Oklahoma Department of Environmental Quality

Air Quality Division

BART Application Analysis September 28, 2009

COMPANY: Oklahoma Gas and Electric 

FACILITY: Seminole Generating Station

FACILITY LOCATION: Konawa, Seminole County, Oklahoma

TYPE OF OPERATION: (3) 567 MW Steam Electric Generating Units

REVIEWER: Phillip Fielder, Senior Engineering Manager

Lee Warden, Engineering Manager

I. PURPOSE OF APPLICATION

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.

II. BART ELIGIBILITY DETERMINATION

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).

Seminole Units 1, 2 and 3 are fossil-fuel fired boilers with heat inputs greater than 250-

mmBtu/hr. All three units were in existence prior to August 7, 1977, but not in operation prior to 

August 7, 1962. Based on a review of existing emissions data, all three units have the potential 

to emit more than 250 tons per year of NOX, a visibility impairing pollutant. Therefore, 

Seminole Units 1, 2 and 3 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. 
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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DEQ 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 conducted by OG&E determined that the maximum predicted visibility impacts from 

Seminole Units 1, 2 and 3 exceeded the 0.5 Δ-dv threshold at the Wichita Mountains Class I 

Area. Therefore, Seminole Units 1, 2 and 3 were determined to be BART applicable sources, 

subject to the BART determination requirements.

III. DESCRIPTION OF BART SOURCES

Baseline emissions from Seminole Units 1, 2 and 3 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 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 rates for each boiler by the boiler’s full load heat input.

Table 1: Seminole Generating Station- Plant Operating Parameters for BART Evaluation

Parameter Seminole Unit 1 Seminole Unit 2 Seminole Unit 3

Plant Configuration Natural Gas-Fired 

Boiler

Natural Gas-Fired 

Boiler

Natural Gas-Fired 

Boiler

Firing Configuration Wall-fired Wall-fired Wall-fired

Gross Output (nominal) 567 MW 567 MW 567 MW

Maximum Input to 

Boiler

5,480 mmBtu/hr 5,480 mmBtu/hr 5,496 mmBtu/hr

Primary Fuel Natural gas Natural gas Natural gas

Existing NOX Controls None None Flue gas recirculation

Existing PM10 Controls NA NA NA

Existing SO2 Controls NA NA NA

Baseline Emissions 

Pollutant Baseline Actual 

Emissions

Baseline Actual 

Emissions

Baseline Actual 

Emissions

lb/hr lb/mmBtu lb/hr lb/mmBtu lb/hr lb/mmBtu

NOX 1,859 0.339 1,940 0.354 1,204 0.219
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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IV. BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

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.

Because the units fire natural gas, emissions of sulfur dioxide (SO2) and particulate matter (PM)

are minimal. There are no SO2 or PM post-combustion control technologies with a practical 

application to natural gas-fired boilers. BART is good combustion practices. A full BART 

analysis was conducted for NOX. 

Table 2: Proposed BART Controls and Limits

Unit NOX BART Emission Limit BART Technology

Seminole Unit 1 0.203 lb/mmBtu (30-day average) Combustion controls including 

LNB/OFA and FGR

Seminole Unit 2 0.212 lb/mmBtu (30-day average) Combustion controls including 

LNB/OFA and FGR

Seminole Unit 3 0.164 lb/mmBtu (30-day average) Combustion controls including 

LNB/OFA and FGR

A. NOX

IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

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

available information. NOX control technologies with potential application to Seminole Units 1, 

2 and 3 are listed in Table 3.

Table 3: List of Potential Control Options

Control Technology

Combustion Controls

Low NOX Burners and 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)

Pahlman Process

Wet NOX Scrubbing
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In support of the Regional Haze Rule, EPA also prepared a cost-effectiveness analysis for retrofit 

control technologies on oil- and gas-fired units. EPA’s analysis concluded that, although a 

number of oil- and gas-fired units could make significant cost-effective reductions in NOX

emissions using currently available combustion control technologies, for a number of units the 

use of combustion controls did not appear to be cost effective. As a result, EPA determined that 

it would be inappropriate to establish a general presumption regarding likely BART limits for 

oil- and natural gas fired units.

ELIMINATE TECHICALLY INFEASIBLE OPTIONS (NOX)

Combustion Controls:

Low NOX burners (LNB)/ Over Fire Air (OFA)

Low NOX burners (LNB) limit NOX formation by controlling both the stoichiometric and 

temperature profiles of the combustion flame in each burner flame envelope. Over Fire Air 

(OFA) allows for staged combustion. Staging combustion reduces NOX formation with a cooler 

flame in the initial stage and less oxygen in the second stage.

LNB/OFA emission control systems have been installed as retrofit control technologies on 

existing natural gas-fired boilers. Boilers of the size and age of the Seminole Units would be 

expected to achieve an average emission reduction in the range of 25% to 40% from baseline 

depending on the baseline emission rate and boiler operating conditions. Seminole units 1, 2, 

and 3 do not operate as base load units. The units have historically operated as “peaking units” 

responding to increased demand for electricity. While technically feasible, LNB/OFA may not 

be as effective under all boiler operating conditions, especially during load changes and at low 

and high operating loads. Based on information available from burner control vendors and 

engineering judgment, it is expected that LNB/OFA on the wall-fired boilers can be designed to 

achieve an average efficiency of 25% from baseline emissions under all normal operating 

conditions.

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 which 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. Seminole Unit 3 is currently designed 

with FGR control.

FGR may be applied in one of two techniques. Both designs are technically feasible retrofit 

options for gas-boilers. Either system would be expected to achieve an additional 15% reduction 

above LNB/OFA or approximately 40% overall reduction from baseline.

Post Combustion Controls:

Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia or urea at 

high flue gas temperatures. The ammonia or urea reacts with NOX in the flue gas to produce N2

and water. At temperatures below the desired operating range, the NOX reduction reactions 

diminish and NH3 emissions increase. Above the desired temperature range, NH3 is oxidized to 
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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NOX resulting in low NOX reduction efficiencies. Mixing of the reactant and flue gas within the 

reaction zone is also an important factor in SNCR performance. In large boilers, the physical 

distance over which the 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, reducing overall efficiency. Performance is further influenced by residence 

time, reagent-to-NOX ratio, and fuel sulfur content.

The size of the Seminole Units would represent several design problems making it difficult to 

ensure that the reagent would be injected at the optimum flue gas temperature, and that there 

would be adequate mixing and residence time. The physical size of the Seminole boilers makes 

it technically infeasible to locate and install ammonia injection points capable of achieving

adequate mixing within the required temperature zone. Higher reagent injection rates would be 

required to achieve adequate mixing. This design would tend to result in relatively high levels of 

ammonia slip. Further, because the Seminole boilers are typically used as peaking units, boiler 

load is continually changing. Boiler load changes affect flue gas flow rates and temperatures, 

which would make it particularly difficult to inject the needed quantity of reactant. 

Installation of SNCR on large boilers, such as those at Seminole, has not been demonstrated in 

practice. Assuming that SNCR could be installed on the Seminole Units, given the issues 

addressed above, control effectiveness would be marginal, and depending on boiler exit 

temperatures, could actually result in additional NOX formation. SNCR is not a technically 

feasible retrofit control for the Seminole Boilers.

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. 

SCR has been installed as NOX control technology on existing gas-fired boilers. Based on 

emissions data available from the EPA Electronic Reporting website, large gas-fired boilers 

(with heat inputs above approximately 1,000 mmBtu/hr) have achieved actual long-term average 

NOX emission rates in the range of approximately 0.02 to 0.05 lb/mmBtu. 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 

temperature, and catalyst activity.

Based on emission rates achieved in practice at existing gas-fired units, and taking into 

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

deactivation) and the fact that the Seminole boilers typically operate as peaking units, it is 

anticipated that SCR could achieve a controlled NOX emission rate of 0.04 lb/mmBtu (30-day 

rolling average) on Seminole Units 1, 2 and 3.

Innovative NOX Control Technologies:

Rotating Opposed Fire Air and Rotomix

Rotating opposed fired air (ROFA) is a boosted over fire air system that includes a patented

rotation process which includes asymmetrically placed air nozzles. Like other OFA systems, 
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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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.

As discussed in for OFA, over fire air control systems are a technically feasible retrofit control 

technology, and, based on engineering judgment, the ROFA design could also be applied on 

Seminole Units 1, 2 and 3. 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 are not evaluated as a specific control system, but are included 

in the overall evaluation of combustion controls (e.g., LNB/OFA).

ROFA + SNCR (Rotamix)

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 the SNCR section, 

including the physical size of the boiler, inadequate NH3/NOX contact, and flue gas 

temperatures, would apply equally to the Rotamix control system. There is no technical basis to 

conclude that the Rotamix design addresses these unresolved technical difficulties. Therefore, 

like other SNCR control systems, the Rotamix system is not a technically feasible retrofit control 

for the Seminole Boilers.

Pahlman Multi-Pollutant Control Process

The PahlmanTM Process is a patented dry-mode multi-pollutant control system. The process uses 

a sorbent composed of oxides of manganese (the PahlmaniteTM sorbent) to remove NOX and SO2

from the flue gas.

To date, bench- and pilot-scale testing have been conducted to evaluate the technology on utilitysized boilers.9 The New & Emerging Environmental Technologies (NEET) Database identifies 

the development status of the Pahlman Process as full-scale development and testing. 10 The 

process is an emerging multi-pollutant control, and there is limited information available to 

evaluate its technically feasibility and long-term effectiveness on a large natural gas-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 Seminole 

Units 1, 2 and 3. 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 a technically feasible retrofit control for the 

Seminole Boilers

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’ LoTOxTM 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 
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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petroleum refining and oil/natural gas production. However the technology has not been 

demonstrated on large utility 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 systems are not technically feasible retrofit 

controls for the Seminole Boilers

EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES (NOX)

Table 4: Technically Feasible NOX Control Technologies- Seminole Station

Control Technology

Seminole Unit 1 Seminole Unit 2 Seminole Unit 3

Approximate NOX

Emission Rate

(lb/mmBtu)

Approximate NOX

Emission Rate

(lb/mmBtu)

Approximate NOX

Emission Rate

(lb/mmBtu)

LNB/OFA + SCR 0.04 0.04 0.04

LNB/OFA + FGR 0.203 0.212 0.164

LNB/OFA 0.254 0.266 NA

Baseline 0.339 0.354 0.219

EVALUATE IMPACTS AND DOCUMENT RESULTS (NOX)

OG&E evaluated the economic, environmental, and energy impacts associated with the three 

proposed control options. In general, the cost estimating methodology followed guidance 

provided in the EPA Air Pollution Cost Control Manual. Major equipment costs were developed 

based on publicly available cost data and equipment costs recently developed for similar 

projects, and include the equipment, material, labor, and all other direct costs needed to retrofit 

Seminole Units 1, 2 and 3 with the control technologies. Fixed and variable O&M costs were 

developed for each control system. Fixed O&M costs include operating labor, maintenance 

labor, maintenance material, and administrative labor. Variable O&M costs include the cost of 

consumables, including reagent (e.g., ammonia), byproduct management, water consumption, 

and auxiliary power requirements. Auxiliary power requirements reflect the additional power 

requirements associated with operation of the new control technology, including operation of any 

new fans as well as the power requirements for pumps, reagent handling, and by-product 

handling. The capital recovery factor used to estimate the annual cost of control was based on a 

7% interest rate and a control life of 25 years. OG&E provided a summary of historical capacity 

factors which typically ranged between approximately 25% to 30%. Annual operating costs and 

annual emission reductions were calculated assuming a capacity factor of 50%.
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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Table 5: Economic Cost Per Boiler

Cost Unit

Option 1: 

LNB/OFA

Option 2: 

LNB/OFA 

w/FGR

Option 3:

LNB/OFA +SCR

Control Equipment Capital 

Cost ($)

Unit 1 $9,432,200 $16,977,200 $104,230,200

Unit 2 $9,432,200 $16,977,200 $104,230,200

Unit 3 $9,468,600 $9,468,600 $104,834,200

Capital Recover Factor

($/Yr)

Unit 1 $809,300 $1,456,700 $8,943,000

Unit 2 $809,300 $1,456,700 $8,943,000

Unit 3 $812,400 $812,400 $8,994,800

Annual O&M Costs

($/Yr)

Unit 1 $588,600 $1,190,900 $8,152,800

Unit 2 $588,600 $1,190,900 $8,175,600

Unit 3 $590,800 $590,800 $8,023,800

Annual Cost of Control

($)

Unit 1 $1,397,900 $2,647,600 $17,095,800

Unit 2 $1,397,900 $2,647,600 $17,118,600

Unit 3 $1,403,200 $1,403,200 $17,018,600

Table 6: Environmental Costs per Boiler

Baseline

Option 1: 

LNB/OFA

Option 2: 

LNB/OFA 

w/FGR

Option 3: 

LNB/OFA 

+SCR

NOX Emission 

Rate 

(lb/mmBtu)

Unit 1 0.339 0.254 0.203 0.04

Unit 2 0.354 0.266 0.212 0.04

Unit 3 0.219 0.164 0.164 0.04

Annual NOX 

Emission 

(TPY)1

Unit 1 4,068 3,048 2,436 480

Unit 2 4,248 3,192 2,544 480

Unit 3 2,636 1,974 1,974 481

Annual NOX

Reduction 

(TPY)

Unit 1 -- 1020 1632 3588

Unit 2 1056 1704 3768

Unit 3 662 662 2155

Annual Cost of 

Control2

Unit 1 $1,397,900 $2,647,600 $17,095,800

Unit 2 $1,397,900 $2,647,600 $17,118,600

Unit 3 $1,403,200 $1,403,200 $17,018,600

Cost per Ton 

of Reduction

Unit 1 $1,370 $1,622 $4,765

Unit 2 $1,324 $1,554 $4,543

Unit 3 $2,120 $2,120 $7,897

Incremental 

Cost per ton of 

Reduction3

Unit 1 N/A -- $2,042 $7,387

Unit 2 $1,929 $7,011

Unit 3 -- $10,459

(1) Emissions for the BART analysis are based on maximum heat inputs of 5,480 mmBtu/hr (Units 1 & 2) and 5,496 

mmBtu/hr (Unit 3). Annual emissions were calculated assuming 4,380 hours/year per boiler (50% capacity factor).

(2)Total annual cost for all three units are not additive because Unit 3 is currently equipped with FGR control and 

Unit 3 has a slightly higher heat input.

(3)

Incremental cost effectiveness of the FGR system is compared to costs/emissions associated with LNB/OFA 

controls. Similarly, incremental cost effectiveness of the SCR system is compared to costs/emissions associated with 

LNB/OFA+FGR controls.
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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B. VISIBILITY IMPROVEMENT DETERMINATION 

The fifth of five factors that must be considered for a BART determination analysis, as required 

by a 40 CFR part 51- Appendix Y, is the degree of Class I area visibility improvement that 

would result from the installation of the various options for control technology. This factor was 

evaluated for the Seminole Generating Station by using an EPA-approved dispersion modeling 

system (CALPUFF) to predict the change in Class I area visibility. The Division had previously 

determined that the Seminole Generating Station was subject to BART based on the results of 

initial screening modeling that was conducted using current (baseline) emissions from the 

facility. The screening modeling, as well as more refined modeling conducted by the applicant, 

is described in detail below.

Wichita Mountain Wildlife Refuge, Caney Creek, Upper Buffalo and Hercules Glade are the 

closest Class I areas to the Seminole Generating Station, as shown in Figure 1 below. 

Only those Class I areas most likely to be impacted by the Seminole Generating Station were 

modeled, as determined by source/Class I area locations, distances to each Class I area, and 

professional judgment considering meteorological and terrain factors. It can be reasonably 

assumed that areas at greater distances and in directions of less frequent plume transport will 

experience lower impacts than those predicted for the four modeled areas. 

Figure 1: Plot of Facility location in relation to nearest Class I areas
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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REFINED MODELING:

Because of the results of the applicants screening modeling for the Seminole Generating Station, 

OG&E was required to conduct a refined BART analysis that included CALPUFF visibility 

modeling for the facility. The modeling approach followed the requirements described in the 

Division’s BART modeling protocol, CENRAP BART Modeling Guidelines (Alpine Geophysics, 

December 2005) with refinements detailed the applicants CALMET modeling protocol, 

CALMET Data Processing Protocol (Trinity Consultants, January 2008)

CALPUFF System

Predicted visibility impacts from the Seminole Generating Station were determined with the EPA 

CALPUFF modeling system, which is the EPA-preferred modeling system for long-range 

transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR 

Part 51), long-range transport is defined as modeling with source-receptor distances greater than 

50 km. Because all modeled areas are located more than 50 km from the sources in question, the 

CALPUFF system was appropriate to use.

The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an 

air dispersion model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, 

CALPOST). The CALPUFF model was developed as a non-steady-state air quality modeling 

system for assessing the effects of time- and space-varying meteorological conditions on 

pollutant transport, transformation, and removal. 

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a 

three-dimensional, gridded modeling domain. Meteorological inputs to CALMET can include 

surface and upper-air observations from multiple meteorological monitoring stations. 

Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale 

models such as MM5 to better represent regional wind flows and complex terrain circulations. 

Associated two-dimensional fields such as mixing height, land use, and surface roughness are 

included in the input to the CALMET model. The CALMET model allows the user to “weight” 

various terrain influences parameters in the vertical and horizontal directions by defining the 

radius of influence for surface and upper-air stations. 

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the 

three-dimensional wind fields developed by the CALMET model (refined mode), or by data 

from a single surface and upper-air station in a format consistent with the meteorological files 

used to drive steady-state dispersion models. All far-field modeling assessments described here 

were completed using the CALPUFF model in a refined mode.

CALPOST is a post-processing program that can read the CALPUFF output files, and calculate 

the impacts to visibility. 

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system 

that was recognized as the EPA-approved release at the time of the application submittal. 

Version designations of the key programs are listed in the table below.
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Table 7: Key Programs in CALPUFF System

Program Version Level

CALMET 5.53a 040716

CALPUFF 5.8 070623

CALPOST 5.51 030709

Meteorological Data Processing (CALMET)

As required by the Division’s modeling protocol, the CALMET model was used to construct the 

initial three-dimensional wind field using data from the MM5 model. Surface and upper-air data 

were also input to CALMET to adjust the initial wind field. 

The following table lists the key user-defined CALMET settings that were selected.

Table 8: CALMET Variables

Variable Description Value

PMAP Map projection LCC (Lambert Conformal 

Conic)

DGRIDKM Grid spacing (km) 4

NZ Number of layers 12

ZFACE Cell face heights (m) 0, 20, 40, 60, 80, 100, 150, 

200, 250, 500, 1000, 2000, 

3500

RMIN2 Minimum distance for 

extrapolation

-1

IPROG Use gridded prognostic model 

outputs

14 km (MM5 data)

RMAX1 Maximum radius of influence 

(surface layer, km)

20 km

RMAX2 Maximum radius of influence 

(layers aloft, km)

50 km

TERRAD Radius of influence for terrain 

(km)

10 km

R1 Relative weighting of first 

guess wind field and 

observation (km)

10 km 

R2 Relative weighting aloft (km) 25 km

The locations of the upper air stations with respect to the modeling domain are shown in Figure 2.
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Figure 2: Plot of surface station locations

Figure 3: Plot of upper air station locations
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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Figure 4. Plot of precipitation observation stations

CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry 

mechanism (MESOPUFF II), the model required input of background ozone and ammonia. 

CALPUFF can use either a single background value representative of an area or hourly ozone data from 

one or more ozone monitoring stations. Hourly ozone data files were used in the CALPUFF simulation. 

As provided by the Oklahoma DEQ, hourly ozone data from the Oklahoma City, Glenpool, and Lawton 

monitors over the 2001-2003 time frames were used. Background concentrations for ammonia were 

assumed to be temporally and spatially invariant and were set to 3 ppb.

Latitude and longitude coordinates for Class I area discrete receptors were taken from the 

National Park Service (NPS) Class I Receptors database and converted to the appropriate LCC 

coordinates.

CALPUFF Inputs- Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current 

(baseline) operations at the facility. Emissions of NOX for the baseline runs were established 

based on CEM data and maximum 24-hour emissions averages for years 2001 to 2003. All 

particulate emissions (PM) were based on emission rates of 0.00186 lb/mmBtu (filterable) and 

were treated as PM10 (coarse PM) and 0.00559 lb/mmBtu (condensable) and were treated as 

PM2.5 (fine PM) within CALPUFF and CALPOST. Direct emissions of sulfate were based on 

the values calculated for the Toxic Release Inventory (TRI) for the years modeled.

Baseline source release parameters and emissions are shown in the table below, followed by 

tables with data for the various control options. No attempt was made by the applicant to 

estimate the increase in sulfate emissions that would result from operations of SCR, and as a 
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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result the visibility improvement for those scenarios may be overestimated by some 

undetermined amount.

Table 9: Baseline Source Parameters

Parameter

Baseline

Natural Gas-Fired

Unit 1

Natural Gas-Fired

Unit 2

Natural Gas-Fired

Unit 3 (FGR)

Heat Input (mmBtu/hr) 5,480 5,480 5,496

Base Elevation (m) 290 290 290

Stack Height (m) 54.27 54.27 106.71

Stack Diameter (m) 4.57 4.57 5.49

Stack Temperature (K) 392.44 392.44 411.89

Exit Velocity (m/s) 42.32 42.32 30.95

SO2 Emissions (lb/mmBtu) 0.00055 0.00042 0.00060

SO2 Emissions (TPY) 13.20 10.08 14.44

NOX Emissions1(lb/mmBtu) 0.339 0.354 0.219

NOX Emissions TPY 8136.81 8496.85 5271.87

PM10 Fine Emissions2

(lb/mmBtu)

0.00745 0.00745 0.00745

PM10 Fine Emissions (TPY) 178.82 178.82 179.34

1Baseline NOx emissions were based on the maximum 24-hr average emission rate (lb/hr) reported by each unit 

during the baseline period 2003-2005. Baseline emissions data were provided by OG&E. Baseline emission rates 

(lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the maximum heat input to the 

boiler.

2

PM emissions are based on AP-42 emission factors for natural gas combustion (filterable and condensable).

Table 10: Source Parameters and Emissions for BART Control Options

Scenario Control

Heat Input 

(mmBtu/hr)

NOX 

Emissions 

(lb/mmBtu)

NOX 

Emissions 

TPY

Control 

Option 1

LNB/OFA 5,480 0.254 6,097

Natural GasFired

Unit 2

LNB/OFA 5,480 0.266 6,384

Natural GasFired

Unit 3

LNB/OFA 

FGR 5,496 0.164 3,948

Control 

Option 2

Natural GasFired

Unit 1

LNB/OFA 

FGR 5,480 0.203 4,872

Natural GasFired

Unit 2

LNB/OFA 

FGR 5,480 0.212 5,089

Natural GasFired

Unit 3

LNB/OFA 

FGR 5,496 0.164 3,948
OG&E Seminole Generating Station BART Evaluation September 28, 2009

15

Scenario Control

Heat Input 

(mmBtu/hr)

NOX 

Emissions 

(lb/mmBtu)

NOX 

Emissions 

TPY

Control 

Option 3

Natural GasFired

Unit 1

LNB/OFA + 

SCR 5,480 0.040 960

Natural GasFired

Unit 2

LNB/OFA + 

SCR 5,480 0.040 960

Natural GasFired

Unit 3

LNB/OFA + 

SCR 5,496 0.040 963

Visibility Post-Processing (CALPOST) Setup

The changes in visibility were calculated using Method 6 with the CALPOST post-processor. 

Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area that is 

being modeled. Monthly f(RH) factors that were used for this analysis are shown in the table 

below. 

Table 11: Relative Humidity Factors for CALPOST

Month

Wichita 

Mountains Caney Creek Upper Buffalo Hercules Glade

January 2.7 3.4 3.3 3.2

February 2.6 3.1 3.0 2.9

March 2.4 2.9 2.7 2.7

April 2.4 3.0 2.8 2.7

May 3.0 3.6 3.4 3.3

June 2.7 3.6 3.4 3.3

July 2.3 3.4 3.4 3.3

August 2.5 3.4 3.4 3.3

September 2.9 3.6 3.6 3.4

October 2.6 3.5 3.3 3.1

November 2.7 3.4 3.2 3.1

December 2.8 3.5 3.3 3.3

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 

of EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Program were to develop natural background estimates for each Class I area.
OG&E Seminole Generating Station BART Evaluation September 28, 2009

16

Visibility Post-Processing Results

Table 12: CALPUFF Visibility Modeling Results for Seminole Units 1, 2 and 3

Class I Area

2001 2002 2003 3-Year Average

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

98th

Percentile 

Value 

(Δdv)

No. of 

Days 

> 0.5 

Δdv

Baseline

Wichita 

Mountains

1.073 20 0.744 12 1.3 25 1.039 19

Caney Creek 1.173 18 0.455 7 0.443 7 0.69 11

Upper Buffalo 0.635 9 0.24 2 0.302 2 0.39 4

Hercules 

Glade

0.403 5 0.294 3 0.301 3 0.33 4

Scenario 2- Combustion Control- LNB/OFA FGR

Wichita 

Mountains

0.707 13 0.476 7 0.832 17 0.67 12

Caney Creek 0.754 12 0.284 1 0.284 2 0.44 5

Upper Buffalo 0.411 4 0.157 2 0.191 1 0.25 2

Hercules 

Glade

0.255 2 0.186 0 0.188 2 0.21 1

Modeling for SCR controls resulted in an approximately 80% reduction in visibility impairment 

from scenario two.

C. BART DETERMINATION

After considering: (1) the costs of compliance, (2) the energy and non-air quality environmental 

impacts of compliance, (3) any pollutant equipment in use or in existence at the source, (4) the 

remaining useful life of the source, and (5) the degree of improvement in visibility (all five 

statutory factors) from each proposed control technology, the Division determined BART for the 

three units at the Seminole Generating Station.

New LNB with OFA is determined to be BART for NOX control for Units 1-3 based, in part, on 

the following conclusions:

1. Installation of new LNB with OFA and FGR was cost effective, with a capital cost of 

$16,977,200 per unit for units 1 and 2 and $9,468,600 for unit 3 and an average cost 

effectiveness of $1,554-$2,120 per ton of NOX removed for each unit over a twenty year 

operational life.

2. Combustion control using the LNB/OFA and FGR does not require non-air quality 

environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and 

there is minimal energy impact.
OG&E Seminole Generating Station BART Evaluation September 28, 2009

17

3. After careful consideration of the five statutory factors, especially the costs of 

compliance and existing controls, NOX control levels on 30-day rolling averages of 0.203 

lb/mmBtu for Unit 1, 0.212 lb/mmBtu for Unit 2 and 0.164 lb/mmBtu for Unit 3 are 

justified. 

4. Annual NOX emission reductions from new LNB with OFA and FGR on Units 1, 2, and 3 

are 662-1,704 tons for a total annual reduction of 3,998 tons.

LNB with OFA and SCR was not determined to be BART for NOX control for Units 1-3 based, 

in part, on the following conclusions:

1. The cost of compliance for installing SCR on each unit is significantly higher than the 

cost for LNB with OFA and FGR. Additional capital costs for SCR on Units 1-3 are on 

average $89,957,200 per unit. Based on projected actual emissions, SCR could reduce 

overall NOX emissions from Seminole Units 1, 2 and 3 by approximately 5,513 tpy 

(compared to combustion controls and flue gas recirculation); however, the incremental 

cost associated with this reduction is approximately $44,534,600 per year, or $8,078/ton.

2. Additional non-air quality environmental mitigation is required for the use of chemical 

reagents. 

3. Operation of LNB with OFA and SCR is parasitic and requires power from each unit.

4. SCR control may not be as effective on boilers that operate as peaking units, as NOX reduction in 

an SCR is a function of flue gas temperature.

5. The cumulative visibility improvement for SCR, as compared to LNB/OFA and FGR across 

Wichita Mountains and Caney Creek (based on the 98th percentile modeled results) was 0.56-0.60 

Δdv for all three units.

The Division considers the installation and operation of the BART determined NOX controls, 

new LNB with OFA and FGR, to meet the statutory requirements of BART.

Unit-by-unit NOX BART determinations:

Seminole Generating Station Unit 1: New LNB with OFA and FGR and meeting NOX

emission limit of 0.203 lb/mmBtu (30-day rolling 

average), 1,112 lb/hr (30-day rolling average), and 

4,872 tpy (12-month rolling) as BART for NOX. 

Seminole Generating Station Unit 2: New LNB with OFA and FGR and meeting NOX

emission limit of 0.212 lb/mmBtu (30-day rolling 

average), 1,162 lb/hr (30-day rolling average), and 

5,089 tpy (12-month rolling) as BART for NOX.

Seminole Generating Station Unit 3: New LNB with OFA and FGR and meeting NOX

emission limit of 0.164 lb/mmBtu (30-day rolling 
OG&E Seminole Generating Station BART Evaluation September 28, 2009

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average), 901 lb/hr (30-day rolling average), and 3,948 

tpy (12-month rolling) as BART for NOX.

V. CONSTRUCTION PERMIT

Prevention of Significant Deterioration (PSD) 

Seminole Generating Station is a major source under OAC 252:100-8 Permits for Part 70 

Sources. Oklahoma Gas and Electric should comply with the permitting requirements of 

Subchapter 8 as they apply to the installation of controls determined to meet BART.

The installation of controls determined to meet BART will not change NSPS or 

NESHAP/MACT applicability for the gas-fired units at the Seminole Station.

VI. OPERATING PERMIT

The Seminole Generating Station is a major source under OAC 252:100-8 and has submitted an 

application to modify their existing Title V permit to incorporate the requirement to install 

controls determined to meet BART. The Permit will contain the following specific conditions:

1. The boilers in EUG 2 are subject to the Best Available Retrofit Technology (BART) 

requirements of 40 CFR Part 51, Subpart P, and shall comply with all applicable requirements 

including but not limited to the following: [40 CFR §§ 51.300-309 & Part 51, Appendix Y]

a. Affected facilities. The following sources are affected facilities and are subject to 

the requirements of this Specific Condition, the Protection of Visibility and 

Regional Haze Requirements of 40 CFR Part 51, and all applicable SIP 

requirements:

EU ID#

Point 

ID# EU Name

Heat Capacity

(MMBTUH)

Construction

Date

2-B 01 Unit 1 Boiler 5,480 1968

2-B 02 Unit 2 Boiler 5,480 1968

2-B 03 Unit 3 Boiler 5,496 5/28/70

b. Each existing affected facility shall install and operate the SIP approved BART as 

expeditiously as practicable but in no later than five years after approval of the 

SIP incorporating the BART requirements.

c. The permittee shall apply for and obtain a construction permit prior to 

modification of the boilers. If the modifications will result in a significant 

emission increase and a significant net emission increase of a regulated NSR 

pollutant, the applicant shall apply for a PSD construction permit.

d. The affected facilities shall be equipped with the following current combustion 

control technology, as determined in the submitted BART analysis, to reduce 

emissions of NOX to below the emission limits below:

i. Low-NOX Burners,

ii. Overfire Air, and
OG&E Seminole Generating Station BART Evaluation September 28, 2009

19

iii. Flue Gas Recirculation.

e. The permittee shall maintain the combustion controls (Low-NOX burners, 

overfire air, and flue gas recirculation) and establish procedures to ensure the 

controls are properly operated and maintained.

f. Within 60 days of achieving maximum power output from each affected facility, 

after modification or installation of BART, not to exceed 180 days from initial 

start-up of the affected facility the permittee shall comply with the emission limits 

established in the construction permit. The emission limits established in the 

construction permit shall be consistent with manufacturer’s data and an agreed 

upon safety factor. The emission limits established in the construction permit 

shall not exceed the following emission limits:

EU ID# Point ID# NOX Emission Limit Averaging Period

2-B 01 0.203 lb/MMBTU 30-day rolling

2-B 02 0.212 lb/MMBTU 30-day rolling

2-B 03 0.164 lb/MMBTU 30-day rolling

g. Boiler operating day shall have the same meaning as in 40 CFR Part 60, Subpart 

Da.

h. After installation of the BART, the affected facilities shall only be fired with 

natural gas.

i. Within 60 days of achieving maximum power output from each boiler, after 

modification of the boilers, not to exceed 180 days from initial start-up, the 

permittee shall conduct performance testing as follows and furnish a written 

report to Air Quality. Such report shall document compliance with BART 

emission limits for the affected facilities. [OAC 252:100-8-6(a)]

i. The permittee shall conduct NOX, CO, and VOC testing on the boilers at 60% 

and 100% of the maximum capacity. NOX and CO testing shall also be 

conducted at least one additional intermediate point in the operating range.

ii. Performance testing shall be conducted while the units are operating within 

10% of the desired testing rates. A testing protocol describing how the testing 

will be performed shall be provided to the AQD for review and approval at least 

30 days prior to the start of such testing. The permittee shall also provide notice 

of the actual test date to AQD.

iii. The following USEPA methods shall be used for testing of emissions, unless 

otherwise approved by Air Quality:

Method 1: Sample and Velocity Traverses for Stationary Sources.

Method 2: Determination of Stack Gas Velocity and Volumetric Flow 

Rate.

Method 3: Gas Analysis for Carbon Dioxide, Excess Air, and Dry 

Molecular Weight.