Air Emissions and Solid Waste from Coal- and Gas-Fired ... · Solid Waste: The estimated amount of...

Braidwood Units 1 and 2License Renewal Application

Air Emissions and Solid Waste Calculation Package

Air Emissions and Solid Waste from Coal- and Gas-Fired Alternativesfor Braidwood Units 1 and 2

License Renewal Chapter 7 Energy Alternatives

Rev 3

September 19, 2012

Prepared for:

Exelon Corporation

Prepared by:

Chuck ConradTetra Tech, Inc.

Aiken, South Carolina

Braidwood Units I and 2License Renewal Application


Approval Page

Air Emissions and Solid Waste from Coal- and Gas-Fired Alternativesfor Bralidwood Units I and 2

Rev 3

September 19, 2012

Author

/Z)? -Reviewed M :

Project Manager:

Date:

9•1,q/i•



Air Emissions and Solid Waste from Coal- and Gas-Fired Alternatives

for Braidwood Units I and 2

This discussion supports the alternatives analysis in Chapter 7.0 of the Environmental Report.

The process of burning fossil fuels (i.e., coal and natural gas) in power generation brings aboutemissions that pollute the atmosphere. Among these, the principle emissions of concern aresulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO), particulate matter (PM) andcarbon dioxide (COA2 ). If coal is the fuel source, mercury (Hg) emissions are also a concern.

The coal combustion process also produces ash, and the flue gas desulfurization equipmentproduces a slurry of ash, unreacted limestone, and calcium sulfite (i.e. scrubber sludge). Themanagement of these solid wastes would require additional facilities at the plant site.

The analysis described below estimates air emissions and solid waste from the operation ofhypothetical coal- and gas-fired electric generation units that could be built to provide the samenet generating capacity as existing Braidwood Units 1 and 2. Braidwood has an approximateannual average net capacity of 2,360 MWe (Exelon Corporation, 2012c) but for purpose of thisanalysis, Exelon projects that Braidwood will increase its approximate annual net meangeneration capacity by 34 MWe in the future to a total of 2,394 MWe.

I. Problem Statement

Provide input for evaluation of energy alternatives to the proposed action of the license renewalfor the nuclear generating capacity at Braidwood Units 1 and 2. Specifically, calculate:

" Controlled emissions of the following criteria pollutants: sulfur oxides as sulfur dioxide(SO2), nitrogen oxides (NOx), carbon monoxide (CO), total suspended particulates (TSP)1, particulates smaller than ten microns (PM10 ) and particulates smaller than 2.5 microns(PM2 .).

* Greenhouse gas [e.g. carbon dioxide (C0 2)] emissions.

* Controlled mercury (Hg) emissions from the coal-fired alternative.

* Solid waste (ash and scrubber sludge) that would be generated by the coal-firedalternative.

II. Analyzed Scenario

For each of the fossil fuel-fired electric generation technologies, identify the appropriateelectrical generation capability, fuel characteristics, firing configurations, and emissions control

In 1971, the National Ambient Air Quality Standards for total suspended particulate (TSP) wereestablished for particulate matter less than 50 microns in diameter. On July 1, 1987 the particulatestandard was revised from TSP to PM1o [52 FR 24634]. The PM10 standard is federally enforceableand applicable nationwide. The TSP standard is not federally enforceable, but is used by some statesfor industrial monitoring purposes.



0devices. Fuel characteristics were based on fuel quality data originating from the region ofinterest (ROI) which was defined at the states surrounding Braidwood (Illinois, Indiana, Iowa,Michigan, Missouri, and Wisconsin). Assumptions are based, in part, on electric power industryexperience, and consist of the following:

Assumptions:

Generating Net Generation Units 2 Capacit ElectricityUn I ConsumedTechnology Capacity' Factory Onsite 4

Coal-fired boiler 2,400 MWe Four 600 MWe (net) 0.85 6 percentCombined cycle Six 400 MWe (net) CC 0.87 4 percent

gas turbine 2,400 MWe 1X1 units 0.87 4_percent

1 The net capacity of the combined cycle gas turbine is based on commercially available units (i.e. GeneralElectric MS7001 H). For equivalency, the coal-fired boilers are assumed to have the same net capacity. (GE2007)

2 International Standards Organization (ISO) rating.3 While higher than typical modern fossil fuel-fired units this provides baseload generation capacity comparable to

a typical nuclear plant.4 Based on industry experience.

Input Data:

Generating2Technology Fuel Type1 Firing Configuration Control Devices2

SO2 - wet scrubber-limestoneNO,, - low NOx burner with overfire air

Coal-Fired Pulverized, Ultra-supercritical, tangentially- and selective catalytic reductionCoired Sub-bituminous fired, dry-bottom, NSPS with low TSP, PM10, and PM2.5 - fabric filterBoiler Coal3 NOx burner4 (baghouse)

Hg - activated carbon injectionCO and C0 2 - none

Combined Six GE H-class (MS7001H) SO2 - not applicable'

Cycle Gas Natural Gas 3 combustion turbines in lx1 NOr and CO - selective catalytic

Turbine combined cycle configuration each injection)with a heat recovery steam TSP and PM10 - not applicable 5

generator and a steam turbine C0 2 - none

123

45

Determination of the heat content and quality of each fuel is described under Calculation Methodology.Best available control technology.Fuel characteristics such as heating value, percent sulfur, and percent ash were determined via a weightedaverage over the fuel consumed in the ROI during the reference year.NSPS = New Source Performance Standards (40 CFR 60)Because of the purity of natural gas, combined-cycle gas units emit only trace amounts of SO 2 and particulatematter.

02



Ill. Calculation Methodology

Air Emissions:

Annual emission estimates for criteria pollutants are calculated using emission factorsdeveloped by the U.S. Environmental Protection Agency (EPA). The emission factors aremultiplied by the relevant "activity level" to determine annual emission estimates for criteriapollutants. The basic emission estimation equation when using an emission factor is:

E = A x EF x (1 - C)Where:

E = emission estimateA = activity level, such as throughputEF = emission factorC = control efficiency (expressed in percent); C equals zero if no

control device is in place 2

The emissions calculations are performed using a series of Excel spreadsheets (Figures Iathrough 4b). To facilitate description of the calculations, these spreadsheets are assignednames as shown below:

Figure Label Spreadsheet PurposeName

Shows user-specified input and air emissionFigure 1 a Coal estimates for the coal alternative

Figure lb Gas Shows user-specified input and air emissionestimates for the gas alternative

Figure 2a Coal-calc Illustrates how the coal emissions are calculatedFigure 2b Gas-calc Illustrates how the gas emissions are calculated

r3 Calculates solid waste produced bycombustion of coal

Figure 4a Controls-Coal Provide databases of EPA emission factors, andother technical information used in the emissionFigure 4b Controls-Gas cluaincalculations

EIA = Energy Information AdministrationEPA = Environmental Protection Agency

Using the gas-fired technology as an example, in a work area that runs along the top of the Gasspreadsheet (cells A3:B8) in Figure lb the analyst specifies the plant name, client, plantcapacity, region of interest, and reference year. The analyst then enters into the Input Table,the assumed number of units, unit size, heat rate, fuel characteristics, and capacityfactor as indicated in Section II, Analyzed Scenario.

2 Most emission factors are developed assuming no control devices are in place. Some emission factors,

however, were derived from data obtained from facilities with a control device in place. When usingthese "controlled emission factors" the control efficiency is included in the emission factor.

3



Going to the Controls-gas spreadsheet (Figure 4b), the analyst specifies the chosen firingconfiguration and control devices as indicated in Section II, Analyzed Scenario, by choosing therow number in the tables, which are directly below the selection cell. The selection enters theemission factors and control devices and control efficiencies into the Input Table. The annualfuel consumption and emissions are calculated and displayed in the Gas spreadsheet (cellsA24:D35). Emissions calculations for the coal-fired alternative are performed in the samemanner.

Solid Waste:

The estimated amount of solid waste (e.g., ash and scrubber sludge) generated by the coal-fired alternative is calculated using a material balance based on annual fuel consumption. Thecalculations assume complete combustion and operating life of 40 years3.

An excel spreadsheet, SW-Coal (Figure 3) was used to perform the calculations. Thisspreadsheet uses parameters (e.g., fuel use, sulfur content, ash content, and pollutant controlefficiency) from the air emissions calculations. The only inputs required are the amounts of ashand scrubber sludge recycled (cell 16 and 17, respectively). Results are displayed on the right-hand side of the output table (cells K10:K58).

IV. Verification and Validation

This documentation assumes that the referenced EIA and EPA data input is valid. Verification,therefore, must demonstrate that the model is functionally equivalent to manual application ofthe emission factor methodology using the actual tables published in AP-42. Verification wouldconsist of confirmation of the input and output files as defined in Section V. This would includeconfirmation of the following:

" The tables in the model are equivalent to the corresponding tables and sections in thereferenced publications.

" The input in the work area maps the correct data from the model tables into the workarea.

* The calculated emissions, which are also mapped into the work area, are correct and

appear correctly in the summary tables and the calculation display tables (e.g. coal-alt).

" Manual calculations from the calculation display tables equate to the listed values.

V. Input and Output File

Coal-Fired Boiler:

3 The total amount of solid waste generated during the 40 operating life of an electric generation plant istwice the amount that would be generated during the 20-year license renewal period. The total,however, is representative of the cumulative impact. a

4



Figure 1 a is the work area for the sheet named Coal, and displays the user defined input (inbold), the source for other input is referenced, and corresponding output from the coalemissions work area in reverse video (white letters on black background). The equations andthe same output values for coal-fired boiler air emissions are displayed in Figure 2a. Theformulas and output for the coal-fired boiler solid waste generation are provided in Figure 3.Lookup matrices and databases for control devices are shown in Figures 4a and 4b.

Each input selects the state or row number for tables that are derived from EIA or EPA data.Section II, Analyzed Scenario, defines the appropriate selections and the information isdisplayed in Figure la.

The Controls-Coal sheet (Figure 4a) input at A4 (cell value = "2") maps the user-selected SO,control technology (Wet scrubber-Limestone) and its control efficiency (95%) into cells B4:C4.The input at E4 (cell value = "8") places the user-selected NO, control technology (Low NO,burners with over-fire air and selective catalytic reduction) and its control efficiency (95%) intocells F4:G4. Similarly, input in cell 14 (cell value = "2") selects the user-selected TSP, PM10 , andPM2 5 control technology (Baghouse) and their control efficiencies (99.9%) into cells J4:M4. Theassigned value for cell 04 (cell value = "13") maps the SO,, NO,, CO and CO 2 emission factorsinto cells Q4:T4 for the firing configuration shown in P4 (cell value = "PC, dry bottom,tangentially fired, sub-bituminous, NSPS"). Similarly, less detailed firing configurations haveassociated emission factors for TSP, PM10 , and PM 2.5. Input at U5 (cell value = "2") for the firingconfiguration placed in cell V5 (cell value = "PC-fired, dry bottom, tangentially-fired") mapsemission factors into cells W5:Y5 (cell values = "10A, 2.3A, and 0.6A").

This is all the input required to calculate emissions listed in the problem statement. The

emissions in tons per year are shown in cells C42:C50 on the Coal worksheet (Figure la).

Gas-Fired Combustion Turbine:

Input and output for the gas alternative are similar to the input and output for the coal-firedalternative. Figure lb is the work area for the sheet named Gas, and Figure 2b shows theformulas to calculate emissions. Lookup matrices and databases are shown in Figure 4b.'

On the Controls-gas sheet, input at cell A4 (cell value = "6") retrieves the NO, and CO emissionfactors for the selected control device (see B4:D4). C0 2, SO 2 , filterable TSP, and condensableTSP are uncontrolled. Their emission factors are listed cells C28:C35 in the worksheet Gas(Figure 1b).

5

Figure la - Emissions for Coal Fired Alternative 0I A I B I C I D

Station: Braidwood Generation Station, Units 1 and 2

PlantLicense Expiration DateClientReplaces (MWe)Fuel: Referenced StateFuel Referenced Year

Braidwood2026Exelon Nuclear2,394ROI: IL, IN, IA, MI, MO, WI2010

(Year current operating license expires)

Coal Fired Worksheet, Section 1.1 AP-42 Supplement E

InputsFuel TypeBoiler Technology

Number of Units

Plant Capacity-gross (MWe)Plant Capacity-net (MWe)Heat Rate (BTU/kWh)Heating Value (BTU/lb)Capacity FactorPercent Sulfur (%)Percent Ash (%)

SO, Control Device

SO, Control Efficiency (%)

NO, Control Device

NO, Control Efficiency (%)

TSP Control DeviceTSP Control Efficiency (%)PM10 Control Device

PM10 Control Efficiency (%)

PM2.5 Control Device

PM2 5 Control Efficiency (%)

Hg Control DeviceHg Control Efficiency (%)

Firing Configuration to determine SOx,

NOx, CO and CO 2 emission factors

ValueSub-Bituminous, Pulverized Coal

Ultra-Supercritical

4

638600

8,9378,7300.850.274.93

Wet scrubber-Limestone

95Low NOX burners with over-fire

air and SCR95

Baghouse99.9

Baghouse

99.9

Baghouse

99.9Activated carbon injection

90PC, dry bottom, tangentially

fired, sub-bituminous, NSPS

SourceAssumedAssumedAssumed: Provides 2,400 MWe -Braidwood net capacity of 2,394 MWeAssume 6% used onsiteTo match gas scenario for comparabilityS&L 2009, Table 2-2EIA 2011d; typical for sub-bituminous coal used in ROIEIA 2011eEIA 201 ld; typical for sub-bituminous coal used in ROIEIA 201 ld; typical for sub-bituminous coal used in ROIEPA 1998, Table 1.1-1

EPA 1998, Table 1.1-1

EPA 1998, Table 1.1-2

EPA 1998, Table 1.1-2EPA 1998, §1.1.4.1EPA 1998, §1.1.4.1EPA 1998, §1.1.4.1EPA 1998, §1.1.4.1

EPA 1998, §1.1.4.1

EPA 1998, §1.1.4.1EPA 2010ADA 2012

EPA 1998, Table 1.1-3

EPA 1998, Table 1.1-4

SourceEnergy BalanceEIIP 2001, page 2.4-5, equation 2.4-4

Firing Configuration to determine TSP, PC-fired, dry bottom, tangentially.PM10, and PM2 5 emission factors fired

ParameterAnnual Coal Consumption (tons/yr)Hi.ann-_Annual Btu input (MMBTU/yr)

Value9,730,777

169,901,877

42

43

4445

4647

48

49

52

5455

Emissions

SO,

NOx

COCO 2

TSPPM10

PM2.0Hg

uncontrolled(lb/ton)

35S = 9.45

7.2

0.5

4810

10A = 49.3

2.3A= 11.3

0.6A = 2.960.000016

controlled(tons/yr)

2,299

1,7522,433

23,402.520

239.9

55.17

14.39

0.14

Source

EPA 1998, Table 1.1-3

EPA 1998, Table 1.1-3EPA 1998, Table 1.1-3EPA 1998, Table 1.1-20EPA 1998, Table 1.1-4EPA 1998, Table 1.1-4

EPA 1998, Table 1.1-6EPA 1998, Table 1.1-17

' Hg emissions are pounds/MMBTU

Bold = user defined inputs (e.g.White font = outputs (e.g.

2,394

0Braidwood Emissions Calc Rev 3.xlsm coal 9/1912012

Figure lb - Emissions for Gas Fired Alternative

IA IB I C I .DStation: Braidwood Generation Station, Units I and 2

PlantLicense Expiration DateClientReplaces (MWe)Fuel: Region of InterestFuel: Referenced Year

Braidwood2026Exelon Nuclear2,394IL, IN, IA, MI, MO, WI2010

(Year current license expires)

Gas Turbines for Electrical Generation Worksheet, Section 3.1, AP-42 Supplement B

InputsNumber of UnitsPlant Capacity-gross (MWe)Plant Capacity-net (MWe)

Heat Rate (BTU/kWh)

Heating Value (BTU/ft3)Capacity FactorPercent Sulfur (%)SO, (lb/MMBTU)

NO, / CO control device

Parameter

Annual gas consumption (ft3/yr)

Annual Btu input (MMBTU/yr)

Emissions

Value6

417400

5,6901,0110.87

0.00070.00066

Selective CatalyticReduction (with

water/steam injection)

SourceAssumed; Provides 2,400 MWe - Braidwood net capacity of 2,394 MWeAssume 4% used onsiteGE H-class (MS7001H) lx1 combined cycle unit (GE 2007)GE 2007EIA 201 1d; typical for natural gas used in ROIEIA 201 leINGAA 2000, page 8EPA 2000a, Table 3.1-2a

Assumed

SourceEnergy BalanceEIIP 2001, pg 2.4-5, eq 2.4-4

(tonslyr) SourceEPA 2000a, Table 3.1-2a

Value107,198,042,714

108,411,570

(IlbMMBTU)SO, 0.94S = 0.00066

NOx 0.0109

CO 0.00226CO 2 110

Filterable TSP 0.0019

Filterable PM2.5 a 0.0019

Condensable TSP 0.0047Condensable PM2 , a 0.0047

aAll particulate matter<1.0 micron (EPA 2000a, paqe 3.1-5)

591

123

5,962,636

103

103

255

255

EPA 2000b, Table 3.1 DatabaseEPA 2000b, Table 3.1 Database

EPA 2000a, Table 3.1-2aEPA 2000a, Table 3.1-2a

EPA 2000a, Table 3.1-2aEPA 2000a, Table 3.1-2a

EPA 2000a, Table 3.1-2a

Bold = user defined input (e.g. 2,394White font = outouts (eo. *

Braidwood Emissions Calc Rev 3.xlsm Gas 9/19/2012

Figure 2a - Calculation of Coal Fired Emissions

A BI C IDI E IFI G IHI I JI K ILI M IN]OIPI Q IRI S T I U1 Station: Braidwood Generation Station, Units 1 and 22 COAL

4 Parameter Calculation Result

67 Annual coal 4 Units x 638 MW 1,000 kW 8937 Btu lb ton 0.85 x (365 x 24) hr 9,730,777 tons of coal per year8 consumption plant MW kWh 8730 Btu 2000 lb yr91011 35x0.27 lb ton (100-95) x 9730777 tons 2299 tons 502 per year12 S2 ton 2000 lb 100 yr

131415 NO 7.2 lb ton (100- 95) 9730777 tons 1,752 tons NOx per year16 ton x 2000 lb -10 yr171819" 0.5 lb ton 9730777 tons = 2,433 tons CO per year20 ton 200b x yr

212223 CO. 4810 lb ton 9730777 tons 23,402,520 tons CO2 per year

24 ton 2000• b yr252627 10x 4.93 1b ton (00 -99.9) x 9730777 tons-" TSP ton x 01 x 100 yr 239.9 tons TSP per year29

3031 PM10 2.3 x 4.93 lb ton (100 - 99.9) 9730777 tons 55.17 tons PM10 per year32 ton 20001b x 100 yr

333435 25 0.6 x 4.93 lb ton (100-99.9) 9730777 tons 14.39 tons PM25 per year36 ton 2000• b 100 - yr37

3839 0.000016 lb x 8730 Btu x MMBtu x 9730777 tons x (10-90) 0,14 tons Hg peryear

4 MMBtu lb 1E6 Btu yr 100

Braidwood Emissions Calc Rev 3 xlsm roal-nnilc 9/19/2012

* 0Figure 2b - Calculation of Gas Fired Emissions

A IBI C IDIEIFIGIHIIIJIKILIMINIOIPI Q IRISITI U IVlWI x I Y1 Station: Braidwood Generation Station, Units I and 22 GAS

4 Parameter Calculation Result5

6. Annualgas 417 MW 5690 Btu 1,000 kW Wft3 (365 x 24) hr ft3

7 consumption 6 Units x Unit kWh MW 1011 Btu yr =

89 Annual BTU 107,198,042,714 ft3 1011 Btu MMBtu10 input yr t X 106 Btu 108,411,570 MMBtu per year

111213 so 0.94S = 0.00066 lb ton 108,411,570 MMBtu 36 tons S02 per year14 MMBtu 2000 lb yr151617 0.0109 lb ton 108,411,570 MMBtu 591 tons NO, peryear18 NOx MMBtu x 2000 lb x yr192021 0.00226 lb ton 108,411,570 MMBtu22 CO MMBtu A 2000 lb x yr 123 tons CO per year

232425 110 lb ton 108,411,570 MMBtu 5,962,636 tons CO 2 per year26 CO 2 MMBtu 2000 lb x yr272829 0.0019 lb ton 108,411,570 MMBtu 103 tons filterableTSP per year30 Filterable TSP MMBtu 2000 lb yr =

3T3233 Condensable 0.0047 lb ton 108,411,570 MMBtu 255 tons condensable TSP per year34 TSP MMBtu x 000 x yr

Braidwood Emissions Calc Rev 3.xlsm Gas-calc 9/19/2 012

Figure 3 - Calculation of Solid Waste from Coal Fired Alternative

A 10 C IDI E IFI G I H I I I K I M I N1 Station: Braidwood Generation Station, Units I and 22 Coal Solid Wastes

4 Basis: SO 2 Control Method: Wet scrubber-Limestone5 Annual coal consumption = 9,730,777 tons6 Percent of ash recycled = 85 % Source: Exelon Corporation 2011

89Percent of scrubber sludge recycled 85 % Source: Exelon Corporation 2011

9 aaeter Calculation Re-suit

SO 2 generated

SO 2 removed

Ash generated

Ash recycled

Waste ash

Limestoneconsumption

Calcium sulfitegenerated

Scrubber sludgegenerated

Scrubber sludgerecycled

Scrubber waste

Total volume ofscrubber waste

Total volume ofash waste

Total volume ofsolid waste

Waste pile area

Waste pile area(acre)

Waste pile area(mil)

0.27 64.065 9,730,777 tons coal100 32.066 yr

95

100 x 52,491 =

4.930 99.900 9,730,777100 100-x yr

85479248 tons of ash x 10

100

52,491 tons SO2 per year

49,867 tons SO 2 per year

479,248 tons ash per year

407,360 tons ash recycled per year

71,887 tons waste ash per year479248 tons - 407360 tons =

Wet Scrubbing - Limestone:CaCO3 + H20 + S02 -- > CaSO3 +C02 + H20

52,491 ton S02 100.087 ton CaCO3

yr 64.065 ton S02

49,867 ton S02 120.142 ton CaSO3

yr 64.065 ton S02

82,006 ton CaSO3 100-95 + 93516 ton CaSO3yr 100

8597,616 tons x =

100

97,616 tons - 82,974 tons =

14,642 tons 2000 lb ft3

yr ton 100 lb

71,887 tons x 20yr x 2000 lb ft3

yr ton 100 lb

5,856,974 ft3

+ 28,754,856 ft3

=

34,611,830 ft3

30 ft high

ft2

1,153,728 ft2

X 4 043,560 acre

26 acre x mile2

640 acre

82,006 tons CaCO3 per year

93,516 tons CaSO3 per year

97,616 tons scrubber sludge per year

82,974 tons scrubber sludge recycled peryear

14,642 tons scrubber waste per year

5,856,974 ft3

scrubber waste

28,754,856 ft3

ash waste

34,611,830 ft3

solid waste

1,153,728 ft2

solid waste

26.49 acre solid waste

0.0414 mi2

Solid waste

61 Notes: a. Calculations were performed using stoichometric ratios from the chemical equation shown above and molecular weights of the

62 compounds.63 b. Calculations assume 100% combustion of coal.64 c. Limestone consumption is based on total S02 generated.65 d. Calcium Sulfite generated is based on total S02 removed.66 e. Total sludge generated includes scrubbing media carryover in the waste.

67 f. Density of Scrubber Sludge (Ib/ft3): 100 Source: RMRC 2008

68 g. Density of Coal Bottom Ash (lb/ft3): 100 Source: RMRC 2008

69 h. Plant life (year): 20 Source: Assumed70 i. Waste pile height (ft): 30 Source: Assumed

Braidwood Emissions Calc Rev 3.xlsm SW-Coal 9/19/2012

Figure 4a - Emission Control Technologies for Coal-Fired Alternative

A B C D2

S02 Control SO2 Control

3 Selection SO2 Control Technology Efficiency

4 2 Wet scrubber-Limestone 95

56

7 Efficiency'8 Number Technology (%)9 1 Wet scrubber-Lime 95

10 2 Wet scrubber-Limestone 95

11 3 Wet scrubber-Sodium carbonate 98

12 4 Wet scrubber-Magnesium oxide/hydroxide 9513 5 Wet scrubber-Dual alkali 9614 6 Spray drying 90

15 7 Furnace injection 50

16 8 Duct injection 50

1718

19 1 Source: EPA 1998, Table 1.1-1, page 1.1-132021222324252627282930

31

3233

34

Braidwood Emissions Calc Rev 3.xlsm Control-coal 9/19/2012


E F G H2

NOx Control NOx Control3 Selection NOx Control Technique Efficiency

4 8 Low NOX burners with over-fire air and SCR 955678 Number Technique Efficiency' (%)9 1 Overfire air 30

10 2 Low NOx burners 55

11 3 Low NOx burners with overfire air 6012 4 Reburn 6013 5 Selective noncatalytic reduction (SNCR) 6014 6 Selective catalytic reduction (SCR) 8515 7 Low NOx burners with selective noncatalytic reduction 80

16 8 Low NOx burners with over-fire air and SCR 95171819 1 Source: EPA 1998, Table 1.1-2, page 1.1-142021222324252627282930

31

323334


oFigure 4a - Emission Control Technologies for Coal-Fired Alternative

J K L M N2

TSP and PM1 o Control Particulate Matter Control TSP Control PM10 Control PM2.5 Control3 Selection Technology Efficiency Efficiency Efficiency

4 2 Baghouse 99.9 99.9 99.956

7 TSP control PM10 control PM2.5 control8 Number Technology efficiency1 (%) efficiency1 (%) efficiency' (%)9 1 Electrostatic Precipitator 99 99 99

10 2 Baghouse 99.9 99.9 99.9

11 3 Wet Scrubber 99 99 99

12 4 Cyclone collector 95 78 781314

15

16

1718

19 1 Source: EPA 1998, §1.1.4.1, page 1.1-62021222324252627282930

31

3233

34



0 P Q R S T2-

SON, NO., CO, CO 2 SO, NO, CO. CO 2Firing Configuration Emission Emission Emission Emission

3 Selection Firing Configuration Factor Factor Factor Factor

4 13 PC, dry bottom, tangentially fired, sub-bituminous, NSPS 35S 7.2 0.5 4810567 Emission Factors' (lb/ton)8 Number Firing Configration Sox NOx CO CO2

9 1 PC, dry bottom, wall-fired, bituminous Pre-NSPS 38S 22 0.5 551010 2 PC, dry bottom, wall-fired, bituminous Pre-NSPS with low-Nox burner 38S 11 0.5 551011 3 PC, dry bottom wall-fired, sub-bituminous Pre-NSPS 35S 12 0.5 481012 4 PC, dry bottom, tangentially fired, bituminous, Pre-NSPS 38S 15 0.5 551013 5 PC, dry bottom, tangentially fired, bituminous, Pre-NSPS with low-NOx burner 38S 9.7 0.5 551014 6 PC, dry bottom, tangentially fired, sub-bituminous, Pre-NSPS 35S 8.4 0.5 481015 7 PC, wet bottom, wall-fired, bituminous, Pre-NSPS 38S 31 0.5 5510

16 8 PC, dry bottom, wall-fired, bituminous NSPS 38S 12 0.5 551017 9 PC, dry bottom, wall fired, sub-bituminous NSPS 35S 7.4 0.5 481018 10 PC, dry bottom, cell burner fired, bituminous 38S 31 0.5 551019 11 PC, dry bottom, cell burner fired, sub-bituminous 35S 14 0.5 481020 12 PC, dry bottom, tangentially fired, bituminous, NSPS 38S 10 0.5 551021 13 PC, dry bottom, tangentially fired, sub-bituminous, NSPS 35S 7.2 0.5 481022 14 PC, wet bottom, tangentially fired, bituminous, NSPS 38S 14 0.5 551023 15 PC, wet bottom, wall-fired sub-bituminous 35S 24 0.5 481024 16 Cyclone Furnace, bituminous 38S 33 0.5 551025 17 Cyclone Furnace, sub-bituminous 35S 17 0.5 481026 18 Spreader Stoker, bituminous 38S 11 5 551027 19 Spreader Stoker, sub-bituminous 35S 8.8 5 481028 20 Overfeed stoker 38S 7.5 6 481029 21 Underfeed stoker 31S 9.5 11 481030 22 Hand-fed units 31S 9.1 275 4810

39.6S/31 23 FBC, circulating bed (Ca/S)1 9 5 18 4810

39.6S/32 24 FBC, bubbling bed (Ca/S)1 9 15.2 18 48103334 1 Source: EPA 1998, Table 1.1-3 on page 1.1-16 and Table 1.1-20 on page 1.1-42


0

oFigure 4a - Emission Control Technologies for Coal-Fired Alternative

U V W x Y z2

Particulate Firing TSP PM10 PM 2.5Configuration Emission Emission Emission

3 Selection Firing Configuration Factor Factor Factor

4 2 PC-fired, dry bottom, tangentially-fired 10A 2.3A 0.6A

56

7 Emission Factors1 (lb/ton)8 Number Firing Configuration TSP PM10 PM2.59 1 PC-fired, dry bottom, wall-fired 10A 2.3A 0.6A

10 2 PC-fired, dry bottom, tangentially-fired 10A 2.3A 0.6A

11 3 PC-fired, wet bottom 7A 2.6A 1.48A

12 4 Cyclone furnace 2A 0.26A 0.11A13 5 Spreader stoker 66 13.2 4.614 6 Spreader stoker, with multiple cyclones, and reinjection 17 12 1.415 7 Spreader stoker, with multiple cyclones, no reinjection 12 7.8 3.2

16 8 Overfeed stoker 16 6 2.2

17 9 Overfeed stoker, with multiple cyclones 9 5 3.818 10 Underfeed stoker 15 6.2 3.819 11 Underfeed stoker, with multiple cyclones 11 6.2 -

20 12 Hand-fed units 15 6.2 3.821 13 FBC, bubbling bed 17 12 1.422 14 FBC, circulating bed 17 12 1.4232425 Source: EPA 1998, Tables 1.1-4, 1.1-6, 1.1-7, 1.1-8, 1.1-9, 1.1-10,26 and 1.1-11 on pages 1.1-21 through 1.1-3127282930

31

3233

34


Figure 4b - Emission Control Technologies for Gas-Fired Alternative

A BC D E2

Select # from Table NO. Emission CO Emission3 3.1-1 or 3.1-2 NO, / CO Control (lb /MMBTU) (lb /MMBTU)

Selective Catalytic Reduction (with water/steam4 6 injection) 0.0109 0.00226

56 NOx CO

7 1 Uncontrolled 0.32 0.082 1

8 2 Water Injection 0.13 0.039 3 Steam injection 0.13 0.03 1

10 4 Lean-Premix 0.099 0.01511 5 Selective Catalytic Reduction 0.0128 0.0168 2

12 6 Selective Catalytic Reduction (with water/steam injectiol 0.0109 0.00226 2

13 7 Steam/Water Injection with SCR & CO Catalyst 0.00899 0.06 2

14151617 1 Source: EPA 2000a, Table 3.1-118 2 Source: EPA 2000b, Section 3.1 database19

Braidwood Emissions Calc Rev 3.xlsm Control-gas 9/19/2012

Fuel References:

Braid-398 EIA 2011d

Braid-384 INGAA 2000

Heat Rate References:

Braid-383 GE 2007

Braid-386 S&L 2009

Emission Factor References:

Braid-375 ADA 2012

Braid-377 EPA 1998

Braid-378 EPA 2000a

Braid-374 EPA 2000b

Braid-379 EPA 2010

Braid-376 EIIP 2001

Solid Waste References:

EIA-923 (Schedule 2) - Monthly Utility and Nonutility Fuel Receipts and Fuel Quality Data -2010 (final data), Available at http://www.eia.gov/cneaf/electricity/page/eia423.html

Interstate Natural Gas Association of America. 2000. "Implications of Reduced Gas Use onEmissions From Power Generation". Available online at www.ingaa.org/File.aspx?id=282(For sulfur content of natural gas.)

"Gas Turbine and Combined Cycle Products." May, Available athttp://www.gepower.com/prod-serv/products/index.html

Sargent & Lundy. "New Coal-Fired Power Plant Performance and Cost Estimates." SL-009808. Available at http://www.epa.gov/airmarkets/resource/docs/CoalPerform.pdf.

Activated Carbon Injection Systems, Available at http://www.adaes.com/mercury/acis/

Air Pollutant Emission Factors. Vol. 1, Stationary Point Sources and Area Sources. Section1.1, "Bituminous and Subbituminous Coal Combustion." AP-42. September. Available athttp://www.epa.gov/ttn/chief/ap42/.

Air Pollutant Emission Factors. Vol. 1, Stationary Point Sources and Area Sources. Section3.1, "Stationary Gas Turbines." AP-42. April. Available athttp://www.epa.gov/ttn/chief/ap42/index. html.

AP-42, Chapter 3, Section 3.1 Emission Factor Query database. Available athttp://www.epa.gov/ttn/chief/ap42/chO3/related/cO3s01. html.

Controlling Power Plant Emissions: Control Technology, Last updated Oct 2010, Available athttp://www.epa.gov/hg/control_emissions/technology. htm

Emission Inventory Improvement Program Technical Report Series, Volume 2, PointSources. Chapter 2, "Preferred and Alternative Methods for Estimating Air Emissions fromBoilers." January.

Recycled Materials Resource Center, User Guidelines for Byproducts and Secondary UseMaterials in Pavement Construction, July, Available athttp://www.rmrc.unh.edu/tools/uguidelines/index.asp

Braid-475 RMRC 2008

Braid-380 Exelon Corporation "Maximizing the resources we use", Available at2011 http://www.exeloncorp.com/environment/results/land.aspx

Other References:

Braid-366 Exelon 2012c

Braid-476 EIA 2011e

United States Securities and Exchange Commission, Form 10-K

"Levelized Cost of New Generation Resources in the Annual Energy Outlook 2011" Availableat http://205.254.135.24/oiaf/aeo/electricitygeneration.html

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