# Emission Contr ol Study – Te chnology Cost Estima tes **American Forest & Paper Association**  **Wa shington, D.C.** 

BE&K Engineering Birmingham, Alabama September 2001 Contract 50
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## Table of Contents **1. Results**  **................................ ................................**  **....................... 6**  **2. Capital Cost Estimate Basis** 
**................................ .....................**  **7 3.**  **Operating Cost Estimate Basis**
**................................ ................**  **8 4.**  **NO x**  

### 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 / W ood Boiler

................................ ................................ ....... 10 4.4. Gas Boiler

................................ ................................ ................................ 11 4.5. Gas Turbine

– Wa ter Injection

................................ ................................ .. 12 4.6. Gas Turbine

– Steam Injection

................................ ................................ . 13 4.7. Oil Boiler

................................ ................................ ................................ ... 14 4.8. Wo od Boiler

................................ ................................ .............................. 14 

### 5. **NO x**  

### 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
- NO x burners, & SCR

................................ ...................... 20 5.7. Coal or Coal / W ood Boiler

– SCR

................................ ........................... 21 5.8. Coal or Coal / W ood Boiler

– Switch to Natural Gas

................................ 22 5.9. Gas Boiler

................................ ................................ ................................ 23 5.10. Gas Turbine

................................ ................................ .......................... 24 5.11. Oil Boiler

................................ ................................ ............................... 25 5.12. Wo od Boiler
- SNCR

................................ ................................ ............. 26 5.13. Wo od Boiler

– SCR (technical feasibility)

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

### 6. **SO 2**  

### Reduction **– Good Technology Limits** 
**............................ 29** **AF &P**  **A Emission Control Study**  **–**

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- 0089 3 6.1. NDCE Recovery Boiler

................................ ................................ ............. 29 6.2. DCE Kraft Recovery Furnace

................................ ................................ ... 30 6.3. Coal or Coal / W ood Boiler

................................ ................................ ....... 31 6.4. Oil Boiler

................................ ................................ ................................ ... 3 2 

### 7. **SO 2**  

### Reduction **– Best Technology**  **Limits .............................**  **33** 7.1. NDCE Recovery Boiler

................................ ................................ ............. 33 7.2. DCE Kraft Recovery Furnace

................................ ................................ ... 34 7.3. Coal or Coal / W ood Boiler

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

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

### 8. **Mercury**

**Removal –**  **Best Technology Limit**  **.......................... 37**  8.1. Coal or Coal / W ood Boiler

................................ ................................ ....... 37 8.2. Wo od 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 / Wo od Boiler

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

................................ ................................ ................................ ... 45 9.9. Wo od 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 4 10.7. Coal Boiler

– New ESP

................................ ................................ ......... 53 10.8. Coal Boiler

– Rebuild Existing ESP

................................ ...................... 53 10.9. Coal / Wo od Boiler
- New

................................ ................................ ..... 54 10.10. Coa l / Wo od Boiler

– Rebuild Existing ESP

................................ .......... 55 10.11. Oil Boiler

................................ ................................ ............................... 56 10.12. Wo od Boiler

................................ ................................ .......................... 57 10.13. Wo od Boiler

– upgrade existing ESP

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

### 11. **Ca rbon Monoxide**  **– Best Technology**  **Limit ..........................**  **59** 11.1. Coal or Coal / W ood Boiler

................................ ................................ ... 59 11.2. Wo od 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 Fu rnace
................................ ............................... 63 14.2. Paper Machines

................................ ................................ .................... 64 14.3. Mechanical Pulping
- TMP

................................ ................................ .... 65 14.4. Mechanical Pulping

– Pressure Groundwood

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

### 15. **VOC –**  **Best Tech nolog**  **y Limit**  **................................ ................**  **67** 15.1. NDCE Kraft Recovery Furnace

................................ ............................. 67 15.2. DCE Kraft Recovery Furnace

................................ ............................... 68 15.3. Paper Machines

– We t End

................................ ................................ .. 69 15.4. Paper M achines

– Dry End

................................ ................................ ... 70 15.5. Mechanical Pulping

– TMP with Existing Heat Recovery System

......... 71 15.6. Mechanical Pulping

– TMP Wi thout Existing Heat Recovery System

... 71 15.7

. Mechanical Pulping

– Pressurized Groundwood Wi thout Existing Heat Recovery System

................................ ................................ ............................ 73 15.8. Mechanical Pulping

– Atmospheric Groundwood

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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. Opera ting Cost Estimate Assumptions

................................ ................. 80 16.6. Impact on Emissions

................................ ................................ ............ 81 

### 17. **Industry –**  **Wide Control Cost Estimates**
**............................... 83**  17.1. General Assumptions

................................ ................................ ........... 83 17.2. CO 2 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 / Wo od Boiler Assumptions

................................ .......................... 93 17.8. Gas Boiler Assumptions

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

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

................................ ................................ .......... 94 17.11. Wo od
- Fired Boiler Assumptions

................................ ........................... 95 17.12. Paper Machine Assumptions

................................ ................................ 96 17.13. Mechanical Pulping

................................ ................................ .............. 97 

### 18. **Ap pendix**  **................................ ................................**  **.................. 98**  18.1. MEANS and BE&K Labor Rate Factors by State

................................ .. 98 18.2. Net Downtime

................................ ................................ ..................... 101**AF &P**  **A Emission Control Study**  **–**

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## 1. Re sults See “AF&PA Emission Control Summary Sheet” Excel Spreadsheet**AF &P**  **A Emission Control Study**  **–**

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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, pay

roll, 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 co st was base upon 5% of the total direct costs. Although process or equipment downtime was considered for inclusion in the anal ys is, it was discarded as being of minimal impact. A net downtime anal ys is 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 f or each technology considered. The capital cost estimate does not include the following:**AF &P**  **A Emission Control Study**  **–**

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- 0089 8  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. Opera ting 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 typ e and amount of chemical used for the pollution control technology . The maintenance category includes the estimated maintenance lab or and maintenance material costs. The energy category was based upon the estimated installed horsepower utilizing a ty pical 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 & wastew ater 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.**AF &P**  **A Emission Control Study**  **–**

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## 4. NO x 

## Control Good Technolog y Limit **4.1. NDCE Kraft Recovery Furnace**  **4.1.1.** Description Combustion controls for recovery furnace s utilizing addition of a quartenary air system yielding a NO x level in the stack gases of 80 ppm @ 8% oxygen. Equipment sized for a NDCE recovery furnace burning 3.7 x 10 6 (Mm) lb BLS per day

. **4.1.2.** Major Equipment  Quartenary

air fan  Dampers  Flow meters  New C EMS **4.1.3.** Basis for Estimate Southeast Kraft mill recovery furnace firing 2.6 x 10 6

- 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 ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 10 **4.2. Lime Kiln**  **– Route SOGs to new Thermal Oxidizer**  **4.2.1.** Description For those s ys tems where the SOGs are incinerated in the limekiln, the SOGs will be rerouted to a new thermal oxidizer equipped with Low NO x controls and a caustic scrubber. The s ystem is sized for a limekiln producing 240 tpd CaO. **4.2.2.** Major Equipment 

##  Thermal oxidizer 

##  Caustic scrubber **4.2.3.** Basis for Es timate 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 dol lars **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 ye ar 

##  Water: 35 gpm **4.3. Coal or Coal / Wood Boiler**  **4.3.1.** Description Installation of Low NO x burners on a coal

- fired boiler producing 300,000 lb/hr of steam. The maximum NO x emission rate is 0.3 lb/Mm Btu**AF &P**  **A Emission Control Study**  **–**

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- 0089 11 **4.3.2.** Major Equipment 

##  Low NO x 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 ye ar. **4.4. Gas Boiler**  **4.4.1.** Description Low NO x burners and flue gas recirculation for a natural gas

- fired boil er producing 120,000 lb/hr of steam. The maximum NO x emission rate is 0.05 lb/Mmbtu as a 30

- day average. **4.4.2.** Major Equipment 

##  Low NO x burner assemblies 

##  Replace forced draft fan 

##  New CEMS 

##  Flue gas recirculation fan**AF &P**  **A Emission Control Study**  **–**

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- 0089 12 **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 lab or & materials : 3% of TIC  Power: 176 kw  Power usage factor: 70% 

##  Workhours: 1.5 hours per day 

##  Testing: $5,000 per ye ar. **4.5. Gas Turbine**  **– Water Injection**  **4.5.1.** Description Installation of water injection system for NO x emission control to reduce the NO x emissions to 25 ppm @ 15% oxygen for a 30

- day average. The s ys tem 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 s ystem for N O x 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**AF &P**  **A Emission Control Study**  **–**

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##  Power usage factor: 70% 

##  Workhours: 1 .5 hours per day 

##  Testing: $5,000 per ye ar. 

##  Water: 10 gpm **4.6. Gas Turbine**  **– Steam Injection**  **4.6.1.** Description Installation of steam injection system for NO x emission control to reduce the NO x emissions to 25 ppm @ 15% oxygen for a 30

- day average. The s ys tem was size d 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 s ystem for NO x reduction. The project costs are in 2001 dollars. **4.6.4.** Capital Co st 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 ye ar. 

##  Water: 4.76 gpm 

##  Steam: 2381 lb/hr**AF &P**  **A Emission Control Study**  **–**

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- 0089 14 **4.7. Oil Boiler**  **4.7.1.** Description Low NO x burners for oil

- fired boiler producing 135,000 lb/hr of steam. The maximum NO x emission rate is 0.2 lb/Mm Btu as a 30

- day average. **4.7.2.** Major Equipment 

##  Low NO x burner assemblies 

##  Replace forced draft fan 

##  New CEMS **4.7.3.** Ba sis 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.** Operati ng 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 ye ar **4.8. Wood Boiler**  **4.8.1.** Description Upgrade combustion controls and FD fan. The NO x 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**AF &P**  **A Emission Control Study**  **–**

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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**AF &P**  **A Emission Control Study**  **–**

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## 5. NO x 

## Control Best Technolog y Limit **5.1. Technical Feasibility**  **of SNCR and SCR Technologies** There are no SNCR units known to be operating for NO x control in a recovery boiler. While SN CR 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 ef fectiveness 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 NO x emissions in Sweden and therefore, it would be expected that either SCR or SNCR would be used extensively if they were cost
effective. Currentl y onl y combustion controls are used to reduce NO x . The SCR technology

presents unique problems with respect to potential poisoning of the catal ys t 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. ND**  **CE Kraft Recovery -**  **SNCR Technology 5.2.1.**  Description Selective non

- catal ytic reduction system for NO x control to achieve a maximum emission of 40 ppm @ 8% oxygen or achieve a 50% reduction using a 30

- day average. The s ys tem is sized for a NDCE recovery furnac e burning 3.7

- Mm lb BL S 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 BL S/day rate. The project was estimated in 1990. The inlet concentration was assumed 60 ppm with an outlet concentration of 24 ppm.**AF &P**  **A Emission Control Study**  **–**

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- 0089 17 **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 ye ar 

##  Water: 3 gpm **5.3. NDCE Kraft Recovery**  **– SCR Technology**  **5.3.1.** Description Installation of a SCR NO x control s ys tem in a NDCE recovery furnace burning 3.7 x 10 6 (Mm) lb BL S 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 NO x is estimated to be 92 ppm and the outlet NO x 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 18  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 ft3 per y r. 

##  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 ye ar 

##  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

- catal ytic reduction system for NO x control to achieve 50% reduction of the NO x . The system is sized for a DCE recovery furnace burning 1.7

- Mm lb BL S/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 BL S/day rate. The project was estimated in 1990. The inlet concentration was assumed 60 ppm with an outlet concentration of 30 ppm.**AF &P**  **A Emission Control Study**  **–**

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- 0089 19 **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 ye ar 

##  Water: 3 gpm **5.5. DCE Kraft Recovery**  **– SCR Technology**  **5.5.1.** Description Installation of a SCR NO x control s ys tem in a DCE recovery furnace burning 1.7 x 10 6 (Mm) lb BL S 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 NO x is estimated to be 67 ppm and the outlet NO x is estimated to be 13 ppm. **5.5.4.** Capital Cost Estimate Assumption s  Costs were factored using the “0.6 power.”  Costs were escalated to 2001 dollars**AF &P**  **A Emission Control Study**  **–**

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- 0089 20  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 ft3 per y r. 

##  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 ye ar 

##  Water: 4 gpm 

##  Steam: 1,190 lb/hr 

##  Compressed air: 26 cfm **5.6. Lime Kiln**  **– Low**  **- NO**  **x burners, & SCR**  **5.6.1.** Description Install Low NO x 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 NO x 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 21 **5.6.4.** Capital Cost Estimate Assumptions  Costs were factored using the “0.6 power.”  Costs were escalated to 2001 dollars  R&D co st: 1.5% of total direct costs (i.e., labor, materials, subcontract, and equipment) **5.6.5.** Operating Cost Estimate Assumptions 

##  Materials

– catalyst: 323 ft3 per y r. 

##  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 ye ar 

##  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 max imum NO x emission rate is 0.17 lb/Mm Btu for a 30

- day average. **5.7.2.** Major Equipment 

##  SCR reactor 

##  Low NO x burners 

##  Upgrade to forced draft fan 

##  ID fan**AF &P**  **A Emission Control Study**  **–**

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- 0089 22 **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

– cat alyst: 1219 ft3 per y r. 

##  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 ye ar 

##  Water: 7.43 gpm 

##  Steam: 2082 lb/hr 

##  Compressed air: 45 cfm **5.8. Coal or Coal / Wood Boile**  **r –**  **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**AF &P**  **A Emission Control Study**  **–**

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- 0089 23 **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 ye ar **5.9. Gas Boiler**  **5.9.1.** Description Installation of SCR on natural gas

- fired boiler producing 120,000 lb/hr of steam. The max imum NO x emission rate is 0.015 lb/Mm Btu utilizing a 30

- day average. **5.9.2.** Major Equipment 

##  SCR reactor 

##  Low NO x 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 24 **5.9.5.** Operating Cost Estimate Assumptions 

##  Materials

– catalyst: 464 ft3 per y r. @ $350 per ft 3 

##  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 ye ar 

##  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% NO x reduction. **5.10.2.** Major Equipment 

##  SCR reactor 

##  Low NO x 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 pro ject 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 25 **5.10.5.** Operating Cost Estimate Assumptions 

##  Materials

– catalyst: 298 ft3 per y r. @ $350 per ft 3 

##  Chemicals

– urea: 105 ton s per year 

##  Maintenance: 2% of TIC 

##  Power: 418 kw 

##  Power usage factor: 70% 

##  Workhours: 3 hr per day 

##  Testing: $5,000 per ye ar 

##  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 1 35,000 lb/hr of steam. The maximum NO x emission rate is 0.04 lb/Mmbtu for a 30

- day average or a 90% reduction. **5.11.2.** Major Equipment 

##  SCR reactor 

##  Low NO x 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 26  R&D cost: 0.5% of total direct costs (i.e., labor, materials, subcontract, and equipment) **5.11.5.** Op erating Cost Estimate Assumptions 

##  Materials

– catalyst: 679 ft3 per y r. @ $350 per ft 3 

##  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 ye ar 

##  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 NO x emission rate is 0.20 lb/ Mmbtu and represents a 40% reduction. **5.12.2.** Major Equipment 

##  Urea storage and metering s ys tem 

##  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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 27 **5.12.4.** Capital Cost Estimate Assumptions  Costs were factored using the “0.6 p ower.”  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 (tec**  **hnical 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 NO x 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 NO x 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 Assumpt ions  Costs were factored using the “0.6 power.”  Costs were escalated to 2001 dollars**AF &P**  **A Emission Control Study**  **–**

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- 0089 28  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 ft3 per y r. @ $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 ye ar 

##  Water: 5 gpm 

##  Steam: 1403 lb/hr 

##  Compressed air: 30 cfm**AF &P**  **A Emission Control Study**  **–**

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## 6. SO 2 

## Re duction – Good Technolog y Limits **6.1. NDCE R** **ecovery Boiler 6.1.1.**  Description Installation of a chemical scrubber to achieve sulfur dioxide (SO 2 ) level in stack gas of 50 ppm @ 8% oxygen. The s ys tem is sized for a NDCE recovery furnace burning 3.7

- Mm lb BL S 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 10 6

- 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 ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 30 **6.2. DCE Kraft Recovery Furnace**  **6.2.1.** Description Installation of a chemical scrubber to achieve sulfur dioxide (SO 2 ) level in stack gas of 50 ppm @ 8% oxygen. The s ys tem is sized for a DCE recovery furnace burning 1.7

- Mm lb BL S per day

. **6.2.2.** Major Equipm ent  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 10 6 lb 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 ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 31 **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 SO 2 level would be reduced b y 50% producing a max imum emission of 0.6 lb / Mm Btu. **6.3.2.** Major Equipment 

##  Scrubber tower 

##  Recirculation pump 

##  Booster fan 

##  Caustic feed s ys tem **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.** Capit al 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% causti c soda  Water: 143 gpm  Wastewater: 14 gpm  Workhours: 3 hours per day  Testing: $5,000 per ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 32 **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 SO 2 emission will be reduced b y 50% with a max imum emission rate of 0.4 lb/Mm Btu for a 30

- day average. **6.4.2.** Major Equipment 

##  Scrubber tower 

##  Booster fan 

##  Caustic feed s ys tem **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% c austic soda  Water: 42.9 gpm  Wastewater: 4.3 gpm  Workhours: 3 hours per day  Testing: $5,000 per ye ar**AF &P**  **A Emission Control Study**  **–**

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## 7. SO 2 

## Re duction – Best Technolog y Limits **7.1. NDCE Recovery Boiler**  **7.1.1.** Description Installation of a caustic scrubber to achieve sulfur dioxide (SO 2 ) level in stack ga s 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 10 6 lb 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  P ower: 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 ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 34 **7.2. DCE Kraft Recovery Furnace**  **7.2.1.** Description Installation of a caustic scrubber to achieve sulfur dioxi de (SO 2 ) 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 10 6 lb 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 ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 35 **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 SO 2 level would be reduced b y 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 s ystem **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.** Op erating 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 ye ar **7.4. Oil Boiler**  **7.4.1.** Descrip tion Installation of caustic scrubber on a oil

- fired boiler producing 135,000 lb/hr of steam. The SO 2 emission will be reduced b y 90% with a maximum emission rate of 0.08 lb/Mm Btu for a 30

- day average.**AF &P**  **A Emission Control Study**  **–**

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- 0089 36 **7.4.2.** Major Equipment 

##  Scrubber tower 

##  Booster fan 

##  Caustic f

eed s ys tem **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 doll ars **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 ye ar**AF &P**  **A Emission Control Study**  **–**

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## 8. Mercury Removal – Best Tec hnolog y Limit **8.1. Coal or Coal / Wood Boiler**  **8.1.1.** Description Installation of a spray

dryer absorber fabric filter dry scrubbing s ys tem 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/10 12 Btu to 8 lb/10 12 Btu, representing a 50% reduction. **8.1.2.** Major Equipment 

##  Fabric filter modules 

##  Lime storage and metering s ys tem 

##  Activated carbon storage and metering s ys tem 

##  Blower 

##  Atomizing air compressor 

##  Fabric filter scrubbing s ystem **8.1.3.** Basis for Estimate A budget quotation from WAPC for a spray dryer absorber fabric filter dry scrubbing s ys tem 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**AF &P**  **A Emission Control Study**  **–**

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##  Testing: $5,000 per ye ar 

##  Water: 64 gpm 

##  Wastewater: 20 gpm 

##  In cremental 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 s ys tem 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/10 12 Btu to 0.286 lb/10 12 Btu, representing a 50% reduction. **8.2.2.** Major Equipment 

##  Fabric filter modules 

##  Lime storage and metering s ys tem 

##  Activated carbon storage and metering s ys tem 

##  Blower 

##  Atomizing air compressor 

##  Fabric filter scrubbing s ystem **8.2.3.** Basis for Estimate A budget quotation from WAPC for a spray dryer absorber fabric filter dry scrubbing s ys tem 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 T IC 

##  Chemicals

– pebble lime: 375 lb/hr 

##  Power: 262 kw**AF &P**  **A Emission Control Study**  **–**

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##  Power usage factor: 70% 

##  Workhours: 3 hours per day 

##  Testing: $5,000 per ye ar 

##  Water: 90 gpm 

##  Wastewater: 28 gpm 

##  In cremental waste disposal: 1,576 tpy of carbon and lime**AF &P**  **A Emission Control Study**  **–**

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## 9. Pa rt iculate Matter – Good Technolog y 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 s ys tem is sized for a NDCE recovery furnace firing 3.7 Mm lb BL S per d ay **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 10 6 lb black liquor solids per day . Proje ct 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 10 6 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 &P**  **A Emission Control Study**  **–**

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- 0089 41 **9.2. NDCE Kraft Recovery Boiler**  **– Rebuilt Precipitator**  **9.2.1.** Description ESP upgrade b y addition of two parallel fields so that system is capa ble of achieving 0.044 gr/dscf @ 8% oxygen of particulate matter. The s ys tem 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 s ys tem **9.2.3.** Basis for Estimate Southeast Kraft mill with a recovery boiler firing 2.70 x 10 6 lb 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 10 6 lb black liquor solids p er day

.  Costs escalated to 2001 **9.2.5.** Operating Cost Estimate Assumptions  Maintenance labor and materials

– 2% of T ICcost  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 s ys tem 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 ac id

- brick lined  Modification to existing ID fan**AF &P**  **A Emission Control Study**  **–**

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- 0089 42  Conveyors  Dampers **9.3.3.** Basis for Estimate Southeast Kraft mill with a recovery boiler firing 2.15 x 10 6 lb black liquor solids per day . Project estimated in 2000. **9.3.4.** Capital Cost Estimate Assumptions  Costs were adjus ted utilizing the 0.6 rule to obtain the cost for an ESP at 1.7 x 10 6 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 fur nace firing 3.7 Mm lb BL S 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 43 **9.4.4.** Capital Cost Estimate Assumptions  C osts were adjusted utilizing the 0.6 rule to obtain the cost for a smelt

dissolving tank scrubber at a recovery furnace firing rate of 3.7 x 10 6 lb black liquor solids per day . Costs escalated to 2001 **9.4.5.** Operating Cost Estimate Assumptions  Maintenance labor and materials

– 2% of T ICcost  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 T ICcost**AF &P**  **A Emission Control Study**  **–**

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- 0089 44  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 T ICcost  Power

– 1331 kw  Power usage factor: 70%  Workhours

– 3 hours per day  Testing

- $5,000 per year  In cremental waste disposal: 39 tpy of ash**AF &P**  **A Emission Control Study**  **–**

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- 0089 45 **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 estimate d 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 T ICcost  Power

– 1331 kw  Power usage factor: 70%  Workhours

– 3 hours per day  Testing

- $5,000 per year  In cremental 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 46 **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 o f 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 Assumptio ns  Maintenance labor and materials

– 3% of T ICcost  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 precip itator 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 produc ing 600,000 lb/hr of steam. The project was estimated in 1992.**AF &P**  **A Emission Control Study**  **–**

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- 0089 47 **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  In cremental waste disposal: 551 tpy of ash**AF &P**  **A Emission Control Study**  **–**

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- 0089 48 

## 10. Pa rt iculate Matter – Best Technolog y 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 s ys tem would be installed in a recovery furnace burning 3.7 Mm lb BL S 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 10 6 lb 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 10 6 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 49 **10.2. NDCE Kraft Recovery Boiler**  **– Rebuilt Precip**  **itator 10.2.1.**  Description ESP upgrade b y addition of two parallel fields so that system is capable of achieving 0.015 gr/dscf @ 8% oxygen of particulate matter. The s ys tem is sized for a NDCE recovery

furnace firing 3.7 Mm lb BLS per day **10.2.2.** Major Equipment  Modific ation to existing ESP  Modifications to ash handling s ys tem **10.2.3.** Basis for Estimate Southeast Kraft mill with a recovery boiler firing 2.70 x 10 6 lb 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 10 6 lb black liquor solids per day

.  Costs escalated to 2001 **10.2.5.** Operating Cost Estimate Assumptions  Maintenance labor and materials

– 2% of T ICcost  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 s ys tem 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 50  Conveyors  Dampers **10.3.3.** Basis for Estimate Southeast Kraft mill with a recovery boiler firing 2.15 x 10 6 lb 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 10 6 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 BL S 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 51 **10.4.4.** Capital Cost Estimate Assumptions  Costs were adjusted utilizing the 0.6 rule to obtain the cost for a smelt

dissolving tank scrubber at a recovery furnace firing rate of 3.7 x 10 6 lb black liquor solids per day.  Costs escalated to 2001 **10.4.5.** Operating Cost Estimate Assumptions  Maintenance labor and materials

– 2% of T ICcost  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.** Bas is 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 52 **10.5.5.** Operating Cost Estimate Assumptions  Maintenance labor and materials

– 3% of T ICcost  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 proces sing 240 TPD of CaO **10.6.5.** Operating Cost Estimate Assumptions  Maintenance labor and materials

– 1% of T ICcost  Power

– 100 kw  Power usage factor: 70%  Workhours

– 1.5 hours per day  Testing

- $5,000 per year**AF &P**  **A Emission Control Study**  **–**

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- 0089 53 **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 cap able 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 T ICcost  Power

– 1664 kw  Power usage factor: 80%  Workhours

– 3 hours per day  Testing

- $5,000 per year  In cremental 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 54 **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 T ICcost  Power

– 550 kw  Power usage factor: 70%  Workhours

– 3 hours per day  Testing

- $5,000 per year  In cremental 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 55 **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 T ICcost  Power 1331 kw  Power usage factor: 80%  Workhours

– 3 hours per day  Testing

- $5,000 per year  In cremental 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 boil er 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 56 **10.10.5.** Operating Cost Estimate Assumption s  Maintenance labor and materials

– 1% of T ICcost  Power 500 kw  Power usage factor: 70%  Workhours

– 3 hours per day  Testing

- $5,000 per year  In cremental 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 Estimat e Assumptions  Maintenance labor and materials

– 3% of T ICcost  Power

– 1098 kw  Power usage factor: 70%  Workhours

– 3 hours per day**AF &P**  **A Emission Control Study**  **–**

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- 0089 57  Testing

- $5,000 per year  In cremental 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  In cremental waste disposal: 599 tpy of ash**AF &P**  **A Emission Control Study**  **–**

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- 0089 58 **10.13. Wood Boiler**  **– upgrade existing ESP**  **10.13.1.** Descri ption 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 Estim ate 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 bo iler 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  In cremental waste disposal: 116 tpy of ash**AF &P**  **A Emission Control Study**  **–**

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- 0089 59 

## 11. Carbon Monoxide – Best Tec hnolog y 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 T ICcost  Power

– 298 kw  Power usage factor: 70%  Workhours

– 1.5 hours per day  Testing

- $5,000 per year**AF &P**  **A Emission Control Study**  **–**

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- 0089 60 **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 Estima te Assumptions  Maintenance labor and materials

– 3% of T ICcost  Power

– 298 kw  Power usage factor: 70%  Workhours

– 1.5 hours per day  Testing

- $5,000 per year**AF &P**  **A Emission Control Study**  **–**

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## 12. HCl – Good Tec hnolog y 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 s ys tem **12.1.3.** Basis for Estimate Southe astern 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 Assumpti ons  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 ye ar  Water: 64 gpm  Wastewater: 20 gpm  Workhours: 3 hours per day**AF &P**  **A Emission Control Study**  **–**

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## 13. HCl – Best Tec hnolog y 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 s ys tem **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  Cost s 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 ye ar  Water: 64 gpm  Wastewater: 20 gpm  Workhours: 3 hours per day**AF &P**  **A Emission Control Study**  **–**

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## 14. VO C – Good Technolog y 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 BL S 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 BL S 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 ye ar  Steam: 500 lb/hr  Workhours: 3 hours per day**AF &P**  **A Emission Control Study**  **–**

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- 0089 64 **14.2. Paper Machines**  **14.2.1.** Description Based upon NCAS I 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 b y 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 s ys tem ba sed 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 ye ar**AF &P**  **A Emission Control Study**  **–**

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- 0089 65  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 w ere deemed beyond the scope of this study

. **14.3. Mechanical Pulping**  **- TMP**  **14.3.1.** Description Installation of a heat recovery s ys tem 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 s ys tem based upon quotation from Andritz

- Ahlstrom for a 50 0 ADTPD TMP heat recovery s ys tem. 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.)**AF &P**  **A Emission Control Study**  **–**

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- 0089 66 **14.4. Mechanical Pulping**  **– Pressure Groundw**  **ood 14.4.1.**  Description Installation of a heat recovery s ys tem on pressure groundwood systems which will produce clean steam, a NCG vent, and dirty condensates. The s ys tem 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 s ys tem 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 Estimat e Assumptions  Maintenance labor & materials: 3% of TIC  Power: 165 kw  Power usage factor: 70%  Testing: $5,000 per ye ar  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 a ssumes that the heat recovery would be 20% of that for a comparable TMP plant.)**AF &P**  **A Emission Control Study**  **–**

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## 15. VO C – Best Technolog y 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 BL S per day . The work was done in October 1 993. **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 ye ar  Workhours: 1.5 hours per day**AF &P**  **A Emission Control Study**  **–**

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- 0089 68 **15.2. DCE Kraft Recovery Furnace**  **15.2.1.** Description Conversion of DCE recovery furnace burning 1.7 Mm lb BL S per day to a NDCE ty pe. **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 BL S 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.** Ope rating Cost Estimate Assumptions  Maintenance labor & materials: 3% of TIC  Power: 450 kw  Power usage factor: 70%  Testing: $5,000 per ye ar  Steam: (26,984 lb/hr) (steam savings)  Workhours: 3 hours per day**AF &P**  **A Emission Control Study**  **–**

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- 0089 69 **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 

##  316Lstainless 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 p ower.”  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 ye ar  Natural gas: 4.71 Mmbtu/hr  Workhours: 1.5 hours per day**AF &P**  **A Emission Control Study**  **–**

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- 0089 70 **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 

##  316Lstainless 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 2 000. **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 ye ar  Natural gas: 8.1 MmBtu/hr  Workhours: 1.5 hours per day**AF &P**  **A Emission Control Study**  **–**

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- 0089 71 **15.5. Mechanical Pulping**  **– TMP with Existing Heat Recovery**  **S ys**  **tem 15.5.1.**  Description Collection and incineration of the NCGs from a TMP heat recovery s ys tem . 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 proje ct 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 ye ar 

##  Water: 10gpm 

##  Wastewater: 10 gpm **15.6. Mechanical Pulping**  **– TMP Without Existing Heat Recovery**  **S ys**  **tem 15.6.1.**  Description Installation of a heat recovery s ys tem on mechanical pulping s ys tems 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 72 **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 s ys tem based upon quotation from Andritz

- Ahlstrom for a 500 ADTPD TMP heat recovery s ys tem. The quotation was in 2001 dollars. For NCG colle ction 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 ye ar 

##  Water: 202gpm 

##  Wastewater: 204 gpm 

##  Steam: (94,255 lb/hr) (This is projected amount of steam to be recovered)**AF &P**  **A Emission Control Study**  **–**

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- 0089 73 **15.7. Mechanical Pulping**  **– Pressurized Groundwood Without Existing**  **Heat Recovery Sy stem**  **15.7.1.** Description Installation of a heat recovery s ys tem on pressurized groundwood pulping systems which will produce clean steam, a N CG 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 s ys tem based upon quotation from Andritz

- Ahlstrom for a 500 ADTPD TMP heat recovery system. The quotation was in 2 001 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%**AF &P**  **A Emission Control Study**  **–**

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##  Workhours: 2.25 hours per day 

##  Testing: $5,000 per ye ar 

##  Water: 202gpm 

##  Wastewater: 49 gpm 

##  S team: (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 Groundw**  **ood 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 Assumption s 

##  Maintenance labor & materials: 3.5% of TIC 

##  Power: 22 kw 

##  Power usage factor: 70% 

##  Workhours: 2.25 hours per day**AF &P**  **A Emission Control Study**  **–**

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##  Testing: $5,000 per ye ar 

##  Water: 10gpm 

##  Wastewater: 10 gpm**AF &P**  **A Emission Control Study**  **–**

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- 0089 76 

## 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

Ga s 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 steam

reforming 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 77 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 b y this s ys tem is probably not sufficient for a ty pical Kraft mill. The additional steam requirements will either need to be provided by a biomass gasifier or boiler or a power boiler. These additi onal 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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- 0089 78 **16.2. Major Equipment**  The major subs ys tems 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 l ine 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. Puls ed 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 sep arator, 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 79 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 s ys tems 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 A**  **ssumptions**  Costs were factored using the “0.6 power.”  Costs were escalated to 2001 dollars  Engineering was assumed to 8% vs. the s tandard 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 80  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 A**  **ssumptions** 

##  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**AF &P**  **A Emission Control Study**  **–**

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- 0089 81 **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 (NO x ) 18.7 46.1 64.7 Carbon monoxide (CO) 11.4 56.1 67.5 Sulfur dioxide (SO 2 ) 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 H 2 S) 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 (NO x ) 89.2 16.1 105.3 Carbon monoxide (CO) 516.5 0 .3 516.8 Sulfur dioxide (SO 2 ) 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 H 2 S) 4.7 2.5 7.2**AF &P**  **A Emission Control Study**  **–**

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- 0089 82 Additionally

for carbon dioxide the black liquor gasification emission rate is estimated to be 240,400 lb/hr for a 4 Mm lb BL S/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

s ys tem:

**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 AF**  **&P A**  **Emission Control Study –** 

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## 17. Industry – Wi de Control Cost Estimates **17.1. Gen**  **eral A**

**ssumptions** 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 b y craft from 6 to 30% of base rate

Indirects $27.00 In cludes home office expenses, field supervision, temporary

facilities, tools/ consumables, construction equipment, permits/miscellaneous, and contractor’s fee Premium mark

up $2.07 Per diem $4.66 In cludes direct and indirect **Total $58.62** **AF &P**  **A Emission Control Study**  **–**

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##  The labor costs portion of the TI C were adjusted for each mill utilizing the BE&K labor rates b y 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 b y 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% 19 99 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 proporti onately 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 /y r. The water usage used the same formula but with only 350 dy /y r.**AF &P**  **A Emission Control Study**  **–**

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##  The steam and compressed air usage was calcul ated by multiplying the usage per feed rate x feed rate per day x 350 dy /y r. 

##  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 (assume s 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 (ty pically 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/ye ar x the hourly

rate. The hourl y rate was obtained from AF&PA Labor**AF &P**  **A Emission Control Study**  **–**

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- 0089 86 Database with 91% of m ember contracts entered (missing about 20); the average hourly rate for year 2000 was $18.14. This data only includes hourl y employees. An additional 40% was added to the figure to account for benefits to yi eld 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. 

##  NCASIprovided the mill code for the BE&K supplied paper machine and mechanical pulping information. **17.2. CO**  **2 Emission A**  **ssumptions**  The CO 2 emissions were calculated b y multiplying the 1995 NCASIfossil fuel usage from the power boilers, recovery f urnaces, and lime kilns times the CO 2 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 CO 2 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. Reco** **very Furnace A ssumptions**  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, NO x 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 87 **17.3.2.** NO x 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 NO x emission rates from the NCASIdatabase were converted to lb/Mm Btu and compared with 80% of the above limits. The NO x 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 b y 50% after treatment **17.3.3.** SO 2 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 SO 2 emission rates from the NCASIdatabase were converted to lb/Mm Btu basis and compared with 80% of the above limits. The SO 2 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 SO 2 emission rates from the 1995 NC ASI database:**AF &P**  **A Emission Control Study**  **–**

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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 T echnology Limit 

# Recovery Furnace SO2 Emission

**Distribution**

 For recovery

furnaces with up to four

- times the adjusted SO 2 limit (i.e., 0.3628 lb/Mm Btu), combustion control modifications (**these are**  **the same**  **as what**  **was estimated**  **for good**  **controls for**  **NO x** ) would be implemented. For recovery furnaces with SO 2 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 tre atment 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 Contro l Technology 

##  Any recovery furnace ESP built or rebuilt after 1990 but before 1998 was assumed capable of meeting the good PM technology limit.**AF &P**  **A Emission Control Study**  **–**

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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 BL S/ 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 furnac e built or rebuilt after 1990 was assumed to meet the best PM technology

limit**AF &P**  **A Emission Control Study**  **–**

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- 0089 90 **17.4. Lime Kiln A** 

**ssumptions** 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.** NO x Control Technology 

##  If the annual NCASI

- estimated NO x levels are less than 20 TPY, no controls will be added. This level represents approximately 10% of the limekilns from the NCASIdatabase. 

##  If no emi ssions 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 NO x level in the limekiln if NCGs are being burned will decrease b y 30% if the SOGs are burned in a thermal oxidizer. The thermal oxidizer would be equipped with staged combustion to control the NO x levels. 

##  The NO x level in the limekiln will decrease b y 60% with the incorporation of SCR and low

-NO x 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,**AF &P**  **A Emission Control Study**  **–**

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- 0089 91  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 Wo od 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 NCASIfuel usage (if given) and Btu estimate. The steam output was calculate d from the Btu estimate and the boiler efficiency, which was assumed 85% for every thing, 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 SO 2 , and NO x ye arl y emission rates were converted to pounds and divided by

Btus to determine a lb/MmBtu emission rate. 

##  The SO 2 and NO x 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 3 0

- 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 SO 2 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 fue l consumption information on 1074 of them. Control technology estimates for boilers were onl y made if fuel consumption information was provided.**AF &P**  **A Emission Control Study**  **–**

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- 0089 92 **17.6. Coal Boiler A** 

**ssumptions 17.6.1.**  General  If more than 80% of the gross Btu’s originated from coal, then the boiler wa s assumed a coal boiler. **17.6.2.** NO x Limits  Any coal boilers after 1990 are assumed to have low NO x burners and are assumed to meet the 0.3 lb/10 6 Btu, 30

- day average.  If the coal boilers were converted to natural gas with low NO x -burners, then the emission rates were assumed to be 0.0490 and 0.1373 lb / 10 6 Btu for boilers less than and greater than 100 million Btu/hr, respectively

. **17.6.3.** SO 2 Limits  Application of scrubbers to coal boilers will yield 50% reduction at good technology

and 90% reduction at best technolo gy. **17.6.4.** Hg limits  The uncontrolled limits were obtained b y multiplying the MmBtu/ye ar for 1995 by 16 lb/10 12 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 b y adding a single field. If the ye ar the ESP was constructed or rebuilt was not in the NCASIdatabase, 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 l imits  Any coal boiler constructed after 1990 is assumed to be able to meet the best technology

limit of 200 ppm (24

-hour average).**AF &P**  **A Emission Control Study**  **–**

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- 0089 93 **17.6.7.** HCl limits  Use same criteria as for SO 2 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 SO 2 control is installed there will be no need to install HCl controls as well; the chemical addition rate for SO 2 is greater than what is required to remove the HCl present. **17.7. Coal / Wood Boiler A** **ssumptions 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.** NO x Limits  Any coal boilers after 1990 were assumed to have low NO x burners and were assumed to meet the 0.3 lb/10 6 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.** SO 2 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 b y multiplying the MmBtu/ye ar for 1995 by 16 lb/10 12 Btu for coal and b y 0.572 lb/10 12 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 b y adding a single field in two chambers. If the ye ar the ESP was constructed or rebuilt was not in the NCASIdatabase, then the ESP was assumed to have been built or rebuilt before 1980.**AF &P**  **A Emission Control Study**  **–**

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- 0089 94  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 A** 

**ssumptions 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.** NO x Limits  Any gas boilers after 1990 are assumed to have low

-NO x burners and are assumed to meet the 0.05 lb/10 6 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 A** 

**ssumptions 17.9.1.**  NO x 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 A** 

**ssumptions 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.**AF &P**  **A Emission Control Study**  **–**

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- 0089 95  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.** NO x Limits  Any oil boilers after 1990 are assumed to have low

-NO x burners and are assumed to meet the 0.2 lb/10 6 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.** SO 2 Limits  Application of scrubbers to oi l 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 technolo gy 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 A**  **ssumptions 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.** NO x Limits  Any wood boiler after 1990 are assumed to have combustion controls and are assumed to meet the 0.25 lb/10 6 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 af ter treatment (i.e., 80% of the 30

- day average limits).**AF &P**  **A Emission Control Study**  **–**

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- 0089 96 **17.11.3.** Hg limits  The uncontrolled limits were obtained b y multiplying the MmBtu/ye ar for 1995 by 0.572 lb/10 12 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 E SP was built or rebuilt before 1980, the ESP’s would be upgraded b y adding a single field in two chambers. If the ye ar the ESP was constructed or rebuilt was not in the NCASIdatabase, 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 A**  **ssumptions** 

##  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 every thing but mechanical pulping, which was set at 100 tons per day

.**AF &P**  **A Emission Control Study**  **–**

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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: NCASITech Bulletin No. 681) 

##  The emi ssion 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 ye ar 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 c onstructed after 1998 is assumed to meet the best technology limits.**AF &P**  **A Emission Control Study**  **–**

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- 0089 98 

## 18. Appendix **18.1. MEA**  **NS and BE&K Labor Rate Factors by State**  The following presents the state factors for the RS Means Open Shop Building Construction Cost Data 17 th 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 Id aho 1.021 0.938 0.960 Illinois 0.970 1.041 0.997 Indiana 0.975 0.957 0.958 Io wa 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**AF &P**  **A Emission Control Study**  **–**

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- 0089 99 Materials Factor Subcontracting Factor BE&K Construction

Labor Factor Michigan 0.970 0.948 0.973 Minnesota 0.984 1.073 0.983 Miss issippi 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 I sland 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 &P**  **A Emission Control Study**  **–**

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- 0089 100 Materials Factor Subcontracting Factor BE&K Construction

Labor Factor Wisconsin 0.984 0.959 0.979 Wyoming 1.00 3 0.826 0.939**AF &P**  **A Emission Control Study**  **–**

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- 0089 101 **18.2. Net Dow**  **ntime** Although mill or process downtime costs were not included in the anal ys is, 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 S O2 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 &P**  **A Emission Control Study**  **–**

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- 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 b oiler 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 &P**  **A Emission Control Study**  **–**

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- 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 Ki lns 3 Best PM Coal Boiler 3 Best PM Coal/W ood Boiler (50/50) 3 Best NOx NDCE Kraft Recovery Furnace 5 Best NOx DCE Kraft Recovery Furnace 5 Best VOC Mechanical Pulp 3