FMCAlkali (:hemicals

FMC Westvaco Facility

April 11, 2006

David A. Finley, Administrator

Wyoming Department of Environmental Quality

Air Quality Division

122 West 25~ Street

Cheyenne,VVY 82002

FMC Corporation

PO Box 872

Green River, WY 82935

307.875.2580 phone

www.fmc.com

Dear Mr. Finley:

Please find enclosed five (5) copies of Addendum 1 of the Best Available Retrofit

Technology (BART) analysis for sources subject to BART located at FMC's Westvaco

facility near Green River, Wyoming, One copy of the addendum has also been sent to Tony

Hoyt at DEQ's Lander district office. An electronic copy of the addendum (in PDF format)

was transmitted earlier via email.

Please note 1hat 1he electronic visibility modeling files associated with the addendum are

being provided to the Division directly by FMC's consultant Sage Environmental.

Please contact me at 307-872-2257 if you have any questions,

Sincerely,

Otto C. Schnauber

Environmental Team Leader

cc: Tony fioyt, District Engineer

Wyoming Department of Environmental Quality

Air Quality Division

510 Meadowview Dr.

Lander, WY 82520

-FMC
, r

FMC Wyoming Corporation

Green River, Wyoming

Best Available Retrofit Technology Analysis

for Sources Subject to BART

FMC Wyoming Corporation's

Westvaco Facility

Addendum 1
FMC Wyoming Corporation

Green River, Wyoming ~.".",., ,.~

Best Available Retrofit Technology Analysis

for Sources Subject to BART

FMC Wyoming Corporation's

Westvaco Facility

Addendum 1

Prepared For:

Wyoming Department of Environmental Quality

Air Quality Division

122 West 25th Street

Cheyenne, Wyoming 82002

Prepared By:

FMC Wyoming Corporation

Otto Schnauber

Sage Environmental

Jim Zapert

April 11, 2008
Table of Contents

Section

1.0 Introduction

2.0 Visibility Assessment Methodology

2.1 Modeling Methodology

2.2 Meteorological Model

2.3 Dispersion Model

2.4 Model Post-processing

2.5 Modeled Sources

2.6 Baseline Analyses

3.0 Best Available Retrofit Technology Analysis - Sulfur Oxides (SOx)

3.1 Impact Anaiysis

3.2 sax BART Visibility Analyses

4.0 Best Available Retrofit Technology Analysis - Nitrogen Oxides (NOx)

4.1 Control Technology Effectiveness

4.2 Impact Analysis

4.3 NOx BART Visibility Analyses

5.0 Selection of BART for FMC Westvaco Sources

5.1 Combined Application of BART for SOx and NOx Emissions

5.2 BART Proposal

Tables

2-1 Source Parameters

2-2 Baseline Emission Rates

2-3 Baseline Visibility Modeling Results

3-1 sax Control: Economic and Environmental Impacts for Each Coal-fired

Boiler (NS-1A, NS-1 B)

3-2 Emission Rates for sax Control Alternatives

3-3 Visibility Modeling Results - SOx Control Option 1

3-4 Visibility Modeling Results - SOx Control Option 2

4-1 NOx BART Effectiveness for NS-1A and NS-1 B

4-2 NOx Control: Economic and Environmental Impacts for Each Coal-fired

Boiler (NS-1A, NS-1 B)

4-3 Emission Rates for NOx Control Alternatives

4-4 Visibility Modeling Resuits - NOx Control Option 1

4-5 Visibility Modeling Results - NOx Control Option 2

4-6 Visibility Modeling Results - NOx Control Option 3

5-1 Source Parameters for Visibility Analysis: Combined sax and NOx Control

5-2 Visibility Modeling Results - Combined sax and NOx Control

ii ~.~
Appendices

1 Cost Effectiveness Analyses Detail - sax and NOx Control Alternatives

iii
1.0 Introduction

FMC submitted a Best Available Retrofit Technology (BART) analysis in March, 2007

that addressed the FMC Green River emission sources that were subject to BART. The

analysis focused on retrofit options for the site's two coal-fired boilers: units NS-1A and

NS-1B.

Information that has become available since the original submittal has resulted in the

need to update the conclusions reached in that analysis with regard to NOx control on

the two boilers. Additionally, the analyses presented in this addendum for both NOx and

SOx visibility impacts address emission units on an individual basis as required by the

BART modeling protocol.
2.0 Visibility Assessment Methodology

The additional visibility modeling performed for this submittal employed the same

techniques that were described in Section 3 of the March 2007 analysis. Those

techniques are repeated here for ease of reference. Baseline modeling results now

show the visibility impacts in the wilderness areas of each of the BART eligible emission

units.

2.1 Modeling Methodology

The protocol indicates that visibility assessments are to be conducted using the

CALPUFF modeling system, and three years of meteorological data, years 2001

through 2003. The modeling system is comprised of the CALMET

meteorological model, the CALPUFF dispersion model, and the CALPOST post

processor. For this analysis CALMET (version 5.53a, level 040716), CALPUFF

(version 5.711a, level 040716), and CALPOST (version 5.51, level 030709) were

used. The modeling domain specified in the WDEQ protocol as applicable for

southwest Wyoming was used since the PSD Class I areas of interest include the

Bridger and Fitzpatrick PSD Class I Wilderness Areas.

2.2 Meteorological Model

The CALMET meteorological model was used to determine hourly windfields for

years 2001 through 2003. Mesoscale model meteorological data (MM5) at 12-

km grid resolution, surface and upper air meteorological observation data,

precipitation data, and geophysical data as provided by the Wyoming DEQ were

used. The modeling domain was processed to a uniform horizontal grid using 4-

1m resolution, based on a Lambert Conformal Projection defined with a central

longitude/latitude at (-108.55',42.55') and first and second latitude parallels at

30' and 60'. Ten vertical layers were used with heights of 20,40, 100, 140,320,

580,1020,1480,2220, and 3400 meters. The height used for the top layer

(3400 meters) differed slightly from what was specified in the WDEQ protocol

(3500 meters) since the upper air data provided by the WDEQ was not sufficient
to support a 3500 meter layer height. All other CALMET input switch settings

and input control values were determined following the WDEQ protocol.

3.3 Dispersion Model

The CALPUFF dispersion model was used to model emissions of nitrogen oxides

(NOx), sulfur dioxide (S02). primary sulfate (S04) and particulate matter (PM).

S04 emissions were determined from sulfuric acid mist (H2S04) emissions using

the ratio of the molecular weights of the two compounds. All particulate matter

was assumed to be PM2.s.

CALPUFF was run using the control file switch settings and values as provided in

the WDEQ protocol. Model receptors determined for the Bridger and Fitzpatrick

Wilderness Areas were provided by the WDEQ. Chemical transformations were

modeled based on the MESOPUFF II chemistry mechanism for conversion of

S02 to S04 and NOx to nitric acid (HNOs) and nitrate (NOs). A background

ammonia (NHs) concentration value of 2.0 parts per billion (ppb) was specified.

Background hourly ozone concentration data from monitoring sites throughout

the modeling domain were provided by the WDEQ for each modeled year.

2.4 Model Post-processing

The CALPUFF model results were post-processed using the CALPOST

processor to estimate visibility impacts at the Bridger and Fitzpatrick Wilderness

Areas. Visibility impacts were determined using CALPOST method 6. Method 6

calculates visibility impacts from CALPUFF predicted concentration data, relative

humidity factors, and aerosol components. Relative humidity factors and

background concentrations of aerosol components for the 20 percent best days

applicable to the Bridger and Fitzpatrick Wilderness Areas and all CALPOST

switch settings were provided from the WDEQ protocol.

CALPOST was used to determine both the 98th percentile,or 8th highest, 24-hour

visibility impacts for each year and the maximum number of days per year above

0.5 deita deciviews (Mv).
2.5 Modeled Sources

The source parameters for the FMC Westvaco BART eligible emission units are

summarized below:

Table 2-1

Source Parameters

#6 coal-fired

NS-1A boiler 599377.25 4607953.88 6305.12

#7 coal-fired

NS-1B boiler 599381.06 4607953.88 6305.12

#4 gas-fired

PH-3 boiler 598665.05 4608318.92 6229.33

2.6 Baseline Analyses

300 11.5

300 11.5

70 7.5

2.6.1 Baseline Emission Rates

The baseline emission rates for the FMC Westvaco BART eligible

emission units are summarized below:

Table 2-2

Baseline Emission Rates

#6 coalNS-1A fired boiler 287 359.000 45.0 1064.4 620.9 13.4

#7 coalNS-1B fired boiler 287 359,900 45.0 1064.4 620.9 13.4

#4 gas-fired

PH-3 boiler 250 72,500 2.5 0 76.7 0

The baseline emission rates represent the maximum potential to emit vaiues for

each pollutant for each of the BART eligible sources. Particulate matter is

assumed to be PM2.5.
2.6.2 Baseline Modeling Results

The baseline modeling results for the FMC Westvaco BART eligible

sources for each modeled year are shown below in Table 2-3.

The average predicted light extinction, given in units of inverse

megameters (Mm'1) for each day and receptor where the predicted

visibility Impact was at or above a 5 percent change in extinction

(approximately equal to 0.5 I1dv), was calculated. Results are provided

for each of the FMC Westvaco BART eligible sources as average

extinction and percent of the total extinction. The number of days above

0.5 I1dv and the 98th percentile values are also provided.

Table 2-3

Baseline Visibility Modeling Results

NS-1A: Extinction, Mm",

NS-1 B: Extinction, Mm'

PH-3: Extinction Mm'

NS-1A: # da s> 0.5l1dv 10 5 11 4 2 1

NS-1 B: # da s > 0.5l1dv 10 5 11 4 2 1

PH-3: # da s > 0,5l1dv 0

° ° ° ° 0

NS-1A: 98 ercentile lIdv 0.566 0.429 0,536 0,327 0,311 0.263

NS-1B: 98 ercentile lIdv 0.566 0.429 0.536 0,327 0,312 0.263

PH-3: 98 ercentlle lIdv 0.041 0.032 0.047 0,017 0,020 0,017

Conclusions from the baseline modeling results are:

• Contributions to visibility impacts from sources NS-1A and NS-1 Bare

virtually identical. The visibility impact from each of these sources is

above the 0.5 dv guideline value in the Bridger Wilderness in two of the

three years modeled, and each sources' impact in the Fitzpatrick

Wilderness is less than the gUideline im pact value in all three years.

• The visibility impact from source PH-3 is significantly less than the 0.5 dv

gUideline value In all cases which means that this source is not subject to

BART.
3.0 Best Available Retrofit Technology Analysis - Sulfur Oxides (SOx)

The Best Available Retrofit Technology Analysis for Sulfur Oxides (SOx) was fUlly

described in Section 5 of the March, 2007 submittal.

3.1 Impact Analysis

Table 3-1 is a summary of the economic and environmental impacts associated with SOx

control effectiveness and reflects impacts on an individual boiler basis.

.-a

~~

...
Table 3-1

SOx Control: Economic and

Environmental Impacts for Each Coal-fired Boiler (NS-1A, NS-1B)

S02 CONTROL LEVEL, Ib/mmBTU 1.2 0.45 0,30

ECONOMIC IMPACTS:

Control Equipment Capital Costs $0 $2,330105 $4403381

Capital Recovery Factor N/A 0.1098 0.1098

Annual Capital Recovery Costs $0 $255,846 $443,963

Annual O&M Costs $0 $277,645 $1,312556

Annual Cost of Control $0 $533491 $1,756,519

ENVIRONMENTAL IMPACTS:

Tons per Year SOx Emissions 4662.1 1748.3 1165.5

Tons per Year SOx Reduction 0 2913.8 3496,6

Highest modeled 98'h percentile

deciview dv vaiues 0.566 0.404 0,384

Deciview reduction 0 0.162 0.182

COST EFFECTIVENESS':

Dollars per ton reduced N/A $183 $502

Incremental dollars par ton reduced N/A $183 $2099

Dollars per dv reduced N/A $3,293154 $9,651205

Incremental dollars per dv reduced N/A $3,293154 $61151421

, Cost effectiveness values are underestimated because the annual power costs and annualized

capital costs associated with downtime for control installation have not been estimated or included in

the calculation of these values.

Control equipment capital costs are estimated based on budgetary quotes from

equipment vendors. The capital recovery factor of 10.98 percent of capital costs is

based on a 7 percent annual interest rate and a contrellife of 15 years as outlined In

U.S. EPA's Control Cost Manual (6th Edition - January 2002). Annual operating and

maintenance costs reflect current FMC costs for labor and other services. The highest

modeled deciview values reflect the maximum 98th percentile value obtained from

modeling the visibility impact of the specific SOx control option (see Section 3.2). Cost

effectiveness values (dollars per ton reduced and dollars per deciview reduced) vary due
to differences in capital investment requirements and operating costs associated with

each option. The incremental cost effectiveness data are the cost of the control

alternative compared to the next most stringent control alternative.

3.2 SOx BART Visibility Analyses

The visibility impacts to the Bridger and Fitzpatrick Wilderness areas resuiting from

application of the SOx control alternatives were evaluated using the visibiiity assessment

methodology described in Section 2 of this document. Boiler source parameters,

baseline emission rates, and baseline visibility modeling results can be found in Section

2.6. Model input data for each of the SOx control alternatives are listed in Table 3-2.

Table 3·2

Emission Rates for SOx Control Alternatives

NS-1A

NS-1B

#6 coalfired boiler

#7 coalfired boiler

170

170

359,000

359.900

399.15

399.15

10.3

10.3

266.10

266.10

9.6

9.6

Visibility modeling results associated with the application of each option are listed in

Tables 3-3 and 3-4. These resuits depict the improvement in visibility over baseline

conditions from implementation of SOx controls.

Table 3-3

Visibility Modeling Results - SOx Control Option 1

NS-1A: # da s > 0.511dv

NS-1 B: # da s> 0.511dv

NS-1A: 98 ercentile lIdv

NS-1 B: 98 ercentile lIdv

0.404

0.404

0.358

0.357

0.386

0.385

0.241 0.234

0.241 0.235

0.187

0.187
Table 3·4

Visibility Modeling Results - SOx Control Option 2

NS-1A: 98 ercentlle lIdv

NS-1B: 98 ercentile lIdv

0,384

0,384

0,339

0,339

0,348 0,215 0,219

0,349 0,216 0,219

0,169

0,169

Conclusions from sax control option modeling:

• Visibility modeling indicates that application of either of the sax control options to

an individual boiler, even without any changes to other existing pollution control

equipment, results in visibility impacts from that unit that are below the Division's

0.5 dv guideline value for determining that a source contributes to visibility

impairment in any Class 1 area.

• Since there would be no perceptibie difference in visibility improvement as a

result of application of a particular control option, FMC proposes control option 1

(scrubber upgrade) as BART for sax.

Impiementation of sax control in conjunction with NOx control is discussed in Section 5.
4.0 Best Available Retrofit Technology Analysis - Nitrogen Oxides (NOx)

The Best Available Retrofit Technology Analysis for Nitrogen Oxides (NOx) was fUlly

described in Section 6 of the March, 2007 submittal.

In August 2007 low NOx burners with Overfire Air were retro-fitted in boiler NS-1A.

Computational Fluid Dynamic modeiing of these units, prior to their installation, indicated

that it would be possible to achieve an emission rate of 0.26 Ibs NOxlMMBTU. While

the 0.26 Ib/MMBTU emission rate has been demonstrated when the boiler is operated at

full load, it has not been possibie to sustain this rate at other boiler loads.

Boilers NS-1A and NS-1B are used to supply steam to the industrial process of

manufacturing soda ash. Uniike utiiity boilers, these two units are not base-loaded - they

react to the variable steam demands of the production process. The performance

history of boiler NS-1A, since installation of the retrofitted burners, indicates that the

boiler can achieve average emission rates approaching 0.33 Ibs NOxlMMBTU.

Consequently, the NOx BART effectiveness, economic and environmental impact

analyses for boilers NS-1A and NS-1 B have been revised to reflect a maximum emission

iimit of 0.35 Ibs NOxlMMBTU (310.4/bs/hr).

4.1 Control Technology Effectiveness

Boilers' NS-1A and NS-1 Boriginal NOX controls were designed to achieve a New Source

Performance Standard limit ofO.lO Ib/MMBtu (40 CFR 60 Subpart D). Table 4-1 presents

the NOx BART effectiveness summary.
Table 4-1

NOx BART Effectiveness for NS-1A and NS1-B

Replace existing burners, modify OFA ports,

lNBs, OFA, SCR instaH SCR s stem

lNBs, OFA, Replace existing burners, modify OFA ports,

SNCR instaH SNCR s stem

lNBs w. OFA Re iace existln burners and modi OFA arts 0.35(bl

Existin Control Baseline 0.70(01

, Data from: "Proposal For Burner Modifications and Overfire Air System Upgrades; Performance

Guarantee;" Prepared by Advanced Combustion Technology, Inc. 1106 Hooksett Rd. Hooksett, NH.

October 31,2006

(blBased on demonstrated ability of retro-fitted equipment and boiler heat Input capacity (887 MMBtu/hr)

(OIBased on original permit limit and boiler heat input capacity (887 MMBtu/hr)

4.2 Impact Analysis

Table 4-2 summarizes the revised economic and environmental impacts associated with the

NOx control effectiveness.

Table 4-2

NOx Control: Economic and

Environmental Impacts for Each Coal·fired Boiler (NS-1A, NS-1B)

NOx CONTROL lEVEL, Ib/mmBTU 0.7 0.35 0.21 0.1

ECONOMIC IMPACTS:

Control Equipment Capital Costs $0 $1,723,091 $3,160,918 $44,719,163

Capital Recovery Factor N/A 0.1098 0.1098 0.1098

Annual Capital Recovery Costs $0 $188976 $347,069 $4910,164

Annual O&M Costs $0 $224,169 $934,782 $3,231,013

Annual Cost of Control $0 $413145 $1,281,851 $8,141,177

ENViRONMENTAL IMPACTS:

Tons per Year NOx Emissions 2719.5 1359.8 815.9 388.5

Tons per Year NOx Reduction 0 1359.7 1903.7 2331.0

Highest modeled 98th percentile

declview dv values 0.566 0.432 0.368 0.321

Deciview reduction 0 0.134 0.198 0.245

...
COST EFFECTIVENESS':

Dollars per ton reduced N/A $304 $673 $3493

Incremental dollars per ton reduced N/A $304 $1,597 $16051

Dollars per dv reduced N/A $3,083172 $6,473 995 $33,229,294

Incremental dollars per dv reduced N/A $3,083172 $13,573,531 $145943,106

, Cost effectiveness values are underestimated because the annual power costs and annualized

capital costs associated with downtime for control installation have not been estimated or included in

the caiculation of these values.

Control equipment capital costs are estimated based on budgetary quotes from

equipment vendors. The capital recovery factor of 10.98 percent of capital cost is based

on a 7 percent annual interest rate and a control life of 15 years as outlined in U.S.

EPA's Control Cost Manual (6th Edition - January 2002). Annual operating and

maintenance costs reflect current FMC costs for labor and other services. The highest

modeled deciview values reflect the maximum 98th percentile value obtained from

modeling the visibility impact of the specific NOx control option (see Section 4.3). Cost

effectiveness values (dollars per ton reduced and dollars per deciview reduced) vary due

to differences in capital investment requirements and operating costs associated with

each option. The incremental cost effectiveness data are the cost of the control

alternative compared to the next most stringent control alternative.

4.3 NOx BART Visibility Analyses

The visibility impacts to the Bridger and Fitzpatrick Wilderness areas resulting from

application of the NOx control alternatives were evaluated using the visibility assessment

methodology described in Section 2 of this addendum. Boiler source parameters,

baseline emission rates, and baseline visibility modeling results can be found in Section

2.6. Model input data for each of the NOx control alternatives are listed in Table 4-3.

....... ' .
Table 4-3

Emission Rates for NOx Control Alternatives

NS-1A

NS-1B

#6 coalfired boiler

#7 coalfired boiler

170

170

359000

359,900

310.44

310.44

186.27

186.27

88.7

88.7

Visibility modeling results associated with the application of each option are listed in

Tables 4-4 thru 4-6. These resuits depict the improvement in visibility over baseline

conditions from use of NOx controls alone.

Table 4-4

Visibility Modeling Results - NOx Control Option 1

NS-1A: 98 ercentile lldv

NS-1 B: 98 ercentile lldv

0.432

0.432

0.302

0.303

0.393 0.252 0.247

0.394 0.252 0.248

0.206

0.206

Table 4-5

Visibility Modeling Results - NOx Control Option 2

NS-1A: 98 ercentile lldv

NS-1 B: 98 ercentile lldv

0.368

0.368

0.256

0.256

0.340 0.221 0.203

0.340 0.221 0.204

0.181

0.181

Table 4-6

Visibility Modeling Results - NOx Control Option 3

NS-1 A: 98 ercentile lldv

NS-1 B: 98 ercentile lldv

0.321

0.321

0.225

0.224

0.295 0.194 0.191

0.295 0.193 0.192

0.161

0.162
Conclusions from NOx control option modeling:

• Visibility modeling indicates that application of either of the NOx control options

to an individual boiler, even without any changes to other existing pollution

control equipment, results in visibility impacts from that unit that are below the

Division's 0.5 dv guideline value for determining that a source contributes to

visibility impairment in any Class 1 area.

• Since there would be no perceptible difference in visibility Improvement as a

result of application of a particular control 0 ption, FMC proposes control option 1

(low NOx burners with overfire air) as BART for NOx.

Implementation of NOx controls in conjunction with SOx controls is discussed in Section

5.

.~~

AUUlliIJ.. ···
5.0 Selection of BART for FMC Westvaco Sources

5.1 Combined Application of BART for sax and NOx Emissions

BART analyses for control of sax and NOx emissions were presented in Section 3 and

Section 4 respectively. The visibility modeling results for the exclusive application of any of

the sax or NOx control options on an individual boiler, even without any accompanying

changes to the other control eqUipment, indicated that visibility impacts to the wilderness

areas from that unit were reduced to levels less than 0.5 dv. The combined implementation

of both sax and NOx controis will result in even lower visibility impacts. Table 5-1

summarizes the source parameters for installation of the combined controls.

Table 5-1

Source Parameters for Visibility Analyses

Combined SOx and NOx Control

Exhaust Rale, ACFM

Stack Tem de. F

S02 ibs/mmBTU

Ibs/hr

I

H2S04Ibs/mmBTU

Ibs/hr

I

NOx Ibs/mmBTU

Ibs/hr

t

359,000

170

0.45

399.15

1748.3

1.16E-02

10.3

45.1

0.35

310.45

1359.8

359,000

170

0.45

399.15

1748.3

1.16E-02

10.3

45.1

0.35

310.45

1359.8

The modeled impacts on visibility in the two wilderness areas that result from the

simultaneous retrofit of sax and NOx controls on each boiler are shown in Table 5-2.

Table 5-2

Visibility Modeling Results - Combined SOx and NOx Control

NS-1A: 98 ercenille Lldv

NS-1 B: 98 ercentile Lldv

0.275

0.275

0.179

0.179

0.260

0.260

0.143 0.123

0.143 0.123

0.128

0.129
The data in table 5-2 indicate that application of both SOx and NOx controls on each boiler

produces modeled visibility impacts for each unit that are significantly less than the Division's

guideline value of 0.5 dv for determining that a source contributes to visibility impairment in

Class 1 areas.

5.2 BART Proposal

The analyses presented in this addendum demonstrate that the application of SOx and NOx

control options, individually, but particularly in combination, result in significant improvement

in visibility impacts in the Class 1wilderness areas. It has also been shown that the capital

investment and annualized cost of achieving additional fractional (but imperceptible)

improvements in visibility are extremely high. Consequently, FMC proposes the application

of SOx scrubber upgrades and low NOx burners with overfire air as BART for coal-fired

boilers NS-1A and NS-1 B.

FMC requests pound per hour (Ibs/hr) emission limits for S02 and NOx based on a 30-day

rolling average for each parameter that is calculated by BART Ibs/mmBTU x max heat input.

The proposed emission limits for each boiler would be:

S02: 0.45lbs/mmBTU x 887 mmBTU/hr= 399.151bs/hr

NOx: 0.35lbs/mmBTU x 887 mmBTU/hr = 310.451bslhr

The FMC Westvaco coal-fired boilers supply steam to the soda ash production process.

Consequently the boilers are routinely subject to load swings based on production conditions

and associated steam requirements. Establishing the emission limits in Ibs/hr will not unduly

penalize boiler operations in circumstances where these ioad swings result in higher rate

emissions (Ibs/mmBTU), but lower mass emissions (Ibs/hr).
Appendix 1

Cost Effectiveness Analyses Detail •

SOx and NOx Control Alternatives
Gost Effectiveness AnalysIs. S02 Control Alteratives

Demlsters + Scrubber

Scrubber Top + mods + Stack

Control 0 tlon 8asellne Stellc Mixers Reheet

EmIssion Rate, Ib/MMBTU 1.20 0.45 0,'

Emission Rate, lonsiyr 4662.1 1748.3 1165,5

Emission Rate Reduction, tonslyr 2913.8 3496.8

%Reducllon 62.5% 75.0%

Ib/hr 1064.4 399.1 266.1

capital Costs

Dlreot Costs

Purchased EqulpmentCosts

New Bypass Ductlng • 75,000 • 75,D00

Expansion Joints • 24,000 • 24,000

Scrubber RoOf • 77,700 • 162,900

Scrubber demlster • 162,900 • 77,700

Wash & purge lines • 12,000 • 12,000

Scrubber Instrumenlallon • 20,000 • 20,000

Flue gas reheat system • 697,700

Sales Tax (5.5%) • 20,438 • 53,465

Freight (4%) • 14,684 • 42,772

Subtotal (PEC) • 406,902 • 1,165,537

DIrect Installation Costs

Labor • 858,700 • 1,133,600

OutsIde Engineering Support • 230,750 • 346,125

Demolish existing ductlng & roof • 36,600 • 36,600

Rental crane for roof • 50,000 • 65,000

Subtotal • 1,176,050 • 1,581,325

Total Direct Costs (TDC) $ 1,582,952 $ 2,746,862

Indirect Costs

Indirect Installation Costs

Engineering (15%TDC) $237,443 $412,029

Escalation (12% of TOC) $169,954 $329,623

Slartup and Perf. Tests (1 %of TOC) $15,830 $27,469

Total Indirect Costs $443,227 $759,121

TOC + TIC $2,026,179 $3,515,983

Contlngenc:y (15%) $303,927 $527,398

Annual

Direct Annual costs

Direct Lebor (@$48/hr) I 52,560 • 78,840

Malnt. Labor (@$5D/hr) $ 50,000 I 75,000

Replacement Parts (5% of PEG) • 20,345 • 58,277

Steam generation cost • 846,400

Total Direct Annual Costs I 122,905 • 1,058,517

Indirect Mnual costs

Ovemead( (60% Of Jabor) • 61,536 • 92,304

Property Tax (1% of TCI) • 23,301 • 40,434

Insuranoe (1% orrcr) • 23,301 $ 40,434

Administration (2% of TCI) • 46,602 • 80,868

Tota/lndlrec:t Annual Costs • 154,740 • 254,039

Control carital recovery costs

Tolal Annualized Cost

Demrsters Scrubber mods +Stack Reheat

Demisters +Scrubber Top +Static Mixers

Baseline

255,846 • 443,963

, 633,491 •1,756,519

DeclYlew Total Tolal Average Incremental

Reduollon Capital Annualized Cost eo"

Emissions 98th Percentile over baseline Investment Cost

0,' 0.384 0.182 • 4,043,381 $1,756,519 • 9,651,205 $ 61,151,421

0,46 0.404 0.162 • 2,330,105 • 633,491 3,293,154 • 3,293,154

1,2 0,566

Note: In the lable above, the capital Investment costs and annUalized costs reflect the cosls to

modify each coal-fired boiler. Cosl effectiveness values are underestimated beoausa the annual

power costs and annualized capital cosls associated with downllme 10r controllnslallalion have not

been estimated or Inoluded In the calculation of these values
Control Option

Emission Rate, IbfMMBTU

Emission Rate, tonslyr

Emission Rate Reduction, tons/yr

% Reduction

Ibfhr

Baseline

0.7

2719,5

620.9

Cost EffecllYeness Analysis - NOx Control A1lernatiYes

burners w. burners w. w. OFA, SCR,

u raded OFA OF SNCR ba house

0.35 0.21 0.1

1359.8 815.9 388.5

1359.7 1903.6 2331.0

50.0% 70.0% 85,7%

310.44 186.27 86.69

Capllal Costs

Direct Costs

Purohased EqulpmentCosfs

Low NOx Burners

Enlarge oYerflre air ports

Indlllldual OFA port dampers

Class 1 Igniters

New burner elbows

instrumentation

Pumps & Piping

SNCR

SCR

Taxes (5%)

Freight (4%)

Subtolotal (PEC)

Direct Installation Costs

Labor

Outside Engineering Support

Matertals

Subtotal

I

I

I

I

235,000 $

100,000 $

40,000 $

31,800 $

88,000 $

136,000 $

I

I

I

30;530 $

24,424 $

665,554 $

258,500 $

230,750 $

I

489,250 $

235,000 $

100,000 $

40,000 $

40,000 $

68,000 $

200,000 $

372,500 $

50,000 $

I

55,275 $

44,220 $

1,204,995 $

631,000 $

230,750 $

I

861,750 $

235,000

100,000

40,000

40,000

68,000

200,000

50,000

8,790,927

478,196

380,957

10;381,081

7,550,373

1,707,430

397,600

9,655,403

Total DIrect Costs (TDC) $ 1,154,804 $ 2,066,745 $ 20,036,483

Indirect Costs

Indirect Installation Costs

EngIneering (15% of TOC)

Escalation (12% of TOC)

hJx. gas costs

Startup and Perf. Tests

Total Indlrsct Cosls

TOC + TIC

Contingency (15%)

$173,221 $206,675

$138.576 $310,012

I I

$30,000 $50,667

$341,797 $567,354

$1,496,601 $2,634,099

$224,490 $526,820

$2,003,648

$3,005,473

$12,000,000

$220,365

$17,229,486

$37,265,969

$7,453,194

Annual Costs

Direct Annual costs

DIrect Labor (@$481hr)

Main!. Labor (@$5OIhr)

Replacement Parts (5% of PEC)

Reagent Replacement

Catalyst Replacement

Total DIrect Annual Cosls

Indireot Annual costs

OYerhead( (60% of labor)

Propoerty Tax (1% of TCI)

Insurance (1% efTCI)

Administration (2% of TCI)

Total IndIrect Annual Cosls

$

I

$

$

•

$

$

$

I

26,280 $

50,000 $

33,278 $

I

109,558 $

45,768 $

17,211 $

17,211 $

34,422 $

114,612 $

52,560

75,000

60,250

544,000

731;810

76,536

31,609

31,609

63,218

202,973

105,120

90,000

519,054

311,000

300,000

1,325,174

117,072

447,192

447,192

894,383

1,905,839

Control capital recoYery costs

Total Annualized Cost

347,069

413,145 $ 1,281,851

Daclview

Reduction

oYer baseline

4,910,164

8,141,177

Total

Capital

Investment

Total

Annualized

Ccst

Incremental eo,(

EffeCtiveness

$/declview reducllon

..,:~

Lcw NOx burners w. OFA, SCR, baghouse

Low NOx burners w. OFA, SNCR

Low NOx burners w. upgraded OFA

Baseline

0.1

0.21

0.35

0.7

0.321

0.368

0.432

0.566

0.245

0.198

0.134

44,719,163

3;160,918

1,721,091

8,141,177 $

1,281,851 $

413,145 $

33,229,294 $

6,473,995 $

3,083,172 $

145,943,106

13,573,531

3,083,172

Note: In the table aboYe, the capltallnvastment costs and annualized costs reflect the costs to

modify each coal-fired boiler. Ccst effecllYeness values are underestimated because the annual

power costs and annualized capital costs associated wUh downtime for ccntrollnstellallon haYe not

been esl1mated or Included In the calculatlcn of these values
Cost Effectiveness Ana!;'sls. NO)!

ControlO '" aaseline

Emlsslon Rate, IbIMMBTU 0,7

Emlsslon Rale, lonslyr 2719.5

Emission Rate ReducUon, Ionslyr

%RodueUon

'''''' 620.9

CapilalCosts

1O'\1 1819 Purchased EqulpmlJrllCosts 20"" f<J"l 1", LowNOxBurners , 235,000 , 235,000 , 235,000

Enlarge overfiro air porls , 100,000 , 100,000 , 100,000 ~"l .1} ~'ii> IndlYldual OFA port dampers , 40,000 , 40,000 , 40,000 C1858 1111nilers , 31,600 , 40,000 , 40,000 r: R New burner elbows , 6a,000 , 69,000 , 613,000 ~lrC£/v, InslfUmenleUon , 136,000 , 200,000 , 200,000 iY cD i" ... FEB (,\1 Pumps & Plplng , , 372,500 , 50,000

SNCR .' 200. '" , , 50,000 ,

seR A/RQUAl! '8 f{} , , $ 0,790,927

Texell(6%J , 30,530 , 55,275 , 476,196

FreIght (-1%) f)/ViSIOf'{rr , 24,424 , 44,220 , 3eO,957

SrtIJfololal (PEC} , 665,554 $ 1,204,995 , 10,361,081

<:"9 Direct InslallallonCOllis

Labor , 258,500 , 631,000 , 7,550,373 -9t>S- <'L __ "... Outslcle E:nglooorlng Support • 230,750 , 230,760 • 1,707,430

Materials , , , 397,600

Sublo/el $ 489,250 , 681,760 $ 9,655,403

Total DirectCosls (TOC} S 1,154,804 $ 2,066,745 S 20,036,483

lodjfQGI CQils

Indirect Inslallatlon Cosls

EngIneering (15%of TOC) $173,221 $206,675 $2,003,648

EscalaUon(12%01 TOC) S136,576 $310,012 $3,005,473

Aux.. gas cosls , $12,000,000

Slartupand Perf. Tesls $30,000 $50,667 $220,365

Tofal /ndfrect Costs $341,797 $567,354 $17,229,486

TDC +TfC Sf,496,601 $2,634,099 $37,265,969

ConUngem:y(I6%' $224,490 $526,920 $7,453,194

Tolal Cup~all~all~rIt (TCI) -' 1,721,091 .$ .~,1t?Q,{l18 , 14,7.!.l),ti33

AMualCos!s DlleC! AnnUAl GQ~!s

OJrecILabor(@$46Ihr) , 26,280 • 52,560 $ 105,120

Mulf'lt Labor (@$5GAn) S 50,000 $ 75,000 • 90,000

Replacomant Paris (5% or PECl $ 33,278 , 60,260 S 519,054

Reegent Replacement , 544,000 , 311,000

Calalysl Replacolll9nt , 300,000

rotel DlI'6c1AnnuillCosl$ , 109,558 731,610 $ 1,325,174

Indiracl Annual eelsls

OV8rheatS( (60% 01 raoor) , 45,768 $ 76,536 $ 117,072

PropoeflyTaK (n~ 01 TCI) S 17,211 , 31,609 , 447,192

Insurance (1% oITCI) $ 17,211 , 31,809 • 447,192

AdmlnlstraUon (2% 01 TCI) S 34,422 $ 83,218 , 694,363

Totallndil'6cl Annuel Costs S 114,612 , 202,973 $ 1,905,839

TotalAooual O&M CoslS 224.169 , {l34,.~!,~ , 3,~31,01a, ,

Conltol capilal recovery cosls , 169,976 • 347,069 $ 4,910,164

Total AnMa&zadCost , 413,146 S 1,281,851 , 8,141,177

Deelvlaw TOlal Tota! Averaga Incremantal

ReducUon Capillil Annuaized Cosl Cosl

Emissions 96th PelcenUle over bassgne Investment C051 Effectiveness ElfecQvaness

Conlrol Alternative .1~5IMMBTU dvValua " , $lyr S!cte?lviaw raducllon <$/daClvlnw radoollon .. -.

LowNOx burnarsw. OFA, SCR, baghouse 0.1 0.663 0.461 , 89A36,328 $ 16,282,354 , 35,319,640 S 161,395,906

LowNOx burners w. OFA, SNCR 0.21 0.748 0.376 , 8,321,637 , 2,563,702 , 6,616,356 S 31,025,214

Lew NOx !lorlltlrs w. upgraded OFA 0.26 0,604 0,320 • 3,442,182 , 626,290 , 2,562,156 $ 2,582,158

Baseline 0.7 1-124

Nole; In this labla, Ilia copltallnvaslillant cOsls and aMualizad costs ranecllhe cO$ls 10 modify both

coal-tired boilers. Tills r~ conslstenll'oilh the v1slbt~ty ana!;'sls daclview data Which reflect

Implemenlation of controls on both boilers.
Cosl Errecllvenl)ss Analysis - Partlculale

By-pass

Control Dollon Basellna Pollshfnll Filler WeI ESP Fabric Filter

EmIssIon Rale, Ib/MMBTU 0.0507 0.040 0.019 0.015

EmissIon Rale,lbJ1lr •• 35.5 16,9 13.3

Emission Rale, lonslyr 197.0 155.4 73.8 58.3

Emission Rale Reducllon, lonslyr 41.6 123.2 138,7

% Reducllon 21.1% 62,5% 70.4%

CepUsl Cosls

Dlrec! Coals

Purchased aqulpmentCos!s

BasIc &Awc Equip!. Costs 5 2,673,119 S 6,321,500 S 6,040,927

SIr'\lctllral Support (10%) 5 267,312 S 632,150 S 604,093

Ductwork S' x 9' S 05,ZOO S $

Ductwork 9' x 15' $ 5 S 268,600

Ductwork 10' x 13' 5 S 128,800 5 128,800

Sales Tax (5.5%) S 166,980 S 389,535 S 387,344

FreIght (4%) 5 121,425 5 283,200 $ 281,705

Subtotoal (PEC) 5 3,324,018 5 7,755,263 $ 7,711,669

Direct lostallonon Cosis

labor 5 2,537,397 S 5,163,080 S 6,600,373

Adjust. for Relrofil Condllions S 986,561 S 2,023,931 S 2,364,944

Malarlals 5

Subtotal $ 3,525,958 5 7,186,991 $ 9,165,316

Tottil Direct 00'($ (TOC) S 6,849,974 S 14,942,274 $ 16,876,985

IndIrect Costs

IndIrect loslallallon Costs

Engineering (15% of PEC) $491),602 $1,163,292 $1,156,750

EscaloUon (12% ofTOC) $821,997 $1,793,073 $2,025,236

AUK. gas cosls 50 $0 50

Sler1up and Perf. Tests $78,500 $159,423 $178,770

Totar indirect Cosls $1,399,099 $3,116,788 $3,360,758

TDC+TIC $6,249,073 $18,058,062 $20,237,743

Connngency (16% ofTOC) $1,237,361 $2,708,709 $3,036,682

I,o,l!1' 9~~I~ll:'!t:'~~,s,~.e~t, (r~!) ,. _t!,~~~,~ s .29..?~~,n~. 5 23;273,405

. :'~'>--"'::""~"-:': '."'., '. ,:\,--: . --',

Annual Cosis

plroc! Annual cos!s

Direct Labor (@$461hr) 5 52,560 5 52,560 S 62,660

Malnl.labor (@$50ihr) 5 75,000 S 50,000 S 100,000

Replacement Parts (3·5% of PEC) 5 166,201 S 232,656 S 365,663

Electricity ($O.04/kw*hr)

Total DIrect Annua1 Cosls S 293,761 S 335,216 5 538,143

Indirect Annual cosls

Overhead( (60% of labor) 5 76,536 S 61,536 S 91,536

PropoertyTBX(1% of TCI) S 94,004 S 207,668 S 232,734

Insurance (1% oITCI) 5 94,664 $ 207,668 S 232,734

Admlnlstrallon (2% ofTCI) 5 169,729 S 415,335 5 465,466

Total (ndfrectAnnual Co.sls S 455,993 S 892,207 5 1,022,472

.rC?l~IAn.rnl.al O&M Cosls S 749,764 S .1,.~~7~42.5. 5 1,56.0,61.~.

','

Control capital recovery costs S 1,041,610 S 2,260,192 5 2,555,420

Tolal Annualized Cosl S 1,791,365 5 3,507,617 S 4,116,036

EmissIons Tolal Tolal Average Incremenlal

ReducUon Cepllal Annualized Cost Cost

Emissions Emlllslons over base Inveslmenl Cost Effecllveness EifecUvenes$

Control Altstnatlve l~s~~~"!:U 1.~n~Iy.~ , ", lon.sly!, -~ -. SIy,- I"·~?n,, .. ~t.on

;Fabn:~:~I{i~; . 0.016 68.3 -

136.7 S 23,273;405' s 4,11'6~O36 lif :-2t~j.; S 39,151

Wet ESP 0,019 73.8 123,2 5 20,766,772 $ 3,607,617 $ 26,481 S 21,036

By-pass PolishIng Filler 0.04 155.4 41.8 5 9,400,434 $ 1,791.365 5 43,003

Baseline 0.0507 197,0
Cost EfroolivllMU Ar'Ill!jsIS· 802 COIll/ols

Deffilslers .j. StnlbOOr

SCfubber Topt mods +Stack Conl/olQJl:\I~!L,, ________,___" ,[3;a&1l • SloUt lAix..~!.L. • Reheat

EmissIon Itale, Ib.'MMBTU 1.20 OA' 0.3-

Emission Ratartonslyr 46,6,2.1 1746.3 116&.5

Emission Ratti RllducUon, tOIlSfy'1 2b13.0 :?4116,6

% ReducUon 62.6% 75.0%

""" 1064.4 399.1 286.1

CapilalCos15

Pllrcllasf!d t::quipmllnICosl&

NQwB~pass OucllnrJ $ 71>,000 $ 75,000

Expam;lonjolnts • 24,000 , 24,000

SCwbber Roof S 77,700 , 162,900

SOIl.lbber den~sh1r S 162,900 , 77,700

Wosh&pu!j)(l'OOS S 12,000 , 12,000

Stwb!xlf InslrumonUlUon , 20.000 S 20,000

FillQ gas reheal s~stom S 691,100

Sakls Tnx (5.5%) S 20,436 , 53,465

Flelglit(4%) 5 \4,864 S <\2,712

Sub/alel/PEW; S 400,902 , 1.165,637

Olrl)CllnstaUallOflCosls

l.abor 856,700 , 1,133,600

Ou1sldG Englnoonog Support 230.700 S 346,125

Damo_sh OOIlsUng dueling &rool 36,600 , 36,600

Rllmal crllne lorrool 50;000 S 65,000

Sublolel 1.176,050 , 1,561,326

fo/al D/liu,/ Cl»ls(rDC) $ 1,582,!}/32 S 2,746,M2

"""'lJ&mIndi~(;\ InstallallOl1 C(lsb

F..nglooarlng (15%TDC) $237,443 $412,0211

Escalation (12% Of TOO) $16\1,\164 $329,623

Startup aOO Parf. Tos!s (1% of rDC) $15J130 627,469

To{a/lndlrocl Costs $443;227 $7(;9,121

roc +TIC $2,026,179 $3,515,983

Conlf/IiJa/lcy 116%) $3001,927 $627,398

Annl.lalCosl$

Qlf!l¢! Annual cosls

Direct tabor (@S4l!!tJr) S 52,560 , 78,840

Malnl Labor (@ S5OJlv) S 50,000 , 75,000

RaplllO!l1l'\l'lfll Parts (5% of PEC) S 20,345 S 5&,277

Staamgeneration cost S a46,40{1

70lel DI(9I;/ Anrlliel Cosis U2,905 , 1,058,517

~I.I/ll~

Ovarhead( ((10% or moor) S 61,536 , 1'12,304

Properly Tax (1% ofTCI) , 23,301 , 40,434

In&vrunco (1% crrCl) , 23,301 S 40,434

Adrnlnlal/llUon (2% of Tel) , 46,602 , 90,989

Tolal/mHrecl Annual Cosls , 154,740 $ 254,039

Control oapltal recov(lry cosls 266,846 443,063

Tollli Armalizod Cosl S33,491 , 1,756,519

Deolvlow

RocucUPIl

En~$g!ol\$ 96th PefellntllG ol'Olooaatioo

Ibs!M_~!3J~

Damlalers +Scrubber Top + S\e~c Mlxar!

BaSE/liM

0.3

0,45

1.2

();70~

1.023

1.124

Q.421

0.101

l.\0fl6,762 $3,513,039 S

$ 4,000,211 $1,066,982

6.344,&10

10,564,176

1,643,928

Nole: IrlltII! tabla, Il1e tapllallnveslment iio"s"(i"llI'ld annlJa~lad OO$lS rBflacfUie"costs to m~dlfy bo1l1

c~a~nred bollars. '"hlsls cor.slsia/lll'>llh tlltl'll$lbMy llnalysls (/(Jclvlawdo!lll'lhich r&flect

Impi(lrtlllnta~oll of controls 011 bol.h bolklrs.