometric, which can eliminate the need for OFA above the 

injection point. 

To effectively reduce NOx emissions, the natural gas must be injected in such as way as to 

achieve complete mixing and adequate residence times in the upper boiler, while creating 

only localized substoichiometric conditions. To achieve sufficient mixing, natural gas is 

injected into the upper furnace using multiple high-velocity turbulent gas injection jets. 

Generally, detailed computational fluid dynamics (CFD) modeling of the boiler is required 

to optimize the gas injection system. 

The most significant operational parameters that affect the performance of a FLGR system 

are: (1) reburn zone residence time and temperature; (2) CO levels; and (3) fuel/O2

stoichiometry. The limiting factor for the control system is complete reburn gas 

combustion without localized substoichiometric conditions or excess CO emissions. The 

amount of natural gas that can be injected into the upper furnace to reduce NOx will be 

limited by residence time. As greater amounts of natural gas are injected in the upper 

furnace, conditions will be reached that inhibit both NOx reduction and complete burnout. 

The reburn fuel injection level in the upper furnace must be installed where sufficient 

residence time exists for the fuel to complete its burnout process. When natural gas is 

injected into the upper furnace, it can consume oxygen required for the primary fuel 

burnout process. This will result in higher CO emissions and increased unburned carbon 

(UBC) due to incomplete No. 6 fuel oil burnout. Therefore, installation of FLGM control 

systems on the Oswego boilers would be coupled with the upgraded LN-REACH and 

modified OFA controlled systems described in section 3.2.1.2. 
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A boiler with an LNB/OFA system will have substoichiometric conditions in the primary 

furnace (0.85 to 0.95). The introduction of the OFA with good jet penetration will 

complete the burnout of the primary combustion zone resulting in stoichiometries at the 

entrance to reburn zone in the range of 1.05-1.15. Sufficient residence time in the upper 

furnace must be available in order to take advantage of the NOX reduction capabilities of 

both technologies. CFD modeling of the primary burnout process and the natural gas 

reburn process, as well as a parametric testing program, is often needed to determine the 

minimum levels of excess air in the primary furnace combustion zone required to sustain 

safe and flexible boiler operation. CFD and LIM (or other turbulent mixing) modeling can 

be combined to formulate the reburn gas injection design (size, location, number, velocity, 

etc.). 

As with the other natural gas options, FLGR may not be possible above a total boiler 

generating capacity of 300 to 400 MW due to the tightness of the primary furnace, 

residence time, and FEGT issues. However, unlike more conventional reburn systems that 

replace 10 to 20% of total heat input to the boiler with natural gas, FLGR replaces only 3% 

to approximately 7% of the heat input with natural gas. Thus, the FEGT issues discussed in 

subsection 3.2.1.4 become less critical, and the technology may be feasible without major 

modifications to the boiler pressure parts. 

Another advantage of the FLGR control option is that the total amount of natural gas 

currently available at the site would be sufficient to install this process on both boilers. 

However, the natural gas subscription issues discussed in subsection 3.2.1.4 still apply, and 

the natural gas needed to effectively implement the FLGR system may be subject to limited 

seasonal availability. 

 

Based on an engineering review of Oswego Units 5 & 6, including flue gas flow rates and 

boiler dimensions, it was determined that FLGR is a technically feasible retrofit NOx 

control technology. Although the absolute maximum natural gas heat input to the existing 

boiler configurations cannot be determined without CFD modeling, based on engineering 

calculations the total FLGR zone within the upper furnace (above the OFA ports) has a 

residence time of only 0.3 seconds, which limits the maximum heat input from the reburn 

fuel to 4% of the total boiler heat input. The 4% heat input from natural gas should also be 

acceptable at full boiler loads without the need for boiler pressure part modifications, 

although CFD modeling would be needed to confirm this conclusion. The relatively short 

residence time calculated for both units from the top row of burners to the start of the 

convective passages will limit the effectiveness of the FLGR control system. Unburned 

fuel leaving the reburn zone will be fired to completion in the burnout zone. 
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Taking into consideration Unit 5 & 6 flue gas flow rates, boiler dimensions, residence 

times, and tightness of the primary furnace, and assuming 96% heat input from fuel oil and 

4% natural gas as reburn fuel, coupled with using oversized LN-REACH atomizers and 

modified OFA ports (higher jet velocities), it was determined that FLGR could achieve the 

following controlled NOx emission rates: 

Controlled NOx Emission Rate 

Control Option (lb/mmBtu 30-day average) 

Unit 5 Unit 6 

LN-REACH (pressure atomizers) + 

modified OFA and FLGR 

0.13 0.13 

LN-REACH (steam atomizers) + 

modified OFA and SNCR 

0.12 0.12 

3.2.1.7 Combustion Control Conclusions 

Several combustion control systems are considered technically feasible and commercially 

available retrofit NOx control technologies for Oswego Units 5 & 6. The control systems 

include: (1) optimizing the existing combustion controls with a Neural Network control 

system; (2) upgrading and reconfiguring the existing combustion controls with LN-REACH 

atomizers (mechanical or steam) and modifying the existing OFA ports; and (3) 

combustion controls plus FLGR on both units. 

3.2.2 Post-Combustion Controls 

Post-combustion NOx control systems with potential application to Oswego Units 5 & 6 are 

discussed below. 

3.2.2.1 Selective Non-Catalytic Reduction 

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH3) 

or urea (CO(NH2)2) at high flue gas temperatures of approximately 1,750 ± 50 oF. The 

ammonia or urea reacts with NOx in the flue gas to produce N2 and water as shown in the 

equations below: 

(NH2) 2CO + 2NO + 1⁄2O2 → 2H2O + CO2 + 2N2 

2NH3 + 2NO + 1⁄2O2 → 2N2 + 3H2O 
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Flue gas temperature at the point of reagent injection will greatly affect NOx removal 

efficiencies and the quantity of NH3 or urea that will pass through the SNCR unreacted 

(referred to as NH3 slip). In general, SNCR reactions are effective in the range of 1,750 ± 

50 o

F. At temperatures below the desired operating range, the NOx reduction reactions 

diminish and unreacted NH3 emissions increase. Above the desired temperature range, 

NH3 is oxidized to NOx resulting in low NOx reduction efficiencies and potentially 

increased NOx emissions. 

Mixing of the reactant and flue gas within the reaction zone is also an important factor to 

SNCR performance. In large boilers, the physical distance over which reagent must be 

dispersed increases, and the surface area-to-volume ratio of the convective pass decreases. 

Both of these factors make it difficult to achieve good mixing of reagent and flue gas 

within the required temperature window. In addition to temperature and mixing, several 

other factors influence the performance of an SNCR system, including residence time, 

reagent-to-NOx ratio, and fuel sulfur content. 

SNCR control systems have been installed as retrofit NOx control systems on small and 

medium sized (i.e., less than approximately 300 MW) boilers. Because of design and 

operating limitations, SNCR has not been used extensively on larger boilers. As the boiler 

size increases, it becomes physically more difficult to achieve adequate reagent mixing and 

residence time within the required flue gas temperature window to achieve effective NOx 

reduction. 

The physical size of Oswego Units 5 & 6 will present significant design challenges to 

locate and install ammonia/urea injection points capable of achieving adequate reagentNOx contact. Higher reagent injection rates could provide additional reagent-NOx contact, 

but would also result in higher levels of reagent slip (i.e., unreacted ammonia or urea in the 

flue gas). However, injecting excess reactant is not a viable NOx control option. Excess 

reagent in the flue gas can react with sulfur compounds in the flue gas to form ammonium 

bisulfate and lead to significant plugging of downstream equipment. To be feasible, the 

SNCR control system would have to be designed with a maximum slip of approximately 5 

ppm. 

Because Oswego Units 5 & 6 tend to operate over a wide operational load window, the area 

of optimal reaction temperature will vary across the load range. Control of injection 

systems during transient operations is difficult as temperatures will vary within the furnace, 

and maintaining injection at the optimum temperature becomes difficult. To address these 
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load changes, the SNCR control systems would have to include multiple levels of injection 

nozzles and a sophisticated control scheme to ensure minimal ammonia slip. 

Finally, SNCR NOx reduction efficiency is reduced substantially when CO levels go above 

approximately 200 ppmv. As discussed in section 3.2.1.2, CO levels from the boilers 

would be addressed by modifying the existing OFA systems to provide better jet 

penetration, mixing, and increased residence time. Therefore, to be effective, SNCR would 

only be installed on Oswego Unit 5 or 6 in conjunction with the combustion modifications 

described in section 3.2.1.2. 

Based on an engineering evaluation of the Oswego boilers, SNCR is considered a 

technically feasible and commercially available retrofit NOx control technology. However, 

as described above, there are several technical difficulties associated with applying SNCR 

to large boilers that will limit its effectiveness, including the ability to achieve adequate 

reagent mixing and reagent-NOx contact within the required temperature window while 

maintaining slip within acceptable limits. Based on NOx removal efficiencies achieved in 

practice on smaller boilers equipped with SNCR, the physical size of Oswego Units 5 & 6, 

information available from control technology vendors, and engineering judgment, it is 

concluded that SNCR coupled with the LN-REACH and modified OFA control systems on 

both units could achieve the following controlled emission rates: 

Controlled NOx Emission Rate 

Control Option (lb/mmBtu 30-day average) 

Unit 5 Unit 6 

LN-REACH (pressure atomizers) + 

modified OFA and SNCR 

0.14 0.14 

LN-REACH (steam atomizers) + 

modified OFA and SNCR 

0.13 0.13 

3.2.2.2 Selective Catalytic Reduction 

Selective catalytic reduction (SCR) involves injecting ammonia into boiler flue gas in the 

presence of a catalyst to reduce NOx to N2 and water. Anhydrous ammonia injection 

systems may be used, or ammonia may be generated on-site from a urea feedstock. The 

overall SCR reactions are: 

4NH3 + 4NO + O2 → 4N2 + 6H2O 

8NH3 + 4NO2 + 2O2 → 6N2 + 12H2O 
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The performance of an SCR system is influenced by several factors including flue gas 

temperature, SCR inlet NOx level, the catalyst surface area, volume and age of the catalyst, 

and the amount of ammonia slip that is acceptable. 

The optimal temperature range depends on the type of catalyst used, but is typically 

between 560 o

F and 750 oF to maximize NOx reduction efficiency and minimize 

ammonium sulfate formation. This temperature range typically occurs between the 

economizer and air heater on a large utility boiler. Below this range, ammonium sulfate is 

formed resulting in catalyst deactivation. Above the optimum temperature, the catalyst will 

sinter and thus deactivate rapidly. 

Incorporating an SCR control system into an existing boiler can represent significant 

retrofit challenges. SCR control systems are large and require adequate space for the 

catalyst. The SCR reactor must be located in an area where flue gas temperatures are 

between approximately 560 o

F and 750 oF. On Oswego Units 5 & 6 this area occurs 

between the economizer outlet and air heater inlet, upstream of the Unit’s ESP. As noted 

during a walk down of Oswego Units 5 & 6, access to the economizer outlet needed to 

install duct work to and from SCR is extremely tight, and could make locating the SCR in 

this area technically infeasible. Detailed engineering would be required to determine if the 

space is available for duct work installation. 

Experience also shows that SCR control on an oil-fired boiler can result in significant 

balance-of-plant impacts. Potential balance-of-plant impacts that must be taken into 

consideration include the potential for increased sulfuric acid mist (SAM) and ammonium 

bisulfate formation. 

Vanadium in the fuel oil ash will cause SO2 in the flue gas to more readily convert to SO3, 

which can react with water to form sulfuric acid mist and increase emissions of fine 

particulates. It is likely that a sorbent injection system would need to be installed upstream 

of the existing ESPs to address increased SO3 formation. It should be noted that catalyst 

suppliers will not offer plume opacity guarantees for boiler firing No. 6 fuel oil with 

vanadium in the ash. 

SCR operation on an oil-fired boiler must be carefully controlled to minimize NH3 slip, 

which leads to formation of ammonium bisulfate (NH4HSO4). This material forms a sticky 

solid that condenses at temperatures between approximately 415 and 475°F, which occur in 

the center of the air heater. Units that experience high bisulfate formation typically require 

regular cleaning of the air heaters to remove these deposits. One option to mitigate 
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NH4HSO4 formation is to install a sorbent injection system after SCR and upstream of the 

ESP to scavenge SO3 in the flue gas. 

Finally, SCR operation with fuel oil systems has, in some cases, been adversely affected by 

potassium in the fuel oil ash. Potassium can deactivate the SCR catalyst. In some cases, 

catalyst cleaning is frequently required to regain lost activity of the catalyst. 

For these reasons SCR NOX reduction technology is typically not recommended for boilers 

firing No. 6 fuel oil. To address potential balance-of-plant impacts, the SCR would have to 

be designed to limit SO2 to SO3 oxidation and limit ammonia slip (generally less than about 

5 ppm), and would likely require installation of a sorbent injection system upstream of the 

existing ESPs. These design limitations will limit how aggressively the facility can operate 

the SCR to reduce NOx emissions. 

The performance of an SCR system is influenced by several factors, including flue gas 

temperature, inlet NOx level, available catalyst surface area, volume and age of the 

catalyst, and the quantity of unreacted excess ammonia acceptable in the flue gas (ammonia 

slip). In order to effectively reduce NOx, NH3 injected into the flue gas must come into 

contact with the NOx molecules within the required temperature window and in the 

presence of active catalyst. Effective NOx control requires thorough NH3 mixing and 

available active catalyst surface area. 

Operating variables affecting the NOx control will fluctuate during normal boiler 

operations, including boiler load changes, low load operation, and toward the end of the 

catalyst life. Catalyst that has been in service for a period of time will have decreased 

performance because of normal deactivation and deterioration. Catalyst that is no longer 

effective due to plugging, blinding or deactivation must be replaced. 

SCR would pose significant engineering and design challenges on Oswego Units 5 & 6; 

however, SCR is considered a technically feasible retrofit NOx control system. Economic 

impacts associated with engineering/designing around those challenges are evaluated in 

Step 4 of the BART determination. 

Based on emission rates achieved in practice at existing units, and taking into consideration 

the Oswego Unit 5 & 6 general arrangements, fuel characteristics, flue gas characteristics, 

and long-term operation of an SCR control system (including catalyst plugging and 

deactivation) it is anticipated that SCR could achieve a controlled NOx emission rate of 

0.03 lb/mmBtu (30-day rolling average). An emission rate of 0.03 lb/mmBtu is equivalent 
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to an average NOx concentration in the flue gas of approximately 22 ppmvd @ 3% O2. 

Reducing NOx emissions below 22 ppmvd @ 3% O2 would tend to increase potential 

balance-of-plant impacts associated with the SCR, including increased ammonia slip, 

increased SO2 to SO3 oxidation, and more frequent catalyst changes. 

3.2.3 Innovative NOx Control Technologies 

A number of innovative NOx control systems, including multi-pollutant control systems, were 

identified as potential retrofit NOx control technologies during the review of available 

technologies. Innovative NOx control technologies with potential application to Oswego Units 

5 & 6 include boosted over-fire air (e.g., MobotecUSA’s ROFA® system), advanced SNCR 

control systems (e.g., MobotecUSA’s Rotamix® system), Enviroscrub’s multi-pollutant 

PahlmanTM process, NOxStarTM, J-Power’s REACT system, and Powerspan’s ECO technology. 

Innovative NOx control systems with potential application to Oswego Units 5 & 6 are 

evaluated below. 

3.2.3.1 Rotating Opposed Fired Air and Rotomix 

Rotating opposed fired air (ROFA®) is a boosted overfire air system that includes a 

patented rotating injection system which includes asymmetrically placed air nozzles.5

 Like 

other OFA systems, ROFA stages the primary combustion zone to burn overall rich, with 

excess air added higher in the furnace to burn out products of incomplete combustion. The 

rotational effect of the combustion air is induced by large ROFA fans in the upper furnace, 

and the ROFA nozzles are designed to increase turbulence within the furnace. Increased 

turbulence should allow for deeper combustion staging, and enable the furnace volume to 

be used more effectively for the combustion process. 

The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan, 

and control system instrumentation. To achieve rotation, secondary combustion air is 

pressurized by the ROFA fans and enters the furnace through nozzles positioned to induce 

the combustion products to rotate and mix in the upper furnace sections. The fans required 

to produce the rotation can be large, and space constraints on existing units can make the 

placement of the ROFA fans difficult. 

The ROFA system also depends on deep staging to reduce initial NOx production. Burner 

stoichiometric ratios with a ROFA system may be as low as 0.80 to 0.85. Deep staging 

 

5

 See, MobotecUSA at www.mobotecusa.com. 
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also extends the combustion process higher in the furnace which can lead to higher upper 

furnace temperatures and higher furnace exit gas temperatures. Shifting temperature to the 

upper furnace can significantly impact boiler performance in the reheat and superheat 

sections of the boiler. 

MobotecUSA’s Rotamix® system combines the rotating opposed overfire air system with 

urea injection into the flue gas (SNCR) to reduce NOx emissions. The turbulent air 

injection and mixing provided by ROFA may allow for more effective mixing of chemical 

reagents with the combustion products in the furnace. The turbulent mixing created by the 

ROFA system is designed to improve distribution of the ammonia or urea reagent and may 

reduce the quantity of reagent required by the SNCR control system. 

As discussed in subsection 3.2.1.1, Oswego Units 5 & 6 are currently equipped with lowNOx burners, OFA and FGR. The effectiveness of the existing combustion system is 

limited by operating issues associated with deep staging in the primary burner zone and 

OFA jet penetration. The same operating issues would apply to the ROFA system. At 

similar burner stoichiometric ratios either combustion control system (i.e., LNB/OFA or 

LNB/ROFA) would be expected to achieve similar boiler NOx emissions. 

Based on a review of available information, ROFA has been installed as a retrofit NOx 

control system on a limited number of coal-fired boilers, and only one boiler greater than 

200 MW in size. Although it may be technically feasible to apply the ROFA design to 

Oswego Units 5 & 6, there is no technical basis to conclude that the ROFA design would 

provide additional NOx reduction beyond that achieved with modifying the existing OFA 

system. All OFA systems will be limited by the degree of staging and residence time in the 

furnace. Therefore, ROFA will not be evaluated as a specific control alternative, but will 

be included in the overall evaluation of potentially feasible combustion controls. 

Similarly, the technical and physical limitations affecting SNCR effectiveness described in 

subsection 3.2.2.1 would also apply to the Rotamix control system. Rotamix is a SNCR 

control system (i.e., ammonia injection system) coupled with the ROFA rotating injection 

nozzle design. Technical limitations, including the physical size of the boiler and boiler 

residence time, would apply to the Rotamix control system. There is no technical basis to 

conclude that Rotamix urea injection design addresses these unresolved technical 

difficulties or provided additional NOx removal. Therefore, Rotomix will not be evaluated 

as a specific control alternative, but will be included in the overall evaluation of potentially 

feasible SNCR control systems. 
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3.2.3.2 NOx Star Control System 

NOxStar is a proprietary technology designed to reduce boiler NOx. The process 

continuously injects controlled quantities of an ammonia-based reagent with relatively 

small amounts of hydrocarbon (typically natural gas or propane) into the convective pass of 

the boiler at a temperature of around 1,600 to 1,800 o

F.6 At the elevated temperatures the 

hydrocarbon auto-ignites to form a plasma of free radicals which autocatalyzes the reaction 

of NH3 and NOx to form N2 and H2O (similar to the SCR reactions shown in subsection 

3.2.2.2). 

The NOxStarTM concept was first demonstrated in 2001 at Mitsui Babcock’s 0.55 mmBtu 

coal-test facility using a single injection point. As a result of near ideal mixing, NOx 

reduction levels of up to 90% were achieved with acceptable ammonia slip levels. The 

NOxStarTM control system offers the potential to reduce NOx emissions without the need to 

install a solid catalyst layer (i.e., SCR), and without the associated operational issues such 

as chemical poisoning, physical plugging, sintering, pressure drop requiring new ID fans, 

and spent catalyst handling. The NOxStarTM concept should also minimize the conversion 

of SO2 to SO3, which can be a significant issue with SCR control. 

The NOxStarTM process was demonstrated in full scale tests at TVA’s Kingston 9 Power 

Plant. Kingston 9 is a coal-fired 200 MW tangentially fired boiler. Test results showed 

that the NOx reduction potential was a function of the flue gas temperature at the injection 

point, fuel sulfur content, and residence time downstream of the injection lances. NOx 

reductions were limited to approximately 50% of the inlet NOx rate. To provide additional 

NOx control a single layer of catalyst could be installed in the existing ductwork 

downstream of the ammonia/hydrocarbon injection system (NOxStarTM Plus). Excess 

ammonia injected in the flue gas would react with NOx in the presence of the catalyst to 

form N2 and H2O. As with more conventional SCR, the effectiveness of the catalyst layer 

would be a function of flue gas composition, residence time, NH3:NOx ratio, and flue gas 

temperature. 

At this point, the NOxStarTM technology has been demonstrated only on a limited basis on 

large boilers. Potential NOx removal efficiencies would be a function of NH3-NOx mixing, 

flue gas temperature, flue gas composition, and residence time downstream of the injection 

lances. Achieving NOx removal efficiencies greater than approximately 50% may require 

 

6

 See, Morris, K.W., Hesselmann, G., NOxStarTM Plant Demonstration, Mitsui Babcock, not dated. 
NRG Energy July 26, 2010 

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the installation of a layer of SCR catalyst in the ductwork downstream of the 

ammonia/hydrocarbon injection system. 

It is likely that NRG would be required to conduct extensive design engineering and testing 

to evaluate the technical feasibility and long-term effectiveness of these control systems on 

Oswego Units 5 & 6. Detailed design of the lances, mixing, optimization of the reagent 

supply across the boiler gas pass, flue gas temperatures and flow distribution would have to 

be studied. It would also have to be determined whether sufficient space is available in the 

existing duct work to install a layer of catalyst. 

Without significant engineering and testing it is not possible to determine whether technical 

difficulties associated with flue gas chemistry, residence time, and space limitations would 

preclude the successful use of these control systems on Oswego Units 5 & 6. BART does 

not require applicants to experience extended time delays or resource penalties to allow 

research to be conducted on an emerging control technique. Therefore, at this time the 

NOxStarTM and NOxStarTM Plus control systems are not considered available NOx retrofit 

control systems for Oswego Units 5 & 6, and will not be further evaluated in the BART 

determination. 

3.2.3.3 Powerspan ECO Technology 

Powerspan’s ECOTM process is a multi-pollutant control technology designed to capture 

SO2, NOx, and mercury from coal-fired boilers. The process utilizes a dielectric barrier 

discharge reactor to oxidize pollutants in the flue gas steam, followed by an ammonia wet 

scrubber and wet ESP for removal of oxidized pollutants and by-products. The technology 

produces a potentially saleable ammonium sulfate/ammonium nitrate fertilizer by-product. 

The ECOTM control system is designed for installation downstream of an existing 

particulate control device. Flue gas flows from the particulate control device to an 

electrocatalytic oxidation (ECO) reactor, where hydroxyl (OH) radicals and atomic oxygen 

(O) are formed by the reaction of high-energy electrons with water and oxygen molecules.7

 

These radicals then react with pollutants in the flue gas, oxidizing SO2 to sulfuric acid and 

NOx to nitric acid (HNO3). 

 

7

 The description for the ECOTM control technology was taken from: Status of Integrated Emission Control 

Process Development: Airborne and ReACT Process Technical Review, Section 2.0, EPRI, Palo Alto, CA: 

2005. 1010338. 
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Oxidized flue gas is then sent to a double loop ammonia scrubber where the sulfuric and 

nitric acids are removed from the flue gas. In the upper loop of the scrubber, ammonia is 

added to react with the acids to form ammonium sulfate and nitrate. The lower loop of the 

scrubber cools and saturates the flue gas and concentrates the by-products for removal. 

Oxidation air is added to the lower loop to further oxidize sulfites and nitrites. 

Following the ammonia scrubber, the flue gas enters a mist eliminator where entrained 

droplets are removed prior to the gas entering a wet electrostatic precipitator (WESP). 

Acid aerosols are collected in the WESP. Soluble ammonium sulfate and nitrate exit the 

ammonia scrubber in a bleed stream that is treated by filtration to remove ash and insoluble 

metal compounds. The stream is then passed through an activated carbon absorption bed 

for mercury removal. The purified by-product stream is then sent to a crystallizer where 

sulfate and nitrate crystals are formed by evaporation. The crystals are then dried and 

granulated to form a fertilizer by-product that may be marketable depending on quality and 

local market conditions. 

The ECOTM technology has been pilot tested on a 1-MW equivalent slipstream at the R.E. 

Burger Plant located in Ohio. Following pilot testing, Powerspan built a 50 MW 

commercial demonstration unit at the same location. Emissions testing from the 

commercial scale demonstration have shown that the control technology can successfully 

remove SO2, NOx, and mercury for coal-fired flue gas. 

At this point, the ECOTM technology is not considered a technically feasible and 

commercially available NOx retrofit control option for oil-fired boilers. The ECOTM 

technology is a multi-pollutant control technology that would have no practical application 

as a NOx-only retrofit control system on an oil-fired unit. Therefore, the ECOTM 

technology is not considered a technically feasible NOx retrofit control system for Oswego 

Units 5 & 6, and will not be evaluated further in the BART determination. 

3.2.4 NOx Control - Summary 

Results of Step 2 of the NOx BART Analysis (technical feasibility analysis of potential NOx 

control technologies) are summarized in Table 3-2. 
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Table 3-2 

Technical Feasibility of Potential NOx Control Technologies – Oswego Unit 3 

Controlled NOx Emission 

Rate 

In Service on 

Existing PC Boilers Control Technology Unit 5 Unit 6 Yes No Technically Feasible and Comm

Retrofit Control Te

Baseline LNB/OFA/FGR 0.22 0.19 x Technically feasible. Optimize LNB/OFA/FGR with Neural Network Control System 

0.21 0.18 x Technically feasible. 

LN-REACH (pressure atomizer) plus modified OFA 

0.18 0.17 x Technically feasible. 

LN-REACH (steam atomizer) plus modified OFA 

0.17 0.16 Technically feasible. Steam would 

boiler during normal operation and fboiler during startup. 

Gas Co-Firing (150 MW) Unit 6 Not 

Available 

Not Feasible x Unit 6 is currently equipped to co-fi

availability, natural gas co-firing is l150 MW (heat input). Additional co5, would require installation of a new which is not considered a technicallHowever, co-firing natural gas at loa300 to 400 MW is not a technically boiler tightness, residence time, and natural gas at the levels needed for ewould require significant modificatiparts, and is not a practical control o
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Table 3-2 continued:

Controlled NOx Emission 

Rate 

In Service on 

Existing PC Boilers Control Technology Unit 5 Unit 6 Yes No Technically Feasible and Comm

Retrofit Control Te

LN-REACH (pressure atomizer) plus modified OFA and Gas Reburn 

Not 

Available 

Not Feasible x 

LN-REACH (steam atomizer) plus modified OFA and Gas Reburn 

Not 

Available 

Not Feasible x 

The gas reburn technically is also suresidence time, and FEGT issues dis3.2.1.4. At the natural gas heat inpueffective NOx control at boiler load400 MW, the gas reburn option wousignificant FEGT issues, and would significant modifications to the boilTherefore, Gas Reburn is not considoption on Unit 6. Using gas rebrrn orequire installation of a new natural considered a technically feasible opt

 LN-REACH (pressure atomizer) plus modified OFA and FLGR 

0.13 0.13 x 

LN-REACH (steam atomizer) plus modified OFA and FLGR 

0.12 0.12 x 

FLGR is a technically feasible optionatural gas currently available at the residence time needed for effective Nwould be coupled with upgraded buIn addition, heat input from natural approximately 4% of the total boiler to minimize potential FEGT issues. 

LN-REACH (pressure atomizer) plus modified OFA and SNCR 

0.14 0.14 x 

LN-REACH (steam atomizer) plus modified OFA and SNCR 

0.13 0.13 x 

SNCR (coupled with optimizing the OFA system) is a technically feasiblboth units. Effectiveness of the optiboiler size, flue gas characteristics, a(e.g., designing the system to achievthe desired temperature window). 
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Table 3-2 continued:

Controlled NOx Emission 

Rate 

In Service on 

Existing PC Boilers Control Technology Unit 5 Unit 6 Yes No Technically Feasible and Comm

Retrofit Control Te

SCR 0.03 0.03 x Although not recommended on an o

technically feasible NOx control optsystem would be limited by the fuel characteristics (e.g., vanadium conc

conversion, ammonia slip, and other plant impacts. 

Rotating Overfire Air (ROFATM) NA NA ROFA has been demonstrated on sm

be a technically feasible retrofit conHowever, there is no technical basis will provide additional NOx control with modified OFA. Therefore, ROevaluation of other OFA control sys

RotamixTM NA NA Rotamix control systems have been 

boilers. However, there is no techniRotamix will provide additional NOachievable with other SNCR control Rotamix will be included in the evacontrol systems. 

NOxStarTM and NOxStarTM Plus Controls NA NA NOxStarTM has been demonstrated o

coal-fired boilers. Based on a review it was determined that, at this time, tnot a technically feasible and commretrofit control technology for Oswe

Powerspan ECO Technology NA NA The ECO control system has been d

number of coal-fired boilers. Based information it was determined that, technology is not a technically feasiavailable NOx retrofit control techn& 6. 
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3.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

The technically feasible and commercially available NOx retrofit control technologies are listed in 

Table 3-3 for Oswego Units 5 & 6. The effectiveness of each control technology was evaluated in 

Step 2. Technically feasible control technologies are listed in Table 3-3 in descending order of 

control efficiency. 

Table 3-3 

Technically Feasible NOx Control Technologies 

Oswego Units 5 & 6 

Control Technology Unit 5 

Controlled NOx 

Emissions 

30-day rolling average 

 (lb/mmBtu) 

Unit 6 

Controlled NOx 

Emissions 

30-day rolling average 

 (lb/mmBtu) 

SCR 0.03 0.03 

LN-REACH (steam atomizer) plus modified 

OFA and FLGR 

0.12 0.12 

LN-REACH (steam atomizer) plus modified 

OFA plus SNCR 

0.13 0.13 

LN-REACH (pressure atomizer) plus 

modified OFA and FLGR 

0.13 0.13 

LN-REACH (pressure atomizer) plus 

modified OFA plus SNCR 

0.14 0.14 

LN-REACH (steam atomizer) plus modified 

OFA 

0.17 0.16 

LN-REACH (pressure atomizer) plus 

modified OFA 

0.18 0.17 

Optimize LNB/OFA/FGR with Neural 

Network Control System 

0.21 0.18 

Baseline LNB/OFA/FGR 0.22 0.19 

 
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3.4 Step 4: Evaluate the Technically Feasible NOx Control Technologies 

3.4.1 NOx Control Technologies – Economic Evaluation 

The most effective NOx retrofit control systems, in terms of reduced emissions, that are 

considered to be technically feasible for Oswego Units 5 & 6, include post-combustion SCR. 

The effectiveness of an SCR control system is dependent on several site-specific system 

variables, including fuel characteristics, flue gas characteristics, catalyst layers, NH3-to-NOx 

stoichiometric ratio, vanadium and potassium in the fuel oil ash, NH3 slip, and catalyst 

plugging/deactivation. 

FLGR and SNCR control technologies provide the next most effective NOx control. Either 

option requires combustion control modifications (i.e., oversized LN-REACH and modified 

OFA) to provide adequate flue gas mixing and residence times. Combustion control 

modifications (i.e., LN-REACH and modified OFA) are the next most effective NOx control 

options. LN-REACH combustion technology and modifying the existing OFA ports to provide 

more effective jet penetration, is a technically feasible NOx control option. The LN-REACH 

burner technology can be designed with either mechanical pressurized or steam pressurized 

burner nozzles. Based on information from burner vendors, it is anticipated that steam 

pressurized nozzles would provide somewhat better atomization and flue gas mixing. Finally, 

installation of a Neural Network control system would provide some NOx control beyond the 

baseline emissions. 

Control systems that require natural gas co-firing at levels above approximately 300 to 400 

MW, including natural gas co-firing and gas reburn, are not considered technically feasible due 

to boiler tightness, residence time, and FEGT limitations. In addition, these co-firing options 

would require the facility to subscribe to a specific quantity of natural gas, which cannot be 

guaranteed by the facility due to boiler operations. Furthermore, because only a limited 

quantity of natural gas is available at the station, gas reburn and gas co-firing control systems 

are not considered an available control option for Unit 5. 

Economic impacts associated with the potentially feasible NOx control systems were evaluated 

in accordance with EPA guidelines (40 CFR Part 51 Appendix Y) and the NYDEC Air Guide 

20 - Economic and Technical Analysis for Reasonably Available Control Technology. For the 

economic impact analysis, projected annual emissions (tpy) were calculated based on a 3.2% 

baseline capacity factor for Oswego Units 5 & 6. A 3.2% capacity factor is equivalent to the 

highest 12-month capacity factor for Unit 5 during the baseline period, and is representative of 

actual option of the units over the past several years. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

38 

Cost estimates were compiled from a number of data sources. Major equipment costs were 

developed based on equipment costs recently developed for similar projects, taking into 

consideration site-specific retrofit challenges and limitations. Capital costs include the 

equipment, material, labor, and all other direct costs needed to retrofit Oswego Units 5 & 6 

with the control technologies. 

Fixed and variable O&M costs were developed for each control system. Fixed O&M costs 

include operating labor, maintenance labor, maintenance material, and administrative labor. 

Variable O&M costs include the cost of consumable, including reagent (e.g., ammonia), byproduct management, water consumption, and auxiliary power requirements. Auxiliary power 

requirements reflect the additional power requirements associated with operation of the new 

control technology, including operation of any new ID fans as well as the power requirements 

for pumps, reagent handling, and by-product handling. 

Summarized in Table 3-4 are the expected controlled NOx emission rates, and annual NOx 

mass emissions, associated with each technically feasible retrofit technology. Table 3-5 

provides a budgetary capital cost estimate for each control system. Tables 3-6 and 3-7 

summarize the total annual costs and average cost effectiveness of each control system on Units 

5 & 6, respectively. More detailed budgetary cost estimates for each control technology are 

included in Attachment A. 
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

39 

Table 3-4 

Annual NOx Emissions* 

Unit 5 Unit 6 

Control Technology 

NOx 

Emission 

Rate 

(lb/mmBtu) 

Annual NOx 

Emissions 

(tpy) 

Annual 

Reduction in 

Emissions 

(tpy from 

baseline) 

NOx 

Emission 

Rate 

(lb/mmBtu) 

Annual NO

Emissions 

(tpy) 

SCR 0.03 33.0 209.1 0.03 33.2 LN-REACH (steam atomizer) plus modified OFA and FLGR 

0.12 132.1 110.0 0.12 132.7 

LN-REACH (steam atomizer) plus modified OFA plus SNCR 

0.13 143.1 99.0 0.13 143.8 

LN-REACH (pressure atomizer) plus modified OFA and FLGR 

0.13 143.1 99.0 0.13 143.8 

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 

0.14 154.1 88.0 0.14 154.8 

LN-REACH (steam atomizer) plus modified OFA 

0.17 187.1 55.0 0.17 177.0 

LN-REACH (pressure atomizer) plus modified OFA 

0.18 198.1 44.0 0.18 188.0 

Optimize LNB/OFA/FGR with Neural Network Control System 

0.21 231.1 11.0 0.18 199.1 

Baseline LNB/OFA/FGR 0.22 242.1 -- 0.19 210.1 

 *Annual emissions for each control option were calculated using a 3.2% capacity factor for each unit, based on historical annual 
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

40 

Table 3-5 

NOx Emission Control System 

Capital Cost Summary 

Control Technology 

Total Capital 

Investment* 

($) 

Total Capital 

Investment 

($/kW-gross) 

Annual Capital 

Recovery Cost 

($/year) 

SCR $104,400,000 $122.8 $14,864,200 LN-REACH (steam atomizer) plus modified OFA and FLGR 

$26,820,000 $31.6 $3,818,600 

LN-REACH (steam atomizer) plus modified OFA plus SNCR 

$13,200,000 $15.5 $1,879,400 

LN-REACH (pressure atomizer) plus modified OFA and FLGR 

$23,220,000 $27.3 $3,306,000 

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 

$9,600,000 $11.3 $1,366,800 

LN-REACH (steam atomizer) plus modified OFA 

$5,940,000 $7.0 $845,700 

LN-REACH (pressure atomizer) plus modified OFA 

$2,340,000 $2.8 $333,200 

Optimize LNB/OFA/FGR with Neural Network Control System 

$1,200,000 $1.4 $170,900 

* Capital costs include the cost of major components and indirect installation costs such as foundations, 

mechanical erection, electrical, piping, and insulation for the control system. 
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

41 

Table 3-6 

Oswego Unit 5 

NOx Emission Control - Cost Effectiveness* 

Control Technology 

Annual Capital 

Recovery Cost 

($/year) 

Annual 

Operating 

Costs 

($/year) 

Total Annual 

Costs 

($/year) 

Annual 

Emission 

Reduction 

(tpy) 

A

E

SCR $14,864,200 $423,800 $15,288,000 209.1 LN-REACH (steam atomizer) plus modified OFA and FLGR 

$3,818,600 $297,700 $4,116,300 110.0 

LN-REACH (steam atomizer) plus modified OFA plus SNCR 

$1,879,400 $317,800 $2,197,200 99.0 

LN-REACH (pressure atomizer) plus modified OFA and FLGR 

$3,306,000 $297,700 $3,603,700 99.0 

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 

$1,366,800 $317,600 $1,684,400 88.0 

LN-REACH (steam atomizer) plus modified OFA 

$845,700 $54,800 $900,500 55.0 

LN-REACH (pressure atomizer) plus modified OFA 

$333,200 $51,700 $384,500 44.0 

Optimize LNB/OFA/FGR with Neural Network Control System 

$170,900 $300,000 $470,900 11.0 

 * Total annual costs and annual emission estimates for each control option were calculated based on a 3.2% capacity factor
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

42 

Table 3-7 

Oswego Unit 6 

NOx Emission Control - Cost Effectiveness* 

Control Technology 

Annual Capital 

Recovery Cost 

($/year) 

Annual 

Operating 

Costs 

($/year) 

Total Annual 

Costs 

($/year) 

Annual 

Emission 

Reduction 

(tpy) 

A

E

SCR $14,864,200 $423,800 $15,288,000 176.9 LN-REACH (steam atomizer) plus modified OFA and FLGR 

$3,818,600 $297,700 $4,116,300 77.4 

LN-REACH (steam atomizer) plus modified OFA plus SNCR 

$1,879,400 $317,800 $2,197,200 66.3 

LN-REACH (pressure atomizer) plus modified OFA and FLGR 

$3,306,000 $297,700 $3,603,700 66.3 

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 

$1,366,800 $317,600 $1,684,400 55.3 

LN-REACH (steam atomizer) plus modified OFA 

$845,700 $54,800 $900,500 33.1 

LN-REACH (pressure atomizer) plus modified OFA 

$333,200 $51,500 $384,900 22.1 

Optimize LNB/OFA/FGR with Neural Network Control System 

$170,900 $300,000 $470,900 11.0 

 * Total annual costs and annual emission estimates for each control option were calculated based on a 3.2% capacity factor
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

43 

The average annual cost effectiveness of the SCR control option on Units 5 & 6 is in the range 

of $73,113/ton (Unit 5) to $86,422/ton (Unit 6). Equipment costs, retrofit challenges, and 

auxiliary equipment costs, including the ammonia handling and delivery systems, all have a 

significant impact on the cost of SCR control. There are also significant annual operating 

costs with SCR control, including energy costs associated with the additional pressure drop 

across the SCR, reactant costs, and catalyst replacement costs. Although retrofit SCR has the 

potential to achieve the lowest NOx emission rates, it is an expensive NOx control option and is 

clearly not cost effective on Oswego Units 5 & 6. 

The second most effective NOx control retrofit options include FLGR. The FLGR process 

injects natural gas above the main combustion furnace to reduce NOx to N2. As described in 

subsection 3.2.1.6, the natural gas reburn fuel injection level in the upper furnace must be 

installed where sufficient residence time exists for the fuel to complete its burnout process. To 

provide sufficient residence time, installation of FLGR control systems on the Oswego boilers 

would be coupled with the upgraded LN-REACH and modified OFA controlled systems 

described in section 3.2.1.2. 

Total capital costs for the FLGR and combustion control system upgrades would be in the 

range of $23.2 to $26.8M, or approximately $27 to $31/kW-gross. Of this total, approximately 

85% of the costs are associated with the FLGR control system. Capital costs associated with 

FLGR include the installation of gas injectors (generally two or more levels of injectors are 

required), modifications to the boilers to provide access at the optimal temperature zone, 

installation of additional safety and temperature sensors in the reburn zone, and modifications 

to the units’ existing control system. Typically, each gas injector has an automatic modulating 

flow control valve to optimize flow to the individual injectors. O&M costs are somewhat less 

than control options that include a reactant (e.g., ammonia or urea), but include costs associated 

with securing the reburn fuel (natural gas), as well as energy costs incurred due to slight loss in 

overall boiler efficiency. The average cost effectiveness of FLGR control ranges from 

$36,401/ton (Unit 5) to $54,353/ton (Unit 6). The control system is less cost effective on Unit 

6 because of the unit’s lower baseline emission rate. Because of the capital costs associated 

with FLGR and the relatively small reduction in annual NOx emissions (from baseline), FLGR 

is not a cost effective NOx control option for Oswego Units 5 & 6. 

The SNCR control options also have relatively high average cost effectiveness and high 

incremental cost effectiveness (compared to the corresponding combustion control option 

without SNCR). As with FLGR, to be effective, SNCR control must be combined with the 

combustion modifications to provide adequate mixing and residence time. The combination of 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

44 

SNCR combined with upgrading the existing combustion controls has an average cost 

effectiveness of $19,141/ton (Unit 5 with pressure atomizers) to $33,140/ton (Unit 6 with steam 

atomizers). In addition, the incremental cost effectiveness of SNCR ranges from approximately 

$29,000/ton on Unit 5 to $39,000/ton on Unit 6 (compared to upgrading the combustion 

controls without SNCR). 

Capital costs and annual O&M costs both contribute to the relatively high cost effectiveness of 

SNCR control. Capital costs of the SNCR system are estimated to be in the range of $8.5/kWgross. Capital costs include the urea handling and storage system, urea injection system, and 

control system. In addition, installation of SNCR typically requires modifications to the units’ 

air heaters. Modifications to the air heaters are required to minimize the potential for 

ammonium bisulfate formation and the resulting operating impacts. Annual O&M costs 

associated with SNCR include auxiliary power costs associated with the urea injection system 

and the reagent costs. The significant increase in total annual costs coupled with the relatively 

small decrease in annual emissions (approximately 25% from the corresponding combustion 

control system option) results in the relatively high average cost effectiveness and high 

incremental cost effectiveness of SNCR control. Thus, SNCR is not a cost effective retrofit 

NOx control system on Oswego Units 5 & 6. 

Combustion modifications (including LN-REACH burners and modified OFA) have average 

cost effectiveness values ranging from $8,748/ton (Unit 5 with pressure atomizers) to 

$17,416/ton (Unit 6 with pressure atomizers). Combustion control modifications are less costeffective on Unit 6 because of its lower baseline NOx emission rate. On both units, the LNREACH option with pressure atomization is more cost effective than the LN-REACH option 

with steam atomization. Capital costs associated with upgrading the combustion control 

systems, including new oversized LN-REACH burners and physical modifications to the OFA 

ports, are estimated to be in the range of approximately $2.8/kW-gross (with pressure 

atomization) to approximately $7.0/kW-gross (with steam atomization). Operating costs 

associated with combustion control options are generally insignificant. 

Although combustion system modifications are significantly less expensive than the postcombustion control systems, combustion controls are still not cost effective on Oswego Units 5 

& 6. Both units are already equipped with LN-REACH burners, OFA, and FGR, and both units 

already achieve relatively low NOx emission rates. Replacing the existing combustion controls 

with oversized LN-REACH burners and modifying the OFA system to provide more residence 

time and mixing should reduce NOx emissions by approximately 15 to 20% (depending on the 

baseline NOx emission rate). However, a 15% reduction in NOx emissions results in a 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

45 

relatively minor decrease in annual NOx emissions because of the units’ baseline capacity 

factors. 

During the baseline period of 2007 – 2009, annual capacity factors for both units ranged from 

0.52% (Unit 5, 2009) to 2.68% (Unit 5, 2007). The highest 12-month rolling average capacity 

factor during the baseline period was 3.2% (Unit 5), which was used to calculate baseline and 

projected annual emissions. The maximum annual capacity factor for either unit since 2005 

was 9.56% (Unit 5, 2005). These low capacity factors, coupled with the existing combustion 

controls, lead to low baseline annual NOx emissions, and higher cost effectiveness numbers. 

Assuming the units continue to operate at low capacity factors, combustion modifications 

would not be cost effective. 

The final NOx control option involves installing a neural network (NN) control system on the 

units to provide some additional NOx control with the existing LN-REACH and OFA systems. 

Based on control achieved at other existing units, it is expected that a NN control system could 

achieve a reduction of approximately 5% in the long-term average NOx emission rate. Capital 

costs of a NN control system are in the range of $1.2M, or $1.4/kW-gross. Operating costs 

associated with NN control are generally insignificant; however, based on experience with NN 

control systems on existing units, it was determined that one full-time operator would be 

needed to ensure proper operation of the neural network control system. Taking into 

consideration potential emission reductions, capital, and operating costs, the average cost 

effectiveness of NN control would be in the range of $43,000/ton. Because of the relatively 

small reduction in annual NOx emissions, NN control is not cost effective on Oswego Units 5 

& 6. 

3.4.2 NOx Control Technologies – Environmental Impacts 

Combustion modifications designed to decrease NOx formation (e.g., lower temperature and 

less oxygen availability) also tend to increase the formation and emission of CO. Therefore, 

the combustion controls must be designed to reduce the formation of NOx while maintaining 

CO at an acceptable level. Other than the NOx/CO trade-off, there are no environmental issues 

associated with using combustion controls to reduce NOx emissions. 

SNCR and SCR control systems have several potential collateral environmental consequences.8

 

First, in order to maintain low NOx emissions, excess reactant (urea or ammonia) will pass 

through the control system. Excess urea/ammonia will tend to increase as NOx emissions are 

 

8

 See, Hinton, W.S., Cushing, K.M., Gooch, J.P., “Balance-of-Plant Impacts Associated with SCR/SNCR 

Installations”, proceedings of the ICAC Forum, 2002. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

46 

driven lower and lower. On an SCR system, ammonia slip also tends to increase as the catalyst 

becomes plugged, blinded, and deactivated. 

Undesirable reactions can occur with SNCR and SCR control systems. With SNCR, excess 

reagent in the flue gas can react with sulfur compounds in the flue gas to form ammonium 

bisulfate and lead to significant plugging of downstream equipment. To minimize potential 

impacts of reactant slip and ammonium bisulfate formation, the SNCR control system would 

have to be designed with a maximum slip of approximately 5 ppm. 

With SCR, a fraction of the SO2 in the flue gas (greater than 1.5% depending on the vanadium 

content of the fuel oil ash) will oxidize to SO3 in the presence of the SCR catalyst. SO3 can 

react with water to form sulfuric acid mist or with ammonia slip to form ammonium sulfate and 

ammonium bisulfate. Ammonium bisulfate is a sticky compound that can adhere to ductwork 

downstream of the SCR and create significant operational and maintenance problems. Sulfuric 

acid mist and ammonium sulfate are classified as condensable particulates; thus, installation of 

an SCR can result in increased PM2.5 emissions. 

On-site ammonia storage also increases the risks associated with an accidental ammonia 

release. Depending on the type, concentration, and quantity of ammonia used, ammonia 

storage/handling will be subject to regulation as a hazardous substance under CERCLA, 

Section 313 of the Emergency Planning and Community Right-to-Know Act, Section 112(r) of 

the Clean Air Act, and Section 311(b)(4) of the Clean Water Act. One strategy that can be used 

to minimize the risk associated with on-site ammonia handling, is to design the ammonia 

handling system as a urea-to-ammonia conversion system. Urea can be delivered to the station 

as an aqueous solution or as a dry solid, and urea storage/handling does not create the process 

safety concerns associated with handling anhydrous ammonia. 

3.4.3 NOx Control Technologies – Energy Impacts 

All of the NOx retrofit control systems require auxiliary power. Auxiliary power requirements 

associated with the LNB/OFA control systems are generally insignificant; however, OFA and 

FLGR systems designed to increase boiler turbulence can require relatively large booster fans 

and increased auxiliary power requirements. Auxiliary power requirements associated with 

SNCR include power requirements for the urea handling and injection system. Auxiliary power 

requirements associated with SCR include the ammonia injection system and additional fan 

power to overcome pressure drop through SCR. Energy impacts associated with each control 

technology were included in the BART economic impact evaluation as an annual auxiliary 

power cost. 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

47 

A summary of the Step 4 economic and environmental impact analysis is provided in Tables 3-

8 and 3-9 for Oswego Units 5 & 6, respectively. 

3.5 NOx RACT/BACT Control Conclusions 

Based on the evaluation of capital costs, operating costs, and annual emission reductions included 

herein, none of the technically feasible and available NOx control options are cost effective on 

Oswego Units 5 & 6. Several site-specific factors contribute to this result. First, there are 

significant capital requirements associated with the post-combustion control systems, including 

SCR, FLGR, and SNCR. Both equipment costs and retrofit challenges contribute to these capital 

costs. Capital costs of post-combustion control range from approximately $11.3/kW-gross (SNCR 

with combustion control modifications) to as high as $122.8/kW-gross (SCR). Capital costs 

associated with combustion control system modifications are significantly less ranging from 

$2.8/kW-gross (with pressure atomization) to $7.0/ton (with steam atomization). 

More importantly, baseline annual NOx emissions from both units are only in the range of 

approximately 240 tpy. Baseline annual NOx emissions are low because of the low capacity factors 

achieved by both units during the baseline period. As discussed above, both units have had 

capacity factors of 3.2% or less during the baseline period, and, in fact, neither unit has had a 

capacity factor above 10% since 2001. Low capacity factors result in low baseline NOx emissions. 

Finally, both units are currently equipped with low-NOx combustion controls, including LNREACH, overfire air (OFA), and flue gas recirculation (FGR) controls, and both units already 

achieve relatively low NOx emission rates (i.e., baseline NOx emission rates for Oswego Units 5 & 

6 are 0.22 lb/mmBtu and 0.19 lb/mmBtu, respectively). Low baseline NOx emission rates, coupled 

with the low unit capacity factors, result in baseline annual NOx emissions of only about 240 tpy 

from each units. The low baseline NOx emission rates contribute significantly to the high costeffectiveness of potential retrofit NOx control technologies. Assuming the units continue to operate 

at low capacity factors, none of the potential NOx control systems, including combustion 

modifications, would be cost effective. 
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

48 

Table 3-8 

Oswego Unit 5 

Summary of NOx BART Impact Analysis 

Control Technology 

Controlled 

Annual 

Emissions 

(tpy) 

Annual 

Emission 

Reductions 

(tpy) 

Total Annual 

Costs 

($/year) 

Average Cost 

Effectiveness 

($/ton) 

Summary of 

SCR 33.0 209.1 $15,288,000 $73,113 Ammonia slip, 

conversion, incremissions, and a

LN-REACH (steam atomizer) plus modified OFA and FLGR 

132.1 110.0 $4,116,300 $37,421 Potential increa

LN-REACH (steam atomizer) plus modified OFA plus SNCR 

143.1 99.0 $2,197,200 $22,194 Reactant storag

ammonia slip emto form ammon

LN-REACH (pressure atomizer) plus modified OFA and FLGR 

143.1 99.0 $3,603,700 $36,401 Potential increa

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 

154.1 88.0 $1,684,400 $19,141 Reactant storag

ammonia slip emto form ammon

LN-REACH (steam atomizer) plus modified OFA 

187.1 55.0 $900,500 $16,873 None 

LN-REACH (pressure atomizer) plus modified OFA 

198.1 44.0 $384,500 $8,748 None 

Optimize LNB/OFA/FGR with Neural Network Control System 

231.1 11.0 $470,900 $42,809 None 

Baseline LNB/OFA/FGR 242.1 -- -- -- NA 
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

49 

Table 3-9 

Oswego Unit 6 

Summary of NOx BART Impact Analysis 

Control Technology 

Controlled 

Annual 

Emissions 

(tpy) 

Annual 

Emission 

Reductions 

(tpy) 

Total Annual 

Costs 

($/year) 

Average Cost 

Effectiveness 

($/ton) 

Summary of 

SCR 33.2 176.9 $15,288,000 $86,422 Ammonia slip, 

conversion, incremissions, and a

LN-REACH (steam atomizer) plus modified OFA and FLGR 

132.7 77.4 $4,116,300 $53,182 Potential increa

LN-REACH (steam atomizer) plus modified OFA plus SNCR 

143.8 66.3 $2,197,200 $33,140 Reactant storag

ammonia slip emto form ammon

LN-REACH (pressure atomizer) plus modified OFA and FLGR 

143.8 66.3 $3,603,700 $54,354 Potential increa

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 

154.8 55.3 $1,684,400 $30,459 Reactant storag

ammonia slip emto form ammon

LN-REACH (steam atomizer) plus modified OFA 

177.0 33.1 $900,500 $27,205 None 

LN-REACH (pressure atomizer) plus modified OFA 

188.0 22.1 $384,900 $17,416 None 

Optimize LNB/OFA/FGR with Neural Network Control System 

199.1 11.0 $470,900 $42,809 None 

Baseline LNB/OFA/FGR 210.1 -- -- -- NA 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

50 

NRG – Oswego Generating Station 

Units 5 & 6 RACT / BART Engineering Study 

Attachment A 

NOx Control System – Budgetary Cost Estimates 
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

51 

Control Option: Neural Network Control System 

Unit 5 

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (Neural Network Control) $1,000,000

Based estimated cost for Neural Network installation (S&L cost database). 

Includes purchased equipment cost and installation.

Contingency $200,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $1,200,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs

(Capital Recover Factor x Total Capital Requirement) $170,900 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $0 65 $ per MWh

0 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $0

Maintenance Costs $300,000 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $300,000

TOTAL ANNUAL COST

Annualized Capital Cost $170,900

Annual Operating Cost $300,000

 Total Annual Cost $470,900

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (Neural Network Control) $1,000,000

Based estimated cost for Neural Network installation (S&L cost database). 

Includes purchased equipment cost and installation.

Contingency $200,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $1,200,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs

(Capital Recover Factor x Total Capital Requirement) $170,900 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $0 65 $ per MWh

0 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $0

Maintenance Costs $300,000 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $300,000

TOTAL ANNUAL COST

Annualized Capital Cost $170,900

Annual Operating Cost $300,000

 Total Annual Cost $470,900
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

52 

Control Option: LN-REACH (pressure atomizers) and Modified OFA 

Unit 5 

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with 

pressure atomizers and modified OFA) $1,950,000

Based on estimated LNR(P)+OFA+FGR retrofit cost (S&L cost database). 

Includes purchased equipment cost and installation.

Contingency $390,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $2,340,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $333,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $0 65 $ per MWh

0 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $0

Maintenance Costs $51,700 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $51,700

TOTAL ANNUAL COST

Annualized Capital Cost $333,200

Annual Operating Cost $51,700

 Total Annual Cost $384,900

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with 

pressure atomizers and modified OFA) $1,950,000

Based on estimated LNR(P)+OFA+FGR retrofit cost (S&L cost database). 

Includes purchased equipment cost and installation.

Contingency $390,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $2,340,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $333,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $0 65 $ per MWh

0 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $0

Maintenance Costs $51,700 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $51,700

TOTAL ANNUAL COST

Annualized Capital Cost $333,200

Annual Operating Cost $51,700

 Total Annual Cost $384,900
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

53 

Control Option: LN-REACH (steam atomizers) and Modified OFA 

Unit 5 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with steam 

atomizers and modified OFA) $4,950,000

Based on estimated LNR(S)+OFA+FGR retrofit cost (S&L cost database). 

Includes purchased equipment cost and installation.

Contingency $990,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $5,940,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $845,700 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $0 65 $ per MWh

0 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $2,200 Includes atomizing steam costs

Maintenance Costs $52,600 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $54,800

TOTAL ANNUAL COST

Annualized Capital Cost $845,700

Annual Operating Cost $54,800

 Total Annual Cost $900,500

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with steam 

atomizers and modified OFA) $4,950,000

Based on estimated LNR(S)+OFA+FGR retrofit cost (S&L cost database). 

Includes purchased equipment cost and installation.

Contingency $990,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $5,940,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $845,700 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $0 65 $ per MWh

0 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $2,200 Includes atomizing steam costs

Maintenance Costs $52,600 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $54,800

TOTAL ANNUAL COST

Annualized Capital Cost $845,700

Annual Operating Cost $54,800

 Total Annual Cost $900,500
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

54 

Control Option: LN-REACH (pressure atomizers) + Modified OFA + SNCR 

Unit 5 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with pressure 

atomizers and modified OFA) $1,950,000

Post-Combustion NOx Control (SNCR) $6,050,000

Contingency $1,600,000 20% Document, Table 6-1.

Total Capital Requirement (TCR) $9,600,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $1,366,800 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $17,100 65 $ per MWh

938 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $154,400 Includes reagent costs

Maintenance Costs $146,100 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $317,600

TOTAL ANNUAL COST

Annualized Capital Cost $1,366,800

Annual Operating Cost $317,600

 Total Annual Cost $1,684,400

Based on estimated LNR(P)+OFA+FGR+SNCR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

SNCR, and auxiliary equipment including installation.

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with pressure 

atomizers and modified OFA) $1,950,000

Post-Combustion NOx Control (SNCR) $6,050,000

Contingency $1,600,000 20% Document, Table 6-1.

Total Capital Requirement (TCR) $9,600,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $1,366,800 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $17,100 65 $ per MWh

938 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $154,400 Includes reagent costs

Maintenance Costs $146,100 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $317,600

TOTAL ANNUAL COST

Annualized Capital Cost $1,366,800

Annual Operating Cost $317,600

 Total Annual Cost $1,684,400

Based on estimated LNR(P)+OFA+FGR+SNCR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

SNCR, and auxiliary equipment including installation.
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

55 

Control Option: LN-REACH (steam atomizers) + Modified OFA + SNCR 

Unit 5 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with steam 

atomizers and modified OFA) $4,950,000

Post-Combustion NOx Control (SNCR) $6,050,000

Contingency $2,200,000 20% Document, Table 6-1.

Total Capital Requirement (TCR) $13,200,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $1,879,400 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $17,100 65 $ per MWh

938 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $154,500 Includes reagent costs

Maintenance Costs $146,200 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $317,800

TOTAL ANNUAL COST

Annualized Capital Cost $1,879,400

Annual Operating Cost $317,800

 Total Annual Cost $2,197,200

Based on estimated LNR(S)+OFA+FGR+SNCR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

SNCR, and auxiliary equipment including installation.

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with steam 

atomizers and modified OFA) $4,950,000

Post-Combustion NOx Control (SNCR) $6,050,000

Contingency $2,200,000 20% Document, Table 6-1.

Total Capital Requirement (TCR) $13,200,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $1,879,400 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $17,100 65 $ per MWh

938 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $154,500 Includes reagent costs

Maintenance Costs $146,200 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $317,800

TOTAL ANNUAL COST

Annualized Capital Cost $1,879,400

Annual Operating Cost $317,800

 Total Annual Cost $2,197,200

Based on estimated LNR(S)+OFA+FGR+SNCR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

SNCR, and auxiliary equipment including installation.
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

56 

Control Option: LN-REACH (pressure atomizers) + Modified OFA + FLGR 

Unit 5 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with 

pressure atomizers and modified OFA) $1,950,000

Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $3,870,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $23,220,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $3,306,000 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $1,500 65 $ per MWh

82 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency

Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $297,700

TOTAL ANNUAL COST

Annualized Capital Cost $3,306,000

Annual Operating Cost $297,700

 Total Annual Cost $3,603,700

Based on estimated LNR(P)+OFA+FGR+FLGR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

FLGR and auxiliary equipment including installation.

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with 

pressure atomizers and modified OFA) $1,950,000

Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $3,870,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $23,220,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $3,306,000 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $1,500 65 $ per MWh

82 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency

Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $297,700

TOTAL ANNUAL COST

Annualized Capital Cost $3,306,000

Annual Operating Cost $297,700

 Total Annual Cost $3,603,700

Based on estimated LNR(P)+OFA+FGR+FLGR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

FLGR and auxiliary equipment including installation.
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

57 

Control Option: LN-REACH (steam atomizers) + Modified OFA + FLGR 

Unit 5 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with steam 

atomizers and modified OFA) $4,950,000

Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $4,470,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $26,820,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $3,818,600 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $1,500 65 $ per MWh

82 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency

Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $297,700

TOTAL ANNUAL COST

Annualized Capital Cost $3,818,600

Annual Operating Cost $297,700

 Total Annual Cost $4,116,300

Based on estimated LNR(S)+OFA+FGR+FLGR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

FLGR and auxiliary equipment including installation.

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (oversized LN-REACH with steam 

atomizers and modified OFA) $4,950,000

Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $4,470,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $26,820,000

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $3,818,600 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $1,500 65 $ per MWh

82 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency

Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $297,700

TOTAL ANNUAL COST

Annualized Capital Cost $3,818,600

Annual Operating Cost $297,700

 Total Annual Cost $4,116,300

Based on estimated LNR(S)+OFA+FGR+FLGR retrofit cost (S&L cost 

database). Includes purchased equipment costs for combustion controls, 

FLGR and auxiliary equipment including installation.
NRG Energy July 26, 2010 

Oswego Generating Station 

Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

58 

Control Option: Selective Catalytic Reduction (SCR) 

Unit 5 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (combustion controls plus SCR and 

ammonia handling system) $87,000,000

Based on estimated SCR retrofit cost (S&L cost database). Includes SCR, 

initial catalyst, ammonia handling system, and installation.

Contingency $17,400,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $104,400,000 sum of direct capital costs, indirect capital costs, and contingency

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $14,864,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $56,200 65 $ per MWh

3,084 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $206,600 Includes reagent costs 

Maintenance Costs $161,000 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $423,800

TOTAL ANNUAL COST

Annualized Capital Cost $14,864,200

Annual Operating Cost $423,800

 Total Annual Cost $15,288,000

Unit 6 

CAPITAL COSTS [$] Basis

Cost of Emissions Control Equipment Including Installation

NOx Control Equipment (combustion controls plus SCR and 

ammonia handling system) $87,000,000

Based on estimated SCR retrofit cost (S&L cost database). Includes SCR, 

initial catalyst, ammonia handling system, and installation.

Contingency $17,400,000 20%

of direct and indirect capital costs. Alternative Control Techniques 

Document, Table 6-1.

Total Capital Requirement (TCR) $104,400,000 sum of direct capital costs, indirect capital costs, and contingency

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $14,864,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs 

Annual O&M Costs are appropriate for unit capacity factors below 

approximatley 11%

Electricty Costs @ Annual CF $56,200 65 $ per MWh

3,084 kW (control system auxiliary power requirement)

Natural Gas Costs $0

Catalyst Replacement and/or Reactant Costs $206,600 Includes reagent costs 

Maintenance Costs $161,000 Includes labor, supervisory labor, administration and other fixed O&M

Total O&M Costs $423,800

TOTAL ANNUAL COST

Annualized Capital Cost $14,864,200

Annual Operating Cost $423,800

 Total Annual Cost $15,288,000
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

59 

Oswego Unit 5 

NOx Control Cost-Effectiveness Summary 

Option Control Technology Emissions

Tons of NOx 

Removed

Annual Capital 

Recovery Cost

Total Annual 

Operating Costs

T

(tpy) (tpy) ($) ($/kW-gross) ($/year) ($/year) 

Base Baseline Boiler Emissions

242.1

Option 1 Neural Network (NN) 231.1 11.0 $1,200,000 $1.4 $170,900 $300,000 Option 2

LNREACH (pressure atomizers) + modified OFA 198.1 44.0 $2,340,000 $2.8 $333,200 $51,700 

Option 3

LNREACH (steam atomizers) + modified OFA 187.1 55.0 $5,940,000 $7.0 $845,700 $54,800 

Option 4

LNREACH (pressure atomizers) + modified OFA + SNCR 154.1 88.0 $9,600,000 $11.3 $1,366,800 $317,600 

Option 5

LNREACH (pressure atomizers) + modified OFA + FLGR 143.1 99.0 $23,220,000 $27.3 $3,306,000 $297,700 

Option 6

LNREACH (steam atomizers) + modified OFA + SNCR 143.1 99.0 $13,200,000 $15.5 $1,879,400 $317,800 

Option 7

LNREACH (steam atomizers) + modified OFA + FLGR 132.1 110.0 $26,820,000 $31.6 $3,818,600 $297,700 

Option 8 SCR 33.0 209.1 $104,400,000 $122.8 $14,864,200 $423,800 $

Total Capital Investment
NRG Energy 

Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study 

FINAL REPORT 

60 

Oswego Unit 6 

NOx Control Cost-Effectiveness Summary 

Option Control Technology Emissions

Tons of NOx 

Removed

Annual Capital 

Recovery Cost

Total Annual 

Operating Costs

(tpy) (tpy) ($) ($/kW-gross) ($/year) ($/year) 

Base Baseline Boiler Emissions

210.1

Option 1 Neural Network (NN) 199.1 11.0 $1,200,000 $1.4 $170,900 $300,000 Option 2

LNREACH (pressure atomizers) + modified OFA 188.0 22.1 $2,340,000 $2.8 $333,200 $51,700 

Option 3

LNREACH (steam atomizers) + modified OFA 177.0 33.1 $5,940,000 $7.0 $845,700 $54,800 

Option 4

LNREACH (pressure atomizers) + modified OFA + SNCR 154.8 55.3 $9,600,000 $11.3 $1,366,800 $317,600 

Option 5

LNREACH (pressure atomizers) + modified OFA + FLGR 143.8 66.3 $23,220,000 $27.3 $3,306,000 $297,700 

Option 6

LNREACH (steam atomizers) + modified OFA + SNCR 143.8 66.3 $13,200,000 $15.5 $1,879,400 $317,800 

Option 7

LNREACH (steam atomizers) + modified OFA + FLGR 132.7 77.4 $26,820,000 $31.6 $3,818,600 $297,700 

Option 8 SCR 33.2 176.9 $104,400,000 $122.8 $14,864,200 $423,800 

Total Capital Investment