Muskogee Generating Station best available retrofit control technology evaluation

              Oklahoma Gas & Electric
Muskogee Generating Station
Best Available Retrofit Control Technology Evaluation
Prepared by: Sargent & Lundy LLC
Chicago, Illinois
Trinity Consultants
Oklahoma City, Oklahoma
May 28, 2008
Oklahoma Gas & Electric
Muskogee Generating Station – BART Determination
May 28, 2008
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EXECUTIVE SUMMARY
OG&E’s Muskogee Generating Station is located at 5501 Three Forks Road near Muskogee,
Oklahoma. The station has a total of four (4) generating units designated as Muskogee Units 3, 4, 5
and 6. Muskogee Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit.
Muskogee Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of
Muskogee Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit
5 coming on-line in 1978. Construction commenced on Muskogee Unit 6 in 1980, and Unit 6
commenced commercial operation in mid-1984. All three coal-fired units at the Muskogee
Generating Station are dry bottom tangentially-fired pulverized coal (PC) boilers. The boilers fire
subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for
particulate control.
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 certain States, including
Oklahoma, 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.
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).
Muskogee Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BART-eligible
source. Muskogee Unit 6 was not in existence prior to August 7, 1977; therefore, Unit 6 is
not a BART-eligible source. Muskogee Units 4 & 5 are fossil-fuel fired boilers with heat inputs
greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 (i.e., construction
of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of
existing emissions data, both units have the potential to emit more than 250 tons per year of
visibility impairing pollutants. Therefore, Muskogee Units 4 & 5 meet the definition of a BART-eligible
source.
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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. 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 (Δ-
dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling previously
conducted by OG&E determined that the maximum predicted visibility impacts from Muskogee
Units 4 & 5 exceeded the 0.5 Δ-dv threshold at the Upper Buffalo, Caney Creek, and Wichita
Mountains Class I Areas. Therefore, Muskogee Units 4 & 5 were determined to be BART-applicable
sources, subject to the BART determination requirements.
Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51
(Guidelines for BART Determinations Under the Regional Haze Rule). 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. The BART determination process
described in Appendix Y 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 report is the BART determination for Muskogee Units 4 & 5. Because the Muskogee
Generating Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines
were used to prepare the BART determination. Based on an evaluation of potentially feasible
retrofit control technologies, including an assessment of the costs and visibility improvements
associated therewith, OG&E is proposing the BART control technologies and emission rates listed
in Table ES-1.
Table ES-1
Muskogee Units 4 & 5
Proposed BART Permit Limits and Control Technologies
Pollutant Proposed BART
Emission Limit
Proposed BART Technology
NOx 0.15 lb/mmBtu
(30-day average)
Combustion controls including LNB
and OFA
SO2 Existing Permit Limits Low sulfur subbituminous coal
PM10 filterable Existing Permit Limits NA
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1.0 INTRODUCTION
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 certain States, including Oklahoma, 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, Oklahoma must:
􀂾 Identify all BART-eligible sources within the State.
􀂾 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.
􀂾 Require each BART-applicable source to identify, install, operate, and maintain BART
controls.
1.1 OG&E’s Muskogee Generating Station
OG&E’s Muskogee Generating Station is located at 5501 Three Forks Road near Muskogee,
Oklahoma. The station has a total of four (4) generating units designated as Muskogee Units 3, 4, 5
and 6. Muskogee Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit.
Muskogee Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of
Muskogee Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit
5 coming on-line in 1978. Construction commenced on Muskogee Unit 6 in 1980, and Unit 6
commenced commercial operation in mid-1984. All three coal-fired units at the Muskogee
Generating Station are dry bottom tangentially-fired pulverized coal (PC) boilers. The boilers fire
subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for
particulate control.
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1.2 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).
Muskogee Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BART-eligible
source. Muskogee Unit 6 was not in existence prior to August 7, 1977; therefore, Unit 6 is
not a BART-eligible source. Muskogee Units 4 & 5 are fossil-fuel fired boilers with heat inputs
greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 (i.e., construction
of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of
existing emissions data, both units have the potential to emit more than 250 tons per year of
visibility impairing pollutants. Therefore, Muskogee Units 4 & 5 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. EPA has
determined that an individual source will be considered to “cause visibility impairment” if
emissions from the source result in a change in visibility, measured as a change in deciviews (Δ-
dv), that is greater than or equal to 1.0 dv on the visibility in a Class I area. An individual source is
considered to “contribute to visibility impairment” if emissions from the source result in a Δ-dv
change greater than or equal to 0.5 dv in a Class I area. Class I areas nearest the Muskogee Station
include:
Distance from
Class I Area Name Muskogee Station (km)
• Upper Buffalo Wilderness Area (Arkansas) 165
• Caney Creek Wilderness Area (Arkansas) 181
• Hercules-Glades Wilderness Area (Missouri) 231
• Wichita Mountains National Wildlife Refuge (Oklahoma) 325
Visibility impact modeling was conducted by OG&E to determine the baseline predicted maximum
98th percentile Δ-dv visibility impact from Muskogee Units 4 & 5. The maximum predicted
visibility impact associated with the Muskogee Station exceeded the 0.5 Δ-dv threshold at the
Upper Buffalo, Caney Creek, and Wichita Mountains Class I Areas. Therefore, the facility was
determined to be a BART-applicable source subject to the BART determination requirements.
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1.3 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) the technology available; (2) the costs of compliance; (3) the
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; 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). 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, but are not required to use the guidelines
when making BART determinations for other types of sources. Because the Muskogee Generating
Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used
to prepare the BART determination.
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 more detailed description of each step 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
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consider BART as a requirement to redesign the source when considering available control
alternatives.
In an effort to identify all potentially applicable retrofit technologies appropriate for use at each
station, information sources consulted included, but were not necessarily limited to, the
following:
􀂾 EPA's RACT/BACT/LAER Clearinghouse (RBLC) Database;
􀂾 New & Emerging Environmental Technologies (NEET) Database;
􀂾 EPA’s New Source Review bulletin board;
􀂾 Information from control technology vendors and engineering/environmental consultants;
􀂾 Federal and State new source review permits and BACT determinations for coal-fired
power plants;
􀂾 Recently submitted Federal and State new source review permit applications submitted for
coal-fired generating projects; and
􀂾 Technical journals, reports, newsletters and air pollution control seminars.
Step 2. Eliminate Technically Infeasible Options.
In step 2 of the BART determination, the technical feasibility of each potential retrofit
technology is evaluated. Control technologies are considered technically feasible if 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:
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(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 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.
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 decreased electricity available to the power grid
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.
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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 a particular 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.
Modeling should be conducted for SO2, NOx, and direct PM emissions (PM2.5 and/or PM10).
Although visibility improvement must be weighted among the five factors in a BART
determination (along with the costs of compliance, energy and non-air-quality environmental
impacts, existing pollution control technologies in use at the source, and the remaining life of
the source) only potential retrofit control technologies meeting the other four factors were
evaluated for visibility impacts. For example, potential retrofit technologies that are not
technically feasible or cost effective will not be evaluated for visibility impacts. The final
regulation also states that sources that elect to apply the most stringent controls available need
not conduct an air quality modeling analysis for the purpose of determining its visibility
impacts (see, 70 FR 39170 col. 1).
BART control technologies and corresponding emission rates are established based on
information developed from the 5-step BART determination process described above.
2.0 MUSKOGEE UNITS 4 & 5 BART DETERMINATION METHODOLOGY
The BART determination process described in Appendix Y of 40 CFR Part 51 (summarized above)
was used to identify BART controls for Muskogee Units 4 & 5. The methodology was used to
evaluate BART control technologies for NOx, SO2, and PM10. Existing operating parameters and
baseline emissions for Muskogee Units 4 & 5 are summarized in Table 2-1. The operating
parameters and emissions summarized in Table 2-1 form the basis for the Muskogee Units 4 & 5
BART determination.
Baseline emissions from Muskogee Units 4 & 5 were developed based on an evaluation of actual
emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance
with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling
analysis to determine visibility impairment impacts should reflect steady-state operating conditions
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during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the
highest 24-hour block emissions reported during the baseline period. Baseline emission rates
(lb/mmBtu) were calculated by dividing the maximum hourly mass emission rate by the full load
heat input to the boiler.
Table 2-1
Plant Operating Parameters for BART Evaluation
Parameter Muskogee Unit 4 Muskogee Unit 5
Plant Configuration Pulverized Coal-Fired Boiler Pulverized Coal-Fired Boiler
Firing Configuration tangentially-fired tangentially-fired
Plant Output 572 MW (gross) 572 MW (gross)
Maximum Input to Boiler 5,480 mmBtu/hr 5,480 mmBtu/hr
Primary Fuel subbituminous coal subbituminous coal
Existing NOx Controls combustion controls combustion controls
Existing SO2 Controls low-sulfur coal low-sulfur coal
Existing PM10 Controls electrostatic precipitator electrostatic precipitator
Baseline Emissions
Pollutant
Baseline Actual Emissions
Baseline Actual Emissions
lb/hr lb/mmBtu lb/hr lb/mmBtu
NOx 2,710 0.495 2,863 0.522
SO2 4,384 0.800 4,657 0.850
PM10 101 0.018 134 0.024
2.1 Presumptive BART Emission Rates
In the final Regional Haze Rule EPA established presumptive BART emission limits for SO2 and
NOx for certain electric generating units (EGUs) based on fuel type, unit size, cost effectiveness,
and the presence or absence of pre-existing controls.1 The presumptive limits apply to EGUs at
power plants with a total generating capacity in excess of 750 MW. For these sources, EPA
established presumptive emission limits for coal-fired EGUs greater than 200 MW in size. The
presumptive levels are intended to reflect highly cost-effective technologies as well as provide
enough flexibility to states to consider source specific characteristics when evaluating BART.
The BART SO2 presumptive emission limit for coal-fired EGUs greater than 200 MW in size
without existing SO2 control is either 95% SO2 removal, or an emission rate of 0.15 lb/mmBtu,
unless a state determines that an alternative control level is justified based on a careful
consideration of the statutory factors. For NOx, EPA established a set of BART presumptive
1 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131.
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emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal
type. The BART NOx presumptive emission limit applicable to Muskogee Units 4 & 5
(tangentially-fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.
States, as a general matter, should presume that owners and operators of greater than 750 MW
power plants can cost effectively meet the presumptive levels. However, the BART process allows
consideration of site-specific retrofit costs and site-specific visibility impacts. States have the
ability to consider the specific characteristics of the source at issue and to find that the presumptive
limits would not be appropriate for that source. Emission control technologies and emission limits
that differ from the presumptive levels can be established if it can be demonstrated that an
alternative emission rate is justified based on a consideration of the five statutory factors, including
the costs of compliance and the degree of improvement in visibility which may reasonably be
anticipated to result from the use of such technology.
3.0 BART DETERMINATION FOR NITROGEN OXIDES (NOx)
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 “thermal” NOx and “fuel” NOx. 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 NOx is formed by the oxidation of nitrogen in the fuel. NOx formation can
be controlled by adjusting the combustion process and/or installing post-combustion controls.
The major factors influencing thermal NOx formation are temperature, the concentration of
combustion gases (primarily nitrogen and oxygen) in the inlet air, and residence time within the
combustion zone. 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 NOx formation.
Coal properties have a major influence on the formation of fuel NOx. Nitrogen compounds are
released from the coal during coal combustion. Fuel NOx conversion is generally dependent on the
fuel rank. In general, a higher percentage of fuel-NOx is converted to NOx as the rank of fuel
decreases. In other words, units firing lower rank coals (e.g., subbituminous coal or lignite) will
have higher uncontrolled NOx emissions.
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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 Muskogee Units 4 & 5 are
listed in Table 3-1.
Table 3-1
List of Potential NOx Control Options
Control Technology
Combustion Controls
Low NOx Burners & Overfire Air (LNB/OFA)
Flue Gas Recirculation (FGR)
Post-Combustion Controls
Selective Noncatalytic Reduction (SNCR)
Selective Catalytic Reduction (SCR)
Innovative Control Technologies
Rotating Overfire Air (ROFA)
ROFA + SNCR (Rotamix)
Wet NOx Scrubbing
3.2 Step 2: Technical Feasibility of Potential Control Options
NOx control technologies can be divided into two general categories: combustion controls and post-combustion
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 applicable NOx control technology is evaluated below.
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. Combustion control options that may be
applicable to the OG&E boilers are described below.
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3.2.1.1 Low NOx Burners and Overfire Air
Low NOx burners (LNB)2 limit NOx formation by controlling both the stoichiometric and
temperature profiles of the combustion flame in each burner flame envelope. This 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.
In the OFA process, the injection of air into the firing chamber is staged into two 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 of 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 is limited by operational problems since the staged
combustion results in incomplete combustion conditions and a longer flame.
LNB/OFA emission control systems have been installed as retrofit control technologies on
existing coal-fired boilers. Coal-fired boilers retrofit with LNB/OFA combustion
technologies would be expected to operate with actual average NOx emission levels in the
range of 85 to 180 ppmvd @ 3% O2 (approximately 0.12 to 0.25 lb/mmBtu) depending on
the fuel, burner configuration, and averaging time. Based on a review of emissions data
available from the EPA’s electronic emissions data reporting website, subbituminous-fired
boilers retrofit with LNB/OFA have achieved actual average NOx emission rates in the
range of 0.12 to 0.18 lb/mmBtu. 3
Although combustion control systems on coal-fired boilers have demonstrated the ability to
achieve average NOx emission rates below 0.15 lb/mmBtu, combustion control systems
may not be as effective under all boiler operating conditions, especially during load
changes and low load operations. Controlling the stoichiometric and temperature profiles
of the combustion flame, and maintaining the air/fuel mixing needed for NOx control,
becomes more difficult under these operating scenarios. Therefore, it is likely that short-
2 The term “LNB” is used generically in this BART analysis, and refers to advanced low-NOx burners
available from leading boiler/burner manufacturers. The term does not represent any vendor-specific trade
name. As used in this BART analysis, the term “LNB” refers to the available advanced low-NOx burner
technologies.
3 Emission data are available from EPA’s Electronic Data Reporting website:
www.epa.gov/airmarkets/emissions/raw/index.html.
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term boiler NOx emissions will be higher under certain operating conditions. Furthermore,
the mechanisms used to reduce NOx formation (e.g., cooler flame and reduced O2
availability) also tend to increase the formation and emission of CO and VOCs.
Based on information available from burner control vendors, emissions achieved in practice
at existing similar sources, and engineering judgment, it is expected that combustion
controls, including LNB and OFA, on the tangentially-fired Muskogee boilers can be
designed to meet the presumptive NOx BART emission rate of 0.15 lb/mmBtu
(approximately 110 ppmvd @ 3% O2). An average emission rate of 0.15 lb/mmBtu should
be achievable on a 30-day rolling average basis under all normal boiler operating
conditions and while maintaining acceptable CO and VOC emission rates.
3.2.1.2 Flue Gas Recirculation
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.
FGR control systems have been used as a retrofit NOx control strategy on natural gas-fired
boilers, but have not generally been considered as a retrofit control technology on coal-fired
units. Natural gas-fired units tend to have lower O2 concentrations in the flue gas and
low particulate loading. In a coal-fired application, the FGR system would have to handle
hot particulate-laden flue gas with a relatively high O2 concentration. Although FGR has
been used on coal-fired boilers for flue gas temperature control, it would not have
application on a coal-fired boiler for NOx control. Because of the flue gas characteristics
(e.g., particulate loading and O2 concentration), FGR would not operate effectively as a
NOx control system on a coal-fired boiler. Therefore, FGR is not considered an applicable
retrofit NOx control option for Muskogee Units 4 & 5, and will not be considered further in
the BART determination.
3.2.2 Post-Combustion Controls
Post-combustion NOx control systems with potential application to Muskogee Units 4 & 5 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 (approximately 1600ºF - 1900ºF). The
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ammonia or urea reacts with NOx in the flue gas to produce N2 and water as shown in the
equations below.
(NH2) 2CO + 2NO + ½O2 → 2H2O + CO2 + 2N2
2NH3 + 2NO + ½O2 → 2N2 + 3H2O
Flue gas temperature at the point of reagent injection can 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 1,700 oF.
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.
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/volume ratio of the convective pass decreases.
Both of these factors make it difficult to achieve good mixing of reagent and flue gas,
delivery of reagent in the proper temperature window, and sufficient residence time of the
reagent and flue gas in that 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) coal-fired boilers. However, because
of design and operating limitations, SNCR has not been used on large subbituminous coal-fired
boilers. Large subbituminous coal-fired boilers, including Muskogee Units 4 & 5,
would not be able to achieve adequate reagent mixing and residence time within the
required flue gas temperature window to achieve effective NOx reduction.
The physical size of the Muskogee boilers makes it technically infeasible to locate and
install ammonia injection points capable of achieving adequate NH3/NOx contact within
the required temperature zone. Higher ammonia injection rates would be needed to achieve
adequate NH3/NOx contact. Higher ammonia injection rates would result in relatively high
levels of unreacted ammonia in the flue gas (ammonia slip), which could lead to plugging
of downstream equipment.
Another design factor limiting the applicability of SNCR control systems on large
subbituminous coal-fired boilers is related to the reflective nature of subbituminous ash.
Subbituminous coals typically contain high levels of calcium oxide and magnesium oxide
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15
that can result in reflective ash deposits on the waterwall surfaces. Because most heat
transfer in the furnace is radiant, reflective ash can result in less heat removal from the
furnace and higher exit gas temperatures. If ammonia is injected above the appropriate
temperature window, it can actually lead to additional NOx formation.
SNCR control systems have not been designed or installed on large subbituminous coal-fired
boilers, and, as described above, there are several currently unresolved technical
difficulties with applying SNCR to large subbituminous coal-fired boilers (including the
physical size of the boiler, inadequate NH3 mixing, and ash characteristics). Even
assuming that SNCR could be installed on Muskogee Units 4 & 5, NOx control
effectiveness would be marginal, and, depending on boiler exit temperatures, could actually
result in additional NOx formation. Because SNCR has not been designed for, or
demonstrated on, a large subbituminous coal-fired boiler, it was determined that the control
technology is not applicable to Muskogee Units 4 & 5, and SNCR will not be evaluated
further in the BART determination.
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
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 oF and 750 oF to maximize NOx reduction efficiency and minimize ammonium
sulfate formation. This temperature range typically occurs between the economizer and air
heater in 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. Another factor affecting SCR performance is the condition of the
catalyst material. As the catalyst degrades over time or is damaged, NOx removal
decreases.
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SCR has been installed as a retrofit control technology on existing coal-fired boilers,
including boilers firing subbituminous coal. SCR control systems on subbituminous coal-fired
boilers have achieved annual average NOx emission rates in the range of 0.04 to
approximately 0.10 lb/mmBtu.4 Several design and operating variables will influence the
performance of the SCR system, including the volume, age and surface area of the catalyst
(e.g., catalyst layers), uncontrolled NOx emission rate, flue gas characteristics (including
temperature, sulfur content, and particulate loading), and catalyst activity.5 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.
Based on emission rates achieved in practice at existing subbituminous coal-fired units, and
taking into consideration 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 0.07 lb/mmBtu (30-day rolling average) on Muskogee Units 4 & 5. An
emission rate of 0.07 lb/mmBtu is equivalent to an average NOx concentration in the flue
gas of approximately 50 ppmvd @ 3% O2. Reducing NOx emissions below 50 ppmvd @
3% O2 would tend to increase collateral environmental 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 control technologies during the review of available documents.
Innovative NOx control technologies with potential application to the BART study 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 Pahlman™ process, and
wet NOx scrubbing systems.
4 Emission data are available from EPA’s Electronic Data Reporting website:
www.epa.gov/airmarkets/emissions/raw/index.html.
5 See, e.g., Sanyal, A., Pircon, J.J., “What and How Should You Know About U.S. Coal to Predict and
Improve SCR Performance”, proceedings of the USEPA, DOE, EPRI, Combined Power Plant Air Pollution
Control Mega Symposium, Chicago, IL, August 2001. See also, Gutberlet, H., Schluter, A., Licata, A.,
“Deactivation of SCR Catalyst”, proceedings of the DOE’s 2000 Conference on Selective Catalytic and
Selective Non-Catalytic Reduction for NOx Control, Pittsburgh, PA, 2000.
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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
rotation process which includes asymmetrically placed air nozzles.6 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 ROFA
nozzles are designed to increase turbulence within the furnace. Increased turbulence should
prevent the formation of stratified laminar flow, enable the furnace volume to be used more
effectively for the combustion process, and reduce the maximum temperatures of the
combustion zone.
The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan,
and control system instrumentation. A ROFA system was installed on an existing 80-MW
(gross) bituminous-fired utility boiler in the summer of 2002. Test results showed that the
ROFA system reduced NOx emissions from baseline levels between 0.58 and 0.62
lb/mmBtu to approximately 0.22 lb/mmBtu at full load. At lower loads (approximately 40
MW), the ROFA system reduced NOx emissions from 0.59 lb/mmBtu to 0.295 lb/mmBtu.7
The turbulent air injection and mixing provided by ROFA allows for the effective mixing
of chemical reagents with the combustion products in the furnace. MobotecUSA’s
Rotamix® system combines the rotating opposed overfire air system with urea injection into
the flue gas to reduce NOx emissions. The turbulent mixing created by the ROFA system is
designed to improve distribution of the ammonia/urea reagent and may reduce the
ammonia/urea injection required by the SNCR control system. A Rotamix control system
was installed on the same 80-MW unit in the spring of 2004.
ROFA and Rotamix® systems have been demonstrated on smaller coal-fired boilers but
have not been demonstrated in practice on boilers similar in size to Muskogee Units 4 & 5.
As discussed in subsection 3.2.1.1, overfire air control systems are a technically feasible
retrofit control technology, and, based on engineering judgment, the ROFA design could
also be applied to Muskogee Units 4 & 5. However, there is no technical basis to conclude
that the ROFA design would provide additional NOx reduction beyond that achieved with
other OFA designs. Therefore, ROFA control systems will not be evaluated as a specific
6 See, MobotecUSA at www.mobotecusa.com.
7 Coombs, K.A., Crilley, J.S., Shilling, M., Higgins, B., “SCR Levels of NOx Reduction with ROFA and
Rotamix (SNCR) at Dynegy’s Vermilion Power Station,” Presented at 2004 Stack Emissions Symposium,
Clearwater Beach, Florida, July 28-30, 2004.
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control system, but will be included in the overall evaluation of combustion controls (e.g.,
LNB/OFA).
The Rotamix system is a SNCR control system (i.e., ammonia injection system) coupled
with the ROFA rotating injection nozzle design. The technical limitations discussed in
section 3.2.2.1, including the physical size of the boiler, inadequate NH3/NOx contact, fly
ash characteristics, and flue gas temperatures, would apply equally to the Rotamix control
system. There is no technical basis to conclude that the Rotamix urea injection design
addresses these unresolved technical difficulties. Therefore, like other SNCR control
systems, the Rotamix system is determined not to be an applicable NOx control system for
Muskogee Units 4 & 5, and will not be evaluated further in the BART determination.
3.2.3.2 Pahlman Multi-Pollutant Control Process
The Pahlman™ Process is a patented dry-mode multi-pollutant control system. The
process uses a sorbent composed of oxides of manganese (the Pahlmanite™ sorbent) to
remove NOx and SO2 from the flue gas.8 Manganese compounds are soluble in water in the
+2 valence state but not in the +4 state. This property is used in the Pahlman sorbent
capture and regeneration procedure, in that Pahlmanite sorbent is reduced from the
insoluble +4 state to the +2 state during the formation of manganese nitrates and sulfates.
These species are water-soluble, allowing the sulfate, nitrate and Mn+2 ions to be
dissociated and the Mn+2 to be oxidized again to Mn+4 and regenerated. In general, the
liquid metal oxide Pahlmanite sorbent is injected as the flue gas enters a spray dryer. The
sorbent dries as it passes through the spray dryer and is collected downstream at the fabric
filter baghouse. NOx and SO2 will react with the sorbent to form manganese sulfates and
nitrates as the flue gas passes through the filter cake.
The filter cake is pulsed off-line into a wet regeneration process. The regenerated sorbent
is stored in liquid form to be employed again via the spray dryer. The captured nitrogen
and sulfur can be purified and may be converted into granular fertilizer by-products.
To date, bench- and pilot-scale testing have been conducted to evaluate the technology on
utility-sized boilers.9 The New & Emerging Environmental Technologies (NEET)
Database identifies the development status of the Pahlman Process as full-scale
8 See, Enviroscrub Technologies Corporation, www.enviroscrub.com.
9 See, Wocken, C.A., “Evaluation of Enviroscrub’s Multipollutant Pahlman™ Process for Mercury Removal
at a Facility Burning Subbituminous Coal,” Energy & Environmental Research Center, University of North
Dakota, April 2004.
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development and testing. 10 The process is an emerging multi-pollutant control, and there is
limited information available to evaluate it’s technically feasibility and long-term
effectiveness on a large subbituminous-fired boiler. It is likely that OG&E would be
required to conduct extensive design engineering and testing to evaluate the technical
feasibility and long-term effectiveness of the control system on Muskogee Units 4 & 5.
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 Pahlman Process is not considered an available NOx control system for Muskogee Units
4 & 5, and will not be further evaluated in the BART determination.
3.2.3.3 Wet NOx Scrubbing Systems
Wet scrubbing systems have been used to remove NOx emissions from fluid catalytic
cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is
Balco Technologies’ LoTOx™ system. The LoTOx system is a patented process, wherein
ozone is injected into the flue gas stream to oxidize NO and NO2 to N2O5. This highly
oxidized species of NOx is very soluble and rapidly reacts with water to form nitric acid.
The conversion of NOx to nitric acid occurs as the N2O5 contacts liquid sprays in the
scrubber.
Wet scrubbing systems have been installed at chemical processing plants and smaller coal-fired
boilers. The NEET Database classifies wet scrubbing systems as commercially
established for petroleum refining and oil/natural gas production. However the technology
has not been demonstrated on large coal-fired boilers and it is likely that OG&E would
incur substantial engineering and testing to evaluate the scale-up potential and long-term
effectiveness of the system. Therefore, at this time wet NOx scrubbing is not considered to
be an applicable or commercially available retrofit control system for Muskogee Units 4 &
5, and will not be further evaluated in this BART determination.
The results of Step 2 of the NOx BART Analysis (technical feasibility analysis of potential NOx
control technologies) are summarized in Table 3-2.
10 NEET is an on-line repository for information about emerging technologies that reduce emissions from
stationary, mobile, and indoor sources. NEET was developed and is operated by RTI International with
support from the EPA Office of Air Quality Planning and Standards.
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Table 3-2
Technical Feasibility of Potential NOx Control Technologies
Muskogee Generating Station
In Service on
Existing PC
Control Technology Boilers
Controlled NOx
Emission Rate
(lb/mmBtu) Yes No
In Service on
Other
Combustion
Sources?
Technically Feasible on
Muskogee Units 4 & 5?
Low NOx Burners and
Overfire Air
0.15 lb/mmBtu X Yes Technically feasible.
SNCR NA X Yes
SNCR has
been applied
to several
smaller coal-fired
boilers.
Not a technically feasible retrofit
technology for Muskogee Units 4
& 5. SNCR has been used as a
retrofit technology on small and
medium sized (<300 MW) coal-fired
boilers, but has not been
demonstrated on larger boilers.
There are several currently
unresolved technical difficulties
associated with applying SNCR on
a large subbituminous coal-fired
boiler.
SCR
0.07 lb/mmBtu
X
Yes
SCR is a technically feasible
retrofit technology for Muskogee
Units 4 & 5. The effectiveness of
the SCR system will depend on
site-specific considerations
including the ammonia injection
rate, site-specific flue gas
characteristics, ammonia slip, and
frequency of catalyst changes.
ROFA NA X Yes ROFA has been demonstrated on
small coal-fired boilers, and would
be a technically feasible retrofit
control technology. However,
there is no technical basis to
conclude that ROFA will provide
additional NOx control beyond that
achievable with other OFA
systems. Therefore, ROFA will be
evaluated along with other OFA
control systems.
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Table 3-2 continued
Control Technology
Controlled NOx
Emission Rate
(lb/mmBtu)
In Service on
Existing PC
Boilers
In Service on
Other
Combustion
Sources?
Technically Feasible on
Muskogee Units 4 & 5?
Rotamix (SNCR) NA X Yes Rotamix control systems have been
demonstrated on small coal-fired
boilers. However, there are several
currently unresolved technical
difficulties associated with
applying SNCR-type systems on a
large subbituminous coal-fired
boiler. Therefore, Rotamix is not
considered an available retrofit
control technology for Muskogee
Units 4 & 5.
Pahlman Process NA X No Bench- and pilot-scale testing has
been conducted on coal-fired
boilers, however, there is limited
data available assessing the
technical feasibility of this system
on large coal-fired boilers.
Wet NOx Scrubbing NA X Yes The system has been used on
refinery fluid catalytic cracking
units and small coal-fired boilers,
but has not been used on large
coal-fired boilers. Wet NOx
scrubbing systems are not
commercially available or
technically feasible for Muskogee
Units 4 & 5.
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3.3 Step 3: Rank the Technically Feasible NOx Control Options by Effectiveness
The technically feasible and commercially available NOx control technologies for Muskogee Units
4 & 5 are listed in Table 3-3, in descending order of control efficiency.
Table 3-3
Technically Feasible NOx Control Technologies
Muskogee Station
Muskogee Unit 4 Muskogee Unit 5
Control Technology Approximate NOx
Emission Rate*
(lb/mmBtu)
Approximate NOx
Emission Rate*
(lb/mmBtu)
Selective Catalytic Reduction (SCR) 0.07 0.07
Low-NOx Burners and Overfire Air 0.15 0.15
Baseline11 0.495 0.522
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 system, in terms of reduced emissions, that is
considered to be technically feasible for Muskogee Units 4 & 5 includes combustion controls
(LNB/OFA) and post-combustion SCR. This combination of controls should be capable of
achieving the lowest controlled NOx emission rate on an on-going long-term basis. The
effectiveness of the SCR system is dependent on several site-specific system variables,
including the size of the SCR, catalyst layers, NH3/ NOx stoichiometric ratio, NH3 slip, and
catalyst deactivation rate. Based on emission rates achieved in practice at similar sources, and
including a reasonable margin to account for normal system fluctuations, the combination of
combustion controls and SCR should achieve a controlled NOx emission rate of 0.07 lb/mmBtu
(30-day average).
The next most effective NOx retrofit control system that is considered technically feasible for
Muskogee Units 4 & 5 includes combustion controls (LNB/OFA). The combination of
11 Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions
reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmBtu) were calculated
by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The
relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts,
and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control
technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation
of the facility’s permitted emission limits, which are averaged over a longer period of time.
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LNB/OFA on Muskogee Units 4 & 5 (large tangentially fired boilers firing subbituminous coal)
should be capable of meeting the BART presumptive limit of 0.15 lb/mmBtu.
Economic impacts associated with the SCR control systems were evaluated in accordance with
EPA guidelines (40 CFR Part 51 Appendix Y). In accordance with the guidelines in Part III of
Appendix Y, emission estimates used in the modeling analysis to determine visibility
impairment impacts should reflect steady-state operating conditions during periods of high
capacity utilization. Therefore, projected emission rates (lb/hr) were calculated based on the
expected controlled emission rate (lb/mmBtu) achievable on a 30-day rolling average and heat
input to the boiler at full load. Annual emissions (tpy) were calculated assuming a 90%
capacity factor for each unit.
Cost estimates were compiled from a number of data sources. In general, the cost estimating
methodology followed guidance provided in the EPA Air Pollution Cost Control Manual.12
Major equipment costs were developed based on equipment costs recently developed for
similar projects, and include the equipment, material, labor, and all other direct costs needed to
retrofit Muskogee Units 4 & 5 with the control technology.
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 consumables, including reagent (e.g., ammonia), by-product
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 maximum annual
NOx mass emissions, associated with each technically feasible retrofit technology. Table 3-5
presents the capital costs and annual operating costs associated with building and operating
each control system. Table 3-6 shows the average annual cost effectiveness and incremental
annual cost effectiveness for each NOx control system. A detailed summary of the cost
estimates used in this BART determination is included in Attachment A.
12 U.S. Environmental Protection Agency, EPA Air Pollution Cost Control Manual, 6th Ed., Publication
Number EPA 452/B-02-001, January 2002.
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Table 3-4
Annual NOx Emissions
Control Technology
NOx Emission Rate
(lb/mmBtu)
Maximum Annual NOx
Emissions
(tpy)*
Annual Reduction in
Emissions
(tpy from baseline)
Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5
LNB/OFA + SCR 0.07 0.07 1,512 1,512 9,181 9,764
LNB/OFA 0.15 0.15 3,240 3,240 7,453 8,036
Baseline NOx Emissions 0.495 0.522 10,693 11.276 -- --
* Maximum annual emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr
per boiler for 7,884 hours per year (90% capacity factor).
Table 3-5
NOx Emission Control System
Cost Summary (per boiler)
Control Technology
Total Capital
Investment*
($)
Total Capital
Investment
($/kW-gross)
Annual Capital
Recovery Cost
($/year)
Annual
Operating Costs
($/year)
Total Annual
Costs
($/year)
LNB/OFA + SCR $193,077,000 $339 $16,568,000 $14,227,600 $30,795,600
LNB/OFA $14,113,700 $25 $1,211,100 $880,700 $2,091,800
* Capital costs for NOx retrofit control systems will be similar for both Units 4 & 5. Capital costs include the cost of major
components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the
control system. Capital costs for the SCR system include costs associated with installation of LNB/OFA systems.
Table 3-6
NOx Emission Control System
Cost Effectiveness (total for both boilers)
Control Technology
Total Annual
Cost
($/year)
Annual Emission
Reduction
(tpy)
Average Cost
Effectiveness
($/ton)
Incremental Cost
Effectiveness
($/ton)
LNB/OFA + SCR $61,591,200 18,945 $3,251 $16,611
LNB/OFA $4,183,600 15,489 $270 NA
The average annual cost effectiveness of LNB/OFA+SCR on Muskogee Units 4 & 5 is
estimated to be approximately $3,251/ton. This cost compares to an average annual cost
effectiveness for LNB/OFA combustion controls of approximately $270/ton. Equipment costs,
retrofit challenges, and annual operating costs all have a significant impact on the annualized
cost of a SCR control system. Significant annual operating costs include the energy cost
associated with the additional pressure drop across the SCR and costs associated with replacing
the SCR catalyst as it degrades over time. Based on projected actual emissions, SCR could
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reduce overall NOx emissions from Muskogee Units 4 & 5 by approximately 3,456 tpy
(compared to advanced combustion controls); however, the incremental cost associated with
this reduction is approximately $57,407,600 per year, or $16,611/ton.
As part of the BART rulemaking, EPA established presumptive NOx emission limits applicable
to EGUs greater than 200 MW at power plants with a generating capacity greater than 750
MW. The presumptive NOx emission limits were based on control strategies that EPA
considered to be generally cost-effective for such units (see, 70 FR 39134). The presumptive
NOx emission limit applicable to Muskogee Units 4 & 5 (tangentially-fired units firing
subbituminous coal) is 0.15 lb/mmBtu. For all types of boilers, other than cyclone units, the
presumptive limits were based on the use of combustion control technologies. EPA estimated
that the “costs of such controls in most cases range from just over $100 to $1000 per ton” (see,
70 FR 39135).
The average cost effectiveness of combustion controls (LNB/OFA) on Muskogee Units 4 & 5 is
similar to the BART cost-effectiveness developed by EPA for NOx control on large EGU
boilers. Both the average and incremental cost effectiveness of SCR on Muskogee Units 4 & 5
are significantly greater than the cost effectiveness of NOx control at other BART-applicable
units. The costs associated with SCR would result in significant economic impacts on the
Muskogee Generating Station (approximately $57,407,600 per year additional costs).
Therefore, SCR should not be selected as BART based on lack of cost effectiveness. Although
SCR does not appear to be cost effective, it will be included in the evaluation of the remaining
factors to assure that the BART determination considers all relevant information.
3.4.2 NOx Control Technologies – Environmental Impacts
Combustion modifications designed to decrease NOx formation (lower temperature and less
oxygen availability) also tend to increase the formation and emission of CO and VOCs.
Therefore, the combustion controls must be designed to reduce the formation of NOx while
maintaining CO and VOC formation at an acceptable level. Other than the NOx/CO-VOC
trade-off, there are no environmental issues associated with using combustion controls to
reduce NOx emissions.
Operation of an SCR system has certain collateral environmental consequences.13 First, in
order to maintain low NOx emissions some excess ammonia will pass through the SCR.
Ammonia slip will increase with lower NOx emission limits, and will also tend to increase as
the catalyst becomes deactivated. Ammonia slip from an SCR designed to achieve a controlled
13 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.
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NOx emission rate of 0.07 lb/mmBtu (30-day average) is expected to be in the range of 2-5 ppm
during the initial operation of the SCR. As the catalyst ages and becomes either deactivated or
blinded, ammonia slip can increase; however, the ammonia slip rate is not expected to exceed
7-10 ppm under normal operating conditions.
Second, undesirable reactions can occur in an SCR system, including the oxidation of NH3 and
SO2 and the formation of sulfate salts. A fraction of the SO2 in the flue gas (approximately 1 -
1.5%) will oxidize to SO3 in the presence of the SCR catalyst. SO3 can react with water to form
sulfuric acid mist or with the ammonia slip to form ammonium sulfate ((NH4)2SO4). Sulfuric
acid mist and (NH4)2SO4 are classified as condensable particulates. The formation of
condensible particulates will increase as the size of the SCR increases.
Finally, the storage of ammonia on-site 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
((NH2)2CO) 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
Both NOx control systems require auxiliary power. Auxiliary power requirements associated
with the LNB/OFA control systems are generally insignificant, but may include booster fans for
the overfire air injection ports to increase turbulence within the boiler. Auxiliary power
requirements associated with the SCR include additional fan power to overcome pressure drop
through the SCR. Energy impacts associated with each control technology were included in the
BART economic impact evaluation as an auxiliary power cost.
A summary of the Step 4 economic and environmental impact analysis is provided in Table 3-7.
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Table 3-7
Summary of NOx BART Impact Analysis (total for both boilers)
Control
Technology
Annual
Controlled
Emissions*
(tpy)
Annual
Emission
Reductions
(tpy)
Average Cost
Effectiveness
($/ton)
Incremental
Cost
Effectiveness
($/ton)
Summary of Environmental
Impacts
LNB/OFA+SCR 3,024 18,945 $3,251 $16,611 Increased SO2 to SO3 oxidation, and
increased condensible PM emissions
including H2SO4. Ammonia
emissions associated with ammonia
slip.
LNB/OFA 6,480 15,489 $270 -- Potential to increase CO/VOC
emissions.
Baseline 21,969 base -- -- --
* Annual controlled emissions and annual emission reductions represent total emissions from both units. Annual
emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr per boiler for 7,884 hours
per year (90% capacity factor).
3.5 Step 5: Evaluate Visibility Impacts
To evaluate the relative effectiveness of potentially feasible NOx retrofit control technologies, NOx
emissions were modeled at the projected post-retrofit controlled emission rates, while SO2 and
PM10 emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA
guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling
analysis to determine visibility impairment impacts reflect steady-state operating conditions during
periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour
basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling
average multiplied by the boiler heat input (mmBtu/hr) at full load. The visibility modeling
methodology is described further in Attachment B of this document, including detailed inputs and
results. The results in Table 3-8 summarize the 98th percentile Δ-dv impact from NOx emissions
associated each NOx retrofit control scenario.
The most significant improvement in visibility can be attributed to NOx reductions associated with
combustion controls (LNB/OFA). Visibility improvements in the range of 70% reductions in
modeled impacts are achieved at each Class I Area. The largest reduction in visibility impairment
(0.74 Δ-dv) occurs at the Caney Creek Class I Area. Modeled impacts associated with NOx
emissions based on LNB/OFA controls at the presumptive NOx emission limit (0.15 lb/mmBtu) are
below the threshold impact level of 0.5 Δ-dv level at all Class I Areas.
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Table 3-8
Muskogee Units 4 & 5
NOx Visibility Assessment
Visibility Improvement
Upper Buffalo
Wilderness Area
Caney Creek
Wilderness Area
Hercules-Glades
Wilderness Area
Wichita Mountains
Wildlife Refuge
NOx Control
Technology
Option
98th %
Δ-dv*
%
Improve-ment
over
Previous
98th %
Δ-dv
%
Improve-ment
over
Previous
98th %
Δ-dv
%
Improve-ment
over
Previous
98th %
Δ-dv
%
Improve-ment
over
Previous
Baseline 0.84 -- 1.06 -- 0.47 -- 0.61 --
LNB/OFA 0.24 71% 0.32 70% 0.14 71% 0.18 71%
LNB/OFA + SCR 0.11 53% 0.14 56% 0.06 54% 0.08 55%
* Δ-dv values included in this table represent the modeled visibility impacts only from NOx emissions associated
with each NOx retrofit control scenario.
Post-combustion SCR control systems could reduce NOx emissions from Muskogee Units 4 & 5
below the BART presumptive level; however, modeled visibility improvements at the lower NOx
emission rates do not justify the costs associated with SCR control. LNB/OFA control systems are
expected to reduce overall NOx emissions from Muskogee Units 4 & 5 by approximately 15,489 tpy
(from baseline). SCR control systems would reduce overall NOx emissions by an additional 3,456
tpy. At the lower NOx emission rates, modeled visibility impairment at the Class I Areas would be
reduced by only 0.08 to 0.18 Δ-dv. Because only small improvements in visibility impacts result
from the lower emission rate, the cost effectiveness of SCR control, on a $/dv basis, will be
significant.
Tables 3-9 and 3-10 summarize the cost effectiveness of the technically feasible NOx retrofit
control technologies on Muskogee Units 4 & 5 as a function of visibility impairment improvement
at the Class I Areas.
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Table 3-9
Muskogee Units 4 & 5
NOx Average Visibility Cost Impact Evaluation
Total Annual
Cost
Modeled
Visibility
Impairment*
Visibility
Impairment
Improvement
from Baseline
Average
Improvement
Cost
Effectiveness
NOx Control
Technology Option
($/yr) 98th % Δ-dv* (dv) ($/dv/yr)
Baseline -- 1.06 -- --
LNB/OFA $4,183,600 0.32 0.74 $5.65 MM/dv
LNB/OFA + SCR $61,591,200 0.14 0.92 $66.9 MM/dv
* Δ-dv values included in this table represent the modeled visibility impacts only from NOx emissions
associated with each NOx retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I
Area was used for the cost effectiveness evaluation because modeling indicated that the largest Δ-dv
improvements would occur at Caney Creek.
Although SCR control systems reduce modeled visibility impacts at the four Class I Areas, the
incremental cost effectiveness of SCR control (with respect to visibility improvement) is very high.
Incremental cost effectiveness of SCR control is in the range of $319 million per dv improvement
at the Wichita Mountains. This cost is significantly higher than costs incurred at other BART
applicable sources. A review of BART determinations at other coal-fired units suggests that BART
cost effectiveness values are typically in the range of less than $1.0 million to approximately $13
million per dv improvement.14 The combination of low visibility impacts with LNB/OFA controls
(less than 0.32 Δ-dv at all Class I Areas) and the high cost of SCR controls contribute to the large
incremental cost effectiveness of SCR at the Muskogee Station.
Table 3-10
Muskogee Units 4 & 5
NOx Incremental Visibility Cost Impact Evaluation
Total Annual
Cost
Incremental
Annual Cost
Modeled
Visibility
Impairment
Incremental
Visibility
Impairment
Improvement
Incremental
Improvement
Cost
Effectiveness
NOx Control
Technology Option
($/yr) ($/yr) 98th % Δ-dv* (dv) ($/dv/yr)
Baseline -- -- 1.06 -- --
LNB/OFA $4,183,600 -- 0.32 -- --
LNB/OFA + SCR $61,591,200 $57,407,600 0.14 0.18 $319 MM/dv
* Δ-dv values included in this table represent the modeled visibility impacts only from NOx emissions associated with
each NOx retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I Area was used for the cost
effectiveness evaluation because modeling indicated that the largest Δ-dv improvements would occur at Caney Creek.
14 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy
Co. (CO); Entergy White Bluff Power Plant (AR).
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To determine whether alterative NOx control scenarios might provide more cost effective visibility
improvements, cumulative impact modeling was conducted using a variety of SCR control
scenarios. A goal of the cumulative impact modeling was to determine whether alternative NOx
control scenarios (i.e., SCR control on some, but not all of the OG&E BART applicable sources)
would provide more cost effective NOx control. To quantify cost effectiveness, visibility
impairment was modeled for several NOx control scenarios, while SO2 and PM emissions were
held constant at their respective baseline emission rates. Modeled NOx control scenarios are listed
in Table 3-11. Results of the cumulative NOx impact modeling are summarized in Table 3-12.
Table 3-11
Cumulative NOx Visibility Assessment
(Muskogee Units 4 & 5 and Sooner Units 1 & 2)*
Unit Base Case Case 1 Case 2 Case 3 Case 4
NOx Controls
(Emission Rate - lb/mmBtu)
Muskogee Unit 4 LNB/OFA
(0.15)
SCR
(0.07)
SCR
(0.07)
SCR
(0.07)
SCR
(0.07)
Muskogee Unit 5 LNB/OFA
(0.15)
LNB/OFA
(0.15)
LNB/OFA
(0.15)
SCR
(0.07)
SCR
(0.07)
Sooner Unit 1 LNB/OFA
(0.15)
LNB/OFA
(0.15)
SCR
(0.07)
SCR
(0.07)
SCR
(0.07)
Sooner Unit 2 LNB/OFA
(0.15)
LNB/OFA
(0.15)
LNB/OFA
(0.15)
LNB/OFA
(0.15)
SCR
(0.07)
* For each case PM and SO2 emissions were held constant at the baseline emission rates. Baseline emissions for SO2
were: 0.80 lb/mmBtu (Muskogee Unit 4), 0.85 lb/mmBtu (Muskogee Unit 5), and 0.86 lb/mmBtu (Sooner Units 1 & 2).
Table 3-12
Cumulative NOx Visibility Modeling Results
(Muskogee Units 4 & 5 and Sooner Units 1 & 2)
Modeled Visibility Impairment*
Upper Buffalo
Wilderness Area
Caney Creek
Wilderness Area
Hercules-Glades
Wilderness Area
Wichita Mountains
Wildlife Refuge
NOx Control
Technology
Option 98th %
Δ-dv
98th %
Δ-dv
98th %
Δ-dv
98th %
Δ-dv
Base Case 1.92 2.00 1.44 2.42
Case 1 1.94 1.99 1.43 2.41
Case 2 1.94 1.98 1.43 2.38
Case 3 1.95 1.97 1.46 2.35
Case 4 1.94 1.96 1.46 2.33
* Δ-dv values included in this table reflect cumulative modeled contributions from NOx, SO2 and PM emissions from both
the Sooner and Muskogee Stations. For each case PM and SO2 emissions were held constant at their respective baseline
emission rates, while NOx emissions varied depending the NOx control system on each unit (see Table 3-11). The dv
values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2), which reflect modeled impacts
from the Muskogee Station only for each individual pollutant.
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Results of the cumulative impact modeling suggest that SCR controls would contribute only
minimally to visibility improvement at the Class I Areas in comparison to LNB/OFA. Modeled
impacts at the Wichita Mountains (at the 98th percentile Δ-dv level) improved from 2.42 Δ-dv with
LNB/OFA on all four units to 2.33 Δ-dv with SCR on all four units, an improvement of
approximately 4%. Modeled improvements were even lower at the other Class I Areas, and, in fact,
modeled impairments at the Hercules-Glades and Upper Buffalo Wilderness Areas actually
increased with the addition of SCR controls. It is suspected that increased sulfuric acid mist
emissions (associated with SO2 to SO3 conversion across the SCR) off-set reductions in controlled
NOx emissions.
3.6 Propose BART for NOx Control at Muskogee Units 4 & 5
OG&E is proposing combustion controls (LNB/OFA), and a controlled NOx emission rate of 0.15
lb/mmBtu (30-day average) as BART for Muskogee Units 4 & 5. This combination of control
technologies represents the most cost effective technically feasible NOx retrofit technology for the
existing boilers. A controlled emission rate of 0.15 lb/mmBtu is equivalent to the presumptive level
for large tangentially-fired units firing subbituminous coals. The average cost effectiveness of
LNB/OFA control systems is estimated to be in the range of $270/ton and $5.65 MM./dv/yr. These
cost effectiveness numbers are in-line with EPA’s cost estimate for BART controls on large EGUs,
and are not of such magnitude as to exclude combustion controls as BART.
The addition of SCR control systems could provide incremental NOx reductions; however, costs
associated with SCR control are significant, and incremental visibility improvements are limited.
The average cost effectiveness of an SCR control system is estimated to be $3,251/ton and $66.9
MM/dv/yr. These costs are significantly higher than the average cost of NOx control at similar
sources. In the BART rule, EPA estimated that the cost of controls to meet the BART NOx
presumptive level on large EGUs “in most cases range from just over $100 to $1000 per ton” (see,
70 FR 39135).
Furthermore, the modeled incremental visibility improvements associated with SCR control are
only in the range of 0.08 to 0.18 Δ-dv. Because of the limited improvement in modeled visibility
impacts, the cost effectiveness of SCR control, on a $/dv basis is significant. Compared to the
costs and modeled visibility impacts associated with LNB/OFA controls, the incremental cost
effectiveness of SCR is estimated to be $16,611/ton and more than $319 MM/dv/yr. Both costs are
significantly higher than the expected cost of BART controls on large EGUs, and should preclude
SCR from consideration as BART. Finally, cumulative impact modeling, summarized in Tables 3-
11 and 3-12, supports the conclusion that post-combustion SCR controls provide limited
improvement in modeled visibility impairment.
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4.0 BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (SO2)
SOX emissions from coal combustion consist primarily of sulfur dioxide (SO2), with a much lower
quantity of sulfur trioxide (SO3) and gaseous sulfates. These compounds form as the organic and
pyretic sulfur in the coal are oxidized during the combustion process. On average, about 95% of
the sulfur present in the fuel will be emitted as gaseous SOX,
15 Boiler size, firing configuration and
boiler operations generally have little effect on the percent conversion of fuel sulfur to SO2.
The generation of SO2 is directly related to the sulfur content and heating value of the fuel burned.
The sulfur content and heating value of coal can vary dramatically depending on the source of the
coal. Muskogee Units 4 & 5 utilize subbituminous coal as their primary fuel source. Heating
values, ash contents, and sulfur contents for subbituminous fuel utilized at the Muskogee Station
are summarized in Table 4-1.
Table 4-1
Muskogee Generating Station
Typical Coal Characteristics
Constituent Units Range
Heating Value Btu/lb 8,490 - 8,900
Ash % 4.1 - 6.0
Sulfur Content % 0.20 – 0.37
Potential Uncontrolled SO2 lb/mmBtu 0.50 – 0.86
* Coal characteristics included in this table represent average values based on fuel
shipments to the Muskogee Station. Characteristics summarized in this table are not
intended to limit the heating value, moisture content, ash content, or sulfur content of
fuels utilized at the Muskogee Station, as short-term coal characteristics may vary
from the values summarized above.
4.1 Step 1: Identify Potentially Feasible SO2 Control Options
Several techniques can be used to reduce SO2 emissions from a pulverized coal-fired combustion
source. SO2 control techniques can be divided into pre-combustion strategies and post-combustion
controls. SO2 control options identified for potential application to Muskogee Units 4 & 5 are listed
in Table 4-2.
15 AP-42, Section 1.1 Bituminous and Sub-Bituminous Coal Combustion, page 1.1-3, September 1998.
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Table 4-2
Muskogee Generating Station
List of Potential SO2 Retrofit Control Options
Control Strategy/Technology
Pre-Combustion Controls
Fuel Switching
Coal Washing
Coal Processing
Post-Combustion Controls
Wet Flue Gas Desulfurization
Wet Lime FGD
Wet Limestone FGD
Wet Magnesium Enhanced Lime FGD
Jet Bubbling Reactor FGD
Dual Alkali Scrubber
Wet FGD with Wet Electrostatic Precipitator
Dry Flue Gas Desulfurization
Spray Dryer Absorber
Dry Sorbent Injection
Circulating Dry Scrubber
4.2 Step 2: Technical Feasibility of Potential Control Options
The technical feasibility of each potential control option is discussed below.
4.2.1 Pre-Combustion Control Strategy
The generation of SO2 is related to the sulfur content and heating value of the fuel burned. The
sulfur content and heating value of coal can vary dramatically depending on the source of the
coal. Potentially feasible pre-combustion control strategies designed to reduce overall SO2
emissions are described below.
4.2.1.1 Fuel Switching
One potential strategy for reducing SO2 emissions is reducing the amount of sulfur
contained in the coal. Muskogee Units 4 & 5 fire subbituminous coal as their primary fuel.
Subbituminous coal has a relatively low heating value, low sulfur content, and low
uncontrolled SO2 emission rate. Typical coal characteristics based on existing
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subbituminous coal shipments to OG&E’s Muskogee Generating Station are summarized in
Table 4-1 above.
Because of the relatively low sulfur content, subbituminous coals generate the lowest
uncontrolled SO2 emissions. In fact, several coal-fired utilities have switched to low-sulfur
coal as an SO2 emission control strategy. Bituminous coals from mines in the Eastern and
Midwestern U.S. generally have higher heating values but also have a significantly higher
sulfur content. Lignites from the upper Midwest and Texas have a relatively low sulfur
content (but higher than subbituminous) but also have high moisture contents and relatively
low heating values.
Fuels currently used at the Muskogee Station generate low uncontrolled SO2 emissions.
Switching to alternative coals (i.e., 100% bituminous coal or lignite) will not reduce
potential uncontrolled SO2 emissions or controlled SO2 emissions from Muskogee Units 4
& 5. No environmental benefits accrue from burning an alternative coal; therefore, fuel
switching is not considered a feasible option for this retrofit project.
4.2.1.2 Coal Washing
Coal washing, or beneficiation, is one pre-combustion method that has been used to reduce
impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by
separating and removing inorganic impurities from organic coal particles. Inorganic
impurities, including inorganic ash constituents and inorganic iron disulfide (FeS2 or
pyrite), are typically more dense than the coal particles. This property is generally used in
a wet cleaning process to separate coal particles from the inorganic impurities.
Each coal seam has different washability characteristics depending on the characteristics of
the inorganic constituents. Based on information available from the Kentucky Coal
Council, inorganic sulfur in high-sulfur eastern bituminous coals may be reduced by 0.5 –
2.5% and inorganic ash may be reduced by 9 – 15% through coal washing.16 Coal washing
is generally done at the mine to maximize the value of the coal and reduce freight charges
to the power plant.
The coal washing process generates a solid waste stream consisting of inorganic materials
separated from the coal, and a wastewater stream that must be treated prior to discharge.
Solids generated from wastewater processing and coarse material removed in the washing
process must be disposed in a properly permitted landfill. Solid wastes from coal washing
16 See, http://www.coaleducation.org/Ky_Coal_Facts/coal_resources/coal_preparation.htm.
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typically contain pyrites and other dense inorganic impurities including silica and trace
metals. The solids are typically dewatered in a mechanical dewatering device and disposed
of in a landfill.
The wastewater stream generally consists of an acidic liquid slurry made up of water,
uncombusted coal fines, and impurities in the coal, including calcium, trace metals,
chloride, sulfate, and dissolved and suspended solids.17 The wastewater slurry must be
treated to remove solids, coal fines, and trace metals prior to discharge. Coal slurry
treatment systems may include surface impoundments, mechanical dewatering systems,
chemical processing systems, and/or thermal dryers.
While washing may be effective in removing rock inclusions from coal, including sulfur-bearing
pyrites, a significant amount of coal may also be lost in the washing process. An
inherent consequence of coal washing, in addition to generating wastewater and solid waste
streams, would be the need for the mine to process significantly more coal to make up for
coal lost in the washing process.
Muskogee Units 4 & 5 are designed to utilize subbituminous coals. Based on a review of
available information, no information was identified regarding the washability or
effectiveness of washing subbituminous coals. Subbituminous coals have a relatively high
ash content and an excessive amount of fines, and significant dewatering equipment would
be required to process and separate the fines from the wastewater stream. It is likely that
the excess fines production, and the difficulties associated with handling and dewatering
the fines, have restricted the commercial viability of subbituminous coal washing.
Furthermore, the coal washing process would generate significant solid and liquid waste
streams that would require proper management and disposal. Based on a review of
available information, there are currently no commercial subbituminous coal washing
facilities, and washed subbituminous coals are not available through commercial channels.
Therefore, coal washing is not considered an available retrofit control option for Muskogee
Units 4 & 5.
4.2.1.3 Coal Processing
Pre-combustion coal processing techniques have been proposed as one strategy to reduce
the sulfur content of coal and help reduce uncontrolled SO2 emissions. Coal processing
17 See, USEPA Report to Congress, Wastes from the Combustion of Fossil Fuels, Office of Solid Waste and
Emergency Response, EPA 530-S-99-010, March 1999 (general composition of selected large-volume and
low-volume wastes).
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technologies are being developed to remove potential contaminants from the coal prior to
use.
These processes typically employ both mechanical and thermal means to increase the
quality of subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy
metals. In one process, raw coal from the mine enters a first stage separator where it is
crushed and screened to remove large rock and rock material.18 The processed coal is then
passed on to an intermediate storage facility. From the intermediate storage facility the
coal goes to a thermal process. In this process coal passes through pressure locks into the
thermal processors where steam at 460 oF and 485 psi is injected. Moisture in the coal is
released under these conditions. Mineral inclusions are also fractured under thermal stress,
removing both included rock and sulfur-forming pyrites. After it has been treated for a
sufficient time in the main processor, the coal is discharged into a second pressurized lock.
The second pressurized lock is vented into a water condenser to return the processor to
atmospheric pressure and to flash cool the coal to approximately 200 oF. Water is removed
from the coal at various points in the process. This water, along with condensed process
steam, is either reused within the process or treated prior to being discharged.
To date, the use of processed fuels has only been demonstrated with test burns in a
pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their
primary fuel source on an on-going, long-term basis. Although burning processed fuels, or
a blend of processed fuels, has been tested in a pulverized coal-fired boiler, using processed
fuels in Muskogee Units 4 & 5 would require significant research, test burns, and extended
trials to identify potential impacts on plant systems, including the boiler, material handling,
and emission control systems. Therefore, processed fuels are not considered commercially
available, and will not be analyzed further in this BART analysis.
4.2.2 Post-Combustion Flue Gas Desulfurization
Over the past decade, post-combustion flue gas desulfurization (FGD) has been the most
frequently used SO2 control technology for large pulverized coal-fired utility boilers. FGD
systems typically have been installed on boilers firing high-sulfur bituminous coals. FGD
systems, including wet scrubbers and dry scrubbers, have been designed to effectively and
economically remove SO2 from pulverized coal-fired utility boiler flue gas. FGD systems with
a potential applicability to Muskogee Units 4 & 5 are described below.
18 The coal processing description provided herein is based on the K-Fuel® process under development by
KFx, Inc.
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4.2.2.1 Wet Scrubbing Systems
Wet FGD technology is an established SO2 control technology. Wet scrubbing systems
offered by vendors may vary in design; however, all wet scrubbing systems utilize an
alkaline scrubber slurry to remove SO2 from the flue gas. Design variations may include
changes to increase the alkalinity of the scrubber slurry, increase slurry/SO2 contact, and
minimize scaling and equipment problems.
All wet scrubbing FGD systems use an alkaline slurry that reacts with SO2 in the flue gas to
form insoluble calcium sulfite (CaSO3) and calcium sulfate (CaSO4) salts. Wet FGD
systems may be generally categorized as lime (CaO) or limestone (CaCO3) scrubbing
systems. The scrubbing process and equipment for either lime- or limestone scrubbing is
similar. The alkaline slurry consisting of hydrated lime or limestone may be sprayed
countercurrent to the flue gas, as in a spray tower, or the flue gas may be bubbled through
the alkaline slurry as in a jet bubbling reactor. Equations 4-1 through 4-5 summarize the
chemical reactions that take place within the wet scrubbing systems to remove SO2 from
flue gas.
SO2 + CaO + ½H2O → CaSO3•½H2O↓ (4-1)
SO2 + CaO + 2H2O → CaSO4•2H2O↓ (4-2)
SO2 + CaCO3 + H2O → CaSO3•H2O↓ + CO2 (4-3)
CaSO3 + ½O2 + 2H2O → CaSO4•2H2O↓ (4-4)
SO2 + 2H2O + ½ O2 + CaCO3 → CaSO4•2H2O↓ + CO2 (4-5)
Potentially feasible wet scrubbing systems are described below.
Wet Lime Scrubbing
The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to
water. The alkaline slurry is sprayed in the absorber and reacts with SO2 in the flue gas.
Insoluble CaSO3 and CaSO4 salts are formed in the chemical reaction that occurs in the
scrubber (see equations 4-1 and 4-2), and are removed as a solid waste by-product. The
waste by-product is made up of mainly CaSO3, which is difficult to dewater. Solid waste
by-products from wet lime scrubbing are typically managed in dewatering ponds and
landfills.
Wet Limestone Scrubbing
Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO3) is mixed
with water to formulate the alkali scrubber slurry. SO2 in the flue gas reacts with the
limestone slurry to form insoluble CaSO3 and CaSO4 which is removed as a solid waste by-
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product (see equations 4-3 and 4-4). The use of limestone instead of lime requires different
feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio
typically requires a larger absorbing unit. The limestone slurry process also requires a ball
mill to crush the limestone feed.
Forced oxidation of the scrubber slurry can be used with either the lime or limestone wet
FGD system to produce gypsum solids instead of the calcium sulfite by-product. Air blown
into the reaction tank provides oxygen to convert most of the calcium sulfite (CaSO3) to
relatively pure gypsum (calcium sulfate) as shown in equation 4-4. Forced oxidation of the
scrubber slurry provides a more stable by-product and reduces the potential for scaling in
the FGD. The gypsum by-product from this process must be dewatered, but may be salable
thus reducing the quantity of solid waste that needs to be landfilled.
Wet scrubbing systems using limestone as the reactant have demonstrated the ability to
achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing
high-sulfur bituminous coals. Wet lime and limestone FGD control systems with forced
oxidation are technically feasible SO2 retrofit technologies. However, wet scrubbing
systems have not been used on large boilers firing subbituminous coals, and the actual
control efficiency of a wet FGD system will depend on several factors, including the
uncontrolled SO2 concentration entering the system. Based on engineering judgment it is
expected that a wet lime or limestone FGD control system with forced oxidation could
achieve average controlled SO2 emissions in the range of 0.08 lb/mmBtu (30-day rolling
average) on Muskogee Units 4 & 5.
Wet lime and wet limestone scrubbing systems will achieve the same SO2 control
efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the
more attractive option. For this reason, wet lime scrubbing will not be evaluated further in
this BART determination.
Wet Magnesium Enhanced Lime Scrubbing
Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD
technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide
(MgO) and 90 – 95% calcium oxide (CaO). The presence of magnesium effectively
increases the dissolved alkalinity, and consequently makes SO2 removal less dependent on
the dissolution of the lime/limestone. In normal lime/limestone spray-tower operation the
amount of SO2 absorbed depends principally upon the soluble-alkali content of the
absorbing slurry. When magnesium is present, the soluble alkali level of the absorbent
increases primarily because of the presence of sulfite and bicarbonate salts of magnesium.
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As these magnesium alkalies are more soluble than the corresponding calcium alkalies,
there is an increase in the SO2 absorption capacity of the slurry.19
Commercial operation of wet FGD systems has shown that soluble Mg in the absorbing
slurry can improve SO2 removal efficiency.20 MEL scrubbers have been installed on coal-fired
utility boilers located in the Ohio River Valley.21 Most are located in a corridor from
Pittsburgh, Pennsylvania to Evansville, Indiana, and use a reagent that naturally contains
approximately 5% MgO. Because of the increased alkalinity in the scrubbing liquid, MEL
wet scrubbing systems have demonstrated the ability to achieve SO2 removal efficiencies
equivalent to wet lime/limestone scrubbers using smaller absorber towers.
Solids from the MEL FGD process consist primarily of calcium sulfite and magnesium
sulfite solids. Dewatering the sulfite solids from an unoxidized MEL FGD system can be
difficult, and produces a filter cake consisting of approximately 40-50% solids. Typically,
unoxidized MEL FGD filter cake is fixed using fly ash and landfilled. This continues to be
one of the drawbacks of the unoxidized MEL FGD process. Systems to oxidize the MEL
solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and
magnesium sulfate continue to be developed.22
Wet limestone FGD control systems can be designed to achieve the same control
efficiencies as the magnesium enhanced limestone systems. However, to achieve the same
control efficiencies, limestone-based systems require a higher liquid-to-gas ratio, and
therefore larger absorber towers. Coal-fired units equipped with MEL FGD typically fire
high-sulfur eastern bituminous coal and use locally available reagent. There are no
subbituminous-fired units equipped with a MEL-FGD system.
Because MEL-FGD systems have not been used on subbituminous-fired boilers, and
because of the cost and limited availability of magnesium enhanced reagent (either
naturally occurring or blended), and because limestone-based wet FGD control systems can
be designed to achieve the same control efficiencies as the magnesium enhanced systems,
MEL-FGD control systems will not be evaluated further as a commercially available
retrofitted control system.
19 Combustion Fossil Power, page 15-43.
20 Combustion Fossil Power, page 15-42.
21 Nolan, P.S., “Flue Gas Desulfurization Technologies for Coal-Fired Power Plant,” Coal-Tech 2000
International Conference, November 13-14, 2000.
22 See, Benson, L., Babu, M., Smith, K., “New Magnesium-Enhanced Lime FGD Process,” Dravo Lime, Inc.
– Technology Center.
Oklahoma Gas & Electric
Muskogee Generating Station – BART Determination
May 28, 2008
40
Jet Bubbling Reactor
Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike
the spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a
countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone
slurry. Spargers are used to create turbulence within the reaction tank and maximize
contact between the flue gas bubbles and scrubbing slurry. SO2 in the flue gas reacts with
the limestone slurry to form insoluble CaSO3 and CaSO4 which is removed as a solid waste
by-product (see equations 4-3, 4-4, and 4-5). Flue gas exits from the reaction vessel
through mist eliminators to reduce carryover of the reactant.
Although the reaction vessel used to contact flue gas with the scrubbing slurry is different
than the spray tower used in a conventional wet FGD system, JBR-FGD systems use the
same reaction chemistry to remove SO2 from the flue gas. JBR-FGD systems do not
require the large slurry pumps associated with other wet FGD technologies; however,
auxiliary power is shifted to larger fans, booster fans, agitators, and oxidation air blowers to
accommodate the larger pressure drop through the system.
There are currently a limited number of commercially operating JBR-WFGD control
systems installed on coal-fired utility units in the U.S. A JBR-WFGD control system was
installed at Georgia Power’s 100 MW coal-fired Yates plant in 1992. Based on publicly
available emissions data, the Yates Plant has an average inlet SO2 concentration of
approximately 3,500 ppm, and has achieved average SO2 removal efficiencies of
approximately 93%. In addition to the Yates Plant, a JBR control system has been in use at
the 40 MW equivalent Abbott Steam plant at the University of Illinois.
Most of the JBR-WFGD control experience has been in Japan. Chiyoda Corporation has
installed JBR-WFGD systems on several coal-fired plants overseas. Based on information
available on Chiyoda’s website, a majority of the plants equipped with JBR-WFGD are
smaller units (e.g., less then 200 MW); however, Chiyoda lists JBR-WFGD systems in
operation on three plants located overseas in the 600 MW range. Commercial deployment
of the JBR-WFGD control system continues to develop in the U.S. A project experience
list available from Chiyoda identifies several U.S. power plants that have decided to install
JBR-WFGD control systems, with control system startup dates between 2008 and 2010.
Although the commercial deployment of the control system continues, there is still a very
limited number of operating units in the U.S. Furthermore, coal-fired boilers currently
considering the JBR-WFGD control system are all located in the eastern U.S., and all fire
eastern bituminous coals. The control system has not been proposed as a retrofit
Oklahoma Gas & Electric
Muskogee Generating Station – BART Determination
May 28, 2008
41
technology on any large subbituminous coal-fired boilers. However, other than scale-up
issues, there do not appear to be any overriding technical issues that would exclude
application of the control technology on a large subbituminous coal-fired unit.
Assuming that the JBR-WFGD control system is commercially available for Muskogee
Units 4 & 5, the JBR is essentially a wet FGD scrubbing system. Unlike the spray tower
systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower,
in the JBR-WFGD flue gas is bubbled through the limestone slurry. SO2 in the flue gas
reacts with the limestone slurry to form insoluble calcium sulfate and calcium sulfite,
which is removed as a solid waste by-product. Although the reaction vessel used to contact
flue gas with the scrubbing slurry uses a different design, the reaction chemistry to remove
SO2 from the flue gas is the same for all wet FGD designs.
There are no data available to conclude that the JBR-WFGD control system will achieve a
higher SO2 removal efficiency than a more traditional spray tower WFGD design,
especially on units firing low-sulfur subbituminous coal. Furthermore, the costs associated
with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to
the costs and control efficiencies achievable with spray tower WFGD control systems.
Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be
included in the overall assessment of WFGD controls.
Dual-Alkali Wet Scrubber
Dual-alkali scrubbing is a desulfurization process that uses a sodium-based alkali solution
to remove SO2 from combustion exhaust gas. The process uses both sodium-based and
calcium-based compounds. The sodium-based reagent absorbs SO2 from the exhaust gas,
and the calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium
sulfites and sulfates are precipitated and discarded as sludge, while the regenerated sodium
solution is returned to the absorber loop.
The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with lime or
limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, however
additional regeneration and sludge processing equipment is necessary.
The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide,
sodium carbonate and sodium sulfite, is an efficient SO2 control reagent. However, the
high cost of the sodium-based chemicals limits the feasibility of such a unit on a large
utility boiler. In addition, the process generates a less stable sludge that can create material
handling and disposal problems.
Oklahoma Gas & Electric
Muskogee Generating Station – BART Determination
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42
It is projected that a dual-alkali system could be designed to achieve SO2 control similar to
a limestone-based wet FGD. However, because of the limitations discussed above, and
because dual-alkali systems are not currently commercially available, dual-alkali scrubbing
systems will not be addressed further in this BART determination.
Wet FGD with Wet Electrostatic Precipitator
Wet FGD systems can result in increased emissions of condensable particulates and acid
gases. In particular, SO3 generated in the unit’s boiler can react with moisture in the wet
FGD to generate sulfuric acid mist. Sulfuric acid mist emissions from boilers firing high
sulfur coals and equipped SCR and wet FGD can contribute to significant opacity problems
if the H2SO4 concentration in the stack gas exceeds approximately 15 ppm.23
Wet electrostatic precipitation (WESP) has been proposed on other coal-fired projects as
one technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have
been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet
FGD.24 WESP has been demonstrated as an effective control technology to abate sulfuric
acid mist emissions from industrial applications with relatively low flue gas flow rates and
high acid mist concentrations, such as sulfuric acid plants. However, until recently, the
technology has not been applied to the utility industry because of the high gas flow
volumes and low acid mist concentrations associated with utility flue gas.
In a utility application, the WESP would be located downstream from the wet FGD to
remove micron-sized sulfuric acid aerosols from the flue gas stream as a condensable
particulate. Electrostatic precipitation consists of three steps: (1) charging the particles to
be collected via a high-voltage electric discharge, (2) collecting the particles on the surface
of an oppositely charged collection electrode surface, and (3) cleaning the surface of the
collecting electrode. In a WESP system, the collecting electrodes are typically cleaned
with a liquid wash. Particulate mass loading, particle size distribution, particulate electrical
resistivity, and precipitator voltage and current will influence ESP performance. The wet
cleaning mechanism can also affect the nature of the particles that can be captured, and the
performance efficiencies that can be achieved.
23 See, Duellman, D.M., Erickson, C.A., Licata, T., Operating Experience with SCR’s and High Sulfur Coals
& SO3 Plumes, presented at the ICAC NOx Forum, February 2002.
24 See for example, the Thoroughbred Generating Station PSD Permit Application submitted to the Kentucky
Department of Environmental Protection, and the Prairie States Energy Center PSD Permit Application
submitted to the Illinois Environmental Protection Agency.
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43
WESP has not been widely used in utility applications, and has only been proposed on
boilers firing high sulfur coals and equipped with SCR. Muskogee Units 4 & 5 fire low-sulfur
subbituminous coal. Based on the fuel characteristics listed in Table 4-1, and
assuming 1% SO2 to SO3 conversion in the boiler, potential uncontrolled H2SO4 emissions
from Muskogee Units 4 & 5 will only be approximately 5 ppm. This emission rate does
not take into account inherent acid gas removal associated with alkalinity in the
subbituminous coal fly ash. Based on engineering judgment, it is unlikely that a WESP
control system would be needed to mitigate visible sulfuric acid mist emissions from
Muskogee Units 4 & 5, even if WFGD control was installed.
WESPs have been proposed to control condensable particulate emissions from boilers
firing a high-sulfur bituminous coal and equipped with SCR and wet FGD. This
combination of coal and control equipment results in relatively high concentrations of
sulfuric acid mist in the flue gas. WESP control systems have not been proposed on units
firing subbituminous coals, and WESP would have no practical application on a
subbituminous-fired units. Therefore, the combination of WFGD+WESP will not be
evaluated further in this BART determination.
Wet FGD Scrubbing - Conclusions
Wet FGD technology is an established SO2 control technology. Wet scrubbing systems
have been designed to utilize various alkaline scrubbing solutions including lime,
limestone, and magnesium-enhanced lime. Wet scrubbing systems may also be designed
with spray tower reactors or reaction vessels (e.g., jet bubbling reactor). Although the flue
gas/reactant contact systems may vary, the chemistry involved in all wet scrubbing systems
is essentially identical. A large majority of the wet FGD systems designed to remove SO2
from existing high-sulfur utility boilers have been designed as wet limestone scrubbers with
spray towers and forced oxidation systems.
Wet scrubbing systems using limestone as the reactant have demonstrated the ability to
achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing
high-sulfur bituminous coals. The chemistry of wet scrubbing consists of a complex series
of kinetic and equilibrium-controlled reactions occurring in the gas, liquid and solid phases.
In general, the amount of SO2 removed from the flue gas is governed by the vapor-liquid
equilibrium between SO2 in the flue gas and the absorbent liquid. If no soluble alkaline
species are present in the liquid, the liquid quickly becomes saturated with SO2 and
absorption is limited.25 Likewise, as the flue gas SO2 concentration goes down, absorption
25 Combustion Fossil Power – A Reference Book on Fuel Burning and Steam Generation, edited by Joseph P.
Singer, Combustion Engineering, Inc., 4th ed., 1991 (pp. 15-41).
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will be limited by the SO2 equilibrium vapor pressure. Therefore, high control efficiencies
would not be expected on a boiler firing low sulfur coals because of the reduced SO2
concentration in the boiler flue gas.
Although WFGD control systems have not been used on subbituminous coal-fired units
there are no technical limitations that would preclude its use on Muskogee Units 4 & 5.
Therefore, WFGD is determined to be a technically feasible SO2 control retrofit
technology. Based on the fuel characteristics listed in Table 4-1, taking into consideration
the reduced SO2 concentration in the flue gas and reduced SO2 loading to the scrubbing
system, and allowing a reasonable operating margin to account for normal operating
conditions (e.g., load changes, changes in fuel characteristics, and minor equipment upsets)
it is concluded that a WFGD retrofit control system could achieve a controlled SO2 rate of
0.08 lb/mmBtu (30-day average).
4.2.2.2 Dry Flue Gas Desulfurization
Another scrubbing system that has been designed to remove SO2 from coal-fired
combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or
hydrated lime slurry into a reaction tower where it reacts with SO2 in the flue gas to form
calcium sulfite solids (see equations 4-1 and 4-2). Dry scrubbing includes a separate lime
preparation system and reaction tower. Unlike wet FGD systems that produce a slurry by-product
that is collected separately from the fly ash, dry FGD systems produce a dry by-product
that must be removed with the fly ash in the particulate control equipment.
Therefore, dry FGD systems must be located upstream of the particulate control device to
remove the reaction products and excess reactant material.
Various dry FGD systems have been designed for use with pulverized coal-fired boilers.
Dry scrubbing systems that may be technically feasible on Muskogee Units 4 & 5 are
discussed below.
Spray Dryer Absorber
Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications.
SDA systems have demonstrated the ability to effectively reduce uncontrolled SO2
emissions from pulverized coal units.
The typical spray dryer absorber uses a slurry of lime and water injected into the tower to
remove SO2 from the combustion gases. The towers must be designed to provide adequate
contact and residence time between the exhaust gas and the slurry to produce a relatively
Oklahoma Gas & Electric
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45
dry by-product. The process equipment associated with a spray dryer typically includes an
alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate
control device and a recycle system. The recycle system collects solid reaction products
and recycles them back to the spray dryer feed system to reduce alkaline sorbent use.
Various process parameters affect the efficiency of the SDA process including: the type and
quality of the additive used for the reactant, reactant stoichiometric ratio, how close the
SDA is operated to saturation conditions, and the amount of solids product recycled to the
atomizer. The control efficiency of a SDA system is limited to approximately 94% of the
SO2 loading to the system, and is a function of numerous operating variables including gas-to-
liquid contact and system operating temperatures.
In a dry FGD system, the amount of reactant slurry introduced to the spray dryer must be
controlled to insure that the reaction products leaving the absorber vessel are dry.
Therefore, the outlet temperature from the absorber must be maintained above the
saturation temperature. SDA systems are typically designed to operate within
approximately 30 oF adiabatic approach to the saturation temperature. Operating closer to
the adiabatic saturation temperature allows higher SO2 control efficiencies; however, outlet
temperatures too close to the saturation temperature will result in severe operating
problems including reactant build-up in the absorber modules, blinding of the fabric filter
bags, and corrosion in the fabric filter and ductwork.
High SO2 removal efficiencies in a SDA are also dependent upon good gas-to-liquid
contact. Reactant spray nozzle designs are vendor-specific; however, both dual-fluid
nozzles and rotary atomizers have been used in large coal-fired boiler applications.
Dual-fluid nozzles (slurry and atomizing air) typically consist of a stainless steel head with
multiple, ceramic two-fluid nozzle inserts. Slurry enters through the nozzle head and is
distributed to the nozzle inserts. Atomizing air enters concentrically into a reservoir in the
nozzle head and mixes with the slurry. The atomizing air expands as it passes through the
air holes and nozzle exit. This expansion creates the shear necessary to atomize the slurry.
Each nozzle is provided with a feed lance assembly consisting of a concentric feed pipe (air
around slurry), hose connections, and the nozzle head. The feed lance assembly is inserted
down through the SDA roof through a nozzle shroud assembly.
Rotary atomizers are comprised basically of a high-speed rotating atomizer wheel coupled
to a drive device and speed-increasing gear box. Because the reactant slurry is abrasive, the
atomizing nozzles typically consist of a stainless steel head and multiple abrasion-resistant
Oklahoma Gas & Electric
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46
ceramic nozzle inserts. The rotary atomizers are inserted down through the SDA roof. The
reactant slurry is atomized as it passes through the rapidly rotating nozzles.
The atomizing nozzle assembly (either the duel-fluid feed lance assembly or the rotary
atomizer assembly) is typically located in the SDA penthouse, and flange mounted to the
roof of the absorber vessel. Overhead cranes or hoists located in the penthouse can be used
to remove the nozzle assemblies from the absorber vessel for repair and maintenance.
Because of the abrasive nature of the reactant slurry, nozzle assemblies must be removed
and replaced on a routine basis. Depending on the design of the SDA system, one or more
spare nozzle assemblies will be available for use. The nozzle assemblies may be changed
without shutting down the SDA system. During that time period, the SDA may not be able
to maintain maximum control efficiencies.
SDA control systems are a technically feasible and commercially available retrofit
technology for Muskogee Units 4 & 5. Based on the fuel characteristics listed in Table 4-1
and allowing a reasonable margin to account for normal operating conditions (e.g., load
changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor
equipment upsets) it is concluded that dry FGD designed as SDA could achieve a
controlled SO2 emission rate of 0.10 lb/mmBtu (30-day average) on an on-going long-term
basis.
Dry Sorbent Injection
Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas
exhaust stream. Dry sorbent injection systems are simple systems, and generally require a
sorbent storage tank, feeding mechanism, transfer line and blower and an injection device.
The dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber
is often located downstream of the injection point to increase residence time and efficiency.
Particulates generated in the reaction are controlled in the system’s particulate control
device.
Typical SO2 control efficiencies for a dry sorbent injection system are generally around
50%. Because the control efficiency of the dry sorbent system is lower then the control
efficiency of either the wet FGD or SDA, the system will not be evaluated further.
Circulating Dry Scrubber
A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system
uses a circulating fluidized bed of dry hydrated lime reagent to remove SO2. Flue gas
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47
passes through a venturi at the base of a vertical reactor tower and is humidified by a water
mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime where
SO2 is removed. The dry by-product produced by this system is similar to the spray dry
absorber by-product, and is routed with the flue gas to the particulate removal system.
Based on engineering judgment and information available from equipment vendors, the
CDS flue gas desulfurization system should be capable of achieving SO2 removal
efficiencies similar to those achieved with a spray dryer absorber. In fact, vendors advise
that the CDS system is capable of achieving even higher removal efficiencies with
increased reactant injection rates and higher Ca/S stoichiometric ratios. However, to date
the CDS has had limited application, and has not been used on large pulverized coal
boilers. The largest CDS unit, in Austria, is on a 275 MW size oil-fired boiler burning oil
with a sulfur content of 1.0 to 2.0%. Operating experience on smaller pulverized coal
boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in
lime utilization based on inlet SO2 loading.26 Furthermore, CDS systems result in high
particulate loading to the unit’s particulate control device.
Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely
that OG&E would be required to conduct extensive design engineering to scale up the
technology for boilers the size of Muskogee Units 4 & 5, and that OG&E would incur
significant time and resource penalties evaluating the technical feasibility and long-term
effectiveness of the control system. Because of these limitations, CDS dry scrubbing
systems are not currently commercially available as a retrofit control technology for
Muskogee Units 4 & 5, and will not be evaluated further in this BART determination.
The results of Step 2 of the SO2 BART analysis (technical feasibility analysis of potential SO2
control technologies) are summarized in Table 4-3.
26 See, Lavely, L.L., Schild, V.S., and Toher, J., “First North American Circulating Dry Scrubber and
Precipitator Remove High Levels of SO2 and Particulate”,
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Table 4-3
Muskogee Units 4 & 5
Technical Feasibility of Potential SO2 Control Technologies
In Service on
Existing PC
Boilers?
Control
Technology
SO2 Emission Rate
(lb/mmBtu) Yes No
In Service on
Other
Combustion
Sources?
Technically Feasible Retrofit
Technology for Muskogee Units
4 & 5?
Fuel Switching NA X PCs have been
designed to burn a
variety of fuels.
Not technically feasible. The fuel
currently used is low-sulfur and
fuel switching will not reduce
controlled SO2 emissions.
Coal Washing NA X Washing has not
been used on sub-bituminous
coals.
Not technically feasible nor
commercially available.
Coal washing has not been used
on subbituminous coals and
washed subbituminous coal is not
commercially available.
Furthermore, it is unlikely that
firing a washed subbituminous
coal would result in any
significant reduction in controlled
SO2 emissions.
Coal Processing -- X Processed coal has
been demonstrated
in PC boilers.
Not technically available nor
commercially available.
Processed coal has not been
demonstrated on a long-term
basis as the primary flue in a PC
boiler, and is not commercially
available as a retrofit technology.
Wet FGD
(lime, limestone,
or magnesium
enhanced lime)
0.08 lb/mmBtu
(approx. 40 ppmvd @
3% O2)
X
Wet FGD has been
used on bituminous
coal-fired PC
boilers.
Technically feasible, however
limited commercial experience
with wet FGD on large
subbituminous fired units.
Jet Bubbling
Reactor Wet
FGD Control
System
0.08 lb/mmBtu
(approx. 40 ppmvd @
3% O2)
X
JBR-FGD systems
are in use on a
limited number of
coal-fired boilers.
Technically feasible, but may not
be commercially available for
Muskogee Units 4 & 5 (large sub-bituminous
fired units). Because
there is no operating experience
with JBR-WFGD systems on
large subbituminous-fired units,
the control system was evaluated
as an alternative WFGD control
system.
Dual-Alkali Wet
Scrubber NA X
In use at a limited
number of coal-fired
facilities.
Not commercially available.
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Table 4-3 continued:
In Service on
Existing PC
Boilers?
Control
Technology
SO2 Emission Rate
(lb/mmBtu) Yes No
In Service on
Other
Combustion
Sources?
Technically Feasible Retrofit
Technology for Muskogee Units
4 & 5?
Wet FGD with
WESP NA X
The WESP control
system is in use at
a limited number of
high-sulfur coal-fired
units.
Not technically feasible nor
commercially available for units
firing a low-sulfur subbituminous
coal.
Dry FGD – Spray
Dryer Absorber
0.10 lb/mmBtu
(approx. 50 ppmvd @
3% O2)
X
In use on sub-bituminous
coal-fired
boilers.
Technically feasible.
Dry Sorbent
Injection
0.4 lb/mmBtu
(approx. 200 ppmvd
@ 3% O2)
X
Dry sorbent
injection has been
used on a limited
number of coal-fired
units.
Technically feasible, but not as
effective as other SO2 control
options therefore excluded as
BART.
Circulating Dry
Scrubber NA X
CDS is in use at a
limited number of
coal-fired boilers.
CDS Dry FGD was determined
not to be commercially available
for Muskogee Units 4 & 5 (large
sub- bituminous fired units). In
addition, there is no commercial
experience with units similar to
Muskogee Units 4 & 5, so CDS-DFGD
was excluded as BART.
Step 3: Rank the Technically Feasible SO2 Control Options by Effectiveness
Both technically feasible SO2 retrofit technologies (i.e., Wet- and Dry-FGD) are capable of meeting
the BART presumptive level of 0.15 lb/mmBtu. However, in order to evaluate the cost
effectiveness of each control technology, annual emissions and costs were estimated at the design
emission limits of 0.08 lb/mmBtu for WFGD and 0.10 lb/mmBtu for DFGD. This approach was
taken in order to determine whether either control technology was cost effective at the anticipated
design emission rate. The technically feasible SO2 control technologies are listed in Table 4-4 in
descending order of control efficiency based on anticipated design emission rates.
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Table 4-4
Summary of Technically Feasible SO2 Control Technologies
SO2 Emission Rate*
(lb/mmBtu)
Control Technology
Muskogee 4 Muskogee 5
Wet FGD 0.08 0.08
Dry FGD – Spray Dryer Absorber 0.10 0.10
Baseline Uncontrolled SO2 Emissions 0.80 0.85
* Emission rates are based on 30-day rolling averages that can be achieved on
an on-going long-term basis under all normal operating conditions.
4.3 Step 4: Evaluate the Technically Feasible SO2 Control Technologies
Two post-combustion flue gas desulfurization control system designs (WFGD and SDA) are
technically feasible and capable of achieving very low SO2 emission rates. An evaluation of the
economic, energy and environmental impacts associated with each control system is provided
below.
4.3.1 Economic Evaluation
Summarized in Table 4-5 are the expected controlled SO2 emission rates and annual SO2 mass
emissions associated with each technically feasible control technology. Table 4-6 presents the
capital costs and annual operating costs associated with building and operating each control
system on Muskogee Units 4 & 5. Table 4-7 shows the average annual and incremental cost
effectiveness for each SO2 control system.
Table 4-5
Muskogee Units 4 & 5
Annual SO2 Emissions (per boiler)
Control Muskogee 4 Muskogee 5
Technology
SO2 Emissions
(lb/mmBtu)
Emissions
(tpy)*
Reduction in
Emissions (tpy)*
Emissions
(tpy)*
Reduction in
Emissions (tpy)*
Wet FGD 0.08 1,728 15,554 1,728 16,634
Dry FGD – SDA 0.10 2,160 15,122 2,160 16,202
Baseline 0.80 (Unit 4)
0.85 (Unit 5)
17,282 -- 18,362 --
* Annual emissions and annual emission reductions for the BART analysis were calculated based on a full
load heat input of 5,480 mmBtu/hr (per boiler), and assuming 7,884 hours/year (90% capacity factor).
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Table 4-6
Muskogee Units 4 & 5
SO2 Emission Control System Cost Summary (each boiler)*
Control
Technology
Total Capital
Investment
($)
Total Capital
Investment
($/kW-gross)
Annual Capital
Recovery Cost
($/year)
Annual
Operating Costs
($/year)
Total Annual
Costs
($/year)
Wet FGD $418,567,000 $732 $35,917,500 $41,412,800 $77,067,900
Dry FGD – SDA $373,106,000 $708 $32,016,400 $39,051,500 $71,330,300
* Capital costs for SO2 control systems will be essentially equal for Units 4 and 5. Capital costs include the cost of
major components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and
insulation for the control system. Capital costs for the Wet FGD scenario include the cost of new chimneys on both
units, and capital costs for the Dry FGD scenario include the cost of a post-scrubber fabric filter baghouse.
Table 4-7
Muskogee Units 4 & 5
SO2 Emission Control System Cost Effectiveness (total for two boilers)
Control Technology
Total Annual
Cost*
($/year)
Annual Emission
Reduction
(tpy)
Average Annual
Cost
Effectiveness
($/ton)
Incremental
Annual Cost
Effectiveness**
($/ton)
Wet FGD $154,135,800 32,188 $4,789 $13,281
Dry FGD – SDA $142,660,600 31,324 $4,554 --
* Total annual costs in this table reflect total costs (capital and O&M) for both units. Costs are slightly more
than double the total annual costs for Unit 4 because of the higher baseline emission rate on Unit 5.
**Incremental cost effectiveness of the wet FGD control systems compared to the SDA control system.
The average cost effectiveness of the potentially feasible SO2 control technologies range from
approximately $4,554/ton for dry FGD to $4,789/ton for wet FGD. To support the BART
rulemaking process, EPA calculated