CASE NO. 8843
INTRODUCTION
In the Environmental Review Document (ERD) accompanying the Application
for a Certificate of Public Convenience and Necessity submitted on May 15, 2000, Free
State provided a range of air quality information covering the three models of combustion
turbines then under consideration for the Kelson Ridge Facility. In a letter filed with the
Commission on December 20, 2000, Free State informed the parties that it had selected
the Seimens/Westinghouse (S/W) 501 F combustion turbine. At the January 9, 2001
hearing in this proceeding, Free State committed to provide updated air quality information reflecting the selection of the S/W turbine.
In this package, Free State presents a series of documents that summarize revised
air quality analyses based on the latest emissions and performance data received from
S/W for the 501 F combustion turbine. Collectively, Free State will hereinafter refer to
these documents as the Update to Air Quality Information for the Seimens/Westinghouse
Combustion Turbine. Specifically, the Update consists of the following documents:

Updated Facility Performance and Emissions: Provides emissions and performance data specific to the S/W CT that updates or replaces the range of information presented in the ERD for the three turbines that were under consideration;

Updated Source Impact Analyses: Provides a revised comparison of the expected air quality impacts from the S/W CT with the significant impact and de
minimis monitoring levels required as part of the Prevention of Significant
Deterioration review process;

Updated Best Available Control Technology Analysis for Carbon Monoxide: Provides an updated evaluation of the appropriate level of control for carbon monoxide based on the specific characteristics of the S/W unit;

Update Regarding Facility Ammonia Usage: Contains an updated estimate
of annual ammonia use necessary to achieve a NOx emission limit of 2.5
ppmvd;

Calculation of Required NOx Offsets Based on Emission Rate of 2.5
ppmvd: Presents Free State’s determination of the required amount of NOx
offsets using the most current information available from S/W and assuming
that a NOx emission limit of 2.5 ppmvd is imposed;

Calculation of Required VOC Offsets: Presents Free State’s determination
of the required amount of VOC offsets using the most current information
available from S/W.
UPDATED FACILITY PERFORMANCE AND EMISSIONS
In the Environmental Review Document (ERD) accompanying the Certificate of Public
Convenience and Necessity (CPCN) application submitted in May 2000, Free State indicated that three gas turbine vendors were being considered: General Electric, Siemens/Westinghouse (S/W), and ABB. Therefore, data were submitted for all three vendors.
In a December 20, 2000 letter, Free State advised the Public Service Commission that
S/W has been selected as the gas turbine supplier for the Kelson Ridge Project. S/W has
proposed to provide the gas turbines, heat recovery steam generators (HRSGs) (with duct
burners), and selective catalytic reduction (SCR) systems for nitrogen oxides (NOx) control and oxidation catalyst systems for carbon monoxide (CO) control as a power island.
This update provides an explanation of the performance information originally presented
and supplies the best, most current information on performance and emissions for the selected S/W-based Facility.
EXPLANATION OF PERFORMANCE INFORMATION
The output and performance of gas turbines varies among vendors. An additional variable that is considered in a combined-cycle facility is the level of additional heat input
provided by the duct burners located in the HRSGs. Duct burner heat input is a function
of the desired additional electrical output from the steam turbine compared to the base
load or unfired output. It is also a function of the ambient temperature conditions as well
as the type of gas turbine selected. In several places in the ERD (and specifically on
page 2-1, Volume 2, Appendix A), a range of gas turbine power outputs and duct burner
heat inputs was provided. In light of its selection of S/W, Free State can now refine its
power output and duct burner heat input calculations.
Regarding power output, at plant site elevation, and at 59 degrees Fahrenheit (°F) and
60-percent relative humidity, the expected gross output of the S/W gas turbines is approximately 184 megawatts (MW) each. There are two gas turbines per combined-cycle unit
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1
or phase of the Project. Without duct firing, the steam turbine output is estimated to add
an additional 196 MW, for a total gross combined-cycle output of approximately
564 MW. Plant auxiliary and parasitic loads reduce this gross output to a net power output of approximately 550 MW. At high ambient temperatures, the gas turbine output declines. However, through the use of duct firing in the HRSG, steam turbine output can be
increased to compensate for this loss.
Turning to duct burner heat input, Free State is still working with S/W to define the steam
cycle and duct burner input. Free State can confirm, however, that the duct burner input
levels for the S/W configuration will not exceed those defined in the original application.
Annual heat input to the duct burners will not exceed 9,210,600 million British thermal
units (MMBtu) per year, with a maximum duct burner input of 357.0 MMBtu per hour
per gas turbine/HRSG. (Due to changes in the latest S/W data [see the following subsection], these duct burner specifications have decreased by a small amount relative to the
original submittal.)
UPDATED PERFORMANCE AND EMISSIONS DATA
In this Update, Free State is providing revised emission calculations based on the recently
revised expected performance and emissions data furnished by S/W on January 19, 2001.
(The S/W data sheets are attached.) The original S/W values presented in the ERD for
the duct-fired cases have been revised.
In this Update, these adjustments are presented in the form of revised Appendices B and
C (which appear in Volume 2 of the ERD). (See the attached updated Appendix B
spreadsheets and the corresponding updates to all Appendix C spreadsheets and tables).
Also attached are updates to Tables 4-26, “Summary of BACT Control Technologies,”
4-27, “Summary of Proposed BACT Emission Limits,” and 4-37, “Summary of Proposed
LAER Emission Limits (Volume 2, pages 4-42, 4-43, and 4-73, respectively). These tables were originally presented in Volume 2, Chapter 4 of the ERD. All of these emissions
updates incorporate NOx control to 2.5 ppmvd and CO control due to the oxidation catalyst control system, consistent with PPRP’s request.
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UPDATED SOURCE IMPACT ANALYSES
As part of the PSD review process, Free State conducted a source impact analysis to determine if ground-level concentrations of pollutants exceeding significant emission rates
will exceed either the significant impact or the de minimis monitoring levels. With the
selection of the Seimens/Westinghouse (S/W) 501 F combustion turbine(CT), Free State
has conducted additional source impact analyses to incorporate information received
from S/W. The updated source impact analysis contains a number of revised tables
whose numbering corresponds to that used in the Environmental Review Document
(ERD).
Four significant changes were made in the updated source impact analyses that follow.
First, the emission rate for NOx was changed to 2.5 ppmvd due to the limit expected to be
established for the CT/HRSG units. Second, the emission rates for CO and PM10 were
revised to reflect recent engine performance data from S/W. The revised emission rates
are presented in updated Table 2-2, which is attached. Because of the revised annual
emission rates for the combustion turbines, the maximum potential facility-wide annual
emission rates have also been revised and are presented in updated Table 2-12.
Third, based on the optimal performance characteristics of the S/W CTs, Free State has
increased the minimum operating mode for the CTs to 70% of the base load, compared to
the 60% minimum operating load contemplated in the ERD. In light of this change, Free
State has defined and evaluated nine operating cases, instead of the twelve operating cases presented in the ERD. The revised operating scenarios are shown in Tables 2-5 and 72. Finally, the stack height was increased to 175-feet. Table 2-8 shows the revised stack
parameters.
Air dispersion modeling analyses were revised for the new stack height, operating scenarios and emission rates. As described below, the revised air dispersion modeling results
are shown in Tables 8-15 through 8-19 and Tables 8-15P through 8-19P. Updated Ta-
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ble 6-1 is a summary table that compares the updated maximum impacts from the S/W
CTs with the de minimis levels for monitoring exemptions.
Screening analysis is performed for the purpose of determining the operating scenario
causing the highest impact. In light of the revised operating scenarios described above,
Free State used the SCREEN3 model to analyze nine operating scenarios. The results are
presented in updated Tables 8-2, 8-5, and 8-8. In the refined modeling analyses, the air
quality impacts from the worst-case operating scenarios identified by the SCREEN3
model were analyzed using the ISCST3 model. As described in Section 7.4.3 of Vol. 2 of
the ERD, these operating scenarios were then reanalyzed using the ISC-PRIME model in
order to predict the impacts at receptors that fall in a building cavity zone for which
ISCST3 may not have calculated the impacts accurately. The revised ISCST3 model results have been presented in updated Tables 8-15 through 8-19, and the ISC-PRIME
model results have been presented in updated Tables 8-15P through 8-19P.
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UPDATED BEST AVAILABLE CONTROL TECHNOLOGY
ANAYSIS FOR CARBON MONOXIDE
The proposed 1,650-megawatt (MW) Free State Electric, LLC, Kelson Ridge Facility is
subject to best available control technology (BACT) review for carbon monoxide (CO)
(as well as other air pollutants). The control technology analyses were presented in the
May 2000 Application for Certificate of Public Convenience and Necessity (CPCN), Environmental Review Document (ERD), Volume 2, Chapter 4.0. The BACT analysis for
CO was provided in Section 4.1.5, which can be found beginning at page 4-17. Three different combustion turbine (CT) units, General Electric (GE) PG7241(FA) (7FA), Siemens/Westinghouse (S/W) 501F, and ABB GT-24, were considered in the original analyses, and the control technology analyses addressed all three units. These original BACT
analyses were all based on best estimates of CT performance and emissions.
Since the original submittal, Free State has selected the S/W 501F CTs, and updates of
expected CT performance and emissions have been provided by S/W. Free State has also
made the decision to limit normal CT operations to loads between 70 and 100 percent.
The combination of the updated emissions, which are at a lower CO exhaust concentration than previously estimated, and the modification in CT load range has reduced annual
potential CO emissions relative to the original submittal. These events warranted an update of the control technology analysis for CO. This update for the selected S/W CTs is
provided herein.
The expected CO emission rate provided by S/W is 10 parts per million by volume, dry
(ppmvd), at 15-percent oxygen over the full range of normal operations (full load down
to 70-percent CT load). This resulted in lower annual CO emissions, which, in turn, affected the economic analyses for CO BACT. The attached narrative discussion and economic analysis tables update or replace the ones submitted in the ERD. (The only table
that is not changed as a result of the revised CO BACT analysis is Table 4-9 at page 4-22
of Vol. II of the ERD.)
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ENERGY AND ENVIRONMENTAL IMPACTS
There continue to be no significant adverse energy or environmental impacts associated
with the use of good combustor designs and operating practices to minimize CO emissions.
However, the energy penalty that was calculated based on the lost power generation due
to pressure drop across the catalyst bed has been revised. The following table shows pressure drop across the catalyst bed at varying control efficiencies. The energy penalty due
to reduced plant output power and lost heat rate is 0.2 percent per inch of pressure drop.
The table also shows the corresponding annual energy penalty calculated in units of kilowatt (kW) for output capacity penalty and million British thermal units (MMBtu) for
heat rate penalty assuming base load operation and a full load plant capacity factor.
Catalyst Bed
Control Efficiency
(%)
Pressure Drop
Across Bed
(inch of water)
50
60
70
80
90
0.50
0.50
0.603
0.90
1.296
Annual Energy Penalty
Output Capacity
Penalty
Heat Rate Penalty
(kW)
(MMBtu)
1,691.1
1,691.1
2,039.5
3,044.0
4,383.4
98,854.9
98,854.9
119,219.0
177,938.8
256,231.8
The plant-wide energy penalty ranges from the equivalent use of 31.45 million cubic feet
(ft3) of natural gas (50-percent control) to 81.5 million ft3 (90-percent control), based on a
natural gas value of 1,050 British thermal units per cubic foot (Btu/ft3). The lost power
generation energy penalties, based on an output capacity penalty of $100.00 per kilowattyear and a fuel heat rate penalty of $3.20 per MMBtu, range from $485,447 at 50-percent
control efficiency to $873,805 at 80-percent control and $1,258,279 at 90-percent control.
ECONOMIC IMPACTS
The economic evaluation performed in the original application for the oxidation catalyst
system has been revised due to updated cost figures involved with the revised energy
penalty and revised annual CO emission reduction. The attached Tables 1 and 2 update
2
Tables 4-11 and 4-14, respectively, of Volume 2 of the CPCN application package (see
pages 4-24 and 4-27), and summarize capital cost and specific annual operating costs for
the oxidation catalyst control system for the S/W 501F CT/HRSG units, based on 80percent control of potential CO emissions. The following table summarizes total annual
costs at different control efficiencies:
Catalyst Bed CO Control Efficiency
(%)
Total Annual Cost
($)
50
60
70
80
90
2,705,795
2,705,795
2,970,964
3,589,655
4,482,336
Potential annual CO emissions from the uncontrolled Facility (i.e., six S/W 501F
CT/HRSG units) are 1,461.1 tons per year (tpy). The controlled annual CO emission rate,
based on 80-percent control efficiency is 292.2 tpy. Base case and controlled CO emission rates are summarized in revised Table 3, which updates Table 4-17 (page 4-30). Total annual CO emission decreases due to the oxidation catalyst control system range from
731 tpy at 50-percent control to 1,315 tpy at 90-percent control, as shown in the table,
below.
Catalyst Bed CO Control
Efficiency
(%)
CO Emissions Decrease
(tpy)
Incremental Cost
Effectiveness
($/ton)
50
60
70
80
90
731
877
1,023
1,169
1,315
—
0
1,815
4,235
6,110
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Table 1. Capital Costs for Oxidation Catalyst System, Six S/W 501F CT/HRSG Units
Item
Dollars
OAQPS Factor
Purchased equipment
Oxidation catalyst system
Instrumentation
Sales tax
Freight
Total Purchased Equipment
4,020,000
402,000
201,000
201,000
4,824,000
A
0.10 × A
0.05 × A
0.05 × A
B
Installation
Foundations and supports
Handling and erection
Electrical
Piping
Insulation for ductwork
Painting
385,920
675,360
192,960
96,480
48,240
48,240
0.08 × B
0.14 × B
0.04 × B
0.02 × B
0.01 × B
0.01 × B
Direct Costs
Total Installation Cost
1,447,200
Total Direct Costs
6,271,200
TDC
Indirect Costs
Engineering
Construction and field expenses
Contractor fees
Startup
Performance test
Contingency
482,400
241,200
482,400
96,480
48,240
144,720
0.10 × B
0.05 × B
0.10 × B
0.02 × B
0.01 × B
0.03 × B
Total Indirect Costs
1,495,440
TIC
TOTAL CAPITAL INVESTMENT
7,766,640
TCI
Source: ECT, 2001.
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Table 2. Annual Operating Costs for Oxidation Catalyst System, Six S/W 501F
CT/HRSG Units
Item
Dollars
Total Labor and Material Costs
37,641
OAQPS Factor
C
Direct Costs
Catalyst costs
Replacement (materials and labor)
Credit for used catalyst
Subtotal Catalyst Costs
Annualized Catalyst Costs
4,294,800
520,200
3,774,600
1,653,188
Energy Penalties
Turbine backpressure
15%
873,805
2,564,633
TDC
Overhead
Administrative charges
Property taxes
Insurance
Capital recovery
Total Indirect Costs
22,584
155,333
77,666
77,666
691,771
1,025,021
0.60 × C
0.02 × TCI
0.01 × TCI
0.01 × TCI
TOTAL ANNUAL COST
3,589,655
Total Direct Costs
Indirect Costs
Source: ECT, 2001.
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Table 3. Economic Analysis for Oxidation Catalyst—Kelson Ridge CT CO BACT Analysis Summary; S/W 501F
6
The updated cost effectiveness of oxidation catalyst for CO emissions was determined to
be $3,071 per ton of CO removed, based on 80-percent control. Results of the oxidation
catalyst economic analysis are summarized in Table 4, which updates Table 4-20
(page 4-34). Since the incremental cost effectiveness for going from 80-percent control
efficiency to 90-percent control is in excess of $5,000 per ton of CO removed, 90-percent
control is considered to be economically not justified. Therefore, CO control using oxidation catalyst systems with a control efficiency of 80 percent is considered appropriate.
PROPOSED BACT EMISSION LIMITATIONS
The BACT emission limitations originally proposed in Table 4-25 of the ERD
(page 4-40) have been revised in attached Table 5 to show the revised proposed CO
BACT emission limits for the selected S/W CTs.
Use of state-of-the-art combustor design and good operating practices to minimize incomplete combustion, plus the installation of oxidation catalyst systems are proposed as
BACT for CO. CO emissions from the CTs at base load, without duct burner firing, will
not exceed 2.0 ppmvd at 15-percent oxygen. With duct burner firing, CO emissions from
the CT/HRSG units at base load will not exceed 3.0 ppmvd at 15-percent oxygen.
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Table 4. Summary of CO BACT Analysis, S/W 501F CTs
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Table 5. Proposed CO BACT Emission Limits
Emission Source
Proposed CO BACT Emission Limits*
ppmvd at 15-percent
lb/hr
Oxygen
[lb/MMBtu]
S/W 501F CTs (Per CT/HRSG Unit)
A. With duct burner-firing
B. Without duct burner-firing
3.0
2.0
16.2
9.0
Duct Burners (Per Duct Burner)
N/A
[0.02]
Auxiliary Boilers
N/A
[0.05]
*Maximum rates for each operating scenario (excluding startup and shutdown).
Sources: S/W, 2001.
PB Power, 2001.
ECT, 2001.
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UPDATE REGARDING FACILITY AMMONIA USAGE
The purpose of this update is to provide an estimate of the amount of ammonia that
would be required if a nitrogen oxides (NOx) emissions limit of 2.5 ppmvd at 15-percent
oxygen is imposed on the Facility.
To achieve the 2.5 ppmvd NOx limit, each CT/HRSG unit will employ a NOx removal
system utilizing a 28-percent solution of aqueous ammonia. Because NOx is produced in
both the combustion turbine (CT) combustors and the duct burners, the amount of ammonia required varies with ambient conditions and the plant load level as well as the level of
duct firing. Expected ammonia usage was analyzed for each operating case and the results are itemized in the Updated Facility Performance and Emissions section of this
package. The operating cases are described in updated Table 7.2 in the Updated Source
Impact Analyses section of the package. At base load with an ambient temperature of
59°F, each NOx removal system is expected to consume approximately 288 pounds per
hour (lb/hr) of 28-percent aqueous ammonia. At the maximum fired condition, which includes 357.0-million-British-thermal-units-per-hour heat input per duct burner, the aqueous ammonia consumption will increase to approximately 378 lb/hr.
On an annual basis with all six CTs operating (including approximately 4,300 hours per
year of duct firing), the total annual aqueous ammonia usage will be approximately
2,200,000 gallons per year.
The ammonia will be stored in aboveground tanks. One storage tank will be provided for
each 550-megawatt power block (two CT/heat recovery steam generator units). Subject to
final design, the tanks are each anticipated to have a capacity of approximately
22,000 gallons, which will provide approximately 7 days of storage for each NOx removal system. The maximum total onsite storage will be approximately 66,000 gallons. The
aqueous ammonia will be delivered by truck. It is anticipated that approximately eight
tanker trucks of ammonia will be delivered per week.
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CALCULATION OF REQUIRED NOx OFFSETS
BASED ON EMISSION RATE OF 2.5 PPMVD
The Maryland Power Plant Research Program (PPRP) has requested that Free State Electric, LLC, calculate the amount of offsets for nitrogen oxides (NOx) that would be required for the selected Siemens/Westinghouse (S/W) 501F combustion turbines (CTs)
with emission controls installed to achieve an exhaust concentration of 2.5 parts per million by volume dry (ppmvd) at 15-percent oxygen (O2). These calculations are presented
in the following subsections.
CT AND DUCT BURNER HOURLY NOX EMISSION RATES
To determine the hourly NOx emission rates, NOx emissions in pounds per hour (lb/hr)
were calculated based on CT NOx emissions plus duct burner NOx emissions (if duct
burner is fired in that case) for each ambient temperature and CT operating load case.
These operating scenarios have been presented in the updated Table 7-2 in the Updated
Source Impact Analyses section of this package. The NOx emissions for the CTs, in both
ppmvd at 15-percent oxygen and in pounds per hour, were based on data provided by
S/W. The duct burner NOx emissions were based on a vendor-supplied rate of 0.1 pound
per million British thermal units (lb/106 Btu). A selective catalytic reduction (SCR) system control efficiency of 90 percent was used. Emissions in pounds per hour were converted to grams per second (g/s) by multiplying by a conversion factor of 0.126.
Example: Case 6; 59°F ambient temperature, 100-percent load, duct burner firing. The
emission rate for Case 6 is the sum of the Case 4 emissions (100-percent load
at 59°F) and the duct burner emissions at 100-percent load and 59°F.
S/W CT NOx (after SCR) = 2.5 ppmvd @ 15-percent oxygen
Case 4 (59°F, 100-percent load, CT only) exhaust flow rate = 1,018.1 lb/sec
= 1,018.1 lb/sec × 1/(molecular weight of exhaust gas, 28.35 lb/mole) ×
385.3 ft3/mole (at 68°F) × 60 min/sec
= 830,170 ft3/min (at 68°F)
= 830,170 ft3/min × (1-[percent water by volume, 8.70/100]) (at 68°F, dry)
= 757,945 ft3/min (at 68°F, dry)
= 757,945 ft3/min × ([20.9- percent oxygen by volume and dry, 13.6]/
[20.9-15]) (at 68°F, dry, 15-percent oxygen)
= 937,347 ft3/min (at 68°F, dry, 15-percent oxygen)
S/W CT NOx (after SCR) = 2.5 ppmvd @ 15-percent oxygen × (1/1,000,000) ×
937,347 ft3/min × mole/385.3 ft3 × molecular weight
of NO2, 46 × 60 min/hr
= 16.8 lb/hr
Duct burner NOx (59°F, 100-percent load) = 0.10 lb/106 Btu × 300.0 × 106 Btu/hr
(before SCR)
= 30.0 lb/hr
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SCR efficiency = 90.0 percent
Duct burner NOx (after SCR) = 30.0 lb/hr × ([100-90.0]/100) = 3.0 lb/hr
CT + Duct burner NOx = 16.8 lb/hr + 3.0 lb/hr = 19.8 lb/hr
CT + Duct burner NOx = 19.8 lb/hr × 0.126 = 2.49 g/s
CT AND DUCT BURNER ANNUAL EMISSION RATES
The annual emission rate is the sum of the CT emissions with no duct firing and the
emissions from the unit when duct firing is utilized. Because annual emissions are being
calculated, Free State analyzed the operating scenarios at the annual average temperature
and determined the worst-case scenarios. Using these scenarios, the annual emission rate
was determined as the Case 4 (no duct firing) pollutant hourly rate for 4,460 hours per
year (hr/yr) plus the Case 6 (duct burner firing) pollutant hourly rate for 4,300 hr/yr. The
calculation for NOx follows.
Case 4 NOx hourly emission rate = 16.8 lb/hr per CT/HRSG unit.
Case 4 NOx hourly emission rate = 100.7 lb/hr for 6 CT/HRSG units.
Case 6 NOx hourly emission rate = 19.8 lb/hr per CT/HRSG unit.
Case 6 NOx hourly emission rate = 118.7 lb/hr for 6 CT/HRSG units.
Annual NOx =
100.7 lb / hr  4,460 hr / yr   118.7 lb / hr  4,300 hr / yr 
2000 lb / ton
Annual NOx = 479.8 tons per year (tpy).
CONTRIBUTIONS FROM OTHER FACILITY SOURCES
As shown in Table 2-12, page 2-24 of Volume 2 of the Certificate of Public Convenience
and Necessity (CPCN) Application Environmental Review Document (ERD), the auxiliary boilers will add 3.15 tpy of NOx to the annual potential to emit. Similarly, the emergency generator will add 5.6 tpy, the emergency firewater pump 1.55 tpy. Thus, the Facility’s total annual potential to emit is:
Facility annual NOx = 479.8 + 3.15 + 5.6 + 1.55 = 490.1 tpy.
REQUIRED OFFSETS
NOx offsets are required at a 1.20 to 1 ratio. Thus, the required offsets under the stated
assumptions are:
Required NOx offsets = 490.1 × 1.2 = 588.12 tpy.
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CALCULATION OF REQUIRED VOC OFFSETS
The calculation for the amount of offsets for volatile organic compounds (VOC) that
would be required for the Siemens/Westinghouse (S/W) 501F combustion turbines (CTs)
has been presented in the following subsections.
CT AND DUCT BURNER HOURLY VOC EMISSION RATES
To determine the VOC hourly emission rates, VOC emissions in lb/hr were calculated as
methane (CH4) emissions for each ambient temperature and CT operating load case, and
were based on CT VOC emissions plus duct burner VOC emissions. These operating
scenarios have been presented in the updated Table 7-2 in the Updated Source Impact
Analyses section of this package. The CT VOC emissions in ppmvd at 15% O2 were
based on S/W data. Duct burner VOC emissions were based on a vendor-supplied rate of
0.024 pound per million British thermal units (lb/106 Btu). At this time, no credit has
been taken for VOC reduction due to the CO oxidation catalyst system. Emissions in
lb/hr were converted to g/s by multiplying by a conversion factor of 0.126.
Example: Case 6; 59°F ambient temperature, 100-percent load, duct burner firing. The
emission rate for Case 6 is the sum of the Case 4 emissions (100-percent load at 59°F)
and the duct burner emissions at 100-percent load and 59°F.
S/W CT VOC = 1.2 ppmvd @ 15-percent oxygen.
Case 4 (59°F, 100-percent load, CT only) exhaust flow rate = 1,018.1 lb/sec
= 1,018.1 lb/sec × 1/(molecular weight of exhaust gas, 28.35 lb/mole) ×
385.3 ft3/mole (at 68°F) × 60 min/sec
= 830,170 ft3/min (at 68°F)
= 830,170 ft3/min × (1-[percent water by volume, 8.70/100]) (at 68°F,
dry)
= 757,945 ft3/min (at 68°F, dry)
= 757,945 ft3/min × ([20.9- percent oxygen by volume and dry,
13.6]/[20.9-15]) (at 68°F, dry, 15-percent oxygen)
= 937,347 ft3/min (at 68°F, dry, 15-percent oxygen).
S/W CT VOC (as CH4) = 1.2 ppmvd @15-percent oxygen × (1/1,000,000) ×
937,347 ft3/min × mole/385.3 ft3 × molecular weight of
CH4, 16 × 60 min/hr
= 2.8 lb/hr.
Duct Burner VOC (59°F, 100-percent load) = 0.024 lb/106 Btu × 300.0 × 106
Btu/hr = 7.2 lb/hr.
CT + Duct Burner VOC = 2.8 lb/hr + 7.2 lb/hr = 10.0 lb/hr.
CT + Duct Burner VOC = 10.0 lb/hr x 0.126 = 1.26 g/s.
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CT AND DUCT BURNER ANNUAL EMISSION RATES
To determine the annual emission rate, Free State analyzed the operating scenarios at the
annual average temperature. Because hourly VOC emission rate for Case 5 (70% base
load, 59 oF, no duct burner firing) are greater than the emission rate for Case 4 (100%
base load, 59 oF, no duct burner firing), Free State used the emission rates associated with
each of the operating scenarios at the annual average temperature in its calculation. Using this method, the annual emission rates were determined using the pollutant hourly
rate for Case 4 for 980 hours per year (hr/yr), the pollutant hourly rate for Case 5 for
3,480 hours per year (hr/yr), and the pollutant hourly rates for Case 6 (59 oF, 100 % base
load, duct burner firing) for 4,300 hr/yr. The calculation for VOC follows.
Case 4 VOC Hourly Emission Rate = 2.8 lb/hr per CT/HRSG unit
Case 4 VOC Hourly Emission Rate = 16.8 lb/hr for 6 CT/HRSG units
Case 5 VOC Hourly Emission Rate = 4.0 lb/hr per CT/HRSG unit
Case 5 VOC Hourly Emission Rate = 24.0 lb/hr for 6 CT/HRSG units
Case 6 VOC Hourly Emission Rate = 10.0 lb/hr per CT/HRSG unit
Case 6 VOC Hourly Emission Rate = 60.0 lb/hr for 6 CT/HRSG units
Annual VOC = [(16.8 lb/hr × 980 hrs/yr) + (24.0 lb/hr × 3,480 hrs/yr) +
(60.0 lb/hr × 4,300 hrs/yr)] / 2000 lb/ton
Annual VOC = 179.0 tons per year (tpy).
CONTRIBUTIONS FROM OTHER SOURCES
As shown in Table 2-12, page 2-24 of Volume 2 of the Certificate of Public Convenience
and Necessity (CPCN) Application Environmental Review Document (ERD), the auxiliary boilers will add 0.42 tpy of VOC to the annual potential to emit. Similarly, the emergency generator will add 0.17 tpy, the emergency firewater pump 0.13 tpy. Thus, the Facility’s total annual potential to emit is:
Facility annual VOC = 179.0 + 0.42 + 0.17 + 0.13 = 179.72 tpy.
REQUIRED OFFSETS
VOC offsets are required at a 1.20 to 1 ratio. Thus, the required offsets under the stated
assumptions are:
Required VOC offsets = 179.72 × 1.2 = 215.66 tpy.
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