### Best Available Retrofit Technolog y Analy s is

For

Sherburne County Ge nerating Plant

Units 1 and 2



## Prepared by

Northern States Power Co.

d/b/a Xcel Energy

October 25, 2006

### Table of Contents



## 1.0 Executive Summary

................................................................................ 1



## 2.0 Introduc tion

............................................................................................... 3



## 3.0 Baseline Conditions and Visibility Im pacts for B A RT-eligible Units

............. 6



## 4.0 BART Analysis for BART-Eligible Emissio n Units

............................. 7

4.A Sulfur Dioxide Emission Contro ls - Emission Unit EU001 / EU002

......................... 7

4.A.1 Available Retrofit Control Technologies

..................................................... 7

4.A.2 Technically Infeasible Options

.................................................................. 17

4.A.3 Control Effectiveness of Remaining Control Technologies

...................... 18

4.A.4 Impact Analysis

........................................................................................ 18

4.A.5 Energy Impacts

........................................................................................ 23

4.A.6 Non-Air Quality Environmental Impacts

................................................... 23

4.A.7 Remaining Useful Life

.............................................................................. 23

4.A.8 Visibility Im pacts

....................................................................................... 23

4.A.9 Proposed SO 2 BART

................................................................................ 27

4.B Nitrogen Oxides Emis sion Controls – Emission Units EU001/EU002

................. 28

4.B.1 Available Retrofit Control Technologies

................................................... 28

4.B.2 Technically Infeasible Options

.................................................................. 41

4.B.3 Control Effectiveness of Remaining Control Technologies

...................... 42

4.B.4 Impact Analysis

........................................................................................ 42

4.B.5 Energy Impacts

........................................................................................ 47

4.B.6 Non-Air Quality Environmental Impacts

................................................... 47

4.B.7 Remaining Useful Life

.............................................................................. 47

4.B.8 Visibility Im pacts

....................................................................................... 47

4.B.9 Proposed NO

x BART

................................................................................ 51

4.C Particulate Matter Emission Contro ls – Emission Units EU001/EU002

............... 52

4.C.1 Available Retrofit Control Technologies

................................................... 52

4.C.2 Technically Infeasible Options

.................................................................. 62

4.C.3 Control Effectiveness of Remaining Control Technologies

...................... 62

4.C.4 Impact Analysis

........................................................................................ 62

4.C.5 Energy Impacts

........................................................................................ 65

4.C.6 Non-air Quality Impacts

............................................................................ 65

4.C.7 Visibility Im pacts

....................................................................................... 65

4.C.8 Proposed PM 10 BART

.............................................................................. 65

Page i4.D Multipollutant Controls – Emissions Units EU001/EU002

................................... 66

4.D.1 Available Retrofit Control Technologies

................................................... 66

4.D.2 Technically Infeasible Options

.................................................................. 70



## 5.0 Conclusions

............................................................................................ 71

Appendix A

.......................................................................................................... 76

Appendix B

........................................................................................................ 100

Page ii

### List of Figures

Figure 1. Process Fl ow Diagram of a Spray Tower Wet FGD S ystem

...................................... 8

Figure 2. Cutaway View of a Je t Bubbling Reactor Wet FGD System

....................................... 9

Figure 3. Spray Dryer System

................................................................................................. 11

Figure 4. SDA FGD System

.................................................................................................... 11

Figure 5. Circulating Dr y Scrubber System (Lurgi Lentjes North America)

.............................. 13

Figure 6. Least Cost Curve - Unit 1 SO 2

................................................................................. 21

Figure 7. Least Cost Curve - Unit 2 SO 2

................................................................................. 22

Figure 8. SO 2 Visibility Impacts at BWCA

............................................................................... 26

Figure 9. Staged Co mbustion of low NO

x burners and overfire air system

.............................. 31

Figure 10. Mobotec ROFATM and ROTAMIXTM Simplified Process Flow Diagr a m

.................. 32

Figure 11. ECOTUBE Installation in a Boiler

........................................................................... 34

Figure 12. Schematic Diagram of a Typical SCR reactor

........................................................ 35

Figure 13. Schematic of SNCR S yst em with Multiple Injection Leve l s

.................................... 37

Figure 14. Schematic of Gas Reburn System

......................................................................... 41

Figure 15. Least Cost Curve - Unit 1 NO

x

............................................................................... 45

Figure 16. Least cost Curve - Unit 2 NO

x

................................................................................ 46

Figure 17. NO

x Visibility Impacts at BWCA

............................................................................. 50

Figure 18. Electrostatic Pr ecipitator System (MHI)

.................................................................. 53

Figure 19. Pulse Jet Fabric Filter Compartment

...................................................................... 55

Figure 20. COHPAC Arrangement

.......................................................................................... 57

Figure 21. Max-9 Elec trostatic Filter

........................................................................................ 58

Figure 22. Multi-cyclone Particulate Collect or

......................................................................... 59

Page iiiFigure 23. Multiclone

............................................................................................................... 59

Figure 24. ECOTM Process Flow Diagram

............................................................................... 67

Figure 25. Pahlman ProcessTM Simplified Pr ocess Flow Diagram

.......................................... 68

Figure 26. Phenix Clean Coal Pr ocess Flow Diagram

............................................................. 69

Figure 27. SO 2 Visibility Impacts at BWCA

........................................................................... 100

Figure 28. NO

x Visibility Impacts at BWCA

........................................................................... 101

Figure 29. SO 2 Visibility Impacts at BWCA

........................................................................... 102

Figure 30. NO

x Visibility Impacts at BWCA

........................................................................... 103

Figure 31. SO 2 Visibility Impacts at IR

................................................................................... 104

Figure 32. NO

x Impacts at IR

................................................................................................ 105

Figure 33. SO 2 Visibility Impacts at IR

................................................................................... 106

Figure 34. NO

x Visibility Impacts at IR

................................................................................... 107

Figure 35. SO 2 Visibility Impacts at VNP

............................................................................... 108

Figure 36. NO

x Visibility Impacts at VNP

............................................................................... 109

Figure 37. SO 2 Visibility Impacts at VNP

............................................................................... 110

Figure 38. NO

x Visibility Impacts at VNP

............................................................................... 111

Page iv

### List of Tables

Table 1. Summary of Proposed BART

...................................................................................... 2

Table 2. Baseline Condi tions Modeling Input Data

.................................................................... 6

Table 3. Basis for 24 Hour Act ual Emissions Data in Table 4

................................................... 6

Table 4. Baseline Vis i bility Modeling Results

............................................................................ 6

Table 5. Control Effectiveness for SO 2 Reduction Technologies

............................................ 18

Table 6. Unit 1 SO 2 Complianc e Costs

................................................................................... 20

Table 7. Unit 2 SO 2 Complianc e Costs

................................................................................... 20

Table 8. SO 2 Post-Control Emission Rates fo r Emission Unit EU001/EU002

......................... 24

Table 9. SO 2 Post-Control Stack Parameters for Emission Un it EU001/EU0 02

...................... 24

Table 10. SO 2 Controls - Visibility Modeling Results

............................................................... 24

Table 11. Incremental Visibility Costs at BWCA for SO 2 Control

............................................. 25

Table 12. Control Effectiveness for NO

x Reduction Technolo g ies

.......................................... 42

Table 13. Unit 1 NO

x Complianc e Costs

................................................................................ 44

Table 14. Unit 2 NO

x Complianc e Costs

................................................................................. 44

Table 15. NO

x Post-Control Emission Rates for Emission Unit EU001/EU002

....................... 48

Table 16. NO

x Post-Control Stack Parameters for Emission Unit EU001/EU002

.................... 48

Table 17. NO

x Controls - Visibility Modeling Results

............................................................... 48

Table 18. Incremental Visibility Costs for BWCA for NO

x Control

........................................... 49

Table 19. Control Effectiveness for PM 10

................................................................................ 62

Table 20. Unit 1 PM 10 Complia n c e Costs

................................................................................ 64

Table 21. Unit 2 PM 10 Complia n c e Costs

................................................................................ 64

Table 22. Emission Unit EU001/ EU002: Su mmary of the Impacts Analysis for SO 2 , NO

x , P M 10

Control Sc enarios

..................................................................................................... 73

Page vTable 23. Visibility Model ing: Baseline Model Results

............................................................. 74

Table 24. Visibility Model ing: Boundary Waters Results

......................................................... 74

Table 25. Visibility Modeling: Voyageur National Park Results

............................................... 74

Table 26. Visibility Model ing: Isle Royale Results

................................................................... 75

Page viPage 1 of 111 

## 1.0 Executive Summary

The Regional Haze Rule ca lls for state and federal agencies to work together to

improve visibility in 156 national parks and wilderness areas. Each state must modify

its State Implementation Plan (SIP) to incorporate measures necessary to make

reasonable progress toward the national visibility goal, in cluding requirements that

certain existing stationary sour ces install, operate, and mainta in Best Available Retrofit

Technology (BART). For Unit s 1 and 2 at Xcel Energy’s Sherburne County Generating

Plant (Sherco), the Minnesot a Pollution Control Agency (MP CA) determined that Xcel

Energy must evaluate what consti tutes BART for nitrogen oxides (NO

x ), sulfur dioxide

(SO 2 ), and particulate matter less than 10 microns (PM 10 ). The regulations also provide

that a state participating in the Clean Air Interstate Rule (CAIR), which includes

Minnesota, need not require BART -eligible electric generating units to install BART,

because EPA’s analysis concluded that CAIR controls are “better than BART” for

electric generating units in states subject to CAIR. The MPCA has stated that it will

determine whether CAIR substitutes for BART after BART analyses have been

submitted. Since EPA conc luded that CAIR will provide more visibility improvement

than BART, Xcel Energy believes Sherco Un its 1 and 2 should not be given BART limits

and instead CAIR should drive emission r eductions. Nevertheless, a BART analysis

has been performed as required for Sherco Un its 1 and 2, and is presented in this

report.

MPCA guidance for the BART ana lysis lists a presumptive NO

x limit of 0.15 lb/MMBTU

for units such as Sherco Units 1 and 2. Sher co 1 currently utilizes an overfire air (OFA)

system and burners that will not allow the unit to achieve the presumptive NO

x limit for

BART. Sherco 2 utilizes low NO

x burners (LNB) and a separated/ close coupled overfire

air system to control NO

x . In response to the CAIR progr am, Xcel Energy is committed

to the installation of LNBs, a separated/ close coupled overfire air system, and a

combustion optimization (CC) system for Sherco Unit 1 for NO

x control in 2007. All

control options for Sherco 1 in clude the costs for t hese projects. Likewise, Xcel Energy

is installing a comput er based CC system for NO

x control for Sherco 2 in 2006. All

control options for Sherco Unit 2 include the co st for this project. These changes to the

boilers will bring NO

x emissions for Sherco Units 1 and 2 to 0.15 lb/MMBTU. Xcel

Energy proposes to meet t he presumptive limit of 0.15 lb /MMBTU at the stack, on a

30-day rolling average. The proposed changes will be complete by the end of 2007,

and compliance demonstra ted by the end of 2008.

There are no presumptive limits for SO 2 for boilers with existing co ntrols that achieve at

least 50% removal. SO 2 is controlled by wet flue ga s desulfurization (FGD) systems

(scrubbers) for each unit, which currently achieve 75% removal. Xcel Energy proposesPage 2 of 111 to retrofit the existing scrubbers with sparger tubes and lime injection. The applicable

emission limit would be 0.12 lb/MMBTU at the stack, based on a 30-day rolling average.

These changes would be in place by the end of 2012

.

PM 10 is controlled by wet scrubbers and wet elec trostatic precipitators (WESP). Xcel

Energy notes that there are no controls at this time for condensable PM 10 . No

technology would significantly improve the par ticulate control from current levels at

Sherco Units 1 and 2. As the cost-effect iveness was so high for all options, no new

technology is proposed for PM 10 . Because no new technology is proposed, no change

to the permit limit is proposed.

Emission modeling predi cts that Sherco Units 1 and 2 have the greatest effect on

visibility in the Boundary Waters Canoe Area (BWCA), as compared to Voyageur

National Park (VNP) and Isle Royale (IR), regar dless of whether the effect is measured

by the number of days with visibility impairment (visibility impairment > 0.5 deciview), or

by the change in impairment at the 98 th percentile. The proposed controls and visibility

improvements (for t he BWCA) are summarized in Table 1 below.

The proposed BART controls and emission limits wil l result in significant visibility

improvement. This proposed control equipment also provides Xcel Energy flexibility in

determining a compliance strategy for mercur y control requirements under the Clean Air

Mercury Rule (CAMR) and the Minnesota Merc ury Reduction Act, as well as for CAIR

Phase II.

Table 1. Summary of Proposed BART

Emission Unit Proposed

BART

Control Pollutant(s)

Controlled Proposed

BART

Emission Limit Visibility

Improvement

on 98 th

percentile

Day 1 Class I

Area(s)

Impacted

EU001/EU002 Retrofit existing

FGD System

with sparger

tubes and lime

injection for

Sherco 1 &

Sherco 2 SO 2 0.12 lb/MMBTU 2.13 BWCA

EU001/EU002 LNB/SOFA –

Sherco1;

Combustion

Optimization –

Sherco 1 &

Sherco 2 NO

x 0.15 lb/MMBTU 2.11 BWCA

1 Baseline 98 th percentile was 2.68 dvPage 3 of 111 

## 2.0 Introduction

In 1999, the U. S. Environmental Prot ection Agency (EPA) announced the Regional

Haze Rule, a major effort to improve visibility in 156 nat ional parks and wilderness

areas. The rule requires states, in coor dination with the EPA, the National Park

Service, U.S. Fish and Wildlif e Service, the U.S. Forest Se rvice, and other interested

parties, to develop and implement air quality protection plans to reduce the pollutants

that cause visibility impai rment, nitrogen oxides (NO

x ), sulfur dioxide (SO 2 ), and

particulate matter less than 10 microns (PM 10 ).

Each state must modify its State Implementation Plan (SIP) to include emissions limits,

schedules of compliance, and ot her measures necessary to make reasonable progress

toward meeting the national visibility goal, including the implementation of Best

Available Retrofit Technology (BART) fo r certain major stationary sources (BARTeligible sources). BART-eligible source s are identified as selected sources (e.g.

coal-fired power plants with more than 250 MMBTU/hour heat input) that were not in

operation prior to August 6, 1962, were in existence on August 7, 1977, and have the

potential to emit 250 tons per year or more of any visib ility impairing air pollutant.

For Xcel Energy’s emission units in Minnesota, Sherburne County (S herco) Units 1 and

2, Riverside Unit 8, and A.S. King Unit 1 were all potentially BART-eligible. As a result

of the Metro Emissions Re duction Project (MERP), Riverside Unit 8 will be

decommissioned prior to the time Xcel Energy would have been required to comply with

BART regulations. Results of visibility modeling conducted by the Minnesota Pollution

Control Agency (MPCA) using the post-MERP emission rates for A.S. King Unit 1

indicated that emissions will not cause a visibi lity impact great er than 0.5 deciview (dv).

Therefore, both Riverside Unit 8 and A. S. King Unit 1 ar e exempt from BART analysis.

The MPCA performed visibility modeling to determine that Sherco Units 1 and 2 are

subject to BART.

The regulations also provide th at a state participating in the Clean Air Interstate Rule

(CAIR), which includes Minnesota, need not require BART-eligible electric generating

units to install BART, because EPA’s analysis concluded that CAIR controls are “better

than BART” for electric generat ing units in states subject to CAIR . The MPCA has

stated that it will determi ne whether CAIR substitute s for BART after BART analyses

have been submitted. Since EPA concluded t hat CAIR will provide more visibility

improvement than BART, Xcel Energy believes Sherco Units 1 and 2 should not be

given BART limits and instead CAIR should dr ive emission reductions. Nevertheless, a

BART analysis has been performed as required for Sherco Units 1 and 2, and is

presented in this report.Page 4 of 111 Sherco Units 1 and 2 are located in Becker, Minnesota. They are tangential, pulverized

coal fired boilers burning sub-bituminous coal. Sherco Unit 1 has a heat input of 7,111

MMBTU/hr with a gross output of 697 MW and began operation in 1976. Sherco Unit 2

began operation in 1977 and has a heat input of 7,111 MMBTU/hr and a gross output of

682 MW. The units discharge through a common 650-foot tall stack. The closest

affected national park or wilderness areas are the Boundary Waters Canoe Area

(BWCA), Voyageurs National Park (V NP), and Isle Royale (IR).

The remainder of this report is the BART analysis performed for Sherco Units 1 and 2

(EU001/EU002). The analysis fo llowed the 5 steps shown below:

Step 1. Identify all available retrofit technologies

Step 2. Eliminate technically infeasible options

Step 3. Evaluate control effectiveness of remaining control technologies

Step 4. Evaluate impacts and document the results

Step 5. Evaluate visibility impacts

The MPCA’s BART guidance document requi res the use of maximum historical

emissions data from different time periods for cost-effectiveness calculations and

visibility modeling.

• The cost-effectiveness data was based on the maximum emissions of each

pollutant during a rolling 12-month per iod from January 2001 through December

2005:

- maximum SO 2 emissions were between January 2005 and December

2005,

- maximum NO

x emissions were between May 2001 and April 2002, and

- maximum heat input, used to calculate maximum PM 10 emissions,

occurred between March 2002 and February 2003.

• The visibility model data are based on t he maximum daily values from the period

between January 2002 and December 2004:

- maximum daily value for NO

x occurred on February 24, 2003,

- maximum daily value for SO 2 occurred on February 12, 2004, and

- maximum daily heat input, which was us ed to calculate the maximum daily

PM 10 emissions, occurred on February 12, 2004.

The different sets of data do not occur during the same time period, nor are they for the

same time periods. Since the units may have been operat ing differently during thesePage 5 of 111 periods, there is no way to correlate the emissions used in cost-effectiveness

calculations with those used in visibility modeling. The heat input numbers were

determined from the Continuous Emissi on Monitoring System (CEMS). The

methodology was discussed with and agreed to by the MPCA.

There are no presumptive limits for SO 2 for coal fired electric generating units with

existing controls that achieve at least 50 % removal. For units with less than 50%

removal, the presumptive SO 2 limit is 0.15 lb/MMBTU. SO 2 from Sherco Units 1 and 2

is controlled by wet flue gas desulfurization (FGD) systems (scrubbers) that currently

achieve 75% removal.

MPCA guidance for the BART analysis lists a pr esumptive limit of 0.15 lb/MMBTU for

NO

x for tangential-fired boilers greater than 200 MW located at sites with a capacity

greater than 750 MW operating without post-combustion controls and burning subbituminous coal. Sherco Units 1 and 2 fit this category. Sherco Unit 1 currently utilizes

an overfire air (OFA) system and burners t hat will not allow the unit to achieve the

presumptive NO

x limit for BART. Sherco Unit 2 utilizes LNBs and a separated/close

coupled OFA system to control NO

x . In response to the CAIR program, Xcel Energy is

committed to the installation of LNBs, a separated/close coupled OFA (SOFA) system,

and a combustion optimization (CC) system fo r the OFA system for Sherco Unit 1 for

NO

x control in 2007. All control options for S herco Unit 1 in this analysis include the

costs for these projects. Likewise, Xcel Energy is installing a computer based CC

system for the OFA system for S herco Unit 2 in 20 06. All control options for Sherco

Unit 2 in this analysis include the cost for th is project. These changes to the boilers will

allow Sherco Units 1 and 2 to achieve the presumptive NO

x limit of 0.15 lb/MMBTU.

PM 10 is controlled by wet scrubbers and wet elec trostatic precipitators (WESP). Xcel

Energy notes that there are no contro ls at this time for condensable PM 10 . No

technology would significantly improve the par ticulate control from current levels at

Sherco Units 1 and 2.3.0Baseline Conditions and VisibilityImpacts for BART-eligible UnitsTable 2. Baseline Conditions Modeling Input DataEmission UnitIDEmissionUnitDescriptionSO2Max24 HourActualEmissions(lb/day)NOXMax24 HourActualEmissions(lb/day)PM2.5Max24HourActualEmissions(lb/day)PM10Max24 HourActualEmissions(lb/day)StackNumberLocationEasting(utm)LocationNorthing(utm)Heightofopeningfromground,ftBaseElevationofground,ftStackDiameter,ftFlowRateat exit,acfmExit GasTemperature,°FEU001/EU002Boiler 1 /Boiler 2122,469102,563N/A12,962SV001429,8425,025,44965096932.55,200,000171Table 3. Basis for 24 HourActual Emissions Datain Table 4Emission Unit IDBasis for SO224 Hour ActualEmissionsBasis for NOx24 Hour ActualEmissionsBasis for PM2.524 Hour ActualEmissionsBasis for PM1024 Hour ActualEmissionsEU001/EU002CEMS DataCEMS DataN/AStack test, 6/2004;Heat input from CEMSTable 4. Baseline VisibilityModelingResults2002200320042002-2004CombinedEmission UnitIDClass IAreawith GreatestImpactModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewEU001/EU002BWCA2.60852.93872.77912.68263Page 6 of 111

## 4.0 BART Analysis for BART-Eligible Emission Units

4.A Sulfur Dioxide Emission Controls - Emission Unit

EU001/EU002

4.A.1 Av ailabl e Retrofit C ontr o l Te chnol ogie s

Both units currently use wet FGD systems to control SO 2 , which achieve 75% removal.

SO 2 control technologies that were identified as available for retrofit for Sherco Units 1

and 2 are listed below, followed by a detailed description:

• Wet flue gas desulfurization (FGD)

• Semi-dry FGD

• Dry FGD

• Furnace/Duct reagent injection

• Increase liquid to gas ratio (L/G) to existing scrubber

• DBA (or other organic acid additive ) addition to existing scrubber

• Lime injection into exis ting scrubber

• Retrofit wet ESP with s parger tubes

• Retrofit existing FG D (installation of liq uid distribution ring, installation of

perforated trays, redesign spray header or nozzle configuration)

Wet flue gas desulfurization

Although wet lime and ammoni a FGD systems are availa ble, wet limestone FGD

processes are the most frequent ly applied F G D technology in the U. S. when treating

flue gas from combustion of medium and high su lfur coals (typically greater than 1.5%

sulfur). Wet limestone FGD systems are a l so applicable for units burning low sulfur

bituminous and sub-bituminous coals, but ec onomics typically f a vor the semi-dry lime

FGD systems. However, wet limestone FGD systems are capable of achieving higher

SO 2 removal than semi-dry lime FGD systems, which could mak e them suitable for low

sulfur applications with high removal requi rements. A typical wet limestone FGD

system consists of a r eagent storage and handling syst em, FGD spray tower absorber,

and byproduct dewatering system as illustrated in Figur e 1.

Page 7 of 111Figure 1. Process Flo w Diagram o f a Spra y To w e r Wet F G D S y stem

For most wet limestone FGD applications, the absorber module is located downstream

of the ID fans (or booster ID fans, if requi red). If flue gas bypas s or reheat is applied,

the ID or ID booster fans could be loc a ted downstream of the FGD absorber module.

For a wet FGD syst em, the flue gas enters the absorber and it contacts a slurry

containing reagent and by produc t solids. The SO 2 is absorbed int o the slurry and reacts

with the calcium to form CaSO 3 • 1⁄2H 2 O and CaSO 4 • 2H 2 O.

There are several types of absor ber modul es, and eac h has c haracteristic advantage s

and disadv antages. FGD equipment vendors have specific designs for one or more

types, and all compete on a capital/operating co st and guarantee basis . Depending on

the process vendor, the absorber may be a co-c urrent or countercurrent spray tower,

with or without internal packing or trays (refer to Figure 1) . Other vendors use a unique

absorber where the flue gas is bubbled into a reaction tank as illustrated in Figure 2.

Regardless of the type of abs orber used, the flue gas leavi ng the absorber is saturated

with water and the stack will hav e a v i sible, persistent moisture plume. Generally, wet

FGD systems do not remove si gnificant quantities of SO 3 from the flue gas

. Condens e d

SO 3 , in the form of sulfuric acid mist (H 2 SO 4 ), can be removed from the flue gas if a wet

ESP is used as a mist elimi nator downstream of a wet FGD system. If a wet ESP is not

used downstream of a wet FGD s ystem, t here will be significant increase in SO 3 emitted

from the stack.

Page 8 of 111Figure 2. Cu ta w a y Vie w of a Je t Bub b ling Reac to r Wet F G D S y stem

Because of the chlorides present in the mi st carryover from t he absorber and the pools

of low pH condensate that c an develop, the conditions downs tream of the absorber are

highly corrosive to m o st materials of cons truction. Highly corros i on-resistant materials

are required for the downstream ductwork and for the stack flue. Careful design of the

stack is needed to prevent “rainout” from condens ation that occurs in the downstream

ductwork and stack.

The reaction byproducts are typically dewat ered by a combinat ion of hydro-cyclones

and vacuum filters. For natural oxidation we t limestone FGD systems, the resulting filter

cake is suitable for landfill dis p osal. In some instanc es, the FGD byproduct requires

mixing with fly ash and/or lime (fixation) to produce a physically stable material.

If air is bubbled through the reaction tank, practically all of the CaSO 3 • 

### 1⁄2 H 2 O can be

converted to CaSO 4 • 2H 2 O, which is commonly known as gy psum. This oxidation step

is termed “forced oxidation.” Compared to calcium sulfite, gypsum has much superior

dewatering and physical proper ties, and forced-oxidiz ed systems exhibit few scaling

problems in the absorber and mist eliminators. Dewatered gy psum can be disposed o f

in landfills without stabilization or fixation. Many wet FGD system s in the U. S. are

using the f o rced-oxidation process to prod uce commercial grade gypsum that can be

Page 9 of 111used in the production of Portland cement or wallboard. Marketi ng of the gy psum can

eliminate or greatly reduce t he need to dispos e of FGD byproducts in landfills.

Howev e r, the market for the commercial gr ade gypsum is often nei ther availab l e nor

stable.

The wet F G D processes are characterized by high ef ficiency (typically bet ween 92 t o

98%) and high reage nt utiliz atio n (95 to 9 7 %). The absorber vessels are fabricate d

from corrosion-resistan t materials such as epoxy/vinyl ester-lined carbon steel, rubberlined carbon steel, stainless steel, or fibergl ass. The absorbers handle large volumes of

abrasive s l urries. The reagent handling and byproduct dewat ering equipment is a l s o

relatively complex and expens iv e. These factors result in relativ e ly higher initial capital

costs and lower annual operatin g costs compared to the semi-dry FGD alternatives.

Semi-dry flue gas desulfurization

The semi-dry FGD process is based on the sp ray drying of lim e into flue gas. Spray

drying has been used in many industrial proc ess industries since the 1920's. Since its

introduction in the utility industry in the 1970' s, the semi-dry spray dryer absorber (SDA)

FGD process has bee n one of the most wid el y app lie d FGD technolog ies. U.S. utilities

have installed numerous SDA FGD systems on boilers using low-sulfur fuels. These

installation s, primarily locate d in the western U.S., us e eit her lignite or sub-bituminous

coals as boiler fuel and generally have spr a y dryer systems designed for a maximum

fuel sulfur content of less than 2%.

There are several variations of this process

, but the most prevalent is the installation of

one or more spray dryer vessels upstream of the particulate control dev ice as shown in

Figures 3 and 4. The SDA abs orber vessel is located between the air heater and the

particulate removal device, most commonly a pulse jet fabric filter (PJFF). Although

either quick lime slurry (CaO) or a sodium car bonate (so da ash) solution may be used as

the scrubbing reagent, the current generation of SDA FGD processes primarily use

quicklime. The quic k lime is first slaked with water to form a calcium hydroxide

(Ca(OH) 2 ) slurry. The lime slurry is combined wi th the recycled solids from the PJFF to

form the reagent slurry. The re agent slurry is injected in t he absorber using either a

rotary or two-fluid at omizer, w here the lime reacts with the SO 2 in the flue gas

. Sufficient water is added with the reagent slu rry to l o wer the flue gas temperature t o

within 18 ° C (32 °F) of the adiabatic saturation temperature. The SO 2 is absorbed int o

the fine spr a y droplets and reacts with the lime slurry to form both calcium sulfite (~1/3)

and calcium sulfate (~2/3). Before the drop let can reach the wall of the at omizer, the

Page 10 of 111heat of the flue gas evaporates the droplet to a dry partic le containing the byproduct

solids and excess reagent. As the reagent sl urry evaporates, a relatively dry powder

remains.

Figure 3. Spra y Dr y e r S y stem

Figure 4. SDA FG D Sy stem

Page 11 of 111The byproduct solids and fly ash are coll ected in the PJF F

. Some ad ditional SO 2

removal occurs as the flue gas passe s through the dust cake on the bags. The

byproducts and fly ash are conveyed pneumat ically to the fly ash silo in the

conventional manner . These solids are unl oaded, conditioned with water, and

transported to a landfill. Bec aus e of the le vel of free lime in the byproduct solids, the

byproduct/fly ash mixt ure attains a very hi gh bearing strength and low per meability in

the landfill. Unlike a wet limestone FGD system, there is currently no commercial use

for the byproduct/fly ash.

Dry flue gas desulfurization

A circulating dry scrubber (CDS) is a form of Dry FGD for SO 2 removal. This technology

is capable of removing 95 to 98% of the SO 2 in the flue gas. Hy drated lime (Ca(OH) 2 ) is

the reagent used and is introduced as a dry, free fl owing powder into the scrubber

vessel. Flue gas is then flowed through th e lime reagent in a circulation p a ttern for

adsorption of SO 2 by the lime. A schemat ic of the process flow of a CDS process is

shown in Figure 5.

Generally, there are no constr aints on the maximum fuel sulf ur content, as the CDS can

be adjusted to account for the higher SO 2 loading by increas i ng the conc entration of

reagent. Howev e r, this flexibility is limit ed by the cost of the lime reagent. An

evaluation on the overall reagent cost is i m portant before selecting this technology.

Lime utilization is improved by cooling the flue gas bef ore it reacts with the lime. Flue

gas coming into the scrubber ve ssel is c ooled to about 30 o F above the adia batic

saturation temperature.

As is the case with the SDA, a downstream particulate collection device is required,

usually an ESP or fabric filter fo r the removal of particulate ma tter that is from the ash in

the coal and the product of t he reaction of li me with the SO 2 in the flue gas. Beca use of

the relatively high velocity of the flue gas through the scr ubber vessel (approximately 19

ft/s ), the treated flue gas carries entrain ed reagent and react i on products from th e

module to the downstream particulate control device.

More than 90% of the collected s o lids in the ESP or fa bric filter c ontain unre a cted lime.

Because of abrasion and impacts of the other particles in the flue gas as well as

materials handling dy namics, t he “shell” of reaction pr oducts on t he reagent particles is

broken up. This mat e rial is recycled into the scrubber vessel to further improve lime

utilization. This s o lids reci rculatio n als o maintains the bed d ensities nee ded for contact

Page 12 of 111and removal of SO 2 . Typically , reagent i s circulated 35 to 50 times, providing a

residence time of 30 minutes or more. Collected solids, whic h ar e not recirc ulated, will

be disposed.

Figure 5. Circulating Dr y Scrubber Sy stem (L urgi Lentje s Nor t h America )

As illustrated in the Figure 5, the CDS is a small vessel wit h the associated ESP in an

elevated location bec ause flue gas travels upward in a CDS ves s el. This results in a

smaller footprint for applic ations with s pace constraints. However, depending on the

site situation, the retrofit of su ch a syst em might b e costly, especially if there are

substantial construction and st ructural difficulties.

Page 13 of 111The disadv antages of this process include hi gh dust loading at the particulate removal

system and lack of U.S. utility o perating experience. Higher f abric filter pressure drops

are encou ntered because of the flue gas dus t loading, thus, ESPs are preferred for

particulate removal. The high particulate l oadings make sizing of the ESP critical to

ensure compliance with particulate emis sion r equir e ments. Howev e r, this could limit

future fuel flex ibility.

Furnace/d u ct reagent injection

Two potent ial low-effic i en cy, low capital cost SO 2 control options ar e furnace and duct

injection systems. Each of these two contro l technologies requires either a wet or dry

reagent such as: sodium bi carbonate, powdered lime, hy drated lime, lime slurry,

limestone or magnesium hydroxi de. This technology is ty pically capable of removing

between 20 to 50% of the SO 2 in the flue gas; removal efficiency is high ly dependent on

the application, primarily t he configuration of the exis ting ductwork and the flue ga s

resident time in the ductwork.

Typically, depending on the type of reaction, temperature, percentage reduction rate,

and the c o rresponding retention time requi rements, dry reagents such as powdered

lime or hy drated lim e are preferred for fu rnace injection appli cations. Wet reagents

such as lim e slurry, sodium bic a rbonate, or magnesium hydroxide ar e typic a lly preferred

for duct injection applications based on the removal requirements and th e flue ga s

properties. Generally, depending on the inlet concentration levels, it is expec t ed that a

combined injection s ystem that includes both furnace and duct injection would be

necessary. However, based on the total re moval requirements in some applications,

duct injection would be preferred over fur nace injection. Therefore, wet reagent duct

injection do wnstream of the boiler and near the ESP in let may be necessary.

The use of a wet reagent for duct injection is preferred over a dry reagent because of

the elevated gas temperatures that exist dur ing normal operating c onditio n s. The use

of a wet reagent ups tream of an existing ESP will h e lp reduce the gas temperature,

improve ESP performance for opacity and partic ulate control, and elimin ate the need for

additional ID booster fans for additional draft control.

Also, Com putational Fluid Dynamics (CFD) and chemical kinet ic modeling may be

necessary to determi ne which reagent is pref erred, the preferred location of reagent

injection, the amount of SO 2 emissions removed, and whether furnace injection, duct

injection or both furnace/duct injection syst em s are required for t h e effective removal.

Page 14 of 111Unit design and operational data are collect ed fo r the CFD computer m odel inputs. This

data, combined with unit mapping informati on, enables the model to develop precis e

injection locations and reagent inject ion characteristics for each boiler.

The major component s of a typic a l reagent inje ction sy stem include an air compressor,

chemical s t orage tank, heat tra c ing, contro ls, injection system (i.e., flanges, lances,

nozzles, hoses, hardware, etc.), in jection platform, and slurry pump.

Furnace injection can reduce or eliminate fireside s l agging, fouling, corrosion and

erosion problems in the furn ace. Other benefits in terms of various efficiency

improvements include: savings through greater heat transfer cleanli ness, reduction of

periodic air heater rep l acement, increase in over all u n it reliab ility, boiler c l ea ning cost

reduction, and ultimately extending unit runs to the point wher e only scheduled outages

are taken.

Increase liquid to ga s ratio to e x

isting scrubber

This alternative assumes that the SO 2 removal efficiency in the existing wet scrubber

could be increased from the current level of 75% to a maximum value of 85% by the

addition of another s p ray header in the s c rubber . For the purpose of this analys is, it

was assumed that this new sp ray level would prov ide a liqui d-to-gas ratio (L/G) of 20

gallons per 1000 cubic feet of fl ue gas. One additional spray pump with a flow rate of

6,000 gpm would be required fo r each of the 12 existing scrubber modules (assuming

10 modules in servic e and 2 in standby). T he location and orientation of the required

new spray header in the absor ber were not identified in th is study. No additional

reagent was assumed to be required in this alter native. As in the ex isting sy stem, all of

the reagent requirements are assu med to be provided by the alkaline fly ash removed in

the scrubber. Pilot testing would be requ ir ed to deter mine the optimum spray header

location and L/G and to identify any effects on the performance of the scrubber and

associated wet ESPs.

DBA addition to existing scrubber

This alternative a ssumes that the SO 2 removal efficiency of the existing scrubber could

be increas ed to 80% by the additi on of dibasic acid (DBA) to the process slurry. DBA

buffers the scrubbing slurry in the optimum range for S O 2 removal. For this alternative,

it was ass u med that 10 pound s of DBA would be consum ed for every ton of SO 2

removed. DBA has a unit cost of approx imately $0.42/lb. Pilo t testing would be

required to determine the effectiveness of DBA addition and the ac tual consumption

Page 15 of 111rate. The only equipment r equired is a DBA storage and fe ed system co nsisting of a

storage tank, feed pumps, and piping. Becaus e DBA will solidify if its temperature

drops below approximately 90 °F, the storage tank must be heated and insulated and all

piping must be heat traced. DBA is corrosive, and all materials of constructi on are Type

316 stainless steel.

Lime injec t ion to existing scrubber

This alternative a ssumes that the SO 2 removal efficiency of the existing scrubber could

be increas ed to 85% by raising the pH of the scrubber slurry through the addition of lime

to the process slurry. Currently, all c a lciu m reagent for the desulfurization process is

provided by the alkaline fly ash removed in the scrubber. Typically, SO 2 removal

efficiency increases as the slurry pH increase s. For this alternat ive, lime slurry would

be added to the exis ting scrubber in an amount equal to 20% of the total reage n t

demand (e.g., a stoichiometric feed rate of 0. 2). At design conditions, this would be

approximately 16 tons per day of lime. Pilot testing would be required to determine the

effectiveness of lime addition and the actual consumption rate.

It was assumed that the existing limestone sl urry storage and feed equipment could be

reused to feed the lime to the scrubber modules. The use of lime slurry from the Unit 3

storage tank was assumed to be available and approved for us e in the Unit 2 system by

Xcel Energy and its SMMPA pa rtner. It was also assumed that the relat i vely small

increase in lime slaking demand could be accommodated by the exis ting slakin g

equipment by extendi ng operating hours. Further analysis of t he existing equipment

would be necessary to dete rmine if new equipment (or rec onditioning of t he existing

equipment) would be required.

Retrofit wet FGD with sparger tubes

Xcel Energy could consider retrofitting t he current venturi scrub ber/wet ESP modules

with sparger tubes. These sp arger tubes would be installed within t he existing modules

so that the incoming flue gas would be channeled through t he sparger tubes, forcing the

flue gas to bubble through the s l urry in the r eaction t ank. With this configuration, the

higher the level of slurry re lative to the bottom of the sparger tubes the greater the

contact of the flue gas wit h the slurry, increasing SO 2 removal. As such, it is similar to

the option of increas ing the L/G ratio.

The volum e tric flue gas flow and the pressu re drop across the sparger modules would

be kept the same as t he current arrangement. Half of the existi ng venturi rods wou l d

Page 16 of 111be removed, reducing the maximum pressure drop across the rods from 22” wc to 3”

wc. This would allow for as much as 18” wc of slurry above the bottom of the sparger

tubes. The venturi spray flows and the cr ossover duct spray flows would remain

unchanged, allowing the inc o ming flue gas to be wett ed and for some particulate and

SO 2 removal prior to entering the sparger tubes.

Retrofit wet FGD wit h

sparger tubes with lime injec t ion

The retrofit of the wet FGD wit h s parger tubes would also allo w the injection of lime into

the scrubber to raise t he pH of the slurry. The increa sed pH would contribute to higher

SO 2 removal as discussed with the option above.



### 4.A.2 Technical l y Infeasi b le O p tions

It is impractical to inst all furnace/ duct in jection when more reagent could be added to

the existing scrubber. In fact, Xcel Energy is not aware of any unit using fu rnace/duct

injection with an existing FGD System. Furnac e/Duct injection will not be considered

further in this report. Retrofitting the existing FGD system (installation of liquid

distribution ring, installation of perforate d trays, redesign spra y header or nozzle

configuration) is considered in feasible due to a lack of ph ysical space in the existing

scrubbers.

Page 17 of 111

### 4.A.3 Con t ro l Effectiveness o f Re maini ng Control Tec h nologi es

Table 5. Co ntrol Effectiv eness for S O 2 Reduc tio n Technolog ies

( l b / M M B T U ) ( t o n s / y r ) (tons/y r )

E m i t t e d E m i t t e d Rem o v e d

Unit 1 (Basel ine 0.27 lb/MMBTU)

DBA Addition to Existi ng Scrubber 0.24 6,70 0 830

Lim e Injectio n into E x istin g Scrubber 0.18 5,00 0 2,50 0

Increase L/G to Existing S c rubber 0.18 5,00 0 2,50 0

Retrofit Wet FGD with Sparger Tubes 0.14 3,90 0 3,60 0

Retrofit Wet FGD with Sparger Tubes

with Lime Injection 0

. 1 2 3

, 3 0 0 4,20 0

New Semidry FGD 0.11 3,10 0 4,40 0

New Wet FGD 0.09 2,50 0 5,00 0

Unit 2 (Basel ine 0.27 lb/MMBTU)

DBA Addition to Existi ng Scrubber 0.24 6,70 0 830

Lim e Injectio n into E x istin g Scrubber 0.18 5,00 0 2,50 0

Increase L/G to Existing S c rubber 0.18 5,00 0 2,50 0

Retrofit Wet FGD with Sparger Tubes 0.14 3,90 0 3,60 0

Retrofit Wet FGD with Sparger Tubes

with Lime Injection 0

. 1 2 3

, 3 0 0 4,20 0

New Semidry FGD 0.11 3,10 0 4,40 0

New Wet FGD 0.09 2,50 0 5,00 0



### 4.A.4 Impact Analy s is

Tables 6 and 7 show the costs of compliance for SO 2 control for Sherco Units 1 and 2

respectively for the technologies consider ed applicable and available. Capital and

operating c o sts were estimated with CUECOS T and s upplement ed with dat a from Xcel

Energy (see Appendix A). As these are or der of magnitude estimates, they are

accurate only to ±30%. The capital costs were annualized over a 20-year period and

then added to the annual operating costs to obtain the total annualized cost s for each

technology. The data in the t able are sorted from least ex pensive annualized cost t o

most expensive annualized c o st. The incremental costs were calculated after

constructing the least cost curves, shown in Figures 6 a nd 7 (based on 40 CF R Part 51,

Page 18 of 111Appendix Y). From these curves, all options wo uld be considered d o minant, or

potentially cost-effecti v e, except new semi-dry FGD systems fo r each unit and lime

injection to the exis ting scrubbers. The incremental costs compare the average

cost-effecti v eness of the dominant options by dividing the difference in annual costs

from a higher cost-effectiveness option to the next less e x pen sive option with the

difference in tons of SO 2 removed for the two options. The incremental

cost-effecti v eness compares the cost-effect iveness between Options 1 and 2 ($60/ton),

Options 2 and 4 ($150/ton), Options 4 and 5 ($900/ton), and Options 5 an d 7

(> $40,000/ton).

As seen above, the increment al costs change significantly between Options 5 and 7.

Based on t hese incremental cos t s, the mo st cost-effective opt ion for optimal SO 2 control

is retrofitting the existing scrubbers with sp arger tubes and lime inje ction (Option 5 in

Tables 6 and 7).

Page 19 of 111Table 6. Unit 1 SO2Compliance CostsOptionNumberTechnologyExpectedReduction(tons/year)Rate(lb/MMBTU)Capital CostsAnnualizedCapitalCostsAnnualOperatingCostsTotalAnnualizedCostCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)1DBA addition to existing scrubber8000.24$1,030,000$97,000$158,000$260,0003102Increase L/G ratio to existing scrubber2,5000.18$2,300,000$217,000$135,000$350,000140583Lime injection in existing scrubber2,5000.18$90,000$8,000$490,000$500,0002004Retrofit existing scrubber withsparger tubes3,6000.14$3,600,000$340,000$177,000$520,0001401505Retrofit scrubbers with sparger tubes +Lime injection in existing scrubber4,2000.12$3,700,000$349,000$667,000$1,000,0002409006New semi-dry FGD4,4000.11$106,000,000$10,017,000$12,105,000$22,000,0005,0007New wet FGD5,0000.09$222,000,000$20,979,000$16,286,000$37,000,0007,50044,000Table 7. Unit 2 SO2Compliance CostsOptionNumberTechnologyExpectedReduction(tons/year)Rate(lb/MMBTU)CapitalCostsAnnualizedCapitalCostsAnnualOperatingCostsTotalAnnualizedCostCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)1DBA addition to existing scrubber800$1,000,0000.24$100,000$200,000300$250,0002Increase L/G ratio to existing scrubber2,5000.18$2,300,000$200,000$100,000$350,000140603Lime injection in existing scrubber2,5000.18$90,000$0$470,000190$480,0004Retrofit existing scrubber with spargertubes3,6000.14$3,600,000$300,000$200,000$510,0001401505Retrofit scrubbers with sparger tubes + Lime injection in existing scrubber4,2000.12$3,700,000$300,000$600,000$990,0002408606New semi-dry FGD4,4000.11$106,100,000$10,000,000$11,800,000$22,000,0004,9007New wet FGD5,0000.09$222,200,000$21,000,000$15,800,000$37,000,0007,40043,000Page 20 of 111Figure 6. Least CostCurve- Unit 1 SO205,00010,00015,00020,00025,00030,00035,00040,00001,0002,0003,0004,0005,0006,000Expected Reduction, tons/yr

Tota l Annualized Cost, $1,0 00/yrSparger TubesSparger Tubes w/LimeInjectionnewWetFGDIncrease L/G RatioDBAAdditionMost Cost Effective OptionPage 21 of 111Figure 7. Least CostCurve- Unit 2 SO205,00010,00015,00020,00025,00030,00035,00040,00001,0002,0003,0004,0005,0006,000Expected Reduction, tons/yr

To tal A nnual i zed C o st, $ 1 ,000 /yrSparger TubesSparger Tubes w/LimeInjectionNewWet FGDIncrease L/G RatioDBA AdditionMost Cost Effective OptionPage 22 of 111

### 4.A.5 Energy Impacts

New wet and semi-dry FGD systems would increase auxiliary power needed in the

plant, and would reduce effici ency and energy available to consumers. This wo uld

increase the need for generation from some other source. A new wet FGD s ystem will

require an additional 13,900 kW of auxiliary power. A new semi-dry FGD system will

require an additional 4,900 kW of auxiliary power. There are no other anticipat ed

energy impacts from the other feasible technologies.



### 4.A.6 Non-Air Q u ality Environm ent a l Impact s

No non-air quality environmental impacts were identified.



### 4.A.7 Rem a ini n g U sef ul Life

Since the useful life of Sher co is longer t han 20 years, there is no impact to the

annualized capital costs because the useful liv es of the units are longer than the

feasible tec hnologies.



### 4.A.8 Visibility Impacts

Computer modeling was perfo rmed to predict the number of days that visibility

impairment would be greater than 0.5 dv. The model also predicts the change in the

98 th percentile delta dv, wher e a larger c hange in the delt a dv translates into an

improvement in vis i bility. Bas ed on th e control c o sts discussed earlier, computer

modeling was performed to predict the effect on vi sibility of either retrofitting the existing

scrubbers with sparger tubes and lime injec t ion (Control Sc enario 3), or installing a new

wet FGD system fo r e a ch unit (Control Scenario 4). F r om Table 10 and Figur e 8, it can

be seen that, over the period from 2002 thr ough 2004, the computer modeling predict s

a 98 th percentile delta dv of 2.13 for the sparger tube retrofit with lime injection to the

existing sc rubbers, a nd 2.00 for new wet FGD systems for both units. The model

predicts that there will be 208 da ys above 0

. 5 dv with the sparger tube retrofit and lim e

injection, and 206 days above 0.5 dv for new wet FGD syste m s fo r both units, as

opposed to the baseline of 263 days abov e 0.5 dv . Also note that for 2003, the model

predicted that visibility would ac tually decreas e with new wet FGDs. From a visibility

standpoint, both options provide nearly the same improvement in visibility.

Page 23 of 111Table 8. SO2Post-ControlEmission Ratesfor Emission Unit EU001/EU002ControlScenario #SO2ControlTechnologySO2Max24Hour ActualEmissions,lb/day% ReductionNOxMax24Hour ActualEmissions,lb/day% Reduction(Increase)PM2.5Max24Hour ActualEmissions,lb/day% Reduction(Increase)PM10Max24Hour ActualEmissions,lb/day% Reduction(Increase)3Spargertube w/limeinjection54,43156102,5630N/AN/A196604New wetFGD system40,82367102,5630N/AN/A19660Table 9. SO2Post-ControlStack Parametersfor Emission Unit EU001/EU002ControlScenario #SO2ControlTechnologyStackNo.LocationEasting (utm)LocationNorthing(utm)Height ofopeningfromground, ftBaseelevation ofground, ftStackDiameter, ftFlowrate atexit, acfmExit gastemperature,°F3Sparger tubew/limeinjectionSV001429,8425,025,44965096932.55,200,0001714New wetFGD systemSV001429,8425,025,44965096932.54,720,000129Table 10. SO2Controls - VisibilityModeling Results2002200320042002-2004CombinedControlScenario #SO2controltechnologyClass IArea withGreatestImpactModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5 deciview3Spargertubew/limeinjectionBWCA2.01642.36722.28722.132084New wetFGDsystemBWCA1.92642.51692.09732.00206Page 24 of 111Table 11. Incremental VisibilityCosts at BWCA for SO2ControlControlCaseTechnologyTotalAnnualizedCostIncrementalTotalAnnualizedCost98thPercentileVisibilityImpairment,dvImpairmentImprovement,dvIncrementalImpairmentImprovement,$/dvBase2.68Case 1Sparger tube retrofit$2,000,000$2,000,0002.130.554,000,000Case 2New wet FGD$74,000,000$72,000,0002.000.13550,000,000Page 25 of 111Figure 8. SO2VisibilityImpacts at BWCA2.602.932.772.682.012.362.282.131.922.512.092.000.000.501.001.502.002.503.003.502002200320042002-2004 combinedYear

98th P e rcentile v a lue, dvBaselineSpargersWetFGDPage 26 of 111

### 4.A.9 Pro posed SO 2 

### BART

Xcel Energy proposes to retrofit the exis ting wet scrubbers with sparger tubes and lime

injection. The proposed emiss i on rate is 0.12 lb/MMBTU at t he stack, on a 30-day

rollin g aver age. Th is rate is lo wer than t he presum ptive limit for units that are not

achiev ing 50% removal. Retrofitting ex ist i ng scrubbers with s parger tubes and lime

injection would be complet ed by the end of 2012. The retrofit would reduce SO 2 emitted

from Sherco Units 1 and 2 on t he order of 8,300 tons per y ear and allow Xcel Energy

flexibility in achiev ing required mercury reductions.

The total annualized cost for retrofitting t he existing s c rubbers with sparger tubes and

lime injection is $2,000,000 wit h a significant visibility im provement of 0.55 dv, or

$4,000,000/dv (Table 11). Conv ersely, the tota l annualized cost to move to the ne xt

most effective control technology (new we t FGD) is approximately $72,000,000 with a

visib ility improvement of only 0.13 d v , or $55 0,000,000/dv. The incremen tal

cost-effecti v eness between the sparger/lime retr ofit and new wet FG D is greater than

$40,000/ton removed, which Xcel Energy asserts is excessive.

New wet FGD systems would increase auxili ary power needed in the plant, reduce

efficiency, and reduce energy available to c onsumers. This would increase the need for

generation from some other source.

Xcel Ener gy firmly believes the most cost -beneficial visibility improvements will be

brought about by retrofitting the existi ng wet scrubbers with sparger tubes and lim e

injection.

Page 27 of 111

### 4.B Nitrogen Oxides Emission Controls – Emission Units

EU001/EU002

4.B.1 Av ailabl e Retrofit C ontr o l Te chnol ogie s

Sherco Unit 2 currently utilizes LNB, and a separated/close co upled OFA system. A

combustion optimization system will be inst alled on this uni t during an outage this fall

(2006). Unit 1 is scheduled to receive LNB and s e parated/clos e coupled OFA system

and a combustion optimizati on system next fall (2007).

NO

x control technologies that were identified as available for retrofit at Sherco Units 1

and 2 are listed below:

• Combustion optimization (CC) system

• LNB with SOFA - Unit 1 only

• Mobotec ROFA & ROTAMIX

• NO

x Star & NO

x Star Plus

• Ecotube

• Induced flue gas recirculation (IFGR)

• Selective c a talytic reduction (SCR)

• Selective non-catalytic reduction (SNCR)

• SCR/SNCR Hybrid (Cascade System)

• LoTOx

• Natural gas reburn (includes fuel l ean gas reburn (FLGR) and amine-enhanced

fuel lean gas reburn (AE-FLGR))

Combustion optimization system

For optimum combustion, properly balanced am ounts of coal and ai r should enter the

furnace through the deliv ery of each burner and the OFA system, if pre s ent. This

balanc ed deliv ery should produce the maxi mum amount of heat with the minimum

amount of waste. However, wit hout the ability to continuously monitor air a nd fuel flow

entering each burner and the resulting burner performance, conditions ty pically exis t

where inadequate air is supplied for co mbustion, creating a fuel-rich or air-rich area.

Both condit ions reduc e boiler efficiency and result in excess ca rbon monoxide (CO), fly

ash loss-on-ignition (LOI) or NO

x emissions.

In an attempt to prevent or reduce these e ffects, plants often turn to the procedure

known as “burner balancing.” This entails the monitoring and adjustment of burners so

Page 28 of 111that the fuel/air ratio is eq ualized across t he boiler. Histo rically, this has not been a

simple proc edure to perform or to main tain ac ross the normal boiler load range.

Initial attempts at monitoring LNB performance were directed toward measuring flue gas

constituents leaving the boiler, which prov ided an indication of the total air-to-fuel ratio

and average NO

x a nd CO e m issions. This info rmation established the average

performance of the complete firing system , but th e performance status of each

indiv i dual burner was not available.

Recent advances in flow measurement and flame-scanning techniques have shown

some limited success in monitoring both coal and primary airflow, and als o secondar y

airflow to each burner, in addition to burner fl ame pattern. With this additional level of

on-line performance data, the se condary air f low and pulverizer feeders can be bias ed to

continuous ly maintain burner-to-burner balance.

Additionally , recent advances in com puter hardware and software technology hav e

enabled power generation companies t o im prove their competitive position by

implementing cost-effective optimization solutions t hat decrease emiss i ons and

maximize plant efficiency. These solutions, c o mmonly referre d to as boiler optimization

or neural network systems, provi de simultaneous improvements in both fuel efficienc y

and emissions. Neural network computing diffe rs from traditional computing in that

engineering, statistica l, and first-law principles have been replaced by complex, tim e

varying, nonlinear relationships. Neural net work systems use rea l -time operational dat a

extracted from a plant Distri buted Control System (DCS), "l earn" solutions from plant

operational experienc e, and reduce emiss i ons , while improving pl ant performance by

continuous ly adapting to changes in plant operation.

Neural net work systems also supplement other NO

x reduction strategies. Some of

these include LNBs, OFA and post-combusti on controls such as SCR and SNCR.

These systems are also used to help boile r manufacturers tune boilers with poor

combustion characteristics or af ter an LNB retrofit or adding OFA.

Low NO

x

burners

NO

x , primarily in the form of nitric oxide (NO) and NO 2 are formed during combustion by

two primary mechani sms: thermal NO

x and fuel NO

x . Thermal NO

x results from the

dissociation and oxidation of nitrogen in the combustion air. The rate and degree of

thermal NO

x formation is dependent upon oxygen availability during the combustio n

Page 29 of 111process and is exponentia lly dependent upon combustion temperature. Fuel NO

x , o n

the other hand, result s from the oxidation of nitrogen organica lly bound in the fuel. T h is

is the dominant NO

x producing mechanism in the co mbustion of pulverized c oal.

All LNB offered commercially for application to coal-fired boiler s control the formati on

and emiss i on of NO

x through s o me form of staged combustion. The basic NO

x reduction principles for low NO

x burners are to control and bal ance the fuel and airflow

to each burner, and to control the amount and position of secondary air in the burner

zone so that fuel dev olatizatio n and high temperature zones are not oxygen rich. In this

process, the mixing of the fuel and the air by the burner is c ontrolled in such a way that

ignition and initial co mbustion of the coal takes plac e under oxy g en deficient conditions

, while the mixing of a portion of the combustion air is del ayed along the length of the

flame.

The objective of this process is to drive the fuel-bound nitrogen out of the coal as

quickly as possib l e, under condit i ons where no oxyg en is present, and wher e it will b e

forced to form molecular nitrogen, rather than be oxidiz ed to NO

x . Any nitrogen

escaping the initial fuel-rich region has a greater opportuni ty to be convert e d to NO

x as

the combustion process is c o mpleted. T h e net result of staged c o mbustion is usu a lly

longer and/ or wider flames, due to this delay ed mixing process.

Low NO

x

burners and OFA system

In addition to the LNB system, a n incremental approac h to NO

x c ontrol is to install an

OFA system to combi ne LNBs with OFA. OF A works by reducing the excess air in the

burner zone, thereby enhanc ing the combusti on staging effect and further reducing NO

x

emissions. Any residual unburned material , such as CO and unburned carbon, whic h

inevitably escapes the main burner zone, is subsequently oxidiz ed as the OFA is added.

As with primary NO

x control, the performance that can be expect e d from a given O F A

system depends upon a number of factors. As the a m ount of OFA is inc r eased, the

stoichiometry in the burner zone decreas es and a point is reached at which CO

emissions r each high levels and become uncontro llable. The point at which this occurs

can be boiler and c oal type spec if ic, particularly if a fuel is di fficult to burn, and will also

depend upon the ext ent to which it is possibl e to balance flows between the indiv i dual

cyclones or burners. As the O F A amount approaches 10 to 15%, the probability for

indiv i dual burners operat ing under overall fuel-rich condi tions increases, such that

pockets of very high CO emissions and u n burned car bon will be formed. Similarly, fue l

rich operation at bur ners close to the wate r walls can begin to lead t o local slag

Page 30 of 111formation and increased tube wastage rates, parti cularly if slagging is an ongoin g

problem and the coals have high su lfur content. A fairly high level of unburned material

leaving the burner zone can be accommodated by proper over fire port design, wher e

requirements call for rapid and complete mixi ng of the OFA with the boiler flue gases. A

diagram illu s trating the staged combustion of LNB and OFA is illus t rated in Figure 9.



## Overfire

Air

Figure 9. Staged Combu s tion of lo w NO

x burners and OF A s y s t em

M o botec ROFA & ROTAM I X

Mobotec provides a NO

x reduction system that co mb ines LNB, OFA, and SNCR

technologies into an integrated system. The system us es a modified OFA sy stem with

improved mixing characteristics achiev ed thr ough adding a rotation to the OFA. This

system is called ROFA TM – Rotating Oppos ed Firing Ai r. In addition ROTAM I X TM , whic h

consists of adding urea or a mmonia injection into the ROFA TM air nozzles, can be

added to the system. The extra mixing pro duced by c o mbining the OFA nozzles wit h

the reagent injection, results in im prov ed mixing a nd a more homogeneous temperature

profile in th e boiler. A simplifi ed process flow di agram of the ROF A TM and ROTAMIX TM

system is illustrated in Figure 10.

The NO

x reduction sys tem has been commercially proven and has achieved up to 75%

NO

x reduct i on. Bas i c a lly, the m o re heterogeneous temperature profile in the boiler will

optimize combustion and, in tu rn, will promote higher carbon c ontent in the fly ash than

a typical combustion environment would.

Page 31 of 111Figure 10. Mobote c RO F A TM and RO TAMIXTM Simplified Process Flo w Di agram

NO

x Star & NO

x Star Plus

NO

x Star TM is the trademarked name for a NO

x c o ntrol technology that involves the

injection of ammonia and a hy dr ocarbon (typically natu r al gas) int o the flue gas path of

a coal-fired boiler at approximatel y 1,600 – 1,800 ° F for reduction of NO

x . The ammonia

reduces NO

x through a selectiv e non-catalytic reduction (SNCR) reaction, with the

hydrocarbon minimiz i ng the ammonia s l ip. This enables higher r eagent injection rates

for NO

x reductions than achievable with a ty pi cal SNCR technology. A c entral premise

of the technology is t he ability to achieve NO

x emiss i ons of less than 0.20 lb/MMBTU

without the use of a c a talyst. Although initially targeting high NO

x reductions, full-scal e

demonstrations to date have bee n limited to nominally 50% NO

x reduction per f ormance.

NO

x Star eliminates solid catalyst and the a ssociated problems of chemical poisoning

, physical plugging, and sintering due to temperat ure excursions, pressure drop requiring

new ID fans and dis posal of a hazardous solid waste. NO

x Star opportunistically

operates within the confines of the boiler’s c onvective pass, eliminating the necessity to

build a huge catalys t reactor and the a ssociated SCR capit a l costs, economizer

modifications, and major outages. The other advantage of the NO

x Star system is that

the conversion of SO 2 to SO 3 is said to be negligible, thus eliminating one of the main

drawbacks of the SCR technology

.

NO

x Star has a lower NO

x reduction efficiency as com pared to SCR and als o has a

higher ammonia slippage rate than an SCR. SO 3 in the presenc e of ammonia will form

ammonia sulfate, ammonia bi sulfate, and other salts in combination with iron and

aluminum. The depos ition temp erature of these salts from the flue gas is dependent on

the relative concentration of amm onia and SO 3 in the flue gas. Amm onium bisulfate is a

sticky substance, which can deposit on air heater b a skets, and other downstream

Page 32 of 111equipment surfaces. Resultant particle diameters at the sta ck are on the order of 1 to

3 microns and thereby could c o ntribute to PM 10 emis sions. Am monia salt s depositing

on air heater surfaces could incr ease the frequency of off-line wash es in combination

with forced outages.

A significant quantity (up to 80% ) of the ammonia slip t hat exits the NO

x Star system will

react with flue gas and fly as h constituents and be collect ed with the fly ash in the

particulate removal equipment (ESP or fabric f ilter). The ammonia c ontent of the fly as h

can affect waste disposal practices, and t he potential for waste pr oduct sales due to

odorous emissions.

The major consideration for the NO

x Star technology is that it c u rrently has only o n e

major installation in the U. S. and may require the installation of a single layer of in-duct

catalyst to achieve advertised levels of NO

x reduction.

ECOTUBE

The ECO T UBE sys tem is a boiler combustion im provement and NO

x reduction

technology. Retractable lance tubes that pe netrate the boiler above the prim ary burner

zone inject high-veloc i ty air as well as reagents. The lance t ubes work to create

turbulent airflow and to increase the resi dence time for the air/fuel mixture.

ECOTUBE is an advanced, extremely cost-effective system for re ducing NO

x , CO, and

volatile organic compounds (VOC) while improv ing thermal efficiency by optimizing the

combustion process in boilers. The ECOT UBE system is a hybr id of two proven

technologies: separated OFA (SOFA) and SNCR . By injecting air, ammonia, or urea

through retractable lances in the upper fu rnace, the ECOTUBE t a kes SOFA and SNCR

well beyond their independent individual c apabilities. Creati ng turbulence at the best

location in the gas flow, an improved fuel/air ratio is achieved through better mixing -

along with a lower stoichiometric ratio of O 2 . An illustration of the ECOTUB E installatio n

in a typical boiler is shown in Figure 11.

The water-cooled ECOTUBEs are automatically retracted from the boiler on a regular

basis and cleaned to remove layers of s oot and other depos itions. The lances ar e

designed to simulate boiler tubing for years of useful life in the boiler. ECOTUBE’s

self-cleaning capability and safety control syst em allow safe and continuous operation.

Unlike many low cost SNCR systems, EC OTUBE’s furnace combustion impr ovements

increase ef ficiency, and reduce fuel usage. At the same time, it reduces c onvection

Page 33 of 111pass, APH, precipitator, bag- house, ductwork, and stac k corro sion and erosion. From a

capital inv e stment perspective, ECOTUB E is one of the lowest cost-per-ton NO

x

reduction systems available that is capable of achieving 60-80% NO

x reducti on. It is

less than one-half the cost of SCRs and involves minimal installation downtime and

boiler modifications.

Figure 11. ECOTUBE Installation in a Boiler

Induced flue gas recirculation

Recirculation of flue gas back to the co mbustion z one has b e en one o f the most

effective methods of reducing NO

x emissions from gas- and oil-fired boilers since the

early 1970's. Injection of flue gas into t he combustion air is a proven method for

controllin g NO

x produ ction from gas-fired utility b o il ers. For units not equipp ed with ga s

recirculation fans, flue gas can be injected in to the combustion air by a technique kn own

as induced flue gas recirculation ( I FGR).

IFGR acts to reduc e NO

x for m ation by reducing peak flame temperatures. In

conventional applications, the recirculated f l ue gas is typically ext r acted from the boile r

outlet duct upstream of the air heater. The fl ue gas is t h en returned through a separate

duct and hot gas fan to the combustion air duct that feeds the wind box. T he recirculated

flue gas is mixed with the combus tion air via airfoils or other mixing devic es in the duct

. This technology is k n own as windbox FG R (WFGR). WFGR systems require installation

of a separate hot gas FGR fan to move fl ue gas from the boiler exit to the air supply

ducting at the windbox inlet, where mixing of the air and flue gas must be uniformly

achieved by installation of appropriate mixing devices.

Page 34 of 111Selective catalytic reduction

Selective c a talytic reduction (SCR) systems are the most widely used post-control

technologies for achieving si gnificant reductions in NO

x emissions. In SCR systems,

vaporized ammonia (NH 3 ) inject ed into the flue gas s t ream acts as a reducing agent

,

achiev ing NO

x emiss i on reductions when passed over a catalyst. The NO

x and

ammonia reagent react to form nitrogen and water vapor. The reaction mechanism s

are very efficient with a reagent s t oich iometry of approximately 1.05 (on a NO

x reduction

basis) with very low ammonia slip (unr eacted ammonia emissions). A simplified

schematic diagram of a typical S CR reactor is illustrated in Figure 12.

I s o l a t i o n

D a m p e r s

T o A i r H e a t e r T e m p e r a t u r e G r i d

u t u re o rns

T uning/ M onito r i n g

G r i d Catal y S o n i c H

st

Catal y s t

Catal y s t

Space f o r F

Catal y st S o n i c H o rns

S o n i c H o rns Vaporiz e d

A mmoni a

B y p a s s Damper Economi z e r

Bypass, if

needed

From

Economi z er

Figure 12. Schematic Diagram of a T y p i cal SCR Rea c tor

The SCR r eactor is the hous ing for the catalyst. The reactor is basically a widene d

section of ductwork modified by the addition of gas f l ow distribution dev ic es, catalyst,

catalyst support structures, access doors, and s oot blowers. An ammonia injection grid

is loc a ted upstream of the SCR reactor and the system can be des ig ned with or without

a flue gas bypass. The SCR r eactor is typically elevated above and behind the air

heater and downstream emission s control equipment (typically an ESP) and gas flow

direction through the reactor is vertically downward for co al-fired applications. In a

“high-dust” SCR arrangement, the reactor is located betwe en t he outlet of the

economizer and the inlet of t he air heater. The high- dust syst em is typically the most

economical and preferred arrangement where physically possible.

Page 35 of 111The SCR reaction oc curs within the temper ature range of 550 to 850 °F where the

extremes are highly depende nt on the fuel quality. The oxidation of SO 2 to SO 3 could

also require moderate air heater modifications since t he acid dew point temperature of

the flue gas is directly related to SO 3 concentration. As the SO 3 c oncentration

increases, the acid dew point of the flue gas increases, potentially increasing corrosion

in downstream equipment or possibly requiring an increase in the air heater gas outlet

temperature.

The ammonia reagent for the SCR systems can be s upplied by anhydrous ammonia,

aqueous ammonia, or by conversion of urea to ammonia. Since the ammonia is

vaporized prior to contact with the catalys t, the selection of ammonia type does not

influenc e the catalyst performance. Howeve r, the selection of ammonia type does

affect all other subsystem co mponents, including reagent stor age, vaporization,

injection control, and balance-of-plant requirem ents. The vast majority of worldwide

installations use anhydrous ammonia.

SCR systems have a variety of interfacing syst em requirements to support operations.

These impacts predominately re late to draft, aux iliary pow er, sootblowing steam, gas

temperature, controls, ductwork, reactor f ootprint, and air heater. The SCR s ystem will

impact the boiler dr aft system. D ependent on arrangement and performanc e

requirements, draft losses can range from 4 to 10 in. wg. This can be compensated

with the addition of ID booster fans. If necessary, ductwork, and/or boiler box

reinforcement need to be cons idered. In conjunction with the fan modification, the

upgrade of the auxiliary po wer system might be nece ssar y . Auxiliary power

modifications may also be necessary for ammonia supply system requirements.

The major impact of th e SCR syst em can be seen at the air heater where there are two

areas of concern. O ne is the for m ation and depos ition of ammonium bisulfate on the air

heater surface. This will c aus e an increas e in the pressure drop of the air heater. The

other potential danger for the air heat er is high concent rations of SO 3 in the flue gas. If

the acid dew point has bee n increased to more than t he exhaust temperature, a

signific ant amount of acid gas es will conden se in the air heater and lead to plugging and

corrosion. Several measures can be taken to avoid or correct this situ ation. Mo st

important is the right co mposition of the catal yst to minimize the SO 2 to SO 3 conversio n

rate and the proper temperatur e control of the flue gas entering the reactor.

Page 36 of 111Selective non-catalytic reduction

Selective non-catalytic reduc tion (SNCR) systems redu ce NO

x emissions by injecting a

reagent at multiple levels in th e steam gener ator as illustrate d in Fig u re 13. SNCR

systems re ly solely on reagent injection ra ther than a catalyst and an appropriate

reagent injection temperature, good reagent/gas mixing, and adequate reaction time to

achieve NO

x reductions. SNCR systems can use either ammonia or urea as the

reagent. Ammonia or urea is in jected into ar eas of the st eam generator where the flue

gas temperature ranges from 1, 500 to 2,200 °F. The furnace of a pulveriz e d coal fired

boiler operates at temperatures between 2,500 to 3,000 °F.

SNCR systems are capable of achiev ing a NO

x emission reduction as high as 50 t o

60% in optimum conditions ( adequate reaction time, temper ature, and reagent/ flue gas

mixing, high baseline NO

x co nditions, multiple lev e ls of injectors) with ammonia slips of

10 to 50 ppmvd. Lower ammonia slip values can be achieved with lower NO

x reduction

capabilities

. Typically, optimum c onditions are di fficult t o achieve, re sulting in emission

reduction levels of 20 to 40%. Potential per formance is very s i te-specific and varie s

with fuel type, steam generator size, allowable ammonia slip, furnace CO

concentrations, and steam generator heat transfer characteristics.

C o m b u s ti on A i r I n j e ction

Le ve l 2

I n

je ct io n

Le ve l 3

Bu r n e r s

Steam Genera t o r

Air H e a t e r I n

j e c t i o n L e vel 1

Flu e

Ga s Am m o n i a o r

Ure a Sto r ag e T a nk

Figure 13. Schematic o f SNCR Sy stem w i th Mul t iple Injection Lev e ls

Page 37 of 111SNCR syst ems reduc e NO

x emissions using the same r eduction mechanism as SCRs.

Most of the undesirable chemical reac ti ons occur when reagent is injected at

temperatures above or below the optimum r ange. At best, these undesired reactions

consume reagent with no reduc tion in NO

x emissions while, at worst, the oxidation of

ammonia c an actually generate NO

x . Acc o rdingly, NO

x reductions and ov erall reaction

stoichiometry are very sensitive to the te mperature of the flue gas at the reagent

injection point. This complicat es the app lication of SNCR for boilers larger than

100 MW.

Reagent injection lances are usually locat ed between the boiler soot blowers in the

pendent superheat section. Optimum injector lo cation is mainly a function of temperature and residenc e time. To accommodat e SNCR r eaction temperature and boile r

turndown requirements, several levels of in jection lances are normally installe d.

Typically, four to five levels of multiple lance nozzles are insta lled if sufficient boiler

height and resident time is avail able. A flue gas residence ti me of at least 0.3 second in

the optimum temperature r ange is desired to assure adequate SNCR performance.

Residence times in excess of 1 second yield high NO

x r eduction levels even under less

than ideal mixing conditions. Computatio nal Fluid Dynamics and Chemical Kinet ic

Model i n g can be performed to establ i s h t he opti m um ammoni a injecti on l o cati ons and

flow patterns. For an existing boiler, minor waterwall modifications are necessary to

accommodate installa tion of SNCR injector l ances. Steam pipin g modifications wou l d

probably be required to achieve optimum performance.

SNCR/SCR hybrid

The SNCR/SCR hybrid system uses component s and operating c haracteristics of both

SNCR and SCR syst ems. Hybrid systems we re developed to combine the low capital

cost and high ammonia slip as sociated with SNCR systems with t he high reduction

potential and low ammonia slip i nherent to the catalyst of SCR sys tems. The result is a

NO

x reduc tion alternative that can meet in itially low reduction requirements but be

upgraded to meet higher reductions at a future date, if required.

The SNCR component of the hy brid system is identical to the SNCR system described

previously except that the hybrid system ma y have more le vels of multiple lance nozzles

for reagent injection. This will in crease the capital cost of the SNCR compo nent of the

hybrid system. During operation, the SNCR syst em would be allowed to inject higher

amounts of reagent into the flue gas. This increased reagent flow has a two-fold effect:

NO

x reduct i on within t he boiler is increased wh ile am monia slip also increases. The

Page 38 of 111ammonia that slips from the SNCR is then used as the reagent for the catalyst in the

SCR.

There are two design philosophies for usi ng this exc e ss ammonia slip. The most

conservative hybrid sy stems will use the cat a lyst simply as an am monia s lip “scrubber”

with some additional NO

x reduction. As with in-duct systems, the flue gas velocity

through the catalyst is an impor tant factor in des ign. O perating in this mode allows

max i mum NO

x reduction within the boiler by the SN CR while minimizing the catalyst

volume requirement. While som e NO

x reduction is realized at t he catalyst, th e relatively

small catalyst requirement of thi s design c an potentially fit all th e catalyst in a true induct arrangement, with no significant ductwor k changes, arrangement interference, or

structural modifications. The second phil osophy us es adequate catalyst volume t o

obtain significant levels of additional NO

x reduction. The addit ional reduction is a

function of the quantity of ammo nia slip, catalyst volume, and distribution of ammonia t o

NO

x within the flue gas. Us ing ammonia s lip produced by the SNCR system is not a

high ly efficient method of introducing re a gent, due to the low reagent utilizatio n

discussed as a part of the SNCR. Therefor e, even though the reacti on at the cataly st

requires 1 ppm of ammonia to remove 1 ppm of NO

x , the SNCR must inject at least 3

ppm of ammonia to generate 1 ppm of ammonia at the catalyst.

Catalyst volume is str ongly influenced by t he NO

x reduction required and the ammonia

distribution. The impact of catalyst volume on the design of a hybrid system is on th e

size of the reactor required to ho ld the catalyst. If multiple le vels of catalyst operating at

low flue gas veloc i ty are required, some m odifications will be required to t he existing

ductwork. If widening the ductwork cannot provide adequate catalyst volume, then a

separate reactor is required. The addit i on of a reactor negates the capital c o st

advantage of a hybrid system.

LoTOx

The LoTOx technology is the low te mperature gas-phase oxidation of NO

x by ozone

injection. In this met hod, ozone is inject ed into the flue gas upstream of a wet FGD

system. The ozone r eacts with the NO and NO 2 to form nitrogen pentoxide ( N 2 O 5 ). Th e

nitrogen pentoxide formed is soluble in wa ter and can be removed from the flue gas

using a wet FGD syste m

.

The LoTOx technology has been demonstrated on several ind u strial size plants and

several refinery applic ations.

Page 39 of 111The LoTO x technology offers high NO

x removal efficiency with a r eported potential of 15

to 25% savings in capital co st over a SCR. The major dr awbacks of this system are the

lack of experience on larger power generating units, high power consumption and the

production of nitrates.

The high power level resulting from the mu ltiple oz on e generators required to produce

the ozone for the process is expected to be comparable to what is needed for a

conventional FGD sy stem and is significantl y higher than the power consumption from

an SCR. The nitrate produced from this proc ess is capt ured in the FGD waste product.

Most regulatory agencies are strict about nitrate release into water systems; a

wastewater treatment pl ant might be required.

Natural gas reburn

The natural gas reburning process employs 3 separate combustion zones to reduce

NO

x emiss i ons as illustrated in Figure 14. The first zone consists of the normal

combustion zone in the lower furnace, whic h is formed by the existing wall burners. In

this zone, 75 to 80% of the to tal fuel heat input is introduced. The first zone burners are

operated with about 10% exc e ss air (a 1:10 stoi chiometric ratio). A second c o mbustion

zone (the reburn zone) is cr eat ed above the lower furnac e by operating a row of

conventional natural gas burners at a stoichiome tric ratio less than 1. This technology

also has the potential for increased furnace corrosion (especially with higher sulfur

fuels) because of the reducing at mosphere in the lower furnace.

The sub-stoichiometric reburn zone causes NO

x produced in the lower furnace units t o

be reduced to molecular nitrogen and oxygen, because the oxygen stripped from the

NO

x molec u les is combined wit h the more acti ve car bon monoxide molecules to form

CO 2 as combustion is completed in the upper fu rnace. Fuel burnout is completed in the

third zone (the burnout zone) by the introduction of O F A. Su fficient OFA is introduce d

to complete combustion of the unburned mate rials in the upper furnace wit h an overall

excess air rate for the boile r of 15 to 20%. Reburn tec hnology has demonstrated NO

x

reduction of 40 to 65%.

Sufficient r e sidenc e time (adequate furnace height) in the reburn and OFA z ones is a

key factor in determining w hether the reburning technology can be applied. Successful

retrofit of this technology requires space within the boiler to a llow adeq uate residenc e

time for both the additional burning zone (0.4 to 0.6 second) an d the associated OF A

Page 40 of 111burnout zone (0.6 to 0.9 second). When this space is available, reburning can be highly

effective, but a low residence time will limit system performance

. In addition, the high

cost of natural gas increases annual operating c o sts and makes these costs

unpredictable becaus e of the high volatility of natural gas prices.

Burnout Zone

•N or mal E x cess A i r

Reburni ng Z o ne •Sligh t ly Fuel Rich

•NOx Re duce d t o N

2

Primar y C o m b us ti o n

Zo n e

•Red uced Fi r i ng Ra te

•Lo w Excess Ai r

•Lo w er NOx Ov e r fire Ai r

40 to 60% NOx Reduction 10 t o 20 % Ga s

Fuel Rich

80 t o 90% Coa l

10 % E x ces s Ai r

Figure 14. Schematic o f Gas Reburn Sy stem



### 4.B.2 Technical l y Infeasi b le O p tions

The following systems were not consider ed further in this st udy for the following

reasons:

• The Mobot ec Rotamix system has not be en demonstrated on uni t s as large as

Sherco.

• The Mobotec ROFA system is in t he same category as OFA syste m

.

• NO

x Star and No

x Star Plus technologies ar e not currently being marketed, nor

there is a natural gas line to the S herco plant site.

• ECOTUBE has no existing installations at uni ts of the size and design of Sherco

Units 1 and 2. Xcel Energy has signifi cant experienc e with injection method s

similar to ECOTUB E, and b e liev e s th at the equipment would be initially

Page 41 of 111unreliable and poss i bly not ca pable of accepting modifi cations to make this

method more reliable.

• IFGR is not applicable fo r coal-fired units.

• LoTOx has no installat i ons at units in t he size range of Sherco Units 1 and 2.

• There is no natural gas line to the S herco site for natura l gas reburn.



### 4.B.3 Con t ro l Effectiveness o f Re maini ng Control Tec h nologi es

Table 12. Control Effec t iv eness for NO

x Reduc tion Techn o logies

( l b / M M B T U ) ( t o n s / y r ) (tons/y r )

Reduction Technologies E m i t t e d E m i t t e d Rem o v e d

Unit 1 (Basel ine 0.34 lb/MMBTU)

Co m bustion Optim i zation Sy stem (CC) 0.28 7,60 0 1,60 0

New LNB, New OFA Sy stem and CC 0.15 4,10 0 5,20 0

New LNBs, OFA, CC, an d SNCR 0.14 3,80 0 5,40 0

New LN Bs, OFA, CC, an d SNCR/SCR

Hy brid (Casc ade) 0

. 1 2 3

, 3 0 0 6,00 0

New LNBs, OFA, CC, an d SCR 0.08 2,20 0 7,10 0

Unit 2 (Basel ine 0.20 lb/MMBTU)

Co m bustion Optim i zation Sy stem (CC) 0.15 4,10 0 1,40 0

CC and SNCR 0.14 3,80 0 1,60 0

CC and SNC R /SCR Hy brid (Cascade) 0.12 3,300 2,200

CC and SCR 0.08 2,20 0 3,30 0



### 4.B.4 Impact Analy s is

Tables 13 and 14 show the costs of compliance for NO

x control for Sherco Units 1 and 2

respectively for the technologies consider ed applicable and available. Capital and

operating c o sts were estimated with CUECOS T, and supplemented wit h data from Xcel

Energy (Appendix A) . As thes e are order of magnit ude estimates, they are accurate

only to ±30%. The capital costs were annu alized over a 20-year period and then added

to the annual operating costs to obtain the total annualized costs for each technology.

The data in the table are sorted from leas t expensive total annualized c o st to most

expensiv e total annualized c o st. The incr emental costs were calcu l ated after

Page 42 of 111constructing the least cost curves, shown in Figures 15 and 16 (bas ed on 40 CFR Part

51, Appendix Y). F r om these curves, a ll options would be considered d o minant, or

potentially cost-effecti v e, except a new SNCR system and a new hybrid SNCR/SCR

system. The incremental costs c o mpare the average c o st-effectiveness of the dominant

options by dividing the di fference in total annualized costs from a higher cos t

effectiveness option t o the next less expens iv e option with the difference in t o ns of NO

x

removed for the two options. The incrementa l cost-effectiveness fo r Unit 1 compare s

the cost effectiveness between Options 1 and 2 ($470/ton), and Options 2 and 5

($8,000/ton). The incremental cost-effect iveness f o r Unit 2 compares the cos t

effectiveness between Options 1 and 4 ($7,600/ton).

As seen above, the incremental costs for Unit 1 change significantly between Options 2

and 5. Bas ed on this incremental cos t, the most cost-effective option for NO

x control f o r

Unit 1 is the installation of a com bustion optimization syst em, and LNB and SOFA

(Option 2 in Table 13)

.

The increm ental costs for Unit 2 change s i gnif icantly between Options 1 and 4. Based

on this inc r emental cost, the most cost-effective option for NO

x control for Unit 2 is

installation of a combu s tion optimizat ion system (Op t ion 1 fro m Table 14).

Page 43 of 111Table 13. Unit 1 NOxCompliance CostsOptionNumberTechnologyExpectedReduction(tons/year)Rate(lb/MMBTU)Capital CostsAnnualizedCapitalCostsAnnualOperatingCostsTotalAnnualizedCostCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)1Combustion Optimization (CC)1,6000.28$4,200,000$400,000$89,000$485,0003002CC + new low NOxburners (LNB)/Separatedoverfire air (SOFA)5,2000.15$19,000,000$1,800,000$400,000$2,200,0004305003CC/LNB/SOFA + new Selective Non-Catalytic Reduction (SNCR)5,4000.14$28,000,000$2,600,000$2,300,000$5,300,0009804CC/LNB/SOFA + new SNCR/SCR Hybrid6,0000.12$66,000,000$6,300,000$3,500,000$10,000,0001,7005CC/LNB/SOFA + new Selective Catalytic Reduction (SCR)7,1000.08$105,000,000$9,900,000$7,200,000$18,000,0002,5008,000Table 14. Unit 2 NOxCompliance CostsOptionNumberTechnologyExpectedReduction(tons/year)Rate(lb/MMBTU)CapitalCostsAnnualizedCapitalCostsAnnualOperatingCostsTotalAnnualizedCostCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)1Combustion Optimization (CC)1,4000.15$4,200,000$400,000$100,000$490,0003602CC + new Selective Non-Catalytic Reduction(SNCR)1,6000.14$13,300,000$1,300,000$2,200,000$3,500,0002,1003CC + new SNCR/SCR Hybrid2,2000.12$51,900,000$4,900,000$3,500,000$8,400,0003,9004CC + new Selective Catalytic Reduction (SCR)3,3000.08$90,100,000$8,500,000$6,400,000$15,000,0004,6007,600Page 44 of 111Figure 15. LeastCostCurve - Unit 1 NOxMost Cost Effective OptionCC/LNB/OFACCCC/LNB/OFA/SCR01,00020,00018,00016,000

Total Annual Cost, $1,000/yr14,00012,00010,0008,0006,0004,0002,0002,0005,0008,0003,0004,0006,0007,000Expected Reduction, tons/yrPage 45 of 111Figure 16. Least costCurve - Unit 2 NOxCC + SCRCCMost Cost Effective Option01,00016,00014,00012,000

Total Annualized Cost, $1,000/y r10,0008,0006,0004,0002,0001,5004,0002,0002,5003,0003,500Expected Reduction, tons/yrPage 46 of 111

### 4.B.5 Energy Impacts

There will be slight energy impacts from t he available an d applic able technologies.



### 4.B.6 Non-Air Q u ality Environm ent a l Impact s

No non-air quality environmental impacts were identified.



### 4.B.7 Rem a ini n g U sef ul Life

Since the useful life of Sher co is longer t han 20 years, there is no impact to the

annualized capital costs becaus e of a shorter us eful life for the unit than t h e feasible

technologies.



### 4.B.8 Visibility Impacts

Computer modeling was perfo rmed to predict the number of days that visibility

impairment would be greater than 0.5 dv. The model also predicts the change in the

98 th percentile delta dv, wher e a larger c hange in the delt a dv translates into an

improvement in visibility. Based on the control costs discussed earlier

, computer

modelin g was performed to predi ct the effect on visib ilit y of either in stallin g a

combustion optimization syst em for each unit, and low NO

x burners and SOFA for Unit

1 (Control Scenario 1), or installation of a combustion optimizat ion system a nd an SCR

for both units, and low NO

x burners and SOFA for U n it 1 (C ontrol Scenario 2). From

Table 17 and Figure 17, it can be seen th at, over the period from 2002 through 2004

, the computer model predicts a 98 th percentile delta dv of 2. 11 for Option 1 ( T able 13),

and 1.80 for Option 2 (Table 14). The m odel predic t s that there would be 227 day s

above 0.5 dv with Control Scenario 1 and 206 days above 0.5 dv for Control Scenario 2,

as opposed to the baseline of 263 days abov e 0.5 dv. It would cost approximately

$1,300,000 per dv to decrease the 98 th percentile delt a dv from 2.68 to 2.11 for Control

Scenario 1. It would cost approximatel y $18,000,000 per dv to decrease the 98 th

percentile delta dv from 2.68 to 1.80 for C ont rol Scenario 2. The incremental cost to

decrease the 98 th percentile delta dv from 2.11 to 1.80 is almost $100,000,000.

Page 47 of 111Page48 of 111Table 15. NOxPost-Control Emission Rates for Emission Unit EU001/EU002ControlScenario#NOxControlTechnologySO2Max 24Hour ActualEmissions,lb/day% Reduction(Increase)NOxMax 24Hour ActualEmissions,lb/day% ReductionPM2.5Max24 HourActualEmissions,lb/day% Reduction(Increase)PM10Max 24Hour ActualEmissions,lb/day% Reduction(Increase)1Sherco Unit 1 -LNB/SOFA/CCSherco Unit 2 – CC122,469056,97944N/AN/A1,96602Sherco Unit 1 -LNB/SOFA/CC/SCRSherco Unit 2 –CC/SCR122,469030,38970N/AN/A1,9660Table 16. NOxPost-Control Stack Parameters for Emission Unit EU001/EU002ControlScenario #NOxControlTechnologyStack No.LocationEasting(utm)LocationNorthing(utm)Height ofopeningfrom ground,ftBaseelevation ofground, ftStackDiameter, ftFlow rate atexit, acfmExit gastemperature,°F1Sherco Unit 1 -LNB/SOFA/CCSherco Unit 2 – CCSV001429,8425,025,44965096932.55,200,0001712Sherco Unit 1 -LNB/SOFA/CC/SCRSherco Unit 2 –CC/SCRSV001429,8425,025,44965096932.55,200,000171Table 17. NOxControls - Visibility Modeling Results2002200320042002-2004CombinedControlScenario#NOxControlTechnologyClass I AreawithGreatestImpactModeled98thpercentileValue,deciviewNo. ofdaysexceeding0.5deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5deciviewModeled98thpercentileValue,deciviewNo. of daysexceeding0.5deciview1Sherco Unit 1 -LNB/SOFA/CCSherco Unit 2 – CCBWCA2.02732.33772.22772.112272Sherco Unit 1 -LNB/SOFA/CC/SCRSherco Unit 2 –CC/SCRBWCA1.74631.95741.94691.80206Page49 of 111Table 18. Incremental Visibility Costs for BWCA for NOxControlControlCaseTechnologyTotalAnnualizedCostIncrementalTotalAnnualizedCost98thPercentileVisibilityImpairment,dvImpairmentImprovement,dvIncrementalImpairmentImprovement,$/dvBase2.68Case 1LNB/SOFA/CC - Unit 1,CC - Unit 2$2,700,000$2,700,0002.110.575,000,000Case 2LNB/SOFA/CC/SCR -Unit 1,CC/SCR - Unit 2$32,000,000$29,300,0001.800.3195,000,000LNB - Low NOxburnersSOFA – Separated/close coupled OFACC – Combustion optimizationPage50 of 111Figure 17. NOxVisibilityImpacts at BWCA2.602.932.772.682.022.332.222.111.741.951.941.800.000.501.001.502.002.503.003.502002200320042002-2004combinedYear

9 8 th P e rcentile va lue, dvBaselineSherco1 - LNB/OFA/CC, Sherco 2 - CCSherco 1 -LNB/SOFA/CC/SCR, Sherco 2- CC/SCR

### 4.B.9 Pro posed NO

x 

### BART

Xcel Energy proposes to install new LNB, a separated/close co upled OFA sy stem, and

a combustion optimiz ation system for Unit 1, and a c o mbustion opt imization system for

Unit 2. The proposed emission rate is 0.15 lb/MMBTU at t he stack, based on a 30-day

rollin g ave r age. This rate meets the pres umptive limit for tangent ia lly f i red bo iler s

burning su b-bitumino us coal. The controls will b e inst alle d on Un it 2 by the end of 200 6

and on Un it 1 by the end of 200 7. Complianc e with the new limit will b e d e monstrated

by the end of 2008. The propos ed option will reduce NO

x emitted from Sherco Units 1

and 2 on the order of 6,800 tons /year and allow Xcel Energy to meet CAIR Phase I

requirements.

The total annualized cost for the propos ed option is $2,700, 000, with a signific a nt

visib ility im provement of 0. 57 dv, or $5,000,000/dv (Table 18). Conversely, the total

annualized cost to move to the next most effective control technology (new SCR) is

approximately $29,300,000, and w ould further improve visibi lity by only 0.31 dv, or

$95,000,000/dv. The incremental cost-effe ctiveness between the proposed option an d

new SCR systems for both boilers is on t he order of $8,000/ton, whic h Xcel Energy

asserts is e x cessive.

Xcel Ener gy firmly believes the most cost -beneficial visibility improvements will be

brought about by installing new LNB, a s eparated/close coupled OFA system, and a

combustion optimization system for Unit 1, and a combusti on optimization s ystem for

Unit 2.

Page 51 of 111

### 4.C Particulate M atter Emission Controls – Emission Units

EU001/EU002

4.C.1 Av ailabl e Retrofit C ontr o l Te chnol ogie s

Sherco Un its 1 and 2 utilize wet electrosta tic precipitators (WESP) for particulate

control. A side benefit of the use of WESP is the control of SO 3

.

PM 10 control technologies that were identified as available for retrofit at Sherco are

listed below:

• Electrostatic precipitator (ESP)

• Pulse jet fabric filter (P JFF) baghouse

• Compact Hybrid Particulate Collector (COH PAC)

• GE MAX-9 Hybrid

• Multi-cyclone

• Wet ESP

Electrostatic precipitator

Electrostatic precipitators (ESPs) are the most widely installed utility particula te removal

technology. ESPs use transformer-rectifiers to energize discharge electrodes and

produce a high v o ltage, direct current electrical field between the discharge electrodes

and grounded collecting plates. Particulate matter entering the electrical field acquires

a negative charge and migrates to the grounded collecting plates. This migration can

be expressed in engineering terms as an em pirically determined effective migration

velocity, but it takes place in the turbulent flow regime, with the particulate entrained

within the turbulent gas patterns. Thus, t he charge d particles ar e actually captured

when the combined effect of electrical a ttraction and gas flow patterns moves the

particulate matter close enough s o that it can attach to the collecting surfaces. A layer

of collected particles forms on the collec ting plates and is removed per iodic a lly by

mechanically rapping t he plates. The collec ted particulate drops into hopper s below the

precipitator and is removed by the ash handling sy stem. Some particulate is a l s o

re-entrained and e i the r collected in subsequ ent el ectric al fields or em itted from the ESP.

A picture showing the sections of an ESP is shown in Figure 18.

Page 52 of 111Figure 18. Electros t a t ic Precipita tor Sy stem (MHI )

The required particulate removal efficiency, t he expected electrical resistiv ity of the fly

ash to be collected, and the expected electr ical c haracteristics of the energization

system determine the physical s i ze of an ESP. Many parameter s determine the ESPs

capability for particulate collection in cluding the followi n g major items.

The first parameter is the specific collecti on a r ea (SCA). ESP size is often measured in

terms of SCA, and is defined as the total collecting area (ft 2 ) divided by the volumetric

flue gas flow rate (1,000 acfm).

Second, the treatment time that the flue gas is withi n the electric c o llection fields of the

ESP is an important aspect of pa rticulate coll ection. High-efficienc y ESPs typically have

treatment times between 7 and 20 seconds. Treatment time is becoming a major

design par ameter, since lower partic ulate emissions are being mandated.

Page 53 of 111Flue gas v e locity, which is the speed with which the flue gas moves through the ESP, is

important in the desig n and sizi n g of the ESP. Design gas velocities ranging between 3

to 4 feet per second are common.

The aspect ratio, defined as the treatment l ength to t he collection plate height, is an

important design para m eter of ESPs. As the aspect ratio in creas es, the re-entrainmen t

l o sses from the E S P are mi ni mized. Many exi s ti ng ES P s have aspect rati os of around

0.8 to 1.2. Newer ESPs, es pecially those meeting new parti cu late emission limits, hav e

aspect ratios around 1.2 to 2.0.

The gas distribution for optimum particulate removal requires uniform gas veloc i ty

throughout the entire ESP treat ment volume with minimal g a s bypass around the

discharge electrodes or collecting plates. If flue gas distribution is uneven, the

particulate removal efficiency will decreas e and re-entrainment lo sses will increase in

high velocit y areas, reducing overall collection efficienc y.

Finally, fly ash resistiv ity is a measure of how easily the ash or particulate acquires an

electric charge. Typic a l coal fly as h resistivit y values range from 1 x 10 8 ohm -cm to 1 x

10 14 ohm-c m. The ideal resistiv ity range for elec trostatic precipit ation of fly ash is 5 x

10 9 to 5 x 10 10 ohm-cm. Ope r ating resistivity varies with flue gas moisture, SO 3

concentration, temperature, and ash chemical composition. As a result of fly ash

resistivity being se n s itive to these cons tituents, ESPs can be affected greatly by

changes in fuel or operating condit i ons.

Pulse jet fabric filter baghouse

Fabric filters are medi a filters that the flue gas passes th rough to remove the particulate.

Cloth filter media is ty pically sewn into cylin drical tubes called bags. Each fabric filter

may have thousands of these filter bags. T he filter unit is typi cally divided into

compartments, which allows online mainten ance or bag replac emen t. The quantity of

compartments is determined by maximum economic compartment size, total gas

volume rat e , air-to-cloth (A/C) ratio, and cl eaning system design. Extra compartments

for maintenance or offline cleaning increase t he reliabilit y at the expense of capital cost

and real estate utilization. Each comp artment includes at least one hopper for

temporary storage of the collect ed fly ash. A cut-away view of a puls e jet fabric filter

(PJFF) compartment is illustrated in Figure 19.

Page 54 of 111Figure 19. Pulse Jet F a b r ic Filter Co mpartmen t

Fabric bags vary in c o mposition, length, and cross-section (diam e ter or shape). Bag

selection c haracteristics vary wit h cleaning technology, emissions limits, flue gas an d

ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential.

Fabric bags are typically guarant eed for 3 year s but frequently last 5 years or more.

In pulse jet fabric filters the flue gas typically enters the compartment hopper and

passes from the outsi de of the bag to the insi de, depositing partic u late on the outside of

the bag. T o prevent t he collaps e of the bag, a metal cage is ins t alled on the ins i de of

Page 55 of 111the bag. T he flue gas passes up through the cent er of the bag into the outlet plenum.

The bags and cages are suspended from a tube sheet.

Cleaning is performed by initiati ng a downward puls e of air in to the top of the bag. The

pulse caus es a ripple effect al ong the lengt h of the bag. This releases the dust cake

from the bag surface. The dus t then falls into the hopper . This cleaning may occur wit h

the compartment online or offline. Care mu st be taken during desi gn to ensure that the

upward velocity between the bags is minimized so that particulate is not re-entrained

during the cleaning process. The PJFF cleans bags in sequential, us ually staggered,

rows. During online cleaning, part of the dust cake from the row being cleaned may be

captured by the adjacent rows. Despit e this apparent shortcoming, PJ FF have

successfully implemented online c l eaning on many large units.

The PJFF bags are typically made of felted ma terials that do not rely as heavily on the

dust cake’s filtering capability as woven fiberglass bags. This allows the PJ FF bags to

be cleaned more vigorously. The felted materi als als o allow the PJFF to operate at a

much higher cloth velocity, whic h significant ly reduces the size of the unit and the space

required for installation.

Compact Hybrid Particulate Collector

Another control technology us ed for particulate control is a high A/C ratio fabric filter

installed after an existing particulate cont rol device (typically a cold s i de E SP).

Commonly referred to as a Compact Hy b r id Particu l ate Co llect or (COHP A C TM ), thi s

technology was developed and trademarked by t he Electric Power Research Institute

(EPRI). A cut-away view of a COHPAC is s hown in F i gure 20. If activated carbon is

injected upstream of a COHPAC TM filter, this configuration is referred to as T O XECON I

and is also trademarked by EPRI

. The COHPAC TM filt er typically operates at A/C ratios

ranging from 6 to 8 ft/min. compared to a convent ional fabric filter that typically operat e

at A/C ratios of about 4 ft/min. F o r a COHPAC TM or TOXECON I system, th e majority of

the particulate is collected in the upstream particulate control device. Therefore, the

performance requirem ents of a high A/C ratio fabric filt er is r educ ed, allowing installation

of this technology in a smaller footprint area, with less steel and filtration media to

substantially lower both capital and operat i ng costs compared to conventional fabric

filters .

Page 56 of 111Figure 20. COHPAC Arra ngemen t

GE M A X-9 hybrid

The Max-9 electrostatic filter is essentially a high-efficiency PJFF that combines fabric

filter and ESP technologies. The Max-9 can be visualiz ed as an ESP us ing f abric filter

bags instead of collecting plates. A front and side elevation view of the Max- 9

particulate filter is illus t ra ted in Figure 21. When the dust particles are charged, they are

attracted to the grounded metal cage ins i de t he filter element, just as they would be

attracted to the collecting plates in an or dinary ESP. Since t he particles are charged

positively, they repel each other on the sur f ace of the filter, making the c o llected dust

cake very porous. This results in a reduction of filter drag at a pr essure drop about 25%

of a normal fabric filter. Consequently, th e Max-9 can operate at an A/C ratio highe r

than a conventional fabric filt er and can treat a significant gas volume wit h a smaller

footprint.

Process gas enters the Max-9 from a hopper inlet duct. The gas then flows upward

through the filters and out through the top of the filters. The area above the tube sheet is

a clean gas plenum. Compressed air pulses are used to clean the filters. Compressed

air pulses are used to clean the filters. A brie f, intense blast of air is fired through the

purge air manifold; holes in the blowpipes lo cated above the filter s direct the cleaning

air pulse down through the filt ers. The cleaning sequence is cont rolled by timers, which

trigger solenoids. The high v o lt age system operates at very low c u rrent densities and at

a steady state. There is no danger of fire caused by sparking, and the

transformer/rectifier requi res no voltage control.

Page 57 of 111The Max-9 can be supplied as s hop-assembled modules that can be erected on site,

although the units are usually custom engineered for each plant s i te and application to

make the best use of available s pace.

Figure 21. Max-9 Elec tro s ta tic Filter

M u lti-cyclone

Multiple-cy c lone separators, also known as mu lticlone s, consist of a number of small

diameter cyclones, operating in parallel and having a co mmon gas inlet and outlet, as

shown in Figure 22. Multiclones operate on the same principle as cyclones, creating a

Page 58 of 111main downward vortex and an ascending inner vortex. Mu ltic lones are m o re efficient

than single cyclones because they are longer and smaller in diameter. The longer

length provides longer residence time wh ile the s m aller diamet er creates greater

centrifugal force. These two factors result in better separation of dust particulates. The

pressure drop of multiclone collect o rs is higher than that of single-cyclone separators.

Cyclone collectors are centrif ugal collectors that rely on t he particle density and velocit y

to separate the fly ash from the flue gas. T he particulate-laden flue gas ent ers the top

or the side of the cyclone. An illustration of the component s and working principles of a

multi-cyclone is shown in Figures 22 and 23. Vanes impart a rotational velocity to the

flue gas, driving the fly ash to the edge of the cylinder. The fl ue gas then exits the

center of the cyclone out the t op, leaving the fly ash to f a ll out the bottom. At pressures

near one atmosphere and 2 to 5 in. wg pressure different ial, this technology can

effectively remove particles larger than 20 microns in size; particles less than 10

microns are usually unaffected and not removed.

Figure 22. Multi-c y clone Particula t e Collector

Figure 23. Multiclone

Page 59 of 111Wet ESP

Currently, both Sh erco Un its 1 a nd 2 have wet ESPs ( W ESP) tha t have b e e n retrofitted

into the venturi scrubber modules. If an SO 2 control strategy is selected that involves

the bypass or demolition of the venturi scrubbers, it may be applicable to consider the

installation of new WESPs at She r co.

A WESP c o llects particles base d on the sa me theory as a dry ESP: negatively charg e d

particles are collected on positiv ely char ge d surfaces. However, a WESP operates

quite differently from a dry ESP. The colle c ting surfaces are we t instead of dry and are

flushed with water to remove the parti culate. Typically, a WESP is installed

downstream of an existing wet FGD system wher e the flue gas is already sat u rated, so

the amount of added water is minimized. T he particulate collection efficiency is

enhanced by preventing re-entrainment after c ontact with the wet walls (as contrasted

with re-entrainment due to rappi ng on a dry electrostatic precip itator). Therefore, the

WESP is well suited for fine particulate or acid mist applicatio ns by reducing opac ity,

sulfuric acid mist (H 2 SO 4 ) and other aerosols.

The use of WESP for acid mist collection is one of the earliest app licatio ns for

electrostatic precipitators. Although there are few applications in the utility in dustry, this

is a mature technology with hundreds of i ndustrial installations. The particulate

characteristics, temperature and humidity in WESPs provide e xcelle nt fuel flexib ility

regarding particulate removal. W a ter chem istry, scaling and c o rrosion potential need t o

be carefully investigated.

The WESP collecting fields impart a negative charge to t he parti c les and c o llect them

on positively charged collecting electrodes. Each collection fi eld is equipped with

independent electrical bus s e ctions, each having a dedicated high voltage

transforme r/rectifier (T R) and controller. Th e controllers for each TR are loc a ted in an

environmentally controlled enclosure. Each electrical field has a separate discharge

electrode support fra m e suspended by alumina insulators. A heater-blower system

dedicated to each module supplies warm pur ge air for each of the insulator

compartments. The dischar ge electrode support frames ar e constructed from 304

stainless st eel. The discharge electrodes are suspended from t he upper gu ide frame

and held in the tube c enterline. The discharge electrode is a rigid electrode constructed

from 304 stainless s t eel and c ontains sp lit corona-generating el ements, which are

welded to the electrode in an opposed orient ation.

Page 60 of 111A WESP can be ins t alled in eit her horizontal or ver t ical gas flow orientation. In a

horizontal gas flow or ientat ion th e WESP is very similar to a common dry ESP. The

collection plates are arranged in parallel horizontal paths with discharge electrodes

hanging be tween them. Vertical gas flow WESPs are usually o f the tubular collectio n

plate type. The collec tion plates are arranged in an array of verti c al pipes o r channe l

with a disc harge elect r ode hanging down t he cent er of the pipe or channel. Channel

shapes suc h as squar es or hexagons have more efficient packing densities than circular

pipes (with a small loss in the maximum voltage that can be applied before sparking)

and are the more common. Where multiple el ectrical stages are used (ana logous to the

electrical fields in a horizontal gas fl ow ESP), the stages are stacked one above the

other. Two to three fields are common.

Several m a jor hurdles exist with the use of a WESP. First, the flue gas must be

saturated with moisture prior to entering the ESP to a llo w the W ESP to wo rk correctly.

This requir e s that a quenching system be inst alled t o add wat e r to the flue gas to

reduce the flue gas temperature to the sa turation point or the WESP ne eds to be

installed downstream of an exis ting wet FG D system. Without t he presence of a wet

FGD system, the WESP adds addi tional c o st, increases water demand on the plant,

and gener ates a vis i ble moistur e plume at the stack outlet. The removed particulate

would a l so be c ontained in a wa stewater stream that is ge nera t ed by the WESP. In

additio n to this issue, the capital cost of a WESP is high as compared to other

technologies because of the high er cost of the alloy materials required. A higher grade

of material is required to withstand the highly corrosive c onditions presented by the wet

and acidic flue gas stream.

Each WESP module is clean ed by sprayin g flush water over the WESP c o mponents.

Flush water is sprayed in the W ESP at d i fferent spray levels. Normally, each WESP

module is flushed once per day. Individual electrical sectio ns of each field may be

flushed on line while the power is turned off to the electrical section being cleaned.

The WESP system may require c ontinuous injection of dispersant into the system t o

help eliminate scale formation within the module. The dis persa nt can be stored in a

small tank and fed into the flush water sur ge tank allowing disper sant to enter the

modules through the spray levels.

Page 61 of 111Additionally , the WESP may periodically r equire out-of-service cleaning of a more

intense nature. Physical cleaning using hi gh pressure water jets (“hydro lasers”) or

chemical flushing us ing an acid based solvent to dissolve the s c ale build- u p are two

options.



### 4.C.2 Technical l y In feasible Options

The COHPAC system was not considered f easible because of blinding problem s

encountered when a slipstream system was tested at Sherco . The Max-9 Hybrid has

not been demonstrated at units in the size range of Sherco and was not considered

further in this study. Vent uri scrubbers and multi-cyclones ar e not effective at removing

fine partic u late. T h e addition of multiclones is not expected to provide ad ditional

reduction with the exist i ng venturi scrubbers and ar e not considered further in this study.



### 4.C.3 Control E ffective n e ss of Re maini ng Control

Te chnologies

Table 19. Control Effec t iv eness for PM 10

( l b / M M B T U ) ( t o n s / y r ) (tons/y r )

E m i t t e d E m i t t e d Rem o v e d

Unit 1 (Basel ine 0.018 lb/MMBTU)

ESPs Upstream of Current AQC Equipment 0.013 360 140

PJFF Upstream of Current AQC Equipment 0.01 3 360 140

Wet ESP Replacement 0.013 360 140

Unit 2 (Basel ine 0.018 lb/MMBTU)

ESPs Upstream of Current AQC Equipment 0.013 360 140

PJFF Upstream of Current AQC Equipment 0.01 3 360 140

Wet ESP Replacement 0.013 360 140



### 4.C.4 Impact Analy s is

Tables 20 and 21 show the costs of compliance for PM 10 control f o r Sherco Units 1 and

2 respectiv e ly for the technologies cons ider ed applicable and av ailable. Capital and

operating c o sts were estimated with CUECOS T, and supplemented wit h data from Xcel

Page 62 of 111Energy (Appendix A) . As thes e are order of magnit ude estimates, they are accurate

only to ±30%. The capital costs were annu alized over a 20-year period and then added

to the annual operating costs to obtain the total annualized costs for each technology.

The data in the table are sorted from leas t expensive total annualized c o st to most

expensiv e total annualized cost. As th e average cost-effecti v eness for all options

considered was greater than $70,000/ton, no incremental cost-effectivenes s

calculations were performed.

Page 63 of 111Page64 of 111Table 20. Unit 1 PM10Compliance CostsOptionNumberTechnologyExpectedReduction(tons/year)Rate(lb/MMBTU)CapitalCostsAnnualizedCapitalCostsAnnualOperatingCostsTotalAnnualizedCostCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)1New ESP upstream of existingAQC equip.1400.013$65,000,000$6,000,000$4,000,000$10,000,00075,0002Wet ESP replacement1400.013$76,000,000$7,000,000$3,000,000$10,000,00076,0003Pulse jet fabric filter w/wet FGD1400.013$55,000,000$5,000,000$6,000,000$11,000,00082,000Table 21. Unit 2 PM10Compliance CostsOptionNumberTechnologyExpectedReductiontons/yearRatelb/MMBTUCapitalCostsAnnualizedCapitalCostsAnnualOperatingCostsTotalAnnualizedCostCostEffectiveness$/tonIncrementalCostEffectiveness$/ton1New ESP upstream of existingAQC equip.1400.013$65,000,000$6,000,000$4,000,000$10,000,00075,0002Wet ESP replacement1400.013$76,000,000$7,000,000$3,000,000$10,000,00075,0003Pulse jet fabric filter w/wet FGD1400.013$55,000,000$5,000,000$6,000,000$11,000,00082,000

### 4.C.5 Energy Impacts

There are no major energy impacts from the control technolo g ies considered.



### 4.C.6 Non-air Q u ality Impacts

No non-air quality environmental impacts were identified.



### 4.C.7 Visibility Impacts

As the cost-effectiveness was so high fo r all options, no CALPUFF modeling was

performed for PM 10

.



### 4.C.8 Pro posed PM 10 

### BART

No technology would signific antly improve t he particulate control from current levels at

Sherco Units 1 and 2. As the cost-e ffectiveness was s o high for all option s

(> $70,000/ton) no new techno logy is proposed for PM 10 . Becaus e no new t e chnology

is proposed, no change to the permit limit i s proposed.

Page 65 of 111

### 4.D M u ltipollutant Controls – Emissions Units EU001/EU002

4.D.1 Av ailabl e Retrofit C ontr o l Te chnol ogie s

Research is ongoing to develop new and im proved technologies for multi-pollutant

control. The investigation focuses on addi ng new sorbents to more effectively adsorb

mercury and on using new tec hnologies t o oxid iz e and remove mercury. Electrically

induced oxidation of mercury is a new technol ogy that is also being investigated. The

list of emerging technologies is numerous and the technologies with the most promise

include the PowerSpan ECO TM , Enviroscrub TM and Mobotec ROFA/ROTAMIX TM

systems. Several ot her pr omising emerging technolog ies such as the Airborne TM and

BOC LoTO x TM systems are also in the early stages of development but are not as far

along in pilot testing as the others. Since many of these techn o log i es are still at the

pilot (slipstr eam) stage of development, they s hould be viewed wit h caution until more is

known and performance guarant ees become available.

PowerSpan

There are several em erging mult i-pollutant te chnologies that use hi gh electron beams or

other proprietary processes. One of the more promising technologies that has only

limited ex perience and has not been fully te sted on full-scale systems is the PowerSpan

ECO TM system. The ECO TM sys tem is located downst r eam of an existing particulate

control dev ice and the process consists of th ree stages. In the first stage, the flue gas

passes through a barrier discharge reactor where it is expos ed to a high voltage

discharge, generating high energy electrons . The electrons initiate a chemic al reaction

forming oxygen and hydroxy l ra dicals, which then oxidize NO

x , SO 2 , and mercury. A

process flow diagram of the ECO TM system is illustrated in Figure 24. This results in the

formation of nitric acid, sulfuric acid and me rcuric oxides. Stage 2 is the collection o f

these acids and oxides in a downstream ammonia scrubber. The final s t age is the

collection of acid aerosols, fine particu late matter and oxidized mercury in the

downstream wet ESP. Scrubber effluents c ontain dissolved ammoni um sulfate nitrate

(ASN) salt s along wit h solids and mercury. The ASN solutio n is sent to a recovery

process where the mercury is removed vi a a sulfur impregnated activated carbon

structure. Once the carbon activ a ted bed be comes saturated with mercury, then it is

disposed as a hazardous waste. The cleaned stream of ASN is c onverted to a saleable

fertilizer.

Page 66 of 111Figure 24. ECOTM Pro ces s Flo w Diagr a m

PowerSpan also offers a mercury only cont rol technology that uses a photochemical

oxidation ( P CO) process. In this process, mercury is ox idized vi a an ul travi o let (U V)

light. The UV lights are placed in the ductwork upstream of a particulate c ontrol dev i ce.

The PCO technology is in its infancy; because PowerSpan’s PCO process has no t

moved bey ond bench- scale testin g and has not been pilot test ed at a facility burning a

low sulfur coal, the technolog y will not be evaluated further.

Enviroscr ub

Enviroscru b is a multi-pollutio n c ontrol tech nol ogy that is capable of removing significant

amounts of elemental and oxidiz ed mercury, NO

x , PM 2.5 , and SO 2 . This technolo gy is

based on t he Pahlman Process. TM A sorbent made up of ox ides of m anganese called

Pahlmanite TM sorbent (PS) is injected upstream of the SDA wher e the flue gas mixes

with the PS. This is where the oxidation and adsor ption of mercury takes place. Other

pollutants such as SO 2 and NO

x are also adsorbed by the PS at this stage. Then the

SDA byproducts are separated from the flue gas in the PJFF. The fly ash and wast e

byproduct collected in the PJF F hopper is eventually transpor ted to a slurry tank for

subsequent PS regeneration in a reactor. A process flow diagram of the Pahlman TM

process is illustrated in Figure 25.

The config uration for this techno logy is as f o llo ws: particulate removal (existing ESP),

SDA, PJF F , sorbent regenerat ion and byproduct s e paration. Although significant

Page 67 of 111progress has been made on the sorbent r egeneration p a rt of its technology,

EnviroScrub is not c onsider ed a proven, viabl e technology. Since EnviroScrub’s

process has not moved beyond pilot-scale te sting, the technology will not be evaluated

further.

Figure 25. Pahlman Proc essTM Simplified Proce s s Flo w Di agra m

Phenix Cle a n Coal

The Clean Combustion System TM (CCS) is an advanced hybrid coal gasification /

combustion process that reduces the formation of NO

x and SO 2 emissions wh en

burning coal. The only reagent required fo r pollution control is limestone.

The CCS concept is that of an entrained-f low coal gasifier followed by stages of

combustion air. The CCS burner is uniquel y designed to provide the neces sary time,

temperature, and stoichiometry required for all the chemicals in coal to complete their

combustion reactions (to reach equilibrium conditions).

The coal, with limestone added as a sour ce of calcium for sulfur capture, is pulveriz ed

and introduced to the burner along with a limit ed am ount of hot combustion air. The

initial high t e mperature combusti on gasifies and/or releases al l the constituents of coal,

carbon, sulfur, nitrogen and as h compounds, into the gas. At these high temperatures

Page 68 of 111and with limited available ox ygen, the carbon aggressively commands oxy g en to form

CO from al l sources, including s u ch compounds as water (H 2 O). Nitrogen compound s

that may form, such as NO

x , HCN's and NH 4 , are s i mply forced to the m o lecular form

(N 2 ) by the aggressiv e action of carbon for ox ygen. In the presence of calcium, the

sulfur reacts to form calcium sulfide (CaS, a solid 'non-gaseous' partic le). The hydrogen

cannot compete with the ot her elements and remains H 2

.

The hig h combustion temperatures melt together the coal a s h (largely silica an d

alumna) and calcium sulfide soli ds to form an inert slag that drains from the bottom o f

the boiler. The very hot gases, high in CO and H 2 , and nearly free of NO

x and sulfur,

then exit into the boiler furnace. As t he gases cool and gene rate steam, additional

OFA air is added in st ages to the furnace to complete the combus tion of CO to CO 2 and

H 2 to water. These steps prevent formation of any new (thermal) NO

x and complete the

combustion with excess air. The clean hot gases then enter the boiler superheat

section as was before the retrof it. A schematic of the proce ss is shown in Figure 26.

Figure 26. Phenix Clea n Coal Proce s s Flo w Diagr a m

Page 69 of 111The CCS retrofit modification requires replacing the existi ng pulverized c oal burners

with new down-fired CCS burne rs, adding separated OFA to t he boiler f u rnace, and

powdered limestone to the coal f uel. This is a complex retrofit that involves the

modification of the boiler pressure parts. Mo st of the new, off-th e-shelf equipment fits

within the existing boiler space.

A CCS repowered boiler has t he potential to show improved efficiency from more

complete coal combu s tion, very low NO

x , and control of SO 2 emissions with either

Western or Midwest coals. Since t he CCS proc ess has not moved beyond the

demonstration stage, the technology will not be evaluated further.



### 4.D.2 Technical l y Infeasi b le O p tions

Since none of the options f o r multi- pollutant control have moved beyond the

demonstration phase, these options will not be considered further in this report.

Page 70 of 111

## 5.0 Conclusions

The Regional Haze Rule provi des that a state participating in the Clean Air Intersta te

Rule (CAIR), which includes Minnesota, need not require BART-eligible e l ectric

generating units to install BA RT, because EPA’s analy sis conc luded that CAI R controls

are ‘”better than BART” for elec tric generating units in stat es subject to CAIR. The

MPCA stated that it would determine whet her CAIR subs titutes for BART after BART

analyses have been submitted. Since EPA c oncluded that CAIR will provide mor e

visib ility im provement than BART, Xcel En er gy believ e s Sherco Units 1 a n d 2 shou ld

not be given BART limits an d instead CAIR should dr iv e emission reduction s.

Nevertheless, Xcel Energy performed a BART analysis for Sh erco 1 and 2 f o llowing the

guidance provided by the MPCA and EPA. The analysis summary table (Table 22)

follows this section.

Based on t he BART analysis for SO 2 , Xcel Energy proposes to retrofit the existing wet

scrubbers with sparger tubes and lime inj e ction. The proposed emission rate is 0.12

lb/MMBTU at the stack, on a 30-day rolling average, to be met by the end of 2012. This

rate is lower than the presumptive limit fo r similar units that are not achieving 50%

removal. The proposed option would reduc e SO 2 emit ted from Sherco Units 1 and 2 on

the order of 8,300 tons per year , and allows Xcel Energy flex ibility in ac hiev in g required

mercury reductions.

Xcel Energy has an obligati on to its ratepayers to eval uate all expenditures to ensur e

they are prudent. New wet FGDs would increase aux iliary power needed in the plant,

and would reduce energy available to consumers, requiring the need for generation

from some other source. The total annualiz ed cost for retrofitti ng the existing scrubbers

with sparger tubes and lime injection is $2,000,000, with a sign ificant visibility

improvement of 0.55 dv, or $4,000,000/dv. Conv ersely, t he total annualiz ed cost to

move to the next mos t effective control technology is approximat ely $72,000,000, and

this would further improve visibility by on ly 0.13 dv, or $550,000, 000/dv. Xcel Energy

firmly believes that retrofi tting the existing wet scrubbers with sparger tubes and lime

injection will bring abo ut the most economica l visib ility improvements.

Xcel Energy proposes a BART NO

x limit o f 0.15 lb/MMBTU at the stack, o n a 30-da y

rolling aver age, to be achieved by instal ling combustion optimizat ion system s for both

Sherco Units 1 and 2, and low NO

x burners and separated/close coupled overfire air for

Sherco Unit 1. This is the presumptive limit for the ca t egory of electric generating units

Page 71 of 111into whic h Sherco Units 1 and 2 fit. The pr oposed controls would be installed by the

end of 2007, and compliance with the proposed limit would be demonstrated by the end

of 2008.

The total annualized cost for installation of combusti on optimization systems for both

units and installation of new low NO

x burners and a separated/clos e coupled overfire air

system for Sherco Unit 1 is $2,700,000, with a significant vi sibility improvement of 0.57

dv, or $5,000,000/dv. Conversely, the total annualized cost to move to the next most

effective control technology is approximatel y $29,000,000; that techno logy would further

improve visibility by 0.31 dv, or $95,000,000/dv. Xcel Ener gy firmly believ e s that the

most economical visibility improvements will be broug ht about by the installation of new

combustion optimization systems for Sherco Units 1 and 2 and the installation of new

low NO

x burners and a separated/clos e coupled overfire air syst em for Sherco Unit 1.

No particulate matter control technology woul d significantly im prove the control from

current levels at Sher co Un its 1 and 2. The cost-effectiv eness v a lues are unreasonab ly

high for all PM10 options (>$70,000/ton). No new limit is proposed for PM 10

.

Page 72 of 111Table 22. Emission Unit EU001/EU002: Summaryof the Impacts Analysis for SO2, NOx, PM10ControlScenariosControlScenario#ControlTechnologyEvaluatedEmissionsPerformanceLevel(percentpollutantremoved)Baseline EmissionRate, tons/yearExpected EmissionsReductions, tons/yearCurrent EmissionRate, lb/MMBTUExpectedEmission Rate,lb/MMBTUTotalAnnualizedControlCost, $Average CostEffectiveness,$/tonpollutantremovedIncrementalCostEffectiveness,$/tonpollutantremovedEnergyImpactsCollateralIncrease inOtherPollutants?Non-AirQualityEnvironmentalImpactsGreatestChangeinmodeledvisibilityon 98thPercentileday frombaseline,dv

SO 2 NO x PM 10 SO 2 NO x PM 10 SO 2 NO x PM 10 SO 2 NO x PM 10 SO 2 NO x PM 10 SO 2 NO x PM 101X44%14,6526,5000.34/0.200.152,700,000400NoNoNo2.112X70%14,65210,3000.34/0.200.0832,000,0003,1007,800YesNoNo1.803X56%14,9758,3000.270.122,000,000200NoNoNo2.134X67%14,97510,0000.270.0974,000,0007,40043,000YesNoNo2.00Control Scenario 1:Combustion optimization/low NOxburners/separated OFA – Sherco Unit 1,Combustion optimization – Sherco Unit 2Control Scenario 2:Combustion optimization/low NOxburners/separated OFA /selective catalytic reduction – Sherco Unit 1,Combustion optimization/selective catalytic reduction – Sherco Unit 2Control Scenario 3:Retrofit existing scrubbers with sparger tubes and limeinjection – Sherco Units 1 and 2Control Scenario 4:Install new wetFGD systems – Sherco Units 1 and 2The total annualized costs for each control scenario were obtained by adding thetotal annualized costs for each unittogether for proposed options. For example, the total annualized cost for anew wet FGD system for Sherco Unit 1was added to the total annualized cost for a new wet FGD system for Sherco Unit 2, and reported in the TotalAnnualized Control Cost column in thetable above. The expected emissions reductions were calculated the sameway, however all reported numbers are rounded.Page 73 of 111Page 74 of 111 Table 23. Visibilit y Modeling: Baseline Model Results

2 0 0 2 2 0 0 3 2 0 0 4 2 0 0 2

- 2 0 0 4 Control Sc enario

Class I Area 98%

dv # days

>0.5 dv 98%

dv # days

>0.5 dv 98%

dv # days

>0.5 dv 98%

dv # days

>0.5 dv

Baseline BWCA

VNP

IR 2.60

1.98

1.69 85

54

50 2.93

2.51

2.04 87

55

52 2.77

2.39

1.95 91

56

57 2.68

2.34

1.79 263

165

159

Table 24. Visibilit y Modeling: Boundar y Waters Results

2 0 0 2 2 0 0 3 2 0 0 4 2 0 0 2 t h r o u g h

2004 Control

Scenario 98 th %

∆ dv # of days

> 0.5 dv 98 th %

∆ dv # of days

> 0.5 dv 98 th %

∆ dv # of days

> 0.5 dv 98 th %

∆ dv # of days

> 0.5 dv

B a s e l i n e 2

. 6 0 8 5 2

. 9 3 8 7 2

. 7 7 9 1 2

. 6 8 2 6 3

C a s e 1 2

. 0 2 7 3 2

. 3 3 7 7 2

. 2 2 7 7 2

. 1 1 2 2 7

C a s e 2 1

. 7 4 6 3 1

. 9 5 7 4 1

. 9 4 6 9 1

. 8 0 2 0 6

C a s e 3 2

. 0 1 6 4 2

. 3 6 7 2 2

. 2 8 7 2 2

. 1 3 2 0 8

C a s e 4 1

. 9 2 6 4 2

. 5 1 6 9 2

. 0 9 7 3 2

. 0 0 2 0 6

Table 25. Visibilit y Modeling: Vo y a ge ur National Park Results

2 0 0 2 2 0 0 3 2 0 0 4 2 0 0 2 t h r o u g h

2004 Control

Scenario 98 th %

∆ dv # of days

> 0.5 ∆ dv 98 th %

∆ dv # of days

> 0.5 ∆ dv 98 th %

∆ dv # of days

> 0.5 ∆ dv 98 th %

∆ dv # of days

> 0.5 ∆ dv

B a s e l i n e 1

. 9 8 5 4 2

. 5 1 5 5 2

. 3 9 5 6 2

. 3 4 1 6 5

C a s e 1 1

. 6 6 4 6 1

. 9 2 5 1 1

. 7 6 5 0 1

. 8 2 1 4 7

C a s e 2 1

. 4 8 4 1 1

. 7 4 5 0 1

. 5 9 4 5 1

. 5 9 1 3 6

C a s e 3 1

. 4 6 3 9 1

. 8 6 4 5 1

. 8 7 3 9 1

. 7 5 1 2 3

C a s e 4 1

. 5 4 4 5 1

. 8 9 4 4 1

. 7 8 3 9 1

. 6 5 1 2 8Page 75 of 111 Table 26. Visibility Modeling: Isle Royale Results

2002 2003 2004 2002 through

2005 Control

Scenario 98 th %

∆ dv # of days

> 0.5 ∆ dv 98 th %

∆ dv # of days

> 0.5 ∆ dv 98 th %

∆ dv # of days

> 0.5 ∆ dv 98 th %

∆ dv # of days

> 0.5 ∆ dv

Baseline 1.69 50 2.04 52 1.95 57 1.79 159

Case 1 1.35 41 1.59 44 1.47 46 1.44 131

Case 2 1.20 39 1.40 36 1.30 42 1.30 117

Case 3 1.16 38 1.38 40 1.47 43 1.34 121

Case 4 1.22 38 1.37 35 1.73 45 1.37 118

1 & 3 0.90 30 1.11 23 1.07 34 0.98 87

2 & 3 0.71 24 0.91 19 0.84 26 0.82 69Appendix A

CUECOST InputPage 77 of 111Page 78 of 111 Page 78 of 111Page 79 of 111 Page 79 of 111Page 80 of 111 Page 80 of 111Page 81 of 111 Page 81 of 111Page 82 of 111 Page 82 of 111Page 83 of 111 Page 83 of 111Page 84 of 111 Page 84 of 111Page 85 of 111Page 86 of 111 Page 86 of 111Page 87 of 111Page 88 of 111Page 89 of 111Page 90 of 111Page 91 of 111Page 92 of 111 Page 92 of 111Page 93 of 111Page 94 of 111Page 95 of 111 Page 95 of 111Page 96 of 111 Page 96 of 111Page 97 of 111Page 98 of 111Appendix B

Visibility Impact In Class I AreasFigure 27. SO2VisibilityImpacts at BWCA2.602.932.772.682.012.362.282.131.922.512.092.000.000.501.001.502.002.503.003.502002200320042002-2004 combinedYear

98th P e rcentile v a lue, dvBaselineSpargersWetFGDPage100of111Figure 28. NOxVisibilityImpacts at BWCA2.602.932.772.682.022.332.222.111.741.951.941.800.000.501.001.502.002.503.003.502002200320042002-2004combinedYear

9 8 th P e rcentile va lue, dvBaselineSherco1 - LNB/OFA/CC, Sherco 2 -CCSherco 1- LNB/SOFA/CC/SCR, Sherco 2- CC/SCRPage101of111Figure 29. SO2VisibilityImpacts at BWCA8587912636472722086469732060501001502002503002002200320042002-2004 combinedYear

# Days > 0.5 dvBaselineSpargersWetFGDPage102of111Figure 30. NOxVisibilityImpacts at BWCA8587912637377772276374692060501001502002503002002200320042002-2004 combinedYear

# Days > 0.5 dvBaselineSherco 1 - LNB/OFA/CC, Sherco 2 - CCSherco 1 - LNB/SOFA/CC/SCR,Sherco 2 - CC/SCRPage103of111Figure 31. SO2VisibilityImpacts at IR1.982.512.392.341.461.861.871.751.541.891.781.650.000.501.001.502.002.503.002002200320042002-2004 combinedYear

98 th Pe rcent ile val ue, dvBaselineSpargersWetFGDPage104of111Figure 32. NOxImpacts at IR0.000.501.001.502.002.503.002002200320042002-2004 combinedYear

98 th Pe rcent ile Va lue, dvBaselineSherco 1 - LNB/OFA/CC, Sherco 2 - CCSherco 1 - LNB/SOFA/CC/SCR,Sherco 2 - CC/SCRPage105of111Figure 33. SO2VisibilityImpacts at IR5455561653945391234544391280204060801001201401601802002200320042002-2004 combinedYear

# Days > 0 .5 dvBaselineSpargersWetFGDPage106of111Figure 34. NOxVisibilityImpacts at IR5455561654651501474150451360204060801001201401601802002200320042002-2004 combinedYear

# Days > 0 .5 dvBaselineSherco 1 - LNB/OFA/CC, Sherco 2 - CCSherco 1 - LNB/SOFA/CC/SCR,Sherco 2 - CC/SCRPage107of111Figure 35. SO2VisibilityImpacts at VNP1.692.041.951.791.161.381.471.341.221.371.731.370.000.501.001.502.002.502002200320042002-2004 combinedYear

98 th pe rcent ile Va lue, dvBaselineSpargersWetFGDPage108of111Figure 36. NOxVisibilityImpacts at VNP1.692.041.951.791.351.591.471.441.201.401.301.300.000.501.001.502.002.502002200320042002-2004 combinedYear

98 th Pe rcent ile val ue, dvBaselineSherco 1 - LNB/OFA/CC, Sherco 2 - CCSherco 1 - LNB/SOFA/CC/SCR,Sherco 2 - CC/SCRPage109of111Figure 37. SO2VisibilityImpacts at VNP5052571593840431213835451180204060801001201401601802002200320042002-2004 combinedYear

# Days > 0.5 dvBaselineSpargersWetFGDPage110of111Figure 38. NOxVisibilityImpacts at VNP5052571594144461313936421170204060801001201401601802002200320042002-2004 combinedYear

# Days > 0 .5 dvBaselineSherco 1 - LNB/OFA/CC, Sherco 2 - CCSherco 1 - LNB/SOFA/CC/SCR,Sherco 2 - CC/SCRPage111of111