Oklahoma Gas & Electric Muskogee Generating Station Best ...
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<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
<strong>Best</strong> Available Retrofit Control Technology Evaluation<br />
Prepared by: Sargent & Lundy LLC<br />
Chicago, Illinois<br />
Trinity Consultants<br />
<strong>Oklahoma</strong> City, <strong>Oklahoma</strong><br />
May 28, 2008
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
EXECUTIVE SUMMARY<br />
OG&E’s <strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> is located at 5501 Three Forks Road near <strong>Muskogee</strong>,<br />
<strong>Oklahoma</strong>. The station has a total of four (4) generating units designated as <strong>Muskogee</strong> Units 3, 4, 5<br />
and 6. <strong>Muskogee</strong> Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit.<br />
<strong>Muskogee</strong> Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of<br />
<strong>Muskogee</strong> Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit<br />
5 coming on-line in 1978. Construction commenced on <strong>Muskogee</strong> Unit 6 in 1980, and Unit 6<br />
commenced commercial operation in mid-1984. All three coal-fired units at the <strong>Muskogee</strong><br />
<strong>Generating</strong> <strong>Station</strong> are dry bottom tangentially-fired pulverized coal (PC) boilers. The boilers fire<br />
subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for<br />
particulate control.<br />
On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional<br />
Haze Regulations and Guidelines for <strong>Best</strong> Available Retrofit Technology Determinations” (the<br />
“Regional Haze Rule” 70 FR 39104). The Regional Haze Rule requires certain States, including<br />
<strong>Oklahoma</strong>, to develop programs to assure reasonable progress toward meeting the national goal of<br />
preventing any future, and remedying any existing, impairment of visibility in Class I Areas. The<br />
Regional Haze Rule requires states to submit a plan to implement the regional haze requirements<br />
(the Regional Haze SIP). The Regional Haze SIP must provide for a <strong>Best</strong> Available Retrofit<br />
Technology (BART) analysis of any existing stationary facility that might cause or contribute to<br />
impairment of visibility in a Class I Area.<br />
BART-eligible sources include those sources that:<br />
(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant;<br />
(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and<br />
(3) whose operations fall within one or more of the specifically listed source categories in 40<br />
CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr<br />
heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).<br />
<strong>Muskogee</strong> Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BARTeligible<br />
source. <strong>Muskogee</strong> Unit 6 was not in existence prior to August 7, 1977; therefore, Unit 6 is<br />
not a BART-eligible source. <strong>Muskogee</strong> Units 4 & 5 are fossil-fuel fired boilers with heat inputs<br />
greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 (i.e., construction<br />
of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of<br />
existing emissions data, both units have the potential to emit more than 250 tons per year of<br />
visibility impairing pollutants. Therefore, <strong>Muskogee</strong> Units 4 & 5 meet the definition of a BARTeligible<br />
source.<br />
1
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART is required for any BART-eligible source that emits any air pollutant which may reasonably<br />
be anticipated to cause or contribute to any impairment of visibility in a Class I Area. EPA has<br />
determined that an individual source will be considered to “contribute to visibility impairment” if<br />
emissions from the source result in a change in visibility, measured as a change in deciviews (∆dv),<br />
that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling previously<br />
conducted by OG&E determined that the maximum predicted visibility impacts from <strong>Muskogee</strong><br />
Units 4 & 5 exceeded the 0.5 ∆-dv threshold at the Upper Buffalo, Caney Creek, and Wichita<br />
Mountains Class I Areas. Therefore, <strong>Muskogee</strong> Units 4 & 5 were determined to be BARTapplicable<br />
sources, subject to the BART determination requirements.<br />
Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51<br />
(Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use<br />
the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants<br />
having a total generating capacity in excess of 750 MW. The BART determination process<br />
described in Appendix Y includes the following steps:<br />
Step 1. Identify All Available Retrofit Control Technologies.<br />
Step 2. Eliminate Technically Infeasible Options.<br />
Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.<br />
Step 4. Evaluate Impacts and Document the Results.<br />
Step 5. Evaluate Visibility Impacts.<br />
This report is the BART determination for <strong>Muskogee</strong> Units 4 & 5. Because the <strong>Muskogee</strong><br />
<strong>Generating</strong> <strong>Station</strong> has a total generating capacity in excess of 750 MW, the Appendix Y guidelines<br />
were used to prepare the BART determination. Based on an evaluation of potentially feasible<br />
retrofit control technologies, including an assessment of the costs and visibility improvements<br />
associated therewith, OG&E is proposing the BART control technologies and emission rates listed<br />
in Table ES-1.<br />
Table ES-1<br />
<strong>Muskogee</strong> Units 4 & 5<br />
Proposed BART Permit Limits and Control Technologies<br />
Pollutant Proposed BART Proposed BART Technology<br />
NOx<br />
Emission Limit<br />
0.15 lb/mmBtu<br />
(30-day average)<br />
2<br />
Combustion controls including LNB<br />
and OFA<br />
SO2 Existing Permit Limits Low sulfur subbituminous coal<br />
PM10 filterable Existing Permit Limits NA
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
1.0 INTRODUCTION<br />
On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional<br />
Haze Regulations and Guidelines for <strong>Best</strong> Available Retrofit Technology Determinations” (the<br />
“Regional Haze Rule” 70 FR 39104). EPA issued the Regional Haze Rule under the authority and<br />
requirements of sections 169A and 169B of the Clean Air Act (CAA). Sections 169A and 169B<br />
require EPA to address regional haze visibility impairment in 156 federally-protected parks and<br />
wilderness areas (Class I Areas). As mandated by the CAA, the Regional Haze Rule requires<br />
certain large stationary sources to install the best available retrofit technology (BART) to reduce<br />
emissions of pollutants that may impact visibility in a Class I Area.<br />
The Regional Haze Rule requires certain States, including <strong>Oklahoma</strong>, to develop programs to<br />
assure reasonable progress toward meeting the national goal of preventing any future, and<br />
remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires<br />
states to submit a plan to implement the regional haze requirements (the Regional Haze SIP). The<br />
Regional Haze SIP must provide for a BART analysis of any existing stationary facility that might<br />
cause or contribute to impairment of visibility in a Class I Area. To address the requirements for<br />
BART, <strong>Oklahoma</strong> must:<br />
� Identify all BART-eligible sources within the State.<br />
� Determine whether each BART-eligible source emits any air pollutant which may<br />
reasonably be anticipated to cause or contribute to any impairment of visibility in a<br />
Class I Area. BART-eligible sources which may reasonably be anticipated to cause or<br />
contribute to visibility impairment are classified as BART-applicable sources.<br />
� Require each BART-applicable source to identify, install, operate, and maintain BART<br />
controls.<br />
1.1 OG&E’s <strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
OG&E’s <strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> is located at 5501 Three Forks Road near <strong>Muskogee</strong>,<br />
<strong>Oklahoma</strong>. The station has a total of four (4) generating units designated as <strong>Muskogee</strong> Units 3, 4, 5<br />
and 6. <strong>Muskogee</strong> Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit.<br />
<strong>Muskogee</strong> Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of<br />
<strong>Muskogee</strong> Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit<br />
5 coming on-line in 1978. Construction commenced on <strong>Muskogee</strong> Unit 6 in 1980, and Unit 6<br />
commenced commercial operation in mid-1984. All three coal-fired units at the <strong>Muskogee</strong><br />
<strong>Generating</strong> <strong>Station</strong> are dry bottom tangentially-fired pulverized coal (PC) boilers. The boilers fire<br />
subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for<br />
particulate control.<br />
3
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
1.2 BART Applicability Review<br />
BART-eligible sources include those sources that:<br />
(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant;<br />
(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and<br />
(3) whose operations fall within one or more of the specifically listed source categories in 40<br />
CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr<br />
heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).<br />
<strong>Muskogee</strong> Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BARTeligible<br />
source. <strong>Muskogee</strong> Unit 6 was not in existence prior to August 7, 1977; therefore, Unit 6 is<br />
not a BART-eligible source. <strong>Muskogee</strong> Units 4 & 5 are fossil-fuel fired boilers with heat inputs<br />
greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 (i.e., construction<br />
of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of<br />
existing emissions data, both units have the potential to emit more than 250 tons per year of<br />
visibility impairing pollutants. Therefore, <strong>Muskogee</strong> Units 4 & 5 meet the definition of a BARTeligible<br />
source.<br />
BART is required for any BART-eligible source that emits any air pollutant which may reasonably<br />
be anticipated to cause or contribute to any impairment of visibility in a Class I Area. EPA has<br />
determined that an individual source will be considered to “cause visibility impairment” if<br />
emissions from the source result in a change in visibility, measured as a change in deciviews (∆dv),<br />
that is greater than or equal to 1.0 dv on the visibility in a Class I area. An individual source is<br />
considered to “contribute to visibility impairment” if emissions from the source result in a ∆-dv<br />
change greater than or equal to 0.5 dv in a Class I area. Class I areas nearest the <strong>Muskogee</strong> <strong>Station</strong><br />
include:<br />
Distance from<br />
Class I Area Name <strong>Muskogee</strong> <strong>Station</strong> (km)<br />
• Upper Buffalo Wilderness Area (Arkansas) 165<br />
• Caney Creek Wilderness Area (Arkansas) 181<br />
• Hercules-Glades Wilderness Area (Missouri) 231<br />
• Wichita Mountains National Wildlife Refuge (<strong>Oklahoma</strong>) 325<br />
Visibility impact modeling was conducted by OG&E to determine the baseline predicted maximum<br />
98 th percentile ∆-dv visibility impact from <strong>Muskogee</strong> Units 4 & 5. The maximum predicted<br />
visibility impact associated with the <strong>Muskogee</strong> <strong>Station</strong> exceeded the 0.5 ∆-dv threshold at the<br />
Upper Buffalo, Caney Creek, and Wichita Mountains Class I Areas. Therefore, the facility was<br />
determined to be a BART-applicable source subject to the BART determination requirements.<br />
4
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
1.3 BART Requirements<br />
A determination of BART must be based on an analysis of the best system of continuous emission<br />
control technology available and associated emission reductions achievable. The BART analysis<br />
must take into consideration: (1) the technology available; (2) the costs of compliance; (3) the<br />
energy and non-air-quality environmental impacts of compliance; (4) any pollution control<br />
equipment in use at the source; (5) the remaining useful life of the source; and (6) the degree of<br />
improvement in visibility which may reasonably be anticipated to result from the use of such<br />
technology.<br />
Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51<br />
(Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use<br />
the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants<br />
having a total generating capacity in excess of 750 MW, but are not required to use the guidelines<br />
when making BART determinations for other types of sources. Because the <strong>Muskogee</strong> <strong>Generating</strong><br />
<strong>Station</strong> has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used<br />
to prepare the BART determination.<br />
The Appendix Y guidelines for BART determinations identify the following five steps in a case-bycase<br />
BART analysis:<br />
Step 1. Identify All Available Retrofit Control Technologies.<br />
Step 2. Eliminate Technically Infeasible Options.<br />
Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.<br />
Step 4. Evaluate Impacts and Document the Results.<br />
Step 5. Evaluate Visibility Impacts.<br />
A more detailed description of each step is provided below.<br />
Step 1. Identify all available retrofit control technologies.<br />
Available retrofit control options are those air pollution control technologies with a practical<br />
potential for application to the emissions unit and the regulated pollutant under evaluation (70<br />
FR 39164 col. 1). Step 1 of the BART determination requires applicants to identify potentially<br />
applicable retrofit control technologies that represent the full range of demonstrated<br />
alternatives. Potentially applicable retrofit control alternatives can include pollution prevention<br />
strategies, the use of add-on controls, or a combination of control strategies. Control<br />
technologies required under the new source review (NSR) program as best available control<br />
technology (BACT) or lowest achievable emission rate (LAER) are available for BART<br />
purposes and must be included as potential control alternatives. However, EPA does not<br />
5
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
consider BART as a requirement to redesign the source when considering available control<br />
alternatives.<br />
In an effort to identify all potentially applicable retrofit technologies appropriate for use at each<br />
station, information sources consulted included, but were not necessarily limited to, the<br />
following:<br />
� EPA's RACT/BACT/LAER Clearinghouse (RBLC) Database;<br />
� New & Emerging Environmental Technologies (NEET) Database;<br />
� EPA’s New Source Review bulletin board;<br />
� Information from control technology vendors and engineering/environmental consultants;<br />
� Federal and State new source review permits and BACT determinations for coal-fired<br />
power plants;<br />
� Recently submitted Federal and State new source review permit applications submitted for<br />
coal-fired generating projects; and<br />
� Technical journals, reports, newsletters and air pollution control seminars.<br />
Step 2. Eliminate Technically Infeasible Options.<br />
In step 2 of the BART determination, the technical feasibility of each potential retrofit<br />
technology is evaluated. Control technologies are considered technically feasible if either (1)<br />
they have been installed and operated successfully for the type of source under review under<br />
similar conditions, or (2) the technology could be applied to the source under review. A<br />
demonstration of technical infeasibility must be based on physical, chemical and engineering<br />
principles, and must show that technical difficulties would preclude the successful use of the<br />
control option on the emission unit under consideration. The economics of an option are not<br />
considered in the determination of technical feasibility/infeasibility. Options that are<br />
technically infeasible for the intended application are eliminated from further review.<br />
Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.<br />
Step 3 of the BART determination involves evaluating the control effectiveness of all the<br />
technically feasible control alternatives identified in Step 2 for the pollutant and emissions<br />
under review. Control effectiveness is generally expressed as the rate at which a pollutant is<br />
emitted after the control system has been installed. The most effective control option is the<br />
system that achieves the lowest emissions level.<br />
Step 4. Evaluate Impacts and Document the Results.<br />
Step 4 of the BART determination involves an evaluation of potential impacts associated with<br />
the technically feasible retrofit technologies. The following evaluations should be conducted<br />
for each technically feasible technology:<br />
6
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
(1) costs of compliance;<br />
(2) energy impacts; and<br />
(3) non-air quality environmental impacts.<br />
Costs of Compliance<br />
The economic analysis performed as part of the BART determination examines the costeffectiveness<br />
of each control technology, on a dollar per ton of pollutant removed basis.<br />
Annual emissions using a particular control device are subtracted from baseline emissions<br />
to calculate tons of pollutant controlled per year. Annual costs are calculated by adding<br />
annual operation and maintenance costs to the annualized capital cost of an option. Cost<br />
effectiveness ($/ton) of an option is simply the annual cost ($/yr) divided by the annual<br />
pollution controlled (ton/yr).<br />
In addition to the cost effectiveness relative to the base case, the incremental costeffectiveness<br />
to go from one level of control to the next more stringent level of control may<br />
also be calculated to evaluate the cost effectiveness of the more stringent control.<br />
Energy Impact Analysis<br />
The energy requirements of a control technology should be examined to determine whether<br />
the use of that technology results in any significant or unusual energy penalties or benefits.<br />
Two forms of energy impacts associated with a control option can normally be quantified.<br />
First, increases in energy consumption resulting from increased heat rate may be shown as<br />
total Btu’s or fuel consumed per year or as Btu’s per ton of pollutant controlled. Second,<br />
the installation of a particular control option may reduce the output and/or reliability of<br />
equipment. This reduction would result in decreased electricity available to the power grid<br />
and/or increased fuel consumption due to use of less efficient electrical and steam<br />
generation methods.<br />
Non-Air Quality Environmental Impact Analysis<br />
The primary purpose of the environmental impact analysis is to assess collateral<br />
environmental impacts due to control of the regulated pollutant in question. Environmental<br />
impacts may include solid or hazardous waste generation, discharges of polluted water<br />
from a control device, increased water consumption, and land use impacts from waste<br />
disposal.<br />
7
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Impact analyses conducted in step 4 should take into consideration the remaining useful life of<br />
the source. For example, the remaining useful life of the source may affect the cost analysis<br />
(specifically, the annualized costs of retrofit controls).<br />
Step 5. Evaluate Visibility Impacts.<br />
Step 5 of the BART determination addresses the degree of improvement in visibility that may<br />
reasonably be anticipated to result from the use of a particular control technology. CALPUFF<br />
modeling, or other appropriate dispersion modeling, should be used to determine the visibility<br />
improvement expected from the potential BART control technology applied to the source.<br />
Modeling should be conducted for SO2, NOx, and direct PM emissions (PM2.5 and/or PM10).<br />
Although visibility improvement must be weighted among the five factors in a BART<br />
determination (along with the costs of compliance, energy and non-air-quality environmental<br />
impacts, existing pollution control technologies in use at the source, and the remaining life of<br />
the source) only potential retrofit control technologies meeting the other four factors were<br />
evaluated for visibility impacts. For example, potential retrofit technologies that are not<br />
technically feasible or cost effective will not be evaluated for visibility impacts. The final<br />
regulation also states that sources that elect to apply the most stringent controls available need<br />
not conduct an air quality modeling analysis for the purpose of determining its visibility<br />
impacts (see, 70 FR 39170 col. 1).<br />
BART control technologies and corresponding emission rates are established based on<br />
information developed from the 5-step BART determination process described above.<br />
2.0 MUSKOGEE UNITS 4 & 5 BART DETERMINATION METHODOLOGY<br />
The BART determination process described in Appendix Y of 40 CFR Part 51 (summarized above)<br />
was used to identify BART controls for <strong>Muskogee</strong> Units 4 & 5. The methodology was used to<br />
evaluate BART control technologies for NOx, SO2, and PM10. Existing operating parameters and<br />
baseline emissions for <strong>Muskogee</strong> Units 4 & 5 are summarized in Table 2-1. The operating<br />
parameters and emissions summarized in Table 2-1 form the basis for the <strong>Muskogee</strong> Units 4 & 5<br />
BART determination.<br />
Baseline emissions from <strong>Muskogee</strong> Units 4 & 5 were developed based on an evaluation of actual<br />
emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance<br />
with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling<br />
analysis to determine visibility impairment impacts should reflect steady-state operating conditions<br />
8
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the<br />
highest 24-hour block emissions reported during the baseline period. Baseline emission rates<br />
(lb/mmBtu) were calculated by dividing the maximum hourly mass emission rate by the full load<br />
heat input to the boiler.<br />
Table 2-1<br />
Plant Operating Parameters for BART Evaluation<br />
Parameter <strong>Muskogee</strong> Unit 4 <strong>Muskogee</strong> Unit 5<br />
Plant Configuration Pulverized Coal-Fired Boiler Pulverized Coal-Fired Boiler<br />
Firing Configuration tangentially-fired tangentially-fired<br />
Plant Output 572 MW (gross) 572 MW (gross)<br />
Maximum Input to Boiler 5,480 mmBtu/hr 5,480 mmBtu/hr<br />
Primary Fuel subbituminous coal subbituminous coal<br />
Existing NOx Controls combustion controls combustion controls<br />
Existing SO2 Controls low-sulfur coal low-sulfur coal<br />
Existing PM10 Controls<br />
Baseline Emissions<br />
electrostatic precipitator electrostatic precipitator<br />
Pollutant<br />
Baseline Actual Emissions Baseline Actual Emissions<br />
lb/hr lb/mmBtu lb/hr lb/mmBtu<br />
NOx 2,710 0.495 2,863 0.522<br />
SO2 4,384 0.800 4,657 0.850<br />
PM10 101 0.018 134 0.024<br />
2.1 Presumptive BART Emission Rates<br />
In the final Regional Haze Rule EPA established presumptive BART emission limits for SO2 and<br />
NOx for certain electric generating units (EGUs) based on fuel type, unit size, cost effectiveness,<br />
and the presence or absence of pre-existing controls. 1 The presumptive limits apply to EGUs at<br />
power plants with a total generating capacity in excess of 750 MW. For these sources, EPA<br />
established presumptive emission limits for coal-fired EGUs greater than 200 MW in size. The<br />
presumptive levels are intended to reflect highly cost-effective technologies as well as provide<br />
enough flexibility to states to consider source specific characteristics when evaluating BART.<br />
The BART SO2 presumptive emission limit for coal-fired EGUs greater than 200 MW in size<br />
without existing SO2 control is either 95% SO2 removal, or an emission rate of 0.15 lb/mmBtu,<br />
unless a state determines that an alternative control level is justified based on a careful<br />
consideration of the statutory factors. For NOx, EPA established a set of BART presumptive<br />
1 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131.<br />
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<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal<br />
type. The BART NOx presumptive emission limit applicable to <strong>Muskogee</strong> Units 4 & 5<br />
(tangentially-fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.<br />
States, as a general matter, should presume that owners and operators of greater than 750 MW<br />
power plants can cost effectively meet the presumptive levels. However, the BART process allows<br />
consideration of site-specific retrofit costs and site-specific visibility impacts. States have the<br />
ability to consider the specific characteristics of the source at issue and to find that the presumptive<br />
limits would not be appropriate for that source. Emission control technologies and emission limits<br />
that differ from the presumptive levels can be established if it can be demonstrated that an<br />
alternative emission rate is justified based on a consideration of the five statutory factors, including<br />
the costs of compliance and the degree of improvement in visibility which may reasonably be<br />
anticipated to result from the use of such technology.<br />
3.0 BART DETERMINATION FOR NITROGEN OXIDES (NOx)<br />
The formation of NOx is determined by the interaction of chemical and physical processes<br />
occurring primarily within the flame zone of the boiler. There are two principal forms of NOx<br />
designated as “thermal” NOx and “fuel” NOx. Thermal NOx formation is the result of oxidation of<br />
atmospheric nitrogen contained in the inlet gas in the high-temperature, post-flame region of the<br />
combustion zone. Fuel NOx is formed by the oxidation of nitrogen in the fuel. NOx formation can<br />
be controlled by adjusting the combustion process and/or installing post-combustion controls.<br />
The major factors influencing thermal NOx formation are temperature, the concentration of<br />
combustion gases (primarily nitrogen and oxygen) in the inlet air, and residence time within the<br />
combustion zone. Advanced burner designs can regulate the distribution and mixing of the fuel and<br />
air to reduce flame temperatures and residence times at peak temperatures to reduce NOx formation.<br />
Coal properties have a major influence on the formation of fuel NOx. Nitrogen compounds are<br />
released from the coal during coal combustion. Fuel NOx conversion is generally dependent on the<br />
fuel rank. In general, a higher percentage of fuel-NOx is converted to NOx as the rank of fuel<br />
decreases. In other words, units firing lower rank coals (e.g., subbituminous coal or lignite) will<br />
have higher uncontrolled NOx emissions.<br />
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3.1 Step 1: Identify Potentially Feasible NOx Control Options<br />
Potentially available control options were identified based on a comprehensive review of available<br />
information. NOx control technologies with potential application to <strong>Muskogee</strong> Units 4 & 5 are<br />
listed in Table 3-1.<br />
Table 3-1<br />
List of Potential NOx Control Options<br />
Combustion Controls<br />
Control Technology<br />
Low NOx Burners & Overfire Air (LNB/OFA)<br />
Flue <strong>Gas</strong> Recirculation (FGR)<br />
Post-Combustion Controls<br />
Selective Noncatalytic Reduction (SNCR)<br />
Selective Catalytic Reduction (SCR)<br />
Innovative Control Technologies<br />
Rotating Overfire Air (ROFA)<br />
ROFA + SNCR (Rotamix)<br />
Wet NOx Scrubbing<br />
3.2 Step 2: Technical Feasibility of Potential Control Options<br />
NOx control technologies can be divided into two general categories: combustion controls and postcombustion<br />
controls. Combustion controls reduce the amount of NOx that is generated in the<br />
boiler. Post-combustion controls remove NOx from the boiler exhaust gas. The technical feasibility<br />
of each potentially applicable NOx control technology is evaluated below.<br />
3.2.1 Combustion Controls<br />
The rate of NOx formation in the combustion zone is a function of free oxygen, peak flame<br />
temperature and residence time. Combustion techniques designed to minimize the formation of<br />
NOx will minimize one or more of these variables. Combustion control options that may be<br />
applicable to the OG&E boilers are described below.<br />
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3.2.1.1 Low NOx Burners and Overfire Air<br />
Low NOx burners (LNB) 2 limit NOx formation by controlling both the stoichiometric and<br />
temperature profiles of the combustion flame in each burner flame envelope. This control<br />
is achieved with design features that regulate the aerodynamic distribution and mixing of<br />
the fuel and air, yielding reduced oxygen (O2) in the primary combustion zone, reduced<br />
flame temperature and reduced residence time at peak combustion temperatures. The<br />
combination of these techniques produces lower NOx emissions during the combustion<br />
process.<br />
In the OFA process, the injection of air into the firing chamber is staged into two zones, in<br />
which approximately 5% to 20% of the total combustion air is diverted from the burners<br />
and injected through ports located above the top burner level. Staging of the combustion<br />
air reduces NOx formation by two mechanisms. First, staged combustion results in a cooler<br />
flame, and second the staged combustion results in less oxygen reacting with fuel<br />
molecules. The degree of staging is limited by operational problems since the staged<br />
combustion results in incomplete combustion conditions and a longer flame.<br />
LNB/OFA emission control systems have been installed as retrofit control technologies on<br />
existing coal-fired boilers. Coal-fired boilers retrofit with LNB/OFA combustion<br />
technologies would be expected to operate with actual average NOx emission levels in the<br />
range of 85 to 180 ppmvd @ 3% O2 (approximately 0.12 to 0.25 lb/mmBtu) depending on<br />
the fuel, burner configuration, and averaging time. Based on a review of emissions data<br />
available from the EPA’s electronic emissions data reporting website, subbituminous-fired<br />
boilers retrofit with LNB/OFA have achieved actual average NOx emission rates in the<br />
range of 0.12 to 0.18 lb/mmBtu. 3<br />
Although combustion control systems on coal-fired boilers have demonstrated the ability to<br />
achieve average NOx emission rates below 0.15 lb/mmBtu, combustion control systems<br />
may not be as effective under all boiler operating conditions, especially during load<br />
changes and low load operations. Controlling the stoichiometric and temperature profiles<br />
of the combustion flame, and maintaining the air/fuel mixing needed for NOx control,<br />
becomes more difficult under these operating scenarios. Therefore, it is likely that short-<br />
2 The term “LNB” is used generically in this BART analysis, and refers to advanced low-NOx burners<br />
available from leading boiler/burner manufacturers. The term does not represent any vendor-specific trade<br />
name. As used in this BART analysis, the term “LNB” refers to the available advanced low-NOx burner<br />
technologies.<br />
3 Emission data are available from EPA’s Electronic Data Reporting website:<br />
www.epa.gov/airmarkets/emissions/raw/index.html.<br />
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term boiler NOx emissions will be higher under certain operating conditions. Furthermore,<br />
the mechanisms used to reduce NOx formation (e.g., cooler flame and reduced O2<br />
availability) also tend to increase the formation and emission of CO and VOCs.<br />
Based on information available from burner control vendors, emissions achieved in practice<br />
at existing similar sources, and engineering judgment, it is expected that combustion<br />
controls, including LNB and OFA, on the tangentially-fired <strong>Muskogee</strong> boilers can be<br />
designed to meet the presumptive NOx BART emission rate of 0.15 lb/mmBtu<br />
(approximately 110 ppmvd @ 3% O2). An average emission rate of 0.15 lb/mmBtu should<br />
be achievable on a 30-day rolling average basis under all normal boiler operating<br />
conditions and while maintaining acceptable CO and VOC emission rates.<br />
3.2.1.2 Flue <strong>Gas</strong> Recirculation<br />
Flue gas recirculation (FGR) controls NOx by recycling a portion of the flue gas back into<br />
the primary combustion zone. The recycled air lowers NOx emissions by two mechanisms:<br />
(1) the recycled gas, consisting of products that are inert during combustion, lowers the<br />
combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the<br />
primary flame zone. The amount of recirculation is based on flame stability.<br />
FGR control systems have been used as a retrofit NOx control strategy on natural gas-fired<br />
boilers, but have not generally been considered as a retrofit control technology on coalfired<br />
units. Natural gas-fired units tend to have lower O2 concentrations in the flue gas and<br />
low particulate loading. In a coal-fired application, the FGR system would have to handle<br />
hot particulate-laden flue gas with a relatively high O2 concentration. Although FGR has<br />
been used on coal-fired boilers for flue gas temperature control, it would not have<br />
application on a coal-fired boiler for NOx control. Because of the flue gas characteristics<br />
(e.g., particulate loading and O2 concentration), FGR would not operate effectively as a<br />
NOx control system on a coal-fired boiler. Therefore, FGR is not considered an applicable<br />
retrofit NOx control option for <strong>Muskogee</strong> Units 4 & 5, and will not be considered further in<br />
the BART determination.<br />
3.2.2 Post-Combustion Controls<br />
Post-combustion NOx control systems with potential application to <strong>Muskogee</strong> Units 4 & 5 are<br />
discussed below.<br />
3.2.2.1 Selective Non-Catalytic Reduction<br />
Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH3)<br />
or urea (CO(NH2)2) at high flue gas temperatures (approximately 1600ºF - 1900ºF). The<br />
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ammonia or urea reacts with NOx in the flue gas to produce N2 and water as shown in the<br />
equations below.<br />
(NH2) 2CO + 2NO + ½O2 → 2H2O + CO2 + 2N2<br />
2NH3 + 2NO + ½O2 → 2N2 + 3H2O<br />
Flue gas temperature at the point of reagent injection can greatly affect NOx removal<br />
efficiencies and the quantity of NH3 or urea that will pass through the SNCR unreacted<br />
(referred to as NH3 slip). In general, SNCR reactions are effective in the range of 1,700 o F.<br />
At temperatures below the desired operating range, the NOx reduction reactions diminish<br />
and unreacted NH3 emissions increase. Above the desired temperature range, NH3 is<br />
oxidized to NOx resulting in low NOx reduction efficiencies.<br />
Mixing of the reactant and flue gas within the reaction zone is also an important factor to<br />
SNCR performance. In large boilers, the physical distance over which reagent must be<br />
dispersed increases, and the surface area/volume ratio of the convective pass decreases.<br />
Both of these factors make it difficult to achieve good mixing of reagent and flue gas,<br />
delivery of reagent in the proper temperature window, and sufficient residence time of the<br />
reagent and flue gas in that temperature window. In addition to temperature and mixing,<br />
several other factors influence the performance of an SNCR system, including residence<br />
time, reagent-to-NOx ratio, and fuel sulfur content.<br />
SNCR control systems have been installed as retrofit NOx control systems on small and<br />
medium sized (i.e., less than approximately 300 MW) coal-fired boilers. However, because<br />
of design and operating limitations, SNCR has not been used on large subbituminous coalfired<br />
boilers. Large subbituminous coal-fired boilers, including <strong>Muskogee</strong> Units 4 & 5,<br />
would not be able to achieve adequate reagent mixing and residence time within the<br />
required flue gas temperature window to achieve effective NOx reduction.<br />
The physical size of the <strong>Muskogee</strong> boilers makes it technically infeasible to locate and<br />
install ammonia injection points capable of achieving adequate NH3/NOx contact within<br />
the required temperature zone. Higher ammonia injection rates would be needed to achieve<br />
adequate NH3/NOx contact. Higher ammonia injection rates would result in relatively high<br />
levels of unreacted ammonia in the flue gas (ammonia slip), which could lead to plugging<br />
of downstream equipment.<br />
Another design factor limiting the applicability of SNCR control systems on large<br />
subbituminous coal-fired boilers is related to the reflective nature of subbituminous ash.<br />
Subbituminous coals typically contain high levels of calcium oxide and magnesium oxide<br />
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that can result in reflective ash deposits on the waterwall surfaces. Because most heat<br />
transfer in the furnace is radiant, reflective ash can result in less heat removal from the<br />
furnace and higher exit gas temperatures. If ammonia is injected above the appropriate<br />
temperature window, it can actually lead to additional NOx formation.<br />
SNCR control systems have not been designed or installed on large subbituminous coalfired<br />
boilers, and, as described above, there are several currently unresolved technical<br />
difficulties with applying SNCR to large subbituminous coal-fired boilers (including the<br />
physical size of the boiler, inadequate NH3 mixing, and ash characteristics). Even<br />
assuming that SNCR could be installed on <strong>Muskogee</strong> Units 4 & 5, NOx control<br />
effectiveness would be marginal, and, depending on boiler exit temperatures, could actually<br />
result in additional NOx formation. Because SNCR has not been designed for, or<br />
demonstrated on, a large subbituminous coal-fired boiler, it was determined that the control<br />
technology is not applicable to <strong>Muskogee</strong> Units 4 & 5, and SNCR will not be evaluated<br />
further in the BART determination.<br />
3.2.2.2 Selective Catalytic Reduction<br />
Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler flue gas in the<br />
presence of a catalyst to reduce NOx to N2 and water. Anhydrous ammonia injection<br />
systems may be used, or ammonia may be generated on-site from a urea feedstock. The<br />
overall SCR reactions are:<br />
4NH3 + 4NO + O2 → 4N2 + 6H2O<br />
8NH3 + 4NO2 + 2O2 → 6N2 + 12H2O<br />
The performance of an SCR system is influenced by several factors including flue gas<br />
temperature, SCR inlet NOx level, the catalyst surface area, volume and age of the catalyst,<br />
and the amount of ammonia slip that is acceptable.<br />
The optimal temperature range depends on the type of catalyst used, but is typically<br />
between 560 o F and 750 o F to maximize NOx reduction efficiency and minimize ammonium<br />
sulfate formation. This temperature range typically occurs between the economizer and air<br />
heater in a large utility boiler. Below this range, ammonium sulfate is formed resulting in<br />
catalyst deactivation. Above the optimum temperature, the catalyst will sinter and thus<br />
deactivate rapidly. Another factor affecting SCR performance is the condition of the<br />
catalyst material. As the catalyst degrades over time or is damaged, NOx removal<br />
decreases.<br />
15
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SCR has been installed as a retrofit control technology on existing coal-fired boilers,<br />
including boilers firing subbituminous coal. SCR control systems on subbituminous coalfired<br />
boilers have achieved annual average NOx emission rates in the range of 0.04 to<br />
approximately 0.10 lb/mmBtu. 4 Several design and operating variables will influence the<br />
performance of the SCR system, including the volume, age and surface area of the catalyst<br />
(e.g., catalyst layers), uncontrolled NOx emission rate, flue gas characteristics (including<br />
temperature, sulfur content, and particulate loading), and catalyst activity. 5 Catalyst that<br />
has been in service for a period of time will have decreased performance because of normal<br />
deactivation and deterioration. Catalyst that is no longer effective due to plugging, blinding<br />
or deactivation must be replaced.<br />
Based on emission rates achieved in practice at existing subbituminous coal-fired units, and<br />
taking into consideration long-term operation of an SCR control system (including catalyst<br />
plugging and deactivation) it is anticipated that SCR could achieve a controlled NOx<br />
emission rate of 0.07 lb/mmBtu (30-day rolling average) on <strong>Muskogee</strong> Units 4 & 5. An<br />
emission rate of 0.07 lb/mmBtu is equivalent to an average NOx concentration in the flue<br />
gas of approximately 50 ppmvd @ 3% O2. Reducing NOx emissions below 50 ppmvd @<br />
3% O2 would tend to increase collateral environmental impacts associated with the SCR,<br />
including increased ammonia slip, increased SO2 to SO3 oxidation, and more frequent<br />
catalyst changes.<br />
3.2.3 Innovative NOx Control Technologies<br />
A number of innovative NOx control systems, including multi-pollutant control systems, were<br />
identified as potential retrofit control technologies during the review of available documents.<br />
Innovative NOx control technologies with potential application to the BART study include<br />
boosted over-fire air (e.g., MobotecUSA’s ROFA ® system), advanced SNCR control systems<br />
(e.g., MobotecUSA’s Rotamix ® system), Enviroscrub’s multi-pollutant Pahlman process, and<br />
wet NOx scrubbing systems.<br />
4 Emission data are available from EPA’s Electronic Data Reporting website:<br />
www.epa.gov/airmarkets/emissions/raw/index.html.<br />
5 See, e.g., Sanyal, A., Pircon, J.J., “What and How Should You Know About U.S. Coal to Predict and<br />
Improve SCR Performance”, proceedings of the USEPA, DOE, EPRI, Combined Power Plant Air Pollution<br />
Control Mega Symposium, Chicago, IL, August 2001. See also, Gutberlet, H., Schluter, A., Licata, A.,<br />
“Deactivation of SCR Catalyst”, proceedings of the DOE’s 2000 Conference on Selective Catalytic and<br />
Selective Non-Catalytic Reduction for NOx Control, Pittsburgh, PA, 2000.<br />
16
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May 28, 2008<br />
3.2.3.1 Rotating Opposed Fired Air and Rotomix<br />
Rotating opposed fired air (ROFA) is a boosted overfire air system that includes a patented<br />
rotation process which includes asymmetrically placed air nozzles. 6 Like other OFA<br />
systems, ROFA stages the primary combustion zone to burn overall rich, with excess air<br />
added higher in the furnace to burn out products of incomplete combustion. The ROFA<br />
nozzles are designed to increase turbulence within the furnace. Increased turbulence should<br />
prevent the formation of stratified laminar flow, enable the furnace volume to be used more<br />
effectively for the combustion process, and reduce the maximum temperatures of the<br />
combustion zone.<br />
The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan,<br />
and control system instrumentation. A ROFA system was installed on an existing 80-MW<br />
(gross) bituminous-fired utility boiler in the summer of 2002. Test results showed that the<br />
ROFA system reduced NOx emissions from baseline levels between 0.58 and 0.62<br />
lb/mmBtu to approximately 0.22 lb/mmBtu at full load. At lower loads (approximately 40<br />
MW), the ROFA system reduced NOx emissions from 0.59 lb/mmBtu to 0.295 lb/mmBtu. 7<br />
The turbulent air injection and mixing provided by ROFA allows for the effective mixing<br />
of chemical reagents with the combustion products in the furnace. MobotecUSA’s<br />
Rotamix ® system combines the rotating opposed overfire air system with urea injection into<br />
the flue gas to reduce NOx emissions. The turbulent mixing created by the ROFA system is<br />
designed to improve distribution of the ammonia/urea reagent and may reduce the<br />
ammonia/urea injection required by the SNCR control system. A Rotamix control system<br />
was installed on the same 80-MW unit in the spring of 2004.<br />
ROFA and Rotamix ® systems have been demonstrated on smaller coal-fired boilers but<br />
have not been demonstrated in practice on boilers similar in size to <strong>Muskogee</strong> Units 4 & 5.<br />
As discussed in subsection 3.2.1.1, overfire air control systems are a technically feasible<br />
retrofit control technology, and, based on engineering judgment, the ROFA design could<br />
also be applied to <strong>Muskogee</strong> Units 4 & 5. However, there is no technical basis to conclude<br />
that the ROFA design would provide additional NOx reduction beyond that achieved with<br />
other OFA designs. Therefore, ROFA control systems will not be evaluated as a specific<br />
6 See, MobotecUSA at www.mobotecusa.com.<br />
7 Coombs, K.A., Crilley, J.S., Shilling, M., Higgins, B., “SCR Levels of NOx Reduction with ROFA and<br />
Rotamix (SNCR) at Dynegy’s Vermilion Power <strong>Station</strong>,” Presented at 2004 Stack Emissions Symposium,<br />
Clearwater Beach, Florida, July 28-30, 2004.<br />
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May 28, 2008<br />
control system, but will be included in the overall evaluation of combustion controls (e.g.,<br />
LNB/OFA).<br />
The Rotamix system is a SNCR control system (i.e., ammonia injection system) coupled<br />
with the ROFA rotating injection nozzle design. The technical limitations discussed in<br />
section 3.2.2.1, including the physical size of the boiler, inadequate NH3/NOx contact, fly<br />
ash characteristics, and flue gas temperatures, would apply equally to the Rotamix control<br />
system. There is no technical basis to conclude that the Rotamix urea injection design<br />
addresses these unresolved technical difficulties. Therefore, like other SNCR control<br />
systems, the Rotamix system is determined not to be an applicable NOx control system for<br />
<strong>Muskogee</strong> Units 4 & 5, and will not be evaluated further in the BART determination.<br />
3.2.3.2 Pahlman Multi-Pollutant Control Process<br />
The Pahlman Process is a patented dry-mode multi-pollutant control system. The<br />
process uses a sorbent composed of oxides of manganese (the Pahlmanite sorbent) to<br />
remove NOx and SO2 from the flue gas. 8 Manganese compounds are soluble in water in the<br />
+2 valence state but not in the +4 state. This property is used in the Pahlman sorbent<br />
capture and regeneration procedure, in that Pahlmanite sorbent is reduced from the<br />
insoluble +4 state to the +2 state during the formation of manganese nitrates and sulfates.<br />
These species are water-soluble, allowing the sulfate, nitrate and Mn +2 ions to be<br />
dissociated and the Mn +2 to be oxidized again to Mn +4 and regenerated. In general, the<br />
liquid metal oxide Pahlmanite sorbent is injected as the flue gas enters a spray dryer. The<br />
sorbent dries as it passes through the spray dryer and is collected downstream at the fabric<br />
filter baghouse. NOx and SO2 will react with the sorbent to form manganese sulfates and<br />
nitrates as the flue gas passes through the filter cake.<br />
The filter cake is pulsed off-line into a wet regeneration process. The regenerated sorbent<br />
is stored in liquid form to be employed again via the spray dryer. The captured nitrogen<br />
and sulfur can be purified and may be converted into granular fertilizer by-products.<br />
To date, bench- and pilot-scale testing have been conducted to evaluate the technology on<br />
utility-sized boilers. 9 The New & Emerging Environmental Technologies (NEET)<br />
Database identifies the development status of the Pahlman Process as full-scale<br />
8 See, Enviroscrub Technologies Corporation, www.enviroscrub.com.<br />
9 See, Wocken, C.A., “Evaluation of Enviroscrub’s Multipollutant Pahlman Process for Mercury Removal<br />
at a Facility Burning Subbituminous Coal,” Energy & Environmental Research Center, University of North<br />
Dakota, April 2004.<br />
18
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May 28, 2008<br />
development and testing. 10 The process is an emerging multi-pollutant control, and there is<br />
limited information available to evaluate it’s technically feasibility and long-term<br />
effectiveness on a large subbituminous-fired boiler. It is likely that OG&E would be<br />
required to conduct extensive design engineering and testing to evaluate the technical<br />
feasibility and long-term effectiveness of the control system on <strong>Muskogee</strong> Units 4 & 5.<br />
BART does not require applicants to experience extended time delays or resource penalties<br />
to allow research to be conducted on an emerging control technique. Therefore, at this time<br />
the Pahlman Process is not considered an available NOx control system for <strong>Muskogee</strong> Units<br />
4 & 5, and will not be further evaluated in the BART determination.<br />
3.2.3.3 Wet NOx Scrubbing Systems<br />
Wet scrubbing systems have been used to remove NOx emissions from fluid catalytic<br />
cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is<br />
Balco Technologies’ LoTOx system. The LoTOx system is a patented process, wherein<br />
ozone is injected into the flue gas stream to oxidize NO and NO2 to N2O5. This highly<br />
oxidized species of NOx is very soluble and rapidly reacts with water to form nitric acid.<br />
The conversion of NOx to nitric acid occurs as the N2O5 contacts liquid sprays in the<br />
scrubber.<br />
Wet scrubbing systems have been installed at chemical processing plants and smaller coalfired<br />
boilers. The NEET Database classifies wet scrubbing systems as commercially<br />
established for petroleum refining and oil/natural gas production. However the technology<br />
has not been demonstrated on large coal-fired boilers and it is likely that OG&E would<br />
incur substantial engineering and testing to evaluate the scale-up potential and long-term<br />
effectiveness of the system. Therefore, at this time wet NOx scrubbing is not considered to<br />
be an applicable or commercially available retrofit control system for <strong>Muskogee</strong> Units 4 &<br />
5, and will not be further evaluated in this BART determination.<br />
The results of Step 2 of the NOx BART Analysis (technical feasibility analysis of potential NOx<br />
control technologies) are summarized in Table 3-2.<br />
10 NEET is an on-line repository for information about emerging technologies that reduce emissions from<br />
stationary, mobile, and indoor sources. NEET was developed and is operated by RTI International with<br />
support from the EPA Office of Air Quality Planning and Standards.<br />
19
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May 28, 2008<br />
Control Technology<br />
Table 3-2<br />
Technical Feasibility of Potential NOx Control Technologies<br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
Controlled NOx<br />
Emission Rate<br />
In Service on<br />
Existing PC<br />
Boilers<br />
(lb/mmBtu) Yes No<br />
20<br />
In Service on<br />
Other<br />
Combustion<br />
Sources?<br />
Low NOx Burners and<br />
Overfire Air<br />
SNCR NA X Yes<br />
SNCR has<br />
been applied<br />
to several<br />
smaller coalfired<br />
boilers.<br />
Technically Feasible on<br />
<strong>Muskogee</strong> Units 4 & 5?<br />
0.15 lb/mmBtu X Yes Technically feasible.<br />
Not a technically feasible retrofit<br />
technology for <strong>Muskogee</strong> Units 4<br />
& 5. SNCR has been used as a<br />
retrofit technology on small and<br />
medium sized (
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Table 3-2 continued<br />
Control Technology<br />
Controlled NOx<br />
Emission Rate<br />
(lb/mmBtu)<br />
In Service on<br />
Existing PC<br />
Boilers<br />
21<br />
In Service on<br />
Other<br />
Combustion<br />
Sources?<br />
Technically Feasible on<br />
<strong>Muskogee</strong> Units 4 & 5?<br />
Rotamix (SNCR) NA X Yes Rotamix control systems have been<br />
demonstrated on small coal-fired<br />
boilers. However, there are several<br />
currently unresolved technical<br />
difficulties associated with<br />
applying SNCR-type systems on a<br />
large subbituminous coal-fired<br />
boiler. Therefore, Rotamix is not<br />
considered an available retrofit<br />
control technology for <strong>Muskogee</strong><br />
Units 4 & 5.<br />
Pahlman Process NA X No Bench- and pilot-scale testing has<br />
been conducted on coal-fired<br />
boilers, however, there is limited<br />
data available assessing the<br />
technical feasibility of this system<br />
on large coal-fired boilers.<br />
Wet NOx Scrubbing NA X Yes The system has been used on<br />
refinery fluid catalytic cracking<br />
units and small coal-fired boilers,<br />
but has not been used on large<br />
coal-fired boilers. Wet NOx<br />
scrubbing systems are not<br />
commercially available or<br />
technically feasible for <strong>Muskogee</strong><br />
Units 4 & 5.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
3.3 Step 3: Rank the Technically Feasible NOx Control Options by Effectiveness<br />
The technically feasible and commercially available NOx control technologies for <strong>Muskogee</strong> Units<br />
4 & 5 are listed in Table 3-3, in descending order of control efficiency.<br />
Table 3-3<br />
Technically Feasible NOx Control Technologies<br />
<strong>Muskogee</strong> <strong>Station</strong><br />
Control Technology Approximate NOx<br />
Emission Rate*<br />
(lb/mmBtu)<br />
<strong>Muskogee</strong> Unit 4 <strong>Muskogee</strong> Unit 5<br />
22<br />
Approximate NOx<br />
Emission Rate*<br />
(lb/mmBtu)<br />
Selective Catalytic Reduction (SCR) 0.07 0.07<br />
Low-NOx Burners and Overfire Air 0.15 0.15<br />
Baseline 11 0.495 0.522<br />
3.4 Step 4: Evaluate the Technically Feasible NOx Control Technologies<br />
3.4.1 NOx Control Technologies – Economic Evaluation<br />
The most effective NOx retrofit control system, in terms of reduced emissions, that is<br />
considered to be technically feasible for <strong>Muskogee</strong> Units 4 & 5 includes combustion controls<br />
(LNB/OFA) and post-combustion SCR. This combination of controls should be capable of<br />
achieving the lowest controlled NOx emission rate on an on-going long-term basis. The<br />
effectiveness of the SCR system is dependent on several site-specific system variables,<br />
including the size of the SCR, catalyst layers, NH3/ NOx stoichiometric ratio, NH3 slip, and<br />
catalyst deactivation rate. Based on emission rates achieved in practice at similar sources, and<br />
including a reasonable margin to account for normal system fluctuations, the combination of<br />
combustion controls and SCR should achieve a controlled NOx emission rate of 0.07 lb/mmBtu<br />
(30-day average).<br />
The next most effective NOx retrofit control system that is considered technically feasible for<br />
<strong>Muskogee</strong> Units 4 & 5 includes combustion controls (LNB/OFA). The combination of<br />
11 Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions<br />
reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmBtu) were calculated<br />
by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The<br />
relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts,<br />
and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control<br />
technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation<br />
of the facility’s permitted emission limits, which are averaged over a longer period of time.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
LNB/OFA on <strong>Muskogee</strong> Units 4 & 5 (large tangentially fired boilers firing subbituminous coal)<br />
should be capable of meeting the BART presumptive limit of 0.15 lb/mmBtu.<br />
Economic impacts associated with the SCR control systems were evaluated in accordance with<br />
EPA guidelines (40 CFR Part 51 Appendix Y). In accordance with the guidelines in Part III of<br />
Appendix Y, emission estimates used in the modeling analysis to determine visibility<br />
impairment impacts should reflect steady-state operating conditions during periods of high<br />
capacity utilization. Therefore, projected emission rates (lb/hr) were calculated based on the<br />
expected controlled emission rate (lb/mmBtu) achievable on a 30-day rolling average and heat<br />
input to the boiler at full load. Annual emissions (tpy) were calculated assuming a 90%<br />
capacity factor for each unit.<br />
Cost estimates were compiled from a number of data sources. In general, the cost estimating<br />
methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. 12<br />
Major equipment costs were developed based on equipment costs recently developed for<br />
similar projects, and include the equipment, material, labor, and all other direct costs needed to<br />
retrofit <strong>Muskogee</strong> Units 4 & 5 with the control technology.<br />
Fixed and variable O&M costs were developed for each control system. Fixed O&M costs<br />
include operating labor, maintenance labor, maintenance material, and administrative labor.<br />
Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct<br />
management, water consumption, and auxiliary power requirements. Auxiliary power<br />
requirements reflect the additional power requirements associated with operation of the new<br />
control technology, including operation of any new ID fans as well as the power requirements<br />
for pumps, reagent handling, and by-product handling.<br />
Summarized in Table 3-4 are the expected controlled NOx emission rates, and maximum annual<br />
NOx mass emissions, associated with each technically feasible retrofit technology. Table 3-5<br />
presents the capital costs and annual operating costs associated with building and operating<br />
each control system. Table 3-6 shows the average annual cost effectiveness and incremental<br />
annual cost effectiveness for each NOx control system. A detailed summary of the cost<br />
estimates used in this BART determination is included in Attachment A.<br />
12 U.S. Environmental Protection Agency, EPA Air Pollution Cost Control Manual, 6 th Ed., Publication<br />
Number EPA 452/B-02-001, January 2002.<br />
23
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Control Technology<br />
Table 3-4<br />
Annual NOx Emissions<br />
NOx Emission Rate<br />
(lb/mmBtu)<br />
24<br />
Maximum Annual NOx<br />
Emissions<br />
(tpy) *<br />
Annual Reduction in<br />
Emissions<br />
(tpy from baseline)<br />
Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5<br />
LNB/OFA + SCR 0.07 0.07 1,512 1,512 9,181 9,764<br />
LNB/OFA 0.15 0.15 3,240 3,240 7,453 8,036<br />
Baseline NOx Emissions 0.495 0.522 10,693 11.276 -- --<br />
* Maximum annual emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr<br />
per boiler for 7,884 hours per year (90% capacity factor).<br />
Control Technology<br />
Total Capital<br />
Investment*<br />
($)<br />
Table 3-5<br />
NOx Emission Control System<br />
Cost Summary (per boiler)<br />
Total Capital<br />
Investment<br />
($/kW-gross)<br />
Annual Capital<br />
Recovery Cost<br />
($/year)<br />
Annual<br />
Operating Costs<br />
($/year)<br />
Total Annual<br />
Costs<br />
($/year)<br />
LNB/OFA + SCR $193,077,000 $339 $16,568,000 $14,227,600 $30,795,600<br />
LNB/OFA $14,113,700 $25 $1,211,100 $880,700 $2,091,800<br />
* Capital costs for NOx retrofit control systems will be similar for both Units 4 & 5. Capital costs include the cost of major<br />
components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the<br />
control system. Capital costs for the SCR system include costs associated with installation of LNB/OFA systems.<br />
Control Technology<br />
Table 3-6<br />
NOx Emission Control System<br />
Cost Effectiveness (total for both boilers)<br />
Total Annual<br />
Cost<br />
($/year)<br />
Annual Emission<br />
Reduction<br />
(tpy)<br />
Average Cost<br />
Effectiveness<br />
($/ton)<br />
Incremental Cost<br />
Effectiveness<br />
($/ton)<br />
LNB/OFA + SCR $61,591,200 18,945 $3,251 $16,611<br />
LNB/OFA $4,183,600 15,489 $270 NA<br />
The average annual cost effectiveness of LNB/OFA+SCR on <strong>Muskogee</strong> Units 4 & 5 is<br />
estimated to be approximately $3,251/ton. This cost compares to an average annual cost<br />
effectiveness for LNB/OFA combustion controls of approximately $270/ton. Equipment costs,<br />
retrofit challenges, and annual operating costs all have a significant impact on the annualized<br />
cost of a SCR control system. Significant annual operating costs include the energy cost<br />
associated with the additional pressure drop across the SCR and costs associated with replacing<br />
the SCR catalyst as it degrades over time. Based on projected actual emissions, SCR could
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
reduce overall NOx emissions from <strong>Muskogee</strong> Units 4 & 5 by approximately 3,456 tpy<br />
(compared to advanced combustion controls); however, the incremental cost associated with<br />
this reduction is approximately $57,407,600 per year, or $16,611/ton.<br />
As part of the BART rulemaking, EPA established presumptive NOx emission limits applicable<br />
to EGUs greater than 200 MW at power plants with a generating capacity greater than 750<br />
MW. The presumptive NOx emission limits were based on control strategies that EPA<br />
considered to be generally cost-effective for such units (see, 70 FR 39134). The presumptive<br />
NOx emission limit applicable to <strong>Muskogee</strong> Units 4 & 5 (tangentially-fired units firing<br />
subbituminous coal) is 0.15 lb/mmBtu. For all types of boilers, other than cyclone units, the<br />
presumptive limits were based on the use of combustion control technologies. EPA estimated<br />
that the “costs of such controls in most cases range from just over $100 to $1000 per ton” (see,<br />
70 FR 39135).<br />
The average cost effectiveness of combustion controls (LNB/OFA) on <strong>Muskogee</strong> Units 4 & 5 is<br />
similar to the BART cost-effectiveness developed by EPA for NOx control on large EGU<br />
boilers. Both the average and incremental cost effectiveness of SCR on <strong>Muskogee</strong> Units 4 & 5<br />
are significantly greater than the cost effectiveness of NOx control at other BART-applicable<br />
units. The costs associated with SCR would result in significant economic impacts on the<br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> (approximately $57,407,600 per year additional costs).<br />
Therefore, SCR should not be selected as BART based on lack of cost effectiveness. Although<br />
SCR does not appear to be cost effective, it will be included in the evaluation of the remaining<br />
factors to assure that the BART determination considers all relevant information.<br />
3.4.2 NOx Control Technologies – Environmental Impacts<br />
Combustion modifications designed to decrease NOx formation (lower temperature and less<br />
oxygen availability) also tend to increase the formation and emission of CO and VOCs.<br />
Therefore, the combustion controls must be designed to reduce the formation of NOx while<br />
maintaining CO and VOC formation at an acceptable level. Other than the NOx/CO-VOC<br />
trade-off, there are no environmental issues associated with using combustion controls to<br />
reduce NOx emissions.<br />
Operation of an SCR system has certain collateral environmental consequences. 13 First, in<br />
order to maintain low NOx emissions some excess ammonia will pass through the SCR.<br />
Ammonia slip will increase with lower NOx emission limits, and will also tend to increase as<br />
the catalyst becomes deactivated. Ammonia slip from an SCR designed to achieve a controlled<br />
13 See, Hinton, W.S., Cushing, K.M., Gooch, J.P., “Balance-of-Plant Impacts Associated with SCR/SNCR<br />
Installations”, proceedings of the ICAC Forum, 2002.<br />
25
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
NOx emission rate of 0.07 lb/mmBtu (30-day average) is expected to be in the range of 2-5 ppm<br />
during the initial operation of the SCR. As the catalyst ages and becomes either deactivated or<br />
blinded, ammonia slip can increase; however, the ammonia slip rate is not expected to exceed<br />
7-10 ppm under normal operating conditions.<br />
Second, undesirable reactions can occur in an SCR system, including the oxidation of NH3 and<br />
SO2 and the formation of sulfate salts. A fraction of the SO2 in the flue gas (approximately 1 -<br />
1.5%) will oxidize to SO3 in the presence of the SCR catalyst. SO3 can react with water to form<br />
sulfuric acid mist or with the ammonia slip to form ammonium sulfate ((NH4)2SO4). Sulfuric<br />
acid mist and (NH4)2SO4 are classified as condensable particulates. The formation of<br />
condensible particulates will increase as the size of the SCR increases.<br />
Finally, the storage of ammonia on-site increases the risks associated with an accidental<br />
ammonia release. Depending on the type, concentration, and quantity of ammonia used,<br />
ammonia storage/handling will be subject to regulation as a hazardous substance under<br />
CERCLA, Section 313 of the Emergency Planning and Community Right-to-Know Act,<br />
Section 112(r) of the Clean Air Act, and Section 311(b)(4) of the Clean Water Act. One<br />
strategy that can be used to minimize the risk associated with on-site ammonia handling is to<br />
design the ammonia handling system as a urea-to-ammonia conversion system. Urea<br />
((NH2)2CO) can be delivered to the station as an aqueous solution or as a dry solid, and urea<br />
storage/handling does not create the process safety concerns associated with handling<br />
anhydrous ammonia.<br />
3.4.3 NOx Control Technologies – Energy Impacts<br />
Both NOx control systems require auxiliary power. Auxiliary power requirements associated<br />
with the LNB/OFA control systems are generally insignificant, but may include booster fans for<br />
the overfire air injection ports to increase turbulence within the boiler. Auxiliary power<br />
requirements associated with the SCR include additional fan power to overcome pressure drop<br />
through the SCR. Energy impacts associated with each control technology were included in the<br />
BART economic impact evaluation as an auxiliary power cost.<br />
A summary of the Step 4 economic and environmental impact analysis is provided in Table 3-7.<br />
26
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Control<br />
Technology<br />
Table 3-7<br />
Summary of NOx BART Impact Analysis (total for both boilers)<br />
Annual<br />
Controlled<br />
Emissions*<br />
(tpy)<br />
Annual<br />
Emission<br />
Reductions<br />
(tpy)<br />
Average Cost<br />
Effectiveness<br />
($/ton)<br />
27<br />
Incremental<br />
Cost<br />
Effectiveness<br />
($/ton)<br />
Summary of Environmental<br />
Impacts<br />
LNB/OFA+SCR 3,024 18,945 $3,251 $16,611 Increased SO2 to SO3 oxidation, and<br />
increased condensible PM emissions<br />
including H2SO4. Ammonia<br />
emissions associated with ammonia<br />
slip.<br />
LNB/OFA 6,480 15,489 $270 -- Potential to increase CO/VOC<br />
emissions.<br />
Baseline 21,969 base -- -- --<br />
* Annual controlled emissions and annual emission reductions represent total emissions from both units. Annual<br />
emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr per boiler for 7,884 hours<br />
per year (90% capacity factor).<br />
3.5 Step 5: Evaluate Visibility Impacts<br />
To evaluate the relative effectiveness of potentially feasible NOx retrofit control technologies, NOx<br />
emissions were modeled at the projected post-retrofit controlled emission rates, while SO2 and<br />
PM10 emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA<br />
guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling<br />
analysis to determine visibility impairment impacts reflect steady-state operating conditions during<br />
periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour<br />
basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling<br />
average multiplied by the boiler heat input (mmBtu/hr) at full load. The visibility modeling<br />
methodology is described further in Attachment B of this document, including detailed inputs and<br />
results. The results in Table 3-8 summarize the 98 th percentile ∆-dv impact from NOx emissions<br />
associated each NOx retrofit control scenario.<br />
The most significant improvement in visibility can be attributed to NOx reductions associated with<br />
combustion controls (LNB/OFA). Visibility improvements in the range of 70% reductions in<br />
modeled impacts are achieved at each Class I Area. The largest reduction in visibility impairment<br />
(0.74 ∆-dv) occurs at the Caney Creek Class I Area. Modeled impacts associated with NOx<br />
emissions based on LNB/OFA controls at the presumptive NOx emission limit (0.15 lb/mmBtu) are<br />
below the threshold impact level of 0.5 ∆-dv level at all Class I Areas.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
NOx Control<br />
Technology<br />
Option<br />
Upper Buffalo<br />
Wilderness Area<br />
98 th %<br />
% Improve-<br />
∆-dv* ment over<br />
Previous<br />
Table 3-8<br />
<strong>Muskogee</strong> Units 4 & 5<br />
NOx Visibility Assessment<br />
Visibility Improvement<br />
Caney Creek Hercules-Glades<br />
Wilderness Area Wilderness Area<br />
98 th %<br />
%<br />
∆-dv<br />
Improvement<br />
over<br />
Previous<br />
98 th %<br />
%<br />
∆-dv<br />
Improvement<br />
over<br />
Previous<br />
28<br />
Wichita Mountains<br />
Wildlife Refuge<br />
98 th %<br />
% Improve-<br />
∆-dv ment over<br />
Previous<br />
Baseline 0.84 -- 1.06 -- 0.47 -- 0.61 --<br />
LNB/OFA 0.24 71% 0.32 70% 0.14 71% 0.18 71%<br />
LNB/OFA + SCR 0.11 53% 0.14 56% 0.06 54% 0.08 55%<br />
* ∆-dv values included in this table represent the modeled visibility impacts only from NOx emissions associated<br />
with each NOx retrofit control scenario.<br />
Post-combustion SCR control systems could reduce NOx emissions from <strong>Muskogee</strong> Units 4 & 5<br />
below the BART presumptive level; however, modeled visibility improvements at the lower NOx<br />
emission rates do not justify the costs associated with SCR control. LNB/OFA control systems are<br />
expected to reduce overall NOx emissions from <strong>Muskogee</strong> Units 4 & 5 by approximately 15,489 tpy<br />
(from baseline). SCR control systems would reduce overall NOx emissions by an additional 3,456<br />
tpy. At the lower NOx emission rates, modeled visibility impairment at the Class I Areas would be<br />
reduced by only 0.08 to 0.18 ∆-dv. Because only small improvements in visibility impacts result<br />
from the lower emission rate, the cost effectiveness of SCR control, on a $/dv basis, will be<br />
significant.<br />
Tables 3-9 and 3-10 summarize the cost effectiveness of the technically feasible NOx retrofit<br />
control technologies on <strong>Muskogee</strong> Units 4 & 5 as a function of visibility impairment improvement<br />
at the Class I Areas.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
NOx Control<br />
Technology Option<br />
Table 3-9<br />
<strong>Muskogee</strong> Units 4 & 5<br />
NOx Average Visibility Cost Impact Evaluation<br />
Total Annual<br />
Cost<br />
Modeled<br />
Visibility<br />
Impairment*<br />
29<br />
Visibility<br />
Impairment<br />
Improvement<br />
from Baseline<br />
Average<br />
Improvement<br />
Cost<br />
Effectiveness<br />
($/yr) 98 th % ∆-dv* (dv) ($/dv/yr)<br />
Baseline -- 1.06 -- --<br />
LNB/OFA $4,183,600 0.32 0.74 $5.65 MM/dv<br />
LNB/OFA + SCR $61,591,200 0.14 0.92 $66.9 MM/dv<br />
* ∆-dv values included in this table represent the modeled visibility impacts only from NOx emissions<br />
associated with each NOx retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I<br />
Area was used for the cost effectiveness evaluation because modeling indicated that the largest ∆-dv<br />
improvements would occur at Caney Creek.<br />
Although SCR control systems reduce modeled visibility impacts at the four Class I Areas, the<br />
incremental cost effectiveness of SCR control (with respect to visibility improvement) is very high.<br />
Incremental cost effectiveness of SCR control is in the range of $319 million per dv improvement<br />
at the Wichita Mountains. This cost is significantly higher than costs incurred at other BART<br />
applicable sources. A review of BART determinations at other coal-fired units suggests that BART<br />
cost effectiveness values are typically in the range of less than $1.0 million to approximately $13<br />
million per dv improvement. 14 The combination of low visibility impacts with LNB/OFA controls<br />
(less than 0.32 ∆-dv at all Class I Areas) and the high cost of SCR controls contribute to the large<br />
incremental cost effectiveness of SCR at the <strong>Muskogee</strong> <strong>Station</strong>.<br />
NOx Control<br />
Technology Option<br />
Table 3-10<br />
<strong>Muskogee</strong> Units 4 & 5<br />
NOx Incremental Visibility Cost Impact Evaluation<br />
Total Annual<br />
Cost<br />
Incremental<br />
Annual Cost<br />
Modeled<br />
Visibility<br />
Impairment<br />
Incremental<br />
Visibility<br />
Impairment<br />
Improvement<br />
Incremental<br />
Improvement<br />
Cost<br />
Effectiveness<br />
($/yr) ($/yr) 98 th % ∆-dv* (dv) ($/dv/yr)<br />
Baseline -- -- 1.06 -- --<br />
LNB/OFA $4,183,600 -- 0.32 -- --<br />
LNB/OFA + SCR $61,591,200 $57,407,600 0.14 0.18 $319 MM/dv<br />
* ∆-dv values included in this table represent the modeled visibility impacts only from NOx emissions associated with<br />
each NOx retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I Area was used for the cost<br />
effectiveness evaluation because modeling indicated that the largest ∆-dv improvements would occur at Caney Creek.<br />
14 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy<br />
Co. (CO); Entergy White Bluff Power Plant (AR).
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
To determine whether alterative NOx control scenarios might provide more cost effective visibility<br />
improvements, cumulative impact modeling was conducted using a variety of SCR control<br />
scenarios. A goal of the cumulative impact modeling was to determine whether alternative NOx<br />
control scenarios (i.e., SCR control on some, but not all of the OG&E BART applicable sources)<br />
would provide more cost effective NOx control. To quantify cost effectiveness, visibility<br />
impairment was modeled for several NOx control scenarios, while SO2 and PM emissions were<br />
held constant at their respective baseline emission rates. Modeled NOx control scenarios are listed<br />
in Table 3-11. Results of the cumulative NOx impact modeling are summarized in Table 3-12.<br />
Table 3-11<br />
Cumulative NOx Visibility Assessment<br />
(<strong>Muskogee</strong> Units 4 & 5 and Sooner Units 1 & 2)*<br />
Unit Base Case Case 1 Case 2<br />
NOx Controls<br />
(Emission Rate - lb/mmBtu)<br />
Case 3 Case 4<br />
<strong>Muskogee</strong> Unit 4 LNB/OFA SCR<br />
SCR<br />
SCR<br />
SCR<br />
(0.15)<br />
(0.07)<br />
(0.07)<br />
(0.07)<br />
(0.07)<br />
<strong>Muskogee</strong> Unit 5 LNB/OFA LNB/OFA LNB/OFA SCR<br />
SCR<br />
(0.15)<br />
(0.15)<br />
(0.15)<br />
(0.07)<br />
(0.07)<br />
Sooner Unit 1 LNB/OFA LNB/OFA SCR<br />
SCR<br />
SCR<br />
(0.15)<br />
(0.15)<br />
(0.07)<br />
(0.07)<br />
(0.07)<br />
Sooner Unit 2 LNB/OFA LNB/OFA LNB/OFA LNB/OFA SCR<br />
(0.15)<br />
(0.15)<br />
(0.15)<br />
(0.15)<br />
(0.07)<br />
* For each case PM and SO2 emissions were held constant at the baseline emission rates. Baseline emissions for SO2<br />
were: 0.80 lb/mmBtu (<strong>Muskogee</strong> Unit 4), 0.85 lb/mmBtu (<strong>Muskogee</strong> Unit 5), and 0.86 lb/mmBtu (Sooner Units 1 & 2).<br />
NOx Control<br />
Technology<br />
Option<br />
Table 3-12<br />
Cumulative NOx Visibility Modeling Results<br />
(<strong>Muskogee</strong> Units 4 & 5 and Sooner Units 1 & 2)<br />
Upper Buffalo<br />
Wilderness Area<br />
98 th %<br />
∆-dv<br />
Modeled Visibility Impairment*<br />
Caney Creek<br />
Wilderness Area<br />
98 th %<br />
∆-dv<br />
30<br />
Hercules-Glades<br />
Wilderness Area<br />
98 th %<br />
∆-dv<br />
Wichita Mountains<br />
Wildlife Refuge<br />
98 th %<br />
∆-dv<br />
Base Case 1.92 2.00 1.44 2.42<br />
Case 1 1.94 1.99 1.43 2.41<br />
Case 2 1.94 1.98 1.43 2.38<br />
Case 3 1.95 1.97 1.46 2.35<br />
Case 4 1.94 1.96 1.46 2.33<br />
* ∆-dv values included in this table reflect cumulative modeled contributions from NOx, SO2 and PM emissions from both<br />
the Sooner and <strong>Muskogee</strong> <strong>Station</strong>s. For each case PM and SO2 emissions were held constant at their respective baseline<br />
emission rates, while NOx emissions varied depending the NOx control system on each unit (see Table 3-11). The dv<br />
values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2), which reflect modeled impacts<br />
from the <strong>Muskogee</strong> <strong>Station</strong> only for each individual pollutant.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Results of the cumulative impact modeling suggest that SCR controls would contribute only<br />
minimally to visibility improvement at the Class I Areas in comparison to LNB/OFA. Modeled<br />
impacts at the Wichita Mountains (at the 98 th percentile ∆-dv level) improved from 2.42 ∆-dv with<br />
LNB/OFA on all four units to 2.33 ∆-dv with SCR on all four units, an improvement of<br />
approximately 4%. Modeled improvements were even lower at the other Class I Areas, and, in fact,<br />
modeled impairments at the Hercules-Glades and Upper Buffalo Wilderness Areas actually<br />
increased with the addition of SCR controls. It is suspected that increased sulfuric acid mist<br />
emissions (associated with SO2 to SO3 conversion across the SCR) off-set reductions in controlled<br />
NOx emissions.<br />
3.6 Propose BART for NOx Control at <strong>Muskogee</strong> Units 4 & 5<br />
OG&E is proposing combustion controls (LNB/OFA), and a controlled NOx emission rate of 0.15<br />
lb/mmBtu (30-day average) as BART for <strong>Muskogee</strong> Units 4 & 5. This combination of control<br />
technologies represents the most cost effective technically feasible NOx retrofit technology for the<br />
existing boilers. A controlled emission rate of 0.15 lb/mmBtu is equivalent to the presumptive level<br />
for large tangentially-fired units firing subbituminous coals. The average cost effectiveness of<br />
LNB/OFA control systems is estimated to be in the range of $270/ton and $5.65 MM./dv/yr. These<br />
cost effectiveness numbers are in-line with EPA’s cost estimate for BART controls on large EGUs,<br />
and are not of such magnitude as to exclude combustion controls as BART.<br />
The addition of SCR control systems could provide incremental NOx reductions; however, costs<br />
associated with SCR control are significant, and incremental visibility improvements are limited.<br />
The average cost effectiveness of an SCR control system is estimated to be $3,251/ton and $66.9<br />
MM/dv/yr. These costs are significantly higher than the average cost of NOx control at similar<br />
sources. In the BART rule, EPA estimated that the cost of controls to meet the BART NOx<br />
presumptive level on large EGUs “in most cases range from just over $100 to $1000 per ton” (see,<br />
70 FR 39135).<br />
Furthermore, the modeled incremental visibility improvements associated with SCR control are<br />
only in the range of 0.08 to 0.18 ∆-dv. Because of the limited improvement in modeled visibility<br />
impacts, the cost effectiveness of SCR control, on a $/dv basis is significant. Compared to the<br />
costs and modeled visibility impacts associated with LNB/OFA controls, the incremental cost<br />
effectiveness of SCR is estimated to be $16,611/ton and more than $319 MM/dv/yr. Both costs are<br />
significantly higher than the expected cost of BART controls on large EGUs, and should preclude<br />
SCR from consideration as BART. Finally, cumulative impact modeling, summarized in Tables 3-<br />
11 and 3-12, supports the conclusion that post-combustion SCR controls provide limited<br />
improvement in modeled visibility impairment.<br />
31
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
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May 28, 2008<br />
4.0 BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (SO2)<br />
SOX emissions from coal combustion consist primarily of sulfur dioxide (SO2), with a much lower<br />
quantity of sulfur trioxide (SO3) and gaseous sulfates. These compounds form as the organic and<br />
pyretic sulfur in the coal are oxidized during the combustion process. On average, about 95% of<br />
the sulfur present in the fuel will be emitted as gaseous SOX, 15 Boiler size, firing configuration and<br />
boiler operations generally have little effect on the percent conversion of fuel sulfur to SO2.<br />
The generation of SO2 is directly related to the sulfur content and heating value of the fuel burned.<br />
The sulfur content and heating value of coal can vary dramatically depending on the source of the<br />
coal. <strong>Muskogee</strong> Units 4 & 5 utilize subbituminous coal as their primary fuel source. Heating<br />
values, ash contents, and sulfur contents for subbituminous fuel utilized at the <strong>Muskogee</strong> <strong>Station</strong><br />
are summarized in Table 4-1.<br />
Table 4-1<br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
Typical Coal Characteristics<br />
Constituent Units Range<br />
Heating Value Btu/lb 8,490 - 8,900<br />
Ash % 4.1 - 6.0<br />
Sulfur Content % 0.20 – 0.37<br />
Potential Uncontrolled SO2 lb/mmBtu 0.50 – 0.86<br />
* Coal characteristics included in this table represent average values based on fuel<br />
shipments to the <strong>Muskogee</strong> <strong>Station</strong>. Characteristics summarized in this table are not<br />
intended to limit the heating value, moisture content, ash content, or sulfur content of<br />
fuels utilized at the <strong>Muskogee</strong> <strong>Station</strong>, as short-term coal characteristics may vary<br />
from the values summarized above.<br />
4.1 Step 1: Identify Potentially Feasible SO2 Control Options<br />
Several techniques can be used to reduce SO2 emissions from a pulverized coal-fired combustion<br />
source. SO2 control techniques can be divided into pre-combustion strategies and post-combustion<br />
controls. SO2 control options identified for potential application to <strong>Muskogee</strong> Units 4 & 5 are listed<br />
in Table 4-2.<br />
15 AP-42, Section 1.1 Bituminous and Sub-Bituminous Coal Combustion, page 1.1-3, September 1998.<br />
32
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May 28, 2008<br />
Table 4-2<br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
List of Potential SO2 Retrofit Control Options<br />
Control Strategy/Technology<br />
Pre-Combustion Controls<br />
Fuel Switching<br />
Coal Washing<br />
Coal Processing<br />
Post-Combustion Controls<br />
Wet Flue <strong>Gas</strong> Desulfurization<br />
Wet Lime FGD<br />
Wet Limestone FGD<br />
Wet Magnesium Enhanced Lime FGD<br />
Jet Bubbling Reactor FGD<br />
Dual Alkali Scrubber<br />
Wet FGD with Wet Electrostatic Precipitator<br />
Dry Flue <strong>Gas</strong> Desulfurization<br />
Spray Dryer Absorber<br />
Dry Sorbent Injection<br />
Circulating Dry Scrubber<br />
4.2 Step 2: Technical Feasibility of Potential Control Options<br />
The technical feasibility of each potential control option is discussed below.<br />
4.2.1 Pre-Combustion Control Strategy<br />
The generation of SO2 is related to the sulfur content and heating value of the fuel burned. The<br />
sulfur content and heating value of coal can vary dramatically depending on the source of the<br />
coal. Potentially feasible pre-combustion control strategies designed to reduce overall SO2<br />
emissions are described below.<br />
4.2.1.1 Fuel Switching<br />
One potential strategy for reducing SO2 emissions is reducing the amount of sulfur<br />
contained in the coal. <strong>Muskogee</strong> Units 4 & 5 fire subbituminous coal as their primary fuel.<br />
Subbituminous coal has a relatively low heating value, low sulfur content, and low<br />
uncontrolled SO2 emission rate. Typical coal characteristics based on existing<br />
33
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
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May 28, 2008<br />
subbituminous coal shipments to OG&E’s <strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> are summarized in<br />
Table 4-1 above.<br />
Because of the relatively low sulfur content, subbituminous coals generate the lowest<br />
uncontrolled SO2 emissions. In fact, several coal-fired utilities have switched to low-sulfur<br />
coal as an SO2 emission control strategy. Bituminous coals from mines in the Eastern and<br />
Midwestern U.S. generally have higher heating values but also have a significantly higher<br />
sulfur content. Lignites from the upper Midwest and Texas have a relatively low sulfur<br />
content (but higher than subbituminous) but also have high moisture contents and relatively<br />
low heating values.<br />
Fuels currently used at the <strong>Muskogee</strong> <strong>Station</strong> generate low uncontrolled SO2 emissions.<br />
Switching to alternative coals (i.e., 100% bituminous coal or lignite) will not reduce<br />
potential uncontrolled SO2 emissions or controlled SO2 emissions from <strong>Muskogee</strong> Units 4<br />
& 5. No environmental benefits accrue from burning an alternative coal; therefore, fuel<br />
switching is not considered a feasible option for this retrofit project.<br />
4.2.1.2 Coal Washing<br />
Coal washing, or beneficiation, is one pre-combustion method that has been used to reduce<br />
impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by<br />
separating and removing inorganic impurities from organic coal particles. Inorganic<br />
impurities, including inorganic ash constituents and inorganic iron disulfide (FeS2 or<br />
pyrite), are typically more dense than the coal particles. This property is generally used in<br />
a wet cleaning process to separate coal particles from the inorganic impurities.<br />
Each coal seam has different washability characteristics depending on the characteristics of<br />
the inorganic constituents. Based on information available from the Kentucky Coal<br />
Council, inorganic sulfur in high-sulfur eastern bituminous coals may be reduced by 0.5 –<br />
2.5% and inorganic ash may be reduced by 9 – 15% through coal washing. 16 Coal washing<br />
is generally done at the mine to maximize the value of the coal and reduce freight charges<br />
to the power plant.<br />
The coal washing process generates a solid waste stream consisting of inorganic materials<br />
separated from the coal, and a wastewater stream that must be treated prior to discharge.<br />
Solids generated from wastewater processing and coarse material removed in the washing<br />
process must be disposed in a properly permitted landfill. Solid wastes from coal washing<br />
16 See, http://www.coaleducation.org/Ky_Coal_Facts/coal_resources/coal_preparation.htm.<br />
34
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
typically contain pyrites and other dense inorganic impurities including silica and trace<br />
metals. The solids are typically dewatered in a mechanical dewatering device and disposed<br />
of in a landfill.<br />
The wastewater stream generally consists of an acidic liquid slurry made up of water,<br />
uncombusted coal fines, and impurities in the coal, including calcium, trace metals,<br />
chloride, sulfate, and dissolved and suspended solids. 17 The wastewater slurry must be<br />
treated to remove solids, coal fines, and trace metals prior to discharge. Coal slurry<br />
treatment systems may include surface impoundments, mechanical dewatering systems,<br />
chemical processing systems, and/or thermal dryers.<br />
While washing may be effective in removing rock inclusions from coal, including sulfurbearing<br />
pyrites, a significant amount of coal may also be lost in the washing process. An<br />
inherent consequence of coal washing, in addition to generating wastewater and solid waste<br />
streams, would be the need for the mine to process significantly more coal to make up for<br />
coal lost in the washing process.<br />
<strong>Muskogee</strong> Units 4 & 5 are designed to utilize subbituminous coals. Based on a review of<br />
available information, no information was identified regarding the washability or<br />
effectiveness of washing subbituminous coals. Subbituminous coals have a relatively high<br />
ash content and an excessive amount of fines, and significant dewatering equipment would<br />
be required to process and separate the fines from the wastewater stream. It is likely that<br />
the excess fines production, and the difficulties associated with handling and dewatering<br />
the fines, have restricted the commercial viability of subbituminous coal washing.<br />
Furthermore, the coal washing process would generate significant solid and liquid waste<br />
streams that would require proper management and disposal. Based on a review of<br />
available information, there are currently no commercial subbituminous coal washing<br />
facilities, and washed subbituminous coals are not available through commercial channels.<br />
Therefore, coal washing is not considered an available retrofit control option for <strong>Muskogee</strong><br />
Units 4 & 5.<br />
4.2.1.3 Coal Processing<br />
Pre-combustion coal processing techniques have been proposed as one strategy to reduce<br />
the sulfur content of coal and help reduce uncontrolled SO2 emissions. Coal processing<br />
17 See, USEPA Report to Congress, Wastes from the Combustion of Fossil Fuels, Office of Solid Waste and<br />
Emergency Response, EPA 530-S-99-010, March 1999 (general composition of selected large-volume and<br />
low-volume wastes).<br />
35
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
technologies are being developed to remove potential contaminants from the coal prior to<br />
use.<br />
These processes typically employ both mechanical and thermal means to increase the<br />
quality of subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy<br />
metals. In one process, raw coal from the mine enters a first stage separator where it is<br />
crushed and screened to remove large rock and rock material. 18 The processed coal is then<br />
passed on to an intermediate storage facility. From the intermediate storage facility the<br />
coal goes to a thermal process. In this process coal passes through pressure locks into the<br />
thermal processors where steam at 460 o F and 485 psi is injected. Moisture in the coal is<br />
released under these conditions. Mineral inclusions are also fractured under thermal stress,<br />
removing both included rock and sulfur-forming pyrites. After it has been treated for a<br />
sufficient time in the main processor, the coal is discharged into a second pressurized lock.<br />
The second pressurized lock is vented into a water condenser to return the processor to<br />
atmospheric pressure and to flash cool the coal to approximately 200 o F. Water is removed<br />
from the coal at various points in the process. This water, along with condensed process<br />
steam, is either reused within the process or treated prior to being discharged.<br />
To date, the use of processed fuels has only been demonstrated with test burns in a<br />
pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their<br />
primary fuel source on an on-going, long-term basis. Although burning processed fuels, or<br />
a blend of processed fuels, has been tested in a pulverized coal-fired boiler, using processed<br />
fuels in <strong>Muskogee</strong> Units 4 & 5 would require significant research, test burns, and extended<br />
trials to identify potential impacts on plant systems, including the boiler, material handling,<br />
and emission control systems. Therefore, processed fuels are not considered commercially<br />
available, and will not be analyzed further in this BART analysis.<br />
4.2.2 Post-Combustion Flue <strong>Gas</strong> Desulfurization<br />
Over the past decade, post-combustion flue gas desulfurization (FGD) has been the most<br />
frequently used SO2 control technology for large pulverized coal-fired utility boilers. FGD<br />
systems typically have been installed on boilers firing high-sulfur bituminous coals. FGD<br />
systems, including wet scrubbers and dry scrubbers, have been designed to effectively and<br />
economically remove SO2 from pulverized coal-fired utility boiler flue gas. FGD systems with<br />
a potential applicability to <strong>Muskogee</strong> Units 4 & 5 are described below.<br />
18 ®<br />
The coal processing description provided herein is based on the K-Fuel process under development by<br />
KFx, Inc.<br />
36
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
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May 28, 2008<br />
4.2.2.1 Wet Scrubbing Systems<br />
Wet FGD technology is an established SO2 control technology. Wet scrubbing systems<br />
offered by vendors may vary in design; however, all wet scrubbing systems utilize an<br />
alkaline scrubber slurry to remove SO2 from the flue gas. Design variations may include<br />
changes to increase the alkalinity of the scrubber slurry, increase slurry/SO2 contact, and<br />
minimize scaling and equipment problems.<br />
All wet scrubbing FGD systems use an alkaline slurry that reacts with SO2 in the flue gas to<br />
form insoluble calcium sulfite (CaSO3) and calcium sulfate (CaSO4) salts. Wet FGD<br />
systems may be generally categorized as lime (CaO) or limestone (CaCO3) scrubbing<br />
systems. The scrubbing process and equipment for either lime- or limestone scrubbing is<br />
similar. The alkaline slurry consisting of hydrated lime or limestone may be sprayed<br />
countercurrent to the flue gas, as in a spray tower, or the flue gas may be bubbled through<br />
the alkaline slurry as in a jet bubbling reactor. Equations 4-1 through 4-5 summarize the<br />
chemical reactions that take place within the wet scrubbing systems to remove SO2 from<br />
flue gas.<br />
SO2 + CaO + ½H2O → CaSO3•½H2O↓ (4-1)<br />
SO2 + CaO + 2H2O → CaSO4•2H2O↓ (4-2)<br />
SO2 + CaCO3 + H2O → CaSO3•H2O↓ + CO2<br />
(4-3)<br />
CaSO3 + ½O2 + 2H2O → CaSO4•2H2O↓ (4-4)<br />
SO2 + 2H2O + ½ O2 + CaCO3 → CaSO4•2H2O↓ + CO2<br />
(4-5)<br />
Potentially feasible wet scrubbing systems are described below.<br />
Wet Lime Scrubbing<br />
The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to<br />
water. The alkaline slurry is sprayed in the absorber and reacts with SO2 in the flue gas.<br />
Insoluble CaSO3 and CaSO4 salts are formed in the chemical reaction that occurs in the<br />
scrubber (see equations 4-1 and 4-2), and are removed as a solid waste by-product. The<br />
waste by-product is made up of mainly CaSO3, which is difficult to dewater. Solid waste<br />
by-products from wet lime scrubbing are typically managed in dewatering ponds and<br />
landfills.<br />
Wet Limestone Scrubbing<br />
Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO3) is mixed<br />
with water to formulate the alkali scrubber slurry. SO2 in the flue gas reacts with the<br />
limestone slurry to form insoluble CaSO3 and CaSO4 which is removed as a solid waste by-<br />
37
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
product (see equations 4-3 and 4-4). The use of limestone instead of lime requires different<br />
feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio<br />
typically requires a larger absorbing unit. The limestone slurry process also requires a ball<br />
mill to crush the limestone feed.<br />
Forced oxidation of the scrubber slurry can be used with either the lime or limestone wet<br />
FGD system to produce gypsum solids instead of the calcium sulfite by-product. Air blown<br />
into the reaction tank provides oxygen to convert most of the calcium sulfite (CaSO3) to<br />
relatively pure gypsum (calcium sulfate) as shown in equation 4-4. Forced oxidation of the<br />
scrubber slurry provides a more stable by-product and reduces the potential for scaling in<br />
the FGD. The gypsum by-product from this process must be dewatered, but may be salable<br />
thus reducing the quantity of solid waste that needs to be landfilled.<br />
Wet scrubbing systems using limestone as the reactant have demonstrated the ability to<br />
achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing<br />
high-sulfur bituminous coals. Wet lime and limestone FGD control systems with forced<br />
oxidation are technically feasible SO2 retrofit technologies. However, wet scrubbing<br />
systems have not been used on large boilers firing subbituminous coals, and the actual<br />
control efficiency of a wet FGD system will depend on several factors, including the<br />
uncontrolled SO2 concentration entering the system. Based on engineering judgment it is<br />
expected that a wet lime or limestone FGD control system with forced oxidation could<br />
achieve average controlled SO2 emissions in the range of 0.08 lb/mmBtu (30-day rolling<br />
average) on <strong>Muskogee</strong> Units 4 & 5.<br />
Wet lime and wet limestone scrubbing systems will achieve the same SO2 control<br />
efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the<br />
more attractive option. For this reason, wet lime scrubbing will not be evaluated further in<br />
this BART determination.<br />
Wet Magnesium Enhanced Lime Scrubbing<br />
Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD<br />
technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide<br />
(MgO) and 90 – 95% calcium oxide (CaO). The presence of magnesium effectively<br />
increases the dissolved alkalinity, and consequently makes SO2 removal less dependent on<br />
the dissolution of the lime/limestone. In normal lime/limestone spray-tower operation the<br />
amount of SO2 absorbed depends principally upon the soluble-alkali content of the<br />
absorbing slurry. When magnesium is present, the soluble alkali level of the absorbent<br />
increases primarily because of the presence of sulfite and bicarbonate salts of magnesium.<br />
38
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
As these magnesium alkalies are more soluble than the corresponding calcium alkalies,<br />
there is an increase in the SO2 absorption capacity of the slurry. 19<br />
Commercial operation of wet FGD systems has shown that soluble Mg in the absorbing<br />
slurry can improve SO2 removal efficiency. 20 MEL scrubbers have been installed on coalfired<br />
utility boilers located in the Ohio River Valley. 21 Most are located in a corridor from<br />
Pittsburgh, Pennsylvania to Evansville, Indiana, and use a reagent that naturally contains<br />
approximately 5% MgO. Because of the increased alkalinity in the scrubbing liquid, MEL<br />
wet scrubbing systems have demonstrated the ability to achieve SO2 removal efficiencies<br />
equivalent to wet lime/limestone scrubbers using smaller absorber towers.<br />
Solids from the MEL FGD process consist primarily of calcium sulfite and magnesium<br />
sulfite solids. Dewatering the sulfite solids from an unoxidized MEL FGD system can be<br />
difficult, and produces a filter cake consisting of approximately 40-50% solids. Typically,<br />
unoxidized MEL FGD filter cake is fixed using fly ash and landfilled. This continues to be<br />
one of the drawbacks of the unoxidized MEL FGD process. Systems to oxidize the MEL<br />
solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and<br />
magnesium sulfate continue to be developed. 22<br />
Wet limestone FGD control systems can be designed to achieve the same control<br />
efficiencies as the magnesium enhanced limestone systems. However, to achieve the same<br />
control efficiencies, limestone-based systems require a higher liquid-to-gas ratio, and<br />
therefore larger absorber towers. Coal-fired units equipped with MEL FGD typically fire<br />
high-sulfur eastern bituminous coal and use locally available reagent. There are no<br />
subbituminous-fired units equipped with a MEL-FGD system.<br />
Because MEL-FGD systems have not been used on subbituminous-fired boilers, and<br />
because of the cost and limited availability of magnesium enhanced reagent (either<br />
naturally occurring or blended), and because limestone-based wet FGD control systems can<br />
be designed to achieve the same control efficiencies as the magnesium enhanced systems,<br />
MEL-FGD control systems will not be evaluated further as a commercially available<br />
retrofitted control system.<br />
19<br />
Combustion Fossil Power, page 15-43.<br />
20<br />
Combustion Fossil Power, page 15-42.<br />
21<br />
Nolan, P.S., “Flue <strong>Gas</strong> Desulfurization Technologies for Coal-Fired Power Plant,” Coal-Tech 2000<br />
International Conference, November 13-14, 2000.<br />
22<br />
See, Benson, L., Babu, M., Smith, K., “New Magnesium-Enhanced Lime FGD Process,” Dravo Lime, Inc.<br />
– Technology Center.<br />
39
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
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May 28, 2008<br />
Jet Bubbling Reactor<br />
Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike<br />
the spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a<br />
countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone<br />
slurry. Spargers are used to create turbulence within the reaction tank and maximize<br />
contact between the flue gas bubbles and scrubbing slurry. SO2 in the flue gas reacts with<br />
the limestone slurry to form insoluble CaSO3 and CaSO4 which is removed as a solid waste<br />
by-product (see equations 4-3, 4-4, and 4-5). Flue gas exits from the reaction vessel<br />
through mist eliminators to reduce carryover of the reactant.<br />
Although the reaction vessel used to contact flue gas with the scrubbing slurry is different<br />
than the spray tower used in a conventional wet FGD system, JBR-FGD systems use the<br />
same reaction chemistry to remove SO2 from the flue gas. JBR-FGD systems do not<br />
require the large slurry pumps associated with other wet FGD technologies; however,<br />
auxiliary power is shifted to larger fans, booster fans, agitators, and oxidation air blowers to<br />
accommodate the larger pressure drop through the system.<br />
There are currently a limited number of commercially operating JBR-WFGD control<br />
systems installed on coal-fired utility units in the U.S. A JBR-WFGD control system was<br />
installed at Georgia Power’s 100 MW coal-fired Yates plant in 1992. Based on publicly<br />
available emissions data, the Yates Plant has an average inlet SO2 concentration of<br />
approximately 3,500 ppm, and has achieved average SO2 removal efficiencies of<br />
approximately 93%. In addition to the Yates Plant, a JBR control system has been in use at<br />
the 40 MW equivalent Abbott Steam plant at the University of Illinois.<br />
Most of the JBR-WFGD control experience has been in Japan. Chiyoda Corporation has<br />
installed JBR-WFGD systems on several coal-fired plants overseas. Based on information<br />
available on Chiyoda’s website, a majority of the plants equipped with JBR-WFGD are<br />
smaller units (e.g., less then 200 MW); however, Chiyoda lists JBR-WFGD systems in<br />
operation on three plants located overseas in the 600 MW range. Commercial deployment<br />
of the JBR-WFGD control system continues to develop in the U.S. A project experience<br />
list available from Chiyoda identifies several U.S. power plants that have decided to install<br />
JBR-WFGD control systems, with control system startup dates between 2008 and 2010.<br />
Although the commercial deployment of the control system continues, there is still a very<br />
limited number of operating units in the U.S. Furthermore, coal-fired boilers currently<br />
considering the JBR-WFGD control system are all located in the eastern U.S., and all fire<br />
eastern bituminous coals. The control system has not been proposed as a retrofit<br />
40
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
technology on any large subbituminous coal-fired boilers. However, other than scale-up<br />
issues, there do not appear to be any overriding technical issues that would exclude<br />
application of the control technology on a large subbituminous coal-fired unit.<br />
Assuming that the JBR-WFGD control system is commercially available for <strong>Muskogee</strong><br />
Units 4 & 5, the JBR is essentially a wet FGD scrubbing system. Unlike the spray tower<br />
systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower,<br />
in the JBR-WFGD flue gas is bubbled through the limestone slurry. SO2 in the flue gas<br />
reacts with the limestone slurry to form insoluble calcium sulfate and calcium sulfite,<br />
which is removed as a solid waste by-product. Although the reaction vessel used to contact<br />
flue gas with the scrubbing slurry uses a different design, the reaction chemistry to remove<br />
SO2 from the flue gas is the same for all wet FGD designs.<br />
There are no data available to conclude that the JBR-WFGD control system will achieve a<br />
higher SO2 removal efficiency than a more traditional spray tower WFGD design,<br />
especially on units firing low-sulfur subbituminous coal. Furthermore, the costs associated<br />
with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to<br />
the costs and control efficiencies achievable with spray tower WFGD control systems.<br />
Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be<br />
included in the overall assessment of WFGD controls.<br />
Dual-Alkali Wet Scrubber<br />
Dual-alkali scrubbing is a desulfurization process that uses a sodium-based alkali solution<br />
to remove SO2 from combustion exhaust gas. The process uses both sodium-based and<br />
calcium-based compounds. The sodium-based reagent absorbs SO2 from the exhaust gas,<br />
and the calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium<br />
sulfites and sulfates are precipitated and discarded as sludge, while the regenerated sodium<br />
solution is returned to the absorber loop.<br />
The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with lime or<br />
limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, however<br />
additional regeneration and sludge processing equipment is necessary.<br />
The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide,<br />
sodium carbonate and sodium sulfite, is an efficient SO2 control reagent. However, the<br />
high cost of the sodium-based chemicals limits the feasibility of such a unit on a large<br />
utility boiler. In addition, the process generates a less stable sludge that can create material<br />
handling and disposal problems.<br />
41
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
It is projected that a dual-alkali system could be designed to achieve SO2 control similar to<br />
a limestone-based wet FGD. However, because of the limitations discussed above, and<br />
because dual-alkali systems are not currently commercially available, dual-alkali scrubbing<br />
systems will not be addressed further in this BART determination.<br />
Wet FGD with Wet Electrostatic Precipitator<br />
Wet FGD systems can result in increased emissions of condensable particulates and acid<br />
gases. In particular, SO3 generated in the unit’s boiler can react with moisture in the wet<br />
FGD to generate sulfuric acid mist. Sulfuric acid mist emissions from boilers firing high<br />
sulfur coals and equipped SCR and wet FGD can contribute to significant opacity problems<br />
if the H2SO4 concentration in the stack gas exceeds approximately 15 ppm. 23<br />
Wet electrostatic precipitation (WESP) has been proposed on other coal-fired projects as<br />
one technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have<br />
been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet<br />
FGD. 24 WESP has been demonstrated as an effective control technology to abate sulfuric<br />
acid mist emissions from industrial applications with relatively low flue gas flow rates and<br />
high acid mist concentrations, such as sulfuric acid plants. However, until recently, the<br />
technology has not been applied to the utility industry because of the high gas flow<br />
volumes and low acid mist concentrations associated with utility flue gas.<br />
In a utility application, the WESP would be located downstream from the wet FGD to<br />
remove micron-sized sulfuric acid aerosols from the flue gas stream as a condensable<br />
particulate. Electrostatic precipitation consists of three steps: (1) charging the particles to<br />
be collected via a high-voltage electric discharge, (2) collecting the particles on the surface<br />
of an oppositely charged collection electrode surface, and (3) cleaning the surface of the<br />
collecting electrode. In a WESP system, the collecting electrodes are typically cleaned<br />
with a liquid wash. Particulate mass loading, particle size distribution, particulate electrical<br />
resistivity, and precipitator voltage and current will influence ESP performance. The wet<br />
cleaning mechanism can also affect the nature of the particles that can be captured, and the<br />
performance efficiencies that can be achieved.<br />
23 See, Duellman, D.M., Erickson, C.A., Licata, T., Operating Experience with SCR’s and High Sulfur Coals<br />
& SO3 Plumes, presented at the ICAC NOx Forum, February 2002.<br />
24 See for example, the Thoroughbred <strong>Generating</strong> <strong>Station</strong> PSD Permit Application submitted to the Kentucky<br />
Department of Environmental Protection, and the Prairie States Energy Center PSD Permit Application<br />
submitted to the Illinois Environmental Protection Agency.<br />
42
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
WESP has not been widely used in utility applications, and has only been proposed on<br />
boilers firing high sulfur coals and equipped with SCR. <strong>Muskogee</strong> Units 4 & 5 fire lowsulfur<br />
subbituminous coal. Based on the fuel characteristics listed in Table 4-1, and<br />
assuming 1% SO2 to SO3 conversion in the boiler, potential uncontrolled H2SO4 emissions<br />
from <strong>Muskogee</strong> Units 4 & 5 will only be approximately 5 ppm. This emission rate does<br />
not take into account inherent acid gas removal associated with alkalinity in the<br />
subbituminous coal fly ash. Based on engineering judgment, it is unlikely that a WESP<br />
control system would be needed to mitigate visible sulfuric acid mist emissions from<br />
<strong>Muskogee</strong> Units 4 & 5, even if WFGD control was installed.<br />
WESPs have been proposed to control condensable particulate emissions from boilers<br />
firing a high-sulfur bituminous coal and equipped with SCR and wet FGD. This<br />
combination of coal and control equipment results in relatively high concentrations of<br />
sulfuric acid mist in the flue gas. WESP control systems have not been proposed on units<br />
firing subbituminous coals, and WESP would have no practical application on a<br />
subbituminous-fired units. Therefore, the combination of WFGD+WESP will not be<br />
evaluated further in this BART determination.<br />
Wet FGD Scrubbing - Conclusions<br />
Wet FGD technology is an established SO2 control technology. Wet scrubbing systems<br />
have been designed to utilize various alkaline scrubbing solutions including lime,<br />
limestone, and magnesium-enhanced lime. Wet scrubbing systems may also be designed<br />
with spray tower reactors or reaction vessels (e.g., jet bubbling reactor). Although the flue<br />
gas/reactant contact systems may vary, the chemistry involved in all wet scrubbing systems<br />
is essentially identical. A large majority of the wet FGD systems designed to remove SO2<br />
from existing high-sulfur utility boilers have been designed as wet limestone scrubbers with<br />
spray towers and forced oxidation systems.<br />
Wet scrubbing systems using limestone as the reactant have demonstrated the ability to<br />
achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing<br />
high-sulfur bituminous coals. The chemistry of wet scrubbing consists of a complex series<br />
of kinetic and equilibrium-controlled reactions occurring in the gas, liquid and solid phases.<br />
In general, the amount of SO2 removed from the flue gas is governed by the vapor-liquid<br />
equilibrium between SO2 in the flue gas and the absorbent liquid. If no soluble alkaline<br />
species are present in the liquid, the liquid quickly becomes saturated with SO2 and<br />
absorption is limited. 25 Likewise, as the flue gas SO2 concentration goes down, absorption<br />
25 Combustion Fossil Power – A Reference Book on Fuel Burning and Steam Generation, edited by Joseph P.<br />
Singer, Combustion Engineering, Inc., 4 th ed., 1991 (pp. 15-41).<br />
43
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
will be limited by the SO2 equilibrium vapor pressure. Therefore, high control efficiencies<br />
would not be expected on a boiler firing low sulfur coals because of the reduced SO2<br />
concentration in the boiler flue gas.<br />
Although WFGD control systems have not been used on subbituminous coal-fired units<br />
there are no technical limitations that would preclude its use on <strong>Muskogee</strong> Units 4 & 5.<br />
Therefore, WFGD is determined to be a technically feasible SO2 control retrofit<br />
technology. Based on the fuel characteristics listed in Table 4-1, taking into consideration<br />
the reduced SO2 concentration in the flue gas and reduced SO2 loading to the scrubbing<br />
system, and allowing a reasonable operating margin to account for normal operating<br />
conditions (e.g., load changes, changes in fuel characteristics, and minor equipment upsets)<br />
it is concluded that a WFGD retrofit control system could achieve a controlled SO2 rate of<br />
0.08 lb/mmBtu (30-day average).<br />
4.2.2.2 Dry Flue <strong>Gas</strong> Desulfurization<br />
Another scrubbing system that has been designed to remove SO2 from coal-fired<br />
combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or<br />
hydrated lime slurry into a reaction tower where it reacts with SO2 in the flue gas to form<br />
calcium sulfite solids (see equations 4-1 and 4-2). Dry scrubbing includes a separate lime<br />
preparation system and reaction tower. Unlike wet FGD systems that produce a slurry byproduct<br />
that is collected separately from the fly ash, dry FGD systems produce a dry byproduct<br />
that must be removed with the fly ash in the particulate control equipment.<br />
Therefore, dry FGD systems must be located upstream of the particulate control device to<br />
remove the reaction products and excess reactant material.<br />
Various dry FGD systems have been designed for use with pulverized coal-fired boilers.<br />
Dry scrubbing systems that may be technically feasible on <strong>Muskogee</strong> Units 4 & 5 are<br />
discussed below.<br />
Spray Dryer Absorber<br />
Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications.<br />
SDA systems have demonstrated the ability to effectively reduce uncontrolled SO2<br />
emissions from pulverized coal units.<br />
The typical spray dryer absorber uses a slurry of lime and water injected into the tower to<br />
remove SO2 from the combustion gases. The towers must be designed to provide adequate<br />
contact and residence time between the exhaust gas and the slurry to produce a relatively<br />
44
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
dry by-product. The process equipment associated with a spray dryer typically includes an<br />
alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate<br />
control device and a recycle system. The recycle system collects solid reaction products<br />
and recycles them back to the spray dryer feed system to reduce alkaline sorbent use.<br />
Various process parameters affect the efficiency of the SDA process including: the type and<br />
quality of the additive used for the reactant, reactant stoichiometric ratio, how close the<br />
SDA is operated to saturation conditions, and the amount of solids product recycled to the<br />
atomizer. The control efficiency of a SDA system is limited to approximately 94% of the<br />
SO2 loading to the system, and is a function of numerous operating variables including gasto-liquid<br />
contact and system operating temperatures.<br />
In a dry FGD system, the amount of reactant slurry introduced to the spray dryer must be<br />
controlled to insure that the reaction products leaving the absorber vessel are dry.<br />
Therefore, the outlet temperature from the absorber must be maintained above the<br />
saturation temperature. SDA systems are typically designed to operate within<br />
approximately 30 o F adiabatic approach to the saturation temperature. Operating closer to<br />
the adiabatic saturation temperature allows higher SO2 control efficiencies; however, outlet<br />
temperatures too close to the saturation temperature will result in severe operating<br />
problems including reactant build-up in the absorber modules, blinding of the fabric filter<br />
bags, and corrosion in the fabric filter and ductwork.<br />
High SO2 removal efficiencies in a SDA are also dependent upon good gas-to-liquid<br />
contact. Reactant spray nozzle designs are vendor-specific; however, both dual-fluid<br />
nozzles and rotary atomizers have been used in large coal-fired boiler applications.<br />
Dual-fluid nozzles (slurry and atomizing air) typically consist of a stainless steel head with<br />
multiple, ceramic two-fluid nozzle inserts. Slurry enters through the nozzle head and is<br />
distributed to the nozzle inserts. Atomizing air enters concentrically into a reservoir in the<br />
nozzle head and mixes with the slurry. The atomizing air expands as it passes through the<br />
air holes and nozzle exit. This expansion creates the shear necessary to atomize the slurry.<br />
Each nozzle is provided with a feed lance assembly consisting of a concentric feed pipe (air<br />
around slurry), hose connections, and the nozzle head. The feed lance assembly is inserted<br />
down through the SDA roof through a nozzle shroud assembly.<br />
Rotary atomizers are comprised basically of a high-speed rotating atomizer wheel coupled<br />
to a drive device and speed-increasing gear box. Because the reactant slurry is abrasive, the<br />
atomizing nozzles typically consist of a stainless steel head and multiple abrasion-resistant<br />
45
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
ceramic nozzle inserts. The rotary atomizers are inserted down through the SDA roof. The<br />
reactant slurry is atomized as it passes through the rapidly rotating nozzles.<br />
The atomizing nozzle assembly (either the duel-fluid feed lance assembly or the rotary<br />
atomizer assembly) is typically located in the SDA penthouse, and flange mounted to the<br />
roof of the absorber vessel. Overhead cranes or hoists located in the penthouse can be used<br />
to remove the nozzle assemblies from the absorber vessel for repair and maintenance.<br />
Because of the abrasive nature of the reactant slurry, nozzle assemblies must be removed<br />
and replaced on a routine basis. Depending on the design of the SDA system, one or more<br />
spare nozzle assemblies will be available for use. The nozzle assemblies may be changed<br />
without shutting down the SDA system. During that time period, the SDA may not be able<br />
to maintain maximum control efficiencies.<br />
SDA control systems are a technically feasible and commercially available retrofit<br />
technology for <strong>Muskogee</strong> Units 4 & 5. Based on the fuel characteristics listed in Table 4-1<br />
and allowing a reasonable margin to account for normal operating conditions (e.g., load<br />
changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor<br />
equipment upsets) it is concluded that dry FGD designed as SDA could achieve a<br />
controlled SO2 emission rate of 0.10 lb/mmBtu (30-day average) on an on-going long-term<br />
basis.<br />
Dry Sorbent Injection<br />
Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas<br />
exhaust stream. Dry sorbent injection systems are simple systems, and generally require a<br />
sorbent storage tank, feeding mechanism, transfer line and blower and an injection device.<br />
The dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber<br />
is often located downstream of the injection point to increase residence time and efficiency.<br />
Particulates generated in the reaction are controlled in the system’s particulate control<br />
device.<br />
Typical SO2 control efficiencies for a dry sorbent injection system are generally around<br />
50%. Because the control efficiency of the dry sorbent system is lower then the control<br />
efficiency of either the wet FGD or SDA, the system will not be evaluated further.<br />
Circulating Dry Scrubber<br />
A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system<br />
uses a circulating fluidized bed of dry hydrated lime reagent to remove SO2. Flue gas<br />
46
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
passes through a venturi at the base of a vertical reactor tower and is humidified by a water<br />
mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime where<br />
SO2 is removed. The dry by-product produced by this system is similar to the spray dry<br />
absorber by-product, and is routed with the flue gas to the particulate removal system.<br />
Based on engineering judgment and information available from equipment vendors, the<br />
CDS flue gas desulfurization system should be capable of achieving SO2 removal<br />
efficiencies similar to those achieved with a spray dryer absorber. In fact, vendors advise<br />
that the CDS system is capable of achieving even higher removal efficiencies with<br />
increased reactant injection rates and higher Ca/S stoichiometric ratios. However, to date<br />
the CDS has had limited application, and has not been used on large pulverized coal<br />
boilers. The largest CDS unit, in Austria, is on a 275 MW size oil-fired boiler burning oil<br />
with a sulfur content of 1.0 to 2.0%. Operating experience on smaller pulverized coal<br />
boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in<br />
lime utilization based on inlet SO2 loading. 26 Furthermore, CDS systems result in high<br />
particulate loading to the unit’s particulate control device.<br />
Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely<br />
that OG&E would be required to conduct extensive design engineering to scale up the<br />
technology for boilers the size of <strong>Muskogee</strong> Units 4 & 5, and that OG&E would incur<br />
significant time and resource penalties evaluating the technical feasibility and long-term<br />
effectiveness of the control system. Because of these limitations, CDS dry scrubbing<br />
systems are not currently commercially available as a retrofit control technology for<br />
<strong>Muskogee</strong> Units 4 & 5, and will not be evaluated further in this BART determination.<br />
The results of Step 2 of the SO2 BART analysis (technical feasibility analysis of potential SO2<br />
control technologies) are summarized in Table 4-3.<br />
26 See, Lavely, L.L., Schild, V.S., and Toher, J., “First North American Circulating Dry Scrubber and<br />
Precipitator Remove High Levels of SO2 and Particulate”,<br />
47
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Control<br />
Technology<br />
Table 4-3<br />
<strong>Muskogee</strong> Units 4 & 5<br />
Technical Feasibility of Potential SO2 Control Technologies<br />
SO2 Emission Rate<br />
In Service on<br />
Existing PC<br />
Boilers?<br />
(lb/mmBtu) Yes No<br />
48<br />
In Service on<br />
Other<br />
Combustion<br />
Sources?<br />
Fuel Switching NA X PCs have been<br />
designed to burn a<br />
variety of fuels.<br />
Coal Washing<br />
Coal Processing<br />
Wet FGD<br />
(lime, limestone,<br />
or magnesium<br />
enhanced lime)<br />
Jet Bubbling<br />
Reactor Wet<br />
FGD Control<br />
System<br />
Dual-Alkali Wet<br />
Scrubber<br />
NA<br />
--<br />
0.08 lb/mmBtu<br />
(approx. 40 ppmvd @<br />
3% O2)<br />
0.08 lb/mmBtu<br />
(approx. 40 ppmvd @<br />
3% O2)<br />
X<br />
X<br />
NA X<br />
X<br />
X<br />
Washing has not<br />
been used on subbituminous<br />
coals.<br />
Processed coal has<br />
been demonstrated<br />
in PC boilers.<br />
Wet FGD has been<br />
used on bituminous<br />
coal-fired PC<br />
boilers.<br />
JBR-FGD systems<br />
are in use on a<br />
limited number of<br />
coal-fired boilers.<br />
In use at a limited<br />
number of coalfired<br />
facilities.<br />
Technically Feasible Retrofit<br />
Technology for <strong>Muskogee</strong> Units<br />
4 & 5?<br />
Not technically feasible. The fuel<br />
currently used is low-sulfur and<br />
fuel switching will not reduce<br />
controlled SO2 emissions.<br />
Not technically feasible nor<br />
commercially available.<br />
Coal washing has not been used<br />
on subbituminous coals and<br />
washed subbituminous coal is not<br />
commercially available.<br />
Furthermore, it is unlikely that<br />
firing a washed subbituminous<br />
coal would result in any<br />
significant reduction in controlled<br />
SO2 emissions.<br />
Not technically available nor<br />
commercially available.<br />
Processed coal has not been<br />
demonstrated on a long-term<br />
basis as the primary flue in a PC<br />
boiler, and is not commercially<br />
available as a retrofit technology.<br />
Technically feasible, however<br />
limited commercial experience<br />
with wet FGD on large<br />
subbituminous fired units.<br />
Technically feasible, but may not<br />
be commercially available for<br />
<strong>Muskogee</strong> Units 4 & 5 (large subbituminous<br />
fired units). Because<br />
there is no operating experience<br />
with JBR-WFGD systems on<br />
large subbituminous-fired units,<br />
the control system was evaluated<br />
as an alternative WFGD control<br />
system.<br />
Not commercially available.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Table 4-3 continued:<br />
Control<br />
Technology<br />
Wet FGD with<br />
WESP<br />
Dry FGD – Spray<br />
Dryer Absorber<br />
Dry Sorbent<br />
Injection<br />
Circulating Dry<br />
Scrubber<br />
SO2 Emission Rate<br />
In Service on<br />
Existing PC<br />
Boilers?<br />
(lb/mmBtu) Yes No<br />
NA X<br />
0.10 lb/mmBtu<br />
(approx. 50 ppmvd @<br />
3% O2)<br />
0.4 lb/mmBtu<br />
(approx. 200 ppmvd<br />
@ 3% O2)<br />
X<br />
X<br />
NA X<br />
49<br />
In Service on<br />
Other<br />
Combustion<br />
Sources?<br />
The WESP control<br />
system is in use at<br />
a limited number of<br />
high-sulfur coal-<br />
fired units.<br />
In use on sub-<br />
bituminous coal-<br />
fired boilers.<br />
Dry sorbent<br />
injection has been<br />
used on a limited<br />
number of coalfired<br />
units.<br />
CDS is in use at a<br />
limited number of<br />
coal-fired boilers.<br />
Step 3: Rank the Technically Feasible SO2 Control Options by Effectiveness<br />
Technically Feasible Retrofit<br />
Technology for <strong>Muskogee</strong> Units<br />
4 & 5?<br />
Not technically feasible nor<br />
commercially available for units<br />
firing a low-sulfur subbituminous<br />
coal.<br />
Technically feasible.<br />
Technically feasible, but not as<br />
effective as other SO2 control<br />
options therefore excluded as<br />
BART.<br />
CDS Dry FGD was determined<br />
not to be commercially available<br />
for <strong>Muskogee</strong> Units 4 & 5 (large<br />
sub- bituminous fired units). In<br />
addition, there is no commercial<br />
experience with units similar to<br />
<strong>Muskogee</strong> Units 4 & 5, so CDS-<br />
DFGD was excluded as BART.<br />
Both technically feasible SO2 retrofit technologies (i.e., Wet- and Dry-FGD) are capable of meeting<br />
the BART presumptive level of 0.15 lb/mmBtu. However, in order to evaluate the cost<br />
effectiveness of each control technology, annual emissions and costs were estimated at the design<br />
emission limits of 0.08 lb/mmBtu for WFGD and 0.10 lb/mmBtu for DFGD. This approach was<br />
taken in order to determine whether either control technology was cost effective at the anticipated<br />
design emission rate. The technically feasible SO2 control technologies are listed in Table 4-4 in<br />
descending order of control efficiency based on anticipated design emission rates.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Table 4-4<br />
Summary of Technically Feasible SO2 Control Technologies<br />
Control Technology<br />
SO2 Emission Rate*<br />
(lb/mmBtu)<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5<br />
Wet FGD 0.08 0.08<br />
Dry FGD – Spray Dryer Absorber 0.10 0.10<br />
Baseline Uncontrolled SO2 Emissions 0.80 0.85<br />
* Emission rates are based on 30-day rolling averages that can be achieved on<br />
an on-going long-term basis under all normal operating conditions.<br />
4.3 Step 4: Evaluate the Technically Feasible SO2 Control Technologies<br />
Two post-combustion flue gas desulfurization control system designs (WFGD and SDA) are<br />
technically feasible and capable of achieving very low SO2 emission rates. An evaluation of the<br />
economic, energy and environmental impacts associated with each control system is provided<br />
below.<br />
4.3.1 Economic Evaluation<br />
Summarized in Table 4-5 are the expected controlled SO2 emission rates and annual SO2 mass<br />
emissions associated with each technically feasible control technology. Table 4-6 presents the<br />
capital costs and annual operating costs associated with building and operating each control<br />
system on <strong>Muskogee</strong> Units 4 & 5. Table 4-7 shows the average annual and incremental cost<br />
effectiveness for each SO2 control system.<br />
Control<br />
Technology<br />
SO2 Emissions<br />
(lb/mmBtu)<br />
Table 4-5<br />
<strong>Muskogee</strong> Units 4 & 5<br />
Annual SO2 Emissions (per boiler)<br />
Emissions<br />
(tpy)*<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5<br />
50<br />
Reduction in<br />
Emissions (tpy)*<br />
Emissions<br />
(tpy)*<br />
Reduction in<br />
Emissions (tpy)*<br />
Wet FGD 0.08 1,728 15,554 1,728 16,634<br />
Dry FGD – SDA 0.10 2,160 15,122 2,160 16,202<br />
Baseline 0.80 (Unit 4)<br />
0.85 (Unit 5)<br />
17,282 -- 18,362 --<br />
* Annual emissions and annual emission reductions for the BART analysis were calculated based on a full<br />
load heat input of 5,480 mmBtu/hr (per boiler), and assuming 7,884 hours/year (90% capacity factor).
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Control<br />
Technology<br />
Table 4-6<br />
<strong>Muskogee</strong> Units 4 & 5<br />
SO2 Emission Control System Cost Summary (each boiler)*<br />
Total Capital<br />
Investment<br />
($)<br />
Total Capital<br />
Investment<br />
($/kW-gross)<br />
51<br />
Annual Capital<br />
Recovery Cost<br />
($/year)<br />
Annual<br />
Operating Costs<br />
($/year)<br />
Total Annual<br />
Costs<br />
($/year)<br />
Wet FGD $418,567,000 $732 $35,917,500 $41,412,800 $77,067,900<br />
Dry FGD – SDA $373,106,000 $708 $32,016,400 $39,051,500 $71,330,300<br />
* Capital costs for SO2 control systems will be essentially equal for Units 4 and 5. Capital costs include the cost of<br />
major components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and<br />
insulation for the control system. Capital costs for the Wet FGD scenario include the cost of new chimneys on both<br />
units, and capital costs for the Dry FGD scenario include the cost of a post-scrubber fabric filter baghouse.<br />
Table 4-7<br />
<strong>Muskogee</strong> Units 4 & 5<br />
SO2 Emission Control System Cost Effectiveness (total for two boilers)<br />
Total Annual Annual Emission Average Annual Incremental<br />
Control Technology<br />
Cost* Reduction<br />
Cost Annual Cost<br />
Effectiveness Effectiveness**<br />
($/year)<br />
(tpy)<br />
($/ton)<br />
($/ton)<br />
Wet FGD $154,135,800 32,188 $4,789 $13,281<br />
Dry FGD – SDA $142,660,600 31,324 $4,554 --<br />
* Total annual costs in this table reflect total costs (capital and O&M) for both units. Costs are slightly more<br />
than double the total annual costs for Unit 4 because of the higher baseline emission rate on Unit 5.<br />
**Incremental cost effectiveness of the wet FGD control systems compared to the SDA control system.<br />
The average cost effectiveness of the potentially feasible SO2 control technologies range from<br />
approximately $4,554/ton for dry FGD to $4,789/ton for wet FGD. To support the BART<br />
rulemaking process, EPA calculated the cost effectiveness of both wet- and dry-FGD systems.<br />
Based on EPA’s analysis, the average cost effectiveness for controlling all BART-eligible<br />
EGUs greater than 200 MW without existing SO2 controls was estimated at $919 per ton SO2<br />
removed. Moreover, the range of cost effectiveness numbers demonstrated that the majority of<br />
these units could meet the presumptive SO2 emission limits at a cost of $400 to $2,000 per ton<br />
of SO2 removed (see, 70 FR 39133). Therefore, the average effectiveness of SO2 removal at<br />
<strong>Muskogee</strong> Units 4 & 5 is more than double the average cost effectiveness calculated by EPA<br />
for SO2 control on large EGUs. EPA’s calculation of average cost effectiveness included<br />
specific estimates for the <strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong>. EPA estimated that the least cost<br />
alternative for <strong>Muskogee</strong> would be dry FGD with estimated cost effectiveness ranging from<br />
$1,690/ton to $1,697/ton. As demonstrated by Table 4-7, the actual cost effectiveness of dry<br />
FGD is actually over 265% worse than the cost effectiveness estimated by EPA for a least cost<br />
scrubber installation at <strong>Muskogee</strong>.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Although the wet FGD control system may provide an incremental reduction in overall SO2<br />
emissions from <strong>Muskogee</strong> Units 4 & 5, the incremental costs associated with the additional SO2<br />
reductions are significantly higher than the average cost effectiveness of either control system.<br />
Wet FGD systems have a higher initial capital requirement (compared to dry systems), require<br />
more energy to operate, and have somewhat higher annual operating costs. The total annual<br />
costs for wet FGD control systems on <strong>Muskogee</strong> Units 4 & 5 are estimated to be approximately<br />
$11,465,200/year higher than the total annual costs for dry FGD systems. The incremental cost<br />
effectiveness of the wet FGD systems is estimated to be approximately $13,281/ton, which is<br />
substantially higher than the average cost effectiveness of the dry FGD control systems<br />
($4,554/ton). The additional costs associated with wet FGD would result in significant<br />
economic impacts on the <strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> (e.g., $11,465,200 per year additional<br />
costs). Therefore, wet FGD should not be selected as BART based on lack of cost<br />
effectiveness.<br />
4.3.2 Environmental Impacts of Wet FGD<br />
In addition to the economic impacts, there are several collateral environmental impacts<br />
associated with a wet FGD system. First, wet FGD systems generate a calcium sulfate waste<br />
by-product that must be properly managed. Historically, solid wastes generated from wet FGD<br />
systems have been dewatered and disposed of in landfills. Most new wet FGD systems utilize a<br />
forced oxidation system that results in a gypsum by-product that can sometimes be sold into the<br />
local gypsum market. If an adequate local gypsum market is not available, the gypsum byproduct<br />
will require proper disposal.<br />
Second, wet FGD systems will result in greater particulate matter emissions from the following<br />
sources:<br />
1. SO3 remaining in the flue gas will react with moisture in the wet FGD to generate<br />
sulfuric acid mist. Sulfuric acid mist is classified as a condensable particulate.<br />
Condensable particulates from the wet FGD system can be captured using additional<br />
emission controls (e.g., WESP). However the effectiveness of a WESP system on a<br />
subbituminous fired unit has not been demonstrated and the additional cost of the<br />
WESP system significantly increases the cost of SO2 control.<br />
2. Wet FGD systems must be located downstream of the unit’s particulate control device;<br />
therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD<br />
plume. Wet FGD control systems also generate lower stack temperatures that can<br />
reduce plume rise and result in a visible moisture plume.<br />
3. Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore<br />
the limestone handling system and storage piles will generate more fugitive dust<br />
emissions.<br />
52
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Third, wet FGD systems also require significantly more water than the dry systems. Based on<br />
preliminary engineering calculations, it is estimated that a wet FGD system would require<br />
approximately 650 million gallons per year (total for both units based on a 90% capacity),<br />
which represents an increase of about 30% over water consumption associated with dry FGD<br />
control systems. Water consumption is an important factor when assessing potential<br />
environmental impacts, and it is beneficial to minimize water consumption and maximize water<br />
recycle/reuse as much as practical.<br />
Finally, wet FGD systems generate a wastewater stream that must be treated and discharged.<br />
Wet FGD wastewater consists of a saturated solution of calcium sulfate, calcium sulfite,<br />
sodium chloride, with trace amounts of flyash and unreacted limestone. Traces of metal ions<br />
will also be present due to flyash carryover from the flue gas to the FGD scrubber liquor. Wet<br />
FGD wastewater treatment systems typically require calcium sulfate/sulfite desaturation, heavy<br />
metals precipitation, coagulation/precipitation, and sludge dewatering. Treated wastewater is<br />
typically discharged to surface water pursuant to an NPDES discharge permit, and solids are<br />
typically disposed of in a landfill. Dry FGD control systems are designed to evaporate water<br />
within the reaction vessel, and therefore do not generate a wastewater stream.<br />
4.3.3 Environmental Impacts of Dry Scrubbing<br />
Collateral environmental impacts are less significant with dry scrubbing systems (spray dryer<br />
absorber). First, dry scrubbing systems utilize lime as the reactant rather than limestone. Limebased<br />
scrubbing systems use less reactant than limestone-based systems, reducing overall<br />
particulate matter emission from the facility’s material handling system. Lime in a dry<br />
scrubbing system will be hydrated prior to use. It is estimated, based on preliminary<br />
engineering calculations, that a dry system would require approximately 440 million gallons<br />
per year (total for both units based on 90% capacity factor); however, water consumption with a<br />
dry system is approximately 30% less than the water requirements for a wet system.<br />
Furthermore, water used to hydrate the lime will be evaporated in the absorber vessel, and dry<br />
FGD systems will not generate a wastewater stream.<br />
Dry scrubbing systems are located upstream of the unit’s particulate control device. FGD<br />
solids mixed with fly ash will be captured in the particulate control device. The mixture of dry<br />
FGD solids and fly ash is generally not salable, however the material does not require<br />
dewatering and is easily landfilled. Assuming the unit is equipped with a fabric filter baghouse<br />
for particulate control, the alkaline filter cake associated with the dry scrubber will augment the<br />
capture of acid gases (including sulfuric acid), and will minimize condensable particulate<br />
emissions without the need for additional controls (e.g., WESP).<br />
53
Control<br />
Technology<br />
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
4.3.4 SO2 Control – Energy Impacts<br />
Both FGD control systems have significant auxiliary power requirements. Auxiliary power is<br />
required for material handling, reactant preparation, pumps, mixers, and to overcome<br />
significant pressure drops through the reaction vessels. Based on engineering estimates,<br />
auxiliary power requirement for wet and dry FGD control systems are approximately 2.25%<br />
and 1.5% of the gross energy output of the generating unit, respectively. <strong>Muskogee</strong> Units 1 &<br />
2 have a gross rating of 572 MW (each); therefore, annual auxiliary power requirements for<br />
FGD control systems would be in the range of 135,000 to 200,000 MWh per year (at a 90%<br />
capacity factor). Energy impacts associated with each control technology were included in the<br />
BART economic impact evaluation as an auxiliary power cost.<br />
A summary of the Step 4 economic and environmental BART impact analysis is provided in Table<br />
4-8.<br />
Table 4-8<br />
<strong>Muskogee</strong> Units 4 & 5<br />
Summary of SO2 BART Impact Analysis*<br />
Annual<br />
Emissions<br />
(tpy)<br />
Annual<br />
Emission<br />
Reductions<br />
(tpy)<br />
Total<br />
Annual<br />
Costs<br />
($/year)<br />
Average<br />
Cost<br />
Effectiveness<br />
($/ton)<br />
54<br />
Incremental<br />
Cost<br />
Effectiveness<br />
($/ton)<br />
Summary of Collateral<br />
Environmental Impacts<br />
Wet FGD 3,456 32,188 $154,135,800 $4,789 $13,281 Increased PM emissions,<br />
including sulfuric acid mist and<br />
other condensable particulates.<br />
Increased NOx, CO, VOC, and<br />
PM10 emissions associated with<br />
decreased unit heat rate and<br />
increased energy consumption.<br />
Increased water use and<br />
wastewater treatment/discharge.<br />
DFGD-SDA 4,320 31,342 $142,660,600 $4,554 NA Less water required. Increased<br />
solid waste generation rates<br />
(compared to wet FGD with<br />
forced oxidation and gypsum<br />
byproduct market). No<br />
wastewater generation or<br />
discharge.<br />
*Emissions and costs summarized in this table represent totals for both boilers. Emissions and costs were estimated<br />
based on a full load boiler heat input of 5,480 mmBtu/hr and a 90% capacity factor.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
4.5 Step 5: Evaluate Visibility Impacts<br />
To evaluate the relative effectiveness of potentially feasible SO2 retrofit control technologies, SO2<br />
emissions were modeled at the projected post-retrofit controlled emission rates, while NOx and<br />
PM10 emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA<br />
guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling<br />
analysis to determine visibility impairment impacts reflect steady-state operating conditions during<br />
periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour<br />
basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling<br />
average multiplied by the boiler heat input (mmBtu/hr) at full load. The visibility modeling<br />
methodology is described further in Attachment B of this document, including detailed inputs and<br />
results. The results in Table 4-9 summarize the 98 th percentile ∆-dv impact from SO2 emissions<br />
associated each SO2 retrofit control scenario.<br />
Table 4-9<br />
<strong>Muskogee</strong> Units 4 & 5<br />
SO2 Visibility Assessment<br />
Visibility Improvement<br />
Upper Buffalo Caney Creek Hercules-Glades Wichita Mountains<br />
Wilderness Area Wilderness Area Wilderness Area Wildlife Refuge<br />
SO2 Control<br />
Technology Option<br />
98 th %<br />
%<br />
∆-dv*<br />
Improvement<br />
over<br />
Baseline<br />
98 th %<br />
%<br />
∆-dv<br />
Improvement<br />
over<br />
Baseline<br />
98 th %<br />
%<br />
∆-dv*<br />
Improvement<br />
over<br />
Baseline<br />
98 th %<br />
%<br />
∆-dv<br />
Improvement<br />
over<br />
Baseline<br />
Baseline 1.277 -- 1.471 -- 0.92 -- 1.176 --<br />
DFGD – SDA 0.167 87% 0.196 87% 0.116 87% 0.148 87%<br />
WFGD 0.194 85% 0.243 83% 0.127 86% 0.143 88%<br />
* ∆-dv values included in this table represent the modeled visibility impacts only from SO2 emissions associated with<br />
each SO2 retrofit control scenario.<br />
With either FGD control system, modeled visibility impact improvements at the four Class I Areas<br />
are reduced by an average of approximately 1.0 ∆-dv, ranging from a 0.739 ∆-dv improvement<br />
(Hercules-Glades with wet FGD) to 1.275 ∆-dv (Caney Creek with dry FGD). Although the wet<br />
FGD control systems result in lower SO2 mass emission rates, modeled visibility impairments are<br />
generally less with dry FGD controls. Modeled impacts associated with SO2 emissions with either<br />
FGD control system are below the threshold impact level of 0.5 ∆-dv level at all Class I Areas. A<br />
summary of the cost effectiveness of both FGD control systems as a function of visibility<br />
impairment improvement at the Class I Areas is provided in Table 4-10.<br />
55
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
SO2 Control<br />
Technology Option<br />
Table 4-10<br />
<strong>Muskogee</strong> Units 4 & 5<br />
SO2 Average Visibility Cost Impact Evaluation<br />
Total Annual<br />
Cost<br />
Modeled<br />
Visibility<br />
Impairment*<br />
56<br />
Visibility<br />
Impairment<br />
Improvement<br />
from Baseline<br />
Average<br />
Improvement<br />
Cost<br />
Effectiveness<br />
($/yr) 98 th % ∆-dv* (dv) ($/dv/yr)<br />
Baseline -- 1.471 -- --<br />
DFGD – SDA $142,660,600 0.196 1.275 $111.9 MM/dv<br />
WFGD $154,135,800 0.243 1.228 $125.5 MM/dv<br />
* ∆-dv values included in this table represent the modeled visibility impacts only from SO2<br />
emissions associated with each SO2 retrofit control scenario. Modeled visibility impairment at the<br />
Caney Creek Class I Area was used for the cost effectiveness evaluation because modeling<br />
indicated that the largest ∆-dv improvements would occur at Caney Creek.<br />
Although FGD control systems reduce modeled visibility impacts at the four Class I Areas, the cost<br />
effectiveness of FGD control (with respect to visibility improvement) is very high. With either<br />
FGD control system, cost effectiveness ranges from approximately $111.9 million to $125.5 million<br />
per dv improvement at the Wichita Mountains. These costs are significantly higher than costs<br />
incurred at other BART applicable sources. A review of BART determinations at other coal-fired<br />
units suggests that BART cost effectiveness values are typically in the range of less than $1.0<br />
million to approximately $13 million per dv improvement. 27 The combination of relatively low<br />
baseline SO2 emissions, low baseline visibility impacts (less than 1.5 ∆-dv at all Class I Areas), and<br />
distance to the Class I Areas, all contribute to the large cost effectiveness values at the <strong>Muskogee</strong><br />
<strong>Station</strong>.<br />
To determine whether alterative SO2 control scenarios might provide more cost effective visibility<br />
improvements, cumulative impact modeling was conducted using a variety of FGD control<br />
scenarios. A goal of the cumulative impact modeling was to determine whether alternative SO2<br />
control scenarios (i.e., FGD control on some, but not all of the OG&E BART applicable sources)<br />
would provide more cost effective SO2 control. To quantify cost effectiveness, visibility<br />
impairment was modeled for several SO2 control scenarios, while NOx and PM emissions were<br />
held constant at their respective baseline emission rates. Modeled SO2 control scenarios are listed<br />
in Table 4-11. Results of the cumulative SO2 impact modeling are summarized in Table 4-12.<br />
27 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy<br />
Co. (CO); Entergy White Bluff Power Plant (AR).
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Table 4-11<br />
Cumulative SO2 Visibility Assessment<br />
(<strong>Muskogee</strong> Units 4 & 5 and Sooner Units 1 & 2)*<br />
Unit Base Case Case 1 Case 2<br />
SO2 Controls<br />
(Emission Rate - lb/mmBtu)<br />
Case 3 Case 4<br />
<strong>Muskogee</strong> Unit 4 Baseline DFGD DFGD<br />
DFGD<br />
DFGD<br />
(0.80)<br />
(0.10)<br />
(0.10)<br />
(0.10)<br />
(0.10)<br />
<strong>Muskogee</strong> Unit 5 Baseline Baseline Baseline DFGD<br />
DFGD<br />
(0.85)<br />
(0.85)<br />
(0.85)<br />
(0.10)<br />
(0.10)<br />
Sooner Unit 1 Baseline Baseline DFGD<br />
DFGD<br />
DFGD<br />
(0.86)<br />
(0.86)<br />
(0.10)<br />
(0.10)<br />
(0.10)<br />
Sooner Unit 2 Baseline Baseline Baseline Baseline DFGD<br />
(0.860)<br />
(0.86)<br />
(0.86)<br />
(0.86)<br />
(0.10)<br />
* For each case PM and NOx emissions were held constant at the baseline emission rates. Baseline emissions for<br />
NOx were: 0.15 lb/mmBtu for both <strong>Muskogee</strong> units (assuming LNB/OFA controls).<br />
SO2 Control<br />
Technology<br />
Option<br />
Table 4-12<br />
Cumulative SO2 Visibility Modeling Results<br />
(<strong>Muskogee</strong> Units 4 & 5 and Sooner Units 1 & 2)<br />
Upper Buffalo<br />
Wilderness Area<br />
98 th %<br />
∆-dv<br />
Modeled Visibility Impairment*<br />
Caney Creek<br />
Wilderness Area<br />
98 th %<br />
∆-dv<br />
57<br />
Hercules-Glades<br />
Wilderness Area<br />
98 th %<br />
∆-dv<br />
Wichita Mountains<br />
Wildlife Refuge<br />
98 th %<br />
∆-dv<br />
Base Case 1.92 2.00 1.44 2.42<br />
Case 1 1.46 1.69 1.05 2.16<br />
Case 2 1.26 1.48 0.90 1.60<br />
Case 3 0.78 0.91 0.52 1.33<br />
Case 4 0.57 0.68 0.38 0.74<br />
* ∆-dv values included in this table reflect cumulative modeled contributions from NOx, SO2 and PM emissions from<br />
both the Sooner and <strong>Muskogee</strong> <strong>Station</strong>s. For each case, PM and NOx emissions were held constant at their<br />
respective baseline emission rates, while SO2 emissions varied depending the SO2 control system on each unit (see<br />
Table 4-11). The dv values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2),<br />
which reflect modeled impacts from the <strong>Muskogee</strong> <strong>Station</strong> only for each individual pollutant.<br />
Results of the cumulative impact modeling suggest that visibility improvement at the Class I Areas<br />
is essentially linear with SO2 emission reductions from the OG&E generating stations (see, Figure<br />
4-1). For example, modeled visibility impairment at the Wichita Mountains was reduced by 0.26<br />
∆-dv with one FGD at the <strong>Muskogee</strong> <strong>Station</strong>, and by an additional 0.27 ∆-dv with a second FGD at<br />
<strong>Muskogee</strong>. Similarly, visibility impairment at the Wichita Mountains was reduced by 0.56 ∆-dv<br />
with one FGD control system at the Sooner <strong>Station</strong>, and by an additional 0.59 ∆-dv with a second<br />
FGD at Sooner. However, because of the relatively small improvement in visibility impairment,<br />
the cost effectiveness for FGD control systems ranged from approximately $120 MM/dv (Sooner
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
<strong>Station</strong>) to more than $260 MM/dv (<strong>Muskogee</strong> <strong>Station</strong>). Cost effectiveness values associated with<br />
the cumulative impact modeling at the Wichita Mountains Wildlife Refuge are summarized in<br />
Table 4-13.<br />
Modeled Visibility Impairment (delta-dv<br />
3.00<br />
2.50<br />
2.00<br />
1.50<br />
1.00<br />
0.50<br />
0.00<br />
Case<br />
Figure 4-1<br />
Cumulative SO2 Visibility Modeling Results<br />
(<strong>Muskogee</strong> Units 4 & 5 and Sooner Units 1 & 2)<br />
Wichita Mountains<br />
Modeled Visibility Impairment vs. FGD Control Systems<br />
Wichita Mts Caney Creek Herc-Glades Upper Buffalo<br />
Baseline Case 1 (<strong>Muskogee</strong> Unit 4) Case 2 (<strong>Muskogee</strong> Unit 4<br />
and Sooner Unit 1)<br />
Table 4-12<br />
Cumulative SO2 Visibility Modeling Results<br />
Wichita Mountains<br />
98 th %<br />
∆-dv<br />
FGD Control Scenario<br />
Incremental<br />
Improvement<br />
58<br />
Case 3 (<strong>Muskogee</strong> 4 & 5 and Case 4 (<strong>Muskogee</strong> 4 & 4 and<br />
Sooner Unit 1)<br />
Sooner 1 & 2)<br />
Incremental<br />
Increase in<br />
Annual Cost<br />
Cost<br />
Effectiveness<br />
Base Case 2.42 -- -- $MM/dv<br />
Case 1 2.16 0.26 $71,067,900 $273.3<br />
Case 2 1.60 0.56 $70,415,900 $125.7<br />
Case 3 1.33 0.27 $71,067,900 $263.2<br />
Case 4 0.74 0.59 $70,415,900 $119.3
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
4.6 Propose BART for SO2 Control<br />
OG&E is proposing that no additional SO2 controls (beyond baseline low sulfur subbituminous<br />
coal) are BART for <strong>Muskogee</strong> Units 4 & 5. In the final Regional Haze Rule EPA established<br />
presumptive BART emission limits for SO2 from coal-fired EGUs greater than 200 MW at power<br />
plants with a total generating capacity in excess of 750 MW. 28 The BART SO2 presumptive<br />
emission limit for these units is either 95% SO2 removal or an emission rate of 0.15 lb/mmBtu,<br />
unless an alternative control level is justified based on a careful consideration of the statutory<br />
factors. Statutory factors include the costs of compliance and the degree of improvement in<br />
visibility which may reasonably be anticipated to result from the use of such technology. In the<br />
case of the <strong>Muskogee</strong> <strong>Station</strong>, the poor cost effectiveness of the feasible controls dictates a decision<br />
that no additional controls are warranted.<br />
The cost effectiveness of FGD control on <strong>Muskogee</strong> Units 4 & 5 is poor in comparison to the cost<br />
effectiveness estimates used by EPA in establishing presumptive BART. EPA believed the average<br />
cost effectiveness would be $919 per ton SO2 removed, with the majority of the BART applicable<br />
units meeting the presumptive standards at a cost of $400 to $2,000 per ton of SO2 removed. To<br />
support the presumptive BART analysis, EPA developed cost effectiveness estimates for <strong>Muskogee</strong><br />
Units 4 & 5 of $1,690 to $1,697 per ton of SO2 removed. In fact, the actual cost effectiveness of<br />
the potentially feasible SO2 control technologies at the <strong>Muskogee</strong> <strong>Station</strong> is $4,554 to $4,789 per<br />
ton of SO2 removed. Therefore, SO2 removal at <strong>Muskogee</strong> Units 4 & 5 is over two-and-a-half<br />
times less cost effective than EPA expected, and it is well outside of the cost effectiveness range<br />
that EPA used to support its presumptive BART determination. The cost effectiveness of FGD<br />
controls at the <strong>Muskogee</strong> <strong>Station</strong> calculated on the basis of visibility improvement also is poor. The<br />
cost effectiveness is estimated to be in the range of $111.9 to $125.5 million per dv improvement,<br />
which is significantly less effective than at other BART applicable sources.<br />
Although FGD control systems (either wet or dry FGD) will reduce SO2 emissions and modeled<br />
visibility impairment at the Class I Areas, the combination of relatively low baseline SO2 emissions,<br />
low baseline visibility impacts (less than 1.5 ∆-dv at all Class I Areas), and distance to the Class I<br />
Areas, all contribute to the poor cost effectiveness values. Based on the poor cost effectiveness of<br />
FGD retrofit controls and the relatively small degree of improvement in visibility, FGD control<br />
systems should not be selected as BART on <strong>Muskogee</strong> Units 4 & 5. As a result, OG&E is<br />
proposing low sulfur subbituminous coal and the existing permit limits as BART for SO2.<br />
28 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131.<br />
59
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May 28, 2008<br />
5.0 BART ANALYSIS FOR MAIN BOILER PARTICULATE MATTER<br />
PM composition and emission levels are a complex function of boiler firing configuration, boiler<br />
operation, pollution control equipment and coal properties. Uncontrolled PM emissions from coalfired<br />
boilers include the ash from combustion of the fuel, noncombustible metals present in trace<br />
quantities and unburned carbon resulting from incomplete combustion. Other sources of PM<br />
include condensable organics and minerals present in the combustion air.<br />
Coal ash may either settle out in the boiler (bottom ash) or be entrained in the flue gas (fly ash).<br />
The distribution of ash between the bottom ash and fly ash fractions affects the PM emission rate<br />
and is a function of the boiler firing method and furnace type. With a PC boiler approximately 80%<br />
of the ash will be emitted with the flue gas as fly ash and 20% will settle out in the combustion bed<br />
as bottom ash. PM10 emissions from <strong>Muskogee</strong> Units 4 & 5 are currently controlled with cold-side<br />
electrostatic precipitators (ESPs).<br />
5.1 Step 1: Identify Available Retrofit PM10 Control Options<br />
The principal techniques for PM control are post-combustion methods (applicable to most boiler<br />
types and sizes). There are two generally recognized PM control devices that are used to control<br />
PM emission from PC boilers: ESPs and fabric filters (or baghouses). <strong>Muskogee</strong> Units 4 & 5 are<br />
currently equipped with ESP control systems.<br />
Retrofit PM10 control options with potential application to a subbituminous-fired PC boiler are<br />
listed in Table 5-1. The technical feasibility of each potential control option is discussed below.<br />
Table 5-1<br />
PM10 Retrofit Control Options with Potential Application to a<br />
Subbituminous-Fired PC Boiler<br />
PM10 Control Technologies<br />
Electrostatic Precipitation (ESP) – existing<br />
Fabric Filtration (FF)<br />
5.2 Step 2: Eliminate Technically Infeasible Retrofit Options<br />
5.2.1 Electrostatic Precipitators (ESPs)<br />
<strong>Muskogee</strong> Units 4 & 5 are currently equipped with ESPs for PM10 control. ESP technology<br />
consists of three steps: (1) charging the particles to be collected via a high-voltage electric<br />
discharge, (2) collecting the particles on the surface of an oppositely charged collection electrode<br />
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surface, and (3) cleaning the surface of the collecting electrode. Particulate material captured on<br />
the collecting electrodes is removed by rapping the electrodes. The collected particulates drop into<br />
hoppers below the precipitator and are periodically removed with the fly ash handling system.<br />
Operating parameters that influence ESP performance include fly ash mass loading, particle size<br />
distribution, fly ash electrical resistivity, and precipitator voltage and current. Other factors that<br />
determine ESP collection efficiency are collection plate area, gas flow velocity, and cleaning cycle.<br />
Baseline controlled PM10 emissions from <strong>Muskogee</strong> Units 4 & 5 are approximately 101 lb/hr and<br />
134 lb/hr, respectively. Based on a maximum heat input of 5,480 mmBtu/hr (each boiler), baseline<br />
PM10 emission rates from Units 4 & 5 are 0.0184 and 0.0244 lb/mmBtu, respectively. 29 These<br />
controlled rates require the existing ESPs to achieve average overall particulate matter control<br />
efficiencies of greater than 99%.<br />
5.2.2 Fabric Filters<br />
Fabric filtration consists of a number of filtering elements (bags) along with a bag cleaning system<br />
contained in a main shell structure incorporating dust hoppers. Particulate-laden gas enters a<br />
fabric filter compartment and passes through a layer of filter bags. The collected particulate forms<br />
a cake on the bag that enhances the bag’s filtering efficiency. Excessive caking will increase the<br />
pressure drop across the fabric filter at which point the filters must be cleaned.<br />
The particulate removal efficiency of fabric filters is dependent upon a variety of particle and<br />
operational characteristics. Particle characteristics that affect the collection efficiency include<br />
particle size distribution and particle cohesion characteristics. Operational parameters that may<br />
affect fabric filter collection efficiency include bag material, air-to-cloth ratio, and operating<br />
pressure loss. In addition, certain filter properties (e.g., structure of the fabric and fiber<br />
composition) can affect the system's particle collection efficiency.<br />
Fabric filter baghouses are considered a technically feasible particulate matter control option for<br />
<strong>Muskogee</strong> Units 4 & 5, and a fabric filter baghouse (or polishing baghouse) would be required if<br />
the units were retrofit with dry FGD. However, retrofitting the existing units with baghouses for<br />
particulate matter control only (i.e., not in conjunction with a dry FGD) would require substantial<br />
modifications to the units without providing any significant reduction in controlled PM emissions.<br />
29 Baseline PM10 emissions used in this BART analysis were based on the highest 24-hour block emissions<br />
reported by each unit during the baseline period. Baseline PM10 emission rates (lb/mmBtu) were calculated<br />
by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The<br />
relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts,<br />
and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control<br />
technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation<br />
of the facility’s permitted emission limits, which are averaged over a longer period of time.<br />
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Extensive ductwork would be required to redirect flue gas flow though the fabric filter and back to<br />
the existing stacks. Furthermore, baghouses would provide only an incremental reduction in PM/<br />
PM10 control compared to the existing ESP control systems.<br />
5.3 Step 3: Rank the Technically Feasible PM10 Control Options by Effectiveness<br />
The effectiveness of each retrofit technology identified as being technically feasible for PM10<br />
control is summarized in Table 5-2 in descending order of control efficiency.<br />
Table 5-2<br />
Summary of Technically Feasible<br />
Main Boiler PM10 Control Technologies<br />
PM10 Emissions* % Reduction<br />
Control Technology<br />
(lb/mmBtu)<br />
(from base case)<br />
Fabric Filter Baghouse 0.015 99.7<br />
ESP - Existing 0.025 99.6<br />
Potential PM Emissions 5.65 -<br />
* The PM10 emission rate for the baghouse case is based on filterable PM10 emission limits<br />
included in recently issued PSD permits for new coal-fired units. The PM10 emission rate for the<br />
ESP case is based on the Units’ baseline PM10 emission rates (e.g., approximately 0.025<br />
lb/mmBtu on Unit 5). Potential PM emissions were calculated assuming an average fuel heating<br />
value of 8,500 Btu/lb and an ash content of 6.0%, and assuming 80% of the fuel ash will be<br />
emitted as fly ash.<br />
5.4 Step 4: Evaluate Impacts and Document the Results<br />
5.4.1 Economic Evaluation<br />
Based on the controlled PM10 emission rates included in Table 5-2, and assuming a maximum<br />
heat input to each boiler of 5,480 mmBtu/hr and 7,884 hours/year operation (90% capacity<br />
factor), potential PM10 emissions from <strong>Muskogee</strong> Units 4 & 5 would be reduced from<br />
approximately 1,080 tpy to 648 tpy with a fabric filter baghouse (total potential emissions from<br />
both units). Equipment costs associated with retrofitting <strong>Muskogee</strong> Units 4 & 5 with a<br />
baghouse are estimated to be in the range of $125 to 135/kW-gross, or in the range of<br />
$75,000,000 per unit. Taking into consideration indirect installation costs for foundations,<br />
mechanical erection, electrical, piping, and insulation, and including engineering, and<br />
contingencies, total capital requirement for a fabric filter baghouse would be in the range of<br />
$104,000,000/unit. The annualized capital recovery cost for the baghouse control systems<br />
(assuming equipment life of 25 years and 7% pretax marginal rate of return) would be<br />
approximately $8,900,000/yr (per unit). Ignoring O&M costs associated with baghouse<br />
operation (including bag replacement costs and energy cost associated with increased pressure<br />
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drop) the cost effectiveness of the retrofit baghouse control system would be more than<br />
$41,000/ton of PM removed (e.g., $8.9 MM/yr/unit x 2 units / 432 tpy potential emission<br />
reductions).<br />
It is apparent that a retrofit baghouse control system would not be cost effective for particulate<br />
matter control only. Although baghouses may provide an incremental reduction in PM10<br />
emissions, the costs associated with a fabric filter retrofit project are significant. Retrofitting<br />
<strong>Muskogee</strong> Units 4 & 5 with baghouses for particulate matter control would require a significant<br />
capital investment for a minimal reduction in emissions. The cost effectiveness of the retrofit<br />
baghouse control systems is excessive, and should preclude fabric filter control systems from<br />
consideration as BART for PM control.<br />
5.4.2 Environmental Evaluation<br />
There are no environmental considerations that would preclude the use of either fabric filters or<br />
ESP control systems as BART on <strong>Muskogee</strong> Units 4 & 5. Both PM control systems generate a<br />
fly ash solid waste that must be properly managed.<br />
5.4.3 PM Control - Energy Impact Evaluation<br />
There are significant auxiliary power requirements associated with the fabric filter control<br />
system. Auxiliary power is required to overcome pressure drop through the baghouse and filter<br />
cake. Based on engineering estimates, auxiliary power requirements for a fabric filter baghouse<br />
are approximately 0.5% of the gross energy output of the generating unit. <strong>Muskogee</strong> Units 4 &<br />
5 have a gross rating of 572 MW (each); therefore, annual auxiliary power requirements for a<br />
baghouse control system would be in the range of 45,000 MWh per year (at a 90% capacity<br />
factor). Annual operating costs associated with the auxiliary power requirement would be<br />
significant, and the increased auxiliary power requirement would reduce the overall efficiency<br />
of both units.<br />
5.5 Step 5: Evaluate Visibility Impacts<br />
Replacing the existing ESPs on <strong>Muskogee</strong> Units 4 & 5 with baghouses is not a cost effective<br />
retrofit control option for PM control. Furthermore, based on visibility impact modeling,<br />
particulate matter emissions from <strong>Muskogee</strong> Units 4 & 5 contribute only minimally to modeled<br />
visibility impacts at the Class I Areas (see, Attachment B). A majority (more than 90%) of the<br />
modeled visibility impacts are associated with NOx and SO2 emissions. Reducing particulate matter<br />
emissions from the existing baseline rate (with ESP control) would provide no discernible reduction<br />
in modeled visibility impacts at the Class I areas.<br />
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5.6 Propose BART for PM10 Control<br />
Based on visibility impact modeling, and economic impacts associated with retrofit PM controls,<br />
OG&E is not proposing any change to its existing PM/ PM10 emission limits as BART. Therefore,<br />
OG&E is proposing no change to existing permitted PM emission limits as BART for particulate<br />
matter control.<br />
6.0 BART SUMMARY<br />
Table 6-1 summarizes the proposed BART control technologies and associated emission limits for<br />
<strong>Muskogee</strong> Units 4 & 5.<br />
Table 6-1<br />
Proposed BART Permit Limits and Control Technologies<br />
Pollutant Proposed BART<br />
Emission Limit<br />
NOx<br />
0.15 lb/mmBtu<br />
(30-day average)<br />
64<br />
Proposed BART Technology<br />
Combustion controls including LNB<br />
and OFA<br />
SO2 Existing Permit Limits Low sulfur subbituminous coal<br />
PM10 filterable Existing Permit Limits NA
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Attachment A<br />
<strong>Muskogee</strong> Units 4 & 5<br />
BART Determination - Cost Estimate Details<br />
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May 28, 2008<br />
Economic Evaluation Methodology for<br />
Technically Feasible Control Options<br />
Summarized below are the basic principles and methodologies used to prepare the economic<br />
analysis of technologically feasible control options. The cost-effectiveness evaluations were<br />
"study" estimates of ±30% accuracy, based on: (1) engineering estimates; (2) vendor quotations<br />
provided for similar projects and similar equipment; (2) S&L’s internal cost database; and (4)<br />
cost estimating guidelines provided in EPA’s, “EPA Air Pollution Control Cost Manual, Sixth<br />
Edition” EPA-452/B-02-001, January 2002.<br />
Over the past several years, prices on air pollution control equipment have increased<br />
significantly. Several trends have contributed to the rapid escalation in costs, including the<br />
greater demand for equipment and materials, significant increases in commodity prices, and<br />
greater demand for skilled labor and construction contractors.<br />
Over the past 4-year period the demand for electric utility steam generating emission control<br />
equipment, including FGD and SCR control systems, increased significantly in response to the<br />
Clean Air Interstate Rule (CAIR). CAIR, published May 12, 2005, mandates specific emission<br />
caps on SO2 and NOx emissions from power plants located in 28 Eastern and Midwestern states.<br />
CAIR emission caps will be imposed in two phases, with the first phase beginning in 2009 for<br />
NOx and 2010 for SO2. The second phase of emission reductions are required in 2015 for both<br />
pollutants. CAIR is projected to result in the installation of an additional 64 GW of flue gas<br />
desulfurization and an additional 34 GW of selective catalytic reduction technology on existing<br />
coal-fired generation capacity. 30 This increase in demand for retrofit emission control systems<br />
created a “sellers market” in the U.S. Pollution control equipment vendors, their fabricators and<br />
material suppliers currently have significant backlogs and are able to charge higher margins,<br />
contributing to the recent escalation in retrofit control technology costs.<br />
Construction contractors and construction labor are currently in high demand in the U.S., not only<br />
in the electric power generating industry but also in the petroleum refining, chemical processing,<br />
and ethanol industries. All of these industries pull from the same labor force. Due to increased<br />
demand, construction contractors are more selective with the projects that they bid, and are able<br />
to demand higher margins. Similarly, the labor force is able to demand more lucrative contracts<br />
in order to be attracted to an area that is short of labor. Per diems and mandatory overtime are<br />
often needed to attract sufficient labor to support major construction projects.<br />
During the same period, commodity prices have also increased significantly. Commodity price<br />
data available from the U.S. Department of Labor’s Bureau of Labor Statistics show a sharp<br />
upturn in metals prices since 2004. For example, steel increased 47% from January 2004 to<br />
January 2005. Prices for copper wire doubled between 2003 and 2006. Pollution control projects<br />
require large quantities of basic commodities, including steel, concrete, and copper. Increased<br />
commodity prices have a significant impact on the cost of large emission control retrofit projects.<br />
30 “Regulatory Impact Analysis for the Final Clean Air Interstate Rule,” U.S. EPA Office of Air and<br />
Radiation, EPA-452/R-05-002, March 2005.<br />
Page A-2
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May 28, 2008<br />
BART Economic Evaluation<br />
Average and incremental cost effectiveness were the two economic criteria considered in the<br />
BART analysis. Effectiveness of a control option is measured in terms of tons of pollutant<br />
emissions removed per year (Eannual). Cost is measured in terms of the total annualized cost<br />
(TAC) associated with the control system. The annual cost effectiveness of a particular control<br />
system (expressed in $/ton) is calculated using the following equation:<br />
Capital Recovery Cost<br />
Average Cost Effectiveness = Eannual / TAC<br />
One important component of the TAC is the annualized cost to recover the initial capital<br />
investment, termed the Capital Recovery Cost (CRC). CRC is a function of the total capital<br />
investment, an assumed interest rate, and the estimated economic life of the control equipment.<br />
Total Capital Investment<br />
Total Capital Investment (TCI) includes all costs required to purchase equipment needed<br />
for the control system, and includes the purchased equipment cost plus direct installation<br />
costs (such as foundations and supports, erection, electrical, and piping), and indirect<br />
capital costs (such as engineering, contractor fees, performance testing and<br />
contingencies).<br />
To calculate the CRC, the equivalent uniform annual cash flow (EUAC) method was used to<br />
annualize the total capital investment. Using the EUAC method, the CRC is determined by<br />
multiplying the TCI by a capital recovery factor (CRF), as shown in the following equation:<br />
CRC = Capital Recovery Factor (CRF) x TCI<br />
The product of the TCI and CRF gives a uniform end-of-year payment necessary to repay the<br />
initial capital investment in "n" years at an interest rate of "i".<br />
The CRF is calculated using the following equation:<br />
n<br />
i * (1 + i)<br />
CRF =<br />
n<br />
(1 + i) −1<br />
Where:<br />
i = interest rate; and<br />
n = economic life of the emission control system<br />
Total Annual Cost<br />
The Total Annual Cost (TAC) is comprised of the following elements: capital recovery costs<br />
(CRC), direct O&M costs (DC), indirect operating costs (IC), and recovery credits (RC) as<br />
follows:<br />
TAC = CRC + DC + IC - RC<br />
Page A-3
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Direct O&M costs are those costs that tend to be proportional to the quantity of exhaust gas<br />
processed by the control system. These may include costs for catalysts, utilities (steam,<br />
electricity, and water), waste treatment and disposal, maintenance materials, replacement parts,<br />
and operating and maintenance labor. Of these direct O&M costs, costs for catalysts, utilities,<br />
waste treatment, and disposal are variable. Emission allowance costs associated with certain<br />
regulatory programs may also be represented as a variable O&M costs, but have not been<br />
included in this cost estimate. Labor costs, maintenance materials and replacement parts are<br />
semi-variable direct costs as they are only partly dependent upon the exhaust flow rate.<br />
Indirect or “Fixed" annual costs are those whose values are totally independent of the exhaust<br />
flow rate and, in fact, would be incurred even if the control system were shut down. They include<br />
such categories as administrative charges, property taxes, and insurance, and include the capital<br />
recovery cost.<br />
The direct and indirect annual costs are offset by recovery credits, taken for materials or energy<br />
recovered by the control system, which may be sold, recycled to the process, or reused elsewhere<br />
at the site.<br />
Summary<br />
In summary, the following methodology was used to calculate the cost effectiveness of various<br />
pollution control systems.<br />
1. The effectiveness of each control system, in terms of annual reduction of pollutant<br />
emissions, was calculated.<br />
2. The Total Capital Investment required for each control system was estimated.<br />
3. The Capital Recovery Cost of each control system was calculated based on an assumed<br />
interest rate and estimated economic life of 20 years for the control equipment.<br />
4. The Total Annualized Cost of each control system was calculated based on the Capital<br />
Recovery Cost and Annual Operating Costs.<br />
5. The Annual Control Effectiveness, in terms of Total Annualized Costs divided by<br />
annual emission reductions, was calculated for each control system.<br />
BART economic evaluations were prepared for the following control systems:<br />
NOx Control Cost Summary<br />
- Combustion Controls (LNB/OFA)<br />
- Combustion Controls plus Selective Catalytic Reduction (SCR)<br />
SO2 Control Cost Summary<br />
- Dry FGD (Spray Dry Absorber)<br />
- Wet FGD<br />
Page A-4
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May 28, 2008<br />
MUSKOGEE GENERATING STATION UNITS 4 & 5<br />
NOx CONTROL SUMMARY<br />
Control Technology<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5 Unit<br />
Design Heat Input: 5,480 5,480 mmBtu/hr<br />
Net Capacity: 532 532 MW<br />
Capacity Factor 90% 90%<br />
Maximum Hours/year: 8,760 8,760 hours<br />
<strong>Muskogee</strong> 4<br />
Expected Emission<br />
Rate<br />
Expected<br />
Emissions<br />
Expected<br />
Emissions<br />
Reduction<br />
BART Economic Evaluation<br />
NOx Summary<br />
Total Capital<br />
Requirement<br />
Page A-5<br />
Annual Capital Recovery<br />
Cost<br />
Total Annual<br />
Operating Costs Total Annual Costs<br />
Average Control<br />
Efficiency<br />
Incremental Control<br />
Efficiency<br />
(lb/mmBtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton) ($/ton)<br />
Baseline Emissions 0.495 10,693 NA<br />
Alternative 1: LNB / OFA 0.150 3,240 7,453 $14,113,700 $1,211,100 $880,700 $2,091,800 $281 --<br />
Alternative 2: LNB/OFA + SCR 0.070 1,512 9,181 $193,077,000 $16,568,000 $14,227,600 $30,795,600 $3,354 16,611<br />
Note: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR.<br />
Control Technology<br />
<strong>Muskogee</strong> 5<br />
Expected Emission Expected<br />
Expected<br />
Emissions Total Capital Annual Capital Recovery Total Annual<br />
Average Control Incremental Control<br />
Rate<br />
Emissions Reduction Requirement<br />
Cost<br />
Operating Costs Total Annual Costs Efficiency Efficiency<br />
(lb/MMBtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton) ($/ton)<br />
Baseline Emissions 0.522 11,276 NA<br />
Notes<br />
Assuming 90% capacity factor for cost evaluations.<br />
Alternative 1: LNB / OFA 0.150 3,240 8,036 $14,113,700 $1,211,100 $880,700 $2,091,800 $260 --<br />
Alternative 2: LNB/OFA + SCR 0.070 1,512 9,764 $193,077,000 $16,568,000 $14,227,600 $30,795,600 $3,154 16,611<br />
Note 1: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR.<br />
Note 2: 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<br />
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<br />
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<br />
limits, which are averaged over a longer period of time.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – NOx<br />
Retrofit Control Technologies – Capital Cost Summary<br />
MUSKOGEE GENERATING STATION UNITS 4 & 5<br />
Capital Cost Worksheet<br />
1 x 572 MW-gross 1 x 572 MW-gross<br />
Case<br />
PC Boiler PC Boiler<br />
Gross Plant Output (MW-gross) MW-gross 572.0 572.0<br />
Net Plant Output (MW-net) MW-net 532.0 532.0<br />
Maximum Heat Input (mmBtu/hr) mmBtu/hr 5,480 5,480<br />
Uncontrolled NOx Emission Rate (lb/mmBtu) lb/mmBtu 0.495 0.522<br />
Capacity Factor Used for Cost Estimates (%) % 90% 90%<br />
Capital Cost Recovery Factor Equipment Life years 25 25<br />
Capital Cost Estimates were based on detailed cost estimates recently prepared for similar projects. Capital costs were<br />
compared to U.S.EPA's Coal Utility Environmental Cost (CUECost) Workbook, modified to account for recent increases in<br />
purchased equipment costs and commodity costs. Estimates were also compared to vendor quotes provided on recent similar<br />
projects.<br />
Low NOX Burner Technology Capital Costs<br />
Page A-6<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5<br />
Cost Basis (Year) 2008 2008<br />
Total Capital Requirement with Retrofit (TCR) $ $14,113,700 $14,113,700<br />
SCR Capital Costs<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5<br />
Cost Basis (Year) 2008 2008<br />
SCR Area $2,023,000 $2,023,000<br />
Civil/Site Work $620,000 $620,000<br />
Flue <strong>Gas</strong> System/Ductwork $32,331,000 $32,331,000<br />
Modifications $5,273,000 $5,273,000<br />
Pipe Rack $7,751,000 $7,751,000<br />
Miscellaneous Mechanical Items $1,101,000 $1,101,000<br />
Urea to Ammonia System $4,904,000 $4,904,000<br />
Booster Fans $5,329,000 $5,329,000<br />
Allowance for Additional Cranes $873,000 $873,000<br />
<strong>Electric</strong>al Modifications $11,336,000 $11,336,000<br />
Equipment Capital Cost Subtotal $ $71,541,000 $71,541,000<br />
Instruments & Controls $ $1,430,800 $1,430,800<br />
Taxes $ $4,292,500 $4,292,500<br />
Freight $ $3,577,100 $3,577,100<br />
Total Direct Cost $80,841,400 $80,841,400<br />
Other Costs<br />
Total Direct Cost with Retrofit Factor $ $97,009,700 $97,009,700<br />
General Facilities $ $4,850,500 $4,850,500<br />
Engineering Fees $ $9,701,000 $9,701,000<br />
Contingency $ $19,401,900 $19,401,900<br />
EPC Fee (20% of total Cost) $19,401,900 $19,401,900<br />
Total Plant Cost (TPC) $ $150,365,000 $150,365,000<br />
Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $154,876,000 $154,876,000<br />
Allow. for Funds During Constr. (AFDC) $ $12,607,000 $12,607,000<br />
Preproduction Costs $ $3,345,300 $3,345,300<br />
Inventory Capital<br />
Initial Ammonia (60 days) $ $87,000 $87,000<br />
Initial Catalyst $ $8,048,000 $8,048,000<br />
Total Capital Requirement (TCR) $ $178,963,300 $178,963,300<br />
Total Capital Requirement ($/kW-gross) $/kW-gross $313 $313<br />
Total Capital Requirement ($/kW-net) $/kW-net $336 $336
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
MUSKOGEE GENERATING STATION UNITS 4 & 5<br />
BART COST EVALUATION - LOW NOx BURNER WORKSHEET<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5<br />
Gross Plant Output (MW-gross) 572 572<br />
Net Plant Output (MW-net) 532 532<br />
Maximum Heat Input (mmBtu/hr) 5,480 5,480<br />
Uncontrolled NOx Emission Rate (lb/mmBtu) 0.495 0.522<br />
Post Low Nox Burner Emission Rate (lb/mmBtu) 0.150 0.150<br />
Capacity Factor used of Cost Estimates (%) 90% 90%<br />
Capital Cost Recovery Factor Equipment Life 25<br />
CAPITAL COSTS<br />
BART Economic Evaluation – NOx<br />
LNB/OFA Combustion Details<br />
Total Capital Requirement (TCR) $14,113,700 $14,113,700<br />
Total Capital Investment ($/kW - net) $27 $27<br />
Capital Recovery Factor = i(1+ i) n / (1 + i) n See, Input Sheet. TCR includes all costs required to purchase and install control equipment, including<br />
materials, labor, site preparation, engineering, contingencies, and retrofit costs.<br />
- 1<br />
Annualized Capital Costs<br />
0.0858 0.0858 EPA Air Pollution Control Cost Manual 6th Ed., page 2-21.<br />
(Capital Recover Factor x Total Capital Investment) $1,211,100 $1,211,100 7% Assumed pretax marginal rate of return on private investment.<br />
OPERATING & MAINTENANCE COSTS<br />
Variable O&M Costs<br />
Basis<br />
Ammonia Reagent Cost $0 $0 Assumed no variable O&M costs with the LNB/OFA retrofit control system.<br />
Catalyst Replacement Cost $0 $0<br />
Auxiliary Power Cost $0 $0<br />
Total Variable O&M Cost $0 $0<br />
Fixed O&M Costs<br />
Additional Operators per shift 0.00 0.00 Assumed no additional operators needed for the LNB/OFA retrofit control system.<br />
Operating Labor<br />
Maintenance Labor $112,900 $112,900 0.80% CUECost Maintenance Labor Default for emission control systems (0.8%/yr * Total Plant Cost)<br />
Maintenance Materials $169,400 $169,400 1.20% CUECost Maintenance Default Factor for control systems (1.2% of installed cost).<br />
Control, Administration, Overhead $33,900 $33,900 30% of Maintenance Labor Cost (CUECost Default of control systems)<br />
Total Fixed O&M Costs $316,200 $316,200<br />
Indirect Operating Cost<br />
Property Taxes $141,100 $141,100 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.<br />
Insurance $141,100 $141,100 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.<br />
Administration $282,300 $282,300 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.<br />
Total Indirect Operating Cost $564,500 $564,500<br />
Total Annual Operating Cost $880,700 $880,700<br />
TOTAL ANNUAL COST<br />
Annualized Capital Cost $1,211,100 $1,211,100<br />
Annual Operating Cost $880,700 $880,700<br />
Total Annual Cost $2,091,800 $2,091,800<br />
Page A-7<br />
Basis
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
MUSKOGEE GENERATING STATION UNITS 4 & 5<br />
BACT COST EVALUATION - SCR WORKSHEET<br />
<strong>Muskogee</strong> 4 <strong>Muskogee</strong> 5<br />
Gross Plant Output (MW-gross) 572.0 572.0<br />
Net Plant Output (MW-net) 532.0 532.0<br />
Maximum Heat Input (mmBtu/hr) 5,480 5,480<br />
Post Boiler NOx Emission Rate (lb/mmBtu) 0.15 0.15<br />
PostSCR NOx Emission Rate (lb/mmBtu) 0.07 0.07<br />
Capacity Factor used of Cost Estimates (%) 90% 90%<br />
Capital Cost Recovery Factor Equipment Life (years) 25<br />
BART Economic Evaluation – NOx<br />
SCR Details<br />
Cost Cost<br />
CAPITAL COSTS [$] [$] Basis<br />
Total Capital Requirement (TCR) $ 178,963,300 $ 178,963,300<br />
Total Capital Investment ($/kW-net) $336 $ 336<br />
Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.0858 0.0858 EPA Air Pollution Control Cost Manual 6th Ed., page 2-21.<br />
Annualized Capital Costs<br />
(Capital Recover Factor x Total Capital Investment) $15,356,900 $15,356,900 7% Assumed pretax marginal rate of return on private investment.<br />
OPERATING COSTS Basis<br />
Operating & Maintenance Costs (based on 90% capacity factor)<br />
Variable O&M Costs<br />
Ammonia Reagent Cost $272,900 $272,900 $ 370<br />
Page A-8<br />
Based on maximum heat input, NOx removal rate (lb/hr), NH2/N2 ratio of approximately 1.1, 90%<br />
capacity factor, and $370/ton reagent cost.<br />
Catalyst Replacement Cost $1,701,700 $1,701,700 $ 7,000 Based on 1.7 M 3 catalyst per MW-gross, 4 year catalyst life, and $7,000/M 3 catalyst cost.<br />
Based on 9" pressure drop across the SCR, 0.065 MWh/inch auxiliary power requirement, and<br />
Auxiliary Power Cost $869,000 $869,000 $ 32 $32/MWh.<br />
Total Variable O&M Cost $2,843,600 $2,843,600<br />
Fixed O&M Costs<br />
Additional Operators per shift 1.00 1.00 Based on S&L O&M estimate for SCR control system.<br />
3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an annual operator<br />
Operating Labor $293,500 $293,500 salary of $70,000/year.<br />
Supervisory Labor $44,000 $44,000 15.0% of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page 2-31.<br />
Maintenance Materials $2,684,400 $2,684,400 1.5% CUECost Maintenance Default Factor for SCR (1.5% of installed cost).<br />
Maintenance Labor $322,900 $322,900 110.0% of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page 2-31.<br />
Total Fixed O&M Cost $3,344,800 $3,344,800<br />
Indirect Operating Cost<br />
Property Taxes $1,789,600 $1,789,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.<br />
Insurance $1,789,600 $1,789,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.<br />
Administration $3,579,300 $3,579,300 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.<br />
Total Indirect Operating Cost $7,158,500 $7,158,500<br />
Total Annual Operating Cost $13,346,900 $13,346,900<br />
TOTAL ANNUAL COST<br />
Annualized Capital Cost $15,356,900 $15,356,900<br />
Annual Operating Cost $13,346,900 $13,346,900<br />
Total Annual Cost $28,703,800 $28,703,800<br />
See, Input Sheet. TCR includes all costs required to purchase and install control equipment,<br />
including materials, labor, site preparation, engineering, contingencies, and retrofit costs.
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
MUSKOGEE STATION UNIT 4<br />
SO2 CONTROL SUMMARY<br />
Pollutant: SO2 Unit<br />
Design Heat Input: 5,480 mmBtu/hr<br />
Capacity Factor 90% %<br />
Maximum Hours/year: 8,760 hours<br />
Control Technology<br />
Expected Emission Expected<br />
Expected<br />
Emissions<br />
Rate<br />
Emissions Reduction<br />
(lb/MMBtu) (ton/year) (ton/year)<br />
Baseline Emissions 0.80 17,282<br />
Alternative 1: DFGD-SDA 0.10 2,160 15,122<br />
Alternative 2: WFGD 0.08 1,728 15,554<br />
Baseline Emissions<br />
BART Economic Evaluation<br />
SO2 Summary – <strong>Muskogee</strong> Unit 4<br />
0<br />
Tons of SO2 Total Capital Annual Capital Total Annual<br />
Average Control Incremental<br />
Control Technology Emissions Removed Requirement Recovery Cost Operating Costs Total Annual Costs Efficiency Control Efficiency<br />
(tpy) (tpy) ($) ($/year) ($/year) ($) ($/ton) ($/ton)<br />
Alternative 1: DFGD-SDA<br />
Alternative 2: WFGD<br />
17,282<br />
2,160<br />
1,728<br />
15,122<br />
15,554<br />
Notes<br />
Design heat input was held constant for both FGD control technologies. Net plant output will<br />
decrease with the wet FGD system due to increased auxiliary power requirements.<br />
Assumed 90% capacity factor for cost evaluations.<br />
$372,609,000 $31,973,800 $38,630,200 $70,604,000 $4,669<br />
$417,788,000 $35,850,600 $41,204,700 $77,055,300 $4,954<br />
Page A-9<br />
$<br />
14,934
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – SO2<br />
Retrofit Control Technology – Capital Cost Summary – <strong>Muskogee</strong> Unit 4<br />
Page A-10
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – SO2<br />
Dry FGD Control System – <strong>Muskogee</strong> Unit 4<br />
EQUIPMENT CAPITAL COSTS<br />
Basis<br />
Total Purchased Equipment Cost (PEC)<br />
General Facilities<br />
Engineering Fees<br />
$270,087,000<br />
$27,009,000<br />
$27,009,000<br />
Contingency $54,017,000<br />
Total Plant Cost $378,122,000<br />
Total Plant Cost (TPC) w/ Prime Contractor's Markup $389,466,000<br />
Total Cash Expended (TCE) $330,579,000<br />
Allow. for Funds During Constr. (AFDC) $32,661,000<br />
Total Plant Investment (TPI) $363,240,000<br />
Preproduction Costs $9,324,000<br />
Inventory Capital $45,000<br />
Total Capital Requirement (TCR) $372,609,000<br />
Total Capital Investment ($/kW - gross) $651<br />
Capital Recovery Factor = i(1+ i) n / (1 + i) n <strong>Muskogee</strong> Unit 4<br />
Equipment capital costs were based on U.S.EPA's Coal Utility<br />
Environmental Cost (CUECost) Worksheet, using Sooner specific fuel<br />
specifications and boiler configuration.<br />
Total Capital Requirements were calculated using U.S.EPA's CUECost<br />
Worksheet, modified to account for recent increases in equipment costs and<br />
commodities. Costs were compared to vendor quotes provided on other<br />
recent similar projects. TCR includes all costs required to purchase<br />
equipment, costs of labor and materials for installing teh equipment, costs for<br />
site preparation and buildings, and retrofit costs.<br />
- 1<br />
Annualized Capital Costs<br />
0.0858 25 years.<br />
(Capital Recover Factor x Total Capital Investment) $31,973,800 7% Assumed pretax marginal rate of return on private investment.<br />
OPERATING COSTS<br />
Operating & Maintenance Costs<br />
Variable O&M Costs<br />
Basis<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry,<br />
Lime Reagent Cost $4,410,400 $ 200 90% CaO, 90% capacity factor, and $200/ton for lime.<br />
Water Cost $276,000 $ 1.20 Based on 0.85 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity<br />
factor, and $30/ton on-site disposal cost. Disposal cost only includes FGD<br />
FGD Waste Disposal Cost $964,000 $ 30 by-products and does not include fly ash.<br />
Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5<br />
for pulse jet baghouse, $2.85/ft2 bag cost (including fabric and hangers), 4%<br />
Bag and Cage Replacement Costs $581,300 $ 2.85 contingency for bag cleaning, and 3 year bag life.<br />
Assumed no increase in ash disposal with the fabric filter compared to the<br />
Ash Disposal Costs $0<br />
existing ESP control system.<br />
Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5%<br />
Auxiliary Power Cost $3,044,000 $ 45 (gross) for the baghouse, 90% capacity factor, and $45/MW.<br />
Total Variable O&M Costs $9,275,700<br />
Fixed O&M Costs<br />
Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.<br />
3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal<br />
Operating Labor $586,900<br />
to an annual operator salary of $70,000/year.<br />
Supervisor Labor $88,000 15.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Maintenance Default Factor for lime spray dryer from EPA's Coal Utility<br />
Maintenance Materials $13,504,400 5.0% Environmental Cost (CUECost) Workbook.<br />
Maintenance Labor $645,600 110.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Total Fixed O&M Cost $14,824,900<br />
Indirect Operating Cost<br />
Property Taxes<br />
Insurance<br />
Administration<br />
$3,632,400<br />
$3,632,400<br />
$7,264,800<br />
1%<br />
Calculated as % of total capital investment (EPA Air Pollution Control Cost<br />
1%<br />
Manual 6th Ed., page 2-34).<br />
2%<br />
Total Indirect Operating Cost $14,529,600<br />
Total Annual Operating Cost $38,630,200<br />
TOTAL ANNUAL COST<br />
Annualized Capital Cost $31,973,800<br />
Annual Operating Cost $38,630,200<br />
Total Annual Cost $70,604,000<br />
Page A-11
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – SO2<br />
Wet FGD Control System – <strong>Muskogee</strong> Unit 4<br />
CAPITAL COSTS<br />
Basis<br />
Total Purchased Equipment Cost (PEC)<br />
General Facilities<br />
Engineering Fees<br />
$302,835,000<br />
$30,284,000<br />
$30,284,000<br />
Contingency $60,567,000<br />
Total Plant Cost $423,970,000<br />
Total Plant Cost (TPC) w/ Prime Contractor's Markup $436,689,000<br />
Total Cash Expended (TCE) $370,662,000<br />
Allow. for Funds During Constr. (AFDC) $36,621,000<br />
Total Plant Investment (TPI) $407,283,000<br />
Preproduction Costs $10,455,000<br />
Inventory Capital $50,000<br />
Total Capital Requirement (TCR) $417,788,000<br />
Total Capital Investment ($/kW - gross) $730<br />
Capital Recovery Factor = i(1+ i) n / (1 + i) n <strong>Muskogee</strong> Unit 4<br />
Equipment capital costs were based on U.S.EPA's Coal Utility<br />
Environmental Cost (CUECost) Worksheet, using Sooner specific fuel<br />
specifications and boiler configuration.<br />
Total Capital Requirements were calculated using U.S.EPA's CUECost<br />
Worksheet, modified to account for recent increases in equipment costs and<br />
commodities. Costs were compared to vendor quotes provided on other<br />
recent similar projects. TCR includes all costs required to purchase<br />
equipment, costs of labor and materials for installing teh equipment, costs for<br />
site preparation and buildings, and retrofit costs.<br />
- 1<br />
Annualized Capital Costs<br />
0.0858 25 years.<br />
(Capital Recover Factor x Total Capital Investment) $35,850,600 7% Assumed pretax marginal rate of return on private investment.<br />
OPERATING COSTS Basis<br />
Operating & Maintenance Costs (based on 90% capacity factor)<br />
Variable O&M Costs<br />
Limestone Reagent Cost $742,600 $ 25<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 1.05 stoichiometry,<br />
95% CaCO3, 90% capacity factor, and $25/ton for limestone.<br />
Water Cost $405,900 $ 1.20 Based on 1.25 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal.<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity<br />
factor, forced oxidation 90% dry, and $30/ton on-site disposal cost. Disposal<br />
cost only includes additional WFGD by-products and does not include fly<br />
FGD Waste Disposal Cost $1,416,000 $ 30 ash. No credit is assumed for by-product sales.<br />
Based on auxiliary power requirement of 2% (gross), 90% capacity factor,<br />
Auxiliary Power Cost $4,566,000 $ 45 and $45/MW.<br />
Total Variable O&M Costs $7,130,500<br />
Fixed O&M Costs<br />
Additional Operators per shift 4.0 Based on S&L O&M estimate for wet FGD.<br />
3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal<br />
Operating Labor $1,173,800<br />
to an annual operator salary of $70,000/year.<br />
Supervisor Labor $176,100 15.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Maintenance Materials $15,141,800<br />
Maintenance Default Factor for limestone scrubber with forced oxidation<br />
5.0% from EPA's Coal Utility Environmental Cost (CUECost) Workbook.<br />
Maintenance Labor $1,291,200 110.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Total Fixed O&M Cost $17,782,900<br />
Indirect Operating Cost<br />
Property Taxes<br />
Insurance<br />
Administration<br />
$4,072,800<br />
$4,072,800<br />
$8,145,700<br />
1%<br />
Calculated as % of total capital investment (EPA Air Pollution Control Cost<br />
1%<br />
Manual 6th Ed., page 2-34).<br />
2%<br />
Total Indirect Operating Cost $16,291,300<br />
Total Annual Operating Cost $41,204,700<br />
TOTAL ANNUAL COST<br />
Annualized Capital Cost $35,850,600<br />
Annual Operating Cost $41,204,700<br />
Total Annual Cost $77,055,300<br />
Page A-12
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation<br />
SO2 Summary – <strong>Muskogee</strong> Unit 5<br />
Page A-10
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – SO2<br />
Retrofit Control Technology – Capital Cost Summary – <strong>Muskogee</strong> Unit 5<br />
Page A-10
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – SO2<br />
Dry FGD Control System – <strong>Muskogee</strong> Unit 5<br />
EQUIPMENT CAPITAL COSTS<br />
Basis<br />
Total Purchased Equipment Cost (PEC)<br />
General Facilities<br />
Engineering Fees<br />
$270,447,000<br />
$27,045,000<br />
$27,045,000<br />
Contingency $54,089,000<br />
Total Plant Cost $378,626,000<br />
Total Plant Cost (TPC) w/ Prime Contractor's Markup $389,985,000<br />
Total Cash Expended (TCE) $331,019,000<br />
Allow. for Funds During Constr. (AFDC) $32,705,000<br />
Total Plant Investment (TPI) $363,724,000<br />
Preproduction Costs $9,337,000<br />
Inventory Capital $45,000<br />
Total Capital Requirement (TCR) $373,106,000<br />
Total Capital Investment ($/kW - gross) $652<br />
Capital Recovery Factor = i(1+ i) n / (1 + i) n <strong>Muskogee</strong> Unit 5<br />
Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost<br />
(CUECost) Worksheet, using Sooner specific fuel specifications and boiler<br />
configuration.<br />
Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet,<br />
modified to account for recent increases in equipment costs and commodities.<br />
Costs were compared to vendor quotes provided on other recent similar projects.<br />
TCR includes all costs required to purchase equipment, costs of labor and<br />
materials for installing teh equipment, costs for site preparation and buildings, and<br />
retrofit costs.<br />
- 1<br />
Annualized Capital Costs<br />
0.0858 25 years.<br />
(Capital Recover Factor x Total Capital Investment) $32,016,400 7% Assumed pretax marginal rate of return on private investment.<br />
OPERATING COSTS<br />
Operating & Maintenance Costs<br />
Variable O&M Costs<br />
Basis<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 90%<br />
Lime Reagent Cost $4,725,500 $ 200 CaO, 90% capacity factor, and $200/ton for lime.<br />
Water Cost $276,000 $ 1.20 Based on 0.85 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, and<br />
$30/ton on-site disposal cost. Disposal cost only includes FGD by-products and<br />
FGD Waste Disposal Cost $1,032,900 $ 30 does not include fly ash.<br />
Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 for<br />
pulse jet baghouse, $2.85/ft2 bag cost (including fabric and hangers), 4%<br />
Bag and Cage Replacement Costs $581,300 $ 2.85 contingency for bag cleaning, and 3 year bag life.<br />
Assumed no increase in ash disposal with the fabric filter compared to the existing<br />
Ash Disposal Costs $0<br />
ESP control system.<br />
Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% (gross)<br />
Auxiliary Power Cost $3,044,000 $ 45 for the baghouse, 90% capacity factor, and $45/MW.<br />
Total Variable O&M Costs $9,659,700<br />
Fixed O&M Costs<br />
Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.<br />
3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an<br />
Operating Labor $586,900<br />
annual operator salary of $70,000/year.<br />
Supervisor Labor $88,000 15.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Maintenance Default Factor for lime spray dryer from EPA's Coal Utility<br />
Maintenance Materials $13,522,400 5.0% Environmental Cost (CUECost) Workbook.<br />
Maintenance Labor $645,600 110.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Total Fixed O&M Cost $14,842,900<br />
Indirect Operating Cost<br />
Property Taxes<br />
Insurance<br />
Administration<br />
$3,637,200<br />
$3,637,200<br />
$7,274,500<br />
1%<br />
Calculated as % of total capital investment (EPA Air Pollution Control Cost<br />
1%<br />
Manual 6th Ed., page 2-34).<br />
2%<br />
Total Indirect Operating Cost $14,548,900<br />
Total Annual Operating Cost $39,051,500<br />
TOTAL ANNUAL COST<br />
Annualized Capital Cost $32,016,400<br />
Annual Operating Cost $39,051,500<br />
Total Annual Cost $71,067,900<br />
Page A-11
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
BART Economic Evaluation – SO2<br />
Wet FGD Control System – <strong>Muskogee</strong> Unit 5<br />
CAPITAL COSTS<br />
Basis<br />
Total Purchased Equipment Cost (PEC)<br />
General Facilities<br />
Engineering Fees<br />
$303,400,000<br />
$30,340,000<br />
$30,340,000<br />
Contingency $60,680,000<br />
Total Plant Cost $424,760,000<br />
Total Plant Cost (TPC) w/ Prime Contractor's Markup $437,503,000<br />
Total Cash Expended (TCE) $371,353,000<br />
Allow. for Funds During Constr. (AFDC) $36,690,000<br />
Total Plant Investment (TPI) $408,043,000<br />
Preproduction Costs $10,474,000<br />
Inventory Capital $50,000<br />
Total Capital Requirement (TCR) $418,567,000<br />
Total Capital Investment ($/kW - gross) $732<br />
Capital Recovery Factor = i(1+ i) n / (1 + i) n <strong>Muskogee</strong> Unit 5<br />
Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost<br />
(CUECost) Worksheet, using Sooner specific fuel specifications and boiler<br />
configuration.<br />
Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet,<br />
modified to account for recent increases in equipment costs and commodities.<br />
Costs were compared to vendor quotes provided on other recent similar projects.<br />
TCR includes all costs required to purchase equipment, costs of labor and<br />
materials for installing teh equipment, costs for site preparation and buildings, and<br />
retrofit costs.<br />
- 1<br />
Annualized Capital Costs<br />
0.0858 25 years.<br />
(Capital Recover Factor x Total Capital Investment) $35,917,500 7% Assumed pretax marginal rate of return on private investment.<br />
OPERATING COSTS<br />
Operating & Maintenance Costs (based on 90% capacity factor)<br />
Variable O&M Costs<br />
Basis<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 1.05 stoichiometry, 95%<br />
Limestone Reagent Cost $794,100 $ 25 CaCO3, 90% capacity factor, and $25/ton for limestone.<br />
Water Cost $405,900 $ 1.20 Based on 1.25 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal.<br />
Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor,<br />
forced oxidation 90% dry, and $30/ton on-site disposal cost. Disposal cost only<br />
includes additional WFGD by-products and does not include fly ash. No credit is<br />
FGD Waste Disposal Cost $1,514,000 $ 30 assumed for by-product sales.<br />
Based on auxiliary power requirement of 2% (gross), 90% capacity factor, and<br />
Auxiliary Power Cost $4,566,000 $ 45 $45/MW.<br />
Total Variable O&M Costs $7,280,000<br />
Fixed O&M Costs<br />
Additional Operators per shift 4.0 Based on S&L O&M estimate for wet FGD.<br />
3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an<br />
Operating Labor $1,173,800<br />
annual operator salary of $70,000/year.<br />
Supervisor Labor $176,100 15.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Maintenance Default Factor for limestone scrubber with forced oxidation from<br />
Maintenance Materials $15,170,000 5.0% EPA's Coal Utility Environmental Cost (CUECost) Workbook.<br />
Maintenance Labor $1,291,200 110.0% of operating labor. EPA Control Cost Manual, page 2-31<br />
Total Fixed O&M Cost $17,811,100<br />
Indirect Operating Cost<br />
Property Taxes<br />
Insurance<br />
Administration<br />
$4,080,400<br />
$4,080,400<br />
$8,160,900<br />
1%<br />
Calculated as % of total capital investment (EPA Air Pollution Control Cost<br />
1%<br />
Manual 6th Ed., page 2-34).<br />
2%<br />
Total Indirect Operating Cost $16,321,700<br />
Total Annual Operating Cost $41,412,800<br />
TOTAL ANNUAL COST<br />
Annualized Capital Cost $35,917,500<br />
Annual Operating Cost $41,412,800<br />
Total Annual Cost $77,330,300<br />
Page A-12
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong><br />
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong> – BART Determination<br />
May 28, 2008<br />
Attachment B<br />
<strong>Muskogee</strong> Units 4 & 5<br />
BART Determination – Visibility Impact Modeling Details<br />
Page B-1
CALPUFF MODELING REPORT � BART DETERMINATION<br />
OKLAHOMA GAS & ELECTRIC<br />
MUSKOGEE GENERATING STATION<br />
Prepared by:<br />
TRINITY CONSULTANTS<br />
120 East Sheridan<br />
Suite 205<br />
<strong>Oklahoma</strong> City, OK 73104<br />
(405) 228-3292<br />
March 17, 2008<br />
Project 083701.0004
TABLE OF CONTENTS<br />
1. INTRODUCTION.................................................................................................... 1-1<br />
1.1 BEST AVAILABLE RETROFIT TECHNOLOGY RULE BACKGROUND......................... 1-1<br />
1.2 MODELING PROTOCOL BACKGROUND .................................................................. 1-2<br />
1.3 OBJECTIVE ............................................................................................................ 1-2<br />
1.4 LOCATION OF SOURCES AND RELEVANT CLASS I AREAS...................................... 1-2<br />
2. CALPUFF MODEL SYSTEM ............................................................................... 2-1<br />
2.1 MODEL VERSIONS................................................................................................. 2-1<br />
2.2 MODELING DOMAIN ............................................................................................. 2-1<br />
3. CALMET............................................................................................................ 3-1<br />
3.1 GEOPHYSICAL DATA............................................................................................. 3-1<br />
3.1.1 TERRAIN DATA ...................................................................................................3-1<br />
3.1.2 LAND USE DATA.................................................................................................3-2<br />
3.1.3 COMPILING TERRAIN AND LAND USE DATA.......................................................3-3<br />
3.2 METEOROLOGICAL DATA ..................................................................................... 3-3<br />
3.2.1 MESOSCALE MODEL METEOROLOGICAL DATA .................................................3-3<br />
3.2.2 SURFACE METEOROLOGICAL DATA ...................................................................3-4<br />
3.2.3 UPPER AIR METEOROLOGICAL DATA.................................................................3-5<br />
3.2.4 PRECIPITATION METEOROLOGICAL DATA..........................................................3-7<br />
3.2.5 BUOY METEOROLOGICAL DATA.........................................................................3-8<br />
3.3 CALMET CONTROL PARAMETERS....................................................................... 3-9<br />
3.3.1 VERTICAL METEOROLOGICAL PROFILE..............................................................3-9<br />
3.3.2 INFLUENCES OF OBSERVATIONS .......................................................................3-10<br />
4. CALPUFF........................................................................................................... 4-1<br />
4.1 SOURCE EMISSIONS............................................................................................... 4-1<br />
4.2 RECEPTOR LOCATIONS.......................................................................................... 4-1<br />
4.3 BACKGROUND OZONE AND AMMONIA.................................................................. 4-1<br />
4.4 CALPUFF MODEL CONTROL PARAMETERS......................................................... 4-1<br />
5. CALPOST........................................................................................................... 5-1<br />
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5.1 CALPOST – LIGHT EXTINCTION ALGORITHM ..................................................... 5-1<br />
5.2 CALPOST PROCESSING METHOD......................................................................... 5-2<br />
5.3 NATURAL BACKGROUND ...................................................................................... 5-2<br />
5.4 EVALUATING VISIBILITY RESULTS ....................................................................... 5-2<br />
5.5 SUMMARY OF CALPOST CONTROL PARAMETERS............................................... 5-2<br />
6. VISIBILITY RESULTS ........................................................................................... 6-1<br />
APPENDIX A- METEOROLOGICAL STATIONS<br />
APPENDIX B – SAMPLE CALMET CONTROL FILE<br />
APPENDIX C – SAMPLE CALPUFF CONTROL FILE<br />
APPENDIX D – SAMPLE CALPOST CONTROL FILE<br />
APPENDIX E – MUSKOGEE STATION EMISSION SUMMARY<br />
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LIST OF TABLES<br />
TABLE 1-1. BART-ELIGIBLE SOURCES ...............................................................................................1-2<br />
TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS .......................................1-3<br />
TABLE 2-1. CALPUFF MODELING SYSTEM VERSIONS .....................................................................2-1<br />
TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN..............................3-10<br />
TABLE 5-1. MONTHLY HUMIDITY FACTORS.......................................................................................5-2<br />
TABLE 5-2. DEFAULT AVERAGE ANNUAL NATURAL BACKGROUND LEVELS ...................................5-2<br />
TABLE A-1. LIST OF SURFACE METEOROLOGICAL STATIONS ...........................................................A-1<br />
TABLE A-2. LIST OF UPPER AIR METEOROLOGICAL STATIONS.........................................................A-5<br />
TABLE A-3. LIST OF PRECIPITATION METEOROLOGICAL STATIONS..................................................A-6<br />
TABLE A-4. LIST OF OVER WATER METEOROLOGICAL STATIONS..................................................A-14<br />
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LIST OF FIGURES<br />
FIGURE 1-1. PLOT OF SOURCES AND NEAREST CLASS I AREAS .........................................................1-3<br />
FIGURE 2-1. REFINED METEOROLOGICAL MODELING DOMAIN.........................................................2-2<br />
FIGURE 3-1. PLOT OF LAND ELEVATION USING USGS TERRAIN DATA ............................................3-2<br />
FIGURE 3-2. PLOT OF LAND USE USING USGS LULC DATA.............................................................3-3<br />
FIGURE 3-3. PLOT OF SURFACE STATION LOCATIONS........................................................................3-5<br />
FIGURE 3-4. PLOT OF UPPER AIR STATIONS LOCATIONS ...................................................................3-6<br />
FIGURE 3-5. PLOT OF PRECIPITATION METEOROLOGICAL STATIONS .................................................3-8<br />
FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS ................................................................3-9<br />
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1. INTRODUCTION<br />
<strong>Oklahoma</strong> <strong>Gas</strong> & <strong>Electric</strong> (OG&E) owns and operates three electric generating stations near<br />
<strong>Muskogee</strong>, <strong>Oklahoma</strong> (<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong>), Seminole, <strong>Oklahoma</strong> (Seminole <strong>Generating</strong><br />
<strong>Station</strong>), and Stillwater, <strong>Oklahoma</strong> (Sooner <strong>Generating</strong> <strong>Station</strong>). These generating stations are<br />
considered eligible to be regulated under the U.S. Environmental Protection Agency’s (EPA) <strong>Best</strong><br />
Available Retrofit Technology (BART) provisions of the Regional Haze Rule.<br />
This report summarizes the results of CALPUFF modeling performed for the <strong>Muskogee</strong> <strong>Generating</strong><br />
<strong>Station</strong>. Modeling methodology used in the analysis is described in this report along with final<br />
visibility impact results.<br />
1.1 BEST AVAILABLE RETROFIT TECHNOLOGY RULE BACKGROUND<br />
On July 1, 1999, the U.S. Environmental EPA published the final Regional Haze Rule (RHR). The<br />
objective of the RHR is to improve visibility in 156 specific areas across with United States, known<br />
as Class I areas. The Clean Air Act defines Class I areas as certain national parks (over 6000 acres),<br />
wilderness areas (over 5000 acres), national memorial parks (over 5000 acres), and international<br />
parks that were in existence on August 7, 1977.<br />
On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the BART rule, which<br />
included guidance for making source-specific <strong>Best</strong> Available Retrofit Technology (BART)<br />
determinations. The BART rule defines BART-eligible sources as sources that meet the following<br />
criteria:<br />
(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant,<br />
(2) Began operation between August 7, 1962 and August 7, 1977, and<br />
(3) Are listed as one of the 26 listed source categories in the guidance.<br />
A BART-eligible source is not automatically subject to BART. Rather, BART-eligible sources are<br />
subject-to-BART if the sources are “reasonably anticipated to cause or contribute to visibility<br />
impairment in any federal mandatory Class I area.” EPA has determined that sources are reasonably<br />
anticipated to cause or contribute to visibility impairment if the visibility impacts from a source are<br />
greater than 0.5 deciviews (dv) when compared against a natural background.<br />
Air quality modeling is the tool that is used to determine a source’s visibility impacts. States have the<br />
authority to exempt certain BART-eligible sources from installing BART controls if the results of the<br />
dispersion modeling demonstrate that the source cannot reasonably be anticipated to cause or<br />
contribute to visibility impairment in a Class I area. Further, states also have the authority to define<br />
the modeling procedures for conducting modeling related to making BART determinations.<br />
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1.2 MODELING PROTOCOL BACKGROUND<br />
To promote consistency between states in the development of BART modeling protocols and to<br />
harmonize the approaches between adjacent RPOs, the Central States Regional Air Planning<br />
(CENRAP) organization developed BART Modeling Guidelines (December 15, 2005). The intent of<br />
the guidelines is to assist CENRAP states and source operators in the development of statewide and<br />
source-specific modeling protocols.<br />
1.3 OBJECTIVE<br />
The objective of this document is to provide a protocol summarizing the modeling methods and<br />
procedures that will be followed to conduct a refined CALPUFF modeling analysis for the OG&E<br />
generating stations discussed above. The modeling methods and procedures will be used to determine<br />
appropriate controls for OG&E’s BART-eligible sources that can reasonably be anticipated to reduce<br />
the sources’ effects on or contribution to visibility impairment in the surrounding Class I areas. It is<br />
OG&E’s intent to determine a combination of emissions controls that will reduce the impact of each<br />
generating station to a degree that the 98 th percentile of the visibility impact predicted by the model<br />
due to all the BART eligible sources at each station collectively is below EPA’s recommended<br />
visibility contribution threshold of 0.5 ∆dv.<br />
1.4 LOCATION OF SOURCES AND RELEVANT CLASS I AREAS<br />
The sources listed in Table 1-1 are the sources that have been identified by OG&E as sources that<br />
meet the three criteria for BART-eligible sources at the <strong>Muskogee</strong> <strong>Station</strong>.<br />
TABLE 1-1. BART-ELIGIBLE SOURCES (MUSKOGEE STATION)<br />
EPN Description<br />
Unit 4 5,480 MMBtu/hr Coal Fired Boiler<br />
Unit 5 5,480 MMBtu/hr Coal Fired Boiler<br />
As required in CENRAP’s BART Modeling Guidelines, Class I areas within 300 km of each station<br />
will be included in each analysis. The following tables summarize the distances of the four closest<br />
Class I areas to each station. As seen from this summary, some Class I areas are more than 300 km<br />
from the certain stations. However, in order to demonstrate that each station will not have an adverse<br />
effect on the visibility at any of the four nearest Class I areas, OG&E has opted to include those Class<br />
I areas more than 300 km away in this analysis. Note that the distances listed in the tables below are<br />
the distances between the stations and the closest border of the Class I areas.<br />
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LCC Northing (km)<br />
TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS<br />
CACR HEGL UPBU WIMO<br />
<strong>Muskogee</strong> 180 230 164 324<br />
A plot of the Class I areas with respect to the each station is provided in Figure 1-1.<br />
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Class I Areas<br />
FIGURE 1-1. PLOT OF SOURCES AND NEAREST CLASS I AREAS<br />
WIMO<br />
Sooner <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
HEGL<br />
Seminole <strong>Station</strong><br />
CACR<br />
UPBU<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
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2. CALPUFF MODEL SYSTEM<br />
The main components of the CALPUFF modeling system are CALMET, CALPUFF, and CALPOST.<br />
CALMET is the meteorological model that generates hourly three-dimensional meteorological fields<br />
such as wind and temperature. CALPUFF simulates the non-steady state transport, dispersion, and<br />
chemical transformation of air pollutants emitted from a source in “puffs.” CALPUFF calculates<br />
hourly concentrations of visibility affecting pollutants at each specified receptor in a modeling<br />
domain. CALPOST is the post-processor for CALPUFF that computes visibility impacts from a<br />
source based on the visibility affecting pollutant concentrations that were output by CALPUFF.<br />
2.1 MODEL VERSIONS<br />
The versions of the CALPUFF modeling system programs that are proposed for conducting OG&E’s<br />
BART modeling are listed in Table 2-1.<br />
TABLE 2-1. CALPUFF MODELING SYSTEM VERSIONS<br />
Processor Version Level<br />
TERREL 3.3 030402<br />
CTGCOMP 2.21 030402<br />
CTGPROC 2.63 050128<br />
MAKEGEO 2.2 030402<br />
CALMET 5.53a 040716<br />
CALPUFF 5.8 070623<br />
POSTUTIL 1.3 030402<br />
CALPOST 5.6394 070622<br />
2.2 MODELING DOMAIN<br />
The CALPUFF modeling system utilizes three modeling grids: the meteorological grid, the<br />
computational grid, and the sampling grid. The meteorological grid is the system of grid points at<br />
which meteorological fields are developed with CALMET. The computational grid determines the<br />
computational area for a CALPUFF run. Puffs are advected and tracked only while within the<br />
computational grid. The meteorological grid is defined so that it covers the areas of concern and<br />
gives enough marginal buffer area for puff transport and dispersion. A plot of the proposed<br />
meteorological modeling domain with respect to the Class I areas being modeled is also provided in<br />
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Figure 2-1. The computational domain will be set to extend at least 50 km in all directions beyond<br />
the <strong>Muskogee</strong>, Seminole, and Sooner <strong>Generating</strong> <strong>Station</strong>s and the Class I areas of interest. Note that<br />
the map projection for the modeling domain will be Lambert Conformal Conic (LCC) and the datum<br />
will be the World Geodetic System 84 (WGS-84). The reference point for the modeling domain is<br />
Latitude 40ºN, Longitude 97ºW. The southwest corner will be set to -951.547 km LCC, -1646.637<br />
km LCC corresponding to Latitude 24.813 ºN and Longitude 87.778ºW. The meteorological grid<br />
spacing will be 4 km, resulting in 462 grid points in the X direction and 376 grid points in the Y<br />
direction.<br />
m )<br />
(<br />
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Class I Areas<br />
FIGURE 2-1. REFINED METEOROLOGICAL MODELING DOMAIN<br />
WIMO<br />
Sooner <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
HEGL<br />
Seminole <strong>Station</strong><br />
CACR<br />
UPBU<br />
Computational Modeling Domain 1<br />
Meteorological Modeling Domain<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
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3. CALMET<br />
CALMET is the meteorological processor that compiles meteorological data from raw observations<br />
of surface and upper air conditions, precipitation measurements, mesoscale model output, and<br />
geophysical parameters into a single hourly, gridded data set for input into CALPUFF. CALMET<br />
will be used to assimilate data for 2001- 2003 using National Weather Service (NWS) surface station<br />
observations, upper air station observations, precipitation station observations, buoy station<br />
observations (for overwater areas), and mesoscale model output to develop the meteorological field.<br />
3.1 GEOPHYSICAL DATA<br />
CALMET requires geophysical data to characterize the terrain and land use parameters that<br />
potentially affect dispersion. Terrain features affect flows and create turbulence in the atmosphere<br />
and are potentially subjected to higher concentrations of elevated puffs. Different land uses exhibit<br />
variable characteristics such as surface roughness, albedo, Bowen ratio, and leaf-area index that also<br />
effect turbulence and dispersion.<br />
3.1.1 TERRAIN DATA<br />
Terrain data will be obtained from the United States Geological Survey (USGS) in<br />
1-degree (1:250,000 scale or approximately 90 meter resolution) digital format. The<br />
USGS terrain data will then be processed by the TERREL program to generate grid-cell<br />
elevation averages across the modeling domain. A plot of the land elevations based on the<br />
USGS data for the modeling domain is provided in Figure 3-1.<br />
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L<br />
C<br />
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) m<br />
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-1600<br />
FIGURE 3-1. PLOT OF LAND ELEVATION USING USGS TERRAIN DATA<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting(km)<br />
3.1.2 LAND USE DATA<br />
Sooner <strong>Station</strong><br />
Seminole <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
0<br />
Terrain<br />
Elevation (m)<br />
The land use land cover (LULC) data from the USGS North American land cover<br />
characteristics data base in the Lambert Azimuthal equal area map projection will be used<br />
in order to determine the land use within the modeling domain. The LULC data will be<br />
processed by the CTGPROC program which will generate land use for each grid cell<br />
across the modeling domain. A plot of the land use based on the USGS data for the<br />
modeling domain is provided in Figure 3-2.<br />
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3930<br />
2950<br />
1960<br />
982
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k<br />
) m<br />
-200<br />
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-600<br />
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-1000<br />
-1200<br />
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-1600<br />
FIGURE 3-2. PLOT OF LAND USE USING USGS LULC DATA<br />
Sooner <strong>Station</strong><br />
Seminole <strong>Station</strong><br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
3.1.3 COMPILING TERRAIN AND LAND USE DATA<br />
The terrain data files output by the TERELL program and the LULC files output by the<br />
CTGPROC program will be uploaded into the MAKEGEO program to create a<br />
geophysical data file that will be input into CALMET.<br />
3.2 METEOROLOGICAL DATA<br />
CALMET will be used to assimilate data for 2001, 2002, and 2003 using mesoscale model output and<br />
National Weather Service (NWS) surface station observations, upper air station observations,<br />
precipitation station observations, and National Oceanic and Atmosphere Administrations (NOAA)<br />
buoy station observations to develop the meteorological field.<br />
3.2.1 MESOSCALE MODEL METEOROLOGICAL DATA<br />
<strong>Muskogee</strong> <strong>Station</strong><br />
Hourly mesoscale data will also be used as the initial guess field in developing the<br />
CALMET meteorological data. It is OG&E’s intent to use the following 5 th generation<br />
mesoscale model meteorological data sets (or MM5 data) in the analysis:<br />
• 2001 MM5 data at 12 km resolution generated by the U.S. EPA<br />
• 2002 MM5 data at 36 km resolution generated by the Iowa DNR<br />
10<br />
Land Use<br />
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62.5<br />
45<br />
27.5
• 2003 MM5 data set at 36 km resolution generated by the Midwest RPO<br />
The specific MM5 data that will be used are subsets of the data listed above. As the<br />
contractor to CENRAP for developing the meteorological data sets for the BART<br />
modeling, Alpine Geophysics extracted three subsets of MM5 data for each year from<br />
2001 to 2003 from the data sets listed above using the CALMM5 extraction program. The<br />
three subsets covered the northern, central, and southern portions of CENRAP. TXI is<br />
proposing to use the southern set of the extracted MM5 data.<br />
The 2001 southern subset of the extracted MM5 data includes 30 files that are broken into<br />
10 to 11 day increments (3 files per month). The 2002 and 2003 southern subsets of<br />
extracted MM5 data include 12 files each of which are broken into 30 to 31 day increment<br />
files (1 file per month). Note that the 2001 to 2003 MM5 data extracted by Alpine<br />
Geophysics will not be able to be used directly in the modeling analysis. To run the Alpine<br />
Geophysics extracted MM data in the EPA approved CALMET program, each of the MM5<br />
files will need to be adjusted by appending an additional six (6) hours, at a minimum, to<br />
the end of each file to account for the shift in time zones from the Greenwich Mean Time<br />
(GMT) prepared Alpine Geophysics data to Time Zone 6 for this analysis. No change to<br />
the data will occur.<br />
The time periods covered by the data in each of the MM5 files extracted by Alpine<br />
Geophysics include a specific number of calendar days, where the data starts at Hour 0 in<br />
GMT for the first calendar day and ends at Hour 23 in GMT on the last calendar day. In<br />
order to run CALMET in the local standard time (LST), which is necessary since the<br />
surface meteorological observations are recorded in LST, there must be hours of MM5 data<br />
referenced in a CALMET run that match the LST observation hours. Since the LST hours<br />
in Central Standard Time (CST) are 6 hours behind GMT, it is necessary to adjust the data<br />
in each MM5 file so that the time periods covered in the files match CST.<br />
Based on the above discussion, the Alpine Geophysics MM5 data will not be used directly.<br />
Instead the data files will be modified to add 8 additional hours of data to the end of each<br />
file from the beginning of the subsequent file. CALMET will then be run using the<br />
appended MM5 data to generate a contiguous set of CALMET output files. The converted<br />
MM5 data files occupy approximately 1.2 terabytes (TB) of hard drive space.<br />
3.2.2 SURFACE METEOROLOGICAL DATA<br />
Parameters affecting turbulent dispersion that are observed hourly at surface stations<br />
include wind speed and direction, temperature, cloud cover and ceiling, relative humidity,<br />
and precipitation type. It is OG&E’s intent to use the surface stations listed in Table A-1<br />
of Appendix A. The locations of the surface stations with respect to the modeling domain<br />
are shown in Figure 3-3. The stations were selected from the available data inventory to<br />
optimize spatial coverage and representation of the domain. Data from the stations will be<br />
processed for use in CALMET using EPA’s SMERGE program.<br />
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L C<br />
N o rth (<br />
i<br />
n<br />
g<br />
k<br />
m )<br />
Missing surface data was filled using procedures recommended by U.S. EPA. 1 Missing<br />
data periods of 5 hours or less were replaced using these procedures. For periods greater<br />
than 5 hours, data was left either unfilled or was not used in CALMET processing. A large<br />
enough quantity of surface stations was included in the domain that overlapping areas of<br />
influence allowed data from an alternate station to be used.<br />
-200<br />
-400<br />
-600<br />
-800<br />
-1000<br />
-1200<br />
-1400<br />
-1600<br />
Class I Areas<br />
Surface <strong>Station</strong>s<br />
FIGURE 3-3. PLOT OF SURFACE STATION LOCATIONS<br />
WIMO<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
3.2.3 UPPER AIR METEOROLOGICAL DATA<br />
Sooner <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
HEGL<br />
Seminole <strong>Station</strong><br />
CACR<br />
UPBU<br />
Observations of meteorological conditions in the upper atmosphere provide a profile of<br />
turbulence from the surface through the depth of the boundary layer in which dispersion<br />
occurs. Upper air data are collected by balloons launched simultaneously across the<br />
observation network at 0000 Greenwich Mean Time (GMT) (6 o’clock PM in <strong>Oklahoma</strong>)<br />
1 “Procedures for Substituting Values for Missing NWS Meteorological Data for Use in Regulatory Air Quality<br />
Models”, Dennis Atkinson and Russell F. Lee, July 7, 1992, http://www.epa.gov/scram001/surface/missdata.txt<br />
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LCC Northing (km)<br />
and 1200 GMT (6 o’clock AM in <strong>Oklahoma</strong>). Sensors observe pressure, wind speed and<br />
direction, and temperature (among other parameters) as the balloon rises through the<br />
atmosphere. The upper air observation network is less dense than surface observation<br />
points since upper air conditions vary less and are generally not as affected by local effects<br />
(e.g., terrain or water bodies). The upper air stations that are proposed for this analysis are<br />
listed in Table A-2 of Appendix A. The locations of the upper air stations with respect to<br />
the modeling domain are shown in Figure 3-4. These stations were selected from the<br />
available data inventory to optimize spatial coverage and representation of the domain.<br />
Data from the stations will be processed for use in CALMET using EPA’s READ62<br />
program. Missing upper air data was replaced using a persistence method- the assumption<br />
that data from the preceding or following hours are representative of the missing period.<br />
Data from either the preceding or following hours were extrapolated to fill the missing<br />
hour.<br />
-200<br />
-400<br />
-600<br />
-800<br />
-1000<br />
-1200<br />
-1400<br />
-1600<br />
Class I Areas<br />
Upper Air <strong>Station</strong>s<br />
FIGURE 3-4. PLOT OF UPPER AIR STATIONS LOCATIONS<br />
WIMO<br />
Sooner <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
HEGL<br />
Seminole <strong>Station</strong><br />
CACR<br />
UPBU<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
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3.2.4 PRECIPITATION METEOROLOGICAL DATA<br />
The effects of chemical transformation and deposition processes on ambient pollutant<br />
concentrations will be considered in this analysis. Therefore, it is necessary to include<br />
observations of precipitation in the CALMET analysis. The precipitation stations that are<br />
proposed for this analysis are listed in Table A-3 of Appendix A. The locations of the<br />
precipitation stations with respect to the modeling domain are shown in Figure 3-5. These<br />
stations were selected from the available data inventory to optimize spatial coverage and<br />
representation of the domain. Data from the stations will be processed for use in<br />
CALMET using EPA’s PMERGE program.<br />
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LCC Northing (km)<br />
-200<br />
-400<br />
-600<br />
-800<br />
-1000<br />
-1200<br />
-1400<br />
-1600<br />
Class I Areas<br />
Precipitation <strong>Station</strong>s<br />
FIGURE 3-5. PLOT OF PRECIPITATION METEOROLOGICAL STATIONS<br />
WIMO<br />
Sooner <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
HEGL<br />
Seminole <strong>Station</strong><br />
CACR<br />
UPBU<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
3.2.5 BUOY METEOROLOGICAL DATA<br />
The effects of land/sea breeze on ambient pollutant concentrations will be considered in<br />
this analysis. Therefore, it is necessary to include observations of buoy stations in the<br />
CALMET analysis. The buoy stations that are proposed for this analysis are listed in Table<br />
A-4 of Appendix A. The locations of the buoy stations with respect to the modeling<br />
domain are shown in Figure 3-6. These stations were selected from the available data<br />
inventory to optimize spatial coverage and representation of the domain along the<br />
coastline. Data from the stations will be prepared by filling missing hour records with the<br />
CALMET missing parameter value (9999). No adjustments to the data will occur.<br />
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LCC Northing (km)<br />
-200<br />
-400<br />
-600<br />
-800<br />
-1000<br />
-1200<br />
-1400<br />
-1600<br />
Class I Areas<br />
Buoy <strong>Station</strong>s<br />
FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS<br />
WIMO<br />
Sooner <strong>Station</strong><br />
<strong>Muskogee</strong> <strong>Station</strong><br />
HEGL<br />
Seminole <strong>Station</strong><br />
CACR<br />
UPBU<br />
-800 -600 -400 -200 0 200 400 600 800<br />
LCC Easting (km)<br />
3.3 CALMET CONTROL PARAMETERS<br />
Appendix B provides a sample CALMET input file used in OG&E’s modeling analysis. A few<br />
details of the CALMET model setup for sensitive parameters are also discussed below.<br />
3.3.1 VERTICAL METEOROLOGICAL PROFILE<br />
The height of the top vertical layer will be set to 3,500 meters. This height corresponds to<br />
the top sounding pressure level for which upper air observation data will be relied upon.<br />
The vertical dimension of the domain will be divided into 12 layers with the maximum<br />
elevations for each layer shown in Table 3-1. The vertical dimensions are weighted<br />
towards the surface to resolve the mixing layer while using a somewhat coarser resolution<br />
for the layers aloft.<br />
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TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN<br />
Layer Elevation (m)<br />
1 20<br />
2 40<br />
3 60<br />
4 80<br />
5 100<br />
6 150<br />
7 200<br />
8 250<br />
9 500<br />
10 1000<br />
11 2000<br />
12 3500<br />
CALMET allows for a bias value to be applied to each of the vertical layers. The bias<br />
settings for each vertical layer determine the relative weight given to the vertically<br />
extrapolated surface and upper air wind and temperature observations. The initial guess<br />
fields are computed with an inverse distance weighting (1/r 2 ) of the surface and upper air<br />
data. The initial guess fields may be modified by a layer dependent bias factor. Values for<br />
the bias factor may range from -1 to +1. A bias of -1 eliminates upper-air observations in<br />
the 1/r 2 interpolations used to initialize the vertical wind fields. Conversely, a bias of +1<br />
eliminates the surface observations in the interpolations for this layer. Normally, bias is set<br />
to zero (0) for each vertical layer, such that the upper air and surface observations are given<br />
equal weight in the 1/r 2 interpolations. The biases for each layer of the proposed modeling<br />
domain will be set to zero.<br />
CALMET allows for vertical extrapolation of surface wind observations to layers aloft to<br />
be skipped if the surface station is close to the upper air station. Alternatively, CALMET<br />
allows data from all surface stations to be extrapolated. The CALMET parameter that<br />
controls this setting is IEXTRP. Setting IEXTRP to a value less than zero (0) means that<br />
layer 1 data from upper air soundings is ignored in any vertical extrapolations. IEXTRP<br />
will be set to -4 for this analysis (i.e., the similarity theory is used to extrapolate the surface<br />
winds into the layers aloft, which provides more information on observed local effects to<br />
the upper layers).<br />
3.3.2 INFLUENCES OF OBSERVATIONS<br />
Step 1 wind fields will be based on an initial guess using MM5 data and refined to reflect<br />
terrain affects. Step 2 wind fields will adjust the Step 1 wind field by incorporating the<br />
influence of local observations. An inverse distance method is used to determine the<br />
influence of observations to the Step 1 wind field. RMAX1 and RMAX2 define the radius<br />
of influence for data from surface stations to land in the surface layer and data from upper<br />
air stations to land in the layers aloft. In general, RMAX1 and RMAX2 are used to<br />
exclude observations from being inappropriately included in the development of the Step 2<br />
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wind field if the distance from an observation station to a grid point exceeds the maximum<br />
radius of influence.<br />
If the distance from an observation station to a grid point is less than the value set for<br />
RMAX, the observation data will be used in the development of the Step 2 wind field. R1<br />
represents the distance from a surface observation station at which the surface observation<br />
and the Step 1 wind field are weighted equally. R2 represents the comparable distance for<br />
winds aloft. R1 and R2 are used to weight the observation data with respect to the MM5<br />
data that was used to generate the Step 1 wind field. Large values for R1 and R2 give<br />
more weight to the observations, where as small values give more weight to the MM5 data.<br />
In this BART modeling analysis, RMAX 1 will be set to 20 km, and R1 will be set to 10<br />
km. This will limit the influence of the surface observation data from all surface stations to<br />
20 km from each station, and will equally weight the MM5 and observation data at 10 km.<br />
RMAX2 will be set to 50 km, and R2 will be set to 25 km. This will limit the influence of<br />
the upper air observation data from all surface stations to 50 km from each station, and will<br />
equally weight the MM5 and observation data at 25 km. These settings of radius of<br />
influence will allow for adequate weighting of the MM5 data and the observation data<br />
across the modeling domain due to the vast domain to be modeled. RAMX 3 will be set to<br />
500 km.<br />
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4. CALPUFF<br />
The CALPUFF model uses the output file from CALMET together with source, receptor, and<br />
chemical reaction information to predict hourly concentration impacts. OG&E proposes to conduct a<br />
three-year CALPUFF analysis using data and model settings as described below.<br />
4.1 SOURCE EMISSIONS<br />
Baseline (pre-BART) emission data is based upon CEMS data collected by OG&E over the 2002-<br />
2005 time frame. In accordance with CENRAP guidelines, the emission rate over the highest<br />
calendar day (24-hr average) was used to establish baseline emissions.<br />
Emission estimates for various control scenarios were developed by Sargent and Lundy. The<br />
effectiveness of a number of different control technologies for NOx, SO2, and PM10 were examined.<br />
Emission estimates for these various scenarios are included in Appendix E. Please note that OG&E<br />
has elected to evaluate cost effectiveness on a facility-wide basis (as opposed to a unit-by-unit basis)<br />
and would install the final selected control technology on each of the affected units at the facility.<br />
4.2 RECEPTOR LOCATIONS<br />
The National Park Service (NPS) has electronic files available on their website that include the<br />
discrete locations and elevations of receptors to be evaluated in Class I area analyses. These receptor<br />
sets will be used in the CALPUFF model.<br />
4.3 BACKGROUND OZONE AND AMMONIA<br />
Background ozone concentrations are required in order to model the photochemical conversion of<br />
SO2 and NOX to sulfates (SO4) and nitrates (NO3). CALPUFF can use either a single background<br />
value representative of an area or hourly ozone data from one or more ozone monitoring stations.<br />
Hourly ozone data files will be used in the CALPUFF simulation. As provided by the <strong>Oklahoma</strong><br />
DEQ, hourly ozone data from the <strong>Oklahoma</strong> City, Glenpool, and Lawton monitors over the 2001-<br />
2003 time frame will be used. Background concentrations for ammonia will be assumed to be<br />
temporally and spatially invariant and will be set to 3 ppb.<br />
4.4 CALPUFF MODEL CONTROL PARAMETERS<br />
Appendix C provides a sample CALPUFF input file that is proposed for the OG&E refined modeling<br />
analyses. Please note that puff splitting is a generally accepted option in refined modeling analyses<br />
over large model domains for assessing impacts on Class I areas; however, this option would require<br />
significant computer resources and longer runtime. Based upon previous model runs performed on<br />
domains (and restricted computational grids) of the size described in this report, it is expected that<br />
runtimes could increase by a factor for 4 to 5 with the inclusion of puff-splitting. Due to this, OG&E<br />
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will evaluate the use of this option during the modeling analysis and provide details in the modeling<br />
report about its use.<br />
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5. CALPOST<br />
A three-year CALPOST analysis will be conducted to determine the visibility change in deciview<br />
(dv) caused by OG&E’s BART-eligible sources when compared to a natural background.<br />
5.1 CALPOST – LIGHT EXTINCTION ALGORITHM<br />
The algorithm will be used to calculate the daily light extinction attributable to OG&E’s BARTeligible<br />
sources and light extinction attributable to a natural background. The change in deciviews<br />
based on the source and background light extinctions will be evaluated using the equation below.<br />
⎡ b + b<br />
∆ dv = 10*ln ⎢<br />
⎣⎢<br />
b<br />
ext, background ext, source<br />
ext, background<br />
EPA’s currently approved algorithm for assessing light extinction and the updated light extinction<br />
calculation algorithms developed by the Interagency Monitoring of Protected Visual Environments<br />
(IMPROVE) workgroup will be used to assess visibility impacts from the <strong>Muskogee</strong> <strong>Station</strong>.<br />
The background extinction coefficient bext, background is affected by various chemical species and the<br />
Rayleigh scattering phenomenon. The original equation for the background extinction coefficient in<br />
the FLM’s FLAG guidance is as follows:<br />
where,<br />
b<br />
b<br />
b<br />
b<br />
b<br />
b<br />
b<br />
SO4<br />
NO3<br />
OC<br />
Soil<br />
Coarse<br />
ap<br />
Ray<br />
=<br />
f ( RH )<br />
[] =<br />
ext,<br />
background<br />
−1<br />
( Mm ) = bSO<br />
+ bNO<br />
+ bOC<br />
+ bSoil<br />
+ bCoarse<br />
+ bap<br />
bRay<br />
b +<br />
=<br />
= 4<br />
= 1<br />
= 10<br />
3[<br />
( NH 4 ) SO 4 ] f ( RH )<br />
2<br />
3[<br />
NH 4 NO 3 ] f ( RH )<br />
[ OC]<br />
[ Soil]<br />
0.<br />
6[<br />
Coarse Mass]<br />
[ EC]<br />
=<br />
= Rayleigh Scattering<br />
=<br />
Concentration<br />
in µg<br />
4<br />
3<br />
−1<br />
( 10 Mm by default)<br />
Relative Humidity Function<br />
m<br />
3<br />
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⎤<br />
⎥<br />
⎦⎥<br />
[ ( NH4<br />
) SO ] 2 4<br />
[ NH4NO3]<br />
[ OC]<br />
denotes<br />
[ Soil]<br />
denotes<br />
[ Coarse Mass]<br />
[ EC]<br />
denotes<br />
denotes the ammonium sulfate concentration<br />
denotes the ammonium nitrate concentration<br />
the concentration<br />
of organic carbon<br />
the concentration<br />
of fine soils<br />
denotes the concentration<br />
of coarse dusts<br />
the concentration<br />
of elemental carbon<br />
Rayleigh Scattering is scattering due to air molecules
5.2 CALPOST PROCESSING METHOD<br />
CALPOST Method 6, which calculates hourly light extinction impacts for the source and background<br />
using monthly average relative humidity adjustment factors will be used in the refined BART<br />
analysis. Monthly Class I area-specific relative humidity adjustment factors based on the centroid of<br />
the Class I areas as included in Table A-3 of EPA’s Guidance for Estimating Natural Visibility<br />
Conditions Under the Regional Haze Program will be used. The factors for the Class I areas listed to<br />
be evaluated in the analysis are provided in Table 5-1.<br />
TABLE 5-1. MONTHLY HUMIDITY FACTORS<br />
Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec<br />
Caney Creek 3.4 3.1 2.9 3.0 3.6 3.6 3.4 3.4 3.6 3.5 3.4 3.5<br />
Hercules-Glades 3.2 2.9 2.7 2.7 3.3 3.3 3.3 3.3 3.4 3.1 3.1 3.3<br />
Upper Buffalo 3.3 3.0 2.7 2.8 3.4 3.4 3.4 3.4 3.6 3.3 3.2 3.3<br />
Wichita Mountains 2.7 2.6 2.4 2.4 3.0 2.7 2.3 2.5 2.9 2.6 2.7 2.8<br />
5.3 NATURAL BACKGROUND<br />
EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 of<br />
EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program will<br />
be used. The annual average concentrations are provided in Table 5-2.<br />
TABLE 5-2. DEFAULT AVERAGE ANNUAL NATURAL BACKGROUND LEVELS<br />
Class I Area Region SO4 NO3 OC EC Soil Coarse Mass<br />
Caney Creek WEST 0.12 0.10 0.47 0.02 0.50 3.00<br />
Hercules-Glades EAST 0.23 0.10 1.40 0.02 0.50 3.00<br />
Upper Buffalo EAST 0.23 0.10 1.40 0.02 0.50 3.00<br />
Wichita Mountains WEST 0.12 0.10 0.47 0.02 0.50 3.00<br />
5.4 EVALUATING VISIBILITY RESULTS<br />
When evaluating cost-control effectiveness of the various control scenarios, OG&E will examine the<br />
98 th percentile of the 2001-2003 daily ∆dv values output by CALPOST. Peak 24-hr impact values<br />
will be included for reference.<br />
5.5 SUMMARY OF CALPOST CONTROL PARAMETERS<br />
Appendix E provides a sample CALPOST input file that OG&E is proposing for the modeling<br />
analysis. Variable values that differ from the CENRAP protocol are generally the result of data<br />
input/output handling issues (e.g., types of output, receptor numbers, etc.).<br />
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6. VISIBILITY RESULTS<br />
A summary of visibility impacts from the various control scenarios described in Section 4 is included<br />
below. In addition to the 98 th percentile values typically examined in BART analyses, peak 24-hr<br />
impacts are also included below.<br />
TABLE 6-1. MUSKOGEE STATION VISIBILITY RESULTS<br />
Peak Impact 98th Percentile<br />
%<br />
Reduction<br />
from<br />
previous<br />
%<br />
Reduction<br />
from<br />
Baseline (∆dv)<br />
%<br />
Reduction<br />
from<br />
previous<br />
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%<br />
Reduction<br />
from<br />
Baseline<br />
Pollutant Class I Area<br />
Control<br />
Technology (∆dv)<br />
NOx Caney Creek Baseline 3.54 -- -- 1.06 -- --<br />
LNB/OFA 1.11 69% 69% 0.32 70% 70%<br />
SCR 0.54 52% 85% 0.14 56% 87%<br />
Herc-Glades Baseline 2.21 -- -- 0.47 -- --<br />
LNB/OFA 0.69 69% 69% 0.14 71% 71%<br />
SCR 0.31 55% 86% 0.06 54% 87%<br />
Upper Buffalo Baseline 3.66 -- -- 0.84 -- --<br />
LNB/OFA 1.21 67% 67% 0.24 71% 71%<br />
SCR 0.58 52% 84% 0.11 53% 86%<br />
Wichita Mts Baseline 2.16 -- -- 0.61 -- --<br />
LNB/OFA 0.69 68% 68% 0.18 71% 71%<br />
SCR 0.31 55% 86% 0.08 55% 87%<br />
PM10 Caney Creek Baseline 0.52 -- -- 0.17 -- --<br />
Polishing Filter 0.31 41% 41% 0.11 38% 38%<br />
Herc-Glades Baseline 0.23 -- -- 0.09 -- --<br />
Polishing Filter 0.15 38% 38% 0.05 45% 45%<br />
Upper Buffalo Baseline 0.51 -- -- 0.14 -- --<br />
Polishing Filter 0.33 35% 35% 0.09 41% 41%<br />
Wichita Mts Baseline 0.21 -- -- 0.08 -- --<br />
Polishing Filter 0.13 39% 39% 0.04 41% 41%<br />
SO2/H2SO4 Caney Creek Baseline 4.17 -- -- 1.47 -- --<br />
DFGD 0.65 84% 84% 0.20 87% 87%<br />
WFGD 0.64 2% 85% 0.24 -24% 83%<br />
Herc-Glades Baseline 2.52 -- -- 0.92 -- --<br />
DFGD 0.43 83% 83% 0.12 87% 87%<br />
WFGD 0.50 -14% 80% 0.13 -9% 86%<br />
Upper Buffalo Baseline 3.72 -- -- 1.28 -- --<br />
DFGD 0.60 84% 84% 0.17 87% 87%<br />
WFGD 0.74 -25% 80% 0.19 -16% 85%<br />
Wichita Mts Baseline 3.13 -- -- 1.18 -- --<br />
DFGD 0.51 84% 84% 0.15 87% 87%<br />
WFGD 0.54 -5% 83% 0.14 3% 88%
APPENDIX A- METEOROLOGICAL STATIONS<br />
TABLE A-1. LIST OF SURFACE METEOROLOGICAL STATIONS<br />
<strong>Station</strong> <strong>Station</strong><br />
LCC<br />
East LCC North<br />
Number Acronym ID (km) (km) Long Lat<br />
1 KDYS 69019 -267.672 -834.095 96.9968 39.9925<br />
2 KNPA 72222 932.565 -1020.909 97.0110 39.9908<br />
3 KBFM 72223 857.471 -996.829 97.0101 39.9910<br />
4 KGZH 72227 946.767 -899.515 97.0112 39.9919<br />
5 KTCL 72228 870.843 -706.104 97.0103 39.9936<br />
6 KNEW 53917 674.172 -1078.342 97.0080 39.9903<br />
7 KNBG 12958 677.719 -1104.227 97.0080 39.9900<br />
8 BVE 12884 741.996 -1153.463 97.0088 39.9896<br />
9 KPTN 72232 550.88 -1124.295 97.0065 39.9898<br />
10 KMEI 13865 774.911 -814.225 97.0092 39.9926<br />
11 KPIB 72234 728.416 -915.165 97.0086 39.9917<br />
12 KGLH 72235 557.072 -703.097 97.0066 39.9936<br />
13 KHEZ 11111 540.777 -912.22 97.0064 39.9918<br />
14 KMCB 11112 622.755 -949.618 97.0074 39.9914<br />
15 KGWO 11113 640.102 -695.286 97.0076 39.9937<br />
16 KASD 72236 692.381 -1043.261 97.0082 39.9906<br />
17 KPOE 72239 363.294 -984.839 97.0043 39.9911<br />
18 KBAZ 72241 -102.133 -1140.886 96.9988 39.9897<br />
19 KGLS 72242 215.108 -1185.604 97.0025 39.9893<br />
20 KDWH 11114 140.413 -1101.174 97.0017 39.9900<br />
21 KIAH 12960 158.266 -1108.37 97.0019 39.9900<br />
22 KHOU 72243 167.147 -1147.402 97.0020 39.9896<br />
23 KEFD 12906 178.551 -1152.782 97.0021 39.9896<br />
24 KCXO 72244 152.739 -1069.309 97.0018 39.9903<br />
25 KCLL 11115 60.898 -1044.381 97.0007 39.9906<br />
26 KLFK 93987 214.643 -969.355 97.0025 39.9912<br />
27 KUTS 11116 136.056 -1026.773 97.0016 39.9907<br />
28 KTYR 11117 150.451 -846.207 97.0018 39.9924<br />
29 KCRS 72246 56.655 -882.642 97.0007 39.9920<br />
30 KGGG 72247 214.572 -841.163 97.0025 39.9924<br />
31 KGKY 11118 -9.365 -812.25 96.9999 39.9927<br />
32 KDTN 72248 304.827 -821.713 97.0036 39.9926<br />
33 KBAD 11119 312.743 -825.101 97.0037 39.9925<br />
34 KMLU 11120 465.834 -816.211 97.0055 39.9926<br />
35 KTVR 11121 561.446 -840.225 97.0066 39.9924<br />
36 KTRL 11122 68.599 -806.417 97.0008 39.9927<br />
37 KOCH 72249 216.81 -930.252 97.0026 39.9916<br />
38 KBRO 12919 -44.167 -1571.387 96.9995 39.9858<br />
OG&E / Sargent & Lundy A-1 Trinity Consultants<br />
BART Modeling Report 083701.0004
<strong>Station</strong> <strong>Station</strong><br />
LCC<br />
East LCC North<br />
Number Acronym ID (km) (km) Long Lat<br />
39 KALI 72251 -103.012 -1363.74 96.9988 39.9877<br />
40 KLRD 12920 -246.548 -1381.603 96.9971 39.9875<br />
41 KSSF 72252 -143.386 -1183.35 96.9983 39.9893<br />
42 KRKP 11123 -4.965 -1324.914 96.9999 39.9880<br />
43 KCOT 11124 -219.097 -1280.964 96.9974 39.9884<br />
44 KLBX 11125 150.245 -1207.466 97.0018 39.9891<br />
45 KSAT 12921 -143.024 -1160.935 96.9983 39.9895<br />
46 KHDO 12962 -211.702 -1178.172 96.9975 39.9894<br />
47 KSKF 72253 -154.625 -1177.555 96.9982 39.9894<br />
48 KHYI 11126 -84.156 -1122.487 96.9990 39.9899<br />
49 KTKI 72254 38.788 -754.791 97.0005 39.9932<br />
50 KBMQ 11127 -118.39 -1027.031 96.9986 39.9907<br />
51 KATT 11128 -67.587 -1075.97 96.9992 39.9903<br />
52 KSGR 11129 131.478 -1151.702 97.0016 39.9896<br />
53 KGTU 11130 -65.624 -1033.173 96.9992 39.9907<br />
54 KVCT 12912 6.587 -1236.788 97.0001 39.9888<br />
55 KPSX 72255 73.878 -1253.33 97.0009 39.9887<br />
56 KACT 13959 -22.12 -929.156 96.9997 39.9916<br />
57 KPWG 72256 -30.147 -944.073 96.9996 39.9915<br />
58 KILE 72257 -65.288 -988.507 96.9992 39.9911<br />
59 KGRK 11131 -79.643 -990.173 96.9991 39.9911<br />
60 KTPL 11132 -38.203 -981.19 96.9996 39.9911<br />
61 KPRX 13960 143.317 -703.663 97.0017 39.9936<br />
62 KDTO 72258 -17.018 -752.974 96.9998 39.9932<br />
63 KAFW 11133 -29.564 -777.061 96.9997 39.9930<br />
64 KFTW 72259 -34.302 -795.502 96.9996 39.9928<br />
65 KMWL 11134 -99.769 -798.767 96.9988 39.9928<br />
66 KRBD 11135 12.453 -810.467 97.0002 39.9927<br />
67 KDRT 11136 -384.069 -1170.59 96.9955 39.9894<br />
68 KFST 22010 -566.418 -988.838 96.9933 39.9911<br />
69 KGDP 72261 -739.127 -873.302 96.9913 39.9921<br />
70 KSJT 72262 -333.338 -952.54 96.9961 39.9914<br />
71 KMRF 23034 -676.265 -1042.616 96.9920 39.9906<br />
72 KMAF 72264 -489.668 -878.107 96.9942 39.9921<br />
73 KINK 23023 -586.882 -890.654 96.9931 39.9920<br />
74 KABI 72265 -252.044 -836.353 96.9970 39.9924<br />
75 KLBB 13962 -445.006 -689.313 96.9948 39.9938<br />
76 KATS 11137 -696.818 -763.258 96.9918 39.9931<br />
77 KCQC 11138 -785.757 -515.724 96.9907 39.9953<br />
78 KROW 23009 -698.822 -712.898 96.9918 39.9936<br />
79 KSRR 72268 -789.593 -686.226 96.9907 39.9938<br />
80 KCNM 11139 -682.79 -822.109 96.9919 39.9926<br />
81 KALM 36870 -838.056 -752.338 96.9901 39.9932<br />
82 KLRU 72269 -931.527 -804.112 96.9890 39.9927<br />
OG&E / Sargent & Lundy A-2 Trinity Consultants<br />
BART Modeling Report 083701.0004
<strong>Station</strong> <strong>Station</strong><br />
LCC<br />
East LCC North<br />
Number Acronym ID (km) (km) Long Lat<br />
83 KTCS 72271 -952.353 -695.469 96.9888 39.9937<br />
84 KSVC 93063 -1042.03 -752.033 96.9877 39.9932<br />
85 KDMN 72272 -1006.77 -799.231 96.9881 39.9928<br />
86 KMSL 72323 854.846 -536.687 97.0101 39.9952<br />
87 KPOF 72330 578.62 -336.733 97.0068 39.9970<br />
88 KGTR 11140 779.065 -689.108 97.0092 39.9938<br />
89 KTUP 93862 753.875 -600.337 97.0089 39.9946<br />
90 KMKL 72334 727.051 -454.383 97.0086 39.9959<br />
91 KLRF 72340 440.654 -550.661 97.0052 39.9950<br />
92 KHKA 11141 643.365 -424.419 97.0076 39.9962<br />
93 KHOT 72341 358.094 -604.603 97.0042 39.9945<br />
94 KTXK 11142 278.022 -720.623 97.0033 39.9935<br />
95 KLLQ 72342 488.655 -698.008 97.0058 39.9937<br />
96 KMWT 72343 254.18 -599.224 97.0030 39.9946<br />
97 KFSM 13964 237.97 -512.87 97.0028 39.9954<br />
98 KSLG 72344 224.881 -419.064 97.0027 39.9962<br />
99 KVBT 11143 248.074 -399.892 97.0029 39.9964<br />
100 KHRO 11144 343.525 -405.601 97.0041 39.9963<br />
101 KFLP 11145 404.239 -399.142 97.0048 39.9964<br />
102 KBVX 11146 480.712 -457.853 97.0057 39.9959<br />
103 KROG 11147 258.44 -397.685 97.0031 39.9964<br />
104 KSPS 13966 -138.053 -664.886 96.9984 39.9940<br />
105 KHBR 72352 -186.121 -551.123 96.9978 39.9950<br />
106 KCSM 11148 -198.844 -513.911 96.9977 39.9954<br />
107 KFDR 11149 -181.653 -625.205 96.9979 39.9944<br />
108 KGOK 72353 -35.905 -458.97 96.9996 39.9959<br />
109 KTIK 72354 -34.581 -506.938 96.9996 39.9954<br />
110 KPWA 11150 -58.596 -493.951 96.9993 39.9955<br />
111 KSWO 11151 -7.42 -425.828 96.9999 39.9962<br />
112 KMKO 72355 146.972 -479.879 97.0017 39.9957<br />
113 KRVS 72356 91.059 -438.276 97.0011 39.9960<br />
114 KBVO 11152 87.136 -357.069 97.0010 39.9968<br />
115 KMLC 11153 110.647 -563.566 97.0013 39.9949<br />
116 KOUN 72357 -40.731 -527.298 96.9995 39.9952<br />
117 KLAW 11154 -129.405 -600.222 96.9985 39.9946<br />
118 KCDS 72360 -300.297 -610.668 96.9965 39.9945<br />
119 KGNT 72362 -985.117 -475.563 96.9884 39.9957<br />
120 KGUP 11155 -1059.48 -427.151 96.9875 39.9961<br />
121 KAMA 23047 -425.319 -518.171 96.9950 39.9953<br />
122 KBGD 72363 -395.603 -466.083 96.9953 39.9958<br />
123 KFMN 72365 -993.449 -297.944 96.9883 39.9973<br />
124 KSKX 72366 -770.464 -355.855 96.9909 39.9968<br />
125 KTCC 23048 -597.271 -511.241 96.9930 39.9954<br />
126 KLVS 23054 -732.565 -448.329 96.9914 39.9960<br />
OG&E / Sargent & Lundy A-3 Trinity Consultants<br />
BART Modeling Report 083701.0004
<strong>Station</strong> <strong>Station</strong><br />
LCC<br />
East LCC North<br />
Number Acronym ID (km) (km) Long Lat<br />
127 KEHR 72423 812.573 -199.695 97.0096 39.9982<br />
128 KEVV 93817 822.929 -172.715 97.0097 39.9984<br />
129 KMVN 72433 704.666 -154.54 97.0083 39.9986<br />
130 KMDH 11156 676.745 -218.041 97.0080 39.9980<br />
131 KBLV 11157 617.659 -136.018 97.0073 39.9988<br />
132 KSUS 3966 547.898 -130.122 97.0065 39.9988<br />
133 KPAH 3816 725.985 -293.319 97.0086 39.9974<br />
134 KJEF 72445 419.01 -145.496 97.0050 39.9987<br />
135 KAIZ 11158 387.096 -200.609 97.0046 39.9982<br />
136 KIXD 72447 182.322 -126.913 97.0022 39.9989<br />
137 KWLD 72450 0 -298.57 97.0000 39.9973<br />
138 KAAO 11159 -18.976 -248.773 96.9998 39.9978<br />
139 KIAB 11160 -23.392 -263.471 96.9997 39.9976<br />
140 KEWK 11161 -24.645 -215.58 96.9997 39.9981<br />
141 KGBD 72451 -161.892 -180.781 96.9981 39.9984<br />
142 KHYS 11162 -195.191 -124.723 96.9977 39.9989<br />
143 KCFV 11163 126.442 -319.698 97.0015 39.9971<br />
144 KFOE 72456 114.618 -115.26 97.0014 39.9990<br />
145 KEHA 72460 -432.761 -320.089 96.9949 39.9971<br />
146 KALS 72462 -777.592 -245.892 96.9908 39.9978<br />
147 KDRO 11164 -945.713 -259.163 96.9888 39.9977<br />
148 KLHX 72463 -568.426 -195.178 96.9933 39.9982<br />
149 KSPD 2128 -494.076 -285.176 96.9942 39.9974<br />
150 KCOS 93037 -664.022 -102.596 96.9922 39.9991<br />
151 KGUC 72467 -857.452 -115.301 96.9899 39.9990<br />
152 KMTJ 93013 -940.981 -109.358 96.9889 39.9990<br />
153 KCEZ 72476 -1020.87 -233.14 96.9880 39.9979<br />
154 KCPS 72531 591.652 -136.14 97.0070 39.9988<br />
155 KLWV 72534 808.939 -94.46 97.0096 39.9992<br />
156 KPPF 74543 130.433 -293.855 97.0015 39.9973<br />
157 KHOP 74671 841.751 -324.569 97.0099 39.9971<br />
158 KBIX 74768 778.252 -1028.514 97.0092 39.9907<br />
159 KPQL 11165 814.599 -1019.583 97.0096 39.9908<br />
160 MMPG 76243 -348.007 -1248.779 96.9959 39.9887<br />
161 MMMV 76342 -446.576 -1449.334 96.9947 39.9869<br />
162 MMMY 76394 -316.664 -1581.176 96.9963 39.9857<br />
OG&E / Sargent & Lundy A-4 Trinity Consultants<br />
BART Modeling Report 083701.0004
TABLE A-2. LIST OF UPPER AIR METEOROLOGICAL STATIONS<br />
Number<br />
LCC<br />
East<br />
(km)<br />
LCC<br />
North<br />
(km) Long Lat<br />
<strong>Station</strong> <strong>Station</strong><br />
Acronym ID<br />
1 KABQ 23050 -869.46 -501.713 96.9897 39.9955<br />
2 KAMA 23047 -425.319 -518.171 96.9950 39.9953<br />
3 KBMX 53823 951.609 -702.935 97.0112 39.9936<br />
4 KBNA 13897 920.739 -377.164 97.0109 39.9966<br />
5 KBRO 12919 -44.167 -1571.39 96.9995 39.9858<br />
6 KCRP 12924 -51.535 -1360.35 96.9994 39.9877<br />
7 KDDC 13985 -259.352 -242.681 96.9969 39.9978<br />
8 KDRT 22010 -384.069 -1170.59 96.9955 39.9894<br />
9 KEPZ 3020 -914.558 -852.552 96.9892 39.9923<br />
10 KFWD 3990 -28.034 -793.745 96.9997 39.9928<br />
11 KJAN 3940 650.105 -826.452 97.0077 39.9925<br />
12 KLCH 3937 364.461 -1089.15 97.0043 39.9902<br />
13 KLZK 3952 432.063 -560.441 97.0051 39.9949<br />
14 KMAF 23023 -489.668 -878.107 96.9942 39.9921<br />
15 KOUN 3948 -40.731 -527.298 96.9995 39.9952<br />
16 KSHV 13957 298.869 -831.166 97.0035 39.9925<br />
17 KSIL 53813 698.079 -1054.03 97.0082 39.9905<br />
OG&E / Sargent & Lundy A-5 Trinity Consultants<br />
BART Modeling Report 083701.0004
TABLE A-3. LIST OF PRECIPITATION METEOROLOGICAL STATIONS<br />
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
1 ADDI 10063 906.825 -601.428 97.0107 39.9946<br />
2 ALBE 10140 917.606 -821.64 97.0108 39.9926<br />
3 BERR 10748 892.454 -683.388 97.0105 39.9938<br />
4 HALE 13620 881.928 -601.878 97.0104 39.9946<br />
5 HAMT 13645 863.663 -612.725 97.0102 39.9945<br />
6 JACK 14193 898.014 -915.623 97.0106 39.9917<br />
7 MBLE 15478 851.953 -1022.41 97.0101 39.9908<br />
8 MUSC 15749 880.113 -567.484 97.0104 39.9949<br />
9 PETE 16370 935.558 -908.259 97.0110 39.9918<br />
10 THOM 18178 900.858 -915.326 97.0106 39.9917<br />
11 TUSC 18385 895.631 -713.223 97.0106 39.9936<br />
12 VERN 18517 825.585 -685.773 97.0098 39.9938<br />
13 BEEB 30530 462.394 -532.485 97.0055 39.9952<br />
14 BRIG 30900 318.015 -554.857 97.0038 39.9950<br />
15 CALI 31140 419.619 -731.44 97.0050 39.9934<br />
16 CAMD 31152 386.546 -699.659 97.0046 39.9937<br />
17 DIER 32020 268.114 -643.184 97.0032 39.9942<br />
18 EURE 32356 286.738 -390.862 97.0034 39.9965<br />
19 GILB 32794 383.362 -435.625 97.0045 39.9961<br />
20 GREE 32978 450.594 -483.201 97.0053 39.9956<br />
21 STUT 36920 509.943 -596.328 97.0060 39.9946<br />
22 TEXA 37048 278.022 -720.623 97.0033 39.9935<br />
23 ALAM 50130 -749.044 -267.856 96.9912 39.9976<br />
24 ARAP 50304 -441.903 -152.324 96.9948 39.9986<br />
25 COCH 51713 -819.794 -148.582 96.9903 39.9987<br />
26 CRES 51959 -828.107 -119.911 96.9902 39.9989<br />
27 GRAN 53477 -451.781 -203.82 96.9947 39.9982<br />
28 GUNN 53662 -829.573 -141.995 96.9902 39.9987<br />
29 HUGO 54172 -539.364 -81.948 96.9936 39.9993<br />
30 JOHN 54388 -483.95 -201.915 96.9943 39.9982<br />
31 KIM 54538 -544.501 -283.337 96.9936 39.9974<br />
32 MESA 55531 -993.391 -256.696 96.9883 39.9977<br />
33 ORDW 56136 -549.552 -55.741 96.9935 39.9995<br />
34 OURA 56203 -904.197 -168.246 96.9893 39.9985<br />
35 PLEA 56591 -1005.94 -229.472 96.9881 39.9979<br />
36 PUEB 56740 -633.961 -176.872 96.9925 39.9984<br />
37 TYE 57320 -662.095 -242.254 96.9922 39.9978<br />
OG&E / Sargent & Lundy A-6 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
38 SAGU 57337 -790.269 -176.061 96.9907 39.9984<br />
39 SANL 57428 -726.777 -285.47 96.9914 39.9974<br />
40 SHEP 57572 -714.046 -252.189 96.9916 39.9977<br />
41 TELL 58204 -920.205 -215.382 96.9891 39.9981<br />
42 TERC 58220 -708.229 -296.023 96.9916 39.9973<br />
43 TRIN 58429 -642.489 -293.805 96.9924 39.9973<br />
44 TRLK 58436 -646.185 -295.727 96.9924 39.9973<br />
45 WALS 58781 -654.989 -262.821 96.9923 39.9976<br />
46 WHIT 58997 -619.615 -250.12 96.9927 39.9977<br />
47 ASHL 110281 684.787 -169.285 97.0081 39.9985<br />
48 CAIR 111166 697.177 -301.436 97.0082 39.9973<br />
49 CARM 111302 772.938 -177.782 97.0091 39.9984<br />
50 CISN 111664 758.146 -151.446 97.0090 39.9986<br />
51 FLOR 113109 751.801 -139.837 97.0089 39.9987<br />
52 HARR 113879 762.044 -246.62 97.0090 39.9978<br />
53 KASK 114629 650.464 -239.886 97.0077 39.9978<br />
54 LAWR 114957 829.038 -128.708 97.0098 39.9988<br />
55 MTCA 115888 827.797 -149.966 97.0098 39.9986<br />
56 MURP 115983 682.261 -251.649 97.0081 39.9977<br />
57 NEWT 116159 766.098 -72.902 97.0090 39.9993<br />
58 REND 117187 731.633 -185.058 97.0086 39.9983<br />
59 SMIT 118020 770.027 -283.638 97.0091 39.9974<br />
60 SPAR 118147 658.275 -185.973 97.0078 39.9983<br />
61 VAND 118781 685.449 -127.048 97.0081 39.9989<br />
62 WEST 119193 778.655 -147.215 97.0092 39.9987<br />
63 EVAN 122738 842.476 -172.871 97.0100 39.9984<br />
64 NEWB 126151 855.854 -223.713 97.0101 39.9980<br />
65 PRIN 127125 836.901 -153.449 97.0099 39.9986<br />
66 STEN 128442 859.099 -156.613 97.0101 39.9986<br />
67 JTML 128967 788.703 -239.572 97.0093 39.9978<br />
68 ARLI 140326 -101.734 -271.373 96.9988 39.9976<br />
69 BAZI 140620 -210.423 -201.758 96.9975 39.9982<br />
70 BEAU 140637 59.762 -288.39 97.0007 39.9974<br />
71 BONN 140957 211.236 -103.29 97.0025 39.9991<br />
72 CALD 141233 -32.689 -330.586 96.9996 39.9970<br />
73 CASS 141351 54.006 -217.645 97.0006 39.9980<br />
74 CENT 141404 170.503 -206.038 97.0020 39.9981<br />
75 CHAN 141427 150.257 -286.094 97.0018 39.9974<br />
76 CLIN 141612 155.623 -157.682 97.0018 39.9986<br />
77 COLL 141730 -265.465 -156.95 96.9969 39.9986<br />
OG&E / Sargent & Lundy A-7 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
78 COLU 141740 220.541 -316.555 97.0026 39.9971<br />
79 CONC 141867 58.918 -175.589 97.0007 39.9984<br />
80 DODG 142164 -226.497 -277.655 96.9973 39.9975<br />
81 ELKH 142432 -400.112 -321.784 96.9953 39.9971<br />
82 ENGL 142560 -264.927 -324.066 96.9969 39.9971<br />
83 ERIE 142582 162.669 -291.383 97.0019 39.9974<br />
84 FALL 142686 83.491 -288.177 97.0010 39.9974<br />
85 GALA 142938 -136.931 -176.83 96.9984 39.9984<br />
86 GARD 142980 -304.059 -215.308 96.9964 39.9981<br />
87 GREN 143248 64.308 -307.161 97.0008 39.9972<br />
88 HAYS 143527 -190.307 -161.342 96.9978 39.9985<br />
89 HEAL 143554 -292.133 -175.921 96.9966 39.9984<br />
90 HILL 143686 214.018 -174.006 97.0025 39.9984<br />
91 INDE 143954 139.335 -315.058 97.0016 39.9972<br />
92 IOLA 143984 153.451 -269.438 97.0018 39.9976<br />
93 JOHR 144104 134.784 -203.41 97.0016 39.9982<br />
94 KANO 144178 -50.289 -181.177 96.9994 39.9984<br />
95 KIOW 144341 -113.967 -329.843 96.9987 39.9970<br />
96 MARI 145039 -4.343 -195.712 97.0000 39.9982<br />
97 MELV 145210 137.104 -186.781 97.0016 39.9983<br />
98 MILF 145306 39.504 -106.05 97.0005 39.9990<br />
99 MOUD 145536 152.624 -318.136 97.0018 39.9971<br />
100 OAKL 145888 -306.378 -96.814 96.9964 39.9991<br />
101 OTTA 146128 158.639 -178.635 97.0019 39.9984<br />
102 POMO 146498 143.864 -176.707 97.0017 39.9984<br />
103 SALI 147160 -29.426 -166.908 96.9997 39.9985<br />
104 SMOL 147551 -34.639 -171.31 96.9996 39.9985<br />
105 STAN 147756 225.026 -164.85 97.0027 39.9985<br />
106 SUBL 147922 -303.514 -292.808 96.9964 39.9974<br />
107 TOPE 148167 139.116 -104.91 97.0016 39.9991<br />
108 TRIB 148235 -387.855 -180.643 96.9954 39.9984<br />
109 UNIO 148293 211.43 -272.537 97.0025 39.9975<br />
110 WALL 148535 -376.076 -152.432 96.9956 39.9986<br />
111 WICH 148830 -23.729 -288.579 96.9997 39.9974<br />
112 WILS 148946 -111.502 -156.22 96.9987 39.9986<br />
113 BENT 150611 781.608 -348.109 97.0092 39.9969<br />
114 CALH 151227 865.268 -261.635 97.0102 39.9976<br />
115 CLTN 151631 749.287 -365.634 97.0088 39.9967<br />
116 HERN 153798 859.01 -352.458 97.0101 39.9968<br />
117 MADI 155067 854.116 -265.064 97.0101 39.9976<br />
OG&E / Sargent & Lundy A-8 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
118 PADU 156110 753.185 -293.024 97.0089 39.9974<br />
119 PCTN 156580 834.464 -280.496 97.0099 39.9975<br />
120 ALEX 160103 433.824 -959.253 97.0051 39.9913<br />
121 BATN 160549 562.794 -1032.4 97.0066 39.9907<br />
122 CALH 161411 436.113 -817.451 97.0052 39.9926<br />
123 CLNT 161899 578.969 -999.986 97.0068 39.9910<br />
124 JENA 164696 455.225 -912.366 97.0054 39.9918<br />
125 LACM 165078 364.784 -1089.92 97.0043 39.9901<br />
126 MIND 166244 346.708 -812.651 97.0041 39.9927<br />
127 MONR 166314 463.225 -814.905 97.0055 39.9926<br />
128 NATC 166582 369.451 -905.316 97.0044 39.9918<br />
129 SHRE 168440 299.526 -831.143 97.0035 39.9925<br />
130 WINN 169803 408.309 -884.596 97.0048 39.9920<br />
131 BROK 221094 621.827 -914.236 97.0073 39.9917<br />
132 CONE 221900 737.007 -823.513 97.0087 39.9926<br />
133 JAKS 224472 650.361 -826.097 97.0077 39.9925<br />
134 LEAK 224966 805.886 -943.78 97.0095 39.9915<br />
135 MERI 225776 774.942 -814.558 97.0092 39.9926<br />
136 SARD 227815 658.33 -593.661 97.0078 39.9946<br />
137 SAUC 227840 763.399 -1005.93 97.0090 39.9909<br />
138 TUPE 229003 753.571 -600.03 97.0089 39.9946<br />
139 ADVA 230022 657.892 -298.102 97.0078 39.9973<br />
140 ALEY 230088 505.348 -305.864 97.0060 39.9972<br />
141 BOLI 230789 331.651 -291.689 97.0039 39.9974<br />
142 CASV 231383 310.855 -392.187 97.0037 39.9965<br />
143 CLER 231674 575.868 -302.209 97.0068 39.9973<br />
144 CLTT 231711 307.465 -190.83 97.0036 39.9983<br />
145 COLU 231791 421.287 -155.672 97.0050 39.9986<br />
146 DREX 232331 228.23 -185.776 97.0027 39.9983<br />
147 ELM 232568 257.758 -159.419 97.0030 39.9986<br />
148 FULT 233079 470.408 -150.668 97.0056 39.9986<br />
149 HOME 233999 619.93 -415.469 97.0073 39.9962<br />
150 JEFF 234271 424.774 -172.095 97.0050 39.9984<br />
151 JOPL 234315 238.245 -318.262 97.0028 39.9971<br />
152 LEBA 234825 402.239 -276.263 97.0048 39.9975<br />
153 LICK 234919 480.849 -280.775 97.0057 39.9975<br />
154 LOCK 235027 302.048 -300.612 97.0036 39.9973<br />
155 MALD 235207 659.982 -377.876 97.0078 39.9966<br />
156 MARS 235298 332.062 -94.655 97.0039 39.9991<br />
157 MAFD 235307 391.968 -300.033 97.0046 39.9973<br />
OG&E / Sargent & Lundy A-9 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
158 MCES 235415 471.737 -143.942 97.0056 39.9987<br />
159 MILL 235594 309.516 -311.398 97.0037 39.9972<br />
160 MTGV 235834 426.937 -310.43 97.0050 39.9972<br />
161 NVAD 235987 243.915 -272.715 97.0029 39.9975<br />
162 OZRK 236460 349.133 -390.626 97.0041 39.9965<br />
163 PDTD 236777 334.055 -265.018 97.0039 39.9976<br />
164 POTO 236826 572.215 -251.455 97.0068 39.9977<br />
165 ROLL 237263 484.503 -253.958 97.0057 39.9977<br />
166 ROSE 237300 500.59 -175.393 97.0059 39.9984<br />
167 SALE 237506 498.94 -274.122 97.0059 39.9975<br />
168 SENE 237656 233.959 -383.703 97.0028 39.9965<br />
169 SPRC 237967 238.112 -373.616 97.0028 39.9966<br />
170 SPVL 237976 332.385 -309.374 97.0039 39.9972<br />
171 STEE 238043 503.354 -205.135 97.0059 39.9981<br />
172 STOK 238082 310.911 -279.239 97.0037 39.9975<br />
173 SWSP 238223 324.053 -150.325 97.0038 39.9986<br />
174 TRKD 238252 340.418 -395.428 97.0040 39.9964<br />
175 TRUM 238466 326.883 -197.796 97.0039 39.9982<br />
176 UNIT 238524 238.567 -154.494 97.0028 39.9986<br />
177 VIBU 238609 519.633 -267.258 97.0061 39.9976<br />
178 VIEN 238620 470.383 -193.872 97.0056 39.9983<br />
179 WAPP 238700 606.68 -358.746 97.0072 39.9968<br />
180 WASG 238746 556.425 -164.993 97.0066 39.9985<br />
181 WEST 238880 489.373 -377.809 97.0058 39.9966<br />
182 ALBU 290234 -869.46 -501.713 96.9897 39.9955<br />
183 ARTE 290600 -689.529 -773.897 96.9919 39.9930<br />
184 AUGU 290640 -973.07 -598.391 96.9885 39.9946<br />
185 CARL 291469 -680.335 -811.474 96.9920 39.9927<br />
186 CARR 291515 -819.836 -665.132 96.9903 39.9940<br />
187 CLAY 291887 -547.124 -374.102 96.9935 39.9966<br />
188 CLOV 291939 -566.973 -599.296 96.9933 39.9946<br />
189 CUBA 292241 -890.304 -392.495 96.9895 39.9965<br />
190 CUBE 292250 -951.142 -489.293 96.9888 39.9956<br />
191 DEMI 292436 -1007.99 -799.087 96.9881 39.9928<br />
192 DURA 292665 -767.148 -577.618 96.9909 39.9948<br />
193 EANT 292700 -735.089 -366.94 96.9913 39.9967<br />
194 LAVG 294862 -738.245 -461.163 96.9913 39.9958<br />
195 PROG 297094 -811.39 -578.971 96.9904 39.9948<br />
196 RAMO 297254 -733.737 -615.175 96.9913 39.9944<br />
197 ROSW 297610 -698.544 -712.921 96.9918 39.9936<br />
OG&E / Sargent & Lundy A-10 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
198 ROY 297638 -644.735 -422.422 96.9924 39.9962<br />
199 SANT 298085 -807.375 -445.708 96.9905 39.9960<br />
200 SPRI 298501 -676.681 -374.272 96.9920 39.9966<br />
201 STAY 298518 -810.491 -495.501 96.9904 39.9955<br />
202 TNMN 299031 -912.488 -413.425 96.9892 39.9963<br />
203 TUCU 299156 -604.359 -508.834 96.9929 39.9954<br />
204 WAST 299569 -638.605 -820.288 96.9925 39.9926<br />
205 WISD 299686 -856.967 -756.366 96.9899 39.9932<br />
206 AIRS 340179 -212.731 -597.062 96.9975 39.9946<br />
207 ARDM 340292 -12.242 -645.633 96.9999 39.9942<br />
208 BENG 340670 174.368 -568.011 97.0021 39.9949<br />
209 CANE 341437 71.857 -637.935 97.0009 39.9942<br />
210 CHRT 341544 203.233 -632.067 97.0024 39.9943<br />
211 CHAN 341684 10.494 -475.655 97.0001 39.9957<br />
212 CHIK 341750 -83.175 -547.26 96.9990 39.9951<br />
213 CCTY 342334 -165 -479.536 96.9981 39.9957<br />
214 DUNC 342654 -88.38 -610.04 96.9990 39.9945<br />
215 ELKC 342849 -216.769 -507.879 96.9974 39.9954<br />
216 FORT 343281 -129.964 -541.113 96.9985 39.9951<br />
217 GEAR 343497 -118.53 -482.187 96.9986 39.9956<br />
218 HENN 344052 -31.964 -601.206 96.9996 39.9946<br />
219 HOBA 344202 -189.062 -547.36 96.9978 39.9951<br />
220 KING 344865 24.538 -664.103 97.0003 39.9940<br />
221 LKEU 344975 141.702 -520.6 97.0017 39.9953<br />
222 LEHI 345108 71.634 -612.05 97.0009 39.9945<br />
223 MACI 345463 -254.63 -466.154 96.9970 39.9958<br />
224 MALL 345589 -55.127 -425.644 96.9994 39.9962<br />
225 MAYF 345648 -258.49 -512.583 96.9970 39.9954<br />
226 MUSK 346130 149.764 -466.905 97.0018 39.9958<br />
227 NOWA 346485 121.551 -364.038 97.0014 39.9967<br />
228 OKAR 346620 -88.424 -473.338 96.9990 39.9957<br />
229 OKEM 346638 63.188 -504.958 97.0008 39.9954<br />
230 OKLA 346661 -54.198 -510.562 96.9994 39.9954<br />
231 PAOL 346859 -23.665 -573.142 96.9997 39.9948<br />
232 PAWH 346935 57.704 -369.174 97.0007 39.9967<br />
233 PAWN 346944 16.927 -398.139 97.0002 39.9964<br />
234 PONC 347196 -8.871 -363.068 96.9999 39.9967<br />
235 PRYO 347309 150.763 -407.824 97.0018 39.9963<br />
236 SHAT 348101 -256.963 -407.368 96.9970 39.9963<br />
237 STIG 348497 171.02 -523.736 97.0020 39.9953<br />
OG&E / Sargent & Lundy A-11 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
238 TULS 348992 99.361 -419.873 97.0012 39.9962<br />
239 TUSK 349023 156.629 -592.395 97.0019 39.9946<br />
240 WMWR 349629 -156.42 -581.308 96.9982 39.9947<br />
241 WOLF 349748 30.212 -538.388 97.0004 39.9951<br />
242 BOLI 400876 760.886 -500.256 97.0090 39.9955<br />
243 BROW 401150 710.048 -480.346 97.0084 39.9957<br />
244 CETR 401587 877.35 -456.294 97.0104 39.9959<br />
245 DICS 402489 872.14 -391.132 97.0103 39.9965<br />
246 DYER 402680 695.792 -409.316 97.0082 39.9963<br />
247 GRNF 403697 760.795 -395.69 97.0090 39.9964<br />
248 JSNN 404561 765.932 -476.414 97.0090 39.9957<br />
249 LWER 405089 885.291 -487.757 97.0105 39.9956<br />
250 LEXI 405210 790.003 -471.897 97.0093 39.9957<br />
251 MASO 405720 694.163 -496.166 97.0082 39.9955<br />
252 MEMP 405954 671.8 -522.492 97.0079 39.9953<br />
253 MWFO 405956 681.292 -516.15 97.0080 39.9953<br />
254 MUNF 406358 678.65 -495.241 97.0080 39.9955<br />
255 SAMB 408065 697.077 -382.536 97.0082 39.9965<br />
256 SAVA 408108 800.788 -498.682 97.0095 39.9955<br />
257 UNCY 409219 711.595 -384.605 97.0084 39.9965<br />
258 ABIL 410016 -251.753 -836.027 96.9970 39.9924<br />
259 AMAR 410211 -425.302 -517.839 96.9950 39.9953<br />
260 AUST 410428 -67.587 -1075.97 96.9992 39.9903<br />
261 BRWN 411136 -43.861 -1571.39 96.9995 39.9858<br />
262 COST 411889 60.611 -1044.72 97.0007 39.9906<br />
263 COCR 412015 -51.832 -1360.01 96.9994 39.9877<br />
264 CROS 412131 -204.599 -868.469 96.9976 39.9922<br />
265 DFWT 412242 -1.867 -786.341 97.0000 39.9929<br />
266 EAST 412715 -171.024 -840.253 96.9980 39.9924<br />
267 ELPA 412797 -886.583 -860.763 96.9895 39.9922<br />
268 HICO 414137 -97.323 -888.181 96.9989 39.9920<br />
269 HUST 414300 157.976 -1108.38 97.0019 39.9900<br />
270 KRES 414880 -434.746 -611.717 96.9949 39.9945<br />
271 LKCK 414975 99.734 -693.521 97.0012 39.9937<br />
272 LNGV 415348 220.962 -844.674 97.0026 39.9924<br />
273 LUFK 415424 214.652 -969.69 97.0025 39.9912<br />
274 MATH 415661 -86.438 -1330.47 96.9990 39.9880<br />
275 MIDR 415890 -489.385 -878.123 96.9942 39.9921<br />
276 MTLK 416104 -672.024 -1008.98 96.9921 39.9909<br />
277 NACO 416177 223.065 -925.966 97.0026 39.9916<br />
OG&E / Sargent & Lundy A-12 Trinity Consultants<br />
BART Modeling Report 083701.0004
LCC LCC<br />
<strong>Station</strong> <strong>Station</strong> East North<br />
Number Acronym ID (km) (km) Long Lat<br />
278 NAVA 416210 28.358 -892.028 97.0003 39.9919<br />
279 NEWB 416270 239.111 -721.818 97.0028 39.9935<br />
280 BPAT 417174 288.962 -1110.65 97.0034 39.9900<br />
281 RANK 417431 -472.048 -959.488 96.9944 39.9913<br />
282 SAAG 417943 -333.338 -952.54 96.9961 39.9914<br />
283 SAAT 417945 -143.322 -1161.27 96.9983 39.9895<br />
284 SHEF 418252 -463.759 -1019.19 96.9945 39.9908<br />
285 STEP 418623 -112.988 -857.918 96.9987 39.9922<br />
286 STER 418630 -376.683 -897.195 96.9956 39.9919<br />
287 VALE 419270 -720.749 -1015.17 96.9915 39.9908<br />
288 VICT 419364 6.882 -1236.45 97.0001 39.9888<br />
289 WACO 419419 -21.834 -928.823 96.9997 39.9916<br />
290 WATR 419499 -353.767 -916.015 96.9958 39.9917<br />
291 WHEE 419665 57.489 -1008.99 97.0007 39.9909<br />
292 WPDM 419916 262.792 -737.786 97.0031 39.9933<br />
293 DORA 232302 433.256 -378.797 97.0051 39.9966<br />
294 DIXN 112353 756.057 -267.193 97.0089 39.9976<br />
295 DAUP 12172 864.408 -1050.41 97.0102 39.9905<br />
296 FREV 123104 847.031 -117.884 97.0100 39.9989<br />
297 WARR 18673 890.447 -788.703 97.0105 39.9929<br />
298 MDTN 235562 493.264 -87.222 97.0058 39.9992<br />
OG&E / Sargent & Lundy A-13 Trinity Consultants<br />
BART Modeling Report 083701.0004
TABLE A-4. LIST OF OVER WATER METEOROLOGICAL STATIONS<br />
<strong>Station</strong> Input file<br />
LCC<br />
East LCC North<br />
Number ID Name (km) (km) Long Lat<br />
1 42001 42001 746.874 -1541.35 89.67 25.9<br />
2 42002 42002 265.486 -1650.616 94.42 25.19<br />
3 42007 42007 795.674 -1063.667 88.77 30.09<br />
4 42019 42019 163.178 -1342.917 95.36 27.91<br />
5 42020 42020 30.212 -1453.738 96.7 26.94<br />
6 42035 42035 254.465 -1193.539 94.41 29.25<br />
7 42040 42040 859.497 -1160.066 88.21 29.18<br />
8 BURL1 42045 743.116 -1202.117 89.43 28.9<br />
9 DPIA1 42046 861.385 -1039.466 88.07 30.25<br />
10 GDIL1 42047 687.984 -1164.910 89.96 29.27<br />
11 PTAT2 42048 -4.980 -1353.398 97.05 27.83<br />
12 SRST2 42049 288.163 -1175.682 94.05 29.67<br />
OG&E / Sargent & Lundy A-14 Trinity Consultants<br />
BART Modeling Report 083701.0004
APPENDIX B – SAMPLE CALMET CONTROL FILE<br />
OG&E Trinity Consultants<br />
BART Modeling Protocol 083701.0004
2001 - Refined<br />
January 1 - January 10<br />
01Met01a.inp<br />
---------------- Run title (3 lines) ------------------------------------------<br />
CALMET MODEL CONTROL FILE<br />
--------------------------<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 0 -- Input and Output File Names<br />
Subgroup (a)<br />
------------<br />
Default Name Type File Name<br />
------------ ---- ---------<br />
GEO.DAT input ! GEODAT=GEO.DAT !<br />
SURF.DAT input ! SRFDAT=SURF2001.DAT !<br />
CLOUD.DAT input * CLDDAT= *<br />
PRECIP.DAT input ! PRCDAT=precip01.DAT !<br />
MM4.DAT input ! MM4DAT=W:\01CENRAPMM\extracted_2001_01a_epa_12km.unx !<br />
WT.DAT input * WTDAT= *<br />
CALMET.LST output ! METLST=01Met01a.LST !<br />
CALMET.DAT output ! METDAT=01MET01a.MET !<br />
PACOUT.DAT output * PACDAT= *<br />
All file names will be converted to lower case if LCFILES = T<br />
Otherwise, if LCFILES = F, file names will be converted to UPPER CASE<br />
T = lower case ! LCFILES = T !<br />
F = UPPER CASE<br />
NUMBER OF UPPER AIR & OVERWATER STATIONS:<br />
Number of upper air stations (NUSTA) No default ! NUSTA = 17 !<br />
Number of overwater met stations<br />
(NOWSTA) No default ! NOWSTA = 12 !<br />
!END!<br />
--------------------------------------------------------------------------------<br />
Subgroup (b)<br />
---------------------------------<br />
Upper air files (one per station)<br />
---------------------------------<br />
Default Name Type File Name<br />
------------ ---- ---------<br />
Page 1
01Met01a.inp<br />
UP1.DAT input 1 ! UPDAT=UPABQ01.DAT! !END!<br />
UP2.DAT input 2 ! UPDAT=UPAMA01.DAT! !END!<br />
UP3.DAT input 3 ! UPDAT=UPBMX01.DAT! !END!<br />
UP4.DAT input 4 ! UPDAT=UPBNA01.DAT! !END!<br />
UP5.DAT input 5 ! UPDAT=UPBRO01.DAT! !END!<br />
UP6.DAT input 6 ! UPDAT=UPCRP01.DAT! !END!<br />
UP7.DAT input 7 ! UPDAT=UPDDC01.DAT! !END!<br />
UP8.DAT input 8 ! UPDAT=UPDRT01.DAT! !END!<br />
UP9.DAT input 9 ! UPDAT=UPEPZ01.DAT! !END!<br />
UP10.DAT input 10 ! UPDAT=UPFWD01.DAT! !END!<br />
UP11.DAT input 11 ! UPDAT=UPJAN01.DAT! !END!<br />
UP12.DAT input 12 ! UPDAT=UPLCH01.DAT! !END!<br />
UP13.DAT input 13 ! UPDAT=UPLZK01.DAT! !END!<br />
UP14.DAT input 14 ! UPDAT=UPMAF01.DAT! !END!<br />
UP15.DAT input 15 ! UPDAT=UPOUN01.DAT! !END!<br />
UP16.DAT input 16 ! UPDAT=UPSHV01.DAT! !END!<br />
UP17.DAT input 17 ! UPDAT=UPSIL01.DAT! !END!<br />
--------------------------------------------------------------------------------<br />
Subgroup (c)<br />
-----------------------------------------<br />
Overwater station files (one per station)<br />
-----------------------------------------<br />
Default Name Type File Name<br />
------------ ---- ---------<br />
OW1.DAT input 1 ! SEADAT=42001_01_sea.dat! !END!<br />
OW2.DAT input 2 ! SEADAT=42002_01_sea.dat! !END!<br />
OW3.DAT input 3 ! SEADAT=42007_01_sea.dat! !END!<br />
OW4.DAT input 4 ! SEADAT=42019_01_sea.dat! !END!<br />
OW5.DAT input 5 ! SEADAT=42020_01_sea.dat! !END!<br />
OW6.DAT input 6 ! SEADAT=42035_01_sea.dat! !END!<br />
OW7.DAT input 7 ! SEADAT=42040_01_sea.dat! !END!<br />
OW8.DAT input 8 ! SEADAT=42045_01_sea.dat! !END!<br />
OW9.DAT input 9 ! SEADAT=42046_01_sea.dat! !END!<br />
OW10.DAT input 10 ! SEADAT=42047_01_sea.dat! !END!<br />
OW11.DAT input 11 ! SEADAT=42048_01_sea.dat! !END!<br />
OW12.DAT input 12 ! SEADAT=42049_01_sea.dat! !END!<br />
--------------------------------------------------------------------------------<br />
Subgroup (d)<br />
----------------<br />
Other file names<br />
----------------<br />
Default Name Type File Name<br />
------------ ---- ---------<br />
DIAG.DAT input * DIADAT= *<br />
PROG.DAT input * PRGDAT= *<br />
Page 2
TEST.PRT output * TSTPRT= *<br />
TEST.OUT output * TSTOUT= *<br />
TEST.KIN output * TSTKIN= *<br />
TEST.FRD output * TSTFRD= *<br />
TEST.SLP output * TSTSLP= *<br />
01Met01a.inp<br />
--------------------------------------------------------------------------------<br />
NOTES: (1) File/path names can be up to 70 characters in length<br />
(2) Subgroups (a) and (d) must have ONE 'END' (surround by<br />
delimiters) at the end of the group<br />
(3) Subgroups (b) and (c) must have an 'END' (surround by<br />
delimiters) at the end of EACH LINE<br />
!END!<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 1 -- General run control parameters<br />
--------------<br />
Starting date: Year (IBYR) -- No default ! IBYR= 2001 !<br />
Month (IBMO) -- No default ! IBMO= 1 !<br />
Day (IBDY) -- No default ! IBDY= 1 !<br />
Hour (IBHR) -- No default ! IBHR= 0 !<br />
Base time zone (IBTZ) -- No default ! IBTZ= 6 !<br />
PST = 08, MST = 07<br />
CST = 06, EST = 05<br />
Length of run (hours) (IRLG) -- No default ! IRLG= 240 !<br />
Run type (IRTYPE) -- Default: 1 ! IRTYPE= 1 !<br />
0 = Computes wind fields only<br />
1 = Computes wind fields and micrometeorological variables<br />
(u*, w*, L, zi, etc.)<br />
(IRTYPE must be 1 to run CALPUFF or CALGRID)<br />
Compute special data fields required<br />
by CALGRID (i.e., 3-D fields of W wind<br />
components and temperature)<br />
in additional to regular Default: T ! LCALGRD = T !<br />
fields ? (LCALGRD)<br />
(LCALGRD must be T to run CALGRID)<br />
Flag to stop run after<br />
Page 3
!END!<br />
01Met01a.inp<br />
SETUP phase (ITEST) Default: 2 ! ITEST= 2 !<br />
(Used to allow checking<br />
of the model inputs, files, etc.)<br />
ITEST = 1 - STOPS program after SETUP phase<br />
ITEST = 2 - Continues with execution of<br />
COMPUTATIONAL phase after SETUP<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 2 -- Map Projection and Grid control parameters<br />
--------------<br />
Projection for all (X,Y):<br />
-------------------------<br />
Map projection<br />
(PMAP) Default: UTM ! PMAP = LCC !<br />
UTM : Universal Transverse Mercator<br />
TTM : Tangential Transverse Mercator<br />
LCC : Lambert Conformal Conic<br />
PS : Polar Stereographic<br />
EM : Equatorial Mercator<br />
LAZA : Lambert Azimuthal Equal Area<br />
False Easting and Northing (km) at the projection origin<br />
(Used only if PMAP= TTM, LCC, or LAZA)<br />
(FEAST) Default=0.0 ! FEAST = 0.000 !<br />
(FNORTH) Default=0.0 ! FNORTH = 0.000 !<br />
UTM zone (1 to 60)<br />
(Used only if PMAP=UTM)<br />
(IUTMZN) No Default ! IUTMZN = 0 !<br />
Hemisphere for UTM projection?<br />
(Used only if PMAP=UTM)<br />
(UTMHEM) Default: N ! UTMHEM = N !<br />
N : Northern hemisphere projection<br />
S : Southern hemisphere projection<br />
Latitude and Longitude (decimal degrees) of projection origin<br />
(Used only if PMAP= TTM, LCC, PS, EM, or LAZA)<br />
(RLAT0) No Default ! RLAT0 = 40N !<br />
(RLON0) No Default ! RLON0 = 97W !<br />
TTM : RLON0 identifies central (true N/S) meridian of projection<br />
Page 4
01Met01a.inp<br />
RLAT0 selected for convenience<br />
LCC : RLON0 identifies central (true N/S) meridian of projection<br />
RLAT0 selected for convenience<br />
PS : RLON0 identifies central (grid N/S) meridian of projection<br />
RLAT0 selected for convenience<br />
EM : RLON0 identifies central meridian of projection<br />
RLAT0 is REPLACED by 0.0N (Equator)<br />
LAZA: RLON0 identifies longitude of tangent-point of mapping plane<br />
RLAT0 identifies latitude of tangent-point of mapping plane<br />
Matching parallel(s) of latitude (decimal degrees) for projection<br />
(Used only if PMAP= LCC or PS)<br />
(XLAT1) No Default ! XLAT1 = 33N !<br />
(XLAT2) No Default ! XLAT2 = 45N !<br />
LCC : Projection cone slices through Earth's surface at XLAT1 and XLAT2<br />
PS : Projection plane slices through Earth at XLAT1<br />
(XLAT2 is not used)<br />
----------<br />
Note: Latitudes and longitudes should be positive, and include a<br />
letter N,S,E, or W indicating north or south latitude, and<br />
east or west longitude. For example,<br />
35.9 N Latitude = 35.9N<br />
118.7 E Longitude = 118.7E<br />
Datum-region<br />
------------<br />
The Datum-Region for the coordinates is identified by a character<br />
string. Many mapping products currently available use the model of the<br />
Earth known as the World Geodetic System 1984 (WGS-G ). Other local<br />
models may be in use, and their selection in CALMET will make its output<br />
consistent with local mapping products. The list of Datum-Regions with<br />
official transformation parameters is provided by the National Imagery and<br />
Mapping Agency (NIMA).<br />
NIMA Datum - Regions(Examples)<br />
------------------------------------------------------------------------------<br />
WGS-G WGS-84 GRS 80 Spheroid, Global coverage (WGS84)<br />
NAS-C NORTH AMERICAN 1927 Clarke 1866 Spheroid, MEAN FOR CONUS (NAD27)<br />
NWS-27 NWS 6370KM Radius, Sphere<br />
NWS-84 NWS 6370KM Radius, Sphere<br />
ESR-S ESRI REFERENCE 6371KM Radius, Sphere<br />
Datum-region for output coordinates<br />
(DATUM) Default: WGS-G ! DATUM = WGS-G !<br />
Page 5
!END!<br />
Horizontal grid definition:<br />
---------------------------<br />
Rectangular grid defined for projection PMAP,<br />
with X the Easting and Y the Northing coordinate<br />
01Met01a.inp<br />
No. X grid cells (NX) No default ! NX = 462 !<br />
No. Y grid cells (NY) No default ! NY = 376 !<br />
Grid spacing (DGRIDKM) No default ! DGRIDKM = 4. !<br />
Units: km<br />
Reference grid coordinate of<br />
SOUTHWEST corner of grid cell (1,1)<br />
X coordinate (XORIGKM) No default ! XORIGKM = -951.547 !<br />
Y coordinate (YORIGKM) No default ! YORIGKM = -1646.637 !<br />
Units: km<br />
Vertical grid definition:<br />
-------------------------<br />
No. of vertical layers (NZ) No default ! NZ = 12 !<br />
Cell face heights in arbitrary<br />
vertical grid (ZFACE(NZ+1)) No defaults<br />
Units: m<br />
! ZFACE = 0.,20.,40.,60.,80.,100.,150.,200.,250.,500.,1000.,2000.,3500. !<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 3 -- Output Options<br />
--------------<br />
DISK OUTPUT OPTION<br />
Save met. fields in an unformatted<br />
output file ? (LSAVE) Default: T ! LSAVE = T !<br />
(F = Do not save, T = Save)<br />
Type of unformatted output file:<br />
Page 6
01Met01a.inp<br />
(IFORMO) Default: 1 ! IFORMO = 1 !<br />
1 = CALPUFF/CALGRID type file (CALMET.DAT)<br />
2 = MESOPUFF-II type file (PACOUT.DAT)<br />
LINE PRINTER OUTPUT OPTIONS:<br />
Print met. fields ? (LPRINT) Default: F ! LPRINT = T !<br />
(F = Do not print, T = Print)<br />
(NOTE: parameters below control which<br />
met. variables are printed)<br />
Print interval<br />
(IPRINF) in hours Default: 1 ! IPRINF = 1 !<br />
(Meteorological fields are printed<br />
every 1 hours)<br />
Specify which layers of U, V wind component<br />
to print (IUVOUT(NZ)) -- NOTE: NZ values must be entered<br />
(0=Do not print, 1=Print)<br />
(used only if LPRINT=T) Defaults: NZ*0<br />
! IUVOUT = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 !<br />
-----------------------<br />
Specify which levels of the W wind component to print<br />
(NOTE: W defined at TOP cell face -- 12 values)<br />
(IWOUT(NZ)) -- NOTE: NZ values must be entered<br />
(0=Do not print, 1=Print)<br />
(used only if LPRINT=T & LCALGRD=T)<br />
-----------------------------------<br />
Defaults: NZ*0<br />
! IWOUT = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 !<br />
Specify which levels of the 3-D temperature field to print<br />
(ITOUT(NZ)) -- NOTE: NZ values must be entered<br />
(0=Do not print, 1=Print)<br />
(used only if LPRINT=T & LCALGRD=T)<br />
-----------------------------------<br />
Defaults: NZ*0<br />
! ITOUT = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 !<br />
Specify which meteorological fields<br />
to print<br />
(used only if LPRINT=T) Defaults: 0 (all variables)<br />
Page 7
-----------------------<br />
Variable Print ?<br />
(0 = do not print,<br />
1 = print)<br />
-------- ------------------<br />
01Met01a.inp<br />
! STABILITY = 0 ! - PGT stability class<br />
! USTAR = 0 ! - Friction velocity<br />
! MONIN = 0 ! - Monin-Obukhov length<br />
! MIXHT = 0 ! - Mixing height<br />
! WSTAR = 0 ! - Convective velocity scale<br />
! PRECIP = 0 ! - Precipitation rate<br />
! SENSHEAT = 0 ! - Sensible heat flux<br />
! CONVZI = 0 ! - Convective mixing ht.<br />
Testing and debug print options for micrometeorological module<br />
Print input meteorological data and<br />
internal variables (LDB) Default: F ! LDB = F !<br />
(F = Do not print, T = print)<br />
(NOTE: this option produces large amounts of output)<br />
First time step for which debug data<br />
are printed (NN1) Default: 1 ! NN1 = 1 !<br />
Last time step for which debug data<br />
are printed (NN2) Default: 1 ! NN2 = 1 !<br />
Testing and debug print options for wind field module<br />
(all of the following print options control output to<br />
wind field module's output files: TEST.PRT, TEST.OUT,<br />
TEST.KIN, TEST.FRD, and TEST.SLP)<br />
Control variable for writing the test/debug<br />
wind fields to disk files (IOUTD)<br />
(0=Do not write, 1=write) Default: 0 ! IOUTD = 0 !<br />
Number of levels, starting at the surface,<br />
to print (NZPRN2) Default: 1 ! NZPRN2 = 0 !<br />
Print the INTERPOLATED wind components ?<br />
(IPR0) (0=no, 1=yes) Default: 0 ! IPR0 = 0 !<br />
Print the TERRAIN ADJUSTED surface wind<br />
Page 8
!END!<br />
01Met01a.inp<br />
components ?<br />
(IPR1) (0=no, 1=yes) Default: 0 ! IPR1 = 0 !<br />
Print the SMOOTHED wind components and<br />
the INITIAL DIVERGENCE fields ?<br />
(IPR2) (0=no, 1=yes) Default: 0 ! IPR2 = 0 !<br />
Print the FINAL wind speed and direction<br />
fields ?<br />
(IPR3) (0=no, 1=yes) Default: 0 ! IPR3 = 0 !<br />
Print the FINAL DIVERGENCE fields ?<br />
(IPR4) (0=no, 1=yes) Default: 0 ! IPR4 = 0 !<br />
Print the winds after KINEMATIC effects<br />
are added ?<br />
(IPR5) (0=no, 1=yes) Default: 0 ! IPR5 = 0 !<br />
Print the winds after the FROUDE NUMBER<br />
adjustment is made ?<br />
(IPR6) (0=no, 1=yes) Default: 0 ! IPR6 = 0 !<br />
Print the winds after SLOPE FLOWS<br />
are added ?<br />
(IPR7) (0=no, 1=yes) Default: 0 ! IPR7 = 0 !<br />
Print the FINAL wind field components ?<br />
(IPR8) (0=no, 1=yes) Default: 0 ! IPR8 = 0 !<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 4 -- Meteorological data options<br />
--------------<br />
NO OBSERVATION MODE (NOOBS) Default: 0 ! NOOBS = 0 !<br />
0 = Use surface, overwater, and upper air stations<br />
1 = Use surface and overwater stations (no upper air observations)<br />
Use MM5 for upper air data<br />
2 = No surface, overwater, or upper air observations<br />
Use MM5 for surface, overwater, and upper air data<br />
NUMBER OF SURFACE & PRECIP. METEOROLOGICAL STATIONS<br />
Number of surface stations (NSSTA) No default ! NSSTA = 162 !<br />
Page 9
!END!<br />
01Met01a.inp<br />
Number of precipitation stations<br />
(NPSTA=-1: flag for use of MM5 precip data)<br />
(NPSTA) No default ! NPSTA = 298 !<br />
CLOUD DATA OPTIONS<br />
Gridded cloud fields:<br />
(ICLOUD) Default: 0 ! ICLOUD = 0 !<br />
ICLOUD = 0 - Gridded clouds not used<br />
ICLOUD = 1 - Gridded CLOUD.DAT generated as OUTPUT<br />
ICLOUD = 2 - Gridded CLOUD.DAT read as INPUT<br />
ICLOUD = 3 - Gridded cloud cover from Prognostic Rel. Humidity<br />
FILE FORMATS<br />
Surface meteorological data file format<br />
(IFORMS) Default: 2 ! IFORMS = 2 !<br />
(1 = unformatted (e.g., SMERGE output))<br />
(2 = formatted (free-formatted user input))<br />
Precipitation data file format<br />
(IFORMP) Default: 2 ! IFORMP = 2 !<br />
(1 = unformatted (e.g., PMERGE output))<br />
(2 = formatted (free-formatted user input))<br />
Cloud data file format<br />
(IFORMC) Default: 2 ! IFORMC = 1 !<br />
(1 = unformatted - CALMET unformatted output)<br />
(2 = formatted - free-formatted CALMET output or user input)<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 5 -- Wind Field Options and Parameters<br />
--------------<br />
WIND FIELD MODEL OPTIONS<br />
Model selection variable (IWFCOD) Default: 1 ! IWFCOD = 1 !<br />
0 = Objective analysis only<br />
1 = Diagnostic wind module<br />
Compute Froude number adjustment<br />
effects ? (IFRADJ) Default: 1 ! IFRADJ = 1 !<br />
(0 = NO, 1 = YES)<br />
Compute kinematic effects ? (IKINE) Default: 0 ! IKINE = 0 !<br />
Page 10
(0 = NO, 1 = YES)<br />
01Met01a.inp<br />
Use O'Brien procedure for adjustment<br />
of the vertical velocity ? (IOBR) Default: 0 ! IOBR = 0 !<br />
(0 = NO, 1 = YES)<br />
Compute slope flow effects ? (ISLOPE) Default: 1 ! ISLOPE = 1 !<br />
(0 = NO, 1 = YES)<br />
Extrapolate surface wind observations<br />
to upper layers ? (IEXTRP) Default: -4 ! IEXTRP = -4 !<br />
(1 = no extrapolation is done,<br />
2 = power law extrapolation used,<br />
3 = user input multiplicative factors<br />
for layers 2 - NZ used (see FEXTRP array)<br />
4 = similarity theory used<br />
-1, -2, -3, -4 = same as above except layer 1 data<br />
at upper air stations are ignored<br />
Extrapolate surface winds even<br />
if calm? (ICALM) Default: 0 ! ICALM = 0 !<br />
(0 = NO, 1 = YES)<br />
Layer-dependent biases modifying the weights of<br />
surface and upper air stations (BIAS(NZ))<br />
-1
01Met01a.inp<br />
2 = Yes, use CSUMM prog. winds as initial guess field [IWFCOD = 1]<br />
3 = Yes, use winds from MM4.DAT file as Step 1 field [IWFCOD = 0]<br />
4 = Yes, use winds from MM4.DAT file as initial guess field [IWFCOD = 1]<br />
5 = Yes, use winds from MM4.DAT file as observations [IWFCOD = 1]<br />
13 = Yes, use winds from MM5.DAT file as Step 1 field [IWFCOD = 0]<br />
14 = Yes, use winds from MM5.DAT file as initial guess field [IWFCOD = 1]<br />
15 = Yes, use winds from MM5.DAT file as observations [IWFCOD = 1]<br />
Timestep (hours) of the prognostic<br />
model input data (ISTEPPG) Default: 1 ! ISTEPPG = 1 !<br />
RADIUS OF INFLUENCE PARAMETERS<br />
Use varying radius of influence Default: F ! LVARY = T!<br />
(if no stations are found within RMAX1,RMAX2,<br />
or RMAX3, then the closest station will be used)<br />
Maximum radius of influence over land<br />
in the surface layer (RMAX1) No default ! RMAX1 = 20. !<br />
Units: km<br />
Maximum radius of influence over land<br />
aloft (RMAX2) No default ! RMAX2 = 50. !<br />
Units: km<br />
Maximum radius of influence over water<br />
(RMAX3) No default ! RMAX3 = 500. !<br />
Units: km<br />
OTHER WIND FIELD INPUT PARAMETERS<br />
Minimum radius of influence used in<br />
the wind field interpolation (RMIN) Default: 0.1 ! RMIN = 0.1 !<br />
Units: km<br />
Radius of influence of terrain<br />
features (TERRAD) No default ! TERRAD = 10. !<br />
Units: km<br />
Relative weighting of the first<br />
guess field and observations in the<br />
SURFACE layer (R1) No default ! R1 = 10. !<br />
(R1 is the distance from an Units: km<br />
observational station at which the<br />
observation and first guess field are<br />
equally weighted)<br />
Relative weighting of the first<br />
guess field and observations in the<br />
layers ALOFT (R2) No default ! R2 = 25. !<br />
Page 12
01Met01a.inp<br />
(R2 is applied in the upper layers Units: km<br />
in the same manner as R1 is used in<br />
the surface layer).<br />
Relative weighting parameter of the<br />
prognostic wind field data (RPROG) No default ! RPROG = 54. !<br />
(Used only if IPROG = 1) Units: km<br />
------------------------<br />
Maximum acceptable divergence in the<br />
divergence minimization procedure<br />
(DIVLIM) Default: 5.E-6 ! DIVLIM= 5.0E-06 !<br />
Maximum number of iterations in the<br />
divergence min. procedure (NITER) Default: 50 ! NITER = 50 !<br />
Number of passes in the smoothing<br />
procedure (NSMTH(NZ))<br />
NOTE: NZ values must be entered<br />
Default: 2,(mxnz-1)*4 ! NSMTH =<br />
2 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 !<br />
Maximum number of stations used in<br />
each layer for the interpolation of<br />
data to a grid point (NINTR2(NZ))<br />
NOTE: NZ values must be entered Default: 99. ! NINTR2 =<br />
99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 !<br />
Critical Froude number (CRITFN) Default: 1.0 ! CRITFN = 1. !<br />
Empirical factor controlling the<br />
influence of kinematic effects<br />
(ALPHA) Default: 0.1 ! ALPHA = 0.1 !<br />
Multiplicative scaling factor for<br />
extrapolation of surface observations<br />
to upper layers (FEXTR2(NZ)) Default: NZ*0.0<br />
! FEXTR2 = 0., 0., 0., 0., 0., 0., 0., 0., 0., 0., 0., 0. !<br />
(Used only if IEXTRP = 3 or -3)<br />
BARRIER INFORMATION<br />
Number of barriers to interpolation<br />
of the wind fields (NBAR) Default: 0 ! NBAR = 0 !<br />
THE FOLLOWING 4 VARIABLES ARE INCLUDED<br />
ONLY IF NBAR > 0<br />
Page 13
01Met01a.inp<br />
NOTE: NBAR values must be entered No defaults<br />
for each variable Units: km<br />
X coordinate of BEGINNING<br />
of each barrier (XBBAR(NBAR)) ! XBBAR = 0. !<br />
Y coordinate of BEGINNING<br />
of each barrier (YBBAR(NBAR)) ! YBBAR = 0. !<br />
X coordinate of ENDING<br />
of each barrier (XEBAR(NBAR)) ! XEBAR = 0. !<br />
Y coordinate of ENDING<br />
of each barrier (YEBAR(NBAR)) ! YEBAR = 0. !<br />
DIAGNOSTIC MODULE DATA INPUT OPTIONS<br />
Surface temperature (IDIOPT1) Default: 0 ! IDIOPT1 = 0 !<br />
0 = Compute internally from<br />
hourly surface observations<br />
1 = Read preprocessed values from<br />
a data file (DIAG.DAT)<br />
Surface met. station to use for<br />
the surface temperature (ISURFT) No default ! ISURFT = 64 !<br />
(Must be a value from 1 to NSSTA)<br />
(Used only if IDIOPT1 = 0)<br />
--------------------------<br />
Domain-averaged temperature lapse<br />
rate (IDIOPT2) Default: 0 ! IDIOPT2 = 0 !<br />
0 = Compute internally from<br />
twice-daily upper air observations<br />
1 = Read hourly preprocessed values<br />
from a data file (DIAG.DAT)<br />
Upper air station to use for<br />
the domain-scale lapse rate (IUPT) No default ! IUPT = 10 !<br />
(Must be a value from 1 to NUSTA)<br />
(Used only if IDIOPT2 = 0)<br />
--------------------------<br />
Depth through which the domain-scale<br />
lapse rate is computed (ZUPT) Default: 200. ! ZUPT = 200. !<br />
(Used only if IDIOPT2 = 0) Units: meters<br />
--------------------------<br />
Domain-averaged wind components<br />
(IDIOPT3) Default: 0 ! IDIOPT3 = 0 !<br />
Page 14
01Met01a.inp<br />
0 = Compute internally from<br />
twice-daily upper air observations<br />
1 = Read hourly preprocessed values<br />
a data file (DIAG.DAT)<br />
Upper air station to use for<br />
the domain-scale winds (IUPWND) Default: -1 ! IUPWND = -1 !<br />
(Must be a value from -1 to NUSTA)<br />
(Used only if IDIOPT3 = 0)<br />
--------------------------<br />
Bottom and top of layer through<br />
which the domain-scale winds<br />
are computed<br />
(ZUPWND(1), ZUPWND(2)) Defaults: 1., 1000. ! ZUPWND= 1., 2000. !<br />
(Used only if IDIOPT3 = 0) Units: meters<br />
--------------------------<br />
Observed surface wind components<br />
for wind field module (IDIOPT4) Default: 0 ! IDIOPT4 = 0 !<br />
0 = Read WS, WD from a surface<br />
data file (SURF.DAT)<br />
1 = Read hourly preprocessed U, V from<br />
a data file (DIAG.DAT)<br />
Observed upper air wind components<br />
for wind field module (IDIOPT5) Default: 0 ! IDIOPT5 = 0 !<br />
0 = Read WS, WD from an upper<br />
air data file (UP1.DAT, UP2.DAT, etc.)<br />
1 = Read hourly preprocessed U, V from<br />
a data file (DIAG.DAT)<br />
LAKE BREEZE INFORMATION<br />
Use Lake Breeze Module (LLBREZE)<br />
Default: F ! LLBREZE = F !<br />
Number of lake breeze regions (NBOX) ! NBOX = 0 !<br />
X Grid line 1 defining the region of interest<br />
X Grid line 2 defining the region of interest<br />
Y Grid line 1 defining the region of interest<br />
Y Grid line 2 defining the region of interest<br />
Page 15<br />
! XG1 = 0. !<br />
! XG2 = 0. !<br />
! YG1 = 0. !<br />
! YG2 = 0. !
!END!<br />
01Met01a.inp<br />
X Point defining the coastline (Straight line)<br />
(XBCST) (KM) Default: none ! XBCST = 0. !<br />
Y Point defining the coastline (Straight line)<br />
(YBCST) (KM) Default: none ! YBCST = 0. !<br />
X Point defining the coastline (Straight line)<br />
(XECST) (KM) Default: none ! XECST = 0. !<br />
Y Point defining the coastline (Straight line)<br />
(YECST) (KM) Default: none ! YECST = 0. !<br />
Number of stations in the region Default: none ! NLB = 0 !<br />
(Surface stations + upper air stations)<br />
<strong>Station</strong> ID's in the region (METBXID(NLB))<br />
(Surface stations first, then upper air stations)<br />
! METBXID = 0 !<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 6 -- Mixing Height, Temperature and Precipitation Parameters<br />
--------------<br />
EMPIRICAL MIXING HEIGHT CONSTANTS<br />
Neutral, mechanical equation<br />
(CONSTB) Default: 1.41 ! CONSTB = 1.41 !<br />
Convective mixing ht. equation<br />
(CONSTE) Default: 0.15 ! CONSTE = 0.15 !<br />
Stable mixing ht. equation<br />
(CONSTN) Default: 2400. ! CONSTN = 2400.!<br />
Overwater mixing ht. equation<br />
(CONSTW) Default: 0.16 ! CONSTW = 0.16 !<br />
Absolute value of Coriolis<br />
parameter (FCORIOL) Default: 1.E-4 ! FCORIOL = 1.0E-04!<br />
Units: (1/s)<br />
SPATIAL AVERAGING OF MIXING HEIGHTS<br />
Conduct spatial averaging<br />
(IAVEZI) (0=no, 1=yes) Default: 1 ! IAVEZI = 1 !<br />
Max. search radius in averaging<br />
Page 16
01Met01a.inp<br />
process (MNMDAV) Default: 1 ! MNMDAV = 1 !<br />
Units: Grid<br />
cells<br />
Half-angle of upwind looking cone<br />
for averaging (HAFANG) Default: 30. ! HAFANG = 30. !<br />
Units: deg.<br />
Layer of winds used in upwind<br />
averaging (ILEVZI) Default: 1 ! ILEVZI = 1 !<br />
(must be between 1 and NZ)<br />
OTHER MIXING HEIGHT VARIABLES<br />
Minimum potential temperature lapse<br />
rate in the stable layer above the<br />
current convective mixing ht. Default: 0.001 ! DPTMIN = 0.001 !<br />
(DPTMIN) Units: deg. K/m<br />
Depth of layer above current conv.<br />
mixing height through which lapse Default: 200. ! DZZI = 200. !<br />
rate is computed (DZZI) Units: meters<br />
Minimum overland mixing height Default: 50. ! ZIMIN = 20. !<br />
(ZIMIN) Units: meters<br />
Maximum overland mixing height Default: 3000. ! ZIMAX = 3500. !<br />
(ZIMAX) Units: meters<br />
Minimum overwater mixing height Default: 50. ! ZIMINW = 20. !<br />
(ZIMINW) -- (Not used if observed Units: meters<br />
overwater mixing hts. are used)<br />
Maximum overwater mixing height Default: 3000. ! ZIMAXW = 3500. !<br />
(ZIMAXW) -- (Not used if observed Units: meters<br />
overwater mixing hts. are used)<br />
TEMPERATURE PARAMETERS<br />
3D temperature from observations or<br />
from prognostic data? (ITPROG) Default:0 !ITPROG = 0 !<br />
0 = Use Surface and upper air stations<br />
(only if NOOBS = 0)<br />
1 = Use Surface stations (no upper air observations)<br />
Use MM5 for upper air data<br />
(only if NOOBS = 0,1)<br />
2 = No surface or upper air observations<br />
Use MM5 for surface and upper air data<br />
(only if NOOBS = 0,1,2)<br />
Interpolation type<br />
(1 = 1/R ; 2 = 1/R**2) Default:1 ! IRAD = 1 !<br />
Page 17
!END!<br />
01Met01a.inp<br />
Radius of influence for temperature<br />
interpolation (TRADKM) Default: 500. ! TRADKM = 500. !<br />
Units: km<br />
Maximum Number of stations to include<br />
in temperature interpolation (NUMTS) Default: 5 ! NUMTS = 5 !<br />
Conduct spatial averaging of temperatures<br />
(IAVET) (0=no, 1=yes) Default: 1 ! IAVET = 1 !<br />
(will use mixing ht MNMDAV,HAFANG<br />
so make sure they are correct)<br />
Default temperature gradient Default: -.0098 ! TGDEFB = -0.0098 !<br />
below the mixing height over<br />
water (K/m) (TGDEFB)<br />
Default temperature gradient Default: -.0045 ! TGDEFA = -0.0045 !<br />
above the mixing height over<br />
water (K/m) (TGDEFA)<br />
Beginning (JWAT1) and ending (JWAT2)<br />
land use categories for temperature ! JWAT1 = 55 !<br />
interpolation over water -- Make ! JWAT2 = 55 !<br />
bigger than largest land use to disable<br />
PRECIP INTERPOLATION PARAMETERS<br />
Method of interpolation (NFLAGP) Default = 2 ! NFLAGP = 2 !<br />
(1=1/R,2=1/R**2,3=EXP/R**2)<br />
Radius of Influence (km) (SIGMAP) Default = 100.0 ! SIGMAP = 100. !<br />
(0.0 => use half dist. btwn<br />
nearest stns w & w/out<br />
precip when NFLAGP = 3)<br />
Minimum Precip. Rate Cutoff (mm/hr) Default = 0.01 ! CUTP = 0.01 !<br />
(values < CUTP = 0.0 mm/hr)<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 7 -- Surface meteorological station parameters<br />
--------------<br />
SURFACE STATION VARIABLES<br />
(One record per station -- 15 records in all)<br />
Page 18
01Met01a.inp<br />
1 2<br />
Name ID X coord. Y coord. Time Anem.<br />
(km) (km) zone Ht.(m)<br />
----------------------------------------------------------<br />
! SS1 ='KDYS' 69019 -267.672 -834.095 6 4 !<br />
! SS2 ='KNPA' 72222 932.565 -1020.909 6 10 !<br />
! SS3 ='KBFM' 72223 857.471 -996.829 6 10 !<br />
! SS4 ='KGZH' 72227 946.767 -899.515 6 10 !<br />
! SS5 ='KTCL' 72228 870.843 -706.104 6 10 !<br />
! SS6 ='KNEW' 53917 674.172 -1078.342 6 8 !<br />
! SS7 ='KNBG' 12958 677.719 -1104.227 6 10 !<br />
! SS8 ='BVE ' 12884 741.996 -1153.463 6 10 !<br />
! SS9 ='KPTN' 72232 550.88 -1124.295 6 10 !<br />
! SS10 ='KMEI' 13865 774.911 -814.225 6 10 !<br />
! SS11 ='KPIB' 72234 728.416 -915.165 6 10 !<br />
! SS12 ='KGLH' 72235 557.072 -703.097 6 6 !<br />
! SS13 ='KHEZ' 11111 540.777 -912.22 6 10 !<br />
! SS14 ='KMCB' 11112 622.755 -949.618 6 10 !<br />
! SS15 ='KGWO' 11113 640.102 -695.286 6 10 !<br />
! SS16 ='KASD' 72236 692.381 -1043.261 6 10 !<br />
! SS17 ='KPOE' 72239 363.294 -984.839 6 4 !<br />
! SS18 ='KBAZ' 72241 -102.133 -1140.886 6 10 !<br />
! SS19 ='KGLS' 72242 215.108 -1185.604 6 8 !<br />
! SS20 ='KDWH' 11114 140.413 -1101.174 6 10 !<br />
! SS21 ='KIAH' 12960 158.266 -1108.37 6 10 !<br />
! SS22 ='KHOU' 72243 167.147 -1147.402 6 10 !<br />
! SS23 ='KEFD' 12906 178.551 -1152.782 6 4 !<br />
! SS24 ='KCXO' 72244 152.739 -1069.309 6 10 !<br />
! SS25 ='KCLL' 11115 60.898 -1044.381 6 8 !<br />
! SS26 ='KLFK' 93987 214.643 -969.355 6 8 !<br />
! SS27 ='KUTS' 11116 136.056 -1026.773 6 10 !<br />
! SS28 ='KTYR' 11117 150.451 -846.207 6 10 !<br />
! SS29 ='KCRS' 72246 56.655 -882.642 6 10 !<br />
! SS30 ='KGGG' 72247 214.572 -841.163 6 10 !<br />
! SS31 ='KGKY' 11118 -9.365 -812.25 6 10 !<br />
! SS32 ='KDTN' 72248 304.827 -821.713 6 10 !<br />
! SS33 ='KBAD' 11119 312.743 -825.101 6 4 !<br />
! SS34 ='KMLU' 11120 465.834 -816.211 6 10 !<br />
! SS35 ='KTVR' 11121 561.446 -840.225 6 10 !<br />
! SS36 ='KTRL' 11122 68.599 -806.417 6 10 !<br />
! SS37 ='KOCH' 72249 216.81 -930.252 6 10 !<br />
! SS38 ='KBRO' 12919 -44.167 -1571.387 6 10 !<br />
! SS39 ='KALI' 72251 -103.012 -1363.74 6 10 !<br />
! SS40 ='KLRD' 12920 -246.548 -1381.603 6 5 !<br />
! SS41 ='KSSF' 72252 -143.386 -1183.35 6 10 !<br />
! SS42 ='KRKP' 11123 -4.965 -1324.914 6 10 !<br />
! SS43 ='KCOT' 11124 -219.097 -1280.964 6 10 !<br />
! SS44 ='KLBX' 11125 150.245 -1207.466 6 10 !<br />
Page 19
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! SS45 ='KSAT' 12921 -143.024 -1160.935 6 10 !<br />
! SS46 ='KHDO' 12962 -211.702 -1178.172 6 10 !<br />
! SS47 ='KSKF' 72253 -154.625 -1177.555 6 4 !<br />
! SS48 ='KHYI' 11126 -84.156 -1122.487 6 10 !<br />
! SS49 ='KTKI' 72254 38.788 -754.791 6 10 !<br />
! SS50 ='KBMQ' 11127 -118.39 -1027.031 6 10 !<br />
! SS51 ='KATT' 11128 -67.587 -1075.97 6 10 !<br />
! SS52 ='KSGR' 11129 131.478 -1151.702 6 10 !<br />
! SS53 ='KGTU' 11130 -65.624 -1033.173 6 10 !<br />
! SS54 ='KVCT' 12912 6.587 -1236.788 6 10 !<br />
! SS55 ='KPSX' 72255 73.878 -1253.33 6 10 !<br />
! SS56 ='KACT' 13959 -22.12 -929.156 6 10 !<br />
! SS57 ='KPWG' 72256 -30.147 -944.073 6 10 !<br />
! SS58 ='KILE' 72257 -65.288 -988.507 6 10 !<br />
! SS59 ='KGRK' 11131 -79.643 -990.173 6 5 !<br />
! SS60 ='KTPL' 11132 -38.203 -981.19 6 10 !<br />
! SS61 ='KDAL' 13960 14.014 -791.89 6 10 !<br />
! SS62 ='KPRX' 72258 143.317 -703.663 6 10 !<br />
! SS63 ='KDTO' 11133 -17.018 -752.974 6 10 !<br />
! SS64 ='KAFW' 72259 -29.564 -777.061 6 10 !<br />
! SS65 ='KFTW' 11134 -34.302 -795.502 6 8 !<br />
! SS66 ='KMWL' 11135 -99.769 -798.767 6 10 !<br />
! SS67 ='KRBD' 11136 12.453 -810.467 6 10 !<br />
! SS68 ='KDRT' 22010 -384.069 -1170.59 6 7 !<br />
! SS69 ='KFST' 72261 -566.418 -988.838 6 10 !<br />
! SS70 ='KGDP' 72262 -739.127 -873.302 6 10 !<br />
! SS71 ='KSJT' 23034 -333.338 -952.54 6 10 !<br />
! SS72 ='KMRF' 72264 -676.265 -1042.616 6 10 !<br />
! SS73 ='KMAF' 23023 -489.668 -878.107 6 8 !<br />
! SS74 ='KINK' 72265 -586.882 -890.654 6 10 !<br />
! SS75 ='KABI' 13962 -252.044 -836.353 6 10 !<br />
! SS76 ='KATS' 11137 -696.818 -763.258 7 21 !<br />
! SS77 ='KCQC' 11138 -785.757 -515.724 7 10 !<br />
! SS78 ='KROW' 23009 -698.822 -712.898 7 8 !<br />
! SS79 ='KSRR' 72268 -789.593 -686.226 7 11 !<br />
! SS80 ='KCNM' 11139 -682.79 -822.109 7 10 !<br />
! SS81 ='KALM' 36870 -838.056 -752.338 7 7 !<br />
! SS82 ='KLRU' 72269 -931.527 -804.112 7 8 !<br />
! SS83 ='KTCS' 72271 -952.353 -695.469 7 10 !<br />
! SS84 ='KSVC' 93063 -1042.029 -752.033 7 10 !<br />
! SS85 ='KDMN' 72272 -1006.77 -799.231 7 10 !<br />
! SS86 ='KMSL' 72323 854.846 -536.687 6 10 !<br />
! SS87 ='KPOF' 72330 578.62 -336.733 6 8 !<br />
! SS88 ='KGTR' 11140 779.065 -689.108 6 10 !<br />
! SS89 ='KTUP' 93862 753.875 -600.337 6 10 !<br />
! SS90 ='KMKL' 72334 727.051 -454.383 6 10 !<br />
! SS91 ='KLRF' 72340 440.654 -550.661 6 10 !<br />
! SS92 ='KHKA' 11141 643.365 -424.419 6 10 !<br />
Page 20
01Met01a.inp<br />
! SS93 ='KHOT' 72341 358.094 -604.603 6 8 !<br />
! SS94 ='KTXK' 11142 278.022 -720.623 6 8 !<br />
! SS95 ='KLLQ' 72342 488.655 -698.008 6 10 !<br />
! SS96 ='KMWT' 72343 254.18 -599.224 6 10 !<br />
! SS97 ='KFSM' 13964 237.97 -512.87 6 10 !<br />
! SS98 ='KSLG' 72344 224.881 -419.064 6 10 !<br />
! SS99 ='KVBT' 11143 248.074 -399.892 6 10 !<br />
! SS100='KHRO' 11144 343.525 -405.601 6 8 !<br />
! SS101='KFLP' 11145 404.239 -399.142 6 10 !<br />
! SS102='KBVX' 11146 480.712 -457.853 6 10 !<br />
! SS103='KROG' 11147 258.44 -397.685 6 10 !<br />
! SS104='KSPS' 13966 -138.053 -664.886 6 10 !<br />
! SS105='KHBR' 72352 -186.121 -551.123 6 10 !<br />
! SS106='KCSM' 11148 -198.844 -513.911 6 10 !<br />
! SS107='KFDR' 11149 -181.653 -625.205 6 10 !<br />
! SS108='KGOK' 72353 -35.905 -458.97 6 10 !<br />
! SS109='KTIK' 72354 -34.581 -506.938 6 5 !<br />
! SS110='KPWA' 11150 -58.596 -493.951 6 8 !<br />
! SS111='KSWO' 11151 -7.42 -425.828 6 10 !<br />
! SS112='KMKO' 72355 146.972 -479.879 6 10 !<br />
! SS113='KRVS' 72356 91.059 -438.276 6 10 !<br />
! SS114='KBVO' 11152 87.136 -357.069 6 9 !<br />
! SS115='KMLC' 11153 110.647 -563.566 6 10 !<br />
! SS116='KOUN' 72357 -40.731 -527.298 6 10 !<br />
! SS117='KLAW' 11154 -129.405 -600.222 6 10 !<br />
! SS118='KCDS' 72360 -300.297 -610.668 6 10 !<br />
! SS119='KGNT' 72362 -985.117 -475.563 6 10 !<br />
! SS120='KGUP' 11155 -1059.475 -427.151 6 10 !<br />
! SS121='KAMA' 23047 -425.319 -518.171 6 10 !<br />
! SS122='KBGD' 72363 -395.603 -466.083 6 10 !<br />
! SS123='KFMN' 72365 -993.449 -297.944 7 10 !<br />
! SS124='KSKX' 72366 -770.464 -355.855 7 10 !<br />
! SS125='KTCC' 23048 -597.271 -511.241 7 10 !<br />
! SS126='KLVS' 23054 -732.565 -448.329 7 10 !<br />
! SS127='KEHR' 72423 812.573 -199.695 6 10 !<br />
! SS128='KEVV' 93817 822.929 -172.715 6 10 !<br />
! SS129='KMVN' 72433 704.666 -154.54 6 7 !<br />
! SS130='KMDH' 11156 676.745 -218.041 6 11 !<br />
! SS131='KBLV' 11157 617.659 -136.018 6 4 !<br />
! SS132='KSUS' 3966 547.898 -130.122 6 10 !<br />
! SS133='KPAH' 3816 725.985 -293.319 6 10 !<br />
! SS134='KJEF' 72445 419.01 -145.496 6 10 !<br />
! SS135='KAIZ' 11158 387.096 -200.609 6 10 !<br />
! SS136='KIXD' 72447 182.322 -126.913 6 10 !<br />
! SS137='KWLD' 72450 0 -298.57 6 10 !<br />
! SS138='KAAO' 11159 -18.976 -248.773 6 10 !<br />
! SS139='KIAB' 11160 -23.392 -263.471 6 10 !<br />
! SS140='KEWK' 11161 -24.645 -215.58 6 10 !<br />
Page 21
01Met01a.inp<br />
! SS141='KGBD' 72451 -161.892 -180.781 6 11 !<br />
! SS142='KHYS' 11162 -195.191 -124.723 6 10 !<br />
! SS143='KCFV' 11163 126.442 -319.698 6 10 !<br />
! SS144='KFOE' 72456 114.618 -115.26 6 10 !<br />
! SS145='KEHA' 72460 -432.761 -320.089 6 10 !<br />
! SS146='KALS' 72462 -777.592 -245.892 7 10 !<br />
! SS147='KDRO' 11164 -945.713 -259.163 7 10 !<br />
! SS148='KLHX' 72463 -568.426 -195.178 7 10 !<br />
! SS149='KSPD' 2128 -494.076 -285.176 7 10 !<br />
! SS150='KCOS' 93037 -664.022 -102.596 7 10 !<br />
! SS151='KGUC' 72467 -857.452 -115.301 7 10 !<br />
! SS152='KMTJ' 93013 -940.981 -109.358 7 10 !<br />
! SS153='KCEZ' 72476 -1020.867 -233.14 7 10 !<br />
! SS154='KCPS' 72531 591.652 -136.14 6 10 !<br />
! SS155='KLWV' 72534 808.939 -94.46 6 10 !<br />
! SS156='KPPF' 74543 130.433 -293.855 6 10 !<br />
! SS157='KHOP' 74671 841.751 -324.569 6 3 !<br />
! SS158='KBIX' 74768 778.252 -1028.514 6 15 !<br />
! SS159='KPQL' 11165 814.599 -1019.583 6 10 !<br />
! SS160='MMPG' 76243 -348.007 -1248.779 6 10 !<br />
! SS161='MMMV' 76342 -446.576 -1449.334 6 10 !<br />
! SS162='MMMY' 76394 -316.664 -1581.176 6 10 !<br />
! END !<br />
-------------------<br />
1<br />
Four character string for station name<br />
(MUST START IN COLUMN 9)<br />
!END!<br />
2<br />
Five digit integer for station ID<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 8 -- Upper air meteorological station parameters<br />
--------------<br />
UPPER AIR STATION VARIABLES<br />
(One record per station -- 2 records in all)<br />
1 2<br />
Name ID X coord. Y coord. Time zone<br />
(km) (km)<br />
-----------------------------------------------<br />
Page 22
01Met01a.inp<br />
! US1 ='KABQ' 23050 -869.46 -501.713 7 !<br />
! US2 ='KAMA' 23047 -425.319 -518.171 6 !<br />
! US3 ='KBMX' 53823 951.609 -702.935 6 !<br />
! US4 ='KBNA' 13897 920.739 -377.164 6 !<br />
! US5 ='KBRO' 12919 -44.167 -1571.387 6 !<br />
! US6 ='KCRP' 12924 -51.535 -1360.349 6 !<br />
! US7 ='KDDC' 13985 -259.352 -242.681 6 !<br />
! US8 ='KDRT' 22010 -384.069 -1170.59 6 !<br />
! US9 ='KEPZ' 3020 -914.558 -852.552 7 !<br />
! US10 ='KFWD' 3990 -28.034 -793.745 6 !<br />
! US11 ='KJAN' 3940 650.105 -826.452 6 !<br />
! US12 ='KLCH' 3937 364.461 -1089.145 6 !<br />
! US13 ='KLZK' 3952 432.063 -560.441 6 !<br />
! US14 ='KMAF' 23023 -489.668 -878.107 6 !<br />
! US15 ='KOUN' 3948 -40.731 -527.298 6 !<br />
! US16 ='KSHV' 13957 298.869 -831.166 6 !<br />
! US17 ='KSIL' 53813 698.079 -1054.027 6 !<br />
! END !<br />
-------------------<br />
1<br />
Four character string for station name<br />
(MUST START IN COLUMN 9)<br />
!END!<br />
2<br />
Five digit integer for station ID<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 9 -- Precipitation station parameters<br />
--------------<br />
PRECIPITATION STATION VARIABLES<br />
(One record per station -- 2 records in all)<br />
(NOT INCLUDED IF NPSTA = 0)<br />
1 2<br />
Name <strong>Station</strong> X coord. Y coord.<br />
Code (km) (km)<br />
------------------------------------<br />
! PS1 ='ADDI' 10063 901.489 -592.955 !<br />
! PS2 ='ALBE' 10140 899.884 -812.458 !<br />
! PS3 ='BERR' 10748 867.154 -661.971 !<br />
! PS4 ='HALE' 13620 857.62 -594.261 !<br />
! PS5 ='HAMT' 13645 826.544 -612.409 !<br />
Page 23
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! PS6 ='JACK' 14193 860.868 -896.436 !<br />
! PS7 ='MBLE' 15478 839.791 -992.343 !<br />
! PS8 ='MUSC' 15749 854.937 -537.327 !<br />
! PS9 ='PETE' 16370 922.473 -882.847 !<br />
! PS10 ='THOM' 18178 864.891 -894.227 !<br />
! PS11 ='TUSC' 18385 873.09 -706.684 !<br />
! PS12 ='VERN' 18517 817.964 -653.134 !<br />
! PS13 ='BEEB' 30530 462.78 -533.08 !<br />
! PS14 ='BRIG' 30900 318.637 -553.97 !<br />
! PS15 ='CALI' 31140 419.129 -730.939 !<br />
! PS16 ='CAMD' 31152 386.263 -700.784 !<br />
! PS17 ='DIER' 32020 267.307 -643.487 !<br />
! PS18 ='EURE' 32356 285.714 -391.299 !<br />
! PS19 ='GILB' 32794 383.775 -434.343 !<br />
! PS20 ='GREE' 32978 450.616 -483.139 !<br />
! PS21 ='STUT' 36920 510.166 -595.821 !<br />
! PS22 ='TEXA' 37048 277.314 -720.245 !<br />
! PS23 ='ALAM' 50130 -777.038 -245.291 !<br />
! PS24 ='ARAP' 50304 -445.453 -114.1 !<br />
! PS25 ='COCH' 51713 -843.702 -126.461 !<br />
! PS26 ='CRES' 51959 -856.972 -76.909 !<br />
! PS27 ='GRAN' 53477 -462.184 -201.033 !<br />
! PS28 ='GUNN' 53662 -860.363 -115.346 !<br />
! PS29 ='HUGO' 54172 -556.037 -74.8 !<br />
! PS30 ='JOHN' 54388 -515.918 -197.306 !<br />
! PS31 ='KIM ' 54538 -554.68 -262.307 !<br />
! PS32 ='MESA' 55531 -1009.654 -245.882 !<br />
! PS33 ='ORDW' 56136 -579.524 -141.149 !<br />
! PS34 ='OURA' 56203 -927.308 -164.38 !<br />
! PS35 ='PLEA' 56591 -1029.946 -199.897 !<br />
! PS36 ='PUEB' 56740 -650.053 -162.245 !<br />
! PS37 ='TYE ' 57320 -690.994 -182.032 !<br />
! PS38 ='SAGU' 57337 -793.779 -171.571 !<br />
! PS39 ='SANL' 57428 -740.179 -277.141 !<br />
! PS40 ='SHEP' 57572 -719.528 -220.042 !<br />
! PS41 ='TELL' 58204 -945.961 -170.11 !<br />
! PS42 ='TERC' 58220 -710.321 -292.412 !<br />
! PS43 ='TRIN' 58429 -659.183 -284.829 !<br />
! PS44 ='TRLK' 58436 -665.568 -287.445 !<br />
! PS45 ='WALS' 58781 -680.162 -233.45 !<br />
! PS46 ='WHIT' 58997 -620.426 -211.536 !<br />
! PS47 ='ASHL' 110281 677.366 -155.437 !<br />
! PS48 ='CAIR' 111166 689.241 -297.405 !<br />
! PS49 ='CARM' 111302 766.305 -175.312 !<br />
! PS50 ='CISN' 111664 742.235 -130.227 !<br />
! PS51 ='FLOR' 113109 725.194 -108.412 !<br />
! PS52 ='HARR' 113879 740.195 -215.267 !<br />
! PS53 ='KASK' 114629 613.959 -199.069 !<br />
Page 24
01Met01a.inp<br />
! PS54 ='LAWR' 114957 801.433 -99.657 !<br />
! PS55 ='MTCA' 115888 799.41 -135.062 !<br />
! PS56 ='MURP' 115983 666.735 -219.575 !<br />
! PS57 ='NEWT' 116159 762.897 -82.814 !<br />
! PS58 ='REND' 117187 696.872 -185.925 !<br />
! PS59 ='SMIT' 118020 754.325 -277.976 !<br />
! PS60 ='SPAR' 118147 632.989 -182.867 !<br />
! PS61 ='VAND' 118781 678.924 -84.301 !<br />
! PS62 ='WEST' 119193 775.327 -124.149 !<br />
! PS63 ='EVAN' 122738 824.11 -173.364 !<br />
! PS64 ='NEWB' 126151 838.034 -184.189 !<br />
! PS65 ='PRIN' 127125 814.415 -139.507 !<br />
! PS66 ='STEN' 128442 852.345 -145.206 !<br />
! PS67 ='JTML' 128967 785.86 -204.812 !<br />
! PS68 ='ARLI' 140326 -110.926 -231.799 !<br />
! PS69 ='BAZI' 140620 -238.84 -188.104 !<br />
! PS70 ='BEAU' 140637 40.693 -259.137 !<br />
! PS71 ='BONN' 140957 180.603 -101.448 !<br />
! PS72 ='CALD' 141233 -54.366 -327.856 !<br />
! PS73 ='CASS' 141351 31.591 -215.278 !<br />
! PS74 ='CENT' 141404 167.504 -197.961 !<br />
! PS75 ='CHAN' 141427 132.698 -256.506 !<br />
! PS76 ='CLIN' 141612 142.776 -115.841 !<br />
! PS77 ='COLL' 141730 -267.979 -117.405 !<br />
! PS78 ='COLU' 141740 189.045 -311.581 !<br />
! PS79 ='CONC' 141867 40.931 -146.37 !<br />
! PS80 ='DODG' 142164 -259.414 -242.501 !<br />
! PS81 ='ELKH' 142432 -431.524 -319.478 !<br />
! PS82 ='ENGL' 142560 -264.379 -322.362 !<br />
! PS83 ='ERIE' 142582 153.917 -265.803 !<br />
! PS84 ='FALL' 142686 80.834 -259.783 !<br />
! PS85 ='GALA' 142938 -170.268 -147.301 !<br />
! PS86 ='GARD' 142980 -332.149 -214.978 !<br />
! PS87 ='GREN' 143248 48.554 -292 !<br />
! PS88 ='HAYS' 143527 -201.021 -123.653 !<br />
! PS89 ='HEAL' 143554 -312.756 -148.447 !<br />
! PS90 ='HILL' 143686 182.105 -145.591 !<br />
! PS91 ='INDE' 143954 114.638 -304.755 !<br />
! PS92 ='IOLA' 143984 137.393 -228.466 !<br />
! PS93 ='JOHR' 144104 108.586 -192.14 !<br />
! PS94 ='KANO' 144178 -82.923 -153.502 !<br />
! PS95 ='KIOW' 144341 -131.156 -328.843 !<br />
! PS96 ='MARI' 145039 -6.525 -179.369 !<br />
! PS97 ='MELV' 145210 112.198 -164.627 !<br />
! PS98 ='MILF' 145306 9.466 -102.305 !<br />
! PS99 ='MOUD' 145536 136.55 -309.82 !<br />
! PS100='OAKL' 145888 -338.36 -90.757 !<br />
! PS101='OTTA' 146128 148.524 -151.952 !<br />
Page 25
01Met01a.inp<br />
! PS102='POMO' 146498 123.872 -148.785 !<br />
! PS103='SALI' 147160 -56.156 -132.792 !<br />
! PS104='SMOL' 147551 -57.589 -138.771 !<br />
! PS105='STAN' 147756 201.192 -129.364 !<br />
! PS106='SUBL' 147922 -337.056 -271.996 !<br />
! PS107='TOPE' 148167 116.838 -102.08 !<br />
! PS108='TRIB' 148235 -413.288 -158.742 !<br />
! PS109='UNIO' 148293 176.609 -236.016 !<br />
! PS110='WALL' 148535 -394.195 -111.564 !<br />
! PS111='WICH' 148830 -38.795 -259.177 !<br />
! PS112='WILS' 148946 -127.991 -113.209 !<br />
! PS113='BENT' 150611 765.835 -310.871 !<br />
! PS114='CALH' 151227 852.121 -227.267 !<br />
! PS115='CLTN' 151631 713.076 -341.509 !<br />
! PS116='HERN' 153798 835.039 -324.875 !<br />
! PS117='MADI' 155067 831.766 -250.005 !<br />
! PS118='PADU' 156110 725.315 -292.67 !<br />
! PS119='PCTN' 156580 804.246 -277.545 !<br />
! PS120='ALEX' 160103 433.936 -959.371 !<br />
! PS121='BATN' 160549 563.036 -1031.572 !<br />
! PS122='CALH' 161411 436.36 -818.181 !<br />
! PS123='CLNT' 161899 577.635 -999.204 !<br />
! PS124='JENA' 164696 455.137 -911.689 !<br />
! PS125='LACM' 165078 364.877 -1088.263 !<br />
! PS126='MIND' 166244 347.179 -812.044 !<br />
! PS127='MONR' 166314 462.55 -814.477 !<br />
! PS128='NATC' 166582 369.813 -903.938 !<br />
! PS129='SHRE' 168440 298.233 -831.498 !<br />
! PS130='WINN' 169803 409.193 -884.925 !<br />
! PS131='BROK' 221094 621.134 -914.907 !<br />
! PS132='CONE' 221900 725.078 -804.862 !<br />
! PS133='JAKS' 224472 650.598 -826.11 !<br />
! PS134='LEAK' 224966 805.886 -943.78 !<br />
! PS135='MERI' 225776 775.44 -813.985 !<br />
! PS136='SARD' 227815 659.252 -594.021 !<br />
! PS137='SAUC' 227840 763.366 -1005.558 !<br />
! PS138='TUPE' 229003 753.481 -600.441 !<br />
! PS139='ADVA' 230022 625.39 -296.764 !<br />
! PS140='ALEY' 230088 489.607 -299.884 !<br />
! PS141='BOLI' 230789 316.095 -257.265 !<br />
! PS142='CASV' 231383 278.848 -363.145 !<br />
! PS143='CLER' 231674 548.572 -298.367 !<br />
! PS144='CLTT' 231711 279.768 -172.497 !<br />
! PS145='COLU' 231791 411.752 -119.977 !<br />
! PS146='DREX' 232331 206.841 -165.718 !<br />
! PS147='ELM ' 232568 255.182 -120.998 !<br />
! PS148='FULT' 233079 436.302 -114.093 !<br />
! PS149='HOME' 233999 616.121 -414.248 !<br />
Page 26
01Met01a.inp<br />
! PS150='JEFF' 234271 416.131 -145.612 !<br />
! PS151='JOPL' 234315 220.234 -312.505 !<br />
! PS152='LEBA' 234825 376.787 -247.055 !<br />
! PS153='LICK' 234919 448.45 -257.796 !<br />
! PS154='LOCK' 235027 268.099 -284.021 !<br />
! PS155='MALD' 235207 622.264 -352.069 !<br />
! PS156='MARS' 235298 323.881 -89.005 !<br />
! PS157='MAFD' 235307 359.618 -286.265 !<br />
! PS158='MCES' 235415 438.31 -103.798 !<br />
! PS159='MILL' 235594 279.592 -303.243 !<br />
! PS160='MTGV' 235834 417.444 -303.975 !<br />
! PS161='NVAD' 235987 229.38 -235.588 !<br />
! PS162='OZRK' 236460 332.595 -322.715 !<br />
! PS163='PDTD' 236777 321.295 -225.142 !<br />
! PS164='POTO' 236826 535.474 -215.124 !<br />
! PS165='ROLL' 237263 455.277 -212.788 !<br />
! PS166='ROSE' 237300 486.744 -156.257 !<br />
! PS167='SALE' 237506 478.319 -247.284 !<br />
! PS168='SENE' 237656 212.232 -346.356 !<br />
! PS169='SPRC' 237967 217.784 -330.588 !<br />
! PS170='SPVL' 237976 317.872 -298.923 !<br />
! PS171='STEE' 238043 490.224 -205.375 !<br />
! PS172='STOK' 238082 282.366 -249.68 !<br />
! PS173='SWSP' 238223 307.988 -108.584 !<br />
! PS174='TRKD' 238252 327.995 -369.664 !<br />
! PS175='TRUM' 238466 312.604 -186.416 !<br />
! PS176='UNIT' 238524 223.807 -113.079 !<br />
! PS177='VIBU' 238609 512.995 -236.439 !<br />
! PS178='VIEN' 238620 435.914 -186.806 !<br />
! PS179='WAPP' 238700 593.558 -318.328 !<br />
! PS180='WASG' 238746 520.949 -143.874 !<br />
! PS181='WEST' 238880 457.784 -347.238 !<br />
! PS182='ALBU' 290234 -871.609 -503.095 !<br />
! PS183='ARTE' 290600 -689.914 -774.455 !<br />
! PS184='AUGU' 290640 -974.149 -598.824 !<br />
! PS185='CARL' 291469 -682.406 -821.637 !<br />
! PS186='CARR' 291515 -821.335 -664.892 !<br />
! PS187='CLAY' 291887 -547.48 -374.232 !<br />
! PS188='CLOV' 291939 -566.944 -597.754 !<br />
! PS189='CUBA' 292241 -891.039 -392.352 !<br />
! PS190='CUBE' 292250 -951.736 -488.294 !<br />
! PS191='DEMI' 292436 -1010.101 -798.493 !<br />
! PS192='DURA' 292665 -783.906 -760.939 !<br />
! PS193='EANT' 292700 -733.551 -347.353 !<br />
! PS194='LAVG' 294862 -731.851 -447.93 !<br />
! PS195='PROG' 297094 -812.31 -577.673 !<br />
! PS196='RAMO' 297254 -734.136 -615.047 !<br />
! PS197='ROSW' 297610 -696.498 -712.285 !<br />
Page 27
01Met01a.inp<br />
! PS198='ROY ' 297638 -644.494 -422.842 !<br />
! PS199='SANT' 298085 -806.849 -444.709 !<br />
! PS200='SPRI' 298501 -676.057 -373.646 !<br />
! PS201='STAY' 298518 -808.857 -493.806 !<br />
! PS202='TNMN' 299031 -912.622 -413.503 !<br />
! PS203='TUCU' 299156 -604.957 -508.728 !<br />
! PS204='WAST' 299569 -638.519 -820.543 !<br />
! PS205='WISD' 299686 -856.457 -756.231 !<br />
! PS206='AIRS' 340179 -213.107 -595.912 !<br />
! PS207='ARDM' 340292 -11.884 -645.109 !<br />
! PS208='BENG' 340670 175.595 -567.462 !<br />
! PS209='CANE' 341437 72.343 -638.116 !<br />
! PS210='CHRT' 341544 203.973 -632.111 !<br />
! PS211='CHAN' 341684 10.792 -474.978 !<br />
! PS212='CHIK' 341750 -83.1 -547.384 !<br />
! PS213='CCTY' 342334 -164.531 -479.853 !<br />
! PS214='DUNC' 342654 -87.336 -609.835 !<br />
! PS215='ELKC' 342849 -217.232 -508.297 !<br />
! PS216='FORT' 343281 -130.039 -541.081 !<br />
! PS217='GEAR' 343497 -119.041 -482.918 !<br />
! PS218='HENN' 344052 -31.628 -599.42 !<br />
! PS219='HOBA' 344202 -189.838 -548.204 !<br />
! PS220='KING' 344865 28.421 -670.751 !<br />
! PS221='LKEU' 344975 141.785 -519.552 !<br />
! PS222='LEHI' 345108 71.833 -611.555 !<br />
! PS223='MACI' 345463 -253.239 -466.413 !<br />
! PS224='MALL' 345589 -55.647 -425.395 !<br />
! PS225='MAYF' 345648 -259.989 -511.519 !<br />
! PS226='MUSK' 346130 151.113 -543.185 !<br />
! PS227='NOWA' 346485 120.357 -364.978 !<br />
! PS228='OKAR' 346620 -88.212 -472.171 !<br />
! PS229='OKEM' 346638 62.894 -505.853 !<br />
! PS230='OKLA' 346661 -54.219 -509.977 !<br />
! PS231='PAOL' 346859 -25.939 -572.797 !<br />
! PS232='PAWH' 346935 57.943 -368.158 !<br />
! PS233='PAWN' 346944 16.863 -402.936 !<br />
! PS234='PONC' 347196 -8.402 -362.214 !<br />
! PS235='PRYO' 347309 148.985 -406.842 !<br />
! PS236='SHAT' 348101 -258.12 -406.316 !<br />
! PS237='STIG' 348497 170.629 -524.268 !<br />
! PS238='TULS' 348992 99.361 -419.873 !<br />
! PS239='TUSK' 349023 156.947 -594.453 !<br />
! PS240='WMWR' 349629 -156.042 -581.407 !<br />
! PS241='WOLF' 349748 29.378 -537.437 !<br />
! PS242='BOLI' 400876 723.871 -492.235 !<br />
! PS243='BROW' 401150 696.499 -458.224 !<br />
! PS244='CETR' 401587 858.366 -415.773 !<br />
! PS245='DICS' 402489 858.059 -388.772 !<br />
Page 28
01Met01a.inp<br />
! PS246='DYER' 402680 681.365 -409.615 !<br />
! PS247='GRNF' 403697 732.076 -390.773 !<br />
! PS248='JSNN' 404561 734.39 -451.872 !<br />
! PS249='LWER' 405089 871.334 -477.677 !<br />
! PS250='LEXI' 405210 773.155 -444.948 !<br />
! PS251='MASO' 405720 673.594 -479.476 !<br />
! PS252='MEMP' 405954 635.711 -522.428 !<br />
! PS253='MWFO' 405956 651.601 -513.031 !<br />
! PS254='MUNF' 406358 648.045 -477.095 !<br />
! PS255='SAMB' 408065 684.448 -363.311 !<br />
! PS256='SAVA' 408108 785.195 -498.799 !<br />
! PS257='UNCY' 409219 709.079 -367.88 !<br />
! PS258='ABIL' 410016 -251.992 -837.072 !<br />
! PS259='AMAR' 410211 -425.807 -517.874 !<br />
! PS260='AUST' 410428 -73.36 -1073.563 !<br />
! PS261='BRWN' 411136 -43.145 -1569.786 !<br />
! PS262='COST' 411889 61.112 -1043.691 !<br />
! PS263='COCR' 412015 -51.11 -1359.669 !<br />
! PS264='CROS' 412131 -203.641 -870.07 !<br />
! PS265='DFWT' 412242 -1.764 -786.588 !<br />
! PS266='EAST' 412715 -170.74 -840.382 !<br />
! PS267='ELPA' 412797 -886.293 -861.789 !<br />
! PS268='HICO' 414137 -97.472 -887.436 !<br />
! PS269='HUST' 414300 158.985 -1110.596 !<br />
! PS270='KRES' 414880 -434.589 -611.633 !<br />
! PS271='LKCK' 414975 100.038 -693.147 !<br />
! PS272='LNGV' 415348 220.658 -845.053 !<br />
! PS273='LUFK' 415424 214.211 -969.019 !<br />
! PS274='MATH' 415661 -86.679 -1329.651 !<br />
! PS275='MIDR' 415890 -490.426 -878.838 !<br />
! PS276='MTLK' 416104 -673.955 -1004.875 !<br />
! PS277='NACO' 416177 223.545 -926.17 !<br />
! PS278='NAVA' 416210 28.358 -892.028 !<br />
! PS279='NEWB' 416270 240.125 -721.264 !<br />
! PS280='BPAT' 417174 288.906 -1110.59 !<br />
! PS281='RANK' 417431 -471.686 -959.663 !<br />
! PS282='SAAG' 417943 -332.751 -952.407 !<br />
! PS283='SAAT' 417945 -143.316 -1160.893 !<br />
! PS284='SHEF' 418252 -463.535 -1020.511 !<br />
! PS285='STEP' 418623 -112.577 -858.48 !<br />
! PS286='STER' 418630 -376.93 -896.223 !<br />
! PS287='VALE' 419270 -719.824 -1014.032 !<br />
! PS288='VICT' 419364 6.856 -1237.418 !<br />
! PS289='WACO' 419419 -21.705 -929.783 !<br />
! PS290='WATR' 419499 -353.588 -915.496 !<br />
! PS291='WHEE' 419665 57.941 -1008.958 !<br />
! PS292='WPDM' 419916 262.52 -737.331 !<br />
! PS293='DORA' 232302 422.323 -345.052 !<br />
Page 29
01Met01a.inp<br />
! PS294='DIXN' 112353 730.842 -249.922 !<br />
! PS295='DAUP' 12172 860.103 -1039.592 !<br />
! PS296='FREV' 123104 832.766 -80.805 !<br />
! PS297='WARR' 18673 856.047 -757.08 !<br />
! PS298='MDTN' 235562 478.829 -82.092 !<br />
! END !<br />
-------------------<br />
1<br />
Four character string for station name<br />
(MUST START IN COLUMN 9)<br />
!END!<br />
2<br />
Six digit station code composed of state<br />
code (first 2 digits) and station ID (last<br />
4 digits)<br />
Page 30
APPENDIX C – SAMPLE CALPUFF CONTROL FILE<br />
OG&E Trinity Consultants<br />
BART Modeling Report 083701.0004
OG&E Sooner BART Refined Analysis<br />
2001<br />
2001_SO_NOx.inp<br />
---------------- Run title (3 lines) ------------------------------------------<br />
CALPUFF MODEL CONTROL FILE<br />
--------------------------<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 0 -- Input and Output File Names<br />
--------------<br />
Default Name Type File Name<br />
------------ ---- ---------<br />
CALMET.DAT input * METDAT = *<br />
or<br />
ISCMET.DAT input * ISCDAT = *<br />
or<br />
PLMMET.DAT input * PLMDAT = *<br />
or<br />
PROFILE.DAT input * PRFDAT = *<br />
SURFACE.DAT input * SFCDAT = *<br />
RESTARTB.DAT input * RSTARTB= *<br />
--------------------------------------------------------------------------------<br />
CALPUFF.LST output ! PUFLST =2001_SO_NOx.LST !<br />
CONC.DAT output ! CONDAT =2001_SO_NOx.DAT !<br />
DFLX.DAT output * DFDAT = *<br />
WFLX.DAT output * WFDAT = *<br />
VISB.DAT output ! VISDAT =2001_SO_NOx.VIS !<br />
RESTARTE.DAT output * RSTARTE= *<br />
--------------------------------------------------------------------------------<br />
Emission Files<br />
--------------<br />
PTEMARB.DAT input * PTDAT = *<br />
VOLEMARB.DAT input * VOLDAT = *<br />
BAEMARB.DAT input * ARDAT = *<br />
LNEMARB.DAT input * LNDAT = *<br />
--------------------------------------------------------------------------------<br />
Other Files<br />
-----------<br />
OZONE.DAT input ! OZDAT =ozone_2001.dat!<br />
VD.DAT input * VDDAT = *<br />
CHEM.DAT input * CHEMDAT= *<br />
H2O2.DAT input * H2O2DAT= *<br />
HILL.DAT input * HILDAT= *<br />
HILLRCT.DAT input * RCTDAT= *<br />
Page 1
2001_SO_NOx.inp<br />
COASTLN.DAT input * CSTDAT= *<br />
FLUXBDY.DAT input * BDYDAT= *<br />
BCON.DAT input * BCNDAT= *<br />
DEBUG.DAT output * DEBUG = *<br />
MASSFLX.DAT output * FLXDAT= *<br />
MASSBAL.DAT output * BALDAT= *<br />
FOG.DAT output * FOGDAT= *<br />
--------------------------------------------------------------------------------<br />
All file names will be converted to lower case if LCFILES = T<br />
Otherwise, if LCFILES = F, file names will be converted to UPPER CASE<br />
T = lower case ! LCFILES = F !<br />
F = UPPER CASE<br />
NOTE: (1) file/path names can be up to 70 characters in length<br />
Provision for multiple input files<br />
----------------------------------<br />
!END!<br />
Number of CALMET.DAT files for run (NMETDAT)<br />
Default: 1 ! NMETDAT = 36 !<br />
Number of PTEMARB.DAT files for run (NPTDAT)<br />
Default: 0 ! NPTDAT = 0 !<br />
Number of BAEMARB.DAT files for run (NARDAT)<br />
Default: 0 ! NARDAT = 0 !<br />
Number of VOLEMARB.DAT files for run (NVOLDAT)<br />
Default: 0 ! NVOLDAT = 0 !<br />
-------------<br />
Subgroup (0a)<br />
-------------<br />
The following CALMET.DAT filenames are processed in sequence if NMETDAT>1<br />
Default Name Type File Name<br />
------------ ---- --------none<br />
input ! METDAT=D:\2001\01Met01a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met01b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met01c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met02a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met02b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met02c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met03a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met03b.met ! !END!<br />
Page 2
2001_SO_NOx.inp<br />
none input ! METDAT=D:\2001\01Met03c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met04a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met04b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met04c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met05a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met05b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met05c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met06a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met06b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met06c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met07a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met07b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met07c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met08a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met08b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met08c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met09a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met09b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met09c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met10a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met10b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met10c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met11a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met11b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met11c.met ! !END!<br />
none input ! METDAT=D:\2001\01Met12a.met ! !END!<br />
none input ! METDAT=D:\2001\01Met12b.met ! !END!<br />
none input ! METDAT=D:\2001\01Met12c.met ! !END!<br />
--------------------------------------------------------------------------------<br />
INPUT GROUP: 1 -- General run control parameters<br />
--------------<br />
Option to run all periods found<br />
in the met. file (METRUN) Default: 0 ! METRUN = 0 !<br />
METRUN = 0 - Run period explicitly defined below<br />
METRUN = 1 - Run all periods in met. file<br />
Starting date: Year (IBYR) -- No default ! IBYR = 2001 !<br />
(used only if Month (IBMO) -- No default ! IBMO = 1 !<br />
METRUN = 0) Day (IBDY) -- No default ! IBDY = 1 !<br />
Hour (IBHR) -- No default ! IBHR = 0 !<br />
Base time zone (XBTZ) -- No default ! XBTZ = 6.0 !<br />
PST = 8., MST = 7.<br />
Page 3
CST = 6., EST = 5.<br />
2001_SO_NOx.inp<br />
Length of run (hours) (IRLG) -- No default ! IRLG = 8760 !<br />
Number of chemical species (NSPEC)<br />
Default: 5 ! NSPEC = 10 !<br />
Number of chemical species<br />
to be emitted (NSE) Default: 3 ! NSE = 7 !<br />
Flag to stop run after<br />
SETUP phase (ITEST) Default: 2 ! ITEST = 2 !<br />
(Used to allow checking<br />
of the model inputs, files, etc.)<br />
ITEST = 1 - STOPS program after SETUP phase<br />
ITEST = 2 - Continues with execution of program<br />
after SETUP<br />
Restart Configuration:<br />
Control flag (MRESTART) Default: 0 ! MRESTART = 0 !<br />
0 = Do not read or write a restart file<br />
1 = Read a restart file at the beginning of<br />
the run<br />
2 = Write a restart file during run<br />
3 = Read a restart file at beginning of run<br />
and write a restart file during run<br />
Number of periods in Restart<br />
output cycle (NRESPD) Default: 0 ! NRESPD = 0 !<br />
0 = File written only at last period<br />
>0 = File updated every NRESPD periods<br />
Meteorological Data Format (METFM)<br />
Default: 1 ! METFM = 1 !<br />
METFM = 1 - CALMET binary file (CALMET.MET)<br />
METFM = 2 - ISC ASCII file (ISCMET.MET)<br />
METFM = 3 - AUSPLUME ASCII file (PLMMET.MET)<br />
METFM = 4 - CTDM plus tower file (PROFILE.DAT) and<br />
surface parameters file (SURFACE.DAT)<br />
PG sigma-y is adjusted by the factor (AVET/PGTIME)**0.2<br />
Averaging Time (minutes) (AVET)<br />
Default: 60.0 ! AVET = 60. !<br />
PG Averaging Time (minutes) (PGTIME)<br />
Page 4
!END!<br />
2001_SO_NOx.inp<br />
Default: 60.0 ! PGTIME = 60. !<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 2 -- Technical options<br />
--------------<br />
Vertical distribution used in the<br />
near field (MGAUSS) Default: 1 ! MGAUSS = 1 !<br />
0 = uniform<br />
1 = Gaussian<br />
Terrain adjustment method<br />
(MCTADJ) Default: 3 ! MCTADJ = 3 !<br />
0 = no adjustment<br />
1 = ISC-type of terrain adjustment<br />
2 = simple, CALPUFF-type of terrain<br />
adjustment<br />
3 = partial plume path adjustment<br />
Subgrid-scale complex terrain<br />
flag (MCTSG) Default: 0 ! MCTSG = 0 !<br />
0 = not modeled<br />
1 = modeled<br />
Near-field puffs modeled as<br />
elongated 0 (MSLUG) Default: 0 ! MSLUG = 0 !<br />
0 = no<br />
1 = yes (slug model used)<br />
Transitional plume rise modeled ?<br />
(MTRANS) Default: 1 ! MTRANS = 1 !<br />
0 = no (i.e., final rise only)<br />
1 = yes (i.e., transitional rise computed)<br />
Stack tip downwash? (MTIP) Default: 1 ! MTIP = 1 !<br />
0 = no (i.e., no stack tip downwash)<br />
1 = yes (i.e., use stack tip downwash)<br />
Method used to simulate building<br />
downwash? (MBDW) Default: 1 ! MBDW = 1 !<br />
1 = ISC method<br />
2 = PRIME method<br />
Page 5
2001_SO_NOx.inp<br />
Vertical wind shear modeled above<br />
stack top? (MSHEAR) Default: 0 ! MSHEAR = 0 !<br />
0 = no (i.e., vertical wind shear not modeled)<br />
1 = yes (i.e., vertical wind shear modeled)<br />
Puff splitting allowed? (MSPLIT) Default: 0 ! MSPLIT = 0 !<br />
0 = no (i.e., puffs not split)<br />
1 = yes (i.e., puffs are split)<br />
Chemical mechanism flag (MCHEM) Default: 1 ! MCHEM = 1 !<br />
0 = chemical transformation not<br />
modeled<br />
1 = transformation rates computed<br />
internally (MESOPUFF II scheme)<br />
2 = user-specified transformation<br />
rates used<br />
3 = transformation rates computed<br />
internally (RIVAD/ARM3 scheme)<br />
4 = secondary organic aerosol formation<br />
computed (MESOPUFF II scheme for OH)<br />
Aqueous phase transformation flag (MAQCHEM)<br />
(Used only if MCHEM = 1, or 3) Default: 0 ! MAQCHEM = 0 !<br />
0 = aqueous phase transformation<br />
not modeled<br />
1 = transformation rates adjusted<br />
for aqueous phase reactions<br />
Wet removal modeled ? (MWET) Default: 1 ! MWET = 1 !<br />
0 = no<br />
1 = yes<br />
Dry deposition modeled ? (MDRY) Default: 1 ! MDRY = 1 !<br />
0 = no<br />
1 = yes<br />
(dry deposition method specified<br />
for each species in Input Group 3)<br />
Method used to compute dispersion<br />
coefficients (MDISP) Default: 3 ! MDISP = 3 !<br />
1 = dispersion coefficients computed from measured values<br />
of turbulence, sigma v, sigma w<br />
2 = dispersion coefficients from internally calculated<br />
sigma v, sigma w using micrometeorological variables<br />
(u*, w*, L, etc.)<br />
3 = PG dispersion coefficients for RURAL areas (computed using<br />
Page 6
2001_SO_NOx.inp<br />
the ISCST multi-segment approximation) and MP coefficients in<br />
urban areas<br />
4 = same as 3 except PG coefficients computed using<br />
the MESOPUFF II eqns.<br />
5 = CTDM sigmas used for stable and neutral conditions.<br />
For unstable conditions, sigmas are computed as in<br />
MDISP = 3, described above. MDISP = 5 assumes that<br />
measured values are read<br />
Sigma-v/sigma-theta, sigma-w measurements used? (MTURBVW)<br />
(Used only if MDISP = 1 or 5) Default: 3 ! MTURBVW = 3 !<br />
1 = use sigma-v or sigma-theta measurements<br />
from PROFILE.DAT to compute sigma-y<br />
(valid for METFM = 1, 2, 3, 4)<br />
2 = use sigma-w measurements<br />
from PROFILE.DAT to compute sigma-z<br />
(valid for METFM = 1, 2, 3, 4)<br />
3 = use both sigma-(v/theta) and sigma-w<br />
from PROFILE.DAT to compute sigma-y and sigma-z<br />
(valid for METFM = 1, 2, 3, 4)<br />
4 = use sigma-theta measurements<br />
from PLMMET.DAT to compute sigma-y<br />
(valid only if METFM = 3)<br />
Back-up method used to compute dispersion<br />
when measured turbulence data are<br />
missing (MDISP2) Default: 3 ! MDISP2 = 3 !<br />
(used only if MDISP = 1 or 5)<br />
2 = dispersion coefficients from internally calculated<br />
sigma v, sigma w using micrometeorological variables<br />
(u*, w*, L, etc.)<br />
3 = PG dispersion coefficients for RURAL areas (computed using<br />
the ISCST multi-segment approximation) and MP coefficients in<br />
urban areas<br />
4 = same as 3 except PG coefficients computed using<br />
the MESOPUFF II eqns.<br />
PG sigma-y,z adj. for roughness? Default: 0 ! MROUGH = 0 !<br />
(MROUGH)<br />
0 = no<br />
1 = yes<br />
Partial plume penetration of Default: 1 ! MPARTL = 1 !<br />
elevated inversion?<br />
(MPARTL)<br />
0 = no<br />
1 = yes<br />
Page 7
2001_SO_NOx.inp<br />
Strength of temperature inversion Default: 0 ! MTINV = 0 !<br />
provided in PROFILE.DAT extended records?<br />
(MTINV)<br />
0 = no (computed from measured/default gradients)<br />
1 = yes<br />
PDF used for dispersion under convective conditions?<br />
Default: 0 ! MPDF = 0 !<br />
(MPDF)<br />
0 = no<br />
1 = yes<br />
Sub-Grid TIBL module used for shore line?<br />
Default: 0 ! MSGTIBL = 0 !<br />
(MSGTIBL)<br />
0 = no<br />
1 = yes<br />
Boundary conditions (concentration) modeled?<br />
Default: 0 ! MBCON = 0 !<br />
(MBCON)<br />
0 = no<br />
1 = yes, using formatted BCON.DAT file<br />
2 = yes, using unformatted CONC.DAT file<br />
Analyses of fogging and icing impacts due to emissions from<br />
arrays of mechanically-forced cooling towers can be performed<br />
using CALPUFF in conjunction with a cooling tower emissions<br />
processor (CTEMISS) and its associated postprocessors. Hourly<br />
emissions of water vapor and temperature from each cooling tower<br />
cell are computed for the current cell configuration and ambient<br />
conditions by CTEMISS. CALPUFF models the dispersion of these<br />
emissions and provides cloud information in a specialized format<br />
for further analysis. Output to FOG.DAT is provided in either<br />
'plume mode' or 'receptor mode' format.<br />
Configure for FOG Model output?<br />
Default: 0 ! MFOG = 0 !<br />
(MFOG)<br />
0 = no<br />
1 = yes - report results in PLUME Mode format<br />
2 = yes - report results in RECEPTOR Mode format<br />
Test options specified to see if<br />
they conform to regulatory<br />
values? (MREG) Default: 1 ! MREG = 0 !<br />
Page 8
!END!<br />
2001_SO_NOx.inp<br />
0 = NO checks are made<br />
1 = Technical options must conform to USEPA<br />
Long Range Transport (LRT) guidance<br />
METFM 1 or 2<br />
AVET 60. (min)<br />
PGTIME 60. (min)<br />
MGAUSS 1<br />
MCTADJ 3<br />
MTRANS 1<br />
MTIP 1<br />
MCHEM 1 or 3 (if modeling SOx, NOx)<br />
MWET 1<br />
MDRY 1<br />
MDISP 2 or 3<br />
MPDF 0 if MDISP=3<br />
1 if MDISP=2<br />
MROUGH 0<br />
MPARTL 1<br />
SYTDEP 550. (m)<br />
MHFTSZ 0<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 3a, 3b -- Species list<br />
-------------------<br />
------------<br />
Subgroup (3a)<br />
------------<br />
The following species are modeled:<br />
! CSPEC = SO2 ! !END!<br />
! CSPEC = SO4 ! !END!<br />
! CSPEC = NOX ! !END!<br />
! CSPEC = HNO3 ! !END!<br />
! CSPEC = NO3 ! !END!<br />
! CSPEC = NH3 ! !END!<br />
! CSPEC = PMC ! !END!<br />
! CSPEC = PMF ! !END!<br />
! CSPEC = EC ! !END!<br />
! CSPEC = SOA ! !END!<br />
Page 9
2001_SO_NOx.inp<br />
Dry OUTPUT GROUP<br />
SPECIES MODELED EMITTED DEPOSITED NUMBER<br />
NAME (0=NO, 1=YES) (0=NO, 1=YES) (0=NO, (0=NONE,<br />
(Limit: 12 1=COMPUTED-GAS 1=1st CGRUP,<br />
Characters 2=COMPUTED-PARTICLE 2=2nd CGRUP,<br />
in length) 3=USER-SPECIFIED) 3= etc.)<br />
! SO2 = 1, 1, 1, 0 !<br />
! SO4 = 1, 1, 2, 0 !<br />
! NOX = 1, 1, 1, 0 !<br />
! HNO3 = 1, 0, 1, 0 !<br />
! NO3 = 1, 0, 2, 0 !<br />
! NH3 = 1, 0, 1, 0 !<br />
! PMC = 1, 1, 2, 0 !<br />
! PMF = 1, 1, 2, 0 !<br />
! EC = 1, 1, 2, 0 !<br />
! SOA = 1, 1, 2, 0 !<br />
!END!<br />
-------------<br />
Subgroup (3b)<br />
-------------<br />
The following names are used for Species-Groups in which results<br />
for certain species are combined (added) prior to output. The<br />
CGRUP name will be used as the species name in output files.<br />
Use this feature to model specific particle-size distributions<br />
by treating each size-range as a separate species.<br />
Order must be consistent with 3(a) above.<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 4 -- Map Projection and Grid control parameters<br />
--------------<br />
Projection for all (X,Y):<br />
-------------------------<br />
Map projection<br />
(PMAP) Default: UTM ! PMAP = LCC !<br />
UTM : Universal Transverse Mercator<br />
TTM : Tangential Transverse Mercator<br />
LCC : Lambert Conformal Conic<br />
PS : Polar Stereographic<br />
Page 10
EM : Equatorial Mercator<br />
LAZA : Lambert Azimuthal Equal Area<br />
2001_SO_NOx.inp<br />
False Easting and Northing (km) at the projection origin<br />
(Used only if PMAP= TTM, LCC, or LAZA)<br />
(FEAST) Default=0.0 ! FEAST = 0.000 !<br />
(FNORTH) Default=0.0 ! FNORTH = 0.000 !<br />
UTM zone (1 to 60)<br />
(Used only if PMAP=UTM)<br />
(IUTMZN) No Default ! IUTMZN = 0 !<br />
Hemisphere for UTM projection?<br />
(Used only if PMAP=UTM)<br />
(UTMHEM) Default: N ! UTMHEM = N !<br />
N : Northern hemisphere projection<br />
S : Southern hemisphere projection<br />
Latitude and Longitude (decimal degrees) of projection origin<br />
(Used only if PMAP= TTM, LCC, PS, EM, or LAZA)<br />
(RLAT0) No Default ! RLAT0 = 40N !<br />
(RLON0) No Default ! RLON0 = 97W !<br />
TTM : RLON0 identifies central (true N/S) meridian of projection<br />
RLAT0 selected for convenience<br />
LCC : RLON0 identifies central (true N/S) meridian of projection<br />
RLAT0 selected for convenience<br />
PS : RLON0 identifies central (grid N/S) meridian of projection<br />
RLAT0 selected for convenience<br />
EM : RLON0 identifies central meridian of projection<br />
RLAT0 is REPLACED by 0.0N (Equator)<br />
LAZA: RLON0 identifies longitude of tangent-point of mapping plane<br />
RLAT0 identifies latitude of tangent-point of mapping plane<br />
Matching parallel(s) of latitude (decimal degrees) for projection<br />
(Used only if PMAP= LCC or PS)<br />
(XLAT1) No Default ! XLAT1 = 33N !<br />
(XLAT2) No Default ! XLAT2 = 45N !<br />
LCC : Projection cone slices through Earth's surface at XLAT1 and XLAT2<br />
PS : Projection plane slices through Earth at XLAT1<br />
(XLAT2 is not used)<br />
----------<br />
Note: Latitudes and longitudes should be positive, and include a<br />
letter N,S,E, or W indicating north or south latitude, and<br />
east or west longitude. For example,<br />
35.9 N Latitude = 35.9N<br />
Page 11
Datum-region<br />
------------<br />
118.7 E Longitude = 118.7E<br />
2001_SO_NOx.inp<br />
The Datum-Region for the coordinates is identified by a character<br />
string. Many mapping products currently available use the model of the<br />
Earth known as the World Geodetic System 1984 (WGS-G ). Other local<br />
models may be in use, and their selection in CALMET will make its output<br />
consistent with local mapping products. The list of Datum-Regions with<br />
official transformation parameters is provided by the National Imagery and<br />
Mapping Agency (NIMA).<br />
NIMA Datum - Regions(Examples)<br />
------------------------------------------------------------------------------<br />
WGS-G WGS-84 GRS 80 Spheroid, Global coverage (WGS84)<br />
NAS-C NORTH AMERICAN 1927 Clarke 1866 Spheroid, MEAN FOR CONUS (NAD27)<br />
NWS-27 NWS 6370KM Radius, Sphere<br />
NWS-84 NWS 6370KM Radius, Sphere<br />
ESR-S ESRI REFERENCE 6371KM Radius, Sphere<br />
Datum-region for output coordinates<br />
(DATUM) Default: WGS-G ! DATUM = WGS-G !<br />
METEOROLOGICAL Grid:<br />
Rectangular grid defined for projection PMAP,<br />
with X the Easting and Y the Northing coordinate<br />
No. X grid cells (NX) No default ! NX = 462 !<br />
No. Y grid cells (NY) No default ! NY = 376 !<br />
No. vertical layers (NZ) No default ! NZ = 12 !<br />
Grid spacing (DGRIDKM) No default ! DGRIDKM = 4. !<br />
Units: km<br />
Cell face heights<br />
(ZFACE(nz+1)) No defaults<br />
Units: m<br />
! ZFACE = 0.,20.,40.,60.,80.,100.,150.,200.,250.,500.,1000.,2000.,3500. !<br />
Reference Coordinates<br />
of SOUTHWEST corner of<br />
grid cell(1, 1):<br />
Page 12
COMPUTATIONAL Grid:<br />
2001_SO_NOx.inp<br />
X coordinate (XORIGKM) No default ! XORIGKM = -951.547 !<br />
Y coordinate (YORIGKM) No default ! YORIGKM = -1646.637 !<br />
Units: km<br />
The computational grid is identical to or a subset of the MET. grid.<br />
The lower left (LL) corner of the computational grid is at grid point<br />
(IBCOMP, JBCOMP) of the MET. grid. The upper right (UR) corner of the<br />
computational grid is at grid point (IECOMP, JECOMP) of the MET. grid.<br />
The grid spacing of the computational grid is the same as the MET. grid.<br />
X index of LL corner (IBCOMP) No default ! IBCOMP = 165 !<br />
(1
!END!<br />
2001_SO_NOx.inp<br />
X index of UR corner (IESAMP) No default ! IESAMP = 462 !<br />
(IBCOMP
2001_SO_NOx.inp<br />
reported hourly?<br />
(IMBAL) Default: 0 ! IMBAL = 0 !<br />
0 = no<br />
1 = yes (MASSBAL.DAT filename is<br />
specified in Input Group 0)<br />
LINE PRINTER OUTPUT OPTIONS:<br />
Print concentrations (ICPRT) Default: 0 ! ICPRT = 0 !<br />
Print dry fluxes (IDPRT) Default: 0 ! IDPRT = 0 !<br />
Print wet fluxes (IWPRT) Default: 0 ! IWPRT = 0 !<br />
(0 = Do not print, 1 = Print)<br />
Concentration print interval<br />
(ICFRQ) in hours Default: 1 ! ICFRQ = 1 !<br />
Dry flux print interval<br />
(IDFRQ) in hours Default: 1 ! IDFRQ = 1 !<br />
Wet flux print interval<br />
(IWFRQ) in hours Default: 1 ! IWFRQ = 1 !<br />
Units for Line Printer Output<br />
(IPRTU) Default: 1 ! IPRTU = 3 !<br />
for for<br />
Concentration Deposition<br />
1 = g/m**3 g/m**2/s<br />
2 = mg/m**3 mg/m**2/s<br />
3 = ug/m**3 ug/m**2/s<br />
4 = ng/m**3 ng/m**2/s<br />
5 = Odour Units<br />
Messages tracking progress of run<br />
written to the screen ?<br />
(IMESG) Default: 2 ! IMESG = 2 !<br />
0 = no<br />
1 = yes (advection step, puff ID)<br />
2 = yes (YYYYJJJHH, # old puffs, # emitted puffs)<br />
SPECIES (or GROUP for combined species) LIST FOR OUTPUT OPTIONS<br />
---- CONCENTRATIONS ---- ------ DRY FLUXES ------ ------ WET FLUXES ------ -- MASS<br />
FLUX --<br />
SPECIES<br />
/GROUP PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? SAVED ON<br />
DISK?<br />
------- ------------------------ ------------------------ ------------------------<br />
---------------<br />
Page 15
2001_SO_NOx.inp<br />
! SO2 = 0, 1, 0, 1, 0, 1, 1 !<br />
! SO4 = 0, 1, 0, 1, 0, 1, 1 !<br />
! NOX = 0, 1, 0, 1, 0, 1, 1 !<br />
! HNO3 = 0, 1, 0, 1, 0, 1, 1 !<br />
! NO3 = 0, 1, 0, 1, 0, 1, 1 !<br />
! PMC = 0, 1, 0, 1, 0, 1, 1 !<br />
! PMF = 0, 1, 0, 1, 0, 1, 1 !<br />
! EC = 0, 1, 0, 1, 0, 1, 1 !<br />
! SOA = 0, 1, 0, 1, 0, 1, 1 !<br />
!END!<br />
OPTIONS FOR PRINTING "DEBUG" QUANTITIES (much output)<br />
Logical for debug output<br />
(LDEBUG) Default: F ! LDEBUG = F !<br />
First puff to track<br />
(IPFDEB) Default: 1 ! IPFDEB = 1 !<br />
Number of puffs to track<br />
(NPFDEB) Default: 1 ! NPFDEB = 1 !<br />
Met. period to start output<br />
(NN1) Default: 1 ! NN1 = 1 !<br />
Met. period to end output<br />
(NN2) Default: 10 ! NN2 = 10 !<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 6a, 6b, & 6c -- Subgrid scale complex terrain inputs<br />
-------------------------<br />
---------------<br />
Subgroup (6a)<br />
---------------<br />
Number of terrain features (NHILL) Default: 0 ! NHILL = 0 !<br />
Number of special complex terrain<br />
receptors (NCTREC) Default: 0 ! NCTREC = 0 !<br />
Terrain and CTSG Receptor data for<br />
CTSG hills input in CTDM format ?<br />
(MHILL) No Default ! MHILL = 2 !<br />
1 = Hill and Receptor data created<br />
Page 16
! END !<br />
by CTDM processors & read from<br />
HILL.DAT and HILLRCT.DAT files<br />
2 = Hill data created by OPTHILL &<br />
input below in Subgroup (6b);<br />
Receptor data in Subgroup (6c)<br />
2001_SO_NOx.inp<br />
Factor to convert horizontal dimensions Default: 1.0 ! XHILL2M = 1. !<br />
to meters (MHILL=1)<br />
Factor to convert vertical dimensions Default: 1.0 ! ZHILL2M = 1. !<br />
to meters (MHILL=1)<br />
X-origin of CTDM system relative to No Default ! XCTDMKM = 0.0E00 !<br />
CALPUFF coordinate system, in Kilometers (MHILL=1)<br />
Y-origin of CTDM system relative to No Default ! YCTDMKM = 0.0E00 !<br />
CALPUFF coordinate system, in Kilometers (MHILL=1)<br />
---------------<br />
Subgroup (6b)<br />
---------------<br />
HILL information<br />
1 **<br />
HILL XC YC THETAH ZGRID RELIEF EXPO 1 EXPO 2 SCALE 1 SCALE 2 AMAX1<br />
AMAX2<br />
NO. (km) (km) (deg.) (m) (m) (m) (m) (m) (m) (m)<br />
(m)<br />
---- ---- ---- ------ ----- ------ ------ ------ ------- ------- -----<br />
-----<br />
---------------<br />
Subgroup (6c)<br />
---------------<br />
COMPLEX TERRAIN RECEPTOR INFORMATION<br />
-------------------<br />
1<br />
XRCT YRCT ZRCT XHH<br />
(km) (km) (m)<br />
------ ----- ------ ----<br />
Page 17
2001_SO_NOx.inp<br />
Description of Complex Terrain Variables:<br />
XC, YC = Coordinates of center of hill<br />
THETAH = Orientation of major axis of hill (clockwise from<br />
North)<br />
ZGRID = Height of the 0 of the grid above mean sea<br />
level<br />
RELIEF = Height of the crest of the hill above the grid elevation<br />
EXPO 1 = Hill-shape exponent for the major axis<br />
EXPO 2 = Hill-shape exponent for the major axis<br />
SCALE 1 = Horizontal length scale along the major axis<br />
SCALE 2 = Horizontal length scale along the minor axis<br />
AMAX = Maximum allowed axis length for the major axis<br />
BMAX = Maximum allowed axis length for the major axis<br />
XRCT, YRCT = Coordinates of the complex terrain receptors<br />
ZRCT = Height of the ground (MSL) at the complex terrain<br />
Receptor<br />
XHH = Hill number associated with each complex terrain receptor<br />
(NOTE: MUST BE ENTERED AS A REAL NUMBER)<br />
**<br />
NOTE: DATA for each hill and CTSG receptor are treated as a separate<br />
input subgroup and therefore must end with an input group terminator.<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 7 -- Chemical parameters for dry deposition of gases<br />
--------------<br />
SPECIES DIFFUSIVITY ALPHA STAR REACTIVITY MESOPHYLL RESISTANCE HENRY'S LAW<br />
COEFFICIENT<br />
NAME (cm**2/s) (s/cm)<br />
(dimensionless)<br />
------- ----------- ---------- ---------- --------------------<br />
-----------------------<br />
! SO2 = 0.1509, 1000., 8., 0., 0.04 !<br />
! NOX = 0.1656, 1., 8., 5., 3.5 !<br />
! HNO3 = 0.1628, 1., 18., 0., 0.00000008 !<br />
!END!<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 8 -- Size parameters for dry deposition of particles<br />
Page 18
--------------<br />
2001_SO_NOx.inp<br />
For SINGLE SPECIES, the mean and standard deviation are used to<br />
compute a deposition velocity for NINT (see group 9) size-ranges,<br />
and these are then averaged to obtain a mean deposition velocity.<br />
For GROUPED SPECIES, the size distribution should be explicitly<br />
specified (by the 'species' in the group), and the standard deviation<br />
for each should be entered as 0. The model will then use the<br />
deposition velocity for the stated mean diameter.<br />
SPECIES GEOMETRIC MASS MEAN GEOMETRIC STANDARD<br />
NAME DIAMETER DEVIATION<br />
(microns) (microns)<br />
------- ------------------- ------------------<br />
! SO4 = 0.48, 2. !<br />
! NO3 = 0.48, 2. !<br />
! PMC = 6.00, 2. !<br />
! PMF = 0.48, 2. !<br />
! EC = 0.48, 2. !<br />
! SOA = 0.48, 2. !<br />
!END!<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 9 -- Miscellaneous dry deposition parameters<br />
--------------<br />
Reference cuticle resistance (s/cm)<br />
(RCUTR) Default: 30 ! RCUTR = 30.0 !<br />
Reference ground resistance (s/cm)<br />
(RGR) Default: 10 ! RGR = 10.0 !<br />
Reference pollutant reactivity<br />
(REACTR) Default: 8 ! REACTR = 8.0 !<br />
Number of particle-size intervals used to<br />
evaluate effective particle deposition velocity<br />
(NINT) Default: 9 ! NINT = 9 !<br />
Vegetation state in unirrigated areas<br />
(IVEG) Default: 1 ! IVEG = 1 !<br />
IVEG=1 for active and unstressed vegetation<br />
IVEG=2 for active and stressed vegetation<br />
IVEG=3 for inactive vegetation<br />
Page 19
!END!<br />
2001_SO_NOx.inp<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 10 -- Wet Deposition Parameters<br />
---------------<br />
Scavenging Coefficient -- Units: (sec)**(-1)<br />
Pollutant Liquid Precip. Frozen Precip.<br />
--------- -------------- --------------<br />
! SO2 = 3.21E-05, 0.0E00 !<br />
! SO4 = 1.0E-04, 3.0E-05 !<br />
! HNO3 = 6.0E-05, 0.0E00 !<br />
! NO3 = 1.0E-04, 3.0E-05 !<br />
! NH3 = 8.0E-05, 0.0E00 !<br />
! PMC = 1.0E-04, 3.0E-05 !<br />
! PMF = 1.0E-04, 3.0E-05 !<br />
! EC = 1.0E-04, 3.0E-05 !<br />
! SOA = 1.0E-04, 3.0E-05 !<br />
!END!<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 11 -- Chemistry Parameters<br />
---------------<br />
Ozone data input option (MOZ) Default: 1 ! MOZ = 1 !<br />
(Used only if MCHEM = 1, 3, or 4)<br />
0 = use a monthly background ozone value<br />
1 = read hourly ozone concentrations from<br />
the OZONE.DAT data file<br />
Monthly ozone concentrations<br />
(Used only if MCHEM = 1, 3, or 4 and<br />
MOZ = 0 or MOZ = 1 and all hourly O3 data missing)<br />
(BCKO3) in ppb Default: 12*80.<br />
! BCKO3 = 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00 !<br />
Monthly ammonia concentrations<br />
(Used only if MCHEM = 1, or 3)<br />
(BCKNH3) in ppb Default: 12*10.<br />
Page 20
2001_SO_NOx.inp<br />
! BCKNH3 = 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00 !<br />
Nighttime SO2 loss rate (RNITE1)<br />
in percent/hour Default: 0.2 ! RNITE1 = .2 !<br />
Nighttime NOx loss rate (RNITE2)<br />
in percent/hour Default: 2.0 ! RNITE2 = 2.0 !<br />
Nighttime HNO3 formation rate (RNITE3)<br />
in percent/hour Default: 2.0 ! RNITE3 = 2.0 !<br />
H2O2 data input option (MH2O2) Default: 1 ! MH2O2 = 0 !<br />
(Used only if MAQCHEM = 1)<br />
0 = use a monthly background H2O2 value<br />
1 = read hourly H2O2 concentrations from<br />
the H2O2.DAT data file<br />
Monthly H2O2 concentrations<br />
(Used only if MQACHEM = 1 and<br />
MH2O2 = 0 or MH2O2 = 1 and all hourly H2O2 data missing)<br />
(BCKH2O2) in ppb Default: 12*1.<br />
! BCKH2O2 = 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00 !<br />
--- Data for SECONDARY ORGANIC AEROSOL (SOA) Option<br />
(used only if MCHEM = 4)<br />
The SOA module uses monthly values of:<br />
Fine particulate concentration in ug/m^3 (BCKPMF)<br />
Organic fraction of fine particulate (OFRAC)<br />
VOC / NOX ratio (after reaction) (VCNX)<br />
to characterize the air mass when computing<br />
the formation of SOA from VOC emissions.<br />
Typical values for several distinct air mass types are:<br />
Month 1 2 3 4 5 6 7 8 9 10 11 12<br />
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec<br />
Clean Continental<br />
BCKPMF 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1.<br />
OFRAC .15 .15 .20 .20 .20 .20 .20 .20 .20 .20 .20 .15<br />
VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.<br />
Clean Marine (surface)<br />
BCKPMF .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5<br />
OFRAC .25 .25 .30 .30 .30 .30 .30 .30 .30 .30 .30 .25<br />
VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.<br />
Page 21
!END!<br />
2001_SO_NOx.inp<br />
Urban - low biogenic (controls present)<br />
BCKPMF 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30.<br />
OFRAC .20 .20 .25 .25 .25 .25 .25 .25 .20 .20 .20 .20<br />
VCNX 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4.<br />
Urban - high biogenic (controls present)<br />
BCKPMF 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60.<br />
OFRAC .25 .25 .30 .30 .30 .55 .55 .55 .35 .35 .35 .25<br />
VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.<br />
Regional Plume<br />
BCKPMF 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20.<br />
OFRAC .20 .20 .25 .35 .25 .40 .40 .40 .30 .30 .30 .20<br />
VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.<br />
Urban - no controls present<br />
BCKPMF 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100.<br />
OFRAC .30 .30 .35 .35 .35 .55 .55 .55 .35 .35 .35 .30<br />
VCNX 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2.<br />
Default: Clean Continental<br />
! BCKPMF = 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00 !<br />
! OFRAC = 0.15, 0.15, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.15 !<br />
! VCNX = 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00 !<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 12 -- Misc. Dispersion and Computational Parameters<br />
---------------<br />
Horizontal size of puff (m) beyond which<br />
time-dependent dispersion equations (Heffter)<br />
are used to determine sigma-y and<br />
sigma-z (SYTDEP) Default: 550. ! SYTDEP = 5.5E02 !<br />
Switch for using Heffter equation for sigma z<br />
as above (0 = Not use Heffter; 1 = use Heffter<br />
(MHFTSZ) Default: 0 ! MHFTSZ = 0 !<br />
Stability class used to determine plume<br />
growth rates for puffs above the boundary<br />
layer (JSUP) Default: 5 ! JSUP = 5 !<br />
Page 22
2001_SO_NOx.inp<br />
Vertical dispersion constant for stable<br />
conditions (k1 in Eqn. 2.7-3) (CONK1) Default: 0.01 ! CONK1 = .01 !<br />
Vertical dispersion constant for neutral/<br />
unstable conditions (k2 in Eqn. 2.7-4)<br />
(CONK2) Default: 0.1 ! CONK2 = .1 !<br />
Factor for determining Transition-point from<br />
Schulman-Scire to Huber-Snyder Building Downwash<br />
scheme (SS used for Hs < Hb + TBD * HL)<br />
(TBD) Default: 0.5 ! TBD = .5 !<br />
TBD < 0 ==> always use Huber-Snyder<br />
TBD = 1.5 ==> always use Schulman-Scire<br />
TBD = 0.5 ==> ISC Transition-point<br />
Range of land use categories for which<br />
urban dispersion is assumed<br />
(IURB1, IURB2) Default: 10 ! IURB1 = 10 !<br />
19 ! IURB2 = 19 !<br />
Site characterization parameters for single-point Met data files ---------<br />
(needed for METFM = 2,3,4)<br />
Land use category for modeling domain<br />
(ILANDUIN) Default: 20 ! ILANDUIN = 20 !<br />
Roughness length (m) for modeling domain<br />
(Z0IN) Default: 0.25 ! Z0IN = .25 !<br />
Leaf area index for modeling domain<br />
(XLAIIN) Default: 3.0 ! XLAIIN = 3.0 !<br />
Elevation above sea level (m)<br />
(ELEVIN) Default: 0.0 ! ELEVIN = .0 !<br />
Latitude (degrees) for met location<br />
(XLATIN) Default: -999. ! XLATIN = -999.0 !<br />
Longitude (degrees) for met location<br />
(XLONIN) Default: -999. ! XLONIN = -999.0 !<br />
Specialized information for interpreting single-point Met data files -----<br />
Anemometer height (m) (Used only if METFM = 2,3)<br />
(ANEMHT) Default: 10. ! ANEMHT = 10.0 !<br />
Form of lateral turbulance data in PROFILE.DAT file<br />
(Used only if METFM = 4 or MTURBVW = 1 or 3)<br />
Page 23
2001_SO_NOx.inp<br />
(ISIGMAV) Default: 1 ! ISIGMAV = 1 !<br />
0 = read sigma-theta<br />
1 = read sigma-v<br />
Choice of mixing heights (Used only if METFM = 4)<br />
(IMIXCTDM) Default: 0 ! IMIXCTDM = 0 !<br />
0 = read PREDICTED mixing heights<br />
1 = read OBSERVED mixing heights<br />
Maximum length of a slug (met. grid units)<br />
(XMXLEN) Default: 1.0 ! XMXLEN = 1.0 !<br />
Maximum travel distance of a puff/slug (in<br />
grid units) during one sampling step<br />
(XSAMLEN) Default: 1.0 ! XSAMLEN = 10 !<br />
Maximum Number of slugs/puffs release from<br />
one source during one time step<br />
(MXNEW) Default: 99 ! MXNEW = 60 !<br />
Maximum Number of sampling steps for<br />
one puff/slug during one time step<br />
(MXSAM) Default: 99 ! MXSAM = 60 !<br />
Number of iterations used when computing<br />
the transport wind for a sampling step<br />
that includes gradual rise (for CALMET<br />
and PROFILE winds)<br />
(NCOUNT) Default: 2 ! NCOUNT = 2 !<br />
Minimum sigma y for a new puff/slug (m)<br />
(SYMIN) Default: 1.0 ! SYMIN = 1.0 !<br />
Minimum sigma z for a new puff/slug (m)<br />
(SZMIN) Default: 1.0 ! SZMIN = 1.0 !<br />
Default minimum turbulence velocities<br />
sigma-v and sigma-w for each<br />
stability class (m/s)<br />
(SVMIN(6) and SWMIN(6)) Default SVMIN : .50, .50, .50, .50, .50, .50<br />
Default SWMIN : .20, .12, .08, .06, .03, .016<br />
Divergence criterion for dw/dz across puff<br />
Stability Class : A B C D E F<br />
--- --- --- --- --- ---<br />
! SVMIN = 0.500, 0.500, 0.500, 0.500, 0.500, 0.500!<br />
! SWMIN = 0.200, 0.120, 0.080, 0.060, 0.030, 0.016!<br />
Page 24
2001_SO_NOx.inp<br />
used to initiate adjustment for horizontal<br />
convergence (1/s)<br />
Partial adjustment starts at CDIV(1), and<br />
full adjustment is reached at CDIV(2)<br />
(CDIV(2)) Default: 0.0,0.0 ! CDIV = 0.01, 0.01 !<br />
Minimum wind speed (m/s) allowed for<br />
non-calm conditions. Also used as minimum<br />
speed returned when using power-law<br />
extrapolation toward surface<br />
(WSCALM) Default: 0.5 ! WSCALM = .5 !<br />
Maximum mixing height (m)<br />
(XMAXZI) Default: 3000. ! XMAXZI = 3000.0 !<br />
Minimum mixing height (m)<br />
(XMINZI) Default: 50. ! XMINZI = 20.0 !<br />
Default wind speed classes --<br />
5 upper bounds (m/s) are entered;<br />
the 6th class has no upper limit<br />
(WSCAT(5)) Default :<br />
ISC RURAL : 1.54, 3.09, 5.14, 8.23, 10.8 (10.8+)<br />
Wind Speed Class : 1 2 3 4 5<br />
--- --- --- --- ---<br />
! WSCAT = 1.54, 3.09, 5.14, 8.23, 10.80 !<br />
Default wind speed profile power-law<br />
exponents for stabilities 1-6<br />
(PLX0(6)) Default : ISC RURAL values<br />
ISC RURAL : .07, .07, .10, .15, .35, .55<br />
ISC URBAN : .15, .15, .20, .25, .30, .30<br />
Stability Class : A B C D E F<br />
--- --- --- --- --- ---<br />
! PLX0 = 0.07, 0.07, 0.10, 0.15, 0.35, 0.55 !<br />
Default potential temperature gradient<br />
for stable classes E, F (degK/m)<br />
(PTG0(2)) Default: 0.020, 0.035<br />
! PTG0 = 0.020, 0.035 !<br />
Default plume path coefficients for<br />
each stability class (used when option<br />
for partial plume height terrain adjustment<br />
is selected -- MCTADJ=3)<br />
(PPC(6)) Stability Class : A B C D E F<br />
Page 25
2001_SO_NOx.inp<br />
Default PPC : .50, .50, .50, .50, .35, .35<br />
--- --- --- --- --- ---<br />
! PPC = 0.50, 0.50, 0.50, 0.50, 0.35, 0.35 !<br />
Slug-to-puff transition criterion factor<br />
equal to sigma-y/length of slug<br />
(SL2PF) Default: 10. ! SL2PF = 10.0 !<br />
Puff-splitting control variables ------------------------<br />
VERTICAL SPLIT<br />
--------------<br />
Number of puffs that result every time a puff<br />
is split - nsplit=2 means that 1 puff splits<br />
into 2<br />
(NSPLIT) Default: 3 ! NSPLIT = 3 !<br />
Time(s) of a day when split puffs are eligible to<br />
be split once again; this is typically set once<br />
per day, around sunset before nocturnal shear develops.<br />
24 values: 0 is midnight (00:00) and 23 is 11 PM (23:00)<br />
0=do not re-split 1=eligible for re-split<br />
(IRESPLIT(24)) Default: Hour 17 = 1<br />
! IRESPLIT = 0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,1,0,0,0,0,0,0,0 !<br />
Split is allowed only if last hour's mixing<br />
height (m) exceeds a minimum value<br />
(ZISPLIT) Default: 100. ! ZISPLIT = 100.0 !<br />
Split is allowed only if ratio of last hour's<br />
mixing ht to the maximum mixing ht experienced<br />
by the puff is less than a maximum value (this<br />
postpones a split until a nocturnal layer develops)<br />
(ROLDMAX) Default: 0.25 ! ROLDMAX = 0.25 !<br />
HORIZONTAL SPLIT<br />
----------------<br />
Number of puffs that result every time a puff<br />
is split - nsplith=5 means that 1 puff splits<br />
into 5<br />
(NSPLITH) Default: 5 ! NSPLITH = 5 !<br />
Minimum sigma-y (Grid Cells Units) of puff<br />
before it may be split<br />
(SYSPLITH) Default: 1.0 ! SYSPLITH = 1.0 !<br />
Page 26
!END!<br />
2001_SO_NOx.inp<br />
Minimum puff elongation rate (SYSPLITH/hr) due to<br />
wind shear, before it may be split<br />
(SHSPLITH) Default: 2. ! SHSPLITH = 2.0 !<br />
Minimum concentration (g/m^3) of each<br />
species in puff before it may be split<br />
Enter array of NSPEC values; if a single value is<br />
entered, it will be used for ALL species<br />
(CNSPLITH) Default: 1.0E-07 ! CNSPLITH = 1.0E-07 !<br />
Integration control variables ------------------------<br />
Fractional convergence criterion for numerical SLUG<br />
sampling integration<br />
(EPSSLUG) Default: 1.0e-04 ! EPSSLUG = 1.0E-04 !<br />
Fractional convergence criterion for numerical AREA<br />
source integration<br />
(EPSAREA) Default: 1.0e-06 ! EPSAREA = 1.0E-06 !<br />
Trajectory step-length (m) used for numerical rise<br />
integration<br />
(DSRISE) Default: 1.0 ! DSRISE = 1.0 !<br />
Boundary Condition (BC) Puff control variables ------------------------<br />
Minimum height (m) to which BC puffs are mixed as they are emitted<br />
(MBCON=2 ONLY). Actual height is reset to the current mixing height<br />
at the release point if greater than this minimum.<br />
(HTMINBC) Default: 500. ! HTMINBC = 500.0 !<br />
Search radius (in BC segment lengths) about a receptor for sampling<br />
nearest BC puff. BC puffs are emitted with a spacing of one segment<br />
length, so the search radius should be greater than 1.<br />
(RSAMPBC) Default: 4. ! RSAMPBC = 10.0 !<br />
Near-Surface depletion adjustment to concentration profile used when<br />
sampling BC puffs?<br />
(MDEPBC) Default: 1 ! MDEPBC = 1 !<br />
0 = Concentration is NOT adjusted for depletion<br />
1 = Adjust Concentration for depletion<br />
-------------------------------------------------------------------------------<br />
Page 27
2001_SO_NOx.inp<br />
INPUT GROUPS: 13a, 13b, 13c, 13d -- Point source parameters<br />
--------------------------------<br />
---------------<br />
Subgroup (13a)<br />
---------------<br />
!END!<br />
Number of point sources with<br />
parameters provided below (NPT1) No default ! NPT1 = 2 !<br />
Units used for point source<br />
emissions below (IPTU) Default: 1 ! IPTU = 3 !<br />
1 = g/s<br />
2 = kg/hr<br />
3 = lb/hr<br />
4 = tons/yr<br />
5 = Odour Unit * m**3/s (vol. flux of odour compound)<br />
6 = Odour Unit * m**3/min<br />
7 = metric tons/yr<br />
Number of source-species<br />
combinations with variable<br />
emissions scaling factors<br />
provided below in (13d) (NSPT1) Default: 0 ! NSPT1 = 0 !<br />
Number of point sources with<br />
variable emission parameters<br />
provided in external file (NPT2) No default ! NPT2 = 0 !<br />
(If NPT2 > 0, these point<br />
source emissions are read from<br />
the file: PTEMARB.DAT)<br />
---------------<br />
Subgroup (13b)<br />
---------------<br />
a<br />
POINT SOURCE: CONSTANT DATA<br />
---------------------------b<br />
c<br />
Source X Y Stack Base Stack Exit Exit Bldg. Emission<br />
No. Coordinate Coordinate Height Elevation Diameter Vel. Temp. Dwash Rates<br />
(km) (km) (m) (m) (m) (m/s) (deg. K)<br />
------ ---------- ---------- ------ ------ -------- ----- -------- ----- --------<br />
1 ! SRCNAM = SO1 ! Sooner Unit 1<br />
Page 28
2001_SO_NOx.inp<br />
1 ! X = -4.646, -392.196, 152.44, 326, 6.10, 34.12, 430.78, 0,<br />
0,0,3075,0,0,0,0,0,0,0!<br />
1 ! FMFAC = 1 !<br />
1 ! END !<br />
2 ! SRCNAM = SO2 ! Sooner Unit 2<br />
2 ! X = -4.721, -392.165, 152.44, 326, 6.10, 34.12, 430.78, 0,<br />
0,0,2988,0,0,0,0,0,0,0!<br />
2 ! FMFAC = 1 !<br />
2 ! END !<br />
--------<br />
a<br />
Data for each source are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
SRCNAM is a 12-character name for a source<br />
(No default)<br />
X is an array holding the source data listed by the column headings<br />
(No default)<br />
SIGYZI is an array holding the initial sigma-y and sigma-z (m)<br />
(Default: 0.,0.)<br />
FMFAC is a vertical momentum flux factor (0. or 1.0) used to represent<br />
the effect of rain-caps or other physical configurations that<br />
reduce momentum rise associated with the actual exit velocity.<br />
(Default: 1.0 -- full momentum used)<br />
b<br />
0. = No building downwash modeled, 1. = downwash modeled<br />
NOTE: must be entered as a REAL number (i.e., with decimal point)<br />
c<br />
An emission rate must be entered for every pollutant modeled.<br />
Enter emission rate of zero for secondary pollutants that are<br />
modeled, but not emitted. Units are specified by IPTU<br />
(e.g. 1 for g/s).<br />
---------------<br />
Subgroup (13c)<br />
---------------<br />
BUILDING DIMENSION DATA FOR SOURCES SUBJECT TO DOWNWASH<br />
-------------------------------------------------------<br />
Source a<br />
No. Effective building height, width, length and X/Y offset (in meters)<br />
every 10 degrees. LENGTH, XBADJ, and YBADJ are only needed for<br />
MBDW=2 (PRIME downwash option)<br />
------ --------------------------------------------------------------------<br />
Page 29
--------<br />
2001_SO_NOx.inp<br />
a<br />
Building height, width, length, and X/Y offset from the source are treated<br />
as a separate input subgroup for each source and therefore must end with<br />
an input group terminator. The X/Y offset is the position, relative to the<br />
stack, of the center of the upwind face of the projected building, with the<br />
x-axis pointing along the flow direction.<br />
---------------<br />
Subgroup (13d)<br />
---------------<br />
POINT SOURCE: VARIABLE EMISSIONS DATA<br />
---------------------------------------<br />
Use this subgroup to describe temporal variations in the emission<br />
rates given in 13b. Factors entered multiply the rates in 13b.<br />
Skip sources here that have constant emissions. For more elaborate<br />
variation in source parameters, use PTEMARB.DAT and NPT2 > 0.<br />
IVARY determines the type of variation, and is source-specific:<br />
(IVARY) Default: 0<br />
0 = Constant<br />
1 = Diurnal cycle (24 scaling factors: hours 1-24)<br />
2 = Monthly cycle (12 scaling factors: months 1-12)<br />
3 = Hour & Season (4 groups of 24 hourly scaling factors,<br />
where first group is DEC-JAN-FEB)<br />
4 = Speed & Stab. (6 groups of 6 scaling factors, where<br />
first group is Stability Class A,<br />
and the speed classes have upper<br />
bounds (m/s) defined in Group 12<br />
5 = Temperature (12 scaling factors, where temperature<br />
classes have upper bounds (C) of:<br />
0, 5, 10, 15, 20, 25, 30, 35, 40,<br />
45, 50, 50+)<br />
-------a<br />
Data for each species are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
-------------------------------------------------------------------------------<br />
a<br />
Page 30
2001_SO_NOx.inp<br />
INPUT GROUPS: 14a, 14b, 14c, 14d -- Area source parameters<br />
--------------------------------<br />
---------------<br />
Subgroup (14a)<br />
---------------<br />
!END!<br />
Number of polygon area sources with<br />
parameters specified below (NAR1) No default ! NAR1 = 0 !<br />
Units used for area source<br />
emissions below (IARU) Default: 1 ! IARU = 1 !<br />
1 = g/m**2/s<br />
2 = kg/m**2/hr<br />
3 = lb/m**2/hr<br />
4 = tons/m**2/yr<br />
5 = Odour Unit * m/s (vol. flux/m**2 of odour compound)<br />
6 = Odour Unit * m/min<br />
7 = metric tons/m**2/yr<br />
Number of source-species<br />
combinations with variable<br />
emissions scaling factors<br />
provided below in (14d) (NSAR1) Default: 0 ! NSAR1 = 0 !<br />
Number of buoyant polygon area sources<br />
with variable location and emission<br />
parameters (NAR2) No default ! NAR2 = 0 !<br />
(If NAR2 > 0, ALL parameter data for<br />
these sources are read from the file: BAEMARB.DAT)<br />
---------------<br />
Subgroup (14b)<br />
---------------<br />
AREA SOURCE: CONSTANT DATA<br />
--------------------------b<br />
Source Effect. Base Initial Emission<br />
No. Height Elevation Sigma z Rates<br />
(m) (m) (m)<br />
------- ------ ------ -------- ---------<br />
--------<br />
a<br />
Page 31
2001_SO_NOx.inp<br />
a<br />
Data for each source are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
b<br />
An emission rate must be entered for every pollutant modeled.<br />
Enter emission rate of zero for secondary pollutants that are<br />
modeled, but not emitted. Units are specified by IARU<br />
(e.g. 1 for g/m**2/s).<br />
---------------<br />
Subgroup (14c)<br />
---------------<br />
COORDINATES (km) FOR EACH VERTEX(4) OF EACH POLYGON<br />
--------------------------------------------------------<br />
Source a<br />
No. Ordered list of X followed by list of Y, grouped by source<br />
------ ------------------------------------------------------------<br />
-------a<br />
Data for each source are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
---------------<br />
Subgroup (14d)<br />
---------------<br />
AREA SOURCE: VARIABLE EMISSIONS DATA<br />
--------------------------------------<br />
Use this subgroup to describe temporal variations in the emission<br />
rates given in 14b. Factors entered multiply the rates in 14b.<br />
Skip sources here that have constant emissions. For more elaborate<br />
variation in source parameters, use BAEMARB.DAT and NAR2 > 0.<br />
IVARY determines the type of variation, and is source-specific:<br />
(IVARY) Default: 0<br />
0 = Constant<br />
1 = Diurnal cycle (24 scaling factors: hours 1-24)<br />
2 = Monthly cycle (12 scaling factors: months 1-12)<br />
3 = Hour & Season (4 groups of 24 hourly scaling factors,<br />
where first group is DEC-JAN-FEB)<br />
4 = Speed & Stab. (6 groups of 6 scaling factors, where<br />
first group is Stability Class A,<br />
and the speed classes have upper<br />
Page 32<br />
a
2001_SO_NOx.inp<br />
bounds (m/s) defined in Group 12<br />
5 = Temperature (12 scaling factors, where temperature<br />
classes have upper bounds (C) of:<br />
0, 5, 10, 15, 20, 25, 30, 35, 40,<br />
45, 50, 50+)<br />
-------a<br />
Data for each species are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
-------------------------------------------------------------------------------<br />
INPUT GROUPS: 15a, 15b, 15c -- Line source parameters<br />
---------------------------<br />
---------------<br />
Subgroup (15a)<br />
---------------<br />
Number of buoyant line sources<br />
with variable location and emission<br />
parameters (NLN2) No default ! NLN2 = 0 !<br />
(If NLN2 > 0, ALL parameter data for<br />
these sources are read from the file: LNEMARB.DAT)<br />
Number of buoyant line sources (NLINES) No default ! NLINES = 0 !<br />
Units used for line source<br />
emissions below (ILNU) Default: 1 ! ILNU = 3 !<br />
1 = g/s<br />
2 = kg/hr<br />
3 = lb/hr<br />
4 = tons/yr<br />
5 = Odour Unit * m**3/s (vol. flux of odour compound)<br />
6 = Odour Unit * m**3/min<br />
7 = metric tons/yr<br />
Number of source-species<br />
combinations with variable<br />
emissions scaling factors<br />
provided below in (15c) (NSLN1) Default: 0 ! NSLN1 = 0 !<br />
Maximum number of segments used to model<br />
Page 33
!END!<br />
2001_SO_NOx.inp<br />
each line (MXNSEG) Default: 7 ! MXNSEG = 7 !<br />
The following variables are required only if NLINES > 0. They are<br />
used in the buoyant line source plume rise calculations.<br />
---------------<br />
Subgroup (15b)<br />
---------------<br />
Number of distances at which Default: 6 ! NLRISE = 6 !<br />
transitional rise is computed<br />
Average building length (XL) No default ! XL = .0 !<br />
(in meters)<br />
Average building height (HBL) No default ! HBL = .0 !<br />
(in meters)<br />
Average building width (WBL) No default ! WBL = .0 !<br />
(in meters)<br />
Average line source width (WML) No default ! WML = .0 !<br />
(in meters)<br />
Average separation between buildings (DXL) No default ! DXL = .0 !<br />
(in meters)<br />
Average buoyancy parameter (FPRIMEL) No default ! FPRIMEL = .0 !<br />
(in m**4/s**3)<br />
BUOYANT LINE SOURCE: CONSTANT DATA<br />
----------------------------------<br />
Source Beg. X Beg. Y End. X End. Y Release Base Emission<br />
No. Coordinate Coordinate Coordinate Coordinate Height Elevation Rates<br />
(km) (km) (km) (km) (m) (m)<br />
------ ---------- ---------- --------- ---------- ------- --------- ---------<br />
--------<br />
a<br />
Data for each source are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
b<br />
An emission rate must be entered for every pollutant modeled.<br />
Page 34<br />
a
2001_SO_NOx.inp<br />
Enter emission rate of zero for secondary pollutants that are<br />
modeled, but not emitted. Units are specified by ILNTU<br />
(e.g. 1 for g/s).<br />
---------------<br />
Subgroup (15c)<br />
---------------<br />
BUOYANT LINE SOURCE: VARIABLE EMISSIONS DATA<br />
----------------------------------------------<br />
Use this subgroup to describe temporal variations in the emission<br />
rates given in 15b. Factors entered multiply the rates in 15b.<br />
Skip sources here that have constant emissions.<br />
IVARY determines the type of variation, and is source-specific:<br />
(IVARY) Default: 0<br />
0 = Constant<br />
1 = Diurnal cycle (24 scaling factors: hours 1-24)<br />
2 = Monthly cycle (12 scaling factors: months 1-12)<br />
3 = Hour & Season (4 groups of 24 hourly scaling factors,<br />
where first group is DEC-JAN-FEB)<br />
4 = Speed & Stab. (6 groups of 6 scaling factors, where<br />
first group is Stability Class A,<br />
and the speed classes have upper<br />
bounds (m/s) defined in Group 12<br />
5 = Temperature (12 scaling factors, where temperature<br />
classes have upper bounds (C) of:<br />
0, 5, 10, 15, 20, 25, 30, 35, 40,<br />
45, 50, 50+)<br />
-------a<br />
Data for each species are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
-------------------------------------------------------------------------------<br />
INPUT GROUPS: 16a, 16b, 16c -- Volume source parameters<br />
---------------------------<br />
---------------<br />
Subgroup (16a)<br />
---------------<br />
a<br />
Page 35
!END!<br />
2001_SO_NOx.inp<br />
Number of volume sources with<br />
parameters provided in 16b,c (NVL1) No default ! NVL1 = 0 !<br />
Units used for volume source<br />
emissions below in 16b (IVLU) Default: 1 ! IVLU = 3 !<br />
1 = g/s<br />
2 = kg/hr<br />
3 = lb/hr<br />
4 = tons/yr<br />
5 = Odour Unit * m**3/s (vol. flux of odour compound)<br />
6 = Odour Unit * m**3/min<br />
7 = metric tons/yr<br />
Number of source-species<br />
combinations with variable<br />
emissions scaling factors<br />
provided below in (16c) (NSVL1) Default: 0 ! NSVL1 = 0 !<br />
Number of volume sources with<br />
variable location and emission<br />
parameters (NVL2) No default ! NVL2 = 0 !<br />
(If NVL2 > 0, ALL parameter data for<br />
these sources are read from the VOLEMARB.DAT file(s) )<br />
---------------<br />
Subgroup (16b)<br />
---------------<br />
a<br />
VOLUME SOURCE: CONSTANT DATA<br />
----------------------------b<br />
X Y Effect. Base Initial Initial Emission<br />
Coordinate Coordinate Height Elevation Sigma y Sigma z Rates<br />
(km) (km) (m) (m) (m) (m)<br />
---------- ---------- ------ ------ -------- -------- --------<br />
-------a<br />
Data for each source are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
b<br />
An emission rate must be entered for every pollutant modeled.<br />
Page 36
2001_SO_NOx.inp<br />
Enter emission rate of zero for secondary pollutants that are<br />
modeled, but not emitted. Units are specified by IVLU<br />
(e.g. 1 for g/s).<br />
---------------<br />
Subgroup (16c)<br />
---------------<br />
VOLUME SOURCE: VARIABLE EMISSIONS DATA<br />
----------------------------------------<br />
Use this subgroup to describe temporal variations in the emission<br />
rates given in 16b. Factors entered multiply the rates in 16b.<br />
Skip sources here that have constant emissions. For more elaborate<br />
variation in source parameters, use VOLEMARB.DAT and NVL2 > 0.<br />
IVARY determines the type of variation, and is source-specific:<br />
(IVARY) Default: 0<br />
0 = Constant<br />
1 = Diurnal cycle (24 scaling factors: hours 1-24)<br />
2 = Monthly cycle (12 scaling factors: months 1-12)<br />
3 = Hour & Season (4 groups of 24 hourly scaling factors,<br />
where first group is DEC-JAN-FEB)<br />
4 = Speed & Stab. (6 groups of 6 scaling factors, where<br />
first group is Stability Class A,<br />
and the speed classes have upper<br />
bounds (m/s) defined in Group 12<br />
5 = Temperature (12 scaling factors, where temperature<br />
classes have upper bounds (C) of:<br />
0, 5, 10, 15, 20, 25, 30, 35, 40,<br />
45, 50, 50+)<br />
-------a<br />
Data for each species are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
-------------------------------------------------------------------------------<br />
INPUT GROUPS: 17a & 17b -- Non-gridded (discrete) receptor information<br />
-----------------------<br />
---------------<br />
Subgroup (17a)<br />
---------------<br />
a<br />
Page 37
!END!<br />
2001_SO_NOx.inp<br />
Number of non-gridded receptors (NREC) No default ! NREC = 291 !<br />
---------------<br />
Subgroup (17b)<br />
-------------a<br />
NON-GRIDDED (DISCRETE) RECEPTOR DATA<br />
------------------------------------<br />
X Y Ground Height b<br />
Receptor Coordinate Coordinate Elevation Above Ground<br />
No. (km) (km) (m) (m)<br />
-------- ---------- ---------- --------- ------------<br />
1 ! X = 359.836, -362.005, 274, 0 ! !END! HG1<br />
2 ! X = 360.575, -361.972, 299, 0 ! !END! HG2<br />
3 ! X = 361.314, -361.939, 328, 0 ! !END! HG3<br />
4 ! X = 362.053, -361.906, 365, 0 ! !END! HG4<br />
5 ! X = 358.316, -361.150, 250, 0 ! !END! HG5<br />
6 ! X = 359.055, -361.117, 278, 0 ! !END! HG6<br />
7 ! X = 359.794, -361.084, 335, 0 ! !END! HG7<br />
8 ! X = 360.533, -361.051, 307, 0 ! !END! HG8<br />
9 ! X = 361.272, -361.018, 345, 0 ! !END! HG9<br />
10 ! X = 357.537, -360.261, 261, 0 ! !END! HG10<br />
11 ! X = 358.275, -360.228, 271, 0 ! !END! HG11<br />
12 ! X = 359.014, -360.195, 274, 0 ! !END! HG12<br />
13 ! X = 359.753, -360.162, 331, 0 ! !END! HG13<br />
14 ! X = 360.492, -360.129, 327, 0 ! !END! HG14<br />
15 ! X = 361.231, -360.096, 304, 0 ! !END! HG15<br />
16 ! X = 361.970, -360.063, 335, 0 ! !END! HG16<br />
17 ! X = 362.709, -360.030, 312, 0 ! !END! HG17<br />
18 ! X = 363.448, -359.997, 340, 0 ! !END! HG18<br />
19 ! X = 364.187, -359.963, 361, 0 ! !END! HG19<br />
20 ! X = 364.926, -359.930, 382, 0 ! !END! HG20<br />
21 ! X = 357.496, -359.340, 274, 0 ! !END! HG21<br />
22 ! X = 358.235, -359.307, 274, 0 ! !END! HG22<br />
23 ! X = 358.973, -359.274, 335, 0 ! !END! HG23<br />
24 ! X = 359.712, -359.241, 294, 0 ! !END! HG24<br />
25 ! X = 360.451, -359.208, 304, 0 ! !END! HG25<br />
26 ! X = 361.190, -359.175, 279, 0 ! !END! HG26<br />
27 ! X = 361.929, -359.142, 304, 0 ! !END! HG27<br />
28 ! X = 362.668, -359.109, 318, 0 ! !END! HG28<br />
29 ! X = 363.406, -359.075, 335, 0 ! !END! HG29<br />
30 ! X = 364.145, -359.042, 347, 0 ! !END! HG30<br />
31 ! X = 364.884, -359.008, 340, 0 ! !END! HG31<br />
32 ! X = 358.932, -358.353, 247, 0 ! !END! HG32<br />
Page 38
2001_SO_NOx.inp<br />
33 ! X = 359.671, -358.320, 271, 0 ! !END! HG33<br />
34 ! X = 360.410, -358.287, 275, 0 ! !END! HG34<br />
35 ! X = 361.149, -358.254, 274, 0 ! !END! HG35<br />
36 ! X = 361.887, -358.220, 277, 0 ! !END! HG36<br />
37 ! X = 362.626, -358.187, 304, 0 ! !END! HG37<br />
38 ! X = 363.365, -358.154, 330, 0 ! !END! HG38<br />
39 ! X = 364.104, -358.121, 357, 0 ! !END! HG39<br />
40 ! X = 364.842, -358.087, 384, 0 ! !END! HG40<br />
41 ! X = 365.581, -358.054, 372, 0 ! !END! HG41<br />
42 ! X = 356.675, -357.530, 274, 0 ! !END! HG42<br />
43 ! X = 357.414, -357.497, 293, 0 ! !END! HG43<br />
44 ! X = 358.153, -357.464, 272, 0 ! !END! HG44<br />
45 ! X = 358.891, -357.431, 271, 0 ! !END! HG45<br />
46 ! X = 359.630, -357.398, 274, 0 ! !END! HG46<br />
47 ! X = 360.369, -357.365, 327, 0 ! !END! HG47<br />
48 ! X = 361.107, -357.332, 316, 0 ! !END! HG48<br />
49 ! X = 361.846, -357.299, 304, 0 ! !END! HG49<br />
50 ! X = 362.585, -357.266, 354, 0 ! !END! HG50<br />
51 ! X = 363.323, -357.233, 346, 0 ! !END! HG51<br />
52 ! X = 364.062, -357.199, 335, 0 ! !END! HG52<br />
53 ! X = 364.801, -357.166, 344, 0 ! !END! HG53<br />
54 ! X = 365.539, -357.132, 364, 0 ! !END! HG54<br />
55 ! X = 357.373, -356.576, 243, 0 ! !END! HG55<br />
56 ! X = 358.112, -356.543, 335, 0 ! !END! HG56<br />
57 ! X = 358.850, -356.510, 324, 0 ! !END! HG57<br />
58 ! X = 359.589, -356.477, 335, 0 ! !END! HG58<br />
59 ! X = 360.327, -356.444, 341, 0 ! !END! HG59<br />
60 ! X = 361.066, -356.411, 333, 0 ! !END! HG60<br />
61 ! X = 361.805, -356.378, 306, 0 ! !END! HG61<br />
62 ! X = 362.543, -356.345, 304, 0 ! !END! HG62<br />
63 ! X = 363.282, -356.311, 365, 0 ! !END! HG63<br />
64 ! X = 364.020, -356.278, 304, 0 ! !END! HG64<br />
65 ! X = 364.759, -356.245, 309, 0 ! !END! HG65<br />
66 ! X = 365.497, -356.211, 307, 0 ! !END! HG66<br />
67 ! X = 357.332, -355.654, 270, 0 ! !END! HG67<br />
68 ! X = 358.071, -355.622, 274, 0 ! !END! HG68<br />
69 ! X = 358.809, -355.589, 301, 0 ! !END! HG69<br />
70 ! X = 359.548, -355.556, 274, 0 ! !END! HG70<br />
71 ! X = 360.286, -355.523, 274, 0 ! !END! HG71<br />
72 ! X = 361.025, -355.490, 312, 0 ! !END! HG72<br />
73 ! X = 361.763, -355.457, 274, 0 ! !END! HG73<br />
74 ! X = 362.502, -355.423, 322, 0 ! !END! HG74<br />
75 ! X = 363.240, -355.390, 304, 0 ! !END! HG75<br />
76 ! X = 363.979, -355.357, 275, 0 ! !END! HG76<br />
77 ! X = 364.717, -355.323, 304, 0 ! !END! HG77<br />
78 ! X = 365.456, -355.290, 290, 0 ! !END! HG78<br />
79 ! X = 362.460, -354.502, 249, 0 ! !END! HG79<br />
80 ! X = 363.199, -354.469, 274, 0 ! !END! HG80<br />
Page 39
2001_SO_NOx.inp<br />
81 ! X = -159.867, -584.484, 454, 0 ! !END! WM1<br />
82 ! X = -159.108, -584.499, 486, 0 ! !END! WM2<br />
83 ! X = -158.348, -584.513, 487, 0 ! !END! WM3<br />
84 ! X = -157.589, -584.528, 478, 0 ! !END! WM4<br />
85 ! X = -156.829, -584.542, 518, 0 ! !END! WM5<br />
86 ! X = -156.070, -584.557, 518, 0 ! !END! WM6<br />
87 ! X = -161.368, -583.531, 510, 0 ! !END! WM7<br />
88 ! X = -160.609, -583.546, 493, 0 ! !END! WM8<br />
89 ! X = -159.849, -583.560, 488, 0 ! !END! WM9<br />
90 ! X = -159.090, -583.575, 615, 0 ! !END! WM10<br />
91 ! X = -158.331, -583.589, 522, 0 ! !END! WM11<br />
92 ! X = -157.571, -583.604, 494, 0 ! !END! WM12<br />
93 ! X = -156.812, -583.618, 609, 0 ! !END! WM13<br />
94 ! X = -156.052, -583.633, 518, 0 ! !END! WM14<br />
95 ! X = -162.110, -582.592, 487, 0 ! !END! WM15<br />
96 ! X = -161.350, -582.607, 518, 0 ! !END! WM16<br />
97 ! X = -160.591, -582.622, 609, 0 ! !END! WM17<br />
98 ! X = -159.832, -582.636, 554, 0 ! !END! WM18<br />
99 ! X = -159.072, -582.651, 578, 0 ! !END! WM19<br />
100 ! X = -158.313, -582.666, 557, 0 ! !END! WM20<br />
101 ! X = -157.554, -582.680, 571, 0 ! !END! WM21<br />
102 ! X = -156.794, -582.694, 670, 0 ! !END! WM22<br />
103 ! X = -156.035, -582.709, 518, 0 ! !END! WM23<br />
104 ! X = -160.573, -581.698, 518, 0 ! !END! WM24<br />
105 ! X = -159.814, -581.712, 548, 0 ! !END! WM25<br />
106 ! X = -159.054, -581.727, 548, 0 ! !END! WM26<br />
107 ! X = -158.295, -581.742, 518, 0 ! !END! WM27<br />
108 ! X = -160.555, -580.774, 517, 0 ! !END! WM28<br />
109 ! X = -159.796, -580.789, 579, 0 ! !END! WM29<br />
110 ! X = -159.037, -580.803, 613, 0 ! !END! WM30<br />
111 ! X = -158.278, -580.818, 548, 0 ! !END! WM31<br />
112 ! X = -157.518, -580.832, 523, 0 ! !END! WM32<br />
113 ! X = -161.296, -579.835, 542, 0 ! !END! WM33<br />
114 ! X = -160.537, -579.850, 545, 0 ! !END! WM34<br />
115 ! X = -159.778, -579.865, 552, 0 ! !END! WM35<br />
116 ! X = -152.895, -577.222, 579, 0 ! !END! WM36<br />
117 ! X = -155.913, -576.242, 609, 0 ! !END! WM37<br />
118 ! X = -155.154, -576.256, 654, 0 ! !END! WM38<br />
119 ! X = -154.396, -576.270, 621, 0 ! !END! WM39<br />
120 ! X = -153.637, -576.284, 629, 0 ! !END! WM40<br />
121 ! X = -152.878, -576.298, 579, 0 ! !END! WM41<br />
122 ! X = -152.119, -576.312, 560, 0 ! !END! WM42<br />
123 ! X = -156.654, -575.304, 615, 0 ! !END! WM43<br />
124 ! X = -155.896, -575.318, 641, 0 ! !END! WM44<br />
125 ! X = -155.137, -575.332, 640, 0 ! !END! WM45<br />
126 ! X = -154.378, -575.346, 662, 0 ! !END! WM46<br />
127 ! X = -153.620, -575.361, 618, 0 ! !END! WM47<br />
128 ! X = -152.861, -575.375, 630, 0 ! !END! WM48<br />
Page 40
2001_SO_NOx.inp<br />
129 ! X = -152.102, -575.389, 534, 0 ! !END! WM49<br />
130 ! X = -156.637, -574.380, 606, 0 ! !END! WM50<br />
131 ! X = -155.878, -574.394, 566, 0 ! !END! WM51<br />
132 ! X = -155.120, -574.408, 633, 0 ! !END! WM52<br />
133 ! X = -154.361, -574.423, 670, 0 ! !END! WM53<br />
134 ! X = -153.603, -574.437, 609, 0 ! !END! WM54<br />
135 ! X = -152.844, -574.451, 579, 0 ! !END! WM55<br />
136 ! X = -152.085, -574.465, 535, 0 ! !END! WM56<br />
137 ! X = -155.102, -573.485, 548, 0 ! !END! WM57<br />
138 ! X = -154.344, -573.499, 518, 0 ! !END! WM58<br />
139 ! X = -153.585, -573.513, 506, 0 ! !END! WM59<br />
140 ! X = 318.344, -456.077, 555, 0 ! !END! UB1<br />
141 ! X = 319.091, -456.047, 589, 0 ! !END! UB2<br />
142 ! X = 321.334, -455.959, 563, 0 ! !END! UB3<br />
143 ! X = 318.308, -455.154, 549, 0 ! !END! UB4<br />
144 ! X = 319.055, -455.125, 487, 0 ! !END! UB5<br />
145 ! X = 319.803, -455.096, 487, 0 ! !END! UB6<br />
146 ! X = 320.551, -455.067, 490, 0 ! !END! UB7<br />
147 ! X = 318.272, -454.232, 650, 0 ! !END! UB8<br />
148 ! X = 319.019, -454.203, 563, 0 ! !END! UB9<br />
149 ! X = 319.767, -454.174, 540, 0 ! !END! UB10<br />
150 ! X = 320.514, -454.144, 502, 0 ! !END! UB11<br />
151 ! X = 321.262, -454.115, 526, 0 ! !END! UB12<br />
152 ! X = 322.757, -454.056, 534, 0 ! !END! UB13<br />
153 ! X = 323.504, -454.026, 563, 0 ! !END! UB14<br />
154 ! X = 318.236, -453.310, 548, 0 ! !END! UB15<br />
155 ! X = 318.983, -453.281, 628, 0 ! !END! UB16<br />
156 ! X = 319.731, -453.252, 623, 0 ! !END! UB17<br />
157 ! X = 320.478, -453.222, 579, 0 ! !END! UB18<br />
158 ! X = 321.225, -453.193, 469, 0 ! !END! UB19<br />
159 ! X = 321.973, -453.163, 457, 0 ! !END! UB20<br />
160 ! X = 322.720, -453.134, 573, 0 ! !END! UB21<br />
161 ! X = 323.468, -453.104, 605, 0 ! !END! UB22<br />
162 ! X = 324.215, -453.074, 588, 0 ! !END! UB23<br />
163 ! X = 318.200, -452.388, 608, 0 ! !END! UB24<br />
164 ! X = 318.947, -452.359, 660, 0 ! !END! UB25<br />
165 ! X = 319.694, -452.329, 598, 0 ! !END! UB26<br />
166 ! X = 320.442, -452.300, 599, 0 ! !END! UB27<br />
167 ! X = 321.189, -452.271, 639, 0 ! !END! UB28<br />
168 ! X = 321.937, -452.241, 457, 0 ! !END! UB29<br />
169 ! X = 322.684, -452.212, 568, 0 ! !END! UB30<br />
170 ! X = 318.164, -451.466, 730, 0 ! !END! UB31<br />
171 ! X = 318.911, -451.437, 681, 0 ! !END! UB32<br />
172 ! X = 319.658, -451.407, 640, 0 ! !END! UB33<br />
173 ! X = 320.406, -451.378, 625, 0 ! !END! UB34<br />
174 ! X = 321.153, -451.348, 426, 0 ! !END! UB35<br />
175 ! X = 321.900, -451.319, 555, 0 ! !END! UB36<br />
176 ! X = 322.647, -451.289, 612, 0 ! !END! UB37<br />
Page 41
2001_SO_NOx.inp<br />
177 ! X = 317.380, -450.573, 667, 0 ! !END! UB38<br />
178 ! X = 318.128, -450.544, 580, 0 ! !END! UB39<br />
179 ! X = 318.875, -450.514, 656, 0 ! !END! UB40<br />
180 ! X = 319.622, -450.485, 640, 0 ! !END! UB41<br />
181 ! X = 320.369, -450.456, 487, 0 ! !END! UB42<br />
182 ! X = 321.116, -450.426, 457, 0 ! !END! UB43<br />
183 ! X = 321.864, -450.397, 654, 0 ! !END! UB44<br />
184 ! X = 322.611, -450.367, 548, 0 ! !END! UB45<br />
185 ! X = 323.358, -450.338, 622, 0 ! !END! UB46<br />
186 ! X = 324.105, -450.308, 683, 0 ! !END! UB47<br />
187 ! X = 317.345, -449.651, 579, 0 ! !END! UB48<br />
188 ! X = 318.092, -449.621, 554, 0 ! !END! UB49<br />
189 ! X = 318.839, -449.592, 609, 0 ! !END! UB50<br />
190 ! X = 319.586, -449.563, 622, 0 ! !END! UB51<br />
191 ! X = 320.333, -449.534, 427, 0 ! !END! UB52<br />
192 ! X = 321.080, -449.504, 555, 0 ! !END! UB53<br />
193 ! X = 321.827, -449.475, 502, 0 ! !END! UB54<br />
194 ! X = 322.574, -449.445, 639, 0 ! !END! UB55<br />
195 ! X = 323.322, -449.416, 580, 0 ! !END! UB56<br />
196 ! X = 324.069, -449.386, 639, 0 ! !END! UB57<br />
197 ! X = 318.803, -448.670, 548, 0 ! !END! UB58<br />
198 ! X = 319.550, -448.641, 548, 0 ! !END! UB59<br />
199 ! X = 320.297, -448.612, 438, 0 ! !END! UB60<br />
200 ! X = 321.044, -448.582, 579, 0 ! !END! UB61<br />
201 ! X = 322.538, -448.523, 620, 0 ! !END! UB62<br />
202 ! X = 320.261, -447.689, 579, 0 ! !END! UB63<br />
203 ! X = 321.007, -447.660, 426, 0 ! !END! UB64<br />
204 ! X = 321.754, -447.631, 611, 0 ! !END! UB65<br />
205 ! X = 318.731, -446.826, 604, 0 ! !END! UB66<br />
206 ! X = 319.477, -446.797, 548, 0 ! !END! UB67<br />
207 ! X = 320.224, -446.767, 488, 0 ! !END! UB68<br />
208 ! X = 320.971, -446.738, 402, 0 ! !END! UB69<br />
209 ! X = 321.718, -446.708, 579, 0 ! !END! UB70<br />
210 ! X = 322.465, -446.679, 573, 0 ! !END! UB71<br />
211 ! X = 323.212, -446.649, 609, 0 ! !END! UB72<br />
212 ! X = 269.710, -618.629, 365, 0 ! !END! CC1<br />
213 ! X = 270.473, -618.605, 365, 0 ! !END! CC2<br />
214 ! X = 271.235, -618.580, 368, 0 ! !END! CC3<br />
215 ! X = 268.155, -617.755, 411, 0 ! !END! CC4<br />
216 ! X = 268.917, -617.730, 462, 0 ! !END! CC5<br />
217 ! X = 269.680, -617.705, 431, 0 ! !END! CC6<br />
218 ! X = 270.443, -617.681, 518, 0 ! !END! CC7<br />
219 ! X = 271.205, -617.656, 487, 0 ! !END! CC8<br />
220 ! X = 271.968, -617.631, 396, 0 ! !END! CC9<br />
221 ! X = 265.075, -616.929, 518, 0 ! !END! CC10<br />
222 ! X = 265.838, -616.904, 523, 0 ! !END! CC11<br />
223 ! X = 266.600, -616.880, 548, 0 ! !END! CC12<br />
224 ! X = 267.363, -616.855, 579, 0 ! !END! CC13<br />
Page 42
2001_SO_NOx.inp<br />
225 ! X = 268.125, -616.831, 547, 0 ! !END! CC14<br />
226 ! X = 268.888, -616.806, 538, 0 ! !END! CC15<br />
227 ! X = 269.650, -616.781, 640, 0 ! !END! CC16<br />
228 ! X = 270.412, -616.757, 608, 0 ! !END! CC17<br />
229 ! X = 259.709, -616.173, 335, 0 ! !END! CC18<br />
230 ! X = 260.472, -616.149, 431, 0 ! !END! CC19<br />
231 ! X = 261.234, -616.125, 457, 0 ! !END! CC20<br />
232 ! X = 261.996, -616.101, 414, 0 ! !END! CC21<br />
233 ! X = 262.759, -616.077, 426, 0 ! !END! CC22<br />
234 ! X = 263.521, -616.053, 426, 0 ! !END! CC23<br />
235 ! X = 264.283, -616.029, 388, 0 ! !END! CC24<br />
236 ! X = 265.046, -616.005, 388, 0 ! !END! CC25<br />
237 ! X = 265.808, -615.980, 365, 0 ! !END! CC26<br />
238 ! X = 266.571, -615.956, 386, 0 ! !END! CC27<br />
239 ! X = 267.333, -615.931, 396, 0 ! !END! CC28<br />
240 ! X = 268.095, -615.907, 426, 0 ! !END! CC29<br />
241 ! X = 268.858, -615.882, 446, 0 ! !END! CC30<br />
242 ! X = 269.620, -615.857, 441, 0 ! !END! CC31<br />
243 ! X = 270.382, -615.833, 457, 0 ! !END! CC32<br />
244 ! X = 271.145, -615.808, 465, 0 ! !END! CC33<br />
245 ! X = 271.907, -615.783, 442, 0 ! !END! CC34<br />
246 ! X = 272.670, -615.758, 426, 0 ! !END! CC35<br />
247 ! X = 259.680, -615.249, 304, 0 ! !END! CC36<br />
248 ! X = 260.443, -615.225, 304, 0 ! !END! CC37<br />
249 ! X = 261.205, -615.201, 319, 0 ! !END! CC38<br />
250 ! X = 261.967, -615.177, 334, 0 ! !END! CC39<br />
251 ! X = 262.730, -615.153, 370, 0 ! !END! CC40<br />
252 ! X = 263.492, -615.129, 405, 0 ! !END! CC41<br />
253 ! X = 264.254, -615.105, 409, 0 ! !END! CC42<br />
254 ! X = 265.016, -615.081, 450, 0 ! !END! CC43<br />
255 ! X = 265.779, -615.056, 518, 0 ! !END! CC44<br />
256 ! X = 266.541, -615.032, 609, 0 ! !END! CC45<br />
257 ! X = 267.303, -615.007, 534, 0 ! !END! CC46<br />
258 ! X = 268.066, -614.983, 517, 0 ! !END! CC47<br />
259 ! X = 268.828, -614.958, 575, 0 ! !END! CC48<br />
260 ! X = 269.590, -614.933, 600, 0 ! !END! CC49<br />
261 ! X = 270.352, -614.909, 609, 0 ! !END! CC50<br />
262 ! X = 271.115, -614.884, 609, 0 ! !END! CC51<br />
263 ! X = 271.877, -614.859, 561, 0 ! !END! CC52<br />
264 ! X = 260.414, -614.301, 335, 0 ! !END! CC53<br />
265 ! X = 261.176, -614.277, 432, 0 ! !END! CC54<br />
266 ! X = 261.938, -614.253, 487, 0 ! !END! CC55<br />
267 ! X = 262.700, -614.229, 499, 0 ! !END! CC56<br />
268 ! X = 263.463, -614.205, 514, 0 ! !END! CC57<br />
269 ! X = 264.225, -614.181, 442, 0 ! !END! CC58<br />
270 ! X = 264.987, -614.157, 439, 0 ! !END! CC59<br />
271 ! X = 265.749, -614.132, 395, 0 ! !END! CC60<br />
272 ! X = 266.511, -614.108, 400, 0 ! !END! CC61<br />
Page 43
2001_SO_NOx.inp<br />
273 ! X = 267.274, -614.083, 426, 0 ! !END! CC62<br />
274 ! X = 268.036, -614.059, 487, 0 ! !END! CC63<br />
275 ! X = 268.798, -614.034, 548, 0 ! !END! CC64<br />
276 ! X = 269.560, -614.010, 548, 0 ! !END! CC65<br />
277 ! X = 270.322, -613.985, 548, 0 ! !END! CC66<br />
278 ! X = 271.085, -613.960, 535, 0 ! !END! CC67<br />
279 ! X = 261.147, -613.353, 304, 0 ! !END! CC68<br />
280 ! X = 261.909, -613.329, 334, 0 ! !END! CC69<br />
281 ! X = 262.671, -613.305, 396, 0 ! !END! CC70<br />
282 ! X = 263.433, -613.281, 457, 0 ! !END! CC71<br />
283 ! X = 264.195, -613.257, 457, 0 ! !END! CC72<br />
284 ! X = 264.958, -613.233, 426, 0 ! !END! CC73<br />
285 ! X = 265.720, -613.208, 411, 0 ! !END! CC74<br />
286 ! X = 266.482, -613.184, 406, 0 ! !END! CC75<br />
287 ! X = 267.244, -613.159, 396, 0 ! !END! CC76<br />
288 ! X = 268.006, -613.135, 401, 0 ! !END! CC77<br />
289 ! X = 268.768, -613.110, 397, 0 ! !END! CC78<br />
290 ! X = 261.118, -612.429, 322, 0 ! !END! CC79<br />
291 ! X = 261.880, -612.405, 334, 0 ! !END! CC80<br />
------------a<br />
Data for each receptor are treated as a separate input subgroup<br />
and therefore must end with an input group terminator.<br />
b<br />
Receptor height above ground is optional. If no value is entered,<br />
the receptor is placed on the ground.<br />
Page 44
APPENDIX D – SAMPLE CALPOST CONTROL FILE<br />
OG&E Trinity Consultants<br />
BART Modeling Report 083701.0004
OGE Sooner <strong>Station</strong> - BART Determination<br />
Visibility Impact<br />
SO01_CC_vis.INP<br />
---------------- Run title (3 lines) ------------------------------------------<br />
CALPOST MODEL CONTROL FILE<br />
--------------------------<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 0 -- Input and Output File Names<br />
--------------<br />
Input Files<br />
-----------<br />
File Default File Name<br />
---- -----------------<br />
Conc/Dep Flux File MODEL.DAT ! MODDAT =..\2001_SO_NOX.DAT !<br />
Relative Humidity File VISB.DAT ! VISDAT =..\2001_SO_NOX.VIS !<br />
Background Data File BACK.DAT *BACKDAT = *<br />
Transmissometer/ VSRN.DAT *VSRDAT = *<br />
Nephelometer Data File<br />
Output Files<br />
------------<br />
File Default File Name<br />
---- -----------------<br />
List File CALPOST.LST ! PSTLST =SO01_CC_vis.lst !<br />
Pathname for Timeseries Files (blank) * TSPATH = *<br />
(activate with exclamation points only if<br />
providing NON-BLANK character string)<br />
Pathname for Plot Files (blank) * PLPATH = *<br />
(activate with exclamation points only if<br />
providing NON-BLANK character string)<br />
User Character String (U) to augment default filenames<br />
(activate with exclamation points only if<br />
providing NON-BLANK character string)<br />
Timeseries TSttUUUU.DAT * TSUNAM = *<br />
Top Nth Rank Plot RttUUUUU.DAT<br />
or RttiiUUU.GRD * TUNAM = *<br />
Page 1
SO01_CC_vis.INP<br />
Exceedance Plot XttUUUUU.DAT<br />
or XttUUUUU.GRD * XUNAM = *<br />
Echo Plot jjjtthhU.DAT<br />
(Specific Days) or jjjtthhU.GRD * EUNAM = *<br />
Visibility Plot V24UUUUU.DAT * VUNAM = *<br />
(Daily Peak Summary)<br />
--------------------------------------------------------------------------------<br />
All file names will be converted to lower case if LCFILES = T<br />
Otherwise, if LCFILES = F, file names will be converted to UPPER CASE<br />
T = lower case ! LCFILES = T !<br />
F = UPPER CASE<br />
NOTE: (1) file/path names can be up to 70 characters in length<br />
NOTE: (2) Filenames for ALL PLOT and TIMESERIES FILES are constructed<br />
using a template that includes a pathname, user-supplied<br />
character(s), and fixed strings (tt,ii,jjj, and hh), where<br />
tt = Averaging Period (e.g. 03)<br />
ii = Rank (e.g. 02)<br />
jjj= Julian Day<br />
hh = Hour(ending)<br />
are determined internally based on selections made below.<br />
If a path or user-supplied character(s) are supplied, each<br />
must contain at least 1 non-blank character.<br />
!END!<br />
--------------------------------------------------------------------------------<br />
INPUT GROUP: 1 -- General run control parameters<br />
--------------<br />
Option to run all periods found<br />
in the met. file(s) (METRUN) Default: 0 ! METRUN = 0 !<br />
METRUN = 0 - Run period explicitly defined below<br />
METRUN = 1 - Run all periods in CALPUFF data file(s)<br />
Starting date: Year (ISYR) -- No default ! ISYR = 2001 !<br />
(used only if Month (ISMO) -- No default ! ISMO = 1 !<br />
METRUN = 0) Day (ISDY) -- No default ! ISDY = 1 !<br />
Hour (ISHR) -- No default ! ISHR = 0 !<br />
Number of hours to process (NHRS) -- No default ! NHRS = 8753 !<br />
Process every hour of data?(NREP) -- Default: 1 ! NREP = 1 !<br />
(1 = every hour processed,<br />
2 = every 2nd hour processed,<br />
Page 2
5 = every 5th hour processed, etc.)<br />
Species & Concentration/Deposition Information<br />
----------------------------------------------<br />
SO01_CC_vis.INP<br />
Species to process (ASPEC) -- No default ! ASPEC = VISIB !<br />
(ASPEC = VISIB for visibility processing)<br />
Layer/deposition code (ILAYER) -- Default: 1 ! ILAYER = 1 !<br />
'1' for CALPUFF concentrations,<br />
'-1' for dry deposition fluxes,<br />
'-2' for wet deposition fluxes,<br />
'-3' for wet+dry deposition fluxes.<br />
Scaling factors of the form: -- Defaults: ! A = 0.0 !<br />
X(new) = X(old) * A + B A = 0.0 ! B = 0.0 !<br />
(NOT applied if A = B = 0.0) B = 0.0<br />
Add Hourly Background Concentrations/Fluxes?<br />
(LBACK) -- Default: F ! LBACK = F !<br />
Receptor information<br />
--------------------<br />
Gridded receptors processed? (LG) -- Default: F ! LG = F !<br />
Discrete receptors processed? (LD) -- Default: F ! LD = T !<br />
CTSG Complex terrain receptors processed?<br />
(LCT) -- Default: F ! LCT = F !<br />
--Report results by DISCRETE receptor RING?<br />
(only used when LD = T) (LDRING) -- Default: F ! LDRING = F !<br />
--Select range of DISCRETE receptors (only used when LD = T):<br />
Select ALL DISCRETE receptors by setting NDRECP flag to -1;<br />
OR<br />
Select SPECIFIC DISCRETE receptors by entering a flag (0,1) for each<br />
0 = discrete receptor not processed<br />
1 = discrete receptor processed<br />
using repeated value notation to select blocks of receptors:<br />
416*0, 1048*1, 1482*0<br />
Flag for all receptors after the last one assigned is set to 0<br />
(NDRECP) -- Default: -1<br />
! NDRECP = 80*0, 59*0, 72*0, 80*1!<br />
--Select range of GRIDDED receptors (only used when LG = T):<br />
Page 3
SO01_CC_vis.INP<br />
X index of LL corner (IBGRID) -- Default: -1 ! IBGRID = -1 !<br />
(-1 OR 1
SO01_CC_vis.INP<br />
the first row entered, or east of the last value provided in a row,<br />
remain ON.<br />
(NGXRECP) -- Default: 1<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 2 -- Visibility Parameters (ASPEC = VISIB)<br />
--------------<br />
Maximum relative humidity (%) used in particle growth curve<br />
(RHMAX) -- Default: 98 ! RHMAX = 95.0 !<br />
Modeled species to be included in computing the light extinction<br />
Include SULFATE? (LVSO4) -- Default: T ! LVSO4 = T !<br />
Include NITRATE? (LVNO3) -- Default: T ! LVNO3 = T !<br />
Include ORGANIC CARBON? (LVOC) -- Default: T ! LVOC = T !<br />
Include COARSE PARTICLES? (LVPMC) -- Default: T ! LVPMC = T !<br />
Include FINE PARTICLES? (LVPMF) -- Default: T ! LVPMF = T !<br />
Include ELEMENTAL CARBON? (LVEC) -- Default: T ! LVEC = T !<br />
And, when ranking for TOP-N, TOP-50, and Exceedance tables,<br />
Include BACKGROUND? (LVBK) -- Default: T ! LVBK = T !<br />
Species name used for particulates in MODEL.DAT file<br />
COARSE (SPECPMC) -- Default: PMC ! SPECPMC = PMC !<br />
FINE (SPECPMF) -- Default: PMF ! SPECPMF = PMF !<br />
Extinction Efficiency (1/Mm per ug/m**3)<br />
----------------------------------------<br />
MODELED particulate species:<br />
PM COARSE (EEPMC) -- Default: 0.6 ! EEPMC = 0.6 !<br />
PM FINE (EEPMF) -- Default: 1.0 ! EEPMF = 1.0 !<br />
BACKGROUND particulate species:<br />
PM COARSE (EEPMCBK) -- Default: 0.6 ! EEPMCBK = 0.6 !<br />
Other species:<br />
AMMONIUM SULFATE (EESO4) -- Default: 3.0 ! EESO4 = 3.0 !<br />
AMMONIUM NITRATE (EENO3) -- Default: 3.0 ! EENO3 = 3.0 !<br />
ORGANIC CARBON (EEOC) -- Default: 4.0 ! EEOC = 4.0 !<br />
SOIL (EESOIL)-- Default: 1.0 ! EESOIL = 1.0 !<br />
ELEMENTAL CARBON (EEEC) -- Default: 10. ! EEEC = 10.0 !<br />
Background Extinction Computation<br />
---------------------------------<br />
Method used for background light extinction<br />
(MVISBK) -- Default: 2 ! MVISBK = 6 !<br />
Page 5
SO01_CC_vis.INP<br />
1 = Supply single light extinction and hygroscopic fraction<br />
- IWAQM (1993) RH adjustment applied to hygroscopic background<br />
and modeled sulfate and nitrate<br />
2 = Compute extinction from speciated PM measurements (A)<br />
- Hourly RH adjustment applied to observed and modeled sulfate<br />
and nitrate<br />
- RH factor is capped at RHMAX<br />
3 = Compute extinction from speciated PM measurements (B)<br />
- Hourly RH adjustment applied to observed and modeled sulfate<br />
and nitrate<br />
- Receptor-hour excluded if RH>RHMAX<br />
- Receptor-day excluded if fewer than 6 valid receptor-hours<br />
4 = Read hourly transmissometer background extinction measurements<br />
- Hourly RH adjustment applied to modeled sulfate and nitrate<br />
- Hour excluded if measurement invalid (missing, interference,<br />
or large RH)<br />
- Receptor-hour excluded if RH>RHMAX<br />
- Receptor-day excluded if fewer than 6 valid receptor-hours<br />
5 = Read hourly nephelometer background extinction measurements<br />
- Rayleigh extinction value (BEXTRAY) added to measurement<br />
- Hourly RH adjustment applied to modeled sulfate and nitrate<br />
- Hour excluded if measurement invalid (missing, interference,<br />
or large RH)<br />
- Receptor-hour excluded if RH>RHMAX<br />
- Receptor-day excluded if fewer than 6 valid receptor-hours<br />
6 = Compute extinction from speciated PM measurements<br />
- FLAG RH adjustment factor applied to observed and<br />
modeled sulfate and nitrate<br />
Additional inputs used for MVISBK = 1:<br />
--------------------------------------<br />
Background light extinction (1/Mm)<br />
(BEXTBK) -- No default ! BEXTBK = 12.0 !<br />
Percentage of particles affected by relative humidity<br />
(RHFRAC) -- No default ! RHFRAC = 10.0 !<br />
Additional inputs used for MVISBK = 6:<br />
--------------------------------------<br />
Extinction coefficients for hygroscopic species (modeled and<br />
background) are computed using a monthly RH adjustment factor<br />
in place of an hourly RH factor (VISB.DAT file is NOT needed).<br />
Enter the 12 monthly factors here (RHFAC). Month 1 is January.<br />
(RHFAC) -- No default ! RHFAC = 3.4,3.1,2.9,3.0,3.6,3.6,3.4,3.4,3.6,3.5,3.4,3.5!<br />
Additional inputs used for MVISBK = 2,3,6:<br />
----------------------------------------<br />
Page 6
SO01_CC_vis.INP<br />
Background extinction coefficients are computed from monthly<br />
CONCENTRATIONS of ammonium sulfate (BKSO4), ammonium nitrate (BKNO3),<br />
coarse particulates (BKPMC), organic carbon (BKOC), soil (BKSOIL), and<br />
elemental carbon (BKEC). Month 1 is January.<br />
(ug/m**3)<br />
(BKSO4) -- No default ! BKSO4 = 0.12, 0.12, 0.12, 0.12,<br />
0.12, 0.12, 0.12, 0.12,<br />
0.12, 0.12, 0.12, 0.12!<br />
(BKNO3) -- No default ! BKNO3 = 0.10, 0.10, 0.10, 0.10,<br />
0.10, 0.10, 0.10, 0.10,<br />
0.10, 0.10, 0.10, 0.10 !<br />
(BKPMC) -- No default ! BKPMC = 3.0, 3.0, 3.0, 3.0,<br />
3.0, 3.0, 3.0, 3.0,<br />
3.0, 3.0, 3.0, 3.0 !<br />
(BKOC) -- No default ! BKOC = 0.47, 0.47, 0.47, 0.47,<br />
0.47, 0.47, 0.47, 0.47,<br />
0.47, 0.47, 0.47, 0.47!<br />
(BKSOIL) -- No default ! BKSOIL= 0.50, 0.50, 0.50, 0.50,<br />
0.50, 0.50, 0.50, 0.50,<br />
0.50, 0.50, 0.50, 0.50 !<br />
(BKEC) -- No default ! BKEC = 0.02, 0.02, 0.02, 0.02,<br />
0.02, 0.02, 0.02, 0.02,<br />
0.02, 0.02, 0.02, 0.02 !<br />
Additional inputs used for MVISBK = 2,3,5,6:<br />
------------------------------------------<br />
Extinction due to Rayleigh scattering is added (1/Mm)<br />
(BEXTRAY) -- Default: 10.0 ! BEXTRAY = 10.0!<br />
!END!<br />
-------------------------------------------------------------------------------<br />
INPUT GROUP: 3 -- Output options<br />
--------------<br />
Documentation<br />
-------------<br />
Documentation records contained in the header of the<br />
CALPUFF output file may be written to the list file.<br />
Print documentation image?<br />
(LDOC) -- Default: F ! LDOC = F !<br />
Output Units<br />
------------<br />
Units for All Output (IPRTU) -- Default: 1 ! IPRTU = 3 !<br />
for for<br />
Page 7
Concentration Deposition<br />
1 = g/m**3 g/m**2/s<br />
2 = mg/m**3 mg/m**2/s<br />
3 = ug/m**3 ug/m**2/s<br />
4 = ng/m**3 ng/m**2/s<br />
5 = Odour Units<br />
SO01_CC_vis.INP<br />
Visibility: extinction expressed in 1/Mega-meters (IPRTU is ignored)<br />
Averaging time(s) reported<br />
--------------------------<br />
1-hr averages (L1HR) -- Default: T ! L1HR = F !<br />
3-hr averages (L3HR) -- Default: T ! L3HR = F !<br />
24-hr averages (L24HR) -- Default: T ! L24HR = T !<br />
Run-length averages (LRUNL) -- Default: T ! LRUNL = F !<br />
User-specified averaging time in hours - results for<br />
an averaging time of NAVG hours are reported for<br />
NAVG greater than 0:<br />
(NAVG) -- Default: 0 ! NAVG = 0 !<br />
Types of tabulations reported<br />
------------------------------<br />
1) Visibility: daily visibility tabulations are always reported<br />
for the selected receptors when ASPEC = VISIB.<br />
In addition, any of the other tabulations listed<br />
below may be chosen to characterize the light<br />
extinction coefficients.<br />
[List file or Plot/Analysis File]<br />
2) Top 50 table for each averaging time selected<br />
[List file only]<br />
(LT50) -- Default: T ! LT50 = T !<br />
3) Top 'N' table for each averaging time selected<br />
[List file or Plot file]<br />
(LTOPN) -- Default: F ! LTOPN = F !<br />
-- Number of 'Top-N' values at each receptor<br />
selected (NTOP must be
SO01_CC_vis.INP<br />
(NTOP) -- Default: 4 ! NTOP = 4 !<br />
-- Specific ranks of 'Top-N' values reported<br />
(NTOP values must be entered)<br />
(ITOP(4) array) -- Default: ! ITOP = 1, 2, 3, 4 !<br />
1,2,3,4<br />
4) Threshold exceedance counts for each receptor and each averaging<br />
time selected<br />
[List file or Plot file]<br />
(LEXCD) -- Default: F ! LEXCD = F !<br />
-- Identify the threshold for each averaging time by assigning a<br />
non-negative value (output units).<br />
-- Default: -1.0<br />
Threshold for 1-hr averages (THRESH1) ! THRESH1 = -1.0 !<br />
Threshold for 3-hr averages (THRESH3) ! THRESH3 = -1.0 !<br />
Threshold for 24-hr averages (THRESH24) ! THRESH24 = -1.0 !<br />
Threshold for NAVG-hr averages (THRESHN) ! THRESHN = -1.0 !<br />
-- Counts for the shortest averaging period selected can be<br />
tallied daily, and receptors that experience more than NCOUNT<br />
counts over any NDAY period will be reported. This type of<br />
exceedance violation output is triggered only if NDAY > 0.<br />
Accumulation period(Days)<br />
(NDAY) -- Default: 0 ! NDAY = 0 !<br />
Number of exceedances allowed<br />
(NCOUNT) -- Default: 1 ! NCOUNT = 1 !<br />
5) Selected day table(s)<br />
Echo Option -- Many records are written each averaging period<br />
selected and output is grouped by day<br />
[List file or Plot file]<br />
(LECHO) -- Default: F ! LECHO = F !<br />
Timeseries Option -- Averages at all selected receptors for<br />
each selected averaging period are written to timeseries files.<br />
Each file contains one averaging period, and all receptors are<br />
written to a single record each averaging time.<br />
[TSttUUUU.DAT files]<br />
(LTIME) -- Default: F ! LTIME = F !<br />
Page 9
SO01_CC_vis.INP<br />
-- Days selected for output<br />
(IECHO(366)) -- Default: 366*0<br />
! IECHO = 366*0 !<br />
(366 values must be entered)<br />
Plot output options<br />
-------------------<br />
Plot files can be created for the Top-N, Exceedance, and Echo<br />
tables selected above. Two formats for these files are available,<br />
DATA and GRID. In the DATA format, results at all receptors are<br />
listed along with the receptor location [x,y,val1,val2,...].<br />
In the GRID format, results at only gridded receptors are written,<br />
using a compact representation. The gridded values are written in<br />
rows (x varies), starting with the most southern row of the grid.<br />
The GRID format is given the .GRD extension, and includes headers<br />
compatible with the SURFER(R) plotting software.<br />
A plotting and analysis file can also be created for the daily<br />
peak visibility summary output, in DATA format only.<br />
Generate Plot file output in addition to writing tables<br />
to List file?<br />
(LPLT) -- Default: F ! LPLT = F !<br />
Use GRID format rather than DATA format,<br />
when available?<br />
(LGRD) -- Default: F ! LGRD = F !<br />
Additional Debug Output<br />
-----------------------<br />
!END!<br />
Output selected information to List file<br />
for debugging?<br />
(LDEBUG) -- Default: F ! LDEBUG = F !<br />
Page 10
APPENDIX E – MUSKOGEE STATION EMISSION SUMMARY<br />
OG&E Trinity Consultants<br />
BART Modeling Report 083701.0004
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
BART Emissions Modeling Inputs<br />
Source Emission Summary<br />
<strong>Muskogee</strong> Unit 4<br />
<strong>Muskogee</strong> Unit 4 <strong>Muskogee</strong> Unit 5<br />
Baseline Heat Input mmBtu/hr 5480 5480<br />
Baseline NOx Emission Rate lb/mmBtu 0.495 2710 0.522 2863<br />
NOx Rate with LNB/OFA lb/mmBtu 0.15 0.15<br />
NOx Rate with SCR lb/mmBtu 0.07 0.07<br />
Baseline SO2 Emission Rate lb/mmBtu 0.80 4384 0.85 4657<br />
SO2 Rate with DFGD lb/mmBtu 0.10 0.10<br />
SO2 Rate with WFGD lb/mmBtu 0.08 0.08<br />
Baseline PM10 Emission Rate lb/mmBtu 0.0184 100.9 0.0244 133.84<br />
PM10 Rate with DFGD/PBH lb/mmBtu 0.012 0.012<br />
Baseline H2SO4 Conversion Rate % 1% 1%<br />
H2SO4 Conversion with SCR % 2% 2%<br />
Baseline H2SO4 Control Efficiency % 0% 0%<br />
H2SO4 Control with DFGD % 90% 90%<br />
H2SO4 Control with WFGD % 40% 40%<br />
Control Systems NOx SO2<br />
H2SO4 (in model as SO4 from SO2)<br />
PM10<br />
NOx SO2 lb/mmBtu lb/hr lb/mmBtu lb/hr conversion control eff lb/hr lb/mmBtu lb/hr<br />
Case 1 Baseline Case base base 0.495 2710 0.80 4384 1% 0% 67.1 0.0184 100.8<br />
Case 2 NOx Combustion Controls LNB/OFA base 0.15 822 0.80 4384 1% 0% 67.1 0.0184 100.8<br />
Case 3 NOx Combustion Controls plus SCR SCR base 0.070 384 0.80 4384 2% 0% 134.3 0.0184 100.8<br />
Case 4 SO2 DFGD Case base DFGD 0.495 2710 0.10 548 1% 90% 6.7 0.012 65.8<br />
Case 5 SO2 WFGD Case base WFGD 0.495 2710 0.08 438 1% 40% 40.3 0.0184 100.8<br />
Case 6 NOx / SO2 Control Case LNB/OFA DFGD 0.15 822 0.10 548 1% 90% 6.7 0.012 65.8<br />
<strong>Muskogee</strong> Unit 4 PM Speciation<br />
SO4 (from PM) PM (coarse) 1<br />
PM (fine) 1<br />
EC SOA<br />
lb/hr lb/hr lb/hr lb/hr lb/hr<br />
Case 1 Baseline Case 62.0 11.1 11.7 0.5 15.5<br />
Case 2 NOx Combustion Controls 62.0 11.1 11.7 0.5 15.5<br />
Case 3 NOx Combustion Controls plus SCR 62.0 11.1 11.7 0.5 15.5<br />
Case 4 SO2 DFGD Case 40.5 7.2 7.7 0.3 10.1<br />
Case 5 SO2 WFGD Case 62.0 11.1 11.7 0.5 15.5<br />
Case 6 NOx / SO2 Control Case 40.5 7.2 7.7 0.3 10.1<br />
Basis / Notes<br />
BART Alternative Report, page 1-1<br />
BART Alternative Report, page 4-1<br />
DBTF Boiler firing subbituminous coal<br />
Based on design target of 0.05 lb/mmBtu plus operating margin.<br />
BART Alternative Report, page 4-1<br />
Design removal efficiency of 92% plus operating margin.<br />
Design removal efficiency of 95% plus operating margin.<br />
BART Alternative Report, page 4-1<br />
DFGD requires polishing baghouse which will reduce PM emissions.<br />
Assumed SO2 to SO3 conversion in the boiler.<br />
Assumed SO2 to SO3 conversion in the boiler and SCR.<br />
Assumed no inherent SO3/H2SO4 control with the baseline technologies.<br />
Assumed 90% H2SO4 control with DFGD/PBH<br />
Assumed 40% H2SO4 controlw with WFGD
<strong>Muskogee</strong> Unit 5<br />
Control Systems NOx SO2<br />
H2SO4 (in model as SO4 from SO2)<br />
PM10<br />
NOx SO2 lb/mmBtu lb/hr lb/mmBtu lb/hr conversion control eff lb/hr lb/mmBtu lb/hr<br />
Case 1 Baseline Case base base 0.522 2863 0.85 4657 1% 0% 71.3 0.024 133.7<br />
Case 2 NOx Combustion Controls LNB/OFA base 0.150 822 0.85 4657 1% 0% 71.3 0.024 133.7<br />
Case 3 NOx Combustion Controls plus SCR SCR base 0.070 384 0.85 4657 2% 0% 142.6 0.024 133.7<br />
Case 4 SO2 DFGD Case base DFGD 0.522 2863 0.10 548 1% 90% 7.1 0.012 65.8<br />
Case 5 SO2 WFGD Case base WFGD 0.522 2863 0.08 438 1% 40% 42.8 0.024 133.7<br />
Case 6 NOx / SO2 Control Case LNB/OFA DFGD 0.150 822 0.10 548 1% 90% 7.1 0.012 65.8<br />
<strong>Muskogee</strong> Unit 5 PM Speciation<br />
SO4 (from PM) PM (coarse) 1<br />
PM (fine) 1<br />
EC SOA<br />
lb/hr lb/hr lb/hr lb/hr lb/hr<br />
Case 1 Baseline Case 82.3 14.7 15.6 0.6 20.6<br />
Case 2 NOx Combustion Controls 82.3 14.7 15.6 0.6 20.6<br />
Case 3 NOx Combustion Controls plus SCR 82.3 14.7 15.6 0.6 20.6<br />
Case 4 SO2 DFGD Case 40.5 7.2 7.7 0.3 10.1<br />
Case 5 SO2 WFGD Case 82.3 14.7 15.6 0.6 20.6<br />
Case 6 NOx / SO2 Control Case 40.5 7.2 7.7 0.3 10.1<br />
1 Condensible/filterable PM speciation were based on the following profiles:<br />
For Coal, National Park Service guidance for PC Wet Bottom ESP. http://www2.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfm<br />
Coarse 10.99%<br />
Fine Soil 11.64% Fine soil included in model as PM (fine)<br />
Fine EC 0.45%<br />
CPM IOR 61.54% Inorganic condensible PM considered sulfates per NPS guidance<br />
CPM OR 15.38% Organic condensible PM considered secondary organic aerosols per NPS
<strong>Muskogee</strong> <strong>Generating</strong> <strong>Station</strong><br />
BART Emissions Modeling Inputs<br />
Stack Parameters<br />
Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5<br />
NOx Controls base base LNB/OFA LNB/OFA SCR SCR base base base base LNB/OFA LNB/OFA<br />
SO2 Controls<br />
Emissions (lb/hr)<br />
base base base base base base DFGD DFGD WFGD WFGD DFGD DFGD<br />
NOx 2710 2863 822 822 384 384 2710 2863 2710 2863 822 822<br />
SO2 4384 4657 4384 4657 4384 4657 548 548 438 438 548 548<br />
PM10 100.8 133.7 100.8 133.7 100.8 133.7 65.8 65.8 100.8 133.7 65.8 65.8<br />
H2SO4<br />
Stack Parameters<br />
English<br />
67.1 71.3 67.1 71.3 134.3 142.6 6.7 7.1 40.3 42.8 6.7 7.1<br />
Flow (acfm) 2,260,202 2,260,202 2,260,202 2,260,202 2,376,222 2,376,222 2,028,009 2,028,009 1,878,400 1,878,400 2,045,112 2,045,112<br />
Temperature ( o Case 1<br />
Case 2<br />
Case 3<br />
Case 4<br />
Case 5<br />
Case 6<br />
(baseline)<br />
(NOx - LNB/OFA) (LNB/OFA+SCR) (SO2 - DFGD)<br />
(SO2 -WFGD) (LNB/OFA + DFGD)<br />
F) 316 316 316 316 323 323 187 187 138 138 192 192<br />
Stack Height (feet) 350 350 350 350 350 350 350 350 350 350 350 350<br />
Stack Diameter (feet) 24 24 24 24 24 24 24 24 24 24 24 24<br />
Exit Velocity (ft/sec)<br />
Metric<br />
83.3 83.3 83.3 83.3 87.5 87.5 74.7 74.7 69.2 69.2 75.3 75.3<br />
Temperature (K) 430.78 430.78 430.78 430.78 434.67 434.67 359.11 359.11 331.89 331.89 361.89 361.89<br />
Stack Height (m) 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71<br />
Stack Diameter (m) 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32<br />
Exit Velocity (m/s) 25.40 25.40 25.40 25.40 26.68 26.68 22.77 22.77 21.10 21.10 22.96 22.96