Wisconsin Electric Power Company’s Application to Install Wet Flue Gas 

Desulfurization and Selective Catalytic Reduction Facilities and Associated 

Equipment On Oak Creek Power Plant Units 5, 6, 7 & 8 for Control of Sulfur 

Dioxide and Nitrogen Oxide Emissions 

Appendix C 

Oak Creek Units 5, 6, 7 and 8 

NOx/SO2 Emissions Reduction Study 

PSC REF#:77790 Public Service Commission of Wisconsin

RECEIVED: 06/21/07, 1:23:24 PM
WE ENERGIES 

OAK CREEK UNITS 5, 6, 7 AND 8 

NOx/SO2 EMISSIONS REDUCTION STUDY 

VOLUME 1 

TECHNICAL AND APPENDICES 

Washington Group International, Inc. 

Building 510 Carnegie Center 

Princeton, New Jersey 08540-5287 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

REPORT REVISION PAGE

Project Name: Oak Creek Units 5 - 8 Discipline: All 

Client: We Energies

Latest Revision: 3

Status 

Rev. 

No. Date Prepared By Pages Description of Changes 

Draft 0 09/08/06 T. Tsui Draft Report for Client Review 

Final 1 09/25/06 T. Tsui Final Report 

Revision 2 10/12/06 T. Tsui Final Report 

Revision 3 04/26/07 A. Crawford Final Report 

 

 

 

 

 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

VOLUME 1 

TABLE OF CONTENTS 

Tab Description Page 

1.0 EXECUTIVE SUMMARY .................................................................................................1

1.1 Background............................................................................................................................1 

1.2 NOx and SO2 Emissions Technology Selection Process........................................................1 

1.3 Constructability......................................................................................................................5 

1.4 Project Schedule.....................................................................................................................5 

2.0 STUDY BASIS .....................................................................................................................7

2.1 Design Coal............................................................................................................................7 

2.2 Boiler Data .............................................................................................................................7 

2.3 Oak Creek ESP Outlet Design Conditions.............................................................................8 

2.4 Emissions Limits....................................................................................................................9 

2.5 Equipment Design Assumptions............................................................................................9 

2.6 Cost Estimate Assumptions ...................................................................................................9 

3.0 DESCRIPTIONS OF EVALUATED SO2 AND NOX CONTROL 

 TECHNOLOGY ................................................................................................................11

3.1 In Furnace NOx Control Technologies ................................................................................11 

3.2 Post Combustion NOx Control Technology – Selected Catalytic Reduction (SCR)...........13 

3.3 SO2 Control Technologies ...................................................................................................16 

3.4 Multi-Pollutant (NOx, SO2 and Mercury) Control Technology...........................................23 

4.0 NOX CONTROL TECHNOLOGY EVALUATION ......................................................30

4.1 Evaluation Criteria ...............................................................................................................30 

4.2 Technology Evaluation Results of Selective Catalytic Reactor (SCR) System ..................31 

4.3 Elimination of Hot Side SCRs use on Units 5 & 6..............................................................32 

4.4 Cold-Side and Tail End SCR Industry Experience..............................................................33 

4.5 Technology Evaluation Results of Mobotec ROFA/ROTAMIX System............................34 

4.6 Technology Evaluation Results of Mitsui Babcock NOxStar System.................................35 

4.7 Summary of NOx Control Technology Screening Results ..................................................35 

5.0 SO2 CONTROL TECHNOLOGY EVALUATION .......................................................39

5.1 Evaluation Criteria ...............................................................................................................39 

5.2 Technology Evaluation Results of Wet Limestone Forced 

 Oxidation (LSFO) Process...................................................................................................40 

5.3 Technology Evaluation Results of Lime Spray Drying (LSD) / Fabric 

Filter (FF) System................................................................................................................41 

5.4 Technology Evaluation Results of Circulating Fluid Bed Scrubber (CFB)/ 

Fabric Filter (FF) System.....................................................................................................42 

5.5 Summary of SO2 Control Technology Evaluation Results..................................................43 

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TABLE OF CONTENTS (Cont'd) 

Tab Description Page 

6.0 MULTI-POLLUTANT (NOX/SO2) CONTROL TECHNOLOGY 

 EVALUATION ..................................................................................................................44

6.1 Technology Evaluation Results of J-Power ReACT System...............................................44 

6.2 Technology Evaluation Results of PowerSpan ECO System..............................................45 

6.3 Summary of Multi Pollutant Control Technology Evaluation Results................................45 

7.0 SO2 AND NOX COMBINED SYSTEM EVALUATION ...............................................47

7.1 Case 1 LSFO and Tail-end SCRs for all Four Units...........................................................47 

7.2 Case 2 LSFO and Cold-side SCRs for all Four Units.........................................................49 

7.3 Case 3 LSFO for all Four Units, Cold-side for 5&6, and Hot-side SCRs for 7&8 ............51 

7.4 Case 4 LSFO for all Four Units, Tail-end SCRs for 5&6, and 

Hot-side SCRs for 7&8........................................................................................................52 

7.5 Comparison of Cases 1 to 4.................................................................................................55 

8.0 CONCLUSIONS AND RECOMMENDATIONS...........................................................56

8.1 Process Selection .................................................................................................................56 

8.2 Site and New Plant Area Considerations.............................................................................57 

8.3 Construction Considerations................................................................................................59 

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1.0 EXECUTIVE SUMMARY 

1.1 Background

We Energies' Oak Creek plant is located on the shore of Lake Michigan, 20 miles south of 

Milwaukee. The plant, located on a 400-acre site, consists of 5 operating Units; 5, 6, 7 and 8 are 

coal fired while Unit 9 is a combustion turbine Unit. The fuel used in Units 5-8 is PRB coal. These 

Units were initially designed to burn eastern bituminous coal, and since have switched to PRB coal 

to reduce SO2 emissions in accordance with We Energies' emissions-reduction program. Units 5, 6, 

7 and 8 are 1959, 1961, 1967 & 1968 vintages, respectively. Units 1-4 have been retired. The coal 

is supplied to the plant by Union Pacific unit trains. Average coal use varies between 5,000 to 

10,000 tons per day, based on the dispatch load requirements. 

Units 5 and 6 have Foster Wheeler arch-fired furnace steam generators. Units 7 and 8 are 

Combustion Engineering corner-fired units. Steam production is at 2400 psig and 1050°F. Each 

Unit has a turbine generator, which produces electric generation at 18 kV. Step-up transformers 

raise supply power to the grid to 138 kV (Unit 5) and 230 kV (Units 6, 7 and 8). 

Electrostatic precipitators remove fly ash from the flue gas prior to discharge to the atmosphere at 

the chimneys. Two chimneys are provided, one each for 2 boiler Units. Once through cooling with 

water from Lake Michigan cools the exhaust steam at the surface condensers. 

Currently We Energies is expanding Oak Creek generation through construction of two supercritical 

615 MW coal-fired Units just north of the existing plant. These Units are equipped with SCRs for 

NOX reduction and limestone forced oxidation (LSFO) systems for SO2 removal. The bi-product of 

the LSFO systems will be gypsum of wallboard production quality. 

1.2 NOx and SO2 Emissions Technology Selection Process 

The objective of this study was to select the most cost-effective, technically and commercially viable 

processes for SO2 and NOx emissions control at Oak Creek for Units 5, 6, 7 and 8. 

Washington Group International (Washington Group) visited the site and obtained the pertinent site 

data through observation of the plant, discussions with plant personnel, and through collection of the 

applicable documentation. We Energies provided the plant design data including the data required 

for economic evaluation. The following processes were considered for evaluation in this Study, 

based on potential to reach the required emission rates: 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

A. SO2 Removal (FGD) Processes 

• Limestone Forced Oxidation (LSFO) 

• Lime Spray-Dryer with Baghouse (LSD) 

• Circulating Fluid Bed with Baghouse (CFB) 

B. NOX Removal Processes

• Mobotec ROFA / ROTAMIX 

• Mitsui NOxStar 

• Foster Wheeler Low NOx Burners 

• SCR (Hot Side, Cold Side, and Tail-end) 

C. Multi-pollutant Processes 

• J-Power ReACT Technology 

• PowerSpan ECO Technology 

These processes represent mature, commercially well-proven technologies, while others are 

demonstrated technologies but do not possess the same level of commercial experience. The not-somature technologies were considered with the view that if the evaluation results indicate 

overwhelming economic benefits with their use, that may justify taking the technology risks 

associated with selecting them. 

The plant costs were established for each of these processes using Washington Group's EPRI 

program IECCOST. The IECCOST program provides order-of-magnitude cost estimates that are 

useful for comparing and screening alternative technologies. The capital costs in the IECCOST 

program are based on historical cost data and recent equipment costs, driven by mass balances for 

the particular Units. Adjustments to the base IECCOST output were made based on conceptual 

general arrangements for the Oak-Creek site as well as other site-specific considerations. Additional 

cost inputs were obtained from vendors and were factored into the cost estimates. 

The IECCOST program also develops fixed and variable operating and maintenance costs for each

emission-control process. This study also evaluated predicted performance, reliability, and 

availability for each of the processes considered. The total estimated capital costs, operating and 

maintenance costs, levelized annual costs, and total evaluated costs were developed. Costs presented 

in this report are in levelized 2006 dollars. Costs details are presented in Sections 4 to 7 of this 

Report. A summary of the comparative cost information is presented below. 

In addition to the cost comparison, other factors relating to the competing technologies were used in 

the selection process to determine the most technically and commercially viable system. To quantify 

these factors, a numerical ranking process was used based on the following: 

• Technology 

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 NOX AND SO2EMISSIONS REDUCTION STUDY

• Constructability 

• O&M 

• Commercial Risk 

• Performance Margin 

• Stable Long-term Market for Byproduct (SO2 systems) 

The results of both the cost estimating and technology ranking process are shown in the tables 

below: 

A. SO2 Removal Systems 

The LSFO system is the preferred technology choice when compared to SDA and 

CFB systems based on total evaluated cost. 

 System 

Cost $M LSFO SDA CFB

Capital Cost 310.8 334.8 313.2

Levelized O&M 28.3 43.4 41.4

Total Evaluated Cost 585.3 755.6 715.0

Evaluated Rank* 23.0 18.0 18.0

Notes:

Costs are for all four Units. LSFO is located downstream of cold-side SCRs. 

*Denotes that higher number is more favorable 

B. NOx Removal Systems 

Based on the lack of demonstrated ability to achieve the desired NOX emission 

reductions with the Mobotec and Mitsui technologies, they were eliminated from

further consideration. Hot-side SCR on Units 5 & 6 cannot be constructed without a 

major reconstruction of the units from the economizer through the electrostatic 

precipitator. The outage impact of this construction is estimated to exceed 

$200 million, so this option was eliminated. Hot-side SCRs on Units 7 & 8 have 

significantly more difficult retrofit construction than standard installations, which 

would increase the estimated total evaluated cost (TEC) when compared with other 

SCR options. The current estimate favors tail-end SCR, but this decision will be 

examined further during detailed engineering, and therefore tail-end SCR is the 

basis for the estimate comparisons in this report.

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

 System

Cost $M

SCR 

Hot Side 7 & 8*

Cold Side 5 & 6

SCR 

Cold Side 

(All Units)

SCR 

Tail End 

(All Units)

Capital Cost 241.9 190.5 178.6 

Levelized O&M 22.6 19.8 12.9 

 Total Evaluated Cost 479.1 382.3 303.7

Evaluated Rank 19 20 22 

*Including $18M power penalty. 

C. Multi-Pollutant Technologies 

The ReACT system from J-Power is a Japanese technology with limited operating 

experience. The ability of the ReACT system to meet Oak Creek's NOx-removal 

requirements has not been demonstrated in large scale. The market for the sulfuric 

acid byproduct is saturated, and other disposal options are not available. Further, 

total evaluated cost is not significantly different from the selected option, and is 

subject to more uncertainty due to the early development stage of the technology. 

The PowerSpan ECO system reduces both SO2 and NOx. This technology has 

currently been demonstrated at a 50 MW scale. The planned next-generation 

application of this technology is for a plant in the 200 MW range. Application of 

this technology for a plant the size of Oak Creek is not anticipated in the required 

timeframe, so its use at Oak Creek would be first-of-a-kind, and would entail 

significant technology risk. The total evaluated cost of PowerSpan ECO compared 

to LSFO and tail-end SCR differs by less than 6%, which is not considered 

significant given the accuracy of the current estimates. Further, due to the early 

development stage of the technology, the PowerSpan estimate is subject to more 

uncertainty.

 

D. Technology Recommendation 

The recommended technology is a combination of LSFO and SCR on units 5 

through 8. The tail end SCR location is preferred, and will be verified during 

detailed design. 

Key considerations for this selection: 

LSFO Process: 

• Has the highest ranking based on the evaluation criteria 

• Can achieve the highest SO2 emission reduction efficiency (up to 98%) 

• Provides the greatest fuel flexibility 

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 NOX AND SO2EMISSIONS REDUCTION STUDY

• Provides opportunity for shared savings with the Elm Road project 

SCR Process: 

• Has the highest ranking based on evaluation criteria 

• Has the most commercial experience and industry acceptance 

• Achieves high NOx reduction efficiency 

• Provides fuel flexibility 

1.3 Constructability 

A number of different system arrangements were considered, with the intent of locating the new 

equipment as close to the existing Units as possible, and minimizing the cost of running flue gas 

ductwork from the existing plants to the new equipment. Ultimately it was determined that the only 

practical location for the new equipment, for all four Units, is in the open area to the south of the 

plant. The study determined that there is adequate space in this area to accommodate the new 

emissions reduction system. 

Constructability issues were also addressed, including: tie-ins to existing plant with minimal 

interruptions to operations, construction laydown area requirements, barge unloading facilities, crane 

access, equipment unloading at the dock, labor availability, construction sequence and schedule. It 

may be desirable to build a temporary dock on the lakeshore adjacent to the new facilities to 

facilitate shipping modularized equipment. 

The most practical construction sequence will be from west to east, Unit 8 first on the West Side 

with Units 7, 6, and 5 following towards the east. This will facilitate equipment movement and 

crane access. Laydown and preassembly areas, and craft parking areas were identified southwest 

and west of the new plant area. There is adequate space available for the construction laydown 

purposes. The interconnecting ductwork from the existing Units to the new equipment has been 

routed and determined to be constructible from the east side of the existing Units, without 

interruptions to ongoing operations. 

Although further study is required regarding labor issues, based on the currently available 

information it appears that adequate labor will be available to man the proposed construction in the 

Oak Creek project time frame. 

1.4 Project Schedule 

A preliminary project development schedule has been prepared, identifying key milestones 

necessary to meet the consent-decree-required in-service dates. The schedule projects that in 2007 

engineering will commence and permits will be obtained. Full project Notice-to-Proceed is 

projected to occur by 1 January 2008. Early site activities in 2008 would involve site preparation 

including the demolition and relocation of underground utilities. Permanent plant equipment facility 

construction is scheduled to start in March 2009 to minimize site construction overlaps and 

interferences and competition for labor with the Elm Road facility construction. The schedule 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

projects commercial operation of Units 7 & 8 by 1 June 2012, and Units 5 & 6 by 15 November 

2012, which meet the required consent decree in-service dates. 

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 NOX AND SO2EMISSIONS REDUCTION STUDY

2.0 STUDY BASIS 

The designs and analyses contained in this report are based on the plant information supplied by We 

Energies, data gathered during visits to the station, and reasonable assumptions and extrapolations 

from previous studies. This section summarizes the design data used for the technical and economic 

analyses of the wet and dry FGD systems, J-Power ReACT system, PowerSpan ECO system, 

Mobotec ROFA/ROTAMIX, Mitsui Babcock NOxStar, and SCR as they would be applied to the 

various configurations at the Oak Creek plant. 

2.1 Design Coal 

For this study, 100% Pleasant Prairie Power Plant (P4) Design PRB coal serves as the design basis 

coal. 

The ultimate analysis of the P4 design-basis fuel is provided in Table 2-1. 

Table 2-1. Coal Analysis 

Item Units PRB Coal

Ultimate Analysis 

Carbon % 49.28

Hydrogen % 3.65

Nitrogen % 0.70

Oxygen % 11.10

Sulfur % 0.50

Chlorine % 0.02

Water % 29.90

Ash % 4.85

Total % 100

HHV, Btu/lb 8,677 

2.2 Boiler Data 

The existing Oak Creek Power Plant is comprised of four (4) pulverized coal fired boilers. At 

current boiler conditions, Units 5 and 6 operate at approximately 85% MCR when firing 100% PRB 

coal and at 100% MCR when supplemented by natural gas. Units 7 and 8 can reach the maximum 

continuous rating (MCR) while firing PRB coal. 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

The operating conditions for Units 5, 6, 7 and 8 when burning PRB coal are provided in Table 2-2. 

Table 2-2. Unit Design Data 

Boiler Units 5 and 6 Units 7 and 8 

Status Existing Existing

Gross Rating, MW 522 669 

Net Rating, MW 500 641 

Gross Unit Heat Rate, Btu/kWHr 9,945 9,666 

Net Unit Heat Rate, Btu/kWHr 10,376 10,085 

Capacity Factor, % 70 70 

Excess Air Downstream of Economizer, % 25 20 

Air Heater Leakage, % 12 12 

Stack NOx Emissions, lbs/MMBtu 0.2 0.15 

Flue Gas Temp. at ESP Outlet, °F 295 286

Particulate Loading At ESP Outlet, lb/MMBtu (*) 0.022 – 0.030 0.017 –0.094 

Note: (*) Per Stack Test Data. 

2.3 Oak Creek ESP Outlet Design Conditions 

Table 2-3 summarizes the flue gas flow rates for the four Oak Creek units. The gas flow rates and 

compositions are based on the existing ID fan inlet conditions. The NOx and fly ash data are based 

on stack measurements. 

Table 2-3. Oak Creek Flue Gas Conditions at the ID Fan Inlet 

Units 5 & 6 Units 7 & 8 

SCFM 1,320,000 1,584,000 Flue Gas Flow 

ACFM 2,025,000 2,401,000

Oper. Pressure In. w.c. -12 -12 

Temperature °F 295 286

O2 lbs/hr 372,516 401,365

CO2 lbs/hr 1,080,662 1,345,658

N2 lbs/hr 4,182,205 5,001,920

HCl lbs/hr 123 153

SO2 lbs/hr 5,976 7,441

H2O lbs/hr 414,471 514,120

Fly Ash lbs/hr 156 194 

Total (Gas only) lbs/hr 6,056,109 7,270,851 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

2.4 Emissions Limits 

The SCR and FGD systems are designed to meet the following NOx and SO2 emission limits. 

• NOx 0.07 lbs/MMBtu 

• SO2 0.07 lbs/MMBtu 

2.5 Equipment Design Assumptions 

The key assumptions for this study include the following: 

• All the wet or dry FGD systems will be located on the South Side of the plant. 

• 29% aqueous ammonia will be used as the reagent for the ReACT, ECO and 

SCR systems. 

• Delivery of reagent and removal of by-product, will be by truck. 

• The new equipment will be designed and installed so that it does not obstruct 

maintenance and operation access to the existing plant during construction or 

after construction is complete. 

• The existing ID fans will not be adequate for the increased flue gas system 

pressure drop through the wet or dry FGD system, so new booster fans will be 

required. 

• The existing boiler furnaces, heat recovery areas, and all the components in the 

flue gas path to the existing ID fans need not be stiffened due to any transient 

conditions that may occur with the installation and operation of the new 

emission reduction equipment. 

• The existing auxiliary electric system will not be adequate to supply the 

additional electrical load imposed by the new wet or dry FGD equipment. Two 

new auxiliary transformers located on the West Side of the turbine building 

will supply power to the new emission reduction equipment. 

• Ductwork from the existing induced fans to the new FGD equipment will be 

made of carbon steel, and insulated. 

2.6 Cost Estimate Assumptions 

The economic criteria and costs provided in Table 2-4 were used to generate the capital and 

operating cost estimates in this report. 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

Table 2-4. Economic Criteria 

Variable Units Value

Economic Criteria 

Discount Rate (MAR) % 7.5 

 AFUDC Rate % 10.3

 Construction Period Years 3

First Year Fixed Charge Rate % 19.2 

Levelized Fixed Charge Rate (FCR) % 14.4 

Levelized Fixed Charge Rate (FCR, constant $) % 10.5 

Service Life For Units 5 & 6 Years 15 

Service Life For Units 7 & 8 Years 30 

 Start-Up Date Year 2009

 Inflation Rate % 3.0

Land Cost (@ Start-Up Date) $ 0 

 Power Outage Days(1) Days 0 

 Cost Basis Year 2006

Construction Labor Rate $/hr 50.00 

Prime Contractor's Markup (% of equip. cost) % 10 

Reagent Bulk Storage Days 30 

Operating Cost Data

FGD Operating Labor Rate $/hr 33.0 

 Power Cost Mills/kWh 40.0

Replacement Power Cost Mills/kWh 40.0 

Steam Cost - high pressure $/1000 lbs 5.50 

Methane Cost $/1000 scf 8.00 

 Activated Coke Cost $/ton 600

Sulfuric Acid Byproduct Price $/ton 30 

Limestone Delivered Cost $/ton 15 

Pebble Lime Delivered Cost $/ton 60 

Ammonia Delivered Cost (as 29% aqueous solution) $/ton 180 

Hydrogen Peroxide (as 50% aqueous solution) $/ton 318 

ATS (as 60% aqueous solution) $/ton 180 

Ammonia Sulfate By Product Credit $/ton 190 

 Gypsum Revenue $/ton 2

 Waste Disposal (landfill) $/ton 35

 Water Cost: 

Fresh Water $/1000 gal 0.40 

Blowdown Water $/1000 gal 0.00 

Cooling Water $/1000 gal 0.16 

 (1) Power Outage Days – For this study it has been assumed that the tie-ins of wet or dry FGD equipment and 

NOx equipment can be completed during a future scheduled 5 to 6 weeks outage period (no power

generation lost during construction). 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

3.0 DESCRIPTIONS OF EVALUATED SO2 AND NOX CONTROL TECHNOLOGY 

3.1 In Furnace NOx Control Technologies 

Mobotec ROFA/ROTAMIX System 

Mobotec's Rotating Opposed Fire Air (ROFA) process utilizes booster fans to supply high velocity 

air to distribution boxes placed at specific locations around the furnace. These boxes are located 

asymmetrically n opposite sides of the boiler. A damper is provided at each ROFA box to control 

the amount of high velocity air going to the box. The flue gas volume in the furnace is set in rotation 

due to the asymmetrically placed boxes and air nozzles. The combustion gases mix well with the 

added high velocity combustion air, making a combustion gas swirl. This generates turbulence and 

rotation in the entire furnace. Rotation prevents laminated flow and the whole volume of the furnace 

can be used more effectively for the combustion process resulting in lower output NOx. The ROFA 

swirl helps reduce the maximum temperature of the flame combustion zone and increases heat 

absorption, which in turn improves the boiler overall efficiency. 

MOBOTEC ROFA/ROTAMIX PROCESS 

The Mobotec ROTAMIX system is an advance selective non-catalyst (SNCR) system and has been 

developed to work in conjunction with the ROFA system to provide additional NOx reduction. The 

same kind of asymmetrically placed air nozzle is used in the ROTAMIX technique as in the ROFA 

system. NOx reduction is achieved by injection of liquid ammonia or urea through lances that are 

inserted in the ROFA/ROTAMIX nozzles. The high velocity air in the ROFA system carries the 

reagent into the center of the furnace. Effective NOx reduction can be achieved with a minimum 

amount of ammonia slip. 

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 NOX AND SO2EMISSIONS REDUCTION STUDY

The ROTAMIX system was designed in Sweden as an addition to a standard SNCR process. The 

Mobotec system has been installed on a number of full-scale utility boilers located in the US, North 

Carolina where removal efficiencies as high as 70-80% have been achieved. Most Mobotec 

experience to date is on units firing eastern bituminous coal with high initial NOx levels. 

Mitsui Babcock NOxStar System 

The NOxStar process is a post-combustion process that continuously injects controlled quantities of 

an ammonia-based reagent with relatively minute amounts of hydrocarbon (typically natural gas or 

propane) into the superheater/reheater pass of an operating boiler. The injection grid comprises a 

permanent array of feed lances attached to the adjacent heat transfer assemblies in the upper furnace 

pass. The lance grid is divided into numerous discrete zones both in width and height in the 

convective gas pass. This arrangement optimizes reagent distribution throughout the relatively high 

temperature NOx -bearing flue gas mass. At these existing elevated temperatures, the hydrocarbon 

auto-ignites to form a plasma of free radicals, which auto catalyses the reaction of ammonia and NOx

to form harmless nitrogen (N2) and water vapor (H2O). 

The NOxStar process has demonstrated removal efficiencies of 60-68% NOx at inlet NOx levels of 

between 0.25 to 0.4 lb/MMBtu at TVA's Colbert 4 station. 

In conjunction with other in-furnace technologies such as low NOx burners or a single layer of 

catalyst installed in the existing ductwork, NOx reduction over 75% is considered achievable with

NOxStar plus system. 

NOxStarTM Process 

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OAK CREEK UNITS 5-8 

 NOX AND SO2EMISSIONS REDUCTION STUDY

Modification of Existing Foster Wheeler Low NOx Burners on Units 5 & 6 

Retrofitting the boiler units with Foster Wheeler low NOx burners could reduce NOx levels. The low 

NOx burners redistribute combustion air to the burners to achieve low NOx levels. Installation of 

these burners in the arch fired boilers, would involve furnace and furnace front modifications. 

The arch-fired boiler arrangement is fairly rare among today's utility boilers. Nevertheless, Foster 

Wheeler indicated they have successfully made NOx-reduction modifications arch-fired boilers. 

However, in further discussions with Foster Wheeler it was determined that their experience was not 

with PRB Coal. Foster Wheeler was not forthcoming concerning the applicability of this approach

to PRB. 

Ultimately it was concluded that these burners alone would not reduce the NOx level to the permit 

limits. 

3.2 Post Combustion NOx Control Technology – Selected Catalytic Reduction (SCR) 

Selective Catalytic Reduction (SCR) utilizes a nitrogen-based reducing agent, such as urea or 

ammonia to reduce flue gas NOx to molecular nitrogen (N2) and water vapor (H2O). The SCR 

process employs a meta-based catalyst with activated sites to increase the rate of the reduction 

reaction, resulting in a higher NOx removal efficiency within a lower and broader temperature 

window that that possible for non catalytic processes. The dominant reduction reactions involved in 

the SCR process are described by the following equations: 

4NO + 4NH3 + O2 Æ 4N2 + 6H2O 

2NO2 + 4NH3 + O2 Æ 3N2 + 6H2O 

These NOx reduction reactions occur as the flue gas passes through the catalyst chamber. Reagent is 

injected into the flue gas downstream of the economizer through an injection grid mounted in the 

ductwork. The reagent is typically diluted with compressed air or steam to aid in injection, and is 

injected at a sufficient distance upstream of the catalyst chamber to allow for adequate mixing of the 

reagent and flue gas. The hot flue gas and reagent then flow into the catalyst where NOx in the flue

gas chemically reduces into nitrogen and water. The nitrogen, water, and other flue gas constituents 

flow out of the SCR reactor. 

The SCR process has demonstrated removal efficiencies of 70-90% NOx. 

For this study, a 29% by weight aqueous ammonia is selected as the NOx control reagent. 

SCR can be located in three places. These are: 

• Hot Side SCR, with the reactor located between the economizer and air preheater. In this configuration the SCR is located upstream of the existing cold 

side ESP and is subject to a high fly ash loading. This is the most commonly 

used configuration in the industry. 

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Hot Side SCR 

• Cold Side SCR, with the reactor located between the existing induced draft fan 

and the booster fan for the FGD system. In this configuration the SCR is 

located downstream of the existing cold side ESP and is subjected to a low fly 

ash loading at normal operation. This configuration requires a gas-gas heat 

exchanger and duct burners or steam coil heaters to bring the flue gas 

temperature to reaction temperature. Steam reheat is likely the lower cost

option. 

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Cold Side SCR 

• Tail End SCR, with the reactor located downstream of a FGD system and 

upstream of a stack. In this configuration since the SCR is located downstream

of the existing cold side ESP and the FGD system, it is subjected to a very low 

fly ash and SO2 loading. It also requires a gas-gas heat exchanger and duct 

burners or steam coil heaters to bring the flue gas temperature to reaction 

temperature. The natural gas or steam usage is higher than the cold side SCR 

due to the lower FGD system exit gas temperature. The expected catalyst life is 

longer because some of the catalyst poison chemicals would be removed in the 

FGD system. 

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3.3 SO2 Control Technologies 

Limestone Forced Oxidation System (LSFO) 

LSFO Process Description 

In the LSFO process, hot flue gas exiting the ESP enters an absorber where it is contacted with a 

dilute calcium carbonate and calcium sulfate slurry (typically 15%-20% by weight suspended 

solids). The dissolved SO2 reacts with the calcium carbonate in the limestone particles and the 

slurry drains into the absorber reaction tank (integral with the absorber). Limestone with forced 

oxidation FGD is a modification of a traditional wet limestone FGD process and involves continuous 

sparging of air into the reaction tank (sparging air is provided by dedicated air compressors). This 

process alleviates problems such as gypsum scaling and dewatering difficulties that plagued early 

natural oxidation, wet limestone processes. LSFO offers the advantage of controlled oxidation of 

reaction products and potentially scale-free operation of the wet scrubber. LSFO produces a salable 

byproduct in the form of commercial-grade gypsum that can be used for wallboard manufacturing or 

other industrial applications. 

LSFO Process 

The chemistry for the LSFO process begins with limestone (CaCO3) reagent, being fed to the spray 

tower absorber, in an aqueous slurry at a molar feed rate of 1.02-1.03 moles of CaCO3/mole of SO2

removed, when producing wallboard quality gypsum. The major product of SO2 reaction with 

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limestone is the formation of hydrated calcium sulfite (CaSO3 • 1/2H2O(s)) according to the 

following reaction:

 CaCO3(s) + SO2(g) + 1/2H2O Æ CaSO3 • 1/2H2O(s) + CO2

The sulfite is oxidized by the injection of air into the bottom of the absorber reaction tank, and then 

hydrated to form calcium sulfate (CaSO4 • 2H2O) through the following reaction: 

 CaSO3 • 1/2H2O(s) + 1/2O2 + 3/2H2O Æ CaSO4 • 2H2O 

The absorber may be an open spray tower, a spray tower with a gas/liquid contact tray, a fountain 

type spray, or a jet bubbler reactor. The contact tray promotes additional removal efficiency but 

results in additional flue gas pressure drop. 

The LSFO process requires makeup water to replace the losses that occur through evaporation, in 

liquor entrained in the byproduct solids, and due to blowdown streams used to control dissolved 

solids and fines. This makeup water can be supplied from any source that is not saturated with 

respect to any of the dissolved solids and contains a relatively low concentration of suspended solids. 

However, the mist eliminator wash stream, which serves as a relatively large portion of the scrubber 

makeup water, must be potable water in order to maintain scale-free operation. 

The LSFO process is capable of removing more than 95% of the SO2 present in the inlet flue gas. Up 

to 98% SO2 removal efficiency is achievable. 

The LSFO process requires limestone as its reagent. The following table shows a typical limestone 

specification.

Limestone Properties 

CaCO3, wt % dry > 95 

CaCO3, wt % (available) dry 94 

MgCO3, wt % dry 0.5 – 3 

Total Inerts, wt% dry 3 –7 

Moisture, wt % 7 

Particle Size (inch) (no more than 50% < 6 mesh) ≤ 3⁄4" x 0" 

Bulk Density, lbm/ft3 100 

Reactivity Test Per EPRI Method or equal 

Work Index, kWh/ short ton 13 

LSFO Byproduct Handling 

The SO2 reaction with calcium carbonate initially forms calcium sulfite, which is subsequently 

oxidized to calcium sulfate (gypsum) in the absorber reaction tank. The formation of gypsum

crystals in the slurry helps to reduce scaling potential by providing suspended crystal surface for 

crystal growth and reducing the calcium sulfate saturation level in the slurry. A certain level of

sulfate super saturation is required for gypsum formation. 

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The gypsum slurry removed from the absorber reaction tank is partially dewatered using 

hydroclones. No additives are required to accomplish this separation since gypsum crystals from the 

LSFO process tend to be relatively large, dense crystals that do not retain water. The hydroclone 

overflow is returned to the scrubber reaction tank. The hydroclone underflow is directed to a 

dewatering facility, which uses either rotary drum or belt filters. The cake coming off the belt filter

is typically 90% gypsum solids and 10% water. If the gypsum is to be sold for industrial use, a 

washing sequence is included in the vacuum filter design, to reduce chloride content and eliminate 

contamination. Only water low in dissolved and suspended solids should be used for washing the 

gypsum filter cake. The cake wash water is usually heated to promote drying to less than 10% 

moisture. 

The gypsum from the vacuum filter is transferred by belt conveyor to a storage building, when it is 

to be sold for wallboard production. The gypsum is offloaded from the storage area by conveyor to 

barge, trucks, or railcars for shipment to the wallboard plant.

LSFO Purge Wastewater Treatment 

Blowdown of a portion of the process water returned from the gypsum dewatering/washing process 

is necessary to control the concentrations of dissolved solids in the scrubber liquor as it concentrates 

due to the continuous recycle of scrubber slurry and evaporation of water into the flue gas. The 

blowdown stream is used primarily to control chloride levels in the absorber reaction tank and 

recycle system. A typical equilibrium chloride level is 15,000 ppm. The blowdown stream may also 

be used to purge fines, which tend to blind filter cloths, leading to difficulties in dewatering. 

The quality of the wastewater purge stream from the FGD process depends upon the sources of 

makeup water, the coal composition, and the byproduct specifications. Contaminants that may 

require removal could include trace heavy metals and chlorides. Multi-stage treatment systems are 

typically used, consisting of precipitation, flocculation, and dewatering equipment to address Hg, Fe, 

Cd, and other contaminants. Sodium hydroxide or lime is added to increase the pH to approximately 

9 where many metals will tend to precipitate out of the solution. Sodium sulfide is then added to 

precipitate additional metals to levels of less than 0.1 ppb. Ferric chloride is then added to remove 

excess sulfides and to produce large flocs of solids that are easily dewatered. Chlorides can be 

removed by a variety of methods including evaporation or treatment with activated carbon, but is 

usually not treated. The solids generated by these treatment systems have to be disposed in an 

environmentally acceptable manner. The liquid stream can be used for coal pile wetting, ash 

sluicing, and/or combined with the plant cooling water discharge. 

LSFO Limestone Reagent 

Limestone from the bulk storage area is transferred to a local storage area by trucks. The reclaim

system includes a vibrating feeder and conveyor system to transfer limestone to day bins. Limestone 

day bins and feeders supply limestone to ball mills. The ball mills grind the limestone to 95 percent 

less than 325 mesh and use a wet recycle classification loop to ensure proper size distribution to the 

process. This particle size produces a large surface area for gas contact without excessive power 

consumption by the ball mill. The 30-35 percent solids slurry from the ball mill system is stored in 

limestone slurry tanks prior to transfer to the absorbers. 

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Lime Spray Drying System (LSD) 

LSD Process Description 

The lime spray drying process is a semi-dry FGD system that produces a dry mixture of fly ash and 

reaction products. In the Lime Spray Dryer process, the hot flue gas exiting the precipitators enters a 

spray dryer vessel. Within the vessel, an atomized slurry of lime and recycled solids contacts the 

flue gas stream. The sulfur oxides in the flue gas react with the lime and fly ash alkali to form

calcium salts. The water entering with the slurry vaporizes, lowering the temperature and raising the 

moisture content of the scrubbed gas. In some spray dryer designs, the scrubbed gas leaves from the 

side of the vessel, and a portion of the dried reaction products and fly ash drop out in the conical 

bottom.

The spray dryer outlet temperature is typically controlled within 1-2°F of the operating set point 

(normally 35°F above the gas saturation temperature). If the coal sulfur content varies over a wide 

range in a short period of time, there might be a tendency to operate outside of the normal outlet 

temperature range. A closer approach to the saturation temperature allows the LSD system to 

achieve higher removal efficiency for a short period, but at the same time risks the buildup of wet 

solids on internal surfaces with the resultant potential for corrosion. 

A particulate control device is required downstream of the spray dryer. A fabric filter downstream

of the LSD vessels removes the dry solid reaction products, unreacted reagent, and fly ash before the 

scrubbed gas is released to the atmosphere. The fabric filter bags collect a layer of solids on their 

surfaces between cleanings, and the movement of the flue gas through this layer enhances the gassolid contact. A portion of the collected reaction product and fly ash solids is recycled to the slurry 

feed system. The remaining solids are transported to a landfill for disposal. 

The following chemical reactions define how the sulfur dioxide is removed from the flue gas in the 

lime spray drying process: 

Raw lime is slaked with an excess of water to form a calcium hydroxide slurry: 

CaO + H2O Æ Ca(OH)2

The sulfur oxides in the flue gas are absorbed into the slurry and react to form the salt 

products: 

 Ca(OH)2 + SO2 Æ CaSO3 • 1/2H2O + 1/2H2O 

 Ca(OH)2 + SO3 + H2O Æ CaSO4 • 2H2O 

A fraction of the sulfite product may also be oxidized to the sulfate form by reaction with 

oxygen in the flue gas: 

 Ca(OH)2 + SO2 + 1/2O2 + H2O Æ CaSO4 • 2H2O 

Any HCl in the flue gas, present because of the chloride content of the fired coal, also 

absorbs into the slurry and reacts with the slaked lime by: 

 Ca(OH)2 + 2HCl Æ CaCl2 + 2H2O 

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LSD Process 

The majority of the water evaporates in the spray dryer, leaving dry particles composed of the 

reaction products, unreacted absorbent, and fly ash. In the particulate control device, the remaining 

SO2 continues to react with the residual lime in the collected solids, although at a much slower rate. 

As much as 25% of the total SO2 removal can occur in the baghouse. In addition, the LSD process is 

highly effective at controlling sulfur trioxide, which condenses with water vapor to form sulfuric 

acid. Over 90% of the sulfur trioxide that is formed during combustion is absorbed in the LSD vessel 

and FF. This eliminates the potential for acid-related problems such as plume opacity due to acid 

mist or sulfuric acid corrosion in the downstream ductwork and particulate collection system. 

However, if the outlet gas temperature drops too low, then water condensation can occur on 

downstream surfaces. The water droplets can absorb additional SO2 producing sulfurous acid, 

increasing the potential for corrosion, and can form a mud that can plug the filter bags. 

LSD Removal Capabilities and Other Performance Parameters 

The Lime Based Semi-Dry system (LSD) can meet the specified 0.07 lb/MMBtu SOx emission and 

95% removal efficiency for the design coal. In order to achieve 95% SO2 removal, plant operators 

must closely watch the LSD system operation and adjust the process control parameters frequently.

Any variation of boiler operations can cause the SO2 emission to exceed the limits. Based on 

industrial experience, a 92-93% SO2 removal can be consistently achieved. The LSD system for 

each boiler will be comprised of one spray dryer, followed with one fabric filter module. 

LSD Reagent 

The LSD process requires pebble lime as its reagent. The following table shows a typical lime 

specification.

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Pebble Lime Property 

CaO, wt % (Total) > 95 

CaO, wt % (available for reaction) 90 or greater 

MgO, wt % 2% max 

Inerts, wt % 5 

Moisture Negligible

Particle Size (inch) 1⁄4" to 3/8" 

Bulk Density, lbm/ft3 55 – 60 

Reactivity Slaking rate test – Achieve 40°C temp 

rise in 3 min. or less 

Fresh slaking water is introduced which hydrates the pebble lime. A ball mill slaker pulverizes the 

inert material and maintains the inerts with the reagent slurry. If a detention or paste slaker is used, 

the grits are removed at the slaker for separate disposal. The slaked lime, Ca(OH)2, flows to an 

agitated lime slurry feed tank, and this slurry is then pumped to the lime spray dryer rotary atomizer 

LSD Waste/Byproduct Handling 

The spray dryer system produces a dry solid product consisting of calcium sulfite/sulfate, unused 

hydrated lime, and fly ash. These dry solid products can be handled by conventional dry fly ash 

handling systems. A portion of the collected reaction product and fly ash solids is recycled to the 

slurry feed system and the remaining solids are sent via the dry solids conveying systems to a 

storage silo. From the silo they are trucked to a landfill for disposal. 

Circulating Fluidized Bed (CFB) Absorption System 

CFB Process Description 

The Circulating Fluid Bed Scrubber (CFB) process is a dry scrubbing technology. The process is 

totally dry, meaning it not only produces a dry, free flowing disposal product but also introduces the 

lime reagent as a dry, free flowing powder. 

In a Circulating Fluid Bed (CFB) process, the flue gas enters the bottom of the fluidized bed 

reactor(s). As the flue gas enters the venturi-shaped entrance to each reactor, it is mixed with 

hydrated lime reagent and recycled fly ash and reaction product solids. Water is injected into the 

reactor to humidify the flue gas and assist in SO2 removal. 

The CFB reactor has a tall cylindrical configuration to allow adequate time for the mixing of the SO2

laden gas with the reagent to complete the reaction. Calcium salts are formed when the hydrated 

lime and fly ash react with the sulfur oxides in the flue gas. 

The spent solids and fly ash are carried out of the top of the reactor and captured downstream by a 

fabric filter or an ESP, one for each CFB Reactor. A portion of these combined solids is recycled to 

the fluid bed absorber via air slides. The remaining material is transported to a disposal solids silo. 

The fly ash and reaction products are drawn from the silo and conditioned in a pug mill(s) for 

disposal to landfill. 

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CFB Process

The Circulating Fluid Bed process chemical reactions are similar to that of the Spray Dryer 

Absorber, as shown below: 

Lime Hydration: CaO + H2O ⇒ Ca(OH)2

SO2 Reaction: Ca(OH)2 + SO2 ⇒ CaSO3 .1/2H2O + 1⁄2 H2O 

SO3 Reaction: Ca(OH)2 + SO3 + H2O ⇒ CaSO4 . 2H2O 

Sulfite Oxidation: Ca(OH)2 + SO2 + H2O 1/2O2 ⇒ CaSO4 . 2H2O 

HCl Reaction: Ca(OH)2 + HCl ⇒ CaCl2 + 2H2O 

Pebble lime is transported pneumatically from the lime storage silos to the lime day bin which feeds 

the dry lime hydration plant. From the day bin, pebble lime is charged into a lime hydrating fluid bed 

reactor. The pebble lime is hydrated by the injection of fresh water in the hydrating reactor in an 

amount proportional to the feed rate of the pebble lime. Hydrating water consumption is 

approximately 150% of the stoichiometric requirement. The highly reactive hydrated lime product is 

pneumatically transported by one of two 100% capacity hydrate transfer blowers to four hydrated 

lime surge bins, one for each CFB tower. A total of four CFB towers are provided, one for each unit. 

The hydrated lime reagent is drawn from each hydrated lime surge bin by a variable speed rotary 

feeder which transfers the hydrated lime to an airslide which conveys and feeds the hydrated lime 

into the associated scrubber tower. 

The hydrated lime feed rate through the variable speed rotary feeder and airslide into the CFB is 

adjusted based on a feed forward signal from the SO2 inlet and outlet monitors. Injection of water 

directly into the CFB reactor further enhances SO2 removal efficiency making 96% to 98% removal 

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efficiency feasible with this technology. However, since high removal efficiencies of 96% to 98% 

have not been commercially demonstrated in FGD systems serving large power plants, the 

evaluation of CFB technology in this study is based on 95% SO2 removal. Furthermore, the 

stoichiometric ratio, and the associated lime consumption rate for SO2 removal levels greater than 

95% have not yet been accurately determined or demonstrated. 

The evaporation of water within the CFB reactor results in decreased flue gas temperature and 

increased humidity. Desulfurized flue gas exits the CFB reactors and is drawn through either an 

electrostatic precipitator (ESP) or fabric filter, one per CFB reactor. Fabric filters are assumed for 

Oak Creek. Hydrated lime and SO2 reaction products are separated from the flue gas and collected 

with the fly ash in the new fabric filter hoppers. The fly ash and reaction solids are discharged from 

the hoppers and split into two streams. The first stream is recycled via an airslide and fed back into 

the lower section of the associated CFB reactor. The second stream is discharged through an airlock 

hopper and transported by a pneumatic pressure conveying system to a fly ash / reaction products 

storage silo. The fly ash and reaction products are gravity discharged from the silo into a pug mill. 

The pug mill conditions and discharges the ash and reaction products into ash dump trucks for 

transportation to the landfill. 

The flue gas exiting the fabric filter is ducted to new booster fans, and then to the chimney. 

CFB System Materials and other Mechanical Considerations 

The CFB vessel and ductwork are typically constructed of carbon steel because sulfuric acid is 

absorbed and neutralized by the alkaline solids present. 

The CFB system includes the dry hydration plant upstream of the reactor vessels. 

Evaluation of the CFB system includes a new fabric filter immediately downstream of the reactor 

vessel to capture the reaction products, unreacted absorbent, and fly ash. 

Evaluation of the CFB system includes the costs associated with installation and operation of new 

booster fans located immediately downstream of the FF. The additional pressure provided by the 

new fans compensates for pressure losses due to the CFB's, FF and ductwork. 

3.4 Multi-Pollutant (NOx, SO2 and Mercury) Control Technology 

J-Power ReACT System 

Process Description 

The ReACTTM technology is a dry multi-pollutant control technology. It utilizes a moving activated 

coke (AC) bed with ammonia injection to simultaneously remove SO2, NOx, and mercury from the 

flue gas. The ReACT system (process flow diagram shown in Figure 3-1) consists of three major 

process steps: 

• SO2 and Hg are removed by adsorption onto activated coke pellets in the 

adsorber modules, while NOx is removed by reduction reactions 

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• SO2 desorption and activated coke regeneration occurs in the regenerator 

modules 

• Sulfuric acid by-product production is in an acid plant. 

ReACT Technology Process 

NH3

Adsorption 

Each adsorber module consists of a bed of activated coke moving slowly downward through each 

open cell at a constant rate. When the flue gas passes through the activated coke bed (horizontal gas 

flow), SO2 is adsorbed onto the activated coke where it reacts with oxygen and water in the flue gas 

to form sulfuric acid. The sulfuric acid then reacts with the injected ammonia to form ammonium 

sulfate and bisulfate salts according to the following chemical reactions: 

Sulfuric Acid 2 2 2 2 4

1

2 SO + O + H O → H SO 

Ammonia Salts H 2 SO4 + NH3 → NH 4HSO4

 ( ) NH 4HSO4 + NH3 → NH 4 2 SO4

Activated coke also works as a NOX reduction catalyst. NOX in the flue gas is reduced to nitrogen 

and water when it reacts with ammonia and other species on the surface of activated coke. 

 NO + NH3 + 1

4 O2 → N2 + 32 H 2O

 NO + NHxO-AC → N2 + H2O + OH-AC (where AC = Activated Coke) 

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AC fines are generated as the coke moves through the adsorber cells and can be entrained in the flue 

gas. However, the adsorber does remove some of these fines as well as a portion of the fly ash that 

enters with the incoming flue gas. The adsorber can achieve an expected net particulate removal of 

70%. 

As the activated coke travels down the adsorber, it continuously adsorbs mercury, SO2 and NOx

from the flue gas and gradually loses its adsorption capability. The ReACT system is designed so 

that when the activated coke is discharged from the adsorber, the spent activated coke is saturated 

with ammonia salts and sulfuric acid. The AC elevator then transfers the spent coke from the 

adsorber modules to a lock hopper before the coke is delivered to the regenerator modules. J-Power 

has confirmed that the activated coke removes 90+% of the mercury contained in the inlet flue gas. 

Regenerator

To regain the activated coke adsorption capability, the spent activated coke needs to be reactivated in 

a regenerator vessel by indirect hot gas heating. The coke goes through three stages of processing – 

preheating, regeneration and cooling – in the regenerator modules to complete the regeneration 

cycle. 

At the preheating stage, the spent activated coke is heated indirectly to a preset temperature using the 

hot air exiting from the coke cooling process. The heated activated coke then travels downward to 

the regeneration stage. 

At the regeneration stage, the preheated activated coke temperature is raised further to 750-930°F. 

Ammonium sulfate and sulfuric acid trapped on the activated coke surface are thermally 

decomposed to ammonia vapor, sulfur dioxide and water vapor. Mercury is not released during the 

regeneration of the activated coke. The coke has a high capacity for Hg adsorption, and will require 

regeneration to remove the collected mercury every 2-3 years depending upon the concentration of 

mercury in the fuel. 

The gas stream generated in the regenerator modules is then directed to a by-product recovery 

facility for further processing. A natural gas or oil-fired furnace equipped with a combustion air fan 

is used to generate the hot gas that is needed for the AC regeneration. 

The regenerated activated coke moves into the cooling section at the bottom of the regenerator 

module where it is cooled indirectly by air. Once cooled to a preset temperature, the AC is 

transferred to a discharge lock hopper. 

From the lock hopper the cooled activated coke is sent to a separator where classification air is used 

to separate the degraded fine material from the coke meeting the desired size parameters. The fine 

material entrained in the classification air is sent directly to a dust collector where the fines and air 

are separated. The fine activated coke can then be burned in the boiler or sent to a landfill for 

disposal. For this analysis, it was assumed that the fines would be landfilled. 

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Fresh activated coke is added to replace the fines that are lost during the regeneration process. The 

added fresh coke along with the regenerated coke is then recycled back to the adsorber modules via 

an AC supply elevator. 

By-Product Recovery Facility to Produce Sulfuric Acid 

The SO2-rich gases from the regenerator must first go through a cleaning process to remove the 

entrained dust and other impurities that might degrade the quality of the sulfuric acid product. Once 

cleaned, the SO2-rich gas stream is sent to an SO2 to SO3 converter. 

Equipment used for washing the concentrated stream of SO2 would normally consist of a wet 

scrubber, a cooler, a wet mist precipitator, a drying tower and a blower. The wet scrubber is used to 

cool and remove the entrained dust and impurities. The gas cooler is used to reduce the water vapor 

in the SO2-rich gas. The mist precipitator is used to remove fine acid mist generated in the wet 

scrubber and cooler. A drying tower is used to remove additional water vapor from the by-product 

gas stream. 

After the washing and cleaning process, the cooled and cleaned SO2-rich gas is reheated before it is 

sent to a converter to complete the catalytic conversion of SO2 to SO3. After the conversion, the SO3

is absorbed in a final absorbing tower to form a 98% sulfuric acid solution. Before the SO3- free gas 

can be discharged to the atmosphere or sent back to the ReACT system, it passes through a mist 

eliminator located at the exit of the final absorbing tower to remove any fine acid mist entrained in 

the gas stream. 

J-Power does not supply the by-product recovery facility. Suppliers such as Monsanto Enviro-Chem 

can provide sulfuric acid plants. For this study the by-product recovery cost is factored from a 

previous Monsanto quote. 

A Process Flow Diagram for a typical Monsanto Enviro-Chem H2SO4 process is provided below: 

Sulfuric Acid Plant Process 

G a s

H e a ti n g 

S O 2 + 1⁄2 O 2 S O 3

A ll o y T r o u g h D is t r ib u t o r s

G a s C ooli n g

 C a t a ly tic

C o n v ert er w it h

 E n v ir o - C h e m

 C a ta ly st

 Ga s He a t 

 E x c h a n g e r

 In t e r p a ss A b s o r b in g

T o w e r w it h Br i n k M ist

 E lim in a t o r s

F in a l A b s o r b in g

T o w e r wit h B r i n k

M is t E lim i n a t o r s 

S t a c k

B r in k M ist

E lim in a t o r SO 3 + H 2O H 2S O 4

 P r im a r y D y n a w ave 

R e v ers e J e t S cru b b e r

G a s C ooli n g

 T o w e r

 W e t 

E lect rosta ti c

 P recip ita t o r

D r y in g T o w er 

w it h D e m ist e r

F in a l D y n a w a v e C o m p ress o r

 R e v e r s e J e t 

 S c r u b b e r

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PowerSpan ECO System 

Process Description 

The ECOTM process is designed for installation downstream of an existing particulate collection 

device. The process utilizes a dielectric barrier discharge reactor to oxidize pollutants in the flue gas 

stream, followed by a wet ammonia scrubber and wet ESP for removal of oxidized pollutants and 

byproducts. The technology produces a saleable ammonium sulfate/ammonium nitrate fertilizer 

byproduct. 

PowerSpan ECOTM Process 

Flue gas flows from the existing ESP or fabric filter into an electrocatalytic oxidation (ECO) reactor, 

where hydroxyl (OH) radicals and atomic oxygen (O) are formed by the reaction of high-energy 

electrons with water and oxygen molecules. 

O2 + e- Æ O + O + eH2O + e- Æ OH + H + eO + H2O Æ 2OH 

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These radicals then react with pollutants in the flue gas, oxidizing mercury (Hg) to mercuric oxide 

(HgO), SO2 to sulfuric acid (H2SO4), and NOx to nitric acid (HNO3). Approximately 90% of NO in 

the flue gas is oxidized to NO2 and HNO3 at this stage. Less than 10% of SO2 in the gas is oxidized 

to form SO3, which ultimately forms sulfuric acid. 

OH + SO2 Æ HSO3

HSO3 + O2 Æ HO2 + SO3

SO3 + H2O Æ H2SO4

NO + HO2 Æ NO2 + OH 

O + NO Æ NO2

OH + NO2 Æ HNO3

O + Hg Æ HgO 

The oxidized flue gas is then sent to a double loop ammonia scrubber where the final products are 

removed from the flue gas stream. In the upper loop of the scrubber, ammonia is added to form

ammonium sulfate and nitrate byproducts by reaction with sulfuric and nitric acid. The lower loop 

of the scrubber cools and saturates the flue gas and concentrates the byproducts for removal. 

Oxidation air is added to the lower loop to further oxidize sulfites and nitrites. Chemical reactions 

that occur in the scrubber are: 

H2SO4 + 2NH3 Æ (NH4)2SO4

HNO3 + NH3 Æ NH4NO3

SO2 + H2O Æ H2SO3

H2SO3 + 2NH3 Æ (NH4)2SO3

H2SO3 + (NH4)2SO3 Æ 2NH4HSO3

(NH4)2SO3 + 1/2O2 Æ (NH4)2SO4

NH4HSO3 + 1/2O2 Æ NH4HSO4

NH4HSO4 + NH3Æ (NH4)2SO4

NH3 + HCl Æ NH4Cl 

The flue gas then enters a mist eliminator that removes entrained droplets from the gas prior to 

entering a wet ESP (WESP) located in the top portion of the scrubber. The WESP collects acid 

aerosols, particulate matter, and mercuric oxide, while collecting and recycling excess ammonia as 

an aqueous solution. 

The soluble ammonium sulfate and nitrate byproducts exit the scrubber in a bleed stream that is 

treated by filtration to remove ash and insoluble metal compounds. The stream is then passed 

through an activated carbon absorption bed where mercury compounds are absorbed onto the bed. 

The purified byproduct stream is then sent to a crystallizer where well-defined sulfate and nitrate 

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crystals are formed by evaporation. The crystals are then dried and granulated to form a fertilizer 

byproduct that could be marketable depending on quality and location. At sites where the fertilizer 

byproduct could be sold, but where synthetic gypsum from a lime or limestone process could not be 

sold due to the absence of a market within the economic haul distance, the ECOTM process would 

avoid the landfill disposal costs that typically account for a large portion of FGD system operating 

costs. 

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4.0 NOX CONTROL TECHNOLOGY EVALUATION 

A set of mandatory criteria was identified and used to evaluate each NOx control technology. Each 

NOx control technology is evaluated and ranked for each criterion. The technology that has the 

highest overall raking is considered the most suitable control technology. 

4.1 Evaluation Criteria 

Each NOx control technology is evaluated in five areas – technology, constructability, operating and 

maintenance, commercial risk, and performance margin. Basing on the rating criteria, a rating is 

assigned to each area. 

• Technology 

Rating: 0 to 5 (5 is proven, 1 is to be demonstrated, 0 is not appropriate for the 

Oak Creek installation) 

Rating Criteria 

– Commercially proven on a power generating facility of 250 MW or more 

for a period at least one year and currently available 

– Capable of achieving the required NOx removal efficiency 

– Compatible with existing boiler configuration and equipment 

• Constructability 

Rating: 0 to 5 (5 is easy, 1 is difficult, 0 is extremely difficult) 

Rating Criteria 

– Compatible with available space and plant location. 

– Compatible with existing boiler configuration and equipment 

• Operating and Maintenance 

Rating: 1 to 5 (5 is easy, 1 is difficult) 

Rating Criteria 

– Ease of operation 

– Ease of Equipment Maintenance 

• Commercial Risk 

Rating: 0 to 5 (5 is low, 1 is high, 0 is extremely high) 

Rating Criteria 

– Commercially proven 

– Comparable experience with the project design fuel 

– Comparable experience with project boiler capacity 

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– Availability of guarantees 

• Performance Margin 

Rating: 1 to 5 (5 is good, 1 is poor) 

Rating Criteria 

– Margin to achieve higher then required NOX removal efficiency 

– Addition of performance-enhanced chemicals is required. 

– Demonstrated. 

Note: Total Ranking is rated zero when any one of the criteria is rated zero. 

4.2 Technology Evaluation Results of Selective Catalytic Reactor (SCR) System 

Units 5 & 6 

Cold side and tail end SCR can be installed at the South side of the plant for Units 5 and 6. 

After a careful review of the site, it is concluded that at east side of the plant, there is insufficient 

space between the Units 5 & 6 boilers, existing ESPs and Lake Michigan for installation of hot side 

SCRs for Units 5 & 6. Further, it is extremely difficult (without major plant modifications at high 

cost) to run the ductwork from the air preheater to the hot side SCR and back to the air preheater. 

For more detailed information, see Section 4.3. Therefore, only cold side and tail end SCRs are 

considered as valid options for these units. 

Table 4-2A below summarizes the technology evaluation results of the cold side and tail end SCR 

for Units 5 & 6. 

Table 4-2A. Technology Evaluation of SCR for Units 5&6 

Cold Side Tail End 

Ranking (0-5) 

Technology 3 4

Constructability 5 5

Operating and Maintenance 3 3 

Commercial Risk 4 5 

Performance Margin 5 5 

 Total 20 22

Other Factors 

Scaling Required No No 

Can meet 0.07 lbs/MMBtu NOx Emission? Yes Yes 

Unconditional Commercial Guarantees Yes Yes 

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Units 7 & 8 

Cold side and tail end SCR can be installed at the South side of plant for Units 7 and 8. 

There is adequate space behind existing Boiler 7 to install a hot side Unit 7 SCR. Routing the 

ductwork from Unit 7 economizer outlet to the SCR and back to the air preheater can be done with 

minimal plant modifications. It is expected that relocation of some of the existing ductwork would 

be needed. 

The Unit 8 hot side SCR can be located directly above the existing workshop on the south side of the 

plant. Routing of the duct from Unit 8 economizer outlet to the SCR and back to the air preheater 

would require relocating existing platforms, Unit 7 ESP control room and electrical cables and 

conduit, FD fan inlet ductwork, piping, wall penetration and siding repairs, etc. It is estimated that an 

additional 60 days down time over the normal outage duration would be needed for the tie in. 

Outage replacement power costs have been included in the total evaluated cost, but the additional 

outage duration does not appear to negatively impact the overall schedule. 

Table 4-2B below summarizes the technology evaluation results of the hot side, cold side and tail 

end SCRs for Units 7 & 8. 

Table 4-2B. Technology Evaluation of SCR For Units 7&8 

Hot Side Cold Side Tail End 

Ranking (0-5) 

Technology 5 3 4

Constructability 1 5 5

Operating and Maintenance 2 3 3 

Commercial Risk 3 4 5 

Performance Margin 5 5 5 

 Total 16 20 22

Other Factors 

Scaling Required No No No 

Can meet 0.07 lbs/MMBtu NOx Emission? Yes Yes Yes 

Unconditional Commercial Guarantees Yes Yes Yes 

4.3 Elimination of Hot Side SCRs use on Units 5 & 6 

Hot side SCRs for Units 5 and 6 would be normally located behind the units, between the boiler 

buildings and Lake Michigan. Ductwork would need to be run from the outlet of the existing boiler 

economizers inside the station building to the SCR inlet, and then from the SCR outlet back into the 

station building to the existing air heaters. 

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No two SCR installations are alike, because of different station configurations. Retrofit SCR 

installations typically are reasonably difficult, because the plants were not originally designed with 

sufficient extra space to accommodate the new equipment. Measures required for an industrytypical SCR retrofit include locating the SCR on new steel, reinforcing some existing building 

support steel to accept additional weight and loading, and relocating some existing equipment to 

permit routing of ductwork. 

For Oak Creek Units 5 and 6 however, installing SCRs and their associated ductwork would be 

substantially more difficult than an "industry typical" installation. The primary reason is that the 

units have already been retrofitted with additional emission control equipment, specifically the larger 

precipitators. When the larger precipitators were added new ductwork was required, and the space 

that would otherwise have been available for the SCR ductwork was consumed. This is further 

complicated by the coal conveying system that is also located inside the plant in this area. In 

addition, the existing economizer design does not permit sufficient space between the economizers 

and air heaters to connect the SCR ductwork. Consequently a workable physical arrangement for 

SCRs and their associated ductwork on these units could not be identified. 

To install SCRs would require extraordinary measures that would include, as a minimum:

• Demolishing the coal conveyors and associated equipment inside the plant and 

installing new conveyors in a location not yet determined. This would involve 

substantial modifications to the boiler building itself and its structural support 

steel. 

• The precipitators and their ductwork would have to be reconfigured and 

possibly moved to provide space for the SCR ductwork. 

• The existing economizers would have to be replaced with economizers of a 

different physical design, which would likely have an impact on the boilers'

thermal performance. 

These are not the type of modifications that are encountered in an "industry-typical" SCR 

installation. Due to the unusual extent of required modifications, their expense, and the substantial 

outage times they would require for installation, hot-side SCRs are not considered practical for Oak 

Creek Units 5 and 6. The estimated outage time exceeds 24 months, which would entail a 

replacement power cost in excess of $200 million. 

4.4 Cold-Side and Tail End SCR Industry Experience 

Most experience with cold-side and tail-end SCR is in Europe. Babcock Power, Alstom Power and 

Babcock & Wilcox were contacted and requested to submit their cold-side and tail-end SCR 

reference list. Babcock Power and Alstom responded to the request, B&W did not. 

Based on the received information, the bulk of the European installations are the cold-side or tail-end 

configuration. Babcock Power's reference list indicates that they have supplied tail-end SCR for 

twenty (20) power plants with a total of 4,550 MW Worldwide, primarily in Europe. Many of those 

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designs were driven by specific site space constraints. Out of the twenty installations, seven plants

have the tail end SCR located downstream of either a wet or dry FGD system. 

Alstom Power has supplied twenty (20) tail end SCRs in Europe. These plants are designed to burn 

waste or sludge. 

In the USA there is only one known cold-side SCR installation at PSE&G Mercer Station. The coldside SCR at Mercer station is located downstream of an existing ESP and ID fan. A future FGD 

system is planned, which will be downstream of the SCR. 

Based on the feedback from Babcock Power, Alstom Power and PSE&G Mercer station, the coldside and tail-end SCRs have all met the performance requirements as originally designed. 

Babcock Power and Alstom Power cold side and tail-end SCR reference lists are included as 

Appendix 8 in this report. 

4.5 Technology Evaluation Results of Mobotec ROFA/ROTAMIX System 

The Mobotec ROFA/ROTAMIX process will not work for Units 5 & 6. Mobotec's process creates a 

rotational opposed fired air (ROFA) condition in the upper furnace. 

Units 5 & 6 are arch-fired. The design of the units requires the use of high excess air to control 

steam temperature. Study indicates that attemperation cannot be accomplished by a means other 

than high excess air, so burner air cannot be diverted to the upper furnace. Therefore, the Mobotec 

ROFA/ROTAMIX is not a feasible technology and is given a performance margin ranking of zero. 

Units 7 & 8 are corner-fired boilers. There is no restriction in the furnace to prevent the introduction

of rotational opposed fired air. Mobotec ROFA/ROTAMIX may be used on Units 7 & 8. 

Mobotec's ROFA/ROTAMIX system has demonstrated that it can remove 50 to 70% NOx for a Tfired or wall fired boiler which normally has a baseline or uncontrolled NOx level of 0.35 lb/MMBtu 

or higher. Mobotec has not demonstrated that the ROFA/ROTAMIX system can achieve the same 

NOx removal for boilers like Oak Creek Units 7 & 8 that have a baseline NOx level in the 0.12 to 

0.15 lbs/MMBtu. Therefore, it is given a performance margin ranking of 1. 

Summary: 

The performance margin issues put the Mobotec system in a high technology risk category. 

Table 4-5 below summarizes the overall evaluation results of the Mobotec ROFA/ROTAMIX 

system. 

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Table 4-5. Technology Evaluation of Mobotec ROFA/ROTAMIX System 

Units 5 & 6 Units 7 & 8 

Ranking (0-5) 

Technology 3 3

Constructability 3 3

Operating and Maintenance 4 4 

Commercial Risk 0 2 

Performance Margin 0 1 

 Total 0 13

Other Factors 

Scaling Required Yes Yes 

Can meet 0.07 lbs/MMBtu NOx Emission? No Unproven 

Unconditional Commercial Guarantees No Possibly 

4.6 Technology Evaluation Results of Mitsui Babcock NOxStar System 

Mitsui Babcock offers the NOxStar process with and without in-duct SCR. 

Only limited information was received from Mitsui-Babcock. However, investigation indicated that 

Mitsui-Babcock has not demonstrated performance at low inlet NOx levels like those at Oak Creek, 

so expected results are difficult to predict. In addition, congestion in the roof and penthouse areas 

will hinder the use of Mitsui's standard concentric lance design. 

Mitsui Babcock stated that with some design changes and/or enhancements to the NOxStar system, 

or combining it with other NOx reduction technology, We Energies could possibly meet its overall 

objectives. Mitsui Babcock proposed a phased approach to demonstrate NOxStar technically at Oak 

Creek 5 & 6, and was not willing to offer performance guarantees. 

Mitsui-Babcock provided a ROM estimate for the NOxStar System with an in-duct SCR. However, 

this configuration is not considered feasible due to lack of ductwork space at Oak Creek for 

installation of an in-duct SCR. 

4.7 Summary of NOx Control Technology Screening Results 

SCR Technology – The SCR process exhibits a higher evaluated ranking and has greater operational 

flexibility in terms of fuel flexibility. Due to layout issues hot side SCR cannot be retrofitted for 

Units 5 & 6, but can be considered for Units 7 & 8. The site layout permits cold side or tail end SCR 

installation on the south side of plant. 

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NOxStar Technology – Was eliminated from further evaluation due to the technical risk associated 

with its use.

Mobotec ROFA/ROTAMIX Technology – Furnace type and geometry precludes the application of 

Mobotec ROFA/ROTAMIX technology for Units 5 & 6. This technology was considered for Units 7 

& 8, but was ultimately discarded due to unproven performance under conditions similar to Oak 

Creek. 

4.8 Cost Comparison of NOx Control Technology Options 

The costs of the technically feasible NOx control options are compared in the tables below: 

Table 4.8A 

Cost Summary for Tail-End SCRs 

(Cost in Millions) 

Unit 7 & 8 

Unit 5 & 6 

Incremental Total

Capital ($2006) $95.6 $83.0 $178.6 

First Year O&M Steam $1.9 $1.9 

Other $3.1 $2.9

Total $5.0 $4.8 $9.8

Levelized O&M Steam $2.6 $2.3 

Other $4.4 $3.6

Total $7.0 $5.9 $12.9

Capitalized O&M Steam $25.2 $22.1 

Other $42.7 $35.1

Total $67.9 $57.2 $125.1

Total Evaluated Cost $163.5 $140.2 $303.7

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Table 4.8B 

Cost Summary for Cold-Side SCRs 

(Cost in Millions) 

Unit 7 & 8 

Unit 5 & 6 

Incremental Total

Capital ($2006) $101.5 $89.0 $190.5 

First Year O&M Steam $1.7 $1.7 

Other $6.1 $5.5

Total $7.8 $7.2 $15.0

Levelized O&M Steam $2.4 $2.1 

Other $8.5 $6.8

Total $10.9 $8.9 $19.8

Capitalized O&M Steam $23.1 $20.2 

Other $82.6 $65.9

Total $105.7 $86.1 $191.8

Total Evaluated Cost $207.2 $175.1 $382.3

Table 4.8C 

Cost Summary for Cold-Side SCRs (Units 5 & 6) and Hot Side SCRs (Units 7 & 8) 

(Cost in Millions) 

Unit 7 & 8 

Unit 5 & 6 

Incremental Total 

Capital ($2006) $104.4 $89.0 $193.4 

First Year O&M Steam $0.1 $1.7 

Other $6.1 $5.5

Total $6.2 $7.2 $13.4

Levelized O&M Steam $0.2 $2.1 

Other $8.6 $6.8

Total $8.8 $8.9 $17.7

Capitalized O&M Steam $1.9 $20.2 

Other $83.1 $65.9

Total $85.0 $86.1 $171.1

Total Evaluated Cost * $189.4 $175.1 $364.5 

Note (*) Including $18M power penalty 

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Table 4.8D 

Cost Summary for Tail-End SCRs (Units 5 & 6) and Hot Side SCRs (Units 7 & 8) 

(Cost in Millions) 

Unit 7 & 8 

Unit 5 & 6 

Incremental Total

Capital ($2006) $104.4 $83.1 $187.5 

First Year O&M Steam $0.1 $1.9 

Other $6.2 $2.9

Total $6.3 $4.8 $11.1

Levelized O&M Steam $0.2 $2.3 

Other $8.7 $3.6

Total $8.9 $5.9 $14.8

Capitalized O&M Steam $1.9 $22.3 

Other $84.4 $34.8

Total $86.3 $57.1 $143.4

Total Evaluated Cost (*) $190.7 $140.2 $330.9 

Note (*) Including $18M power penalty 

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5.0 SO2 CONTROL TECHNOLOGY EVALUATION 

A set of mandatory criteria was identified and used to evaluate each SO2 control technology. A 

control technology that has the highest overall raking is considered the most suitable. 

5.1 Evaluation Criteria 

Each SO2 control technology is evaluated in five areas – technology, constructability, operating and 

maintenance, commercial risk, and performance margin. 

• Technology 

Rating: 0 to 5 (5 is proven, 1 is to be demonstrated, 0 is not suitable for the 

Oak Creek application)

Rating Criteria 

– Commercially proven on a power generating facility of 250 MW or more 

for a period at least one-year and currently available 

– Capable of achieving the required SO2 removal efficiency 

– Produces an acceptable waste product for disposal, if applicable. 

– Compatible with available space, reagent suitability/availability and plant 

location 

– A stable long-term market exists for the by-product 

• Constructability 

Rating: 0 to 5 (5 is easy, 1 is difficult, 0 is extremely difficult) 

Rating Criteria 

– Compatible with available space and plant location. 

– Compatible with existing boiler configuration and equipment 

• Operating and Maintenance 

Rating: 1 to 5 (5 is easy, 1 is difficult) 

Rating Criteria 

– Ease of operation 

– Ease of Equipment Maintenance 

• Commercial Risk 

Rating: 0 to 5 (5 is low, 1 is high, 0 is extremely high) 

Rating Criteria 

– Commercially proven 

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– Comparable experience with the project design fuel 

– Comparable experience with project boiler capacity 

– Availability of guarantees 

• Performance Margin 

Rating: 1 to 5 (5 is good, 1 is poor) 

Rating Criteria 

– Margin to achieve higher then required NOX removal efficiency 

– Addition of performance-enhanced chemicals is required. 

– Demonstrated. 

Note: Total Ranking is rated zero when any one of the criteria is rated. 

5.2 Technology Evaluation Results of Wet Limestone Forced Oxidation (LSFO) Process 

Major equipment included in each LSFO system is: 

• One (1) Absorber common for two (2) units, with its associated pumps, piping, 

instruments and controls 

• One (1) Limestone storage and slurry preparation system

• One (1) Gypsum dewatering system

• One (1) Wastewater treatment system 

• One (1) Flue for two (2) units in a common stack 

Table 5-2 below summarizes the technology evaluation results of Wet Limestone Forced Oxidation 

system located upstream of the tail-end SCR. 

Table 5-2. Evaluation of LSFO System Based on Cold-Side SCR Selection 

(Cost in Millions) 

Units 7 & 8 

Units 5 & 6 

Incremental Total 

Cost ($2006) 

Capital Cost $148 $162.8 $310.8

First Year O&M $10.5 $8.1 $18.6 

Levelized O&M $14.8 $13.5 $28.3

Capitalized O&M $148.1 $126.4 $274.5

Total Evaluated Cost $291.3 $294 $585.3 

Ranking (0-5) 

Technology 5 5 5

Constructability 5 5 5

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Units 7 & 8 

Units 5 & 6 

Incremental Total

Operating and Maintenance 3 3 3 

Commercial Risk 5 5 5

Performance Margin 5 5 5

Total 23 23 23

Other Factors 

Scaling Required No No 

Unconditional Commercial Guarantees Yes Yes 

5.3 Technology Evaluation Results of Lime Spray Drying (LSD) / Fabric Filter (FF) System 

Major equipment included in each LSD/FF system is: 

• Four (4) LSD/FF systems, one for each unit with associated recycle silo, slurry 

tank, pumps, piping, instruments and controls 

• One (1) Common Lime Storage and slurry preparation system 

• One (1) Common Ash Handling system

• One (1) Common Stack with two (2) flues (total of two stacks and four flues 

for four units) 

Table 5-3 below summarizes the technology evaluation results of the Lime Spray Drying / Fabric 

Filter system. 

Table 5-3. Evaluation of LSD/FF System 

(Cost in Millions) 

Units 7 & 8 

Units 5 & 6 

Incremental Total

Cost ($2006) 

Capital Cost $151.6 $183.2 $334.8 

First Year O&M $16.8 $16.1 $32.9 

Levelized O&M $23.6 $19.8 $43.4 

Capitalized O&M $228.6 $192.3 $420.9 

Total Evaluated Cost $380.3 $375.3 $755.6 

Ranking (0-5) 

Technology 5 5 5

Constructability 5 5 5

Operating and Maintenance 2 2 2 

Commercial Risk 5 5 5 

Performance Margin 1 1 1 

 Total 18 18 18

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Units 7 & 8 

Units 5 & 6 

Incremental Total

Other Factors 

Scaling Required No No 

Unconditional Commercial Guarantees Yes Yes 

5.4 Technology Evaluation Results of Circulating Fluid Bed Scrubber (CFB) / Fabric Filter (FF) 

System 

Major equipment included in the CFB/FF system is: 

• Four CFB/FF systems, one for each unit with associated recycle silo, slurry 

tank, pumps, piping, instruments and controls 

• One (1) Common Lime storage and hydrated lime system

• One (1) common ash handling system 

• One (1) stack with two flues (total of two stacks and four flues for four units) 

Table 5-4 below summarizes the technology evaluation results of the Circulating Fluid Bed 

Scrubber/Fabric Filter system. 

Table 5-4. Evaluation of CFB/FF System 

(Cost in Millions) 

Units 7 & 8 

Units 5 & 6 

Incremental Total

Cost ($2006) 

Capital Cost $142.3 $170.9 $313.2

First Year O&M $16.2 $15.2 $31.4 

Levelized O&M $22.7 $18.7 $41.4

Capitalized O&M $220.5 $181.3 $401.8

Total Evaluated Cost $362.9 $352.1 $715.0 

Ranking (0-5) 

Technology 4 4 4

Constructability 5 5 5

Operating and Maintenance 4 4 4 

Commercial Risk 2 2 2

Performance Margin 3 3 3

Total 18 18 18

Other Factors 

Scaling Required No No 

Unconditional Commercial Guarantees Yes Yes 

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5.5 Summary of SO2 Control Technology Evaluation Results 

The LSFO technology has the highest technical ranking and the lowest total evaluated cost when 

compared with the LSD and CFB processes. 

The LSFO process has the capability to achieve greater than 95% SO2 removal on a long term basis 

and has greater operational flexibility in terms of fuel variability than SDA and CFB processes. The 

expected SO2 removal efficiency for the LSD and CFB technology is 92% and 95% respectively. 

The LSFO process has the most commercial operating experience of all the available processes 

For these reasons, the LSFO technology was retained for evaluation in the total project case studies 

and LSD and CFB technologies were eliminated. 

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6.0 MULTI POLLUTANT (NOX/SO2) CONTROL TECHNOLOGY EVALUATION 

The most promising of the emerging multi-pollutant technologies are the ReACT system from the 

Japanese company J-Power and the ECO system from the US company PowerSpan. Both of these 

technologies are under development, and have very limited application. Neither technology is 

installed on units that have similar size and performance requirements as Oak Creek. It is 

questionable whether either of these technologies will be sufficiently developed in time to meet Oak 

Creek’s consent decree schedule. The evaluation of the ReACT and ECO systems was done on a 

technical/performance basis, which is summarized in this section. 

6.1 Technology Evaluation Results of J-Power ReACT System 

Major equipment included in the ReACT system for Oak Creek would potentially include: 

• Two (2) ReACT adsorber/regenerator systems, one for Units 5 & 6 and one for 

Units 7 & 8. 

• One (1) Ammonia delivery /storage system. 

• One (1) activated coke feed storage system. 

• One (1) by-product recovery facility (sulfuric plant). 

• One (1) stack with two flues 

Table 6-1 below summarizes the technology evaluation results of the ReACT System. 

Table 6-1. Technology Evaluation of ReACT System 

Units 5 & 6 Units 7 & 8 

Ranking (0-5) 

Technology 3 3

Constructability 4 4

Operating and Maintenance 2 2 

Commercial Risk 1 1 

Performance Margin 1 1 

 Total 11 11

Other Factors 

Scaling Required No Yes 

Can meet 0.07 lbs/MMBtu NOx Emission? Unproven Unproven

Unconditional Commercial Guarantees Undetermined Undetermined 

Chemical Used Activated Coke and 

Ammonia 

Activated Coke and 

Ammonia 

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6.2 Technology Evaluation Results of PowerSpan ECO System 

Major equipment included in the PowerSpan ECO System for Oak Creek would potentially include: 

• Two (2) ECO reactor/absorber/WESPs. 

• One (1) Ammonia delivery/storage system. 

• One (1) by-product facility (ammonia sulfate) 

• One (1) stack with two flues 

Table 6-2 below summarizes the technology evaluation results of the PowerSpan ECO System. 

Table 6-2. Technical Evaluation of PowerSpan System 

Units 5 & 6 Units 7 & 8 

Ranking (0-5) 

Technology 2 2

Constructability 4 4

Operating and Maintenance 3 3 

Commercial Risk 1 1 

Performance Margin 3 3 

Total 13 13 

Other Factors 

Scaling Required Yes Yes 

Can meet 0.07 lbs/MMBtu NOx Yes Yes 

Unconditional Commercial Guarantees Doubtful Doubtful 

Chemical Used Ammonia Ammonia 

6.3 Summary of Multi Pollutant Control Technology Evaluation Results 

J-Power ReACT technology was eliminated for further analysis because of the risks associated with 

this technology. The risks are: 

• Lack of US experience, including PRB coal-fired units 

• Lack of an execution plan for engineering procurement and construction of a 

ReACT System in the US 

• Excess world-wide supply of the process byproduct: Sulfuric Acid 

• No ReACT reference plant removing both high levels of both SO2 and NOX in 

the same system, raising technical questions concerning the ability of the 

system to meet the level of NOx removal required by We Energies 

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PowerSpan ECO technology was also eliminated from further consideration for the following 

reasons: 

• Currently only operating as a 50 MW demonstration project, with operating 

experience only at lower loads. 

• Demonstrated scale-up for Oak Creek will not be accomplished in time to meet 

the consent decree schedule; project would be first-of-a-kind. 

• Technology has not been demonstrated on 100% PRB coal. 

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7.0 SO2 AND NOX COMBINED SYSTEM EVALUATION 

Based on the above technology and economic evaluations it is determined that: 

• For Units 5 & 6, LSFO and SCR (cold side and tail end) technologies are suitable 

candidates for combined system evaluation. 

• For Unit 7 & 8, LSFO and SCR (hot side, cold side and tail end) technologies are 

suitable candidates for combined system evaluation. 

• Four combined systems, Cases 1 to 4 as listed below, are formulated and evaluated 

further to determine which combined system would offer the most cost effective, 

technically and commercially viable processes for NOx and SO2 emissions control 

at Oak Creek for Units 5, 6, 7 and 8. 

Case 1 LSFO and Tail-end SCRs for all four units 

Case 2 LSFO and Cold-side SCRs for all four units 

Case 3 LSFO for all four units, Cold-side 

SCRs for Units 5 & 6, and Hot-side SCRs for Units 7 & 8 

Case 4 LSFO for all four units, Tail-end SCRs for Units 5 & 6, 

Hot-side SCRs for Units 7 & 8 

Evaluation results of the four combined systems follow. 

7.1 Case 1 LSFO and Tail-end SCRs for all Four Units 

Overall System Description 

Limestone Forced-Oxidation FGD system producing wallboard quality gypsum controls the SO2

emissions. Tail-End SCR addresses NOx-reduction requirements. All the equipment will be located

south of Unit 8. 

LSFO 

The LSFO FGD would consist of two absorber systems. One absorber system would treat the 

combined flue gas from Units 5 & 6, and the second absorber would treat the combined flue gas 

from Units 7 and 8. 

Common systems consist of: 

• Limestone storage and slurry preparation 

• Gypsum dewatering 

• Wastewater treatment 

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SCR System 

Tail-End SCRs will be installed downstream of each LSFO system. For this arrangement the flue gas 

temperature must be reheated to raise it to the temperature (>525°F) at which the catalyst is active. 

Each tail end SCR would consists of two (2) gas-gas heaters, two (2) duct burners or steam coil 

heaters, and two (2) reactors. The combined treated flue gas from each reactor would be discharged 

to a common stack which has two (2) flues, one for treated flue gas from Units 5 & 6 and one for 

treated flue gas from Units 7 & 8. 

Stack 

One common stack with two flues downstream of the SCR system will discharge clean flue gas to 

atmosphere. 

Technology Evaluation and Cost 

Table 7-1 below summarizes the technology evaluation results of Case 1. 

Table 7-1 Evaluation results of Case 1 

(Cost in Millions) 

Total 

Technology NOx SO2 NOx + SO2

Tail End SCR LSFO

Tail End SCR + 

LSFO

Cost ($2006) 

Capital Cost $178.6 $335.8 $514.4 

First Year O&M $9.8 $18.9 $28.7 

Levelized O&M $12.9 $28.4 $41.3 

Capitalized O&M $125.1 $276.1 $401.2 

Total Evaluated Cost $303.7 $612.0 $915.7 

Ranking (0-5) 

Technology 4 5 9

Constructability 5 5 10

Operating and Maintenance 3 3 6 

Commercial Risk 5 5 10 

Performance Margin 5 5 10 

Total (Note 1) 22 23 45 

Other Factors 

Scaling Required No No No 

Can meet 0.07 lbs/MMBtu NOx Emission? Yes NA Yes

Unconditional Commercial Guarantees Yes Yes Yes 

Chemical Used Ammonia Limestone 

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7.2 Case 2 LSFO and Cold-side SCRs for all Four Units 

Overall System Description 

Limestone Forced-Oxidation FGD system producing wallboard quality gypsum controls the SO2

emission. Cold Side SCR addresses NOx-reduction requirements. All the equipment will be located 

south of Unit 8. 

LSFO 

The LSFO FGD would consist of two absorber systems. One absorber system would treat the 

combined flue gas from Units 5 & 6, and the second absorber would treat the combined flue gas 

from Units 7 and 8. 

Common systems consist of: 

• Limestone storage and slurry preparation 

• Gypsum dewatering 

• Wastewater treatment 

SCR System 

Four (4) cold side SCRs, one for each Unit, will be used to control the NOx emissions. Each unit's 

cold side SCR will be located down stream of its dedicated existing induced draft fans and upstream

of the new booster induced draft fans. For this arrangement the flue gas temperature must be 

reheated to raise it to the temperature (>600°F) at which the catalyst is active. Each cold side SCR 

would consists of one (1) gas-gas heater, one (1) duct burner system or steam coil heater system, and 

one (1) reactor. 

The treated flue gas from each cold side SCR will be ducted to the new booster inducted draft fans. 

Stack 

One common stack with two flues downstream of LSFO will discharge clean flue gas to the 

atmosphere. 

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Technology Evaluation and Cost 

Table 7-2 below summarizes the technology evaluation results of Case 2. 

Table 7-2 Evaluation Results of Case 2 

(Cost in Millions) 

Total 

NOx SO2 NOx + SO2

Technology Cold Side 

SCR LSFO

Cold Side SCR + 

LSFO

Cost ($2006) 

Capital Cost $190.5 $310.8 $501.3 

First Year O&M $15.0 $18.6 $33.6 

Levelized O&M $19.8 $28.3 $48.1 

Capitalized O&M $191.8 $274.5 $466.3 

Total Evaluated Cost $382.3 $585.3 $967.6 

Ranking (0-5) 

Technology 3 5 8

Constructability 5 5 10

Operating and Maintenance 3 3 6 

Commercial Risk 4 5 9 

Performance Margin 5 5 10 

 Total 20 23 43

Other Factors 

Scaling Required No No No 

Can meet 0.7 lbs/MMBtu NOx Emission? Yes NA Yes

Unconditional Commercial Guarantees Yes Yes Yes 

Chemical Used Ammonia Limestone 

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7.3 Case 3 LSFO for all Four Units, Cold-side SCR for 5 & 6, and Hot-side SCRs for 7 & 8 

Overall System Description 

Limestone Forced-Oxidation FGD system producing wallboard quality gypsum controls the SO2

emission. Hot side SCR addresses NOx-reduction requirements for Units 7 & 8. Cold Side SCR 

addresses NOx-reduction requirements for Units 5 & 6. All the equipment will be located south of

Unit 8. 

LSFO 

The LSFO FGD would consist of two absorber systems. One absorber system would treat the 

combined flue gas from Units 5 & 6, and the second absorber would treat the combined flue gas 

from Units 7 and 8. 

Common systems consist of: 

• Limestone storage and slurry preparation 

• Gypsum dewatering 

• Wastewater treatment 

SCR System 

Hot side SCRs, one for Unit 7 and one for Unit 8, would be installed between each existing unit's

economizer and air preheater. 

Two Cold Side SCRs will be installed upstream of one common 5 & 6 LSFO system. For this 

arrangement the flue gas must be reheated to raise it to the temperature (>600°F) at which the 

catalyst is active. Each cold side SCR would consist of two (2) gas-gas heaters, two (2) duct burner 

systems or steam coil heater systems, and two (2) reactors. The combined treated flue gas from each

reactor would be discharged to the common LSFO system. 

Technology Evaluation and Cost 

Table 7-3 below summarizes the technology evaluation results of Case 3. 

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Table 7-3 Evaluation Results of Case 3 

(Cost in Millions) 

Total 

NOx SO2 NOx + SO2

Technology Hot Side & 

Cold Side SCR LSFO SCR + LSFO 

Cost ($2006) 

Capital Cost $193.4 $325.6 $519.0 

First Year O&M $13.4 $18.8 $32.2 

Levelized O&M $17.7 $28.1 $45.8 

Capitalized O&M $171.1 $272.3 $443.4 

Total Evaluated Cost* $364.5 $598 $962.5 

Ranking (0-5) 

Technology 4.5 5 9.5

Constructability 3 5 8

Operating and Maintenance 2.5 3 5.5 

Commercial Risk 4 5 9 

Performance Margin 5 5 10 

 Total 19 23 42

Other Factors 

Scaling Required No No No 

Can meet 0.7 lbs/MMBtu NOx Emission? Yes NA Yes 

Unconditional Commercial Guarantees Yes Yes Yes 

Chemical Used Ammonia Limestone 

*Including $18M power penalty. 

7.4 Case 4 LSFO for all Four Units, Tail-end SCRs for 5&6, and Hot-side SCRs for 7&8 

Overall System Description 

Limestone Forced-Oxidation FGD system producing wallboard quality gypsum controls the SO2

emission. Hot side SCR addresses NOx-reduction requirements for Units 7 & 8. Tail End SCR 

addresses NOx-reduction requirements for Units 5 & 6. All the equipment will be located south of

Unit 8. 

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LSFO

The LSFO FGD would consist of two absorber systems. One absorber system would treat the 

combined flue gas from Units 5 & 6, and the second absorber would treat the combined flue gas 

from Units 7 and 8. 

Common systems consist of: 

• Limestone storage and slurry preparation 

• Gypsum dewatering 

• Wastewater treatment 

SCR System 

Hot side SCRs, one for Unit 7 and one for Unit 8, would be installed between each existing unit's

economizer and air preheater. 

One Tail-End SCR will be installed downstream of one common 5 & 6 LSFO system. For this 

arrangement the flue gas must be reheated to raise it to the temperature (>525°F) at which the 

catalyst is active. Each tail end SCR would consist of two (2) gas-gas heaters, two (2) duct burner 

systems or steam coil heater systems, and two (2) reactors. For this configuration, a single stack 

would be installed; one flue would discharge dry flue gas from the Units 5 & 6 SCRs and the other 

flue would discharge saturated flue gas from the Unit 7 & 8 LSFO, with potential associated stack 

design issues. 

Technology Evaluation and Cost 

Table 7-4 below summarizes the technology evaluation results of Case 4. 

Table 7-4 Evaluation Results of Case 4 

(Cost in Millions) 

Total 

NOx SO2 NOx + SO2

Technology Hot Side & Tail 

End SCR LSFO SCR + LSFO 

Cost ($2006) 

Capital Cost $187.5 $325.6 $513.1 

First Year O&M $11.1 $18.8 $29.9 

Levelized O&M $14.8 $28.2 $43.0 

Capitalized O&M $143.4 $274.1 $417.5 

 Total Evaluated Cost* $330.9 $599.6 $930.5

Ranking (0-5) 

Technology 4.5 5 9.5

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NOx SO2 NOx + SO2

Technology Hot Side & Tail 

End SCR LSFO SCR + LSFO 

Constructability 3 5 8

Operating and Maintenance 2.5 3 5.5 

Commercial Risk 4 5 9 

Performance Margin 5 5 10 

 Total 19 23 42

Other Factors 

Scaling Required No No No 

Can meet 0.7 lbs/MMBtu NOx Emission? Yes NA Yes 

Unconditional Commercial Guarantees Yes Yes Yes 

Chemical Used Ammonia Limestone 

*Including $18M power penalty. 

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7.5 Comparison of Cases 1 to 4 

Table 7.5 summarizes the total process capital, evaluated cost with power penalty and overall system

ranking of Cases 1 to 4. 

Table 7-5. Summary of Cases 1 to 4 (Cost in Millions) 

Cases Unit # System Component 

Total 

Process 

Capital 

Total 

Evaluated 

Cost 

Power 

Outage 

Penalty 

Total 

Evaluated 

Cost + 

Penalty Ranking

1 All Four LSFO +Tail End SCR $514 $916 $0 $916 45 

2 All Four LSFO + Cold Side SCR $501 $968 $0 $968 43 

3 Units 5 & 6 

Units 7 & 8 

LSFO +Cold Side SCR 

LSFO + Hot Side SCR 

$519 $945 $18 $963 42

4 Units 5 & 6 

Units 7 & 8 

LSFO +Tail End SCR 

LSFO + Hot Side SCR 

$513 $913 $18 $931 42

LSFO and Tail-end SCR (Case 1) have a total evaluated cost of $916 million and an overall ranking 

of 45. Due to cleaner flue gas conditions downstream of LSFO system, the tail-end applications 

have technical benefits when compared to the cold side SCR applications.

LSFO and Cold side SCR for all units (Case 2) has a total evaluated cost of $968 million and an 

overall ranking of 43. Both the LSFO and SCR are proven technologies. 

Hot side SCR for Units 7 & 8 (Case 3 & 4) pose high retrofit difficulties resulting in higher than 

standard capital cost, and power outage penalties due to extended outage time. 

Based on the overall closeness of both the total estimated cost and technical ranking, all four cases 

should be retained for further examination during preliminary engineering before a final selection is 

made. 

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8.0 CONCLUSIONS AND RECOMMENDATIONS 

8.1 Process Selection 

This study evaluated the following technologies: 

A. SO2 Removal (FGD) Processes 

• Limestone Forced Oxidation (LSFO) 

• Lime Spray-Dryer with Baghouse (LSD) 

• Circulating Fluid Bed with Baghouse (CFB) 

B. NOX Removal Processes

• Mobotec ROFA / ROTAMIX 

• Mitsui NOxStar 

• Foster Wheeler Low NOx Burners 

• SCR (Hot Side, Cold Side, and Tail-end) 

C. Multi-pollutant Processes 

• J-Power ReACT Technology 

• PowerSpan ECO Technology 

Based upon the analyses presented in this report, LSFO and SCR systems are recommended for use 

on Oak Creek Units 5-8. Some of the key considerations are listed below. 

NOx Reduction 

The design criterion is to reduce NOx emissions to less than .07 lbs/mbtu. The SCR process can 

achieve this performance with margin to spare. 

The SCR process exhibits a higher evaluated ranking over the other evaluated technologies. The 

overriding factor is the number of successfully (reliability/availability) operating SCR systems in the 

USA and overseas. 

The SCR process has greater operational flexibility compared with the other choices.

Mobotec technology is promising but not yet proven on PRB coal. Also low inlet NOx emissions 

level is a harder application than the current experience of this system. 

Mitsui has not convincingly demonstrated that their NOxStar system can achieve the required NOx

reduction. There is no space at Oak Creek for accommodating polishing SCRs in the ductwork 

downstream of the economizers, which is a feature of the NOxStar Plus system

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SO2 Reduction 

The design criterion is to reduce SO2 emissions to less than 0.07 lbs/MMBtu. The LSFO process can 

achieve this performance with margin to spare. 

The LSFO process exhibits a higher evaluated ranking over the SDA and CFB technologies. The 

overriding factor is the number of successfully (reliability/availability) operating LSFO systems in 

the USA. 

After resolution of initial problems in the early development phase, the LSFO process is now 

considered highly reliable. The forced oxidation feature produces commercial grade gypsum that can 

be sold for wall board manufacturing use. 

The LSFO process is capable of achieving greater than 95% SO2 removal efficiency. In comparison 

the SDA can achieve 93% and CFB can achieve 95% SO2 removal efficiency. 

The LSFO process has greater operational flexibility in terms of fuels used at the boilers. 

The LSFO process has the lowest evaluated cost of the alternatives compared. The LSFO process 

has also the highest evaluated ranking 

Installation of an LSFO system for the Oak Creek units presents the possibility of further shared 

savings with the neighboring Elm Road project by utilizing the capacity of common systems such as 

limestone storage and handling, gypsum storage and handling, and the wastewater treatment system. 

Multi-pollutant (NOx plus SO2) Systems 

J-Power has not convincingly demonstrated that they could make a commercial offering of their 

system in the Oak Creek project time frame. 

PowerSpan ECO system is a potential alternative; however, PowerSpan has limited industry 

experience and a high degree of scaling will be required for Oak Creek capacity. The technical risk

is considered high. Overall ranking is lower than the combined LSFO and SCR system. 

For reasons stated above the SCR and LSFO combined system is recommended for Oak Creek 

units. 

8.2 Site and New Plant Area Considerations 

The Study confirmed that there is adequate space at the site to locate combined SO2 and NOx

systems on the South side of the existing plant. The area required to accommodate the new 

equipment will require excavating some bluff areas adjacent to the west of the new plant area. Two 

new auxiliary transformers will be located southwest of the existing plant. The underground utilities 

that are present in the area would be abandoned or relocated based on further investigation. Some

preassembly work needs to be performed in areas not in the immediate vicinity of the plant. Certain 

auxiliary system equipment such as reagent storage and preparation, byproduct storage and handling 

facilities, chemical storage, etc. were located on the bluff to reduce cost of excavation for the 

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purposes of this study. However, during detail design, areas adjacent to the plant will be analyzed for 

locating these facilities to reduce piping and electrical material costs and also to minimize operating 

and maintenance costs. 

A new Stack with 2 flues, one for Units 5 & 6 flue gas and the other for Units 7 & 8 flue gas is 

required. The stack will be located on the south side of the new plant towards the existing ash ponds. 

The height of the new stack is to be determined based on dispersion analysis and regulatory code 

requirements. The new stack will be of concrete construction; the materials of construction of the 

flues will be determined through life and economic studies to be performed later. 

The flue gas ductwork from the existing ID fan(s) discharge to the new plant will be routed on the 

east side of the existing plant. Portions of the Units 7 & 8 ductwork transporting gas to the 7 & 8 

existing chimney will be no longer needed for Units 7 & 8. Therefore, these ductwork sections will 

be utilized and made part of Units 5 & 6 gas ductwork to the new plant. Other ductwork routing 

options were studied and found to be either not practical or economical. Round ductwork will be 

used where possible. Combining two (2) units' gas flow into common ductwork may provide 

opportunities for cost savings, but will increase the potential for ductwork corrosion. This will be

studied during detailed design. 

The SCR location will require further study before final configuration selection: 

• Tail-end SCRs have the potential for longer catalyst life, smaller reactor size, and lower 

operating temperature 

• Cold-side SCRs may have simpler and less-costly ductwork arrangements, and maintain 

unitized operation 

• Hot-side SCRs eliminate the gas/gas heat exchanger and natural gas usage, but have 

increased impact on the existing station 

The booster fans receive the flue gas through the new gas ductwork from the existing ID fans. These 

new booster fans were assumed to be axial fans. Further study is required to compare axial and radial 

fans. The new design assumes that two booster fans are provided for each unit. Potential cost 

savings with the use of single booster fan for each unit will be studied. 

Materials of construction of various components of the LSFO FGD system will be determined based 

on process conditions and industry experience. 

The designs assumed in this report do not share facilities with Elm Road. However, it is expected 

that the limestone unloading and long term storage could be at the existing dock area designated for 

this purpose for Elm Road plant. Limestone transfer between facilities would be by truck. A shorter 

duration close-in storage is planned on the West Side of the new facility. Likewise gypsum produced 

at Oak Creek plant could be trucked to the Elm Road dock. Future studies will include sharing of

systems with the Elm Road plant. 

A wastewater treatment facility is included in the scope of the new facility. 

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Two auxiliary transformers will receive electrical feed from the existing switchyard. These 

transformers will meet the load demand from the new emissions control plant. 

Electrical and control rooms will be located within the new plant area based operation and 

maintenance considerations. A DCS system will be provided for plant controls with monitoring 

inputs to the main plant control room. 

A temporary materials unloading dock to receive construction material deliveries transported by 

barges should be evaluated. This may allow shipment of larger assemblies to the site to reduce 

construction time and cost. 

Areas for craft parking and equipment storage have been identified, and need to be further studied 

from efficient movement point of view. 

8.3 Construction Considerations 

The new plant constructability issues were studied to ensure there are no issues that could 

significantly increase erection duration and costs. Among the construction issues studied are: 

• The ductwork routing from the existing Units 5 & 6 ID fan discharge to the 

inlet of booster fans. This ductwork runs in a North-South direction along east 

of the boiler house. Large sections of ductwork can be erected utilizing cranes 

that travel over the ash haul road. The construction sequence and technique 

needs to be further developed taking into consideration the existing plant 

operations. Portions of Units 7 & 8 return ductwork to the stack will be used as 

new Units 5 & 6 ductwork for cost savings. The ductwork supports and 

foundations will need to be designed to take into consideration existing 

structures and underground utilities. 

• A temporary materials unloading dock could be built on the lakeshore adjacent 

to the new facility. This would allow transportation of modularized and 

preassembled sections to the site utilizing barges, which may result in 

considerable savings in schedule and construction cost. 

• Crane and material movement requires the new plant construction to begin 

with Unit 8 and follow with Units 7, 6, and 5 in that order. New Unit 7 & 8 

equipment is located West of 5 & 6 and will be placed in operation first to free 

up the portions existing Units 7 & 8 ductwork that will be used for Units 5 & 6. 

• Units 5 & 6 and 7& 8 have common flues, therefore each pair of units will be 

started up together. The preliminary project schedule is based on a 6-month 

gap between the commissioning of Units 7 & 8 and Units 5 & 6. 

• Installation of certain new plant equipment such as booster fans will be 

sequenced to allow material movement to the areas north of the fans. "Leaveout" equipment and "leave-out" steel may be necessary for access to certain 

erection areas. 

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• Further investigations are needed to determine the underground utility 

relocations. 

• Excavation of certain bluff areas may be required to accommodate the 

permanent plant structures. 

• It is believed that sufficient craft labor will be available for the new facility 

construction in the window of 2008 through 2012. During the development of 

the project execution procedures, detailed labor surveys will be conducted 

which will include the study of any new construction projects that may be on 

the anvil. 

• The existing plant tie-ins to the new facility will be generally be completed in 

the planned outages of the existing units. The tie-in work will be carefully 

coordinated not to cause interruptions to the existing plant generation. 

• Detailed plant testing and start-up procedures will be developed to allow 

smooth transition of the new plant from construction to start-up and from startup to permanent plant operation. 

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