Emission Control Study –

Technology Cost Estimates

American Forest & Paper Association 

Washington, D.C.

BE&K Engineering

Birmingham, Alabama

September 2001

Contract 50-01-0089
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Table of Contents

1. Results....................................................................................... 6

2. Capital Cost Estimate Basis..................................................... 7

3. Operating Cost Estimate Basis ................................................ 8

4. NOx Control Good Technology Limit ....................................... 9

4.1. NDCE Kraft Recovery Furnace ..................................................................9

4.2. Lime Kiln – Route SOGs to new Thermal Oxidizer ..................................10

4.3. Coal or Coal / Wood Boiler.......................................................................10

4.4. Gas Boiler ................................................................................................11

4.5. Gas Turbine – Water Injection..................................................................12

4.6. Gas Turbine – Steam Injection.................................................................13

4.7. Oil Boiler...................................................................................................14

4.8. Wood Boiler..............................................................................................14

5. NOx Control Best Technology Limit....................................... 16

5.1. Technical Feasibility of SNCR and SCR Technologies ............................16

5.2. NDCE Kraft Recovery - SNCR Technology.............................................16

5.3. NDCE Kraft Recovery – SCR Technology ...............................................17

5.4. DCE Kraft Recovery – SNCR Technology ...............................................18

5.5. DCE Kraft Recovery – SCR Technology..................................................19

5.6. Lime Kiln – Low-NOx burners, & SCR ......................................................20

5.7. Coal or Coal / Wood Boiler – SCR ...........................................................21

5.8. Coal or Coal / Wood Boiler – Switch to Natural Gas ................................22

5.9. Gas Boiler ................................................................................................23

5.10. Gas Turbine..........................................................................................24

5.11. Oil Boiler...............................................................................................25

5.12. Wood Boiler - SNCR.............................................................................26

5.13. Wood Boiler – SCR (technical feasibility) .............................................27

6. SO2 Reduction – Good Technology Limits............................ 29
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6.1. NDCE Recovery Boiler.............................................................................29

6.2. DCE Kraft Recovery Furnace...................................................................30

6.3. Coal or Coal / Wood Boiler.......................................................................31

6.4. Oil Boiler...................................................................................................32

7. SO2 Reduction – Best Technology Limits ............................. 33

7.1. NDCE Recovery Boiler.............................................................................33

7.2. DCE Kraft Recovery Furnace...................................................................34

7.3. Coal or Coal / Wood Boiler.......................................................................35

7.4. Oil Boiler...................................................................................................35

8. Mercury Removal – Best Technology Limit .......................... 37

8.1. Coal or Coal / Wood Boiler.......................................................................37

8.2. Wood Boiler..............................................................................................38

9. Particulate Matter – Good Technology Limits....................... 40

9.1. NDCE Kraft Recovery Boiler – New Precipitator......................................40

9.2. NDCE Kraft Recovery Boiler – Rebuilt Precipitator..................................41

9.3. DCE Kraft Recovery Boiler.......................................................................41

9.4. Smelt Dissolving Tank..............................................................................42

9.5. Lime Kiln ..................................................................................................43

9.6. Coal Boiler................................................................................................44

9.7. Coal / Wood Boiler ...................................................................................45

9.8. Oil Boiler...................................................................................................45

9.9. Wood Boiler..............................................................................................46

10. Particulate Matter – Best Technology Limit .......................... 48

10.1. NDCE Kraft Recovery Boiler – New Precipitator ..................................48

10.2. NDCE Kraft Recovery Boiler – Rebuilt Precipitator ..............................49

10.3. DCE Kraft Recovery Boiler ...................................................................49

10.4. Smelt Dissolving Tank ..........................................................................50

10.5. Lime Kiln – New ESP............................................................................51

10.6. Lime Kiln – Upgraded ESP...................................................................52
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10.7. Coal Boiler – New ESP.........................................................................53

10.8. Coal Boiler – Rebuild Existing ESP ......................................................53

10.9. Coal / Wood Boiler - New .....................................................................54

10.10. Coal / Wood Boiler – Rebuild Existing ESP..........................................55

10.11. Oil Boiler...............................................................................................56

10.12. Wood Boiler..........................................................................................57

10.13. Wood Boiler – upgrade existing ESP....................................................58

11. Carbon Monoxide – Best Technology Limit.......................... 59

11.1. Coal or Coal / Wood Boiler ...................................................................59

11.2. Wood Boiler..........................................................................................60

12. HCl – Good Technology Limit ................................................ 61

12.1. Coal Boiler............................................................................................61

13. HCl – Best Technology Limit.................................................. 62

13.1. Coal Boiler............................................................................................62

14. VOC – Good Technology Limit............................................... 63

14.1. DCE Kraft Recovery Furnace ...............................................................63

14.2. Paper Machines....................................................................................64

14.3. Mechanical Pulping - TMP....................................................................65

14.4. Mechanical Pulping – Pressure Groundwood.......................................66

15. VOC – Best Technology Limit ................................................ 67

15.1. NDCE Kraft Recovery Furnace.............................................................67

15.2. DCE Kraft Recovery Furnace ...............................................................68

15.3. Paper Machines – Wet End..................................................................69

15.4. Paper Machines – Dry End...................................................................70

15.5. Mechanical Pulping – TMP with Existing Heat Recovery System.........71

15.6. Mechanical Pulping – TMP Without Existing Heat Recovery System...71

15.7. Mechanical Pulping – Pressurized Groundwood Without Existing Heat 

Recovery System ............................................................................................73

15.8. Mechanical Pulping – Atmospheric Groundwood .................................74
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16. Gasification ............................................................................. 76

16.1. Description of Technology ....................................................................76

16.2. Major Equipment ..................................................................................78

16.3. Basis for Estimate.................................................................................79

16.4. Capital Cost Estimate Assumptions......................................................79

16.5. Operating Cost Estimate Assumptions .................................................80

16.6. Impact on Emissions ............................................................................81

17. Industry – Wide Control Cost Estimates ............................... 83

17.1. General Assumptions ...........................................................................83

17.2. CO2 Emission Assumptions..................................................................86

17.3. Recovery Furnace Assumptions...........................................................86

17.4. Lime Kiln Assumptions .........................................................................90

17.5. Boiler and Turbine Assumptions...........................................................90

17.6. Coal Boiler Assumptions.......................................................................92

17.7. Coal / Wood Boiler Assumptions ..........................................................93

17.8. Gas Boiler Assumptions .......................................................................94

17.9. Gas Turbine Assumptions ....................................................................94

17.10. Oil Boiler Assumptions..........................................................................94

17.11. Wood-Fired Boiler Assumptions ...........................................................95

17.12. Paper Machine Assumptions................................................................96

17.13. Mechanical Pulping ..............................................................................97

18. Appendix.................................................................................. 98

18.1. MEANS and BE&K Labor Rate Factors by State..................................98

18.2. Net Downtime.....................................................................................101
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1. Results

See “AF&PA Emission Control Summary Sheet” Excel Spreadsheet
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2. Capital Cost Estimate Basis

The capital cost estimate is based upon similar projects that have been done within the 

last 10 years. The costs were escalated to 2001 dollars, where necessary. The capital 

cost estimates were divided into labor, materials, subcontracts, and equipment. The 0.6 

power conversion [Cost of Project A x (AF&PA rate / Project A)0.6] rate was used to 

adjust the estimated costs to the AF&PA sizing criteria for each control technology.

For some of the selected technologies – Mercury removal, VOC removal on paper 

machines, use of SCR on a non-gas fired combustion unit, use of SNCR on recovery 

furnace, and black liquor gasification - Research & Development costs were factored in. 

The R&D costs were assumed to be 0.5 to 1.5% of the direct costs – labor, materials, 

subcontract, and equipment. 

The labor cost includes the labor rate and construction indirects (i.e., equipment rental, 

small tool rentals, payroll, temporary facilities, home office and field office expenses, and 

profit). The material cost represents the cost for the materials of construction such as 

concrete, pipe, electrical conduit, steel, etc. The subcontract cost represents the cost for 

the specialty items such as siding, piping, field-erected tanks, cooling towers, etc. The 

equipment cost includes the cost for the control equipment, motors, instrumentation, etc. 

The major process equipment was based on quotes, recent projects, and similar projects. 

The labor work-hours and materials of construction were based on historical data and 

similar projects. The basis for all construction costs is for the Southeastern United States.

The engineering cost was based upon 15% of the total direct costs (i.e., sum of labor, 

materials, subcontract, and equipment costs). The contingency was based upon 20% of 

the total direct costs. The owner’s cost (i.e., corporate and mill engineering, training, 

builder’s risk insurance, checkout and start-up, etc.) was based upon 5% of the total 

direct costs. The construction management cost was base upon 5% of the total direct 

costs.

Although process or equipment downtime was considered for inclusion in the analysis, it 

was discarded as being of minimal impact. A net downtime analysis was conducted 

which initially assumed that the majority of the work would be done during scheduled 

downtime. Then the net downtime was computed which was the number of additional 

days past the scheduled downtime, which would be required to complete the work. With 

the exception of the conversion from a DCE to NDCE recovery furnace, the net 

downtime was between three and 5 days. Therefore, since process or equipment 

downtime is very mill specific, no inclusion was made for this short duration downtime. 

Appendix 18.2 contains BE&K’s estimate of net downtime for each technology

considered.

The capital cost estimate does not include the following:
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 Local, state, and federal permitting costs

 Sales tax (varies by both company directives, and by state)

 Extraordinary workman’s compensation costs (beyond scope of this study)

 Spares 

 Cost of capital

3. Operating Cost Estimate Basis

The annual operating costs were divided into the following categories: materials, 

chemicals, maintenance, energy, manpower, testing, and water wastewater, utilities, and 

fuel cost.

The materials category included the cost for, fabric filter media, SCR media, etc. The 

chemical category provides an estimate of the type and amount of chemical used for the 

pollution control technology. The maintenance category includes the estimated 

maintenance labor and maintenance material costs. The energy category was based upon 

the estimated installed horsepower utilizing a typical usage factor. The manpower 

category is an estimate of fraction of time existing operators would need to spend in 

operating the control equipment. No additional personnel were added for any of the 

technologies. However, the time spent by mill technology operating the new 

technologies was estimated. The testing category is an estimate of annual fees for testing. 

The water & wastewater category is an estimate of the additional water and subsequent 

wastewater costs for the given technology. The utility category includes the cost of the 

additional steam and compressed air used for a given technology. For the technology

case where fuel switching was employed, the fuel usage category contains the differential 

cost for either switching to low-sulfur oil or to natural gas.
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4. NOx Control Good Technology Limit

4.1. NDCE Kraft Recovery Furnace 

4.1.1. Description

Combustion controls for recovery furnaces utilizing addition of a quartenary air 

system yielding a NOx level in the stack gases of 80 ppm @ 8% oxygen. 

Equipment sized for a NDCE recovery furnace burning 3.7 x 106 (Mm) lb BLS 

per day.

4.1.2. Major Equipment

 Quartenary air fan

 Dampers

 Flow meters

 New CEMS

4.1.3. Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.6 x 106-lb black liquor solids per 

day. Project was estimated in 1999.

4.1.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

4.1.5. Operating Cost Estimate Assumptions

 Maintenance & materials – 1% of TIC

 Power75 kw

 Power usage factor: 70%

 Workhours: 0.75 hours /day

 Testing: $5,000 per year
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4.2. Lime Kiln – Route SOGs to new Thermal Oxidizer

4.2.1. Description

For those systems where the SOGs are incinerated in the limekiln, the SOGs will 

be rerouted to a new thermal oxidizer equipped with Low NOx controls and a 

caustic scrubber. The system is sized for a limekiln producing 240 tpd CaO.

4.2.2. Major Equipment

 Thermal oxidizer

 Caustic scrubber

4.2.3. Basis for Estimate

Southeastern Kraft mill which routed its NCGs to a thermal oxidizer. System was 

sized for 20,000 ACFM. The project was estimated in 1999.

4.2.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

4.2.5. Operating Cost Estimate Assumptions

 Caustic: 0 gpm (assumed that all the caustic-sulfur solution would be 

reclaimed)

 Maintenance labor & materials: 3.5% of TIC

 Power: 75 kw

 Power usage factor: 70%

 Workhours: 3 hours per day

 Testing: $5,000 per year

 Water: 35 gpm 

4.3. Coal or Coal / Wood Boiler

4.3.1. Description

Installation of Low NOx burners on a coal-fired boiler producing 300,000 lb/hr of 

steam. The maximum NOx emission rate is 0.3 lb/Mm Btu
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4.3.2. Major Equipment

 Low NOx burner assemblies

 Replace forced draft fan

 New CEMS

4.3.3. Basis for Estimate

Southeastern Kraft mill with 400,000 lb/hr steam coal / wood boiler. The project 

was estimated in 1999.

4.3.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

4.3.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials : 2% of TIC

 Power: 243 kw

 Power usage factor: 70%

 Workhours: 1.5 hours per day

 Testing: $5,000 per year.

4.4. Gas Boiler

4.4.1. Description

Low NOx burners and flue gas recirculation for a natural gas-fired boiler 

producing 120,000 lb/hr of steam. The maximum NOx emission rate is 

0.05 lb/Mmbtu as a 30-day average.

4.4.2. Major Equipment

 Low NOx burner assemblies

 Replace forced draft fan

 New CEMS

 Flue gas recirculation fan
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4.4.3. Basis for Estimate

Southeastern Kraft mill with a multi-fuel boiler producing 420,000 lb/hr of steam. 

The project was estimated in 1999.

4.4.4. Capital Cost Estimate Assumption

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

4.4.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials : 3% of TIC

 Power: 176 kw 

 Power usage factor: 70%

 Workhours: 1.5 hours per day

 Testing: $5,000 per year.

4.5. Gas Turbine – Water Injection

4.5.1. Description

Installation of water injection system for NOx emission control to reduce the NOx

emissions to 25 ppm @ 15% oxygen for a 30-day average. The system was sized 

for a 30 MW gas turbine.

4.5.2. Major Equipment

 High pressure water pump

 Water injection system

4.5.3. Basis for Estimate

Budget quotation from Alpha Power Systems for a Swirlflash technology system 

for NOx reduction. The project costs are in 2001 dollars.

4.5.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.

4.5.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials : 2% of TIC

 Power: 2 kw
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 Power usage factor: 70%

 Workhours: 1.5 hours per day

 Testing: $5,000 per year.

 Water: 10 gpm

4.6. Gas Turbine – Steam Injection

4.6.1. Description

Installation of steam injection system for NOx emission control to reduce the NOx

emissions to 25 ppm @ 15% oxygen for a 30-day average. The system was sized 

for a 30 MW gas turbine.

4.6.2. Major Equipment

 High pressure water pump

 Water injection system

4.6.3. Basis for Estimate

Budget quotation from Alpha Power Systems for a Swirlflash technology system 

for NOx reduction. The project costs are in 2001 dollars.

4.6.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

4.6.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials : 2% of TIC

 Power: 2 kw

 Power usage factor: 70%

 Workhours: 1.5 hours per day

 Testing: $5,000 per year.

 Water: 4.76 gpm

 Steam: 2381 lb/hr 
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4.7. Oil Boiler

4.7.1. Description

Low NOx burners for oil-fired boiler producing 135,000 lb/hr of steam. The 

maximum NOx emission rate is 0.2 lb/Mm Btu as a 30-day average.

4.7.2. Major Equipment

 Low NOx burner assemblies

 Replace forced draft fan

 New CEMS

4.7.3. Basis for Estimate

Southeastern Kraft mill with a multi-fuel boiler producing 420,000 lb/hr of steam. 

The project was estimated in 1999.

4.7.4. Capital Cost Estimate Assumption

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

4.7.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 151 kw

 Power usage factor: 70%

 Workhours: 1.5 hours per day

 Testing: $5,000 per year

4.8. Wood Boiler

4.8.1. Description

Upgrade combustion controls and FD fan. The NOx emissions will be reduced 

from 0.33 lb/Mm Btu to 0.25 lb/Mm Btu for a 3-hour limit.

4.8.2. Major Equipment

 Upgrade FD fan

 Replace combustion dampers and controls
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 New tertiary air nozzles

 New cameras

 New CEM

 Upgrade DCS controls

4.8.3. Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.

4.8.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

4.8.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 298 kw

 Power usage factor: 70%

 Workhours: 1.5 hours per day

 Testing: $5,000
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5. NOx Control Best Technology Limit

5.1. Technical Feasibility of SNCR and SCR Technologies

There are no SNCR units known to be operating for NOx control in a recovery boiler. 

While SNCR was attempted on one recovery furnace in Sweden for a short period, the 

unit no longer operates and the technology is not considered to be proven. The major 

concern with SNCR is the ability to add urea in the correct flue temperature window to 

ensure effectiveness and minimal slip (i.e., urea/ammonia carryover with the flue gas). 

Recovery boilers are operated over a wide range of conditions, which affect both the 

amount of urea added and the location of the addition. Other concerns include safety 

(i.e., risk of urea solution reaching the floor and causing a smelt-water explosion), and 

maintenance of equipment (i.e., atomizing nozzles) in a highly corrosive environment. 

There are financial incentives to reduce NOx emissions in Sweden and therefore, it would 

be expected that either SCR or SNCR would be used extensively if they were costeffective. Currently only combustion controls are used to reduce NOx.

The SCR technology presents unique problems with respect to potential poisoning of the 

catalyst from the alkali dust from the recovery boiler. To minimize this the SCR would 

need to be place downstream of the ESP, which means that the flue gas must be reheated 

before application of the SCR. This adds unnecessary cost – both capital and operating. 

5.2. NDCE Kraft Recovery - SNCR Technology

5.2.1. Description

Selective non-catalytic reduction system for NOx control to achieve a maximum 

emission of 40 ppm @ 8% oxygen or achieve a 50% reduction using a 30-day

average. The system is sized for a NDCE recovery furnace burning 3.7-Mm lb 

BLS per day.

5.2.2. Major Equipment

 Urea storage 

 Metering pump

 Urea injection system

5.2.3. Basis for Estimate

A Scandinavian recovery furnace firing at a 3.5-Mm lb BLS/day rate. The project 

was estimated in 1990. The inlet concentration was assumed 60 ppm with an 

outlet concentration of 24 ppm. 
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5.2.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 R&D cost: 1.0% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.2.5. Operating Cost Estimate Assumptions

 Urea: 256 TPY

 Maintenance labor & materials: 3.5% of TIC

 Power: 16 kw

 Power usage factor: 70%

 Workhours: 3 hours per day

 Testing: $5,000 per year

 Water: 3 gpm

5.3. NDCE Kraft Recovery – SCR Technology

5.3.1. Description

Installation of a SCR NOx control system in a NDCE recovery furnace burning 

3.7 x 106 (Mm) lb BLS per day. The target is 40 ppm @ 8% oxygen or 50% 

reduction) for a 30-day average.

5.3.2. Major Equipment

 SCR reactor

 Duct burner

 CEM

5.3.3. Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999. The inlet NOx is estimated to be 92 ppm and the outlet NOx is 

estimated to be 18 ppm. 

5.3.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars
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 R&D cost: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.3.5. Operating Cost Estimate Assumptions

 Materials – catalyst: 1072 ft3per yr. 

 Chemicals – urea: 377 tons per year

 Maintenance: 2% of TIC

 Power: 547 kw

 Power usage factor: 70%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 7 gpm

 Steam: 1,830 lb/hr

 Compressed air: 39 cfm

5.4. DCE Kraft Recovery – SNCR Technology

5.4.1. Description

Selective non-catalytic reduction system for NOx control to achieve 50% 

reduction of the NOx. The system is sized for a DCE recovery furnace burning 

1.7-Mm lb BLS/day.

5.4.2. Major Equipment

 Urea storage 

 Metering pump

 Urea injection system

5.4.3. Basis for Estimate

A Scandinavian recovery furnace firing at a 3.5-Mm lb BLS/day rate. The project 

was estimated in 1990. The inlet concentration was assumed 60 ppm with an 

outlet concentration of 30 ppm. 
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5.4.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 R&D cost: 1.0% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.4.5. Operating Cost Estimate Assumptions

 Urea: 118 TPY

 Maintenance labor & materials: 3.5% of TIC

 Power: 16 kw

 Power usage factor: 70%

 Workhours: 3 hours per day

 Testing: $5,000 per year

 Water: 3 gpm

5.5. DCE Kraft Recovery – SCR Technology

5.5.1. Description

Installation of a SCR NOx control system in a DCE recovery furnace burning 1.7 

x 106 (Mm) lb BLS per day. The target is 40 ppm @ 8% oxygen or 50% 

reduction) for a 30-day average.

5.5.2. Major Equipment

 SCR reactor

 Duct burner

 CEM

5.5.3. Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999. The inlet NOx is estimated to be 67 ppm and the outlet NOx is 

estimated to be 13 ppm. 

5.5.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars
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 R&D cost: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.5.5. Operating Cost Estimate Assumptions

 Materials – catalyst: 697 ft3per yr. 

 Chemicals – urea: 245 tons per year

 Maintenance: 2% of TIC

 Power: 355 kw

 Power usage factor: 70%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 4 gpm

 Steam: 1,190 lb/hr

 Compressed air: 26 cfm

5.6. Lime Kiln – Low-NOx burners, & SCR

5.6.1. Description

Install Low NOx burners and SCR systems in lime kiln, which produces 240 tpd 

CaO. SCR can be applied at the limekiln provided the flue gas temperature is 

controlled and the dust is removed prior to application.

5.6.2. Major Equipment

 SCR reactor

 Low NOx burners

 Upgrade to forced draft fan

 ID fan

5.6.3. Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.
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5.6.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 R&D cost: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.6.5. Operating Cost Estimate Assumptions

 Materials – catalyst: 323 ft3per yr. 

 Chemicals – urea: 113.5 tons per year

 Maintenance: 2% of TIC

 Power: 165 kw

 Power usage factor: 70%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 1.97 gpm

 Steam: 552 lb/hr

 Compressed air: 12 cfm

5.7. Coal or Coal / Wood Boiler – SCR

5.7.1. Description

Installation of a SCR system on a coal or coal/wood boiler producing 300,000 

lb/hr of steam. The maximum NOx emission rate is 0.17 lb/Mm Btu for a 30-day

average.

5.7.2. Major Equipment

 SCR reactor

 Low NOx burners

 Upgrade to forced draft fan

 ID fan
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5.7.3. Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.

5.7.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 R&D cost: 0.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.7.5. Operating Cost Estimate Assumptions

 Materials – catalyst: 1219 ft3per yr. 

 Chemicals – urea: 428 tons per year

 Maintenance: 2% of TIC

 Power: 622 kw

 Power usage factor: 70%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 7.43 gpm

 Steam: 2082 lb/hr

 Compressed air: 45 cfm

5.8. Coal or Coal / Wood Boiler – Switch to Natural Gas

5.8.1. Description

Switch from coal to natural gas for a coal or coal/wood boiler producing 300,000 

lb/hr of steam. 

5.8.2. Major Equipment

 New burners

 Natural gas reducing station
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5.8.3. Basis for Estimate

Southeastern Kraft mill which switched from coal to natural gas for a boiler 

producing 420,000 lb/hr of steam. The project was estimated in 1999.

5.8.4. Capital Cost Estimate Assumptions

 Natural gas delivered at 700 psig to property line of plant.

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

5.8.5. Operating Cost Estimate Assumptions

 Maintenance: 1% of TIC

 Power: N/A

 Workhours: 1.5 hr per day

 Testing: $5,000 per year

5.9. Gas Boiler

5.9.1. Description

Installation of SCR on natural gas-fired boiler producing 120,000 lb/hr of steam. 

The maximum NOx emission rate is 0.015 lb/Mm Btu utilizing a 30-day average.

5.9.2. Major Equipment

 SCR reactor

 Low NOx burners

 Upgrade to forced draft fan

 ID fan

5.9.3. Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.

5.9.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars
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5.9.5. Operating Cost Estimate Assumptions

 Materials – catalyst: 464 ft3per yr. @ $350 per ft3

 Chemicals – urea: 163 tons per year

 Maintenance: 2% of TIC

 Power: 237 kw

 Power usage factor: 70%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 2.83 gpm

 Steam: 793 lb/hr

 Compressed air: 17 cfm

5.10. Gas Turbine

5.10.1.Description

Installation of SCR system for a 30-MW natural gas turbine yielding an emission 

level of 5 ppm @15% oxygen for a 30-day average representing a 95% NOx

reduction.

5.10.2.Major Equipment

 SCR reactor

 Low NOx burners

 Upgrade to forced draft fan

 ID fan

5.10.3.Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.

5.10.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars
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5.10.5.Operating Cost Estimate Assumptions

 Materials – catalyst: 298 ft3per yr. @ $350 per ft3

 Chemicals – urea: 105 tons per year

 Maintenance: 2% of TIC

 Power: 418 kw

 Power usage factor: 70%

 Workhours: 3 hr per day

 Testing: $5,000 per year

 Water: 5 gpm

 Steam: 1400 lb/hr

 Compressed air: 30 cfm

5.11. Oil Boiler

5.11.1.Description

Installation of SCR system on oil-fired boiler producing 135,000 lb/hr of steam. 

The maximum NOx emission rate is 0.04 lb/Mmbtu for a 30-day average or a 90% 

reduction.

5.11.2.Major Equipment

 SCR reactor

 Low NOx burners

 Upgrade to forced draft fan

 ID fan

5.11.3.Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.

5.11.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars
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 R&D cost: 0.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.11.5.Operating Cost Estimate Assumptions

 Materials – catalyst: 679 ft3per yr. @ $350 per ft3

 Chemicals – urea: 238 tons per year

 Maintenance: 2% of TIC

 Power: 346 kw

 Power usage factor: 70%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 4.14 gpm

 Steam: 1159 lb/hr

 Compressed air: 25 cfm

5.12. Wood Boiler - SNCR

5.12.1.Description

Installation of SNCR system on a wood boiler producing 300,000 lb/hr of steam. 

The maximum NOx emission rate is 0.20 lb/ Mmbtu and represents a 40% 

reduction.

5.12.2.Major Equipment

 Urea storage and metering system

 Urea Injectors

 Boiler Modifications

 Control Enhancements

5.12.3.Basis for Estimate

An Atlantic states Kraft mill with a multi-fuel boiler producing 400,000 lb/hr of 

steam.
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5.12.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

5.12.5.Operating Cost Estimate Assumptions

 Chemical – urea 165 tons per year

 Maintenance labor & materials: 3.5% of TIC

 Power: 13 kw

 Power usage factor: 80%

 Workhours: 3 hours per day

 Water: 3 gpm

5.13. Wood Boiler – SCR (technical feasibility)

5.13.1.Description

Installation of a SCR system on a wood-fired boiler capable of producing 300,000 

lb/hr of steam. The maximum NOx emission rate is 0.025 lb/Mmbtu with a 85% 

reduction anticipated. The SCR is feasible provided the temperature of the flue 

gas is controlled.

5.13.2.Major Equipment

 SCR reactor

 Low NOx burners

 Upgrade to forced draft fan

 ID fan

5.13.3.Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler. The project was 

estimated in 1999.

5.13.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars
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 R&D cost: 0.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

5.13.5.Operating Cost Estimate Assumptions

 Materials – catalyst: 821 ft3per yr. @ $350 per ft3

 Chemicals – urea: 287 tons per year

 Maintenance: 2% of TIC

 Power: 420 kw

 Power usage factor: 75%

 Workhours: 28.6 hr per day

 Testing: $5,000 per year

 Water: 5 gpm

 Steam: 1403 lb/hr

 Compressed air: 30 cfm
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Phase I Pulp & Paper Industry

September 20, 2001

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6. SO2 Reduction – Good Technology Limits

6.1. NDCE Recovery Boiler

6.1.1. Description

Installation of a chemical scrubber to achieve sulfur dioxide (SO2) level in stack 

gas of 50 ppm @ 8% oxygen. The system is sized for a NDCE recovery furnace 

burning 3.7-Mm lb BLS per day.

6.1.2. Major Equipment

 Scrubber tower

 Booster fan

 Recirculation pump

 Caustic pump

6.1.3. Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106-lb black liquor solids per 

day. Project was estimated in 1998.

6.1.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

6.1.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 1631 kw 

 Power usage factor: 70%

 Chemical: 1.3 gpm 50% caustic soda

 Water: 148 gpm

 Wastewater: 15 gpm

 Workhours: 3 hours per day

 Testing: $5,000 per year
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6.2. DCE Kraft Recovery Furnace

6.2.1. Description

Installation of a chemical scrubber to achieve sulfur dioxide (SO2) level in stack 

gas of 50 ppm @ 8% oxygen. The system is sized for a DCE recovery furnace 

burning 1.7-Mm lb BLS per day.

6.2.2. Major Equipment

 Scrubber tower

 Booster fan

 Recirculation pump

 Oxidizer blower

 Caustic pump

6.2.3. Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106lb black liquor solids per 

day. Project was estimated in 1998.

6.2.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

6.2.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 1023 kw

 Power usage factor: 70%

 Chemical: 0.82 gpm 50% caustic soda

 Water: 68 gpm

 Wastewater: 6.8 gpm

 Workhours: 3 hours per day

 Testing: $5,000 per year
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6.3. Coal or Coal / Wood Boiler

6.3.1. Description

Installation of a caustic scrubber for a coal or coal / wood boiler producing 

300,000 lb/hour of steam. The SO2 level would be reduced by 50% producing a 

maximum emission of 0.6 lb / Mm Btu.

6.3.2. Major Equipment

 Scrubber tower

 Recirculation pump

 Booster fan

 Caustic feed system

6.3.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of steam. 

The project was estimated in 1992. 

6.3.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

6.3.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 1142 kw

 Power usage factor: 70% 

 Chemical: 0.6 gpm 50% caustic soda

 Water: 143 gpm

 Wastewater: 14 gpm

 Workhours: 3 hours per day

 Testing: $5,000 per year
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Cost Estimate & Industry-Wide Model 

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6.4. Oil Boiler

6.4.1. Description

Installation of caustic scrubber on a oil-fired boiler producing 135,000 lb/hr of 

steam. The SO2 emission will be reduced by 50% with a maximum emission rate 

of 0.4 lb/Mm Btu for a 30-day average.

6.4.2. Major Equipment

 Scrubber tower

 Booster fan

 Caustic feed system

6.4.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of steam. 

The project was estimated in 1992. 

6.4.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

6.4.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.0% of TIC

 Power: 555 kw 

 Power usage factor: 70%

 Chemical: 0.26 gpm 50% caustic soda

 Water: 42.9 gpm

 Wastewater: 4.3 gpm

 Workhours: 3 hours per day

 Testing: $5,000 per year
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

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7. SO2 Reduction – Best Technology Limits

7.1. NDCE Recovery Boiler

7.1.1. Description

Installation of a caustic scrubber to achieve sulfur dioxide (SO2) level in stack gas 

of 10 ppm @ 8% oxygen. The system is sized for a NDCE recovery furnace 

burning 3.7 Mm lb BLS per day.

7.1.2. Major Equipment

 Scrubber tower

 Booster fan

 Recirculation pump

 Caustic pump

7.1.3. Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106lb black liquor solids per 

day. Project was estimated in 1998.

7.1.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

7.1.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 1631 kw 

 Power usage factor: 80%

 Chemical: 1.5 gpm 50% caustic soda

 Water: 148 gpm

 Wastewater: 15 gpm

 Work hours: 3 hours / day

 Testing: $5,000 per year
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Phase I Pulp & Paper Industry

September 20, 2001

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7.2. DCE Kraft Recovery Furnace

7.2.1. Description

Installation of a caustic scrubber to achieve sulfur dioxide (SO2) level in stack gas 

of 10 ppm @ 8% oxygen. The system is sized for a DCE recovery furnace 

burning 1.7 Mm lb BLS per day.

7.2.2. Major Equipment

 Scrubber tower

 Booster fan

 Recirculation pump

 Oxidizer blower

 Caustic pump

7.2.3. Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106lb black liquor solids per 

day. Project was estimated in 1998.

7.2.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

7.2.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 1023 kw

 Power usage factor: 80% 

 Chemical: 0.94 gpm 50% caustic soda

 Water: 68 gpm

 Wastewater: 6.8 gpm

 Work hours: 3 hours / day

 Testing: $5,000 per year
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

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7.3. Coal or Coal / Wood Boiler

7.3.1. Description

Installation of a caustic scrubber for a coal or coal / wood boiler producing 

300,000 lb/hour of steam. The SO2 level would be reduced by 90% producing a 

maximum emission of 0.17 lb / Mm Btu for a 30-day average.

7.3.2. Major Equipment

 Scrubber tower

 Booster fan

 Caustic feed system

7.3.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of steam. 

The project was estimated in 1992. 

7.3.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

7.3.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 1523 kw 

 Power usage factor: 80%

 Chemical: 1.1 gpm 50% caustic soda

 Water: 143 gpm

 Wastewater: 14 gpm

 Workhours: 3 hours per day

 Testing: $5,000 per year

7.4. Oil Boiler

7.4.1. Description

Installation of caustic scrubber on a oil-fired boiler producing 135,000 lb/hr of 

steam. The SO2 emission will be reduced by 90% with a maximum emission rate 

of 0.08 lb/Mm Btu for a 30-day average.
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7.4.2. Major Equipment

 Scrubber tower

 Booster fan

 Caustic feed system

7.4.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of steam. 

The project was estimated in 1992. 

7.4.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

7.4.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.0% of TIC

 Power: 740 kw 

 Power usage factor: 80%

 Chemical: 0.34 gpm 50% caustic soda

 Water: 42.9 gpm

 Wastewater: 4.3 gpm

 Workhours: 3 hours per day

 Testing: $5,000 per year
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

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8. Mercury Removal – Best Technology Limit

8.1. Coal or Coal / Wood Boiler

8.1.1. Description

Installation of a spray dryer absorber fabric filter dry scrubbing system with 

carbon injection for a coal or coal/wood-fired boiler producing 300,000 lb/hr of 

steam. The Hg emission level is anticipated to be lowered from 16 lb/1012 Btu to 

8 lb/1012 Btu, representing a 50% reduction.

8.1.2. Major Equipment

 Fabric filter modules

 Lime storage and metering system

 Activated carbon storage and metering system

 Blower

 Atomizing air compressor

 Fabric filter scrubbing system

8.1.3. Basis for Estimate

A budget quotation from WAPC for a spray dryer absorber fabric filter dry

scrubbing system with carbon injection for a coal-fired boiler.

8.1.4. Capital Cost Estimate Assumptions

 R&D cost: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

8.1.5. Operating Cost Estimate Assumptions

 Chemicals – activated carbon: 0.08 tons per day

 Maintenance labor & materials: 5% of TIC

 Chemicals – pebble lime: 3750 lb/hr

 Power: 327 kw

 Power usage factor: 75%

 Workhours: 3 hours per day
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 Testing: $5,000 per year

 Water: 64 gpm

 Wastewater: 20 gpm

 Incremental waste disposal: 15,780 tpy of carbon and lime

8.2. Wood Boiler 

8.2.1. Description

Installation of a spray dryer absorber fabric filter dry scrubbing system with 

carbon injection for a wood-fired boiler producing 300,000 lb/hr of steam. The 

Hg emission level is anticipated to be lowered from 0.572 lb/1012 Btu to 

0.286 lb/1012 Btu, representing a 50% reduction. 

8.2.2. Major Equipment

 Fabric filter modules

 Lime storage and metering system

 Activated carbon storage and metering system

 Blower

 Atomizing air compressor

 Fabric filter scrubbing system

8.2.3. Basis for Estimate

A budget quotation from WAPC for a spray dryer absorber fabric filter dry

scrubbing system with carbon injection for a wood fired boiler.

8.2.4. Capital Cost Estimate Assumptions

 R&D cost: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

8.2.5. Operating Cost Estimate Assumptions

 Chemicals – activated carbon: 7.923 lb per day

 Maintenance labor & materials: 5% of TIC

 Chemicals – pebble lime: 375 lb/hr

 Power: 262 kw
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 Power usage factor: 70%

 Workhours: 3 hours per day

 Testing: $5,000 per year

 Water: 90 gpm

 Wastewater: 28 gpm

 Incremental waste disposal: 1,576 tpy of carbon and lime
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

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9. Particulate Matter – Good Technology Limits

9.1. NDCE Kraft Recovery Boiler – New Precipitator

9.1.1. Description

Installation of an electrostatic precipitator capable of achieving 0.044 gr/dscf @ 

8% oxygen of particulate matter. The system is sized for a NDCE recovery 

furnace firing 3.7 Mm lb BLS per day

9.1.2. Major Equipment

 New electrostatic precipitator

 New concrete stack acid-brick lined

 Modification to existing ID fan

 Conveyors

 Dampers

9.1.3. Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106lb black liquor solids 

per day. Project estimated in 2000.

9.1.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP at 3.7 x 

106 lb black liquor solids per day.

 Costs escalated to 2001

9.1.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 2023 kw 

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

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9.2. NDCE Kraft Recovery Boiler – Rebuilt Precipitator

9.2.1. Description

ESP upgrade by addition of two parallel fields so that system is capable of 

achieving 0.044 gr/dscf @ 8% oxygen of particulate matter. The system is sized 

for a NDCE recovery furnace firing 3.7 Mm lb BLS per day

9.2.2. Major Equipment

 Modification to existing ESP

 Modifications to ash handling system

9.2.3. Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.70 x 106lb black liquor solids 

per day. Project estimated in 1999.

9.2.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP at 3.7 x 

106 lb black liquor solids per day.

 Costs escalated to 2001

9.2.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 2% of TIC cost

 Power –377 kw 

 Power usage factor: 70%

 Workhours – 1.5 hours per day

 Testing - $5,000 per year

9.3. DCE Kraft Recovery Boiler

9.3.1. Description

Installation of a electrostatic precipitator capable of achieving 0.044 gr/SDCF @ 

8% oxygen of particulate matter. The system is sized for a DCE recovery furnace 

firing 1.7 Mm lb BLS per day.

9.3.2. Major Equipment

 New electrostatic precipitator

 New concrete stack acid-brick lined

 Modification to existing ID fan
AF&PA Emission Control Study –

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 Conveyors

 Dampers

9.3.3. Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106lb black liquor solids 

per day. Project estimated in 2000.

9.3.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP at 1.7 x 

106 lb black liquor solids per day.

 Costs escalated to 2001

9.3.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 1268 kw 

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

9.4. Smelt Dissolving Tank

9.4.1. Description

Installation of a scrubber on a smelt dissolving tank capable of achieving a 

particulate matter emission rate of 0.2 lb/ton BLS. The system is sized for a 

recovery furnace firing 3.7 Mm lb BLS per day.

9.4.2. Major Equipment

 New scrubber

 Fan

 Recirculation pump

9.4.3. Basis for Estimate

Atlantic states Kraft mill with a recovery furnace firing 2 Mm lb BLS per day. 

The project was estimated in 1997.
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9.4.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for a smeltdissolving tank scrubber at a recovery furnace firing rate of 3.7 x 106 lb black 

liquor solids per day. Costs escalated to 2001

9.4.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 2% of TIC cost

 Power – 287 kw

 Power usage factor: 70% 

 Workhours – 1.5 hours per day

 Testing - $5,000 per year

9.5. Lime Kiln

9.5.1. Description

Installation of an electrostatic precipitator on a lime kiln processing 240 TPD of 

CaO. The emission rate for particulate matter is 0.064 gr/DSCF @ 10% oxygen.

9.5.2. Major Equipment

 New ESP

 Penthouse blower

 Hopper with screw conveyor

 Bucket elevator

 ID fan

 New stack

9.5.3. Basis for Estimate

Southeastern Kraft mill with a lime kiln capable of processing 540 TPD of CaO. 

The project was estimated in 2001.

9.5.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

lime kiln processing 240 tpd of CaO.

9.5.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost
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 Power 187 kw

 Power usage factor: 70%

 Workhours – 2.25 hours per day

 Testing - $5,000 per year

9.6. Coal Boiler

9.6.1. Description

Installation of electrostatic precipitator in a coal boiler producing 300,000 lb/hr of 

steam. The particulate emission rate is 0.065 lb / Mm Btu.

9.6.2. Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

9.6.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

9.6.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

9.6.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 1331 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 39 tpy of ash
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9.7. Coal / Wood Boiler

9.7.1. Description

Installation of electrostatic precipitator in a coal or coal / wood boiler producing 

300,000 lb/hr of steam. The particulate emission rate is 0.065 lb / Mm Btu.

9.7.2. Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

9.7.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

9.7.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

9.7.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 1331 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 94 tpy of ash

9.8. Oil Boiler

9.8.1. Description

The switch to low-sulfur fuel oil to achieve lower particulate matter emission

rates from a oil-fired boiler capable of producing 135,000 lb/hr of steam.
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9.8.2. Major Equipment

 Oil gun nozzles

 Flow meters

9.8.3. Basis for Estimate

Southeastern Kraft mill which switched from No. 6 to No. 2 fuel oil in a oil-fired 

boiler producing 135,000 lb/hour of steam. The project was estimated in 1999.

9.8.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 135,000 lb/hr of steam.

 Costs escalated to 2001

9.8.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – not applicable

 Workhours – not applicable

 Testing - $5,000 per year

 Fuel costs: $2.86 million per year

9.9. Wood Boiler

9.9.1. Description

Removal of existing scrubber and installation of electrostatic precipitator in a 

wood boiler producing 300,000 lb/hr of steam. The particulate emission rate is 

0.065 lb / Mm Btu.

9.9.2. Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

9.9.3. Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.
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9.9.4. Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

9.9.5. Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 911 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Water – (200) gpm savings from elimination of scrubber

 Wastewater – (20) gpm savings from elimination of scrubber

 Incremental waste disposal: 551 tpy of ash
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10. Particulate Matter – Best Technology Limit

10.1. NDCE Kraft Recovery Boiler – New Precipitator

10.1.1.Description

Installation of an electrostatic precipitator capable of achieving 0.015 gr/dscf @ 

8% oxygen. The system would be installed in a recovery furnace burning 3.7 Mm 

lb BLS per day.

10.1.2.Major Equipment

 New electrostatic precipitator

 New concrete stack acid-brick lined

 Modification to existing ID fan

 Conveyors

 Dampers

10.1.3.Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106lb black liquor solids 

per day. Project estimated in 2000.

10.1.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP at 3.7 x 

106 lb black liquor solids per day.

 Costs escalated to 2001

10.1.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 2528 kw 

 Power usage factor: 80%

 Workhours – 3 hours per day

 Testing - $5,000 per year
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10.2. NDCE Kraft Recovery Boiler – Rebuilt Precipitator

10.2.1.Description

ESP upgrade by addition of two parallel fields so that system is capable of 

achieving 0.015 gr/dscf @ 8% oxygen of particulate matter. The system is sized 

for a NDCE recovery furnace firing 3.7 Mm lb BLS per day

10.2.2.Major Equipment

 Modification to existing ESP

 Modifications to ash handling system

10.2.3.Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.70 x 106lb black liquor solids 

per day. Project estimated in 1999.

10.2.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP at 3.7 x 

106 lb black liquor solids per day.

 Costs escalated to 2001

10.2.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 2% of TIC cost

 Power –411 kw 

 Power usage factor: 70%

 Workhours – 1.5 hours per day

 Testing - $5,000 per year

10.3. DCE Kraft Recovery Boiler

10.3.1.Description

Installation of a electrostatic precipitator capable of achieving 0.015 gr/SDCF @ 

8% oxygen of particulate matter. The system is sized for a DCE recovery furnace 

firing 1.7 Mm lb BLS per day.

10.3.2.Major Equipment

 New electrostatic precipitator

 New concrete stack acid-brick lined

 Modification to existing ID fan
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 Conveyors

 Dampers

10.3.3.Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106lb black liquor solids

per day. Project estimated in 2000.

10.3.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP at 1.7 x 

106 lb black liquor solids per day.

 Costs escalated to 2001

10.3.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 1585 kw

 Power usage factor: 80% 

 Workhours – 3 hours per day

 Testing - $5,000 per year

10.4. Smelt Dissolving Tank

10.4.1.Description

Installation of a scrubber on a smelt dissolving tank capable of achieving a 

particulate matter emission rate of 0.12 lb/ton BLS. The system is sized for a 

recovery furnace firing 3.7 Mm lb BLS per day.

10.4.2.Major Equipment

 New scrubber

 Fan

 Recirculation pump

10.4.3.Basis for Estimate

Atlantic states Kraft mill with a recovery furnace firing 2 Mm lb BLS per day. 

The project was estimated in 1997.
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10.4.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for a smeltdissolving tank scrubber at a recovery furnace firing rate of 3.7 x 106 lb black 

liquor solids per day.

 Costs escalated to 2001

10.4.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 2% of TIC cost

 Power – 315 kw 

 Power usage factor: 80%

 Workhours – 1.5 hours per day

 Testing - $5,000 per year

10.5. Lime Kiln – New ESP

10.5.1.Description

Installation of an electrostatic precipitator on a lime kiln processing 240 TPD of 

CaO. The emission rate for particulate matter is 0.01 gr/DSCF @ 10% oxygen.

10.5.2.Major Equipment

 New ESP

 Penthouse blower

 Hopper with screw conveyor

 Bucket elevator

 ID fan

 New stack

10.5.3.Basis for Estimate

Southeastern Kraft mill with a lime kiln capable of processing 540 TPD of CaO. 

The project was estimated in 2001.

10.5.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

lime kiln processing 240 TPD of CaO.
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10.5.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 233 kw

 Power usage factor: 80%

 Workhours – 2.25 hours per day

 Testing - $5,000 per year

10.6. Lime Kiln – Upgraded ESP

10.6.1.Description

Addition of a single electric field to an existing electrostatic precipitator on a lime 

kiln processing 240 TPD of CaO. The emission rate for particulate matter is 0.01 

gr/DSCF @ 10% oxygen.

10.6.2.Major Equipment

 Modifications to existing ESP

 Ductwork modifications

10.6.3.Basis for Estimate

Southeastern Kraft mill with a lime kiln capable of processing 540 TPD of CaO. 

The project was estimated in 2001.

10.6.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

lime kiln processing 240 TPD of CaO

10.6.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 1% of TIC cost

 Power – 100 kw

 Power usage factor: 70%

 Workhours – 1.5 hours per day

 Testing - $5,000 per year
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10.7. Coal Boiler – New ESP

10.7.1.Description

Installation of electrostatic precipitator in a coal boiler producing 300,000 lb/hr of 

steam. The particulate emission rate is 0.04 lb / Mm Btu.

10.7.2.Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

10.7.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

10.7.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

10.7.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 1664 kw

 Power usage factor: 80%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 77 tpy of ash

10.8. Coal Boiler – Rebuild Existing ESP

10.8.1.Description

Addition of a single electric field in two chambers to an electrostatic precipitator 

in a coal boiler producing 300,000 lb/hr of steam. The particulate emission rate is 

0.04 lb / Mm Btu.
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10.8.2.Major Equipment

 Modifications to existing ESP

 Ductwork modifications

10.8.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

10.8.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

10.8.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 1% of TIC cost

 Power – 550 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 38 tpy of ash

10.9. Coal / Wood Boiler - New

10.9.1.Description

Installation of electrostatic precipitator in a coal or coal / wood boiler producing 

300,000 lb/hr of steam. The particulate emission rate is 0.04 lb / Mm Btu.

10.9.2.Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower
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10.9.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

10.9.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

10.9.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power 1331 kw

 Power usage factor: 80%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 137 tpy of ash

10.10. Coal / Wood Boiler – Rebuild Existing ESP

10.10.1.Description

Addition of single electric field in two chambers to an existing electrostatic 

precipitator in a coal or coal / wood boiler producing 300,000 lb/hr of steam. The 

particulate emission rate is 0.04 lb / Mm Btu.

10.10.2.Major Equipment

 Modifications to existing ESP

 Ductwork modifications

10.10.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of

steam. The project was estimated in 1992.

10.10.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001
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10.10.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 1% of TIC cost

 Power 500 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 43 tpy of ash

10.11. Oil Boiler

10.11.1.Description

Installation of electrostatic precipitator in a oil-fired boiler producing 135,000 

lb/hr of steam. The particulate emission rate is 0.02 lb / Mm Btu.

10.11.2.Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

10.11.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

10.11.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 135,000 lb/hr of steam.

 Costs escalated to 2001

10.11.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 1098 kw

 Power usage factor: 70%

 Workhours – 3 hours per day
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 Testing - $5,000 per year

 Incremental waste disposal: 99 tpy of ash

10.12. Wood Boiler

10.12.1.Description

Installation of an electrostatic precipitator in wood boiler producing 300,000 lb/hr 

of steam. The particulate emission rate is 0.04 lb / Mm Btu.

10.12.2.Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

10.12.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000 lb/hr of 

steam. The project was estimated in 1992.

10.12.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

10.12.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 1978 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 599 tpy of ash
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10.13. Wood Boiler – upgrade existing ESP

10.13.1.Description

Upgrade of existing electrostatic precipitator in a wood boiler producing 300,000 

lb/hr of steam. The particulate emission rate is moved from 0.1 to 0.04 lb / Mm 

Btu.

10.13.2.Major Equipment

 ID fan modification

 ESP

 Conveyors

 Penthouse blower

10.13.3.Basis for Estimate

Southeastern Kraft mill boiler ESP rebuild for a boiler capable of producing 

310,000 lb/hr of steam. The project was estimated in 1996.

10.13.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

10.13.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3.5% of TIC cost

 Power – 250 kw

 Power usage factor: 70%

 Workhours – 3 hours per day

 Testing - $5,000 per year

 Incremental waste disposal: 116 tpy of ash
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11. Carbon Monoxide – Best Technology Limit

11.1. Coal or Coal / Wood Boiler

11.1.1.Description

Installation of combustion control modifications on a coal-fired boiler producing 

300,000 lb/hr of steam. The carbon monoxide (CO) emission rate is anticipated 

to be 200 or less ppm for a 24-hour average.

11.1.2.Major Equipment

 Replace forced draft fan

 Repairs to windbox

 Replace combustion air dampers

 New set of tertiary air nozzles

 New furnace cameras

 New CEM

 DCS control upgrade

11.1.3.Basis for Estimate

Southeastern Kraft mill which installed combustion controls on a wood-fired 

boiler producing 350,000 lb/hr of steam. The project was estimated in 2000.

11.1.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

11.1.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 298 kw

 Power usage factor: 70%

 Workhours – 1.5 hours per day

 Testing - $5,000 per year
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11.2. Wood Boiler

11.2.1.Description

Installation of combustion control modifications on a wood-fired boiler producing 

300,000 lb/hr of steam. The carbon monoxide (CO) emission rate is anticipated 

to be 200 or less ppm for a 24-hour average.

11.2.2.Major Equipment

 Replace forced draft fan

 Repairs to windbox

 Replace combustion air dampers

 New set of tertiary air nozzles

 New furnace cameras

 New CEM

 DCS control upgrade

11.2.3.Basis for Estimate

Southeastern Kraft mill which installed combustion controls on a wood-fired 

boiler producing 350,000 lb/hr of steam. The project was estimated in 2000.

11.2.4.Capital Cost Estimate Assumptions

 Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP for a 

boiler producing 300,000 lb/hr of steam.

 Costs escalated to 2001

11.2.5.Operating Cost Estimate Assumptions

 Maintenance labor and materials – 3% of TIC cost

 Power – 298 kw

 Power usage factor: 70%

 Workhours – 1.5 hours per day

 Testing - $5,000 per year
AF&PA Emission Control Study –

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12. HCl – Good Technology Limit

12.1. Coal Boiler

12.1.1.Description

Installation of caustic scrubber to remove HCl to the level of 0.048 lb/Mm Btu 

from a coal-fired boiler producing 300,000 lb/hr of steam. Assumes inlet HCl 

concentration of 0.064 lb/Mm Btu.

12.1.2.Major Equipment

 Scrubber tower

 Recirculation pump

 Booster fan

 Caustic feed system

12.1.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of steam. 

The project was estimated in 1992. 

12.1.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

12.1.5.Operating Cost Estimate Assumptions

 Chloride content of coal is 800 ppm which equates to 23 lb/hr of HCl

 Maintenance labor & materials: 5% of TIC

 Power: 811 kw 

 Power usage factor: 70%

 Chemical: 8 lb/hr caustic soda

 Testing: $5,000 per year

 Water: 64 gpm

 Wastewater: 20 gpm

 Workhours: 3 hours per day
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13. HCl – Best Technology Limit

13.1. Coal Boiler

13.1.1.Description

Installation of caustic scrubber to remove HCl to the level of 0.015 lb/Mm Btu 

from a coal-fired boiler producing 300,000 lb/hr of steam. Assumes inlet HCl 

concentration of 0.064 lb/Mm Btu.

13.1.2.Major Equipment

 Scrubber tower

 Recirculation pump

 Booster fan

 Caustic feed system

13.1.3.Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of steam. 

The project was estimated in 1992. 

13.1.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

13.1.5.Operating Cost Estimate Assumptions

 Chloride content of coal is 800 ppm which equates to 23 lb/hr of HCl

 Maintenance labor & materials: 5% of TIC

 Power: 811 kw 

 Power usage factor: 80%

 Chemical: 25 lb/hr caustic soda

 Testing: $5,000 per year

 Water: 64 gpm

 Wastewater: 20 gpm

 Workhours: 3 hours per day
AF&PA Emission Control Study –

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14. VOC – Good Technology Limit

14.1. DCE Kraft Recovery Furnace

14.1.1.Description

Collection of black liquor oxidation system vent gases from a DCE recovery

furnace burning 1.7 Mm lb BLS per day. The vent gases would be incinerated in 

an existing multi-fuel boiler. 

14.1.2.Major Equipment

 Vent fan

 Condensate pump

14.1.3.Basis for Estimate

Rust MACT Cost Analysis report for a DCE recovery furnace burning 1.5 Mm lb 

BLS per day. The work was done in October 1993. 

14.1.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 Rust estimate was escalated and included as a TIC only.

 No additional indirect costs were applied to the Rust estimate.

14.1.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 151 kw 

 Power usage factor: 70%

 Testing: $5,000 per year

 Steam: 500 lb/hr

 Workhours: 3 hours per day
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14.2. Paper Machines 

14.2.1.Description

Based upon NCASI studies ("Volatile Organic Emissions from Pulp & Paper 

Sources Part VII - Pulp Dryers & Paper Machines at Integrated Chemical Pulp 

Mills. Tech Bulletin No.681 Oct 1994 NCASI) the paper machines utilizing 

unbleached pulps had the highest non-additive VOC emission rates. The 

machines utilizing bleached pulps had very low VOC emissions. 

The source of the VOC was from the fluid contained in the unbleached pulp. If 

the consistency of the unbleached pulp is raised to 30+% (from a nominal 12%) 

prior to discharge to either the high density storage or to the paper machines, then 

the VOC contained in the fluid will be reduced by more than two-thirds. 

To increase the consistency to 30+%, a screw press would be installed ahead of 

the high density storage for the unbleached Kraft, semi-chemical (or NSSC), and 

mechanical pulp mills. The re-dilution water to be used after the screw press 

would be paper machine whitewater. In the case of the unbleached Kraft mill and 

semi-chemical mill, the filtrate from the press would be sent to the spent pulping 

liquor system.

The system was sized for a 1000 ton per day paper machine.

14.2.2.Major Equipment

 Two screw presses

 Pressate (filtrate) tank

 Thick stock pump 

14.2.3.Basis for Estimate

Estimate for 1000 tons per day screw press system based upon a quotation from 

Kvaerner Pulping. The estimate is in 2001 dollars.

14.2.4.Capital Cost Estimate Assumptions

 None

14.2.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 861 kw 

 Power usage factor: 70%

 Testing: $5,000 per year
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 Workhours: 1.5 hours per day

 A COD reduction will result from utilizing the screw press, which can result 

in enhanced runnability, improved sheet quality, and reduced chemical costs. 

However, these potential savings are very paper machine specific and were 

deemed beyond the scope of this study.

14.3. Mechanical Pulping - TMP

14.3.1.Description

Installation of a heat recovery system on TMP systems which will produce clean 

steam, a NCG vent, and dirty condensates. The system is designed to condense 

the VOCs to <0.5 lb C / ODTP.

14.3.2.Major Equipment

 Reboiler

 Vent condenser / feed water heater

 Boiler feed water heater

 Atmospheric start-up scrubber with silencer

14.3.3.Basis for Estimate

Estimate for 500 tpd TMP heat recovery system based upon quotation from 

Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery system. The quotation 

was in 2001 dollars.

14.3.4.Capital Cost Estimate Assumptions

 None

14.3.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 165 kw 

 Power usage factor: 70%

 Testing: $5,000

 Workhours: 1.5 hours per day

 Water: 192 gpm

 Wastewater: 194

 Steam: (94,255 lb/hr) (This is projected amount of steam to be recovered.)
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14.4. Mechanical Pulping – Pressure Groundwood

14.4.1.Description

Installation of a heat recovery system on pressure groundwood systems which 

will produce clean steam, a NCG vent, and dirty condensates. The system is 

designed to condense the VOCs to <0.5 lb C / ODTP.

14.4.2.Major Equipment

 Reboiler

 Vent condenser / feed water heater

 Boiler feed water heater

 Atmospheric start-up scrubber with silencer

14.4.3.Basis for Estimate

Estimate for 500-tpd-pressure groundwood heat recovery system based upon 

quotation from Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery system. 

The quotation was in 2001 dollars.

14.4.4.Capital Cost Estimate Assumptions

 None

14.4.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 165 kw 

 Power usage factor: 70%

 Testing: $5,000 per year

 Workhours: 1.5 hours per day

 Water: 192 gpm

 Wastewater: 39

 Steam: (18,851 lb/hr) (This is projected amount of steam to be recovered and 

assumes that the heat recovery would be 20% of that for a comparable TMP 

plant.)
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15. VOC – Best Technology Limit

15.1. NDCE Kraft Recovery Furnace

15.1.1.Description

Conversion of wet bottom ESP to a dry bottom ESP for a NDCE recovery furnace 

burning 3.7 Mm lb BLS per day. 99.8% particulate collection efficiency was 

assumed.

15.1.2.Major Equipment

 New dry bottom hopper

 Ash mix tank

 Conveyors

15.1.3.Basis for Estimate

Rust MACT Cost Analysis report for a NDCE recovery furnace burning 1.5-Mm 

lb BLS per day. The work was done in October 1993. 

15.1.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 Rust estimate was escalated and included as a TIC only. 

 No additional indirect costs were applied to the Rust estimate.

15.1.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 2% of TIC

 Power: 15 kw 

 Power usage factor: 70%

 Testing: $5,000 per year

 Workhours: 1.5 hours per day
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15.2. DCE Kraft Recovery Furnace

15.2.1.Description

Conversion of DCE recovery furnace burning 1.7 Mm lb BLS per day to a NDCE 

type.

15.2.2.Major Equipment

 New economizer

 New spent pulping liquor concentrator

 Additional soot blowers

 Ash mix tank

 CEMS

15.2.3.Basis for Estimate

Rust MACT Cost Analysis report for a DCE recovery furnace burning 1.5-Mm lb 

BLS per day. The work was done in October 1993. 

15.2.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 Rust estimate was escalated and included as a TIC only.

 No additional indirect costs were applied to the Rust estimate.



15.2.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 450 kw

 Power usage factor: 70% 

 Testing: $5,000 per year

 Steam: (26,984 lb/hr) (steam savings)

 Workhours: 3 hours per day
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15.3. Paper Machines – Wet End

15.3.1.Description

Collection of wet end exhaust gases from a 1000 TPD paper machine and 

incineration in a regenerative thermal oxidizer (RTO). 

15.3.2.Major Equipment

 Combustion blower

 Seal fan

 Main fan

 Regenerative thermal oxidizer

 100’ stack with testing platform

 316L stainless steel duct

15.3.3.Basis for Estimate

Northern pulp mill with dryer equipped with a collection system and RTO unit. 

The mill is designed to produce 415 ODTPD of deink pulp. The project was 

estimated in 2000.

15.3.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 R&D costs: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

15.3.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 310 kw

 Power usage factor: 70% 

 Testing: $5,000 per year

 Natural gas: 4.71 Mmbtu/hr

 Workhours: 1.5 hours per day
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15.4. Paper Machines – Dry End

15.4.1.Description

Collection of dry-end exhaust gases from a 1000 TPD paper machine and 

incineration in a RTO.

15.4.2.Major Equipment

15.4.3.Major Equipment

 Combustion blower

 Seal fan

 Main fan

 Regenerative thermal oxidizer

 100’ stack with testing platform

 316L stainless steel duct

15.4.4.Basis for Estimate

Northern pulp mill with dryer equipped with a collection system and RTO unit. 

The mill is designed to produce 415 ODTPD of deink pulp. The project was 

estimated in 2000.

15.4.5.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 R&D costs: 1.5% of total direct costs (i.e., labor, materials, subcontract, and 

equipment)

15.4.6.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC

 Power: 380 kw

 Power usage factor: 70% 

 Testing: $5,000 per year

 Natural gas: 8.1 MmBtu/hr

 Workhours: 1.5 hours per day
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15.5. Mechanical Pulping – TMP with Existing Heat Recovery System

15.5.1.Description

Collection and incineration of the NCGs from a TMP heat recovery system. The 

system was sized for a 500 ADTPD mechanical pulp mill.

15.5.2.Major Equipment

 Duct work

 Combustion blower

 Thermal oxidizer

15.5.3.Basis for Estimate

Southeastern Kraft mill which routed its NCGs to a thermal oxidizer. System was 

sized for 20,000 ACFM. The project was estimated in 1999.

15.5.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

15.5.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 22 kw

 Power usage factor: 70%

 Workhours: 2.25 hours per day

 Testing: $5,000 per year

 Water: 10gpm

 Wastewater: 10 gpm

15.6. Mechanical Pulping – TMP Without Existing Heat Recovery System

15.6.1.Description

Installation of a heat recovery system on mechanical pulping systems which will 

produce clean steam, a NCG vent, and dirty condensates. Then collection and 

incineration of the NCGs. The system was sized for a 500 ADTPD TMP mill.
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15.6.2.Major Equipment

 Reboiler

 Vent condenser / feed water heater

 Boiler feed water heater

 Atmospheric start-up scrubber with silencer

 Duct work

 Combustion blower

 Thermal oxidizer

15.6.3.Basis for Estimate

Estimate for 500 tpd TMP heat recovery system based upon quotation from 

Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery system. The quotation 

was in 2001 dollars. 

For NCG collection and incineration, Southeastern Kraft mill which routed its 

NCGs to a thermal oxidizer. System was sized for 20,000 ACFM. The project 

was estimated in 1999.

15.6.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

15.6.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 187 kw

 Power usage factor: 70%

 Workhours: 2.25 hours per day

 Testing: $5,000 per year

 Water: 202gpm

 Wastewater: 204 gpm

 Steam: (94,255 lb/hr) (This is projected amount of steam to be recovered)
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15.7. Mechanical Pulping – Pressurized Groundwood Without Existing 

Heat Recovery System

15.7.1.Description

Installation of a heat recovery system on pressurized groundwood pulping 

systems which will produce clean steam, a NCG vent, and dirty condensates. 

Then collection and incineration of the NCGs. The system was sized for a 500 

ADTPD pressurized groundwood mill.

15.7.2.Major Equipment

 Reboiler

 Vent condenser / feed water heater

 Boiler feed water heater

 Atmospheric start-up scrubber with silencer

 Duct work

 Combustion blower

 Thermal oxidizer

15.7.3.Basis for Estimate

Estimate for 500 tpd pressurized groundwood heat recovery system based upon 

quotation from Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery system. 

The quotation was in 2001 dollars. 

For NCG collection and incineration, Southeastern Kraft mill which routed its 

NCGs to a thermal oxidizer. System was sized for 20,000 ACFM. The project 

was estimated in 1999.

15.7.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

15.7.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 198 kw

 Power usage factor: 70%
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 Workhours: 2.25 hours per day

 Testing: $5,000 per year

 Water: 202gpm

 Wastewater: 49 gpm

 Steam: (18,851 lb/hr) (This is projected amount of steam to be recovered and 

assumes that the heat recovery would be 20% of that for a comparable TMP 

plant.)

15.8. Mechanical Pulping – Atmospheric Groundwood

15.8.1.Description

Collection and incineration of the NCGs from a atmospheric groundwood system. 

The system was sized for a 500 ADTPD mechanical pulp mill. The estimated 

emission was 20,000 ACFM. 

15.8.2.Major Equipment

 Hoods

 Duct work

 Combustion blower

 Thermal oxidizer

15.8.3.Basis for Estimate

Southeastern Kraft mill which routed its NCGs to a thermal oxidizer. System was 

sized for 20,000 ACFM. The project was estimated in 1999.

15.8.4.Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

15.8.5.Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3.5% of TIC

 Power: 22 kw

 Power usage factor: 70%

 Workhours: 2.25 hours per day
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 Testing: $5,000 per year

 Water: 10gpm

 Wastewater: 10 gpm
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16. Gasification

16.1. Description of Technology

For this study, chemical recovery via gasification is based on the PulseEnhancedTM 

Steam Reformation technology developed by MTCI/ThermoChem, which is designed to 

process spent liquor and recover its chemical and energy value. A simplified diagram of 

the technology is shown below.

Bed

Solids

Stack

Raw Gas

Heat Recovery

Filtration

Gas Cleanup

Product

Gas

Steam

The recovery of chemicals and energy from spent liquor is effected by an indirectly

heated steam-reforming process which results in the generation of a hydrogen-rich, 

medium-Btu product gas and bed solids, a dry alkali, which flow from the bottom of the 

reformer. Neither direct combustion nor alkali salt smelt formation occurs in this steamreforming process. 

Dissolving, washing, and filtering the bed solids produce a “clear” alkali carbonate 

solution. The filter cake contains any unreacted carbon as well as insoluble non-process 

elements such as calcium and silicon. The carbon cake can be used as an activated 

charcoal for color or odor removal, mixed on the fuel pile for the powerhouse, or 

discarded as a “dregs” waste.

The product gas is cleaned, compressed, and then sent to the pulse heaters to provide the 

indirect heat in the reformer and to a combustion turbine to produce electricity. The 

combustion turbine exhaust is combined with the pulse heater exhaust and then sent to a 
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heat recovery steam generator. The resulting high-pressure steam is then sent to an 

extraction/condensing steam turbine where addition electricity is produced and lower 

pressure steam is made available to the mill. A process flow diagram showing the 

complete system is shown on the following page. 

The scope developed assumes that the mill can supply concentrated black liquor (80% 

solids). Since the costs for doing this can vary widely between mills and modern 

recovery boilers would require a similar concentration, these costs have been omitted 

from this study.

We recognize that the steam produced by this system is probably not sufficient for a 

typical Kraft mill. The additional steam requirements will either need to be provided by a 

biomass gasifier or boiler or a power boiler. These additional systems offer the 

opportunity for further power generation as well as steam production. This too is site 

specific and not included in this study.
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16.2. Major Equipment

The major subsystems include liquor injection, steam reformer, gas cleanup, combustion 

turbine, heat recovery and steam generation, steam turbine, bed solids dissolution, 

sodium carbonate solution filter, and bed solids storage. 

16.2.1.Black Liquor Supply and Steam Reformer

High solids black liquor is supplied to the reformer via a recirculation line feeding 

multiple steam jacketed injectors. Four reformers each containing 8-pulse heaters 

are required for this size plant. Each steam reformer is a carbon steel; fabricated 

vessel lined with refractory. The upper region of the vessel is expanded to reduce 

gas velocity, permitting entrained particles to disengage and fall back to the fluid 

bed. Internal stainless cyclones, mounted from the roof of the reformer, provide 

primary dust collection and a second set of external cyclones further captures 

fines. The reformer is fluidized with superheated steam using stainless fluidizer 

headers that are located just above the refractory floor. Bed drains penetrate the 

refractory floor for removal of bed solids via lock hoppers during normal 

operation. 

Pulsed jet heater modules (fired heat exchangers) are used to indirectly heat the 

reformer. Pulsed heater modules are cantilever-mounted in the reformer utilizing 

a flange located on the front of the vessel. Each module extends through the 

reformer with it resonance tubes in contact with the fluid bed particles inside the 

vessel. 

16.2.2.Product Gas Cleanup

Cyclone-cleaned product gas exits the reformer and enters a product gas heat 

recovery steam generator (HRSG) which cools the gas prior to entering a venturi 

separator, which further cools the gas and washes out any solids carryover. A 

packed gas cooler follows the venturi separator. Once the gas is cooled, it enters 

the H2S absorber (green liquor column). The absorber is a carbon steel cylinder 

with two packed stages.

16.2.3.Product Gas Combustion

The clean/cool product gas is sent to the pulse heaters and to a compressor, which 

then feeds a combustion turbine. The CT generates 50mW of net power.

16.2.4.Heat Recovery and Steam Generation

Steam is generated in both the product gas HRSG and the waste heat boiler. The 

product gas HRSG consists of a vertical shell and tube generating section and an 

external steam drum. The product gas HRSG also serves as a source of cooling 

water for the pulsed heaters. 
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The waste heat boiler is a two-drum, bottom-supported boiler. Hot flue gas from 

the pulse heaters and the combustion turbine flows into the HRSG to produce 

220-pph 900psi/900F steam. 

16.2.5.Steam Turbine

Steam from the waste heat boiler is sent to an extraction condensing steam 

turbine, which will extract the energy in the high-pressure steam to generate a net 

8 mw of power. The resulting lower pressure steam is then piped to the mill 

steam distribution system.

16.2.6.Solids Dissolution

The solids from each reformer flows through refractory-lined lock hoppers into 

dissolving tanks. The dissolving tank is carbon steel, insulated tank outfitted with 

a side-entry agitator, and sized to provide additional retention time to effect 

dissolution of the soluble sodium carbonate.

16.2.7.Sodium Carbonate Filter

The function of the filter system is to filter the dissolving tank solution to produce 

a clear sodium carbonate liquor; free of suspended solids such as unreacted 

organic carbon and non-process elements.

16.2.8.Media Storage Bin

The media bin is an insulated carbon steel vessel (mass flow design) with a 

capacity sufficient to hold the inventory of several reformers during repair and 

maintenance.

16.3. Basis for Estimate

Our database of studies, extending over the last 5 years for systems ranging from 250,000 

lb/day to 1,000,000 lb/day black liquor solids, was used to create a base for the capital 

cost estimate. 

16.4. Capital Cost Estimate Assumptions

 Costs were factored using the “0.6 power.”

 Costs were escalated to 2001 dollars

 Engineering was assumed to 8% vs. the standard 15% because of the high cost 

of the equipment and the fact that there is little integration to existing plant

 R&D expenses of 1.5% of the direct costs were assumed.

 Equipment foundations on spread footings

 No allowance for disposal of any potential contaminated soils
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 Except for the purchase of one spare pulsed heater unit, no standalone spares 

are included. Installed spares are listed as equipment.

 No demolition costs

 Pricing was obtained for major equipment. Some prices were not 

competitively bid and no negotiations were undertaken to firm or clarify

process scope. 

16.5. Operating Cost Estimate Assumptions

 Maintenance labor & materials: 3% of TIC cost

 Utilities: 0.1% of TIC cost

 Power

 New loads: 11,600 kw

 Credit for shutdown of existing recovery boiler: (3700) kw

 Revenue – sale of power: 50,000 kw

 Dregs disposal: 1.9 tons per hour

 Waste water treatment: 650 gpm

 Steam (revenue): (170,000) lb/hr 
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16.6. Impact on Emissions

Emissions estimates prepared in earlier studies were scaled up for the 3.7 million-lb/day 

gasifier and then compared to equivalent data for a similarly sized recovery boiler. The 

emissions are shown in the tables and chart below.

Black Liquor Gasification Emission Estimates

Black Liquor Reformer 

Pulse Combustion 

Exhaust

Combustion Turbine

Exhaust Total

(lb/hr) (lb/hr) (lb/hr)

Particulate matter 2.9 5.7 8.5

Nitrous oxides (NOx) 18.7 46.1 64.7

Carbon monoxide (CO) 11.4 56.1 67.5

Sulfur dioxide (SO2) 70.0 81.0 151.0

Volatile organic (as carbon) 0.4 0.0 0.4

as Methanol 2.8 0.0 2.8

TRS (as H2S) 0.0 0.0 0.0

Recovery Boiler & Smelt Dissolver Emission Estimates

Recovery Boiler

Exhaust

Smelt Dissolving 

Exhaust Total

lb/hr lb/hr lb/hr

Particulate matter 93.9 9.4 103.3

Nitrous oxides (NOx) 89.2 16.1 105.3

Carbon monoxide (CO) 516.5 0.3 516.8

Sulfur dioxide (SO2) 98.7 9.4 108.1

Volatile organic (as carbon) 37.6 7.5 45.1

as Methanol 100.2 20.0 120.2

TRS (as H2S) 4.7 2.5 7.2
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Additionally for carbon dioxide the black liquor gasification emission rate is estimated to 

be 240,400 lb/hr for a 4 Mm lb BLS/day unit, while a comparable Tomilson unit would 

discharge 318,600 lb/hour.

The following illustrates the differences between a black liquor gasification unit and a 

Tomilson recovery system:

PM NOx CO SO2 VOC

Pollutant

0

100

200

300

400

500

600

Emission rates, lb/hour

Gasifier Recovery

Emission estimates based on 3.7 Mmlb BLS/day firing rate.

Estimated Emission Rates - 

Gasifier vs. Recovery Furnace
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17. Industry – Wide Control Cost Estimates

17.1. General Assumptions

The following are the general assumptions:

17.1.1. Capital Costs

 The individual mill cost estimates are based upon using the 0.6 power rule 

[Project A cost x (AF&PA firing rate / Project A firing rate)0.6] to factor the 

control technology estimates

 The boiler emission rates are compared with pollutant limits to determine 

relative compliance. If the mill discharge level is less than 90% of the 

pollutant limit, then no control technology will be installed.

 The base labor is $58.62 per hour and was determined from:

Area Rate, $/hour Comment

Base rate $17.50

Benefits $3.25 18.55% of base rate

Fringes $2.01 11.50% of base rate

Workman’s 

compensation 

insurance

$2.13 Varies by craft from 6 to 30% of base rate

Indirects $27.00 Includes home office expenses, field 

supervision, temporary facilities, tools/ 

consumables, construction equipment, 

permits/miscellaneous, and contractor’s 

fee

Premium markup$2.07

Per diem $4.66 Includes direct and indirect

Total $58.62
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 The labor costs portion of the TIC were adjusted for each mill utilizing the 

BE&K labor rates by region. See Appendix 18.1 for a listing of the factors by

state.

 The material and subcontract costs were adjusted for each mill utilizing the 

MEANS database factors averaged for each state. See Appendix 18.1 for a 

listing of the factors by state.

 Research & Development expenses were assumed for the SCR-non-natural 

gas, mercury removal, and paper machine VOC removal – best technology

applications. They ranged from 0.5 to 1.5% of the sum of the labor, material, 

subcontract, and equipment direct costs.

 The BE&K project costs were escalated according to the following:

Period Escalation rate

1994 to 1995 2.50%

1995 to 1996 3.30%

1996 to 1997 1.70%

1997 to 1998 1.60%

1998 to 1999 2.70%

1999 to 2000 3.40%

17.1.2. Annual Operating and Maintenance Costs

 The maintenance labor and material annual costs were reported as a percentage of 

the TIC. The typical range was between 1% and 5% of the total TIC.

 The operating costs for the mills were proportionately factored for each of the 

areas (excluding testing and workhours) from the design case.

 355 operating days per year were assumed for the equipment.

 The materials category such as fabric filter or SCR catalyst was reported in terms 

of 2001 dollars.

 The wastewater category reported the usage in gallons per year based upon the 

estimated flow; gpm/feed rate x feed rate x 1440 min/day x 365 dy/yr. The water 

usage used the same formula but with only 350 dy/yr.
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 The steam and compressed air usage was calculated by multiplying the usage per 

feed rate x feed rate per day x 350 dy/yr.

 The estimated cost for process water was $0.58 per thousand gallons.

 The estimated cost for wastewater treatment was $0.41 per thousand gallons.

 The estimated cost for caustic soda was $0.17 per lb.

 The estimated cost for urea was $225 per ton

 The estimated cost for activated carbon is $0.58 per lb

 The estimated cost for pebble lime is $56.50 per ton

 The differential price between No. 2 and No. 6 fuel oil is $0.84 per Mmbtu 

(assumes a cost of $4.32 /Mmbtu for No. 6 fuel oil and $5.16 / MmBtu for No. 2 

fuel oil)

 The energy usage was first calculated in kWh/year and is based upon the 

estimated connected kilowatts x 24/hr/day times 350 days times usage factor 

(typically 70 to 80%). 

 The price of electricity was assumed to $0.05/kwhr and was multiplied by the 

kWh/year.

 The price of steam was assumed to be $0.00500 per lb of steam and was 

multiplied by the steam usage in lb/hr per year. For any recovered steam, a 

recovered steam factor times the price of steam was used to determine the value 

of the steam.

 The price of compressed air was assume to be $0.00010 per cfm and was 

multiplied by the compressed air usage in cfm/year.

 The utilities category totals the costs for compressed air, water, wastewater, 

steam, and solid waste disposal.

 The price of natural gas was assumed to be $4.00 per Mmbtu.

 The landfill cost for hauling and disposal was assumed to be $25 per ton of solid 

waste.

 An annual testing cost of $5,000 was assumed for each technology applied and 

was assumed constant independent of the size of the facility.

 The workhours were reported in $ /year based upon hours / day x 350 operating 

days/year x the hourly rate. The hourly rate was obtained from AF&PA Labor
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Database with 91% of member contracts entered (missing about 20); the average

hourly rate for year 2000 was $18.14. This data only includes hourly employees. 

An additional 40% was added to the figure to account for benefits to yield a rate 

of $25.40. The workhour dollars were not factored, but were assumed to be 

constant no matter what the size of the facility.

 The NCASI database for recovery furnaces, limekilns, and power boilers was 

used. This included equipment information, combustion firing rates and types, 

and pulping information. 

 NCASI provided the mill code for the BE&K supplied paper machine and 

mechanical pulping information.

17.2. CO2 Emission Assumptions

 The CO2 emissions were calculated by multiplying the 1995 NCASI fossil fuel usage 

from the power boilers, recovery furnaces, and lime kilns times the CO2 factors times 

99% (assuming a 99% burn factor). This was the recommended calculation technique 

from the DOE Emission of Greenhouse Gases in the United States report.

 The CO2 emission factors are:

Distillate Oil (No.2) 21.945 Tons / MmBtu

Residual Oil (No.6) 23.639 Tons / MmBtu

Coal Industrial (other) 28.193 Tons / MmBtu

Natural gas 15.917 Tons / MmBtu

Petroleum Coke* 30.635 Tons / MmBtu

* Petroleum Coke was assumed to have a heat content of 15,000 Btu/lb

17.3. Recovery Furnace Assumptions

The following are the assumptions:

17.3.1. General Assumptions

 NDCE recovery furnace firing 3.7 Mm lb BLS/day is assumed to have an 

air flow of 27,500 lb/min, NOx Control Technology.

 For the cases where the design heat load (i.e., Mm Btu/hr) is not known, it 

was calculated from the design BLS firing rate, utilizing a heat content of 

5900 Btu/lb.
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17.3.2. NOx Control Technology

 The limits were converted to a lb/Mm Btu basis that equates to.

NDCE at 80 ppm 0.1415 lb / Mm Btu

NDCE at 40 ppm 0.0726 lb / Mm Btu

DCE at 30 ppm 0.0544 lb / Mm Btu

 The annual NOx emission rates from the NCASI database were 

converted to lb/Mm Btu and compared with 80% of the above limits. 

The NOx limits are based upon 30-day averages and it was assumed 

that to comply with the 30-day average limits the annual average 

would be approximately 80% of the 30-day limits.

 For the case of the good technology, if a given furnace did not meet 

the adjusted limit, then its emission rate was assumed to average the 

adjusted limit (i.e., 80% of the 30-day average limits) after treatment. 

The adjustment of 80% represents a compliance safety margin.

 If no emission rates were indicated for 1995, then no treatment 

estimate was made for that furnace.

 For the case of the best technology, if a given furnace did not meet the 

adjusted limit, then its emission rate was assumed to be reduced by 

50% after treatment 

17.3.3. SO2 Control Technology

 The limits were converted to a lb/Mm Btu basis that equates to.

NDCE at 50 ppm 0.12 Lb / MmBtu

NDCE at 10 ppm 0.0.024 Lb / MmBtu

DCE at 50 ppm 0.0.12 Lb / MmBtu

DCE at 10 ppm 0.0.024 Lb / MmBtu

 The annual SO2 emission rates from the NCASI database were 

converted to lb/Mm Btu basis and compared with 80% of the above 

limits. The SO2 limits are based upon 30-day averages and it was 

assumed that to comply with the 30-day average limits the annual 

average would be approximately 80% of the 30-day limits.

 The following illustrates the cumulative distribution for the recovery

furnace SO2 emission rates from the 1995 NCASI database:
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0.000 0.100 0.200 0.300 0.400 0.500 0.600 0.700

Annual Sulfur dioxide emission rate, lb/Mm Btu

0%

20%

40%

60%

80%

100%

Cumualtive frequency

Basis: 1995 NCASI emission data base

Good technology limit is based upon 30-day average time 0.8

Good Technology 

Limit

Recovery Furnace SO2 Emission 

Distribution

 For recovery furnaces with up to four-times the adjusted SO2 limit 

(i.e., 0.3628 lb/Mm Btu), combustion control modifications (these are

the same as what was estimated for good controls for NOx) would 

be implemented. For recovery furnaces with SO2 limits greater than 

0.3628 lb/Mm Btu, a new scrubber would be installed. In either case, 

the controlled emission rate would be equivalent to an annual average 

of 40 ppm (i.e., 50 ppm x 80%). 

 If no emissions were indicated for 1995, then no treatment estimate 

was made for the furnace.

 For both technologies, if a given furnace did not meet the adjusted 

limit, then its emission rate was assumed to average the adjusted limit. 

The adjustment of 80% represents a compliance safety margin.

17.3.4. PM Control Technology

 Any recovery furnace ESP built or rebuilt after 1990 but before 1998 was 

assumed capable of meeting the good PM technology limit.
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 Any recovery furnace ESP built after 1990 but before 1998 will be 

upgraded with additional fields for best PM technology limits.

 Any NDCE recovery furnace ESP built or rebuilt before 1980 will be 

upgraded with additional field for the good PM technology limit and be 

replaced for the best PM technology limit.

 Any NDCE recovery furnace ESP built or rebuilt after 1980 will meet the 

good technology limits.

 Any non-NDCE recovery furnace ESP or scrubber built before 1990 will 

be replaced with a new ESP for either good or best PM technology.

 Any recovery furnace ESP built or rebuilt after 1998 was assumed to 

comply with the best PM technology limit.

17.3.5. VOC Control Technology

 Good VOC technology limit consists of collecting and incinerating the 

BLO vent gas from any non-NDCE recovery furnace.

 Best VOC technology consists of converting any NDCE recovery furnace 

ESPs from wet to dry bottom and converting any non-NDCE to a NDCE 

recovery furnace

17.3.6.Smelt Dissolving Tank Scrubber - PM Technology

 Number of smelt dissolving tank was determined based upon the 

manufacturer. Combustion Engineering furnaces with greater than a 3.5 

Mm lb BLS/ day firing rates are assumed to have two smelt dissolving 

tanks and the other manufacturer’s have one smelt dissolving tank. For 

the case of the two smelt dissolving tank scrubbers, the initial scrubber 

was factored based on half the black liquor-firing rate and then multiplied 

by two.

 Any recovery furnace built before 1976 will require a new smelt 

dissolving tank scrubber.

 Any recovery furnace built or rebuilt after 1976 but before 1990 was 

assumed to meet the good PM technology limit

 Any recovery furnace built or rebuilt after 1990 was assumed to meet the 

best PM technology limit 
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17.4. Lime Kiln Assumptions

The following are the assumptions:

17.4.1. PM Control Technology

 Any lime kiln built after 1976 and equipped with a wet scrubber or those kiln 

equipped with an ESP installed prior to 1990 was assumed to meet the good 

PM technology limit.

 Any limekiln equipped with an ESP installed prior to 1990 was assumed 

upgradable to meet the best PM technology limit.

 Any lime kiln equipped with an ESP installed after 1990 was assumed to meet 

the best PM technology limit 

17.4.2. NOx Control Technology

 If the annual NCASI-estimated NOx levels are less than 20 TPY, no controls 

will be added. This level represents approximately 10% of the limekilns from 

the NCASI database.

 If no emissions where indicated for 1995, then no treatment estimate was 

made for the kiln.

 If the mill burns the NCGs primarily in the limekiln, then it was assumed that 

if there is a stripper present the stripper off-gases (SOGs) are burned in the 

limekiln. 

 The NOx level in the limekiln if NCGs are being burned will decrease by 30% 

if the SOGs are burned in a thermal oxidizer. The thermal oxidizer would be 

equipped with staged combustion to control the NOx levels. 

 The NOx level in the limekiln will decrease by 60% with the incorporation of 

SCR and low-NOx burners. If a good technology fix was required, the best 

technology was additive: the 60% reduction was compounded on the 30% 

reduction for a total of a 72% reduction [(1-0.3) x (1-0.6)].

17.5. Boiler and Turbine Assumptions

 350 operating days per year were assumed.

 If the Btu/hr capacity of the boiler was not provided, then the steam output was 

multiplied by the assumed heating value for the steam of 1200 Btu/lb.

 If only the fuel combusted in 1995 was known, 
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 The fuel usage for each boiler from the NCASI database was multiplied by the 

following heating values:

Coal 25,000 MmBtu/1000 ton

Residual Oil (No.6) 5,920 MmBtu/1000 bbl

Distillate Oil (No.2) 5,376 MmBtu/1000 bbl

Natural gas 950 MmBtu/MmCF

Wood 9,000 MmBtu/1000 ton

Sludge 10,000 MmBtu/1000 ton

 If the design information for the boiler – either steam or Btu were not provided, then 

the sizing was based upon the 1995 NCASI fuel usage (if given) and Btu estimate. 

The steam output was calculated from the Btu estimate and the boiler efficiency, 

which was assumed 85% for everything, except for wood-fired boilers, which was 

assumed to have a 65% efficiency.

 The boiler design figure was compared with the predicted steam (i.e., based upon 

1995 reported fuel usages) and which ever was higher was used to compute the 

capital costs for the control technologies. The operating costs were based upon the 

predicted steam usage. 

 The best estimate SO2, and NOx yearly emission rates were converted to pounds and

divided by Btus to determine a lb/MmBtu emission rate. 

 The SO2 and NOx emission rates were then multiplied by 80% and compared with the 

technology limits. The technology limits are based upon 30-day averages and it was 

assumed that to comply with the 30-day average limits the annual average would be 

approximately 80% of the 30-day limits.

 For the case of the good technology, if a given furnace did not meet the adjusted 

limit, then its emission rate was assumed to average the adjusted limit after treatment 

(i.e., 80% of the 30-day average limits). 

 For the case of SO2 control technology, no control costs were assumed for any boiler 

designated as a wood or gas boiler, regardless of the emission level.

 NCASI has listed 1225 boilers or turbines, and had fuel consumption information on

1074 of them. Control technology estimates for boilers were only made if fuel

consumption information was provided.
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17.6. Coal Boiler Assumptions

17.6.1. General

 If more than 80% of the gross Btu’s originated from coal, then the boiler was 

assumed a coal boiler. 

17.6.2.NOx Limits

 Any coal boilers after 1990 are assumed to have low NOx burners and are 

assumed to meet the 0.3 lb/106 Btu, 30-day average.

 If the coal boilers were converted to natural gas with low NOx-burners, then 

the emission rates were assumed to be 0.0490 and 0.1373 lb / 106 Btu for 

boilers less than and greater than 100 million Btu/hr, respectively.

17.6.3. SO2 Limits

 Application of scrubbers to coal boilers will yield 50% reduction at good 

technology and 90% reduction at best technology.

17.6.4. Hg limits

 The uncontrolled limits were obtained by multiplying the MmBtu/year for 

1995 by 16 lb/1012 Btu that is the AP-42 emission factor.

 The removal rate for the carbon injection and fabric filter approach was 

assumed 50%.

17.6.5.PM limits

 Any coal boiler with an ESP built or rebuilt after 1980 is assumed able to 

meet the good technology limit. If the ESP was built or rebuilt before 1980, 

the ESP’s would be upgraded by adding a single field. If the year the ESP 

was constructed or rebuilt was not in the NCASI database, then the ESP was 

assumed to have been built or rebuilt before 1980. Any coal boiler 

constructed after 1990 is assumed to meet the good technology limit.

 Any coal boiler with an ESP built or rebuilt after 1980 can be upgraded to by

adding a single field in two chambers to meet the best technology limit. A 

new ESP will be priced out for an ESP built or rebuilt before 1980. 

 Any coal boiler constructed or an ESP built or rebuilt after 1998 is assumed to 

meet the best technology limit.

17.6.6. CO limits

 Any coal boiler constructed after 1990 is assumed to be able to meet the best 

technology limit of 200 ppm (24-hour average). 
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17.6.7. HCl limits

 Use same criteria as for SO2 limits – if a scrubber was required for SO2, then

it was assumed a scrubber would be required for HCl control. This applied to

both good and best control technologies.

 If SO2 control is installed there will be no need to install HCl controls as well;

the chemical addition rate for SO2 is greater than what is required to remove

the HCl present.

17.7. Coal / Wood Boiler Assumptions

17.7.1. General Assumptions

 At least 20% of the Btus had to come from coal or wood provided both were 

used within the boiler.

17.7.2. NOx Limits

 Any coal boilers after 1990 were assumed to have low NOx burners and were 

assumed to meet the 0.3 lb/106 Btu, 30-day average

 For the case of the good or best technology, if a given boiler did not meet the 

adjusted limit, then its emission rate was assumed to average the adjusted 

limit (i.e., 80% of the 30-day average limits) after treatment

17.7.3. SO2 Limits

 Application of scrubbers to coal/wood boilers will yield 50% reduction at 

good technology and 90% reduction at best technology.

17.7.4. Hg limits

 The uncontrolled limits were obtained by multiplying the MmBtu/year for 

1995 by 16 lb/1012 Btu for coal and by 0.572 lb/1012 Btu for wood. Both are 

based upon the AP-42 emission factor with the wood corrected for the 

difference in heavy metals between coal and wood.

 The removal rate for the carbon injection and fabric filter approach was 

assumed 50%.

17.7.5. PM limits

 Any coal/wood boiler with an ESP built or rebuilt after 1980 is assumed able 

to meet the good technology limit. If the ESP was built or rebuilt before 

1980, the ESP’s would be upgraded by adding a single field in two chambers. 

If the year the ESP was constructed or rebuilt was not in the NCASI database, 

then the ESP was assumed to have been built or rebuilt before 1980. 
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 Any coal/wood boiler constructed after 1990 is assumed to meet the good 

technology limit.

 Any coal /wood boiler with an ESP built or rebuilt after 1980 can be upgraded 

to by adding a single field in two chambers to meet the best technology limit. 

A new ESP will be priced out for an ESP built or rebuilt before 1980. 

 Any coal/wood boiler constructed or an ESP built or rebuilt after 1998 is 

assumed to meet the best technology limit.

17.7.6. CO limits

 Any coal / wood boiler will require controls to meet the best technology limit 

of 200 ppm (24-hour average)

17.8. Gas Boiler Assumptions

17.8.1. General Assumptions

 A minimum of 90% of the Btu’s had to come from natural gas, in order for the 

boiler to be considered a gas boiler.

17.8.2. NOx Limits

 Any gas boilers after 1990 are assumed to have low-NOx burners and are 

assumed to meet the 0.05 lb/106 Btu, 30-day average

 For the case of the good or best technology, if a given boiler did not meet the 

adjusted limit, then its emission rate was assumed to average the adjusted 

limit (i.e., 80% of the 30-day average limits) after treatment

17.9. Gas Turbine Assumptions

17.9.1. NOx Limits

 Any gas turbines after 1995 are assumed to have water or steam injection to 

control to the good technology limit of 25 ppm @ 15% oxygen.

 For the case of the good or best technology, if a given turbine did not meet the 

adjusted limit, then its emission rate was assumed to average the adjusted 

limit (i.e., 80% of the 30-day average limits) after treatment

17.10. Oil Boiler Assumptions

17.10.1. General Assumptions

 If both oil and gas are burned, then if more than 15% of the Btu’s originates 

from oil, the boiler was considered an oil boiler.
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 If oil and wood or coal was burned, then at least 85% of the Btu had to 

originate from oil for the boiler to be considered an oil boiler.

17.10.2. NOx Limits

 Any oil boilers after 1990 are assumed to have low-NOx burners and are 

assumed to meet the 0.2 lb/106 Btu, 30-day average

 For the case of the good or best technology, if a given boiler did not meet the 

adjusted limit, then its emission rate was assumed to average the adjusted 

limit (i.e., 80% of the 30-day average limits) after treatment

17.10.3. SO2 Limits

 Application of scrubbers to oil boilers will yield 50% reduction at good 

technology and 90% reduction at best technology.

17.10.4.PM limits

 Any oil boiler with an ESP is assumed able to meet the good technology limit. 

 Any oil boiler constructed after 1990 is assumed to meet the good technology

limit.

 Any oil boiler burning distillate oil is assumed to meet the good technology

limit.

 Any oil boiler with an ESP can be upgraded to by adding a single field in two 

chambers to meet the best technology limit.

 Any oil boiler constructed after 1998 is assumed to meet the best technology

limit.

17.11. Wood-Fired Boiler Assumptions

17.11.1. General Assumptions

 Any boiler where at least 80% of the Btu originate from wood, then the boiler 

is considered a wood-fired boiler.

17.11.2. NOx Limits

 Any wood boiler after 1990 are assumed to have combustion controls and are 

assumed to meet the 0.25 lb/106 Btu, 30-day average

 For the case of the good or best technology, if a given boiler did not meet the 

adjusted limit, then its emission rate was assumed to average the adjusted 

limit after treatment (i.e., 80% of the 30-day average limits).
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17.11.3. Hg limits

 The uncontrolled limits were obtained by multiplying the MmBtu/year for 

1995 by 0.572 lb/1012 Btu for wood. This is based upon the AP-42 emission 

factor for coal corrected for the difference in heavy metals between coal and 

wood.

 The removal rate for the carbon injection and fabric filter approach was 

assumed 50%.

17.11.4. PM limits

 Any wood boiler with an ESP built or rebuilt after 1980 is assumed able to 

meet the good technology limit. If the ESP was built or rebuilt before 1980, 

the ESP’s would be upgraded by adding a single field in two chambers. If the 

year the ESP was constructed or rebuilt was not in the NCASI database, then 

the ESP was assumed to have been built or rebuilt before 1980. 

 Any wood boiler constructed after 1990 is assumed to meet the good 

technology limit.

 Any wood boiler with an ESP built or rebuilt after 1980 can be upgraded to by

adding a single field in two chambers to meet the best technology limit. A 

new ESP will be priced out for an ESP built or rebuilt before 1980. 

 Any wood boiler constructed or an ESP built or rebuilt after 1998 is assumed 

to meet the best technology limit.

17.11.5.CO limits

 Any wood boiler will require cotnrols to meet the best technology limit of 200 

ppm (24-hour average)

17.12. Paper Machine Assumptions

 Fisher Database statistics were used. 

 Minimum machine size capacity of 50 tons per day was used as the cut-off.

 Only paper machines with unbleached Kraft, semi-chemical, NSSC, and mechanical 

pulp furnishes were considered for the good technology limits. Unbleached recycle 

fiber furnishes were considered for the best technology limits.

 Each mechanical pulp line was treated separately for the good technology limit.

 The good technology was sized based upon the pulp mill production. A minimum of 

200 tons per day was used as the cut-off for the pulp mill production for everything 

but mechanical pulping, which was set at 100 tons per day.
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 The best technology was sized based upon the paper machine capacity. If only a 

portion of a paper machine’s furnish was one of the above fiber furnishes, then the 

paper machine was treated.

 The untreated emission rate for the unbleached paper machines was assumed to be 

0.47 lb C / ODTP. (Basis: NCASI Tech Bulletin No. 681)

 The emission reduction for the good technology was assumed 67%. 

 The emission reduction for the best technology was assumed 99%.

17.13. Mechanical Pulping

 Fisher Database statistics were used

 Minimum production level of 18,000 tons per year was used as the cut-off.

 Any TMP line constructed after 1989 is assumed to meet the good technology limits. 

Heat recovery was applied to all pressure groundwood mills regardless of age.

 Heat recovery was not applied to any atmospheric groundwood pulping lines.

 Any TMP pulping line constructed after 1998 is assumed to meet the best technology

limits.
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18. Appendix

18.1. MEANS and BE&K Labor Rate Factors by State

The following presents the state factors for the RS Means Open Shop Building 

Construction Cost Data 17th edition location factors for materials and subcontracting (or 

total) and the BE&K construction labor factors:

Materials Factor Subcontracting 

Factor

BE&K Construction 

Labor Factor

Alabama 0.967 0.823 1.000

Alaska 1.354 1.254 0.959

Arizona 0.989 0.876 0.975

Arkansas 0.957 0.778 0.970

California 1.076 1.119 0.983

Colorado 1.019 0.937 0.974

Connecticut 1.028 1.054 0.979

Delaware 0.992 1.009 0.968

Florida 0.987 0.841 0.992

Georgia 0.967 0.840 0.979

Idaho 1.021 0.938 0.960

Illinois 0.970 1.041 0.997

Indiana 0.975 0.957 0.958

Iowa 0.996 0.918 0.995

Kansas 0.966 0.864 0.961

Kentucky 0.955 0.895 0.992

Louisiana 0.989 0.824 0.990

Maine 0.996 0.824 1.003

Massachusetts 0.997 1.043 0.975

Maryland 0.937 0.884 0.973
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Materials Factor Subcontracting 

Factor

BE&K Construction 

Labor Factor

Michigan 0.970 0.948 0.973

Minnesota 0.984 1.073 0.983

Mississippi 0.985 0.739 0.977

Missouri 0.962 0.950 0.987

Montana 0.995 0.938 0.977

Nebraska 0.978 0.828 0.962

Nevada 1.020 0.993 0.967

New Hampshire 0.983 0.913 0.982

New Jersey 1.028 1.125 0.965

New Mexico 1.006 0.912 0.972

New York 0.968 0.945 0.977

North Carolina 0.959 0.734 0.982

North Dakota 1.008 0.849 0.939

Ohio 0.967 0.944 0.954

Oklahoma 0.971 0.789 0.990

Oregon 1.044 1.060 0.967

Pennsylvania 0.975 0.982 0.982

Rhode Island 1.001 1.040 0.980

South Carolina 0.954 0.726 0.970

South Dakota 0.989 0.778 0.970

Tennessee 0.968 0.803 0.998

Texas 0.965 0.807 0.991

Utah 1.018 0.899 0.951

Vermont 1.010 0.855 0.973

Virginia 0.972 0.838 0.966

Washington 1.062 1.016 0.964

West Virginia 0.970 0.937 1.005
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

50-01-0089 100

Materials Factor Subcontracting 

Factor

BE&K Construction 

Labor Factor

Wisconsin 0.984 0.959 0.979

Wyoming 1.003 0.826 0.939
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

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18.2. Net Downtime

Although mill or process downtime costs were not included in the analysis, an estimate 

was made of the net downtime. Since the work would be done during scheduled 

downtime, the net downtime is the additional time required above the typical scheduled 

downtime. The following is BE&K’s estimate for net downtime:

Good / Best 

Technology

Pollutant Equipment Net Downtime, 

days

Good PM NDCE Kraft Recovery Furnace 3

Best PM NDCE Kraft Recovery Furnace 3

Good SO2 NDCE Kraft Recovery Furnace 3

Best SO2 NDCE Kraft Recovery Furnace 3

Good NOx NDCE Kraft Recovery Furnace 3

Best NOx NDCE Kraft Recovery Furnace 3

Best VOC NDCE Kraft Recovery Furnace 3

Good PM DCE Kraft Recovery Furnace 3

Best PM DCE Kraft Recovery Furnace 3

Good SO2 DCE Kraft Recovery Furnace 3

Best SO2 DCE Kraft Recovery Furnace 3

Best NOx DCE Kraft Recovery Furnace 3

Good VOC DCE Kraft Recovery Furnace 4

Best VOC DCE Kraft Recovery Furnace 20

Good PM Smelt Dissolving tank 3

Best PM Smelt Dissolving tank 3

Good PM Lime Kilns 3

Best PM Lime Kilns 3

Best NOx Lime Kilns 3

Best NOx Lime Kilns 5

Good PM Coal Boiler 3

Best PM Coal Boiler 3
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

50-01-0089 102

Good / Best 

Technology

Pollutant Equipment Net Downtime, 

days

Good HCl Coal Boiler 3

Best HCl Coal Boiler 3

Good PM Coal/Wood Boiler (50/50) 3

Best PM Coal/Wood Boiler (50/50) 3

Good SO2 Coal or Coal/Wood boiler (50/50) 3

Best SO2 Coal or Coal/Wood boiler (50/50) 3

Good NOx Coal or Coal/Wood boiler (50/50) 3

Best NOx Coal or Coal/Wood boiler (50/50) 5

Best NOx Coal or Coal/Wood boiler (50/50) 3

Best Hg Coal or Coal/Wood boiler (50/50) 5

Best CO Coal or Coal/Wood boiler (50/50) 3

Good NOx Gas boiler 3

Best NOx Gas boiler 5

Good NOx Gas turbine 5

Good NOx Gas turbine 5

Best NOx Gas turbine 5

Good PM Oil boiler 3

Best PM Oil boiler 3

Good SO2 Oil boiler 3

Best SO2 Oil boiler 3

Good NOx Oil boiler 3

Best NOx Oil boiler 5

Good PM Wood boiler 5

Best PM Wood boiler 3

Best PM Wood boiler 5

Good NOx Wood boiler 3

Best NOx Wood boiler 3
AF&PA Emission Control Study –

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry

September 20, 2001

50-01-0089 103

Good / Best 

Technology

Pollutant Equipment Net Downtime, 

days

Best NOx Wood boiler 5

Best Hg Wood boiler 5

Best CO Wood boiler 3

Good VOC Paper machines 3

Best VOC Paper machines 3

Best VOC Paper machines 3

Good VOC Mechanical pulping 3

Best VOC Mechanical pulping 3

Best Various Recovery Furnace NA

Best PM NDCE Kraft Recovery Furnace 3

Good PM NDCE Kraft Recovery Furnace 3

Best PM Lime Kilns 3

Best PM Coal Boiler 3

Best PM Coal/Wood Boiler (50/50) 3

Best NOx NDCE Kraft Recovery Furnace 5

Best NOx DCE Kraft Recovery Furnace 5

Best VOC Mechanical Pulp 3