ATTACHMENT B 

ENGINEERING ANALYSIS FOR CONTROL TECHNOLOGY 

OPTIONS – GREEN BAY BROADWAY MILL 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

i 

1.0 ENGINEERING ANALYSIS METHODOLOGY 1

2.0 BART ENGINEERING ANALYSIS FOR BOILER NO. 6 3

2.1 SOURCE DESCRIPTION 3

2.2 BASELINE EMISSIONS 3

2.3 PARTICULATE MATTER 5

2.4 SULFUR DIOXIDE 7

Wet Spray Tower with Sodium Hydroxide Cost Evaluation 8

Dry Scrubbing with Hydrated Lime Fluidized Bed Absorber (FBA) Cost Evaluation 16

Furnace Sorbent Injection (FSI) Cost Evaluation 21

In-Duct Absorption System with Trona Cost Evaluation 25

Clean Fuels Cost Evaluation 28

Energy and Environmental Impacts 32

SO2 Engineering Analysis Summary 32

2.5 NITROGEN OXIDES 33

SCR Cost Evaluation 38

ROFA and Rotamix Cost Evaluation 42

SNCR Cost Evaluation 43

FGR/OFA Cost Evaluation 46

SNCR with FGR and OFA Cost Evaluation 48

Energy and Environmental Impacts 50

NOx Engineering Analysis Summary 51

2.6 SUMMARY OF ENGINEERING ANALYSES FOR BOILER NO. 6 51

3.0 BART ENGINEERING ANALYSIS FOR POWER BOILER NO.7 52

3.1 SOURCE DESCRIPTION 52

3.2 BASELINE EMISSIONS 52

3.3 PARTICULATE MATTER 54

3.4 SULFUR DIOXIDE 56

Wet Spray Tower with Sodium Hydroxide Cost Evaluation 57

Dry Scrubbing with Hydrated Lime Fluidized Bed Absorber (FBA) Cost Evaluation 60

Furnace Sorbent Injection (FSI) Cost Evaluation 62

In-Duct Absorption System with Trona Cost Evaluation 65

Clean Fuels Cost Evaluation 68

Energy and Environmental Impacts 70

3.5 NITROGEN OXIDES 72

SCR Cost Evaluation 73

ROFA and Rotamix Cost Evaluation 77

SNCR Cost Evaluation 78

OFA Cost Evaluation 81

SNCR with OFA Cost Evaluation 84

Energy and Environmental Impacts 85

3.6 ADDITIONAL MULTI-POLLUTANT CONTROL OPTION FOR BOILER NO. 7 87

Cost Evaluation 87

4.0 BART ENGINEERING ANALYSIS SUMMARY 90

APPENDIX A
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March 2009 

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1.0 ENGINEERING ANALYSIS METHODOLOGY

NR 433 Wisconsin Administrative Code requires Best Available Retrofit Technology (BART) engineering 

analyses for emission units which meet eligibility requirements of source size, type, and date of initial 

operation. Wisconsin Department of Natural Resources (DNR) notified Georgia-Pacific Consumer Products

LP – Green Bay Broadway Mill on July 9, 2008, of its eligibility for two emission units. As required by NR 

433, the Green Bay Broadway Mill has prepared an engineering analysis for units we agree are eligible for 

BART. As explained in the July 9, 2008, notice, the two units are Boiler No. 6 and Boiler No. 7 (source IDs 

B26 and B27, respectively). The requirements of a BART engineering analysis are summarized in NR 433.

The Best Available Retrofit Technology (BART) engineering analysis in this application follows the U.S. 

EPA’s BART guidelines1

 which reflect a “top-down” approach that is similar to analyses required by 

federal Prevention of Significant Deterioration regulations for Best Available Technology (BACT). The 

BART review is performed on a case-by-case basis, taking into account energy, environmental, and 

economic impacts and other costs for technologies determined to be technically feasible. The “top-down” 

approach starts with an assessment of the most stringent control technology. If the technology is shown not 

to be technically or economically effective, then the analysis provides a basis for rejecting this alternative in 

favor of the next most stringent technology as BART. Following are the basic steps of a “top-down” 

analysis: 

1) Identify all control technologies 

a) Typically in use or shown to be technically feasible by an equipment vendor, 

b) Determined as BACT and listed in USEPA RACT/BACT/LAER Clearinghouse,

c) Already in use at one of Georgia-Pacific’s operating facilities. 

2) Eliminate technically or economically infeasible options. 

3) Rank remaining control technologies by control effectiveness. 

4) Evaluate most effective controls (considering costs, energy and environmental impacts). 

5) Select BART control technology. 

GP performed the 5 steps for each visibility-affecting pollutant individually for each affected unit subject to 

BART. Wisconsin DNR has determined that the relevant pollutants are: sulfur dioxide (SO2), nitrogen 

 

1

 70 Federal Register 39104 July 6, 2005 
GP Consumer Products Green Bay Mill 

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oxides (NOx) and particulate matter (PM10)

2

. For each analysis of control technology costs, GP followed 

US EPA’s Cost Control Manual 3

 guidance. Generally, the Manual techniques reflect a “rough order of 

magnitude” with an accuracy of approximately +/- 30%. GP prepared site-specific cost estimates that meet 

or exceed this level of accuracy. 

The following sections provide a detailed engineering analysis for Boiler No. 6 and Boiler No. 7 

individually. To determine emission reduction efficiency and operating costs, the analyses used the 

BART baseline years selected by Wisconsin DNR (2002-2004). The estimated rates of reduction 

(efficiencies) reflect the design of control options. In contrast, the reduction in mass emissions (tpy) 

reflects the control option as it applies to the actual operating rates and actual fuel selections during the 

baseline period. 

 

2

 NR 433.02 (13) 

3

 EPA Air Pollution Control Cost Manual Sixth Edition EPA/452/B-02-001 January 2002 
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2.0 BART ENGINEERING ANALYSIS FOR BOILER NO. 6

2.1 SOURCE DESCRIPTION 

Boiler No. 6 is a spreader stoker-fired unit manufactured by Babcock and Wilcox installed in 1962. It is 

a two drum, balanced draft furnace, with a maximum rated heat input capacity of 350 million British 

Thermal Units per hour (MM Btu/hr). Boiler No. 6 burns washed coal 4 (eastern high and low fusion 

and western coals) and petroleum coke. Boiler No. 6 provides steam for process heating and for the 

production of electrical energy using turbine generators. The boiler is designed for steam production at a 

maximum continuous rating (MCR) of 275,000 (lbs/hr) at 850 psig and 890 o

F. The boiler exhaust gases 

pass through an air heater and then are discharged via the boiler’s induced draft fan into a common duct 

connected with the flue gas discharge streams of several other boilers at the mill. The common duct is 

equipped with a baghouse to remove particulate matter emissions from the exhaust gases. Figure B-1 

presents a side-view drawing of Boiler No. 6. 

2.2 BASELINE EMISSIONS 

The following table presents the actual fuels fired, sulfur content of each fuel combusted, and the 

BART-regulated emissions generated from Boiler No. 6 during the baseline period of 2002 through 

2004. 

Table B-1. Summary of Baseline Fuels and Emissions, Boiler No. 6 

Parameter 2002 2003 2004 3-yr Average 

Total MMBtu All Fuels 1732160 1917674 1998835 1882890 

Tons High Fusion Coal 45060 18112 894 

% S High Fusion Coal 1.01 0.96 0.96 

Tons Western Coal 9997 33588 64601 

%S Western Coal 0.54 0.49 0.5 

Tons Low Fusion Coal 0 8771 5009 

% S Low Fusion Coal 2.33 2.36 2.43 

Tons Pet Coke 10971 12084 14119 

% S Pet Coke 5.89 5.38 5.49 

Annual Average SO2 (lb/MMBtu) 2.22 2.52 2.14 2.29 

Actual SO2 Emissions (tpy) 1926 2413 2141 2160 

Actual NOx Emissions (tpy) 375 432 477 428 

Actual PM10 Emissions (tpy) 72 79 50 67 

 

 

4

 Coal is washed prior to arrival at the mill as needed to reduce ash and achieve heat content specifications. 
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Best Available Retrofit Technology Analysis 

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Figure B-1. Side View of Boiler No. 6, Green Bay Broadway Mill 
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2.3 PARTICULATE MATTER

Step 1a-Identification of Control Technologies-Typical Technologies in Use in the United States 

Technology that may be considered for the control of particulate matter emissions from boilers includes 

the substitution and use of clean fuels, mechanical/gravity separation devices (e.g., cyclones, settling 

chambers), electrostatic precipitators (ESPs), baghouses, and high efficiency wet scrubbers. 

Step 1b-Identification of Control Technologies-Review of RACT/BACT/LAER Clearinghouse 

(RBLC) 

Searches of the RBLC were conducted to identify control technologies for the control of PM10 emissions 

from stoker-fired boilers. The specific category searched was External Combustion- -11 

The clearinghouse listed multiclones with ESPs, baghouses, good combustion practices and wet 

scrubbers as the PM10 control technologies. 

Step 1c-Identification of Control Technologies-Review of Technologies in Use at Georgia-Pacific 

Corporation Facilities 

GP operates numerous combination fuel-fired boilers and coal-fired boilers at its operating facilities within 

the United States. PM10 control devices in use at these mills include ESPs, baghouses and wet scrubbers. 

Step 2-Technical Feasibility Analysis-Eliminate Technically Infeasible Options 

All of the control options identified in Step 1 are technically feasible. 

Step 3 – Ranking the Technically Feasible Alternatives to Establish a Control Hierarchy 

The ranking of technologies for PM10 control is: 

1. Baghouse with greater than 99% removal efficiency 

2. ESP with multiclones at greater than 99% removal efficiency 

3. High efficiency scrubbers with 98%+ removal efficiency 

4. Wet scrubbers with 50 to 95% removal efficiency 

5. High efficiency cyclones with 50-90% removal efficiency 

Step 4- Cost Effectiveness Evaluation 

GP currently operates a high efficiency (above 99%) baghouse to control PM10 emissions generated by 

Boiler Nos. 5, 6, 7, and 8. The baghouse design inlet particulate loading ranges from 1 to 3.5 

grains/actual cubic foot (gr/acf) while the outlet loading is consistently at or below 0.01 gr/acf. The 

baghouse design exhaust gas flowrate is 772,000 acf/minute (ACFM) at 365 °F. The existing State limit
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of 0.3 lb PM10/MM Btu from NR 415.06(1)(b), (equivalent to 105 lb/hr at Boiler No. 6’s maximum 

rated capacity), is much greater than the baseline annual emission rate of approximately 17 lbs/hr5

(equal to 0.07 lb/MM Btu) from Boiler No. 6. As the Mill presently operates the highest ranked PM10 

control technology, no additional cost effectiveness evaluation is necessary. 

Step 5-Select BART 

GP is proposing to continue the use of the highest level of control, a baghouse with the current emission 

limit of 0.3 lb PM10/MM Btu. 

 

5

 Estimated with actual reported emissions presented in Table B-1 and the total operating hours for the baseline 

period (23520 hours). That is, [72 tons + 79 tons + 50 tons] x 2000 lbs/ton / 23,520 hours = 17.1 lbs/hr average. 

Using the total MMBtu for the baseline period, the actual emissions are estimated as [72 tons + 79 tons + 50 tons] 

x 2000 lbs/ton / 5648669 MMBtu = 0.07 lb/MMBtu. These emissions include both filterable and condensible 

particulate matter. 
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2.4 SULFUR DIOXIDE 

Step 1a-Identification of Control Technologies-Typical Technologies in Use in the United States 

Emission control equipment that may be considered to control sulfur dioxide emissions from coal-fired 

boilers includes: 

1. Gas absorption using wet and dry scrubbers (90% control), 

2. Flue gas desulfurization techniques such as sorbent injection (50 to 65% control). 

3. The use of clean substitute fuels can also be considered as an alternative to add-on controls. 

Step 1b-Identification of Control Technologies-Review of RACT/BACT/LAER Clearinghouse 

(RBLC) 

Searches of the RBLC were conducted to identify control technologies for the control of SO2 emissions 

from stoker-fired boilers. The specific category searched was “External Combustion- -11”. The 

clearinghouse listed the use of clean fuels, wet and dry scrubbers, and flue gas desulfurization 

techniques such as limestone injection and spray dryer absorbers (SDA) as the control technologies. 

Step 1c-Identification of Control Technologies-Review of Technologies installed at Georgia-Pacific 

Corporation Facilities 

Georgia-Pacific operates numerous combination fuel-fired boilers and coal-fired boilers within the 

United States. SO2 control technologies include dry scrubbing, limestone and sorbent injection on 

fluidized bed boilers, and the use of clean fuels. However, the company has limited experience with wet 

scrubbing with caustic on similar types of stoker coal-fired boilers. 

Step 2-Technical Feasibility Analysis-Eliminate Technically Infeasible Options 

The Green Bay Broadway Mill investigated several gas absorption technologies: wet scrubbing with caustic 

(sodium hydroxide) solutions, semi-dry scrubbing using a lime slurry with conventional scrubbers, Spray 

Dry Absorbers (SDAs), and circulating fluidized bed scrubbers. Scrubber vendors have indicated to the

Mill that spray drying is not technically feasible because the allowable inlet sulfur concentration associated 

with the current fuel mix would be too high and the flue gas temperatures too low to support the water

evaporation requirements in the hydrated lime slurry SDA. As a result, SDA vendors have informed GP that 

they cannot provide quotations for this particular application of the technology. All of the other SO2 control 

technology options are technically feasible. 
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Step 3 – Ranking the Technically Feasible Alternatives to Establish a Control Hierarchy 

The ranking of the technologies are: 

1. Gas absorption with a wet spray tower or semi-dry scrubbing system with hydrated lime at 90%+ 

SO2 removal efficiency, 

2. In-Furnace Sorbent Injection at 65% removal efficiency, 

3. In-duct absorption with sodium sesquicarbonate (Trona) injection with 50% removal efficiency, 

4. Fuel substitution: Low SO2/MMBtu coal in place of all higher sulfur containing fuels at 40-62% 

removal efficiency. 

Step 4- Effectiveness Evaluation 

Economic Evaluation 

For each control technology cost estimate, the Green Bay Broadway Mill provided several general 

assumptions to the equipment vendors and engineering contractors for their use in determining site-specific 

cost estimates with a target accuracy of +/- 30% or better. 

The Title V Permit for the Green Bay Broadway Mill limits the firing of petroleum coke to a rate 

demonstrated during a compliance stack test. As a result of these tests, the current fuel mix is limited to 

approximately 17% by weight petroleum coke and 83% coal, based on the heat content of the fuels currently 

combusted in the boiler. The cost analysis for Boiler No. 6 considers equipment that has been designed for 

the control to accommodate an SO2 inlet loading of 760 to 1,300 lb/hr.6

 In instances that pumps are part of 

the equipment design, the cost estimates include redundant pumps to allow the control equipment to 

continue operating while one pump is being repaired or otherwise out-of service. In addition, the analysis 

applied a 15-year life to the capital recovery factor calculation for scrubber technologies. Other technologies 

with less equipment (i.e., in furnace sorbent inject) applied a longer, conservative value of 20-year life for 

the capital recovery factor. The analysis also applied 8,400 hours/year and/or actual uncontrolled emissions 

to determine the direct operating costs. This approach is conservative in that an analysis using potential 

emissions would overstate direct operating costs such as reagent use. 

Wet Spray Tower with Sodium Hydroxide Cost Evaluation

The Green Broadway Bay Mill worked with several control equipment vendors to review technical issues 

and challenges with SO2 control by using either wet, dry, or semi-dry scrubbing technologies. Based on the 

 

6

 Hourly emissions reflect the maximum heat input rate of 350 MMBtu/hr and a range of fuel mixes represented as 

2.17 to 3.7 pounds sulfur dioxide per MMBtu. Though the stack is permitted for 4.55 pounds sulfur dioxide per 

MMBtu, this rate is limited by other permit conditions that restrict the amount of petroleum coke burned at any 

time. 
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technical reviews, the use of a wet spray tower demonstrates the best overall SO2 removal efficiency of all 

the technologies reviewed and that were considered technically feasible. Jacobs Engineering provided the 

Green Bay Broadway Mill with a +/-30% cost estimate to install and operate a wet spray tower scrubber. 

The cost estimate for a wet spray tower scrubber assumed that the scrubber would be located downstream of 

the existing baghouse. This requirement is necessary to maintain low PM10 emissions entering the scrubber 

as the scrubber would not function properly if it was “overloaded” with PM10 emissions. Additionally, the 

proposed scrubber is not capable of replacing the baghouse since it is not capable of reducing PM10

emissions to the same levels achieved by the existing baghouse. For gas absorption, the control equipment 

was designed with a maximum flue gas exhaust gas flow rate of 235,000 acf per minute (ACFM). The 

scrubber was designed with an exhaust gas flow rate greater than the existing rate from Boiler No. 6 of 

approximately 140,000 ACFM. This was done to accommodate additional exhaust gases from a slip-stream 

during periods of lower SO2 influent conditions. That is, when the fuels burned in the boilers yield a lower 

inlet air concentration of sulfur dioxide, the scrubber may need to treat a larger exhaust gas flowrate to 

achieve the same SO2 removal efficiency. 

 

The wet spray tower scrubber operates by directing the boiler exhaust gases through an alkaline liquid

solution. The flue gas would enter the wet spray tower scrubber radially at the bottom of the unit flowing 

vertically upward through the scrubber vessel, and counter-current to the alkaline solution. The clean 

(scrubbed) flue gas would then be passed through a chevron-type mist eliminator for removal of large water 

droplets prior to exiting to the atmosphere through the top of the scrubber vessel. The mist eliminator would 

be equipped with an internal water wash header that is activated intermittently to wash away potential

formations of reacted salts. The alkaline solution, by way of contacting the flue gas surface, promotes the 

absorption of the acid gases and the reduction of SO2 from the exhaust gas stream. The alkaline solution 

used for this study is a 50% (wt.) solution of sodium hydroxide. The caustic solution would be introduced 

into the top of the scrubber vessel via multiple spray nozzles by a metering pump initiated by a pH analyzer 

loop located in the recycle reservoir. These nozzles would be arranged to ensure that the flue gas stream is 

in complete contact with the downward flowing caustic solution. The caustic solution would drain to the 

bottom of the absorber vessel’s reservoir and be recycled back to the spray headers with recirculation pumps 

by blowing down some of the liquid based on reservoir conductivity and adding fresh makeup water as 

needed. 

The clean flue gas would exit the wet spray tower scrubber and enter a new 16’-4” diameter, 316L stainless 

steel stack mounted on top of the new spray tower scrubber outlet. The stack would terminate at an 

elevation of 199 feet above grade. The stack would be sized for a flue gas velocity of approximately 34 
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Best Available Retrofit Technology Analysis 

March 2009 

B-10 

ft/sec of saturated flue gas. The lower velocity in the stack is critical to prevent water carry-over from stack 

sidewalls (as would occur when operating at higher velocities) or what is referred to as “raining” from the 

stack exit. Stainless steel material was chosen for the stack to allow for good resistance to acid attack that is 

possible due to contact with the saturated flue gas. Acid attack occurs mainly in the wet-to-dry interface in 

a stack. Therefore, the stack would be designed on top of the scrubber to ensure any water formation on the 

internal stack wall will drain back to the scrubber. 

The existing induced draft (ID) fan on the baghouse outlet and associated drive would be reused as presently 

installed. The existing fan curves and motor horsepower were reviewed and found to be adequately 

designed to account for the increased pressure drop created by the additional ductwork (4” w.c. drop 

through ductwork) and the spray tower scrubber (3” w.c. drop through scrubber). The incremental cost of 

the fan horsepower required for the additional scrubber and associated ductwork pressure drop is included in 

the operating cost for the spray tower scrubber. Money is included in the estimate as an allowance to

evaluate and seal any air infiltration due to leakage from Boiler No. 6’s physical structure and associated 

ductwork. 

The cost estimate considered additional site-specific design conditions which have a significant impact on 

the control system design and cost: 

• Mill process water would be used for scrubber make-up due to evaporation during operation and for 

supply of water to the mist eliminator wash water header. However, mill process water is not 

available at the required pressure (greater than 65 psi) in the new scrubber area, therefore, make-up 

water booster pumps would also be required as part of the new scrubber system . 

• While no capital has been specifically identified for rerouting of underground lines, there are funds 

available in the cost estimate for “site improvements”. Money for the labor and material cost for 

relocating process, sewer, and fire water lines would come from this estimate; however, without 

detailed information regarding the underground lines in the installation site this may not be 

sufficient. The funds included in the cost estimate are based on the typical amount of rerouting 

required for an installation such as this, based on experience Jacobs Engineering (working under 

contract for GP) has gained from other projects. 

• The existing electrical control infrastructure is not adequate for the additional equipment in this 

option. Thus, a new Motor Control Center/Rack Room was also included in the factored estimate in 

order to provide an area to house the electrical equipment for the ID Fan new pump drives. 
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• The scrubber would be completely field-welded in place due to its large size. Lower-cost shopwelded scrubber vessels cannot be used for this project as they do not have the flow rate capacity 

required for this project. 

• The 50% caustic solution storage tank would be equipped with in-tank electric heaters and caustic 

metering pumps. At this level of design, the residence time of delivered caustic is expected to be 

less than one day and the estimate does not include permanent buildings for the storage tank. 

To prevent the buildup of sulfur compounds in the scrubber, a waste bleed stream would be required to 

remove concentrated solids. This waste stream would be rich in sodium and sulfur-bearing compounds 

created from the reaction of sulfur dioxide gases with the caustic solution. The waste bleed stream from the 

scrubber would be nominally comprised of 10% dissolved sodium salts including sodium sulfate, sodium 

sulfite, and sodium bi-sulfite. The Green Bay Broadway Mill has no allowance in their NPDES wastewater 

discharge permit for the additional dissolved ions present in the scrubber’s wastewater stream, and 

therefore, simply combining the scrubber’s wastewater with the mill’s wastewater would exceed the mill’s 

NPDES permit limit for conductivity. Furthermore, while the Mill’s wastewater treatment system may 

remove most of the sulfate bearing compounds, Jacobs’ analysis has determined that the plant’s wastewater 

effluent will have the potential to discharge mercury above the current NPDES Permit limit. The Fox River 

is the receiving water for the wastewater plant effluent. GP believes the ongoing study to establish a total 

maximum daily limit (TMDL) of mercury discharges into the Fox River disqualifies the discharge of wet 

scrubber blow down into the plant’s wastewater treatment system. To eliminate the mercury discharge 

issue, Jacobs’ cost estimate has included a dedicated, separate wastewater treatment process to remove

solids (including mercury and other metals) using concentration and evaporation methodology. 

The preferred alternative for managing scrubber wastewater is the use of a recirculating evaporator/ 

condenser/ccentrifuge system. In this design, the wastewater bleed from the scrubber would enter a series 

of preheated steam condensing exchangers, and then move on to the evaporator crystallizer vvessels. By 

evaporating water, the salt solution would be concentrated past its solubility point, resulting in the formation 

of solid crystals. The wastewater stream from the evaporator crystallizer vvessel would be taken to a

centrifuge, where any solid crystals present would be separated to form a solid waste stream. The solid 

waste stream would drop into a truck that will then be transported to a landfill. The evaporated water would 

be condensed with mill process cooling water. The condensed water would be the then used as a clean 

water stream for potential use at the mill. 
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The spray tower scrubber evaluated has a 24’ by 30’ footprint and the scrubber absorber vessel is 19’-3” in 

diameter and stands approximately 58’ tall. The bottom of the absorber would be raised several feet above 

grade to allow for access to auxiliary equipment located underneath at grade. The steel structure would 

terminate at the stack testing platform level. New 10’ x 10’ ductwork would be added to transfer flue gas 

from the existing roof-mounted dual chamber baghouse ID fans outlets to the spray tower scrubber’s inlet. 

Figure B-2 presents a simplified general equipment arrangement. 

Table B-2 summarizes the estimated capital costs to install a complete wet spray tower scrubber system. 

The total installed cost is estimated to be equal to $33,062,714. 
GP Consumer 

Best Available Retro

B-13 

Figure B-2. General Arrangement of Wet Spray Tower System, Green Bay Broadway Mill 
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Table B-2. Summary of Capital Cost for Installation of Wet Spray Tower Scrubber System, Boiler 

No. 6 Green Bay Broadway Mill 

Description7 Total Cost (2007$) 8

Direct Costs 

Major Equipment 8,971,255 

Demolition 14,522 

Site Improvements 448,563 

Piling, Caissons 627,988 

Buildings 502,180 

Concrete 741,100 

Structural Steel 1,644,865 

Piping 2,496,353 

Insulation - Pipe, Equipment & Ductwork 643,899 

Instrumentation 715,662 

Electrical 1,088,346 

Painting, Protective Coatings 89,713 

Construction Indirect Costs 

Construction Support Labor 778,526 

Premium Time 229,937 

Craft Per Diem ($7/Hour On 100 % Of Time) 493,602 

Non-Payroll Tax, Insurance & Permits 775,873 

Craft Start-Up Assistance 32,717 

Contractor's Construction Fee 1,441,756 

Project Indirect Costs 

Construction Management 1,493,050 

Engineering Professional Services 3,315,140 

Study Cost 50,000 

Outside Consultant Services 100,000 

Owner's Cost 993,118 

Spare Parts 343,840 

Non-Craft Start-Up Assistance 89,306 

Allowance For Unforeseen 2,804,624 

Escalation 2,036,801 

Air Infiltration Allowance 9

$100,000 

Total Installed Cost (TIC)(+/- 30%) $33,062,714 

 

7

 See Appendix for further description of estimator’s cost categories 

8

 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 

9

 Modifications to the exhaust system are expected to require studies and upgrades to eliminate air infiltration. 
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To determine estimated operating costs for the scrubber, this cost analysis used the templates provided by 

EPA in their Cost Control Manual. Determining annual operating costs is sensitive to the amount of sulfur 

dioxide removed and the amount of scrubbant required to maintain the desired SO2 removal efficiency. The 

2002-2004 actual emissions are significantly lower than permitted emissions (i.e.., 2.29 lbs SO2/MMBtu in 

2002-2004 compared to permit limit of 4.55 lb SO2 /MMBtu) and thus represent a conservatively lower 

annualized cost estimate. Table B-3 presents operating costs for the spray tower technology. 

Table B-3. Annual Operating Cost Calculations, Wet Spray Tower for Boiler No. 6, Actual 2002-2004 

Conditions

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per shift x 1095 shifts/yr @ $40/hr 43,800 

Supervisor Labor 15% of Operator costs 6,570 

Maintenance labor: 0.5 hours per shift x 1095 shifts/yr @ $40/hr 21,900 

Maintenance material 100% of Maintenance Labor 21,900 

Electricity 0.059$/kWhr x 11,160,688 kWhr/yr 658,481 

Caustic Solution10 $1,050/dry ton NaOH x 3,375 ton NaOH 3,543,750 

Process water: $0.06/kgal x 976,039 kgal 58,562 

Landfill Scrubber system solids $ 9.50/ton x 24,878 tons 236,341 

Additional Process Steam $2.45/klb steam x 186,588 klbs 457,141 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 56,502 

Taxes, insurance, admin. factor: 4% of TIC (Table B-2) 1,322,509 

Capital recovery factor (system): 0.1098 x TIC 11 3,630,108 

Total Annual Cost 10,057,563 

 

10 2002-2004 actual SO2

 tons = 2,160 emitted; consumption is 2.5 lb-mol NaOH per lb mol of SO2 emitted; 2008 average unit 

cost of caustic as delivered to Mill = $1,050/dry ton NaOH; 

2,160 tons SO2

 x 2,000 lbs/ton x lbmol SO2/64 lbs SO2 x 2.5 lb-mol NaOH/lb-mol SO2 x 40 lbs NaOH/lb-mol NaOH / 2,000 

lbs/ton =3,375 tons dry NaOH 

11 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: 

(0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

The cost effectiveness of this technology is equal to the Annual Operating Costs/ Annual Quantity of SO2

Removed. 

The estimated cost effectiveness is: $ 10,057,563 / (90% x 2,160 tons) = $5,174/ton. 
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Dry Scrubbing with Hydrated Lime Fluidized Bed Absorber (FBA) Cost Evaluation 

Dry scrubbers have significantly lower capital and annual operating costs than wet systems because they are 

simpler, demand less water, and waste disposal is less complex. Dry injection systems are easier to install 

and use less space; therefore, they are good candidates for retrofit applications, such as the one at the Green 

Bay Broadway Mill. In contrast to a wet spray tower, FBAs use a reactor vessel with a closely controlled 

temperature. Both an even distribution of sorbent across the reactor and adequate residence time at the 

proper temperature are critical for the best SO2 removal rates 12

. 

Flue gas from the boiler would enter the bottom of the fluid bed absorber. Water would be first sprayed into 

the gas stream to cool the flue gas to near adiabatic conditions to improve adsorption. Once the flue gas 

stream is cooled, hydrated lime would be added to the reactor at a rate of approximately 5,000 lbs per hour. 

The SO2 would react with the hydrated lime to form calcium sulfate. The unreacted hydrated lime, fly ash, 

spent lime, and calcium sulfate would then be captured in the fabric filter and then recirculated back to the 

inlet of the fluidized bed absorber. Fresh hydrated lime would be added to the circuit to maintain absorber 

SO2 removal efficiency. The system would bleed out excess spent material for disposal using the same 

methods presently used for boiler ash disposal. Because the original design of the baghouse is much larger 

than the flue gas volume from the current boilers, the mill expects that the existing baghouse will collect the 

additional particulate loading and maintain its high removal efficiency from an FBA without significant 

modification. 

ESI Inc. of Tennessee provided the Green Bay Broadway Mill with a +/-20% cost estimate to install an 

FBA system. 

The FBA cost estimate reflects the installation and operation of the following new equipment: 

• new fluidizing bed reactor 18' diameter x 100' overall height, 

• solids recirculation systems, 

• pre-piped lime slurry pump skids, 

• booster fans, 

• 210-ton powdered hydrated lime silos with fabric filter to collect dust from silo loading, 

• a hydrated lime bulk pneumatic truck unloading station, 

• rotary hydrated lime volumetric hydrated lime feeders, 

• shutoff dampers (double sealing) with purge air blowers for safe access to confined spaces. 

 

12 Srivastava, 2001. Srivastava R. K., and W. Josewicz.. “Flue Gas Desulfurization: The State of the Art”. Air and 

Waste Management Assoc., 51:1676-1688, 2001. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-17 

Table B-4 summarizes the total cost for installation of the FBA system. 

Table B-4. Summary of Capital Cost for Installation of Fluidized Bed Absorber System, 

Boiler No. 6 Green Bay Broadway Mill 

Description Total Cost (2008$)13

Scrubber systems installation and duct modifications 10,158,367 

Footings and foundation work 405,000 

Electrical and controls 929,094 

Structural steel 285,000 

Engineering and commissioning 1,228,922 

Construction management 829,523 

General contractor overhead and mark-up 1,013,861 

Contingency 1,536,153 

Emission Monitoring systems 180,000 

Piping 61,760 

Freight 591,961 

Miscellaneous 270,000 

Total Installed Cost (TIC) (+/-20%) 17,489,639 

 

 

13 BART Preliminary Engineering Study (ESI Inc. of Tennessee March 2008) 

Figure B-3 represents a simplified flow diagram of the required equipment for a generic case of any one of 

several boilers at the mill. In contrast to the wet spray tower scrubber technology, most of the equipment 

will be located within the existing buildings at a point upstream of the baghouse. Figure B-4 presents a 

footprint diagram. 
GP Consumer 

Best Available Retro

B-18 

Figure B-3. Schematic of Process Equipment for Fluidized Bed Absorber, Generic Case 
GP Consumer 

Best Available Retro

B-19 

Figure B-4. Equipment Arrangement for Fluidized Bed Absorber, Generic Case 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-20 

To determine annual operating costs, the analysis followed US EPA’s Cost Control Manual templates 14

with some equipment-specific adjustments. Table B-5 presents the annual operating costs for the FBA 

technology. 

Table B-5. Annual Operating Cost Calculations, Fluidized Bed Absorber for Boiler No. 6, Based on Actual 

2002-2004 Emissions and Operating Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 3 hour per shift x 1095 shifts/yr @ $40/hr 131,400 

Supervisor Labor 15% of Operator Costs 19,710 

Maintenance labor & equipment: Vendor Estimate 10% of Equipment Costs 910,000 

 

Electricity- direct 0.059$/kWhr x 6,864,000 kWhr/yr 404,976 

Electricity- fan make-up 8 inches w.c 201,680 

Hydrated Lime $90/ ton hy. lime x 8,932 ton hy. Lime/yr15 803,853 

Process water: $0.06/kgal x 8,400 kgal 504

Landfill Scrubber system solids $ 9.50/ton x 29,601 tons 276,080 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 636,666 

Taxes, insurance, admin. factor: 4% of TIC (Table B-4) 699,586 

Capital recovery factor (system): 0.1098 x TIC 16 (Table B-4) 1,920,268 

 

Total Annual Cost 6,004,723 

 

14 EPA Air Pollution Control Cost Manual Sixth Edition EPA/452/B-02-001 January 2002 

15 2002-2004 actual SO2

 tons = 2,160; consumption is 3.25 lb-mol hydrated lime per lb mol of SO2 removed; 2008 average unit 

cost = $275 dry ton hydrated lime 

2,160 tons SO2

 x 2,000 lbs/ton x lb-mol SO2/64 lbs SO2 x 3.25 lb-mol hydrated lime/lb-mol SO2 x 74.1 lbs hydrated lime / lbmol hydrated lime / 2,000 lbs/ton x 1ton pure CaCO3/0.91 ton hydrated lime = 8,932 tons hydrated lime 

16 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: 

(0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and scrubbant 

required. The 2002-2004 emission rates are significantly lower than permitted emissions and thus represent 

a conservatively lower annual cost (and operation) estimate. 

The cost effectiveness of this technology is equal to Annual Costs/ Annual SO2 Removed. 

The estimated cost effectiveness is: $6,004,273/ (90% x 2,160 tons) = 3,089 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-21 

Furnace Sorbent Injection (FSI) Cost Evaluation 

As an alternative to “back-end” controls, the Green Bay Broadway Mill assessed control technologies 

further upstream. One such technique involves injecting a sorbent into the combustion chamber of the 

boiler with the fuel. As additional material in the boiler can significantly affect boiler performance, this 

technology is coupled with improving the air distribution system within the boiler. The technology has been 

demonstrated on stoker-fired boilers, however, an unknown risk to operations is the potential erosion of 

boiler furnace tubes due to the additional sorbent material injected into the combustion chamber of the 

boiler. The FSI technology is similar to the dry scrubbing system in that it eliminates management of wet 

streams and has a small equipment footprint relative to wet scrubbing systems. Limestone with a high 

CaCO3 content would absorb SO2 as the fuel sulfur is oxidized in the furnace. The resultant particulate 

would be carried out with the boiler flue gas and then captured in the existing baghouse. As mentioned

earlier, the mill expects that the existing baghouse would collect the additional particulate and maintain its 

high removal efficiency from an FBA without significant modification, and the same expectation holds for 

any additional particulate resulting from FSI. 

The Green Bay Broadway Mill selected Mobotec USA as a vendor to develop an equipment cost estimate 

for a Furnace Sorbent Injection (FSI) system. Mobotec USA would supply the injection equipment, mixing 

nozzles (ROTAMIX), and rotating overfire air fans (ROFA) for such a system, which would also be 

considered a technically feasible NOx control technology. Installation of the ROFA system includes a new 

overfire air fan that will take suction from the hot combustion air side of the boiler’s existing air preheater, a 

new ductwork system, and multiple ROFA boxes installed on the furnace walls. A detailed study for 

appropriate placement of the FSI system nozzles and injection locations was not conducted for Boiler No. 6; 

however, the cost estimate includes a one time study cost of $50,000. 

The installed equipment required for the FSI system includes a: 

• Limestone storage silo with truck unloading connections, a baghouse to control loading emissions, 

feed hoppers, screw feeders and rotary valves, pulse system and isolation valves; 

• A new blower with the pneumatic limestone feed piping system and injection devices mounted on 

the furnace wall, and; 

• Additional fans, ductwork and controls for ROFA boxes. 

The BART estimate includes additional (above those normally factored) allowances for demolition and 

relocation inside of the building around Boiler No. 6 due to the extensive amount of ductwork and injection 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-22 

piping required for the FSI system. Extensive layout and engineering planning would be required at the 

time of design to make the installation of this system functional in regards to good maintenance access and 

basic boiler walk-around access. The physical location of Boiler No. 6 is a congested area that is 

immediately adjacent to other boilers which in turn may limit the ability to locate ROFA boxes and injection 

lances in the optimum positions predicted by the study. The total installed cost (TIC) for the FSI system is 

$26,827,507. Table B-6 presents the total installed costs for an FSI system for Boiler No. 6. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-23 

Table B-6. Summary Of Capital Cost For Installation Of FSI System, Boiler No. 6 Green 

Bay Broadway Mill 

Description17 Total Cost (2007$)18

Major Equipment 5,926,151 

Demolition 811,138 

Site Improvements 491,316 

Piling, Caissons 631,692 

Buildings 330,000 

Concrete 828,031 

Structural Steel 1,497,449 

Piping 1,886,064 

Insulation - Pipe, Equipment & Ductwork 296,308 

Instrumentation 658,012 

Electrical 1,014,583 

Painting, Protective Coatings 59,262 

Construction Indirect Costs 

Construction Support Labor 711,432 

Premium Time 209,454 

Craft Per Diem ($7/Hour On 100 % Of Time) 451,063 

Non-Payroll Tax, Insurance & Permits 504,113 

Craft Start-Up Assistance 43,650 

Contractor's Construction Fee 1,242,334 

Project Indirect Costs 

Construction Management 1,209,000 

Engineering Professional Services 2,683,000 

Study Cost 50,000 

Outside Consultant Services 100,000 

Owner's Cost 804,000 

Spare Parts 245,193 

Non-Craft Start-Up Assistance 119,150 

Allowance For Unforeseen 2,275,240 

Escalation 1,649,872 

Air Infiltration Allowance 100,000 

TOTAL INSTALLED COST (TIC) (+/-30%) 26,827,507 

 

17 See Appendix for further description of estimator’s cost categories 

18 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 
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Best Available Retrofit Technology Analysis 

March 2009 

B-24 

Table B-7 presents annual operating costs for the FSI system. Without a site-specific study by Mobotec, the 

economic analysis could not estimate what, if any, loss of steaming capacity would occur with the 

significant amount of “dead load” material (i.e., sorbent) added into the furnace. The operating costs also do 

not include lost steam production due to increased wear on boiler tubes. Though the increased rate of tube 

erosion cannot yet be determined, the operation of the boiler will be affected by a significant increase in 

tube wall inspections following startup with an FSI system.

Table B-7. Annual Operating Cost Calculations, FSI for Boiler No. 6, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hour/shift x 1,095 shifts/year @ $40/hr 43,800 

Supervisor Labor 15% of Operator costs 6,570 

Maintenance labor: 0.5 hrs/shift x 1,095 shifts/year @ $40/hr 21,900 

Maintenance material 100% of Maintenance Labor 21,900 

 

Electricity- direct 0.059$/kWhr x 3,437,500 kWhr 202,813 

Limestone $40/ton limestone x 10,978 tons19 439,189 

Landfill Additional system solids $ 9.50/ton x 10,978 tons 104,291 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 56,502 

Taxes, insurance, admin. factor: 4% of TIC (Table B-6) 1,073,100 

Capital recovery factor (system): 0.0944 x TIC20 (Table B-6) 2,532,327 

 

Total Annual Cost 4,502,391 

 

19 2002-2004 actual SO2

 tons = 2,160; consumption is 3.25 lb-mol limestone per lb mol of SO2; Average unit cost is $40/ton 

delivered. 

 

2,160 tons SO2 x 2,000 lbs/ton x lb-mol SO2/64 lbs SO2 x 3.25 lb-mol limestone /lb-mol SO2 x 100.1 lbs limestone (CaCO3)/ 

lb-mol limestone / 2,000 lbs/ton = 10,978 tons limestone 

20 7% interest for the cost of capital and an equipment life of 20 years using Equation 2.8a of USEPA Cost Control Manual 

yields: (0.07*(1+0.07)^20)/((1+0.07)^20-1) = 0.0944

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent 

required. The 2002-2004 actual emissions are significantly lower than permitted emissions and thus 

represent a conservatively lower annual cost (and operation) estimate. 

The cost effectiveness of this technology is equal to Annual Costs/ Annual SO2 Removed. 

The estimated cost effectiveness is: $4,502,391/ (50% x 2,160 tons) = 4,169 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-25 

In-Duct Absorption System with Trona Cost Evaluation 

In contrast to injecting sorbent into the boiler or using a wet spray tower scrubber vessel, in-duct absorption 

is an alternative capable of obtaining a 50% reduction in SO2 emissions from Boiler No. 6. Unlike the other 

SO2 removal technologies described above, this technology does not have many similar applications in 

commercial operation. With the use of this technology, offered by O’Brien and Gere, the sorbent is fed into 

the flue gas as a dry powder. The sorbent (sodium sesquicarbonate, or Trona) undergoes thermal 

decomposition and reacts with sulfur dioxide in the flue gases to form a particulate. Approximately onethird of the sorbent mass forms carbon dioxide and exhausts to the atmosphere while the other two-thirds of 

the particulate mass is captured in the existing baghouse. The supply market for this sorbent is limited to a 

few active mines in western United States. Without multiple sources for Trona, deliveries to the mill are at 

higher risk of supply interruptions (e.g., natural or other external events) than sorbents with many suppliers. 

For Boiler No. 6, Trona would be injected between into the flue gas stream between the boiler’s economizer 

outlet and the air preheater inlet where the flue gas exhaust temperature is approximately 700°F. Vendor 

experience indicates that this is the optimum temperature for SO2 removal for this sorbent application and 

type of boiler. The thermal decomposition at this temperature increases the amount of surface area on the 

Trona particle, and increases its SO2 capture efficiency. The chemical reaction taking place in the flue gas 

stream with Trona injection is shown below:

2(Na2CO3•NaHCO3•2H2O) + 3SO2 → 3Na2SO3 + 4CO2 + 5H2O 

As shown, the use of Trona will result in the release of 4 moles of CO2 for every 2 moles of Trona. 

The particle size specification for Trona injection is a minimum of 90% by weight shall be no larger than 10 

microns in diameter. If the Trona particles are not ground properly, the consumption of Trona in the flue gas 

stream will be significantly higher, thereby resulting in higher operating costs. 

Jacobs Engineering provided the Mill with a +/-30% cost estimate to install a Trona injection system. 

The capital cost estimate includes the following equipment: 

• 2 Trona silos (approximately 16' diameter and 40' high), 

• 3 Trona pulverizers, particle size classifiers, feeders and blowers, and 

• Trona pneumatic truck unloading station with a baghouse for PM control. 

Table B-8 presents a summary of installation the installed costs for the In-Duct Absorption System.
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-26 

 

 

21 See Appendix for further description of estimator’s cost categories 

22 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 

23 Modifications to the exhaust system are expected to require studies and upgrades to eliminate air infiltration. 

Table B-8. Summary of Capital Cost for Installation of In-Duct Absorption 

System, Boiler No. 6 Green Bay Broadway Mill 

Description21 Total Cost (2007$)22

Direct Costs 

Major Equipment $5,400,000 

Demolition $250,000 

Site Improvements $135,000 

Piling, Caissons $250,000 

Buildings $120,000 

Concrete $121,500 

Structural Steel $486,000 

Piping $459,000 

Insulation - Pipe, Equipment & Ductwork $243,000 

Instrumentation $135,000 

Electrical $297,000 

Painting, Protective Coatings $27,000 

Construction Indirect Costs 

Construction Support Labor $164,232 

Premium Time $47,350 

Craft Per Diem ($7/Hour On 100 % Of Time) $104,126 

Non-Payroll Tax, Insurance & Permits $223,644 

Craft Start-Up Assistance $43,650 

Contractor's Construction Fee $323,046 

Project Indirect Costs 

Construction Management $322,000 

Engineering Professional Services $715,000 

Outside Consultant Services $100,000 

Owner's Cost $378,000 

Spare Parts $279,450 

Non-Craft Start-Up Assistance $119,150 

Allowance For Unforeseen $1,074,315 

Escalation $603,026 

Air Infiltration Allowance23 $100,000 

Total Installed Cost (+/- 30%) (TIC) $12,520,489 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-27 

The total installed cost (TIC) is $12,520,489. Table B-9 presents the annual operating costs for the In-Duct 

Absorption System. 

Table B-9. Annual Operating Cost Calculations, In-Duct Absorption System for Boiler No. 6, Actual 

2002-2004 Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hr/shift x 1,025 shifts/yr @ $40/hr 41,000 

Supervisor Labor 15% of Operator 6,150 

Maintenance labor: 0.5 hrs per day x 350 days/yr @ $40/hr 7,000 

Maintenance material 100% of Maintenance Labor 7,000 

 

Electricity 0.059$/kWhr x 2,534,375 kWhr 149,528 

Trona consumption $150/ton Trona x 1.8 tons Trona/hr 24 x 8,400 hr/yr 2,268,000 

Landfill Additional Baghouse solids $ 9.50/ton x 1.5 tons solids/hr x 8,400 hrs/yr 119,700 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 36,690 

Taxes, insurance, admin. factor: 4% of TIC (Table B-8) 500,820 

Capital recovery factor (system): 0.0944 x TIC (Table B-8) 1,181,846 

 

Total Annual Cost 4,317,733 

 

24 Reagent usage of 3600 lbs/hr estimated by vendor 

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent 

required. The 2002-2004 actual emissions are significantly lower than permitted emissions and thus 

represent a conservatively lower annualized cost (and operation) estimate. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of SO2

Removed. 

The estimated cost effectiveness is: $4,317,733/ (50% x 2,160 tons) = 3,998 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-28 

Clean Fuels Cost Evaluation 

As mentioned above, Boiler No. 6 combusts several fuels with the existing equipment: eastern coal (high / 

low fusion), western coal and petroleum coke. The only fuel limited by the air permit is the amount of

petroleum coke to approximately 17-21% by weight of total fuel. All solid fuels are stored outdoors in a 

common area. Table B-10 presents the range of heat content, as well as ash and sulfur content of the 

various fuels combusted in the boiler. 

Determining marginal costs of fuel with different sulfur concentrations is reasonably certain when using 

short-term “future” forecasts. As the period for fuel forecasting is extended, uncertainty rapidly increases. 

Therefore, the unit costs below are presented as a range where estimated. Subsequent calculations use the 

average of the high and low end of the range. 

Table B-10. Comparison of Various Fuels Fired in Boiler No. 6, Green Bay Broadway Mill 

Fuel Sulfur % MMBtu/ton $/MMBtu 

2007-2009 25

Petroleum Coke 5 to 6.5 27.6-28.4 1.71 

Eastern Low-fusion Coal 2.5-2.7 25.4-27.0 3.35 

Western Coal 0.4-0.7 20.6-23.6 4.55 

Eastern High-fusion Coal 0.9 – 1.5 24-25.5 3.60 

 

25 Prices reflect cost from source delivered to the Mill between 2007 and 2009. Year-to-year prices are volatile. 

An additional difference between the fuels is the estimated CO2 emissions. CO2 Emissions from petroleum 

coke combustion is approximately 10 to 15% above coal combustion (on a lb/MMBtu basis). 

The cost evaluation compared the following three options with increasing emission reduction: 

1. Switch 100% of petroleum coke to eastern high fusion coal 

2. Switch 100% of petroleum coke to western coal 

3. Switch 100% of all fuel to western coal 

Table B-11 presents a summary of the sulfur dioxide emission estimates and fuel costs for each case. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-29 

Table B-11. Clean Fuel SO2 Emission Calculations, Boiler No. 6, Green Bay Broadway Mill 

 

Eastern Coal 

 Parameter High 

Fusion 

Low 

Fusion 

Western 

Coal 

Petroleum 

Coke 

Total 

2002-2004 MMBtu Estimate (annual) 528,545 120,345 796,970 346957 1,792,817 

2002-2004 Tons (annual) 21,355 4,593 36,062 12391 74,402 

Sulfur into the Boiler (tpy) 213 109.6 184 694 1200 

Percent of total SO2Emissions 18% 9% 15% 58% 

SO2 Emission Estimate (tpy) 383 197 331 1249 2160 

Fuel Cost (MM$) 1.903 0.40 3.63 0.59 6.53 

 

Case 1 : Switch from Petroleum Coke to Eastern High Fusion 

MMBtu 875,502 120,345 796,970 -- 1,792,817 

Tons Fuel 35,374 4,593 36,062 -- 76,029 

Sulfur into the Boiler (tpy) 352 109.6 184 -- 

SO2 Emission Estimate (tpy) 704 219 368 -- 1291 

Fuel Cost (MM$) 3.15 0.40 3.63 -- 7.18 

 

Case 2 : Switch from Petroleum Coke to Western 

Coal 

MMBtu 528,545 120,345 1143928 -- 1,792,817 

Tons Fuel 20,251 4,593 51761 -- 76,606 

Sulfur into the Boiler (tpy) 251 110 264 -- 

SO2 Emission Estimate (tpy) 502 219 528 -- 1,249 

Fuel Cost (MM$) 1.90 0.40 5.20 -- 7.51 

 

Case 3 Switch All Fuels to Western Coal 

MMBtu Fuel -- -- 1,792,817 -- 1,792,817 

Tons Fuel -- -- 81,123 -- 81,123 

Sulfur into the Boiler (tpy) -- -- 414 -- 

SO2 Emission Estimate (tpy) -- -- 827 -- 827 

Fuel Cost (MM$) -- -- 8.16 0 8.16 

 

Table B-12 summarizes the annual marginal fuel costs and emissions reductions relative to 2002-2004 

actual emissions for these cases. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-30 

Table B-12. Summary of Fuel Cost Increases for Various Fuel Switch Cases, Green Bay 

Broadway Mill 

Case 

Parameter 2002-2004 1 2 3 

 

Average $/MMBtu $3.64 $4.01 $4.19 $4.55 

SO2 Emissions (tpy) 2,160 1291 1249 827 

Emission Change (tpy) NA 869 911 1,333 

Reduction Efficiency (%) 40% 42% 62% 

Fuel Cost ($/yr) $6,525,429 $7,181,178 $7,510,787 $8,157,319 

Fuel Cost Increase ($/yr) NA $655,749 $985,359 $1,631,891 

Cost Effectiveness Fuel Price Only ($/ton) NA 755 1,082 1,225 

 

Though Boiler No. 6 is equipped to handle the various fuel selections of the three cases above, the actual 

operating costs for ash hauling and disposal will increase. Petroleum coke ash content is near 0.5% 

compared to 12 % for western coal. Based on using the Mill’s current unit cost for ash disposal of $9.50 per 

ton, additional operating costs of approximately 0.03 to 0.05 $/MMBtu will be incurred, or, an increase of 

approximately $90,00 per year. 

Summary of Economic Evaluation, SO2 Controls for Power Boiler No. 6

The economic evaluation determined a range of cost effectiveness values for the following levels of control: 

Less than 50%, 50%, 62%, and 90%. Figure B-5 presents a marginal cost curve for the cost estimates 

presented in Table B-2 through B-12. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-31 

Figure B-5 Marginal Cost Curve for SO2 Control Options, Green Bay Broadway Mill Boiler No. 6 

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions 

Control options: 42% removal by Clean Fuels (case 2); 50% removal by FSI or in-duct sorbent injection; 

62% removal by Clean Fuels (case 3); 90% removal by wet or dry scrubber 

Incremental Costs 

In addition to marginal cost effectiveness, the incremental cost effectiveness can be used to compare the 

additional cost for a higher level of control. USEPA guidance indicates that “the incremental cost 

effectiveness should be examined in combination with the average cost effectiveness in order to justify 

elimination of a control option.”26 The incremental cost effectiveness formula is as follows: 

(Annual Costs ($/yr)| Control Option – Annual Cost ($/yr)| Next Control Option) / Change in Controlled Emissions 

(tpy) 

 

26 New Source Review Workshop Manual Draft (USEPA, 1980) 

0

1000

2000

3000

4000

5000

6000

500 1000 1500 2000 2500

Actual Tons Removed Per Year (tpy)

Cost Effectiveness ($/ton)

Low Cost

High Cost

90%

62%

50%

40-42%
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-32 

Figure B-5 graphically shows a large increment in cost effectiveness is between the 62% control option

(clean fuels) and the 90% control option (scrubber). The incremental cost effectiveness between the two 

options is: 

($8,031,143/yr for scrubbers (average of either wet or dry) – $1,631,891/yr for Clean Fuels) / ((1-62% x 

2,160 tons) – (1-90% x 2160 tons)) 

= $6,399,253 additional annual cost/ 605 additional tons SO2 removed 

= $10,581 /ton for additional reductions in SO2 emissions beyond the clean fuel option. 

Energy and Environmental Impacts

Throughout the economic analysis, the cost estimates documented, where possible, the actual costs for 

additional energy consumption, additional water demand, and addition solid waste generated. Also in each 

technology discussion, the analysis discussed environmental impacts. Table B-13 summarized a 

comparison of energy and environmental impacts for each option. 

Table B-13. Summary of Additional Impacts for SO2 Control Technologies, Boiler No. 6 

 

Technology 

Impacts Scrubber FSI/ Induct Injection Clean Fuels 

Additional Energy (kWhr/yr) up to 11,160,688 3,437,500 None 

Additional Water (million gal) up to 976 None None 

Additional Solid Waste (tons) 29,601 10,978 up to 7,900 

Environmental Impacts Treatment of metals 

in waste stream 

Higher PM10 Loading 

to Baghouse 

Higher PM10 Loading 

to Baghouse 

Other Impacts Wet Plume Additional CO2 from 

Trona decomposition; 

FSI may reduce NOx 

Less CO2 emissions 

SO2 Engineering Analysis Summary

Through a detailed comparison of many site specific issues and costs, the Mill believes a 62% level of

control of SO2 is economically feasible for Boiler No. 6. The incremental cost effectiveness for options 

greater than 62% control (i.e., a scrubber) is greater than $10,000/ton and is economically infeasible. 

The expected annual cost to meet an SO2 removal efficiency of 62%, compared to the baseline period of 

2002 through 2004, is $1.63 million per year. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-33 

2.5 NITROGEN OXIDES 

Step 1a-Identification of Control Technologies-Typical Technologies in Use in the United States 

The following sections discuss the technologies typically available for multi-fuel stoker-fired boilers 

including reduction of nitrogen content in fuels with the use of clean fuels, chemical selective 

catalytic/noncatalytic reduction, combustion air improvements, reducing the residence time at peak 

combustion operating temperature, and reducing the peak combustion temperature inside of the boiler. 

Removal of Nitrogen 

Ultra-Low Nitrogen Fuel –The range of fuels typically combusted in stoker-fired boilers can range from 

wood/bark to coal and pet-coke. The combustion of fuel with lower nitrogen content may result in 

slightly lower emissions of NOx. However, this relationship is not well understood 27. The variety of 

solid fuels normally combusted in Boiler No. 6 (i.e., petroleum coke and coal) are comparable in 

nitrogen content. A fuel substitution from conventional fuels to wood or bark would introduce lower 

levels of nitrogen, but a much higher moisture content. The high moisture content of bark results in 

lower combustion temperatures than that of petroleum coke or coal that may result in less thermal NOx

formation. However, fuel substitution using wood would result in a loss of heat from nearly 24 

MMBtu/ton for coal to less than 10 MMBtu/ton for wood. Substituting wood for coal and/or pet coke 

would derate the boiler to less than 50% of its design capacity. Additionally, the boiler is not designed 

to accommodate bark as the lower heat release rate does not match the design of other boiler internal 

elements (e.g., tube sections, economizer). Though lower in fuel nitrogen, the use of wood in the boiler 

would require an evaluation of the existing baghouse and may require additional equipment to continue 

to meet the current PM emission limits. 

Chemical Reduction of NOx

Selective Catalytic Reduction – Selective Catalytic Reduction (SCR) uses a catalyst to react with 

injected ammonia to chemically reduce NOx to elemental nitrogen, carbon dioxide and water vapor. The 

catalyst has a finite life in the flue gas, and some ammonia slips through the boiler without reacting. 

SCR has historically used precious metal catalysts, which are quite expensive, but can now also use less 

costly base metal and zeolite catalyst materials. Important considerations in the design, operation and 

maintenance of an SCR application include physical access, flue gas temperature, flue gas velocity, 

sulfur content, and particulate matter loading. If a conventional catalyst system is used, the SCR reactor 

must be located at a point where the flue gas temperature is no greater than 780 degrees Fahrenheit (oF) 

 

27 Fortune, D. "Influence of nitrogen content of coal on NOx emissions from pulverised fuel systems", Internal Shell Coal 

Report No. LMD03068. 
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Best Available Retrofit Technology Analysis 

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and no lower than approximately 570oF. Other options are available for using catalysts - higher 

temperature and lower temperature – but both of these options are more expensive. 

If the SCR reactor can be located in a position where the flue gas temperature ranges between 570 to 

780oF (nominal), then no preheating of the flue gas is required. There are high-temperature (>800oF) 

and low-temperature (250 to 650oF) catalysts, however, the high-temperature catalysts are more 

effective at NOx removal and can accommodate a broader range of fuel characteristics, higher sulfur 

levels in the fuel, and trace metals in the flue gas. However, the selection of a high temperature catalyst 

usually means reheating the flue gas which is rarely a cost-effective approach since a large quantity of 

fuel must be used to heat the flue gas stream to the proper temperature for the catalyst to work 

effectively. 

Another important consideration is the flue gas velocity through the SCR catalyst bed. For most 

applications, the flue gas velocity exiting the boiler is too high to provide sufficient residence time for 

the catalyst to provide the level of reaction required to reduce NOx emissions. For this reason, the 

exhaust ductwork must be expanded to allow for a reduction in the flue gas velocity dictated by the 

catalyst vendor, which will be approximately 20 feet per second (ft/s) depending on the fuel. 

Another key consideration is the additional pressure drop across the SCR reactor bed. The pressure 

drop due to the use of a catalyst bed is approximately 1 to 1.5 inches water (H2O), but there will be 

additional pressure drop due to the expanded ductwork and the addition of a static mixing device to 

maintain a uniform flow across the catalyst bed. 

The SCR catalyst design, and therefore life expectancy, is based on the particulate matter loading and

sulfur content of the flue gas stream. The catalyst design takes into account the particulate matter 

loading and the expected contaminants in the flue gas – more difficult fuels are typically handled using 

a larger pitch (e.g., pore size) which translates into an increase in treatment length and additional 

pressure drop. GP did receive one quotation for a “tail-end” SCR installation behind the current 

baghouse. Application of SCR is technically feasible in a “back-end” system approach with a typical 

removal efficiency of 70% to 80% for a retrofit installation. 

Selective Non-Catalytic Reduction – In a SNCR system, ammonia or urea is injected in the combustion 

chamber of a boiler or in ductwork in a region where the temperature ranges between 1,600 and 

2,000oF. This technology is based on high temperature ionization of the ammonia or urea instead of 

using a catalyst. The temperature window for SNCR is very important because if the temperature is too

low, there may be more ammonia slip through the system or, if the temperature is too high, more NOx is 
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generated than is being chemically reduced. SNCR has been demonstrated as a feasible technology for 

stoker-fired boilers and can achieve variable reductions of 25 to 50 percent. Site-specific assessments 

are required by SNCR vendors for each application. 

Based on the above discussion, SNCR is considered to be technically feasible for Boiler No. 6. 

Reducing Residence Time at Peak Operating Temperature 

Air Staging of Combustion – An overfire air (OFA) system modifies the combustion air system through 

the installation of air ports and potentially new fans. Air ports are designed to inject air at the proper 

velocity to complete combustion prior to the furnace exit. Combustion air inside of a boiler is divided 

into two streams. The first stream is mixed with fuel in a ratio that produces a flame in an oxygendeprived zone. The second stream is injected downstream of the flame and creates an oxygen-rich zone 

where combustion is completed. OFA modifications lower the flame temperature, reducing thermal 

NOx and reducing the amount of oxygen available in the flame zone for conversion of fuel nitrogen 

species to NOx, reducing fuel NOx. A sub-specialized application of this technology is rotating opposed 

fire air (ROFA) by Mobotec USA. The technology optimizes mixing with the use of air ports and fans. 

The OFA technology for this boiler is believed to reduce NOx by up to 15% while the ROFA technology 

may reduce NOx up to 66%. 

Steam Injection - Steam injection causes the stoichiometry of the mixture to be changed and dilutes the 

heat generated by the combustion process. These actions cause the combustion temperature to be lower,

and in turn reduces the amount of thermal NOx formed. However, air staging accomplishes a very 

similar result. 

Each of the techniques described above to reduce residence time at peak temperature are considered 

technically feasible. 

Reducing Peak Temperature 

Flue Gas Recirculation (FGR) – Recirculation of flue gas for use as combustion air reduces the 

combustion temperature by diluting the oxygen content of the combustion air and causing heat 

generated by combustion to be diluted in a greater mass of flue gas. For Boiler No. 6, FGR involves 

taking flue gas from the outlet of the economizer and injecting it in a number of locations in the stokerfired boiler. The recirculated flue gas would be mixed with the under-grate combustion air to replace 

some of the air used to maintain grate velocities and to reduce the flame temperature on the grate. The 

recirculated flue gas will also be used to reduce excess oxygen in the combustion process in general to 
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minimize overall NOx formation. Injection of the recirculated flue gas will require additional boilerspecific evaluation. This reduction of temperature lowers the thermal NOx generated but can adversely 

increase CO emissions. A NOx reduction of 15 percent is estimated with a flue gas recirculation (FGR) 

system. 

Reburn – In a boiler outfitted with reburn technology, a set of natural gas burners is installed above the 

primary combustion zone. Natural gas is injected to form a fuel-rich, oxygen-deficient combustion zone 

above the main firing zone. NOx emissions created by the combustion process in the main portion of 

the boiler drift upward into the reburn zone and are converted to elemental nitrogen by combustion of 

the natural gas. The technology requires no catalysts, chemical reagents, or changes to any existing 

burners. Typical reburn systems also incorporate redesign of the combustion air system along with the

water-cooled, pinhole grate to provide less excess air (LEA). Natural gas reburn is a feasible 

technology for stoker-fired boilers. However, the reduction efficiency is generally less than 15%. 

Low-NOx Burners (LNB) – A LNB system provides a stable flame that has several different zones. For 

example, the first zone can be primary combustion. The second zone can be fuel reburning (FR) with 

fuel added to chemically reduce NOx. The third zone can be the final combustion in low excess air to 

limit the combustion temperature. LNB is not an option for stoker-fired systems where solid fuel is 

injected into the furnace above a traveling grate. In a stoker-fired traveling grate system, lighter

particles burn in suspension and fuel not combusting in suspension falls to the grate where the 

combustion process is completed. Low-NOx burners can only be used for supplemental gas or liquid 

fuels. 

Step 1b-Identification of Control Technologies-Review of RACT/BACT/LAER Clearinghouse 

(RBLC) 

Searches of the RBLC were conducted to identify control technologies for the control of emissions from

stoker-fired boilers. The specific category searched was 

• External Combustion- -11 

GP reviewed previous BACT NOx determinations for utility and non-utility coal-fired boilers. The 

RBLC database contains over 30 utility boiler NOx determinations, and several non-utility boilers NOx

determinations, two of which are based on new circulating-fluidizied bed designs. The following table

summarizes the technologies and emission limits from the RBLC database and recent permit rates for 

industrial coal and coal/combination fuel boilers: 
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Summary of RBLC and Recent NOx Emission Limits for Various Coal Boilers 

 NOx 

Emissions 

Source Technology (lb/MMBtu) 

Utility Boilers SCR/SCR+LNB 0.07 - 0.09 

Utility Boilers LNB+SNCR 0.1 

Utility Boilers SNCR 0.08 - 0.15 

 

Industrial Boilers 

Circulating Fluid Bed SNCR 0.08 

Stoker/Other None Economically Feasible 0.246 - 0.7

 

Recent Permits with Add On Technologies 

Temple Inland -Rome, GA LNB 0.5 

Smurfit-Stone (Maritime) Jacksonville, FL SNCR 0.5 

 

Step 1c-Identification of Control Technologies-Review of Technologies in Use at Georgia-Pacific 

Corporation Facilities 

For several coal boilers at various facilities, GP uses a variety of NOx reduction measures, including 

overfire air, FGR, and combustion controls. GP uses ammonia injection for NOx control for one 

combination fuel fluidized bed boiler and one de-inked wastewater sludge-fired boiler. 

Step 2-Technical Feasibility Analysis-Eliminate Technically Infeasible Options 

All of the options identified above are technically feasible except for two options: 

First, fuel substitution cannot be accommodated by the boiler due to its design and fuel properties. 

Secondly, as this boiler does not employ burners, the use of Low NOx burners is not feasible. 

After eliminating the technically infeasible options, GP added a combination of SNCR and FGR or OFA 

as a control system to include in the evaluation. 

Step 3 – Ranking the Technically Feasible Alternatives to Establish a Control Hierarchy 

The ranking for NOx control is: 

1. Tail-end SCR at 80% removal efficiency 

2. ROFA and Rotamix at 66% removal efficiency 

3. SNCR with FGR and OFA at 56% removal efficiency 

4. SNCR alone at 25% removal efficiency (site-specific vendor estimate) 

5. OFA or FGR alone at 15% to 20% removal efficiency 
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Step 4- Effectiveness Evaluation 

Economic Effectiveness 

For each cost estimate, the Green Bay Broadway Mill provided several general assumptions to equipment 

vendors and engineering contractors to determine site-specific cost estimates with a target accuracy of +/- 

30% or better. The Title V Permit for the site limits the firing of petroleum coke to a rate demonstrated 

during a compliance stack test. As a result of these tests, the current fuel mix is limited to approximately 

17% by weight of petroleum coke and 83% coal, based on the heat content of the fuels currently combusted 

in Boiler No. 6. 

SCR Cost Evaluation 

The NOx removal technology with the highest removal efficiency studied is SCR. SCR technology is a post 

process NOx control option used to remove NOx after the combustion process rather than limit NOx

development at the source. In this case, a reactor filled with an application-specific catalyst is placed in the 

boiler outlet flue gas stream. The catalyst in these reactions is only effective in a narrow elevated

temperature range. In this case, the flue gas needs to be between 600oF and 650oF in order to maximize the 

effectiveness of the catalyst without causing thermal damage. Two (2) SCR reactor installation locations 

that allow for the appropriate flue gas temperature were evaluated. The first option would be to modify the 

boiler’s flue gas outlet path to accommodate placement of the SCR reactor prior to the boiler’s existing air 

preheater. The second available reactor installation location is downstream of the existing baghouse.

Locating the SCR reactor between the boiler flue gas outlet and the existing air preheater provides the 

necessary flue gas temperatures; however, it also presents several key obstacles. These obstacles include 

high flue gas velocities, reduced residence time for the flue gas to pass through the catalyst bed, damage to 

the catalyst, and blinding of catalyst pores due to high particulate loading. Because of these factors as well 

as constructability issues, the Slip Stream SCR was estimated as a tail-end unit. Figure B-6 presents a 

general arrangement. 

In this estimate, one of the existing Standard Havens Baghouse chambers would be disconnected from the

existing Stack 10 and instead sent across a plant road to the old Building 66 area where a new Slip Stream 

SCR reactor would be located. The reactor would contain two layers of catalyst. Duct burners would be 

installed in the top inlet of the SCR reactor to reheat the flue gas to 625oF in order to allow the catalyst to be 

as effective as possible. An ammonia injection grid would be installed between the duct burners and the top 

row of catalyst and be used to inject atomized ammonia across the entire plan area of the Slip Stream SCR 

reactor. A new aqueous ammonia system include a tank and a heated building for pumps and air blowers. 
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Figure B-6. General Arrangement of SCR Slip-Stream System, Green Bay Broadway Mill 
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The SCR Slip-Stream System reactor outlet would feed to a new free-standing 14’-0” diameter, 199’ tall 

carbon steel insulated stack. Stack 10 would continue to serve one chamber of the Standard Havens 

baghouse. Table B-14 presents the cost estimate for a SCR for Boiler No. 6. 

Table B-14. Summary of Capital Cost for Installation of SCR Slip-Stream System, Boiler No. 6 

Green Bay Broadway Mill 

Description 2009 Costs ($) 

Direct Costs 

Major Equipment 6,125,967 

Demolition 17,776 

Site Improvements 459,447 

Piling, Caissons 643,227 

Buildings 21,494 

Concrete 825,819 

Structural Steel 1,684,872 

Piping 1,704,620 

Insulation - Pipe, Equipment & Ductwork 1,612,124 

Instrumentation 689,171 

Electrical 720,352 

Painting, Protective Coatings 91,890 

Construction Indirect Costs 

Construction Support Labor 697,539 

Premium Time 208,332 

Craft Per Diem 426,485 

Non-Payroll Tax, Insurance & Permits 579,468 

Craft Start-Up Assistance 43,650 

Contractor's Construction Fee 1,345,967 

Project Indirect Costs 

Construction Management 1,299,178 

Engineering Professional Services 4,330,343 

Study Cost 50,000 

Outside Consultant Services 100,000 

Owner's Cost 817,255 

Spare Parts 217,099 

Non-Craft Start-Up Assistance 71,139 

Allowance For Unforeseen 2,467,524 

Escalation 1,621,194 

Air Infiltration Allowance 100,000 

Total Installed Cost (+/- 30%) (TIC) 28,971,933 
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Table B-15 presents the annual operating costs for the SCR system. 

Table B-15. Annual Operating Cost Calculations, SCR for Boiler No. 6, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 2 hours per shift x 1,025 shifts/yr @ $40/hr 82,000

Supervisor Labor 15% of Operator 12,300

Maintenance labor: 0.5 hours per day x 365 days/yr @ $40/hr 7,300

Maintenance material 100% of Maintenance Labor 7,300

 

Electricity 0.059$/kWhr x 3464778 kWhr 204,422

Ammonia consumption $160/ton aq NH3x 6619 tons aq NH3 /yr 1,059,040

Natural Gas-duct burners $10/MMBtu x 429,040 MMBtu/yr 4,290,400

Catalyst $750,000/ 3 years 250,000

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 65,340

Taxes, insurance, admin. factor: 4% of TIC (Table B-14) 1,158,877

Capital recovery factor (system): 0.0944 x TIC 28 (Table B-14) 2,734,746

 

Total Annual Cost 9,871,725

 

28 7% interest for the cost of capital and an equipment life of 20 years using Equation 2.8a of USEPA Cost Control Manual 

yields: (0.07*(1+0.07)^20)/((1+0.07)^20-1) = 0.0944

Determining annual operating costs is sensitive to the amount of NOx removed and ammonia required. The 

2002-2004 actual emissions are significantly lower than permitted emissions and thus represent a 

conservatively lower annual cost (and operation) estimate. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $9,871,725/ (80% x 428 tons) = 28,831 $/ton. 
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ROFA and Rotamix Cost Evaluation 

Section 2.4 presented the application of Mobotec’s ROFA and Rotamix costs within its FSI technology. 

The total installed cost for targeting NOx control only is estimated to be approximately $1.9MM lower 

by removing the limestone injection, handling, and storage equipment specifically needed for SO2

removal. Thus, the expected total installed cost is $25,000,000. Table B-16 presents the annual 

operating costs without the limestone use or landfilling charges. 

Table B-16. Annual Operating Cost Calculations, ROFA/ROTAMIX for Boiler No. 6, Actual 2002-

2004 Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per shift x 1,025 shifts/yr @ $40/hr 41,000 

Supervisor Labor 15% of Operator 6,150 

Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 

Maintenance material 100% of Maintenance Labor 7,000 

 

Electricity- direct 0.059$/kWhr x 3437500 kWhr 202,813 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 36,690 

Taxes, insurance, admin. factor: 4% of TIC 1,000,000 

Capital recovery factor (system): 0.0944 x TIC 29 2,359,823

 

Total Annual Cost 3,660,476 

 

29 7% interest for the cost of capital and an equipment life of 20 years using Equation 2.8a of USEPA Cost Control Manual 

yields: (0.07*(1+0.07)^20)/((1+0.07)^20-1) = 0.0944

Determining annual operating costs is only sensitive to the number of hours the air mixing system is 

operated. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $3,660,476/ (66% x 428 tons) = 12,958 $/ton. 
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SNCR Cost Evaluation

SNCR systems are most efficient in a single temperature window; therefore, in order to properly operate 

an SNCR system, a boiler study is required to map the gas temperatures at several locations during 

varying boiler operating points. A detailed SNCR study was not conducted for Boiler No. 6; however, 

the SNCR supplier requires such a study and the SNCR estimate includes a one-time cost of $50,000 to 

accomplish this task. 

This system would consist of a new urea storage tank equipped with skid-mounted metering, circulating 

and booster pumps within a diked containment area. The new tank will be electrically heat-traced and 

insulated. The existing Boiler No. 6 furnace front wall would be modified to accept the new spray 

nozzles, and distribution module skids would be placed near the spray nozzles of the two (2) levels. For 

Boiler No. 6, tilting injectors would be installed at a single level. A pump would be used to circulate a 

steady stream of concentrated urea to a metering skid. The metering skid would then pump the diluted 

urea solution up to the distribution modules located at the boiler’s injection nozzles. 

Other than the addition of a diked containment area and the need to modify the existing boiler walls, 

there are few installation complications to consider in this system. Extra steel is considered in the

factored installation cost to allow for reworking of platforms to accept control skids, and demolition

dollars are included in the factored estimate for removal of items that may be in the way of the new 

platforms. 

The only additional operational concern with a urea-based SNCR system is ammonia slip. Unreacted 

urea can degrade to nitrogen, carbon dioxide and ammonia in the boiler. This ammonia slip can be 

controlled with careful monitoring. Urea-based SNCR systems often operate at 1 ppm ammonia slip or 

less and are usually guaranteed at a 5 ppm ammonia slip rate. The most important factor in reducing 

ammonia carryover in these systems is proper distribution based on the boiler temperature gradient 

study. In this case, the preliminary data from the vendor indicates that ammonia slip is expected to be 2 

ppm at the exit of the existing baghouse and 5 ppm exiting the boiler. These values would be revised 

once a boiler-specific study is completed. 

Table B-17 presents the total installed cost estimate for an SNCR system alone. 
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Table B-17. Summary of Capital Cost for Installation of SNCR System, Boiler No. 6 

Green Bay Broadway Mill 

Description TOTAL COST 

(2007$) 

Direct Costs 

Major Equipment 1,531,501 

Demolition 34,459 

Site Improvements 76,575 

Piling, Caissons 107,205 

Buildings 270,000 

Concrete 68,918 

Structural Steel 275,670 

Piping 260,355 

Insulation - Pipe, Equipment & Ductwork 137,835 

Instrumentation 38,288 

Electrical 213,048 

Painting, Protective Coatings 15,315 

Construction Indirect Costs 

Construction Support Labor 125,805 

Premium Time 36,854 

Craft Per Diem ($7/Hour On 100 % Of Time) 79,763 

Non-Payroll Tax, Insurance & Permits 113,499 

Craft Start-Up Assistance 45,000 

Contractor's Construction Fee 223,604 

Project Indirect Costs 

Construction Management 268,000 

Engineering Professional Services 594,000 

Study Cost 50,000 

Outside Consultant Services 100,000 

Owner's Cost 179,000 

Spare Parts 67,188 

Non-Craft Start-Up Assistance 119,150 

Allowance For Unforeseen 498,103 

Escalation 350,665 

Air Infiltration Allowance 100,000 

Total Installed Cost (+/- 30%) (TIC) 5,979,799

Table B-18 presents the annual operating costs for the SNCR system.
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Table B-18. Annual Operating Cost Calculations, SNCR for Boiler No. 6, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per shift x 1,025 shifts/yr @ 

$40/hr 

41,000 

Supervisor Labor 15% of Operator 6,150 

Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 

Maintenance material 100% of Maintenance Labor 7,000 

 

Electricity 0.059$/kWhr x 821763 kWhr 48,484 

Urea Consumption $1.35/gal x 10 gph x 8400 hr/yr 113,400 

Mill Water $0.06/kgal x 7,884 kgal/yr 473

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 36,690 

Taxes, insurance, admin. factor: 4% of TIC (Table B-17) 239,192 

Capital recovery factor (system): 0.094 x TIC (Table B-17) 562,101 

 

Total Annual Cost 1,061,490 

Determining annual operating costs is sensitive to the amount of NOx removed and the amount of urea 

required. The 2002-2004 actual emissions are lower than permitted emissions and thus represent a 

conservatively lower annual cost (and operation) estimate. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $1,061,490/ (25% x 428 tons) = 9,920 $/ton. 
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FGR/OFA Cost Evaluation 

An additional NOx control case that was studied and estimated for Boiler No. 6 was Flue Gas Recirculation 

(FGR) and Overfire Air (OFA). Both of these technologies are expected to provide the same approximate

level of control and have similar costs. In FGR, flue gas would be taken from the outlet of the boiler’s 

economizer section and directed to several injection locations in the stoker-fired boiler using ductwork. The 

exact location for the injection points of recirculated flue gas would be determined by boiler modeling. The 

price for this model is included in the cost estimate. Three main locations proposed for injection of the flue 

gas are (1) at the coal feeder level, (2) through the nozzles under the fuel feeder, and (3) at the under-grate 

air system. Other potential injection sites such as the fly ash reinjection ports would be evaluated during the 

study. The injected flue gas under the grate would replace some of the air used for over-fire air to maintain 

grate velocities and reduce flame temperatures on the grate. Feeding recirculated flue gas to the coal feeders 

and to the nozzles under the coal feeders would control the high temperatures at the air/coal interface above 

the grate. Reducing excess oxygen and flame temperature at or above the grate would help prevent the 

formation of thermal and fuel bound NOx. 

The new FGR system would include an FGR fan located inside of the boiler house, ductwork from the 

economizer outlet to each point of injection, expansion joints, dampers and operators, flow indicators to 

major injection locations, boiler tube bends and injection wall boxes, and undergrate air mixing spargers. 

Money is included in the cost estimate for minor relocation and demolition to allow for installation of the 

FGR system ductwork. Table B-19 presents the total installed cost estimate for an FGR system alone. 

 
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Table B-19. Summary of Capital Cost for Installation of FGR System, Boiler No. 6 

Green Bay Broadway Mill

Description TOTAL COST (2007$) 

Direct Costs 

Major Equipment $1,256,014 

Demolition $43,454 

Piling, Caissons $87,921 

Buildings $270,000 

Concrete $41,448 

Structural Steel $91,061 

Insulation - Pipe, Equipment & Ductwork $192,418 

Instrumentation $17,270 

Electrical $45,216 

Construction Indirect Costs 

Construction Support Labor $85,575 

Premium Time $25,563 

Craft Per Diem $54,256 

Non-Payroll Tax, Insurance & Permits $68,363 

Craft Start-Up Assistance $10,400 

Contractor's Construction Fee $159,898 

Project Indirect Costs 

Construction Management $174,000 

Engineering Professional Services $387,000 

Study Cost $50,000 

Outside Consultant Services $50,000 

Owner's Cost $117,000 

Spare Parts $40,279 

Non-Craft Start-Up Assistance $57,288 

Allowance For Unforeseen $327,442 

Escalation $207,164 

 

Total Installed Cost (+/- 30%) (TIC) $3,859,031 

Table B-20 presents the annual operating costs for the FGR system. 
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Table B-20. Annual Operating Cost Calculations, FGR for Boiler No. 6, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per day x 350 days/yr @ $40/hr 14,000 

Supervisor Labor 15% of Operator costs 2,100 

Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 

Maintenance material 100% of Maintenance Labor costs 7,000 

 

Electricity 0.059$/kWhr x 927593 kWhr 54,728 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 18,060 

Taxes, insurance, admin. factor: 4% of TIC (Table B-19) 154,361 

Capital recovery factor (system): 0.094 x TIC (Table B-19) 362,749 

 

Total Annual Cost 619,998 

Determining annual operating costs for FGR is sensitive only to the number of hours the fan is used. The 

operating costs reflect a typical annual operation of 8,400 hours/year. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $619,998/ (20% x 428 tons) = 7,242 $/ton. 

SNCR with FGR and OFA Cost Evaluation 

In an attempt to design a more successful combustion modification technology with urea injection, the 

Mill developed a cost estimate for the combination of FGR, OFA and SNCR. This combination is 

different than the ROFA/ROTAMIX option though the addition of urea injection. Table B-21 tabulates 

the cost estimate for this combination of technologies. 
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Table B-21. Summary of Capital Cost for Installation of FGR/OFA/SNCR System, 

Boiler No. 6 Green Bay Broadway Mill 

Description TOTAL COST 

FGR FAN System (Table B-19) 3,859,031 

OFA System (estimated by a ratio of equipment)30 2,371,174 

SNCR System (Table B-17) 5,979,799 

Total Installed Cost (+/- 30%) (TIC) 12,210,004 

 

30 OFA System Installation Cost = FGR Fan Installation x OFA Equipment Cost / FGR Equipment Cost; 

$3,859,031 x $757,000 / $1,232,000 = $2,371,174

Table B-22 presents the annual operating costs. 

Table B-22. Annual Operating Cost Calculations, FGR+OFA+SNCR for Boiler No. 

6, Actual 2002-2004 Conditions

Parameter Annual Cost ($) 

Direct Costs FGR OFA SNCR Total 

Operating labor : 14000 0 41000 

Supervisor Labor 2100 0 6150 

Maintenance labor: 7000 7000 7000 

Maintenance material 7000 7000 7000 

 

Electricity 54728 54728 48484 

Urea and Water 0 0 113873 

Indirect Costs 

 

Overhead rate (fractional): 18060 8400 36690 

Taxes, insurance, admin. factor: 154361 94847 239192 

Capital recovery factor (system): 364749 223839 562101 

 

Total Annual Cost 619998 395814 1061490 $ 2,077,302 

Determining annual operating costs for the combination is sensitive to the number of hours the fan is used as 

well as the urea consumption requirement. The cost effectiveness of this technology is equal to the Total 

Annualized Costs/ Annual Quantity of NOx Removed. 

The estimated cost effectiveness is: $2,077,302/ (56% x 428 tons) = 8,666 $/ton. 
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Summary of Economic Evaluation, NOx Controls for Power Boiler No. 6

The economic evaluation determined a range of cost effectiveness values for the following levels of control: 

20%, 25%, 56%, 66%, and 80%. Figure B-7 presents a marginal cost curve for all the cost estimates 

presented in Table B-14 through B-22. 

Figure B-7 Marginal Cost Curve for NOx Control Options, Green Bay Broadway Mill Boiler No.6 

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions 

Control options: 20% removal by FGR or OFA; 25% removal by SNCR alone; 56% removal by a 

combination of FGR/OFA and SNCR; 80% removal by SCR

Energy and Environmental Impacts

Throughout the economic analysis, the cost estimates documented, where possible, the actual costs for 

additional energy consumption, additional water demand, and addition solid waste generated. Also in each 

technology discussion, the analysis discussed environmental impacts. Table B-23 summarizes a comparison 

of energy and environmental impacts for each option. 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 100 200 300 400

Actual Annual Tons Removed Per Year (tpy)

Cost Effectiveness ($/ton)

Average $/ton

 

80%

66%

56% 25%

20%
GP Consumer Products Green Bay Mill 

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Table B-23. Summary of Additional Impacts for NOx Control Technologies, Boiler No. 6 

Technology 

Impacts SNCR Options Combustion Modifications SCR 

Additional Energy (kWhr/yr) 2,676,949 1,855,186 3,464,778 

Additional Water (million gal/yr) 7.884 0 0 

Additional Natural Gas (MMcf/yr) 0 0 429.04 

Environmental Impacts NH3 Emissions None NH3 Emissions 

Other Impacts NH3 Handling None NH3 Handling 

NOx Engineering Analysis Summary

Through a detailed comparison of many site specific issues and costs, the Mill believes no additional 

controls meets the BART requirement for Boiler No. 6. While technologies do exist for stoker-fired 

boilers to reduce NOx, the site-specific cost estimates indicate the retrofit nature of the installations 

proves to be economically infeasible. The cost effectiveness for the lowest cost option (OFA/FGR) is 

$7,242/ton removed for a reduction of 86 tons per year.

2.6 SUMMARY OF ENGINEERING ANALYSES FOR BOILER NO. 6 

Using a “top-down” procedure, the engineering analysis determined that 62% SO2 reduction technology 

is technically and economically feasible for Boiler No. 6. The analysis determined that no additional

controls are feasible for PM10 and NOx. Boiler No. 6 will continue to use the existing baghouse to 

remove PM. 
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3.0 BART ENGINEERING ANALYSIS FOR POWER BOILER NO.7

3.1 SOURCE DESCRIPTION 

Boiler No. 7 is a two (2) drum cyclone-type boiler manufactured by Babcock and Wilcox and installed 

in 1969. The boiler has a heat input rating of 615 MM Btu/hr with a maximum continuous rated (MCR) 

steam flow of 500,000 lbs/hr and an ultimate maximum steam flow of 550,000 lb/hr for a one (1) - hour

period over 24 hours of operation. The boiler’s steam superheater outlet condition is 850 psig at 890 oF. 

Boiler No. 7 is permitted to burn coal, petroleum coke, natural gas, and No. 2 fuel oil. Natural gas is 

normally used for startup and maintaining stability. Boiler No. 7 typically operates in a swing-loaded 

mode and fires low fusion eastern coal with up to 25% petroleum coke. The Boiler’s exhaust gases are 

discharged into a common duct connected with the flue gas discharge streams from several other boilers

at the mill. The common duct is equipped with a baghouse to remove particulate matter emissions from 

the exhaust gases. Figure B-8 presents a side-view drawing of Boiler No. 7. 

3.2 BASELINE EMISSIONS 

The following table presents the actual fuels fired, sulfur content of each fuel combusted, and the 

BART-regulated emissions generated from Boiler No. 7 during the baseline period of 2002 through 

2004. 

Table B-24. Summary of Baseline Solid Fuels and Emissions, Boiler No. 7 

Parameter 2002 2003 2004 3-yr Average 

Total MMBtu All Solid Fuels 4550267 4298870 4251026 4366721 

Tons Low Fusion Coal 132187 126175 131213 129858 

%S Low Fusion Coal 2.33 2.37 2.43 2.38 

Tons Pet Coke 32961 29212 30262 30812 

%S Pet Coke 5.89 5.38 5.49 5.59 

Annual Average SO2 (lb/MMBtu) 3.87 4.10 4.01 3.99 

Actual SO2 Emissions (tpy) 8807 8810 8527 8715 

Actual NOx Emissions (tpy) 2812 2673 2735 2740 

Actual PM10 Emissions (tpy) 199 187 112 166 

 
GP Consumer Products Green Bay Mill 

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Figure B-8. Side View of Boiler No. 7, Green Bay Broadway Mill 
GP Consumer Products Green Bay Mill 

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March 2009 

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3.3 PARTICULATE MATTER

Step 1a-Identification of Control Technologies-Typical Technologies in Use in the United States 

Technology that may be considered for the control of particulate matter emissions from boilers includes 

the substitution and use of clean fuels, mechanical/gravity separation devices (e.g., cyclones, settling 

chambers), electrostatic precipitators (ESPs), baghouses, and high efficiency wet scrubbers. 

Step 1b-Identification of Control Technologies-Review of RACT/BACT/LAER Clearinghouse 

(RBLC) 

Searches of the RBLC were conducted to identify control technologies for the control of PM10 emissions 

from cyclone boilers. The specific category searched was External Combustion- -11 

The clearinghouse listed multiclones with ESPs, baghouses, good combustion practices, and wet 

scrubbers as the PM10 control technologies. 

Step 1c-Identification of Control Technologies-Review of Technologies in Use at Georgia-Pacific 

Corporation Facilities 

GP operates numerous combination fuel-fired boilers and coal-fired boilers at its operating facilities within 

the United States. PM10 control devices in use at these mills include ESPs, baghouses and wet scrubbers. 

Step 2-Technical Feasibility Analysis-Eliminate Technically Infeasible Options 

All of the control options identified in Step 1 are technically feasible. 

Step 3 – Ranking the Technically Feasible Alternatives to Establish a Control Hierarchy 

The ranking of technologies for PM10 control is: 

1. Baghouse with greater than 99% removal efficiency 

2. ESP with multiclones at greater than 99% removal efficiency 

3. High efficiency scrubbers with 98%+ removal efficiency 

4. Wet scrubbers with 50 to 95% removal efficiency 

5. High efficiency cyclones with 50-90% removal efficiency 

Step 4- Effectiveness Evaluation 

GP currently operates a high efficiency (above 99%) baghouse to control PM10 emissions generated by 

Boiler Nos. 5, 6, 7, and 8. The baghouse design inlet particulate loading ranges from 1 to 3.5 gr/acf, 

while the outlet loading is consistently at or below 0.01 gr/acf. The baghouse design exhaust gas 

flowrate is 772,000 acf/minute (ACFM) at 365 °F. The baghouse meets the existing State limit of 0.3 lb 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

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B-55 

PM10/MM Btu from NR415.06(1)(b), (equivalent to 184.5 lb/hr at Boiler No. 7’s maximum rated 

capacity), is much greater than the baseline annual emissions rate of approximately 40 lbs/hr 31(equal to 

0.08 lb/MM Btu) from Boiler No. 7. As the Mill presently operates the highest ranked PM10 control 

technology, no additional cost effectiveness evaluation is necessary. 

Step 5-Select BART 

GP is proposing to continue the use of the highest level of control, a baghouse with the current emission 

limit of 0.3 lb PM10/MM Btu. 

 

31 [199 tons (2002) + 187 tons (2003) + 112 tons (2004)] x 2000 lbs/ton / 25,104 hours = 40 lbs/hr. 

[(199 tons (2002) + 187 tons (2003) + 112 tons (2004))*2000 lb/ton] / 13,100,163 MMBTU total = 0.08 

lb/MMBtu including both filterable and condensible. 
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Best Available Retrofit Technology Analysis 

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B-56 

3.4 SULFUR DIOXIDE 

Step 1a-Identification of Control Technologies-Typical Technologies in Use in the United States 

Emission control equipment that may be considered to control sulfur dioxide emissions from coal-fired 

boilers includes gas absorption using wet and dry scrubbers, and flue gas desulfurization techniques 

such as sorbent injection. The use of clean substitute fuels can also be considered as an alternative to 

add-on controls. 

Step 1b-Identification of Control Technologies-Review of RACT/BACT/LAER Clearinghouse 

(RBLC) 

Searches of the RBLC were conducted to identify control technologies for the control of SO2 emissions 

from cyclone boilers. The specific category searched was “External Combustion- -11”. The 

clearinghouse listed the use of clean fuels, wet and dry scrubbers, and flue gas desulfurization 

techniques such as limestone injection and spray dryer absorbers (SDA) as the control technologies. 

Step 1c-Identification of Control Technologies-Review of Technologies installed at Georgia-Pacific 

Corporation Facilities 

Georgia-Pacific operates numerous combination fuel-fired boilers and coal-fired boilers within the 

United States. SO2 control technologies include dry scrubbing, limestone and sorbent injection on 

fluidized bed boilers, and the use of clean fuels. However, the company has limited experience with wet 

scrubbing with caustic on similar cyclone boilers. 

Step 2-Technical Feasibility Analysis-Eliminate Technically Infeasible Options 

The Green Bay Broadway Mill investigated several gas absorption technologies: wet scrubbing with caustic 

(sodium hydroxide) solution, semi-dry scrubbing using a lime slurry with conventional scrubbers, Spray Dry 

Absorbers (SDAs) and circulating fluidized bed scrubbers. Scrubber vendors have indicated to the Mill that 

spray drying is not technically feasible because the allowable inlet sulfur concentration associated with the 

current fuel mix would be too high and the flue gas temperatures too low to support the water evaporation 

requirements in the hydrated lime slurry SDA. As a result, SDA vendors have informed GP that they cannot 

provide quotations for this particular application of the technology. All of the other SO2 control technology 

options are technically feasible. 

Step 3 – Ranking the Technically Feasible Alternatives to Establish a Control Hierarchy 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

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B-57 

The ranking of the technologies are: 

1. Gas absorption with a wet spray tower or semi-dry scrubbing system with hydrated lime at 90%+ 

SO2 removal efficiency, 

2. In-Furnace Sorbent Injection at 50% removal efficiency, 

3. In-duct absorption with sodium sesquicarbonate (Trona) injection with 50% removal efficiency, 

4. Fuel substitution: Low SO2/MMBtu coal in place of all higher sulfur containing fuels at 11% 

removal efficiency 

Step 4- Cost Effectiveness Evaluation 

Economic Evaluation 

For each control technology cost estimate, the Green Bay Broadway Mill provided several general 

assumptions to the equipment vendors and engineering contractors for their use in determining site-specific 

cost estimates with a target accuracy of +/- 30% or better. The cost analysis for Boiler No. 7 follows the 

conventions presented above for Boiler No. 6. 

Wet Spray Tower with Sodium Hydroxide Cost Evaluation

The Green Broadway Bay Mill worked with several control equipment vendors to review technical issues 

and challenges with SO2 control by using wet, dry, or semi-dry scrubbing technologies. Based on the 

technical reviews, the use of a wet spray tower demonstrates the best overall SO2 removal efficiency of all 

the technologies reviewed and that were considered technically feasible. Jacobs Engineering provided the 

Green Bay Broadway Mill with a +/-30% cost estimate to install and operate a wet spray tower scrubber. 

The cost estimate for a wet spray tower scrubber presented in Table B-25 assumed that the scrubber will be 

located downstream of the existing baghouse and is parallel to the estimates presented for Boiler No. 6. The 

key design differences are: 

1. The clean flue gas exits the Scrubber and enters a new 16’ diameter, 316L stainless steel Stack mounted 

on top of the new Spray Tower Scrubber outlet. The Stack will terminate at an elevation of 199 feet 

above grade. The Stack is sized for a flue gas velocity of approximately 34 ft/sec with 395,000 cubic

feet/minute of scrubbed and saturated flue gas. 

2. The Spray Tower Scrubber has a 38’ by 30’ footprint and the Scrubber absorber vessel is 25’-0” in 

diameter and stands approximately 58’ tall. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

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Table B-25. Summary of Capital Cost for Installation of Wet Spray Tower Scrubber System, 

Boiler No. 7 Green Bay Broadway Mill 

Description32 Total Cost (2007$) 33

Direct Costs 

Major Equipment $11,969,285 

Demolition $19,375 

Site Improvements $598,464 

Piling, Caissons $837,850 

Buildings $670,000 

Concrete $988,762 

Structural Steel $2,194,549 

Piping $3,330,589 

Insulation - Pipe, Equipment & Ductwork $859,079 

Instrumentation $954,823 

Electrical $1,452,051 

Painting, Protective Coatings $119,693 

Construction Indirect Costs 

Construction Support Labor $1,038,695 

Premium Time $306,778 

Craft Per Diem $658,555 

Non-Payroll Tax, Insurance & Permits $1,035,129 

Craft Start-Up Assistance $43,650 

Contractor's Construction Fee $1,923,564 

Project Indirect Costs 

Construction Management $1,992,000 

Engineering Professional Services $4,423,000 

Study Cost $50,000 

Outside Consultant Services $100,000 

Owner's Cost $1,325,000 

Spare Parts $458,745 

Non-Craft Start-Up Assistance $119,150 

Allowance For Unforeseen $3,741,878 

Escalation $2,717,463 

Air Infiltration Allowance 34 $100,000 

Total Installed Cost (TIC)(+/- 30%) $44,028,127 

 

 

32 See Appendix for further description of estimator’s cost categories 

33 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 

34 Modifications to the exhaust system are expected to require studies and upgrades to eliminate air infiltration. 
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Best Available Retrofit Technology Analysis 

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B-59 

To determine estimated operating costs for the scrubber, this cost analysis used the templates provided by 

EPA in their Cost Control Manual. Determining annual operating costs is sensitive to the amount of sulfur 

dioxide removed and the amount of scrubbant required to maintain the desired SO2 removal efficiency. The 

2002-2004 actual emissions are significantly lower than permitted emissions (i.e.., 3.99 lbs SO2/MMBtu in 

2002-2004 compared to permit limit of 4.55 lb SO2 /MMBtu) and thus represent a conservatively lower 

annualized cost estimate. Table B-26 presents operating costs for the spray tower technology. 

Table B-26. Annual Operating Cost Calculations, Wet Spray Tower for Boiler No. 7, Actual 2002-

2004 Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per shift @ $40/hr $ 43,800 

Supervisor Labor 15% of Operator $ 6,570 

Maintenance labor: 0.5 hours per shift @ $40/hr $ 21,900 

Maintenance material 100% of Maintenance Labor $ 21,900 

 

Electricity 0.059$/kWhr x 11963492 kWhr $ 705,846 

Caustic Solution35 $1050/dry ton NaOH x 13,617 ton NaOH $ 14,298,047 

Process water: $0.06/kgal x 4518951 kgal $ 271,137 

Landfill Scrubber system solids $ 9.50 /ton x 100,377 tons $ 953,582 

Additional Process Steam $2.45/klb steam x 752,831 klbs $ 1,844,436 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs $ 56,502 

Taxes, insurance, admin. factor: 4% of TIC (Table B-25) $ 1,761,125 

Capital recovery factor (system): 0.1098 x TIC 36 (Table B-25) $ 4,834,052 

 

Total Annual Cost $ 24,818,896 

 

35 2002-2004 actual SO2

 tons emitted = 8715 emitted; consumption is 2.5 lb-mol NaOH per lb mol of SO2 removed; 2008 

average unit cost of caustic as delivered to Mill = $1,050/dry ton NaOH; 

8715 tons SO2 x 2,000 lbs/ton x lbmol SO2/64 lbs SO2 x 2.5 lb-mol NaOH/lb-mol SO2 x 40 lbs NaOH/lb-mol NaOH / 2,000 

lbs/ton =13,617 tons dry NaOH 

36 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: 

(0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

The cost effectiveness of this technology is equal to the Annual Operating Costs/ Annual Quantity of SO2

Removed. 

The estimated cost effectiveness is: $24,818,896 / (90% x 8,715 tons) = $3,164 /ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-60 

Dry Scrubbing with Hydrated Lime Fluidized Bed Absorber (FBA) Cost Evaluation 

Dry scrubbers have significantly lower capital and annual operating costs than wet systems because they are 

simpler, demand less water, and waste disposal is less complex. Dry injection systems are easier to install 

and use less space; therefore, they are good candidates for retrofit applications, such as the one at the Green 

Bay Broadway Mill. In contrast to a wet spray tower, FBAs use a reactor vessel with a closely controlled 

temperature. 

The cost estimate for a FBA scrubber assumes that the scrubber will be located downstream of the existing 

baghouse and is comparable to the estimates presented for Boiler No. 6 although equipment size is scaled 

for the higher airflow rate. 

Table B-27 summarizes the total cost for installation of the FBA system. 

Table B-27. Summary of Capital Cost for Installation of Fluidized Bed 

Absorber System, Boiler No. 7 Green Bay Broadway Mill 

Description TOTAL COST 

(2008$) 

Scrubber systems installation and duct modifications 15,357,754 

Footings and foundation work 684,809 

Electrical and controls 1,680,120 

Structural steel 536,569 

Engineering and commissioning 2,370,307 

Construction management 1,623,336 

General contractor overhead and mark-up 2,001,420 

Contingency 3,048,333 

CEM systems 358,312 

Piping 123,172 

Miscellaneous 539,087 

Freight 919,121 

Total Installed Cost 29,242,339 

 

Figure B-3 represents a simplified flow diagram of the required equipment for a generic case of any one of 

several boilers at the mill. In contrast to the wet spray tower scrubber technology, most of the equipment 

will be located within the existing buildings at a point upstream of the baghouse. Figure B-4 presents a 

footprint diagram. Table B-28 presents the operating costs for the FBA specific to Boiler No. 7. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-61 

Table B-28. Annual Operating Cost Calculations, Fluidized Circulating Absorber for 

Boiler No. 7, Actual 2002-2004 Conditions 

Parameter Methodology Annual Cost ($)

Direct Costs 

Operating labor : 3 hour per shift @ $40/hr 131,400 

Supervisor Labor 15% of Operator 19,710 

Maintenance labor & equipment: Vendor Estimate 10% of Equipment Costs 1,838,242 

 

Electricity- direct 0.059$/kWhr x 6864000 kWhr 404,976 

Electricity- fan make-up 8 inches w.c 201,680 

Hydrated Lime $90/ton hy lime x 36,037 tons hy lime/yr37 3,243,322

Process water: $0.06/kgal x 36,600 kgal 2,196 

Landfill Scrubber system solids $ 9.50 /ton x 58,575 tons 556,458 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 1,193,611 

Taxes, insurance, admin. factor: 4% of TIC (Table B-27) 1,169,694 

Capital recovery factor (system): 0.1098 x TIC 38 (Table B-27) 3,210,652 

 

Total Annual Cost 11,971,942

 

37 2002-2004 actual SO2

 tons = 8,715; consumption is 3.25 lb-mol hydrated lime per lb mol of SO2 removed; 2008 average unit 

cost = $90/ ton hydrated lime (91% active) 

8,715 tons SO2

 x 2,000 lbs/ton x lb-mol SO2/64 lbs SO2 x 3.25 lb-mol hydrated lime/lb-mol SO2 x 74.1 lbs hydrated lime / lbmol hydrated lime / 2,000 lbs/ton 1ton pure CaCO3/0.91 ton hydrated lime = 36,037 tons hydrated lime 

38 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: 

(0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

The cost effectiveness of this technology is equal to the Annual Operating Costs/ Annual Quantity of SO2

Removed. 

The estimated cost effectiveness is: $11,971,942/ (90% x 8,715 tons) = $1,526 /ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-62 

Furnace Sorbent Injection (FSI) Cost Evaluation 

As an alternative to “back-end” controls, the Green Bay Broadway Mill assessed control technologies 

further upstream. One such technique involves injecting a sorbent into the combustion chamber of the 

boiler with the fuel. As additional material in the boiler can significantly affect boiler performance, this 

technology is coupled with improving the air distribution system within the boiler. The technology has been 

demonstrated on stoker-fired boilers (further demonstration on cyclone boilers is expected in 2009), 

however, an unknown risk to operations is the potential erosion of boiler furnace tubes due to the additional 

sorbent material injected into the combustion chamber of the boiler. The FSI technology is similar to the 

dry scrubbing system in that it eliminates management of wet streams and has a small equipment footprint 

relative to wet scrubbing systems. Limestone with a high CaCO3 content would absorb SO2 as the fuel 

sulfur is oxidized in the furnace. The resultant particulate would be carried out with the boiler flue gas and 

then captured in the existing baghouse. As mentioned earlier, the mill expects that the existing baghouse 

would collect the additional particulate and maintain its high removal efficiency from an FSI without 

significant modification. 

The cost estimate for an FSI system is comparable to the estimates presented for Boiler No. 6, though 

equipment size is scaled for the higher airflow rate. However, Mobotec has very little experience with this 

type of system on cyclone boilers at this time. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

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Table B-29. Summary Of Capital Cost For Installation Of FSI System, Boiler No. 7 Green 

Bay Broadway Mill 

Description39 Total Cost (2007$)40

Major Equipment $7,018,799 

Demolition $661,504 

Site Improvements $491,316 

Piling, Caissons $631,692 

Buildings $330,000 

Concrete $828,031 

Structural Steel $1,497,449 

Piping $2,233,812 

Insulation - Pipe, Equipment & Ductwork $350,940 

Instrumentation $658,012 

Electrical $1,035,904 

Painting, Protective Coatings $70,188 

Construction Indirect Costs 

Construction Support Labor $758,232 

Premium Time $223,596 

Craft Per Diem $480,735 

Non-Payroll Tax, Insurance & Permits $564,881 

Craft Start-Up Assistance $43,650 

Contractor's Construction Fee $1,315,374 

Project Indirect Costs 

Construction Management $1,320,000 

Engineering Professional Services $2,931,000 

Study Cost $50,000 

Outside Consultant Services $100,000 

Owner's Cost $878,000 

Spare Parts $288,461 

Non-Craft Start-Up Assistance $119,150 

Allowance For Unforeseen $2,485,548 

Escalation $1,814,693 

Air Infiltration Allowance $100,000 

TOTAL INSTALLED COST (TIC) (+/- 30%) $29,280,967 

 

39 See Appendix for further description of estimator’s cost categories 

40 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-64 

Table B-30 presents annual operating costs for the FSI system. Without a site-specific study by Mobotec, 

the economic analysis could not estimate what, if any, loss of steaming capacity would occur with the 

significant amount of “dead load” material (i.e., sorbent) added into the furnace. The operating costs also do 

not include lost steam production due to increased wear on boiler tubes. Though the increased rate of tube 

erosion cannot yet be determined, the operation of the boiler will be affected by a significant increase in 

tube wall inspections following startup with an FSI system.

Table B-30. Annual Operating Cost Calculations, FSI for Boiler No. 7, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hour/shift x 1,095 shifts/year @ $40/hr 43,800 

Supervisor Labor 15% of Operator costs 6,570 

Maintenance labor: 0.5 hrs/shift x 1,095 shifts/year @ $40/hr 21,900 

Maintenance material 100% of Maintenance Labor 21,900 

 

Electricity- direct 0.059$/kWhr x 3,801,797 kWhr 224,306 

Limestone $40/ton limestone x 44,300 tons41 1,772,005 

Landfill Additional system solids $ 9.50/ton x 44,300 tons 420,850 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 56,502 

Taxes, insurance, admin. factor: 4% of TIC (Table B-29) 1,171,239 

Capital recovery factor (system): 0.1098 x TIC (Table B-29) 3,214,893 

 

Total Annual Cost 6,953,964 

 

41 2002-2004 actual SO2

 tons = 8,715; consumption is 3.25 lb-mol limestone per lb mol of SO2; Average unit cost is $40/ton 

delivered. 

 

8,715 tons SO2 x 2,000 lbs/ton x lb-mol SO2/64 lbs SO2 x 3.25 lb-mol limestone /lb-mol SO2 x 100.1 lbs limestone (CaCO3)/ 

lb-mol limestone / 2,000 lbs/ton = 44,300 tons limestone

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent 

required. The 2002-2004 actual emissions are significantly lower than permitted emissions and thus 

represent a conservatively lower annual cost (and operation) estimate. 

The cost effectiveness of this technology is equal to Annual Costs/ Annual SO2 Removed. 

The estimated cost effectiveness is: $6,953,964 / (50% x 8,715 tons) = 1,596 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-65 

In-Duct Absorption System with Trona Cost Evaluation 

In contrast to injecting sorbent into the boiler or using a wet spray tower scrubber vessel, in-duct absorption 

is an alternative capable of obtaining a 50% reduction in SO2 emissions from Boiler No. 7. Unlike the other 

SO2 technologies described above, this technology does not have many similar applications in commercial 

operation. With the use of this technology, offered by O’Brien and Gere, the sorbent is fed into the flue gas 

as a dry powder. The sorbent (sodium sesquicarbonate, or Trona) undergoes thermal decomposition and 

reacts with sulfur dioxide in the flue gases to form a particulate. Approximately one-third of the sorbent 

mass forms carbon dioxide and exhausts to the atmosphere while the other two-thirds of the particulate mass 

is captured in the existing baghouse. The use of Trona will result in the release of 4 moles of carbon dioxide 

for every 2 moles of Trona. The supply market for this sorbent is very limited to a few active mines in the 

western United States. Without multiple sources for the sorbent, deliveries to the mill are at higher risk of 

supply interruptions (e.g., natural or other external events) than other technologies with many suppliers. 

The cost estimate for an In-Duct Absorbtion System is comparable to the estimates presented for Boiler No. 

6, although equipment size is designed for the higher airflow rate. Table B-31 presents a summary of 

installation the installed costs for the In-Duct Absorption System for Boiler No. 7.
GP Consumer Products Green Bay Mill 

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March 2009 

B-66 

 

 

42 See Appendix for further description of estimator’s cost categories 

43 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 

44 Modifications to the exhaust system are expected to require studies and upgrades to eliminate air infiltration. 

Table B-31. Summary of Capital Cost for Installation of In-Duct Sorbent 

System, Boiler No. 7 Green Bay Broadway Mill 

Description42 Total Cost (2007$)43

Direct Costs 

Major Equipment 12,600,000 

Demolition 250,000 

Site Improvements 157,500 

Piling, Caissons 450,000 

Buildings 120,000 

Concrete 141,750 

Structural Steel 567,000 

Piping 535,500 

Insulation - Pipe, Equipment & Ductwork 283,500 

Instrumentation 157,500 

Electrical 346,500 

Painting, Protective Coatings 47,250 

Construction Indirect Costs 

Construction Support Labor 184,480 

Premium Time 53,062 

Craft Per Diem 116,965 

Non-Payroll Tax, Insurance & Permits 438,838 

Craft Start-Up Assistance 43,650 

Contractor's Construction Fee 406,796 

Project Indirect Costs 

Construction Management 478,000 

Engineering Professional Services 1,058,000 

Outside Consultant Services 100,000 

Owner's Cost 700,000 

Spare Parts 641,025 

Non-Craft Start-Up Assistance 119,150 

Allowance For Unforeseen 1,999,647 

Escalation 1,044,328 

Air Infiltration Allowance44 100,000 

Total Installed Cost (+/- 30%) (TIC) 23,140,441 
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March 2009 

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Table B-32 presents the annual operating costs for the In-Duct Absorption system. 

Table B-32. Annual Operating Cost Calculations, In-Duct Absorption System for Boiler No. 7, Actual 

2002-2004 Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 0.5 hrs/shift x 1,095 shifts/yr @ $40/hr 21,900 

Supervisor Labor 15% of Operator 3,285 

Maintenance labor: 0.5 hrs per day x 365 days/yr @ $40/hr 7,300 

Maintenance material 100% of Maintenance Labor 7,300 

Electricity 0.059$/kWhr x 2,534,375 kWhr 149,528 

Trona consumption $150/ton Trona x 5.2 tons Trona/hr

45 x 8,400 hr/yr 6,552,000 

Landfill Additional Baghouse solids $ 9.50/ton x 4.4 tons solids/hr x 8,400 hrs/yr 351,120 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 23,871 

Taxes, insurance, admin. factor: 4% of TIC (Table B-31) 925,618 

Capital recovery factor (system): 0.1098 x TIC (Table B-31) 2,540,696 

Total Annual Cost 10,582,618 

 

45 Based on vendor estimate 

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent 

required. The 2002-2004 actual emissions are significantly lower than permitted emissions and thus 

represent a conservatively lower annualized cost (and operation) estimate. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of SO2

Removed. 

The estimated cost effectiveness is: $10,582,618 / (50% x 8,715 tons) = 2,428 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-68 

Clean Fuels Cost Evaluation 

As mentioned above, Boiler No. 7 combusts eastern low fusion coal and petroleum coke. The only fuel 

limited by the air permit is the amount of petroleum coke to approximately 24% by weight of total fuel. 

Table B-33 presents the range of heat value, ash and sulfur content of the various fuels. 

Determining marginal costs of fuel with different sulfur concentrations is reasonably certain for a short 

“future”. As the period for a fuel forecast is extended, uncertainty rapidly increases. Therefore, the unit 

cost is presented as a range where estimated. Subsequent calculations use the average of the high and low 

end of the range. 

Table B-33 Unit Costs for Various Fuels Fired in Boiler No. 7, Green Bay Broadway Mill 

Fuel Sulfur % MMBtu/ton $/MMBtu 

2009-2013 

Petroleum Coke 5 to 6.5 27.6-28.4 1.71 

Eastern Low-fusion Coal 2.5-2.7 25.4-27.0 3.35 

 

The cost evaluation determined the costs of substituting all petroleum coke with eastern low-fusion coal. 

Table B-34 presents a summary of the sulfur dioxide emission estimates for this case. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-69 

Table B-34. Clean Fuel Emission Calculations, Boiler No. 7, Green Bay 

Broadway Mill 

 

 Low 

Fusion 

Petroleum 

Coke 

Total 

2002-2004 MMBtu Estimate (annual) 3402280 871980 4274259 

2002-2004 Tons (annual) 129858 30812 160670 

Sulfur into the Boiler (tpy) 3091 1722 4813 

Percent of Emissions 64% 36% 

SO2 Emission Estimate (tpy) 5596 3119 8715 

Fuel Cost (MM$) 11.4 1.5 12.9 

 

Case 1 : Switch Petroleum Coke to Eastern Low Fusion 

MMBtu 4274259 -- 4274259 

Tons Fuel 163140 -- 163140 

Sulfur into the Boiler (tpy) 3883 -- 

SO2 Emission Estimate (tpy) 7765 -- 7765 

Fuel Cost (MM$) 14.3 -- 14.3 

 

Table B-35 summarizes the annual marginal fuel costs and emissions reductions relative to 2002-2004 

actual emissions for these cases. 

Table B-35. Summary of Fuel Cost Increases for Various Fuel Switch Cases, Green Bay 

Broadway Mill 

 

Case 2002-2004 1 

 

Average $/MMBtu $3.02 $3.35 

SO2 Emissions 8,715 7765 

Emission Change (tpy) NA 950 

% Reduction 11% 

Fuel Cost ($/yr) $12,888,722 $14,318,768 

Fuel Cost Increase ($/yr) NA $1,430,047 

Cost Effectiveness Fuel Price Only ($/ton) NA 1,506 

 

Summary of Economic Evaluation, SO2 Controls for Power Boiler No. 7
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-70 

The economic evaluation determined a range of cost effectiveness values for the following levels of control: 

Less than 50%, 50%, and 90%. Figure B-9 presents a marginal cost curve for all the cost estimates 

presented in Table B-25 through B-35. 

Figure B-9. Marginal Cost Curve for SO2 Control Options, Green Bay Broadway Mill Boiler No.7 

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions 

Control options: 11% removal by Clean Fuels; 50% removal by FSI or In Dusct Sorbent 

Injectionremoval by gas absorption (scrubber) 

Energy and Environmental Impacts

Throughout the economic analysis, the cost estimates documented, where possible, the actual costs for 

additional energy consumption, additional water demand, and addition solid waste generated. Also in each 

technology discussion, the analysis discussed environmental impacts. Table B-36 summarizes a comparison 

of energy and environmental impacts for each option. 

500

1000

1500

2000

2500

3000

3500

0 2000 4000 6000 8000 10000

Actual Annual Tons SO2 Removed (tpy)

Cost Effectiveness ($/ton)

Low Cost

High Cost 11%

50%

90%
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-71 

Table B-36. Summary of Additional Impacts for SO2 Control Technologies, Boiler No. 7 

 

Technology 

Impacts Scrubber FSI/ Induct Injection Clean Fuels 

Additional Energy (kWhr/yr) 11,963,492 3,801,797 None 

Additional Water (million gal) 4,519 None None 

Additional Solid Waste (tons) 100,377 44,300 None 

Environmental Impacts Treatment of metals 

in waste stream 

Higher PM10 Loading 

to Baghouse 

Higher PM10 Loading 

to Baghouse 

Other Impacts Wet Plume Additional CO2 from 

Trona decomposition; 

FSI may reduce NOx 

Less CO2 emissions 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-72 

3.5 NITROGEN OXIDES 

Step 1a-Identification of Control Technologies-Typical Technologies in Use in the United States 

The technologies typically available for multi-fuel cyclone boilers are equivalent to the technologies

presented in Section 2.5 for Boiler No. 6. These technologies are: 

• Low Nitrogen Fuel 

• Selective Catalytic Reduction 

• Selective Non-Catalytic Reduction 

• Air Staging of Combustion 

• Flue Gas Recirculation 

• Low-NOx Burners 

Step 1b-Identification of Control Technologies-Review of RACT/BACT/LAER Clearinghouse 

(RBLC) 

Searches of the RBLC were conducted to identify control technologies for the control of emissions from

cyclone power boilers. The specific category searched was External Combustion- 11. Table B-37 

summarizes recent retrofit technologies determinations. 

Table B-37. Summary of RBLC and Recent NOx Emission Limits for Various Coal 

Boilers 

 NOx 

Emissions 

Source Technology (lb/MMBtu) 

Utility Boilers SCR/SCR+LNB 0.07 - 0.09 

Utility Boilers LNB+SNCR 0.1 

Utility Boilers SNCR 0.08 - 0.15 

 

Industrial Boilers 

Circulating Fluid Bed SNCR 0.08 

Stoker/Other None 0.246 - 0.7 

 

Recent Permits with Add On Technologies 

Temple Inland -Rome, GA LNB 0.5 

Smurfit-Stone (Maritime) Jacksonville, FL SNCR 0.5 

 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-73 

Step 1c-Identification of Control Technologies-Review of Technologies in Use at Georgia-Pacific 

Corporation Facilities 

For several coal boilers at various facilities, GP uses a variety of NOx reduction measures, including 

overfire air, FGR, and combustion controls. GP uses ammonia injection for NOx control for one 

combination fuel fluidized bed boiler and one deinked wastewater sludge-fired boiler. 

Step 2-Technical Feasibility Analysis-Eliminate Technically Infeasible Options 

All of the options identified above are technically feasible except for low-Nitrogen fuel substitution and 

the use of low NOx burners. 

Step 3 – Ranking the Technically Feasible Alternatives to Establish a Control Hierarchy 

The ranking for NOx control is: 

1. Tail-end SCR at 80% removal efficiency 

2. SNCR with OFA at 70% removal efficiency 

3. ROFA and Rotamix at 66% removal efficiency 

4. OFA at 60% removal efficiency 

5. SNCR alone at 35% removal efficiency 

Step 4- Effectiveness Evaluation 

Economic Effectiveness 

For each cost estimate, the Green Bay Broadway Mill provided several general assumptions to equipment 

vendors and engineering contractors to determine site-specific cost estimates with a target accuracy of +/- 

30% or better. 

SCR Cost Evaluation 

The NOx removal technology with the highest removal efficiency studied is SCR. SCR technology is a 

post-process NOx control option used to remove NOx after the combustion process rather than limit NOx

development at the source. In this case, a reactor filled with an application-specific catalyst is placed in the 

boiler outlet flue gas stream. The catalyst in these reactions is only effective in a narrow elevated

temperature range. In this case, the flue gas needs to be between 600oF and 650oF in order to maximize the 

effectiveness of the catalyst without causing thermal damage. Two (2) SCR reactor installation locations 

that allow for the appropriate flue gas temperature were evaluated. The first option would be to modify the 

boiler’s flue gas outlet path to accommodate placement of the SCR reactor prior to the boiler’s existing air 

preheater. The second available reactor installation location is downstream of the existing baghouse.
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-74 

Locating the SCR reactor between the boiler flue gas outlet and the existing air preheater provides the 

necessary flue gas temperatures; however, it also presents several key obstacles. These obstacles include 

high flue gas velocities, reduced residence time for the flue gas to pass through the catalyst bed, damage to 

the catalyst, and blinding of catalyst pores due to high particulate loading. Because of these factors as well 

as constructability issues, the Slip Stream SCR was estimated as a tail-end unit. Figure B-6 presents a 

general arrangement. 

The estimate for Boiler No. 7 follows a similar methodology as Boiler No. 6 with a re-design of equipment 

due to size of the boiler and its level of emissions. Stack 10 will continue to serve one chamber of the 

Standard Havens baghouse. Table B-38 presents the capital cost estimate for a tail-end SCR for Boiler No. 

7. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-75 

Table B-38. Summary of Capital Cost for Installation of SCR Slip-Stream System, Boiler 

No. 7 Green Bay Broadway Mill 

Description 2009 Costs ($) 

Direct Costs 

Major Equipment 9,158,122 

Demolition 20,773 

Site Improvements 686,859 

Piling, Caissons 961,603 

Buildings 36,000 

Concrete 1,249,240 

Structural Steel 2,518,690 

Piping 2,548,351 

Insulation - Pipe, Equipment & Ductwork 2,447,224 

Instrumentation 1,030,289 

Electrical 1,076,904 

Painting, Protective Coatings 137,372 

Construction Indirect Costs 

Construction Support Labor 1,044,553 

Premium Time 311,917 

Craft Per Diem ($7/Hour On 100 % Of Time) 638,654 

Non-Payroll Tax, Insurance & Permits 864,094 

Craft Start-Up Assistance 43,650 

Contractor's Construction Fee 2,029,476 

Project Indirect Costs 

Construction Management 1,949,000 

Engineering Professional Services 6,500,000 

 Study Cost 50,000 

Outside Consultant Services 100,000 

Owner's Cost 1,225,000 

Spare Parts 319,000 

Non-Craft Start-Up Assistance 119,150 

Allowance For Unforeseen 3,701,594 

Escalation 2,422,800 

Air Infiltration Allowance 100,000 

 

Total Installed Cost (+/- 30%) (TIC) 43,290,315 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-76 

Table B-39 presents the annual operating costs for the SCR system. 

Table B-39. Annual Operating Cost Calculations, SCR for Boiler No. 7, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 2 hours per shift x 1,025 shifts/yr @ $40/hr 82,000 

Supervisor Labor 15% of Operator 12,300 

Maintenance labor: 0.5 hours per day x 365 days/yr @ $40/hr 7,300 

Maintenance material 100% of Maintenance Labor 7,300 

 

Electricity 0.059$/kWhr x 6737068 kWhr 397,487 

Ammonia consumption $160/ton aq NH3x 33899 tons aq NH3 /yr 5,423,840 

Natural Gas $10/MMBtu x 822,326 MMBtu/yr 8,223,260 

Catalyst $936,224/ 3 years 312,075 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 65,340 

Taxes, insurance, admin. factor: 4% of TIC (Table B-38) 1,731,613 

Capital recovery factor (system): 0.094 x TIC (Table B-38) 4,086,299 

 

Total Annual Cost 20,348,814 

Determining annual operating costs is sensitive to the amount of NOx removed and ammonia required. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $20,348,814/ (80% x 2,740 tons) = 9,283 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-77 

ROFA and Rotamix Cost Evaluation 

Section 3.4 presented the application of Mobotec’s ROFA and Rotamix costs within its FSI technology. 

The total installed cost for targeting NOx contol only is estimated to be approximately $1.9MM lower 

by removing the limestone injection, handling, and storage equipment specifically needed for SO2

removal. Thus, the expected total installed cost is $27,000,000. Table B-40 presents the annual 

operating costs without the limestone use or landfilling charges. 

Table B-40. Annual Operating Cost Calculations, ROFA/ROTAMIX for Boiler No. 7, Actual 2002-

2004 Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per shift x 1,025 shifts/yr @ $40/hr 41,000 

Supervisor Labor 15% of Operator 6,150 

Maintenance labor: 0.5 hours per day x 365 days/yr @ $40/hr 7,300 

Maintenance material 100% of Maintenance Labor 7,300 

 

Electricity- direct 0.059$/kWhr x 3801797 kWhr 224,306 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 37,050 

Taxes, insurance, admin. factor: 4% of TIC 1,080,000 

Capital recovery factor (system): 0.094 x TIC ($27MM) 2,548,609 

 

Total Annual Cost 3,951,715 

Determining annual operating costs is only sensitive to the number of hours the air mixing system is 

operated. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $3,951,715/ (66% x 2,740 tons) = 2,185 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-78 

SNCR Cost Evaluation

SNCR systems are most efficient in a single temperature window; therefore, in order to properly operate 

an SNCR system, a boiler study is required to map the gas temperatures at several locations during 

varying boiler operating points. A detailed SNCR study was not conducted for Power Boiler No. 7; 

however, the SNCR supplier requires such a study and the SNCR estimate includes a one-time cost of 

$50,000 to accomplish this task. 

The estimate for Boiler No. 7 follows a similar methodology as Boiler No. 6 with a re-design of 

equipment due to size of the boiler and its level of emissions. The vendor has indicated that an SNCR 

system on a cyclone boiler can achieve 35% reduction. Table B-41 presents the total installed cost 

estimate for an SNCR system alone. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-79 

Table B-41. Summary of Capital Cost for Installation of SNCR System, Boiler 

No. 7 Green Bay Broadway Mill 

Description TOTAL COST 

(2007$) 

Direct Costs 

Major Equipment 1,704,630 

Demolition 38,354 

Site Improvements 85,232 

Piling, Caissons 119,324 

Buildings 270,000 

Concrete 76,708 

Structural Steel 306,833 

Piping 289,787 

Insulation - Pipe, Equipment & Ductwork 153,417 

Instrumentation 42,616 

Electrical 232,092 

Painting, Protective Coatings 17,046 

Construction Indirect Costs 

Construction Support Labor 140,891 

Premium Time 41,289 

Craft Per Diem 89,328 

Non-Payroll Tax, Insurance & Permits 124,932 

Craft Start-Up Assistance 45,000 

Contractor's Construction Fee 245,577 

Project Indirect Costs 

Construction Management 295,000 

Engineering Professional Services 652,000 

Outside Consultant Services 100,000 

Owner's Cost 197,000 

Spare Parts 74,279 

Non-Craft Start-Up Assistance 119,150 

Allowance For Unforeseen 546,048 

Escalation 386,091 

Air Infiltration Allowance 100,000 

Total Installed Cost (+/- 30%) (TIC) 6,492,624 

Table B-42 presents the annual operating costs for the SNCR system.
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-80 

Table B-42. Annual Operating Cost Calculations, SNCR for Boiler No. 7, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per shift x 1,025 shifts/yr @ $40/hr 41,000 

Supervisor Labor 15% of Operator 6,150 

Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 

Maintenance material 100% of Maintenance Labor 7,000 

 

Electricity 0.059$/kWhr x 821763 kWhr 48,484 

Urea Consumption $1.35/gal x 34.4 gph x 8400 hr/yr 390,096 

Mill Water $0.06/kgal x 7,884 kgal/yr 473

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 36,690 

Taxes, insurance, admin. factor: 4% of TIC (Table B-41) 259,705 

Capital recovery factor (system): 0.094 x TIC (Table B-41) 610,307 

 

Total Annual Cost 1,406,905 

Determining annual operating costs is sensitive to the amount of NOx removed and urea required. 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $1,406,905/ (35% x 2740 tons) = 1,467 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-81 

OFA Cost Evaluation 

An additional NOx control case that was studied and estimated for Power Boiler No. 7 was Overfire Air. 

The installation of OFA reduces the formation of NOx by staging combustion into two zones. The first 

combustion stage created by this process control system redistributes some of the combustion air away from 

the cyclone burners allowing the burners to operate fuel rich. The subsequent fuel rich zone prevents the 

formation of thermal NOx by providing a low oxygen concentration in the cyclone burner. Thermal NOx is 

caused by the reaction of nitrogen and oxygen in areas of high flame temperatures. In the fuel-rich stage, 

the formation of NOx is low but the formation of CO and combustibles is high. The second stage of the 

OFA system allows for the completion of combustion by adding combustion air to the furnace downstream 

of the cyclone burners. The second stage combustion in the furnace occurs at a lower temperature with

subsequent reduction in formation of thermal and fuel bound NOx. Fuel bound NOx is the result of the 

oxidation of fuel bound nitrogen. 

The new OFA system would include ductwork from the existing high pressure forced draft (FD) fans’ outlet 

to each port location; expansion joints, dampers and operators, annubars for delta-P measurement to major 

port locations, as well as boiler tube bends and injection wall boxes. Due to the cyclone boiler’s high 

pressure FD Fans, no booster OFA fan would be required for the system. Combustion air port design would 

be dependent on the supplier. Several different designs are available in the market place to ensure that the 

appropriate amount of air and air penetration could be achieved during boiler swings. Money is included in 

the BART estimate for the supplier to perform a study to determine the appropriate location for the OFA 

ports. Money is included in the BART estimate for minor relocation and demolition to allow for the OFA 

system ductwork installation. 

Table B-43 presents the total installed cost estimate for an OFA system alone. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-82 

Table B-43. Summary of Capital Cost for Installation of OFA System, Boiler No. 7 Green 

Bay Broadway Mill 

Description TOTAL COST (2007$) 

Direct Costs 

 Major Equipment 992,465 

 Demolition 38,749 

 Site Improvements 49,623 

 Buildings 270,000 

 Concrete 29,774 

 Structural Steel 148,870 

 Insulation - Pipe, Equipment & Ductwork 45,021 

 Instrumentation 24,812 

 Electrical 99,168 

 Painting, Protective Coatings 9,925 

Construction Indirect Costs 

 Construction Support Labor 86,960 

 Premium Time 25,969 

 Craft Per Diem 55,135 

 Non-Payroll Tax, Insurance & Permits 56,507 

 Craft Start-Up Assistance 45,000 

 Contractor's Construction Fee 143,014 

Project Indirect Costs 

 Construction Management 162,000 

 Engineering Professional Services 358,000 

 Study Cost 50,000 

 Outside Consultant Services 100,000 

 Owner's Cost 108,000 

 Spare Parts 32,742 

 Non-Craft Start-Up Assistance 59,575 

 Allowance For Unforeseen 294,131 

 Escalation 190,808 

 Air Infiltration Allowance 100,000 

Total Installed Cost (+/- 30%) (TIC) 3,576,246 

Table B-44 presents the annual operating costs for the OFA system. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-83 

Table B-44. Annual Operating Cost Calculations, OFA for Boiler No. 7, Actual 2002-2004 

Conditions 

Parameter Methodology Annual Cost ($) 

Direct Costs 

Operating labor : 1 hours per day x 350 days/yr @ $40/hr 14,000 

Supervisor Labor 15% of Operator 2,100 

Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 

Maintenance material 100% of Maintenance Labor 7,000 

 

Electricity 0.059$/kWhr x 890,491 kWhr 52,539 

 

Indirect Costs 

Overhead rate (fractional): 60% of total labor and material costs 18,060 

Taxes, insurance, admin. factor: 4% of TIC (Table B-43) 143,050 

Capital recovery factor (system): 0.094 x TIC (Table B-43) 336,167 

 

Total Annual Cost 579,916 

Determining annual operating costs for OFA is sensitive only to the number of hours the fan is used. The 

operating costs reflect a typical annual operation of 8,400 hours/year (350 days/yr). 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 

The estimated cost effectiveness is: $579,916/ (60% x 2,740 tons) = 353 $/ton. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-84 

SNCR with OFA Cost Evaluation

In an attempt to design a more successful combustion modification technology with urea injection, the 

Mill developed a cost estimate for the combination of both OFA and SNCR. Table B-45 tabulates the 

cost estimate for this combination of technologies. 

Table B-45. Summary of Capital Cost for Installation of OFA/SNCR System, 

Boiler No. 7 Green Bay Broadway Mill 

Description TOTAL COST 

OFA System (Table B-43) 3,576,246 

SNCR System (Table B-41) 6,492,624

Total Installed Cost (+/- 30%) (TIC) 10,068,870 

Table B-46 presents the operating costs for a combination of OFA and SNCR.

Table B-46. Annual Operating Cost Calculations, OFA+SNCR for Boiler No. 7, 

Actual 2002-2004 Conditions

Parameter Annual Cost ($) 

Direct Costs OFA SNCR Total 

Operating labor : 14,000 41,000 

Supervisor Labor 2,100 6,150 

Maintenance labor: 7,000 7,000 

Maintenance material 7,000 7,000 

 

Electricity 52,539 48,484 

Urea and Water 0 390,569 

Indirect Costs 

Overhead rate (fractional): 18,060 36,690 

Taxes, insurance, admin. factor: 143,050 259,705 

Capital recovery factor (system): 336,167 610,307 

 

Total Annual Cost 579,916 1,406,905 1,986,821 

Determining annual operating costs for the combination is sensitive to the number of hours the fan is used as 

well as the urea consumption requirement. 

 

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of NOx 

Removed. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-85 

The estimated cost effectiveness is: $1,986,821/ (70% x 2,740 tons) = 1,036 $/ton. 

Summary of Economic Evaluation, NOx Controls for Power Boiler No. 7

The economic evaluation determined a range of cost effectiveness values for the following levels of control: 

35%, 60%, 66%, 70%, and 80%. Figure B-10 presents a marginal cost curve for all the cost estimates 

presented in above. 

Figure B-10 Marginal Cost Curve for NOx Control Options, Green Bay Broadway Mill Boiler No. 7 

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions 

Control options: 35% by SNCR; 60% by OFA; 66% by ROFA/ROTAMIX; 70% by SNCR and OFA; 

80% by SCR 

Energy and Environmental Impacts

Throughout the economic analysis, the cost estimates documented, where possible, the actual costs for 

additional energy consumption, additional water demand, and addition solid waste generated. Also in each 

technology discussion, the analysis discussed environmental impacts. Table B-47 summarizes a comparison 

of energy and environmental impacts for each option. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

750 1250 1750 2250 2750

Acutal Annual Ton NOX Removed (tpy)

Cost Effectiveness ($/ton)

Average $/ton

80%

70%

66%

60%

35%
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-86 

Table B-47. Summary of Additional Impacts for NOx Control Technologies, Boiler No. 7 

Technology 

Impacts SNCR Options Combustion Modifications SCR 

Additional Energy (kWhr/yr) 82,1763 1,712,254 6,737,068 

Additional Water (million gal/yr) 7.884 0 0 

Additional Natural Gas (MMcf/yr) 0 0 822 

Environmental Impacts NH3 Emissions None NH3 Emissions 

Other Impacts NH3 Handling None NH3 Handling 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-87 

3.6 ADDITIONAL MULTI-POLLUTANT CONTROL OPTION FOR BOILER NO. 7 

As mentioned above, Boiler No. 7 provides significant energy to the Mill. The steam that Boiler No. 7 

produces can be viewed as being directly used for electricity generation through condensing this steam

in the mill’s steam turbine condensers. Boiler No. 7 has the capacity to produce 550,000 lbs steam per 

hour and, by passing this steam through the mill’s turbines to its condensers, can yield an output of 

approximately 55 megawatts (MW) for use in the plant. An additional multi-pollutant option for Boiler

No. 7 is to replace the electrical generation with purchased electricity while reserving its steam 

production capacity for intermittent operation (i.e., scheduled downtime of other steam-producing units 

at the Mill). Increasing the use of purchased electricity will require a one-time upgrade to electrical 

infrastructure. The Electrical Infrastructure Upgrade option is technically feasible. The cost evaluation 

is provided for comparison purposes. This option is not a conventional control technology as it 

drastically reduces the ability for the source to operate as it does presently. 

Cost Evaluation

Through its current arrangement with Wisconsin Public Service Corporation (WPS), (the mill’s utility 

service provider), two potential electrical infrastructure upgrades could be considered for the mill. One 

upgrade would involve the installation of a new transmission level (138 Kilovolt) connection to the 

utility with the substation being located on the mill property. The other upgrade would involve the 

installation of one or two additional primary voltage level (13.8 Kilovolt) connections to the mill 

property from existing or new WPS substations. Both solutions have distinct advantages and 

disadvantages which need to be further evaluated before a solution is chosen. The estimated total 

installed cost for either one of these solutions is $5 million. 

The annual operating cost of the Electrical Infrastructure Upgrade is limited to the marginal cost of 

purchased electricity and indirect costs. Direct operating costs associated with the electrical equipment 

is shared with WPS. 

The average steam production across the 2002-2004 baseline period was 3,441,735 klbs/steam per year. 

Assuming all of the steam from Boiler No. 7 was used to generate electricity through condensing in the

mill’s turbine generators, the mill would convert this amount of steam into approximately 344,173 MW 

for an annual period, and 39.29MW/hr (annual average). The incremental unit cost of purchased 

electricity from WPS above the cost for Boiler No. 7 to produce the power is $25/MW-hr for on-peak 

hours. The incremental cost of purchased electricity from WPS is approximately equal to the Boiler No. 

7 generation cost during off-peak hours. The annual average incremental unit cost is: 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-88 

$25/MW-hr x 3900 on-peak hr/yr + $0.00/MW-hr x 4860 off peak hr/yr / (8,760 hours/yr) = 

= $11.13/MW-hr (annual average) 

The electrical infrastructure upgrade option would require the mill to operate Boiler No. 7 as a steam

source when another boiler is down. Based on the number of boilers at the mill, their steam usage and

scheduled outage durations, the mill estimates that Boiler No. 7 would operate up to 60 days or 16.4% 

of the year. This would result in an 83.6% emissions reduction for all pollutants on a pollutant-bypollutant basis, including those not subject to BART. 

The direct annual operating cost associated with electrical energy charges is estimated to be: 

39.29 MW-hr/hr x (83.6%) x 8760 hr/yr x $11.13/MW-hr = $3,202,488/yr ($2009). 

In addition to the electrical energy charges detailed above, the mill would also incur electrical demandrelated charges. Electrical demand charges from WPS are billed monthly and consist of an annual 

demand-related charge and a monthly demand-related charge. The annual (customer) demand charge 

would be largely unchanged. However, monthly (system) demand charges would be affected for 

approximately 10 months of the year. 

Based on a 4 MW firm demand nomination, the additional demand-related costs resulting from reducing 

the operation of Boiler No. 7 to 60 days per year are: 

[39.29 MW – 4 MW] x 10-months x $3,139/MW = $1,107,753/yr ($2009) 

The estimated indirect annual cost is the capital recovery for the installed equipment. For this option, 

the analysis used a capital recovery factor of 7% interest over 20 years. As described above, the capital 

recovery factor is 0.0944. Thus the indirect annual cost for capital recovery is: 

0.0944 x $5,000,000 = $472,000/yr. 

The total annual cost is $3,202,488/yr + $1,107,753 + $472,000 = $4,782,241/yr. ($2009) 

In addition to the limited operating schedule, the option will include the exclusive use of low fusion

eastern coal. As presented above, the reduction in actual emissions from this fuel switch is 

approximately 11%. When combined with the 83.6% reduction, the total annual average reduction is: 

83.6% + (1-83.6%) x 11% = 85% for SO2. 
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-89 

The cost effectiveness is equal to the Annual Cost per Ton removed. Though this is a multi-pollutant 

option, the analysis calculated cost effectiveness for each pollutant individually for direct comparison to 

other technologies. 

The cost effectiveness for SO2 is: $4,782,241/ (85% x 8,715 tons SO2) = $646 

The cost effectiveness for NOx is: $4,782,241/ (83.6% x 2,740 tons NOx) = $2,088 

The actual cost effectiveness is lower than these calculated values as the total annual cost is only spent once 

and achieves the reduction of both pollutants simultaneously.
GP Consumer Products Green Bay Mill 

Best Available Retrofit Technology Analysis 

March 2009 

B-90 

4.0 BART ENGINEERING ANALYSIS SUMMARY

Table B-48 presents the summary of the technically feasible options for the BART eligible emission 

units. 

* Technologies which are not economically feasible due to marginal or incremental cost effectiveness. 

Table B-48. Summary of BART Engineering Analysis Green Bay Broadway Mill 

Emission Unit Pollutant Technology 

Maximum 

Reduction 

(%) 

Annual Operating 

Cost ($) 

Effectiveness 

($/ton) 

Boiler No. 6 SO2 Wet Scrubber 90 10,057,563 5,174* 

Boiler No. 6 SO2 Semi Dry Scrubber 90 6,004,723 3,089* 

Boiler No. 6 SO2 Clean Fuels 62 $1,631,891 1,082 

Boiler No. 6 SO2 Furnace Sorbent Injection 50 4,502,391 4,169 

Boiler No. 6 SO2 In Duct Sorbent Injection 50 4,317,733 3,998 

 

Boiler No. 6 NOx SCR 80 9,871,725 28,831* 

Boiler No. 6 NOx ROFA - ROTAMIX 66 3,660,476 12,958* 

Boiler No. 6 NOx SNCR+ OFA +FGR 56 2,077,302 8,667*

Boiler No. 6 NOx SNCR 25 1,061,490 9,920* 

Boiler No. 6 NOx OFA/FGR 20 619,998 7,243* 

 

Boiler No. 7 SO2 Wet Scrubber 90 24,818,896 3,164* 

Boiler No. 7 SO2 Semi Dry Scrubber 90 11,971,942 1,526* 

Boiler No. 7 SO2 Electrical Upgrades + Fuel Switch 85 4,782,241 646

Boiler No. 7 SO2 Furnace Sorbent Injection 50 6,953,964 2,429 

Boiler No. 7 SO2 In Duct Sorbent Injection 50 10,582,618 1,596 

Boiler No. 7 SO2 Clean Fuels 11 1,430,047 1,506 

 

Boiler No. 7 NOx Electrical Upgrades + Fuel Switch 83.6 4,782,241 2,088 

Boiler No. 7 NOx SCR 80 20,348,814 9,283* 

Boiler No. 7 NOx SNCR+ OFA 70 1,986,821 1,036 

Boiler No. 7 NOx ROFA - ROTAMIX 66 3,951,715 2,185 

Boiler No. 7 NOx OFA 60 579,916 353 

Boiler No. 7 NOx SNCR 35 1,406,905 1,467 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

Appendix A: 

Basis of Estimated Costs 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

GENERAL

The purpose of these cost estimates is to provide Georgia Pacific with a Feasibility 

Study Level Report in 2007 dollars with an accuracy range of ± 30 % for the Regional 

Haze/ Boiler BART Program at the Greenbay, Wisconsin Mill. 

Estimates were prepared by Jacobs for various SO2 and NOX control technologies for 

the boilers which where put in place or under construction between August 7, 1962 and 

August 7, 1977. These cost estimates were prepared in such a manner to ensure that 

each boiler proposed control technology and related cost estimate would stand alone on 

its own merit. This approach was selected to better address the uncertainty that will 

exist between which project or combination of projects might ultimately be implemented 

to meet the emissions targets established for the EPA Regional Haze / Boiler BART 

2013 compliance date. Certain site specific conditions and / or the presence of alternate 

control technologies in the future may ultimately impact the overall project costs and 

feasibility of these projects if several of these projects are implemented concurrently on 

any given site. 

In addition, the numbers used in this estimate for equipment cost do not always reflect 

the exact dollar amount that was provided by a vendor and reported in Appendix D. In 

many cases, Jacobs has used their sound engineering judgment and previous 

experience to change these prices. These changes may be for many reasons including 

but not limited to: adding or removing installation costs, adjusting for construction with a 

more expensive material, adding or removing options, increasing the controls included, 

etc. 

In order to allow for air in-leakage in the existing Boilers, $100,000 has been added to 

each estimate to locate and repair any areas where excessive air infiltration may be 

occurring. This is required to ensure that any control technologies installed operate as 

they were designed. 

GP plans to utilize the results from this feasibility study report and cost estimate(s) to 

support the Regional Haze / Boiler BART documentation submittal requirements to the 

individual States. This will establish the viability for installing the Boiler BART Control 

Technologies on these respective site boilers or whether to de-rate or decommission 

them to a capacity level below BART-eligibility. 

At the time of issue, this estimate reflects the fair market value for construction costs, 

based upon 2007 dollars, in the Greenbay, Wisconsin area. 

ESTIMATE APPROACH

The estimate is based on Jacobs providing Engineering, Construction Management and 

Procurement Services. 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

For the basis of the cost estimate, detailed engineering, procurement and construction 

activities are assumed be completed by December 31, 2007. 

WAGE RATES

The wage rates used in this estimate are composite, union all-in rates. The base 

journeyman rate ranges from $25.53 to $29.11. Jacobs established a crew mix for each 

craft, ranging from 97.98 % to 99.89 % of the base journeyman rate - see the All-In 

Wage Rate Sheet in the Estimate Detail Printout. Included in the wage rates are the 

following: 

• 81 - PAYROLL TAXES AND INSURANCE 

Payroll Taxes and Insurance are included at 33.6 % of bare craft labor. 

• 79 - CRAFT FRINGE BENEFITS 

Craft Fringe Benefits are included and range from 37.95 % to 62.01 % of bare craft 

labor. 

• 76 - TEMPORARY CONSTRUCTION FACILITIES 

Temporary Construction Facilities include Contractor’s office supplies, PC’s, copiers, 

postage, phones, Fed Ex, temporary sanitary facilities, mobilization, trash removal 

and temporary lights. These items are calculated at 7.5% of bare craft labor. 

• 83 & 84 - SMALL TOOLS AND CONSUMABLES 

Small tools are included in the estimate at 7.5 % of bare craft labor. Construction 

consumables are included in the estimate at 7.5 % of bare craft labor. 

• 87 - CONTRACTORS FIELD STAFF 

Field staff includes all contractors’ field support staff except for craft foremen which 

are included in the crew mix calculations. Contractors Field Staff is calculated at 25 

% to 35 % of bare craft labor based on the type of work being performed. 

• 85 - CONSTRUCTION EQUIPMENT RENTAL 

Construction equipment rental includes the contractors’ automotive equipment, 

general equipment and small cranes. This construction equipment cost is calculated 

at 25 % to 40 % of bare craft labor based on the discipline - concrete, steel, pipe, 

electrical, etc. - being supported - see the All-In Wage Rate Sheet in the Estimate 

Detail Printout for the percent used for each discipline. If required, a line item is listed 

in the estimate for situations that require large cranes not covered by the allowance 

carried in the rate. 

• 93 – CONTRACTOR’S HOME OFFICE 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

Contractor’s Home Office cost includes time for Project Manager, accounting, safety, 

quality control, etc. is included in the Contractor’s Fee. 

• 99 - CONTRACTOR’S FEE 

Contractor’s fee is included in the estimate at 10 % of contractor’s construction cost. 

• 75 - CONTRUCTION SUPPORT LABOR 

Construction Support Labor includes drug testing, safety training, fire watch, final 

cleanup, yard crews, etc. This cost is calculated as 20 % of bare craft labor. 

DIRECT COSTS

50 - MAJOR EQUIPMENT 

Vendor budget quotes were received for the Major Equipment. 

Pump and motor installation hours are from Jacobs Standards. Other equipment 

installation cost items are based on historical experience. 

Freight cost is included at 6 % of equipment cost. 

51 – DEMOLITION AND RELOCATION 

Demolition cost is factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 

 

53 - SITE IMPROVEMENTS 

Site Improvement costs are factored from installed process equipment cost but have 

been adjusted, as required, to reflect specific site requirements. 

54 – PILING 

Piling costs are factored from installed process equipment cost but have been adjusted, 

as required, to reflect specific site requirements. 

56 – CONCRETE 

Concrete costs are factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 

58 – STRUCTURAL STEEL 

Structural Steel costs are factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

62 – PIPING 

Piping costs are factored from installed process equipment cost but have been adjusted, 

as required, to reflect specific site requirements. 

63 – INSULATION

Insulation costs are factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 

64 – INSTRUMENTATION 

Instrumentation costs are factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 

65 – ELECTRICAL 

Electrical Costs are factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 

66 – PAINTING 

Painting costs are factored from installed process equipment cost but have been 

adjusted, as required, to reflect specific site requirements. 

INDIRECT COSTS

70 – SPARE PARTS 

An allowance for Spare Parts of 5 % of the process equipment cost is included. 

78 - PREMIUM TIME 

Premium Time is included based on the assumption that 100 % of the craft labor hours 

will be worked on a 50-hour week. 

XX - CRAFT PER DIEM 

Craft Per Diem is included at $7.00 per craft hour for all workers. 

81 - NON-PAYROLL TAXES, INSURANCE AND PERMITS 

Sales Tax is included at 6.5 % on equipment, materials and 6.5 % on 50 % of 

subcontract costs. 

88 - CONSTRUCTION MANAGEMENT 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

Construction Management is estimated at 4.5 % of Total Installed Cost. 

 

90 – ENGINEERING PROFESSIONAL SERVICES 

Detail Design Engineering is estimated at 10 % of Total Installed Cost. 

91 – OWNER’S COST 

Owner’s Cost is included at approximately 3 % of Total Installed Cost. 

96 – OUTSIDE CONSULTANT SERVICES 

An allowance of $100,000 is carried in the estimates for Outside Consultant Services. 

98 – CONTINGENCY 

Contingency is included in the estimate at 10 % of labor, equipment, material and 

subcontract costs. 

This Contingency is part of the estimated project cost and is to cover unusual weather 

conditions, productivity issues, increases in costs not covered by contractual provisions, 

delays in delivery of equipment or materials, etc. It does not cover cost of additional 

work or scope changes after the definition of the project has been frozen for the 

estimate. 

98 – ESCALATION 

Escalation is based on the assumption that all work will be completed by 

December 31, 2007. Escalation is included at 7 % on labor, 10 % on equipment, 10 % 

on all material except for concrete, steel, pipe, instrumentation and electrical material 

which is included at 15 % and 5 % on subcontract cost. 
Georgia Pacific – Green Bay, WI December 12, 2008 

Regional Haze/Boiler BART Program Rev. 2 

Feasibility Study Report and Estimate Jacobs Job No. 71BN3708 

ITEMS NOT INCLUDED

The following is a list of items not included in this estimate: 

Cost of Land 

Cost of borrowing money 

Cost of operating supplies 

Property taxes 

Hazardous materials handling or disposal 

All Risk Insurance 

Payment and Performance Bond 

Permits, Fees and Licenses 

ITEMS AFFECTING THE COST ESTIMATE

Items, which may change the estimated construction cost, include, but are not limited to: 

 

Modifications to the scope of work included in this estimate 

Above normal escalation in material costs due to market availability and demands 

Special phasing requirements 

Restrictive technical specifications 

Volume discounts on National agreements 

Sole source specifications of materials or products 

Bids delayed beyond the projected schedule 

Sales and Use Tax exemptions 

Labor disputes or difficulties