Emission Control Study – Technology Cost Estimates

American Forest & Paper Association 

Washington, D.C.

BE&K Engineering

Birmingham, Alabama

September 2001

Contract 50-01-0089

Table of Contents  TOC \o "1-2"  

1.	Results	  PAGEREF _Toc521810029 \h  6 

2.	Capital Cost Estimate Basis	  PAGEREF _Toc521810030 \h  7 

3.	Operating Cost Estimate Basis	  PAGEREF _Toc521810031 \h  8 

4.	NOx Control Good Technology Limit	  PAGEREF _Toc521810032 \h  9 

4.1.	NDCE Kraft Recovery Furnace	  PAGEREF _Toc521810033 \h  9 

4.2.	Lime Kiln – Route SOGs to new Thermal Oxidizer	  PAGEREF
_Toc521810034 \h  10 

4.3.	Coal or Coal / Wood Boiler	  PAGEREF _Toc521810035 \h  10 

4.4.	Gas Boiler	  PAGEREF _Toc521810036 \h  11 

4.5.	Gas Turbine – Water Injection	  PAGEREF _Toc521810037 \h  12 

4.6.	Gas Turbine – Steam Injection	  PAGEREF _Toc521810038 \h  13 

4.7.	Oil Boiler	  PAGEREF _Toc521810039 \h  14 

4.8.	Wood Boiler	  PAGEREF _Toc521810040 \h  14 

5.	NOx Control Best Technology Limit	  PAGEREF _Toc521810041 \h  16 

5.1.	Technical Feasibility of SNCR and SCR Technologies	  PAGEREF
_Toc521810042 \h  16 

5.2.	NDCE Kraft Recovery  - SNCR Technology	  PAGEREF _Toc521810043 \h 
16 

5.3.	NDCE Kraft Recovery – SCR Technology	  PAGEREF _Toc521810044 \h 
17 

5.4.	DCE Kraft Recovery – SNCR Technology	  PAGEREF _Toc521810045 \h 
18 

5.5.	DCE Kraft Recovery – SCR Technology	  PAGEREF _Toc521810046 \h 
19 

5.6.	Lime Kiln – Low-NOx burners, & SCR	  PAGEREF _Toc521810047 \h  20


5.7.	Coal or Coal / Wood Boiler – SCR	  PAGEREF _Toc521810048 \h  21 

5.8.	Coal or Coal / Wood Boiler – Switch to Natural Gas	  PAGEREF
_Toc521810049 \h  22 

5.9.	Gas Boiler	  PAGEREF _Toc521810050 \h  23 

5.10.	Gas Turbine	  PAGEREF _Toc521810051 \h  24 

5.11.	Oil Boiler	  PAGEREF _Toc521810052 \h  25 

5.12.	Wood Boiler - SNCR	  PAGEREF _Toc521810053 \h  26 

5.13.	Wood Boiler – SCR (technical feasibility)	  PAGEREF
_Toc521810054 \h  27 

6.	SO2 Reduction – Good Technology Limits	  PAGEREF _Toc521810055 \h 
29 

6.1.	NDCE Recovery Boiler	  PAGEREF _Toc521810056 \h  29 

6.2.	DCE Kraft Recovery Furnace	  PAGEREF _Toc521810057 \h  30 

6.3.	Coal or Coal / Wood Boiler	  PAGEREF _Toc521810058 \h  31 

6.4.	Oil Boiler	  PAGEREF _Toc521810059 \h  32 

7.	SO2 Reduction – Best Technology Limits	  PAGEREF _Toc521810060 \h 
33 

7.1.	NDCE Recovery Boiler	  PAGEREF _Toc521810061 \h  33 

7.2.	DCE Kraft Recovery Furnace	  PAGEREF _Toc521810062 \h  34 

7.3.	Coal or Coal / Wood Boiler	  PAGEREF _Toc521810063 \h  35 

7.4.	Oil Boiler	  PAGEREF _Toc521810064 \h  35 

8.	Mercury Removal – Best Technology Limit	  PAGEREF _Toc521810065 \h 
37 

8.1.	Coal or Coal / Wood Boiler	  PAGEREF _Toc521810066 \h  37 

8.2.	Wood Boiler	  PAGEREF _Toc521810067 \h  38 

9.	Particulate Matter – Good Technology Limits	  PAGEREF _Toc521810068
\h  40 

9.1.	NDCE Kraft Recovery Boiler – New Precipitator	  PAGEREF
_Toc521810069 \h  40 

9.2.	NDCE Kraft Recovery Boiler – Rebuilt Precipitator	  PAGEREF
_Toc521810070 \h  41 

9.3.	DCE Kraft Recovery Boiler	  PAGEREF _Toc521810071 \h  41 

9.4.	Smelt Dissolving Tank	  PAGEREF _Toc521810072 \h  42 

9.5.	Lime Kiln	  PAGEREF _Toc521810073 \h  43 

9.6.	Coal Boiler	  PAGEREF _Toc521810074 \h  44 

9.7.	Coal / Wood Boiler	  PAGEREF _Toc521810075 \h  45 

9.8.	Oil Boiler	  PAGEREF _Toc521810076 \h  45 

9.9.	Wood Boiler	  PAGEREF _Toc521810077 \h  46 

10.	Particulate Matter – Best Technology Limit	  PAGEREF _Toc521810078
\h  48 

10.1.	NDCE Kraft Recovery Boiler – New Precipitator	  PAGEREF
_Toc521810079 \h  48 

10.2.	NDCE Kraft Recovery Boiler – Rebuilt Precipitator	  PAGEREF
_Toc521810080 \h  49 

10.3.	DCE Kraft Recovery Boiler	  PAGEREF _Toc521810081 \h  49 

10.4.	Smelt Dissolving Tank	  PAGEREF _Toc521810082 \h  50 

10.5.	Lime Kiln – New ESP	  PAGEREF _Toc521810083 \h  51 

10.6.	Lime Kiln – Upgraded ESP	  PAGEREF _Toc521810084 \h  52 

10.7.	Coal Boiler – New ESP	  PAGEREF _Toc521810085 \h  53 

10.8.	Coal Boiler – Rebuild Existing ESP	  PAGEREF _Toc521810086 \h 
53 

10.9.	Coal / Wood Boiler - New	  PAGEREF _Toc521810087 \h  54 

10.10.	Coal / Wood Boiler – Rebuild Existing ESP	  PAGEREF
_Toc521810088 \h  55 

10.11.	Oil Boiler	  PAGEREF _Toc521810089 \h  56 

10.12.	Wood Boiler	  PAGEREF _Toc521810090 \h  57 

10.13.	Wood Boiler – upgrade existing ESP	  PAGEREF _Toc521810091 \h 
58 

11.	Carbon Monoxide – Best Technology Limit	  PAGEREF _Toc521810092 \h
 59 

11.1.	Coal or Coal / Wood Boiler	  PAGEREF _Toc521810093 \h  59 

11.2.	Wood Boiler	  PAGEREF _Toc521810094 \h  60 

12.	HCl – Good Technology Limit	  PAGEREF _Toc521810095 \h  61 

12.1.	Coal Boiler	  PAGEREF _Toc521810096 \h  61 

13.	HCl – Best Technology Limit	  PAGEREF _Toc521810097 \h  62 

13.1.	Coal Boiler	  PAGEREF _Toc521810098 \h  62 

14.	VOC – Good Technology Limit	  PAGEREF _Toc521810099 \h  63 

14.1.	DCE Kraft Recovery Furnace	  PAGEREF _Toc521810100 \h  63 

14.2.	Paper Machines	  PAGEREF _Toc521810101 \h  64 

14.3.	Mechanical Pulping - TMP	  PAGEREF _Toc521810102 \h  65 

14.4.	Mechanical Pulping – Pressure Groundwood	  PAGEREF _Toc521810103
\h  66 

15.	VOC – Best Technology Limit	  PAGEREF _Toc521810104 \h  67 

15.1.	NDCE Kraft Recovery Furnace	  PAGEREF _Toc521810105 \h  67 

15.2.	DCE Kraft Recovery Furnace	  PAGEREF _Toc521810106 \h  68 

15.3.	Paper Machines – Wet End	  PAGEREF _Toc521810107 \h  69 

15.4.	Paper Machines – Dry End	  PAGEREF _Toc521810108 \h  70 

15.5.	Mechanical Pulping – TMP with Existing Heat Recovery System	 
PAGEREF _Toc521810109 \h  71 

15.6.	Mechanical Pulping – TMP Without Existing Heat Recovery System	 
PAGEREF _Toc521810110 \h  71 

15.7.	Mechanical Pulping – Pressurized Groundwood Without Existing
Heat Recovery System	  PAGEREF _Toc521810111 \h  73 

15.8.	Mechanical Pulping – Atmospheric Groundwood	  PAGEREF
_Toc521810112 \h  74 

16.	Gasification	  PAGEREF _Toc521810113 \h  76 

16.1.	Description of Technology	  PAGEREF _Toc521810114 \h  76 

16.2.	Major Equipment	  PAGEREF _Toc521810115 \h  78 

16.3.	Basis for Estimate	  PAGEREF _Toc521810116 \h  79 

16.4.	Capital Cost Estimate Assumptions	  PAGEREF _Toc521810117 \h  79 

16.5.	Operating Cost Estimate Assumptions	  PAGEREF _Toc521810118 \h  80


16.6.	Impact on Emissions	  PAGEREF _Toc521810119 \h  81 

17.	Industry – Wide Control Cost Estimates	  PAGEREF _Toc521810120 \h 
83 

17.1.	General Assumptions	  PAGEREF _Toc521810121 \h  83 

17.2.	CO2 Emission Assumptions	  PAGEREF _Toc521810122 \h  86 

17.3.	Recovery Furnace Assumptions	  PAGEREF _Toc521810123 \h  86 

17.4.	Lime Kiln Assumptions	  PAGEREF _Toc521810124 \h  90 

17.5.	Boiler and Turbine Assumptions	  PAGEREF _Toc521810125 \h  90 

17.6.	Coal Boiler Assumptions	  PAGEREF _Toc521810126 \h  92 

17.7.	Coal / Wood Boiler Assumptions	  PAGEREF _Toc521810127 \h  93 

17.8.	Gas Boiler Assumptions	  PAGEREF _Toc521810128 \h  94 

17.9.	Gas Turbine Assumptions	  PAGEREF _Toc521810129 \h  94 

17.10.	Oil Boiler Assumptions	  PAGEREF _Toc521810130 \h  94 

17.11.	Wood-Fired Boiler Assumptions	  PAGEREF _Toc521810131 \h  95 

17.12.	Paper Machine Assumptions	  PAGEREF _Toc521810132 \h  96 

17.13.	Mechanical Pulping	  PAGEREF _Toc521810133 \h  96 

18.	Appendix	  PAGEREF _Toc521810134 \h  98 

18.1.	MEANS and BE&K Labor Rate Factors by State	  PAGEREF _Toc521810135
\h  98 

18.2.	Net Downtime	  PAGEREF _Toc521810136 \h  101 

 Results

See “AF&PA Emission Control Summary Sheet” Excel Spreadsheet

Capital Cost Estimate Basis

The capital cost estimate is based upon similar projects that have been
done within the last 10 years.  The costs were escalated to 2001
dollars, where necessary.  The capital cost estimates were divided into
labor, materials, subcontracts, and equipment.  The 0.6 power conversion
[Cost of Project A x (AF&PA rate / Project A)0.6] rate was used to
adjust the estimated costs to the AF&PA sizing criteria for each control
technology.

For some of the selected technologies – Mercury removal, VOC removal
on paper machines, use of SCR on a non-gas fired combustion unit, use of
SNCR on recovery furnace, and black liquor gasification - Research &
Development costs were factored in.  The R&D costs were assumed to be
0.5 to 1.5% of the direct costs – labor, materials, subcontract, and
equipment. 

The labor cost includes the labor rate and construction indirects (i.e.,
equipment rental, small tool rentals, payroll, temporary facilities,
home office and field office expenses, and profit).  The material cost
represents the cost for the materials of construction such as concrete,
pipe, electrical conduit, steel, etc.  The subcontract cost represents
the cost for the specialty items such as siding, piping, field-erected
tanks, cooling towers, etc.  The equipment cost includes the cost for
the control equipment, motors, instrumentation, etc. 

The major process equipment was based on quotes, recent projects, and
similar projects.  The labor work-hours and materials of construction
were based on historical data and similar projects.  The basis for all
construction costs is for the Southeastern United States.

The engineering cost was based upon 15% of the total direct costs (i.e.,
sum of labor, materials, subcontract, and equipment costs).  The
contingency was based upon 20% of the total direct costs.  The owner’s
cost (i.e., corporate and mill engineering, training, builder’s risk
insurance, checkout and start-up, etc.) was based upon 5% of the total
direct costs.  The construction management cost was base upon 5% of the
total direct costs.

Although process or equipment downtime was considered for inclusion in
the analysis, it was discarded as being of minimal impact.  A net
downtime analysis was conducted which initially assumed that the
majority of the work would be done during scheduled downtime.  Then the
net downtime was computed which was the number of additional days past
the scheduled downtime, which would be required to complete the work. 
With the exception of the conversion from a DCE to NDCE recovery
furnace, the net downtime was between three and 5 days.  Therefore,
since process or equipment downtime is very mill specific, no inclusion
was made for this short duration downtime.  Appendix 18.2 contains
BE&K’s estimate of net downtime for each technology considered.

The capital cost estimate does not include the following:

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

Operating Cost Estimate Basis

The annual operating costs were divided into the following categories:
materials, chemicals, maintenance, energy, manpower, testing, and water
wastewater, utilities, and fuel cost.

The materials category included the cost for, fabric filter media, SCR
media, etc.  The chemical category provides an estimate of the type and
amount of chemical used for the pollution control technology.  The
maintenance category includes the estimated maintenance labor and
maintenance material costs.  The energy category was based upon the
estimated installed horsepower utilizing a typical usage factor.  The
manpower category is an estimate of fraction of time existing operators
would need to spend in operating the control equipment.  No additional
personnel were added for any of the technologies.  However, the time
spent by mill technology operating the new technologies was estimated. 
The testing category is an estimate of annual fees for testing.  The
water & wastewater category is an estimate of the additional water and
subsequent wastewater costs for the given technology.  The utility
category includes the cost of the additional steam and compressed air
used for a given technology.  For the technology case where fuel
switching was employed, the fuel usage category contains the
differential cost for either switching to low-sulfur oil or to natural
gas.

NOx Control Good Technology Limit

NDCE Kraft Recovery Furnace 

Description

Combustion controls for recovery furnaces utilizing addition of a
quartenary air system yielding a NOx level in the stack gases of 80 ppm
@ 8% oxygen.  Equipment sized for a NDCE recovery furnace burning 3.7 x
106  (Mm) lb BLS per day.

Major Equipment

Quartenary air fan

Dampers

Flow meters

New CEMS

Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.6 x 106-lb black liquor
solids per day.  Project was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance & materials – 1% of TIC

Power75 kw

Power usage factor: 70%

Workhours: 0.75 hours /day

Testing: $5,000 per year

Lime Kiln – Route SOGs to new Thermal Oxidizer

Description

For those systems where the SOGs are incinerated in the limekiln, the
SOGs will be rerouted to a new thermal oxidizer equipped with Low NOx
controls and a caustic scrubber.  The system is sized for a limekiln
producing 240 tpd CaO.

Major Equipment

Thermal oxidizer

Caustic scrubber

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.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

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

Maintenance labor & materials: 3.5% of TIC

Power: 75 kw

Power usage factor: 70%

Workhours: 3 hours per day

Testing: $5,000 per year

Water: 35 gpm 

Coal or Coal / Wood Boiler

Description

Installation of Low NOx burners on a coal-fired boiler producing 300,000
lb/hr of steam.  The maximum NOx emission rate is 0.3 lb/Mm Btu

Major Equipment

Low NOx burner assemblies

Replace forced draft fan

New CEMS

Basis for Estimate

Southeastern Kraft mill with 400,000 lb/hr steam coal / wood boiler. 
The project was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials : 2% of TIC

Power: 243 kw

Power usage factor: 70%

Workhours: 1.5 hours per day

Testing: $5,000 per year.

Gas Boiler

Description

Low NOx burners and flue gas recirculation for a natural gas-fired
boiler producing 120,000 lb/hr of steam.  The maximum NOx emission rate
is 

0.05 lb/Mmbtu as a 30-day average.

Major Equipment

Low NOx burner assemblies

Replace forced draft fan

New CEMS

Flue gas recirculation fan

Basis for Estimate

Southeastern Kraft mill with a multi-fuel boiler producing 420,000 lb/hr
of steam.  The project was estimated in 1999.

Capital Cost Estimate Assumption

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials : 3% of TIC

Power: 176 kw 

Power usage factor: 70%

Workhours: 1.5 hours per day

Testing: $5,000 per year.

Gas Turbine – Water Injection

Description

Installation of water injection system for NOx emission control to
reduce the NOx emissions to 25 ppm @ 15% oxygen for a 30-day average. 
The system was sized for a 30 MW gas turbine.

Major Equipment

High pressure water pump

Water injection system

Basis for Estimate

Budget quotation from Alpha Power Systems for a Swirlflash technology
system for NOx reduction.  The project costs are in 2001 dollars.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.

Operating Cost Estimate Assumptions

Maintenance labor & materials : 2% of TIC

Power: 2 kw

Power usage factor: 70%

Workhours: 1.5 hours per day

Testing: $5,000 per year.

Water: 10 gpm

Gas Turbine – Steam Injection

Description

Installation of steam injection system for NOx emission control to
reduce the NOx emissions to 25 ppm @ 15% oxygen for a 30-day average. 
The system was sized for a 30 MW gas turbine.

Major Equipment

High pressure water pump

Water injection system

Basis for Estimate

Budget quotation from Alpha Power Systems for a Swirlflash technology
system for NOx reduction.  The project costs are in 2001 dollars.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Operating Cost Estimate Assumptions

Maintenance labor & materials : 2% of TIC

Power: 2 kw

Power usage factor: 70%

Workhours: 1.5 hours per day

Testing: $5,000 per year.

Water: 4.76 gpm

Steam: 2381 lb/hr 

Oil Boiler

Description

Low NOx burners for oil-fired boiler producing 135,000 lb/hr of steam. 
The maximum NOx emission rate is 0.2 lb/Mm Btu as a 30-day average.

Major Equipment

Low NOx burner assemblies

Replace forced draft fan

New CEMS

Basis for Estimate

Southeastern Kraft mill with a multi-fuel boiler producing 420,000 lb/hr
of steam.  The project was estimated in 1999.

Capital Cost Estimate Assumption

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 151 kw

Power usage factor: 70%

Workhours: 1.5 hours per day

Testing: $5,000 per year

Wood Boiler

Description

Upgrade combustion controls and FD fan.  The NOx emissions will be
reduced from 0.33 lb/Mm Btu to 0.25 lb/Mm Btu for a 3-hour limit.

Major Equipment

Upgrade FD fan

Replace combustion dampers and controls

New tertiary air nozzles

New cameras

New CEM

Upgrade DCS controls

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

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

NOx Control Best Technology Limit

Technical Feasibility of SNCR and SCR Technologies

There are no SNCR units known to be operating for NOx control in a
recovery boiler.  While SNCR was attempted on one recovery furnace in
Sweden for a short period, the unit no longer operates and the
technology is not considered to be proven. The major concern with SNCR
is the ability to add urea in the correct flue temperature window to
ensure effectiveness and minimal slip (i.e., urea/ammonia carryover with
the flue gas).  Recovery boilers are operated over a wide range of
conditions, which affect both the amount of urea added and the location
of the addition.  Other concerns include safety (i.e., risk of urea
solution reaching the floor and causing a smelt-water explosion), and
maintenance of equipment (i.e., atomizing nozzles) in a highly corrosive
environment.  

There are financial incentives to reduce NOx emissions in Sweden and
therefore, it would be expected that either SCR or SNCR would be used
extensively if they were cost-effective.  Currently only combustion
controls are used to reduce NOx.

The SCR technology presents unique problems with respect to potential
poisoning of the catalyst from the alkali dust from the recovery boiler.
 To minimize this the SCR would need to be place downstream of the ESP,
which means that the flue gas must be reheated before application of the
SCR.  This adds unnecessary cost – both capital and operating.  

NDCE Kraft Recovery  - SNCR Technology

Description

Selective non-catalytic reduction system for NOx control to achieve a
maximum emission of 40 ppm @ 8% oxygen or achieve a 50% reduction using
a 30-day average.  The system is sized for a NDCE recovery furnace
burning 3.7-Mm lb BLS per day.

Major Equipment

Urea storage 

Metering pump

Urea injection system

Basis for Estimate

A Scandinavian recovery furnace firing at a 3.5-Mm lb BLS/day rate.  The
project was estimated in 1990.  The inlet concentration was assumed 60
ppm with an outlet concentration of 24 ppm.  

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)

Operating Cost Estimate Assumptions

Urea: 256 TPY

Maintenance labor & materials: 3.5% of TIC

Power: 16 kw

Power usage factor: 70%

Workhours: 3 hours per day

Testing: $5,000 per year

Water: 3 gpm

NDCE Kraft Recovery – SCR Technology

Description

Installation of a SCR NOx control system in a NDCE recovery furnace
burning 3.7 x 106  (Mm) lb BLS per day.  The target is 40 ppm @ 8%
oxygen or 50% reduction) for a 30-day average.

Major Equipment

SCR reactor

Duct burner

CEM

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.  The inlet NOx is estimated to be 92 ppm and the
outlet NOx is estimated to be 18 ppm.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

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

Operating Cost Estimate Assumptions

Materials – catalyst: 1072 ft3 per yr. 

Chemicals – urea: 377 tons per year

Maintenance: 2% of TIC

Power: 547 kw

Power usage factor: 70%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 7 gpm

Steam: 1,830 lb/hr

Compressed air: 39 cfm

DCE Kraft Recovery – SNCR Technology

Description

Selective non-catalytic reduction system for NOx control to achieve 50%
reduction of the NOx.  The system is sized for a DCE recovery furnace
burning 1.7-Mm lb BLS/day.

Major Equipment

Urea storage 

Metering pump

Urea injection system

Basis for Estimate

A Scandinavian recovery furnace firing at a 3.5-Mm lb BLS/day rate.  The
project was estimated in 1990.  The inlet concentration was assumed 60
ppm with an outlet concentration of 30 ppm.  

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)

Operating Cost Estimate Assumptions

Urea: 118 TPY

Maintenance labor & materials: 3.5% of TIC

Power: 16 kw

Power usage factor: 70%

Workhours: 3 hours per day

Testing: $5,000 per year

Water: 3 gpm

DCE Kraft Recovery – SCR Technology

Description

Installation of a SCR NOx control system in a DCE recovery furnace
burning 1.7 x 106  (Mm) lb BLS per day.  The target is 40 ppm @ 8%
oxygen or 50% reduction) for a 30-day average.

Major Equipment

SCR reactor

Duct burner

CEM

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.  The inlet NOx is estimated to be 67 ppm and the
outlet NOx is estimated to be 13 ppm.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

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

Operating Cost Estimate Assumptions

Materials – catalyst: 697 ft3 per yr. 

Chemicals – urea: 245 tons per year

Maintenance: 2% of TIC

Power: 355 kw

Power usage factor: 70%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 4 gpm

Steam: 1,190 lb/hr

Compressed air: 26 cfm

Lime Kiln – Low-NOx burners, & SCR

Description

Install Low NOx burners and SCR systems in lime kiln, which produces 240
tpd CaO.  SCR can be applied at the limekiln provided the flue gas
temperature is controlled and the dust is removed prior to application.

Major Equipment

SCR reactor

Low NOx burners

Upgrade to forced draft fan

ID fan

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

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

Operating Cost Estimate Assumptions

Materials – catalyst: 323 ft3 per yr. 

Chemicals – urea: 113.5 tons per year

Maintenance: 2% of TIC

Power: 165 kw

Power usage factor: 70%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 1.97 gpm

Steam: 552 lb/hr

Compressed air: 12 cfm

Coal or Coal / Wood Boiler – SCR

Description

Installation of a SCR system on a coal or coal/wood boiler producing
300,000 lb/hr of steam.  The maximum NOx emission rate is 0.17 lb/Mm Btu
for a 30-day average.

Major Equipment

SCR reactor

Low NOx burners

Upgrade to forced draft fan

ID fan

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

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)

Operating Cost Estimate Assumptions

Materials – catalyst: 1219 ft3 per yr. 

Chemicals – urea: 428 tons per year

Maintenance: 2% of TIC

Power: 622 kw

Power usage factor: 70%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 7.43 gpm

Steam: 2082 lb/hr

Compressed air: 45 cfm

Coal or Coal / Wood Boiler – Switch to Natural Gas

Description

Switch from coal to natural gas for a coal or coal/wood boiler producing
300,000 lb/hr of steam. 

Major Equipment

New burners

Natural gas reducing station

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.

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

Operating Cost Estimate Assumptions

Maintenance: 1% of TIC

Power: N/A

Workhours: 1.5 hr per day

Testing: $5,000 per year

Gas Boiler

Description

Installation of SCR on natural gas-fired boiler producing 120,000 lb/hr
of steam.  The maximum NOx emission rate is 0.015 lb/Mm Btu utilizing a
30-day average.

Major Equipment

SCR reactor

Low NOx burners

Upgrade to forced draft fan

ID fan

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

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

Chemicals – urea: 163 tons per year

Maintenance: 2% of TIC

Power: 237 kw

Power usage factor: 70%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 2.83 gpm

Steam: 793 lb/hr

Compressed air: 17 cfm

Gas Turbine

Description

Installation of SCR system for a 30-MW natural gas turbine yielding an
emission level of 5 ppm @15% oxygen for a 30-day average representing a
95% NOx reduction.

Major Equipment

SCR reactor

Low NOx burners

Upgrade to forced draft fan

ID fan

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

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

Chemicals – urea: 105 tons per year

Maintenance: 2% of TIC

Power: 418 kw

Power usage factor: 70%

Workhours: 3 hr per day

Testing: $5,000 per year

Water: 5 gpm

Steam: 1400 lb/hr

Compressed air: 30 cfm

Oil Boiler

Description

Installation of SCR system on oil-fired boiler producing 135,000 lb/hr
of steam.  The maximum NOx emission rate is 0.04 lb/Mmbtu for a 30-day
average or a 90% reduction.

Major Equipment

SCR reactor

Low NOx burners

Upgrade to forced draft fan

ID fan

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

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)

Operating Cost Estimate Assumptions

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

Chemicals – urea: 238 tons per year

Maintenance: 2% of TIC

Power: 346 kw

Power usage factor: 70%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 4.14 gpm

Steam: 1159 lb/hr

Compressed air: 25 cfm

Wood Boiler - SNCR

Description

Installation of SNCR system on a wood boiler producing 300,000 lb/hr of
steam.  The maximum NOx emission rate is 0.20 lb/ Mmbtu and represents a
40% reduction.

Major Equipment

Urea storage and metering system

Urea Injectors

Boiler Modifications

Control Enhancements

Basis for Estimate

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

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

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

Wood Boiler – SCR (technical feasibility)

Description

Installation of a SCR system on a wood-fired boiler capable of producing
300,000 lb/hr of steam.  The maximum NOx emission rate is 0.025 lb/Mmbtu
with a 85% reduction anticipated.  The SCR is feasible provided the
temperature of the flue gas is controlled.

Major Equipment

SCR reactor

Low NOx burners

Upgrade to forced draft fan

ID fan

Basis for Estimate

Northern Kraft mill with a coal fired 120,000-lb/hr boiler.  The project
was estimated in 1999.

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)

Operating Cost Estimate Assumptions

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

Chemicals – urea: 287 tons per year

Maintenance: 2% of TIC

Power: 420 kw

Power usage factor: 75%

Workhours: 28.6 hr per day

Testing: $5,000 per year

Water: 5 gpm

Steam: 1403 lb/hr

Compressed air: 30 cfmSO2 Reduction – Good Technology Limits

NDCE Recovery Boiler

Description

Installation of a chemical scrubber to achieve sulfur dioxide (SO2)
level in stack gas of 50 ppm @ 8% oxygen.  The system is sized for a
NDCE recovery furnace burning 3.7-Mm lb BLS per day.

Major Equipment

Scrubber tower

Booster fan

Recirculation pump

Caustic pump

Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106-lb black liquor
solids per day.  Project was estimated in 1998.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 1631 kw 

Power usage factor: 70%

Chemical: 1.3 gpm 50% caustic soda

Water: 148 gpm

Wastewater: 15 gpm

Workhours: 3 hours per day

Testing: $5,000 per year

DCE Kraft Recovery Furnace

Description

Installation of a chemical scrubber to achieve sulfur dioxide (SO2)
level in stack gas of 50 ppm @ 8% oxygen.  The system is sized for a DCE
recovery furnace burning 1.7-Mm lb BLS per day.

Major Equipment

Scrubber tower

Booster fan

Recirculation pump

Oxidizer blower

Caustic pump

Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106 lb black liquor
solids per day.  Project was estimated in 1998.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 1023 kw

Power usage factor: 70%

Chemical: 0.82 gpm 50% caustic soda

Water: 68 gpm

Wastewater: 6.8 gpm

Workhours: 3 hours per day

Testing: $5,000 per year

Coal or Coal / Wood Boiler

Description

Installation of a caustic scrubber for a coal or coal / wood boiler
producing 300,000 lb/hour of steam.  The SO2 level would be reduced by
50% producing a maximum emission of 0.6 lb / Mm Btu.

Major Equipment

Scrubber tower

Recirculation pump

Booster fan

Caustic feed system

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of
steam.  The project was estimated in 1992.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 1142 kw

Power usage factor: 70% 

Chemical: 0.6 gpm 50% caustic soda

Water: 143 gpm

Wastewater: 14 gpm

Workhours: 3 hours per day

Testing: $5,000 per year

Oil Boiler

Description

Installation of caustic scrubber on a oil-fired boiler producing 135,000
lb/hr of steam.  The SO2 emission will be reduced by 50% with a maximum
emission rate of 0.4 lb/Mm Btu for a 30-day average.

Major Equipment

Scrubber tower

Booster fan

Caustic feed system

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of
steam.  The project was estimated in 1992.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.0% of TIC

Power: 555 kw 

Power usage factor: 70%

Chemical: 0.26 gpm 50% caustic soda

Water: 42.9 gpm

Wastewater: 4.3 gpm

Workhours: 3 hours per day

Testing: $5,000 per yearSO2 Reduction – Best Technology Limits

NDCE Recovery Boiler

Description

Installation of a caustic scrubber to achieve sulfur dioxide (SO2) level
in stack gas of 10 ppm @ 8% oxygen.  The system is sized for a NDCE
recovery furnace burning 3.7 Mm lb BLS per day.

Major Equipment

Scrubber tower

Booster fan

Recirculation pump

Caustic pump

Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106 lb black liquor
solids per day.  Project was estimated in 1998.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 1631 kw 

Power usage factor: 80%

Chemical: 1.5 gpm 50% caustic soda

Water: 148 gpm

Wastewater: 15 gpm

Work hours: 3 hours / day

Testing: $5,000 per year

DCE Kraft Recovery Furnace

Description

Installation of a caustic scrubber to achieve sulfur dioxide (SO2) level
in stack gas of 10 ppm @ 8% oxygen.  The system is sized for a DCE
recovery furnace burning 1.7 Mm lb BLS per day.

Major Equipment

Scrubber tower

Booster fan

Recirculation pump

Oxidizer blower

Caustic pump

Basis for Estimate

Southeast Kraft mill recovery furnace firing 2.5 x 106 lb black liquor
solids per day.  Project was estimated in 1998.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 1023 kw

Power usage factor: 80% 

Chemical: 0.94 gpm 50% caustic soda

Water: 68 gpm

Wastewater: 6.8 gpm

Work hours: 3 hours / day

Testing: $5,000 per year

Coal or Coal / Wood Boiler

Description

Installation of a caustic scrubber for a coal or coal / wood boiler
producing 300,000 lb/hour of steam.  The SO2 level would be reduced by
90% producing a maximum emission of 0.17 lb / Mm Btu for a 30-day
average.

Major Equipment

Scrubber tower

Booster fan

Caustic feed system

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of
steam.  The project was estimated in 1992.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 1523 kw 

Power usage factor: 80%

Chemical: 1.1 gpm 50% caustic soda

Water: 143 gpm

Wastewater: 14 gpm

Workhours: 3 hours per day

Testing: $5,000 per year

Oil Boiler

Description

Installation of caustic scrubber on a oil-fired boiler producing 135,000
lb/hr of steam.  The SO2 emission will be reduced by 90% with a maximum
emission rate of 0.08 lb/Mm Btu for a 30-day average.

Major Equipment

Scrubber tower

Booster fan

Caustic feed system

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of
steam.  The project was estimated in 1992.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.0% of TIC

Power: 740 kw 

Power usage factor: 80%

Chemical: 0.34 gpm 50% caustic soda

Water: 42.9 gpm

Wastewater: 4.3 gpm

Workhours: 3 hours per day

Testing: $5,000 per year

Mercury Removal – Best Technology Limit

Coal or Coal / Wood Boiler

Description

Installation of a spray dryer absorber fabric filter dry scrubbing
system with carbon injection for a coal or coal/wood-fired boiler
producing 300,000 lb/hr of steam.  The Hg emission level is anticipated
to be lowered from 16 lb/1012 Btu to 8 lb/1012 Btu, representing a 50%
reduction.

Major Equipment

Fabric filter modules

Lime storage and metering system

Activated carbon storage and metering system

Blower

Atomizing air compressor

Fabric filter scrubbing system

Basis for Estimate

A budget quotation from WAPC for a spray dryer absorber fabric filter
dry scrubbing system with carbon injection for a coal-fired boiler.

Capital Cost Estimate Assumptions

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

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

Testing: $5,000 per year

Water: 64 gpm

Wastewater: 20 gpm

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

Wood Boiler 

Description

Installation of a spray dryer absorber fabric filter dry scrubbing
system with carbon injection for a wood-fired boiler producing 300,000
lb/hr of steam.  The Hg emission level is anticipated to be lowered from
0.572 lb/1012 Btu to 

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

Major Equipment

Fabric filter modules

Lime storage and metering system

Activated carbon storage and metering system

Blower

Atomizing air compressor

Fabric filter scrubbing system

Basis for Estimate

A budget quotation from WAPC for a spray dryer absorber fabric filter
dry scrubbing system with carbon injection for a wood fired boiler.

Capital Cost Estimate Assumptions

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

Operating Cost Estimate Assumptions

Chemicals – activated carbon: 7.923 lb per day

Maintenance labor & materials: 5% of TIC

Chemicals – pebble lime: 375 lb/hr

Power: 262 kw

Power usage factor: 70%

Workhours: 3 hours per day

Testing: $5,000 per year

Water: 90 gpm

Wastewater: 28 gpm

Incremental waste disposal: 1,576 tpy of carbon and lime

Particulate Matter – Good Technology Limits

NDCE Kraft Recovery Boiler – New Precipitator

Description

Installation of an electrostatic precipitator capable of achieving 0.044
gr/dscf @ 8% oxygen of particulate matter.  The system is sized for a
NDCE recovery furnace firing 3.7 Mm lb BLS per day 

Major Equipment

New electrostatic precipitator

New concrete stack acid-brick lined

Modification to existing ID fan

Conveyors

Dampers

Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106 lb black
liquor solids per day.  Project estimated in 2000.

Capital Cost Estimate Assumptions

Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP
at 3.7 x 106 lb black liquor solids per day.

Costs escalated to 2001

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

NDCE Kraft Recovery Boiler – Rebuilt Precipitator

Description

ESP upgrade by addition of two parallel fields so that system is capable
of achieving 0.044 gr/dscf @ 8% oxygen of particulate matter.  The
system is sized for a NDCE recovery furnace firing 3.7 Mm lb BLS per day


Major Equipment

Modification to existing ESP

Modifications to ash handling system

Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.70 x 106 lb black
liquor solids per day.  Project estimated in 1999.

Capital Cost Estimate Assumptions

Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP
at 3.7 x 106 lb black liquor solids per day.

Costs escalated to 2001

Operating Cost Estimate Assumptions

Maintenance labor and materials – 2% of TIC cost

Power –377 kw 

Power usage factor: 70%

Workhours – 1.5 hours  per day

Testing - $5,000 per year

DCE Kraft Recovery Boiler

Description

Installation of a electrostatic precipitator capable of achieving 0.044
gr/SDCF @ 8% oxygen of particulate matter.  The system is sized for a
DCE recovery furnace firing 1.7 Mm lb BLS per day.

Major Equipment

New electrostatic precipitator

New concrete stack acid-brick lined

Modification to existing ID fan

Conveyors

Dampers

Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106 lb black
liquor solids per day.  Project estimated in 2000.

Capital Cost Estimate Assumptions

Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP
at 1.7 x 106 lb black liquor solids per day.

Costs escalated to 2001

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

Smelt Dissolving Tank

Description

Installation of a scrubber on a smelt dissolving tank capable of
achieving a particulate matter emission rate of 0.2 lb/ton BLS.  The
system is sized for a 

recovery furnace firing 3.7 Mm lb BLS per day.

Major Equipment

New scrubber

Fan

Recirculation pump

Basis for Estimate

Atlantic states Kraft mill with a recovery furnace firing 2 Mm lb BLS
per day.  The project was estimated in 1997.

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 106 lb black liquor solids per day.  Costs escalated to 2001

Operating Cost Estimate Assumptions

Maintenance labor and materials – 2% of TIC cost

Power – 287 kw

Power usage factor: 70% 

Workhours – 1.5 hours  per day

Testing - $5,000 per year

Lime Kiln

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.

Major Equipment

New ESP

Penthouse blower

Hopper with screw conveyor

Bucket elevator

ID fan

New stack

Basis for Estimate

Southeastern Kraft mill with a lime kiln capable of processing 540 TPD
of CaO.  The project was estimated in 2001.

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.

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power  187 kw

Power usage factor: 70%

Workhours – 2.25 hours  per day

Testing - $5,000 per year

Coal Boiler

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.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 1331 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 39 tpy of ash

Coal / Wood Boiler

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.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 1331 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 94 tpy of ash

Oil Boiler

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.

Major Equipment

Oil gun nozzles

Flow meters

Basis for Estimate

Southeastern Kraft mill which switched from No. 6 to No. 2 fuel oil in a
oil-fired boiler producing 135,000 lb/hour of steam.  The project was
estimated in 1999.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – not applicable

Workhours – not applicable

Testing - $5,000 per year

Fuel costs: $2.86 million per year

Wood Boiler

Description

Removal of existing scrubber and installation of electrostatic
precipitator in a wood boiler producing 300,000 lb/hr of steam.  The
particulate emission rate is 0.065 lb / Mm Btu.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3.5% of TIC cost

Power – 911 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Water – (200) gpm savings from elimination of scrubber

Wastewater – (20) gpm savings from elimination of scrubber

Incremental waste disposal: 551 tpy of ash

Particulate Matter – Best Technology Limit

NDCE Kraft Recovery Boiler – New Precipitator

Description

Installation of an electrostatic precipitator capable of achieving 0.015
gr/dscf @ 8% oxygen.  The system would be installed in a recovery
furnace burning 3.7 Mm lb BLS per day.

Major Equipment

New electrostatic precipitator

New concrete stack acid-brick lined

Modification to existing ID fan

Conveyors

Dampers

Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106 lb black
liquor solids per day.  Project estimated in 2000.

Capital Cost Estimate Assumptions

Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP
at 3.7 x 106 lb black liquor solids per day.

Costs escalated to 2001

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

NDCE Kraft Recovery Boiler – Rebuilt Precipitator

Description

ESP upgrade by addition of two parallel fields so that system is capable
of achieving 0.015 gr/dscf @ 8% oxygen of particulate matter.  The
system is sized for a NDCE recovery furnace firing 3.7 Mm lb BLS per day


Major Equipment

Modification to existing ESP

Modifications to ash handling system

Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.70 x 106 lb black
liquor solids per day.  Project estimated in 1999.

Capital Cost Estimate Assumptions

Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP
at 3.7 x 106 lb black liquor solids per day.

Costs escalated to 2001

Operating Cost Estimate Assumptions

Maintenance labor and materials – 2% of TIC cost

Power –411 kw 

Power usage factor: 70%

Workhours – 1.5 hours  per day

Testing - $5,000 per year

DCE Kraft Recovery Boiler

Description

Installation of a electrostatic precipitator capable of achieving 0.015
gr/SDCF @ 8% oxygen of particulate matter.  The system is sized for a
DCE recovery furnace firing 1.7 Mm lb BLS per day.

Major Equipment

New electrostatic precipitator

New concrete stack acid-brick lined

Modification to existing ID fan

Conveyors

Dampers

Basis for Estimate

Southeast Kraft mill with a recovery boiler firing 2.15 x 106 lb black
liquor solids per day.  Project estimated in 2000.

Capital Cost Estimate Assumptions

Costs were adjusted utilizing the 0.6 rule to obtain the cost for an ESP
at 1.7 x 106 lb black liquor solids per day.

Costs escalated to 2001

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

Smelt Dissolving Tank

Description

Installation of a scrubber on a smelt dissolving tank capable of
achieving a particulate matter emission rate of 0.12 lb/ton BLS.  The
system is sized for a 

recovery furnace firing 3.7 Mm lb BLS per day.

Major Equipment

New scrubber

Fan

Recirculation pump

Basis for Estimate

Atlantic states Kraft mill with a recovery furnace firing 2 Mm lb BLS
per day.  The project was estimated in 1997.

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 106 lb black liquor solids per day.

Costs escalated to 2001

Operating Cost Estimate Assumptions

Maintenance labor and materials – 2% of TIC cost

Power – 315 kw 

Power usage factor: 80%

Workhours – 1.5 hours  per day

Testing - $5,000 per year

Lime Kiln – New ESP

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.

Major Equipment

New ESP

Penthouse blower

Hopper with screw conveyor

Bucket elevator

ID fan

New stack

Basis for Estimate

Southeastern Kraft mill with a lime kiln capable of processing 540 TPD
of CaO.  The project was estimated in 2001.

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.

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 233 kw

Power usage factor: 80%

Workhours – 2.25 hours  per day

Testing - $5,000 per year

Lime Kiln – Upgraded ESP

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.

Major Equipment

Modifications to existing ESP

Ductwork modifications

Basis for Estimate

Southeastern Kraft mill with a lime kiln capable of processing 540 TPD
of CaO.  The project was estimated in 2001.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 1% of TIC cost

Power – 100 kw

Power usage factor: 70%

Workhours – 1.5 hours  per day

Testing - $5,000 per year

Coal Boiler – New ESP

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.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 1664 kw

Power usage factor: 80%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 77 tpy of ash

Coal Boiler – Rebuild Existing ESP

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.

Major Equipment

Modifications to existing ESP

Ductwork modifications

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 1% of TIC cost

Power – 550 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 38 tpy of ash

Coal / Wood Boiler - New

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.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power 1331 kw

Power usage factor: 80%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 137 tpy of ash

Coal / Wood Boiler – Rebuild Existing ESP

Description

Addition of single electric field in two chambers to an existing
electrostatic precipitator in a coal or coal / wood boiler producing
300,000 lb/hr of steam.  The particulate emission rate is 0.04 lb / Mm
Btu.

Major Equipment

Modifications to existing ESP

Ductwork modifications

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 1% of TIC cost

Power 500 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 43 tpy of ash

Oil Boiler

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.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 1098 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 99 tpy of ash

Wood Boiler

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.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler capable of producing 600,000
lb/hr of steam.  The project was estimated in 1992.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3.5% of TIC cost

Power – 1978 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 599 tpy of ash

Wood Boiler – upgrade existing ESP

Description

Upgrade of existing electrostatic precipitator in a wood boiler
producing 300,000 lb/hr of steam.  The particulate emission rate is
moved from 0.1 to 0.04 lb / Mm Btu.

Major Equipment

ID fan modification

ESP

Conveyors

Penthouse blower

Basis for Estimate

Southeastern Kraft mill boiler ESP rebuild for a boiler capable of
producing 310,000 lb/hr of steam.  The project was estimated in 1996.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3.5% of TIC cost

Power – 250 kw

Power usage factor: 70%

Workhours – 3 hours  per day

Testing - $5,000 per year

Incremental waste disposal: 116 tpy of ash

Carbon Monoxide – Best Technology Limit

Coal or Coal / Wood Boiler

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.

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

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.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 298 kw

Power usage factor: 70%

Workhours – 1.5 hours  per day

Testing - $5,000 per year

Wood Boiler

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.

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

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.

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

Operating Cost Estimate Assumptions

Maintenance labor and materials – 3% of TIC cost

Power – 298 kw

Power usage factor: 70%

Workhours – 1.5 hours  per day

Testing - $5,000 per year

HCl – Good Technology Limit

Coal Boiler

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.

Major Equipment

Scrubber tower

Recirculation pump

Booster fan

Caustic feed system

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of
steam.  The project was estimated in 1992.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

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

Maintenance labor & materials: 5% of TIC

Power: 811 kw 

Power usage factor: 70%

Chemical: 8 lb/hr caustic soda

Testing: $5,000 per year

Water: 64 gpm

Wastewater: 20 gpm

Workhours: 3 hours per day

HCl – Best Technology Limit

Coal Boiler

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.

Major Equipment

Scrubber tower

Recirculation pump

Booster fan

Caustic feed system

Basis for Estimate

Southeastern Kraft mill multi-fuel boiler producing 600,000 lb/hour of
steam.  The project was estimated in 1992.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

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

Maintenance labor & materials: 5% of TIC

Power: 811 kw 

Power usage factor: 80%

Chemical: 25 lb/hr caustic soda

Testing: $5,000 per year

Water: 64 gpm

Wastewater: 20 gpm

Workhours: 3 hours per day

VOC – Good Technology Limit

DCE Kraft Recovery Furnace

Description

Collection of black liquor oxidation system vent gases from a DCE
recovery furnace burning 1.7 Mm lb BLS per day.  The vent gases would be
incinerated in an existing multi-fuel boiler. 

Major Equipment

Vent fan

Condensate pump

Basis for Estimate

Rust MACT Cost Analysis report for a DCE recovery furnace burning 1.5 Mm
lb BLS per day.  The work was done in October 1993. 

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.

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 151 kw 

Power usage factor: 70%

Testing: $5,000 per year

Steam: 500 lb/hr

Workhours: 3 hours per day

Paper Machines 

Description

Based upon NCASI studies ("Volatile Organic Emissions from Pulp & Paper
Sources Part VII - Pulp Dryers & Paper Machines at Integrated Chemical
Pulp Mills.  Tech Bulletin No.681 Oct 1994 NCASI) the paper machines
utilizing unbleached pulps had the highest non-additive VOC emission
rates.  The machines utilizing bleached pulps had very low VOC
emissions. 

The source of the VOC was from the fluid contained in the unbleached
pulp.  If the consistency of the unbleached pulp is raised to 30+% (from
a nominal 12%) prior to discharge to either the high density storage or
to the paper machines, then the VOC contained in the fluid will be
reduced by more than two-thirds. 

To increase the consistency to 30+%, a screw press would be installed
ahead of the high density storage for the unbleached Kraft,
semi-chemical (or NSSC), and mechanical pulp mills.  The re-dilution
water to be used after the screw press would be paper machine
whitewater.  In the case of the unbleached Kraft mill and semi-chemical
mill, the filtrate from the press would be sent to the spent pulping
liquor system.

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

Major Equipment

Two screw presses

Pressate (filtrate) tank

Thick stock pump 

Basis for Estimate

Estimate for 1000 tons per day screw press system based upon a quotation
from Kvaerner Pulping.  The estimate is in 2001 dollars.

Capital Cost Estimate Assumptions

None

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 861 kw 

Power usage factor: 70%

Testing: $5,000 per year

Workhours: 1.5 hours per day

A COD reduction will result from utilizing the screw press, which can
result in enhanced runnability, improved sheet quality, and reduced
chemical costs.  However, these potential savings are very paper machine
specific and were deemed beyond the scope of this study.

Mechanical Pulping - TMP

Description

Installation of a heat recovery system on TMP systems which will produce
clean steam, a NCG vent, and dirty condensates.  The system is designed
to condense the VOCs to <0.5 lb C / ODTP.

Major Equipment

Reboiler

Vent condenser / feed water heater

Boiler feed water heater

Atmospheric start-up scrubber with silencer

Basis for Estimate

Estimate for 500 tpd TMP heat recovery system based upon quotation from
Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery system.  The
quotation was in 2001 dollars.

Capital Cost Estimate Assumptions

None

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.)

Mechanical Pulping – Pressure Groundwood

Description

Installation of a heat recovery system on pressure groundwood systems
which will produce clean steam, a NCG vent, and dirty condensates.  The
system is designed to condense the VOCs to <0.5 lb C / ODTP.

Major Equipment

Reboiler

Vent condenser / feed water heater

Boiler feed water heater

Atmospheric start-up scrubber with silencer

Basis for Estimate

Estimate for 500-tpd-pressure groundwood heat recovery system based upon
quotation from Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery
system.  The quotation was in 2001 dollars.

Capital Cost Estimate Assumptions

None

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 165 kw 

Power usage factor: 70%

Testing: $5,000 per year

Workhours: 1.5 hours per day

Water: 192 gpm

Wastewater: 39

Steam: (18,851 lb/hr) (This is projected amount of steam to be recovered
and assumes that the heat recovery would be 20% of that for a comparable
TMP plant.)

VOC – Best Technology Limit

NDCE Kraft Recovery Furnace

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.

Major Equipment

New dry bottom hopper

Ash mix tank

Conveyors

Basis for Estimate

Rust MACT Cost Analysis report for a NDCE recovery furnace burning
1.5-Mm lb BLS per day.  The work was done in October 1993. 

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.

Operating Cost Estimate Assumptions

Maintenance labor & materials: 2% of TIC

Power: 15 kw 

Power usage factor: 70%

Testing: $5,000 per year

Workhours: 1.5 hours per day

DCE Kraft Recovery Furnace

Description

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

Major Equipment

New economizer

New spent pulping liquor concentrator

Additional soot blowers

Ash mix tank

CEMS

Basis for Estimate

Rust MACT Cost Analysis report for a DCE recovery furnace burning 1.5-Mm
lb BLS per day.  The work was done in October 1993. 

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.

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 450 kw

Power usage factor: 70% 

Testing: $5,000 per year

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

Workhours: 3 hours per day

Paper Machines – Wet End

Description

Collection of wet end exhaust gases from a 1000 TPD paper machine and
incineration in a regenerative thermal oxidizer (RTO). 

Major Equipment

Combustion blower

Seal fan

Main fan

Regenerative thermal oxidizer

100’ stack with testing platform

316L stainless steel duct

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.

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)

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 310 kw

Power usage factor: 70% 

Testing: $5,000 per year

Natural gas: 4.71 Mmbtu/hr

Workhours: 1.5 hours per day

Paper Machines – Dry End

Description

Collection of dry-end exhaust gases from a 1000 TPD paper machine and
incineration in a RTO.

Major Equipment

Major Equipment

Combustion blower

Seal fan

Main fan

Regenerative thermal oxidizer

100’ stack with testing platform

316L stainless steel duct

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.

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)

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC

Power: 380 kw

Power usage factor: 70% 

Testing: $5,000 per year

Natural gas: 8.1 MmBtu/hr

Workhours: 1.5 hours per day

Mechanical Pulping – TMP with Existing Heat Recovery System

Description

Collection and incineration of the NCGs from a TMP heat recovery system.
 The system was sized for a 500 ADTPD mechanical pulp mill.

Major Equipment

Duct work

Combustion blower

Thermal oxidizer

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.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 22 kw

Power usage factor: 70%

Workhours: 2.25 hours per day

Testing: $5,000 per year

Water: 10gpm

Wastewater: 10 gpm

Mechanical Pulping – TMP Without Existing Heat Recovery System

Description

Installation of a heat recovery system on mechanical pulping systems
which will produce clean steam, a NCG vent, and dirty condensates.  Then
collection and incineration of the NCGs.  The system was sized for a 500
ADTPD TMP mill.

Major Equipment

Reboiler

Vent condenser / feed water heater

Boiler feed water heater

Atmospheric start-up scrubber with silencer

Duct work

Combustion blower

Thermal oxidizer

Basis for Estimate

Estimate for 500 tpd TMP heat recovery system based upon quotation from
Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery system.  The
quotation was in 2001 dollars.  

For NCG collection and incineration, Southeastern Kraft mill which
routed its NCGs to a thermal oxidizer.  System was sized for 20,000
ACFM.  The project was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 187 kw

Power usage factor: 70%

Workhours: 2.25 hours per day

Testing: $5,000 per year

Water: 202gpm

Wastewater: 204 gpm

Steam: (94,255 lb/hr) (This is projected amount of steam to be
recovered)

Mechanical Pulping – Pressurized Groundwood Without Existing Heat
Recovery System

Description

Installation of a heat recovery system on pressurized groundwood pulping
systems which will produce clean steam, a NCG vent, and dirty
condensates.  Then collection and incineration of the NCGs.  The system
was sized for a 500 ADTPD pressurized groundwood mill.

Major Equipment

Reboiler

Vent condenser / feed water heater

Boiler feed water heater

Atmospheric start-up scrubber with silencer

Duct work

Combustion blower

Thermal oxidizer

Basis for Estimate

Estimate for 500 tpd pressurized groundwood heat recovery system based
upon quotation from Andritz-Ahlstrom for a 500 ADTPD TMP heat recovery
system.  The quotation was in 2001 dollars.  

For NCG collection and incineration, Southeastern Kraft mill which
routed its NCGs to a thermal oxidizer.  System was sized for 20,000
ACFM.  The project was estimated in 1999.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 198 kw

Power usage factor: 70%

Workhours: 2.25 hours per day

Testing: $5,000 per year

Water: 202gpm

Wastewater: 49 gpm

Steam: (18,851 lb/hr) (This is projected amount of steam to be recovered
and assumes that the heat recovery would be 20% of that for a comparable
TMP plant.)

Mechanical Pulping – Atmospheric Groundwood

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.  

Major Equipment

Hoods

Duct work

Combustion blower

Thermal oxidizer

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.

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3.5% of TIC

Power: 22 kw

Power usage factor: 70%

Workhours: 2.25 hours per day

Testing: $5,000 per year

Water: 10gpm

Wastewater: 10 gpm

Gasification

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.

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 heat recovery
steam generator.  The resulting high-pressure steam is then sent to an
extraction/condensing steam turbine where addition electricity is
produced and lower pressure steam is made available to the mill.  A
process flow diagram showing the complete system is shown on the
following page.  

The scope developed assumes that the mill can supply concentrated black
liquor (80% solids).  Since the costs for doing this can vary widely
between mills and modern recovery boilers would require a similar
concentration, these costs have been omitted from this study.

We recognize that the steam produced by this system is probably not
sufficient for a typical Kraft mill.  The additional steam requirements
will either need to be provided by a biomass gasifier or boiler or a
power boiler.  These additional systems offer the opportunity for
further power generation as well as steam production.  This too is site
specific and not included in this study.

Major Equipment

The major subsystems include liquor injection, steam reformer, gas
cleanup, combustion turbine, heat recovery and steam generation, steam
turbine, bed solids dissolution, sodium carbonate solution filter, and
bed solids storage.  

Black Liquor Supply and Steam Reformer

High solids black liquor is supplied to the reformer via a recirculation
line feeding multiple steam jacketed injectors.  Four reformers each
containing 8-pulse heaters are required for this size plant.  Each steam
reformer is a carbon steel; fabricated vessel lined with refractory. 
The upper region of the vessel is expanded to reduce gas velocity,
permitting entrained particles to disengage and fall back to the fluid
bed.  Internal stainless cyclones, mounted from the roof of the
reformer, provide primary dust collection and a second set of external
cyclones further captures fines.  The reformer is fluidized with
superheated steam using stainless fluidizer headers that are located
just above the refractory floor.  Bed drains penetrate the refractory
floor for removal of bed solids via lock hoppers during normal
operation.  

Pulsed jet heater modules (fired heat exchangers) are used to indirectly
heat the reformer.  Pulsed heater modules are cantilever-mounted in the
reformer utilizing a flange located on the front of the vessel.  Each
module extends through the reformer with it resonance tubes in contact
with the fluid bed particles inside the vessel.  

Product Gas Cleanup

Cyclone-cleaned product gas exits the reformer and enters a product gas
heat recovery steam generator (HRSG) which cools the gas prior to
entering a venturi separator, which further cools the gas and washes out
any solids carryover.  A packed gas cooler follows the venturi
separator.  Once the gas is cooled, it enters the H2S absorber (green
liquor column).  The absorber is a carbon steel cylinder with two packed
stages.

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.

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.  

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.  

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.

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.

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.

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.

Basis for Estimate

Our database of studies, extending over the last 5 years for systems
ranging from 250,000 lb/day to 1,000,000 lb/day black liquor solids, was
used to create a base for the capital cost estimate.  

Capital Cost Estimate Assumptions

Costs were factored using the “0.6 power.”

Costs were escalated to 2001 dollars

Engineering was assumed to 8% vs. the standard 15% because of the high
cost of the equipment and the fact that there is little integration to
existing plant

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

Equipment foundations on spread footings

No allowance for disposal of any potential contaminated soils

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. 

Operating Cost Estimate Assumptions

Maintenance labor & materials: 3% of TIC cost

Utilities: 0.1% of TIC cost

Power

New loads: 11,600 kw

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

Revenue – sale of power: 50,000 kw

Dregs disposal: 1.9 tons per hour

Waste water treatment: 650 gpm

Steam (revenue): (170,000) lb/hr 



Impact on Emissions

Emissions estimates prepared in earlier studies were scaled up for the
3.7 million-lb/day gasifier and then compared to equivalent data for a
similarly sized recovery boiler.  The emissions are shown in the tables
and chart below.

Black Liquor Gasification Emission Estimates

	Black Liquor Reformer Pulse Combustion Exhaust	Combustion Turbine
Exhaust	Total

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

Particulate matter	2.9	5.7	8.5

Nitrous oxides (NOx)	18.7	46.1	64.7

Carbon monoxide (CO)	11.4	56.1	67.5

Sulfur dioxide (SO2)	70.0	81.0	151.0

Volatile organic (as carbon)	0.4	0.0	0.4

as Methanol	2.8	0.0	2.8

TRS (as H2S)	0.0	0.0	0.0



Recovery Boiler & Smelt Dissolver Emission Estimates

	Recovery Boiler

Exhaust	Smelt Dissolving Exhaust	Total

	lb/hr	lb/hr	lb/hr

Particulate matter	93.9	9.4	103.3

Nitrous oxides (NOx)	89.2	16.1	105.3

Carbon monoxide (CO)	516.5	0.3	516.8

Sulfur dioxide (SO2)	98.7	9.4	108.1

Volatile organic (as carbon)	37.6	7.5	45.1

as Methanol	100.2	20.0	120.2

TRS (as H2S)	4.7	2.5	7.2



Additionally for carbon dioxide the black liquor gasification emission
rate is estimated to be 240,400 lb/hr for a 4 Mm lb BLS/day unit, while
a comparable Tomilson unit would discharge 318,600 lb/hour.

The following illustrates the differences between a black liquor
gasification unit and a Tomilson recovery system:

Industry – Wide Control Cost Estimates

General Assumptions

The following are the general assumptions:

  Capital Costs

The individual mill cost estimates are based upon using the 0.6 power
rule [Project A cost x (AF&PA firing rate / Project A firing rate)0.6]
to factor the control technology estimates

The boiler emission rates are compared with pollutant limits to
determine relative compliance.  If the mill discharge level is less than
90% of the pollutant limit, then no control technology will be
installed.

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

Area	Rate, $/hour	Comment

Base rate	$17.50

	Benefits	$3.25	18.55% of base rate

Fringes	$2.01	11.50% of base rate

Workman’s compensation insurance	$2.13	Varies by craft from 6 to 30%
of base rate

Indirects	$27.00	Includes home office expenses, field supervision,
temporary facilities, tools/ consumables, construction equipment,
permits/miscellaneous, and contractor’s fee

Premium mark-up	$2.07

	Per diem	$4.66	Includes direct and indirect

Total	$58.62

	

The labor costs portion of the TIC were adjusted for each mill utilizing
the BE&K labor rates by region.  See Appendix 18.1 for a listing of the
factors by state.

The material and subcontract costs were adjusted for each mill utilizing
the MEANS database factors averaged for each state.  See Appendix 18.1
for a listing of the factors by state.

Research & Development expenses were assumed for the SCR-non-natural
gas, mercury removal, and paper machine VOC removal – best technology
applications.  They ranged from 0.5 to 1.5% of the sum of the labor,
material, subcontract, and equipment direct costs.

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

Period	Escalation rate

1994 to 1995	2.50%

1995 to 1996	3.30%

1996 to 1997	1.70%

1997 to 1998	1.60%

1998 to 1999	2.70%

1999 to 2000	3.40%



  Annual Operating and Maintenance Costs

The maintenance labor and material annual costs were reported as a
percentage of the TIC.  The typical range was between 1% and 5% of the
total TIC.

The operating costs for the mills were proportionately factored for each
of the areas (excluding testing and workhours) from the design case.

355 operating days per year were assumed for the equipment.

The materials category such as fabric filter or SCR catalyst was
reported in terms of 2001 dollars.

The wastewater category reported the usage in gallons per year based
upon the estimated flow; gpm/feed rate x feed rate x 1440 min/day x 365
dy/yr.  The water usage used the same formula but with only 350 dy/yr.

The steam and compressed air usage was calculated by multiplying the
usage per feed rate x feed rate per day x 350 dy/yr.

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

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

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

The estimated cost for urea was $225 per ton

The estimated cost for activated carbon is $0.58 per lb

The estimated cost for pebble lime is $56.50 per ton

The differential price between No. 2 and No. 6 fuel oil is $0.84 per
Mmbtu (assumes a cost of $4.32 /Mmbtu for No. 6 fuel oil and $5.16 /
MmBtu for No. 2 fuel oil)

The energy usage was first calculated in kWh/year and is based upon the
estimated connected kilowatts x 24/hr/day times 350 days times usage
factor (typically 70 to 80%). 

The price of electricity was assumed to $0.05/kwhr and was multiplied by
the kWh/year.

The price of steam was assumed to be $0.00500 per lb of steam and was
multiplied by the steam usage in lb/hr per year.  For any recovered
steam, a recovered steam factor times the price of steam was used to
determine the value of the steam.

The price of compressed air was assume to be $0.00010 per cfm and was
multiplied by the compressed air usage in cfm/year.

The utilities category totals the costs for compressed air, water,
wastewater, steam, and solid waste disposal.

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

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

An annual testing cost of $5,000 was assumed for each technology applied
and was assumed constant independent of the size of the facility.

The workhours were reported in $ /year based upon hours / day x 350
operating days/year x the hourly rate.  The hourly rate was obtained
from AF&PA Labor Database with 91% of member contracts entered (missing
about 20); the average hourly rate for year 2000 was $18.14.  This data
only includes hourly employees.  An additional 40% was added to the
figure to account for benefits to yield a rate of $25.40.  The workhour
dollars were not factored, but were assumed to be constant no matter
what the size of the facility.

The NCASI database for recovery furnaces, limekilns, and power boilers
was used.  This included equipment information, combustion firing rates
and types, and pulping information.  

NCASI provided the mill code for the BE&K supplied paper machine and
mechanical pulping information.

CO2 Emission Assumptions

The CO2 emissions were calculated by multiplying the 1995 NCASI fossil
fuel usage from the power boilers, recovery furnaces, and lime kilns
times the CO2 factors times 99% (assuming a 99% burn factor).  This was
the recommended calculation technique from the DOE Emission of
Greenhouse Gases in the United States report.

The CO2 emission factors are:

Distillate Oil (No.2) 	21.945	Tons / MmBtu

Residual Oil (No.6) 	23.639	Tons / MmBtu

Coal Industrial (other)	28.193	Tons / MmBtu

Natural gas	15.917	Tons / MmBtu

Petroleum Coke*	30.635	Tons / MmBtu

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



Recovery Furnace Assumptions

The following are the assumptions:

  General Assumptions

NDCE recovery furnace firing 3.7 Mm lb BLS/day is assumed to have an air
flow of 27,500 lb/min, NOx Control Technology.

For the cases where the design heat load (i.e., Mm Btu/hr) is not known,
it was calculated from the design BLS firing rate, utilizing a heat
content of 5900 Btu/lb.

 NOx Control Technology

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

NDCE at 80 ppm	0.1415 lb / Mm Btu

NDCE at 40 ppm	0.0726 lb / Mm Btu

DCE at 30 ppm	0.0544 lb / Mm Btu

The annual NOx emission rates from the NCASI database were converted to
lb/Mm Btu and compared with 80% of the above limits.  The NOx limits are
based upon 30-day averages and it was assumed that to comply with the
30-day average limits the annual average would be approximately 80% of
the 30-day limits.

For the case of the good technology, if a given furnace did not meet the
adjusted limit, then its emission rate was assumed to average the
adjusted limit (i.e., 80% of the 30-day average limits) after treatment.
 The adjustment of 80% represents a compliance safety margin.

If no emission rates were indicated for 1995, then no treatment estimate
was made for that furnace.

For the case of the best technology, if a given furnace did not meet the
adjusted limit, then its emission rate was assumed to be reduced by 50%
after treatment 

  SO2 Control Technology

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

NDCE at 50 ppm	0.12	Lb / MmBtu

NDCE at 10 ppm	0.0.024	Lb / MmBtu

DCE at 50 ppm	0.0.12	Lb / MmBtu

DCE at 10 ppm	0.0.024	Lb / MmBtu

The annual SO2 emission rates from the NCASI database were converted to
lb/Mm Btu basis and compared with 80% of the above limits.  The SO2
limits are based upon 30-day averages and it was assumed that to comply
with the 30-day average limits the annual average would be approximately
80% of the 30-day limits.

The following illustrates the cumulative distribution for the recovery
furnace SO2 emission rates from the 1995 NCASI database:

For recovery furnaces with up to four-times the adjusted SO2 limit
(i.e., 0.3628 lb/Mm Btu), combustion control modifications (these are
the same as what was estimated for good controls for NOx) would be
implemented.  For recovery furnaces with SO2 limits greater than 0.3628
lb/Mm Btu, a new scrubber would be installed.   In either case, the
controlled emission rate would be equivalent to an annual average of 40
ppm (i.e., 50 ppm x 80%).  

If no emissions were indicated for 1995, then no treatment estimate was
made for the furnace.

For both technologies, if a given furnace did not meet the adjusted
limit, then its emission rate was assumed to average the adjusted limit.
 The adjustment of 80% represents a compliance safety margin.

  PM Control Technology

Any recovery furnace ESP built or rebuilt after 1990 but before 1998 was
assumed capable of meeting the good PM technology limit.

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.

  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

Smelt Dissolving Tank Scrubber - PM Technology

Number of smelt dissolving tank was determined based upon the
manufacturer.  Combustion Engineering furnaces with greater than a 3.5
Mm lb BLS/ day firing rates are assumed to have two smelt dissolving
tanks and the other manufacturer’s have one smelt dissolving tank. 
For the case of the two smelt dissolving tank scrubbers, the initial
scrubber was factored based on half the black liquor-firing rate and
then multiplied by two.

Any recovery furnace built before 1976 will require a new smelt
dissolving tank scrubber.

Any recovery furnace built or rebuilt after 1976 but before 1990 was
assumed to meet the good PM technology limit

Any recovery furnace built or rebuilt after 1990 was assumed to meet the
best PM technology limit 



Lime Kiln Assumptions

The following are the assumptions:

  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 

  NOx Control Technology

If the annual NCASI-estimated NOx levels are less than 20 TPY, no
controls will be added.  This level represents approximately 10% of the
limekilns from the NCASI database.

If no emissions where indicated for 1995, then no treatment estimate was
made for the kiln.

If the mill burns the NCGs primarily in the limekiln, then it was
assumed that if there is a stripper present the stripper off-gases
(SOGs) are burned in the limekiln.  

The NOx level in the limekiln if NCGs are being burned will decrease by
30% if the SOGs are burned in a thermal oxidizer.  The thermal oxidizer
would be equipped with staged combustion to control the NOx levels.  

The NOx level in the limekiln will decrease by 60% with the
incorporation of SCR and low-NOx burners.  If a good technology fix was
required, the best technology was additive: the 60% reduction was
compounded on the 30% reduction for a total of a 72% reduction [(1-0.3)
x (1-0.6)].

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, 

The fuel usage for each boiler from the NCASI database was multiplied
by the following heating values:

Coal	 25,000 	MmBtu/1000 ton

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

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

Natural gas	950	MmBtu/MmCF

Wood	 9,000 	MmBtu/1000 ton

Sludge	 10,000 	MmBtu/1000 ton



If the design information for the boiler – either steam or Btu were
not provided, then the sizing was based upon the 1995 NCASI fuel usage
(if given) and Btu estimate.  The steam output was calculated from the
Btu estimate and the boiler efficiency, which was assumed 85% for
everything, except for wood-fired boilers, which was assumed to have a
65% efficiency.

The boiler design figure was compared with the predicted steam (i.e.,
based upon 1995 reported fuel usages) and which ever was higher was used
to compute the capital costs for the control technologies.  The
operating costs were based upon the predicted steam usage. 

The best estimate SO2, and NOx yearly emission rates were converted to
pounds and divided by Btus to determine a lb/MmBtu emission rate.  

The SO2 and NOx emission rates were then multiplied by 80% and compared
with the technology limits.  The technology limits are based upon 30-day
averages and it was assumed that to comply with the 30-day average
limits the annual average would be approximately 80% of the 30-day
limits.

For the case of the good technology, if a given furnace did not meet the
adjusted limit, then its emission rate was assumed to average the
adjusted limit after treatment (i.e., 80% of the 30-day average limits).
 

For the case of SO2 control technology, no control costs were assumed
for any boiler designated as a wood or gas boiler, regardless of the
emission level.

NCASI has listed 1225 boilers or turbines, and had fuel consumption
information on 1074 of them.  Control technology estimates for boilers
were only made if fuel consumption information was provided.

Coal Boiler Assumptions

  General

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

NOx Limits

Any coal boilers after 1990 are assumed to have low NOx burners and are
assumed to meet the 0.3 lb/106 Btu, 30-day average.

If the coal boilers were converted to natural gas with low NOx-burners,
then the emission rates were assumed to be 0.0490 and 0.1373 lb / 106
Btu for boilers less than and greater than 100 million Btu/hr,
respectively.

  SO2 Limits

Application of scrubbers to coal boilers will yield 50% reduction at
good technology and 90% reduction at best technology.

  Hg limits

The uncontrolled limits were obtained by multiplying the MmBtu/year for
1995 by 16 lb/1012 Btu that is the AP-42 emission factor.

The removal rate for the carbon injection and fabric filter approach was
assumed 50%.

PM limits

Any coal boiler with an ESP built or rebuilt after 1980 is assumed able
to meet the good technology limit.  If the ESP was built or rebuilt
before 1980, the ESP’s would be upgraded by adding a single field.  If
the year the ESP was constructed or rebuilt was not in the NCASI
database, then the ESP was assumed to have been built or rebuilt before
1980.  Any coal boiler constructed after 1990 is assumed to meet the
good technology limit.

Any coal boiler with an ESP built or rebuilt after 1980 can be upgraded
to by adding a single field in two chambers to meet the best technology
limit.  A new ESP will be priced out for an ESP built or rebuilt before
1980.  

Any coal boiler constructed or an ESP built or rebuilt after 1998 is
assumed to meet the best technology limit.

  CO limits

Any coal boiler constructed after 1990 is assumed to be able to meet the
best technology limit of 200 ppm (24-hour average).  

  HCl limits

Use same criteria as for SO2 limits – if a scrubber was required for
SO2, then it was assumed a scrubber would be required for HCl control. 
This applied to both good and best control technologies.

If SO2 control is installed there will be no need to install HCl
controls as well; the chemical addition rate for SO2 is greater than
what is required to remove the HCl present.

Coal / Wood Boiler Assumptions

  General Assumptions

At least 20% of the Btus had to come from coal or wood provided both
were used within the boiler.

  NOx Limits

Any coal boilers after 1990 were assumed to have low NOx burners and
were assumed to meet the 0.3 lb/106 Btu, 30-day average

For the case of the good or best technology, if a given boiler did not
meet the adjusted limit, then its emission rate was assumed to average
the adjusted limit (i.e., 80% of the 30-day average limits) after
treatment

  SO2 Limits

Application of scrubbers to coal/wood boilers will yield 50% reduction
at good technology and 90% reduction at best technology.

  Hg limits

The uncontrolled limits were obtained by multiplying the MmBtu/year for
1995 by 16 lb/1012 Btu for coal and by 0.572 lb/1012 Btu for wood.  Both
are based upon the AP-42 emission factor with the wood corrected for the
difference in heavy metals between coal and wood.

The removal rate for the carbon injection and fabric filter approach was
assumed 50%.

  PM limits

Any coal/wood boiler with an ESP built or rebuilt after 1980 is assumed
able to meet the good technology limit.  If the ESP was built or rebuilt
before 1980, the ESP’s would be upgraded by adding a single field in
two chambers.  If the year the ESP was constructed or rebuilt was not in
the NCASI database, then the ESP was assumed to have been built or
rebuilt before 1980.  

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.

  CO limits

Any coal / wood boiler will require controls to meet the best technology
limit of 200 ppm (24-hour average)

Gas Boiler Assumptions

  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.

  NOx Limits

Any gas boilers after 1990 are assumed to have low-NOx burners and are
assumed to meet the 0.05 lb/106 Btu, 30-day average

For the case of the good or best technology, if a given boiler did not
meet the adjusted limit, then its emission rate was assumed to average
the adjusted limit (i.e., 80% of the 30-day average limits) after
treatment

Gas Turbine Assumptions

 NOx Limits

Any gas turbines after 1995 are assumed to have water or steam injection
to control to the good technology limit of 25 ppm @ 15% oxygen.

For the case of the good or best technology, if a given turbine did not
meet the adjusted limit, then its emission rate was assumed to average
the adjusted limit (i.e., 80% of the 30-day average limits) after
treatment

Oil Boiler Assumptions

  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.

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.

  NOx Limits

Any oil boilers after 1990 are assumed to have low-NOx burners and are
assumed to meet the 0.2 lb/106 Btu, 30-day average

For the case of the good or best technology, if a given boiler did not
meet the adjusted limit, then its emission rate was assumed to average
the adjusted limit (i.e., 80% of the 30-day average limits) after
treatment

  SO2 Limits

Application of scrubbers to oil boilers will yield 50% reduction at good
technology and 90% reduction at best technology.

PM limits

Any oil boiler with an ESP is assumed able to meet the good technology
limit.  

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

Any oil boiler burning distillate oil is assumed to meet the good
technology limit.

Any oil boiler with an ESP can be upgraded to by adding a single field
in two chambers to meet the best technology limit.

Any oil boiler constructed after 1998 is assumed to meet the best
technology limit.

Wood-Fired Boiler Assumptions

  General Assumptions

Any boiler where at least 80% of the Btu originate from wood, then the
boiler is considered a wood-fired boiler.

  NOx Limits

Any wood boiler after 1990 are assumed to have combustion controls and
are assumed to meet the 0.25 lb/106 Btu, 30-day average

For the case of the good or best technology, if a given boiler did not
meet the adjusted limit, then its emission rate was assumed to average
the adjusted limit after treatment (i.e., 80% of the 30-day average
limits).

  Hg limits

The uncontrolled limits were obtained by multiplying the MmBtu/year for
1995 by 0.572 lb/1012 Btu for wood.  This is based upon the AP-42
emission factor for coal corrected for the difference in heavy metals
between coal and wood.

The removal rate for the carbon injection and fabric filter approach was
assumed 50%.

 PM limits

Any wood boiler with an ESP built or rebuilt after 1980 is assumed able
to meet the good technology limit.  If the ESP was built or rebuilt
before 1980, the ESP’s would be upgraded by adding a single field in
two chambers.  If the year the ESP was constructed or rebuilt was not in
the NCASI database, then the ESP was assumed to have been built or
rebuilt before 1980.  

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

Any wood boiler with an ESP built or rebuilt after 1980 can be upgraded
to by adding a single field in two chambers to meet the best technology
limit.  A new ESP will be priced out for an ESP built or rebuilt before
1980.  

Any wood boiler constructed or an ESP built or rebuilt after 1998 is
assumed to meet the best technology limit.

CO limits

Any wood boiler will require cotnrols to meet the best technology limit
of 200 ppm (24-hour average)

Paper Machine Assumptions

Fisher Database statistics were used. 

Minimum machine size capacity of 50 tons per day was used as the
cut-off.

Only paper machines with unbleached Kraft, semi-chemical, NSSC, and
mechanical pulp furnishes were considered for the good technology
limits.  Unbleached recycle fiber furnishes were considered for the best
technology limits.

Each mechanical pulp line was treated separately for the good technology
limit.

The good technology was sized based upon the pulp mill production.  A
minimum of 200 tons per day was used as the cut-off for the pulp mill
production for everything but mechanical pulping, which was set at 100
tons per day.

The best technology was sized based upon the paper machine capacity.  If
only a portion of a paper machine’s furnish was one of the above fiber
furnishes, then the paper machine was treated.

The untreated emission rate for the unbleached paper machines was
assumed to be 0.47 lb C / ODTP.  (Basis: NCASI Tech Bulletin No. 681)

The emission reduction for the good technology was assumed 67%.  

The emission reduction for the best technology was assumed 99%.

Mechanical Pulping

Fisher Database statistics were used

Minimum production level of 18,000 tons per year was used as the
cut-off.

Any TMP line constructed after 1989 is assumed to meet the good
technology limits.  Heat recovery was applied to all pressure groundwood
mills regardless of age.

Heat recovery was not applied to any atmospheric groundwood pulping
lines.

Any TMP pulping line constructed after 1998 is assumed to meet the best
technology limits.

Appendix

MEANS and BE&K Labor Rate Factors by State

The following presents the state factors for the RS Means Open Shop
Building Construction Cost Data 17th edition location factors for
materials and subcontracting (or total) and the BE&K construction labor
factors:

	Materials Factor	Subcontracting Factor	BE&K Construction Labor Factor

Alabama	0.967	0.823	1.000

Alaska	1.354	1.254	0.959

Arizona	0.989	0.876	0.975

Arkansas	0.957	0.778	0.970

California	1.076	1.119	0.983

Colorado	1.019	0.937	0.974

Connecticut	1.028	1.054	0.979

Delaware	0.992	1.009	0.968

Florida	0.987	0.841	0.992

Georgia	0.967	0.840	0.979

Idaho	1.021	0.938	0.960

Illinois	0.970	1.041	0.997

Indiana	0.975	0.957	0.958

Iowa	0.996	0.918	0.995

Kansas	0.966	0.864	0.961

Kentucky	0.955	0.895	0.992

Louisiana	0.989	0.824	0.990

Maine	0.996	0.824	1.003

Massachusetts	0.997	1.043	0.975

Maryland	0.937	0.884	0.973

Michigan	0.970	0.948	0.973

Minnesota	0.984	1.073	0.983

Mississippi	0.985	0.739	0.977

Missouri	0.962	0.950	0.987

Montana	0.995	0.938	0.977

Nebraska	0.978	0.828	0.962

Nevada	1.020	0.993	0.967

New Hampshire	0.983	0.913	0.982

New Jersey	1.028	1.125	0.965

New Mexico	1.006	0.912	0.972

New York	0.968	0.945	0.977

North Carolina	0.959	0.734	0.982

North Dakota	1.008	0.849	0.939

Ohio	0.967	0.944	0.954

Oklahoma	0.971	0.789	0.990

Oregon	1.044	1.060	0.967

Pennsylvania	0.975	0.982	0.982

Rhode Island	1.001	1.040	0.980

South Carolina	0.954	0.726	0.970

South Dakota	0.989	0.778	0.970

Tennessee	0.968	0.803	0.998

Texas	0.965	0.807	0.991

Utah	1.018	0.899	0.951

Vermont	1.010	0.855	0.973

Virginia	0.972	0.838	0.966

Washington	1.062	1.016	0.964

West Virginia	0.970	0.937	1.005

Wisconsin	0.984	0.959	0.979

Wyoming	1.003	0.826	0.939



Net Downtime

Although mill or process downtime costs were not included in the
analysis, an estimate was made of the net downtime.  Since the work
would be done during scheduled downtime, the net downtime is the
additional time required above the typical scheduled downtime.  The
following is BE&K’s estimate for net downtime:

Good / Best Technology	Pollutant	Equipment	Net Downtime, days

Good  	PM	NDCE Kraft Recovery Furnace	3

Best	PM	NDCE Kraft Recovery Furnace	3

Good	SO2	NDCE Kraft Recovery Furnace	3

Best	SO2	NDCE Kraft Recovery Furnace	3

Good	NOx	NDCE Kraft Recovery Furnace	3

Best	NOx	NDCE Kraft Recovery Furnace	3

Best	VOC	NDCE Kraft Recovery Furnace	3

Good	PM	DCE Kraft Recovery Furnace	3

Best	PM	DCE Kraft Recovery Furnace	3

Good	SO2	DCE Kraft Recovery Furnace	3

Best	SO2	DCE Kraft Recovery Furnace	3

Best	NOx	DCE Kraft Recovery Furnace	3

Good	VOC	DCE Kraft Recovery Furnace	4

Best	VOC	DCE Kraft Recovery Furnace	20

Good	PM	Smelt Dissolving tank	3

Best	PM	Smelt Dissolving tank	3

Good	PM	Lime Kilns	3

Best	PM	Lime Kilns	3

Best	NOx	Lime Kilns	3

Best	NOx	Lime Kilns	5

Good	PM	Coal Boiler	3

Best	PM	Coal Boiler	3

Good	HCl	Coal Boiler	3

Best	HCl	Coal Boiler	3

Good	PM	Coal/Wood Boiler (50/50)	3

Best	PM	Coal/Wood Boiler (50/50)	3

Good	SO2	Coal or Coal/Wood boiler (50/50)	3

Best	SO2	Coal or Coal/Wood boiler (50/50)	3

Good	NOx	Coal or Coal/Wood boiler (50/50)	3

Best	NOx	Coal or Coal/Wood boiler (50/50)	5

Best	NOx	Coal or Coal/Wood boiler (50/50)	3

Best	Hg	Coal or Coal/Wood boiler (50/50)	5

Best	CO	Coal or Coal/Wood boiler (50/50)	3

Good	NOx	Gas boiler	3

Best	NOx	Gas boiler	5

Good	NOx	Gas turbine	5

Good	NOx	Gas turbine	5

Best	NOx	Gas turbine	5

Good	PM	Oil boiler	3

Best	PM	Oil boiler	3

Good	SO2	Oil boiler	3

Best	SO2	Oil boiler	3

Good	NOx	Oil boiler	3

Best	NOx	Oil boiler	5

Good	PM	Wood boiler	5

Best	PM	Wood boiler	3

Best	PM	Wood boiler	5

Good	NOx	Wood boiler	3

Best	NOx	Wood boiler	3

Best	NOx	Wood boiler	5

Best	Hg	Wood boiler	5

Best	CO	Wood boiler	3

Good	VOC	Paper machines	3

Best	VOC	Paper machines	3

Best	VOC	Paper machines	3

Good	VOC	Mechanical pulping	3

Best	VOC	Mechanical pulping	3

Best	Various	Recovery Furnace	NA

Best	PM	NDCE Kraft Recovery Furnace	3

Good	PM	NDCE Kraft Recovery Furnace	3

Best	PM	Lime Kilns	3

Best	PM	Coal Boiler	3

Best	PM	Coal/Wood Boiler (50/50)	3

Best	NOx	NDCE Kraft Recovery Furnace	5

Best	NOx	DCE Kraft Recovery Furnace	5

Best	VOC	Mechanical Pulp	3





	







AF&PA Emission Control Study – 

Cost Estimate & Industry-Wide Model 

Phase I Pulp & Paper Industry









